Cluster Level 1,Cluster Level 2,AF,TI,DE,"ID",AB,TC,Z9,U1
Fracture,Hydraulic Fracture,"Phan, T. N.; Zapata, Y. M.; Kabir, C. S.; Pigott, J. D.; Pranter, M. J.; Reza, Z. A.",Probing hydraulically-fractured wells in unconventional shale reservoirs under cyclic CO2 injection: Variation of thermophysical properties,Unconventional reservoirs; CO2 cyclic injection; Exploring variation of thermophysical properties; Understanding injection-soaking-production cycles; Realistic oil recovery with large number of cycles; Molecular diffusion yields 6% incremental oil,OIL RESERVOIRS,"Despite the recent growth in oil production from unconventional reservoirs, existing hydraulically-fractured horizontal wells face challenges of poor recovery with the rapid production decline over a short life span. Enhanced recovery techniques, such as cyclic CO2 injection can be a solution to this impending problem and lead to energy independence for the foreseeable future. However, mechanisms occurring around the hydraulically fractured wells are far from fully understood. The primary motivation of this study revolves around addressing this limitation. Specifically, we explored the evolution of various thermophysical properties occurring around hydraulically-fractured wells in liquid-rich unconventional reservoirs using a holistic, integrated modeling framework. Available well-logs and other data from Howard County in the Midland Basin formed the basis for constructing representative 3D structural models that capture the Midland Basin stratigraphy. We used a simulator to create multistage hydraulic fractures that allowed integration into numerical reservoir-flow simulation models. Then, both convective and diffusive flow within a multicomponent compositional simulation modeling paradigm is used to examine the role of molecular diffusion in performance under cyclic CO2 injections in hydraulically-fractured well. The simulation results indicate that molecular diffusion yields an incremental oil recovery of 6% compared to models that do not. Our analysis reveals different thermophysical properties transition from near wellbore regions to outer regions into the rock matrix. Changes in total mole fractions of CO2, methane, and hydrocarbons with C7+ fraction, pressure and saturation variation, viscosity reduction and the surface tension over 14 injection-soaking-production cycles are tracked. The analyses of the evolution of these thermophysical properties provide us with means to evaluate the efficiency of the solvent injection process. The simulation results explain how, when, and where CO2 disperses into the reservoir.",0,0,0
Fracture,Hydraulic Fracture,"Su, Kai; Zhou, Xiao-Yang; Zhou, Li; Wu, He-Gao; Shi, Chang-Zheng",Propagation behaviors of hydraulic fractures arising from the sidewall of wellbore using high-order Generalized Finite Element Method,Hydraulic fracturing; High-order GFEM; Intersection angle; In-situ stress; Fracture interaction,SIMULATION; PARTITION; SINGLE,"Accurately predicting the propagation of hydraulic fracturing arising from the wellbore is essential in petroleum engineering, hydraulic engineering, etc. There are various factors influencing fracture propagation, such as the initial fracture orientation and in-situ stresses, while the limitation of appropriate methods and techniques hinders the further investigation on the propagating mechanism. In the study, a simulator based on High-order Generalized Finite Element Method (GFEM) is introduced to investigate the propagation behaviors of hydraulic fractures arising from the sidewall of wellbore. For better recognization of hydraulic fracturing, several numerical examples are performed based on the simulator. Different influencing factors are studied, including intersection angle between fracture and wellbore, in-situ stresses and fracture interactions. It is found that, regardless of in-situ stresses in the surrounding rock, pre-existing fractures approximately propagate straight-forward along their initial directions and finally form planar fracture surfaces. Regarding in-situ stresses, with acute intersection angle between fracture and wellbore, fractures propagate toward the direction of the minimum principal stress. Besides, two parallel and opposite fractures individually arising from two parallel and non-coincidence wellbores always propagate towards each other after passing by each other. Moreover, the interactions between them become strengthened as the distance between them decreases. Finally, the propagating sequences of hydraulic fractures arising from a group of parallel wellbores are discussed. It is found that the sequence can influence the fracture geometry and previously propagated fractures can restrain the nearest fractures embedded in other wellbores propagating away from each other in subsequent stages.",0,0,1
Fracture,Hydraulic Fracture,"Liu, Qingling; Tian, Shouceng; Yu, Wei; Li, Gensheng; Sheng, Mao; Sepehrnoori, Kamy; Shen, Zhonghou",A semi-analytical model for simulation of fluid flow in tight rock with irregular fracture geometry,Semi-analytical model; Transient pressure behavior; Vertical fractured well; Complex fracture geometries,PRESSURE-TRANSIENT ANALYSIS; HORIZONTAL WELLS; CONDUCTIVITY,"Numerous micro-seismic and laboratorial studies show that hydraulic fracture is usually with complex geometries, such as plugged fracture, asymmetry and non-plane. It is a challenging task to recognize the complex fracture and obtain reliable fracture parameters through transient pressure analysis. In this work, we extend the semi-analytical model by Zhou a al. (2013) to analyze transient pressure behavior of a fractured vertical well with complex fracture geometries. We verified the semi-analytical model by a numerical reservoir simulator on a planar fracture. Then, based on this model, we made a systematical discussion about the transient pressure behavior of the planar fracture with varying conductivity, asymmetric fracture and non-planar fracture. Results show that when the fracture conductivity is varying along the fracture path, the influence of fracture zone conductivity on the transient pressure behavior gradually decreases with the distance from the wellbore growing. Besides, we found that the fracture asymmetry is against for the fluid flow in the fracture, and it decreases the slope of transient pressure behavior curve and enlarge pressure drop. In addition, the non-planar fracture is usually with severe fracture width restriction around the wellbore, which will induce pseudo-radial flow in the fracture at early times and large pressure drop in the fracture. Furthermore, the influences of varying conductivity, fracture asymmetry and non-plane on transient pressure behavior are obvious for fracture with average small-to-middle conductivity (average dimensionless fracture conductivity ranging from 0.1 to 50); the influences become negotiable for fracture with average high-to-infinite conductivity (average dimensionless fracture conductivity ranging from 50 to 1000). This work can provide critical insights into understanding the effect of complex fracture geometry on transient pressure behavior of fractured vertical well in tight oil reservoir.",1,2,0
Fracture,Hydraulic Fracture,"Teng, Bailu; Li, Huazhou Andy",A semi-analytical model for characterizing transient flow behavior of reoriented refractures,Transient flow behavior; Reoriented refracture; Hydraulic fracturing; Unconventional reservoir; Well stimulation,PRODUCTION SIMULATION; FRACTURES; WELL,"In order to improve the field productivity, the industries can create new fractured wells to reduce the interval between the initial fractures (initial fracture indicates a fracture that is induced during the initial fracturing treatment). Production from the initial fractured wells can induce stress reorientation in the vicinity of the fractures. As such, a refracturing treatment in the stress reorientation region can lead to a reoriented refracture which has a certain azimuth with respect to the initial fractures. This azimuth can even be 90 degrees if the stress reorientation is sufficiently large. In addition to the conventional parameters (including refracture's length, refracture's conductivity, and the in-situ conditions), there are two more factors, the reorientation azimuth and the interference from the initial fracture, which can exert significant influence on the transient flow behavior of the reoriented refractures. In such case, the conventional analytical/semi-analytical models neglecting these two factors are no longer applicable to characterize the transient flow behavior from such a refracture. In this work, we develop a novel semi-analytical model to characterize the transient flow behavior of a reoriented refracture considering the interference from the initial fractures. In this model, the fractures are explicitly represented with discretized segments. We apply finite difference approximation to the initial fractures and refractures, respectively, to simulate the transient flow in the fracture system. In addition, the fluid flow in the matrix system can be characterized by Green function and Newman product method. Based on the continuity of flux and pressure, we couple the fracture flow equations with the matrix flow equations to construct a semi-analytical model. With the aid of the proposed model, we conduct a thorough investigation of the transient flow behavior of reoriented refractures. It is observed that, at the early production period, two fracture pseudosteady-state flows can appear due to the interference from the initial fractures. The formation linear flow and bilinear flow can also be observed during the production period of a refractured well. In an anisotropic-permeability reservoir, the refracture's azimuth and position can exert a significant impact on the productivity of the fractures. There is a region in the vicinity of the initial fractures, within which an orthogonal refracture can lead to the highest field productivity.",2,2,1
Fracture,Hydraulic Fracture,"Venkatesh, Prashanth Bangalore D.; D'Entremont, James H.; Meyer, Scott E.; Bane, Sally P. M.; Grubelich, Mark C.; King, Dennis K.",Bipropellant high energy stimulation for oil and gas applications,Energetics; Propellant; Fracturing; Fracture networks; DDT; Detonations,PRODUCTIVITY,"Large-scale extraction of oil and natural gas requires an effective method of generating a high surface area network of fractures, or the stimulation of existing fractures, in a formation in order to increase permeability. Conventional hydraulic fracturing has limited utility in this application. In this work, Sandia National Laboratories is exploring high rate pressurization techniques employing tailored energetic materials systems to control both pressure rise rate and peak pressure in order to optimally stimulate potential rock formations. Rapid pressurization, at rates far exceeding quasi-static conventional hydraulic rates, can generate multiple radial well bore fractures and potentially provide a mechanism to induce shear destabilization within the formation that enables the fractures to be self-propping. Multiple fractures from the well bore allow efficient coupling to the existing formation fracture network and increase near field well bore permeability. Furthermore, these techniques can allow for repeated stimulations and produce energetic events within the fractures thereby allowing fractures to be extended further. Controlled rate pressurization is a useful tool for the efficient generation of fracture networks and has potential application to increase oil and gas production. This paper provides an overview of the concept of controlled rate pressurization, laboratory experiments and field trials that are being conducted. The present work investigates detonations of a stoichiometric mixture of ethylene and nitrous oxide (C2H4 + 6N(2)O) at high initial pressures ranging from 0.862 to 2.068 MPa as a method of fracturing rock below the ground surface. The experiments investigate the fracture generation as a function of the initial pressure of the mixture. In the current configuration, the combustion reaction is initiated by an electrically fired igniter at the ground surface and quickly transitions to a detonation. The experimental setup accommodates one high pressure (690 MPa) transducer, placed downstream of the igniter, to measure peak pressure. The pressure transducer recorded peak pressures, which are 2.3-2.6 times in excess of the Chapman-Jouguet (CJ) values as a result of pre-compression of the unburned gas mixture during the flame acceleration prior to deflagration-to-detonation transition (DDT). Analysis of the data indicated an increase in rock permeability due to detonations and this was confirmed by the core drilled sections at the test site.",2,2,1
Fracture,Hydraulic Fracture,"McKean, Scott H.; Priest, Jeffrey A.",Multiple failure state triaxial testing of the Montney Formation,Unconventional reservoir geomechanics; Multiple failure state; Triaxial test; Elastic anisotropy; Post-peak behaviour; Failure envelope; Montney Formation,ROCK; STRENGTH,"Elastic behaviour controls hydraulic fracture propagation and ultimately, the productivity of unconventional reservoirs. Various index tests and single stage triaxial tests are used to characterize elastic moduli but it can be difficult to obtain enough samples and sufficient information. This is partly due to the fissile nature of shales, which results in a paucity of representative core plugs. It is also partially due to the complex and heterogeneous nature of unconventional reservoir's geomechanical behaviour. The failure mechanics of unconventional rocks are poorly understood and seldom incorporated in hydraulic fracturing or geomechanical models. Yet, failure is major influence on fracture complexity and reservoir drainage volumes. The objectives of this study were to evaluate the variability in geomechanical properties and characterize the post-peak behaviour of a stiff siltstone from the Montney Formation in Alberta, Canada. The multiple failure state triaxial test was used to define the pre-peak elastic behaviour, post-peak behaviour, and failure envelope of a single core plug. This is beneficial for practitioners that are faced with a paucity of samples. The multiple failure state triaxial test is difficult to implement for stiff specimens, which fail in a brittle and unstable manner and a methodology to improve the stability near and beyond sample failure was therefore developed. The results from this study, which were also compared to various index tests and publicly available data, show that the samples had low porosity, low clay, and high stiffness. Significant variability in elastic behaviour was observed due to non-linearities in the loading curve - an effect that overshadowed changes due to confining pressure and highlighted that need for careful consideration of elastic parameter variability. Several oriented samples sets were used to characterize elastic and strength anisotropy. The improved test methodology was able to capture stable post-peak behaviour on almost all the tested samples. Brittle stick-slip failure was observed and an exponential model for approximating post-peak behaviour was presented. The combination of triaxial testing and index testing was able to completely characterize the constitutive law and failure envelope of the samples, save the Biot coefficient. These results can be incorporated into both routine and advanced geomechanical models and hydraulic fracturing simulators.",2,2,1
Fracture,Hydraulic Fracture,"Sun, Jin; Wu, Shiguo; Deng, Jingen",An analytical model for fracture initiation in elasto-plastic soft formations based on stress path analysis,Fracture initiation pressure; Soft formations; Fracturing mode; Stress path; Tensile fracturing; Shear fracturing,CONSOLIDATED ROCK STRATA; NUMERICAL-SIMULATION; BOREHOLE YIELD; WELLBORE; PROPAGATION; STABILITY,"Most models developed for hydraulic fracturing initiation of borehole are based on the elasticity mechanics, and tensile fracturing is considered as the mechanism of fracture initiation. However, the lab and field data show that these models cannot properly predict the fracturing mechanism of soft formations. We proposed an elasto-plastic model to analyze the fracturing mode and fracture initiation pressure in the soft formations that considers the effect of overburden pressure and fluid flow. The analytical stress solutions under six different stress state are obtained, thus the effective stress path on the borehole wall is analyzed to determine the fracturing mode. The effective stress path analysis indicate that both tensile and shear fracturing are considered as the fracturing mode. The fracturing mode and fracture initiation pressure are influenced by the burial depth significantly. The tensile fracturing is more likely to occur in the shallow formation, while the shear fracturing usually occurs in the deep formation. In addition, the formation strength and mud cake also affect fracturing mode and fracture initiation pressure. The shear fracturing is more easily to be induced in the formation with low strength and tight mud cake. The preyielding around the borehole due to the low strength will decrease the fracture initiation pressure without affecting the fracturing mode of the borehole wall.",2,2,2
Fracture,Hydraulic Fracture,"Shi, Jingyu; Shen, Baotang",Approximations for fluid pressure and flux of hydraulic flow in three-dimensional fractures,Hydraulic fracture flow; Finite volume method; Fluid pressure; Three-dimensional fractures,PROPAGATION; SIMULATION; ROCK,"In this paper, we implement a finite volume method for approximating the pressure of fluid flowing within three dimensional fractures and formulate a scheme for computation of the fluid velocity and flux in the fractures. These are needed to couple with an existing fracture propagation code based on a displacement discontinuity method for simulation of hydraulic fracturing processes. Both of the methods discretise the fracture only, not its two surfaces. The pressure and velocity computed with the proposed numerical schemes are shown to qualitatively agree with analytic solutions for several cases of flow in planar annular fractures.",2,2,3
Fracture,Hydraulic Fracture,"Wang, Dongying; Wang, Zhiming; Zeng, Quanshu",An experimental study on gas/liquid/solid three-phase flow in horizontal coalbed methane production wells,Gas/liquid/solid three-phase flow; Coalbed methane; Horizontal well; Flow pattern; Height of coal particle bed; Explicit equation,SAND-DEPOSITION VELOCITY; RESERVOIR ROCKS; LIQUID; GAS; PARTICLES; TRANSPORT,"Coal particles caused by well drilling and completion, hydraulic fracturing, and formation pressure decreasing would migrate into the horizontal well carried by fracturing flow-back fluid, formation water and CBM, and then deposit on the low side of pipe leading to the decrease of cross section area of pipe for flow and even blocking of the pipe. The purpose of current research was to obtain the flow pattern while there was stationary solid particle bed on the low side of the pipe and an explicit equation to predict the height of solid particle bed was proposed. In this study, with the coal particle, water, and air as the solid, liquid, and gas phases respectively, gas/liquid/ solid three-phase flow experiments in horizontal well were carried out and 4 crucial factors including different water flow rate, gas flow rate, coal particle size, and coal particle mass concentration were considered. Fluid's real apparent velocity was defined and used to analyze the distribution of flow pattern coordinate points. Results show that the flow pattern coordinate points determined by real gas apparent velocity and real water apparent velocity distribute near the flow pattern transition lines of Taitel and Dukler flow pattern map. Besides, coal particle size, water flow rate, and gas flow rate have obvious impact on the height of coal particle bed and the coal particle mass concentration has a negligible effect while the height of interface between gas layer and water layer is only dramatically affected by the gas flow rate. At last, an explicit equation for predicting the cross section area of coal particle bed based on the experimental data was proposed which is crucial to predict the flow pattern and calculate the pressure drop in horizontal well. The predicting cross section area of coal particle bed is in good agreement with the measured cross section area of coal particle bed and the average relative differences are 9.38% and 13.45% for stratified smooth flow and stratified wavy flow respectively. The equation is applicable for a range of coal particle size (8-30 mesh) and water apparent velocity (0.025-0.123 m/s).",2,2,4
Fracture,Hydraulic Fracture,"Chu, Hongyang; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Liu, Wenyuan",Estimating carbon geosequestration capacity in shales based on multiple fractured horizontal well: A case study,Multiple fractured horizontal well; CO2 geosequestration; Shale reservoirs; Semi-analytical method; Transient pressure response,TRANSIENT PRESSURE BEHAVIOR; ENHANCED GAS RECOVERY; STORAGE CAPACITY; CO2 STORAGE; NUMERICAL-SIMULATION; SEQUESTRATION; RESERVOIR; MODEL; FEASIBILITY; ADSORPTION,"Nowadays, shale reservoirs have been though as good candidates for CO2 geosequestration for reduction of carbon emission. When estimating the carbon geosequestration capacity, multiple fractured horizontal well (MFHW) is a prerequisite for consideration when shale reservoirs are included in candidate geological sites, as it is one of the critical factors for the successful development of shale reservoirs. In order to perfect our previous works, a new model is proposed to calculate the carbon geosequestration capacity of depleted shale reservoirs based on MFHW. The methodology calculates carbon geosequestration capacity of shale reservoirs by considering Knudsen diffusion, molecular diffusion, supercritical Langmuir adsorption, stimulated reservoir volume (SRV), and stress-sensitivity of the permeability. Utilizing the perturbation transformation technique, finite difference method, and Laplace transform technique, our method is more in accordance with the actual situations, allowing us to accurately estimate the carbon storage capacity by capturing the transient pressure response of the MFHW. A field case from the Ordos Basin in China presents that the CO2 geosequestration capacity is proportional to the dimensionless fracture half-length and conductivity. The properties of hydraulic fractures only affect the early period of the CO2 geosequestration process. For the adsorption coefficient and flow coefficient ratio, with the change of these parameters, the middle and late periods of the CO2 geosequestration process are mainly influenced.",2,2,4
Fracture,Hydraulic Fracture,"Chen, Zan; Lin, Menglu; Wang, Shuhua; Chen, Shengnan; Cheng, Linsong",Impact of un-propped fracture conductivity on produced gas huff-n-puff performance in Montney liquid rich tight reservoirs,Un-propped fracture; Huff-n-puff; Liquid rich tight reservoir; Reservoir simulation,,"Studies have shown that the gas huff and puff injection potentially perform better than the continuous gas flooding in enhancing the hydrocarbon recovery in the liquid rich tight reservoirs. During the fracturing stimulation, only part of the induced hydraulic fractures is propped because proppants cannot be carried to the fracture tips. Moreover, some secondary and tertiary fractures may be too narrow to accommodate any proppants. The conductivity of the unpropped fractures is highly dependent on the variation of the in-situ pressure and may be open and close periodically during the huff-n-puff cycles. In this study, the stress-dependent fracture conductivity and its impact on the produced gas huff-n-puff performance are investigated in a liquid rich tight reservoir, considering the existence of the large amount of the unpropped fractures. The experimental data of stress-dependent fracture conductivity is employed first to simulate the dynamic conductivity during the depletion and the gas huff and puff cycles. A reservoir model is then constructed and history-matched based on the reservoir fluid samples and the field production data collected from the Montney liquid rich tight reservoir in Western Canada. Performance of the produced gas huff-n-puff is examined in the targeted reservoir and results show that contributions of the unpropped fractures cannot be ignored, which leads to 7.8% more condensate (i.e., oil) production and 2.8% higher in barrel of oil equivalent (BOE), compared to the case with propped fractures only. The effects of complex fracture geometry and the cluster completion are also investigated and results show that the unpropped fracture contributions towards the condensate production and BOE are even more pronounced in the complicated scenarios. The condensate oil and BOE are 42.0% and 22.9% higher in complex fracture geometry case and 12.4% and 5.6% higher in the fractures with multiple clusters than those scenarios with propped fractures only. This paper provides a better understanding on the potential performance of enhanced hydrocarbons recovery in liquid rich tight gas reservoirs via gas huff-n-puff operations.",3,3,0
Fracture,Hydraulic Fracture,"Zhao, Jinsheng; Li, Tiantai; Shi, Yu; An, Chongqing; Liu, Yueliang",A new sinking agent used in water-control fracturing for low-permeability/bottom-water reservoirs: Experimental study and field application,Water-control fracturing; Low permeability; Bottom-water reservoirs; Barrier; Fracture height,MODEL,"Hydraulic fracturing is widely applied in tight reservoirs for hydrocarbon recovery. However, as for bottom water reservoirs, the created vertical hydraulic fractures can readily penetrate into the bottom-water layer, leading to a drastic increase of water cut when the pay-zones are too thin and the barrier lying between the pay-zone and bottom water are quite weak. In this work, a new sinking agent is used in hydraulic fracturing for water control in the low-permeability/bottom-water reservoirs. The settlement velocity and the plugging ability of this new sinking agent as well as the flow conductivity of the sinking-agent barrier is measured and compared with that of the other six commonly used sinking agents. We finally investigate the placement rule of the new sinking agent by varying the concentration of the carrying fluid and sand ratio in the modeling fracture. Filtration test show that this new sinking agent can form a barrier, which can strongly plug fracturing fluid. When the closure pressure range is in the range of 6.9 MPa-69.0 MPa, conductivity of the barrier formed by this new sinking agent is at a low level of 2.9 mu m(2)cm to 1.5 mu m(2)cm. With a given sand ratio and carrying-fluid concentration, the barrier formed in the fracture by the new sinking agent is more uniform than the other sinking agents. Based on the field application in a low-permeability/bottom-water reservoir, the usage of this new sinking agent increases oil recovery but decreases the water cut compared to other sinking agents.",3,3,2
Fracture,Hydraulic Fracture,"Ghosh, Sayantan; Busetti, Seth; Slatt, Roger M.",Analysis and prediction of stimulated reservoir volumes through hydraulic fracturing: Examples from western Arkoma Basin,,,"Geologic models built from well logs and natural fracture (NF) parameters obtained at shale and carbonate outcrops/quarries were employed in understand artificial hydraulic fracture (HF) propagation and stimulated reservoir volume (SRV) geometries. We applied field HF treatment parameters from an Arkoma Basin well, located 20-25 miles (32-40 km) east of the studied quarries. We matched the microseismic cloud (MC) geometries of three field stages, followed by sensitivity analyses of various HF treatment and reservoir parameters. Geometry matches reveal that the average NF permeability in the Viola Group Limestone is nearly eight times that in the Woodford Shale. The sensitivity analyses (forward modeling) disclosed several likely outcomes. First, a minor (5x10(-6)) increase in the minimum horizontal tectonic strain and ensuing increase in the minimum horizontal stress resulted in a sizeable transformation of the SRV geometry. Second, pumping at a higher net pressure (ISIP increased from 6500 to 7000 psi) diminished the stimulation volume and opened more previously non-dilatable NFs closer to the wellbore. Higher net pressure also triggered more stimulation downward and out of the target zone in the studied area. Third, halving the number of NFs and doubling their final storage apertures significantly magnified the fracturing-fluid efficiency (i.e., lowered leak off into NFs) in areas where it was restricted from flowing through non-dilatable NFs. Additionally, this modification caused greater lateral growth and comparatively large downward (out of target zone) growth of the HF and NF reactivation front, lowering the effectiveness of the HF job. However, halving the number of NFs and doubling their final storage apertures did not result in a substantial change in the SRV geometry upon allowing fluid flow through non-dilatable NFs. Fourth, altering the well-landing depth within the Woodford Shale did not result in a major shift in the overall stimulation geometry or volume. Most importantly, the simulated hydraulic fractures emanating from the wellbore do not span the entire recorded microseismic cloud length and height.",4,4,1
Fracture,Hydraulic Fracture,"Gong, Yiwen; El-Monier, Ilham",Microstructure diagnosis of the fractured tight sandstone using image analysis,Grain size; Image analysis; Tight sandstone; Statistical analysis,SIZE DISTRIBUTIONS; PROCESS ZONE; SIMULATION; BEHAVIOR; CHANNEL,"In the hydraulically failed rock, a process zone where the natural fractures and the intergranular rock grain boundaries are activated while induced transgranular fractures are formed. These fractures in all scales share the drainage with the main hydraulic fracture. The objective of this study is to develop a novel approach thereafter to diagnose the evolutions of the critical above said microstructure properties at the post-fracturing state. In the previous work, we have examined the remarkable capability of image analysis on hydraulic fracture roughness determination (Gong and El-Monier, 2018). As an extension, this work introduces a fast and precise approach to study the aforementioned features of the post-fracturing core sample, including crack density, rock grain, and pore size distributions, by coding the desired image processing and analysis program. The hydraulic fracturing test was carried out using a Tennessee sandstone core sample and a sub-core of this fractured rock is excavated and polished (Patel et al., 2017). Its cross-section was subdivided into sequences and captured by the high-resolution SEM images after the ion-milling process. The post-fracturing grain size and pore size are investigated in the orthogonal direction of the main fracture at various locations and are compared to those from the literatures. The results from this study indicate that our proposed image analysis approach is capable to detect the grain damages resulting from the rock crushing. In addition, a positive relationship between the two parameters is found regardless of the cementing, packing mechanism, damage condition, and sorting of the fractured rock.",4,4,2
Fracture,Hydraulic Fracture,"Behnoudfar, Pouria; Asadi, Mohammad Bagher; Gholilou, Alireza; Zendehboudi, Sohrab",A new model to conduct hydraulic fracture design in coalbed methane reservoirs by incorporating stress variations,CO2 injection; Hydraulic fracture; Stress variations; Boundary element method; Latrobe Valley coalbed,CARBON-DIOXIDE; CO2; PRESSURE; CAPTURE,"Coalbed reservoirs are considered as suitable media for injection operations, especially for geological sequestration of carbon dioxide (CO2). This type of reservoirs might be stimulated to enhance the efficiency of injection as the permeability of these formations is usually low (0.1-10 mD). The hydraulic fracturing technology is one of the effective methods to attain a greater injectivity. To design an efficient hydraulic fracture, it is vital to systematically investigate important changes (e.g., pressure and stresses) occurring over the injection process on the fracturing performance. An increase in the reservoir pressure is an inevitable occuerrence during the fracturing operation. In situ stresses will also vary due to the fluid injection. As a consequence, the permeability of coalbed will be altered during the reservoir life. In this research study, a novel model for the hydraulic fracture design is introduced to consider the changes in the reservoir permeability during the injection process. A Direct Boundary Element Method (DBEM), which is a fundamental concept in the Unified Fracture Design (UFD), is employed to determine the fracture injectivity. In this study, the pressure change is estimated based on the injectivity. The variations of in situ stresses are determined using a model, which uses the Boundary Element Method (BEM) and theory of inclusions. Permeability is then updated based on the new values of stresses and the design dimensions of the fracture for the new time steps. Therefore, the model presents a suitable design of hydraulic fracture by considering the reservoir pressure changes during the injection. The proposed method is implemented on Latrobe Valley brown coal. The results suggest that the reservoir life is an important parameter to optimize the hydraulic fracturing design. Fractures with the same width and different penetrations yield very different efficiencies during the injection. The highest amount of cumulative injection can be achieved after 10 years using a fracture, which seems to be not optimum at the initiation stage of the injection process. This study proposes that it is necessary to take into account the stress changes in the design of a hydraulic fracture system in a coalbed to attain the effective injection operation regardless of high penetrations.",4,4,2
Fracture,Hydraulic Fracture,"Song, Zhen; Zhou, Qi You",Micro-scale granite permeability estimation based on digital image analysis,Fracture permeability; Porosity; Digital image analysis; Lattice Boltzmann simulation; Granite rocks,PETROPHYSICAL PROPERTIES; ROCKS; QUANTIFICATION,"Permeability is a key parameter in describing the flow conductivity of rocks. But experimental measurements of the parameter not only consume time but also only provide us with limited data number. By analyzing digital images of cast thin sections of rock samples in micro-scale, this study presented a systematic method of extracting geometric parameters of fractures and applied it to the granite rock samples from fault F4 in Gansu Beishan, China, which have low permeability and poor water-containing property. With the extracted geometric parameters, the rock permeabilities were estimated by Kozeny-Carman equation and Lattice Boltzmann simulation and were compared with those obtained by pulse decay technique. The results show that although there exists abnormal values in the estimated porosities and permeabilities, in general the relative error is only about onefold for the conditions used in this study. The method proposed here would be useful in the permeability and porosity estimation for fractured rocks that have low hydraulic conductivity.",4,4,3
