Cluster Level 1,Cluster Level 2,AF,TI,DE,"ID",AB,TC,Z9,U1
Oil Recovery,Water Flooding,"Miguel, Paiva Rojas; Joanna, Zanetti; Stefano, Zanetti; Alejandro, Stieben; Eduardo, Tidball",Fluid dynamics analysis and performance of polymer flow regulators for polymer flooding in multilayered reservoirs,Flow regulator; Pressure drop; Mechanical degradation; Polymer flooding; Computed fluid dynamics,ENHANCED OIL-RECOVERY; MECHANICAL DEGRADATION,"Polymer flooding, a high viscosity solution of water and polymer, is introduced as an enhancement of oil recovery methods which is pumped through injector wells to push the liquid hydrocarbon towards production wells. Nowadays, the polymer injections method through layers for different flow admissions has allowed the improvement of heterogeneous flow distribution and the oil recovery factor itself. However, choke valves are needed to get the flow control in admission layers. Nevertheless, any flow obstruction affects the polymer viscosity via mechanical degradation. The shear stress in a standard orifice waterflood regulator breaks down the polymer molecule, causing viscosity loss, and hence reducing the recovery factor properties. In order to avoid shear degradation, several proposal nonstandard regulators of flow/pressure control options have been selected. In this work, experimental and computational studies were made to evaluate the design performance of pressure regulators to inject a polymer solution. The intermittent flow patterns concept has gotten a superior performance. The experimental data from this shock absorber has shown the average viscosity loss being less than 10% and pressure drop up to 34.5 bar with a polymer concentration of up to 700 mg/L, high flowrate around 89 m(3)/d and average salinity water was used to prepare the polymer solution. It was confirmed that the computational results have achieved a good match with experimental data. These results will validate regulator design, and improve cost estimation, saving materials and additional water treatment facilities.",0,0,0
Oil Recovery,Water Flooding,"Al Kalbani, Munther; Jordan, Myles; Mackay, Eric; Sorbie, Ken; Nghiem, Long",Modelling the impact of Alkaline-surfactant and Alkaline-surfactant-polymer flooding processes on scale precipitation and management,Chemical EOR; Alkaline-surfactant-polymer; Geochemical reactions; Inorganic scale precipitation; Squeeze modelling,OIL; TECHNOLOGY; RECOVERY; WATER,"Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the in situ mineral reactions on the produced scaling ions and pH has been little reported in the literature. The objective of this study is to investigate the impact of the in situ chemical and geochemical interactions on the scale precipitation risk when the fluids reach the wellbore, and their inhibition during Alkaline-Surfactant (AS) and ASP flooding processes. Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options. Results: show that the in situ rock dissolution, mineral precipitation and brine mixing reduce the produced ion concentrations (Ca2+, Mg2+, HCO3) and pH compared to the initial concentration and the injected pH value. The calcite scaling risk can be high during Na2CO3 injection while silica and Mg(OH)(2) scales are potential minerals that will precipitate in the production system during NaOH injection. Uncertainty in the mineral reaction rate parameters, especially mineral surface area, is important and must be captured, as this may impact the scaling risk in the producer. Among the studied flooding options, ASP with pre and post polymer slugs shortens the calcite scaling period, reduces the scaling ion concentrations and the produced water rates. This case, then, requires the least number of squeeze treatments, the lowest scale inhibitor volume, and delivers the highest incremental oil recovery. This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.",0,0,0
Oil Recovery,Water Flooding,"Ligeiro, Tayanne S.; Vaz, Alexandre; Chequer, Larissa",Forecasting the impact of formation damage on relative permeability during low-salinity waterflooding,Low-salinity waterflooding; Fines migration; Relative permeability; Formation damage; Particle detachment; Coreflood experiments,FINES-MIGRATION; POROUS-MEDIA; INJECTIVITY DECLINE; SWEEP EFFICIENCY; SLOW MIGRATION; OIL-RECOVERY; FLOW; PARTICLES; TRANSPORT; RELEASE,"Low-salinity waterflooding is considered to be an advanced oil recovery method, but the main mechanism behind the increase in oil recovery factor is still under investigation. Fines migration has been recognized to be one of the mechanisms responsible for the increase in oil production. In this case, the increase in oil recovery happens as a result of increased sweep efficiency and consequent reduction of residual oil. The release of particles due to reduction of electrostatic forces results in flux diversion to previously unswept areas in the reservoir, increasing oil recovery. This paper provides a better understanding of the effects of formation damage during low-salinity water injection in Berea sandstones and proposes a methodology to forecast its effects on water relative permeability. We have performed one- and two-phase flow coreflood experiments with varying salinity of the injected solution. The effluent was analysed for salinity, pH and particle concentration. The laboratory data was treated using a mathematical model that accounts for permeability impairment during low-salinity waterflooding due to fines detachment, migration and capture in small pore throats. The parameters of the model were used to predict the impact of formation damage on the water relative permeability during two-phase flow. The mathematical model matched the laboratory data for pressure drop and particle concentration in the outlet with great accuracy. A methodology to predict the impact of formation damage in two-phase flow using one-phase flow data was proposed. A good agreement between the predicted and the measured water relative permeabilities was obtained. The forecasted water relative permeability curve was able to reproduce the non-monotonic behaviour of water relative permeability due to low-salinity water injection.",0,0,0
Oil Recovery,Water Flooding,"Kurgyis, Kata; Hommel, Johannes; Flemisch, Bernd; Helmig, Rainer; Ott, Holger",Explicit continuum scale modeling of low-salinity mechanisms,Low-salinity; Double layer expansion; Multicomponent ion exchange; Reactive transport modeling; Dispersion; IOR EOR,,"Understanding the influence of injection water composition on the displacement efficiency has been a long-standing issue in reservoir engineering; a reduction of the injection water salinity can lead to additional oil production, which is considered a low-cost and environmentally friendly method for enhanced oil recovery. Several underlying chemical mechanisms have been identified; however, the identification of the governing mechanisms remains difficult and specific to the chemical setting of the reservoir and injection water composition. In this work, we implement two potential mechanisms, namely, double layer expansion and multicomponent ion exchange, to achieve an explicit description of low-salinity effects in the open-source continuum-scale flow simulator DuMu(X), with the goal of designing and interpreting experiments, and upscaling the results. By assuming sets of input parameters, we show that there is a minimum required core length dependent on the dispersion of the chemical flooding front dominated by sample heterogeneity. Above this length scale, the saturation profile is fully developed, and the chemical effluent analysis is conclusive, which both is required to calibrate continuum scale models. The change in the chemical water composition shows a characteristic fingerprint for both investigated mechanisms and therefore allows the identification of the leading low-salinity mechanism. The model is publicly available.",0,0,0
Oil Recovery,Water Flooding,"Almarri, Misfer",Identification and characterization of Thermally Induced Fractures through integrated analytical and semi-analytical models,Waterflooding; Oil recovery; Thermally induced fracture; Inter-well communication; Flood efficiency; Fracture characterization,,"Thermally induced fractures (TIFs) are common in waterflooded fields where the injection of (relatively) cold water leads to a cooling front that reduces a formation's in-situ stresses. Understanding TIFs is important since their existence impacts oil recovery potential, well injectivity, injection well integrity, and injector-producer well spacing in reservoirs under waterflooding. Identifying and characterizing dynamic TIF growth is a critical step in defining field development strategies and making daily reservoir management decisions. This research introduces a workflow that integrates analytical well monitoring and semi-analytical models to identify TIF onset, propagation properties, direction, and impact during dynamic reservoir events occurring at different levels. The practicality of the proposed workflow has been tested using synthetic data and its robustness confirmed by an analysis of actual field data. The novelty of the approach presented here is in its efficient integration of recent analytical and semi-analytical models to identify TIF onset, propagation, characteristics, and impact from generally available well injection production history data. This practical workflow will help engineers detect and monitor TIFs and evaluate the metrics describing waterflood performance, including flood efficiency, inter-well communication, and pressure maintenance.",0,0,1
Oil Recovery,Water Flooding,"Khalilnezhad, Ali; Simjoo, Mohammad; Hamidian, Nima",Insights into viscous fingering effect induced by wettability alteration processes: A fractional flow study,Wettability alteration; Viscous fingering; Fractional flow; Low salinity injection,LOW-SALINITY; OIL-RECOVERY; DISPLACEMENT; INSTABILITY; MECHANISMS; INJECTION; DISPERSION,"Wettability alteration is one of the promising mechanisms for enhancement of oil recovery from preferentially oil-wet rocks. Many water-based EOR methods containing chemicals (e.g. surfactants) or ions (e.g. low salinity water: Low-Sal) were proposed to alter rock wettability to more water wetness. But, one of the possible challenges to get the full potential of such EOR methods is the occurrence of the viscous fingering phenomena. This could be the case for those of EOR methods in which an oil mobility profile over the flow domain could be formed due to the wettability alteration and thus potentially trigger viscous fingering with a negative impact on the oil displacement. In this paper, we aimed to describe this kind of viscous fingering phenomena by applying the fractional flow theory for the case of a tertiary Low-Sal injection process in a core sample previously flooded by a high salinity water. We explained the fractional flow procedure to obtain the saturation and location of the viscous fingered-region. As to the results, water saturation continuously decreases over the viscous fingered-region from an upstream point located at the Low-Sal region to a downstream point at the High-Sal region. The severity of the viscous fingering phenomena could be well addressed by the location of upstream and downstream saturation points as the proposed model honors these points. The model performance to predict breakthrough time and oil recovery factor was also validated by the previously reported Low-Sal experimental data and we found a good agreement between the model outcome and lab data.",0,0,1
Oil Recovery,Water Flooding,"Kalam, Shams; Yousuf, Usama; Abu-Khamsin, Sidqi A.; Bin Waheed, Umair; Khan, Rizwan Ahmed",An ANN model to predict oil recovery from a 5-spot waterflood of a heterogeneous reservoir,ANN; ANFIS; SVR; Waterflooding,ARTIFICIAL NEURAL-NETWORK; POROUS-MEDIA; PERFORMANCE; SELECTION; GAS; INTELLIGENCE; REGRESSION; AKAIKE; FLOW,"Waterflooding is a secondary oil recovery technique in which water is injected into an underground oil reservoir to maintain the reservoir pressure and boost oil recovery. The performance of a waterflood depends on several factors such as reservoir heterogeneity, reservoir fluid properties, flood pattern, etc. Most of the models developed to predict waterflood performance are either for linear systems or involve simplified assumptions for nonlinear systems. In this study, we propose a novel, artificial neural network (ANN) model comprised of two hidden layers with 256 neurons each for the performance prediction of a 5-spot pattern waterflood in a heterogeneous reservoir at and beyond water breakthrough. The proposed model can be applied to estimate movable oil recovery efficiency of the waterflood (RFM) as a function of Dykstra-Parsons permeability variation coefficient (V), mobility ratio (M), permeability anisotropy ratio (kz/kx), production water cut (fw), a simple indicator of wettability (WI), and oil/water density ratio (DR) within reasonable accuracy. The MAPE of the proposed model was -4% and -5% using training and testing data, respectively. Our ANN model recommendation is based on a detailed comparative study against other popular soft computing models, such as adaptive neuro-fuzzy inference system (ANFIS) and support vector regression (SVR). Based on the accuracy and computational efficiency, the ANN model outperforms ANFIS and SVR. AIC and BIC of the proposed ANN model were also the lowest among all applied soft computing tools. The proposed model is tested on two real field cases and compared with a semianalytical model and an empirical correlation. The presented model shows good agreement with the real field data. The trained ANN model, proposed here, saves computational time in forecasting the waterflood performance compared to a reservoir simulator.",0,0,1
Oil Recovery,Water Flooding,"Afanasyev, Andrey; Andreeva, Anna; Chernova, Anna",Influence of oil field production life on optimal CO2 flooding strategies: Insight from the microscopic displacement efficiency,CO2 flooding; Immiscible gas injection; WAG process; Optimization; Production life; Net present value,CARBON-DIOXIDE; RECOVERY; STORAGE; EQUATION,"We investigate the influence of the microscopic displacement processes on optimal gas flooding strategies. We couple a 1-D compositional reservoir model with an economic model of the flooding to assess profitability of the strategies. In general, we aim at the net present value maximization, although the oil recovery and CO2 storage efficiencies are also estimated. Under certain assumptions, we reduce the number of parameters controlling selection of optimal strategy to just a few dimensionless quantities characterizing both physical and economic processes. We show that the production life of oil fields should not be fixed in optimization studies, especially at low oil prices. A significantly larger net present value can be achieved by varying the reservoir lifetime in addition to the injection rates and volumes and other well controls. Herewith, the optimal strategy can differ from that in the case of a presumed production time. We conclude that waterflooding is the optimal recovery method if the injection rate is low, whereas gas (WAG) flooding applied as a primary method and followed by waterflooding is most optimal for large injection rates. Gas flooding applied as the tertiary recovery method is most optimal for an intermediate range of the rates. In the latter case, gas injection should begin much earlier than water breaks through to producing wells. Finally, we investigate how oil price influences the range of parameters suitable for gas injection.",0,0,1
Oil Recovery,Water Flooding,"Altaheini, Suleiman; Mostaghimi, Peyman; Clark, Stuart R.",Incorporating adaptive well conditions into numerical reservoir simulators constrained by well and reservoir performance data,Adaptive well control; Adaptive well conditions; Water flooding; Improved oil recovery; Extended well lifetime,OPTIMAL INJECTION POLICIES; ENHANCED OIL-RECOVERY; OPTIMIZATION; PLACEMENT; ALGORITHM,"Using fixed boundary conditions has always been the way wells are modelled in reservoir simulators for prediction runs. This commonly results in oil wells being shut-in due to increasing production of water or gas or triggering a workover option shutting-in a section of the wells perforated interval. These actions are late reactive actions instead of being proactive actions that can help prolong a wells life. In actual field operations, well flow rates and bottomhole pressures are often adjusted to better suit reservoir management strategies and control water and gas production. This paper introduces a novel yet simple implementation of adaptive well conditions that updates well boundary conditions based on wellbore or near-wellbore performance. This methodology can be executed using a commercial simulator alongside a small instructing application, or internally integrated as done here with an inhouse reservoir simulator built to present this work as proof of concept. Three case studies are presented in this paper with increasing complexity. We show that an improvement in the amount of recovered oil, an increase in the lifetime of assets, and a reduction of produced water and gas are all possible with adaptive well controls. In one of the three cases, adaptive well controls resulted in an oil recovery increase as high as 20%. We also discuss the differences between well-data and reservoir-data dependencies of the adaptive well-condition algorithms in terms of dynamic response and physical application. Implementing adaptive well controls can help in reconsidering business plans by reducing water and gas production and avoiding early abandonment of wells. It was also considered that one of the main advantages of adaptive well conditions is the potentially significant reduction in number of variables for future optimization studies due to the elimination of control steps.",0,0,1
Oil Recovery,Water Flooding,"Habibi, A.; Riazi, M.; Malayeri, M. R.",Experimental and simulation study of the tensile strength of wet carbonate rocks using the Brazilian Test,Tensile strength; Wet carbonate rock; Hydration force; Brazilian tensile test; Extended finite element method,,"Mechanical behavior of rocks would have substantial implications for different operations from fluid injection and hydraulic fracturing in hydrocarbon reservoirs to underground carbon dioxide storage in the crust of the earth. In all of these operations, restricting the undesired seismicity events and preserving the integrity of formations is a crucial subject that enforces engineers to evaluate the mechanical behaviors of constituent rocks and predict the formation response. Tensile strength is an important factor for maintaining caprock and reservoir formation from induced tensile cracking which can be influenced by the pore fluid. This paper focuses on the tensile strength of carbonate rock, as an important reservoir rock, in the presence of seawater, as a common injection fluid candidate for enhanced oil recovery objectives. For this purpose, twelve dolomite samples from the Asmari-Jahrum Formation outcrop in Fars province, Iran, were prepared for performing tensile tests. Also for a thorough comparison, sample properties, fluid contents, digital image correlation measurements, and a finite element simulation have been investigated. The experimental results showed a noticeable reduction in the tensile strength of dolomite samples in the presence of distilled water and seawater. In comparison with a dry sample though, a reduction of 16% tensile strength for a seawater saturated sample was observed for similar samples. Among the various mechanisms, which are reported in the open literature, the hydration force seems to be the main reason for the tensile strength reduction and this conclusion was examined by measuring the mass of vaporized adsorbed water on the powder of the same dolomite sample. In addition by testing flooded samples, the impact of flow on the tensile strength was examined. For both cases of seawater and distilled water flooding, the samples which were placed in the outlet zone during the flooding showed lower tensile strength. Moreover, simulation results confirmed the similarity of the weakening trend and impact of seawater.",0,0,2
Oil Recovery,Water Flooding,"Chen, Quan; Otaibi, Mohammed; Ayirala, Subhash; Yousef, Ali",The prospects and potential opportunities of low salinity water flooding for offshore applications in sandstones,Low salinity waterflooding (LSWF); Multicomponent ion exchange (MIE); Desulfated seawater (DSSW); Single well chemical tracer test (SWCTT); Interwell field trial; Sulfate removal unit (SRU); Reverse osmosis (RO) desalination,,"Low salinity water flooding (LSWF) is an emerging enhanced oil recovery (EOR) technology with enormous potential for offshore applications in sandstones. The objective of this study is to provide a review on LSWF offshore field applications and summarize the key lessons learned. A review was also conducted on the capabilities of existing sulfate removal units (SRUs) for seawater injection in offshore fields. Furthermore, the potential of targeting offshore oil fields with de-sulfated seawater (DSSW) injection, either ongoing or planned, as primary candidates to switch over to LSWF EOR has been investigated. For LSWF field trials, the chance of success can be significantly improved when it is based on key laboratory screening tests such as reservoir condition corefloods. The LSWF field tests implemented in offshore fields mainly comprise of single well chemical tracer tests (SWCTT) and interwell trials. However, the reported interwell field trials are restricted to unconfined pilots, which makes the injection and production allocation difficult. Therefore, confined pilots are recommended for future consideration of LSWF field trials to provide better estimations on swept volumes and accurately determine the improvements in the displacement efficiency. Globally there are more than 80 sulfate removal units in operation for de-sulfated seawater (DSSW) injection in offshore waterflooding. All these offshore fields with DSSW injection either currently ongoing or planned can become potential candidates for screening and switch over to LSWF EOR for the following two reasons: (1) The divalent cations can act as bridges between negatively charged rock surfaces and negatively charged polar oil components to increase the oil-wet tendency. These bridges can become primary targets to be replaced by uncomplexed cations in low salinity water for EOR. (2) The de-sulfated seawater injection processes can easily be switched to LSWF by retrofitting the existing sulfate removal units with reverse osmosis (RO) desalination systems and upgrading the facilities to handle larger water volumes. Such retrofitting is considered sufficient to generate low salinity water, which can bring significant gains to increase oil recovery with minimal additional investment. The availability of RO desalination systems on offshore platforms can also provide potential opportunities for the cost-effective implementation of tertiary chemical EOR technologies especially polymer flooding. The novelty of this study is that it provides useful guidelines for reservoir screening and offshore field implementation of LSWF processes. Also, the new potential of evaluating the offshore oil fields with existing DSSW injection for switching over to LSWF has been identified. These findings will have a potential impact on enhancing the LSWF prospects and opportunities for EOR in different offshore fields.",0,0,2
Oil Recovery,Water Flooding,"Aboelkhair, Hamed; Diaz, Pedro; Attia, Attia",Biosurfactant production using Egyptian oil fields indigenous bacteria for microbial enhanced oil recovery,Microbial enhanced oil recovery; Indigenous bacteria; Biosurfactant; Bacillus subtilis; Surface activity; Critical micelle concentration,BACILLUS-SUBTILIS; SURFACTANT; LICHENIFORMIS; OPTIMIZATION; WETTABILITY; HYDROCARBON; INJECTION; MOLASSES; STRAINS,"Biosurfactant production is one of the most efficient mechanisms in microbial enhanced oil recovery (MEOR) processes. This work investigates the production of biosurfactants by indigenous bacteria isolated from Egyptian oil fields, and how to optimize these produced biosurfactants for MEOR. 59 Egyptian oil reservoirs were screened to evaluate the potential applicability of MEOR processes, based on their rock and fluid properties. Results showed that 8 reservoirs from the Gulf of Suez and 3 reservoirs from the Western Desert had the potential to MEOR. Combined analysis of morphological, and biochemical characterization was performed on the 11 bacterial strains isolated from different crude oil samples collected from the reservoirs that have the potential to MEOR process to identify their types. Bacillus spp, a bacilli species that can produce biosurfactants, was selected for further studies. To optimize the surface activity of the produced biosurfactant, ten different reported nutrient media, and a new proposed nutrient media were examined. Bacillus spp has shown the ability to produce a very active biosurfactant that reduced the surface tension of water from 71.8 +/- 1.9 mN/m to 25.7 +/- 1.2 mN/m, and the interfacial tension of water against kerosene from 48.4 +/- 2.1 mN/m to 0.38 +/- 0.07 mN/m at Critical Micelle Concentration (CMC) of 0.04 +/- 0.01 g/l, in a medium supplemented by the new proposed nutrient medium H. The growth rate of Bacillus spp was studied, and it was found it reached its maximum (OD600nm 2.59 +/- 0.16) after 24 h of incubation. Biosurfactant production has no significant change in its surface activity over a wide range of temperature range up to 120 degrees C, which means the studied species Bacillus spp is a thermophilic bacterium. Bacillus spp grew well in the presence of high salt concentration up to 20% (w/v) NaCl, the optimal surface activity was obtained in the range of 0-2% (w/v) NaCl, and at pH 7. The emulsification activity of the produced biosurfactant was examined, and it reached the maximum (69.6 + 1.5%) against kerosene at temperature 25 degrees C, Salinity 0% (w/v) NaCl (distilled water), and pH 7. The produced biosurfactant was purified and extracted by acid precipitation method, and the biosurfactant yield of the purified compound was found to be 2.8 +/- 0.3 g/l. Finally, the core-flooding experiments were conducted to investigate the effect of produced biosurfactants by Bacillus subtilis in oil recovery. The obtained results reveal the potential of Bacillus spp to grow in the new proposed medium H and produce effective and efficient biosurfactants that enhanced oil recovery by 25.19-39.35% of additional oil over the water flooding residual oil saturation in the studied cores and retain more than 60% of its surface activity under harsh conditions and that are relevant to Microbial Enhanced Oil Recovery, MEOR.",0,0,2
Oil Recovery,Water Flooding,"Khan, Mohammad Yunus; Mandal, Ajay",Analytical model of incremental oil recovery as a function of WAG ratio and tapered WAG ratio benefits over uniform WAG ratio for heterogeneous reservoir,EOR; Analytical model; Tapered WAG; Uniform WAG; Reservoirheterogeneity; WAG incremental oil recovery; Gas utilization factor,GAS; INJECTION; EFFICIENCY; DESIGN; DISPLACEMENTS; OPTIMIZATION,"The water-alternating-gas (WAG) operating scheme and reservoir permeability heterogeneity are the main crucial parameters, which highlyaffect WAG displacement process. The novelty of this article lies in the development of an analytical model for WAG incremental oil recovery as function of WAG ratio, viscous gravity ratio and mobility ratio for the stratified heterogeneous reservoir. We have investigated the effect WAG ratio on WAG incremental oil recovery with variation horizontal permeability heterogeneity, vertical permeability anisotropy and dip angle of the reservoir. The critical operating parameters investigations were carried to optimize WAG displacement process in both homogeneous and heterogeneous reservoirs. Finally, we have estimated all the benefits of the most suitable techno-economical WAG operating scheme as tapered WAG (TWAG) over uniform WAG (UWAG). The developed analytical model showsreasonably similar results as numerical simulation. The results of the analytical and numerical analysisshow that the incremental oil recovery accelerated bya decrease WAG ratio. However, this effect is more noticeable at high viscous gravity (VGR). The increase in reservoir dip angle subsequently increases vertical and displacement sweep efficiencies compared to the horizontal reservoir for different WAG ratio. While increasing WAG ratio decreases vertical sweep and increases displacement sweep of inclined reservoir compared to the horizontal reservoir. The increase of oil recoverywas observed by higher Kv/ Kh with a lower WAG ratio. However, this effect is less evident at lower Kv/Kh. The WAG ratio with a higher proportion of water is beneficial for the heterogeneous reservoir. The infill implemented before WAG start shows faster oil recovery compared to WAG start first then infill implemented in the heterogeneous reservoir. The TWAG incremental recovery over water flood was 18% in homogeneous and 8% in heterogeneous reservoirs, while EUR was approximately similar to UWAG. The TWAG shows more efficient techno-economic benefits over UWAG due to better economics, faster oil recovery rate, more efficient use of injected gas and reduces response time in both homogeneous and heterogeneous reservoirs.",0,0,2
Oil Recovery,Water Flooding,"Shahmohammadi, Borhan; Chahardowli, Mohammad; Simjoo, Mohammad",Insights into the pore-scale mechanism of low salinity water injection using a clay-coated micromodel,Low-salinity; Water flooding; Crude oil polar component; Partitioning; Wettability alteration; Clay-coated micromodel; Emulsified phase,IMPROVED OIL-RECOVERY; NAPHTHENIC ACIDS; IMPACT; BRINE; SANDSTONE; RESERVOIR; EMULSION,"This study aims to provide new insights into the interactions among an acidic crude-oil, brine with different salinities and clay using flow experiments in montmorillonite-coated micromodels. To this end, a series of oildisplacement experiments are performed in a transparent clay - coated micromodel. In addition, salinityscreening tests, pH and IFT measurements are performed to support the results of flow-experiments. It is shown that during water injection into a clay-coated micromodel, polar components of crude oil partition between oil/water phases and form an emulsified phase. With the 90% reduction in water salinity, the partitioning of crude oil polar components in the aqueous phase is increased. Such partitioning lead to a significant reduction in the pH of the aqueous phase. This observation is supported by an increase in the IFT of oil/brine due to the decrease of crude oil polar components. Salinity screening tests show that there is a critical water salinity, i.e., below the critical point, a large amount of crude oil polar components is partitioned between phases, which can be attributed to the polarization effect. Overall, results show that low salinity water injection benefits from formation of an emulsified phase and wettability alteration to improve oil recovery in the microscale.",0,0,2
Oil Recovery,Water Flooding,"Al Ghafri, Al Yaqathan; Mackay, Eric; Stephen, Karl",The relevance of the linear stability theory to the simulation of unstable immiscible viscous-dominated displacements in porous media,Instability predictor; Saffman-Taylor instability; End-point mobility ratio; Fractional flow analysis; Viscous oil; Polymer flooding; Correlated random field,MISCIBLE DISPLACEMENT; INSTABILITIES; MECHANISM; POLYMER; GROWTH; MODELS; FLUID,"The 2D governing equations for the immiscible two-phase flow admissible to linear stability analysis are inspected. The identification of the term v(ws)delta D-st in the generalized Saffman-Taylor criterion is key to the analysis. It can be regarded as a predictor that correlates with observed immiscible instability in terms of the rate of advancement of the viscous pattern, the number of small protrusions, and their roughness in a given heterogeneous domain described by a correlated random field. The predictor is extended, heuristically, for polymer flooding shock-wise and used to characterize the instability of the two shocks. The extension is validated by simulation. The instability of the primary shock is essential when considering the breakthrough recovery. In light of the instability predictor, the geometric interpretations of the fractional flow are essential to understand the stability enhancement of the primary shock over the Buckley-Leverett shock in water flooding. It is also concluded that the end-point mobility ratio does not directly control the immiscible instability. This conclusion was arrived at by fixing the end-point mobility ratios for three sets of relative permeability curves, and yet noticeably different instabilities occur, both in transverse and correlated random fields. The criterion can predict the viscous instability in the laboratory experiments under certain flooding conditions and sample configurations. Concerning the instability in a field scale, the predictor is applicable if the field is regarded as a prototype of a given model experiment.",0,0,2
Oil Recovery,Water Flooding,"Liu, Hangyu; Shi, Kaibo; Liu, Bo; Song, Xinmin; Deng, Liben; Guo, Rui; Tian, Zhongyuan; Li, Yong; Deng, Ya; Wang, Genjiu",The characteristics and origins of thief zones in the Cretaceous limestone reservoirs of Central and southern Mesopotamian Basin,Mesopotamian Basin; Cretaceous; Carbonate reservoirs; Thief zones; Rudist shoals; Tidal channels; Bioturbation,,"Thief zone is a common reservoir unit with super permeability developed in giant carbonate reservoirs and readily leads to the breakthrough of fluids bring the challenge to water flooding development or tertiary oil recovery. To provide insight into the characteristics and origins of thief zones in Cretaceous carbonate reservoirs in Central and Southern Mesopotamian Basin, core analyses, well log, and production performance data analyses were performed in three formations from two giant oilfields. Thief zones are indicated and located by higher water injection and liquid production rates and classified based on their sedimentary environment, that is, rudist shoal thief zone (RS-TZ), tidal channel thief zone (TC-TZ), and bioturbated-associated thief zone (BS-TZ). Both RS-TZ and TC-TZ are characterized by similar or higher porosity, much higher permeability, and much larger pore-throat radii than overlying and underlying adjacent non-thief zones. The RS-TZ comprises microfacies of rudist rudstone and rudist grainstone with interparticle pores, interparticle dissolved pores and vugs. It occurs in the upper-middle section of the uppermost rudist shoal in the shoal complex, shows the sheet-shaped horizontal distribution in the late highstand system tract of the field. The TC-TZ comprises microfacies of bioclastic grainstone with interparticle pores and few interparticle dissolved pores, and presents banded horizontal distribution. The BS-TZ went through strong bioturbation within hardground substrate leading to the great difference of microfacies, pore types and pore structures in burrows and matrix, and this type has lower porosity but much higher permeability than adjacent reservoirs. The key to developing the thief zones is to form the great permeability difference between the thief zone and its adjacent reservoirs. The origins of the three types of thief zones can not only be attributed to the primary porosity having well-connected pore structures resulted from high-energy sedimentary facies or high-energy sediments filling bioturbation-associated burrows, and freshwater dissolution in the eogenesis stage also enlarged the pores and pore-throat sizes and further improved pore connectivity, which enhanced the porosity and significantly improved permeability. Due to the difference in rock textures, pore structures and sedimentary successions, the three types of thief zones have different well log response characteristics which could be used for thief zone identification in non-coring wells and other oilfields that occurred the similar thief zones.",0,0,2
Oil Recovery,Water Flooding,"Wang, Mibang; Yang, Shenglai; Li, Jiajun; Zheng, Zuhao; Wen, Jing; Ma, Quanzheng; Wang, Qian; Chen, Hao",Cold water-flooding in a heterogeneous high-pour-point oil reservoir using computerized tomography scanning: Characteristics of flow channel and trapped oil distribution,High-PPT live oil; CT-Scanning; Positive-rhythm reservoir; Variable water injection temperature; Flow channel,WAXY CRUDE-OIL; ASPHALTENE PRECIPITATION; PERMEABILITY REDUCTION; PARAFFIN PRECIPITATION; RELATIVE PERMEABILITY; START-UP; DEPOSITION; MODEL; IMBIBITION; EFFICIENCY,"There are relatively few studies that consider the influence of reservoir heterogeneity on reservoir wax deposition. This study conducts a computerized tomography scan to study the flow channels, heavy component retention, displacement efficiency, and trapped oil distribution in a high-pour point oil reservoir with a positive sedimentary rhythm under various water injection temperatures. This study greatly improves the understanding of the wax deposition influences on the flow channel. Three displacement models are proposed: water-flooding breakthrough model (49.5 ?C), approximate-equilibrium piston-like displacement model (54.5 ?C/59.5 ?C), and non-equilibrium piston-like displacement model (64.5 ?C). When the injection temperature is lower than the wax appearance temperature (59.5 ?C), an elliptical wax deposition is formed at the inlet, the most serious deposition is in the middle-permeability layer. A wax deposition barrier is formed away from the inlet, and constrains the downward movement trend of the water injected above. Therefore, the moderate wax precipitation will improve the oil recovery from the top low-permeability layer. However, the heterogeneity in the spaces and strength of the barrier result in the oil recovery from the 100 mD layer at 59.5 ?C begin higher than that at 54.5 ?C; moreover, at 59.5 ?C, the recovery at the inlet is better than that at the outlet. The vortex phenomenon increases the oil recovery from wax deposition area in the bottom layer at the inlet. The heavy component retention is significant, and the oil recovery decreases with decreasing injection temperature. After flooding, the formation mechanisms of the trapped oil include wax deposition, weak water washing, and reservoir sedimentary rhythms. The research results provide initial insights for the evaluation of cold damage.",0,0,2
Oil Recovery,Water Flooding,"Redekop, E. P.; Boronin, S. A.; Tolmacheva, K., I; Burukhin, A. A.; Osiptsov, A. A.; Belonogov, E., V","Effects of salinity and rock clogging on injectivity dynamics of flooding wells: Experiments, modeling and validation on field data",Low salinity flooding; Oil displacement; Formation damage; Pore clogging; Field data,FINES-MIGRATION; WETTABILITY ALTERATION; BRINE COMPOSITION; OIL-RECOVERY; WATER; FLOW; DISPLACEMENT,"Injection of water into a rock formation is a common oilfield services technology to maintain high reservoir pressure and increase ultimate recovery of hydrocarbons. While flowing through the well from surface to the rock formation, injected water typically transports fine particles, for example, fine sand grains and calcite precipitated at surface pipeline conditions while mixing water from different sources (e.g., fresh, Cenomanian and formation brine). In the framework of the two-fluid approach to suspension flow modelling, we formulate mathematical model for linear filtration of a particle-laden suspension in the vicinity of a fractured flooding well and transport of ion concentration (salinity). Two major factors of well injectivity decline are described, namely, particle trapping with associated reduction in permeability and porosity of the rock as well as the effect of salinity of injecting water leading to clay swelling, calcite precipitation and change of relative permeabilities of the rock with respect to water and oil. We calibrate suspension filtration model against in-house experiments on clogging of artificial and natural rock cores, in which the profiles of fines concentration along the cores are obtained using X-Ray computed tomography and analysis of 3D rock reconstruction images. The water injection model is adopted to conditions of Priobskoye oilfield of Western Siberia by using the results of standard laboratory experiments on fluid-fluid (calcite precipitation) and fluid-rock (clay swelling, migration of internal fines) compatibility, as well as the effect of salinity on oil displacement and analysis of solid fraction in the injecting water. The calibrated model is then used to describe field data on dynamics of injection rate of three flooding wells. It is obtained that the simulations predict the long-term injectivity dynamics of the wells very well, while at early times (up to 5 months from the start of injection) the model underestimates the injection rate. While fitting the model to field data, we varied only two parameters, namely, solids concentration in the injecting water (in the range provided by lab experiments) and trapping coefficient (the range is limited to result of experiments made with target rock cores). It is demonstrated that only a combination of injectivity decline factors allows to describe the long-term flooding rate of the wells. Ignoring either particle trapping or salinity effects lead to significant overestimation (up to 50%) of the long-term injection rate. Parametric study of water injection showed that two-fold increase in solids concentration in the injecting water as well as oil compressibility lead to similar decrease in long-term injection rate of a well.",0,0,2
Oil Recovery,Water Flooding,"Xu, Jianchun; Zhou, Wenxin; Li, Hangyu; Wang, Xiaopu; Liu, Shuyang; Fan, Ling",Stochastic simplex approximation gradient for reservoir production optimization: Algorithm testing and parameter analysis,Stochastic simplex approximation gradient; Production optimization; Algorithm testing; Computational cost; Reservoir numerical simulation,WELL PLACEMENT OPTIMIZATION; CYCLE PRODUCTION OPTIMIZATION; ALTERNATING-GAS-INJECTION,"Production optimization is an effective technique to maximize the oil recovery or the net present value in reservoir development. Recently, the stochastic simplex approximation gradient (StoSAG) optimization algorithm draws significant attention in the optimization algorithm family. It shows high searching quality in largescale engineering problems. However, its optimization performance and features are not fully understood. This study evaluated and analyzed the influence of some key parameters related to the optimization process of StoSAG including the ensemble size to estimate the approximation gradient, the step size, the cut number, the perturbation size, and the initial position by using 47 mathematical benchmark functions. Statistical analysis was employed to diminish the randomness of the algorithm. The quality of the optimization results, the convergence, and the computational time consuming were analyzed and compared. The parameter selection strategy was presented. The results showed that a larger ensemble size was not always favorable to obtain better optimization results. The increase of the search step size was favorable to escape from the local optimum. A large step size needed to match a large cut number. The increase of cut number was beneficial to increase the local searchability, but also made the algorithm more easily fall into the local optimum. The random initial position was beneficial to find the global optimal point. Moreover, the effectiveness of the parameter selection strategy was tested by a classical reservoir production optimization example. The final net present value (NPV) for water flooding reservoir production optimization substantially increased, which indicated the excellent performance of StoSAG by adjusting the key parameters.",0,0,2
Oil Recovery,Water Flooding,"Rodriguez, Astrid X.; Salazar, Diego A.",Methodology for the prediction of fluid production in the waterflooding process based on multivariate long-short term memory neural networks,Waterflooding; Multivariate LSTM; Fluid prediction; Oil production forecast; Neural networks,,"Given the depletion of hydrocarbon reserves, the oil industry is developing enhanced recovery processes, including waterflooding, to increase the quantity of hydrocarbon to be extracted from each reservoir. However, one of the main challenges in assessing these processes is predicting water and oil production associated with the method, given the uncertainty, lack of reservoir information, and access to commercial software. This work proposes a methodology based on multivariate Long-Short Term Memory (LSTM) Neural Networks to predict oil and water production time-series in an oil field exploited through waterflooding. First, we used the oil and water production's time series of the producer wells in an inverted five-point injection pattern developed in a numerical reservoir simulation software based on a Colombian oil field exploited with waterflooding. In this scenario, we evaluated three multivariate LSTMs to determine the input features that should be included. Thus, through a define-by-run process, we assessed the LSTM structures most suitable. Finally, we found that the information obtained by operational variables, such as bottom-hole pressure or water injection rate, allows significant approximations to predict oil or water production.",0,0,2
Oil Recovery,Water Flooding,"Santos, Denisson; Barros, Vanderson S.; Silva, Maria Luiza P.; Sales, Havila M. M. S.; Borges, Gustavo R.; Franceschi, Elton; Dariva, Claudio",Strontium-based low salinity water as an IOR/EOR method: Oil-brine interaction,Strontium based saline water; Low salinity water; Oil recovery; Interfacial properties,WETTABILITY ALTERATION; NAPHTHENIC ACIDS; INTERACTION MECHANISM; INTERFACIAL BEHAVIOR; IONIC-STRENGTH; CONTACT-ANGLE; PENDANT DROP; SMART-WATER; SURFACE; RECOVERY,"Strontium-based injection water for enhanced oil recovery has been neglected due to the low solubility of the cation in water. However, challenging reservoirs like those in the Brazilian pre-salt region demand nonconventional solutions to improve oil production. This work shows for the first time that the strontium cation in low salinity water solutions shall be henceforth considered as a potential component in the development of enhanced/improved oil recovery (EOR/IOR) studies. Acidic and non-acidic model oils and real crude oils from Brazilian post-salt and pre-salt fields were used for this study. The oil/brine interfacial tension and viscoelastic properties of the interfacial films were measured by an ascendant drop tensiometer. The results showed that strontium presents the highest interfacial activity among the other alkaline-earth metals. Also, the strontiumbased low salinity water produced the most elastic interfacial film, which is desired for the improvement of oil volumetric sweeping promoted by water flooding. Nonetheless, it is worth highlighting that further studies including core flooding experiments must be performed to assess the strontium effect on the crude oil outflow through reservoir pores as well as the influence of water/oil/rock interactions upon it.",0,0,3
Oil Recovery,Water Flooding,"Boampong, Lawrence Opoku; Rafati, Roozbeh; Haddad, Amin Sharifi",A calibrated surface complexation model for carbonate-oil-brine interactions coupled with reservoir simulation - Application to controlled salinity water flooding,Low salinity water flooding; Disjoining pressure; Electrical double layer; Wettability alteration; Zeta potential; Controlled salinity water flooding,POTENTIAL DETERMINING IONS; WETTABILITY ALTERATION; STRUCTURAL APPROACH; RECOVERY; TEMPERATURE; CALCITE; CHALK; ADSORPTION; INTERFACE; CHARGE,"Vast majority of past studies that have been conducted on controlled salinity water flooding (CSWF) use diffuse layer model (DLM) that calculates only the surface potential, which can be significantly different from the xi-potential of the interface. Importantly, stability of the water-film (between the oil and the rock surface) which dictates ultimate oil recovery is related to xi-potential. As such, using DLM calculated surface potential (directly) for CSWF can be misleading. Additionally, most of the existing DLMs use integer charges instead of fractional charges to model carbonate-brine interactions, which may not represent the actual carbonate crystallographic. We present a triple layer surface complexation model (TLM) which offers the option to locate and distribute charge of the adsorbing ion(s) at three locations. TLM can therefore calculate potentials at three different locations within the Stern layer. To the best of our knowledge, only few authors have used TLM to simulate CSWF. However, some surface reactions were ignored in these models. For instance, adsorption of monovalent ions such as Na+ and Cl- ions was ignored in some of the few available TLMs. Also, the effect of basic-oil components was not considered in some TLMs, and lastly, some TLMs used integer charges for the carbonate surface group. This study introduced a comprehensive TLM that includes all these complexities. Moreover, we introduced a new wettability indicator (WI) that is related to the electrostatic forces between the oil-brine and the rock-brine interfaces. That is, WI was calculated from xi-potentials at the oil-brine and rock-brine interfaces. The TLM, built in a geochemical simulator, PHREEQC, was then coupled with UTCHEM, a multiphase reservoir simulator. The developed simulator based on the TLM-CSWF model was tested against several experimentally measured oil recovery data sets. Results of the model suggest that Oil basic component significantly impacts oil-brine interface xi-potential irrespective of temperature, brine composition, and ionic strength. On the otherhand, Na+ ions in brine may influence oil-brine xi-potential, and this relates to temperature, brine composition, and ionic strength. The results further suggest that injection of (sulfate-free) diluted brine in chalk resulted to increased oil adhesion, shifting the reservoir to oil-wet condition. Hence, no additional oil is recovered with this brine injected at tertiary oil recovery stage. Finally, the results showed that wettability is related to xi-potentials at the oil-brine and rock-brine interfaces, and the carbonate rock would be strongly oil-wet or water-wet only at significantly large magnitude of xi-potentials at the interfaces.",0,0,3
Oil Recovery,Optimization,"Motahhari, S. Mahdia; Rafizadeh, Mehdi; Pishvaie, Mahmoud Reza; Ahmadi, Mohammad",An innovative workflow for selecting appraisal area in low permeability greenfield development under uncertainties,Probabilistic appraisal opportunity index; Appraisal candidate area; Low permeability field development; Fuzzy clustering; Shannon entropy; Uncertainty,WELL PLACEMENT; INFORMATION; OIL,"There are uncertainties in both inherent geological properties and IOR/EOR performance parameters of low permeability greenfield reservoirs. Therefore, efforts to reduce uncertainties in the appraisal phase are necessary for the development and production phases. An adequate selection of the appraisal area in the hydrocarbon field is an imperative factor since the results of the appraisal well drilling and IOR/EOR pilot tests will be utilized for the development of the entire field. The major challenge in selecting an appraisal area is the lack of an integrated and systematic approach. In this study, we present a novel systematic and quantitative approach consisting of a better representative of reservoir features. To do this, some sort of cluster analysis over multiple realization is utilized. The underlying field of study is firstly segmented into appraisal candidate areas. Afterwards, the corresponding covariance matrix and recovery factor arrays are calculated for the simulated 3-D reservoir quality maps in the areas. The areas are optimally clustered by fuzzy clustering method to choose the dominant cluster. Subsequently, the distances between each area and the center of dominant clusters could be used as a criterion for decision making. Moreover, the coefficient of variation for the oil volume changes is another criterion. Finally, the Shannon entropy weighting along with Reference Ideal Method (RIM)-Multi Attribute Range Evaluations (MARE) are applied. They are used as a multi-criteria decision-making method to calculate the Probabilistic Appraisal Opportunity Index (PAOI) in each area. The proposed method was applied for an appraisal study on an oil field in southwest Iran and, the optimum appraisal area is thereby determined based on the PAOI.",0,0,0
Oil Recovery,Optimization,"Ma, Zhiwei; Leung, Juliana Y.",Efficient tracking and estimation of solvent chamber development during warm solvent injection in heterogeneous reservoirs via machine learning,Heavy oil; Machine learning; Deep learning; Solvents; Interface tracking,HEAVY OIL-RECOVERY; STEAM-CHAMBER; GRAVITY-DRAINAGE; DATA ANALYTICS; SIMULATION; ENSEMBLE; OPTIMIZATION; PERFORMANCE; ALGORITHM; EVOLUTION,"Warm solvent injection (WSI) has been proposed as a promising alternative to steam-based methods for bitumen recovery, due to its potential to reduce greenhouse gas emissions and environmental footprint. It involves injecting heated vaporized solvent to reduce the viscosity of bitumen via solvent diffusion and latent heat transfer. The presence of reservoir heterogeneity caused by shale barriers is a severe concern for the success of the WSI because the conformance of solvent chamber advancement can be compromised. However, the efficient estimation and tracking methods for solvent chamber growth and propagation in heterogeneous reservoirs have not been widely investigated in the past. To fill this gap, this work proposes a novel machine learning-based approach to efficiently track solvent chamber positions in heterogeneous reservoirs for the WSI process. From a large training dataset consisting of numerous synthetic heterogeneous models and their simulation results, the input features and output parameters are extracted from oil production time-series data and the dynamic evolution of solvent chamber, respectively. A convolutional neural network (CNN) is implemented to dynamically track solvent chamber positions by correlating the extracted inputs and outputs. The estimation results are reliable and accurate for both scenarios where the shale barriers are either regularly or irregularly shaped with high conformance index (CI). Only production data is used to assess the conformance of solvent chamber advancement, which is an important consideration in operations design and real-time optimization. The presented workflow offers a novel alternative to infer the development of solvent chambers in heterogeneous reservoirs from production time-series data directly. This type of analysis could complement many existing monitoring techniques to deliver a more comprehensive inference of the distribution of shale heterogeneities in solvent-based bitumen recovery operations.",0,0,0
Oil Recovery,Optimization,"Muradov, Khafiz; Sefat, Morteza Haghighat; Dowlatabad, Mojtaba Moradi",Fast optimization of packer locations in wells with flow control completions,Intelligent or smart or advanced well completion; Flow control device; Annular flow isolation; Packer placement; Wellbore flow modelling,,"Intelligent (a.k.a. smart or 'flow control completion') well (i-well) technology is being successfully used in thousands of wells worldwide. Dozens of companies are involved in manufacturing, modelling, installing, and optimizing i-well equipment. I-wells have their completion intervals divided into zones with packers, followed by regulation of production or injection in each zone using flow control devices. In production wells this balances flow profile as well as reduces inflow of unwanted fluids, overall resulting in increased oil or gas recovery. Finding the optimal locations of any given number of packers that improve the long-term production performance is a complex problem with few solution attempts published to-date. This paper is the first to offer an easy-to-implement, comprehensive solution to this packer placement optimization problem. The complexity of this problem comes from the fact that ideally the i-well's designed flow control performance should be optimized together with its packer placement configuration, which makes it a largely multi-variable, mixed-integer optimization problem often requiring from thousands to millions of iterations to solve. Furthermore, where there is a long-term optimization objective, e.g. ultimate asset value or oil recovery, each evaluation of an i-well design requires a separate reservoir model run that takes time. This easily makes the i-well optimization problem insurmountable. The solution approach developed in this paper rests on two unique findings: the first one shows that optimality of a given i-well flow control performance reduces its subsequent, packer placement optimization problem to a simpler, perturbation problem which is much easier to solve. The second finding is a novel method relating an arbitrary, i-well flow performance to a mathematically equivalent nonlinear electric circuit performance. This allows the well performance to be fast-solved semi-analytically using methodology from the circuit design theory. Firstly in this paper, reduction of the i-well optimization problem to the packer placement -caused perturbation one is carried out by evaluating the impact of the annular flow isolation disturbance on the well/reservoir flow state. The relatively small weight of such disturbance on the scale of a simulation time-step is explained and further demonstrated on a test model. Secondly, an i-well flow model is presented as a nodal system, equivalent to a non-linear electric circuit, and subsequently solved using an approach adopted from the circuit theory. This solution is verified by numerical modelling. Lastly, these two findings enabled development of a fast, packer placement optimization algorithm that is described, verified, and finally successfully applied to a basic, test model. The packer placement optimization algorithm presented in this paper, as well as the novel i-well nodal analysis approach, complement and complete the multiple i-well performance optimization workflows published to-date, all of which use the simplifying 'infinite number of packers' assumption for the lack of anything better. This algorithm will be of immediate use to the well and reservoir engineers involved in design, installation, and evaluation of i-wells.",0,0,0
Oil Recovery,Optimization,"Botechia, Vinicius E.; de Lemos, Randerson Araujo; von Hohendorff Filho, Joao Carlos; Schiozer, Denis J.",Well and ICV management in a carbonate reservoir with high gas content,ICV; Field management; GOR; Numerical simulation,,"The management of oil fields that present high gas content is challenging, mainly in cases where this represents a bottleneck for oil production due to gas platform constraints. One way to deal with this problem is with the use of ICVs (Interval Control Valves), which enables the production to be controlled by zones in the wells. In this work, we propose a methodology using reactive control rules for producers and ICVs, with GOR as monitoring variable, to improve the economic performance of the field. We compare the management of the field in three ways: (a) well management by shutting down producers when they reach an uneconomic GOR limit, (b) the use of ICVs on-off type and (c) application of multi-position type ICVs. We extend the application of algorithm IDLHC (Iterative Discrete Latin Hypercube) for the optimization process in this context. This study is made in a synthetic simulation case (Lira1_2022) with characteristics of a Brazilian pre-salt carbonate field with karstic features, high CO2 content and using WAG (Water-Alternate-Gas) injection as recovery mechanism. The results demonstrated that the use of ICVs has a great potential to increase the performance of the field, both in economic and production indicators, when compared to well shut-in management. Both ICV on-off and multi-position types achieved similar results, with a slight advantage to the multi-position type ICVs. The improvement in the field's performance was mainly caused by the interference among zones and wells, in which the closure of less productive wells, or zones, reflected in improvements in other more productive wells.",0,0,0
Oil Recovery,Optimization,"Shojaiepour, Mohammadali; Rashidi, Fariborz; Dabir, Bahram; Amirsardari, Mahdi",A treatment protocol for controlling gas oil ratio in heterogeneous carbonate reservoirs by foam injection: Case study simulation,Foam injection; Gas channeling; Gas overriding; Gas oil ratio; Heterogeneous carbonate reservoir; Production well treatment,RECOVERY,"In this study, foam is selected to treat production wells of heterogeneous reservoirs that are suffering from high amounts of gas oil ratio (GOR). To this end, a numerical study is carried out by injecting foam through the perforations that produce high amounts of gas to block the gas path and allow much more oil to be simultaneously produced from the remaining perforations by applying a new technology in well completion. For this purpose, three heterogeneous synthetic base sectors are simulated in which large amounts of injected gas are produced from the upper, middle and lower perforations of the producing well, known as gas overriding, gas channeling-midriding and gas channeling-underriding, respectively. Since Kv/Kh is an important, decisive and effective parameter, different values of it have been considered for each of three base sector models including 0.001, 0.01, 0.1, 0.3, 0.5, 0.7, 0.9 and 1.0. Then, depending on the magnitude of Kv/Kh, the most optimal treatment method is sensitivity analyzed. In the following, foam injection parameters, e.g. surfactant concentration, depth of packer set, foam injection sequence and foam injection rate are sensitivity analyzed. Also, the phenomenon of gas cross-flow during the treatment process is investigated. The simulation results show that if after some time following well treatment, the GOR level increased, it is suggested to take a production test to determine what length of the production well below the packer produces lots of gas to set the packer at the lower depth and inject a larger volume of foam to block that gas path so that the GOR is reduced. The results also conclude that the magnitude of Kv/Kh on one hand and the location of gas entry to the production well on the other hand play a key role in the selection of the best treatment scenario in heterogeneous reservoirs. This has led to presenting a protocol for treatment of high GOR production wells in a wide range of reservoirs based on anisotropy ratios. Finally, in order to validate the protocol, a real specific sector of a heterogeneous carbonate reservoir located in the Middle East, in which the GOR level has increased, is simulated and treated. The results indicate that the protocol is efficient and causes a reduction in GOR by 60%.",0,0,0
Oil Recovery,Optimization,"Angga, I. Gusti Agung Gede; Stanko, Milan",Automated decision support methodology for early planning phase of a multi-reservoir field,Field development planning; Optimization; Proxy model; Mixed-integer linear programming; Uncertainty analysis,PRODUCTION OPTIMIZATION; NETWORK,"The field planning process is a crucial phase in the life of a hydrocarbon field when many design features must be decided upon. The field development team has the task of finding a configuration of these field design features which maximizes the value of the company's asset while considering several constraints. This paper presents a decision support methodology suitable for the early stage of the field planning process. The methodology is applied on a synthetic field called Safari. This field is characterized by having multiple reservoir units, where these reservoir units are non-communicating and have distinct properties. The reservoirs, namely Love, Nesehorn, and Sebra, have original oil-in-place (OOIP) of 75, 55, and 13 million sm(3), respectively. Both Love and Nesehorn have a permeability of 250 mD, whereas Sebra has a higher permeability of 450 mD. All these reservoirs lie 2500 m below the sea level with an initial reservoir pressure of 280 bara and an initial reservoir temperature of 80 degrees C. The main part of the methodology is a mathematical optimization that uses (i) proxy models to represent the flow performance of the production system and to estimate the development costs and (ii) piecewise linear (PWL) approximations to represent the non-linear functions. In this study, two optimization problems with the objective function to maximize plateau duration or net present value (NPV) are formulated and solved. The optimization models consider production schedule, drilling schedule, and recovery mechanism as the decision variables. Some constraints concerning production, injection, and drilling are also included in the optimization models. According to the optimization results, the objective value can be improved by considering more decision variables in the optimization problems. For example, including the drilling schedule and recovery mechanism as decision variables gives us 85% higher optimal NPV than optimizing the production schedule alone. Several investigations have been made to reduce the optimization runtime and to ensure the accuracy of the optimization results. Furthermore, the uncertainty of the optimization results has been quantified through uncertainty analyses. These analyses consider three uncertain parameters, i.e., OOIP, development costs, and oil price. Two approaches have been evaluated for conducting the uncertainty analysis, i.e., using the Latin hypercube sampling (LHS) method and using a probability tree. The uncertainty analysis using a probability tree is recommended because it requires less time to complete while produces similar results as the other approach.",0,0,0
Oil Recovery,Optimization,"Nieto-Alvarez, David A.; Luna-Rojero, Erick E.; Marin-Leon, Adlai; Ceron-Camacho, Ricardo; Nieto-Rivero, Carlos J. T.; Zamudio-Rivera, Luis S.",Static adsorption and mathematical model applied in EOR using a supramolecular surfactant,Static adsorption; Supramolecular surfactant; Adsorption model; EOR,OIL-RECOVERY; FOAM STABILITY; ZWITTERIONIC SURFACTANT; INTERFACIAL-TENSION; LIMESTONE; MINERALS; BEHAVIOR; ISOTHERM,"Typical adsorption isotherms show the characteristic Langmuir behavior. However, in the presence of a supramolecular surfactant, its corresponding adsorption isotherms, exhibiting atypical decrement behavior. The static adsorption results on limestone and dolomite show maximum values of 2.40 and 5.98 mg(surfactant)/grock, respectively. For explaining this behavior, was developed a new modified mathematical adsorption model, (d Gamma/dt) (ads) = k(ads)c(Gamma(infinity) - Gamma) - k(cmc)(c - c(cmc))(n)Gamma H(c - c(cmc)). This model describes the adsorption isotherms in two ads regions: the first one corresponds to the conventional adsorption increase and the second to decay adsorption phenomena. This decrement behavior is mainly due to the ultra-high salinity and the monomer reversible arrow micelle reversible arrow vesicle equilibrium in connate water. The new model shows the better fitting with r(2) = 0.9743 for limestone and r(2) = 0.9668 for dolomite, respect to the Langmuir model r(2) = 0.8556. Which represents the accuracy with the experimental values in the adsorption isotherm. Also, it is highlighted the significance of the information provided by the new static adsorption Langmuir mathematical model. That establishes criteria for using a chemical in enhanced oil recovery processes. From the data in the adsorption profile, the optimal concentration for the adsorption process occurs between 1800 and 2000 ppm of supramolecular surfactant. The enhanced oil recovery experiment in ultra-high salinity and hardness is better with an increase in the temperature: 8% at 80 degrees C, 15% at 90 degrees C and 20% at 100 degrees C.",0,0,0
Oil Recovery,Optimization,"Afanasyev, Andrey; Andreeva, Anna; Chernova, Anna",Influence of oil field production life on optimal CO2 flooding strategies: Insight from the microscopic displacement efficiency,CO2 flooding; Immiscible gas injection; WAG process; Optimization; Production life; Net present value,CARBON-DIOXIDE; RECOVERY; STORAGE; EQUATION,"We investigate the influence of the microscopic displacement processes on optimal gas flooding strategies. We couple a 1-D compositional reservoir model with an economic model of the flooding to assess profitability of the strategies. In general, we aim at the net present value maximization, although the oil recovery and CO2 storage efficiencies are also estimated. Under certain assumptions, we reduce the number of parameters controlling selection of optimal strategy to just a few dimensionless quantities characterizing both physical and economic processes. We show that the production life of oil fields should not be fixed in optimization studies, especially at low oil prices. A significantly larger net present value can be achieved by varying the reservoir lifetime in addition to the injection rates and volumes and other well controls. Herewith, the optimal strategy can differ from that in the case of a presumed production time. We conclude that waterflooding is the optimal recovery method if the injection rate is low, whereas gas (WAG) flooding applied as a primary method and followed by waterflooding is most optimal for large injection rates. Gas flooding applied as the tertiary recovery method is most optimal for an intermediate range of the rates. In the latter case, gas injection should begin much earlier than water breaks through to producing wells. Finally, we investigate how oil price influences the range of parameters suitable for gas injection.",0,0,1
Oil Recovery,Optimization,"Monette, Matthew; Nguyen, Quoc P.",Investigation of the effect of gas compositions on low-tension-gas flooding,Foam; Microemulsion; Low tension gas flood; Enhanced oil recovery; Sandstone reservoirs,FOAM STABILITY; TEMPERATURE; PRESSURE,"Gas floods have long been used for enhanced oil recovery, however they often times require miscible conditions within the reservoir to be successful. If this reservoir has been depleted and no longer contains the internal pressure to achieve these miscible conditions, an enhanced oil recovery technique known as Low Tension Gas (LTG) may be a better alternative that has been proven to increase oil recovery. This LTG process is a technique which involves either co-injection or alternating injection of gas and an optimized aqueous surfactant solution to both improve mobility control and reduce the interfacial tension between the oil and aqueous phases. When paired with specifically selected surfactants, the injected gas will create an in-situ generated foam which increases the apparent viscosity and acts as a mobility control agent to improve sweep efficiency. The optimized surfactant formulation also has the ability to generate ultra-low interfacial tension between the oil and aqueous phases. This reduced IFT allows the previously trapped oil to become mobile and the added mobility control from the foam better allows for this mobile oil to exit the porous media. The impact of hydrocarbon gas as the co-injected gas was investigated and found to be not only compatible with, but ultimately beneficial to the LTG process. The use of hydrocarbon gas at elevated pressures had a notable impact on phase behavior by slightly lowering the optimum salinity, while significantly increasing the solubilization ratio. This increase in solubilization ratio corresponds to a lower IFT experienced between the oil and aqueous phases, leading to improved oil recovery. This investigation also noted that in the presence of Type I microemulsion, foams created using a hydrocarbon gas composition, appeared to produce a slightly lower foam strength than that of previously used nitrogen. However this slight decrease in foam strength was more than offset by the significant increase in solubilization ratio. Using different hydrocarbon gas compositions as the injected gas during a series of corefloods presented an increase in both the recovery rate and ultimate recovery. This suggests that repurposing produced hydrocarbon gas may not only be the environmentally responsible decision, but also economically advantageous as this may allow for a decrease in surfactant costs used within a Low Tension Gas flood while still achieving the same improved oil recovery.",0,0,1
Oil Recovery,Optimization,"Altaheini, Suleiman; Mostaghimi, Peyman; Clark, Stuart R.",Incorporating adaptive well conditions into numerical reservoir simulators constrained by well and reservoir performance data,Adaptive well control; Adaptive well conditions; Water flooding; Improved oil recovery; Extended well lifetime,OPTIMAL INJECTION POLICIES; ENHANCED OIL-RECOVERY; OPTIMIZATION; PLACEMENT; ALGORITHM,"Using fixed boundary conditions has always been the way wells are modelled in reservoir simulators for prediction runs. This commonly results in oil wells being shut-in due to increasing production of water or gas or triggering a workover option shutting-in a section of the wells perforated interval. These actions are late reactive actions instead of being proactive actions that can help prolong a wells life. In actual field operations, well flow rates and bottomhole pressures are often adjusted to better suit reservoir management strategies and control water and gas production. This paper introduces a novel yet simple implementation of adaptive well conditions that updates well boundary conditions based on wellbore or near-wellbore performance. This methodology can be executed using a commercial simulator alongside a small instructing application, or internally integrated as done here with an inhouse reservoir simulator built to present this work as proof of concept. Three case studies are presented in this paper with increasing complexity. We show that an improvement in the amount of recovered oil, an increase in the lifetime of assets, and a reduction of produced water and gas are all possible with adaptive well controls. In one of the three cases, adaptive well controls resulted in an oil recovery increase as high as 20%. We also discuss the differences between well-data and reservoir-data dependencies of the adaptive well-condition algorithms in terms of dynamic response and physical application. Implementing adaptive well controls can help in reconsidering business plans by reducing water and gas production and avoiding early abandonment of wells. It was also considered that one of the main advantages of adaptive well conditions is the potentially significant reduction in number of variables for future optimization studies due to the elimination of control steps.",0,0,1
Oil Recovery,Optimization,"Aboelkhair, Hamed; Diaz, Pedro; Attia, Attia",Biosurfactant production using Egyptian oil fields indigenous bacteria for microbial enhanced oil recovery,Microbial enhanced oil recovery; Indigenous bacteria; Biosurfactant; Bacillus subtilis; Surface activity; Critical micelle concentration,BACILLUS-SUBTILIS; SURFACTANT; LICHENIFORMIS; OPTIMIZATION; WETTABILITY; HYDROCARBON; INJECTION; MOLASSES; STRAINS,"Biosurfactant production is one of the most efficient mechanisms in microbial enhanced oil recovery (MEOR) processes. This work investigates the production of biosurfactants by indigenous bacteria isolated from Egyptian oil fields, and how to optimize these produced biosurfactants for MEOR. 59 Egyptian oil reservoirs were screened to evaluate the potential applicability of MEOR processes, based on their rock and fluid properties. Results showed that 8 reservoirs from the Gulf of Suez and 3 reservoirs from the Western Desert had the potential to MEOR. Combined analysis of morphological, and biochemical characterization was performed on the 11 bacterial strains isolated from different crude oil samples collected from the reservoirs that have the potential to MEOR process to identify their types. Bacillus spp, a bacilli species that can produce biosurfactants, was selected for further studies. To optimize the surface activity of the produced biosurfactant, ten different reported nutrient media, and a new proposed nutrient media were examined. Bacillus spp has shown the ability to produce a very active biosurfactant that reduced the surface tension of water from 71.8 +/- 1.9 mN/m to 25.7 +/- 1.2 mN/m, and the interfacial tension of water against kerosene from 48.4 +/- 2.1 mN/m to 0.38 +/- 0.07 mN/m at Critical Micelle Concentration (CMC) of 0.04 +/- 0.01 g/l, in a medium supplemented by the new proposed nutrient medium H. The growth rate of Bacillus spp was studied, and it was found it reached its maximum (OD600nm 2.59 +/- 0.16) after 24 h of incubation. Biosurfactant production has no significant change in its surface activity over a wide range of temperature range up to 120 degrees C, which means the studied species Bacillus spp is a thermophilic bacterium. Bacillus spp grew well in the presence of high salt concentration up to 20% (w/v) NaCl, the optimal surface activity was obtained in the range of 0-2% (w/v) NaCl, and at pH 7. The emulsification activity of the produced biosurfactant was examined, and it reached the maximum (69.6 + 1.5%) against kerosene at temperature 25 degrees C, Salinity 0% (w/v) NaCl (distilled water), and pH 7. The produced biosurfactant was purified and extracted by acid precipitation method, and the biosurfactant yield of the purified compound was found to be 2.8 +/- 0.3 g/l. Finally, the core-flooding experiments were conducted to investigate the effect of produced biosurfactants by Bacillus subtilis in oil recovery. The obtained results reveal the potential of Bacillus spp to grow in the new proposed medium H and produce effective and efficient biosurfactants that enhanced oil recovery by 25.19-39.35% of additional oil over the water flooding residual oil saturation in the studied cores and retain more than 60% of its surface activity under harsh conditions and that are relevant to Microbial Enhanced Oil Recovery, MEOR.",0,0,2
Oil Recovery,Optimization,"Khan, Mohammad Yunus; Mandal, Ajay",Analytical model of incremental oil recovery as a function of WAG ratio and tapered WAG ratio benefits over uniform WAG ratio for heterogeneous reservoir,EOR; Analytical model; Tapered WAG; Uniform WAG; Reservoirheterogeneity; WAG incremental oil recovery; Gas utilization factor,GAS; INJECTION; EFFICIENCY; DESIGN; DISPLACEMENTS; OPTIMIZATION,"The water-alternating-gas (WAG) operating scheme and reservoir permeability heterogeneity are the main crucial parameters, which highlyaffect WAG displacement process. The novelty of this article lies in the development of an analytical model for WAG incremental oil recovery as function of WAG ratio, viscous gravity ratio and mobility ratio for the stratified heterogeneous reservoir. We have investigated the effect WAG ratio on WAG incremental oil recovery with variation horizontal permeability heterogeneity, vertical permeability anisotropy and dip angle of the reservoir. The critical operating parameters investigations were carried to optimize WAG displacement process in both homogeneous and heterogeneous reservoirs. Finally, we have estimated all the benefits of the most suitable techno-economical WAG operating scheme as tapered WAG (TWAG) over uniform WAG (UWAG). The developed analytical model showsreasonably similar results as numerical simulation. The results of the analytical and numerical analysisshow that the incremental oil recovery accelerated bya decrease WAG ratio. However, this effect is more noticeable at high viscous gravity (VGR). The increase in reservoir dip angle subsequently increases vertical and displacement sweep efficiencies compared to the horizontal reservoir for different WAG ratio. While increasing WAG ratio decreases vertical sweep and increases displacement sweep of inclined reservoir compared to the horizontal reservoir. The increase of oil recoverywas observed by higher Kv/ Kh with a lower WAG ratio. However, this effect is less evident at lower Kv/Kh. The WAG ratio with a higher proportion of water is beneficial for the heterogeneous reservoir. The infill implemented before WAG start shows faster oil recovery compared to WAG start first then infill implemented in the heterogeneous reservoir. The TWAG incremental recovery over water flood was 18% in homogeneous and 8% in heterogeneous reservoirs, while EUR was approximately similar to UWAG. The TWAG shows more efficient techno-economic benefits over UWAG due to better economics, faster oil recovery rate, more efficient use of injected gas and reduces response time in both homogeneous and heterogeneous reservoirs.",0,0,2
Oil Recovery,Optimization,"Xu, Jianchun; Zhou, Wenxin; Li, Hangyu; Wang, Xiaopu; Liu, Shuyang; Fan, Ling",Stochastic simplex approximation gradient for reservoir production optimization: Algorithm testing and parameter analysis,Stochastic simplex approximation gradient; Production optimization; Algorithm testing; Computational cost; Reservoir numerical simulation,WELL PLACEMENT OPTIMIZATION; CYCLE PRODUCTION OPTIMIZATION; ALTERNATING-GAS-INJECTION,"Production optimization is an effective technique to maximize the oil recovery or the net present value in reservoir development. Recently, the stochastic simplex approximation gradient (StoSAG) optimization algorithm draws significant attention in the optimization algorithm family. It shows high searching quality in largescale engineering problems. However, its optimization performance and features are not fully understood. This study evaluated and analyzed the influence of some key parameters related to the optimization process of StoSAG including the ensemble size to estimate the approximation gradient, the step size, the cut number, the perturbation size, and the initial position by using 47 mathematical benchmark functions. Statistical analysis was employed to diminish the randomness of the algorithm. The quality of the optimization results, the convergence, and the computational time consuming were analyzed and compared. The parameter selection strategy was presented. The results showed that a larger ensemble size was not always favorable to obtain better optimization results. The increase of the search step size was favorable to escape from the local optimum. A large step size needed to match a large cut number. The increase of cut number was beneficial to increase the local searchability, but also made the algorithm more easily fall into the local optimum. The random initial position was beneficial to find the global optimal point. Moreover, the effectiveness of the parameter selection strategy was tested by a classical reservoir production optimization example. The final net present value (NPV) for water flooding reservoir production optimization substantially increased, which indicated the excellent performance of StoSAG by adjusting the key parameters.",0,0,2
Oil Recovery,Optimization,"Tian, Xiaoming; Voskov, Denis",p Efficient application of stochastic Discrete Well Affinity (DiWA) proxy model with adjoint gradients for production forecast,DiWA model; Adjoint gradient; Data-driven model; Proxy model; DARTS,OPERATOR-BASED LINEARIZATION; OPTIMAL INJECTION POLICIES; ENHANCED OIL-RECOVERY; RESERVOIR SIMULATION; FLOW; OPTIMIZATION,"In this paper, we describe adjoint gradient formulation for the Operator-Based Linearization modeling approach. Adjoint gradients are implemented in Delft Advanced Research Terra Simulator (DARTS) framework and applied for history matching using a proxy methodology. Due to the application of adjoint gradients, the computational efficiency of the discrete well affinity (DiWA) proxy model for production forecast is significantly improved. That allows us to derive several important extensions. The proxy methodology is further extended and validated for 3D three-phase black-oil problems. The results show that the gradient-based regression can provide good history matching and reconstruct a true petrophysical characterization when the initial guess is generated based on highly reliable geological information. For cases with a limited or not sufficient geological characterization, an efficient stochastic application of DiWA proxy model is proposed. This approach consists of massive sampling procedures for collecting different realizations based on high-fidelity statistics with filtering. These realizations are generated stochastically because they are not conditioned to any production information but the basic geological statistics of the reservoir. The trained DiWA proxy model demonstrates a small deviation between the model response and the observation data. When applying the refined DiWA model for the training, the error between the model response and observation data can be further reduced. The forecast based on the trained model has slightly larger variability but the deviation is still reasonable. The enhanced DiWA methodology presents an efficient and robust technique for creating an ensemble of stochastic proxy models that can be used in production forecast, flow diagnostic, and optimization.",0,0,2
Oil Recovery,Optimization,"Monteiro, Lua; Baptista-Pereira, Catarina; Azevedo, Leonardo",Sensitivity analysis of injection parameters in steam assisted gravity drainage under geological uncertainty,Steam-assisted gravity drainage; Heavy oil; Sensitivity analysis; Geological uncertainty; Reservoir simulation; Optimization,OPTIMIZATION; SAGD; OIL; SIMULATION; RESERVOIR,"Steam-assisted gravity drainage (SAGD) is a challenging enhanced oil recovery technique that requires proper parameterization in terms of well geometry and steam injection parameters as these parameters are highly dependent on the reservoir geology and fluid characteristics (e.g., net pay variation, water saturation). Injection rate and pressure, temperature, steam quality, lean zone, gas zone, water saturation, and wellbore hydraulics are among the most important engineering parameters of SAGD. This work focuses in the sensitivity analysis under geological uncertainty of some operational parameters, such as: injection rate, temperature, steam quality and pressure. To reach this objective we build a realistic reservoir model with multiple geological settings and descriptions. Moreover, two complementary approaches were studied: i) a deterministic sensitivity analysis relying on a factorial design matrix and ii) a stochastic analysis using particle swarm optimization. There are several key geological uncertainties in SAGD, such as net pay variation, inclined heterolithic stratification (IHS) presence, high water saturation in reservoirs, bottom water issues, and gas cap problems. This work focuses on the role of porosity and permeability in oil production, as these impact these geological properties. To reach this objective, two specific groups of ten different porosity and permeability pairs of geostatistical realizations were generated using Direct Sequence Simulation and Co-simulation. Group 1 used the same variogram model for 10 random seeds; and Group 2 used a combination of values that adopted a simultaneous and a random variation, which were assigned to the seed and to the variogram. We opted by a reservoir model that mimics an anticlinal reservoir, as it proved to be a determining factor for the low levels of Net Present Value (NPV) when compared to other geological scenarios. Within the four most commonly studied parameters in SAGD projects, the association of deterministic versus stochastic multi-objective analysis allowed to accurately validate injection rate as the most relevant parameter. Regarding the geological uncertainties, Group 1 showed that for a certain porosity distribution and permeability orientation, the random origin of these distribution maps eventually attributed a higher NPV uncertain. On the other hand, in Group 2, the simultaneous spatial and seed variation provided less uncertainty associated to NPV.",0,0,2
Oil Recovery,Porous Media,"Hasanzadeh, Maryam; Azin, Reza; Fatehi, Rouhollah; Zendehboudi, Sohrab",New insights into forced and free fall gravity drainage performance in a fractured physical model,Fractured physical model; Gas injection; Recovery factor; Free fall gravity drainage; Forced gravity drainage,TERTIARY OIL-RECOVERY; POROUS-MEDIA; WETTABILITY; DISPLACEMENT; SECONDARY; FLOW,"Gravity is one of the major driving forces for fluid flow in naturally fractured reservoirs. Gravity drainage appears to be a vital recovery mechanism over the oil production process in a majority of fractured reserves. In this paper, free-fall gravity drainage (FFGD) and forced gravity drainage (FGD) production approaches are investigated through employing a new fractured sand pack with a rectangular geometry. Distilled water and condensate are used as the wetting phase. Nitrogen, carbon dioxide, and air are also utilized as the non-wetting phase. A systematic sensitivity analysis is conducted to find the effects of the key factors such as fracture blockage, injection rate, dip angle, and type of wetting phase and injection fluid on the performance of FFGD and FGD processes. Also, a numerical simulation is performed to simulate the experiments. Results reveal that the FGD has a better performance under controlled process conditions, compared to the FFGD so that gas injection with a controlled rate improves the recovery. Moreover, it was found that increasing the gas injection rate improves the recovery factor (RF) of wetting-phase when the up and bottom sides of the fractures are blocked; the RF is decreased in the case with open fracture sides. The recovery of the wetting phase decreases in both FFGD and FGD modes when the porous system has a deviation from the vertical orientation. According to the study outcomes, the immiscible gas-assisted gravity drainage offers a higher condensate recovery, compared to water recovery, due to lower viscosity and interfacial tension (IFT) of the condensate phase. The comparison of the experimental data and simulation results implies that the simulation approach can satisfactorily predict the performance of the FGD process. Based on the error analysis, there is a good match between the simulation results and the experimental measurements; the fluid pair of CO2-condensate exhibits the highest accuracy with an R-squared of 0.9961 and an average relative error (ARE) of 0.0054.",0,0,0
Oil Recovery,Porous Media,"Ligeiro, Tayanne S.; Vaz, Alexandre; Chequer, Larissa",Forecasting the impact of formation damage on relative permeability during low-salinity waterflooding,Low-salinity waterflooding; Fines migration; Relative permeability; Formation damage; Particle detachment; Coreflood experiments,FINES-MIGRATION; POROUS-MEDIA; INJECTIVITY DECLINE; SWEEP EFFICIENCY; SLOW MIGRATION; OIL-RECOVERY; FLOW; PARTICLES; TRANSPORT; RELEASE,"Low-salinity waterflooding is considered to be an advanced oil recovery method, but the main mechanism behind the increase in oil recovery factor is still under investigation. Fines migration has been recognized to be one of the mechanisms responsible for the increase in oil production. In this case, the increase in oil recovery happens as a result of increased sweep efficiency and consequent reduction of residual oil. The release of particles due to reduction of electrostatic forces results in flux diversion to previously unswept areas in the reservoir, increasing oil recovery. This paper provides a better understanding of the effects of formation damage during low-salinity water injection in Berea sandstones and proposes a methodology to forecast its effects on water relative permeability. We have performed one- and two-phase flow coreflood experiments with varying salinity of the injected solution. The effluent was analysed for salinity, pH and particle concentration. The laboratory data was treated using a mathematical model that accounts for permeability impairment during low-salinity waterflooding due to fines detachment, migration and capture in small pore throats. The parameters of the model were used to predict the impact of formation damage on the water relative permeability during two-phase flow. The mathematical model matched the laboratory data for pressure drop and particle concentration in the outlet with great accuracy. A methodology to predict the impact of formation damage in two-phase flow using one-phase flow data was proposed. A good agreement between the predicted and the measured water relative permeabilities was obtained. The forecasted water relative permeability curve was able to reproduce the non-monotonic behaviour of water relative permeability due to low-salinity water injection.",0,0,0
Oil Recovery,Porous Media,"Baghooee, Hadise; Montel, Francois; Galliero, Guillaume; Yan, Wei; Shapiro, Alexander",A new approach to thermal segregation in petroleum reservoirs: Algorithm and case studies,Gravity segregation; Thermal gradient; Thermodiffusion; Numerical algorithm; Reservoir cases,,"In many petroleum reservoirs, the fluid properties vary through the reservoir thickness. Variation of the composition, i.e. compositional grading, can affect reserve estimation, production and enhanced oil recovery strategies. Apart from gravity, the geothermal gradient may also contribute to the fluid distribution. Thermodiffusion is the governing phenomenon determining the contribution of the geothermal gradient. The non-equilibrium thermodynamics models are applied for the calculation of the compositional gradients under the varying temperature. In order to determine the variations in pressure and composition with depth and to be able to indicate if/where a gas-oil contact exists, we have developed a model based on the principles of irreversible thermodynamics, within the approach to thermodiffusion in porous media proposed by Montel et al. (2019). Based on the relationships where pressure, chemical potentials, and thermal gradient are linked, the distribution of hydrocarbons in a petroleum reservoir is described. A computational algorithm accounting for non-ideality of the mixture, characterization, and phase transitions has been developed. The model and the computational procedure have been validated by comparison with the case studies reported in the literature for a North Sea reservoir, and with sample component distributions produced by application of molecular dynamics simulations. It has been shown that the model is capable of predicting the fluid distributions with depth with no or a minimum of adjustable parameters. The thermal gradient modifies the predicted fluid distributions making them closer to the observed data points. Depending on the mixture composition, the thermal diffusion may either enforce the effect of gravity or counteract it.",0,0,0
Oil Recovery,Porous Media,"Kalam, Shams; Yousuf, Usama; Abu-Khamsin, Sidqi A.; Bin Waheed, Umair; Khan, Rizwan Ahmed",An ANN model to predict oil recovery from a 5-spot waterflood of a heterogeneous reservoir,ANN; ANFIS; SVR; Waterflooding,ARTIFICIAL NEURAL-NETWORK; POROUS-MEDIA; PERFORMANCE; SELECTION; GAS; INTELLIGENCE; REGRESSION; AKAIKE; FLOW,"Waterflooding is a secondary oil recovery technique in which water is injected into an underground oil reservoir to maintain the reservoir pressure and boost oil recovery. The performance of a waterflood depends on several factors such as reservoir heterogeneity, reservoir fluid properties, flood pattern, etc. Most of the models developed to predict waterflood performance are either for linear systems or involve simplified assumptions for nonlinear systems. In this study, we propose a novel, artificial neural network (ANN) model comprised of two hidden layers with 256 neurons each for the performance prediction of a 5-spot pattern waterflood in a heterogeneous reservoir at and beyond water breakthrough. The proposed model can be applied to estimate movable oil recovery efficiency of the waterflood (RFM) as a function of Dykstra-Parsons permeability variation coefficient (V), mobility ratio (M), permeability anisotropy ratio (kz/kx), production water cut (fw), a simple indicator of wettability (WI), and oil/water density ratio (DR) within reasonable accuracy. The MAPE of the proposed model was -4% and -5% using training and testing data, respectively. Our ANN model recommendation is based on a detailed comparative study against other popular soft computing models, such as adaptive neuro-fuzzy inference system (ANFIS) and support vector regression (SVR). Based on the accuracy and computational efficiency, the ANN model outperforms ANFIS and SVR. AIC and BIC of the proposed ANN model were also the lowest among all applied soft computing tools. The proposed model is tested on two real field cases and compared with a semianalytical model and an empirical correlation. The presented model shows good agreement with the real field data. The trained ANN model, proposed here, saves computational time in forecasting the waterflood performance compared to a reservoir simulator.",0,0,1
Oil Recovery,Porous Media,"Monette, Matthew; Nguyen, Quoc P.",Investigation of the effect of gas compositions on low-tension-gas flooding,Foam; Microemulsion; Low tension gas flood; Enhanced oil recovery; Sandstone reservoirs,FOAM STABILITY; TEMPERATURE; PRESSURE,"Gas floods have long been used for enhanced oil recovery, however they often times require miscible conditions within the reservoir to be successful. If this reservoir has been depleted and no longer contains the internal pressure to achieve these miscible conditions, an enhanced oil recovery technique known as Low Tension Gas (LTG) may be a better alternative that has been proven to increase oil recovery. This LTG process is a technique which involves either co-injection or alternating injection of gas and an optimized aqueous surfactant solution to both improve mobility control and reduce the interfacial tension between the oil and aqueous phases. When paired with specifically selected surfactants, the injected gas will create an in-situ generated foam which increases the apparent viscosity and acts as a mobility control agent to improve sweep efficiency. The optimized surfactant formulation also has the ability to generate ultra-low interfacial tension between the oil and aqueous phases. This reduced IFT allows the previously trapped oil to become mobile and the added mobility control from the foam better allows for this mobile oil to exit the porous media. The impact of hydrocarbon gas as the co-injected gas was investigated and found to be not only compatible with, but ultimately beneficial to the LTG process. The use of hydrocarbon gas at elevated pressures had a notable impact on phase behavior by slightly lowering the optimum salinity, while significantly increasing the solubilization ratio. This increase in solubilization ratio corresponds to a lower IFT experienced between the oil and aqueous phases, leading to improved oil recovery. This investigation also noted that in the presence of Type I microemulsion, foams created using a hydrocarbon gas composition, appeared to produce a slightly lower foam strength than that of previously used nitrogen. However this slight decrease in foam strength was more than offset by the significant increase in solubilization ratio. Using different hydrocarbon gas compositions as the injected gas during a series of corefloods presented an increase in both the recovery rate and ultimate recovery. This suggests that repurposing produced hydrocarbon gas may not only be the environmentally responsible decision, but also economically advantageous as this may allow for a decrease in surfactant costs used within a Low Tension Gas flood while still achieving the same improved oil recovery.",0,0,1
Oil Recovery,Porous Media,"Tan, Fengqi; Liu, Wentao; Ma, Chunmiao; Cheng, Hongjie; Li, Xiankun; Zhang, Chaoliang",Classification methods of conglomerate reservoirs based on the adsorption and retention law of surfactant-polymer binary systems,Conglomerate reservoir; Surfactant-polymer flooding; Absorption capacity; Micropore structure; Reservoir classification,OIL-RECOVERY; CAPILLARY NUMBER; REMAINING OIL; TEMPERATURE,"Factors such as clay minerals and micropore structure can lead to the adsorption and retention of chemical agents when the components of surfactant-polymer systems enter porous media. This study aims to clarify the influence of adsorption and retention of surfactant-polymer components on reservoir permeability and oil displacement efficiency and then classify the reservoirs into types. The natural cores of conglomerate reservoirs from the Badaowan Formation in the 7th block are selected as research objects to reveal the adsorption law of surfactantpolymer components on different minerals and different micro pores through the dynamic oil displacement method based on physical model and the N element calibration method. Experimental results show that the adsorption capacity of clay minerals for surfactant-polymer components is significantly higher than that of carbonate and skeleton minerals, and different clay minerals differ in adsorption capacity for surfactant-polymer components depending on their cation exchange capacity and end surface adsorption activity. In addition, the adsorption and retention capacities of reservoirs for surfactant-polymer components are closely related to the type and content of clay minerals. The combination type of clay minerals controls the adsorption activity of surfactant-polymer components, and the values of polymer and the surfactant are quantitatively calculated to be 11.3 and 21.4 mg/g, respectively. The adsorption strength of surfactant-polymer components is controlled by the content of clay minerals. With increasing clay content, the adsorption strength of the polymer ranges from 0.5 to 2.5 mg/cm3, and that of the surfactant ranges from 1.0 to 4.5 mg/cm3. On this basis, the ""N element calibration method"" is used to determine the occurrence state and content of chemical agents in micropores for different permeability samples after surfactant-polymer binary flooding. Research results show that the polymer and surfactant components mainly have two types of occurrence form in micropores, including the complex pores accumulated by clay minerals and the intersections of small pores and throats. With decreasing reservoir permeability, the number and content of detected N element gradually increase, indicating an increase in the adsorption and retention of polymer and surfactant, and the influence on the reservoir seepage capacity also increases. Finally, the conglomerate reservoirs in the Badaowan Formation from the 7th block are divided into four types after considering the influence of clay minerals and micropore structure on the adsorption and retention of surfactant-polymer components, and the reasonable classification of reservoir types can effectively enhance the oil recovery of surfactant-polymer binary flooding.",0,0,1
Oil Recovery,Porous Media,"Velasco-Lozano, Moises; Balhoff, Matthew T.",Modeling of early- and late-time countercurrent spontaneous imbibition in porous media: A semi-analytical approach,Countercurrent spontaneous imbibition; Porous media; Oil recovery; Early-time solution; Late-time solution; Universal scaling,OIL-RECOVERY; WATER,"Countercurrent spontaneous imbibition (SI) is an important flow mechanism to recover oil in water-wet porous media through capillarity. Experimental imbibition tests conducted in core samples show that oil recovery as a function of time occurs in a characteristic S-shaped curve, which describes the infinite-acting and the boundary-dominated regime. Although several dimensionless time groups have been proposed to model countercurrent SI in porous media, they fail to properly scale the results, causing inaccurate estimates of oil recovery. In this work, we present a new approach, using a hybrid solution, to model countercurrent SI for oil-water systems dominated by capillary forces. The infinite-acting regime is modeled by an early-time solution using a new dimensionless time group, which enables the correct scaling of imbibition results onto a universal single curve. To model the boundary-dominated regime, we introduce a late-time solution derived as a function of a characteristic distribution of saturation to estimate the flow behavior after the imbibing fluid reaches the no-flow boundary. The novelty of the model is that it enables the accurate estimation of fluid imbibition under the boundary-dominated regime, a flow condition critical to evaluate the true potential of countercurrent SI driven by capillarity for oil recovery in porous media. We verified the model against numerical simulations under a wide range of flow conditions relevant in water-oil systems, and used experimental data reported in the literature to validate our model. The solution presented provides an accurate approach to model countercurrent SI, which could be extended for dynamic conditions and the modeling of the flow of fluids in fractured media.",0,0,2
Oil Recovery,Porous Media,"Al Ghafri, Al Yaqathan; Mackay, Eric; Stephen, Karl",The relevance of the linear stability theory to the simulation of unstable immiscible viscous-dominated displacements in porous media,Instability predictor; Saffman-Taylor instability; End-point mobility ratio; Fractional flow analysis; Viscous oil; Polymer flooding; Correlated random field,MISCIBLE DISPLACEMENT; INSTABILITIES; MECHANISM; POLYMER; GROWTH; MODELS; FLUID,"The 2D governing equations for the immiscible two-phase flow admissible to linear stability analysis are inspected. The identification of the term v(ws)delta D-st in the generalized Saffman-Taylor criterion is key to the analysis. It can be regarded as a predictor that correlates with observed immiscible instability in terms of the rate of advancement of the viscous pattern, the number of small protrusions, and their roughness in a given heterogeneous domain described by a correlated random field. The predictor is extended, heuristically, for polymer flooding shock-wise and used to characterize the instability of the two shocks. The extension is validated by simulation. The instability of the primary shock is essential when considering the breakthrough recovery. In light of the instability predictor, the geometric interpretations of the fractional flow are essential to understand the stability enhancement of the primary shock over the Buckley-Leverett shock in water flooding. It is also concluded that the end-point mobility ratio does not directly control the immiscible instability. This conclusion was arrived at by fixing the end-point mobility ratios for three sets of relative permeability curves, and yet noticeably different instabilities occur, both in transverse and correlated random fields. The criterion can predict the viscous instability in the laboratory experiments under certain flooding conditions and sample configurations. Concerning the instability in a field scale, the predictor is applicable if the field is regarded as a prototype of a given model experiment.",0,0,2
Oil Recovery,Porous Media,"Zheng, Lei; Nian, Yong-Le; Zhao, Rui; Cheng, Wen-Long",Prediction of multi-reservoir production for water injection well by using temperature logging data,Multi-reservoir production; Water injection well; Heat transfer model; Temperature logging data; Stochastic approximation method,HEAVY OIL; NUMERICAL-SIMULATION; PRODUCTION FORECAST; POROUS-MEDIA; FLOW-RATE; RECOVERY; MODEL; EXTRACTION; SYSTEMS,"In most cases, oil wells are completed and perforated to produce from multiple reservoirs. Thus, it is crucial to monitor production from each individual reservoir. Therefore, a new prediction method for multi-reservoir production by using temperature logging data is presented in this paper. Firstly, by coupling the wellbore and formation heat transfer with reservoirs heat transfer, a new comprehensive heat transfer model for the oil well with multiple reservoirs is established in this paper. Both the heat convection of two-phase flow in reservoir and vertical heat transfer between different reservoirs was considered in the model, and the relationship between flow rate distribution and temperature distribution could be specified by the model. Then based on the model, the stochastic approximation method was proposed to predict the multi-reservoir production through the temperature logging data. Lastly for a water injection well with five layered reservoirs and depth of 3500m, the production of each reservoir was predicted by the presented method. The results show that the temperature distribution simulated by the built model has a good agreement with the reference data. The estimation error of the total flow rate is less than 9% compared with the reference data, and the production of the five reservoirs accounted for 36%, 35%, 17%, 7% and 5% of the total production respectively.",0,0,2
Oil Recovery,Porous Media,"Beheshti, Elahe; Doryani, Hosein; Malayeri, Mohammad Reza; Riazi, Masoud",Asphaltene stability during heptane injection in a glass micromodel in the presence of Co3O4 nanoparticles,Nanoparticle; Asphaltene precipitation; Glass micromodel; Adsorption; Optimum concentration; Porous media,OIL; PRECIPITATION; DEPOSITION; ADSORPTION; RECOVERY; VISUALIZATION; DISPLACEMENT; AGGREGATION; OXIDATION; PRESSURE,"Severe challenges and difficulties in oil production may arise from asphaltene precipitation and deposition in porous media and upstream facilities. The investigation for a proper solution for such detrimental damages is indispensable for the oil industry. Nanoparticles, due to their unique properties of high degree of dispersibility and high adsorption affinity, may potentially be useful for hampering the asphaltene related problems to some extent. In this study, by the use of glass micromodels, the utilization of Co3O4 nanoparticles to stem asphaltene precipitation has been investigated. These nanoparticles were dispersed in synthetic solutions comprising of toluene, n-heptane and asphaltenes as well as crude oil. The prepared solutions were then subjected to n-heptane injection as asphaltene precipitator. The amount and extent of asphaltene precipitation and deposition in micromodels was then measured and analyzed. The results showed that Co3O4 nanoparticles positively affect asphaltene stability in both crude oil and synthetic solutions. However, it was found that once these nanoparticles adhere to glass surface, then intense asphaltene precipitation and deposition would take place. The impacts of nanoparticle concentration were also discerned through experiments for 0.01, 0.05 and 0.1 wt% concentrations of nanoparticles. It was obtained that generally, higher concentration of nanoparticles would reduce asphaltene precipitation intensity. However, due to very little difference between the efficiency of solutions containing 0.05 and 0.1 wt% in terms of increasing asphaltene stability, 0.05 wt% of dispersed nanoparticles was found to be the optimum concentration for preventing asphaltene precipitation and deposition. This study, for the first time, provides a micro visual study in order to observe the impacts of nanoparticles on the stability of asphaltene in crude oil and synthetic oil samples in a uniformly patterned glass micromodel.",0,0,3
Oil Recovery,Porous Media,"Male, Frank; Duncan, Ian J.",The paradox of increasing initial oil production but faster decline rates in fracking the Bakken Shale: Implications for long term productivity of tight oil plays,Energy forecasting; Unconventional oil; Hydraulic fracturing,WATER; GAS,"In the US, tight oil is the largest source of liquid hydrocarbons and has enabled the country to become the world's largest oil producer. The estimated ultimate recovery (EUR) and rate of production decline are key metrics in the evaluation of the future productivity of tight oil wells. We chose the Bakken Shale because of its high quality, publicly available data. Traditionally, well operators have estimated the EUR for each well from the initial production (IP), using empirical type curves to extrapolate to the ultimate production. From 2015 to 2018 the IP of the average Bakken well increased by approximately 50%. This increase resulted in claims by operators and in the academic literature that more intense hydraulic fracturing was increasing the average EUR of the Bakken play. At the same time, other observers claimed the wells declined much more rapidly than previous wells. This faster decline provided evidence for lower ultimate production from newer wells. The aim of this study was to understand the origin of these seemingly conflicting observations. A physics-based, scaling model was used to predict production from horizontal multi-stage fractured wells. The model for oil recovery is based on pressure diffusion through fractured porous media. The model assumes that the rock is incompressible, the permeability and oil saturation are constant, the water is incompressible, and the viscosity is slowly varying with space. The scaling model was applied to 13,444 wells. The EUR and terminal decline rate (TDR) were estimated from fitting production to our scaling model. Our study found that implementation of more intensive hydraulic fracturing resulted in higher IP and steeper terminal-production declines. Recently published results estimating the total production from the Bakken that include increased lifetime production commensurate with observed increases in average IP, significantly overestimate the long-term production potential of tight oil, both in the US and globally.",0,0,3
Oil Recovery,Porous Media,"Pashapouryeganeh, Farzad; Zargar, Ghasem; Takassi, Mohammad Ali; kadkhodaie, Ali; Rabiee, Ahmad",One-Pot synthesis of modified-cationic surfactants for enhanced oil recovery applications in carbonate reservoirs,Surfactant synthesis; Cationic surfactant; Quaternary ammonium salt; Wettability alteration; IFT reduction; Chemical enhanced oil recovery (CEOR),INTERFACIAL-TENSION BEHAVIOR; DETERMINING IONS CA2+; HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; POROUS-MEDIA; CHAIN-LENGTH; WET; MECHANISM; LIQUID,"In this study two cationic surfactants, dodecyltriethylammoniumbromide (C(12)TEAB) and hexadecyl-triethylammoniumbromide (C(16)TEAB) were prepared. The formation of synthezied surfactants were confirmed using FTIR and HNMR spectroscopy. Electrical conductivity, interfacial tension and surface tension methods were used to determine the critical micelle concentrations (CMC) of these surfactants. To understand the behavior of synthesized surfactants in harsh environments, the CMC was measured in deionized water (DIW), sea water and petroleum formation water. Using electrical conductivity technique, for C(12)TEAB surfactant the CMC values of 4000 ppm, 2000 ppm and 850 ppm were recorded in DIW, sea water and formation water respectively. For C(16)TEAB surfactant, the CMC values of 420 ppm, 190 ppm and 115 ppm were obtained in DIW, sea water and formation water respectively. The similar CMC results were obtained using the interfacial tension (IFT) and surface tension (ST) methods. Reduction of IFT between crude oil and formation water and also alteration of wettability of petroleum reservoir of carbonated rock from oil-wet (large contact angle) to water-wet (small contact angle) are two major factors affecting chemical enhanced oil recovery (EOR). Interfacial tension (IFT), surface tension (ST) and contact angle measurements were carried out using an IFT-PDSA-06 apparatus (Apex Technologies Company, Iran). The IFT and ST of these surfactants were also carried out in DIW, sea water and formation water. For C(12)TEAB surfactant, the IFT values of 0.051 mN/m, 0.036 mN/m and 0.023 mN/m were recorded in DIW, sea water and formation water respectively. The IFT values of 0.044 mN/m, 0.026 mN/m and 0.0126 mN/m were measured for C(16)TEAB surfactant in DIW, sea water and formation water respectively. The effect of temperature on IFT was studied for both surfactants. When temperature increases, IFT decreases. The reduction of IFT continues up to 55 degrees C, then the IFT increases with increasing temperature. For C(12)TEAB surfactant, the ST values of 44.9 mN/m, 38.8 mN/m and 31.8 mN/m were obtained in DIW, sea water and formation water respectively. In similar measurements for C(16)TEAB surfactant, the recorded ST values were 33.95; 32.9 and 32.22 mN/m in DIW, sea water and formation water respectively. In wettability alteration study both surfactants altered the contact angle from oil-wet to water-wet conditions. Using formation water and C(12)TEAB surfactant, the contact angle varied from 96.4 degrees to 54.5 degrees. In similar study using C(16)TEAB surfactant the contact angle changed from 92 degrees to 46.1 degrees. The contact angles of these surfactants in DIW and sea water were also measured and reported. The results of IFT and wettability studies demonstrated excellent potential application of synthesized surfactants in EOR process in carbonate petroleum reservoirs.",0,0,3
Oil Recovery,Porous Media,"Abiz, Mehdi Rezaei; Norouzi-Apourvari, Saeid; Jafari, Saeed; Schaffie, Mahin",The effect of subsurface factors on the performance of nanofluid-assisted enhanced oil recovery: Modeling and sensitivity analysis,Enhanced oil recovery; Nanoparticle transport; Porous media; Wettability alteration; Mobility control,POROUS-MEDIA ROLE; WETTABILITY ALTERATION; CARBON NANOTUBES; SOLUTION CHEMISTRY; 2-PHASE FLOW; TRANSPORT; NANOPARTICLES; RETENTION; STABILITY; OXIDE,"Successful implementation of nanofluid-assisted enhanced oil recovery (EOR) operation mainly depends on proper determination of the main factors that control both transport and retention of nano-sized particles in porous media. In this study, a new transport scheme using the kinetic Langmuir model was first developed and validated by some experimental data from the literature. This model was then used to investigate the effect of reservoir rock type, clay content, grain size, brine type, and reservoir temperature on distribution of nanoparticles on the rock surface and in the injected fluid in relation to EOR methods. Moreover, a two-phase approach was derived to simulate the effect of these parameters on both wettability alteration and mobility control. Results confirmed that the deposition tendency of silica nanoparticles on limestone is higher than that on sandstone. By increasing clay content, both surface area and deposition sites increases and consequently more nanoparticles were found to retain. In the case of polyethylene glycol (PEG) stabilized silica nanoparticles, the amount of oil recovery increased by increasing the salinity of brine. Increasing the salinity of brine resulted in considerable deposition of silica nanoparticles on the rock surface and made them more water wet. These phenomena eventually increased the final recovery factor from 62% to 79%. Since the temperature simultaneously affects the deposition and detachment kinetics of nanoparticles and the reservoir fluid properties, its effect on oil recovery in nanoassisted-EOR technique cannot be generalized.",0,0,3
Oil Recovery,EOR,"Al Kalbani, Munther; Jordan, Myles; Mackay, Eric; Sorbie, Ken; Nghiem, Long",Modelling the impact of Alkaline-surfactant and Alkaline-surfactant-polymer flooding processes on scale precipitation and management,Chemical EOR; Alkaline-surfactant-polymer; Geochemical reactions; Inorganic scale precipitation; Squeeze modelling,OIL; TECHNOLOGY; RECOVERY; WATER,"Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the in situ mineral reactions on the produced scaling ions and pH has been little reported in the literature. The objective of this study is to investigate the impact of the in situ chemical and geochemical interactions on the scale precipitation risk when the fluids reach the wellbore, and their inhibition during Alkaline-Surfactant (AS) and ASP flooding processes. Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options. Results: show that the in situ rock dissolution, mineral precipitation and brine mixing reduce the produced ion concentrations (Ca2+, Mg2+, HCO3) and pH compared to the initial concentration and the injected pH value. The calcite scaling risk can be high during Na2CO3 injection while silica and Mg(OH)(2) scales are potential minerals that will precipitate in the production system during NaOH injection. Uncertainty in the mineral reaction rate parameters, especially mineral surface area, is important and must be captured, as this may impact the scaling risk in the producer. Among the studied flooding options, ASP with pre and post polymer slugs shortens the calcite scaling period, reduces the scaling ion concentrations and the produced water rates. This case, then, requires the least number of squeeze treatments, the lowest scale inhibitor volume, and delivers the highest incremental oil recovery. This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.",0,0,0
Oil Recovery,EOR,"Orlando Jr, Aloisio E.; Barca, Luiz F.; Heindel, Theodore J.; Klein, Tania S.; Medronho, Ricardo A.",Gas holdup and flow regime in a bubble column that includes enhanced oil recovery chemicals,Bubble column; EOR chemicals; Flow regime; Gas holdup; Transitional gas holdup,EMULSIFICATION STABILITY; WATER; HYDRODYNAMICS; CFD; TRANSITION; SIMULATION; VISCOSITY; MODEL,"Chemical enhanced oil recovery (EOR) methods are alternatives to increase oil production in mature reservoirs. However, the presence of EOR chemicals in the produced water may impact the separation of gas-water systems in oil platforms. The present work aims to evaluate the impact of polymers, surfactants, inorganic salts, and their interactions on gas holdup in a 32.1-cm-diameter semi-batch bubble column over a range of superficial gas velocities ranging from 0 to 19 cm/s. It has been confirmed through physical-chemical analysis that synthetic produced water containing salts, polymers and organic surfactants is non-Newtonian with low surface tension. Results have shown that both salt and surfactants increase gas holdup regardless of superficial gas velocity, while the effect of polymers depends on superficial gas velocity. This work also innovates by showing how interactions between EOR chemicals and salinity affect transition gas holdup and superficial gas velocity between different flow regimes. Overall results shed some light on how the chemical composition of EOR effluents affect gas holdup and flow regime as a function of a wide range of superficial gas velocities and therefore contributes to the development of gas-liquid systems.",0,0,0
Oil Recovery,EOR,"Kurgyis, Kata; Hommel, Johannes; Flemisch, Bernd; Helmig, Rainer; Ott, Holger",Explicit continuum scale modeling of low-salinity mechanisms,Low-salinity; Double layer expansion; Multicomponent ion exchange; Reactive transport modeling; Dispersion; IOR EOR,,"Understanding the influence of injection water composition on the displacement efficiency has been a long-standing issue in reservoir engineering; a reduction of the injection water salinity can lead to additional oil production, which is considered a low-cost and environmentally friendly method for enhanced oil recovery. Several underlying chemical mechanisms have been identified; however, the identification of the governing mechanisms remains difficult and specific to the chemical setting of the reservoir and injection water composition. In this work, we implement two potential mechanisms, namely, double layer expansion and multicomponent ion exchange, to achieve an explicit description of low-salinity effects in the open-source continuum-scale flow simulator DuMu(X), with the goal of designing and interpreting experiments, and upscaling the results. By assuming sets of input parameters, we show that there is a minimum required core length dependent on the dispersion of the chemical flooding front dominated by sample heterogeneity. Above this length scale, the saturation profile is fully developed, and the chemical effluent analysis is conclusive, which both is required to calibrate continuum scale models. The change in the chemical water composition shows a characteristic fingerprint for both investigated mechanisms and therefore allows the identification of the leading low-salinity mechanism. The model is publicly available.",0,0,0
Oil Recovery,EOR,"Nieto-Alvarez, David A.; Luna-Rojero, Erick E.; Marin-Leon, Adlai; Ceron-Camacho, Ricardo; Nieto-Rivero, Carlos J. T.; Zamudio-Rivera, Luis S.",Static adsorption and mathematical model applied in EOR using a supramolecular surfactant,Static adsorption; Supramolecular surfactant; Adsorption model; EOR,OIL-RECOVERY; FOAM STABILITY; ZWITTERIONIC SURFACTANT; INTERFACIAL-TENSION; LIMESTONE; MINERALS; BEHAVIOR; ISOTHERM,"Typical adsorption isotherms show the characteristic Langmuir behavior. However, in the presence of a supramolecular surfactant, its corresponding adsorption isotherms, exhibiting atypical decrement behavior. The static adsorption results on limestone and dolomite show maximum values of 2.40 and 5.98 mg(surfactant)/grock, respectively. For explaining this behavior, was developed a new modified mathematical adsorption model, (d Gamma/dt) (ads) = k(ads)c(Gamma(infinity) - Gamma) - k(cmc)(c - c(cmc))(n)Gamma H(c - c(cmc)). This model describes the adsorption isotherms in two ads regions: the first one corresponds to the conventional adsorption increase and the second to decay adsorption phenomena. This decrement behavior is mainly due to the ultra-high salinity and the monomer reversible arrow micelle reversible arrow vesicle equilibrium in connate water. The new model shows the better fitting with r(2) = 0.9743 for limestone and r(2) = 0.9668 for dolomite, respect to the Langmuir model r(2) = 0.8556. Which represents the accuracy with the experimental values in the adsorption isotherm. Also, it is highlighted the significance of the information provided by the new static adsorption Langmuir mathematical model. That establishes criteria for using a chemical in enhanced oil recovery processes. From the data in the adsorption profile, the optimal concentration for the adsorption process occurs between 1800 and 2000 ppm of supramolecular surfactant. The enhanced oil recovery experiment in ultra-high salinity and hardness is better with an increase in the temperature: 8% at 80 degrees C, 15% at 90 degrees C and 20% at 100 degrees C.",0,0,0
Oil Recovery,EOR,"Khalilnezhad, Ali; Simjoo, Mohammad; Hamidian, Nima",Insights into viscous fingering effect induced by wettability alteration processes: A fractional flow study,Wettability alteration; Viscous fingering; Fractional flow; Low salinity injection,LOW-SALINITY; OIL-RECOVERY; DISPLACEMENT; INSTABILITY; MECHANISMS; INJECTION; DISPERSION,"Wettability alteration is one of the promising mechanisms for enhancement of oil recovery from preferentially oil-wet rocks. Many water-based EOR methods containing chemicals (e.g. surfactants) or ions (e.g. low salinity water: Low-Sal) were proposed to alter rock wettability to more water wetness. But, one of the possible challenges to get the full potential of such EOR methods is the occurrence of the viscous fingering phenomena. This could be the case for those of EOR methods in which an oil mobility profile over the flow domain could be formed due to the wettability alteration and thus potentially trigger viscous fingering with a negative impact on the oil displacement. In this paper, we aimed to describe this kind of viscous fingering phenomena by applying the fractional flow theory for the case of a tertiary Low-Sal injection process in a core sample previously flooded by a high salinity water. We explained the fractional flow procedure to obtain the saturation and location of the viscous fingered-region. As to the results, water saturation continuously decreases over the viscous fingered-region from an upstream point located at the Low-Sal region to a downstream point at the High-Sal region. The severity of the viscous fingering phenomena could be well addressed by the location of upstream and downstream saturation points as the proposed model honors these points. The model performance to predict breakthrough time and oil recovery factor was also validated by the previously reported Low-Sal experimental data and we found a good agreement between the model outcome and lab data.",0,0,1
Oil Recovery,EOR,"Zhang, Jin; Wang, Dongmei",Aqueous imbibition further investigation on contact area penetration enhancement for hydrocarbon extraction from tight rocks,Forced imbibition; Surfactant EOR; Acid stimulation; Tight formation; Carbonate,OIL-RECOVERY; SHALE; WET,"The rapid decline of production and low oil recovery in shale and other tight formations have been identified in practice. Surfactant EOR has been considered as one of the best options for those challenging formations. Many studies indicated that the oil recovery was improved by surfactant spontaneous imbibition in a huff-n-puff mode. However, the slow oil extraction rate and the limited penetrating area into the rock matrix by laboratory experimental results indicated it might be impractical for real-time extraction. To address this problem for the carbonate-rich tight formations, a new approach of forced surfactant imbibition process coupled with enhanced contact area stimulation (acidizing, for instance) was proposed. In this paper, samples from the Middle Bakken were used for the laboratory studies. A chemical formulation (CF) consists of surfactant, organic acid, and other components was designed to evaluate the effects on carbonate-rich rocks, rock microstructure and petrophysical properties (porosity and permeability). Oil recovery was also examined by forced imbibition with chemical formulation. Research results demonstrated that CF treatment could dissolve the carbonate minerals in the Bakken rocks resulted in the microstructure changes. These changes led to the injected fluid deeply imbibe into the rock matrix and therefore enlarge the rock-fluid contact area. Rock porosity and permeability were increased and oil recovery was significantly improved with the designed chemical formulation through forced imbibition. In a summary, this laboratory study of combination of acid stimulation and forced surfactant imbibition process may serve as a possible approach for a field application to improve the hydrocarbon recovery from well to well besides of huff-n-puff method.",0,0,1
Oil Recovery,EOR,"Sheikha, Ammar; Sheikha, Hussain",Top lean zone and cardinal parameters affecting SAGD,SAGD; Thermal EOR; Lean zone; High water saturation; Oil sands; Long Lake pilot; Surmont pilot,,"SAGD is a thermal recovery process in which steam oil ratio, SOR, is a key parameter that can affect the economic outcome of the process. Reservoirs with underlying or overlying lean bitumen present challenges for SAGD as they can act as a heat sink. Water has higher heat capacity than the bitumen and thus requires more steam to heat up the reservoir leading to higher SOR. The potential outcome of operating SAGD in these conditions may be lower bitumen rate and higher steam injection rate, both of which affect plant throughput and thus the economic matrix of SAGD. This paper looks at the performance of SAGD process in the presence of top lean bitumen. It will examine the theoretical CSOR that is needed to produce the bitumen with different water saturations and will highlight the key parameters of lean bitumen affecting SAGD performance. The paper reviews performance of several fields where lean bitumen is present. The paper also analyzes simulation results to examine the impact of water saturation and the size of lean bitumen resource on the SAGD process.",0,0,1
Oil Recovery,EOR,"Chen, Quan; Otaibi, Mohammed; Ayirala, Subhash; Yousef, Ali",The prospects and potential opportunities of low salinity water flooding for offshore applications in sandstones,Low salinity waterflooding (LSWF); Multicomponent ion exchange (MIE); Desulfated seawater (DSSW); Single well chemical tracer test (SWCTT); Interwell field trial; Sulfate removal unit (SRU); Reverse osmosis (RO) desalination,,"Low salinity water flooding (LSWF) is an emerging enhanced oil recovery (EOR) technology with enormous potential for offshore applications in sandstones. The objective of this study is to provide a review on LSWF offshore field applications and summarize the key lessons learned. A review was also conducted on the capabilities of existing sulfate removal units (SRUs) for seawater injection in offshore fields. Furthermore, the potential of targeting offshore oil fields with de-sulfated seawater (DSSW) injection, either ongoing or planned, as primary candidates to switch over to LSWF EOR has been investigated. For LSWF field trials, the chance of success can be significantly improved when it is based on key laboratory screening tests such as reservoir condition corefloods. The LSWF field tests implemented in offshore fields mainly comprise of single well chemical tracer tests (SWCTT) and interwell trials. However, the reported interwell field trials are restricted to unconfined pilots, which makes the injection and production allocation difficult. Therefore, confined pilots are recommended for future consideration of LSWF field trials to provide better estimations on swept volumes and accurately determine the improvements in the displacement efficiency. Globally there are more than 80 sulfate removal units in operation for de-sulfated seawater (DSSW) injection in offshore waterflooding. All these offshore fields with DSSW injection either currently ongoing or planned can become potential candidates for screening and switch over to LSWF EOR for the following two reasons: (1) The divalent cations can act as bridges between negatively charged rock surfaces and negatively charged polar oil components to increase the oil-wet tendency. These bridges can become primary targets to be replaced by uncomplexed cations in low salinity water for EOR. (2) The de-sulfated seawater injection processes can easily be switched to LSWF by retrofitting the existing sulfate removal units with reverse osmosis (RO) desalination systems and upgrading the facilities to handle larger water volumes. Such retrofitting is considered sufficient to generate low salinity water, which can bring significant gains to increase oil recovery with minimal additional investment. The availability of RO desalination systems on offshore platforms can also provide potential opportunities for the cost-effective implementation of tertiary chemical EOR technologies especially polymer flooding. The novelty of this study is that it provides useful guidelines for reservoir screening and offshore field implementation of LSWF processes. Also, the new potential of evaluating the offshore oil fields with existing DSSW injection for switching over to LSWF has been identified. These findings will have a potential impact on enhancing the LSWF prospects and opportunities for EOR in different offshore fields.",0,0,2
Oil Recovery,EOR,"Ado, Muhammad Rabiu",Comparisons of predictive ability of THAI in situ combustion process models with pre-defined fuel against that having fuel deposited based on Arrhenius kinetics parameters,In situ combustion (ISC); Enhanced oil recovery (EOR); Heavy oil; bitumen; tar sand; Reservoir simulation; Toe-to-heel air injection (THAI); Chemical kinetics,HEAVY OIL-RECOVERY; SIMULATION; STABILITY,"Toe-to-heel air injection (THAI) is an in situ thermal-enhanced oil upgrading and recovery technology that makes use of a horizontal producer well for mobilised partially upgraded oil production to the surface. To design operation of the THAI process requires up-scaling lab-scale numerical model to field-scale reservoir numerical model. There are a number of up-scaling methods that were developed. However, these previous up-scaling methods only concentrated on the qualitative nature of the physicochemical processes. Furthermore, these methods have deficiencies ranging from assumption of 100% oxygen utilisation, failing to compare oil production rates for up-scaled reservoir models with and without fuel pre-defined, not reporting on the dynamics inside the reservoirs with and without fuel pre-defined, etc. As a result, this work provided in depth comparative studies of both the qualitative and quantitative physicochemical processes in numerical models containing Arrhenius-based coke deposition thermal cracking reaction (i.e. model A) and that having pre-defined fuel concentration (i.e. model F) as an initial parameter respectively. It is found that oil production started earlier in model A compared to in model F even though they have approximately similar trajectories. It is shown that by the end of the combustion period, oil recovery of 28.5% OOIP is achieved in model F which is greater than that in model A by an additional of 4.8% OOIP. It is found that the peak temperature, which indicates how healthy the combustion is at a single point only at different times, is generally considerably higher in model A than that in model F. It is further discovered that in some cases the combustion at all points might be stable and rigorous but in other cases the combustion might not be stable and rigorous at all points thereby implying that the peak temperature alone does not give the measure of the efficiency and spread of the combustion front. It is shown for the first time that pre-defining fuel concentration throughout the reservoir as is done in model F resulted in faster downward advancement and expansion of the combustion front compared to in the reservoir where the fuel is deposited based on the Arrhenius kinetics parameters (i.e. like in model A). It is also discovered that higher areal sweep of the reservoir is achieved in model F when compared to that achieved in model A. Overall, it then follows that higher volume of the reservoir of model F is combustion-swept, heat-affected, and oil-depleted compared to that in model A. These findings explain the reason why more oil is produced during the combustion period in model F than in model A. Conclusively, this first-of-a-kind study shows that pre-defining the fuel has no effect on the qualitative nature of the physicochemical processes, but has considerable influence on the quantitative parameters such as the rate of and cumulative oil production, peak temperature, areal and volumetric sweeps by the combustion zone, size of the oil-depleted zone, and size of the heat-affect zone.",0,0,2
Oil Recovery,EOR,"Khan, Mohammad Yunus; Mandal, Ajay",Analytical model of incremental oil recovery as a function of WAG ratio and tapered WAG ratio benefits over uniform WAG ratio for heterogeneous reservoir,EOR; Analytical model; Tapered WAG; Uniform WAG; Reservoirheterogeneity; WAG incremental oil recovery; Gas utilization factor,GAS; INJECTION; EFFICIENCY; DESIGN; DISPLACEMENTS; OPTIMIZATION,"The water-alternating-gas (WAG) operating scheme and reservoir permeability heterogeneity are the main crucial parameters, which highlyaffect WAG displacement process. The novelty of this article lies in the development of an analytical model for WAG incremental oil recovery as function of WAG ratio, viscous gravity ratio and mobility ratio for the stratified heterogeneous reservoir. We have investigated the effect WAG ratio on WAG incremental oil recovery with variation horizontal permeability heterogeneity, vertical permeability anisotropy and dip angle of the reservoir. The critical operating parameters investigations were carried to optimize WAG displacement process in both homogeneous and heterogeneous reservoirs. Finally, we have estimated all the benefits of the most suitable techno-economical WAG operating scheme as tapered WAG (TWAG) over uniform WAG (UWAG). The developed analytical model showsreasonably similar results as numerical simulation. The results of the analytical and numerical analysisshow that the incremental oil recovery accelerated bya decrease WAG ratio. However, this effect is more noticeable at high viscous gravity (VGR). The increase in reservoir dip angle subsequently increases vertical and displacement sweep efficiencies compared to the horizontal reservoir for different WAG ratio. While increasing WAG ratio decreases vertical sweep and increases displacement sweep of inclined reservoir compared to the horizontal reservoir. The increase of oil recoverywas observed by higher Kv/ Kh with a lower WAG ratio. However, this effect is less evident at lower Kv/Kh. The WAG ratio with a higher proportion of water is beneficial for the heterogeneous reservoir. The infill implemented before WAG start shows faster oil recovery compared to WAG start first then infill implemented in the heterogeneous reservoir. The TWAG incremental recovery over water flood was 18% in homogeneous and 8% in heterogeneous reservoirs, while EUR was approximately similar to UWAG. The TWAG shows more efficient techno-economic benefits over UWAG due to better economics, faster oil recovery rate, more efficient use of injected gas and reduces response time in both homogeneous and heterogeneous reservoirs.",0,0,2
Oil Recovery,EOR,"Al-Shami, Tareq Mohammed; Jufar, Shiferaw Regassa; Negash, Berihun Mamo; Abdullahi, Mohammed Bashir",Impact of external excitation on flow behavior of trapped oil blob,Oil mobilization; Unconventional EOR; External excitation; Seismic stimulation; Flow behavior,CAPILLARY TUBES; OSCILLATORY FLOW; RECOVERY; DROPLETS; WAVES; MOBILIZATION; STIMULATION; RESONANCE; WATER,"External excitation of oil reservoirs has shown promising potential in increasing residual oil recovery. Although several numerical, experimental, and pilot studies were conducted over the last decades, large-scale field application is not realized due to inconclusive results on its performance. This paper aims to investigate the effect of external excitation on the flow behavior of an oil blob trapped in a constricted capillary tube model. Flow evolution and characteristic flow behaviors were studied using computational fluid dynamics (CFD) simulations. An external excitation with a sinusoidal profile propagating in the axial direction was applied at the wall of the constricted capillary tube model. The excitation intensity and frequency were varied to identify the flow characteristics. The results show that under the influence of external excitation, three distinct flow regimes develop based on the excitation frequency and intensity; these are trapped, clear pass, and dispersed pass. Velocity profiles, streamlines, and pressure contours were used to examine the resulting flow behaviors. In addition, dimensional analysis was carried out, and the dominant factors in each flow regime were identified. The dominant dimensionless numbers are Euler number, Reynolds number, and Weber number. Accordingly, the three flow regimes were mapped in the domains of these dimensionless numbers. As such, under given flow conditions, fluid properties, and external excitation parameters, the subsequent flow behavior can be predicted using the characteristic flow behavior maps presented in the study. Moreover, any of these flow regimes can be induced for a given application by tuning the excitation parameters based on the dimensionless characteristic maps presented.",0,0,2
Oil Recovery,EOR,"Li Yisong; Gholami, Raoof; Safari, Mehdi; Rahimi, Ali; Khur, Wee Siaw","On surface interactions of environmental friendly surfactant/oil/rock/low salinity system: IFT, wettability, and foamability",Natural surfactant; Low salinity water; Surface wettability; IFT; Sandstone,ENHANCED OIL-RECOVERY; LEAF-DERIVED SURFACTANTS; INTERFACIAL-TENSION; NATURAL SURFACTANT; ANIONIC SURFACTANT; WATER INJECTION; SMART WATER; ADSORPTION; SANDSTONE; NANOPARTICLES,"In recent years, natural surfactants have been considered as part of the EOR processes given their non-toxic and environment friendly nature. However, once chosen wisely, surfactants can only reduce the interfacial tension (IFT) and are often unable to alter the surface wettability for a better hydrocarbon production. Low salinity water (LSW) is a good candidate on these occasions, but the interaction of LSW with natural surfactants for wettability alteration has not been deeply understood. In this work, an attempt was made to extract and characterize a natural surfactant which could be used together with LSW for EOR purposes. To do this, a natural surfactant was extracted from Saponin and its physico-chemical properties such as CMC, foamability, and thermal stability were tested. A series of IFT and wettability measurements were then conducted to evaluate the performance of the surfactant as an EOR additive. The results obtained indicated that the extracted surfactant has a high thermal stability and can be fully functional in the temperature of up to 100 degrees C. It appears that increasing the level of salinity in the solution can improve the efficiency and foamability of the surfactant. It was observed that the extracted surfactant as can reduce the IFT of an air-water system by 78.65% and is capable of favorably altering the surface wettability of sandstone for a better hydrocarbon production once combined with LSW.",0,0,2
Oil Recovery,EOR,"Pashapouryeganeh, Farzad; Zargar, Ghasem; Takassi, Mohammad Ali; kadkhodaie, Ali; Rabiee, Ahmad",One-Pot synthesis of modified-cationic surfactants for enhanced oil recovery applications in carbonate reservoirs,Surfactant synthesis; Cationic surfactant; Quaternary ammonium salt; Wettability alteration; IFT reduction; Chemical enhanced oil recovery (CEOR),INTERFACIAL-TENSION BEHAVIOR; DETERMINING IONS CA2+; HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; POROUS-MEDIA; CHAIN-LENGTH; WET; MECHANISM; LIQUID,"In this study two cationic surfactants, dodecyltriethylammoniumbromide (C(12)TEAB) and hexadecyl-triethylammoniumbromide (C(16)TEAB) were prepared. The formation of synthezied surfactants were confirmed using FTIR and HNMR spectroscopy. Electrical conductivity, interfacial tension and surface tension methods were used to determine the critical micelle concentrations (CMC) of these surfactants. To understand the behavior of synthesized surfactants in harsh environments, the CMC was measured in deionized water (DIW), sea water and petroleum formation water. Using electrical conductivity technique, for C(12)TEAB surfactant the CMC values of 4000 ppm, 2000 ppm and 850 ppm were recorded in DIW, sea water and formation water respectively. For C(16)TEAB surfactant, the CMC values of 420 ppm, 190 ppm and 115 ppm were obtained in DIW, sea water and formation water respectively. The similar CMC results were obtained using the interfacial tension (IFT) and surface tension (ST) methods. Reduction of IFT between crude oil and formation water and also alteration of wettability of petroleum reservoir of carbonated rock from oil-wet (large contact angle) to water-wet (small contact angle) are two major factors affecting chemical enhanced oil recovery (EOR). Interfacial tension (IFT), surface tension (ST) and contact angle measurements were carried out using an IFT-PDSA-06 apparatus (Apex Technologies Company, Iran). The IFT and ST of these surfactants were also carried out in DIW, sea water and formation water. For C(12)TEAB surfactant, the IFT values of 0.051 mN/m, 0.036 mN/m and 0.023 mN/m were recorded in DIW, sea water and formation water respectively. The IFT values of 0.044 mN/m, 0.026 mN/m and 0.0126 mN/m were measured for C(16)TEAB surfactant in DIW, sea water and formation water respectively. The effect of temperature on IFT was studied for both surfactants. When temperature increases, IFT decreases. The reduction of IFT continues up to 55 degrees C, then the IFT increases with increasing temperature. For C(12)TEAB surfactant, the ST values of 44.9 mN/m, 38.8 mN/m and 31.8 mN/m were obtained in DIW, sea water and formation water respectively. In similar measurements for C(16)TEAB surfactant, the recorded ST values were 33.95; 32.9 and 32.22 mN/m in DIW, sea water and formation water respectively. In wettability alteration study both surfactants altered the contact angle from oil-wet to water-wet conditions. Using formation water and C(12)TEAB surfactant, the contact angle varied from 96.4 degrees to 54.5 degrees. In similar study using C(16)TEAB surfactant the contact angle changed from 92 degrees to 46.1 degrees. The contact angles of these surfactants in DIW and sea water were also measured and reported. The results of IFT and wettability studies demonstrated excellent potential application of synthesized surfactants in EOR process in carbonate petroleum reservoirs.",0,0,3
Oil Recovery,EOR,"Wang, Qiong; Jiang, Ruizhong; Leng, Jie; Liu, Xiuwei",The effect of the viscosity-dependent boundary layer on tight oil flow behavior in CO2 Huff-Puff processes: A unified dimensional Pre-Darcy flow model,Pre-Darcy flow; Compositional simulation; CO2 EOR,N-PUFF; RESERVOIR SIMULATION; NUMERICAL-SIMULATION; FRACTURE NETWORKS; RECOVERY; SHALE,"There are numerous percolation studies of unconventional reservoirs showing that in tight or low-permeability formations, the oil flow behavior could be described by the Pre-Darcy mechanism. However, for the CO2 Huff-nPuff operations, the most presented low-velocity Pre-Darcy flow models may result in an erroneous evaluation due to the intensive boundary layer thickness changes caused by the CO2 extraction and dissolution. In this paper, with multiple parameters fitting the seepage experimental results of the studied area, a unified dimensional Pre-Darcy flow model for CO2 enhanced oil recovery (EOR) is derived from the classic Poiseuille model. Then, the proposed flow model is applied in the compositional simulator for analyzing the viscosity-dependent boundary layer (VDBL) effect, applicability evaluation in Huff-Puff EOR, and field history matching. The results indicate that the VDBL effect improves the oil mobility in injection periods and lowers the residual oil saturation at the front of the CO2 convection-diffusion area in reproduction periods. Additionally, the nonlinear parameter alpha and the shape parameter beta enhance the proposed model's applicability for the Huff process and the Puff process respectively. Finally, by adjusting the parameters alpha and beta for different permeability intervals of the geological model, the flow model is successfully applied in the oil production matching of the Y6 well, which exhibits its reliability in the history matching.",0,0,3
Oil Recovery,EOR,"Shilov, Evgeny; Dorhjie, Desmond Batsa; Mukhina, Elena; Zvada, Maya; Kasyanenko, Anton; Cheremisin, Alexey",Experimental and numerical studies of rich gas Huff-n-Puff injection in tight formation,Associated gas EOR; Huff-n-Puff; Tight oil reservoirs; Minimum miscibility pressure; Gas diffusivity,ENHANCED-OIL-RECOVERY; SHALE PLUGS; PERFORMANCE; SIMULATION,"Huff-n-Puff technology is considered one of the most effective methods to increase oil recovery in shale reservoirs. Previous works were mainly focused on Bakken and Eagle Ford shales. This paper is devoted to experimental and numerical studies of rich gas injection in core samples with high organic matter content from a tight oil reservoir in Russia. Eighteen core samples from different well intervals and different sizes were used in a Huff-n-Puff experimental study. Eight of the core samples were investigated at an injection pressure of 15 MPa, while ten core samples were studied at near-miscible pressure conditions of 30 MPa. The experiment results indicate that Huff-n-Puff injection of rich gas could give an oil recovery average of 63.03% and a maximum of 88.40% at 30 MPa injection pressure. A compositional model was created utilizing a commercial simulator and history matched to experimental results. The validated model was used to investigate the effect of molecular gas diffusivity, injection pressure, injection duration, shut-in duration, production duration, and other reservoir properties on the recovery factor. Sensitivity analysis by numerical modeling shows that the molecular gas diffusivity was critical in the history matching of the model. The numerical simulation results imply that the recovery factor could be increased by extending the injection period. In contrast, the duration of a soak period does not significantly influence the recovery factor. Furthermore, the recovery factor could be increased by extension of the production due to a slow decline in the pressure gradient between the matrix and fracture at the later stage of the production. The results of the present study imply that the application of the Huff-n-Puff injection of rich gas could increase oil recovery from tight reservoirs.",0,0,3
Oil Recovery,EOR,"Abiz, Mehdi Rezaei; Norouzi-Apourvari, Saeid; Jafari, Saeed; Schaffie, Mahin",The effect of subsurface factors on the performance of nanofluid-assisted enhanced oil recovery: Modeling and sensitivity analysis,Enhanced oil recovery; Nanoparticle transport; Porous media; Wettability alteration; Mobility control,POROUS-MEDIA ROLE; WETTABILITY ALTERATION; CARBON NANOTUBES; SOLUTION CHEMISTRY; 2-PHASE FLOW; TRANSPORT; NANOPARTICLES; RETENTION; STABILITY; OXIDE,"Successful implementation of nanofluid-assisted enhanced oil recovery (EOR) operation mainly depends on proper determination of the main factors that control both transport and retention of nano-sized particles in porous media. In this study, a new transport scheme using the kinetic Langmuir model was first developed and validated by some experimental data from the literature. This model was then used to investigate the effect of reservoir rock type, clay content, grain size, brine type, and reservoir temperature on distribution of nanoparticles on the rock surface and in the injected fluid in relation to EOR methods. Moreover, a two-phase approach was derived to simulate the effect of these parameters on both wettability alteration and mobility control. Results confirmed that the deposition tendency of silica nanoparticles on limestone is higher than that on sandstone. By increasing clay content, both surface area and deposition sites increases and consequently more nanoparticles were found to retain. In the case of polyethylene glycol (PEG) stabilized silica nanoparticles, the amount of oil recovery increased by increasing the salinity of brine. Increasing the salinity of brine resulted in considerable deposition of silica nanoparticles on the rock surface and made them more water wet. These phenomena eventually increased the final recovery factor from 62% to 79%. Since the temperature simultaneously affects the deposition and detachment kinetics of nanoparticles and the reservoir fluid properties, its effect on oil recovery in nanoassisted-EOR technique cannot be generalized.",0,0,3
Oil Recovery,Relative Permeability,"Gao, Yanfang; Ren, Zhanli; Chen, Mian; Jiang, Hailong; Ding, Shuaiwei",Coupled geomechanical-thermal simulation for oil sand reservoirs with shale barriers under hot water injection in vertical well-assisted SAGD wells,Oil sands; Shale barriers; Geomechanical-thermal simulation; Vertical well; SAGD,PROPAGATION BEHAVIOR; PERMEABILITY CHANGES; RECOVERY PROCESSES; MODEL; TEMPERATURE,"Mudstone stringers in an oil sand reservoir can significantly affect the propagation of the steam chamber in the process of steam-assisted gravity drainage (SAGD). The micro-fracturing by water injection in strongly heterogeneous oil sands can result in these problems such as hard stringer breakthrough and aggravating heterogeneity. This paper proposed a comprehensive numerical model for conventional SAGD wells and vertical well-assisted SAGD (VWA-SAGD) wells to predict the coupled thermo-hydro-mechanical responses under hot water injection in a typical Karamay oil sand reservoir with two stringers, considering skeleton shear dilation, the ""phase change"" of bitumen, formation heterogeneity, the permeability evolution induced by elastoplastic deformations, and the theory of heat and mass transfer. Major conclusions were drawn that there are three relatively narrow separate transition zones effectively heated around the SAGD wells and vertical well. The vertical well makes about 0.5 MPa increase to the pore pressure of the reservoir embedded with mudstone stringers in vertical directions and rises by about 0.6 MPa for the reservoir pore pressure above the upper stringer to reduce the pore pressure differential along the wellbore. Water injection-induced ultimate stress states can't reach the shear failure line under field operations, so the shear dilation can't be induced. The thermoporoelastic deformation determines whole reservoir deformation. The reservoir between the two stringers contributes to most of the caprock uplift. The VWA-SAGD technique can improve the porosity by about 1% in the whole vertical direction and reduce the anisotropy of porosity along the wellbore, which is beneficial to the uniform and fast propagation of the steam chamber in subsequent preheating and production stages. These findings can be employed to accurately predict the temperature, pore pressure, stress/displacement, and porosity evolutions for the field engineers to properly evaluate the uplift of reservoir and caprock, oil output changes, and heat utilization efficiency.",0,0,0
Oil Recovery,Relative Permeability,"Al Kalbani, Munther; Jordan, Myles; Mackay, Eric; Sorbie, Ken; Nghiem, Long",Modelling the impact of Alkaline-surfactant and Alkaline-surfactant-polymer flooding processes on scale precipitation and management,Chemical EOR; Alkaline-surfactant-polymer; Geochemical reactions; Inorganic scale precipitation; Squeeze modelling,OIL; TECHNOLOGY; RECOVERY; WATER,"Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the in situ mineral reactions on the produced scaling ions and pH has been little reported in the literature. The objective of this study is to investigate the impact of the in situ chemical and geochemical interactions on the scale precipitation risk when the fluids reach the wellbore, and their inhibition during Alkaline-Surfactant (AS) and ASP flooding processes. Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options. Results: show that the in situ rock dissolution, mineral precipitation and brine mixing reduce the produced ion concentrations (Ca2+, Mg2+, HCO3) and pH compared to the initial concentration and the injected pH value. The calcite scaling risk can be high during Na2CO3 injection while silica and Mg(OH)(2) scales are potential minerals that will precipitate in the production system during NaOH injection. Uncertainty in the mineral reaction rate parameters, especially mineral surface area, is important and must be captured, as this may impact the scaling risk in the producer. Among the studied flooding options, ASP with pre and post polymer slugs shortens the calcite scaling period, reduces the scaling ion concentrations and the produced water rates. This case, then, requires the least number of squeeze treatments, the lowest scale inhibitor volume, and delivers the highest incremental oil recovery. This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.",0,0,0
Oil Recovery,Relative Permeability,"Ligeiro, Tayanne S.; Vaz, Alexandre; Chequer, Larissa",Forecasting the impact of formation damage on relative permeability during low-salinity waterflooding,Low-salinity waterflooding; Fines migration; Relative permeability; Formation damage; Particle detachment; Coreflood experiments,FINES-MIGRATION; POROUS-MEDIA; INJECTIVITY DECLINE; SWEEP EFFICIENCY; SLOW MIGRATION; OIL-RECOVERY; FLOW; PARTICLES; TRANSPORT; RELEASE,"Low-salinity waterflooding is considered to be an advanced oil recovery method, but the main mechanism behind the increase in oil recovery factor is still under investigation. Fines migration has been recognized to be one of the mechanisms responsible for the increase in oil production. In this case, the increase in oil recovery happens as a result of increased sweep efficiency and consequent reduction of residual oil. The release of particles due to reduction of electrostatic forces results in flux diversion to previously unswept areas in the reservoir, increasing oil recovery. This paper provides a better understanding of the effects of formation damage during low-salinity water injection in Berea sandstones and proposes a methodology to forecast its effects on water relative permeability. We have performed one- and two-phase flow coreflood experiments with varying salinity of the injected solution. The effluent was analysed for salinity, pH and particle concentration. The laboratory data was treated using a mathematical model that accounts for permeability impairment during low-salinity waterflooding due to fines detachment, migration and capture in small pore throats. The parameters of the model were used to predict the impact of formation damage on the water relative permeability during two-phase flow. The mathematical model matched the laboratory data for pressure drop and particle concentration in the outlet with great accuracy. A methodology to predict the impact of formation damage in two-phase flow using one-phase flow data was proposed. A good agreement between the predicted and the measured water relative permeabilities was obtained. The forecasted water relative permeability curve was able to reproduce the non-monotonic behaviour of water relative permeability due to low-salinity water injection.",0,0,0
Oil Recovery,Relative Permeability,"El-Yamani, Mahmoud Samir; Al-Ramadan, Khalid; Cantrell, Dave","Diagenetic controls on porosity evolution and reservoir quality of an outcrop analogue of the Jurassic carbonate reservoirs in the Arabian Plate: An example from the Middle Jurassic Tuwaiq Mountain Formation, Central Saudi Arabia",Carbonate-diagenesis; Chert-replacing-evaporites; Dolomitization; Dolomite-calcitization; Porosity-evolution; Tuwaiq Mountain formation,DEPOSITIONAL-ENVIRONMENTS; STAINING TECHNIQUE; SILICA DIAGENESIS; DOLOMITE; DEDOLOMITIZATION; LIMESTONE; CLASSIFICATION; MICROFACIES; DISSOLUTION; JUBAILA,"The Middle Jurassic Tuwaiq Mountain Formation (TMF; formed of three members, from bottom to top T1, T2, and T3) represents one of the primary conventional and unconventional reservoirs to be assessed in Saudi Arabia. It is considered as a tight carbonate reservoir in the Jafurah Basin and conventional reservoir in the Arabian Basin. Here, we investigate the depositional, diagenetic, and stratigraphic impact on reservoir quality and porosity evolution of the TMF through an integrated petrographical, geochemical and petrophysical analyses on outcrop samples. The TMF has a complex diagenetic history including micritization, dissolution, recrystallization and neomorphism, meteoric cementation, evaporite precipitation, dolomitization, silicification, dolomite dissolution and calcitization. Dolomitization occurred via a hypersaline fluid mechanism, based on texture, association with evaporites, and Sr concentration. X-ray diffraction results support chert replacing evaporite as the mechanism of the two chert beds in the T3 member due to the presence of anhydrite relics in their samples. This replacement formed the necessary Ca2+ rich fluid for dolomite dissolution and calcitization. Therefore, dolomite calcitization occurs locally and is stratigraphically controlled based on its position relative to chert beds in T3. T3 and the upper part of the T2 member contain calcitized dolomites, while the lower part of T2 and T1 contain only dissolved dolomite. As the fluid went deeper in the TMF, it became weaker. Therefore, the fluid was too weak to develop dolomite calcitization process and instead only affected T1 and the lower part of T2 by dolomite dissolution. Overall, dolomite dissolution and dolomite calcitization didn't have a high impact on porosity evolution as the TMF isn't a highly dolomitized formation. The distribution of porosity (empty set), permeability (K), and reservoir-quality-index (RQI) of the TMF are stratigraphically controlled. The TMF represents the regressive system tract of a 3rd order depositional sequence, which is composed of seven 4th order cycles (i.e. deep lagoon cycles (DLC) and shallow lagoon cycles (SLC)). RQI, empty set, and K plots showed great fitting with the 4th order depositional-cycles as DLC has very poor reservoir properties (average empty set = 7.7%, average K = 0.17 mD, average RQI = 0.03), while SLC has fair reservoir properties (average 0 = 15.4%, average K = 2.64 mD, average RQI = 0.11). Reservoir quality contrast is controlled by two factors: (1) the reduced mud-content and increased grain-content in SLC compared with DLC resulted in increased primary interparticle porosity, and is governed by depositional energy; and (2) the higher primary interparticle porosity in SLCs compared with DLCs preferentially facilitated more infiltration of undersaturated meteoric fluids, resulting in enhanced grain dissolution. This is reflected on the higher proportion of moldic and vuggy porosity in SLCs compared with DLCs. The accurate assessment of the TMF micro-scale attributes and controls on reservoir quality in an outcrop analogue that occurs in close proximity to subsurface hydrocarbon producing intervals can provide important input for oilfield appraisal and enhanced oil recovery performance.",0,0,1
Oil Recovery,Relative Permeability,"Al-Masri, Wael; Shapiro, Alexander",Experimental determination of relative permeabilities and critical gas saturations under solution-gas drive,Gas liberation; Relative permeability; Critical gas saturation; Steady state method; Solution gas drive,VISCOSITY; PRESSURE; DEPRESSURIZATION; VISUALIZATION; EVOLUTION; RECOVERY; METHANE; DECANE; PHASE,"Relative permeabilities are crucial to predict oil production from underground reservoirs. Multiple previous studies are limited to measuring/estimating relative permeabilities within the region where both phases are mobile. This study presents a novel experimental method to measure the oil relative permeability under presence of the trapped gas for gas-oil systems under depressurization. The experiments were carried out with the carbonaceous reservoir and outcrop samples. The results show a highly variable amount of immobile gas for North Sea chalk (from 8% up to 26% volume) and a significant reduction in oil relative permeability (up to 75%). The relative permeabilities were found to be power-law type functions. A comparison with the previously developed pore-network based model for gas-oil relative permeabilities is presented, allowing for reconstruction of both gas and oil relative permeability curves in the whole saturation range.",0,0,1
Oil Recovery,Relative Permeability,"Tan, Fengqi; Liu, Wentao; Ma, Chunmiao; Cheng, Hongjie; Li, Xiankun; Zhang, Chaoliang",Classification methods of conglomerate reservoirs based on the adsorption and retention law of surfactant-polymer binary systems,Conglomerate reservoir; Surfactant-polymer flooding; Absorption capacity; Micropore structure; Reservoir classification,OIL-RECOVERY; CAPILLARY NUMBER; REMAINING OIL; TEMPERATURE,"Factors such as clay minerals and micropore structure can lead to the adsorption and retention of chemical agents when the components of surfactant-polymer systems enter porous media. This study aims to clarify the influence of adsorption and retention of surfactant-polymer components on reservoir permeability and oil displacement efficiency and then classify the reservoirs into types. The natural cores of conglomerate reservoirs from the Badaowan Formation in the 7th block are selected as research objects to reveal the adsorption law of surfactantpolymer components on different minerals and different micro pores through the dynamic oil displacement method based on physical model and the N element calibration method. Experimental results show that the adsorption capacity of clay minerals for surfactant-polymer components is significantly higher than that of carbonate and skeleton minerals, and different clay minerals differ in adsorption capacity for surfactant-polymer components depending on their cation exchange capacity and end surface adsorption activity. In addition, the adsorption and retention capacities of reservoirs for surfactant-polymer components are closely related to the type and content of clay minerals. The combination type of clay minerals controls the adsorption activity of surfactant-polymer components, and the values of polymer and the surfactant are quantitatively calculated to be 11.3 and 21.4 mg/g, respectively. The adsorption strength of surfactant-polymer components is controlled by the content of clay minerals. With increasing clay content, the adsorption strength of the polymer ranges from 0.5 to 2.5 mg/cm3, and that of the surfactant ranges from 1.0 to 4.5 mg/cm3. On this basis, the ""N element calibration method"" is used to determine the occurrence state and content of chemical agents in micropores for different permeability samples after surfactant-polymer binary flooding. Research results show that the polymer and surfactant components mainly have two types of occurrence form in micropores, including the complex pores accumulated by clay minerals and the intersections of small pores and throats. With decreasing reservoir permeability, the number and content of detected N element gradually increase, indicating an increase in the adsorption and retention of polymer and surfactant, and the influence on the reservoir seepage capacity also increases. Finally, the conglomerate reservoirs in the Badaowan Formation from the 7th block are divided into four types after considering the influence of clay minerals and micropore structure on the adsorption and retention of surfactant-polymer components, and the reasonable classification of reservoir types can effectively enhance the oil recovery of surfactant-polymer binary flooding.",0,0,1
Oil Recovery,Relative Permeability,"Al Ghafri, Al Yaqathan; Mackay, Eric; Stephen, Karl",The relevance of the linear stability theory to the simulation of unstable immiscible viscous-dominated displacements in porous media,Instability predictor; Saffman-Taylor instability; End-point mobility ratio; Fractional flow analysis; Viscous oil; Polymer flooding; Correlated random field,MISCIBLE DISPLACEMENT; INSTABILITIES; MECHANISM; POLYMER; GROWTH; MODELS; FLUID,"The 2D governing equations for the immiscible two-phase flow admissible to linear stability analysis are inspected. The identification of the term v(ws)delta D-st in the generalized Saffman-Taylor criterion is key to the analysis. It can be regarded as a predictor that correlates with observed immiscible instability in terms of the rate of advancement of the viscous pattern, the number of small protrusions, and their roughness in a given heterogeneous domain described by a correlated random field. The predictor is extended, heuristically, for polymer flooding shock-wise and used to characterize the instability of the two shocks. The extension is validated by simulation. The instability of the primary shock is essential when considering the breakthrough recovery. In light of the instability predictor, the geometric interpretations of the fractional flow are essential to understand the stability enhancement of the primary shock over the Buckley-Leverett shock in water flooding. It is also concluded that the end-point mobility ratio does not directly control the immiscible instability. This conclusion was arrived at by fixing the end-point mobility ratios for three sets of relative permeability curves, and yet noticeably different instabilities occur, both in transverse and correlated random fields. The criterion can predict the viscous instability in the laboratory experiments under certain flooding conditions and sample configurations. Concerning the instability in a field scale, the predictor is applicable if the field is regarded as a prototype of a given model experiment.",0,0,2
Oil Recovery,Relative Permeability,"Wang, Mibang; Yang, Shenglai; Li, Jiajun; Zheng, Zuhao; Wen, Jing; Ma, Quanzheng; Wang, Qian; Chen, Hao",Cold water-flooding in a heterogeneous high-pour-point oil reservoir using computerized tomography scanning: Characteristics of flow channel and trapped oil distribution,High-PPT live oil; CT-Scanning; Positive-rhythm reservoir; Variable water injection temperature; Flow channel,WAXY CRUDE-OIL; ASPHALTENE PRECIPITATION; PERMEABILITY REDUCTION; PARAFFIN PRECIPITATION; RELATIVE PERMEABILITY; START-UP; DEPOSITION; MODEL; IMBIBITION; EFFICIENCY,"There are relatively few studies that consider the influence of reservoir heterogeneity on reservoir wax deposition. This study conducts a computerized tomography scan to study the flow channels, heavy component retention, displacement efficiency, and trapped oil distribution in a high-pour point oil reservoir with a positive sedimentary rhythm under various water injection temperatures. This study greatly improves the understanding of the wax deposition influences on the flow channel. Three displacement models are proposed: water-flooding breakthrough model (49.5 ?C), approximate-equilibrium piston-like displacement model (54.5 ?C/59.5 ?C), and non-equilibrium piston-like displacement model (64.5 ?C). When the injection temperature is lower than the wax appearance temperature (59.5 ?C), an elliptical wax deposition is formed at the inlet, the most serious deposition is in the middle-permeability layer. A wax deposition barrier is formed away from the inlet, and constrains the downward movement trend of the water injected above. Therefore, the moderate wax precipitation will improve the oil recovery from the top low-permeability layer. However, the heterogeneity in the spaces and strength of the barrier result in the oil recovery from the 100 mD layer at 59.5 ?C begin higher than that at 54.5 ?C; moreover, at 59.5 ?C, the recovery at the inlet is better than that at the outlet. The vortex phenomenon increases the oil recovery from wax deposition area in the bottom layer at the inlet. The heavy component retention is significant, and the oil recovery decreases with decreasing injection temperature. After flooding, the formation mechanisms of the trapped oil include wax deposition, weak water washing, and reservoir sedimentary rhythms. The research results provide initial insights for the evaluation of cold damage.",0,0,2
Oil Recovery,Relative Permeability,"Redekop, E. P.; Boronin, S. A.; Tolmacheva, K., I; Burukhin, A. A.; Osiptsov, A. A.; Belonogov, E., V","Effects of salinity and rock clogging on injectivity dynamics of flooding wells: Experiments, modeling and validation on field data",Low salinity flooding; Oil displacement; Formation damage; Pore clogging; Field data,FINES-MIGRATION; WETTABILITY ALTERATION; BRINE COMPOSITION; OIL-RECOVERY; WATER; FLOW; DISPLACEMENT,"Injection of water into a rock formation is a common oilfield services technology to maintain high reservoir pressure and increase ultimate recovery of hydrocarbons. While flowing through the well from surface to the rock formation, injected water typically transports fine particles, for example, fine sand grains and calcite precipitated at surface pipeline conditions while mixing water from different sources (e.g., fresh, Cenomanian and formation brine). In the framework of the two-fluid approach to suspension flow modelling, we formulate mathematical model for linear filtration of a particle-laden suspension in the vicinity of a fractured flooding well and transport of ion concentration (salinity). Two major factors of well injectivity decline are described, namely, particle trapping with associated reduction in permeability and porosity of the rock as well as the effect of salinity of injecting water leading to clay swelling, calcite precipitation and change of relative permeabilities of the rock with respect to water and oil. We calibrate suspension filtration model against in-house experiments on clogging of artificial and natural rock cores, in which the profiles of fines concentration along the cores are obtained using X-Ray computed tomography and analysis of 3D rock reconstruction images. The water injection model is adopted to conditions of Priobskoye oilfield of Western Siberia by using the results of standard laboratory experiments on fluid-fluid (calcite precipitation) and fluid-rock (clay swelling, migration of internal fines) compatibility, as well as the effect of salinity on oil displacement and analysis of solid fraction in the injecting water. The calibrated model is then used to describe field data on dynamics of injection rate of three flooding wells. It is obtained that the simulations predict the long-term injectivity dynamics of the wells very well, while at early times (up to 5 months from the start of injection) the model underestimates the injection rate. While fitting the model to field data, we varied only two parameters, namely, solids concentration in the injecting water (in the range provided by lab experiments) and trapping coefficient (the range is limited to result of experiments made with target rock cores). It is demonstrated that only a combination of injectivity decline factors allows to describe the long-term flooding rate of the wells. Ignoring either particle trapping or salinity effects lead to significant overestimation (up to 50%) of the long-term injection rate. Parametric study of water injection showed that two-fold increase in solids concentration in the injecting water as well as oil compressibility lead to similar decrease in long-term injection rate of a well.",0,0,2
Oil Recovery,Wettability Alteration,"Khalilnezhad, Ali; Simjoo, Mohammad; Hamidian, Nima",Insights into viscous fingering effect induced by wettability alteration processes: A fractional flow study,Wettability alteration; Viscous fingering; Fractional flow; Low salinity injection,LOW-SALINITY; OIL-RECOVERY; DISPLACEMENT; INSTABILITY; MECHANISMS; INJECTION; DISPERSION,"Wettability alteration is one of the promising mechanisms for enhancement of oil recovery from preferentially oil-wet rocks. Many water-based EOR methods containing chemicals (e.g. surfactants) or ions (e.g. low salinity water: Low-Sal) were proposed to alter rock wettability to more water wetness. But, one of the possible challenges to get the full potential of such EOR methods is the occurrence of the viscous fingering phenomena. This could be the case for those of EOR methods in which an oil mobility profile over the flow domain could be formed due to the wettability alteration and thus potentially trigger viscous fingering with a negative impact on the oil displacement. In this paper, we aimed to describe this kind of viscous fingering phenomena by applying the fractional flow theory for the case of a tertiary Low-Sal injection process in a core sample previously flooded by a high salinity water. We explained the fractional flow procedure to obtain the saturation and location of the viscous fingered-region. As to the results, water saturation continuously decreases over the viscous fingered-region from an upstream point located at the Low-Sal region to a downstream point at the High-Sal region. The severity of the viscous fingering phenomena could be well addressed by the location of upstream and downstream saturation points as the proposed model honors these points. The model performance to predict breakthrough time and oil recovery factor was also validated by the previously reported Low-Sal experimental data and we found a good agreement between the model outcome and lab data.",0,0,1
Oil Recovery,Wettability Alteration,"Silva, Graciele Oliveira de Moura e; Lamas, Luis Fernando; Soares, Ana Paula",Characterization of carbonate facies and study of their relationship with dissolution and wettability in CO2 injection,Carbonate facies; Dissolution; CO2 injection; Surface complexation modeling,,"Hydrocarbon reserves can be found in porous reservoir rocks, which may be of siliciclastic or carbonate origin. Each type of rock presents its own characteristics, which directly impact the recovery of oil and gas. To better understand the heterogeneity of carbonate rocks, their geological processes and behavior of fluid flow, this work aims to characterize carbonate facies and simulate its behavior with the injection of carbonated water, evaluating the dissolution of the minerals and the superficial interactions, giving indications about the wettability of these facies. The characterization of the facies involved the observation of macro and micro images of the carbonate frameworks, identification of petrophysical characteristics and attribution to the reservoir rock. From this characterization, six facies models, three calcitic and three dolomitic, with different properties were chosen to be used in the simulation with a Surface Complexation Model (SCM) to identify the dissolution behavior of minerals and Total Bond Product (TBP) during the injection of carbonated water. This paper purpose is to analyze different carbonate facies and understand the relationship of these facies to the change in wettability due to CO2 injection. The facies were identified in four groups, travertine, biogenic, chemical, and reworked, that differ in their geological processes, identifying how the precipitation of minerals influences the geological structure. The mineral dissolution presented higher dissolution for the calcite mineral compared to dolomite, presenting significant differences between the facies and between the concentration of CO2 for both minerals. For the dissolution of kaolinite, which presented higher values when present in the dolomitic facies, significant differences were identified between the rocks, calcitic and dolomitic, between facies, between the concentrations of CO2 and the correlations between factors. The calculation of TBP, a factor that assesses oil-mineral adhesion and may interfere with rock wettability, indicated a decrease in the value as the porosity of the facies increases, however, the statistical analysis indicated that there is no significant difference between the carbon dioxide concentrations in the alteration of TBP. The results made it possible to achieve the proposed objectives, as well as to make room for subsequent discussions.",0,0,1
Oil Recovery,Wettability Alteration,"Shahmohammadi, Borhan; Chahardowli, Mohammad; Simjoo, Mohammad",Insights into the pore-scale mechanism of low salinity water injection using a clay-coated micromodel,Low-salinity; Water flooding; Crude oil polar component; Partitioning; Wettability alteration; Clay-coated micromodel; Emulsified phase,IMPROVED OIL-RECOVERY; NAPHTHENIC ACIDS; IMPACT; BRINE; SANDSTONE; RESERVOIR; EMULSION,"This study aims to provide new insights into the interactions among an acidic crude-oil, brine with different salinities and clay using flow experiments in montmorillonite-coated micromodels. To this end, a series of oildisplacement experiments are performed in a transparent clay - coated micromodel. In addition, salinityscreening tests, pH and IFT measurements are performed to support the results of flow-experiments. It is shown that during water injection into a clay-coated micromodel, polar components of crude oil partition between oil/water phases and form an emulsified phase. With the 90% reduction in water salinity, the partitioning of crude oil polar components in the aqueous phase is increased. Such partitioning lead to a significant reduction in the pH of the aqueous phase. This observation is supported by an increase in the IFT of oil/brine due to the decrease of crude oil polar components. Salinity screening tests show that there is a critical water salinity, i.e., below the critical point, a large amount of crude oil polar components is partitioned between phases, which can be attributed to the polarization effect. Overall, results show that low salinity water injection benefits from formation of an emulsified phase and wettability alteration to improve oil recovery in the microscale.",0,0,2
Oil Recovery,Wettability Alteration,"Li Yisong; Gholami, Raoof; Safari, Mehdi; Rahimi, Ali; Khur, Wee Siaw","On surface interactions of environmental friendly surfactant/oil/rock/low salinity system: IFT, wettability, and foamability",Natural surfactant; Low salinity water; Surface wettability; IFT; Sandstone,ENHANCED OIL-RECOVERY; LEAF-DERIVED SURFACTANTS; INTERFACIAL-TENSION; NATURAL SURFACTANT; ANIONIC SURFACTANT; WATER INJECTION; SMART WATER; ADSORPTION; SANDSTONE; NANOPARTICLES,"In recent years, natural surfactants have been considered as part of the EOR processes given their non-toxic and environment friendly nature. However, once chosen wisely, surfactants can only reduce the interfacial tension (IFT) and are often unable to alter the surface wettability for a better hydrocarbon production. Low salinity water (LSW) is a good candidate on these occasions, but the interaction of LSW with natural surfactants for wettability alteration has not been deeply understood. In this work, an attempt was made to extract and characterize a natural surfactant which could be used together with LSW for EOR purposes. To do this, a natural surfactant was extracted from Saponin and its physico-chemical properties such as CMC, foamability, and thermal stability were tested. A series of IFT and wettability measurements were then conducted to evaluate the performance of the surfactant as an EOR additive. The results obtained indicated that the extracted surfactant has a high thermal stability and can be fully functional in the temperature of up to 100 degrees C. It appears that increasing the level of salinity in the solution can improve the efficiency and foamability of the surfactant. It was observed that the extracted surfactant as can reduce the IFT of an air-water system by 78.65% and is capable of favorably altering the surface wettability of sandstone for a better hydrocarbon production once combined with LSW.",0,0,2
Oil Recovery,Wettability Alteration,"Redekop, E. P.; Boronin, S. A.; Tolmacheva, K., I; Burukhin, A. A.; Osiptsov, A. A.; Belonogov, E., V","Effects of salinity and rock clogging on injectivity dynamics of flooding wells: Experiments, modeling and validation on field data",Low salinity flooding; Oil displacement; Formation damage; Pore clogging; Field data,FINES-MIGRATION; WETTABILITY ALTERATION; BRINE COMPOSITION; OIL-RECOVERY; WATER; FLOW; DISPLACEMENT,"Injection of water into a rock formation is a common oilfield services technology to maintain high reservoir pressure and increase ultimate recovery of hydrocarbons. While flowing through the well from surface to the rock formation, injected water typically transports fine particles, for example, fine sand grains and calcite precipitated at surface pipeline conditions while mixing water from different sources (e.g., fresh, Cenomanian and formation brine). In the framework of the two-fluid approach to suspension flow modelling, we formulate mathematical model for linear filtration of a particle-laden suspension in the vicinity of a fractured flooding well and transport of ion concentration (salinity). Two major factors of well injectivity decline are described, namely, particle trapping with associated reduction in permeability and porosity of the rock as well as the effect of salinity of injecting water leading to clay swelling, calcite precipitation and change of relative permeabilities of the rock with respect to water and oil. We calibrate suspension filtration model against in-house experiments on clogging of artificial and natural rock cores, in which the profiles of fines concentration along the cores are obtained using X-Ray computed tomography and analysis of 3D rock reconstruction images. The water injection model is adopted to conditions of Priobskoye oilfield of Western Siberia by using the results of standard laboratory experiments on fluid-fluid (calcite precipitation) and fluid-rock (clay swelling, migration of internal fines) compatibility, as well as the effect of salinity on oil displacement and analysis of solid fraction in the injecting water. The calibrated model is then used to describe field data on dynamics of injection rate of three flooding wells. It is obtained that the simulations predict the long-term injectivity dynamics of the wells very well, while at early times (up to 5 months from the start of injection) the model underestimates the injection rate. While fitting the model to field data, we varied only two parameters, namely, solids concentration in the injecting water (in the range provided by lab experiments) and trapping coefficient (the range is limited to result of experiments made with target rock cores). It is demonstrated that only a combination of injectivity decline factors allows to describe the long-term flooding rate of the wells. Ignoring either particle trapping or salinity effects lead to significant overestimation (up to 50%) of the long-term injection rate. Parametric study of water injection showed that two-fold increase in solids concentration in the injecting water as well as oil compressibility lead to similar decrease in long-term injection rate of a well.",0,0,2
Oil Recovery,Wettability Alteration,"Santos, Denisson; Barros, Vanderson S.; Silva, Maria Luiza P.; Sales, Havila M. M. S.; Borges, Gustavo R.; Franceschi, Elton; Dariva, Claudio",Strontium-based low salinity water as an IOR/EOR method: Oil-brine interaction,Strontium based saline water; Low salinity water; Oil recovery; Interfacial properties,WETTABILITY ALTERATION; NAPHTHENIC ACIDS; INTERACTION MECHANISM; INTERFACIAL BEHAVIOR; IONIC-STRENGTH; CONTACT-ANGLE; PENDANT DROP; SMART-WATER; SURFACE; RECOVERY,"Strontium-based injection water for enhanced oil recovery has been neglected due to the low solubility of the cation in water. However, challenging reservoirs like those in the Brazilian pre-salt region demand nonconventional solutions to improve oil production. This work shows for the first time that the strontium cation in low salinity water solutions shall be henceforth considered as a potential component in the development of enhanced/improved oil recovery (EOR/IOR) studies. Acidic and non-acidic model oils and real crude oils from Brazilian post-salt and pre-salt fields were used for this study. The oil/brine interfacial tension and viscoelastic properties of the interfacial films were measured by an ascendant drop tensiometer. The results showed that strontium presents the highest interfacial activity among the other alkaline-earth metals. Also, the strontiumbased low salinity water produced the most elastic interfacial film, which is desired for the improvement of oil volumetric sweeping promoted by water flooding. Nonetheless, it is worth highlighting that further studies including core flooding experiments must be performed to assess the strontium effect on the crude oil outflow through reservoir pores as well as the influence of water/oil/rock interactions upon it.",0,0,3
Oil Recovery,Wettability Alteration,"Pashapouryeganeh, Farzad; Zargar, Ghasem; Takassi, Mohammad Ali; kadkhodaie, Ali; Rabiee, Ahmad",One-Pot synthesis of modified-cationic surfactants for enhanced oil recovery applications in carbonate reservoirs,Surfactant synthesis; Cationic surfactant; Quaternary ammonium salt; Wettability alteration; IFT reduction; Chemical enhanced oil recovery (CEOR),INTERFACIAL-TENSION BEHAVIOR; DETERMINING IONS CA2+; HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; POROUS-MEDIA; CHAIN-LENGTH; WET; MECHANISM; LIQUID,"In this study two cationic surfactants, dodecyltriethylammoniumbromide (C(12)TEAB) and hexadecyl-triethylammoniumbromide (C(16)TEAB) were prepared. The formation of synthezied surfactants were confirmed using FTIR and HNMR spectroscopy. Electrical conductivity, interfacial tension and surface tension methods were used to determine the critical micelle concentrations (CMC) of these surfactants. To understand the behavior of synthesized surfactants in harsh environments, the CMC was measured in deionized water (DIW), sea water and petroleum formation water. Using electrical conductivity technique, for C(12)TEAB surfactant the CMC values of 4000 ppm, 2000 ppm and 850 ppm were recorded in DIW, sea water and formation water respectively. For C(16)TEAB surfactant, the CMC values of 420 ppm, 190 ppm and 115 ppm were obtained in DIW, sea water and formation water respectively. The similar CMC results were obtained using the interfacial tension (IFT) and surface tension (ST) methods. Reduction of IFT between crude oil and formation water and also alteration of wettability of petroleum reservoir of carbonated rock from oil-wet (large contact angle) to water-wet (small contact angle) are two major factors affecting chemical enhanced oil recovery (EOR). Interfacial tension (IFT), surface tension (ST) and contact angle measurements were carried out using an IFT-PDSA-06 apparatus (Apex Technologies Company, Iran). The IFT and ST of these surfactants were also carried out in DIW, sea water and formation water. For C(12)TEAB surfactant, the IFT values of 0.051 mN/m, 0.036 mN/m and 0.023 mN/m were recorded in DIW, sea water and formation water respectively. The IFT values of 0.044 mN/m, 0.026 mN/m and 0.0126 mN/m were measured for C(16)TEAB surfactant in DIW, sea water and formation water respectively. The effect of temperature on IFT was studied for both surfactants. When temperature increases, IFT decreases. The reduction of IFT continues up to 55 degrees C, then the IFT increases with increasing temperature. For C(12)TEAB surfactant, the ST values of 44.9 mN/m, 38.8 mN/m and 31.8 mN/m were obtained in DIW, sea water and formation water respectively. In similar measurements for C(16)TEAB surfactant, the recorded ST values were 33.95; 32.9 and 32.22 mN/m in DIW, sea water and formation water respectively. In wettability alteration study both surfactants altered the contact angle from oil-wet to water-wet conditions. Using formation water and C(12)TEAB surfactant, the contact angle varied from 96.4 degrees to 54.5 degrees. In similar study using C(16)TEAB surfactant the contact angle changed from 92 degrees to 46.1 degrees. The contact angles of these surfactants in DIW and sea water were also measured and reported. The results of IFT and wettability studies demonstrated excellent potential application of synthesized surfactants in EOR process in carbonate petroleum reservoirs.",0,0,3
Oil Recovery,Wettability Alteration,"Boampong, Lawrence Opoku; Rafati, Roozbeh; Haddad, Amin Sharifi",A calibrated surface complexation model for carbonate-oil-brine interactions coupled with reservoir simulation - Application to controlled salinity water flooding,Low salinity water flooding; Disjoining pressure; Electrical double layer; Wettability alteration; Zeta potential; Controlled salinity water flooding,POTENTIAL DETERMINING IONS; WETTABILITY ALTERATION; STRUCTURAL APPROACH; RECOVERY; TEMPERATURE; CALCITE; CHALK; ADSORPTION; INTERFACE; CHARGE,"Vast majority of past studies that have been conducted on controlled salinity water flooding (CSWF) use diffuse layer model (DLM) that calculates only the surface potential, which can be significantly different from the xi-potential of the interface. Importantly, stability of the water-film (between the oil and the rock surface) which dictates ultimate oil recovery is related to xi-potential. As such, using DLM calculated surface potential (directly) for CSWF can be misleading. Additionally, most of the existing DLMs use integer charges instead of fractional charges to model carbonate-brine interactions, which may not represent the actual carbonate crystallographic. We present a triple layer surface complexation model (TLM) which offers the option to locate and distribute charge of the adsorbing ion(s) at three locations. TLM can therefore calculate potentials at three different locations within the Stern layer. To the best of our knowledge, only few authors have used TLM to simulate CSWF. However, some surface reactions were ignored in these models. For instance, adsorption of monovalent ions such as Na+ and Cl- ions was ignored in some of the few available TLMs. Also, the effect of basic-oil components was not considered in some TLMs, and lastly, some TLMs used integer charges for the carbonate surface group. This study introduced a comprehensive TLM that includes all these complexities. Moreover, we introduced a new wettability indicator (WI) that is related to the electrostatic forces between the oil-brine and the rock-brine interfaces. That is, WI was calculated from xi-potentials at the oil-brine and rock-brine interfaces. The TLM, built in a geochemical simulator, PHREEQC, was then coupled with UTCHEM, a multiphase reservoir simulator. The developed simulator based on the TLM-CSWF model was tested against several experimentally measured oil recovery data sets. Results of the model suggest that Oil basic component significantly impacts oil-brine interface xi-potential irrespective of temperature, brine composition, and ionic strength. On the otherhand, Na+ ions in brine may influence oil-brine xi-potential, and this relates to temperature, brine composition, and ionic strength. The results further suggest that injection of (sulfate-free) diluted brine in chalk resulted to increased oil adhesion, shifting the reservoir to oil-wet condition. Hence, no additional oil is recovered with this brine injected at tertiary oil recovery stage. Finally, the results showed that wettability is related to xi-potentials at the oil-brine and rock-brine interfaces, and the carbonate rock would be strongly oil-wet or water-wet only at significantly large magnitude of xi-potentials at the interfaces.",0,0,3
Oil Recovery,Wettability Alteration,"Abiz, Mehdi Rezaei; Norouzi-Apourvari, Saeid; Jafari, Saeed; Schaffie, Mahin",The effect of subsurface factors on the performance of nanofluid-assisted enhanced oil recovery: Modeling and sensitivity analysis,Enhanced oil recovery; Nanoparticle transport; Porous media; Wettability alteration; Mobility control,POROUS-MEDIA ROLE; WETTABILITY ALTERATION; CARBON NANOTUBES; SOLUTION CHEMISTRY; 2-PHASE FLOW; TRANSPORT; NANOPARTICLES; RETENTION; STABILITY; OXIDE,"Successful implementation of nanofluid-assisted enhanced oil recovery (EOR) operation mainly depends on proper determination of the main factors that control both transport and retention of nano-sized particles in porous media. In this study, a new transport scheme using the kinetic Langmuir model was first developed and validated by some experimental data from the literature. This model was then used to investigate the effect of reservoir rock type, clay content, grain size, brine type, and reservoir temperature on distribution of nanoparticles on the rock surface and in the injected fluid in relation to EOR methods. Moreover, a two-phase approach was derived to simulate the effect of these parameters on both wettability alteration and mobility control. Results confirmed that the deposition tendency of silica nanoparticles on limestone is higher than that on sandstone. By increasing clay content, both surface area and deposition sites increases and consequently more nanoparticles were found to retain. In the case of polyethylene glycol (PEG) stabilized silica nanoparticles, the amount of oil recovery increased by increasing the salinity of brine. Increasing the salinity of brine resulted in considerable deposition of silica nanoparticles on the rock surface and made them more water wet. These phenomena eventually increased the final recovery factor from 62% to 79%. Since the temperature simultaneously affects the deposition and detachment kinetics of nanoparticles and the reservoir fluid properties, its effect on oil recovery in nanoassisted-EOR technique cannot be generalized.",0,0,3
Oil Recovery,Ratio,"Liu, Nannan; Chen, Xinglong; Ju, Binshan; He, Yanfeng; Yang, Yong; Brantson, Eric Thompson; Tian, Yapeng",Microbubbles generation by an orifice spraying method in a water-gas dispersion flooding system for enhanced oil recovery,Micron-sized microbubbles; Visual device; Orifice spraying method; Orifice plate materials; Water-gas dispersion flooding system,PERMEABILITY; TEMPERATURE; SEPARATION; BEHAVIOR; BUBBLES,"In China, many oilfields with low permeability and heterogeneity have entered the secondary oil recovery stage, in which more oil displacement agents for expanding sweep volume has become a key technology. A water-gas dispersion flooding system is reasonably proposed to change the seepage resistance and adjust the mobility ratio. In this FOR technique, the generation of micron-sized bubbles in the low-permeability reservoir is of considerable interest. In this study, a visual device by using an orifice spraying method was designed to simulate reservoir conditions with high temperature and high pressure, and efficiently to produce more microbubbles. Based on the orifice spraying method, the morphological characteristics of microbubbles generated by different orifice plate materials were compared, which provided the choice of the microbubbles generation by the orifice spraying method for laboratory experiments. Besides, the influence of different factors on the quantity and size of microbubbles produced by a single orifice plate was presented in detail. The experimental results showed that the diameter of the microbubbles generated by the orifice spraying method under a hypothetic reservoir condition was about 10-100 mu m. These visual experimental devices were practically designed to meet the demand of the micron-level pores and throats to enhance oil recovery in low-permeability reservoirs. This investigation of microbubbles generation provided the basic research means for further preparation of a water-gas dispersion flooding system.",0,0,0
Oil Recovery,Ratio,"Shojaiepour, Mohammadali; Rashidi, Fariborz; Dabir, Bahram; Amirsardari, Mahdi",A treatment protocol for controlling gas oil ratio in heterogeneous carbonate reservoirs by foam injection: Case study simulation,Foam injection; Gas channeling; Gas overriding; Gas oil ratio; Heterogeneous carbonate reservoir; Production well treatment,RECOVERY,"In this study, foam is selected to treat production wells of heterogeneous reservoirs that are suffering from high amounts of gas oil ratio (GOR). To this end, a numerical study is carried out by injecting foam through the perforations that produce high amounts of gas to block the gas path and allow much more oil to be simultaneously produced from the remaining perforations by applying a new technology in well completion. For this purpose, three heterogeneous synthetic base sectors are simulated in which large amounts of injected gas are produced from the upper, middle and lower perforations of the producing well, known as gas overriding, gas channeling-midriding and gas channeling-underriding, respectively. Since Kv/Kh is an important, decisive and effective parameter, different values of it have been considered for each of three base sector models including 0.001, 0.01, 0.1, 0.3, 0.5, 0.7, 0.9 and 1.0. Then, depending on the magnitude of Kv/Kh, the most optimal treatment method is sensitivity analyzed. In the following, foam injection parameters, e.g. surfactant concentration, depth of packer set, foam injection sequence and foam injection rate are sensitivity analyzed. Also, the phenomenon of gas cross-flow during the treatment process is investigated. The simulation results show that if after some time following well treatment, the GOR level increased, it is suggested to take a production test to determine what length of the production well below the packer produces lots of gas to set the packer at the lower depth and inject a larger volume of foam to block that gas path so that the GOR is reduced. The results also conclude that the magnitude of Kv/Kh on one hand and the location of gas entry to the production well on the other hand play a key role in the selection of the best treatment scenario in heterogeneous reservoirs. This has led to presenting a protocol for treatment of high GOR production wells in a wide range of reservoirs based on anisotropy ratios. Finally, in order to validate the protocol, a real specific sector of a heterogeneous carbonate reservoir located in the Middle East, in which the GOR level has increased, is simulated and treated. The results indicate that the protocol is efficient and causes a reduction in GOR by 60%.",0,0,0
Oil Recovery,Ratio,"Kalam, Shams; Yousuf, Usama; Abu-Khamsin, Sidqi A.; Bin Waheed, Umair; Khan, Rizwan Ahmed",An ANN model to predict oil recovery from a 5-spot waterflood of a heterogeneous reservoir,ANN; ANFIS; SVR; Waterflooding,ARTIFICIAL NEURAL-NETWORK; POROUS-MEDIA; PERFORMANCE; SELECTION; GAS; INTELLIGENCE; REGRESSION; AKAIKE; FLOW,"Waterflooding is a secondary oil recovery technique in which water is injected into an underground oil reservoir to maintain the reservoir pressure and boost oil recovery. The performance of a waterflood depends on several factors such as reservoir heterogeneity, reservoir fluid properties, flood pattern, etc. Most of the models developed to predict waterflood performance are either for linear systems or involve simplified assumptions for nonlinear systems. In this study, we propose a novel, artificial neural network (ANN) model comprised of two hidden layers with 256 neurons each for the performance prediction of a 5-spot pattern waterflood in a heterogeneous reservoir at and beyond water breakthrough. The proposed model can be applied to estimate movable oil recovery efficiency of the waterflood (RFM) as a function of Dykstra-Parsons permeability variation coefficient (V), mobility ratio (M), permeability anisotropy ratio (kz/kx), production water cut (fw), a simple indicator of wettability (WI), and oil/water density ratio (DR) within reasonable accuracy. The MAPE of the proposed model was -4% and -5% using training and testing data, respectively. Our ANN model recommendation is based on a detailed comparative study against other popular soft computing models, such as adaptive neuro-fuzzy inference system (ANFIS) and support vector regression (SVR). Based on the accuracy and computational efficiency, the ANN model outperforms ANFIS and SVR. AIC and BIC of the proposed ANN model were also the lowest among all applied soft computing tools. The proposed model is tested on two real field cases and compared with a semianalytical model and an empirical correlation. The presented model shows good agreement with the real field data. The trained ANN model, proposed here, saves computational time in forecasting the waterflood performance compared to a reservoir simulator.",0,0,1
Oil Recovery,Ratio,"Sheikha, Ammar; Sheikha, Hussain",Top lean zone and cardinal parameters affecting SAGD,SAGD; Thermal EOR; Lean zone; High water saturation; Oil sands; Long Lake pilot; Surmont pilot,,"SAGD is a thermal recovery process in which steam oil ratio, SOR, is a key parameter that can affect the economic outcome of the process. Reservoirs with underlying or overlying lean bitumen present challenges for SAGD as they can act as a heat sink. Water has higher heat capacity than the bitumen and thus requires more steam to heat up the reservoir leading to higher SOR. The potential outcome of operating SAGD in these conditions may be lower bitumen rate and higher steam injection rate, both of which affect plant throughput and thus the economic matrix of SAGD. This paper looks at the performance of SAGD process in the presence of top lean bitumen. It will examine the theoretical CSOR that is needed to produce the bitumen with different water saturations and will highlight the key parameters of lean bitumen affecting SAGD performance. The paper reviews performance of several fields where lean bitumen is present. The paper also analyzes simulation results to examine the impact of water saturation and the size of lean bitumen resource on the SAGD process.",0,0,1
Oil Recovery,Ratio,"Monette, Matthew; Nguyen, Quoc P.",Investigation of the effect of gas compositions on low-tension-gas flooding,Foam; Microemulsion; Low tension gas flood; Enhanced oil recovery; Sandstone reservoirs,FOAM STABILITY; TEMPERATURE; PRESSURE,"Gas floods have long been used for enhanced oil recovery, however they often times require miscible conditions within the reservoir to be successful. If this reservoir has been depleted and no longer contains the internal pressure to achieve these miscible conditions, an enhanced oil recovery technique known as Low Tension Gas (LTG) may be a better alternative that has been proven to increase oil recovery. This LTG process is a technique which involves either co-injection or alternating injection of gas and an optimized aqueous surfactant solution to both improve mobility control and reduce the interfacial tension between the oil and aqueous phases. When paired with specifically selected surfactants, the injected gas will create an in-situ generated foam which increases the apparent viscosity and acts as a mobility control agent to improve sweep efficiency. The optimized surfactant formulation also has the ability to generate ultra-low interfacial tension between the oil and aqueous phases. This reduced IFT allows the previously trapped oil to become mobile and the added mobility control from the foam better allows for this mobile oil to exit the porous media. The impact of hydrocarbon gas as the co-injected gas was investigated and found to be not only compatible with, but ultimately beneficial to the LTG process. The use of hydrocarbon gas at elevated pressures had a notable impact on phase behavior by slightly lowering the optimum salinity, while significantly increasing the solubilization ratio. This increase in solubilization ratio corresponds to a lower IFT experienced between the oil and aqueous phases, leading to improved oil recovery. This investigation also noted that in the presence of Type I microemulsion, foams created using a hydrocarbon gas composition, appeared to produce a slightly lower foam strength than that of previously used nitrogen. However this slight decrease in foam strength was more than offset by the significant increase in solubilization ratio. Using different hydrocarbon gas compositions as the injected gas during a series of corefloods presented an increase in both the recovery rate and ultimate recovery. This suggests that repurposing produced hydrocarbon gas may not only be the environmentally responsible decision, but also economically advantageous as this may allow for a decrease in surfactant costs used within a Low Tension Gas flood while still achieving the same improved oil recovery.",0,0,1
Oil Recovery,Ratio,"Zhao, Yang; Bai, Baojun",Selective penetration behavior of microgels in superpermeable channels and reservoir matrices,Enhanced oil recovery; Conformance control; Gel treatment; Preformed particle gel; Threshold penetration pressure,PREFORMED PARTICLE GEL; CONFORMANCE-CONTROL; ELASTIC MICROSPHERES; WATER; SUSPENSIONS; SIMULATION; TRANSPORT,"Gel treatment is an effective way to attack excessive water production in many mature oilfields around the world. Selective penetration is desired for successful gel treatments. That is, gel materials should easily penetrate the target zones (i.e., channeling features such as superpermeable channels) without entering/damaging the nontarget zones (i.e., reservoir matrices or oil zones). This study revealed that presence of threshold penetration pressure (Delta Pth) was responsible for selective penetration behavior of tested microgels. The concept of Delta Pth was utilized to figure out favorable working conditions for effective gel treatments. Microgel dispersions were injected into superpermeable (super-k) sandpacks (mimicking super-k channels in reservoirs, 60-221 darcies), heterogeneous models with super-k channels (79-230 darcies), and sandstone cores (mimicking reservoir matrices, 50-5000 md). The results demonstrated that a minimum differential driving pressure (i.e., threshold penetration pressure, Delta Pth) was required to push microgel particles to penetrate channels or matrices. The critical penetration behavior was closely related to the particle/pore size ratio. Low Delta Pth at smaller particle/pore ratios was beneficial to allow easy penetration of gel materials into the channeling zones. On the contrary, high Delta Pth at larger particle/pore ratios was desirable to prevent gel materials from massively invading and damaging the matrices. Instead, the gel particles accumulated at the inlet surface, and a gel cake was gradually formed. The cake further prevented the invasion of the gels. The cake could be removed by chemical breakers to resume the injectivity/productivity of the matrices. Correlations were developed to describe the relationship between Delta Pth and particle/pore ratio. A distinct transition was identified at the particle/pore ratio of about 3. This work could help identify the favorable conditions to achieve successful gel treatments. In an effective conformance treatment, the particle/pore ratio in the channel should be sufficiently low to allow easy penetration of gel materials into the channel (e.g., particle/pore ratio<2 in this study). Meanwhile, the particle/pore ratio in the matrix should be large enough to support a high Delta Pth and thus prevent massive gel invasion into the matrix. This study advances the current pore scale studies (a single particle passing through a single channel) to Darcy-scale characterization.",0,0,2
Oil Recovery,Ratio,"Sun, Zhifeng; Bai, Qinglin; Ren, Huaiqiang; Yan, Ke; Gao, Liang; Wei, Liu Zhong","Quantitative evaluation of morphological characteristics of thin sand body: Taking the deltaic distributary channel sand body as an example in Shengtuo oil field of Dongying sag, east of Bohai Bay Basin*",Thin interbeds; Distributary channel; Architecture; Quantitative model; Sandstone reservoir,SEISMIC ATTRIBUTES; RESERVOIRS; DEPOSITS; ARCHITECTURE; DEPRESSION; PREDICTION,"Because of the small scale of distributary channel sand body and the superposition of sand bodies in vertical and lateral direction, drilling data with 150-200 m well spacing is difficult to describe its scale, shape and connectivity characteristics effectively. It has a great restriction on the recovery of these reservoirs. Taking Sheng2 Block of Shengtuo Oilfield as an example, the architectural elements of distributary channel are quantitatively investigated by using dense-drilling well and seismic data. Based on frequency division seismic data, the boundary of distributary channel belts are described vertically and laterally, and then the scale and morphological characteristics of channel bodies in the channel belt are characterized by using local dense well pattern data. The target layer can be divided into six channel belts longitudinally. After seismic frequency demultiplication, 60-75 Hz seismic data was used to describe the distribution of channel belts. From the bottom to the top, the width and distribution range of the channel belts decrease as a whole. Channel belt thickness and its width show linear positive correlation. On the channel-belt cross section, channel stories on the dense drilling-well logging profiles are identified with reference to the profile geometry of the distributary channel. On the channel-belt cross section, the projection distance between wells is fitted to a linear correlation with the thickness variation of channel stories. The ratio of the two parameters decreases from bottom to top of the target layer as a whole. The channel shape parameters predicted by the dense drilling-well logging section are of great significance to the study of paleocurrent deposition and paleohydrological evolution. At the same time, it has guiding significance for the development and adjustment of oil and gas reservoirs.",0,0,2
Oil Recovery,Ratio,"Khan, Mohammad Yunus; Mandal, Ajay",Analytical model of incremental oil recovery as a function of WAG ratio and tapered WAG ratio benefits over uniform WAG ratio for heterogeneous reservoir,EOR; Analytical model; Tapered WAG; Uniform WAG; Reservoirheterogeneity; WAG incremental oil recovery; Gas utilization factor,GAS; INJECTION; EFFICIENCY; DESIGN; DISPLACEMENTS; OPTIMIZATION,"The water-alternating-gas (WAG) operating scheme and reservoir permeability heterogeneity are the main crucial parameters, which highlyaffect WAG displacement process. The novelty of this article lies in the development of an analytical model for WAG incremental oil recovery as function of WAG ratio, viscous gravity ratio and mobility ratio for the stratified heterogeneous reservoir. We have investigated the effect WAG ratio on WAG incremental oil recovery with variation horizontal permeability heterogeneity, vertical permeability anisotropy and dip angle of the reservoir. The critical operating parameters investigations were carried to optimize WAG displacement process in both homogeneous and heterogeneous reservoirs. Finally, we have estimated all the benefits of the most suitable techno-economical WAG operating scheme as tapered WAG (TWAG) over uniform WAG (UWAG). The developed analytical model showsreasonably similar results as numerical simulation. The results of the analytical and numerical analysisshow that the incremental oil recovery accelerated bya decrease WAG ratio. However, this effect is more noticeable at high viscous gravity (VGR). The increase in reservoir dip angle subsequently increases vertical and displacement sweep efficiencies compared to the horizontal reservoir for different WAG ratio. While increasing WAG ratio decreases vertical sweep and increases displacement sweep of inclined reservoir compared to the horizontal reservoir. The increase of oil recoverywas observed by higher Kv/ Kh with a lower WAG ratio. However, this effect is less evident at lower Kv/Kh. The WAG ratio with a higher proportion of water is beneficial for the heterogeneous reservoir. The infill implemented before WAG start shows faster oil recovery compared to WAG start first then infill implemented in the heterogeneous reservoir. The TWAG incremental recovery over water flood was 18% in homogeneous and 8% in heterogeneous reservoirs, while EUR was approximately similar to UWAG. The TWAG shows more efficient techno-economic benefits over UWAG due to better economics, faster oil recovery rate, more efficient use of injected gas and reduces response time in both homogeneous and heterogeneous reservoirs.",0,0,2
Oil Recovery,Ratio,"Al Ghafri, Al Yaqathan; Mackay, Eric; Stephen, Karl",The relevance of the linear stability theory to the simulation of unstable immiscible viscous-dominated displacements in porous media,Instability predictor; Saffman-Taylor instability; End-point mobility ratio; Fractional flow analysis; Viscous oil; Polymer flooding; Correlated random field,MISCIBLE DISPLACEMENT; INSTABILITIES; MECHANISM; POLYMER; GROWTH; MODELS; FLUID,"The 2D governing equations for the immiscible two-phase flow admissible to linear stability analysis are inspected. The identification of the term v(ws)delta D-st in the generalized Saffman-Taylor criterion is key to the analysis. It can be regarded as a predictor that correlates with observed immiscible instability in terms of the rate of advancement of the viscous pattern, the number of small protrusions, and their roughness in a given heterogeneous domain described by a correlated random field. The predictor is extended, heuristically, for polymer flooding shock-wise and used to characterize the instability of the two shocks. The extension is validated by simulation. The instability of the primary shock is essential when considering the breakthrough recovery. In light of the instability predictor, the geometric interpretations of the fractional flow are essential to understand the stability enhancement of the primary shock over the Buckley-Leverett shock in water flooding. It is also concluded that the end-point mobility ratio does not directly control the immiscible instability. This conclusion was arrived at by fixing the end-point mobility ratios for three sets of relative permeability curves, and yet noticeably different instabilities occur, both in transverse and correlated random fields. The criterion can predict the viscous instability in the laboratory experiments under certain flooding conditions and sample configurations. Concerning the instability in a field scale, the predictor is applicable if the field is regarded as a prototype of a given model experiment.",0,0,2
Oil Recovery,Residual Oil,"Kryganov, P., V; Afanaskin, I., V; Volpin, S. G.; Akhapkin, M. Yu; Yalov, P., V",Searching for reservoirs with bypassed oil using well tests and mathematical modeling,Bypassed oil; Residual oil reserves; Hydrodynamic simulation; Well test; Pressure buildup test; Interference test; Flow analysis,,"The increase of oil recovery by the involvement of bypassed oil into production is a significant source of oil production increase at a minimal cost. Bypassed oil zones identification possibilities researched through mathematical flow modeling and simulated well tests. Two hypothetical models of homogeneous and heterogeneous (with low permeability zones) oil formations were generated, in which the bypassed oil was trapped during the production. Based on these models, the authors calculated data of comprehensive well tests: buildup, drawdown and interference. The aspects of the well test interpretation results data obtained for both models through the best-match method allowed bypassed oil areas identification possibility assessment. A significant difference between the cumulative oil rate actually observed at the field and the one obtained in the model is the first diagnostic feature, which suggests the presence of bypassed oil. During the pressure buildup (drawdown) tests, the curves of pressure change derivatives on the Bourdet diagnostic plots for heterogeneous and homogeneous models differ significantly, which is the second diagnostic feature that suggests the presence of bypassed oil. The analysis of the data processing results obtained during the pressure buildup tests indicated cases of significant changes in conductivity over time which is associated with higher water cut due to the absence of any obstacles for water to flow through. This factor can be considered a third diagnostic feature. During the interference tests of a heterogeneous model in multiple directions, the permeability of the interwell space in all directions turned out to be much lower in comparison to the reservoir permeability in the vicinity of the wells, that is explained by the bypassed oil presence - this is the fourth diagnostic feature which suggests the bypassed oil presence in the interwell space. The obtained results of well test data interpretation means a possibility to identify undeveloped areas with bypassed oil, filtration model improvement and recommendations development of infill drilling or sidetracks for the residual reserves extraction.",0,0,0
Oil Recovery,Residual Oil,"Ligeiro, Tayanne S.; Vaz, Alexandre; Chequer, Larissa",Forecasting the impact of formation damage on relative permeability during low-salinity waterflooding,Low-salinity waterflooding; Fines migration; Relative permeability; Formation damage; Particle detachment; Coreflood experiments,FINES-MIGRATION; POROUS-MEDIA; INJECTIVITY DECLINE; SWEEP EFFICIENCY; SLOW MIGRATION; OIL-RECOVERY; FLOW; PARTICLES; TRANSPORT; RELEASE,"Low-salinity waterflooding is considered to be an advanced oil recovery method, but the main mechanism behind the increase in oil recovery factor is still under investigation. Fines migration has been recognized to be one of the mechanisms responsible for the increase in oil production. In this case, the increase in oil recovery happens as a result of increased sweep efficiency and consequent reduction of residual oil. The release of particles due to reduction of electrostatic forces results in flux diversion to previously unswept areas in the reservoir, increasing oil recovery. This paper provides a better understanding of the effects of formation damage during low-salinity water injection in Berea sandstones and proposes a methodology to forecast its effects on water relative permeability. We have performed one- and two-phase flow coreflood experiments with varying salinity of the injected solution. The effluent was analysed for salinity, pH and particle concentration. The laboratory data was treated using a mathematical model that accounts for permeability impairment during low-salinity waterflooding due to fines detachment, migration and capture in small pore throats. The parameters of the model were used to predict the impact of formation damage on the water relative permeability during two-phase flow. The mathematical model matched the laboratory data for pressure drop and particle concentration in the outlet with great accuracy. A methodology to predict the impact of formation damage in two-phase flow using one-phase flow data was proposed. A good agreement between the predicted and the measured water relative permeabilities was obtained. The forecasted water relative permeability curve was able to reproduce the non-monotonic behaviour of water relative permeability due to low-salinity water injection.",0,0,0
Oil Recovery,Residual Oil,"Aboelkhair, Hamed; Diaz, Pedro; Attia, Attia",Biosurfactant production using Egyptian oil fields indigenous bacteria for microbial enhanced oil recovery,Microbial enhanced oil recovery; Indigenous bacteria; Biosurfactant; Bacillus subtilis; Surface activity; Critical micelle concentration,BACILLUS-SUBTILIS; SURFACTANT; LICHENIFORMIS; OPTIMIZATION; WETTABILITY; HYDROCARBON; INJECTION; MOLASSES; STRAINS,"Biosurfactant production is one of the most efficient mechanisms in microbial enhanced oil recovery (MEOR) processes. This work investigates the production of biosurfactants by indigenous bacteria isolated from Egyptian oil fields, and how to optimize these produced biosurfactants for MEOR. 59 Egyptian oil reservoirs were screened to evaluate the potential applicability of MEOR processes, based on their rock and fluid properties. Results showed that 8 reservoirs from the Gulf of Suez and 3 reservoirs from the Western Desert had the potential to MEOR. Combined analysis of morphological, and biochemical characterization was performed on the 11 bacterial strains isolated from different crude oil samples collected from the reservoirs that have the potential to MEOR process to identify their types. Bacillus spp, a bacilli species that can produce biosurfactants, was selected for further studies. To optimize the surface activity of the produced biosurfactant, ten different reported nutrient media, and a new proposed nutrient media were examined. Bacillus spp has shown the ability to produce a very active biosurfactant that reduced the surface tension of water from 71.8 +/- 1.9 mN/m to 25.7 +/- 1.2 mN/m, and the interfacial tension of water against kerosene from 48.4 +/- 2.1 mN/m to 0.38 +/- 0.07 mN/m at Critical Micelle Concentration (CMC) of 0.04 +/- 0.01 g/l, in a medium supplemented by the new proposed nutrient medium H. The growth rate of Bacillus spp was studied, and it was found it reached its maximum (OD600nm 2.59 +/- 0.16) after 24 h of incubation. Biosurfactant production has no significant change in its surface activity over a wide range of temperature range up to 120 degrees C, which means the studied species Bacillus spp is a thermophilic bacterium. Bacillus spp grew well in the presence of high salt concentration up to 20% (w/v) NaCl, the optimal surface activity was obtained in the range of 0-2% (w/v) NaCl, and at pH 7. The emulsification activity of the produced biosurfactant was examined, and it reached the maximum (69.6 + 1.5%) against kerosene at temperature 25 degrees C, Salinity 0% (w/v) NaCl (distilled water), and pH 7. The produced biosurfactant was purified and extracted by acid precipitation method, and the biosurfactant yield of the purified compound was found to be 2.8 +/- 0.3 g/l. Finally, the core-flooding experiments were conducted to investigate the effect of produced biosurfactants by Bacillus subtilis in oil recovery. The obtained results reveal the potential of Bacillus spp to grow in the new proposed medium H and produce effective and efficient biosurfactants that enhanced oil recovery by 25.19-39.35% of additional oil over the water flooding residual oil saturation in the studied cores and retain more than 60% of its surface activity under harsh conditions and that are relevant to Microbial Enhanced Oil Recovery, MEOR.",0,0,2
Oil Recovery,Residual Oil,"Al-Shami, Tareq Mohammed; Jufar, Shiferaw Regassa; Negash, Berihun Mamo; Abdullahi, Mohammed Bashir",Impact of external excitation on flow behavior of trapped oil blob,Oil mobilization; Unconventional EOR; External excitation; Seismic stimulation; Flow behavior,CAPILLARY TUBES; OSCILLATORY FLOW; RECOVERY; DROPLETS; WAVES; MOBILIZATION; STIMULATION; RESONANCE; WATER,"External excitation of oil reservoirs has shown promising potential in increasing residual oil recovery. Although several numerical, experimental, and pilot studies were conducted over the last decades, large-scale field application is not realized due to inconclusive results on its performance. This paper aims to investigate the effect of external excitation on the flow behavior of an oil blob trapped in a constricted capillary tube model. Flow evolution and characteristic flow behaviors were studied using computational fluid dynamics (CFD) simulations. An external excitation with a sinusoidal profile propagating in the axial direction was applied at the wall of the constricted capillary tube model. The excitation intensity and frequency were varied to identify the flow characteristics. The results show that under the influence of external excitation, three distinct flow regimes develop based on the excitation frequency and intensity; these are trapped, clear pass, and dispersed pass. Velocity profiles, streamlines, and pressure contours were used to examine the resulting flow behaviors. In addition, dimensional analysis was carried out, and the dominant factors in each flow regime were identified. The dominant dimensionless numbers are Euler number, Reynolds number, and Weber number. Accordingly, the three flow regimes were mapped in the domains of these dimensionless numbers. As such, under given flow conditions, fluid properties, and external excitation parameters, the subsequent flow behavior can be predicted using the characteristic flow behavior maps presented in the study. Moreover, any of these flow regimes can be induced for a given application by tuning the excitation parameters based on the dimensionless characteristic maps presented.",0,0,2
Oil Recovery,Residual Oil,"Wang, Jinxun; AlSofi, Abdulkareem M.; Boqmi, Abdullah M.",A core-scale study of polymer retention in carbonates at different wettability and residual oil conditions,Polymer flooding; Polymer retention; Wettability; Residual oil; Inaccessible pore volume,ADSORPTION; FLOOD; FIELD,"As an effective technique to improve oil recovery, polymer flooding has been successfully used worldwide in many fields. The retention of polymer in reservoir increases the project cost, retards polymer transport, and thus delays the incremental oil response. Therefore, low polymer retention is crucial for a successful polymer-flooding project. Accurate quantification of this parameter is accordingly essential. Polymer retention is often evaluated in the absence of oil, which is not representative of the polymer-flooded oil regions in the reservoir. There is also a lack of consensus on the wettability impact on retention in the literature. In this work, the polymer retention in carbonates is investigated at varied wettability conditions, in the presence of oil as well as in the absence of oil. A sulfonated polyacrylamide polymer is evaluated in this study, and representative reservoir fluids and core samples are used in the experiments. The results demonstrate that the studied polymer exhibits relatively low retention in the carbonate cores, ranging from 20.9 to 60.8 mu g/g-rock. The inaccessible pore volume (IPV) ranges from 9.0 to 12.0% pore volume (PV). These results demonstrate a potential of this polymer for carbonate reservoir applications. More importantly, the results indicate that the polymer retention is reduced more than 50% in the presence of residual oil. In other words, the presence of oil in actual reservoir condition has a positive side in terms of polymer consumption. Accordingly, it is a factor that must be either simulated or accounted for. On the other hand, the results suggest that the wettability impact on polymer retention is small compared to the presence of oil. Furthermore, both residual oil and wettability have insignificant impact on polymer IPV. In summary, the polymer retention results from single phase displacement experiments tend to be more conservative. When using these retention estimates for designing a polymer flooding project, their conservative nature should be kept in mind or factored in.",0,0,2
Oil Recovery,Residual Oil,"Wang, Qiong; Jiang, Ruizhong; Leng, Jie; Liu, Xiuwei",The effect of the viscosity-dependent boundary layer on tight oil flow behavior in CO2 Huff-Puff processes: A unified dimensional Pre-Darcy flow model,Pre-Darcy flow; Compositional simulation; CO2 EOR,N-PUFF; RESERVOIR SIMULATION; NUMERICAL-SIMULATION; FRACTURE NETWORKS; RECOVERY; SHALE,"There are numerous percolation studies of unconventional reservoirs showing that in tight or low-permeability formations, the oil flow behavior could be described by the Pre-Darcy mechanism. However, for the CO2 Huff-nPuff operations, the most presented low-velocity Pre-Darcy flow models may result in an erroneous evaluation due to the intensive boundary layer thickness changes caused by the CO2 extraction and dissolution. In this paper, with multiple parameters fitting the seepage experimental results of the studied area, a unified dimensional Pre-Darcy flow model for CO2 enhanced oil recovery (EOR) is derived from the classic Poiseuille model. Then, the proposed flow model is applied in the compositional simulator for analyzing the viscosity-dependent boundary layer (VDBL) effect, applicability evaluation in Huff-Puff EOR, and field history matching. The results indicate that the VDBL effect improves the oil mobility in injection periods and lowers the residual oil saturation at the front of the CO2 convection-diffusion area in reproduction periods. Additionally, the nonlinear parameter alpha and the shape parameter beta enhance the proposed model's applicability for the Huff process and the Puff process respectively. Finally, by adjusting the parameters alpha and beta for different permeability intervals of the geological model, the flow model is successfully applied in the oil production matching of the Y6 well, which exhibits its reliability in the history matching.",0,0,3