Fracture,Hydraulic Fracture,"Rivas, Endrina; Gracie, Robert",Numerical considerations for the simulation of proppant transport through fractures,Proppant transport; Hydraulic fracture; Proppant bridging; Multiphase flow; Nonlinear advection; Finite volume,TIP SCREEN-OUT; HYDRAULIC FRACTURE; NEWTONIAN SLURRY; FLUID-MECHANICS; FLOW; SUSPENSIONS; VISCOSITY; PROPAGATION; MIGRATION; RHEOLOGY,"Injection of a proppant slurry (fluid mixed with granular material) into a reservoir to keep fractures open is a common procedure in hydraulic fracturing treatments. This article presents the numerical methodology for simulation of proppant transport through a hydraulic fracture using the Finite Volume Method. Proppant models commonly used in the hydraulic fracture literature solve the linearized advection equation; this work presents solution methods for the nonlinear form of the proppant flux equation. The complexities of solving the nonlinear hyperbolic advection equation that governs proppant transport are tackled, particularly handling shock waves that are generated due to the nonlinear flux function and the spatially-varying width and pressure gradient along the fracture. A critical time step is derived for the proppant transport problem solved using an explicit solution strategy. A predictor-corrector algorithm is developed to constrain the proppant from exceeding the physically admissible range. The model is able to capture the mechanism of proppant bridging which occurs in sections of narrow fracture width, tip screen-out which occurs where fracture becomes saturated with proppant, and flushing of proppant into new fracture segments. The results are verified by comparing with characteristic solutions, and the model is used to simulate proppant transport through a KGD fracture.",4,4,4
Fracture,Hydraulic Fracture,"Wang, Shibin; Chen, Fuhu; Guo, Jianchun; Li, Yang; Zhao, Feng; Zhou, SiYan",Adsorption damage of hydroxypropyl guar gum to porous media composed of quartz,Guar gum; Adsorption; Quartz; Porous media; Hydrogen bond,NONIONIC SURFACTANT; NATURAL SURFACTANT; WATER; MECHANISM; SILICA; SAND,"Hydroxypropyl guar gum (HPG) is widely used in the hydraulic fracturing of sand rock gas reservoirs. The HPG residue can severely damage the rock surface of the reservoirs owing to the interaction between the HPG molecular chain and the rock surface, which results in adsorption and retention of HPG. To confirm the interaction between HPG and rock, the adsorption properties of HPG on a rock surface were investigated. The dependence of HPG adsorption on HPG concentration, pH, and temperature is discussed, and the adsorption force between HPG and quartz is also studied. With an increase in HPG concentration and pH, the amount of adsorbed HPG increases. The amount of adsorption increases first with temperature and then decreaseds. According to infrared spectroscopy and Zeta potential results, there is a weak chemical bond between HPG and quartz particles. Hydrogen bonding is the main force, which results in the adsorption and retention of HPG in porous media.",4,4,4
Fracture,Hydraulic Fracture,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Fracture,Hydraulic Fracture,"Govindu, Abhishek; Ahmed, Ramadan; Shah, Subhash; Amani, Mahmood",Stability of foams in pipe and annulus,Foam stability; Bubble coarsening; Coalescence; Gravity drainage; Half-life; Foam quality,RHEOLOGICAL BEHAVIOR; DRAINAGE,"Foam fluids present numerous advantages for many oil field applications. Due to their bubble structure and a gaseous component, foams exhibit very high viscosity and low density. Low density makes foam an attractive fluid in underbalanced drilling operation in which light fluid is essential to maintain wellbore pressure below pore pressure. Due to its high viscosity, foam exhibits good hole-cleaning performance even at low annular velocities. Nevertheless, foams are thermodynamically unstable fluids and their structures eventually collapse. Foam decays as a function of time and the decay occurs mainly due to bubble coalescence and the gravity drainage of the liquid phase. Maintaining fluid stability is necessary for foam drilling. For a successful drilling operation, the half-life of foam, which is the time taken by foam to drain 50% of its liquid volume, should exceed circulation time. For other applications, such as hydraulic fracturing or cementing, the half-life of foam should exceed the time taken for fluid to reach target zones. In this study, foam stability experiments were conducted in a concentric annulus (50mmx75 mm) and 25 mm pipe sections. The pipe section was transparent to observe drained liquid level. Aqueous, polymer-based, and oil-based foams were considered in the investigation. The effect of gas volume fraction (quality) was studied under static condition. All experiments were performed at 400 kPa and ambient temperature (20 +/- 2 degrees C). Foam quality was increased from 40% to 80%. However, at high qualities (greater than 70%), the oil-based foam was unstable. Hydrostatic pressure data was collected from the annular section and converted into density curves to determine drained liquid volume. In the pipe section, the drainage was physically measured from the liquid level and recorded periodically. A digital camera with a microscope was used to capture foam image in real-time to examine bubble coarsening and foam decay. For a given quality, the polymer-based foam was the most stable, while oil-based foam was the least. For all three types of foams, stability increased with quality. Foams were more stable in the annular section, as compared to the pipe, possibly due to the impact of container wall on bubbles and drained liquid motion. Foam decay and bubble coarsening were observed by comparing bubble sizes in captured images at various times. On average, larger bubbles were observed in higher quality foams. The rate at which foam bubbles coarsening mostly reduced with time.",4,4,5
Fracture,Hydraulic Fracture,"Tolmacheva, K. I.; Boronin, S. A.; Osiptsov, A. A.",Formation damage and cleanup in the vicinity of flooding wells: Multi-fluid suspension flow model and calibration on lab data,Flooding wells; Injectivity decline; Suspension filtration; Formation damage; Colmatation,DEEP-BED FILTRATION; POROUS-MEDIA; PLANE WALL; TRANSPORT; SPHERE; ENTRAINMENT; DEPOSITION; SIMULATION; PARTICLES; MECHANICS,"Injection of water into a rock formation through the flooding wells is a common practice to maintain 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, which are introduced either externally (untreated water) or internally (e.g., particles detached from the inner surface of a pipeline due to erosion and abrasion as well as mineral particles detached from pore surface). In the framework of the two-fluid approach, we formulate mathematical model for filtration of a particle-laden suspension in the vicinity of flooding wells. Two mechanisms affecting transport of non-colloidal fines are considered: trapping and mobilization. Trapped particles reduce permeability and porosity of the rock, which leads to the injectivity decline of the well. The model contains minimal set of tuning parameters describing particle trapping and mobilization rates. This is achieved by critical overview of existing models. We calibrate suspension filtration model against existing experimental (laboratory) data on fines mobilization and trapping in porous media. A parametric study of different flooding scenarios is carried out numerically. In particular, we investigate the effectiveness of periodic flooding regime, when the periods of injection are followed by flowback in order to wash out trapped fines from the near-wellbore zone and restore well injectivity. Implications to formation damage and cleanup phenomena peculiar to hydraulic fracturing and drilling are discussed. Practical recommendations are given.",5,5,0
Fracture,Hydraulic Fracture,"Maity, Debotyam; Ciezobka, Jordan",Designing a robust proppant detection and classification workflow using machine learning for subsurface fractured rock samples post hydraulic fracturing operations,Artificial neural nets; Image processing; Classifier benchmarking; Unconventional reservoirs; Core sampling; Shale rock,NEURAL-NETWORK; ALGORITHM,"Hydraulic fracturing is a method of reservoir stimulation that enhances the effective permeability of tight unconventional reservoirs such as shale oil and gas. In typical hydraulic fracturing treatments, millions of gallons of water are pumped under pressure into rock formations deep below the earths surface. Proppant particles such as sand are injected as part of the fracturing slurry to hold the hydraulic fractures open, or propped, after high-pressure water injection has ceased. Propped hydraulic fractures provide a conduit for long-term hydrocarbon production, thus being essential to commercial oil and gas production from shale reservoirs. The distribution of the proppant particles can be useful in understanding effectiveness of hydraulic fracturing treatments. It can also help identify both, unstimulated and under-stimulated zones within the reservoirs of interest. These proppant particles can be found in drilling fluid return or in cores, which can be sampled from subsurface. In this study, we highlight the design and development of artificial neural network based workflow that helps identify where proppant particles are located and classifies proppant and various particles of interest. In this study, these particles are limited to naturally occurring calcite or other minerals from subsurface rocks. Various features of interest that help with the classification process have been conceptualized and defined. This method has been verified using controlled test cases and validated using actual samples from subsurface. The designed ANN classifier has also been benchmarked with other classification methods including k-nearest neighbor, naive-Bayes classifiers and Support vector machines. A workflow to process samples from subsurface and quantify proppant distribution for future test programs including potential real time applications has been proposed. Based on this workflow, we share proppant distribution from a Permian Basin case study. We have also compared proppant distribution using our proposed method with results from an independent workflow on a similar dataset, which does not utilize machine learning.",5,5,0
Fracture,Hydraulic Fracture,"Mandiyar, H.; Salari, A.; Qajar, J.; Kalantariasl, A.",New correlations for etched fracture width and half-length of acid-fractured wells,Acid fracturing; Etched fracture width; Acid fracture half-length; Fracture conductivity; Effective wellbore radius,,"Acid fracturing is one of the most efficient well stimulation techniques in carbonate reservoirs. Estimation of well productivity after fracturing is an important issue in acid fracturing design and production engineering analysis. There are some correlations, available in the literature, for estimation of effective wellbore radius of hydraulically fractured wells. However, fracture etched width and its half-length must be known to use these correlations and, to our best knowledge, a simple and correct method for prediction of these parameters has not been reported yet. This paper presents a couple of correlations for estimation of etched fracture width and fracture half-length considering acid-rock interactions, reservoir and operational parameters. To develop and verify the proposed correlations, we used a large data bank produced by our in-house simulator, which models one-dimensional acid flow through a single hydraulic fracture considering acid-rock reaction and also fluid leakoff to the matrix. The governing equations are solved numerically using finite difference approach and the results were compared with a commercial simulator for verification. It is also explained how the values of etched fracture width and fracture half length, estimated by our new correlations, can be used in the available correlations for prediction of effective wellbore radius.",5,5,1
Fracture,Hydraulic Fracture,"He, Zhenhua; Duan, Benchun",Significance of the dynamic stress perturbations induced by hydraulic fracturing,Hydraulic fracturing; Dynamic modeling; Dynamic effects; Dynamic stress; Stability,RUPTURE; SLIP; VELOCITY,"Hydraulic fracturing and microseismicity generation and radiation are dynamic processes. The associated dynamic stress perturbations could play a significant role in relevant studies, such as activation of weak planes including natural fractures, bedding planes, etc. We study how different the dynamic and static stress perturbations could be during hydraulic fracturing. Our work is based on a 2D plane-strain framework. A dynamic finite element method is applied to solve the equations of motion. The static stress perturbations are obtained when the models reach static equilibrium (i.e., after generated seismic waves die out). We compare the static and dynamic stress perturbations at a moment when a hydraulic fracture (HF) propagates to a certain length. Mohr circle analysis shows that around the HF the Mohr circle based on a dynamic stress tensor is closer to a failure line than that based on a static stress tensor. The peak static and dynamic stress perturbations during the process are also compared. We conclude that the absolute values of the peak dynamic stress perturbations are always greater than that of the peak static stress perturbations, especially in the area close to the HF and its tips. The effect of injection rates on the static and dynamic stress perturbations is also studied. The largest peak static and dynamic stress perturbations during the hydraulic fracturing process are measured. The absolute values of both the largest peak dynamic and static stress perturbations increase with injection rates. The absolute values of the difference between the largest peak dynamic and static stress perturbations also increase with injection rates due to more significant dynamic effects.",5,7,1
Fracture,Hydraulic Fracture,"Hu, Xiaohu; Yu, Wei; Liu, Malin; Wang, Mingwei; Wang, Weihong",A multiscale model for methane transport mechanisms in shale gas reservoirs,Semi-analytical model; Complex hydraulic fractures; Shale gas; Multiple horizontal wells; Nanopores,HYDRAULIC-FRACTURE GEOMETRY; HORIZONTAL WELLS; PRODUCTION SIMULATION; SEMIANALYTICAL MODEL; COMPREHENSIVE MODEL; COMPLEX FRACTURES; FLOW; NETWORKS; PERMEABILITY,"We presented an efficient semi-analytical model-based analysis of methane transport in shale reservoirs including multiple horizontal wells with nanopores and complex hydraulic fractures. Multiple important gas transport mechanisms in nanopores such as gas desorption, gas slippage and diffusion and pressure-dependent fracture conductivity are fully incorporated in the model. Both simple and complex fractures in multiple shale-gas wells can be easily and effectively dealt with in accordance with the discretization approach, which does not require detailed gridding like numerical model. The superposition principle is utilized to capture the interactions between all fracture segments in order to accurately simulate real gas transport from matrix to fractures and finally from fractures to wellbores. We verified the semi-analytical model against a numerical compositional reservoir model for two shale-gas wells with multiple simple planar hydraulic fractures considering the gas desorption effect. The semi-analytical model was used to analyze ultimate gas recovery of different complex hydraulic fracture patterns in a two-well scenario, which were generated from a complex fracture propagation model with and without considering natural fractures. In addition, it was applied to perform field-scale simulation with multiple wells and complex fracture geometries in accordance with microseismic data. The simulation results show that multiple gas transport mechanisms, pressure-dependent fracture conductivity and complex fracture geometries play an important role in controlling well productivity and gas recovery, which should be properly accounted for in the physical model in order to achieve more accurate long-term production forecasting of multiple-fractured shale-gas horizontal wells.",5,6,1
Fracture,Natural Fractures,"Ma, Zhengqian; Yin, Xingyao; Zong, Zhaoyun; Song, Mingshui; Wang, Yanguang; Chen, Zuqing; Li, Jinlei; Liu, Xiaojing",Azimuthally variation of elastic impedances for fracture estimation,Azimuthally anisotropic elastic impedance; Fourier series; Fracture orientation; Fracture density; Karhunen-Loeve transformation; 90 degrees ambiguity,SEISMIC AMPLITUDE VARIATION; INVERSION; COEFFICIENTS; PARAMETERS; OFFSET; PROPAGATION; ANISOTROPY; MODELS; FLUID,"Fracture parameters including fracture orientation and fracture density, work as significant information in the fields of the engineering and exploration geophysics. However, it nowadays still remains challenging to concisely and stably estimate those fracture parameters from seismic data due to the limited signal to noise ratio of the azimuthal seismic data. A method based on azimuthally anisotropic elastic impedance (azimuthal AEI) in terms of Fourier series variation with azimuth is proposed to characterize the fracture distribution. Firstly, the azimuthal AEI equation in terms of truncated Fourier series is derived to reduce the number of unknown parameters in the fracture parameters estimation. In addition, KL (Karhunen-Loeve) transformation is used to extract the primary feature of reflection amplitude variation with azimuth and weaken the random noise for azimuthal pre-stack seismic data. And then the azimuthal AEI is estimated from KL transformed azimuthal pre-stack seismic data with the constrained sparse spike inversion method. The fracture orientation without 90 degrees ambiguity can be estimated by an innovative azimuthal AEI equation incorporating the azimuthal AEI equation in terms of Fourier series and the fracture orientation prior information. And the biased estimate for the anisotropic gradient of the azimuthal AEI can be estimated from the second order Fourier coefficient to forecast the fracture density. Besides, we introduce a more convenient way, which is employing the standard deviation of the nature logarithm (SDNL) of the azimuthal AEI in the azimuth domain, than that based on the anisotropic gradient in the fracture density estimation. The synthetic cases demonstrate the rationality and robustness of the innovative primary wave azimuthal AEI equation and the fracture parameters estimation method even with sparse 30 degrees sampling interval in the azimuth. A field data example demonstrates that the proposed method is effective and efficient in the fracture parameters prediction.",0,0,3
Fracture,Natural Fractures,"Prasun, Samir; Wojtanowicz, Andrew K.",Semi-analytical prediction of critical oil rate in naturally fractured reservoirs with water coning,Critical oil rate; Naturally fractured reservoirs; Semi-analytical; Water coning; Matrix well; Fracture well,FLUID-FLOW; PERMEABILITY; MODEL,"Naturally fractured reservoirs (NFRs) with bottom water are generally produced above their critical oil rate (maximum possible oil production rate without water breakthrough) that is difficult to determine as it varies between wells, depending on the well's location in the fracture network. In principle, wells can either be completed in matrix or fractures. Present formulas of critical-rate in NFR are oversimplified ignoring the network heterogeneity and anisotropy ratio of fractures, and they also do not consider the difference between on-fracture/off-fracture well completion placements. Presented is development of a new semi-analytical formula that considers these effects-with emphasis given to well placement assessment. The critical rate model is derived from mechanistic principles and then improved with statistical calibration. The mechanistic approach (Chaperon (1986)) considers vertical equilibrium of viscous and gravity forces for a hemispherical flow to a point-source well in a dual porosity/dual permeability model of naturally fractured reservoirs. The model considers the water cone instability, and anisotropy ratio of NFR only for a short-perforated completion interval. The model is tested for wide variety of NFRs for short completions. The model is then statistically calibrated to including the effect of long penetration ratio, using a designed matrix of simulated experiments covering wide ranges of NFR properties. This statistical approach allows the model to consider any change in flow regime from semi-spherical to non-radial distorted flow. The comparison of Chaperon's analytical model and NFR simulations shows that the model is good for NFRs for penetration ratio smaller than 0.35. For penetration ratio greater than 0.35, a new semi-analytical model of critical-rate for NFR is developed by statistically calibrating the Chaperon's analytical model. The new model considers the parameters ignored in the previous models of NFR. Finally, a new mechanistic derivation of critical rate for wells completed in matrix block of NFR is determined by analytically including the effect of well's distance to fracture in a critical rate formula for NFR. The model matches well with the simulated data when compared with it. The model shows that the wells accidently completed off-fractures may display higher values of critical rates and the difference relates to their distance to the nearest fractures. It is also shown that the offfracture well's formula reduces to the on-fracture well's formula when the distance is reduced to zero.",1,1,0
Fracture,Natural Fractures,"Venkatesh, Prashanth Bangalore D.; D'Entremont, James H.; Meyer, Scott E.; Bane, Sally P. M.; Grubelich, Mark C.; King, Dennis K.",Bipropellant high energy stimulation for oil and gas applications,Energetics; Propellant; Fracturing; Fracture networks; DDT; Detonations,PRODUCTIVITY,"Large-scale extraction of oil and natural gas requires an effective method of generating a high surface area network of fractures, or the stimulation of existing fractures, in a formation in order to increase permeability. Conventional hydraulic fracturing has limited utility in this application. In this work, Sandia National Laboratories is exploring high rate pressurization techniques employing tailored energetic materials systems to control both pressure rise rate and peak pressure in order to optimally stimulate potential rock formations. Rapid pressurization, at rates far exceeding quasi-static conventional hydraulic rates, can generate multiple radial well bore fractures and potentially provide a mechanism to induce shear destabilization within the formation that enables the fractures to be self-propping. Multiple fractures from the well bore allow efficient coupling to the existing formation fracture network and increase near field well bore permeability. Furthermore, these techniques can allow for repeated stimulations and produce energetic events within the fractures thereby allowing fractures to be extended further. Controlled rate pressurization is a useful tool for the efficient generation of fracture networks and has potential application to increase oil and gas production. This paper provides an overview of the concept of controlled rate pressurization, laboratory experiments and field trials that are being conducted. The present work investigates detonations of a stoichiometric mixture of ethylene and nitrous oxide (C2H4 + 6N(2)O) at high initial pressures ranging from 0.862 to 2.068 MPa as a method of fracturing rock below the ground surface. The experiments investigate the fracture generation as a function of the initial pressure of the mixture. In the current configuration, the combustion reaction is initiated by an electrically fired igniter at the ground surface and quickly transitions to a detonation. The experimental setup accommodates one high pressure (690 MPa) transducer, placed downstream of the igniter, to measure peak pressure. The pressure transducer recorded peak pressures, which are 2.3-2.6 times in excess of the Chapman-Jouguet (CJ) values as a result of pre-compression of the unburned gas mixture during the flame acceleration prior to deflagration-to-detonation transition (DDT). Analysis of the data indicated an increase in rock permeability due to detonations and this was confirmed by the core drilled sections at the test site.",2,2,1
Fracture,Natural Fractures,"McKean, Scott H.; Priest, Jeffrey A.",Multiple failure state triaxial testing of the Montney Formation,Unconventional reservoir geomechanics; Multiple failure state; Triaxial test; Elastic anisotropy; Post-peak behaviour; Failure envelope; Montney Formation,ROCK; STRENGTH,"Elastic behaviour controls hydraulic fracture propagation and ultimately, the productivity of unconventional reservoirs. Various index tests and single stage triaxial tests are used to characterize elastic moduli but it can be difficult to obtain enough samples and sufficient information. This is partly due to the fissile nature of shales, which results in a paucity of representative core plugs. It is also partially due to the complex and heterogeneous nature of unconventional reservoir's geomechanical behaviour. The failure mechanics of unconventional rocks are poorly understood and seldom incorporated in hydraulic fracturing or geomechanical models. Yet, failure is major influence on fracture complexity and reservoir drainage volumes. The objectives of this study were to evaluate the variability in geomechanical properties and characterize the post-peak behaviour of a stiff siltstone from the Montney Formation in Alberta, Canada. The multiple failure state triaxial test was used to define the pre-peak elastic behaviour, post-peak behaviour, and failure envelope of a single core plug. This is beneficial for practitioners that are faced with a paucity of samples. The multiple failure state triaxial test is difficult to implement for stiff specimens, which fail in a brittle and unstable manner and a methodology to improve the stability near and beyond sample failure was therefore developed. The results from this study, which were also compared to various index tests and publicly available data, show that the samples had low porosity, low clay, and high stiffness. Significant variability in elastic behaviour was observed due to non-linearities in the loading curve - an effect that overshadowed changes due to confining pressure and highlighted that need for careful consideration of elastic parameter variability. Several oriented samples sets were used to characterize elastic and strength anisotropy. The improved test methodology was able to capture stable post-peak behaviour on almost all the tested samples. Brittle stick-slip failure was observed and an exponential model for approximating post-peak behaviour was presented. The combination of triaxial testing and index testing was able to completely characterize the constitutive law and failure envelope of the samples, save the Biot coefficient. These results can be incorporated into both routine and advanced geomechanical models and hydraulic fracturing simulators.",2,2,1
Fracture,Natural Fractures,"Fernandez-Ibanez, Fermin; DeGraff, James M.; Moore, Paul J.; Ahdyar, LaOde; Nolting, Andrea",Characterization of non-matrix type and flow potential using lost circulation information,Non-matrix; Karst; Natural fractures; Lost circulation; Drilling; Carbonate reservoir characterization,FIELD,"Lost circulation zones (LCZs) provide valuable information about the properties of non-matrix features - i.e., fractures and karst - intersected by wells during conventional drilling, including information about the type, size, connectivity and flow potential. The magnitude of the loss rate and lost volume should reflect the nature of the non-matrix feature responsible for losses. For example, the total volume lost in each of these zones provides a minimum volume of connected pore space, whereas the instantaneous rate of loss suggests whether the LCZ is due to drilling into a cave (high rate of loss) versus a fracture (low rate of loss). We define and quantify each LCZ from information recorded in the drilling reports including top and base of the LCZ, maximum loss rate, and cumulative volume lost to the zone. Once each LCZ has been identified from the drilling reports, we evaluate wellbore images and caliper logs across each anomalous zone to determine the cause of the loss event - e.g., caves or fractures. Results suggest that caves are typically characterized by high lost rates (> 50 m(3)/h or 315 bbl/h), while fractures and touching vugs are characterized by lower rates (< 50 m(3)/h or 315 bbl/h). Low rates and volumes in excess of 160 m(3) (1006 bbl) appear to be related to fractures, while volumes below this threshold can be attributed to either fractures or touching vugs. This natural breakout between karst and fractures in particular, allows us to work in data challenged environments and use drilling data as a screening tool to evaluate whether the main non-matrix flow elements are fracture or karst dominated. A key product of this work is a volume versus rate (VvR) plot that typifies loss characteristics for specific non-matrix features, so that in the absence of image logs, it can be used to infer the causes of each LCZ event.",3,3,0
Fracture,Natural Fractures,"Li, Zhenglan; Duan, Yonggang; Wei, Mingqiang; Peng, Yu; Chen, Qingxuan",Pressure performance of interlaced fracture networks in shale gas reservoirs with consideration of induced fractures,Interlaced fracture networks; Shale gas; Secondary induced fractures; Flux distribution; Pressure performance,HORIZONTAL WELLS; SEMIANALYTICAL MODEL; TRANSIENT PRESSURE; METHANE; FLOW; PERMEABILITY; MECHANISMS; ADSORPTION; BEHAVIOR,"Multi-stage fracturing in shale gas reservoirs may create complex fracture network around horizontal wellbore, due to the widely-distributed natural fractures. However, little work has been done to investigate the effects of secondary fractures on well testing models for shale gas reservoirs. In this paper, a more comprehensive model was developed for interlaced fracture networks in shale gas reservoirs with consideration of multiple transport mechanisms and different flow states. By employing the source function and Laplace transformation, the line sink solutions for four kinds of flow states were unified. Based on the discretization method and unified line sink solution, the pressure responses for interlaced fracture networks with infinite conductivity were obtained. Type curves were plotted and typical flow regimes of this model were identified. In order to have a further understanding of the effect of induced fractures, the slope curves of pseudo-pressure derivative were introduced to analyze the interference between fractures. The influences of the angel and the length of induced fractures on the well testing curves were simulated by the semi-analytical model for the first time. Then, the flux distributions of interlaced fracture networks were simulated and discussed for achieving significant advice. Finally, the proposed model was verified by a simplified case and a field case. The presented model will be helpful for understanding the transient performance of multi-stage fractured horizontal wells with consideration of induced fractures.",3,3,0
Fracture,Natural Fractures,"da Silva Ribeiro, Vanessa de Jesus; de Moraes Oliveira, Gabrielle Fontella; Cristian, Muara; Martins, Andre Leibsohn; Fernandes, Lindoval Domiciano; Vega, Marcia Peixoto",Neural network based controllers for the oil well drilling process,Downhole pressure; Control; Artificial intelligence; Pipe connection; Kick; Lost circulation,CONTROL SCHEME; KICK DETECTION; PRESSURE; PREDICTION; PARAMETERS; SIMULATION; MODELS; TIME,"The oil well drilling is a complex process, requiring that the bottomhole pressure be maintained within an operational window, limited by fracture pressure and pore pressure (and/or wellbore collapse). During the drilling process, there are several phenomena that directly influence the annulus bottomhole pressure: kick, lost circulation, inefficient removal of solids, well length increase, reservoir parameters and pipe connection procedure (surge and swab effects). The main objective of this work is to develop neural network controllers able to regulate the annulus bottomhole pressure under pipe connection procedure, kick and lost circulation disturbances. For this purpose, an experimental drilling unit was built, depicting the oil well drilling process primordial characteristics. Besides, real oil well offshore data were employed for validating the neural network controllers. Neural networks were built for predicting the direct plant dynamics (inverse neural network controller) and the inverse plant dynamics (direct neural network controller). It is noteworthy to mention that direct plant dynamics neural modelling was employed as the nonlinear model of a gain scheduling control approach; in addition, the inverse plant dynamics neural modelling constituted a nonlinear controller, directly predicting the manipulated variable. Both controllers employed real-time neural network training, being, therefore, adaptive schemes for regulating the oil well drilling process, which nature is inherently transient.",3,3,0
Fracture,Natural Fractures,"Canbolat, Serhat; Parlaktuna, Mahmut",Analytical and visual assessment of fluid flow in fractured medium,Fluid flow; Natural fracture; Equivalent fracture aperture (EFA); Improved cubic law (ICL),LOCAL CUBIC LAW; ROCK; CONDUCTIVITY; EQUATION,"Most reservoirs consist of natural and artificial fractures, including isolated microscopic fissures. These fractures form complicated paths for reservoir characterization and fluid movement that ultimately impacts production performance and ultimate recovery. That's why recovery estimations of fractured reservoirs are considered to be extremely challenging due to complexity and heterogeneity of the geological patterns. Oil production from fractured reservoirs results in varying saturation values throughout the reservoir. This is due to the microscopic fissures and heterogeneity of the fracture environment, which could not be swept thoroughly. Higher production/injection ratios also enhance the fingering effect by passing oil through the reservoir. In this study, naturally and artificially fractured cores were used. Analytical and experimental calculations were performed in order to understand the physical structure of the cores. Moreover, in the literature the analytical solutions of the fractures were defined by cubic law (CL), local cubic law (LCL) and modified cubic law (MCL). However, due to the lack of consideration of fracture properties with limited experimental work, there needs still work on this field. Equivalent fracture aperture (EFA) measurements were done by microscope and compared with the analytical calculations. Laboratory results were defined by the equation developed for predicting equivalent fracture apertures as Improved Cubic Law (ICL). Shrinkage in equivalent fracture aperture was also defined by ICL observed by microscope. Using ICL, analytical calculations were done in different environments. Equivalent fracture apertures were calculated for all the experimental flow rates under laminar flow. ICL has worked with the fractured cores flow definition whereas not for homogeneous cores. That's why due to higher calculated values and the 15% error on EFA, a correction coefficient (C) included to the CL equation for the tortuosity or the roughness effect This result was in th error range of previous results and gave more realistic estimation with respect to the previous studies carried out Finally, C coefficient was calculated in a range of 0.53-0.65.",3,3,0