Oil Recovery,Low Permeability,"Motahhari, S. Mahdia; Rafizadeh, Mehdi; Pishvaie, Mahmoud Reza; Ahmadi, Mohammad",An innovative workflow for selecting appraisal area in low permeability greenfield development under uncertainties,Probabilistic appraisal opportunity index; Appraisal candidate area; Low permeability field development; Fuzzy clustering; Shannon entropy; Uncertainty,WELL PLACEMENT; INFORMATION; OIL,"There are uncertainties in both inherent geological properties and IOR/EOR performance parameters of low permeability greenfield reservoirs. Therefore, efforts to reduce uncertainties in the appraisal phase are necessary for the development and production phases. An adequate selection of the appraisal area in the hydrocarbon field is an imperative factor since the results of the appraisal well drilling and IOR/EOR pilot tests will be utilized for the development of the entire field. The major challenge in selecting an appraisal area is the lack of an integrated and systematic approach. In this study, we present a novel systematic and quantitative approach consisting of a better representative of reservoir features. To do this, some sort of cluster analysis over multiple realization is utilized. The underlying field of study is firstly segmented into appraisal candidate areas. Afterwards, the corresponding covariance matrix and recovery factor arrays are calculated for the simulated 3-D reservoir quality maps in the areas. The areas are optimally clustered by fuzzy clustering method to choose the dominant cluster. Subsequently, the distances between each area and the center of dominant clusters could be used as a criterion for decision making. Moreover, the coefficient of variation for the oil volume changes is another criterion. Finally, the Shannon entropy weighting along with Reference Ideal Method (RIM)-Multi Attribute Range Evaluations (MARE) are applied. They are used as a multi-criteria decision-making method to calculate the Probabilistic Appraisal Opportunity Index (PAOI) in each area. The proposed method was applied for an appraisal study on an oil field in southwest Iran and, the optimum appraisal area is thereby determined based on the PAOI.",0,0,0
Oil Recovery,Low Permeability,"Kryganov, P., V; Afanaskin, I., V; Volpin, S. G.; Akhapkin, M. Yu; Yalov, P., V",Searching for reservoirs with bypassed oil using well tests and mathematical modeling,Bypassed oil; Residual oil reserves; Hydrodynamic simulation; Well test; Pressure buildup test; Interference test; Flow analysis,,"The increase of oil recovery by the involvement of bypassed oil into production is a significant source of oil production increase at a minimal cost. Bypassed oil zones identification possibilities researched through mathematical flow modeling and simulated well tests. Two hypothetical models of homogeneous and heterogeneous (with low permeability zones) oil formations were generated, in which the bypassed oil was trapped during the production. Based on these models, the authors calculated data of comprehensive well tests: buildup, drawdown and interference. The aspects of the well test interpretation results data obtained for both models through the best-match method allowed bypassed oil areas identification possibility assessment. A significant difference between the cumulative oil rate actually observed at the field and the one obtained in the model is the first diagnostic feature, which suggests the presence of bypassed oil. During the pressure buildup (drawdown) tests, the curves of pressure change derivatives on the Bourdet diagnostic plots for heterogeneous and homogeneous models differ significantly, which is the second diagnostic feature that suggests the presence of bypassed oil. The analysis of the data processing results obtained during the pressure buildup tests indicated cases of significant changes in conductivity over time which is associated with higher water cut due to the absence of any obstacles for water to flow through. This factor can be considered a third diagnostic feature. During the interference tests of a heterogeneous model in multiple directions, the permeability of the interwell space in all directions turned out to be much lower in comparison to the reservoir permeability in the vicinity of the wells, that is explained by the bypassed oil presence - this is the fourth diagnostic feature which suggests the bypassed oil presence in the interwell space. The obtained results of well test data interpretation means a possibility to identify undeveloped areas with bypassed oil, filtration model improvement and recommendations development of infill drilling or sidetracks for the residual reserves extraction.",0,0,0
Oil Recovery,Low Permeability,"Liu, Nannan; Chen, Xinglong; Ju, Binshan; He, Yanfeng; Yang, Yong; Brantson, Eric Thompson; Tian, Yapeng",Microbubbles generation by an orifice spraying method in a water-gas dispersion flooding system for enhanced oil recovery,Micron-sized microbubbles; Visual device; Orifice spraying method; Orifice plate materials; Water-gas dispersion flooding system,PERMEABILITY; TEMPERATURE; SEPARATION; BEHAVIOR; BUBBLES,"In China, many oilfields with low permeability and heterogeneity have entered the secondary oil recovery stage, in which more oil displacement agents for expanding sweep volume has become a key technology. A water-gas dispersion flooding system is reasonably proposed to change the seepage resistance and adjust the mobility ratio. In this FOR technique, the generation of micron-sized bubbles in the low-permeability reservoir is of considerable interest. In this study, a visual device by using an orifice spraying method was designed to simulate reservoir conditions with high temperature and high pressure, and efficiently to produce more microbubbles. Based on the orifice spraying method, the morphological characteristics of microbubbles generated by different orifice plate materials were compared, which provided the choice of the microbubbles generation by the orifice spraying method for laboratory experiments. Besides, the influence of different factors on the quantity and size of microbubbles produced by a single orifice plate was presented in detail. The experimental results showed that the diameter of the microbubbles generated by the orifice spraying method under a hypothetic reservoir condition was about 10-100 mu m. These visual experimental devices were practically designed to meet the demand of the micron-level pores and throats to enhance oil recovery in low-permeability reservoirs. This investigation of microbubbles generation provided the basic research means for further preparation of a water-gas dispersion flooding system.",0,0,0
Oil Recovery,Low Permeability,"Zhang, Jin; Wang, Dongmei",Aqueous imbibition further investigation on contact area penetration enhancement for hydrocarbon extraction from tight rocks,Forced imbibition; Surfactant EOR; Acid stimulation; Tight formation; Carbonate,OIL-RECOVERY; SHALE; WET,"The rapid decline of production and low oil recovery in shale and other tight formations have been identified in practice. Surfactant EOR has been considered as one of the best options for those challenging formations. Many studies indicated that the oil recovery was improved by surfactant spontaneous imbibition in a huff-n-puff mode. However, the slow oil extraction rate and the limited penetrating area into the rock matrix by laboratory experimental results indicated it might be impractical for real-time extraction. To address this problem for the carbonate-rich tight formations, a new approach of forced surfactant imbibition process coupled with enhanced contact area stimulation (acidizing, for instance) was proposed. In this paper, samples from the Middle Bakken were used for the laboratory studies. A chemical formulation (CF) consists of surfactant, organic acid, and other components was designed to evaluate the effects on carbonate-rich rocks, rock microstructure and petrophysical properties (porosity and permeability). Oil recovery was also examined by forced imbibition with chemical formulation. Research results demonstrated that CF treatment could dissolve the carbonate minerals in the Bakken rocks resulted in the microstructure changes. These changes led to the injected fluid deeply imbibe into the rock matrix and therefore enlarge the rock-fluid contact area. Rock porosity and permeability were increased and oil recovery was significantly improved with the designed chemical formulation through forced imbibition. In a summary, this laboratory study of combination of acid stimulation and forced surfactant imbibition process may serve as a possible approach for a field application to improve the hydrocarbon recovery from well to well besides of huff-n-puff method.",0,0,1
Oil Recovery,Low Permeability,"Redekop, E. P.; Boronin, S. A.; Tolmacheva, K., I; Burukhin, A. A.; Osiptsov, A. A.; Belonogov, E., V","Effects of salinity and rock clogging on injectivity dynamics of flooding wells: Experiments, modeling and validation on field data",Low salinity flooding; Oil displacement; Formation damage; Pore clogging; Field data,FINES-MIGRATION; WETTABILITY ALTERATION; BRINE COMPOSITION; OIL-RECOVERY; WATER; FLOW; DISPLACEMENT,"Injection of water into a rock formation is a common oilfield services technology to maintain high reservoir pressure and increase ultimate recovery of hydrocarbons. While flowing through the well from surface to the rock formation, injected water typically transports fine particles, for example, fine sand grains and calcite precipitated at surface pipeline conditions while mixing water from different sources (e.g., fresh, Cenomanian and formation brine). In the framework of the two-fluid approach to suspension flow modelling, we formulate mathematical model for linear filtration of a particle-laden suspension in the vicinity of a fractured flooding well and transport of ion concentration (salinity). Two major factors of well injectivity decline are described, namely, particle trapping with associated reduction in permeability and porosity of the rock as well as the effect of salinity of injecting water leading to clay swelling, calcite precipitation and change of relative permeabilities of the rock with respect to water and oil. We calibrate suspension filtration model against in-house experiments on clogging of artificial and natural rock cores, in which the profiles of fines concentration along the cores are obtained using X-Ray computed tomography and analysis of 3D rock reconstruction images. The water injection model is adopted to conditions of Priobskoye oilfield of Western Siberia by using the results of standard laboratory experiments on fluid-fluid (calcite precipitation) and fluid-rock (clay swelling, migration of internal fines) compatibility, as well as the effect of salinity on oil displacement and analysis of solid fraction in the injecting water. The calibrated model is then used to describe field data on dynamics of injection rate of three flooding wells. It is obtained that the simulations predict the long-term injectivity dynamics of the wells very well, while at early times (up to 5 months from the start of injection) the model underestimates the injection rate. While fitting the model to field data, we varied only two parameters, namely, solids concentration in the injecting water (in the range provided by lab experiments) and trapping coefficient (the range is limited to result of experiments made with target rock cores). It is demonstrated that only a combination of injectivity decline factors allows to describe the long-term flooding rate of the wells. Ignoring either particle trapping or salinity effects lead to significant overestimation (up to 50%) of the long-term injection rate. Parametric study of water injection showed that two-fold increase in solids concentration in the injecting water as well as oil compressibility lead to similar decrease in long-term injection rate of a well.",0,0,2
Oil Recovery,Low Permeability,"Monteiro, Lua; Baptista-Pereira, Catarina; Azevedo, Leonardo",Sensitivity analysis of injection parameters in steam assisted gravity drainage under geological uncertainty,Steam-assisted gravity drainage; Heavy oil; Sensitivity analysis; Geological uncertainty; Reservoir simulation; Optimization,OPTIMIZATION; SAGD; OIL; SIMULATION; RESERVOIR,"Steam-assisted gravity drainage (SAGD) is a challenging enhanced oil recovery technique that requires proper parameterization in terms of well geometry and steam injection parameters as these parameters are highly dependent on the reservoir geology and fluid characteristics (e.g., net pay variation, water saturation). Injection rate and pressure, temperature, steam quality, lean zone, gas zone, water saturation, and wellbore hydraulics are among the most important engineering parameters of SAGD. This work focuses in the sensitivity analysis under geological uncertainty of some operational parameters, such as: injection rate, temperature, steam quality and pressure. To reach this objective we build a realistic reservoir model with multiple geological settings and descriptions. Moreover, two complementary approaches were studied: i) a deterministic sensitivity analysis relying on a factorial design matrix and ii) a stochastic analysis using particle swarm optimization. There are several key geological uncertainties in SAGD, such as net pay variation, inclined heterolithic stratification (IHS) presence, high water saturation in reservoirs, bottom water issues, and gas cap problems. This work focuses on the role of porosity and permeability in oil production, as these impact these geological properties. To reach this objective, two specific groups of ten different porosity and permeability pairs of geostatistical realizations were generated using Direct Sequence Simulation and Co-simulation. Group 1 used the same variogram model for 10 random seeds; and Group 2 used a combination of values that adopted a simultaneous and a random variation, which were assigned to the seed and to the variogram. We opted by a reservoir model that mimics an anticlinal reservoir, as it proved to be a determining factor for the low levels of Net Present Value (NPV) when compared to other geological scenarios. Within the four most commonly studied parameters in SAGD projects, the association of deterministic versus stochastic multi-objective analysis allowed to accurately validate injection rate as the most relevant parameter. Regarding the geological uncertainties, Group 1 showed that for a certain porosity distribution and permeability orientation, the random origin of these distribution maps eventually attributed a higher NPV uncertain. On the other hand, in Group 2, the simultaneous spatial and seed variation provided less uncertainty associated to NPV.",0,0,2
Oil Recovery,Tight Oil,"Zhang, Jin; Wang, Dongmei",Aqueous imbibition further investigation on contact area penetration enhancement for hydrocarbon extraction from tight rocks,Forced imbibition; Surfactant EOR; Acid stimulation; Tight formation; Carbonate,OIL-RECOVERY; SHALE; WET,"The rapid decline of production and low oil recovery in shale and other tight formations have been identified in practice. Surfactant EOR has been considered as one of the best options for those challenging formations. Many studies indicated that the oil recovery was improved by surfactant spontaneous imbibition in a huff-n-puff mode. However, the slow oil extraction rate and the limited penetrating area into the rock matrix by laboratory experimental results indicated it might be impractical for real-time extraction. To address this problem for the carbonate-rich tight formations, a new approach of forced surfactant imbibition process coupled with enhanced contact area stimulation (acidizing, for instance) was proposed. In this paper, samples from the Middle Bakken were used for the laboratory studies. A chemical formulation (CF) consists of surfactant, organic acid, and other components was designed to evaluate the effects on carbonate-rich rocks, rock microstructure and petrophysical properties (porosity and permeability). Oil recovery was also examined by forced imbibition with chemical formulation. Research results demonstrated that CF treatment could dissolve the carbonate minerals in the Bakken rocks resulted in the microstructure changes. These changes led to the injected fluid deeply imbibe into the rock matrix and therefore enlarge the rock-fluid contact area. Rock porosity and permeability were increased and oil recovery was significantly improved with the designed chemical formulation through forced imbibition. In a summary, this laboratory study of combination of acid stimulation and forced surfactant imbibition process may serve as a possible approach for a field application to improve the hydrocarbon recovery from well to well besides of huff-n-puff method.",0,0,1
Oil Recovery,Tight Oil,"El-Yamani, Mahmoud Samir; Al-Ramadan, Khalid; Cantrell, Dave","Diagenetic controls on porosity evolution and reservoir quality of an outcrop analogue of the Jurassic carbonate reservoirs in the Arabian Plate: An example from the Middle Jurassic Tuwaiq Mountain Formation, Central Saudi Arabia",Carbonate-diagenesis; Chert-replacing-evaporites; Dolomitization; Dolomite-calcitization; Porosity-evolution; Tuwaiq Mountain formation,DEPOSITIONAL-ENVIRONMENTS; STAINING TECHNIQUE; SILICA DIAGENESIS; DOLOMITE; DEDOLOMITIZATION; LIMESTONE; CLASSIFICATION; MICROFACIES; DISSOLUTION; JUBAILA,"The Middle Jurassic Tuwaiq Mountain Formation (TMF; formed of three members, from bottom to top T1, T2, and T3) represents one of the primary conventional and unconventional reservoirs to be assessed in Saudi Arabia. It is considered as a tight carbonate reservoir in the Jafurah Basin and conventional reservoir in the Arabian Basin. Here, we investigate the depositional, diagenetic, and stratigraphic impact on reservoir quality and porosity evolution of the TMF through an integrated petrographical, geochemical and petrophysical analyses on outcrop samples. The TMF has a complex diagenetic history including micritization, dissolution, recrystallization and neomorphism, meteoric cementation, evaporite precipitation, dolomitization, silicification, dolomite dissolution and calcitization. Dolomitization occurred via a hypersaline fluid mechanism, based on texture, association with evaporites, and Sr concentration. X-ray diffraction results support chert replacing evaporite as the mechanism of the two chert beds in the T3 member due to the presence of anhydrite relics in their samples. This replacement formed the necessary Ca2+ rich fluid for dolomite dissolution and calcitization. Therefore, dolomite calcitization occurs locally and is stratigraphically controlled based on its position relative to chert beds in T3. T3 and the upper part of the T2 member contain calcitized dolomites, while the lower part of T2 and T1 contain only dissolved dolomite. As the fluid went deeper in the TMF, it became weaker. Therefore, the fluid was too weak to develop dolomite calcitization process and instead only affected T1 and the lower part of T2 by dolomite dissolution. Overall, dolomite dissolution and dolomite calcitization didn't have a high impact on porosity evolution as the TMF isn't a highly dolomitized formation. The distribution of porosity (empty set), permeability (K), and reservoir-quality-index (RQI) of the TMF are stratigraphically controlled. The TMF represents the regressive system tract of a 3rd order depositional sequence, which is composed of seven 4th order cycles (i.e. deep lagoon cycles (DLC) and shallow lagoon cycles (SLC)). RQI, empty set, and K plots showed great fitting with the 4th order depositional-cycles as DLC has very poor reservoir properties (average empty set = 7.7%, average K = 0.17 mD, average RQI = 0.03), while SLC has fair reservoir properties (average 0 = 15.4%, average K = 2.64 mD, average RQI = 0.11). Reservoir quality contrast is controlled by two factors: (1) the reduced mud-content and increased grain-content in SLC compared with DLC resulted in increased primary interparticle porosity, and is governed by depositional energy; and (2) the higher primary interparticle porosity in SLCs compared with DLCs preferentially facilitated more infiltration of undersaturated meteoric fluids, resulting in enhanced grain dissolution. This is reflected on the higher proportion of moldic and vuggy porosity in SLCs compared with DLCs. The accurate assessment of the TMF micro-scale attributes and controls on reservoir quality in an outcrop analogue that occurs in close proximity to subsurface hydrocarbon producing intervals can provide important input for oilfield appraisal and enhanced oil recovery performance.",0,0,1
Oil Recovery,Tight Oil,"Aoun, Ala Eddine; Soto, Ricardo; Rabiei, Minou; Rasouli, Vamegh; Khetib, Youcef; Irofti, Doina","Neural Network based Mechanical Earth Modelling (MEM): A case study in Hassi Messaoud Field, Algeria",Mechanical Earth model; Hassi Messaoud field; Hydraulic fracturing; Neural network,EMPIRICAL RELATIONS; PHYSICAL-PROPERTIES; STRENGTH; FAULT,"Accurate estimation of in-situ stresses is of great importance in the oil and gas industry from the exploration to the field development and production phases. The collected logs and mini-frac data in the last 15 years in the Hassi Messaoud Field (HMD), Algeria, shows that the reported state of stresses in this field is not consistent. This called for further studies to estimate more accurately the state of stresses, which more specifically will be used for the design of hydraulic fracturing at a later stage. This paper presents the results of the Mechanical Earth Model (MEM) constructed for the HMD field in Algeria. The results of the MEM, which is continuous logs of formations' elastic and strength properties, as well as the state of the in-situ stresses will be the direct input to the hydraulic fracture (HF) design. Hydraulic fracturing is the prime technique used in the field in order to enhance recovery from this tight sandstone reservoir. MEM is built beyond the conventional correlation with both a Generalized Linear Model (GLM), which serves as a simplified ""ground truth"" and three Artificial Neural Networks (ANN) layers: the first one is training mechanical properties from lab data, the second one trains shear and compressional sonic waves from acquired log data and the last one uses mini-frac data to calculate and train stress regimes from a poro-elastic model. The model is calibrated with the observed breakouts and fracturing data and a close agreement is observed. The work presented in this paper elaborates a detailed roadmap to accurately approximate and synthesize missing data using ANN's and extend it across the rest of the field to build, a 3D MEM. It is hoped that the results of this study can improve the HF operations in the field, which is currently reported to be not efficient.",0,0,1
Oil Recovery,Tight Oil,"Male, Frank; Duncan, Ian J.",The paradox of increasing initial oil production but faster decline rates in fracking the Bakken Shale: Implications for long term productivity of tight oil plays,Energy forecasting; Unconventional oil; Hydraulic fracturing,WATER; GAS,"In the US, tight oil is the largest source of liquid hydrocarbons and has enabled the country to become the world's largest oil producer. The estimated ultimate recovery (EUR) and rate of production decline are key metrics in the evaluation of the future productivity of tight oil wells. We chose the Bakken Shale because of its high quality, publicly available data. Traditionally, well operators have estimated the EUR for each well from the initial production (IP), using empirical type curves to extrapolate to the ultimate production. From 2015 to 2018 the IP of the average Bakken well increased by approximately 50%. This increase resulted in claims by operators and in the academic literature that more intense hydraulic fracturing was increasing the average EUR of the Bakken play. At the same time, other observers claimed the wells declined much more rapidly than previous wells. This faster decline provided evidence for lower ultimate production from newer wells. The aim of this study was to understand the origin of these seemingly conflicting observations. A physics-based, scaling model was used to predict production from horizontal multi-stage fractured wells. The model for oil recovery is based on pressure diffusion through fractured porous media. The model assumes that the rock is incompressible, the permeability and oil saturation are constant, the water is incompressible, and the viscosity is slowly varying with space. The scaling model was applied to 13,444 wells. The EUR and terminal decline rate (TDR) were estimated from fitting production to our scaling model. Our study found that implementation of more intensive hydraulic fracturing resulted in higher IP and steeper terminal-production declines. Recently published results estimating the total production from the Bakken that include increased lifetime production commensurate with observed increases in average IP, significantly overestimate the long-term production potential of tight oil, both in the US and globally.",0,0,3
Oil Recovery,Tight Oil,"Wang, Qiong; Jiang, Ruizhong; Leng, Jie; Liu, Xiuwei",The effect of the viscosity-dependent boundary layer on tight oil flow behavior in CO2 Huff-Puff processes: A unified dimensional Pre-Darcy flow model,Pre-Darcy flow; Compositional simulation; CO2 EOR,N-PUFF; RESERVOIR SIMULATION; NUMERICAL-SIMULATION; FRACTURE NETWORKS; RECOVERY; SHALE,"There are numerous percolation studies of unconventional reservoirs showing that in tight or low-permeability formations, the oil flow behavior could be described by the Pre-Darcy mechanism. However, for the CO2 Huff-nPuff operations, the most presented low-velocity Pre-Darcy flow models may result in an erroneous evaluation due to the intensive boundary layer thickness changes caused by the CO2 extraction and dissolution. In this paper, with multiple parameters fitting the seepage experimental results of the studied area, a unified dimensional Pre-Darcy flow model for CO2 enhanced oil recovery (EOR) is derived from the classic Poiseuille model. Then, the proposed flow model is applied in the compositional simulator for analyzing the viscosity-dependent boundary layer (VDBL) effect, applicability evaluation in Huff-Puff EOR, and field history matching. The results indicate that the VDBL effect improves the oil mobility in injection periods and lowers the residual oil saturation at the front of the CO2 convection-diffusion area in reproduction periods. Additionally, the nonlinear parameter alpha and the shape parameter beta enhance the proposed model's applicability for the Huff process and the Puff process respectively. Finally, by adjusting the parameters alpha and beta for different permeability intervals of the geological model, the flow model is successfully applied in the oil production matching of the Y6 well, which exhibits its reliability in the history matching.",0,0,3
Oil Recovery,Tight Oil,"Shilov, Evgeny; Dorhjie, Desmond Batsa; Mukhina, Elena; Zvada, Maya; Kasyanenko, Anton; Cheremisin, Alexey",Experimental and numerical studies of rich gas Huff-n-Puff injection in tight formation,Associated gas EOR; Huff-n-Puff; Tight oil reservoirs; Minimum miscibility pressure; Gas diffusivity,ENHANCED-OIL-RECOVERY; SHALE PLUGS; PERFORMANCE; SIMULATION,"Huff-n-Puff technology is considered one of the most effective methods to increase oil recovery in shale reservoirs. Previous works were mainly focused on Bakken and Eagle Ford shales. This paper is devoted to experimental and numerical studies of rich gas injection in core samples with high organic matter content from a tight oil reservoir in Russia. Eighteen core samples from different well intervals and different sizes were used in a Huff-n-Puff experimental study. Eight of the core samples were investigated at an injection pressure of 15 MPa, while ten core samples were studied at near-miscible pressure conditions of 30 MPa. The experiment results indicate that Huff-n-Puff injection of rich gas could give an oil recovery average of 63.03% and a maximum of 88.40% at 30 MPa injection pressure. A compositional model was created utilizing a commercial simulator and history matched to experimental results. The validated model was used to investigate the effect of molecular gas diffusivity, injection pressure, injection duration, shut-in duration, production duration, and other reservoir properties on the recovery factor. Sensitivity analysis by numerical modeling shows that the molecular gas diffusivity was critical in the history matching of the model. The numerical simulation results imply that the recovery factor could be increased by extending the injection period. In contrast, the duration of a soak period does not significantly influence the recovery factor. Furthermore, the recovery factor could be increased by extension of the production due to a slow decline in the pressure gradient between the matrix and fracture at the later stage of the production. The results of the present study imply that the application of the Huff-n-Puff injection of rich gas could increase oil recovery from tight reservoirs.",0,0,3
Oil Recovery,Gravity Drainage,"Gao, Yanfang; Ren, Zhanli; Chen, Mian; Jiang, Hailong; Ding, Shuaiwei",Coupled geomechanical-thermal simulation for oil sand reservoirs with shale barriers under hot water injection in vertical well-assisted SAGD wells,Oil sands; Shale barriers; Geomechanical-thermal simulation; Vertical well; SAGD,PROPAGATION BEHAVIOR; PERMEABILITY CHANGES; RECOVERY PROCESSES; MODEL; TEMPERATURE,"Mudstone stringers in an oil sand reservoir can significantly affect the propagation of the steam chamber in the process of steam-assisted gravity drainage (SAGD). The micro-fracturing by water injection in strongly heterogeneous oil sands can result in these problems such as hard stringer breakthrough and aggravating heterogeneity. This paper proposed a comprehensive numerical model for conventional SAGD wells and vertical well-assisted SAGD (VWA-SAGD) wells to predict the coupled thermo-hydro-mechanical responses under hot water injection in a typical Karamay oil sand reservoir with two stringers, considering skeleton shear dilation, the ""phase change"" of bitumen, formation heterogeneity, the permeability evolution induced by elastoplastic deformations, and the theory of heat and mass transfer. Major conclusions were drawn that there are three relatively narrow separate transition zones effectively heated around the SAGD wells and vertical well. The vertical well makes about 0.5 MPa increase to the pore pressure of the reservoir embedded with mudstone stringers in vertical directions and rises by about 0.6 MPa for the reservoir pore pressure above the upper stringer to reduce the pore pressure differential along the wellbore. Water injection-induced ultimate stress states can't reach the shear failure line under field operations, so the shear dilation can't be induced. The thermoporoelastic deformation determines whole reservoir deformation. The reservoir between the two stringers contributes to most of the caprock uplift. The VWA-SAGD technique can improve the porosity by about 1% in the whole vertical direction and reduce the anisotropy of porosity along the wellbore, which is beneficial to the uniform and fast propagation of the steam chamber in subsequent preheating and production stages. These findings can be employed to accurately predict the temperature, pore pressure, stress/displacement, and porosity evolutions for the field engineers to properly evaluate the uplift of reservoir and caprock, oil output changes, and heat utilization efficiency.",0,0,0
Oil Recovery,Gravity Drainage,"Hasanzadeh, Maryam; Azin, Reza; Fatehi, Rouhollah; Zendehboudi, Sohrab",New insights into forced and free fall gravity drainage performance in a fractured physical model,Fractured physical model; Gas injection; Recovery factor; Free fall gravity drainage; Forced gravity drainage,TERTIARY OIL-RECOVERY; POROUS-MEDIA; WETTABILITY; DISPLACEMENT; SECONDARY; FLOW,"Gravity is one of the major driving forces for fluid flow in naturally fractured reservoirs. Gravity drainage appears to be a vital recovery mechanism over the oil production process in a majority of fractured reserves. In this paper, free-fall gravity drainage (FFGD) and forced gravity drainage (FGD) production approaches are investigated through employing a new fractured sand pack with a rectangular geometry. Distilled water and condensate are used as the wetting phase. Nitrogen, carbon dioxide, and air are also utilized as the non-wetting phase. A systematic sensitivity analysis is conducted to find the effects of the key factors such as fracture blockage, injection rate, dip angle, and type of wetting phase and injection fluid on the performance of FFGD and FGD processes. Also, a numerical simulation is performed to simulate the experiments. Results reveal that the FGD has a better performance under controlled process conditions, compared to the FFGD so that gas injection with a controlled rate improves the recovery. Moreover, it was found that increasing the gas injection rate improves the recovery factor (RF) of wetting-phase when the up and bottom sides of the fractures are blocked; the RF is decreased in the case with open fracture sides. The recovery of the wetting phase decreases in both FFGD and FGD modes when the porous system has a deviation from the vertical orientation. According to the study outcomes, the immiscible gas-assisted gravity drainage offers a higher condensate recovery, compared to water recovery, due to lower viscosity and interfacial tension (IFT) of the condensate phase. The comparison of the experimental data and simulation results implies that the simulation approach can satisfactorily predict the performance of the FGD process. Based on the error analysis, there is a good match between the simulation results and the experimental measurements; the fluid pair of CO2-condensate exhibits the highest accuracy with an R-squared of 0.9961 and an average relative error (ARE) of 0.0054.",0,0,0
Oil Recovery,Gravity Drainage,"Lyu, Xiaocong; Liu, Huiqing; Tian, Ji; Zheng, Qiang; Zhao, Wei",Influence of top water on SAGD steam chamber growth in heavy oil reservoirs: An experimental study,Steam-assisted gravity drainage (SAGD); Steam chamber; Top water; Heavy oil; Experiments,ASSISTED GRAVITY-DRAINAGE; NUMERICAL-SIMULATION; RECOVERY; PERFORMANCE; FOAM,"Steam-assisted gravity drainage (SAGD) is one efficient and mature technology for recovering heavy oil and bitumen resources. The key underlying mechanism is the growth of the steam chamber after injecting steam. However, due to the complex geological environment, the thief zones exist and have a prejudicial effect on the development of the steam chamber, thus impacting the ultimate heavy-oil recovery. In this work, our objective is to investigate the effect of a top-water thief zone (i.e., water zone overlies the oil sand) on SAGD performance and further to understand the crucial mechanisms that control the heat loss during steam injection. A large-scale three-dimensional experimental apparatus is used to carry out the SAGD process with a top aquifer. Based on the similarity criterion, the field-scale model is transformed into a laboratory elemental model. To evaluate the SAGD performance quantitatively, the dynamic growth of the steam chamber is measured using the thermal detectors and the production data is recorded. The results show that the steam chamber exhibits three distinguished stages, that is, upward spread, lateral extension, and downward development in the presence of top-water zone. The bottom-water zone has less impact on the steam-chamber growth. The existence of a confined top-water zone, however, significantly affects SAGD performance, especially the lateral expansion of the steam chamber. The lateral propagation of the steam front is hindered by the top thief zone due to the heat exchange with the top water. Once the steam chamber reaches the boundary, the accumulation of energy in the water thief zone, in turn, can reduce the remaining oil saturation along the topwater-oil interface. This study provides us some key insights into the development of heavy oil resources with top thief zones when implementing SAGD technology.",0,0,0
Oil Recovery,Gravity Drainage,"Monteiro, Lua; Baptista-Pereira, Catarina; Azevedo, Leonardo",Sensitivity analysis of injection parameters in steam assisted gravity drainage under geological uncertainty,Steam-assisted gravity drainage; Heavy oil; Sensitivity analysis; Geological uncertainty; Reservoir simulation; Optimization,OPTIMIZATION; SAGD; OIL; SIMULATION; RESERVOIR,"Steam-assisted gravity drainage (SAGD) is a challenging enhanced oil recovery technique that requires proper parameterization in terms of well geometry and steam injection parameters as these parameters are highly dependent on the reservoir geology and fluid characteristics (e.g., net pay variation, water saturation). Injection rate and pressure, temperature, steam quality, lean zone, gas zone, water saturation, and wellbore hydraulics are among the most important engineering parameters of SAGD. This work focuses in the sensitivity analysis under geological uncertainty of some operational parameters, such as: injection rate, temperature, steam quality and pressure. To reach this objective we build a realistic reservoir model with multiple geological settings and descriptions. Moreover, two complementary approaches were studied: i) a deterministic sensitivity analysis relying on a factorial design matrix and ii) a stochastic analysis using particle swarm optimization. There are several key geological uncertainties in SAGD, such as net pay variation, inclined heterolithic stratification (IHS) presence, high water saturation in reservoirs, bottom water issues, and gas cap problems. This work focuses on the role of porosity and permeability in oil production, as these impact these geological properties. To reach this objective, two specific groups of ten different porosity and permeability pairs of geostatistical realizations were generated using Direct Sequence Simulation and Co-simulation. Group 1 used the same variogram model for 10 random seeds; and Group 2 used a combination of values that adopted a simultaneous and a random variation, which were assigned to the seed and to the variogram. We opted by a reservoir model that mimics an anticlinal reservoir, as it proved to be a determining factor for the low levels of Net Present Value (NPV) when compared to other geological scenarios. Within the four most commonly studied parameters in SAGD projects, the association of deterministic versus stochastic multi-objective analysis allowed to accurately validate injection rate as the most relevant parameter. Regarding the geological uncertainties, Group 1 showed that for a certain porosity distribution and permeability orientation, the random origin of these distribution maps eventually attributed a higher NPV uncertain. On the other hand, in Group 2, the simultaneous spatial and seed variation provided less uncertainty associated to NPV.",0,0,2
Oil Recovery,Long Term,"Wijaya, Nur; Sheng, James",Effect of compaction and imbibition on benefits of drawdown management in shale oil production: Uncertainty in recovery driving mechanisms,Shale oil; Choke management; Stress-dependent permeability; History matching; Proppant selection; Net present value,HORIZONTAL WELLS; GAS-WELL; PERMEABILITY,"Economic production from shale oil reservoirs relies on the longevity of conductive fractures. Choke or draw-down management is believed to better preserve the fracture conductivity during the early life of the wells, which thus potentially leads to higher ultimate oil recovery. However, there is no strong consensus among the previous literature as to whether choke management can offer incremental oil recovery in the long term. Even if it can, the mechanism is not well understood, and the economic benefit can be challenged, because the choke management slows down the early oil production, which is worth the most in terms of Net Present Value (NPV). In this study, a series of coupled flow-geomechanical numerical simulations is performed to examine the effect of choke management on the ultimate oil recovery and NPV. We built multiple reservoir realization models, each of which is validated based on the same field production data from Middle Bakken shale-oil reservoirs to perform probabilistic production forecasts. The different reservoir realization models are built to assess the uncertainty in the Stimulated Reservoir Volume parameters, including natural fracture spacing, water saturation in the matrix and fracture, and formation compressibility. The different reservoir parameters lead to each model having different primary recovery driving mechanisms of oil recovery, including imbibition and compaction drive. This study quantitatively demonstrates that the choke management seems to increase both the ultimate oil recovery and NPV if the oil recovery is strongly driven by imbibition. A mechanistic discussion for this claim is presented.",0,0,0
Oil Recovery,Long Term,"Teigland, Andreas; Dale, Stein Inge; Sangesland, Sigbjorn; Brechan, Bjorn",A generalized empirical expression for the collapse of worn tubulars with a crescent-shaped wear groove under combined loads,Casing wear; Casing collapse; Well integrity; Finite element method,STRENGTH,"As a large proportion of easily recoverable global hydrocarbon reserves is extracted and fields in operation are maturing, the oil and gas industry requires new methods of ensuring well integrity. Production of the remaining reserves may involve, for instance, extended-reach wells, multilateral wellbores, long horizontal sections and highly deviated trajectories. Moreover, wells in mature fields are being used to increase recovery through sidetracking. Casing wear has a significant influence on the well integrity in such operations and the ability to assess its effects is crucial, both in terms of its impact on health, safety and environment, and in terms of enabling cost efficiency. This article utilizes the Finite Element Method (FEM) to analyze the stress distribution in worn tubulars with a crescent-shaped wear groove under external pressure. A model for tubular collapse is proposed using generalized empirical expressions for stress concentration factors in worn tubulars. The generalized expressions are based on 640 finite element analyses of different geometries designed to represent typical dimensions used in the oil and gas industry. Comparisons with experimental data and existing models demonstrate improvement in both accuracy and precision using the developed approach.",0,0,1
Oil Recovery,Long Term,"Male, Frank; Duncan, Ian J.",The paradox of increasing initial oil production but faster decline rates in fracking the Bakken Shale: Implications for long term productivity of tight oil plays,Energy forecasting; Unconventional oil; Hydraulic fracturing,WATER; GAS,"In the US, tight oil is the largest source of liquid hydrocarbons and has enabled the country to become the world's largest oil producer. The estimated ultimate recovery (EUR) and rate of production decline are key metrics in the evaluation of the future productivity of tight oil wells. We chose the Bakken Shale because of its high quality, publicly available data. Traditionally, well operators have estimated the EUR for each well from the initial production (IP), using empirical type curves to extrapolate to the ultimate production. From 2015 to 2018 the IP of the average Bakken well increased by approximately 50%. This increase resulted in claims by operators and in the academic literature that more intense hydraulic fracturing was increasing the average EUR of the Bakken play. At the same time, other observers claimed the wells declined much more rapidly than previous wells. This faster decline provided evidence for lower ultimate production from newer wells. The aim of this study was to understand the origin of these seemingly conflicting observations. A physics-based, scaling model was used to predict production from horizontal multi-stage fractured wells. The model for oil recovery is based on pressure diffusion through fractured porous media. The model assumes that the rock is incompressible, the permeability and oil saturation are constant, the water is incompressible, and the viscosity is slowly varying with space. The scaling model was applied to 13,444 wells. The EUR and terminal decline rate (TDR) were estimated from fitting production to our scaling model. Our study found that implementation of more intensive hydraulic fracturing resulted in higher IP and steeper terminal-production declines. Recently published results estimating the total production from the Bakken that include increased lifetime production commensurate with observed increases in average IP, significantly overestimate the long-term production potential of tight oil, both in the US and globally.",0,0,3
Oil Recovery,Flow Regime,"Orlando Jr, Aloisio E.; Barca, Luiz F.; Heindel, Theodore J.; Klein, Tania S.; Medronho, Ricardo A.",Gas holdup and flow regime in a bubble column that includes enhanced oil recovery chemicals,Bubble column; EOR chemicals; Flow regime; Gas holdup; Transitional gas holdup,EMULSIFICATION STABILITY; WATER; HYDRODYNAMICS; CFD; TRANSITION; SIMULATION; VISCOSITY; MODEL,"Chemical enhanced oil recovery (EOR) methods are alternatives to increase oil production in mature reservoirs. However, the presence of EOR chemicals in the produced water may impact the separation of gas-water systems in oil platforms. The present work aims to evaluate the impact of polymers, surfactants, inorganic salts, and their interactions on gas holdup in a 32.1-cm-diameter semi-batch bubble column over a range of superficial gas velocities ranging from 0 to 19 cm/s. It has been confirmed through physical-chemical analysis that synthetic produced water containing salts, polymers and organic surfactants is non-Newtonian with low surface tension. Results have shown that both salt and surfactants increase gas holdup regardless of superficial gas velocity, while the effect of polymers depends on superficial gas velocity. This work also innovates by showing how interactions between EOR chemicals and salinity affect transition gas holdup and superficial gas velocity between different flow regimes. Overall results shed some light on how the chemical composition of EOR effluents affect gas holdup and flow regime as a function of a wide range of superficial gas velocities and therefore contributes to the development of gas-liquid systems.",0,0,0
Oil Recovery,Flow Regime,"Al-Shami, Tareq Mohammed; Jufar, Shiferaw Regassa; Negash, Berihun Mamo; Abdullahi, Mohammed Bashir",Impact of external excitation on flow behavior of trapped oil blob,Oil mobilization; Unconventional EOR; External excitation; Seismic stimulation; Flow behavior,CAPILLARY TUBES; OSCILLATORY FLOW; RECOVERY; DROPLETS; WAVES; MOBILIZATION; STIMULATION; RESONANCE; WATER,"External excitation of oil reservoirs has shown promising potential in increasing residual oil recovery. Although several numerical, experimental, and pilot studies were conducted over the last decades, large-scale field application is not realized due to inconclusive results on its performance. This paper aims to investigate the effect of external excitation on the flow behavior of an oil blob trapped in a constricted capillary tube model. Flow evolution and characteristic flow behaviors were studied using computational fluid dynamics (CFD) simulations. An external excitation with a sinusoidal profile propagating in the axial direction was applied at the wall of the constricted capillary tube model. The excitation intensity and frequency were varied to identify the flow characteristics. The results show that under the influence of external excitation, three distinct flow regimes develop based on the excitation frequency and intensity; these are trapped, clear pass, and dispersed pass. Velocity profiles, streamlines, and pressure contours were used to examine the resulting flow behaviors. In addition, dimensional analysis was carried out, and the dominant factors in each flow regime were identified. The dominant dimensionless numbers are Euler number, Reynolds number, and Weber number. Accordingly, the three flow regimes were mapped in the domains of these dimensionless numbers. As such, under given flow conditions, fluid properties, and external excitation parameters, the subsequent flow behavior can be predicted using the characteristic flow behavior maps presented in the study. Moreover, any of these flow regimes can be induced for a given application by tuning the excitation parameters based on the dimensionless characteristic maps presented.",0,0,2
Oil Recovery,Flow Regime,"Velasco-Lozano, Moises; Balhoff, Matthew T.",Modeling of early- and late-time countercurrent spontaneous imbibition in porous media: A semi-analytical approach,Countercurrent spontaneous imbibition; Porous media; Oil recovery; Early-time solution; Late-time solution; Universal scaling,OIL-RECOVERY; WATER,"Countercurrent spontaneous imbibition (SI) is an important flow mechanism to recover oil in water-wet porous media through capillarity. Experimental imbibition tests conducted in core samples show that oil recovery as a function of time occurs in a characteristic S-shaped curve, which describes the infinite-acting and the boundary-dominated regime. Although several dimensionless time groups have been proposed to model countercurrent SI in porous media, they fail to properly scale the results, causing inaccurate estimates of oil recovery. In this work, we present a new approach, using a hybrid solution, to model countercurrent SI for oil-water systems dominated by capillary forces. The infinite-acting regime is modeled by an early-time solution using a new dimensionless time group, which enables the correct scaling of imbibition results onto a universal single curve. To model the boundary-dominated regime, we introduce a late-time solution derived as a function of a characteristic distribution of saturation to estimate the flow behavior after the imbibing fluid reaches the no-flow boundary. The novelty of the model is that it enables the accurate estimation of fluid imbibition under the boundary-dominated regime, a flow condition critical to evaluate the true potential of countercurrent SI driven by capillarity for oil recovery in porous media. We verified the model against numerical simulations under a wide range of flow conditions relevant in water-oil systems, and used experimental data reported in the literature to validate our model. The solution presented provides an accurate approach to model countercurrent SI, which could be extended for dynamic conditions and the modeling of the flow of fluids in fractured media.",0,0,2
Oil Recovery,Gel,"Vinay, Guillaume; Bhaskoro, Petrus Tri; Henaut, Isabelle; Sariman, Mior Zaiga; Anuar, Astriyana; Shafian, Siti Rohaida M.",A methodology to investigate factors governing the restart pressure of a Malaysian waxy crude oil pipeline,Waxy crude oil; Gelling; Numerical simulation; Rheology; Restart pressure,STARTUP FLOW; MODEL,"Waxy crude oils account for about 20% of world oil reserves. Wax gelation due to pipeline operating at low ambient temperature, especially in subsea environment, is a worst-case scenario that operators fear most since the gel can potentially block the entire pipeline, if it is not managed early. Restart pressure calculation is the first step to assess severity of gelation and subsequently used to plan for the mitigation strategies which are translated into project CAPEX (Capital Expenditure) and OPEX (Operating Expenditure). Gel characteristic (i.e. rheology behaviour and gel compressibility), operating conditions (oil temperature, ambient temperature and oil flow rate) and pipeline geometry (length and diameter) are known factors governing the restart pressure calculation for a gelled waxy pipeline. Malaysian waxy crude oils are unique and have distinctive rheology which differ from waxy crude oils from other regions mainly due to high gel yield stress of more than 500 Pa with potential failure to recovery from gelation. Hence, accurate restart pressure prediction that account for all the governing factors as well as the interplay between them, are crucial for safe operation and cost-effective mitigation strategies. A conservative approach where the entire gel is assumed to yield simultaneously is frequently used but this simple approach fails to take into account many factors, resulting in an overestimation of the restart pressure. Several improved restart pressure calculation methods have been proposed in literature. In this study, an original methodology developed by IFPEN, has been applied to predict the restart pressure of a Malaysian waxy crude oil pipeline at various conditions. The main benefit of this methodology comes from its ability to consider the conditions under which the gel has been formed, that produces a more realistic description where gel strength varies along a pipeline. The case study highlighted that Conservative laws, assuming a homogeneous gel structure everywhere in the pipe, can overestimate the restart pressure by a factor of up to 100 times than a heterogenous gel. Thanks to the 2D axisymmetric description of the pipeline gel, we showed that the shape and the location of the gel also impact the restart pressure.",0,0,2
Oil Recovery,Gel,"Zhao, Yang; Bai, Baojun",Selective penetration behavior of microgels in superpermeable channels and reservoir matrices,Enhanced oil recovery; Conformance control; Gel treatment; Preformed particle gel; Threshold penetration pressure,PREFORMED PARTICLE GEL; CONFORMANCE-CONTROL; ELASTIC MICROSPHERES; WATER; SUSPENSIONS; SIMULATION; TRANSPORT,"Gel treatment is an effective way to attack excessive water production in many mature oilfields around the world. Selective penetration is desired for successful gel treatments. That is, gel materials should easily penetrate the target zones (i.e., channeling features such as superpermeable channels) without entering/damaging the nontarget zones (i.e., reservoir matrices or oil zones). This study revealed that presence of threshold penetration pressure (Delta Pth) was responsible for selective penetration behavior of tested microgels. The concept of Delta Pth was utilized to figure out favorable working conditions for effective gel treatments. Microgel dispersions were injected into superpermeable (super-k) sandpacks (mimicking super-k channels in reservoirs, 60-221 darcies), heterogeneous models with super-k channels (79-230 darcies), and sandstone cores (mimicking reservoir matrices, 50-5000 md). The results demonstrated that a minimum differential driving pressure (i.e., threshold penetration pressure, Delta Pth) was required to push microgel particles to penetrate channels or matrices. The critical penetration behavior was closely related to the particle/pore size ratio. Low Delta Pth at smaller particle/pore ratios was beneficial to allow easy penetration of gel materials into the channeling zones. On the contrary, high Delta Pth at larger particle/pore ratios was desirable to prevent gel materials from massively invading and damaging the matrices. Instead, the gel particles accumulated at the inlet surface, and a gel cake was gradually formed. The cake further prevented the invasion of the gels. The cake could be removed by chemical breakers to resume the injectivity/productivity of the matrices. Correlations were developed to describe the relationship between Delta Pth and particle/pore ratio. A distinct transition was identified at the particle/pore ratio of about 3. This work could help identify the favorable conditions to achieve successful gel treatments. In an effective conformance treatment, the particle/pore ratio in the channel should be sufficiently low to allow easy penetration of gel materials into the channel (e.g., particle/pore ratio<2 in this study). Meanwhile, the particle/pore ratio in the matrix should be large enough to support a high Delta Pth and thus prevent massive gel invasion into the matrix. This study advances the current pore scale studies (a single particle passing through a single channel) to Darcy-scale characterization.",0,0,2
Fracture,Hydraulic Fracture,"Dontsov, Egor; Suarez-Rivera, Roberto",Representation of high resolution rock properties on a coarser grid for hydraulic fracture modeling,Hydraulic fracturing; Homogenization; Upscaling; High resolution properties,DRIVEN; ANISOTROPY; MATRIX; FLUID,"This study presents a homogenization procedure for the high resolution rock properties that are used as an input data for hydraulic fracture simulations. In particular, the high resolution data for fracture toughness (both vertical and horizontal), elastic constants, leak-off coefficient, and stress are suitably upscaled for a given element size, so that the small scale variations within this element are captured implicitly. Homogenization of the elastic properties is performed assuming that each individual layer is transversely isotropic and is based on Backus averaging. Fracture energy is used to homogenize the fracture toughness and to account for the contrast of elastic properties on the fracture height containment. The average energy is used in the horizontal direction and the maximum energy is used in the vertical direction. To preserve the total force acting on the element, the weighted average is used for stress homogenization. In addition, a correction to the vertical fracture toughness that is caused by the difference between the high resolution stress and the homogenized stress is introduced. Finally, a weighted average is used to homogenize leak-off. A series of numerical examples that consider synthetic data with periodic variation of parameters is used to validate the homogenization procedure. One of the most important implications of using the homogenization is an increase of the apparent vertical fracture toughness (that represents small scale property variations), which can be of the same order or even larger than the intrinsic rock toughness. Thus, high resolution property variations have a potential to considerably alter fracture geometry and can lead to a more pronounced fracture height containment.",0,0,0
Fracture,Hydraulic Fracture,"Muravleva, Ekaterina A.; Derbyshev, Dmitry Yu; Boronin, Sergei A.; Osiptsov, Andrei A.","Multigrid pressure solver for 2D displacement problems in drilling, cementing, fracturing and EOR",Multigrid; Hydraulic fracturing; Cementing; Numerical modeling; Fast linear solver; BiCGStab,WELLBORE COMPLETION FLUIDS; ANNULAR DISPLACEMENTS; NUMERICAL-SIMULATION; MUD REMOVAL; OIL-WELL; FLOW; PLACEMENT; MODEL; TRANSPORT,"Numerical simulators for the design of oilfield services technologies are required to be fast and robust, hence the implementation of underlying mathematical models is expected to be highly efficient. We present an optimized numerical algorithm based on the multigrid approach for solving the pressure equation in 2D problems of fluid-fluid displacement. This type of problems arise in oilfield services applications, such as drilling, cementing, hydraulic fracturing and EOR. The displacement of fluids with different properties in a narrow annular gap (drilling, cementing) or a slot (hydraulic fracturing, production) is governed by the 2D width-averaged model in the lubrication approximation. In numerical implementation, the most time-consuming is the elliptic Poisson pressure equation, which has coefficients with discontinuities (jumps) in the case of displacement of fluids with viscosity contrast. Specifically for this case of discontinuous coefficients, we designed and implemented numerically the black-box multigrid algorithm, which resolves the divergence issue typical of standard realization of multigrid algorithm using bilinear prolongation operators. The algorithm is tested on a number of matrices corresponding to discretization of elliptic equation at rectangular staggered meshes with different resolution. The performance of the algorithm is compared against several other sparse solvers available for commercial use: smoothed aggregated algebraic multigrid (PyAMG software package), direct sparse solver from Intel MKL library (DSS), Bi-Conjugate Gradient-Stabilized solver preconditioned by ILUT factorization implemented into BLAS package, and our in-house Conjugated Gradient algorithm preconditioned by ILU(2) factorization. It was found that the performance of the black-box multigrid solver is significantly higher (from 7x to 30x in terms of CPU time depending on the mesh resolution) as compared to the closest solver under consideration, which allows us to recommend this solver for implementation into existing 2D drilling simulators, fracturing design tools, cement placement and production simulators.",0,0,0
Fracture,Hydraulic Fracture,"Mackey, Justin; Gardiner, James; Kutchko, Barbara; Brandi, Meghan; Fazio, James; Hakala, J. Alexandra",Characterizing mineralization on low carbon steel exposed to aerated and degassed synthetic hydraulic fracture fluids,Hydraulic fracturing fluids; Oilfield mineral scale; Unconventional resources; Well integrity; Barite; Corrosion,BARITE SCALE FORMATION; MARCELLUS SHALE; CORROSION; WATER; IRON; OIL; CHLORIDE; INHIBITION; OXIDATION; INSIGHTS,This study investigates the mineralization occurring at the interface between injected hydraulic fracturing fluids and steel production casing during the shut-in period of unconventional shale wells. Mild steel coupons were reacted with synthetic hydraulic fracturing fluids with varying base fluid and dissolved gas concentrations. Experiments were carried out in an autoclave system set at 50 ?C and 2000 PSI for 2 and 14 days. Physical and mineralogical changes to the steel coupons? surface were characterized using an FEI Quanta 600 field emission gun (FEG) scanning electron microscope (SEM) and a PANalytical XPert Pro diffractometer. Barite precipitation occurred ubiquitously during the first 48 h in all experimental scenarios. Sulfate radicals created from degradation and reduction of ammonium persulfate breakers facilitate barite formation. Concomitant barite and corrosion related precipitates on the sample surfaces suggest iron hydroxy salts act as nucleation sites for mineral scale growth. These results suggest hydraulic fracturing fluids may have deleterious effects on the wellbore before production of the well begins.,0,0,1
Fracture,Hydraulic Fracture,"Liu, Xing; Jin, Yan; Lin, Botao",An efficient stimulated reservoir area (SRA) estimation method based on octree decomposition of microseismic events,Hydraulic fracturing; Microseismic monitoring; Stimulated reservoir volume; Stimulated reservoir area; Octree method; Monte Carlo method,FRACTURE; GEOMECHANICS; PROPAGATION; SYSTEMS; SHALE,"Fracture contact area is the critical factor determining post-treatment production after multi-stage hydraulic fracturing. At present, there are no effective methods for the estimation of the stimulated reservoir area (SRA) of the complex fracture network after stimulation. Conventional methods mostly focused on calculating stimulated reservoir volume (SRV) by using microseismic events directly or indirectly. However, since there is a large number of noise events in microseismic data that can't be removed completely, the SRV results often have huge errors and are inconsistent with practical well production. For this reason, we propose an efficient and robust SRA calculation method based on 3D octree decomposition. The method is able to effectively estimate SRA by generating a multi-level grid structure without reconstructing the fracture network. Through a large number of case simulations based on synthetic events generated by Monte Carlo method, it is found that our method could adapt to the estimation of SRA for different configurations. It could obtain reliable and robust results in the presence of noise events. Specifically, it is indicated that the maximum relative calculation error is less than 20% for mesoscale and large-scale fracture network. The error for small-scale fractures could be reduced below 30% combining with the error reduction approach put forward in this paper. The applicability of our method is also investigated through two horizontal well platforms. Compared with the conventional SRV method, it is found that SRA obtained by our method could better reflect the stimulation effects and is more consistent with real production. It could become a potential and effective index for stimulation evaluation and fracturing operation optimization.",0,0,1
Fracture,Hydraulic Fracture,"Fabbri, Heber A.; Cleto, Pedro R.; Gaiotto Jr, Aldo T.; Rodrigues, Eduardo A.; Maedo, Michael A.; Manzoli, Osvaldo L.",Modeling the closure behavior of natural fractures in porous media using high aspect ratio interface elements,Natural fractures; Fracture closure model; High aspect ratio interface elements; Hydro-mechanical analysis,FINITE-ELEMENT; FLUID-FLOW; LAND SUBSIDENCE; INTEGRATION SCHEME; CONTACT PROBLEMS; 2-PHASE FLOW; FORMULATION; APPROXIMATION; CONDUCTIVITY; PERMEABILITY,"Many reservoirs consist of fully saturated rock masses containing a very complex natural fracture network. In such cases a decrease in the fracture fluid pressure reduces its aperture due to an increase in the effective stresses. In order to tackle the influence of fracture permeability on the pressure field and fluid flow, this paper proposes a Discrete Fracture-Matrix (DFM) model based on the finite elements to simulate coupled flow and geomechanics in porous media containing fractures with known position and properties (e.g. DFN realizations and fracture networks interpreted from outcrops). The proposed model is based on the use of triangular finite elements with high aspect ratio (HAR) to explicitly represent the fractures. These HAR elements have been successfully used to deal with cracks in concrete structures, desiccation cracks in soils and hydraulic fracturing in geo-reservoirs. This work demonstrate that these HAR elements equipped with a simple continuum (stress-strain) constitutive contact model that mimics the discrete (stress-displacement) Barton-Bandis joint model are able to properly describe the closure behavior associated with natural fractures. The constitutive model is integrated by means of the IMPL-EX scheme, which is a robust and stable technique used to achieve faster convergence. Darcy's law establishes the relationship between the fluid flow and the pressure field, and a fully coupled hydro-mechanical formulation comprises the mathematical framework. The proposed approach is based on continuous mechanics concepts and the implementation is made at constitutive level, and therefore it is simple and easy to be included in any existing FE program. To show the efficiency and accuracy of the proposed model, three numerical examples are conducted in this work: (i) benchmarks involving a medium with a single natural fracture, (ii) three reservoirs with different discrete fracture networks, and (iii) a transient analysis of a reservoir under different fracture conditions, such that the behavior of a intact reservoir, a reservoir containing fractures with constant aperture, and a reservoir in which the fractures aperture depends on the stress state are compared in terms of pore pressure, displacement field and fluid loss. In the first example, the results obtained with the proposed methodology are validated against the Barton-Bandis model. The agreement between the results is very satisfactory. The analysis of the latter two cases show the Barton-Bandis contact model is able to reproduce the effects of fracture permeability on pressure field in the reservoir, showing the capacity of the model to reproduce the main trends associated with the closure of natural fractures.",0,0,1
Fracture,Hydraulic Fracture,"Tugan, Murat Fatih; Weijermars, Ruud",Searching for the root cause of shale well rate variance: Highly variable fracture treatment response,Well rate variance; Root causes; Fracture treatment quality; Wolfcamp formation; Permian basin,,"This case study highlights that shale wells drilled with tight well spacing in the same landing zone using the same fracture treatment plan, commonly show large variance in well productivity. Searching for the root cause(s) of this variance in performance, we conclude that the factory model - which assumes wells can be engineered in reproducible and identical ways - is not yet feasible in practice. For each well, largely similar fracture treatment schedules result in different fracture half lengths. Also, a significant proportion of perforations may fail to create any hydraulic fractures at all. This new reality means that underperforming wells in otherwise promising acreage are more likely an indication of varying fracture treatment response, rather than a result of poor source rock. Research focusing on the reduction of fracture treatment variance therefore deserves priority and may help steady the performance of future wells.",0,0,1
Fracture,Hydraulic Fracture,"Aoun, Ala Eddine; Soto, Ricardo; Rabiei, Minou; Rasouli, Vamegh; Khetib, Youcef; Irofti, Doina","Neural Network based Mechanical Earth Modelling (MEM): A case study in Hassi Messaoud Field, Algeria",Mechanical Earth model; Hassi Messaoud field; Hydraulic fracturing; Neural network,EMPIRICAL RELATIONS; PHYSICAL-PROPERTIES; STRENGTH; FAULT,"Accurate estimation of in-situ stresses is of great importance in the oil and gas industry from the exploration to the field development and production phases. The collected logs and mini-frac data in the last 15 years in the Hassi Messaoud Field (HMD), Algeria, shows that the reported state of stresses in this field is not consistent. This called for further studies to estimate more accurately the state of stresses, which more specifically will be used for the design of hydraulic fracturing at a later stage. This paper presents the results of the Mechanical Earth Model (MEM) constructed for the HMD field in Algeria. The results of the MEM, which is continuous logs of formations' elastic and strength properties, as well as the state of the in-situ stresses will be the direct input to the hydraulic fracture (HF) design. Hydraulic fracturing is the prime technique used in the field in order to enhance recovery from this tight sandstone reservoir. MEM is built beyond the conventional correlation with both a Generalized Linear Model (GLM), which serves as a simplified ""ground truth"" and three Artificial Neural Networks (ANN) layers: the first one is training mechanical properties from lab data, the second one trains shear and compressional sonic waves from acquired log data and the last one uses mini-frac data to calculate and train stress regimes from a poro-elastic model. The model is calibrated with the observed breakouts and fracturing data and a close agreement is observed. The work presented in this paper elaborates a detailed roadmap to accurately approximate and synthesize missing data using ANN's and extend it across the rest of the field to build, a 3D MEM. It is hoped that the results of this study can improve the HF operations in the field, which is currently reported to be not efficient.",0,0,1
Fracture,Hydraulic Fracture,"Du, Xin; Li, Qingyu; Xian, Yuxi; Lu, Detang",Fully implicit and fully coupled numerical scheme for discrete fracture modeling of shale gas flow in deformable rock,Shale gas; Discrete fracture model; Rock deformation; Explicit method; Implicit method,PERMEABILITY; SIMULATION; STRESS; STRAIN,"Shale gas reservoirs contribute significantly to hydrocarbon production because of their abundant reserves. Shale formation is characterized by low permeability and extremely low porosity. Horizontal well drilling and hydraulic fracturing treatments are typical methods for stimulating the shale gas reservoirs. The discrete fracture model has been widely used to describe flow problems in fractured media. Rock deformation is an important process that occurs simultaneously with the gas flow during the production period and cannot be neglected when modeling the gas flow in shale formations. The matrix permeability, matrix porosity, fracture permeability, and fracture aperture are all considered pressure-dependent parameters when accounting for rock deformation. Two inadequacies exist in previous studies on modeling shale gas flow in deformable rock. One is determining the values of pressure-dependent parameters using an explicit method, which means that the pressure-dependent parameters in the next time step are calculated according to the pore pressure of the last time step and remain constant in the iterative solving process of the next time step. During the production, the pore pressure always decreasing, which leads to compression in fractures and a reduction in the fracture permeability and aperture. The explicit method inevitably causes an overestimation of the reservoir productivity. Another inadequacy is neglecting the effect of the change in fracture geometry. In this paper, a fully implicit and fully coupled numerical scheme for discrete fracture modeling of shale gas flow in deformable rock is proposed to reduce the computational error. A comparison between the results of no rock deformation, an explicit method, and implicit method and a field example are presented to calibrate the accuracy of proposed scheme. Another comparison between the explicit and implicit methods shows that the implicit method can noticeably reduce the overestimation caused by the explicit method. The effects of the controlling parameters on the relative difference between the explicit and implicit methods are demonstrated. The results show that the initial permeability of the hydraulic fracture has negligible influence on the relative difference. The initial permeability and compression coefficient of the natural fracture are the main influencing parameters, the initial matrix permeability has a limited impact on the relative difference. The relative difference is caused by the comprehensive effect of kij and (A/d)ij terms.",0,0,1
Fracture,Hydraulic Fracture,"Childers, D.; Wu, X.",Fracture diagnostic technologies with process workflow for implementation,Hydraulic fracturing; Diagnosis; Unconventional reservoir; Fracture conductivity; Stimulated reservoir volume,WELL; GROWTH; MODEL,"Hydraulic Fracturing (HF) is a frequently used well stimulation technology to improve a well's productivity by increasing the contact area with the formation matrix. Hydraulic fractures are created by following a customized design based on imperfect knowledge of the subsurface formation and idealizations. Therefore, the resulting fracture system is often different from the original design, which calls for post-fracturing evaluations. Fracture diagnostics are utilized to understand fracture behavior during or after hydraulic fracturing. Understanding the geomechanics of how fractures form during fracturing has been studied in detail; however, predicting fracture genesis and propagation behavior has been a challenging endeavor because of reservoir heterogeneity. This paper will reveal the current fracture diagnostic technologies and assess their ability to detect HF extension and quantify the properties of hydraulic fractures in terms of conductivity and stimulated reservoir volumes. This paper is not an abridged version of the technical manual regarding how each method is conducted or used but focuses on insight into what they measure and their difference from others. With the critical reviews on current HF diagnostic technologies, we intend to (1) define key terminologies that are often used in HF evaluation to set up a common linguistic lexicon for comparison, (2) provide a brief discussion on their mechanisms; (3) stipulate a framework on how to choose proper HF diagnostic tools and analysis methods for different HF applications.",0,0,1
Fracture,Hydraulic Fracture,"Habibi, A.; Riazi, M.; Malayeri, M. R.",Experimental and simulation study of the tensile strength of wet carbonate rocks using the Brazilian Test,Tensile strength; Wet carbonate rock; Hydration force; Brazilian tensile test; Extended finite element method,,"Mechanical behavior of rocks would have substantial implications for different operations from fluid injection and hydraulic fracturing in hydrocarbon reservoirs to underground carbon dioxide storage in the crust of the earth. In all of these operations, restricting the undesired seismicity events and preserving the integrity of formations is a crucial subject that enforces engineers to evaluate the mechanical behaviors of constituent rocks and predict the formation response. Tensile strength is an important factor for maintaining caprock and reservoir formation from induced tensile cracking which can be influenced by the pore fluid. This paper focuses on the tensile strength of carbonate rock, as an important reservoir rock, in the presence of seawater, as a common injection fluid candidate for enhanced oil recovery objectives. For this purpose, twelve dolomite samples from the Asmari-Jahrum Formation outcrop in Fars province, Iran, were prepared for performing tensile tests. Also for a thorough comparison, sample properties, fluid contents, digital image correlation measurements, and a finite element simulation have been investigated. The experimental results showed a noticeable reduction in the tensile strength of dolomite samples in the presence of distilled water and seawater. In comparison with a dry sample though, a reduction of 16% tensile strength for a seawater saturated sample was observed for similar samples. Among the various mechanisms, which are reported in the open literature, the hydration force seems to be the main reason for the tensile strength reduction and this conclusion was examined by measuring the mass of vaporized adsorbed water on the powder of the same dolomite sample. In addition by testing flooded samples, the impact of flow on the tensile strength was examined. For both cases of seawater and distilled water flooding, the samples which were placed in the outlet zone during the flooding showed lower tensile strength. Moreover, simulation results confirmed the similarity of the weakening trend and impact of seawater.",0,0,2
Fracture,Hydraulic Fracture,"Fu, Chunkai; Guo, Boyun; Mokhtari, Ali",Quantitative analysis of the sequential initiation and simultaneous propagation of multiple fractures in shale gas/oil formations,Frac driven interaction; Quantitative analysis; Fracture length; Fracture initiation; Fracturing design,,"The excessive reach of new fractures during hydraulic fracturing can interact with the pre-existing fracture system during reservoir stimulation. This phenomenon is known as Frac Driven Interaction (FDI), which can greatly compromise the production performance of the wells. The key to minimizing the impact of FDI is to effectively control the length of fractures through a proper fracturing design. This study provides a computer program that outputs the length and initiation time of each fracture to quantitively analyze the sequential initiation and propagation of multiple fractures. Parametric analysis results show that increasing the injection rate, apparent viscosity, and the dilatancy of the fluid can help shorten fracture length and increase fracture count, which ultimately mitigate fracture interaction. Higher dilatancy mainly contributes to the resultant populated length of fractures, while a higher injection rate mainly contributes to the resultant number of fractures. The results also show that a better estimation of critical fracture width is critical to improving the accuracy of the simulation. The effect of various parameters on the FDI index is analyzed i.e. decreasing the injection time from 2h to 1h has led to a 46% decrease of fracture length while the number of fractures is only reduced from 10 to 8. It is found that factors that lead to a higher energy dissipation rate can result in shorter fractures and higher fracture counts. The methodology and results of this paper can deepen our understanding of the fracture interaction mechanism, which may also be used as a guideline and tool to control fracture length and count to mitigate FDI issues.",0,0,2
Fracture,Hydraulic Fracture,"Birkle, Peter; Makechnie, Glenn K.",Geochemical cycle of hydraulic fracturing fluids: Implications for fracture functionality and frac job efficiency in tight sandstone,Hydraulic fracturing; Geochemical fingerprinting; Recovery load; Flowback efficiency; Fracture type,NORTHERN APPALACHIAN BASIN; WATER; EVOLUTION; GAS; RESERVOIR; ORIGIN; WELLS; FIELD; SHALE; GULF,"The efficiency of the hydraulic fracturing processes is measured through its success rate in opening fracture space, fracturing fluid injectivity, and recovery rates of flowback fluid. This paper applies the volumetric ratio (R FF/Fw ) between recovered hydraulic fracturing fluid (FF) and formation water (FW) - besides gas production (GP) and flowback efficiency (FE) - as a third criterion and novel classification tool to quantify the loss of fracturing fluids, the inflow of formation water, and to define the type of involved fractures during hydraulic fracturing. Eight scenarios were designed to assess the performance and success rate of hydraulic fracking operations. For model calibration, geochemical time trends of flowback fluids from two horizontal wells were compared with the known composition of injected FF and local FW to quantify mixing ratios (R FF/Fw ) between both fluid types in produced water. The use of Na and Cl concentrations as nonreactive elements resulted in the most precise solution for endmember calculations. For the cased-hole scenario (C-1), low values of most operational parameters (gas recovery, injected fracturing fluid, recovered flowback volume, and FE of 0.37) reflect tight reservoir conditions with limited conductive capacity of induced fractures in the target zone. The elevated RFF/Fw ratio (2.65) and dominant FF return during the first day of flowback suggest that injected fracturing fluids either remained close to the sealed borehole and returned immediately to surface during post-fracture production or were lost to the formation due to unconnected hydraulic fractures. In contrast, a complex fracture system at the open-hole completion (O-1) allowed the release of gas from micropores, reflected by relatively elevated ratios of 0.5 for FE and low RFF/Fw ratios of 1.09. The interconnectivity between natural and induced fractures permitted the injection of larger volumes of FF with an elevated flowback of both fracturing fluid and formation water. A portion of 26% of the injected FF was recovered from well O-1 during a flowback period of 41 days, while an identical percentage was reached at well C-1 during 10 days. It is of practical importance for fracking operations that geochemical fingerprinting of flowback water can provide strategic decisions to optimize fracturing project performance beyond the capabilities of petrophysical data from well logging. In the present case, similar permeability and porosity characteristics for both targeted elastic intervals could not explain the contrasting performance of both frac jobs. Geochemical assessment can lead to avoiding water-pay zones to minimize the volume of required fracturing fluids for injection purposes, and to economize the recycling process for recoverable flowback fluids. An improved understanding of the functionality of the structural network of natural and induced fractures by the present classification is applicable to predict the success rate for upcoming frac jobs.",0,0,2
Fracture,Hydraulic Fracture,"Kim, Jongkook",Petrophysical/geophysical approaches to identify ISIP variability in the Eagle Ford shale,Geomechanics; ISIP; MWD Gamma ray; Eagle ford; Seismic inversion,DEFORMATION; ROCKS,"Understanding geomechanical properties is essential for an optimal completion strategy that ensures commercial productivity in shale reservoirs with ultra-low permeability. This study provides details to identify the variability of Instantaneous Shut-In Pressure (ISIP) in multidisciplinary approaches using petrophysical and geophysical data. ISIP is one of the input data required for well completion design. Operators commonly ignore the variability of ISIP and use uniform geomechanical assumptions due to cost and time constraints. In the case study, the variability of ISIP was observed up to 30 % in a single horizontal well, which could lower the efficiency of hydraulic fracturing with uniform geomechanical assumptions along a horizontal well trajectory. We propose practical approaches to identify the variability of ISIP from a case study in the Eagle Ford shale. MWD (Measurement While Drilling) Gamma Ray log, which is commonly acquired for a geosteering purpose, was utilized to prove its correlation with actual ISIP data gained at frac-stages in horizontal production wells. Correlation between ISIP and microseismic data was analyzed to identify the integrated relationship among the variability of Gamma Ray, ISIP, and hydraulically-induced fracture. In addition, practical approaches using a series of seismic inversion and attribute data were proposed to help identify geological variabilities affecting ISIP. This study was designed to provide operators hands-on approaches to capturing the variability of ISIP under limited data accessibility. We suggest multifunctional ways using the basic datasets commonly available at field sites. It can be applied to mitigate risks concerning well planning, drilling, and completion design in where operators face frequent challenges from geomechanical heterogeneity in global shale plays.",0,0,2
Fracture,Hydraulic Fracture,"Male, Frank; Duncan, Ian J.",The paradox of increasing initial oil production but faster decline rates in fracking the Bakken Shale: Implications for long term productivity of tight oil plays,Energy forecasting; Unconventional oil; Hydraulic fracturing,WATER; GAS,"In the US, tight oil is the largest source of liquid hydrocarbons and has enabled the country to become the world's largest oil producer. The estimated ultimate recovery (EUR) and rate of production decline are key metrics in the evaluation of the future productivity of tight oil wells. We chose the Bakken Shale because of its high quality, publicly available data. Traditionally, well operators have estimated the EUR for each well from the initial production (IP), using empirical type curves to extrapolate to the ultimate production. From 2015 to 2018 the IP of the average Bakken well increased by approximately 50%. This increase resulted in claims by operators and in the academic literature that more intense hydraulic fracturing was increasing the average EUR of the Bakken play. At the same time, other observers claimed the wells declined much more rapidly than previous wells. This faster decline provided evidence for lower ultimate production from newer wells. The aim of this study was to understand the origin of these seemingly conflicting observations. A physics-based, scaling model was used to predict production from horizontal multi-stage fractured wells. The model for oil recovery is based on pressure diffusion through fractured porous media. The model assumes that the rock is incompressible, the permeability and oil saturation are constant, the water is incompressible, and the viscosity is slowly varying with space. The scaling model was applied to 13,444 wells. The EUR and terminal decline rate (TDR) were estimated from fitting production to our scaling model. Our study found that implementation of more intensive hydraulic fracturing resulted in higher IP and steeper terminal-production declines. Recently published results estimating the total production from the Bakken that include increased lifetime production commensurate with observed increases in average IP, significantly overestimate the long-term production potential of tight oil, both in the US and globally.",0,0,3
Fracture,Hydraulic Fracture,"Zhao, Xinyi; Sang, Qian; Li, Yajun; Liu, Huimin; Li, Zheng; Liu, Yali; Dong, Mingzhe",Dynamic effective permeability of a laminated structure with cross flow in the transient flow process and its application to reservoir simulation,Laminated structure; Coarsening of grid blocks; Dynamic effective permeability; Cross flow; Transient process; Reservoir simulation,FRACTURED HORIZONTAL WELLS; RELATIVE PERMEABILITY; SHALE; HETEROGENEITY; MEDIA,"The effective permeability of a laminated structure is an important parameter related to the practical necessity of coarsening of grid blocks in large scale reservoir simulations. Traditional effective permeability derived under steady state flow conditions can cause great errors in the transient flow process due to the great heterogeneity and anisotropy of laminated formations. To handle this error, the unsteady oil flow in the matrix between hydraulic fractures of a laminated system during an oil depletion process is analyzed in this study. Based on material balance, we present an analytical method for calculating the dynamic effective permeability of the laminated structure considering the cross flow between laminae in the transient flow process. The proposed dynamic effective permeability can be used to conduct coarsening of grid blocks and can be incorporated into numerical models for accurate modeling of transient flow in a laminated structure in the reservoir simulation. It is shown that the simulation results using the proposed effective permeability model match well with those from two-dimensional (2D) simulations. Further, the effects of the horizontal permeability, vertical permeability, thickness of the laminae, and the length of the matrix between fractures are studied.",0,0,3
Fracture,Hydraulic Fracture,"Li, Hao; Shi, Yongmin",Triaxial experimental investigation into the characteristics of acid-etched fractures and acid fracturing,Acid fracturing; Acid-etched fracture; Fracture morphology; Crack spread; Numerical simulation,SIMULATION; SANDSTONE; PROPAGATION; MODEL,"A high-strength pressure-resistant material and acid-resistant thickener are developed, and natural cores extracted from the Changqing Oilfield in China are wrapped in three dimensions to study the initiation, propagation, and characteristics of cracks. Conventional hydraulic fracturing, acid fluid fracturing, and thickener compound acid fluid fracturing were carried out through physical and numerical simulations. The results show that under the simulated environmental pressure, the fracture pressure in the core increases significantly. Ordinary hydraulic fracturing produces a fixed-direction fracture. The acid fluid effectively corroded the wellbore, thereby reducing the fracture pressure, but only some cracks were produced with pure acid pressure. Fracturing with the acid plus the thickener produced a single main fracture. The acidic fluid flowed in a fixed direction and effectively corroded the wellbore, thereby reducing the fracture pressure. A large number of microcracks are due to the thickener slowing down the acid nucleus reaction, which greatly increases the acid transmission distance. The shape of acid-etched cracks is significantly different from hydraulic fracturing because of the acid-rock reaction. Compared with other fracturing simulation studies, this study has the advantage of effectively reducing the initiation and propagation direction of fractures induced by acid fracturing in the presence of underground confining pressure. This experimental method restores the actual underground situation to the greatest extent. This paper combines physical simulation with numerical simulation to study acid erosion fracturing experiments, which provides guidance for optimizing the effect of acid fracturing.",0,0,3
Fracture,Natural Fracture,"Khalaf, Mina S.; Soliman, Noha; El-Banbi, Ahmed H.",Wellbore storage removal in pressure transient analysis for gas wells,Wellbore storage; Deconvolution; Pressure transient analysis; Well testing; Gas wells,DECONVOLUTION ALGORITHM; FLOW; RESERVOIRS,"Wellbore storage (WBS) occurs due to fluid loading/unloading in the wellbore, when a well starts production or is shut-in. This phenomenon creates variable sandface rate and time lag between the surface production rate and the stable sandface rate. Wellbore storage effects can sometimes conceal important information and complicate well test analysis and interpretation. In well tests that suffer from long WBS, removal of WBS effects can usually recover important features in the reservoir signal and lead to significant improvement in identifying the reservoir model and calculating reservoir parameters. Until recently, WBS removal relied on direct deconvolution techniques that require accurate well test data. Presence of noise in the pressure and rate data usually makes direct deconvolution methods unstable. Well test pressure and rate data usually suffer from some noise, and therefore, application of direct deconvolution methods may not work. This work develops a stable technique to eliminate WBS effects present in gas wells. The technique uses two deconvolution steps and applies the recently developed deconvolution algorithms (e.g. von Schroeter algorithm) for stable computations. Unlike the direct deconvolution methods (which become largely unstable when minor noise is present in data) in WBS removal, the proposed approach also extends the reservoir signal over both the drawdown and buildup periods. The new technique is applied to simulated gas well test data in a variety of conditions for validation. The applications considered different well/reservoir models and included different levels of data noise. The technique is also applied to a field case to show the value of the proposed approach. The findings of this study can be used to eliminate WBS effects and recover reservoir signal. It has applications in variety of gas reservoirs where WBS can hide information such as low permeability reservoirs, natural fractured reservoirs, small reservoirs, and wells with large wellbore volume. The reservoir properties calculated from reservoirs after removal of WBS can be used in further calculations such as estimates of gas in place and well productivity to help engineers optimize their wells/reservoirs performance.",0,0,0
Fracture,Natural Fracture,"Hasanzadeh, Maryam; Azin, Reza; Fatehi, Rouhollah; Zendehboudi, Sohrab",New insights into forced and free fall gravity drainage performance in a fractured physical model,Fractured physical model; Gas injection; Recovery factor; Free fall gravity drainage; Forced gravity drainage,TERTIARY OIL-RECOVERY; POROUS-MEDIA; WETTABILITY; DISPLACEMENT; SECONDARY; FLOW,"Gravity is one of the major driving forces for fluid flow in naturally fractured reservoirs. Gravity drainage appears to be a vital recovery mechanism over the oil production process in a majority of fractured reserves. In this paper, free-fall gravity drainage (FFGD) and forced gravity drainage (FGD) production approaches are investigated through employing a new fractured sand pack with a rectangular geometry. Distilled water and condensate are used as the wetting phase. Nitrogen, carbon dioxide, and air are also utilized as the non-wetting phase. A systematic sensitivity analysis is conducted to find the effects of the key factors such as fracture blockage, injection rate, dip angle, and type of wetting phase and injection fluid on the performance of FFGD and FGD processes. Also, a numerical simulation is performed to simulate the experiments. Results reveal that the FGD has a better performance under controlled process conditions, compared to the FFGD so that gas injection with a controlled rate improves the recovery. Moreover, it was found that increasing the gas injection rate improves the recovery factor (RF) of wetting-phase when the up and bottom sides of the fractures are blocked; the RF is decreased in the case with open fracture sides. The recovery of the wetting phase decreases in both FFGD and FGD modes when the porous system has a deviation from the vertical orientation. According to the study outcomes, the immiscible gas-assisted gravity drainage offers a higher condensate recovery, compared to water recovery, due to lower viscosity and interfacial tension (IFT) of the condensate phase. The comparison of the experimental data and simulation results implies that the simulation approach can satisfactorily predict the performance of the FGD process. Based on the error analysis, there is a good match between the simulation results and the experimental measurements; the fluid pair of CO2-condensate exhibits the highest accuracy with an R-squared of 0.9961 and an average relative error (ARE) of 0.0054.",0,0,0
Fracture,Natural Fracture,"Zhang, Jing; Zeng, Yijin; Becerra, Daniela; Slatt, Roger","Statistical analysis of geological factors controlling bed-bounded fracture density in heterolithic shale reservoirs: The example of the Woodford Shale Formation (Oklahoma, USA)",Natural fracture density; Reservoir quality; Rock deformation pattern; Unconventional shale fractures; Layering; Heterolithic; Rock hardness,,"The geological controlling factors of natural fracture distribution and density in the Woodford Shale Formation are quantitatively investigated in this study. The Upper Woodford Shale member in southern Oklahoma, is exceptionally brittle due to the abundance of recrystallized radiolaria chert beds that alternate with siliceous shale beds. Bed-bounded compressional fractures are well developed in the structural-active region. Two areas were characterized and compared to represent low and high confining pressure conditions respectively. A statistical analysis workflow consisting of Principal Component Analysis (PCA) and Partial Least Square Regression (PLS) was proposed to quantify the controlling factors' relationship and their Variable Importance in Projection (VIP) which reveals the contribution of each controlling factor to the fracture density. The result indicated that natural fractures' occurrence in shale reservoirs are impacted by three controlling factors: rock hardness, hard bed ratio (thickness percentage of hard beds within a stratigraphic unit interval) and bed frequency (number of beds within a unit interval). The contributions from these individual controlling factors are different under different reservoir conditions. Bed frequency (layering anisotropy) is the dominant controlling factor that contributes on average three times more than the hard bed ratio and hardness to fracture density. Hardness's contribution to fracture density in the subsurface scenario is lower by 22% than the surface scenario due to the increase in confining pressure. The analytical results highlight the importance of the layering effect on fracture density which has often been overlooked in geomechanical modeling workflow. A new concept of Fracture Density Index (FDI) is defined and can be further applied to predict fracture density in other unconventional reservoirs.",0,0,0
Fracture,Natural Fracture,"Wijaya, Nur; Sheng, James",Effect of compaction and imbibition on benefits of drawdown management in shale oil production: Uncertainty in recovery driving mechanisms,Shale oil; Choke management; Stress-dependent permeability; History matching; Proppant selection; Net present value,HORIZONTAL WELLS; GAS-WELL; PERMEABILITY,"Economic production from shale oil reservoirs relies on the longevity of conductive fractures. Choke or draw-down management is believed to better preserve the fracture conductivity during the early life of the wells, which thus potentially leads to higher ultimate oil recovery. However, there is no strong consensus among the previous literature as to whether choke management can offer incremental oil recovery in the long term. Even if it can, the mechanism is not well understood, and the economic benefit can be challenged, because the choke management slows down the early oil production, which is worth the most in terms of Net Present Value (NPV). In this study, a series of coupled flow-geomechanical numerical simulations is performed to examine the effect of choke management on the ultimate oil recovery and NPV. We built multiple reservoir realization models, each of which is validated based on the same field production data from Middle Bakken shale-oil reservoirs to perform probabilistic production forecasts. The different reservoir realization models are built to assess the uncertainty in the Stimulated Reservoir Volume parameters, including natural fracture spacing, water saturation in the matrix and fracture, and formation compressibility. The different reservoir parameters lead to each model having different primary recovery driving mechanisms of oil recovery, including imbibition and compaction drive. This study quantitatively demonstrates that the choke management seems to increase both the ultimate oil recovery and NPV if the oil recovery is strongly driven by imbibition. A mechanistic discussion for this claim is presented.",0,0,0
Fracture,Natural Fracture,"Le Ngoc Son; Phan Ngoc Trung; Masuda, Yoshihiro; Murata, Sumihiko; Nguyen The Duc; Takagi, Sunao; Ghassemi, Ahmad",Development of a method for adjusting rock compaction parameters and aquifer size from production data and its application to Nam-Su fractured basement reservoir of Vietnam,Aquifer size; Computer-aided engineering; Fractured basement reservoir; History matching; Permeability anisotropy; Reservoir simulation; Rock compaction; Reservoir compressibility,HISTORY; ALGORITHM; FLOW,"The Nam-Su is a major naturally fractured basement reservoir (FBR), offshore Vietnam. To date, simulation models of Nam-Su FBR have failed to give an adequate history match without invoking the presence of large aquifers. In a previous study (Son et al., 2007), the authors investigated several possible alternatives to achieve a satisfactory history match. They modeled porosity reduction by compaction along with the change of aquifer size and produced an improved history match that is consistent with the geological nature of the system. The key to such modeling is reservoir rock compressibility. Estimating the values of rock compressibility from cores is a challenge in FBR's due to the failure of coring from a naturally fractured interval, and thus reliable values are not available. We developed a computer-assisted history matching method to resolve these two problems together and save significant time compared to the manual trial-and-error methods used to adjust these parameters generally used in Vietnam. The methodology developed has been applied successfully to determine rock compaction coefficients and adjust aquifers' sizes of the Nam-Su FBR. Comparisons between our adjusted model and the existing model show considerable improvement between computed and measured values. Simulators can always be adjusted to obtain a history match even with geologically unrealistic values. The approach outlined here is more physically realistic than existing approaches and hence should provide/provides better production and other forecasts.",0,0,1
Fracture,Natural Fracture,"Fabbri, Heber A.; Cleto, Pedro R.; Gaiotto Jr, Aldo T.; Rodrigues, Eduardo A.; Maedo, Michael A.; Manzoli, Osvaldo L.",Modeling the closure behavior of natural fractures in porous media using high aspect ratio interface elements,Natural fractures; Fracture closure model; High aspect ratio interface elements; Hydro-mechanical analysis,FINITE-ELEMENT; FLUID-FLOW; LAND SUBSIDENCE; INTEGRATION SCHEME; CONTACT PROBLEMS; 2-PHASE FLOW; FORMULATION; APPROXIMATION; CONDUCTIVITY; PERMEABILITY,"Many reservoirs consist of fully saturated rock masses containing a very complex natural fracture network. In such cases a decrease in the fracture fluid pressure reduces its aperture due to an increase in the effective stresses. In order to tackle the influence of fracture permeability on the pressure field and fluid flow, this paper proposes a Discrete Fracture-Matrix (DFM) model based on the finite elements to simulate coupled flow and geomechanics in porous media containing fractures with known position and properties (e.g. DFN realizations and fracture networks interpreted from outcrops). The proposed model is based on the use of triangular finite elements with high aspect ratio (HAR) to explicitly represent the fractures. These HAR elements have been successfully used to deal with cracks in concrete structures, desiccation cracks in soils and hydraulic fracturing in geo-reservoirs. This work demonstrate that these HAR elements equipped with a simple continuum (stress-strain) constitutive contact model that mimics the discrete (stress-displacement) Barton-Bandis joint model are able to properly describe the closure behavior associated with natural fractures. The constitutive model is integrated by means of the IMPL-EX scheme, which is a robust and stable technique used to achieve faster convergence. Darcy's law establishes the relationship between the fluid flow and the pressure field, and a fully coupled hydro-mechanical formulation comprises the mathematical framework. The proposed approach is based on continuous mechanics concepts and the implementation is made at constitutive level, and therefore it is simple and easy to be included in any existing FE program. To show the efficiency and accuracy of the proposed model, three numerical examples are conducted in this work: (i) benchmarks involving a medium with a single natural fracture, (ii) three reservoirs with different discrete fracture networks, and (iii) a transient analysis of a reservoir under different fracture conditions, such that the behavior of a intact reservoir, a reservoir containing fractures with constant aperture, and a reservoir in which the fractures aperture depends on the stress state are compared in terms of pore pressure, displacement field and fluid loss. In the first example, the results obtained with the proposed methodology are validated against the Barton-Bandis model. The agreement between the results is very satisfactory. The analysis of the latter two cases show the Barton-Bandis contact model is able to reproduce the effects of fracture permeability on pressure field in the reservoir, showing the capacity of the model to reproduce the main trends associated with the closure of natural fractures.",0,0,1
Fracture,Natural Fracture,"Fawaz, Youssef; La Borderie, Christian; Senechal, Pascale; Jacques, Antoine; Pijaudier-Cabot, Gilles",Fracture cleaning: Experimental study on the unclogging process within a propped fracture under a dynamic stimulation,Fracture; Proppant; Dynamic stimulation; Waves; Intrinsic permeability; Unclogging,PARTICLE,"This experimental study investigates the unclogging process of a propped fracture previously clogged, using a synthetic dynamic load. Pressure oscillations inside the fracture are expected to flush out the fine particles blocking the flow. Laboratory experiments are presented: fractures are clogged with crushed natural sand; after applying the dynamic load, a significant increase of the intrinsic permeability is observed. The highest recovery rate reached was 82%. X-ray CT scans provide images of the fracture before and after the dynamic load is applied. The results show that a high percentage of fines are flushed out of the fracture. The influence of the proppant characteristics and of the quantity of fine particles in the fracture are discussed. Flushing of fines is more effective with large-size proppant. As the density of proppant increases, it passes through a minimum for one layer of proppant which corresponds to a very dense particle distribution. Above one layer of proppant, particles stack onto each other which increases the propped fracture thickness and its conductivity. Finally, it is found that high frequencies and high amplitudes of the dynamic load promote unclogging.",0,0,1
Fracture,Natural Fracture,"Du, Xin; Li, Qingyu; Xian, Yuxi; Lu, Detang",Fully implicit and fully coupled numerical scheme for discrete fracture modeling of shale gas flow in deformable rock,Shale gas; Discrete fracture model; Rock deformation; Explicit method; Implicit method,PERMEABILITY; SIMULATION; STRESS; STRAIN,"Shale gas reservoirs contribute significantly to hydrocarbon production because of their abundant reserves. Shale formation is characterized by low permeability and extremely low porosity. Horizontal well drilling and hydraulic fracturing treatments are typical methods for stimulating the shale gas reservoirs. The discrete fracture model has been widely used to describe flow problems in fractured media. Rock deformation is an important process that occurs simultaneously with the gas flow during the production period and cannot be neglected when modeling the gas flow in shale formations. The matrix permeability, matrix porosity, fracture permeability, and fracture aperture are all considered pressure-dependent parameters when accounting for rock deformation. Two inadequacies exist in previous studies on modeling shale gas flow in deformable rock. One is determining the values of pressure-dependent parameters using an explicit method, which means that the pressure-dependent parameters in the next time step are calculated according to the pore pressure of the last time step and remain constant in the iterative solving process of the next time step. During the production, the pore pressure always decreasing, which leads to compression in fractures and a reduction in the fracture permeability and aperture. The explicit method inevitably causes an overestimation of the reservoir productivity. Another inadequacy is neglecting the effect of the change in fracture geometry. In this paper, a fully implicit and fully coupled numerical scheme for discrete fracture modeling of shale gas flow in deformable rock is proposed to reduce the computational error. A comparison between the results of no rock deformation, an explicit method, and implicit method and a field example are presented to calibrate the accuracy of proposed scheme. Another comparison between the explicit and implicit methods shows that the implicit method can noticeably reduce the overestimation caused by the explicit method. The effects of the controlling parameters on the relative difference between the explicit and implicit methods are demonstrated. The results show that the initial permeability of the hydraulic fracture has negligible influence on the relative difference. The initial permeability and compression coefficient of the natural fracture are the main influencing parameters, the initial matrix permeability has a limited impact on the relative difference. The relative difference is caused by the comprehensive effect of kij and (A/d)ij terms.",0,0,1
Fracture,Natural Fracture,"Ye, Tao; Chen, Anqing; Niu, Chengming; Wang, Qingbin; Hou, Mingcai","Characteristics, controlling factors and petroleum geologic significance of fractures in the Archean crystalline basement rocks: A case study of the South Jinzhou oilfield in Liaodong Bay depression, North China",Basement buried-hill reservoir; Fracture characteristics; Controlling factor; Petroleum geologic significance; South jinzhou oilfield,QUANTITATIVE FLUORESCENCE TECHNIQUES; BURIED-HILL; QAIDAM BASIN; DEVELOPMENTAL CHARACTERISTICS; SHAHEJIE FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; DOMINANT FACTORS; GAS-RESERVOIRS; CHARGE HISTORY,"Fractures play an important role in hydrocarbon storage and migration in basement buried hills. Taking the South Jinzhou oilfield (JZS oilfield) as an example, based on the data from cores, thin sections, seismic, logging, and experimental analysis, we clarified the genetic types and characteristics of fractures in the JZS crystalline basement oilfield and discussed controlling factors and their significance to petroleum geology. Tectonic and non-tectonic fractures are present in the study area, in which tectonic fractures are predominant. Tectonic fractures show three dominant directions with E-W, NE-SW, and NW-SE trends; among them, fractures with E-W trends are best developed. Most of the fractures are oblique, with a dip angle between 45 degrees and 60 degrees. The shear-compression zone trigged by strike-slip faults in-plane is favorable for fracture development. The granitic rocks with low compressive strength are more prone to fracture than diabase. Meteoric water and organic acids promote dissolution along fractures, expanding the tectonic fractures further. The fractures can increase the permeability of crystalline basement rocks by 10(3) times compared with the matrix. The dissolution along fractures can effectively improve the storage capacity of the crystalline basement rocks. Furthermore, there are a large number of fractures developed below the oil-water contact, which are important lateral migration channels for hydrocarbons.",0,0,1
Fracture,Natural Fracture,"Kelishami, Shervin Bahramali Asadi; Mohebian, Reza; Salmian, Omidreza","A comprehensive perspective on pore connectivity and natural fracture analysis in Oligo-Miocene heterogeneous carbonates, southern Iran",Pore connectivity; Permeability; Fracture aperture; Artificial neural network (ANN); Porosity; Image log; Velocity deviation log (VDL),POROSITY; TECTONICS; LOG,"Ascertaining the pore connection criterion has always been a challenge for geoscientists. In the framework of this research, an attempt was made to study the pore connectivity in a heterogeneous carbonate rock by combining several techniques. Pore types and rock facies were investigated for 321 thin sections. The abundance of connected porosities, cementation type and intensity which significantly control the matrix pore connectivity were specified on thin sections and finally a connectivity log was extracted that showed an accurate result on poroperm cross-plots. Most of the porosity volumes were related to interparticle, vuggy and moldic porosities which are microscale. The velocity deviation log, estimated in four wells, indicates the presence of micro porosity, which is consistent with the results of thin-sections. Zero velocity deviation is usually associated with the predominant presence of micro-pores. Different permeability values in identical lithological facies, as well as micro-fracture markers, prompted us to conduct more extensive research on fractures. FMI analysis proved that the studied reservoir is intensively fractured. The recorded high permeability in a sample with low matrix connectivity is specifically a fracture indication. Fracture apertures vary from microscale (<50 mu m) to 12.5 mm and calculated fracture density is raised up to 2 fractures per meter. Determined fractured intervals are very consistent with mud-loss information, for instance, a complete loss has been reported in the fault zone identified in well B. The detected fractures somewhat follow the main Zagros fault trend (NW-SE). Eventually, calculated connectivity was predicted in other wells using Artificial Neural Network (ANN) and a 3D model was constructed with respect to seismic attributes which gives a precise perspective of pore connection distribution throughout the studied field.",0,0,2
Fracture,Natural Fracture,"Saedi, Ghasem; Soleimani, Bahman; Samani, Babak; Arzani, Ali",The interaction between faults and in-situ stress on the kinematic and subsurface natural fracture of Aghajari oilfield in southwest of Iran,Natural fracture; Fault; In-situ stress; Seismic data frequency; Dipole sonic tool,ASMARI FORMATION; BOREHOLE ELONGATION; ZAGROS MOUNTAINS; DEZFUL EMBAYMENT; GAS-RESERVOIRS; IMAGE; BASIN; CORE; WELL; LOGS,"Electrical and acoustic image logs are the best evaluating subsurface fracture and In-situ Stress wellbore data among direct and indirect methods. In this study, which had done by using the 24 Asmari reservoir well data in the Aghajari giant oilfield firstly were determined and categorized subsurface natural fracture, fault and In-situ Stress from common conventional well log, electrical and acoustic image logs, dipole sonic logs and 3D seismic data. Then, the relationship between determined features are evaluated in terms of genesis, events and different structural setting as the interaction between fault and In-situ Stress on the kinematic and subsurface natural fracture of Aghajari oilfield in southwest of Iran. The maximum and minimum horizontal in-situ stress direction is derived from image and dipole data had a good correlation except regions due to the fault effect. the integration of data evinced that the perturbation of regional stresses inherited from seismic faults and the effect of both regional stress and fault effect in the construction of a transforming fold as detachment type in SW nose to forming fault propagation and bending fold towards central and SE nose, respectively, which it could be useful for fracture modeling to enhance oil production, especially in heterogeneous carbonate fractured reservoirs.",0,0,2
Fracture,Natural Fracture,"Birkle, Peter; Makechnie, Glenn K.",Geochemical cycle of hydraulic fracturing fluids: Implications for fracture functionality and frac job efficiency in tight sandstone,Hydraulic fracturing; Geochemical fingerprinting; Recovery load; Flowback efficiency; Fracture type,NORTHERN APPALACHIAN BASIN; WATER; EVOLUTION; GAS; RESERVOIR; ORIGIN; WELLS; FIELD; SHALE; GULF,"The efficiency of the hydraulic fracturing processes is measured through its success rate in opening fracture space, fracturing fluid injectivity, and recovery rates of flowback fluid. This paper applies the volumetric ratio (R FF/Fw ) between recovered hydraulic fracturing fluid (FF) and formation water (FW) - besides gas production (GP) and flowback efficiency (FE) - as a third criterion and novel classification tool to quantify the loss of fracturing fluids, the inflow of formation water, and to define the type of involved fractures during hydraulic fracturing. Eight scenarios were designed to assess the performance and success rate of hydraulic fracking operations. For model calibration, geochemical time trends of flowback fluids from two horizontal wells were compared with the known composition of injected FF and local FW to quantify mixing ratios (R FF/Fw ) between both fluid types in produced water. The use of Na and Cl concentrations as nonreactive elements resulted in the most precise solution for endmember calculations. For the cased-hole scenario (C-1), low values of most operational parameters (gas recovery, injected fracturing fluid, recovered flowback volume, and FE of 0.37) reflect tight reservoir conditions with limited conductive capacity of induced fractures in the target zone. The elevated RFF/Fw ratio (2.65) and dominant FF return during the first day of flowback suggest that injected fracturing fluids either remained close to the sealed borehole and returned immediately to surface during post-fracture production or were lost to the formation due to unconnected hydraulic fractures. In contrast, a complex fracture system at the open-hole completion (O-1) allowed the release of gas from micropores, reflected by relatively elevated ratios of 0.5 for FE and low RFF/Fw ratios of 1.09. The interconnectivity between natural and induced fractures permitted the injection of larger volumes of FF with an elevated flowback of both fracturing fluid and formation water. A portion of 26% of the injected FF was recovered from well O-1 during a flowback period of 41 days, while an identical percentage was reached at well C-1 during 10 days. It is of practical importance for fracking operations that geochemical fingerprinting of flowback water can provide strategic decisions to optimize fracturing project performance beyond the capabilities of petrophysical data from well logging. In the present case, similar permeability and porosity characteristics for both targeted elastic intervals could not explain the contrasting performance of both frac jobs. Geochemical assessment can lead to avoiding water-pay zones to minimize the volume of required fracturing fluids for injection purposes, and to economize the recycling process for recoverable flowback fluids. An improved understanding of the functionality of the structural network of natural and induced fractures by the present classification is applicable to predict the success rate for upcoming frac jobs.",0,0,2
Fracture,Natural Fracture,"Redekop, E. P.; Boronin, S. A.; Tolmacheva, K., I; Burukhin, A. A.; Osiptsov, A. A.; Belonogov, E., V","Effects of salinity and rock clogging on injectivity dynamics of flooding wells: Experiments, modeling and validation on field data",Low salinity flooding; Oil displacement; Formation damage; Pore clogging; Field data,FINES-MIGRATION; WETTABILITY ALTERATION; BRINE COMPOSITION; OIL-RECOVERY; WATER; FLOW; DISPLACEMENT,"Injection of water into a rock formation is a common oilfield services technology to maintain high reservoir pressure and increase ultimate recovery of hydrocarbons. While flowing through the well from surface to the rock formation, injected water typically transports fine particles, for example, fine sand grains and calcite precipitated at surface pipeline conditions while mixing water from different sources (e.g., fresh, Cenomanian and formation brine). In the framework of the two-fluid approach to suspension flow modelling, we formulate mathematical model for linear filtration of a particle-laden suspension in the vicinity of a fractured flooding well and transport of ion concentration (salinity). Two major factors of well injectivity decline are described, namely, particle trapping with associated reduction in permeability and porosity of the rock as well as the effect of salinity of injecting water leading to clay swelling, calcite precipitation and change of relative permeabilities of the rock with respect to water and oil. We calibrate suspension filtration model against in-house experiments on clogging of artificial and natural rock cores, in which the profiles of fines concentration along the cores are obtained using X-Ray computed tomography and analysis of 3D rock reconstruction images. The water injection model is adopted to conditions of Priobskoye oilfield of Western Siberia by using the results of standard laboratory experiments on fluid-fluid (calcite precipitation) and fluid-rock (clay swelling, migration of internal fines) compatibility, as well as the effect of salinity on oil displacement and analysis of solid fraction in the injecting water. The calibrated model is then used to describe field data on dynamics of injection rate of three flooding wells. It is obtained that the simulations predict the long-term injectivity dynamics of the wells very well, while at early times (up to 5 months from the start of injection) the model underestimates the injection rate. While fitting the model to field data, we varied only two parameters, namely, solids concentration in the injecting water (in the range provided by lab experiments) and trapping coefficient (the range is limited to result of experiments made with target rock cores). It is demonstrated that only a combination of injectivity decline factors allows to describe the long-term flooding rate of the wells. Ignoring either particle trapping or salinity effects lead to significant overestimation (up to 50%) of the long-term injection rate. Parametric study of water injection showed that two-fold increase in solids concentration in the injecting water as well as oil compressibility lead to similar decrease in long-term injection rate of a well.",0,0,2
Fracture,Natural Fracture,"Li, Hao; Shi, Yongmin",Triaxial experimental investigation into the characteristics of acid-etched fractures and acid fracturing,Acid fracturing; Acid-etched fracture; Fracture morphology; Crack spread; Numerical simulation,SIMULATION; SANDSTONE; PROPAGATION; MODEL,"A high-strength pressure-resistant material and acid-resistant thickener are developed, and natural cores extracted from the Changqing Oilfield in China are wrapped in three dimensions to study the initiation, propagation, and characteristics of cracks. Conventional hydraulic fracturing, acid fluid fracturing, and thickener compound acid fluid fracturing were carried out through physical and numerical simulations. The results show that under the simulated environmental pressure, the fracture pressure in the core increases significantly. Ordinary hydraulic fracturing produces a fixed-direction fracture. The acid fluid effectively corroded the wellbore, thereby reducing the fracture pressure, but only some cracks were produced with pure acid pressure. Fracturing with the acid plus the thickener produced a single main fracture. The acidic fluid flowed in a fixed direction and effectively corroded the wellbore, thereby reducing the fracture pressure. A large number of microcracks are due to the thickener slowing down the acid nucleus reaction, which greatly increases the acid transmission distance. The shape of acid-etched cracks is significantly different from hydraulic fracturing because of the acid-rock reaction. Compared with other fracturing simulation studies, this study has the advantage of effectively reducing the initiation and propagation direction of fractures induced by acid fracturing in the presence of underground confining pressure. This experimental method restores the actual underground situation to the greatest extent. This paper combines physical simulation with numerical simulation to study acid erosion fracturing experiments, which provides guidance for optimizing the effect of acid fracturing.",0,0,3
Fracture,Injection,"Hasanzadeh, Maryam; Azin, Reza; Fatehi, Rouhollah; Zendehboudi, Sohrab",New insights into forced and free fall gravity drainage performance in a fractured physical model,Fractured physical model; Gas injection; Recovery factor; Free fall gravity drainage; Forced gravity drainage,TERTIARY OIL-RECOVERY; POROUS-MEDIA; WETTABILITY; DISPLACEMENT; SECONDARY; FLOW,"Gravity is one of the major driving forces for fluid flow in naturally fractured reservoirs. Gravity drainage appears to be a vital recovery mechanism over the oil production process in a majority of fractured reserves. In this paper, free-fall gravity drainage (FFGD) and forced gravity drainage (FGD) production approaches are investigated through employing a new fractured sand pack with a rectangular geometry. Distilled water and condensate are used as the wetting phase. Nitrogen, carbon dioxide, and air are also utilized as the non-wetting phase. A systematic sensitivity analysis is conducted to find the effects of the key factors such as fracture blockage, injection rate, dip angle, and type of wetting phase and injection fluid on the performance of FFGD and FGD processes. Also, a numerical simulation is performed to simulate the experiments. Results reveal that the FGD has a better performance under controlled process conditions, compared to the FFGD so that gas injection with a controlled rate improves the recovery. Moreover, it was found that increasing the gas injection rate improves the recovery factor (RF) of wetting-phase when the up and bottom sides of the fractures are blocked; the RF is decreased in the case with open fracture sides. The recovery of the wetting phase decreases in both FFGD and FGD modes when the porous system has a deviation from the vertical orientation. According to the study outcomes, the immiscible gas-assisted gravity drainage offers a higher condensate recovery, compared to water recovery, due to lower viscosity and interfacial tension (IFT) of the condensate phase. The comparison of the experimental data and simulation results implies that the simulation approach can satisfactorily predict the performance of the FGD process. Based on the error analysis, there is a good match between the simulation results and the experimental measurements; the fluid pair of CO2-condensate exhibits the highest accuracy with an R-squared of 0.9961 and an average relative error (ARE) of 0.0054.",0,0,0
Fracture,Injection,"Zhou, Bocheng; Jin, Yan; Xiong, Wei; Zhang, Junjiang; Lai, Jianlin; Fang, Qilong",Investigation on surface strength of acid fracture from scratch test,Surface strength; Scratch test; Limestone; Acid reactivity; Acid fracture optimization,CONDUCTIVITY; MODEL,"Acid fracture surface strength plays an important role in acid fracture conductivity. Previous experimental studies have proven mechanical deterioration of carbonate after acid etching. However, such conclusion drawn from cylindrical samples could not be applied into conductivity evaluation as such samples represent the rock mechanical properties of the carbonate mass rather than the fracture surface. As another representative of fracture surface strength, embedment strength has not met an agreement on the evolution pattern during acid etching. So the absence of fracture surface strength measurement data during acid etching causes a challenge to conductivity evaluation and acid fracturing optimization. In an effort to overcome this challenge, scratch test was adopted for the measurement of the fracture surface strength before and after acid etching, as scratch test could acquire the uniaxial compressive strength of asperities on the fracture surface. In an aim to study the influence of mineral composition, acid contact time and acid injection rate, acid etching experiments under different etching conditions were carried out. The scratch test results uncovered the strong heterogeneity on the limestone samples, and strength of limestone fracture surface would experience both rising and declining trend during acid etching process. Dolomite in limestone samples was responsible for the strength increase while Calcite contributed to the decrease of strength according to the X-ray diffraction experimental results. What is more, the rising Dolomite strength and the decreasing Calcite strength affected the average strength of acidized fracture inherently. As acid contact time increased, the firstly strengthened then weakened Dolomite strength and constantly decreasing Calcite strength gave rise to an average surface strength change tendency that rises in the beginning and later declines. The change tendency of surface strength clearly indicated an optimal acid contact time in acid fracturing operation. Calcite strength showed the decreasing trend and Dolomite exhibited both the rising and decreasing trend as injection rate increased, resulting in an indefinite evolution trend of average strength of acid fracture surface.",0,0,0
Fracture,Injection,"Almarri, Misfer",Identification and characterization of Thermally Induced Fractures through integrated analytical and semi-analytical models,Waterflooding; Oil recovery; Thermally induced fracture; Inter-well communication; Flood efficiency; Fracture characterization,,"Thermally induced fractures (TIFs) are common in waterflooded fields where the injection of (relatively) cold water leads to a cooling front that reduces a formation's in-situ stresses. Understanding TIFs is important since their existence impacts oil recovery potential, well injectivity, injection well integrity, and injector-producer well spacing in reservoirs under waterflooding. Identifying and characterizing dynamic TIF growth is a critical step in defining field development strategies and making daily reservoir management decisions. This research introduces a workflow that integrates analytical well monitoring and semi-analytical models to identify TIF onset, propagation properties, direction, and impact during dynamic reservoir events occurring at different levels. The practicality of the proposed workflow has been tested using synthetic data and its robustness confirmed by an analysis of actual field data. The novelty of the approach presented here is in its efficient integration of recent analytical and semi-analytical models to identify TIF onset, propagation, characteristics, and impact from generally available well injection production history data. This practical workflow will help engineers detect and monitor TIFs and evaluate the metrics describing waterflood performance, including flood efficiency, inter-well communication, and pressure maintenance.",0,0,1
Fracture,Injection,"Mackey, Justin; Gardiner, James; Kutchko, Barbara; Brandi, Meghan; Fazio, James; Hakala, J. Alexandra",Characterizing mineralization on low carbon steel exposed to aerated and degassed synthetic hydraulic fracture fluids,Hydraulic fracturing fluids; Oilfield mineral scale; Unconventional resources; Well integrity; Barite; Corrosion,BARITE SCALE FORMATION; MARCELLUS SHALE; CORROSION; WATER; IRON; OIL; CHLORIDE; INHIBITION; OXIDATION; INSIGHTS,This study investigates the mineralization occurring at the interface between injected hydraulic fracturing fluids and steel production casing during the shut-in period of unconventional shale wells. Mild steel coupons were reacted with synthetic hydraulic fracturing fluids with varying base fluid and dissolved gas concentrations. Experiments were carried out in an autoclave system set at 50 ?C and 2000 PSI for 2 and 14 days. Physical and mineralogical changes to the steel coupons? surface were characterized using an FEI Quanta 600 field emission gun (FEG) scanning electron microscope (SEM) and a PANalytical XPert Pro diffractometer. Barite precipitation occurred ubiquitously during the first 48 h in all experimental scenarios. Sulfate radicals created from degradation and reduction of ammonium persulfate breakers facilitate barite formation. Concomitant barite and corrosion related precipitates on the sample surfaces suggest iron hydroxy salts act as nucleation sites for mineral scale growth. These results suggest hydraulic fracturing fluids may have deleterious effects on the wellbore before production of the well begins.,0,0,1
Fracture,Injection,"Guo, Yonggui; Mohamed, Ibrahim; Zidane, Ali; Panchal, Yashesh; Abou-Sayed, Omar; Abou-Sayed, Ahmed",Automated pressure transient analysis: A cloud-based approach,Pressure transient analysis; Cloud computing; ISIP; Flow regime; G-function; Web-based application,,"Pressure transient analysis provides essential information to evaluate the dimensions of injection induced fractures, permeability damage near the wellbore, and pressure elevation in the injection horizon. For injection wells, shut-in data can be collected and analyzed after each injection cycle to evaluate the well injectivity and predict the well longevity. However, any interactive analysis of the pressure data could be subjective and time-consuming. In this study a novel cloud-based approach to automatically analyzing pressure data is presented, which aims to improve the reliability and efficiency of pressure transient analysis. There are two fundamental requirements for automated pressure transient analysis: 1) Pressure data needs to be automatically retrieved from field sites and fed to the analyzer; 2) The engineer can automatically select instantaneous shut-in pressure (ISIP), identify flow regimes, and determine the fracture closure point if any. To meet these requirements as well as to take advantage of cloud storage and computing technologies, a web-based application has been developed to pull real time injection data from any field sites and push it to a cloud database. A built-in pressure transient workflow has been also proposed to detect any stored or real-time pressure data and perform pressure analysis automatically if the required data is available. The automated pressure transient analysis technology has been applied to multiple injection projects. In general, the analysis results including formation and fracture properties (i.e. permeability, fracture half length, skin factor, and fracture closure pressure) are comparable to results from interactive analysis. Any discrepancies are mainly caused by poor data quality. Issues such as inconsistent selections of ISIP and different slopes defined for pre and after closure analyses also contribute to the divergence. Overall, the automated pressure transient analysis provides consistent results as the exact same criteria are applied to the pressure data, and analysis results are independent of the analyzer's experience and knowledge. As data from oil/gas industry increases exponentially over time, automated data transmission, storage, analysis and access are becoming necessary to maximize the value of the data and reduce operation cost. The automated pressure transient analysis presented here demonstrates that cloud storage and computing combined with automated analysis tools is a viable way to overcome big data challenges faced by oil/gas industry professionals.",0,0,1
Fracture,Injection,"Habibi, A.; Riazi, M.; Malayeri, M. R.",Experimental and simulation study of the tensile strength of wet carbonate rocks using the Brazilian Test,Tensile strength; Wet carbonate rock; Hydration force; Brazilian tensile test; Extended finite element method,,"Mechanical behavior of rocks would have substantial implications for different operations from fluid injection and hydraulic fracturing in hydrocarbon reservoirs to underground carbon dioxide storage in the crust of the earth. In all of these operations, restricting the undesired seismicity events and preserving the integrity of formations is a crucial subject that enforces engineers to evaluate the mechanical behaviors of constituent rocks and predict the formation response. Tensile strength is an important factor for maintaining caprock and reservoir formation from induced tensile cracking which can be influenced by the pore fluid. This paper focuses on the tensile strength of carbonate rock, as an important reservoir rock, in the presence of seawater, as a common injection fluid candidate for enhanced oil recovery objectives. For this purpose, twelve dolomite samples from the Asmari-Jahrum Formation outcrop in Fars province, Iran, were prepared for performing tensile tests. Also for a thorough comparison, sample properties, fluid contents, digital image correlation measurements, and a finite element simulation have been investigated. The experimental results showed a noticeable reduction in the tensile strength of dolomite samples in the presence of distilled water and seawater. In comparison with a dry sample though, a reduction of 16% tensile strength for a seawater saturated sample was observed for similar samples. Among the various mechanisms, which are reported in the open literature, the hydration force seems to be the main reason for the tensile strength reduction and this conclusion was examined by measuring the mass of vaporized adsorbed water on the powder of the same dolomite sample. In addition by testing flooded samples, the impact of flow on the tensile strength was examined. For both cases of seawater and distilled water flooding, the samples which were placed in the outlet zone during the flooding showed lower tensile strength. Moreover, simulation results confirmed the similarity of the weakening trend and impact of seawater.",0,0,2
Fracture,Injection,"Feng, Chenchen; Ma, Xurui; Jing, Zefeng",Dynamic proppant-carrying performance of VES-CO2 foam fracturing fluid in the pipeline and the fracture,VES; Foam fracturing fluid; Proppant; Sedimentation; Fracture,PARTICLE-TRANSPORT,"A viscoelastic surfactant (VES) fluid blends with CO2 to form the foam fracturing fluid. To obtain the dynamic proppant-carrying behaviors of the VES-CO2 foam fluid, an experimental system with a horizontal transparent tube and a visual fracture is built. In the horizontal pipeline, it is displayed that the critical settling flow velocity of the ceramsite proppant in the flowing VES-CO2 foam fluid increases with the temperature. Further, the critical settling flow velocity initially decreases and then increases with both the increases of the foam quality and the proppant ratio, and its transition points are at the foam quality of 0.75-0.80 and at the proppant ratio of 0.25, respectively. In addition, considering the influencing parameters in the experiments, we obtain a correlation equation of the critical settling flow velocity. In the experiments of the fracture observation section, the height of the equilibrium sand bank and the angle of repose are mainly investigated. Both of these two parameters decrease as the foam quality, as well as the injection flow velocity, is increased. Especially, it is found that the angle of repose is below 20 degrees at larger injection flow velocity.",0,0,2
Fracture,Injection,"Fu, Chunkai; Guo, Boyun; Mokhtari, Ali",Quantitative analysis of the sequential initiation and simultaneous propagation of multiple fractures in shale gas/oil formations,Frac driven interaction; Quantitative analysis; Fracture length; Fracture initiation; Fracturing design,,"The excessive reach of new fractures during hydraulic fracturing can interact with the pre-existing fracture system during reservoir stimulation. This phenomenon is known as Frac Driven Interaction (FDI), which can greatly compromise the production performance of the wells. The key to minimizing the impact of FDI is to effectively control the length of fractures through a proper fracturing design. This study provides a computer program that outputs the length and initiation time of each fracture to quantitively analyze the sequential initiation and propagation of multiple fractures. Parametric analysis results show that increasing the injection rate, apparent viscosity, and the dilatancy of the fluid can help shorten fracture length and increase fracture count, which ultimately mitigate fracture interaction. Higher dilatancy mainly contributes to the resultant populated length of fractures, while a higher injection rate mainly contributes to the resultant number of fractures. The results also show that a better estimation of critical fracture width is critical to improving the accuracy of the simulation. The effect of various parameters on the FDI index is analyzed i.e. decreasing the injection time from 2h to 1h has led to a 46% decrease of fracture length while the number of fractures is only reduced from 10 to 8. It is found that factors that lead to a higher energy dissipation rate can result in shorter fractures and higher fracture counts. The methodology and results of this paper can deepen our understanding of the fracture interaction mechanism, which may also be used as a guideline and tool to control fracture length and count to mitigate FDI issues.",0,0,2
Fracture,Injection,"Birkle, Peter; Makechnie, Glenn K.",Geochemical cycle of hydraulic fracturing fluids: Implications for fracture functionality and frac job efficiency in tight sandstone,Hydraulic fracturing; Geochemical fingerprinting; Recovery load; Flowback efficiency; Fracture type,NORTHERN APPALACHIAN BASIN; WATER; EVOLUTION; GAS; RESERVOIR; ORIGIN; WELLS; FIELD; SHALE; GULF,"The efficiency of the hydraulic fracturing processes is measured through its success rate in opening fracture space, fracturing fluid injectivity, and recovery rates of flowback fluid. This paper applies the volumetric ratio (R FF/Fw ) between recovered hydraulic fracturing fluid (FF) and formation water (FW) - besides gas production (GP) and flowback efficiency (FE) - as a third criterion and novel classification tool to quantify the loss of fracturing fluids, the inflow of formation water, and to define the type of involved fractures during hydraulic fracturing. Eight scenarios were designed to assess the performance and success rate of hydraulic fracking operations. For model calibration, geochemical time trends of flowback fluids from two horizontal wells were compared with the known composition of injected FF and local FW to quantify mixing ratios (R FF/Fw ) between both fluid types in produced water. The use of Na and Cl concentrations as nonreactive elements resulted in the most precise solution for endmember calculations. For the cased-hole scenario (C-1), low values of most operational parameters (gas recovery, injected fracturing fluid, recovered flowback volume, and FE of 0.37) reflect tight reservoir conditions with limited conductive capacity of induced fractures in the target zone. The elevated RFF/Fw ratio (2.65) and dominant FF return during the first day of flowback suggest that injected fracturing fluids either remained close to the sealed borehole and returned immediately to surface during post-fracture production or were lost to the formation due to unconnected hydraulic fractures. In contrast, a complex fracture system at the open-hole completion (O-1) allowed the release of gas from micropores, reflected by relatively elevated ratios of 0.5 for FE and low RFF/Fw ratios of 1.09. The interconnectivity between natural and induced fractures permitted the injection of larger volumes of FF with an elevated flowback of both fracturing fluid and formation water. A portion of 26% of the injected FF was recovered from well O-1 during a flowback period of 41 days, while an identical percentage was reached at well C-1 during 10 days. It is of practical importance for fracking operations that geochemical fingerprinting of flowback water can provide strategic decisions to optimize fracturing project performance beyond the capabilities of petrophysical data from well logging. In the present case, similar permeability and porosity characteristics for both targeted elastic intervals could not explain the contrasting performance of both frac jobs. Geochemical assessment can lead to avoiding water-pay zones to minimize the volume of required fracturing fluids for injection purposes, and to economize the recycling process for recoverable flowback fluids. An improved understanding of the functionality of the structural network of natural and induced fractures by the present classification is applicable to predict the success rate for upcoming frac jobs.",0,0,2
Fracture,Injection,"Redekop, E. P.; Boronin, S. A.; Tolmacheva, K., I; Burukhin, A. A.; Osiptsov, A. A.; Belonogov, E., V","Effects of salinity and rock clogging on injectivity dynamics of flooding wells: Experiments, modeling and validation on field data",Low salinity flooding; Oil displacement; Formation damage; Pore clogging; Field data,FINES-MIGRATION; WETTABILITY ALTERATION; BRINE COMPOSITION; OIL-RECOVERY; WATER; FLOW; DISPLACEMENT,"Injection of water into a rock formation is a common oilfield services technology to maintain high reservoir pressure and increase ultimate recovery of hydrocarbons. While flowing through the well from surface to the rock formation, injected water typically transports fine particles, for example, fine sand grains and calcite precipitated at surface pipeline conditions while mixing water from different sources (e.g., fresh, Cenomanian and formation brine). In the framework of the two-fluid approach to suspension flow modelling, we formulate mathematical model for linear filtration of a particle-laden suspension in the vicinity of a fractured flooding well and transport of ion concentration (salinity). Two major factors of well injectivity decline are described, namely, particle trapping with associated reduction in permeability and porosity of the rock as well as the effect of salinity of injecting water leading to clay swelling, calcite precipitation and change of relative permeabilities of the rock with respect to water and oil. We calibrate suspension filtration model against in-house experiments on clogging of artificial and natural rock cores, in which the profiles of fines concentration along the cores are obtained using X-Ray computed tomography and analysis of 3D rock reconstruction images. The water injection model is adopted to conditions of Priobskoye oilfield of Western Siberia by using the results of standard laboratory experiments on fluid-fluid (calcite precipitation) and fluid-rock (clay swelling, migration of internal fines) compatibility, as well as the effect of salinity on oil displacement and analysis of solid fraction in the injecting water. The calibrated model is then used to describe field data on dynamics of injection rate of three flooding wells. It is obtained that the simulations predict the long-term injectivity dynamics of the wells very well, while at early times (up to 5 months from the start of injection) the model underestimates the injection rate. While fitting the model to field data, we varied only two parameters, namely, solids concentration in the injecting water (in the range provided by lab experiments) and trapping coefficient (the range is limited to result of experiments made with target rock cores). It is demonstrated that only a combination of injectivity decline factors allows to describe the long-term flooding rate of the wells. Ignoring either particle trapping or salinity effects lead to significant overestimation (up to 50%) of the long-term injection rate. Parametric study of water injection showed that two-fold increase in solids concentration in the injecting water as well as oil compressibility lead to similar decrease in long-term injection rate of a well.",0,0,2
Fracture,Injection,"Wang, Qiong; Jiang, Ruizhong; Leng, Jie; Liu, Xiuwei",The effect of the viscosity-dependent boundary layer on tight oil flow behavior in CO2 Huff-Puff processes: A unified dimensional Pre-Darcy flow model,Pre-Darcy flow; Compositional simulation; CO2 EOR,N-PUFF; RESERVOIR SIMULATION; NUMERICAL-SIMULATION; FRACTURE NETWORKS; RECOVERY; SHALE,"There are numerous percolation studies of unconventional reservoirs showing that in tight or low-permeability formations, the oil flow behavior could be described by the Pre-Darcy mechanism. However, for the CO2 Huff-nPuff operations, the most presented low-velocity Pre-Darcy flow models may result in an erroneous evaluation due to the intensive boundary layer thickness changes caused by the CO2 extraction and dissolution. In this paper, with multiple parameters fitting the seepage experimental results of the studied area, a unified dimensional Pre-Darcy flow model for CO2 enhanced oil recovery (EOR) is derived from the classic Poiseuille model. Then, the proposed flow model is applied in the compositional simulator for analyzing the viscosity-dependent boundary layer (VDBL) effect, applicability evaluation in Huff-Puff EOR, and field history matching. The results indicate that the VDBL effect improves the oil mobility in injection periods and lowers the residual oil saturation at the front of the CO2 convection-diffusion area in reproduction periods. Additionally, the nonlinear parameter alpha and the shape parameter beta enhance the proposed model's applicability for the Huff process and the Puff process respectively. Finally, by adjusting the parameters alpha and beta for different permeability intervals of the geological model, the flow model is successfully applied in the oil production matching of the Y6 well, which exhibits its reliability in the history matching.",0,0,3
Fracture,Injection,"Pagano, Arianna Gea; El Mountassir, Grainne; Lunn, Rebecca Jane",Performance of colloidal silica grout at elevated temperatures and pressures for cement fracture sealing at depth,Colloidal silica; Well decommissioning; Plug &amp; abandonment; Wellbore integrity,WELL INTEGRITY,"Hydrocarbon well decommissioning requires the long-term sealing of abandoned wells. Current plug and abandonment (P&A) operations are not always able to address all potential fluid migration pathways, resulting in the possible upwards migration of hydrocarbons from formations penetrated by the wellbore. The development of innovative materials to improve well sealing remains a major challenge. This paper presents a proof of concept for the use of colloidal silica (CS)-based grout to improve the sealing performance of P&A operations. CS is a non-toxic suspension of silica nanoparticles (<100 nm) undergoing gelation upon destabilisation. Due to its excellent penetrability and controllable gel time, CS has the potential for repairing fine-aperture cracks within the cement sheath, at the cement/casing interface, or within a cement plug, where the penetration of cementitious grouts is restricted due to their relatively large particle size. In this study, the suitability of CS grout for deployment up to 1500 m depth was successfully demonstrated. Firstly, a range of CS grout mixes were investigated to test the feasibility of grout emplacement considering a timescale of 2 h for pumping operations from the surface to depth. Secondly, to investigate the sealing performance, the CS grout was injected into fractured cement cores (0.2 and 0.5 mm fracture aperture) and exposed to pressure and temperature conditions simulating downhole scenarios up to 1500 m depth (based on gradients for North Sea, UK). Fracture permeability upon water injection was assessed pre- and post-treatment. This work found that permeability values after treatment were reduced by three orders of magnitude, thus confirming the potential of CS grout for repairing fine-aperture cracks.",0,0,3
Fracture,Injection,"Shilov, Evgeny; Dorhjie, Desmond Batsa; Mukhina, Elena; Zvada, Maya; Kasyanenko, Anton; Cheremisin, Alexey",Experimental and numerical studies of rich gas Huff-n-Puff injection in tight formation,Associated gas EOR; Huff-n-Puff; Tight oil reservoirs; Minimum miscibility pressure; Gas diffusivity,ENHANCED-OIL-RECOVERY; SHALE PLUGS; PERFORMANCE; SIMULATION,"Huff-n-Puff technology is considered one of the most effective methods to increase oil recovery in shale reservoirs. Previous works were mainly focused on Bakken and Eagle Ford shales. This paper is devoted to experimental and numerical studies of rich gas injection in core samples with high organic matter content from a tight oil reservoir in Russia. Eighteen core samples from different well intervals and different sizes were used in a Huff-n-Puff experimental study. Eight of the core samples were investigated at an injection pressure of 15 MPa, while ten core samples were studied at near-miscible pressure conditions of 30 MPa. The experiment results indicate that Huff-n-Puff injection of rich gas could give an oil recovery average of 63.03% and a maximum of 88.40% at 30 MPa injection pressure. A compositional model was created utilizing a commercial simulator and history matched to experimental results. The validated model was used to investigate the effect of molecular gas diffusivity, injection pressure, injection duration, shut-in duration, production duration, and other reservoir properties on the recovery factor. Sensitivity analysis by numerical modeling shows that the molecular gas diffusivity was critical in the history matching of the model. The numerical simulation results imply that the recovery factor could be increased by extending the injection period. In contrast, the duration of a soak period does not significantly influence the recovery factor. Furthermore, the recovery factor could be increased by extension of the production due to a slow decline in the pressure gradient between the matrix and fracture at the later stage of the production. The results of the present study imply that the application of the Huff-n-Puff injection of rich gas could increase oil recovery from tight reservoirs.",0,0,3
Fracture,Horizontal Wells,"Wijaya, Nur; Sheng, James",Effect of compaction and imbibition on benefits of drawdown management in shale oil production: Uncertainty in recovery driving mechanisms,Shale oil; Choke management; Stress-dependent permeability; History matching; Proppant selection; Net present value,HORIZONTAL WELLS; GAS-WELL; PERMEABILITY,"Economic production from shale oil reservoirs relies on the longevity of conductive fractures. Choke or draw-down management is believed to better preserve the fracture conductivity during the early life of the wells, which thus potentially leads to higher ultimate oil recovery. However, there is no strong consensus among the previous literature as to whether choke management can offer incremental oil recovery in the long term. Even if it can, the mechanism is not well understood, and the economic benefit can be challenged, because the choke management slows down the early oil production, which is worth the most in terms of Net Present Value (NPV). In this study, a series of coupled flow-geomechanical numerical simulations is performed to examine the effect of choke management on the ultimate oil recovery and NPV. We built multiple reservoir realization models, each of which is validated based on the same field production data from Middle Bakken shale-oil reservoirs to perform probabilistic production forecasts. The different reservoir realization models are built to assess the uncertainty in the Stimulated Reservoir Volume parameters, including natural fracture spacing, water saturation in the matrix and fracture, and formation compressibility. The different reservoir parameters lead to each model having different primary recovery driving mechanisms of oil recovery, including imbibition and compaction drive. This study quantitatively demonstrates that the choke management seems to increase both the ultimate oil recovery and NPV if the oil recovery is strongly driven by imbibition. A mechanistic discussion for this claim is presented.",0,0,0
Fracture,Horizontal Wells,"Li, Meng; Su, YuLiang; Wang, WenDong; Li, YaJun; Dong, MingZhe",Impact of cross-flow on well production in shale reservoir considering vertical variation of reservoir and fracture properties: Model and field application,Shale oil; Vertical heterogeneity; Cross-flow; Hydraulically fractured horizontal well,PRESSURE TRANSIENT ANALYSIS; LONGMAXI MARINE SHALE; SEMIANALYTIC SOLUTION; BASIN; HETEROGENEITY; GEOCHEMISTRY; LITHOFACIES,"Shale is a highly vertical heterogeneous formation due to the complex sedimentary environment. Unfortunately, available models to predict the well production rely on the over-simplified assumption that ignores the effect of vertical heterogeneity and cross-flow on well production. This work aims to propose a simple-yet-rigorous oil flow model considering the vertical heterogeneity in shale formation. The stimulated reservoir volume (SRV) near well is characterized by a Vertical Heterogeneous Cross-flow Model (VHCM). The drainage volume is divided into several layers, and the diffusivity equation of each segment is derived separately. Thus, three dimensions of flow are considered simultaneously. The VHCM is analytically solved in Laplace domain and inversed to real domain numerically. Then the proposed model is verified against the fine-grid numerical results. Based on the VHCM, the flow characteristics in shale formation considering the effects of vertical heterogeneity and cross-flow are systemically investigated. The result shows that the adoption of a vertical homogeneous model will lead to the overestimation of reservoir properties and using the Vertical Heterogeneous No-cross-flow Model (VHNM) will lead to the underestimation of reservoir properties in shale formation. In addition, thin interbedded structures and stratified sandstone in shale are beneficial for well production. Compared with the traditional vertical homogeneous model, the VHCM captures the variation of reservoir and fracture properties in shale reservoirs, and the results better match the field data.",0,0,0
Fracture,Horizontal Wells,"Liu, Xing; Jin, Yan; Lin, Botao",An efficient stimulated reservoir area (SRA) estimation method based on octree decomposition of microseismic events,Hydraulic fracturing; Microseismic monitoring; Stimulated reservoir volume; Stimulated reservoir area; Octree method; Monte Carlo method,FRACTURE; GEOMECHANICS; PROPAGATION; SYSTEMS; SHALE,"Fracture contact area is the critical factor determining post-treatment production after multi-stage hydraulic fracturing. At present, there are no effective methods for the estimation of the stimulated reservoir area (SRA) of the complex fracture network after stimulation. Conventional methods mostly focused on calculating stimulated reservoir volume (SRV) by using microseismic events directly or indirectly. However, since there is a large number of noise events in microseismic data that can't be removed completely, the SRV results often have huge errors and are inconsistent with practical well production. For this reason, we propose an efficient and robust SRA calculation method based on 3D octree decomposition. The method is able to effectively estimate SRA by generating a multi-level grid structure without reconstructing the fracture network. Through a large number of case simulations based on synthetic events generated by Monte Carlo method, it is found that our method could adapt to the estimation of SRA for different configurations. It could obtain reliable and robust results in the presence of noise events. Specifically, it is indicated that the maximum relative calculation error is less than 20% for mesoscale and large-scale fracture network. The error for small-scale fractures could be reduced below 30% combining with the error reduction approach put forward in this paper. The applicability of our method is also investigated through two horizontal well platforms. Compared with the conventional SRV method, it is found that SRA obtained by our method could better reflect the stimulation effects and is more consistent with real production. It could become a potential and effective index for stimulation evaluation and fracturing operation optimization.",0,0,1
Fracture,Horizontal Wells,"Du, Xin; Li, Qingyu; Xian, Yuxi; Lu, Detang",Fully implicit and fully coupled numerical scheme for discrete fracture modeling of shale gas flow in deformable rock,Shale gas; Discrete fracture model; Rock deformation; Explicit method; Implicit method,PERMEABILITY; SIMULATION; STRESS; STRAIN,"Shale gas reservoirs contribute significantly to hydrocarbon production because of their abundant reserves. Shale formation is characterized by low permeability and extremely low porosity. Horizontal well drilling and hydraulic fracturing treatments are typical methods for stimulating the shale gas reservoirs. The discrete fracture model has been widely used to describe flow problems in fractured media. Rock deformation is an important process that occurs simultaneously with the gas flow during the production period and cannot be neglected when modeling the gas flow in shale formations. The matrix permeability, matrix porosity, fracture permeability, and fracture aperture are all considered pressure-dependent parameters when accounting for rock deformation. Two inadequacies exist in previous studies on modeling shale gas flow in deformable rock. One is determining the values of pressure-dependent parameters using an explicit method, which means that the pressure-dependent parameters in the next time step are calculated according to the pore pressure of the last time step and remain constant in the iterative solving process of the next time step. During the production, the pore pressure always decreasing, which leads to compression in fractures and a reduction in the fracture permeability and aperture. The explicit method inevitably causes an overestimation of the reservoir productivity. Another inadequacy is neglecting the effect of the change in fracture geometry. In this paper, a fully implicit and fully coupled numerical scheme for discrete fracture modeling of shale gas flow in deformable rock is proposed to reduce the computational error. A comparison between the results of no rock deformation, an explicit method, and implicit method and a field example are presented to calibrate the accuracy of proposed scheme. Another comparison between the explicit and implicit methods shows that the implicit method can noticeably reduce the overestimation caused by the explicit method. The effects of the controlling parameters on the relative difference between the explicit and implicit methods are demonstrated. The results show that the initial permeability of the hydraulic fracture has negligible influence on the relative difference. The initial permeability and compression coefficient of the natural fracture are the main influencing parameters, the initial matrix permeability has a limited impact on the relative difference. The relative difference is caused by the comprehensive effect of kij and (A/d)ij terms.",0,0,1
Fracture,Horizontal Wells,"Saedi, Ghasem; Soleimani, Bahman; Samani, Babak; Arzani, Ali",The interaction between faults and in-situ stress on the kinematic and subsurface natural fracture of Aghajari oilfield in southwest of Iran,Natural fracture; Fault; In-situ stress; Seismic data frequency; Dipole sonic tool,ASMARI FORMATION; BOREHOLE ELONGATION; ZAGROS MOUNTAINS; DEZFUL EMBAYMENT; GAS-RESERVOIRS; IMAGE; BASIN; CORE; WELL; LOGS,"Electrical and acoustic image logs are the best evaluating subsurface fracture and In-situ Stress wellbore data among direct and indirect methods. In this study, which had done by using the 24 Asmari reservoir well data in the Aghajari giant oilfield firstly were determined and categorized subsurface natural fracture, fault and In-situ Stress from common conventional well log, electrical and acoustic image logs, dipole sonic logs and 3D seismic data. Then, the relationship between determined features are evaluated in terms of genesis, events and different structural setting as the interaction between fault and In-situ Stress on the kinematic and subsurface natural fracture of Aghajari oilfield in southwest of Iran. The maximum and minimum horizontal in-situ stress direction is derived from image and dipole data had a good correlation except regions due to the fault effect. the integration of data evinced that the perturbation of regional stresses inherited from seismic faults and the effect of both regional stress and fault effect in the construction of a transforming fold as detachment type in SW nose to forming fault propagation and bending fold towards central and SE nose, respectively, which it could be useful for fracture modeling to enhance oil production, especially in heterogeneous carbonate fractured reservoirs.",0,0,2
Fracture,Horizontal Wells,"Feng, Chenchen; Ma, Xurui; Jing, Zefeng",Dynamic proppant-carrying performance of VES-CO2 foam fracturing fluid in the pipeline and the fracture,VES; Foam fracturing fluid; Proppant; Sedimentation; Fracture,PARTICLE-TRANSPORT,"A viscoelastic surfactant (VES) fluid blends with CO2 to form the foam fracturing fluid. To obtain the dynamic proppant-carrying behaviors of the VES-CO2 foam fluid, an experimental system with a horizontal transparent tube and a visual fracture is built. In the horizontal pipeline, it is displayed that the critical settling flow velocity of the ceramsite proppant in the flowing VES-CO2 foam fluid increases with the temperature. Further, the critical settling flow velocity initially decreases and then increases with both the increases of the foam quality and the proppant ratio, and its transition points are at the foam quality of 0.75-0.80 and at the proppant ratio of 0.25, respectively. In addition, considering the influencing parameters in the experiments, we obtain a correlation equation of the critical settling flow velocity. In the experiments of the fracture observation section, the height of the equilibrium sand bank and the angle of repose are mainly investigated. Both of these two parameters decrease as the foam quality, as well as the injection flow velocity, is increased. Especially, it is found that the angle of repose is below 20 degrees at larger injection flow velocity.",0,0,2
Fracture,Horizontal Wells,"Birkle, Peter; Makechnie, Glenn K.",Geochemical cycle of hydraulic fracturing fluids: Implications for fracture functionality and frac job efficiency in tight sandstone,Hydraulic fracturing; Geochemical fingerprinting; Recovery load; Flowback efficiency; Fracture type,NORTHERN APPALACHIAN BASIN; WATER; EVOLUTION; GAS; RESERVOIR; ORIGIN; WELLS; FIELD; SHALE; GULF,"The efficiency of the hydraulic fracturing processes is measured through its success rate in opening fracture space, fracturing fluid injectivity, and recovery rates of flowback fluid. This paper applies the volumetric ratio (R FF/Fw ) between recovered hydraulic fracturing fluid (FF) and formation water (FW) - besides gas production (GP) and flowback efficiency (FE) - as a third criterion and novel classification tool to quantify the loss of fracturing fluids, the inflow of formation water, and to define the type of involved fractures during hydraulic fracturing. Eight scenarios were designed to assess the performance and success rate of hydraulic fracking operations. For model calibration, geochemical time trends of flowback fluids from two horizontal wells were compared with the known composition of injected FF and local FW to quantify mixing ratios (R FF/Fw ) between both fluid types in produced water. The use of Na and Cl concentrations as nonreactive elements resulted in the most precise solution for endmember calculations. For the cased-hole scenario (C-1), low values of most operational parameters (gas recovery, injected fracturing fluid, recovered flowback volume, and FE of 0.37) reflect tight reservoir conditions with limited conductive capacity of induced fractures in the target zone. The elevated RFF/Fw ratio (2.65) and dominant FF return during the first day of flowback suggest that injected fracturing fluids either remained close to the sealed borehole and returned immediately to surface during post-fracture production or were lost to the formation due to unconnected hydraulic fractures. In contrast, a complex fracture system at the open-hole completion (O-1) allowed the release of gas from micropores, reflected by relatively elevated ratios of 0.5 for FE and low RFF/Fw ratios of 1.09. The interconnectivity between natural and induced fractures permitted the injection of larger volumes of FF with an elevated flowback of both fracturing fluid and formation water. A portion of 26% of the injected FF was recovered from well O-1 during a flowback period of 41 days, while an identical percentage was reached at well C-1 during 10 days. It is of practical importance for fracking operations that geochemical fingerprinting of flowback water can provide strategic decisions to optimize fracturing project performance beyond the capabilities of petrophysical data from well logging. In the present case, similar permeability and porosity characteristics for both targeted elastic intervals could not explain the contrasting performance of both frac jobs. Geochemical assessment can lead to avoiding water-pay zones to minimize the volume of required fracturing fluids for injection purposes, and to economize the recycling process for recoverable flowback fluids. An improved understanding of the functionality of the structural network of natural and induced fractures by the present classification is applicable to predict the success rate for upcoming frac jobs.",0,0,2
Fracture,Horizontal Wells,"Kim, Jongkook",Petrophysical/geophysical approaches to identify ISIP variability in the Eagle Ford shale,Geomechanics; ISIP; MWD Gamma ray; Eagle ford; Seismic inversion,DEFORMATION; ROCKS,"Understanding geomechanical properties is essential for an optimal completion strategy that ensures commercial productivity in shale reservoirs with ultra-low permeability. This study provides details to identify the variability of Instantaneous Shut-In Pressure (ISIP) in multidisciplinary approaches using petrophysical and geophysical data. ISIP is one of the input data required for well completion design. Operators commonly ignore the variability of ISIP and use uniform geomechanical assumptions due to cost and time constraints. In the case study, the variability of ISIP was observed up to 30 % in a single horizontal well, which could lower the efficiency of hydraulic fracturing with uniform geomechanical assumptions along a horizontal well trajectory. We propose practical approaches to identify the variability of ISIP from a case study in the Eagle Ford shale. MWD (Measurement While Drilling) Gamma Ray log, which is commonly acquired for a geosteering purpose, was utilized to prove its correlation with actual ISIP data gained at frac-stages in horizontal production wells. Correlation between ISIP and microseismic data was analyzed to identify the integrated relationship among the variability of Gamma Ray, ISIP, and hydraulically-induced fracture. In addition, practical approaches using a series of seismic inversion and attribute data were proposed to help identify geological variabilities affecting ISIP. This study was designed to provide operators hands-on approaches to capturing the variability of ISIP under limited data accessibility. We suggest multifunctional ways using the basic datasets commonly available at field sites. It can be applied to mitigate risks concerning well planning, drilling, and completion design in where operators face frequent challenges from geomechanical heterogeneity in global shale plays.",0,0,2
Fracture,Horizontal Wells,"Nie, Ren-Shi; Li, Jing-Shun; Deng, Qi; Chen, Zhangxin; Xie, Fei; Qu, Jianhua; Zhan, Jie; Cao, Xianping; Lu, Cong; Yi, Pan",Modeling transient flow behavior of eccentric horizontal well in bi-zonal formation,Transient flow behavior; Horizontal well; Bi -zonal formation; Type curves; Flow regime,PARTIALLY PENETRATING WELL; FRACTURED WELL; PUMPING TESTS; COMPOSITE; PRESSURE; STORAGE; RESERVOIRS; SKIN,"In this study, an eccentric horizontal well in a bi-zonal formation and traversing the inner zone is first modeled. Three novel conceptual models are presented for three different well-placement situations: a horizontal well (i) in an inner zone, (ii) traversing partially in an inner zone, and (iii) traversing fully in an inner zone. A point source model in a bi-zonal formation is established and solved using the Laplace transform, finite Fourier cosine transform and separation of variables. The pressure solutions for a point source in the inner and outer zones are obtained by integrating the point-source solution along a horizontal well. A series of type curves is simulated to reveal the transient flow behavior of a horizontal well in a bi-zonal formation. The main flow regimes are discerned based on the type curves. Eight, six, and six flow regimes were discerned for the first, second, and third situations, respectively. The effect of different deviated distances on the type curves was analyzed. The type curves are compared among the three situations. Finally, the model is applied to a real case to validate it. This study can provide insights into the transient flow behavior controlled by an eccentric horizontal well in a bi-zonal formation.",0,0,2
Fracture,Horizontal Wells,"Male, Frank; Duncan, Ian J.",The paradox of increasing initial oil production but faster decline rates in fracking the Bakken Shale: Implications for long term productivity of tight oil plays,Energy forecasting; Unconventional oil; Hydraulic fracturing,WATER; GAS,"In the US, tight oil is the largest source of liquid hydrocarbons and has enabled the country to become the world's largest oil producer. The estimated ultimate recovery (EUR) and rate of production decline are key metrics in the evaluation of the future productivity of tight oil wells. We chose the Bakken Shale because of its high quality, publicly available data. Traditionally, well operators have estimated the EUR for each well from the initial production (IP), using empirical type curves to extrapolate to the ultimate production. From 2015 to 2018 the IP of the average Bakken well increased by approximately 50%. This increase resulted in claims by operators and in the academic literature that more intense hydraulic fracturing was increasing the average EUR of the Bakken play. At the same time, other observers claimed the wells declined much more rapidly than previous wells. This faster decline provided evidence for lower ultimate production from newer wells. The aim of this study was to understand the origin of these seemingly conflicting observations. A physics-based, scaling model was used to predict production from horizontal multi-stage fractured wells. The model for oil recovery is based on pressure diffusion through fractured porous media. The model assumes that the rock is incompressible, the permeability and oil saturation are constant, the water is incompressible, and the viscosity is slowly varying with space. The scaling model was applied to 13,444 wells. The EUR and terminal decline rate (TDR) were estimated from fitting production to our scaling model. Our study found that implementation of more intensive hydraulic fracturing resulted in higher IP and steeper terminal-production declines. Recently published results estimating the total production from the Bakken that include increased lifetime production commensurate with observed increases in average IP, significantly overestimate the long-term production potential of tight oil, both in the US and globally.",0,0,3
Fracture,Horizontal Wells,"Zhao, Xinyi; Sang, Qian; Li, Yajun; Liu, Huimin; Li, Zheng; Liu, Yali; Dong, Mingzhe",Dynamic effective permeability of a laminated structure with cross flow in the transient flow process and its application to reservoir simulation,Laminated structure; Coarsening of grid blocks; Dynamic effective permeability; Cross flow; Transient process; Reservoir simulation,FRACTURED HORIZONTAL WELLS; RELATIVE PERMEABILITY; SHALE; HETEROGENEITY; MEDIA,"The effective permeability of a laminated structure is an important parameter related to the practical necessity of coarsening of grid blocks in large scale reservoir simulations. Traditional effective permeability derived under steady state flow conditions can cause great errors in the transient flow process due to the great heterogeneity and anisotropy of laminated formations. To handle this error, the unsteady oil flow in the matrix between hydraulic fractures of a laminated system during an oil depletion process is analyzed in this study. Based on material balance, we present an analytical method for calculating the dynamic effective permeability of the laminated structure considering the cross flow between laminae in the transient flow process. The proposed dynamic effective permeability can be used to conduct coarsening of grid blocks and can be incorporated into numerical models for accurate modeling of transient flow in a laminated structure in the reservoir simulation. It is shown that the simulation results using the proposed effective permeability model match well with those from two-dimensional (2D) simulations. Further, the effects of the horizontal permeability, vertical permeability, thickness of the laminae, and the length of the matrix between fractures are studied.",0,0,3
Fracture,Fracture Network,"Liu, Xing; Jin, Yan; Lin, Botao",An efficient stimulated reservoir area (SRA) estimation method based on octree decomposition of microseismic events,Hydraulic fracturing; Microseismic monitoring; Stimulated reservoir volume; Stimulated reservoir area; Octree method; Monte Carlo method,FRACTURE; GEOMECHANICS; PROPAGATION; SYSTEMS; SHALE,"Fracture contact area is the critical factor determining post-treatment production after multi-stage hydraulic fracturing. At present, there are no effective methods for the estimation of the stimulated reservoir area (SRA) of the complex fracture network after stimulation. Conventional methods mostly focused on calculating stimulated reservoir volume (SRV) by using microseismic events directly or indirectly. However, since there is a large number of noise events in microseismic data that can't be removed completely, the SRV results often have huge errors and are inconsistent with practical well production. For this reason, we propose an efficient and robust SRA calculation method based on 3D octree decomposition. The method is able to effectively estimate SRA by generating a multi-level grid structure without reconstructing the fracture network. Through a large number of case simulations based on synthetic events generated by Monte Carlo method, it is found that our method could adapt to the estimation of SRA for different configurations. It could obtain reliable and robust results in the presence of noise events. Specifically, it is indicated that the maximum relative calculation error is less than 20% for mesoscale and large-scale fracture network. The error for small-scale fractures could be reduced below 30% combining with the error reduction approach put forward in this paper. The applicability of our method is also investigated through two horizontal well platforms. Compared with the conventional SRV method, it is found that SRA obtained by our method could better reflect the stimulation effects and is more consistent with real production. It could become a potential and effective index for stimulation evaluation and fracturing operation optimization.",0,0,1
Fracture,Fracture Network,"Fabbri, Heber A.; Cleto, Pedro R.; Gaiotto Jr, Aldo T.; Rodrigues, Eduardo A.; Maedo, Michael A.; Manzoli, Osvaldo L.",Modeling the closure behavior of natural fractures in porous media using high aspect ratio interface elements,Natural fractures; Fracture closure model; High aspect ratio interface elements; Hydro-mechanical analysis,FINITE-ELEMENT; FLUID-FLOW; LAND SUBSIDENCE; INTEGRATION SCHEME; CONTACT PROBLEMS; 2-PHASE FLOW; FORMULATION; APPROXIMATION; CONDUCTIVITY; PERMEABILITY,"Many reservoirs consist of fully saturated rock masses containing a very complex natural fracture network. In such cases a decrease in the fracture fluid pressure reduces its aperture due to an increase in the effective stresses. In order to tackle the influence of fracture permeability on the pressure field and fluid flow, this paper proposes a Discrete Fracture-Matrix (DFM) model based on the finite elements to simulate coupled flow and geomechanics in porous media containing fractures with known position and properties (e.g. DFN realizations and fracture networks interpreted from outcrops). The proposed model is based on the use of triangular finite elements with high aspect ratio (HAR) to explicitly represent the fractures. These HAR elements have been successfully used to deal with cracks in concrete structures, desiccation cracks in soils and hydraulic fracturing in geo-reservoirs. This work demonstrate that these HAR elements equipped with a simple continuum (stress-strain) constitutive contact model that mimics the discrete (stress-displacement) Barton-Bandis joint model are able to properly describe the closure behavior associated with natural fractures. The constitutive model is integrated by means of the IMPL-EX scheme, which is a robust and stable technique used to achieve faster convergence. Darcy's law establishes the relationship between the fluid flow and the pressure field, and a fully coupled hydro-mechanical formulation comprises the mathematical framework. The proposed approach is based on continuous mechanics concepts and the implementation is made at constitutive level, and therefore it is simple and easy to be included in any existing FE program. To show the efficiency and accuracy of the proposed model, three numerical examples are conducted in this work: (i) benchmarks involving a medium with a single natural fracture, (ii) three reservoirs with different discrete fracture networks, and (iii) a transient analysis of a reservoir under different fracture conditions, such that the behavior of a intact reservoir, a reservoir containing fractures with constant aperture, and a reservoir in which the fractures aperture depends on the stress state are compared in terms of pore pressure, displacement field and fluid loss. In the first example, the results obtained with the proposed methodology are validated against the Barton-Bandis model. The agreement between the results is very satisfactory. The analysis of the latter two cases show the Barton-Bandis contact model is able to reproduce the effects of fracture permeability on pressure field in the reservoir, showing the capacity of the model to reproduce the main trends associated with the closure of natural fractures.",0,0,1
Fracture,Fracture Network,"Zhang, Yanhui; Hoteit, Ibrahim; Katterbauer, Klemens; Maucec, Marko; Marsala, Alberto F.",Feature-based ensemble history matching in a fractured carbonate reservoir using time-lapse deep electromagnetic tomography,History matching; Ensemble methods; Adaptive localization; Distance parameterization; Fractured carbonate reservoir; EM tomography,DISTANCE PARAMETERIZATION; FIELD MODEL; ASSIMILATION; FRAMEWORK,"Carbonate reservoirs typically exhibit very complex geological structures and are characterized by flow dynamics primarily occurring in fractures. The intricate network of fractures as well as their interconnectedness may lead to unexpected flow patterns and uneven sweep efficiency. Determining reservoir properties of both matrix and fracture channels is quintessential for accurately tracking the fluid front movement in the reservoir, optimizing sweep efficiency, and maximizing hydrocarbon production. In this study, we showcase the application of a feature-oriented ensemble-based history matching workflow to a complex fractured carbonate reservoir box model, focusing on the use of formation resistivity tomography data that are usually inferred from deep crosswell electromagnetic (EM) surveys. Compared with the production data that are commonly used in history matching, deep EM measurements provide additional information about the spatial distribution of subsurface reservoir properties in the interwell volumes by exploiting the strong resistivity contrast between water and hydrocarbons. A hybrid parameterization approach is used to represent the multiscale fracture distribution in which the spatial distribution of small-scale fractures is modelled by a truncated Gaussian simulation method. A large number (over one million) of uncertain model parameters including reservoir matrix and fracture properties as well as Archie's parameters are identified and updated by an iterative ensemble smoother. For an efficient integration of the high-dimensional and noisy EM tomography data, the boundary or contour information extracted from the EM resistivity field is instead assimilated through a distance parameterization approach. A modified bootstrapbased localization is proposed to regularize the model updates adaptively during the iteration to reduce sampling errors. Especially, to improve the computational efficiency in dealing with the large dimensions of both data and model parameters, the localization is implemented in a projected low-dimensional data subspace. Experimental results demonstrate the applicability and efficiency of the developed workflow for reservoir history matching in more realistic model settings. The comparative case study also illustrates the significance of jointly incorporating multiple sources of data for better quantification of model uncertainty, and the great potential of deep EM data for enhancing the characterization of complex fractured carbonate reservoirs.",0,0,1
Fracture,Fracture Network,"Aoun, Ala Eddine; Soto, Ricardo; Rabiei, Minou; Rasouli, Vamegh; Khetib, Youcef; Irofti, Doina","Neural Network based Mechanical Earth Modelling (MEM): A case study in Hassi Messaoud Field, Algeria",Mechanical Earth model; Hassi Messaoud field; Hydraulic fracturing; Neural network,EMPIRICAL RELATIONS; PHYSICAL-PROPERTIES; STRENGTH; FAULT,"Accurate estimation of in-situ stresses is of great importance in the oil and gas industry from the exploration to the field development and production phases. The collected logs and mini-frac data in the last 15 years in the Hassi Messaoud Field (HMD), Algeria, shows that the reported state of stresses in this field is not consistent. This called for further studies to estimate more accurately the state of stresses, which more specifically will be used for the design of hydraulic fracturing at a later stage. This paper presents the results of the Mechanical Earth Model (MEM) constructed for the HMD field in Algeria. The results of the MEM, which is continuous logs of formations' elastic and strength properties, as well as the state of the in-situ stresses will be the direct input to the hydraulic fracture (HF) design. Hydraulic fracturing is the prime technique used in the field in order to enhance recovery from this tight sandstone reservoir. MEM is built beyond the conventional correlation with both a Generalized Linear Model (GLM), which serves as a simplified ""ground truth"" and three Artificial Neural Networks (ANN) layers: the first one is training mechanical properties from lab data, the second one trains shear and compressional sonic waves from acquired log data and the last one uses mini-frac data to calculate and train stress regimes from a poro-elastic model. The model is calibrated with the observed breakouts and fracturing data and a close agreement is observed. The work presented in this paper elaborates a detailed roadmap to accurately approximate and synthesize missing data using ANN's and extend it across the rest of the field to build, a 3D MEM. It is hoped that the results of this study can improve the HF operations in the field, which is currently reported to be not efficient.",0,0,1
Fracture,Fracture Network,"Kelishami, Shervin Bahramali Asadi; Mohebian, Reza; Salmian, Omidreza","A comprehensive perspective on pore connectivity and natural fracture analysis in Oligo-Miocene heterogeneous carbonates, southern Iran",Pore connectivity; Permeability; Fracture aperture; Artificial neural network (ANN); Porosity; Image log; Velocity deviation log (VDL),POROSITY; TECTONICS; LOG,"Ascertaining the pore connection criterion has always been a challenge for geoscientists. In the framework of this research, an attempt was made to study the pore connectivity in a heterogeneous carbonate rock by combining several techniques. Pore types and rock facies were investigated for 321 thin sections. The abundance of connected porosities, cementation type and intensity which significantly control the matrix pore connectivity were specified on thin sections and finally a connectivity log was extracted that showed an accurate result on poroperm cross-plots. Most of the porosity volumes were related to interparticle, vuggy and moldic porosities which are microscale. The velocity deviation log, estimated in four wells, indicates the presence of micro porosity, which is consistent with the results of thin-sections. Zero velocity deviation is usually associated with the predominant presence of micro-pores. Different permeability values in identical lithological facies, as well as micro-fracture markers, prompted us to conduct more extensive research on fractures. FMI analysis proved that the studied reservoir is intensively fractured. The recorded high permeability in a sample with low matrix connectivity is specifically a fracture indication. Fracture apertures vary from microscale (<50 mu m) to 12.5 mm and calculated fracture density is raised up to 2 fractures per meter. Determined fractured intervals are very consistent with mud-loss information, for instance, a complete loss has been reported in the fault zone identified in well B. The detected fractures somewhat follow the main Zagros fault trend (NW-SE). Eventually, calculated connectivity was predicted in other wells using Artificial Neural Network (ANN) and a 3D model was constructed with respect to seismic attributes which gives a precise perspective of pore connection distribution throughout the studied field.",0,0,2
Fracture,Fracture Network,"Birkle, Peter; Makechnie, Glenn K.",Geochemical cycle of hydraulic fracturing fluids: Implications for fracture functionality and frac job efficiency in tight sandstone,Hydraulic fracturing; Geochemical fingerprinting; Recovery load; Flowback efficiency; Fracture type,NORTHERN APPALACHIAN BASIN; WATER; EVOLUTION; GAS; RESERVOIR; ORIGIN; WELLS; FIELD; SHALE; GULF,"The efficiency of the hydraulic fracturing processes is measured through its success rate in opening fracture space, fracturing fluid injectivity, and recovery rates of flowback fluid. This paper applies the volumetric ratio (R FF/Fw ) between recovered hydraulic fracturing fluid (FF) and formation water (FW) - besides gas production (GP) and flowback efficiency (FE) - as a third criterion and novel classification tool to quantify the loss of fracturing fluids, the inflow of formation water, and to define the type of involved fractures during hydraulic fracturing. Eight scenarios were designed to assess the performance and success rate of hydraulic fracking operations. For model calibration, geochemical time trends of flowback fluids from two horizontal wells were compared with the known composition of injected FF and local FW to quantify mixing ratios (R FF/Fw ) between both fluid types in produced water. The use of Na and Cl concentrations as nonreactive elements resulted in the most precise solution for endmember calculations. For the cased-hole scenario (C-1), low values of most operational parameters (gas recovery, injected fracturing fluid, recovered flowback volume, and FE of 0.37) reflect tight reservoir conditions with limited conductive capacity of induced fractures in the target zone. The elevated RFF/Fw ratio (2.65) and dominant FF return during the first day of flowback suggest that injected fracturing fluids either remained close to the sealed borehole and returned immediately to surface during post-fracture production or were lost to the formation due to unconnected hydraulic fractures. In contrast, a complex fracture system at the open-hole completion (O-1) allowed the release of gas from micropores, reflected by relatively elevated ratios of 0.5 for FE and low RFF/Fw ratios of 1.09. The interconnectivity between natural and induced fractures permitted the injection of larger volumes of FF with an elevated flowback of both fracturing fluid and formation water. A portion of 26% of the injected FF was recovered from well O-1 during a flowback period of 41 days, while an identical percentage was reached at well C-1 during 10 days. It is of practical importance for fracking operations that geochemical fingerprinting of flowback water can provide strategic decisions to optimize fracturing project performance beyond the capabilities of petrophysical data from well logging. In the present case, similar permeability and porosity characteristics for both targeted elastic intervals could not explain the contrasting performance of both frac jobs. Geochemical assessment can lead to avoiding water-pay zones to minimize the volume of required fracturing fluids for injection purposes, and to economize the recycling process for recoverable flowback fluids. An improved understanding of the functionality of the structural network of natural and induced fractures by the present classification is applicable to predict the success rate for upcoming frac jobs.",0,0,2
Fracture,Fracture Network,"Gao, Reyu; Li, Jun; Yang, Hongwei; Lian, Wei; Wang, Wei",A novel approach to investigating the mechanism of permeability-induced borehole breathing in deepwater shallow formations,Borehole breathing; Deep-water shallow formation; The mechanism of permeability-induced; Mud loss,BEHAVIOR; STRESS,"Due to the uniqueness of deep-water shallow formations, there is no fracture system around the wellbore when borehole breathing is observed in this part of the formation. Therefore, the inducing mechanism of the opening/closing of the fracture network cannot reasonably explain this type of borehole breathing. In this study, a new mechanism of permeability-induced is proposed to explain borehole breathing, based on the fact that there is no fracture system around the well and the formation has the characteristics of high permeability and porosity. By using the stress and seepage coupling method in the porous elastic medium, a new model is established to simulate and describe permeability-induced borehole breathing. Through comparison with actual cases, this model can effectively simulate the typical characteristics of fluid loss-flow back in borehole breathing. This study also analyzed the influence of factors such as formation parameters and mud rheological parameters on the borehole breathing caused by permeability. According to the results of the study, the use of a smaller diameter wellbore and agents that can adjust related parameters (such as loss-reducing circulating material) can effectively inhibit wellbore breathing while drilling.",0,0,2
Fracture,Fracture Network,"Zhang, Yabing; Liu, Xinrui; Guo, Pengshuang; Jia, Peng; Yang, Tianhong; Ren, Fengyu",Quantifying strength and permeability of fractured rock mass using 3D bonded block numerical model,Bonded block model; Rock mass strength; Permeability; Fracture network; Hoek-Brown criterion,DEFORMABILITY,"In this research, a 3D bonded block model (BBM) is applied to numerically quantify the strength and permeability of fractured rock mass. The reliability of the BBM is initially verified through comparisons between conceptual models and theoretical and laboratory results. A series of rock mass models incorporating complex fracture networks is then constructed, and the strengths are quantified accordingly. The rock mass is weakened when low fracture stiffness and friction angle are assigned, and steep fractures are simulated. In both cases the low strength is attributed to the decreasing frictional resistance of the initial fractures. The rock mass is further weakened when more persistent fractures are simulated, in which the weakening effects of the fractures are amplified. The numerical models are compared with the widely used Hoek-Brown strength criterion. The strengths resulting from the two methods converge only when steep and less persistent fractures are simulated. Numerical simulations also suggest that in general, the permeability is positively related to the strength for rock masses that are impermeable in the pre-peak loading stage. In such cases additional flow paths are formed and attributed to failed rock bridges. The research works provide new options to quantify the strength and permeability of fractured rock mass, and offer opportunities to examine relations between these parameters.",0,0,3
Fracture,Fracture Network,"Xu, Jiaxiang; Gao, Rui; Yang, Lifeng; Liu, Zhe; Ding, Yunhong; Wang, Zhen; Mo, Shaoyuan",A 3D tortuous fracture network construction approach to analyze proppant distribution in post-fractured shale,Shale formation; Tortuous fracture network; Proppants transport; Particle tracing,ROUGHNESS; DIMENSION; PROFILES,"To reveal the proppant transport in the tortuous fracture network, a method introducing the normal distribution random function into the quartet structure generation set was proposed to construct the three-dimensional tortuous fracture networks. The tortuosity can be controlled by the variance of random function. And then, the proppant distribution in the tortuous fracture network was simulated with the consideration of the interact between slurry, fracture surface and proppants. Finally, effects of velocity and viscosity of slurry and the density and particle size of proppants on the proppant distribution in three different fracture networks were investigated. The accuracy of this model was verified by the experiment. The simulation reveals that besides the velocity decrease due to the fluid split, the slurry velocity also fluctuates because of the fracture width variation. The transport distance of proppants in tortuous fracture is about 10.7% shorter than that in the smooth fracture, while the distribution height is increased in the tortuous fracture network. Instead of forming the regular sand dune, the proppant is dispersively distributed in the tortuous fracture network. The proppant density and the slurry velocity are the main factors influencing the proppant distribution, followed by the slurry viscosity and proppant size. Proppant with smaller particle size can enter the area with narrow fracture width, so that the distribution of proppant in the fracture is more uniform. The research results can provide some guidance for the optimal design of slurry and pumping schedule in the hydaulic fracturing operation.",0,0,3
Fracture,Fracture Network,"Wang, Qiong; Jiang, Ruizhong; Leng, Jie; Liu, Xiuwei",The effect of the viscosity-dependent boundary layer on tight oil flow behavior in CO2 Huff-Puff processes: A unified dimensional Pre-Darcy flow model,Pre-Darcy flow; Compositional simulation; CO2 EOR,N-PUFF; RESERVOIR SIMULATION; NUMERICAL-SIMULATION; FRACTURE NETWORKS; RECOVERY; SHALE,"There are numerous percolation studies of unconventional reservoirs showing that in tight or low-permeability formations, the oil flow behavior could be described by the Pre-Darcy mechanism. However, for the CO2 Huff-nPuff operations, the most presented low-velocity Pre-Darcy flow models may result in an erroneous evaluation due to the intensive boundary layer thickness changes caused by the CO2 extraction and dissolution. In this paper, with multiple parameters fitting the seepage experimental results of the studied area, a unified dimensional Pre-Darcy flow model for CO2 enhanced oil recovery (EOR) is derived from the classic Poiseuille model. Then, the proposed flow model is applied in the compositional simulator for analyzing the viscosity-dependent boundary layer (VDBL) effect, applicability evaluation in Huff-Puff EOR, and field history matching. The results indicate that the VDBL effect improves the oil mobility in injection periods and lowers the residual oil saturation at the front of the CO2 convection-diffusion area in reproduction periods. Additionally, the nonlinear parameter alpha and the shape parameter beta enhance the proposed model's applicability for the Huff process and the Puff process respectively. Finally, by adjusting the parameters alpha and beta for different permeability intervals of the geological model, the flow model is successfully applied in the oil production matching of the Y6 well, which exhibits its reliability in the history matching.",0,0,3
Fracture,Shale Gas,"Porlles, Jerjes; Panja, Palash; Sorkhabi, Rasoul; McLennan, John",Integrated porosity methods for estimation of gas-in-place in the Muerto Formation of Northwestern Peru,Muerto formation; Peru; Lancones and Talara Basins; Shale porosity; Kerogen porosity; Gas-in-place; Reservoir Model,SHALE,"The Albian-age Muerto formation in the Talara and Lancones basins of Northwestern Peru is a world-class source rock with high organic carbon (up to 4%, kerogen type III) and thermal maturity for the generation of both oil and gas as constrained by geochemical data presented here. We used wireline logs from one well in the Lancones basin in conjunction with geochemical data to model a multi-porosity model for the Muerto shaly carbonates. Our porosity model suggests total porosity 10.8% (from neutron and density logs), matrix porosity 10.3% (from the sonic log) of which inorganic porosity is 7.96% and kerogen (organic) porosity is 2.02%. Fracture porosity was found to be negligible (0.5%). The study thus incorporates porosities storing both free and adsorbed gas in this self-sourced reservoir. Moreover, the paper offers an integrated volumetric and reservoir modeling for estimation of gas-in-place (GIP) in the studied interval of the Muerto formation. The calculated GIP, including adsorbed gas is 660.2 MSCF/(acre-ft). This is the first application of a multi-porosity model for an unconventional gas reservoir in Peru, thus offering a methodology for porosity modeling of other unconventional tight reservoirs in Peru where petroleum plays have been relatively underdeveloped. Our study mainly aims to quantify different porosities that control the estimation of total GIP in tight rock formations.",0,0,0
Fracture,Shale Gas,"Gu, Yue; Gao, Deli; Diao, Binbin; Yang, Jin; Nie, Shuaishuai",Optimization design method of infill well trajectory with bypassing obstacles in the fractured area of shale gas reservoir,Shale gas infill well; Bypassing obstacles; Fractrued area; Vector algebra method; Optimization model,,"In the design of infill well trajectory in fractured area of shale gas reservoir, it is necessary to consider the problem how to bypass the fractured influence area of the old shale gas wells, as well as the problem of mutual interference between the different fractured sections during production. In this paper, the geometric model of the obstacles in fractured area of shale gas reservoir, which considers the trajectory error and fracturing effect, is established by vector algebra method. The trajectory type is classified according to positional relations among the obstacle, the directional line of initial point and target point. The trajectory optimization model for bypassing obstacles takes the minimum total well length as objective function, the safety distance to obstacle as one of the constraints. In addition, the geometric check method for judging whether there is interference between the different fractured sections is proposed based on the geometric obstacle model. Case studies have been carried out according to the field data from Fuling, and the results indicate that the trajectory optimization model in this paper can obtain the optimum trajectory to meet the needs for bypassing obstacle, minimum trajectory length and avoiding trial calculation. Besides, if the fracturing effect is ignored, the size of the obstacle will be significantly underestimated in fractured area of shale gas reservoir, which will result in drilling accidents. In sum, the obstacle model in this paper is more consistent with the situation of field fractured area drilling practice than that of the published model. This study will provide a more safer and briefer design method for optimizing the infill well trajectory in fractured area of shale gas reservoir, which is of great significance to the shale gas drilling design and drilling safety.",0,0,1
Fracture,Shale Gas,"Mackey, Justin; Gardiner, James; Kutchko, Barbara; Brandi, Meghan; Fazio, James; Hakala, J. Alexandra",Characterizing mineralization on low carbon steel exposed to aerated and degassed synthetic hydraulic fracture fluids,Hydraulic fracturing fluids; Oilfield mineral scale; Unconventional resources; Well integrity; Barite; Corrosion,BARITE SCALE FORMATION; MARCELLUS SHALE; CORROSION; WATER; IRON; OIL; CHLORIDE; INHIBITION; OXIDATION; INSIGHTS,This study investigates the mineralization occurring at the interface between injected hydraulic fracturing fluids and steel production casing during the shut-in period of unconventional shale wells. Mild steel coupons were reacted with synthetic hydraulic fracturing fluids with varying base fluid and dissolved gas concentrations. Experiments were carried out in an autoclave system set at 50 ?C and 2000 PSI for 2 and 14 days. Physical and mineralogical changes to the steel coupons? surface were characterized using an FEI Quanta 600 field emission gun (FEG) scanning electron microscope (SEM) and a PANalytical XPert Pro diffractometer. Barite precipitation occurred ubiquitously during the first 48 h in all experimental scenarios. Sulfate radicals created from degradation and reduction of ammonium persulfate breakers facilitate barite formation. Concomitant barite and corrosion related precipitates on the sample surfaces suggest iron hydroxy salts act as nucleation sites for mineral scale growth. These results suggest hydraulic fracturing fluids may have deleterious effects on the wellbore before production of the well begins.,0,0,1
Fracture,Shale Gas,"Zhao, Gang; Ding, Wenlong; Tian, Jing; Liu, Jingshou; Gu, Yang; Shi, Siyu; Wang, Ruyue; Sun, Ning","Spearman rank correlations analysis of the elemental, mineral concentrations, and mechanical parameters of the Lower Cambrian Niutitang shale: A case study in the Fenggang block, Northeast Guizhou Province, South China",Elemental and mineral concentrations; Mechanical parameters; Spearman rank correlation analysis; Brittleness index; Niutitang Formation shale,CENGONG BLOCK; DEVELOPMENTAL CHARACTERISTICS; DOMINANT FACTORS; GAS EXPLORATION; MARINE SHALE; RESERVOIRS; FRACTURES; SEDIMENTARY; TECHNOLOGY; PREDICTION,"The increasing complexity of reservoirs, particularly shale reservoirs, demands accurate information on the formation composition, mineralogy, and mechanical parameters for effective exploitation. The development of geochemical and geophysical logging technology allows the investigation of the correlations between the elemental, mineral contents, and the mechanical parameters of shale. Taking the Lower Cambrian Niutitang Formation shale in the Fenggang block in northeastern Guizhou as an example, 889 data sets of the main elemental (Si, Ca, Fe, 5, Ti, Gd, K, Mg, and S) concentrations and minerals (carbonate, pyrite, clay, quartz, feldspar, and mica) from Elemental Capture Spectroscopy logging and rock mechanics parameters (dynamic Young's modulus, dynamic Poisson's ratio, shear modulus, bulk modulus, and brittleness index) determined via Sonic Scanner logging data in the target zone of the study area are collected. We investigated the relationships between the mechanical parameters and the elemental, and mineral concentrations by Spearman rank correlation analysis. The influence of different Si concentrations on the mechanical parameters of the rock (positive/ negative, and significance) is discussed based on the mineral contents determined via X-ray diffraction of 24 experimental samples. When 22.1% < DWSi (dry weight fraction of the silicon content as a percent) < 28.40% and 28.40% < DWSi <34.20%, the static Young's modulus, shear modulus, bulk modulus, and brittleness index exhibit a highly positive/negative correlation that is significant with the increase/decrease in DWSi, WCLA (dry weight fraction of clay), and WQFM (dry weight fraction of quartz, feldspar, and mica) contents, respectively. DWSi = 28.4% is suggested as the turning point for the correlation change (positive/negative, significance). Thus, there exists uncertainty in the determination of the mechanical parameters of rock within certain elemental content ranges. More mathematical models and factors need to be considered to adequately characterize the mechanical parameters of rock.",0,0,1
Fracture,Shale Gas,"Verdugo, Martin; Doster, Florian",Impact of capillary pressure and flowback design on the clean up and productivity of hydraulically fractured tight gas wells,Flowback; Tight gas; Capillary pressure; Well performance; Rate transient analysis,WATER-USE; SHALE,"This work analyses the impact of capillary pressure and flowback operational variables on hydraulically fractured tight gas wells with the objective of understanding the clean-up process at reservoir level and its impact on future well performance. Through numerical reservoir simulation, different scenarios were investigated, varying capillary pressure, flowback duration, shut-in duration and drawdown. These scenarios are interpreted with rate transient analysis. The results of this work show the ambivalent effect of capillary pressure in terms of facilitating imbibition but also holding back water close to the fracture. The novelty of this work consists in the findings that for lower capillary pressures, short shut-in periods lead to a better well productivity while for higher capillary pressure extended shut-in periods are better for well productivity. It was also found that drawdown can be used to minimize fracture face relative permeability damage and as shut-in period extends, flowback should be performed at smaller drawdowns.",0,0,1
Fracture,Shale Gas,"Du, Xin; Li, Qingyu; Xian, Yuxi; Lu, Detang",Fully implicit and fully coupled numerical scheme for discrete fracture modeling of shale gas flow in deformable rock,Shale gas; Discrete fracture model; Rock deformation; Explicit method; Implicit method,PERMEABILITY; SIMULATION; STRESS; STRAIN,"Shale gas reservoirs contribute significantly to hydrocarbon production because of their abundant reserves. Shale formation is characterized by low permeability and extremely low porosity. Horizontal well drilling and hydraulic fracturing treatments are typical methods for stimulating the shale gas reservoirs. The discrete fracture model has been widely used to describe flow problems in fractured media. Rock deformation is an important process that occurs simultaneously with the gas flow during the production period and cannot be neglected when modeling the gas flow in shale formations. The matrix permeability, matrix porosity, fracture permeability, and fracture aperture are all considered pressure-dependent parameters when accounting for rock deformation. Two inadequacies exist in previous studies on modeling shale gas flow in deformable rock. One is determining the values of pressure-dependent parameters using an explicit method, which means that the pressure-dependent parameters in the next time step are calculated according to the pore pressure of the last time step and remain constant in the iterative solving process of the next time step. During the production, the pore pressure always decreasing, which leads to compression in fractures and a reduction in the fracture permeability and aperture. The explicit method inevitably causes an overestimation of the reservoir productivity. Another inadequacy is neglecting the effect of the change in fracture geometry. In this paper, a fully implicit and fully coupled numerical scheme for discrete fracture modeling of shale gas flow in deformable rock is proposed to reduce the computational error. A comparison between the results of no rock deformation, an explicit method, and implicit method and a field example are presented to calibrate the accuracy of proposed scheme. Another comparison between the explicit and implicit methods shows that the implicit method can noticeably reduce the overestimation caused by the explicit method. The effects of the controlling parameters on the relative difference between the explicit and implicit methods are demonstrated. The results show that the initial permeability of the hydraulic fracture has negligible influence on the relative difference. The initial permeability and compression coefficient of the natural fracture are the main influencing parameters, the initial matrix permeability has a limited impact on the relative difference. The relative difference is caused by the comprehensive effect of kij and (A/d)ij terms.",0,0,1
Fracture,Shale Gas,"Birkle, Peter; Makechnie, Glenn K.",Geochemical cycle of hydraulic fracturing fluids: Implications for fracture functionality and frac job efficiency in tight sandstone,Hydraulic fracturing; Geochemical fingerprinting; Recovery load; Flowback efficiency; Fracture type,NORTHERN APPALACHIAN BASIN; WATER; EVOLUTION; GAS; RESERVOIR; ORIGIN; WELLS; FIELD; SHALE; GULF,"The efficiency of the hydraulic fracturing processes is measured through its success rate in opening fracture space, fracturing fluid injectivity, and recovery rates of flowback fluid. This paper applies the volumetric ratio (R FF/Fw ) between recovered hydraulic fracturing fluid (FF) and formation water (FW) - besides gas production (GP) and flowback efficiency (FE) - as a third criterion and novel classification tool to quantify the loss of fracturing fluids, the inflow of formation water, and to define the type of involved fractures during hydraulic fracturing. Eight scenarios were designed to assess the performance and success rate of hydraulic fracking operations. For model calibration, geochemical time trends of flowback fluids from two horizontal wells were compared with the known composition of injected FF and local FW to quantify mixing ratios (R FF/Fw ) between both fluid types in produced water. The use of Na and Cl concentrations as nonreactive elements resulted in the most precise solution for endmember calculations. For the cased-hole scenario (C-1), low values of most operational parameters (gas recovery, injected fracturing fluid, recovered flowback volume, and FE of 0.37) reflect tight reservoir conditions with limited conductive capacity of induced fractures in the target zone. The elevated RFF/Fw ratio (2.65) and dominant FF return during the first day of flowback suggest that injected fracturing fluids either remained close to the sealed borehole and returned immediately to surface during post-fracture production or were lost to the formation due to unconnected hydraulic fractures. In contrast, a complex fracture system at the open-hole completion (O-1) allowed the release of gas from micropores, reflected by relatively elevated ratios of 0.5 for FE and low RFF/Fw ratios of 1.09. The interconnectivity between natural and induced fractures permitted the injection of larger volumes of FF with an elevated flowback of both fracturing fluid and formation water. A portion of 26% of the injected FF was recovered from well O-1 during a flowback period of 41 days, while an identical percentage was reached at well C-1 during 10 days. It is of practical importance for fracking operations that geochemical fingerprinting of flowback water can provide strategic decisions to optimize fracturing project performance beyond the capabilities of petrophysical data from well logging. In the present case, similar permeability and porosity characteristics for both targeted elastic intervals could not explain the contrasting performance of both frac jobs. Geochemical assessment can lead to avoiding water-pay zones to minimize the volume of required fracturing fluids for injection purposes, and to economize the recycling process for recoverable flowback fluids. An improved understanding of the functionality of the structural network of natural and induced fractures by the present classification is applicable to predict the success rate for upcoming frac jobs.",0,0,2
Fracture,Shale Gas,"Mohammed, Shaibu; Anumah, Prosper; Sarkodie-kyeremeh, Justice; Acheaw, Emmanuel",A production-based model for a fractured well in unconventional reservoirs,Unconventional reservoirs; Fractured-well performance; Production-based model; Reserve estimate; P90; P50 and P10 estimates; Barnett shale,RATE-DECLINE ANALYSIS; GAS; DIFFUSION; BARNETT,"Due to the depletion of conventional reservoirs and the high demand of energy, unconventional reservoirs will be relied on to supply the world's energy for the foreseeable future. Unfortunately, because of their complex storage and flow mechanisms, modelling and analysis of unconventional reservoirs have been very challenging. Although semi-analytical and numerical models have been proposed, these models rely on somewhat simplifying assumptions and require several input parameters. In this paper, a production-based model is proposed to analyze and predict a fractured-well performance in unconventional reservoirs (specifically, tight and shale reservoirs). The model assumes a power law with a stretched exponential cut-off. While the power-law term governs the transient-state period, the stretched exponential term, which is a superposition of exponential decays, governs the boundary-dominated flow period. As a result, the model is capable of matching both the transient state and boundary-dominated flow portions of the data. The model has been validated with a numerical data and applied to several field data. Results of the model have been compared with other existing models. The findings show that the proposed model yields relatively good estimates, and matches both the transient and boundary-dominated flow periods. The proposed model may contribute to the ongoing efforts to improve the analysis and forecasting of fractured-well performance in unconventional reservoirs.",0,0,2
Fracture,Shale Gas,"Male, Frank; Duncan, Ian J.",The paradox of increasing initial oil production but faster decline rates in fracking the Bakken Shale: Implications for long term productivity of tight oil plays,Energy forecasting; Unconventional oil; Hydraulic fracturing,WATER; GAS,"In the US, tight oil is the largest source of liquid hydrocarbons and has enabled the country to become the world's largest oil producer. The estimated ultimate recovery (EUR) and rate of production decline are key metrics in the evaluation of the future productivity of tight oil wells. We chose the Bakken Shale because of its high quality, publicly available data. Traditionally, well operators have estimated the EUR for each well from the initial production (IP), using empirical type curves to extrapolate to the ultimate production. From 2015 to 2018 the IP of the average Bakken well increased by approximately 50%. This increase resulted in claims by operators and in the academic literature that more intense hydraulic fracturing was increasing the average EUR of the Bakken play. At the same time, other observers claimed the wells declined much more rapidly than previous wells. This faster decline provided evidence for lower ultimate production from newer wells. The aim of this study was to understand the origin of these seemingly conflicting observations. A physics-based, scaling model was used to predict production from horizontal multi-stage fractured wells. The model for oil recovery is based on pressure diffusion through fractured porous media. The model assumes that the rock is incompressible, the permeability and oil saturation are constant, the water is incompressible, and the viscosity is slowly varying with space. The scaling model was applied to 13,444 wells. The EUR and terminal decline rate (TDR) were estimated from fitting production to our scaling model. Our study found that implementation of more intensive hydraulic fracturing resulted in higher IP and steeper terminal-production declines. Recently published results estimating the total production from the Bakken that include increased lifetime production commensurate with observed increases in average IP, significantly overestimate the long-term production potential of tight oil, both in the US and globally.",0,0,3
Fracture,Shale Gas,"Shilov, Evgeny; Dorhjie, Desmond Batsa; Mukhina, Elena; Zvada, Maya; Kasyanenko, Anton; Cheremisin, Alexey",Experimental and numerical studies of rich gas Huff-n-Puff injection in tight formation,Associated gas EOR; Huff-n-Puff; Tight oil reservoirs; Minimum miscibility pressure; Gas diffusivity,ENHANCED-OIL-RECOVERY; SHALE PLUGS; PERFORMANCE; SIMULATION,"Huff-n-Puff technology is considered one of the most effective methods to increase oil recovery in shale reservoirs. Previous works were mainly focused on Bakken and Eagle Ford shales. This paper is devoted to experimental and numerical studies of rich gas injection in core samples with high organic matter content from a tight oil reservoir in Russia. Eighteen core samples from different well intervals and different sizes were used in a Huff-n-Puff experimental study. Eight of the core samples were investigated at an injection pressure of 15 MPa, while ten core samples were studied at near-miscible pressure conditions of 30 MPa. The experiment results indicate that Huff-n-Puff injection of rich gas could give an oil recovery average of 63.03% and a maximum of 88.40% at 30 MPa injection pressure. A compositional model was created utilizing a commercial simulator and history matched to experimental results. The validated model was used to investigate the effect of molecular gas diffusivity, injection pressure, injection duration, shut-in duration, production duration, and other reservoir properties on the recovery factor. Sensitivity analysis by numerical modeling shows that the molecular gas diffusivity was critical in the history matching of the model. The numerical simulation results imply that the recovery factor could be increased by extending the injection period. In contrast, the duration of a soak period does not significantly influence the recovery factor. Furthermore, the recovery factor could be increased by extension of the production due to a slow decline in the pressure gradient between the matrix and fracture at the later stage of the production. The results of the present study imply that the application of the Huff-n-Puff injection of rich gas could increase oil recovery from tight reservoirs.",0,0,3
Fracture,Core Samples,"Kadyrov, Rail; Nurgaliev, Danis; Saenger, Erik H.; Balcewicz, Martin; Minebaev, Rezit; Statsenko, Evgeny; Glukhov, Mikhail; Nizamova, Aigul; Galiullin, Bulat",Digital rock physics: Defining the reservoir properties on drill cuttings,Cuttings; Core; Carbonates; Pore structure; Digital rock physics,TRANSPORT; CFD; PARAMETERS; PROGRAM; OIL,"Well drilling with core extraction is one of the most expensive procedures in the oil industry. The potential alternative, which may open opportunities for cost-efficient acquisition of petrophysical data, can be an approach based on digital analysis of drill cuttings. The main purpose of this research was to evaluate the possibility of using digital cuttings analysis and rock physics for reservoir properties evaluation. The carbonate samples of core and cuttings were simultaneously collected from the same intervals during the drilling of deviated wells in the Carboniferous reservoir of the oil deposit in the Republic of Tatarstan, Russia. Based on the core analysis using the optical study of thin sections and XRD, we investigated sedimentological and mineralogical features and classified all lithotypes of well intervals. The standard samples were produced from all defined facies and their reservoir properties were studied in routine tests. The largest cuttings from each well interval were separated and their structures were compared using mu CT with core subsamples of the same intervals. We assessed the changes of cuttings structure occurring in the drilling process, which include the colmatation of the pore space with drilling fluid and disintegrated rock particles and the formation of secondary fractures. Detailed analysis of cuttings from one well interval consisting of the border between the facies of high porous grainstones with packstones and dense micrite limestones demonstrated that high porous varieties were eroded in the drilling process. The analysis of chemical composition using XRF-mapping, XRD and SEM with EDS showed that most of the cuttings were constituted by disintegrated rock particles or form elements (e.g. separate fusulinids) cemented by drilling mud. However, more durable cuttings from dense micrite limestones facies were generally retained their dominant calcite composition and original rock structure, with only secondary fractures. Finally, we analyzed pore space properties and performed digital simulations of wave propagation velocities to compare the characteristics of these cuttings and core subsamples from this lithotype, scanned in the same mu CT settings. The results demonstrate close characteristics of porosity 0.08-0.6%, dominant pore sizes 1-60 mu m and velocities Vp = 6130-6240 m/s, Vs = 3180-3230 m/s. However, the comparison of obtained values with measured on standard samples shows a significant difference, which is caused by deviation from REV. The potential use of cuttings for assessing reservoir and petrophysical properties can be possible in case of provision with the factors of cuttings structure alteration, representativity of samples, as well as optimization for these purposes of the drilling process with cuttings selection.",0,0,1
Fracture,Core Samples,"Shaibu, Rashid; Guo, Boyun; Wortman, Philip B.; Lee, Jim",Stress-sensitivity of fracture conductivity of Tuscaloosa Marine Shale cores,Fracture conductivity; Tuscaloosa Marine Shale; Productivity; Shale; Proppant embedment,PROPPANT EMBEDMENT DEPTH; MECHANICAL-PROPERTIES; SHUT-IN; MODEL; WELL; PERMEABILITY; IMPACT,"Production decline from wells producing from shale rocks is typically quite rapid. One possible factor responsible for such decline is loss in fracture conductivity. This is true in the case of the Tuscaloosa Marine shale reservoir. In this work, the stress-dependent fracture conductivity of TMS core samples is investigated using five propped cores under varying stress conditions. In addition, the effects of static rock mechanical properties and rock mineralogy on conductivity decline are investigated. The mineralogy of each core sample was determined by Xray Diffraction analysis. Fracture conductivity was measured using a Hassler-type pressure core holder with a pressure rating of 15,000 psi (103.42 MPa). Estimated rock mechanical properties showed that shale anisotropy could affect fracture conductivity. The time decline in conductivity revealed two possible decline trends, a) decline from the reduction in induced fracture width, and b) decline from the healing of developed micro-cracks. An exponential decline in fracture conductivity with increasing confinement pressure was observed with an average decline rate constant of 3.15 x 10- 10 mPaxfffd; 1. While rock mineralogy did not have any clear relationship with conductivity decline, the effects of rock mechanical properties were only important at 10.34 MPa confinement pressure and above. The observation showed that a high Young's modulus correlate to high conductivity, whereas a high Poisson's ratio correlate to low conductivity. This study provides useful observations for optimizing fracture design to enhance well productivity in the TMS.",0,0,2
Fracture,Core Samples,"Velasco-Lozano, Moises; Balhoff, Matthew T.",Modeling of early- and late-time countercurrent spontaneous imbibition in porous media: A semi-analytical approach,Countercurrent spontaneous imbibition; Porous media; Oil recovery; Early-time solution; Late-time solution; Universal scaling,OIL-RECOVERY; WATER,"Countercurrent spontaneous imbibition (SI) is an important flow mechanism to recover oil in water-wet porous media through capillarity. Experimental imbibition tests conducted in core samples show that oil recovery as a function of time occurs in a characteristic S-shaped curve, which describes the infinite-acting and the boundary-dominated regime. Although several dimensionless time groups have been proposed to model countercurrent SI in porous media, they fail to properly scale the results, causing inaccurate estimates of oil recovery. In this work, we present a new approach, using a hybrid solution, to model countercurrent SI for oil-water systems dominated by capillary forces. The infinite-acting regime is modeled by an early-time solution using a new dimensionless time group, which enables the correct scaling of imbibition results onto a universal single curve. To model the boundary-dominated regime, we introduce a late-time solution derived as a function of a characteristic distribution of saturation to estimate the flow behavior after the imbibing fluid reaches the no-flow boundary. The novelty of the model is that it enables the accurate estimation of fluid imbibition under the boundary-dominated regime, a flow condition critical to evaluate the true potential of countercurrent SI driven by capillarity for oil recovery in porous media. We verified the model against numerical simulations under a wide range of flow conditions relevant in water-oil systems, and used experimental data reported in the literature to validate our model. The solution presented provides an accurate approach to model countercurrent SI, which could be extended for dynamic conditions and the modeling of the flow of fluids in fractured media.",0,0,2
Fracture,Core Samples,"Haagsma, Autumn; Scharenberg, Mackenzie; Keister, Laura; Schuetter, Jared; Gupta, Neeraj",Secondary porosity prediction in complex carbonate reefs using 3D CT scan image analysis and machine learning,Machine learning; Image analysis; CT scans; Carbonates; Secondary porosity,,"Development and preservation of carbonate porosity and permeability are critical to characterizing reservoirs. However, secondary porosity, such as vugs and fractures, are difficult to identify and require collection of expensive wireline tools or core sampling. Wireline logs and cores have traditionally been used to identify the presence of secondary porosity but fail to quantify the contribution to total reservoir porosity. Additionally, advanced wireline logs and core are not readily available for most wells. Dual energy CT scans were collected on whole core from the A-1 Carbonate and Brown Niagaran formations drawn from six wells in northern Michigan. 3D analysis techniques were applied to identify and isolate secondary porosity features. A series of machine learning and data analytics techniques were applied to the dataset to predict secondary porosity features on basic wireline logs. The predictive model successfully predicted secondary porosity with high confidence.",0,0,3
Fracture,Core Samples,"Shilov, Evgeny; Dorhjie, Desmond Batsa; Mukhina, Elena; Zvada, Maya; Kasyanenko, Anton; Cheremisin, Alexey",Experimental and numerical studies of rich gas Huff-n-Puff injection in tight formation,Associated gas EOR; Huff-n-Puff; Tight oil reservoirs; Minimum miscibility pressure; Gas diffusivity,ENHANCED-OIL-RECOVERY; SHALE PLUGS; PERFORMANCE; SIMULATION,"Huff-n-Puff technology is considered one of the most effective methods to increase oil recovery in shale reservoirs. Previous works were mainly focused on Bakken and Eagle Ford shales. This paper is devoted to experimental and numerical studies of rich gas injection in core samples with high organic matter content from a tight oil reservoir in Russia. Eighteen core samples from different well intervals and different sizes were used in a Huff-n-Puff experimental study. Eight of the core samples were investigated at an injection pressure of 15 MPa, while ten core samples were studied at near-miscible pressure conditions of 30 MPa. The experiment results indicate that Huff-n-Puff injection of rich gas could give an oil recovery average of 63.03% and a maximum of 88.40% at 30 MPa injection pressure. A compositional model was created utilizing a commercial simulator and history matched to experimental results. The validated model was used to investigate the effect of molecular gas diffusivity, injection pressure, injection duration, shut-in duration, production duration, and other reservoir properties on the recovery factor. Sensitivity analysis by numerical modeling shows that the molecular gas diffusivity was critical in the history matching of the model. The numerical simulation results imply that the recovery factor could be increased by extending the injection period. In contrast, the duration of a soak period does not significantly influence the recovery factor. Furthermore, the recovery factor could be increased by extension of the production due to a slow decline in the pressure gradient between the matrix and fracture at the later stage of the production. The results of the present study imply that the application of the Huff-n-Puff injection of rich gas could increase oil recovery from tight reservoirs.",0,0,3
Fracture,Function,"Costa, Beethoven G. dos S.; Jaculli, Marcelo A.; Mendes, Jose Ricardo P.; Colombo, Danilo",Evaluation of rock integrity during well drilling activities using reliability analysis,Well integrity; Rock reliability; Well safety; Kick tolerance,,"The main risk during the construction of oil wells is the possibility of uncontrolled hydrocarbon flow occurring from the well to the environment, commonly known as a blowout. After the Macondo accident, in the Gulf of Mexico, in 2010, there has been, in recent years, a significant increase in researches related to both well integrity and operational safety. A possible approach is to seek tools that can predict disastrous scenarios and support the decision making process. In this context, this work evaluates the reliability of the weakest rock in an open hole section, which is the formation immediately below the last settled casing shoe. Reliability, in this case, refers to the likelihood that the rock does not fracture during a possible kick or during drilling fluid circulation without a kick. The formulation of this problem involves addressing the inherent uncertainties, which may cause the failure of the ""rock"" barrier element. Modeling was performed by assigning probabilistic distributions to the parameters carrying uncertainties and by proposing two solutions. If all the uncertainties can be modeled using the normal distribution, it is possible to calculate the reliability analytically; meanwhile, if the variables are modeled using more than one type of distribution, an analytical solution may be hard to achieve and Monte Carlo simulations are preferred to obtain a numerical solution. The numerical solution does not require mean values and standard deviations of the output variables and becomes particularly useful when these characteristics are unknown. Therefore, this methodology evaluates the competence of the rock as a barrier element, enhancing operational safety and maintaining well integrity. The calculated reliability values can be used to assist in real-time drilling monitoring, from a rock integrity standpoint. The results of this methodology include the rock reliability as a function of the well depth, based on the current drilling phase. This includes the two aforementioned scenarios, with and without a kick.",0,0,0