Fracture,Natural Fractures,"Mokhtari, Mehdi; Nath, Fatick; Hayatdavoudi, Asadollah; Nizamutdinov, Rustam; Jiang, Shuxian; Rizvi, Hashim",Complex deformation of naturally fractured rocks,Strain; Optical technique; Digital image correlation; Natural fracture; Complex fracture,DIGITAL-IMAGE-CORRELATION; SHEAR DEFORMATION; GROWTH; IDENTIFICATION; VISUALIZATION; EVOLUTION; FAILURE; SHALE,"Strain is a key parameter in the evaluation of rock mechanical properties and failure behavior. Strain is usually measured using strain gauges, however, this laboratory method has inherent uncertainty in the attachment of sensitive gauges to the rock surface and it is limited to one-point strain measurement. In complex geometries such as rock samples with natural fractures or lamination, that classical approach cannot provide the whole picture of strain development in such complex geometries. To overcome these challenges, the application of optical technique with image processing is proposed. The optical technique has the advantage of being a non-contact method and it provides quantitative visualization of full-field strain measurement. To examine quantitative visualization of strain development, DIC technique was first conducted on a homogeneous sandstone sample as a benchmark. The results verify that the maximum tensile strain is developed at the central vertical line of the sample as it was expected from theoretical solutions. This DIC measurement matches the post-failure fracture pattern of the specimen. Then the technique was applied on the Buda Limestone samples with horizontal, sub-horizontal or multiple complex natural fractures (sealed or partially open) and inclusions while the samples were under diametrical compression experiment. The results of this study provide further insight into the role of natural fractures on induced fracture initiation and propagation under this specific testing condition. Horizontal natural fractures are planes of maximum compressive strain which can delay the propagation of vertical tensile fractures. The maximum amount of tensile strain usually initiates at the boundary of these natural fractures and vertical tensile fractures usually deviate toward horizontal fracture for a short distance before turning back to propagate vertically following the maximum stress path. Full-field surface deformations are mapped optically in the crack-inclusion vicinity where DIC results showed that crack front is arrested by the inclusion for the complete fracture event. In contrast to the failure pattern in homogenous sandstone specimen, complex fracture pattern was observed on several specimens with multiple fracture network. Fracture slippages along the natural fracture, fracture deviation was observed in samples with steep inclined natural fractures. The results of this study can help us to better understand the complex failure mechanism in naturally fractured media and elaborate on various mechanisms of failure under diametrical compression tests. DIC is a powerful technique in providing the dynamic strain development over the surface of the sample in real-time, thus it can provide the fracture initiation and propagation in such heterogeneous rock media.",3,3,1
Fracture,Natural Fractures,"Mi, Lidong; Jiang, Hanqiao; Cao, Yang; Fang, Sidong; Liu, Hua; Zhou, Yuanlong; An, Cheng; Yan, Bicheng",Comprehensive apparent permeability model coupled shale gas transfer mechanisms in natural fractures and matrix,,RESERVOIR; TRANSPORT; FLOW; HYDROCARBON; SIMULATION; NANOPORES; BASIN,"This paper presents a method to quantitatively characterize natural Fractures Intensity (FI) and proposes a Comprehensive Permeability Model (CPM) coupling gas transfer mechanisms in natural fractures and matrix for shale gas reservoirs. Firstly, the Scanning Electron Microscope (SEM) images of natural shale cores are used to quantitatively characterize FI, such as the aperture, length, spacing, general fracture distribution described by Fisher orientation dispersion value (K), and the Angle between the mean pole of Fractures and the Scan-line (AFS). Secondly, the corresponding relationship between the AFS and K, which can be used to evaluate the length of fracture traces per unit area of trace plane and the area of fractures per unit volume of rock, is built based on the numerical simulation results. Then, we can obtain the natural fracture distribution state and quantitatively distinguish the natural fracture volume from the matrix. Finally, the CPM is proposed by combining the FI and matrix pore parameters based on the series-parallel circuit theory. The CPM is not only verified by the numerical simulation in which the Boundary Element Method (BEM) is adopted to simulate the fractures' influence, but also in good agreement with the lab measurements of shale samples from the Cambrian Niutitang formation in South Sichuan Basin, China. The FI evaluation method and the CPM proposed in this paper provide a new approach to quantitatively understand the natural fracture distribution and the contribution to the shale reservoir percolation capability. In turn, this will enable engineers better understand the shale gas transport mechanisms and develop the simulation in a more practical way.",4,4,0
Fracture,Natural Fractures,"Aghabarari, Amirhossein; Ghaedi, Mojtaba",A new simulation approach to investigate reinfiltration phenomenon in fractured porous media,Naturally fractured reservoirs; Reinfiltration; Grey relational analysis; Simulation; Block to block interaction,RECOVERY,"The reinfiltration is a common phenomenon in fractured reservoirs and severely influence production rate. Despite the efforts made to study the reinfiltration process experimentally or theoretically, still there is not a comprehensive study that investigates all the affecting parameters. In this paper, a new approach to specify the reinfiltrated oil into the matrix block and drained oil from the matrix block in a commercial simulator has been introduced. Moreover, a new dimensionless parameter showing the degree of reinfiltration has been defined. Then, by using the proposed simulation method, the impact of different reservoir parameters has been examined. The investigated parameters are: porosity, permeability, matrix block dimensions, matrix and fracture compressibility, rock type and different type of reservoir's fluids. Finally, the grey relational analysis (GRA) was used to determine factors that have a significant influence on reinfiltration process. Results show that matrix block permeability-porosity factor has the highest impact on reinfiltration process.",4,5,0
Fracture,Natural Fractures,"Ghosh, Sayantan; Busetti, Seth; Slatt, Roger M.",Analysis and prediction of stimulated reservoir volumes through hydraulic fracturing: Examples from western Arkoma Basin,,,"Geologic models built from well logs and natural fracture (NF) parameters obtained at shale and carbonate outcrops/quarries were employed in understand artificial hydraulic fracture (HF) propagation and stimulated reservoir volume (SRV) geometries. We applied field HF treatment parameters from an Arkoma Basin well, located 20-25 miles (32-40 km) east of the studied quarries. We matched the microseismic cloud (MC) geometries of three field stages, followed by sensitivity analyses of various HF treatment and reservoir parameters. Geometry matches reveal that the average NF permeability in the Viola Group Limestone is nearly eight times that in the Woodford Shale. The sensitivity analyses (forward modeling) disclosed several likely outcomes. First, a minor (5x10(-6)) increase in the minimum horizontal tectonic strain and ensuing increase in the minimum horizontal stress resulted in a sizeable transformation of the SRV geometry. Second, pumping at a higher net pressure (ISIP increased from 6500 to 7000 psi) diminished the stimulation volume and opened more previously non-dilatable NFs closer to the wellbore. Higher net pressure also triggered more stimulation downward and out of the target zone in the studied area. Third, halving the number of NFs and doubling their final storage apertures significantly magnified the fracturing-fluid efficiency (i.e., lowered leak off into NFs) in areas where it was restricted from flowing through non-dilatable NFs. Additionally, this modification caused greater lateral growth and comparatively large downward (out of target zone) growth of the HF and NF reactivation front, lowering the effectiveness of the HF job. However, halving the number of NFs and doubling their final storage apertures did not result in a substantial change in the SRV geometry upon allowing fluid flow through non-dilatable NFs. Fourth, altering the well-landing depth within the Woodford Shale did not result in a major shift in the overall stimulation geometry or volume. Most importantly, the simulated hydraulic fractures emanating from the wellbore do not span the entire recorded microseismic cloud length and height.",4,4,1
Fracture,Natural Fractures,"Gong, Yiwen; El-Monier, Ilham",Microstructure diagnosis of the fractured tight sandstone using image analysis,Grain size; Image analysis; Tight sandstone; Statistical analysis,SIZE DISTRIBUTIONS; PROCESS ZONE; SIMULATION; BEHAVIOR; CHANNEL,"In the hydraulically failed rock, a process zone where the natural fractures and the intergranular rock grain boundaries are activated while induced transgranular fractures are formed. These fractures in all scales share the drainage with the main hydraulic fracture. The objective of this study is to develop a novel approach thereafter to diagnose the evolutions of the critical above said microstructure properties at the post-fracturing state. In the previous work, we have examined the remarkable capability of image analysis on hydraulic fracture roughness determination (Gong and El-Monier, 2018). As an extension, this work introduces a fast and precise approach to study the aforementioned features of the post-fracturing core sample, including crack density, rock grain, and pore size distributions, by coding the desired image processing and analysis program. The hydraulic fracturing test was carried out using a Tennessee sandstone core sample and a sub-core of this fractured rock is excavated and polished (Patel et al., 2017). Its cross-section was subdivided into sequences and captured by the high-resolution SEM images after the ion-milling process. The post-fracturing grain size and pore size are investigated in the orthogonal direction of the main fracture at various locations and are compared to those from the literatures. The results from this study indicate that our proposed image analysis approach is capable to detect the grain damages resulting from the rock crushing. In addition, a positive relationship between the two parameters is found regardless of the cementing, packing mechanism, damage condition, and sorting of the fractured rock.",4,4,2
Fracture,Natural Fractures,Xi Yan; Li Jun; Zha Chunqing; Guo Boyun; Liu Gonghui,A new investigation on casing shear deformation during multistage fracturing in shale gas wells based on microseism data and calliper surveys,Multistage fracturing; Shear deformation; Finite-element; Microseismic; Multi-finger callipe,PRESSURE; VOLUME,"Casing shear deformation has become a serious problem in the development of shale gas fields, which is believed to relate to fault slipping caused by multistage fracturing. This paper presents a new investigation aiming at understanding the reduction of casing inner diameter after fault slipping under different conditions, according to microseism data and calliper surveys. A mathematical model, which was verified by measurement results, was established to build a relationship between microseism moment magnitude and slip distance. A 3D numerical model, which was verified by physical model experiments, was developed to quantify the relationships between slip distance and the reduction of casing inner diameter. And then the relationships among microseism moment magnitude, slip distance and the reduction of casing inner diameter were established. The influence of casing internal pressure, slip distance, mechanical parameters of cement sheath, and casing thickness on the reduction of casing inner diameter was analyzed. The mathematical calculation results showed that with the increase of the degree of moment magnitude, the radius and slip distance increase, and with the increase of stress drop, the radius decreases and the slip distance increases. The numerical analysis results showed maintaining high pressure, increasing the elasticity modulus and decreasing the Passion ratio of cement sheath and increasing the casing thickness were beneficial to decrease the reduction of casing inner diameter. Keeping the designed horizontal segment of well trajectory away from the fracture-developed area, or be parallel to natural fracture can decrease the slip distance of fault, which can decrease the reduction of casing inner diameter. Finally, some effective measures to reduce or prevent casing shear deformation were recommended.",4,8,3
Fracture,Natural Fractures,"Wang, Shibin; Chen, Fuhu; Guo, Jianchun; Li, Yang; Zhao, Feng; Zhou, SiYan",Adsorption damage of hydroxypropyl guar gum to porous media composed of quartz,Guar gum; Adsorption; Quartz; Porous media; Hydrogen bond,NONIONIC SURFACTANT; NATURAL SURFACTANT; WATER; MECHANISM; SILICA; SAND,"Hydroxypropyl guar gum (HPG) is widely used in the hydraulic fracturing of sand rock gas reservoirs. The HPG residue can severely damage the rock surface of the reservoirs owing to the interaction between the HPG molecular chain and the rock surface, which results in adsorption and retention of HPG. To confirm the interaction between HPG and rock, the adsorption properties of HPG on a rock surface were investigated. The dependence of HPG adsorption on HPG concentration, pH, and temperature is discussed, and the adsorption force between HPG and quartz is also studied. With an increase in HPG concentration and pH, the amount of adsorbed HPG increases. The amount of adsorption increases first with temperature and then decreaseds. According to infrared spectroscopy and Zeta potential results, there is a weak chemical bond between HPG and quartz particles. Hydrogen bonding is the main force, which results in the adsorption and retention of HPG in porous media.",4,4,4
Fracture,Natural Fractures,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Fracture,Natural Fractures,"Benaafi, Mohammed; Hariri, Mustafa; Bertotti, Giovanni; Al-Shaibani, Abdulaziz; Abdullatif, Osman; Makkawi, Mohammad","Natural fracture system of the Cambro-Permian Wajid Group, Wadi Al-Dawasir, SW Saudi Arabia",Wajid group; Sandstone; Fracture system; Outcrop analogue; Saudi Arabia; Rub' Al-Khali basin,DEPOSITIONAL-ENVIRONMENTS; STRATIGRAPHIC ARCHITECTURE; OUTCROP ANALOG; LAYERED ROCKS; FLUID-FLOW; SANDSTONE; EVOLUTION; BASIN; DEFORMATION; LITHOFACIES,"This study investigates the regional and outcrop-scale fracture system within the Wajid Group exposures in Wadi Al-Dawasir, southwest Saudi Arabia. The Wajid Group is a Cambro-Permian siliciclastic succession that forms the main groundwater aquifers in the study area and is considered as a potential hydrocarbon reservoir in the Rub' Al-Khali Basin. The succession is composed of fluvial, marine, and glacial to glaciofluvial deposits. This study aims to characterize and model the fracture system within the Wajid Group in the Wadi Al-Dawasir area using satellite imagery and direct field measurements. A further study objective is to define the geological factors controlling the fracture distribution within the Wajid Group succession. Five sets of regional-scale fractures (lineaments) were defined: N000 degrees, N015 degrees, N035 degrees, N075 degrees, and N135 degrees. In addition, five sets of the outcrop-scale fractures were delineated: N015 degrees, N035 degrees, N075 degrees, N135 degrees, and N165 degrees. The N135 degrees- and N035 degrees-oriented fracture sets are predominant at the regional scale. At the outcrop scale, however, the N165 degrees- and N075 degrees-oriented fracture sets are predominant. The trace-length of the regional-scale fractures is distributed according to the negative exponential distribution. The fractures within the Wajid Group outcrops are vertical to sub-vertical extensional fractures (mode 1). Those fractures are open, however, and at some localities, they are sealed or coated with calcite or iron oxides. Fracture swarms with an orientation of N015 degrees were also observed in the southeastern part of the study area. Hierarchical outcrop conceptual models of two fracture sets are proposed. The proposed models show that the regional-scale fractures are not influenced by stratigraphic or lithological variations. In contrast, the outcrop-scale fractures are controlled by the stratigraphic, lithological, and diagenetic variations in the fracture-hosting sandstone. The diagenetic characteristics (cementation and dissolution), bed thickness, and porosity of the fracture-hosting sandstone play a key role in the fracture distribution within the Wajid succession. The results of this study contribute to the understanding of groundwater flow behaviour within fractured aquifers in the study area and will help to enhance gas production from fractured hydrocarbon reservoirs in the Rub' Al-Khali Basin.",5,5,0
Fracture,Natural Fractures,"Maity, Debotyam; Ciezobka, Jordan",Designing a robust proppant detection and classification workflow using machine learning for subsurface fractured rock samples post hydraulic fracturing operations,Artificial neural nets; Image processing; Classifier benchmarking; Unconventional reservoirs; Core sampling; Shale rock,NEURAL-NETWORK; ALGORITHM,"Hydraulic fracturing is a method of reservoir stimulation that enhances the effective permeability of tight unconventional reservoirs such as shale oil and gas. In typical hydraulic fracturing treatments, millions of gallons of water are pumped under pressure into rock formations deep below the earths surface. Proppant particles such as sand are injected as part of the fracturing slurry to hold the hydraulic fractures open, or propped, after high-pressure water injection has ceased. Propped hydraulic fractures provide a conduit for long-term hydrocarbon production, thus being essential to commercial oil and gas production from shale reservoirs. The distribution of the proppant particles can be useful in understanding effectiveness of hydraulic fracturing treatments. It can also help identify both, unstimulated and under-stimulated zones within the reservoirs of interest. These proppant particles can be found in drilling fluid return or in cores, which can be sampled from subsurface. In this study, we highlight the design and development of artificial neural network based workflow that helps identify where proppant particles are located and classifies proppant and various particles of interest. In this study, these particles are limited to naturally occurring calcite or other minerals from subsurface rocks. Various features of interest that help with the classification process have been conceptualized and defined. This method has been verified using controlled test cases and validated using actual samples from subsurface. The designed ANN classifier has also been benchmarked with other classification methods including k-nearest neighbor, naive-Bayes classifiers and Support vector machines. A workflow to process samples from subsurface and quantify proppant distribution for future test programs including potential real time applications has been proposed. Based on this workflow, we share proppant distribution from a Permian Basin case study. We have also compared proppant distribution using our proposed method with results from an independent workflow on a similar dataset, which does not utilize machine learning.",5,5,0
Fracture,Natural Fractures,"Janjuhah, Hammad Tariq; Alansari, Abubaker; Vintaned, Jose Antonio Gamez","Quantification of microporosity and its effect on permeability and acoustic velocity in Miocene carbonates, Central Luconia, offshore Sarawak, Malaysia",Central Luconia; Microporosity; Permeability; Acoustic velocity; Natural gas,DEPOSITIONAL-ENVIRONMENTS; RESERVOIR; CLASSIFICATION; POROSITY; PLATFORMS; MICRITE; HISTORY; BASIN; LOG,"Carbonate reservoirs are mostly considered to be complicated since in the petroleum industry, and because predicting the quality and achieving a high recovery factor from these rocks is challenging. Carbonate rocks have a complex porosity, which often leads to substantial uncertainty in prediction of permeability values for any particular porosity figure. The petrophysical analysis of carbonate reservoirs is and prone to more significant uncertainty. Pore size in carbonates rocks varies from micro to cave system scale. Carbonates with moldic and vuggy porosity usually contribute positively to the hydrocarbon production, yet sometimes these pores are mostly unconnected, thus yielding low flow rates, even though micropores form a high component of the total porosity of a reservoir. This study explores the reservoir properties of carbonate rocks of Central Luconia (Offshore Sarawak, eastern Malaysia), with emphasis on the relevance of microporosity on permeability and acoustic velocity relationships. A petrographic study of 260 samples obtained from the reservoir interval of Well A in the Central Luconia, Malaysia, was conducted to identify pore types (moldic, vuggy, interparticle, intraparticle and fractures) and measure porosity (ranging from 4 to 25%). For microporosity quantification, an enhanced workflow is introduced using the Digital Image Analysis (DIA) technique, where 32 petrographic images of each thin sections were taken under the transmitted light microscope that covers the entire thin section. The DIA technique was then implemented on these petrographic images to quantify the amount of macroporosity. After that, the microporosity was calculated in the following way: the difference in value between the observed macroporosity using DIA, and the total porosity measured on core plugs. Finally, the resulting amount of microporosity was then correlated with acoustic velocity and permeability to determine if significant improvement is achieved in the coefficient of determination (R-2). Moreover, it has increased from 0.55 to 0.67 for the permeability and from 0.61 to 0.87 for the acoustic velocity. The analysis also highlights that those samples with more substantial pores and a high figure ( > 50% of total porosity) of microporosity exhibit slower acoustic velocity for both P and S waves. Also, this study proposed a simple predictive model of elastic properties in the Central Luconian Miocene carbonate, Malaysia.",5,6,0
Fracture,Natural Fractures,"Singh, Harpreet; Dilmore, Robert M.",Stochastic prediction of fractured caprock by history matching pressure monitoring data,Fractures; Caprock; Shale; CO2 storage; Optimization,LEAKAGE DETECTION; RISK-ASSESSMENT; CO2 STORAGE; PERMEABILITY; RESERVOIRS; MODEL; MANAGEMENT; SYSTEMS; IMPACT; SCALE,"In this study, a novel method to stochastically characterize the effective permeability of a fractured caprock (typically fine-grained sedimentary rock or natural mudstones) is presented. The method requires pressure monitoring data from above and below the caprock, which are used in combination with other readily-available data from laboratory and outcrop observations in a history-matching process that maintains the distribution of underlying fracture attributes to characterize the spatial variation in permeability of the caprock. A ""best-fitting"" geological model of caprock, representing a most-likely scenario, is selected from an ensemble of stochastic realizations generated using optimized parameters. The method is demonstrated using a representative, moderately permeable, heterogeneous caprock, as a reference ""truth"" to compare accuracy of caprock predicted using pressures from injection and post-injection phases. The accuracy of ""best-fitting"" caprock is assessed by studying its sensitivity to four variables, which are caprock thickness, leakage intensity, time length of available pressure history, and injection rate. Improved characterization of effective caprock permeability allows more confident prediction of flux through the sealing interval, over time. That information is useful in quantifying potential impacts of fluid migration, evaluating monitoring designs, and designing mitigation alternatives, should they be needed. It has value both during active injection and in building confidence that a site can be safely closed after injection is complete.",5,5,0
Fracture,Natural Fractures,"He, Zhenhua; Duan, Benchun",Significance of the dynamic stress perturbations induced by hydraulic fracturing,Hydraulic fracturing; Dynamic modeling; Dynamic effects; Dynamic stress; Stability,RUPTURE; SLIP; VELOCITY,"Hydraulic fracturing and microseismicity generation and radiation are dynamic processes. The associated dynamic stress perturbations could play a significant role in relevant studies, such as activation of weak planes including natural fractures, bedding planes, etc. We study how different the dynamic and static stress perturbations could be during hydraulic fracturing. Our work is based on a 2D plane-strain framework. A dynamic finite element method is applied to solve the equations of motion. The static stress perturbations are obtained when the models reach static equilibrium (i.e., after generated seismic waves die out). We compare the static and dynamic stress perturbations at a moment when a hydraulic fracture (HF) propagates to a certain length. Mohr circle analysis shows that around the HF the Mohr circle based on a dynamic stress tensor is closer to a failure line than that based on a static stress tensor. The peak static and dynamic stress perturbations during the process are also compared. We conclude that the absolute values of the peak dynamic stress perturbations are always greater than that of the peak static stress perturbations, especially in the area close to the HF and its tips. The effect of injection rates on the static and dynamic stress perturbations is also studied. The largest peak static and dynamic stress perturbations during the hydraulic fracturing process are measured. The absolute values of both the largest peak dynamic and static stress perturbations increase with injection rates. The absolute values of the difference between the largest peak dynamic and static stress perturbations also increase with injection rates due to more significant dynamic effects.",5,7,1
Fracture,Natural Fractures,"Hu, Xiaohu; Yu, Wei; Liu, Malin; Wang, Mingwei; Wang, Weihong",A multiscale model for methane transport mechanisms in shale gas reservoirs,Semi-analytical model; Complex hydraulic fractures; Shale gas; Multiple horizontal wells; Nanopores,HYDRAULIC-FRACTURE GEOMETRY; HORIZONTAL WELLS; PRODUCTION SIMULATION; SEMIANALYTICAL MODEL; COMPREHENSIVE MODEL; COMPLEX FRACTURES; FLOW; NETWORKS; PERMEABILITY,"We presented an efficient semi-analytical model-based analysis of methane transport in shale reservoirs including multiple horizontal wells with nanopores and complex hydraulic fractures. Multiple important gas transport mechanisms in nanopores such as gas desorption, gas slippage and diffusion and pressure-dependent fracture conductivity are fully incorporated in the model. Both simple and complex fractures in multiple shale-gas wells can be easily and effectively dealt with in accordance with the discretization approach, which does not require detailed gridding like numerical model. The superposition principle is utilized to capture the interactions between all fracture segments in order to accurately simulate real gas transport from matrix to fractures and finally from fractures to wellbores. We verified the semi-analytical model against a numerical compositional reservoir model for two shale-gas wells with multiple simple planar hydraulic fractures considering the gas desorption effect. The semi-analytical model was used to analyze ultimate gas recovery of different complex hydraulic fracture patterns in a two-well scenario, which were generated from a complex fracture propagation model with and without considering natural fractures. In addition, it was applied to perform field-scale simulation with multiple wells and complex fracture geometries in accordance with microseismic data. The simulation results show that multiple gas transport mechanisms, pressure-dependent fracture conductivity and complex fracture geometries play an important role in controlling well productivity and gas recovery, which should be properly accounted for in the physical model in order to achieve more accurate long-term production forecasting of multiple-fractured shale-gas horizontal wells.",5,6,1
Fracture,Fracture Networks,"Prasun, Samir; Wojtanowicz, Andrew K.",Semi-analytical prediction of critical oil rate in naturally fractured reservoirs with water coning,Critical oil rate; Naturally fractured reservoirs; Semi-analytical; Water coning; Matrix well; Fracture well,FLUID-FLOW; PERMEABILITY; MODEL,"Naturally fractured reservoirs (NFRs) with bottom water are generally produced above their critical oil rate (maximum possible oil production rate without water breakthrough) that is difficult to determine as it varies between wells, depending on the well's location in the fracture network. In principle, wells can either be completed in matrix or fractures. Present formulas of critical-rate in NFR are oversimplified ignoring the network heterogeneity and anisotropy ratio of fractures, and they also do not consider the difference between on-fracture/off-fracture well completion placements. Presented is development of a new semi-analytical formula that considers these effects-with emphasis given to well placement assessment. The critical rate model is derived from mechanistic principles and then improved with statistical calibration. The mechanistic approach (Chaperon (1986)) considers vertical equilibrium of viscous and gravity forces for a hemispherical flow to a point-source well in a dual porosity/dual permeability model of naturally fractured reservoirs. The model considers the water cone instability, and anisotropy ratio of NFR only for a short-perforated completion interval. The model is tested for wide variety of NFRs for short completions. The model is then statistically calibrated to including the effect of long penetration ratio, using a designed matrix of simulated experiments covering wide ranges of NFR properties. This statistical approach allows the model to consider any change in flow regime from semi-spherical to non-radial distorted flow. The comparison of Chaperon's analytical model and NFR simulations shows that the model is good for NFRs for penetration ratio smaller than 0.35. For penetration ratio greater than 0.35, a new semi-analytical model of critical-rate for NFR is developed by statistically calibrating the Chaperon's analytical model. The new model considers the parameters ignored in the previous models of NFR. Finally, a new mechanistic derivation of critical rate for wells completed in matrix block of NFR is determined by analytically including the effect of well's distance to fracture in a critical rate formula for NFR. The model matches well with the simulated data when compared with it. The model shows that the wells accidently completed off-fractures may display higher values of critical rates and the difference relates to their distance to the nearest fractures. It is also shown that the offfracture well's formula reduces to the on-fracture well's formula when the distance is reduced to zero.",1,1,0
Fracture,Fracture Networks,"Zhang, Jiali; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Gao, Jian",A weak fluid supply model for transient pressure analysis in vertically fractured wells from tight gas reservoirs: A case study,Unconventional reservoirs; Weak fluid supply; Vertically fractured well; Pressure transient behaviors; Case study; Parameter estimation,SEMIANALYTICAL MODEL; HORIZONTAL WELLS; BEHAVIOR; NETWORKS,"An interesting phenomenon of weak fluid supply (WFS) has been observed in tight gas reservoirs from the Ordos Basin. To facilitate parameters evaluation and productivity estimations of those well, this paper presents a new WFS model for transient pressure analysis in vertically fractured wells from tight gas reservoirs. In the new model, a WFS pressure and a WFS index are first introduced to describe the weak fluid supply boundary. Based on that, a mathematical model is developed with considering WFS, finite-conductivity fractures, and stress-sensitive effect. Using perturbation transformation method and semianalytical method, the proposed mathematical model is solved with effects of wellbore storage and skin factor. Following that, the model verification, sensitivity study, and field application are performed. Results shows that the WFS causes a rapid drop after ""hump"" at the late stage in the pressure curves. The start time of ""hump"" decreases as the WFS index increases. When the WFS pressure is bigger than zero, the pressure derivative curves exhibit a significant ""hump"", and it is more obvious with the increase in the WFS pressure. When the WFS pressure is equal to zero, the pressure derivative curves directly drop, which is assemble to the effect of constant pressure boundary. When the WFS index is zero, the pressure derivative curve in the late period is a unit-slope line, demonstrating a closed boundary effect. The field application in the well Z1 from the Ordos Basin shows that a ""hump"" caused by WFS does appears at the late stage in the pressure curves. By using the WFS model, the estimated reservoir permeability and drainage radius are 0.524 mD and 451.68 m. The WFS pressure and WFS index are respectively estimated as 0.13 and 0.022 by the WFS model. It demonstrates the applicability of the new proposed WFS model, which also provides a good understanding of transient pressure behaviors and accurate estimation of reservoir parameters for fractured wells with WFS.",1,1,1
Fracture,Fracture Networks,"Venkatesh, Prashanth Bangalore D.; D'Entremont, James H.; Meyer, Scott E.; Bane, Sally P. M.; Grubelich, Mark C.; King, Dennis K.",Bipropellant high energy stimulation for oil and gas applications,Energetics; Propellant; Fracturing; Fracture networks; DDT; Detonations,PRODUCTIVITY,"Large-scale extraction of oil and natural gas requires an effective method of generating a high surface area network of fractures, or the stimulation of existing fractures, in a formation in order to increase permeability. Conventional hydraulic fracturing has limited utility in this application. In this work, Sandia National Laboratories is exploring high rate pressurization techniques employing tailored energetic materials systems to control both pressure rise rate and peak pressure in order to optimally stimulate potential rock formations. Rapid pressurization, at rates far exceeding quasi-static conventional hydraulic rates, can generate multiple radial well bore fractures and potentially provide a mechanism to induce shear destabilization within the formation that enables the fractures to be self-propping. Multiple fractures from the well bore allow efficient coupling to the existing formation fracture network and increase near field well bore permeability. Furthermore, these techniques can allow for repeated stimulations and produce energetic events within the fractures thereby allowing fractures to be extended further. Controlled rate pressurization is a useful tool for the efficient generation of fracture networks and has potential application to increase oil and gas production. This paper provides an overview of the concept of controlled rate pressurization, laboratory experiments and field trials that are being conducted. The present work investigates detonations of a stoichiometric mixture of ethylene and nitrous oxide (C2H4 + 6N(2)O) at high initial pressures ranging from 0.862 to 2.068 MPa as a method of fracturing rock below the ground surface. The experiments investigate the fracture generation as a function of the initial pressure of the mixture. In the current configuration, the combustion reaction is initiated by an electrically fired igniter at the ground surface and quickly transitions to a detonation. The experimental setup accommodates one high pressure (690 MPa) transducer, placed downstream of the igniter, to measure peak pressure. The pressure transducer recorded peak pressures, which are 2.3-2.6 times in excess of the Chapman-Jouguet (CJ) values as a result of pre-compression of the unburned gas mixture during the flame acceleration prior to deflagration-to-detonation transition (DDT). Analysis of the data indicated an increase in rock permeability due to detonations and this was confirmed by the core drilled sections at the test site.",2,2,1
Fracture,Fracture Networks,"Liu, Zhiyuan; Peng, Shujun; Zhao, Haiyang; Geng, Yudi; Zhang, Zhennan",Numerical simulation of pulsed fracture in reservoir by using discretized virtual internal bond,Pulsed fracture; Fracture network; Field size; Reservoir stimulation; Numerical simulation; Discretized virtual internal bond,DYNAMIC FRACTURE; FLUID RHEOLOGY; DRIVEN; MODEL; HYPERELASTICITY,"Driven by the pulse pressure, fractures can branch and form a complex network, which is mostly desired in the reservoir stimulation. Thus, the pulsed fracture(PF) should be an inspiring potential technique to improve the reservoir. To explore the regulations of the pulsed fracturing process in field size, the PF is simulated by using the discretized virtual internal bond method. The normal triangular and the in-situ measured pulse are respectively taken as the pressure input in the numerical simulation. It is found that in the high in-situ stress contrast condition, the simple fracture symmetrically initiates on the wellbore wall and then propagates along the major in-situ stress direction. After the fracture advances a certain distance from the wellbore, it suddenly branches in the radial pattern, which forms a complex network. The distance of the fracture network to the wellbore is determined by the difference of the two principal in-situ stresses. The smaller the stress difference is, the closer the fracture network is to the wellbore. On the post-peak stage of pulse, the fracture network still grows self-similarly, but the growing velocity decreases with increasing the unloading rate. When the loading time is fixed, the peak pressure has significant impact on the fracture network profile. The higher peak pressure can generate a larger and more complex fracture network. It is observed that many branched fractures oblique stretch towards the minor in-situ stress direction, which is very helpful for the PF connect to the reservoir in that direction. In addition, the fracture network is generated at a certain distance to the wellbore in the larger in-situ stress difference cases, which is in favor of the wellbore stability. Besides these qualitative regulations, some quantitative conclusions are drawn in this paper. These provide valuable references for the assessment of the PF stimulation in reservoir.",2,2,1
Fracture,Fracture Networks,"Vega, Bolivia; Kovscek, Anthony R.",A systematic study of internal gas generation in shale source rocks using analog experiments,Rock analog; Gelatin; Fracture; Shale; Source rock; Rock maturation,PRIMARY MIGRATION; GELATIN; PROPAGATION; OIL; MICROFRACTURES; VISUALIZATION; RHEOLOGY,"A two-dimensional Hele-Shaw cell was created to study and visualize hydrocarbon source rock (i.e., shale) elastic-brittle fracture and fracture network propagation mechanisms triggered by internal gas generation and gas build up during maturation of organic components. An analog immature source rock was created using a mixture of gelatin, sugar, and live yeast in pre-determined proportions. This mixture was poured into the Hele-Shaw cell and allowed to gel. The internal gas generated as a result of sugar fermentation by yeast caused pressure build up within the gel that ultimately resulted in the activation of dissipation mechanisms such as gas diffusion and deformation of the gel matrix. These mechanisms are analogous to shale maturation and fluid generation. Image analysis was employed to study and characterize key events such as fracture nucleation, propagation, and coalescence versus time. Derivative parameters such as fracture growth rate, fracture tip pressure, and fracture spatial distribution, among others, were calculated using the image-sourced data and applying Linear Elastic Fracture Mechanics (LEFM) principles. Results showed that the experiments are repeatable within a consistent response range and additional parameters were identified to be useful input for numerical modelling, including nucleation sites, fracture merging angle, merging to nucleation ratio, and fracture connectivity. For a volume of about 100 cm(3) of 11.6% wt food-grade gelatin solution with 0.25% wt. yeast and a sugar/yeast ratio of 3, measured average total gas production was 35 cm(3) (at standard conditions). On an average gelatin matrix area of 400 cm(2), the average total fracture length and fracture density are 106 cm and 0.15 fractures/cm(2), respectively. Average maximum calculated fracture tip pressure and maximum fracture velocity are 0.92 psi and 5.85 x 10(-4)cm/s, respectively. Fracture connectivity was more frequent in the second half of the gas generation process and greater for the older and longer fractures. Average final fracture spacing was 4.42 cm. Connection angles between fractures tended to be closer to 0 degrees than to 90 degrees. Photoelasticity imaging techniques were applied to the experimental setup to visualize the stress field within the sample. The difference of principal stresses was estimated at 3.70 x 10(3) Pa for the tested material late in the maturation process. Results suggest interdependence of gas pressure, gas diffusion, and transient stress field states. The range of laboratory-scaled data are useful as benchmarking parameters for numerical modelling of source rock maturation including geomechanics.",2,2,2
Fracture,Fracture Networks,"Li, Zhenglan; Duan, Yonggang; Wei, Mingqiang; Peng, Yu; Chen, Qingxuan",Pressure performance of interlaced fracture networks in shale gas reservoirs with consideration of induced fractures,Interlaced fracture networks; Shale gas; Secondary induced fractures; Flux distribution; Pressure performance,HORIZONTAL WELLS; SEMIANALYTICAL MODEL; TRANSIENT PRESSURE; METHANE; FLOW; PERMEABILITY; MECHANISMS; ADSORPTION; BEHAVIOR,"Multi-stage fracturing in shale gas reservoirs may create complex fracture network around horizontal wellbore, due to the widely-distributed natural fractures. However, little work has been done to investigate the effects of secondary fractures on well testing models for shale gas reservoirs. In this paper, a more comprehensive model was developed for interlaced fracture networks in shale gas reservoirs with consideration of multiple transport mechanisms and different flow states. By employing the source function and Laplace transformation, the line sink solutions for four kinds of flow states were unified. Based on the discretization method and unified line sink solution, the pressure responses for interlaced fracture networks with infinite conductivity were obtained. Type curves were plotted and typical flow regimes of this model were identified. In order to have a further understanding of the effect of induced fractures, the slope curves of pseudo-pressure derivative were introduced to analyze the interference between fractures. The influences of the angel and the length of induced fractures on the well testing curves were simulated by the semi-analytical model for the first time. Then, the flux distributions of interlaced fracture networks were simulated and discussed for achieving significant advice. Finally, the proposed model was verified by a simplified case and a field case. The presented model will be helpful for understanding the transient performance of multi-stage fractured horizontal wells with consideration of induced fractures.",3,3,0
Fracture,Fracture Networks,"da Silva Ribeiro, Vanessa de Jesus; de Moraes Oliveira, Gabrielle Fontella; Cristian, Muara; Martins, Andre Leibsohn; Fernandes, Lindoval Domiciano; Vega, Marcia Peixoto",Neural network based controllers for the oil well drilling process,Downhole pressure; Control; Artificial intelligence; Pipe connection; Kick; Lost circulation,CONTROL SCHEME; KICK DETECTION; PRESSURE; PREDICTION; PARAMETERS; SIMULATION; MODELS; TIME,"The oil well drilling is a complex process, requiring that the bottomhole pressure be maintained within an operational window, limited by fracture pressure and pore pressure (and/or wellbore collapse). During the drilling process, there are several phenomena that directly influence the annulus bottomhole pressure: kick, lost circulation, inefficient removal of solids, well length increase, reservoir parameters and pipe connection procedure (surge and swab effects). The main objective of this work is to develop neural network controllers able to regulate the annulus bottomhole pressure under pipe connection procedure, kick and lost circulation disturbances. For this purpose, an experimental drilling unit was built, depicting the oil well drilling process primordial characteristics. Besides, real oil well offshore data were employed for validating the neural network controllers. Neural networks were built for predicting the direct plant dynamics (inverse neural network controller) and the inverse plant dynamics (direct neural network controller). It is noteworthy to mention that direct plant dynamics neural modelling was employed as the nonlinear model of a gain scheduling control approach; in addition, the inverse plant dynamics neural modelling constituted a nonlinear controller, directly predicting the manipulated variable. Both controllers employed real-time neural network training, being, therefore, adaptive schemes for regulating the oil well drilling process, which nature is inherently transient.",3,3,0
Fracture,Fracture Networks,"Mokhtari, Mehdi; Nath, Fatick; Hayatdavoudi, Asadollah; Nizamutdinov, Rustam; Jiang, Shuxian; Rizvi, Hashim",Complex deformation of naturally fractured rocks,Strain; Optical technique; Digital image correlation; Natural fracture; Complex fracture,DIGITAL-IMAGE-CORRELATION; SHEAR DEFORMATION; GROWTH; IDENTIFICATION; VISUALIZATION; EVOLUTION; FAILURE; SHALE,"Strain is a key parameter in the evaluation of rock mechanical properties and failure behavior. Strain is usually measured using strain gauges, however, this laboratory method has inherent uncertainty in the attachment of sensitive gauges to the rock surface and it is limited to one-point strain measurement. In complex geometries such as rock samples with natural fractures or lamination, that classical approach cannot provide the whole picture of strain development in such complex geometries. To overcome these challenges, the application of optical technique with image processing is proposed. The optical technique has the advantage of being a non-contact method and it provides quantitative visualization of full-field strain measurement. To examine quantitative visualization of strain development, DIC technique was first conducted on a homogeneous sandstone sample as a benchmark. The results verify that the maximum tensile strain is developed at the central vertical line of the sample as it was expected from theoretical solutions. This DIC measurement matches the post-failure fracture pattern of the specimen. Then the technique was applied on the Buda Limestone samples with horizontal, sub-horizontal or multiple complex natural fractures (sealed or partially open) and inclusions while the samples were under diametrical compression experiment. The results of this study provide further insight into the role of natural fractures on induced fracture initiation and propagation under this specific testing condition. Horizontal natural fractures are planes of maximum compressive strain which can delay the propagation of vertical tensile fractures. The maximum amount of tensile strain usually initiates at the boundary of these natural fractures and vertical tensile fractures usually deviate toward horizontal fracture for a short distance before turning back to propagate vertically following the maximum stress path. Full-field surface deformations are mapped optically in the crack-inclusion vicinity where DIC results showed that crack front is arrested by the inclusion for the complete fracture event. In contrast to the failure pattern in homogenous sandstone specimen, complex fracture pattern was observed on several specimens with multiple fracture network. Fracture slippages along the natural fracture, fracture deviation was observed in samples with steep inclined natural fractures. The results of this study can help us to better understand the complex failure mechanism in naturally fractured media and elaborate on various mechanisms of failure under diametrical compression tests. DIC is a powerful technique in providing the dynamic strain development over the surface of the sample in real-time, thus it can provide the fracture initiation and propagation in such heterogeneous rock media.",3,3,1
Fracture,Fracture Networks,"Ishibashi, Takuya; Watanabe, Noriaki; Tamagawa, Tetsuya; Tsuchiya, Noriyoshi",Three-dimensional channeling flow within subsurface rock fracture networks suggested via fluid flow analysis in the yufutsu fractured oil/gas reservoir,Discrete fracture network (DFN); 3-D channeling flow; Aperture distribution; Critically-stressed fracture; 3-D seismic data; The yufutsu oil/gas field,PERMEABILITY; APERTURE; JOINTS; MEDIA,"The present study explores the fluid flows within the fractured reservoir of the Yufutsu field (Hokkaido, Japan) by using the innovative discrete fracture network models (DFN-HA model), where the critically-stressed fractures are characterized by their heterogeneous aperture distributions depending on their length and shear displacement. Simulation results suggest that the three-dimensional preferential flow paths are originally formed within the fractured reservoir (i.e., 3-D channeling flow), that is exclusively influenced by both connectivity of critically-stressed fractures and pore space connectivity within them. Additionally, the huge difference in oil/gas production between two neighboring wells (approximately 3 orders of magnitude), that is observed in the Yufutsu field, can be reproduced only by the DFN-HA models. The present study suggests that 3-D channeling flow is necessary to be considered carefully in region where the connectivity of critically-stressed fractures is extremely limited. Although it is convenient to model the fractures by pairs of parallel plates with representative aperture values in analyzing fluid flow within fracture networks, such analyses potentially lead to the wrong scenarios for developing the fractured reservoirs because 3-D channeling flow within the reservoirs is never considered (e.g., potentially overestimate the volume containing flowing fluid by more than 25%). Thus, the present study concludes that the fluid flow within fractured reservoirs should be analyzed by DFN-HA model. By continuing such approaches, we will be close to the true images and the new insights into the fluid migration within the fractured systems in Earth's upper crust.",4,4,3
Fracture,Fracture Networks,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Fracture,Fracture Networks,"Maity, Debotyam; Ciezobka, Jordan",Designing a robust proppant detection and classification workflow using machine learning for subsurface fractured rock samples post hydraulic fracturing operations,Artificial neural nets; Image processing; Classifier benchmarking; Unconventional reservoirs; Core sampling; Shale rock,NEURAL-NETWORK; ALGORITHM,"Hydraulic fracturing is a method of reservoir stimulation that enhances the effective permeability of tight unconventional reservoirs such as shale oil and gas. In typical hydraulic fracturing treatments, millions of gallons of water are pumped under pressure into rock formations deep below the earths surface. Proppant particles such as sand are injected as part of the fracturing slurry to hold the hydraulic fractures open, or propped, after high-pressure water injection has ceased. Propped hydraulic fractures provide a conduit for long-term hydrocarbon production, thus being essential to commercial oil and gas production from shale reservoirs. The distribution of the proppant particles can be useful in understanding effectiveness of hydraulic fracturing treatments. It can also help identify both, unstimulated and under-stimulated zones within the reservoirs of interest. These proppant particles can be found in drilling fluid return or in cores, which can be sampled from subsurface. In this study, we highlight the design and development of artificial neural network based workflow that helps identify where proppant particles are located and classifies proppant and various particles of interest. In this study, these particles are limited to naturally occurring calcite or other minerals from subsurface rocks. Various features of interest that help with the classification process have been conceptualized and defined. This method has been verified using controlled test cases and validated using actual samples from subsurface. The designed ANN classifier has also been benchmarked with other classification methods including k-nearest neighbor, naive-Bayes classifiers and Support vector machines. A workflow to process samples from subsurface and quantify proppant distribution for future test programs including potential real time applications has been proposed. Based on this workflow, we share proppant distribution from a Permian Basin case study. We have also compared proppant distribution using our proposed method with results from an independent workflow on a similar dataset, which does not utilize machine learning.",5,5,0
Fracture,Fracture Networks,"Hu, Xiaohu; Yu, Wei; Liu, Malin; Wang, Mingwei; Wang, Weihong",A multiscale model for methane transport mechanisms in shale gas reservoirs,Semi-analytical model; Complex hydraulic fractures; Shale gas; Multiple horizontal wells; Nanopores,HYDRAULIC-FRACTURE GEOMETRY; HORIZONTAL WELLS; PRODUCTION SIMULATION; SEMIANALYTICAL MODEL; COMPREHENSIVE MODEL; COMPLEX FRACTURES; FLOW; NETWORKS; PERMEABILITY,"We presented an efficient semi-analytical model-based analysis of methane transport in shale reservoirs including multiple horizontal wells with nanopores and complex hydraulic fractures. Multiple important gas transport mechanisms in nanopores such as gas desorption, gas slippage and diffusion and pressure-dependent fracture conductivity are fully incorporated in the model. Both simple and complex fractures in multiple shale-gas wells can be easily and effectively dealt with in accordance with the discretization approach, which does not require detailed gridding like numerical model. The superposition principle is utilized to capture the interactions between all fracture segments in order to accurately simulate real gas transport from matrix to fractures and finally from fractures to wellbores. We verified the semi-analytical model against a numerical compositional reservoir model for two shale-gas wells with multiple simple planar hydraulic fractures considering the gas desorption effect. The semi-analytical model was used to analyze ultimate gas recovery of different complex hydraulic fracture patterns in a two-well scenario, which were generated from a complex fracture propagation model with and without considering natural fractures. In addition, it was applied to perform field-scale simulation with multiple wells and complex fracture geometries in accordance with microseismic data. The simulation results show that multiple gas transport mechanisms, pressure-dependent fracture conductivity and complex fracture geometries play an important role in controlling well productivity and gas recovery, which should be properly accounted for in the physical model in order to achieve more accurate long-term production forecasting of multiple-fractured shale-gas horizontal wells.",5,6,1
Fracture,Carbonate Reservoirs,"Maschio, Celio; Schiozer, Denis Jose",A new parameterization method for data assimilation and uncertainty assessment for complex carbonate reservoir models based on cumulative distribution function,Reservoir simulation; History matching; Data assimilation and uncertainty assessment; Cumulative distribution function; Complex geological systems; Super-K,PRINCIPAL-COMPONENT ANALYSIS; DIFFERENTIABLE PARAMETERIZATION; OPTIMIZATION; ZONES,"Data assimilation (also known as history matching) and uncertainty assessment is the process of conditioning reservoir models to dynamic data to improve its production forecast capacity. One of the main challenges of the process is the representation and updating of spatial properties in a geologically consistent way. The process is even more challenging for complex geological systems such as highly channeling reservoirs, fractured systems and super-K layered reservoirs. Therefore, mainly for highly heterogeneous reservoirs, a proper parameterization scheme is crucial to ensure an effective and consistent process. This paper presents a new approach based on cumulative distribution function (CDF) for parameterization of complex geological models focused on layered reservoir with the presence of high permeability zones (super-K). The main innovative aspect of this work is focused on a new sampling procedure based on a cut-off frequency. The proposed method is simple to implement and, at the same time, very robust. It is able to properly represent super-K distribution along the reservoir during the data assimilation process, obtaining good data matches and reducing the uncertainty in the production forecast. The new method, which preserves the prior characteristics of the model, was tested in a complex carbonate reservoir model (UNISIM-II-H benchmark case) built based on a combination of Brazilian Pre-salt characteristics and Ghawar field information available in the literature. Promising results, which indicate the robustness of the method, are shown.",1,1,0
Fracture,Carbonate Reservoirs,"Salimidelshad, Yaser; Moradzadeh, Ali; Kazemzadeh, Ezatallah; Pourafshary, Peyman; Majdi, Abbas",Effect of hysteresis on petrophysical properties of limestone hydrocarbon reservoir rock,Hysteresis; Petrophysical properties; SEM; CT scan; Pore size distribution,PERMEABILITY; DEFORMATION; MECHANISM; POROSITY,"The petrophysical properties of carbonate reservoirs may change when they are subjected to mechanical loadings due to the softness of the formation. As the reservoir fluid pressure declines due to production, the net load on the rock increases, which leads to compaction of the rock and decrease in its pore volume, causing blocking of pore throats and the permeability reduction. In this study, we experimentally investigated the hysteresis effect of petrophysical properties of two carbonate core samples during the loading using CMS-300 apparatus. The structure of samples was processed by CT scan images and analysis of the pore size distribution was also conducted using mercury injection testing followed by scanning electron microcopy (SEM). Our results indicate that isotropic long-term and short-term loading considerably change the grain structure, while the petrophysical properties do not have a clear effect. The porosity induced by the cyclic loading was affected by intergranular micro-extension fractures. The results also indicate that the greatest reduction of porosity in fractured limestone occurred at the first loading step; however, further reduction was strongly due to the consolidation and adherence of the grain matrix. This fluctuating trend was also observed for the permeability, with a severe reduction in the permeability when crushed grains were placed in the connected pore path. The measured porosity and permeability of carbonated rocks, as stress-sensitive parameters, along analysis of the micro-fracture effects during loading and unloading, can be considered in production and injection management of reservoirs. They are also useful for predicting of any possible risks during different periods of reservoir life and determining the optimum production pressure of the reservoir.",1,1,1
Fracture,Carbonate Reservoirs,"Youssef, AbdAllah A.",Inflow performance relationship of vertical wells in fractured vuggy media during semi-steady state flow regime,IPR; Error parameter and fractured-vuggy reservoirs,HORIZONTAL WELL; PERMEABILITY; BEHAVIOR; POROSITY; MODEL,"The inflow performance relationship (IPR) is one of the essential key parameters that control the fluids production/injection rate from wells. The presence of the vugs in addition to fractures in carbonate reservoirs introduce many difficulties related the estimation of IPR of future wells. In this study, a novel analytical IPR of dual-permeability, triple porosity model is derived for the first time. The introduced IPR formula is derived for the standard scenario model of a vertical and fully penetrating well in a circular reservoir under single-phase flow of slightly compressible fluid. The three governing flow equations (matrix flow equation, fracture flow equation and interaction between vugs and other two continuum equation) are solved simultaneously as a system of differential equations for semi-steady state (SSS) flow regime. The generated SSS IPR is the same as Darcy's straight line IPR multiplied by an error parameter (E-23) which is bounded between zero and one. A detailed investigation of the effect of the reservoir petro-physical parameters like storativities, inter-porosities and fracture to matrix permeability ratio are presented. The newly presented IPR of dual-permeability, triple porosity system can be reduced to sub-models IPRs by further modification of error parameter to fit sub-model as single permeability, triple porosity (E-13) or dual permeability, dual porosity (E-22). The presented IPR formula has the advantage of dividing the pressure drop of the fluid flow to two components, one for the internal resistance between different continuums (which is resented by E) and the other one is the radial flow in the same continuum toward/from well-bore. The generated IPR model is double verified using both cell pressure centred finite volume numerical simulation and conventional pressure transient analysis.",2,2,0
Fracture,Carbonate Reservoirs,"Chu, Hongyang; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Liu, Wenyuan",Estimating carbon geosequestration capacity in shales based on multiple fractured horizontal well: A case study,Multiple fractured horizontal well; CO2 geosequestration; Shale reservoirs; Semi-analytical method; Transient pressure response,TRANSIENT PRESSURE BEHAVIOR; ENHANCED GAS RECOVERY; STORAGE CAPACITY; CO2 STORAGE; NUMERICAL-SIMULATION; SEQUESTRATION; RESERVOIR; MODEL; FEASIBILITY; ADSORPTION,"Nowadays, shale reservoirs have been though as good candidates for CO2 geosequestration for reduction of carbon emission. When estimating the carbon geosequestration capacity, multiple fractured horizontal well (MFHW) is a prerequisite for consideration when shale reservoirs are included in candidate geological sites, as it is one of the critical factors for the successful development of shale reservoirs. In order to perfect our previous works, a new model is proposed to calculate the carbon geosequestration capacity of depleted shale reservoirs based on MFHW. The methodology calculates carbon geosequestration capacity of shale reservoirs by considering Knudsen diffusion, molecular diffusion, supercritical Langmuir adsorption, stimulated reservoir volume (SRV), and stress-sensitivity of the permeability. Utilizing the perturbation transformation technique, finite difference method, and Laplace transform technique, our method is more in accordance with the actual situations, allowing us to accurately estimate the carbon storage capacity by capturing the transient pressure response of the MFHW. A field case from the Ordos Basin in China presents that the CO2 geosequestration capacity is proportional to the dimensionless fracture half-length and conductivity. The properties of hydraulic fractures only affect the early period of the CO2 geosequestration process. For the adsorption coefficient and flow coefficient ratio, with the change of these parameters, the middle and late periods of the CO2 geosequestration process are mainly influenced.",2,2,4
Fracture,Carbonate Reservoirs,"Liu, Chao; Gu, Liang; Wang, Jian; Si, Shanghua","Reservoir characteristics and forming controls of intrusive-metamorphic reservoir complex: A case study on the diabase-metamudstone rocks in the Gaoyou sag, eastern China",Metamudstone reservoirs; Diabase intrusion; Funing formation; Reservoir complex,BASIN; ACCUMULATIONS; CARBONATES; QUALITY,"Hydrocarbon reservoirs associated with magmatic intrusion have significance in expanding hydrocarbon exploration. However, this type of reservoir is rarely documented in previous studies. Taking the diabases and their contact metamudstones from the Funing Formation, northern slope of the Gaoyou sag, as study objectives, the current work mainly investigated lithofacies, reservoir porosities and properties, and C, O isotopes of intrusive diabases and/or contact metamudstones, aiming to unravel reservoir characteristics and forming controls of diabase and metamudstones. After diabase intrusion, four lithofacies, i.e., diabase center, diabase margins, slates, and hornfels, were formed. Meanwhile, various porosity types were developed, including primary vesicles, grain-dissolved micropores, contractive micropores, cooling fractures, and structural fractures in the diabases, and recrystallizational and matrix-dissolved micropores, hydrothermal and contractive microfractures, and structural fractures in the contact metamudstones. Controls on diabase reservoir development include uneven cooling, dissolution, authigenic minerals filling, and structural movements. For contact metamudstone reservoirs, the forming controls include physical fracturing, hydrothermal baking, and authigenic carbonate dissolution. The controlling factors exerted diverse influences on reservoir properties with respect to different parts in contact metamudstones or diabase, thus causing obvious heterogeneity regarding to reservoir quality, i.e., hornfelses and diabase margins exhibiting preferable reservoir properties than slates and diabase center, respectively. Finally, an evolutional model depicting the forming process of diabase-metamudstone reservoir complex was tentatively proposed.",3,3,0
Fracture,Carbonate Reservoirs,"Fernandez-Ibanez, Fermin; DeGraff, James M.; Moore, Paul J.; Ahdyar, LaOde; Nolting, Andrea",Characterization of non-matrix type and flow potential using lost circulation information,Non-matrix; Karst; Natural fractures; Lost circulation; Drilling; Carbonate reservoir characterization,FIELD,"Lost circulation zones (LCZs) provide valuable information about the properties of non-matrix features - i.e., fractures and karst - intersected by wells during conventional drilling, including information about the type, size, connectivity and flow potential. The magnitude of the loss rate and lost volume should reflect the nature of the non-matrix feature responsible for losses. For example, the total volume lost in each of these zones provides a minimum volume of connected pore space, whereas the instantaneous rate of loss suggests whether the LCZ is due to drilling into a cave (high rate of loss) versus a fracture (low rate of loss). We define and quantify each LCZ from information recorded in the drilling reports including top and base of the LCZ, maximum loss rate, and cumulative volume lost to the zone. Once each LCZ has been identified from the drilling reports, we evaluate wellbore images and caliper logs across each anomalous zone to determine the cause of the loss event - e.g., caves or fractures. Results suggest that caves are typically characterized by high lost rates (> 50 m(3)/h or 315 bbl/h), while fractures and touching vugs are characterized by lower rates (< 50 m(3)/h or 315 bbl/h). Low rates and volumes in excess of 160 m(3) (1006 bbl) appear to be related to fractures, while volumes below this threshold can be attributed to either fractures or touching vugs. This natural breakout between karst and fractures in particular, allows us to work in data challenged environments and use drilling data as a screening tool to evaluate whether the main non-matrix flow elements are fracture or karst dominated. A key product of this work is a volume versus rate (VvR) plot that typifies loss characteristics for specific non-matrix features, so that in the absence of image logs, it can be used to infer the causes of each LCZ event.",3,3,0
Fracture,Carbonate Reservoirs,"Han, Guofeng; Liu, Yuewu; Sun, Liang; Liu, Min; Gao, Dapeng; Li, Qi",Determination of pore compressibility and geological reserves using a new form of the flowing material balance method,Flowing material balance method; Pore compressibility; Geological reserve; Material balance equation,VOLUME COMPRESSIBILITY; FEEDBACK-CONTROL; POROUS ROCKS; PERMEABILITY; MODEL; CARBONATES; PRESSURE; STRESS,"Pore compressibility is an important parameter in reservoir engineering. However, its variation from laboratory core analysis or logging data can be large. Moreover, laboratory core analysis cannot identify the influence of macroscopic fractures on pore compressibility. The geological reserves obtained with the commonly used flowing material balance (FMB) method are significantly impacted by the accuracy of the pore compressibility. Therefore, a new form of the FMB method is proposed in this study which can determine the pore compressibility and geological reserves at the same time. For gas wells, the new method uses the material balance equation and the FMB equation including the pore compressibility. For oil wells, new forms of the material balance equation and the FMB equation were established which have the same form as the corresponding equations for gas wells. A new linear expression of the material balance equation is employed for the analysis. Simulation results indicate that the new method can provide more precise predictions of both the pore compressibility and the geological reserves. Furthermore, the new method also considers the influence of formation fractures because it uses well production data. Sensitivity analysis indicates that the error in the pore compressibility has a significant influence on the determination of the geological reserves.",4,4,1