Fracture,Function,"Kilicaslan, Ufuk; Akin, Serhat",Transient shape factors for dual-porosity simulation of tight rocks,Matrix-fracture transfer function; Tight reservoir; Unsteady-state flow,,"The shape-factor concept provides an elegant and powerful upscaling method for fractured reservoir simulation. Many different shape-factors, among which the well-known Warren and Root, and Kazemi shape-factors have been proposed in the past. Since different shape-factors can lead to totally different reservoir behavior, selection of the appropriate shape-factor value is critical for accurate fractured reservoir modeling. Constant shape factor is commonly used for simulation of fractured reservoirs by assuming that pressure transient reaches to center of the matrix block within very small time. On the contrary, tight rocks exhibit longer duration of unsteady-state flow such that matrix - fracture transfer is not constant, but rather varies with time until reaching to a constant value. In this regard, dual-porosity simulation of tight rocks using constant shape factor does not capture actual physics of matrix to fracture flow and yields inaccurate performance prediction. In this study, analytical solutions of pressure diffusion and corresponding shape factors are presented for various matrix shapes. The results are compared to those obtained with simple empirical functions. Proposed functions significantly improve accuracy over existing approaches in the prediction of both mean matrix pressure and transfer function. Results of fine grid single-porosity model are compared with two different dual porosity models, one with constant shape factor and one with time dependent shape factor, to verify proposed approach.",0,0,0
Fracture,Function,"Gu, Yue; Gao, Deli; Diao, Binbin; Yang, Jin; Nie, Shuaishuai",Optimization design method of infill well trajectory with bypassing obstacles in the fractured area of shale gas reservoir,Shale gas infill well; Bypassing obstacles; Fractrued area; Vector algebra method; Optimization model,,"In the design of infill well trajectory in fractured area of shale gas reservoir, it is necessary to consider the problem how to bypass the fractured influence area of the old shale gas wells, as well as the problem of mutual interference between the different fractured sections during production. In this paper, the geometric model of the obstacles in fractured area of shale gas reservoir, which considers the trajectory error and fracturing effect, is established by vector algebra method. The trajectory type is classified according to positional relations among the obstacle, the directional line of initial point and target point. The trajectory optimization model for bypassing obstacles takes the minimum total well length as objective function, the safety distance to obstacle as one of the constraints. In addition, the geometric check method for judging whether there is interference between the different fractured sections is proposed based on the geometric obstacle model. Case studies have been carried out according to the field data from Fuling, and the results indicate that the trajectory optimization model in this paper can obtain the optimum trajectory to meet the needs for bypassing obstacle, minimum trajectory length and avoiding trial calculation. Besides, if the fracturing effect is ignored, the size of the obstacle will be significantly underestimated in fractured area of shale gas reservoir, which will result in drilling accidents. In sum, the obstacle model in this paper is more consistent with the situation of field fractured area drilling practice than that of the published model. This study will provide a more safer and briefer design method for optimizing the infill well trajectory in fractured area of shale gas reservoir, which is of great significance to the shale gas drilling design and drilling safety.",0,0,1
Fracture,Function,"Velasco-Lozano, Moises; Balhoff, Matthew T.",Modeling of early- and late-time countercurrent spontaneous imbibition in porous media: A semi-analytical approach,Countercurrent spontaneous imbibition; Porous media; Oil recovery; Early-time solution; Late-time solution; Universal scaling,OIL-RECOVERY; WATER,"Countercurrent spontaneous imbibition (SI) is an important flow mechanism to recover oil in water-wet porous media through capillarity. Experimental imbibition tests conducted in core samples show that oil recovery as a function of time occurs in a characteristic S-shaped curve, which describes the infinite-acting and the boundary-dominated regime. Although several dimensionless time groups have been proposed to model countercurrent SI in porous media, they fail to properly scale the results, causing inaccurate estimates of oil recovery. In this work, we present a new approach, using a hybrid solution, to model countercurrent SI for oil-water systems dominated by capillary forces. The infinite-acting regime is modeled by an early-time solution using a new dimensionless time group, which enables the correct scaling of imbibition results onto a universal single curve. To model the boundary-dominated regime, we introduce a late-time solution derived as a function of a characteristic distribution of saturation to estimate the flow behavior after the imbibing fluid reaches the no-flow boundary. The novelty of the model is that it enables the accurate estimation of fluid imbibition under the boundary-dominated regime, a flow condition critical to evaluate the true potential of countercurrent SI driven by capillarity for oil recovery in porous media. We verified the model against numerical simulations under a wide range of flow conditions relevant in water-oil systems, and used experimental data reported in the literature to validate our model. The solution presented provides an accurate approach to model countercurrent SI, which could be extended for dynamic conditions and the modeling of the flow of fluids in fractured media.",0,0,2
Fracture,Function,"Xu, Jiaxiang; Gao, Rui; Yang, Lifeng; Liu, Zhe; Ding, Yunhong; Wang, Zhen; Mo, Shaoyuan",A 3D tortuous fracture network construction approach to analyze proppant distribution in post-fractured shale,Shale formation; Tortuous fracture network; Proppants transport; Particle tracing,ROUGHNESS; DIMENSION; PROFILES,"To reveal the proppant transport in the tortuous fracture network, a method introducing the normal distribution random function into the quartet structure generation set was proposed to construct the three-dimensional tortuous fracture networks. The tortuosity can be controlled by the variance of random function. And then, the proppant distribution in the tortuous fracture network was simulated with the consideration of the interact between slurry, fracture surface and proppants. Finally, effects of velocity and viscosity of slurry and the density and particle size of proppants on the proppant distribution in three different fracture networks were investigated. The accuracy of this model was verified by the experiment. The simulation reveals that besides the velocity decrease due to the fluid split, the slurry velocity also fluctuates because of the fracture width variation. The transport distance of proppants in tortuous fracture is about 10.7% shorter than that in the smooth fracture, while the distribution height is increased in the tortuous fracture network. Instead of forming the regular sand dune, the proppant is dispersively distributed in the tortuous fracture network. The proppant density and the slurry velocity are the main factors influencing the proppant distribution, followed by the slurry viscosity and proppant size. Proppant with smaller particle size can enter the area with narrow fracture width, so that the distribution of proppant in the fracture is more uniform. The research results can provide some guidance for the optimal design of slurry and pumping schedule in the hydaulic fracturing operation.",0,0,3
Fracture,Secondary,"Hasanzadeh, Maryam; Azin, Reza; Fatehi, Rouhollah; Zendehboudi, Sohrab",New insights into forced and free fall gravity drainage performance in a fractured physical model,Fractured physical model; Gas injection; Recovery factor; Free fall gravity drainage; Forced gravity drainage,TERTIARY OIL-RECOVERY; POROUS-MEDIA; WETTABILITY; DISPLACEMENT; SECONDARY; FLOW,"Gravity is one of the major driving forces for fluid flow in naturally fractured reservoirs. Gravity drainage appears to be a vital recovery mechanism over the oil production process in a majority of fractured reserves. In this paper, free-fall gravity drainage (FFGD) and forced gravity drainage (FGD) production approaches are investigated through employing a new fractured sand pack with a rectangular geometry. Distilled water and condensate are used as the wetting phase. Nitrogen, carbon dioxide, and air are also utilized as the non-wetting phase. A systematic sensitivity analysis is conducted to find the effects of the key factors such as fracture blockage, injection rate, dip angle, and type of wetting phase and injection fluid on the performance of FFGD and FGD processes. Also, a numerical simulation is performed to simulate the experiments. Results reveal that the FGD has a better performance under controlled process conditions, compared to the FFGD so that gas injection with a controlled rate improves the recovery. Moreover, it was found that increasing the gas injection rate improves the recovery factor (RF) of wetting-phase when the up and bottom sides of the fractures are blocked; the RF is decreased in the case with open fracture sides. The recovery of the wetting phase decreases in both FFGD and FGD modes when the porous system has a deviation from the vertical orientation. According to the study outcomes, the immiscible gas-assisted gravity drainage offers a higher condensate recovery, compared to water recovery, due to lower viscosity and interfacial tension (IFT) of the condensate phase. The comparison of the experimental data and simulation results implies that the simulation approach can satisfactorily predict the performance of the FGD process. Based on the error analysis, there is a good match between the simulation results and the experimental measurements; the fluid pair of CO2-condensate exhibits the highest accuracy with an R-squared of 0.9961 and an average relative error (ARE) of 0.0054.",0,0,0
Fracture,Secondary,"Kadyrov, Rail; Nurgaliev, Danis; Saenger, Erik H.; Balcewicz, Martin; Minebaev, Rezit; Statsenko, Evgeny; Glukhov, Mikhail; Nizamova, Aigul; Galiullin, Bulat",Digital rock physics: Defining the reservoir properties on drill cuttings,Cuttings; Core; Carbonates; Pore structure; Digital rock physics,TRANSPORT; CFD; PARAMETERS; PROGRAM; OIL,"Well drilling with core extraction is one of the most expensive procedures in the oil industry. The potential alternative, which may open opportunities for cost-efficient acquisition of petrophysical data, can be an approach based on digital analysis of drill cuttings. The main purpose of this research was to evaluate the possibility of using digital cuttings analysis and rock physics for reservoir properties evaluation. The carbonate samples of core and cuttings were simultaneously collected from the same intervals during the drilling of deviated wells in the Carboniferous reservoir of the oil deposit in the Republic of Tatarstan, Russia. Based on the core analysis using the optical study of thin sections and XRD, we investigated sedimentological and mineralogical features and classified all lithotypes of well intervals. The standard samples were produced from all defined facies and their reservoir properties were studied in routine tests. The largest cuttings from each well interval were separated and their structures were compared using mu CT with core subsamples of the same intervals. We assessed the changes of cuttings structure occurring in the drilling process, which include the colmatation of the pore space with drilling fluid and disintegrated rock particles and the formation of secondary fractures. Detailed analysis of cuttings from one well interval consisting of the border between the facies of high porous grainstones with packstones and dense micrite limestones demonstrated that high porous varieties were eroded in the drilling process. The analysis of chemical composition using XRF-mapping, XRD and SEM with EDS showed that most of the cuttings were constituted by disintegrated rock particles or form elements (e.g. separate fusulinids) cemented by drilling mud. However, more durable cuttings from dense micrite limestones facies were generally retained their dominant calcite composition and original rock structure, with only secondary fractures. Finally, we analyzed pore space properties and performed digital simulations of wave propagation velocities to compare the characteristics of these cuttings and core subsamples from this lithotype, scanned in the same mu CT settings. The results demonstrate close characteristics of porosity 0.08-0.6%, dominant pore sizes 1-60 mu m and velocities Vp = 6130-6240 m/s, Vs = 3180-3230 m/s. However, the comparison of obtained values with measured on standard samples shows a significant difference, which is caused by deviation from REV. The potential use of cuttings for assessing reservoir and petrophysical properties can be possible in case of provision with the factors of cuttings structure alteration, representativity of samples, as well as optimization for these purposes of the drilling process with cuttings selection.",0,0,1
Fracture,Secondary,"Di, Shiying; Cheng, Shiqing; Wei, Cao",Evaluation of fracture closure and its contribution to total production for a well with non-planar asymmetrical vertical fracture based on bottom-hole pressure,Pressure transient analysis; Fracture closure; Finite difference method; Double-segment non-planar asymmetrical fracture,NON-DARCY-FLOW; SEMIANALYTICAL SOLUTION; CONDUCTIVITY; LENGTH,"Hydraulic-fracturing is an important well-stimulation technique, the fracture closure is inevitable during production. The existing pressure transient analysis models either ignore the length of fracture-closure segment that causes the explained fracture half-length to be smaller, or only use the fracture conductivity to evaluate fracture closure. To fully evaluate fracture closure and provide a reference for oilfield engineers determining whether need measures to improve the well performance, meanwhile considering the non-planar asymmetrical fracture is common met in low-permeability reservoirs, this paper proposes to use two parameters (flowrate proportion and conductivity of fracture-closure segment) to comprehensively evaluate fracture closure, and hence develops double-segment non-planar asymmetrical fracture model (DPAFM). Planar asymmetrical fracture model is simplified case of proposed model. The semi-analytical solution is obtained by using finite difference method (FDM) and Gonzalez-Chavez and Cinco-Ley (2006) model is used to verify the solution. The results of this work show that (a) The example of actual well simulation proves the model is more suitable for the actual field data, and the model established is better matched than the saphir software; (b) The proposed model can obtain production proportion and conductivity of fracture-closure segment to comprehensively evaluate fracture closure; (c) There are four typical flow regimes for the DPAFM, including bilinear flow, interference linear flow, formation linear flow, pseudo-radial flow. The interference linear flow regime with 'V-shape' characteristic is unique; (d) Conventional explanation thinks the 'V-shape' characteristic represents the secondary fracture developed (e.g., OFFN, TLFN and MOFN). However, this paper gives another possibility that the 'V-shape' reflects fracture closure. The findings of this study can help for better understanding of illustrating the practicability of proposed methodology in evaluating the fracture closure and reservoir parameters. This research provides guidance for technicians to formulate the next step to increase production plan and helps the oilfield engineers determine whether take measures to improve the well performance.",0,0,2
Fracture,Secondary,"Haagsma, Autumn; Scharenberg, Mackenzie; Keister, Laura; Schuetter, Jared; Gupta, Neeraj",Secondary porosity prediction in complex carbonate reefs using 3D CT scan image analysis and machine learning,Machine learning; Image analysis; CT scans; Carbonates; Secondary porosity,,"Development and preservation of carbonate porosity and permeability are critical to characterizing reservoirs. However, secondary porosity, such as vugs and fractures, are difficult to identify and require collection of expensive wireline tools or core sampling. Wireline logs and cores have traditionally been used to identify the presence of secondary porosity but fail to quantify the contribution to total reservoir porosity. Additionally, advanced wireline logs and core are not readily available for most wells. Dual energy CT scans were collected on whole core from the A-1 Carbonate and Brown Niagaran formations drawn from six wells in northern Michigan. 3D analysis techniques were applied to identify and isolate secondary porosity features. A series of machine learning and data analytics techniques were applied to the dataset to predict secondary porosity features on basic wireline logs. The predictive model successfully predicted secondary porosity with high confidence.",0,0,3
Fracture,Fracture Closure,"Fabbri, Heber A.; Cleto, Pedro R.; Gaiotto Jr, Aldo T.; Rodrigues, Eduardo A.; Maedo, Michael A.; Manzoli, Osvaldo L.",Modeling the closure behavior of natural fractures in porous media using high aspect ratio interface elements,Natural fractures; Fracture closure model; High aspect ratio interface elements; Hydro-mechanical analysis,FINITE-ELEMENT; FLUID-FLOW; LAND SUBSIDENCE; INTEGRATION SCHEME; CONTACT PROBLEMS; 2-PHASE FLOW; FORMULATION; APPROXIMATION; CONDUCTIVITY; PERMEABILITY,"Many reservoirs consist of fully saturated rock masses containing a very complex natural fracture network. In such cases a decrease in the fracture fluid pressure reduces its aperture due to an increase in the effective stresses. In order to tackle the influence of fracture permeability on the pressure field and fluid flow, this paper proposes a Discrete Fracture-Matrix (DFM) model based on the finite elements to simulate coupled flow and geomechanics in porous media containing fractures with known position and properties (e.g. DFN realizations and fracture networks interpreted from outcrops). The proposed model is based on the use of triangular finite elements with high aspect ratio (HAR) to explicitly represent the fractures. These HAR elements have been successfully used to deal with cracks in concrete structures, desiccation cracks in soils and hydraulic fracturing in geo-reservoirs. This work demonstrate that these HAR elements equipped with a simple continuum (stress-strain) constitutive contact model that mimics the discrete (stress-displacement) Barton-Bandis joint model are able to properly describe the closure behavior associated with natural fractures. The constitutive model is integrated by means of the IMPL-EX scheme, which is a robust and stable technique used to achieve faster convergence. Darcy's law establishes the relationship between the fluid flow and the pressure field, and a fully coupled hydro-mechanical formulation comprises the mathematical framework. The proposed approach is based on continuous mechanics concepts and the implementation is made at constitutive level, and therefore it is simple and easy to be included in any existing FE program. To show the efficiency and accuracy of the proposed model, three numerical examples are conducted in this work: (i) benchmarks involving a medium with a single natural fracture, (ii) three reservoirs with different discrete fracture networks, and (iii) a transient analysis of a reservoir under different fracture conditions, such that the behavior of a intact reservoir, a reservoir containing fractures with constant aperture, and a reservoir in which the fractures aperture depends on the stress state are compared in terms of pore pressure, displacement field and fluid loss. In the first example, the results obtained with the proposed methodology are validated against the Barton-Bandis model. The agreement between the results is very satisfactory. The analysis of the latter two cases show the Barton-Bandis contact model is able to reproduce the effects of fracture permeability on pressure field in the reservoir, showing the capacity of the model to reproduce the main trends associated with the closure of natural fractures.",0,0,1
Fracture,Fracture Closure,"Guo, Yonggui; Mohamed, Ibrahim; Zidane, Ali; Panchal, Yashesh; Abou-Sayed, Omar; Abou-Sayed, Ahmed",Automated pressure transient analysis: A cloud-based approach,Pressure transient analysis; Cloud computing; ISIP; Flow regime; G-function; Web-based application,,"Pressure transient analysis provides essential information to evaluate the dimensions of injection induced fractures, permeability damage near the wellbore, and pressure elevation in the injection horizon. For injection wells, shut-in data can be collected and analyzed after each injection cycle to evaluate the well injectivity and predict the well longevity. However, any interactive analysis of the pressure data could be subjective and time-consuming. In this study a novel cloud-based approach to automatically analyzing pressure data is presented, which aims to improve the reliability and efficiency of pressure transient analysis. There are two fundamental requirements for automated pressure transient analysis: 1) Pressure data needs to be automatically retrieved from field sites and fed to the analyzer; 2) The engineer can automatically select instantaneous shut-in pressure (ISIP), identify flow regimes, and determine the fracture closure point if any. To meet these requirements as well as to take advantage of cloud storage and computing technologies, a web-based application has been developed to pull real time injection data from any field sites and push it to a cloud database. A built-in pressure transient workflow has been also proposed to detect any stored or real-time pressure data and perform pressure analysis automatically if the required data is available. The automated pressure transient analysis technology has been applied to multiple injection projects. In general, the analysis results including formation and fracture properties (i.e. permeability, fracture half length, skin factor, and fracture closure pressure) are comparable to results from interactive analysis. Any discrepancies are mainly caused by poor data quality. Issues such as inconsistent selections of ISIP and different slopes defined for pre and after closure analyses also contribute to the divergence. Overall, the automated pressure transient analysis provides consistent results as the exact same criteria are applied to the pressure data, and analysis results are independent of the analyzer's experience and knowledge. As data from oil/gas industry increases exponentially over time, automated data transmission, storage, analysis and access are becoming necessary to maximize the value of the data and reduce operation cost. The automated pressure transient analysis presented here demonstrates that cloud storage and computing combined with automated analysis tools is a viable way to overcome big data challenges faced by oil/gas industry professionals.",0,0,1
Fracture,Fracture Closure,"Di, Shiying; Cheng, Shiqing; Wei, Cao",Evaluation of fracture closure and its contribution to total production for a well with non-planar asymmetrical vertical fracture based on bottom-hole pressure,Pressure transient analysis; Fracture closure; Finite difference method; Double-segment non-planar asymmetrical fracture,NON-DARCY-FLOW; SEMIANALYTICAL SOLUTION; CONDUCTIVITY; LENGTH,"Hydraulic-fracturing is an important well-stimulation technique, the fracture closure is inevitable during production. The existing pressure transient analysis models either ignore the length of fracture-closure segment that causes the explained fracture half-length to be smaller, or only use the fracture conductivity to evaluate fracture closure. To fully evaluate fracture closure and provide a reference for oilfield engineers determining whether need measures to improve the well performance, meanwhile considering the non-planar asymmetrical fracture is common met in low-permeability reservoirs, this paper proposes to use two parameters (flowrate proportion and conductivity of fracture-closure segment) to comprehensively evaluate fracture closure, and hence develops double-segment non-planar asymmetrical fracture model (DPAFM). Planar asymmetrical fracture model is simplified case of proposed model. The semi-analytical solution is obtained by using finite difference method (FDM) and Gonzalez-Chavez and Cinco-Ley (2006) model is used to verify the solution. The results of this work show that (a) The example of actual well simulation proves the model is more suitable for the actual field data, and the model established is better matched than the saphir software; (b) The proposed model can obtain production proportion and conductivity of fracture-closure segment to comprehensively evaluate fracture closure; (c) There are four typical flow regimes for the DPAFM, including bilinear flow, interference linear flow, formation linear flow, pseudo-radial flow. The interference linear flow regime with 'V-shape' characteristic is unique; (d) Conventional explanation thinks the 'V-shape' characteristic represents the secondary fracture developed (e.g., OFFN, TLFN and MOFN). However, this paper gives another possibility that the 'V-shape' reflects fracture closure. The findings of this study can help for better understanding of illustrating the practicability of proposed methodology in evaluating the fracture closure and reservoir parameters. This research provides guidance for technicians to formulate the next step to increase production plan and helps the oilfield engineers determine whether take measures to improve the well performance.",0,0,2
Fracture,Salinity,"Abujayyab, Mohammed A.; Hamouda, Mohamed; Hassan, Ashraf Aly",Biological treatment of produced water: A comprehensive review and metadata analysis,COD removal; Salinity; Treatment scale; Treatment process; Oxygen availability,FIELD-PRODUCED WATER; GAS PRODUCED WATER; MIXED LIQUOR CHARACTERISTICS; HYPERSALINE PRODUCED WATER; OIL-PRODUCED WATER; WASTE-WATER; MEMBRANE BIOREACTOR; FRACTURING FLOWBACK; PERFORMANCE EVALUATION; CONSTRUCTED WETLAND,"A metadata analysis was conducted to analyze the impact of several operating conditions on the biological removal of chemical oxygen demand (COD) from produced water (PW). Operating conditions including temperature, salinity, oxygen availability, treatment technology, microorganism type, and treatment scale were investigated. No limiting maximum COD elimination capacity was reported in the literature, signaling the need to experiment with higher COD concentrations at reduced retention times to identify if such a limit exists. The maximum recorded COD elimination capacity of PW was achieved under low salinity and aerobic conditions in a membrane bioreactor using oil-degradation bacteria on a laboratory scale. Suspended growth exhibited maximum COD removal efficiency, and membrane bioreactors were the most studied technique and achieved the highest performance. Superior COD removal efficiency was realized under hypersaline conditions; however, the COD removal efficiency under freshwater conditions was higher than that under hypersaline conditions.",0,0,2
Fracture,Salinity,"Redekop, E. P.; Boronin, S. A.; Tolmacheva, K., I; Burukhin, A. A.; Osiptsov, A. A.; Belonogov, E., V","Effects of salinity and rock clogging on injectivity dynamics of flooding wells: Experiments, modeling and validation on field data",Low salinity flooding; Oil displacement; Formation damage; Pore clogging; Field data,FINES-MIGRATION; WETTABILITY ALTERATION; BRINE COMPOSITION; OIL-RECOVERY; WATER; FLOW; DISPLACEMENT,"Injection of water into a rock formation is a common oilfield services technology to maintain high reservoir pressure and increase ultimate recovery of hydrocarbons. While flowing through the well from surface to the rock formation, injected water typically transports fine particles, for example, fine sand grains and calcite precipitated at surface pipeline conditions while mixing water from different sources (e.g., fresh, Cenomanian and formation brine). In the framework of the two-fluid approach to suspension flow modelling, we formulate mathematical model for linear filtration of a particle-laden suspension in the vicinity of a fractured flooding well and transport of ion concentration (salinity). Two major factors of well injectivity decline are described, namely, particle trapping with associated reduction in permeability and porosity of the rock as well as the effect of salinity of injecting water leading to clay swelling, calcite precipitation and change of relative permeabilities of the rock with respect to water and oil. We calibrate suspension filtration model against in-house experiments on clogging of artificial and natural rock cores, in which the profiles of fines concentration along the cores are obtained using X-Ray computed tomography and analysis of 3D rock reconstruction images. The water injection model is adopted to conditions of Priobskoye oilfield of Western Siberia by using the results of standard laboratory experiments on fluid-fluid (calcite precipitation) and fluid-rock (clay swelling, migration of internal fines) compatibility, as well as the effect of salinity on oil displacement and analysis of solid fraction in the injecting water. The calibrated model is then used to describe field data on dynamics of injection rate of three flooding wells. It is obtained that the simulations predict the long-term injectivity dynamics of the wells very well, while at early times (up to 5 months from the start of injection) the model underestimates the injection rate. While fitting the model to field data, we varied only two parameters, namely, solids concentration in the injecting water (in the range provided by lab experiments) and trapping coefficient (the range is limited to result of experiments made with target rock cores). It is demonstrated that only a combination of injectivity decline factors allows to describe the long-term flooding rate of the wells. Ignoring either particle trapping or salinity effects lead to significant overestimation (up to 50%) of the long-term injection rate. Parametric study of water injection showed that two-fold increase in solids concentration in the injecting water as well as oil compressibility lead to similar decrease in long-term injection rate of a well.",0,0,2
Fracture,Salinity,"Ishii, Mikihito; Murata, Sumihiko; Ishitsuka, Kazuya; Lin, Weiren",Stability of novel cellulose-nanofiber-containing foam as environmentally friendly fracturing fluid,Foam stability; Cellulose nanofiber; Fracturing fluid; High pressure; High temperature; Salinity,CRITICAL MICELLE CONCENTRATION; TEMPO-MEDIATED OXIDATION; PROPPANT TRANSPORT; BEHAVIOR; FILMS; WATER; TEMPERATURE; MIXTURES; DRAINAGE; SHALE,"Foam-based fracturing is one of the waterless fracturing technologies that can reduce the environmental issues of water-based fracturing. To utilize foam as a fracturing fluid in oil/gas developments, improving foam stability is essential. To examine whether the environmentally friendly and low-cost cellulose nanofiber (CNF) can be a novel foam stabilizer, we investigated the effect of surfactant on the initial foam volume and stability of CNF-containing foam using four types of surfactants with different electrical properties. Then, we investigated the stability of CNF-containing foam under the high-pressure or high-temperature conditions as well as under the laboratory pressure and temperature condition and compared to the stability of foam containing sodium salt of CMC (NaCMC). In addition, we investigated the stability of CNF-containing foam under the presence of salts. As a result, it was concluded that the initial foam volume and stability of CNF-containing foam strongly depend on the type of surfactant because the CNF surface is negatively charged; the CNF is superior to NaCMC as a foam stabilizer, especially in the CNF concentration range above 0.10 wt%; the stability of CNF-containing foam decreases with increasing temperature and increases with increasing pressure, and it is significantly reduced with the addition of salt because the aggregation of the CNFs is formed due to the interaction between the salt cations and CNFs. Further research is expected to use CNF as a stabilizer for foam-based fracturing fluids as CNF is an attractive biomass substance as a foam stabilizer.",0,0,3
Fracture,Foam,"Feng, Chenchen; Ma, Xurui; Jing, Zefeng",Dynamic proppant-carrying performance of VES-CO2 foam fracturing fluid in the pipeline and the fracture,VES; Foam fracturing fluid; Proppant; Sedimentation; Fracture,PARTICLE-TRANSPORT,"A viscoelastic surfactant (VES) fluid blends with CO2 to form the foam fracturing fluid. To obtain the dynamic proppant-carrying behaviors of the VES-CO2 foam fluid, an experimental system with a horizontal transparent tube and a visual fracture is built. In the horizontal pipeline, it is displayed that the critical settling flow velocity of the ceramsite proppant in the flowing VES-CO2 foam fluid increases with the temperature. Further, the critical settling flow velocity initially decreases and then increases with both the increases of the foam quality and the proppant ratio, and its transition points are at the foam quality of 0.75-0.80 and at the proppant ratio of 0.25, respectively. In addition, considering the influencing parameters in the experiments, we obtain a correlation equation of the critical settling flow velocity. In the experiments of the fracture observation section, the height of the equilibrium sand bank and the angle of repose are mainly investigated. Both of these two parameters decrease as the foam quality, as well as the injection flow velocity, is increased. Especially, it is found that the angle of repose is below 20 degrees at larger injection flow velocity.",0,0,2
Fracture,Foam,"Ishii, Mikihito; Murata, Sumihiko; Ishitsuka, Kazuya; Lin, Weiren",Stability of novel cellulose-nanofiber-containing foam as environmentally friendly fracturing fluid,Foam stability; Cellulose nanofiber; Fracturing fluid; High pressure; High temperature; Salinity,CRITICAL MICELLE CONCENTRATION; TEMPO-MEDIATED OXIDATION; PROPPANT TRANSPORT; BEHAVIOR; FILMS; WATER; TEMPERATURE; MIXTURES; DRAINAGE; SHALE,"Foam-based fracturing is one of the waterless fracturing technologies that can reduce the environmental issues of water-based fracturing. To utilize foam as a fracturing fluid in oil/gas developments, improving foam stability is essential. To examine whether the environmentally friendly and low-cost cellulose nanofiber (CNF) can be a novel foam stabilizer, we investigated the effect of surfactant on the initial foam volume and stability of CNF-containing foam using four types of surfactants with different electrical properties. Then, we investigated the stability of CNF-containing foam under the high-pressure or high-temperature conditions as well as under the laboratory pressure and temperature condition and compared to the stability of foam containing sodium salt of CMC (NaCMC). In addition, we investigated the stability of CNF-containing foam under the presence of salts. As a result, it was concluded that the initial foam volume and stability of CNF-containing foam strongly depend on the type of surfactant because the CNF surface is negatively charged; the CNF is superior to NaCMC as a foam stabilizer, especially in the CNF concentration range above 0.10 wt%; the stability of CNF-containing foam decreases with increasing temperature and increases with increasing pressure, and it is significantly reduced with the addition of salt because the aggregation of the CNFs is formed due to the interaction between the salt cations and CNFs. Further research is expected to use CNF as a stabilizer for foam-based fracturing fluids as CNF is an attractive biomass substance as a foam stabilizer.",0,0,3
Fracture,Wireline Logs,"Porlles, Jerjes; Panja, Palash; Sorkhabi, Rasoul; McLennan, John",Integrated porosity methods for estimation of gas-in-place in the Muerto Formation of Northwestern Peru,Muerto formation; Peru; Lancones and Talara Basins; Shale porosity; Kerogen porosity; Gas-in-place; Reservoir Model,SHALE,"The Albian-age Muerto formation in the Talara and Lancones basins of Northwestern Peru is a world-class source rock with high organic carbon (up to 4%, kerogen type III) and thermal maturity for the generation of both oil and gas as constrained by geochemical data presented here. We used wireline logs from one well in the Lancones basin in conjunction with geochemical data to model a multi-porosity model for the Muerto shaly carbonates. Our porosity model suggests total porosity 10.8% (from neutron and density logs), matrix porosity 10.3% (from the sonic log) of which inorganic porosity is 7.96% and kerogen (organic) porosity is 2.02%. Fracture porosity was found to be negligible (0.5%). The study thus incorporates porosities storing both free and adsorbed gas in this self-sourced reservoir. Moreover, the paper offers an integrated volumetric and reservoir modeling for estimation of gas-in-place (GIP) in the studied interval of the Muerto formation. The calculated GIP, including adsorbed gas is 660.2 MSCF/(acre-ft). This is the first application of a multi-porosity model for an unconventional gas reservoir in Peru, thus offering a methodology for porosity modeling of other unconventional tight reservoirs in Peru where petroleum plays have been relatively underdeveloped. Our study mainly aims to quantify different porosities that control the estimation of total GIP in tight rock formations.",0,0,0
Fracture,Wireline Logs,"Haagsma, Autumn; Scharenberg, Mackenzie; Keister, Laura; Schuetter, Jared; Gupta, Neeraj",Secondary porosity prediction in complex carbonate reefs using 3D CT scan image analysis and machine learning,Machine learning; Image analysis; CT scans; Carbonates; Secondary porosity,,"Development and preservation of carbonate porosity and permeability are critical to characterizing reservoirs. However, secondary porosity, such as vugs and fractures, are difficult to identify and require collection of expensive wireline tools or core sampling. Wireline logs and cores have traditionally been used to identify the presence of secondary porosity but fail to quantify the contribution to total reservoir porosity. Additionally, advanced wireline logs and core are not readily available for most wells. Dual energy CT scans were collected on whole core from the A-1 Carbonate and Brown Niagaran formations drawn from six wells in northern Michigan. 3D analysis techniques were applied to identify and isolate secondary porosity features. A series of machine learning and data analytics techniques were applied to the dataset to predict secondary porosity features on basic wireline logs. The predictive model successfully predicted secondary porosity with high confidence.",0,0,3
Fracture,Young's Modulus,"Zhao, Gang; Ding, Wenlong; Tian, Jing; Liu, Jingshou; Gu, Yang; Shi, Siyu; Wang, Ruyue; Sun, Ning","Spearman rank correlations analysis of the elemental, mineral concentrations, and mechanical parameters of the Lower Cambrian Niutitang shale: A case study in the Fenggang block, Northeast Guizhou Province, South China",Elemental and mineral concentrations; Mechanical parameters; Spearman rank correlation analysis; Brittleness index; Niutitang Formation shale,CENGONG BLOCK; DEVELOPMENTAL CHARACTERISTICS; DOMINANT FACTORS; GAS EXPLORATION; MARINE SHALE; RESERVOIRS; FRACTURES; SEDIMENTARY; TECHNOLOGY; PREDICTION,"The increasing complexity of reservoirs, particularly shale reservoirs, demands accurate information on the formation composition, mineralogy, and mechanical parameters for effective exploitation. The development of geochemical and geophysical logging technology allows the investigation of the correlations between the elemental, mineral contents, and the mechanical parameters of shale. Taking the Lower Cambrian Niutitang Formation shale in the Fenggang block in northeastern Guizhou as an example, 889 data sets of the main elemental (Si, Ca, Fe, 5, Ti, Gd, K, Mg, and S) concentrations and minerals (carbonate, pyrite, clay, quartz, feldspar, and mica) from Elemental Capture Spectroscopy logging and rock mechanics parameters (dynamic Young's modulus, dynamic Poisson's ratio, shear modulus, bulk modulus, and brittleness index) determined via Sonic Scanner logging data in the target zone of the study area are collected. We investigated the relationships between the mechanical parameters and the elemental, and mineral concentrations by Spearman rank correlation analysis. The influence of different Si concentrations on the mechanical parameters of the rock (positive/ negative, and significance) is discussed based on the mineral contents determined via X-ray diffraction of 24 experimental samples. When 22.1% < DWSi (dry weight fraction of the silicon content as a percent) < 28.40% and 28.40% < DWSi <34.20%, the static Young's modulus, shear modulus, bulk modulus, and brittleness index exhibit a highly positive/negative correlation that is significant with the increase/decrease in DWSi, WCLA (dry weight fraction of clay), and WQFM (dry weight fraction of quartz, feldspar, and mica) contents, respectively. DWSi = 28.4% is suggested as the turning point for the correlation change (positive/negative, significance). Thus, there exists uncertainty in the determination of the mechanical parameters of rock within certain elemental content ranges. More mathematical models and factors need to be considered to adequately characterize the mechanical parameters of rock.",0,0,1
Fracture,Young's Modulus,"Shaibu, Rashid; Guo, Boyun; Wortman, Philip B.; Lee, Jim",Stress-sensitivity of fracture conductivity of Tuscaloosa Marine Shale cores,Fracture conductivity; Tuscaloosa Marine Shale; Productivity; Shale; Proppant embedment,PROPPANT EMBEDMENT DEPTH; MECHANICAL-PROPERTIES; SHUT-IN; MODEL; WELL; PERMEABILITY; IMPACT,"Production decline from wells producing from shale rocks is typically quite rapid. One possible factor responsible for such decline is loss in fracture conductivity. This is true in the case of the Tuscaloosa Marine shale reservoir. In this work, the stress-dependent fracture conductivity of TMS core samples is investigated using five propped cores under varying stress conditions. In addition, the effects of static rock mechanical properties and rock mineralogy on conductivity decline are investigated. The mineralogy of each core sample was determined by Xray Diffraction analysis. Fracture conductivity was measured using a Hassler-type pressure core holder with a pressure rating of 15,000 psi (103.42 MPa). Estimated rock mechanical properties showed that shale anisotropy could affect fracture conductivity. The time decline in conductivity revealed two possible decline trends, a) decline from the reduction in induced fracture width, and b) decline from the healing of developed micro-cracks. An exponential decline in fracture conductivity with increasing confinement pressure was observed with an average decline rate constant of 3.15 x 10- 10 mPaxfffd; 1. While rock mineralogy did not have any clear relationship with conductivity decline, the effects of rock mechanical properties were only important at 10.34 MPa confinement pressure and above. The observation showed that a high Young's modulus correlate to high conductivity, whereas a high Poisson's ratio correlate to low conductivity. This study provides useful observations for optimizing fracture design to enhance well productivity in the TMS.",0,0,2
Crude Oil,Formation Water,"Wang, Feilong; Tang, Guomin; Wang, Deying; Pan, Wenjing; Yang, Hong; Awan, Rizwan Sarwar",Paleoenvironmental characteristics and evidence of subsag migration within the Laizhouwan Sag in the Bohai Sea,Sag-migration; Paleoenvironment; Paleoproductivity; Palynofacies; Laizhouwan sag; Bohai sea,DEPOSITIONAL ENVIRONMENT; SHALE; OIL,"The Laizhouwan Sag comprises many sets of source rocks, and their crude oil properties are complex and changeable. This research evaluates the quality of source rocks using mudstone samples of the Shahejie Formation from typical wells from northern and southern subsags by incorporating a detailed organic-inorganic geochemical, palynology and petrological analysis. Moreover, it analyzes the difference between the paleoenvironment and paleoproductivity. It also discusses the migration characteristics of the sag in combination with seismic data to reveal the fundamental reason for the complex oil source characteristics of the Laizhouwan sag. The results show there are two sets of effective source rocks in the northern subsag of the Laizhouwan Sag, (i) the third member of the Shahejie Formation(E2s3) (ii) the fourth member of the Shahejie Formation (E2s4). Additionally, the E2s4 is a high-quality, effective source rock in the southern subsag of Laizhouwan Sag. (2) During the sedimentary period of the E2s4 in Laizhouwan Sag, the water bodies of the southern and northern subsags were separated. The organic matter (OM) in the E2s4 of northern subsag mainly comes from lower algae, mainly amorphous, and deposited in a weak reducing environment of brackish water. The OM in the E2s4 of southern subsags mainly comes from terrigenous higher plants, mainly composed of terrigenous amorphous assemblages, and it was deposited in a strongly reducing environment of brackish water to saline water. (3) Moreover, the water bodies of the southern and northern subsags gradually changed to unified water bodies during the sedimentary period of the E2s3. During this period, OM comes from lower algae, mainly from amorphous material, and the water bodies were transformed to a weak oxidation-reduction environment from freshwater-brackish water. The subsidence center of the Laizhouwan sag continued to move southward during the sedimentary period of E2s4-E2s3. Gradually the southern subsag became a sedimentary center containing higher paleoproductivity and eutrophic lake settings. The differences in organic source, sedimentary environment and paleoproductivity of source rocks in different subsags lead to the complexity of crude oil generation features.",0,0,1
Crude Oil,Formation Water,"Alves, Caiua Araujo; Yanes, Jose Francisco Romero; Feitosa, Filipe Xavier; de Sant'Ana, Hosiberto Batista",Influence of asphaltenes and resins on water/model oil interfacial tension and emulsion behavior: Comparison of extracted fractions from crude oils with different asphaltene stability,Asphaltenes size; Resins; Oil stability; Interfacial tension; Emulsion stability,ADSORPTION-KINETICS; OIL/WATER INTERFACE; TEMPERATURE; AGGREGATION; REDUCTION; TIME,"Asphaltenes and resins make a major contribution for the formation of stable water-in-oil emulsions during crude production, which could affect process operations and increase costs. The purpose of this investigation is to study the influence of these molecular substances from two different crude oil samples (regarding asphaltene stability) on the water-model oil interfacial tension, along with their effect on the emulsion stability. Asphaltene stability of these crude oils presented a marked difference when studied in our past work, with asphaltene precipitation onset that vary from 56 to 75 n-heptane wt %, despite their similar SARA composition. This difference on asphaltene stability was contrasted in this work with the chemical characterization, interfacial activity, and emulsion behavior of crude oil asphaltenes, resins, and their mixtures using toluene solutions. For each crude oil, resins and asphaltenes were extracted and characterized by XRD, SEM/EDS, FTIR, and elemental analysis, to better understand their molecular structure and surface-active species content. Then, it was prepared different model oil solutions in toluene, varying the content of asphaltenes and resins (500, 1,000, and 2000 mg/L). Additionally, it was prepared 2000 mg/L asphaltene/resin mixtures with different ratios (75:25 wt%, 50:50 wt%, and 25:75 wt%). Dynamic interfacial tension between the model oil and water was measured by intermediate of a Du Nouy ring method. Afterward, each model system was emulsified by adding water (at the same volumetric ratio) in a bottle test and stability was analyzed. For the sample with lower stable asphaltenes, a rapid stabilization of the dynamic interfacial tension (IFT) was observed, together with a decrease of IFT from 26.8 to 24.2 mN/m at the limit of asphaltene content studied. On the contrary, for the high stable asphaltenes sample, a transient dynamic IFT behavior was observed, until reach 12.0 mN/m (the lower operational equipment limit). Similar results were obtained for resins model solutions for both crude oils tested. For asphaltene obtained from the sample with lower asphaltene stability, the emulsions presented high stability (for a 24 h test). Besides for the high asphaltene stability sample and resins model oils, all emulsions prepared were unstable. Useful insights are given by the oil fractions chemical characterization, suggesting that smaller sized molecules from high stable crude oils have a predominant effect on IFT reduction, while larger molecules from less stable oils are responsible for the emulsion stability.",0,0,1
Crude Oil,Formation Water,"Li, Yi-Bo; Deng, Qing-Huan; Huang, Tao; Zhang, Ya-Qian; Pu, Wanfen; Zhao, Jin-Zhou",A numerical and experimental investigation into the influence of CO2 on the stability of W/O emulsion,CO2; W/O emulsion; Demulsification; Diffusion; Mathematical model,DROPLET SIZE DISTRIBUTION; CRUDE OIL-EMULSIONS; INTERFACIAL-TENSION; WATER; TEMPERATURE; MISCIBILITY; PRESSURE,"The formation of water in oil (W/O) emulsion can result in flow issues in the reservoir and a high cost of demulsification throughout the water treatment process. Without treatment, the W/O emulsion takes a long time to settle, which results in blockage in porous media. CO2 has strong interaction with crude oil and so has the potential to alter the settling process of W/O emulsion. The purpose of this paper is to undertake a numerical and experimental investigation into the influence of CO2 on the emulsion stability. To anticipate the settling process of a W/O emulsion in a high-pressure environment, a mathematical model was created that included a CO2 diffusion model, a viscosity prediction model, and an emulsion settling model. A high-pressure reactor was used to model the emulsion demulsification process at three different pressure conditions and to evaluate the model's prediction capability. The results indicate that under a high-pressure CO2 atmosphere, the demulsification process of a W/O emulsion can be accelerated. The CO2 dissolution and diffusion into the oil phase might enhance the likelihood of droplets colliding, resulting in the demulsification of the W/O emulsion system. Pressure has a significant influence on the stability of the emulsion. High pressure accelerates the CO2 dissolution process and significantly reduces the time required for the emulsion system to reach equilibrium. Additionally, the oil/water ratio can affect the stability of a W/O emulsion. At the same pressure, an emulsion with a higher oil/water ratio required a shorter time to reach equilibrium and had a higher equilibrium viscosity.",0,0,1
Crude Oil,Formation Water,"Bahu, Juliana Otavia; Miranda, Nahieh Toscano; Khouri, Nadia Gagliardi; Batistella, Cesar Benedito; Cardenas Concha, Viktor Oswaldo; Wolf Maciel, Maria Regina; Rocha Barbosa Schiavon, Maria Ingrid; Maciel Filho, Rubens",Crude oil emulsion breaking: An investigation about gravitational and rheological stability under demulsifiers action,Bottle test; Dehydration; Demulsifier testing; Emulsion breaking; Rheology; Stability,PETROLEUM EMULSIONS; DROPLET SIZE; WATER; LIGHT; METHODOLOGY; TEMPERATURE; SURFACTANTS; PERFORMANCE; VISCOSITY; SALINITY,"Emulsions are common in the oil industry, being present in the extraction and production stages. Its formation occurs with the contact of brine and crude oil under intense flow. The presence of emulsified water (dispersed droplet size, phi <= 50 mu m) in crude oil can negatively impact its exploration, transportation, and refining, making transportation more expensive, requiring more energy for heating, and causing equipment corrosion on all processes. In addition, crude oil has salts and sediments that encrust and corrode equipment of the primary oil treatment unit and distillation towers, also causing catalyst poisoning in the cracking step. Therefore, such components need to be removed for subsequent refining processes. To prevent these problems, the dehydration/ desalting of crude oils is a strategy adopted to reach adequate values of water, salts, and sediments required in the refineries for the next steps after primary treatment. However, the emulsion breaking is influenced by several factors that affect the stability of crude oil (W/O emulsion), such as viscosity, contents of water, salts, sediments, and natural surfactants, among others. Given this perspective, this work investigated the stability of two different types of crude oils with demulsifier under the action of gravity (bottle test) and shear stress (rheology). The comparisons of gravitational and rheological techniques concluded that the shear stress sweep analyses are useful to evaluate the demulsifier performance in the emulsion breaking, being a reliable and fast methodology. Such studies allowed the identification of adequate parameters: temperature (80 degrees C) and, demulsifier type and quantity (500 ppm) for efficient crude oil phase separation, without using washing water. The physicochemical and rheological characterizations clarified the crude oil's colloidal stability behavior to understand the impurities' influence on the oils' properties (crude and desalted).",0,0,2
Crude Oil,Formation Water,"Shahmohammadi, Borhan; Chahardowli, Mohammad; Simjoo, Mohammad",Insights into the pore-scale mechanism of low salinity water injection using a clay-coated micromodel,Low-salinity; Water flooding; Crude oil polar component; Partitioning; Wettability alteration; Clay-coated micromodel; Emulsified phase,IMPROVED OIL-RECOVERY; NAPHTHENIC ACIDS; IMPACT; BRINE; SANDSTONE; RESERVOIR; EMULSION,"This study aims to provide new insights into the interactions among an acidic crude-oil, brine with different salinities and clay using flow experiments in montmorillonite-coated micromodels. To this end, a series of oildisplacement experiments are performed in a transparent clay - coated micromodel. In addition, salinityscreening tests, pH and IFT measurements are performed to support the results of flow-experiments. It is shown that during water injection into a clay-coated micromodel, polar components of crude oil partition between oil/water phases and form an emulsified phase. With the 90% reduction in water salinity, the partitioning of crude oil polar components in the aqueous phase is increased. Such partitioning lead to a significant reduction in the pH of the aqueous phase. This observation is supported by an increase in the IFT of oil/brine due to the decrease of crude oil polar components. Salinity screening tests show that there is a critical water salinity, i.e., below the critical point, a large amount of crude oil polar components is partitioned between phases, which can be attributed to the polarization effect. Overall, results show that low salinity water injection benefits from formation of an emulsified phase and wettability alteration to improve oil recovery in the microscale.",0,0,2
Crude Oil,Formation Water,"Husein, Norhafizuddin; Ismail, Issham; Boyou, Natalie Vanessa; Mani, Sanjihuen V. Selva; Wong, Zhu Ker; Sulaiman, Wan Rosli Wan",Experimental investigation of different simulated formation water salinity in three-phase waxy crude oil-water-gas flow in horizontal pipes,Waxy crude oil; Oil-water-gas three-phase flow; Flow pattern; Pressure gradient; Liquid holdup,2-PHASE FLOW; PRESSURE-DROP; MULTIPHASE FLOW; PREDICTING FLOW; VOID FRACTION; EMULSIONS; PATTERNS; VISCOSITY; DIAMETER; TRANSITIONS,"Three-phase oil-water-gas flow experiments have been conducted in a horizontally configured rig made of carbon steel pipe with an ID of 0.041 m and a total length of 24.3 m. The test fluids were Malaysian waxy crude oil from Malay basin and three concentrations of simulated formation water salinity, namely 0 ppm, 15 000 ppm, and 30 000 ppm. The waxy crude oil and simulated formation water are varied at six different superficial liquid velocities ranging from 0.5 to 3.0 m/s while the gas phase is varied at 10 different superficial velocities ranging from 0.01 to 0.61 m/s. Eight flow patterns are observed using observational method; one of which is a newly discovered flow pattern identified as Slug with Oil Film-Oil Continuous (SLOF-OC). Salinity does not give significant effect on oil-gas interface but significantly affects the oil-water interface as lower formation water salinity is dispersed easily in crude oil compared to higher formation water salinity. The highest pressure gradient recorded was 2506.84 Pa/m at the highest superficial gas velocity while the lowest pressure gradient recorded was 89.53 Pa/m at the lowest superficial gas velocity. It is imperative to note that the experimental investigation of Malaysian waxy crude oil with different formation salinity in the three-phase flow study is in an unchartered area, therefore it provides a new platform for furthering more complex research works such as fourphase flow (gas, oil, water, and wax particles) below Wax-Appearing Temperature (WAT).",0,0,2
Crude Oil,Formation Water,"Li, Rongbin; Huang, Qiyu; Zhu, Xiangrui; Zhang, Dongxu; Lv, Yang; Larson, Ronald G.",Investigation of delayed formation of wax deposits in polyethylene pipe using a flow-loop,Wax deposition; Contact angle; Delayed formation; Adhesion; Sloughing; Wax content,OPERATING-CONDITIONS; BREAKING FORCE; LAMINAR-FLOW; CRUDE; WATER; INHIBITORS; PERFORMANCE; PIPELINES; SURFACES; MODEL,"After the start of the flow in a home-built flow-loop, the thickness of a waxy layer deposited on a stainless steel (SS) test section was found to increase immediately, while deposition was delayed for around 4 h on a polyethylene (PE) test section. The radial thermal gradient, wax precipitation rate, radial diffusivity of wax, and shear stresses at the surface of the deposit layer were calculated, eliminating these factors as sources of different deposition behavior. However, the contact angles of oils containing precipitated wax crystals on PE surfaces were found to increase more with increasing wax content than those on SS surfaces. Consistent with this, while the wax contents of deposits were found to be around 18 wt % for both PE and SS pipes, the adhesion of the deposit on the PE surface was found to be much weaker than on the SS surface, as evidenced by the easier of removal of the deposit from PE than from SS pipes when heated in vertical orientation under gravity. These results point to pipe wall wettability as a significant factor in both initial growth of wax deposit, and ease of removal.",0,0,2
Crude Oil,Formation Water,"Sauerer, Bastian; Al-Hamad, Mohammed; Ma, Shouxiang Mark; Abdallah, Wael",Effect of formation water salinity on interfacial tension of reservoir fluids,Interfacial tension; Crude oil; Salinity; Formation water; Seawater,SURFACE-TENSION; DIVALENT SALTS; SYSTEMS; WETTABILITY; MONOVALENT; IONS,"The interaction of surface-active species within crude oil with ions in the aqueous phase can have a major influence on the interfacial tension (IFT) between these two phases. Herein, the influence of salinity on IFT is investigated systematically. Brines with different salinities, including seawater and reservoir formation water, are considered. The measurements clearly show distinct IFT trends depending on the composition and concentration of salts in the aqueous phase as well as on the crude oil chemical species, as represented by the API values. The results show that complex brine systems have a stronger effect on IFT than individual single salt brine systems. It is possible to derive distinct additive correction factors for the respective tested brine systems based on the averaged values of deviation from the respective cases in deionized water. On average for the tested 10 oils, and in comparison to measurements in DI water, IFT was reduced by 3.4 mN/m in 100 kppm CaCl2 solution, by 5.3 mN/m in 100 kppm NaCl solution, by 6.8 mN/m in formation water and by 8.2 mN/m in seawater.",0,0,2
Crude Oil,Formation Water,"Wang, Mibang; Yang, Shenglai; Li, Jiajun; Zheng, Zuhao; Wen, Jing; Ma, Quanzheng; Wang, Qian; Chen, Hao",Cold water-flooding in a heterogeneous high-pour-point oil reservoir using computerized tomography scanning: Characteristics of flow channel and trapped oil distribution,High-PPT live oil; CT-Scanning; Positive-rhythm reservoir; Variable water injection temperature; Flow channel,WAXY CRUDE-OIL; ASPHALTENE PRECIPITATION; PERMEABILITY REDUCTION; PARAFFIN PRECIPITATION; RELATIVE PERMEABILITY; START-UP; DEPOSITION; MODEL; IMBIBITION; EFFICIENCY,"There are relatively few studies that consider the influence of reservoir heterogeneity on reservoir wax deposition. This study conducts a computerized tomography scan to study the flow channels, heavy component retention, displacement efficiency, and trapped oil distribution in a high-pour point oil reservoir with a positive sedimentary rhythm under various water injection temperatures. This study greatly improves the understanding of the wax deposition influences on the flow channel. Three displacement models are proposed: water-flooding breakthrough model (49.5 ?C), approximate-equilibrium piston-like displacement model (54.5 ?C/59.5 ?C), and non-equilibrium piston-like displacement model (64.5 ?C). When the injection temperature is lower than the wax appearance temperature (59.5 ?C), an elliptical wax deposition is formed at the inlet, the most serious deposition is in the middle-permeability layer. A wax deposition barrier is formed away from the inlet, and constrains the downward movement trend of the water injected above. Therefore, the moderate wax precipitation will improve the oil recovery from the top low-permeability layer. However, the heterogeneity in the spaces and strength of the barrier result in the oil recovery from the 100 mD layer at 59.5 ?C begin higher than that at 54.5 ?C; moreover, at 59.5 ?C, the recovery at the inlet is better than that at the outlet. The vortex phenomenon increases the oil recovery from wax deposition area in the bottom layer at the inlet. The heavy component retention is significant, and the oil recovery decreases with decreasing injection temperature. After flooding, the formation mechanisms of the trapped oil include wax deposition, weak water washing, and reservoir sedimentary rhythms. The research results provide initial insights for the evaluation of cold damage.",0,0,2
Crude Oil,Formation Water,"Velasquez, Ingrid; Silva, Iris; Martinez, Lesbia; Rattia, Luz; Labrador, Henry; Villanueva, Ivan; Perez, Victor; Aguero, Bari; Gonzalez, Maria; Monroy, Ruth; Bejarano, Celia; Milano, Eliecer; Mendoza, German; Pereira, Juan",Interfacial phenomena in petroleum reservoir conditions related to fluid-fluid interactions and rock-fluid interactions: Formulation effects and in porous medium test,Interfacial phenomena; Dispersions; Emulsions; Wettability; Colloid aggregate,ASPHALTENE DEPOSITION; WATER; PERFORMANCE,"Precipitation of asphaltenes in oil fields represents interfacial phenomena of great concern for oil industry. Oil production decreases due to the obstruction of reservoir rock pores by asphaltene blockage. Futhermore, the phenomena of wettability changes and water/oil (W/O) emulsions formation take place in the production processes of crude oil. Herein, the performance and evaluation of a developed product (F2) based on the formulation of an asphaltene inhibitor to overcome these problems is presented. Different systems to assess the product were prepared with crude oil, synthetic formation water and the inhibitor product itself. These components were mixture under certening conditions according to simulated reservoir conditions. Displacement tests using F2 product in three different core samples were carried out. The results of asphaltenes dispersions tests (ADT) indicate that the product has a 100% dispersion effect on the asphaltenes, with a colloidal stability for more than 2 h in the presence of an excess of heptane. The product performance to break up W/O emulsions is evaluated, through the preparation of model systems with synthetic water. Water resolution results indicate that resultant emulsions have low stability. In addition, the interaction (adsorption and adhesion) between crude oil and glass surface was evaluated. Crude oil shows strong adsorption on the glass surface even after water washing. While in the presence of the inhibitor product there is lower adsorption and adherence weakness of crude oil was observed on glass surface. The performance observed within the porous medium after the product been injected at reservoir conditions, shows that the product F2 mitigates formation damages responsible for asphaltene formation and deposition. Observed increments on fluid permeability values after injection of F2 to the crude oil are indication of a greater oil flow in the rock reservoir sample. Based on these findings, it can be concluded that F2 product is a suitable candidate to be evaluated into porous media, as chemical treatment in matrix non-reactive stimulation operations.",0,0,2
Crude Oil,Formation Water,"Pashapouryeganeh, Farzad; Zargar, Ghasem; Takassi, Mohammad Ali; kadkhodaie, Ali; Rabiee, Ahmad",One-Pot synthesis of modified-cationic surfactants for enhanced oil recovery applications in carbonate reservoirs,Surfactant synthesis; Cationic surfactant; Quaternary ammonium salt; Wettability alteration; IFT reduction; Chemical enhanced oil recovery (CEOR),INTERFACIAL-TENSION BEHAVIOR; DETERMINING IONS CA2+; HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; POROUS-MEDIA; CHAIN-LENGTH; WET; MECHANISM; LIQUID,"In this study two cationic surfactants, dodecyltriethylammoniumbromide (C(12)TEAB) and hexadecyl-triethylammoniumbromide (C(16)TEAB) were prepared. The formation of synthezied surfactants were confirmed using FTIR and HNMR spectroscopy. Electrical conductivity, interfacial tension and surface tension methods were used to determine the critical micelle concentrations (CMC) of these surfactants. To understand the behavior of synthesized surfactants in harsh environments, the CMC was measured in deionized water (DIW), sea water and petroleum formation water. Using electrical conductivity technique, for C(12)TEAB surfactant the CMC values of 4000 ppm, 2000 ppm and 850 ppm were recorded in DIW, sea water and formation water respectively. For C(16)TEAB surfactant, the CMC values of 420 ppm, 190 ppm and 115 ppm were obtained in DIW, sea water and formation water respectively. The similar CMC results were obtained using the interfacial tension (IFT) and surface tension (ST) methods. Reduction of IFT between crude oil and formation water and also alteration of wettability of petroleum reservoir of carbonated rock from oil-wet (large contact angle) to water-wet (small contact angle) are two major factors affecting chemical enhanced oil recovery (EOR). Interfacial tension (IFT), surface tension (ST) and contact angle measurements were carried out using an IFT-PDSA-06 apparatus (Apex Technologies Company, Iran). The IFT and ST of these surfactants were also carried out in DIW, sea water and formation water. For C(12)TEAB surfactant, the IFT values of 0.051 mN/m, 0.036 mN/m and 0.023 mN/m were recorded in DIW, sea water and formation water respectively. The IFT values of 0.044 mN/m, 0.026 mN/m and 0.0126 mN/m were measured for C(16)TEAB surfactant in DIW, sea water and formation water respectively. The effect of temperature on IFT was studied for both surfactants. When temperature increases, IFT decreases. The reduction of IFT continues up to 55 degrees C, then the IFT increases with increasing temperature. For C(12)TEAB surfactant, the ST values of 44.9 mN/m, 38.8 mN/m and 31.8 mN/m were obtained in DIW, sea water and formation water respectively. In similar measurements for C(16)TEAB surfactant, the recorded ST values were 33.95; 32.9 and 32.22 mN/m in DIW, sea water and formation water respectively. In wettability alteration study both surfactants altered the contact angle from oil-wet to water-wet conditions. Using formation water and C(12)TEAB surfactant, the contact angle varied from 96.4 degrees to 54.5 degrees. In similar study using C(16)TEAB surfactant the contact angle changed from 92 degrees to 46.1 degrees. The contact angles of these surfactants in DIW and sea water were also measured and reported. The results of IFT and wettability studies demonstrated excellent potential application of synthesized surfactants in EOR process in carbonate petroleum reservoirs.",0,0,3
Crude Oil,Asphaltene,"Alhosani, Ahmed; Daraboina, Nagu",Effect of multi-phase flow on asphaltene deposition: Field case application of integrated simulator,Flow assurance; Multiphase flow; Asphaltene deposition,GAS-LIQUID FLOW; HEAT-TRANSFER; PARTICLE DEPOSITION; UNIFIED MODEL; CRUDE OILS; TOOL ADEPT; PRECIPITATION; SLUG; HOLDUP; AGGREGATION,"Asphaltene is initially stable in the oil, but when there is a change in pressure, temperature, or composition, particles tend to phase out and form precipitants. Issues arise when those particles diffuse toward the wall and deposit, which contributes to reducing the flowing area and increasing the pressure drop. Preventing precipi-tation is the optimum solution to maintain the target production rate; however, it is challenging to avoid favorable precipitation conditions. Remedies and treatments to mitigate this issue cause the oil industry a considerable increase in expenditure and time; thus, it is necessary to develop a tool to accurately predict the deposition for a wide range of operating conditions, especially in multiphase flow. In this study, a multiphase simulator is developed by coupling thermodynamics, hydrodynamics, heat transfer, and asphaltene modules to predict the deposition. A deposition data obtained from a field case is used to validate the robustness of the simulator. The simulator results matched well with the asphaltene deposition and the equilibrium profile available in the literature. The simulation approach presented here offers useful insights into the effect of multiphase flow on asphaltene deposition and eventually aid in improving the accuracy of pre-diction. Using single-phase assumption under multiphase conditions contributed to a significant error in the prediction, and these inaccuracies may lead to a substantial economic and operational burden for the oil and gas industry.",0,0,0
Crude Oil,Asphaltene,"Alves, Caiua Araujo; Yanes, Jose Francisco Romero; Feitosa, Filipe Xavier; de Sant'Ana, Hosiberto Batista",Influence of asphaltenes and resins on water/model oil interfacial tension and emulsion behavior: Comparison of extracted fractions from crude oils with different asphaltene stability,Asphaltenes size; Resins; Oil stability; Interfacial tension; Emulsion stability,ADSORPTION-KINETICS; OIL/WATER INTERFACE; TEMPERATURE; AGGREGATION; REDUCTION; TIME,"Asphaltenes and resins make a major contribution for the formation of stable water-in-oil emulsions during crude production, which could affect process operations and increase costs. The purpose of this investigation is to study the influence of these molecular substances from two different crude oil samples (regarding asphaltene stability) on the water-model oil interfacial tension, along with their effect on the emulsion stability. Asphaltene stability of these crude oils presented a marked difference when studied in our past work, with asphaltene precipitation onset that vary from 56 to 75 n-heptane wt %, despite their similar SARA composition. This difference on asphaltene stability was contrasted in this work with the chemical characterization, interfacial activity, and emulsion behavior of crude oil asphaltenes, resins, and their mixtures using toluene solutions. For each crude oil, resins and asphaltenes were extracted and characterized by XRD, SEM/EDS, FTIR, and elemental analysis, to better understand their molecular structure and surface-active species content. Then, it was prepared different model oil solutions in toluene, varying the content of asphaltenes and resins (500, 1,000, and 2000 mg/L). Additionally, it was prepared 2000 mg/L asphaltene/resin mixtures with different ratios (75:25 wt%, 50:50 wt%, and 25:75 wt%). Dynamic interfacial tension between the model oil and water was measured by intermediate of a Du Nouy ring method. Afterward, each model system was emulsified by adding water (at the same volumetric ratio) in a bottle test and stability was analyzed. For the sample with lower stable asphaltenes, a rapid stabilization of the dynamic interfacial tension (IFT) was observed, together with a decrease of IFT from 26.8 to 24.2 mN/m at the limit of asphaltene content studied. On the contrary, for the high stable asphaltenes sample, a transient dynamic IFT behavior was observed, until reach 12.0 mN/m (the lower operational equipment limit). Similar results were obtained for resins model solutions for both crude oils tested. For asphaltene obtained from the sample with lower asphaltene stability, the emulsions presented high stability (for a 24 h test). Besides for the high asphaltene stability sample and resins model oils, all emulsions prepared were unstable. Useful insights are given by the oil fractions chemical characterization, suggesting that smaller sized molecules from high stable crude oils have a predominant effect on IFT reduction, while larger molecules from less stable oils are responsible for the emulsion stability.",0,0,1
Crude Oil,Asphaltene,"Sulaimon, Aliyu Adebayo; Falade, Gabriel Kayode",New two-phase and three-phase thermodynamic models for predicting wax precipitation in hydrocarbon mixtures,Thermodynamic model; Continuous gamma distribution function; Thermodynamic property correlation; Wax appearance temperature; Hydrocarbon mixtures; Absolute deviation,CRUDE OILS; ASPHALTENE; DEPOSITION; TEMPERATURE; EQUILIBRIA; PRESSURE,"One of the major issues in flow assurance is the precipitation and subsequent deposition of paraffin wax in petroleum production systems. A new two-phase multicomponent thermodynamic model based on a continuous thermodynamic phase equilibria employing a three-parameter gamma distribution function has been developed to predict the wax appearance temperature (WAT), the amount of precipitated wax, and the wax content of crude oils. Also, a generalized three-phase multicomponent thermodynamic model based on the combined polymer and regular solution theories of mixtures as well as on equations of state (EOS) is presented. The model utilizes the solid-liquid-vapour phase equilibrium relations with some constraint functions. Furthermore, hinged on the regression analysis of published experimental data, a new set of molecular-weight-dependent thermodynamic properties' correlations were developed and used to calculate the solid-liquid-equilibrium-ratios (K-i(S-L)) for the individual component. The models were validated with data obtained from experiments conducted on 32 different hydrocarbon fluids from the Niger Delta, North Sea, Gulf of Mexico, East Asia, and Middle East fields. Results show that the gamma distribution parameters (alpha, beta, eta) can be used to classify hydrocarbon mixtures into three categories: light oils or condensate, waxy oil or asphaltenic oils, and biodegraded oils. Analysis shows that when compared with experimental data, the two-phase thermodynamic model is reliable with the average absolute deviations (AAD%) of 0.80% for paraffinic and waxy oils, 0.42% for paraffinic and waxy condensates, and 4.33% for paraffinic-asphaltenic and biodegraded oils. For the three-phase model, results show that the AAD% for the paraffinic and waxy oils, paraffinic and waxy condensates, and biodegraded oils are 0.93%, 1.03%, and 4.88% respectively. However, the two models slightly overestimate the WAT for biodegraded crude oils. Nevertheless, the generalized thermodynamic models developed have proved to be effective for predicting the onset conditions for wax precipitation during petroleum production and processing. It will prove a helpful tool for the fast and accurate assessment of wax deposition tendencies of hydrocarbon mixtures.",0,0,1
Crude Oil,Asphaltene,"Asbaghi, Ehsan Vahabzadeh; Assareh, Mehdi; Nazari, Farzaneh",An effective procedure for wax formation modeling using multi-solid approach and PC-SAFT EOS for petroleum fluids with PNA characterization,Petroleum cuts; Multi-solid approach; Wax precipitation; PC-SAFT; PNA Analysis,EQUATION-OF-STATE; PERTURBED-CHAIN SAFT; SEA CRUDE OILS; DIRECTIONAL ATTRACTIVE FORCES; THERMODYNAMIC MODEL; PHASE-EQUILIBRIA; ASPHALTENE PRECIPITATION; LIQUID-EQUILIBRIA; N-ALKANES; PLUS,"Several experiments and thermodynamic models are developed to prevent Wax precipitation. Paraffinic hydrocarbons participate to a greater extent in the precipitation process than other hydrocarbon families. However, the existing models do not distinguish these hydrocarbon families, leading to the overestimation or underestimation of wax precipitation parameters. To address this problem, we will use a predictive Paraffin, Naphthene, and Aromatic (PNA) estimation technique to split the petroleum fractions that avoids using average properties for petroleum fractions. A sequential multi-solid approach is also implemented for the thermodynamic analysis of wax precipitation. The perturbed chain statistical associating fluid theory (PC-SAFT) equation of state (EOS) is utilized to calculate liquid properties. The binary interaction coefficients (BIC) of non-paraffin hydrocarbons are modified to improve the model's accuracy for calculating wax weight and wax appearance temperature (WAT). Six crudes from the North Sea are selected to evaluate the reliability of the proposed model. The contribution of each hydrocarbons family in the precipitation process is investigated. The results show a considerable improvement compared to previous models. The predicted WAT presents a slight deviation from the experimental data. In addition, the outcome of this work is compared to the modeling works from two reliable references. The average estimation error of wax weight for all crude oils is about 0.19. This deviation increases to 0.36 and 0.38 for the works of the first and second reference, in turn.",0,0,1
Crude Oil,Asphaltene,"Tomiyama, Yuna; Takeshita, Toshihide; Mori, Jiro F.; Kanaly, Robert A.",Functionalization of the model asphaltene 1-dodecylnaphthalene by Pseudomonas aeruginosa KK6 through subterminal metabolism,Asphaltenes; 1-Dodecylnaphthalene; Functionalization; Polycyclic n-alkyl aromatic; Pseudomonas aeruginosa,COLLISION-INDUCED DISSOCIATION; CRUDE-OIL; LIQUID-CHROMATOGRAPHY; FATTY-ACIDS; BIODEGRADATION; PRODUCTS; BIOTRANSFORMATION; IDENTIFICATION; MINERALIZATION; DEGRADATION,"Asphaltenic compounds in heavy oils may be biologically functionalized in the contexts of oil upgrading and in mitigating contamination however there are knowledge gaps in regard to the mechanisms of asphaltene functionalization by microorganisms. Due to the challenges of studying asphaltene functionalization, model asphaltene compounds comprised of polyaromatic centers and long alkyl chains may be utilized. In this work, a soil bacterium identified as Pseudomonas aeruginosa KK6 was characterized and it was found to extensively biotransform the water insoluble polycyclic n-alkylaromatic model asphaltene, 1-dodecylnaphthalene (1-DDN). Gas chromatography was utilized to quantify 1-DDN transformation and liquid chromatography with UV detection coupled to electrospray ionization tandem mass spectrometry (LC-UV/ESI-MS/MS) was used to analyze transformation products. An unusual transformation product profile occurred that showed that varying alkyl chain length compounds that differed by one methylene unit each were detected attached to their polycyclic aromatic chromophores. CID product ion scan analyses revealed that 1-DDN was transformed into oxidized, alkyl chain-shortened, reduced molecular weight 1-naphthyl-alkanoic acids and 1-naphthyl-alkanals and results interpretation supported that these compounds were produced through subterminal oxidation mechanisms by strain KK6. Based upon the results, biotransformation pathways that described the biological functionalization of a model asphaltene compound were constructed. On its own or in conjunction with polycyclic aromatic hydrocarbon-degrading bacteria, this strain may be applied to upgrading heavy oil.",0,0,2
Crude Oil,Asphaltene,"De las Heras, Igor; Dufour, Javier; Coto, Baudilio",Simulation of the deasphalting process of crude oils: Models development and extraction conditions analysis,Asphaltenes elimination; Liquid-liquid equilibrium; Solvent extraction; Solvent deasphalting; Modeling; Crude oil model,ASPHALTENE PRECIPITATION; LIQUID-EQUILIBRIA; PHASE-EQUILIBRIA; MIXTURES; PLUS; FLOCCULATION; DISTILLATION; PREDICTION; SOLUBILITY; DENSITIES,"Heavy crude oils are under constant investigation due to light oil exhaustion. So, its use is compulsory to meet the world energy demand. Heavy crude oils present several drawbacks as high content of metals, heteroatoms, and asphaltenes, and, therefore, upgrading processes are becoming essential. A deasphalting process, conventionally used for vacuum residue upgrading, can be an interesting pretreatment to eliminate the heavier phases and ease the crude processing in conventional refining facilities. Most of the models developed for deasphalting simulation show problems to be implemented in simulation software packages. In this work, a versatile deasphalting simulation method is developed, composed by the definition of a synthetic crude oil model, formed by discrete pseudo components, and a deasphalting model approaching the process to a liquid-liquid extraction based on the thermodynamic model modified UNIFAC (Dortmund). Both models were satisfactorily validated. The deasphalting method was used to explore the solvent/crude ratio, extraction temperatures, and alternative solvents in substitution of conventional light paraffins. Higher extraction temperatures did not enhance remarkably the deasphalting process and the optimum solvent to crude ratio depends on the solvent type. Alcohols were found as promising compounds as their use is recommended by some studies and they showed great deasphalting results.",0,0,2
Crude Oil,Asphaltene,"Wang, Mibang; Yang, Shenglai; Li, Jiajun; Zheng, Zuhao; Wen, Jing; Ma, Quanzheng; Wang, Qian; Chen, Hao",Cold water-flooding in a heterogeneous high-pour-point oil reservoir using computerized tomography scanning: Characteristics of flow channel and trapped oil distribution,High-PPT live oil; CT-Scanning; Positive-rhythm reservoir; Variable water injection temperature; Flow channel,WAXY CRUDE-OIL; ASPHALTENE PRECIPITATION; PERMEABILITY REDUCTION; PARAFFIN PRECIPITATION; RELATIVE PERMEABILITY; START-UP; DEPOSITION; MODEL; IMBIBITION; EFFICIENCY,"There are relatively few studies that consider the influence of reservoir heterogeneity on reservoir wax deposition. This study conducts a computerized tomography scan to study the flow channels, heavy component retention, displacement efficiency, and trapped oil distribution in a high-pour point oil reservoir with a positive sedimentary rhythm under various water injection temperatures. This study greatly improves the understanding of the wax deposition influences on the flow channel. Three displacement models are proposed: water-flooding breakthrough model (49.5 ?C), approximate-equilibrium piston-like displacement model (54.5 ?C/59.5 ?C), and non-equilibrium piston-like displacement model (64.5 ?C). When the injection temperature is lower than the wax appearance temperature (59.5 ?C), an elliptical wax deposition is formed at the inlet, the most serious deposition is in the middle-permeability layer. A wax deposition barrier is formed away from the inlet, and constrains the downward movement trend of the water injected above. Therefore, the moderate wax precipitation will improve the oil recovery from the top low-permeability layer. However, the heterogeneity in the spaces and strength of the barrier result in the oil recovery from the 100 mD layer at 59.5 ?C begin higher than that at 54.5 ?C; moreover, at 59.5 ?C, the recovery at the inlet is better than that at the outlet. The vortex phenomenon increases the oil recovery from wax deposition area in the bottom layer at the inlet. The heavy component retention is significant, and the oil recovery decreases with decreasing injection temperature. After flooding, the formation mechanisms of the trapped oil include wax deposition, weak water washing, and reservoir sedimentary rhythms. The research results provide initial insights for the evaluation of cold damage.",0,0,2
Crude Oil,Asphaltene,"Velasquez, Ingrid; Silva, Iris; Martinez, Lesbia; Rattia, Luz; Labrador, Henry; Villanueva, Ivan; Perez, Victor; Aguero, Bari; Gonzalez, Maria; Monroy, Ruth; Bejarano, Celia; Milano, Eliecer; Mendoza, German; Pereira, Juan",Interfacial phenomena in petroleum reservoir conditions related to fluid-fluid interactions and rock-fluid interactions: Formulation effects and in porous medium test,Interfacial phenomena; Dispersions; Emulsions; Wettability; Colloid aggregate,ASPHALTENE DEPOSITION; WATER; PERFORMANCE,"Precipitation of asphaltenes in oil fields represents interfacial phenomena of great concern for oil industry. Oil production decreases due to the obstruction of reservoir rock pores by asphaltene blockage. Futhermore, the phenomena of wettability changes and water/oil (W/O) emulsions formation take place in the production processes of crude oil. Herein, the performance and evaluation of a developed product (F2) based on the formulation of an asphaltene inhibitor to overcome these problems is presented. Different systems to assess the product were prepared with crude oil, synthetic formation water and the inhibitor product itself. These components were mixture under certening conditions according to simulated reservoir conditions. Displacement tests using F2 product in three different core samples were carried out. The results of asphaltenes dispersions tests (ADT) indicate that the product has a 100% dispersion effect on the asphaltenes, with a colloidal stability for more than 2 h in the presence of an excess of heptane. The product performance to break up W/O emulsions is evaluated, through the preparation of model systems with synthetic water. Water resolution results indicate that resultant emulsions have low stability. In addition, the interaction (adsorption and adhesion) between crude oil and glass surface was evaluated. Crude oil shows strong adsorption on the glass surface even after water washing. While in the presence of the inhibitor product there is lower adsorption and adherence weakness of crude oil was observed on glass surface. The performance observed within the porous medium after the product been injected at reservoir conditions, shows that the product F2 mitigates formation damages responsible for asphaltene formation and deposition. Observed increments on fluid permeability values after injection of F2 to the crude oil are indication of a greater oil flow in the rock reservoir sample. Based on these findings, it can be concluded that F2 product is a suitable candidate to be evaluated into porous media, as chemical treatment in matrix non-reactive stimulation operations.",0,0,2
Crude Oil,Asphaltene,"Beheshti, Elahe; Doryani, Hosein; Malayeri, Mohammad Reza; Riazi, Masoud",Asphaltene stability during heptane injection in a glass micromodel in the presence of Co3O4 nanoparticles,Nanoparticle; Asphaltene precipitation; Glass micromodel; Adsorption; Optimum concentration; Porous media,OIL; PRECIPITATION; DEPOSITION; ADSORPTION; RECOVERY; VISUALIZATION; DISPLACEMENT; AGGREGATION; OXIDATION; PRESSURE,"Severe challenges and difficulties in oil production may arise from asphaltene precipitation and deposition in porous media and upstream facilities. The investigation for a proper solution for such detrimental damages is indispensable for the oil industry. Nanoparticles, due to their unique properties of high degree of dispersibility and high adsorption affinity, may potentially be useful for hampering the asphaltene related problems to some extent. In this study, by the use of glass micromodels, the utilization of Co3O4 nanoparticles to stem asphaltene precipitation has been investigated. These nanoparticles were dispersed in synthetic solutions comprising of toluene, n-heptane and asphaltenes as well as crude oil. The prepared solutions were then subjected to n-heptane injection as asphaltene precipitator. The amount and extent of asphaltene precipitation and deposition in micromodels was then measured and analyzed. The results showed that Co3O4 nanoparticles positively affect asphaltene stability in both crude oil and synthetic solutions. However, it was found that once these nanoparticles adhere to glass surface, then intense asphaltene precipitation and deposition would take place. The impacts of nanoparticle concentration were also discerned through experiments for 0.01, 0.05 and 0.1 wt% concentrations of nanoparticles. It was obtained that generally, higher concentration of nanoparticles would reduce asphaltene precipitation intensity. However, due to very little difference between the efficiency of solutions containing 0.05 and 0.1 wt% in terms of increasing asphaltene stability, 0.05 wt% of dispersed nanoparticles was found to be the optimum concentration for preventing asphaltene precipitation and deposition. This study, for the first time, provides a micro visual study in order to observe the impacts of nanoparticles on the stability of asphaltene in crude oil and synthetic oil samples in a uniformly patterned glass micromodel.",0,0,3
Crude Oil,Interfacial Tension,"Alves, Caiua Araujo; Yanes, Jose Francisco Romero; Feitosa, Filipe Xavier; de Sant'Ana, Hosiberto Batista",Influence of asphaltenes and resins on water/model oil interfacial tension and emulsion behavior: Comparison of extracted fractions from crude oils with different asphaltene stability,Asphaltenes size; Resins; Oil stability; Interfacial tension; Emulsion stability,ADSORPTION-KINETICS; OIL/WATER INTERFACE; TEMPERATURE; AGGREGATION; REDUCTION; TIME,"Asphaltenes and resins make a major contribution for the formation of stable water-in-oil emulsions during crude production, which could affect process operations and increase costs. The purpose of this investigation is to study the influence of these molecular substances from two different crude oil samples (regarding asphaltene stability) on the water-model oil interfacial tension, along with their effect on the emulsion stability. Asphaltene stability of these crude oils presented a marked difference when studied in our past work, with asphaltene precipitation onset that vary from 56 to 75 n-heptane wt %, despite their similar SARA composition. This difference on asphaltene stability was contrasted in this work with the chemical characterization, interfacial activity, and emulsion behavior of crude oil asphaltenes, resins, and their mixtures using toluene solutions. For each crude oil, resins and asphaltenes were extracted and characterized by XRD, SEM/EDS, FTIR, and elemental analysis, to better understand their molecular structure and surface-active species content. Then, it was prepared different model oil solutions in toluene, varying the content of asphaltenes and resins (500, 1,000, and 2000 mg/L). Additionally, it was prepared 2000 mg/L asphaltene/resin mixtures with different ratios (75:25 wt%, 50:50 wt%, and 25:75 wt%). Dynamic interfacial tension between the model oil and water was measured by intermediate of a Du Nouy ring method. Afterward, each model system was emulsified by adding water (at the same volumetric ratio) in a bottle test and stability was analyzed. For the sample with lower stable asphaltenes, a rapid stabilization of the dynamic interfacial tension (IFT) was observed, together with a decrease of IFT from 26.8 to 24.2 mN/m at the limit of asphaltene content studied. On the contrary, for the high stable asphaltenes sample, a transient dynamic IFT behavior was observed, until reach 12.0 mN/m (the lower operational equipment limit). Similar results were obtained for resins model solutions for both crude oils tested. For asphaltene obtained from the sample with lower asphaltene stability, the emulsions presented high stability (for a 24 h test). Besides for the high asphaltene stability sample and resins model oils, all emulsions prepared were unstable. Useful insights are given by the oil fractions chemical characterization, suggesting that smaller sized molecules from high stable crude oils have a predominant effect on IFT reduction, while larger molecules from less stable oils are responsible for the emulsion stability.",0,0,1
Crude Oil,Interfacial Tension,"Li, Yi-Bo; Deng, Qing-Huan; Huang, Tao; Zhang, Ya-Qian; Pu, Wanfen; Zhao, Jin-Zhou",A numerical and experimental investigation into the influence of CO2 on the stability of W/O emulsion,CO2; W/O emulsion; Demulsification; Diffusion; Mathematical model,DROPLET SIZE DISTRIBUTION; CRUDE OIL-EMULSIONS; INTERFACIAL-TENSION; WATER; TEMPERATURE; MISCIBILITY; PRESSURE,"The formation of water in oil (W/O) emulsion can result in flow issues in the reservoir and a high cost of demulsification throughout the water treatment process. Without treatment, the W/O emulsion takes a long time to settle, which results in blockage in porous media. CO2 has strong interaction with crude oil and so has the potential to alter the settling process of W/O emulsion. The purpose of this paper is to undertake a numerical and experimental investigation into the influence of CO2 on the emulsion stability. To anticipate the settling process of a W/O emulsion in a high-pressure environment, a mathematical model was created that included a CO2 diffusion model, a viscosity prediction model, and an emulsion settling model. A high-pressure reactor was used to model the emulsion demulsification process at three different pressure conditions and to evaluate the model's prediction capability. The results indicate that under a high-pressure CO2 atmosphere, the demulsification process of a W/O emulsion can be accelerated. The CO2 dissolution and diffusion into the oil phase might enhance the likelihood of droplets colliding, resulting in the demulsification of the W/O emulsion system. Pressure has a significant influence on the stability of the emulsion. High pressure accelerates the CO2 dissolution process and significantly reduces the time required for the emulsion system to reach equilibrium. Additionally, the oil/water ratio can affect the stability of a W/O emulsion. At the same pressure, an emulsion with a higher oil/water ratio required a shorter time to reach equilibrium and had a higher equilibrium viscosity.",0,0,1
Crude Oil,Interfacial Tension,"Xu, Limin; Han, Ming; Cao, Dongqing; Wang, Jinxun",Study on dynamic interfacial tension behaviors in surfactant selection for improving oil production,Surfactant selection; Alkali free; Dynamic interfacial tension; Emulsion; Oil production,CRUDE-OIL; POLYMER; MECHANISMS; MIXTURES; SYSTEMS; ABILITY; PROFILE,"The selection of appropriate surfactants for improving oil production in chemical flooding relies considerably on the values of the interfacial tension (IFT) between surfactant solution and crude oil. This paper presents a study on the impact of the dynamic IFT on emulsifying capacity and oil production improvement. The dynamic IFT behaviors of anionic, nonionic, cationic and zwitterionic surfactants were measured against a light crude oil using a spinning drop tensiometer, and classified into two categories. A pair of surfactants with a similar equilibrium IFT value but different initial values were selected for comparative studies. The emulsification results suggest that the instantaneous emulsification, a key mechanism for oil mobilization, is mainly attributed to a quick initial IFT reduction, affecting oil productions. The results of micromodel tests using surfactants and coreflooding oil displacement experiments using surfactant-polymer mixtures indicate that the system has low initial IFT value achieves significantly higher incremental oil production than the system that has high initial IFT value. This suggests the surfactants that are able to reach quick initial IFT reduction are preferential for improving oil production applications.",0,0,1
Crude Oil,Interfacial Tension,"Aboelkhair, Hamed; Diaz, Pedro; Attia, Attia",Biosurfactant production using Egyptian oil fields indigenous bacteria for microbial enhanced oil recovery,Microbial enhanced oil recovery; Indigenous bacteria; Biosurfactant; Bacillus subtilis; Surface activity; Critical micelle concentration,BACILLUS-SUBTILIS; SURFACTANT; LICHENIFORMIS; OPTIMIZATION; WETTABILITY; HYDROCARBON; INJECTION; MOLASSES; STRAINS,"Biosurfactant production is one of the most efficient mechanisms in microbial enhanced oil recovery (MEOR) processes. This work investigates the production of biosurfactants by indigenous bacteria isolated from Egyptian oil fields, and how to optimize these produced biosurfactants for MEOR. 59 Egyptian oil reservoirs were screened to evaluate the potential applicability of MEOR processes, based on their rock and fluid properties. Results showed that 8 reservoirs from the Gulf of Suez and 3 reservoirs from the Western Desert had the potential to MEOR. Combined analysis of morphological, and biochemical characterization was performed on the 11 bacterial strains isolated from different crude oil samples collected from the reservoirs that have the potential to MEOR process to identify their types. Bacillus spp, a bacilli species that can produce biosurfactants, was selected for further studies. To optimize the surface activity of the produced biosurfactant, ten different reported nutrient media, and a new proposed nutrient media were examined. Bacillus spp has shown the ability to produce a very active biosurfactant that reduced the surface tension of water from 71.8 +/- 1.9 mN/m to 25.7 +/- 1.2 mN/m, and the interfacial tension of water against kerosene from 48.4 +/- 2.1 mN/m to 0.38 +/- 0.07 mN/m at Critical Micelle Concentration (CMC) of 0.04 +/- 0.01 g/l, in a medium supplemented by the new proposed nutrient medium H. The growth rate of Bacillus spp was studied, and it was found it reached its maximum (OD600nm 2.59 +/- 0.16) after 24 h of incubation. Biosurfactant production has no significant change in its surface activity over a wide range of temperature range up to 120 degrees C, which means the studied species Bacillus spp is a thermophilic bacterium. Bacillus spp grew well in the presence of high salt concentration up to 20% (w/v) NaCl, the optimal surface activity was obtained in the range of 0-2% (w/v) NaCl, and at pH 7. The emulsification activity of the produced biosurfactant was examined, and it reached the maximum (69.6 + 1.5%) against kerosene at temperature 25 degrees C, Salinity 0% (w/v) NaCl (distilled water), and pH 7. The produced biosurfactant was purified and extracted by acid precipitation method, and the biosurfactant yield of the purified compound was found to be 2.8 +/- 0.3 g/l. Finally, the core-flooding experiments were conducted to investigate the effect of produced biosurfactants by Bacillus subtilis in oil recovery. The obtained results reveal the potential of Bacillus spp to grow in the new proposed medium H and produce effective and efficient biosurfactants that enhanced oil recovery by 25.19-39.35% of additional oil over the water flooding residual oil saturation in the studied cores and retain more than 60% of its surface activity under harsh conditions and that are relevant to Microbial Enhanced Oil Recovery, MEOR.",0,0,2
Crude Oil,Interfacial Tension,"Sauerer, Bastian; Al-Hamad, Mohammed; Ma, Shouxiang Mark; Abdallah, Wael",Effect of formation water salinity on interfacial tension of reservoir fluids,Interfacial tension; Crude oil; Salinity; Formation water; Seawater,SURFACE-TENSION; DIVALENT SALTS; SYSTEMS; WETTABILITY; MONOVALENT; IONS,"The interaction of surface-active species within crude oil with ions in the aqueous phase can have a major influence on the interfacial tension (IFT) between these two phases. Herein, the influence of salinity on IFT is investigated systematically. Brines with different salinities, including seawater and reservoir formation water, are considered. The measurements clearly show distinct IFT trends depending on the composition and concentration of salts in the aqueous phase as well as on the crude oil chemical species, as represented by the API values. The results show that complex brine systems have a stronger effect on IFT than individual single salt brine systems. It is possible to derive distinct additive correction factors for the respective tested brine systems based on the averaged values of deviation from the respective cases in deionized water. On average for the tested 10 oils, and in comparison to measurements in DI water, IFT was reduced by 3.4 mN/m in 100 kppm CaCl2 solution, by 5.3 mN/m in 100 kppm NaCl solution, by 6.8 mN/m in formation water and by 8.2 mN/m in seawater.",0,0,2
Crude Oil,Interfacial Tension,"Santos, Denisson; Barros, Vanderson S.; Silva, Maria Luiza P.; Sales, Havila M. M. S.; Borges, Gustavo R.; Franceschi, Elton; Dariva, Claudio",Strontium-based low salinity water as an IOR/EOR method: Oil-brine interaction,Strontium based saline water; Low salinity water; Oil recovery; Interfacial properties,WETTABILITY ALTERATION; NAPHTHENIC ACIDS; INTERACTION MECHANISM; INTERFACIAL BEHAVIOR; IONIC-STRENGTH; CONTACT-ANGLE; PENDANT DROP; SMART-WATER; SURFACE; RECOVERY,"Strontium-based injection water for enhanced oil recovery has been neglected due to the low solubility of the cation in water. However, challenging reservoirs like those in the Brazilian pre-salt region demand nonconventional solutions to improve oil production. This work shows for the first time that the strontium cation in low salinity water solutions shall be henceforth considered as a potential component in the development of enhanced/improved oil recovery (EOR/IOR) studies. Acidic and non-acidic model oils and real crude oils from Brazilian post-salt and pre-salt fields were used for this study. The oil/brine interfacial tension and viscoelastic properties of the interfacial films were measured by an ascendant drop tensiometer. The results showed that strontium presents the highest interfacial activity among the other alkaline-earth metals. Also, the strontiumbased low salinity water produced the most elastic interfacial film, which is desired for the improvement of oil volumetric sweeping promoted by water flooding. Nonetheless, it is worth highlighting that further studies including core flooding experiments must be performed to assess the strontium effect on the crude oil outflow through reservoir pores as well as the influence of water/oil/rock interactions upon it.",0,0,3
Crude Oil,Interfacial Tension,"Pashapouryeganeh, Farzad; Zargar, Ghasem; Takassi, Mohammad Ali; kadkhodaie, Ali; Rabiee, Ahmad",One-Pot synthesis of modified-cationic surfactants for enhanced oil recovery applications in carbonate reservoirs,Surfactant synthesis; Cationic surfactant; Quaternary ammonium salt; Wettability alteration; IFT reduction; Chemical enhanced oil recovery (CEOR),INTERFACIAL-TENSION BEHAVIOR; DETERMINING IONS CA2+; HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; POROUS-MEDIA; CHAIN-LENGTH; WET; MECHANISM; LIQUID,"In this study two cationic surfactants, dodecyltriethylammoniumbromide (C(12)TEAB) and hexadecyl-triethylammoniumbromide (C(16)TEAB) were prepared. The formation of synthezied surfactants were confirmed using FTIR and HNMR spectroscopy. Electrical conductivity, interfacial tension and surface tension methods were used to determine the critical micelle concentrations (CMC) of these surfactants. To understand the behavior of synthesized surfactants in harsh environments, the CMC was measured in deionized water (DIW), sea water and petroleum formation water. Using electrical conductivity technique, for C(12)TEAB surfactant the CMC values of 4000 ppm, 2000 ppm and 850 ppm were recorded in DIW, sea water and formation water respectively. For C(16)TEAB surfactant, the CMC values of 420 ppm, 190 ppm and 115 ppm were obtained in DIW, sea water and formation water respectively. The similar CMC results were obtained using the interfacial tension (IFT) and surface tension (ST) methods. Reduction of IFT between crude oil and formation water and also alteration of wettability of petroleum reservoir of carbonated rock from oil-wet (large contact angle) to water-wet (small contact angle) are two major factors affecting chemical enhanced oil recovery (EOR). Interfacial tension (IFT), surface tension (ST) and contact angle measurements were carried out using an IFT-PDSA-06 apparatus (Apex Technologies Company, Iran). The IFT and ST of these surfactants were also carried out in DIW, sea water and formation water. For C(12)TEAB surfactant, the IFT values of 0.051 mN/m, 0.036 mN/m and 0.023 mN/m were recorded in DIW, sea water and formation water respectively. The IFT values of 0.044 mN/m, 0.026 mN/m and 0.0126 mN/m were measured for C(16)TEAB surfactant in DIW, sea water and formation water respectively. The effect of temperature on IFT was studied for both surfactants. When temperature increases, IFT decreases. The reduction of IFT continues up to 55 degrees C, then the IFT increases with increasing temperature. For C(12)TEAB surfactant, the ST values of 44.9 mN/m, 38.8 mN/m and 31.8 mN/m were obtained in DIW, sea water and formation water respectively. In similar measurements for C(16)TEAB surfactant, the recorded ST values were 33.95; 32.9 and 32.22 mN/m in DIW, sea water and formation water respectively. In wettability alteration study both surfactants altered the contact angle from oil-wet to water-wet conditions. Using formation water and C(12)TEAB surfactant, the contact angle varied from 96.4 degrees to 54.5 degrees. In similar study using C(16)TEAB surfactant the contact angle changed from 92 degrees to 46.1 degrees. The contact angles of these surfactants in DIW and sea water were also measured and reported. The results of IFT and wettability studies demonstrated excellent potential application of synthesized surfactants in EOR process in carbonate petroleum reservoirs.",0,0,3
Crude Oil,Calculation,"Gaganis, Vassilis; Marinakis, Dimitris; Samnioti, Anna",A soft computing method for rapid phase behavior calculations in fluid flow simulations,Phase stability; Phase split; Equilibrium coefficients; Flow simulation; Phase equilibrium calculations acceleration,OPERATOR-BASED LINEARIZATION; FLASH CALCULATIONS; ROBUST ALGORITHM; CUBIC EQUATIONS; CRUDE-OIL; K-VALUES; 2-PHASE; MULTICOMPONENT; FRAMEWORK; MIXTURES,"To describe the flow of hydrocarbons in the reservoir and in pipelines upstream petroleum engineers utilize compositional simulation models which allow for the accurate description of complex phase behavior phenomena by means of EoS models and detailed compositional characterization. To speed up the conventional time-consuming phase stability and phase split calculations, soft computing has been recently utilized by means of methods such as proxy models and on-the-fly tabulation of phase behavior results. In this work, a new soft computing pressure-explicit, adaptive interpolation technique is presented which allows for the direct, offline, non-iterative estimation of fluid specific equilibrium coefficients values as functions of the conditions prevailing during the process to be modeled. The so calculated equilibrium coefficients allow for the rapid determination of the number, composition and properties of the phases present in every cell and at every timestep by means of the Rachford-Rice equation, thus greatly reducing the CPU time required for phase equilibrium calculations. Moreover, the proposed method guarantees continuous first and second order phase properties derivatives with respect to p and T. The method is applicable to any type of EoS including the SRK and the PR ones. The method is fully applicable to depletion projects of all types of oil and gas condensates. Additionally, it can be used for the history matching of the past depletion phase of oil and gas reservoirs before the initiation of EOR projects such as acid or sour gas injection as well as before dry gas reinjection in gas condensate reservoirs.",0,0,0
Crude Oil,Calculation,"Sulaimon, Aliyu Adebayo; Falade, Gabriel Kayode",New two-phase and three-phase thermodynamic models for predicting wax precipitation in hydrocarbon mixtures,Thermodynamic model; Continuous gamma distribution function; Thermodynamic property correlation; Wax appearance temperature; Hydrocarbon mixtures; Absolute deviation,CRUDE OILS; ASPHALTENE; DEPOSITION; TEMPERATURE; EQUILIBRIA; PRESSURE,"One of the major issues in flow assurance is the precipitation and subsequent deposition of paraffin wax in petroleum production systems. A new two-phase multicomponent thermodynamic model based on a continuous thermodynamic phase equilibria employing a three-parameter gamma distribution function has been developed to predict the wax appearance temperature (WAT), the amount of precipitated wax, and the wax content of crude oils. Also, a generalized three-phase multicomponent thermodynamic model based on the combined polymer and regular solution theories of mixtures as well as on equations of state (EOS) is presented. The model utilizes the solid-liquid-vapour phase equilibrium relations with some constraint functions. Furthermore, hinged on the regression analysis of published experimental data, a new set of molecular-weight-dependent thermodynamic properties' correlations were developed and used to calculate the solid-liquid-equilibrium-ratios (K-i(S-L)) for the individual component. The models were validated with data obtained from experiments conducted on 32 different hydrocarbon fluids from the Niger Delta, North Sea, Gulf of Mexico, East Asia, and Middle East fields. Results show that the gamma distribution parameters (alpha, beta, eta) can be used to classify hydrocarbon mixtures into three categories: light oils or condensate, waxy oil or asphaltenic oils, and biodegraded oils. Analysis shows that when compared with experimental data, the two-phase thermodynamic model is reliable with the average absolute deviations (AAD%) of 0.80% for paraffinic and waxy oils, 0.42% for paraffinic and waxy condensates, and 4.33% for paraffinic-asphaltenic and biodegraded oils. For the three-phase model, results show that the AAD% for the paraffinic and waxy oils, paraffinic and waxy condensates, and biodegraded oils are 0.93%, 1.03%, and 4.88% respectively. However, the two models slightly overestimate the WAT for biodegraded crude oils. Nevertheless, the generalized thermodynamic models developed have proved to be effective for predicting the onset conditions for wax precipitation during petroleum production and processing. It will prove a helpful tool for the fast and accurate assessment of wax deposition tendencies of hydrocarbon mixtures.",0,0,1
Crude Oil,Calculation,"Ayuba, Nuhu; da Silva, Luciano Silva; Lopes, Toni Jefferson",Fouling monitoring in oil-water flow using density profile,Oil fouling; Laminar level-set; Density flow profile; Water lubricated transportation; Plug flow; Core annular flow (CAF),LEVEL SET METHOD; 2-PHASE FLOW; ALGORITHMS; SIMULATION,"In water lubricated transportation of heavy crude oil, fouling monitoring on the walls of the pipe is fundamental, since it reflects in the cost of transportation. Although such phenomenon has been discussed by many researchers, more of experimental and theoretical evaluations have been carried out than numerical ones. For this reason, this work was aimed at using laminar Level-set (numerical method) to identify oil fouling (through oil density magnitude identification) on the upper and lower walls of a round horizontal pipe during water lubricated transportation. In order to achieve such objective, fluid constants (found in literature) and operational conditions established experimentally were applied to simulate and observe the density flow profiles along the upper and lower walls of a 2D pipe. Prior to the simulation process, a grid convergence test was carried out in order to establish a mesh which was capable of representing the flow characteristics, and at the same time reducing computational cost. Additionally, laminar Level-set was validated through comparing Reynolds numbers obtained from its application to analytical values calculated at the same conditions. Two main volumetric flow profiles (plug and core-annular flow- CAF) with their respective density profiles were obtained. In both cases, oil fouling was identified at specific regions of the pipe's upper and lower walls, presenting densities closer to 918.8 kg/m(3).",0,0,1
Crude Oil,Calculation,"Ghasemi, Mohammad; Whitson, Curtis H.",PVT modeling of complex heavy oil mixtures,Equation of state (EOS); Extra heavy oil (or bitumen; Saturated oil viscosity; Solvent solubility; Single-carbon-number (SCN),ATHABASCA BITUMEN; GAS SOLUBILITY; VISCOSITY; PETROLEUM; STEAM,"This paper describes a systematic approach to model the phase and volumetric behavior of extra heavy oil and light solvent mixtures for a wide range of temperatures. A cubic equation of state (EOS) is first developed using crude assay data. We use a modified Jacoby correlation to describe the relationship of specific gravity and molecular weight for the heavy oil sample. A gamma molar distribution model is used to fit the crude assay data, then single-carbon-number (SCN) fractions are defined up to C90+. The Twu correlation is used for estimating SCN critical properties, including C90+, resulting in an EOS with 89 components. Pure solvent-crude oil mixture PVT experimental data are analyzed and used to tune the EOS model. The resulting model reproduces accurately all phase and volumetric behavior of pure-solvent-crude mixtures. The prediction of the final EOS model provides accurate prediction against measured PVT data for mixtures of extra-heavy oil sample and synthetic combustion gas solvents made up of CO2, N2, C1, and C2. For viscosity modeling, we propose a novel technique to model large variation of viscosity for a wide range of pressures, temperatures and solvent compositions. In our proposed approach, the LBC (Lorenz-Bray-Clark) correlation is used, with SCN critical volumes modified individually to ensure the LBC correlation estimates SCN viscosities as given by a modified Twu correlation. The viscosity predictions of the pure-solvent-saturated heavy oil at varying temperatures, the EOS/LBC model results in poor agreement against measured saturated viscosity data. Our solution was to split the heaviest fraction C90+ into two sub-fractions, where only critical volumes differ, resulting in ""lower-viscous"" and ""higher-viscous"" C90+ fractions (C90+L into C90+H). We find that the fraction of C90+L (fL) correlates well against pure solvent solubility and temperature, resulting in an accurate overall viscosity fit. The final EOS/LBC model is successfully employed to predict measured PVT and viscosity data that was not used during the training process. Our new approach can provide accurate phase properties and volumetric behavior calculations and as well as good predictions of large variation of liquid viscosity. Such developed EOS technique is vital for providing an accurate estimation of phase behavior and volumetric properties, and the viscosity variations required for modeling thermal-EOR techniques.",0,0,1
Crude Oil,Calculation,"Asbaghi, Ehsan Vahabzadeh; Assareh, Mehdi; Nazari, Farzaneh",An effective procedure for wax formation modeling using multi-solid approach and PC-SAFT EOS for petroleum fluids with PNA characterization,Petroleum cuts; Multi-solid approach; Wax precipitation; PC-SAFT; PNA Analysis,EQUATION-OF-STATE; PERTURBED-CHAIN SAFT; SEA CRUDE OILS; DIRECTIONAL ATTRACTIVE FORCES; THERMODYNAMIC MODEL; PHASE-EQUILIBRIA; ASPHALTENE PRECIPITATION; LIQUID-EQUILIBRIA; N-ALKANES; PLUS,"Several experiments and thermodynamic models are developed to prevent Wax precipitation. Paraffinic hydrocarbons participate to a greater extent in the precipitation process than other hydrocarbon families. However, the existing models do not distinguish these hydrocarbon families, leading to the overestimation or underestimation of wax precipitation parameters. To address this problem, we will use a predictive Paraffin, Naphthene, and Aromatic (PNA) estimation technique to split the petroleum fractions that avoids using average properties for petroleum fractions. A sequential multi-solid approach is also implemented for the thermodynamic analysis of wax precipitation. The perturbed chain statistical associating fluid theory (PC-SAFT) equation of state (EOS) is utilized to calculate liquid properties. The binary interaction coefficients (BIC) of non-paraffin hydrocarbons are modified to improve the model's accuracy for calculating wax weight and wax appearance temperature (WAT). Six crudes from the North Sea are selected to evaluate the reliability of the proposed model. The contribution of each hydrocarbons family in the precipitation process is investigated. The results show a considerable improvement compared to previous models. The predicted WAT presents a slight deviation from the experimental data. In addition, the outcome of this work is compared to the modeling works from two reliable references. The average estimation error of wax weight for all crude oils is about 0.19. This deviation increases to 0.36 and 0.38 for the works of the first and second reference, in turn.",0,0,1
Crude Oil,Calculation,"Vinay, Guillaume; Bhaskoro, Petrus Tri; Henaut, Isabelle; Sariman, Mior Zaiga; Anuar, Astriyana; Shafian, Siti Rohaida M.",A methodology to investigate factors governing the restart pressure of a Malaysian waxy crude oil pipeline,Waxy crude oil; Gelling; Numerical simulation; Rheology; Restart pressure,STARTUP FLOW; MODEL,"Waxy crude oils account for about 20% of world oil reserves. Wax gelation due to pipeline operating at low ambient temperature, especially in subsea environment, is a worst-case scenario that operators fear most since the gel can potentially block the entire pipeline, if it is not managed early. Restart pressure calculation is the first step to assess severity of gelation and subsequently used to plan for the mitigation strategies which are translated into project CAPEX (Capital Expenditure) and OPEX (Operating Expenditure). Gel characteristic (i.e. rheology behaviour and gel compressibility), operating conditions (oil temperature, ambient temperature and oil flow rate) and pipeline geometry (length and diameter) are known factors governing the restart pressure calculation for a gelled waxy pipeline. Malaysian waxy crude oils are unique and have distinctive rheology which differ from waxy crude oils from other regions mainly due to high gel yield stress of more than 500 Pa with potential failure to recovery from gelation. Hence, accurate restart pressure prediction that account for all the governing factors as well as the interplay between them, are crucial for safe operation and cost-effective mitigation strategies. A conservative approach where the entire gel is assumed to yield simultaneously is frequently used but this simple approach fails to take into account many factors, resulting in an overestimation of the restart pressure. Several improved restart pressure calculation methods have been proposed in literature. In this study, an original methodology developed by IFPEN, has been applied to predict the restart pressure of a Malaysian waxy crude oil pipeline at various conditions. The main benefit of this methodology comes from its ability to consider the conditions under which the gel has been formed, that produces a more realistic description where gel strength varies along a pipeline. The case study highlighted that Conservative laws, assuming a homogeneous gel structure everywhere in the pipe, can overestimate the restart pressure by a factor of up to 100 times than a heterogenous gel. Thanks to the 2D axisymmetric description of the pipeline gel, we showed that the shape and the location of the gel also impact the restart pressure.",0,0,2
Crude Oil,Calculation,"Zhao, Haining; Song, Chuanzhen; Zhang, Hui; Di, Chaojie; Tian, Zhen",Improved fluid characterization and phase behavior approaches for gas flooding and application on Tahe light crude oil system,Direct PnA fluid characterization; Vaporizing-gas drive; C/V-gas drive; Multiple-mixing-cell; MMP,MIXING-CELL METHOD; RESERVOIR FLUIDS; DISPLACEMENT; MISCIBILITY; PETROLEUM; PRESSURE; MULTICOMPONENT; PERTURBATION; SIMULATION; INJECTION,"N-2 or N-2/CO2 mixture is considered as injection gas to enhance oil recovery from Tahe oil field. The reservoir pressure and temperature are around 66 MPa and 414 K. The target light crude oil is produced from S117 well of the Tahe oil field. The two main objectives of this study are: 1) to find an effective fluid characterization procedure to calculate the MMP for the N-2/CO2-S117 oil system accurately. 2) to identify the effect of injection gas composition (i.e. N-2/CO2 mixture) on the gas drive mechanisms for the S117 light crude oil. The PVT and multiple-contact experimental data were measured and these data were used to characterize and validate different fluid characterization methods, including the 'conventional methods' and the direct PnA method. We proposed an integrated fluid characterization procedure to accurately calculate MMP. The novelty of the proposed fluid characterization procedure can be summarized as: 1) the procedure regains excellent match in both phase envelopes and critical points before and after lumping; 2) an improved direct PnA regression procedure with only two perturbation parameters was used to calculate pseudo-component properties. The comparison of calculated MMP to the experimental slim-tube data taken from literature shows that the integrated procedure using the direct PnA characterization has the best performance on MMP calculation. For the CO2/N-2-S117 system, the vaporizing-gas drive mechanism controls the miscibility provided the CO2 mole fraction in the injection gas is less than 70%. The calculated MMP is independent of the CO(2 )mole fraction within the range approximately from 0 to 70% in the injection gas. At a higher CO2 mole fraction (ranging from 71% to 100%), the complex condensing/vaporizing (C/V)-gas drive mechanism dominates the miscibility and thus the MMP of the fluid system decreases dramatically as CO2 mole fraction increases.",0,0,2
Crude Oil,Calculation,"Li, Rongbin; Huang, Qiyu; Zhu, Xiangrui; Zhang, Dongxu; Lv, Yang; Larson, Ronald G.",Investigation of delayed formation of wax deposits in polyethylene pipe using a flow-loop,Wax deposition; Contact angle; Delayed formation; Adhesion; Sloughing; Wax content,OPERATING-CONDITIONS; BREAKING FORCE; LAMINAR-FLOW; CRUDE; WATER; INHIBITORS; PERFORMANCE; PIPELINES; SURFACES; MODEL,"After the start of the flow in a home-built flow-loop, the thickness of a waxy layer deposited on a stainless steel (SS) test section was found to increase immediately, while deposition was delayed for around 4 h on a polyethylene (PE) test section. The radial thermal gradient, wax precipitation rate, radial diffusivity of wax, and shear stresses at the surface of the deposit layer were calculated, eliminating these factors as sources of different deposition behavior. However, the contact angles of oils containing precipitated wax crystals on PE surfaces were found to increase more with increasing wax content than those on SS surfaces. Consistent with this, while the wax contents of deposits were found to be around 18 wt % for both PE and SS pipes, the adhesion of the deposit on the PE surface was found to be much weaker than on the SS surface, as evidenced by the easier of removal of the deposit from PE than from SS pipes when heated in vertical orientation under gravity. These results point to pipe wall wettability as a significant factor in both initial growth of wax deposit, and ease of removal.",0,0,2
Crude Oil,Core,"Aslanidis, Panagiotis; Strand, Skule; Torrijos, Ivan D. Pinerez; Puntervold, Tina",Reproducing wettability in sandstone reservoir core material in laboratory core restorations,Core analysis; Core restoration; Core cleaning; Smart water; FOR; Wettability,OIL; COMPONENTS; ADSORPTION,"Replicating initial reservoir wettability conditions in core restoration by core cleaning and fluid restoration in the laboratory is of great importance. There are several core cleaning and restoration protocols used in the oil industry and academia that include the usage of different equipment, techniques, and materials. Strong solvents used in core cleaning can remove material that is part of the rock phase leading to more water-wet behavior. Large volumes of crude oil exposure in core restorations can result in high adsorption of polar organic components onto the mineral surfaces giving less water-wet behavior. Therefore, sufficient core cleaning should be targeted, involving no physical damage to the solid rock phase and effective crude oil exposure securing realistic water saturations, avoiding overexposure of crude oil. The objective of this study was to establish an optimum core restoration process in terms of cleaning solvents and the amount of crude oil exposure, to re-establish the same core wettability from one core restoration to the next. Seven sandstone cores from a reservoir on the Norwegian Continental Shelf underwent a series of core restorations. Two different core cleaning procedures were used, in which mild (kerosene/heptane) and strong (toluene/methanol) solvents were involved, and furthermore, the cores were exposed to various volumes of crude oil. Spontaneous imbibition experiments showed that mild core cleaning in combination with 5 pore volumes or more crude oil exposure rendered the cores less water-wet in successive core restorations. More rigorous cleaning with 5 pore volumes of crude oil exposure rendered the cores more water-wet in successive core restorations. From spontaneous imbibition results it was concluded that an optimum core restoration procedure involving mild cleaning and only 1 pore volume of crude oil exposure successfully reproduced core wettability in successive experiments.",0,0,0
Crude Oil,Core,"Ayuba, Nuhu; da Silva, Luciano Silva; Lopes, Toni Jefferson",Fouling monitoring in oil-water flow using density profile,Oil fouling; Laminar level-set; Density flow profile; Water lubricated transportation; Plug flow; Core annular flow (CAF),LEVEL SET METHOD; 2-PHASE FLOW; ALGORITHMS; SIMULATION,"In water lubricated transportation of heavy crude oil, fouling monitoring on the walls of the pipe is fundamental, since it reflects in the cost of transportation. Although such phenomenon has been discussed by many researchers, more of experimental and theoretical evaluations have been carried out than numerical ones. For this reason, this work was aimed at using laminar Level-set (numerical method) to identify oil fouling (through oil density magnitude identification) on the upper and lower walls of a round horizontal pipe during water lubricated transportation. In order to achieve such objective, fluid constants (found in literature) and operational conditions established experimentally were applied to simulate and observe the density flow profiles along the upper and lower walls of a 2D pipe. Prior to the simulation process, a grid convergence test was carried out in order to establish a mesh which was capable of representing the flow characteristics, and at the same time reducing computational cost. Additionally, laminar Level-set was validated through comparing Reynolds numbers obtained from its application to analytical values calculated at the same conditions. Two main volumetric flow profiles (plug and core-annular flow- CAF) with their respective density profiles were obtained. In both cases, oil fouling was identified at specific regions of the pipe's upper and lower walls, presenting densities closer to 918.8 kg/m(3).",0,0,1
Crude Oil,Core,"Aboelkhair, Hamed; Diaz, Pedro; Attia, Attia",Biosurfactant production using Egyptian oil fields indigenous bacteria for microbial enhanced oil recovery,Microbial enhanced oil recovery; Indigenous bacteria; Biosurfactant; Bacillus subtilis; Surface activity; Critical micelle concentration,BACILLUS-SUBTILIS; SURFACTANT; LICHENIFORMIS; OPTIMIZATION; WETTABILITY; HYDROCARBON; INJECTION; MOLASSES; STRAINS,"Biosurfactant production is one of the most efficient mechanisms in microbial enhanced oil recovery (MEOR) processes. This work investigates the production of biosurfactants by indigenous bacteria isolated from Egyptian oil fields, and how to optimize these produced biosurfactants for MEOR. 59 Egyptian oil reservoirs were screened to evaluate the potential applicability of MEOR processes, based on their rock and fluid properties. Results showed that 8 reservoirs from the Gulf of Suez and 3 reservoirs from the Western Desert had the potential to MEOR. Combined analysis of morphological, and biochemical characterization was performed on the 11 bacterial strains isolated from different crude oil samples collected from the reservoirs that have the potential to MEOR process to identify their types. Bacillus spp, a bacilli species that can produce biosurfactants, was selected for further studies. To optimize the surface activity of the produced biosurfactant, ten different reported nutrient media, and a new proposed nutrient media were examined. Bacillus spp has shown the ability to produce a very active biosurfactant that reduced the surface tension of water from 71.8 +/- 1.9 mN/m to 25.7 +/- 1.2 mN/m, and the interfacial tension of water against kerosene from 48.4 +/- 2.1 mN/m to 0.38 +/- 0.07 mN/m at Critical Micelle Concentration (CMC) of 0.04 +/- 0.01 g/l, in a medium supplemented by the new proposed nutrient medium H. The growth rate of Bacillus spp was studied, and it was found it reached its maximum (OD600nm 2.59 +/- 0.16) after 24 h of incubation. Biosurfactant production has no significant change in its surface activity over a wide range of temperature range up to 120 degrees C, which means the studied species Bacillus spp is a thermophilic bacterium. Bacillus spp grew well in the presence of high salt concentration up to 20% (w/v) NaCl, the optimal surface activity was obtained in the range of 0-2% (w/v) NaCl, and at pH 7. The emulsification activity of the produced biosurfactant was examined, and it reached the maximum (69.6 + 1.5%) against kerosene at temperature 25 degrees C, Salinity 0% (w/v) NaCl (distilled water), and pH 7. The produced biosurfactant was purified and extracted by acid precipitation method, and the biosurfactant yield of the purified compound was found to be 2.8 +/- 0.3 g/l. Finally, the core-flooding experiments were conducted to investigate the effect of produced biosurfactants by Bacillus subtilis in oil recovery. The obtained results reveal the potential of Bacillus spp to grow in the new proposed medium H and produce effective and efficient biosurfactants that enhanced oil recovery by 25.19-39.35% of additional oil over the water flooding residual oil saturation in the studied cores and retain more than 60% of its surface activity under harsh conditions and that are relevant to Microbial Enhanced Oil Recovery, MEOR.",0,0,2
Crude Oil,Core,"Cobos, Jacquelin E.; Sandnes, Martine; Steinsbo, Marianne; Brattekas, Bergit; Sogaard, Erik G.; Graue, Arne",Evaluation of wettability alteration in heterogeneous limestone at microscopic and macroscopic levels,Dynamic aging; Static aging; Wettability alteration; Fluid-fluid interactions; Rock-fluid interactions,NAPHTHENIC ACIDS; MODEL COMPOUNDS; OUTCROP CHALK; OIL; STRENGTH,"Wettability controls the location, distribution, and flow of fluids in a pore network. Obtaining a uniform core scale wettability distribution is therefore a necessary condition for reliable special core analysis (SCAL). In the present work, dynamic and static aging procedures were used to alter the wettability of outcrop Edwards limestone, and Amott-Harvey cycles were performed on whole and split core samples to evaluate wetting distribution and stability. Dynamic aging was observed to be more efficient and produced a more uniform and reproducible wettability distribution compared to static aging. Rock-fluid and fluid-fluid interactions, evaluated by Isothermal Titration Calorimetry (ITC) experiments, confirm that supplying fresh crude oil during the aging procedure to a core plug causes the greatest wettability change. Synergy between ITC and simple core scale experiments provide an improved understanding of the wettability alteration at microscopic and macroscopic levels in heterogeneous Edwards limestone.",0,0,2
Crude Oil,Core,"Velasquez, Ingrid; Silva, Iris; Martinez, Lesbia; Rattia, Luz; Labrador, Henry; Villanueva, Ivan; Perez, Victor; Aguero, Bari; Gonzalez, Maria; Monroy, Ruth; Bejarano, Celia; Milano, Eliecer; Mendoza, German; Pereira, Juan",Interfacial phenomena in petroleum reservoir conditions related to fluid-fluid interactions and rock-fluid interactions: Formulation effects and in porous medium test,Interfacial phenomena; Dispersions; Emulsions; Wettability; Colloid aggregate,ASPHALTENE DEPOSITION; WATER; PERFORMANCE,"Precipitation of asphaltenes in oil fields represents interfacial phenomena of great concern for oil industry. Oil production decreases due to the obstruction of reservoir rock pores by asphaltene blockage. Futhermore, the phenomena of wettability changes and water/oil (W/O) emulsions formation take place in the production processes of crude oil. Herein, the performance and evaluation of a developed product (F2) based on the formulation of an asphaltene inhibitor to overcome these problems is presented. Different systems to assess the product were prepared with crude oil, synthetic formation water and the inhibitor product itself. These components were mixture under certening conditions according to simulated reservoir conditions. Displacement tests using F2 product in three different core samples were carried out. The results of asphaltenes dispersions tests (ADT) indicate that the product has a 100% dispersion effect on the asphaltenes, with a colloidal stability for more than 2 h in the presence of an excess of heptane. The product performance to break up W/O emulsions is evaluated, through the preparation of model systems with synthetic water. Water resolution results indicate that resultant emulsions have low stability. In addition, the interaction (adsorption and adhesion) between crude oil and glass surface was evaluated. Crude oil shows strong adsorption on the glass surface even after water washing. While in the presence of the inhibitor product there is lower adsorption and adherence weakness of crude oil was observed on glass surface. The performance observed within the porous medium after the product been injected at reservoir conditions, shows that the product F2 mitigates formation damages responsible for asphaltene formation and deposition. Observed increments on fluid permeability values after injection of F2 to the crude oil are indication of a greater oil flow in the rock reservoir sample. Based on these findings, it can be concluded that F2 product is a suitable candidate to be evaluated into porous media, as chemical treatment in matrix non-reactive stimulation operations.",0,0,2
Crude Oil,Core,"Santos, Denisson; Barros, Vanderson S.; Silva, Maria Luiza P.; Sales, Havila M. M. S.; Borges, Gustavo R.; Franceschi, Elton; Dariva, Claudio",Strontium-based low salinity water as an IOR/EOR method: Oil-brine interaction,Strontium based saline water; Low salinity water; Oil recovery; Interfacial properties,WETTABILITY ALTERATION; NAPHTHENIC ACIDS; INTERACTION MECHANISM; INTERFACIAL BEHAVIOR; IONIC-STRENGTH; CONTACT-ANGLE; PENDANT DROP; SMART-WATER; SURFACE; RECOVERY,"Strontium-based injection water for enhanced oil recovery has been neglected due to the low solubility of the cation in water. However, challenging reservoirs like those in the Brazilian pre-salt region demand nonconventional solutions to improve oil production. This work shows for the first time that the strontium cation in low salinity water solutions shall be henceforth considered as a potential component in the development of enhanced/improved oil recovery (EOR/IOR) studies. Acidic and non-acidic model oils and real crude oils from Brazilian post-salt and pre-salt fields were used for this study. The oil/brine interfacial tension and viscoelastic properties of the interfacial films were measured by an ascendant drop tensiometer. The results showed that strontium presents the highest interfacial activity among the other alkaline-earth metals. Also, the strontiumbased low salinity water produced the most elastic interfacial film, which is desired for the improvement of oil volumetric sweeping promoted by water flooding. Nonetheless, it is worth highlighting that further studies including core flooding experiments must be performed to assess the strontium effect on the crude oil outflow through reservoir pores as well as the influence of water/oil/rock interactions upon it.",0,0,3
Crude Oil,Source Rocks,"Zhang, Zhiyao; Zhu, Guangyou; Han, Jianfa; Sun, Chonghao; Huang, Chuanyan; Li, Jingfei; Zhao, Kun","Genesis and preservation of the giant ultradeep Hadexun petroleum accumulation in the Tarim Basin, China",Ultradeep strata; Liquid petroleum; Diamondoids; Thermal cracking; Tarim basin,2-DIMENSIONAL GAS-CHROMATOGRAPHY; NW CHINA; TAZHONG AREA; HYDROCARBON EXPLORATION; PHASE FRACTIONATION; TABEI UPLIFT; OIL CRACKING; SOURCE ROCKS; CRUDE OILS; ORIGIN,"Reservoired liquid petroleum has limited potential to be preserved under high temperature conditions due to thermal cracking and potentially thermochemical sulfate reduction, and thus exploration targets in ultradeep strata are mainly gas and condensate gas. However, a giant ultradeep liquid petroleum accumulation, with an average depth of >6500 m, was discovered recently in the Hadexun area, Tarim Basin. In this study, integrated geochemical analyses were conducted on the black oil samples from the Hadexun area. Intact terpanes and steranes and low concentration of diamondoids were detected, indicating that these oils were generated at peak oil window and were barely altered by secondary geochemical process (thermal cracking or others) despite their depth. The associated wet gas with light isotopic profiles was classified as mature oil-derived gas co-generated with the oil. Petroleum accumulation analyses suggested that the favorable carbonate reservoir bodies in the Middle Ordovician Yijianfang Formation were attributed to karstification and weathering, and mainly distributed along the major strike-slip fault belts. Together with the thick mudstones in the overlying Upper Ordovician Sangtamu Formation, they formed a favorable reservoir-seal assemblage in the Hadexun area. Massive volumes of liquid petroleum were generated and expelled from the Lower Cambrian black shales in the Late Hercynian and migrated into the Ordovician carbonate reservoirs through the strike-slip fault system, and subsequently were exposed to stable tectonic conditions. Due to the rapid subsidence since the Neogene, insufficient temperature-time exposure eliminated the impact of thermal cracking; therefore, the petroleum accumulation was preserved in the liquid phase, and further indicates that huge petroleum resource potential remains in ultradeep strata in the Tarim Basin.",0,0,0
Crude Oil,Source Rocks,"Wang, Feilong; Tang, Guomin; Wang, Deying; Pan, Wenjing; Yang, Hong; Awan, Rizwan Sarwar",Paleoenvironmental characteristics and evidence of subsag migration within the Laizhouwan Sag in the Bohai Sea,Sag-migration; Paleoenvironment; Paleoproductivity; Palynofacies; Laizhouwan sag; Bohai sea,DEPOSITIONAL ENVIRONMENT; SHALE; OIL,"The Laizhouwan Sag comprises many sets of source rocks, and their crude oil properties are complex and changeable. This research evaluates the quality of source rocks using mudstone samples of the Shahejie Formation from typical wells from northern and southern subsags by incorporating a detailed organic-inorganic geochemical, palynology and petrological analysis. Moreover, it analyzes the difference between the paleoenvironment and paleoproductivity. It also discusses the migration characteristics of the sag in combination with seismic data to reveal the fundamental reason for the complex oil source characteristics of the Laizhouwan sag. The results show there are two sets of effective source rocks in the northern subsag of the Laizhouwan Sag, (i) the third member of the Shahejie Formation(E2s3) (ii) the fourth member of the Shahejie Formation (E2s4). Additionally, the E2s4 is a high-quality, effective source rock in the southern subsag of Laizhouwan Sag. (2) During the sedimentary period of the E2s4 in Laizhouwan Sag, the water bodies of the southern and northern subsags were separated. The organic matter (OM) in the E2s4 of northern subsag mainly comes from lower algae, mainly amorphous, and deposited in a weak reducing environment of brackish water. The OM in the E2s4 of southern subsags mainly comes from terrigenous higher plants, mainly composed of terrigenous amorphous assemblages, and it was deposited in a strongly reducing environment of brackish water to saline water. (3) Moreover, the water bodies of the southern and northern subsags gradually changed to unified water bodies during the sedimentary period of the E2s3. During this period, OM comes from lower algae, mainly from amorphous material, and the water bodies were transformed to a weak oxidation-reduction environment from freshwater-brackish water. The subsidence center of the Laizhouwan sag continued to move southward during the sedimentary period of E2s4-E2s3. Gradually the southern subsag became a sedimentary center containing higher paleoproductivity and eutrophic lake settings. The differences in organic source, sedimentary environment and paleoproductivity of source rocks in different subsags lead to the complexity of crude oil generation features.",0,0,1
Crude Oil,Source Rocks,"Zheng, Ruihui; Zhang, Guanlong; Qu, Yansheng; Wang, Shengzhu; Jin, Xiao; Chen, Xue; Zhang, Zhihuan","Oil-source correlation under the complex geological conditions: A case study of the Chaiwopu Sag, southern Junggar Basin, NW China",Unconventional resource; Biodegradation; Hydrocarbon inclusion; Carbon isotope; Oil-source correlation,QUANTITATIVE FLUORESCENCE TECHNIQUES; LASER-SCANNING MICROSCOPY; FLUID INCLUSIONS; CRUDE OILS; CHARGE HISTORY; PETROLEUM; GEOCHEMISTRY; ENVIRONMENTS; SEDIMENTARY; MATURATION,"Slightly (PM 1) to very strongly (PM 9) biodegraded crude oil was discovered in the reservoir of the Tashikula Formation in the eastern Chaiwopu Sag. The origin of oil in the eastern Chaiwopu Sag remains unclear due to different degrees of biodegradation and multi-stage nappe structure. In this study, the geochemical data from crude oil, source rocks and hydrocarbon inclusions are used to establish the correlations between oils and source rocks under complex geological conditions. The characteristics of biomarkers, isotopes and hydrocarbon inclusions reveal two stages of hydrocarbon charging in the eastern Chaiwopu Sag. Hydrocarbons formed during the first charging stage has low maturity and a relatively light carbon isotope composition, and its relative abundance of C20-23 tricyclic terpanes follows the sequence: C23 C21> C20. Hydrocarbons formed during the second charging stage is characterized by relatively high maturity and heavy carbon isotope composition, and the corresponding abundance of C20-23 tricyclic terpanes is C23< C21< C20. The biomarkers and isotopic characteristics of crude oil, source rocks and hydrocarbon inclusions reveal the hydrocarbons formed during the first charging stage originated from the Lucaogou Formation in the northern Chaiwopu Sag and the northern Bogeda Mountains, and those formed during the second charging stage originated from the Lucaogou Formation in the central Chaiwopu Sag. The high-quality source rocks and reservoirs of the Lucaogou Formation were deposited in the northern Chaiwopu Sag, which has great potential for tight/shale oil exploration.",0,0,2
Crude Oil,Source Rocks,"El Diasty, W. Sh.; Moldowan, J. M.; Peters, K. E.; Hammad, M. M.; Essa, G. I.","Organic geochemistry of possible Middle Miocene-Pliocene source rocks in the west and northwest Nile Delta, Egypt",Miocene-Pliocene rocks; Biomarkers; Chemometrics; MRM-GCMS; WDDM; Nile Delta,CRUDE OILS; TETRACYCLIC POLYPRENOIDS; NATURAL-GAS; PETROLEUM; BASIN; ISOMERIZATION; SEDIMENTATION; INDICATORS; BIOMARKER; SYSTEM,"An important step for any frontier basin source rock survey is to understand the natural variability of geochemical characteristics within the source intervals. No previous studies addressed the molecular characteristics of organic matter or the source rock potential in the west and northwest onshore/offshore portion of the Nile Delta province. For this reason, the current work used geochemical proxies, including Rock-Eval/TOC screening analyses, gas chromatography-mass spectrometry, and metastable reaction monitoring mass spectrometry to examine the type and origin of the disseminated organic matter, thermal maturity, and depositional environments of the Miocene-Pliocene sediments in this basin. Results show fair-very good organic content for the Miocene Sidi Salem and Abu Madi rock samples compared to the Pliocene Kafr El Sheikh and El Wastani samples that generally show low TOC with fair-good organic content. The low organic content recoded in the Pliocene rocks may be due to high rates of sedimentation associated with elastic dilution and microbial degradation, typical of deltaic environments. In general, kerogen in the samples has high proportions of gas or non-generating and recycled organic materials and is dominantly of fluvial or deltaic origin. The analyzed source rocks exhibit a wide range of organic matter quality varying from Type-III, Type-II/III, to Type-IV kerogens. The molecular findings suggest mixed-source input from planktonic-bacterial and land plants with significant algal contributions to the source rock facies. This is based on high C-30 24-n-propylcholestanes, C(27 )cholestanes and C-29 stigmastanes, moderate tetracyclic polyprenoid (TPP) ratios, and low oleanane and gammacerane. The most striking biomarkers are high bicadinane and 24-norcholestane ratios. Local differences related to facies variation in the source depositional environment result in significant variations in biomarker characteristics. Pyrolysis T-max sterane isomerizations %20S and %beta beta, moretane/hopane ratios, and C-32 homohopane %22S suggest immature to maturity near the beginning of the oil window. Five genetic families were identified among the extract samples using hierarchical cluster analysis (HCA) and principal component analysis (PCA) based on 15 source-related biomarker ratios. Some of these families are questionable because of low TOC, significant differences in maturity between the extracts and condensates, and possible contamination by diesel additive. However, five rocks from the Miocene Sidi Salem Formation contain elevated TOC (1.22-2.25 wt%) and HI (366-458 mg HC/g TOC) and the extracts show no evidence of significant contamination in the biomarker range of molecular weight and good correlation with four WDDM-14 (2739, 2854, 2804, and 2870 m) oils in the offshore Rosetta and Abu Qir oilfields.",0,0,2
Crude Oil,Source Rocks,"Song, Jianyang; Chen, Tao; Zhang, Jinliang","Permian and Triassic hydrocarbon migration and accumulation in the Cainan area, Junggar Basin, China",QGF; Migration; Fault; Biomarker; Source rock,CRUDE OILS; MOLECULAR-PARAMETERS; NITROGEN-COMPOUNDS; TOARCIAN SHALES; SOURCE ROCKS; PARIS BASIN; FLUID-FLOW; PETROLEUM; FIELD; DISTRIBUTIONS,"Gas Chromatography-Mass Spectrometer (GC-MS), chloroform asphalt ""A"", and carbon isotope measurements were used to determine hydrocarbon migration pathways. This study focused on hydrocarbon migration pathways and accumulation distribution in the Wucaiwan region, Junggar Basin, China. The biometric parameters were used to compare oil sources. Type and distribution characteristics of natural gas were determined in order to study the different strata. Quantitative grain fluorescence (QGF) and quantitative grain fluorescence on extract (QGF-E) were analyzed to determine the hydrocarbon migration and charging periods. Geochemical indexes, such as, n-alkane, triterpenoids, sterane, and hopane, were utilized to investigate the pathways of hydrocarbon migration. Recent studies on petroleum maturity have focused on comparison of source rocks and reported that the maturity effects of source rock and reservoir oil are weak, while those effects are high in the Liuchu area. Analysis of triterpenoid and steroid hydrocarbon biomarkers elucidate the underground petroleum migration pathways to the reservoirs. Geochemical analyses of hopane and cholestanes were used. The alpha alpha alpha C29 (20 S)/(20 S + 20 R), C29 beta beta/(alpha alpha + beta beta), and C31 hopane 22R/C30 hoopane ratios, and C19/C21 tricyclic terpane ratio, C19/C21 tricyclic terpenes, C31 (22 S)/(22 S + 22 R), and C29 (20 S)/(20 S + 20 R) ratios were analyzed to determine the maturity of crude oil. Petroleum migrated along fault, sandbody, and unconformity, which suggest vertical and lateral migration occurred. Reservoir sandstone porosity and mudstone content of the thick caprock are likely to limit lateral hydrocarbon migration. Petroleum migration and accumulation primarily occurred by vertical migration and lateral migration was weak. The study offers an improved understanding of uncertain hydrocarbon migration pathways and further developed the hydrocarbon migration and accumulation models.",0,0,3
Crude Oil,Correlation,"Sulaimon, Aliyu Adebayo; Falade, Gabriel Kayode",New two-phase and three-phase thermodynamic models for predicting wax precipitation in hydrocarbon mixtures,Thermodynamic model; Continuous gamma distribution function; Thermodynamic property correlation; Wax appearance temperature; Hydrocarbon mixtures; Absolute deviation,CRUDE OILS; ASPHALTENE; DEPOSITION; TEMPERATURE; EQUILIBRIA; PRESSURE,"One of the major issues in flow assurance is the precipitation and subsequent deposition of paraffin wax in petroleum production systems. A new two-phase multicomponent thermodynamic model based on a continuous thermodynamic phase equilibria employing a three-parameter gamma distribution function has been developed to predict the wax appearance temperature (WAT), the amount of precipitated wax, and the wax content of crude oils. Also, a generalized three-phase multicomponent thermodynamic model based on the combined polymer and regular solution theories of mixtures as well as on equations of state (EOS) is presented. The model utilizes the solid-liquid-vapour phase equilibrium relations with some constraint functions. Furthermore, hinged on the regression analysis of published experimental data, a new set of molecular-weight-dependent thermodynamic properties' correlations were developed and used to calculate the solid-liquid-equilibrium-ratios (K-i(S-L)) for the individual component. The models were validated with data obtained from experiments conducted on 32 different hydrocarbon fluids from the Niger Delta, North Sea, Gulf of Mexico, East Asia, and Middle East fields. Results show that the gamma distribution parameters (alpha, beta, eta) can be used to classify hydrocarbon mixtures into three categories: light oils or condensate, waxy oil or asphaltenic oils, and biodegraded oils. Analysis shows that when compared with experimental data, the two-phase thermodynamic model is reliable with the average absolute deviations (AAD%) of 0.80% for paraffinic and waxy oils, 0.42% for paraffinic and waxy condensates, and 4.33% for paraffinic-asphaltenic and biodegraded oils. For the three-phase model, results show that the AAD% for the paraffinic and waxy oils, paraffinic and waxy condensates, and biodegraded oils are 0.93%, 1.03%, and 4.88% respectively. However, the two models slightly overestimate the WAT for biodegraded crude oils. Nevertheless, the generalized thermodynamic models developed have proved to be effective for predicting the onset conditions for wax precipitation during petroleum production and processing. It will prove a helpful tool for the fast and accurate assessment of wax deposition tendencies of hydrocarbon mixtures.",0,0,1
Crude Oil,Correlation,"Ahmed, Syed Amjad; John, Bibin",Predictive correlations for heat transfer characteristics of oil-water horizontal pipe flow-an experimental study,convective heat transfer; oil-water flow; stratified flow; dispersed flow,LIQUID-LIQUID DISPERSIONS; CRUDE-OIL; DEPOSITION; VISCOSITY; PATTERNS,"This paper presents convective heat transfer characteristics of liquid-liquid horizontal pipe flow. Experiments are carried out in a stainless-steel pipe of diameter 1.59 cm with L/D ratio of 377. Three different oils with varying properties (viscosity: 630 mPa-s, 202 mPa-s and 1.95 mPa-s and density: 919 kg/m3, 901 kg/m3 and 790 kg/m3 respectively) are employed as oil phase and the other fluid phase being water. The experiments are conducted for four oil-water flow patterns-stratified flow, stratified flow with droplets at the interface, dispersed oil-in-water and dispersed water-in-oil with fluid fractions ranging 0 to 1 at different fluid velocities. A constant temperature heat supply, using jacketed hot water flowing over the test pipe, is maintained. The analysis of heat transfer experiments indicates that the heat transfer process in liquid-liquid flow depends on the same dimensionless terms, the Reynolds number and the Prandtl number, that signifies single-phase flow heat transfer. Accordingly, it is found that the established and existing single-phase heat transfer correlations, modified according to flow regime, flow pattern and fluid flow and thermal properties, are also applicable for liquid-liquid flow. The heat transfer in liquid-liquid flow found to be influenced by the fluid fraction. Effectively, for stratified flow, the heat transfer in the liquid-liquid flow is the sum of heat transfer of the individual fluid phases. However, for dispersed flow, the presence of additional fluid phase is incorporated by employing the effective Reynolds number and effective Prandtl number. Using this methodology, more than 85% of stratified flow and 92% of dispersed flow heat transfer characteristics are predicted within +/- 20% of experimental data.",0,0,1
Crude Oil,Correlation,"Ghasemi, Mohammad; Whitson, Curtis H.",PVT modeling of complex heavy oil mixtures,Equation of state (EOS); Extra heavy oil (or bitumen; Saturated oil viscosity; Solvent solubility; Single-carbon-number (SCN),ATHABASCA BITUMEN; GAS SOLUBILITY; VISCOSITY; PETROLEUM; STEAM,"This paper describes a systematic approach to model the phase and volumetric behavior of extra heavy oil and light solvent mixtures for a wide range of temperatures. A cubic equation of state (EOS) is first developed using crude assay data. We use a modified Jacoby correlation to describe the relationship of specific gravity and molecular weight for the heavy oil sample. A gamma molar distribution model is used to fit the crude assay data, then single-carbon-number (SCN) fractions are defined up to C90+. The Twu correlation is used for estimating SCN critical properties, including C90+, resulting in an EOS with 89 components. Pure solvent-crude oil mixture PVT experimental data are analyzed and used to tune the EOS model. The resulting model reproduces accurately all phase and volumetric behavior of pure-solvent-crude mixtures. The prediction of the final EOS model provides accurate prediction against measured PVT data for mixtures of extra-heavy oil sample and synthetic combustion gas solvents made up of CO2, N2, C1, and C2. For viscosity modeling, we propose a novel technique to model large variation of viscosity for a wide range of pressures, temperatures and solvent compositions. In our proposed approach, the LBC (Lorenz-Bray-Clark) correlation is used, with SCN critical volumes modified individually to ensure the LBC correlation estimates SCN viscosities as given by a modified Twu correlation. The viscosity predictions of the pure-solvent-saturated heavy oil at varying temperatures, the EOS/LBC model results in poor agreement against measured saturated viscosity data. Our solution was to split the heaviest fraction C90+ into two sub-fractions, where only critical volumes differ, resulting in ""lower-viscous"" and ""higher-viscous"" C90+ fractions (C90+L into C90+H). We find that the fraction of C90+L (fL) correlates well against pure solvent solubility and temperature, resulting in an accurate overall viscosity fit. The final EOS/LBC model is successfully employed to predict measured PVT and viscosity data that was not used during the training process. Our new approach can provide accurate phase properties and volumetric behavior calculations and as well as good predictions of large variation of liquid viscosity. Such developed EOS technique is vital for providing an accurate estimation of phase behavior and volumetric properties, and the viscosity variations required for modeling thermal-EOR techniques.",0,0,1
Crude Oil,Correlation,"Zheng, Ruihui; Zhang, Guanlong; Qu, Yansheng; Wang, Shengzhu; Jin, Xiao; Chen, Xue; Zhang, Zhihuan","Oil-source correlation under the complex geological conditions: A case study of the Chaiwopu Sag, southern Junggar Basin, NW China",Unconventional resource; Biodegradation; Hydrocarbon inclusion; Carbon isotope; Oil-source correlation,QUANTITATIVE FLUORESCENCE TECHNIQUES; LASER-SCANNING MICROSCOPY; FLUID INCLUSIONS; CRUDE OILS; CHARGE HISTORY; PETROLEUM; GEOCHEMISTRY; ENVIRONMENTS; SEDIMENTARY; MATURATION,"Slightly (PM 1) to very strongly (PM 9) biodegraded crude oil was discovered in the reservoir of the Tashikula Formation in the eastern Chaiwopu Sag. The origin of oil in the eastern Chaiwopu Sag remains unclear due to different degrees of biodegradation and multi-stage nappe structure. In this study, the geochemical data from crude oil, source rocks and hydrocarbon inclusions are used to establish the correlations between oils and source rocks under complex geological conditions. The characteristics of biomarkers, isotopes and hydrocarbon inclusions reveal two stages of hydrocarbon charging in the eastern Chaiwopu Sag. Hydrocarbons formed during the first charging stage has low maturity and a relatively light carbon isotope composition, and its relative abundance of C20-23 tricyclic terpanes follows the sequence: C23 C21> C20. Hydrocarbons formed during the second charging stage is characterized by relatively high maturity and heavy carbon isotope composition, and the corresponding abundance of C20-23 tricyclic terpanes is C23< C21< C20. The biomarkers and isotopic characteristics of crude oil, source rocks and hydrocarbon inclusions reveal the hydrocarbons formed during the first charging stage originated from the Lucaogou Formation in the northern Chaiwopu Sag and the northern Bogeda Mountains, and those formed during the second charging stage originated from the Lucaogou Formation in the central Chaiwopu Sag. The high-quality source rocks and reservoirs of the Lucaogou Formation were deposited in the northern Chaiwopu Sag, which has great potential for tight/shale oil exploration.",0,0,2
Crude Oil,Correlation,"Ayoub, Mohammed Abdalla; Elhadi, A.; Fatherlhman, Diab; Saleh, M. O.; Alakbari, Fahd Saeed; Mohyaldinn, Mysara Eissa",A new correlation for accurate prediction of oil formation volume factor at the bubble point pressure using Group Method of Data Handling approach,Group method of data handling; Oil formation volume factor; PVT properties; The curse of dimensionality; Statistical analyses; Graphical analyses,PVT PROPERTIES,"Pressure-Volume-Temperature (PVT) crude oil properties play a significant role in reservoir evaluation and field planning. PVT properties are usually determined through laboratory experiments on representative fluid samples. However, during the preliminary stages of exploration and appraisal, such data might not be available; hence, it is frequent to use empirical correlations to predict PVT properties. Oil formation volume factor (FVF) is one of the PVT properties used to convert the measured oil flow rate from surface conditions to reservoir conditions. In this paper, the Group Method of Data Handling (GMDH) has been used to predict the oil FVF at the bubble point pressure as a function of gas solubility, reservoir temperature, oil API gravity, and gas specific gravity. A total of 625 data sets were collected from published literature. Then, the data were divided into four sets: training, validation, testing, and deployment, with the ratio of 2:1:1:1. The results of the proposed correlation are compared against seven other correlations used in the petroleum industry. Also, trend analysis has been performed to confirm that the proposed correlation is physically sound. From the results, the proposed correlation is proven to accurately predict the oil FVF at the bubble point pressure with an average absolute percentage error AAPE of 1.333% and correlation coefficient of 0.995 for the deployment set.",0,0,2
Crude Oil,Correlation,"El Diasty, W. Sh.; Moldowan, J. M.; Peters, K. E.; Hammad, M. M.; Essa, G. I.","Organic geochemistry of possible Middle Miocene-Pliocene source rocks in the west and northwest Nile Delta, Egypt",Miocene-Pliocene rocks; Biomarkers; Chemometrics; MRM-GCMS; WDDM; Nile Delta,CRUDE OILS; TETRACYCLIC POLYPRENOIDS; NATURAL-GAS; PETROLEUM; BASIN; ISOMERIZATION; SEDIMENTATION; INDICATORS; BIOMARKER; SYSTEM,"An important step for any frontier basin source rock survey is to understand the natural variability of geochemical characteristics within the source intervals. No previous studies addressed the molecular characteristics of organic matter or the source rock potential in the west and northwest onshore/offshore portion of the Nile Delta province. For this reason, the current work used geochemical proxies, including Rock-Eval/TOC screening analyses, gas chromatography-mass spectrometry, and metastable reaction monitoring mass spectrometry to examine the type and origin of the disseminated organic matter, thermal maturity, and depositional environments of the Miocene-Pliocene sediments in this basin. Results show fair-very good organic content for the Miocene Sidi Salem and Abu Madi rock samples compared to the Pliocene Kafr El Sheikh and El Wastani samples that generally show low TOC with fair-good organic content. The low organic content recoded in the Pliocene rocks may be due to high rates of sedimentation associated with elastic dilution and microbial degradation, typical of deltaic environments. In general, kerogen in the samples has high proportions of gas or non-generating and recycled organic materials and is dominantly of fluvial or deltaic origin. The analyzed source rocks exhibit a wide range of organic matter quality varying from Type-III, Type-II/III, to Type-IV kerogens. The molecular findings suggest mixed-source input from planktonic-bacterial and land plants with significant algal contributions to the source rock facies. This is based on high C-30 24-n-propylcholestanes, C(27 )cholestanes and C-29 stigmastanes, moderate tetracyclic polyprenoid (TPP) ratios, and low oleanane and gammacerane. The most striking biomarkers are high bicadinane and 24-norcholestane ratios. Local differences related to facies variation in the source depositional environment result in significant variations in biomarker characteristics. Pyrolysis T-max sterane isomerizations %20S and %beta beta, moretane/hopane ratios, and C-32 homohopane %22S suggest immature to maturity near the beginning of the oil window. Five genetic families were identified among the extract samples using hierarchical cluster analysis (HCA) and principal component analysis (PCA) based on 15 source-related biomarker ratios. Some of these families are questionable because of low TOC, significant differences in maturity between the extracts and condensates, and possible contamination by diesel additive. However, five rocks from the Miocene Sidi Salem Formation contain elevated TOC (1.22-2.25 wt%) and HI (366-458 mg HC/g TOC) and the extracts show no evidence of significant contamination in the biomarker range of molecular weight and good correlation with four WDDM-14 (2739, 2854, 2804, and 2870 m) oils in the offshore Rosetta and Abu Qir oilfields.",0,0,2
Crude Oil,Phase Behavior,"Gaganis, Vassilis; Marinakis, Dimitris; Samnioti, Anna",A soft computing method for rapid phase behavior calculations in fluid flow simulations,Phase stability; Phase split; Equilibrium coefficients; Flow simulation; Phase equilibrium calculations acceleration,OPERATOR-BASED LINEARIZATION; FLASH CALCULATIONS; ROBUST ALGORITHM; CUBIC EQUATIONS; CRUDE-OIL; K-VALUES; 2-PHASE; MULTICOMPONENT; FRAMEWORK; MIXTURES,"To describe the flow of hydrocarbons in the reservoir and in pipelines upstream petroleum engineers utilize compositional simulation models which allow for the accurate description of complex phase behavior phenomena by means of EoS models and detailed compositional characterization. To speed up the conventional time-consuming phase stability and phase split calculations, soft computing has been recently utilized by means of methods such as proxy models and on-the-fly tabulation of phase behavior results. In this work, a new soft computing pressure-explicit, adaptive interpolation technique is presented which allows for the direct, offline, non-iterative estimation of fluid specific equilibrium coefficients values as functions of the conditions prevailing during the process to be modeled. The so calculated equilibrium coefficients allow for the rapid determination of the number, composition and properties of the phases present in every cell and at every timestep by means of the Rachford-Rice equation, thus greatly reducing the CPU time required for phase equilibrium calculations. Moreover, the proposed method guarantees continuous first and second order phase properties derivatives with respect to p and T. The method is applicable to any type of EoS including the SRK and the PR ones. The method is fully applicable to depletion projects of all types of oil and gas condensates. Additionally, it can be used for the history matching of the past depletion phase of oil and gas reservoirs before the initiation of EOR projects such as acid or sour gas injection as well as before dry gas reinjection in gas condensate reservoirs.",0,0,0
Crude Oil,Phase Behavior,"Aslanidis, Panagiotis; Strand, Skule; Torrijos, Ivan D. Pinerez; Puntervold, Tina",Reproducing wettability in sandstone reservoir core material in laboratory core restorations,Core analysis; Core restoration; Core cleaning; Smart water; FOR; Wettability,OIL; COMPONENTS; ADSORPTION,"Replicating initial reservoir wettability conditions in core restoration by core cleaning and fluid restoration in the laboratory is of great importance. There are several core cleaning and restoration protocols used in the oil industry and academia that include the usage of different equipment, techniques, and materials. Strong solvents used in core cleaning can remove material that is part of the rock phase leading to more water-wet behavior. Large volumes of crude oil exposure in core restorations can result in high adsorption of polar organic components onto the mineral surfaces giving less water-wet behavior. Therefore, sufficient core cleaning should be targeted, involving no physical damage to the solid rock phase and effective crude oil exposure securing realistic water saturations, avoiding overexposure of crude oil. The objective of this study was to establish an optimum core restoration process in terms of cleaning solvents and the amount of crude oil exposure, to re-establish the same core wettability from one core restoration to the next. Seven sandstone cores from a reservoir on the Norwegian Continental Shelf underwent a series of core restorations. Two different core cleaning procedures were used, in which mild (kerosene/heptane) and strong (toluene/methanol) solvents were involved, and furthermore, the cores were exposed to various volumes of crude oil. Spontaneous imbibition experiments showed that mild core cleaning in combination with 5 pore volumes or more crude oil exposure rendered the cores less water-wet in successive core restorations. More rigorous cleaning with 5 pore volumes of crude oil exposure rendered the cores more water-wet in successive core restorations. From spontaneous imbibition results it was concluded that an optimum core restoration procedure involving mild cleaning and only 1 pore volume of crude oil exposure successfully reproduced core wettability in successive experiments.",0,0,0
Crude Oil,Phase Behavior,"Ghasemi, Mohammad; Whitson, Curtis H.",PVT modeling of complex heavy oil mixtures,Equation of state (EOS); Extra heavy oil (or bitumen; Saturated oil viscosity; Solvent solubility; Single-carbon-number (SCN),ATHABASCA BITUMEN; GAS SOLUBILITY; VISCOSITY; PETROLEUM; STEAM,"This paper describes a systematic approach to model the phase and volumetric behavior of extra heavy oil and light solvent mixtures for a wide range of temperatures. A cubic equation of state (EOS) is first developed using crude assay data. We use a modified Jacoby correlation to describe the relationship of specific gravity and molecular weight for the heavy oil sample. A gamma molar distribution model is used to fit the crude assay data, then single-carbon-number (SCN) fractions are defined up to C90+. The Twu correlation is used for estimating SCN critical properties, including C90+, resulting in an EOS with 89 components. Pure solvent-crude oil mixture PVT experimental data are analyzed and used to tune the EOS model. The resulting model reproduces accurately all phase and volumetric behavior of pure-solvent-crude mixtures. The prediction of the final EOS model provides accurate prediction against measured PVT data for mixtures of extra-heavy oil sample and synthetic combustion gas solvents made up of CO2, N2, C1, and C2. For viscosity modeling, we propose a novel technique to model large variation of viscosity for a wide range of pressures, temperatures and solvent compositions. In our proposed approach, the LBC (Lorenz-Bray-Clark) correlation is used, with SCN critical volumes modified individually to ensure the LBC correlation estimates SCN viscosities as given by a modified Twu correlation. The viscosity predictions of the pure-solvent-saturated heavy oil at varying temperatures, the EOS/LBC model results in poor agreement against measured saturated viscosity data. Our solution was to split the heaviest fraction C90+ into two sub-fractions, where only critical volumes differ, resulting in ""lower-viscous"" and ""higher-viscous"" C90+ fractions (C90+L into C90+H). We find that the fraction of C90+L (fL) correlates well against pure solvent solubility and temperature, resulting in an accurate overall viscosity fit. The final EOS/LBC model is successfully employed to predict measured PVT and viscosity data that was not used during the training process. Our new approach can provide accurate phase properties and volumetric behavior calculations and as well as good predictions of large variation of liquid viscosity. Such developed EOS technique is vital for providing an accurate estimation of phase behavior and volumetric properties, and the viscosity variations required for modeling thermal-EOR techniques.",0,0,1
Crude Oil,Phase Behavior,"Bahu, Juliana Otavia; Miranda, Nahieh Toscano; Khouri, Nadia Gagliardi; Batistella, Cesar Benedito; Cardenas Concha, Viktor Oswaldo; Wolf Maciel, Maria Regina; Rocha Barbosa Schiavon, Maria Ingrid; Maciel Filho, Rubens",Crude oil emulsion breaking: An investigation about gravitational and rheological stability under demulsifiers action,Bottle test; Dehydration; Demulsifier testing; Emulsion breaking; Rheology; Stability,PETROLEUM EMULSIONS; DROPLET SIZE; WATER; LIGHT; METHODOLOGY; TEMPERATURE; SURFACTANTS; PERFORMANCE; VISCOSITY; SALINITY,"Emulsions are common in the oil industry, being present in the extraction and production stages. Its formation occurs with the contact of brine and crude oil under intense flow. The presence of emulsified water (dispersed droplet size, phi <= 50 mu m) in crude oil can negatively impact its exploration, transportation, and refining, making transportation more expensive, requiring more energy for heating, and causing equipment corrosion on all processes. In addition, crude oil has salts and sediments that encrust and corrode equipment of the primary oil treatment unit and distillation towers, also causing catalyst poisoning in the cracking step. Therefore, such components need to be removed for subsequent refining processes. To prevent these problems, the dehydration/ desalting of crude oils is a strategy adopted to reach adequate values of water, salts, and sediments required in the refineries for the next steps after primary treatment. However, the emulsion breaking is influenced by several factors that affect the stability of crude oil (W/O emulsion), such as viscosity, contents of water, salts, sediments, and natural surfactants, among others. Given this perspective, this work investigated the stability of two different types of crude oils with demulsifier under the action of gravity (bottle test) and shear stress (rheology). The comparisons of gravitational and rheological techniques concluded that the shear stress sweep analyses are useful to evaluate the demulsifier performance in the emulsion breaking, being a reliable and fast methodology. Such studies allowed the identification of adequate parameters: temperature (80 degrees C) and, demulsifier type and quantity (500 ppm) for efficient crude oil phase separation, without using washing water. The physicochemical and rheological characterizations clarified the crude oil's colloidal stability behavior to understand the impurities' influence on the oils' properties (crude and desalted).",0,0,2
Crude Oil,Phase Behavior,"Zhao, Haining; Song, Chuanzhen; Zhang, Hui; Di, Chaojie; Tian, Zhen",Improved fluid characterization and phase behavior approaches for gas flooding and application on Tahe light crude oil system,Direct PnA fluid characterization; Vaporizing-gas drive; C/V-gas drive; Multiple-mixing-cell; MMP,MIXING-CELL METHOD; RESERVOIR FLUIDS; DISPLACEMENT; MISCIBILITY; PETROLEUM; PRESSURE; MULTICOMPONENT; PERTURBATION; SIMULATION; INJECTION,"N-2 or N-2/CO2 mixture is considered as injection gas to enhance oil recovery from Tahe oil field. The reservoir pressure and temperature are around 66 MPa and 414 K. The target light crude oil is produced from S117 well of the Tahe oil field. The two main objectives of this study are: 1) to find an effective fluid characterization procedure to calculate the MMP for the N-2/CO2-S117 oil system accurately. 2) to identify the effect of injection gas composition (i.e. N-2/CO2 mixture) on the gas drive mechanisms for the S117 light crude oil. The PVT and multiple-contact experimental data were measured and these data were used to characterize and validate different fluid characterization methods, including the 'conventional methods' and the direct PnA method. We proposed an integrated fluid characterization procedure to accurately calculate MMP. The novelty of the proposed fluid characterization procedure can be summarized as: 1) the procedure regains excellent match in both phase envelopes and critical points before and after lumping; 2) an improved direct PnA regression procedure with only two perturbation parameters was used to calculate pseudo-component properties. The comparison of calculated MMP to the experimental slim-tube data taken from literature shows that the integrated procedure using the direct PnA characterization has the best performance on MMP calculation. For the CO2/N-2-S117 system, the vaporizing-gas drive mechanism controls the miscibility provided the CO2 mole fraction in the injection gas is less than 70%. The calculated MMP is independent of the CO(2 )mole fraction within the range approximately from 0 to 70% in the injection gas. At a higher CO2 mole fraction (ranging from 71% to 100%), the complex condensing/vaporizing (C/V)-gas drive mechanism dominates the miscibility and thus the MMP of the fluid system decreases dramatically as CO2 mole fraction increases.",0,0,2
Crude Oil,Wax Deposition,"Sulaimon, Aliyu Adebayo; Falade, Gabriel Kayode",New two-phase and three-phase thermodynamic models for predicting wax precipitation in hydrocarbon mixtures,Thermodynamic model; Continuous gamma distribution function; Thermodynamic property correlation; Wax appearance temperature; Hydrocarbon mixtures; Absolute deviation,CRUDE OILS; ASPHALTENE; DEPOSITION; TEMPERATURE; EQUILIBRIA; PRESSURE,"One of the major issues in flow assurance is the precipitation and subsequent deposition of paraffin wax in petroleum production systems. A new two-phase multicomponent thermodynamic model based on a continuous thermodynamic phase equilibria employing a three-parameter gamma distribution function has been developed to predict the wax appearance temperature (WAT), the amount of precipitated wax, and the wax content of crude oils. Also, a generalized three-phase multicomponent thermodynamic model based on the combined polymer and regular solution theories of mixtures as well as on equations of state (EOS) is presented. The model utilizes the solid-liquid-vapour phase equilibrium relations with some constraint functions. Furthermore, hinged on the regression analysis of published experimental data, a new set of molecular-weight-dependent thermodynamic properties' correlations were developed and used to calculate the solid-liquid-equilibrium-ratios (K-i(S-L)) for the individual component. The models were validated with data obtained from experiments conducted on 32 different hydrocarbon fluids from the Niger Delta, North Sea, Gulf of Mexico, East Asia, and Middle East fields. Results show that the gamma distribution parameters (alpha, beta, eta) can be used to classify hydrocarbon mixtures into three categories: light oils or condensate, waxy oil or asphaltenic oils, and biodegraded oils. Analysis shows that when compared with experimental data, the two-phase thermodynamic model is reliable with the average absolute deviations (AAD%) of 0.80% for paraffinic and waxy oils, 0.42% for paraffinic and waxy condensates, and 4.33% for paraffinic-asphaltenic and biodegraded oils. For the three-phase model, results show that the AAD% for the paraffinic and waxy oils, paraffinic and waxy condensates, and biodegraded oils are 0.93%, 1.03%, and 4.88% respectively. However, the two models slightly overestimate the WAT for biodegraded crude oils. Nevertheless, the generalized thermodynamic models developed have proved to be effective for predicting the onset conditions for wax precipitation during petroleum production and processing. It will prove a helpful tool for the fast and accurate assessment of wax deposition tendencies of hydrocarbon mixtures.",0,0,1
Crude Oil,Wax Deposition,"Li, Rongbin; Huang, Qiyu; Zhu, Xiangrui; Zhang, Dongxu; Lv, Yang; Larson, Ronald G.",Investigation of delayed formation of wax deposits in polyethylene pipe using a flow-loop,Wax deposition; Contact angle; Delayed formation; Adhesion; Sloughing; Wax content,OPERATING-CONDITIONS; BREAKING FORCE; LAMINAR-FLOW; CRUDE; WATER; INHIBITORS; PERFORMANCE; PIPELINES; SURFACES; MODEL,"After the start of the flow in a home-built flow-loop, the thickness of a waxy layer deposited on a stainless steel (SS) test section was found to increase immediately, while deposition was delayed for around 4 h on a polyethylene (PE) test section. The radial thermal gradient, wax precipitation rate, radial diffusivity of wax, and shear stresses at the surface of the deposit layer were calculated, eliminating these factors as sources of different deposition behavior. However, the contact angles of oils containing precipitated wax crystals on PE surfaces were found to increase more with increasing wax content than those on SS surfaces. Consistent with this, while the wax contents of deposits were found to be around 18 wt % for both PE and SS pipes, the adhesion of the deposit on the PE surface was found to be much weaker than on the SS surface, as evidenced by the easier of removal of the deposit from PE than from SS pipes when heated in vertical orientation under gravity. These results point to pipe wall wettability as a significant factor in both initial growth of wax deposit, and ease of removal.",0,0,2
Crude Oil,Wax Deposition,"Amiri-Ramsheh, Behnam; Safaei-Farouji, Majid; Larestani, Aydin; Zabihi, Reza; Hemmati-Sarapardeh, Abdolhossein",Modeling of wax disappearance temperature (WDT) using soft computing approaches: Tree-based models and hybrid models,Solid scales; Wax disappearance temperature; Multilayer perceptron; Random forest; ANFIS; Leverage approach,HIGH-PRESSURE; PHASE-EQUILIBRIA; CRUDE OILS; PREDICTION; PRECIPITATION; OPTIMIZATION; ALGORITHM; DEPOSITION; ANFIS,"Solid scales can cause significant problems in oil production and transmission systems such as oil flow rate reduction. Wax is one of the most critical substances that are highly prone to precipitate and deposit in oil pipelines. This occurrence typically happens in low temperatures, and can extremely affect the flow rate. In the wax deposition process, wax disappearance temperature (WDT) is a crucial factor since it denotes the lowest temperature, at which wax deposits melt and the consequences of wax deposition vanish. In this research, smart models were utilized to predict WDT as a function of molar mass and pressure according to a comprehensive database. The proposed intelligent models are radial basis function (RBF) and multilayer perceptron (MLP) neural networks, adaptive neuro-fuzzy inference system (ANFIS), random forest (RF), extra tree (ET), and decision tree (DT). The MLP networks were trained with Bayesian Regularization (BR) and Levenberg-Marquardt (LM) algorithms, and the ANFIS models were coupled with three optimization algorithms, namely Cultural Algorithm (CA), Biogeography-based Optimization (BBO), and Teaching-Learning-Based Optimization (TLBO). Results demonstrate that the developed RF model could present an outstanding performance and provide predictions for WDT with the lowest average absolute percent relative error (AAPRE = 0.246%), the maximum coefficient of determination (for predicting = 0.993), and minimum root mean squared error (RMSE = 1.01). Trend analysis showed that increasing pressure and molar mass leads to wax disappearance temperature increase. Lastly, outlier discovery was performed using the Leverage approach to recognize the suspected data points. The outlier detection found that only 6 points (out of 346) are located in the upper and lower suspected data zones.",0,0,2
Crude Oil,Wax Deposition,"Wang, Mibang; Yang, Shenglai; Li, Jiajun; Zheng, Zuhao; Wen, Jing; Ma, Quanzheng; Wang, Qian; Chen, Hao",Cold water-flooding in a heterogeneous high-pour-point oil reservoir using computerized tomography scanning: Characteristics of flow channel and trapped oil distribution,High-PPT live oil; CT-Scanning; Positive-rhythm reservoir; Variable water injection temperature; Flow channel,WAXY CRUDE-OIL; ASPHALTENE PRECIPITATION; PERMEABILITY REDUCTION; PARAFFIN PRECIPITATION; RELATIVE PERMEABILITY; START-UP; DEPOSITION; MODEL; IMBIBITION; EFFICIENCY,"There are relatively few studies that consider the influence of reservoir heterogeneity on reservoir wax deposition. This study conducts a computerized tomography scan to study the flow channels, heavy component retention, displacement efficiency, and trapped oil distribution in a high-pour point oil reservoir with a positive sedimentary rhythm under various water injection temperatures. This study greatly improves the understanding of the wax deposition influences on the flow channel. Three displacement models are proposed: water-flooding breakthrough model (49.5 ?C), approximate-equilibrium piston-like displacement model (54.5 ?C/59.5 ?C), and non-equilibrium piston-like displacement model (64.5 ?C). When the injection temperature is lower than the wax appearance temperature (59.5 ?C), an elliptical wax deposition is formed at the inlet, the most serious deposition is in the middle-permeability layer. A wax deposition barrier is formed away from the inlet, and constrains the downward movement trend of the water injected above. Therefore, the moderate wax precipitation will improve the oil recovery from the top low-permeability layer. However, the heterogeneity in the spaces and strength of the barrier result in the oil recovery from the 100 mD layer at 59.5 ?C begin higher than that at 54.5 ?C; moreover, at 59.5 ?C, the recovery at the inlet is better than that at the outlet. The vortex phenomenon increases the oil recovery from wax deposition area in the bottom layer at the inlet. The heavy component retention is significant, and the oil recovery decreases with decreasing injection temperature. After flooding, the formation mechanisms of the trapped oil include wax deposition, weak water washing, and reservoir sedimentary rhythms. The research results provide initial insights for the evaluation of cold damage.",0,0,2
Crude Oil,Enhanced Oil-recovery,"Aboelkhair, Hamed; Diaz, Pedro; Attia, Attia",Biosurfactant production using Egyptian oil fields indigenous bacteria for microbial enhanced oil recovery,Microbial enhanced oil recovery; Indigenous bacteria; Biosurfactant; Bacillus subtilis; Surface activity; Critical micelle concentration,BACILLUS-SUBTILIS; SURFACTANT; LICHENIFORMIS; OPTIMIZATION; WETTABILITY; HYDROCARBON; INJECTION; MOLASSES; STRAINS,"Biosurfactant production is one of the most efficient mechanisms in microbial enhanced oil recovery (MEOR) processes. This work investigates the production of biosurfactants by indigenous bacteria isolated from Egyptian oil fields, and how to optimize these produced biosurfactants for MEOR. 59 Egyptian oil reservoirs were screened to evaluate the potential applicability of MEOR processes, based on their rock and fluid properties. Results showed that 8 reservoirs from the Gulf of Suez and 3 reservoirs from the Western Desert had the potential to MEOR. Combined analysis of morphological, and biochemical characterization was performed on the 11 bacterial strains isolated from different crude oil samples collected from the reservoirs that have the potential to MEOR process to identify their types. Bacillus spp, a bacilli species that can produce biosurfactants, was selected for further studies. To optimize the surface activity of the produced biosurfactant, ten different reported nutrient media, and a new proposed nutrient media were examined. Bacillus spp has shown the ability to produce a very active biosurfactant that reduced the surface tension of water from 71.8 +/- 1.9 mN/m to 25.7 +/- 1.2 mN/m, and the interfacial tension of water against kerosene from 48.4 +/- 2.1 mN/m to 0.38 +/- 0.07 mN/m at Critical Micelle Concentration (CMC) of 0.04 +/- 0.01 g/l, in a medium supplemented by the new proposed nutrient medium H. The growth rate of Bacillus spp was studied, and it was found it reached its maximum (OD600nm 2.59 +/- 0.16) after 24 h of incubation. Biosurfactant production has no significant change in its surface activity over a wide range of temperature range up to 120 degrees C, which means the studied species Bacillus spp is a thermophilic bacterium. Bacillus spp grew well in the presence of high salt concentration up to 20% (w/v) NaCl, the optimal surface activity was obtained in the range of 0-2% (w/v) NaCl, and at pH 7. The emulsification activity of the produced biosurfactant was examined, and it reached the maximum (69.6 + 1.5%) against kerosene at temperature 25 degrees C, Salinity 0% (w/v) NaCl (distilled water), and pH 7. The produced biosurfactant was purified and extracted by acid precipitation method, and the biosurfactant yield of the purified compound was found to be 2.8 +/- 0.3 g/l. Finally, the core-flooding experiments were conducted to investigate the effect of produced biosurfactants by Bacillus subtilis in oil recovery. The obtained results reveal the potential of Bacillus spp to grow in the new proposed medium H and produce effective and efficient biosurfactants that enhanced oil recovery by 25.19-39.35% of additional oil over the water flooding residual oil saturation in the studied cores and retain more than 60% of its surface activity under harsh conditions and that are relevant to Microbial Enhanced Oil Recovery, MEOR.",0,0,2
Crude Oil,Enhanced Oil-recovery,"Zhao, Haining; Song, Chuanzhen; Zhang, Hui; Di, Chaojie; Tian, Zhen",Improved fluid characterization and phase behavior approaches for gas flooding and application on Tahe light crude oil system,Direct PnA fluid characterization; Vaporizing-gas drive; C/V-gas drive; Multiple-mixing-cell; MMP,MIXING-CELL METHOD; RESERVOIR FLUIDS; DISPLACEMENT; MISCIBILITY; PETROLEUM; PRESSURE; MULTICOMPONENT; PERTURBATION; SIMULATION; INJECTION,"N-2 or N-2/CO2 mixture is considered as injection gas to enhance oil recovery from Tahe oil field. The reservoir pressure and temperature are around 66 MPa and 414 K. The target light crude oil is produced from S117 well of the Tahe oil field. The two main objectives of this study are: 1) to find an effective fluid characterization procedure to calculate the MMP for the N-2/CO2-S117 oil system accurately. 2) to identify the effect of injection gas composition (i.e. N-2/CO2 mixture) on the gas drive mechanisms for the S117 light crude oil. The PVT and multiple-contact experimental data were measured and these data were used to characterize and validate different fluid characterization methods, including the 'conventional methods' and the direct PnA method. We proposed an integrated fluid characterization procedure to accurately calculate MMP. The novelty of the proposed fluid characterization procedure can be summarized as: 1) the procedure regains excellent match in both phase envelopes and critical points before and after lumping; 2) an improved direct PnA regression procedure with only two perturbation parameters was used to calculate pseudo-component properties. The comparison of calculated MMP to the experimental slim-tube data taken from literature shows that the integrated procedure using the direct PnA characterization has the best performance on MMP calculation. For the CO2/N-2-S117 system, the vaporizing-gas drive mechanism controls the miscibility provided the CO2 mole fraction in the injection gas is less than 70%. The calculated MMP is independent of the CO(2 )mole fraction within the range approximately from 0 to 70% in the injection gas. At a higher CO2 mole fraction (ranging from 71% to 100%), the complex condensing/vaporizing (C/V)-gas drive mechanism dominates the miscibility and thus the MMP of the fluid system decreases dramatically as CO2 mole fraction increases.",0,0,2
Crude Oil,Enhanced Oil-recovery,"Santos, Denisson; Barros, Vanderson S.; Silva, Maria Luiza P.; Sales, Havila M. M. S.; Borges, Gustavo R.; Franceschi, Elton; Dariva, Claudio",Strontium-based low salinity water as an IOR/EOR method: Oil-brine interaction,Strontium based saline water; Low salinity water; Oil recovery; Interfacial properties,WETTABILITY ALTERATION; NAPHTHENIC ACIDS; INTERACTION MECHANISM; INTERFACIAL BEHAVIOR; IONIC-STRENGTH; CONTACT-ANGLE; PENDANT DROP; SMART-WATER; SURFACE; RECOVERY,"Strontium-based injection water for enhanced oil recovery has been neglected due to the low solubility of the cation in water. However, challenging reservoirs like those in the Brazilian pre-salt region demand nonconventional solutions to improve oil production. This work shows for the first time that the strontium cation in low salinity water solutions shall be henceforth considered as a potential component in the development of enhanced/improved oil recovery (EOR/IOR) studies. Acidic and non-acidic model oils and real crude oils from Brazilian post-salt and pre-salt fields were used for this study. The oil/brine interfacial tension and viscoelastic properties of the interfacial films were measured by an ascendant drop tensiometer. The results showed that strontium presents the highest interfacial activity among the other alkaline-earth metals. Also, the strontiumbased low salinity water produced the most elastic interfacial film, which is desired for the improvement of oil volumetric sweeping promoted by water flooding. Nonetheless, it is worth highlighting that further studies including core flooding experiments must be performed to assess the strontium effect on the crude oil outflow through reservoir pores as well as the influence of water/oil/rock interactions upon it.",0,0,3
Crude Oil,Enhanced Oil-recovery,"Pashapouryeganeh, Farzad; Zargar, Ghasem; Takassi, Mohammad Ali; kadkhodaie, Ali; Rabiee, Ahmad",One-Pot synthesis of modified-cationic surfactants for enhanced oil recovery applications in carbonate reservoirs,Surfactant synthesis; Cationic surfactant; Quaternary ammonium salt; Wettability alteration; IFT reduction; Chemical enhanced oil recovery (CEOR),INTERFACIAL-TENSION BEHAVIOR; DETERMINING IONS CA2+; HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; POROUS-MEDIA; CHAIN-LENGTH; WET; MECHANISM; LIQUID,"In this study two cationic surfactants, dodecyltriethylammoniumbromide (C(12)TEAB) and hexadecyl-triethylammoniumbromide (C(16)TEAB) were prepared. The formation of synthezied surfactants were confirmed using FTIR and HNMR spectroscopy. Electrical conductivity, interfacial tension and surface tension methods were used to determine the critical micelle concentrations (CMC) of these surfactants. To understand the behavior of synthesized surfactants in harsh environments, the CMC was measured in deionized water (DIW), sea water and petroleum formation water. Using electrical conductivity technique, for C(12)TEAB surfactant the CMC values of 4000 ppm, 2000 ppm and 850 ppm were recorded in DIW, sea water and formation water respectively. For C(16)TEAB surfactant, the CMC values of 420 ppm, 190 ppm and 115 ppm were obtained in DIW, sea water and formation water respectively. The similar CMC results were obtained using the interfacial tension (IFT) and surface tension (ST) methods. Reduction of IFT between crude oil and formation water and also alteration of wettability of petroleum reservoir of carbonated rock from oil-wet (large contact angle) to water-wet (small contact angle) are two major factors affecting chemical enhanced oil recovery (EOR). Interfacial tension (IFT), surface tension (ST) and contact angle measurements were carried out using an IFT-PDSA-06 apparatus (Apex Technologies Company, Iran). The IFT and ST of these surfactants were also carried out in DIW, sea water and formation water. For C(12)TEAB surfactant, the IFT values of 0.051 mN/m, 0.036 mN/m and 0.023 mN/m were recorded in DIW, sea water and formation water respectively. The IFT values of 0.044 mN/m, 0.026 mN/m and 0.0126 mN/m were measured for C(16)TEAB surfactant in DIW, sea water and formation water respectively. The effect of temperature on IFT was studied for both surfactants. When temperature increases, IFT decreases. The reduction of IFT continues up to 55 degrees C, then the IFT increases with increasing temperature. For C(12)TEAB surfactant, the ST values of 44.9 mN/m, 38.8 mN/m and 31.8 mN/m were obtained in DIW, sea water and formation water respectively. In similar measurements for C(16)TEAB surfactant, the recorded ST values were 33.95; 32.9 and 32.22 mN/m in DIW, sea water and formation water respectively. In wettability alteration study both surfactants altered the contact angle from oil-wet to water-wet conditions. Using formation water and C(12)TEAB surfactant, the contact angle varied from 96.4 degrees to 54.5 degrees. In similar study using C(16)TEAB surfactant the contact angle changed from 92 degrees to 46.1 degrees. The contact angles of these surfactants in DIW and sea water were also measured and reported. The results of IFT and wettability studies demonstrated excellent potential application of synthesized surfactants in EOR process in carbonate petroleum reservoirs.",0,0,3
Crude Oil,Solvent,"Aslanidis, Panagiotis; Strand, Skule; Torrijos, Ivan D. Pinerez; Puntervold, Tina",Reproducing wettability in sandstone reservoir core material in laboratory core restorations,Core analysis; Core restoration; Core cleaning; Smart water; FOR; Wettability,OIL; COMPONENTS; ADSORPTION,"Replicating initial reservoir wettability conditions in core restoration by core cleaning and fluid restoration in the laboratory is of great importance. There are several core cleaning and restoration protocols used in the oil industry and academia that include the usage of different equipment, techniques, and materials. Strong solvents used in core cleaning can remove material that is part of the rock phase leading to more water-wet behavior. Large volumes of crude oil exposure in core restorations can result in high adsorption of polar organic components onto the mineral surfaces giving less water-wet behavior. Therefore, sufficient core cleaning should be targeted, involving no physical damage to the solid rock phase and effective crude oil exposure securing realistic water saturations, avoiding overexposure of crude oil. The objective of this study was to establish an optimum core restoration process in terms of cleaning solvents and the amount of crude oil exposure, to re-establish the same core wettability from one core restoration to the next. Seven sandstone cores from a reservoir on the Norwegian Continental Shelf underwent a series of core restorations. Two different core cleaning procedures were used, in which mild (kerosene/heptane) and strong (toluene/methanol) solvents were involved, and furthermore, the cores were exposed to various volumes of crude oil. Spontaneous imbibition experiments showed that mild core cleaning in combination with 5 pore volumes or more crude oil exposure rendered the cores less water-wet in successive core restorations. More rigorous cleaning with 5 pore volumes of crude oil exposure rendered the cores more water-wet in successive core restorations. From spontaneous imbibition results it was concluded that an optimum core restoration procedure involving mild cleaning and only 1 pore volume of crude oil exposure successfully reproduced core wettability in successive experiments.",0,0,0
Crude Oil,Solvent,"Ghasemi, Mohammad; Whitson, Curtis H.",PVT modeling of complex heavy oil mixtures,Equation of state (EOS); Extra heavy oil (or bitumen; Saturated oil viscosity; Solvent solubility; Single-carbon-number (SCN),ATHABASCA BITUMEN; GAS SOLUBILITY; VISCOSITY; PETROLEUM; STEAM,"This paper describes a systematic approach to model the phase and volumetric behavior of extra heavy oil and light solvent mixtures for a wide range of temperatures. A cubic equation of state (EOS) is first developed using crude assay data. We use a modified Jacoby correlation to describe the relationship of specific gravity and molecular weight for the heavy oil sample. A gamma molar distribution model is used to fit the crude assay data, then single-carbon-number (SCN) fractions are defined up to C90+. The Twu correlation is used for estimating SCN critical properties, including C90+, resulting in an EOS with 89 components. Pure solvent-crude oil mixture PVT experimental data are analyzed and used to tune the EOS model. The resulting model reproduces accurately all phase and volumetric behavior of pure-solvent-crude mixtures. The prediction of the final EOS model provides accurate prediction against measured PVT data for mixtures of extra-heavy oil sample and synthetic combustion gas solvents made up of CO2, N2, C1, and C2. For viscosity modeling, we propose a novel technique to model large variation of viscosity for a wide range of pressures, temperatures and solvent compositions. In our proposed approach, the LBC (Lorenz-Bray-Clark) correlation is used, with SCN critical volumes modified individually to ensure the LBC correlation estimates SCN viscosities as given by a modified Twu correlation. The viscosity predictions of the pure-solvent-saturated heavy oil at varying temperatures, the EOS/LBC model results in poor agreement against measured saturated viscosity data. Our solution was to split the heaviest fraction C90+ into two sub-fractions, where only critical volumes differ, resulting in ""lower-viscous"" and ""higher-viscous"" C90+ fractions (C90+L into C90+H). We find that the fraction of C90+L (fL) correlates well against pure solvent solubility and temperature, resulting in an accurate overall viscosity fit. The final EOS/LBC model is successfully employed to predict measured PVT and viscosity data that was not used during the training process. Our new approach can provide accurate phase properties and volumetric behavior calculations and as well as good predictions of large variation of liquid viscosity. Such developed EOS technique is vital for providing an accurate estimation of phase behavior and volumetric properties, and the viscosity variations required for modeling thermal-EOR techniques.",0,0,1
Crude Oil,Solvent,"De las Heras, Igor; Dufour, Javier; Coto, Baudilio",Simulation of the deasphalting process of crude oils: Models development and extraction conditions analysis,Asphaltenes elimination; Liquid-liquid equilibrium; Solvent extraction; Solvent deasphalting; Modeling; Crude oil model,ASPHALTENE PRECIPITATION; LIQUID-EQUILIBRIA; PHASE-EQUILIBRIA; MIXTURES; PLUS; FLOCCULATION; DISTILLATION; PREDICTION; SOLUBILITY; DENSITIES,"Heavy crude oils are under constant investigation due to light oil exhaustion. So, its use is compulsory to meet the world energy demand. Heavy crude oils present several drawbacks as high content of metals, heteroatoms, and asphaltenes, and, therefore, upgrading processes are becoming essential. A deasphalting process, conventionally used for vacuum residue upgrading, can be an interesting pretreatment to eliminate the heavier phases and ease the crude processing in conventional refining facilities. Most of the models developed for deasphalting simulation show problems to be implemented in simulation software packages. In this work, a versatile deasphalting simulation method is developed, composed by the definition of a synthetic crude oil model, formed by discrete pseudo components, and a deasphalting model approaching the process to a liquid-liquid extraction based on the thermodynamic model modified UNIFAC (Dortmund). Both models were satisfactorily validated. The deasphalting method was used to explore the solvent/crude ratio, extraction temperatures, and alternative solvents in substitution of conventional light paraffins. Higher extraction temperatures did not enhance remarkably the deasphalting process and the optimum solvent to crude ratio depends on the solvent type. Alcohols were found as promising compounds as their use is recommended by some studies and they showed great deasphalting results.",0,0,2
Crude Oil,Heat-transfer,"Alhosani, Ahmed; Daraboina, Nagu",Effect of multi-phase flow on asphaltene deposition: Field case application of integrated simulator,Flow assurance; Multiphase flow; Asphaltene deposition,GAS-LIQUID FLOW; HEAT-TRANSFER; PARTICLE DEPOSITION; UNIFIED MODEL; CRUDE OILS; TOOL ADEPT; PRECIPITATION; SLUG; HOLDUP; AGGREGATION,"Asphaltene is initially stable in the oil, but when there is a change in pressure, temperature, or composition, particles tend to phase out and form precipitants. Issues arise when those particles diffuse toward the wall and deposit, which contributes to reducing the flowing area and increasing the pressure drop. Preventing precipi-tation is the optimum solution to maintain the target production rate; however, it is challenging to avoid favorable precipitation conditions. Remedies and treatments to mitigate this issue cause the oil industry a considerable increase in expenditure and time; thus, it is necessary to develop a tool to accurately predict the deposition for a wide range of operating conditions, especially in multiphase flow. In this study, a multiphase simulator is developed by coupling thermodynamics, hydrodynamics, heat transfer, and asphaltene modules to predict the deposition. A deposition data obtained from a field case is used to validate the robustness of the simulator. The simulator results matched well with the asphaltene deposition and the equilibrium profile available in the literature. The simulation approach presented here offers useful insights into the effect of multiphase flow on asphaltene deposition and eventually aid in improving the accuracy of pre-diction. Using single-phase assumption under multiphase conditions contributed to a significant error in the prediction, and these inaccuracies may lead to a substantial economic and operational burden for the oil and gas industry.",0,0,0
Crude Oil,Heat-transfer,"Ahmed, Syed Amjad; John, Bibin",Predictive correlations for heat transfer characteristics of oil-water horizontal pipe flow-an experimental study,convective heat transfer; oil-water flow; stratified flow; dispersed flow,LIQUID-LIQUID DISPERSIONS; CRUDE-OIL; DEPOSITION; VISCOSITY; PATTERNS,"This paper presents convective heat transfer characteristics of liquid-liquid horizontal pipe flow. Experiments are carried out in a stainless-steel pipe of diameter 1.59 cm with L/D ratio of 377. Three different oils with varying properties (viscosity: 630 mPa-s, 202 mPa-s and 1.95 mPa-s and density: 919 kg/m3, 901 kg/m3 and 790 kg/m3 respectively) are employed as oil phase and the other fluid phase being water. The experiments are conducted for four oil-water flow patterns-stratified flow, stratified flow with droplets at the interface, dispersed oil-in-water and dispersed water-in-oil with fluid fractions ranging 0 to 1 at different fluid velocities. A constant temperature heat supply, using jacketed hot water flowing over the test pipe, is maintained. The analysis of heat transfer experiments indicates that the heat transfer process in liquid-liquid flow depends on the same dimensionless terms, the Reynolds number and the Prandtl number, that signifies single-phase flow heat transfer. Accordingly, it is found that the established and existing single-phase heat transfer correlations, modified according to flow regime, flow pattern and fluid flow and thermal properties, are also applicable for liquid-liquid flow. The heat transfer in liquid-liquid flow found to be influenced by the fluid fraction. Effectively, for stratified flow, the heat transfer in the liquid-liquid flow is the sum of heat transfer of the individual fluid phases. However, for dispersed flow, the presence of additional fluid phase is incorporated by employing the effective Reynolds number and effective Prandtl number. Using this methodology, more than 85% of stratified flow and 92% of dispersed flow heat transfer characteristics are predicted within +/- 20% of experimental data.",0,0,1
Crude Oil,Soft Computing,"Gaganis, Vassilis; Marinakis, Dimitris; Samnioti, Anna",A soft computing method for rapid phase behavior calculations in fluid flow simulations,Phase stability; Phase split; Equilibrium coefficients; Flow simulation; Phase equilibrium calculations acceleration,OPERATOR-BASED LINEARIZATION; FLASH CALCULATIONS; ROBUST ALGORITHM; CUBIC EQUATIONS; CRUDE-OIL; K-VALUES; 2-PHASE; MULTICOMPONENT; FRAMEWORK; MIXTURES,"To describe the flow of hydrocarbons in the reservoir and in pipelines upstream petroleum engineers utilize compositional simulation models which allow for the accurate description of complex phase behavior phenomena by means of EoS models and detailed compositional characterization. To speed up the conventional time-consuming phase stability and phase split calculations, soft computing has been recently utilized by means of methods such as proxy models and on-the-fly tabulation of phase behavior results. In this work, a new soft computing pressure-explicit, adaptive interpolation technique is presented which allows for the direct, offline, non-iterative estimation of fluid specific equilibrium coefficients values as functions of the conditions prevailing during the process to be modeled. The so calculated equilibrium coefficients allow for the rapid determination of the number, composition and properties of the phases present in every cell and at every timestep by means of the Rachford-Rice equation, thus greatly reducing the CPU time required for phase equilibrium calculations. Moreover, the proposed method guarantees continuous first and second order phase properties derivatives with respect to p and T. The method is applicable to any type of EoS including the SRK and the PR ones. The method is fully applicable to depletion projects of all types of oil and gas condensates. Additionally, it can be used for the history matching of the past depletion phase of oil and gas reservoirs before the initiation of EOR projects such as acid or sour gas injection as well as before dry gas reinjection in gas condensate reservoirs.",0,0,0
Crude Oil,Soft Computing,"Amiri-Ramsheh, Behnam; Safaei-Farouji, Majid; Larestani, Aydin; Zabihi, Reza; Hemmati-Sarapardeh, Abdolhossein",Modeling of wax disappearance temperature (WDT) using soft computing approaches: Tree-based models and hybrid models,Solid scales; Wax disappearance temperature; Multilayer perceptron; Random forest; ANFIS; Leverage approach,HIGH-PRESSURE; PHASE-EQUILIBRIA; CRUDE OILS; PREDICTION; PRECIPITATION; OPTIMIZATION; ALGORITHM; DEPOSITION; ANFIS,"Solid scales can cause significant problems in oil production and transmission systems such as oil flow rate reduction. Wax is one of the most critical substances that are highly prone to precipitate and deposit in oil pipelines. This occurrence typically happens in low temperatures, and can extremely affect the flow rate. In the wax deposition process, wax disappearance temperature (WDT) is a crucial factor since it denotes the lowest temperature, at which wax deposits melt and the consequences of wax deposition vanish. In this research, smart models were utilized to predict WDT as a function of molar mass and pressure according to a comprehensive database. The proposed intelligent models are radial basis function (RBF) and multilayer perceptron (MLP) neural networks, adaptive neuro-fuzzy inference system (ANFIS), random forest (RF), extra tree (ET), and decision tree (DT). The MLP networks were trained with Bayesian Regularization (BR) and Levenberg-Marquardt (LM) algorithms, and the ANFIS models were coupled with three optimization algorithms, namely Cultural Algorithm (CA), Biogeography-based Optimization (BBO), and Teaching-Learning-Based Optimization (TLBO). Results demonstrate that the developed RF model could present an outstanding performance and provide predictions for WDT with the lowest average absolute percent relative error (AAPRE = 0.246%), the maximum coefficient of determination (for predicting = 0.993), and minimum root mean squared error (RMSE = 1.01). Trend analysis showed that increasing pressure and molar mass leads to wax disappearance temperature increase. Lastly, outlier discovery was performed using the Leverage approach to recognize the suspected data points. The outlier detection found that only 6 points (out of 346) are located in the upper and lower suspected data zones.",0,0,2
Flow Rate,Well Testing,"Beltran-Jimenez, K.; Skadsem, H. J.; Sunde, J. K.; Gardner, D.; Wolterbeek, T. K. T.; Cornelissen, E. K.; Keultjes, W. J. G.",Restoration of annular zonal isolation using localized casing expansion (LCE) technology: Treatment of near-horizontal test sections containing a free-water channel,Well integrity; Well abandonment; Sustained casing pressure; Surface casing vent flow; Annular fluid migration; Casing expansion,CEMENT PASTE; GAS; BEHAVIOR,"Fluid migration behind casings is a well integrity problem that can result in sustained casing pressure, undetected leaks to the environment, and potentially very difficult remediation attempts. Traditional methods for treating annular fluid migration are perf-and-squeeze cementing or section milling followed by recementing. The main disadvantage of the former is the limited penetrability of cement slurry into narrow cracks and microannuli, while for the latter it is the requirement of a full rig to perform the operation. Casing expansion is a recent alternative remediation technology that involves imposing a permanent radial expansion of the casing and external cement layer, with the purpose of mechanically closing pathways for migrating fluids. A necessary requirement for the treatment to be effective is that the annular cement is confined between casings or between casing and competent rock formations, such that the cement can sustain significant mechanical strains without failure. Recent laboratory experiments and field trials have shown casing expansion to be a promising alternative to traditional treatment methods. We build on these insights and perform controlled treatment experiments involving a 7-in Local Expander tool and full-scale cemented annulus test assemblies, which contained much larger-scale defects than previously tested. Prior to treatment, the test assemblies had continuous migration channels on the top side of the cement, leading to high effective permeabilities ranging from approximately 80 to hundreds of darcy. The origin of the defects was likely separation of free water from the cement slurry, which is considered a relevant failure mode for primary cementing of inclined wellbores. We study the effect of imposing single and multiple local dents on the annular seepage rates, and probe for potential alteration of the cement and casing properties using Vickers hardness testing. We find that casing expansion can be highly effective in treating relatively major defects in cemented annuli, even when the defect is several millimeters wide and located adjacent to the outer casing. The effectiveness of the treatment is found to be linked to the degree of casing expansion and the initial condition of the annular cement. The deformed cement shows a tendency toward increased Vickers hardness, which is likely linked to densification of the cement microstructure. Vickers hardness testing of casing steel indicated no significant changes in hardness at the dent locations compared to average hardness values away from these points.",0,0,0
Flow Rate,Well Testing,"Khalaf, Mina S.; Soliman, Noha; El-Banbi, Ahmed H.",Wellbore storage removal in pressure transient analysis for gas wells,Wellbore storage; Deconvolution; Pressure transient analysis; Well testing; Gas wells,DECONVOLUTION ALGORITHM; FLOW; RESERVOIRS,"Wellbore storage (WBS) occurs due to fluid loading/unloading in the wellbore, when a well starts production or is shut-in. This phenomenon creates variable sandface rate and time lag between the surface production rate and the stable sandface rate. Wellbore storage effects can sometimes conceal important information and complicate well test analysis and interpretation. In well tests that suffer from long WBS, removal of WBS effects can usually recover important features in the reservoir signal and lead to significant improvement in identifying the reservoir model and calculating reservoir parameters. Until recently, WBS removal relied on direct deconvolution techniques that require accurate well test data. Presence of noise in the pressure and rate data usually makes direct deconvolution methods unstable. Well test pressure and rate data usually suffer from some noise, and therefore, application of direct deconvolution methods may not work. This work develops a stable technique to eliminate WBS effects present in gas wells. The technique uses two deconvolution steps and applies the recently developed deconvolution algorithms (e.g. von Schroeter algorithm) for stable computations. Unlike the direct deconvolution methods (which become largely unstable when minor noise is present in data) in WBS removal, the proposed approach also extends the reservoir signal over both the drawdown and buildup periods. The new technique is applied to simulated gas well test data in a variety of conditions for validation. The applications considered different well/reservoir models and included different levels of data noise. The technique is also applied to a field case to show the value of the proposed approach. The findings of this study can be used to eliminate WBS effects and recover reservoir signal. It has applications in variety of gas reservoirs where WBS can hide information such as low permeability reservoirs, natural fractured reservoirs, small reservoirs, and wells with large wellbore volume. The reservoir properties calculated from reservoirs after removal of WBS can be used in further calculations such as estimates of gas in place and well productivity to help engineers optimize their wells/reservoirs performance.",0,0,0
Flow Rate,Well Testing,"Rodrigues, Hendy T.; Almeida, Alcino R.; Barrionuevo, Daniel C.; Fraga, Ricardo S.",Effect of the gas injection angle and configuration in the efficiency of gas lift,Gas lift; Gas-liquid mixing; Crossflow gas injection; Upward gas injection; Downward gas injection,BUBBLE FORMATION; FLOW,"In oil wells using gas lift as a method of artificial lift, the gas is normally injected inside the tubing at a downward direction, i.e., in countercurrent flow relative to the fluids coming from the reservoir. This creates turbulence in the flow, causing pressure drop for the gas to change direction and to flow upward along with the produced fluid. The optimization of this geometry, by changing the gas injection angle, for instance, may introduce some gain. In this paper, we present theoretical analyzes and computer simulation showing that, for high gas injection flow rates and/or small jet diameters, it is possible to obtain a gain when reversing the direction of the gas injection. Although it is intuitive that an upward injection can improve the flow, experiments are needed to give confidence to this proposal. However, there is very few studies in the literature addressing this issue. To improve the knowledge of subject, this study shows experiments performed using an experimental well flowing oil and natural gas. Such an experiment, at real scale configurations and fluids is unique. The usual configuration, injecting downward, was compared with two alternatives, injecting the gas jet upward and injecting in an annular pattern. This article describes and discusses the tests and the results obtained. Although the tests have not been performed with the ideal conditions to maximize the gain, the results were consistent and conclusive. A slight local gain was observed due to the gas angle change, consistent with the previsions of a simple theoretical model. The estimated gains can reach 2 bar and are obtained at no additional cost by simply inverting the gas jet direction, but it is more effective for wells with high gas injection flow rate. Since gas lift is applied to a large number of wells, even a modest gain can be significant in the overall context. Based on the results, it is speculated that there is probably an optimum way to inject gas by taking advantage of the jet inversion and of the reduction on slippage between gas and liquid.",0,0,0
Flow Rate,Well Testing,"Chaves, Gabriela Souza; Karami, Hamidreza; Ferreira Filho, Virgilio Jose Martins; Vieira, Bruno Ferreira",A comparative study on the performance of multiphase flow models against offshore field production data,Multiphase flow; Production optimization; Offshore data analysis; Flow assurance; Flow models,2-PHASE FLOW; PRESSURE-DROP; PATTERN TRANSITIONS; MECHANISTIC MODEL; PREDICTING FLOW; VISCOSITY; OIL,"In the oil industry, multiphase flow models are commonly used to simulate the flow from reservoir to the production unit. Flow simulations help in the production monitoring and optimization to support the decisionmaking process. Despite the need for accurate simulations to support production operations, multiphase flow models are mostly developed using laboratory data and rarely validated under field-scale conditions. To improve the understanding of multiphase flow models in field conditions, this work evaluates the performance of a large set of models for a dataset composed of two production units with 20 producing wells and 865 measured production points. The wells are divided and analyzed in two segments: the surface flowline and the wellbore. The evaluation compares the models' performances using various statistical parameters and trending charts. The evaluation analyzes the impacts of production parameters, well geometry, predicted flow pattern, and pressure drop components on the model performances. Overall, Ansari's model presented the best performance with 13.8% absolute average percent error for the flowline segment and 14.1% error for the wellbore segment. In addition, Gray can also generate good results for most but not all of the tested wellbores. From the production parameters evaluation, higher flow rate tests resulted in more stable outputs. Ansari and Beggs models showed a trend of increasing errors for wells with larger horizontal wellbore lengths. Also, Beggs model showed larger errors when the transition flow pattern was predicted. Finally, both Ansari and Beggs models showed larger overprediction errors for tests with higher pressure losses in the flowline segment, while Gray showed smaller errors for these cases. The conclusions can be used to select the best models given the production system's flow parameters, or be incorporated in systems to increase the accuracy.",0,0,0
Flow Rate,Well Testing,"Nascimento, Julio Cesar S.; dos Santos, Adriano; Ortiz, Carlos E. Pico; Pires, Adolfo Puime",A fully implicit EOS based compositional two-phase transient flow simulator in wellbores,Two-phase transient flow; Two-fluid model; Two-phase segregation; Fully implicit solution; Compositional flow,NUMERICAL SCHEMES; 2-FLUID MODEL,"Transient two-phase flow in pipes and wellbores appears in several processes in petroleum industry. Predicting pressure, temperature and composition behavior during offshore well tests can support investment decisions in exploration. The governing system of equations that model production (or injection) and build-up (or fall off) is composed by the mass conservation of each component, the transport equation for each phase and one overall system energy equation. In this paper we develop a fully implicit equation of state based thermal compositional simulator able to model two-phase multicomponent flow in wellbores and pipes. This simulator is fully compositional and includes thermal effects. The thermodynamics calculations are based on the Peng-Robinson equation of state, and the momentum equations are based on the Single-Pressure Two-Fluid model. The finite volume method is used to discretize the non-linear system of equations, and time is discretized using Euler's implicit technique. The obtained numerical solutions for both co-current as well as countercurrent flow showed excellent agreement when compared to benchmark solutions published in the literature. A well kick-off followed by constant flow rate production and posterior shut-in was also simulated and the numerical results were discussed. It also models surge pressure and gravitational segregation effects in the wellbore. The presented simulator may be applied in numerical pressure transient analysis and pressure behavior in flowlines connecting wellheads and production platforms.",0,0,0
Flow Rate,Well Testing,"Kryganov, P., V; Afanaskin, I., V; Volpin, S. G.; Akhapkin, M. Yu; Yalov, P., V",Searching for reservoirs with bypassed oil using well tests and mathematical modeling,Bypassed oil; Residual oil reserves; Hydrodynamic simulation; Well test; Pressure buildup test; Interference test; Flow analysis,,"The increase of oil recovery by the involvement of bypassed oil into production is a significant source of oil production increase at a minimal cost. Bypassed oil zones identification possibilities researched through mathematical flow modeling and simulated well tests. Two hypothetical models of homogeneous and heterogeneous (with low permeability zones) oil formations were generated, in which the bypassed oil was trapped during the production. Based on these models, the authors calculated data of comprehensive well tests: buildup, drawdown and interference. The aspects of the well test interpretation results data obtained for both models through the best-match method allowed bypassed oil areas identification possibility assessment. A significant difference between the cumulative oil rate actually observed at the field and the one obtained in the model is the first diagnostic feature, which suggests the presence of bypassed oil. During the pressure buildup (drawdown) tests, the curves of pressure change derivatives on the Bourdet diagnostic plots for heterogeneous and homogeneous models differ significantly, which is the second diagnostic feature that suggests the presence of bypassed oil. The analysis of the data processing results obtained during the pressure buildup tests indicated cases of significant changes in conductivity over time which is associated with higher water cut due to the absence of any obstacles for water to flow through. This factor can be considered a third diagnostic feature. During the interference tests of a heterogeneous model in multiple directions, the permeability of the interwell space in all directions turned out to be much lower in comparison to the reservoir permeability in the vicinity of the wells, that is explained by the bypassed oil presence - this is the fourth diagnostic feature which suggests the bypassed oil presence in the interwell space. The obtained results of well test data interpretation means a possibility to identify undeveloped areas with bypassed oil, filtration model improvement and recommendations development of infill drilling or sidetracks for the residual reserves extraction.",0,0,0
Flow Rate,Well Testing,"Aitkulov, Almas; Edwards, Reid; Delamaide, Eric; Mohanty, Kishore K.",An analytical tool to forecast horizontal well injectivity in viscous oil polymer floods,Horizontal well; Injectivity; Viscous oil reservoir; Polymer flooding; Analytical model,FIELD; SIMULATION; MOBILITY,"Injection rate is a key factor for successful polymer floods of viscous oil reservoirs. Injectivity during polymer flooding is lower compared to waterflooding due to the viscosity of polymer solution. Accurate estimation of injection rate/pressure build-up due to polymer injection is essential to evaluation and design of polymer flood projects. Typically, a short-term polymer injectivity test is performed on a single well, but it is hard to extrapolate future behavior of polymer injectivity because the tests are often too short. Reservoir simulation can be used to forecast injectivity, but the grid size and radial flow often affect the calculated injectivity. Analytical methods provide simple and quick ways to estimate injectivity using realistic reservoir conditions. The goal of this work is to develop an analytical tool and demonstrate its applicability by comparison with field data. An analytical solution is developed for the injectivity of horizontal wells in polymer floods in viscous oil reservoirs. The analytical solution is validated by comparing it to a numerical field-scale box model simulation. The pressure profiles are calculated using spreadsheets and compared against the data from several fields with increasing degrees of complexity. In each case, the analytical-spreadsheet method provides close matches of injection pressure data. This analytical tool can be used for preliminary design of polymer floods before getting into more complex and time-consuming reservoir simulations.",0,0,0
Flow Rate,Well Testing,"Tavakkoli, Mohammad; Panuganti, Sai R.; Khemka, Yash; Valdes, Humberto; Vargas, Francisco M.",Foam-assisted gas lift: A novel experimental setup to investigate the feasibility of using a commercial surfactant for increasing oil well productivity,Pressure drop; Foam; FAGL; Artificial lift; Wellbore productivity; Multiphase flow,,"Most oil wells require artificial lift at some point to increase the life of the field and enhance production. Conventional methods such as gas lift are not effective in depleted reservoirs with high water cut where very high gas injection rates are required for relatively low oil production rates. Consequently, foamers or surfactants, which have been previously applied for de-liquifying gas wells, are now used in depleted gas-lifted oil wells to either boost production rates or reduce gas lift requirements while maintaining production levels. While there is a growing global interest, foam-assisted gas lift (FAGL) is a relatively modern artificial lifting method with less experience regarding its applications in oil wells. In this study, the feasibility of using a commercial surfactant for improving oil well productivity is investigated via laboratory experiments. A novel laboratory setup resembling a vertical well rig is designed to analyze the impact of surfactant concentration, temperature, brine salinity and phase-specific flow rates (or flow regimes) on the pressure drop across the column. This setup is operational at high temperatures, requires minimal sample amounts, and significantly reduces the experimental errors in pressure drop readings, resulting in highly accurate and stable measurements. The laboratory tests confirm that the addition of foamer reduces pressure drop in the production tubing, thus effectively increasing production. Additionally, an optimal foamer concentration is also detected. The results obtained in this study are very promising and present opportunities to explore a new chapter in artificial lift and production enhancement techniques.",0,0,0
Flow Rate,Well Testing,"Li, Xiangling; Xiao, Kang; Li, Xianbing; Yu, Chunye; Fan, Dongyan; Sun, Zhixue",A well rate prediction method based on LSTM algorithm considering manual operations,Manual operations; Time series; LSTM; Deep learning method; Rate prediction,FLOW; GAS,"Manual operations such as changing the size of chokes as well as opening and closing of the well have a great impact on oil and gas production from the well. This scenario is not considered in most deep learning methods for predicting productivity. Therefore, a deep learning method based on a long short-term memory (LSTM) neural network model was established to predict well performance considering the manual operations. The input dataset was composed of data related to choke size, daily opening time series, and production; the first 90% of the dataset was used as the training set and the remaining 10% was used as the test set. The deep learning model was constructed using a LSTM module, regularization process, and dropout network. The formulated LSTM model was proficient compared with a model that did not consider the manual operation process, and showed better prediction accuracy. Through multiple experiments, the production-related time step was optimized at three, indicating that prediction for the subsequent step was most relevant to the initial three step inputs. Overall, the operation of opening and closing of wells, changing the size of chokes, and variations in daily production time can be considered in our LSTM deep learning model, which provides more reasonable results.",0,0,1
Flow Rate,Well Testing,"Zhu, Dancheng; Zou, Huayao; Yang, Minglei; Li, Ting; Li, Tao; Li, Haiping; Xu, Liang; Wen, Long; Zhou, Gang","The Middle Permian Maokou reservoir (southern Sichuan Basin, China): Controls on karst development and distribution",Carbonate reservoir; Reservoir distribution; Reservoir productivity; Dual permeability; Caves; Maokou Formation,EOGENETIC KARST; GAS-FIELD; CARBONATE; PERMEABILITY; CLASSIFICATION; POROSITY; DEPTH,"The Middle Permian Maokou limestone is a major natural gas producing reservoir in the southern Sichuan Basin, China. While matrix porosity is low, bit drops, losses while drilling, blowouts, and extremely high well testing flow rates indicate the presence of a dual permeability system in the form of paleocaves, which were formed by karstification in the late Maokouan Age. A combination of geological, paleogeomorphological and karstic analyses reveal that the development and distribution of the karst features within the reservoir are primarily regulated by shoal facies, paleotopography and syndepositional faults. In our conceptual paleogeomorphological model, the potential cave-bearing zones are located along the rim and outer edge of the Luzhou Paleohigh, which was the highland during the karst. Outside the highland were the karst slopes, and the poljes were on the flanks of the study area. Reservoir performance data suggest, there are two types of sweet spots in the study area. The first corresponds to the syndepositional fault zones along the rim of the karst highland and on the karst slope, where the caves appear to distribute along the faults, impacting the reservoir's vertical permeability. The second corresponds to the shoals of the Mao 2 and Mao 3 members on the lower western karst slope and the upper eastern karst slope, where the caves are widespread, enhancing the horizontal permeability and connectivity of the reservoir. However, the caves are rare in the central karst highland, lower karst slopes, and poljes, which is consistent with the limited gas discoveries.",0,1,2
Flow Rate,Well Testing,"Goes, Maria Rosa R. T.; Guedes, Thamires A. L.; D'Avila, Thiago C.; Vieira, Bruno Ferreira; Ribeiro, Leonardo D.; de Campos, Mario C. M.; Secchi, Argimiro R.",Virtual flow metering of oil wells for a pre-salt field,Virtual flow metering; Pre-salt; EMSO; Real time,,"The flow rate values reported in real time, for an oil and gas production unit, refer to the total amount produced by that unit. On the other hand, data referring to the flow rate of each producing well in real time are usually not available, due to the difficulty in implementing flow measurement devices. These individual flows are determined by production tests that are generally performed every two months and are important for production planning and optimization. Therefore, there is a need to generate models capable of predicting the flow of each well in the period between tests, in order to identify possible issues during the production. In this context, we propose in this paper a method to predict the liquid and gas flow rates of each well as function of measured variables available in plant data collected in real time. Choke valve specifications and fluid properties are also required as model input data. Since there is no flow measurement device, it is not possible to directly validate the model results against plant data. In this case, the model validation is performed using the total liquid and gas flow rates presented in the Daily Operation Report (DOR) and those provided by fiscal meters. Relative errors below 3.5% were observed, showing good agreement between the calculated flow rates and the provided by fiscal meters. The proposed method was implemented in the computational environment EMSO, which presents as advantages the low simulation time and robustness over a wide range of input data. These advantages become important as the model is used for monitoring platforms in real time. The range of applicability of this model can be attributed to the Gas-Oil Rate (GOR). In this work, the lowest and highest values of GOR considering all the wells are 207.58 and 393.97, respectively.",0,0,2