Fracture,Carbonate Reservoirs,"Ghosh, Sayantan; Busetti, Seth; Slatt, Roger M.",Analysis and prediction of stimulated reservoir volumes through hydraulic fracturing: Examples from western Arkoma Basin,,,"Geologic models built from well logs and natural fracture (NF) parameters obtained at shale and carbonate outcrops/quarries were employed in understand artificial hydraulic fracture (HF) propagation and stimulated reservoir volume (SRV) geometries. We applied field HF treatment parameters from an Arkoma Basin well, located 20-25 miles (32-40 km) east of the studied quarries. We matched the microseismic cloud (MC) geometries of three field stages, followed by sensitivity analyses of various HF treatment and reservoir parameters. Geometry matches reveal that the average NF permeability in the Viola Group Limestone is nearly eight times that in the Woodford Shale. The sensitivity analyses (forward modeling) disclosed several likely outcomes. First, a minor (5x10(-6)) increase in the minimum horizontal tectonic strain and ensuing increase in the minimum horizontal stress resulted in a sizeable transformation of the SRV geometry. Second, pumping at a higher net pressure (ISIP increased from 6500 to 7000 psi) diminished the stimulation volume and opened more previously non-dilatable NFs closer to the wellbore. Higher net pressure also triggered more stimulation downward and out of the target zone in the studied area. Third, halving the number of NFs and doubling their final storage apertures significantly magnified the fracturing-fluid efficiency (i.e., lowered leak off into NFs) in areas where it was restricted from flowing through non-dilatable NFs. Additionally, this modification caused greater lateral growth and comparatively large downward (out of target zone) growth of the HF and NF reactivation front, lowering the effectiveness of the HF job. However, halving the number of NFs and doubling their final storage apertures did not result in a substantial change in the SRV geometry upon allowing fluid flow through non-dilatable NFs. Fourth, altering the well-landing depth within the Woodford Shale did not result in a major shift in the overall stimulation geometry or volume. Most importantly, the simulated hydraulic fractures emanating from the wellbore do not span the entire recorded microseismic cloud length and height.",4,4,1
Fracture,Carbonate Reservoirs,"Behnoudfar, Pouria; Asadi, Mohammad Bagher; Gholilou, Alireza; Zendehboudi, Sohrab",A new model to conduct hydraulic fracture design in coalbed methane reservoirs by incorporating stress variations,CO2 injection; Hydraulic fracture; Stress variations; Boundary element method; Latrobe Valley coalbed,CARBON-DIOXIDE; CO2; PRESSURE; CAPTURE,"Coalbed reservoirs are considered as suitable media for injection operations, especially for geological sequestration of carbon dioxide (CO2). This type of reservoirs might be stimulated to enhance the efficiency of injection as the permeability of these formations is usually low (0.1-10 mD). The hydraulic fracturing technology is one of the effective methods to attain a greater injectivity. To design an efficient hydraulic fracture, it is vital to systematically investigate important changes (e.g., pressure and stresses) occurring over the injection process on the fracturing performance. An increase in the reservoir pressure is an inevitable occuerrence during the fracturing operation. In situ stresses will also vary due to the fluid injection. As a consequence, the permeability of coalbed will be altered during the reservoir life. In this research study, a novel model for the hydraulic fracture design is introduced to consider the changes in the reservoir permeability during the injection process. A Direct Boundary Element Method (DBEM), which is a fundamental concept in the Unified Fracture Design (UFD), is employed to determine the fracture injectivity. In this study, the pressure change is estimated based on the injectivity. The variations of in situ stresses are determined using a model, which uses the Boundary Element Method (BEM) and theory of inclusions. Permeability is then updated based on the new values of stresses and the design dimensions of the fracture for the new time steps. Therefore, the model presents a suitable design of hydraulic fracture by considering the reservoir pressure changes during the injection. The proposed method is implemented on Latrobe Valley brown coal. The results suggest that the reservoir life is an important parameter to optimize the hydraulic fracturing design. Fractures with the same width and different penetrations yield very different efficiencies during the injection. The highest amount of cumulative injection can be achieved after 10 years using a fracture, which seems to be not optimum at the initiation stage of the injection process. This study proposes that it is necessary to take into account the stress changes in the design of a hydraulic fracture system in a coalbed to attain the effective injection operation regardless of high penetrations.",4,4,2
Fracture,Carbonate Reservoirs,"Janjuhah, Hammad Tariq; Alansari, Abubaker; Vintaned, Jose Antonio Gamez","Quantification of microporosity and its effect on permeability and acoustic velocity in Miocene carbonates, Central Luconia, offshore Sarawak, Malaysia",Central Luconia; Microporosity; Permeability; Acoustic velocity; Natural gas,DEPOSITIONAL-ENVIRONMENTS; RESERVOIR; CLASSIFICATION; POROSITY; PLATFORMS; MICRITE; HISTORY; BASIN; LOG,"Carbonate reservoirs are mostly considered to be complicated since in the petroleum industry, and because predicting the quality and achieving a high recovery factor from these rocks is challenging. Carbonate rocks have a complex porosity, which often leads to substantial uncertainty in prediction of permeability values for any particular porosity figure. The petrophysical analysis of carbonate reservoirs is and prone to more significant uncertainty. Pore size in carbonates rocks varies from micro to cave system scale. Carbonates with moldic and vuggy porosity usually contribute positively to the hydrocarbon production, yet sometimes these pores are mostly unconnected, thus yielding low flow rates, even though micropores form a high component of the total porosity of a reservoir. This study explores the reservoir properties of carbonate rocks of Central Luconia (Offshore Sarawak, eastern Malaysia), with emphasis on the relevance of microporosity on permeability and acoustic velocity relationships. A petrographic study of 260 samples obtained from the reservoir interval of Well A in the Central Luconia, Malaysia, was conducted to identify pore types (moldic, vuggy, interparticle, intraparticle and fractures) and measure porosity (ranging from 4 to 25%). For microporosity quantification, an enhanced workflow is introduced using the Digital Image Analysis (DIA) technique, where 32 petrographic images of each thin sections were taken under the transmitted light microscope that covers the entire thin section. The DIA technique was then implemented on these petrographic images to quantify the amount of macroporosity. After that, the microporosity was calculated in the following way: the difference in value between the observed macroporosity using DIA, and the total porosity measured on core plugs. Finally, the resulting amount of microporosity was then correlated with acoustic velocity and permeability to determine if significant improvement is achieved in the coefficient of determination (R-2). Moreover, it has increased from 0.55 to 0.67 for the permeability and from 0.61 to 0.87 for the acoustic velocity. The analysis also highlights that those samples with more substantial pores and a high figure ( > 50% of total porosity) of microporosity exhibit slower acoustic velocity for both P and S waves. Also, this study proposed a simple predictive model of elastic properties in the Central Luconian Miocene carbonate, Malaysia.",5,6,0
Fracture,Carbonate Reservoirs,"Mandiyar, H.; Salari, A.; Qajar, J.; Kalantariasl, A.",New correlations for etched fracture width and half-length of acid-fractured wells,Acid fracturing; Etched fracture width; Acid fracture half-length; Fracture conductivity; Effective wellbore radius,,"Acid fracturing is one of the most efficient well stimulation techniques in carbonate reservoirs. Estimation of well productivity after fracturing is an important issue in acid fracturing design and production engineering analysis. There are some correlations, available in the literature, for estimation of effective wellbore radius of hydraulically fractured wells. However, fracture etched width and its half-length must be known to use these correlations and, to our best knowledge, a simple and correct method for prediction of these parameters has not been reported yet. This paper presents a couple of correlations for estimation of etched fracture width and fracture half-length considering acid-rock interactions, reservoir and operational parameters. To develop and verify the proposed correlations, we used a large data bank produced by our in-house simulator, which models one-dimensional acid flow through a single hydraulic fracture considering acid-rock reaction and also fluid leakoff to the matrix. The governing equations are solved numerically using finite difference approach and the results were compared with a commercial simulator for verification. It is also explained how the values of etched fracture width and fracture half length, estimated by our new correlations, can be used in the available correlations for prediction of effective wellbore radius.",5,5,1
Fracture,Carbonate Reservoirs,"Amadu, Mumuni; Pegg, Michael J.",Analytical solution to spontaneous imbibition under vertical temperature gradient based on the theory of spontaneous imbibition dynamics,Spontaneous imbibition; Capillary pressure; Dimensionless time; Dimensionless distance; Equilibrium; Temperature gradient,CAPILLARY RISE; OIL RECOVERY; GRAVITY,"In this work, we have theoretically studied the imbibition process related to a block in a fractured carbonate reservoir under an assumed constant, vertical temperature gradient, G(T). An analytical solution to an ordinary differential equation we developed has been obtained using a computer program, and the original Washburn law normally valid for isothermal conditions of spontaneous imbibition has been found to hold true for G(T) equal to zero. The theoretical results of our study show that the space and time evolution of the imbibition front is strongly dependent on surface tension and dynamic viscosity of the imbibing fluid under a given temperature gradient. We have also validated our model against experimental data from a literature source based on spontaneous imbibition into a Hele Shaw Cell under longitudinal temperature gradient. The general conclusion of our study is that spontaneous imbibition in fractured carbonate reservoirs will be accelerated the higher the temperature of the injected water. This corresponds to a negative temperature gradient where the temperature of the injected water exceeds the ambient temperature of the reservoir.",5,4,3
Fracture,Carbonate Reservoirs,"Li, Yongqiang; Sun, Jianfang; Wei, Hehua; Song, Suihong",Architectural features of fault-controlled karst reservoirs in the Tahe oilfield,Karst outcrops; Tahe oilfield; Fault-controlled karst; Architectural features; Production significance,CARBONATE RESERVOIR; TARIM BASIN; PALEOKARST; SYSTEM; ROCKS,"Based on the analysis of the characteristics of modern karst and paleokarst outcrops, this study summarizes the features of subsurface reservoirs by using core, logging, seismic and production data, establishes the structural model of fault-controlled karst reservoirs, and points out the guiding significance of this structural model for development and production in the Tahe oilfield. Modern karst in southern China shows the three-component structural characteristics of fault-controlled karst which are fault core, damage zone, and host rock. The cavern is developed in the fault core and the fracture-vugs are fully developed. Paleokarst outcrops reveal the evolutionary process of fault-controlled karst reservoirs, the characteristics of caverns along the fault and the surrounding fracture-vuggy features. Seismic structure tensor attributes, ant-track attributes and amplitude spectrum gradient attributes are used to describe the external geometry, caverns, and large-scale fractures of fault-controlled karst reservoirs, and the small fractures and vugs can be described by using cores. According to the characteristics of modern karst, paleokarst and subsurface reservoirs, three architectural patterns of fault-controlled cavern complexes, fault-controlled caverns and fault-controlled vugs are summarized. Different architectural patterns of karst reservoirs lead to different production capacities. The architectural patterns have important guiding significance for new drilling and water or gas injection to improve oil recovery.",5,6,3
Fracture,Semianalytical Model,"Liu, Qingling; Tian, Shouceng; Yu, Wei; Li, Gensheng; Sheng, Mao; Sepehrnoori, Kamy; Shen, Zhonghou",A semi-analytical model for simulation of fluid flow in tight rock with irregular fracture geometry,Semi-analytical model; Transient pressure behavior; Vertical fractured well; Complex fracture geometries,PRESSURE-TRANSIENT ANALYSIS; HORIZONTAL WELLS; CONDUCTIVITY,"Numerous micro-seismic and laboratorial studies show that hydraulic fracture is usually with complex geometries, such as plugged fracture, asymmetry and non-plane. It is a challenging task to recognize the complex fracture and obtain reliable fracture parameters through transient pressure analysis. In this work, we extend the semi-analytical model by Zhou a al. (2013) to analyze transient pressure behavior of a fractured vertical well with complex fracture geometries. We verified the semi-analytical model by a numerical reservoir simulator on a planar fracture. Then, based on this model, we made a systematical discussion about the transient pressure behavior of the planar fracture with varying conductivity, asymmetric fracture and non-planar fracture. Results show that when the fracture conductivity is varying along the fracture path, the influence of fracture zone conductivity on the transient pressure behavior gradually decreases with the distance from the wellbore growing. Besides, we found that the fracture asymmetry is against for the fluid flow in the fracture, and it decreases the slope of transient pressure behavior curve and enlarge pressure drop. In addition, the non-planar fracture is usually with severe fracture width restriction around the wellbore, which will induce pseudo-radial flow in the fracture at early times and large pressure drop in the fracture. Furthermore, the influences of varying conductivity, fracture asymmetry and non-plane on transient pressure behavior are obvious for fracture with average small-to-middle conductivity (average dimensionless fracture conductivity ranging from 0.1 to 50); the influences become negotiable for fracture with average high-to-infinite conductivity (average dimensionless fracture conductivity ranging from 50 to 1000). This work can provide critical insights into understanding the effect of complex fracture geometry on transient pressure behavior of fractured vertical well in tight oil reservoir.",1,2,0
Fracture,Semianalytical Model,"Prasun, Samir; Wojtanowicz, Andrew K.",Semi-analytical prediction of critical oil rate in naturally fractured reservoirs with water coning,Critical oil rate; Naturally fractured reservoirs; Semi-analytical; Water coning; Matrix well; Fracture well,FLUID-FLOW; PERMEABILITY; MODEL,"Naturally fractured reservoirs (NFRs) with bottom water are generally produced above their critical oil rate (maximum possible oil production rate without water breakthrough) that is difficult to determine as it varies between wells, depending on the well's location in the fracture network. In principle, wells can either be completed in matrix or fractures. Present formulas of critical-rate in NFR are oversimplified ignoring the network heterogeneity and anisotropy ratio of fractures, and they also do not consider the difference between on-fracture/off-fracture well completion placements. Presented is development of a new semi-analytical formula that considers these effects-with emphasis given to well placement assessment. The critical rate model is derived from mechanistic principles and then improved with statistical calibration. The mechanistic approach (Chaperon (1986)) considers vertical equilibrium of viscous and gravity forces for a hemispherical flow to a point-source well in a dual porosity/dual permeability model of naturally fractured reservoirs. The model considers the water cone instability, and anisotropy ratio of NFR only for a short-perforated completion interval. The model is tested for wide variety of NFRs for short completions. The model is then statistically calibrated to including the effect of long penetration ratio, using a designed matrix of simulated experiments covering wide ranges of NFR properties. This statistical approach allows the model to consider any change in flow regime from semi-spherical to non-radial distorted flow. The comparison of Chaperon's analytical model and NFR simulations shows that the model is good for NFRs for penetration ratio smaller than 0.35. For penetration ratio greater than 0.35, a new semi-analytical model of critical-rate for NFR is developed by statistically calibrating the Chaperon's analytical model. The new model considers the parameters ignored in the previous models of NFR. Finally, a new mechanistic derivation of critical rate for wells completed in matrix block of NFR is determined by analytically including the effect of well's distance to fracture in a critical rate formula for NFR. The model matches well with the simulated data when compared with it. The model shows that the wells accidently completed off-fractures may display higher values of critical rates and the difference relates to their distance to the nearest fractures. It is also shown that the offfracture well's formula reduces to the on-fracture well's formula when the distance is reduced to zero.",1,1,0
Fracture,Semianalytical Model,"Zhang, Jiali; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Gao, Jian",A weak fluid supply model for transient pressure analysis in vertically fractured wells from tight gas reservoirs: A case study,Unconventional reservoirs; Weak fluid supply; Vertically fractured well; Pressure transient behaviors; Case study; Parameter estimation,SEMIANALYTICAL MODEL; HORIZONTAL WELLS; BEHAVIOR; NETWORKS,"An interesting phenomenon of weak fluid supply (WFS) has been observed in tight gas reservoirs from the Ordos Basin. To facilitate parameters evaluation and productivity estimations of those well, this paper presents a new WFS model for transient pressure analysis in vertically fractured wells from tight gas reservoirs. In the new model, a WFS pressure and a WFS index are first introduced to describe the weak fluid supply boundary. Based on that, a mathematical model is developed with considering WFS, finite-conductivity fractures, and stress-sensitive effect. Using perturbation transformation method and semianalytical method, the proposed mathematical model is solved with effects of wellbore storage and skin factor. Following that, the model verification, sensitivity study, and field application are performed. Results shows that the WFS causes a rapid drop after ""hump"" at the late stage in the pressure curves. The start time of ""hump"" decreases as the WFS index increases. When the WFS pressure is bigger than zero, the pressure derivative curves exhibit a significant ""hump"", and it is more obvious with the increase in the WFS pressure. When the WFS pressure is equal to zero, the pressure derivative curves directly drop, which is assemble to the effect of constant pressure boundary. When the WFS index is zero, the pressure derivative curve in the late period is a unit-slope line, demonstrating a closed boundary effect. The field application in the well Z1 from the Ordos Basin shows that a ""hump"" caused by WFS does appears at the late stage in the pressure curves. By using the WFS model, the estimated reservoir permeability and drainage radius are 0.524 mD and 451.68 m. The WFS pressure and WFS index are respectively estimated as 0.13 and 0.022 by the WFS model. It demonstrates the applicability of the new proposed WFS model, which also provides a good understanding of transient pressure behaviors and accurate estimation of reservoir parameters for fractured wells with WFS.",1,1,1
Fracture,Semianalytical Model,"Teng, Bailu; Li, Huazhou Andy",A semi-analytical model for characterizing transient flow behavior of reoriented refractures,Transient flow behavior; Reoriented refracture; Hydraulic fracturing; Unconventional reservoir; Well stimulation,PRODUCTION SIMULATION; FRACTURES; WELL,"In order to improve the field productivity, the industries can create new fractured wells to reduce the interval between the initial fractures (initial fracture indicates a fracture that is induced during the initial fracturing treatment). Production from the initial fractured wells can induce stress reorientation in the vicinity of the fractures. As such, a refracturing treatment in the stress reorientation region can lead to a reoriented refracture which has a certain azimuth with respect to the initial fractures. This azimuth can even be 90 degrees if the stress reorientation is sufficiently large. In addition to the conventional parameters (including refracture's length, refracture's conductivity, and the in-situ conditions), there are two more factors, the reorientation azimuth and the interference from the initial fracture, which can exert significant influence on the transient flow behavior of the reoriented refractures. In such case, the conventional analytical/semi-analytical models neglecting these two factors are no longer applicable to characterize the transient flow behavior from such a refracture. In this work, we develop a novel semi-analytical model to characterize the transient flow behavior of a reoriented refracture considering the interference from the initial fractures. In this model, the fractures are explicitly represented with discretized segments. We apply finite difference approximation to the initial fractures and refractures, respectively, to simulate the transient flow in the fracture system. In addition, the fluid flow in the matrix system can be characterized by Green function and Newman product method. Based on the continuity of flux and pressure, we couple the fracture flow equations with the matrix flow equations to construct a semi-analytical model. With the aid of the proposed model, we conduct a thorough investigation of the transient flow behavior of reoriented refractures. It is observed that, at the early production period, two fracture pseudosteady-state flows can appear due to the interference from the initial fractures. The formation linear flow and bilinear flow can also be observed during the production period of a refractured well. In an anisotropic-permeability reservoir, the refracture's azimuth and position can exert a significant impact on the productivity of the fractures. There is a region in the vicinity of the initial fractures, within which an orthogonal refracture can lead to the highest field productivity.",2,2,1
Fracture,Semianalytical Model,"Chu, Hongyang; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Liu, Wenyuan",Estimating carbon geosequestration capacity in shales based on multiple fractured horizontal well: A case study,Multiple fractured horizontal well; CO2 geosequestration; Shale reservoirs; Semi-analytical method; Transient pressure response,TRANSIENT PRESSURE BEHAVIOR; ENHANCED GAS RECOVERY; STORAGE CAPACITY; CO2 STORAGE; NUMERICAL-SIMULATION; SEQUESTRATION; RESERVOIR; MODEL; FEASIBILITY; ADSORPTION,"Nowadays, shale reservoirs have been though as good candidates for CO2 geosequestration for reduction of carbon emission. When estimating the carbon geosequestration capacity, multiple fractured horizontal well (MFHW) is a prerequisite for consideration when shale reservoirs are included in candidate geological sites, as it is one of the critical factors for the successful development of shale reservoirs. In order to perfect our previous works, a new model is proposed to calculate the carbon geosequestration capacity of depleted shale reservoirs based on MFHW. The methodology calculates carbon geosequestration capacity of shale reservoirs by considering Knudsen diffusion, molecular diffusion, supercritical Langmuir adsorption, stimulated reservoir volume (SRV), and stress-sensitivity of the permeability. Utilizing the perturbation transformation technique, finite difference method, and Laplace transform technique, our method is more in accordance with the actual situations, allowing us to accurately estimate the carbon storage capacity by capturing the transient pressure response of the MFHW. A field case from the Ordos Basin in China presents that the CO2 geosequestration capacity is proportional to the dimensionless fracture half-length and conductivity. The properties of hydraulic fractures only affect the early period of the CO2 geosequestration process. For the adsorption coefficient and flow coefficient ratio, with the change of these parameters, the middle and late periods of the CO2 geosequestration process are mainly influenced.",2,2,4
Fracture,Semianalytical Model,"Li, Zhenglan; Duan, Yonggang; Wei, Mingqiang; Peng, Yu; Chen, Qingxuan",Pressure performance of interlaced fracture networks in shale gas reservoirs with consideration of induced fractures,Interlaced fracture networks; Shale gas; Secondary induced fractures; Flux distribution; Pressure performance,HORIZONTAL WELLS; SEMIANALYTICAL MODEL; TRANSIENT PRESSURE; METHANE; FLOW; PERMEABILITY; MECHANISMS; ADSORPTION; BEHAVIOR,"Multi-stage fracturing in shale gas reservoirs may create complex fracture network around horizontal wellbore, due to the widely-distributed natural fractures. However, little work has been done to investigate the effects of secondary fractures on well testing models for shale gas reservoirs. In this paper, a more comprehensive model was developed for interlaced fracture networks in shale gas reservoirs with consideration of multiple transport mechanisms and different flow states. By employing the source function and Laplace transformation, the line sink solutions for four kinds of flow states were unified. Based on the discretization method and unified line sink solution, the pressure responses for interlaced fracture networks with infinite conductivity were obtained. Type curves were plotted and typical flow regimes of this model were identified. In order to have a further understanding of the effect of induced fractures, the slope curves of pseudo-pressure derivative were introduced to analyze the interference between fractures. The influences of the angel and the length of induced fractures on the well testing curves were simulated by the semi-analytical model for the first time. Then, the flux distributions of interlaced fracture networks were simulated and discussed for achieving significant advice. Finally, the proposed model was verified by a simplified case and a field case. The presented model will be helpful for understanding the transient performance of multi-stage fractured horizontal wells with consideration of induced fractures.",3,3,0
Fracture,Semianalytical Model,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Fracture,Semianalytical Model,"Yang, Xu; Guo, Boyun",Productivity analysis of multi-fractured shale oil wells accounting for the low-velocity non-Darcy effect,Low-velocity non-Darcy; TMS; Shale oil; Productivity; Cluster spacing,THRESHOLD PRESSURE-GRADIENT; LOW-PERMEABILITY RESERVOIR; PRODUCTION PERFORMANCE; MATHEMATICAL-MODEL; POROUS-MEDIA; FLUID-FLOW; BEHAVIOR,"Well productivity of the Tuscaloosa Marine Shale (TMS) trend located in Louisiana and Mississippi presents a significant challenge. Well productivity declines rapidly for some reasons not known to the operators. By taking advantage of the concept of apparent matrix permeability, a semi-analytical model was developed in this investigation considering the low-velocity non-Darcy effect. An iterative procedure is proposed to calculate the oil production rate of multi-fractured horizontal shale oil wells. Field case studies of the Eagle Ford Shale (EFS) and TMS wells indicated that the productivity model considering low-velocity non-Darcy is consistent with field data, with a relative error of less than 10%. The low-velocity non-Darcy phenomenon may harm the TMS oil production rate as high as 29.7%. Sensitivity analysis demonstrates that low permeability reservoirs are more likely to be affected by non-Darcy behavior. The apparent matrix permeability declines severer in low permeability than in high permeability reservoirs, thus reducing well productivity more significantly in the low-permeability TMS trend. The oil production rate of Darcy flow increases with increasing fracture conductivity. However, this benefit was hindered by non-Darcy effect. A larger fracture half-length favors oil production, although it reduces the non-Darcy effect slightly. Besides, reducing the cluster spacing can mitigate the adverse impact of low-velocity non-Darcy, thus enhancing the shale oil production rate. Therefore, there is a vast potential for enhancing oil productivity in the TMS trend by reducing perforation cluster spacing.",5,5,0
Fracture,Semianalytical Model,"Hu, Xiaohu; Yu, Wei; Liu, Malin; Wang, Mingwei; Wang, Weihong",A multiscale model for methane transport mechanisms in shale gas reservoirs,Semi-analytical model; Complex hydraulic fractures; Shale gas; Multiple horizontal wells; Nanopores,HYDRAULIC-FRACTURE GEOMETRY; HORIZONTAL WELLS; PRODUCTION SIMULATION; SEMIANALYTICAL MODEL; COMPREHENSIVE MODEL; COMPLEX FRACTURES; FLOW; NETWORKS; PERMEABILITY,"We presented an efficient semi-analytical model-based analysis of methane transport in shale reservoirs including multiple horizontal wells with nanopores and complex hydraulic fractures. Multiple important gas transport mechanisms in nanopores such as gas desorption, gas slippage and diffusion and pressure-dependent fracture conductivity are fully incorporated in the model. Both simple and complex fractures in multiple shale-gas wells can be easily and effectively dealt with in accordance with the discretization approach, which does not require detailed gridding like numerical model. The superposition principle is utilized to capture the interactions between all fracture segments in order to accurately simulate real gas transport from matrix to fractures and finally from fractures to wellbores. We verified the semi-analytical model against a numerical compositional reservoir model for two shale-gas wells with multiple simple planar hydraulic fractures considering the gas desorption effect. The semi-analytical model was used to analyze ultimate gas recovery of different complex hydraulic fracture patterns in a two-well scenario, which were generated from a complex fracture propagation model with and without considering natural fractures. In addition, it was applied to perform field-scale simulation with multiple wells and complex fracture geometries in accordance with microseismic data. The simulation results show that multiple gas transport mechanisms, pressure-dependent fracture conductivity and complex fracture geometries play an important role in controlling well productivity and gas recovery, which should be properly accounted for in the physical model in order to achieve more accurate long-term production forecasting of multiple-fractured shale-gas horizontal wells.",5,6,1
Fracture,Semianalytical Model,"Sun, Zheng; Shi, Juntai; Wu, Keliu; Ma, Hongyan; Li, Simin; Zhang, Tao; Feng, Dong; Liu, Wenyuan; Liu, Yisheng; Wang, Suran; Ramachandran, Hariharan; Li, Xiangfang",Novel optimization method for production strategy of coal-bed methane well: Implication from gas-water two-phase version productivity equations,Productivity equations; Gas-water two-phase flow; Production strategy; Optimization criterion,FRACTURED VERTICAL WELL; NEWTONIAN FLUID-FLOWS; LOW-PERMEABILITY; DESORPTION AREA; SEMIANALYTICAL MODEL; MATHEMATICAL-MODEL; TRANSIENT ANALYSIS; QINSHUI BASIN; CBM FIELD; SHALE,"To date, the development of coalbed methane (CBM) reservoirs has attracted a great deal of attention due to its considerable perspective reserves. As a result, nearly all research aspects of CBM reservoirs have been extensively investigated and expect to advance gas production performance as well as associated economic value. Notably, amongst the most significant issue influencing the production performance is the production strategy optimization, which however remains challenging because of the complex time-varying fluid flow performance during the development process of CBM reservoirs. It is always difficult but crucial to shed light on the optimal drawdown pressure within different production scenarios. According to the gas-water two-phase version productivity equations which have been proposed in our previous work, a set of quantified optimization criterion for production strategy within the entire CBM well production process is developed for the first time in this research paper. The proposed optimization criterion contains three procedures: (1) the gas well maintains the bottom-hole pressure (BHP) as critical desorption pressure until the pressure wave propagate to the boundary; (2) the BHP is set as the critical pressure, which is firstly proposed herein and determined by gas phase productivity equation, until the pressure at the boundary become below the critical desorption pressure; (3) the gas well maintains the BHP as the abandonment pressure. In order to clarify the validity of the proposed criterion, we applied the optimization criterion to an actual CBM well located in Hancheng field, China, and found the case with optimized production strategy achieved much better gas recovery compared with that based on the previous production strategy. Moreover, production evaluation work is performed based on the utilization of the proposed optimization method, it indicates that optimized gas production can attain relatively high gas production rate in the future three years. The optimization method possesses simple and easy-operation advantages, which shares great application potential in actual CBM fields and turns out to be practical. In addition, because a practical optimization method for scheduling production strategy of CBM wells has not been proposed before, this work is able to fill the knowledge gap and will contribute to the efficient development of CBM reservoirs.",5,5,3