Flow Rate,Well Testing,"Yang, Mou; Luo, Hao; Xie, Rongxuan; Wu, Pengcheng; Yang, Mingzheng; Yang, Lvchao; Xue, Hu",Estimating and optimizing wellbore pressure during primary cementing in low pressure and leakage formations,Circulating pressure; Cementing operation; Low pressure and leakage formations; Mathematical model; Computational fluid dynamics,NON-NEWTONIAN FLUIDS; POWER-LAW FLUID; HERSCHEL-BULKLEY; ECCENTRIC ANNULI; DRILLING-FLUIDS; TURBULENT-FLOW; LAMINAR; CIRCULATION; TRANSITION; BEHAVIOR,"In most realistic situations, casing eccentricity and various fluids injected during primary cementing lead to a significant difference in fluid flow and circulating pressure, compared with a single fluid flowing in the concentric annulus. Ignoring the effect of eccentricity and fluid rheological model on the wellbore circulating pressure results in an inaccurate evaluation and leads to formation leakage, especially for low pressure and leakage formations. To overcome this challenge, firstly, rheological models of various fluids were analyzed using experimental data, including drilling fluid, spacer, and cement slurry. Secondly, the modified correlations of frictional pressure losses for Herschel-Bulkley and Power Law fluids in the eccentric annulus were developed, using the simulation data of computational fluid dynamics software (CFD) and considering the effects of flow behavior index, pipe diameter ratio, and casing eccentricity on the frictional pressure losses. Finally, based on the developed mathematical models, the optimal method of primary cementing and evaluation results were presented, analyzed, and tested in the field with great success. The results demonstrated that the drilling fluid and spacer fluid had the highest goodness of fit for the Herschel-Bulkley model, and the cementing slurry was suitable for the Power Law model. The ratio coefficient of pressure loss in the eccentric to concentric annulus decreased with a decrease of hole size and an increase of casing eccentricity. A 50 percent reduction in frictional pressure loss was evaluated when the casing lies on the borehole wall. Comparing the calculations of the developed correlation with the published correlation in the literature reveals a more accurate evaluation of friction pressure losses in the analyzed case. Combined with the realistic situation of a test well, the density, flow rate, and returning depth of the lead cement slurry were recommended as 1.5 g/cm(3), 0.5 m(3)/min and 4100 m, respectively, according to the leakage pressure of 65.6 MPa that was calculated by the developed mathematical model. Most importantly, the developed method in this paper can accurately predict the variation characteristics of wellbore pressure during the primary cementing process and provide effective guidance in managing downhole pressure in low pressure and leakage formations by real-time adjustment of the most effective and controllable operation parameters.",0,0,3
Flow Rate,Permeability,"Beltran-Jimenez, K.; Skadsem, H. J.; Sunde, J. K.; Gardner, D.; Wolterbeek, T. K. T.; Cornelissen, E. K.; Keultjes, W. J. G.",Restoration of annular zonal isolation using localized casing expansion (LCE) technology: Treatment of near-horizontal test sections containing a free-water channel,Well integrity; Well abandonment; Sustained casing pressure; Surface casing vent flow; Annular fluid migration; Casing expansion,CEMENT PASTE; GAS; BEHAVIOR,"Fluid migration behind casings is a well integrity problem that can result in sustained casing pressure, undetected leaks to the environment, and potentially very difficult remediation attempts. Traditional methods for treating annular fluid migration are perf-and-squeeze cementing or section milling followed by recementing. The main disadvantage of the former is the limited penetrability of cement slurry into narrow cracks and microannuli, while for the latter it is the requirement of a full rig to perform the operation. Casing expansion is a recent alternative remediation technology that involves imposing a permanent radial expansion of the casing and external cement layer, with the purpose of mechanically closing pathways for migrating fluids. A necessary requirement for the treatment to be effective is that the annular cement is confined between casings or between casing and competent rock formations, such that the cement can sustain significant mechanical strains without failure. Recent laboratory experiments and field trials have shown casing expansion to be a promising alternative to traditional treatment methods. We build on these insights and perform controlled treatment experiments involving a 7-in Local Expander tool and full-scale cemented annulus test assemblies, which contained much larger-scale defects than previously tested. Prior to treatment, the test assemblies had continuous migration channels on the top side of the cement, leading to high effective permeabilities ranging from approximately 80 to hundreds of darcy. The origin of the defects was likely separation of free water from the cement slurry, which is considered a relevant failure mode for primary cementing of inclined wellbores. We study the effect of imposing single and multiple local dents on the annular seepage rates, and probe for potential alteration of the cement and casing properties using Vickers hardness testing. We find that casing expansion can be highly effective in treating relatively major defects in cemented annuli, even when the defect is several millimeters wide and located adjacent to the outer casing. The effectiveness of the treatment is found to be linked to the degree of casing expansion and the initial condition of the annular cement. The deformed cement shows a tendency toward increased Vickers hardness, which is likely linked to densification of the cement microstructure. Vickers hardness testing of casing steel indicated no significant changes in hardness at the dent locations compared to average hardness values away from these points.",0,0,0
Flow Rate,Permeability,"Khalaf, Mina S.; Soliman, Noha; El-Banbi, Ahmed H.",Wellbore storage removal in pressure transient analysis for gas wells,Wellbore storage; Deconvolution; Pressure transient analysis; Well testing; Gas wells,DECONVOLUTION ALGORITHM; FLOW; RESERVOIRS,"Wellbore storage (WBS) occurs due to fluid loading/unloading in the wellbore, when a well starts production or is shut-in. This phenomenon creates variable sandface rate and time lag between the surface production rate and the stable sandface rate. Wellbore storage effects can sometimes conceal important information and complicate well test analysis and interpretation. In well tests that suffer from long WBS, removal of WBS effects can usually recover important features in the reservoir signal and lead to significant improvement in identifying the reservoir model and calculating reservoir parameters. Until recently, WBS removal relied on direct deconvolution techniques that require accurate well test data. Presence of noise in the pressure and rate data usually makes direct deconvolution methods unstable. Well test pressure and rate data usually suffer from some noise, and therefore, application of direct deconvolution methods may not work. This work develops a stable technique to eliminate WBS effects present in gas wells. The technique uses two deconvolution steps and applies the recently developed deconvolution algorithms (e.g. von Schroeter algorithm) for stable computations. Unlike the direct deconvolution methods (which become largely unstable when minor noise is present in data) in WBS removal, the proposed approach also extends the reservoir signal over both the drawdown and buildup periods. The new technique is applied to simulated gas well test data in a variety of conditions for validation. The applications considered different well/reservoir models and included different levels of data noise. The technique is also applied to a field case to show the value of the proposed approach. The findings of this study can be used to eliminate WBS effects and recover reservoir signal. It has applications in variety of gas reservoirs where WBS can hide information such as low permeability reservoirs, natural fractured reservoirs, small reservoirs, and wells with large wellbore volume. The reservoir properties calculated from reservoirs after removal of WBS can be used in further calculations such as estimates of gas in place and well productivity to help engineers optimize their wells/reservoirs performance.",0,0,0
Flow Rate,Permeability,"Al Kalbani, Munther; Jordan, Myles; Mackay, Eric; Sorbie, Ken; Nghiem, Long",Modelling the impact of Alkaline-surfactant and Alkaline-surfactant-polymer flooding processes on scale precipitation and management,Chemical EOR; Alkaline-surfactant-polymer; Geochemical reactions; Inorganic scale precipitation; Squeeze modelling,OIL; TECHNOLOGY; RECOVERY; WATER,"Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the in situ mineral reactions on the produced scaling ions and pH has been little reported in the literature. The objective of this study is to investigate the impact of the in situ chemical and geochemical interactions on the scale precipitation risk when the fluids reach the wellbore, and their inhibition during Alkaline-Surfactant (AS) and ASP flooding processes. Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options. Results: show that the in situ rock dissolution, mineral precipitation and brine mixing reduce the produced ion concentrations (Ca2+, Mg2+, HCO3) and pH compared to the initial concentration and the injected pH value. The calcite scaling risk can be high during Na2CO3 injection while silica and Mg(OH)(2) scales are potential minerals that will precipitate in the production system during NaOH injection. Uncertainty in the mineral reaction rate parameters, especially mineral surface area, is important and must be captured, as this may impact the scaling risk in the producer. Among the studied flooding options, ASP with pre and post polymer slugs shortens the calcite scaling period, reduces the scaling ion concentrations and the produced water rates. This case, then, requires the least number of squeeze treatments, the lowest scale inhibitor volume, and delivers the highest incremental oil recovery. This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.",0,0,0
Flow Rate,Permeability,"Kryganov, P., V; Afanaskin, I., V; Volpin, S. G.; Akhapkin, M. Yu; Yalov, P., V",Searching for reservoirs with bypassed oil using well tests and mathematical modeling,Bypassed oil; Residual oil reserves; Hydrodynamic simulation; Well test; Pressure buildup test; Interference test; Flow analysis,,"The increase of oil recovery by the involvement of bypassed oil into production is a significant source of oil production increase at a minimal cost. Bypassed oil zones identification possibilities researched through mathematical flow modeling and simulated well tests. Two hypothetical models of homogeneous and heterogeneous (with low permeability zones) oil formations were generated, in which the bypassed oil was trapped during the production. Based on these models, the authors calculated data of comprehensive well tests: buildup, drawdown and interference. The aspects of the well test interpretation results data obtained for both models through the best-match method allowed bypassed oil areas identification possibility assessment. A significant difference between the cumulative oil rate actually observed at the field and the one obtained in the model is the first diagnostic feature, which suggests the presence of bypassed oil. During the pressure buildup (drawdown) tests, the curves of pressure change derivatives on the Bourdet diagnostic plots for heterogeneous and homogeneous models differ significantly, which is the second diagnostic feature that suggests the presence of bypassed oil. The analysis of the data processing results obtained during the pressure buildup tests indicated cases of significant changes in conductivity over time which is associated with higher water cut due to the absence of any obstacles for water to flow through. This factor can be considered a third diagnostic feature. During the interference tests of a heterogeneous model in multiple directions, the permeability of the interwell space in all directions turned out to be much lower in comparison to the reservoir permeability in the vicinity of the wells, that is explained by the bypassed oil presence - this is the fourth diagnostic feature which suggests the bypassed oil presence in the interwell space. The obtained results of well test data interpretation means a possibility to identify undeveloped areas with bypassed oil, filtration model improvement and recommendations development of infill drilling or sidetracks for the residual reserves extraction.",0,0,0
Flow Rate,Permeability,"Almutairi, Abdulmajeed; Othman, Faisal; Ge, Jiachao; Le-Hussain, Furqan",Modified Johnson-Bossler-Naumann method to incorporate capillary pressure boundary conditions in drainage relative permeability estimation,Capillary pressure; Outlet boundary; Drainage relative permeability; Unsteady-state,COREFLOOD; FLOW,"A proposed modification of the Johnson-Bossler-Naumann (JBN) method incorporates capillary pressure at the inlet and outlet of a rock sample. The experimental runs are performed on Berea and Obernkriechner sandstone rock samples. Fluid is injected into Berea rock at capillary to viscous ratios 0.05, 0.1, 0.5, and 1 and into Obernkriechner rock at capillary to viscous ratios 0.05 and 0.25. Rock samples are initially saturated with 20 g/l NaCl water. The experimental observations are analyzed using classical JBN and our modified JBN. The latter's relative permeability curves are found to closely match those derived by applying history matching to a numerical model. This indicates that modified JBN can be used to provide an initial guess for history matching. We also show that accurate estimates of threshold capillary pressure are crucial to obtaining accurate oil relative permeability estimates. In contrast to those derived from the JBN method, modified JBN relative permeabilities are independent of capillary to viscous ratio or injection rate.",0,0,0
Flow Rate,Permeability,"Qazvini, Sajjad; Golkari, Abdolah; Azdarpour, Amin; Santos, Rafael M.; Safavi, Mir Saeid; Norouzpour, Milad",Experimental and modelling approach to investigate the mechanisms of formation damage due to calcium carbonate precipitation in carbonate reservoirs,CaCO3 scale formation; OLI Software; Carbonate reservoir; Water flooding; Low flow rate; Permeability reduction; Turbidity,CACO3 SCALE FORMATION; HETEROGENEOUS NUCLEATION; OIL; DEPOSITION; FIELD; INHIBITION; SURFACE; WATER; TEMPERATURE; MANAGEMENT,"Calcium carbonate (CaCO3) precipitation, due to incompatibility between the injected water (IW) and formation water (FW), is known to be a major operational obstacle during water flooding projects. In this study, initially by using OLI Scale Chem and ScaleSoftPitzer software and static beaker tests, the potentiality of CaCO3 scaling was determined from the given ionic content of incompatible synthetic brines, under different conditions (temperature, pressure, and volume mixing ratio of incompatible brines). The results showed that the maximum amount of CaCO3 salt was formed at a volume mixing ratio of 0.8:0.2 (IW:FW). The simulation results showed that OLI software is more reliable than the ScaleSoftPitzer. In the second stage of this work, the 0.8:0.2 proportion of IW: FW was selected to examine the mechanisms under which the maximum formation damage of the tight carbonate cores occurred through the water injection experiments. In addition, the turbidity of the bulk solution was measured to confirm the core flooding outcomes. Various hydrodynamic parameters (low flow rate, scaling tendency, and the temperature) were evaluated in these experiments. Bulk induction time (t(ind)) and scaling period (t(s)) were determined from the setup. Either heterogeneous nucleation (i.e. crystallization processes), or both heterogeneous nucleation and adhesion of pre-deposited crystals from the mixed incompatible brines to the pore wall of the cores, were attributed as the principal mechanisms of the formation damage of tight carbonate rocks owing to CaCO3 salt formation. Moreover, a semi-empirical model was established from this laboratory study, which predicts the scaling period (t(s)) as a function of interfacial energy, temperature, and scaling tendencies.",0,0,1
Flow Rate,Permeability,"Fawaz, Youssef; La Borderie, Christian; Senechal, Pascale; Jacques, Antoine; Pijaudier-Cabot, Gilles",Fracture cleaning: Experimental study on the unclogging process within a propped fracture under a dynamic stimulation,Fracture; Proppant; Dynamic stimulation; Waves; Intrinsic permeability; Unclogging,PARTICLE,"This experimental study investigates the unclogging process of a propped fracture previously clogged, using a synthetic dynamic load. Pressure oscillations inside the fracture are expected to flush out the fine particles blocking the flow. Laboratory experiments are presented: fractures are clogged with crushed natural sand; after applying the dynamic load, a significant increase of the intrinsic permeability is observed. The highest recovery rate reached was 82%. X-ray CT scans provide images of the fracture before and after the dynamic load is applied. The results show that a high percentage of fines are flushed out of the fracture. The influence of the proppant characteristics and of the quantity of fine particles in the fracture are discussed. Flushing of fines is more effective with large-size proppant. As the density of proppant increases, it passes through a minimum for one layer of proppant which corresponds to a very dense particle distribution. Above one layer of proppant, particles stack onto each other which increases the propped fracture thickness and its conductivity. Finally, it is found that high frequencies and high amplitudes of the dynamic load promote unclogging.",0,0,1
Flow Rate,Permeability,"Zhu, Dancheng; Zou, Huayao; Yang, Minglei; Li, Ting; Li, Tao; Li, Haiping; Xu, Liang; Wen, Long; Zhou, Gang","The Middle Permian Maokou reservoir (southern Sichuan Basin, China): Controls on karst development and distribution",Carbonate reservoir; Reservoir distribution; Reservoir productivity; Dual permeability; Caves; Maokou Formation,EOGENETIC KARST; GAS-FIELD; CARBONATE; PERMEABILITY; CLASSIFICATION; POROSITY; DEPTH,"The Middle Permian Maokou limestone is a major natural gas producing reservoir in the southern Sichuan Basin, China. While matrix porosity is low, bit drops, losses while drilling, blowouts, and extremely high well testing flow rates indicate the presence of a dual permeability system in the form of paleocaves, which were formed by karstification in the late Maokouan Age. A combination of geological, paleogeomorphological and karstic analyses reveal that the development and distribution of the karst features within the reservoir are primarily regulated by shoal facies, paleotopography and syndepositional faults. In our conceptual paleogeomorphological model, the potential cave-bearing zones are located along the rim and outer edge of the Luzhou Paleohigh, which was the highland during the karst. Outside the highland were the karst slopes, and the poljes were on the flanks of the study area. Reservoir performance data suggest, there are two types of sweet spots in the study area. The first corresponds to the syndepositional fault zones along the rim of the karst highland and on the karst slope, where the caves appear to distribute along the faults, impacting the reservoir's vertical permeability. The second corresponds to the shoals of the Mao 2 and Mao 3 members on the lower western karst slope and the upper eastern karst slope, where the caves are widespread, enhancing the horizontal permeability and connectivity of the reservoir. However, the caves are rare in the central karst highland, lower karst slopes, and poljes, which is consistent with the limited gas discoveries.",0,1,2
Flow Rate,Permeability,"Al Ghafri, Al Yaqathan; Mackay, Eric; Stephen, Karl",The relevance of the linear stability theory to the simulation of unstable immiscible viscous-dominated displacements in porous media,Instability predictor; Saffman-Taylor instability; End-point mobility ratio; Fractional flow analysis; Viscous oil; Polymer flooding; Correlated random field,MISCIBLE DISPLACEMENT; INSTABILITIES; MECHANISM; POLYMER; GROWTH; MODELS; FLUID,"The 2D governing equations for the immiscible two-phase flow admissible to linear stability analysis are inspected. The identification of the term v(ws)delta D-st in the generalized Saffman-Taylor criterion is key to the analysis. It can be regarded as a predictor that correlates with observed immiscible instability in terms of the rate of advancement of the viscous pattern, the number of small protrusions, and their roughness in a given heterogeneous domain described by a correlated random field. The predictor is extended, heuristically, for polymer flooding shock-wise and used to characterize the instability of the two shocks. The extension is validated by simulation. The instability of the primary shock is essential when considering the breakthrough recovery. In light of the instability predictor, the geometric interpretations of the fractional flow are essential to understand the stability enhancement of the primary shock over the Buckley-Leverett shock in water flooding. It is also concluded that the end-point mobility ratio does not directly control the immiscible instability. This conclusion was arrived at by fixing the end-point mobility ratios for three sets of relative permeability curves, and yet noticeably different instabilities occur, both in transverse and correlated random fields. The criterion can predict the viscous instability in the laboratory experiments under certain flooding conditions and sample configurations. Concerning the instability in a field scale, the predictor is applicable if the field is regarded as a prototype of a given model experiment.",0,0,2
Flow Rate,Permeability,"Zhang, Lan; Wang, Yingjun; Liu, Ming; Wang, Liquan; Liu, Hengxu",Multiple-flow-regime models for real gas transport in fractal porous media at high pressure,Multiple flow regimes; fractal Porous media; Real gas; High pressure,PERMEABILITY; SHALE; DIFFUSION; NANOPORES,"A Mathematical model for total mass flow rate per unit area and total permeability of real gas flow in fractal porous media was proposed on the basis of fractal theory. Proposed models in this paper paid attention to the influence of real gas effect on gas, taking transition regime as the coupling of slip regime and Knudsen diffusion, considering multi-flow-regime coexist, multi-flow-regime is continuum flow regime, slip flow regime, transition flow regime and Knudsen diffusion regime., pore which pore diameter is A mass flow rate per unit area multiply corresponding pore number dN obtain mass flow rate(dq). Integrate dq within corresponding diameter range and divide fractal porous media work out corresponding flow regime the mass flow rate per unit area. The total mass flow rate per unit area was then calculated through integrating over the mass flow rate deduced, where different flow regimes have been engaged, including continuum regime, slip regime, transition regime and Knudsen diffusion. Based on the Darcy theory, the total permeability was then calculated. In order to verify correctness of model, compare proposed model to Wang's model and Fan's model. Calculate correlation coefficient of proposed model and Wang's model, R-2 = 0.9912; Calculate correlation coefficient of proposed model and Wang's model, R-2 = 0.9997. Indicate that proposed model can fit well with Wang's model and Fan's model, proposed model can correctly predict total permeability. And calculate correlation coefficient of D.B.Bennion experiment data and three model. In the last part, the paper analyzed the influence factor of total mass flow rate per unit area and total permeabilities and mass flow rate per unit area and permeability of different flow regimes. The concludes as follow: (1) total mass flow rate per unit area, total permeability and each flow regime mass flow rate per unit area and permeability increase with fractal dimension(D-p) increasing and tortuous fractal dimension(D-t) decreasing. Variation of D-p and D-t has different influence on each flow regime. D-p and D-t has most influence on Knudsen diffusion flow regime, least influence on continuum flow regime. (2) Real gas effect affects the mass flow rate per unit area and permeability in different flow regime by affecting the mean free path of gas molecule. Whether consider real gas effect would cause great difference, maximum difference is 232.35%. (3) Flow regime that have the lowest Knudsen number play leading role in variation of total mass flow rate and total permeability. (4) The more maximum pore diameter of fractal porous media, the more significant influence of total mass flow rate per unit area and total permeability. Maximum pore diameter has different influence on each flow regime, has most influence on Knudsen diffusion flow regime, least influence on continuum flow regime.",0,0,2
Flow Rate,Permeability,"Redekop, E. P.; Boronin, S. A.; Tolmacheva, K., I; Burukhin, A. A.; Osiptsov, A. A.; Belonogov, E., V","Effects of salinity and rock clogging on injectivity dynamics of flooding wells: Experiments, modeling and validation on field data",Low salinity flooding; Oil displacement; Formation damage; Pore clogging; Field data,FINES-MIGRATION; WETTABILITY ALTERATION; BRINE COMPOSITION; OIL-RECOVERY; WATER; FLOW; DISPLACEMENT,"Injection of water into a rock formation is a common oilfield services technology to maintain high reservoir pressure and increase ultimate recovery of hydrocarbons. While flowing through the well from surface to the rock formation, injected water typically transports fine particles, for example, fine sand grains and calcite precipitated at surface pipeline conditions while mixing water from different sources (e.g., fresh, Cenomanian and formation brine). In the framework of the two-fluid approach to suspension flow modelling, we formulate mathematical model for linear filtration of a particle-laden suspension in the vicinity of a fractured flooding well and transport of ion concentration (salinity). Two major factors of well injectivity decline are described, namely, particle trapping with associated reduction in permeability and porosity of the rock as well as the effect of salinity of injecting water leading to clay swelling, calcite precipitation and change of relative permeabilities of the rock with respect to water and oil. We calibrate suspension filtration model against in-house experiments on clogging of artificial and natural rock cores, in which the profiles of fines concentration along the cores are obtained using X-Ray computed tomography and analysis of 3D rock reconstruction images. The water injection model is adopted to conditions of Priobskoye oilfield of Western Siberia by using the results of standard laboratory experiments on fluid-fluid (calcite precipitation) and fluid-rock (clay swelling, migration of internal fines) compatibility, as well as the effect of salinity on oil displacement and analysis of solid fraction in the injecting water. The calibrated model is then used to describe field data on dynamics of injection rate of three flooding wells. It is obtained that the simulations predict the long-term injectivity dynamics of the wells very well, while at early times (up to 5 months from the start of injection) the model underestimates the injection rate. While fitting the model to field data, we varied only two parameters, namely, solids concentration in the injecting water (in the range provided by lab experiments) and trapping coefficient (the range is limited to result of experiments made with target rock cores). It is demonstrated that only a combination of injectivity decline factors allows to describe the long-term flooding rate of the wells. Ignoring either particle trapping or salinity effects lead to significant overestimation (up to 50%) of the long-term injection rate. Parametric study of water injection showed that two-fold increase in solids concentration in the injecting water as well as oil compressibility lead to similar decrease in long-term injection rate of a well.",0,0,2
Flow Rate,Drilling,"Gjerstad, Kristian; Aamo, Ole Morten",A dynamic model of two-phase flow for simulating gas kick and facilitating model-based control in drilling operations,Gas influx dynamics; Transient kick detection model; Gas bubble propagation in drilling well; Control-oriented gas-liquid model; Low-order two-phase flow model,,"A low-order two-phase dynamic flow model for drilling operations with gas kick is developed. The purpose is to enable fast and robust simulation of the behavior and propagation of influx gas in the bore hole, and the effects it has on the total flow dynamics. The model handles both open and closed wells, as well as the full range of pump rates and gas influx rates that are likely to occur in drilling operations. It incorporates equations for gas bubbles into a low-order liquid model in a new way. Some aspects of the gas are described in a mechanistic way, but with a new ""dual-shape"" bubble representation approach. Momentum is treated for the mixture as a whole, while conservation of mass is handled individually for each of the two phases. The result is a model consisting of a set of ordinary differential equations on explicit form, which makes it possible to couple it with control system- and estimation theory. A comparison with published data from four different sources shows that the model is able to qualitatively reproduce both steady state and transient responses in a handful quite different flow situations. In particular, we verified that the dominating effects that the gas has on compressibility, friction loss and hydrostatic pressure of the total mixture are satisfactory reproduced.",0,0,0
Flow Rate,Drilling,"Kryganov, P., V; Afanaskin, I., V; Volpin, S. G.; Akhapkin, M. Yu; Yalov, P., V",Searching for reservoirs with bypassed oil using well tests and mathematical modeling,Bypassed oil; Residual oil reserves; Hydrodynamic simulation; Well test; Pressure buildup test; Interference test; Flow analysis,,"The increase of oil recovery by the involvement of bypassed oil into production is a significant source of oil production increase at a minimal cost. Bypassed oil zones identification possibilities researched through mathematical flow modeling and simulated well tests. Two hypothetical models of homogeneous and heterogeneous (with low permeability zones) oil formations were generated, in which the bypassed oil was trapped during the production. Based on these models, the authors calculated data of comprehensive well tests: buildup, drawdown and interference. The aspects of the well test interpretation results data obtained for both models through the best-match method allowed bypassed oil areas identification possibility assessment. A significant difference between the cumulative oil rate actually observed at the field and the one obtained in the model is the first diagnostic feature, which suggests the presence of bypassed oil. During the pressure buildup (drawdown) tests, the curves of pressure change derivatives on the Bourdet diagnostic plots for heterogeneous and homogeneous models differ significantly, which is the second diagnostic feature that suggests the presence of bypassed oil. The analysis of the data processing results obtained during the pressure buildup tests indicated cases of significant changes in conductivity over time which is associated with higher water cut due to the absence of any obstacles for water to flow through. This factor can be considered a third diagnostic feature. During the interference tests of a heterogeneous model in multiple directions, the permeability of the interwell space in all directions turned out to be much lower in comparison to the reservoir permeability in the vicinity of the wells, that is explained by the bypassed oil presence - this is the fourth diagnostic feature which suggests the bypassed oil presence in the interwell space. The obtained results of well test data interpretation means a possibility to identify undeveloped areas with bypassed oil, filtration model improvement and recommendations development of infill drilling or sidetracks for the residual reserves extraction.",0,0,0
Flow Rate,Drilling,"Krishna, Shwetank; Ridha, Syahrir; Campbell, Scott; Ilyas, Suhaib Umer; Dzulkarnain, Iskandar; Abdurrahman, Muslim",Experimental evaluation of surge/swab pressure in varying annular eccentricities using non-Newtonian fluid under Couette-Poiseuille flow for drilling applications,Concentric and eccentric annulus; Couette-Poiseuille (CP) flow; Drilling; Non-Newtonian fluid; Surge; swab pressure gradient,SWAB PRESSURES; FOOD PROCESSES; MASS-TRANSFER; MODEL; EQUATIONS,"Global energy demand is rapidly increasing at a rate of 8% between 2004 and 2019, and conventional energy sources are unable to meet this requirement. Therefore, the oil and gas energy industry is working continuously to produce unconventional energy sources such as deepwater oil and gas reservoirs, gas hydrates, and geothermal energy using drilling operations. In the drilled borehole, the stability and integrity issues are encountered that are related to pressure differential generated by the Couette-Poiseuille (CP) fluid flow phenomenon occurred during pipe tripping operation. There is a lack of experimental data to comprehend the impact of CP flow on pressure differential using non-Newtonian fluid in concentric and eccentric annuli, especially in petroleum exploration. Hence, an experimental investigation is performed to replicate the tripping operations during oil and gas well drilling. The investigation provides an extensive understanding of the physical and mechanical characteristics of non-Newtonian fluids under CP flow at varying inner pipe tripping speeds (0.030481-0.21336 m/s), rheological properties, and geometrical dimensions. The results indicate that surge/ swab pressure gradient tends to decrease with increasing eccentricity (epsilon) and increase with increasing diameter ratio (delta) and pipe tripping speed (Vp). Furthermore, the pressure differential rate is considerably high at low tripping speed but reduces at high pipe tripping speed due to the shear-thinning behavior of YPL fluid. The study also reveals that gel strength increases the surge/swab pressure gradient by approximately 18%. A multi-variable correlation is developed to predict surge/swab pressure gradient, exhibiting an excellent agreement with experimental data and existing theoretical models.",0,0,1
Flow Rate,Drilling,"Wang, Chao; Liu, Gonghui; Li, Jun; Zhang, Tao; Jiang, Hailong; Huang, Honglin; Zhu, Zhongxi; Luo, Ming; Huang, Peng",Downhole mud loss transient simulation and detection with downhole dual measurement points,Mud loss detection; Characteristic lines; Machine learning; Downhole pressure difference measurement; Measurement of theological parameters; Unscented kalman filter,KICK DETECTION; FLOW MODEL; CIRCULATION; DIAGNOSIS,"Mud loss is usually challenging to discover in time by detecting the mud pit's liquid level, leading to a significant wastage of time and money. Due to the measurement-while-drilling system's low data-transmission speed, downhole measured data is usually ignored in mud loss detection. What is more, surface detection methods comprising pressure and flow-rate sensors require professional knowledge and many input parameters, some of which are required to be assumed. In this study, we proposed a downhole mud loss detection method based on downhole dual measurement points without any use of surface input parameters, which significantly increased the detection method's feasibility. Firstly, we established an end-to-end neural network to recognize the downhole ten working conditions. Once the static and circulation working conditions are recognized, the drilling fluid's density and rheological parameters can be automatically determined with the proposed method. Then, an unscented Kalman filter was applied to perform a backward calculation of mud loss rate dynamically. Thirdly, we proposed a new pressure difference measurement method with high precision, capturing the flow friction pressure consumption in a short distance. To evaluate the mud loss detection method comprehensively, we built the downhole mud loss transient simulation model to generate transient data with the highest possible accuracy. The characteristic lines method was used to solve the partial differential equations of the mud loss simulation model. The accuracy of the simulation model was successfully validated with a small-scale laboratory experiment in the horizontal direction, a full-scale laboratory experiment in the vertical, and a real field experiment. Finally, we generated a set of mud loss well data to describe the proposed mud loss detection method's processes in detail. The results showed that the proposed mud loss detection model successfully detected mud loss and obtained the accurate mud loss rate.",0,0,1
Flow Rate,Drilling,"Zhu, Dancheng; Zou, Huayao; Yang, Minglei; Li, Ting; Li, Tao; Li, Haiping; Xu, Liang; Wen, Long; Zhou, Gang","The Middle Permian Maokou reservoir (southern Sichuan Basin, China): Controls on karst development and distribution",Carbonate reservoir; Reservoir distribution; Reservoir productivity; Dual permeability; Caves; Maokou Formation,EOGENETIC KARST; GAS-FIELD; CARBONATE; PERMEABILITY; CLASSIFICATION; POROSITY; DEPTH,"The Middle Permian Maokou limestone is a major natural gas producing reservoir in the southern Sichuan Basin, China. While matrix porosity is low, bit drops, losses while drilling, blowouts, and extremely high well testing flow rates indicate the presence of a dual permeability system in the form of paleocaves, which were formed by karstification in the late Maokouan Age. A combination of geological, paleogeomorphological and karstic analyses reveal that the development and distribution of the karst features within the reservoir are primarily regulated by shoal facies, paleotopography and syndepositional faults. In our conceptual paleogeomorphological model, the potential cave-bearing zones are located along the rim and outer edge of the Luzhou Paleohigh, which was the highland during the karst. Outside the highland were the karst slopes, and the poljes were on the flanks of the study area. Reservoir performance data suggest, there are two types of sweet spots in the study area. The first corresponds to the syndepositional fault zones along the rim of the karst highland and on the karst slope, where the caves appear to distribute along the faults, impacting the reservoir's vertical permeability. The second corresponds to the shoals of the Mao 2 and Mao 3 members on the lower western karst slope and the upper eastern karst slope, where the caves are widespread, enhancing the horizontal permeability and connectivity of the reservoir. However, the caves are rare in the central karst highland, lower karst slopes, and poljes, which is consistent with the limited gas discoveries.",0,1,2
Flow Rate,Drilling,"Yousefi, Seyed Hamidreza; Rashidi, Fariborz; Sharifi, Mohammad; Soroush, Mohammad; Ghahfarokhi, Ashkan Jahanbani",Interwell connectivity identification in immiscible gas-oil systems using statistical method and modified capacitance-resistance model: A comparative study,Capacitance-resistance model; Gas injection; Interwell connectivity; Least square support vector machine,FLOODING PERFORMANCE; INJECTION; FLOW; OPTIMIZATION; PREDICTION; FIELD,"Interwell connectivity identification between injector-producer well pairs and hydrocarbon production estimation are essential parameters in reservoir management, which can determine unrecovered oil volume and reservoir continuity. Although there are several published methods for determination of interwell connectivity in water-oil systems, there is no such comprehensive study on gas flooded reservoirs. Due to the high mobility of gas, interwell connectivity is a critical criterion in channelized, faulted and heterogeneous reservoirs for reservoir characterization, production optimization, infill drilling and performance predication. There are physical and statistical techniques to determine interwell connectivity mathematically and identify reservoir flow dynamics without using any operational activities. All methods are working with limited production data and unlike the numerical simulators, they are simple and do not require detailed data. In this paper, modified capacitance-resistance model (or M-CRM as a physical approach) and combination of least square support vector machine and multiple linear regression (as a statistical approach) are applied to two immiscible gas injection cases with different assumptions, and the results are compared. The results show that both methods are reliable in terms of validity, speed and flexibility. The physical approach (M-CRM) is more accurate for interwell connectivity prediction while the statistical method is more precise for producer total rate estimation.",0,0,3
Flow Rate,Drilling,"Yang, Mou; Luo, Hao; Xie, Rongxuan; Wu, Pengcheng; Yang, Mingzheng; Yang, Lvchao; Xue, Hu",Estimating and optimizing wellbore pressure during primary cementing in low pressure and leakage formations,Circulating pressure; Cementing operation; Low pressure and leakage formations; Mathematical model; Computational fluid dynamics,NON-NEWTONIAN FLUIDS; POWER-LAW FLUID; HERSCHEL-BULKLEY; ECCENTRIC ANNULI; DRILLING-FLUIDS; TURBULENT-FLOW; LAMINAR; CIRCULATION; TRANSITION; BEHAVIOR,"In most realistic situations, casing eccentricity and various fluids injected during primary cementing lead to a significant difference in fluid flow and circulating pressure, compared with a single fluid flowing in the concentric annulus. Ignoring the effect of eccentricity and fluid rheological model on the wellbore circulating pressure results in an inaccurate evaluation and leads to formation leakage, especially for low pressure and leakage formations. To overcome this challenge, firstly, rheological models of various fluids were analyzed using experimental data, including drilling fluid, spacer, and cement slurry. Secondly, the modified correlations of frictional pressure losses for Herschel-Bulkley and Power Law fluids in the eccentric annulus were developed, using the simulation data of computational fluid dynamics software (CFD) and considering the effects of flow behavior index, pipe diameter ratio, and casing eccentricity on the frictional pressure losses. Finally, based on the developed mathematical models, the optimal method of primary cementing and evaluation results were presented, analyzed, and tested in the field with great success. The results demonstrated that the drilling fluid and spacer fluid had the highest goodness of fit for the Herschel-Bulkley model, and the cementing slurry was suitable for the Power Law model. The ratio coefficient of pressure loss in the eccentric to concentric annulus decreased with a decrease of hole size and an increase of casing eccentricity. A 50 percent reduction in frictional pressure loss was evaluated when the casing lies on the borehole wall. Comparing the calculations of the developed correlation with the published correlation in the literature reveals a more accurate evaluation of friction pressure losses in the analyzed case. Combined with the realistic situation of a test well, the density, flow rate, and returning depth of the lead cement slurry were recommended as 1.5 g/cm(3), 0.5 m(3)/min and 4100 m, respectively, according to the leakage pressure of 65.6 MPa that was calculated by the developed mathematical model. Most importantly, the developed method in this paper can accurately predict the variation characteristics of wellbore pressure during the primary cementing process and provide effective guidance in managing downhole pressure in low pressure and leakage formations by real-time adjustment of the most effective and controllable operation parameters.",0,0,3
Flow Rate,Drilling,"Ettehadi, Ali; Ulker, Ceylan; Altun, Gursat",Nonlinearity in large amplitude oscillatory shear of drilling fluid: A comparative study on the oil and water base muds behavior,Drilling fluid; Nonlinear viscoelasticity; Large amplitude oscillatory shear (LAOS); Shear mechanism; Structural stability,VISCOELASTIC PROPERTIES; PRESSURE-DROP; LAOS BEHAVIOR; MODEL; RHEOLOGY; STRESS; TRANSITION; VISCOSITY; EQUATION,"A viscoelastic material exhibits both fluid (viscous) and solid (elastic) like properties simultaneously. The rheological behavior of drilling fluids is customarily measured under the assumption of pure viscous flow, yet they exhibit both viscous and elastic characteristics when subjected to deformation. Some imperative properties of drilling fluids such as gel strength, yield stress, and sag tendency at near-zero shear rate region are categorically under the influence of viscoelastic behavior and have not yet been completely understood due to the lack of appropriate measurement methods. Characterizing the complete rheological profile of material requires measuring linear and nonlinear viscoelastic responses at a wide range of stress/strain levels. The viscoelastic nonlinearity can be characterized under Large Amplitude Oscillatory Shear (LAOS) tests. This study presents a large amplitude oscillatory shear rheology investigation of two water-base (Lignosulfonate and KCl/polymer) and two oil-base (low and high temperature) drilling fluids each in three states; unweighted, weighted, and weighted-contaminated. The viscoelastic nonlinearities of four fluid samples were investigated experimentally as a function of strain amplitude and strain-rate space at different temperatures. The results were described using Lissajous-Bowditch (L-B) plots and local nonlinear viscoelastic dynamic moduli through an oscillatory shear cycle. Structural stability of fluid samples was also studied using the creep-recovery test. The nonlinear viscoelastic behavior of drilling fluids was comprehensively compared and distinguished to understand their nonlinear shear mechanism. As a result of the creep-recovery test at 150 degrees C, high-temperature oil base mud provided higher thermostructural stability and zero shear viscosity than those of Lignosulfonate, KCl/polymer, and low-temperature oil-base muds. While the elastic nonlinearity was found to be strain/strain rate softening, the nonlinear viscous character was recorded as shear/shear rate thinning at large strain rates for all drilling fluid systems. Quite a different shear mechanism was detected at low and moderate strain rates. Shear rate thinning was found to be the dominant mechanism for all fluids except Lignosulfonate mud samples that demonstrated shearthickening behavior at moderate strain rates at 25 degrees C. At high temperatures (100 degrees C and 150 degrees C), shear rate thickening followed by shear rate thinning behavior was governing mechanism under the low and moderate strain rates in all mud samples except KCl/polymer muds. An inverse behavior (shear rate thinning followed by shear rate thickening) was observed through low and moderate strain rates in KCl/polymer muds at 100 degrees C and 150 degrees C. Therefore, as revealed from the LAOS test results, shear rate thickening behavior at low to moderate strain rates is in contradiction of the commonly known shear thinning behavior for a drilling fluid undergoing viscous deformation. This finding explains the facts underlying some important properties of drilling fluids such as gel structure formation, hole cleaning ability, and sag tendency.",0,0,3
Flow Rate,Pressure Drop,"Hasan, A. Rashid; Jang, Minsoo",An analytic model for computing the countercurrent flow of heat in tubing and annulus system and its application: Jet pump,Jet pumps; Artificial lift; Counter-current flow; Tubing-annulus heat-transfer; Heat balance-based ODE,TEMPERATURE PROFILE; FLUID TEMPERATURE; STEAM,"Shale fields are currently over-reliant on electric submersible pumps (ESPs) in the early stage of artificial lift despite its weakness to sandy flow and often failing within the first three months. Jet pumps are reliable and costeffective alternatives to the ESPs. Current studies on jet pumps have focused on designing parameters for maximizing performance; however, there have been very few investigations on predicting temperature profiles in the wellbore with a jet pump in use. Fluid temperature influences viscosity; hence, the production of heavy oil. Typically, the heavier the hydrocarbon, the greater is the variation in viscosity with temperature. Therefore accurate temperature prediction is essential for the efficient design of heavy oil production facilities. This paper offers an analytic model to compute temperature profiles in the tubing and annulus. Results show a good match with a field data set. Data set from a well in Tah field in China is used to validate the model. In addition, sensitivity analyses were performed that showed that injection temperature affects the annulus temperature profile, leading to significant changes in frictional pressure loss at shallow depths. In contrast, injection rate has less influence on temperature profiles, although, of course, higher fluid velocity causes greater frictional losses. Results show that a hotter and relatively small flow rate leads to lesser pumping cost by reducing frictional pressure drop during the operation. The proposed model ideally requires the bottom-hole temperature as a boundary condition (BC). When subsurface temperature data are unavailable, as often the case due to cost, a computing method is offered in the paper for reliable temperature profile estimation from only two data points at the wellhead.",0,0,0
Flow Rate,Pressure Drop,"Rodrigues, Hendy T.; Almeida, Alcino R.; Barrionuevo, Daniel C.; Fraga, Ricardo S.",Effect of the gas injection angle and configuration in the efficiency of gas lift,Gas lift; Gas-liquid mixing; Crossflow gas injection; Upward gas injection; Downward gas injection,BUBBLE FORMATION; FLOW,"In oil wells using gas lift as a method of artificial lift, the gas is normally injected inside the tubing at a downward direction, i.e., in countercurrent flow relative to the fluids coming from the reservoir. This creates turbulence in the flow, causing pressure drop for the gas to change direction and to flow upward along with the produced fluid. The optimization of this geometry, by changing the gas injection angle, for instance, may introduce some gain. In this paper, we present theoretical analyzes and computer simulation showing that, for high gas injection flow rates and/or small jet diameters, it is possible to obtain a gain when reversing the direction of the gas injection. Although it is intuitive that an upward injection can improve the flow, experiments are needed to give confidence to this proposal. However, there is very few studies in the literature addressing this issue. To improve the knowledge of subject, this study shows experiments performed using an experimental well flowing oil and natural gas. Such an experiment, at real scale configurations and fluids is unique. The usual configuration, injecting downward, was compared with two alternatives, injecting the gas jet upward and injecting in an annular pattern. This article describes and discusses the tests and the results obtained. Although the tests have not been performed with the ideal conditions to maximize the gain, the results were consistent and conclusive. A slight local gain was observed due to the gas angle change, consistent with the previsions of a simple theoretical model. The estimated gains can reach 2 bar and are obtained at no additional cost by simply inverting the gas jet direction, but it is more effective for wells with high gas injection flow rate. Since gas lift is applied to a large number of wells, even a modest gain can be significant in the overall context. Based on the results, it is speculated that there is probably an optimum way to inject gas by taking advantage of the jet inversion and of the reduction on slippage between gas and liquid.",0,0,0
Flow Rate,Pressure Drop,"Alhosani, Ahmed; Daraboina, Nagu",Effect of multi-phase flow on asphaltene deposition: Field case application of integrated simulator,Flow assurance; Multiphase flow; Asphaltene deposition,GAS-LIQUID FLOW; HEAT-TRANSFER; PARTICLE DEPOSITION; UNIFIED MODEL; CRUDE OILS; TOOL ADEPT; PRECIPITATION; SLUG; HOLDUP; AGGREGATION,"Asphaltene is initially stable in the oil, but when there is a change in pressure, temperature, or composition, particles tend to phase out and form precipitants. Issues arise when those particles diffuse toward the wall and deposit, which contributes to reducing the flowing area and increasing the pressure drop. Preventing precipi-tation is the optimum solution to maintain the target production rate; however, it is challenging to avoid favorable precipitation conditions. Remedies and treatments to mitigate this issue cause the oil industry a considerable increase in expenditure and time; thus, it is necessary to develop a tool to accurately predict the deposition for a wide range of operating conditions, especially in multiphase flow. In this study, a multiphase simulator is developed by coupling thermodynamics, hydrodynamics, heat transfer, and asphaltene modules to predict the deposition. A deposition data obtained from a field case is used to validate the robustness of the simulator. The simulator results matched well with the asphaltene deposition and the equilibrium profile available in the literature. The simulation approach presented here offers useful insights into the effect of multiphase flow on asphaltene deposition and eventually aid in improving the accuracy of pre-diction. Using single-phase assumption under multiphase conditions contributed to a significant error in the prediction, and these inaccuracies may lead to a substantial economic and operational burden for the oil and gas industry.",0,0,0
Flow Rate,Pressure Drop,"Chaves, Gabriela Souza; Karami, Hamidreza; Ferreira Filho, Virgilio Jose Martins; Vieira, Bruno Ferreira",A comparative study on the performance of multiphase flow models against offshore field production data,Multiphase flow; Production optimization; Offshore data analysis; Flow assurance; Flow models,2-PHASE FLOW; PRESSURE-DROP; PATTERN TRANSITIONS; MECHANISTIC MODEL; PREDICTING FLOW; VISCOSITY; OIL,"In the oil industry, multiphase flow models are commonly used to simulate the flow from reservoir to the production unit. Flow simulations help in the production monitoring and optimization to support the decisionmaking process. Despite the need for accurate simulations to support production operations, multiphase flow models are mostly developed using laboratory data and rarely validated under field-scale conditions. To improve the understanding of multiphase flow models in field conditions, this work evaluates the performance of a large set of models for a dataset composed of two production units with 20 producing wells and 865 measured production points. The wells are divided and analyzed in two segments: the surface flowline and the wellbore. The evaluation compares the models' performances using various statistical parameters and trending charts. The evaluation analyzes the impacts of production parameters, well geometry, predicted flow pattern, and pressure drop components on the model performances. Overall, Ansari's model presented the best performance with 13.8% absolute average percent error for the flowline segment and 14.1% error for the wellbore segment. In addition, Gray can also generate good results for most but not all of the tested wellbores. From the production parameters evaluation, higher flow rate tests resulted in more stable outputs. Ansari and Beggs models showed a trend of increasing errors for wells with larger horizontal wellbore lengths. Also, Beggs model showed larger errors when the transition flow pattern was predicted. Finally, both Ansari and Beggs models showed larger overprediction errors for tests with higher pressure losses in the flowline segment, while Gray showed smaller errors for these cases. The conclusions can be used to select the best models given the production system's flow parameters, or be incorporated in systems to increase the accuracy.",0,0,0
Flow Rate,Pressure Drop,"Tavakkoli, Mohammad; Panuganti, Sai R.; Khemka, Yash; Valdes, Humberto; Vargas, Francisco M.",Foam-assisted gas lift: A novel experimental setup to investigate the feasibility of using a commercial surfactant for increasing oil well productivity,Pressure drop; Foam; FAGL; Artificial lift; Wellbore productivity; Multiphase flow,,"Most oil wells require artificial lift at some point to increase the life of the field and enhance production. Conventional methods such as gas lift are not effective in depleted reservoirs with high water cut where very high gas injection rates are required for relatively low oil production rates. Consequently, foamers or surfactants, which have been previously applied for de-liquifying gas wells, are now used in depleted gas-lifted oil wells to either boost production rates or reduce gas lift requirements while maintaining production levels. While there is a growing global interest, foam-assisted gas lift (FAGL) is a relatively modern artificial lifting method with less experience regarding its applications in oil wells. In this study, the feasibility of using a commercial surfactant for improving oil well productivity is investigated via laboratory experiments. A novel laboratory setup resembling a vertical well rig is designed to analyze the impact of surfactant concentration, temperature, brine salinity and phase-specific flow rates (or flow regimes) on the pressure drop across the column. This setup is operational at high temperatures, requires minimal sample amounts, and significantly reduces the experimental errors in pressure drop readings, resulting in highly accurate and stable measurements. The laboratory tests confirm that the addition of foamer reduces pressure drop in the production tubing, thus effectively increasing production. Additionally, an optimal foamer concentration is also detected. The results obtained in this study are very promising and present opportunities to explore a new chapter in artificial lift and production enhancement techniques.",0,0,0
Flow Rate,Pressure Drop,"Eghbali, Sara; Banks, Jonathan; Nobes, David S.",A numerical study on compositional modeling of two-phase fluid flow and heat transfer in vertical wells,Two-phase flow; Pressure drop; Heat transfer; Geothermal energy; Equation of state; Vertical well,,"Geothermal energy is a sustainable and renewable source that can be extracted by circulating a single- or two-phase fluid through a geothermal well system. Two-phase flow and heat transfer models are required for predicting pressure and temperature profiles in oil, gas, and geothermal wells. We model fluid flow, thermodynamics and heat transfer in an idealised vertical well for single-(i.e., water) and two-phase fluid mixtures (CO2-, and air-water) under a bubbly flow regime. First, we calibrated a Peng-Robinson Equation of State (PR-EOS) for CO2-, and air-water systems. Second, we solved continuity, energy and momentum equations and modelled transient conductive heat transfer through the well. Third, we investigated the effects of mass flow rate, transient heat transfer, single- and two-phase fluid on the extracted power, temperature, and pressure profiles of the deep well bore heat exchanger. The results show that the temperature of the hot fluid decreases as it flows to the surface both in the case of adiabatic flow and in cases with heat loss. The mass flow rate controls the fluid temperature drop during its ascent to the surface. The production pressure of a gas-liquid phase system is higher than that of a system with single liquid phase at the same injection pressure, temperature, and mass flow rate. Increasing mass flow rate up to a threshold value leads to an increase in the production pressure. Above the threshold mass flow rate (i.e., 7 kg/s in this study), the production pressure reduces because of the significant increase in the frictional pressure drop. Production temperature, production pressure, and total power increases over time due to the local heating around the production well and reduction of the heat loss.",0,0,2
Flow Rate,Pressure Drop,"Ettehadi, Ali; Ulker, Ceylan; Altun, Gursat",Nonlinearity in large amplitude oscillatory shear of drilling fluid: A comparative study on the oil and water base muds behavior,Drilling fluid; Nonlinear viscoelasticity; Large amplitude oscillatory shear (LAOS); Shear mechanism; Structural stability,VISCOELASTIC PROPERTIES; PRESSURE-DROP; LAOS BEHAVIOR; MODEL; RHEOLOGY; STRESS; TRANSITION; VISCOSITY; EQUATION,"A viscoelastic material exhibits both fluid (viscous) and solid (elastic) like properties simultaneously. The rheological behavior of drilling fluids is customarily measured under the assumption of pure viscous flow, yet they exhibit both viscous and elastic characteristics when subjected to deformation. Some imperative properties of drilling fluids such as gel strength, yield stress, and sag tendency at near-zero shear rate region are categorically under the influence of viscoelastic behavior and have not yet been completely understood due to the lack of appropriate measurement methods. Characterizing the complete rheological profile of material requires measuring linear and nonlinear viscoelastic responses at a wide range of stress/strain levels. The viscoelastic nonlinearity can be characterized under Large Amplitude Oscillatory Shear (LAOS) tests. This study presents a large amplitude oscillatory shear rheology investigation of two water-base (Lignosulfonate and KCl/polymer) and two oil-base (low and high temperature) drilling fluids each in three states; unweighted, weighted, and weighted-contaminated. The viscoelastic nonlinearities of four fluid samples were investigated experimentally as a function of strain amplitude and strain-rate space at different temperatures. The results were described using Lissajous-Bowditch (L-B) plots and local nonlinear viscoelastic dynamic moduli through an oscillatory shear cycle. Structural stability of fluid samples was also studied using the creep-recovery test. The nonlinear viscoelastic behavior of drilling fluids was comprehensively compared and distinguished to understand their nonlinear shear mechanism. As a result of the creep-recovery test at 150 degrees C, high-temperature oil base mud provided higher thermostructural stability and zero shear viscosity than those of Lignosulfonate, KCl/polymer, and low-temperature oil-base muds. While the elastic nonlinearity was found to be strain/strain rate softening, the nonlinear viscous character was recorded as shear/shear rate thinning at large strain rates for all drilling fluid systems. Quite a different shear mechanism was detected at low and moderate strain rates. Shear rate thinning was found to be the dominant mechanism for all fluids except Lignosulfonate mud samples that demonstrated shearthickening behavior at moderate strain rates at 25 degrees C. At high temperatures (100 degrees C and 150 degrees C), shear rate thickening followed by shear rate thinning behavior was governing mechanism under the low and moderate strain rates in all mud samples except KCl/polymer muds. An inverse behavior (shear rate thinning followed by shear rate thickening) was observed through low and moderate strain rates in KCl/polymer muds at 100 degrees C and 150 degrees C. Therefore, as revealed from the LAOS test results, shear rate thickening behavior at low to moderate strain rates is in contradiction of the commonly known shear thinning behavior for a drilling fluid undergoing viscous deformation. This finding explains the facts underlying some important properties of drilling fluids such as gel structure formation, hole cleaning ability, and sag tendency.",0,0,3
Flow Rate,Gas Injection,"Hasanzadeh, Maryam; Azin, Reza; Fatehi, Rouhollah; Zendehboudi, Sohrab",New insights into forced and free fall gravity drainage performance in a fractured physical model,Fractured physical model; Gas injection; Recovery factor; Free fall gravity drainage; Forced gravity drainage,TERTIARY OIL-RECOVERY; POROUS-MEDIA; WETTABILITY; DISPLACEMENT; SECONDARY; FLOW,"Gravity is one of the major driving forces for fluid flow in naturally fractured reservoirs. Gravity drainage appears to be a vital recovery mechanism over the oil production process in a majority of fractured reserves. In this paper, free-fall gravity drainage (FFGD) and forced gravity drainage (FGD) production approaches are investigated through employing a new fractured sand pack with a rectangular geometry. Distilled water and condensate are used as the wetting phase. Nitrogen, carbon dioxide, and air are also utilized as the non-wetting phase. A systematic sensitivity analysis is conducted to find the effects of the key factors such as fracture blockage, injection rate, dip angle, and type of wetting phase and injection fluid on the performance of FFGD and FGD processes. Also, a numerical simulation is performed to simulate the experiments. Results reveal that the FGD has a better performance under controlled process conditions, compared to the FFGD so that gas injection with a controlled rate improves the recovery. Moreover, it was found that increasing the gas injection rate improves the recovery factor (RF) of wetting-phase when the up and bottom sides of the fractures are blocked; the RF is decreased in the case with open fracture sides. The recovery of the wetting phase decreases in both FFGD and FGD modes when the porous system has a deviation from the vertical orientation. According to the study outcomes, the immiscible gas-assisted gravity drainage offers a higher condensate recovery, compared to water recovery, due to lower viscosity and interfacial tension (IFT) of the condensate phase. The comparison of the experimental data and simulation results implies that the simulation approach can satisfactorily predict the performance of the FGD process. Based on the error analysis, there is a good match between the simulation results and the experimental measurements; the fluid pair of CO2-condensate exhibits the highest accuracy with an R-squared of 0.9961 and an average relative error (ARE) of 0.0054.",0,0,0
Flow Rate,Gas Injection,"Rodrigues, Hendy T.; Almeida, Alcino R.; Barrionuevo, Daniel C.; Fraga, Ricardo S.",Effect of the gas injection angle and configuration in the efficiency of gas lift,Gas lift; Gas-liquid mixing; Crossflow gas injection; Upward gas injection; Downward gas injection,BUBBLE FORMATION; FLOW,"In oil wells using gas lift as a method of artificial lift, the gas is normally injected inside the tubing at a downward direction, i.e., in countercurrent flow relative to the fluids coming from the reservoir. This creates turbulence in the flow, causing pressure drop for the gas to change direction and to flow upward along with the produced fluid. The optimization of this geometry, by changing the gas injection angle, for instance, may introduce some gain. In this paper, we present theoretical analyzes and computer simulation showing that, for high gas injection flow rates and/or small jet diameters, it is possible to obtain a gain when reversing the direction of the gas injection. Although it is intuitive that an upward injection can improve the flow, experiments are needed to give confidence to this proposal. However, there is very few studies in the literature addressing this issue. To improve the knowledge of subject, this study shows experiments performed using an experimental well flowing oil and natural gas. Such an experiment, at real scale configurations and fluids is unique. The usual configuration, injecting downward, was compared with two alternatives, injecting the gas jet upward and injecting in an annular pattern. This article describes and discusses the tests and the results obtained. Although the tests have not been performed with the ideal conditions to maximize the gain, the results were consistent and conclusive. A slight local gain was observed due to the gas angle change, consistent with the previsions of a simple theoretical model. The estimated gains can reach 2 bar and are obtained at no additional cost by simply inverting the gas jet direction, but it is more effective for wells with high gas injection flow rate. Since gas lift is applied to a large number of wells, even a modest gain can be significant in the overall context. Based on the results, it is speculated that there is probably an optimum way to inject gas by taking advantage of the jet inversion and of the reduction on slippage between gas and liquid.",0,0,0
Flow Rate,Gas Injection,"Tavakkoli, Mohammad; Panuganti, Sai R.; Khemka, Yash; Valdes, Humberto; Vargas, Francisco M.",Foam-assisted gas lift: A novel experimental setup to investigate the feasibility of using a commercial surfactant for increasing oil well productivity,Pressure drop; Foam; FAGL; Artificial lift; Wellbore productivity; Multiphase flow,,"Most oil wells require artificial lift at some point to increase the life of the field and enhance production. Conventional methods such as gas lift are not effective in depleted reservoirs with high water cut where very high gas injection rates are required for relatively low oil production rates. Consequently, foamers or surfactants, which have been previously applied for de-liquifying gas wells, are now used in depleted gas-lifted oil wells to either boost production rates or reduce gas lift requirements while maintaining production levels. While there is a growing global interest, foam-assisted gas lift (FAGL) is a relatively modern artificial lifting method with less experience regarding its applications in oil wells. In this study, the feasibility of using a commercial surfactant for improving oil well productivity is investigated via laboratory experiments. A novel laboratory setup resembling a vertical well rig is designed to analyze the impact of surfactant concentration, temperature, brine salinity and phase-specific flow rates (or flow regimes) on the pressure drop across the column. This setup is operational at high temperatures, requires minimal sample amounts, and significantly reduces the experimental errors in pressure drop readings, resulting in highly accurate and stable measurements. The laboratory tests confirm that the addition of foamer reduces pressure drop in the production tubing, thus effectively increasing production. Additionally, an optimal foamer concentration is also detected. The results obtained in this study are very promising and present opportunities to explore a new chapter in artificial lift and production enhancement techniques.",0,0,0
Flow Rate,Gas Injection,"Altaheini, Suleiman; Mostaghimi, Peyman; Clark, Stuart R.",Incorporating adaptive well conditions into numerical reservoir simulators constrained by well and reservoir performance data,Adaptive well control; Adaptive well conditions; Water flooding; Improved oil recovery; Extended well lifetime,OPTIMAL INJECTION POLICIES; ENHANCED OIL-RECOVERY; OPTIMIZATION; PLACEMENT; ALGORITHM,"Using fixed boundary conditions has always been the way wells are modelled in reservoir simulators for prediction runs. This commonly results in oil wells being shut-in due to increasing production of water or gas or triggering a workover option shutting-in a section of the wells perforated interval. These actions are late reactive actions instead of being proactive actions that can help prolong a wells life. In actual field operations, well flow rates and bottomhole pressures are often adjusted to better suit reservoir management strategies and control water and gas production. This paper introduces a novel yet simple implementation of adaptive well conditions that updates well boundary conditions based on wellbore or near-wellbore performance. This methodology can be executed using a commercial simulator alongside a small instructing application, or internally integrated as done here with an inhouse reservoir simulator built to present this work as proof of concept. Three case studies are presented in this paper with increasing complexity. We show that an improvement in the amount of recovered oil, an increase in the lifetime of assets, and a reduction of produced water and gas are all possible with adaptive well controls. In one of the three cases, adaptive well controls resulted in an oil recovery increase as high as 20%. We also discuss the differences between well-data and reservoir-data dependencies of the adaptive well-condition algorithms in terms of dynamic response and physical application. Implementing adaptive well controls can help in reconsidering business plans by reducing water and gas production and avoiding early abandonment of wells. It was also considered that one of the main advantages of adaptive well conditions is the potentially significant reduction in number of variables for future optimization studies due to the elimination of control steps.",0,0,1
Flow Rate,Gas Injection,"Eghbali, Sara; Banks, Jonathan; Nobes, David S.",A numerical study on compositional modeling of two-phase fluid flow and heat transfer in vertical wells,Two-phase flow; Pressure drop; Heat transfer; Geothermal energy; Equation of state; Vertical well,,"Geothermal energy is a sustainable and renewable source that can be extracted by circulating a single- or two-phase fluid through a geothermal well system. Two-phase flow and heat transfer models are required for predicting pressure and temperature profiles in oil, gas, and geothermal wells. We model fluid flow, thermodynamics and heat transfer in an idealised vertical well for single-(i.e., water) and two-phase fluid mixtures (CO2-, and air-water) under a bubbly flow regime. First, we calibrated a Peng-Robinson Equation of State (PR-EOS) for CO2-, and air-water systems. Second, we solved continuity, energy and momentum equations and modelled transient conductive heat transfer through the well. Third, we investigated the effects of mass flow rate, transient heat transfer, single- and two-phase fluid on the extracted power, temperature, and pressure profiles of the deep well bore heat exchanger. The results show that the temperature of the hot fluid decreases as it flows to the surface both in the case of adiabatic flow and in cases with heat loss. The mass flow rate controls the fluid temperature drop during its ascent to the surface. The production pressure of a gas-liquid phase system is higher than that of a system with single liquid phase at the same injection pressure, temperature, and mass flow rate. Increasing mass flow rate up to a threshold value leads to an increase in the production pressure. Above the threshold mass flow rate (i.e., 7 kg/s in this study), the production pressure reduces because of the significant increase in the frictional pressure drop. Production temperature, production pressure, and total power increases over time due to the local heating around the production well and reduction of the heat loss.",0,0,2
Flow Rate,Gas Injection,"Yousefi, Seyed Hamidreza; Rashidi, Fariborz; Sharifi, Mohammad; Soroush, Mohammad; Ghahfarokhi, Ashkan Jahanbani",Interwell connectivity identification in immiscible gas-oil systems using statistical method and modified capacitance-resistance model: A comparative study,Capacitance-resistance model; Gas injection; Interwell connectivity; Least square support vector machine,FLOODING PERFORMANCE; INJECTION; FLOW; OPTIMIZATION; PREDICTION; FIELD,"Interwell connectivity identification between injector-producer well pairs and hydrocarbon production estimation are essential parameters in reservoir management, which can determine unrecovered oil volume and reservoir continuity. Although there are several published methods for determination of interwell connectivity in water-oil systems, there is no such comprehensive study on gas flooded reservoirs. Due to the high mobility of gas, interwell connectivity is a critical criterion in channelized, faulted and heterogeneous reservoirs for reservoir characterization, production optimization, infill drilling and performance predication. There are physical and statistical techniques to determine interwell connectivity mathematically and identify reservoir flow dynamics without using any operational activities. All methods are working with limited production data and unlike the numerical simulators, they are simple and do not require detailed data. In this paper, modified capacitance-resistance model (or M-CRM as a physical approach) and combination of least square support vector machine and multiple linear regression (as a statistical approach) are applied to two immiscible gas injection cases with different assumptions, and the results are compared. The results show that both methods are reliable in terms of validity, speed and flexibility. The physical approach (M-CRM) is more accurate for interwell connectivity prediction while the statistical method is more precise for producer total rate estimation.",0,0,3
Flow Rate,Mass Flow Rate,"Gjerstad, Kristian; Aamo, Ole Morten",A dynamic model of two-phase flow for simulating gas kick and facilitating model-based control in drilling operations,Gas influx dynamics; Transient kick detection model; Gas bubble propagation in drilling well; Control-oriented gas-liquid model; Low-order two-phase flow model,,"A low-order two-phase dynamic flow model for drilling operations with gas kick is developed. The purpose is to enable fast and robust simulation of the behavior and propagation of influx gas in the bore hole, and the effects it has on the total flow dynamics. The model handles both open and closed wells, as well as the full range of pump rates and gas influx rates that are likely to occur in drilling operations. It incorporates equations for gas bubbles into a low-order liquid model in a new way. Some aspects of the gas are described in a mechanistic way, but with a new ""dual-shape"" bubble representation approach. Momentum is treated for the mixture as a whole, while conservation of mass is handled individually for each of the two phases. The result is a model consisting of a set of ordinary differential equations on explicit form, which makes it possible to couple it with control system- and estimation theory. A comparison with published data from four different sources shows that the model is able to qualitatively reproduce both steady state and transient responses in a handful quite different flow situations. In particular, we verified that the dominating effects that the gas has on compressibility, friction loss and hydrostatic pressure of the total mixture are satisfactory reproduced.",0,0,0
Flow Rate,Mass Flow Rate,"Nascimento, Julio Cesar S.; dos Santos, Adriano; Ortiz, Carlos E. Pico; Pires, Adolfo Puime",A fully implicit EOS based compositional two-phase transient flow simulator in wellbores,Two-phase transient flow; Two-fluid model; Two-phase segregation; Fully implicit solution; Compositional flow,NUMERICAL SCHEMES; 2-FLUID MODEL,"Transient two-phase flow in pipes and wellbores appears in several processes in petroleum industry. Predicting pressure, temperature and composition behavior during offshore well tests can support investment decisions in exploration. The governing system of equations that model production (or injection) and build-up (or fall off) is composed by the mass conservation of each component, the transport equation for each phase and one overall system energy equation. In this paper we develop a fully implicit equation of state based thermal compositional simulator able to model two-phase multicomponent flow in wellbores and pipes. This simulator is fully compositional and includes thermal effects. The thermodynamics calculations are based on the Peng-Robinson equation of state, and the momentum equations are based on the Single-Pressure Two-Fluid model. The finite volume method is used to discretize the non-linear system of equations, and time is discretized using Euler's implicit technique. The obtained numerical solutions for both co-current as well as countercurrent flow showed excellent agreement when compared to benchmark solutions published in the literature. A well kick-off followed by constant flow rate production and posterior shut-in was also simulated and the numerical results were discussed. It also models surge pressure and gravitational segregation effects in the wellbore. The presented simulator may be applied in numerical pressure transient analysis and pressure behavior in flowlines connecting wellheads and production platforms.",0,0,0
Flow Rate,Mass Flow Rate,"Eghbali, Sara; Banks, Jonathan; Nobes, David S.",A numerical study on compositional modeling of two-phase fluid flow and heat transfer in vertical wells,Two-phase flow; Pressure drop; Heat transfer; Geothermal energy; Equation of state; Vertical well,,"Geothermal energy is a sustainable and renewable source that can be extracted by circulating a single- or two-phase fluid through a geothermal well system. Two-phase flow and heat transfer models are required for predicting pressure and temperature profiles in oil, gas, and geothermal wells. We model fluid flow, thermodynamics and heat transfer in an idealised vertical well for single-(i.e., water) and two-phase fluid mixtures (CO2-, and air-water) under a bubbly flow regime. First, we calibrated a Peng-Robinson Equation of State (PR-EOS) for CO2-, and air-water systems. Second, we solved continuity, energy and momentum equations and modelled transient conductive heat transfer through the well. Third, we investigated the effects of mass flow rate, transient heat transfer, single- and two-phase fluid on the extracted power, temperature, and pressure profiles of the deep well bore heat exchanger. The results show that the temperature of the hot fluid decreases as it flows to the surface both in the case of adiabatic flow and in cases with heat loss. The mass flow rate controls the fluid temperature drop during its ascent to the surface. The production pressure of a gas-liquid phase system is higher than that of a system with single liquid phase at the same injection pressure, temperature, and mass flow rate. Increasing mass flow rate up to a threshold value leads to an increase in the production pressure. Above the threshold mass flow rate (i.e., 7 kg/s in this study), the production pressure reduces because of the significant increase in the frictional pressure drop. Production temperature, production pressure, and total power increases over time due to the local heating around the production well and reduction of the heat loss.",0,0,2
Flow Rate,Mass Flow Rate,"Amiri-Ramsheh, Behnam; Safaei-Farouji, Majid; Larestani, Aydin; Zabihi, Reza; Hemmati-Sarapardeh, Abdolhossein",Modeling of wax disappearance temperature (WDT) using soft computing approaches: Tree-based models and hybrid models,Solid scales; Wax disappearance temperature; Multilayer perceptron; Random forest; ANFIS; Leverage approach,HIGH-PRESSURE; PHASE-EQUILIBRIA; CRUDE OILS; PREDICTION; PRECIPITATION; OPTIMIZATION; ALGORITHM; DEPOSITION; ANFIS,"Solid scales can cause significant problems in oil production and transmission systems such as oil flow rate reduction. Wax is one of the most critical substances that are highly prone to precipitate and deposit in oil pipelines. This occurrence typically happens in low temperatures, and can extremely affect the flow rate. In the wax deposition process, wax disappearance temperature (WDT) is a crucial factor since it denotes the lowest temperature, at which wax deposits melt and the consequences of wax deposition vanish. In this research, smart models were utilized to predict WDT as a function of molar mass and pressure according to a comprehensive database. The proposed intelligent models are radial basis function (RBF) and multilayer perceptron (MLP) neural networks, adaptive neuro-fuzzy inference system (ANFIS), random forest (RF), extra tree (ET), and decision tree (DT). The MLP networks were trained with Bayesian Regularization (BR) and Levenberg-Marquardt (LM) algorithms, and the ANFIS models were coupled with three optimization algorithms, namely Cultural Algorithm (CA), Biogeography-based Optimization (BBO), and Teaching-Learning-Based Optimization (TLBO). Results demonstrate that the developed RF model could present an outstanding performance and provide predictions for WDT with the lowest average absolute percent relative error (AAPRE = 0.246%), the maximum coefficient of determination (for predicting = 0.993), and minimum root mean squared error (RMSE = 1.01). Trend analysis showed that increasing pressure and molar mass leads to wax disappearance temperature increase. Lastly, outlier discovery was performed using the Leverage approach to recognize the suspected data points. The outlier detection found that only 6 points (out of 346) are located in the upper and lower suspected data zones.",0,0,2
Flow Rate,Mass Flow Rate,"Zhang, Lan; Wang, Yingjun; Liu, Ming; Wang, Liquan; Liu, Hengxu",Multiple-flow-regime models for real gas transport in fractal porous media at high pressure,Multiple flow regimes; fractal Porous media; Real gas; High pressure,PERMEABILITY; SHALE; DIFFUSION; NANOPORES,"A Mathematical model for total mass flow rate per unit area and total permeability of real gas flow in fractal porous media was proposed on the basis of fractal theory. Proposed models in this paper paid attention to the influence of real gas effect on gas, taking transition regime as the coupling of slip regime and Knudsen diffusion, considering multi-flow-regime coexist, multi-flow-regime is continuum flow regime, slip flow regime, transition flow regime and Knudsen diffusion regime., pore which pore diameter is A mass flow rate per unit area multiply corresponding pore number dN obtain mass flow rate(dq). Integrate dq within corresponding diameter range and divide fractal porous media work out corresponding flow regime the mass flow rate per unit area. The total mass flow rate per unit area was then calculated through integrating over the mass flow rate deduced, where different flow regimes have been engaged, including continuum regime, slip regime, transition regime and Knudsen diffusion. Based on the Darcy theory, the total permeability was then calculated. In order to verify correctness of model, compare proposed model to Wang's model and Fan's model. Calculate correlation coefficient of proposed model and Wang's model, R-2 = 0.9912; Calculate correlation coefficient of proposed model and Wang's model, R-2 = 0.9997. Indicate that proposed model can fit well with Wang's model and Fan's model, proposed model can correctly predict total permeability. And calculate correlation coefficient of D.B.Bennion experiment data and three model. In the last part, the paper analyzed the influence factor of total mass flow rate per unit area and total permeabilities and mass flow rate per unit area and permeability of different flow regimes. The concludes as follow: (1) total mass flow rate per unit area, total permeability and each flow regime mass flow rate per unit area and permeability increase with fractal dimension(D-p) increasing and tortuous fractal dimension(D-t) decreasing. Variation of D-p and D-t has different influence on each flow regime. D-p and D-t has most influence on Knudsen diffusion flow regime, least influence on continuum flow regime. (2) Real gas effect affects the mass flow rate per unit area and permeability in different flow regime by affecting the mean free path of gas molecule. Whether consider real gas effect would cause great difference, maximum difference is 232.35%. (3) Flow regime that have the lowest Knudsen number play leading role in variation of total mass flow rate and total permeability. (4) The more maximum pore diameter of fractal porous media, the more significant influence of total mass flow rate per unit area and total permeability. Maximum pore diameter has different influence on each flow regime, has most influence on Knudsen diffusion flow regime, least influence on continuum flow regime.",0,0,2
Flow Rate,Multi-phase Flow,"Park, Ki-Heum; Kim, Tea-Woo; Kim, Young-Ju; Lee, Nayoung; Seo, Yutaek",Experimental investigation of model-based IMC control of severe slugging,Multi-phase flow; Flow loop; Severe slugging; IMC control; OLGA,,"Severe slugging formation has been investigated experimentally in a two-phase flow-loop composed of a downwardly inclined pipe and a vertical riser. In this study, a bifurcation diagram was made to more clearly identify which flow the current system has at each valve opening. A model was made by inputting the dimensions of the flow loop using OLGA, a multiphase flow simulation program, to compare the experimental results. The model-based control logic was constructed by estimating the transfer function utilizing the OLGA model. The estimated transfer function is used to tune the gain of the PI controller, using the method called the Internal Model Control (IMC). Through this method, PI gain can be easily obtained through only one tuning parameter. When the PI controller gain is obtained through the transfer function of the flow loop system, mitigation of severe slugging was achieved while increasing the flow rate than the case with manual choking.",0,0,0
Flow Rate,Multi-phase Flow,"Alhosani, Ahmed; Daraboina, Nagu",Effect of multi-phase flow on asphaltene deposition: Field case application of integrated simulator,Flow assurance; Multiphase flow; Asphaltene deposition,GAS-LIQUID FLOW; HEAT-TRANSFER; PARTICLE DEPOSITION; UNIFIED MODEL; CRUDE OILS; TOOL ADEPT; PRECIPITATION; SLUG; HOLDUP; AGGREGATION,"Asphaltene is initially stable in the oil, but when there is a change in pressure, temperature, or composition, particles tend to phase out and form precipitants. Issues arise when those particles diffuse toward the wall and deposit, which contributes to reducing the flowing area and increasing the pressure drop. Preventing precipi-tation is the optimum solution to maintain the target production rate; however, it is challenging to avoid favorable precipitation conditions. Remedies and treatments to mitigate this issue cause the oil industry a considerable increase in expenditure and time; thus, it is necessary to develop a tool to accurately predict the deposition for a wide range of operating conditions, especially in multiphase flow. In this study, a multiphase simulator is developed by coupling thermodynamics, hydrodynamics, heat transfer, and asphaltene modules to predict the deposition. A deposition data obtained from a field case is used to validate the robustness of the simulator. The simulator results matched well with the asphaltene deposition and the equilibrium profile available in the literature. The simulation approach presented here offers useful insights into the effect of multiphase flow on asphaltene deposition and eventually aid in improving the accuracy of pre-diction. Using single-phase assumption under multiphase conditions contributed to a significant error in the prediction, and these inaccuracies may lead to a substantial economic and operational burden for the oil and gas industry.",0,0,0
Flow Rate,Multi-phase Flow,"Chaves, Gabriela Souza; Karami, Hamidreza; Ferreira Filho, Virgilio Jose Martins; Vieira, Bruno Ferreira",A comparative study on the performance of multiphase flow models against offshore field production data,Multiphase flow; Production optimization; Offshore data analysis; Flow assurance; Flow models,2-PHASE FLOW; PRESSURE-DROP; PATTERN TRANSITIONS; MECHANISTIC MODEL; PREDICTING FLOW; VISCOSITY; OIL,"In the oil industry, multiphase flow models are commonly used to simulate the flow from reservoir to the production unit. Flow simulations help in the production monitoring and optimization to support the decisionmaking process. Despite the need for accurate simulations to support production operations, multiphase flow models are mostly developed using laboratory data and rarely validated under field-scale conditions. To improve the understanding of multiphase flow models in field conditions, this work evaluates the performance of a large set of models for a dataset composed of two production units with 20 producing wells and 865 measured production points. The wells are divided and analyzed in two segments: the surface flowline and the wellbore. The evaluation compares the models' performances using various statistical parameters and trending charts. The evaluation analyzes the impacts of production parameters, well geometry, predicted flow pattern, and pressure drop components on the model performances. Overall, Ansari's model presented the best performance with 13.8% absolute average percent error for the flowline segment and 14.1% error for the wellbore segment. In addition, Gray can also generate good results for most but not all of the tested wellbores. From the production parameters evaluation, higher flow rate tests resulted in more stable outputs. Ansari and Beggs models showed a trend of increasing errors for wells with larger horizontal wellbore lengths. Also, Beggs model showed larger errors when the transition flow pattern was predicted. Finally, both Ansari and Beggs models showed larger overprediction errors for tests with higher pressure losses in the flowline segment, while Gray showed smaller errors for these cases. The conclusions can be used to select the best models given the production system's flow parameters, or be incorporated in systems to increase the accuracy.",0,0,0
Flow Rate,Multi-phase Flow,"Tavakkoli, Mohammad; Panuganti, Sai R.; Khemka, Yash; Valdes, Humberto; Vargas, Francisco M.",Foam-assisted gas lift: A novel experimental setup to investigate the feasibility of using a commercial surfactant for increasing oil well productivity,Pressure drop; Foam; FAGL; Artificial lift; Wellbore productivity; Multiphase flow,,"Most oil wells require artificial lift at some point to increase the life of the field and enhance production. Conventional methods such as gas lift are not effective in depleted reservoirs with high water cut where very high gas injection rates are required for relatively low oil production rates. Consequently, foamers or surfactants, which have been previously applied for de-liquifying gas wells, are now used in depleted gas-lifted oil wells to either boost production rates or reduce gas lift requirements while maintaining production levels. While there is a growing global interest, foam-assisted gas lift (FAGL) is a relatively modern artificial lifting method with less experience regarding its applications in oil wells. In this study, the feasibility of using a commercial surfactant for improving oil well productivity is investigated via laboratory experiments. A novel laboratory setup resembling a vertical well rig is designed to analyze the impact of surfactant concentration, temperature, brine salinity and phase-specific flow rates (or flow regimes) on the pressure drop across the column. This setup is operational at high temperatures, requires minimal sample amounts, and significantly reduces the experimental errors in pressure drop readings, resulting in highly accurate and stable measurements. The laboratory tests confirm that the addition of foamer reduces pressure drop in the production tubing, thus effectively increasing production. Additionally, an optimal foamer concentration is also detected. The results obtained in this study are very promising and present opportunities to explore a new chapter in artificial lift and production enhancement techniques.",0,0,0
Flow Rate,Multi-phase Flow,"Andrade, Gabriel M. P.; de Menezes, Diego Q. F.; Soares, Rafael M.; Lemos, Tiago S. M.; Teixeira, Alex F.; Ribeiro, Leonardo D.; Vieira, Bruno F.; Pinto, Jose Carlos",Virtual flow metering of production flow rates of individual wells in oil and gas platforms through data reconciliation,Virtual flow metering; Soft sensor; Data reconciliation; Oil and gas production,REAL-TIME,"In the present work, virtual flow metering (VFM) tools are developed to provide estimates for the individual flow rate measurements of the wells operated simultaneously in typical oil and gas platforms. Data reconciliation (DR) procedures are used to calibrate phenomenological models using available measured profiles of well pressure and temperature, and overall flow rates of gas, oil and water. In order to evaluate the relative importance of key hypotheses, three different phenomenological models were used to describe the platform operation: (i) a simple single phase fluid flow model, to evaluate whether the DR task can be successfully accomplished with the available data; (ii) a simple multiphase fluid flow model, in order to evaluate whether the explicit consideration of the multiphase nature of the problem can affect the obtained DR results; and (iii) a detailed phenomenological multiphase flow model, to represent accurately the behavior of an oil and gas production platform. Obtained results show that the proposed DR scheme can be indeed implemented successfully in the form of a VFM sensor to assign online and in real time the individual production of wells operated simultaneously in typical oil and gas platforms. The DR-based VFM was able to reconcile total oil and total water flow rates with average relative deviations of 0.87% and 17% respectively and maximum deviation of 2.3% for oil flow rates. Besides, the DR-based VFM tool provided insights about the system behavior and sensoring management, being able to indicate the oil lines and sensors that were subject to the highest variability.",0,0,3
Flow Rate,Deposition,"Alhosani, Ahmed; Daraboina, Nagu",Effect of multi-phase flow on asphaltene deposition: Field case application of integrated simulator,Flow assurance; Multiphase flow; Asphaltene deposition,GAS-LIQUID FLOW; HEAT-TRANSFER; PARTICLE DEPOSITION; UNIFIED MODEL; CRUDE OILS; TOOL ADEPT; PRECIPITATION; SLUG; HOLDUP; AGGREGATION,"Asphaltene is initially stable in the oil, but when there is a change in pressure, temperature, or composition, particles tend to phase out and form precipitants. Issues arise when those particles diffuse toward the wall and deposit, which contributes to reducing the flowing area and increasing the pressure drop. Preventing precipi-tation is the optimum solution to maintain the target production rate; however, it is challenging to avoid favorable precipitation conditions. Remedies and treatments to mitigate this issue cause the oil industry a considerable increase in expenditure and time; thus, it is necessary to develop a tool to accurately predict the deposition for a wide range of operating conditions, especially in multiphase flow. In this study, a multiphase simulator is developed by coupling thermodynamics, hydrodynamics, heat transfer, and asphaltene modules to predict the deposition. A deposition data obtained from a field case is used to validate the robustness of the simulator. The simulator results matched well with the asphaltene deposition and the equilibrium profile available in the literature. The simulation approach presented here offers useful insights into the effect of multiphase flow on asphaltene deposition and eventually aid in improving the accuracy of pre-diction. Using single-phase assumption under multiphase conditions contributed to a significant error in the prediction, and these inaccuracies may lead to a substantial economic and operational burden for the oil and gas industry.",0,0,0
Flow Rate,Deposition,"Tian, Hui; Deng, Song; Wang, Caibao; Ni, Xingya; Wang, Hao; Liu, Yuan; Ma, Mingyu; Wei, Yaohui; Li, Xiaogang",A novel method for prediction of paraffin deposit in sucker rod pumping system based on CNN indicator diagram feature deep learning,Paraffin deposit; Convolutional neutral network; Prediction; Accuracy; Efficient production,WAX DEPOSITION; MODEL; FLOW; OIL,"Paraffin deposit is a major problem associated with water injection in waxy heavy oil reservoirs, therefore accurately and effectively predicting the development of paraffin deposit can avoid some major faults, such as stuck pump, and ensure the stability of the system. Paraffin deposit, as a gradual changing fault, shows a clear trend of development. Based on the convolutional neutral network (CNN) combined with deep learning, the indicator diagram is extracted to calculate the growth rate, and then the timing of serious paraffin problems can be predicted. The paper firstly analyzes and calculates the force of the column in the process of paraffin deposition and obtains the theoretical maximum load in the upper stroke and the theoretical minimum load in the lower stroke, then the load difference is selected as the parameter to characterize the paraffin deposit. In a case study, an experimental well is selected to determine maximum load difference in paraffin deposit process and load difference in normal production, and then the percentage of paraffin deposit is determined based on the growth law as the label of each indicator diagram. The structure of convolutional neural network is designed, and the accuracy rate is taken as the index to optimize the matching scheme of convolutional neural network structure parameters. Finally, the convolution neural network is trained by using training sets of 1.3 million well data. This method is an effective way to predict the paraffin deposit with CNN combined with deep learning and indicator diagram with an accuracy rate of 98.08% and loss less than 0.633. The prediction method in this paper can facilitate the intelligent management of oilfield safety and ensure the efficient production of pumping system.",0,0,1
Flow Rate,Deposition,"Qazvini, Sajjad; Golkari, Abdolah; Azdarpour, Amin; Santos, Rafael M.; Safavi, Mir Saeid; Norouzpour, Milad",Experimental and modelling approach to investigate the mechanisms of formation damage due to calcium carbonate precipitation in carbonate reservoirs,CaCO3 scale formation; OLI Software; Carbonate reservoir; Water flooding; Low flow rate; Permeability reduction; Turbidity,CACO3 SCALE FORMATION; HETEROGENEOUS NUCLEATION; OIL; DEPOSITION; FIELD; INHIBITION; SURFACE; WATER; TEMPERATURE; MANAGEMENT,"Calcium carbonate (CaCO3) precipitation, due to incompatibility between the injected water (IW) and formation water (FW), is known to be a major operational obstacle during water flooding projects. In this study, initially by using OLI Scale Chem and ScaleSoftPitzer software and static beaker tests, the potentiality of CaCO3 scaling was determined from the given ionic content of incompatible synthetic brines, under different conditions (temperature, pressure, and volume mixing ratio of incompatible brines). The results showed that the maximum amount of CaCO3 salt was formed at a volume mixing ratio of 0.8:0.2 (IW:FW). The simulation results showed that OLI software is more reliable than the ScaleSoftPitzer. In the second stage of this work, the 0.8:0.2 proportion of IW: FW was selected to examine the mechanisms under which the maximum formation damage of the tight carbonate cores occurred through the water injection experiments. In addition, the turbidity of the bulk solution was measured to confirm the core flooding outcomes. Various hydrodynamic parameters (low flow rate, scaling tendency, and the temperature) were evaluated in these experiments. Bulk induction time (t(ind)) and scaling period (t(s)) were determined from the setup. Either heterogeneous nucleation (i.e. crystallization processes), or both heterogeneous nucleation and adhesion of pre-deposited crystals from the mixed incompatible brines to the pore wall of the cores, were attributed as the principal mechanisms of the formation damage of tight carbonate rocks owing to CaCO3 salt formation. Moreover, a semi-empirical model was established from this laboratory study, which predicts the scaling period (t(s)) as a function of interfacial energy, temperature, and scaling tendencies.",0,0,1
Flow Rate,Deposition,"Li, Rongbin; Huang, Qiyu; Zhu, Xiangrui; Zhang, Dongxu; Lv, Yang; Larson, Ronald G.",Investigation of delayed formation of wax deposits in polyethylene pipe using a flow-loop,Wax deposition; Contact angle; Delayed formation; Adhesion; Sloughing; Wax content,OPERATING-CONDITIONS; BREAKING FORCE; LAMINAR-FLOW; CRUDE; WATER; INHIBITORS; PERFORMANCE; PIPELINES; SURFACES; MODEL,"After the start of the flow in a home-built flow-loop, the thickness of a waxy layer deposited on a stainless steel (SS) test section was found to increase immediately, while deposition was delayed for around 4 h on a polyethylene (PE) test section. The radial thermal gradient, wax precipitation rate, radial diffusivity of wax, and shear stresses at the surface of the deposit layer were calculated, eliminating these factors as sources of different deposition behavior. However, the contact angles of oils containing precipitated wax crystals on PE surfaces were found to increase more with increasing wax content than those on SS surfaces. Consistent with this, while the wax contents of deposits were found to be around 18 wt % for both PE and SS pipes, the adhesion of the deposit on the PE surface was found to be much weaker than on the SS surface, as evidenced by the easier of removal of the deposit from PE than from SS pipes when heated in vertical orientation under gravity. These results point to pipe wall wettability as a significant factor in both initial growth of wax deposit, and ease of removal.",0,0,2
Flow Rate,Deposition,"Amiri-Ramsheh, Behnam; Safaei-Farouji, Majid; Larestani, Aydin; Zabihi, Reza; Hemmati-Sarapardeh, Abdolhossein",Modeling of wax disappearance temperature (WDT) using soft computing approaches: Tree-based models and hybrid models,Solid scales; Wax disappearance temperature; Multilayer perceptron; Random forest; ANFIS; Leverage approach,HIGH-PRESSURE; PHASE-EQUILIBRIA; CRUDE OILS; PREDICTION; PRECIPITATION; OPTIMIZATION; ALGORITHM; DEPOSITION; ANFIS,"Solid scales can cause significant problems in oil production and transmission systems such as oil flow rate reduction. Wax is one of the most critical substances that are highly prone to precipitate and deposit in oil pipelines. This occurrence typically happens in low temperatures, and can extremely affect the flow rate. In the wax deposition process, wax disappearance temperature (WDT) is a crucial factor since it denotes the lowest temperature, at which wax deposits melt and the consequences of wax deposition vanish. In this research, smart models were utilized to predict WDT as a function of molar mass and pressure according to a comprehensive database. The proposed intelligent models are radial basis function (RBF) and multilayer perceptron (MLP) neural networks, adaptive neuro-fuzzy inference system (ANFIS), random forest (RF), extra tree (ET), and decision tree (DT). The MLP networks were trained with Bayesian Regularization (BR) and Levenberg-Marquardt (LM) algorithms, and the ANFIS models were coupled with three optimization algorithms, namely Cultural Algorithm (CA), Biogeography-based Optimization (BBO), and Teaching-Learning-Based Optimization (TLBO). Results demonstrate that the developed RF model could present an outstanding performance and provide predictions for WDT with the lowest average absolute percent relative error (AAPRE = 0.246%), the maximum coefficient of determination (for predicting = 0.993), and minimum root mean squared error (RMSE = 1.01). Trend analysis showed that increasing pressure and molar mass leads to wax disappearance temperature increase. Lastly, outlier discovery was performed using the Leverage approach to recognize the suspected data points. The outlier detection found that only 6 points (out of 346) are located in the upper and lower suspected data zones.",0,0,2
Flow Rate,Porous Media,"Hasanzadeh, Maryam; Azin, Reza; Fatehi, Rouhollah; Zendehboudi, Sohrab",New insights into forced and free fall gravity drainage performance in a fractured physical model,Fractured physical model; Gas injection; Recovery factor; Free fall gravity drainage; Forced gravity drainage,TERTIARY OIL-RECOVERY; POROUS-MEDIA; WETTABILITY; DISPLACEMENT; SECONDARY; FLOW,"Gravity is one of the major driving forces for fluid flow in naturally fractured reservoirs. Gravity drainage appears to be a vital recovery mechanism over the oil production process in a majority of fractured reserves. In this paper, free-fall gravity drainage (FFGD) and forced gravity drainage (FGD) production approaches are investigated through employing a new fractured sand pack with a rectangular geometry. Distilled water and condensate are used as the wetting phase. Nitrogen, carbon dioxide, and air are also utilized as the non-wetting phase. A systematic sensitivity analysis is conducted to find the effects of the key factors such as fracture blockage, injection rate, dip angle, and type of wetting phase and injection fluid on the performance of FFGD and FGD processes. Also, a numerical simulation is performed to simulate the experiments. Results reveal that the FGD has a better performance under controlled process conditions, compared to the FFGD so that gas injection with a controlled rate improves the recovery. Moreover, it was found that increasing the gas injection rate improves the recovery factor (RF) of wetting-phase when the up and bottom sides of the fractures are blocked; the RF is decreased in the case with open fracture sides. The recovery of the wetting phase decreases in both FFGD and FGD modes when the porous system has a deviation from the vertical orientation. According to the study outcomes, the immiscible gas-assisted gravity drainage offers a higher condensate recovery, compared to water recovery, due to lower viscosity and interfacial tension (IFT) of the condensate phase. The comparison of the experimental data and simulation results implies that the simulation approach can satisfactorily predict the performance of the FGD process. Based on the error analysis, there is a good match between the simulation results and the experimental measurements; the fluid pair of CO2-condensate exhibits the highest accuracy with an R-squared of 0.9961 and an average relative error (ARE) of 0.0054.",0,0,0
Flow Rate,Porous Media,"Ratnakar, Ram R.; Dindoruk, Birol",Transient measurement and modeling of integrated capillary viscometer for live oils at high temperatures with volumetric constraints,Capillary viscometer; Integrated viscosity experiment; Modeling fluid flow; Hagen-Poiseuille equation; Live and dead oils; High temperature high pressure (HTHP) studies,HEAVY-OIL; VISCOSITY CORRELATION; PREDICTION; BITUMEN; DEAD,"The viscosity of oils at reservoir conditions whether under natural depletion conditions or under induced conditions (i.e. EOR/IOR) is one of the key parameters for the dynamics of flow in porous media, and it has direct impact on the economically recoverable volumes as well as transportation problems where the fluids can get exposed to potentially wide range of temperatures. It becomes even more essential measurement for thermal based EOR techniques including high temperature steam injection or in-situ upgrading techniques due to strong (exponential) dependency of viscosity to temperature. Unfortunately, viscosity measurements for such applications suffer with the two key challenges. First, most commercial and research labs could measure viscosities up to 200 degrees C (while the application considered may induce temperatures as high as 300 degrees C beyond which most naturally occurring hydrocarbons starts decomposing). And second, these measurements are based on steady-state conditions, requiring significant volumes of oil samples. However, the available volume of oil samples for such applications may be very small for various reasons, including emulsions leading to very low useful volumes, cost of sampling, or inheritance of candidate samples from other laboratory processes, such as but not limited to core-flooding or reactive transport experiments. Therefore, in this work, we present a novel but simple technique to overcome these challenges by using simple capillary device that could be integrated to any system that requires charging and/or charging the candidate fluids such as PVT-cells, pressurized vessels that could be operated up to 300 degrees C or higher. Such integration utilizes the charging of fluids to the cell for viscosity measurements, leading to the following advantages: (i) it requires no additional volume of oil for viscosity measurements, and also saves the operational time and cost (ii) it could produce viscosity data at higher temperatures that are desired for in-situ upgrading or thermal EOR, even small amounts of particulates evolve in the bulk phase (iii) it ensures that the viscosity and PVT measurements are performed on the same sample eliminating the potential sample to sample variations. (iv) the proposed approach along with the developed methodology paves the way for a the implementation of unsteady in-line measurement of viscosities for pressurized systems. This includes not only lab processes, but also the downhole sampling where the method could be implemented in sampling devices. The technique proposed here is based on transient measurements and modeling of capillary viscometer, where pressure at the end points and flow rate through the capillary tube may vary with time (which is the most realistic conditions for variable back pressure systems or systems with frictional pistons). In addition to the experimental process, necessary mathematical model and interpretative analysis tools to quality check, assessment of the experimental data (and the establishment of the range of validity and limitations) are derived from first principals (bottom-up approach) using Navier-Stokes equations.",0,0,1
Flow Rate,Porous Media,"Al Ghafri, Al Yaqathan; Mackay, Eric; Stephen, Karl",The relevance of the linear stability theory to the simulation of unstable immiscible viscous-dominated displacements in porous media,Instability predictor; Saffman-Taylor instability; End-point mobility ratio; Fractional flow analysis; Viscous oil; Polymer flooding; Correlated random field,MISCIBLE DISPLACEMENT; INSTABILITIES; MECHANISM; POLYMER; GROWTH; MODELS; FLUID,"The 2D governing equations for the immiscible two-phase flow admissible to linear stability analysis are inspected. The identification of the term v(ws)delta D-st in the generalized Saffman-Taylor criterion is key to the analysis. It can be regarded as a predictor that correlates with observed immiscible instability in terms of the rate of advancement of the viscous pattern, the number of small protrusions, and their roughness in a given heterogeneous domain described by a correlated random field. The predictor is extended, heuristically, for polymer flooding shock-wise and used to characterize the instability of the two shocks. The extension is validated by simulation. The instability of the primary shock is essential when considering the breakthrough recovery. In light of the instability predictor, the geometric interpretations of the fractional flow are essential to understand the stability enhancement of the primary shock over the Buckley-Leverett shock in water flooding. It is also concluded that the end-point mobility ratio does not directly control the immiscible instability. This conclusion was arrived at by fixing the end-point mobility ratios for three sets of relative permeability curves, and yet noticeably different instabilities occur, both in transverse and correlated random fields. The criterion can predict the viscous instability in the laboratory experiments under certain flooding conditions and sample configurations. Concerning the instability in a field scale, the predictor is applicable if the field is regarded as a prototype of a given model experiment.",0,0,2
Flow Rate,Porous Media,"Zhang, Lan; Wang, Yingjun; Liu, Ming; Wang, Liquan; Liu, Hengxu",Multiple-flow-regime models for real gas transport in fractal porous media at high pressure,Multiple flow regimes; fractal Porous media; Real gas; High pressure,PERMEABILITY; SHALE; DIFFUSION; NANOPORES,"A Mathematical model for total mass flow rate per unit area and total permeability of real gas flow in fractal porous media was proposed on the basis of fractal theory. Proposed models in this paper paid attention to the influence of real gas effect on gas, taking transition regime as the coupling of slip regime and Knudsen diffusion, considering multi-flow-regime coexist, multi-flow-regime is continuum flow regime, slip flow regime, transition flow regime and Knudsen diffusion regime., pore which pore diameter is A mass flow rate per unit area multiply corresponding pore number dN obtain mass flow rate(dq). Integrate dq within corresponding diameter range and divide fractal porous media work out corresponding flow regime the mass flow rate per unit area. The total mass flow rate per unit area was then calculated through integrating over the mass flow rate deduced, where different flow regimes have been engaged, including continuum regime, slip regime, transition regime and Knudsen diffusion. Based on the Darcy theory, the total permeability was then calculated. In order to verify correctness of model, compare proposed model to Wang's model and Fan's model. Calculate correlation coefficient of proposed model and Wang's model, R-2 = 0.9912; Calculate correlation coefficient of proposed model and Wang's model, R-2 = 0.9997. Indicate that proposed model can fit well with Wang's model and Fan's model, proposed model can correctly predict total permeability. And calculate correlation coefficient of D.B.Bennion experiment data and three model. In the last part, the paper analyzed the influence factor of total mass flow rate per unit area and total permeabilities and mass flow rate per unit area and permeability of different flow regimes. The concludes as follow: (1) total mass flow rate per unit area, total permeability and each flow regime mass flow rate per unit area and permeability increase with fractal dimension(D-p) increasing and tortuous fractal dimension(D-t) decreasing. Variation of D-p and D-t has different influence on each flow regime. D-p and D-t has most influence on Knudsen diffusion flow regime, least influence on continuum flow regime. (2) Real gas effect affects the mass flow rate per unit area and permeability in different flow regime by affecting the mean free path of gas molecule. Whether consider real gas effect would cause great difference, maximum difference is 232.35%. (3) Flow regime that have the lowest Knudsen number play leading role in variation of total mass flow rate and total permeability. (4) The more maximum pore diameter of fractal porous media, the more significant influence of total mass flow rate per unit area and total permeability. Maximum pore diameter has different influence on each flow regime, has most influence on Knudsen diffusion flow regime, least influence on continuum flow regime.",0,0,2
Flow Rate,Porous Media,"Zheng, Lei; Nian, Yong-Le; Zhao, Rui; Cheng, Wen-Long",Prediction of multi-reservoir production for water injection well by using temperature logging data,Multi-reservoir production; Water injection well; Heat transfer model; Temperature logging data; Stochastic approximation method,HEAVY OIL; NUMERICAL-SIMULATION; PRODUCTION FORECAST; POROUS-MEDIA; FLOW-RATE; RECOVERY; MODEL; EXTRACTION; SYSTEMS,"In most cases, oil wells are completed and perforated to produce from multiple reservoirs. Thus, it is crucial to monitor production from each individual reservoir. Therefore, a new prediction method for multi-reservoir production by using temperature logging data is presented in this paper. Firstly, by coupling the wellbore and formation heat transfer with reservoirs heat transfer, a new comprehensive heat transfer model for the oil well with multiple reservoirs is established in this paper. Both the heat convection of two-phase flow in reservoir and vertical heat transfer between different reservoirs was considered in the model, and the relationship between flow rate distribution and temperature distribution could be specified by the model. Then based on the model, the stochastic approximation method was proposed to predict the multi-reservoir production through the temperature logging data. Lastly for a water injection well with five layered reservoirs and depth of 3500m, the production of each reservoir was predicted by the presented method. The results show that the temperature distribution simulated by the built model has a good agreement with the reference data. The estimation error of the total flow rate is less than 9% compared with the reference data, and the production of the five reservoirs accounted for 36%, 35%, 17%, 7% and 5% of the total production respectively.",0,0,2
Flow Rate,Real Time,"Wang, Chao; Liu, Gonghui; Li, Jun; Zhang, Tao; Jiang, Hailong; Huang, Honglin; Zhu, Zhongxi; Luo, Ming; Huang, Peng",Downhole mud loss transient simulation and detection with downhole dual measurement points,Mud loss detection; Characteristic lines; Machine learning; Downhole pressure difference measurement; Measurement of theological parameters; Unscented kalman filter,KICK DETECTION; FLOW MODEL; CIRCULATION; DIAGNOSIS,"Mud loss is usually challenging to discover in time by detecting the mud pit's liquid level, leading to a significant wastage of time and money. Due to the measurement-while-drilling system's low data-transmission speed, downhole measured data is usually ignored in mud loss detection. What is more, surface detection methods comprising pressure and flow-rate sensors require professional knowledge and many input parameters, some of which are required to be assumed. In this study, we proposed a downhole mud loss detection method based on downhole dual measurement points without any use of surface input parameters, which significantly increased the detection method's feasibility. Firstly, we established an end-to-end neural network to recognize the downhole ten working conditions. Once the static and circulation working conditions are recognized, the drilling fluid's density and rheological parameters can be automatically determined with the proposed method. Then, an unscented Kalman filter was applied to perform a backward calculation of mud loss rate dynamically. Thirdly, we proposed a new pressure difference measurement method with high precision, capturing the flow friction pressure consumption in a short distance. To evaluate the mud loss detection method comprehensively, we built the downhole mud loss transient simulation model to generate transient data with the highest possible accuracy. The characteristic lines method was used to solve the partial differential equations of the mud loss simulation model. The accuracy of the simulation model was successfully validated with a small-scale laboratory experiment in the horizontal direction, a full-scale laboratory experiment in the vertical, and a real field experiment. Finally, we generated a set of mud loss well data to describe the proposed mud loss detection method's processes in detail. The results showed that the proposed mud loss detection model successfully detected mud loss and obtained the accurate mud loss rate.",0,0,1
Flow Rate,Real Time,"Goes, Maria Rosa R. T.; Guedes, Thamires A. L.; D'Avila, Thiago C.; Vieira, Bruno Ferreira; Ribeiro, Leonardo D.; de Campos, Mario C. M.; Secchi, Argimiro R.",Virtual flow metering of oil wells for a pre-salt field,Virtual flow metering; Pre-salt; EMSO; Real time,,"The flow rate values reported in real time, for an oil and gas production unit, refer to the total amount produced by that unit. On the other hand, data referring to the flow rate of each producing well in real time are usually not available, due to the difficulty in implementing flow measurement devices. These individual flows are determined by production tests that are generally performed every two months and are important for production planning and optimization. Therefore, there is a need to generate models capable of predicting the flow of each well in the period between tests, in order to identify possible issues during the production. In this context, we propose in this paper a method to predict the liquid and gas flow rates of each well as function of measured variables available in plant data collected in real time. Choke valve specifications and fluid properties are also required as model input data. Since there is no flow measurement device, it is not possible to directly validate the model results against plant data. In this case, the model validation is performed using the total liquid and gas flow rates presented in the Daily Operation Report (DOR) and those provided by fiscal meters. Relative errors below 3.5% were observed, showing good agreement between the calculated flow rates and the provided by fiscal meters. The proposed method was implemented in the computational environment EMSO, which presents as advantages the low simulation time and robustness over a wide range of input data. These advantages become important as the model is used for monitoring platforms in real time. The range of applicability of this model can be attributed to the Gas-Oil Rate (GOR). In this work, the lowest and highest values of GOR considering all the wells are 207.58 and 393.97, respectively.",0,0,2
Flow Rate,Real Time,"Andrade, Gabriel M. P.; de Menezes, Diego Q. F.; Soares, Rafael M.; Lemos, Tiago S. M.; Teixeira, Alex F.; Ribeiro, Leonardo D.; Vieira, Bruno F.; Pinto, Jose Carlos",Virtual flow metering of production flow rates of individual wells in oil and gas platforms through data reconciliation,Virtual flow metering; Soft sensor; Data reconciliation; Oil and gas production,REAL-TIME,"In the present work, virtual flow metering (VFM) tools are developed to provide estimates for the individual flow rate measurements of the wells operated simultaneously in typical oil and gas platforms. Data reconciliation (DR) procedures are used to calibrate phenomenological models using available measured profiles of well pressure and temperature, and overall flow rates of gas, oil and water. In order to evaluate the relative importance of key hypotheses, three different phenomenological models were used to describe the platform operation: (i) a simple single phase fluid flow model, to evaluate whether the DR task can be successfully accomplished with the available data; (ii) a simple multiphase fluid flow model, in order to evaluate whether the explicit consideration of the multiphase nature of the problem can affect the obtained DR results; and (iii) a detailed phenomenological multiphase flow model, to represent accurately the behavior of an oil and gas production platform. Obtained results show that the proposed DR scheme can be indeed implemented successfully in the form of a VFM sensor to assign online and in real time the individual production of wells operated simultaneously in typical oil and gas platforms. The DR-based VFM was able to reconcile total oil and total water flow rates with average relative deviations of 0.87% and 17% respectively and maximum deviation of 2.3% for oil flow rates. Besides, the DR-based VFM tool provided insights about the system behavior and sensoring management, being able to indicate the oil lines and sensors that were subject to the highest variability.",0,0,3
Flow Rate,Yield Stress,"Vinay, Guillaume; Bhaskoro, Petrus Tri; Henaut, Isabelle; Sariman, Mior Zaiga; Anuar, Astriyana; Shafian, Siti Rohaida M.",A methodology to investigate factors governing the restart pressure of a Malaysian waxy crude oil pipeline,Waxy crude oil; Gelling; Numerical simulation; Rheology; Restart pressure,STARTUP FLOW; MODEL,"Waxy crude oils account for about 20% of world oil reserves. Wax gelation due to pipeline operating at low ambient temperature, especially in subsea environment, is a worst-case scenario that operators fear most since the gel can potentially block the entire pipeline, if it is not managed early. Restart pressure calculation is the first step to assess severity of gelation and subsequently used to plan for the mitigation strategies which are translated into project CAPEX (Capital Expenditure) and OPEX (Operating Expenditure). Gel characteristic (i.e. rheology behaviour and gel compressibility), operating conditions (oil temperature, ambient temperature and oil flow rate) and pipeline geometry (length and diameter) are known factors governing the restart pressure calculation for a gelled waxy pipeline. Malaysian waxy crude oils are unique and have distinctive rheology which differ from waxy crude oils from other regions mainly due to high gel yield stress of more than 500 Pa with potential failure to recovery from gelation. Hence, accurate restart pressure prediction that account for all the governing factors as well as the interplay between them, are crucial for safe operation and cost-effective mitigation strategies. A conservative approach where the entire gel is assumed to yield simultaneously is frequently used but this simple approach fails to take into account many factors, resulting in an overestimation of the restart pressure. Several improved restart pressure calculation methods have been proposed in literature. In this study, an original methodology developed by IFPEN, has been applied to predict the restart pressure of a Malaysian waxy crude oil pipeline at various conditions. The main benefit of this methodology comes from its ability to consider the conditions under which the gel has been formed, that produces a more realistic description where gel strength varies along a pipeline. The case study highlighted that Conservative laws, assuming a homogeneous gel structure everywhere in the pipe, can overestimate the restart pressure by a factor of up to 100 times than a heterogenous gel. Thanks to the 2D axisymmetric description of the pipeline gel, we showed that the shape and the location of the gel also impact the restart pressure.",0,0,2
Flow Rate,Yield Stress,"Tobar Espinoza, Pedro J.; Varges, Priscilla R.; Rodrigues, Elias C.; Naccache, Monica F.; de Souza Mendes, Paulo R.",Displacement flow of yield stress materials in annular spaces of variable cross section,Complex fluids; Non-Newtonian flows; Rheology; Experimental measurement; Experiments,HERSCHEL-BULKLEY FLUIDS; VISCOPLASTIC MATERIALS; LAMINAR,"We conducted an experimental study of a yield stress material being displaced upwardly at controlled flow rate by a Newtonian fluid in an annular space whose external wall consists of a sudden expansion-contraction. This system is a simplified representation of the primary cementing process of an oil well, whose bore diameter may present variations. In the experiments, different pairs of fluids were employed. The yield stress materials were Carbopol aqueous solutions at three different weight concentrations, with Herschel-Bulkley viscosity behavior. The Newtonian liquid was a glycerin/water mixture. A wide range of flow rates were explored, varying the dimensionless cavity depth and cavity axial length. A non-monotonic behavior is observed for the dimensionless volume of yield stress material displaced from the cavity by the Newtonian fluid flow. In addition, the rheological properties and geometrical parameters were seen to have a strong influence on the displaced volume.",0,0,2
Flow Rate,Yield Stress,"Ettehadi, Ali; Ulker, Ceylan; Altun, Gursat",Nonlinearity in large amplitude oscillatory shear of drilling fluid: A comparative study on the oil and water base muds behavior,Drilling fluid; Nonlinear viscoelasticity; Large amplitude oscillatory shear (LAOS); Shear mechanism; Structural stability,VISCOELASTIC PROPERTIES; PRESSURE-DROP; LAOS BEHAVIOR; MODEL; RHEOLOGY; STRESS; TRANSITION; VISCOSITY; EQUATION,"A viscoelastic material exhibits both fluid (viscous) and solid (elastic) like properties simultaneously. The rheological behavior of drilling fluids is customarily measured under the assumption of pure viscous flow, yet they exhibit both viscous and elastic characteristics when subjected to deformation. Some imperative properties of drilling fluids such as gel strength, yield stress, and sag tendency at near-zero shear rate region are categorically under the influence of viscoelastic behavior and have not yet been completely understood due to the lack of appropriate measurement methods. Characterizing the complete rheological profile of material requires measuring linear and nonlinear viscoelastic responses at a wide range of stress/strain levels. The viscoelastic nonlinearity can be characterized under Large Amplitude Oscillatory Shear (LAOS) tests. This study presents a large amplitude oscillatory shear rheology investigation of two water-base (Lignosulfonate and KCl/polymer) and two oil-base (low and high temperature) drilling fluids each in three states; unweighted, weighted, and weighted-contaminated. The viscoelastic nonlinearities of four fluid samples were investigated experimentally as a function of strain amplitude and strain-rate space at different temperatures. The results were described using Lissajous-Bowditch (L-B) plots and local nonlinear viscoelastic dynamic moduli through an oscillatory shear cycle. Structural stability of fluid samples was also studied using the creep-recovery test. The nonlinear viscoelastic behavior of drilling fluids was comprehensively compared and distinguished to understand their nonlinear shear mechanism. As a result of the creep-recovery test at 150 degrees C, high-temperature oil base mud provided higher thermostructural stability and zero shear viscosity than those of Lignosulfonate, KCl/polymer, and low-temperature oil-base muds. While the elastic nonlinearity was found to be strain/strain rate softening, the nonlinear viscous character was recorded as shear/shear rate thinning at large strain rates for all drilling fluid systems. Quite a different shear mechanism was detected at low and moderate strain rates. Shear rate thinning was found to be the dominant mechanism for all fluids except Lignosulfonate mud samples that demonstrated shearthickening behavior at moderate strain rates at 25 degrees C. At high temperatures (100 degrees C and 150 degrees C), shear rate thickening followed by shear rate thinning behavior was governing mechanism under the low and moderate strain rates in all mud samples except KCl/polymer muds. An inverse behavior (shear rate thinning followed by shear rate thickening) was observed through low and moderate strain rates in KCl/polymer muds at 100 degrees C and 150 degrees C. Therefore, as revealed from the LAOS test results, shear rate thickening behavior at low to moderate strain rates is in contradiction of the commonly known shear thinning behavior for a drilling fluid undergoing viscous deformation. This finding explains the facts underlying some important properties of drilling fluids such as gel structure formation, hole cleaning ability, and sag tendency.",0,0,3
Flow Rate,Deep Learning,"Tian, Hui; Deng, Song; Wang, Caibao; Ni, Xingya; Wang, Hao; Liu, Yuan; Ma, Mingyu; Wei, Yaohui; Li, Xiaogang",A novel method for prediction of paraffin deposit in sucker rod pumping system based on CNN indicator diagram feature deep learning,Paraffin deposit; Convolutional neutral network; Prediction; Accuracy; Efficient production,WAX DEPOSITION; MODEL; FLOW; OIL,"Paraffin deposit is a major problem associated with water injection in waxy heavy oil reservoirs, therefore accurately and effectively predicting the development of paraffin deposit can avoid some major faults, such as stuck pump, and ensure the stability of the system. Paraffin deposit, as a gradual changing fault, shows a clear trend of development. Based on the convolutional neutral network (CNN) combined with deep learning, the indicator diagram is extracted to calculate the growth rate, and then the timing of serious paraffin problems can be predicted. The paper firstly analyzes and calculates the force of the column in the process of paraffin deposition and obtains the theoretical maximum load in the upper stroke and the theoretical minimum load in the lower stroke, then the load difference is selected as the parameter to characterize the paraffin deposit. In a case study, an experimental well is selected to determine maximum load difference in paraffin deposit process and load difference in normal production, and then the percentage of paraffin deposit is determined based on the growth law as the label of each indicator diagram. The structure of convolutional neural network is designed, and the accuracy rate is taken as the index to optimize the matching scheme of convolutional neural network structure parameters. Finally, the convolution neural network is trained by using training sets of 1.3 million well data. This method is an effective way to predict the paraffin deposit with CNN combined with deep learning and indicator diagram with an accuracy rate of 98.08% and loss less than 0.633. The prediction method in this paper can facilitate the intelligent management of oilfield safety and ensure the efficient production of pumping system.",0,0,1
Flow Rate,Deep Learning,"Li, Xiangling; Xiao, Kang; Li, Xianbing; Yu, Chunye; Fan, Dongyan; Sun, Zhixue",A well rate prediction method based on LSTM algorithm considering manual operations,Manual operations; Time series; LSTM; Deep learning method; Rate prediction,FLOW; GAS,"Manual operations such as changing the size of chokes as well as opening and closing of the well have a great impact on oil and gas production from the well. This scenario is not considered in most deep learning methods for predicting productivity. Therefore, a deep learning method based on a long short-term memory (LSTM) neural network model was established to predict well performance considering the manual operations. The input dataset was composed of data related to choke size, daily opening time series, and production; the first 90% of the dataset was used as the training set and the remaining 10% was used as the test set. The deep learning model was constructed using a LSTM module, regularization process, and dropout network. The formulated LSTM model was proficient compared with a model that did not consider the manual operation process, and showed better prediction accuracy. Through multiple experiments, the production-related time step was optimized at three, indicating that prediction for the subsequent step was most relevant to the initial three step inputs. Overall, the operation of opening and closing of wells, changing the size of chokes, and variations in daily production time can be considered in our LSTM deep learning model, which provides more reasonable results.",0,0,1
Neural Network,Simulation Models,"Ma, Zhiwei; Leung, Juliana Y.",Efficient tracking and estimation of solvent chamber development during warm solvent injection in heterogeneous reservoirs via machine learning,Heavy oil; Machine learning; Deep learning; Solvents; Interface tracking,HEAVY OIL-RECOVERY; STEAM-CHAMBER; GRAVITY-DRAINAGE; DATA ANALYTICS; SIMULATION; ENSEMBLE; OPTIMIZATION; PERFORMANCE; ALGORITHM; EVOLUTION,"Warm solvent injection (WSI) has been proposed as a promising alternative to steam-based methods for bitumen recovery, due to its potential to reduce greenhouse gas emissions and environmental footprint. It involves injecting heated vaporized solvent to reduce the viscosity of bitumen via solvent diffusion and latent heat transfer. The presence of reservoir heterogeneity caused by shale barriers is a severe concern for the success of the WSI because the conformance of solvent chamber advancement can be compromised. However, the efficient estimation and tracking methods for solvent chamber growth and propagation in heterogeneous reservoirs have not been widely investigated in the past. To fill this gap, this work proposes a novel machine learning-based approach to efficiently track solvent chamber positions in heterogeneous reservoirs for the WSI process. From a large training dataset consisting of numerous synthetic heterogeneous models and their simulation results, the input features and output parameters are extracted from oil production time-series data and the dynamic evolution of solvent chamber, respectively. A convolutional neural network (CNN) is implemented to dynamically track solvent chamber positions by correlating the extracted inputs and outputs. The estimation results are reliable and accurate for both scenarios where the shale barriers are either regularly or irregularly shaped with high conformance index (CI). Only production data is used to assess the conformance of solvent chamber advancement, which is an important consideration in operations design and real-time optimization. The presented workflow offers a novel alternative to infer the development of solvent chambers in heterogeneous reservoirs from production time-series data directly. This type of analysis could complement many existing monitoring techniques to deliver a more comprehensive inference of the distribution of shale heterogeneities in solvent-based bitumen recovery operations.",0,0,0
Neural Network,Simulation Models,"Liu, Rui; Misra, Siddharth",A generalized machine learning workflow to visualize mechanical discontinuity,Machine learning; Regression; Wave propagation; Mechanical discontinuity; Discrete wavelet transform; Signal processing,PROPAGATION; MODEL,"Accurate detection and mapping of mechanical discontinuity in materials has widespread industrial and research applications. We developed a generalized machine-learning framework for visualizing single mechanical discontinuity embedded in material of any composition, velocity, density, porosity, and size with limited data. The proposed visualization of discontinuity requires accurate estimations of the length, location, and orientation of the embedded discontinuity by processing multipoint wave-transmission measurements. k-Wave simulator is used to create a large dataset of elastic waveforms recorded during multi-point wave-transmission measurements through materials containing single mechanical discontinuity. k-Wave simulator considers the wave attenuation, dispersion, and mode conversion in wave motion. Discrete wavelet transform (DWT) and statistical feature extraction are essential for data preprocessing prior to the data-driven model development. DWT also minimizes the effect of noise. Using hyper-parameter tuning and cross validation, gradient boosting regression can visualize the mechanical discontinuity with an accuracy of 0.85, in terms of coefficient of determination. A double-layered neural network-based regression has better performance with an accuracy of 0.95. Use of convolutional neural network converts the predictive task from a waveform processing to an image processing problem. Convolutional neural network achieved a generalization performance of 0.91. The proposed generalized workflow requires robust simulation of wave propagation, signal processing, feature engineering, and model evaluation. Sensors closest to the source and those located opposite the source are the most significant for the desired visualization. Notably, the sensors closest to the source capture the non-linear associations, whereas the sensor on the border opposite to the source capture the linear associations between the measured waveforms and the properties of the mechanical discontinuity.",0,0,0
Neural Network,Simulation Models,"Wu, Hao; Li, Zhen; Liu, Naihao; Zhang, Bo",Improved seismic well tie by integrating variable-size window resampling with well-tie net,Seismic well tie; Waveform resampling; CNN,SYNTHETIC SEISMOGRAMS,"Accurate seismic well tie is essential for seismic inversion and reservoir characterization. The procedure of seismic well tie involves shifting, stretching and squeezing the synthetic seismogram computed from well logs to match the seismic traces at or near the borehole location. Numerous methods have been proposed for nonlinear alignment between synthetic and real seismograms. However, most well-tie methods are prone to over-stretching and the alignment result is sensitive to the chosen window size. To solve those problems, we propose a variablesize window resampling (VWR) algorithm and integrate with convolutional neural network (CNN) for automatic seismic well tie. Using VWR algorithm to reconstruct the waveforms in synthetic seismogram can simulate the variety of subsurface velocity. CNN can learn the characteristic of different waveforms and recognize the most correlated waveforms between synthetic and real seismograms for sequence alignment. We first use VWR algorithm to reconstruct a large number of synthetic seismograms for train set generation. We then build an CNN model that named well-tie net for training to learn the feature of different resampled synthetic seismograms. Finally, we use the well trained CNN model to segment the real seismogram and align with the synthetic seismogram for seismic well tie. We apply our method into the synthetic test and real seismic data with well logs and obtain high correlated seismic-well tie. We also compare with the conventional method dynamic time warping (DTW) to illustrate the effectiveness and robustness of our proposed method. Our proposed method can avoid the problem of over-stretching by using the variable-size window resampling algorithm and automatically tying the well to seismic trace using well-tie net. In addition, the train set for our method is generated automatically.",0,0,0
Neural Network,Simulation Models,"Kolajoobi, Rasool Amiri; Haddadpour, Hosein; Niri, Mohammad Emami",Investigating the capability of data-driven proxy models as solution for reservoir geological uncertainty quantification,Geological uncertainty; Uncertainty quantification; Representative models; Artificial neural networks; Proxy model; Data-driven models,RANKING; SIMULATION,"Quantifying and analyzing the geological uncertainties associated with the geostatistical models is critical to design a reliable production strategy. A large number, hundreds, even thousands, of model realizations should be run in a reservoir simulator to quantify the uncertainties in terms of a target flow response. However, this becomes a time consuming and computationally demanding process. In practice, different methods are used to select only a few representative models for further analyses. This study aims to take a fresh look at uncertainty quantification solutions by means of a proxy model based on artificial neural networks (ANN). The idea is replacing the flow simulator with an ANN-based proxy model by which the target responses of all realizations are calculated much faster and with a lower computational demand. The ability of computing the combined effect of several uncertain parameters along with successful experiences of utilizing ANNs for reservoir simulation, motivated us to propose our ANN-based methodology as a solution for uncertainty quantification problem. We apply our methodology on a realistic 3D synthetic model which is a channelized model with uncertainties in porosity, permeability, and facies properties. The results are compared with those of two widely used methods, i. e., the traditional ranking and distance-based clustering techniques. It is shown that the ANN-based proxy is able to accurately quantify the geological uncertainties in a much shorter time. Hence, it can be used as a reliable tool for uncertainty quantification and representative models selection.",0,0,0
Neural Network,Simulation Models,"Faraji, Foad; Ugwu, Johnson Obunwa; Chong, Perk Lin",Modelling two-phase Z factor of gas condensate reservoirs: Application of Artificial Intelligence (AI),Artificial neural network (ANN); Particle Swarm Optimization (PSO); ANFIS modelling; Two-phase Z factor; Gas condensate,DEW-POINT PRESSURE; PARTICLE SWARM OPTIMIZATION; COMPRESSIBILITY FACTOR; NEURAL-NETWORK; PHASE-BEHAVIOR; EFFICIENT METHODS; BACK-PROPAGATION; HIGH-TEMPERATURE; PREDICTION; VISCOSITY,"Accurate estimation of two-phase compressibility factor (Z factor) in gas condensate reservoirs is essential for understanding phase behaviour and reliable simulation studies. Experimental measurements of Z factor in wide operational conditions are cumbersome and costly. Hence, engineers rely on existing models such as cubic equation of states (EoSs) and empirical models for estimating such important property. In this study initially the accuracy of prevalent available Z factor models for prediction of two-phase gas condensate Z factor were examined. Then, several smart models including two multilayer perceptron neural networks known as feedforward neural network (FFNN) and cascade forward neural network (CFNN) optimized with Levenberg-Marquardt (LM) and Bayesian-Regularization (BR) algorithms and one Adaptive Neuro Fuzzy Inference System (ANFIS) optimized with Particle Swarm Optimization (PSO) were developed based on 19518 data points for the same task. The databank covers gas condensate two-phase Z factor, compositional variations, molecular weight of heptane plus (MWC7+) and gas specific gravity in wide range of pressure and temperature. The results indicate that the FFNN-BR predicts all experimental data with high accuracy with an average absolute relative deviation of 0.321%. Furthermore, the accuracy of the developed model over two cubic EoSs and three empirical models from literature was confirmed. Finally, based on the sensitivity analysis, it was found that the pseudoreduced pressure (P-pr), MWC7+, and molar content of C7+ in the mixture have the highest impact on prediction of twophase Z factor. The proposed tools can be utilized for accurate prediction of gas condensate two-phase Z factor to ensure accurate simulation studies and better phase behaviour treatments.",0,0,1
Neural Network,Simulation Models,"Kalam, Shams; Yousuf, Usama; Abu-Khamsin, Sidqi A.; Bin Waheed, Umair; Khan, Rizwan Ahmed",An ANN model to predict oil recovery from a 5-spot waterflood of a heterogeneous reservoir,ANN; ANFIS; SVR; Waterflooding,ARTIFICIAL NEURAL-NETWORK; POROUS-MEDIA; PERFORMANCE; SELECTION; GAS; INTELLIGENCE; REGRESSION; AKAIKE; FLOW,"Waterflooding is a secondary oil recovery technique in which water is injected into an underground oil reservoir to maintain the reservoir pressure and boost oil recovery. The performance of a waterflood depends on several factors such as reservoir heterogeneity, reservoir fluid properties, flood pattern, etc. Most of the models developed to predict waterflood performance are either for linear systems or involve simplified assumptions for nonlinear systems. In this study, we propose a novel, artificial neural network (ANN) model comprised of two hidden layers with 256 neurons each for the performance prediction of a 5-spot pattern waterflood in a heterogeneous reservoir at and beyond water breakthrough. The proposed model can be applied to estimate movable oil recovery efficiency of the waterflood (RFM) as a function of Dykstra-Parsons permeability variation coefficient (V), mobility ratio (M), permeability anisotropy ratio (kz/kx), production water cut (fw), a simple indicator of wettability (WI), and oil/water density ratio (DR) within reasonable accuracy. The MAPE of the proposed model was -4% and -5% using training and testing data, respectively. Our ANN model recommendation is based on a detailed comparative study against other popular soft computing models, such as adaptive neuro-fuzzy inference system (ANFIS) and support vector regression (SVR). Based on the accuracy and computational efficiency, the ANN model outperforms ANFIS and SVR. AIC and BIC of the proposed ANN model were also the lowest among all applied soft computing tools. The proposed model is tested on two real field cases and compared with a semianalytical model and an empirical correlation. The presented model shows good agreement with the real field data. The trained ANN model, proposed here, saves computational time in forecasting the waterflood performance compared to a reservoir simulator.",0,0,1
Neural Network,Simulation Models,"Wang, Chao; Liu, Gonghui; Li, Jun; Zhang, Tao; Jiang, Hailong; Huang, Honglin; Zhu, Zhongxi; Luo, Ming; Huang, Peng",Downhole mud loss transient simulation and detection with downhole dual measurement points,Mud loss detection; Characteristic lines; Machine learning; Downhole pressure difference measurement; Measurement of theological parameters; Unscented kalman filter,KICK DETECTION; FLOW MODEL; CIRCULATION; DIAGNOSIS,"Mud loss is usually challenging to discover in time by detecting the mud pit's liquid level, leading to a significant wastage of time and money. Due to the measurement-while-drilling system's low data-transmission speed, downhole measured data is usually ignored in mud loss detection. What is more, surface detection methods comprising pressure and flow-rate sensors require professional knowledge and many input parameters, some of which are required to be assumed. In this study, we proposed a downhole mud loss detection method based on downhole dual measurement points without any use of surface input parameters, which significantly increased the detection method's feasibility. Firstly, we established an end-to-end neural network to recognize the downhole ten working conditions. Once the static and circulation working conditions are recognized, the drilling fluid's density and rheological parameters can be automatically determined with the proposed method. Then, an unscented Kalman filter was applied to perform a backward calculation of mud loss rate dynamically. Thirdly, we proposed a new pressure difference measurement method with high precision, capturing the flow friction pressure consumption in a short distance. To evaluate the mud loss detection method comprehensively, we built the downhole mud loss transient simulation model to generate transient data with the highest possible accuracy. The characteristic lines method was used to solve the partial differential equations of the mud loss simulation model. The accuracy of the simulation model was successfully validated with a small-scale laboratory experiment in the horizontal direction, a full-scale laboratory experiment in the vertical, and a real field experiment. Finally, we generated a set of mud loss well data to describe the proposed mud loss detection method's processes in detail. The results showed that the proposed mud loss detection model successfully detected mud loss and obtained the accurate mud loss rate.",0,0,1
Neural Network,Simulation Models,"Rollmann, Klaus; Soriano-Vargas, Aurea; Cirne, Marcos; Davolio, Alessandra; Schiozer, Denis Jose; Rocha, Anderson",A three-way convolutional network to compare 4D seismic data and reservoir simulation models in different domains,History-matching; 4D seismic data; Simulation models; Deep learning; Data assimilation; 3-way deep neural network,NEURAL-NETWORKS; HISTORY; PARAMETERIZATION,"Four-dimensional seismic (4DS) contains spatial information that provides insights into the location, shape, and movement of fluids (oil, gas, water). It helps engineers to adjust reservoir simulation models and increase their capability of providing reliable production forecasts. Recent probabilistic approaches consider hundreds of numerical simulation model scenarios, which require automated methods to evaluate this large number of numerical models based on observed 4D seismic data. Comparing spatial information of seismic and numerical simulation data is difficult as, usually, these data are converted to maps with different properties. We propose a novel approach to compare 4D seismic data and simulation models using a three-way deep neural network that is trained using a reference image (4D seismic data) with two simulation model candidates. It learns to find the simulation models that best characterize the reference. Our method is underpinned by more than a thousand pairs of simulation models and reference maps evaluated by human specialists for training. For testing, we compare the inter-rater agreement among different specialist groups and generate a reliable test set considering examples in which there was agreement among at least two specialists. We observed that the group with best-trained specialists agree more in their answers and have a considerably higher inter-rater agreement than the less trained groups. When we evaluate our method with the answers from this specialized group, we observe that the simulation model chosen by our method is the one agreed by the specialists in almost 90% of the cases. We also discuss the impact of different noise levels in the input and show that our method outperforms other approaches in the literature if noise is present both in the training and test sets.",0,0,2
Neural Network,Simulation Models,"Illarionov, E.; Temirchev, P.; Voloskov, D.; Kostoev, R.; Simonov, M.; Pissarenko, D.; Orlov, D.; Koroteev, D.",End-to-end neural network approach to 3D reservoir simulation and adaptation,Machine learning; Reservoir simulation; History matching; Neural networks,,"Reservoir simulation and adaptation (also known as history matching) are typically considered as separate problems. While a set of models are aimed at the solution of the forward simulation problem assuming all initial geological parameters are known, the other set of models adjust geological parameters under the fixed forward simulation model to fit production data. This results in many difficulties for both reservoir engineers and developers of new efficient computation schemes. We present a unified approach to reservoir simulation and adaptation problems. A single neural network model allows a forward pass from initial geological parameters of the 3D reservoir model through dynamic state variables to well's production rates and backward gradient propagation to any model inputs and variables. The model fitting and geological parameters adaptation both become the optimization problem over specific parts of the same neural network model. Standard gradient-based optimization schemes can be used to find the optimal solution. Using real-world oilfield model and historical production rates we demonstrate that the suggested approach allows reservoir simulation and history matching with a benefit of several orders of magnitude simulation speed-up. Finally, to propagate this research we open-source a Python-based framework DeepField that allows standard processing of reservoir models and reproducing the approach presented in this paper.",0,0,3
Neural Network,Deep Learning,"Ma, Zhiwei; Leung, Juliana Y.",Efficient tracking and estimation of solvent chamber development during warm solvent injection in heterogeneous reservoirs via machine learning,Heavy oil; Machine learning; Deep learning; Solvents; Interface tracking,HEAVY OIL-RECOVERY; STEAM-CHAMBER; GRAVITY-DRAINAGE; DATA ANALYTICS; SIMULATION; ENSEMBLE; OPTIMIZATION; PERFORMANCE; ALGORITHM; EVOLUTION,"Warm solvent injection (WSI) has been proposed as a promising alternative to steam-based methods for bitumen recovery, due to its potential to reduce greenhouse gas emissions and environmental footprint. It involves injecting heated vaporized solvent to reduce the viscosity of bitumen via solvent diffusion and latent heat transfer. The presence of reservoir heterogeneity caused by shale barriers is a severe concern for the success of the WSI because the conformance of solvent chamber advancement can be compromised. However, the efficient estimation and tracking methods for solvent chamber growth and propagation in heterogeneous reservoirs have not been widely investigated in the past. To fill this gap, this work proposes a novel machine learning-based approach to efficiently track solvent chamber positions in heterogeneous reservoirs for the WSI process. From a large training dataset consisting of numerous synthetic heterogeneous models and their simulation results, the input features and output parameters are extracted from oil production time-series data and the dynamic evolution of solvent chamber, respectively. A convolutional neural network (CNN) is implemented to dynamically track solvent chamber positions by correlating the extracted inputs and outputs. The estimation results are reliable and accurate for both scenarios where the shale barriers are either regularly or irregularly shaped with high conformance index (CI). Only production data is used to assess the conformance of solvent chamber advancement, which is an important consideration in operations design and real-time optimization. The presented workflow offers a novel alternative to infer the development of solvent chambers in heterogeneous reservoirs from production time-series data directly. This type of analysis could complement many existing monitoring techniques to deliver a more comprehensive inference of the distribution of shale heterogeneities in solvent-based bitumen recovery operations.",0,0,0
Neural Network,Deep Learning,"Tian, Hui; Deng, Song; Wang, Caibao; Ni, Xingya; Wang, Hao; Liu, Yuan; Ma, Mingyu; Wei, Yaohui; Li, Xiaogang",A novel method for prediction of paraffin deposit in sucker rod pumping system based on CNN indicator diagram feature deep learning,Paraffin deposit; Convolutional neutral network; Prediction; Accuracy; Efficient production,WAX DEPOSITION; MODEL; FLOW; OIL,"Paraffin deposit is a major problem associated with water injection in waxy heavy oil reservoirs, therefore accurately and effectively predicting the development of paraffin deposit can avoid some major faults, such as stuck pump, and ensure the stability of the system. Paraffin deposit, as a gradual changing fault, shows a clear trend of development. Based on the convolutional neutral network (CNN) combined with deep learning, the indicator diagram is extracted to calculate the growth rate, and then the timing of serious paraffin problems can be predicted. The paper firstly analyzes and calculates the force of the column in the process of paraffin deposition and obtains the theoretical maximum load in the upper stroke and the theoretical minimum load in the lower stroke, then the load difference is selected as the parameter to characterize the paraffin deposit. In a case study, an experimental well is selected to determine maximum load difference in paraffin deposit process and load difference in normal production, and then the percentage of paraffin deposit is determined based on the growth law as the label of each indicator diagram. The structure of convolutional neural network is designed, and the accuracy rate is taken as the index to optimize the matching scheme of convolutional neural network structure parameters. Finally, the convolution neural network is trained by using training sets of 1.3 million well data. This method is an effective way to predict the paraffin deposit with CNN combined with deep learning and indicator diagram with an accuracy rate of 98.08% and loss less than 0.633. The prediction method in this paper can facilitate the intelligent management of oilfield safety and ensure the efficient production of pumping system.",0,0,1
Neural Network,Deep Learning,"Li, Xiangling; Xiao, Kang; Li, Xianbing; Yu, Chunye; Fan, Dongyan; Sun, Zhixue",A well rate prediction method based on LSTM algorithm considering manual operations,Manual operations; Time series; LSTM; Deep learning method; Rate prediction,FLOW; GAS,"Manual operations such as changing the size of chokes as well as opening and closing of the well have a great impact on oil and gas production from the well. This scenario is not considered in most deep learning methods for predicting productivity. Therefore, a deep learning method based on a long short-term memory (LSTM) neural network model was established to predict well performance considering the manual operations. The input dataset was composed of data related to choke size, daily opening time series, and production; the first 90% of the dataset was used as the training set and the remaining 10% was used as the test set. The deep learning model was constructed using a LSTM module, regularization process, and dropout network. The formulated LSTM model was proficient compared with a model that did not consider the manual operation process, and showed better prediction accuracy. Through multiple experiments, the production-related time step was optimized at three, indicating that prediction for the subsequent step was most relevant to the initial three step inputs. Overall, the operation of opening and closing of wells, changing the size of chokes, and variations in daily production time can be considered in our LSTM deep learning model, which provides more reasonable results.",0,0,1
Neural Network,Deep Learning,"Ao, Yile; Lu, Wenkai; Hou, Qiuyuan; Jiang, Bowu",Sequence-to-sequence borehole formation property prediction via multi-task deep networks with sparse core calibration,Formation evaluation; Deep learning; Multi-task learning; Mask loss; Total variation regularization,PETROLEUM RESERVOIR CHARACTERIZATION; SUPPORT VECTOR REGRESSION; ARTIFICIAL NEURAL-NETWORK; WELL LOG DATA; PERMEABILITY PREDICTION; POROSITY PREDICTION; WATER SATURATION; FUZZY-LOGIC; GAS-FIELD; MACHINE,"Building empirical models to estimate formation properties from logging curves is a key task in logging formation evaluation, which can be implemented with numerous statistical or machine learning regression algorithms. The majority of existing works are limited in the paradigm of point-to-point mapping, which implicitly assumes the relationships between logging responses and formation properties can be represented by simple pointwise mapping models. However, since logging responses of a specified measuring point are comprehensive reflections of formations near it, the above assumption is not true in fact. In this study, through the introduction and combination of deep learning techniques such as end-to-end deep network, mask loss, total variation regularization, and multi-task learning, we develop an algorithm framework for more accurate core calibrated formation property prediction. Algorithms in the proposed framework take sequences of logging responses as input, and simultaneously predict sequences of multiple formation properties with the same length. This not only makes it possible to utilize the sequential dependence and morphological features of input logging response curves, but also highlights the morphological consistency and the inner correlation among predicted property sequences. The proposed framework is realized into three algorithms, namely, the multi-task fully convolutional neural network (MtFCNN), the multi-task long short term memory network (MtLSTM), and the multi-task gated recurrent unit network (MtGRUN). Advantages of these algorithms are fully confirmed by comparative experiments and real-world applications, while their abilities to utilize morphological features of logging curves, reduce the risk of overfitting, and emphasize the inner correlation among multiple formation properties are also substantiated. We believe the proposed algorithms have provided improvements for more accurate borehole formation property prediction, while the introduced techniques will also inspire future studies on machine learning assisted logging formation evaluation.",0,0,2
Neural Network,Deep Learning,"Rollmann, Klaus; Soriano-Vargas, Aurea; Cirne, Marcos; Davolio, Alessandra; Schiozer, Denis Jose; Rocha, Anderson",A three-way convolutional network to compare 4D seismic data and reservoir simulation models in different domains,History-matching; 4D seismic data; Simulation models; Deep learning; Data assimilation; 3-way deep neural network,NEURAL-NETWORKS; HISTORY; PARAMETERIZATION,"Four-dimensional seismic (4DS) contains spatial information that provides insights into the location, shape, and movement of fluids (oil, gas, water). It helps engineers to adjust reservoir simulation models and increase their capability of providing reliable production forecasts. Recent probabilistic approaches consider hundreds of numerical simulation model scenarios, which require automated methods to evaluate this large number of numerical models based on observed 4D seismic data. Comparing spatial information of seismic and numerical simulation data is difficult as, usually, these data are converted to maps with different properties. We propose a novel approach to compare 4D seismic data and simulation models using a three-way deep neural network that is trained using a reference image (4D seismic data) with two simulation model candidates. It learns to find the simulation models that best characterize the reference. Our method is underpinned by more than a thousand pairs of simulation models and reference maps evaluated by human specialists for training. For testing, we compare the inter-rater agreement among different specialist groups and generate a reliable test set considering examples in which there was agreement among at least two specialists. We observed that the group with best-trained specialists agree more in their answers and have a considerably higher inter-rater agreement than the less trained groups. When we evaluate our method with the answers from this specialized group, we observe that the simulation model chosen by our method is the one agreed by the specialists in almost 90% of the cases. We also discuss the impact of different noise levels in the input and show that our method outperforms other approaches in the literature if noise is present both in the training and test sets.",0,0,2
Neural Network,Deep Learning,"Mopuri, Konda Reddy; Bilen, Hakan; Tsuchihashi, Naoki; Wada, Ryota; Inoue, Tomoya; Kusanagi, Kazuya; Nishiyama, Tazuru; Tamamura, Hitoshi",Early sign detection for the stuck pipe scenarios using unsupervised deep learning,Stuck prediction; Field drilling data; Unsupervised machine learning; Deep learning; Autoencoder,PREDICTION; STICKING,"In this paper we present a novel approach for detecting early signs for the stuck events in drilling using Deep Learning. Specifically, we adapt neural network based unsupervised learning tool called Autoencoder for anticipating the 'stuck' events during the drilling process. We build Autoencoders on Recurrent Neural Networks (RNNs) to model the normal drilling activity, thereby detecting the stuck incidents as anomalous activity. We conduct experiments on the actual drilling data collected from 30 field wells operated by multiple drilling sources with diverse well profiles and demonstrate that our approach obtains promising results for the stuck sign detection. Furthermore towards explaining the trained model's prediction, we present reconstruction analysis on the individual drilling parameters.",0,0,2
Neural Network,Deep Learning,"Song, Lei; Yin, Xingyao; Zong, Zhaoyun; Jiang, Man",Semi-supervised learning seismic inversion based on Spatio-temporal sequence residual modeling neural network,Seismic inversion; Deep learning; Semi-supervised learning; Initial model; Conventional well log; Spatio-temporal sequence residual modeling neural network,,"The Spatio-temporal sequence residual modeling neural network (STSRM-net) is built to address the geophysical problem of obtaining P-impedance of the subsurface from the zero-offset seismic data and initial model of P impedance. The initial model is used as the initial value of STSRM-net, and the modification value of the initial model and the residual between the modified initial model and true P-impedance are learned during the training. The Spatio-temporal characteristics of the data could be fully dug by STSRM-net. Limited by the inadequacy of labeled data, the semi-supervised learning inversion framework is constructed to train the STSRM-net. The performance of the STSRM-net and some deep learning inversion methods are compared on the synthetic dataset. The test results indicate that STSRM-net has higher inversion accuracy, stronger continuity, and better anti-noise performance. In addition, the robustness experiments indicate that the STSRM-net has excellent fault tolerance to the initial model. Finally, the STSRM-net is applied to the field data and compared with the sparse pulse inversion method, which also proves high inversion resolution, inversion accuracy and robustness to the choice of training wells of the proposed method.",0,0,3
Neural Network,Deep Learning,"Werneck, Rafael de Oliveira; Prates, Raphael; Moura, Renato; Goncalves, Maiara Moreira; Castro, Manuel; Soriano-Vargas, Aurea; Mendes Junior, Pedro Ribeiro; Hossain, M. Manzur; Zampieri, Marcelo Ferreira; Ferreira, Alexandre; Davolio, Alessandra; Schiozer, Denis; Rocha, Anderson",p Data-driven deep-learning forecasting for oil production and pressure,Forecasting; Data-driven; Deep learning; Oil production; Pre-salt,NEURAL-NETWORK; PREDICTION,"Production forecasting plays an important role in oil and gas production, aiding engineers to perform field management. However, this can be challenging for complex reservoirs such as the highly heterogeneous carbonate reservoirs from Brazilian Pre-salt fields. We propose a new setup for forecasting multiple outputs using machine-learning algorithms and evaluate a set of deep-learning architectures suitable for time-series forecasting. The setup proposed is called N-th Day and it provides a coherent solution for the problem of forecasting multiple data points in which a sliding window mechanism guarantees there is no data leakage during training. We also devise four deep-learning architectures for forecasting, stacking the layers to focus on different timescales, and compare them with different existing off-the-shelf methods. The obtained results confirm that specific architectures, as those we propose, are crucial for oil and gas production forecasting. Although LSTM and GRU layers are designed to capture temporal sequences, the experiments also indicate that the investigated scenario of production forecasting requires additional and specific structures.",0,0,3
Neural Network,Error,"Ghorayeb, Kassem; Mawlod, Arwa Ahmed; Maarouf, Alaa; Sami, Qazi; El Droubi, Nour; Merrill, Robert; El Jundi, Obeida; Mustapha, Hussein",Chain-based machine learning for full PVT data prediction,PVT properties; Machine learning; Exploratory data analysis; Clustering; Chain approach; Compositional delumping; Splitting,NEURAL-NETWORK; OIL; MODEL; PRESSURE,"Building machine learning (ML) models based on pressure-volume-temperature (PVT) data is of paramount importance to capture trends and predict fluid behavior in a very heterogeneous and highly nonlinear thermodynamic system. PVT samples stored in an oil company database are often not complete and might be missing properties; both black oil and compositional. Before delving into building optimized fluid models, it is required to have a clean and structured PVT database complete with all the required properties. We present multiple novel algorithms developed to accurately predict a complete set of black oil and compositional properties within a PVT database. The proposed methodology consists of predicting properties in series, starting from a minimal set of data (black oil and compositional) and obtaining a complete set of data for all PVT samples. The order through which this is completed relies on benefiting from the existing data to predict missing data starting from the highest correlating data to the lowest. We also honored the physical nature of correlations between properties, and consequently, ranked properties for prediction as this leads to less error propagation. In addition, we have implemented data clustering prior to training ML models. Clustering is used to categorize the fluid samples into families based on the collective behavior of their different features, and hence, improve the quality of the PVT samples' properties prediction using machine learning. Several options are tested where clustering is performed using black oil properties only, compositional properties, or a combined set of black oil and compositional properties and the clustering scenario leading to the least prediction error is adopted. We have trained ML models to generically predict all black oil and compositional properties resulting from laboratory experiments, including molecular weights (MW) and mole fractions of heavy fractions (any set of heavy fractions) from the mole fractions of all the commonly available components up to C7+ and molecular weight of C7+. The massive data set used in this paper enabled comprehensive testing of the developed algorithms and provided striking accuracy of the predicted PVT properties; especially the compositional ones. Despite all the significant efforts shown in the literature concerning predicting PVT properties, the missing link is a systematic methodology to complete PVT samples' properties in a consistent manner. Furthermore, the focus in the literature is mainly on forecasting black oil properties; compositional properties are scarcely considered. Algorithms developed in this paper address these two limitations and are tested using a uniquely large data set available for onshore and offshore fields and reservoirs in Abu Dhabi. No previous algorithms, to the best of our knowledge, are tested on such a large data set.",0,0,0
Neural Network,Error,"Al-AbdulJabbar, Ahmad; Mahmoud, Ahmed Abdulhamid; Elkatatny, Salaheldin; Abughaban, Mahmoud",Artificial neural networks-based correlation for evaluating the rate of penetration in a vertical carbonate formation for an entire oil field,ROP; Carbonate formations; ANN; Mechanical specific energy,,"The rate of penetration (ROP) is a critical factor affecting the process of oil well drilling optimization and the total drilling cost. This work introduces an empirical correlation extracted from the learned artificial neural networks (ANN) to assess the ROP across a vertical carbonate formation from five surface drilling parameters measurable through real-time sensors. The ANN was built based on real 220 datasets obtained from eight wells. The data from five of these wells were used to train the ANN model. Several sensitivity analyses were conducted on the model's parameters to achieve the best combination of these parameters. To enable real-time assessment of the ROP, a correlation from the leaned ANN model was extracted, which was tested on 92 datasets from the same training wells while unseen datasets from another three wells were used for validating the empirical correlation. The results showed that the ANN was effectively predicted the ROP with an average absolute percentage error (AAPE) of only 4.34% for the training data. Using the developed equation, the ROP was assessed for the validation data with an average AAPE of 6.75%.",0,0,0
Neural Network,Error,"Wahid, Md Ferdous; Tafreshi, Reza; Khan, Zurwa; Retnanto, Albertus",Prediction of pressure gradient for oil-water flow: A comprehensive analysis on the performance of machine learning algorithms,Pressure gradient; Horizontal wellbore; Oil-water flow; Machine-learning; Flow pattern,NEURAL-NETWORK; PATTERNS; VISCOSITY; NORMALITY; MODEL; DROP; TOOL,"Pressure gradient (PG) in liquid-liquid flow is one of the key components to design an energy-efficient transportation system for wellbores. This study aims to develop five robust machine learning (ML) algorithms and their fusions for a wide range of flow patterns (FP) regimes. The MLs include Support Vector Machine (SVM), Gaussian Process (GP), Random Forest (RF), Artificial Neural Network (ANN), k-Nearest Neighbor (kNN), and fusions of these five MLs. A total of eleven hundred experimental data points for nine FPs (two stratified and seven dispersed patterns) in horizontal wellbores are used to develop the MLs. The MLs' performance is evaluated using the metrics including mean absolute percentage error (MAPE), median absolute percentage error (MdAPE), coefficient of variation of root mean squared error (CV-RMSE), and adjusted coefficient of determination. The evaluation metrics are cross-validated using a repeated train-test split strategy. Seven important predictor variables are identified using a supervised feature selection approach: oil and water velocities, FP, input diameter, oil and water density, and oil viscosity. The results show that the high PG prediction accuracy can be achieved using GP compared to other MLs except for the ML-fusions (p < 0.05). A Friedman's test and Wilcoxon Sign-Rank post hoc analysis with Bonferroni correction show that PG prediction errors using GP are significantly lower than using the ANN model (p < 0.05). The values are 18.44 % and 23.9 % for CV-RMSE, 11.6 % and 10.06 % for MAPE, and 7.5 % and 6.75 % for MdAPE, using ANN and GP, respectively. While the previous studies mostly used ANN to demonstrate the capability of MLs to predict PG over the mechanistic or correlationbased models, the present research has shown that GP is even better than ANN using a wide range of FPs and a large data set.",0,0,1
Neural Network,Error,"Shahabi-Ghahfarokhy, Aria; Nakhaei-Kohani, Reza; Amar, Menad Nait; Hemmati-Sarapardeh, Abdolhossein","Modelling density of pure and binary mixtures of normal alkanes: Comparison of hybrid soft computing techniques, gene expression programming, and equations of state",Density; Hydrocarbons; Normal alkane; EOS; Machine learning; LSSVM; RBFNN,GREY WOLF OPTIMIZATION; PLUS N-DECANE; HIGH-PRESSURE; LIQUID DENSITIES; INTERFACIAL-TENSION; HIGH-TEMPERATURES; CUBIC EQUATIONS; PHASE-BEHAVIOR; PREDICTION; VISCOSITY,"Determining the properties of hydrocarbons, especially density, is one of the most important measures in the oil and gas industry. In this study, robust artificial intelligence techniques have been investigated to predict the density of pure and binary mixtures of normal alkanes (between C1 and C44). Since there are various conditions in oil and gas reservoirs, it has been tried to study the properties of different hydrocarbons in a wide range of temperature (up to 522 K) and pressure (up to 275 MPa). An extensive databank, including 2143 and 985 data points for pure and binary mixtures of normal alkanes, respectively, was extracted from the literature. The crow search algorithm (CSA), firefly algorithm (FFA), grey wolf optimization (GWO), and wind-driven optimization (WDO) algorithms were utilized to improve the learning process of least square support vector machine (LSSVM) and radial basis function neural network (RBFNN) models, which were developed to predict the density of hydrocarbons. Also, gene expression programming (GEP) correlations were presented using complex mathematical calculations to estimate the density of hydrocarbons. The results obtained from the models were also compared with seven equations of state (EOSs). The obtained results showed that the predictions of the proposed techniques are in a great match with the experimental data. By performing a comparison on the models' outcomes, LSSVM-GWO and RBFNN-CSA were found to be the most accurate models for pure and binary mixtures of normal alkanes with overall average absolute percent relative error (AAPRE) values of 0.0622% and 0.0098%, respectively. It is noteworthy that the GEP correlations with the AAPRE values of 0.1955% and 0.3525% for pure and binary mixtures of normal alkanes, respectively, have a high accuracy compared to the equations of state and are suitable practical correlations for estimating the density of hydrocarbons.",0,0,1
Neural Network,Error,"Gholami, Amin; Amirpour, Masoud; Ansari, Hamid Reza; Seyedali, Seyed Mohsen; Semnani, Amir; Golsanami, Naser; Heidaryan, Ehsan; Ostadhassan, Mehdi",Porosity prediction from pre-stack seismic data via committee machine with optimized parameters,Porosity; Seismic pre-stack (SPS); Optimized model (OM); Committee machine (CM); Bat-inspired algorithm (BA),SUPPORT VECTOR REGRESSION; RESERVOIR CHARACTERIZATION; PERMEABILITY PREDICTION; SANDSTONE RESERVOIR; INTELLIGENT SYSTEMS; REFRACTIVE-INDEX; MODEL; ATTRIBUTES; ALGORITHM,"Prediction of porosity from the seismic data via geophysical methods when limited number of wells are available is a challenging task that has high uncertainties. This study aims to construct a hybrid data-driven predictive model to establish a quantitative correlation between seismic pre-stack (SPS) data and the porosity. First, three intelligent models that are optimized by bat-inspired algorithm (BA): optimized neural network (ONN), optimized fuzzy inference system (OFIS), and optimized support vector regression (OSVR) are constructed for relating porosity to the SPS data. Then, to benefit from all individual optimized models, a final hybrid model was built via committee machine (CM) where single models are combined with a proper weight to predict porosity in the reservoir space. This approach is examined on the SPS data from an oil field in the Persian Gulf with a single exploratory well where input parameters (Vp, Vs, and rho) to the AI models are derived from a two-parameter inversion method. We found that the coefficient of determination, root mean square error, average absolute relative error, and symmetric mean absolute percentage error for the CM are 0.923615, 0.015793, 0.132280, and 0.061310, respectively. Moreover, based on four statistical indexes that are calculated for each model, CM outperformed its individual elements followed by the OSRV. A comprehensive analysis of the results confirms that CM with the OM elements is a superior approach for computing porosity from the SPS in the well and then throughout the entire reservoir volume. This strategy can aid petroleum engineers to have a better forecast of porosity population in the reservoir static model immediately following the data that is obtained from the first exploratory well. Ultimately, successful implementation of this approach will promptly delineate sweet spots that can replace uncertain and complicated conventional geophysical methods.",0,0,1
Neural Network,Error,"Amiri-Ramsheh, Behnam; Safaei-Farouji, Majid; Larestani, Aydin; Zabihi, Reza; Hemmati-Sarapardeh, Abdolhossein",Modeling of wax disappearance temperature (WDT) using soft computing approaches: Tree-based models and hybrid models,Solid scales; Wax disappearance temperature; Multilayer perceptron; Random forest; ANFIS; Leverage approach,HIGH-PRESSURE; PHASE-EQUILIBRIA; CRUDE OILS; PREDICTION; PRECIPITATION; OPTIMIZATION; ALGORITHM; DEPOSITION; ANFIS,"Solid scales can cause significant problems in oil production and transmission systems such as oil flow rate reduction. Wax is one of the most critical substances that are highly prone to precipitate and deposit in oil pipelines. This occurrence typically happens in low temperatures, and can extremely affect the flow rate. In the wax deposition process, wax disappearance temperature (WDT) is a crucial factor since it denotes the lowest temperature, at which wax deposits melt and the consequences of wax deposition vanish. In this research, smart models were utilized to predict WDT as a function of molar mass and pressure according to a comprehensive database. The proposed intelligent models are radial basis function (RBF) and multilayer perceptron (MLP) neural networks, adaptive neuro-fuzzy inference system (ANFIS), random forest (RF), extra tree (ET), and decision tree (DT). The MLP networks were trained with Bayesian Regularization (BR) and Levenberg-Marquardt (LM) algorithms, and the ANFIS models were coupled with three optimization algorithms, namely Cultural Algorithm (CA), Biogeography-based Optimization (BBO), and Teaching-Learning-Based Optimization (TLBO). Results demonstrate that the developed RF model could present an outstanding performance and provide predictions for WDT with the lowest average absolute percent relative error (AAPRE = 0.246%), the maximum coefficient of determination (for predicting = 0.993), and minimum root mean squared error (RMSE = 1.01). Trend analysis showed that increasing pressure and molar mass leads to wax disappearance temperature increase. Lastly, outlier discovery was performed using the Leverage approach to recognize the suspected data points. The outlier detection found that only 6 points (out of 346) are located in the upper and lower suspected data zones.",0,0,2
Neural Network,Error,"Bahonar, Ehsan; Chahardowli, Mohammad; Ghalenoei, Yaser; Simjoo, Mohammad",New correlations to predict oil viscosity using data mining techniques,Oil viscosity; Correlation; Data mining; Machine learning; Symbolic regression; Scatter matrix plot,ARTIFICIAL NEURAL-NETWORK; SENSITIVITY-ANALYSIS; PVT PROPERTIES; MODEL; CONDUCTIVITY; TEMPERATURE; PRESSURE; ANN,"Oil viscosity is used in any fluid transport calculation in both subsurface and surface conditions. It is possible to determine oil viscosity from laboratory measurements or empirical correlations. However, laboratory measurements are not always available; and empirical correlations suffer from low accuracy. This work implements data mining algorithms to suggest a new correlation for oil viscosity calculation in a wide pressure range from subsurface to surface conditions. First, a scatter plot matrix is applied to analyze 1950 PVT experimental data points from Iranian oil reservoirs. Therefore, the most correlated parameters for predicting oil viscosity are determined. Next, 75% of data points are randomly selected to train the models. The remaining data, i.e., 25% of data points, are utilized to investigate the accuracy of the developed correlation. Then, a symbolic regression analysis is performed in all pressure ranges, i.e., dead oil viscosity, bubble point oil viscosity, below and above the bubble point pressure. Finally, a new oil viscosity correlation is proposed. The statistical and graphical evaluations reveal that the new correlation outperformed the previously proposed correlations by lowering average absolute errors. It can be concluded that the presented correlation improves the prediction accuracy in all pressure ranges. Consequently, it is inferred from the results that machine learning could provide a highly accurate prediction for oil viscosity in all pressure regions. Overall, the proposed correlation could be used to calculate oil viscosity in all pressure ranges with reasonable accuracy.",0,0,2
Neural Network,Error,"Mahdaviara, Mehdi; Larestani, Aydin; Amar, Menad Nait; Hemmati-Sarapardeh, Abdolhossein",On the evaluation of permeability of heterogeneous carbonate reservoirs using rigorous data-driven techniques,Artificial intelligence; Neural network; Smart models; Absolute permeability; Carbonate reservoir,REGRESSION NEURAL-NETWORK; GENERALIZED REGRESSION; PREDICTION; FEED; FLOW; SATURATION; PARAMETERS; VISCOSITY; POROSITY; MODELS,"This study probes the application of Cascade Forward Neural Network (CFNN), Least Square Support Vector Machine (LSSVM), Multilayer Perceptron (MLP), and Generalized Regression Neural Network (GRNN) techniques for modeling the absolute permeability of carbonate rocks in terms of pore specific surface area, porosity, and irreducible water saturation. The control parameters of the MLP and CFNN models were tuned through Levenberg Marquardt Algorithm (LMA) and Bayesian Regularization (BR) optimizers, and the LSSVM paradigm was optimized using Gravitational Search Algorithm (GSA). Accordingly, six intelligent schemes, viz. MLP-BR, MLP-LMA, LSSVM-GSA, CFNN-BR, CFNN-LMA, and GRNN were trained by utilizing 80% of a valuable set of core data compiled from reliable literature and were tested through the rest of the data points (20%). The accuracy of the proposed paradigms was evaluated using several statistical and graphical assessments. The overall results were fulfilling and fair enough for the scope of this study. The proposed MLP-BR, MLP-LMA, LSSVM-GSA, CFNN-BR, CFNN-LMA, and GRNN models were associated with the Root Mean Square Errors of 6.8019, 5.6225, 165.8852, 6.6841, 5.2136, and 11.1799, respectively. The results were endorsed through 3-fold cross-validation. Furthermore, outlier detection was carried out by means of the plot of standardized residuals versus Leverage values. For all models, the majority of the points were valid values distributing in the applicability domain of the models. In the end, the developed models were compared against two literature smart models and a traditional correlation. The results demonstrated that the recently generated models offer remarkably higher accuracy than other alternatives followed by the Gene Expression Programming (GEP) modeling approach.",0,0,2
Neural Network,Well Logs,"Wu, Hao; Li, Zhen; Liu, Naihao; Zhang, Bo",Improved seismic well tie by integrating variable-size window resampling with well-tie net,Seismic well tie; Waveform resampling; CNN,SYNTHETIC SEISMOGRAMS,"Accurate seismic well tie is essential for seismic inversion and reservoir characterization. The procedure of seismic well tie involves shifting, stretching and squeezing the synthetic seismogram computed from well logs to match the seismic traces at or near the borehole location. Numerous methods have been proposed for nonlinear alignment between synthetic and real seismograms. However, most well-tie methods are prone to over-stretching and the alignment result is sensitive to the chosen window size. To solve those problems, we propose a variablesize window resampling (VWR) algorithm and integrate with convolutional neural network (CNN) for automatic seismic well tie. Using VWR algorithm to reconstruct the waveforms in synthetic seismogram can simulate the variety of subsurface velocity. CNN can learn the characteristic of different waveforms and recognize the most correlated waveforms between synthetic and real seismograms for sequence alignment. We first use VWR algorithm to reconstruct a large number of synthetic seismograms for train set generation. We then build an CNN model that named well-tie net for training to learn the feature of different resampled synthetic seismograms. Finally, we use the well trained CNN model to segment the real seismogram and align with the synthetic seismogram for seismic well tie. We apply our method into the synthetic test and real seismic data with well logs and obtain high correlated seismic-well tie. We also compare with the conventional method dynamic time warping (DTW) to illustrate the effectiveness and robustness of our proposed method. Our proposed method can avoid the problem of over-stretching by using the variable-size window resampling algorithm and automatically tying the well to seismic trace using well-tie net. In addition, the train set for our method is generated automatically.",0,0,0
Neural Network,Well Logs,"Aoun, Ala Eddine; Soto, Ricardo; Rabiei, Minou; Rasouli, Vamegh; Khetib, Youcef; Irofti, Doina","Neural Network based Mechanical Earth Modelling (MEM): A case study in Hassi Messaoud Field, Algeria",Mechanical Earth model; Hassi Messaoud field; Hydraulic fracturing; Neural network,EMPIRICAL RELATIONS; PHYSICAL-PROPERTIES; STRENGTH; FAULT,"Accurate estimation of in-situ stresses is of great importance in the oil and gas industry from the exploration to the field development and production phases. The collected logs and mini-frac data in the last 15 years in the Hassi Messaoud Field (HMD), Algeria, shows that the reported state of stresses in this field is not consistent. This called for further studies to estimate more accurately the state of stresses, which more specifically will be used for the design of hydraulic fracturing at a later stage. This paper presents the results of the Mechanical Earth Model (MEM) constructed for the HMD field in Algeria. The results of the MEM, which is continuous logs of formations' elastic and strength properties, as well as the state of the in-situ stresses will be the direct input to the hydraulic fracture (HF) design. Hydraulic fracturing is the prime technique used in the field in order to enhance recovery from this tight sandstone reservoir. MEM is built beyond the conventional correlation with both a Generalized Linear Model (GLM), which serves as a simplified ""ground truth"" and three Artificial Neural Networks (ANN) layers: the first one is training mechanical properties from lab data, the second one trains shear and compressional sonic waves from acquired log data and the last one uses mini-frac data to calculate and train stress regimes from a poro-elastic model. The model is calibrated with the observed breakouts and fracturing data and a close agreement is observed. The work presented in this paper elaborates a detailed roadmap to accurately approximate and synthesize missing data using ANN's and extend it across the rest of the field to build, a 3D MEM. It is hoped that the results of this study can improve the HF operations in the field, which is currently reported to be not efficient.",0,0,1
Neural Network,Well Logs,"Zhang, Yan; Zhang, Chunlei; Ma, Qiaoyu; Zhang, Xin; Zhou, Heng",Automatic prediction of shear wave velocity using convolutional neural networks for different reservoirs in Ordos Basin,Ordos basin; Shear wave velocity; Convolutional neural networks; Well logs; Rock-physics model,WELL LOG DATA; MACHINE; MODEL,"Shear wave velocity (S-wave velocity) has great significance for reservoir characterization and can effectively reduce the ambiguity in seismic interpretation. However, owning to its high cost and technical difficulties, it is usually difficult to obtain for the whole region. Therefore, the prediction of S-wave velocity currently has turned into an urgent task. Thus, the S-wave velocity was predicted using 1D convolutional neural network (1D-CNN) with the well logs. In the first step, the traditional Xu-White and Xu-Payne model were used to carry out the inversion of bulk modulus, shear modulus and density, and illustrated the phenomenon for the traditional rockphysics model. Then, 1D-CNN, including one input layer, four convolutional layers, three fully connected layers and one output layer, was proposed, in which three types of well logs (conventional well logs, array induction well logs and gamma ray spectral well logs) sensitive to the S-wave velocity were determined through the well logs analysis. Finally, based on the established 1D-CNN model, the influence of different well logs combination on the S-wave velocity prediction was analyzed, indicating that the addition of different well logs can improve the accuracy of S-wave velocity. And different machine learning methods (MLs), including back-propagation (BP) and support vector regression (SVR), were also compared, showing that the predicted accuracy of 1DCNN has been improved by 4.2% on average. Two cases for sandstone and carbonate reservoirs also showed that 1D-CNN proposed can achieve higher accuracy and better performance than traditional MLs and rockphysics models. Furthermore, the proposed method can be applied to the other oil and gas exploration fields, improving the exploration accuracy and increasing the production of oil and gas.",0,0,1
Neural Network,Well Logs,"Kelishami, Shervin Bahramali Asadi; Mohebian, Reza; Salmian, Omidreza","A comprehensive perspective on pore connectivity and natural fracture analysis in Oligo-Miocene heterogeneous carbonates, southern Iran",Pore connectivity; Permeability; Fracture aperture; Artificial neural network (ANN); Porosity; Image log; Velocity deviation log (VDL),POROSITY; TECTONICS; LOG,"Ascertaining the pore connection criterion has always been a challenge for geoscientists. In the framework of this research, an attempt was made to study the pore connectivity in a heterogeneous carbonate rock by combining several techniques. Pore types and rock facies were investigated for 321 thin sections. The abundance of connected porosities, cementation type and intensity which significantly control the matrix pore connectivity were specified on thin sections and finally a connectivity log was extracted that showed an accurate result on poroperm cross-plots. Most of the porosity volumes were related to interparticle, vuggy and moldic porosities which are microscale. The velocity deviation log, estimated in four wells, indicates the presence of micro porosity, which is consistent with the results of thin-sections. Zero velocity deviation is usually associated with the predominant presence of micro-pores. Different permeability values in identical lithological facies, as well as micro-fracture markers, prompted us to conduct more extensive research on fractures. FMI analysis proved that the studied reservoir is intensively fractured. The recorded high permeability in a sample with low matrix connectivity is specifically a fracture indication. Fracture apertures vary from microscale (<50 mu m) to 12.5 mm and calculated fracture density is raised up to 2 fractures per meter. Determined fractured intervals are very consistent with mud-loss information, for instance, a complete loss has been reported in the fault zone identified in well B. The detected fractures somewhat follow the main Zagros fault trend (NW-SE). Eventually, calculated connectivity was predicted in other wells using Artificial Neural Network (ANN) and a 3D model was constructed with respect to seismic attributes which gives a precise perspective of pore connection distribution throughout the studied field.",0,0,2
Neural Network,Well Logs,"Ao, Yile; Lu, Wenkai; Hou, Qiuyuan; Jiang, Bowu",Sequence-to-sequence borehole formation property prediction via multi-task deep networks with sparse core calibration,Formation evaluation; Deep learning; Multi-task learning; Mask loss; Total variation regularization,PETROLEUM RESERVOIR CHARACTERIZATION; SUPPORT VECTOR REGRESSION; ARTIFICIAL NEURAL-NETWORK; WELL LOG DATA; PERMEABILITY PREDICTION; POROSITY PREDICTION; WATER SATURATION; FUZZY-LOGIC; GAS-FIELD; MACHINE,"Building empirical models to estimate formation properties from logging curves is a key task in logging formation evaluation, which can be implemented with numerous statistical or machine learning regression algorithms. The majority of existing works are limited in the paradigm of point-to-point mapping, which implicitly assumes the relationships between logging responses and formation properties can be represented by simple pointwise mapping models. However, since logging responses of a specified measuring point are comprehensive reflections of formations near it, the above assumption is not true in fact. In this study, through the introduction and combination of deep learning techniques such as end-to-end deep network, mask loss, total variation regularization, and multi-task learning, we develop an algorithm framework for more accurate core calibrated formation property prediction. Algorithms in the proposed framework take sequences of logging responses as input, and simultaneously predict sequences of multiple formation properties with the same length. This not only makes it possible to utilize the sequential dependence and morphological features of input logging response curves, but also highlights the morphological consistency and the inner correlation among predicted property sequences. The proposed framework is realized into three algorithms, namely, the multi-task fully convolutional neural network (MtFCNN), the multi-task long short term memory network (MtLSTM), and the multi-task gated recurrent unit network (MtGRUN). Advantages of these algorithms are fully confirmed by comparative experiments and real-world applications, while their abilities to utilize morphological features of logging curves, reduce the risk of overfitting, and emphasize the inner correlation among multiple formation properties are also substantiated. We believe the proposed algorithms have provided improvements for more accurate borehole formation property prediction, while the introduced techniques will also inspire future studies on machine learning assisted logging formation evaluation.",0,0,2
Neural Network,Well Logs,"Song, Lei; Yin, Xingyao; Zong, Zhaoyun; Jiang, Man",Semi-supervised learning seismic inversion based on Spatio-temporal sequence residual modeling neural network,Seismic inversion; Deep learning; Semi-supervised learning; Initial model; Conventional well log; Spatio-temporal sequence residual modeling neural network,,"The Spatio-temporal sequence residual modeling neural network (STSRM-net) is built to address the geophysical problem of obtaining P-impedance of the subsurface from the zero-offset seismic data and initial model of P impedance. The initial model is used as the initial value of STSRM-net, and the modification value of the initial model and the residual between the modified initial model and true P-impedance are learned during the training. The Spatio-temporal characteristics of the data could be fully dug by STSRM-net. Limited by the inadequacy of labeled data, the semi-supervised learning inversion framework is constructed to train the STSRM-net. The performance of the STSRM-net and some deep learning inversion methods are compared on the synthetic dataset. The test results indicate that STSRM-net has higher inversion accuracy, stronger continuity, and better anti-noise performance. In addition, the robustness experiments indicate that the STSRM-net has excellent fault tolerance to the initial model. Finally, the STSRM-net is applied to the field data and compared with the sparse pulse inversion method, which also proves high inversion resolution, inversion accuracy and robustness to the choice of training wells of the proposed method.",0,0,3
Neural Network,Oil Viscosity,"Ma, Zhiwei; Leung, Juliana Y.",Efficient tracking and estimation of solvent chamber development during warm solvent injection in heterogeneous reservoirs via machine learning,Heavy oil; Machine learning; Deep learning; Solvents; Interface tracking,HEAVY OIL-RECOVERY; STEAM-CHAMBER; GRAVITY-DRAINAGE; DATA ANALYTICS; SIMULATION; ENSEMBLE; OPTIMIZATION; PERFORMANCE; ALGORITHM; EVOLUTION,"Warm solvent injection (WSI) has been proposed as a promising alternative to steam-based methods for bitumen recovery, due to its potential to reduce greenhouse gas emissions and environmental footprint. It involves injecting heated vaporized solvent to reduce the viscosity of bitumen via solvent diffusion and latent heat transfer. The presence of reservoir heterogeneity caused by shale barriers is a severe concern for the success of the WSI because the conformance of solvent chamber advancement can be compromised. However, the efficient estimation and tracking methods for solvent chamber growth and propagation in heterogeneous reservoirs have not been widely investigated in the past. To fill this gap, this work proposes a novel machine learning-based approach to efficiently track solvent chamber positions in heterogeneous reservoirs for the WSI process. From a large training dataset consisting of numerous synthetic heterogeneous models and their simulation results, the input features and output parameters are extracted from oil production time-series data and the dynamic evolution of solvent chamber, respectively. A convolutional neural network (CNN) is implemented to dynamically track solvent chamber positions by correlating the extracted inputs and outputs. The estimation results are reliable and accurate for both scenarios where the shale barriers are either regularly or irregularly shaped with high conformance index (CI). Only production data is used to assess the conformance of solvent chamber advancement, which is an important consideration in operations design and real-time optimization. The presented workflow offers a novel alternative to infer the development of solvent chambers in heterogeneous reservoirs from production time-series data directly. This type of analysis could complement many existing monitoring techniques to deliver a more comprehensive inference of the distribution of shale heterogeneities in solvent-based bitumen recovery operations.",0,0,0
Neural Network,Oil Viscosity,"Wahid, Md Ferdous; Tafreshi, Reza; Khan, Zurwa; Retnanto, Albertus",Prediction of pressure gradient for oil-water flow: A comprehensive analysis on the performance of machine learning algorithms,Pressure gradient; Horizontal wellbore; Oil-water flow; Machine-learning; Flow pattern,NEURAL-NETWORK; PATTERNS; VISCOSITY; NORMALITY; MODEL; DROP; TOOL,"Pressure gradient (PG) in liquid-liquid flow is one of the key components to design an energy-efficient transportation system for wellbores. This study aims to develop five robust machine learning (ML) algorithms and their fusions for a wide range of flow patterns (FP) regimes. The MLs include Support Vector Machine (SVM), Gaussian Process (GP), Random Forest (RF), Artificial Neural Network (ANN), k-Nearest Neighbor (kNN), and fusions of these five MLs. A total of eleven hundred experimental data points for nine FPs (two stratified and seven dispersed patterns) in horizontal wellbores are used to develop the MLs. The MLs' performance is evaluated using the metrics including mean absolute percentage error (MAPE), median absolute percentage error (MdAPE), coefficient of variation of root mean squared error (CV-RMSE), and adjusted coefficient of determination. The evaluation metrics are cross-validated using a repeated train-test split strategy. Seven important predictor variables are identified using a supervised feature selection approach: oil and water velocities, FP, input diameter, oil and water density, and oil viscosity. The results show that the high PG prediction accuracy can be achieved using GP compared to other MLs except for the ML-fusions (p < 0.05). A Friedman's test and Wilcoxon Sign-Rank post hoc analysis with Bonferroni correction show that PG prediction errors using GP are significantly lower than using the ANN model (p < 0.05). The values are 18.44 % and 23.9 % for CV-RMSE, 11.6 % and 10.06 % for MAPE, and 7.5 % and 6.75 % for MdAPE, using ANN and GP, respectively. While the previous studies mostly used ANN to demonstrate the capability of MLs to predict PG over the mechanistic or correlationbased models, the present research has shown that GP is even better than ANN using a wide range of FPs and a large data set.",0,0,1
Neural Network,Oil Viscosity,"Shahabi-Ghahfarokhy, Aria; Nakhaei-Kohani, Reza; Amar, Menad Nait; Hemmati-Sarapardeh, Abdolhossein","Modelling density of pure and binary mixtures of normal alkanes: Comparison of hybrid soft computing techniques, gene expression programming, and equations of state",Density; Hydrocarbons; Normal alkane; EOS; Machine learning; LSSVM; RBFNN,GREY WOLF OPTIMIZATION; PLUS N-DECANE; HIGH-PRESSURE; LIQUID DENSITIES; INTERFACIAL-TENSION; HIGH-TEMPERATURES; CUBIC EQUATIONS; PHASE-BEHAVIOR; PREDICTION; VISCOSITY,"Determining the properties of hydrocarbons, especially density, is one of the most important measures in the oil and gas industry. In this study, robust artificial intelligence techniques have been investigated to predict the density of pure and binary mixtures of normal alkanes (between C1 and C44). Since there are various conditions in oil and gas reservoirs, it has been tried to study the properties of different hydrocarbons in a wide range of temperature (up to 522 K) and pressure (up to 275 MPa). An extensive databank, including 2143 and 985 data points for pure and binary mixtures of normal alkanes, respectively, was extracted from the literature. The crow search algorithm (CSA), firefly algorithm (FFA), grey wolf optimization (GWO), and wind-driven optimization (WDO) algorithms were utilized to improve the learning process of least square support vector machine (LSSVM) and radial basis function neural network (RBFNN) models, which were developed to predict the density of hydrocarbons. Also, gene expression programming (GEP) correlations were presented using complex mathematical calculations to estimate the density of hydrocarbons. The results obtained from the models were also compared with seven equations of state (EOSs). The obtained results showed that the predictions of the proposed techniques are in a great match with the experimental data. By performing a comparison on the models' outcomes, LSSVM-GWO and RBFNN-CSA were found to be the most accurate models for pure and binary mixtures of normal alkanes with overall average absolute percent relative error (AAPRE) values of 0.0622% and 0.0098%, respectively. It is noteworthy that the GEP correlations with the AAPRE values of 0.1955% and 0.3525% for pure and binary mixtures of normal alkanes, respectively, have a high accuracy compared to the equations of state and are suitable practical correlations for estimating the density of hydrocarbons.",0,0,1
Neural Network,Oil Viscosity,"Bahonar, Ehsan; Chahardowli, Mohammad; Ghalenoei, Yaser; Simjoo, Mohammad",New correlations to predict oil viscosity using data mining techniques,Oil viscosity; Correlation; Data mining; Machine learning; Symbolic regression; Scatter matrix plot,ARTIFICIAL NEURAL-NETWORK; SENSITIVITY-ANALYSIS; PVT PROPERTIES; MODEL; CONDUCTIVITY; TEMPERATURE; PRESSURE; ANN,"Oil viscosity is used in any fluid transport calculation in both subsurface and surface conditions. It is possible to determine oil viscosity from laboratory measurements or empirical correlations. However, laboratory measurements are not always available; and empirical correlations suffer from low accuracy. This work implements data mining algorithms to suggest a new correlation for oil viscosity calculation in a wide pressure range from subsurface to surface conditions. First, a scatter plot matrix is applied to analyze 1950 PVT experimental data points from Iranian oil reservoirs. Therefore, the most correlated parameters for predicting oil viscosity are determined. Next, 75% of data points are randomly selected to train the models. The remaining data, i.e., 25% of data points, are utilized to investigate the accuracy of the developed correlation. Then, a symbolic regression analysis is performed in all pressure ranges, i.e., dead oil viscosity, bubble point oil viscosity, below and above the bubble point pressure. Finally, a new oil viscosity correlation is proposed. The statistical and graphical evaluations reveal that the new correlation outperformed the previously proposed correlations by lowering average absolute errors. It can be concluded that the presented correlation improves the prediction accuracy in all pressure ranges. Consequently, it is inferred from the results that machine learning could provide a highly accurate prediction for oil viscosity in all pressure regions. Overall, the proposed correlation could be used to calculate oil viscosity in all pressure ranges with reasonable accuracy.",0,0,2
Neural Network,Drilling,"Al-AbdulJabbar, Ahmad; Mahmoud, Ahmed Abdulhamid; Elkatatny, Salaheldin; Abughaban, Mahmoud",Artificial neural networks-based correlation for evaluating the rate of penetration in a vertical carbonate formation for an entire oil field,ROP; Carbonate formations; ANN; Mechanical specific energy,,"The rate of penetration (ROP) is a critical factor affecting the process of oil well drilling optimization and the total drilling cost. This work introduces an empirical correlation extracted from the learned artificial neural networks (ANN) to assess the ROP across a vertical carbonate formation from five surface drilling parameters measurable through real-time sensors. The ANN was built based on real 220 datasets obtained from eight wells. The data from five of these wells were used to train the ANN model. Several sensitivity analyses were conducted on the model's parameters to achieve the best combination of these parameters. To enable real-time assessment of the ROP, a correlation from the leaned ANN model was extracted, which was tested on 92 datasets from the same training wells while unseen datasets from another three wells were used for validating the empirical correlation. The results showed that the ANN was effectively predicted the ROP with an average absolute percentage error (AAPE) of only 4.34% for the training data. Using the developed equation, the ROP was assessed for the validation data with an average AAPE of 6.75%.",0,0,0
Neural Network,Drilling,"de Moura, Jeronimo; Xiao, Yingjian; Yang, Jianming; Butt, Stephen D.",An empirical model for the drilling performance prediction for roller-cone drill bits,Rate of penetration; Roller-cone bit; Drilling performance; Drill off test; Drilling performance prediction model; Physics-based model,,"The drilling process is a challenge in the oil and gas industry. These challenges are usually associated with the high costs involved in this process. Technological advances in the past few years, specifically in the drilling process, have allowed the exploitation of oil and gas fields that were uneconomical before. The economic feasibility of drilling a well is directly associated with the accuracy of the plan before the drilling starts, called ""well planning"". Therefore, an accurate drilling performance prediction is crucial. Usually, the approaches to drilling performance prediction are divided into two categories: physics-based and data-driven models. Physicsbased prediction models, or traditional models, are based on laboratory experiments, being empirical models designed for specific types of drilling parameters. Data-driven models are based purely on data, incorporating either machine learning or the implementation of neural networks to predict the rate of penetration. de Moura et al. (de Moura et al., 2020) developed a new drilling performance prediction model that includes the founder point location for fixed cutter drill bit operations. This model was based on the physics-based prediction approach because it usually presents low complexities and good accuracy. Based on several drilling datasets, the applicability and accuracy of the new model for roller-cone bit operations is discussed. Based on an analysis of the drilling data-sets from drill-off tests and field operations, the linear relationship between the ""drillability constant"" of the Maurer model and the weight on bit (WOB) was confirmed. The results of this study show that the new model presented high accuracy to predict the drilling performance in 25 distinct scenarios that included roller-cone bits with diameters that varied between 63.50 and 444.50 mm and in different rock specimens with rock strength varying between 30 and 317.16 MPa.",0,0,1
Neural Network,Drilling,"Wang, Chao; Liu, Gonghui; Li, Jun; Zhang, Tao; Jiang, Hailong; Huang, Honglin; Zhu, Zhongxi; Luo, Ming; Huang, Peng",Downhole mud loss transient simulation and detection with downhole dual measurement points,Mud loss detection; Characteristic lines; Machine learning; Downhole pressure difference measurement; Measurement of theological parameters; Unscented kalman filter,KICK DETECTION; FLOW MODEL; CIRCULATION; DIAGNOSIS,"Mud loss is usually challenging to discover in time by detecting the mud pit's liquid level, leading to a significant wastage of time and money. Due to the measurement-while-drilling system's low data-transmission speed, downhole measured data is usually ignored in mud loss detection. What is more, surface detection methods comprising pressure and flow-rate sensors require professional knowledge and many input parameters, some of which are required to be assumed. In this study, we proposed a downhole mud loss detection method based on downhole dual measurement points without any use of surface input parameters, which significantly increased the detection method's feasibility. Firstly, we established an end-to-end neural network to recognize the downhole ten working conditions. Once the static and circulation working conditions are recognized, the drilling fluid's density and rheological parameters can be automatically determined with the proposed method. Then, an unscented Kalman filter was applied to perform a backward calculation of mud loss rate dynamically. Thirdly, we proposed a new pressure difference measurement method with high precision, capturing the flow friction pressure consumption in a short distance. To evaluate the mud loss detection method comprehensively, we built the downhole mud loss transient simulation model to generate transient data with the highest possible accuracy. The characteristic lines method was used to solve the partial differential equations of the mud loss simulation model. The accuracy of the simulation model was successfully validated with a small-scale laboratory experiment in the horizontal direction, a full-scale laboratory experiment in the vertical, and a real field experiment. Finally, we generated a set of mud loss well data to describe the proposed mud loss detection method's processes in detail. The results showed that the proposed mud loss detection model successfully detected mud loss and obtained the accurate mud loss rate.",0,0,1
Neural Network,Drilling,"Mopuri, Konda Reddy; Bilen, Hakan; Tsuchihashi, Naoki; Wada, Ryota; Inoue, Tomoya; Kusanagi, Kazuya; Nishiyama, Tazuru; Tamamura, Hitoshi",Early sign detection for the stuck pipe scenarios using unsupervised deep learning,Stuck prediction; Field drilling data; Unsupervised machine learning; Deep learning; Autoencoder,PREDICTION; STICKING,"In this paper we present a novel approach for detecting early signs for the stuck events in drilling using Deep Learning. Specifically, we adapt neural network based unsupervised learning tool called Autoencoder for anticipating the 'stuck' events during the drilling process. We build Autoencoders on Recurrent Neural Networks (RNNs) to model the normal drilling activity, thereby detecting the stuck incidents as anomalous activity. We conduct experiments on the actual drilling data collected from 30 field wells operated by multiple drilling sources with diverse well profiles and demonstrate that our approach obtains promising results for the stuck sign detection. Furthermore towards explaining the trained model's prediction, we present reconstruction analysis on the individual drilling parameters.",0,0,2
Neural Network,Coefficient of Determination,"Liu, Rui; Misra, Siddharth",A generalized machine learning workflow to visualize mechanical discontinuity,Machine learning; Regression; Wave propagation; Mechanical discontinuity; Discrete wavelet transform; Signal processing,PROPAGATION; MODEL,"Accurate detection and mapping of mechanical discontinuity in materials has widespread industrial and research applications. We developed a generalized machine-learning framework for visualizing single mechanical discontinuity embedded in material of any composition, velocity, density, porosity, and size with limited data. The proposed visualization of discontinuity requires accurate estimations of the length, location, and orientation of the embedded discontinuity by processing multipoint wave-transmission measurements. k-Wave simulator is used to create a large dataset of elastic waveforms recorded during multi-point wave-transmission measurements through materials containing single mechanical discontinuity. k-Wave simulator considers the wave attenuation, dispersion, and mode conversion in wave motion. Discrete wavelet transform (DWT) and statistical feature extraction are essential for data preprocessing prior to the data-driven model development. DWT also minimizes the effect of noise. Using hyper-parameter tuning and cross validation, gradient boosting regression can visualize the mechanical discontinuity with an accuracy of 0.85, in terms of coefficient of determination. A double-layered neural network-based regression has better performance with an accuracy of 0.95. Use of convolutional neural network converts the predictive task from a waveform processing to an image processing problem. Convolutional neural network achieved a generalization performance of 0.91. The proposed generalized workflow requires robust simulation of wave propagation, signal processing, feature engineering, and model evaluation. Sensors closest to the source and those located opposite the source are the most significant for the desired visualization. Notably, the sensors closest to the source capture the non-linear associations, whereas the sensor on the border opposite to the source capture the linear associations between the measured waveforms and the properties of the mechanical discontinuity.",0,0,0
Neural Network,Coefficient of Determination,"Wahid, Md Ferdous; Tafreshi, Reza; Khan, Zurwa; Retnanto, Albertus",Prediction of pressure gradient for oil-water flow: A comprehensive analysis on the performance of machine learning algorithms,Pressure gradient; Horizontal wellbore; Oil-water flow; Machine-learning; Flow pattern,NEURAL-NETWORK; PATTERNS; VISCOSITY; NORMALITY; MODEL; DROP; TOOL,"Pressure gradient (PG) in liquid-liquid flow is one of the key components to design an energy-efficient transportation system for wellbores. This study aims to develop five robust machine learning (ML) algorithms and their fusions for a wide range of flow patterns (FP) regimes. The MLs include Support Vector Machine (SVM), Gaussian Process (GP), Random Forest (RF), Artificial Neural Network (ANN), k-Nearest Neighbor (kNN), and fusions of these five MLs. A total of eleven hundred experimental data points for nine FPs (two stratified and seven dispersed patterns) in horizontal wellbores are used to develop the MLs. The MLs' performance is evaluated using the metrics including mean absolute percentage error (MAPE), median absolute percentage error (MdAPE), coefficient of variation of root mean squared error (CV-RMSE), and adjusted coefficient of determination. The evaluation metrics are cross-validated using a repeated train-test split strategy. Seven important predictor variables are identified using a supervised feature selection approach: oil and water velocities, FP, input diameter, oil and water density, and oil viscosity. The results show that the high PG prediction accuracy can be achieved using GP compared to other MLs except for the ML-fusions (p < 0.05). A Friedman's test and Wilcoxon Sign-Rank post hoc analysis with Bonferroni correction show that PG prediction errors using GP are significantly lower than using the ANN model (p < 0.05). The values are 18.44 % and 23.9 % for CV-RMSE, 11.6 % and 10.06 % for MAPE, and 7.5 % and 6.75 % for MdAPE, using ANN and GP, respectively. While the previous studies mostly used ANN to demonstrate the capability of MLs to predict PG over the mechanistic or correlationbased models, the present research has shown that GP is even better than ANN using a wide range of FPs and a large data set.",0,0,1
Neural Network,Coefficient of Determination,"Gholami, Amin; Amirpour, Masoud; Ansari, Hamid Reza; Seyedali, Seyed Mohsen; Semnani, Amir; Golsanami, Naser; Heidaryan, Ehsan; Ostadhassan, Mehdi",Porosity prediction from pre-stack seismic data via committee machine with optimized parameters,Porosity; Seismic pre-stack (SPS); Optimized model (OM); Committee machine (CM); Bat-inspired algorithm (BA),SUPPORT VECTOR REGRESSION; RESERVOIR CHARACTERIZATION; PERMEABILITY PREDICTION; SANDSTONE RESERVOIR; INTELLIGENT SYSTEMS; REFRACTIVE-INDEX; MODEL; ATTRIBUTES; ALGORITHM,"Prediction of porosity from the seismic data via geophysical methods when limited number of wells are available is a challenging task that has high uncertainties. This study aims to construct a hybrid data-driven predictive model to establish a quantitative correlation between seismic pre-stack (SPS) data and the porosity. First, three intelligent models that are optimized by bat-inspired algorithm (BA): optimized neural network (ONN), optimized fuzzy inference system (OFIS), and optimized support vector regression (OSVR) are constructed for relating porosity to the SPS data. Then, to benefit from all individual optimized models, a final hybrid model was built via committee machine (CM) where single models are combined with a proper weight to predict porosity in the reservoir space. This approach is examined on the SPS data from an oil field in the Persian Gulf with a single exploratory well where input parameters (Vp, Vs, and rho) to the AI models are derived from a two-parameter inversion method. We found that the coefficient of determination, root mean square error, average absolute relative error, and symmetric mean absolute percentage error for the CM are 0.923615, 0.015793, 0.132280, and 0.061310, respectively. Moreover, based on four statistical indexes that are calculated for each model, CM outperformed its individual elements followed by the OSRV. A comprehensive analysis of the results confirms that CM with the OM elements is a superior approach for computing porosity from the SPS in the well and then throughout the entire reservoir volume. This strategy can aid petroleum engineers to have a better forecast of porosity population in the reservoir static model immediately following the data that is obtained from the first exploratory well. Ultimately, successful implementation of this approach will promptly delineate sweet spots that can replace uncertain and complicated conventional geophysical methods.",0,0,1
Neural Network,Coefficient of Determination,"Amiri-Ramsheh, Behnam; Safaei-Farouji, Majid; Larestani, Aydin; Zabihi, Reza; Hemmati-Sarapardeh, Abdolhossein",Modeling of wax disappearance temperature (WDT) using soft computing approaches: Tree-based models and hybrid models,Solid scales; Wax disappearance temperature; Multilayer perceptron; Random forest; ANFIS; Leverage approach,HIGH-PRESSURE; PHASE-EQUILIBRIA; CRUDE OILS; PREDICTION; PRECIPITATION; OPTIMIZATION; ALGORITHM; DEPOSITION; ANFIS,"Solid scales can cause significant problems in oil production and transmission systems such as oil flow rate reduction. Wax is one of the most critical substances that are highly prone to precipitate and deposit in oil pipelines. This occurrence typically happens in low temperatures, and can extremely affect the flow rate. In the wax deposition process, wax disappearance temperature (WDT) is a crucial factor since it denotes the lowest temperature, at which wax deposits melt and the consequences of wax deposition vanish. In this research, smart models were utilized to predict WDT as a function of molar mass and pressure according to a comprehensive database. The proposed intelligent models are radial basis function (RBF) and multilayer perceptron (MLP) neural networks, adaptive neuro-fuzzy inference system (ANFIS), random forest (RF), extra tree (ET), and decision tree (DT). The MLP networks were trained with Bayesian Regularization (BR) and Levenberg-Marquardt (LM) algorithms, and the ANFIS models were coupled with three optimization algorithms, namely Cultural Algorithm (CA), Biogeography-based Optimization (BBO), and Teaching-Learning-Based Optimization (TLBO). Results demonstrate that the developed RF model could present an outstanding performance and provide predictions for WDT with the lowest average absolute percent relative error (AAPRE = 0.246%), the maximum coefficient of determination (for predicting = 0.993), and minimum root mean squared error (RMSE = 1.01). Trend analysis showed that increasing pressure and molar mass leads to wax disappearance temperature increase. Lastly, outlier discovery was performed using the Leverage approach to recognize the suspected data points. The outlier detection found that only 6 points (out of 346) are located in the upper and lower suspected data zones.",0,0,2
Neural Network,Smart Models,"Faraji, Foad; Ugwu, Johnson Obunwa; Chong, Perk Lin",Modelling two-phase Z factor of gas condensate reservoirs: Application of Artificial Intelligence (AI),Artificial neural network (ANN); Particle Swarm Optimization (PSO); ANFIS modelling; Two-phase Z factor; Gas condensate,DEW-POINT PRESSURE; PARTICLE SWARM OPTIMIZATION; COMPRESSIBILITY FACTOR; NEURAL-NETWORK; PHASE-BEHAVIOR; EFFICIENT METHODS; BACK-PROPAGATION; HIGH-TEMPERATURE; PREDICTION; VISCOSITY,"Accurate estimation of two-phase compressibility factor (Z factor) in gas condensate reservoirs is essential for understanding phase behaviour and reliable simulation studies. Experimental measurements of Z factor in wide operational conditions are cumbersome and costly. Hence, engineers rely on existing models such as cubic equation of states (EoSs) and empirical models for estimating such important property. In this study initially the accuracy of prevalent available Z factor models for prediction of two-phase gas condensate Z factor were examined. Then, several smart models including two multilayer perceptron neural networks known as feedforward neural network (FFNN) and cascade forward neural network (CFNN) optimized with Levenberg-Marquardt (LM) and Bayesian-Regularization (BR) algorithms and one Adaptive Neuro Fuzzy Inference System (ANFIS) optimized with Particle Swarm Optimization (PSO) were developed based on 19518 data points for the same task. The databank covers gas condensate two-phase Z factor, compositional variations, molecular weight of heptane plus (MWC7+) and gas specific gravity in wide range of pressure and temperature. The results indicate that the FFNN-BR predicts all experimental data with high accuracy with an average absolute relative deviation of 0.321%. Furthermore, the accuracy of the developed model over two cubic EoSs and three empirical models from literature was confirmed. Finally, based on the sensitivity analysis, it was found that the pseudoreduced pressure (P-pr), MWC7+, and molar content of C7+ in the mixture have the highest impact on prediction of twophase Z factor. The proposed tools can be utilized for accurate prediction of gas condensate two-phase Z factor to ensure accurate simulation studies and better phase behaviour treatments.",0,0,1
Neural Network,Smart Models,"Amiri-Ramsheh, Behnam; Safaei-Farouji, Majid; Larestani, Aydin; Zabihi, Reza; Hemmati-Sarapardeh, Abdolhossein",Modeling of wax disappearance temperature (WDT) using soft computing approaches: Tree-based models and hybrid models,Solid scales; Wax disappearance temperature; Multilayer perceptron; Random forest; ANFIS; Leverage approach,HIGH-PRESSURE; PHASE-EQUILIBRIA; CRUDE OILS; PREDICTION; PRECIPITATION; OPTIMIZATION; ALGORITHM; DEPOSITION; ANFIS,"Solid scales can cause significant problems in oil production and transmission systems such as oil flow rate reduction. Wax is one of the most critical substances that are highly prone to precipitate and deposit in oil pipelines. This occurrence typically happens in low temperatures, and can extremely affect the flow rate. In the wax deposition process, wax disappearance temperature (WDT) is a crucial factor since it denotes the lowest temperature, at which wax deposits melt and the consequences of wax deposition vanish. In this research, smart models were utilized to predict WDT as a function of molar mass and pressure according to a comprehensive database. The proposed intelligent models are radial basis function (RBF) and multilayer perceptron (MLP) neural networks, adaptive neuro-fuzzy inference system (ANFIS), random forest (RF), extra tree (ET), and decision tree (DT). The MLP networks were trained with Bayesian Regularization (BR) and Levenberg-Marquardt (LM) algorithms, and the ANFIS models were coupled with three optimization algorithms, namely Cultural Algorithm (CA), Biogeography-based Optimization (BBO), and Teaching-Learning-Based Optimization (TLBO). Results demonstrate that the developed RF model could present an outstanding performance and provide predictions for WDT with the lowest average absolute percent relative error (AAPRE = 0.246%), the maximum coefficient of determination (for predicting = 0.993), and minimum root mean squared error (RMSE = 1.01). Trend analysis showed that increasing pressure and molar mass leads to wax disappearance temperature increase. Lastly, outlier discovery was performed using the Leverage approach to recognize the suspected data points. The outlier detection found that only 6 points (out of 346) are located in the upper and lower suspected data zones.",0,0,2
Neural Network,Smart Models,"Mahdaviara, Mehdi; Larestani, Aydin; Amar, Menad Nait; Hemmati-Sarapardeh, Abdolhossein",On the evaluation of permeability of heterogeneous carbonate reservoirs using rigorous data-driven techniques,Artificial intelligence; Neural network; Smart models; Absolute permeability; Carbonate reservoir,REGRESSION NEURAL-NETWORK; GENERALIZED REGRESSION; PREDICTION; FEED; FLOW; SATURATION; PARAMETERS; VISCOSITY; POROSITY; MODELS,"This study probes the application of Cascade Forward Neural Network (CFNN), Least Square Support Vector Machine (LSSVM), Multilayer Perceptron (MLP), and Generalized Regression Neural Network (GRNN) techniques for modeling the absolute permeability of carbonate rocks in terms of pore specific surface area, porosity, and irreducible water saturation. The control parameters of the MLP and CFNN models were tuned through Levenberg Marquardt Algorithm (LMA) and Bayesian Regularization (BR) optimizers, and the LSSVM paradigm was optimized using Gravitational Search Algorithm (GSA). Accordingly, six intelligent schemes, viz. MLP-BR, MLP-LMA, LSSVM-GSA, CFNN-BR, CFNN-LMA, and GRNN were trained by utilizing 80% of a valuable set of core data compiled from reliable literature and were tested through the rest of the data points (20%). The accuracy of the proposed paradigms was evaluated using several statistical and graphical assessments. The overall results were fulfilling and fair enough for the scope of this study. The proposed MLP-BR, MLP-LMA, LSSVM-GSA, CFNN-BR, CFNN-LMA, and GRNN models were associated with the Root Mean Square Errors of 6.8019, 5.6225, 165.8852, 6.6841, 5.2136, and 11.1799, respectively. The results were endorsed through 3-fold cross-validation. Furthermore, outlier detection was carried out by means of the plot of standardized residuals versus Leverage values. For all models, the majority of the points were valid values distributing in the applicability domain of the models. In the end, the developed models were compared against two literature smart models and a traditional correlation. The results demonstrated that the recently generated models offer remarkably higher accuracy than other alternatives followed by the Gene Expression Programming (GEP) modeling approach.",0,0,2
Neural Network,Water Flooding,"Kalam, Shams; Yousuf, Usama; Abu-Khamsin, Sidqi A.; Bin Waheed, Umair; Khan, Rizwan Ahmed",An ANN model to predict oil recovery from a 5-spot waterflood of a heterogeneous reservoir,ANN; ANFIS; SVR; Waterflooding,ARTIFICIAL NEURAL-NETWORK; POROUS-MEDIA; PERFORMANCE; SELECTION; GAS; INTELLIGENCE; REGRESSION; AKAIKE; FLOW,"Waterflooding is a secondary oil recovery technique in which water is injected into an underground oil reservoir to maintain the reservoir pressure and boost oil recovery. The performance of a waterflood depends on several factors such as reservoir heterogeneity, reservoir fluid properties, flood pattern, etc. Most of the models developed to predict waterflood performance are either for linear systems or involve simplified assumptions for nonlinear systems. In this study, we propose a novel, artificial neural network (ANN) model comprised of two hidden layers with 256 neurons each for the performance prediction of a 5-spot pattern waterflood in a heterogeneous reservoir at and beyond water breakthrough. The proposed model can be applied to estimate movable oil recovery efficiency of the waterflood (RFM) as a function of Dykstra-Parsons permeability variation coefficient (V), mobility ratio (M), permeability anisotropy ratio (kz/kx), production water cut (fw), a simple indicator of wettability (WI), and oil/water density ratio (DR) within reasonable accuracy. The MAPE of the proposed model was -4% and -5% using training and testing data, respectively. Our ANN model recommendation is based on a detailed comparative study against other popular soft computing models, such as adaptive neuro-fuzzy inference system (ANFIS) and support vector regression (SVR). Based on the accuracy and computational efficiency, the ANN model outperforms ANFIS and SVR. AIC and BIC of the proposed ANN model were also the lowest among all applied soft computing tools. The proposed model is tested on two real field cases and compared with a semianalytical model and an empirical correlation. The presented model shows good agreement with the real field data. The trained ANN model, proposed here, saves computational time in forecasting the waterflood performance compared to a reservoir simulator.",0,0,1
Neural Network,Water Flooding,"Rodriguez, Astrid X.; Salazar, Diego A.",Methodology for the prediction of fluid production in the waterflooding process based on multivariate long-short term memory neural networks,Waterflooding; Multivariate LSTM; Fluid prediction; Oil production forecast; Neural networks,,"Given the depletion of hydrocarbon reserves, the oil industry is developing enhanced recovery processes, including waterflooding, to increase the quantity of hydrocarbon to be extracted from each reservoir. However, one of the main challenges in assessing these processes is predicting water and oil production associated with the method, given the uncertainty, lack of reservoir information, and access to commercial software. This work proposes a methodology based on multivariate Long-Short Term Memory (LSTM) Neural Networks to predict oil and water production time-series in an oil field exploited through waterflooding. First, we used the oil and water production's time series of the producer wells in an inverted five-point injection pattern developed in a numerical reservoir simulation software based on a Colombian oil field exploited with waterflooding. In this scenario, we evaluated three multivariate LSTMs to determine the input features that should be included. Thus, through a define-by-run process, we assessed the LSTM structures most suitable. Finally, we found that the information obtained by operational variables, such as bottom-hole pressure or water injection rate, allows significant approximations to predict oil or water production.",0,0,2
Neural Network,Deposition,"Tian, Hui; Deng, Song; Wang, Caibao; Ni, Xingya; Wang, Hao; Liu, Yuan; Ma, Mingyu; Wei, Yaohui; Li, Xiaogang",A novel method for prediction of paraffin deposit in sucker rod pumping system based on CNN indicator diagram feature deep learning,Paraffin deposit; Convolutional neutral network; Prediction; Accuracy; Efficient production,WAX DEPOSITION; MODEL; FLOW; OIL,"Paraffin deposit is a major problem associated with water injection in waxy heavy oil reservoirs, therefore accurately and effectively predicting the development of paraffin deposit can avoid some major faults, such as stuck pump, and ensure the stability of the system. Paraffin deposit, as a gradual changing fault, shows a clear trend of development. Based on the convolutional neutral network (CNN) combined with deep learning, the indicator diagram is extracted to calculate the growth rate, and then the timing of serious paraffin problems can be predicted. The paper firstly analyzes and calculates the force of the column in the process of paraffin deposition and obtains the theoretical maximum load in the upper stroke and the theoretical minimum load in the lower stroke, then the load difference is selected as the parameter to characterize the paraffin deposit. In a case study, an experimental well is selected to determine maximum load difference in paraffin deposit process and load difference in normal production, and then the percentage of paraffin deposit is determined based on the growth law as the label of each indicator diagram. The structure of convolutional neural network is designed, and the accuracy rate is taken as the index to optimize the matching scheme of convolutional neural network structure parameters. Finally, the convolution neural network is trained by using training sets of 1.3 million well data. This method is an effective way to predict the paraffin deposit with CNN combined with deep learning and indicator diagram with an accuracy rate of 98.08% and loss less than 0.633. The prediction method in this paper can facilitate the intelligent management of oilfield safety and ensure the efficient production of pumping system.",0,0,1
Neural Network,Deposition,"Amiri-Ramsheh, Behnam; Safaei-Farouji, Majid; Larestani, Aydin; Zabihi, Reza; Hemmati-Sarapardeh, Abdolhossein",Modeling of wax disappearance temperature (WDT) using soft computing approaches: Tree-based models and hybrid models,Solid scales; Wax disappearance temperature; Multilayer perceptron; Random forest; ANFIS; Leverage approach,HIGH-PRESSURE; PHASE-EQUILIBRIA; CRUDE OILS; PREDICTION; PRECIPITATION; OPTIMIZATION; ALGORITHM; DEPOSITION; ANFIS,"Solid scales can cause significant problems in oil production and transmission systems such as oil flow rate reduction. Wax is one of the most critical substances that are highly prone to precipitate and deposit in oil pipelines. This occurrence typically happens in low temperatures, and can extremely affect the flow rate. In the wax deposition process, wax disappearance temperature (WDT) is a crucial factor since it denotes the lowest temperature, at which wax deposits melt and the consequences of wax deposition vanish. In this research, smart models were utilized to predict WDT as a function of molar mass and pressure according to a comprehensive database. The proposed intelligent models are radial basis function (RBF) and multilayer perceptron (MLP) neural networks, adaptive neuro-fuzzy inference system (ANFIS), random forest (RF), extra tree (ET), and decision tree (DT). The MLP networks were trained with Bayesian Regularization (BR) and Levenberg-Marquardt (LM) algorithms, and the ANFIS models were coupled with three optimization algorithms, namely Cultural Algorithm (CA), Biogeography-based Optimization (BBO), and Teaching-Learning-Based Optimization (TLBO). Results demonstrate that the developed RF model could present an outstanding performance and provide predictions for WDT with the lowest average absolute percent relative error (AAPRE = 0.246%), the maximum coefficient of determination (for predicting = 0.993), and minimum root mean squared error (RMSE = 1.01). Trend analysis showed that increasing pressure and molar mass leads to wax disappearance temperature increase. Lastly, outlier discovery was performed using the Leverage approach to recognize the suspected data points. The outlier detection found that only 6 points (out of 346) are located in the upper and lower suspected data zones.",0,0,2
Neural Network,PVT,"Ghorayeb, Kassem; Mawlod, Arwa Ahmed; Maarouf, Alaa; Sami, Qazi; El Droubi, Nour; Merrill, Robert; El Jundi, Obeida; Mustapha, Hussein",Chain-based machine learning for full PVT data prediction,PVT properties; Machine learning; Exploratory data analysis; Clustering; Chain approach; Compositional delumping; Splitting,NEURAL-NETWORK; OIL; MODEL; PRESSURE,"Building machine learning (ML) models based on pressure-volume-temperature (PVT) data is of paramount importance to capture trends and predict fluid behavior in a very heterogeneous and highly nonlinear thermodynamic system. PVT samples stored in an oil company database are often not complete and might be missing properties; both black oil and compositional. Before delving into building optimized fluid models, it is required to have a clean and structured PVT database complete with all the required properties. We present multiple novel algorithms developed to accurately predict a complete set of black oil and compositional properties within a PVT database. The proposed methodology consists of predicting properties in series, starting from a minimal set of data (black oil and compositional) and obtaining a complete set of data for all PVT samples. The order through which this is completed relies on benefiting from the existing data to predict missing data starting from the highest correlating data to the lowest. We also honored the physical nature of correlations between properties, and consequently, ranked properties for prediction as this leads to less error propagation. In addition, we have implemented data clustering prior to training ML models. Clustering is used to categorize the fluid samples into families based on the collective behavior of their different features, and hence, improve the quality of the PVT samples' properties prediction using machine learning. Several options are tested where clustering is performed using black oil properties only, compositional properties, or a combined set of black oil and compositional properties and the clustering scenario leading to the least prediction error is adopted. We have trained ML models to generically predict all black oil and compositional properties resulting from laboratory experiments, including molecular weights (MW) and mole fractions of heavy fractions (any set of heavy fractions) from the mole fractions of all the commonly available components up to C7+ and molecular weight of C7+. The massive data set used in this paper enabled comprehensive testing of the developed algorithms and provided striking accuracy of the predicted PVT properties; especially the compositional ones. Despite all the significant efforts shown in the literature concerning predicting PVT properties, the missing link is a systematic methodology to complete PVT samples' properties in a consistent manner. Furthermore, the focus in the literature is mainly on forecasting black oil properties; compositional properties are scarcely considered. Algorithms developed in this paper address these two limitations and are tested using a uniquely large data set available for onshore and offshore fields and reservoirs in Abu Dhabi. No previous algorithms, to the best of our knowledge, are tested on such a large data set.",0,0,0
Neural Network,PVT,"Bahonar, Ehsan; Chahardowli, Mohammad; Ghalenoei, Yaser; Simjoo, Mohammad",New correlations to predict oil viscosity using data mining techniques,Oil viscosity; Correlation; Data mining; Machine learning; Symbolic regression; Scatter matrix plot,ARTIFICIAL NEURAL-NETWORK; SENSITIVITY-ANALYSIS; PVT PROPERTIES; MODEL; CONDUCTIVITY; TEMPERATURE; PRESSURE; ANN,"Oil viscosity is used in any fluid transport calculation in both subsurface and surface conditions. It is possible to determine oil viscosity from laboratory measurements or empirical correlations. However, laboratory measurements are not always available; and empirical correlations suffer from low accuracy. This work implements data mining algorithms to suggest a new correlation for oil viscosity calculation in a wide pressure range from subsurface to surface conditions. First, a scatter plot matrix is applied to analyze 1950 PVT experimental data points from Iranian oil reservoirs. Therefore, the most correlated parameters for predicting oil viscosity are determined. Next, 75% of data points are randomly selected to train the models. The remaining data, i.e., 25% of data points, are utilized to investigate the accuracy of the developed correlation. Then, a symbolic regression analysis is performed in all pressure ranges, i.e., dead oil viscosity, bubble point oil viscosity, below and above the bubble point pressure. Finally, a new oil viscosity correlation is proposed. The statistical and graphical evaluations reveal that the new correlation outperformed the previously proposed correlations by lowering average absolute errors. It can be concluded that the presented correlation improves the prediction accuracy in all pressure ranges. Consequently, it is inferred from the results that machine learning could provide a highly accurate prediction for oil viscosity in all pressure regions. Overall, the proposed correlation could be used to calculate oil viscosity in all pressure ranges with reasonable accuracy.",0,0,2
Drilling Fluids,Wellbore Pressure,"Xie, Yuhong; Ouyang, Min; Zhao, Hu; Li, Lie; Feng, Yingtao",Wellbore pressure management of offshore wells during casing running in narrow safety pressure window formations,Safety pressure window; Surge-swab pressure; Managed mud level; Offshore well; Casing running,,"Casing running in subsea wells has long been considered a daunting task and repeatedly proved unsuccessful, largely due to the narrow safety pressure window formations. Mud losses to formations, formation fluid influx and well wall collapsing have been the three most common causes in such casing running failures. The problem can be solved with the managed wellbore pressure casing running technique, which was developed based on managed pressure cementing and implemented by controlling mud level. Accurate calculation of surge-swab pressure is the key to successful managed pressure casing running. In this study, we show a dynamic surges-wab pressure model for the managed pressure casing running method. By analyzing the factors influencing surge-swab pressure, it is found that the surge-swab pressure of wellbore rises with the increase in initial position of the bottom of the casing, casing running speed, drilling mud density and viscosity. By contrast, changing mud level has little impact on surge-swab pressure. The surge-swab pressure during the deceleration stage of the casing has a negative value, namely the swab pressure. Therefore, we propose a managed pressure casing running method based on the accurate calculation dynamic surge-swab pressure. This method controls the wellbore pressure by adjusting the mud level according to the surge-swab pressure. Managed wellbore pressure casing running can reduce not only the risk of lost circulation and fluid influx during casing running, but also the time for casing running operation.",0,0,0
Drilling Fluids,Wellbore Pressure,"Muravleva, Ekaterina A.; Derbyshev, Dmitry Yu; Boronin, Sergei A.; Osiptsov, Andrei A.","Multigrid pressure solver for 2D displacement problems in drilling, cementing, fracturing and EOR",Multigrid; Hydraulic fracturing; Cementing; Numerical modeling; Fast linear solver; BiCGStab,WELLBORE COMPLETION FLUIDS; ANNULAR DISPLACEMENTS; NUMERICAL-SIMULATION; MUD REMOVAL; OIL-WELL; FLOW; PLACEMENT; MODEL; TRANSPORT,"Numerical simulators for the design of oilfield services technologies are required to be fast and robust, hence the implementation of underlying mathematical models is expected to be highly efficient. We present an optimized numerical algorithm based on the multigrid approach for solving the pressure equation in 2D problems of fluid-fluid displacement. This type of problems arise in oilfield services applications, such as drilling, cementing, hydraulic fracturing and EOR. The displacement of fluids with different properties in a narrow annular gap (drilling, cementing) or a slot (hydraulic fracturing, production) is governed by the 2D width-averaged model in the lubrication approximation. In numerical implementation, the most time-consuming is the elliptic Poisson pressure equation, which has coefficients with discontinuities (jumps) in the case of displacement of fluids with viscosity contrast. Specifically for this case of discontinuous coefficients, we designed and implemented numerically the black-box multigrid algorithm, which resolves the divergence issue typical of standard realization of multigrid algorithm using bilinear prolongation operators. The algorithm is tested on a number of matrices corresponding to discretization of elliptic equation at rectangular staggered meshes with different resolution. The performance of the algorithm is compared against several other sparse solvers available for commercial use: smoothed aggregated algebraic multigrid (PyAMG software package), direct sparse solver from Intel MKL library (DSS), Bi-Conjugate Gradient-Stabilized solver preconditioned by ILUT factorization implemented into BLAS package, and our in-house Conjugated Gradient algorithm preconditioned by ILU(2) factorization. It was found that the performance of the black-box multigrid solver is significantly higher (from 7x to 30x in terms of CPU time depending on the mesh resolution) as compared to the closest solver under consideration, which allows us to recommend this solver for implementation into existing 2D drilling simulators, fracturing design tools, cement placement and production simulators.",0,0,0
Drilling Fluids,Wellbore Pressure,"Erivwo, Ochuko; Makis, Viliam",Improved abnormal formation pressure detection from drilling performance data in a partially observable setting,Drilling performance optimization; Pore pressure detection; D exponent; Analysis of variance (ANOVA); Factorial design experiment,PREDICTION; ENERGY,"Pore pressure prognosis during drilling is one of the most impactful pressure related information gathering activity for operational decision making. It enables the establishing of an appropriate overbalance, or differential pressure with bottom hole pressure (BHP) exerted by the drilling fluid, and has a direct bearing on the safety, efficiency, and cost of drilling the well. There are multiple approaches for detecting formation pressure but penetration rate (or drilling data) models are the only wholly internal, and most direct approach available in the partially observed downhole drilling operations system. In addition, they are unique in that they also encapsulate the variances from the uncertainty of the changes in the pressure data within the drilling performance optimization system. They however have been historically challenged because of the perceived limitation with the degree of their accuracy, largely as a result of conflating factor effects on drilling rate of penetration (ROP). This paper investigates the evolution of differential pressure in the drilling wellbore for the purpose of detecting abnormal formation pressure changes essential for improving drilling performance. The modified d exponent (dmod) was identified as an applicable source of diagnostic data for analyzing the downhole drilling system, and factorial design experiments were conducted to study the response of the dmod variable to changes in factor effects and systemic error. The results and analysis of variance from the experiments established the interactions of the two main exogenous factors - differential pressure and lithology - that contribute to the variations in ROP, and the unique effects of these often coalescing factors were extracted. A generalized stochastic model from the analysis of variance (ANOVA) extended with a randomized complete block design (RCBD) was thereafter developed for the evolution of differential pressure in the wellbore with uncertainty in operational time. The fitted model was used to calibrate abnormal pore pressure detection from the synthetic drilling data of the deepwater field case study. The results showed an improved detection accuracy, compared to classical drilling prognosis methods. This illustrates the effectiveness of our improved method in detecting abnormal formation pressure changes from drilling performance data and modeling the effect of overbalance transitions on ROP needed for optimal decision making in real time.",0,0,1
Drilling Fluids,Wellbore Pressure,"Gao, Reyu; Li, Jun; Yang, Hongwei; Lian, Wei; Wang, Wei",A novel approach to investigating the mechanism of permeability-induced borehole breathing in deepwater shallow formations,Borehole breathing; Deep-water shallow formation; The mechanism of permeability-induced; Mud loss,BEHAVIOR; STRESS,"Due to the uniqueness of deep-water shallow formations, there is no fracture system around the wellbore when borehole breathing is observed in this part of the formation. Therefore, the inducing mechanism of the opening/closing of the fracture network cannot reasonably explain this type of borehole breathing. In this study, a new mechanism of permeability-induced is proposed to explain borehole breathing, based on the fact that there is no fracture system around the well and the formation has the characteristics of high permeability and porosity. By using the stress and seepage coupling method in the porous elastic medium, a new model is established to simulate and describe permeability-induced borehole breathing. Through comparison with actual cases, this model can effectively simulate the typical characteristics of fluid loss-flow back in borehole breathing. This study also analyzed the influence of factors such as formation parameters and mud rheological parameters on the borehole breathing caused by permeability. According to the results of the study, the use of a smaller diameter wellbore and agents that can adjust related parameters (such as loss-reducing circulating material) can effectively inhibit wellbore breathing while drilling.",0,0,2
Drilling Fluids,Wellbore Pressure,"Zhang, Mingming; Fan, Xiangyu; Zhang, Qiangui; Yang, Bozhong; Zhao, Pengfei; Yao, Bowei; Ran, Jiawei",Parametric sensitivity study of wellbore stability in transversely isotropic medium based on polyaxial strength criteria,Shale; Anisotropy; Wellbore breakout; Polyaxial criteria; Transversely isotropic,BOREHOLE STABILITY; FAILURE CRITERION; HORIZONTAL WELLS; MODEL; ROCKS; SHALES; PLANES,"Borehole instability in laminar formations often occurs during drilling operations without a clear explanation. Two dominant factors, rock lithology and stress concentration effects on borehole instability, are investigated in this study. The microstructure and mineral composition are evaluated to determine the possible reactions of the drilling fluid and shale interaction. A borehole stability model in a transversely isotropic medium is established using three different types of polyaxial strength criteria to study the effect of the degree of elastic anisotropy and intermediate principal stress on the lower boundary of the safe drilling window. Research has indicated that Poisson's ratio anisotropy does not markedly change the collapse pressure at low anisotropy. However, the effect of the elastic modulus anisotropy is notable, and the collapse pressure predicted by polyaxial criteria is more sensitive to elastic anisotropy. The collapse pressure calculated by the Mohr-Coulomb criterion is the upper limit; the results predicted by the Modified Lade and Modified Wiebols-Cook criterion are similar, corresponding to the wellbore orientations. This study explores the failure mechanisms of wells drilled in layered shales, which can help determine critical mud pressure and well orientation design. The outcomes of this investigation indicate the implications of fully accounting for the degree of elastic anisotropy and the influence of intermediate stress in conducting wellbore stability analysis.",0,1,2
Drilling Fluids,Wellbore Pressure,"Tan, Tianyi; Zhang, Hui",A risk prediction method of pipe sticking accidents due to wellbore uncleanness for long horizontal section wells,Wellbore uncleanness; Bulldozer effect; Pipe sticking prediction; Long horizontal section well; Torque and drag,CUTTINGS TRANSPORT; FLUID; MODEL; FLOW; CLEANOUT; OIL,"The prediction of pipe sticking accidents due to wellbore uncleanness is significant for safe drilling, while existing qualitative prediction methods result in inaccuracy and lateness. To cover the shortages, a novel quantitative pipe sticking prediction method is established to achieve pipe sticking prediction early in drilling preparatory stage. First, the additional axial forces and torques on the drill string exerted by accumulated cuttings are calculated in tripping out, tripping in, back reaming and reaming processes based on granular mechanics. Second, the torque and drag model is modified considering additional axial forces and torques to calculate the hook load and the top drive torque. Finally, the pipe sticking prediction is conducted according to the critical hook load and the critical top drive torque in a specific drilling process. A case study including comparison with the classical model and sensitivity analysis is conducted. Under the given condition, pipe sticking risk is predicted with the new mothed by anticipating hook loads (5524.67 and -667.71 kN) and top drive torques (60.87 and 66.36 kN m) exceeding the critical values. The hook load and the top drive torque change exponentially with the travelling distance. In tripping out and back reaming processes from 4350 to 4250 m, the hook load and the top drive torque respectively increase for 1894.36 kN and 53.99 kN m. In tripping in and reaming processes from 3450 to 3550 m, the hook load decreases for 29925.66 kN and the top drive torque increases for 157.3 kN m. According to the sensitivity analysis, low frictional coefficients, initial cutting volume fractions, torque and drag frictional factors and high junk slot ratios are required to reduce the risk of pipe sticking. This study provides a timely and quantitative prediction method for pipe sticking accidents due to wellbore uncleanness in long horizontal drilling.",0,0,3
Drilling Fluids,Wellbore Pressure,"Epelle, Emmanuel, I; Obande, Winifred; Okolie, Jude A.; Wilberforce, Tabbi; Gerogiorgis, Dimitrios, I",CFD modelling and simulation of drill cuttings transport efficiency in annular bends: Effect of particle size polydispersity,Polydispersity; Cuttings transport; Discrete phase model; Rosin-Rammler,FLOW; PREDICTION; ROTATION; OIL,"This study analyses the impact of particle polydispersity using the Eulerian-Eulerian (EE) and LagrangianEulerian (LE) modelling approaches in the context of wellbore cleaning operations in the drilling industry. Spherical particles of sizes 0.5 mm, 0.75 mm and 1 mm are considered, whereas a Power Law rheological model is used for the fluid phase description. The EE approach implemented herein applies the Kinetic Theory of Granular Flow (KTGF) in ANSYS Fluent (R) and accounts for the particle size differences by representing them as different phases within the computational domain. With the LE approach, we employ the Dense Discrete Phase Model (DDPM) and capture this difference with the aid of a size distribution model (the Rosin-Rammler model). The findings of our computational experiments show considerable differences in key variables (the pressure drop, and particle deposition tendencies) between monodispersed and polydispersed transport scenarios.",0,0,3
Drilling Fluids,Wellbore Pressure,"Yang, Mou; Luo, Hao; Xie, Rongxuan; Wu, Pengcheng; Yang, Mingzheng; Yang, Lvchao; Xue, Hu",Estimating and optimizing wellbore pressure during primary cementing in low pressure and leakage formations,Circulating pressure; Cementing operation; Low pressure and leakage formations; Mathematical model; Computational fluid dynamics,NON-NEWTONIAN FLUIDS; POWER-LAW FLUID; HERSCHEL-BULKLEY; ECCENTRIC ANNULI; DRILLING-FLUIDS; TURBULENT-FLOW; LAMINAR; CIRCULATION; TRANSITION; BEHAVIOR,"In most realistic situations, casing eccentricity and various fluids injected during primary cementing lead to a significant difference in fluid flow and circulating pressure, compared with a single fluid flowing in the concentric annulus. Ignoring the effect of eccentricity and fluid rheological model on the wellbore circulating pressure results in an inaccurate evaluation and leads to formation leakage, especially for low pressure and leakage formations. To overcome this challenge, firstly, rheological models of various fluids were analyzed using experimental data, including drilling fluid, spacer, and cement slurry. Secondly, the modified correlations of frictional pressure losses for Herschel-Bulkley and Power Law fluids in the eccentric annulus were developed, using the simulation data of computational fluid dynamics software (CFD) and considering the effects of flow behavior index, pipe diameter ratio, and casing eccentricity on the frictional pressure losses. Finally, based on the developed mathematical models, the optimal method of primary cementing and evaluation results were presented, analyzed, and tested in the field with great success. The results demonstrated that the drilling fluid and spacer fluid had the highest goodness of fit for the Herschel-Bulkley model, and the cementing slurry was suitable for the Power Law model. The ratio coefficient of pressure loss in the eccentric to concentric annulus decreased with a decrease of hole size and an increase of casing eccentricity. A 50 percent reduction in frictional pressure loss was evaluated when the casing lies on the borehole wall. Comparing the calculations of the developed correlation with the published correlation in the literature reveals a more accurate evaluation of friction pressure losses in the analyzed case. Combined with the realistic situation of a test well, the density, flow rate, and returning depth of the lead cement slurry were recommended as 1.5 g/cm(3), 0.5 m(3)/min and 4100 m, respectively, according to the leakage pressure of 65.6 MPa that was calculated by the developed mathematical model. Most importantly, the developed method in this paper can accurately predict the variation characteristics of wellbore pressure during the primary cementing process and provide effective guidance in managing downhole pressure in low pressure and leakage formations by real-time adjustment of the most effective and controllable operation parameters.",0,0,3
Drilling Fluids,Rock,"Costa, Beethoven G. dos S.; Jaculli, Marcelo A.; Mendes, Jose Ricardo P.; Colombo, Danilo",Evaluation of rock integrity during well drilling activities using reliability analysis,Well integrity; Rock reliability; Well safety; Kick tolerance,,"The main risk during the construction of oil wells is the possibility of uncontrolled hydrocarbon flow occurring from the well to the environment, commonly known as a blowout. After the Macondo accident, in the Gulf of Mexico, in 2010, there has been, in recent years, a significant increase in researches related to both well integrity and operational safety. A possible approach is to seek tools that can predict disastrous scenarios and support the decision making process. In this context, this work evaluates the reliability of the weakest rock in an open hole section, which is the formation immediately below the last settled casing shoe. Reliability, in this case, refers to the likelihood that the rock does not fracture during a possible kick or during drilling fluid circulation without a kick. The formulation of this problem involves addressing the inherent uncertainties, which may cause the failure of the ""rock"" barrier element. Modeling was performed by assigning probabilistic distributions to the parameters carrying uncertainties and by proposing two solutions. If all the uncertainties can be modeled using the normal distribution, it is possible to calculate the reliability analytically; meanwhile, if the variables are modeled using more than one type of distribution, an analytical solution may be hard to achieve and Monte Carlo simulations are preferred to obtain a numerical solution. The numerical solution does not require mean values and standard deviations of the output variables and becomes particularly useful when these characteristics are unknown. Therefore, this methodology evaluates the competence of the rock as a barrier element, enhancing operational safety and maintaining well integrity. The calculated reliability values can be used to assist in real-time drilling monitoring, from a rock integrity standpoint. The results of this methodology include the rock reliability as a function of the well depth, based on the current drilling phase. This includes the two aforementioned scenarios, with and without a kick.",0,0,0
Drilling Fluids,Rock,"Nunes, Marcos; Valle, Bruno; Borghi, Leonardo; Favoreto, Julia; Mendes, Marcelo","Multi-scale and multi-technique characterization of hybrid coquinas: A study case from the Morro do Chaves Formation (Barremian-Aptian of Sergipe-Alagoas Basin, Northeast Brazil)",Multi-scale reservoir characterization; Rock typing; Upscaling; Petrophysics; Heterogeneity; Coquinas,GEOLOGICAL ATTRIBUTES; ARCHIES EXPONENTS; CARBONATE ROCKS; FLUID MIGRATION; CAMPOS BASIN; SEDIMENTARY; POROSITY; FAULTS; CLASSIFICATION; EVOLUTION,"The coquinas are carbonate rocks with variable content of siliciclastics and have a complex porous framework that implies an issue for their characterization as reservoirs. Furthermore, these rocks are considered important reservoirs due to the giant accumulations in the Campos and Santos basins (Coqueiros and Itapema formations, respectively), increasing the interest in understanding and characterizing these complex and heterogeneous lithologies. In this context, this study aims to introduce a novel method of petrophysical characterization of coquinas through a multi-technique and multi-scale approach in a continuous well core of approximately 135 m, drilled in the ""Atol Quarry"", Sa similar to o Miguel dos Campos County, Alagoas State. Based in mineralogical content, x-ray attenuation and pore type, seven tomofacies were defined using computerized tomography and allowed a representative sampling (plugs and thin sections). Five rock types were defined based textural aspects (tomofacies and petrography) and petrophysical data (routine core analysis and micro-computerized tomography). The rock types were compared to well logs, establishing boundary values and distributed along the whole well, in an upscaling process from thin-section and plugs (microscopic scale) to the well core (macroscale). The Morro do Chaves Formation core was divided into two portions: upper portion, with better reservoir quality and greater influence of mineral dissolution; and lower portion, a poor reservoir quality portion influenced by cementation processes. The upscaling method using the concepts of tomofacies and rock types proved to be a successful way to improve the understanding of reservoir characterization in heterogeneous of complex limestone successions, which can improve the recovery factor and aid in the field development.",0,0,1
Drilling Fluids,Rock,"Mohammadi, Mojtaba Kalhor; Riahi, Siavash; Boek, Edo S.",Developing novel bio-nano catalyst well clean up fluid to remove formation damage induced by polymeric water-based drilling fluids,Well clean-up; Production enhancement; Filter cake breaker; Formation damage; Nanobiocatalyst,,"Drilling and completion fluids may cause significant formation damage in oil and gas reservoirs, directly affecting productivity. For many years, operators have applied different stimulation practices such as acidizing, oxidizers, chelating agents, and enzyme treatment to remove formation damage associated with drilling fluids filter cake. An enzyme-based biological treatment was combined with other chemicals or additives as a selective well clean-up practice to improve removing polymer content in the filter cake. However, the secondary formation damage such as deep cleaning of the invaded zone and wettability alteration remained the main concern. This paper presents the development of an innovative clean-up fluid formulation by immobilizing an enzyme and a selective nanoparticle as Bio-Nano Well Clean-Up Fluid (BNWC) in potassium chloride brine to enhance WBM filter cake removal. Several bulk experiments, including; precipitation, iodine test, and viscosity measurement, demonstrate the enzyme's optimization, the nanoparticle concentration, and base fluid brine. BNWC in potassium chloride brine showed the highest HPHT filtration rate at 200 degrees F and differential pressure of 100 psi and increased the filtration rate by more than 90 percent compared to the conventional enzyme in the same brine. Contact angle measurements confirmed wettability alteration of the carbonate rock to water-wet, and IFT measurements showed higher oil mobility potential. Finally, core flooding tests at reservoir conditions showed a 300 percent enhancement in injection rate and a 50% improvement in core permeability after damage. The immobilization of the enzyme with the nanoparticle has been developed successfully for other applications in bioremediation, farming, and other industries, but the novelty of this research demonstrates the application of nanobiocatalysts in drilling fluids for the first time. This innovative clean-up fluid enhances the enzymatic activity and removes primary and secondary formation damage associated with drilling fluid filter cake.",0,0,1
Drilling Fluids,Rock,"Kadyrov, Rail; Nurgaliev, Danis; Saenger, Erik H.; Balcewicz, Martin; Minebaev, Rezit; Statsenko, Evgeny; Glukhov, Mikhail; Nizamova, Aigul; Galiullin, Bulat",Digital rock physics: Defining the reservoir properties on drill cuttings,Cuttings; Core; Carbonates; Pore structure; Digital rock physics,TRANSPORT; CFD; PARAMETERS; PROGRAM; OIL,"Well drilling with core extraction is one of the most expensive procedures in the oil industry. The potential alternative, which may open opportunities for cost-efficient acquisition of petrophysical data, can be an approach based on digital analysis of drill cuttings. The main purpose of this research was to evaluate the possibility of using digital cuttings analysis and rock physics for reservoir properties evaluation. The carbonate samples of core and cuttings were simultaneously collected from the same intervals during the drilling of deviated wells in the Carboniferous reservoir of the oil deposit in the Republic of Tatarstan, Russia. Based on the core analysis using the optical study of thin sections and XRD, we investigated sedimentological and mineralogical features and classified all lithotypes of well intervals. The standard samples were produced from all defined facies and their reservoir properties were studied in routine tests. The largest cuttings from each well interval were separated and their structures were compared using mu CT with core subsamples of the same intervals. We assessed the changes of cuttings structure occurring in the drilling process, which include the colmatation of the pore space with drilling fluid and disintegrated rock particles and the formation of secondary fractures. Detailed analysis of cuttings from one well interval consisting of the border between the facies of high porous grainstones with packstones and dense micrite limestones demonstrated that high porous varieties were eroded in the drilling process. The analysis of chemical composition using XRF-mapping, XRD and SEM with EDS showed that most of the cuttings were constituted by disintegrated rock particles or form elements (e.g. separate fusulinids) cemented by drilling mud. However, more durable cuttings from dense micrite limestones facies were generally retained their dominant calcite composition and original rock structure, with only secondary fractures. Finally, we analyzed pore space properties and performed digital simulations of wave propagation velocities to compare the characteristics of these cuttings and core subsamples from this lithotype, scanned in the same mu CT settings. The results demonstrate close characteristics of porosity 0.08-0.6%, dominant pore sizes 1-60 mu m and velocities Vp = 6130-6240 m/s, Vs = 3180-3230 m/s. However, the comparison of obtained values with measured on standard samples shows a significant difference, which is caused by deviation from REV. The potential use of cuttings for assessing reservoir and petrophysical properties can be possible in case of provision with the factors of cuttings structure alteration, representativity of samples, as well as optimization for these purposes of the drilling process with cuttings selection.",0,0,1
Drilling Fluids,Rock,"Bellabiod, Sofiane; Deghmoum, Abdelhakim; Aris, Abdelkader; Karacali, Ozgur",An insight to formation damage evolution,Formation damage time evolution; Pressure transient analysis; Well test,,"Formation damage can significantly defer hydrocarbon production. Formation damage is one of the key parameters used to evaluate the quality of various operations during the life of a well. The evolution of formation damage over time is rarely studied. This paper presents the pressure transient analysis (PTA) used to derive a correlation between skin factor increase and the length of time for which a well was left exposed to drilling fluid. Multiple field examples are analyzed and modeled comparatively to evaluate the magnitude of the time-lapse formation damage. A quantitative relationship between the increase in mechanical skin as a function of exposure to drilling mud is constructed by a polynomial fitting. This gives us an insight on the how the well skin increases with exposure to drilling mud. Several mathematical models have been developed to model formation damage mechanisms. However, it is cumbersome to isolate and compute the individual mechanisms contributing to observed damage. Formation damage results from a combination of the pore size distribution, fines migration, fluid compatibility problems, wettability, presence of inorganic salts deposition, insufficient well cleanup, organic substance deposition, multiphase flow effects, etc. The proposed approach uses the skin factor derived from pressure transient analysis (PTA) to track the time-lapse evolution of formation damage during exposure time to mud, from drilling to production. The methodology has been applied to various reservoir rocks to quantify the impact for a specific rock type. Results from pressure transient tests conducted immediately after drilling, casing, and perforating are compared with production tests performed multiple years after drilling confirm that there is a mathematical relation between the formation damage, type of drilling and completion fluid, formation rock type, and exposure time to such fluids. The formation damage increase is more severe for longer duration of exposure, and also more severe for higher formation permeability.",0,0,2
Drilling Fluids,Rock,"Zhang, Mingming; Fan, Xiangyu; Zhang, Qiangui; Yang, Bozhong; Zhao, Pengfei; Yao, Bowei; Ran, Jiawei",Parametric sensitivity study of wellbore stability in transversely isotropic medium based on polyaxial strength criteria,Shale; Anisotropy; Wellbore breakout; Polyaxial criteria; Transversely isotropic,BOREHOLE STABILITY; FAILURE CRITERION; HORIZONTAL WELLS; MODEL; ROCKS; SHALES; PLANES,"Borehole instability in laminar formations often occurs during drilling operations without a clear explanation. Two dominant factors, rock lithology and stress concentration effects on borehole instability, are investigated in this study. The microstructure and mineral composition are evaluated to determine the possible reactions of the drilling fluid and shale interaction. A borehole stability model in a transversely isotropic medium is established using three different types of polyaxial strength criteria to study the effect of the degree of elastic anisotropy and intermediate principal stress on the lower boundary of the safe drilling window. Research has indicated that Poisson's ratio anisotropy does not markedly change the collapse pressure at low anisotropy. However, the effect of the elastic modulus anisotropy is notable, and the collapse pressure predicted by polyaxial criteria is more sensitive to elastic anisotropy. The collapse pressure calculated by the Mohr-Coulomb criterion is the upper limit; the results predicted by the Modified Lade and Modified Wiebols-Cook criterion are similar, corresponding to the wellbore orientations. This study explores the failure mechanisms of wells drilled in layered shales, which can help determine critical mud pressure and well orientation design. The outcomes of this investigation indicate the implications of fully accounting for the degree of elastic anisotropy and the influence of intermediate stress in conducting wellbore stability analysis.",0,1,2
Drilling Fluids,Rheological Properties,"Krishna, Shwetank; Ridha, Syahrir; Campbell, Scott; Ilyas, Suhaib Umer; Dzulkarnain, Iskandar; Abdurrahman, Muslim",Experimental evaluation of surge/swab pressure in varying annular eccentricities using non-Newtonian fluid under Couette-Poiseuille flow for drilling applications,Concentric and eccentric annulus; Couette-Poiseuille (CP) flow; Drilling; Non-Newtonian fluid; Surge; swab pressure gradient,SWAB PRESSURES; FOOD PROCESSES; MASS-TRANSFER; MODEL; EQUATIONS,"Global energy demand is rapidly increasing at a rate of 8% between 2004 and 2019, and conventional energy sources are unable to meet this requirement. Therefore, the oil and gas energy industry is working continuously to produce unconventional energy sources such as deepwater oil and gas reservoirs, gas hydrates, and geothermal energy using drilling operations. In the drilled borehole, the stability and integrity issues are encountered that are related to pressure differential generated by the Couette-Poiseuille (CP) fluid flow phenomenon occurred during pipe tripping operation. There is a lack of experimental data to comprehend the impact of CP flow on pressure differential using non-Newtonian fluid in concentric and eccentric annuli, especially in petroleum exploration. Hence, an experimental investigation is performed to replicate the tripping operations during oil and gas well drilling. The investigation provides an extensive understanding of the physical and mechanical characteristics of non-Newtonian fluids under CP flow at varying inner pipe tripping speeds (0.030481-0.21336 m/s), rheological properties, and geometrical dimensions. The results indicate that surge/ swab pressure gradient tends to decrease with increasing eccentricity (epsilon) and increase with increasing diameter ratio (delta) and pipe tripping speed (Vp). Furthermore, the pressure differential rate is considerably high at low tripping speed but reduces at high pipe tripping speed due to the shear-thinning behavior of YPL fluid. The study also reveals that gel strength increases the surge/swab pressure gradient by approximately 18%. A multi-variable correlation is developed to predict surge/swab pressure gradient, exhibiting an excellent agreement with experimental data and existing theoretical models.",0,0,1
Drilling Fluids,Rheological Properties,"Ahmad, Hafiz Mudaser; Iqbal, Tanveer; Al Harthi, Mamdouh A.; Kamal, Muhammad Shahzad",Synergistic effect of polymer and nanoparticles on shale hydration and swelling performance of drilling fluids,Zinc oxide; Nanoparticles; Shale inhibition; Drilling formulations,XANTHAN GUM; BENTONITE; PRESSURE; BEHAVIOR; ENERGY; MUDS; INTERCALATION; ENHANCEMENT; SURFACTANT; EFFICIENCY,"The inhibition attributes of drilling formulations typically rely on the type of additives, concentration, and reactivity with shale formations. In this work, the impact of ZnO and polymer on rheological, shale inhibition, and filtration properties were studied. Several drilling formulations were prepared with different concentrations of ZnO and polymer in the deionized water. Rheological properties (viscosity, yield stress, and gel strengths) were measured using a hybrid rheometer to investigate drilling formulation performance. The filtration properties drilling formulations and permeability analysis of filter cake was performed to analyze the impact of ZnO and associative polymer on fluid loss. SEM-EDS analysis of filter cake was accomplished to investigate the dispersion of drilling additives on filter cake. Shale swelling inhibition characteristics of drilling formulations were determined by performing shale dispersion test and linear swelling test as per API standards. The shale dispersion test showed 97% shale recovery with BPN4 formulation compared to 81% of shale recovery with the base formulation. Shale swelling rate decreased to 6.69% with BPN4 formulation compared to the 14.29% of shale swelling rate in the base formulation. Shale inhibition results showed that the synergic impact of ZnO and polymer in the formulations enhanced the inhibition characteristics. Contact angle measurements showed that synergy of ZnO and polymer in the drilling formulation increased the hydrophobicity of the shale surface. Hence, drilling formulations comprising both ZnO and polymer can be applied to drilling operations for superior inhibition characteristics.",0,0,1
Drilling Fluids,Rheological Properties,"Alkalbani, Alhaitham M.; Chala, Girma T.; Myint, Myo Tay Zar",Experimental investigation of rheological properties of water-base mud with zinc oxide nanoparticles using response surface methodology,Nanoparticles; Zinc oxide; Downhole condition; Viscosity; Yield point; Gel strength,OIL,"Special and advanced techniques at drilling and production operations are used to drill and produce hydrocarbons from different eccentric reservoirs such as deep-water reservoirs, shale gas, and shale oil necessitates. However, these advanced techniques are considered to be costly and affecting the environment. Therefore, nanotechnology has been implemented in the drilling fluids to improve the rheological properties, hydrogen concentration, and filtration rate. This study is, therefore, aimed at evaluating the properties of zinc oxide nanoparticles and their previous implementation in drilling fluids, examining the rheological properties of water base mud from atmospheric temperature to downhole condition (90 degrees C). The experiment was designed to investigate the effect of nanoparticles concentration and temperature variation on the rheological properties of water-based mud using response surface methodology. A rotational viscometer was used to measure viscosity, yield point and gel strength. Moreover, a Consistometer was used to heat the fluid sample to different temperatures reaching up to downhole condition (90 degrees C). It was observed experimentally that addition of zinc oxide nanoparticles impressively improved the rheological properties of water-base mud by 50% for viscosity and gel strength, and 80% for yield point. It also allowed them to maintain their quality at all temperatures. Furthermore, addition of higher concentrations of zinc oxide nanoparticles of more than 1 wt% (6 g) at low temperatures (below 40 degrees C) gave the highest and most effective results of the rheological properties.",0,0,1
Drilling Fluids,Rheological Properties,"Duarte, A. C. R.; Ribeiro, P. R.; Kim, N. R.; Mendes, J. R. P.; Policarpo, N. A.; Vianna, A. M.",An experimental study of gas solubility in glycerin based drilling fluid applied to well control,Solubility; Drilling; Well control; Drilling fluids; Aqueous glycerol solution,METHANE,"The drilling fluid is the primary barrier element against a kick. In the path of drilling fluids evolution, syntheticbased drilling fluid (SBDF) is commonly used on offshore rigs due to its benefits to the high level of drilling complexity, especially at deep and ultra-deep-water scenarios. However, when formation gas dissolves in the mud due to high pressure and high temperature, the complexity of kick detection increases significantly. Furthermore, environmental concerns raised a red flag on SBDF usage due to potential impacts on the marine environment, with most governmental agencies around the world passing very strict regulations. Considering both aspects - safety, and environmental concerns - glycerin emerges as a potential candidate to perform a key role as a base drilling fluid (GBDF). At first, a GBDF has the potential to behave as an SBDF due to its benefits, such as lubricity and shale stabilization, and, at the same time, it has the same characteristics of water-based drilling fluid (WBDF) with very low methane solubility, the major component of natural gas. Additionally, GBDF is considered to be more environmentally friendly than SBDF. In this work, we first analyzed the PVT properties and rheology of three different molar composition glycerin-based drilling fluids: 100% glycerin, 5050% glycerin/brine, and 40-60% glycerin/brine. Then, we performed the PVT properties analysis of methane (10-50% molar mass) mixed with each of these GBDF mentioned. In a systematic constant composition expansion through a visual high-resolution PVT cell under temperature and pressure range conditions of 20-80 degrees C and 0-55 MPa, respectively, and rheology characterization. The GBDF exhibited interesting results for density and rheology parameters similar to an SDBF and no methane solubility. Finally, mathematical correlations are proposed and applied to illustrate a pit-gain calculation comparing to an n-paraffin-based drilling fluid.",0,0,3
Drilling Fluids,Rheological Properties,"Ettehadi, Ali; Ulker, Ceylan; Altun, Gursat",Nonlinearity in large amplitude oscillatory shear of drilling fluid: A comparative study on the oil and water base muds behavior,Drilling fluid; Nonlinear viscoelasticity; Large amplitude oscillatory shear (LAOS); Shear mechanism; Structural stability,VISCOELASTIC PROPERTIES; PRESSURE-DROP; LAOS BEHAVIOR; MODEL; RHEOLOGY; STRESS; TRANSITION; VISCOSITY; EQUATION,"A viscoelastic material exhibits both fluid (viscous) and solid (elastic) like properties simultaneously. The rheological behavior of drilling fluids is customarily measured under the assumption of pure viscous flow, yet they exhibit both viscous and elastic characteristics when subjected to deformation. Some imperative properties of drilling fluids such as gel strength, yield stress, and sag tendency at near-zero shear rate region are categorically under the influence of viscoelastic behavior and have not yet been completely understood due to the lack of appropriate measurement methods. Characterizing the complete rheological profile of material requires measuring linear and nonlinear viscoelastic responses at a wide range of stress/strain levels. The viscoelastic nonlinearity can be characterized under Large Amplitude Oscillatory Shear (LAOS) tests. This study presents a large amplitude oscillatory shear rheology investigation of two water-base (Lignosulfonate and KCl/polymer) and two oil-base (low and high temperature) drilling fluids each in three states; unweighted, weighted, and weighted-contaminated. The viscoelastic nonlinearities of four fluid samples were investigated experimentally as a function of strain amplitude and strain-rate space at different temperatures. The results were described using Lissajous-Bowditch (L-B) plots and local nonlinear viscoelastic dynamic moduli through an oscillatory shear cycle. Structural stability of fluid samples was also studied using the creep-recovery test. The nonlinear viscoelastic behavior of drilling fluids was comprehensively compared and distinguished to understand their nonlinear shear mechanism. As a result of the creep-recovery test at 150 degrees C, high-temperature oil base mud provided higher thermostructural stability and zero shear viscosity than those of Lignosulfonate, KCl/polymer, and low-temperature oil-base muds. While the elastic nonlinearity was found to be strain/strain rate softening, the nonlinear viscous character was recorded as shear/shear rate thinning at large strain rates for all drilling fluid systems. Quite a different shear mechanism was detected at low and moderate strain rates. Shear rate thinning was found to be the dominant mechanism for all fluids except Lignosulfonate mud samples that demonstrated shearthickening behavior at moderate strain rates at 25 degrees C. At high temperatures (100 degrees C and 150 degrees C), shear rate thickening followed by shear rate thinning behavior was governing mechanism under the low and moderate strain rates in all mud samples except KCl/polymer muds. An inverse behavior (shear rate thinning followed by shear rate thickening) was observed through low and moderate strain rates in KCl/polymer muds at 100 degrees C and 150 degrees C. Therefore, as revealed from the LAOS test results, shear rate thickening behavior at low to moderate strain rates is in contradiction of the commonly known shear thinning behavior for a drilling fluid undergoing viscous deformation. This finding explains the facts underlying some important properties of drilling fluids such as gel structure formation, hole cleaning ability, and sag tendency.",0,0,3
Drilling Fluids,Formation Damage,"de Souza Fritoli, Giovani; De Lai, Fernando Cesar; de Mello Junqueira, Silvio Luiz",Effect of LCM and polymeric additives on mudcake and filtrate rheology parameters,Lost circulation; LCM; Filtration; CaCO3; Mudcake,CAKE; CIRCULATION; OIL,"In oil and gas well drilling operations, lost circulation is characterized by the invasion of drilling fluid into permeable formations. Besides generating additional costs to the process, the loss of circulation can damage producer formations and, if uncorrected, reduce pressure inside the well, inducing kicks. One of the alternatives for combating this problem is the addition of lost circulation materials (LCM) to the drilling fluid. The added LCMs will accumulate and form a filter cake on the interface between the well and the porous formation, thus reducing the volume of fluid lost. In the present work, the cake formation process resulting from the deposition of particulate material on a porous substrate is studied experimentally. The objective is evaluating the influence of type and concentration of two polymeric additives and four types of LCM on the formation of the filter cake. The experiments were carried out in an API filter press at pressures of 100 psi, using solutions of carboxymethylcellulose (CMC) and xanthan gum (XG) in water at 1.05 and 2.10 lbm/bbl. The particle size used as loss of circulation material comprises two values (2 - 44 and 44 - 106 mu m) of calcium carbonate (CaCO3), glass microspheres (180 - 300 mu m), and plastic particles (250 - 420 mu m). The efficiency of the fluid-LCM combination in combating lost circulation is evaluated based on the filtrate volume, thickness, dry and wet cake masses, and filtrate flow curves. Results show that the increase of the LCM concentration and the use of the calcium carbonate particulate with smaller particles favor the filtrate volume reduction. Also, the filtrates exhibit non-Newtonian behavior with reduced values of viscosity due to the retention of polymeric chains by the formed filter cake. Such phenomenon is most significantly detected when calcium carbonate is used.",0,0,0
Drilling Fluids,Formation Damage,"Mohammadi, Mojtaba Kalhor; Riahi, Siavash; Boek, Edo S.",Developing novel bio-nano catalyst well clean up fluid to remove formation damage induced by polymeric water-based drilling fluids,Well clean-up; Production enhancement; Filter cake breaker; Formation damage; Nanobiocatalyst,,"Drilling and completion fluids may cause significant formation damage in oil and gas reservoirs, directly affecting productivity. For many years, operators have applied different stimulation practices such as acidizing, oxidizers, chelating agents, and enzyme treatment to remove formation damage associated with drilling fluids filter cake. An enzyme-based biological treatment was combined with other chemicals or additives as a selective well clean-up practice to improve removing polymer content in the filter cake. However, the secondary formation damage such as deep cleaning of the invaded zone and wettability alteration remained the main concern. This paper presents the development of an innovative clean-up fluid formulation by immobilizing an enzyme and a selective nanoparticle as Bio-Nano Well Clean-Up Fluid (BNWC) in potassium chloride brine to enhance WBM filter cake removal. Several bulk experiments, including; precipitation, iodine test, and viscosity measurement, demonstrate the enzyme's optimization, the nanoparticle concentration, and base fluid brine. BNWC in potassium chloride brine showed the highest HPHT filtration rate at 200 degrees F and differential pressure of 100 psi and increased the filtration rate by more than 90 percent compared to the conventional enzyme in the same brine. Contact angle measurements confirmed wettability alteration of the carbonate rock to water-wet, and IFT measurements showed higher oil mobility potential. Finally, core flooding tests at reservoir conditions showed a 300 percent enhancement in injection rate and a 50% improvement in core permeability after damage. The immobilization of the enzyme with the nanoparticle has been developed successfully for other applications in bioremediation, farming, and other industries, but the novelty of this research demonstrates the application of nanobiocatalysts in drilling fluids for the first time. This innovative clean-up fluid enhances the enzymatic activity and removes primary and secondary formation damage associated with drilling fluid filter cake.",0,0,1
Drilling Fluids,Formation Damage,"Kalatehno, Javad Mahdavi; Khamehchi, Ehsan",A novel packer fluid for completing HP/HT oil and gas wells,Completion fluid; Heavy brine; Formation damage; Phosphate brines,,"Today, many oil and gas resources in onshore and offshore environments worldwide are often in hightemperature, high-pressure and low-permeability reservoirs, creating challenges for well completion in these reservoirs. Thus, designing a completion fluid which is solid-free and has high-density and high-thermal resistance is essential in the oil industry. Parameters that make it more challenging to choose a completion fluid include: cost-effectiveness, availability of components, low corrosion rate, environmental compatibility, fluid stability, compatibility with the reservoir, low crystallization point, high density, suitable pH, and low damage potential. The primary purpose of this study is to overcome these parameters. In this study, a novel packer fluid for well completion was developed using potassium hydroxide and phosphoric acid for the first time. The novel packer fluid is a brine that can act as a high-density, solid-free fluid during drilling and completion in HT/HP reservoirs. This brine is prepared using an experimental design in three different densities and is compared with potassium formate and calcium bromide. Potassium formate is prepared from the reaction of potassium hydroxide and formic acid, while potassium hydroxide is cheaper and more available compared to other brines. The results show that novel brine is stable at changes in density and pH under surface and bottom-hole conditions. The concentration of toxic elements in the novel brine indicates that this brine is environmentally compatible. The corrosion rate of L80 steel after contact with novel brine at temperatures above 180 and 300 degrees F is low and very close to traditional completion fluid. In addition, return permeability of the carbonate core can reach 88.38% of the initial permeability. The novel brine is compatible with formation water, and has excellent performance against clay swelling. Furthermore, results of the wettability test show that novel brine causes changes in the wettability of carbonate core from oil-wet to water-wet conditions.",0,0,2
Drilling Fluids,Formation Damage,"Bellabiod, Sofiane; Deghmoum, Abdelhakim; Aris, Abdelkader; Karacali, Ozgur",An insight to formation damage evolution,Formation damage time evolution; Pressure transient analysis; Well test,,"Formation damage can significantly defer hydrocarbon production. Formation damage is one of the key parameters used to evaluate the quality of various operations during the life of a well. The evolution of formation damage over time is rarely studied. This paper presents the pressure transient analysis (PTA) used to derive a correlation between skin factor increase and the length of time for which a well was left exposed to drilling fluid. Multiple field examples are analyzed and modeled comparatively to evaluate the magnitude of the time-lapse formation damage. A quantitative relationship between the increase in mechanical skin as a function of exposure to drilling mud is constructed by a polynomial fitting. This gives us an insight on the how the well skin increases with exposure to drilling mud. Several mathematical models have been developed to model formation damage mechanisms. However, it is cumbersome to isolate and compute the individual mechanisms contributing to observed damage. Formation damage results from a combination of the pore size distribution, fines migration, fluid compatibility problems, wettability, presence of inorganic salts deposition, insufficient well cleanup, organic substance deposition, multiphase flow effects, etc. The proposed approach uses the skin factor derived from pressure transient analysis (PTA) to track the time-lapse evolution of formation damage during exposure time to mud, from drilling to production. The methodology has been applied to various reservoir rocks to quantify the impact for a specific rock type. Results from pressure transient tests conducted immediately after drilling, casing, and perforating are compared with production tests performed multiple years after drilling confirm that there is a mathematical relation between the formation damage, type of drilling and completion fluid, formation rock type, and exposure time to such fluids. The formation damage increase is more severe for longer duration of exposure, and also more severe for higher formation permeability.",0,0,2
Drilling Fluids,Degrees C,"Deng, Chunping; Du, Guoyong; Li, Xingchun; Xi, Junnan; Lin, Chen",Effect of high temperature and high pressure on the biodegradability and biotoxicity of typical additives in drilling fluid,Drilling fluid additives; HTHP; Biodegradability; Biotoxicity; Structure,XANTHAN GUM; PHYSICOCHEMICAL PROPERTIES; XANTHOMONAS-CAMPESTRIS; OIL; DEGRADATION; ASPHALT; PROTEIN; MUD; XPS,"Under the high-temperature and high-pressure (HTHP) conditions in the ground, the environmental features of drilling fluid additives may change to some extent. But the relevant information of the influence of HTHP environment on drilling fluid additives is very limited. Four typical additives, namely, sulfonate asphalt (SEB), potassium polyacrylamide (KPAM), potassium humate (KHm) and xanthan gum (XG), were treated for 40 min under two typical bottom hole conditions of 7 MPa, 90 degrees C and 11 MPa, 120 degrees C. The biodegradability and biotoxicity of these additives before and after treatments were determined. The structures of the four additives were also analyzed by Fourier transform infrared spectroscopy (FT-IR), X-ray photoelectron spectroscopy (XPS), nuclear magnetic resonance spectroscopy (NMR), thermogravimetric analysis (TGA) and gas chromatography-mass spectrometry (GC-MS). The results revealed no remarkable difference in biotoxicity and biodegradability of each sample between the two conditions. SEB became nontoxic from microtoxic after being treated with HTHP, with the value of EC50 notably increased from 2463 to 33,398 mg L-1, which might be due to the relative increase of light components observed by GC-MS. Original XG was nontoxic (EC50 = 21,000 mg L-1) and easily biodegraded (BC ratio = 0.469), but HTHP treatments increased the toxicity (EC50 = 5701 mg L-1) and decreased the biodegradability (BC ratio = 0.02), which could be attributed to the reduce of the C-OH/C-O-C bonds observed by FT-IR and XPS spectra. Both KPAM and KHm were midtoxic and had low degradability, and only KPAM became highly toxic (EC50 < 100 mg L-1) after HTHP treatments, which might result from the slight increase in the relative peak area of the amide group. The results could provide preliminary insights into the mechanism of how the HTHP conditions impacted the pollution properties of the additives and pave a new and facile route for the screening of environmentally friendly additives, and consequently mitigate the pollution from the source in the oil and gas exploitation industry.",0,0,1
Drilling Fluids,Degrees C,"Alkalbani, Alhaitham M.; Chala, Girma T.; Myint, Myo Tay Zar",Experimental investigation of rheological properties of water-base mud with zinc oxide nanoparticles using response surface methodology,Nanoparticles; Zinc oxide; Downhole condition; Viscosity; Yield point; Gel strength,OIL,"Special and advanced techniques at drilling and production operations are used to drill and produce hydrocarbons from different eccentric reservoirs such as deep-water reservoirs, shale gas, and shale oil necessitates. However, these advanced techniques are considered to be costly and affecting the environment. Therefore, nanotechnology has been implemented in the drilling fluids to improve the rheological properties, hydrogen concentration, and filtration rate. This study is, therefore, aimed at evaluating the properties of zinc oxide nanoparticles and their previous implementation in drilling fluids, examining the rheological properties of water base mud from atmospheric temperature to downhole condition (90 degrees C). The experiment was designed to investigate the effect of nanoparticles concentration and temperature variation on the rheological properties of water-based mud using response surface methodology. A rotational viscometer was used to measure viscosity, yield point and gel strength. Moreover, a Consistometer was used to heat the fluid sample to different temperatures reaching up to downhole condition (90 degrees C). It was observed experimentally that addition of zinc oxide nanoparticles impressively improved the rheological properties of water-base mud by 50% for viscosity and gel strength, and 80% for yield point. It also allowed them to maintain their quality at all temperatures. Furthermore, addition of higher concentrations of zinc oxide nanoparticles of more than 1 wt% (6 g) at low temperatures (below 40 degrees C) gave the highest and most effective results of the rheological properties.",0,0,1
Drilling Fluids,Degrees C,"Duarte, A. C. R.; Ribeiro, P. R.; Kim, N. R.; Mendes, J. R. P.; Policarpo, N. A.; Vianna, A. M.",An experimental study of gas solubility in glycerin based drilling fluid applied to well control,Solubility; Drilling; Well control; Drilling fluids; Aqueous glycerol solution,METHANE,"The drilling fluid is the primary barrier element against a kick. In the path of drilling fluids evolution, syntheticbased drilling fluid (SBDF) is commonly used on offshore rigs due to its benefits to the high level of drilling complexity, especially at deep and ultra-deep-water scenarios. However, when formation gas dissolves in the mud due to high pressure and high temperature, the complexity of kick detection increases significantly. Furthermore, environmental concerns raised a red flag on SBDF usage due to potential impacts on the marine environment, with most governmental agencies around the world passing very strict regulations. Considering both aspects - safety, and environmental concerns - glycerin emerges as a potential candidate to perform a key role as a base drilling fluid (GBDF). At first, a GBDF has the potential to behave as an SBDF due to its benefits, such as lubricity and shale stabilization, and, at the same time, it has the same characteristics of water-based drilling fluid (WBDF) with very low methane solubility, the major component of natural gas. Additionally, GBDF is considered to be more environmentally friendly than SBDF. In this work, we first analyzed the PVT properties and rheology of three different molar composition glycerin-based drilling fluids: 100% glycerin, 5050% glycerin/brine, and 40-60% glycerin/brine. Then, we performed the PVT properties analysis of methane (10-50% molar mass) mixed with each of these GBDF mentioned. In a systematic constant composition expansion through a visual high-resolution PVT cell under temperature and pressure range conditions of 20-80 degrees C and 0-55 MPa, respectively, and rheology characterization. The GBDF exhibited interesting results for density and rheology parameters similar to an SDBF and no methane solubility. Finally, mathematical correlations are proposed and applied to illustrate a pit-gain calculation comparing to an n-paraffin-based drilling fluid.",0,0,3
Drilling Fluids,Degrees C,"Ettehadi, Ali; Ulker, Ceylan; Altun, Gursat",Nonlinearity in large amplitude oscillatory shear of drilling fluid: A comparative study on the oil and water base muds behavior,Drilling fluid; Nonlinear viscoelasticity; Large amplitude oscillatory shear (LAOS); Shear mechanism; Structural stability,VISCOELASTIC PROPERTIES; PRESSURE-DROP; LAOS BEHAVIOR; MODEL; RHEOLOGY; STRESS; TRANSITION; VISCOSITY; EQUATION,"A viscoelastic material exhibits both fluid (viscous) and solid (elastic) like properties simultaneously. The rheological behavior of drilling fluids is customarily measured under the assumption of pure viscous flow, yet they exhibit both viscous and elastic characteristics when subjected to deformation. Some imperative properties of drilling fluids such as gel strength, yield stress, and sag tendency at near-zero shear rate region are categorically under the influence of viscoelastic behavior and have not yet been completely understood due to the lack of appropriate measurement methods. Characterizing the complete rheological profile of material requires measuring linear and nonlinear viscoelastic responses at a wide range of stress/strain levels. The viscoelastic nonlinearity can be characterized under Large Amplitude Oscillatory Shear (LAOS) tests. This study presents a large amplitude oscillatory shear rheology investigation of two water-base (Lignosulfonate and KCl/polymer) and two oil-base (low and high temperature) drilling fluids each in three states; unweighted, weighted, and weighted-contaminated. The viscoelastic nonlinearities of four fluid samples were investigated experimentally as a function of strain amplitude and strain-rate space at different temperatures. The results were described using Lissajous-Bowditch (L-B) plots and local nonlinear viscoelastic dynamic moduli through an oscillatory shear cycle. Structural stability of fluid samples was also studied using the creep-recovery test. The nonlinear viscoelastic behavior of drilling fluids was comprehensively compared and distinguished to understand their nonlinear shear mechanism. As a result of the creep-recovery test at 150 degrees C, high-temperature oil base mud provided higher thermostructural stability and zero shear viscosity than those of Lignosulfonate, KCl/polymer, and low-temperature oil-base muds. While the elastic nonlinearity was found to be strain/strain rate softening, the nonlinear viscous character was recorded as shear/shear rate thinning at large strain rates for all drilling fluid systems. Quite a different shear mechanism was detected at low and moderate strain rates. Shear rate thinning was found to be the dominant mechanism for all fluids except Lignosulfonate mud samples that demonstrated shearthickening behavior at moderate strain rates at 25 degrees C. At high temperatures (100 degrees C and 150 degrees C), shear rate thickening followed by shear rate thinning behavior was governing mechanism under the low and moderate strain rates in all mud samples except KCl/polymer muds. An inverse behavior (shear rate thinning followed by shear rate thickening) was observed through low and moderate strain rates in KCl/polymer muds at 100 degrees C and 150 degrees C. Therefore, as revealed from the LAOS test results, shear rate thickening behavior at low to moderate strain rates is in contradiction of the commonly known shear thinning behavior for a drilling fluid undergoing viscous deformation. This finding explains the facts underlying some important properties of drilling fluids such as gel structure formation, hole cleaning ability, and sag tendency.",0,0,3
Drilling Fluids,Particle Size,"de Souza Fritoli, Giovani; De Lai, Fernando Cesar; de Mello Junqueira, Silvio Luiz",Effect of LCM and polymeric additives on mudcake and filtrate rheology parameters,Lost circulation; LCM; Filtration; CaCO3; Mudcake,CAKE; CIRCULATION; OIL,"In oil and gas well drilling operations, lost circulation is characterized by the invasion of drilling fluid into permeable formations. Besides generating additional costs to the process, the loss of circulation can damage producer formations and, if uncorrected, reduce pressure inside the well, inducing kicks. One of the alternatives for combating this problem is the addition of lost circulation materials (LCM) to the drilling fluid. The added LCMs will accumulate and form a filter cake on the interface between the well and the porous formation, thus reducing the volume of fluid lost. In the present work, the cake formation process resulting from the deposition of particulate material on a porous substrate is studied experimentally. The objective is evaluating the influence of type and concentration of two polymeric additives and four types of LCM on the formation of the filter cake. The experiments were carried out in an API filter press at pressures of 100 psi, using solutions of carboxymethylcellulose (CMC) and xanthan gum (XG) in water at 1.05 and 2.10 lbm/bbl. The particle size used as loss of circulation material comprises two values (2 - 44 and 44 - 106 mu m) of calcium carbonate (CaCO3), glass microspheres (180 - 300 mu m), and plastic particles (250 - 420 mu m). The efficiency of the fluid-LCM combination in combating lost circulation is evaluated based on the filtrate volume, thickness, dry and wet cake masses, and filtrate flow curves. Results show that the increase of the LCM concentration and the use of the calcium carbonate particulate with smaller particles favor the filtrate volume reduction. Also, the filtrates exhibit non-Newtonian behavior with reduced values of viscosity due to the retention of polymeric chains by the formed filter cake. Such phenomenon is most significantly detected when calcium carbonate is used.",0,0,0
Drilling Fluids,Particle Size,"Andrade, GabrielM P.; Oechsler, Bruno F.; Coelho, Josiane S. C.; Fagundes, Flavia M.; Arouca, Fabio O.; Damasceno, Joao J. R.; Scheid, Claudia M.; Calcada, Luis A.",Evaluation of characteristic diameter on barite settling in drilling fluids by Monte Carlo method,Barite settling; Drilling fluids; Characteristic particle size; Optimization; Monte Carlo,,"Several researchers have discussed the settling behaviour of particulate materials because of the challenges and applications in different engineering fields. Particularly, settling of such weighting agents as barite, commonly added to drilling fluids, can cause problems in oil production, either on drilling processes or in production. Typically, sedimentation models consider a single value of particle size, which in this work, we refer to as characteristic diameter. This particle size can be chosen by statistical methods, such as the Sauter mean diameter, or it can be extracted directly from particle size distribution such as its mean, median, or mode. There are some conventions by how to choose the characteristic diameter; however, discarding the whole size variability from the particle size distribution is unwise. Regarding the literature, only a few works have, to the best of our knowledge, discussed the effects of this choice on the models' performance. This work then presents a new perspective on evaluating the uncertainty of the particle size distribution and choosing the best characteristic diameter, using a novel method based on Monte Carlo simulations. To evaluate the method, research team chose a barite settling model (recently published) for drilling fluids. Experimental data of barite concentration in batch settling test supported the Monte Carlo simulations. Five characteristic diameters were evaluated. Results showed different column heights have different characteristic diameters which differed from classical values such as Sauter's diameter by up to 200%, producing different model output variables. New particle size also affected estimation of remaining parameters and changed predicted properties such as media permeability by up to 90%. This work opens a discussion on how well-represented a particle size distribution is when researchers choose only a characteristic diameter is chosen without evaluating the whole distribution.",0,0,0
Drilling Fluids,Particle Size,"Kadyrov, Rail; Nurgaliev, Danis; Saenger, Erik H.; Balcewicz, Martin; Minebaev, Rezit; Statsenko, Evgeny; Glukhov, Mikhail; Nizamova, Aigul; Galiullin, Bulat",Digital rock physics: Defining the reservoir properties on drill cuttings,Cuttings; Core; Carbonates; Pore structure; Digital rock physics,TRANSPORT; CFD; PARAMETERS; PROGRAM; OIL,"Well drilling with core extraction is one of the most expensive procedures in the oil industry. The potential alternative, which may open opportunities for cost-efficient acquisition of petrophysical data, can be an approach based on digital analysis of drill cuttings. The main purpose of this research was to evaluate the possibility of using digital cuttings analysis and rock physics for reservoir properties evaluation. The carbonate samples of core and cuttings were simultaneously collected from the same intervals during the drilling of deviated wells in the Carboniferous reservoir of the oil deposit in the Republic of Tatarstan, Russia. Based on the core analysis using the optical study of thin sections and XRD, we investigated sedimentological and mineralogical features and classified all lithotypes of well intervals. The standard samples were produced from all defined facies and their reservoir properties were studied in routine tests. The largest cuttings from each well interval were separated and their structures were compared using mu CT with core subsamples of the same intervals. We assessed the changes of cuttings structure occurring in the drilling process, which include the colmatation of the pore space with drilling fluid and disintegrated rock particles and the formation of secondary fractures. Detailed analysis of cuttings from one well interval consisting of the border between the facies of high porous grainstones with packstones and dense micrite limestones demonstrated that high porous varieties were eroded in the drilling process. The analysis of chemical composition using XRF-mapping, XRD and SEM with EDS showed that most of the cuttings were constituted by disintegrated rock particles or form elements (e.g. separate fusulinids) cemented by drilling mud. However, more durable cuttings from dense micrite limestones facies were generally retained their dominant calcite composition and original rock structure, with only secondary fractures. Finally, we analyzed pore space properties and performed digital simulations of wave propagation velocities to compare the characteristics of these cuttings and core subsamples from this lithotype, scanned in the same mu CT settings. The results demonstrate close characteristics of porosity 0.08-0.6%, dominant pore sizes 1-60 mu m and velocities Vp = 6130-6240 m/s, Vs = 3180-3230 m/s. However, the comparison of obtained values with measured on standard samples shows a significant difference, which is caused by deviation from REV. The potential use of cuttings for assessing reservoir and petrophysical properties can be possible in case of provision with the factors of cuttings structure alteration, representativity of samples, as well as optimization for these purposes of the drilling process with cuttings selection.",0,0,1
Drilling Fluids,Particle Size,"Epelle, Emmanuel, I; Obande, Winifred; Okolie, Jude A.; Wilberforce, Tabbi; Gerogiorgis, Dimitrios, I",CFD modelling and simulation of drill cuttings transport efficiency in annular bends: Effect of particle size polydispersity,Polydispersity; Cuttings transport; Discrete phase model; Rosin-Rammler,FLOW; PREDICTION; ROTATION; OIL,"This study analyses the impact of particle polydispersity using the Eulerian-Eulerian (EE) and LagrangianEulerian (LE) modelling approaches in the context of wellbore cleaning operations in the drilling industry. Spherical particles of sizes 0.5 mm, 0.75 mm and 1 mm are considered, whereas a Power Law rheological model is used for the fluid phase description. The EE approach implemented herein applies the Kinetic Theory of Granular Flow (KTGF) in ANSYS Fluent (R) and accounts for the particle size differences by representing them as different phases within the computational domain. With the LE approach, we employ the Dense Discrete Phase Model (DDPM) and capture this difference with the aid of a size distribution model (the Rosin-Rammler model). The findings of our computational experiments show considerable differences in key variables (the pressure drop, and particle deposition tendencies) between monodispersed and polydispersed transport scenarios.",0,0,3
Drilling Fluids,Cuttings,"Kadyrov, Rail; Nurgaliev, Danis; Saenger, Erik H.; Balcewicz, Martin; Minebaev, Rezit; Statsenko, Evgeny; Glukhov, Mikhail; Nizamova, Aigul; Galiullin, Bulat",Digital rock physics: Defining the reservoir properties on drill cuttings,Cuttings; Core; Carbonates; Pore structure; Digital rock physics,TRANSPORT; CFD; PARAMETERS; PROGRAM; OIL,"Well drilling with core extraction is one of the most expensive procedures in the oil industry. The potential alternative, which may open opportunities for cost-efficient acquisition of petrophysical data, can be an approach based on digital analysis of drill cuttings. The main purpose of this research was to evaluate the possibility of using digital cuttings analysis and rock physics for reservoir properties evaluation. The carbonate samples of core and cuttings were simultaneously collected from the same intervals during the drilling of deviated wells in the Carboniferous reservoir of the oil deposit in the Republic of Tatarstan, Russia. Based on the core analysis using the optical study of thin sections and XRD, we investigated sedimentological and mineralogical features and classified all lithotypes of well intervals. The standard samples were produced from all defined facies and their reservoir properties were studied in routine tests. The largest cuttings from each well interval were separated and their structures were compared using mu CT with core subsamples of the same intervals. We assessed the changes of cuttings structure occurring in the drilling process, which include the colmatation of the pore space with drilling fluid and disintegrated rock particles and the formation of secondary fractures. Detailed analysis of cuttings from one well interval consisting of the border between the facies of high porous grainstones with packstones and dense micrite limestones demonstrated that high porous varieties were eroded in the drilling process. The analysis of chemical composition using XRF-mapping, XRD and SEM with EDS showed that most of the cuttings were constituted by disintegrated rock particles or form elements (e.g. separate fusulinids) cemented by drilling mud. However, more durable cuttings from dense micrite limestones facies were generally retained their dominant calcite composition and original rock structure, with only secondary fractures. Finally, we analyzed pore space properties and performed digital simulations of wave propagation velocities to compare the characteristics of these cuttings and core subsamples from this lithotype, scanned in the same mu CT settings. The results demonstrate close characteristics of porosity 0.08-0.6%, dominant pore sizes 1-60 mu m and velocities Vp = 6130-6240 m/s, Vs = 3180-3230 m/s. However, the comparison of obtained values with measured on standard samples shows a significant difference, which is caused by deviation from REV. The potential use of cuttings for assessing reservoir and petrophysical properties can be possible in case of provision with the factors of cuttings structure alteration, representativity of samples, as well as optimization for these purposes of the drilling process with cuttings selection.",0,0,1
Drilling Fluids,Cuttings,"Issoufou, Mamane Kondo; Song, Xianzhi; Zhu, Zhaopeng; Xu, Zhengming; Yu, Buwen; Jing, Silin; Duan, Shiming",Predicting cuttings settling velocity in drilling muds and in rising-bubbles-containing muds,Cuttings settling behavior; Rising-bubbles-containing muds; Micro interaction of particle and bubbles pi theorem; New model of settling velocity,DRAG COEFFICIENT; PARTICLES; BEHAVIOR; MODEL,"The main objectives of this paper are to study the cuttings settling velocity in drilling muds and rising-bubbles-containing muds and to develop a prediction model suitable for both cases. For this purpose, experiments were carried out by using water, glycerine and Carboxymethyl Cellulose (CMC) fluids with different viscosity as drilling muds and aluminum particles as cuttings. Air was used as the gas phase. To ensure the reliability of the tests, the work has been divided into two parts. In the first part, the goodness of the obtained experimental results from gas-free liquids was assessed with the standard drag coefficient curve and the Cheng's equation. In the second part, the above-mentioned results were compared with those obtained from gas-liquid mixtures under various gas void fraction conditions. Through this work, in addition to the settling velocity calculation procedure of Walker and Mayes, a newly developed model is suggested for predicting cuttings settling velocity applicable for the solid-liquid two-phase flow and solid-liquid-gas three-phase flow. Furthermore, it was found that the bubble-particle collision in viscous fluids resulted in a decrease in cuttings settling velocity by 20%-50% while the combined effect of the bubble-particle interaction and mixture viscosity and density variation due to the gas phase could increase cuttings settling velocity by two or three times compared with that in gas-free drilling muds. The results also showed that only in water (non-viscous fluid) with a gas volumetric smaller than 7.5% can considerably help to maintain solid particles in suspension, and for more than 7.5% there is increased in settling velocity compare to its value in gas-free water before mitigating at around 20% void fractions and more. The results of this study could provide to the drilling operators additional information on the cuttings slip velocity estimation during gas influx or underbalanced conditions.",0,0,2
Drilling Fluids,Cuttings,"Tan, Tianyi; Zhang, Hui",A risk prediction method of pipe sticking accidents due to wellbore uncleanness for long horizontal section wells,Wellbore uncleanness; Bulldozer effect; Pipe sticking prediction; Long horizontal section well; Torque and drag,CUTTINGS TRANSPORT; FLUID; MODEL; FLOW; CLEANOUT; OIL,"The prediction of pipe sticking accidents due to wellbore uncleanness is significant for safe drilling, while existing qualitative prediction methods result in inaccuracy and lateness. To cover the shortages, a novel quantitative pipe sticking prediction method is established to achieve pipe sticking prediction early in drilling preparatory stage. First, the additional axial forces and torques on the drill string exerted by accumulated cuttings are calculated in tripping out, tripping in, back reaming and reaming processes based on granular mechanics. Second, the torque and drag model is modified considering additional axial forces and torques to calculate the hook load and the top drive torque. Finally, the pipe sticking prediction is conducted according to the critical hook load and the critical top drive torque in a specific drilling process. A case study including comparison with the classical model and sensitivity analysis is conducted. Under the given condition, pipe sticking risk is predicted with the new mothed by anticipating hook loads (5524.67 and -667.71 kN) and top drive torques (60.87 and 66.36 kN m) exceeding the critical values. The hook load and the top drive torque change exponentially with the travelling distance. In tripping out and back reaming processes from 4350 to 4250 m, the hook load and the top drive torque respectively increase for 1894.36 kN and 53.99 kN m. In tripping in and reaming processes from 3450 to 3550 m, the hook load decreases for 29925.66 kN and the top drive torque increases for 157.3 kN m. According to the sensitivity analysis, low frictional coefficients, initial cutting volume fractions, torque and drag frictional factors and high junk slot ratios are required to reduce the risk of pipe sticking. This study provides a timely and quantitative prediction method for pipe sticking accidents due to wellbore uncleanness in long horizontal drilling.",0,0,3
Drilling Fluids,Cuttings,"Epelle, Emmanuel, I; Obande, Winifred; Okolie, Jude A.; Wilberforce, Tabbi; Gerogiorgis, Dimitrios, I",CFD modelling and simulation of drill cuttings transport efficiency in annular bends: Effect of particle size polydispersity,Polydispersity; Cuttings transport; Discrete phase model; Rosin-Rammler,FLOW; PREDICTION; ROTATION; OIL,"This study analyses the impact of particle polydispersity using the Eulerian-Eulerian (EE) and LagrangianEulerian (LE) modelling approaches in the context of wellbore cleaning operations in the drilling industry. Spherical particles of sizes 0.5 mm, 0.75 mm and 1 mm are considered, whereas a Power Law rheological model is used for the fluid phase description. The EE approach implemented herein applies the Kinetic Theory of Granular Flow (KTGF) in ANSYS Fluent (R) and accounts for the particle size differences by representing them as different phases within the computational domain. With the LE approach, we employ the Dense Discrete Phase Model (DDPM) and capture this difference with the aid of a size distribution model (the Rosin-Rammler model). The findings of our computational experiments show considerable differences in key variables (the pressure drop, and particle deposition tendencies) between monodispersed and polydispersed transport scenarios.",0,0,3
Drilling Fluids,Diameter,"Andrade, GabrielM P.; Oechsler, Bruno F.; Coelho, Josiane S. C.; Fagundes, Flavia M.; Arouca, Fabio O.; Damasceno, Joao J. R.; Scheid, Claudia M.; Calcada, Luis A.",Evaluation of characteristic diameter on barite settling in drilling fluids by Monte Carlo method,Barite settling; Drilling fluids; Characteristic particle size; Optimization; Monte Carlo,,"Several researchers have discussed the settling behaviour of particulate materials because of the challenges and applications in different engineering fields. Particularly, settling of such weighting agents as barite, commonly added to drilling fluids, can cause problems in oil production, either on drilling processes or in production. Typically, sedimentation models consider a single value of particle size, which in this work, we refer to as characteristic diameter. This particle size can be chosen by statistical methods, such as the Sauter mean diameter, or it can be extracted directly from particle size distribution such as its mean, median, or mode. There are some conventions by how to choose the characteristic diameter; however, discarding the whole size variability from the particle size distribution is unwise. Regarding the literature, only a few works have, to the best of our knowledge, discussed the effects of this choice on the models' performance. This work then presents a new perspective on evaluating the uncertainty of the particle size distribution and choosing the best characteristic diameter, using a novel method based on Monte Carlo simulations. To evaluate the method, research team chose a barite settling model (recently published) for drilling fluids. Experimental data of barite concentration in batch settling test supported the Monte Carlo simulations. Five characteristic diameters were evaluated. Results showed different column heights have different characteristic diameters which differed from classical values such as Sauter's diameter by up to 200%, producing different model output variables. New particle size also affected estimation of remaining parameters and changed predicted properties such as media permeability by up to 90%. This work opens a discussion on how well-represented a particle size distribution is when researchers choose only a characteristic diameter is chosen without evaluating the whole distribution.",0,0,0
Drilling Fluids,Diameter,"Krishna, Shwetank; Ridha, Syahrir; Campbell, Scott; Ilyas, Suhaib Umer; Dzulkarnain, Iskandar; Abdurrahman, Muslim",Experimental evaluation of surge/swab pressure in varying annular eccentricities using non-Newtonian fluid under Couette-Poiseuille flow for drilling applications,Concentric and eccentric annulus; Couette-Poiseuille (CP) flow; Drilling; Non-Newtonian fluid; Surge; swab pressure gradient,SWAB PRESSURES; FOOD PROCESSES; MASS-TRANSFER; MODEL; EQUATIONS,"Global energy demand is rapidly increasing at a rate of 8% between 2004 and 2019, and conventional energy sources are unable to meet this requirement. Therefore, the oil and gas energy industry is working continuously to produce unconventional energy sources such as deepwater oil and gas reservoirs, gas hydrates, and geothermal energy using drilling operations. In the drilled borehole, the stability and integrity issues are encountered that are related to pressure differential generated by the Couette-Poiseuille (CP) fluid flow phenomenon occurred during pipe tripping operation. There is a lack of experimental data to comprehend the impact of CP flow on pressure differential using non-Newtonian fluid in concentric and eccentric annuli, especially in petroleum exploration. Hence, an experimental investigation is performed to replicate the tripping operations during oil and gas well drilling. The investigation provides an extensive understanding of the physical and mechanical characteristics of non-Newtonian fluids under CP flow at varying inner pipe tripping speeds (0.030481-0.21336 m/s), rheological properties, and geometrical dimensions. The results indicate that surge/ swab pressure gradient tends to decrease with increasing eccentricity (epsilon) and increase with increasing diameter ratio (delta) and pipe tripping speed (Vp). Furthermore, the pressure differential rate is considerably high at low tripping speed but reduces at high pipe tripping speed due to the shear-thinning behavior of YPL fluid. The study also reveals that gel strength increases the surge/swab pressure gradient by approximately 18%. A multi-variable correlation is developed to predict surge/swab pressure gradient, exhibiting an excellent agreement with experimental data and existing theoretical models.",0,0,1
Drilling Fluids,Diameter,"Gao, Reyu; Li, Jun; Yang, Hongwei; Lian, Wei; Wang, Wei",A novel approach to investigating the mechanism of permeability-induced borehole breathing in deepwater shallow formations,Borehole breathing; Deep-water shallow formation; The mechanism of permeability-induced; Mud loss,BEHAVIOR; STRESS,"Due to the uniqueness of deep-water shallow formations, there is no fracture system around the wellbore when borehole breathing is observed in this part of the formation. Therefore, the inducing mechanism of the opening/closing of the fracture network cannot reasonably explain this type of borehole breathing. In this study, a new mechanism of permeability-induced is proposed to explain borehole breathing, based on the fact that there is no fracture system around the well and the formation has the characteristics of high permeability and porosity. By using the stress and seepage coupling method in the porous elastic medium, a new model is established to simulate and describe permeability-induced borehole breathing. Through comparison with actual cases, this model can effectively simulate the typical characteristics of fluid loss-flow back in borehole breathing. This study also analyzed the influence of factors such as formation parameters and mud rheological parameters on the borehole breathing caused by permeability. According to the results of the study, the use of a smaller diameter wellbore and agents that can adjust related parameters (such as loss-reducing circulating material) can effectively inhibit wellbore breathing while drilling.",0,0,2
Drilling Fluids,Diameter,"Yang, Mou; Luo, Hao; Xie, Rongxuan; Wu, Pengcheng; Yang, Mingzheng; Yang, Lvchao; Xue, Hu",Estimating and optimizing wellbore pressure during primary cementing in low pressure and leakage formations,Circulating pressure; Cementing operation; Low pressure and leakage formations; Mathematical model; Computational fluid dynamics,NON-NEWTONIAN FLUIDS; POWER-LAW FLUID; HERSCHEL-BULKLEY; ECCENTRIC ANNULI; DRILLING-FLUIDS; TURBULENT-FLOW; LAMINAR; CIRCULATION; TRANSITION; BEHAVIOR,"In most realistic situations, casing eccentricity and various fluids injected during primary cementing lead to a significant difference in fluid flow and circulating pressure, compared with a single fluid flowing in the concentric annulus. Ignoring the effect of eccentricity and fluid rheological model on the wellbore circulating pressure results in an inaccurate evaluation and leads to formation leakage, especially for low pressure and leakage formations. To overcome this challenge, firstly, rheological models of various fluids were analyzed using experimental data, including drilling fluid, spacer, and cement slurry. Secondly, the modified correlations of frictional pressure losses for Herschel-Bulkley and Power Law fluids in the eccentric annulus were developed, using the simulation data of computational fluid dynamics software (CFD) and considering the effects of flow behavior index, pipe diameter ratio, and casing eccentricity on the frictional pressure losses. Finally, based on the developed mathematical models, the optimal method of primary cementing and evaluation results were presented, analyzed, and tested in the field with great success. The results demonstrated that the drilling fluid and spacer fluid had the highest goodness of fit for the Herschel-Bulkley model, and the cementing slurry was suitable for the Power Law model. The ratio coefficient of pressure loss in the eccentric to concentric annulus decreased with a decrease of hole size and an increase of casing eccentricity. A 50 percent reduction in frictional pressure loss was evaluated when the casing lies on the borehole wall. Comparing the calculations of the developed correlation with the published correlation in the literature reveals a more accurate evaluation of friction pressure losses in the analyzed case. Combined with the realistic situation of a test well, the density, flow rate, and returning depth of the lead cement slurry were recommended as 1.5 g/cm(3), 0.5 m(3)/min and 4100 m, respectively, according to the leakage pressure of 65.6 MPa that was calculated by the developed mathematical model. Most importantly, the developed method in this paper can accurately predict the variation characteristics of wellbore pressure during the primary cementing process and provide effective guidance in managing downhole pressure in low pressure and leakage formations by real-time adjustment of the most effective and controllable operation parameters.",0,0,3
Drilling Fluids,Rheological Parameters,"de Souza Fritoli, Giovani; De Lai, Fernando Cesar; de Mello Junqueira, Silvio Luiz",Effect of LCM and polymeric additives on mudcake and filtrate rheology parameters,Lost circulation; LCM; Filtration; CaCO3; Mudcake,CAKE; CIRCULATION; OIL,"In oil and gas well drilling operations, lost circulation is characterized by the invasion of drilling fluid into permeable formations. Besides generating additional costs to the process, the loss of circulation can damage producer formations and, if uncorrected, reduce pressure inside the well, inducing kicks. One of the alternatives for combating this problem is the addition of lost circulation materials (LCM) to the drilling fluid. The added LCMs will accumulate and form a filter cake on the interface between the well and the porous formation, thus reducing the volume of fluid lost. In the present work, the cake formation process resulting from the deposition of particulate material on a porous substrate is studied experimentally. The objective is evaluating the influence of type and concentration of two polymeric additives and four types of LCM on the formation of the filter cake. The experiments were carried out in an API filter press at pressures of 100 psi, using solutions of carboxymethylcellulose (CMC) and xanthan gum (XG) in water at 1.05 and 2.10 lbm/bbl. The particle size used as loss of circulation material comprises two values (2 - 44 and 44 - 106 mu m) of calcium carbonate (CaCO3), glass microspheres (180 - 300 mu m), and plastic particles (250 - 420 mu m). The efficiency of the fluid-LCM combination in combating lost circulation is evaluated based on the filtrate volume, thickness, dry and wet cake masses, and filtrate flow curves. Results show that the increase of the LCM concentration and the use of the calcium carbonate particulate with smaller particles favor the filtrate volume reduction. Also, the filtrates exhibit non-Newtonian behavior with reduced values of viscosity due to the retention of polymeric chains by the formed filter cake. Such phenomenon is most significantly detected when calcium carbonate is used.",0,0,0
Drilling Fluids,Rheological Parameters,"Gao, Reyu; Li, Jun; Yang, Hongwei; Lian, Wei; Wang, Wei",A novel approach to investigating the mechanism of permeability-induced borehole breathing in deepwater shallow formations,Borehole breathing; Deep-water shallow formation; The mechanism of permeability-induced; Mud loss,BEHAVIOR; STRESS,"Due to the uniqueness of deep-water shallow formations, there is no fracture system around the wellbore when borehole breathing is observed in this part of the formation. Therefore, the inducing mechanism of the opening/closing of the fracture network cannot reasonably explain this type of borehole breathing. In this study, a new mechanism of permeability-induced is proposed to explain borehole breathing, based on the fact that there is no fracture system around the well and the formation has the characteristics of high permeability and porosity. By using the stress and seepage coupling method in the porous elastic medium, a new model is established to simulate and describe permeability-induced borehole breathing. Through comparison with actual cases, this model can effectively simulate the typical characteristics of fluid loss-flow back in borehole breathing. This study also analyzed the influence of factors such as formation parameters and mud rheological parameters on the borehole breathing caused by permeability. According to the results of the study, the use of a smaller diameter wellbore and agents that can adjust related parameters (such as loss-reducing circulating material) can effectively inhibit wellbore breathing while drilling.",0,0,2
Drilling Fluids,Rheological Parameters,"Duarte, A. C. R.; Ribeiro, P. R.; Kim, N. R.; Mendes, J. R. P.; Policarpo, N. A.; Vianna, A. M.",An experimental study of gas solubility in glycerin based drilling fluid applied to well control,Solubility; Drilling; Well control; Drilling fluids; Aqueous glycerol solution,METHANE,"The drilling fluid is the primary barrier element against a kick. In the path of drilling fluids evolution, syntheticbased drilling fluid (SBDF) is commonly used on offshore rigs due to its benefits to the high level of drilling complexity, especially at deep and ultra-deep-water scenarios. However, when formation gas dissolves in the mud due to high pressure and high temperature, the complexity of kick detection increases significantly. Furthermore, environmental concerns raised a red flag on SBDF usage due to potential impacts on the marine environment, with most governmental agencies around the world passing very strict regulations. Considering both aspects - safety, and environmental concerns - glycerin emerges as a potential candidate to perform a key role as a base drilling fluid (GBDF). At first, a GBDF has the potential to behave as an SBDF due to its benefits, such as lubricity and shale stabilization, and, at the same time, it has the same characteristics of water-based drilling fluid (WBDF) with very low methane solubility, the major component of natural gas. Additionally, GBDF is considered to be more environmentally friendly than SBDF. In this work, we first analyzed the PVT properties and rheology of three different molar composition glycerin-based drilling fluids: 100% glycerin, 5050% glycerin/brine, and 40-60% glycerin/brine. Then, we performed the PVT properties analysis of methane (10-50% molar mass) mixed with each of these GBDF mentioned. In a systematic constant composition expansion through a visual high-resolution PVT cell under temperature and pressure range conditions of 20-80 degrees C and 0-55 MPa, respectively, and rheology characterization. The GBDF exhibited interesting results for density and rheology parameters similar to an SDBF and no methane solubility. Finally, mathematical correlations are proposed and applied to illustrate a pit-gain calculation comparing to an n-paraffin-based drilling fluid.",0,0,3
Drilling Fluids,Rheological Parameters,"Yang, Mou; Luo, Hao; Xie, Rongxuan; Wu, Pengcheng; Yang, Mingzheng; Yang, Lvchao; Xue, Hu",Estimating and optimizing wellbore pressure during primary cementing in low pressure and leakage formations,Circulating pressure; Cementing operation; Low pressure and leakage formations; Mathematical model; Computational fluid dynamics,NON-NEWTONIAN FLUIDS; POWER-LAW FLUID; HERSCHEL-BULKLEY; ECCENTRIC ANNULI; DRILLING-FLUIDS; TURBULENT-FLOW; LAMINAR; CIRCULATION; TRANSITION; BEHAVIOR,"In most realistic situations, casing eccentricity and various fluids injected during primary cementing lead to a significant difference in fluid flow and circulating pressure, compared with a single fluid flowing in the concentric annulus. Ignoring the effect of eccentricity and fluid rheological model on the wellbore circulating pressure results in an inaccurate evaluation and leads to formation leakage, especially for low pressure and leakage formations. To overcome this challenge, firstly, rheological models of various fluids were analyzed using experimental data, including drilling fluid, spacer, and cement slurry. Secondly, the modified correlations of frictional pressure losses for Herschel-Bulkley and Power Law fluids in the eccentric annulus were developed, using the simulation data of computational fluid dynamics software (CFD) and considering the effects of flow behavior index, pipe diameter ratio, and casing eccentricity on the frictional pressure losses. Finally, based on the developed mathematical models, the optimal method of primary cementing and evaluation results were presented, analyzed, and tested in the field with great success. The results demonstrated that the drilling fluid and spacer fluid had the highest goodness of fit for the Herschel-Bulkley model, and the cementing slurry was suitable for the Power Law model. The ratio coefficient of pressure loss in the eccentric to concentric annulus decreased with a decrease of hole size and an increase of casing eccentricity. A 50 percent reduction in frictional pressure loss was evaluated when the casing lies on the borehole wall. Comparing the calculations of the developed correlation with the published correlation in the literature reveals a more accurate evaluation of friction pressure losses in the analyzed case. Combined with the realistic situation of a test well, the density, flow rate, and returning depth of the lead cement slurry were recommended as 1.5 g/cm(3), 0.5 m(3)/min and 4100 m, respectively, according to the leakage pressure of 65.6 MPa that was calculated by the developed mathematical model. Most importantly, the developed method in this paper can accurately predict the variation characteristics of wellbore pressure during the primary cementing process and provide effective guidance in managing downhole pressure in low pressure and leakage formations by real-time adjustment of the most effective and controllable operation parameters.",0,0,3
Drilling Fluids,Control,"Xie, Yuhong; Ouyang, Min; Zhao, Hu; Li, Lie; Feng, Yingtao",Wellbore pressure management of offshore wells during casing running in narrow safety pressure window formations,Safety pressure window; Surge-swab pressure; Managed mud level; Offshore well; Casing running,,"Casing running in subsea wells has long been considered a daunting task and repeatedly proved unsuccessful, largely due to the narrow safety pressure window formations. Mud losses to formations, formation fluid influx and well wall collapsing have been the three most common causes in such casing running failures. The problem can be solved with the managed wellbore pressure casing running technique, which was developed based on managed pressure cementing and implemented by controlling mud level. Accurate calculation of surge-swab pressure is the key to successful managed pressure casing running. In this study, we show a dynamic surges-wab pressure model for the managed pressure casing running method. By analyzing the factors influencing surge-swab pressure, it is found that the surge-swab pressure of wellbore rises with the increase in initial position of the bottom of the casing, casing running speed, drilling mud density and viscosity. By contrast, changing mud level has little impact on surge-swab pressure. The surge-swab pressure during the deceleration stage of the casing has a negative value, namely the swab pressure. Therefore, we propose a managed pressure casing running method based on the accurate calculation dynamic surge-swab pressure. This method controls the wellbore pressure by adjusting the mud level according to the surge-swab pressure. Managed wellbore pressure casing running can reduce not only the risk of lost circulation and fluid influx during casing running, but also the time for casing running operation.",0,0,0
Drilling Fluids,Control,"Erge, Oney; Gu, Qifan; Chen, Dongmei; van Oort, Eric",MPD choke control considering the thixotropic gelation behavior of drilling fluids,Thixotropy modeling; Control algorithms; Preview-based feedback control; Hydraulics modeling; Managed pressure drilling,PRESSURE,"This study evaluates control algorithms that manage choke pressure during managed pressure drilling applications (MPD) while also taking the thixotropic behavior of drilling fluids into account. This evaluation analyzes proportional-integral (PI) feedback control and proposed preview-based feedback control for choke pressure. A pressure spike can be observed in standpipe and bottomhole pressure after making a drillstring connection or experiencing a prolonged break in drilling operations. This is caused by the gelation of drilling fluids. It is vital to be able to predict the magnitude of such pressure spikes when drilling with active annular pressure control, such that the choke can be effectively controlled to mitigate an induced non-productive time event (i.e., lost circulation events, pump or pipe failures, or well control situations). In this study, a shear-rate and time-dependent thixotropy model is integrated into a rigorously validated transient hydraulics engine with MPD control capabilities. Drilling scenarios are simulated with choke controllers and a case study is presented. When using a preview-based feedback control algorithm, a physics-based model is executed while setpoints are established proactively. The combined capabilities of the physics-based model and the improved MPD controller are demonstrated. Accurately modeling and controlling pressure during drilling operations is essential, especially for wells drilled in narrow-margin environments. The results of our study show that a reactive PI controller is not fast enough to account for transient pressure behavior related to fluid thixotropy. Moreover, the results show that a previewbased feedback controller is more robust and efficient. We demonstrate how a physics-based model can be used in a preview-based control scenario to keep the bottomhole pressure constant with strongly attenuated pressure fluctuations, leading to safer, more optimized operations.",0,0,2
Drilling Fluids,Control,"Duarte, A. C. R.; Ribeiro, P. R.; Kim, N. R.; Mendes, J. R. P.; Policarpo, N. A.; Vianna, A. M.",An experimental study of gas solubility in glycerin based drilling fluid applied to well control,Solubility; Drilling; Well control; Drilling fluids; Aqueous glycerol solution,METHANE,"The drilling fluid is the primary barrier element against a kick. In the path of drilling fluids evolution, syntheticbased drilling fluid (SBDF) is commonly used on offshore rigs due to its benefits to the high level of drilling complexity, especially at deep and ultra-deep-water scenarios. However, when formation gas dissolves in the mud due to high pressure and high temperature, the complexity of kick detection increases significantly. Furthermore, environmental concerns raised a red flag on SBDF usage due to potential impacts on the marine environment, with most governmental agencies around the world passing very strict regulations. Considering both aspects - safety, and environmental concerns - glycerin emerges as a potential candidate to perform a key role as a base drilling fluid (GBDF). At first, a GBDF has the potential to behave as an SBDF due to its benefits, such as lubricity and shale stabilization, and, at the same time, it has the same characteristics of water-based drilling fluid (WBDF) with very low methane solubility, the major component of natural gas. Additionally, GBDF is considered to be more environmentally friendly than SBDF. In this work, we first analyzed the PVT properties and rheology of three different molar composition glycerin-based drilling fluids: 100% glycerin, 5050% glycerin/brine, and 40-60% glycerin/brine. Then, we performed the PVT properties analysis of methane (10-50% molar mass) mixed with each of these GBDF mentioned. In a systematic constant composition expansion through a visual high-resolution PVT cell under temperature and pressure range conditions of 20-80 degrees C and 0-55 MPa, respectively, and rheology characterization. The GBDF exhibited interesting results for density and rheology parameters similar to an SDBF and no methane solubility. Finally, mathematical correlations are proposed and applied to illustrate a pit-gain calculation comparing to an n-paraffin-based drilling fluid.",0,0,3
Drilling Fluids,Mathematical Model,"Muravleva, Ekaterina A.; Derbyshev, Dmitry Yu; Boronin, Sergei A.; Osiptsov, Andrei A.","Multigrid pressure solver for 2D displacement problems in drilling, cementing, fracturing and EOR",Multigrid; Hydraulic fracturing; Cementing; Numerical modeling; Fast linear solver; BiCGStab,WELLBORE COMPLETION FLUIDS; ANNULAR DISPLACEMENTS; NUMERICAL-SIMULATION; MUD REMOVAL; OIL-WELL; FLOW; PLACEMENT; MODEL; TRANSPORT,"Numerical simulators for the design of oilfield services technologies are required to be fast and robust, hence the implementation of underlying mathematical models is expected to be highly efficient. We present an optimized numerical algorithm based on the multigrid approach for solving the pressure equation in 2D problems of fluid-fluid displacement. This type of problems arise in oilfield services applications, such as drilling, cementing, hydraulic fracturing and EOR. The displacement of fluids with different properties in a narrow annular gap (drilling, cementing) or a slot (hydraulic fracturing, production) is governed by the 2D width-averaged model in the lubrication approximation. In numerical implementation, the most time-consuming is the elliptic Poisson pressure equation, which has coefficients with discontinuities (jumps) in the case of displacement of fluids with viscosity contrast. Specifically for this case of discontinuous coefficients, we designed and implemented numerically the black-box multigrid algorithm, which resolves the divergence issue typical of standard realization of multigrid algorithm using bilinear prolongation operators. The algorithm is tested on a number of matrices corresponding to discretization of elliptic equation at rectangular staggered meshes with different resolution. The performance of the algorithm is compared against several other sparse solvers available for commercial use: smoothed aggregated algebraic multigrid (PyAMG software package), direct sparse solver from Intel MKL library (DSS), Bi-Conjugate Gradient-Stabilized solver preconditioned by ILUT factorization implemented into BLAS package, and our in-house Conjugated Gradient algorithm preconditioned by ILU(2) factorization. It was found that the performance of the black-box multigrid solver is significantly higher (from 7x to 30x in terms of CPU time depending on the mesh resolution) as compared to the closest solver under consideration, which allows us to recommend this solver for implementation into existing 2D drilling simulators, fracturing design tools, cement placement and production simulators.",0,0,0
Drilling Fluids,Mathematical Model,"Bellabiod, Sofiane; Deghmoum, Abdelhakim; Aris, Abdelkader; Karacali, Ozgur",An insight to formation damage evolution,Formation damage time evolution; Pressure transient analysis; Well test,,"Formation damage can significantly defer hydrocarbon production. Formation damage is one of the key parameters used to evaluate the quality of various operations during the life of a well. The evolution of formation damage over time is rarely studied. This paper presents the pressure transient analysis (PTA) used to derive a correlation between skin factor increase and the length of time for which a well was left exposed to drilling fluid. Multiple field examples are analyzed and modeled comparatively to evaluate the magnitude of the time-lapse formation damage. A quantitative relationship between the increase in mechanical skin as a function of exposure to drilling mud is constructed by a polynomial fitting. This gives us an insight on the how the well skin increases with exposure to drilling mud. Several mathematical models have been developed to model formation damage mechanisms. However, it is cumbersome to isolate and compute the individual mechanisms contributing to observed damage. Formation damage results from a combination of the pore size distribution, fines migration, fluid compatibility problems, wettability, presence of inorganic salts deposition, insufficient well cleanup, organic substance deposition, multiphase flow effects, etc. The proposed approach uses the skin factor derived from pressure transient analysis (PTA) to track the time-lapse evolution of formation damage during exposure time to mud, from drilling to production. The methodology has been applied to various reservoir rocks to quantify the impact for a specific rock type. Results from pressure transient tests conducted immediately after drilling, casing, and perforating are compared with production tests performed multiple years after drilling confirm that there is a mathematical relation between the formation damage, type of drilling and completion fluid, formation rock type, and exposure time to such fluids. The formation damage increase is more severe for longer duration of exposure, and also more severe for higher formation permeability.",0,0,2
Drilling Fluids,Mathematical Model,"Yang, Mou; Luo, Hao; Xie, Rongxuan; Wu, Pengcheng; Yang, Mingzheng; Yang, Lvchao; Xue, Hu",Estimating and optimizing wellbore pressure during primary cementing in low pressure and leakage formations,Circulating pressure; Cementing operation; Low pressure and leakage formations; Mathematical model; Computational fluid dynamics,NON-NEWTONIAN FLUIDS; POWER-LAW FLUID; HERSCHEL-BULKLEY; ECCENTRIC ANNULI; DRILLING-FLUIDS; TURBULENT-FLOW; LAMINAR; CIRCULATION; TRANSITION; BEHAVIOR,"In most realistic situations, casing eccentricity and various fluids injected during primary cementing lead to a significant difference in fluid flow and circulating pressure, compared with a single fluid flowing in the concentric annulus. Ignoring the effect of eccentricity and fluid rheological model on the wellbore circulating pressure results in an inaccurate evaluation and leads to formation leakage, especially for low pressure and leakage formations. To overcome this challenge, firstly, rheological models of various fluids were analyzed using experimental data, including drilling fluid, spacer, and cement slurry. Secondly, the modified correlations of frictional pressure losses for Herschel-Bulkley and Power Law fluids in the eccentric annulus were developed, using the simulation data of computational fluid dynamics software (CFD) and considering the effects of flow behavior index, pipe diameter ratio, and casing eccentricity on the frictional pressure losses. Finally, based on the developed mathematical models, the optimal method of primary cementing and evaluation results were presented, analyzed, and tested in the field with great success. The results demonstrated that the drilling fluid and spacer fluid had the highest goodness of fit for the Herschel-Bulkley model, and the cementing slurry was suitable for the Power Law model. The ratio coefficient of pressure loss in the eccentric to concentric annulus decreased with a decrease of hole size and an increase of casing eccentricity. A 50 percent reduction in frictional pressure loss was evaluated when the casing lies on the borehole wall. Comparing the calculations of the developed correlation with the published correlation in the literature reveals a more accurate evaluation of friction pressure losses in the analyzed case. Combined with the realistic situation of a test well, the density, flow rate, and returning depth of the lead cement slurry were recommended as 1.5 g/cm(3), 0.5 m(3)/min and 4100 m, respectively, according to the leakage pressure of 65.6 MPa that was calculated by the developed mathematical model. Most importantly, the developed method in this paper can accurately predict the variation characteristics of wellbore pressure during the primary cementing process and provide effective guidance in managing downhole pressure in low pressure and leakage formations by real-time adjustment of the most effective and controllable operation parameters.",0,0,3
Drilling Fluids,Yield Point,"Peixoto, Renato D. L.; Bicudo, Tatiana C.; Moura, Heloise O. M. de A.; Sousa, Adriano S.; de Carvalho, Luciene S.",Synthesis of decyl methyl carbonate and a comparative assessment of its performance as the continuous phase of synthetic-based drilling fluids,Green drilling fluids; Asymmetric carbonates; Babassu esters; Carbonate-based fluid,DIMETHYL CARBONATE; BIODIESEL; OIL; FORMULATION; STABILITY; ALCOHOLS; ESTER,"Ester-based drilling fluids have been explored as an alternative to the mineral oil and diesel-based fluids for their low toxicity and high biodegradability. In this work, decyl methyl carbonate (DeMeC) was synthesized and assessed as a novel continuous phase for synthetic-based drilling fluids (SBF), since it is equally biodegradable, presents higher chemical stability and elastomer compatibility when compared to fatty ester bases. Babassu oil methyl esters (BME) were synthesized and tested for comparison. Fourier transform infrared spectroscopy (FTIR), gas chromatography coupled to a mass spectrometer (GC/MS) or a flame ionization (GC/FID) detector, thermogravimetry (TG/DTG/DSC) and proton nuclear magnetic resonance (H-1 NMR) techniques were applied for characterizing the obtained products and confirmed the synthesis of DeMeC and BME. The low pour point of DeMeC and BME may allow the application to approach the blowout preventer region in ultra-deepwater drilling, while the low viscosity of both compounds make them suitable for drilling operations. In addition, the high flash point value for both bases is considered safe for its use, transportation and storage. The drilling fluid produced with DeMeC (DeMeC-DF) presented high efficiency, with satisfactory results of plastic viscosity, initial and 10-min gel strengths, yield point and filtrate, thus standing out as a real alternative for application in synthetic-based drilling fluids.",0,0,0
Drilling Fluids,Yield Point,"Alkalbani, Alhaitham M.; Chala, Girma T.; Myint, Myo Tay Zar",Experimental investigation of rheological properties of water-base mud with zinc oxide nanoparticles using response surface methodology,Nanoparticles; Zinc oxide; Downhole condition; Viscosity; Yield point; Gel strength,OIL,"Special and advanced techniques at drilling and production operations are used to drill and produce hydrocarbons from different eccentric reservoirs such as deep-water reservoirs, shale gas, and shale oil necessitates. However, these advanced techniques are considered to be costly and affecting the environment. Therefore, nanotechnology has been implemented in the drilling fluids to improve the rheological properties, hydrogen concentration, and filtration rate. This study is, therefore, aimed at evaluating the properties of zinc oxide nanoparticles and their previous implementation in drilling fluids, examining the rheological properties of water base mud from atmospheric temperature to downhole condition (90 degrees C). The experiment was designed to investigate the effect of nanoparticles concentration and temperature variation on the rheological properties of water-based mud using response surface methodology. A rotational viscometer was used to measure viscosity, yield point and gel strength. Moreover, a Consistometer was used to heat the fluid sample to different temperatures reaching up to downhole condition (90 degrees C). It was observed experimentally that addition of zinc oxide nanoparticles impressively improved the rheological properties of water-base mud by 50% for viscosity and gel strength, and 80% for yield point. It also allowed them to maintain their quality at all temperatures. Furthermore, addition of higher concentrations of zinc oxide nanoparticles of more than 1 wt% (6 g) at low temperatures (below 40 degrees C) gave the highest and most effective results of the rheological properties.",0,0,1
Drilling Fluids,Algorithm,"Muravleva, Ekaterina A.; Derbyshev, Dmitry Yu; Boronin, Sergei A.; Osiptsov, Andrei A.","Multigrid pressure solver for 2D displacement problems in drilling, cementing, fracturing and EOR",Multigrid; Hydraulic fracturing; Cementing; Numerical modeling; Fast linear solver; BiCGStab,WELLBORE COMPLETION FLUIDS; ANNULAR DISPLACEMENTS; NUMERICAL-SIMULATION; MUD REMOVAL; OIL-WELL; FLOW; PLACEMENT; MODEL; TRANSPORT,"Numerical simulators for the design of oilfield services technologies are required to be fast and robust, hence the implementation of underlying mathematical models is expected to be highly efficient. We present an optimized numerical algorithm based on the multigrid approach for solving the pressure equation in 2D problems of fluid-fluid displacement. This type of problems arise in oilfield services applications, such as drilling, cementing, hydraulic fracturing and EOR. The displacement of fluids with different properties in a narrow annular gap (drilling, cementing) or a slot (hydraulic fracturing, production) is governed by the 2D width-averaged model in the lubrication approximation. In numerical implementation, the most time-consuming is the elliptic Poisson pressure equation, which has coefficients with discontinuities (jumps) in the case of displacement of fluids with viscosity contrast. Specifically for this case of discontinuous coefficients, we designed and implemented numerically the black-box multigrid algorithm, which resolves the divergence issue typical of standard realization of multigrid algorithm using bilinear prolongation operators. The algorithm is tested on a number of matrices corresponding to discretization of elliptic equation at rectangular staggered meshes with different resolution. The performance of the algorithm is compared against several other sparse solvers available for commercial use: smoothed aggregated algebraic multigrid (PyAMG software package), direct sparse solver from Intel MKL library (DSS), Bi-Conjugate Gradient-Stabilized solver preconditioned by ILUT factorization implemented into BLAS package, and our in-house Conjugated Gradient algorithm preconditioned by ILU(2) factorization. It was found that the performance of the black-box multigrid solver is significantly higher (from 7x to 30x in terms of CPU time depending on the mesh resolution) as compared to the closest solver under consideration, which allows us to recommend this solver for implementation into existing 2D drilling simulators, fracturing design tools, cement placement and production simulators.",0,0,0
Drilling Fluids,Algorithm,"Erge, Oney; Gu, Qifan; Chen, Dongmei; van Oort, Eric",MPD choke control considering the thixotropic gelation behavior of drilling fluids,Thixotropy modeling; Control algorithms; Preview-based feedback control; Hydraulics modeling; Managed pressure drilling,PRESSURE,"This study evaluates control algorithms that manage choke pressure during managed pressure drilling applications (MPD) while also taking the thixotropic behavior of drilling fluids into account. This evaluation analyzes proportional-integral (PI) feedback control and proposed preview-based feedback control for choke pressure. A pressure spike can be observed in standpipe and bottomhole pressure after making a drillstring connection or experiencing a prolonged break in drilling operations. This is caused by the gelation of drilling fluids. It is vital to be able to predict the magnitude of such pressure spikes when drilling with active annular pressure control, such that the choke can be effectively controlled to mitigate an induced non-productive time event (i.e., lost circulation events, pump or pipe failures, or well control situations). In this study, a shear-rate and time-dependent thixotropy model is integrated into a rigorously validated transient hydraulics engine with MPD control capabilities. Drilling scenarios are simulated with choke controllers and a case study is presented. When using a preview-based feedback control algorithm, a physics-based model is executed while setpoints are established proactively. The combined capabilities of the physics-based model and the improved MPD controller are demonstrated. Accurately modeling and controlling pressure during drilling operations is essential, especially for wells drilled in narrow-margin environments. The results of our study show that a reactive PI controller is not fast enough to account for transient pressure behavior related to fluid thixotropy. Moreover, the results show that a previewbased feedback controller is more robust and efficient. We demonstrate how a physics-based model can be used in a preview-based control scenario to keep the bottomhole pressure constant with strongly attenuated pressure fluctuations, leading to safer, more optimized operations.",0,0,2
Cement,Well Integrity,"Beltran-Jimenez, K.; Skadsem, H. J.; Sunde, J. K.; Gardner, D.; Wolterbeek, T. K. T.; Cornelissen, E. K.; Keultjes, W. J. G.",Restoration of annular zonal isolation using localized casing expansion (LCE) technology: Treatment of near-horizontal test sections containing a free-water channel,Well integrity; Well abandonment; Sustained casing pressure; Surface casing vent flow; Annular fluid migration; Casing expansion,CEMENT PASTE; GAS; BEHAVIOR,"Fluid migration behind casings is a well integrity problem that can result in sustained casing pressure, undetected leaks to the environment, and potentially very difficult remediation attempts. Traditional methods for treating annular fluid migration are perf-and-squeeze cementing or section milling followed by recementing. The main disadvantage of the former is the limited penetrability of cement slurry into narrow cracks and microannuli, while for the latter it is the requirement of a full rig to perform the operation. Casing expansion is a recent alternative remediation technology that involves imposing a permanent radial expansion of the casing and external cement layer, with the purpose of mechanically closing pathways for migrating fluids. A necessary requirement for the treatment to be effective is that the annular cement is confined between casings or between casing and competent rock formations, such that the cement can sustain significant mechanical strains without failure. Recent laboratory experiments and field trials have shown casing expansion to be a promising alternative to traditional treatment methods. We build on these insights and perform controlled treatment experiments involving a 7-in Local Expander tool and full-scale cemented annulus test assemblies, which contained much larger-scale defects than previously tested. Prior to treatment, the test assemblies had continuous migration channels on the top side of the cement, leading to high effective permeabilities ranging from approximately 80 to hundreds of darcy. The origin of the defects was likely separation of free water from the cement slurry, which is considered a relevant failure mode for primary cementing of inclined wellbores. We study the effect of imposing single and multiple local dents on the annular seepage rates, and probe for potential alteration of the cement and casing properties using Vickers hardness testing. We find that casing expansion can be highly effective in treating relatively major defects in cemented annuli, even when the defect is several millimeters wide and located adjacent to the outer casing. The effectiveness of the treatment is found to be linked to the degree of casing expansion and the initial condition of the annular cement. The deformed cement shows a tendency toward increased Vickers hardness, which is likely linked to densification of the cement microstructure. Vickers hardness testing of casing steel indicated no significant changes in hardness at the dent locations compared to average hardness values away from these points.",0,0,0
Cement,Well Integrity,"Bahrehvar, Mohammad; Mehrabi, Hamzeh; Akbarzadeh, Samira; Rahimpour-Bonab, Hossain",Depositional and diagenetic controls on reservoir quality of the uppermost Jurassic-Lower Cretaceous sequences in the Persian Gulf; a focus on J-K boundary,Manifa-Yamama formations; Reservoir facies; Hydraulic flow units; Jurassic-Cretaceous boundary; Persian Gulf,FAHLIYAN FORMATION; DARIYAN FORMATION; MIDDLE-EAST; STRATIGRAPHY; BASIN; GEOCHEMISTRY; ZAGROS; IRAN; PALEOCLIMATE; MICROFACIES,"This study presents reservoir characterization of the uppermost Jurassic-Lower Cretaceous successions of the Manifa and Yamama formations in four wells in the Persian Gulf. Detailed sedimentological, petrophysical and geochemical analyses are integrated to evaluate the controlling factors on reservoir quality of these sequences. Microfacies analysis has resulted in the recognition of 10 facies types deposited in lagoon, algal mounds, shoal, and open marine settings. Micritization, dissolution, various types of cementation, dolomitization, and compaction are notable diagenetic alterations indicating marine/hypersaline, meteoric and shallow to deep burial realms. Stable carbon and oxygen isotopic compositions indicate a meteoric diagenetic alteration at the topmost part of Manifa unit, beneath the Jurassic-Cretaceous (J-K) disconformity. Sequence stratigraphic analysis led to the identification of four transgressive-regressive (T-R) sequences in the Yamama Fm. and a regressive hemi-sequence in the Manifa unit. Reservoir quality study resulted in the recognition of eight hydraulic flow units and four types of reservoir facies with specific and predictable sequence stratigraphic framework. Dissolved grain-dominated shoal facies at the upper part of regressive systems tracts and algal reef/mound facies in transgressive systems tracts provide the best reservoir units of the studied sequences. Microporous mud-dominated facies of open marine settings are dominant reservoir facies in the upper Yamama unit, with moderate to low reservoir quality.",0,0,0
Cement,Well Integrity,"Taghipour, Ali; Ghaderi, Amir; Cerasi, Pierre; Gheibi, Sohrab",Novel laboratory setup for realistic wellbore cement and formation integrity studies,Well integrity; Cement integrity; Formation integrity; Experimental realistic setup,SHEATH INTEGRITY; ZONAL ISOLATION,"Oilfield wellbore integrity relies on a good well cement formulation, placement, and resistance to solicitations when aging, either due to chemical or stress changes. Requirements are that the cement sheath and plugs remain as proper hydraulic barriers for all foreseeable future. Thus, to qualify the cement formulations with respect to various types of stress changes, it is important to carry out these tests in the field relevant conditions in the laboratory. These tests will contribute to improved understanding of the limiting factors influencing the well integrity and assist in design of remediation strategies. Hence, a new experimental setup designed for studying near wellbore systems in field conditions is introduced. The setup comprises of an advanced X-ray cell with the possibility of three independent pressure controls of casing, pore and formation pressures. The experiments are carried out under simultaneous X-ray Micro-CT imaging allowing to monitor the in-situ mechanical changes. Numerical calculations in the finite element domain are carried out for the same test conditions with first results showing the evolution of radial cracks in the cement sheath and the formation rock submitted to excessive well pressures. The test results confirm with the numerical simulation. These results may provide valuable input for near-wellbore integrity assessments.",0,0,1
Cement,Well Integrity,"Khodami, Eissa; Ramezanzadeh, Ahmad; Sharifi, Ali",The 3D simulation of the effect of casing standoff on cement integrity by considering the direction of horizontal stresses in one of the wells of Iranian oil fields,Casing standoff; Cement integrity; ABAQUS; Plastic strain; Horizontal stresses,,"Drilling engineers must conduct predictive tests before the occurrence of integrity issues to save time and money. A successful casing standoff helps boost well integrity and cement integrity, both of which are critical factors during a well's production life. The casing standoff is 100 percent in several books and computational simulations. However, it should be remembered that this standoff is never 100 percent, and the casing is still inclined to one side of the well wall. Also, with the use of centralizers, the casing shifts, and the standoff deviates from ideal conditions In this study, a 3D simulation was analyzed using ABAQUS Software, using the geomechanical modeling data and considering the well's environmental conditions. The effect of casing standoff on cement integrity was investigated using sensitivity analysis and parametric tests. According to the simulation results in the studied well, the plastic strain in the cement sheath increases as the casing standoff decreases, resulting in the highest strain at the cement-casing interface. The plastic pressure increases as the cement's narrow side face the direction of most minor horizontal tension. As a result, having adequate information about the conditions and direction of in-situ stresses is needed before driving the casing in the well drilling stage.",0,0,1
Cement,Well Integrity,"Arouri, Khaled R.; van Dijk, Clemens",Mapping solid reservoir bitumen by deconvoluting formation mechanism,Solid reservoir bitumen; Formation mechanism; Geochemistry; Fluid distribution; Reservoir quality prediction; Sandstone diagenesis,COMPACTION PROCESSES; SANDSTONE RESERVOIR; RELATIVE IMPORTANCE; POROSITY; CEMENTATION; REDUCTION; OFFSHORE; MATURITY; BASIN; OIL,"Solid reservoir bitumen is a geologic risk that controls reservoir quality and fluid distribution and has a profound impact on field development and near-field exploration. Understanding the exact mechanism responsible for the development of solid bitumen is therefore a prerequisite toward its proper quantification and mapping. A sandstone reservoir of an anticlinal gas condensate field was investigated geochemically, and data integrated with reservoir diagenetic history to explain abundant solid bitumen encountered within several meters immediately below a regional unconformity in crestal wells, as opposed to deeper sections and downdip wells. The reservoir is generally characterized by a similar sedimentological and diagenetic history across the field, with diagenetic illite grain coats and quartz cement occurring in both updip and downdip wells. The influx of gas condensates into the upper part of the preexisting oil reservoir, possibly facilitated by a major fault, appears to have caused thermodynamic disequilibrium, leading to de-asphalting and subsequent deposition of solid bitumen. Textural and radiometric age dating, integrated with fluid inclusion homogenization temperatures and basin modeling, suggests the initiation of bitumen deposition 129 Ma, immediately after the arrival of gas condensates into the reservoir. As the process was restricted to the uppermost part of the reservoir, it is possible that the solid bitumen, once developed, has improved sealing efficiency along the unconformity and the trapping of subsequent hydrocarbon charges in the underlying reservoir. Better reservoir quality can be inferred farther downdip in areas inaccessible to gas incursions and hence not affected by gas de-asphalting. Other processes, such as regional uplift-induced phase separation, in-reservoir thermal cracking, water-washing, and biodegradation, were also examined and found irrelevant to the formation of solid bitumen in question.",0,0,1
Cement,Well Integrity,"Khodami, Eissa; Ramezanzadeh, Ahmad; Noroozi, Mehdi",Numerical modeling of oil well integrity with a particular view to cement (case study: Maroon Oilfield in southwest of Iran),Well integrity; Numerical modeling; Geomechanical model; Cement; ABAQUS,PORE PRESSURE; FAILURE; STRESS; PREDICTION; RESERVOIR; IMPACT,"Well integrity represents an objective/solution for protecting human life and environment while retaining oil production rate during the life of the well. Characterization of cement behavior plays an important role in ensuring the well integrity and can be effectively considered when it comes to the prevention of casing failure. In this research, firstly, petrophysical data at one of the wells drilled into Maroon Oilfield in southwest of Iran was used to build a one-dimensional geomechanical model of the formation encompassing the well, based on which geomechanical characteristics of the formation were estimated. Subsequently, mechanical parameters of the cement sheath used in the considered well and the friction parameters of the cement-formation contact surface were determined via laboratory tests on samples of the cement. Next, using the obtained data and considering the environmental conditions in the well, a reference numerical model was constructed for a particular section of the studied well utilizing ABAQUS Software followed by analyzing the wellbore stability under existing conditions. Finally, sensitivity analysis and parametric studies were performed to investigate the impact of friction parameters of contact surfaces, and mechanical properties of the cement on the well integrity. The results indicated that, higher Young's modulus and/or lower Poisson's ratio, cohesion, and friction angle in the cement sheath further contributed to larger plastic strains in the sheath. Moreover, with increasing the friction of formation-cement and cement-casing contact surfaces, plastic strain of the cement was observed to decrease. In the parametric analysis, the coefficient of friction between cement-formation and cement-casing has decreased by About 45% and 60%, respectively, and the amount of PEEQ in cement increases by up to 30 mm.",0,0,2
Cement,Well Integrity,"Jaculli, Marcelo Anunciacao; Pelaquim Mendes, Jose Ricardo; Colombo, Danilo",Evaluation of excessive wellhead motions: Reliability assessment and wellhead integrity index (Part II),Wellhead; Excessive motions; Reliability; Integrity index,,"As discussed in part I of this work, the wellhead is an important component in the context of well integrity and operational safety, as it serves as a link between well and riser in offshore oil wells. The wellhead must sustain loads from the casings (soil reaction), which are hung into it through the casing hangers, as well as sustain loads from the riser (waves, current), which is connected at the top of the BOP (right above the wellhead) through the lower flex joint. In Part I of this work, we proposed a deterministic methodology to evaluate excessive wellhead motions, considering a mechanical system that couples the vessel, the riser, the wellhead itself, the conductor and surface casings, and their interaction with the soil. Now, in Part II, we move onto a stochastic analysis, which allows us to calculate the wellhead reliability. The simulation of this system provides the motions experienced by the wellhead; then, criteria such as maximum allowable lateral deflection and maximum allowable rotation are applied to verify if they will cause wellhead failure. Several interesting results have been observed: modern 5-phase wells with cemented conductor confer higher integrity to the wellhead compared to old 4-phase wells with jetted conductors; current speed/profile is the variable that affects the most the wellhead reliability; and heavier inner fluids reduce the reliability, posing a problem for later drilling phases. Finally, an integrity index for the wellhead throughout the well life cycle is suggested, aggregating the literature related to wellhead fatigue failure. The wellhead integrity index can then be combined with other indexes from other barrier elements to evaluate the overall integrity of barrier envelopes.",0,0,2
Cement,Well Integrity,"Pagano, Arianna Gea; El Mountassir, Grainne; Lunn, Rebecca Jane",Performance of colloidal silica grout at elevated temperatures and pressures for cement fracture sealing at depth,Colloidal silica; Well decommissioning; Plug &amp; abandonment; Wellbore integrity,WELL INTEGRITY,"Hydrocarbon well decommissioning requires the long-term sealing of abandoned wells. Current plug and abandonment (P&A) operations are not always able to address all potential fluid migration pathways, resulting in the possible upwards migration of hydrocarbons from formations penetrated by the wellbore. The development of innovative materials to improve well sealing remains a major challenge. This paper presents a proof of concept for the use of colloidal silica (CS)-based grout to improve the sealing performance of P&A operations. CS is a non-toxic suspension of silica nanoparticles (<100 nm) undergoing gelation upon destabilisation. Due to its excellent penetrability and controllable gel time, CS has the potential for repairing fine-aperture cracks within the cement sheath, at the cement/casing interface, or within a cement plug, where the penetration of cementitious grouts is restricted due to their relatively large particle size. In this study, the suitability of CS grout for deployment up to 1500 m depth was successfully demonstrated. Firstly, a range of CS grout mixes were investigated to test the feasibility of grout emplacement considering a timescale of 2 h for pumping operations from the surface to depth. Secondly, to investigate the sealing performance, the CS grout was injected into fractured cement cores (0.2 and 0.5 mm fracture aperture) and exposed to pressure and temperature conditions simulating downhole scenarios up to 1500 m depth (based on gradients for North Sea, UK). Fracture permeability upon water injection was assessed pre- and post-treatment. This work found that permeability values after treatment were reduced by three orders of magnitude, thus confirming the potential of CS grout for repairing fine-aperture cracks.",0,0,3
Cement,Calculation,"Tavakoli, Vahid; Hassani, Danial; Rahimpour-Bonab, Hossain; Mondak, Alireza","How petrophysical heterogeneity controls the saturation calculations in carbonates, the Barremian-Aptian of the central Persian Gulf",Tight carbonate reservoir; Water saturation; Archie equation; Archie coefficients; Heterogeneity,CAPILLARY-PRESSURE CURVES; SEQUENCE STRATIGRAPHY; CEMENTATION FACTOR; ARCHIES EXPONENTS; DARIYAN FORMATION; FLOW UNITS; RESERVOIR; EXAMPLE; CLASSIFICATION; PERMEABILITY,"Water saturation calculations are among the most important aspects of reservoir characterization. Despite this importance, the effects of these calculations on the resulted oil in place remain unclear. Extreme heterogeneity in most of the carbonate reservoirs strongly affects the coefficients of the Archie equation and resulted water saturation. Therefore, a practical method to evaluate and manage the heterogeneity of such reservoirs, greatly improves the reliability of the final results. In this study, porosity, permeability, thin sections data, well logs and saturation tests of Barremian-Aptian carbonate Dariyan Formation in the central Persian Gulf have been used. Both core and reservoir scale techniques including flow zone indicator, Winland R-35, electrofacies and stratigraphically modified Lorenz plot were used to evaluate the heterogeneity. Archie coefficients were arranged in different rock types. Results show that flow zone indicator is the most accurate technique to manage the heterogeneity of the reservoir with higher R-2 value between porosity and permeability. The cementation factor was measured for each unit and the amounts of water saturation was calculated using deterministic analysis. Water saturation also calculated with the constant coefficients, which are routinely used in formation evaluation. The average S-w amount for constant Archie coefficients method was determined as 0.62, whereas it is 0.73, 0.80, 0.70, and 0.77 in flow zone indicator method, Winland R-35 technique, stratigraphically modified Lorenz plot and electrofacies determination, respectively. The results demonstrate that calculating water saturation with constant Archie coefficients leads to slightly lower water saturation values, resulting in higher oil saturations and overestimating the oil in place.",0,0,0
Cement,Calculation,"Yuan, Bin; Li, Junfu; Xu, Bihua; Su, Yu; Li, Bin; Yang, Lin",Managed wellhead backpressure during waiting setting of managed pressure cementing,Managed pressure cementing; Narrow safe density window; Hydration shrinkage; Filtration shrinkage; Gel strength; Hydrostatic pressure,LOST CIRCULATION; HYDRATION; TEMPERATURE; REDUCTION,"Managed pressure cementing (MPC) has been successfully used to reduce risk lost circulation and improve cementing quality in wells with a narrow safe pressure window. However, during the waiting setting period of MPC, the magnitude of the managed well backpressure is still based on experience, which results in a high risk of leakage or gas channeling especially in formations with a narrow safe density window. Therefore, a backpressure managing method is proposed here based on a model we built for calculating wellhead backpressure. This model was used to analyze the effect of cement slurry, temperature and wellbore pressure on wellhead backpressure. The results show that hydration, filtration shrinkage and gel supporting are essential to reduce wellbore pressure, although hydration is less effective compared with the latter two on pressure reduction. The magnitude and duration of wellhead backpressure depend on the extent of volume shrinkage and the gel strength development of cement slurry. Latex-cement slurry requires minimal wellhead backpressure with the shortest duration. Temperature and wellbore pressure greatly impact wellhead backpressure with temperature playing a more dominant role.",0,0,0
Cement,Calculation,"Xie, Yuhong; Ouyang, Min; Zhao, Hu; Li, Lie; Feng, Yingtao",Wellbore pressure management of offshore wells during casing running in narrow safety pressure window formations,Safety pressure window; Surge-swab pressure; Managed mud level; Offshore well; Casing running,,"Casing running in subsea wells has long been considered a daunting task and repeatedly proved unsuccessful, largely due to the narrow safety pressure window formations. Mud losses to formations, formation fluid influx and well wall collapsing have been the three most common causes in such casing running failures. The problem can be solved with the managed wellbore pressure casing running technique, which was developed based on managed pressure cementing and implemented by controlling mud level. Accurate calculation of surge-swab pressure is the key to successful managed pressure casing running. In this study, we show a dynamic surges-wab pressure model for the managed pressure casing running method. By analyzing the factors influencing surge-swab pressure, it is found that the surge-swab pressure of wellbore rises with the increase in initial position of the bottom of the casing, casing running speed, drilling mud density and viscosity. By contrast, changing mud level has little impact on surge-swab pressure. The surge-swab pressure during the deceleration stage of the casing has a negative value, namely the swab pressure. Therefore, we propose a managed pressure casing running method based on the accurate calculation dynamic surge-swab pressure. This method controls the wellbore pressure by adjusting the mud level according to the surge-swab pressure. Managed wellbore pressure casing running can reduce not only the risk of lost circulation and fluid influx during casing running, but also the time for casing running operation.",0,0,0
Cement,Calculation,"Taghipour, Ali; Ghaderi, Amir; Cerasi, Pierre; Gheibi, Sohrab",Novel laboratory setup for realistic wellbore cement and formation integrity studies,Well integrity; Cement integrity; Formation integrity; Experimental realistic setup,SHEATH INTEGRITY; ZONAL ISOLATION,"Oilfield wellbore integrity relies on a good well cement formulation, placement, and resistance to solicitations when aging, either due to chemical or stress changes. Requirements are that the cement sheath and plugs remain as proper hydraulic barriers for all foreseeable future. Thus, to qualify the cement formulations with respect to various types of stress changes, it is important to carry out these tests in the field relevant conditions in the laboratory. These tests will contribute to improved understanding of the limiting factors influencing the well integrity and assist in design of remediation strategies. Hence, a new experimental setup designed for studying near wellbore systems in field conditions is introduced. The setup comprises of an advanced X-ray cell with the possibility of three independent pressure controls of casing, pore and formation pressures. The experiments are carried out under simultaneous X-ray Micro-CT imaging allowing to monitor the in-situ mechanical changes. Numerical calculations in the finite element domain are carried out for the same test conditions with first results showing the evolution of radial cracks in the cement sheath and the formation rock submitted to excessive well pressures. The test results confirm with the numerical simulation. These results may provide valuable input for near-wellbore integrity assessments.",0,0,1
Cement,Calculation,"Zhao, Xiaodong; Zhang, Shiqi; Yang, Shaochun; Ju, Xiaoyu; Chen, Gangqiang; Zhang, Xiaotong; Khan, Danish; Zhang, Yaxuan; Zhang, Jiankun","Controlling factors of carbonate cement and its influence on oil-water distribution of the Neogene Shawan Formation in the northern Chepaizi area, Junggar Basin, NW China",Junggar basin; Reservoir characteristics; Carbonate cements; AxioVision image analysis; Diagenetic environment,SANDSTONE; RESERVOIR; DIAGENESIS; HISTORY,"The distribution of physical property of the Neogene Shawan Formation(N1s) in the north of Chepaizi area (Abbreviated as ""Chebei area"") is characterized by ""double peak"", which is mainly related to carbonate cements in the reservoirs. It is observed that the large amounts of early carbonate cements are present in thin sections, which are inhomogeneously filled in some primary intergranular pores and caused strong heterogeneity of the reservoir. On the basis of convent calculate of carbonate cement in core, AxioVision image analysis with multiple times and multiple fields of view was used to supplement the calculation of carbonate cement content, and the relative error compared with the core measurement result was -0.14, which effectively compensated for the lack of core measurement data points. The content of carbonate cement has been characterized by ""higher in the north area and lower in the south area"" on the plane. The carbonate cement is formed in closed diagenetic environment with good sealing ability and water body stagnated alternately. The closed diagenetic environment of the Shawan formation in Chebei area primed the environmental foundation for the growth of carbonate cements, and the abundant Ca2+ in the formation water primed the material foundation for the growth of carbonate cements. The difference in Ca2+ content in formation water determines the distribution difference of carbonate cements, and the diagenetic environment is the controlling factor for the development of carbonate cements. The complex oil-water distribution in the study area is principally related to the carbonate cementation. The super heavy oil with high viscosity cannot enter the low porosity and permeability reservoir with tough cementation, which is prone to the phenomenon of oil-water inversion.",0,0,1
Cement,Calculation,"Kelishami, Shervin Bahramali Asadi; Mohebian, Reza; Salmian, Omidreza","A comprehensive perspective on pore connectivity and natural fracture analysis in Oligo-Miocene heterogeneous carbonates, southern Iran",Pore connectivity; Permeability; Fracture aperture; Artificial neural network (ANN); Porosity; Image log; Velocity deviation log (VDL),POROSITY; TECTONICS; LOG,"Ascertaining the pore connection criterion has always been a challenge for geoscientists. In the framework of this research, an attempt was made to study the pore connectivity in a heterogeneous carbonate rock by combining several techniques. Pore types and rock facies were investigated for 321 thin sections. The abundance of connected porosities, cementation type and intensity which significantly control the matrix pore connectivity were specified on thin sections and finally a connectivity log was extracted that showed an accurate result on poroperm cross-plots. Most of the porosity volumes were related to interparticle, vuggy and moldic porosities which are microscale. The velocity deviation log, estimated in four wells, indicates the presence of micro porosity, which is consistent with the results of thin-sections. Zero velocity deviation is usually associated with the predominant presence of micro-pores. Different permeability values in identical lithological facies, as well as micro-fracture markers, prompted us to conduct more extensive research on fractures. FMI analysis proved that the studied reservoir is intensively fractured. The recorded high permeability in a sample with low matrix connectivity is specifically a fracture indication. Fracture apertures vary from microscale (<50 mu m) to 12.5 mm and calculated fracture density is raised up to 2 fractures per meter. Determined fractured intervals are very consistent with mud-loss information, for instance, a complete loss has been reported in the fault zone identified in well B. The detected fractures somewhat follow the main Zagros fault trend (NW-SE). Eventually, calculated connectivity was predicted in other wells using Artificial Neural Network (ANN) and a 3D model was constructed with respect to seismic attributes which gives a precise perspective of pore connection distribution throughout the studied field.",0,0,2
Cement,Calculation,"Jaculli, Marcelo Anunciacao; Pelaquim Mendes, Jose Ricardo; Colombo, Danilo",Evaluation of excessive wellhead motions: Reliability assessment and wellhead integrity index (Part II),Wellhead; Excessive motions; Reliability; Integrity index,,"As discussed in part I of this work, the wellhead is an important component in the context of well integrity and operational safety, as it serves as a link between well and riser in offshore oil wells. The wellhead must sustain loads from the casings (soil reaction), which are hung into it through the casing hangers, as well as sustain loads from the riser (waves, current), which is connected at the top of the BOP (right above the wellhead) through the lower flex joint. In Part I of this work, we proposed a deterministic methodology to evaluate excessive wellhead motions, considering a mechanical system that couples the vessel, the riser, the wellhead itself, the conductor and surface casings, and their interaction with the soil. Now, in Part II, we move onto a stochastic analysis, which allows us to calculate the wellhead reliability. The simulation of this system provides the motions experienced by the wellhead; then, criteria such as maximum allowable lateral deflection and maximum allowable rotation are applied to verify if they will cause wellhead failure. Several interesting results have been observed: modern 5-phase wells with cemented conductor confer higher integrity to the wellhead compared to old 4-phase wells with jetted conductors; current speed/profile is the variable that affects the most the wellhead reliability; and heavier inner fluids reduce the reliability, posing a problem for later drilling phases. Finally, an integrity index for the wellhead throughout the well life cycle is suggested, aggregating the literature related to wellhead fatigue failure. The wellhead integrity index can then be combined with other indexes from other barrier elements to evaluate the overall integrity of barrier envelopes.",0,0,2
Cement,Calculation,"Yang, Mou; Luo, Hao; Xie, Rongxuan; Wu, Pengcheng; Yang, Mingzheng; Yang, Lvchao; Xue, Hu",Estimating and optimizing wellbore pressure during primary cementing in low pressure and leakage formations,Circulating pressure; Cementing operation; Low pressure and leakage formations; Mathematical model; Computational fluid dynamics,NON-NEWTONIAN FLUIDS; POWER-LAW FLUID; HERSCHEL-BULKLEY; ECCENTRIC ANNULI; DRILLING-FLUIDS; TURBULENT-FLOW; LAMINAR; CIRCULATION; TRANSITION; BEHAVIOR,"In most realistic situations, casing eccentricity and various fluids injected during primary cementing lead to a significant difference in fluid flow and circulating pressure, compared with a single fluid flowing in the concentric annulus. Ignoring the effect of eccentricity and fluid rheological model on the wellbore circulating pressure results in an inaccurate evaluation and leads to formation leakage, especially for low pressure and leakage formations. To overcome this challenge, firstly, rheological models of various fluids were analyzed using experimental data, including drilling fluid, spacer, and cement slurry. Secondly, the modified correlations of frictional pressure losses for Herschel-Bulkley and Power Law fluids in the eccentric annulus were developed, using the simulation data of computational fluid dynamics software (CFD) and considering the effects of flow behavior index, pipe diameter ratio, and casing eccentricity on the frictional pressure losses. Finally, based on the developed mathematical models, the optimal method of primary cementing and evaluation results were presented, analyzed, and tested in the field with great success. The results demonstrated that the drilling fluid and spacer fluid had the highest goodness of fit for the Herschel-Bulkley model, and the cementing slurry was suitable for the Power Law model. The ratio coefficient of pressure loss in the eccentric to concentric annulus decreased with a decrease of hole size and an increase of casing eccentricity. A 50 percent reduction in frictional pressure loss was evaluated when the casing lies on the borehole wall. Comparing the calculations of the developed correlation with the published correlation in the literature reveals a more accurate evaluation of friction pressure losses in the analyzed case. Combined with the realistic situation of a test well, the density, flow rate, and returning depth of the lead cement slurry were recommended as 1.5 g/cm(3), 0.5 m(3)/min and 4100 m, respectively, according to the leakage pressure of 65.6 MPa that was calculated by the developed mathematical model. Most importantly, the developed method in this paper can accurately predict the variation characteristics of wellbore pressure during the primary cementing process and provide effective guidance in managing downhole pressure in low pressure and leakage formations by real-time adjustment of the most effective and controllable operation parameters.",0,0,3
Cement,Reservoir Quality,"Bahrehvar, Mohammad; Mehrabi, Hamzeh; Akbarzadeh, Samira; Rahimpour-Bonab, Hossain",Depositional and diagenetic controls on reservoir quality of the uppermost Jurassic-Lower Cretaceous sequences in the Persian Gulf; a focus on J-K boundary,Manifa-Yamama formations; Reservoir facies; Hydraulic flow units; Jurassic-Cretaceous boundary; Persian Gulf,FAHLIYAN FORMATION; DARIYAN FORMATION; MIDDLE-EAST; STRATIGRAPHY; BASIN; GEOCHEMISTRY; ZAGROS; IRAN; PALEOCLIMATE; MICROFACIES,"This study presents reservoir characterization of the uppermost Jurassic-Lower Cretaceous successions of the Manifa and Yamama formations in four wells in the Persian Gulf. Detailed sedimentological, petrophysical and geochemical analyses are integrated to evaluate the controlling factors on reservoir quality of these sequences. Microfacies analysis has resulted in the recognition of 10 facies types deposited in lagoon, algal mounds, shoal, and open marine settings. Micritization, dissolution, various types of cementation, dolomitization, and compaction are notable diagenetic alterations indicating marine/hypersaline, meteoric and shallow to deep burial realms. Stable carbon and oxygen isotopic compositions indicate a meteoric diagenetic alteration at the topmost part of Manifa unit, beneath the Jurassic-Cretaceous (J-K) disconformity. Sequence stratigraphic analysis led to the identification of four transgressive-regressive (T-R) sequences in the Yamama Fm. and a regressive hemi-sequence in the Manifa unit. Reservoir quality study resulted in the recognition of eight hydraulic flow units and four types of reservoir facies with specific and predictable sequence stratigraphic framework. Dissolved grain-dominated shoal facies at the upper part of regressive systems tracts and algal reef/mound facies in transgressive systems tracts provide the best reservoir units of the studied sequences. Microporous mud-dominated facies of open marine settings are dominant reservoir facies in the upper Yamama unit, with moderate to low reservoir quality.",0,0,0
Cement,Reservoir Quality,"Nunes, Marcos; Valle, Bruno; Borghi, Leonardo; Favoreto, Julia; Mendes, Marcelo","Multi-scale and multi-technique characterization of hybrid coquinas: A study case from the Morro do Chaves Formation (Barremian-Aptian of Sergipe-Alagoas Basin, Northeast Brazil)",Multi-scale reservoir characterization; Rock typing; Upscaling; Petrophysics; Heterogeneity; Coquinas,GEOLOGICAL ATTRIBUTES; ARCHIES EXPONENTS; CARBONATE ROCKS; FLUID MIGRATION; CAMPOS BASIN; SEDIMENTARY; POROSITY; FAULTS; CLASSIFICATION; EVOLUTION,"The coquinas are carbonate rocks with variable content of siliciclastics and have a complex porous framework that implies an issue for their characterization as reservoirs. Furthermore, these rocks are considered important reservoirs due to the giant accumulations in the Campos and Santos basins (Coqueiros and Itapema formations, respectively), increasing the interest in understanding and characterizing these complex and heterogeneous lithologies. In this context, this study aims to introduce a novel method of petrophysical characterization of coquinas through a multi-technique and multi-scale approach in a continuous well core of approximately 135 m, drilled in the ""Atol Quarry"", Sa similar to o Miguel dos Campos County, Alagoas State. Based in mineralogical content, x-ray attenuation and pore type, seven tomofacies were defined using computerized tomography and allowed a representative sampling (plugs and thin sections). Five rock types were defined based textural aspects (tomofacies and petrography) and petrophysical data (routine core analysis and micro-computerized tomography). The rock types were compared to well logs, establishing boundary values and distributed along the whole well, in an upscaling process from thin-section and plugs (microscopic scale) to the well core (macroscale). The Morro do Chaves Formation core was divided into two portions: upper portion, with better reservoir quality and greater influence of mineral dissolution; and lower portion, a poor reservoir quality portion influenced by cementation processes. The upscaling method using the concepts of tomofacies and rock types proved to be a successful way to improve the understanding of reservoir characterization in heterogeneous of complex limestone successions, which can improve the recovery factor and aid in the field development.",0,0,1
Cement,Reservoir Quality,"El-Yamani, Mahmoud Samir; Al-Ramadan, Khalid; Cantrell, Dave","Diagenetic controls on porosity evolution and reservoir quality of an outcrop analogue of the Jurassic carbonate reservoirs in the Arabian Plate: An example from the Middle Jurassic Tuwaiq Mountain Formation, Central Saudi Arabia",Carbonate-diagenesis; Chert-replacing-evaporites; Dolomitization; Dolomite-calcitization; Porosity-evolution; Tuwaiq Mountain formation,DEPOSITIONAL-ENVIRONMENTS; STAINING TECHNIQUE; SILICA DIAGENESIS; DOLOMITE; DEDOLOMITIZATION; LIMESTONE; CLASSIFICATION; MICROFACIES; DISSOLUTION; JUBAILA,"The Middle Jurassic Tuwaiq Mountain Formation (TMF; formed of three members, from bottom to top T1, T2, and T3) represents one of the primary conventional and unconventional reservoirs to be assessed in Saudi Arabia. It is considered as a tight carbonate reservoir in the Jafurah Basin and conventional reservoir in the Arabian Basin. Here, we investigate the depositional, diagenetic, and stratigraphic impact on reservoir quality and porosity evolution of the TMF through an integrated petrographical, geochemical and petrophysical analyses on outcrop samples. The TMF has a complex diagenetic history including micritization, dissolution, recrystallization and neomorphism, meteoric cementation, evaporite precipitation, dolomitization, silicification, dolomite dissolution and calcitization. Dolomitization occurred via a hypersaline fluid mechanism, based on texture, association with evaporites, and Sr concentration. X-ray diffraction results support chert replacing evaporite as the mechanism of the two chert beds in the T3 member due to the presence of anhydrite relics in their samples. This replacement formed the necessary Ca2+ rich fluid for dolomite dissolution and calcitization. Therefore, dolomite calcitization occurs locally and is stratigraphically controlled based on its position relative to chert beds in T3. T3 and the upper part of the T2 member contain calcitized dolomites, while the lower part of T2 and T1 contain only dissolved dolomite. As the fluid went deeper in the TMF, it became weaker. Therefore, the fluid was too weak to develop dolomite calcitization process and instead only affected T1 and the lower part of T2 by dolomite dissolution. Overall, dolomite dissolution and dolomite calcitization didn't have a high impact on porosity evolution as the TMF isn't a highly dolomitized formation. The distribution of porosity (empty set), permeability (K), and reservoir-quality-index (RQI) of the TMF are stratigraphically controlled. The TMF represents the regressive system tract of a 3rd order depositional sequence, which is composed of seven 4th order cycles (i.e. deep lagoon cycles (DLC) and shallow lagoon cycles (SLC)). RQI, empty set, and K plots showed great fitting with the 4th order depositional-cycles as DLC has very poor reservoir properties (average empty set = 7.7%, average K = 0.17 mD, average RQI = 0.03), while SLC has fair reservoir properties (average 0 = 15.4%, average K = 2.64 mD, average RQI = 0.11). Reservoir quality contrast is controlled by two factors: (1) the reduced mud-content and increased grain-content in SLC compared with DLC resulted in increased primary interparticle porosity, and is governed by depositional energy; and (2) the higher primary interparticle porosity in SLCs compared with DLCs preferentially facilitated more infiltration of undersaturated meteoric fluids, resulting in enhanced grain dissolution. This is reflected on the higher proportion of moldic and vuggy porosity in SLCs compared with DLCs. The accurate assessment of the TMF micro-scale attributes and controls on reservoir quality in an outcrop analogue that occurs in close proximity to subsurface hydrocarbon producing intervals can provide important input for oilfield appraisal and enhanced oil recovery performance.",0,0,1
Cement,Reservoir Quality,"March, Rafael; Zhang, Shuo; Liu, Hui-Hai",Direct numerical simulation of density driven fingering flow: Towards a model to predict the spacing between halite fingers in hydrocarbon reservoirs,Halite cementation; Fingering flow; Numerical simulation; Finger spacing; The Rayleigh number,POROUS-MEDIA; SOLUTE TRANSPORT; ARA GROUP; CONVECTION; CEMENTATION; BOUNDARY,"Halite cementation is a major exploration risk in hydrocarbon reservoirs. Halite-cemented reservoir zones are characterized by extremely low porosity and permeability due to partial or complete occlusion of the pore space. Despite being a key process that affects the quality of the productive formation, a quantitative analysis of the physical processes responsible for halite cementation is still missing in the scientific literature. Brine reflux caused by temperature and density gradients is one of the main physical mechanisms responsible for the intrusion of salt in the pores of a productive formation. Physically, the dissolution of salt by the resident brine creates a zone of higher density which may give rise to the development of flow instabilities. In this work, we present a quantitative methodology for estimating the distribution of halite-cemented zones by numerically simulating unstable flows for different flow and rock parameters. The main non-dimensional parameter, the Rayleigh number, that governs the flow is identified. The impact of the Rayleigh number on finger distribution is investigated using a statistical methodology to obtain a finger spacing distribution. Finally, a simple relationship is developed between finger spacing and the Rayleigh number that may be used to predict finger spacing.",0,0,1
Cement,Reservoir Quality,"Arouri, Khaled R.; van Dijk, Clemens",Mapping solid reservoir bitumen by deconvoluting formation mechanism,Solid reservoir bitumen; Formation mechanism; Geochemistry; Fluid distribution; Reservoir quality prediction; Sandstone diagenesis,COMPACTION PROCESSES; SANDSTONE RESERVOIR; RELATIVE IMPORTANCE; POROSITY; CEMENTATION; REDUCTION; OFFSHORE; MATURITY; BASIN; OIL,"Solid reservoir bitumen is a geologic risk that controls reservoir quality and fluid distribution and has a profound impact on field development and near-field exploration. Understanding the exact mechanism responsible for the development of solid bitumen is therefore a prerequisite toward its proper quantification and mapping. A sandstone reservoir of an anticlinal gas condensate field was investigated geochemically, and data integrated with reservoir diagenetic history to explain abundant solid bitumen encountered within several meters immediately below a regional unconformity in crestal wells, as opposed to deeper sections and downdip wells. The reservoir is generally characterized by a similar sedimentological and diagenetic history across the field, with diagenetic illite grain coats and quartz cement occurring in both updip and downdip wells. The influx of gas condensates into the upper part of the preexisting oil reservoir, possibly facilitated by a major fault, appears to have caused thermodynamic disequilibrium, leading to de-asphalting and subsequent deposition of solid bitumen. Textural and radiometric age dating, integrated with fluid inclusion homogenization temperatures and basin modeling, suggests the initiation of bitumen deposition 129 Ma, immediately after the arrival of gas condensates into the reservoir. As the process was restricted to the uppermost part of the reservoir, it is possible that the solid bitumen, once developed, has improved sealing efficiency along the unconformity and the trapping of subsequent hydrocarbon charges in the underlying reservoir. Better reservoir quality can be inferred farther downdip in areas inaccessible to gas incursions and hence not affected by gas de-asphalting. Other processes, such as regional uplift-induced phase separation, in-reservoir thermal cracking, water-washing, and biodegradation, were also examined and found irrelevant to the formation of solid bitumen in question.",0,0,1
Cement,Reservoir Quality,"Chakraborty, Shantanu; Mondal, Samit; Chatterjee, Rima",Comprehensive workflow to quantify diagenetic cement from wireline logs of deep water east coast of India wells and rock physics modeling,Cementation; Neutron and density logs; Rock physics modeling; Core data,LITHOLOGY; RESERVOIR; TEMPLATE; BASIN,"Presence of diagenetic cement is common in deep-water siliciclastic reservoirs and largely affects reservoir quality. Hence, the quantification of cement volume is an integral part of the reservoir characterization workflow. Lab analysis of core samples provides the cement volume information used as input for rock physics modeling. In the absence of core sample analysis, use of analogous offset well information provides an approximate estimate of cement. In reality, most deep-water wells do not have core samples for lab analysis. Consequently, the availability of offset well information is sparse and sometimes unavailable. Hence, getting an accurate cement volume estimate for reservoir characterization is challenging. For a detailed analysis, it is desirable to have a continuous measurement of cement volume across the reservoir sand. Presence of a calibrated cement volume log for the entire reservoir improves rock physics modeling. In this work, petrophysical M-N lithology cross plot, which is widely used to identify lithologies, has been used to quantify the diagenetic cement present within the reservoir, where M is the density normalized sonic values and N is the density normalized neutron values. Here, the M and N has been used as M-Lithology (MLITH) and N-Lithology (NLITH). In estimating MLITH and NLITH values, compressional sonic, bulk density and neutron logs are used. Porosity estimated from neutron/density is useful to identify the type of cement. Whereas, sonic slowness values are more sensitive towards the amount of grain contact cements. Hence, the estimated values of MLITH and NLITH varies differently in the presence of diagenetic materials. These variations of MLITH and NLITH values are captured and converted to cement volume fractions. In the presence of core data, the lab analysis measurements are used to calibrate the cement volume log. Further, rock physics modeling results helps to validate the output. The results of the study add value by quantifying diagenetic cementation in the reservoir characterization process by mitigating the associated limitations due to absence of sufficient core data.",0,0,1
Cement,Cement Sheath,"Valov, A. V.; Golovin, S. V.; Shcherbakov, V. V.; Kuznetsov, D. S.",Thermoporoelastic model for the cement sheath failure in a cased and cemented wellbore,Cased wellbore; Cement sheath damage; Linear thermoporoelastic model; Prestress,FINITE-ELEMENT; BEHAVIOR; WATER,"In the paper, we analyze factors that can lead to a failure of the cement sheath of a cased wellbore. By using a fully coupled linear thermo-poro-elastic model, we describe mechanical compression of the casing by fluid pressure and inhomogeneous geological stresses together with heating or cooling of the casing relative to the reservoir temperature. Due to the characteristic small ratio of the well diameter to its length, we observe the 2D problem in the section perpendicular to the well axis by adopting the plane strain approximation. We model the construction of single-or double-casings of the well, at that, both casings can be non-centered relative to the well axis. The cement sheath can be loaded by a prestress appeared during the cement hydration. The model is implemented numerically using the finite element method (FEM). Although many articles consider individual factors of the cement sheath failure, in our paper all these factors are modeled in a complex. Among the triggering effects for the failure we distinguish the strong contrast of geological stresses, the prestress in the cement sheath coupled with the action of the temperature variation. We also found that the thermo-poroelastic coupling may lead to the significant growth of the pore pressure due to temperature changes when the pore pressure cannot dissolve either in the case of the very low permeability of cement or for the double-cased wellbore. In many situations, it is a combination of various factors that causes the failure of the cement sheath of the well, and not each factor separately.",0,0,1
Cement,Cement Sheath,"Taghipour, Ali; Ghaderi, Amir; Cerasi, Pierre; Gheibi, Sohrab",Novel laboratory setup for realistic wellbore cement and formation integrity studies,Well integrity; Cement integrity; Formation integrity; Experimental realistic setup,SHEATH INTEGRITY; ZONAL ISOLATION,"Oilfield wellbore integrity relies on a good well cement formulation, placement, and resistance to solicitations when aging, either due to chemical or stress changes. Requirements are that the cement sheath and plugs remain as proper hydraulic barriers for all foreseeable future. Thus, to qualify the cement formulations with respect to various types of stress changes, it is important to carry out these tests in the field relevant conditions in the laboratory. These tests will contribute to improved understanding of the limiting factors influencing the well integrity and assist in design of remediation strategies. Hence, a new experimental setup designed for studying near wellbore systems in field conditions is introduced. The setup comprises of an advanced X-ray cell with the possibility of three independent pressure controls of casing, pore and formation pressures. The experiments are carried out under simultaneous X-ray Micro-CT imaging allowing to monitor the in-situ mechanical changes. Numerical calculations in the finite element domain are carried out for the same test conditions with first results showing the evolution of radial cracks in the cement sheath and the formation rock submitted to excessive well pressures. The test results confirm with the numerical simulation. These results may provide valuable input for near-wellbore integrity assessments.",0,0,1
Cement,Cement Sheath,"Khodami, Eissa; Ramezanzadeh, Ahmad; Sharifi, Ali",The 3D simulation of the effect of casing standoff on cement integrity by considering the direction of horizontal stresses in one of the wells of Iranian oil fields,Casing standoff; Cement integrity; ABAQUS; Plastic strain; Horizontal stresses,,"Drilling engineers must conduct predictive tests before the occurrence of integrity issues to save time and money. A successful casing standoff helps boost well integrity and cement integrity, both of which are critical factors during a well's production life. The casing standoff is 100 percent in several books and computational simulations. However, it should be remembered that this standoff is never 100 percent, and the casing is still inclined to one side of the well wall. Also, with the use of centralizers, the casing shifts, and the standoff deviates from ideal conditions In this study, a 3D simulation was analyzed using ABAQUS Software, using the geomechanical modeling data and considering the well's environmental conditions. The effect of casing standoff on cement integrity was investigated using sensitivity analysis and parametric tests. According to the simulation results in the studied well, the plastic strain in the cement sheath increases as the casing standoff decreases, resulting in the highest strain at the cement-casing interface. The plastic pressure increases as the cement's narrow side face the direction of most minor horizontal tension. As a result, having adequate information about the conditions and direction of in-situ stresses is needed before driving the casing in the well drilling stage.",0,0,1
Cement,Cement Sheath,"Khodami, Eissa; Ramezanzadeh, Ahmad; Noroozi, Mehdi",Numerical modeling of oil well integrity with a particular view to cement (case study: Maroon Oilfield in southwest of Iran),Well integrity; Numerical modeling; Geomechanical model; Cement; ABAQUS,PORE PRESSURE; FAILURE; STRESS; PREDICTION; RESERVOIR; IMPACT,"Well integrity represents an objective/solution for protecting human life and environment while retaining oil production rate during the life of the well. Characterization of cement behavior plays an important role in ensuring the well integrity and can be effectively considered when it comes to the prevention of casing failure. In this research, firstly, petrophysical data at one of the wells drilled into Maroon Oilfield in southwest of Iran was used to build a one-dimensional geomechanical model of the formation encompassing the well, based on which geomechanical characteristics of the formation were estimated. Subsequently, mechanical parameters of the cement sheath used in the considered well and the friction parameters of the cement-formation contact surface were determined via laboratory tests on samples of the cement. Next, using the obtained data and considering the environmental conditions in the well, a reference numerical model was constructed for a particular section of the studied well utilizing ABAQUS Software followed by analyzing the wellbore stability under existing conditions. Finally, sensitivity analysis and parametric studies were performed to investigate the impact of friction parameters of contact surfaces, and mechanical properties of the cement on the well integrity. The results indicated that, higher Young's modulus and/or lower Poisson's ratio, cohesion, and friction angle in the cement sheath further contributed to larger plastic strains in the sheath. Moreover, with increasing the friction of formation-cement and cement-casing contact surfaces, plastic strain of the cement was observed to decrease. In the parametric analysis, the coefficient of friction between cement-formation and cement-casing has decreased by About 45% and 60%, respectively, and the amount of PEEQ in cement increases by up to 30 mm.",0,0,2
Cement,Cement Sheath,"Pagano, Arianna Gea; El Mountassir, Grainne; Lunn, Rebecca Jane",Performance of colloidal silica grout at elevated temperatures and pressures for cement fracture sealing at depth,Colloidal silica; Well decommissioning; Plug &amp; abandonment; Wellbore integrity,WELL INTEGRITY,"Hydrocarbon well decommissioning requires the long-term sealing of abandoned wells. Current plug and abandonment (P&A) operations are not always able to address all potential fluid migration pathways, resulting in the possible upwards migration of hydrocarbons from formations penetrated by the wellbore. The development of innovative materials to improve well sealing remains a major challenge. This paper presents a proof of concept for the use of colloidal silica (CS)-based grout to improve the sealing performance of P&A operations. CS is a non-toxic suspension of silica nanoparticles (<100 nm) undergoing gelation upon destabilisation. Due to its excellent penetrability and controllable gel time, CS has the potential for repairing fine-aperture cracks within the cement sheath, at the cement/casing interface, or within a cement plug, where the penetration of cementitious grouts is restricted due to their relatively large particle size. In this study, the suitability of CS grout for deployment up to 1500 m depth was successfully demonstrated. Firstly, a range of CS grout mixes were investigated to test the feasibility of grout emplacement considering a timescale of 2 h for pumping operations from the surface to depth. Secondly, to investigate the sealing performance, the CS grout was injected into fractured cement cores (0.2 and 0.5 mm fracture aperture) and exposed to pressure and temperature conditions simulating downhole scenarios up to 1500 m depth (based on gradients for North Sea, UK). Fracture permeability upon water injection was assessed pre- and post-treatment. This work found that permeability values after treatment were reduced by three orders of magnitude, thus confirming the potential of CS grout for repairing fine-aperture cracks.",0,0,3
Cement,Cement Slurry,"Beltran-Jimenez, K.; Skadsem, H. J.; Sunde, J. K.; Gardner, D.; Wolterbeek, T. K. T.; Cornelissen, E. K.; Keultjes, W. J. G.",Restoration of annular zonal isolation using localized casing expansion (LCE) technology: Treatment of near-horizontal test sections containing a free-water channel,Well integrity; Well abandonment; Sustained casing pressure; Surface casing vent flow; Annular fluid migration; Casing expansion,CEMENT PASTE; GAS; BEHAVIOR,"Fluid migration behind casings is a well integrity problem that can result in sustained casing pressure, undetected leaks to the environment, and potentially very difficult remediation attempts. Traditional methods for treating annular fluid migration are perf-and-squeeze cementing or section milling followed by recementing. The main disadvantage of the former is the limited penetrability of cement slurry into narrow cracks and microannuli, while for the latter it is the requirement of a full rig to perform the operation. Casing expansion is a recent alternative remediation technology that involves imposing a permanent radial expansion of the casing and external cement layer, with the purpose of mechanically closing pathways for migrating fluids. A necessary requirement for the treatment to be effective is that the annular cement is confined between casings or between casing and competent rock formations, such that the cement can sustain significant mechanical strains without failure. Recent laboratory experiments and field trials have shown casing expansion to be a promising alternative to traditional treatment methods. We build on these insights and perform controlled treatment experiments involving a 7-in Local Expander tool and full-scale cemented annulus test assemblies, which contained much larger-scale defects than previously tested. Prior to treatment, the test assemblies had continuous migration channels on the top side of the cement, leading to high effective permeabilities ranging from approximately 80 to hundreds of darcy. The origin of the defects was likely separation of free water from the cement slurry, which is considered a relevant failure mode for primary cementing of inclined wellbores. We study the effect of imposing single and multiple local dents on the annular seepage rates, and probe for potential alteration of the cement and casing properties using Vickers hardness testing. We find that casing expansion can be highly effective in treating relatively major defects in cemented annuli, even when the defect is several millimeters wide and located adjacent to the outer casing. The effectiveness of the treatment is found to be linked to the degree of casing expansion and the initial condition of the annular cement. The deformed cement shows a tendency toward increased Vickers hardness, which is likely linked to densification of the cement microstructure. Vickers hardness testing of casing steel indicated no significant changes in hardness at the dent locations compared to average hardness values away from these points.",0,0,0
Cement,Cement Slurry,"Yuan, Bin; Li, Junfu; Xu, Bihua; Su, Yu; Li, Bin; Yang, Lin",Managed wellhead backpressure during waiting setting of managed pressure cementing,Managed pressure cementing; Narrow safe density window; Hydration shrinkage; Filtration shrinkage; Gel strength; Hydrostatic pressure,LOST CIRCULATION; HYDRATION; TEMPERATURE; REDUCTION,"Managed pressure cementing (MPC) has been successfully used to reduce risk lost circulation and improve cementing quality in wells with a narrow safe pressure window. However, during the waiting setting period of MPC, the magnitude of the managed well backpressure is still based on experience, which results in a high risk of leakage or gas channeling especially in formations with a narrow safe density window. Therefore, a backpressure managing method is proposed here based on a model we built for calculating wellhead backpressure. This model was used to analyze the effect of cement slurry, temperature and wellbore pressure on wellhead backpressure. The results show that hydration, filtration shrinkage and gel supporting are essential to reduce wellbore pressure, although hydration is less effective compared with the latter two on pressure reduction. The magnitude and duration of wellhead backpressure depend on the extent of volume shrinkage and the gel strength development of cement slurry. Latex-cement slurry requires minimal wellhead backpressure with the shortest duration. Temperature and wellbore pressure greatly impact wellhead backpressure with temperature playing a more dominant role.",0,0,0
Cement,Cement Slurry,"Krezinksi, Cody; Panchmatia, Parth; Genedy, Moneeb; Nair, Sriramya; Juenger, Maria; Usher, Craig; van Oort, Eric",Magnetorheological cements for plug setting control in oil and gas wells,Cement slurry; Electromagnetic tool; Magneto-rheology; Thickening time; Compressive strength; Pressure sealing ability; Rheology,,"Magnetorheological-blended cements (MRBC) are promising materials for plugging and abandonment applications in oil and gas wells because their viscosity can be reversibly controlled through the addition of magnetic particles and application of an external magnetic field. In this study, the fresh state and hardened state properties of MRBC with varied amounts of additives were investigated, including fresh slurry viscosity, thickening time, and compressive strength. A new test method was developed to determine the pressure a liquid MRBC column can hold while activated by a magnetic field. Results showed that the apparent viscosity of MRBC formulations increased as the content of magnetic particles increased, while thickening time was reduced. Compressive strengths of MRBC were found to be similar to standard neat slurries, with MRBC showing slightly higher early strength. The newly developed pressure testing method demonstrated that the MRBC fluid columns tested were able to hold more than the minimum goal of 345 kPa (50 psi) of pressure before movement was indicated. This MRBC characteristic can be exploited to form temporary and permanent cement barriers both inside casing and open hole, as well as in casing annuli. For the latter application, it was shown that sufficient magnetic field strength (in the range of 0.15T-0.25T) can be generated in the annular space outside of a stainless steel casing with the magnet located inside the casing, to still effectively magnetize the MRBC slurry.",0,0,1
Cement,Cement Slurry,"Santiago, R. C.; Costa, B. L. S.; Silva, F. P. F.; Medeiros, R. L. B. A.; Nascimento, R. A. B.; Aum, P. T. P.; Freitas, J. C. O.",Sustainable cement blends for oil well steam injection using rice husk ash,Oil well cementing; High temperature; Retrogression; Rice husk ash; Alternative material,,"This study involves applying Rice Husk Ash (RHA), a sustainable source of silica, as an alternative to the use of Silica Flour (SF) in well cementing prior to steam injection. Slurries were prepared containing 20% and 30% BWOC of RHA along with standard slurries without additives and with 40% BWOC of SF. Behavior of the slurries was investigated using X-ray diffraction (XRD), thermogravimetric analysis (TGA), scanning electron microscopy (SEM) and uniaxial compressive strength assays. The results indicate that adding 30% of RHA and silica flour makes it possible to maintain compressive strength in the cement, and presents C-S-H crystalline phases rich in silica (Xonotlite and Tobermorite), as demonstrated by XRD, TGA and SEM. That makes it more attractive than standard slurry with 20% of RHA. That substitution makes slurry RHA competitive with SF and interesting for industry, due to its high content of renewable silica along with a low production cost.",0,0,2
Cement,Cement Slurry,"Yang, Mou; Luo, Hao; Xie, Rongxuan; Wu, Pengcheng; Yang, Mingzheng; Yang, Lvchao; Xue, Hu",Estimating and optimizing wellbore pressure during primary cementing in low pressure and leakage formations,Circulating pressure; Cementing operation; Low pressure and leakage formations; Mathematical model; Computational fluid dynamics,NON-NEWTONIAN FLUIDS; POWER-LAW FLUID; HERSCHEL-BULKLEY; ECCENTRIC ANNULI; DRILLING-FLUIDS; TURBULENT-FLOW; LAMINAR; CIRCULATION; TRANSITION; BEHAVIOR,"In most realistic situations, casing eccentricity and various fluids injected during primary cementing lead to a significant difference in fluid flow and circulating pressure, compared with a single fluid flowing in the concentric annulus. Ignoring the effect of eccentricity and fluid rheological model on the wellbore circulating pressure results in an inaccurate evaluation and leads to formation leakage, especially for low pressure and leakage formations. To overcome this challenge, firstly, rheological models of various fluids were analyzed using experimental data, including drilling fluid, spacer, and cement slurry. Secondly, the modified correlations of frictional pressure losses for Herschel-Bulkley and Power Law fluids in the eccentric annulus were developed, using the simulation data of computational fluid dynamics software (CFD) and considering the effects of flow behavior index, pipe diameter ratio, and casing eccentricity on the frictional pressure losses. Finally, based on the developed mathematical models, the optimal method of primary cementing and evaluation results were presented, analyzed, and tested in the field with great success. The results demonstrated that the drilling fluid and spacer fluid had the highest goodness of fit for the Herschel-Bulkley model, and the cementing slurry was suitable for the Power Law model. The ratio coefficient of pressure loss in the eccentric to concentric annulus decreased with a decrease of hole size and an increase of casing eccentricity. A 50 percent reduction in frictional pressure loss was evaluated when the casing lies on the borehole wall. Comparing the calculations of the developed correlation with the published correlation in the literature reveals a more accurate evaluation of friction pressure losses in the analyzed case. Combined with the realistic situation of a test well, the density, flow rate, and returning depth of the lead cement slurry were recommended as 1.5 g/cm(3), 0.5 m(3)/min and 4100 m, respectively, according to the leakage pressure of 65.6 MPa that was calculated by the developed mathematical model. Most importantly, the developed method in this paper can accurately predict the variation characteristics of wellbore pressure during the primary cementing process and provide effective guidance in managing downhole pressure in low pressure and leakage formations by real-time adjustment of the most effective and controllable operation parameters.",0,0,3
Cement,Thin Sections,"Tavakoli, Vahid; Hassani, Danial; Rahimpour-Bonab, Hossain; Mondak, Alireza","How petrophysical heterogeneity controls the saturation calculations in carbonates, the Barremian-Aptian of the central Persian Gulf",Tight carbonate reservoir; Water saturation; Archie equation; Archie coefficients; Heterogeneity,CAPILLARY-PRESSURE CURVES; SEQUENCE STRATIGRAPHY; CEMENTATION FACTOR; ARCHIES EXPONENTS; DARIYAN FORMATION; FLOW UNITS; RESERVOIR; EXAMPLE; CLASSIFICATION; PERMEABILITY,"Water saturation calculations are among the most important aspects of reservoir characterization. Despite this importance, the effects of these calculations on the resulted oil in place remain unclear. Extreme heterogeneity in most of the carbonate reservoirs strongly affects the coefficients of the Archie equation and resulted water saturation. Therefore, a practical method to evaluate and manage the heterogeneity of such reservoirs, greatly improves the reliability of the final results. In this study, porosity, permeability, thin sections data, well logs and saturation tests of Barremian-Aptian carbonate Dariyan Formation in the central Persian Gulf have been used. Both core and reservoir scale techniques including flow zone indicator, Winland R-35, electrofacies and stratigraphically modified Lorenz plot were used to evaluate the heterogeneity. Archie coefficients were arranged in different rock types. Results show that flow zone indicator is the most accurate technique to manage the heterogeneity of the reservoir with higher R-2 value between porosity and permeability. The cementation factor was measured for each unit and the amounts of water saturation was calculated using deterministic analysis. Water saturation also calculated with the constant coefficients, which are routinely used in formation evaluation. The average S-w amount for constant Archie coefficients method was determined as 0.62, whereas it is 0.73, 0.80, 0.70, and 0.77 in flow zone indicator method, Winland R-35 technique, stratigraphically modified Lorenz plot and electrofacies determination, respectively. The results demonstrate that calculating water saturation with constant Archie coefficients leads to slightly lower water saturation values, resulting in higher oil saturations and overestimating the oil in place.",0,0,0
Cement,Thin Sections,"Nunes, Marcos; Valle, Bruno; Borghi, Leonardo; Favoreto, Julia; Mendes, Marcelo","Multi-scale and multi-technique characterization of hybrid coquinas: A study case from the Morro do Chaves Formation (Barremian-Aptian of Sergipe-Alagoas Basin, Northeast Brazil)",Multi-scale reservoir characterization; Rock typing; Upscaling; Petrophysics; Heterogeneity; Coquinas,GEOLOGICAL ATTRIBUTES; ARCHIES EXPONENTS; CARBONATE ROCKS; FLUID MIGRATION; CAMPOS BASIN; SEDIMENTARY; POROSITY; FAULTS; CLASSIFICATION; EVOLUTION,"The coquinas are carbonate rocks with variable content of siliciclastics and have a complex porous framework that implies an issue for their characterization as reservoirs. Furthermore, these rocks are considered important reservoirs due to the giant accumulations in the Campos and Santos basins (Coqueiros and Itapema formations, respectively), increasing the interest in understanding and characterizing these complex and heterogeneous lithologies. In this context, this study aims to introduce a novel method of petrophysical characterization of coquinas through a multi-technique and multi-scale approach in a continuous well core of approximately 135 m, drilled in the ""Atol Quarry"", Sa similar to o Miguel dos Campos County, Alagoas State. Based in mineralogical content, x-ray attenuation and pore type, seven tomofacies were defined using computerized tomography and allowed a representative sampling (plugs and thin sections). Five rock types were defined based textural aspects (tomofacies and petrography) and petrophysical data (routine core analysis and micro-computerized tomography). The rock types were compared to well logs, establishing boundary values and distributed along the whole well, in an upscaling process from thin-section and plugs (microscopic scale) to the well core (macroscale). The Morro do Chaves Formation core was divided into two portions: upper portion, with better reservoir quality and greater influence of mineral dissolution; and lower portion, a poor reservoir quality portion influenced by cementation processes. The upscaling method using the concepts of tomofacies and rock types proved to be a successful way to improve the understanding of reservoir characterization in heterogeneous of complex limestone successions, which can improve the recovery factor and aid in the field development.",0,0,1
Cement,Thin Sections,"Kadyrov, Rail; Nurgaliev, Danis; Saenger, Erik H.; Balcewicz, Martin; Minebaev, Rezit; Statsenko, Evgeny; Glukhov, Mikhail; Nizamova, Aigul; Galiullin, Bulat",Digital rock physics: Defining the reservoir properties on drill cuttings,Cuttings; Core; Carbonates; Pore structure; Digital rock physics,TRANSPORT; CFD; PARAMETERS; PROGRAM; OIL,"Well drilling with core extraction is one of the most expensive procedures in the oil industry. The potential alternative, which may open opportunities for cost-efficient acquisition of petrophysical data, can be an approach based on digital analysis of drill cuttings. The main purpose of this research was to evaluate the possibility of using digital cuttings analysis and rock physics for reservoir properties evaluation. The carbonate samples of core and cuttings were simultaneously collected from the same intervals during the drilling of deviated wells in the Carboniferous reservoir of the oil deposit in the Republic of Tatarstan, Russia. Based on the core analysis using the optical study of thin sections and XRD, we investigated sedimentological and mineralogical features and classified all lithotypes of well intervals. The standard samples were produced from all defined facies and their reservoir properties were studied in routine tests. The largest cuttings from each well interval were separated and their structures were compared using mu CT with core subsamples of the same intervals. We assessed the changes of cuttings structure occurring in the drilling process, which include the colmatation of the pore space with drilling fluid and disintegrated rock particles and the formation of secondary fractures. Detailed analysis of cuttings from one well interval consisting of the border between the facies of high porous grainstones with packstones and dense micrite limestones demonstrated that high porous varieties were eroded in the drilling process. The analysis of chemical composition using XRF-mapping, XRD and SEM with EDS showed that most of the cuttings were constituted by disintegrated rock particles or form elements (e.g. separate fusulinids) cemented by drilling mud. However, more durable cuttings from dense micrite limestones facies were generally retained their dominant calcite composition and original rock structure, with only secondary fractures. Finally, we analyzed pore space properties and performed digital simulations of wave propagation velocities to compare the characteristics of these cuttings and core subsamples from this lithotype, scanned in the same mu CT settings. The results demonstrate close characteristics of porosity 0.08-0.6%, dominant pore sizes 1-60 mu m and velocities Vp = 6130-6240 m/s, Vs = 3180-3230 m/s. However, the comparison of obtained values with measured on standard samples shows a significant difference, which is caused by deviation from REV. The potential use of cuttings for assessing reservoir and petrophysical properties can be possible in case of provision with the factors of cuttings structure alteration, representativity of samples, as well as optimization for these purposes of the drilling process with cuttings selection.",0,0,1
Cement,Thin Sections,"Zhao, Xiaodong; Zhang, Shiqi; Yang, Shaochun; Ju, Xiaoyu; Chen, Gangqiang; Zhang, Xiaotong; Khan, Danish; Zhang, Yaxuan; Zhang, Jiankun","Controlling factors of carbonate cement and its influence on oil-water distribution of the Neogene Shawan Formation in the northern Chepaizi area, Junggar Basin, NW China",Junggar basin; Reservoir characteristics; Carbonate cements; AxioVision image analysis; Diagenetic environment,SANDSTONE; RESERVOIR; DIAGENESIS; HISTORY,"The distribution of physical property of the Neogene Shawan Formation(N1s) in the north of Chepaizi area (Abbreviated as ""Chebei area"") is characterized by ""double peak"", which is mainly related to carbonate cements in the reservoirs. It is observed that the large amounts of early carbonate cements are present in thin sections, which are inhomogeneously filled in some primary intergranular pores and caused strong heterogeneity of the reservoir. On the basis of convent calculate of carbonate cement in core, AxioVision image analysis with multiple times and multiple fields of view was used to supplement the calculation of carbonate cement content, and the relative error compared with the core measurement result was -0.14, which effectively compensated for the lack of core measurement data points. The content of carbonate cement has been characterized by ""higher in the north area and lower in the south area"" on the plane. The carbonate cement is formed in closed diagenetic environment with good sealing ability and water body stagnated alternately. The closed diagenetic environment of the Shawan formation in Chebei area primed the environmental foundation for the growth of carbonate cements, and the abundant Ca2+ in the formation water primed the material foundation for the growth of carbonate cements. The difference in Ca2+ content in formation water determines the distribution difference of carbonate cements, and the diagenetic environment is the controlling factor for the development of carbonate cements. The complex oil-water distribution in the study area is principally related to the carbonate cementation. The super heavy oil with high viscosity cannot enter the low porosity and permeability reservoir with tough cementation, which is prone to the phenomenon of oil-water inversion.",0,0,1
Cement,Thin Sections,"Kelishami, Shervin Bahramali Asadi; Mohebian, Reza; Salmian, Omidreza","A comprehensive perspective on pore connectivity and natural fracture analysis in Oligo-Miocene heterogeneous carbonates, southern Iran",Pore connectivity; Permeability; Fracture aperture; Artificial neural network (ANN); Porosity; Image log; Velocity deviation log (VDL),POROSITY; TECTONICS; LOG,"Ascertaining the pore connection criterion has always been a challenge for geoscientists. In the framework of this research, an attempt was made to study the pore connectivity in a heterogeneous carbonate rock by combining several techniques. Pore types and rock facies were investigated for 321 thin sections. The abundance of connected porosities, cementation type and intensity which significantly control the matrix pore connectivity were specified on thin sections and finally a connectivity log was extracted that showed an accurate result on poroperm cross-plots. Most of the porosity volumes were related to interparticle, vuggy and moldic porosities which are microscale. The velocity deviation log, estimated in four wells, indicates the presence of micro porosity, which is consistent with the results of thin-sections. Zero velocity deviation is usually associated with the predominant presence of micro-pores. Different permeability values in identical lithological facies, as well as micro-fracture markers, prompted us to conduct more extensive research on fractures. FMI analysis proved that the studied reservoir is intensively fractured. The recorded high permeability in a sample with low matrix connectivity is specifically a fracture indication. Fracture apertures vary from microscale (<50 mu m) to 12.5 mm and calculated fracture density is raised up to 2 fractures per meter. Determined fractured intervals are very consistent with mud-loss information, for instance, a complete loss has been reported in the fault zone identified in well B. The detected fractures somewhat follow the main Zagros fault trend (NW-SE). Eventually, calculated connectivity was predicted in other wells using Artificial Neural Network (ANN) and a 3D model was constructed with respect to seismic attributes which gives a precise perspective of pore connection distribution throughout the studied field.",0,0,2
Cement,Numerical Simulation,"Muravleva, Ekaterina A.; Derbyshev, Dmitry Yu; Boronin, Sergei A.; Osiptsov, Andrei A.","Multigrid pressure solver for 2D displacement problems in drilling, cementing, fracturing and EOR",Multigrid; Hydraulic fracturing; Cementing; Numerical modeling; Fast linear solver; BiCGStab,WELLBORE COMPLETION FLUIDS; ANNULAR DISPLACEMENTS; NUMERICAL-SIMULATION; MUD REMOVAL; OIL-WELL; FLOW; PLACEMENT; MODEL; TRANSPORT,"Numerical simulators for the design of oilfield services technologies are required to be fast and robust, hence the implementation of underlying mathematical models is expected to be highly efficient. We present an optimized numerical algorithm based on the multigrid approach for solving the pressure equation in 2D problems of fluid-fluid displacement. This type of problems arise in oilfield services applications, such as drilling, cementing, hydraulic fracturing and EOR. The displacement of fluids with different properties in a narrow annular gap (drilling, cementing) or a slot (hydraulic fracturing, production) is governed by the 2D width-averaged model in the lubrication approximation. In numerical implementation, the most time-consuming is the elliptic Poisson pressure equation, which has coefficients with discontinuities (jumps) in the case of displacement of fluids with viscosity contrast. Specifically for this case of discontinuous coefficients, we designed and implemented numerically the black-box multigrid algorithm, which resolves the divergence issue typical of standard realization of multigrid algorithm using bilinear prolongation operators. The algorithm is tested on a number of matrices corresponding to discretization of elliptic equation at rectangular staggered meshes with different resolution. The performance of the algorithm is compared against several other sparse solvers available for commercial use: smoothed aggregated algebraic multigrid (PyAMG software package), direct sparse solver from Intel MKL library (DSS), Bi-Conjugate Gradient-Stabilized solver preconditioned by ILUT factorization implemented into BLAS package, and our in-house Conjugated Gradient algorithm preconditioned by ILU(2) factorization. It was found that the performance of the black-box multigrid solver is significantly higher (from 7x to 30x in terms of CPU time depending on the mesh resolution) as compared to the closest solver under consideration, which allows us to recommend this solver for implementation into existing 2D drilling simulators, fracturing design tools, cement placement and production simulators.",0,0,0
Cement,Numerical Simulation,"Taghipour, Ali; Ghaderi, Amir; Cerasi, Pierre; Gheibi, Sohrab",Novel laboratory setup for realistic wellbore cement and formation integrity studies,Well integrity; Cement integrity; Formation integrity; Experimental realistic setup,SHEATH INTEGRITY; ZONAL ISOLATION,"Oilfield wellbore integrity relies on a good well cement formulation, placement, and resistance to solicitations when aging, either due to chemical or stress changes. Requirements are that the cement sheath and plugs remain as proper hydraulic barriers for all foreseeable future. Thus, to qualify the cement formulations with respect to various types of stress changes, it is important to carry out these tests in the field relevant conditions in the laboratory. These tests will contribute to improved understanding of the limiting factors influencing the well integrity and assist in design of remediation strategies. Hence, a new experimental setup designed for studying near wellbore systems in field conditions is introduced. The setup comprises of an advanced X-ray cell with the possibility of three independent pressure controls of casing, pore and formation pressures. The experiments are carried out under simultaneous X-ray Micro-CT imaging allowing to monitor the in-situ mechanical changes. Numerical calculations in the finite element domain are carried out for the same test conditions with first results showing the evolution of radial cracks in the cement sheath and the formation rock submitted to excessive well pressures. The test results confirm with the numerical simulation. These results may provide valuable input for near-wellbore integrity assessments.",0,0,1
Cement,Numerical Simulation,"March, Rafael; Zhang, Shuo; Liu, Hui-Hai",Direct numerical simulation of density driven fingering flow: Towards a model to predict the spacing between halite fingers in hydrocarbon reservoirs,Halite cementation; Fingering flow; Numerical simulation; Finger spacing; The Rayleigh number,POROUS-MEDIA; SOLUTE TRANSPORT; ARA GROUP; CONVECTION; CEMENTATION; BOUNDARY,"Halite cementation is a major exploration risk in hydrocarbon reservoirs. Halite-cemented reservoir zones are characterized by extremely low porosity and permeability due to partial or complete occlusion of the pore space. Despite being a key process that affects the quality of the productive formation, a quantitative analysis of the physical processes responsible for halite cementation is still missing in the scientific literature. Brine reflux caused by temperature and density gradients is one of the main physical mechanisms responsible for the intrusion of salt in the pores of a productive formation. Physically, the dissolution of salt by the resident brine creates a zone of higher density which may give rise to the development of flow instabilities. In this work, we present a quantitative methodology for estimating the distribution of halite-cemented zones by numerically simulating unstable flows for different flow and rock parameters. The main non-dimensional parameter, the Rayleigh number, that governs the flow is identified. The impact of the Rayleigh number on finger distribution is investigated using a statistical methodology to obtain a finger spacing distribution. Finally, a simple relationship is developed between finger spacing and the Rayleigh number that may be used to predict finger spacing.",0,0,1
Cement,Numerical Simulation,"Liu, Peng; Wu, Hongliang; Yang, Shubo; Zhao, Qiqi; Wu, Jinping; Li, Xin",A dual-frequency acoustic measurement method for detecting fluid-filled channels at two boundaries in cased holes,Dual-frequency; Acoustic logging; Fluid-filled channel; Casing wave; Numerical simulation,NUMERICAL-SIMULATION; WAVE-FIELD; LOGS,"The recognition of fluid-filled channels in cased holes is significant for the safety production of oil and gas wells. The fluid-filled channel at the cement-formation boundary is more difficult to be detected than that at the casing-cement boundary. To solve the key technical problem, a dual-frequency acoustic measurement method is proposed to obtain the cementation state of the two interfaces at the same time. The related theory is that the casing wave amplitude from the low-frequency source is sensitive to the channel at both two boundaries, but that from the high-frequency source is only sensitive to the channel at the casing-cement boundary. Therefore, high amplitudes of the casing waves from both two sources represent a channel on the casing-cement boundary, high amplitude from the low-frequency source but low amplitude from the high-frequency source represent a channel on the cement-formation boundary, and low amplitudes from both two sources represent no channel. Subsequently, numerical simulations are performed to examine the effects of several critical parameters on the dual-frequency acoustic measurement. The results show that the best combination of the measurement system is one low-frequency source at 10 kHz together with one high-frequency source at 150 kHz. For the low-frequency source, the casing wave amplitude increases obviously with the increasing channel thickness, regardless of the channel position. The increase of the cement thickness and the casing size damps out the casing wave. For the high-frequency source, the casing wave amplitude is little affected by these parameters except for the casing-cement channel. Moreover, the dual-frequency acoustic measurement method is suitable for common sandstone and shale formations. The findings of this study provide a theoretical foundation for next-generation cementing-quality-evaluation tool development.",0,0,2
Cement,Dolomite,"Bahrehvar, Mohammad; Mehrabi, Hamzeh; Akbarzadeh, Samira; Rahimpour-Bonab, Hossain",Depositional and diagenetic controls on reservoir quality of the uppermost Jurassic-Lower Cretaceous sequences in the Persian Gulf; a focus on J-K boundary,Manifa-Yamama formations; Reservoir facies; Hydraulic flow units; Jurassic-Cretaceous boundary; Persian Gulf,FAHLIYAN FORMATION; DARIYAN FORMATION; MIDDLE-EAST; STRATIGRAPHY; BASIN; GEOCHEMISTRY; ZAGROS; IRAN; PALEOCLIMATE; MICROFACIES,"This study presents reservoir characterization of the uppermost Jurassic-Lower Cretaceous successions of the Manifa and Yamama formations in four wells in the Persian Gulf. Detailed sedimentological, petrophysical and geochemical analyses are integrated to evaluate the controlling factors on reservoir quality of these sequences. Microfacies analysis has resulted in the recognition of 10 facies types deposited in lagoon, algal mounds, shoal, and open marine settings. Micritization, dissolution, various types of cementation, dolomitization, and compaction are notable diagenetic alterations indicating marine/hypersaline, meteoric and shallow to deep burial realms. Stable carbon and oxygen isotopic compositions indicate a meteoric diagenetic alteration at the topmost part of Manifa unit, beneath the Jurassic-Cretaceous (J-K) disconformity. Sequence stratigraphic analysis led to the identification of four transgressive-regressive (T-R) sequences in the Yamama Fm. and a regressive hemi-sequence in the Manifa unit. Reservoir quality study resulted in the recognition of eight hydraulic flow units and four types of reservoir facies with specific and predictable sequence stratigraphic framework. Dissolved grain-dominated shoal facies at the upper part of regressive systems tracts and algal reef/mound facies in transgressive systems tracts provide the best reservoir units of the studied sequences. Microporous mud-dominated facies of open marine settings are dominant reservoir facies in the upper Yamama unit, with moderate to low reservoir quality.",0,0,0
Cement,Dolomite,"El-Yamani, Mahmoud Samir; Al-Ramadan, Khalid; Cantrell, Dave","Diagenetic controls on porosity evolution and reservoir quality of an outcrop analogue of the Jurassic carbonate reservoirs in the Arabian Plate: An example from the Middle Jurassic Tuwaiq Mountain Formation, Central Saudi Arabia",Carbonate-diagenesis; Chert-replacing-evaporites; Dolomitization; Dolomite-calcitization; Porosity-evolution; Tuwaiq Mountain formation,DEPOSITIONAL-ENVIRONMENTS; STAINING TECHNIQUE; SILICA DIAGENESIS; DOLOMITE; DEDOLOMITIZATION; LIMESTONE; CLASSIFICATION; MICROFACIES; DISSOLUTION; JUBAILA,"The Middle Jurassic Tuwaiq Mountain Formation (TMF; formed of three members, from bottom to top T1, T2, and T3) represents one of the primary conventional and unconventional reservoirs to be assessed in Saudi Arabia. It is considered as a tight carbonate reservoir in the Jafurah Basin and conventional reservoir in the Arabian Basin. Here, we investigate the depositional, diagenetic, and stratigraphic impact on reservoir quality and porosity evolution of the TMF through an integrated petrographical, geochemical and petrophysical analyses on outcrop samples. The TMF has a complex diagenetic history including micritization, dissolution, recrystallization and neomorphism, meteoric cementation, evaporite precipitation, dolomitization, silicification, dolomite dissolution and calcitization. Dolomitization occurred via a hypersaline fluid mechanism, based on texture, association with evaporites, and Sr concentration. X-ray diffraction results support chert replacing evaporite as the mechanism of the two chert beds in the T3 member due to the presence of anhydrite relics in their samples. This replacement formed the necessary Ca2+ rich fluid for dolomite dissolution and calcitization. Therefore, dolomite calcitization occurs locally and is stratigraphically controlled based on its position relative to chert beds in T3. T3 and the upper part of the T2 member contain calcitized dolomites, while the lower part of T2 and T1 contain only dissolved dolomite. As the fluid went deeper in the TMF, it became weaker. Therefore, the fluid was too weak to develop dolomite calcitization process and instead only affected T1 and the lower part of T2 by dolomite dissolution. Overall, dolomite dissolution and dolomite calcitization didn't have a high impact on porosity evolution as the TMF isn't a highly dolomitized formation. The distribution of porosity (empty set), permeability (K), and reservoir-quality-index (RQI) of the TMF are stratigraphically controlled. The TMF represents the regressive system tract of a 3rd order depositional sequence, which is composed of seven 4th order cycles (i.e. deep lagoon cycles (DLC) and shallow lagoon cycles (SLC)). RQI, empty set, and K plots showed great fitting with the 4th order depositional-cycles as DLC has very poor reservoir properties (average empty set = 7.7%, average K = 0.17 mD, average RQI = 0.03), while SLC has fair reservoir properties (average 0 = 15.4%, average K = 2.64 mD, average RQI = 0.11). Reservoir quality contrast is controlled by two factors: (1) the reduced mud-content and increased grain-content in SLC compared with DLC resulted in increased primary interparticle porosity, and is governed by depositional energy; and (2) the higher primary interparticle porosity in SLCs compared with DLCs preferentially facilitated more infiltration of undersaturated meteoric fluids, resulting in enhanced grain dissolution. This is reflected on the higher proportion of moldic and vuggy porosity in SLCs compared with DLCs. The accurate assessment of the TMF micro-scale attributes and controls on reservoir quality in an outcrop analogue that occurs in close proximity to subsurface hydrocarbon producing intervals can provide important input for oilfield appraisal and enhanced oil recovery performance.",0,0,1
Cement,Dolomite,"Guo, Ruixin; Zhang, Shaonan; Wang, Kun; Han, Meimei; Ding, Xiaoqi","Multiphase dolomitization and hydrothermal alteration of the Upper Cambrian-Lower Ordovician carbonates in the Gucheng uplift, Tarim Basin (NW China)",Multiphase dolomitization; Dolomitizing fluids; Hydrothermal alteration; Hydrothermal dolomite reservoirs,DOLOMITE RESERVOIR FACIES; PENESALINE SEA-WATER; FLUID-FLOW; ISOTOPE GEOCHEMISTRY; BURIAL DOLOMITIZATION; PLATFORM CARBONATES; FORMATION MECHANISM; PRESQUILE BARRIER; ORIGIN; SEDIMENTARY,"The thick Upper Cambrian-Lower Ordovician carbonates of the Gucheng uplift (southeastern Tarim Basin, northwestern China) have been extensively dolomitized, leading to the formation of massive dolomite reservoirs. The origins of different dolomites and their original fluids were studied based on an integrated analysis of petrology, geochemical data (C, O, and Sr isotopes) and fluid inclusion assemblages (FIAs). The D1 (very finely to finely crystalline planar-e/s dolomite) and the D2 (finely to medium crystalline planar-s/a dolomite) dolomites were formed from the mesosaline to penesaline seawater in the subsurface to shallow burial stage. The increasing temperatures and changes of dolomitizing fluid properties led to the formation of different textures and distributions. Both D1 and D2 dolomites, compared to the matrix limestone, show no obvious improvements in porosity, which indicates that early dolomitizations did not create or preserve the primary pores. CD1 (finely to medium crystalline nonplanar-e/s dolomite) and CD2 (medium to coarsely crystalline nonplanar saddle dolomite) dolomites are dolomite cements of hydrothermal alteration at the deep burial stage. Due to changes in temperature and Mg2+ concentrations of the hydrothermal fluids, the precipitation of CD1 and CD2 dolomites exhibited different textures and filling sequences. In the limited space of matrix dolomite, hydrothermally altered dolomite was dominated by D3 (medium to coarsely crystalline nonplanar-a dolomite). The late calcite fillings were precipitated on account of decreasing Mg2+ concentration at the end of the hydrothermal alteration. Hydrothermal fluids, depleted in Mg2+ and enriched in silica, could be deep-basinal brines driven by the strongly transpressional faults from the Late Caledonian to Early Hercynian. Compared to D1 and D2 dolomites, the higher porosities in hydrothermally altered dolomite indicate that hydrothermal fluids are constructive to the formation of reservoirs. Hydrothermal alteration products showed obvious differences between the dolomite and limestone, and led to different performance in physical characteristics. Hence, the hydrothermally altered reservoirs in the eastern Tarim Basin were mostly distributed in the dolomite but were less developed in the limestone. This study provides new insights into the evolution of dolomitizing fluids that are responsible for multiple dolomitization events and the formation of the hydrtothermal dolomite in the Tarim Basin and elsewhere around the world.",0,0,2