Fracture,Failure,"Vtorushin, E. V.; Dorovsky, V. N.",Application of non-stationary non-Euclidean model of inelastic deformations to rock cutting,anelasticity; Zonal disintegration phenomenon; Non-euclidean continuum model; Non-stationary process; Rock cutting; Dynamic hardening,SPATIALLY NONLOCAL MODEL,"Rock behavior does not fit the classical theory of continuum mechanics at high level of stresses with respect to the tensile strength because of rock heterogeneous structure. Particularly, rock failure may be accompanied by initiation of zonal disintegration. The key to building the non-classical model of rock failure is the granulated structure. Deformations of solid bodies with microscopic flaws can be described within the scope of non-Euclidean geometry, and the non-trivial deformation incompatibility can be referred to as a failure parameter. The new dynamic model presented in this paper enables one to predict the failure zones to initialize and develop them as a periodic structure. The non-Euclidean description of this phenomenon initiates two unusual material constants that can be called ""inelastic"" moduli. The coupled model must include a fourth-order parabolic equation to find a disintegration thermodynamic parameter. The equation should be solved together with the classical hyperbolic system of equations for continuous medium dynamics. In the classical approach to the rock cutting problem, the fracture is caused by critical shear stresses when the failure criterion based on the Tresca (or more general Mohr) theory is applied. In this case, it is difficult to predict the chip size and optimal depth of cut because the criterion is beyond the model. Another flaw of the conventional approach is that it is hard to explain a dynamic hardening effect in the scope of local models of plasticity. In this paper, the developed dynamic theory of zonal disintegration (Dorovsky et al., 2015) is applied to the numerical analysis of rock cutting by polycrystalline diamond compact (PDC) bit cutter process. It has been shown that the initial shear stress at the cutter tip causes the disintegration (destruction) developing deep into the medium and along the cutting direction with contouring of the rock failure scale. The appearance of plasticity effects at the yield stress above tensile/shear strength allows us to come up with an adequate description of the dynamic hardening observed in recent laboratory experiments.",1,1,3
Fracture,Failure,"McKean, Scott H.; Priest, Jeffrey A.",Multiple failure state triaxial testing of the Montney Formation,Unconventional reservoir geomechanics; Multiple failure state; Triaxial test; Elastic anisotropy; Post-peak behaviour; Failure envelope; Montney Formation,ROCK; STRENGTH,"Elastic behaviour controls hydraulic fracture propagation and ultimately, the productivity of unconventional reservoirs. Various index tests and single stage triaxial tests are used to characterize elastic moduli but it can be difficult to obtain enough samples and sufficient information. This is partly due to the fissile nature of shales, which results in a paucity of representative core plugs. It is also partially due to the complex and heterogeneous nature of unconventional reservoir's geomechanical behaviour. The failure mechanics of unconventional rocks are poorly understood and seldom incorporated in hydraulic fracturing or geomechanical models. Yet, failure is major influence on fracture complexity and reservoir drainage volumes. The objectives of this study were to evaluate the variability in geomechanical properties and characterize the post-peak behaviour of a stiff siltstone from the Montney Formation in Alberta, Canada. The multiple failure state triaxial test was used to define the pre-peak elastic behaviour, post-peak behaviour, and failure envelope of a single core plug. This is beneficial for practitioners that are faced with a paucity of samples. The multiple failure state triaxial test is difficult to implement for stiff specimens, which fail in a brittle and unstable manner and a methodology to improve the stability near and beyond sample failure was therefore developed. The results from this study, which were also compared to various index tests and publicly available data, show that the samples had low porosity, low clay, and high stiffness. Significant variability in elastic behaviour was observed due to non-linearities in the loading curve - an effect that overshadowed changes due to confining pressure and highlighted that need for careful consideration of elastic parameter variability. Several oriented samples sets were used to characterize elastic and strength anisotropy. The improved test methodology was able to capture stable post-peak behaviour on almost all the tested samples. Brittle stick-slip failure was observed and an exponential model for approximating post-peak behaviour was presented. The combination of triaxial testing and index testing was able to completely characterize the constitutive law and failure envelope of the samples, save the Biot coefficient. These results can be incorporated into both routine and advanced geomechanical models and hydraulic fracturing simulators.",2,2,1
Fracture,Failure,"Zhang, Rui; Li, Yinghao; Yang, Bin; Jia, Zongyi; Zhang, Feng; Wang, Ruihe; Li, Na; Zhou, Xianhai",A segmenting method of long horizontal wellbore for staged sand control completion based on multi-dimension sequential clustering,Sand production; Staged completion; Multi-dimension sequential clustering; Critical wellbore pressure of sanding onset; Water breakthrough time,INFLOW-CONTROL DEVICES; GAS-RESERVOIRS; OPTIMIZATION; PRESSURE,"For horizontal well, the uniform measure of completion for sand control in the whole horizontal wellbore will cause local sand control failure or excessive sand control, even a decrease in production. An effective measure solved the problem is to segment long horizontal wellbore and conduct completion with staged sand control. In this paper, taking into consideration impacts of reservoir properties heterogeneity, the heel-toe effect of wellbore flow and the different distance between wellbore and water-oil contact (WOC) on sand production along long horizontal wellbore, the difference (CWP - p(wf)) between critical wellbore pressure of sanding onset (CWP) and wellbore flowing pressure (p(wf))and water breakthrough time (T) of each micro section of horizontal wellbore are used to make up vector components and selected as segmenting indexes, further mull-dimension sequential clustering method is employed to segment horizontal wellbore according to the principle of location contiguity and similarly of CWP - p(wf) and T between micro intervals. Then the segmenting method for sand control completion together with water control in horizontal wells is proposed. Furthermore, the segmentation method is utilized in investigating staged sand and water control in TP65 well of T block in Shengli Oilfield, and the optimal number and location of segments for the well are given. This research can provide a new theoretical and quantitative method for staged sand control completion in horizontal well. And it also can be regarded as a fundamental platform to investigate other kinds of wellbore staging problems, such as staged fracturing.",2,3,3
Fracture,Failure,"Mokhtari, Mehdi; Nath, Fatick; Hayatdavoudi, Asadollah; Nizamutdinov, Rustam; Jiang, Shuxian; Rizvi, Hashim",Complex deformation of naturally fractured rocks,Strain; Optical technique; Digital image correlation; Natural fracture; Complex fracture,DIGITAL-IMAGE-CORRELATION; SHEAR DEFORMATION; GROWTH; IDENTIFICATION; VISUALIZATION; EVOLUTION; FAILURE; SHALE,"Strain is a key parameter in the evaluation of rock mechanical properties and failure behavior. Strain is usually measured using strain gauges, however, this laboratory method has inherent uncertainty in the attachment of sensitive gauges to the rock surface and it is limited to one-point strain measurement. In complex geometries such as rock samples with natural fractures or lamination, that classical approach cannot provide the whole picture of strain development in such complex geometries. To overcome these challenges, the application of optical technique with image processing is proposed. The optical technique has the advantage of being a non-contact method and it provides quantitative visualization of full-field strain measurement. To examine quantitative visualization of strain development, DIC technique was first conducted on a homogeneous sandstone sample as a benchmark. The results verify that the maximum tensile strain is developed at the central vertical line of the sample as it was expected from theoretical solutions. This DIC measurement matches the post-failure fracture pattern of the specimen. Then the technique was applied on the Buda Limestone samples with horizontal, sub-horizontal or multiple complex natural fractures (sealed or partially open) and inclusions while the samples were under diametrical compression experiment. The results of this study provide further insight into the role of natural fractures on induced fracture initiation and propagation under this specific testing condition. Horizontal natural fractures are planes of maximum compressive strain which can delay the propagation of vertical tensile fractures. The maximum amount of tensile strain usually initiates at the boundary of these natural fractures and vertical tensile fractures usually deviate toward horizontal fracture for a short distance before turning back to propagate vertically following the maximum stress path. Full-field surface deformations are mapped optically in the crack-inclusion vicinity where DIC results showed that crack front is arrested by the inclusion for the complete fracture event. In contrast to the failure pattern in homogenous sandstone specimen, complex fracture pattern was observed on several specimens with multiple fracture network. Fracture slippages along the natural fracture, fracture deviation was observed in samples with steep inclined natural fractures. The results of this study can help us to better understand the complex failure mechanism in naturally fractured media and elaborate on various mechanisms of failure under diametrical compression tests. DIC is a powerful technique in providing the dynamic strain development over the surface of the sample in real-time, thus it can provide the fracture initiation and propagation in such heterogeneous rock media.",3,3,1
Fracture,Failure,"Dong, Xuelin; Duan, Zhiyin; Qu, Zhe; Gao, Deli",Failure analysis for the cement with radial cracking in HPHT wells based on stress intensity factors,Cement sheath; Well integrity; Radial crack; Stress intensity factor; High pressure/high temperature,GAS-WELLS; INTEGRITY; SHEATH; OIL,"Wells are often cemented to provide zonal isolation and structural support through their entire service lifetime. Even if a cement sheath is set properly, it may inevitably contain small cracks which tend to propagate under harsh environmental and operational conditions. This work presents a mechanical model to predict the stress intensity factor at a radial crack tip in the cement under high pressure/high temperature (HPHT) conditions. The well section comprised of casing-cement-formation is modeled as three isotropic material domains under plane strain condition. The model calculates the stress field in the well section and estimates the stress intensity factor by a distributed dislocation technique. Two failure factors corresponding to the material strength criterion and fracture propagation criterion are introduced to evaluate the cement integrity. The influence of loading conditions and cement's mechanical and thermal properties on the failure factors is also investigated. The results indicate the predominant failure mode under HPHT conditions. The proposed model provides guidelines for the assessment of cement sheath integrity based on fracture mechanics.",4,4,3
Fracture,Failure,"Ma, Yongfeng; Yu, Rangang",New analytical methods to evaluate uncertainty of wellbore stability,Wellbore stability; Uncertainty evaluation; Analytical model; Monte Carlo method; Sensitivity analysis,FAILURE CRITERIA; STRENGTH CRITERIA; LOGGING PROBLEMS; MODEL; COULOMB; ROCKS; LIMIT,"The uncertainties of the inputting parameters lead to the uncertainty of the wellbore stability. In view of this, two analytical methods were proposed to address the problem, based on second order Taylor series expansion and Rosenbluthe method. Using two analytical methods, the collapse and fracture pressures were calculated in the form of the probability distribution. To accomplish the calculation above, the mean and standard deviation of input parameters were firstly determined based on well log data. Especially, a new method of sensitivity analysis was proposed to quantify the effect of the input parameter on the uncertainty of the wellbore stability, through the way that one parameter changes the uncertainty while other parameters keep initial uncertainties. Additionally, two analytical methods were validated by Monte Carlo simulation. The results show that the probability distributions agree very well between analytical methods and Monte Carlo method. According to the new method of sensitivity analysis, the horizontal maximum stress is the most sensitive parameter for the collapse pressure, and the horizontal minimum stress has the maximum effect on the fracture pressure.",5,6,1
Fracture,Failure,"He, Zhenhua; Duan, Benchun",Significance of the dynamic stress perturbations induced by hydraulic fracturing,Hydraulic fracturing; Dynamic modeling; Dynamic effects; Dynamic stress; Stability,RUPTURE; SLIP; VELOCITY,"Hydraulic fracturing and microseismicity generation and radiation are dynamic processes. The associated dynamic stress perturbations could play a significant role in relevant studies, such as activation of weak planes including natural fractures, bedding planes, etc. We study how different the dynamic and static stress perturbations could be during hydraulic fracturing. Our work is based on a 2D plane-strain framework. A dynamic finite element method is applied to solve the equations of motion. The static stress perturbations are obtained when the models reach static equilibrium (i.e., after generated seismic waves die out). We compare the static and dynamic stress perturbations at a moment when a hydraulic fracture (HF) propagates to a certain length. Mohr circle analysis shows that around the HF the Mohr circle based on a dynamic stress tensor is closer to a failure line than that based on a static stress tensor. The peak static and dynamic stress perturbations during the process are also compared. We conclude that the absolute values of the peak dynamic stress perturbations are always greater than that of the peak static stress perturbations, especially in the area close to the HF and its tips. The effect of injection rates on the static and dynamic stress perturbations is also studied. The largest peak static and dynamic stress perturbations during the hydraulic fracturing process are measured. The absolute values of both the largest peak dynamic and static stress perturbations increase with injection rates. The absolute values of the difference between the largest peak dynamic and static stress perturbations also increase with injection rates due to more significant dynamic effects.",5,7,1
Fracture,Analytical Model,"Prasun, Samir; Wojtanowicz, Andrew K.",Semi-analytical prediction of critical oil rate in naturally fractured reservoirs with water coning,Critical oil rate; Naturally fractured reservoirs; Semi-analytical; Water coning; Matrix well; Fracture well,FLUID-FLOW; PERMEABILITY; MODEL,"Naturally fractured reservoirs (NFRs) with bottom water are generally produced above their critical oil rate (maximum possible oil production rate without water breakthrough) that is difficult to determine as it varies between wells, depending on the well's location in the fracture network. In principle, wells can either be completed in matrix or fractures. Present formulas of critical-rate in NFR are oversimplified ignoring the network heterogeneity and anisotropy ratio of fractures, and they also do not consider the difference between on-fracture/off-fracture well completion placements. Presented is development of a new semi-analytical formula that considers these effects-with emphasis given to well placement assessment. The critical rate model is derived from mechanistic principles and then improved with statistical calibration. The mechanistic approach (Chaperon (1986)) considers vertical equilibrium of viscous and gravity forces for a hemispherical flow to a point-source well in a dual porosity/dual permeability model of naturally fractured reservoirs. The model considers the water cone instability, and anisotropy ratio of NFR only for a short-perforated completion interval. The model is tested for wide variety of NFRs for short completions. The model is then statistically calibrated to including the effect of long penetration ratio, using a designed matrix of simulated experiments covering wide ranges of NFR properties. This statistical approach allows the model to consider any change in flow regime from semi-spherical to non-radial distorted flow. The comparison of Chaperon's analytical model and NFR simulations shows that the model is good for NFRs for penetration ratio smaller than 0.35. For penetration ratio greater than 0.35, a new semi-analytical model of critical-rate for NFR is developed by statistically calibrating the Chaperon's analytical model. The new model considers the parameters ignored in the previous models of NFR. Finally, a new mechanistic derivation of critical rate for wells completed in matrix block of NFR is determined by analytically including the effect of well's distance to fracture in a critical rate formula for NFR. The model matches well with the simulated data when compared with it. The model shows that the wells accidently completed off-fractures may display higher values of critical rates and the difference relates to their distance to the nearest fractures. It is also shown that the offfracture well's formula reduces to the on-fracture well's formula when the distance is reduced to zero.",1,1,0
Fracture,Analytical Model,"Youssef, AbdAllah A.",Inflow performance relationship of vertical wells in fractured vuggy media during semi-steady state flow regime,IPR; Error parameter and fractured-vuggy reservoirs,HORIZONTAL WELL; PERMEABILITY; BEHAVIOR; POROSITY; MODEL,"The inflow performance relationship (IPR) is one of the essential key parameters that control the fluids production/injection rate from wells. The presence of the vugs in addition to fractures in carbonate reservoirs introduce many difficulties related the estimation of IPR of future wells. In this study, a novel analytical IPR of dual-permeability, triple porosity model is derived for the first time. The introduced IPR formula is derived for the standard scenario model of a vertical and fully penetrating well in a circular reservoir under single-phase flow of slightly compressible fluid. The three governing flow equations (matrix flow equation, fracture flow equation and interaction between vugs and other two continuum equation) are solved simultaneously as a system of differential equations for semi-steady state (SSS) flow regime. The generated SSS IPR is the same as Darcy's straight line IPR multiplied by an error parameter (E-23) which is bounded between zero and one. A detailed investigation of the effect of the reservoir petro-physical parameters like storativities, inter-porosities and fracture to matrix permeability ratio are presented. The newly presented IPR of dual-permeability, triple porosity system can be reduced to sub-models IPRs by further modification of error parameter to fit sub-model as single permeability, triple porosity (E-13) or dual permeability, dual porosity (E-22). The presented IPR formula has the advantage of dividing the pressure drop of the fluid flow to two components, one for the internal resistance between different continuums (which is resented by E) and the other one is the radial flow in the same continuum toward/from well-bore. The generated IPR model is double verified using both cell pressure centred finite volume numerical simulation and conventional pressure transient analysis.",2,2,0
Fracture,Analytical Model,"Sun, Jin; Wu, Shiguo; Deng, Jingen",An analytical model for fracture initiation in elasto-plastic soft formations based on stress path analysis,Fracture initiation pressure; Soft formations; Fracturing mode; Stress path; Tensile fracturing; Shear fracturing,CONSOLIDATED ROCK STRATA; NUMERICAL-SIMULATION; BOREHOLE YIELD; WELLBORE; PROPAGATION; STABILITY,"Most models developed for hydraulic fracturing initiation of borehole are based on the elasticity mechanics, and tensile fracturing is considered as the mechanism of fracture initiation. However, the lab and field data show that these models cannot properly predict the fracturing mechanism of soft formations. We proposed an elasto-plastic model to analyze the fracturing mode and fracture initiation pressure in the soft formations that considers the effect of overburden pressure and fluid flow. The analytical stress solutions under six different stress state are obtained, thus the effective stress path on the borehole wall is analyzed to determine the fracturing mode. The effective stress path analysis indicate that both tensile and shear fracturing are considered as the fracturing mode. The fracturing mode and fracture initiation pressure are influenced by the burial depth significantly. The tensile fracturing is more likely to occur in the shallow formation, while the shear fracturing usually occurs in the deep formation. In addition, the formation strength and mud cake also affect fracturing mode and fracture initiation pressure. The shear fracturing is more easily to be induced in the formation with low strength and tight mud cake. The preyielding around the borehole due to the low strength will decrease the fracture initiation pressure without affecting the fracturing mode of the borehole wall.",2,2,2
Fracture,Analytical Model,"Ma, Yongfeng; Yu, Rangang",New analytical methods to evaluate uncertainty of wellbore stability,Wellbore stability; Uncertainty evaluation; Analytical model; Monte Carlo method; Sensitivity analysis,FAILURE CRITERIA; STRENGTH CRITERIA; LOGGING PROBLEMS; MODEL; COULOMB; ROCKS; LIMIT,"The uncertainties of the inputting parameters lead to the uncertainty of the wellbore stability. In view of this, two analytical methods were proposed to address the problem, based on second order Taylor series expansion and Rosenbluthe method. Using two analytical methods, the collapse and fracture pressures were calculated in the form of the probability distribution. To accomplish the calculation above, the mean and standard deviation of input parameters were firstly determined based on well log data. Especially, a new method of sensitivity analysis was proposed to quantify the effect of the input parameter on the uncertainty of the wellbore stability, through the way that one parameter changes the uncertainty while other parameters keep initial uncertainties. Additionally, two analytical methods were validated by Monte Carlo simulation. The results show that the probability distributions agree very well between analytical methods and Monte Carlo method. According to the new method of sensitivity analysis, the horizontal maximum stress is the most sensitive parameter for the collapse pressure, and the horizontal minimum stress has the maximum effect on the fracture pressure.",5,6,1
Fracture,Analytical Model,"Albattat, Rami; Hoteit, Hussein",Modeling yield-power-law drilling fluid loss in fractured formation,Lost-circulation; Loss of drilling fluid; Mud loss; Flow in fractured formation; Yield power law; Herschel-Buckley; Cauchy momentum equation; Fracture ballooning,MATERIAL SELECTION GUIDELINES; PERFORMANCE; FLOW,"Loss of circulation during drilling is a pressing problem that typically occurs when significant volumes of the drilling fluid leak to the surrounding formation. In fractured media, circulation loss is often a sudden event which may interrupt the drilling operations, increase nonproductive time, and add complexity in controlling the fluid flow and wellbore stability. Developing models to predict the fluid leak dynamics and identify the suitable loss-control-material (LCM) is of significant interest to the industry. In this work, simulation and analytical models are developed to model the dynamics of fluid loss for power-law drilling fluids from the wellbore to a surrounding fractured medium. The model is based on the Cauchy momentum equation and accounts for the key predominant flow mechanisms, including the non-Newtonian behavior of the drilling fluid (mud) using a power-law model. Experiments from the literature are used to assess the behavior of mud loss into a single horizontal fracture, which includes the effects of mud rheology and yield stress. We show that previous unsuccessful attempts to match the experimental data using analytical models are related to the assumption of uniform fracture aperture. Simulations are then used to demonstrate that a slight deformation in the fracture walls leads to a significant deviation in the analytical model predictions, and therefore the dynamics of fracture opening is a critical parameter that should be carefully assessed. In other related experiments, the analytical model also failed to capture the mud invasion distance within the fracture as a function of pressure drop and the mud properties. To address this issue, a modified analytical model that accounts for non-parallel fracture walls is proposed. The new model allows to quickly assessing the impact of nonuniform fracture apertures. It can serve as a screening tool to evaluate mud invasion distance as a function of fracture geometry, mud rheological properties, and pressure drop resulting from the well depth, injection rate, and mud density.",5,5,3
Fracture,Analytical Model,"Amadu, Mumuni; Pegg, Michael J.",Analytical solution to spontaneous imbibition under vertical temperature gradient based on the theory of spontaneous imbibition dynamics,Spontaneous imbibition; Capillary pressure; Dimensionless time; Dimensionless distance; Equilibrium; Temperature gradient,CAPILLARY RISE; OIL RECOVERY; GRAVITY,"In this work, we have theoretically studied the imbibition process related to a block in a fractured carbonate reservoir under an assumed constant, vertical temperature gradient, G(T). An analytical solution to an ordinary differential equation we developed has been obtained using a computer program, and the original Washburn law normally valid for isothermal conditions of spontaneous imbibition has been found to hold true for G(T) equal to zero. The theoretical results of our study show that the space and time evolution of the imbibition front is strongly dependent on surface tension and dynamic viscosity of the imbibing fluid under a given temperature gradient. We have also validated our model against experimental data from a literature source based on spontaneous imbibition into a Hele Shaw Cell under longitudinal temperature gradient. The general conclusion of our study is that spontaneous imbibition in fractured carbonate reservoirs will be accelerated the higher the temperature of the injected water. This corresponds to a negative temperature gradient where the temperature of the injected water exceeds the ambient temperature of the reservoir.",5,4,3
Fracture,Size Distribution,"Salimidelshad, Yaser; Moradzadeh, Ali; Kazemzadeh, Ezatallah; Pourafshary, Peyman; Majdi, Abbas",Effect of hysteresis on petrophysical properties of limestone hydrocarbon reservoir rock,Hysteresis; Petrophysical properties; SEM; CT scan; Pore size distribution,PERMEABILITY; DEFORMATION; MECHANISM; POROSITY,"The petrophysical properties of carbonate reservoirs may change when they are subjected to mechanical loadings due to the softness of the formation. As the reservoir fluid pressure declines due to production, the net load on the rock increases, which leads to compaction of the rock and decrease in its pore volume, causing blocking of pore throats and the permeability reduction. In this study, we experimentally investigated the hysteresis effect of petrophysical properties of two carbonate core samples during the loading using CMS-300 apparatus. The structure of samples was processed by CT scan images and analysis of the pore size distribution was also conducted using mercury injection testing followed by scanning electron microcopy (SEM). Our results indicate that isotropic long-term and short-term loading considerably change the grain structure, while the petrophysical properties do not have a clear effect. The porosity induced by the cyclic loading was affected by intergranular micro-extension fractures. The results also indicate that the greatest reduction of porosity in fractured limestone occurred at the first loading step; however, further reduction was strongly due to the consolidation and adherence of the grain matrix. This fluctuating trend was also observed for the permeability, with a severe reduction in the permeability when crushed grains were placed in the connected pore path. The measured porosity and permeability of carbonated rocks, as stress-sensitive parameters, along analysis of the micro-fracture effects during loading and unloading, can be considered in production and injection management of reservoirs. They are also useful for predicting of any possible risks during different periods of reservoir life and determining the optimum production pressure of the reservoir.",1,1,1
Fracture,Size Distribution,"Ettehadi, Ali; Tezcan, Meltem; Altun, Gursat",A comparative study on essential parameters to minimize sealing time in wide fractures,Early sealing time; Wide fracture; Sepiolite base mud; Gel structure; Thixotropy; Bi-modal and tri-modal particle size distribution,LOST-CIRCULATION; YIELD-STRESS; THIXOTROPY,"Efficient early-time plugging of wide fractures was aimed to investigate by considering granular lost circulation material (LCM) sizes, its concentrations, and geometries as the essential parameters. Fracture sealing time was experimentally investigated using sepiolite based mud prepared considering API standards. Steady shear flow, thixotropy loop and oscillatory dynamic shear tests were conducted using Discovery Hybrid Rheometer (DHR-II) to evaluate gel structure and particle suspension ability of sepiolite based mud as carrier fluid. The set of seventeen sieves 75-3360 mu m was used for analyzing grain sizes of calcium carbonate (CaCO3) as LCM. The effect of sixteen different LCM size ranges on the fracture sealing time was investigated through six slotted discs having different fracture widths (apertures) (508 mu m-3048 mu m) and lengths. Using wide range of sieve set allows providing uniform, bi-modal, and tri-modal particle size distribution of CaCO3 pills as the fundamentals to investigate fracture sealing time. Upward flow direction was provided using Pore Plugging Apparatus (PPA) under 1000 psi of pressure differential. Fracture sealing time values were measured using precise pressure transmitter connected between experimental setup and computer. Sealing performance of LCM sizes and concentrations was visually evaluated using optical microscope. Results reveal that rheological characteristics particularly gel structure and thixotropy of carrier fluid are highly noteworthy. High degree of thixotropy and gel structure development make the sepiolite mud an active carrier fluid. Early fracture sealing time intensely depends on accurate combination of fine, medium, and coarse LCMs, particle size distribution, particle shape and concentration of LCM. Early sealing time and plug developing in wide fractures occurs efficiently by increasing modality in particle size distribution. The fine, medium and coarse LCMs must be added with optimum concentrations to seal fracture effectively and minimize sealing time.",2,2,1
Fracture,Size Distribution,"Wang, Dongying; Wang, Zhiming; Zeng, Quanshu",An experimental study on gas/liquid/solid three-phase flow in horizontal coalbed methane production wells,Gas/liquid/solid three-phase flow; Coalbed methane; Horizontal well; Flow pattern; Height of coal particle bed; Explicit equation,SAND-DEPOSITION VELOCITY; RESERVOIR ROCKS; LIQUID; GAS; PARTICLES; TRANSPORT,"Coal particles caused by well drilling and completion, hydraulic fracturing, and formation pressure decreasing would migrate into the horizontal well carried by fracturing flow-back fluid, formation water and CBM, and then deposit on the low side of pipe leading to the decrease of cross section area of pipe for flow and even blocking of the pipe. The purpose of current research was to obtain the flow pattern while there was stationary solid particle bed on the low side of the pipe and an explicit equation to predict the height of solid particle bed was proposed. In this study, with the coal particle, water, and air as the solid, liquid, and gas phases respectively, gas/liquid/ solid three-phase flow experiments in horizontal well were carried out and 4 crucial factors including different water flow rate, gas flow rate, coal particle size, and coal particle mass concentration were considered. Fluid's real apparent velocity was defined and used to analyze the distribution of flow pattern coordinate points. Results show that the flow pattern coordinate points determined by real gas apparent velocity and real water apparent velocity distribute near the flow pattern transition lines of Taitel and Dukler flow pattern map. Besides, coal particle size, water flow rate, and gas flow rate have obvious impact on the height of coal particle bed and the coal particle mass concentration has a negligible effect while the height of interface between gas layer and water layer is only dramatically affected by the gas flow rate. At last, an explicit equation for predicting the cross section area of coal particle bed based on the experimental data was proposed which is crucial to predict the flow pattern and calculate the pressure drop in horizontal well. The predicting cross section area of coal particle bed is in good agreement with the measured cross section area of coal particle bed and the average relative differences are 9.38% and 13.45% for stratified smooth flow and stratified wavy flow respectively. The equation is applicable for a range of coal particle size (8-30 mesh) and water apparent velocity (0.025-0.123 m/s).",2,2,4
Fracture,Size Distribution,"Zhang, Yulai; Mostaghimi, Peyman; Armstrong, Ryan T.",Multiscale characterization of shale diffusivity using time-lapsed X-ray computed tomography and pore-level simulations,Shale; Pore spaces; Micro-CT; FIB-SEM; Organic matter; Pore-scale simulation,POROSITY; COEFFICIENTS; TORTUOSITY; DISTRIBUTIONS; PERMEABILITY; ADSORPTION; MICROSCOPY; BARNETT; SYSTEMS; MEDIA,"Shale rock is challenging to characterize due to its complex multiscale structure, which directly influences various mass transport processes. The diffusion of a single component fluid through shale rocks is further complicated by the existence of various pore types, e.g. organic or intercrystalline, and fractures that range in size from sub-nanometer to micrometer. We present a workflow that investigates the process of liquid/liquid diffusion in shale rocks, which provides insights into its multiscale structure. We combine scanning electron microscopy (SEM), focused ion beam-scanning electron microscopy (FIB-SEM), pore-scale simulations and high-resolution 4D X-ray microcomputed tomography to investigate shale structure and effective diffusivities at various length scales. We find that fractures, matrix heterogeneity and pore-level characteristics are important factors that influence mass transport. Fractures influence effective diffusivities at the core scale providing high diffusivities over early time scales. Matrix heterogeneity results in effective diffusivity differences at the sub-core scale that are lower than the effective diffusivities measured at the core scale at early time. Effective diffusivities for organic matter rich regions are at least one order of magnitude greater than regions with low organic matter. Within the organic matter rich regions, effective diffusivities are mostly within one order of magnitude. These analyses provide a framework to build multi-scale shale models based on the pore-scale structure (10(-9) m) of organic matter rich regions, distribution of porosities at the sub-core scale (10(-6) m) and the arrangement of fractures at the core scale (10(-3) m).",4,4,1
Fracture,Size Distribution,"Gong, Yiwen; El-Monier, Ilham",Microstructure diagnosis of the fractured tight sandstone using image analysis,Grain size; Image analysis; Tight sandstone; Statistical analysis,SIZE DISTRIBUTIONS; PROCESS ZONE; SIMULATION; BEHAVIOR; CHANNEL,"In the hydraulically failed rock, a process zone where the natural fractures and the intergranular rock grain boundaries are activated while induced transgranular fractures are formed. These fractures in all scales share the drainage with the main hydraulic fracture. The objective of this study is to develop a novel approach thereafter to diagnose the evolutions of the critical above said microstructure properties at the post-fracturing state. In the previous work, we have examined the remarkable capability of image analysis on hydraulic fracture roughness determination (Gong and El-Monier, 2018). As an extension, this work introduces a fast and precise approach to study the aforementioned features of the post-fracturing core sample, including crack density, rock grain, and pore size distributions, by coding the desired image processing and analysis program. The hydraulic fracturing test was carried out using a Tennessee sandstone core sample and a sub-core of this fractured rock is excavated and polished (Patel et al., 2017). Its cross-section was subdivided into sequences and captured by the high-resolution SEM images after the ion-milling process. The post-fracturing grain size and pore size are investigated in the orthogonal direction of the main fracture at various locations and are compared to those from the literatures. The results from this study indicate that our proposed image analysis approach is capable to detect the grain damages resulting from the rock crushing. In addition, a positive relationship between the two parameters is found regardless of the cementing, packing mechanism, damage condition, and sorting of the fractured rock.",4,4,2
Fracture,Foam,"Luo, Xiangrong; Qi, Yin; Li, Jianshan; Huang, Penggang; Wang, Shuzhong; Ren, Xiaojuan; Zhang, Pengfei",Convection heat transfer and friction characteristics of liquid CO2-N-2 foam fracturing fluid using C4F9OCH3 as frother,Fracturing; Frother; Heat transfer; Fiction; Foam quality,THERMAL-CONDUCTIVITY; RHEOLOGICAL PROPERTIES; PERFORMANCE; FLOWS,"The liquid CO2-N-2 foam fracturing fluid containing C4F9OCH3 causes no damage to formation, similar to dry CO2 fracturing, can be used to stimulate water sensitivity and low-permeability gas reservoirs. The main objective of this experimental study was to ascertain the convective heat transfer and frictional characteristics of this modified dry fracturing fluid system. A foam fracturing fluid test system was adopted in this study. The results showed that the viscosity of the liquid CO2-N-2 foam fracturing fluid with C4F9OCH3 added was significantly higher compared with the liquid CO2-N-2. The optimum frother concentration was 0.65%. The shear rate had the most significant effect on the convective heat transfer. The pressure had a significant effect on the frictional characteristics of the complex foam fluid due to the compressibility of the internal and external phases. When the flow velocity was greater than 1.4 m/s, the frictional resistance coefficients for foams of different qualities were similar. The velocities in the expression of the generalized Reynolds number, Re', and the generalized Prandtl number, Pr', were not sufficient to describe the influence of the shear rate on the heat transfer. When fitting the convection heat transfer coefficient, the effect of shear rate on coefficient of thermal conductivity was also considered. These results can be used to calculate the temperature field and predict the friction pressure drop in the use of this foam fracturing fluid.",1,1,4
Fracture,Foam,"Fathollahi, Alireza; Rostami, Behzad; Khosravi, Maryam",Fluid displacement mechanisms by foam injection within a microfluidic matrix-fracture system,Enhanced oil recovery (EOR); Foam injection; Matrix-fracture micromodel; Viscous cross-flow; Effect of gravity force,OIL DISPLACEMENT; FLOW; TRANSPORT; TEMPERATURE; GENERATION; STABILITY; DRAINAGE; MODEL; GLASS,"In this study, the researchers visually investigated changes in the saturation of fluids and the oil recovery factor (RF) during foam injection in a two-dimensional matrix-fracture micromodel system. The effects of the 1) presence of oleic phase (comparison of the results of foam injection tests with and without oil), 2) viscous force (comparison of the results of foam and gas injection tests), and 3) gravity force (comparison of the results of gas/foam injection tests in vertical and horizontal states) were mechanistically studied. The results showed that the presence of oleic phase has the potential to cause foam to degrade at the beginning of the test. However, as the experiment advanced and oil saturation was reduced, foam injection resulted in the recovery of the fluid in the matrix. Pressure decline in the fracture due to the high viscosity of the foam acted as a driving force perpendicular to the fracture in the matrix and caused a viscous cross-flow leading to a dramatic increase in oil recovery. Although the gravity force reduced the foam stability due to the foam film drainage process and the gravity segregation of gas and surfactant solution, a comparison of the performances of gas and foam in the vertical state revealed the superiorly of foam injection.",4,4,2
Fracture,Foam,"Govindu, Abhishek; Ahmed, Ramadan; Shah, Subhash; Amani, Mahmood",Stability of foams in pipe and annulus,Foam stability; Bubble coarsening; Coalescence; Gravity drainage; Half-life; Foam quality,RHEOLOGICAL BEHAVIOR; DRAINAGE,"Foam fluids present numerous advantages for many oil field applications. Due to their bubble structure and a gaseous component, foams exhibit very high viscosity and low density. Low density makes foam an attractive fluid in underbalanced drilling operation in which light fluid is essential to maintain wellbore pressure below pore pressure. Due to its high viscosity, foam exhibits good hole-cleaning performance even at low annular velocities. Nevertheless, foams are thermodynamically unstable fluids and their structures eventually collapse. Foam decays as a function of time and the decay occurs mainly due to bubble coalescence and the gravity drainage of the liquid phase. Maintaining fluid stability is necessary for foam drilling. For a successful drilling operation, the half-life of foam, which is the time taken by foam to drain 50% of its liquid volume, should exceed circulation time. For other applications, such as hydraulic fracturing or cementing, the half-life of foam should exceed the time taken for fluid to reach target zones. In this study, foam stability experiments were conducted in a concentric annulus (50mmx75 mm) and 25 mm pipe sections. The pipe section was transparent to observe drained liquid level. Aqueous, polymer-based, and oil-based foams were considered in the investigation. The effect of gas volume fraction (quality) was studied under static condition. All experiments were performed at 400 kPa and ambient temperature (20 +/- 2 degrees C). Foam quality was increased from 40% to 80%. However, at high qualities (greater than 70%), the oil-based foam was unstable. Hydrostatic pressure data was collected from the annular section and converted into density curves to determine drained liquid volume. In the pipe section, the drainage was physically measured from the liquid level and recorded periodically. A digital camera with a microscope was used to capture foam image in real-time to examine bubble coarsening and foam decay. For a given quality, the polymer-based foam was the most stable, while oil-based foam was the least. For all three types of foams, stability increased with quality. Foams were more stable in the annular section, as compared to the pipe, possibly due to the impact of container wall on bubbles and drained liquid motion. Foam decay and bubble coarsening were observed by comparing bubble sizes in captured images at various times. On average, larger bubbles were observed in higher quality foams. The rate at which foam bubbles coarsening mostly reduced with time.",4,4,5
Fracture,Foam,"AlQuaimi, B., I; Rossen, W. R.",Characterizing foam flow in fractures for enhanced oil recovery,,,"Gas is used in displacing oil for enhanced oil recovery because of its high microscopic-displacement efficiency. However, the process at the reservoir scale suffers from poor sweep efficiency due to density and viscosity differences compared to in-situ fluids. Foam substantially increases the viscosity of injected gas and hence improves the sweep. Foam rheology in 3D geological porous media has been characterized both theoretically and experimentally. In contrast, the knowledge of foam flow in fractured porous media is far less complete. A companion paper (AlQuaimi and Rossen, 2017c), We focused on foam generation and propagation in a fully characterized model fracture. Here we focus on foam rheology in the same model fracture. This investigation is conducted by varying superficial velocities of gas and surfactant solution. We find in this model fracture the same two foam-flow regimes central to the understanding of foam in 3D porous media: a low-quality regime where pressure gradient is independent of liquid velocity and a high-quality regime where pressure gradient is independent of gas velocity. The transition between regimes is less abrupt than in 3D porous media. Our study directly relates flow regime to foam texture through observation of bubble size, bubble trapping and mobilization, and foam stability as functions of superficial velocities which allows comparison with our understanding of the mechanisms behind the two flow regimes in 3D porous media. Additionally, foam is shear-thinning in both regimes. However, the mechanisms thought to be behind the two flow regimes in 3D porous media do not appear in our model fracture. Foam is not at the limit of stability in the high-quality regime. Mobility in the high-quality regime, instead, reflects reduced and fluctuating foam generation at high foam quality. Moreover, bubble size is not fixed at approximately pore size, the mechanism thought to control the low-quality regime in 3D porous media. Instead, bubbles are much smaller than pores. Finally, for this model fracture, the investigation of vertical flow reaches the same findings as for horizontal flow, with somewhat lower pressure gradient.",5,6,1
Fracture,Surface Tension,"Phan, T. N.; Zapata, Y. M.; Kabir, C. S.; Pigott, J. D.; Pranter, M. J.; Reza, Z. A.",Probing hydraulically-fractured wells in unconventional shale reservoirs under cyclic CO2 injection: Variation of thermophysical properties,Unconventional reservoirs; CO2 cyclic injection; Exploring variation of thermophysical properties; Understanding injection-soaking-production cycles; Realistic oil recovery with large number of cycles; Molecular diffusion yields 6% incremental oil,OIL RESERVOIRS,"Despite the recent growth in oil production from unconventional reservoirs, existing hydraulically-fractured horizontal wells face challenges of poor recovery with the rapid production decline over a short life span. Enhanced recovery techniques, such as cyclic CO2 injection can be a solution to this impending problem and lead to energy independence for the foreseeable future. However, mechanisms occurring around the hydraulically fractured wells are far from fully understood. The primary motivation of this study revolves around addressing this limitation. Specifically, we explored the evolution of various thermophysical properties occurring around hydraulically-fractured wells in liquid-rich unconventional reservoirs using a holistic, integrated modeling framework. Available well-logs and other data from Howard County in the Midland Basin formed the basis for constructing representative 3D structural models that capture the Midland Basin stratigraphy. We used a simulator to create multistage hydraulic fractures that allowed integration into numerical reservoir-flow simulation models. Then, both convective and diffusive flow within a multicomponent compositional simulation modeling paradigm is used to examine the role of molecular diffusion in performance under cyclic CO2 injections in hydraulically-fractured well. The simulation results indicate that molecular diffusion yields an incremental oil recovery of 6% compared to models that do not. Our analysis reveals different thermophysical properties transition from near wellbore regions to outer regions into the rock matrix. Changes in total mole fractions of CO2, methane, and hydrocarbons with C7+ fraction, pressure and saturation variation, viscosity reduction and the surface tension over 14 injection-soaking-production cycles are tracked. The analyses of the evolution of these thermophysical properties provide us with means to evaluate the efficiency of the solvent injection process. The simulation results explain how, when, and where CO2 disperses into the reservoir.",0,0,0
Fracture,Surface Tension,"Gu, Jun; Gan, Pin; Dong, Lifei; Wang, Shuai; Tang, Naiqian",Prediction of water channeling along cement-aquifuge interface in CBM well: Model development and experimental verification,Coalbed methane; Water channeling; Cement-aquifuge interface; Prediction model; Verification,COALBED METHANE; QINSHUI BASIN; INRUSH; ADSORPTION; STRENGTH; FLUID; RISK,"Controlling water channeling (e.g. water inrush) is vital for coalbed methane (CBM) development In this work, the prediction models for bottom water channeling along cement-aquifuge interface (CAI) in CBM well were deduced to describe the time variation of water channeling at different stages during production. The prediction is focused on the evolution process characteristics of the bottom water channeling along CAI. The models indicate that the water channeling time is related to the differential pressure of both ends of channeling pathway, and the tortuosity of the channeling pathway, the height of bottom water channeling, fracture size of CAI, bottom water density, bottom water viscosity, bottom water surface tension, contact angle, bottom water dissolution time, permeability of mud cake before and after bottom water dissolution, and hole diameter. In order to verify the models, the simulation device was established independently. The experimental devices and methods are constructed to verify the prediction models. The results illustrate that the predicted results of the models are in good agreement with the experimental data. This study will provide a new insight into the solution of water channeling problem, which is common in the exploitation of CBM reservoirs.",1,2,3
Fracture,Surface Tension,"Su, Xianbo; Yao, Shun; Song, Jinxing; Wang, Qian; Li, Feng",The discovery and control of slug flow in coalbed methane reservoir,Coalbed methane reservoirs; Slug flow; Permeability; Surface tension; Differential pressure,MODEL,"Slug flow, which can cause severe velocity sensitivity damage to coalbed methane (CBM) reservoirs, tends to happen at the gas-liquid two-phase flow stage during the CBM production process. However, little attention has been paid to this phenomenon. This paper investigates the factors which can influence the forming of slug flow in CBM reservoirs systematically via a series of laboratory experiments and production data from two CBM wells. Results show that a slug flow is more likely to be formed under the conditions of high reservoir permeability, high fluid surface tension and high producing differential pressure. This is because that both the high permeability and high production differential pressure would lead to a high fluid flow velocity that can cause strong Kelvin-Helmholtz instability effect of the interface wave. Then, the strong Kelvin-Helmholtz instability effect will cause the slug flow. Meanwhile, a high fluid surface tension means that the liquid will form slug flow more easily. The most effective way to restrain slug flow is to utilize a fracturing fluid with low surface tension in combination with continuous, slow and stable productions.",4,5,3
Fracture,Surface Tension,"Amadu, Mumuni; Pegg, Michael J.",Analytical solution to spontaneous imbibition under vertical temperature gradient based on the theory of spontaneous imbibition dynamics,Spontaneous imbibition; Capillary pressure; Dimensionless time; Dimensionless distance; Equilibrium; Temperature gradient,CAPILLARY RISE; OIL RECOVERY; GRAVITY,"In this work, we have theoretically studied the imbibition process related to a block in a fractured carbonate reservoir under an assumed constant, vertical temperature gradient, G(T). An analytical solution to an ordinary differential equation we developed has been obtained using a computer program, and the original Washburn law normally valid for isothermal conditions of spontaneous imbibition has been found to hold true for G(T) equal to zero. The theoretical results of our study show that the space and time evolution of the imbibition front is strongly dependent on surface tension and dynamic viscosity of the imbibing fluid under a given temperature gradient. We have also validated our model against experimental data from a literature source based on spontaneous imbibition into a Hele Shaw Cell under longitudinal temperature gradient. The general conclusion of our study is that spontaneous imbibition in fractured carbonate reservoirs will be accelerated the higher the temperature of the injected water. This corresponds to a negative temperature gradient where the temperature of the injected water exceeds the ambient temperature of the reservoir.",5,4,3
Fracture,Bottom Water,"Prasun, Samir; Wojtanowicz, Andrew K.",Semi-analytical prediction of critical oil rate in naturally fractured reservoirs with water coning,Critical oil rate; Naturally fractured reservoirs; Semi-analytical; Water coning; Matrix well; Fracture well,FLUID-FLOW; PERMEABILITY; MODEL,"Naturally fractured reservoirs (NFRs) with bottom water are generally produced above their critical oil rate (maximum possible oil production rate without water breakthrough) that is difficult to determine as it varies between wells, depending on the well's location in the fracture network. In principle, wells can either be completed in matrix or fractures. Present formulas of critical-rate in NFR are oversimplified ignoring the network heterogeneity and anisotropy ratio of fractures, and they also do not consider the difference between on-fracture/off-fracture well completion placements. Presented is development of a new semi-analytical formula that considers these effects-with emphasis given to well placement assessment. The critical rate model is derived from mechanistic principles and then improved with statistical calibration. The mechanistic approach (Chaperon (1986)) considers vertical equilibrium of viscous and gravity forces for a hemispherical flow to a point-source well in a dual porosity/dual permeability model of naturally fractured reservoirs. The model considers the water cone instability, and anisotropy ratio of NFR only for a short-perforated completion interval. The model is tested for wide variety of NFRs for short completions. The model is then statistically calibrated to including the effect of long penetration ratio, using a designed matrix of simulated experiments covering wide ranges of NFR properties. This statistical approach allows the model to consider any change in flow regime from semi-spherical to non-radial distorted flow. The comparison of Chaperon's analytical model and NFR simulations shows that the model is good for NFRs for penetration ratio smaller than 0.35. For penetration ratio greater than 0.35, a new semi-analytical model of critical-rate for NFR is developed by statistically calibrating the Chaperon's analytical model. The new model considers the parameters ignored in the previous models of NFR. Finally, a new mechanistic derivation of critical rate for wells completed in matrix block of NFR is determined by analytically including the effect of well's distance to fracture in a critical rate formula for NFR. The model matches well with the simulated data when compared with it. The model shows that the wells accidently completed off-fractures may display higher values of critical rates and the difference relates to their distance to the nearest fractures. It is also shown that the offfracture well's formula reduces to the on-fracture well's formula when the distance is reduced to zero.",1,1,0
Fracture,Bottom Water,"Gu, Jun; Gan, Pin; Dong, Lifei; Wang, Shuai; Tang, Naiqian",Prediction of water channeling along cement-aquifuge interface in CBM well: Model development and experimental verification,Coalbed methane; Water channeling; Cement-aquifuge interface; Prediction model; Verification,COALBED METHANE; QINSHUI BASIN; INRUSH; ADSORPTION; STRENGTH; FLUID; RISK,"Controlling water channeling (e.g. water inrush) is vital for coalbed methane (CBM) development In this work, the prediction models for bottom water channeling along cement-aquifuge interface (CAI) in CBM well were deduced to describe the time variation of water channeling at different stages during production. The prediction is focused on the evolution process characteristics of the bottom water channeling along CAI. The models indicate that the water channeling time is related to the differential pressure of both ends of channeling pathway, and the tortuosity of the channeling pathway, the height of bottom water channeling, fracture size of CAI, bottom water density, bottom water viscosity, bottom water surface tension, contact angle, bottom water dissolution time, permeability of mud cake before and after bottom water dissolution, and hole diameter. In order to verify the models, the simulation device was established independently. The experimental devices and methods are constructed to verify the prediction models. The results illustrate that the predicted results of the models are in good agreement with the experimental data. This study will provide a new insight into the solution of water channeling problem, which is common in the exploitation of CBM reservoirs.",1,2,3
Fracture,Bottom Water,"Zhao, Jinsheng; Li, Tiantai; Shi, Yu; An, Chongqing; Liu, Yueliang",A new sinking agent used in water-control fracturing for low-permeability/bottom-water reservoirs: Experimental study and field application,Water-control fracturing; Low permeability; Bottom-water reservoirs; Barrier; Fracture height,MODEL,"Hydraulic fracturing is widely applied in tight reservoirs for hydrocarbon recovery. However, as for bottom water reservoirs, the created vertical hydraulic fractures can readily penetrate into the bottom-water layer, leading to a drastic increase of water cut when the pay-zones are too thin and the barrier lying between the pay-zone and bottom water are quite weak. In this work, a new sinking agent is used in hydraulic fracturing for water control in the low-permeability/bottom-water reservoirs. The settlement velocity and the plugging ability of this new sinking agent as well as the flow conductivity of the sinking-agent barrier is measured and compared with that of the other six commonly used sinking agents. We finally investigate the placement rule of the new sinking agent by varying the concentration of the carrying fluid and sand ratio in the modeling fracture. Filtration test show that this new sinking agent can form a barrier, which can strongly plug fracturing fluid. When the closure pressure range is in the range of 6.9 MPa-69.0 MPa, conductivity of the barrier formed by this new sinking agent is at a low level of 2.9 mu m(2)cm to 1.5 mu m(2)cm. With a given sand ratio and carrying-fluid concentration, the barrier formed in the fracture by the new sinking agent is more uniform than the other sinking agents. Based on the field application in a low-permeability/bottom-water reservoir, the usage of this new sinking agent increases oil recovery but decreases the water cut compared to other sinking agents.",3,3,2
Fracture,Pressure Loss,"Yao, L. M.; Liu, J. B.; Li, X. Y.; Yue, Q. B.; Liu, Y. X.; Wang, H. T.",Application of the building block approach to characterize the pressure loss of water and fracturing fluid in contraction-expansion pipe,Two-phase flow; Fracturing pipe; Proppant concentration; Experimental study,NON-NEWTONIAN FLUIDS; TURBULENT-FLOW; SUDDEN; BEHAVIOR,"In the fracturing pipeline, the contraction-expansion pipe structure is various. Accurate calculation of pressure loss can provide a theoretical support for the design of high sand ratio fracturing process parameter and tools selection. In this paper, the building block approach is used to describe the general framework for calculating the pressure loss of water in contraction-expansion pipe [D-1 not equal D-2, L-d/(D-1/2 + D-2/2) < 2.00] and expansion-contraction pipe (d(1) not equal d(2), L-D/D < 3.75). The drag ratio method was used to describe the pressure loss of the fracturing fluid based on the pressure loss of water in the contraction-expansion pipe and the expansion-contraction pipe. Finally, the calculation methods for the pressure loss of water and fracturing fluid were described. The data from the experimental test showed that the relative error was less than 15%. The experimental study of water in the contraction-expansion pipe showed that the pressure loss was positively correlated with the flow rate, but it was negatively correlated with the ratio of inlet-outlet diameter and the ratio of flow path length. And for the expansion-contraction pipe, pressure loss was positively correlated with the flow rate and ratio of flow path length. When the ratio of flow path length was close to 3.75, the ratio of inlet-outlet diameter was positively correlated with the pressure loss, and when the ratio of flow path length was close to 0.05, the ratio of inlet outlet diameter was negatively correlated with the pressure loss. Analysis of fracturing fluid in contraction expansion pipe and expansion-contraction pipe showed that the flow rate, proppant concentration and thickener concentration were positively correlated with pressure loss, and the drag rate of fracturing fluid reached 72%.",3,4,2
Fracture,Pressure Loss,"Liu, Houbin; Liu, Teng; Meng, Yingfeng; Han, Xu; Cui, Shuai; Yu, Anran",Experimental study and evaluation for borehole stability of fractured limestone formation,Fractured formation; Mechanical properties; Borehole stability; Collapse pressure; Fracture strike,MODEL,"With the increase of drilling depth, the stability of the borehole in deep fractured formation has received more and more attention. The exploration and development of fractured formations is difficult, because complex conditions such as borehole collapse, circulation loss, pipe-sticking occur frequently, causing huge economic losses and affecting the later drilling operations. Therefore, it is very important to study the stability of fractured formation. Observations of the microstructural characteristics and mechanics performance testing reveal the influence of fracture on the mechanical properties of limestone and enable the establishment of a model of collapse pressure as a function of fracture strike (the angle between the fracture and the maximum horizontal principal stress). The results showed that the fractures have great influence on the mechanical strength of rock and that the compressive strength of rock containing fractures is similar to 30% lower than that of bedrock on average. The influence of different fracture strikes on the stability of the borehole varies, with a maximum effect occurring for fracture orientation of 40 degrees-60 degrees. The model of fractured formation collapse pressure is consistent with the results of mechanical experiments. This research results provide a guiding value for stability studies of fractured formations.",3,5,3
Fracture,Pressure Loss,"Albattat, Rami; Hoteit, Hussein",Modeling yield-power-law drilling fluid loss in fractured formation,Lost-circulation; Loss of drilling fluid; Mud loss; Flow in fractured formation; Yield power law; Herschel-Buckley; Cauchy momentum equation; Fracture ballooning,MATERIAL SELECTION GUIDELINES; PERFORMANCE; FLOW,"Loss of circulation during drilling is a pressing problem that typically occurs when significant volumes of the drilling fluid leak to the surrounding formation. In fractured media, circulation loss is often a sudden event which may interrupt the drilling operations, increase nonproductive time, and add complexity in controlling the fluid flow and wellbore stability. Developing models to predict the fluid leak dynamics and identify the suitable loss-control-material (LCM) is of significant interest to the industry. In this work, simulation and analytical models are developed to model the dynamics of fluid loss for power-law drilling fluids from the wellbore to a surrounding fractured medium. The model is based on the Cauchy momentum equation and accounts for the key predominant flow mechanisms, including the non-Newtonian behavior of the drilling fluid (mud) using a power-law model. Experiments from the literature are used to assess the behavior of mud loss into a single horizontal fracture, which includes the effects of mud rheology and yield stress. We show that previous unsuccessful attempts to match the experimental data using analytical models are related to the assumption of uniform fracture aperture. Simulations are then used to demonstrate that a slight deformation in the fracture walls leads to a significant deviation in the analytical model predictions, and therefore the dynamics of fracture opening is a critical parameter that should be carefully assessed. In other related experiments, the analytical model also failed to capture the mud invasion distance within the fracture as a function of pressure drop and the mud properties. To address this issue, a modified analytical model that accounts for non-parallel fracture walls is proposed. The new model allows to quickly assessing the impact of nonuniform fracture apertures. It can serve as a screening tool to evaluate mud invasion distance as a function of fracture geometry, mud rheological properties, and pressure drop resulting from the well depth, injection rate, and mud density.",5,5,3
Fracture,Degrees C.,"Matias Paiva, Luanna Carla; Ferreira, Irantecio Mendonca; Martinelli, Antonio Eduardo; de Oliveira Freitas, Julio Cezar; Bezerra, Ulisses Targino",Milled basalt fiber reinforced Portland slurries for oil well applications,Basalt fiber; Oil well cement; Portland cement; Silica flour,MECHANICAL-PROPERTIES; SILICA FUME; CEMENT; CONCRETE; TEMPERATURE; STRENGTH; BEHAVIOR; MICROSTRUCTURE; PERFORMANCE; DURABILITY,"The dispersion of short fibers to oil well Portland slurries may improve the compressive strength and fracture energy of the hardened cementing material. A study was carried out to investigate the effect of the addition of ball-milled basalt fibers (5% BWOC) to Portland slurries. Samples were prepared with and without silica flour (40% BWOC) in the composition and cured for 7 days under different Bottom Hole Static Temperatures (BHST): 80 degrees C (176 degrees F) and 300 degrees C (572 degrees F). The mechanical properties and the microstructure of the hardened pastes were evaluated by compressive strength tests, X-ray diffraction and scanning electron microscopy. The results showed that milling basalt fibers was a cost efficient method to adjust the length of the basalt wool fibers assuring slurry mixing and, therefore, adequate pumpability. The combined addition of silica flour and basalt fibers improved the fracture energy of samples cured at 80 degrees C, therefore below the strength retrogression temperature. Curing at 300 degrees C resulted in significant fiber consumption by pozzolanic reactions that could not be prevented by the addition of silica flour. Therefore, ball-milled basalt fibers can be a cost-efficient and environmental-friendly solution to improve the mechanical properties of oil well cement slurries used below the retrogression temperature.",2,2,7
Fracture,Degrees C.,"Yuan, Lin; Wang, Yanling; Li, Qiang; Chen, Kai; Li, Yongfei",Evaluation of a control-released in-situ generated acid tablet for acid fracturing,In-situ generated acid; Controlled release; Matrix tablets; Acid fracturing,FORMALDEHYDE; CORROSION; MECHANISM; AMINES,"Acid fracturing is one of the common well stimulations techniques in carbonates. There are some limitations in conventional acid systems during the application, such as fast reaction of acid-rock, high leak-off rate and strong corrosion, that's why, the retarded acid systems, like gelled acids, are developed. In this work, a control-released in-situ generated acid matrix tablet is reported as a novel retarded acid system to overcome the above limitations. In the tablets, ammonium chloride and paraformaldehyde are used as active substances to generate hydrochloric acid (HCl), with high dissolving capacity of over 85% and excellent corrosion inhibition of more than 90% at 90 degrees C without inhibitors. A one-step and economic method is used to prepare the acid tablets by directly compacting the powder mixture of active substances. The dissolution rate of tablets is adjusted to control the release of acid, so that such form reduces the leak-off rate and slows the reaction of acid-rock. The simplicity of preparation process of the tablets along with excellent dissolution and corrosion inhibition makes the proposed acid tablets technique potential for the application in acid fracturing.",3,3,0
Fracture,Degrees C.,"Govindu, Abhishek; Ahmed, Ramadan; Shah, Subhash; Amani, Mahmood",Stability of foams in pipe and annulus,Foam stability; Bubble coarsening; Coalescence; Gravity drainage; Half-life; Foam quality,RHEOLOGICAL BEHAVIOR; DRAINAGE,"Foam fluids present numerous advantages for many oil field applications. Due to their bubble structure and a gaseous component, foams exhibit very high viscosity and low density. Low density makes foam an attractive fluid in underbalanced drilling operation in which light fluid is essential to maintain wellbore pressure below pore pressure. Due to its high viscosity, foam exhibits good hole-cleaning performance even at low annular velocities. Nevertheless, foams are thermodynamically unstable fluids and their structures eventually collapse. Foam decays as a function of time and the decay occurs mainly due to bubble coalescence and the gravity drainage of the liquid phase. Maintaining fluid stability is necessary for foam drilling. For a successful drilling operation, the half-life of foam, which is the time taken by foam to drain 50% of its liquid volume, should exceed circulation time. For other applications, such as hydraulic fracturing or cementing, the half-life of foam should exceed the time taken for fluid to reach target zones. In this study, foam stability experiments were conducted in a concentric annulus (50mmx75 mm) and 25 mm pipe sections. The pipe section was transparent to observe drained liquid level. Aqueous, polymer-based, and oil-based foams were considered in the investigation. The effect of gas volume fraction (quality) was studied under static condition. All experiments were performed at 400 kPa and ambient temperature (20 +/- 2 degrees C). Foam quality was increased from 40% to 80%. However, at high qualities (greater than 70%), the oil-based foam was unstable. Hydrostatic pressure data was collected from the annular section and converted into density curves to determine drained liquid volume. In the pipe section, the drainage was physically measured from the liquid level and recorded periodically. A digital camera with a microscope was used to capture foam image in real-time to examine bubble coarsening and foam decay. For a given quality, the polymer-based foam was the most stable, while oil-based foam was the least. For all three types of foams, stability increased with quality. Foams were more stable in the annular section, as compared to the pipe, possibly due to the impact of container wall on bubbles and drained liquid motion. Foam decay and bubble coarsening were observed by comparing bubble sizes in captured images at various times. On average, larger bubbles were observed in higher quality foams. The rate at which foam bubbles coarsening mostly reduced with time.",4,4,5