Cement,Rock Physics,"March, Rafael; Zhang, Shuo; Liu, Hui-Hai",Direct numerical simulation of density driven fingering flow: Towards a model to predict the spacing between halite fingers in hydrocarbon reservoirs,Halite cementation; Fingering flow; Numerical simulation; Finger spacing; The Rayleigh number,POROUS-MEDIA; SOLUTE TRANSPORT; ARA GROUP; CONVECTION; CEMENTATION; BOUNDARY,"Halite cementation is a major exploration risk in hydrocarbon reservoirs. Halite-cemented reservoir zones are characterized by extremely low porosity and permeability due to partial or complete occlusion of the pore space. Despite being a key process that affects the quality of the productive formation, a quantitative analysis of the physical processes responsible for halite cementation is still missing in the scientific literature. Brine reflux caused by temperature and density gradients is one of the main physical mechanisms responsible for the intrusion of salt in the pores of a productive formation. Physically, the dissolution of salt by the resident brine creates a zone of higher density which may give rise to the development of flow instabilities. In this work, we present a quantitative methodology for estimating the distribution of halite-cemented zones by numerically simulating unstable flows for different flow and rock parameters. The main non-dimensional parameter, the Rayleigh number, that governs the flow is identified. The impact of the Rayleigh number on finger distribution is investigated using a statistical methodology to obtain a finger spacing distribution. Finally, a simple relationship is developed between finger spacing and the Rayleigh number that may be used to predict finger spacing.",0,0,1
Cement,Rock Physics,"Chakraborty, Shantanu; Mondal, Samit; Chatterjee, Rima",Comprehensive workflow to quantify diagenetic cement from wireline logs of deep water east coast of India wells and rock physics modeling,Cementation; Neutron and density logs; Rock physics modeling; Core data,LITHOLOGY; RESERVOIR; TEMPLATE; BASIN,"Presence of diagenetic cement is common in deep-water siliciclastic reservoirs and largely affects reservoir quality. Hence, the quantification of cement volume is an integral part of the reservoir characterization workflow. Lab analysis of core samples provides the cement volume information used as input for rock physics modeling. In the absence of core sample analysis, use of analogous offset well information provides an approximate estimate of cement. In reality, most deep-water wells do not have core samples for lab analysis. Consequently, the availability of offset well information is sparse and sometimes unavailable. Hence, getting an accurate cement volume estimate for reservoir characterization is challenging. For a detailed analysis, it is desirable to have a continuous measurement of cement volume across the reservoir sand. Presence of a calibrated cement volume log for the entire reservoir improves rock physics modeling. In this work, petrophysical M-N lithology cross plot, which is widely used to identify lithologies, has been used to quantify the diagenetic cement present within the reservoir, where M is the density normalized sonic values and N is the density normalized neutron values. Here, the M and N has been used as M-Lithology (MLITH) and N-Lithology (NLITH). In estimating MLITH and NLITH values, compressional sonic, bulk density and neutron logs are used. Porosity estimated from neutron/density is useful to identify the type of cement. Whereas, sonic slowness values are more sensitive towards the amount of grain contact cements. Hence, the estimated values of MLITH and NLITH varies differently in the presence of diagenetic materials. These variations of MLITH and NLITH values are captured and converted to cement volume fractions. In the presence of core data, the lab analysis measurements are used to calibrate the cement volume log. Further, rock physics modeling results helps to validate the output. The results of the study add value by quantifying diagenetic cementation in the reservoir characterization process by mitigating the associated limitations due to absence of sufficient core data.",0,0,1
Cement,Rock Physics,"Kadyrov, Rail; Nurgaliev, Danis; Saenger, Erik H.; Balcewicz, Martin; Minebaev, Rezit; Statsenko, Evgeny; Glukhov, Mikhail; Nizamova, Aigul; Galiullin, Bulat",Digital rock physics: Defining the reservoir properties on drill cuttings,Cuttings; Core; Carbonates; Pore structure; Digital rock physics,TRANSPORT; CFD; PARAMETERS; PROGRAM; OIL,"Well drilling with core extraction is one of the most expensive procedures in the oil industry. The potential alternative, which may open opportunities for cost-efficient acquisition of petrophysical data, can be an approach based on digital analysis of drill cuttings. The main purpose of this research was to evaluate the possibility of using digital cuttings analysis and rock physics for reservoir properties evaluation. The carbonate samples of core and cuttings were simultaneously collected from the same intervals during the drilling of deviated wells in the Carboniferous reservoir of the oil deposit in the Republic of Tatarstan, Russia. Based on the core analysis using the optical study of thin sections and XRD, we investigated sedimentological and mineralogical features and classified all lithotypes of well intervals. The standard samples were produced from all defined facies and their reservoir properties were studied in routine tests. The largest cuttings from each well interval were separated and their structures were compared using mu CT with core subsamples of the same intervals. We assessed the changes of cuttings structure occurring in the drilling process, which include the colmatation of the pore space with drilling fluid and disintegrated rock particles and the formation of secondary fractures. Detailed analysis of cuttings from one well interval consisting of the border between the facies of high porous grainstones with packstones and dense micrite limestones demonstrated that high porous varieties were eroded in the drilling process. The analysis of chemical composition using XRF-mapping, XRD and SEM with EDS showed that most of the cuttings were constituted by disintegrated rock particles or form elements (e.g. separate fusulinids) cemented by drilling mud. However, more durable cuttings from dense micrite limestones facies were generally retained their dominant calcite composition and original rock structure, with only secondary fractures. Finally, we analyzed pore space properties and performed digital simulations of wave propagation velocities to compare the characteristics of these cuttings and core subsamples from this lithotype, scanned in the same mu CT settings. The results demonstrate close characteristics of porosity 0.08-0.6%, dominant pore sizes 1-60 mu m and velocities Vp = 6130-6240 m/s, Vs = 3180-3230 m/s. However, the comparison of obtained values with measured on standard samples shows a significant difference, which is caused by deviation from REV. The potential use of cuttings for assessing reservoir and petrophysical properties can be possible in case of provision with the factors of cuttings structure alteration, representativity of samples, as well as optimization for these purposes of the drilling process with cuttings selection.",0,0,1
Cement,Persian Gulf,"Tavakoli, Vahid; Hassani, Danial; Rahimpour-Bonab, Hossain; Mondak, Alireza","How petrophysical heterogeneity controls the saturation calculations in carbonates, the Barremian-Aptian of the central Persian Gulf",Tight carbonate reservoir; Water saturation; Archie equation; Archie coefficients; Heterogeneity,CAPILLARY-PRESSURE CURVES; SEQUENCE STRATIGRAPHY; CEMENTATION FACTOR; ARCHIES EXPONENTS; DARIYAN FORMATION; FLOW UNITS; RESERVOIR; EXAMPLE; CLASSIFICATION; PERMEABILITY,"Water saturation calculations are among the most important aspects of reservoir characterization. Despite this importance, the effects of these calculations on the resulted oil in place remain unclear. Extreme heterogeneity in most of the carbonate reservoirs strongly affects the coefficients of the Archie equation and resulted water saturation. Therefore, a practical method to evaluate and manage the heterogeneity of such reservoirs, greatly improves the reliability of the final results. In this study, porosity, permeability, thin sections data, well logs and saturation tests of Barremian-Aptian carbonate Dariyan Formation in the central Persian Gulf have been used. Both core and reservoir scale techniques including flow zone indicator, Winland R-35, electrofacies and stratigraphically modified Lorenz plot were used to evaluate the heterogeneity. Archie coefficients were arranged in different rock types. Results show that flow zone indicator is the most accurate technique to manage the heterogeneity of the reservoir with higher R-2 value between porosity and permeability. The cementation factor was measured for each unit and the amounts of water saturation was calculated using deterministic analysis. Water saturation also calculated with the constant coefficients, which are routinely used in formation evaluation. The average S-w amount for constant Archie coefficients method was determined as 0.62, whereas it is 0.73, 0.80, 0.70, and 0.77 in flow zone indicator method, Winland R-35 technique, stratigraphically modified Lorenz plot and electrofacies determination, respectively. The results demonstrate that calculating water saturation with constant Archie coefficients leads to slightly lower water saturation values, resulting in higher oil saturations and overestimating the oil in place.",0,0,0
Cement,Persian Gulf,"Bahrehvar, Mohammad; Mehrabi, Hamzeh; Akbarzadeh, Samira; Rahimpour-Bonab, Hossain",Depositional and diagenetic controls on reservoir quality of the uppermost Jurassic-Lower Cretaceous sequences in the Persian Gulf; a focus on J-K boundary,Manifa-Yamama formations; Reservoir facies; Hydraulic flow units; Jurassic-Cretaceous boundary; Persian Gulf,FAHLIYAN FORMATION; DARIYAN FORMATION; MIDDLE-EAST; STRATIGRAPHY; BASIN; GEOCHEMISTRY; ZAGROS; IRAN; PALEOCLIMATE; MICROFACIES,"This study presents reservoir characterization of the uppermost Jurassic-Lower Cretaceous successions of the Manifa and Yamama formations in four wells in the Persian Gulf. Detailed sedimentological, petrophysical and geochemical analyses are integrated to evaluate the controlling factors on reservoir quality of these sequences. Microfacies analysis has resulted in the recognition of 10 facies types deposited in lagoon, algal mounds, shoal, and open marine settings. Micritization, dissolution, various types of cementation, dolomitization, and compaction are notable diagenetic alterations indicating marine/hypersaline, meteoric and shallow to deep burial realms. Stable carbon and oxygen isotopic compositions indicate a meteoric diagenetic alteration at the topmost part of Manifa unit, beneath the Jurassic-Cretaceous (J-K) disconformity. Sequence stratigraphic analysis led to the identification of four transgressive-regressive (T-R) sequences in the Yamama Fm. and a regressive hemi-sequence in the Manifa unit. Reservoir quality study resulted in the recognition of eight hydraulic flow units and four types of reservoir facies with specific and predictable sequence stratigraphic framework. Dissolved grain-dominated shoal facies at the upper part of regressive systems tracts and algal reef/mound facies in transgressive systems tracts provide the best reservoir units of the studied sequences. Microporous mud-dominated facies of open marine settings are dominant reservoir facies in the upper Yamama unit, with moderate to low reservoir quality.",0,0,0
Cement,Pressure Loss,"Xie, Yuhong; Ouyang, Min; Zhao, Hu; Li, Lie; Feng, Yingtao",Wellbore pressure management of offshore wells during casing running in narrow safety pressure window formations,Safety pressure window; Surge-swab pressure; Managed mud level; Offshore well; Casing running,,"Casing running in subsea wells has long been considered a daunting task and repeatedly proved unsuccessful, largely due to the narrow safety pressure window formations. Mud losses to formations, formation fluid influx and well wall collapsing have been the three most common causes in such casing running failures. The problem can be solved with the managed wellbore pressure casing running technique, which was developed based on managed pressure cementing and implemented by controlling mud level. Accurate calculation of surge-swab pressure is the key to successful managed pressure casing running. In this study, we show a dynamic surges-wab pressure model for the managed pressure casing running method. By analyzing the factors influencing surge-swab pressure, it is found that the surge-swab pressure of wellbore rises with the increase in initial position of the bottom of the casing, casing running speed, drilling mud density and viscosity. By contrast, changing mud level has little impact on surge-swab pressure. The surge-swab pressure during the deceleration stage of the casing has a negative value, namely the swab pressure. Therefore, we propose a managed pressure casing running method based on the accurate calculation dynamic surge-swab pressure. This method controls the wellbore pressure by adjusting the mud level according to the surge-swab pressure. Managed wellbore pressure casing running can reduce not only the risk of lost circulation and fluid influx during casing running, but also the time for casing running operation.",0,0,0
Cement,Pressure Loss,"Yang, Mou; Luo, Hao; Xie, Rongxuan; Wu, Pengcheng; Yang, Mingzheng; Yang, Lvchao; Xue, Hu",Estimating and optimizing wellbore pressure during primary cementing in low pressure and leakage formations,Circulating pressure; Cementing operation; Low pressure and leakage formations; Mathematical model; Computational fluid dynamics,NON-NEWTONIAN FLUIDS; POWER-LAW FLUID; HERSCHEL-BULKLEY; ECCENTRIC ANNULI; DRILLING-FLUIDS; TURBULENT-FLOW; LAMINAR; CIRCULATION; TRANSITION; BEHAVIOR,"In most realistic situations, casing eccentricity and various fluids injected during primary cementing lead to a significant difference in fluid flow and circulating pressure, compared with a single fluid flowing in the concentric annulus. Ignoring the effect of eccentricity and fluid rheological model on the wellbore circulating pressure results in an inaccurate evaluation and leads to formation leakage, especially for low pressure and leakage formations. To overcome this challenge, firstly, rheological models of various fluids were analyzed using experimental data, including drilling fluid, spacer, and cement slurry. Secondly, the modified correlations of frictional pressure losses for Herschel-Bulkley and Power Law fluids in the eccentric annulus were developed, using the simulation data of computational fluid dynamics software (CFD) and considering the effects of flow behavior index, pipe diameter ratio, and casing eccentricity on the frictional pressure losses. Finally, based on the developed mathematical models, the optimal method of primary cementing and evaluation results were presented, analyzed, and tested in the field with great success. The results demonstrated that the drilling fluid and spacer fluid had the highest goodness of fit for the Herschel-Bulkley model, and the cementing slurry was suitable for the Power Law model. The ratio coefficient of pressure loss in the eccentric to concentric annulus decreased with a decrease of hole size and an increase of casing eccentricity. A 50 percent reduction in frictional pressure loss was evaluated when the casing lies on the borehole wall. Comparing the calculations of the developed correlation with the published correlation in the literature reveals a more accurate evaluation of friction pressure losses in the analyzed case. Combined with the realistic situation of a test well, the density, flow rate, and returning depth of the lead cement slurry were recommended as 1.5 g/cm(3), 0.5 m(3)/min and 4100 m, respectively, according to the leakage pressure of 65.6 MPa that was calculated by the developed mathematical model. Most importantly, the developed method in this paper can accurately predict the variation characteristics of wellbore pressure during the primary cementing process and provide effective guidance in managing downhole pressure in low pressure and leakage formations by real-time adjustment of the most effective and controllable operation parameters.",0,0,3
Cement,Management,"Yuan, Bin; Li, Junfu; Xu, Bihua; Su, Yu; Li, Bin; Yang, Lin",Managed wellhead backpressure during waiting setting of managed pressure cementing,Managed pressure cementing; Narrow safe density window; Hydration shrinkage; Filtration shrinkage; Gel strength; Hydrostatic pressure,LOST CIRCULATION; HYDRATION; TEMPERATURE; REDUCTION,"Managed pressure cementing (MPC) has been successfully used to reduce risk lost circulation and improve cementing quality in wells with a narrow safe pressure window. However, during the waiting setting period of MPC, the magnitude of the managed well backpressure is still based on experience, which results in a high risk of leakage or gas channeling especially in formations with a narrow safe density window. Therefore, a backpressure managing method is proposed here based on a model we built for calculating wellhead backpressure. This model was used to analyze the effect of cement slurry, temperature and wellbore pressure on wellhead backpressure. The results show that hydration, filtration shrinkage and gel supporting are essential to reduce wellbore pressure, although hydration is less effective compared with the latter two on pressure reduction. The magnitude and duration of wellhead backpressure depend on the extent of volume shrinkage and the gel strength development of cement slurry. Latex-cement slurry requires minimal wellhead backpressure with the shortest duration. Temperature and wellbore pressure greatly impact wellhead backpressure with temperature playing a more dominant role.",0,0,0
Cement,Management,"Xie, Yuhong; Ouyang, Min; Zhao, Hu; Li, Lie; Feng, Yingtao",Wellbore pressure management of offshore wells during casing running in narrow safety pressure window formations,Safety pressure window; Surge-swab pressure; Managed mud level; Offshore well; Casing running,,"Casing running in subsea wells has long been considered a daunting task and repeatedly proved unsuccessful, largely due to the narrow safety pressure window formations. Mud losses to formations, formation fluid influx and well wall collapsing have been the three most common causes in such casing running failures. The problem can be solved with the managed wellbore pressure casing running technique, which was developed based on managed pressure cementing and implemented by controlling mud level. Accurate calculation of surge-swab pressure is the key to successful managed pressure casing running. In this study, we show a dynamic surges-wab pressure model for the managed pressure casing running method. By analyzing the factors influencing surge-swab pressure, it is found that the surge-swab pressure of wellbore rises with the increase in initial position of the bottom of the casing, casing running speed, drilling mud density and viscosity. By contrast, changing mud level has little impact on surge-swab pressure. The surge-swab pressure during the deceleration stage of the casing has a negative value, namely the swab pressure. Therefore, we propose a managed pressure casing running method based on the accurate calculation dynamic surge-swab pressure. This method controls the wellbore pressure by adjusting the mud level according to the surge-swab pressure. Managed wellbore pressure casing running can reduce not only the risk of lost circulation and fluid influx during casing running, but also the time for casing running operation.",0,0,0
Cement,Shale,"Liu, Peng; Wu, Hongliang; Yang, Shubo; Zhao, Qiqi; Wu, Jinping; Li, Xin",A dual-frequency acoustic measurement method for detecting fluid-filled channels at two boundaries in cased holes,Dual-frequency; Acoustic logging; Fluid-filled channel; Casing wave; Numerical simulation,NUMERICAL-SIMULATION; WAVE-FIELD; LOGS,"The recognition of fluid-filled channels in cased holes is significant for the safety production of oil and gas wells. The fluid-filled channel at the cement-formation boundary is more difficult to be detected than that at the casing-cement boundary. To solve the key technical problem, a dual-frequency acoustic measurement method is proposed to obtain the cementation state of the two interfaces at the same time. The related theory is that the casing wave amplitude from the low-frequency source is sensitive to the channel at both two boundaries, but that from the high-frequency source is only sensitive to the channel at the casing-cement boundary. Therefore, high amplitudes of the casing waves from both two sources represent a channel on the casing-cement boundary, high amplitude from the low-frequency source but low amplitude from the high-frequency source represent a channel on the cement-formation boundary, and low amplitudes from both two sources represent no channel. Subsequently, numerical simulations are performed to examine the effects of several critical parameters on the dual-frequency acoustic measurement. The results show that the best combination of the measurement system is one low-frequency source at 10 kHz together with one high-frequency source at 150 kHz. For the low-frequency source, the casing wave amplitude increases obviously with the increasing channel thickness, regardless of the channel position. The increase of the cement thickness and the casing size damps out the casing wave. For the high-frequency source, the casing wave amplitude is little affected by these parameters except for the casing-cement channel. Moreover, the dual-frequency acoustic measurement method is suitable for common sandstone and shale formations. The findings of this study provide a theoretical foundation for next-generation cementing-quality-evaluation tool development.",0,0,2
Cement,Shale,"Xu, Liangwei; Yang, Keji; Wei, Hao; Liu, Luofu; Jiang, Zhenxue; Li, Xiao; Chen, Lei; Xu, Tong; Wang, Ximeng","Pore evolution model and diagenetic evolution sequence of the Mesoproterozoic Xiamaling shale in Zhangjiakou, Hebei",Xiamaling shale; Framework mineral pores; Hydrocarbon generation and expulsion model; Clay mineral transformation; Digenetic sequence; Pore system evolution model,BOHAI BAY BASIN; ORGANIC-RICH; MARINE SHALE; GAS; ADSORPTION; LITHOFACIES; MUDSTONES; MUDROCKS; POROSITY; REGION,"Current research on diagenesis and its evolution focuses mainly on sandstone reservoirs. Conventional oil and gas reservoir observation techniques for characterizing shale reservoirs are limited, and comprehensive research on nanoscale pore variations, diagenesis and evolution of shale reservoirs, especially immature and low-maturity marine shale reservoirs, is relatively scarce. To reveal the diagenesis and evolution of low-maturity marine shale, geochemical and mineral analyses, quantitative characterization of the pore structure and qualitative characterization of the pore morphology were performed on the Xiamaling shale. With the burial and geothermal history, the Xiamaling diagenetic evolution sequence and the nanoscale pore system evolution were studied. The results show that smectite continually transforms to an illite-smectite (I/S) mixed layer and then quickly transforms to illite and chlorite; the kaolinite content gradually decreases as maturity increases. The hydrocarbon expulsion threshold of the Xiamaling shale is EqRo = 1.0%, and the porosity decreases to a minimum value of EqRo = 1.0% and then increases. The pore structure evolution model shows that the pore volumes (PVs) of micropores and macropores decrease to minima at approximately EqRo = 0.92% and 0.85%, respectively, and then increase; the mesopore PVs continuously decrease. Micropore and mesopore surface areas (SAs) decrease to their minima at approximately EqRo = 0.85% and 1.0%, respectively, and then increase; simultaneously, the macropore SAs continuously decrease. The main diagenetic types of the Xiamaling shale are compaction, dissolution, cementation, thermal maturation of organic matter (OM), and clay mineral transformation; it reaches period B of the middle diagenetic stage, and the diagenetic evolution sequence is determined. The pore system composition and variation characteristics of the Xiamaling shale are analysed, and a corresponding evolution model is established.",0,0,2
Cement,NW China,"Zhao, Xiaodong; Zhang, Shiqi; Yang, Shaochun; Ju, Xiaoyu; Chen, Gangqiang; Zhang, Xiaotong; Khan, Danish; Zhang, Yaxuan; Zhang, Jiankun","Controlling factors of carbonate cement and its influence on oil-water distribution of the Neogene Shawan Formation in the northern Chepaizi area, Junggar Basin, NW China",Junggar basin; Reservoir characteristics; Carbonate cements; AxioVision image analysis; Diagenetic environment,SANDSTONE; RESERVOIR; DIAGENESIS; HISTORY,"The distribution of physical property of the Neogene Shawan Formation(N1s) in the north of Chepaizi area (Abbreviated as ""Chebei area"") is characterized by ""double peak"", which is mainly related to carbonate cements in the reservoirs. It is observed that the large amounts of early carbonate cements are present in thin sections, which are inhomogeneously filled in some primary intergranular pores and caused strong heterogeneity of the reservoir. On the basis of convent calculate of carbonate cement in core, AxioVision image analysis with multiple times and multiple fields of view was used to supplement the calculation of carbonate cement content, and the relative error compared with the core measurement result was -0.14, which effectively compensated for the lack of core measurement data points. The content of carbonate cement has been characterized by ""higher in the north area and lower in the south area"" on the plane. The carbonate cement is formed in closed diagenetic environment with good sealing ability and water body stagnated alternately. The closed diagenetic environment of the Shawan formation in Chebei area primed the environmental foundation for the growth of carbonate cements, and the abundant Ca2+ in the formation water primed the material foundation for the growth of carbonate cements. The difference in Ca2+ content in formation water determines the distribution difference of carbonate cements, and the diagenetic environment is the controlling factor for the development of carbonate cements. The complex oil-water distribution in the study area is principally related to the carbonate cementation. The super heavy oil with high viscosity cannot enter the low porosity and permeability reservoir with tough cementation, which is prone to the phenomenon of oil-water inversion.",0,0,1
Cement,NW China,"Guo, Ruixin; Zhang, Shaonan; Wang, Kun; Han, Meimei; Ding, Xiaoqi","Multiphase dolomitization and hydrothermal alteration of the Upper Cambrian-Lower Ordovician carbonates in the Gucheng uplift, Tarim Basin (NW China)",Multiphase dolomitization; Dolomitizing fluids; Hydrothermal alteration; Hydrothermal dolomite reservoirs,DOLOMITE RESERVOIR FACIES; PENESALINE SEA-WATER; FLUID-FLOW; ISOTOPE GEOCHEMISTRY; BURIAL DOLOMITIZATION; PLATFORM CARBONATES; FORMATION MECHANISM; PRESQUILE BARRIER; ORIGIN; SEDIMENTARY,"The thick Upper Cambrian-Lower Ordovician carbonates of the Gucheng uplift (southeastern Tarim Basin, northwestern China) have been extensively dolomitized, leading to the formation of massive dolomite reservoirs. The origins of different dolomites and their original fluids were studied based on an integrated analysis of petrology, geochemical data (C, O, and Sr isotopes) and fluid inclusion assemblages (FIAs). The D1 (very finely to finely crystalline planar-e/s dolomite) and the D2 (finely to medium crystalline planar-s/a dolomite) dolomites were formed from the mesosaline to penesaline seawater in the subsurface to shallow burial stage. The increasing temperatures and changes of dolomitizing fluid properties led to the formation of different textures and distributions. Both D1 and D2 dolomites, compared to the matrix limestone, show no obvious improvements in porosity, which indicates that early dolomitizations did not create or preserve the primary pores. CD1 (finely to medium crystalline nonplanar-e/s dolomite) and CD2 (medium to coarsely crystalline nonplanar saddle dolomite) dolomites are dolomite cements of hydrothermal alteration at the deep burial stage. Due to changes in temperature and Mg2+ concentrations of the hydrothermal fluids, the precipitation of CD1 and CD2 dolomites exhibited different textures and filling sequences. In the limited space of matrix dolomite, hydrothermally altered dolomite was dominated by D3 (medium to coarsely crystalline nonplanar-a dolomite). The late calcite fillings were precipitated on account of decreasing Mg2+ concentration at the end of the hydrothermal alteration. Hydrothermal fluids, depleted in Mg2+ and enriched in silica, could be deep-basinal brines driven by the strongly transpressional faults from the Late Caledonian to Early Hercynian. Compared to D1 and D2 dolomites, the higher porosities in hydrothermally altered dolomite indicate that hydrothermal fluids are constructive to the formation of reservoirs. Hydrothermal alteration products showed obvious differences between the dolomite and limestone, and led to different performance in physical characteristics. Hence, the hydrothermally altered reservoirs in the eastern Tarim Basin were mostly distributed in the dolomite but were less developed in the limestone. This study provides new insights into the evolution of dolomitizing fluids that are responsible for multiple dolomitization events and the formation of the hydrtothermal dolomite in the Tarim Basin and elsewhere around the world.",0,0,2
Seismic Data,Oil Field,"Sadeghi, Mehdi; Madani, Nasser; Falahat, Reza; Sabeti, Hamid; Amini, Navid",Hierarchical reservoir lithofacies and acoustic impedance simulation: Application to an oil field in SW of Iran,Hierarchical simulation; Pluri-Gaussian simulation; Turning bands simulation; Lithofacies; Acoustic impedance,CONDITIONAL SIMULATION; POINT; UNCERTAINTY; PROGRAM,"In this study, a hierarchical simulation algorithm was implemented to produce 3D models of lithofacies and acoustic impedance (AI) in an oil field in southwestern Iran. Hierarchical simulation is a powerful method that takes into account the spatial distribution and hard contact relationships of continuous variables within the categorical variables in reservoir characterization. To implement the hierarchical simulation algorithm in this study, pluri-Gaussian simulation was used to construct the layouts of one categorical variable (lithofacies domains) and turning bands simulation was used to produce one continuous variable (AI models) within each simulated domain. The dataset that is available to test the proposed method includes the lithofacies and AI logs of seven wells. For validation of the proposed model, one of wells was excluded from the initial dataset to check the accuracy of results. The algorithm was implemented on a gridded model to produce 50 realizations of 3D lithofacies and AI models. The statistical analyses of the produced models verified the capabilities of hierarchical simulation in reproducing the lithofacies domains and AI values related to each domain. The simulated AI models were compared with the seismic inversion model to corroborate the reliability of the results. In addition, to show the superiority of the hierarchical approach, the results were compared to the results of direct AI modeling in which the AI models were generated without considering any lithofacies data. The comparisons in the blind well indicated a high correlation between the modeled values and the true AI. The correlation coefficient between average AI models of the hierarchical approach and the true AI was 0.85. Whereas, this value was 0.75 for the average of directly simulated AI models and 0.74 for the seismic inversion, respectively. Histogram analysis also verified the capability of the hierarchical modeling in reproducing the statistical properties of the original data. The resulting AI model obtained using the method proposed in this study also showed a high compatibility with the deterministic seismic inversion cube.",0,0,0
Seismic Data,Oil Field,"Khoshnoodkia, Mehdi; Rahmani, Omeid; Adabi, Mohammad Hossein; Hosseini-Barzi, Mahboubeh; Mahdi, Thamer A.","Depositional environment, seismic stratigraphy, and Sr-isotope geochronology, Bangestan reservoir, Ahwaz oilfield, SW Iran",Cretaceous; Seismic tectonostratigraphic; Extensional tectonic; Sarvak; Ilam; The zagros basin,SOUTHERN MESOPOTAMIAN BASIN; DEZFUL EMBAYMENT; SARVAK FORMATION; THRUST BELT; SEQUENCE STRATIGRAPHY; CRETACEOUS CARBONATES; MISHRIF FORMATION; ZAGROS MOUNTAINS; ARABIAN PLATE; TECTONICS,"The Bangestan reservoir, which occurs in the Ahwaz oilfield, consists of the middle Cretaceous limestone Ilam and Sarvak Formations that were deposited in the Zagros Basin. The reservoir is divided into ten Zones (A to J) formed in the upper Albian-Santonian and contains considerable hydrocarbon accumulations. The limestones were deposited on an extensive shallow carbonate platform on a passive margin and are dominated by rudist biostrome and grainstone facies. Paleogeographical changes mean that identification of the facies is complex. Seismic stratigraphy and isotopic data are used to better understand the structural and geological setting and develop an understanding of the sedimentary environment. The results show that the rudist biostrome facies extends to a shallow interior shelf as a patch reef, indicating a regressive trend. Petrographic studies on 3174 thin sections identified twelve microfacies in the Bangestan reservoir. In the Sarvak Formation, the dominant microfacies consist of rudist biostrome, shoal bar, and lagoon facies, with a high sedimentation rate in the basin, whereas the Ilam Formation involves open and deep-marine facies. Seismic tectono-stratigraphy shows that there are seven sedimentary sequences with mostly regressive cycles and six maximum flooding surfaces from the upper Albian to the Santonian. In addition, the Ahwaz oilfield had experienced pre-tectonic extension before the Early Cretaceous and post-tectonic extension after the Late Cretaceous. The isotopic data from the Bangestan reservoir demonstrate two important disconformities (Cenomanian-Turonian and post-Turonian) that had an important influence on the evolution of the area evolution. Sr geochronology confirms long-term exposure to two main disconformities within the Ahwaz Bangestan reservoir.",0,0,0
Seismic Data,Oil Field,"Danaei, Shahram; Silva Neto, Gilson M.; Schiozer, Denis J.; Davolio, Alessandra",Substituting petro-elastic model with a new proxy to assimilate time-lapse seismic data considering model errors,4D seismic; Petro-elastic model; Data assimilation; ES-MDA; Model error,SATURATION CHANGES; OBJECTIVE FUNCTION; PRESSURE; FIELD,"Dynamic data from oil and gas reservoirs (such as well-production or 4D seismic data) have been used often to reduce uncertainty in reservoir simulation models. These data are assimilated in the simulation models separately or jointly. Assimilation of 4D seismic data conventionally involves with a petro-elastic model (PEM) to transform outputs from the simulation models to elastic properties. The PEM is a set of different equations with uncertain parameters and its inclusion in assimilation algorithms calls on multidisciplinary teams of geoscientists and engineers. Moreover, PEM requires extraction of different outputs from the simulation models for the seismic forward model calculations. The extraction process can be costly for large-scale simulation models of giant reservoirs. This research presents a new petro-elastic proxy model (named DAI-Proxy) with a novel formulation to substitute the PEM and integrate 4D seismic data. DAI-Proxy relates time-lapse acoustic impedance to a summation of saturation and pressure changes with two coefficients which are functions of porosity. As the proxy is an approximation of the PEM, its application is affected by model error. We introduce two approaches to account for the proxy model error: (1) considering uncertain coefficients for the DAI-Proxy and (2) using fixed coefficients in the proxy while estimating model errors statistics from the prior ensemble of models. We incorporate these two approaches with a data assimilation algorithm to assimilate simultaneously 4D seismic and well-production data. A benchmark case is used with different cases of data assimilation to compare the DAIProxy and the PEM applications. Results show that data match quality for 4D seismic and well-production have similar responses for the PEM and DAI-Proxy implementations. In terms of production forecast, using fixed coefficients in the proxy with its model error treatment create a data assimilation framework comparable to the PEM case. Our results indicate that the traditional PEM application to integrate jointly 4D seismic and wellproduction data can be replaced with our new DAI-Proxy application. Given the degree of uncertainty in the PEM, related to the rock and fluid models, our proxy provides similar results with fewer uncertain inputs. The proxy offers further advantage as it needs less outputs from the simulation models for seismic forward model calculations. In addition, it helps petroleum engineers to use a computationally less expensive model (light model) as a substitute for the PEM to assimilate 4D seismic data.",0,0,1
Seismic Data,Oil Field,"Nosjean, N.; Holeywell, R.; Pettingill, H. S.; Roden, R.; Forrest, M.",Geological probability of success assessment for amplitude-driven Prospects:A Nile Delta case study,Risk analysis; Probability of success; Portfolio management; Uncertainty; Subsurface geology; Geophysics; Seismic amplitudes; Seismic attributes; DHI; DHI uplift; Hydrocarbon exploration; Bias mitigation; Seismic interpretation; Petroleum system elements; Pliocene; Nile delta; Egypt,UNCERTAINTY; RISK; AVO; EXPLORATION; FRAMEWORK; CHANNELS; HISTORY; GUIDE; BASIN; FIELD,"Effective quantification and management of exploration risks and associated uncertainties remains a key challenge for the Oil and Gas industry. Geological probability of success evaluation is one of the key steps of the exploration process, which will lead - if properly managed - to enhanced project?s value creation, as well as improved portfolio management and exploration decisions. This paper reviews and discusses a consistent, uniform and reproducible approach for evaluating seismic amplitude-supported prospects, weighted by the input data quality and availability. The method and workflows are further illustrated with an offshore Nile Delta case study. This approach enhances the confidence in the appropriate risk and associated resource estimate for less biased and more consistent probability estimation.",0,0,1
Seismic Data,Oil Field,"Ye, Tao; Chen, Anqing; Niu, Chengming; Wang, Qingbin; Hou, Mingcai","Characteristics, controlling factors and petroleum geologic significance of fractures in the Archean crystalline basement rocks: A case study of the South Jinzhou oilfield in Liaodong Bay depression, North China",Basement buried-hill reservoir; Fracture characteristics; Controlling factor; Petroleum geologic significance; South jinzhou oilfield,QUANTITATIVE FLUORESCENCE TECHNIQUES; BURIED-HILL; QAIDAM BASIN; DEVELOPMENTAL CHARACTERISTICS; SHAHEJIE FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; DOMINANT FACTORS; GAS-RESERVOIRS; CHARGE HISTORY,"Fractures play an important role in hydrocarbon storage and migration in basement buried hills. Taking the South Jinzhou oilfield (JZS oilfield) as an example, based on the data from cores, thin sections, seismic, logging, and experimental analysis, we clarified the genetic types and characteristics of fractures in the JZS crystalline basement oilfield and discussed controlling factors and their significance to petroleum geology. Tectonic and non-tectonic fractures are present in the study area, in which tectonic fractures are predominant. Tectonic fractures show three dominant directions with E-W, NE-SW, and NW-SE trends; among them, fractures with E-W trends are best developed. Most of the fractures are oblique, with a dip angle between 45 degrees and 60 degrees. The shear-compression zone trigged by strike-slip faults in-plane is favorable for fracture development. The granitic rocks with low compressive strength are more prone to fracture than diabase. Meteoric water and organic acids promote dissolution along fractures, expanding the tectonic fractures further. The fractures can increase the permeability of crystalline basement rocks by 10(3) times compared with the matrix. The dissolution along fractures can effectively improve the storage capacity of the crystalline basement rocks. Furthermore, there are a large number of fractures developed below the oil-water contact, which are important lateral migration channels for hydrocarbons.",0,0,1
Seismic Data,Oil Field,"Gholami, Amin; Amirpour, Masoud; Ansari, Hamid Reza; Seyedali, Seyed Mohsen; Semnani, Amir; Golsanami, Naser; Heidaryan, Ehsan; Ostadhassan, Mehdi",Porosity prediction from pre-stack seismic data via committee machine with optimized parameters,Porosity; Seismic pre-stack (SPS); Optimized model (OM); Committee machine (CM); Bat-inspired algorithm (BA),SUPPORT VECTOR REGRESSION; RESERVOIR CHARACTERIZATION; PERMEABILITY PREDICTION; SANDSTONE RESERVOIR; INTELLIGENT SYSTEMS; REFRACTIVE-INDEX; MODEL; ATTRIBUTES; ALGORITHM,"Prediction of porosity from the seismic data via geophysical methods when limited number of wells are available is a challenging task that has high uncertainties. This study aims to construct a hybrid data-driven predictive model to establish a quantitative correlation between seismic pre-stack (SPS) data and the porosity. First, three intelligent models that are optimized by bat-inspired algorithm (BA): optimized neural network (ONN), optimized fuzzy inference system (OFIS), and optimized support vector regression (OSVR) are constructed for relating porosity to the SPS data. Then, to benefit from all individual optimized models, a final hybrid model was built via committee machine (CM) where single models are combined with a proper weight to predict porosity in the reservoir space. This approach is examined on the SPS data from an oil field in the Persian Gulf with a single exploratory well where input parameters (Vp, Vs, and rho) to the AI models are derived from a two-parameter inversion method. We found that the coefficient of determination, root mean square error, average absolute relative error, and symmetric mean absolute percentage error for the CM are 0.923615, 0.015793, 0.132280, and 0.061310, respectively. Moreover, based on four statistical indexes that are calculated for each model, CM outperformed its individual elements followed by the OSRV. A comprehensive analysis of the results confirms that CM with the OM elements is a superior approach for computing porosity from the SPS in the well and then throughout the entire reservoir volume. This strategy can aid petroleum engineers to have a better forecast of porosity population in the reservoir static model immediately following the data that is obtained from the first exploratory well. Ultimately, successful implementation of this approach will promptly delineate sweet spots that can replace uncertain and complicated conventional geophysical methods.",0,0,1
Seismic Data,Oil Field,"Zhang, Yan; Zhang, Chunlei; Ma, Qiaoyu; Zhang, Xin; Zhou, Heng",Automatic prediction of shear wave velocity using convolutional neural networks for different reservoirs in Ordos Basin,Ordos basin; Shear wave velocity; Convolutional neural networks; Well logs; Rock-physics model,WELL LOG DATA; MACHINE; MODEL,"Shear wave velocity (S-wave velocity) has great significance for reservoir characterization and can effectively reduce the ambiguity in seismic interpretation. However, owning to its high cost and technical difficulties, it is usually difficult to obtain for the whole region. Therefore, the prediction of S-wave velocity currently has turned into an urgent task. Thus, the S-wave velocity was predicted using 1D convolutional neural network (1D-CNN) with the well logs. In the first step, the traditional Xu-White and Xu-Payne model were used to carry out the inversion of bulk modulus, shear modulus and density, and illustrated the phenomenon for the traditional rockphysics model. Then, 1D-CNN, including one input layer, four convolutional layers, three fully connected layers and one output layer, was proposed, in which three types of well logs (conventional well logs, array induction well logs and gamma ray spectral well logs) sensitive to the S-wave velocity were determined through the well logs analysis. Finally, based on the established 1D-CNN model, the influence of different well logs combination on the S-wave velocity prediction was analyzed, indicating that the addition of different well logs can improve the accuracy of S-wave velocity. And different machine learning methods (MLs), including back-propagation (BP) and support vector regression (SVR), were also compared, showing that the predicted accuracy of 1DCNN has been improved by 4.2% on average. Two cases for sandstone and carbonate reservoirs also showed that 1D-CNN proposed can achieve higher accuracy and better performance than traditional MLs and rockphysics models. Furthermore, the proposed method can be applied to the other oil and gas exploration fields, improving the exploration accuracy and increasing the production of oil and gas.",0,0,1
Seismic Data,Oil Field,"Saedi, Ghasem; Soleimani, Bahman; Samani, Babak; Arzani, Ali",The interaction between faults and in-situ stress on the kinematic and subsurface natural fracture of Aghajari oilfield in southwest of Iran,Natural fracture; Fault; In-situ stress; Seismic data frequency; Dipole sonic tool,ASMARI FORMATION; BOREHOLE ELONGATION; ZAGROS MOUNTAINS; DEZFUL EMBAYMENT; GAS-RESERVOIRS; IMAGE; BASIN; CORE; WELL; LOGS,"Electrical and acoustic image logs are the best evaluating subsurface fracture and In-situ Stress wellbore data among direct and indirect methods. In this study, which had done by using the 24 Asmari reservoir well data in the Aghajari giant oilfield firstly were determined and categorized subsurface natural fracture, fault and In-situ Stress from common conventional well log, electrical and acoustic image logs, dipole sonic logs and 3D seismic data. Then, the relationship between determined features are evaluated in terms of genesis, events and different structural setting as the interaction between fault and In-situ Stress on the kinematic and subsurface natural fracture of Aghajari oilfield in southwest of Iran. The maximum and minimum horizontal in-situ stress direction is derived from image and dipole data had a good correlation except regions due to the fault effect. the integration of data evinced that the perturbation of regional stresses inherited from seismic faults and the effect of both regional stress and fault effect in the construction of a transforming fold as detachment type in SW nose to forming fault propagation and bending fold towards central and SE nose, respectively, which it could be useful for fracture modeling to enhance oil production, especially in heterogeneous carbonate fractured reservoirs.",0,0,2
Seismic Data,Oil Field,"Sun, Zhifeng; Bai, Qinglin; Ren, Huaiqiang; Yan, Ke; Gao, Liang; Wei, Liu Zhong","Quantitative evaluation of morphological characteristics of thin sand body: Taking the deltaic distributary channel sand body as an example in Shengtuo oil field of Dongying sag, east of Bohai Bay Basin*",Thin interbeds; Distributary channel; Architecture; Quantitative model; Sandstone reservoir,SEISMIC ATTRIBUTES; RESERVOIRS; DEPOSITS; ARCHITECTURE; DEPRESSION; PREDICTION,"Because of the small scale of distributary channel sand body and the superposition of sand bodies in vertical and lateral direction, drilling data with 150-200 m well spacing is difficult to describe its scale, shape and connectivity characteristics effectively. It has a great restriction on the recovery of these reservoirs. Taking Sheng2 Block of Shengtuo Oilfield as an example, the architectural elements of distributary channel are quantitatively investigated by using dense-drilling well and seismic data. Based on frequency division seismic data, the boundary of distributary channel belts are described vertically and laterally, and then the scale and morphological characteristics of channel bodies in the channel belt are characterized by using local dense well pattern data. The target layer can be divided into six channel belts longitudinally. After seismic frequency demultiplication, 60-75 Hz seismic data was used to describe the distribution of channel belts. From the bottom to the top, the width and distribution range of the channel belts decrease as a whole. Channel belt thickness and its width show linear positive correlation. On the channel-belt cross section, channel stories on the dense drilling-well logging profiles are identified with reference to the profile geometry of the distributary channel. On the channel-belt cross section, the projection distance between wells is fitted to a linear correlation with the thickness variation of channel stories. The ratio of the two parameters decreases from bottom to top of the target layer as a whole. The channel shape parameters predicted by the dense drilling-well logging section are of great significance to the study of paleocurrent deposition and paleohydrological evolution. At the same time, it has guiding significance for the development and adjustment of oil and gas reservoirs.",0,0,2
Seismic Data,Simulation Models,"Sadeghi, Mehdi; Madani, Nasser; Falahat, Reza; Sabeti, Hamid; Amini, Navid",Hierarchical reservoir lithofacies and acoustic impedance simulation: Application to an oil field in SW of Iran,Hierarchical simulation; Pluri-Gaussian simulation; Turning bands simulation; Lithofacies; Acoustic impedance,CONDITIONAL SIMULATION; POINT; UNCERTAINTY; PROGRAM,"In this study, a hierarchical simulation algorithm was implemented to produce 3D models of lithofacies and acoustic impedance (AI) in an oil field in southwestern Iran. Hierarchical simulation is a powerful method that takes into account the spatial distribution and hard contact relationships of continuous variables within the categorical variables in reservoir characterization. To implement the hierarchical simulation algorithm in this study, pluri-Gaussian simulation was used to construct the layouts of one categorical variable (lithofacies domains) and turning bands simulation was used to produce one continuous variable (AI models) within each simulated domain. The dataset that is available to test the proposed method includes the lithofacies and AI logs of seven wells. For validation of the proposed model, one of wells was excluded from the initial dataset to check the accuracy of results. The algorithm was implemented on a gridded model to produce 50 realizations of 3D lithofacies and AI models. The statistical analyses of the produced models verified the capabilities of hierarchical simulation in reproducing the lithofacies domains and AI values related to each domain. The simulated AI models were compared with the seismic inversion model to corroborate the reliability of the results. In addition, to show the superiority of the hierarchical approach, the results were compared to the results of direct AI modeling in which the AI models were generated without considering any lithofacies data. The comparisons in the blind well indicated a high correlation between the modeled values and the true AI. The correlation coefficient between average AI models of the hierarchical approach and the true AI was 0.85. Whereas, this value was 0.75 for the average of directly simulated AI models and 0.74 for the seismic inversion, respectively. Histogram analysis also verified the capability of the hierarchical modeling in reproducing the statistical properties of the original data. The resulting AI model obtained using the method proposed in this study also showed a high compatibility with the deterministic seismic inversion cube.",0,0,0
Seismic Data,Simulation Models,"Wu, Hao; Li, Zhen; Liu, Naihao; Zhang, Bo",Improved seismic well tie by integrating variable-size window resampling with well-tie net,Seismic well tie; Waveform resampling; CNN,SYNTHETIC SEISMOGRAMS,"Accurate seismic well tie is essential for seismic inversion and reservoir characterization. The procedure of seismic well tie involves shifting, stretching and squeezing the synthetic seismogram computed from well logs to match the seismic traces at or near the borehole location. Numerous methods have been proposed for nonlinear alignment between synthetic and real seismograms. However, most well-tie methods are prone to over-stretching and the alignment result is sensitive to the chosen window size. To solve those problems, we propose a variablesize window resampling (VWR) algorithm and integrate with convolutional neural network (CNN) for automatic seismic well tie. Using VWR algorithm to reconstruct the waveforms in synthetic seismogram can simulate the variety of subsurface velocity. CNN can learn the characteristic of different waveforms and recognize the most correlated waveforms between synthetic and real seismograms for sequence alignment. We first use VWR algorithm to reconstruct a large number of synthetic seismograms for train set generation. We then build an CNN model that named well-tie net for training to learn the feature of different resampled synthetic seismograms. Finally, we use the well trained CNN model to segment the real seismogram and align with the synthetic seismogram for seismic well tie. We apply our method into the synthetic test and real seismic data with well logs and obtain high correlated seismic-well tie. We also compare with the conventional method dynamic time warping (DTW) to illustrate the effectiveness and robustness of our proposed method. Our proposed method can avoid the problem of over-stretching by using the variable-size window resampling algorithm and automatically tying the well to seismic trace using well-tie net. In addition, the train set for our method is generated automatically.",0,0,0
Seismic Data,Simulation Models,"Yadav, Ashok; Nayak, Soumya Ranjan; Mondal, Samit",Agglomerative clustering to improve the resolution of pseudo well stochastic seismic inversion: A case study,"Reservoir characterization; Inversion; Rock Physics, Volume of Sand",CHAIN MONTE-CARLO; SIMULATION,"The Monte Carlo rejection and Monte Carlo Markov Chain methods are two common sampling techniques in Bayesian seismic inversion. Conventional methods of pseudo well stochastic seismic inversion for reservoir properties uses Monte Carlo rejection sampling of pseudo-wells to select those that best match seismic traces. The selected pseudo-wells do not influence the selection/rejection of subsequent pseudo-wells. The process requires a very large number of prior pseudo-wells to draw a reasonable outcome, which consumes a major part of the computation time. In conventional methods, the best-matched pseudo-wells often have dissimilarly shaped volume of shale logs, which can degrade the resolution of the outcome. Though Agglomerative clustering is well-known but the idea of grouping pseudo-wells based on similarly shaped volume of shale logs in pseudo well stochastic seismic inversion is unique. We propose an agglomerative clustering technique to group the prior pseudo-wells according to the shape of their volume of shale logs, before matching to seismic. The centroids of the pseudo-well clusters summarize the large number of prior pseudo-wells. The best-matched pseudo-well cluster centmid with seismic gives the most likely outcome while the two next best-matched cluster centroids give alternative results. The alternative results are useful to understand the uncertainty in the outcome. It has been observed that, the proposed method has reduced computation time (50-55% less than conventional pseudo well stochastic inversion). Meanwhile, the quantification of sand volume from the proposed method shows improvement over the conventional method. A comparison between the proposed and the conventional method has been shown on a synthetic wedge model and real seismic. In the wedge model (volume of sand is 0.65), the resultant volume of sand predicted in the modified method (0.7) is better than that predicted using the conventional method (0.8). The modified pseudo-well stochastic seismic inversion method has been applied on seismic data from deepwater Krishna-Godavari basin. The result shows an improvement in the characterization of thin shale layers within the reservoir.",0,0,0
Seismic Data,Simulation Models,"Danaei, Shahram; Silva Neto, Gilson M.; Schiozer, Denis J.; Davolio, Alessandra",Substituting petro-elastic model with a new proxy to assimilate time-lapse seismic data considering model errors,4D seismic; Petro-elastic model; Data assimilation; ES-MDA; Model error,SATURATION CHANGES; OBJECTIVE FUNCTION; PRESSURE; FIELD,"Dynamic data from oil and gas reservoirs (such as well-production or 4D seismic data) have been used often to reduce uncertainty in reservoir simulation models. These data are assimilated in the simulation models separately or jointly. Assimilation of 4D seismic data conventionally involves with a petro-elastic model (PEM) to transform outputs from the simulation models to elastic properties. The PEM is a set of different equations with uncertain parameters and its inclusion in assimilation algorithms calls on multidisciplinary teams of geoscientists and engineers. Moreover, PEM requires extraction of different outputs from the simulation models for the seismic forward model calculations. The extraction process can be costly for large-scale simulation models of giant reservoirs. This research presents a new petro-elastic proxy model (named DAI-Proxy) with a novel formulation to substitute the PEM and integrate 4D seismic data. DAI-Proxy relates time-lapse acoustic impedance to a summation of saturation and pressure changes with two coefficients which are functions of porosity. As the proxy is an approximation of the PEM, its application is affected by model error. We introduce two approaches to account for the proxy model error: (1) considering uncertain coefficients for the DAI-Proxy and (2) using fixed coefficients in the proxy while estimating model errors statistics from the prior ensemble of models. We incorporate these two approaches with a data assimilation algorithm to assimilate simultaneously 4D seismic and well-production data. A benchmark case is used with different cases of data assimilation to compare the DAIProxy and the PEM applications. Results show that data match quality for 4D seismic and well-production have similar responses for the PEM and DAI-Proxy implementations. In terms of production forecast, using fixed coefficients in the proxy with its model error treatment create a data assimilation framework comparable to the PEM case. Our results indicate that the traditional PEM application to integrate jointly 4D seismic and wellproduction data can be replaced with our new DAI-Proxy application. Given the degree of uncertainty in the PEM, related to the rock and fluid models, our proxy provides similar results with fewer uncertain inputs. The proxy offers further advantage as it needs less outputs from the simulation models for seismic forward model calculations. In addition, it helps petroleum engineers to use a computationally less expensive model (light model) as a substitute for the PEM to assimilate 4D seismic data.",0,0,1
Seismic Data,Simulation Models,"Neto, Gilson M. Silva; Davolio, Alessandra; Schiozer, Denis J.",Assimilating time-lapse seismic data in the presence of significant spatially correlated model errors,Model calibration; Ensemble data assimilation; Iterative ensemble smoothers; History matching; Model errors; ESMDA,DISCRETE LATIN HYPERCUBE; ENSEMBLE SMOOTHER; HISTORY,"Time-lapse seismic data is becoming a common information source in reservoir model calibration workflows to improve production forecasts. The standard process compares a forward model's results with the observed data to update the model's parameters from the existing deviations. Ensemble-based methods are popular choices for this process. However, the so-called forward model is always a simplification of the real phenomena. These simplifications may significatively influence the relation between simulated and observed data and possibly yield inconsistent updates of the parameters and uncertainty underestimation. In the conventional approach for this problem, the so-called strong-constraint formulation neglects the model's limitations, causing unphysical updates of the parameters to reduce the distance between simulated and observed data. In this work, we propose a methodology to apply a weak-constraint formulation to the time-lapse seismic data assimilation to mitigate the above problem. We consider the forward model error with an additive term and update it during the data assimilation workflow. By adopting this approach, we reduce the impact of the model errors in the calibrated parameters. Also, the proposed methodology handles model bias as a type of general model error. The inclusion of the additive term weakens the updates of the model due to the time-lapse seismic data. We show that this procedure significantly benefits the data assimilation results when there are substantial spatially correlated model errors, and it has a minor impact when applied to a low-error case. We apply the proposed method to assimilate time-lapse seismic data using the Ensemble Smoother with Multiple Data Assimilations in a simple 2D case and in a realistic benchmark synthetic case based on a real offshore reservoir. In the former case, we consider model error related to the pressure sensitivity in the petroelastic model. In the latter, we consider a realistic synthetic time-lapse seismic and the correlated errors result from seismic modeling and inversion. Moreover, in the latter, we also assimilate well data. The results indicate that our methodology improved the reservoir characterization and the production forecast using relatively low-resolution time-lapse seismic data.",0,0,2
Seismic Data,Simulation Models,"Han, Jianhui; Steel, Ronald J.; Hou, Mingcai; Li, Yangyang; Yuan, Lizhong; Zheng, Jinyun; Liu, Jun","Subsidence and maturation evolution of a new lower-slope minibasin, Xingning Sag, northern South China Sea",Lower slope basin; Backstripping; Thermal modeling; Maturation history; South China Sea,RIVER MOUTH BASIN; TECTONIC SUBSIDENCE; QIONGDONGNAN BASIN; CONTINENTAL-MARGIN; ANOMALIES; EXTENSION; HISTORY,"Study of Subsidence and maturation evolution of a continental slope basin without a drilled well is an important problem in the early stage of deep-water exploration. Lack of some parameters, such as stratigraphic-age, porosity-depth relationship, exact paleo-water depth and heat flow value are common problems in the study of subsidence and maturity history. Using 46 long 2D seismic lines and paleo-water depth data from paleonto-logical data of a well on the slope toe, the present study combines backstripping with thermal modeling to reconstruct the subsidence and maturation evolution of a lower-slope minibasin, Xingning Sag (XS), on the southeast Pearl River Mouth Basin (PRMB) of the South China Sea (SCS), now a new prospecting area. Stratigraphic-ages, porosity-depth relationship, lithology of XS were estimated using data from an adjacent basin. Paleo-water depths were obtained by clinoform geometry using seismic facies and paleontological method. With these parameters, the subsidence curves were created by backstripping. Crustal stretching factors (beta) were obtained by best fit of tectonic subsidence curve and thermal modeling. With these stretching factors, the theoretical subsidence and heat flow values were obtained at the same time. Based on the heat flow value and the backstripping parameters, the maturation history of this basin was simulated. The result shows XS evolved through three cycles of subsidence during 46-23.03 Ma, 23.03-13.82 Ma and 13.82-0 Ma, respectively. Each cycle shows a rifting phase of relatively rapid tectonic subsidence followed a cooling phase of slow subsidence. Potential Eocene lacustrine source rocks are distributed primarily in the central depression area (Xingning main sub-sag), and would have entered the main oil-generation window and main gas generation during early- and mid-Miocene respectively.",0,0,2
Seismic Data,Simulation Models,"Rollmann, Klaus; Soriano-Vargas, Aurea; Cirne, Marcos; Davolio, Alessandra; Schiozer, Denis Jose; Rocha, Anderson",A three-way convolutional network to compare 4D seismic data and reservoir simulation models in different domains,History-matching; 4D seismic data; Simulation models; Deep learning; Data assimilation; 3-way deep neural network,NEURAL-NETWORKS; HISTORY; PARAMETERIZATION,"Four-dimensional seismic (4DS) contains spatial information that provides insights into the location, shape, and movement of fluids (oil, gas, water). It helps engineers to adjust reservoir simulation models and increase their capability of providing reliable production forecasts. Recent probabilistic approaches consider hundreds of numerical simulation model scenarios, which require automated methods to evaluate this large number of numerical models based on observed 4D seismic data. Comparing spatial information of seismic and numerical simulation data is difficult as, usually, these data are converted to maps with different properties. We propose a novel approach to compare 4D seismic data and simulation models using a three-way deep neural network that is trained using a reference image (4D seismic data) with two simulation model candidates. It learns to find the simulation models that best characterize the reference. Our method is underpinned by more than a thousand pairs of simulation models and reference maps evaluated by human specialists for training. For testing, we compare the inter-rater agreement among different specialist groups and generate a reliable test set considering examples in which there was agreement among at least two specialists. We observed that the group with best-trained specialists agree more in their answers and have a considerably higher inter-rater agreement than the less trained groups. When we evaluate our method with the answers from this specialized group, we observe that the simulation model chosen by our method is the one agreed by the specialists in almost 90% of the cases. We also discuss the impact of different noise levels in the input and show that our method outperforms other approaches in the literature if noise is present both in the training and test sets.",0,0,2
Seismic Data,Simulation Models,"Babu, M. Nagendra; Ambati, Venkatesh; Nair, Rajesh R.",An integrated approach to lithofacies characterization of a sandstone reservoir using the Single Normal Simulation equation: A Case study,Simultaneous prestack inversion; Angle dependent wavelets; Non-parametric statistical classification; Multiple-point geostatistics; SNESIM algorithm,MULTIPLE-POINT GEOSTATISTICS; WAVELET ESTIMATION; WELL-TIE; 3D RECONSTRUCTION; TRAINING IMAGE; STATISTICS; BASIN,"This paper describes a comprehensive approach to improved lithofacies characterization using the simultaneous pre-stack inversion, Bayesian classification, and multiple-point geostatistics. This integrated workflow provides an enhanced lithofacies characterization by reproducing the continuity of geological facies in the meandering-fluvial sandstone reservoir from Upper Assam, India. The simultaneous pre-stack inversion provides the rock elastic properties of the reservoir, such as P-impedance, s-impedance, density, and V-P/V-S ratio. Next, the probabilistic modeling approach of Baye's theorem is used to integrates seismic elastic properties with well log lithofacies identified from the cross-plot analysis for probability volumes of lithofacies. Finally, the multiple-point geostatistics based on the Single Normal equation Simulation algorithm is used to generate the improved lithofacies model by constraining of the lithofacies probability volumes (soft data) and well logging data (hard data). These results were compared with the Bayesian lithofacies classification and proved that the adopted method had successfully improved the continuation of the reservoir lithofacies by reproducing the lithofacies, hence an improvement in the reservoir characterization.",0,0,3
Seismic Data,"Waves,Velocity","Wu, Hao; Li, Zhen; Liu, Naihao; Zhang, Bo",Improved seismic well tie by integrating variable-size window resampling with well-tie net,Seismic well tie; Waveform resampling; CNN,SYNTHETIC SEISMOGRAMS,"Accurate seismic well tie is essential for seismic inversion and reservoir characterization. The procedure of seismic well tie involves shifting, stretching and squeezing the synthetic seismogram computed from well logs to match the seismic traces at or near the borehole location. Numerous methods have been proposed for nonlinear alignment between synthetic and real seismograms. However, most well-tie methods are prone to over-stretching and the alignment result is sensitive to the chosen window size. To solve those problems, we propose a variablesize window resampling (VWR) algorithm and integrate with convolutional neural network (CNN) for automatic seismic well tie. Using VWR algorithm to reconstruct the waveforms in synthetic seismogram can simulate the variety of subsurface velocity. CNN can learn the characteristic of different waveforms and recognize the most correlated waveforms between synthetic and real seismograms for sequence alignment. We first use VWR algorithm to reconstruct a large number of synthetic seismograms for train set generation. We then build an CNN model that named well-tie net for training to learn the feature of different resampled synthetic seismograms. Finally, we use the well trained CNN model to segment the real seismogram and align with the synthetic seismogram for seismic well tie. We apply our method into the synthetic test and real seismic data with well logs and obtain high correlated seismic-well tie. We also compare with the conventional method dynamic time warping (DTW) to illustrate the effectiveness and robustness of our proposed method. Our proposed method can avoid the problem of over-stretching by using the variable-size window resampling algorithm and automatically tying the well to seismic trace using well-tie net. In addition, the train set for our method is generated automatically.",0,0,0
Seismic Data,"Waves,Velocity","Meng, Xiangyu; Sun, Jianguo; Wei, Puli; Xu, Yangyang; Xu, Zeshuang",Superwide-angle seismic migration by including the back-scattered wave through domain decomposition and biaxial parabolic approximation,Parabolic approximation; Domain decomposition; Scattering; Green's function,EQUATION; SCATTERING; ALGORITHM,"Using ideas from computational electromagnetics and the basic procedure from the domain decomposition method, we present a biaxial parabolic approximation method for enlarging the angle domain in which the parabolic approximation to the acoustic wave equation is multiple applied and that can be used for migrating data with super-wide angles. Mathematically, the biaxial approximation is a special case of the multiaxial parabolic approximation, and thus can be straightforwardly extended to multiaxial approximations. In detail, we first divide the subsurface into several fan-shaped subdomains and use the axis of each subdomain as the local wave propagation direction. Then, we make a parabolic approximation to the wave equation in each subdomain with respect to the corresponding symmetry axis and compute the forward-propagating wave alternately using a high-order parabolic approximated wave equation in two subdomains. Finally, we use the computed forward-propagating wave as the boundary condition for calculating the back-scattered wave and Green's function by applying the thin slab approximation. Compared with most one-way methods, the proposed method can deal with the strong velocity contrast in the horizontal direction at a large scattering angles. Moreover, compared with certain full-wave methods that have been published in recent years, the proposed method is considerably more efficient and sacrifices only a little in terms of accuracy. Numerical results from comparisons with models of different complexities demonstrate that our method is cost-effective and has considerable potential for use in seismic modeling and imaging.",0,0,0
Seismic Data,"Waves,Velocity","Chatterjee, Debashis; Mohanty, Priya Ranjan; Chatterjee, Rima; Singh, Sunil K.",Scope of sub basalt imaging using locally generated converted waves and mixed mode depth imaging: A study on real data,Passive margin; Sub-basalt; PSSP waves; Mixed mode depth imaging,,"The seismic imaging below basaltic layer is extremely challenging. The attenuation of PP energy while penetrating through basalt section, very high absorption and scattering of PP waves and generation of multiples are some important impediments. The imaging problems are severe when basaltic layer has varying thicknesses (undulations) of multiple flows with inter layered sediments. Basalt has high velocity compared to surrounding sediment. Hence the point of critical reflection angle is reached at a smaller offset. Anomalous value of Vp/Vs generates converted waves from basalt top. Quantitative modelling has demonstrated the presence of PSSP energy up to a wide offset range (8+ Km). This has led us to explore the option of sub-basalt imaging using PSSP waves. We generated synthetic PP and PSSP gathers with one dimensional modelling. The PSSP energy is visible from an offset of 1800 m onwards from basalt top. In absence of multi component OBN or OBC data, an attempt has been made to extract PSSP waves from 2D seismic data (streamer data) for time and depth imaging of PSSP waves. In this paper, we also present mixed mode (PP + PSSP), depth imaging as an alternative option for more precise structural interpretation and mapping of sub-basalt reflectors.",0,0,0
Seismic Data,"Waves,Velocity","Zhang, Jian; Li, Jingye; Chen, Xiaohong; Li, Yuanqiang",Geological structure-guided hybrid MCMC and Bayesian linearized inversion methodology,Seismic inversion; Plane wave destruction (PWD); Block coordinate descent (BCD); Acoustic impedance (AI); Uncertainty evaluation,,"Seismic inversion is a common method for hydrocarbon reservoir characterization, as it consists of a proven and effective approach to derive elastic properties from reflectivity seismic data. Markov Chain Monte Carlo (MCMC) based seismic inversion approach is a suitable choice to numerically evaluate the posterior uncertainties associated with the inverse solution without assuming linear forward operators, Gaussian, or generalized Gaussian prior models. However, the existing MCMC based seismic inversion approaches are mostly performed trace-bytrace, which means that the spatial coupling of model parameters is not considered. When the results of trace-bytrace based inversion are combined to generate a 2D profile, the final results will be laterally discontinuous. Moreover, the large dimension of the model space causes low convergence efficiency of MCMC-based seismic inversion. To overcome these issues, a geological structure-guided hybrid MCMC and Bayesian linearized inversion (BLI) methodology for seismic inversion is implemented. The geological structure information obtained using plane wave destruction (PWD) is incorporated to the MCMC based inversion algorithm in the form of dips yields more geologically meaningful results. The hybrid MCMC and BLI strategy, which takes advantage of BLI s high efficiency to provide initial configuration for MCMC, is used to improve the convergence of MCMC-based inversion. Additionally, the block coordinate descent (BCD) algorithm is introduced to replace the large-scale matrix solution in geological structure-guided, and consequently reduce memory consumption and time cost. This methodology is validated on a synthetic seismic dataset, as well as on a real case. It has proven to be a reliable approach to obtain acoustic impedance (AI) from post-stack seismic data in an efficient way. It also addresses the uncertainty related with the ill-posed characteristics of the inversion methodology itself.",0,0,1
Seismic Data,"Waves,Velocity","Xue, Ya-juan; Cao, Jun-xing; Wang, Xing-jian; Du, Hao-kun",Reservoir permeability estimation from seismic amplitudes using variational mode decomposition,Permeability estimation; Seismic amplitude; Variational mode decomposition; Reflection coefficient; Reservoir thickness,FLUID MOBILITY; ELASTIC WAVES; REFLECTION; PROPAGATION; ATTENUATION; POROSITY,A new qualitative Reservoir Permeability estimation approach using variational mode decomposition named RPE-VMD is proposed which directly use seismic amplitude and frequency attributes. The method reveals amplitude anomalies that may reflect details about the heterogenous distribution of reservoir permeability. The main procedure is carried out in the time-frequency domain which generates by using a generalized S transform. Reflection coefficient information is used as seismic amplitude attribute and extracted by using variational mode decomposition combined with mutual information theory from seismic data using the logarithmic spectrum. The dominant frequency extracted in the time-frequency domain is used as seismic frequency attribute for estimating reservoir thickness information. The RPE-VMD approach uses dominant reflection coefficient information from the seismic data combined with reservoir thickness information for permeability estimation. Application of this approach to field data from a sandstone reservoir in China illustrates that it can provide permeability estimation with a high resolution and accuracy. The proposed method directly uses seismic data to measure the reservoir permeability avoiding the need of seismic velocity in the conventional estimation methods.,0,0,1
Seismic Data,"Waves,Velocity","Zhang, Yan; Zhang, Chunlei; Ma, Qiaoyu; Zhang, Xin; Zhou, Heng",Automatic prediction of shear wave velocity using convolutional neural networks for different reservoirs in Ordos Basin,Ordos basin; Shear wave velocity; Convolutional neural networks; Well logs; Rock-physics model,WELL LOG DATA; MACHINE; MODEL,"Shear wave velocity (S-wave velocity) has great significance for reservoir characterization and can effectively reduce the ambiguity in seismic interpretation. However, owning to its high cost and technical difficulties, it is usually difficult to obtain for the whole region. Therefore, the prediction of S-wave velocity currently has turned into an urgent task. Thus, the S-wave velocity was predicted using 1D convolutional neural network (1D-CNN) with the well logs. In the first step, the traditional Xu-White and Xu-Payne model were used to carry out the inversion of bulk modulus, shear modulus and density, and illustrated the phenomenon for the traditional rockphysics model. Then, 1D-CNN, including one input layer, four convolutional layers, three fully connected layers and one output layer, was proposed, in which three types of well logs (conventional well logs, array induction well logs and gamma ray spectral well logs) sensitive to the S-wave velocity were determined through the well logs analysis. Finally, based on the established 1D-CNN model, the influence of different well logs combination on the S-wave velocity prediction was analyzed, indicating that the addition of different well logs can improve the accuracy of S-wave velocity. And different machine learning methods (MLs), including back-propagation (BP) and support vector regression (SVR), were also compared, showing that the predicted accuracy of 1DCNN has been improved by 4.2% on average. Two cases for sandstone and carbonate reservoirs also showed that 1D-CNN proposed can achieve higher accuracy and better performance than traditional MLs and rockphysics models. Furthermore, the proposed method can be applied to the other oil and gas exploration fields, improving the exploration accuracy and increasing the production of oil and gas.",0,0,1
Seismic Data,Model Error,"Oliver, Dean S.",Information content in 4D seismic data: Effect of correlated noise,Time-lapse seismic; 4D seismic; History matching,DATA ASSIMILATION; OBSERVATION ERRORS; SHANNON ENTROPY; MODELS,"Several types of data used in history matching for subsurface reservoir characterization have errors that are spatially or temporally correlated. Although it is often assumed that correlated observation errors decrease information content, using a simplified flow problem, we show that for data that are spatially dense (such as 4D seismic data), correlated observation errors result in higher information content than data with similar levels of errors, but without correlation. Unfortunately, correlations in the observation error are often unrecognized and difficult to estimate, especially if the correlation scale of the errors is similar to a characteristic length of the signal. In addition, many history matching algorithms are incapable of accounting properly for correlated observation error, so data are either thinned or the observation error is inflated to partially account for the lack of proper treatment. We show that neglecting correlations in the observation errors or inflating the variance, result in loss of information content. Finally, we show that it is possible to iteratively estimate the correlated observation errors through analysis of residuals after history matching.",0,0,0
Seismic Data,Model Error,"Danaei, Shahram; Silva Neto, Gilson M.; Schiozer, Denis J.; Davolio, Alessandra",Substituting petro-elastic model with a new proxy to assimilate time-lapse seismic data considering model errors,4D seismic; Petro-elastic model; Data assimilation; ES-MDA; Model error,SATURATION CHANGES; OBJECTIVE FUNCTION; PRESSURE; FIELD,"Dynamic data from oil and gas reservoirs (such as well-production or 4D seismic data) have been used often to reduce uncertainty in reservoir simulation models. These data are assimilated in the simulation models separately or jointly. Assimilation of 4D seismic data conventionally involves with a petro-elastic model (PEM) to transform outputs from the simulation models to elastic properties. The PEM is a set of different equations with uncertain parameters and its inclusion in assimilation algorithms calls on multidisciplinary teams of geoscientists and engineers. Moreover, PEM requires extraction of different outputs from the simulation models for the seismic forward model calculations. The extraction process can be costly for large-scale simulation models of giant reservoirs. This research presents a new petro-elastic proxy model (named DAI-Proxy) with a novel formulation to substitute the PEM and integrate 4D seismic data. DAI-Proxy relates time-lapse acoustic impedance to a summation of saturation and pressure changes with two coefficients which are functions of porosity. As the proxy is an approximation of the PEM, its application is affected by model error. We introduce two approaches to account for the proxy model error: (1) considering uncertain coefficients for the DAI-Proxy and (2) using fixed coefficients in the proxy while estimating model errors statistics from the prior ensemble of models. We incorporate these two approaches with a data assimilation algorithm to assimilate simultaneously 4D seismic and well-production data. A benchmark case is used with different cases of data assimilation to compare the DAIProxy and the PEM applications. Results show that data match quality for 4D seismic and well-production have similar responses for the PEM and DAI-Proxy implementations. In terms of production forecast, using fixed coefficients in the proxy with its model error treatment create a data assimilation framework comparable to the PEM case. Our results indicate that the traditional PEM application to integrate jointly 4D seismic and wellproduction data can be replaced with our new DAI-Proxy application. Given the degree of uncertainty in the PEM, related to the rock and fluid models, our proxy provides similar results with fewer uncertain inputs. The proxy offers further advantage as it needs less outputs from the simulation models for seismic forward model calculations. In addition, it helps petroleum engineers to use a computationally less expensive model (light model) as a substitute for the PEM to assimilate 4D seismic data.",0,0,1
Seismic Data,Model Error,"Gholami, Amin; Amirpour, Masoud; Ansari, Hamid Reza; Seyedali, Seyed Mohsen; Semnani, Amir; Golsanami, Naser; Heidaryan, Ehsan; Ostadhassan, Mehdi",Porosity prediction from pre-stack seismic data via committee machine with optimized parameters,Porosity; Seismic pre-stack (SPS); Optimized model (OM); Committee machine (CM); Bat-inspired algorithm (BA),SUPPORT VECTOR REGRESSION; RESERVOIR CHARACTERIZATION; PERMEABILITY PREDICTION; SANDSTONE RESERVOIR; INTELLIGENT SYSTEMS; REFRACTIVE-INDEX; MODEL; ATTRIBUTES; ALGORITHM,"Prediction of porosity from the seismic data via geophysical methods when limited number of wells are available is a challenging task that has high uncertainties. This study aims to construct a hybrid data-driven predictive model to establish a quantitative correlation between seismic pre-stack (SPS) data and the porosity. First, three intelligent models that are optimized by bat-inspired algorithm (BA): optimized neural network (ONN), optimized fuzzy inference system (OFIS), and optimized support vector regression (OSVR) are constructed for relating porosity to the SPS data. Then, to benefit from all individual optimized models, a final hybrid model was built via committee machine (CM) where single models are combined with a proper weight to predict porosity in the reservoir space. This approach is examined on the SPS data from an oil field in the Persian Gulf with a single exploratory well where input parameters (Vp, Vs, and rho) to the AI models are derived from a two-parameter inversion method. We found that the coefficient of determination, root mean square error, average absolute relative error, and symmetric mean absolute percentage error for the CM are 0.923615, 0.015793, 0.132280, and 0.061310, respectively. Moreover, based on four statistical indexes that are calculated for each model, CM outperformed its individual elements followed by the OSRV. A comprehensive analysis of the results confirms that CM with the OM elements is a superior approach for computing porosity from the SPS in the well and then throughout the entire reservoir volume. This strategy can aid petroleum engineers to have a better forecast of porosity population in the reservoir static model immediately following the data that is obtained from the first exploratory well. Ultimately, successful implementation of this approach will promptly delineate sweet spots that can replace uncertain and complicated conventional geophysical methods.",0,0,1
Seismic Data,Model Error,"Neto, Gilson M. Silva; Davolio, Alessandra; Schiozer, Denis J.",Assimilating time-lapse seismic data in the presence of significant spatially correlated model errors,Model calibration; Ensemble data assimilation; Iterative ensemble smoothers; History matching; Model errors; ESMDA,DISCRETE LATIN HYPERCUBE; ENSEMBLE SMOOTHER; HISTORY,"Time-lapse seismic data is becoming a common information source in reservoir model calibration workflows to improve production forecasts. The standard process compares a forward model's results with the observed data to update the model's parameters from the existing deviations. Ensemble-based methods are popular choices for this process. However, the so-called forward model is always a simplification of the real phenomena. These simplifications may significatively influence the relation between simulated and observed data and possibly yield inconsistent updates of the parameters and uncertainty underestimation. In the conventional approach for this problem, the so-called strong-constraint formulation neglects the model's limitations, causing unphysical updates of the parameters to reduce the distance between simulated and observed data. In this work, we propose a methodology to apply a weak-constraint formulation to the time-lapse seismic data assimilation to mitigate the above problem. We consider the forward model error with an additive term and update it during the data assimilation workflow. By adopting this approach, we reduce the impact of the model errors in the calibrated parameters. Also, the proposed methodology handles model bias as a type of general model error. The inclusion of the additive term weakens the updates of the model due to the time-lapse seismic data. We show that this procedure significantly benefits the data assimilation results when there are substantial spatially correlated model errors, and it has a minor impact when applied to a low-error case. We apply the proposed method to assimilate time-lapse seismic data using the Ensemble Smoother with Multiple Data Assimilations in a simple 2D case and in a realistic benchmark synthetic case based on a real offshore reservoir. In the former case, we consider model error related to the pressure sensitivity in the petroelastic model. In the latter, we consider a realistic synthetic time-lapse seismic and the correlated errors result from seismic modeling and inversion. Moreover, in the latter, we also assimilate well data. The results indicate that our methodology improved the reservoir characterization and the production forecast using relatively low-resolution time-lapse seismic data.",0,0,2
Seismic Data,Fault,"Khomich, Vadim G.; Boriskina, Natalia G.",Petroleum potential of the Uchur zone of the Aldan anteclise (Siberian platform),Rift grabens; Horsts; Deep transform faults; Petroleum occurrences,,"The hydrocarbon prospects of the southern flank of the Aldan anteclise (anteclise is a large platform uplift with gentle (1-20) angles of incidence, isometric shape, and significant dimensions (hundreds of kilometers across) (Parnachev et al., 1996) are estimated by comparison with the petroleum-bearing structures of the West Siberian Plate, Siberian craton, and North Sakhalin. The distribution of hydrocarbon reservoirs in these structures is controlled by rift grabens, horsts, and paleotransform deep-seated fault zones identified using geophysical and seismic tomographic data. There is evidence that these faults penetrated the asthenosphere above and beneath a subduction zone and were saturated in gases and fluids, which then migrated in metasomatized mantle and Earth's crust. Based on the comparative analysis of factors controlling the petroleum provinces in Siberia and Russian Far East, the Uchur zone of the Aldan anteclise is regarded as a prospective petroleum basin.",0,0,0
Seismic Data,Fault,"Ye, Tao; Chen, Anqing; Niu, Chengming; Wang, Qingbin; Hou, Mingcai","Characteristics, controlling factors and petroleum geologic significance of fractures in the Archean crystalline basement rocks: A case study of the South Jinzhou oilfield in Liaodong Bay depression, North China",Basement buried-hill reservoir; Fracture characteristics; Controlling factor; Petroleum geologic significance; South jinzhou oilfield,QUANTITATIVE FLUORESCENCE TECHNIQUES; BURIED-HILL; QAIDAM BASIN; DEVELOPMENTAL CHARACTERISTICS; SHAHEJIE FORMATION; NATURAL FRACTURES; SHALE RESERVOIRS; DOMINANT FACTORS; GAS-RESERVOIRS; CHARGE HISTORY,"Fractures play an important role in hydrocarbon storage and migration in basement buried hills. Taking the South Jinzhou oilfield (JZS oilfield) as an example, based on the data from cores, thin sections, seismic, logging, and experimental analysis, we clarified the genetic types and characteristics of fractures in the JZS crystalline basement oilfield and discussed controlling factors and their significance to petroleum geology. Tectonic and non-tectonic fractures are present in the study area, in which tectonic fractures are predominant. Tectonic fractures show three dominant directions with E-W, NE-SW, and NW-SE trends; among them, fractures with E-W trends are best developed. Most of the fractures are oblique, with a dip angle between 45 degrees and 60 degrees. The shear-compression zone trigged by strike-slip faults in-plane is favorable for fracture development. The granitic rocks with low compressive strength are more prone to fracture than diabase. Meteoric water and organic acids promote dissolution along fractures, expanding the tectonic fractures further. The fractures can increase the permeability of crystalline basement rocks by 10(3) times compared with the matrix. The dissolution along fractures can effectively improve the storage capacity of the crystalline basement rocks. Furthermore, there are a large number of fractures developed below the oil-water contact, which are important lateral migration channels for hydrocarbons.",0,0,1
Seismic Data,Fault,"Saedi, Ghasem; Soleimani, Bahman; Samani, Babak; Arzani, Ali",The interaction between faults and in-situ stress on the kinematic and subsurface natural fracture of Aghajari oilfield in southwest of Iran,Natural fracture; Fault; In-situ stress; Seismic data frequency; Dipole sonic tool,ASMARI FORMATION; BOREHOLE ELONGATION; ZAGROS MOUNTAINS; DEZFUL EMBAYMENT; GAS-RESERVOIRS; IMAGE; BASIN; CORE; WELL; LOGS,"Electrical and acoustic image logs are the best evaluating subsurface fracture and In-situ Stress wellbore data among direct and indirect methods. In this study, which had done by using the 24 Asmari reservoir well data in the Aghajari giant oilfield firstly were determined and categorized subsurface natural fracture, fault and In-situ Stress from common conventional well log, electrical and acoustic image logs, dipole sonic logs and 3D seismic data. Then, the relationship between determined features are evaluated in terms of genesis, events and different structural setting as the interaction between fault and In-situ Stress on the kinematic and subsurface natural fracture of Aghajari oilfield in southwest of Iran. The maximum and minimum horizontal in-situ stress direction is derived from image and dipole data had a good correlation except regions due to the fault effect. the integration of data evinced that the perturbation of regional stresses inherited from seismic faults and the effect of both regional stress and fault effect in the construction of a transforming fold as detachment type in SW nose to forming fault propagation and bending fold towards central and SE nose, respectively, which it could be useful for fracture modeling to enhance oil production, especially in heterogeneous carbonate fractured reservoirs.",0,0,2
Seismic Data,Fault,"Song, Lei; Yin, Xingyao; Zong, Zhaoyun; Jiang, Man",Semi-supervised learning seismic inversion based on Spatio-temporal sequence residual modeling neural network,Seismic inversion; Deep learning; Semi-supervised learning; Initial model; Conventional well log; Spatio-temporal sequence residual modeling neural network,,"The Spatio-temporal sequence residual modeling neural network (STSRM-net) is built to address the geophysical problem of obtaining P-impedance of the subsurface from the zero-offset seismic data and initial model of P impedance. The initial model is used as the initial value of STSRM-net, and the modification value of the initial model and the residual between the modified initial model and true P-impedance are learned during the training. The Spatio-temporal characteristics of the data could be fully dug by STSRM-net. Limited by the inadequacy of labeled data, the semi-supervised learning inversion framework is constructed to train the STSRM-net. The performance of the STSRM-net and some deep learning inversion methods are compared on the synthetic dataset. The test results indicate that STSRM-net has higher inversion accuracy, stronger continuity, and better anti-noise performance. In addition, the robustness experiments indicate that the STSRM-net has excellent fault tolerance to the initial model. Finally, the STSRM-net is applied to the field data and compared with the sparse pulse inversion method, which also proves high inversion resolution, inversion accuracy and robustness to the choice of training wells of the proposed method.",0,0,3
Seismic Data,Domain,"Sadeghi, Mehdi; Madani, Nasser; Falahat, Reza; Sabeti, Hamid; Amini, Navid",Hierarchical reservoir lithofacies and acoustic impedance simulation: Application to an oil field in SW of Iran,Hierarchical simulation; Pluri-Gaussian simulation; Turning bands simulation; Lithofacies; Acoustic impedance,CONDITIONAL SIMULATION; POINT; UNCERTAINTY; PROGRAM,"In this study, a hierarchical simulation algorithm was implemented to produce 3D models of lithofacies and acoustic impedance (AI) in an oil field in southwestern Iran. Hierarchical simulation is a powerful method that takes into account the spatial distribution and hard contact relationships of continuous variables within the categorical variables in reservoir characterization. To implement the hierarchical simulation algorithm in this study, pluri-Gaussian simulation was used to construct the layouts of one categorical variable (lithofacies domains) and turning bands simulation was used to produce one continuous variable (AI models) within each simulated domain. The dataset that is available to test the proposed method includes the lithofacies and AI logs of seven wells. For validation of the proposed model, one of wells was excluded from the initial dataset to check the accuracy of results. The algorithm was implemented on a gridded model to produce 50 realizations of 3D lithofacies and AI models. The statistical analyses of the produced models verified the capabilities of hierarchical simulation in reproducing the lithofacies domains and AI values related to each domain. The simulated AI models were compared with the seismic inversion model to corroborate the reliability of the results. In addition, to show the superiority of the hierarchical approach, the results were compared to the results of direct AI modeling in which the AI models were generated without considering any lithofacies data. The comparisons in the blind well indicated a high correlation between the modeled values and the true AI. The correlation coefficient between average AI models of the hierarchical approach and the true AI was 0.85. Whereas, this value was 0.75 for the average of directly simulated AI models and 0.74 for the seismic inversion, respectively. Histogram analysis also verified the capability of the hierarchical modeling in reproducing the statistical properties of the original data. The resulting AI model obtained using the method proposed in this study also showed a high compatibility with the deterministic seismic inversion cube.",0,0,0
Seismic Data,Domain,"Meng, Xiangyu; Sun, Jianguo; Wei, Puli; Xu, Yangyang; Xu, Zeshuang",Superwide-angle seismic migration by including the back-scattered wave through domain decomposition and biaxial parabolic approximation,Parabolic approximation; Domain decomposition; Scattering; Green's function,EQUATION; SCATTERING; ALGORITHM,"Using ideas from computational electromagnetics and the basic procedure from the domain decomposition method, we present a biaxial parabolic approximation method for enlarging the angle domain in which the parabolic approximation to the acoustic wave equation is multiple applied and that can be used for migrating data with super-wide angles. Mathematically, the biaxial approximation is a special case of the multiaxial parabolic approximation, and thus can be straightforwardly extended to multiaxial approximations. In detail, we first divide the subsurface into several fan-shaped subdomains and use the axis of each subdomain as the local wave propagation direction. Then, we make a parabolic approximation to the wave equation in each subdomain with respect to the corresponding symmetry axis and compute the forward-propagating wave alternately using a high-order parabolic approximated wave equation in two subdomains. Finally, we use the computed forward-propagating wave as the boundary condition for calculating the back-scattered wave and Green's function by applying the thin slab approximation. Compared with most one-way methods, the proposed method can deal with the strong velocity contrast in the horizontal direction at a large scattering angles. Moreover, compared with certain full-wave methods that have been published in recent years, the proposed method is considerably more efficient and sacrifices only a little in terms of accuracy. Numerical results from comparisons with models of different complexities demonstrate that our method is cost-effective and has considerable potential for use in seismic modeling and imaging.",0,0,0
Seismic Data,Domain,"Xue, Ya-juan; Cao, Jun-xing; Wang, Xing-jian; Du, Hao-kun",Reservoir permeability estimation from seismic amplitudes using variational mode decomposition,Permeability estimation; Seismic amplitude; Variational mode decomposition; Reflection coefficient; Reservoir thickness,FLUID MOBILITY; ELASTIC WAVES; REFLECTION; PROPAGATION; ATTENUATION; POROSITY,A new qualitative Reservoir Permeability estimation approach using variational mode decomposition named RPE-VMD is proposed which directly use seismic amplitude and frequency attributes. The method reveals amplitude anomalies that may reflect details about the heterogenous distribution of reservoir permeability. The main procedure is carried out in the time-frequency domain which generates by using a generalized S transform. Reflection coefficient information is used as seismic amplitude attribute and extracted by using variational mode decomposition combined with mutual information theory from seismic data using the logarithmic spectrum. The dominant frequency extracted in the time-frequency domain is used as seismic frequency attribute for estimating reservoir thickness information. The RPE-VMD approach uses dominant reflection coefficient information from the seismic data combined with reservoir thickness information for permeability estimation. Application of this approach to field data from a sandstone reservoir in China illustrates that it can provide permeability estimation with a high resolution and accuracy. The proposed method directly uses seismic data to measure the reservoir permeability avoiding the need of seismic velocity in the conventional estimation methods.,0,0,1
Seismic Data,Domain,"Rollmann, Klaus; Soriano-Vargas, Aurea; Cirne, Marcos; Davolio, Alessandra; Schiozer, Denis Jose; Rocha, Anderson",A three-way convolutional network to compare 4D seismic data and reservoir simulation models in different domains,History-matching; 4D seismic data; Simulation models; Deep learning; Data assimilation; 3-way deep neural network,NEURAL-NETWORKS; HISTORY; PARAMETERIZATION,"Four-dimensional seismic (4DS) contains spatial information that provides insights into the location, shape, and movement of fluids (oil, gas, water). It helps engineers to adjust reservoir simulation models and increase their capability of providing reliable production forecasts. Recent probabilistic approaches consider hundreds of numerical simulation model scenarios, which require automated methods to evaluate this large number of numerical models based on observed 4D seismic data. Comparing spatial information of seismic and numerical simulation data is difficult as, usually, these data are converted to maps with different properties. We propose a novel approach to compare 4D seismic data and simulation models using a three-way deep neural network that is trained using a reference image (4D seismic data) with two simulation model candidates. It learns to find the simulation models that best characterize the reference. Our method is underpinned by more than a thousand pairs of simulation models and reference maps evaluated by human specialists for training. For testing, we compare the inter-rater agreement among different specialist groups and generate a reliable test set considering examples in which there was agreement among at least two specialists. We observed that the group with best-trained specialists agree more in their answers and have a considerably higher inter-rater agreement than the less trained groups. When we evaluate our method with the answers from this specialized group, we observe that the simulation model chosen by our method is the one agreed by the specialists in almost 90% of the cases. We also discuss the impact of different noise levels in the input and show that our method outperforms other approaches in the literature if noise is present both in the training and test sets.",0,0,2
Seismic Data,Gamma Ray,"Kim, Jongkook",New geomechanical application utilizing MWD gamma ray logs: An Eagle Ford case study,Geomechanics; MWD gamma Ray log; Young's modulus; Eagle ford,SHALE; STRENGTH,"Understanding mechanical rock properties is essential for optimal well placement and hydraulic stimulation design which directly impacts hydrocarbon productivity from shale reservoirs with ultra-low permeability. Current industrial practice is to assess spatial variability of subsurface mechanical properties through analyzing core and dipole sonic logs. Seismic inversion is another commonly applicable approach. However, although numerous existing approaches have contributed to upstream operators mitigating operational risk, these individual or combined evaluations ultimately require significant cost and time for exploration. These approaches also have limitations identifying fine-scale variability within inter-well spacing or along the length of a horizontal well due to sparse pilot-well control and the intrinsic limitation of seismic resolution. In this study, we propose a new approach to capture spatial variability of Young's modulus utilizing MWD (Measurement While Drilling) gamma ray logs of horizontal wells. The MWD gamma ray log is essentially acquired for the purpose of having geometric and stratigraphic information on well position while drilling in real time. And, due to cost and time related issues, shale operators commonly acquire only MWD log rather than core or wireline log set for horizontal production drilling while the massive pad drilling has the advantage of large areal coverage. Under the circumstance, MWD gamma ray log is often only data having geological implication. In purpose of utilizing MWD gamma ray log for geomechanical approaches, we examined a relationship between gamma ray and Young's modulus acquired from pilot wells. The MWD gamma ray logs were converted into Young's modulus logs and ultimately populated for three-dimensional property modeling. To validate the property model, an integrated assessment using wireline logs, microseismic, and three-dimensional seismic data was conducted. The study results demonstrate that this new geomechanical approach utilizing MWD gamma ray logs can be supportive or even serve as an alternative to the existing approaches. The method enables identification of finerscale spatial variability than sparse pilot-well control and conventional seismic analysis, which is attributed to the advantage of long-lateral, multi-benched, staggered, and dense production well placement. Based on the reliability and cost-effectiveness of the new approach, we expect it could help upstream operators mitigate risk and uncertainty related to geomechanical properties without excessive spending for exploration and ultimately improve hydrocarbon productivity with optimal well completion strategies.",0,0,0
Seismic Data,Gamma Ray,"Zhang, Yan; Zhang, Chunlei; Ma, Qiaoyu; Zhang, Xin; Zhou, Heng",Automatic prediction of shear wave velocity using convolutional neural networks for different reservoirs in Ordos Basin,Ordos basin; Shear wave velocity; Convolutional neural networks; Well logs; Rock-physics model,WELL LOG DATA; MACHINE; MODEL,"Shear wave velocity (S-wave velocity) has great significance for reservoir characterization and can effectively reduce the ambiguity in seismic interpretation. However, owning to its high cost and technical difficulties, it is usually difficult to obtain for the whole region. Therefore, the prediction of S-wave velocity currently has turned into an urgent task. Thus, the S-wave velocity was predicted using 1D convolutional neural network (1D-CNN) with the well logs. In the first step, the traditional Xu-White and Xu-Payne model were used to carry out the inversion of bulk modulus, shear modulus and density, and illustrated the phenomenon for the traditional rockphysics model. Then, 1D-CNN, including one input layer, four convolutional layers, three fully connected layers and one output layer, was proposed, in which three types of well logs (conventional well logs, array induction well logs and gamma ray spectral well logs) sensitive to the S-wave velocity were determined through the well logs analysis. Finally, based on the established 1D-CNN model, the influence of different well logs combination on the S-wave velocity prediction was analyzed, indicating that the addition of different well logs can improve the accuracy of S-wave velocity. And different machine learning methods (MLs), including back-propagation (BP) and support vector regression (SVR), were also compared, showing that the predicted accuracy of 1DCNN has been improved by 4.2% on average. Two cases for sandstone and carbonate reservoirs also showed that 1D-CNN proposed can achieve higher accuracy and better performance than traditional MLs and rockphysics models. Furthermore, the proposed method can be applied to the other oil and gas exploration fields, improving the exploration accuracy and increasing the production of oil and gas.",0,0,1
Seismic Data,Gamma Ray,"Kim, Jongkook",Petrophysical/geophysical approaches to identify ISIP variability in the Eagle Ford shale,Geomechanics; ISIP; MWD Gamma ray; Eagle ford; Seismic inversion,DEFORMATION; ROCKS,"Understanding geomechanical properties is essential for an optimal completion strategy that ensures commercial productivity in shale reservoirs with ultra-low permeability. This study provides details to identify the variability of Instantaneous Shut-In Pressure (ISIP) in multidisciplinary approaches using petrophysical and geophysical data. ISIP is one of the input data required for well completion design. Operators commonly ignore the variability of ISIP and use uniform geomechanical assumptions due to cost and time constraints. In the case study, the variability of ISIP was observed up to 30 % in a single horizontal well, which could lower the efficiency of hydraulic fracturing with uniform geomechanical assumptions along a horizontal well trajectory. We propose practical approaches to identify the variability of ISIP from a case study in the Eagle Ford shale. MWD (Measurement While Drilling) Gamma Ray log, which is commonly acquired for a geosteering purpose, was utilized to prove its correlation with actual ISIP data gained at frac-stages in horizontal production wells. Correlation between ISIP and microseismic data was analyzed to identify the integrated relationship among the variability of Gamma Ray, ISIP, and hydraulically-induced fracture. In addition, practical approaches using a series of seismic inversion and attribute data were proposed to help identify geological variabilities affecting ISIP. This study was designed to provide operators hands-on approaches to capturing the variability of ISIP under limited data accessibility. We suggest multifunctional ways using the basic datasets commonly available at field sites. It can be applied to mitigate risks concerning well planning, drilling, and completion design in where operators face frequent challenges from geomechanical heterogeneity in global shale plays.",0,0,2
Seismic Data,4D Seismic Data,"Oliver, Dean S.",Information content in 4D seismic data: Effect of correlated noise,Time-lapse seismic; 4D seismic; History matching,DATA ASSIMILATION; OBSERVATION ERRORS; SHANNON ENTROPY; MODELS,"Several types of data used in history matching for subsurface reservoir characterization have errors that are spatially or temporally correlated. Although it is often assumed that correlated observation errors decrease information content, using a simplified flow problem, we show that for data that are spatially dense (such as 4D seismic data), correlated observation errors result in higher information content than data with similar levels of errors, but without correlation. Unfortunately, correlations in the observation error are often unrecognized and difficult to estimate, especially if the correlation scale of the errors is similar to a characteristic length of the signal. In addition, many history matching algorithms are incapable of accounting properly for correlated observation error, so data are either thinned or the observation error is inflated to partially account for the lack of proper treatment. We show that neglecting correlations in the observation errors or inflating the variance, result in loss of information content. Finally, we show that it is possible to iteratively estimate the correlated observation errors through analysis of residuals after history matching.",0,0,0
Seismic Data,4D Seismic Data,"Danaei, Shahram; Silva Neto, Gilson M.; Schiozer, Denis J.; Davolio, Alessandra",Substituting petro-elastic model with a new proxy to assimilate time-lapse seismic data considering model errors,4D seismic; Petro-elastic model; Data assimilation; ES-MDA; Model error,SATURATION CHANGES; OBJECTIVE FUNCTION; PRESSURE; FIELD,"Dynamic data from oil and gas reservoirs (such as well-production or 4D seismic data) have been used often to reduce uncertainty in reservoir simulation models. These data are assimilated in the simulation models separately or jointly. Assimilation of 4D seismic data conventionally involves with a petro-elastic model (PEM) to transform outputs from the simulation models to elastic properties. The PEM is a set of different equations with uncertain parameters and its inclusion in assimilation algorithms calls on multidisciplinary teams of geoscientists and engineers. Moreover, PEM requires extraction of different outputs from the simulation models for the seismic forward model calculations. The extraction process can be costly for large-scale simulation models of giant reservoirs. This research presents a new petro-elastic proxy model (named DAI-Proxy) with a novel formulation to substitute the PEM and integrate 4D seismic data. DAI-Proxy relates time-lapse acoustic impedance to a summation of saturation and pressure changes with two coefficients which are functions of porosity. As the proxy is an approximation of the PEM, its application is affected by model error. We introduce two approaches to account for the proxy model error: (1) considering uncertain coefficients for the DAI-Proxy and (2) using fixed coefficients in the proxy while estimating model errors statistics from the prior ensemble of models. We incorporate these two approaches with a data assimilation algorithm to assimilate simultaneously 4D seismic and well-production data. A benchmark case is used with different cases of data assimilation to compare the DAIProxy and the PEM applications. Results show that data match quality for 4D seismic and well-production have similar responses for the PEM and DAI-Proxy implementations. In terms of production forecast, using fixed coefficients in the proxy with its model error treatment create a data assimilation framework comparable to the PEM case. Our results indicate that the traditional PEM application to integrate jointly 4D seismic and wellproduction data can be replaced with our new DAI-Proxy application. Given the degree of uncertainty in the PEM, related to the rock and fluid models, our proxy provides similar results with fewer uncertain inputs. The proxy offers further advantage as it needs less outputs from the simulation models for seismic forward model calculations. In addition, it helps petroleum engineers to use a computationally less expensive model (light model) as a substitute for the PEM to assimilate 4D seismic data.",0,0,1
Seismic Data,4D Seismic Data,"Rollmann, Klaus; Soriano-Vargas, Aurea; Cirne, Marcos; Davolio, Alessandra; Schiozer, Denis Jose; Rocha, Anderson",A three-way convolutional network to compare 4D seismic data and reservoir simulation models in different domains,History-matching; 4D seismic data; Simulation models; Deep learning; Data assimilation; 3-way deep neural network,NEURAL-NETWORKS; HISTORY; PARAMETERIZATION,"Four-dimensional seismic (4DS) contains spatial information that provides insights into the location, shape, and movement of fluids (oil, gas, water). It helps engineers to adjust reservoir simulation models and increase their capability of providing reliable production forecasts. Recent probabilistic approaches consider hundreds of numerical simulation model scenarios, which require automated methods to evaluate this large number of numerical models based on observed 4D seismic data. Comparing spatial information of seismic and numerical simulation data is difficult as, usually, these data are converted to maps with different properties. We propose a novel approach to compare 4D seismic data and simulation models using a three-way deep neural network that is trained using a reference image (4D seismic data) with two simulation model candidates. It learns to find the simulation models that best characterize the reference. Our method is underpinned by more than a thousand pairs of simulation models and reference maps evaluated by human specialists for training. For testing, we compare the inter-rater agreement among different specialist groups and generate a reliable test set considering examples in which there was agreement among at least two specialists. We observed that the group with best-trained specialists agree more in their answers and have a considerably higher inter-rater agreement than the less trained groups. When we evaluate our method with the answers from this specialized group, we observe that the simulation model chosen by our method is the one agreed by the specialists in almost 90% of the cases. We also discuss the impact of different noise levels in the input and show that our method outperforms other approaches in the literature if noise is present both in the training and test sets.",0,0,2
Seismic Data,AI Models,"Sadeghi, Mehdi; Madani, Nasser; Falahat, Reza; Sabeti, Hamid; Amini, Navid",Hierarchical reservoir lithofacies and acoustic impedance simulation: Application to an oil field in SW of Iran,Hierarchical simulation; Pluri-Gaussian simulation; Turning bands simulation; Lithofacies; Acoustic impedance,CONDITIONAL SIMULATION; POINT; UNCERTAINTY; PROGRAM,"In this study, a hierarchical simulation algorithm was implemented to produce 3D models of lithofacies and acoustic impedance (AI) in an oil field in southwestern Iran. Hierarchical simulation is a powerful method that takes into account the spatial distribution and hard contact relationships of continuous variables within the categorical variables in reservoir characterization. To implement the hierarchical simulation algorithm in this study, pluri-Gaussian simulation was used to construct the layouts of one categorical variable (lithofacies domains) and turning bands simulation was used to produce one continuous variable (AI models) within each simulated domain. The dataset that is available to test the proposed method includes the lithofacies and AI logs of seven wells. For validation of the proposed model, one of wells was excluded from the initial dataset to check the accuracy of results. The algorithm was implemented on a gridded model to produce 50 realizations of 3D lithofacies and AI models. The statistical analyses of the produced models verified the capabilities of hierarchical simulation in reproducing the lithofacies domains and AI values related to each domain. The simulated AI models were compared with the seismic inversion model to corroborate the reliability of the results. In addition, to show the superiority of the hierarchical approach, the results were compared to the results of direct AI modeling in which the AI models were generated without considering any lithofacies data. The comparisons in the blind well indicated a high correlation between the modeled values and the true AI. The correlation coefficient between average AI models of the hierarchical approach and the true AI was 0.85. Whereas, this value was 0.75 for the average of directly simulated AI models and 0.74 for the seismic inversion, respectively. Histogram analysis also verified the capability of the hierarchical modeling in reproducing the statistical properties of the original data. The resulting AI model obtained using the method proposed in this study also showed a high compatibility with the deterministic seismic inversion cube.",0,0,0
Seismic Data,AI Models,"Zhang, Jian; Li, Jingye; Chen, Xiaohong; Li, Yuanqiang",Geological structure-guided hybrid MCMC and Bayesian linearized inversion methodology,Seismic inversion; Plane wave destruction (PWD); Block coordinate descent (BCD); Acoustic impedance (AI); Uncertainty evaluation,,"Seismic inversion is a common method for hydrocarbon reservoir characterization, as it consists of a proven and effective approach to derive elastic properties from reflectivity seismic data. Markov Chain Monte Carlo (MCMC) based seismic inversion approach is a suitable choice to numerically evaluate the posterior uncertainties associated with the inverse solution without assuming linear forward operators, Gaussian, or generalized Gaussian prior models. However, the existing MCMC based seismic inversion approaches are mostly performed trace-bytrace, which means that the spatial coupling of model parameters is not considered. When the results of trace-bytrace based inversion are combined to generate a 2D profile, the final results will be laterally discontinuous. Moreover, the large dimension of the model space causes low convergence efficiency of MCMC-based seismic inversion. To overcome these issues, a geological structure-guided hybrid MCMC and Bayesian linearized inversion (BLI) methodology for seismic inversion is implemented. The geological structure information obtained using plane wave destruction (PWD) is incorporated to the MCMC based inversion algorithm in the form of dips yields more geologically meaningful results. The hybrid MCMC and BLI strategy, which takes advantage of BLI s high efficiency to provide initial configuration for MCMC, is used to improve the convergence of MCMC-based inversion. Additionally, the block coordinate descent (BCD) algorithm is introduced to replace the large-scale matrix solution in geological structure-guided, and consequently reduce memory consumption and time cost. This methodology is validated on a synthetic seismic dataset, as well as on a real case. It has proven to be a reliable approach to obtain acoustic impedance (AI) from post-stack seismic data in an efficient way. It also addresses the uncertainty related with the ill-posed characteristics of the inversion methodology itself.",0,0,1
Seismic Data,AI Models,"Gholami, Amin; Amirpour, Masoud; Ansari, Hamid Reza; Seyedali, Seyed Mohsen; Semnani, Amir; Golsanami, Naser; Heidaryan, Ehsan; Ostadhassan, Mehdi",Porosity prediction from pre-stack seismic data via committee machine with optimized parameters,Porosity; Seismic pre-stack (SPS); Optimized model (OM); Committee machine (CM); Bat-inspired algorithm (BA),SUPPORT VECTOR REGRESSION; RESERVOIR CHARACTERIZATION; PERMEABILITY PREDICTION; SANDSTONE RESERVOIR; INTELLIGENT SYSTEMS; REFRACTIVE-INDEX; MODEL; ATTRIBUTES; ALGORITHM,"Prediction of porosity from the seismic data via geophysical methods when limited number of wells are available is a challenging task that has high uncertainties. This study aims to construct a hybrid data-driven predictive model to establish a quantitative correlation between seismic pre-stack (SPS) data and the porosity. First, three intelligent models that are optimized by bat-inspired algorithm (BA): optimized neural network (ONN), optimized fuzzy inference system (OFIS), and optimized support vector regression (OSVR) are constructed for relating porosity to the SPS data. Then, to benefit from all individual optimized models, a final hybrid model was built via committee machine (CM) where single models are combined with a proper weight to predict porosity in the reservoir space. This approach is examined on the SPS data from an oil field in the Persian Gulf with a single exploratory well where input parameters (Vp, Vs, and rho) to the AI models are derived from a two-parameter inversion method. We found that the coefficient of determination, root mean square error, average absolute relative error, and symmetric mean absolute percentage error for the CM are 0.923615, 0.015793, 0.132280, and 0.061310, respectively. Moreover, based on four statistical indexes that are calculated for each model, CM outperformed its individual elements followed by the OSRV. A comprehensive analysis of the results confirms that CM with the OM elements is a superior approach for computing porosity from the SPS in the well and then throughout the entire reservoir volume. This strategy can aid petroleum engineers to have a better forecast of porosity population in the reservoir static model immediately following the data that is obtained from the first exploratory well. Ultimately, successful implementation of this approach will promptly delineate sweet spots that can replace uncertain and complicated conventional geophysical methods.",0,0,1
Seismic Data,Source Rocks,"Wang, Feilong; Tang, Guomin; Wang, Deying; Pan, Wenjing; Yang, Hong; Awan, Rizwan Sarwar",Paleoenvironmental characteristics and evidence of subsag migration within the Laizhouwan Sag in the Bohai Sea,Sag-migration; Paleoenvironment; Paleoproductivity; Palynofacies; Laizhouwan sag; Bohai sea,DEPOSITIONAL ENVIRONMENT; SHALE; OIL,"The Laizhouwan Sag comprises many sets of source rocks, and their crude oil properties are complex and changeable. This research evaluates the quality of source rocks using mudstone samples of the Shahejie Formation from typical wells from northern and southern subsags by incorporating a detailed organic-inorganic geochemical, palynology and petrological analysis. Moreover, it analyzes the difference between the paleoenvironment and paleoproductivity. It also discusses the migration characteristics of the sag in combination with seismic data to reveal the fundamental reason for the complex oil source characteristics of the Laizhouwan sag. The results show there are two sets of effective source rocks in the northern subsag of the Laizhouwan Sag, (i) the third member of the Shahejie Formation(E2s3) (ii) the fourth member of the Shahejie Formation (E2s4). Additionally, the E2s4 is a high-quality, effective source rock in the southern subsag of Laizhouwan Sag. (2) During the sedimentary period of the E2s4 in Laizhouwan Sag, the water bodies of the southern and northern subsags were separated. The organic matter (OM) in the E2s4 of northern subsag mainly comes from lower algae, mainly amorphous, and deposited in a weak reducing environment of brackish water. The OM in the E2s4 of southern subsags mainly comes from terrigenous higher plants, mainly composed of terrigenous amorphous assemblages, and it was deposited in a strongly reducing environment of brackish water to saline water. (3) Moreover, the water bodies of the southern and northern subsags gradually changed to unified water bodies during the sedimentary period of the E2s3. During this period, OM comes from lower algae, mainly from amorphous material, and the water bodies were transformed to a weak oxidation-reduction environment from freshwater-brackish water. The subsidence center of the Laizhouwan sag continued to move southward during the sedimentary period of E2s4-E2s3. Gradually the southern subsag became a sedimentary center containing higher paleoproductivity and eutrophic lake settings. The differences in organic source, sedimentary environment and paleoproductivity of source rocks in different subsags lead to the complexity of crude oil generation features.",0,0,1
Seismic Data,Source Rocks,"Han, Jianhui; Steel, Ronald J.; Hou, Mingcai; Li, Yangyang; Yuan, Lizhong; Zheng, Jinyun; Liu, Jun","Subsidence and maturation evolution of a new lower-slope minibasin, Xingning Sag, northern South China Sea",Lower slope basin; Backstripping; Thermal modeling; Maturation history; South China Sea,RIVER MOUTH BASIN; TECTONIC SUBSIDENCE; QIONGDONGNAN BASIN; CONTINENTAL-MARGIN; ANOMALIES; EXTENSION; HISTORY,"Study of Subsidence and maturation evolution of a continental slope basin without a drilled well is an important problem in the early stage of deep-water exploration. Lack of some parameters, such as stratigraphic-age, porosity-depth relationship, exact paleo-water depth and heat flow value are common problems in the study of subsidence and maturity history. Using 46 long 2D seismic lines and paleo-water depth data from paleonto-logical data of a well on the slope toe, the present study combines backstripping with thermal modeling to reconstruct the subsidence and maturation evolution of a lower-slope minibasin, Xingning Sag (XS), on the southeast Pearl River Mouth Basin (PRMB) of the South China Sea (SCS), now a new prospecting area. Stratigraphic-ages, porosity-depth relationship, lithology of XS were estimated using data from an adjacent basin. Paleo-water depths were obtained by clinoform geometry using seismic facies and paleontological method. With these parameters, the subsidence curves were created by backstripping. Crustal stretching factors (beta) were obtained by best fit of tectonic subsidence curve and thermal modeling. With these stretching factors, the theoretical subsidence and heat flow values were obtained at the same time. Based on the heat flow value and the backstripping parameters, the maturation history of this basin was simulated. The result shows XS evolved through three cycles of subsidence during 46-23.03 Ma, 23.03-13.82 Ma and 13.82-0 Ma, respectively. Each cycle shows a rifting phase of relatively rapid tectonic subsidence followed a cooling phase of slow subsidence. Potential Eocene lacustrine source rocks are distributed primarily in the central depression area (Xingning main sub-sag), and would have entered the main oil-generation window and main gas generation during early- and mid-Miocene respectively.",0,0,2
Seismic Data,Approximation,"Meng, Xiangyu; Sun, Jianguo; Wei, Puli; Xu, Yangyang; Xu, Zeshuang",Superwide-angle seismic migration by including the back-scattered wave through domain decomposition and biaxial parabolic approximation,Parabolic approximation; Domain decomposition; Scattering; Green's function,EQUATION; SCATTERING; ALGORITHM,"Using ideas from computational electromagnetics and the basic procedure from the domain decomposition method, we present a biaxial parabolic approximation method for enlarging the angle domain in which the parabolic approximation to the acoustic wave equation is multiple applied and that can be used for migrating data with super-wide angles. Mathematically, the biaxial approximation is a special case of the multiaxial parabolic approximation, and thus can be straightforwardly extended to multiaxial approximations. In detail, we first divide the subsurface into several fan-shaped subdomains and use the axis of each subdomain as the local wave propagation direction. Then, we make a parabolic approximation to the wave equation in each subdomain with respect to the corresponding symmetry axis and compute the forward-propagating wave alternately using a high-order parabolic approximated wave equation in two subdomains. Finally, we use the computed forward-propagating wave as the boundary condition for calculating the back-scattered wave and Green's function by applying the thin slab approximation. Compared with most one-way methods, the proposed method can deal with the strong velocity contrast in the horizontal direction at a large scattering angles. Moreover, compared with certain full-wave methods that have been published in recent years, the proposed method is considerably more efficient and sacrifices only a little in terms of accuracy. Numerical results from comparisons with models of different complexities demonstrate that our method is cost-effective and has considerable potential for use in seismic modeling and imaging.",0,0,0
Seismic Data,Approximation,"Danaei, Shahram; Silva Neto, Gilson M.; Schiozer, Denis J.; Davolio, Alessandra",Substituting petro-elastic model with a new proxy to assimilate time-lapse seismic data considering model errors,4D seismic; Petro-elastic model; Data assimilation; ES-MDA; Model error,SATURATION CHANGES; OBJECTIVE FUNCTION; PRESSURE; FIELD,"Dynamic data from oil and gas reservoirs (such as well-production or 4D seismic data) have been used often to reduce uncertainty in reservoir simulation models. These data are assimilated in the simulation models separately or jointly. Assimilation of 4D seismic data conventionally involves with a petro-elastic model (PEM) to transform outputs from the simulation models to elastic properties. The PEM is a set of different equations with uncertain parameters and its inclusion in assimilation algorithms calls on multidisciplinary teams of geoscientists and engineers. Moreover, PEM requires extraction of different outputs from the simulation models for the seismic forward model calculations. The extraction process can be costly for large-scale simulation models of giant reservoirs. This research presents a new petro-elastic proxy model (named DAI-Proxy) with a novel formulation to substitute the PEM and integrate 4D seismic data. DAI-Proxy relates time-lapse acoustic impedance to a summation of saturation and pressure changes with two coefficients which are functions of porosity. As the proxy is an approximation of the PEM, its application is affected by model error. We introduce two approaches to account for the proxy model error: (1) considering uncertain coefficients for the DAI-Proxy and (2) using fixed coefficients in the proxy while estimating model errors statistics from the prior ensemble of models. We incorporate these two approaches with a data assimilation algorithm to assimilate simultaneously 4D seismic and well-production data. A benchmark case is used with different cases of data assimilation to compare the DAIProxy and the PEM applications. Results show that data match quality for 4D seismic and well-production have similar responses for the PEM and DAI-Proxy implementations. In terms of production forecast, using fixed coefficients in the proxy with its model error treatment create a data assimilation framework comparable to the PEM case. Our results indicate that the traditional PEM application to integrate jointly 4D seismic and wellproduction data can be replaced with our new DAI-Proxy application. Given the degree of uncertainty in the PEM, related to the rock and fluid models, our proxy provides similar results with fewer uncertain inputs. The proxy offers further advantage as it needs less outputs from the simulation models for seismic forward model calculations. In addition, it helps petroleum engineers to use a computationally less expensive model (light model) as a substitute for the PEM to assimilate 4D seismic data.",0,0,1
Seismic Data,Reservoir Thickness,"Xue, Ya-juan; Cao, Jun-xing; Wang, Xing-jian; Du, Hao-kun",Reservoir permeability estimation from seismic amplitudes using variational mode decomposition,Permeability estimation; Seismic amplitude; Variational mode decomposition; Reflection coefficient; Reservoir thickness,FLUID MOBILITY; ELASTIC WAVES; REFLECTION; PROPAGATION; ATTENUATION; POROSITY,A new qualitative Reservoir Permeability estimation approach using variational mode decomposition named RPE-VMD is proposed which directly use seismic amplitude and frequency attributes. The method reveals amplitude anomalies that may reflect details about the heterogenous distribution of reservoir permeability. The main procedure is carried out in the time-frequency domain which generates by using a generalized S transform. Reflection coefficient information is used as seismic amplitude attribute and extracted by using variational mode decomposition combined with mutual information theory from seismic data using the logarithmic spectrum. The dominant frequency extracted in the time-frequency domain is used as seismic frequency attribute for estimating reservoir thickness information. The RPE-VMD approach uses dominant reflection coefficient information from the seismic data combined with reservoir thickness information for permeability estimation. Application of this approach to field data from a sandstone reservoir in China illustrates that it can provide permeability estimation with a high resolution and accuracy. The proposed method directly uses seismic data to measure the reservoir permeability avoiding the need of seismic velocity in the conventional estimation methods.,0,0,1
Seismic Data,Reservoir Thickness,"Sun, Zhifeng; Bai, Qinglin; Ren, Huaiqiang; Yan, Ke; Gao, Liang; Wei, Liu Zhong","Quantitative evaluation of morphological characteristics of thin sand body: Taking the deltaic distributary channel sand body as an example in Shengtuo oil field of Dongying sag, east of Bohai Bay Basin*",Thin interbeds; Distributary channel; Architecture; Quantitative model; Sandstone reservoir,SEISMIC ATTRIBUTES; RESERVOIRS; DEPOSITS; ARCHITECTURE; DEPRESSION; PREDICTION,"Because of the small scale of distributary channel sand body and the superposition of sand bodies in vertical and lateral direction, drilling data with 150-200 m well spacing is difficult to describe its scale, shape and connectivity characteristics effectively. It has a great restriction on the recovery of these reservoirs. Taking Sheng2 Block of Shengtuo Oilfield as an example, the architectural elements of distributary channel are quantitatively investigated by using dense-drilling well and seismic data. Based on frequency division seismic data, the boundary of distributary channel belts are described vertically and laterally, and then the scale and morphological characteristics of channel bodies in the channel belt are characterized by using local dense well pattern data. The target layer can be divided into six channel belts longitudinally. After seismic frequency demultiplication, 60-75 Hz seismic data was used to describe the distribution of channel belts. From the bottom to the top, the width and distribution range of the channel belts decrease as a whole. Channel belt thickness and its width show linear positive correlation. On the channel-belt cross section, channel stories on the dense drilling-well logging profiles are identified with reference to the profile geometry of the distributary channel. On the channel-belt cross section, the projection distance between wells is fitted to a linear correlation with the thickness variation of channel stories. The ratio of the two parameters decreases from bottom to top of the target layer as a whole. The channel shape parameters predicted by the dense drilling-well logging section are of great significance to the study of paleocurrent deposition and paleohydrological evolution. At the same time, it has guiding significance for the development and adjustment of oil and gas reservoirs.",0,0,2
Degrees C.,Formation Water,"Kadafur, Ibrahim; BinGhanim, Ahmed; Aljawad, Murtada Saleh; Kamal, Muhammad Shahzad; AlYousef, Zuhair; Mahmoud, Mohamed",Rheological study of CO2 foamed chelating stimulation fluids under harsh reservoir conditions,Foam; Chelating agents; Stimulation fluids; Acidizing; Foam rheology,STABILITY; DRAINAGE; EOR,"Foamed acid is usually an HCl acid-based stimulation fluid applied to carbonate reservoirs. However, this study investigates the rheology of a CO2 foamed chelating agent, L-glutamic acid-N, N-diacetic acid (GLDA), that acts as less corrosive, environmentally friendly, and more stable foamed acid. Foam rheometer and analyzer were used to study the foam rheology, quality, size and structure, and half-life. Five different commercial surfactants with different chemical structures were investigated. The study was conducted at 100 degrees C, 1000 psi, 3.5 pH level, and various water salinity, resembling harsh reservoir conditions. The general trend showed that the higher the water salinity, the higher the effective viscosity. It also showed that the chelating agent improved the effective viscosity of the high total dissolved solids (TDS) water samples. The highest viscosity (76 mPa.s) was attained by mixing GLDA with a cationic alkyl diamine derivative surfactant in formation water at a 100 1/s shear rate. The prolonged constant shear rate experiments revealed that some formulations are stable for more than 8 h. The study revealed that higher surfactant concentrations did not result in improved performance. For the first time, the study reveals that chelating agents could be used as a stable stimulation foamed fluid at harsh reservoir conditions.",0,0,1
Degrees C.,Formation Water,"Bahu, Juliana Otavia; Miranda, Nahieh Toscano; Khouri, Nadia Gagliardi; Batistella, Cesar Benedito; Cardenas Concha, Viktor Oswaldo; Wolf Maciel, Maria Regina; Rocha Barbosa Schiavon, Maria Ingrid; Maciel Filho, Rubens",Crude oil emulsion breaking: An investigation about gravitational and rheological stability under demulsifiers action,Bottle test; Dehydration; Demulsifier testing; Emulsion breaking; Rheology; Stability,PETROLEUM EMULSIONS; DROPLET SIZE; WATER; LIGHT; METHODOLOGY; TEMPERATURE; SURFACTANTS; PERFORMANCE; VISCOSITY; SALINITY,"Emulsions are common in the oil industry, being present in the extraction and production stages. Its formation occurs with the contact of brine and crude oil under intense flow. The presence of emulsified water (dispersed droplet size, phi <= 50 mu m) in crude oil can negatively impact its exploration, transportation, and refining, making transportation more expensive, requiring more energy for heating, and causing equipment corrosion on all processes. In addition, crude oil has salts and sediments that encrust and corrode equipment of the primary oil treatment unit and distillation towers, also causing catalyst poisoning in the cracking step. Therefore, such components need to be removed for subsequent refining processes. To prevent these problems, the dehydration/ desalting of crude oils is a strategy adopted to reach adequate values of water, salts, and sediments required in the refineries for the next steps after primary treatment. However, the emulsion breaking is influenced by several factors that affect the stability of crude oil (W/O emulsion), such as viscosity, contents of water, salts, sediments, and natural surfactants, among others. Given this perspective, this work investigated the stability of two different types of crude oils with demulsifier under the action of gravity (bottle test) and shear stress (rheology). The comparisons of gravitational and rheological techniques concluded that the shear stress sweep analyses are useful to evaluate the demulsifier performance in the emulsion breaking, being a reliable and fast methodology. Such studies allowed the identification of adequate parameters: temperature (80 degrees C) and, demulsifier type and quantity (500 ppm) for efficient crude oil phase separation, without using washing water. The physicochemical and rheological characterizations clarified the crude oil's colloidal stability behavior to understand the impurities' influence on the oils' properties (crude and desalted).",0,0,2
Degrees C.,Formation Water,"Pashapouryeganeh, Farzad; Zargar, Ghasem; Takassi, Mohammad Ali; kadkhodaie, Ali; Rabiee, Ahmad",One-Pot synthesis of modified-cationic surfactants for enhanced oil recovery applications in carbonate reservoirs,Surfactant synthesis; Cationic surfactant; Quaternary ammonium salt; Wettability alteration; IFT reduction; Chemical enhanced oil recovery (CEOR),INTERFACIAL-TENSION BEHAVIOR; DETERMINING IONS CA2+; HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; POROUS-MEDIA; CHAIN-LENGTH; WET; MECHANISM; LIQUID,"In this study two cationic surfactants, dodecyltriethylammoniumbromide (C(12)TEAB) and hexadecyl-triethylammoniumbromide (C(16)TEAB) were prepared. The formation of synthezied surfactants were confirmed using FTIR and HNMR spectroscopy. Electrical conductivity, interfacial tension and surface tension methods were used to determine the critical micelle concentrations (CMC) of these surfactants. To understand the behavior of synthesized surfactants in harsh environments, the CMC was measured in deionized water (DIW), sea water and petroleum formation water. Using electrical conductivity technique, for C(12)TEAB surfactant the CMC values of 4000 ppm, 2000 ppm and 850 ppm were recorded in DIW, sea water and formation water respectively. For C(16)TEAB surfactant, the CMC values of 420 ppm, 190 ppm and 115 ppm were obtained in DIW, sea water and formation water respectively. The similar CMC results were obtained using the interfacial tension (IFT) and surface tension (ST) methods. Reduction of IFT between crude oil and formation water and also alteration of wettability of petroleum reservoir of carbonated rock from oil-wet (large contact angle) to water-wet (small contact angle) are two major factors affecting chemical enhanced oil recovery (EOR). Interfacial tension (IFT), surface tension (ST) and contact angle measurements were carried out using an IFT-PDSA-06 apparatus (Apex Technologies Company, Iran). The IFT and ST of these surfactants were also carried out in DIW, sea water and formation water. For C(12)TEAB surfactant, the IFT values of 0.051 mN/m, 0.036 mN/m and 0.023 mN/m were recorded in DIW, sea water and formation water respectively. The IFT values of 0.044 mN/m, 0.026 mN/m and 0.0126 mN/m were measured for C(16)TEAB surfactant in DIW, sea water and formation water respectively. The effect of temperature on IFT was studied for both surfactants. When temperature increases, IFT decreases. The reduction of IFT continues up to 55 degrees C, then the IFT increases with increasing temperature. For C(12)TEAB surfactant, the ST values of 44.9 mN/m, 38.8 mN/m and 31.8 mN/m were obtained in DIW, sea water and formation water respectively. In similar measurements for C(16)TEAB surfactant, the recorded ST values were 33.95; 32.9 and 32.22 mN/m in DIW, sea water and formation water respectively. In wettability alteration study both surfactants altered the contact angle from oil-wet to water-wet conditions. Using formation water and C(12)TEAB surfactant, the contact angle varied from 96.4 degrees to 54.5 degrees. In similar study using C(16)TEAB surfactant the contact angle changed from 92 degrees to 46.1 degrees. The contact angles of these surfactants in DIW and sea water were also measured and reported. The results of IFT and wettability studies demonstrated excellent potential application of synthesized surfactants in EOR process in carbonate petroleum reservoirs.",0,0,3
Degrees C.,Formation Water,"Ettehadi, Ali; Ulker, Ceylan; Altun, Gursat",Nonlinearity in large amplitude oscillatory shear of drilling fluid: A comparative study on the oil and water base muds behavior,Drilling fluid; Nonlinear viscoelasticity; Large amplitude oscillatory shear (LAOS); Shear mechanism; Structural stability,VISCOELASTIC PROPERTIES; PRESSURE-DROP; LAOS BEHAVIOR; MODEL; RHEOLOGY; STRESS; TRANSITION; VISCOSITY; EQUATION,"A viscoelastic material exhibits both fluid (viscous) and solid (elastic) like properties simultaneously. The rheological behavior of drilling fluids is customarily measured under the assumption of pure viscous flow, yet they exhibit both viscous and elastic characteristics when subjected to deformation. Some imperative properties of drilling fluids such as gel strength, yield stress, and sag tendency at near-zero shear rate region are categorically under the influence of viscoelastic behavior and have not yet been completely understood due to the lack of appropriate measurement methods. Characterizing the complete rheological profile of material requires measuring linear and nonlinear viscoelastic responses at a wide range of stress/strain levels. The viscoelastic nonlinearity can be characterized under Large Amplitude Oscillatory Shear (LAOS) tests. This study presents a large amplitude oscillatory shear rheology investigation of two water-base (Lignosulfonate and KCl/polymer) and two oil-base (low and high temperature) drilling fluids each in three states; unweighted, weighted, and weighted-contaminated. The viscoelastic nonlinearities of four fluid samples were investigated experimentally as a function of strain amplitude and strain-rate space at different temperatures. The results were described using Lissajous-Bowditch (L-B) plots and local nonlinear viscoelastic dynamic moduli through an oscillatory shear cycle. Structural stability of fluid samples was also studied using the creep-recovery test. The nonlinear viscoelastic behavior of drilling fluids was comprehensively compared and distinguished to understand their nonlinear shear mechanism. As a result of the creep-recovery test at 150 degrees C, high-temperature oil base mud provided higher thermostructural stability and zero shear viscosity than those of Lignosulfonate, KCl/polymer, and low-temperature oil-base muds. While the elastic nonlinearity was found to be strain/strain rate softening, the nonlinear viscous character was recorded as shear/shear rate thinning at large strain rates for all drilling fluid systems. Quite a different shear mechanism was detected at low and moderate strain rates. Shear rate thinning was found to be the dominant mechanism for all fluids except Lignosulfonate mud samples that demonstrated shearthickening behavior at moderate strain rates at 25 degrees C. At high temperatures (100 degrees C and 150 degrees C), shear rate thickening followed by shear rate thinning behavior was governing mechanism under the low and moderate strain rates in all mud samples except KCl/polymer muds. An inverse behavior (shear rate thinning followed by shear rate thickening) was observed through low and moderate strain rates in KCl/polymer muds at 100 degrees C and 150 degrees C. Therefore, as revealed from the LAOS test results, shear rate thickening behavior at low to moderate strain rates is in contradiction of the commonly known shear thinning behavior for a drilling fluid undergoing viscous deformation. This finding explains the facts underlying some important properties of drilling fluids such as gel structure formation, hole cleaning ability, and sag tendency.",0,0,3
Degrees C.,Formation Water,"Liu, Chao; Zhao, Wanchun; Sun, Lidong; Wang, Xiaolian; Sun, Youhai; Zhang, Ying; Zhang, Jingjing; Zhang, Lei; Li, Jijun","Geochemical assessment of the newly discovered oil-type Shale in the Shuangcheng area of the northern Songliao Basin, China",Shale; Geochemistry; Hydrocarbon potential; Shuangcheng depression; Songliao basin,HYDROCARBON SOURCE ROCKS; DEPOSITIONAL ENVIRONMENT; CARBON ISOTOPES; ORGANIC-MATTER; TRACE-ELEMENTS; SOUTH CHINA; DEPRESSION; LACUSTRINE; MATURATION; EXPULSION,"For the past fifty years, the northern Songliao Basin in China was thought to contain Lower Cretaceous coal-measure and gas-generating shale. Oil-type shales did not receive much attention until oil exploration activities made a breakthrough in the Southern Shuangcheng (SSC) depression. In this study, the geochemical characteristics of the newly discovered K(1)yc(4) (fourth member of the Lower Cretaceous YingCheng Formation) oil-type shale in the SSC depression were analyzed, including the organic matter abundance, organic matter type, thermal maturity, hydrocarbon potential, and sedimentary environment. A total of 393 core samples were collected, and Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), organic petrography, carbon isotope analysis, and constant and trace element analyses were conducted. The K(1)yc(4) shale was determined to have a good to excellent hydrocarbon potential with high TOC values (mostly 2.0-4.0%). The organic matter was mainly from lower hydrobiont, algae, bacteria, and lesser amounts of terrestrial plants. The organic matter is mainly type Ito type II based on the hydrogen index (HI) (average HI = 193.36 mg HC/g TOC), the carbon isotopes of the kerogen (mostly -26 to -30 parts per thousand), and the organic petrography (average sapropelinite + liptinite of 55.0 vol%). The maturity parameters, i.e., T-max (mean 452 degrees C) and vitrinite reflectance (0.8-1.1%), suggest that the shale is in the mature thermal evolution stage. The shale's maximum hydrocarbon-generating intensity is up to 713.29 x 10(4)/km(2), and its hydrocarbon-expelling intensity is stable at 116.63 x 10(4)/km(2). The constant and trace element analyses (Sr, Ba, V, Ni, Cr, Ti) revealed that the organic matter deposition and preservation occurred in a fresh-brackish and dysoxic-anoxic water environment. Volcanic eruptions probably played a vital role in the enrichment of the organic matter in the oil-type shale. In addition, the results of this study provide evidence that the Lower Cretaceous strata in the northern Songliao Basin meet the geological conditions of oil-prone shale, which expands the petroleum exploration horizon in this region.",0,0,3
Degrees C.,Drilling,"Angga, I. Gusti Agung Gede; Stanko, Milan",Automated decision support methodology for early planning phase of a multi-reservoir field,Field development planning; Optimization; Proxy model; Mixed-integer linear programming; Uncertainty analysis,PRODUCTION OPTIMIZATION; NETWORK,"The field planning process is a crucial phase in the life of a hydrocarbon field when many design features must be decided upon. The field development team has the task of finding a configuration of these field design features which maximizes the value of the company's asset while considering several constraints. This paper presents a decision support methodology suitable for the early stage of the field planning process. The methodology is applied on a synthetic field called Safari. This field is characterized by having multiple reservoir units, where these reservoir units are non-communicating and have distinct properties. The reservoirs, namely Love, Nesehorn, and Sebra, have original oil-in-place (OOIP) of 75, 55, and 13 million sm(3), respectively. Both Love and Nesehorn have a permeability of 250 mD, whereas Sebra has a higher permeability of 450 mD. All these reservoirs lie 2500 m below the sea level with an initial reservoir pressure of 280 bara and an initial reservoir temperature of 80 degrees C. The main part of the methodology is a mathematical optimization that uses (i) proxy models to represent the flow performance of the production system and to estimate the development costs and (ii) piecewise linear (PWL) approximations to represent the non-linear functions. In this study, two optimization problems with the objective function to maximize plateau duration or net present value (NPV) are formulated and solved. The optimization models consider production schedule, drilling schedule, and recovery mechanism as the decision variables. Some constraints concerning production, injection, and drilling are also included in the optimization models. According to the optimization results, the objective value can be improved by considering more decision variables in the optimization problems. For example, including the drilling schedule and recovery mechanism as decision variables gives us 85% higher optimal NPV than optimizing the production schedule alone. Several investigations have been made to reduce the optimization runtime and to ensure the accuracy of the optimization results. Furthermore, the uncertainty of the optimization results has been quantified through uncertainty analyses. These analyses consider three uncertain parameters, i.e., OOIP, development costs, and oil price. Two approaches have been evaluated for conducting the uncertainty analysis, i.e., using the Latin hypercube sampling (LHS) method and using a probability tree. The uncertainty analysis using a probability tree is recommended because it requires less time to complete while produces similar results as the other approach.",0,0,0
Degrees C.,Drilling,"Deng, Chunping; Du, Guoyong; Li, Xingchun; Xi, Junnan; Lin, Chen",Effect of high temperature and high pressure on the biodegradability and biotoxicity of typical additives in drilling fluid,Drilling fluid additives; HTHP; Biodegradability; Biotoxicity; Structure,XANTHAN GUM; PHYSICOCHEMICAL PROPERTIES; XANTHOMONAS-CAMPESTRIS; OIL; DEGRADATION; ASPHALT; PROTEIN; MUD; XPS,"Under the high-temperature and high-pressure (HTHP) conditions in the ground, the environmental features of drilling fluid additives may change to some extent. But the relevant information of the influence of HTHP environment on drilling fluid additives is very limited. Four typical additives, namely, sulfonate asphalt (SEB), potassium polyacrylamide (KPAM), potassium humate (KHm) and xanthan gum (XG), were treated for 40 min under two typical bottom hole conditions of 7 MPa, 90 degrees C and 11 MPa, 120 degrees C. The biodegradability and biotoxicity of these additives before and after treatments were determined. The structures of the four additives were also analyzed by Fourier transform infrared spectroscopy (FT-IR), X-ray photoelectron spectroscopy (XPS), nuclear magnetic resonance spectroscopy (NMR), thermogravimetric analysis (TGA) and gas chromatography-mass spectrometry (GC-MS). The results revealed no remarkable difference in biotoxicity and biodegradability of each sample between the two conditions. SEB became nontoxic from microtoxic after being treated with HTHP, with the value of EC50 notably increased from 2463 to 33,398 mg L-1, which might be due to the relative increase of light components observed by GC-MS. Original XG was nontoxic (EC50 = 21,000 mg L-1) and easily biodegraded (BC ratio = 0.469), but HTHP treatments increased the toxicity (EC50 = 5701 mg L-1) and decreased the biodegradability (BC ratio = 0.02), which could be attributed to the reduce of the C-OH/C-O-C bonds observed by FT-IR and XPS spectra. Both KPAM and KHm were midtoxic and had low degradability, and only KPAM became highly toxic (EC50 < 100 mg L-1) after HTHP treatments, which might result from the slight increase in the relative peak area of the amide group. The results could provide preliminary insights into the mechanism of how the HTHP conditions impacted the pollution properties of the additives and pave a new and facile route for the screening of environmentally friendly additives, and consequently mitigate the pollution from the source in the oil and gas exploitation industry.",0,0,1
Degrees C.,Drilling,"Alkalbani, Alhaitham M.; Chala, Girma T.; Myint, Myo Tay Zar",Experimental investigation of rheological properties of water-base mud with zinc oxide nanoparticles using response surface methodology,Nanoparticles; Zinc oxide; Downhole condition; Viscosity; Yield point; Gel strength,OIL,"Special and advanced techniques at drilling and production operations are used to drill and produce hydrocarbons from different eccentric reservoirs such as deep-water reservoirs, shale gas, and shale oil necessitates. However, these advanced techniques are considered to be costly and affecting the environment. Therefore, nanotechnology has been implemented in the drilling fluids to improve the rheological properties, hydrogen concentration, and filtration rate. This study is, therefore, aimed at evaluating the properties of zinc oxide nanoparticles and their previous implementation in drilling fluids, examining the rheological properties of water base mud from atmospheric temperature to downhole condition (90 degrees C). The experiment was designed to investigate the effect of nanoparticles concentration and temperature variation on the rheological properties of water-based mud using response surface methodology. A rotational viscometer was used to measure viscosity, yield point and gel strength. Moreover, a Consistometer was used to heat the fluid sample to different temperatures reaching up to downhole condition (90 degrees C). It was observed experimentally that addition of zinc oxide nanoparticles impressively improved the rheological properties of water-base mud by 50% for viscosity and gel strength, and 80% for yield point. It also allowed them to maintain their quality at all temperatures. Furthermore, addition of higher concentrations of zinc oxide nanoparticles of more than 1 wt% (6 g) at low temperatures (below 40 degrees C) gave the highest and most effective results of the rheological properties.",0,0,1
Degrees C.,Drilling,"Duarte, A. C. R.; Ribeiro, P. R.; Kim, N. R.; Mendes, J. R. P.; Policarpo, N. A.; Vianna, A. M.",An experimental study of gas solubility in glycerin based drilling fluid applied to well control,Solubility; Drilling; Well control; Drilling fluids; Aqueous glycerol solution,METHANE,"The drilling fluid is the primary barrier element against a kick. In the path of drilling fluids evolution, syntheticbased drilling fluid (SBDF) is commonly used on offshore rigs due to its benefits to the high level of drilling complexity, especially at deep and ultra-deep-water scenarios. However, when formation gas dissolves in the mud due to high pressure and high temperature, the complexity of kick detection increases significantly. Furthermore, environmental concerns raised a red flag on SBDF usage due to potential impacts on the marine environment, with most governmental agencies around the world passing very strict regulations. Considering both aspects - safety, and environmental concerns - glycerin emerges as a potential candidate to perform a key role as a base drilling fluid (GBDF). At first, a GBDF has the potential to behave as an SBDF due to its benefits, such as lubricity and shale stabilization, and, at the same time, it has the same characteristics of water-based drilling fluid (WBDF) with very low methane solubility, the major component of natural gas. Additionally, GBDF is considered to be more environmentally friendly than SBDF. In this work, we first analyzed the PVT properties and rheology of three different molar composition glycerin-based drilling fluids: 100% glycerin, 5050% glycerin/brine, and 40-60% glycerin/brine. Then, we performed the PVT properties analysis of methane (10-50% molar mass) mixed with each of these GBDF mentioned. In a systematic constant composition expansion through a visual high-resolution PVT cell under temperature and pressure range conditions of 20-80 degrees C and 0-55 MPa, respectively, and rheology characterization. The GBDF exhibited interesting results for density and rheology parameters similar to an SDBF and no methane solubility. Finally, mathematical correlations are proposed and applied to illustrate a pit-gain calculation comparing to an n-paraffin-based drilling fluid.",0,0,3
Degrees C.,Drilling,"Ettehadi, Ali; Ulker, Ceylan; Altun, Gursat",Nonlinearity in large amplitude oscillatory shear of drilling fluid: A comparative study on the oil and water base muds behavior,Drilling fluid; Nonlinear viscoelasticity; Large amplitude oscillatory shear (LAOS); Shear mechanism; Structural stability,VISCOELASTIC PROPERTIES; PRESSURE-DROP; LAOS BEHAVIOR; MODEL; RHEOLOGY; STRESS; TRANSITION; VISCOSITY; EQUATION,"A viscoelastic material exhibits both fluid (viscous) and solid (elastic) like properties simultaneously. The rheological behavior of drilling fluids is customarily measured under the assumption of pure viscous flow, yet they exhibit both viscous and elastic characteristics when subjected to deformation. Some imperative properties of drilling fluids such as gel strength, yield stress, and sag tendency at near-zero shear rate region are categorically under the influence of viscoelastic behavior and have not yet been completely understood due to the lack of appropriate measurement methods. Characterizing the complete rheological profile of material requires measuring linear and nonlinear viscoelastic responses at a wide range of stress/strain levels. The viscoelastic nonlinearity can be characterized under Large Amplitude Oscillatory Shear (LAOS) tests. This study presents a large amplitude oscillatory shear rheology investigation of two water-base (Lignosulfonate and KCl/polymer) and two oil-base (low and high temperature) drilling fluids each in three states; unweighted, weighted, and weighted-contaminated. The viscoelastic nonlinearities of four fluid samples were investigated experimentally as a function of strain amplitude and strain-rate space at different temperatures. The results were described using Lissajous-Bowditch (L-B) plots and local nonlinear viscoelastic dynamic moduli through an oscillatory shear cycle. Structural stability of fluid samples was also studied using the creep-recovery test. The nonlinear viscoelastic behavior of drilling fluids was comprehensively compared and distinguished to understand their nonlinear shear mechanism. As a result of the creep-recovery test at 150 degrees C, high-temperature oil base mud provided higher thermostructural stability and zero shear viscosity than those of Lignosulfonate, KCl/polymer, and low-temperature oil-base muds. While the elastic nonlinearity was found to be strain/strain rate softening, the nonlinear viscous character was recorded as shear/shear rate thinning at large strain rates for all drilling fluid systems. Quite a different shear mechanism was detected at low and moderate strain rates. Shear rate thinning was found to be the dominant mechanism for all fluids except Lignosulfonate mud samples that demonstrated shearthickening behavior at moderate strain rates at 25 degrees C. At high temperatures (100 degrees C and 150 degrees C), shear rate thickening followed by shear rate thinning behavior was governing mechanism under the low and moderate strain rates in all mud samples except KCl/polymer muds. An inverse behavior (shear rate thinning followed by shear rate thickening) was observed through low and moderate strain rates in KCl/polymer muds at 100 degrees C and 150 degrees C. Therefore, as revealed from the LAOS test results, shear rate thickening behavior at low to moderate strain rates is in contradiction of the commonly known shear thinning behavior for a drilling fluid undergoing viscous deformation. This finding explains the facts underlying some important properties of drilling fluids such as gel structure formation, hole cleaning ability, and sag tendency.",0,0,3
Degrees C.,"Produce,Methodology","Angga, I. Gusti Agung Gede; Stanko, Milan",Automated decision support methodology for early planning phase of a multi-reservoir field,Field development planning; Optimization; Proxy model; Mixed-integer linear programming; Uncertainty analysis,PRODUCTION OPTIMIZATION; NETWORK,"The field planning process is a crucial phase in the life of a hydrocarbon field when many design features must be decided upon. The field development team has the task of finding a configuration of these field design features which maximizes the value of the company's asset while considering several constraints. This paper presents a decision support methodology suitable for the early stage of the field planning process. The methodology is applied on a synthetic field called Safari. This field is characterized by having multiple reservoir units, where these reservoir units are non-communicating and have distinct properties. The reservoirs, namely Love, Nesehorn, and Sebra, have original oil-in-place (OOIP) of 75, 55, and 13 million sm(3), respectively. Both Love and Nesehorn have a permeability of 250 mD, whereas Sebra has a higher permeability of 450 mD. All these reservoirs lie 2500 m below the sea level with an initial reservoir pressure of 280 bara and an initial reservoir temperature of 80 degrees C. The main part of the methodology is a mathematical optimization that uses (i) proxy models to represent the flow performance of the production system and to estimate the development costs and (ii) piecewise linear (PWL) approximations to represent the non-linear functions. In this study, two optimization problems with the objective function to maximize plateau duration or net present value (NPV) are formulated and solved. The optimization models consider production schedule, drilling schedule, and recovery mechanism as the decision variables. Some constraints concerning production, injection, and drilling are also included in the optimization models. According to the optimization results, the objective value can be improved by considering more decision variables in the optimization problems. For example, including the drilling schedule and recovery mechanism as decision variables gives us 85% higher optimal NPV than optimizing the production schedule alone. Several investigations have been made to reduce the optimization runtime and to ensure the accuracy of the optimization results. Furthermore, the uncertainty of the optimization results has been quantified through uncertainty analyses. These analyses consider three uncertain parameters, i.e., OOIP, development costs, and oil price. Two approaches have been evaluated for conducting the uncertainty analysis, i.e., using the Latin hypercube sampling (LHS) method and using a probability tree. The uncertainty analysis using a probability tree is recommended because it requires less time to complete while produces similar results as the other approach.",0,0,0
Degrees C.,"Produce,Methodology","Ratnakar, Ram R.; Dindoruk, Birol",Transient measurement and modeling of integrated capillary viscometer for live oils at high temperatures with volumetric constraints,Capillary viscometer; Integrated viscosity experiment; Modeling fluid flow; Hagen-Poiseuille equation; Live and dead oils; High temperature high pressure (HTHP) studies,HEAVY-OIL; VISCOSITY CORRELATION; PREDICTION; BITUMEN; DEAD,"The viscosity of oils at reservoir conditions whether under natural depletion conditions or under induced conditions (i.e. EOR/IOR) is one of the key parameters for the dynamics of flow in porous media, and it has direct impact on the economically recoverable volumes as well as transportation problems where the fluids can get exposed to potentially wide range of temperatures. It becomes even more essential measurement for thermal based EOR techniques including high temperature steam injection or in-situ upgrading techniques due to strong (exponential) dependency of viscosity to temperature. Unfortunately, viscosity measurements for such applications suffer with the two key challenges. First, most commercial and research labs could measure viscosities up to 200 degrees C (while the application considered may induce temperatures as high as 300 degrees C beyond which most naturally occurring hydrocarbons starts decomposing). And second, these measurements are based on steady-state conditions, requiring significant volumes of oil samples. However, the available volume of oil samples for such applications may be very small for various reasons, including emulsions leading to very low useful volumes, cost of sampling, or inheritance of candidate samples from other laboratory processes, such as but not limited to core-flooding or reactive transport experiments. Therefore, in this work, we present a novel but simple technique to overcome these challenges by using simple capillary device that could be integrated to any system that requires charging and/or charging the candidate fluids such as PVT-cells, pressurized vessels that could be operated up to 300 degrees C or higher. Such integration utilizes the charging of fluids to the cell for viscosity measurements, leading to the following advantages: (i) it requires no additional volume of oil for viscosity measurements, and also saves the operational time and cost (ii) it could produce viscosity data at higher temperatures that are desired for in-situ upgrading or thermal EOR, even small amounts of particulates evolve in the bulk phase (iii) it ensures that the viscosity and PVT measurements are performed on the same sample eliminating the potential sample to sample variations. (iv) the proposed approach along with the developed methodology paves the way for a the implementation of unsteady in-line measurement of viscosities for pressurized systems. This includes not only lab processes, but also the downhole sampling where the method could be implemented in sampling devices. The technique proposed here is based on transient measurements and modeling of capillary viscometer, where pressure at the end points and flow rate through the capillary tube may vary with time (which is the most realistic conditions for variable back pressure systems or systems with frictional pistons). In addition to the experimental process, necessary mathematical model and interpretative analysis tools to quality check, assessment of the experimental data (and the establishment of the range of validity and limitations) are derived from first principals (bottom-up approach) using Navier-Stokes equations.",0,0,1
Degrees C.,"Produce,Methodology","Alkalbani, Alhaitham M.; Chala, Girma T.; Myint, Myo Tay Zar",Experimental investigation of rheological properties of water-base mud with zinc oxide nanoparticles using response surface methodology,Nanoparticles; Zinc oxide; Downhole condition; Viscosity; Yield point; Gel strength,OIL,"Special and advanced techniques at drilling and production operations are used to drill and produce hydrocarbons from different eccentric reservoirs such as deep-water reservoirs, shale gas, and shale oil necessitates. However, these advanced techniques are considered to be costly and affecting the environment. Therefore, nanotechnology has been implemented in the drilling fluids to improve the rheological properties, hydrogen concentration, and filtration rate. This study is, therefore, aimed at evaluating the properties of zinc oxide nanoparticles and their previous implementation in drilling fluids, examining the rheological properties of water base mud from atmospheric temperature to downhole condition (90 degrees C). The experiment was designed to investigate the effect of nanoparticles concentration and temperature variation on the rheological properties of water-based mud using response surface methodology. A rotational viscometer was used to measure viscosity, yield point and gel strength. Moreover, a Consistometer was used to heat the fluid sample to different temperatures reaching up to downhole condition (90 degrees C). It was observed experimentally that addition of zinc oxide nanoparticles impressively improved the rheological properties of water-base mud by 50% for viscosity and gel strength, and 80% for yield point. It also allowed them to maintain their quality at all temperatures. Furthermore, addition of higher concentrations of zinc oxide nanoparticles of more than 1 wt% (6 g) at low temperatures (below 40 degrees C) gave the highest and most effective results of the rheological properties.",0,0,1
Degrees C.,"Produce,Methodology","Bahu, Juliana Otavia; Miranda, Nahieh Toscano; Khouri, Nadia Gagliardi; Batistella, Cesar Benedito; Cardenas Concha, Viktor Oswaldo; Wolf Maciel, Maria Regina; Rocha Barbosa Schiavon, Maria Ingrid; Maciel Filho, Rubens",Crude oil emulsion breaking: An investigation about gravitational and rheological stability under demulsifiers action,Bottle test; Dehydration; Demulsifier testing; Emulsion breaking; Rheology; Stability,PETROLEUM EMULSIONS; DROPLET SIZE; WATER; LIGHT; METHODOLOGY; TEMPERATURE; SURFACTANTS; PERFORMANCE; VISCOSITY; SALINITY,"Emulsions are common in the oil industry, being present in the extraction and production stages. Its formation occurs with the contact of brine and crude oil under intense flow. The presence of emulsified water (dispersed droplet size, phi <= 50 mu m) in crude oil can negatively impact its exploration, transportation, and refining, making transportation more expensive, requiring more energy for heating, and causing equipment corrosion on all processes. In addition, crude oil has salts and sediments that encrust and corrode equipment of the primary oil treatment unit and distillation towers, also causing catalyst poisoning in the cracking step. Therefore, such components need to be removed for subsequent refining processes. To prevent these problems, the dehydration/ desalting of crude oils is a strategy adopted to reach adequate values of water, salts, and sediments required in the refineries for the next steps after primary treatment. However, the emulsion breaking is influenced by several factors that affect the stability of crude oil (W/O emulsion), such as viscosity, contents of water, salts, sediments, and natural surfactants, among others. Given this perspective, this work investigated the stability of two different types of crude oils with demulsifier under the action of gravity (bottle test) and shear stress (rheology). The comparisons of gravitational and rheological techniques concluded that the shear stress sweep analyses are useful to evaluate the demulsifier performance in the emulsion breaking, being a reliable and fast methodology. Such studies allowed the identification of adequate parameters: temperature (80 degrees C) and, demulsifier type and quantity (500 ppm) for efficient crude oil phase separation, without using washing water. The physicochemical and rheological characterizations clarified the crude oil's colloidal stability behavior to understand the impurities' influence on the oils' properties (crude and desalted).",0,0,2
Degrees C.,"Produce,Methodology","Aboelkhair, Hamed; Diaz, Pedro; Attia, Attia",Biosurfactant production using Egyptian oil fields indigenous bacteria for microbial enhanced oil recovery,Microbial enhanced oil recovery; Indigenous bacteria; Biosurfactant; Bacillus subtilis; Surface activity; Critical micelle concentration,BACILLUS-SUBTILIS; SURFACTANT; LICHENIFORMIS; OPTIMIZATION; WETTABILITY; HYDROCARBON; INJECTION; MOLASSES; STRAINS,"Biosurfactant production is one of the most efficient mechanisms in microbial enhanced oil recovery (MEOR) processes. This work investigates the production of biosurfactants by indigenous bacteria isolated from Egyptian oil fields, and how to optimize these produced biosurfactants for MEOR. 59 Egyptian oil reservoirs were screened to evaluate the potential applicability of MEOR processes, based on their rock and fluid properties. Results showed that 8 reservoirs from the Gulf of Suez and 3 reservoirs from the Western Desert had the potential to MEOR. Combined analysis of morphological, and biochemical characterization was performed on the 11 bacterial strains isolated from different crude oil samples collected from the reservoirs that have the potential to MEOR process to identify their types. Bacillus spp, a bacilli species that can produce biosurfactants, was selected for further studies. To optimize the surface activity of the produced biosurfactant, ten different reported nutrient media, and a new proposed nutrient media were examined. Bacillus spp has shown the ability to produce a very active biosurfactant that reduced the surface tension of water from 71.8 +/- 1.9 mN/m to 25.7 +/- 1.2 mN/m, and the interfacial tension of water against kerosene from 48.4 +/- 2.1 mN/m to 0.38 +/- 0.07 mN/m at Critical Micelle Concentration (CMC) of 0.04 +/- 0.01 g/l, in a medium supplemented by the new proposed nutrient medium H. The growth rate of Bacillus spp was studied, and it was found it reached its maximum (OD600nm 2.59 +/- 0.16) after 24 h of incubation. Biosurfactant production has no significant change in its surface activity over a wide range of temperature range up to 120 degrees C, which means the studied species Bacillus spp is a thermophilic bacterium. Bacillus spp grew well in the presence of high salt concentration up to 20% (w/v) NaCl, the optimal surface activity was obtained in the range of 0-2% (w/v) NaCl, and at pH 7. The emulsification activity of the produced biosurfactant was examined, and it reached the maximum (69.6 + 1.5%) against kerosene at temperature 25 degrees C, Salinity 0% (w/v) NaCl (distilled water), and pH 7. The produced biosurfactant was purified and extracted by acid precipitation method, and the biosurfactant yield of the purified compound was found to be 2.8 +/- 0.3 g/l. Finally, the core-flooding experiments were conducted to investigate the effect of produced biosurfactants by Bacillus subtilis in oil recovery. The obtained results reveal the potential of Bacillus spp to grow in the new proposed medium H and produce effective and efficient biosurfactants that enhanced oil recovery by 25.19-39.35% of additional oil over the water flooding residual oil saturation in the studied cores and retain more than 60% of its surface activity under harsh conditions and that are relevant to Microbial Enhanced Oil Recovery, MEOR.",0,0,2
Degrees C.,Enhanced Oil-recovery,"Nieto-Alvarez, David A.; Luna-Rojero, Erick E.; Marin-Leon, Adlai; Ceron-Camacho, Ricardo; Nieto-Rivero, Carlos J. T.; Zamudio-Rivera, Luis S.",Static adsorption and mathematical model applied in EOR using a supramolecular surfactant,Static adsorption; Supramolecular surfactant; Adsorption model; EOR,OIL-RECOVERY; FOAM STABILITY; ZWITTERIONIC SURFACTANT; INTERFACIAL-TENSION; LIMESTONE; MINERALS; BEHAVIOR; ISOTHERM,"Typical adsorption isotherms show the characteristic Langmuir behavior. However, in the presence of a supramolecular surfactant, its corresponding adsorption isotherms, exhibiting atypical decrement behavior. The static adsorption results on limestone and dolomite show maximum values of 2.40 and 5.98 mg(surfactant)/grock, respectively. For explaining this behavior, was developed a new modified mathematical adsorption model, (d Gamma/dt) (ads) = k(ads)c(Gamma(infinity) - Gamma) - k(cmc)(c - c(cmc))(n)Gamma H(c - c(cmc)). This model describes the adsorption isotherms in two ads regions: the first one corresponds to the conventional adsorption increase and the second to decay adsorption phenomena. This decrement behavior is mainly due to the ultra-high salinity and the monomer reversible arrow micelle reversible arrow vesicle equilibrium in connate water. The new model shows the better fitting with r(2) = 0.9743 for limestone and r(2) = 0.9668 for dolomite, respect to the Langmuir model r(2) = 0.8556. Which represents the accuracy with the experimental values in the adsorption isotherm. Also, it is highlighted the significance of the information provided by the new static adsorption Langmuir mathematical model. That establishes criteria for using a chemical in enhanced oil recovery processes. From the data in the adsorption profile, the optimal concentration for the adsorption process occurs between 1800 and 2000 ppm of supramolecular surfactant. The enhanced oil recovery experiment in ultra-high salinity and hardness is better with an increase in the temperature: 8% at 80 degrees C, 15% at 90 degrees C and 20% at 100 degrees C.",0,0,0
Degrees C.,Enhanced Oil-recovery,"Aboelkhair, Hamed; Diaz, Pedro; Attia, Attia",Biosurfactant production using Egyptian oil fields indigenous bacteria for microbial enhanced oil recovery,Microbial enhanced oil recovery; Indigenous bacteria; Biosurfactant; Bacillus subtilis; Surface activity; Critical micelle concentration,BACILLUS-SUBTILIS; SURFACTANT; LICHENIFORMIS; OPTIMIZATION; WETTABILITY; HYDROCARBON; INJECTION; MOLASSES; STRAINS,"Biosurfactant production is one of the most efficient mechanisms in microbial enhanced oil recovery (MEOR) processes. This work investigates the production of biosurfactants by indigenous bacteria isolated from Egyptian oil fields, and how to optimize these produced biosurfactants for MEOR. 59 Egyptian oil reservoirs were screened to evaluate the potential applicability of MEOR processes, based on their rock and fluid properties. Results showed that 8 reservoirs from the Gulf of Suez and 3 reservoirs from the Western Desert had the potential to MEOR. Combined analysis of morphological, and biochemical characterization was performed on the 11 bacterial strains isolated from different crude oil samples collected from the reservoirs that have the potential to MEOR process to identify their types. Bacillus spp, a bacilli species that can produce biosurfactants, was selected for further studies. To optimize the surface activity of the produced biosurfactant, ten different reported nutrient media, and a new proposed nutrient media were examined. Bacillus spp has shown the ability to produce a very active biosurfactant that reduced the surface tension of water from 71.8 +/- 1.9 mN/m to 25.7 +/- 1.2 mN/m, and the interfacial tension of water against kerosene from 48.4 +/- 2.1 mN/m to 0.38 +/- 0.07 mN/m at Critical Micelle Concentration (CMC) of 0.04 +/- 0.01 g/l, in a medium supplemented by the new proposed nutrient medium H. The growth rate of Bacillus spp was studied, and it was found it reached its maximum (OD600nm 2.59 +/- 0.16) after 24 h of incubation. Biosurfactant production has no significant change in its surface activity over a wide range of temperature range up to 120 degrees C, which means the studied species Bacillus spp is a thermophilic bacterium. Bacillus spp grew well in the presence of high salt concentration up to 20% (w/v) NaCl, the optimal surface activity was obtained in the range of 0-2% (w/v) NaCl, and at pH 7. The emulsification activity of the produced biosurfactant was examined, and it reached the maximum (69.6 + 1.5%) against kerosene at temperature 25 degrees C, Salinity 0% (w/v) NaCl (distilled water), and pH 7. The produced biosurfactant was purified and extracted by acid precipitation method, and the biosurfactant yield of the purified compound was found to be 2.8 +/- 0.3 g/l. Finally, the core-flooding experiments were conducted to investigate the effect of produced biosurfactants by Bacillus subtilis in oil recovery. The obtained results reveal the potential of Bacillus spp to grow in the new proposed medium H and produce effective and efficient biosurfactants that enhanced oil recovery by 25.19-39.35% of additional oil over the water flooding residual oil saturation in the studied cores and retain more than 60% of its surface activity under harsh conditions and that are relevant to Microbial Enhanced Oil Recovery, MEOR.",0,0,2
Degrees C.,Enhanced Oil-recovery,"Li Yisong; Gholami, Raoof; Safari, Mehdi; Rahimi, Ali; Khur, Wee Siaw","On surface interactions of environmental friendly surfactant/oil/rock/low salinity system: IFT, wettability, and foamability",Natural surfactant; Low salinity water; Surface wettability; IFT; Sandstone,ENHANCED OIL-RECOVERY; LEAF-DERIVED SURFACTANTS; INTERFACIAL-TENSION; NATURAL SURFACTANT; ANIONIC SURFACTANT; WATER INJECTION; SMART WATER; ADSORPTION; SANDSTONE; NANOPARTICLES,"In recent years, natural surfactants have been considered as part of the EOR processes given their non-toxic and environment friendly nature. However, once chosen wisely, surfactants can only reduce the interfacial tension (IFT) and are often unable to alter the surface wettability for a better hydrocarbon production. Low salinity water (LSW) is a good candidate on these occasions, but the interaction of LSW with natural surfactants for wettability alteration has not been deeply understood. In this work, an attempt was made to extract and characterize a natural surfactant which could be used together with LSW for EOR purposes. To do this, a natural surfactant was extracted from Saponin and its physico-chemical properties such as CMC, foamability, and thermal stability were tested. A series of IFT and wettability measurements were then conducted to evaluate the performance of the surfactant as an EOR additive. The results obtained indicated that the extracted surfactant has a high thermal stability and can be fully functional in the temperature of up to 100 degrees C. It appears that increasing the level of salinity in the solution can improve the efficiency and foamability of the surfactant. It was observed that the extracted surfactant as can reduce the IFT of an air-water system by 78.65% and is capable of favorably altering the surface wettability of sandstone for a better hydrocarbon production once combined with LSW.",0,0,2
Degrees C.,Enhanced Oil-recovery,"Pashapouryeganeh, Farzad; Zargar, Ghasem; Takassi, Mohammad Ali; kadkhodaie, Ali; Rabiee, Ahmad",One-Pot synthesis of modified-cationic surfactants for enhanced oil recovery applications in carbonate reservoirs,Surfactant synthesis; Cationic surfactant; Quaternary ammonium salt; Wettability alteration; IFT reduction; Chemical enhanced oil recovery (CEOR),INTERFACIAL-TENSION BEHAVIOR; DETERMINING IONS CA2+; HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; POROUS-MEDIA; CHAIN-LENGTH; WET; MECHANISM; LIQUID,"In this study two cationic surfactants, dodecyltriethylammoniumbromide (C(12)TEAB) and hexadecyl-triethylammoniumbromide (C(16)TEAB) were prepared. The formation of synthezied surfactants were confirmed using FTIR and HNMR spectroscopy. Electrical conductivity, interfacial tension and surface tension methods were used to determine the critical micelle concentrations (CMC) of these surfactants. To understand the behavior of synthesized surfactants in harsh environments, the CMC was measured in deionized water (DIW), sea water and petroleum formation water. Using electrical conductivity technique, for C(12)TEAB surfactant the CMC values of 4000 ppm, 2000 ppm and 850 ppm were recorded in DIW, sea water and formation water respectively. For C(16)TEAB surfactant, the CMC values of 420 ppm, 190 ppm and 115 ppm were obtained in DIW, sea water and formation water respectively. The similar CMC results were obtained using the interfacial tension (IFT) and surface tension (ST) methods. Reduction of IFT between crude oil and formation water and also alteration of wettability of petroleum reservoir of carbonated rock from oil-wet (large contact angle) to water-wet (small contact angle) are two major factors affecting chemical enhanced oil recovery (EOR). Interfacial tension (IFT), surface tension (ST) and contact angle measurements were carried out using an IFT-PDSA-06 apparatus (Apex Technologies Company, Iran). The IFT and ST of these surfactants were also carried out in DIW, sea water and formation water. For C(12)TEAB surfactant, the IFT values of 0.051 mN/m, 0.036 mN/m and 0.023 mN/m were recorded in DIW, sea water and formation water respectively. The IFT values of 0.044 mN/m, 0.026 mN/m and 0.0126 mN/m were measured for C(16)TEAB surfactant in DIW, sea water and formation water respectively. The effect of temperature on IFT was studied for both surfactants. When temperature increases, IFT decreases. The reduction of IFT continues up to 55 degrees C, then the IFT increases with increasing temperature. For C(12)TEAB surfactant, the ST values of 44.9 mN/m, 38.8 mN/m and 31.8 mN/m were obtained in DIW, sea water and formation water respectively. In similar measurements for C(16)TEAB surfactant, the recorded ST values were 33.95; 32.9 and 32.22 mN/m in DIW, sea water and formation water respectively. In wettability alteration study both surfactants altered the contact angle from oil-wet to water-wet conditions. Using formation water and C(12)TEAB surfactant, the contact angle varied from 96.4 degrees to 54.5 degrees. In similar study using C(16)TEAB surfactant the contact angle changed from 92 degrees to 46.1 degrees. The contact angles of these surfactants in DIW and sea water were also measured and reported. The results of IFT and wettability studies demonstrated excellent potential application of synthesized surfactants in EOR process in carbonate petroleum reservoirs.",0,0,3
Degrees C.,Control,"Zeng, Dezhi; Dong, Baojun; Yu, Zhiming; Huang, Zhiyao; Yi, Yonggang; Yu, Huiyong; Li, Jie; Tian, Gang",Design of water-based annulus protection fluid for CO2 flooding injection well,Water-based annulus protection fluid corrosion inhibitor; Deoxidizer; bactericide; CO2 flooding,CORROSION BEHAVIOR; DRILLING-FLUIDS; STEELS; X65; IMPURITIES; MECHANISM,"To solve the issue that casing and tubing can be easily corroded in the injection well of CO2 flooding, a novel water-based annulus protection fluid suitable for injection well in CO2 flooding was developed. Firstly, the appropriate additives, such as the deoxidizer, inhibitor, bactericide, pour point depressant and density regulators, were selected according to the service environment of wellbore. On this basis, the synergism among the additives was evaluated. Then, the ratio of additives was optimized to form the formulation of water-based annulus protection fluid. Finally, the performance evaluation of the water-based annulus protection liquid was evaluated. The results showed the composition of the water-based annulus protection fluid was commercial corrosion inhibitor (XCN20) (1500 ppm), CT4-42 bactericide (1 g/L), D-isoascorbic acid sodium deoxidizer (3 g/ L), sodium formate (100 g/L), glycol 20%. The density of the protection fluid was 1.01-1.17 g/cm(3), and its freezing point was - 2-20 degrees C. The dissolved oxygen content in the injected water was controlled within 0.3 ppm by using the protection liquid. The corrosion inhibition rate of the water-based annulus protection liquid was higher than 98% in aqueous phase, and the corrosion rate of steel reached the corrosion control index of oil field (0.076mm/a) in gas-aqueous phase.",0,1,1
Degrees C.,Control,"Ko, Saebom; Wang, Xin; Kan, Amy T.; Tomson, Mason B.",Growth inhibition and deposition prevention of sulfide scales using dispersants,Sulfide scales; Deposition; Particle dispersion; Water-soluble polymer dispersants,NANOPARTICLES; CHEMISTRY; IMMOBILIZATION; NANOCOMPOSITE; PREDICTION; STABILIZER; MAGNETITE; KINETICS; SULFATE; MODEL,"Although sulfide scales of FeS, PbS, and ZnS do not occur as frequently as carbonate and sulfate scales, it is difficult to remove them once they are formed and deposited. Effective prevention and remediation of sulfide scales have not been fully developed. For sulfide scales, the conventional threshold inhibition approach is not as effective as for carbonate and sulfate scales, presumably, due to strong ion pairs formation of FeS0 and fast precipitation kinetics of FeS,. Polyacrylamide (PAM), polyvinyl pyrrolidone (PVP), and carboxymethyl cellulose (CMC) were examined as dispersants for sulfide scales to prevent and mitigate sulfide scale deposition through controlling the particle sizes of FeS, PbS and ZnS. PAM, PVP, and CMC dispersed FeS particles more effectively at pH 6.7 than 5.0 and temperature 70 degrees C than 90 degrees C. PAM and CMC successfully dispersed FeS particles even in extremely high ionic strength (I) of 4.6 M, while, PVP, slightly less effective, up to I = 2.6 M. At pH 5.0 and 90 degrees C, CMC was able to disperse FeS particles up to I = 1.3 M and PVP up to I = 0.6 M. In contrast, PAM could not disperse FeS particles at all. When FeS particles were dispersed in the presence of polymeric dispersants, FeS particle sizes remained in nanometer ranges, from 100 to 600 nm. Our results demonstrated that CMC was the best dispersant for FeS particles among the three polymers we tested. For CMC, the larger molecular weight and the lower degree of substitution of carboxylic groups on cellulose, the more effective dispersant CMC became. PbS and ZnS were also well dispersed in the presence of CMC. Almost all fraction of PbS particles was smaller than 200 nm, while about 60% of ZnS particles were smaller than 200 nm. Results demonstrated that the promising treatment selection of CMC as a universal dispersant for sulfide scales.",0,0,1
Degrees C.,Control,"Duarte, A. C. R.; Ribeiro, P. R.; Kim, N. R.; Mendes, J. R. P.; Policarpo, N. A.; Vianna, A. M.",An experimental study of gas solubility in glycerin based drilling fluid applied to well control,Solubility; Drilling; Well control; Drilling fluids; Aqueous glycerol solution,METHANE,"The drilling fluid is the primary barrier element against a kick. In the path of drilling fluids evolution, syntheticbased drilling fluid (SBDF) is commonly used on offshore rigs due to its benefits to the high level of drilling complexity, especially at deep and ultra-deep-water scenarios. However, when formation gas dissolves in the mud due to high pressure and high temperature, the complexity of kick detection increases significantly. Furthermore, environmental concerns raised a red flag on SBDF usage due to potential impacts on the marine environment, with most governmental agencies around the world passing very strict regulations. Considering both aspects - safety, and environmental concerns - glycerin emerges as a potential candidate to perform a key role as a base drilling fluid (GBDF). At first, a GBDF has the potential to behave as an SBDF due to its benefits, such as lubricity and shale stabilization, and, at the same time, it has the same characteristics of water-based drilling fluid (WBDF) with very low methane solubility, the major component of natural gas. Additionally, GBDF is considered to be more environmentally friendly than SBDF. In this work, we first analyzed the PVT properties and rheology of three different molar composition glycerin-based drilling fluids: 100% glycerin, 5050% glycerin/brine, and 40-60% glycerin/brine. Then, we performed the PVT properties analysis of methane (10-50% molar mass) mixed with each of these GBDF mentioned. In a systematic constant composition expansion through a visual high-resolution PVT cell under temperature and pressure range conditions of 20-80 degrees C and 0-55 MPa, respectively, and rheology characterization. The GBDF exhibited interesting results for density and rheology parameters similar to an SDBF and no methane solubility. Finally, mathematical correlations are proposed and applied to illustrate a pit-gain calculation comparing to an n-paraffin-based drilling fluid.",0,0,3
Degrees C.,Control,"Saikia, Tinku; Khamidy, Nur Iman; Sultan, Abdullah; Patil, Shirish",Rheological investigation of pickering invert emulsion system for conformance control in high temperature reservoirs,Conformance control; Gelation time; Pickering emulsion; Organoclay,COLLOID-STABILIZED EMULSIONS; DROPLET SIZE; OIL; GEL,"The use of emulsified gel system in high temperature reservoirs is a promising technique for deep reservoir conformance control. The successful implementation of emulsified gel system for conformance control is mainly dependent on emulsion stability. The emulsion system was designed in a way so that it will only breaks once it reaches the desired depth/zone of interest. The gelation time is very much dependent on the emulsion stability. The flow properties of the emulsion system, which is one of its important physical attributes help to determine the gelation time. In this research study the invert pickering emulsion system was developed for conformance control in high temperature reservoirs. The effect of various variables such as different type of mixing method, salinity, type of emulsifier and temperature was studied. The emulsion systems were prepared using three different mixing methods denoted as M1, M2 and M3. Five different aqueous phase with different salinity were used and their effect on the emulsion systems gelation time was studied. The effect of four different emulsifiers i. e., Cloisite 20, Claytone II, Claytone HY and Claytone ER was evaluated. The emulsion systems were also tested at two different temperatures of 80 degrees C and 95 degrees C (ambient pressure conditions). In total fifteen different emulsion systems were prepared and tested. The emulsion system with highest salinity and Cloisite 20 as emulsifier was found to be with the longest gelation time of 24306 s (at 80 degrees C). At 95 degrees C, the Cloisite 20 as emulsifier and aqueous phase in field mixing water provided highest gelation time of 3362 s. The emulsion system with lowest salinity and Claytone HY as emulsifier was found to be with the lowest gelation time of 1684 s. Increase in temperature tends to decrease the gelation time of the developed emulsified gel system. The emulsion prepared with mixing method 3 (M3) and Cloisite 20 as emulsifier provided a gelation time of 5040 s at 80 degrees C but the gelation time of the same system is decreased to 3362 s at 95 degrees C. The effect of mixing method on the gelation time was also studied. Emulsion system prepared with mixing method 1 (M1) gives the gelation time of 7020 s whereas the same emulsion system prepared with the mixing method 3 (M3) gives gelation time of 5040 s.",0,0,3
Degrees C.,Respect,"Angga, I. Gusti Agung Gede; Stanko, Milan",Automated decision support methodology for early planning phase of a multi-reservoir field,Field development planning; Optimization; Proxy model; Mixed-integer linear programming; Uncertainty analysis,PRODUCTION OPTIMIZATION; NETWORK,"The field planning process is a crucial phase in the life of a hydrocarbon field when many design features must be decided upon. The field development team has the task of finding a configuration of these field design features which maximizes the value of the company's asset while considering several constraints. This paper presents a decision support methodology suitable for the early stage of the field planning process. The methodology is applied on a synthetic field called Safari. This field is characterized by having multiple reservoir units, where these reservoir units are non-communicating and have distinct properties. The reservoirs, namely Love, Nesehorn, and Sebra, have original oil-in-place (OOIP) of 75, 55, and 13 million sm(3), respectively. Both Love and Nesehorn have a permeability of 250 mD, whereas Sebra has a higher permeability of 450 mD. All these reservoirs lie 2500 m below the sea level with an initial reservoir pressure of 280 bara and an initial reservoir temperature of 80 degrees C. The main part of the methodology is a mathematical optimization that uses (i) proxy models to represent the flow performance of the production system and to estimate the development costs and (ii) piecewise linear (PWL) approximations to represent the non-linear functions. In this study, two optimization problems with the objective function to maximize plateau duration or net present value (NPV) are formulated and solved. The optimization models consider production schedule, drilling schedule, and recovery mechanism as the decision variables. Some constraints concerning production, injection, and drilling are also included in the optimization models. According to the optimization results, the objective value can be improved by considering more decision variables in the optimization problems. For example, including the drilling schedule and recovery mechanism as decision variables gives us 85% higher optimal NPV than optimizing the production schedule alone. Several investigations have been made to reduce the optimization runtime and to ensure the accuracy of the optimization results. Furthermore, the uncertainty of the optimization results has been quantified through uncertainty analyses. These analyses consider three uncertain parameters, i.e., OOIP, development costs, and oil price. Two approaches have been evaluated for conducting the uncertainty analysis, i.e., using the Latin hypercube sampling (LHS) method and using a probability tree. The uncertainty analysis using a probability tree is recommended because it requires less time to complete while produces similar results as the other approach.",0,0,0
Degrees C.,Respect,"Nieto-Alvarez, David A.; Luna-Rojero, Erick E.; Marin-Leon, Adlai; Ceron-Camacho, Ricardo; Nieto-Rivero, Carlos J. T.; Zamudio-Rivera, Luis S.",Static adsorption and mathematical model applied in EOR using a supramolecular surfactant,Static adsorption; Supramolecular surfactant; Adsorption model; EOR,OIL-RECOVERY; FOAM STABILITY; ZWITTERIONIC SURFACTANT; INTERFACIAL-TENSION; LIMESTONE; MINERALS; BEHAVIOR; ISOTHERM,"Typical adsorption isotherms show the characteristic Langmuir behavior. However, in the presence of a supramolecular surfactant, its corresponding adsorption isotherms, exhibiting atypical decrement behavior. The static adsorption results on limestone and dolomite show maximum values of 2.40 and 5.98 mg(surfactant)/grock, respectively. For explaining this behavior, was developed a new modified mathematical adsorption model, (d Gamma/dt) (ads) = k(ads)c(Gamma(infinity) - Gamma) - k(cmc)(c - c(cmc))(n)Gamma H(c - c(cmc)). This model describes the adsorption isotherms in two ads regions: the first one corresponds to the conventional adsorption increase and the second to decay adsorption phenomena. This decrement behavior is mainly due to the ultra-high salinity and the monomer reversible arrow micelle reversible arrow vesicle equilibrium in connate water. The new model shows the better fitting with r(2) = 0.9743 for limestone and r(2) = 0.9668 for dolomite, respect to the Langmuir model r(2) = 0.8556. Which represents the accuracy with the experimental values in the adsorption isotherm. Also, it is highlighted the significance of the information provided by the new static adsorption Langmuir mathematical model. That establishes criteria for using a chemical in enhanced oil recovery processes. From the data in the adsorption profile, the optimal concentration for the adsorption process occurs between 1800 and 2000 ppm of supramolecular surfactant. The enhanced oil recovery experiment in ultra-high salinity and hardness is better with an increase in the temperature: 8% at 80 degrees C, 15% at 90 degrees C and 20% at 100 degrees C.",0,0,0
Degrees C.,Respect,"Duarte, A. C. R.; Ribeiro, P. R.; Kim, N. R.; Mendes, J. R. P.; Policarpo, N. A.; Vianna, A. M.",An experimental study of gas solubility in glycerin based drilling fluid applied to well control,Solubility; Drilling; Well control; Drilling fluids; Aqueous glycerol solution,METHANE,"The drilling fluid is the primary barrier element against a kick. In the path of drilling fluids evolution, syntheticbased drilling fluid (SBDF) is commonly used on offshore rigs due to its benefits to the high level of drilling complexity, especially at deep and ultra-deep-water scenarios. However, when formation gas dissolves in the mud due to high pressure and high temperature, the complexity of kick detection increases significantly. Furthermore, environmental concerns raised a red flag on SBDF usage due to potential impacts on the marine environment, with most governmental agencies around the world passing very strict regulations. Considering both aspects - safety, and environmental concerns - glycerin emerges as a potential candidate to perform a key role as a base drilling fluid (GBDF). At first, a GBDF has the potential to behave as an SBDF due to its benefits, such as lubricity and shale stabilization, and, at the same time, it has the same characteristics of water-based drilling fluid (WBDF) with very low methane solubility, the major component of natural gas. Additionally, GBDF is considered to be more environmentally friendly than SBDF. In this work, we first analyzed the PVT properties and rheology of three different molar composition glycerin-based drilling fluids: 100% glycerin, 5050% glycerin/brine, and 40-60% glycerin/brine. Then, we performed the PVT properties analysis of methane (10-50% molar mass) mixed with each of these GBDF mentioned. In a systematic constant composition expansion through a visual high-resolution PVT cell under temperature and pressure range conditions of 20-80 degrees C and 0-55 MPa, respectively, and rheology characterization. The GBDF exhibited interesting results for density and rheology parameters similar to an SDBF and no methane solubility. Finally, mathematical correlations are proposed and applied to illustrate a pit-gain calculation comparing to an n-paraffin-based drilling fluid.",0,0,3
Degrees C.,Respect,"Pashapouryeganeh, Farzad; Zargar, Ghasem; Takassi, Mohammad Ali; kadkhodaie, Ali; Rabiee, Ahmad",One-Pot synthesis of modified-cationic surfactants for enhanced oil recovery applications in carbonate reservoirs,Surfactant synthesis; Cationic surfactant; Quaternary ammonium salt; Wettability alteration; IFT reduction; Chemical enhanced oil recovery (CEOR),INTERFACIAL-TENSION BEHAVIOR; DETERMINING IONS CA2+; HEAVY CRUDE-OIL; WETTABILITY ALTERATION; SPONTANEOUS IMBIBITION; POROUS-MEDIA; CHAIN-LENGTH; WET; MECHANISM; LIQUID,"In this study two cationic surfactants, dodecyltriethylammoniumbromide (C(12)TEAB) and hexadecyl-triethylammoniumbromide (C(16)TEAB) were prepared. The formation of synthezied surfactants were confirmed using FTIR and HNMR spectroscopy. Electrical conductivity, interfacial tension and surface tension methods were used to determine the critical micelle concentrations (CMC) of these surfactants. To understand the behavior of synthesized surfactants in harsh environments, the CMC was measured in deionized water (DIW), sea water and petroleum formation water. Using electrical conductivity technique, for C(12)TEAB surfactant the CMC values of 4000 ppm, 2000 ppm and 850 ppm were recorded in DIW, sea water and formation water respectively. For C(16)TEAB surfactant, the CMC values of 420 ppm, 190 ppm and 115 ppm were obtained in DIW, sea water and formation water respectively. The similar CMC results were obtained using the interfacial tension (IFT) and surface tension (ST) methods. Reduction of IFT between crude oil and formation water and also alteration of wettability of petroleum reservoir of carbonated rock from oil-wet (large contact angle) to water-wet (small contact angle) are two major factors affecting chemical enhanced oil recovery (EOR). Interfacial tension (IFT), surface tension (ST) and contact angle measurements were carried out using an IFT-PDSA-06 apparatus (Apex Technologies Company, Iran). The IFT and ST of these surfactants were also carried out in DIW, sea water and formation water. For C(12)TEAB surfactant, the IFT values of 0.051 mN/m, 0.036 mN/m and 0.023 mN/m were recorded in DIW, sea water and formation water respectively. The IFT values of 0.044 mN/m, 0.026 mN/m and 0.0126 mN/m were measured for C(16)TEAB surfactant in DIW, sea water and formation water respectively. The effect of temperature on IFT was studied for both surfactants. When temperature increases, IFT decreases. The reduction of IFT continues up to 55 degrees C, then the IFT increases with increasing temperature. For C(12)TEAB surfactant, the ST values of 44.9 mN/m, 38.8 mN/m and 31.8 mN/m were obtained in DIW, sea water and formation water respectively. In similar measurements for C(16)TEAB surfactant, the recorded ST values were 33.95; 32.9 and 32.22 mN/m in DIW, sea water and formation water respectively. In wettability alteration study both surfactants altered the contact angle from oil-wet to water-wet conditions. Using formation water and C(12)TEAB surfactant, the contact angle varied from 96.4 degrees to 54.5 degrees. In similar study using C(16)TEAB surfactant the contact angle changed from 92 degrees to 46.1 degrees. The contact angles of these surfactants in DIW and sea water were also measured and reported. The results of IFT and wettability studies demonstrated excellent potential application of synthesized surfactants in EOR process in carbonate petroleum reservoirs.",0,0,3
Degrees C.,Source Rocks,"Shalaby, Mohamed Ragab; Mahlstedt, Nicolaj; Osli, Liyana Nadiah; Islam, Md Aminul","PhaseKinetics for assessing the compositional evolution of petroleum generated from the early to Late Miocene source rock, Belait Formation, Brunei-Muara district, Brunei Darussalam",Phasekinetic; Compositional maturity; Bulk maturation; Belait formation; Brunei Darussalam,NORTHERN WESTERN DESERT; JURASSIC SOURCE ROCKS; GEOCHEMICAL CHARACTERISTICS; HYDROCARBON GENERATION; DEPOSITIONAL ENVIRONMENT; GAS GENERATION; PHASE-BEHAVIOR; SHOUSHAN BASIN; PYROLYSIS; RESERVOIR,"The Early to Late Miocene Belait Formation in Brunei-Muara district has been investigated using the PhaseKinetic approach for compositional petroleum generation kinetics. The source rock characteristics of the selected coal and coaly shale samples indicate kerogen type III-II and type III with moderate HI recorded in the range of 156-258 mg HC/g TOC. The Rock Eval pyrolysis data also show immature organic matter with maximum recorded Tmax values of 415 degrees C. Pyrolysis gas chromatography (PyGC) reflects that the source rocks generated petroleum grading from paraffinic-naphthenic-aromatic (P-N-A) high wax to gas and condensate, which can be interpreted as heterogeneous kerogen derived from terrigenous higher land plant material. The main activation energies range of two selected coal samples (S24 and S27) are located at 49-52 kcal/mol accounting each for only 15% of the total bulk reaction. Assuming a 3 degrees C/My geologic heating rate, calculated onset temperatures for the generated hydrocarbon at transformation ration, TR = 10% were 105-120 degrees C for the two samples. The end of hydrocarbon generation at approximately TR = 95% is expected to occur at temperatures around 170 degrees C and above. MSSV pyrolysis gas chromatography affirms the existence of high wax paraffinic kerogen type-III-II with some marine input for one end member sample (S24). The 4-component compositional kinetic model indicates that the maximum generation of different petroleum components of sample S24 is predicted at lower values of temperature and vitrinite reflectance if compared with sample S27. The other end member of sample (S27) is more typically humic coal-like with type-III kerogen generating mostly gas and condensate.",0,0,0
Degrees C.,Source Rocks,"Osli, Liyana Nadiah; Shalaby, Mohamed R.; Islam, Md Aminul; Kalaitzidis, Stavros; Damoulianou, Maria Elli; Karim, Khairunnisa Nazirah Pg Dr; Tsikouras, Basilios; Pasadakis, Nikos","Organic matter characteristics and hydrocarbon generating potential of the Miocene Belait Formation, Brunei-Muara district, Brunei Darussalam",Belait formation; Brunei Darussalam; Coal rank; DOM; Organic petrography; Source rock; Biomarkers,DEPOSITIONAL ENVIRONMENT; SOURCE-ROCK; NYALAU FORMATION; BARAM DELTA; SARAWAK; BASIN; SEQUENCE; COALS; OIL; CLASSIFICATION,"The characteristics of the source rocks in the early to late Miocene Belait Formation of Brunei Darussalam have been evaluated through the application of Rock-Eval and biomarker analyses, as well as by organic petro-graphical examination. Analyses have been performed on coal, coaly shale/carbonaceous claystones and shale samples from the Formation, retrieved from outcrops across the Brunei-Muara district, and covering a wide lateral extension of the Formation. The geochemical results indicate that the coal and some carbonaceous samples (with TOC from 14.1% to 67.7%) from the Belait Formation have ""good to excellent"" generating potential, quantity and quality, due to their high S-2 and TOC values, which are consistent with the intermediate hydrogen index (HI) values ranging from 144 to 258 mg HC/g TOC. Organic material of ""fair to good"" quantity, quality and hydrocarbon generating potential is recorded for the coaly shale samples in the Belait Formation. Non-coal samples generally have the lowest potential as source rocks, due to their low TOC, HI and S-2 values. Within the Formation, the coal layers together with a number of coaly shale and shale layers contain type III (gas prone) and type II-III (mixed oil and gas) kerogens. This is proven by the dominance of huminite, often of fluorescent varieties, which is confirmed though maceral analysis, as well as a trend of n-alkanes skewed towards heavier compounds. Evidence of the possible generation of liquid hydrocarbon is offered by the fact that liptinite is the second most abundant maceral group in most of the samples, as well as by the perhydrous nature of part of the huminite. Furthermore, kerogen type IV (dry gas) has been identified in a majority of the coaly shale samples. Facies analysis of the Belait Formation through the use of maceral indices and biomarkers data indicates that the coals were deposited in a mangrove setting in a lower delta plain, where mainly herbaceous and arboreal plants were growing. The depositional conditions were predominantly oxic, with a possible marine influence, and hence brackish conditions. All samples are found to be thermally immature to early mature, with T-max values ranging from 356 degrees C to 441 degrees C, huminite reflectance values of up to 0.46% and high carbon preference index (CPI) values.",0,0,3
Degrees C.,Source Rocks,"Liu, Chao; Zhao, Wanchun; Sun, Lidong; Wang, Xiaolian; Sun, Youhai; Zhang, Ying; Zhang, Jingjing; Zhang, Lei; Li, Jijun","Geochemical assessment of the newly discovered oil-type Shale in the Shuangcheng area of the northern Songliao Basin, China",Shale; Geochemistry; Hydrocarbon potential; Shuangcheng depression; Songliao basin,HYDROCARBON SOURCE ROCKS; DEPOSITIONAL ENVIRONMENT; CARBON ISOTOPES; ORGANIC-MATTER; TRACE-ELEMENTS; SOUTH CHINA; DEPRESSION; LACUSTRINE; MATURATION; EXPULSION,"For the past fifty years, the northern Songliao Basin in China was thought to contain Lower Cretaceous coal-measure and gas-generating shale. Oil-type shales did not receive much attention until oil exploration activities made a breakthrough in the Southern Shuangcheng (SSC) depression. In this study, the geochemical characteristics of the newly discovered K(1)yc(4) (fourth member of the Lower Cretaceous YingCheng Formation) oil-type shale in the SSC depression were analyzed, including the organic matter abundance, organic matter type, thermal maturity, hydrocarbon potential, and sedimentary environment. A total of 393 core samples were collected, and Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), organic petrography, carbon isotope analysis, and constant and trace element analyses were conducted. The K(1)yc(4) shale was determined to have a good to excellent hydrocarbon potential with high TOC values (mostly 2.0-4.0%). The organic matter was mainly from lower hydrobiont, algae, bacteria, and lesser amounts of terrestrial plants. The organic matter is mainly type Ito type II based on the hydrogen index (HI) (average HI = 193.36 mg HC/g TOC), the carbon isotopes of the kerogen (mostly -26 to -30 parts per thousand), and the organic petrography (average sapropelinite + liptinite of 55.0 vol%). The maturity parameters, i.e., T-max (mean 452 degrees C) and vitrinite reflectance (0.8-1.1%), suggest that the shale is in the mature thermal evolution stage. The shale's maximum hydrocarbon-generating intensity is up to 713.29 x 10(4)/km(2), and its hydrocarbon-expelling intensity is stable at 116.63 x 10(4)/km(2). The constant and trace element analyses (Sr, Ba, V, Ni, Cr, Ti) revealed that the organic matter deposition and preservation occurred in a fresh-brackish and dysoxic-anoxic water environment. Volcanic eruptions probably played a vital role in the enrichment of the organic matter in the oil-type shale. In addition, the results of this study provide evidence that the Lower Cretaceous strata in the northern Songliao Basin meet the geological conditions of oil-prone shale, which expands the petroleum exploration horizon in this region.",0,0,3
Degrees C.,Nanoparticles,"Ko, Saebom; Wang, Xin; Kan, Amy T.; Tomson, Mason B.",Growth inhibition and deposition prevention of sulfide scales using dispersants,Sulfide scales; Deposition; Particle dispersion; Water-soluble polymer dispersants,NANOPARTICLES; CHEMISTRY; IMMOBILIZATION; NANOCOMPOSITE; PREDICTION; STABILIZER; MAGNETITE; KINETICS; SULFATE; MODEL,"Although sulfide scales of FeS, PbS, and ZnS do not occur as frequently as carbonate and sulfate scales, it is difficult to remove them once they are formed and deposited. Effective prevention and remediation of sulfide scales have not been fully developed. For sulfide scales, the conventional threshold inhibition approach is not as effective as for carbonate and sulfate scales, presumably, due to strong ion pairs formation of FeS0 and fast precipitation kinetics of FeS,. Polyacrylamide (PAM), polyvinyl pyrrolidone (PVP), and carboxymethyl cellulose (CMC) were examined as dispersants for sulfide scales to prevent and mitigate sulfide scale deposition through controlling the particle sizes of FeS, PbS and ZnS. PAM, PVP, and CMC dispersed FeS particles more effectively at pH 6.7 than 5.0 and temperature 70 degrees C than 90 degrees C. PAM and CMC successfully dispersed FeS particles even in extremely high ionic strength (I) of 4.6 M, while, PVP, slightly less effective, up to I = 2.6 M. At pH 5.0 and 90 degrees C, CMC was able to disperse FeS particles up to I = 1.3 M and PVP up to I = 0.6 M. In contrast, PAM could not disperse FeS particles at all. When FeS particles were dispersed in the presence of polymeric dispersants, FeS particle sizes remained in nanometer ranges, from 100 to 600 nm. Our results demonstrated that CMC was the best dispersant for FeS particles among the three polymers we tested. For CMC, the larger molecular weight and the lower degree of substitution of carboxylic groups on cellulose, the more effective dispersant CMC became. PbS and ZnS were also well dispersed in the presence of CMC. Almost all fraction of PbS particles was smaller than 200 nm, while about 60% of ZnS particles were smaller than 200 nm. Results demonstrated that the promising treatment selection of CMC as a universal dispersant for sulfide scales.",0,0,1
Degrees C.,Nanoparticles,"Alkalbani, Alhaitham M.; Chala, Girma T.; Myint, Myo Tay Zar",Experimental investigation of rheological properties of water-base mud with zinc oxide nanoparticles using response surface methodology,Nanoparticles; Zinc oxide; Downhole condition; Viscosity; Yield point; Gel strength,OIL,"Special and advanced techniques at drilling and production operations are used to drill and produce hydrocarbons from different eccentric reservoirs such as deep-water reservoirs, shale gas, and shale oil necessitates. However, these advanced techniques are considered to be costly and affecting the environment. Therefore, nanotechnology has been implemented in the drilling fluids to improve the rheological properties, hydrogen concentration, and filtration rate. This study is, therefore, aimed at evaluating the properties of zinc oxide nanoparticles and their previous implementation in drilling fluids, examining the rheological properties of water base mud from atmospheric temperature to downhole condition (90 degrees C). The experiment was designed to investigate the effect of nanoparticles concentration and temperature variation on the rheological properties of water-based mud using response surface methodology. A rotational viscometer was used to measure viscosity, yield point and gel strength. Moreover, a Consistometer was used to heat the fluid sample to different temperatures reaching up to downhole condition (90 degrees C). It was observed experimentally that addition of zinc oxide nanoparticles impressively improved the rheological properties of water-base mud by 50% for viscosity and gel strength, and 80% for yield point. It also allowed them to maintain their quality at all temperatures. Furthermore, addition of higher concentrations of zinc oxide nanoparticles of more than 1 wt% (6 g) at low temperatures (below 40 degrees C) gave the highest and most effective results of the rheological properties.",0,0,1
Degrees C.,Nanoparticles,"Li Yisong; Gholami, Raoof; Safari, Mehdi; Rahimi, Ali; Khur, Wee Siaw","On surface interactions of environmental friendly surfactant/oil/rock/low salinity system: IFT, wettability, and foamability",Natural surfactant; Low salinity water; Surface wettability; IFT; Sandstone,ENHANCED OIL-RECOVERY; LEAF-DERIVED SURFACTANTS; INTERFACIAL-TENSION; NATURAL SURFACTANT; ANIONIC SURFACTANT; WATER INJECTION; SMART WATER; ADSORPTION; SANDSTONE; NANOPARTICLES,"In recent years, natural surfactants have been considered as part of the EOR processes given their non-toxic and environment friendly nature. However, once chosen wisely, surfactants can only reduce the interfacial tension (IFT) and are often unable to alter the surface wettability for a better hydrocarbon production. Low salinity water (LSW) is a good candidate on these occasions, but the interaction of LSW with natural surfactants for wettability alteration has not been deeply understood. In this work, an attempt was made to extract and characterize a natural surfactant which could be used together with LSW for EOR purposes. To do this, a natural surfactant was extracted from Saponin and its physico-chemical properties such as CMC, foamability, and thermal stability were tested. A series of IFT and wettability measurements were then conducted to evaluate the performance of the surfactant as an EOR additive. The results obtained indicated that the extracted surfactant has a high thermal stability and can be fully functional in the temperature of up to 100 degrees C. It appears that increasing the level of salinity in the solution can improve the efficiency and foamability of the surfactant. It was observed that the extracted surfactant as can reduce the IFT of an air-water system by 78.65% and is capable of favorably altering the surface wettability of sandstone for a better hydrocarbon production once combined with LSW.",0,0,2
Degrees C.,"Annulus Protection Fluid,CO2 Flooding","Zeng, Dezhi; Dong, Baojun; Yu, Zhiming; Huang, Zhiyao; Yi, Yonggang; Yu, Huiyong; Li, Jie; Tian, Gang",Design of water-based annulus protection fluid for CO2 flooding injection well,Water-based annulus protection fluid corrosion inhibitor; Deoxidizer; bactericide; CO2 flooding,CORROSION BEHAVIOR; DRILLING-FLUIDS; STEELS; X65; IMPURITIES; MECHANISM,"To solve the issue that casing and tubing can be easily corroded in the injection well of CO2 flooding, a novel water-based annulus protection fluid suitable for injection well in CO2 flooding was developed. Firstly, the appropriate additives, such as the deoxidizer, inhibitor, bactericide, pour point depressant and density regulators, were selected according to the service environment of wellbore. On this basis, the synergism among the additives was evaluated. Then, the ratio of additives was optimized to form the formulation of water-based annulus protection fluid. Finally, the performance evaluation of the water-based annulus protection liquid was evaluated. The results showed the composition of the water-based annulus protection fluid was commercial corrosion inhibitor (XCN20) (1500 ppm), CT4-42 bactericide (1 g/L), D-isoascorbic acid sodium deoxidizer (3 g/ L), sodium formate (100 g/L), glycol 20%. The density of the protection fluid was 1.01-1.17 g/cm(3), and its freezing point was - 2-20 degrees C. The dissolved oxygen content in the injected water was controlled within 0.3 ppm by using the protection liquid. The corrosion inhibition rate of the water-based annulus protection liquid was higher than 98% in aqueous phase, and the corrosion rate of steel reached the corrosion control index of oil field (0.076mm/a) in gas-aqueous phase.",0,1,1
Degrees C.,"Annulus Protection Fluid,CO2 Flooding","Zeng, Dezhi; Dong, Baojun; Zhang, Sisong; Yi, Yonggang; Huang, Zhiyao; Tian, Gang; Yu, Huiyong; Sun, Yicheng",Annular corrosion risk analysis of gas injection in CO2 flooding and development of oil-based annulus protection fluid,Corrosion risk; Supercritical CO2 corrosion; Oil-based annulus protection fluid; Corrosion inhibitor; CO2 flooding,CO2-SATURATED BRINE; STEEL; ENVIRONMENT; PRESSURE; BEHAVIOR; X65,"To investigate the corrosion behavior of gas-injection well of CO2 flooding and then to take measures to inhibit the corrosion of casing, firstly an HTHP autoclave and surface characterization technology are applied to analyzing the corrosion behavior of casing and then a new type of oil-based annulus protection fluid has been developed to avoid the casing corrosion issue. The results show that the casing in the simulated supercritical CO2-saturated aqueous brine phase (SC CO2 -saturated aqueous phase) has severe uniform corrosion, while that in the simulated water-saturated supercritical CO2 (SC CO2 phase) has severe pitting corrosion. The temperature and CO2 partial pressure can promote the water film adsorbed on the steel surface, further inducing the corrosion of casing. In order to prevent casing corrosion, an oil-based annulus protection fluid suitable for gas-injection well in CO2 flooding is developed, and the preparation process of oil-based annulus protection fluid is proposed. The oil-based annulus protection fluid is composed of white oil and 1000 mg/L imidazoline inhibitor. The flash point of the oil-based annulus protection fluid is over 160 degrees C, the freezing point -23 degrees C, and the density 0.85 g/cm(3). The corrosion inhibition rate is more than 80% when P110 steel is in SC CO2 phase with oil-based annulus protection fluid, and it is more than 95% when P110 steel is in SC CO2-saturated aqueous phase. It proves that the newly developed oil-based annulus fluid can effectively solve the corrosion problem of P110 steel as casing in gas-injection well of CO2 flooding.",0,0,2
Degrees C.,Emulsion System,"Ratnakar, Ram R.; Dindoruk, Birol",Transient measurement and modeling of integrated capillary viscometer for live oils at high temperatures with volumetric constraints,Capillary viscometer; Integrated viscosity experiment; Modeling fluid flow; Hagen-Poiseuille equation; Live and dead oils; High temperature high pressure (HTHP) studies,HEAVY-OIL; VISCOSITY CORRELATION; PREDICTION; BITUMEN; DEAD,"The viscosity of oils at reservoir conditions whether under natural depletion conditions or under induced conditions (i.e. EOR/IOR) is one of the key parameters for the dynamics of flow in porous media, and it has direct impact on the economically recoverable volumes as well as transportation problems where the fluids can get exposed to potentially wide range of temperatures. It becomes even more essential measurement for thermal based EOR techniques including high temperature steam injection or in-situ upgrading techniques due to strong (exponential) dependency of viscosity to temperature. Unfortunately, viscosity measurements for such applications suffer with the two key challenges. First, most commercial and research labs could measure viscosities up to 200 degrees C (while the application considered may induce temperatures as high as 300 degrees C beyond which most naturally occurring hydrocarbons starts decomposing). And second, these measurements are based on steady-state conditions, requiring significant volumes of oil samples. However, the available volume of oil samples for such applications may be very small for various reasons, including emulsions leading to very low useful volumes, cost of sampling, or inheritance of candidate samples from other laboratory processes, such as but not limited to core-flooding or reactive transport experiments. Therefore, in this work, we present a novel but simple technique to overcome these challenges by using simple capillary device that could be integrated to any system that requires charging and/or charging the candidate fluids such as PVT-cells, pressurized vessels that could be operated up to 300 degrees C or higher. Such integration utilizes the charging of fluids to the cell for viscosity measurements, leading to the following advantages: (i) it requires no additional volume of oil for viscosity measurements, and also saves the operational time and cost (ii) it could produce viscosity data at higher temperatures that are desired for in-situ upgrading or thermal EOR, even small amounts of particulates evolve in the bulk phase (iii) it ensures that the viscosity and PVT measurements are performed on the same sample eliminating the potential sample to sample variations. (iv) the proposed approach along with the developed methodology paves the way for a the implementation of unsteady in-line measurement of viscosities for pressurized systems. This includes not only lab processes, but also the downhole sampling where the method could be implemented in sampling devices. The technique proposed here is based on transient measurements and modeling of capillary viscometer, where pressure at the end points and flow rate through the capillary tube may vary with time (which is the most realistic conditions for variable back pressure systems or systems with frictional pistons). In addition to the experimental process, necessary mathematical model and interpretative analysis tools to quality check, assessment of the experimental data (and the establishment of the range of validity and limitations) are derived from first principals (bottom-up approach) using Navier-Stokes equations.",0,0,1
Degrees C.,Emulsion System,"Saikia, Tinku; Khamidy, Nur Iman; Sultan, Abdullah; Patil, Shirish",Rheological investigation of pickering invert emulsion system for conformance control in high temperature reservoirs,Conformance control; Gelation time; Pickering emulsion; Organoclay,COLLOID-STABILIZED EMULSIONS; DROPLET SIZE; OIL; GEL,"The use of emulsified gel system in high temperature reservoirs is a promising technique for deep reservoir conformance control. The successful implementation of emulsified gel system for conformance control is mainly dependent on emulsion stability. The emulsion system was designed in a way so that it will only breaks once it reaches the desired depth/zone of interest. The gelation time is very much dependent on the emulsion stability. The flow properties of the emulsion system, which is one of its important physical attributes help to determine the gelation time. In this research study the invert pickering emulsion system was developed for conformance control in high temperature reservoirs. The effect of various variables such as different type of mixing method, salinity, type of emulsifier and temperature was studied. The emulsion systems were prepared using three different mixing methods denoted as M1, M2 and M3. Five different aqueous phase with different salinity were used and their effect on the emulsion systems gelation time was studied. The effect of four different emulsifiers i. e., Cloisite 20, Claytone II, Claytone HY and Claytone ER was evaluated. The emulsion systems were also tested at two different temperatures of 80 degrees C and 95 degrees C (ambient pressure conditions). In total fifteen different emulsion systems were prepared and tested. The emulsion system with highest salinity and Cloisite 20 as emulsifier was found to be with the longest gelation time of 24306 s (at 80 degrees C). At 95 degrees C, the Cloisite 20 as emulsifier and aqueous phase in field mixing water provided highest gelation time of 3362 s. The emulsion system with lowest salinity and Claytone HY as emulsifier was found to be with the lowest gelation time of 1684 s. Increase in temperature tends to decrease the gelation time of the developed emulsified gel system. The emulsion prepared with mixing method 3 (M3) and Cloisite 20 as emulsifier provided a gelation time of 5040 s at 80 degrees C but the gelation time of the same system is decreased to 3362 s at 95 degrees C. The effect of mixing method on the gelation time was also studied. Emulsion system prepared with mixing method 1 (M1) gives the gelation time of 7020 s whereas the same emulsion system prepared with the mixing method 3 (M3) gives gelation time of 5040 s.",0,0,3
Degrees C.,Gel Strength,"Alkalbani, Alhaitham M.; Chala, Girma T.; Myint, Myo Tay Zar",Experimental investigation of rheological properties of water-base mud with zinc oxide nanoparticles using response surface methodology,Nanoparticles; Zinc oxide; Downhole condition; Viscosity; Yield point; Gel strength,OIL,"Special and advanced techniques at drilling and production operations are used to drill and produce hydrocarbons from different eccentric reservoirs such as deep-water reservoirs, shale gas, and shale oil necessitates. However, these advanced techniques are considered to be costly and affecting the environment. Therefore, nanotechnology has been implemented in the drilling fluids to improve the rheological properties, hydrogen concentration, and filtration rate. This study is, therefore, aimed at evaluating the properties of zinc oxide nanoparticles and their previous implementation in drilling fluids, examining the rheological properties of water base mud from atmospheric temperature to downhole condition (90 degrees C). The experiment was designed to investigate the effect of nanoparticles concentration and temperature variation on the rheological properties of water-based mud using response surface methodology. A rotational viscometer was used to measure viscosity, yield point and gel strength. Moreover, a Consistometer was used to heat the fluid sample to different temperatures reaching up to downhole condition (90 degrees C). It was observed experimentally that addition of zinc oxide nanoparticles impressively improved the rheological properties of water-base mud by 50% for viscosity and gel strength, and 80% for yield point. It also allowed them to maintain their quality at all temperatures. Furthermore, addition of higher concentrations of zinc oxide nanoparticles of more than 1 wt% (6 g) at low temperatures (below 40 degrees C) gave the highest and most effective results of the rheological properties.",0,0,1
Degrees C.,Gel Strength,"Ettehadi, Ali; Ulker, Ceylan; Altun, Gursat",Nonlinearity in large amplitude oscillatory shear of drilling fluid: A comparative study on the oil and water base muds behavior,Drilling fluid; Nonlinear viscoelasticity; Large amplitude oscillatory shear (LAOS); Shear mechanism; Structural stability,VISCOELASTIC PROPERTIES; PRESSURE-DROP; LAOS BEHAVIOR; MODEL; RHEOLOGY; STRESS; TRANSITION; VISCOSITY; EQUATION,"A viscoelastic material exhibits both fluid (viscous) and solid (elastic) like properties simultaneously. The rheological behavior of drilling fluids is customarily measured under the assumption of pure viscous flow, yet they exhibit both viscous and elastic characteristics when subjected to deformation. Some imperative properties of drilling fluids such as gel strength, yield stress, and sag tendency at near-zero shear rate region are categorically under the influence of viscoelastic behavior and have not yet been completely understood due to the lack of appropriate measurement methods. Characterizing the complete rheological profile of material requires measuring linear and nonlinear viscoelastic responses at a wide range of stress/strain levels. The viscoelastic nonlinearity can be characterized under Large Amplitude Oscillatory Shear (LAOS) tests. This study presents a large amplitude oscillatory shear rheology investigation of two water-base (Lignosulfonate and KCl/polymer) and two oil-base (low and high temperature) drilling fluids each in three states; unweighted, weighted, and weighted-contaminated. The viscoelastic nonlinearities of four fluid samples were investigated experimentally as a function of strain amplitude and strain-rate space at different temperatures. The results were described using Lissajous-Bowditch (L-B) plots and local nonlinear viscoelastic dynamic moduli through an oscillatory shear cycle. Structural stability of fluid samples was also studied using the creep-recovery test. The nonlinear viscoelastic behavior of drilling fluids was comprehensively compared and distinguished to understand their nonlinear shear mechanism. As a result of the creep-recovery test at 150 degrees C, high-temperature oil base mud provided higher thermostructural stability and zero shear viscosity than those of Lignosulfonate, KCl/polymer, and low-temperature oil-base muds. While the elastic nonlinearity was found to be strain/strain rate softening, the nonlinear viscous character was recorded as shear/shear rate thinning at large strain rates for all drilling fluid systems. Quite a different shear mechanism was detected at low and moderate strain rates. Shear rate thinning was found to be the dominant mechanism for all fluids except Lignosulfonate mud samples that demonstrated shearthickening behavior at moderate strain rates at 25 degrees C. At high temperatures (100 degrees C and 150 degrees C), shear rate thickening followed by shear rate thinning behavior was governing mechanism under the low and moderate strain rates in all mud samples except KCl/polymer muds. An inverse behavior (shear rate thinning followed by shear rate thickening) was observed through low and moderate strain rates in KCl/polymer muds at 100 degrees C and 150 degrees C. Therefore, as revealed from the LAOS test results, shear rate thickening behavior at low to moderate strain rates is in contradiction of the commonly known shear thinning behavior for a drilling fluid undergoing viscous deformation. This finding explains the facts underlying some important properties of drilling fluids such as gel structure formation, hole cleaning ability, and sag tendency.",0,0,3
Multiphase Flow,Production System,"Takacs, Gabor",A critical comparison of TDH calculation models in manual ESP design procedures,ESP pump; Total dynamic head; Pump design; Hand calculation; Comparison,,"The design of an ESP installation is started with the selection of the centrifugal pump, the heart of the system. To choose the ESP pump, one must calculate the installation's Total Dynamic Head (TDH) that is a measure of the required pressure increment to be generated by the pump under the operating conditions. Although this is a basic task in the installation design process, some controversies still exist in the industry about the way TDH should be calculated and many of the standard literature sources recommend an incorrect formula. The paper discusses the available TDH calculation models for single-phase and multiphase flow conditions. The traditional formula widely used in hand calculations is derived and its validity in other than gasless oil production is shown to be highly questionable. The correct formula for single-phase liquid flow is developed, and the calculation error committed by the traditional model is compared to the results of the proper formula. The incorrect model is shown to produce predominantly higher TDH values than the correct one; this fact seemingly increases the safety of pump selection. For increased reliability and in multiphase flow conditions the use of computer programs is advised.",0,0,0
Multiphase Flow,Production System,"Chaves, Gabriela Souza; Karami, Hamidreza; Ferreira Filho, Virgilio Jose Martins; Vieira, Bruno Ferreira",A comparative study on the performance of multiphase flow models against offshore field production data,Multiphase flow; Production optimization; Offshore data analysis; Flow assurance; Flow models,2-PHASE FLOW; PRESSURE-DROP; PATTERN TRANSITIONS; MECHANISTIC MODEL; PREDICTING FLOW; VISCOSITY; OIL,"In the oil industry, multiphase flow models are commonly used to simulate the flow from reservoir to the production unit. Flow simulations help in the production monitoring and optimization to support the decisionmaking process. Despite the need for accurate simulations to support production operations, multiphase flow models are mostly developed using laboratory data and rarely validated under field-scale conditions. To improve the understanding of multiphase flow models in field conditions, this work evaluates the performance of a large set of models for a dataset composed of two production units with 20 producing wells and 865 measured production points. The wells are divided and analyzed in two segments: the surface flowline and the wellbore. The evaluation compares the models' performances using various statistical parameters and trending charts. The evaluation analyzes the impacts of production parameters, well geometry, predicted flow pattern, and pressure drop components on the model performances. Overall, Ansari's model presented the best performance with 13.8% absolute average percent error for the flowline segment and 14.1% error for the wellbore segment. In addition, Gray can also generate good results for most but not all of the tested wellbores. From the production parameters evaluation, higher flow rate tests resulted in more stable outputs. Ansari and Beggs models showed a trend of increasing errors for wells with larger horizontal wellbore lengths. Also, Beggs model showed larger errors when the transition flow pattern was predicted. Finally, both Ansari and Beggs models showed larger overprediction errors for tests with higher pressure losses in the flowline segment, while Gray showed smaller errors for these cases. The conclusions can be used to select the best models given the production system's flow parameters, or be incorporated in systems to increase the accuracy.",0,0,0
Multiphase Flow,Production System,"Maschio, Celio; von Hohendorff Filho, Joao Carlos; Schiozer, Denis Jose",Methodology for data assimilation in reservoir and production system to improve short- and medium-term forecast,Data assimilation; Uncertainty reduction; Integrated production system; Production forecast,,"Numerical reservoir simulation is an important tool that is widely used in the petroleum industry for production forecast and decision-making processes. In a context of integrated production system involving the reservoir, wells, and production facilities, the quality of production forecast depends not only on the quality of reservoir models and well productivity/injectivity but also on the boundary condition for the future extrapolation which, in turn, depends on the production system characteristics. Both systems, reservoir and production facilities, are characterized by uncertain properties and behavior, such as porosity and permeability, among others, for reservoir; pipeline roughness, multiphase flow behavior in pipes, among others, for the production system. This paper proposes a methodology for dynamic data assimilation to reduce uncertainty in both reservoir and production system models to improve short- and medium-term production forecast. The methodology was applied to a benchmark case built using real data from an offshore field in The Campos Basin (Brazil). The results from this study show that it is important to perform data assimilation process in both reservoir and production systems to obtain more reliable production forecasts. We also show that, by focusing on the short- and medium-term production forecast, the production system and reservoir uncertainties cause variability in the production forecast in the same order or magnitude. Based on that, it is recommended to consider multiple solutions of the production system to obtain more realistic production forecasts.",0,0,1
Multiphase Flow,Production System,"Andrade, Gabriel M. P.; de Menezes, Diego Q. F.; Soares, Rafael M.; Lemos, Tiago S. M.; Teixeira, Alex F.; Ribeiro, Leonardo D.; Vieira, Bruno F.; Pinto, Jose Carlos",Virtual flow metering of production flow rates of individual wells in oil and gas platforms through data reconciliation,Virtual flow metering; Soft sensor; Data reconciliation; Oil and gas production,REAL-TIME,"In the present work, virtual flow metering (VFM) tools are developed to provide estimates for the individual flow rate measurements of the wells operated simultaneously in typical oil and gas platforms. Data reconciliation (DR) procedures are used to calibrate phenomenological models using available measured profiles of well pressure and temperature, and overall flow rates of gas, oil and water. In order to evaluate the relative importance of key hypotheses, three different phenomenological models were used to describe the platform operation: (i) a simple single phase fluid flow model, to evaluate whether the DR task can be successfully accomplished with the available data; (ii) a simple multiphase fluid flow model, in order to evaluate whether the explicit consideration of the multiphase nature of the problem can affect the obtained DR results; and (iii) a detailed phenomenological multiphase flow model, to represent accurately the behavior of an oil and gas production platform. Obtained results show that the proposed DR scheme can be indeed implemented successfully in the form of a VFM sensor to assign online and in real time the individual production of wells operated simultaneously in typical oil and gas platforms. The DR-based VFM was able to reconcile total oil and total water flow rates with average relative deviations of 0.87% and 17% respectively and maximum deviation of 2.3% for oil flow rates. Besides, the DR-based VFM tool provided insights about the system behavior and sensoring management, being able to indicate the oil lines and sensors that were subject to the highest variability.",0,0,3
Multiphase Flow,Pressure Drop,"Alhosani, Ahmed; Daraboina, Nagu",Effect of multi-phase flow on asphaltene deposition: Field case application of integrated simulator,Flow assurance; Multiphase flow; Asphaltene deposition,GAS-LIQUID FLOW; HEAT-TRANSFER; PARTICLE DEPOSITION; UNIFIED MODEL; CRUDE OILS; TOOL ADEPT; PRECIPITATION; SLUG; HOLDUP; AGGREGATION,"Asphaltene is initially stable in the oil, but when there is a change in pressure, temperature, or composition, particles tend to phase out and form precipitants. Issues arise when those particles diffuse toward the wall and deposit, which contributes to reducing the flowing area and increasing the pressure drop. Preventing precipi-tation is the optimum solution to maintain the target production rate; however, it is challenging to avoid favorable precipitation conditions. Remedies and treatments to mitigate this issue cause the oil industry a considerable increase in expenditure and time; thus, it is necessary to develop a tool to accurately predict the deposition for a wide range of operating conditions, especially in multiphase flow. In this study, a multiphase simulator is developed by coupling thermodynamics, hydrodynamics, heat transfer, and asphaltene modules to predict the deposition. A deposition data obtained from a field case is used to validate the robustness of the simulator. The simulator results matched well with the asphaltene deposition and the equilibrium profile available in the literature. The simulation approach presented here offers useful insights into the effect of multiphase flow on asphaltene deposition and eventually aid in improving the accuracy of pre-diction. Using single-phase assumption under multiphase conditions contributed to a significant error in the prediction, and these inaccuracies may lead to a substantial economic and operational burden for the oil and gas industry.",0,0,0
Multiphase Flow,Pressure Drop,"Chaves, Gabriela Souza; Karami, Hamidreza; Ferreira Filho, Virgilio Jose Martins; Vieira, Bruno Ferreira",A comparative study on the performance of multiphase flow models against offshore field production data,Multiphase flow; Production optimization; Offshore data analysis; Flow assurance; Flow models,2-PHASE FLOW; PRESSURE-DROP; PATTERN TRANSITIONS; MECHANISTIC MODEL; PREDICTING FLOW; VISCOSITY; OIL,"In the oil industry, multiphase flow models are commonly used to simulate the flow from reservoir to the production unit. Flow simulations help in the production monitoring and optimization to support the decisionmaking process. Despite the need for accurate simulations to support production operations, multiphase flow models are mostly developed using laboratory data and rarely validated under field-scale conditions. To improve the understanding of multiphase flow models in field conditions, this work evaluates the performance of a large set of models for a dataset composed of two production units with 20 producing wells and 865 measured production points. The wells are divided and analyzed in two segments: the surface flowline and the wellbore. The evaluation compares the models' performances using various statistical parameters and trending charts. The evaluation analyzes the impacts of production parameters, well geometry, predicted flow pattern, and pressure drop components on the model performances. Overall, Ansari's model presented the best performance with 13.8% absolute average percent error for the flowline segment and 14.1% error for the wellbore segment. In addition, Gray can also generate good results for most but not all of the tested wellbores. From the production parameters evaluation, higher flow rate tests resulted in more stable outputs. Ansari and Beggs models showed a trend of increasing errors for wells with larger horizontal wellbore lengths. Also, Beggs model showed larger errors when the transition flow pattern was predicted. Finally, both Ansari and Beggs models showed larger overprediction errors for tests with higher pressure losses in the flowline segment, while Gray showed smaller errors for these cases. The conclusions can be used to select the best models given the production system's flow parameters, or be incorporated in systems to increase the accuracy.",0,0,0
Multiphase Flow,Pressure Drop,"Tavakkoli, Mohammad; Panuganti, Sai R.; Khemka, Yash; Valdes, Humberto; Vargas, Francisco M.",Foam-assisted gas lift: A novel experimental setup to investigate the feasibility of using a commercial surfactant for increasing oil well productivity,Pressure drop; Foam; FAGL; Artificial lift; Wellbore productivity; Multiphase flow,,"Most oil wells require artificial lift at some point to increase the life of the field and enhance production. Conventional methods such as gas lift are not effective in depleted reservoirs with high water cut where very high gas injection rates are required for relatively low oil production rates. Consequently, foamers or surfactants, which have been previously applied for de-liquifying gas wells, are now used in depleted gas-lifted oil wells to either boost production rates or reduce gas lift requirements while maintaining production levels. While there is a growing global interest, foam-assisted gas lift (FAGL) is a relatively modern artificial lifting method with less experience regarding its applications in oil wells. In this study, the feasibility of using a commercial surfactant for improving oil well productivity is investigated via laboratory experiments. A novel laboratory setup resembling a vertical well rig is designed to analyze the impact of surfactant concentration, temperature, brine salinity and phase-specific flow rates (or flow regimes) on the pressure drop across the column. This setup is operational at high temperatures, requires minimal sample amounts, and significantly reduces the experimental errors in pressure drop readings, resulting in highly accurate and stable measurements. The laboratory tests confirm that the addition of foamer reduces pressure drop in the production tubing, thus effectively increasing production. Additionally, an optimal foamer concentration is also detected. The results obtained in this study are very promising and present opportunities to explore a new chapter in artificial lift and production enhancement techniques.",0,0,0
Multiphase Flow,Pressure Drop,"Husein, Norhafizuddin; Ismail, Issham; Boyou, Natalie Vanessa; Mani, Sanjihuen V. Selva; Wong, Zhu Ker; Sulaiman, Wan Rosli Wan",Experimental investigation of different simulated formation water salinity in three-phase waxy crude oil-water-gas flow in horizontal pipes,Waxy crude oil; Oil-water-gas three-phase flow; Flow pattern; Pressure gradient; Liquid holdup,2-PHASE FLOW; PRESSURE-DROP; MULTIPHASE FLOW; PREDICTING FLOW; VOID FRACTION; EMULSIONS; PATTERNS; VISCOSITY; DIAMETER; TRANSITIONS,"Three-phase oil-water-gas flow experiments have been conducted in a horizontally configured rig made of carbon steel pipe with an ID of 0.041 m and a total length of 24.3 m. The test fluids were Malaysian waxy crude oil from Malay basin and three concentrations of simulated formation water salinity, namely 0 ppm, 15 000 ppm, and 30 000 ppm. The waxy crude oil and simulated formation water are varied at six different superficial liquid velocities ranging from 0.5 to 3.0 m/s while the gas phase is varied at 10 different superficial velocities ranging from 0.01 to 0.61 m/s. Eight flow patterns are observed using observational method; one of which is a newly discovered flow pattern identified as Slug with Oil Film-Oil Continuous (SLOF-OC). Salinity does not give significant effect on oil-gas interface but significantly affects the oil-water interface as lower formation water salinity is dispersed easily in crude oil compared to higher formation water salinity. The highest pressure gradient recorded was 2506.84 Pa/m at the highest superficial gas velocity while the lowest pressure gradient recorded was 89.53 Pa/m at the lowest superficial gas velocity. It is imperative to note that the experimental investigation of Malaysian waxy crude oil with different formation salinity in the three-phase flow study is in an unchartered area, therefore it provides a new platform for furthering more complex research works such as fourphase flow (gas, oil, water, and wax particles) below Wax-Appearing Temperature (WAT).",0,0,2
Multiphase Flow,Relative Permeability,"Alpak, Faruk Omer",Practical implementation of a method for global single-phase flow-based transmissibility upscaling using generic flow boundary conditions and its application on models with non-local heterogeneities,Global flow-based upscaling; Transmissibility upscaling; Generic flow boundary conditions; Multi-point flux approximation; Reservoir simulation,FINITE-ELEMENT-METHOD; QUADRILATERAL GRIDS; ELLIPTIC PROBLEMS; SIMULATION; PERMEABILITY; DISCRETIZATION; RESERVOIRS; IMPACT,"Local upscaling techniques fall short in capturing the dynamic effects of laterally continuous non-local geologic heterogeneities, for example, high-permeability channels, vertically thin, yet, horizontally extensive shale layers. Global upscaling techniques have been introduced to remedy the shortcomings of local scale-up approaches. In order to address the upscaling challenges associated with non-local heterogeneities, we have developed a practical and effective flow-based transmissibility scale-up method that computes coarse-scale transmissibilities using flux derived from single-phase flow simulations with generic global boundary conditions, referred to as the global transmissibility upscaling (GTU) method. GTU targets more accurate upscaling of laterally continuous non-local heterogeneities including the ones modeled on distorted cornerpoint grids. A variant of GTU is developed in this context that uses fluxes computed by use of the multi-point flux approximation (MPFA) discretization technique at the fine scale. While various global upscaling methods were described in the literature, they are rarely used in industrial applications due to challenges related to implementation. We describe in detail an effective practical implementation of the GTU method in a comprehensive industrial-grade simulation package and share our learnings with GTU on aggressively upscaled models with non-local heterogeneities. We demonstrate the application of GTU to several challenging reservoir models. Comparisons of GTU-based model responses are made with ones stemming from local upscaling techniques popularly utilized in the industry using fine-scale model predictions as reference. Investigated numerical examples demonstrate that the GTU method leads to notable improvements in the accuracy delivered by coarse-scale models. Especially, the application of GTU is most impactful for high-upscaling-ratio models with complex fine-scale connectivity because GTU preserves the fine-scale behavior more authentically compared to local techniques. We demonstrate that GTU naturally complements an innovative regional multiphase upscaling (RMU) method on aggressively upscaled models with strong multiphase flow associated with displacement-type recovery mechanisms. It has also been observed that using MPFA on cornerpoint grids to obtain fine-scale fluxes for GTU gives rise to more accurate coarse-scale pressure behavior. We have also observed that GTU is especially effective when combined with a regional multiphase upscaling method for ultimate accuracy in simulations of displacement-based recovery mechanisms.",0,0,0
Multiphase Flow,Relative Permeability,"Yang, Shikai; Yang, Daoyong",Integrated characterization of wormhole network by use of a modified pressure-gradient-based (PGB) sand failure criterion and ensemble-based history matching during CHOPS processes,Wormhole network; Cold heavy oil production with sand; Pressure-gradient-based sand failure criterion; Ensemble-based history matching; Upscaling,RELATIVE PERMEABILITY; HEAVY-OIL; KALMAN-FILTER; CAPILLARY-PRESSURE; TIGHT FORMATIONS; DATA ASSIMILATION; MODEL; RESERVOIR; FLOW; QUANTIFICATION,"In this paper, a damped iterative ensemble Kalman filter (IEnKF) technique has been developed and integrated with a recently modified pressure-gradient-based (PGB) sand failure criterion to implicitly and inversely characterize the dynamic wormhole network during cold heavy oil production with sand (CHOPS) processes. With an improved upscaling process, not only has a microscopic PGB sand failure criterion been properly upscaled to the grid-scale simulation, but also it can be dynamically, implicitly, and inversely determined. Then, such a sand failure model together with three-phase relative permeability is validated and applied to reproduce wormhole network in a laboratory experiment conditioned to its sand production profile. Good agreements between the observed and simulated cumulative production profiles including oil, gas, and sand have been achieved with satisfactory convergence by integrating the ensemble-based history matching method. The simulated wormhole network has shown its great similarity to the experimental observations, while the convergence of the ensemble based history matching algorithm is greatly improved with a widespread of initial ensembles in each grid. Furthermore, deviations between the observed and updated production profiles can be significantly minimized by dividing the entire production period into three sequential stages, each of which has its distinct relative permeability curves due to the major effect (i.e., foamy oil flow, sand failure, and slurry flow) on its multiphase flow behaviours, respectively. By integrating the ensemble-based sand failure model with the damped-IEnKF method, the dynamic wormhole network during a CHOPS process can be accurately characterized with satisfactory convergence, demonstrating its robustness and practicality of dynamically and inversely simulating the preferential wormhole network. Such an ensemble-based sand failure model can be seamlessly incorporated with any commercial reservoir simulators under various conditions.",0,0,1
Multiphase Flow,Relative Permeability,"Faramarzi-Palangar, Mohsen; Mirzaei-Paiaman, Abouzar",Identifying two-phase flow rock types in CO2-brine systems using TEM-function,CO2 geo-sequestration; CO2-Brine; Rock type; TEM-Function; Relative permeability; FZI-star,WETTABILITY LITERATURE SURVEY; RELATIVE PERMEABILITY DATA; IN-SITU CONDITIONS; CO2 STORAGE; MULTIPHASE FLOW; SUPERCRITICAL CO2/BRINE; SANDSTONE; DRAINAGE; MODELS; BRINE,"CO2 injection into deep saline aquifers is a feasible solution for mitigating climate change. Prediction of fate and transport of CO2 in subsurface requires accurate numerical reservoir models. A reliable reservoir model needs a precise two-phase flow characterization. Recently, technique of True Effective Mobility (TEM-function) was proposed to characterize multi-phase fluid flow properties of rocks (i.e., dynamic rock typing). In this study, applicability of two-phase flow rock typing in CO2-brine systems was studied using TEM-function. Five and three two-phase flow rock types were found for the studied sandstone and carbonate samples, respectively. Existence of multiple dynamic rock types shows that the injection of CO2 into saline aquifers forms a complex and heterogeneous two-phase flow pattern due to pore space heterogeneity and fluid properties along with in-situ conditions. Relative permeability curves of each two-phase rock type were also studied to check if relative permeability data can reflect two-phase flow characteristics. It was observed that relative permeability fails in establishing a relationship with two-phase flow characteristics in the CO2-brine systems. Furthermore, it was investigated whether the two-phase flow rock types identified by TEM-function establish a relationship with basic rock properties. The results show that the two-phase flow rock types identified by TEM-function establish clear relationships with FZI* (FZI-star).",0,0,2
Multiphase Flow,Relative Permeability,"Bellabiod, Sofiane; Deghmoum, Abdelhakim; Aris, Abdelkader; Karacali, Ozgur",An insight to formation damage evolution,Formation damage time evolution; Pressure transient analysis; Well test,,"Formation damage can significantly defer hydrocarbon production. Formation damage is one of the key parameters used to evaluate the quality of various operations during the life of a well. The evolution of formation damage over time is rarely studied. This paper presents the pressure transient analysis (PTA) used to derive a correlation between skin factor increase and the length of time for which a well was left exposed to drilling fluid. Multiple field examples are analyzed and modeled comparatively to evaluate the magnitude of the time-lapse formation damage. A quantitative relationship between the increase in mechanical skin as a function of exposure to drilling mud is constructed by a polynomial fitting. This gives us an insight on the how the well skin increases with exposure to drilling mud. Several mathematical models have been developed to model formation damage mechanisms. However, it is cumbersome to isolate and compute the individual mechanisms contributing to observed damage. Formation damage results from a combination of the pore size distribution, fines migration, fluid compatibility problems, wettability, presence of inorganic salts deposition, insufficient well cleanup, organic substance deposition, multiphase flow effects, etc. The proposed approach uses the skin factor derived from pressure transient analysis (PTA) to track the time-lapse evolution of formation damage during exposure time to mud, from drilling to production. The methodology has been applied to various reservoir rocks to quantify the impact for a specific rock type. Results from pressure transient tests conducted immediately after drilling, casing, and perforating are compared with production tests performed multiple years after drilling confirm that there is a mathematical relation between the formation damage, type of drilling and completion fluid, formation rock type, and exposure time to such fluids. The formation damage increase is more severe for longer duration of exposure, and also more severe for higher formation permeability.",0,0,2
Multiphase Flow,Flow Pattern,"Chaves, Gabriela Souza; Karami, Hamidreza; Ferreira Filho, Virgilio Jose Martins; Vieira, Bruno Ferreira",A comparative study on the performance of multiphase flow models against offshore field production data,Multiphase flow; Production optimization; Offshore data analysis; Flow assurance; Flow models,2-PHASE FLOW; PRESSURE-DROP; PATTERN TRANSITIONS; MECHANISTIC MODEL; PREDICTING FLOW; VISCOSITY; OIL,"In the oil industry, multiphase flow models are commonly used to simulate the flow from reservoir to the production unit. Flow simulations help in the production monitoring and optimization to support the decisionmaking process. Despite the need for accurate simulations to support production operations, multiphase flow models are mostly developed using laboratory data and rarely validated under field-scale conditions. To improve the understanding of multiphase flow models in field conditions, this work evaluates the performance of a large set of models for a dataset composed of two production units with 20 producing wells and 865 measured production points. The wells are divided and analyzed in two segments: the surface flowline and the wellbore. The evaluation compares the models' performances using various statistical parameters and trending charts. The evaluation analyzes the impacts of production parameters, well geometry, predicted flow pattern, and pressure drop components on the model performances. Overall, Ansari's model presented the best performance with 13.8% absolute average percent error for the flowline segment and 14.1% error for the wellbore segment. In addition, Gray can also generate good results for most but not all of the tested wellbores. From the production parameters evaluation, higher flow rate tests resulted in more stable outputs. Ansari and Beggs models showed a trend of increasing errors for wells with larger horizontal wellbore lengths. Also, Beggs model showed larger errors when the transition flow pattern was predicted. Finally, both Ansari and Beggs models showed larger overprediction errors for tests with higher pressure losses in the flowline segment, while Gray showed smaller errors for these cases. The conclusions can be used to select the best models given the production system's flow parameters, or be incorporated in systems to increase the accuracy.",0,0,0
Multiphase Flow,Flow Pattern,"Faramarzi-Palangar, Mohsen; Mirzaei-Paiaman, Abouzar",Identifying two-phase flow rock types in CO2-brine systems using TEM-function,CO2 geo-sequestration; CO2-Brine; Rock type; TEM-Function; Relative permeability; FZI-star,WETTABILITY LITERATURE SURVEY; RELATIVE PERMEABILITY DATA; IN-SITU CONDITIONS; CO2 STORAGE; MULTIPHASE FLOW; SUPERCRITICAL CO2/BRINE; SANDSTONE; DRAINAGE; MODELS; BRINE,"CO2 injection into deep saline aquifers is a feasible solution for mitigating climate change. Prediction of fate and transport of CO2 in subsurface requires accurate numerical reservoir models. A reliable reservoir model needs a precise two-phase flow characterization. Recently, technique of True Effective Mobility (TEM-function) was proposed to characterize multi-phase fluid flow properties of rocks (i.e., dynamic rock typing). In this study, applicability of two-phase flow rock typing in CO2-brine systems was studied using TEM-function. Five and three two-phase flow rock types were found for the studied sandstone and carbonate samples, respectively. Existence of multiple dynamic rock types shows that the injection of CO2 into saline aquifers forms a complex and heterogeneous two-phase flow pattern due to pore space heterogeneity and fluid properties along with in-situ conditions. Relative permeability curves of each two-phase rock type were also studied to check if relative permeability data can reflect two-phase flow characteristics. It was observed that relative permeability fails in establishing a relationship with two-phase flow characteristics in the CO2-brine systems. Furthermore, it was investigated whether the two-phase flow rock types identified by TEM-function establish a relationship with basic rock properties. The results show that the two-phase flow rock types identified by TEM-function establish clear relationships with FZI* (FZI-star).",0,0,2
Multiphase Flow,Flow Pattern,"Husein, Norhafizuddin; Ismail, Issham; Boyou, Natalie Vanessa; Mani, Sanjihuen V. Selva; Wong, Zhu Ker; Sulaiman, Wan Rosli Wan",Experimental investigation of different simulated formation water salinity in three-phase waxy crude oil-water-gas flow in horizontal pipes,Waxy crude oil; Oil-water-gas three-phase flow; Flow pattern; Pressure gradient; Liquid holdup,2-PHASE FLOW; PRESSURE-DROP; MULTIPHASE FLOW; PREDICTING FLOW; VOID FRACTION; EMULSIONS; PATTERNS; VISCOSITY; DIAMETER; TRANSITIONS,"Three-phase oil-water-gas flow experiments have been conducted in a horizontally configured rig made of carbon steel pipe with an ID of 0.041 m and a total length of 24.3 m. The test fluids were Malaysian waxy crude oil from Malay basin and three concentrations of simulated formation water salinity, namely 0 ppm, 15 000 ppm, and 30 000 ppm. The waxy crude oil and simulated formation water are varied at six different superficial liquid velocities ranging from 0.5 to 3.0 m/s while the gas phase is varied at 10 different superficial velocities ranging from 0.01 to 0.61 m/s. Eight flow patterns are observed using observational method; one of which is a newly discovered flow pattern identified as Slug with Oil Film-Oil Continuous (SLOF-OC). Salinity does not give significant effect on oil-gas interface but significantly affects the oil-water interface as lower formation water salinity is dispersed easily in crude oil compared to higher formation water salinity. The highest pressure gradient recorded was 2506.84 Pa/m at the highest superficial gas velocity while the lowest pressure gradient recorded was 89.53 Pa/m at the lowest superficial gas velocity. It is imperative to note that the experimental investigation of Malaysian waxy crude oil with different formation salinity in the three-phase flow study is in an unchartered area, therefore it provides a new platform for furthering more complex research works such as fourphase flow (gas, oil, water, and wax particles) below Wax-Appearing Temperature (WAT).",0,0,2
Multiphase Flow,Flow Pattern,"Aldhuhoori, Mohammed A.; Belhaj, Hadi; Alkuwaiti, Hamda K.; Ghosh, Bisweswar; Fernandes, Ryan; Qaddoura, Rabab","Role of viscous, diffusion and inertial mechanisms in modeling fluid flow through unconventional reservoir",,NON-DARCY FLOW; SURFACE-DIFFUSION; GAS-FLOW; PERMEABILITY; TRANSPORT; NANOPORES,"Diffusion forces contribution has been heavily underestimated when modeling fluid flow in porous media especially in UCRs with a general agreement that viscous transport is the predominant controller. This work introduces a new comprehensive flow model suitable for tight UCRs, including viscous, inertia, and diffusion forces, to account for the transport of fluid in the three scales. The new model addressing multi-phase 1-D linear flow in tight UCRs has been mathematically derived and numerically solved, and tested against real cases using MATLAB software. Detailed parametric analysis has been conducted, and very clear profiles and flow patterns of the main flow parameters were identified. It has been established that, with lower permeability of the porous medium and lower viscosity of the flowing fluid, the diffusion mechanism becomes more predominant in controlling flow velocity. The results of the newly derived equations that includes the diffusion term clearly depicted the contribution of diffusivity to the flow in the nano-scaled pore spaces. The comparison between the suggested equation to existing equations and correlations that are used in the field to describe the behavior of the flow in low permeability and low porous medium have been established.",0,0,2
Multiphase Flow,Rock Types,"Faramarzi-Palangar, Mohsen; Mirzaei-Paiaman, Abouzar",Identifying two-phase flow rock types in CO2-brine systems using TEM-function,CO2 geo-sequestration; CO2-Brine; Rock type; TEM-Function; Relative permeability; FZI-star,WETTABILITY LITERATURE SURVEY; RELATIVE PERMEABILITY DATA; IN-SITU CONDITIONS; CO2 STORAGE; MULTIPHASE FLOW; SUPERCRITICAL CO2/BRINE; SANDSTONE; DRAINAGE; MODELS; BRINE,"CO2 injection into deep saline aquifers is a feasible solution for mitigating climate change. Prediction of fate and transport of CO2 in subsurface requires accurate numerical reservoir models. A reliable reservoir model needs a precise two-phase flow characterization. Recently, technique of True Effective Mobility (TEM-function) was proposed to characterize multi-phase fluid flow properties of rocks (i.e., dynamic rock typing). In this study, applicability of two-phase flow rock typing in CO2-brine systems was studied using TEM-function. Five and three two-phase flow rock types were found for the studied sandstone and carbonate samples, respectively. Existence of multiple dynamic rock types shows that the injection of CO2 into saline aquifers forms a complex and heterogeneous two-phase flow pattern due to pore space heterogeneity and fluid properties along with in-situ conditions. Relative permeability curves of each two-phase rock type were also studied to check if relative permeability data can reflect two-phase flow characteristics. It was observed that relative permeability fails in establishing a relationship with two-phase flow characteristics in the CO2-brine systems. Furthermore, it was investigated whether the two-phase flow rock types identified by TEM-function establish a relationship with basic rock properties. The results show that the two-phase flow rock types identified by TEM-function establish clear relationships with FZI* (FZI-star).",0,0,2
Multiphase Flow,Rock Types,"Bellabiod, Sofiane; Deghmoum, Abdelhakim; Aris, Abdelkader; Karacali, Ozgur",An insight to formation damage evolution,Formation damage time evolution; Pressure transient analysis; Well test,,"Formation damage can significantly defer hydrocarbon production. Formation damage is one of the key parameters used to evaluate the quality of various operations during the life of a well. The evolution of formation damage over time is rarely studied. This paper presents the pressure transient analysis (PTA) used to derive a correlation between skin factor increase and the length of time for which a well was left exposed to drilling fluid. Multiple field examples are analyzed and modeled comparatively to evaluate the magnitude of the time-lapse formation damage. A quantitative relationship between the increase in mechanical skin as a function of exposure to drilling mud is constructed by a polynomial fitting. This gives us an insight on the how the well skin increases with exposure to drilling mud. Several mathematical models have been developed to model formation damage mechanisms. However, it is cumbersome to isolate and compute the individual mechanisms contributing to observed damage. Formation damage results from a combination of the pore size distribution, fines migration, fluid compatibility problems, wettability, presence of inorganic salts deposition, insufficient well cleanup, organic substance deposition, multiphase flow effects, etc. The proposed approach uses the skin factor derived from pressure transient analysis (PTA) to track the time-lapse evolution of formation damage during exposure time to mud, from drilling to production. The methodology has been applied to various reservoir rocks to quantify the impact for a specific rock type. Results from pressure transient tests conducted immediately after drilling, casing, and perforating are compared with production tests performed multiple years after drilling confirm that there is a mathematical relation between the formation damage, type of drilling and completion fluid, formation rock type, and exposure time to such fluids. The formation damage increase is more severe for longer duration of exposure, and also more severe for higher formation permeability.",0,0,2
Multiphase Flow,Two-phase Flow,"Park, Ki-Heum; Kim, Tea-Woo; Kim, Young-Ju; Lee, Nayoung; Seo, Yutaek",Experimental investigation of model-based IMC control of severe slugging,Multi-phase flow; Flow loop; Severe slugging; IMC control; OLGA,,"Severe slugging formation has been investigated experimentally in a two-phase flow-loop composed of a downwardly inclined pipe and a vertical riser. In this study, a bifurcation diagram was made to more clearly identify which flow the current system has at each valve opening. A model was made by inputting the dimensions of the flow loop using OLGA, a multiphase flow simulation program, to compare the experimental results. The model-based control logic was constructed by estimating the transfer function utilizing the OLGA model. The estimated transfer function is used to tune the gain of the PI controller, using the method called the Internal Model Control (IMC). Through this method, PI gain can be easily obtained through only one tuning parameter. When the PI controller gain is obtained through the transfer function of the flow loop system, mitigation of severe slugging was achieved while increasing the flow rate than the case with manual choking.",0,0,0
Multiphase Flow,Two-phase Flow,"Faramarzi-Palangar, Mohsen; Mirzaei-Paiaman, Abouzar",Identifying two-phase flow rock types in CO2-brine systems using TEM-function,CO2 geo-sequestration; CO2-Brine; Rock type; TEM-Function; Relative permeability; FZI-star,WETTABILITY LITERATURE SURVEY; RELATIVE PERMEABILITY DATA; IN-SITU CONDITIONS; CO2 STORAGE; MULTIPHASE FLOW; SUPERCRITICAL CO2/BRINE; SANDSTONE; DRAINAGE; MODELS; BRINE,"CO2 injection into deep saline aquifers is a feasible solution for mitigating climate change. Prediction of fate and transport of CO2 in subsurface requires accurate numerical reservoir models. A reliable reservoir model needs a precise two-phase flow characterization. Recently, technique of True Effective Mobility (TEM-function) was proposed to characterize multi-phase fluid flow properties of rocks (i.e., dynamic rock typing). In this study, applicability of two-phase flow rock typing in CO2-brine systems was studied using TEM-function. Five and three two-phase flow rock types were found for the studied sandstone and carbonate samples, respectively. Existence of multiple dynamic rock types shows that the injection of CO2 into saline aquifers forms a complex and heterogeneous two-phase flow pattern due to pore space heterogeneity and fluid properties along with in-situ conditions. Relative permeability curves of each two-phase rock type were also studied to check if relative permeability data can reflect two-phase flow characteristics. It was observed that relative permeability fails in establishing a relationship with two-phase flow characteristics in the CO2-brine systems. Furthermore, it was investigated whether the two-phase flow rock types identified by TEM-function establish a relationship with basic rock properties. The results show that the two-phase flow rock types identified by TEM-function establish clear relationships with FZI* (FZI-star).",0,0,2
Monte Carlo,Distribution,"Costa, Beethoven G. dos S.; Jaculli, Marcelo A.; Mendes, Jose Ricardo P.; Colombo, Danilo",Evaluation of rock integrity during well drilling activities using reliability analysis,Well integrity; Rock reliability; Well safety; Kick tolerance,,"The main risk during the construction of oil wells is the possibility of uncontrolled hydrocarbon flow occurring from the well to the environment, commonly known as a blowout. After the Macondo accident, in the Gulf of Mexico, in 2010, there has been, in recent years, a significant increase in researches related to both well integrity and operational safety. A possible approach is to seek tools that can predict disastrous scenarios and support the decision making process. In this context, this work evaluates the reliability of the weakest rock in an open hole section, which is the formation immediately below the last settled casing shoe. Reliability, in this case, refers to the likelihood that the rock does not fracture during a possible kick or during drilling fluid circulation without a kick. The formulation of this problem involves addressing the inherent uncertainties, which may cause the failure of the ""rock"" barrier element. Modeling was performed by assigning probabilistic distributions to the parameters carrying uncertainties and by proposing two solutions. If all the uncertainties can be modeled using the normal distribution, it is possible to calculate the reliability analytically; meanwhile, if the variables are modeled using more than one type of distribution, an analytical solution may be hard to achieve and Monte Carlo simulations are preferred to obtain a numerical solution. The numerical solution does not require mean values and standard deviations of the output variables and becomes particularly useful when these characteristics are unknown. Therefore, this methodology evaluates the competence of the rock as a barrier element, enhancing operational safety and maintaining well integrity. The calculated reliability values can be used to assist in real-time drilling monitoring, from a rock integrity standpoint. The results of this methodology include the rock reliability as a function of the well depth, based on the current drilling phase. This includes the two aforementioned scenarios, with and without a kick.",0,0,0
Monte Carlo,Distribution,"Andrade, GabrielM P.; Oechsler, Bruno F.; Coelho, Josiane S. C.; Fagundes, Flavia M.; Arouca, Fabio O.; Damasceno, Joao J. R.; Scheid, Claudia M.; Calcada, Luis A.",Evaluation of characteristic diameter on barite settling in drilling fluids by Monte Carlo method,Barite settling; Drilling fluids; Characteristic particle size; Optimization; Monte Carlo,,"Several researchers have discussed the settling behaviour of particulate materials because of the challenges and applications in different engineering fields. Particularly, settling of such weighting agents as barite, commonly added to drilling fluids, can cause problems in oil production, either on drilling processes or in production. Typically, sedimentation models consider a single value of particle size, which in this work, we refer to as characteristic diameter. This particle size can be chosen by statistical methods, such as the Sauter mean diameter, or it can be extracted directly from particle size distribution such as its mean, median, or mode. There are some conventions by how to choose the characteristic diameter; however, discarding the whole size variability from the particle size distribution is unwise. Regarding the literature, only a few works have, to the best of our knowledge, discussed the effects of this choice on the models' performance. This work then presents a new perspective on evaluating the uncertainty of the particle size distribution and choosing the best characteristic diameter, using a novel method based on Monte Carlo simulations. To evaluate the method, research team chose a barite settling model (recently published) for drilling fluids. Experimental data of barite concentration in batch settling test supported the Monte Carlo simulations. Five characteristic diameters were evaluated. Results showed different column heights have different characteristic diameters which differed from classical values such as Sauter's diameter by up to 200%, producing different model output variables. New particle size also affected estimation of remaining parameters and changed predicted properties such as media permeability by up to 90%. This work opens a discussion on how well-represented a particle size distribution is when researchers choose only a characteristic diameter is chosen without evaluating the whole distribution.",0,0,0
Monte Carlo,Distribution,"Maior, Caio B. S.; Macedo, July B.; Lins, Isis D.; Moura, Marcio C.; Azevedo, Rafael, V; Santana, Joao M. M.; da Silva, Manoel F.; Magalhaes, Marcus V. C.",Bayesian prior distribution based on generic data and experts' opinion: A case study in the O&G industry,Informative prior distribution; Bayesian reliability; Technology development; Well equipment,REMAINING USEFUL LIFE; RELIABILITY; INFORMATION; FAILURE; SIMULATION; PSO,"Reliability estimation is an essential task to ensure predictability on the life of equipment installed in oil wells, allowing forecasting costs, planning maintenance, and estimating system availability. However, data may be rather scarce and/or expensive to obtain, especially for technologies under development in the Oil and Gas (O&G) industry. The information is frequently available in generic databases and expert opinions. In the Bayesian framework, the prior knowledge about a system's reliability is updated as a new field and/or test data are gathered. This paper proposes an approach that does not require direct elicitation of parameters to define informative prior distributions for the reliability function using fault tree analysis, expert's opinions, and/or generic data at the system level of equipment under development. Specifically, the method-of-moments and maximum-entropy are adopted to propagate downward the uncertainty from the system level through the failure modes until the basic events of the fault tree, weighted by the expert knowledge of the failure behavior. Then, in possession of all prior distributions of the basic events, the information may be propagated upward based on Monte Carlo simulation to update the system reliability distribution. Finally, we present a case study of the proposed methodology applied to a novel open-hole expandable packer, a completion equipment recently installed in a Brazilian oil field. The failure modes and failure causes are discussed, and, after expert elicitation, the definition of the informative prior distribution is achieved. Therefore, we estimate the reliability for a given time and assess if the novel equipment attains the company's risk target, taking O&G standards as reference.",0,0,1
Monte Carlo,Drilling,"Costa, Beethoven G. dos S.; Jaculli, Marcelo A.; Mendes, Jose Ricardo P.; Colombo, Danilo",Evaluation of rock integrity during well drilling activities using reliability analysis,Well integrity; Rock reliability; Well safety; Kick tolerance,,"The main risk during the construction of oil wells is the possibility of uncontrolled hydrocarbon flow occurring from the well to the environment, commonly known as a blowout. After the Macondo accident, in the Gulf of Mexico, in 2010, there has been, in recent years, a significant increase in researches related to both well integrity and operational safety. A possible approach is to seek tools that can predict disastrous scenarios and support the decision making process. In this context, this work evaluates the reliability of the weakest rock in an open hole section, which is the formation immediately below the last settled casing shoe. Reliability, in this case, refers to the likelihood that the rock does not fracture during a possible kick or during drilling fluid circulation without a kick. The formulation of this problem involves addressing the inherent uncertainties, which may cause the failure of the ""rock"" barrier element. Modeling was performed by assigning probabilistic distributions to the parameters carrying uncertainties and by proposing two solutions. If all the uncertainties can be modeled using the normal distribution, it is possible to calculate the reliability analytically; meanwhile, if the variables are modeled using more than one type of distribution, an analytical solution may be hard to achieve and Monte Carlo simulations are preferred to obtain a numerical solution. The numerical solution does not require mean values and standard deviations of the output variables and becomes particularly useful when these characteristics are unknown. Therefore, this methodology evaluates the competence of the rock as a barrier element, enhancing operational safety and maintaining well integrity. The calculated reliability values can be used to assist in real-time drilling monitoring, from a rock integrity standpoint. The results of this methodology include the rock reliability as a function of the well depth, based on the current drilling phase. This includes the two aforementioned scenarios, with and without a kick.",0,0,0
Monte Carlo,Drilling,"Ruschel, Augusto; Silva Dantas, Claudio Marcio; Mendes de Sousa, Fernando Jorge; Simao, Marina Leivas; Sudati Sagrilo, Luis Volnei; Percy, Joseir Gandra; Oliveira, Felipe Lima",Wellhead fatigue analysis considering the effect of wind-sea and swell waves by using Univariate Dimension Reduction Method,Wellhead fatigue; Wind-sea and swell induced fatigue; UDRM approach for fatigue assessment,,"In recent years, the observation of dynamic motions in wellhead structures during drilling operations turned wellhead fatigue into a great concern for the oil industry. As stated by DNV in its Recommended Practice E104 (DNVGL, 2018), the fatigue damage evaluation demands an accurate representation of environmental loads acting on the whole drilling structure, including rig, drilling riser and BOP/LMRP. In terms of computational costs, this representation can make the fatigue analysis very expensive. A high number of loading cases may be needed to take into account the statistical independence between environmental parameters, mainly when windsea and swell waves are taken into account. To solve this issue, this paper proposes the use of the Univariate Dimension Reduction Method (UDRM) to compute the fatigue damage in wellhead structures considering the effects of both types of waves. The main advantage of this procedure is that it replaces the solution of the fourfold integral associated to the problem by the solution of four one-dimensional integrals, which drastically reduces the number of numerical simulations required in the fatigue assessment. The method is applied to two study cases considering the environmental conditions of the Brazilian coast. In the first, the drilling unit is a semisubmersible platform, while in the second case a ship-based drilling unit is considered. The obtained results indicate a substantial reduction in computational costs without loss of accuracy of UDRM when compared to a Monte Carlo Simulation-based approach.",0,0,0
Monte Carlo,Drilling,"Andrade, GabrielM P.; Oechsler, Bruno F.; Coelho, Josiane S. C.; Fagundes, Flavia M.; Arouca, Fabio O.; Damasceno, Joao J. R.; Scheid, Claudia M.; Calcada, Luis A.",Evaluation of characteristic diameter on barite settling in drilling fluids by Monte Carlo method,Barite settling; Drilling fluids; Characteristic particle size; Optimization; Monte Carlo,,"Several researchers have discussed the settling behaviour of particulate materials because of the challenges and applications in different engineering fields. Particularly, settling of such weighting agents as barite, commonly added to drilling fluids, can cause problems in oil production, either on drilling processes or in production. Typically, sedimentation models consider a single value of particle size, which in this work, we refer to as characteristic diameter. This particle size can be chosen by statistical methods, such as the Sauter mean diameter, or it can be extracted directly from particle size distribution such as its mean, median, or mode. There are some conventions by how to choose the characteristic diameter; however, discarding the whole size variability from the particle size distribution is unwise. Regarding the literature, only a few works have, to the best of our knowledge, discussed the effects of this choice on the models' performance. This work then presents a new perspective on evaluating the uncertainty of the particle size distribution and choosing the best characteristic diameter, using a novel method based on Monte Carlo simulations. To evaluate the method, research team chose a barite settling model (recently published) for drilling fluids. Experimental data of barite concentration in batch settling test supported the Monte Carlo simulations. Five characteristic diameters were evaluated. Results showed different column heights have different characteristic diameters which differed from classical values such as Sauter's diameter by up to 200%, producing different model output variables. New particle size also affected estimation of remaining parameters and changed predicted properties such as media permeability by up to 90%. This work opens a discussion on how well-represented a particle size distribution is when researchers choose only a characteristic diameter is chosen without evaluating the whole distribution.",0,0,0
Monte Carlo,Seismic Inversion,"Yadav, Ashok; Nayak, Soumya Ranjan; Mondal, Samit",Agglomerative clustering to improve the resolution of pseudo well stochastic seismic inversion: A case study,"Reservoir characterization; Inversion; Rock Physics, Volume of Sand",CHAIN MONTE-CARLO; SIMULATION,"The Monte Carlo rejection and Monte Carlo Markov Chain methods are two common sampling techniques in Bayesian seismic inversion. Conventional methods of pseudo well stochastic seismic inversion for reservoir properties uses Monte Carlo rejection sampling of pseudo-wells to select those that best match seismic traces. The selected pseudo-wells do not influence the selection/rejection of subsequent pseudo-wells. The process requires a very large number of prior pseudo-wells to draw a reasonable outcome, which consumes a major part of the computation time. In conventional methods, the best-matched pseudo-wells often have dissimilarly shaped volume of shale logs, which can degrade the resolution of the outcome. Though Agglomerative clustering is well-known but the idea of grouping pseudo-wells based on similarly shaped volume of shale logs in pseudo well stochastic seismic inversion is unique. We propose an agglomerative clustering technique to group the prior pseudo-wells according to the shape of their volume of shale logs, before matching to seismic. The centroids of the pseudo-well clusters summarize the large number of prior pseudo-wells. The best-matched pseudo-well cluster centmid with seismic gives the most likely outcome while the two next best-matched cluster centroids give alternative results. The alternative results are useful to understand the uncertainty in the outcome. It has been observed that, the proposed method has reduced computation time (50-55% less than conventional pseudo well stochastic inversion). Meanwhile, the quantification of sand volume from the proposed method shows improvement over the conventional method. A comparison between the proposed and the conventional method has been shown on a synthetic wedge model and real seismic. In the wedge model (volume of sand is 0.65), the resultant volume of sand predicted in the modified method (0.7) is better than that predicted using the conventional method (0.8). The modified pseudo-well stochastic seismic inversion method has been applied on seismic data from deepwater Krishna-Godavari basin. The result shows an improvement in the characterization of thin shale layers within the reservoir.",0,0,0
Monte Carlo,Seismic Inversion,"Zhang, Jian; Li, Jingye; Chen, Xiaohong; Li, Yuanqiang",Geological structure-guided hybrid MCMC and Bayesian linearized inversion methodology,Seismic inversion; Plane wave destruction (PWD); Block coordinate descent (BCD); Acoustic impedance (AI); Uncertainty evaluation,,"Seismic inversion is a common method for hydrocarbon reservoir characterization, as it consists of a proven and effective approach to derive elastic properties from reflectivity seismic data. Markov Chain Monte Carlo (MCMC) based seismic inversion approach is a suitable choice to numerically evaluate the posterior uncertainties associated with the inverse solution without assuming linear forward operators, Gaussian, or generalized Gaussian prior models. However, the existing MCMC based seismic inversion approaches are mostly performed trace-bytrace, which means that the spatial coupling of model parameters is not considered. When the results of trace-bytrace based inversion are combined to generate a 2D profile, the final results will be laterally discontinuous. Moreover, the large dimension of the model space causes low convergence efficiency of MCMC-based seismic inversion. To overcome these issues, a geological structure-guided hybrid MCMC and Bayesian linearized inversion (BLI) methodology for seismic inversion is implemented. The geological structure information obtained using plane wave destruction (PWD) is incorporated to the MCMC based inversion algorithm in the form of dips yields more geologically meaningful results. The hybrid MCMC and BLI strategy, which takes advantage of BLI s high efficiency to provide initial configuration for MCMC, is used to improve the convergence of MCMC-based inversion. Additionally, the block coordinate descent (BCD) algorithm is introduced to replace the large-scale matrix solution in geological structure-guided, and consequently reduce memory consumption and time cost. This methodology is validated on a synthetic seismic dataset, as well as on a real case. It has proven to be a reliable approach to obtain acoustic impedance (AI) from post-stack seismic data in an efficient way. It also addresses the uncertainty related with the ill-posed characteristics of the inversion methodology itself.",0,0,1
Monte Carlo,Conventional Methods,"Yadav, Ashok; Nayak, Soumya Ranjan; Mondal, Samit",Agglomerative clustering to improve the resolution of pseudo well stochastic seismic inversion: A case study,"Reservoir characterization; Inversion; Rock Physics, Volume of Sand",CHAIN MONTE-CARLO; SIMULATION,"The Monte Carlo rejection and Monte Carlo Markov Chain methods are two common sampling techniques in Bayesian seismic inversion. Conventional methods of pseudo well stochastic seismic inversion for reservoir properties uses Monte Carlo rejection sampling of pseudo-wells to select those that best match seismic traces. The selected pseudo-wells do not influence the selection/rejection of subsequent pseudo-wells. The process requires a very large number of prior pseudo-wells to draw a reasonable outcome, which consumes a major part of the computation time. In conventional methods, the best-matched pseudo-wells often have dissimilarly shaped volume of shale logs, which can degrade the resolution of the outcome. Though Agglomerative clustering is well-known but the idea of grouping pseudo-wells based on similarly shaped volume of shale logs in pseudo well stochastic seismic inversion is unique. We propose an agglomerative clustering technique to group the prior pseudo-wells according to the shape of their volume of shale logs, before matching to seismic. The centroids of the pseudo-well clusters summarize the large number of prior pseudo-wells. The best-matched pseudo-well cluster centmid with seismic gives the most likely outcome while the two next best-matched cluster centroids give alternative results. The alternative results are useful to understand the uncertainty in the outcome. It has been observed that, the proposed method has reduced computation time (50-55% less than conventional pseudo well stochastic inversion). Meanwhile, the quantification of sand volume from the proposed method shows improvement over the conventional method. A comparison between the proposed and the conventional method has been shown on a synthetic wedge model and real seismic. In the wedge model (volume of sand is 0.65), the resultant volume of sand predicted in the modified method (0.7) is better than that predicted using the conventional method (0.8). The modified pseudo-well stochastic seismic inversion method has been applied on seismic data from deepwater Krishna-Godavari basin. The result shows an improvement in the characterization of thin shale layers within the reservoir.",0,0,0
Monte Carlo,Conventional Methods,"Liu, Xing; Jin, Yan; Lin, Botao",An efficient stimulated reservoir area (SRA) estimation method based on octree decomposition of microseismic events,Hydraulic fracturing; Microseismic monitoring; Stimulated reservoir volume; Stimulated reservoir area; Octree method; Monte Carlo method,FRACTURE; GEOMECHANICS; PROPAGATION; SYSTEMS; SHALE,"Fracture contact area is the critical factor determining post-treatment production after multi-stage hydraulic fracturing. At present, there are no effective methods for the estimation of the stimulated reservoir area (SRA) of the complex fracture network after stimulation. Conventional methods mostly focused on calculating stimulated reservoir volume (SRV) by using microseismic events directly or indirectly. However, since there is a large number of noise events in microseismic data that can't be removed completely, the SRV results often have huge errors and are inconsistent with practical well production. For this reason, we propose an efficient and robust SRA calculation method based on 3D octree decomposition. The method is able to effectively estimate SRA by generating a multi-level grid structure without reconstructing the fracture network. Through a large number of case simulations based on synthetic events generated by Monte Carlo method, it is found that our method could adapt to the estimation of SRA for different configurations. It could obtain reliable and robust results in the presence of noise events. Specifically, it is indicated that the maximum relative calculation error is less than 20% for mesoscale and large-scale fracture network. The error for small-scale fractures could be reduced below 30% combining with the error reduction approach put forward in this paper. The applicability of our method is also investigated through two horizontal well platforms. Compared with the conventional SRV method, it is found that SRA obtained by our method could better reflect the stimulation effects and is more consistent with real production. It could become a potential and effective index for stimulation evaluation and fracturing operation optimization.",0,0,1
Monte Carlo,Gas Reservoir,"Zoeir, A.; Riazi, M.; Kazemzadeh, Y.; Khodapanah, E.",To optimize well pattern during miscible gas injection process via heuristic techniques,Heuristic techniques; Injection well pattern; Uncertainty; Porous media; Gas injection,PARTICLE SWARM OPTIMIZATION; PLACEMENT OPTIMIZATION; DIFFERENTIAL EVOLUTION; ALGORITHM,"To detect optimum well locations for new injection wells one must generally notice to existing well locations, reservoir shape, capital cost per well construction in each area as well as recovery increase relevant to new well layout. Designing injection process presents inverse optimization issue whereas adjusting exploitation wells prior to primary recovery exhibits classic optimization problem. Most important design factor namely injection well layout has no unique explicit solution to solve via analytical or numerical techniques thus one can propose meta or hyper heuristic approaches to solve such problems. Our main novelty in this work is that here we cooperate four heuristic optimization approaches with our self made fast simulation technique to optimize well locations for two exemplar miscible gas injection processes. We employ MATLAB software to construct artificial porous media prototypes with different uncertainties to investigate optimization technique performances in low rather than high risk media. Outcomes illustrate that approaches like artificial immune system or particle swarm optimization which exhibit strong local search can effectively detect optimal well locations in high risk porous media. Results also show that solution techniques such as Monte Carlo that have strong global search capabilities at expense of weak local search can discover optimum well locations only in media with low uncertainty.",0,0,0
Monte Carlo,Gas Reservoir,"Fu, Xinyue; Wu, Wensheng; Wang, Hu; Ge, Yunlong",A new method of gas reservoir evaluation based on neutron cross section logging,Gas reservoir evaluation; Neutron cross section logging; Monte Carlo method,POROSITY; SATURATION,"It is a widely used method to evaluate gas reservoirs by measuring inelastic gamma rays. A petrophysical parameter fast neutron cross section (FNXS) was proposed to describe the inelastic gamma for gas reservoir evaluation. FNXS is the 14 MeV neutron macroscopic elastic scattering cross section. However, the description of inelastic gamma using FNXS is only a first order approximation. Therefore, in some scenarios, the evaluation of gas saturation is not accurate enough. In this paper, we propose a new parameter total fast neutron cross section (TFNXS) based on the inelastic gamma generation and attenuation theory. TFNXS is the sum of macroscopic elastic and inelastic scattering cross sections of 14 MeV neutrons. The physical meaning of TFNXS is the probability of inelastic and elastic scattering between neutrons and formation. TFNXS is a new formation property independent of neutron macroscopic capture cross section (Sigma). TFNXS value of gas is quite different from that of matrix minerals, water, oil and clay, so TFNXS is more sensitive to gas-bearing formation and can identify gas reservoir more effectively. We compared the sensitivity of TFNXS and FNXS to gas. The sensitivity of TFNXS to gas is similar to that of FNXS. The effects of different formation conditions on the measurement accuracy of the TFNXS and the FNXS are analyzed with the Monte Carlo method. Compared with FNXS, TFNXS can be obtained more accurately in water and oil layers. Different clay minerals have different effects on TFNXS and FNXS. TFNXS is less affected by wellbore environment, such as well diameter and wellbore fluid, than that of FNXS. We evaluate the application results of TFNXS and FNXS in various model wells. Both TFNXS and FNXS can effectively identify gas-bearing formations. The accuracy of using TFNXS to obtain gas saturation is higher than that of FNXS. TFNXS can more accurately monitor reservoirs and evaluate low porosity gas reservoirs than FNXS.",0,0,1
Monte Carlo,Neutron,"Tian, Lili; Zhang, Feng; Wu, Zeyun; Wang, Zhen; Qiu, Fei; Fang, Qunwei; Chen, Qian; Zhou, Liangwei",A new diffusion effect correction method in pulsed neutron capture logging,Pulsed neutron capture logging; Diffusion effect; Time decay spectrum,,"The neutron diffusion effect contributed considerate bias to the sigma estimation in the pulsed neutron capture (PNC) well logging, and thus this effect must be corrected to achieve an accepted sigma prediction. This paper developed a new diffusion effect correction method for a more accurate sigma estimation in the PNC well logging method. Since the diffusion effect with a given source spacing in a PNC tool mainly depends on neutron slowing down and absorption, two parameters, the capture gamma ray counts ratio (RCAP) of the far to near detectors and the gamma ray counts ratio of inelastic scattering to capture (RIC) in the near detector, were used in the new method to effectively correct the diffusion effect. This is because RCAP is sensitive to neutron slowing down ability and RIC is sensitive to thermal neutron absorption ability. A combined expression of RCAP and RIC thus can reflect both the scattering and absorption contribution to the diffusion coefficient, which is subsequently used to correct the diffusion effect. No additional efforts are required to measure RCAP and RIC because they can be simultaneously obtained with the gamma ray decay time spectrum measurement. Computational experiments based on Monte Carlo simulations demonstrated the sigma calculated with the new correction method has shown to be more accurate than the non-corrected apparent sigma in the PNC logging.",0,0,1
Monte Carlo,Neutron,"Fu, Xinyue; Wu, Wensheng; Wang, Hu; Ge, Yunlong",A new method of gas reservoir evaluation based on neutron cross section logging,Gas reservoir evaluation; Neutron cross section logging; Monte Carlo method,POROSITY; SATURATION,"It is a widely used method to evaluate gas reservoirs by measuring inelastic gamma rays. A petrophysical parameter fast neutron cross section (FNXS) was proposed to describe the inelastic gamma for gas reservoir evaluation. FNXS is the 14 MeV neutron macroscopic elastic scattering cross section. However, the description of inelastic gamma using FNXS is only a first order approximation. Therefore, in some scenarios, the evaluation of gas saturation is not accurate enough. In this paper, we propose a new parameter total fast neutron cross section (TFNXS) based on the inelastic gamma generation and attenuation theory. TFNXS is the sum of macroscopic elastic and inelastic scattering cross sections of 14 MeV neutrons. The physical meaning of TFNXS is the probability of inelastic and elastic scattering between neutrons and formation. TFNXS is a new formation property independent of neutron macroscopic capture cross section (Sigma). TFNXS value of gas is quite different from that of matrix minerals, water, oil and clay, so TFNXS is more sensitive to gas-bearing formation and can identify gas reservoir more effectively. We compared the sensitivity of TFNXS and FNXS to gas. The sensitivity of TFNXS to gas is similar to that of FNXS. The effects of different formation conditions on the measurement accuracy of the TFNXS and the FNXS are analyzed with the Monte Carlo method. Compared with FNXS, TFNXS can be obtained more accurately in water and oil layers. Different clay minerals have different effects on TFNXS and FNXS. TFNXS is less affected by wellbore environment, such as well diameter and wellbore fluid, than that of FNXS. We evaluate the application results of TFNXS and FNXS in various model wells. Both TFNXS and FNXS can effectively identify gas-bearing formations. The accuracy of using TFNXS to obtain gas saturation is higher than that of FNXS. TFNXS can more accurately monitor reservoirs and evaluate low porosity gas reservoirs than FNXS.",0,0,1
Monte Carlo,Unit,"Ogolo, Oghenerume",Modification of the unit technical cost equation for the accurate determination of the cost of producing a barrel of oil in relation to the Contractor's revenue,Unit technical cost; Modified unit technical cost; Economics; Profitability indicator,,"The unit technical cost (UTC) is the profitability indicator used in the oil and gas industry to determine the cost of producing a barrel of oil. The method used to calculate the UTC has certain limitation as it does not capture the entire cost burden borne by the contractor in respect to the revenue they generate from investments in the exploration and production of hydrocarbon. This is as a result of the front-end loaded nature of oil and gas Nations fiscal system. This research therefore modified the equation used to calculate the UTC and termed it as the modified UTC (MUTC). To determine the accuracy of the MUTC as a profitability indicator, a hypothetical oil field was assumed. Investment in the exploration and production of oil from this field was modelled using spreadsheet modeling technique. Three different petroleum economic models were built to capture the front-end loaded nature of a fiscal system. The base case model (Scenario 1) had no government take before tax deduction, while the other two scenarios had government take before tax deductions. The UTC and MUTC for each scenario were determined. Stochastic simulation using Monte Carlo sampling method of the uncertain variables and sensitivity analysis of the investment was also carried out. The UTC obtained for all the Scenarios was $18.78 per barrel. The modified unit technical cost (MUTC) for Scenario 1-3 were $18.78 per barrel, $22.09 per barrel and $23.66 per barrel. It was observed that the MUTC increases as the government take before tax deduction increases unlike the UTC. It was also observed that the contractor's net cash flow was negative when the oil price was the same value with the UTC for the models with government take before tax deduction. But when the oil price was the same value with the MUTC, the net cash flow of the contractor for all the models was zero. This shows that the MUTC is more accurate as a profitability indicator than the UTC because it determined the breakeven price of the investment. The internal rate of return (IRR), payout period and contractor's take obtained from the models also proved the accuracy of the MUTC as a profitability indicator.",0,0,0
Monte Carlo,Unit,"Ruschel, Augusto; Silva Dantas, Claudio Marcio; Mendes de Sousa, Fernando Jorge; Simao, Marina Leivas; Sudati Sagrilo, Luis Volnei; Percy, Joseir Gandra; Oliveira, Felipe Lima",Wellhead fatigue analysis considering the effect of wind-sea and swell waves by using Univariate Dimension Reduction Method,Wellhead fatigue; Wind-sea and swell induced fatigue; UDRM approach for fatigue assessment,,"In recent years, the observation of dynamic motions in wellhead structures during drilling operations turned wellhead fatigue into a great concern for the oil industry. As stated by DNV in its Recommended Practice E104 (DNVGL, 2018), the fatigue damage evaluation demands an accurate representation of environmental loads acting on the whole drilling structure, including rig, drilling riser and BOP/LMRP. In terms of computational costs, this representation can make the fatigue analysis very expensive. A high number of loading cases may be needed to take into account the statistical independence between environmental parameters, mainly when windsea and swell waves are taken into account. To solve this issue, this paper proposes the use of the Univariate Dimension Reduction Method (UDRM) to compute the fatigue damage in wellhead structures considering the effects of both types of waves. The main advantage of this procedure is that it replaces the solution of the fourfold integral associated to the problem by the solution of four one-dimensional integrals, which drastically reduces the number of numerical simulations required in the fatigue assessment. The method is applied to two study cases considering the environmental conditions of the Brazilian coast. In the first, the drilling unit is a semisubmersible platform, while in the second case a ship-based drilling unit is considered. The obtained results indicate a substantial reduction in computational costs without loss of accuracy of UDRM when compared to a Monte Carlo Simulation-based approach.",0,0,0
Monte Carlo,Determination,"Ogolo, Oghenerume",Modification of the unit technical cost equation for the accurate determination of the cost of producing a barrel of oil in relation to the Contractor's revenue,Unit technical cost; Modified unit technical cost; Economics; Profitability indicator,,"The unit technical cost (UTC) is the profitability indicator used in the oil and gas industry to determine the cost of producing a barrel of oil. The method used to calculate the UTC has certain limitation as it does not capture the entire cost burden borne by the contractor in respect to the revenue they generate from investments in the exploration and production of hydrocarbon. This is as a result of the front-end loaded nature of oil and gas Nations fiscal system. This research therefore modified the equation used to calculate the UTC and termed it as the modified UTC (MUTC). To determine the accuracy of the MUTC as a profitability indicator, a hypothetical oil field was assumed. Investment in the exploration and production of oil from this field was modelled using spreadsheet modeling technique. Three different petroleum economic models were built to capture the front-end loaded nature of a fiscal system. The base case model (Scenario 1) had no government take before tax deduction, while the other two scenarios had government take before tax deductions. The UTC and MUTC for each scenario were determined. Stochastic simulation using Monte Carlo sampling method of the uncertain variables and sensitivity analysis of the investment was also carried out. The UTC obtained for all the Scenarios was $18.78 per barrel. The modified unit technical cost (MUTC) for Scenario 1-3 were $18.78 per barrel, $22.09 per barrel and $23.66 per barrel. It was observed that the MUTC increases as the government take before tax deduction increases unlike the UTC. It was also observed that the contractor's net cash flow was negative when the oil price was the same value with the UTC for the models with government take before tax deduction. But when the oil price was the same value with the MUTC, the net cash flow of the contractor for all the models was zero. This shows that the MUTC is more accurate as a profitability indicator than the UTC because it determined the breakeven price of the investment. The internal rate of return (IRR), payout period and contractor's take obtained from the models also proved the accuracy of the MUTC as a profitability indicator.",0,0,0
Monte Carlo,Determination,"Liu, Xing; Jin, Yan; Lin, Botao",An efficient stimulated reservoir area (SRA) estimation method based on octree decomposition of microseismic events,Hydraulic fracturing; Microseismic monitoring; Stimulated reservoir volume; Stimulated reservoir area; Octree method; Monte Carlo method,FRACTURE; GEOMECHANICS; PROPAGATION; SYSTEMS; SHALE,"Fracture contact area is the critical factor determining post-treatment production after multi-stage hydraulic fracturing. At present, there are no effective methods for the estimation of the stimulated reservoir area (SRA) of the complex fracture network after stimulation. Conventional methods mostly focused on calculating stimulated reservoir volume (SRV) by using microseismic events directly or indirectly. However, since there is a large number of noise events in microseismic data that can't be removed completely, the SRV results often have huge errors and are inconsistent with practical well production. For this reason, we propose an efficient and robust SRA calculation method based on 3D octree decomposition. The method is able to effectively estimate SRA by generating a multi-level grid structure without reconstructing the fracture network. Through a large number of case simulations based on synthetic events generated by Monte Carlo method, it is found that our method could adapt to the estimation of SRA for different configurations. It could obtain reliable and robust results in the presence of noise events. Specifically, it is indicated that the maximum relative calculation error is less than 20% for mesoscale and large-scale fracture network. The error for small-scale fractures could be reduced below 30% combining with the error reduction approach put forward in this paper. The applicability of our method is also investigated through two horizontal well platforms. Compared with the conventional SRV method, it is found that SRA obtained by our method could better reflect the stimulation effects and is more consistent with real production. It could become a potential and effective index for stimulation evaluation and fracturing operation optimization.",0,0,1
Monte Carlo,Flow,"Costa, Beethoven G. dos S.; Jaculli, Marcelo A.; Mendes, Jose Ricardo P.; Colombo, Danilo",Evaluation of rock integrity during well drilling activities using reliability analysis,Well integrity; Rock reliability; Well safety; Kick tolerance,,"The main risk during the construction of oil wells is the possibility of uncontrolled hydrocarbon flow occurring from the well to the environment, commonly known as a blowout. After the Macondo accident, in the Gulf of Mexico, in 2010, there has been, in recent years, a significant increase in researches related to both well integrity and operational safety. A possible approach is to seek tools that can predict disastrous scenarios and support the decision making process. In this context, this work evaluates the reliability of the weakest rock in an open hole section, which is the formation immediately below the last settled casing shoe. Reliability, in this case, refers to the likelihood that the rock does not fracture during a possible kick or during drilling fluid circulation without a kick. The formulation of this problem involves addressing the inherent uncertainties, which may cause the failure of the ""rock"" barrier element. Modeling was performed by assigning probabilistic distributions to the parameters carrying uncertainties and by proposing two solutions. If all the uncertainties can be modeled using the normal distribution, it is possible to calculate the reliability analytically; meanwhile, if the variables are modeled using more than one type of distribution, an analytical solution may be hard to achieve and Monte Carlo simulations are preferred to obtain a numerical solution. The numerical solution does not require mean values and standard deviations of the output variables and becomes particularly useful when these characteristics are unknown. Therefore, this methodology evaluates the competence of the rock as a barrier element, enhancing operational safety and maintaining well integrity. The calculated reliability values can be used to assist in real-time drilling monitoring, from a rock integrity standpoint. The results of this methodology include the rock reliability as a function of the well depth, based on the current drilling phase. This includes the two aforementioned scenarios, with and without a kick.",0,0,0
Monte Carlo,Flow,"Ogolo, Oghenerume",Modification of the unit technical cost equation for the accurate determination of the cost of producing a barrel of oil in relation to the Contractor's revenue,Unit technical cost; Modified unit technical cost; Economics; Profitability indicator,,"The unit technical cost (UTC) is the profitability indicator used in the oil and gas industry to determine the cost of producing a barrel of oil. The method used to calculate the UTC has certain limitation as it does not capture the entire cost burden borne by the contractor in respect to the revenue they generate from investments in the exploration and production of hydrocarbon. This is as a result of the front-end loaded nature of oil and gas Nations fiscal system. This research therefore modified the equation used to calculate the UTC and termed it as the modified UTC (MUTC). To determine the accuracy of the MUTC as a profitability indicator, a hypothetical oil field was assumed. Investment in the exploration and production of oil from this field was modelled using spreadsheet modeling technique. Three different petroleum economic models were built to capture the front-end loaded nature of a fiscal system. The base case model (Scenario 1) had no government take before tax deduction, while the other two scenarios had government take before tax deductions. The UTC and MUTC for each scenario were determined. Stochastic simulation using Monte Carlo sampling method of the uncertain variables and sensitivity analysis of the investment was also carried out. The UTC obtained for all the Scenarios was $18.78 per barrel. The modified unit technical cost (MUTC) for Scenario 1-3 were $18.78 per barrel, $22.09 per barrel and $23.66 per barrel. It was observed that the MUTC increases as the government take before tax deduction increases unlike the UTC. It was also observed that the contractor's net cash flow was negative when the oil price was the same value with the UTC for the models with government take before tax deduction. But when the oil price was the same value with the MUTC, the net cash flow of the contractor for all the models was zero. This shows that the MUTC is more accurate as a profitability indicator than the UTC because it determined the breakeven price of the investment. The internal rate of return (IRR), payout period and contractor's take obtained from the models also proved the accuracy of the MUTC as a profitability indicator.",0,0,0
Monte Carlo,Produce,"Ogolo, Oghenerume",Modification of the unit technical cost equation for the accurate determination of the cost of producing a barrel of oil in relation to the Contractor's revenue,Unit technical cost; Modified unit technical cost; Economics; Profitability indicator,,"The unit technical cost (UTC) is the profitability indicator used in the oil and gas industry to determine the cost of producing a barrel of oil. The method used to calculate the UTC has certain limitation as it does not capture the entire cost burden borne by the contractor in respect to the revenue they generate from investments in the exploration and production of hydrocarbon. This is as a result of the front-end loaded nature of oil and gas Nations fiscal system. This research therefore modified the equation used to calculate the UTC and termed it as the modified UTC (MUTC). To determine the accuracy of the MUTC as a profitability indicator, a hypothetical oil field was assumed. Investment in the exploration and production of oil from this field was modelled using spreadsheet modeling technique. Three different petroleum economic models were built to capture the front-end loaded nature of a fiscal system. The base case model (Scenario 1) had no government take before tax deduction, while the other two scenarios had government take before tax deductions. The UTC and MUTC for each scenario were determined. Stochastic simulation using Monte Carlo sampling method of the uncertain variables and sensitivity analysis of the investment was also carried out. The UTC obtained for all the Scenarios was $18.78 per barrel. The modified unit technical cost (MUTC) for Scenario 1-3 were $18.78 per barrel, $22.09 per barrel and $23.66 per barrel. It was observed that the MUTC increases as the government take before tax deduction increases unlike the UTC. It was also observed that the contractor's net cash flow was negative when the oil price was the same value with the UTC for the models with government take before tax deduction. But when the oil price was the same value with the MUTC, the net cash flow of the contractor for all the models was zero. This shows that the MUTC is more accurate as a profitability indicator than the UTC because it determined the breakeven price of the investment. The internal rate of return (IRR), payout period and contractor's take obtained from the models also proved the accuracy of the MUTC as a profitability indicator.",0,0,0
Monte Carlo,Produce,"Andrade, GabrielM P.; Oechsler, Bruno F.; Coelho, Josiane S. C.; Fagundes, Flavia M.; Arouca, Fabio O.; Damasceno, Joao J. R.; Scheid, Claudia M.; Calcada, Luis A.",Evaluation of characteristic diameter on barite settling in drilling fluids by Monte Carlo method,Barite settling; Drilling fluids; Characteristic particle size; Optimization; Monte Carlo,,"Several researchers have discussed the settling behaviour of particulate materials because of the challenges and applications in different engineering fields. Particularly, settling of such weighting agents as barite, commonly added to drilling fluids, can cause problems in oil production, either on drilling processes or in production. Typically, sedimentation models consider a single value of particle size, which in this work, we refer to as characteristic diameter. This particle size can be chosen by statistical methods, such as the Sauter mean diameter, or it can be extracted directly from particle size distribution such as its mean, median, or mode. There are some conventions by how to choose the characteristic diameter; however, discarding the whole size variability from the particle size distribution is unwise. Regarding the literature, only a few works have, to the best of our knowledge, discussed the effects of this choice on the models' performance. This work then presents a new perspective on evaluating the uncertainty of the particle size distribution and choosing the best characteristic diameter, using a novel method based on Monte Carlo simulations. To evaluate the method, research team chose a barite settling model (recently published) for drilling fluids. Experimental data of barite concentration in batch settling test supported the Monte Carlo simulations. Five characteristic diameters were evaluated. Results showed different column heights have different characteristic diameters which differed from classical values such as Sauter's diameter by up to 200%, producing different model output variables. New particle size also affected estimation of remaining parameters and changed predicted properties such as media permeability by up to 90%. This work opens a discussion on how well-represented a particle size distribution is when researchers choose only a characteristic diameter is chosen without evaluating the whole distribution.",0,0,0
Monte Carlo,Samples,"Ogolo, Oghenerume",Modification of the unit technical cost equation for the accurate determination of the cost of producing a barrel of oil in relation to the Contractor's revenue,Unit technical cost; Modified unit technical cost; Economics; Profitability indicator,,"The unit technical cost (UTC) is the profitability indicator used in the oil and gas industry to determine the cost of producing a barrel of oil. The method used to calculate the UTC has certain limitation as it does not capture the entire cost burden borne by the contractor in respect to the revenue they generate from investments in the exploration and production of hydrocarbon. This is as a result of the front-end loaded nature of oil and gas Nations fiscal system. This research therefore modified the equation used to calculate the UTC and termed it as the modified UTC (MUTC). To determine the accuracy of the MUTC as a profitability indicator, a hypothetical oil field was assumed. Investment in the exploration and production of oil from this field was modelled using spreadsheet modeling technique. Three different petroleum economic models were built to capture the front-end loaded nature of a fiscal system. The base case model (Scenario 1) had no government take before tax deduction, while the other two scenarios had government take before tax deductions. The UTC and MUTC for each scenario were determined. Stochastic simulation using Monte Carlo sampling method of the uncertain variables and sensitivity analysis of the investment was also carried out. The UTC obtained for all the Scenarios was $18.78 per barrel. The modified unit technical cost (MUTC) for Scenario 1-3 were $18.78 per barrel, $22.09 per barrel and $23.66 per barrel. It was observed that the MUTC increases as the government take before tax deduction increases unlike the UTC. It was also observed that the contractor's net cash flow was negative when the oil price was the same value with the UTC for the models with government take before tax deduction. But when the oil price was the same value with the MUTC, the net cash flow of the contractor for all the models was zero. This shows that the MUTC is more accurate as a profitability indicator than the UTC because it determined the breakeven price of the investment. The internal rate of return (IRR), payout period and contractor's take obtained from the models also proved the accuracy of the MUTC as a profitability indicator.",0,0,0
Monte Carlo,Samples,"Yadav, Ashok; Nayak, Soumya Ranjan; Mondal, Samit",Agglomerative clustering to improve the resolution of pseudo well stochastic seismic inversion: A case study,"Reservoir characterization; Inversion; Rock Physics, Volume of Sand",CHAIN MONTE-CARLO; SIMULATION,"The Monte Carlo rejection and Monte Carlo Markov Chain methods are two common sampling techniques in Bayesian seismic inversion. Conventional methods of pseudo well stochastic seismic inversion for reservoir properties uses Monte Carlo rejection sampling of pseudo-wells to select those that best match seismic traces. The selected pseudo-wells do not influence the selection/rejection of subsequent pseudo-wells. The process requires a very large number of prior pseudo-wells to draw a reasonable outcome, which consumes a major part of the computation time. In conventional methods, the best-matched pseudo-wells often have dissimilarly shaped volume of shale logs, which can degrade the resolution of the outcome. Though Agglomerative clustering is well-known but the idea of grouping pseudo-wells based on similarly shaped volume of shale logs in pseudo well stochastic seismic inversion is unique. We propose an agglomerative clustering technique to group the prior pseudo-wells according to the shape of their volume of shale logs, before matching to seismic. The centroids of the pseudo-well clusters summarize the large number of prior pseudo-wells. The best-matched pseudo-well cluster centmid with seismic gives the most likely outcome while the two next best-matched cluster centroids give alternative results. The alternative results are useful to understand the uncertainty in the outcome. It has been observed that, the proposed method has reduced computation time (50-55% less than conventional pseudo well stochastic inversion). Meanwhile, the quantification of sand volume from the proposed method shows improvement over the conventional method. A comparison between the proposed and the conventional method has been shown on a synthetic wedge model and real seismic. In the wedge model (volume of sand is 0.65), the resultant volume of sand predicted in the modified method (0.7) is better than that predicted using the conventional method (0.8). The modified pseudo-well stochastic seismic inversion method has been applied on seismic data from deepwater Krishna-Godavari basin. The result shows an improvement in the characterization of thin shale layers within the reservoir.",0,0,0
Monte Carlo,Assuming,"Ogolo, Oghenerume",Modification of the unit technical cost equation for the accurate determination of the cost of producing a barrel of oil in relation to the Contractor's revenue,Unit technical cost; Modified unit technical cost; Economics; Profitability indicator,,"The unit technical cost (UTC) is the profitability indicator used in the oil and gas industry to determine the cost of producing a barrel of oil. The method used to calculate the UTC has certain limitation as it does not capture the entire cost burden borne by the contractor in respect to the revenue they generate from investments in the exploration and production of hydrocarbon. This is as a result of the front-end loaded nature of oil and gas Nations fiscal system. This research therefore modified the equation used to calculate the UTC and termed it as the modified UTC (MUTC). To determine the accuracy of the MUTC as a profitability indicator, a hypothetical oil field was assumed. Investment in the exploration and production of oil from this field was modelled using spreadsheet modeling technique. Three different petroleum economic models were built to capture the front-end loaded nature of a fiscal system. The base case model (Scenario 1) had no government take before tax deduction, while the other two scenarios had government take before tax deductions. The UTC and MUTC for each scenario were determined. Stochastic simulation using Monte Carlo sampling method of the uncertain variables and sensitivity analysis of the investment was also carried out. The UTC obtained for all the Scenarios was $18.78 per barrel. The modified unit technical cost (MUTC) for Scenario 1-3 were $18.78 per barrel, $22.09 per barrel and $23.66 per barrel. It was observed that the MUTC increases as the government take before tax deduction increases unlike the UTC. It was also observed that the contractor's net cash flow was negative when the oil price was the same value with the UTC for the models with government take before tax deduction. But when the oil price was the same value with the MUTC, the net cash flow of the contractor for all the models was zero. This shows that the MUTC is more accurate as a profitability indicator than the UTC because it determined the breakeven price of the investment. The internal rate of return (IRR), payout period and contractor's take obtained from the models also proved the accuracy of the MUTC as a profitability indicator.",0,0,0
Monte Carlo,Assuming,"Zhang, Jian; Li, Jingye; Chen, Xiaohong; Li, Yuanqiang",Geological structure-guided hybrid MCMC and Bayesian linearized inversion methodology,Seismic inversion; Plane wave destruction (PWD); Block coordinate descent (BCD); Acoustic impedance (AI); Uncertainty evaluation,,"Seismic inversion is a common method for hydrocarbon reservoir characterization, as it consists of a proven and effective approach to derive elastic properties from reflectivity seismic data. Markov Chain Monte Carlo (MCMC) based seismic inversion approach is a suitable choice to numerically evaluate the posterior uncertainties associated with the inverse solution without assuming linear forward operators, Gaussian, or generalized Gaussian prior models. However, the existing MCMC based seismic inversion approaches are mostly performed trace-bytrace, which means that the spatial coupling of model parameters is not considered. When the results of trace-bytrace based inversion are combined to generate a 2D profile, the final results will be laterally discontinuous. Moreover, the large dimension of the model space causes low convergence efficiency of MCMC-based seismic inversion. To overcome these issues, a geological structure-guided hybrid MCMC and Bayesian linearized inversion (BLI) methodology for seismic inversion is implemented. The geological structure information obtained using plane wave destruction (PWD) is incorporated to the MCMC based inversion algorithm in the form of dips yields more geologically meaningful results. The hybrid MCMC and BLI strategy, which takes advantage of BLI s high efficiency to provide initial configuration for MCMC, is used to improve the convergence of MCMC-based inversion. Additionally, the block coordinate descent (BCD) algorithm is introduced to replace the large-scale matrix solution in geological structure-guided, and consequently reduce memory consumption and time cost. This methodology is validated on a synthetic seismic dataset, as well as on a real case. It has proven to be a reliable approach to obtain acoustic impedance (AI) from post-stack seismic data in an efficient way. It also addresses the uncertainty related with the ill-posed characteristics of the inversion methodology itself.",0,0,1
Monte Carlo,Oil and Gas Industry,"Ogolo, Oghenerume",Modification of the unit technical cost equation for the accurate determination of the cost of producing a barrel of oil in relation to the Contractor's revenue,Unit technical cost; Modified unit technical cost; Economics; Profitability indicator,,"The unit technical cost (UTC) is the profitability indicator used in the oil and gas industry to determine the cost of producing a barrel of oil. The method used to calculate the UTC has certain limitation as it does not capture the entire cost burden borne by the contractor in respect to the revenue they generate from investments in the exploration and production of hydrocarbon. This is as a result of the front-end loaded nature of oil and gas Nations fiscal system. This research therefore modified the equation used to calculate the UTC and termed it as the modified UTC (MUTC). To determine the accuracy of the MUTC as a profitability indicator, a hypothetical oil field was assumed. Investment in the exploration and production of oil from this field was modelled using spreadsheet modeling technique. Three different petroleum economic models were built to capture the front-end loaded nature of a fiscal system. The base case model (Scenario 1) had no government take before tax deduction, while the other two scenarios had government take before tax deductions. The UTC and MUTC for each scenario were determined. Stochastic simulation using Monte Carlo sampling method of the uncertain variables and sensitivity analysis of the investment was also carried out. The UTC obtained for all the Scenarios was $18.78 per barrel. The modified unit technical cost (MUTC) for Scenario 1-3 were $18.78 per barrel, $22.09 per barrel and $23.66 per barrel. It was observed that the MUTC increases as the government take before tax deduction increases unlike the UTC. It was also observed that the contractor's net cash flow was negative when the oil price was the same value with the UTC for the models with government take before tax deduction. But when the oil price was the same value with the MUTC, the net cash flow of the contractor for all the models was zero. This shows that the MUTC is more accurate as a profitability indicator than the UTC because it determined the breakeven price of the investment. The internal rate of return (IRR), payout period and contractor's take obtained from the models also proved the accuracy of the MUTC as a profitability indicator.",0,0,0
Monte Carlo,Oil and Gas Industry,"Maior, Caio B. S.; Macedo, July B.; Lins, Isis D.; Moura, Marcio C.; Azevedo, Rafael, V; Santana, Joao M. M.; da Silva, Manoel F.; Magalhaes, Marcus V. C.",Bayesian prior distribution based on generic data and experts' opinion: A case study in the O&G industry,Informative prior distribution; Bayesian reliability; Technology development; Well equipment,REMAINING USEFUL LIFE; RELIABILITY; INFORMATION; FAILURE; SIMULATION; PSO,"Reliability estimation is an essential task to ensure predictability on the life of equipment installed in oil wells, allowing forecasting costs, planning maintenance, and estimating system availability. However, data may be rather scarce and/or expensive to obtain, especially for technologies under development in the Oil and Gas (O&G) industry. The information is frequently available in generic databases and expert opinions. In the Bayesian framework, the prior knowledge about a system's reliability is updated as a new field and/or test data are gathered. This paper proposes an approach that does not require direct elicitation of parameters to define informative prior distributions for the reliability function using fault tree analysis, expert's opinions, and/or generic data at the system level of equipment under development. Specifically, the method-of-moments and maximum-entropy are adopted to propagate downward the uncertainty from the system level through the failure modes until the basic events of the fault tree, weighted by the expert knowledge of the failure behavior. Then, in possession of all prior distributions of the basic events, the information may be propagated upward based on Monte Carlo simulation to update the system reliability distribution. Finally, we present a case study of the proposed methodology applied to a novel open-hole expandable packer, a completion equipment recently installed in a Brazilian oil field. The failure modes and failure causes are discussed, and, after expert elicitation, the definition of the informative prior distribution is achieved. Therefore, we estimate the reliability for a given time and assess if the novel equipment attains the company's risk target, taking O&G standards as reference.",0,0,1
Trajectory,Directional Drilling,"Gu, Yue; Gao, Deli; Diao, Binbin; Yang, Jin; Nie, Shuaishuai",Optimization design method of infill well trajectory with bypassing obstacles in the fractured area of shale gas reservoir,Shale gas infill well; Bypassing obstacles; Fractrued area; Vector algebra method; Optimization model,,"In the design of infill well trajectory in fractured area of shale gas reservoir, it is necessary to consider the problem how to bypass the fractured influence area of the old shale gas wells, as well as the problem of mutual interference between the different fractured sections during production. In this paper, the geometric model of the obstacles in fractured area of shale gas reservoir, which considers the trajectory error and fracturing effect, is established by vector algebra method. The trajectory type is classified according to positional relations among the obstacle, the directional line of initial point and target point. The trajectory optimization model for bypassing obstacles takes the minimum total well length as objective function, the safety distance to obstacle as one of the constraints. In addition, the geometric check method for judging whether there is interference between the different fractured sections is proposed based on the geometric obstacle model. Case studies have been carried out according to the field data from Fuling, and the results indicate that the trajectory optimization model in this paper can obtain the optimum trajectory to meet the needs for bypassing obstacle, minimum trajectory length and avoiding trial calculation. Besides, if the fracturing effect is ignored, the size of the obstacle will be significantly underestimated in fractured area of shale gas reservoir, which will result in drilling accidents. In sum, the obstacle model in this paper is more consistent with the situation of field fractured area drilling practice than that of the published model. This study will provide a more safer and briefer design method for optimizing the infill well trajectory in fractured area of shale gas reservoir, which is of great significance to the shale gas drilling design and drilling safety.",0,0,1
Trajectory,Directional Drilling,"Liu, Jianqiao; Lin, Yaqi; Yang, Jin; Yin, Qishuai",A robust and efficient method to geometrically calculate the minimum bit stick-out in a deepwater conductor jetting project,Deepwater; Conductor; Bit stick-out; Drill bit; Theoretical model; Numerical simulation experiment analysis,,"The length of the bit protruding from the running conductor assembly (i.e., bit stick-out), a key factor in deepwater drilling design, directly affects the efficiency of the injection process and the bearing safety of the conductor after installation. To improve the efficiency and safety of conductor installation, it is necessary to establish a reasonable theoretical model of the bit stick-out to provide a feasible scheme for field applications. In this study, geometric judgment criteria of the reasonable bit stick-out location are proposed that determine whether the diameter of the nozzle jet circle is smaller than that of the conductor. These judgment criteria are applied to obtain the reasonable position of the minimum bit stick-out for different diameters of conductors and tricone bits. According to these judgment criteria, we propose a mathematical model of the minimum bit stickout during deepwater conductor jetting, which considers the influence of the heterogeneity in the nozzle space. Through theoretical analysis and experimental research, combined with on-site cases, the results indicate that if the diameter of the nozzle jet circle is larger than that of the conductor, the reasonable bit stick-out location occurs where the upper boundary of the nozzle jet beam is tangential to the inner boundary of the lower end of the conductor. Conversely, the reasonable bit stick-out location occurs where the jet beam originating from the nozzle can reach the intersection of the jet trajectory and the curved surface formed by the main and secondary cones of the cone bit at the bottom of the well. A numerical simulation study reveals that when the bit stick-out is greater than 150 mm, the hole can be enlarged during the jetting process, thus increasing the installation depth of the conductor and affecting the stability of the conductor. In addition, the models established in this work are applied in the field. In 12 wells, the average value of the calculated results is 114.76 mm, which is close to the lower limit of the interval. Overall, the research results provide a more accurate theoretical basis for bit stick-out design in deepwater conductor jetting projects. This study can maximize the jetting depth, considering that the size of the created hole optimally matches the casing size to achieve wellbore stability. In addition, the developed procedure based on the proposed mathematical model can be applied more conveniently to different combinations of conductor and bit sizes in the field.",0,0,1
Trajectory,Directional Drilling,"Tian, Haiping; Ren, Haitao; Song, Dongdong; Yang, Yan",Research on cutting track and working load of directional drilling PDC bit,PDC bit; Directional drilling; Motion trajectory; Working load; Cross cutting,,"Polycrystalline diamond compact bit directional drilling technology has proven to be an important means to effectively improve drilling efficiency and save drilling costs. Under the directional drilling condition of PDC bit, due to the existence of screw angle or offset mechanism, the center axis of the bit deviates from the center of the borehole, and the cutting teeth of the bit do complex alternating trajectory cutting motion at the bottomhole and the trajectory lines of the cutting teeth themselves intersect in space. (1) The kinematics analysis of directional drilling PDC bit under different working conditions was carried out, including motion analysis at the stage of sliding steering deflection and motion analysis at the stage of composite steering drilling. The kinematics equation of PDC bit under sliding steering deflection and motion space equation of PDC bit cutters at the stage of composite steering drilling were deduced respectively. (2) By establishing the calculation model of cross Angle of cutters under directional drilling conditions, the influences of transmission ratio, tooth placement, offset and deflection Angle on the cross angle are analyzed. The movement law of PDC cutters and the bottom hole morphology formed by bit are studied under directional drilling conditions. (3) Based on the digital simulation system of PDC bit rock breaking, the cutting load under the state of alternating trajectory was studied. On this basis, the cutting mechanics model of PDC bit cutters in directional drilling was established. At the same time, the accuracy of simulation analysis was verified by laboratory unit experiments. It is considered that PDC cutters can form alternate cutting path in directional drilling, which can easily invade rock and improve mechanical efficiency. The larger the intersecting angle of the cutting teeth, the more likely the rock is to form a through crack and then be broken. When the intersecting angle is 90 degrees, the average energy consumption of rock breaking in cross cutting is reduced by about 32.9% compared with parallel cutting. The research results have improved the understanding of the rock breaking mechanism of PDC bit directional drilling, provided a new technical means for bit performance analysis and have also provided a reference for the design of new personalized bits under the discussed working conditions.",0,0,2
Trajectory,Directional Drilling,Cao Wenke; Liu Wei; Liu Hailong; Lin Hai,Effect of formation strength anisotropy on wellbore shear failure in bedding shale,Jointed material; Bedding shale; Wellbore stability; FDM,BOREHOLE STABILITY; ROCK; PERMEABILITY; CRITERION; MODEL,"The shale gas/oil is playing an important role in the current energy resources. However, the wellbore instability problems bring a high risk to drilling engineering especially in the formation with bedding planes. A normal wellbore stability analysis approach is based on elasticity, which is not enough to recognize the mechanisms. In this paper, the poroelasticity was adopted to present the hydro-mechanical coupling effect in shale formation, meanwhile, the permeability anisotropy which could affect the effective stresses around the well was considered. A three-dimensional finite difference model was developed to simulate arbitrary directional well in shale by the coordinate transformation method. The jointed material model was proposed to character the strength anisotropy and plastic behavior of bedding shale. Additionally, the effects of well trajectory, bedding plane orientation and mud weight on shale wellbore stability were discussed, thus some implications for improving wellbore stability in bedding shale formation were obtained from the proposed model.",0,0,3
Trajectory,Well Planning,"Liu, Haoge; Gjersvik, Tor Berge; Faanes, Audun",Subsea field layout optimization (part III) --- the location-allocation problem of drilling sites,Field layout optimization; Location-allocation; BLP; 3D dubins curve,OFFSHORE; INVESTMENT; DESIGN,"This study proposes an efficient method to optimize the subsea field layout with the aim of minimizing the subsea field development cost, based on the two methods introduced in Part I and Part II for solving the well trajectory planning problem and the location-allocation problem, i.e., 3D Dubins Curve method and Binary Linear Programming (BLP) method, respectively. The most complex part in subsea field layout optimization is essentially a location-allocation problem of drilling sites embedded with the well trajectory optimization. The full process of our method is clearly summarized in a flowchart. Abundant case studies with comparison to the existing results demonstrate the optimality and the flexibility of our method to solve practical subsea field layout optimization problems. In the cases studies, we also reveal how different user-defined cost items affect the optimal field layout. Details of implementing our method for a better performance is also discussed. This work is the third of a series of papers which systematically introduce an efficient method for subsea field layout optimization to minimize the development cost.",0,0,0
Trajectory,Well Planning,"Kristoffersen, Brage S.; Bellout, Mathias C.; Silva, Thiago L.; Berg, Carl F.",Reduced well path parameterization for optimization problems through machine learning,Machine learning; Well placement; Derivative-free optimization; Well parameterization,FIELD-DEVELOPMENT OPTIMIZATION; PARTICLE SWARM OPTIMIZATION; PARALLEL PATTERN SEARCH; PLACEMENT OPTIMIZATION; ALGORITHM,"In this work we apply a recently developed machine learning routine for automatic well planning to simplify well parameterization in reservoir simulation models. This reduced-order parameterization is shown to be beneficial for well placement optimization, both in terms of convergence and final well configuration. The proposed machine learning routine maps trajectories that honor predefined engineering requirements by exploiting spatial information about the reservoir and prior domain-knowledge about the problem. In this paper, the well planner creates wells that traverse high-permeable parts of the reservoir, thereby increasing well productivity. Previous work found that small changes to the start- and end-points of the well had limited impact on most of the resulting well trajectories, since development of trajectories is chiefly determined by local information around the digital drill bit. In particular, changes in the depth component of the start- and end-points had limited impact on the trajectory away from the end-points. Based on these observations, this work reduces well parameterization to only include horizontal coordinates. The main assumption is that the perforated part of the well always enters the reservoir at the upper reservoir boundary, while the stopping criteria in the machine learning routine is a perforation length only. This formulation reduces the number of decision variables from six to four coordinates for each well. The resulting reduced search space enables a more efficient exploration effort at the cost of less freedom over the start and end points of the well path. However, we show that the highly-refined well trajectory developed by the well planning routine is robust and compensates for fewer degrees of freedom at the overarching parameterization. This robustness is tested by investigating the effect of different start locations on the automatic well planning routines. Moreover, the effect of the reduced well parameterization for well placement optimization is explored. Two optimization scenarios using four different optimizations algorithms are presented. Results show the implementation of the reduced well parameterization for optimization purposes consistently produces high quality solutions.",0,0,1
Trajectory,Well Planning,"Kim, Jongkook",Petrophysical/geophysical approaches to identify ISIP variability in the Eagle Ford shale,Geomechanics; ISIP; MWD Gamma ray; Eagle ford; Seismic inversion,DEFORMATION; ROCKS,"Understanding geomechanical properties is essential for an optimal completion strategy that ensures commercial productivity in shale reservoirs with ultra-low permeability. This study provides details to identify the variability of Instantaneous Shut-In Pressure (ISIP) in multidisciplinary approaches using petrophysical and geophysical data. ISIP is one of the input data required for well completion design. Operators commonly ignore the variability of ISIP and use uniform geomechanical assumptions due to cost and time constraints. In the case study, the variability of ISIP was observed up to 30 % in a single horizontal well, which could lower the efficiency of hydraulic fracturing with uniform geomechanical assumptions along a horizontal well trajectory. We propose practical approaches to identify the variability of ISIP from a case study in the Eagle Ford shale. MWD (Measurement While Drilling) Gamma Ray log, which is commonly acquired for a geosteering purpose, was utilized to prove its correlation with actual ISIP data gained at frac-stages in horizontal production wells. Correlation between ISIP and microseismic data was analyzed to identify the integrated relationship among the variability of Gamma Ray, ISIP, and hydraulically-induced fracture. In addition, practical approaches using a series of seismic inversion and attribute data were proposed to help identify geological variabilities affecting ISIP. This study was designed to provide operators hands-on approaches to capturing the variability of ISIP under limited data accessibility. We suggest multifunctional ways using the basic datasets commonly available at field sites. It can be applied to mitigate risks concerning well planning, drilling, and completion design in where operators face frequent challenges from geomechanical heterogeneity in global shale plays.",0,0,2
Trajectory,Shale Gas,"Gu, Yue; Gao, Deli; Diao, Binbin; Yang, Jin; Nie, Shuaishuai",Optimization design method of infill well trajectory with bypassing obstacles in the fractured area of shale gas reservoir,Shale gas infill well; Bypassing obstacles; Fractrued area; Vector algebra method; Optimization model,,"In the design of infill well trajectory in fractured area of shale gas reservoir, it is necessary to consider the problem how to bypass the fractured influence area of the old shale gas wells, as well as the problem of mutual interference between the different fractured sections during production. In this paper, the geometric model of the obstacles in fractured area of shale gas reservoir, which considers the trajectory error and fracturing effect, is established by vector algebra method. The trajectory type is classified according to positional relations among the obstacle, the directional line of initial point and target point. The trajectory optimization model for bypassing obstacles takes the minimum total well length as objective function, the safety distance to obstacle as one of the constraints. In addition, the geometric check method for judging whether there is interference between the different fractured sections is proposed based on the geometric obstacle model. Case studies have been carried out according to the field data from Fuling, and the results indicate that the trajectory optimization model in this paper can obtain the optimum trajectory to meet the needs for bypassing obstacle, minimum trajectory length and avoiding trial calculation. Besides, if the fracturing effect is ignored, the size of the obstacle will be significantly underestimated in fractured area of shale gas reservoir, which will result in drilling accidents. In sum, the obstacle model in this paper is more consistent with the situation of field fractured area drilling practice than that of the published model. This study will provide a more safer and briefer design method for optimizing the infill well trajectory in fractured area of shale gas reservoir, which is of great significance to the shale gas drilling design and drilling safety.",0,0,1
Trajectory,Shale Gas,"Hu, Haixiang; Xing, Yanfei; Wang, Bin; Lv, Yinghui; Zhang, Qiang; Li, Xiaoyong",CH4 diffusion in intra-pore of montmorillonite: From self-diffusion to fick-diffusion,Shale gas; Diffusion; Fick diffusivity; Clay; Molecular simulation,SHALE-GAS-RESERVOIRS; MONTE-CARLO-SIMULATION; MOLECULAR-DYNAMICS; APPARENT PERMEABILITY; TRANSPORT-PROPERTIES; METHANE ADSORPTION; ELEVATED PRESSURES; CLAY-MINERALS; MODEL; FLOW,"Given the low permeability of clay (the main component of shale), diffusion is the main method for transport of methane in shale. Diffusion is a slower process than flow and permeation. Therefore, diffusion is a rate-controlling step during shale gas extraction. Diffusion of CH4 in clay mineral with water is investigated in detail. Dependences of self-diffusivity, Maxwell-Stefan (M-S) diffusivity and Fick diffusivity on various geological conditions are discussed. The practically important Fick diffusivity of methane in montmorillonite is calculated through molecular dynamics for the first time. Results show that self-diffusivity conventionally increases with temperature and its dependence on methane concentration follows the similar behavior of dependence on temperature. However, self-diffusivity displays a maximum at the water concentration of 2.5 molecules/unit-cell. The displacement distribution of CH4 calculated from molecule trajectory follows a logarithmic normal distribution, whose mean reaches the maximum at the same water concentration, resulting in the above-mentioned unusual behavior of self-diffusivity. M-S and Fick diffusivities go up with CH4 concentration and temperature while peak at the water content of 3.125 molecules/unit-cell. On the basis of self-diffusivity and M-S diffusivity, diffusion correlation parameter, D-ii, among methane molecules is computed. The diffusion correlation increases with methane concentration, water content, and temperature. Consequently, high methane concentration, temperature and moderately increasing water content result in fast methane diffusion, whereas excessively high water concentration hinders methane diffusion.",0,0,2
Trajectory,Wellbore Stability,"Liu, Jianqiao; Lin, Yaqi; Yang, Jin; Yin, Qishuai",A robust and efficient method to geometrically calculate the minimum bit stick-out in a deepwater conductor jetting project,Deepwater; Conductor; Bit stick-out; Drill bit; Theoretical model; Numerical simulation experiment analysis,,"The length of the bit protruding from the running conductor assembly (i.e., bit stick-out), a key factor in deepwater drilling design, directly affects the efficiency of the injection process and the bearing safety of the conductor after installation. To improve the efficiency and safety of conductor installation, it is necessary to establish a reasonable theoretical model of the bit stick-out to provide a feasible scheme for field applications. In this study, geometric judgment criteria of the reasonable bit stick-out location are proposed that determine whether the diameter of the nozzle jet circle is smaller than that of the conductor. These judgment criteria are applied to obtain the reasonable position of the minimum bit stick-out for different diameters of conductors and tricone bits. According to these judgment criteria, we propose a mathematical model of the minimum bit stickout during deepwater conductor jetting, which considers the influence of the heterogeneity in the nozzle space. Through theoretical analysis and experimental research, combined with on-site cases, the results indicate that if the diameter of the nozzle jet circle is larger than that of the conductor, the reasonable bit stick-out location occurs where the upper boundary of the nozzle jet beam is tangential to the inner boundary of the lower end of the conductor. Conversely, the reasonable bit stick-out location occurs where the jet beam originating from the nozzle can reach the intersection of the jet trajectory and the curved surface formed by the main and secondary cones of the cone bit at the bottom of the well. A numerical simulation study reveals that when the bit stick-out is greater than 150 mm, the hole can be enlarged during the jetting process, thus increasing the installation depth of the conductor and affecting the stability of the conductor. In addition, the models established in this work are applied in the field. In 12 wells, the average value of the calculated results is 114.76 mm, which is close to the lower limit of the interval. Overall, the research results provide a more accurate theoretical basis for bit stick-out design in deepwater conductor jetting projects. This study can maximize the jetting depth, considering that the size of the created hole optimally matches the casing size to achieve wellbore stability. In addition, the developed procedure based on the proposed mathematical model can be applied more conveniently to different combinations of conductor and bit sizes in the field.",0,0,1
Trajectory,Wellbore Stability,Cao Wenke; Liu Wei; Liu Hailong; Lin Hai,Effect of formation strength anisotropy on wellbore shear failure in bedding shale,Jointed material; Bedding shale; Wellbore stability; FDM,BOREHOLE STABILITY; ROCK; PERMEABILITY; CRITERION; MODEL,"The shale gas/oil is playing an important role in the current energy resources. However, the wellbore instability problems bring a high risk to drilling engineering especially in the formation with bedding planes. A normal wellbore stability analysis approach is based on elasticity, which is not enough to recognize the mechanisms. In this paper, the poroelasticity was adopted to present the hydro-mechanical coupling effect in shale formation, meanwhile, the permeability anisotropy which could affect the effective stresses around the well was considered. A three-dimensional finite difference model was developed to simulate arbitrary directional well in shale by the coordinate transformation method. The jointed material model was proposed to character the strength anisotropy and plastic behavior of bedding shale. Additionally, the effects of well trajectory, bedding plane orientation and mud weight on shale wellbore stability were discussed, thus some implications for improving wellbore stability in bedding shale formation were obtained from the proposed model.",0,0,3
Trajectory,Oil Production,"Teigland, Andreas; Dale, Stein Inge; Sangesland, Sigbjorn; Brechan, Bjorn",A generalized empirical expression for the collapse of worn tubulars with a crescent-shaped wear groove under combined loads,Casing wear; Casing collapse; Well integrity; Finite element method,STRENGTH,"As a large proportion of easily recoverable global hydrocarbon reserves is extracted and fields in operation are maturing, the oil and gas industry requires new methods of ensuring well integrity. Production of the remaining reserves may involve, for instance, extended-reach wells, multilateral wellbores, long horizontal sections and highly deviated trajectories. Moreover, wells in mature fields are being used to increase recovery through sidetracking. Casing wear has a significant influence on the well integrity in such operations and the ability to assess its effects is crucial, both in terms of its impact on health, safety and environment, and in terms of enabling cost efficiency. This article utilizes the Finite Element Method (FEM) to analyze the stress distribution in worn tubulars with a crescent-shaped wear groove under external pressure. A model for tubular collapse is proposed using generalized empirical expressions for stress concentration factors in worn tubulars. The generalized expressions are based on 640 finite element analyses of different geometries designed to represent typical dimensions used in the oil and gas industry. Comparisons with experimental data and existing models demonstrate improvement in both accuracy and precision using the developed approach.",0,0,1
Trajectory,Oil Production,"Ado, Muhammad Rabiu",Comparisons of predictive ability of THAI in situ combustion process models with pre-defined fuel against that having fuel deposited based on Arrhenius kinetics parameters,In situ combustion (ISC); Enhanced oil recovery (EOR); Heavy oil; bitumen; tar sand; Reservoir simulation; Toe-to-heel air injection (THAI); Chemical kinetics,HEAVY OIL-RECOVERY; SIMULATION; STABILITY,"Toe-to-heel air injection (THAI) is an in situ thermal-enhanced oil upgrading and recovery technology that makes use of a horizontal producer well for mobilised partially upgraded oil production to the surface. To design operation of the THAI process requires up-scaling lab-scale numerical model to field-scale reservoir numerical model. There are a number of up-scaling methods that were developed. However, these previous up-scaling methods only concentrated on the qualitative nature of the physicochemical processes. Furthermore, these methods have deficiencies ranging from assumption of 100% oxygen utilisation, failing to compare oil production rates for up-scaled reservoir models with and without fuel pre-defined, not reporting on the dynamics inside the reservoirs with and without fuel pre-defined, etc. As a result, this work provided in depth comparative studies of both the qualitative and quantitative physicochemical processes in numerical models containing Arrhenius-based coke deposition thermal cracking reaction (i.e. model A) and that having pre-defined fuel concentration (i.e. model F) as an initial parameter respectively. It is found that oil production started earlier in model A compared to in model F even though they have approximately similar trajectories. It is shown that by the end of the combustion period, oil recovery of 28.5% OOIP is achieved in model F which is greater than that in model A by an additional of 4.8% OOIP. It is found that the peak temperature, which indicates how healthy the combustion is at a single point only at different times, is generally considerably higher in model A than that in model F. It is further discovered that in some cases the combustion at all points might be stable and rigorous but in other cases the combustion might not be stable and rigorous at all points thereby implying that the peak temperature alone does not give the measure of the efficiency and spread of the combustion front. It is shown for the first time that pre-defining fuel concentration throughout the reservoir as is done in model F resulted in faster downward advancement and expansion of the combustion front compared to in the reservoir where the fuel is deposited based on the Arrhenius kinetics parameters (i.e. like in model A). It is also discovered that higher areal sweep of the reservoir is achieved in model F when compared to that achieved in model A. Overall, it then follows that higher volume of the reservoir of model F is combustion-swept, heat-affected, and oil-depleted compared to that in model A. These findings explain the reason why more oil is produced during the combustion period in model F than in model A. Conclusively, this first-of-a-kind study shows that pre-defining the fuel has no effect on the qualitative nature of the physicochemical processes, but has considerable influence on the quantitative parameters such as the rate of and cumulative oil production, peak temperature, areal and volumetric sweeps by the combustion zone, size of the oil-depleted zone, and size of the heat-affect zone.",0,0,2
Trajectory,Angle,"Jia, Haibo; Ji, Hancheng; Yu, Jifeng",Shoreline trajectory and stratal stacking patterns: Relation to sediment partitioning and types of deep-lacustrine deposits,Shoreline trajectory; Stratal stacking pattern; Sediment partitioning; Deep-lacustrine deposits; Northwestern junggar basin,SHELF-EDGE TRAJECTORIES; JUNGGAR BASIN; SEQUENCE STRATIGRAPHY; MARGIN; MODEL; RIVER; CRITERIA; CHINA; SANDS; GULF,"This study utilizes drilling data to investigate shoreline trajectory, associated stratal stacking patterns and their relationships to sediment partitioning within the Lower Triassic in the Mahu Sag, northwestern Junggar Basin. Accretionary transgression occurred with changing of shoreline trajectory, sediment partition and basin-margin morphology. Two main types of shoreline trajectory and their associated stratal stacking patterns were recognized: (1) slightly rising trajectory, which has low trajectory angle (0.065 degrees-0.072 degrees) and is associated with retrogradational to aggradational back-stepping stacking patterns with low slope relief, and (2) moderately rising trajectory, which has relatively higher trajectory angle (0.09 degrees-0.27 degrees) and is associated with aggradational to retrogradational stacking patterns with moderate slope relief. The rising shoreline trajectory is associated with a fan-delta system with facies belts that migrate landward and are fining-upward, which is characterized by thick plain and thin front architecture. In vertical, the ascending trajectory developed with upward decreasing of sediment grain-size, muddy matrix changed to sandy matrix and even changed to clast supported in conglomerates. In planar, shoreline trajectory angle variations exist associated with different delta-front processes and different prodelta/deep-lacustrine deposits. Shoreline trajectory angle variations generated by sediment partition represents the relations between aggradation and retrogradation which determines the basin-margin growth pattern and morphology. It also indicates the vertical succession of basin-margin deposits and the preservation potential of deposits generated in various depositional environments. The results of this study show that shoreline trajectory could be a good indicator for basin-margin process and reservoir interpretation.",0,0,1
Trajectory,Angle,"Tian, Haiping; Ren, Haitao; Song, Dongdong; Yang, Yan",Research on cutting track and working load of directional drilling PDC bit,PDC bit; Directional drilling; Motion trajectory; Working load; Cross cutting,,"Polycrystalline diamond compact bit directional drilling technology has proven to be an important means to effectively improve drilling efficiency and save drilling costs. Under the directional drilling condition of PDC bit, due to the existence of screw angle or offset mechanism, the center axis of the bit deviates from the center of the borehole, and the cutting teeth of the bit do complex alternating trajectory cutting motion at the bottomhole and the trajectory lines of the cutting teeth themselves intersect in space. (1) The kinematics analysis of directional drilling PDC bit under different working conditions was carried out, including motion analysis at the stage of sliding steering deflection and motion analysis at the stage of composite steering drilling. The kinematics equation of PDC bit under sliding steering deflection and motion space equation of PDC bit cutters at the stage of composite steering drilling were deduced respectively. (2) By establishing the calculation model of cross Angle of cutters under directional drilling conditions, the influences of transmission ratio, tooth placement, offset and deflection Angle on the cross angle are analyzed. The movement law of PDC cutters and the bottom hole morphology formed by bit are studied under directional drilling conditions. (3) Based on the digital simulation system of PDC bit rock breaking, the cutting load under the state of alternating trajectory was studied. On this basis, the cutting mechanics model of PDC bit cutters in directional drilling was established. At the same time, the accuracy of simulation analysis was verified by laboratory unit experiments. It is considered that PDC cutters can form alternate cutting path in directional drilling, which can easily invade rock and improve mechanical efficiency. The larger the intersecting angle of the cutting teeth, the more likely the rock is to form a through crack and then be broken. When the intersecting angle is 90 degrees, the average energy consumption of rock breaking in cross cutting is reduced by about 32.9% compared with parallel cutting. The research results have improved the understanding of the rock breaking mechanism of PDC bit directional drilling, provided a new technical means for bit performance analysis and have also provided a reference for the design of new personalized bits under the discussed working conditions.",0,0,2
Trajectory,Algorithm,"Kristoffersen, Brage S.; Bellout, Mathias C.; Silva, Thiago L.; Berg, Carl F.",Reduced well path parameterization for optimization problems through machine learning,Machine learning; Well placement; Derivative-free optimization; Well parameterization,FIELD-DEVELOPMENT OPTIMIZATION; PARTICLE SWARM OPTIMIZATION; PARALLEL PATTERN SEARCH; PLACEMENT OPTIMIZATION; ALGORITHM,"In this work we apply a recently developed machine learning routine for automatic well planning to simplify well parameterization in reservoir simulation models. This reduced-order parameterization is shown to be beneficial for well placement optimization, both in terms of convergence and final well configuration. The proposed machine learning routine maps trajectories that honor predefined engineering requirements by exploiting spatial information about the reservoir and prior domain-knowledge about the problem. In this paper, the well planner creates wells that traverse high-permeable parts of the reservoir, thereby increasing well productivity. Previous work found that small changes to the start- and end-points of the well had limited impact on most of the resulting well trajectories, since development of trajectories is chiefly determined by local information around the digital drill bit. In particular, changes in the depth component of the start- and end-points had limited impact on the trajectory away from the end-points. Based on these observations, this work reduces well parameterization to only include horizontal coordinates. The main assumption is that the perforated part of the well always enters the reservoir at the upper reservoir boundary, while the stopping criteria in the machine learning routine is a perforation length only. This formulation reduces the number of decision variables from six to four coordinates for each well. The resulting reduced search space enables a more efficient exploration effort at the cost of less freedom over the start and end points of the well path. However, we show that the highly-refined well trajectory developed by the well planning routine is robust and compensates for fewer degrees of freedom at the overarching parameterization. This robustness is tested by investigating the effect of different start locations on the automatic well planning routines. Moreover, the effect of the reduced well parameterization for well placement optimization is explored. Two optimization scenarios using four different optimizations algorithms are presented. Results show the implementation of the reduced well parameterization for optimization purposes consistently produces high quality solutions.",0,0,1
Trajectory,Algorithm,"Li, Jingzhe; Sun, Zhifeng; Ren, Huaiqiang; Gong, Liang; Li, Tanglu; Du, Dongxing",Magnetic random walk algorithm and its application in the distributary channel system reservoir modeling,Distributary channel system; Reservoir description; Magnetic random walk; Reservoir modeling; Shengtuo oilfield,DELTA,"Random walk algorithms have unique advantages in reservoir modelling of distributary channel systems (DCS). However, the existing random walk algorithms often face several shortcomings, and typically do not perform adequately in complex scenarios. To overcome this problem, this paper introduces our recent development and application of magnetic random walk algorithm. The algorithm absorbs the concept of attraction and repulsion in the magnetic field and allows the walking seeds to wander randomly in a magnetic field composed of ""channel well"" observations and ""non-channel well"" observations, based on magnetic force. After post-processing of the walking trajectories, a DCS reservoir can be reconstructed. In a case study, the magnetic random walk algorithm efficiently completed the reservoir modelling, and parallels the manually drawn version completed by experienced geologists. This algorithm can effectively overcome several of the shortcomings of the existing methods and reduce manpower to a great extent in solving redundant work, which has a great application prospect.",0,0,2
Capillary Pressure,Water Saturation,"Tavakoli, Vahid; Hassani, Danial; Rahimpour-Bonab, Hossain; Mondak, Alireza","How petrophysical heterogeneity controls the saturation calculations in carbonates, the Barremian-Aptian of the central Persian Gulf",Tight carbonate reservoir; Water saturation; Archie equation; Archie coefficients; Heterogeneity,CAPILLARY-PRESSURE CURVES; SEQUENCE STRATIGRAPHY; CEMENTATION FACTOR; ARCHIES EXPONENTS; DARIYAN FORMATION; FLOW UNITS; RESERVOIR; EXAMPLE; CLASSIFICATION; PERMEABILITY,"Water saturation calculations are among the most important aspects of reservoir characterization. Despite this importance, the effects of these calculations on the resulted oil in place remain unclear. Extreme heterogeneity in most of the carbonate reservoirs strongly affects the coefficients of the Archie equation and resulted water saturation. Therefore, a practical method to evaluate and manage the heterogeneity of such reservoirs, greatly improves the reliability of the final results. In this study, porosity, permeability, thin sections data, well logs and saturation tests of Barremian-Aptian carbonate Dariyan Formation in the central Persian Gulf have been used. Both core and reservoir scale techniques including flow zone indicator, Winland R-35, electrofacies and stratigraphically modified Lorenz plot were used to evaluate the heterogeneity. Archie coefficients were arranged in different rock types. Results show that flow zone indicator is the most accurate technique to manage the heterogeneity of the reservoir with higher R-2 value between porosity and permeability. The cementation factor was measured for each unit and the amounts of water saturation was calculated using deterministic analysis. Water saturation also calculated with the constant coefficients, which are routinely used in formation evaluation. The average S-w amount for constant Archie coefficients method was determined as 0.62, whereas it is 0.73, 0.80, 0.70, and 0.77 in flow zone indicator method, Winland R-35 technique, stratigraphically modified Lorenz plot and electrofacies determination, respectively. The results demonstrate that calculating water saturation with constant Archie coefficients leads to slightly lower water saturation values, resulting in higher oil saturations and overestimating the oil in place.",0,0,0
Capillary Pressure,Water Saturation,"Capotosto, Anastasia; Lopes, Bruna de Carvalho Faria Lima; Tarantino, Alessandro",Proof-of-concept for a probe to measure pore water pressure in oil-water saturated porous rock,Hydrophilic probe; Pore-water pressure; Hydrocarbon reservoir; Porous rock,CAPILLARY-PRESSURE; HYDROCARBON,"The identification of the Oil/Water Contact (OWC) in a hydrocarbon reservoir is crucial for the determination of its volume and it is also important for detailed petrophysical calculations. Estimation of the OWC requires the determination of the Free Water Level (FWL). Routine practice in the oil and gas industry involves drilling multiple discovery wells since the undulation of the rock layers confining the hydrocarbon reservoir does not generally enable a single discovery well to intercept the water phase. Well drilling is expensive and industry looks forward to approaches to reduce the number of wells required for estimation of the OWC. In this context, this paper presents the proof-of-concept for a probe to measure pore water pressure in oil-water saturated porous rock. This would allow predicting the depth of the FWL in hydrocarbon reservoirs even if the single discovery well does not go through the OWC. This probe could significantly improve the appraisal process and guide the drilling campaigns, saving time, money and reducing the environmental impact of hydrocarbon search. The probe prototype was validated at laboratory scale via measurements of water pressure in core plugs saturated with water and oil. Mock-up tests on sandstone core plugs have shown that the probe can successfully measure water pressure in samples saturated with water and oil as long as the water phase is continuous in the pore space. The paper has therefore provided a proof-of-concept for a technology that can now be moved to the next readiness level.",0,0,0
Capillary Pressure,Water Saturation,"Almutairi, Abdulmajeed; Othman, Faisal; Ge, Jiachao; Le-Hussain, Furqan",Modified Johnson-Bossler-Naumann method to incorporate capillary pressure boundary conditions in drainage relative permeability estimation,Capillary pressure; Outlet boundary; Drainage relative permeability; Unsteady-state,COREFLOOD; FLOW,"A proposed modification of the Johnson-Bossler-Naumann (JBN) method incorporates capillary pressure at the inlet and outlet of a rock sample. The experimental runs are performed on Berea and Obernkriechner sandstone rock samples. Fluid is injected into Berea rock at capillary to viscous ratios 0.05, 0.1, 0.5, and 1 and into Obernkriechner rock at capillary to viscous ratios 0.05 and 0.25. Rock samples are initially saturated with 20 g/l NaCl water. The experimental observations are analyzed using classical JBN and our modified JBN. The latter's relative permeability curves are found to closely match those derived by applying history matching to a numerical model. This indicates that modified JBN can be used to provide an initial guess for history matching. We also show that accurate estimates of threshold capillary pressure are crucial to obtaining accurate oil relative permeability estimates. In contrast to those derived from the JBN method, modified JBN relative permeabilities are independent of capillary to viscous ratio or injection rate.",0,0,0
Capillary Pressure,Porous Media,"Ratnakar, Ram R.; Dindoruk, Birol",Transient measurement and modeling of integrated capillary viscometer for live oils at high temperatures with volumetric constraints,Capillary viscometer; Integrated viscosity experiment; Modeling fluid flow; Hagen-Poiseuille equation; Live and dead oils; High temperature high pressure (HTHP) studies,HEAVY-OIL; VISCOSITY CORRELATION; PREDICTION; BITUMEN; DEAD,"The viscosity of oils at reservoir conditions whether under natural depletion conditions or under induced conditions (i.e. EOR/IOR) is one of the key parameters for the dynamics of flow in porous media, and it has direct impact on the economically recoverable volumes as well as transportation problems where the fluids can get exposed to potentially wide range of temperatures. It becomes even more essential measurement for thermal based EOR techniques including high temperature steam injection or in-situ upgrading techniques due to strong (exponential) dependency of viscosity to temperature. Unfortunately, viscosity measurements for such applications suffer with the two key challenges. First, most commercial and research labs could measure viscosities up to 200 degrees C (while the application considered may induce temperatures as high as 300 degrees C beyond which most naturally occurring hydrocarbons starts decomposing). And second, these measurements are based on steady-state conditions, requiring significant volumes of oil samples. However, the available volume of oil samples for such applications may be very small for various reasons, including emulsions leading to very low useful volumes, cost of sampling, or inheritance of candidate samples from other laboratory processes, such as but not limited to core-flooding or reactive transport experiments. Therefore, in this work, we present a novel but simple technique to overcome these challenges by using simple capillary device that could be integrated to any system that requires charging and/or charging the candidate fluids such as PVT-cells, pressurized vessels that could be operated up to 300 degrees C or higher. Such integration utilizes the charging of fluids to the cell for viscosity measurements, leading to the following advantages: (i) it requires no additional volume of oil for viscosity measurements, and also saves the operational time and cost (ii) it could produce viscosity data at higher temperatures that are desired for in-situ upgrading or thermal EOR, even small amounts of particulates evolve in the bulk phase (iii) it ensures that the viscosity and PVT measurements are performed on the same sample eliminating the potential sample to sample variations. (iv) the proposed approach along with the developed methodology paves the way for a the implementation of unsteady in-line measurement of viscosities for pressurized systems. This includes not only lab processes, but also the downhole sampling where the method could be implemented in sampling devices. The technique proposed here is based on transient measurements and modeling of capillary viscometer, where pressure at the end points and flow rate through the capillary tube may vary with time (which is the most realistic conditions for variable back pressure systems or systems with frictional pistons). In addition to the experimental process, necessary mathematical model and interpretative analysis tools to quality check, assessment of the experimental data (and the establishment of the range of validity and limitations) are derived from first principals (bottom-up approach) using Navier-Stokes equations.",0,0,1
Capillary Pressure,Porous Media,"Li, Yajun; Jia, Peng; Dong, Mingzhe",Analytical solutions of critical oil film thickness of negative spreading coefficient in a capillary corner,Three-phase flow; Oil film; Critical oil film thickness; Imbibition; Capillary pressure; Analytical solution,RELATIVE PERMEABILITY ANALYSIS; PORE-SCALE; THRESHOLD PRESSURE; 3-PHASE FLOW; BUNDLE; WETTABILITY; DRAINAGE; TUBE; SIMULATION; IMBIBITION,"In this paper, by combining applications of minimum surface free energy with capillary force balance equations, and considering that the total free energy change is zero at thermodynamic equilibrium, an analytical equation of the oil film critical thickness to spread over a water film in a three-dimensional capillary corner is derived. The derivation is based on the analysis proposed by Dong et al. [Journal of Colloid and Interface Science 172 (1995) 21-36]. This analytical solution allows the critical oil film thickness in three-phase systems to be calculated conveniently without lengthy calculation and be readily applied in simulation of three-phase systems in porous media using predictive models. The equation was examined by comparing the analytical solutions with the numerical results by Dong et al. Using the analytical solution, the reason why the oil phase spreads between the gas and water phases in three-phase systems in porous media was analyzed. The spreading of oil phase is controlled by the free energy change, and the spreading of oil phase only occurs in the system when the free energy change during the oil spreading process is negative. Also, there is a critical oil film thickness controlling this process that is a function of interfacial tension, contact angles, and corner angles. This analytical solution of critical oil film thickness can also be utilized to find the correlation of three-phase capillary pressure when the system is in thermodynamic equilibrium for water-wet porous media. This correlation should be useful in pore-scale simulation of three-phase flow of spreading oil.",0,0,1
Capillary Pressure,Porous Media,"Zhang, Faqiang; Kor, Ting; Yan, Jianzhao",Oil secondary migration simulation in tight reservoir and fingering factors analysis,Tight reservoir; Oil migration; Two phase fluid fingering; Numerical simulation,PORE-NETWORK; POROUS-MEDIA; FLOW; MODELS,"In the tight reservoirs, the oil accumulation is characterized by ambiguous trap boundaries, complicated oil distribution and nano-scale pore-throat interconnection system. As one of significant process for understanding the oil trap in the tight reservoir, oil migration from source rocks to reservoirs is the key concern by geoscientist. Investigating the immiscible two-phase fluids displacement in porous media, especially the fingering problem during the hydrocarbon migration, has always been a challenge scientific topic. This study establishes PNMs (Pore Network Model) with multiple viable parameters. A fluid migration numerical program is built for the flow study by modifying Poiseuille equation. Sensitive studies have been conducted by several dimensionless numbers to investigate the control factors of the flow behavior. Five factors are identified as the key factors on the migration mode: 1) Fluid viscosity ratio; 2) Interface tension force; 3) Fluid density; 4) Pore structure of sediments; 5) Capillary number. Oil migration behavior is affected by pressure domain, buoyancy, and resistance forces, such as capillary resistance and viscous forces. As the distribution fractal dimension increases with a given viscosity ratio, the width of the front edge of oil-water interface gradually expands. Oil saturation increases in parallel with a rising capillary number. During the simulation, Haines Jump phenomenon is observed. When the capillary number increases, oil migration gravitates towards piston-like displacement. As the oil-water viscosity ratio increases, the front width reaches its maximum at a particular point in time, and plateaus.",0,0,2
Capillary Pressure,Flow Behavior,"Zhang, Faqiang; Kor, Ting; Yan, Jianzhao",Oil secondary migration simulation in tight reservoir and fingering factors analysis,Tight reservoir; Oil migration; Two phase fluid fingering; Numerical simulation,PORE-NETWORK; POROUS-MEDIA; FLOW; MODELS,"In the tight reservoirs, the oil accumulation is characterized by ambiguous trap boundaries, complicated oil distribution and nano-scale pore-throat interconnection system. As one of significant process for understanding the oil trap in the tight reservoir, oil migration from source rocks to reservoirs is the key concern by geoscientist. Investigating the immiscible two-phase fluids displacement in porous media, especially the fingering problem during the hydrocarbon migration, has always been a challenge scientific topic. This study establishes PNMs (Pore Network Model) with multiple viable parameters. A fluid migration numerical program is built for the flow study by modifying Poiseuille equation. Sensitive studies have been conducted by several dimensionless numbers to investigate the control factors of the flow behavior. Five factors are identified as the key factors on the migration mode: 1) Fluid viscosity ratio; 2) Interface tension force; 3) Fluid density; 4) Pore structure of sediments; 5) Capillary number. Oil migration behavior is affected by pressure domain, buoyancy, and resistance forces, such as capillary resistance and viscous forces. As the distribution fractal dimension increases with a given viscosity ratio, the width of the front edge of oil-water interface gradually expands. Oil saturation increases in parallel with a rising capillary number. During the simulation, Haines Jump phenomenon is observed. When the capillary number increases, oil migration gravitates towards piston-like displacement. As the oil-water viscosity ratio increases, the front width reaches its maximum at a particular point in time, and plateaus.",0,0,2
Capillary Pressure,Flow Behavior,"Al-Shami, Tareq Mohammed; Jufar, Shiferaw Regassa; Negash, Berihun Mamo; Abdullahi, Mohammed Bashir",Impact of external excitation on flow behavior of trapped oil blob,Oil mobilization; Unconventional EOR; External excitation; Seismic stimulation; Flow behavior,CAPILLARY TUBES; OSCILLATORY FLOW; RECOVERY; DROPLETS; WAVES; MOBILIZATION; STIMULATION; RESONANCE; WATER,"External excitation of oil reservoirs has shown promising potential in increasing residual oil recovery. Although several numerical, experimental, and pilot studies were conducted over the last decades, large-scale field application is not realized due to inconclusive results on its performance. This paper aims to investigate the effect of external excitation on the flow behavior of an oil blob trapped in a constricted capillary tube model. Flow evolution and characteristic flow behaviors were studied using computational fluid dynamics (CFD) simulations. An external excitation with a sinusoidal profile propagating in the axial direction was applied at the wall of the constricted capillary tube model. The excitation intensity and frequency were varied to identify the flow characteristics. The results show that under the influence of external excitation, three distinct flow regimes develop based on the excitation frequency and intensity; these are trapped, clear pass, and dispersed pass. Velocity profiles, streamlines, and pressure contours were used to examine the resulting flow behaviors. In addition, dimensional analysis was carried out, and the dominant factors in each flow regime were identified. The dominant dimensionless numbers are Euler number, Reynolds number, and Weber number. Accordingly, the three flow regimes were mapped in the domains of these dimensionless numbers. As such, under given flow conditions, fluid properties, and external excitation parameters, the subsequent flow behavior can be predicted using the characteristic flow behavior maps presented in the study. Moreover, any of these flow regimes can be induced for a given application by tuning the excitation parameters based on the dimensionless characteristic maps presented.",0,0,2
Capillary Pressure,Steady State,"Yang, Shuyan; Hemmati, Nassim; Russell, Thomas; Zeinijahromi, Abbas; Borazjani, Sara; Behr, Aron; Genolet, Luis; Bedrikovetsky, Pavel",3D effects in two-phase steady-state tests,Steady state test; Capillary pressure; Relative permeability; 3D effects; Core simulation; Laboratory coreflood,IMAGED FLUID DISTRIBUTIONS; RELATIVE PERMEABILITY; INTERCEPT METHOD; HYSTERESIS; OIL; COMPUTATION; EXCHANGE; FLOW,"This study analyses three-dimensional (3D) effects during steady-state tests in short cores, primarily used to determine relative permeability (K-r) and capillary pressure (P-c). Here we concentrate on steady-state transition tests (SSTTs), which allows simultaneous determination of K-r and P-c from the steady-state data and the transition data measured between the steady states. Comparison between three- and one-dimensional (1D) modelling in short cores shows a significant difference in measured water-cut and pressure-drop data. This difference has been observed for cores with different inlet distributor geometries, aspect ratios, and anisotropy. Despite the influence of 3D flow effects on measurement data, the agreement between K-r and P-c as obtained from the 3D and 1D models is close. This phenomenon of conservative inverse-solution results has been demonstrated for different inlet distributor geometries. The Spiral distributor exhibits lower 3D flow effects and more accurate determination of relative permeability and capillary pressure from SSTT tests.",0,0,0
Capillary Pressure,Steady State,"Ratnakar, Ram R.; Dindoruk, Birol",Transient measurement and modeling of integrated capillary viscometer for live oils at high temperatures with volumetric constraints,Capillary viscometer; Integrated viscosity experiment; Modeling fluid flow; Hagen-Poiseuille equation; Live and dead oils; High temperature high pressure (HTHP) studies,HEAVY-OIL; VISCOSITY CORRELATION; PREDICTION; BITUMEN; DEAD,"The viscosity of oils at reservoir conditions whether under natural depletion conditions or under induced conditions (i.e. EOR/IOR) is one of the key parameters for the dynamics of flow in porous media, and it has direct impact on the economically recoverable volumes as well as transportation problems where the fluids can get exposed to potentially wide range of temperatures. It becomes even more essential measurement for thermal based EOR techniques including high temperature steam injection or in-situ upgrading techniques due to strong (exponential) dependency of viscosity to temperature. Unfortunately, viscosity measurements for such applications suffer with the two key challenges. First, most commercial and research labs could measure viscosities up to 200 degrees C (while the application considered may induce temperatures as high as 300 degrees C beyond which most naturally occurring hydrocarbons starts decomposing). And second, these measurements are based on steady-state conditions, requiring significant volumes of oil samples. However, the available volume of oil samples for such applications may be very small for various reasons, including emulsions leading to very low useful volumes, cost of sampling, or inheritance of candidate samples from other laboratory processes, such as but not limited to core-flooding or reactive transport experiments. Therefore, in this work, we present a novel but simple technique to overcome these challenges by using simple capillary device that could be integrated to any system that requires charging and/or charging the candidate fluids such as PVT-cells, pressurized vessels that could be operated up to 300 degrees C or higher. Such integration utilizes the charging of fluids to the cell for viscosity measurements, leading to the following advantages: (i) it requires no additional volume of oil for viscosity measurements, and also saves the operational time and cost (ii) it could produce viscosity data at higher temperatures that are desired for in-situ upgrading or thermal EOR, even small amounts of particulates evolve in the bulk phase (iii) it ensures that the viscosity and PVT measurements are performed on the same sample eliminating the potential sample to sample variations. (iv) the proposed approach along with the developed methodology paves the way for a the implementation of unsteady in-line measurement of viscosities for pressurized systems. This includes not only lab processes, but also the downhole sampling where the method could be implemented in sampling devices. The technique proposed here is based on transient measurements and modeling of capillary viscometer, where pressure at the end points and flow rate through the capillary tube may vary with time (which is the most realistic conditions for variable back pressure systems or systems with frictional pistons). In addition to the experimental process, necessary mathematical model and interpretative analysis tools to quality check, assessment of the experimental data (and the establishment of the range of validity and limitations) are derived from first principals (bottom-up approach) using Navier-Stokes equations.",0,0,1
Capillary Pressure,Production,"Verdugo, Martin; Doster, Florian",Impact of capillary pressure and flowback design on the clean up and productivity of hydraulically fractured tight gas wells,Flowback; Tight gas; Capillary pressure; Well performance; Rate transient analysis,WATER-USE; SHALE,"This work analyses the impact of capillary pressure and flowback operational variables on hydraulically fractured tight gas wells with the objective of understanding the clean-up process at reservoir level and its impact on future well performance. Through numerical reservoir simulation, different scenarios were investigated, varying capillary pressure, flowback duration, shut-in duration and drawdown. These scenarios are interpreted with rate transient analysis. The results of this work show the ambivalent effect of capillary pressure in terms of facilitating imbibition but also holding back water close to the fracture. The novelty of this work consists in the findings that for lower capillary pressures, short shut-in periods lead to a better well productivity while for higher capillary pressure extended shut-in periods are better for well productivity. It was also found that drawdown can be used to minimize fracture face relative permeability damage and as shut-in period extends, flowback should be performed at smaller drawdowns.",0,0,1
Capillary Pressure,Production,"Yang, Shikai; Yang, Daoyong",Integrated characterization of wormhole network by use of a modified pressure-gradient-based (PGB) sand failure criterion and ensemble-based history matching during CHOPS processes,Wormhole network; Cold heavy oil production with sand; Pressure-gradient-based sand failure criterion; Ensemble-based history matching; Upscaling,RELATIVE PERMEABILITY; HEAVY-OIL; KALMAN-FILTER; CAPILLARY-PRESSURE; TIGHT FORMATIONS; DATA ASSIMILATION; MODEL; RESERVOIR; FLOW; QUANTIFICATION,"In this paper, a damped iterative ensemble Kalman filter (IEnKF) technique has been developed and integrated with a recently modified pressure-gradient-based (PGB) sand failure criterion to implicitly and inversely characterize the dynamic wormhole network during cold heavy oil production with sand (CHOPS) processes. With an improved upscaling process, not only has a microscopic PGB sand failure criterion been properly upscaled to the grid-scale simulation, but also it can be dynamically, implicitly, and inversely determined. Then, such a sand failure model together with three-phase relative permeability is validated and applied to reproduce wormhole network in a laboratory experiment conditioned to its sand production profile. Good agreements between the observed and simulated cumulative production profiles including oil, gas, and sand have been achieved with satisfactory convergence by integrating the ensemble-based history matching method. The simulated wormhole network has shown its great similarity to the experimental observations, while the convergence of the ensemble based history matching algorithm is greatly improved with a widespread of initial ensembles in each grid. Furthermore, deviations between the observed and updated production profiles can be significantly minimized by dividing the entire production period into three sequential stages, each of which has its distinct relative permeability curves due to the major effect (i.e., foamy oil flow, sand failure, and slurry flow) on its multiphase flow behaviours, respectively. By integrating the ensemble-based sand failure model with the damped-IEnKF method, the dynamic wormhole network during a CHOPS process can be accurately characterized with satisfactory convergence, demonstrating its robustness and practicality of dynamically and inversely simulating the preferential wormhole network. Such an ensemble-based sand failure model can be seamlessly incorporated with any commercial reservoir simulators under various conditions.",0,0,1
Capillary Pressure,Properties,"Bai, Yubin; Zhao, Jingzhou; Wu, Weitao",Methods to determine the upper limits of petrophysical properties in tight oil reservoirs: Examples from the Ordos and Songliao Basins,Petrophysical property upper limit; High-pressure mercury injection; Non-Darcy percolation; Tight sandstone; Ordos basin; Songliao basin,TRIASSIC YANCHANG FORMATION; HYDROCARBON ACCUMULATION; SASKATCHEWAN; MIGRATION; MEMBER; ROCK,"In large petroliferous basins, tight and conventional reservoirs are widely distributed. These reservoirs have significant differences in formation mechanisms, enrichment rules, and development modes. Only when a reservoir petrophysical property is less than a certain upper limit can a large area of tight oil accumulation be formed. Therefore, it is necessary to scientifically define the petrophysical property boundary between tight and conventional reservoirs. In the past, the determination of petrophysical property boundaries between tight and conventional reservoirs was based mainly on the statistics of a large number of measured petrophysical property data of typical tight oil basins and lacked theoretical research. Taking the Ordos and Songliao Basins as examples, this paper studies the petrophysical upper limits of tight reservoirs, starting with the reservoir-forming mechanism and characteristics of tight and conventional reservoirs. Based on four methods-the mechanical balance method assuming that the buoyancy and capillary pressure are equal, petrophysical simulation of an oil accumulation in sandstone, analysis of the distribution characteristics of the current petrophysical properties of conventional and tight oil reservoirs, and mercury injection porosimetry tests to determine the change in reservoir porosity and permeability with displacement pressure-this research determines that basically the same upper limits of tight reservoir properties are found among these methods. Obtained synthetically, the upper limit of permeability is approximately 1 md, corresponding to the upper limit of porosity of approximately 12%. These research results provide new ideas and methods to distinguish tight oil from conventional oil accumulations in petroliferous basins in different stages of exploration.",0,0,0
Capillary Pressure,Properties,"Al-Shami, Tareq Mohammed; Jufar, Shiferaw Regassa; Negash, Berihun Mamo; Abdullahi, Mohammed Bashir",Impact of external excitation on flow behavior of trapped oil blob,Oil mobilization; Unconventional EOR; External excitation; Seismic stimulation; Flow behavior,CAPILLARY TUBES; OSCILLATORY FLOW; RECOVERY; DROPLETS; WAVES; MOBILIZATION; STIMULATION; RESONANCE; WATER,"External excitation of oil reservoirs has shown promising potential in increasing residual oil recovery. Although several numerical, experimental, and pilot studies were conducted over the last decades, large-scale field application is not realized due to inconclusive results on its performance. This paper aims to investigate the effect of external excitation on the flow behavior of an oil blob trapped in a constricted capillary tube model. Flow evolution and characteristic flow behaviors were studied using computational fluid dynamics (CFD) simulations. An external excitation with a sinusoidal profile propagating in the axial direction was applied at the wall of the constricted capillary tube model. The excitation intensity and frequency were varied to identify the flow characteristics. The results show that under the influence of external excitation, three distinct flow regimes develop based on the excitation frequency and intensity; these are trapped, clear pass, and dispersed pass. Velocity profiles, streamlines, and pressure contours were used to examine the resulting flow behaviors. In addition, dimensional analysis was carried out, and the dominant factors in each flow regime were identified. The dominant dimensionless numbers are Euler number, Reynolds number, and Weber number. Accordingly, the three flow regimes were mapped in the domains of these dimensionless numbers. As such, under given flow conditions, fluid properties, and external excitation parameters, the subsequent flow behavior can be predicted using the characteristic flow behavior maps presented in the study. Moreover, any of these flow regimes can be induced for a given application by tuning the excitation parameters based on the dimensionless characteristic maps presented.",0,0,2
Carbon Dioxide,,"Hasanzadeh, Maryam; Azin, Reza; Fatehi, Rouhollah; Zendehboudi, Sohrab",New insights into forced and free fall gravity drainage performance in a fractured physical model,Fractured physical model; Gas injection; Recovery factor; Free fall gravity drainage; Forced gravity drainage,TERTIARY OIL-RECOVERY; POROUS-MEDIA; WETTABILITY; DISPLACEMENT; SECONDARY; FLOW,"Gravity is one of the major driving forces for fluid flow in naturally fractured reservoirs. Gravity drainage appears to be a vital recovery mechanism over the oil production process in a majority of fractured reserves. In this paper, free-fall gravity drainage (FFGD) and forced gravity drainage (FGD) production approaches are investigated through employing a new fractured sand pack with a rectangular geometry. Distilled water and condensate are used as the wetting phase. Nitrogen, carbon dioxide, and air are also utilized as the non-wetting phase. A systematic sensitivity analysis is conducted to find the effects of the key factors such as fracture blockage, injection rate, dip angle, and type of wetting phase and injection fluid on the performance of FFGD and FGD processes. Also, a numerical simulation is performed to simulate the experiments. Results reveal that the FGD has a better performance under controlled process conditions, compared to the FFGD so that gas injection with a controlled rate improves the recovery. Moreover, it was found that increasing the gas injection rate improves the recovery factor (RF) of wetting-phase when the up and bottom sides of the fractures are blocked; the RF is decreased in the case with open fracture sides. The recovery of the wetting phase decreases in both FFGD and FGD modes when the porous system has a deviation from the vertical orientation. According to the study outcomes, the immiscible gas-assisted gravity drainage offers a higher condensate recovery, compared to water recovery, due to lower viscosity and interfacial tension (IFT) of the condensate phase. The comparison of the experimental data and simulation results implies that the simulation approach can satisfactorily predict the performance of the FGD process. Based on the error analysis, there is a good match between the simulation results and the experimental measurements; the fluid pair of CO2-condensate exhibits the highest accuracy with an R-squared of 0.9961 and an average relative error (ARE) of 0.0054.",0,0,0
Carbon Dioxide,,"Useche-Narvaez, Catalina; Giovany Montes-Paez, Erik; Andres Guerrero-Martin, Camilo",Evaluation of the carbon footprint produced by conventional artificial lift systems in a Colombian field,Artificial Lift System; CO (2) emissions; Petroleum Production,EMISSIONS; ENERGY; LAND; GAS,"In the area of hydrocarbon production, when designing an artificial lift system for a well, technical and financial criteria are taken into account, leaving aside environmental criteria, such as the carbon footprint; Hence, this research focuses on evaluating and calculating the CO2 emissions and the energy efficiency of the different conventional artificial lift systems in a Colombian field. This project's development started by searching for information related to the properties of representative type wells in the basins with the highest production in Colombia. We proceeded to design the most used artificial lifting systems in the country, and we finished with the evaluation and the calculation of the carbon footprint, the energy efficiency, and the operating costs for the selected cases. According to the calculations made, it was concluded that an artificial lift system that generates less CO2 emissions is at the same time the one that has greater energy efficiency and lower financial costs; these three parameters are directly proportional to each other. In addition, the carbon footprint evaluation methodology allows us to conclude that the lifting system that emits least carbon dioxide indirectly is the rod pumping, followed by the pumping by progressive cavities and the electrical sumersible pumping system, which generates the greatest carbon footprint. This research seeks to propose that in the decisions that are taken when selecting a survey system, environmental parameters be included due to the importance of CO2 emissions as a vital aspect in the fight against global warming.",0,0,1
Carbon Dioxide,,"Afanasyev, Andrey; Andreeva, Anna; Chernova, Anna",Influence of oil field production life on optimal CO2 flooding strategies: Insight from the microscopic displacement efficiency,CO2 flooding; Immiscible gas injection; WAG process; Optimization; Production life; Net present value,CARBON-DIOXIDE; RECOVERY; STORAGE; EQUATION,"We investigate the influence of the microscopic displacement processes on optimal gas flooding strategies. We couple a 1-D compositional reservoir model with an economic model of the flooding to assess profitability of the strategies. In general, we aim at the net present value maximization, although the oil recovery and CO2 storage efficiencies are also estimated. Under certain assumptions, we reduce the number of parameters controlling selection of optimal strategy to just a few dimensionless quantities characterizing both physical and economic processes. We show that the production life of oil fields should not be fixed in optimization studies, especially at low oil prices. A significantly larger net present value can be achieved by varying the reservoir lifetime in addition to the injection rates and volumes and other well controls. Herewith, the optimal strategy can differ from that in the case of a presumed production time. We conclude that waterflooding is the optimal recovery method if the injection rate is low, whereas gas (WAG) flooding applied as a primary method and followed by waterflooding is most optimal for large injection rates. Gas flooding applied as the tertiary recovery method is most optimal for an intermediate range of the rates. In the latter case, gas injection should begin much earlier than water breaks through to producing wells. Finally, we investigate how oil price influences the range of parameters suitable for gas injection.",0,0,1
Carbon Dioxide,,"Bannerjee, Mollika; Mendhe, Vinod Atmaram; Kamble, Alka Damodhar; Varma, Atul Kumar; Singh, Bhagwan D.; Kumar, Susheel","Facets of coalbed methane reservoir in East Bokaro Basin, India",Organo-petrographic facets; Desorbed gas; Gas genesis; Sorption capacity; Cleat/fractures; Pore network,RANIGANJ BASIN; HYDROLOGICAL CONTROLS; GEOLOGICAL CONTROLS; CARBON-DIOXIDE; GAS-RESERVOIR; SAN-JUAN; SEAMS; COALFIELD; SORPTION; NORTH,"The East Bokaro Basin of the Damodar valley is a potentially prospective CBM (coalbed methane) play having significant cumulative coal seam thickness, in-situ gas content, vitrinite percentage, and adequate thermal maturity. Successful CBM recovery needs a detailed understanding of the organic content, pore structures/networks, storage properties and gas flow mechanism. The present work attempts to systematically investigate East Bokaro coal for organo-petrographic controls on gas content and generation, variations in sorption capacity and saturation, pore mechanisms, cleat intensity, cleat aperture distribution and spacing. The values of in-situ gas, sorption capacity and methane concentration (C-1) vary from 3.52 to 30.93 cc/g (dry ash-free basis), 15.40-32.40 cc/g (dry ash-free basis), and 66-93 vol%, respectively. The atomic ratios H/C and O/C indicate that thermally matured coal seams contain type III-IV kerogen positioned in the dry gas window. The decrease of hydrogen-containing liptinite with increasing depth reveals the function of thermal gradient on the cracking of liptinitic compounds with successive evolution of hydrocarbons and the development of a carbon-rich pore matrix. The H/C ratio is also influenced by the increasing content of vitrinite and reflectance values of deeper coal. More than 63 % of desorbed gas was determined from desorption measurement and low sorption time (tau, mainly <10 days). This demonstrates good diffusion characteristics of the studied coal. It shows the tendency of desorbed gas diffusion from pores reaches to cleat-fractures with negligible influence of secondary mineral infillings. The high-pressure sorption studies of methane on various samples indicate substantial open-pore characteristics, supporting adsorption, diffusion and gas release. The relationship of C-3/C-1 and C-2/C-1 ratios demonstrates that the hydrocarbons in coal primarily originated from the thermogenic transformation of organic matter. Such an assessment is also supported by the stable isotope (delta C-13(1)) value that ranges between -22.70 parts per thousand and -57.30 parts per thousand. However, some of the lighter isotope values (<-50 parts per thousand) indicate a mixed origin of gases, which may be due to the influx of fresh-water to coal associated aquifers carrying bacteria received from local drainage. Geochemically and thermally altered dissolved and partially filled pores, shown by SEM photographs, negligibly influence gas sorption, diffusion, and flow mechanism in coalbeds. The pore network model signifying that the studied coal seams are microstructurally different comprises a lateral difference in pore and cleat/fracture.",0,0,1
Carbon Dioxide,,"Silva, Graciele Oliveira de Moura e; Lamas, Luis Fernando; Soares, Ana Paula",Characterization of carbonate facies and study of their relationship with dissolution and wettability in CO2 injection,Carbonate facies; Dissolution; CO2 injection; Surface complexation modeling,,"Hydrocarbon reserves can be found in porous reservoir rocks, which may be of siliciclastic or carbonate origin. Each type of rock presents its own characteristics, which directly impact the recovery of oil and gas. To better understand the heterogeneity of carbonate rocks, their geological processes and behavior of fluid flow, this work aims to characterize carbonate facies and simulate its behavior with the injection of carbonated water, evaluating the dissolution of the minerals and the superficial interactions, giving indications about the wettability of these facies. The characterization of the facies involved the observation of macro and micro images of the carbonate frameworks, identification of petrophysical characteristics and attribution to the reservoir rock. From this characterization, six facies models, three calcitic and three dolomitic, with different properties were chosen to be used in the simulation with a Surface Complexation Model (SCM) to identify the dissolution behavior of minerals and Total Bond Product (TBP) during the injection of carbonated water. This paper purpose is to analyze different carbonate facies and understand the relationship of these facies to the change in wettability due to CO2 injection. The facies were identified in four groups, travertine, biogenic, chemical, and reworked, that differ in their geological processes, identifying how the precipitation of minerals influences the geological structure. The mineral dissolution presented higher dissolution for the calcite mineral compared to dolomite, presenting significant differences between the facies and between the concentration of CO2 for both minerals. For the dissolution of kaolinite, which presented higher values when present in the dolomitic facies, significant differences were identified between the rocks, calcitic and dolomitic, between facies, between the concentrations of CO2 and the correlations between factors. The calculation of TBP, a factor that assesses oil-mineral adhesion and may interfere with rock wettability, indicated a decrease in the value as the porosity of the facies increases, however, the statistical analysis indicated that there is no significant difference between the carbon dioxide concentrations in the alteration of TBP. The results made it possible to achieve the proposed objectives, as well as to make room for subsequent discussions.",0,0,1
Carbon Dioxide,,"Zhu, Ziming; Fang, Chao; Qiao, Rui; Coskuner, Yakup; Yin, Xiaolong; Ozkan, Erdal",Experimental measurements and mechanisms of selective hindrance of oil mixtures in Niobrara shale,Selective hindrance; Niobrara shale; Experiment; Molecular dynamics simulation,CARBON-DIOXIDE; SOURCE ROCKS; ADSORPTION; HYDROCARBONS; NANOPORES; METHANE; SURFACE; CLAYS,"In nanoporous rocks, potential size exclusion and fluid-rock interactions in nano-sized pores and pore throats may turn the rock into a semi-permeable membrane, hindering the transport of certain molecules while allowing other molecules to pass freely. In this work, to investigate whether Niobrara samples possess such selectivity to a liquid hydrocarbon mixture, we conducted core-flow tests by pumping a binary hydrocarbon mixture (decane, C10 and heptadecane, C17) into Niobrara samples and analyzing the produced fluid compositions. Molecular dynamics simulation of C10 and C17 adsorption on calcite surfaces using all-atom models was performed to help understand the mechanisms of the experiments. Experimental results show that the transport of heavier component (C17) was noticeably hindered, with a decrease of its mole fraction in the produced fluid and an increase in the upstream injection fluid, demonstrating the presence of selective hindrance. Simulation results indicate that, for a calcite surface in equilibrium with the binary mixture of C10 and C17, more C17 molecules adsorb on the calcite surface than C10. Compositional change of fluid upstream of the sample and a mole balance calculation suggest that size exclusion should also exist.",0,0,1
Carbon Dioxide,,"Carchini, Giuliano; Hussein, Ibnelwaleed A.; Al-Marri, Mohammed J.; Mahmoud, Mohamed; Shawabkeh, Reyad; Aparicio, Santiago",Ab-Initio Molecular Dynamics investigation of gas adsorption on alpha-quartz (001) for CO2 enhanced natural gas recovery,Enhanced gas recovery; Carbon dioxide; Methane; Ab-initio molecular dynamics; DFT; Quartz,GENERALIZED GRADIENT APPROXIMATION; CARBON-DIOXIDE; METHANE RECOVERY; SEQUESTRATION; CAPTURE; CHEMISTRY,"In this work, the interaction of methane and carbon dioxide on alpha-quartz with surface 001, with a siloxane termination (dense) surface was investigated by means of Ab-Initio Molecular Dynamics. Different temperatures were addressed, ranging from 298 to 423 K. For completeness, pure and mixed compositions were considered, to replicate the conditions present during Enhanced Gas Recovery processes by CO2 injection. When considering pure compositions, both gases stick to the surface, except for the highest temperature (423 K), where most of CH4 tend to desorb. When mixed compositions are addressed, carbon dioxide generally hinders the interaction of methane, except for high temperature, where both gases are equally distributed both close and far from the surface. To the goal of improving EGR processes on sandstone reservoirs, this work shows that a temperature of 323 K offers the best efficiency by increasing the interaction of carbon dioxide and pushing methane out of the surface. At the same time, this study would not recommend the use of very high temperatures (T > 373 K) and excessive concentration of CO2, as the majority of this gas would desorb, without improving methane extraction in a meaningful way.",0,0,2
Carbon Dioxide,,"Habibi, A.; Riazi, M.; Malayeri, M. R.",Experimental and simulation study of the tensile strength of wet carbonate rocks using the Brazilian Test,Tensile strength; Wet carbonate rock; Hydration force; Brazilian tensile test; Extended finite element method,,"Mechanical behavior of rocks would have substantial implications for different operations from fluid injection and hydraulic fracturing in hydrocarbon reservoirs to underground carbon dioxide storage in the crust of the earth. In all of these operations, restricting the undesired seismicity events and preserving the integrity of formations is a crucial subject that enforces engineers to evaluate the mechanical behaviors of constituent rocks and predict the formation response. Tensile strength is an important factor for maintaining caprock and reservoir formation from induced tensile cracking which can be influenced by the pore fluid. This paper focuses on the tensile strength of carbonate rock, as an important reservoir rock, in the presence of seawater, as a common injection fluid candidate for enhanced oil recovery objectives. For this purpose, twelve dolomite samples from the Asmari-Jahrum Formation outcrop in Fars province, Iran, were prepared for performing tensile tests. Also for a thorough comparison, sample properties, fluid contents, digital image correlation measurements, and a finite element simulation have been investigated. The experimental results showed a noticeable reduction in the tensile strength of dolomite samples in the presence of distilled water and seawater. In comparison with a dry sample though, a reduction of 16% tensile strength for a seawater saturated sample was observed for similar samples. Among the various mechanisms, which are reported in the open literature, the hydration force seems to be the main reason for the tensile strength reduction and this conclusion was examined by measuring the mass of vaporized adsorbed water on the powder of the same dolomite sample. In addition by testing flooded samples, the impact of flow on the tensile strength was examined. For both cases of seawater and distilled water flooding, the samples which were placed in the outlet zone during the flooding showed lower tensile strength. Moreover, simulation results confirmed the similarity of the weakening trend and impact of seawater.",0,0,2
Carbon Dioxide,,"Nie, Bin",Circulating preheating model of full-length horizontal wellbore in heavy oil reservoirs with multiple thermal fluid injection,Heavy oil reservoir; Vertical wellbore and horizontal wellbore; Superheated multi-element thermal fluid; Cyclic preheating model; Numerical model,STEAM INJECTION; THERMOPHYSICAL PROPERTIES; CARBON-DIOXIDE; CO2 INJECTION; HOT-WATER; FLOW; TEMPERATURE; WELLS; LOSSES,"Heavy oil reservoirs are rich in resources and have broad prospects for exploration and development. Wellbore heat transfer is one of the important areas of heavy oil research. However, the current research on the preheating of multi-element thermal fluid circulation in the wellbore is still insufficient. Based on thermodynamic equations and fluid dynamics equations, this paper establishes a cyclic preheating model of multi-element thermal fluid in the wellbore. The model considers the mixing characteristics of superheated steam and non-condensed gas, and is applicable to both vertical and horizontal wellbores. Results show that the temperature curve can be divided into four parts: the temperature of the inner tube in the vertical section of the wellbore, the temperature of the inner tube in the horizontal section of the wellbore, the temperature of the annular space in the horizontal section of the wellbore, and the temperature of the annular space in the vertical section of the wellbore; In the horizontal section of the wellbore, the multi-element thermal fluid in the inner tube releases heat energy into the annular space, and there is a large temperature difference at the heel end and a small temperature difference at the toe end.",0,0,2
Carbon Dioxide,,"Kim, Seunghee; Zadeh, Amin Hosseini; Nole, Michael; Daigle, Hugh; Huh, Chun; Kim, Ijung",Spontaneous generation of stable CO2 emulsions via the dissociation of nanoparticle-aided CO2 hydrate,Gas hydrate; Carbon dioxide; Nanoparticles; Emulsion; Foam; CO2 utilization,IN-WATER EMULSIONS; SILICA NANOPARTICLES; MOLECULAR-DYNAMICS; GAS; DIOXIDE; SURFACTANTS; METHANE; STORAGE; FOAMS; CONVERSION,"This study finds that CO2 hydrate dissociation spontaneously generates fine-textured emulsions or foams, and that the phase state of CO2 which was used to form hydrate determines the stability of the emulsion or foam when hydrate is dissociated in an aqueous dispersion of hydrophilic silica nanoparticles. This process suggests an energy-efficient method of generating stable emulsions for high-pressure applications without a need for mechanical energy input. We proved experimentally that the CO2 hydrate phase could be used to generate foams and emulsions because the hydrate formation process naturally disconnects a hydrate guest molecule phase from the bulk water phase. During dissociation, easy adsorption of nanoparticles at CO2-water interfaces hinders the coalescence of bubbles. As a result, CO2 emulsions or foams were generated upon the completion of hydrate dissociation. The CO2 emulsions generated remained fairly stable, while the CO2 foams generated became unstable and the buoyant force of the CO2 bubbles led to their coalescence. The concepts experimentally proven here could be applicable to any suitable clathrate compound undergoing a solid to a liquid phase transition.",0,0,2
Heat Transfer,,"Gao, Yanfang; Ren, Zhanli; Chen, Mian; Jiang, Hailong; Ding, Shuaiwei",Coupled geomechanical-thermal simulation for oil sand reservoirs with shale barriers under hot water injection in vertical well-assisted SAGD wells,Oil sands; Shale barriers; Geomechanical-thermal simulation; Vertical well; SAGD,PROPAGATION BEHAVIOR; PERMEABILITY CHANGES; RECOVERY PROCESSES; MODEL; TEMPERATURE,"Mudstone stringers in an oil sand reservoir can significantly affect the propagation of the steam chamber in the process of steam-assisted gravity drainage (SAGD). The micro-fracturing by water injection in strongly heterogeneous oil sands can result in these problems such as hard stringer breakthrough and aggravating heterogeneity. This paper proposed a comprehensive numerical model for conventional SAGD wells and vertical well-assisted SAGD (VWA-SAGD) wells to predict the coupled thermo-hydro-mechanical responses under hot water injection in a typical Karamay oil sand reservoir with two stringers, considering skeleton shear dilation, the ""phase change"" of bitumen, formation heterogeneity, the permeability evolution induced by elastoplastic deformations, and the theory of heat and mass transfer. Major conclusions were drawn that there are three relatively narrow separate transition zones effectively heated around the SAGD wells and vertical well. The vertical well makes about 0.5 MPa increase to the pore pressure of the reservoir embedded with mudstone stringers in vertical directions and rises by about 0.6 MPa for the reservoir pore pressure above the upper stringer to reduce the pore pressure differential along the wellbore. Water injection-induced ultimate stress states can't reach the shear failure line under field operations, so the shear dilation can't be induced. The thermoporoelastic deformation determines whole reservoir deformation. The reservoir between the two stringers contributes to most of the caprock uplift. The VWA-SAGD technique can improve the porosity by about 1% in the whole vertical direction and reduce the anisotropy of porosity along the wellbore, which is beneficial to the uniform and fast propagation of the steam chamber in subsequent preheating and production stages. These findings can be employed to accurately predict the temperature, pore pressure, stress/displacement, and porosity evolutions for the field engineers to properly evaluate the uplift of reservoir and caprock, oil output changes, and heat utilization efficiency.",0,0,0
Heat Transfer,,"Ma, Zhiwei; Leung, Juliana Y.",Efficient tracking and estimation of solvent chamber development during warm solvent injection in heterogeneous reservoirs via machine learning,Heavy oil; Machine learning; Deep learning; Solvents; Interface tracking,HEAVY OIL-RECOVERY; STEAM-CHAMBER; GRAVITY-DRAINAGE; DATA ANALYTICS; SIMULATION; ENSEMBLE; OPTIMIZATION; PERFORMANCE; ALGORITHM; EVOLUTION,"Warm solvent injection (WSI) has been proposed as a promising alternative to steam-based methods for bitumen recovery, due to its potential to reduce greenhouse gas emissions and environmental footprint. It involves injecting heated vaporized solvent to reduce the viscosity of bitumen via solvent diffusion and latent heat transfer. The presence of reservoir heterogeneity caused by shale barriers is a severe concern for the success of the WSI because the conformance of solvent chamber advancement can be compromised. However, the efficient estimation and tracking methods for solvent chamber growth and propagation in heterogeneous reservoirs have not been widely investigated in the past. To fill this gap, this work proposes a novel machine learning-based approach to efficiently track solvent chamber positions in heterogeneous reservoirs for the WSI process. From a large training dataset consisting of numerous synthetic heterogeneous models and their simulation results, the input features and output parameters are extracted from oil production time-series data and the dynamic evolution of solvent chamber, respectively. A convolutional neural network (CNN) is implemented to dynamically track solvent chamber positions by correlating the extracted inputs and outputs. The estimation results are reliable and accurate for both scenarios where the shale barriers are either regularly or irregularly shaped with high conformance index (CI). Only production data is used to assess the conformance of solvent chamber advancement, which is an important consideration in operations design and real-time optimization. The presented workflow offers a novel alternative to infer the development of solvent chambers in heterogeneous reservoirs from production time-series data directly. This type of analysis could complement many existing monitoring techniques to deliver a more comprehensive inference of the distribution of shale heterogeneities in solvent-based bitumen recovery operations.",0,0,0
Heat Transfer,,"Hasan, A. Rashid; Jang, Minsoo",An analytic model for computing the countercurrent flow of heat in tubing and annulus system and its application: Jet pump,Jet pumps; Artificial lift; Counter-current flow; Tubing-annulus heat-transfer; Heat balance-based ODE,TEMPERATURE PROFILE; FLUID TEMPERATURE; STEAM,"Shale fields are currently over-reliant on electric submersible pumps (ESPs) in the early stage of artificial lift despite its weakness to sandy flow and often failing within the first three months. Jet pumps are reliable and costeffective alternatives to the ESPs. Current studies on jet pumps have focused on designing parameters for maximizing performance; however, there have been very few investigations on predicting temperature profiles in the wellbore with a jet pump in use. Fluid temperature influences viscosity; hence, the production of heavy oil. Typically, the heavier the hydrocarbon, the greater is the variation in viscosity with temperature. Therefore accurate temperature prediction is essential for the efficient design of heavy oil production facilities. This paper offers an analytic model to compute temperature profiles in the tubing and annulus. Results show a good match with a field data set. Data set from a well in Tah field in China is used to validate the model. In addition, sensitivity analyses were performed that showed that injection temperature affects the annulus temperature profile, leading to significant changes in frictional pressure loss at shallow depths. In contrast, injection rate has less influence on temperature profiles, although, of course, higher fluid velocity causes greater frictional losses. Results show that a hotter and relatively small flow rate leads to lesser pumping cost by reducing frictional pressure drop during the operation. The proposed model ideally requires the bottom-hole temperature as a boundary condition (BC). When subsurface temperature data are unavailable, as often the case due to cost, a computing method is offered in the paper for reliable temperature profile estimation from only two data points at the wellhead.",0,0,0
Heat Transfer,,"Alhosani, Ahmed; Daraboina, Nagu",Effect of multi-phase flow on asphaltene deposition: Field case application of integrated simulator,Flow assurance; Multiphase flow; Asphaltene deposition,GAS-LIQUID FLOW; HEAT-TRANSFER; PARTICLE DEPOSITION; UNIFIED MODEL; CRUDE OILS; TOOL ADEPT; PRECIPITATION; SLUG; HOLDUP; AGGREGATION,"Asphaltene is initially stable in the oil, but when there is a change in pressure, temperature, or composition, particles tend to phase out and form precipitants. Issues arise when those particles diffuse toward the wall and deposit, which contributes to reducing the flowing area and increasing the pressure drop. Preventing precipi-tation is the optimum solution to maintain the target production rate; however, it is challenging to avoid favorable precipitation conditions. Remedies and treatments to mitigate this issue cause the oil industry a considerable increase in expenditure and time; thus, it is necessary to develop a tool to accurately predict the deposition for a wide range of operating conditions, especially in multiphase flow. In this study, a multiphase simulator is developed by coupling thermodynamics, hydrodynamics, heat transfer, and asphaltene modules to predict the deposition. A deposition data obtained from a field case is used to validate the robustness of the simulator. The simulator results matched well with the asphaltene deposition and the equilibrium profile available in the literature. The simulation approach presented here offers useful insights into the effect of multiphase flow on asphaltene deposition and eventually aid in improving the accuracy of pre-diction. Using single-phase assumption under multiphase conditions contributed to a significant error in the prediction, and these inaccuracies may lead to a substantial economic and operational burden for the oil and gas industry.",0,0,0
Heat Transfer,,"Ahmed, Syed Amjad; John, Bibin",Predictive correlations for heat transfer characteristics of oil-water horizontal pipe flow-an experimental study,convective heat transfer; oil-water flow; stratified flow; dispersed flow,LIQUID-LIQUID DISPERSIONS; CRUDE-OIL; DEPOSITION; VISCOSITY; PATTERNS,"This paper presents convective heat transfer characteristics of liquid-liquid horizontal pipe flow. Experiments are carried out in a stainless-steel pipe of diameter 1.59 cm with L/D ratio of 377. Three different oils with varying properties (viscosity: 630 mPa-s, 202 mPa-s and 1.95 mPa-s and density: 919 kg/m3, 901 kg/m3 and 790 kg/m3 respectively) are employed as oil phase and the other fluid phase being water. The experiments are conducted for four oil-water flow patterns-stratified flow, stratified flow with droplets at the interface, dispersed oil-in-water and dispersed water-in-oil with fluid fractions ranging 0 to 1 at different fluid velocities. A constant temperature heat supply, using jacketed hot water flowing over the test pipe, is maintained. The analysis of heat transfer experiments indicates that the heat transfer process in liquid-liquid flow depends on the same dimensionless terms, the Reynolds number and the Prandtl number, that signifies single-phase flow heat transfer. Accordingly, it is found that the established and existing single-phase heat transfer correlations, modified according to flow regime, flow pattern and fluid flow and thermal properties, are also applicable for liquid-liquid flow. The heat transfer in liquid-liquid flow found to be influenced by the fluid fraction. Effectively, for stratified flow, the heat transfer in the liquid-liquid flow is the sum of heat transfer of the individual fluid phases. However, for dispersed flow, the presence of additional fluid phase is incorporated by employing the effective Reynolds number and effective Prandtl number. Using this methodology, more than 85% of stratified flow and 92% of dispersed flow heat transfer characteristics are predicted within +/- 20% of experimental data.",0,0,1
Heat Transfer,,"Alan, Cihan; Cinar, Murat",Interpretation of temperature transient data from coupled reservoir and wellbore model for single phase fluids,Temperature transients; Numerical simulation; Well testing; Parameter estimation; History matching; Sensitivity analysis,WATER GEOTHERMAL-RESERVOIRS; HEAT-TRANSFER; PRESSURE; BEHAVIOR; DRAWDOWN; SKIN,"This paper presents a non-isothermal, transient coupled reservoir/wellbore model that accounts for the JouleThomson (J-T), isentropic expansion, conduction and convection effects for predicting the transient temperature behavior and computing the wellbore temperature at different gauge depths. In this study, single phase fluid flow of oil or geothermal brine from a fully penetrating vertical or inclined well in an infinite-acting homogeneous single layer reservoir is modeled. The coupled simulator solves mass, momentum and energy conservation equations simultaneously for both reservoir and wellbore. We improve solutions by the functional iteration procedure that updates fluid properties based on available correlations as a function of pressure and temperature at a given time step. A comparison of the developed model with a commercial simulator is provided. To understand and identify diagnostic characteristics of temperature transients at gauge locations at the sandface and above the sandface that may arise during a well test, we examine the sensitivity of the model parameters appearing in the coupled non-isothermal reservoir/wellbore model through a synthetically generated test data sets and history matched field application. The drawdown and buildup sandface transient temperature data are obtained from the coupled model and used to interpret and analyze temperature transients. In addition to the J-T coefficient of fluid, history matching transient temperature data provides estimates for the skin zone radius and permeability when analyzed jointly with the conventional pressure test analysis (PTA). An investigation on the effect of gauge location on temperature data shows that the early-time response is influenced by the wellbore phenomena while the J-T effects are clearly identified at later times at typical gauge locations up to 100 m above the top of the producing horizon. Logarithmic derivative of temperature transients are found as a useful diagnostic tool to differentiate the wellbore phenomena from the reservoir response. It is also shown that the temperature transient is more reflective of the properties of the near wellbore region (e.g., skin zone) than the pressure transient. For this reason, analyzing temperature transients together with the pressure transients could add more value to the analysis to better examine near wellbore characteristics.",0,0,2
Heat Transfer,,"Eghbali, Sara; Banks, Jonathan; Nobes, David S.",A numerical study on compositional modeling of two-phase fluid flow and heat transfer in vertical wells,Two-phase flow; Pressure drop; Heat transfer; Geothermal energy; Equation of state; Vertical well,,"Geothermal energy is a sustainable and renewable source that can be extracted by circulating a single- or two-phase fluid through a geothermal well system. Two-phase flow and heat transfer models are required for predicting pressure and temperature profiles in oil, gas, and geothermal wells. We model fluid flow, thermodynamics and heat transfer in an idealised vertical well for single-(i.e., water) and two-phase fluid mixtures (CO2-, and air-water) under a bubbly flow regime. First, we calibrated a Peng-Robinson Equation of State (PR-EOS) for CO2-, and air-water systems. Second, we solved continuity, energy and momentum equations and modelled transient conductive heat transfer through the well. Third, we investigated the effects of mass flow rate, transient heat transfer, single- and two-phase fluid on the extracted power, temperature, and pressure profiles of the deep well bore heat exchanger. The results show that the temperature of the hot fluid decreases as it flows to the surface both in the case of adiabatic flow and in cases with heat loss. The mass flow rate controls the fluid temperature drop during its ascent to the surface. The production pressure of a gas-liquid phase system is higher than that of a system with single liquid phase at the same injection pressure, temperature, and mass flow rate. Increasing mass flow rate up to a threshold value leads to an increase in the production pressure. Above the threshold mass flow rate (i.e., 7 kg/s in this study), the production pressure reduces because of the significant increase in the frictional pressure drop. Production temperature, production pressure, and total power increases over time due to the local heating around the production well and reduction of the heat loss.",0,0,2
Heat Transfer,,"Nie, Bin",Circulating preheating model of full-length horizontal wellbore in heavy oil reservoirs with multiple thermal fluid injection,Heavy oil reservoir; Vertical wellbore and horizontal wellbore; Superheated multi-element thermal fluid; Cyclic preheating model; Numerical model,STEAM INJECTION; THERMOPHYSICAL PROPERTIES; CARBON-DIOXIDE; CO2 INJECTION; HOT-WATER; FLOW; TEMPERATURE; WELLS; LOSSES,"Heavy oil reservoirs are rich in resources and have broad prospects for exploration and development. Wellbore heat transfer is one of the important areas of heavy oil research. However, the current research on the preheating of multi-element thermal fluid circulation in the wellbore is still insufficient. Based on thermodynamic equations and fluid dynamics equations, this paper establishes a cyclic preheating model of multi-element thermal fluid in the wellbore. The model considers the mixing characteristics of superheated steam and non-condensed gas, and is applicable to both vertical and horizontal wellbores. Results show that the temperature curve can be divided into four parts: the temperature of the inner tube in the vertical section of the wellbore, the temperature of the inner tube in the horizontal section of the wellbore, the temperature of the annular space in the horizontal section of the wellbore, and the temperature of the annular space in the vertical section of the wellbore; In the horizontal section of the wellbore, the multi-element thermal fluid in the inner tube releases heat energy into the annular space, and there is a large temperature difference at the heel end and a small temperature difference at the toe end.",0,0,2
Heat Transfer,,"Zheng, Lei; Nian, Yong-Le; Zhao, Rui; Cheng, Wen-Long",Prediction of multi-reservoir production for water injection well by using temperature logging data,Multi-reservoir production; Water injection well; Heat transfer model; Temperature logging data; Stochastic approximation method,HEAVY OIL; NUMERICAL-SIMULATION; PRODUCTION FORECAST; POROUS-MEDIA; FLOW-RATE; RECOVERY; MODEL; EXTRACTION; SYSTEMS,"In most cases, oil wells are completed and perforated to produce from multiple reservoirs. Thus, it is crucial to monitor production from each individual reservoir. Therefore, a new prediction method for multi-reservoir production by using temperature logging data is presented in this paper. Firstly, by coupling the wellbore and formation heat transfer with reservoirs heat transfer, a new comprehensive heat transfer model for the oil well with multiple reservoirs is established in this paper. Both the heat convection of two-phase flow in reservoir and vertical heat transfer between different reservoirs was considered in the model, and the relationship between flow rate distribution and temperature distribution could be specified by the model. Then based on the model, the stochastic approximation method was proposed to predict the multi-reservoir production through the temperature logging data. Lastly for a water injection well with five layered reservoirs and depth of 3500m, the production of each reservoir was predicted by the presented method. The results show that the temperature distribution simulated by the built model has a good agreement with the reference data. The estimation error of the total flow rate is less than 9% compared with the reference data, and the production of the five reservoirs accounted for 36%, 35%, 17%, 7% and 5% of the total production respectively.",0,0,2
Data Assimilation,,"Oliver, Dean S.",Information content in 4D seismic data: Effect of correlated noise,Time-lapse seismic; 4D seismic; History matching,DATA ASSIMILATION; OBSERVATION ERRORS; SHANNON ENTROPY; MODELS,"Several types of data used in history matching for subsurface reservoir characterization have errors that are spatially or temporally correlated. Although it is often assumed that correlated observation errors decrease information content, using a simplified flow problem, we show that for data that are spatially dense (such as 4D seismic data), correlated observation errors result in higher information content than data with similar levels of errors, but without correlation. Unfortunately, correlations in the observation error are often unrecognized and difficult to estimate, especially if the correlation scale of the errors is similar to a characteristic length of the signal. In addition, many history matching algorithms are incapable of accounting properly for correlated observation error, so data are either thinned or the observation error is inflated to partially account for the lack of proper treatment. We show that neglecting correlations in the observation errors or inflating the variance, result in loss of information content. Finally, we show that it is possible to iteratively estimate the correlated observation errors through analysis of residuals after history matching.",0,0,0
Data Assimilation,,"Silva, Thiago M. D.; Pesco, Sinesio; Barreto, Abelardo, Jr.",Influences of the inflation factors generation in the main parameters of the ensemble smoother with multiple data assimilation,Ensemble smoother with multiple data; assimilation; Ensemble-based methods; Singular values; Discrepancy principle; History matching,LEVENBERG-MARQUARDT SCHEME; PERFORMANCE,"The generation of the ensemble smoother with multiple data assimilation (ES-MDA) inflation factors has been the focus of several recent studies. These factors must be selected such that the sum of their inverses is equal to one. It guarantees the ES-MDA to correctly sample the posterior probability density function in the linear Gaussian case when the ensemble size goes to infinity. Concurrently, recent researches have shown a relationship between inflation factors and the final ensemble estimates quality. They have also suggested techniques to generate these factors based on methods derived from the discrepancy principle. However, a procedure to efficiently generate ES-MDA inflation factors remains an open problem. Additionally, the studies diverge on what regularization method suffices to produce ES-MDA inflation factors that provide optimal final results. Therefore, this study presents an investigation of the generation of ES-MDA inflation factors. Two main paths will be investigated: selecting them constant, equal to the number of assimilations, and in a geometrically decreasing order. When selecting them geometrically, two techniques will be used to generate the first inflation factor: the regular discrepancy principle and a Levenberg-Marquardt regularization scheme. The main objective of this study is to examine the error propagation during the multiple data assimilation of the ES-MDA and the estimates' quality, considering only the generation of the inflation factors. Moreover, we numerically analyze their influence on the ES-MDA ensemble size and number of assimilations and how their choices affect the ES-MDA performance. The method will be evaluated in a synthetic two-dimensional history matching problem of waterflooding.",0,0,0
Data Assimilation,,"Danaei, Shahram; Silva Neto, Gilson M.; Schiozer, Denis J.; Davolio, Alessandra",Substituting petro-elastic model with a new proxy to assimilate time-lapse seismic data considering model errors,4D seismic; Petro-elastic model; Data assimilation; ES-MDA; Model error,SATURATION CHANGES; OBJECTIVE FUNCTION; PRESSURE; FIELD,"Dynamic data from oil and gas reservoirs (such as well-production or 4D seismic data) have been used often to reduce uncertainty in reservoir simulation models. These data are assimilated in the simulation models separately or jointly. Assimilation of 4D seismic data conventionally involves with a petro-elastic model (PEM) to transform outputs from the simulation models to elastic properties. The PEM is a set of different equations with uncertain parameters and its inclusion in assimilation algorithms calls on multidisciplinary teams of geoscientists and engineers. Moreover, PEM requires extraction of different outputs from the simulation models for the seismic forward model calculations. The extraction process can be costly for large-scale simulation models of giant reservoirs. This research presents a new petro-elastic proxy model (named DAI-Proxy) with a novel formulation to substitute the PEM and integrate 4D seismic data. DAI-Proxy relates time-lapse acoustic impedance to a summation of saturation and pressure changes with two coefficients which are functions of porosity. As the proxy is an approximation of the PEM, its application is affected by model error. We introduce two approaches to account for the proxy model error: (1) considering uncertain coefficients for the DAI-Proxy and (2) using fixed coefficients in the proxy while estimating model errors statistics from the prior ensemble of models. We incorporate these two approaches with a data assimilation algorithm to assimilate simultaneously 4D seismic and well-production data. A benchmark case is used with different cases of data assimilation to compare the DAIProxy and the PEM applications. Results show that data match quality for 4D seismic and well-production have similar responses for the PEM and DAI-Proxy implementations. In terms of production forecast, using fixed coefficients in the proxy with its model error treatment create a data assimilation framework comparable to the PEM case. Our results indicate that the traditional PEM application to integrate jointly 4D seismic and wellproduction data can be replaced with our new DAI-Proxy application. Given the degree of uncertainty in the PEM, related to the rock and fluid models, our proxy provides similar results with fewer uncertain inputs. The proxy offers further advantage as it needs less outputs from the simulation models for seismic forward model calculations. In addition, it helps petroleum engineers to use a computationally less expensive model (light model) as a substitute for the PEM to assimilate 4D seismic data.",0,0,1
Data Assimilation,,"Yang, Shikai; Yang, Daoyong",Integrated characterization of wormhole network by use of a modified pressure-gradient-based (PGB) sand failure criterion and ensemble-based history matching during CHOPS processes,Wormhole network; Cold heavy oil production with sand; Pressure-gradient-based sand failure criterion; Ensemble-based history matching; Upscaling,RELATIVE PERMEABILITY; HEAVY-OIL; KALMAN-FILTER; CAPILLARY-PRESSURE; TIGHT FORMATIONS; DATA ASSIMILATION; MODEL; RESERVOIR; FLOW; QUANTIFICATION,"In this paper, a damped iterative ensemble Kalman filter (IEnKF) technique has been developed and integrated with a recently modified pressure-gradient-based (PGB) sand failure criterion to implicitly and inversely characterize the dynamic wormhole network during cold heavy oil production with sand (CHOPS) processes. With an improved upscaling process, not only has a microscopic PGB sand failure criterion been properly upscaled to the grid-scale simulation, but also it can be dynamically, implicitly, and inversely determined. Then, such a sand failure model together with three-phase relative permeability is validated and applied to reproduce wormhole network in a laboratory experiment conditioned to its sand production profile. Good agreements between the observed and simulated cumulative production profiles including oil, gas, and sand have been achieved with satisfactory convergence by integrating the ensemble-based history matching method. The simulated wormhole network has shown its great similarity to the experimental observations, while the convergence of the ensemble based history matching algorithm is greatly improved with a widespread of initial ensembles in each grid. Furthermore, deviations between the observed and updated production profiles can be significantly minimized by dividing the entire production period into three sequential stages, each of which has its distinct relative permeability curves due to the major effect (i.e., foamy oil flow, sand failure, and slurry flow) on its multiphase flow behaviours, respectively. By integrating the ensemble-based sand failure model with the damped-IEnKF method, the dynamic wormhole network during a CHOPS process can be accurately characterized with satisfactory convergence, demonstrating its robustness and practicality of dynamically and inversely simulating the preferential wormhole network. Such an ensemble-based sand failure model can be seamlessly incorporated with any commercial reservoir simulators under various conditions.",0,0,1
Data Assimilation,,"Zhang, Yanhui; Hoteit, Ibrahim; Katterbauer, Klemens; Maucec, Marko; Marsala, Alberto F.",Feature-based ensemble history matching in a fractured carbonate reservoir using time-lapse deep electromagnetic tomography,History matching; Ensemble methods; Adaptive localization; Distance parameterization; Fractured carbonate reservoir; EM tomography,DISTANCE PARAMETERIZATION; FIELD MODEL; ASSIMILATION; FRAMEWORK,"Carbonate reservoirs typically exhibit very complex geological structures and are characterized by flow dynamics primarily occurring in fractures. The intricate network of fractures as well as their interconnectedness may lead to unexpected flow patterns and uneven sweep efficiency. Determining reservoir properties of both matrix and fracture channels is quintessential for accurately tracking the fluid front movement in the reservoir, optimizing sweep efficiency, and maximizing hydrocarbon production. In this study, we showcase the application of a feature-oriented ensemble-based history matching workflow to a complex fractured carbonate reservoir box model, focusing on the use of formation resistivity tomography data that are usually inferred from deep crosswell electromagnetic (EM) surveys. Compared with the production data that are commonly used in history matching, deep EM measurements provide additional information about the spatial distribution of subsurface reservoir properties in the interwell volumes by exploiting the strong resistivity contrast between water and hydrocarbons. A hybrid parameterization approach is used to represent the multiscale fracture distribution in which the spatial distribution of small-scale fractures is modelled by a truncated Gaussian simulation method. A large number (over one million) of uncertain model parameters including reservoir matrix and fracture properties as well as Archie's parameters are identified and updated by an iterative ensemble smoother. For an efficient integration of the high-dimensional and noisy EM tomography data, the boundary or contour information extracted from the EM resistivity field is instead assimilated through a distance parameterization approach. A modified bootstrapbased localization is proposed to regularize the model updates adaptively during the iteration to reduce sampling errors. Especially, to improve the computational efficiency in dealing with the large dimensions of both data and model parameters, the localization is implemented in a projected low-dimensional data subspace. Experimental results demonstrate the applicability and efficiency of the developed workflow for reservoir history matching in more realistic model settings. The comparative case study also illustrates the significance of jointly incorporating multiple sources of data for better quantification of model uncertainty, and the great potential of deep EM data for enhancing the characterization of complex fractured carbonate reservoirs.",0,0,1
Data Assimilation,,"Maschio, Celio; von Hohendorff Filho, Joao Carlos; Schiozer, Denis Jose",Methodology for data assimilation in reservoir and production system to improve short- and medium-term forecast,Data assimilation; Uncertainty reduction; Integrated production system; Production forecast,,"Numerical reservoir simulation is an important tool that is widely used in the petroleum industry for production forecast and decision-making processes. In a context of integrated production system involving the reservoir, wells, and production facilities, the quality of production forecast depends not only on the quality of reservoir models and well productivity/injectivity but also on the boundary condition for the future extrapolation which, in turn, depends on the production system characteristics. Both systems, reservoir and production facilities, are characterized by uncertain properties and behavior, such as porosity and permeability, among others, for reservoir; pipeline roughness, multiphase flow behavior in pipes, among others, for the production system. This paper proposes a methodology for dynamic data assimilation to reduce uncertainty in both reservoir and production system models to improve short- and medium-term production forecast. The methodology was applied to a benchmark case built using real data from an offshore field in The Campos Basin (Brazil). The results from this study show that it is important to perform data assimilation process in both reservoir and production systems to obtain more reliable production forecasts. We also show that, by focusing on the short- and medium-term production forecast, the production system and reservoir uncertainties cause variability in the production forecast in the same order or magnitude. Based on that, it is recommended to consider multiple solutions of the production system to obtain more realistic production forecasts.",0,0,1
Data Assimilation,,"Neto, Gilson M. Silva; Davolio, Alessandra; Schiozer, Denis J.",Assimilating time-lapse seismic data in the presence of significant spatially correlated model errors,Model calibration; Ensemble data assimilation; Iterative ensemble smoothers; History matching; Model errors; ESMDA,DISCRETE LATIN HYPERCUBE; ENSEMBLE SMOOTHER; HISTORY,"Time-lapse seismic data is becoming a common information source in reservoir model calibration workflows to improve production forecasts. The standard process compares a forward model's results with the observed data to update the model's parameters from the existing deviations. Ensemble-based methods are popular choices for this process. However, the so-called forward model is always a simplification of the real phenomena. These simplifications may significatively influence the relation between simulated and observed data and possibly yield inconsistent updates of the parameters and uncertainty underestimation. In the conventional approach for this problem, the so-called strong-constraint formulation neglects the model's limitations, causing unphysical updates of the parameters to reduce the distance between simulated and observed data. In this work, we propose a methodology to apply a weak-constraint formulation to the time-lapse seismic data assimilation to mitigate the above problem. We consider the forward model error with an additive term and update it during the data assimilation workflow. By adopting this approach, we reduce the impact of the model errors in the calibrated parameters. Also, the proposed methodology handles model bias as a type of general model error. The inclusion of the additive term weakens the updates of the model due to the time-lapse seismic data. We show that this procedure significantly benefits the data assimilation results when there are substantial spatially correlated model errors, and it has a minor impact when applied to a low-error case. We apply the proposed method to assimilate time-lapse seismic data using the Ensemble Smoother with Multiple Data Assimilations in a simple 2D case and in a realistic benchmark synthetic case based on a real offshore reservoir. In the former case, we consider model error related to the pressure sensitivity in the petroelastic model. In the latter, we consider a realistic synthetic time-lapse seismic and the correlated errors result from seismic modeling and inversion. Moreover, in the latter, we also assimilate well data. The results indicate that our methodology improved the reservoir characterization and the production forecast using relatively low-resolution time-lapse seismic data.",0,0,2
Data Assimilation,,"Rollmann, Klaus; Soriano-Vargas, Aurea; Cirne, Marcos; Davolio, Alessandra; Schiozer, Denis Jose; Rocha, Anderson",A three-way convolutional network to compare 4D seismic data and reservoir simulation models in different domains,History-matching; 4D seismic data; Simulation models; Deep learning; Data assimilation; 3-way deep neural network,NEURAL-NETWORKS; HISTORY; PARAMETERIZATION,"Four-dimensional seismic (4DS) contains spatial information that provides insights into the location, shape, and movement of fluids (oil, gas, water). It helps engineers to adjust reservoir simulation models and increase their capability of providing reliable production forecasts. Recent probabilistic approaches consider hundreds of numerical simulation model scenarios, which require automated methods to evaluate this large number of numerical models based on observed 4D seismic data. Comparing spatial information of seismic and numerical simulation data is difficult as, usually, these data are converted to maps with different properties. We propose a novel approach to compare 4D seismic data and simulation models using a three-way deep neural network that is trained using a reference image (4D seismic data) with two simulation model candidates. It learns to find the simulation models that best characterize the reference. Our method is underpinned by more than a thousand pairs of simulation models and reference maps evaluated by human specialists for training. For testing, we compare the inter-rater agreement among different specialist groups and generate a reliable test set considering examples in which there was agreement among at least two specialists. We observed that the group with best-trained specialists agree more in their answers and have a considerably higher inter-rater agreement than the less trained groups. When we evaluate our method with the answers from this specialized group, we observe that the simulation model chosen by our method is the one agreed by the specialists in almost 90% of the cases. We also discuss the impact of different noise levels in the input and show that our method outperforms other approaches in the literature if noise is present both in the training and test sets.",0,0,2
SAGD,,"Gao, Yanfang; Ren, Zhanli; Chen, Mian; Jiang, Hailong; Ding, Shuaiwei",Coupled geomechanical-thermal simulation for oil sand reservoirs with shale barriers under hot water injection in vertical well-assisted SAGD wells,Oil sands; Shale barriers; Geomechanical-thermal simulation; Vertical well; SAGD,PROPAGATION BEHAVIOR; PERMEABILITY CHANGES; RECOVERY PROCESSES; MODEL; TEMPERATURE,"Mudstone stringers in an oil sand reservoir can significantly affect the propagation of the steam chamber in the process of steam-assisted gravity drainage (SAGD). The micro-fracturing by water injection in strongly heterogeneous oil sands can result in these problems such as hard stringer breakthrough and aggravating heterogeneity. This paper proposed a comprehensive numerical model for conventional SAGD wells and vertical well-assisted SAGD (VWA-SAGD) wells to predict the coupled thermo-hydro-mechanical responses under hot water injection in a typical Karamay oil sand reservoir with two stringers, considering skeleton shear dilation, the ""phase change"" of bitumen, formation heterogeneity, the permeability evolution induced by elastoplastic deformations, and the theory of heat and mass transfer. Major conclusions were drawn that there are three relatively narrow separate transition zones effectively heated around the SAGD wells and vertical well. The vertical well makes about 0.5 MPa increase to the pore pressure of the reservoir embedded with mudstone stringers in vertical directions and rises by about 0.6 MPa for the reservoir pore pressure above the upper stringer to reduce the pore pressure differential along the wellbore. Water injection-induced ultimate stress states can't reach the shear failure line under field operations, so the shear dilation can't be induced. The thermoporoelastic deformation determines whole reservoir deformation. The reservoir between the two stringers contributes to most of the caprock uplift. The VWA-SAGD technique can improve the porosity by about 1% in the whole vertical direction and reduce the anisotropy of porosity along the wellbore, which is beneficial to the uniform and fast propagation of the steam chamber in subsequent preheating and production stages. These findings can be employed to accurately predict the temperature, pore pressure, stress/displacement, and porosity evolutions for the field engineers to properly evaluate the uplift of reservoir and caprock, oil output changes, and heat utilization efficiency.",0,0,0
SAGD,,"Abou-Kassem, Abdulla J.; Sidahmed, Anas; Kotb, Omar; Haftani, Mohammad; Nouri, Alireza",Integrated wellbore-reservoir simulations to design sand retention tests for flowback scenarios in SAGD injection wells,SAGD injector flowback; Injector SRT; Slotted liner design; SAGD completion; Sand control testing,,"In the past, sand retention testing (SRT) research for steam-assisted gravity drainage (SAGD) injector was a parametric study, or general solution, rather than a case-specific solution for a particular problem in terms of testing parameters. Testing parameters were assigned based on hypothetical assumptions due to a lack of necessary field data to perform such a study. Field data are often confidential and nearly impossible to obtain for a hazardous scenario like a thermal injector flowback. The literature is rich with multiple proposed slotted liner (SL) design criteria for SAGD production wells. The SRT designed for SAGD producer takes into consideration some measurable factors to specify suitable aperture size. In contrast, SRT for the SAGD injector seems to rely on industry experience or rules of thumb. A systematic methodology, consisting of three steps, was developed for SL design using the SRT setup for SAGD injector wells. The first step involves estimating the laboratory testing variables or operational parameters based on case-specific data and reservoir simulations to assess the consequences of steam flowback. A 2D Computer Modelling Group (CMG) thermal simulator was coupled with gas flow correlation and used to predict the outcomes of SAGD injector flowback. The second step involves developing a new SRT setup dedicated to SAGD injector flowback laboratory testing. Intensive testing was performed to troubleshoot the problems associated with a high-velocity gas flow. The third and final step involves conducting six tests to verify the developed setup's performance. The consideration of thermodynamic equilibrium improved testing by avoiding inconsistent assumptions used in the previous studies. Neither low steam quality (SQ) nor high SQ flowback scenarios used in the past are found to fully represent SAGD injector flowback. SAGD injector depth and other operational parameters are linked to flowback differential pressure. In other words, one set of testing parameters cannot be representative for all SAGD injector, which makes developing design criteria a challenge. The preliminary results of SRT for SAGD injector indicate the possibility of using small aperture size slots of 0.010 inch that do not cause significant permeability reduction at laboratory scale, unlike the case for SAGD producer SRT. This may justify why the industry tends to prefer small aperture size slotted liner for SAGD injector completion. Eventually, this research should be considered as a first step only in SRT for SAGD injector flowback, and necessary methodology enhancements and facility upgrades should be investigated in future work.",0,0,0
SAGD,,"Zhang, Shengfei; Li, Xiuluan; Jiang, Youwei; Zhang, Zhongyi; Sun, Xinge; Wang, Hongzhuang",Physical modeling of nitrogen slug operation in Xinjiang SAGD projects-Fundamental roles of NCG in SAGD process,Non-condensable gas; Slug injection; Partial pressure; SAGD; Gas production; Gas fingering,GRAVITY DRAINAGE; STEAM; PREDICTION,"Non-condensable gas (NCG) co-injection in mature Steam Assisted Gravity Drainage (SAGD) chamber had been widely implemented and significant amount of steam was saved. Encouraged by their performance, NCG SAGD was also tested in Xinjiang oilfield since 2012. Its strategy differed from others in that nitrogen slug was injected once per year since the early SAGD stage. However, its performance was quite mixed. A unique 2D model was used to mimic the field operation of SAGD and NCG SAGD. The general performance, temperature drop, pressure oscillation, gas fingering and gas coning were analyzed. It showed non-condensable feature of NCG lead to gas accumulation and pressure oscillation in NCG slug operation. Its partial pressure effect lowered down temperature, saving steam but reducing oil rate, potentially leading to gas coning issue. The main purge mechanism was gas solubility in water and oil which controlled the NCG concentration inside the steam chamber. NCG fingering was found to speed up vertical growth of steam chamber in the early SAGD stage. However, injecting NCG before chamber getting mature should be treated with caution. Lastly, NCG was recommended to inject through vertical well to the top of the formation.",0,0,0
SAGD,,"Lyu, Xiaocong; Liu, Huiqing; Tian, Ji; Zheng, Qiang; Zhao, Wei",Influence of top water on SAGD steam chamber growth in heavy oil reservoirs: An experimental study,Steam-assisted gravity drainage (SAGD); Steam chamber; Top water; Heavy oil; Experiments,ASSISTED GRAVITY-DRAINAGE; NUMERICAL-SIMULATION; RECOVERY; PERFORMANCE; FOAM,"Steam-assisted gravity drainage (SAGD) is one efficient and mature technology for recovering heavy oil and bitumen resources. The key underlying mechanism is the growth of the steam chamber after injecting steam. However, due to the complex geological environment, the thief zones exist and have a prejudicial effect on the development of the steam chamber, thus impacting the ultimate heavy-oil recovery. In this work, our objective is to investigate the effect of a top-water thief zone (i.e., water zone overlies the oil sand) on SAGD performance and further to understand the crucial mechanisms that control the heat loss during steam injection. A large-scale three-dimensional experimental apparatus is used to carry out the SAGD process with a top aquifer. Based on the similarity criterion, the field-scale model is transformed into a laboratory elemental model. To evaluate the SAGD performance quantitatively, the dynamic growth of the steam chamber is measured using the thermal detectors and the production data is recorded. The results show that the steam chamber exhibits three distinguished stages, that is, upward spread, lateral extension, and downward development in the presence of top-water zone. The bottom-water zone has less impact on the steam-chamber growth. The existence of a confined top-water zone, however, significantly affects SAGD performance, especially the lateral expansion of the steam chamber. The lateral propagation of the steam front is hindered by the top thief zone due to the heat exchange with the top water. Once the steam chamber reaches the boundary, the accumulation of energy in the water thief zone, in turn, can reduce the remaining oil saturation along the topwater-oil interface. This study provides us some key insights into the development of heavy oil resources with top thief zones when implementing SAGD technology.",0,0,0
SAGD,,"Sheikha, Ammar; Sheikha, Hussain",Top lean zone and cardinal parameters affecting SAGD,SAGD; Thermal EOR; Lean zone; High water saturation; Oil sands; Long Lake pilot; Surmont pilot,,"SAGD is a thermal recovery process in which steam oil ratio, SOR, is a key parameter that can affect the economic outcome of the process. Reservoirs with underlying or overlying lean bitumen present challenges for SAGD as they can act as a heat sink. Water has higher heat capacity than the bitumen and thus requires more steam to heat up the reservoir leading to higher SOR. The potential outcome of operating SAGD in these conditions may be lower bitumen rate and higher steam injection rate, both of which affect plant throughput and thus the economic matrix of SAGD. This paper looks at the performance of SAGD process in the presence of top lean bitumen. It will examine the theoretical CSOR that is needed to produce the bitumen with different water saturations and will highlight the key parameters of lean bitumen affecting SAGD performance. The paper reviews performance of several fields where lean bitumen is present. The paper also analyzes simulation results to examine the impact of water saturation and the size of lean bitumen resource on the SAGD process.",0,0,1
SAGD,,"Guevara, J. L.; Patel, Rajan; Trivedi, Japan",Optimization of steam injection in SAGD using reinforcement learning,Reinforcement learning; SAGD optimization; SARSA; Function approximation,MODEL-PREDICTIVE CONTROL,"Conventional steam injection strategies or policies in SAGD are typically not a result of a formal optimization process but rather empirically found. However, finding the steam injection policy that maximizes cumulative performance over the entire production horizon represents a major challenge due to the complex dynamics of the physical phenomena. To address this challenge one alternative is to use a reinforcement learning (RL) approach; here an agent is trained to find the optimal policy only by continuous interactions with the reservoir simulation model (environment). In this work, the RL-SARSA on-line on-policy learning algorithm is used to find the optimal steam injection policy and offer insight in the physics of the SAGD process. Net Present Value (NPV) is used as a performance measure of objective function, the action-value function is approximated using a stochastic gradient regression strategy, and the state vector is featurized using radial basis kernels. The action space is discrete, three (3) possible actions: increase/decrease/no change on the steam injection rate w.r.t the previous value, and the state space is continuous and is made up of cumulative values for water and oil production and steam injection. Additionally, the environment is represented by a one well pair reservoir simulation model built using data from a reservoir located in northern Alberta and a production horizon of 250 days is considered. For the considered case study, the agent showed a significant improvement on the cumulative NPV value after 200 episodes or simulations and the optimal policies are characterized by three distinct regions, (1) constant rate to increase the average reservoir pressure and allow the steam chamber reach the overburden, (2) sharp increase to increase average reservoir temperature and abrupt decrease and (3) constant minimum value to maintain the average reservoir temperature.",0,0,2
SAGD,,"Monteiro, Lua; Baptista-Pereira, Catarina; Azevedo, Leonardo",Sensitivity analysis of injection parameters in steam assisted gravity drainage under geological uncertainty,Steam-assisted gravity drainage; Heavy oil; Sensitivity analysis; Geological uncertainty; Reservoir simulation; Optimization,OPTIMIZATION; SAGD; OIL; SIMULATION; RESERVOIR,"Steam-assisted gravity drainage (SAGD) is a challenging enhanced oil recovery technique that requires proper parameterization in terms of well geometry and steam injection parameters as these parameters are highly dependent on the reservoir geology and fluid characteristics (e.g., net pay variation, water saturation). Injection rate and pressure, temperature, steam quality, lean zone, gas zone, water saturation, and wellbore hydraulics are among the most important engineering parameters of SAGD. This work focuses in the sensitivity analysis under geological uncertainty of some operational parameters, such as: injection rate, temperature, steam quality and pressure. To reach this objective we build a realistic reservoir model with multiple geological settings and descriptions. Moreover, two complementary approaches were studied: i) a deterministic sensitivity analysis relying on a factorial design matrix and ii) a stochastic analysis using particle swarm optimization. There are several key geological uncertainties in SAGD, such as net pay variation, inclined heterolithic stratification (IHS) presence, high water saturation in reservoirs, bottom water issues, and gas cap problems. This work focuses on the role of porosity and permeability in oil production, as these impact these geological properties. To reach this objective, two specific groups of ten different porosity and permeability pairs of geostatistical realizations were generated using Direct Sequence Simulation and Co-simulation. Group 1 used the same variogram model for 10 random seeds; and Group 2 used a combination of values that adopted a simultaneous and a random variation, which were assigned to the seed and to the variogram. We opted by a reservoir model that mimics an anticlinal reservoir, as it proved to be a determining factor for the low levels of Net Present Value (NPV) when compared to other geological scenarios. Within the four most commonly studied parameters in SAGD projects, the association of deterministic versus stochastic multi-objective analysis allowed to accurately validate injection rate as the most relevant parameter. Regarding the geological uncertainties, Group 1 showed that for a certain porosity distribution and permeability orientation, the random origin of these distribution maps eventually attributed a higher NPV uncertain. On the other hand, in Group 2, the simultaneous spatial and seed variation provided less uncertainty associated to NPV.",0,0,2
SAGD,,"Liu, Hao; Xiong, Hao; Rao, Xiang; Huang, Desheng",Rising-phase performance evaluation of Expanding-Solvent SAGD: Considering the horizontal-wellbore effect,,ASSISTED-GRAVITY-DRAINAGE; HEAVY-OIL; STEAM INJECTION; ISENTHALPIC FLASH; BITUMEN; MODEL; COINJECTION; SIMULATION; SYSTEMS; WELLS,"Expanding-Solvent Steam-Assisted Gravity Drainage (ES-SAGD) is proposed to develop the oil sands more efficiently than conventional SAGD. Even in the rising phase when the steam hasn't reached the overburden, the heat-mass transfer in the wellbore can be one of the reasons for the non-uniform chamber growth of ES-SAGD along the horizontal well. Furthermore, the time and oil production during the rising phase greatly determine the final benefits of the ES-SAGD. In this study, a mathematical method is established to evaluate the performance of ES-SAGD in the rising phase. The calculated results show that: pentane can help increase the oil rate in the rising phase significantly, while the effect of heptane is not quite obvious. Although propane is also a widely used solvent, the oil rate with it is even lower than that of conventional SAGD. The differentials between the cases, which consider the wellbore or not, is different for different solvent-steam co-injections. Specifically, the oil rate differential between the situations considering the wellbore effect or not for propane-SAGD is the highest and is almost twice that of conventional SAGD which has the least differential. Pentane-SAGD has the second-largest differential which is followed by heptane-SAGD. Therefore, for the sake of a more accurate evaluation of ES-SAGD performance in the chamber rising phase, the effects of solvent diffusion into the bitumen and the heat-mass transfer in the wellbore should be comprehensively considered.",0,0,3
Cretaceous,,"Kiani, Arad; Saberi, Mohammad Hossein; ZareNezhad, Bahman; Mehmandosti, Elham Asadi","Reservoir zonation in the framework of sequence stratigraphy: A case study from Sarvak Formation, Abadan Plain, SW Iran",Sarvak Formation; Sedimentary environment; Diagenesis; Electrofacies; Flow unit; Reservoir quality,FOLD-THRUST BELT; CENOMANIAN-TURONIAN CARBONATES; PALAEO-EXPOSURE SURFACES; DEZFUL EMBAYMENT; ZAGROS BASIN; OIL-FIELD; DEPOSITIONAL ENVIRONMENT; METEORIC DIAGENESIS; ASMARI RESERVOIR; ILAM FORMATION,"Located in the northeast of the Arabian Plate, Zagros Basin hosts some of the most significant hydrocarbon reservoirs in Iran, including the Sarvak Formation. It has been dated back to the Middle Cretaceous and exhibits a dominantly carbonate lithology. In this study, petrographic and petrophysical data of the Sarvak Formation were analyzed. The results of the petrographic study showed that the formation was deposited in a homoclinal carbonate-ramp depositional environment and exposed to diagenetic processes in three depositional environments: marine, meteoric, and deeply buried environments. The stratigraphic modified Lorenz plot (SMLP) method was used to distinguish between the reservoir and non-reservoir zones. By integrating the petrographic and petrophysical findings, stratigraphic relationships among the identified zones were assessed. Accordingly, three third-order sedimentary sequences were identified on the Middle Cenomanian-to-Middle Turonian section within the studied formation. Two disconformities were detected in the Upper Sarvak, namely Cenomanian-Turonian disconformity (CTD) and Middle Turonian disconformity (MTD). The highest-quality reservoir zones were related to the CTD. The porosity resulted from the karstification, meteoric diagenesis, and significant dissolution beneath the CTD was found to have greatly increased the reservoir quality. Later on, however, the sediments were overmatured under the impact of the MTD, which is known to take a long time to occur, with their porosity largely decreased, ending up with a much lower reservoir quality. In general, the sedimentary facies were found to be the most important factors controlling the distribution of the reservoir zones across the Sarvak Formation, followed by the diagenetic processes. The findings provided an insight into the factors controlling the reservoir quality in the Sarvak Formation within the study area and the Arabian Plate.",0,0,0
Cretaceous,,"Heydarzadeh, K.; Hajialibeigi, H.; Gharabeigli, G. R.",Structural geometry and evolution of the Dehdasht Basin in the Central Zagros fold-and-thrust belt: Implications for the timing of oil generation and trap formation,Sequential restoration; Evaporitic detachment; Anticlinal trap; Source rock maturation; Dehdasht structural basin; Central zagros,SOURCE-ROCK EVALUATION; DEZFUL EMBAYMENT; FORELAND BASIN; ASMARI FORMATION; SW IRAN; TECTONICS; DEPOSITS; SEEPAGE; MIOCENE; MAGNETOSTRATIGRAPHY,"Structural analysis and temporal evolution of the Dehdasht Structural Basin in the Central Zagros through the constructed cross-sections and 2D sequential restoration have defined the timing of trap formation in the basin. At the level of the competent layer (Early Cretaceous to Oligo-Miocene), the basin is deeper toward the center where it is covered by the thicker Miocene evaporites and syn-tectonic clastic deposits. The evolutionary history of the basin based on the sequential restoration proposes that the anticlinal traps are formed since the Pabdeh deposition at Paleocene-Eocene on the boundaries and during the middle Miocene Mishan deposition within the basin. The proposed structural evolution and the suggested oil window using the burial depth and the present thermal gradient for the Dehdasht Basin give insight into its hydrocarbon potential. Accordingly, the Cretaceous Kazhdumi source rock has started oil generation since Paleocene-Eocene (deposition of the Pabdeh Formation) in the deeper central part until the present in the subsurface relatively large-amplitude anticlines close to the boundaries. We also suggest that the Paleocene-Eocene Pabdeh Formation contained oil mainly in the subsurface low-amplitude anticlines in the central part of the basin during deposition of the Gachsaran and Mishan formations at early-middle Miocene. The older oil generation in the basin is attributed to its thicker deposits in the Paleocene-Eocene and early Miocene resulting in deeper burial depth for the source rocks. The obtained results propose that the subsurface relatively large-amplitude anticlines near the basin margins with the possible hydrocarbon (mainly generated from the Cretaceous Kazhdumi shale) are the most likely targets for future oil exploration. Additionally, we obtained that the boundary fore-thrusts and the caprock erosion due to the lateral anticlinal growth control the oil and gas seepages on the Dehdasht Basin boundaries.",0,0,0
Cretaceous,,"Khoshnoodkia, Mehdi; Rahmani, Omeid; Adabi, Mohammad Hossein; Hosseini-Barzi, Mahboubeh; Mahdi, Thamer A.","Depositional environment, seismic stratigraphy, and Sr-isotope geochronology, Bangestan reservoir, Ahwaz oilfield, SW Iran",Cretaceous; Seismic tectonostratigraphic; Extensional tectonic; Sarvak; Ilam; The zagros basin,SOUTHERN MESOPOTAMIAN BASIN; DEZFUL EMBAYMENT; SARVAK FORMATION; THRUST BELT; SEQUENCE STRATIGRAPHY; CRETACEOUS CARBONATES; MISHRIF FORMATION; ZAGROS MOUNTAINS; ARABIAN PLATE; TECTONICS,"The Bangestan reservoir, which occurs in the Ahwaz oilfield, consists of the middle Cretaceous limestone Ilam and Sarvak Formations that were deposited in the Zagros Basin. The reservoir is divided into ten Zones (A to J) formed in the upper Albian-Santonian and contains considerable hydrocarbon accumulations. The limestones were deposited on an extensive shallow carbonate platform on a passive margin and are dominated by rudist biostrome and grainstone facies. Paleogeographical changes mean that identification of the facies is complex. Seismic stratigraphy and isotopic data are used to better understand the structural and geological setting and develop an understanding of the sedimentary environment. The results show that the rudist biostrome facies extends to a shallow interior shelf as a patch reef, indicating a regressive trend. Petrographic studies on 3174 thin sections identified twelve microfacies in the Bangestan reservoir. In the Sarvak Formation, the dominant microfacies consist of rudist biostrome, shoal bar, and lagoon facies, with a high sedimentation rate in the basin, whereas the Ilam Formation involves open and deep-marine facies. Seismic tectono-stratigraphy shows that there are seven sedimentary sequences with mostly regressive cycles and six maximum flooding surfaces from the upper Albian to the Santonian. In addition, the Ahwaz oilfield had experienced pre-tectonic extension before the Early Cretaceous and post-tectonic extension after the Late Cretaceous. The isotopic data from the Bangestan reservoir demonstrate two important disconformities (Cenomanian-Turonian and post-Turonian) that had an important influence on the evolution of the area evolution. Sr geochronology confirms long-term exposure to two main disconformities within the Ahwaz Bangestan reservoir.",0,0,0
Cretaceous,,"Ahmad, Waqar; Gingras, Murray K.",Integrating sedimentology and ichnology with rock typing and flow units: Implications for clastic reservoir characterization,Sedimentology; Ichnology; Pore throat radii; Storage-flow capacity; Reservoir,MCMURRAY FORMATION; FACIES; BASIN; DISSOLUTION; SANDSTONES; DIAGENESIS; DEPOSIT,"Shallow marine elastic reservoir facies prediction, correlation, distribution, thickness, and quality remains a challenge. This study integrates sedimentology and ichnology with reservoir rock typing and flow units to characterize the Lower Cretaceous Wabiskaw Member reservoir. An integrated geologic depositional model is presented using sedimentological data (rock types, sedimentary structures, grain size), ichnological data (trace fossils intensity, size, diversity), reservoir characteristics (porosity, permeability), and well log data. The Wabiskaw Member strata are characterized using four facies associations (composed of nine sedimentary facies). Facies association 1 (FA-1) comprises dark grey to blue-grey mudstone with a distinctly lenticular appearance (Facies 1, 2). Ichnologically, a stressed archetypal Cruziana Ichnofacies represent FA-1. Facies association 2 (FA2) is fine-lower medium-grained sandstone with thin mudstone interbeds (Facies 3, 4). A stressed ichnological suite of mixed Skolithos-Cruziana Ichnofacies is present in FA-2. Facies association 3 (FA-3) is dark grey to bluish-grey mudstone with minor sandstone interbeds (Facies 5, 6). Trace fossils of archetypal Cruziana Ichnofacies are present in FA-3. Facies association 4 (FA-4) comprises upper fine to lower fine glauconitic sandstone (Facies 7, 8, 9) with a high-density trace fossil assemblage. FA-1 and FA-2 represent deposition in a waveinfluenced prodelta to delta front settings, whereas FA-3 and FA-4 represent deposition in the offshoreshoreface environment. The reservoir quality of various reservoir facies (F-3, F-4, F-7, F-8) is evaluated by comparing facies reservoir characteristics (porosity, permeability, pore throat radii, flow-storage capacity, oil saturation, and thickness). F-4 is the best and most productive reservoir (pore throat radius >20 mu m, 18% flow, and 4% storage capacity) in the study area. F-7 is ranked second-best in reservoir quality based on petrophysical characteristics (pore throat radius between 10 and 20 mu m, 36% storage 47% flow capacity). F-8 is ranked third in reservoir quality with pore-throat radii ranging from 4 to 10 mu m (mesoporous), 23% storage, and <= 5% flow capacity. F-3 is ranked last amongst the Wabiskaw Member reservoir facies. It is micro-porous (pore-throat radii ranging from 2 to 4 mu m) with 37% storage and <= 5% capacity flow. The reservoir characteristics are effectively constrained by the range of values recorded within each facies, demonstrating that a geological model (based upon detailed facies and wireline analyses) allows assessing how lateral facies changes affect the reservoir quality.",0,0,0
Cretaceous,,"Bahrehvar, Mohammad; Mehrabi, Hamzeh; Akbarzadeh, Samira; Rahimpour-Bonab, Hossain",Depositional and diagenetic controls on reservoir quality of the uppermost Jurassic-Lower Cretaceous sequences in the Persian Gulf; a focus on J-K boundary,Manifa-Yamama formations; Reservoir facies; Hydraulic flow units; Jurassic-Cretaceous boundary; Persian Gulf,FAHLIYAN FORMATION; DARIYAN FORMATION; MIDDLE-EAST; STRATIGRAPHY; BASIN; GEOCHEMISTRY; ZAGROS; IRAN; PALEOCLIMATE; MICROFACIES,"This study presents reservoir characterization of the uppermost Jurassic-Lower Cretaceous successions of the Manifa and Yamama formations in four wells in the Persian Gulf. Detailed sedimentological, petrophysical and geochemical analyses are integrated to evaluate the controlling factors on reservoir quality of these sequences. Microfacies analysis has resulted in the recognition of 10 facies types deposited in lagoon, algal mounds, shoal, and open marine settings. Micritization, dissolution, various types of cementation, dolomitization, and compaction are notable diagenetic alterations indicating marine/hypersaline, meteoric and shallow to deep burial realms. Stable carbon and oxygen isotopic compositions indicate a meteoric diagenetic alteration at the topmost part of Manifa unit, beneath the Jurassic-Cretaceous (J-K) disconformity. Sequence stratigraphic analysis led to the identification of four transgressive-regressive (T-R) sequences in the Yamama Fm. and a regressive hemi-sequence in the Manifa unit. Reservoir quality study resulted in the recognition of eight hydraulic flow units and four types of reservoir facies with specific and predictable sequence stratigraphic framework. Dissolved grain-dominated shoal facies at the upper part of regressive systems tracts and algal reef/mound facies in transgressive systems tracts provide the best reservoir units of the studied sequences. Microporous mud-dominated facies of open marine settings are dominant reservoir facies in the upper Yamama unit, with moderate to low reservoir quality.",0,0,0
Cretaceous,,"Liu, Hangyu; Shi, Kaibo; Liu, Bo; Song, Xinmin; Deng, Liben; Guo, Rui; Tian, Zhongyuan; Li, Yong; Deng, Ya; Wang, Genjiu",The characteristics and origins of thief zones in the Cretaceous limestone reservoirs of Central and southern Mesopotamian Basin,Mesopotamian Basin; Cretaceous; Carbonate reservoirs; Thief zones; Rudist shoals; Tidal channels; Bioturbation,,"Thief zone is a common reservoir unit with super permeability developed in giant carbonate reservoirs and readily leads to the breakthrough of fluids bring the challenge to water flooding development or tertiary oil recovery. To provide insight into the characteristics and origins of thief zones in Cretaceous carbonate reservoirs in Central and Southern Mesopotamian Basin, core analyses, well log, and production performance data analyses were performed in three formations from two giant oilfields. Thief zones are indicated and located by higher water injection and liquid production rates and classified based on their sedimentary environment, that is, rudist shoal thief zone (RS-TZ), tidal channel thief zone (TC-TZ), and bioturbated-associated thief zone (BS-TZ). Both RS-TZ and TC-TZ are characterized by similar or higher porosity, much higher permeability, and much larger pore-throat radii than overlying and underlying adjacent non-thief zones. The RS-TZ comprises microfacies of rudist rudstone and rudist grainstone with interparticle pores, interparticle dissolved pores and vugs. It occurs in the upper-middle section of the uppermost rudist shoal in the shoal complex, shows the sheet-shaped horizontal distribution in the late highstand system tract of the field. The TC-TZ comprises microfacies of bioclastic grainstone with interparticle pores and few interparticle dissolved pores, and presents banded horizontal distribution. The BS-TZ went through strong bioturbation within hardground substrate leading to the great difference of microfacies, pore types and pore structures in burrows and matrix, and this type has lower porosity but much higher permeability than adjacent reservoirs. The key to developing the thief zones is to form the great permeability difference between the thief zone and its adjacent reservoirs. The origins of the three types of thief zones can not only be attributed to the primary porosity having well-connected pore structures resulted from high-energy sedimentary facies or high-energy sediments filling bioturbation-associated burrows, and freshwater dissolution in the eogenesis stage also enlarged the pores and pore-throat sizes and further improved pore connectivity, which enhanced the porosity and significantly improved permeability. Due to the difference in rock textures, pore structures and sedimentary successions, the three types of thief zones have different well log response characteristics which could be used for thief zone identification in non-coring wells and other oilfields that occurred the similar thief zones.",0,0,2
Cretaceous,,"Zhang, Liying; Li, Ruixue; Deng, Hucheng; Fu, Meiyan; Hu, Lanxiao; Guo, Xiaobo; Xie, Xinhui; Zhao, Chenyang","Identification, distribution characteristics, and effects on production of interlayers in carbonate reservoirs: A case study from the Cretaceous Mishrif Formation in Halfaya Oilfield, Iraq",Interlayer identification; Distribution characteristics; Halfaya oilfield; Carbonate reservoir; Mishrif Formation,MESOPOTAMIAN BASIN; STRATIGRAPHY; SEQUENCE; ORIGIN; GULF,"Carbonate reservoirs play an essential role in the oil and gas exploration, especially in the Middle East. Halfaya oilfield is a super-giant oilfield, in which Mishrif Formation is the main oil-bearing formation. Mishrif Formation has a strong heterogeneity with an alternative appearance of interlayers and reservoirs. The appearance of interlayers has an obvious effect on oil production. Therefore, it is necessary to identify and characterize interlayers in Mishrif Formation in Halfaya oilfield. The interlayers in the study area can be divided into three types with different lithology according to the core and well logging data. In this study, a zonal identification method is established to accurately identify these three types of interlayers. In this method, the reservoir and interlayer are divided based on their permeability. The identification criteria of the three types of interlayers are developed based on analyzing the well logging data. After identifying the interlayers at wells based on the newly developed identification criteria, the distribution of interlayers far away from the well is characterized by a zonal interwell comparison method. Then, the planar distributions of the interlayer thickness in each member are generated. The identification results show that barriers develop in members MA1, MB1-1, MC2-1 and MC3-1. For the intercalations, there are 8 members developing large-scale continuous intercalations, which are members MA2, MB1-2A, MB1-2B, MC1-3, MC1-4, MC2-2, MC2-3 and MC3-2. Comparing the distributions of the interlayers and those of the sedimentary microfacies, the development of interlayers is controlled by sedimentary microfacies. It can be concluded that the interlayers prefer to appear in shallow open sea and subtidal flats. To quantitively characterize the effects of intercalations on oil production, intercalation density and intercalation frequency are compared with half-year oil production decline rate. The results show that the half-year decline rate increases with the increase of intercalation density and frequency. The intercalation density can better reflect the effect of intercalations on oil production than the intercalation frequency.",0,0,3
Cretaceous,,"Liu, Chao; Zhao, Wanchun; Sun, Lidong; Wang, Xiaolian; Sun, Youhai; Zhang, Ying; Zhang, Jingjing; Zhang, Lei; Li, Jijun","Geochemical assessment of the newly discovered oil-type Shale in the Shuangcheng area of the northern Songliao Basin, China",Shale; Geochemistry; Hydrocarbon potential; Shuangcheng depression; Songliao basin,HYDROCARBON SOURCE ROCKS; DEPOSITIONAL ENVIRONMENT; CARBON ISOTOPES; ORGANIC-MATTER; TRACE-ELEMENTS; SOUTH CHINA; DEPRESSION; LACUSTRINE; MATURATION; EXPULSION,"For the past fifty years, the northern Songliao Basin in China was thought to contain Lower Cretaceous coal-measure and gas-generating shale. Oil-type shales did not receive much attention until oil exploration activities made a breakthrough in the Southern Shuangcheng (SSC) depression. In this study, the geochemical characteristics of the newly discovered K(1)yc(4) (fourth member of the Lower Cretaceous YingCheng Formation) oil-type shale in the SSC depression were analyzed, including the organic matter abundance, organic matter type, thermal maturity, hydrocarbon potential, and sedimentary environment. A total of 393 core samples were collected, and Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), organic petrography, carbon isotope analysis, and constant and trace element analyses were conducted. The K(1)yc(4) shale was determined to have a good to excellent hydrocarbon potential with high TOC values (mostly 2.0-4.0%). The organic matter was mainly from lower hydrobiont, algae, bacteria, and lesser amounts of terrestrial plants. The organic matter is mainly type Ito type II based on the hydrogen index (HI) (average HI = 193.36 mg HC/g TOC), the carbon isotopes of the kerogen (mostly -26 to -30 parts per thousand), and the organic petrography (average sapropelinite + liptinite of 55.0 vol%). The maturity parameters, i.e., T-max (mean 452 degrees C) and vitrinite reflectance (0.8-1.1%), suggest that the shale is in the mature thermal evolution stage. The shale's maximum hydrocarbon-generating intensity is up to 713.29 x 10(4)/km(2), and its hydrocarbon-expelling intensity is stable at 116.63 x 10(4)/km(2). The constant and trace element analyses (Sr, Ba, V, Ni, Cr, Ti) revealed that the organic matter deposition and preservation occurred in a fresh-brackish and dysoxic-anoxic water environment. Volcanic eruptions probably played a vital role in the enrichment of the organic matter in the oil-type shale. In addition, the results of this study provide evidence that the Lower Cretaceous strata in the northern Songliao Basin meet the geological conditions of oil-prone shale, which expands the petroleum exploration horizon in this region.",0,0,3
Drill String,,"Ramba, Viswanth; Selvaraju, Senthil; Muppidathi, Balakumara Vignesh; Subbiah, Senthilmurugan; Palanisamy, Muthukumar",Evaluation of structural integrity of tubulars in directional wellbores: A case study in north-eastern parts of India,True tension; Effective tension; Neutral point; Sheave efficiency; Anomaly detection; Drilling mechanics,,"Severe fatigue and excessive load transmissions on drill strings during rotary drilling may lead to unexpected drill string failure. And if the driller within the stipulated time-bound did not control these load forces, the situation might increase NPT. To achieve the same by driller in real-time, the structural integrity of the tubular was monitored with a workflow that estimates the overall stresses acting along the drill string. In actual operating conditions, the drill string is subjected to both internal and external pressures, and it can be well explained in terms of true tension and effective tension. The estimation of these tensional forces and other load forces acting on the drill string is important for efficient drilling operation and the selection of optimum operational parameters. In addition, these forces are further utilized to estimate the neutral point and load acting at the deadline. The conventional rigs are subjected to numerous uncertainties that affect the precision of the hookload measurement at the deadline. Therefore, the factors affecting the hookload measurement at the deadline are summed up to a quantifiable metric labeled as Rig Uncertainty Compensation (RUC) factor. Further, the estimated hookload is compared with the actual hookload to detect the upcoming complications and prevent it from aggravation. And, to confirm the upcoming anomaly, the wellbore secondary drilling parameters are monitored in the real-time drilling operation. Additionally, all the forces acting along the drill string were also determined and monitored dynamically such that stress exposure in all the sections of the drill string is below a threshold value. To determine the efficacy of the developed model, the model was integrated with a Decision Support System (DSS) tool and tested in the actual field conditions. The tool was able to detect the upcoming complication successfully, and a field case study was presented in brief.",0,0,0
Drill String,,"Pagtalunan, Jed; Parmar, Kaushik; Kim, Seonghwan; Moon, Bryan; Park, Simon S.",Experimental study on repeater-free acoustic telemetry for downhole operations,Acoustic telemetry; Downhole drilling; Convolutional coding; Lock-in amplifier,THERMAL AGITATION; TRANSMISSION; DESIGN,"Measurement while drilling (MWD) enables real-time measurement of downhole conditions for directional drilling, but most commercial MWD telemetry techniques suffer from limited transmission speeds. Acoustic telemetry has the potential for significantly faster transmission speeds, but it has limited range due to drill string attenuation and noise. A common solution to this is to use acoustic repeaters, which incur high costs and require complex implementation. Instead of using repeaters, we utilized two carrier frequencies at the modes to transmit redundant data in combination with a lock-in amplifier (LIA) to extract the signals from the carriers. The extracted signals were then fused at the receiver to increase signal fidelity. An experimental setup was developed to transmit acoustic signals through a simulated drill string. The signals were first attenuated by the rubber section of the simulated drill string. The results show that the proposed system was able to achieve error-free transmission of packets at 64 bps up to 1.95 km without the use of a repeater which is orders of magnitude faster than current commercial MWD methods (mud-pulse and electromagnetic).",0,0,1
Drill String,,"Shi, Xiaolei; Huang, Wenjun; Gao, Deli; Zhu, Na",Optimal design of drag reduction oscillators by considering drillstring fatigue and hydraulic loss in sliding drilling,Sliding drilling; Friction force; Drag reduction oscillator; Drillstring failure; Hydraulic loss,FRICTION REDUCTION; VIBRATION; SURFACE,"Practice has proved that drag reduction oscillators can be used to decrease the axial friction and increase wellbore extension effectively in sliding drilling. However, the complicated mechanical behaviors of drillstring with drag reduction oscillators have not been revealed sufficiently, and there has no theoretical method to optimize drag reduction parameters. In this paper, an optimization design model of drag reduction oscillators is built with drag reduction efficiency as the target, and the mechanical model of drillstring with drag reduction oscillators is established by considering the friction nonlinearity. Further introducing the initial conditions, boundary conditions, and continuity conditions, the finite differential equation of drillstring vibration is obtained and solved. Next, combined with the oscillation propagation length and the installation position optimization models, the orthogonal experimental design method is applied to optimize the relevant parameters. In the optimization process, the constraint factors, including drillstring failure and hydraulic loss, are considered. Finally, the new model is applied to a field case study, in which the drag reduction effects of drillstring with and without oscillators are compared, and the impact of relevant factors on drag reduction are analyzed. The results show that the equivalent friction coefficient near the oscillator installation position is significantly reduced, whereas the hook load and weight on bit (WOB) are increased significantly with drag reduction oscillators. With the increase of amplitude or frequency, the propagation distance of the oscillator increases. The amplitude of vibration force and the number of oscillators are the two main factors affecting drag reduction efficiency. Three hydraulic oscillators with vibration amplitudes of 40 KN are recommended, and the drag reduction efficiency is 51.78%. However, excessively large oscillation amplitude may lead to drillstring failure and too many oscillators will increase the hydraulic loss a lot. Therefore, there are optimal values of oscillation amplitude and the number of oscillators. The research results are of significant guiding significance for optimal design and safety control of drag reduction oscillators in sliding drilling.",0,0,2
Drill String,,"Zhang, Jiantao; Yan, Hanbing",Deflection of eccentric tubes under axial loading in curved wellbores,Eccentric tube; Deflection; Beam-column model; Energy method; Bending moment; Contact force; Accessibility,LOCK-UP; CONNECTORS; CURVATURE; TUBULARS; PIPE,"With the advancement of technology, various types of downhole tools have been developed. It is necessary to ensure that downhole tools can be tripped to the predetermined well depth through a drilling and completion string without any damage. However, mathematical models to predict the downhole tool deformation under axial loading are lacking. In this paper, an eccentric tube deflection model is established according to the geometric characteristics of downhole tools. First, six contact cases of an eccentric tube under axial loading in a curved wellbore are considered. The model solves the eccentric tube deflection in the different contact cases through the beam-column model and energy method. Second, using this model, the critical axial load in the contact cases is examined along with the deflection, bending moment, and contact force of the eccentric tube. The results show that the deflection, bending moment, and contact force of the eccentric tube are related to the contact case. The bending moment and contact force of the eccentric tube in wrap contact under axial compression are higher than those in other contact cases. In particular, when the eccentric tube is subjected to wrap contact under axial compression, the maximum bending moment and contact force increase sharply, and this aspect can help evaluate the accessibility of the downhole tool. Finally, this paper proposes a new method based on the eccentric tube deflection model to analyze the accessibility of a completion string in the context of eccentric downhole tools. The effectiveness of the proposed method is demonstrated through a field case.",0,0,2
Drill String,,"Erge, Oney; Gu, Qifan; Chen, Dongmei; van Oort, Eric",MPD choke control considering the thixotropic gelation behavior of drilling fluids,Thixotropy modeling; Control algorithms; Preview-based feedback control; Hydraulics modeling; Managed pressure drilling,PRESSURE,"This study evaluates control algorithms that manage choke pressure during managed pressure drilling applications (MPD) while also taking the thixotropic behavior of drilling fluids into account. This evaluation analyzes proportional-integral (PI) feedback control and proposed preview-based feedback control for choke pressure. A pressure spike can be observed in standpipe and bottomhole pressure after making a drillstring connection or experiencing a prolonged break in drilling operations. This is caused by the gelation of drilling fluids. It is vital to be able to predict the magnitude of such pressure spikes when drilling with active annular pressure control, such that the choke can be effectively controlled to mitigate an induced non-productive time event (i.e., lost circulation events, pump or pipe failures, or well control situations). In this study, a shear-rate and time-dependent thixotropy model is integrated into a rigorously validated transient hydraulics engine with MPD control capabilities. Drilling scenarios are simulated with choke controllers and a case study is presented. When using a preview-based feedback control algorithm, a physics-based model is executed while setpoints are established proactively. The combined capabilities of the physics-based model and the improved MPD controller are demonstrated. Accurately modeling and controlling pressure during drilling operations is essential, especially for wells drilled in narrow-margin environments. The results of our study show that a reactive PI controller is not fast enough to account for transient pressure behavior related to fluid thixotropy. Moreover, the results show that a previewbased feedback controller is more robust and efficient. We demonstrate how a physics-based model can be used in a preview-based control scenario to keep the bottomhole pressure constant with strongly attenuated pressure fluctuations, leading to safer, more optimized operations.",0,0,2
Drill String,,"Kandala, Shanti Swaroop; Shor, Roman",Evolution of static and kinetic friction in a horizontal well using an adaptive model-based observer: Field validation,Friction coefficients; Drillstring dynamics; Bit off-bottom; Soft sensor,SELF-EXCITED VIBRATIONS; STICK-SLIP; BIT; MITIGATION; DYNAMICS; DRAG,"Evolution of static and kinetic friction coefficients across the depth of a horizontal wellbore and field validation against the downhole parameters is presented in this paper. It has been observed in the literature that stick-slip oscillations exist in drill strings even with bit off-bottom and persist with the bit on bottom. In the past, various lumped mass models have failed to explain this phenomenon, as they have only considered bit-rock interaction to be the main reason for the stick-slip oscillations. The model considered in this study was used previously to estimate the friction factors at particular connections with bit off-bottom. For effective estimation of the downhole parameters, the model employs an adaptive soft sensor, robust to capture the disturbances occurring at the downhole. Using only the topside measurements (i.e., surface measurements), downhole RPM is estimated along with the evolution of friction coefficients (static mu(s) and kinetic (mu(k))) using the soft sensor. For obtaining the friction factors profile, those values of mu(s) and mu(k) that converge and remain stable for a specified time are considered. The model is first validated against the downhole RPM data obtained for a well in North America. It was observed that the estimates of the downhole RPM obtained using the model are in close agreement with that of the actual data. Next, the model was employed to obtain reasonable downhole RPM estimates for another well in North America where the downhole data is unavailable.",0,0,2
Drill String,,"Tan, Tianyi; Zhang, Hui",A risk prediction method of pipe sticking accidents due to wellbore uncleanness for long horizontal section wells,Wellbore uncleanness; Bulldozer effect; Pipe sticking prediction; Long horizontal section well; Torque and drag,CUTTINGS TRANSPORT; FLUID; MODEL; FLOW; CLEANOUT; OIL,"The prediction of pipe sticking accidents due to wellbore uncleanness is significant for safe drilling, while existing qualitative prediction methods result in inaccuracy and lateness. To cover the shortages, a novel quantitative pipe sticking prediction method is established to achieve pipe sticking prediction early in drilling preparatory stage. First, the additional axial forces and torques on the drill string exerted by accumulated cuttings are calculated in tripping out, tripping in, back reaming and reaming processes based on granular mechanics. Second, the torque and drag model is modified considering additional axial forces and torques to calculate the hook load and the top drive torque. Finally, the pipe sticking prediction is conducted according to the critical hook load and the critical top drive torque in a specific drilling process. A case study including comparison with the classical model and sensitivity analysis is conducted. Under the given condition, pipe sticking risk is predicted with the new mothed by anticipating hook loads (5524.67 and -667.71 kN) and top drive torques (60.87 and 66.36 kN m) exceeding the critical values. The hook load and the top drive torque change exponentially with the travelling distance. In tripping out and back reaming processes from 4350 to 4250 m, the hook load and the top drive torque respectively increase for 1894.36 kN and 53.99 kN m. In tripping in and reaming processes from 3450 to 3550 m, the hook load decreases for 29925.66 kN and the top drive torque increases for 157.3 kN m. According to the sensitivity analysis, low frictional coefficients, initial cutting volume fractions, torque and drag frictional factors and high junk slot ratios are required to reduce the risk of pipe sticking. This study provides a timely and quantitative prediction method for pipe sticking accidents due to wellbore uncleanness in long horizontal drilling.",0,0,3
Spatial Distribution,,"Sadeghi, Mehdi; Madani, Nasser; Falahat, Reza; Sabeti, Hamid; Amini, Navid",Hierarchical reservoir lithofacies and acoustic impedance simulation: Application to an oil field in SW of Iran,Hierarchical simulation; Pluri-Gaussian simulation; Turning bands simulation; Lithofacies; Acoustic impedance,CONDITIONAL SIMULATION; POINT; UNCERTAINTY; PROGRAM,"In this study, a hierarchical simulation algorithm was implemented to produce 3D models of lithofacies and acoustic impedance (AI) in an oil field in southwestern Iran. Hierarchical simulation is a powerful method that takes into account the spatial distribution and hard contact relationships of continuous variables within the categorical variables in reservoir characterization. To implement the hierarchical simulation algorithm in this study, pluri-Gaussian simulation was used to construct the layouts of one categorical variable (lithofacies domains) and turning bands simulation was used to produce one continuous variable (AI models) within each simulated domain. The dataset that is available to test the proposed method includes the lithofacies and AI logs of seven wells. For validation of the proposed model, one of wells was excluded from the initial dataset to check the accuracy of results. The algorithm was implemented on a gridded model to produce 50 realizations of 3D lithofacies and AI models. The statistical analyses of the produced models verified the capabilities of hierarchical simulation in reproducing the lithofacies domains and AI values related to each domain. The simulated AI models were compared with the seismic inversion model to corroborate the reliability of the results. In addition, to show the superiority of the hierarchical approach, the results were compared to the results of direct AI modeling in which the AI models were generated without considering any lithofacies data. The comparisons in the blind well indicated a high correlation between the modeled values and the true AI. The correlation coefficient between average AI models of the hierarchical approach and the true AI was 0.85. Whereas, this value was 0.75 for the average of directly simulated AI models and 0.74 for the seismic inversion, respectively. Histogram analysis also verified the capability of the hierarchical modeling in reproducing the statistical properties of the original data. The resulting AI model obtained using the method proposed in this study also showed a high compatibility with the deterministic seismic inversion cube.",0,0,0
Spatial Distribution,,"Zhang, Yanhui; Hoteit, Ibrahim; Katterbauer, Klemens; Maucec, Marko; Marsala, Alberto F.",Feature-based ensemble history matching in a fractured carbonate reservoir using time-lapse deep electromagnetic tomography,History matching; Ensemble methods; Adaptive localization; Distance parameterization; Fractured carbonate reservoir; EM tomography,DISTANCE PARAMETERIZATION; FIELD MODEL; ASSIMILATION; FRAMEWORK,"Carbonate reservoirs typically exhibit very complex geological structures and are characterized by flow dynamics primarily occurring in fractures. The intricate network of fractures as well as their interconnectedness may lead to unexpected flow patterns and uneven sweep efficiency. Determining reservoir properties of both matrix and fracture channels is quintessential for accurately tracking the fluid front movement in the reservoir, optimizing sweep efficiency, and maximizing hydrocarbon production. In this study, we showcase the application of a feature-oriented ensemble-based history matching workflow to a complex fractured carbonate reservoir box model, focusing on the use of formation resistivity tomography data that are usually inferred from deep crosswell electromagnetic (EM) surveys. Compared with the production data that are commonly used in history matching, deep EM measurements provide additional information about the spatial distribution of subsurface reservoir properties in the interwell volumes by exploiting the strong resistivity contrast between water and hydrocarbons. A hybrid parameterization approach is used to represent the multiscale fracture distribution in which the spatial distribution of small-scale fractures is modelled by a truncated Gaussian simulation method. A large number (over one million) of uncertain model parameters including reservoir matrix and fracture properties as well as Archie's parameters are identified and updated by an iterative ensemble smoother. For an efficient integration of the high-dimensional and noisy EM tomography data, the boundary or contour information extracted from the EM resistivity field is instead assimilated through a distance parameterization approach. A modified bootstrapbased localization is proposed to regularize the model updates adaptively during the iteration to reduce sampling errors. Especially, to improve the computational efficiency in dealing with the large dimensions of both data and model parameters, the localization is implemented in a projected low-dimensional data subspace. Experimental results demonstrate the applicability and efficiency of the developed workflow for reservoir history matching in more realistic model settings. The comparative case study also illustrates the significance of jointly incorporating multiple sources of data for better quantification of model uncertainty, and the great potential of deep EM data for enhancing the characterization of complex fractured carbonate reservoirs.",0,0,1
Spatial Distribution,,"Guo, Qiulin; Ren, Hongjia; Yu, Jingdu; Wang, Jian; Liu, Jifeng; Chen, Ningsheng",A method of predicting oil and gas resource spatial distribution based on Bayesian network and its application,Petroleum resources; Spatial distribution prediction; Bayesian network; AODE model; Sangonghe Formation; Junggar Basin,EXPLORATION RISK; MODEL; PLAY,"The spatial distribution prediction of hydrocarbon resource is essential to reduce exploration risks and improve investment returns. Determining the location of the spatial distribution of oil and gas resources is a complex and uncertain problem. This paper systematically analyzes oil and gas exploration risk assessment and resource spatial distribution prediction technology, and proposes a method of predicting hydrocarbon spatial distribution based on averaged one-dependence estimators(AODE). Firstly, the transformation process of petroleum geological problem to mathematical model is described. Then, the classification principle and decision rule of AODE model are expounded. Finally, a case study of Sangonghe Formation in the hinterland of Junggar Basin in China is given to further illustrate the proposed method and work flow. The case prediction results not only reveal that the accuracy of the AODE model can reach 85.2% on the data set of 203 exploratory wells, which is higher than state-of-the-art methods (such as tree augmented Bayesian network method and the Mahalanobis distance method), but also point out the areas with high probability of remaining hydrocarbon resources in Sangonghe Formation, which provides decision-making basis for the next exploration. The application results show that the AODE model can effectively predict the spatial distribution of oil and gas and visualize the risk of geological exploration, thereby optimizing drilling strategy and increasing economic benefits.",0,0,1
Spatial Distribution,,"de Mello, Vitor Leal; Lupinacci, Wagner Moreira",Mineralogy based classification of carbonate rocks using elastic parameters: A case study from Buzios Field,Carbonate reservoirs; Bayesian classification; Elastic parameters; Buzios field,COMPRESSIONAL-WAVE; SONIC VELOCITY; PORE TYPE; POROSITY; PERMEABILITY; MEDIA; SHEAR; RATIO; TOOL,"Brazilian presalt carbonate reservoirs are highly heterogeneous. This feature is mostly justified by the nature of the original depositional system and subsequently diagenetic processes. Consequently, reserve estimates and production forecasting are under large uncertainties. In this geologic context, it is of great relevance to develop techniques that helps to obtain a detailed description on the spatial distribution of these different rocks. In doing so, it contributes to the understanding of presalt carbonate sedimentary deposits, providing inputs for more predictive reservoir models. Traditionally, these carbonates are grouped into three classes, from which only one exhibits reservoir properties. Using a dataset from Buzios Field, this work proposes a characterization of presalt carbonate reservoir rocks by grouping them in terms of their mineral composition. Taking advantage of rock physics concepts, we aim to potentialize the use of elastic parameters for multiple rock type discrimination. We explored several attempts for rock classification by using a Bayesian approach. Among all the tested propositions, a two-step workflow for five lithotypes classification, emerges as the most appropriate for the Buzios Field. In this scheme, three lithotypes represent good-quality reservoirs and the other two are low-porosity and Mg-clay-rich carbonates. The average root-mean-square error of the most likely a posteriori rock proportions is around 8.4%, only approximately 1% higher than the conventional three lithotypes configuration. To support that, we compared different methodologies for Bayesian classification at well-log scale through acoustic impedance and compressional to shear velocity ratio. Potential applicability of the proposed methodology at field scale is reinforced by similar results achieved using well-logs filtered to the seismic bandwidth.",0,0,2
Spatial Distribution,,"Monteiro, Lua; Baptista-Pereira, Catarina; Azevedo, Leonardo",Sensitivity analysis of injection parameters in steam assisted gravity drainage under geological uncertainty,Steam-assisted gravity drainage; Heavy oil; Sensitivity analysis; Geological uncertainty; Reservoir simulation; Optimization,OPTIMIZATION; SAGD; OIL; SIMULATION; RESERVOIR,"Steam-assisted gravity drainage (SAGD) is a challenging enhanced oil recovery technique that requires proper parameterization in terms of well geometry and steam injection parameters as these parameters are highly dependent on the reservoir geology and fluid characteristics (e.g., net pay variation, water saturation). Injection rate and pressure, temperature, steam quality, lean zone, gas zone, water saturation, and wellbore hydraulics are among the most important engineering parameters of SAGD. This work focuses in the sensitivity analysis under geological uncertainty of some operational parameters, such as: injection rate, temperature, steam quality and pressure. To reach this objective we build a realistic reservoir model with multiple geological settings and descriptions. Moreover, two complementary approaches were studied: i) a deterministic sensitivity analysis relying on a factorial design matrix and ii) a stochastic analysis using particle swarm optimization. There are several key geological uncertainties in SAGD, such as net pay variation, inclined heterolithic stratification (IHS) presence, high water saturation in reservoirs, bottom water issues, and gas cap problems. This work focuses on the role of porosity and permeability in oil production, as these impact these geological properties. To reach this objective, two specific groups of ten different porosity and permeability pairs of geostatistical realizations were generated using Direct Sequence Simulation and Co-simulation. Group 1 used the same variogram model for 10 random seeds; and Group 2 used a combination of values that adopted a simultaneous and a random variation, which were assigned to the seed and to the variogram. We opted by a reservoir model that mimics an anticlinal reservoir, as it proved to be a determining factor for the low levels of Net Present Value (NPV) when compared to other geological scenarios. Within the four most commonly studied parameters in SAGD projects, the association of deterministic versus stochastic multi-objective analysis allowed to accurately validate injection rate as the most relevant parameter. Regarding the geological uncertainties, Group 1 showed that for a certain porosity distribution and permeability orientation, the random origin of these distribution maps eventually attributed a higher NPV uncertain. On the other hand, in Group 2, the simultaneous spatial and seed variation provided less uncertainty associated to NPV.",0,0,2
Spatial Distribution,,"Mustofa, Muhammad Bisri; Fauzi, Umar; Latief, Fourier Dzar Eljabbar; Warsa, Warsa",Experimental and modeling of electrical resistivity changes due to micro-spatial distribution of fluid for unconsolidated sand,Electrical resistivity; Micro-spatial distribution of fluid; Digital sample image; Unconsolidated sand,WATER SATURATION; ARCHIES LAW; ATTENUATION; CONDUCTIVITY; PERMEABILITY,"Electrical resistivity measurements of reservoir rocks are usually applied to identify fluid type and saturation. Although it has been widely studied, the effect of fluid saturation on electrical resistivity is not yet fully understood, especially when considering the spatial distribution of fluids. Hysteresis and electrical resistivity jump in the imbibition process are two of the phenomena that remain unclear. Microscopical evaluation would be useful in understanding these phenomena. In this paper, we analyzed the influence of the micro-spatial distribution of fluids on electrical resistivity. In order to achieve the objective, laboratory measurements and computer modeling of electrical resistivity were carried out. Measurements were made on unconsolidated sand samples that were saturated with brine. Two categories of samples were prepared based on the position of the brine injection to obtain fluid spatial distribution variations in rock pores. Measurement results showed that the electrical resistivity varies depending on the brine injection position. Subsequently, 3-D microcomputed to-mography images were acquired to analyze sample microstructure and model fluid spatial distribution. We implemented three different saturation models made up of varying fluid filling mechanisms onto digital images of samples, then used them to compute the electrical resistivity of the sub-sample using the finite element method. The measurement and calculation of electrical resistivity showed good agreement. These results indicate that the proposed model is capable of representing spatial fluid distribution in pore spaces of measured samples. This fluid distribution is most responsible for the variation of the electrical resistivity in the samples. Furthermore, the electrical resistivity jump phenomenon in the imbibition process was successfully explained through the proposed model. Based on this study's results, it can be concluded that the spatial distribution of fluids needs to be considered in the estimation of electrical resistivity. The research findings provide insight into how microspatial distribution affects electrical properties of rocks of importance to the interpretation of electrical resistivity data.",0,0,2
Spatial Distribution,,"Miao, Zhengshuo; Pei, Yangwen; Su, Nan; Sheng, Shouzheng; Feng, Ben; Jiang, Hua; Liang, Han; Hong, Haitao","Spatial and temporal evolution of the Sinian and its implications on petroleum exploration in the Sichuan Basin, China",Tectonic kinematics; Deformation quantification; Erosion distribution; Paleo-highs; lows; Dengying formation; Hydrocarbon accumulation,GIANT GAS-FIELD; PALEO-UPLIFT; SOUTH CHINA; TECTONIC EVOLUTION; ACCUMULATION; DISCOVERY; HISTORY; RODINIA; NORTH; RIFT,"In recent years, there have been significant discoveries of hydrocarbon resources with commercial value in the Dengying Formation of the central Sichuan Basin. However, the impact of tectonic evolution on hydrocarbon accumulation has not been appropriately documented. In this study, we employed multiple methods, including seismic interpretation, balanced cross-section restoration, deformation quantification, erosion calculation, and paleo-highs/lows reconstruction, to investigate the tectonic kinematics, erosion distribution, paleo-highs/lows evolution of the Sichuan Basin. The quantification of deformation reveals that the Sichuan Basin has experienced a complicated tectonic evolution, with two rounds of transition from tension to contraction since the Sinian. In the Late Ordovician, contraction caused by the Caledonian Orogeny resulted in a foreland basin being developed in the Sichuan Basin. Since the Late Triassic, the Sichuan Basin has experienced intense contraction, resulting in the development of its current structural pattern. By integrating the erosion distribution, the reconstructed paleo-highs/lows maps of Sinian strata indicate the development of inherited paleo-uplifts in the central and southwestern Sichuan Basin from the Early Cambrian to the present. The evolution of paleo-highs/ lows plays a critical control on the hydrocarbon accumulation of the Weiyuan and Anyue gas fields, indicating there could be high potential for hydrocarbon exploration in areas with high slope gradients in the paleo-uplifts.",0,0,3
SW Iran,,"Kiani, Arad; Saberi, Mohammad Hossein; ZareNezhad, Bahman; Mehmandosti, Elham Asadi","Reservoir zonation in the framework of sequence stratigraphy: A case study from Sarvak Formation, Abadan Plain, SW Iran",Sarvak Formation; Sedimentary environment; Diagenesis; Electrofacies; Flow unit; Reservoir quality,FOLD-THRUST BELT; CENOMANIAN-TURONIAN CARBONATES; PALAEO-EXPOSURE SURFACES; DEZFUL EMBAYMENT; ZAGROS BASIN; OIL-FIELD; DEPOSITIONAL ENVIRONMENT; METEORIC DIAGENESIS; ASMARI RESERVOIR; ILAM FORMATION,"Located in the northeast of the Arabian Plate, Zagros Basin hosts some of the most significant hydrocarbon reservoirs in Iran, including the Sarvak Formation. It has been dated back to the Middle Cretaceous and exhibits a dominantly carbonate lithology. In this study, petrographic and petrophysical data of the Sarvak Formation were analyzed. The results of the petrographic study showed that the formation was deposited in a homoclinal carbonate-ramp depositional environment and exposed to diagenetic processes in three depositional environments: marine, meteoric, and deeply buried environments. The stratigraphic modified Lorenz plot (SMLP) method was used to distinguish between the reservoir and non-reservoir zones. By integrating the petrographic and petrophysical findings, stratigraphic relationships among the identified zones were assessed. Accordingly, three third-order sedimentary sequences were identified on the Middle Cenomanian-to-Middle Turonian section within the studied formation. Two disconformities were detected in the Upper Sarvak, namely Cenomanian-Turonian disconformity (CTD) and Middle Turonian disconformity (MTD). The highest-quality reservoir zones were related to the CTD. The porosity resulted from the karstification, meteoric diagenesis, and significant dissolution beneath the CTD was found to have greatly increased the reservoir quality. Later on, however, the sediments were overmatured under the impact of the MTD, which is known to take a long time to occur, with their porosity largely decreased, ending up with a much lower reservoir quality. In general, the sedimentary facies were found to be the most important factors controlling the distribution of the reservoir zones across the Sarvak Formation, followed by the diagenetic processes. The findings provided an insight into the factors controlling the reservoir quality in the Sarvak Formation within the study area and the Arabian Plate.",0,0,0
SW Iran,,"Heydarzadeh, K.; Hajialibeigi, H.; Gharabeigli, G. R.",Structural geometry and evolution of the Dehdasht Basin in the Central Zagros fold-and-thrust belt: Implications for the timing of oil generation and trap formation,Sequential restoration; Evaporitic detachment; Anticlinal trap; Source rock maturation; Dehdasht structural basin; Central zagros,SOURCE-ROCK EVALUATION; DEZFUL EMBAYMENT; FORELAND BASIN; ASMARI FORMATION; SW IRAN; TECTONICS; DEPOSITS; SEEPAGE; MIOCENE; MAGNETOSTRATIGRAPHY,"Structural analysis and temporal evolution of the Dehdasht Structural Basin in the Central Zagros through the constructed cross-sections and 2D sequential restoration have defined the timing of trap formation in the basin. At the level of the competent layer (Early Cretaceous to Oligo-Miocene), the basin is deeper toward the center where it is covered by the thicker Miocene evaporites and syn-tectonic clastic deposits. The evolutionary history of the basin based on the sequential restoration proposes that the anticlinal traps are formed since the Pabdeh deposition at Paleocene-Eocene on the boundaries and during the middle Miocene Mishan deposition within the basin. The proposed structural evolution and the suggested oil window using the burial depth and the present thermal gradient for the Dehdasht Basin give insight into its hydrocarbon potential. Accordingly, the Cretaceous Kazhdumi source rock has started oil generation since Paleocene-Eocene (deposition of the Pabdeh Formation) in the deeper central part until the present in the subsurface relatively large-amplitude anticlines close to the boundaries. We also suggest that the Paleocene-Eocene Pabdeh Formation contained oil mainly in the subsurface low-amplitude anticlines in the central part of the basin during deposition of the Gachsaran and Mishan formations at early-middle Miocene. The older oil generation in the basin is attributed to its thicker deposits in the Paleocene-Eocene and early Miocene resulting in deeper burial depth for the source rocks. The obtained results propose that the subsurface relatively large-amplitude anticlines near the basin margins with the possible hydrocarbon (mainly generated from the Cretaceous Kazhdumi shale) are the most likely targets for future oil exploration. Additionally, we obtained that the boundary fore-thrusts and the caprock erosion due to the lateral anticlinal growth control the oil and gas seepages on the Dehdasht Basin boundaries.",0,0,0
SW Iran,,"Sadeghi, Mehdi; Madani, Nasser; Falahat, Reza; Sabeti, Hamid; Amini, Navid",Hierarchical reservoir lithofacies and acoustic impedance simulation: Application to an oil field in SW of Iran,Hierarchical simulation; Pluri-Gaussian simulation; Turning bands simulation; Lithofacies; Acoustic impedance,CONDITIONAL SIMULATION; POINT; UNCERTAINTY; PROGRAM,"In this study, a hierarchical simulation algorithm was implemented to produce 3D models of lithofacies and acoustic impedance (AI) in an oil field in southwestern Iran. Hierarchical simulation is a powerful method that takes into account the spatial distribution and hard contact relationships of continuous variables within the categorical variables in reservoir characterization. To implement the hierarchical simulation algorithm in this study, pluri-Gaussian simulation was used to construct the layouts of one categorical variable (lithofacies domains) and turning bands simulation was used to produce one continuous variable (AI models) within each simulated domain. The dataset that is available to test the proposed method includes the lithofacies and AI logs of seven wells. For validation of the proposed model, one of wells was excluded from the initial dataset to check the accuracy of results. The algorithm was implemented on a gridded model to produce 50 realizations of 3D lithofacies and AI models. The statistical analyses of the produced models verified the capabilities of hierarchical simulation in reproducing the lithofacies domains and AI values related to each domain. The simulated AI models were compared with the seismic inversion model to corroborate the reliability of the results. In addition, to show the superiority of the hierarchical approach, the results were compared to the results of direct AI modeling in which the AI models were generated without considering any lithofacies data. The comparisons in the blind well indicated a high correlation between the modeled values and the true AI. The correlation coefficient between average AI models of the hierarchical approach and the true AI was 0.85. Whereas, this value was 0.75 for the average of directly simulated AI models and 0.74 for the seismic inversion, respectively. Histogram analysis also verified the capability of the hierarchical modeling in reproducing the statistical properties of the original data. The resulting AI model obtained using the method proposed in this study also showed a high compatibility with the deterministic seismic inversion cube.",0,0,0
SW Iran,,"Khoshnoodkia, Mehdi; Rahmani, Omeid; Adabi, Mohammad Hossein; Hosseini-Barzi, Mahboubeh; Mahdi, Thamer A.","Depositional environment, seismic stratigraphy, and Sr-isotope geochronology, Bangestan reservoir, Ahwaz oilfield, SW Iran",Cretaceous; Seismic tectonostratigraphic; Extensional tectonic; Sarvak; Ilam; The zagros basin,SOUTHERN MESOPOTAMIAN BASIN; DEZFUL EMBAYMENT; SARVAK FORMATION; THRUST BELT; SEQUENCE STRATIGRAPHY; CRETACEOUS CARBONATES; MISHRIF FORMATION; ZAGROS MOUNTAINS; ARABIAN PLATE; TECTONICS,"The Bangestan reservoir, which occurs in the Ahwaz oilfield, consists of the middle Cretaceous limestone Ilam and Sarvak Formations that were deposited in the Zagros Basin. The reservoir is divided into ten Zones (A to J) formed in the upper Albian-Santonian and contains considerable hydrocarbon accumulations. The limestones were deposited on an extensive shallow carbonate platform on a passive margin and are dominated by rudist biostrome and grainstone facies. Paleogeographical changes mean that identification of the facies is complex. Seismic stratigraphy and isotopic data are used to better understand the structural and geological setting and develop an understanding of the sedimentary environment. The results show that the rudist biostrome facies extends to a shallow interior shelf as a patch reef, indicating a regressive trend. Petrographic studies on 3174 thin sections identified twelve microfacies in the Bangestan reservoir. In the Sarvak Formation, the dominant microfacies consist of rudist biostrome, shoal bar, and lagoon facies, with a high sedimentation rate in the basin, whereas the Ilam Formation involves open and deep-marine facies. Seismic tectono-stratigraphy shows that there are seven sedimentary sequences with mostly regressive cycles and six maximum flooding surfaces from the upper Albian to the Santonian. In addition, the Ahwaz oilfield had experienced pre-tectonic extension before the Early Cretaceous and post-tectonic extension after the Late Cretaceous. The isotopic data from the Bangestan reservoir demonstrate two important disconformities (Cenomanian-Turonian and post-Turonian) that had an important influence on the evolution of the area evolution. Sr geochronology confirms long-term exposure to two main disconformities within the Ahwaz Bangestan reservoir.",0,0,0
SW Iran,,"Saedi, Ghasem; Soleimani, Bahman; Samani, Babak; Arzani, Ali",The interaction between faults and in-situ stress on the kinematic and subsurface natural fracture of Aghajari oilfield in southwest of Iran,Natural fracture; Fault; In-situ stress; Seismic data frequency; Dipole sonic tool,ASMARI FORMATION; BOREHOLE ELONGATION; ZAGROS MOUNTAINS; DEZFUL EMBAYMENT; GAS-RESERVOIRS; IMAGE; BASIN; CORE; WELL; LOGS,"Electrical and acoustic image logs are the best evaluating subsurface fracture and In-situ Stress wellbore data among direct and indirect methods. In this study, which had done by using the 24 Asmari reservoir well data in the Aghajari giant oilfield firstly were determined and categorized subsurface natural fracture, fault and In-situ Stress from common conventional well log, electrical and acoustic image logs, dipole sonic logs and 3D seismic data. Then, the relationship between determined features are evaluated in terms of genesis, events and different structural setting as the interaction between fault and In-situ Stress on the kinematic and subsurface natural fracture of Aghajari oilfield in southwest of Iran. The maximum and minimum horizontal in-situ stress direction is derived from image and dipole data had a good correlation except regions due to the fault effect. the integration of data evinced that the perturbation of regional stresses inherited from seismic faults and the effect of both regional stress and fault effect in the construction of a transforming fold as detachment type in SW nose to forming fault propagation and bending fold towards central and SE nose, respectively, which it could be useful for fracture modeling to enhance oil production, especially in heterogeneous carbonate fractured reservoirs.",0,0,2
SW Iran,,"Alipour, Majid; Alizadeh, Bahram; Mirzaie, Shohreh",Petroleum system analysis of the Paleozoic series in the Fars Platform of Iran,Petroleum system analysis; Paleozoic petroleum system; Fars Platform; Salt tectonics,SANANDAJ-SIRJAN ZONE; FOLD-THRUST BELT; ZAGROS BASIN; MIDDLE-EAST; SOURCE-ROCK; RESERVOIR ROCKS; SALT STRUCTURES; SW IRAN; EVOLUTION; OFFSHORE,"The Paleozoic petroleum system of the Fars Platform of Iran is analyzed using 1D petroleum system models of 17 deep wells drilled in the study area. The main aim was to investigate the hitherto undocumented influence of salt tectonics on the essential elements and processes of this petroleum system. For the first time, a better understanding about the geohistory evolution of this prolific petroleum system is provided over the Fars Platform. Modeling results indicate that hydrocarbon generation from the Silurian source rock was associated with salt withdrawal synclines. Salt tectonics further controlled the entrapment styles and the geometric distribution of carrier/reservoir rocks and their overlying evaporitic seals. Our findings provide new insights for identifying the remaining exploration potential in the Paleozoic petroleum system of the Fars Platform and suggest that the role of salt tectonics should be considered in the future basin and petroleum system modeling studies in this area.",0,0,2
Semianalytical Solution,,"Shafeer, Althaf; Hyun, Lee Jang; Ganat, Tarek; Habte, Azeb Demisi",A two-step semi-analytical solution method for the pressure response during cold water injection for a vertical well in a warm bounded reservoir,Semi-analytical solution; Pressure transient behaviour; Injection and falloff test; Cold water injection,LAPLACE-TRANSFORM; FINITE-DIFFERENCE; FLUID; OIL,"Development of a mathematical solution for injection/falloff problem of an oil-water system for transient data analysis is complicated due to the presence of two mobile phases that create a moving discontinuity. The solutions that have been developed in the past are based on a series of assumptions that make the models limited. The previous models have neglected one or more of the key reservoir and well parameters such as the variation of saturation in the invaded zone, temperature effects, wellbore storage, skin and outer boundary conditions. In this work, a generalized two-step semi-analytical solution method is presented to precisely simulate the pressure transient behaviour for injection and falloff tests following cold water injection for a fully-penetrating vertical well in a warm and bounded oil reservoir in the presence of skin and wellbore storage. The formulated model uses two simplistic steps to solve the complex mathematical problem and improve computational efficiency. The usage of the Laplace-transform finite-difference method to solve the system of equations eliminates the need for temporal discretization, thereby resolving issues related to convergence and time iterations by allowing an unlimited timestep size without the loss of stability and accuracy. The accuracy and consistency of the proposed solution method are assessed by comparing the results with that of ECLIPSE 100 and an excellent agreement is observed. The results suggest that the injection period pressure behaviour is vastly influenced by the injected water propagation under cold conditions, whereas, the falloff period pressure behaviour provides information of the water bank under cold conditions and the uninvaded zone under hot conditions. The comparison of the non-isothermal and isothermal pressure behaviour shows that the isothermal model can be improved using modified fluid viscosities to match the non-isothermal pressure behaviour that not only could minimize the mathematical complications, but also the computation time.",0,0,0
Semianalytical Solution,,"Di, Shiying; Cheng, Shiqing; Wei, Cao",Evaluation of fracture closure and its contribution to total production for a well with non-planar asymmetrical vertical fracture based on bottom-hole pressure,Pressure transient analysis; Fracture closure; Finite difference method; Double-segment non-planar asymmetrical fracture,NON-DARCY-FLOW; SEMIANALYTICAL SOLUTION; CONDUCTIVITY; LENGTH,"Hydraulic-fracturing is an important well-stimulation technique, the fracture closure is inevitable during production. The existing pressure transient analysis models either ignore the length of fracture-closure segment that causes the explained fracture half-length to be smaller, or only use the fracture conductivity to evaluate fracture closure. To fully evaluate fracture closure and provide a reference for oilfield engineers determining whether need measures to improve the well performance, meanwhile considering the non-planar asymmetrical fracture is common met in low-permeability reservoirs, this paper proposes to use two parameters (flowrate proportion and conductivity of fracture-closure segment) to comprehensively evaluate fracture closure, and hence develops double-segment non-planar asymmetrical fracture model (DPAFM). Planar asymmetrical fracture model is simplified case of proposed model. The semi-analytical solution is obtained by using finite difference method (FDM) and Gonzalez-Chavez and Cinco-Ley (2006) model is used to verify the solution. The results of this work show that (a) The example of actual well simulation proves the model is more suitable for the actual field data, and the model established is better matched than the saphir software; (b) The proposed model can obtain production proportion and conductivity of fracture-closure segment to comprehensively evaluate fracture closure; (c) There are four typical flow regimes for the DPAFM, including bilinear flow, interference linear flow, formation linear flow, pseudo-radial flow. The interference linear flow regime with 'V-shape' characteristic is unique; (d) Conventional explanation thinks the 'V-shape' characteristic represents the secondary fracture developed (e.g., OFFN, TLFN and MOFN). However, this paper gives another possibility that the 'V-shape' reflects fracture closure. The findings of this study can help for better understanding of illustrating the practicability of proposed methodology in evaluating the fracture closure and reservoir parameters. This research provides guidance for technicians to formulate the next step to increase production plan and helps the oilfield engineers determine whether take measures to improve the well performance.",0,0,2
Semianalytical Solution,,"Wang, Shihao; Wu, Yu-Shu",Theoretical analysis and semi-analytical formulation for capturing the coupled thermal-hydraulic-mechanical process using the stress formulation,Multiphysical simulation; A priori analysis; Semi-analytical solution; Stress method,FLOW; GEOMECHANICS; DEFORMATION; BEHAVIOR; FLUID; MODEL,"The research of multiphysical thermal-hydraulic-mechanical (THM) simulation has achieved significant progress in the past decade. Currently, two types of approaches for poromechanical simulation co-exist in the reservoir simulation community, namely the stress approach with stress as the primary variable for the mechanical governing equations and the displacement approach with displacement as the primary variable. In this work, we aim to provide a theoretical foundation and a practical semi-analytical solution for the stress approach, which is based on the Navier-Beltrami-Michell Equations. Moreover, we will clarify the relationship (and equivalence) between the two approaches. We have proven the existence and uniqueness of the stress solution of Navier-Beltrami-Michell equation with given pressure and temperature field. Moreover, we have demonstrated the equivalence of the stress formulation to the displacement formulation. We have shown that the stress approach yields the same results as the displacement approach, but is more convenient to be implemented. We also conducted an a priori analysis of the mean stress solution. Based on Fourier's analysis, we have developed a general semi-analytical solution for thermal-hydraulic-mechanical process. The semi-analytical solution takes the pressure solution from the hydraulic simulation module (or a commercial reservoir simulator) and directly predicts the stress tensor of the multiphysical system. As such, the solution can be programmed fully coupled with the hydraulic simulation module to predict the stress field with varying pressure and temperature of homogeneous poroelastic rocks under given stress boundary conditions. From the work above, we have laid a theoretical foundation for the stress approach. The derived semianalytical solution of the stress field shows excellent accuracy. The solution has been used to predict the transient stress field of a dual-porosity system during primary depletion. This paper is arguably the first trial in the petroleum engineering community to clarify the relationship between the stress approach and the displacement approach. Moreover, the derived semi-analytical solution provides a convenient yet precise way to obtain the stress field without time-consuming numerical simulation.",0,0,2
Semianalytical Solution,,"Velasco-Lozano, Moises; Balhoff, Matthew T.",Modeling of early- and late-time countercurrent spontaneous imbibition in porous media: A semi-analytical approach,Countercurrent spontaneous imbibition; Porous media; Oil recovery; Early-time solution; Late-time solution; Universal scaling,OIL-RECOVERY; WATER,"Countercurrent spontaneous imbibition (SI) is an important flow mechanism to recover oil in water-wet porous media through capillarity. Experimental imbibition tests conducted in core samples show that oil recovery as a function of time occurs in a characteristic S-shaped curve, which describes the infinite-acting and the boundary-dominated regime. Although several dimensionless time groups have been proposed to model countercurrent SI in porous media, they fail to properly scale the results, causing inaccurate estimates of oil recovery. In this work, we present a new approach, using a hybrid solution, to model countercurrent SI for oil-water systems dominated by capillary forces. The infinite-acting regime is modeled by an early-time solution using a new dimensionless time group, which enables the correct scaling of imbibition results onto a universal single curve. To model the boundary-dominated regime, we introduce a late-time solution derived as a function of a characteristic distribution of saturation to estimate the flow behavior after the imbibing fluid reaches the no-flow boundary. The novelty of the model is that it enables the accurate estimation of fluid imbibition under the boundary-dominated regime, a flow condition critical to evaluate the true potential of countercurrent SI driven by capillarity for oil recovery in porous media. We verified the model against numerical simulations under a wide range of flow conditions relevant in water-oil systems, and used experimental data reported in the literature to validate our model. The solution presented provides an accurate approach to model countercurrent SI, which could be extended for dynamic conditions and the modeling of the flow of fluids in fractured media.",0,0,2
Gas Kick,,"Gjerstad, Kristian; Aamo, Ole Morten",A dynamic model of two-phase flow for simulating gas kick and facilitating model-based control in drilling operations,Gas influx dynamics; Transient kick detection model; Gas bubble propagation in drilling well; Control-oriented gas-liquid model; Low-order two-phase flow model,,"A low-order two-phase dynamic flow model for drilling operations with gas kick is developed. The purpose is to enable fast and robust simulation of the behavior and propagation of influx gas in the bore hole, and the effects it has on the total flow dynamics. The model handles both open and closed wells, as well as the full range of pump rates and gas influx rates that are likely to occur in drilling operations. It incorporates equations for gas bubbles into a low-order liquid model in a new way. Some aspects of the gas are described in a mechanistic way, but with a new ""dual-shape"" bubble representation approach. Momentum is treated for the mixture as a whole, while conservation of mass is handled individually for each of the two phases. The result is a model consisting of a set of ordinary differential equations on explicit form, which makes it possible to couple it with control system- and estimation theory. A comparison with published data from four different sources shows that the model is able to qualitatively reproduce both steady state and transient responses in a handful quite different flow situations. In particular, we verified that the dominating effects that the gas has on compressibility, friction loss and hydrostatic pressure of the total mixture are satisfactory reproduced.",0,0,0
Gas Kick,,"Sleiti, Ahmad K.; Al-Ammari, Wahib A.; Abdelrazeq, Motasem; El-Naas, Muftah; Rahman, Mohammad Azizur; Barooah, Abinash; Hasan, Rashid; Manikonda, Kaushik","Comprehensive assessment and evaluation of correlations for gas-oil ratio, oil formation volume factor, gas viscosity, and gas density utilized in gas kick detection",PVT properties; Empirical correlations; Gas kick; Gas-oil ratio; Gas viscosity; Equations of state,EQUATION-OF-STATE; PENG-ROBINSON EQUATION; BUBBLE POINT PRESSURE; PVT PROPERTIES; NATURAL-GAS; EMPIRICAL CORRELATIONS; CUBIC EQUATIONS; TEMPERATURE; PREDICTION; COMPRESSIBILITY,"For reliable gas kick detection modeling and simulation, the PVT properties of the gas must be predicted accurately. The property correlations available in open literature are developed mostly for certain regions and conditions, which usually over-predict or under-predict when applied to different regions and conditions. To assess these correlations and to determine their applicability and accuracy, a comprehensive evaluation is performed for 63 empirical correlations of four gas properties; gas-oil ratio GOR, oil formation volume factor OFVF, gas viscosity, and gas density based on published laboratory measurements. The GOR and OFVF correlations were evaluated on a regional basis and three best-fit correlations are recommended for each selected region including the Middle East, Central & South America, North America, Africa, and Asia. A universal new correlation for the GOR is developed in this study that can be used for any region in the world with better accuracy and wider range than all available correlations. Furthermore, based on the evaluation results, the most accurate correlations for gas viscosity and density at high-temperature and high-pressure (HTHP) conditions are recommended. The density-based models of the gas viscosity show close results within a minimum average absolute relative error (AARE) of 3.50% to a maximum of 4.45%. Further assessment for the equations of state based on real compositions of the gas kick is recommended for future work. The present work provides a comprehensive and one-stop source database for property correlations and measured data related to gas kick detection.",0,0,1
Gas Kick,,"Duarte, A. C. R.; Ribeiro, P. R.; Kim, N. R.; Mendes, J. R. P.; Policarpo, N. A.; Vianna, A. M.",An experimental study of gas solubility in glycerin based drilling fluid applied to well control,Solubility; Drilling; Well control; Drilling fluids; Aqueous glycerol solution,METHANE,"The drilling fluid is the primary barrier element against a kick. In the path of drilling fluids evolution, syntheticbased drilling fluid (SBDF) is commonly used on offshore rigs due to its benefits to the high level of drilling complexity, especially at deep and ultra-deep-water scenarios. However, when formation gas dissolves in the mud due to high pressure and high temperature, the complexity of kick detection increases significantly. Furthermore, environmental concerns raised a red flag on SBDF usage due to potential impacts on the marine environment, with most governmental agencies around the world passing very strict regulations. Considering both aspects - safety, and environmental concerns - glycerin emerges as a potential candidate to perform a key role as a base drilling fluid (GBDF). At first, a GBDF has the potential to behave as an SBDF due to its benefits, such as lubricity and shale stabilization, and, at the same time, it has the same characteristics of water-based drilling fluid (WBDF) with very low methane solubility, the major component of natural gas. Additionally, GBDF is considered to be more environmentally friendly than SBDF. In this work, we first analyzed the PVT properties and rheology of three different molar composition glycerin-based drilling fluids: 100% glycerin, 5050% glycerin/brine, and 40-60% glycerin/brine. Then, we performed the PVT properties analysis of methane (10-50% molar mass) mixed with each of these GBDF mentioned. In a systematic constant composition expansion through a visual high-resolution PVT cell under temperature and pressure range conditions of 20-80 degrees C and 0-55 MPa, respectively, and rheology characterization. The GBDF exhibited interesting results for density and rheology parameters similar to an SDBF and no methane solubility. Finally, mathematical correlations are proposed and applied to illustrate a pit-gain calculation comparing to an n-paraffin-based drilling fluid.",0,0,3
Gas Kick,,"Ashena, Rahman; Ghorbani, Farzad; Mubashir, Muhammad",The root cause analysis of an oilwell blowout and explosion in the Middle East,Oilwell blowout; Explosion; Safety; Kick volume data; Root causal analysis; Development wells,,"Hundreds of blowouts have been reported during the history of the oil and gas drilling activities. These undesired accidents are at the cost of the life of people, in addition to the loss of the equipment and resources; thus, it is important to investigate the root causes of the blowouts in order to prevent them to occur in the future. In 2017, a blowout occurred in a development drilling well in the Middle East. It resulted in several consequences including fatalities, environmental related damages and a subsequent well capping. The incident happened mainly due to insufficient hydrostatic pressure during the tripping operation at the depth of 1132 m. The tripping was decided in order to change the bit when drilling horizontally at the depth of 2610 m. Some details regarding this blowout event will be presented in this paper and the engineering or operational activities and causal factors which led to the incident will be discussed, with the purpose of avoiding similar accidents in the future. Despite analysis of the past kick and blowout data for the whole field, the analysis of the kick volume data of the blowout well indicates that in the period of 2.66 h, the kick converted to the blowout, while in the last 7 min the kick volume reached from 172 to 341.5 bbl which was due to the sudden huge gas expansion. Such an analysis of the root cause factors was rarely made and presented in the region, as was done in this work.",0,0,3
Random Forest,,"Wahid, Md Ferdous; Tafreshi, Reza; Khan, Zurwa; Retnanto, Albertus",Prediction of pressure gradient for oil-water flow: A comprehensive analysis on the performance of machine learning algorithms,Pressure gradient; Horizontal wellbore; Oil-water flow; Machine-learning; Flow pattern,NEURAL-NETWORK; PATTERNS; VISCOSITY; NORMALITY; MODEL; DROP; TOOL,"Pressure gradient (PG) in liquid-liquid flow is one of the key components to design an energy-efficient transportation system for wellbores. This study aims to develop five robust machine learning (ML) algorithms and their fusions for a wide range of flow patterns (FP) regimes. The MLs include Support Vector Machine (SVM), Gaussian Process (GP), Random Forest (RF), Artificial Neural Network (ANN), k-Nearest Neighbor (kNN), and fusions of these five MLs. A total of eleven hundred experimental data points for nine FPs (two stratified and seven dispersed patterns) in horizontal wellbores are used to develop the MLs. The MLs' performance is evaluated using the metrics including mean absolute percentage error (MAPE), median absolute percentage error (MdAPE), coefficient of variation of root mean squared error (CV-RMSE), and adjusted coefficient of determination. The evaluation metrics are cross-validated using a repeated train-test split strategy. Seven important predictor variables are identified using a supervised feature selection approach: oil and water velocities, FP, input diameter, oil and water density, and oil viscosity. The results show that the high PG prediction accuracy can be achieved using GP compared to other MLs except for the ML-fusions (p < 0.05). A Friedman's test and Wilcoxon Sign-Rank post hoc analysis with Bonferroni correction show that PG prediction errors using GP are significantly lower than using the ANN model (p < 0.05). The values are 18.44 % and 23.9 % for CV-RMSE, 11.6 % and 10.06 % for MAPE, and 7.5 % and 6.75 % for MdAPE, using ANN and GP, respectively. While the previous studies mostly used ANN to demonstrate the capability of MLs to predict PG over the mechanistic or correlationbased models, the present research has shown that GP is even better than ANN using a wide range of FPs and a large data set.",0,0,1
Random Forest,,"Amiri-Ramsheh, Behnam; Safaei-Farouji, Majid; Larestani, Aydin; Zabihi, Reza; Hemmati-Sarapardeh, Abdolhossein",Modeling of wax disappearance temperature (WDT) using soft computing approaches: Tree-based models and hybrid models,Solid scales; Wax disappearance temperature; Multilayer perceptron; Random forest; ANFIS; Leverage approach,HIGH-PRESSURE; PHASE-EQUILIBRIA; CRUDE OILS; PREDICTION; PRECIPITATION; OPTIMIZATION; ALGORITHM; DEPOSITION; ANFIS,"Solid scales can cause significant problems in oil production and transmission systems such as oil flow rate reduction. Wax is one of the most critical substances that are highly prone to precipitate and deposit in oil pipelines. This occurrence typically happens in low temperatures, and can extremely affect the flow rate. In the wax deposition process, wax disappearance temperature (WDT) is a crucial factor since it denotes the lowest temperature, at which wax deposits melt and the consequences of wax deposition vanish. In this research, smart models were utilized to predict WDT as a function of molar mass and pressure according to a comprehensive database. The proposed intelligent models are radial basis function (RBF) and multilayer perceptron (MLP) neural networks, adaptive neuro-fuzzy inference system (ANFIS), random forest (RF), extra tree (ET), and decision tree (DT). The MLP networks were trained with Bayesian Regularization (BR) and Levenberg-Marquardt (LM) algorithms, and the ANFIS models were coupled with three optimization algorithms, namely Cultural Algorithm (CA), Biogeography-based Optimization (BBO), and Teaching-Learning-Based Optimization (TLBO). Results demonstrate that the developed RF model could present an outstanding performance and provide predictions for WDT with the lowest average absolute percent relative error (AAPRE = 0.246%), the maximum coefficient of determination (for predicting = 0.993), and minimum root mean squared error (RMSE = 1.01). Trend analysis showed that increasing pressure and molar mass leads to wax disappearance temperature increase. Lastly, outlier discovery was performed using the Leverage approach to recognize the suspected data points. The outlier detection found that only 6 points (out of 346) are located in the upper and lower suspected data zones.",0,0,2
Random Forest,,"Otchere, Daniel Asante; Ganat, Tarek Omar Arbi; Ojero, Jude Oghenerurie; Tackie-Otoo, Bennet Nii; Taki, Mohamed Yassir",Application of gradient boosting regression model for the evaluation of feature selection techniques in improving reservoir characterisation predictions,Feature selection techniques; Dimensionality reduction techniques; Reservoir characterisation; Ensemble machine learning; Decision tree algorithm,VIKING-GRABEN; MIDDLE,"Feature Selection, a critical data preprocessing step in machine learning, is an effective way in removing irrelevant variables, thus reducing the dimensionality of input features. Removing uninformative or, even worse, misinformative input columns helps train a machine learning model on a more generalised data with better performances on new and unseen data. In this paper, eight feature selection techniques paired with the gradient boosting regressor model were evaluated based on the statistical comparison of their prediction errors and computational efficiency in characterising a shallow marine reservoir. Analysis of the results shows that the best technique in selecting relevant logs for permeability, porosity and water saturation prediction was the Random Forest, SelectKBest and Lasso regularisation methods, respectively. These techniques did not only reduce the features of the high dimensional dataset but also achieved low prediction errors based on MAE and RMSE and improved computational efficiency. This indicates that the Random Forest, SelectKBest, and Lasso regularisation can identify the best input features for permeability, porosity and water saturation predictions, respectively.",0,0,2
Random Forest,,"Tripathi, Achyut Mani; DuttaBaruah, Rashmi; Subbiah, Senthilmurugan",Oil well drilling activities recognition using a hierarchical classifier,Drilling activities; Fuzzy rule-base; Hierarchical classifier; Oil well drilling; Random forest; Stuck pipe,,"Recognition of oil well drilling activities is a crucial task as it allows for identification of nonproductive time. Activity recognition is also important as it can be part of a complete oil well monitoring system. In this paper, we propose a novel hierarchical classifier that consists of Fuzzy Rule-based (FRB) and Random Forest (RF) Classifiers to recognize distinct oil well drilling activities in an oil well drilling process. The novel hierarchical classifier is designed by stacking the FRB and RF classifiers to achieve a classification of the numerous oil well drilling activities with high accuracy. The evaluation of the proposed method is illustrated through a case study of identifying the drilling activities in a real drilling data from oil well rig. Further recommended classifier generates an accurate report of time spent to execute the numerous drilling activities in a complete cycle of the oil well drilling process. Empirical evaluation of the real drilling data shows the efficiency and stability of the proposed method.",0,0,3
Sichuan BASIN,,"Zhu, Dancheng; Zou, Huayao; Yang, Minglei; Li, Ting; Li, Tao; Li, Haiping; Xu, Liang; Wen, Long; Zhou, Gang","The Middle Permian Maokou reservoir (southern Sichuan Basin, China): Controls on karst development and distribution",Carbonate reservoir; Reservoir distribution; Reservoir productivity; Dual permeability; Caves; Maokou Formation,EOGENETIC KARST; GAS-FIELD; CARBONATE; PERMEABILITY; CLASSIFICATION; POROSITY; DEPTH,"The Middle Permian Maokou limestone is a major natural gas producing reservoir in the southern Sichuan Basin, China. While matrix porosity is low, bit drops, losses while drilling, blowouts, and extremely high well testing flow rates indicate the presence of a dual permeability system in the form of paleocaves, which were formed by karstification in the late Maokouan Age. A combination of geological, paleogeomorphological and karstic analyses reveal that the development and distribution of the karst features within the reservoir are primarily regulated by shoal facies, paleotopography and syndepositional faults. In our conceptual paleogeomorphological model, the potential cave-bearing zones are located along the rim and outer edge of the Luzhou Paleohigh, which was the highland during the karst. Outside the highland were the karst slopes, and the poljes were on the flanks of the study area. Reservoir performance data suggest, there are two types of sweet spots in the study area. The first corresponds to the syndepositional fault zones along the rim of the karst highland and on the karst slope, where the caves appear to distribute along the faults, impacting the reservoir's vertical permeability. The second corresponds to the shoals of the Mao 2 and Mao 3 members on the lower western karst slope and the upper eastern karst slope, where the caves are widespread, enhancing the horizontal permeability and connectivity of the reservoir. However, the caves are rare in the central karst highland, lower karst slopes, and poljes, which is consistent with the limited gas discoveries.",0,1,2
Sichuan BASIN,,"Zhang, Wentong; Ning, Zhengfu; Gai, Shaohua; Zhu, Jie; Fan, Fan; Liu, Zongke; Wang, Hengli",Fast and effective observations of the pore structure of tight sandstones at the same location by utilizing AFM and CF-SEM,AFM; SEM; Surface morphology; Tight sandstones; Heterogeneity,TRIASSIC YANCHANG FORMATION; ATOMIC-FORCE MICROSCOPY; ORDOS BASIN; SICHUAN BASIN; SPONTANEOUS IMBIBITION; MECHANICAL-PROPERTIES; QUANTITATIVE-ANALYSIS; NANOPORE STRUCTURE; SURFACE-ROUGHNESS; GAS-ADSORPTION,"Atomic force microscopy (AFM), which allows 3D construction, nondestructive, and has a high resolution has been used to describe the pore structure of unconventional reservoirs. Due to its scalability, convenience, and flexibility, scanning electron microscopy (SEM) is widely conducted to describe the surface morphology of unconventional reservoirs. However, the two technologies are rarely combined to achieve fast and effective observations of the pore structure of unconventional reservoirs at the same location of the same sample (SLSS). In this study, nanoindentation technology is introduced to create a marked district (MD). Afterward, fast and effective observations of the pore structure of tight sandstones at the SLSS can be realized by searching this identifiable district with AFM and cold-field scanning electron microscopy (CF-SEM). The results demonstrate that AFM and CF-SEM rapidly capture observations of the surface morphology of tight sandstones at the SLSS. The method used in this study accomplishes the goal of fast and effective scanning at the SLSS (only a few minutes), while exhibiting the high potential of combining AFM and CF-SEM for comprehensively investigating the pore structure of reservoirs ranging from nanoscale to microscale. The most unique component of the presented method is that it is especially for the in situ observation of variations in the surface properties (morphology, electric, mechanical, surface force, and roughness) and pore size of all heterogeneous materials subjected to various external stimuli because the applied experimental technologies (nanoindentation, AFM, and CF-SEM) are all exhibit nondestructive properties.",0,0,2
Sichuan BASIN,,"Miao, Zhengshuo; Pei, Yangwen; Su, Nan; Sheng, Shouzheng; Feng, Ben; Jiang, Hua; Liang, Han; Hong, Haitao","Spatial and temporal evolution of the Sinian and its implications on petroleum exploration in the Sichuan Basin, China",Tectonic kinematics; Deformation quantification; Erosion distribution; Paleo-highs; lows; Dengying formation; Hydrocarbon accumulation,GIANT GAS-FIELD; PALEO-UPLIFT; SOUTH CHINA; TECTONIC EVOLUTION; ACCUMULATION; DISCOVERY; HISTORY; RODINIA; NORTH; RIFT,"In recent years, there have been significant discoveries of hydrocarbon resources with commercial value in the Dengying Formation of the central Sichuan Basin. However, the impact of tectonic evolution on hydrocarbon accumulation has not been appropriately documented. In this study, we employed multiple methods, including seismic interpretation, balanced cross-section restoration, deformation quantification, erosion calculation, and paleo-highs/lows reconstruction, to investigate the tectonic kinematics, erosion distribution, paleo-highs/lows evolution of the Sichuan Basin. The quantification of deformation reveals that the Sichuan Basin has experienced a complicated tectonic evolution, with two rounds of transition from tension to contraction since the Sinian. In the Late Ordovician, contraction caused by the Caledonian Orogeny resulted in a foreland basin being developed in the Sichuan Basin. Since the Late Triassic, the Sichuan Basin has experienced intense contraction, resulting in the development of its current structural pattern. By integrating the erosion distribution, the reconstructed paleo-highs/lows maps of Sinian strata indicate the development of inherited paleo-uplifts in the central and southwestern Sichuan Basin from the Early Cambrian to the present. The evolution of paleo-highs/ lows plays a critical control on the hydrocarbon accumulation of the Weiyuan and Anyue gas fields, indicating there could be high potential for hydrocarbon exploration in areas with high slope gradients in the paleo-uplifts.",0,0,3
Distributary Channel,,"Sun, Zhifeng; Bai, Qinglin; Ren, Huaiqiang; Yan, Ke; Gao, Liang; Wei, Liu Zhong","Quantitative evaluation of morphological characteristics of thin sand body: Taking the deltaic distributary channel sand body as an example in Shengtuo oil field of Dongying sag, east of Bohai Bay Basin*",Thin interbeds; Distributary channel; Architecture; Quantitative model; Sandstone reservoir,SEISMIC ATTRIBUTES; RESERVOIRS; DEPOSITS; ARCHITECTURE; DEPRESSION; PREDICTION,"Because of the small scale of distributary channel sand body and the superposition of sand bodies in vertical and lateral direction, drilling data with 150-200 m well spacing is difficult to describe its scale, shape and connectivity characteristics effectively. It has a great restriction on the recovery of these reservoirs. Taking Sheng2 Block of Shengtuo Oilfield as an example, the architectural elements of distributary channel are quantitatively investigated by using dense-drilling well and seismic data. Based on frequency division seismic data, the boundary of distributary channel belts are described vertically and laterally, and then the scale and morphological characteristics of channel bodies in the channel belt are characterized by using local dense well pattern data. The target layer can be divided into six channel belts longitudinally. After seismic frequency demultiplication, 60-75 Hz seismic data was used to describe the distribution of channel belts. From the bottom to the top, the width and distribution range of the channel belts decrease as a whole. Channel belt thickness and its width show linear positive correlation. On the channel-belt cross section, channel stories on the dense drilling-well logging profiles are identified with reference to the profile geometry of the distributary channel. On the channel-belt cross section, the projection distance between wells is fitted to a linear correlation with the thickness variation of channel stories. The ratio of the two parameters decreases from bottom to top of the target layer as a whole. The channel shape parameters predicted by the dense drilling-well logging section are of great significance to the study of paleocurrent deposition and paleohydrological evolution. At the same time, it has guiding significance for the development and adjustment of oil and gas reservoirs.",0,0,2
Distributary Channel,,"Ogbe, Ovie B.","Reservoir sandstone grain-size distributions: Implications for sequence stratigraphic and reservoir depositional modelling in Otovwe field, onshore Niger Delta Basin, Nigeria",Grain-size parameters; Well log signatures; Log-probability plot; Hydrocarbon reservoir sandstone; Sequence stratigraphy; Depositional environment,RIVER; ARCHITECTURE,"The grain-size distribution and the complexity of the sand-body suggests a high degree of heterogeneity of the depositional environments of clastic reservoirs. To understand the facies and depositional environments distribution of the oil-bearing sandstone reservoir in the Otovwe field, onshore Niger Delta Basin, an integrated sedimentological approach was employed. This involves the integration of well log signatures and log-probability plots of grain-size analyses of ditch-cuttings obtained from 3 wells that showed variability in the rates of oil production. The result suggests that the sediments were deposited in a fluvial environment that contains point bars of a lowstand systems tract; delta front environment that contains mouth bars and distributary channel deposits of a highstand and lowstand systems tracts, respectively; and the nearshore environment with tidal flat sediments of a transgressive systems tract. In some cases, stratigraphic correlation shows variations in facies succession at the same stratigraphic level in individual wells. A systematic variation in grain-size distribution parameters of the various depositional facies, however, appears similar in individual wells. These suggest that the location of the wells within the field experienced different depositional processes, fluvial controlled, and rates of reworking by marine-influenced. Grain-size distribution pattern shows very fine, and fine sands constitute the grain framework of the reservoir sandstone and a minor amount of silt and medium sands with an insignificant amount of sediment size ranging between coarser sand and fine gravel with clay. These suggest that possibly the very fine-grained and fine-grained sands constitute thick beds, silty-sand and shaly-sand as thin beds. Conversely, the clay and gravelly-sand occur as dispersed sediments constituted laminae, and lenticular beds, respectively. The mixture of silt and gravel possibly constituted the sediments that gave rise to the poorly sorted status of the reservoir. Variations in depositional environment and facies, together with grain-size distribution across the reservoir, possibly constituted heterogeneous elements that instituted the variability in the oil production rates of these wells. This study demonstrates the importance of ""textural-electrofacies"" analytical method in sedimentological studies in a situation where other subsurface data are not readily available for interpretation in anticipation of hydrocarbon reservoir sandstone management and field development in siliciclastic settings.",0,0,2
Distributary Channel,,"Li, Jingzhe; Sun, Zhifeng; Ren, Huaiqiang; Gong, Liang; Li, Tanglu; Du, Dongxing",Magnetic random walk algorithm and its application in the distributary channel system reservoir modeling,Distributary channel system; Reservoir description; Magnetic random walk; Reservoir modeling; Shengtuo oilfield,DELTA,"Random walk algorithms have unique advantages in reservoir modelling of distributary channel systems (DCS). However, the existing random walk algorithms often face several shortcomings, and typically do not perform adequately in complex scenarios. To overcome this problem, this paper introduces our recent development and application of magnetic random walk algorithm. The algorithm absorbs the concept of attraction and repulsion in the magnetic field and allows the walking seeds to wander randomly in a magnetic field composed of ""channel well"" observations and ""non-channel well"" observations, based on magnetic force. After post-processing of the walking trajectories, a DCS reservoir can be reconstructed. In a case study, the magnetic random walk algorithm efficiently completed the reservoir modelling, and parallels the manually drawn version completed by experienced geologists. This algorithm can effectively overcome several of the shortcomings of the existing methods and reduce manpower to a great extent in solving redundant work, which has a great application prospect.",0,0,2
Ensemble Kalman Filter,,"Safari, Mehdi; Ameri, Mohammad Javad; Gholami, Raoof; Rahimi, Ali",Water coning control concurrently with permeability estimation using Ensemble Kalman Filter associated boundary control approach,Water coning; Boundary control; Ensemble kalman filter; Permeability; Simulation,ENKF,"Undesirable water production due to water coning in hydrocarbon reservoirs has been a long-standing issue. This phenomenon decreases the oil production rate, increases the water cut and ultimately leads to early wellshutdown. Water coning may also interrupt the well testing data acquisition used to determine the reservoir permeability. In this study, attempts are made to propose a new approach which can control the water coning and estimate the reservoir permeability simultaneously. This was done by proposing a new boundary control model that was coupled by the Ensemble Kalman Filter (EnKF). A synthetic case study was considered to evaluate the performance of the EnKF associated boundary control (EnKF-ABC) approach. The results obtained indicated that the water cone development is controlled by the proposed method. In addition, the proposed method was also successful to estimate the reservoir permeability in the presence of water cone with less than 20% error after 12 times of downhole data acquisition. Even in the worst case scenario where there was a significant uncertainty in the initial estimated permeability, all the permeability ensemble members converged after about 200 days and tended to the real permeability after 500 days with less than 5% error. It was also observed that the Root Mean Squared Error (RMSE) of permeability sharply decreases when the ensemble size exceeds 15. The proposed approach is robust and reliable even where the mean of initial estimated permeability is considered quite far from the actual one. The EnKF-ABC approach proposed in this study can be applied to those production wells that suffer from water coning and there is lack of prior knowledge about the reservoir permeability.",0,0,0
Ensemble Kalman Filter,,"Yang, Shikai; Yang, Daoyong",Integrated characterization of wormhole network by use of a modified pressure-gradient-based (PGB) sand failure criterion and ensemble-based history matching during CHOPS processes,Wormhole network; Cold heavy oil production with sand; Pressure-gradient-based sand failure criterion; Ensemble-based history matching; Upscaling,RELATIVE PERMEABILITY; HEAVY-OIL; KALMAN-FILTER; CAPILLARY-PRESSURE; TIGHT FORMATIONS; DATA ASSIMILATION; MODEL; RESERVOIR; FLOW; QUANTIFICATION,"In this paper, a damped iterative ensemble Kalman filter (IEnKF) technique has been developed and integrated with a recently modified pressure-gradient-based (PGB) sand failure criterion to implicitly and inversely characterize the dynamic wormhole network during cold heavy oil production with sand (CHOPS) processes. With an improved upscaling process, not only has a microscopic PGB sand failure criterion been properly upscaled to the grid-scale simulation, but also it can be dynamically, implicitly, and inversely determined. Then, such a sand failure model together with three-phase relative permeability is validated and applied to reproduce wormhole network in a laboratory experiment conditioned to its sand production profile. Good agreements between the observed and simulated cumulative production profiles including oil, gas, and sand have been achieved with satisfactory convergence by integrating the ensemble-based history matching method. The simulated wormhole network has shown its great similarity to the experimental observations, while the convergence of the ensemble based history matching algorithm is greatly improved with a widespread of initial ensembles in each grid. Furthermore, deviations between the observed and updated production profiles can be significantly minimized by dividing the entire production period into three sequential stages, each of which has its distinct relative permeability curves due to the major effect (i.e., foamy oil flow, sand failure, and slurry flow) on its multiphase flow behaviours, respectively. By integrating the ensemble-based sand failure model with the damped-IEnKF method, the dynamic wormhole network during a CHOPS process can be accurately characterized with satisfactory convergence, demonstrating its robustness and practicality of dynamically and inversely simulating the preferential wormhole network. Such an ensemble-based sand failure model can be seamlessly incorporated with any commercial reservoir simulators under various conditions.",0,0,1
Colloidal Silica,,"Jin, Jiaqi; Lin, Chen-Luh; Assemi, Shoeleh; Miller, Jan D.; Butt, Darryl P.; Jordan, Taylor; Deo, Milind D.; Semeykina, Viktoriya",Nanopore networks in colloidal silica assemblies characterized by XCT for confined fluid flow modeling,Colloidal silica assembly; X-ray nano CT; 3D image analysis; Pore size; Permeability,CO2 STORAGE; DARCY FLOW; SLIP-FLOW; PERMEABILITY; FRACTIONATION; SIMULATION; TRANSPORT,"Fluid flow through nanopore structures has exhibited different behavior than that described by Darcy's law, derived from pore networks of micrometer scale. Pressure assemblies of colloidal silica spheres of specified diameters from 94 to 620 nanometers were prepared as model nano-porous media. The smaller silica spheres tended to form random packing, but some substantial ordering was found in the packing of the larger silica spheres. X-ray computed tomography (XCT), with a voxel resolution of 16 nm, was used to characterize the nanopore networks. The porosity of the Nano-XCT pore network (34%) was less than the total porosity of the assemblies as determined by X-ray attenuation (52%), possibly due to the limits of voxel resolution during segmentation. Fluid flow in the nanopore networks was simulated using the single-phase Lattice Boltzmann Method, and the simulated permeability was compared with the empirical and experimental values. Based on our characterization, although a well-ordered packing of silica spheres was not achieved, it was found that the nanopore networks in the colloidal silica assemblies had pore size distributions corresponding to the particle sizes. The simulated permeability was less than the experimental measurement for water flow, but the complex packing of silica spheres and surface chemistry issues need to be considered in future research.",0,0,2
Colloidal Silica,,"Pagano, Arianna Gea; El Mountassir, Grainne; Lunn, Rebecca Jane",Performance of colloidal silica grout at elevated temperatures and pressures for cement fracture sealing at depth,Colloidal silica; Well decommissioning; Plug &amp; abandonment; Wellbore integrity,WELL INTEGRITY,"Hydrocarbon well decommissioning requires the long-term sealing of abandoned wells. Current plug and abandonment (P&A) operations are not always able to address all potential fluid migration pathways, resulting in the possible upwards migration of hydrocarbons from formations penetrated by the wellbore. The development of innovative materials to improve well sealing remains a major challenge. This paper presents a proof of concept for the use of colloidal silica (CS)-based grout to improve the sealing performance of P&A operations. CS is a non-toxic suspension of silica nanoparticles (<100 nm) undergoing gelation upon destabilisation. Due to its excellent penetrability and controllable gel time, CS has the potential for repairing fine-aperture cracks within the cement sheath, at the cement/casing interface, or within a cement plug, where the penetration of cementitious grouts is restricted due to their relatively large particle size. In this study, the suitability of CS grout for deployment up to 1500 m depth was successfully demonstrated. Firstly, a range of CS grout mixes were investigated to test the feasibility of grout emplacement considering a timescale of 2 h for pumping operations from the surface to depth. Secondly, to investigate the sealing performance, the CS grout was injected into fractured cement cores (0.2 and 0.5 mm fracture aperture) and exposed to pressure and temperature conditions simulating downhole scenarios up to 1500 m depth (based on gradients for North Sea, UK). Fracture permeability upon water injection was assessed pre- and post-treatment. This work found that permeability values after treatment were reduced by three orders of magnitude, thus confirming the potential of CS grout for repairing fine-aperture cracks.",0,0,3
Other topics ,,"Taboada, Jose, V; Diaz-Casas, Vicente; Yu, Xi",CBM challenges and opportunities for O&M of the Johan Sverdrup Oil and Gas Field,Phases of johan sverdrup; Concept selection; Production profiles; Oil&Gas price; Condition base monitoring (CBM); O&M philosophy; Maintenance strategy; IO principles; LCC Analysis; O&M cost; Downtime cost; Cost-benefit analysis (CBA); Cash-flow; And future outlook,MAINTENANCE; OPTIMIZATION,"Paper describes the challenges and forward developments to face up on Operation and Maintenance (O&M) issues at the Johan Sverdrup field (Blocks: PL 501, PL 265 and PL 502), on the phases (Concept and Design, Construction and Hook-up, Commissioning, Operations and Maintenance, and Recycling), and a research study of the Oil&Gas profitability. Estimated reserves are between 1.8 billion to 2.8 billion bbl, so assessing the total risk of the field development is crucial. Although, development is estimated to cost up to $31 billion, but the full life-cycle price tag, including operating costs through 2068, is around $58.33 billion. The purpose of this paper is to demonstrate a conceptual methodology analysis framework, for understanding how analysis of cost and benefits, are carry out for assessment and implementation of the Condition Base Monitoring (CBM) and measure the total OPEX (Operate Expenditure/Operating Cost). As well as a specific maintenance philosophy and conceptual approach on the business cases studies of the project lead, to a cost-effective solution. Paper begins by providing a background for analyzing the life-cycle impacts during the life of the field (50 years), and describing measures to implement during the O&M strategies. Follows by targeting the expectations, which one rest on profitability and optimization of the field, with oil prices above $60 per barrel (proved on Case 3). The harvest will, therefore, be profitable even after the price crash. Life Cycle Cost (LCC) analysis (Alternatives A and B) focuses and identifies ""Cost Items"" (Cost Drivers) that the project carries. Achieved a reliable ""concept development"" is the greatest ambition, but uncertainties on Maintenance strategies and programs, have showed high cost at early phases. The aim was to measure the actual costs against predicted LCC and to calculate the cumulative costs throughout a product's Life Cycle (LC) of the assets. Discussed and summarized the extent to which these costs and benefits may already take into account and how the CBM strategy mechanism should be works based on a model built. Finally, is demonstrated through calculating an ""downtime scenario"" that could happens, which one creates Deferred Production Costs. Also, has been estimate the cost-benefit analysis (CBA) might be applicable on the researched project development ratio (cost vs. benefit), with overall maintenance effectiveness strategy under study on the LCC Alternative 2. Therefore, describing the maintenance support functionality, based on input obtained from CBM systems and a predictive, periodic maintenance plan is indispensable, in order to cut off potential costs, target future benefits and guaranty a safety robust production installation. At the end, the paper addresses the future performance outlook development in the Oil&Gas Industry as whole, stating essential optimization valuable principles.",0,0,0
Other topics ,,"Yan, Xiaoping; Liang, Huaqing; Dou, Xinyu; Qing, Meiyi; Cao, Xudong",An active magnetic ranging method for drilling cluster wells based on casing current excitation,Cluster wells; Collision avoidance; Active magnetic ranging; Current excitation; Magnetic induction intensity,OPTIMIZATION; MECHANISM,"Multiple wellheads are required to be constructed in a confined space for drilling cluster wells, so it is necessary to take high-precision cross-well ranging measures to prevent borehole collisions. To solve the problem of ranging between the drilling wells and multiple adjacent wells, a new method of ranging between adjacent wells based on the casing current excitation of adjacent wells is proposed, in which low frequency excitation current is injected into the casing in adjacent wells with time-division or frequency-division excitation mode, and the ranging tool in the drilling well is used to detect the magnetic induction intensity generated by the casing current around the formation, so as to determine the distance between adjacent wells. In this paper, the algorithm for determining distances and directions between adjacent wells is established, and the key factors affecting the ranging model are analyzed by numerical simulations. The results show that with the increase of well depth, the magnetic induction decreases at the exponential rate of exp, and high formation resistivity and low excitation current frequency are beneficial to enhance the magnetic induction. The experimental results show that within the range of 10 m, the measured value of magnetic induction intensity matches well with the theoretical value, and the directional measurement error is less than 1 degrees, which validates the effectiveness and accuracy of this method, and provides theoretical guidance and experimental basis for the development of anti-collision measurement while drilling system for cluster wells.",0,0,0
Other topics ,,"Skjevrak, I; Standnes, D. C.; Thomsen, U. S.; Xu, J.; Haland, K.; Kjolhamar, A.; Munkerud, P. K.",Field observations of reservoir souring development and implications for the Extended Growth Zone (EGZ) souring model,Reservoir souring; Field data; Controlling factors; Extended growth zone model,LIFE,"Microbial generation of H2S in-situ due to injection of seawater, so-called reservoir souring, can induce severe negative impact in terms of health, safety, maintenance and economics in mature oil fields. Historical H2S data have been collected for decades at the Norwegian Continental Shelf fields. The Gullfaks field in the North Sea has been negatively impacted by severe H2S production, whereas another comparable North Sea field, called Field B, only has minor H2S challenges. The difference in cumulative H2S development in Gullfaks wells are described as Type I, II and III by an empirical classification. Type I wells show rapid increase in the H2S concentration produced (< 1 year or < 1 mill. Sm(3)produced water), whereas Type III show a significant delay and slowly rising H2S production (> 10 years or > 10 mill. Sm(3)produced water). Type II can be considered as a mixture of Type I and III. To understand the difference between these types, a microbial reservoir souring model called the Extended Growth Zone (EGZ) model has previously been introduced. Differences in H2S development described by the three different well types are supported by the consequences of the EGZ model for both fields on field, platform/installation and well level. The results support that the overall drainage water injection strategy implemented is the single-most important cause governing the development of produced H2S over the lifespan of a field: High H2S production is expected when cold seawater is injected directly into oil bearing zones (Type I behavior). Relatively lower H2S production is expected when cold seawater is injected in the water zone below oil bearing zones (Type III behavior). The EGZ model describes the development of reservoir souring based on two main hypotheses (1) Degradation of crude oil as carbon source (2) The importance of temperature on the rate of H2S generation as summarized: The expected H2S development according to the EGZ model agrees with observed data from Gullfaks both on platform level (GFA > GFC > GFB) and for individual wells. The observed slow development of H2S for Field B observed for platform and well bore level is explained by the presence of Type III wells only. Type III wells in Gullfaks and Field B behave similarly within the uncertainty range for H2S production.",0,0,0
Other topics ,,"Aarsnes, Ulf Jakob F.; Ambrus, Adrian; Di Meglio, Florent; Gerbaud, Laurent",A phenomenological transient model of bit foundering,Drilling; Drilling optimization; Bit foundering; Bit-rock interaction; ESC,,"In this paper we developed a phenomenological transient model of bit foundering which accounts for cuttings transport around the bit through time-dependent erosion and deposition terms. By bit foundering we mean the observed effect where Rate of Penetration no longer increases (and potentially decreases) with Weight on Bit. The model is compared against several experimental data sets and a data set from a full-scale drilling test, and is shown to qualitatively replicate the foundering behavior observed in the data. The simple formulation of the bit foundering model makes it attractive for drilling optimization and control applications.",0,0,0
Other topics ,,"Gessner, Tobias R.; Barbosa Jr, Jader R.",An internally consistent procedure to characterize single carbon number fractions for phase equilibrium of petroleum mixtures: Application to Brazilian pre-salt reservoir fluids,Equation of state; Petroleum characterization; Reservoir fluids; HPHT wells; Brazilian pre-salt,REDLICH-KWONG EQUATION; PERTURBED-CHAIN SAFT; PHYSICAL-PROPERTIES; ALPHA-FUNCTION; OF-STATE; PRESSURE; PREDICTION; PARAMETERS; BEHAVIOR; MODEL,"Each natural accumulation of hydrocarbons has unique chemical and molecular characteristics. A complete experimental assessment of every substance involved is impossible and, in most cases, gaps left by laboratory tests must be filled by empirical correlations to provide the minimum set of parameters necessary for the proper functioning of a thermodynamic model. In the present work, a new procedure is developed for calculating the critical properties and acentric factor of single carbon number (SCN) fractions, valid for the C-7-C-22 interval (M-w <= 300 g/mol) and successfully tested for mixtures containing heavy fractions with average molecular weights up to 520 g/mol. The proposed method is based on a refit of existing correlations that fully respects the internal consistency of the equations. These, in turn, were selected by observing the trends described by the critical compressibility factor in the Soave-Redlich-Kwong (SRK) and Peng-Robinson (PR) cubic equations of state, resulting from the introduction of a volume translation parameter. After applying the new procedure to characterize ten oil samples collected from High-Pressure High-Temperature (HPHT) reservoirs in the Brazilian pre-salt cluster, thermodynamic parameters derived from flash and differential liberation tests were successfully predicted. With average absolute deviations of 8.38% and 8.32% for the SRK and PR equations of state, respectively, the proposed method is superior (or at least equivalent) to other characterization schemes considered in the study, with the advantage of being thermodynamically consistent.",0,0,0
Other topics ,,"Stanko, Milan",A material balance model based on mass conservation in the producing layer and gas and water injection in non-communicating gas-cap and aquifer layers,,,"In this work a material balance model has been developed, expanding the previous work of Borthne (1986), based on: the modified black-oil model, mass-conservation in the producing layer, gas and water injection in non-communicating gas-cap and aquifer layers and volume conservation between the producing, gas-cap and aquifer layers. The model takes as input produced surface quantities of oil (or gas) in time and voidage replacement ratios for gas and water injection and outputs reservoir pressure, associated surface quantities of gas (or oil), fluid saturations and surface volumes of aquifer and gas-cap. The model is solved by converging the pore volume of the producing layer in each iteration of the Secant method, which is used to converge the oil or gas mass balance of the producing layer. The pore volume of the producing layer is converged by substitution and considers the expansion of gas-cap and aquifer, the injected volumes of gas and (or) water and compressibility of connate water and rock. Injection of gas and (or) water is allocated to a gas-cap or aquifer layer only thus not affecting the saturation and mobility of oil and gas in the producing layer. The model successfully reproduces the results of the volatile-oil base case of Borthne and a dry gas case with a pot aquifer. Cases considering water and gas injection with different voidage replacement ratios are also simulated and discussed.",0,0,0
Other topics ,,"Clauer, Norbert","An elemental and Sr-87/Sr-86 isotopic restitution of contaminated pore waters from sandy sediments of the Peciko gas field (Mahakam Delta, Indonesia)",Restored pore waters; H 2 O and dilute HCl leachates; 87 Sr; 86 Sr ratios; Major; trace and rare-earth elemental contents; Peciko gas field; Mahakam delta (Indonesia),KETTLEMAN NORTH-DOME; STRONTIUM; BRINES; EVOLUTION; GEOCHEMISTRY; ORIGIN; KANSAS; BASIN,"Pore waters of hydrocarbon-bearing sand layers from gigantic Peciko gas reservoir located to the South of the Mahakam Delta in Indonesia were reconstructed and studied by applying the restored pore-water technique. The method is based on the Sr isotopic compositions of rock chips leached with de-ionized water aided, here, by the associated contents of major, metal and rare-earth elements (REEs). The soluble minerals were also leached with dilute hydrochloric acid and analyzed for their Sr isotopic compositions. The main founding is that many of the recovered H2O leachates were most probably contaminated during coring, which induced abnormally high metal and REE contents. The leachates considered free of pollution yield 87Sr/86Sr ratios that increase progressively with depth, which suggests a recent supply of surface waters to the upper pore waters. It seems also that only a few sedimentary horizons are interconnected at intermediate depths. Furthermore, the minerals dissolved by dilute HCl yield quite systematically lower 87Sr/86Sr ratios than the associated pore waters, which suggests a crystallization earlier than the recent flushing of the upper sediments by surface-type waters.",0,0,0
Other topics ,,"Kumar, Arvind; Balikram, Archana; Ojha, Keka",Deep transient testing methodology: An integrated approach to redefine the real-time reservoir complexities and well deliverability,Well testing; PTA; DST; DTT; Numerical modeling; Well deliverability,,"Pressure transient analysis (PTA) forms a critical part of the reservoir characterization and quantitative evaluation of reservoir properties. In most of the cases, the pressure transient data are acquired by conventional drill stem tests (DST) to estimate fundamental reservoir properties like permeability, skin, and boundary, used for various well deliverability studies. However, with the emergence of cost optimization scenarios due to reduced crude oil prices in the market, and strict regulatory standards issued by the concerned governments, many exploration wells fail to pass the feasibility standards for a conventional full-scale drill stem test. At the same time, conventional formation testers couldn't help because of the limitation of its extremely low radius of investigation. The recent development of an improved wireline formation tester (WFT) version known as Deep Transient Tester (DTT) enables the industry to capture the far-field reservoir properties with a deeper investigation, complex reservoir heterogeneities, and possible boundary information. However, the acquired data needs advanced solution techniques for accurate interpretation of the information, which lacks at present. In the present study, we have showcased the development of a novel workflow that can interpret the deep transient testing data with better accuracy. The workflow is called Integrated Deep Transient Testing (IDTT). The IDTT workflow is the first of its kind, as per our knowledge, that utilizes both the analytical and numerical methods for the pressure transient analysis with advancements in each of them. The workflow has been validated by comparing results from three modes of testing DST, DTT, and WFT in a common well. Reservoir engineers can refer to the IDTT workflow to interpret the DTT pressure data to characterize reservoir properties, boundary information, and deliverability studies in simple to complex geological settings using the presently developed method.",0,0,0
Other topics ,,"Ren, Lan; Tang, Dengji; Zhao, Jinzhou; Li, Mu; Gan, Wenjie",Optimizing the structural parameters of downhole vortex tool in gas well using a genetic algorithm,Vortex tool; Helical angle; Genetic algorithm; Optimization; Structural parameters,,"Structural parameters of vortex tools affect the drainage of water producing gas wells, while previous research mostly focused on the optimization of individual parameters. This study aimed at establishing the optimal sizes of downhole vortex tools. The gas-liquid separation efficiency (SE) model and pressure loss model of the vortex tool were also established. A multi-objective genetic algorithm (GA) optimization process was designed to achieve the maximum SE and minimum pressure loss of the vortex tool. A sensitivity analysis was performed to investigate the impact of structural parameters on SE and pressure loss of vortex tools. It was found that an increase in the spindle diameter (D-VT) and/or the helical height (H-VT) and/or a decrease of the flow channel width (W-FC) improved the SE of the vortex tool. In addition, reducing D-VT and/or H-VT and/or increasing W-FC reduced the pressure loss of the vortex tool. A set of optimum combinations of structural parameters was obtained through GA with an average SE of 0.9982, an average pressure loss of 1513.3 Pa, and an average fitness function value of 0.0068. Field results showed that the optimized vortex tools were conducive for gas well drainage and improved gas production. An optimized method for designing the structural parameters in vortex tools has been proposed in this study. Our study findings are of great significance in improving the drainage capacity of water producing gas wells.",0,0,0
Other topics ,,"Zahedizadeh, Parviz; Osfouri, Shahriar; Azin, Reza","Accurate, cost-effective strategy for lean gas condensate sampling, characterization, and phase equilibria study",Lean gas condensate; CVD; CCE; EoS tuning; Material balance,EQUATION-OF-STATE; PETROLEUM MIXTURES; SIMULATION,"Accurate recognition of the fluid phase behaviour is the most important and first step for the preservation and hydrocarbon reservoir management. Among the various hydrocarbon fluids, the lean gas condensate fluids show complex and unique behaviour. Due to the nature of these fluids, errors in the laboratory constant volume depletion (CVD) experimental data are inevitable. In this study, the significance of using CVD data in the EoS tuning process is debated using six samples of lean gas condensate. According to the negative composition in the CVD data material balance of all samples, just data of the constant composition expansion (CCE) experiment, saturation pressure, and liquid density in the stock tank are used for tuning the equation of state (EoS) as fundamental experimental data. The results of this study demonstrate that without using any CVD experimental data in the EoS tuning process, this data can be generated accurately using tuned EoS with fundamental data. Therefore, there is no need to do CVD experiments for lean gas condensate fluids characterization, which leads to reduces not only the error in the simulation process but also the laboratory costs. Furthermore, the tuning strategy in this study demonstrates that molecular weight of plus fraction and the volume shift parameter of the heaviest pseudo-component are the effective parameters to adjust the EoS. The objective function has reduced from 0.7360 to 0.1538 (79.10% improvement) just by using these two parameters. A constrained tuning strategy was proposed to keep the critical properties and acentric factor expected trends versus carbon number. The results show uniform and swing trends in the case of constrained and unconstrained tuning strategies, respectively. Therefore, using a constrained tuning strategy is essential to obtain a fluid with an authentic thermodynamic background after the tuning process. The proposed analysis method of CVD experimental data suggests that gas compressibility factor and gas composition as the main sources of error, while the experimental parameters of retrograde liquid and cumulative gas production have ignorable errors.",0,0,0
Other topics ,,"Loomba, Ashish Kumar; Botechia, Vinicius Eduardo; Schiozer, Denis Jose",A comparative study to accelerate field development plan optimization,Distributed Computing; Efficiency; Field development plan; Giant field; Isolated sector; Optimization; Partial simulations; Predictive analytics; Propagation of best experiments; Reservoir simulation; Time-consuming models; Uncertainties,,"Rigorous and continual advancement in the computational domain have drastically reduced the time consumed for simulations. Despite this, the heterogeneity and requirement to use compositional models, among constraints such as field size, can still thwart the optimization of the field development plan (FDP) in terms of time spent. To address this, we proposed and compared different techniques to underscore how to optimize FDP efficiently under uncertainty using an example of a giant benchmark field. We compared four workflows to improve the efficiency of the optimization process. Method 1 uses a full-field model (FFM) approach with an intelligent selection process to eliminate the poorest FDPs. As it is usual to divide a field into sectors for risk-aversion and strategic purposes, Method 2 uses an isolated-sector approach to reduce average simulation time. Method 3 employs the FFM approach to perform the optimization using only the monetary value of the partial life of the field. Method 4 uses a cluster-based search space reduction technique for a predictive analysis from the technical results obtained with partial simulations, which are similar to Method 3. To ensure good decisions, the optimized FDP was always implemented in the FFM with complete field-life at the end of all methods. All proposed workflows are promising in terms of efficiency, acknowledge the entire envelope of uncertainty, and consider multiple scenarios to improve the chances of success of the optimized FDP in the real field. Aside from obtaining good results when compared to traditional methods, we also saved 80-93% of the computational time with these methods. Thus, one can reduce exorbitant costs and delays in performing the FDP optimization. As anticipated, we observed a generic trade-off between decreasing computational time and increasing field objective function. Despite this, using a new algorithm with predictive analytics in Method 4 produced the best improvement within the shortest timespan, which demonstrates that one can use shorter-term data to understand a field's non-linear response. Numerous authors have already presented various algorithms to optimize an FDP. Despite the existing computational capabilities, these algorithms are still inept at developing a field with time-consuming simulation models. Unlike previous studies, this work presents practical solutions to assist field development, considering probabilistic scenarios to capture associated uncertainty. We also discuss the advantages and disadvantages of the methods to establish their application in different situations.",0,0,0
Other topics ,,"Li, Shengli; Ma, Y. Zee; Gomez, Ernest",Correlation-based data analytics of wireline logs for decoding and modeling shale gas resources,Organic mudstone; Wireline logs; Correlation-based analytics; Simpson's paradox; Causal inference,,"Correlation is widely used and its importance has become even more pronounced in big data. Generally, scientists and engineers look for highly correlated variables and ignore weakly correlated variables. We use a more holistic view of correlations in evaluating unconventional resources by integrating correlation with causal inference. In formation evalutions, many variables are involved and they generally have different effects on hydrocarbon accumulations, and they are inter-correlated. These phenomena often lead to weak correlations among causally related variables. We show that using weak or moderate correlations can help identify gas-prone lithofacies. This methodology is related to discerning a statistical phenomenon, termed Simpson's paradox. Although this paradox has been interpreted as a bias in the literature, we show that it can genuinely represent a weak correlation as an effect of multiple causes. More importantly, we will show that both a weak and strong correlation of wireline-log data can be used to decode gas-prone organic mudstones in evaluating and developing shale gas resources when the causal inference based on physical laws is invoked.",0,0,0
Other topics ,,"Salmani, Niloofar; Fatehi, Rouhollah; Azin, Reza",A Double-Scale method for near-well flow in reservoir simulation,Gas-condensate reservoir; Algorithms; Computational methods; Overlapping grid,REACTIVE FLOW; GRIDS,"Simulation of near-well flow around a single well in reservoirs is normally studied using radial logarithmic grids. A promising method for more complicated, multi-well cases is a combined approach of using a Cartesian and a radial grid. In this paper, a new method of overlapping grids is introduced in which a radial grid is overlapped on a coarse Cartesian grid in the area around a well. Connectivity between the two grids is established using an appropriate boundary condition. Five different algorithms of grids connectivity with internal boundary conditions are presented in which the data are transferred between the grids by interpolation pressure and saturations in each grid. This method is implemented in the open-source Matlab Reservoir Simulation Toolbox (MRST) using the modified black-oil model. The proposed approach is validated by simulation of a reference fine radial grid model on a gas-condensate reservoir. Comparing the results with the reference model indicates that the proposed Double-Scale method using a 21 x 21 coarse Cartesian grid is as accurate as a 1001 x 1001 simple Cartesian fine grid model. Then, a double-layer numerical problem with two production wells was simulated and sensitivity analysis was conducted to investigate the effect of critical condensate saturation and vertical permeability. Finally, the second SPE comparative solution project was simulated to compare the performance of the proposed method with the use of the perpendicular bisector (PEBI) grids around the well. Results showed that the accuracy of the PEBI grid and Double-Scale method are comparable. However, the proposed Double-Scale method is almost 2 times faster in this specific problem.",0,0,0
Other topics ,,"Wood, James M.",Effect of reservoir characteristics on the productivity and production forecasting of the Montney shale gas in Canada: Discussion,Montney Formation; Tight gas; Shale gas; Well performance; Reservoir quality (RQ); Total organic carbon (TOC),TIGHT-GAS; SOLID BITUMEN; INSIGHTS,"Kim et al. (2019) recently presented an analysis of the influence of reservoir and completion parameters on natural gas production from wells drilled and completed in the Montney Formation in Alberta, Canada. A key finding of their study is that one of the reservoir quality parameters, total organic carbon (TOC), has a strong positive linear relationship with peak monthly gas rate. However, their data set incorrectly includes a TOC measurement of a drill-core sample acquired from the unrelated Jurassic Nordegg Member, which unconformably overlies the Triassic Montney Formation. Excluding this single inapplicable Nordegg sample from the Montney data set results in peak monthly gas rate having essentially no significant correlation with TOC, and calls into question the proposal of Kim et al. that productivity in the unconventional Montney gas play can quantified and forecasted solely on the basis of organic carbon content parameters.",0,0,0
Other topics ,,"Wang, Yuzhu; Sun, Shuyu",Image-based grain partitioning using skeleton extension erosion method,Image-based grain partitioning; Granular rock sample; Skeleton extension erosion,CENTROIDAL VORONOI TESSELLATIONS; CONVEX; RECONSTRUCTION; ALGORITHMS,"Image-based grain partitioning is carried out to classify a granular rock sample's image into numerous single grains, which is the premise of obtaining grains' geometry features (e.g., grain size and sphericity) and grains' contact relationship. Because grain geometry features play an important role in understanding the rock petrophysical properties and the sedimentary environment, image-based grain partitioning attracts more and more attention in the digital core society. Several grain partitioning algorithms have been proposed and applied in some rock samples. However, it is still challenging to process the consolidated rock samples in which most of the grains adhered with each other, characterized by stylolite contact. All current grain partitioning algorithms contain two steps: grain center's extraction and identifying each grain domain. In the image of a granular rock sample, the grain centers can be defined as the local maxima of the solid phase's Euclidean distance map or the remaining cores after successive erosions of the solid phase. However, the former option prefers to result in an over partitioning, while the latter choice brings under partitioning. In this paper, an innovative image-based grain partitioning algorithm based on skeleton extension erosion strategy is proposed to improve the under partitioning problem. The key idea of the proposed method is to introduce the skeleton extension erosion strategy to realize the differential erosion by which the potential grain boundaries will be eroded but the other part is intact. This process effectively enhances the ability of the proposed method to deal with consolidated granular rock samples. The proposed method presents better performance than the popularly used methods, including the watershed grain partitioning method and the erosion-watershed grain partitioning method.",0,0,0
Other topics ,,"Ravazzoli, Claudia L.; Blanco, Gonzalo",A rock physics analysis based on inversion of poroelastic Brown and Korringa parameters in Vaca Muerta shale: Theoretical aspects and applications,Rock physics; Poroelasticity; Brown and korringa model; Critical porosity; Inversion; Vaca Muerta,FLUID SUBSTITUTION; COMPRESSIBILITY; CONSTANTS,"In their classical paper, Brown and Korringa (1975) developed a theory to describe the elastic behavior of porous saturated rocks with microheterogenous frames, valid for isotropic and anisotropic media. However, it has been almost unused for practical applications in geophysics due to the difficulties in the determination of the parameters involved. With these ideas in this work we propose and test a simple modeling workflow for composite porous rocks which does not require detailed petrophysical information about mineral volume fractions and their corresponding elastic properties. This is particularly convenient when dealing with multiphase rocks, such as organic-rich shales, which are formed by many different minerals, organic matter, and pore fluids. The physical parameters of such amount of constituents may introduce errors and uncertainty in the computations. To overcome this problem we show that it is possible to calibrate the model coefficients using a numerical inversion procedure without using a detailed description employing Brown and Korringa (1975) and Gassmann (1951) formulations. We illustrate the application of the procedure using real data of the Vaca Muerta shale formation. We analyze appropriate search ranges for the different model coefficients, with special attention to the feasibility of the inversion of the unjacketed pore modulus from velocity data. The overall goodness of fit between real and synthetic velocities is quantified and the statistical distribution of the inverted coefficients, as well as the determination of the critical porosity in this shale, are also discussed.",0,0,0
Other topics ,,"Ozturk, Ufuk; Tureyen, Omer Inanc; Satman, Abdurrahman",A study on the proper location of observation wells for various boundary conditions for geothermal reservoirs,Geothermal reservoir modeling; Observation well location; History matching; Pressure forecast; Average reservoir pressure,MODELS,"This study deals with the determination of the region within a geothermal reservoir that best provides the volumetric average reservoir pressure. This is performed in order to able to determine the proper location for an observation well through which the volumetric average reservoir pressure could be recorded. In this study a numerical work is carried out for determining the proper location for an observation well to be placed for various configurations of reservoir outer boundary conditions and well configurations. Even though either a single well or two wells are used, the results may be generalized to cases where there are multiple wells in the reservoir by using the production/injection well locations as the region where production/injection occurs. The locations of the wells and boundary conditions have been chosen as to cover many of the possible configurations that could take place in practice. The boundary conditions used in this study are of two types; a sealed outer boundary and a constant pressure outer boundary for mimicking the effects of a recharge source. Wells are considered to be either producer or injector wells where a constant rate production or injection scheme is applied. The effects of faults are also considered in this study where the faults are modeled as a very high permeability medium. The results of this study provide various maps for various boundary and well configurations from which the engineer may be able to determine qualitatively where to place the observation well. This study is original in the sense that to the authors knowledge no such study exists in the literature. This study will be filling the gap.",0,0,0
Other topics ,,"Jo, Yeonghwa; Choi, Yonggyu; Seol, Soon Jee; Byun, Joongmoo",Machine learning-based vertical resolution enhancement considering the seismic attenuation,Resolution enhancements; Gas reservoir; Time-variant; U-net,DECONVOLUTION,"The vertical resolution of seismic data is important for the interpretation of geologic features at a fine scale. To improve the resolution of seismic data, spectral enhancement has progressed mainly due to one-dimensional (1D) convolutional models and deconvolution filters; however, recent studies have applied machine learning (ML) algorithms. To generate successful outcome using ML techniques, it is important to reflect the features of target data in the training stage of the ML model. One of main features of seismic field data is a non-stationary wavelet over time due to the change of frequency content as the wavelet passes through specific regions, such as a gas reservoir. However, since conventional methods are generally based on a 1D convolutional model, which assumes that the propagating wavelet is stationary, they show low performance for the parts where the frequency content of the wavelet is significantly changed. In this study, we developed a spectral enhancement algorithm using ML techniques, which can be applied to a seismic trace with different frequency contents over time. We showed that sparse spike inversion results of all target data, rather than just well log data, can be useful to obtain information on the reflectivity series for generating a training data set. To verify the performance of the new algorithm, we compared the spectrally enhanced results from the ML model trained by stationary wavelets and time-variant wavelets and confirmed that the latter wavelets provided better results. In addition, we proposed a quality control (QC) method for verifying the spectrally enhanced results.",0,0,0
Other topics ,,"Azari, Vahid; Vazquez, Oscar; Mackay, Eric; Sorbie, Ken; Jordan, Myles",Gradient descent algorithm to optimize the offshore scale squeeze treatment,Oilfield scale; Squeeze treatment; Iso-lifetime designs; Treatment optimization; Gradient descent algorithm,AUTOMATIC OPTIMIZATION; OIL; INHIBITORS; PRECIPITATION; INJECTION; IMPACT; FLOW,"Scale deposition is one of the serious oilfield chemical issues which may lead to a range of downhole and production problems, including the reduction of well productivity index. Scale Inhibitor (SI) squeeze treatments are one of the most common techniques which are applied to prevent downhole scaling in production wells. A treatment typically consists of four stages, (i) a preflush, to condition the rock surface; (ii) a main treatment, where a batch of high concentration inhibitor is bullheaded into the formation; (iii) an overflush, to displace the scale inhibitor slug deeper into the near-well formation, and (iv) a shut-in stage to allow further inhibitor retention before putting the well back on production. During this backflow period, scale inhibitor is released from the rock surface into the produced water, and the scale deposition is prevented if the inhibitor concentration is above some specified Minimum Inhibitor Concentration (MIC). Due to logistic constraints in offshore wells, it is often required that the scale protection afforded by a squeeze treatment should last for some fixed design lifetime until the next treatment becomes available. For example, in the North Sea sector, well operations are often based on an annual treatment design. This paper presents a methodology to optimize the squeeze treatment design for a fixed target lifetime and this is applied for two offshore well squeeze treatments. This approach allows us to account for the operational constraints in the squeeze optimization process to treat a fixed volume of produced water, while minimizing the inhibitor neat volume and the total pumping time. A sensitivity study was performed on the inhibitor concentration, where the results showed that deploying a smaller inhibitor slug but with higher concentration is more effective than a larger slug with lower concentration, assuming a fixed volume of inhibitor and injected water. Therefore, it is recommended that the inhibitor is deployed at the maximum possible concentration, while avoiding the potential for any formation damage. Considering the same inhibitor slug (volume and concentration), this study suggests that the squeeze lifetime continuously increases with the overflush volume. This implies that the lifetime function is differentiable with respect to the overflush, and thus a gradient-based optimization algorithm, specifically the Gradient Descent (GD) may be applied to find the exact overflush volume resulting in the target lifetime. Employing this procedure for a wide range of main treatment volumes allows us to calculate the squeeze ""Iso-Lifetime"" curve which represents all the possible squeeze designs for the target lifetime. Thereafter, from the iso-lifetime designs, the CPB value (total cost of squeeze per treated barrel of water produced) can be minimized to find the most optimum squeeze design. This approach is shown to result in the optimum scale inhibitor squeeze treatment strategy in the long-term.",0,0,0
Other topics ,,"Jafarizadeh, Babak; Bratvold, Reidar B.",Project Economics in the Big-Bets Industry: The Integrated Valuation in Practice,Project valuation under uncertainty; Investment analysis; Exploration economics; Real options; Economic decision analysis; Oil price dynamics,EXPLORATION VALUATION; OIL; INVESTMENT; FINANCE; COST; RISK,"Value creation from petroleum projects is uncertain. Yet, even with great odds of failure, companies increasingly take on these ventures. Here, no analytics could cut failures out. We could only avoid loss by avoiding poor investment decisions. In practice, most valuations use inconsistent principles that potentially obscure the value-maximizing decisions. For example, when drilling for hydrocarbons most firms decide which opportunity to drill based on their expected value-calculated from values of multiple outcomes, each with different levels of uncertainty but traditionally evaluated with a single discount rate. The all-inclusive discounting could lead to biases and poor decisions. In this paper, we discuss the shortcomings of the traditional approach and implement a coherent method of integrated valuation that, while more detailed, excels in valuation of uncertain investments.",0,0,0
Other topics ,,"Huang, Kun; Zhang, Liming; Zhu, Weiyao; Sun, Lei; Xia, Jing",Nonequilibrium override phenomenon between gases in condensate gas development,Condensate gas; Gas override; Nonequilibrium thermodynamics; Entropy production,SIMULATION; INJECTION,"The cyclic gas injection technique is widely used in the development of condensate gas reservoirs. However, the override of injected gas induces severe gravity segregation in formations, thereby substantially limiting the application of this technique. At present, few literatures have been found to illustrate the override phenomenon taking place between gases. In this study, experiments were performed, and nonequilibrium thermodynamic theory was used, to examine the phase behavior of injected dry gas and condensate gas in place during the gas injection process. It is observed that in the equilibrium state, the injected gas can potentially reduce the condensate content by about 80%, yet the equilibrium is hard to achieve and the accompanied gas override weakens the effect of injected gas. After gas injection, the visual cell in the pressure-volume-temperature test exhibits a combination of dry gas-condensate gas-condensate oil for the case in which the testing pressure fluctuates around the dew point pressure and a combination of dry gas-condensate gas for the case in which the testing pressure exceeds the dew point pressure. Displacement experiments that were performed on a twodimensional sandpack helped to determine the dynamic evolution of gas override, and until the end of the tests, the overburden degree increases 13% and 28% for the symmetrical injection mode and the top injection mode, respectively. Further theoretical analysis indicates that after gas injection, the system is prone to becoming trapped in a nonequilibrium steady state in which the fully mixed scenario is unlikely to occur. The results of this study enrich the understanding of the nonequilibrium override phenomenon, especially for that occurs between gas phases, and are crucial to early prediction and intervention of gas override.",0,0,0
Other topics ,,"Lobanov, A.; Fedorovskiy, S.; Promzelev, I; Tikhomirov, E.; Mosharev, P.; Struchkov, I",Systematic approach to quality management of downhole sampling: Analysis of current trends in Russia,Reservoir fluids; Downhole sample; PVT-Studies; Quality assurance; Quality control,,"The overview and analysis of technical, regulatory and procedural, administrative and business aspects of current situation in the field of downhole sampling in the Russian Federation is presented. The author's viewpoint on the physical and chemical factors of the samples quality is presented, concept and development trends of systematic approach to quality control of downhole sampling are proposed.",0,0,1
Other topics ,,"Chen, Zijuan; Yu, Wei; Liang, Jenn-Tai; Wang, Suojin; Liang, Hwa-chi",Application of statistical machine learning clustering algorithms to improve EUR predictions using decline curve analysis in shale-gas reservoirs,Data analysis; Decline curve model; Estimated ultimate recovery; Horizontal well; Shale gas,SIMULATION; TRANSPORT; CHOICE; MODEL; FLOW,"A robust machine learning workflow using two well-established statistical clustering algorithms, K-Means Clustering (K-MC) and K-Nearest Neighbors (K-NN) was developed to improve ultimate recovery (EUR) predictions of new wells in shale-gas reservoirs using a decline curve model developed by Duong (2011). These two clustering algorithms can handle big datasets with multiple well parameters with high computational efficiency. Out of a total of 55,623 dry-gas wells from seven shale gas formations, 7631 wells that fit the criteria for Duong's decline curve model were selected in this study for further analysis. K-MC and K-NN were applied to group wells with similar well characteristics using well location, well depth, well length, and production starting year as parameters. Locations of the grouped wells show that the clusters of wells with similar well characteristics identified by both clustering methods scatter over a big area. These findings clearly demonstrate that simply grouping wells by the proximity of physical locations is not a good way of identifying wells with similar well characteristics. The results from this study also suggest that the selection of optimal clustering methods is highly dependent on the shale formation and the method used for EUR prediction. Even with the limited number of well parameters available in the datasets used in this study, the machine learning clustering algorithms managed to improve the EUR prediction accuracy by around 20%. More available well information will allow the machine learning algorithms to capture more of the well characteristics, thereby further increasing the accuracy of EUR predictions.",0,0,1
Other topics ,,"Milkov, Alexei, V","Reporting the expected exploration outcome: When, why and how the probability of geological success and success-case volumes for the well differ from those for the prospect",Well; Prospect; Probability of success; Exploration; Petroleum,RISKS,"Some petroleum explorers and exploration companies do not distinguish the probability of geological success (PoS) and the success-case volumes estimated and reported for the prospect from those for an exploration well. This may mislead decision-makers and investors and may result in disappointments with drilling outcomes. When the well is positioned downdip from the highest closure point(s) of explored segment(s) (also called target (s) or zone(s)) in a prospect in order to penetrate larger than the minimum assumed petroleum column(s), the geological PoS for the well is smaller than the geological PoS for the prospect. Conversely, the expected successcase volumes for such a downdip well are larger than for the prospect. This paper discusses a simple fictitious prospect with three segments and the exploration well that penetrates these segments downdip from highest closure points. The results demonstrate the key differences in geological PoS and success-case volumes between the well and the prospect. Proper reporting of the expected exploration outcomes from planned exploration wells will result in better-informed drilling decisions. Modeling outcomes of drilling the well at various locations within the prospect would help to understand if the well can discover the minimum economic field size, estimate the volumes that may remain untested updip, and maximize the expected monetary value of the exploration project. During postmortem evaluations (look-backs), it is important that well outcomes are compared with relevant pre-drill well assessments.",0,0,1
Other topics ,,"Li, Changzhi; Xu, Guosheng; Xu, Fanghao; Yu, Qing; Liang, Haoran","A model for faults to link the Neogene reservoirs to the Paleogene organic-rich sediments in low-relief regions of the south Bohai Sea, China",Rift basin; Source rock; Fault displacement; Caprock thickness; Hydrocarbon accumulation,,"Fault acts as an important vertical migration conduit for hydrocarbons in rift basins and can transport hydrocarbons from deep-buried organic-rich sediments to shallow-buried coarse-grained sequences. Such migration process is expected, but generally needs to pass through thick mudstone intervals and its controlling factors are not well understood. The low-relief regions of the south Bohai Sea in the Bohai Bay rift basin, comprising both Paleogene and Neogene hydrocarbon traps, can act as a good case study for the factors controlling the hydrocarbon transporting capacity of faults. By comparing the hydrocarbon generation potential of source rocks in different formations, we confirm that the hydrocarbons trapped in the Neogene traps mainly originate from the Eocene Shahejie Formation, and need to pass through a thick Oligocene regional caprock. Hydrocarbon fluid inclusions within the Neogene reservoir sandstones indicate two major hydrocarbon charging events in the middle Pliocene to Quaternary, based on which we chose the T-0(2) seismic marker bed to calculate fault displacement. Seismic profiles show that Neogene hydrocarbon-charged traps are commonly linked to faults with large-amount displacement, where the regional caprock has a limited thickness. Using statistics of the Neogene charged traps in a regional 3D seismic grid, we draw the minimum fault displacement for hydrocarbon migration in the Laizhouwan Sag at 53.6 m and in the Huanghekou Sag at 56 m, and the biggest caprock thickness for hydrocarbon migration in the Laizhouwan Sag at 240.7 m and in the Huanghekou Sag at 320.2 m. These observations emphasize the coupling of fault displacement and regional caprock thickness controlling the hydrocarbon transporting capacity of faults in a rift basin.",0,0,1
Other topics ,,"Wang, Qiaochu; Chen, Dongxia; Wang, Fuwei; Gao, Xianzhi; Shi, Xuebin; Jiang, Mengya; Li, Sha; Lei, Wenzhi; Cheng, Ming",Attenuating gradient of residual stratigraphic pressure and its controls on hydrocarbon migration and accumulation,Abnormal pressure; Residual pressure; Hydrocarbon migration; Geodynamics; Attenuating gradient; Huimin depression,PORE-PRESSURE; FLUID-FLOW; SECONDARY MIGRATION; PETROLEUM MIGRATION; ABNORMAL PRESSURE; BASIN; OVERPRESSURE; ORIGIN; MODEL; GENERATION,"Abnormal stratigraphic pressure is highly significant for hydrocarbon migration and accumulation for the exploration and exploitation of exploratory fields. However, the relationship between abnormal pressure and hydrocarbon migration processes is difficult to characterize quantitatively. In this paper, a new parameter, the attenuating gradient of residual pressure (AGRP), which is defined as the variation in residual stratigraphic pressure over a unit distance in a certain direction, is introduced to characterize hydrocarbon migration forced by residual pressure and hydrocarbon accumulation influenced by fault seals in the Huimin Depression, Bohai Bay Basin. The AGRP against the geological background can be calculated by the formation pressure of the source region by equivalent depth method using well log data (sonic travel time/velocity and resistivity) formation pressure of hydrocarbon reservoirs by drill stem tests of 32 exploration wells. For the Huimin Depression, the calculation results of the third member of the Paleogene Shahejie Formation (Es-3) reservoir interval show that the northern tectonic uplift belt (NTUB) and parts of the central deep sag zone (CDSZ) and southern slope belt (SSB) are characterized by stepped distributions of high AGRP values ranging from 1.2 to 2.5 MPa/km with developed faults. The other parts of the Huimin Depression are characterized by continuously distributed low AGRP values from 0.5 to 1.0 MPa/km. The AGRP is effective for characterizing and evaluating hydrocarbon migration and accumulation in structural hydrocarbon traps with AGRP values higher than 1.0 MPa/km, which indicates that these reservoirs are dominated by residual pressure as the main driving force. For these traps, oil and gas tend to migrate to the high-AGRP areas, which indicates a large driving force by residual pressure. Furthermore, the stepped distribution of the AGRP suggests a well-sealed fault and hence good preservation conditions for hydrocarbon accumulation. This study shows that the AGRP can characterize hydrocarbon migration and accumulation more precisely and hence provide guidance for petroleum exploration and exploitation, especially in rift petroliferous basins with abnormal pressure and developed faults.",0,0,1
Other topics ,,"Yolchuyeva, Ulviyya; Jafarova, Rena; Khamiyev, Matlab; Vakhshouri, Amir Reza; Khamiyeva, Gunay",Investigation of photochemical conversion processes in aromatic hydrocarbons of Balakhani oil,Balakhani oil; Petroleum luminophore; Photo-irradiation process; Photochemical conversion,ENERGY-TRANSFER; PETROLEUM; PHOTOIRRADIATION; PRODUCTS,"In this paper, Balakhani oil, as the case study, was separated into 4 groups of aromatics by adsorption column chromatography. With the aid of GC-MS and UV/vis spectrometers, it was proved that the composition of the separated groups is mainly composed of mono-, di-, tri- and a trace amount of tetracyclic aromatics. The conversion process of separated aromatics under photo-irradiation was investigated by IR, UV, H-1 NMR and GC-MS spectroscopies. It was found that the components of aromatic groups undergo photo-conversion processes at different rates depending on their composition. In the 3rd and 4th groups, the mentioned process occurs slowly, so their use as petroleum luminophores (PLs) may be recommended. It was found that the PLs based on these groups have variable luminescence properties, and the variation range of their spectral-luminescence properties was also determined. Finally, the role of singlet (O-1(2)) and triplet (O-3(2)) oxygens in reversible and irreversible photooxidation reactions with aromatics was investigated as well as, the significance of molecular and chainradical reactions in this process was also determined.",0,0,1
Other topics ,,"Acheampong, Theophilus; Phimister, Euan; Kemp, Alexander",An optimisation model for incentivising the development of marginal oil and gas fields amidst increasingly complex ownership patterns: UKCS case study,Marginal fields; Petroleum economics; Mathematical modelling; Oil and gas; MER; UKCS,CONTRACTUAL FAILURE; INFRASTRUCTURE; COMPETITION; INVESTMENT; DESIGN,"Many recent discoveries in the UKCS have been economically marginal and comparatively small such that they are unable to be developed on a standalone basis. Nevertheless, there is a proliferation of production facilities and transport infrastructure that can, on accepting a tariff, process hydrocarbons from these smaller-sized oil and gas fields, thereby contributing to the UK Government's strategy of maximising economic recovery (MER). However, the empirical dimensions of cost-sharing arrangements between a field owner (host field or hub) and tie-in (satellite) fields are not well examined in the literature although they influence long-term economics in matured oil provinces. In this paper, we develop a mixed integer programming optimisation model to analyse how these third-party access to infrastructure issues impact MER in the UKCS. A first-best situation with only one regional operator is empirically compared with the actual situation of multiple ownership. We then assess the impact of different infrastructure unbundling provisions via pipeline tariff choices and their interaction with the fiscal regime on the net present value (NPV) and other project metrics such as timings of hub and field shutdowns. We find that differences in field ownership, tariff choice and changes to the fiscal regime impact the overall NPV of field developments. Our results also show that having a progressive fiscal regime in a mature basin such as the UKCS is important to support continued operations under low oil prices while increasing the government's take at high prices. The cost-sharing effect shows that imposing strict cost-sharing rules does not change overall project valuations, even in a low oil price scenario. An additional contribution to the extant literature is that tariff determination could be based on cost-sharing rules that enjoin each field tieback to a hub to pay a split tariff, comprised of a fixed cost of service (access charge) and variable (marginal) costs.",0,0,1
Other topics ,,"Diehl, C. Fabio; Gerevini, G. Giovani; Machado, Tatiane O.; Quelhas, Andre D.; Anzai, Thiago K.; Bitarelli, Tiago; Serpentini, Fulvio; de Azambuja, Jose R. F.; Jahanshahi, Esmaeil; Skogestad, Sigurd; Farenzena, Marcelo; Trierweiler, O. Jorge",Anti-slug control design: Combining first principle modeling with a data-driven approach to obtain an easy-to-fit model-based control,Active anti-slug control; Nonlinear control design; Semi-empirical model; Unsteady flow; Real deployment,OFFSHORE OIL; PARAMETER-ESTIMATION; DATA RECONCILIATION; IDENTIFICATION; SYSTEMS; RULES; FLOW,"The limit cycle is an unexceptional problem in the oil industry that may cause significant losses in production. Also called slug flow or slugging, the unsteady flow can be handled by feedback control, although nonlinear issues must be considered. As an oil well production valve is opened, its transfer function gain tends to decrease until it reaches zero, meaning that the valve actions lose effect against the system backpressure. Notwithstanding, this sensitivity loss can be compensated by adapting a suitable tuning according to the well operating point. In this work, a methodology to generate this control policy is proposed based on combining first principle modeling with a data-driven approach. The method aims at improving closed-loop performance through a gain scheduling curve resulting from an easy-to-fit model to plant data. A systematic procedure is defined and validated through an actual deployment in a Petrobras ultra-deepwater oil rig. As a result, it was possible to suppress unsteady flow and increase oil production by more than 9%. Although the method has been validated in a satellite offshore well, one expects that feedback control can be used in different scenarios successfully, regardless of the slugging mechanism.",0,0,1
Other topics ,,"Iscan, A. Gurkan",Water saturation calculation using fractional flow and production logging data in a Caspian region sandstone petroleum reservoir,Saturation modeling; SCAL; MICP; Core analysis; Reservoir characterization; Geo modeling,,"Water saturation in porous media plays a significant role in static, dynamic reservoir modeling and petroleum reserves calculations. In this paper, a Pliocene conglomerate type of sandstone Caspian reservoir was studied. The objective of this paper is to apply water saturation calculation method using fractional flow and PLT (Production Logging Tool) and to compare the results with other methods. In this study, 6 petrophysical rock typing were defined by two methods at log level using the porosity, water saturation logs and RQI(Reservoir Quality Index). Core porosity and permeability correlations were calculated for each rock type where k-phi transforms were generated, respectively. Relative Permeability data of the reservoir was classified based on the rock types. Oil-Water relative permeability ratios versus water saturation data were correlated exponentially. A solution for water saturation was derived at log level using fractional flow, relative permeability, core porosity, permeability and production data. Leverett-J function and Archie saturations were calculated to compare to the proposed fractional flow approach. The comparison of the saturation logs with J-function and Archie saturation showed good match. This approach can be considered as a tool to validate the saturation-J function. This methodology helps to estimate pre-production water cut performance of the wells in reservoir models considering that not all the wells will start flowing at 100% dry oil. The employed methods regarding the petrophysical rock typing and water saturation calculations will facilitate reservoir characterization for future field development activities.",0,0,1
Other topics ,,"Liu, Tianshi; Zheng, Min; Song, Xinai; Wu, Ying; Zhang, Rong",Submergence depth modeling of oil well reservoirs and applications,Submergence depth model; Dynamic fluid level; Least-squares curve fitting; Weighted dichotomy; Monotonically increasing function,ITERATIVE APPROXIMATION; PERMEABILITY; FLOW,"In oilfield production, it is important to be able to acquire the reservoir status of oil wells in real time, especially for low or ultra-low permeability oil wells. In this paper, based on the reservoir percolation characteristics of the oil layer and combined with the oil well permeability, liquid pressure and oil well pressure formulas, the non homogeneous linear differential equation for oil well pressure is derived, based on which a submergence depth model of oil well reservoirs is established. The parameter merging is applied to reduce the parameter dimension of the submergence depth model; this approach substantially reduces the parameter dimension and application complexity and effectively improves the model application range. The model not only conforms to the reservoir percolation law of the oil layer but also applies to the balance laws of other substances with potential energy balancing ability. The application methods studied (namely, the extraction of the greatest common divisor, the weighted dichotomy and least-squares curve fitting) successively reduce the calculation error and expand the application scope. The least-squares curve fitting method causes the submergence depth error to reach the minimum of the 2-norm, and the number of iterations can be accurately assessed by the convergence speed of halving the numerical calculation error in every iteration. This method is suitable not only for the zero submergence depth case in the initial state but also for non-zero submergence depth cases. The experimental results show that the proposed submergence depth model for oil well reservoirs accurately reflects the change laws of submergence depth and time. Combined with the proposed application methods, the corresponding submergence depth can be obtained at any time point. The model and application methods provide strong support for formulating scientific oil production plans and implementing reasonable production methods for oil wells.",0,0,1
Other topics ,,"Jeong, Daein; Yoshioka, Katsuhei; Jeong, Hoonyoung; Min, Baehyun",Sequential short-term optimization of gas lift using linear programming: A case study of a mature oil field in Russia,Gas lift; Linear programming; Mature field; Sequential short-term optimization,,"The present study examines the sequential optimization of total lifting-gas allocation into multiple producing wells via linear programming for the maximization of oil production in a mature field located in Russia. Because the injection rate of lifting gas depends on the well production status, the ten-year gas lift schedule is determined by performing the gas lift optimization on a sequential, bi-weekly basis. For each short-term production optimization, the linear programming is solved by considering four operating parameters (e.g., tubing head pressure, bottom hole pressure, oil production rate, and gas lifting rate) which are calculated via high-fidelity reservoir simulation runs. Compared to the constant rate injection case, the optimal injection case increases the cumulative oil production by 14% at the same expenditure. These numerical results indicate that the sequential short-term optimization of the gas lift can be a practical approach towards boosting the asset value of a mature oil field with consideration for the well production status.",0,0,1
Other topics ,,"El-Aal, Ahmed K.; Zakhera, Mohamed; Khalifa, Mohamed A.; Qadri, S. M. Talha; Nabawy, Bassem S.","Carbonate strength classification based on depositional textures and fossil content of the Lower Eocene Drunka Formation, Assiut Area, central Egypt",Rock anisotropy; Drunka formation; Carbonate classification; Physico-mechanical properties,PETROGRAPHIC CHARACTERISTICS; ROCKS,"The present study reports petrographic and physico-mechanical analyses conducted on the lower Drunka Formation in the Assiut Area of Central Egypt. The study investigated the percentage of carbonate content and percentage of allochems ""Ach"" and their impact on the petrophysical features using correlation and multivariate regression analyses. This study analyzes the petrophysical characterization of Drunka Formation rocks and the effect of fossil content on them. The carbonate rock samples derived from the lower Drunka Formation were studied to evaluate the compressive strength, dry and saturated unit weight, porosity, and acoustic wave velocities. The petrographic examination of the rock samples was conducted to understand the facies characteristics, size and percentage of grains, matrix type and extent of diagenesis. Various microfacies associations were also detected within the examined samples, such as lime-mudstone, echinoidal bioclastic wackestones, nummulitic/miliolid wackestones, bioclastic peiodal packstone, echinoidal packstone and nummulitic grainstone. Petrophysical analyses displayed a wide range of porosity and dry bulk density values from 1.3 to 2.75% and 2.31-2.48 g/cm(3), respectively. The wet bulk density and grain densities are between 2.33-2.50 and 2.35- 2.57 g/cm(3), respectively. The dry ultrasonic wave velocity ""V-p"" was observed between 2926 and 5549 m/s, whereas the saturated ultrasonic wave velocity ""V-p"" was estimated between 3067 and 5875 m/s. The Unconfined Compressive Strength (UCS) of the tested samples was 22 <= UCS <= 82 MPa while the slake durability index was recorded as 94.37 < SDI < 98.7%. The Brazilian test indices characterized the studied rock samples as highly porous rocks and showed the values of 1.47 <= Brazilian <= 5.13 MPa. Finally, for all tested facies, the Bohme test data have a minimum, maximum, and an average of 12.98, 25.95, and 19.04 cm(3)/50 cm(2)' respectively. The study's findings showed that, except for the mineral grain scale, the physico-mechanical properties are highly dependent on the petrographic characteristics. The study also revealed that the Ach% and the rock's carbonate content significantly affect the rock's petrophysical and mechanical properties under investigation. The mechanical properties such as UCS, tensile and point load test. increase with increasing carbonate content and decreasing with increasing Ach% of the rock. This paper presents an extensive dataset of physical parameters of a carbonate formation in Egypt; many empirical relationships are presented for predicting mechanical properties. This provides site-specific predictive value; the relationships can be used for all carbonate rocks worldwide with broader international significance.",0,0,1
Other topics ,,"Bertini Junior, Joao Roberto; Batista Filho, Sergio Ferreira; Funcia, Mei Abe; da Silva, Luis Otavio Mendes; Santos, Antonio Alberto S.; Schiozer, Denis Jose",A comparison of machine learning surrogate models for net present value prediction from well placement binary data,Well placement optimization; Surrogate model; NPV forecasting; Oil production strategy; Regression; Genetic algorithm; Objective function,PRODUCTION STRATEGY; OPTIMIZATION; UNCERTAINTY,"Net Present Value (NPV) is an important indicator to guide investment decisions. In oil production planning, NPV is employed to evaluate and select among different production strategies. However, NPV estimation requires computational costly numerical simulations. So, evaluating as many production strategies as is desirable may be prohibitive. Therefore, one can only evaluate a small part of the search space, decreasing the chance of finding a near-optimal production strategy. To speed up the searching process, a much faster, but error-prone, surrogate model is used to approximate the simulator output. Data-driven surrogate modeling depends on both: 1) building a simple model to reproduce the quality of a high-fidelity model, while 2) considering a large volume of data to build it. In this work, we address the well placement optimization task by considering a binary data representation, indicating the presence or absence of a given well in a production strategy. We show the possibility of predicting the NPV from binary data, thus reducing data dimension and model complexity. Specifically, we compare six machine learning regression algorithms to predict the NPV. The simulations conducted in a benchmark case, based on a real field, showed that some regression algorithms can be used as a surrogate model to the simulator to efficiently perform well placement optimization considering binary data. The best results were obtained with Multi-Layer Perceptron, whose estimations covered a wide range of NPV with a small and constant error.",0,0,1
Other topics ,,"de Abreu, Christiane R.; Cordeiro, Thallis C.; Carrasquilla, Antonio Abel G.; de Souza, Eliane S.; Guimaraes, Andre O.",Electron spin resonance (ESR) in petrophysical characterization of pure carbonatic rocks and containing oil,ESR spectroscopy; Limestone; Dolomite; Petroleum,MN2+ IMPURITIES; EPR; PETROLEUM; ASPHALTENES; COMPLEXES; CHEMISTRY; CALCITE; GLASSES; PROBE; RIVER,"Petrophysical evaluation from laboratory and well logging data, such as gamma ray, Nuclear Magnetic Resonance (NMR) and resistivity has been used to identify and evaluate oil zones in reservoirs. Gamma ray log is able to predict lithologies along the well, and X-ray Diffraction (XRD) and X-ray Fluorescence (XRF) techniques also provide important lithological laboratory information. The NMR log directly estimates the porosity of the rock. Resistivity log identifies the water region, but cannot provide information about oil saturation. However, the application of unconventional techniques, such as Electron Spin Resonance (ESR), can be of great relevance in the well logging, adding information about lithologies, oil quality and saturation. The ESR technique, which can directly estimate the oil saturation inside the rock, can also provide important information about the origin and formation of rocks. This technique could be an advance for the oil industry, helping to understand the geothermal processes suffered by the rocks and identifying important regions of the reservoir. Thus, in this work, we studied carbonate rock (limestone and dolomite) samples with and without oil, by ESR technique. Firstly, the effectiveness of ESR in the differentiation of carbonates (calcitic and dolomitic) without oil was tested, through the analysis of manganese ion impurity, which promotes the replacement of calcium and magnesium ions in calcites and dolomites. The samples had a typical manganese ESR signature. The hyperfine parameter, A, was homogeneous for both limestone and dolomites. The zero-field split parameter, D, showed variability, as reported in the literature. The studies were carried out at X-band frequency. The analysis by XRF and XRD provided information on the chemical and mineralogical composition of the carbonates, which were added to the ESR data for application in a correlation matrix, by which it was identified that the components CaO and MgO were directly related to the intensity of the ESR signal and the concentration of CaO was inversely related to the concentration of Al2O3 and SiO2. In one limestone rock sample was incorporated oil, with 25 degrees API and moderate biodegradation level, to identify by ESR, the oil presence inside this rock. The technique was able to identify the oil and its saturation in the rock through the detection of free radical signal, g = 1.9951. The innovative application of the ESR technique to identify oil in varying saturation, in carbonate rock samples from the Illinois Basin (USA), was successful. These results demonstrated that this technique in addition to being accurate, nondestructive and relatively low cost, could be used in mud logging operations providing results for lithological characterization, oil identification and its saturation inside the reservoirs.",0,0,1
Other topics ,,"Lee, Jungin; Huang, Jingjing; Babadagli, Tayfun",Viscous fingering during heavy-oil displacement by chemical solutions: Emulsion instability and partial-miscibility,Heavy-oil emulsion; Stability; Fingering; Fractal dimension; Capillary number,MISCIBLE DISPLACEMENT; FRACTAL DIMENSION; FLUID; GROWTH,"The viscous fingering morphologies at a particular stage of emulsion displacements are observed to follow similar development patterns as that of the partially-miscible viscous fingering behavior (existent between the commonly studied fully miscible and immiscible systems). Chemically-induced viscous fingering before and after the finger droplet development resembling the partially-miscible fluid behavior is investigated using fractal dimensions and various -classic and modified-dimensionless scaling groups. We demonstrate, through the quantitative analysis using the empirical data collected from our previous experimental study, that the finger droplet formation morphologies observed in partially-miscible injection are indicative of an emulsion hydrodynamic instability behavior. The dominant parameters responsible for such droplet formation and their relationship to fractal dimension and hydrodynamic stability are mapped in a phase diagram with the original experimental images.",0,0,1
Other topics ,,"Al-Mukainah, Hani Salman; Hussaini, Syed Rizwanullah; Dvorkin, Jack Petrovich",Electrical formation factor versus porosity coarse-scale transforms from microscopic digital images: Example-based study,Porosity; Formation factor; Digital rock physics,RESISTIVITY; RENORMALIZATION,"The question posed in this work is whether and how elemental data obtained on small and often sub representative fragments of natural rock can be exploited to generate a physically valid transform between two physical properties useable at a coarser spatial scale, such as the reservoir scale. The pair of such properties targeted here is the porosity and electrical formation factor. We use the process-based upscaling to prove, by example, that a coarse-scale transform between these two variables can be obtained from a dataset computed on microscopic digital volumes of natural rock, including unconsolidated sand, medium-porosity sandstones, and low-and high-porosity carbonates. This upscaling method is based on constructing a coarse-scale (effective) rock volume from the elemental volumes with a subsequent simulation of a relevant physical process in this effective object, specifically the electrical current. A numerical simulation of Laplace equation governing electrical current is used to compute the effective resistivity. The effective porosity is simply the arithmetically averaged porosity of the elements. By using hundreds of random realizations of the effective object, we generate tight formation factor versus porosity transforms for each of the natural rock samples under examination. Because the proof offered here is by-example, it is not general. However, the method offered is general and, as such, can be used to address the same question as posed for various situations.",0,0,1
Other topics ,,"Tu, Yi; Wang, Yahui; Dai, Jianwen; Dai, Zong; Yan, Zhenghe; Zhu, Yidong; Wang, Jie; Wang, Yi",Assessment of reserves in anticline structures based on sparse exploration data-A case study from the Pearl River Mouth,Probability distribution; Test method; Shape factor; Sensitivity analysis; Reserve assessment,,"The ""two-step"" method of fine evaluation is deployed for less drilling, less data and low well control in early development of offshore oilfield. Firstly, A-D, K-S and chi 2 methods are used to test the distribution model of reservoir parameters. Secondly, the probability distribution model plate of reservoir parameters is established to accurately predict the geological reserves of the new oilfield. In this paper, a saddle-like reservoir and a platformlike reservoir (both of anticline) of T oil field in the Pearl River Mouth Basin are selected as the target reservoirs. Firstly, the rationality of reservoir parameters are checked. Secondly, due to the two-limb and interwell structure are deep with a long gentler section in the platform-like structure, the shape factor method was used to simulate the rock volume model to divide the irregular structure into N modules, which can accurately describe the structure of the reservoir and reduce the influence of the irregular structure. Finally, the distribution model of various parameters of reserves was established. The results show that the P_mean reserve of two reservoirs calculated by the approximate algorithm is close to the reverse scale estimated by the deterministic method, and the reserve errors are 2.5% and 3% respectively. For platform-like structure reservoirs, infill wells could be deployed along the fold axis of the structure if one horizontal well near the exploration well is drilled. For saddlelike structure reservoirs, it is recommended to deploy production wells along the fold axis of the structure at the two high points of the structure. The well location designed above has been incorporated into the economic development plan of the oilfield.",0,0,1
Other topics ,,"Fan, Jianbao; Zhang, Wenxiu; Chen, Wenxuan; Li, Xinghan",Inversion based on deep learning of logging-while-drilling directional resistivity measurements,Deep learning; Inversion problem; Logging-while-drilling; Directional resistivity tool,COMPUTATION,"Because of the response complexity and real-time interpretation required by geosteering, an efficient and reliable inversion method for logging-while-drilling (LWD) directional resistivity measurement is important. A three-layer parametric inversion method based on deep learning has been developed. The inversion process includes two steps. The first step is the inversion of formation parameters, such as the resistivity and distance to boundary, and the second step is the uncertainty estimation of the inversed parameters, to remove the low-quality inversed boundaries. The input of the first part of the inversion is the directional resistivity logging data. The input of the second step is the output of the first step. The second step is based on the relationship between the output error and the value of each output parameter of the first step. A synthetic example shows the original results of the first step of the inversion have some low-quality false boundaries, such as some of the ones in thick layers. By estimating the uncertainty and distinguishing the low-quality boundary in the second step, these false boundaries can be effectively removed.",0,0,1
Other topics ,,"Liljenhjerte, Johannes; Nygaard, Jens Vinge",Evaluating stabilizing initiatives to extend coiled tubing reach,Tubing force analysis; Extended-reach; Coiled tubing; Stabilizing support; Stabilizing strategy; Buckling,FRICTION-REDUCING TECHNOLOGIES,"New numerical strategies that reconsider tubing force analysis (TFA) in connection with buckling induced lockup are presented and applied. The strategies introduce new visualizations of downhole instabilities in coiled tubings (CT) for the entire run-in-hole (RIH) process. Most extended reach interventions seek to reduce compressive forces experienced by the CT through usage of lubrication, vibrations or tractors, but little attention has been given to stabilizing initiatives that prevent buckling. A stabilizing initiative is anything that increases the critical helical buckling load of the CT, for example a reduction of radial clearance between CT and wellbore. The strategies presented allow us to (1) evaluate the gain in CT reach from stabilizing initiatives, and (2) automatically determine the minimum requirement for a stabilizing initiative that will bring the CT to the desired operational depth, when it is applied optimally along the length of a CT/wellbore. Thus, the strategies promote investigations of novel stabilizing solutions that can complement existing extended reach technologies. The developed TFA algorithm is validated against field data and the strategies are utilized on a wellbore in the Danish North Sea. The investigation showed that a stabilizing initiative that increases the critical helical buckling load by 31% when introduced into 35.57% of the wellbore length will extend CT reach from 69.72% to 100% into the payzone. With these strategies in place we present a new approach to optimize well utilization.",0,0,1
Other topics ,,"Montero, Jose M.; Colombera, Luca; Yan, Na; Mountney, Nigel P.",A workflow for modelling fluvial meander-belt successions: Combining forward stratigraphic modelling and multi-point geostatistics,Facies modelling; Multi-point statistics; SNESIM; DEESSE; Training image; Meandering fluvial system,POINT; RESERVOIRS; SIMULATIONS; ARCHITECTURE; DATABASE; ALBERTA; FLOW,"A new workflow has been developed for modelling reservoir successions that comprise fluvial meander-belt deposits, based on algorithms that employ multi-point statistics (MPS). A library of training images - from which MPS modelling algorithms can borrow geological patterns for modelling fluvial meandering systems - has been built. The training images incorporate sedimentary architectures relating to point-bar deposits accumulated by fluvial meander-bend expansion and translation, as observed in high-sinuosity river systems and their preserved deposits in the geological record. The training-image library has been developed using a forward stratigraphic modelling software (PB-SAND) that simulates fluvial meander-bend evolution and resulting point-bar facies organization, and which has been constrained using sedimentological data from geological analogues. The training images are applied to two widely employed MPS modelling algorithms: SNESIM and DEESSE. Solutions to common issues encountered in MPS modelling workflows have been established through optimization of modelling settings for SNESIM and DEESSE. Auxiliary variables are used to simulate common facies trends. Application of the training-image library through the developed workflows for SNESIM and DEESSE has been tested; the sensitivity of unconditional simulation results to input parameters has been analysed to define modelling recipes, consisting of sets of appropriate modelling parameters for use with each training image and modelling algorithm. The creation of fluvial reservoir models that are geologically realistic using MPS algorithms remains challenging, but the proposed approach holds promise.",0,0,2
Other topics ,,"Chen, Lei; Yuan, Ziyun; Xu, JianXin; Gao, Jingyang; Zhang, Yuhan; Liu, Gang",A novel predictive model of mixed oil length of products pipeline driven by traditional model and data,Products pipeline; Mixed oil length; Traditional model; GBDT; Dual-driven modeling,TURBULENT-FLOW,"Mixed oil will inevitably form during the batch transportation in products pipeline, and accurate calculation of mixed oil length is of great significance for the economic benefit of the oil pipeline network. Traditional models (White Box/WB) are based on underlying engineering principles, however, there are some problems including low accuracy or high computing complexity. Data model (Black Box/BB), developed by historical data and machine learning algorithms, could act as a problem-solving approach while it takes the risk of overfitting due to the lack of understanding of the physical process. In this article, the Austin-Palfrey equation is used as the WB model to convert original features and input them into the BB model built on the Gradient Boosting Decision Tree algorithm (GBDT), and finally a novel predictive model (Grey Box/GB) incorporated prior knowledge is proposed. Experimental results of industrial examples reveal that the new model has higher predictive accuracy and better robustness, which means the dual-driven modeling method is more effective and can even become a new and valuable research direction.",0,1,2
Other topics ,,"Aguilera, Roberto F.",Effects of technological progress and external costs on upstream petroleum supply,Technological progress; Oil and gas; Supply curves; External costs,NATURAL-GAS; ASIA,"As the increase in world energy consumption over the coming decades will occur predominantly in Asia, the region will be influential in determining the role and combination of oil and gas in the world?s energy mix. To assess physical and economic availability of these resources, supply curves are estimated in this study by distributing volumetric quantities across production cost categories. The supply figures show how Asian oil and gas resources, both conventional and unconventional, vary with costs over time. The role of exogenous technological advancement until the year 2035 is included, as are the external (environmental) costs of production. On an axis showing quantities, the curves include resources estimated with a size-distribution method. The findings suggest that oil and gas in Asia is abundant and economically feasible to produce, with costs potentially decreasing in the future as technology progresses. Given appropriate public policies, gas in particular may experience rising market share in the energy mix and aid in the transition towards a low carbon economy.",0,0,2
Other topics ,,"Zhai, Xinle; Atefi-Monfared, Kamelia",Production versus injection induced poroelasticity in porous media incorporating fines migration,Poroelasticity; Permeability damage; Fines migration; Fines mobilization; Particle straining,IN-SITU STRESS; INCLINED BOREHOLE; WATER INJECTION; PERMEABILITY; SANDSTONE; SALINITY; TEMPERATURE; DETACHMENT; FILTRATION; PRESSURE,"Current fines migration models follow a decoupled approach, not incorporating the effects from the poroelastic response of the porous medium on mobilization and straying of fines and the resulting permeability damages. Furthermore, the impact of in-situ fine particles present in the porous matrix, on the poroelastic response of the formation to fluid-induced flow has not been studied. This paper presents a novel coupled numerical model to explain the spatiotemporal geomechanical response of a saturated porous formation that contains fine particles retained on the solid skeleton, under both injection and production induced flow. The coupled effects from the poroelastic response of the target zone as well as those from the fine-migration-induced permeability reduction are integrated into our mathematical formulations, while also incorporating vertical confinement effects using the Winkler model approximation. Results reveal that fine migration and straining notably impacts the induced pore pressures, displacements, and in-situ permeability, specifically at wellbore vicinity. Higher pore pressure alterations (higher increase under injection, and higher drop under production) is detected when incorporating fines migration, which captures field observations in damaged permeability zones. The impact of fine migration and straining is more significant during production versus injection, due to the geomechanical compression generated in the reservoir under production flow. Exitance of fine particles complicate the geomechanical response of a confined formation to flow, enhancing the effects of vertical confinement. Flow induced deviatoric stresses are significantly higher when fine migration effects are incorporated, resulting in early failure; which cannot be captured using conventional poroelasticity models.",0,0,2
Other topics ,,"Jia, Bao; Cui, Xiaojun",Pore pressure dependent gas flow in tight porous media,Tight gas; Pulse-decay; History matching; Gas compressibility,PERMEABILITY,"Gas flow in micro-porous media is more complex than liquid flow, partially because of the gas compressibility storage effect, and because of that, permeability as a function describing the flow efficiency for liquid might not apply to gas, but gas pressure diffusivity concept taking into account the effect of gas compressibility might do. However, verifying this supposition in conventional reservoirs at the core scale is challenging because the gas flow process finishes almost instantly. In comparison, gas flow time in unconventional tight cores is longer, and pulse-decay experiments are frequently used to estimate permeability, which requires a period to be finished. Therefore, theoretically, the supposition could be tested. In this study, pulse-decay experiments were performed on one shale core plug under different pore pressures with different pulse magnitudes to explore the relationship between gas permeability/diffusivity with experiment durations. We put forward a novel approach to determining the intrinsic permeability and gas slippage factor through a single pulse-decay experiment, which requires running multiple experiments by the conventional approach. We verified that gas pressure diffusivity instead of the permeability is the appropriate measure of the efficiency of gas propagating through the porous media, given the fact that the ratio of pulse size over diffusivity is roughly proportional to the experiment duration. Consistent results were obtained using different empirical models to obtain the intrinsic permeability, gas slippage factor, and pressure-dependent apparent gas permeability simultaneously. Results in this study also verified that pulse size affects the permeability determination more under a lower pore pressure in a pulse-decay experiment.",0,0,2
Other topics ,,"Arif, Jawad; Rehman-Shaikh, Muhammad Asim; Evangelou, Simos A.",Novel evaluation and testing of technology qualification process of subsea oil and gas products,"Oil and gas, product qualification; Technology readiness level; Environmental stress; Electromagnetic compatibility",DESIGN; RELIABILITY,"Use of robust products is of utmost importance in the subsea production systems to ensure the maximum utilization of the energy resources available under the seabed. To achieve highly reliable products, a comprehensive technology qualification program is proposed in this paper for the subsea electrical and electronics-based products. The recommended qualification program is specifically focused on a novel technology readiness level 4 (TRL4) process of the product used in an intended environment condition, which guarantees the product availability on the seabed without any operational failures. The analytical assessment on the products' design, operating conditions and compliance stress tests are proposed following the internationally recognized standards, e.g. The American Petroleum Institute (API), International Electrotechnical Commission (IEC), Institute of Electrical and Electronics Engineers (IEEE), International Organization for Standardization (ISO), European Standards (EN) and European Union (EU-directives). Modified environmental tests methods and novel product safety procedures are introduced for the first time to ensure that products meet the acceptance criteria set in the proposed TRL4 process. Finally, the proposed TRL4 process and its recommended test methods are exercised on the various functional units of the subsea electronic module. The experimental results show that the product is fit for use in the subsea environment after going through the proposed extensive qualification test program.",0,0,2
Other topics ,,"Szabo, N. P.; Remeczki, F.; Jobbik, A.; Kiss, K.; Dobroka, M.","Interval inversion based well log analysis assisted by petrophysical laboratory measurements for evaluating tight gas formations in Derecske through, Pannonian basin, east Hungary",Interval inversion; Differential evolution algorithm; Well logging; Total organic carbon content; Permeability,SHALE RESERVOIRS,"The evaluation of Hungarian tight gas formations requires the use of innovative interpretation technologies because of diverse geological environment, heterogeneous dataset including several variables measured with different accuracies, and reservoirs under varying petrophysical conditions. Conventional well logging methods based on the use of limited number of wireline logs make only a quick-look interpretation, in which a limited number of unknowns is determined, and there is a non-negligible risk for occurrence of ambiguity. In order to increase the overdetermination (data-to-unknowns) ratio and the estimation accuracy and reliability, all suitable well logs are to be jointly processed in a more effective manner. To estimate the total organic carbon content together with porosity, water saturation, shale content and rock matrix volumes with higher accuracy, a new inversion methodology is introduced that is tested in tight gas reservoirs. A differential evolution algorithmbased interval inversion method is developed that is combined by nano-permeability and high precision porosity laboratory measurements for the detection and evaluation of Hungarian tight gas reservoirs. Spectral gamma-ray, neutron-porosity and electric resistivity logs are jointly analyzed using the interval inversion approach. By solving a highly overdetermined inverse problem, the effective porosity, water- and gas saturation, shale and sand content, as well as the kerogen volume are estimated in a reliable inversion procedure. The silt and clay content of Miocene tight gas formations are separated and both determined by inversion, while the total organic carbon content is derived from the inversion results. The permeability log is directly derived from the inverted porosity values using the local porosity versus permeability relation established by multi-well core analysis. The combination of in situ wireline log data analysis and porosity and nano-permeability laboratory measurements is shown to be advantageous for a more reliable interpretation of unconventional hydrocarbon formations. An added advantage of the interval inversion method is the calculation of depth dependent errors of the estimated petrophysical quantities. It is shown that total organic carbon and other volumetric parameters can be determined with high accuracy in one interpretation procedure. In the Derecske basin, East Hungary, gas indications are confirmed by interval inversion, that were previously made it probable according to measurements made on poor core samples and rather noise-sensitive local well logging inversion procedure. The joint evaluation of new core data and original wireline logs using the proposed methodology may reveal further potential tight gas resources in the studied area. The Hungarian case study confirms that the suggested workflow may serve a new alternative for an improved evaluation of tight gas formations in different other hydrocarbon fields.",0,0,2
Other topics ,,"Lyu, Ye; Dasani, Devang; Tsotsis, Theodore; Jessen, Kristian",Characterization of shale using Helium and Argon at high pressures,Shale gas; Characterization; Cube and full-diameter core; Thermogravimetric analysis; Argon sorption,GAS-TRANSPORT; APPARENT PERMEABILITY; PORE STRUCTURE; ADSORPTION; MATRIX; MODEL; STORAGE; SORPTION; METHANE; CARBON,"In order to estimate the shale gas in place and the eventual recovery during shale gas operations, one of the key requirements is to accurately characterize the shale's petrophysical and transport properties such as porosity, permeability, diffusivity, and storage capacity. Despite the many efforts reported in the technical literature aiming to provide an improved understanding of the complex pore structures and the associated fluid flow in gas shales, a complete characterization of organic-rich shale samples still poses a big challenge. In this work, we have characterized mass transfer and sorption in shale at different length scales using Helium (He) and Argon (Ar) as probe gases. Thermogravimetric analysis (TGA) with a shale cube of similar to 1 cm(3) in size and gas expansion experiments with a full-diameter core (3.5 '' in diameter) were used to measure sorption kinetics/isotherms and mass transfer, respectively. Both samples are from the same depth/location in the Marcellus shale formation. The TGA steady-state technique was initially used to generate excess sorption isotherms for Ar, while dynamic TGA experiments were used to study its sorption kinetics. The TGA experiments demonstrate that Ar, which has a similar sorption potential as Methane, but is generally assumed to be inert, adsorbs onto the surfaces of the mesoporous and microporous regions of the shale samples according to a Langmuir-type behavior. Helium expansion experiments, on the full-diameter core, were used to measure the overall porosity, on the basis that He is a non-sorbing and inert gas as compared to Ar. The He expansion experiments, furthermore, allow us to delineate the mass transfer of gas across the inherent hierarchy of pore sizes, including macropores (macro- and micro-cracks), mesopores and micropores. Similar expansion experiments were also performed with Ar to study the combined impact of mass transfer and sorption. A triple-porosity model (TPM) was utilized to interpret the He expansion experiments with the shale core and to extract (estimate) relevant transport parameters. We report and compare here the diffusivities and permeabilities of the whole core for both He and Ar, as calculated from the modeling and fitting of the experimental data. On the premise that the shale cube is representative of the matrix region of the core, the Ar sorption kinetics from the cube experiments were subsequently combined with the transport parameters extracted from the He experiments to predict the behavior of the Ar expansion test with the full-diameter core. An excellent agreement is observed between the model predictions and the experimental data. The experimental observations and their interpretation indicate that one must be cautious when using Ar to estimate the true porosity and permeability of shales. In addition, we demonstrate that He and Ar probe gases, when used in tandem, can be employed effectively as a tool to characterize shales in terms of mass transfer and sorption dynamics across scales.",0,0,2
Other topics ,,"Hu, Gang; Tian, Xuanhua; Liu, Quanwen; Yi, Linzi; Liu, Dawei; Li, Pengchun",Quick assessment to ascertain technical rational well spacing density in artificial water flooding oilfield,Pressure distribution; Injection well starting pressure; Production well starting pressure gradient; Technical rational well spacing density; Artificial water flooding oilfield,,"Optimization of technical rational well spacing density (TRWSD) is a crucial part of the study of oilfield development. However, the methods widely used previously have some disadvantages as followings: (1) Some quoted theories and formulas for algorithms are intractable. (2) Some are incompatible with the reality as they assumed too many conditions which are more ideal. (3) The influence factors considered by other algorithms are not comprehensive and irrational. (4) In applications, the applicable conditions are ignored by some algorithms. Aiming at the problems above, this paper has built a quick estimation model of TRWSD and proposed a new optimizing method of TRWSD, based on the comprehensive investigation of pressure distribution and the theoretical model of rational ratio of oil to water wells (RROWW) in artificial water flooding oilfield. Verification by reservoir numerical simulation model and actual data of the field implementation shows that the TRWSD model is reliable, and practical. It is revealed from the studies that the injection-production pressure system factors are the main ones to control TRWSD except water cut, such as the oil-bearing area of producing geological reserves, liquid productivity index, injection-production ratio and number of injection-production wells, and so on. And compared with the previous ones, the TRWSD method comprehensively takes into account such the factors as injection-production unbalance, density difference between oil and water, volume factor, start-up pressure gradient of injection wells, start-up pressure gradient of production wells and so on. Hereinafter, the new model can be applied for the calculation of the TRWSD and related parameters at any injection-production development stages, reservoir types and reservoir pressure distributions in artificial water flooding oilfield, all of which means that the new method has a strong promising adaptabilities and prospects in the water flooding oilfield with close well spacings or during high water cut stage.",0,0,2
Other topics ,,"Zhang, Ting; Yang, Zhonghao; Sun, Chaochao",Stochastic simulation of fan deltas using parallel multi-stage generative adversarial networks,tochastic simulation; Fan delta; Generative adversarial network; Training image; Parallel,,"The stochastic simulation of fan deltas has always been one of the significant problems in the numerical simulation of reservoirs. As one of the important numerical simulation methods of fan deltas, multiple-point statistics (MPS) obtains the statistical characteristics through the patterns in the training image (TI) to perform simulation. However, due to the non-stationarity of the TI of fan deltas, the traditional MPS cannot extract the non-stationary characteristics of the TI smoothly. Besides, traditional MPS mainly relies on CPU-based simulation, and the extracted probability information cannot be reused during simulation since the information only stored in memory instead of files on the storage medium, making the simulation process quite time-consuming if multiple simulations are performed successively. Thanks to the powerful feature extraction capability brought by deep learning, the fan delta simulation possibly will be largely improved. The generative adversarial network (GAN) is an important deep learning method for image generation, but it suffers from the lengthy simulation time and needs large-quantity training samples. Some variants of GAN, such as the single-image GAN (SinGAN), were proposed to reduce the amount of training data when realizing GAN. Based on SinGAN, a stochastic simulation method of fan deltas using parallel multi-stage GAN is proposed in this paper, through which the structural characteristics of fan deltas are learned from a single image of TI, and the stochastic simulation process can be parallelized for acceleration without lowering the simulation quality.",0,0,3
Other topics ,,"Li, Linfei; Zhang, Yige; Hubler, Mija H.; Xi, Yunping",Experimental study on nanoparticle injection technology for remediating leaks in the cement from wellbore systems,Well cement; Nanoparticle; Electrochemical injection; Agglomeration; Chloride removal,PORTLAND-CEMENT; NANO-SILICA; CONCRETE; PASTE; MICROSTRUCTURE; NANOSILICA; MORTAR; AREA,"The objective of this paper is to experimentally study the possibility of using nanoparticles for repairing cracks and leaks generated in the well cement used in underground gas storage and acquisition. Several types of nanoparticles can be injected into the intact/distressed (aged) cement with the newly developed electromigration method to repair wellbore leakage. The injection of nanoparticles is evaluated by the saturatedrying method, electric conductivity method, and BET method. After the injection, the decrease of chloride permeability can be captured, and nanoparticle agglomeration can be observed. In addition, the capability of extracting harmful ions from the cement is provided simultaneously during the injection of nanoparticles.",0,0,3
Other topics ,,"Cartagena-Perez, D. F.; Alzate-Espinosa, G. A.; Arbelaez-Londono, A.",Conceptual evolution and practice of sand management,Sand management; Sand control; Sanding; Sand production; Risk management; Risk evaluation,RISK,"This paper focuses on understanding the conceptual evolution and practice of sand management through six stages. The geomechanical mechanisms leading to sand production are presented at different scales for comprehensive conceptualization. The concept of ""conservatism"" is assumed when analyzing passive and active methods for sand control and in the models and approaches to the sanding risk. There is a strong relationship between oil prices and publications (papers) about sand management and sand control. At its core, sand management considers sand production not as a problem but as a phenomenon that demands an intensive study of the genesis and mechanism of sanding. However, the risk assessment must be considered instead of avoiding sand influx as sand control currently does. This paper illustrates how the focus of technical literature and practices has adjusted its questions about sand management through different stages of understanding. Therefore, this paper helps the technical community understand sand management from its historical conceptualization and its relationship with multiple external factors.",0,0,3
Other topics ,,"Winecki, Slawek; Nowaczewski, Stephen; Johnson, Kathryn L.; Lord, Anna Snider; Lord, David L.; Moriarty, Dylan Michael; Scharenberg, Mackenzie; Moody, Mark A.; Argumedo, Darwin; Larsen, Glenn E.; Duguid, Andrew; Bettin, Giorgia",Quantitative assessment approach to assess benefits of subsurface safety valves and tubing and packer systems in depleted reservoir and aquifer gas storage wells,Underground gas storage; Quantitative risk model; Risk management; Tubing & packer; Sub surface safety valve; Workover risk,,"The Battelle Memorial Institute, Sandia National Laboratory, and Nova Northstar LLC, jointly carried out two projects, sponsored by the Pipeline and Hazardous Materials Safety Administration, assessing the roles of subsurface safety valves and tubing and packer systems in depleted reservoir or aquifer wells used for underground gas storage. The assessment was based on the American Petroleum Institute 581 method and on the storage well-specific model created by the 2017 Joint Industry Task Force organized by the UGS industry in response to the Aliso Canyon gas leak. The model was expanded to capture the specific functionalities of safety valves and tubing and packers, as well as to account for workover risk associated with monitoring and maintenance of such devices. The main conclusion of the two projects is that the application of safety valves and/or tubing and packer systems can reduce risk in some, but not all, gas storage wells. Gas storage wells with low initial risk, as measured by a likelihood of a loss of control event and by a projected consequence of such event, would generally not benefit from installation of new safety systems. In fact, the risk may be increased due to risk of more frequent and more complex workover operations or due to deliverability impairments. For some wells, the initial risk is such that the application of a safety valve or a tubing and packer can substantially decrease risk, specifically reduce consequences of loss of control events. Wells with inherent or initial risk, particularly driven by high likelihood of failure, would see risk reduced by the application of a safety valve or a tubing and packer, however, remaining risk are unacceptably high. An effective way to assess the applicability of these safety devices is to apply quantitative risk models, specifically models that evaluate probabilities/likelihood and consequence of accidents.",0,0,3