Fracture,Cross Section,"Herrera, Maria S.; Ortiz, Alberto; Hryb, Damian; Rendtorff, Nicolas M.",Detectability of smart proppants traced with gadolinium and samarium in the Vaca Muerta formation,Vaca Muerta formation; Traceable proppant; Samarium oxide; Gadolinium oxide; Thermal neutron capture cross section; MCNP; 2010 MSC; 82D75; 65C05,BALL CLAY; PLACEMENT; BEHAVIOR; OXIDE,"The use of smart proppants traced with gadolinium and samarium was evaluated in a realistic model by Monte Carlo simulations. The addition of compounds with high thermal neutron capture cross section, such as gadolinium oxide (Gd2O3) and samarium oxide (Sm2O3) into ceramic proppants, makes them detectable after placement in induced fractures. Proppants traced with different oxide concentrations were studied in a generic borehole-formation-tool configuration, modeled with MCNP. The Vaca Muerta formation model was constructed based on measured geochemical data. A theoretical formation of water-saturated limestone with 20% porosity was also used as a reference case of study. The minimum concentration of gadolinium and samarium oxides needed, in order to make them detectable by logging tools, was determined. In the case of gadolinium, results are in agreement with previous reported values for Gd2O3 addition of about 0.4% by weight of proppant. In the case of samarium, a minimum concentration of 1.25% by weight of Sm2O3 addition could be detected in both Limestone and Vaca Muerta formations.",2,2,0
Fracture,Cross Section,"Wang, Dongying; Wang, Zhiming; Zeng, Quanshu",An experimental study on gas/liquid/solid three-phase flow in horizontal coalbed methane production wells,Gas/liquid/solid three-phase flow; Coalbed methane; Horizontal well; Flow pattern; Height of coal particle bed; Explicit equation,SAND-DEPOSITION VELOCITY; RESERVOIR ROCKS; LIQUID; GAS; PARTICLES; TRANSPORT,"Coal particles caused by well drilling and completion, hydraulic fracturing, and formation pressure decreasing would migrate into the horizontal well carried by fracturing flow-back fluid, formation water and CBM, and then deposit on the low side of pipe leading to the decrease of cross section area of pipe for flow and even blocking of the pipe. The purpose of current research was to obtain the flow pattern while there was stationary solid particle bed on the low side of the pipe and an explicit equation to predict the height of solid particle bed was proposed. In this study, with the coal particle, water, and air as the solid, liquid, and gas phases respectively, gas/liquid/ solid three-phase flow experiments in horizontal well were carried out and 4 crucial factors including different water flow rate, gas flow rate, coal particle size, and coal particle mass concentration were considered. Fluid's real apparent velocity was defined and used to analyze the distribution of flow pattern coordinate points. Results show that the flow pattern coordinate points determined by real gas apparent velocity and real water apparent velocity distribute near the flow pattern transition lines of Taitel and Dukler flow pattern map. Besides, coal particle size, water flow rate, and gas flow rate have obvious impact on the height of coal particle bed and the coal particle mass concentration has a negligible effect while the height of interface between gas layer and water layer is only dramatically affected by the gas flow rate. At last, an explicit equation for predicting the cross section area of coal particle bed based on the experimental data was proposed which is crucial to predict the flow pattern and calculate the pressure drop in horizontal well. The predicting cross section area of coal particle bed is in good agreement with the measured cross section area of coal particle bed and the average relative differences are 9.38% and 13.45% for stratified smooth flow and stratified wavy flow respectively. The equation is applicable for a range of coal particle size (8-30 mesh) and water apparent velocity (0.025-0.123 m/s).",2,2,4
Oil Recovery,Water Flooding,"Mukhamatdinov, Irek I.; Aliev, Firdays A.; Acosta, Anabel Sosa; Vakhin, Alexey V.",A new approach for measuring rheology of polymer solutions in reservoir conditions,Polymer; Polyacrylamide; Rheology; Wettability; Interfacial tension,ENHANCED OIL-RECOVERY; HEAVY OIL; WATER; NANOPARTICLES; SURFACTANT; ADSORPTION; NETWORKS,"The simulation of flow processes under reservoir condition is a hard task. Viscosity of polymer solution in porous media depends on adsorption of polymers on mineral substrates. Specific features characterize filtration of polymer solutions in porous media. Here, we propose a new approach to evaluate the rheology of polymers that considers fluid interactions with mineral surfaces. The principle of this method is as follows: measuring viscosity of ""mineral-in-polymer"" suspension. Hence, this approach needs simple equipment rather than complex core flooding system. The laboratory selection of effective polymer and its optimum concentration is carried out by the proposed approach. It is crucial for primary screening of some polymers. The presence of dispersed minerals in model suspensions influences the surface tension between the polymer solution and solid surface with various chemical nature. In order to justify this method, we used minerals with different chemical nature such as dispersed calcite and dolomite, and two widely used polyacrylamide type polymers that differ in molecular masses. We observed that viscosities between various suspensions differ several times due to the surface nature. We also determined the correlation between the viscosity of model suspension and contact angle. The latter is determined by chemical nature of minerals.",0,0,1
Oil Recovery,Water Flooding,"Nekoeian, Sahand; Aghajani, Masoud; Alavi, Seyed Mehdi",Experimental study of the surfactants effects on gas phase mass transfer coefficients in gas condensate reservoirs,Gas condensate reservoirs; Local equilibrium assumption; Gas phase mass transfer coefficients; Surfactants; Specific interfacial area; Spreading coefficients,ORGANIC-CHEMICALS; POROUS-MEDIA; WETTABILITY ALTERATION; LIQUID VOLATILIZATION; THERMAL-DIFFUSIVITY; DISSOLUTION; RECOVERY; OIL; CONDUCTIVITY; TRANSPORT,"Surfactant flooding in gas-condensate reservoirs, shown to be an effective treatment method to remediate condensate blockage in near well bore regions, have been the focus of several studies in the recent decades. However, the effect of these chemicals on the gas phase mass transfer coefficients has not been yet addressed though they have to be incorporated in non-equilibrium compositional simulators to imitate the reservoir behavior reliably. Besides, any knowledge of the overall effect of the surfactants on these coefficients can shed light on the side effects of the surfactant flooding on mass transfer phenomenon and evaluate its suitability as a treatment strategy. In this study, separate empirical correlations were developed for methane and isobutane representing light and intermediate components respectively in the absence and the presence of surfactants at the temperature of 40 degrees C. In all the developed correlations for both components in the presence of surfactants, while spreading coefficient has a positive exponent, equilibrium adsorption constant possesses a negative exponent. This implies that surfactants with a larger former parameter and a smaller latter parameter like SDS have more opportunity to enhance the volumetric mass transfer coefficient. The results also confirm the positive effect of pore gas velocity on gas phase mass transfer coefficients even in low gas flow rates. Similarly, this effect has already been reported in NAPL (Non Aqueous Phase Liquid) volatilization related studies. Effective diffusion coefficient, condensate saturation, mean grain size, component type, surfactant type and residual water saturation were also shown to affect these mass transfer coefficients. In addition, it has been shown that surfactants which are conventionally believed to reduce volumetric mass transfer coefficients in gas-liquid systems like bubble columns, improve gas phase mass transfer coefficients in gas condensate reservoirs. This improvement is considered a drawback for the cited technique.",0,0,1
Oil Recovery,Water Flooding,"Kim, Tae Wook; Vittoratos, Euthymios; Kovscek, Anthony R.",Recovery efficiency of a 28 degrees API crude-oil system as a function of voidage replacement ratio,Water flooding; Voidage replacement; Laboratory studies; Improved oil recovery,SOLUTION-GAS DRIVE; RELATIVE PERMEABILITY,"Crude-oil recovery processes with a voidage replacement ratio (VRR = injected volume/produced volume) less than 1 combine solution gas drive mechanisms and viscous crude-oil displacement. Previous laboratory and field studies have shown that a VRR less than 1 for a period of time is optimal for recovery of some viscous and heavy crude oils that form emulsions and/or bubbly oil in situ. This study extends understanding of the effect of VRR to recovery of live, less-viscous crude oils from sands. The crude oil used is roughly 28 degrees API, has a dead-oil viscosity of 26 cP, a live-oil viscosity of 0.41 cP, and an asphalt content of 2.1 wt%. It is found in the laboratory that the final crude-oil recovery (70.5%) using a 0.01 PV/h depletion rate and VRR equal to 0.7 is more than 8% greater than recovery with VRR equal to 1 (65.1%). Recovery using a 0.001 PV/h depletion rate with VRR equal to 0.7 (79.1%) was nearly the same as the sum of oil recoveries for solution gas drive (VRR = 0, 24.5%) plus waterflooding (VRR = 1, 53.4%). For these two depletion rates, the oil recovery obtained using VRR equal to 0.7 is more favorable than VRR = 1 (waterflooding). Relative permeability was inferred from experimental results. Substantial critical gas saturations (8.1-16.1%) also contributed to oil production. A concave shape of the oil/water relative permeability curve indicated an emulsion-like effect that also promoted recovery when the VRR was less than 1.",1,1,0
Oil Recovery,Water Flooding,Wang Tianyuan; Yu Li; Xiu Jianlong; Huang Lixin; Cui Qingfeng; Ma Yuandong,A mathematical model for microbial enhanced oil recovery considering the double-bacterial competition mechanism,Microbial enhanced oil recovery; Mathematical model; Double-bacterial; Competition,,"Considering the influence of reservoir on microbial growth and the competition of microbial community on nutrition, a mathematical model for microbial enhanced oil recovery considering the double-bacterial competition mechanism is established. The components of this mathematical model consist of oil, water, microbe 1, microbe 2, nutrients, metabolite) and metabolite2. The equations of this numerical model take into account the decay and growth of microorganisms, nutrient consumption, metabolism production, chemotaxis, convection-dispersion, water viscosity increment, oil viscosity reduction, interfacial tension reduction, adsorption, and desorption. In this study, three numerical examples were performed to analyze the double-bacterial competition mechanism and the effects of product interaction on improving oil recovery through a simulator developed according to our mathematical model. We found that (1) Under different double-bacterial growth models (symbiotic effect, repressive effect and no effect), there is a big difference in product concentration and oil displacement efficiency; (2) Double-bacterial growth model can better simulate actual reservoir application of microbial flooding technology than single microbial model; (3) Double-bacterial growth model with different products can increase oil recovery by up to 12.3% compared with water flooding.",1,3,2
Oil Recovery,Water Flooding,"Zampieri, M. F.; Quispe, C. C.; Moreno, R. B. Z. L.",Model upsizing for integrated evaluation of polymer degradation and polymer flooding lab data,Enhanced oil recovery; Polymer flooding; Simulation; Polymer degradation; Model upsizing,ENHANCED OIL-RECOVERY; SURFACTANT,"In oil recovery operations through polymer flooding, it is essential that the polymer maintains its stability until near the producer well, avoiding degradation phenomena. The present paper seeks to assess the representation of the degradation effects associated with polymer flooding for heavy oil recovery through one-dimension simulation models with different sizes. Base models were developed using data from the literature and previous lab work. The models consider adsorption, accessible pore volume, residual resistance factor, polymer concentration and non-Newtonian effects. Aiming at including degradation effects, a methodology of model size increase was developed, allowing to combine the evaluation of long-term dependent effects with displacement mechanisms. A sensitivity analysis was performed for the degradation, considering four levels of polymer half-life time. The lab-scale models were submitted to an upsizing procedure, generating models 100 times and 10.000 times bigger. The outcomes showed that the higher the level of the reaction frequency factor, the faster the degradation process. In the presence of original and degraded polymers in the porous media, we observed two advance fronts. The front of the degraded polymer advanced faster for a higher reaction frequency factor, while the advance front of the original polymer was delayed. We analyzed the results in terms of cumulative produced water, cumulative produced oil, average pressure, oil recovery factor, cumulative mass of the injected polymer, cumulative mass of the degraded polymer, water phase saturation, and water phase viscosity. The procedure for model upsizing was matched using a linear scaling factor. The method permits parameters found in laboratory experiments to be simulated in field-scale. Normalized results allowed comparing the impact of the main physical phenomena related to polymer flooding in the mentioned results, independent of the model size.",3,3,0
Oil Recovery,Water Flooding,"Gao, Shuai; Chen, Shumin; Pu, Hui; Gong, Lei; Ma, Shizhong; Luo, Qingyong; Wang, Xixin; Gao, Ang; Zhang, Binchi","Fine characterization of large composite channel sandbody architecture and its control on remaining oil distribution: A case study of alkaline-surfactant-polymer (ASP) flooding test area in Xingshugang oilfield, China",Composite channel; Sandbody architecture; Lateral accretion deposits; Tracer test; Remaining oil; Songliao basin,RESERVOIR; RECOVERY; STORAGE; BASIN,"Lateral accretion deposit, the most critical element in channel sandbody architecture, significantly affect the distribution of remaining oil in the middle and late development phases of oilfields. However, the lateral accretion deposits in a composite channel sandbody are extremely thin and small, complicating the identification through log data. In this regard, the fine characterization of sandbody architecture is an effective alternative, which can further guide the evaluation of the remaining oil distribution in composite channels. In this paper, illustrated by an example of the alkaline-surfactant-polymer (ASP) flooding test area of Xing 12 block in Daqing oil field, China, a fine characterization method of the sandbody architecture of large composite channel was proposed. Integrated with the production data, the influence of the lateral accretion deposits of the sandbody on the direction and uniformity of waterflooding was analyzed, and the distribution pattern of the remaining oil controlled by sandbody architecture was discussed. The results show that, although the sandbodies in the large composite channel seem to have characteristics of connectivity and efficiency as a whole, the sandbody is only an apparent connecting body in reality. Due to the complicated contact relationship of the various architectural elements at all levels and stages, and the existence of low permeability barriers, for instance, thin lateral accretion beds and abandoned channel, the sandbodies of the large composite channel are not completely connected. The fifth and third level of architectural interfaces in the sandbody architecture of large composite channels control the frame of non-permeable lateral accretion deposits. Blocked by these lateral accretion deposits, the thickness of watered out reservoirs decreases along the lateral accretion direction, in which the bottom of the point bar is watered out severely. Hence the remaining oil is mainly distributed in the middle and upper parts of the composite channels, the inter-channel sands where the production and injection wells are imperfect, as well as the edge of channels. Under the control of the sandbody architecture of large composite channels, three types of remaining oil were determined: remaining oil blocked by lateral accretion units, remaining oil blocked by abandoned channel and remaining oil located at the edge of the channel with poor petrophysical properties.",3,3,1
Oil Recovery,Water Flooding,"Ziabakhsh-Ganji, Zaman; Nick, Hamidreza M.; Bruhn, David F.",Investigation of the synergy potential of oil and geothermal energy from a fluvial oil reservoir,Geothermal energy; Thermal enhanced heavy oil recovery (TEOR); Heterogeneity; Net to gross (N/G); Net present value (NPV),HEAT-RECOVERY; HOT-WATER; HETEROGENEITY; CONNECTIVITY; PERFORMANCE; FLOW; INJECTION; EXPLOITATION; AQUIFER; SYSTEM,"Geothermal projects, as renewable energy projects, are not economically attractive in most places of the world at the current state of development; for this reason, subsidies are required by energy and environmental authorities in order to increase the interest in such projects. In this paper, we assess and model strategies for integration of geothermal energy with oil productions of the Moerkapelle oil field in the Netherlands. To do so, numerical simulations have been employed to analyse the feasibility of a fluvial oil reservoir for the synergy potential of oil and geothermal energy exploitation. In order to implement the simulation studies, single phase and two-phase non-isothermal fluid flow modelling are utilized for the geothermal well doublet system and for water flooding in an oil reservoir (including facies heterogeneity), respectively. A series of simulations have been conducted to investigate how hot water from a geothermal reservoir beneath a heavy oil reservoir in the fluvial sedimentary system of the West Netherlands Basin can be used for Thermal Enhanced Oil Recovery (TEOR) and geothermal energy production. This study finds that the high degree of heterogeneity in fluvial oil reservoirs could significantly affect oil recovery improvement and hence the synergy strategy. High values of a) Net to gross (N/G) b) Bottom Hole Pressure (BHP) and c) horizontal wellbore length are favourable for oil recovery. In contrast, wide horizontal wellbore spacing and high oil viscosity have an adverse effect on oil recovery enhancement. Furthermore, the results display that the enhanced oil production helps to reduce the required subsidy for a single doublet geothermal project up to 100%. Consequently, the extra amount of oil produced by utilising the geothermal energy, could make the geothermal business case independent and profitable.",3,3,1
Oil Recovery,Water Flooding,"Han, Lihong; Yin, Fei; Yang, Shangyu; Liu, Wei; Deng, Yong",Coupled seepage-mechanical modeling to evaluate formation deformation and casing failure in waterflooding oilfields,Well integrity; Waterflooding; Formation deformation; Casing failure; Coupled model,WATER INJECTION; FLUID; RESERVOIR; STORAGE; SLIP,"Waterflooding implemented to enhance oil recovery could concomitantly induce formation deformation and casing failure. The adverse responses should be evaluated to ensure the safety and performance of wells. A coupled seepage-mechanical model is developed to analyze the responses of formation and wells in waterflooding oilfields. The fluid-solid coupling method is employed to capture the flow and deformation in interlayers. The behavior of casing is predicted from the mechanical interaction among the wellbore-cement sheathcasing system. This model is validated by the analytical result. Results indicate that injection-production unbalance causes nonuniform pressurization or depletion in formation. Under pressurization, the vertical displacement along wellbore increases with the increases of axial position and time and displays a sharp rise in mudstone layer. There is an offset in mudstone layer. Casing stress increases under continuous pressurization or depletion, and stress concentration occurs in the mudstone interval. The predicted casing yield situation is consistent with the failure location in oilfield. The incongruous displacement in mudstone is the mechanism of casing deformation. Sustaining injection-production balance and adopting no-cementation operation are the possible strategies for mitigating the adverse effects of waterflooding. The findings can be applied to evaluate and manage formation response and casing integrity in waterflooding oilfields.",3,3,2
Oil Recovery,Water Flooding,"Li, Yi-Long; Wu, Feng; Li, Xiao-Ping; Tan, Xiao-Hua",Experimental study on waterflood development in large-scale karst structures,Karst structure; Waterflood experiment; Large-scale three-dimensional physical model; Two-phase flow of oil/water,FLUID-FLOW; PERMEABILITY; SIMULATION,"On the basis of the seismic data volume of a certain well group unit of the Tahe fracture-vuggy reservoirs, the similarity theory is adopted, and a numerical model with geometric, kinematic, dynamic, and fracture-cavity characteristic parameter similarities is designed. Moreover, a large-scale three-dimensional physical karst cave model is built with the carving technology. The model is used in the experimental study of two-phase flow of oil/ water during waterflood development and in the analysis of relevant influencing factors. Results show that the displacement efficiency of low-high mode is obviously superior to the case of high-low mode. A high crude oil viscosity is found to equate to a low ultimate recovery. High-velocity water flooding improves ultimate recovery but results earlier water breakthrough. Well shutdown improves recovery factor and well shutdown during middle water cut stage achieves optimum effects. Bottom water energy benefits oil reservoir exploitation to some degree.",3,3,2
Oil Recovery,Water Flooding,"Ahmadi, Pouyan; Shahsavani, Behnam; Malayeri, Mohammad Reza; Riazi, Masoud",Impact of different injection sites on the water and oil exchange in a fractured porous medium for different polymers: A visual study,Viscosity; Shear rate; Polymer injection; Recovery factor; Water flooding; Fractured medium,GRAVITY CURRENTS; FLOW; RHEOLOGY; FLUID; CARBOXYMETHYLCELLULOSE; POLYACRYLAMIDE; IMBIBITION; BEHAVIOR,"This study aimed at investigating the impact of injection sites including i) matrix and ii) fracture when polymers of PVA, PAM, and CMC are injected at different concentrations within a fractured medium. The experimental results showed that PAM for all concentrations had a high recovery factor (RF) when its injection site is matrix and also at low concentrations. PAM has performed better due to its higher viscosity as well as its high capillary pressure in water-wet condition. In different pore sizes, the amount of shear rate that will be applied to the polymers will vary, which is why in the case of PAM injection in the fracture, the tendency of polymer to penetrate through the grains is more than fracture. CMC at low concentrations of 100 and 1000 ppm cannot wash the oil effectively. However, for a concentration of 5000 ppm, it has maximum breakthrough time as well as the maximum RF of 96% and 83% when it is injected via the matrix and fracture, respectively. These efficiencies are approximately 15% and 10% higher than that of PAM although PAM is more viscous of nearly threefold. PVA can ultimately sweep 12% of the OOIP when its 5000-ppm solution is injected from the matrix.",4,4,0
Oil Recovery,Water Flooding,"Liu, Changwei; Li, Kewen; Tian, Xiaoming; Zhao, Guoxiang; Chen, Youguang; Mahlalela, B. M.",Experimental studies on production performance of oil reservoirs with bottom water,Bottom-water reservoir; Horizontal well; Physical model; Optimal production pressure,LEG,"Water coning is a major problem in oil reservoirs with bottom water. It reduces the oil production and overall oil recovery. Excessive water production causes corrosion problems in production facilities and increases the cost of water disposal. This may cause the early shutdown of oil wells. In this study, an experimental apparatus has been designed and developed to physically model an oil reservoir with bottom water. The reservoir model was transparent and the change in water coning could be visualized. Many water-flooding tests were conducted at different pressures and oil viscosities ranging from 22 to 260 mPa s. The effects of production pressures and oil viscosity on oil production were investigated. The results indicated that for a medium oil viscosity of 74 mPa s, the optimal production pressure was about 0.054 bar. For minimum and maximum oil viscosity (22 mPa s and 260 mPa s), the smaller the production pressure, the larger the water breakthrough time and oil recovery. Five types of flooding characteristic curves were used to characterize the water-cut variation, and their applicability were compared and analyzed. The water drive curves were fitted using the water-cut models and the oil ""reserves"" (originally placed in the reservoir model) were predicted using the mathematical models with the experimental data. The results indicated that the Maksimov model of water-drive characteristic curve is more suitable to match the water production performance. Most interestingly, when applying the most suitable model Maksimov water-drive characteristic curve to predict oil reserves, the cases with optimal production pressures have a greater accuracy.",5,5,0
Oil Recovery,Water Flooding,"Sanaei, Alireza; Varavei, Abdoljalil; Sepehrnoori, Kamy",Mechanistic modeling of carbonated waterflooding,,WATER INJECTION; CO2 SOLUBILITY; SIMULATION,"CO2 enhanced oil recovery is usually affected by poor sweep efficiency due to unfavorable mobility contrast between the injected CO2 and oil. To alleviate this problem, CO2 is added to the injected brine and transported in the reservoir by flood water. Therefore, Carbonated Water Injection (CWI) takes advantage of both CO2 and water flooding processes. Furthermore, geochemical reactions between the injected carbonated brine and rock can alter petrophysical properties of the reservoir and affect final oil recovery. While there are several CWI coreflood experiments reported in the literature, simulation studies for this process are scarce. Accurate modeling of CWI performance requires a simulator with the ability to capture true physics of the CWI process. In this study, a compositional reservoir simulator developed at The University of Texas at Austin, UTCOMP, coupled with a state-of-the-art geochemical package developed by United States Geological Survey, IPhreeqc, is used to model CWI process. We considered the impact of CO2 mass transfer between brine and hydrocarbon phases based on thermodynamic constrains at the reservoir condition. In order to validate our simulation approach, the results of our CWI simulations were compared with a recently published coreflood experiment. Moreover, we investigated the fluid-rock interactions in CWI. The results of the simulations, indicated that prior to water breakthrough the main drive mechanism is displacement. But as more carbonated water is injected, CO2 diffuses more into the trapped oil left behind, which results in oil swelling and subsequent oil viscosity reduction. Moreover, reaction of carbonate minerals such as calcite with carbonated brine results in dissolution of the main rock matrix which consequently creates wormholes similar to carbonates acidizing. In this study we propose a novel approach for accurate modeling of carbonated waterflooding process. The results of this study highlight the importance of geochemical reactions in modeling CWI process. Our approach has been validated based on history matching at the backdrop of a recently published coreflood experiment.",5,5,1
Oil Recovery,Water Flooding,"Al-Khafaji, Arije; Wen, Dongsheng",Quantification of wettability characteristics for carbonates using different salinities,Low salinity flooding; Enhanced oil recovery; Carbonate reservoir; Wettability; Interfacial tension; Adhesion force,OIL-RECOVERY; CRUDE OILS; INTERFACIAL ACTIVITY; SMART WATER; INJECTION; BRINE; IONS; ASPHALTENE; RESERVOIR; TENSION,"Low salinity water flooding has received strong interest recently. It has been reported that injecting low salinity water can improve oil recovery in carbonate reservoirs through wettability alteration, whose mechanism however remains unclear, especially regarding the contributions from adsorbed polar organic components. This work investigates systematically the key parameters that govern the complex interactions of rock/brine/crude oil in carbonate reservoirs. The effects of crude oil composition and salinity on surface wettability alteration are studied by using three types of dead oil from Norwegian and North Sea with various acid numbers and two types of carbonate rocks (outcrop-calcite and subsurface-dolomite). Ion-substitution-adsorption is evaluated using the infrared spectrometer (IFR) and energy-dispersive X-ray spectroscopy (EDX). Oil/brine interactions by means of the interfacial tension (IFT) and contact angle as a function of oil composition, rock type, and salinity are experimentally investigated. The IFR and EDX data indicate a compositional change when the carbonate minerals are in touch with saline solutions, supporting the proposed rock-brine interaction mechanism. The salinity effect is more salient at the liquid/rock interface than the liquid/liquid interface, and the response to the brine composition is highly dominated by the oil composition with respect to its content of polar organic components. There is a reduction of contact angle as the seawater water is diluted twice while its influence on the IFT is small, and the effect is more pronounced for dolomite rock, showing different results for different crude oils used. This suggests that the wettability alteration of carbonate rock is an intricate phenomenon that is influenced not only by the salinity but also by the chemical composition of crude oil and rock mineralogy. A combination of three possible mechanisms, including multiple ion exchange, EDL expansion (electrokinetics repulsive), and salting-out, is discussed to illustrate the mechanism of wettability alteration during low salinity injection.",5,6,1
Oil Recovery,Water Flooding,"Orrego-Ruiz, Jorge A.; Medina-Sandoval, Camila F.; Castillo Hinds, Carmen; Villar-Garcia, Alvaro; Rojas-Ruiz, Fernando A.",FT-ICR MS determination of the role of naphthenic acids on the stabilization of alkali/surfactant/polymer emulsified effluents: A field study,Microemulsions; Enhanced oil recovery; ASP flooding; Surfactants; Emulsion stability; FT-ICR MS,ENHANCED OIL-RECOVERY; RESONANCE MASS-SPECTROMETRY; INTERFACIAL-TENSION; PHASE-BEHAVIOR; CRUDE OILS; SURFACTANT; ASPHALTENES; ADSORPTION; STABILITY; EMULSIONS,"Numerous Alkali/Surfactant/Polymer flooding (ASP) projects have been developed worldwide. Nevertheless, some disadvantages have limited the success of ASP during the execution in field, such as injection lines scaling and strong emulsification of the produced fluids. Commonly, appropriate formulations for particular reservoir conditions are selected after a series of evaluation steps. These includes tests of surfactants, polymers and commercially available alkali, based on the reservoir temperature, reservoir salinity, reservoir water pH, rock permeability, formation type and adsorption of the surfactant on the matrix rock, to obtain the highest oil recovery at the lowest cost. As part of the different strategies adopted for increasing the oil recovery factor, San Francisco oil field, Huila Colombia, was selected in 2012 for ASP flooding application at pilot scale. After two years of injection, ASP effluents affected considerably the quality of water and its treatment for reinjection. The present work focuses on the compositional study of the production effluents obtained after ASP flooding. A detailed analysis using Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) allowed disclosing the role of natural organic acids on reducing the interfacial tension which in turn entailed highly stable microemulsions. Together with the added surfactant, naphthenic acids (because of the alkaline pH) prompts the formation of these thermodynamically stable oil in water systems. A test using an acid free oil proved that the formation of microemulsions strongly depends on naphthenic acids presence. Additional tests using oils with different acidity showed the dependence on the naphthenics acids structure over the emulsion stability. The results obtained in this study stands out FT-ICR MS as a prominent tool on understanding breaking and/or clarifying treatment processes from a molecular level point of view and thus, could help on proposing a correct and cost effective water treatment.",5,5,2
Oil Recovery,Water Flooding,"Du, Qingjun; Hou, Jian; Zhao, Fan; Zhou, Kang; Liu, Wenbin; Liu, Yongge",A new organic fiber composite gel as a plugging agent for assisting CO2 huff and puff in water channeling reservoirs,CO2 utilization ratio; Organic fiber composite gel; Water channeling reservoir; Real rock plate experiment; Numerical simulation,ENHANCED OIL-RECOVERY; DIFFUSION-COEFFICIENTS; N-PUFF; CARBON-DIOXIDE; INJECTION; PERFORMANCE; SIMULATION; PROPANE; METHANE; SHALE,"The utilization of CO2 for enhancing oil recovery is an environmentally friendly way to dispose the industrial CO2 emissions. CO2 utilization ratio is defined as the volume ratio of produced oil to injected CO2. CO2 huff and puff technology can further improve oil recovery in high water cut reservoirs. However, as the huff and puff cycle increase, gas channeling is easy to happen and the utilization ratio of CO2 is reduced. Organic fiber composite gel is an effective plugging agent for gas channel. The major objective of this paper is to study the mechanisms of increasing CO2 utilization by injecting organic composite gel as the plugging agent. A large scale (40 cm*40 cm*3 cm) natural rock model with grooves is used to simulate the experimental conditions such as channeling channel and horizontal well. Two groups of experiments of direct CO2 huff and plugging agent assisted CO2 huff and puff were conducted. By comparing the pressure changes during the experiments, the mechanism of blocking the channel, balancing the CO2 displacement front and improving the utilization ratio of CO2 were analyzed. The experimental process was fitted by reservoir numerical simulation, and the remaining oil distribution, plugging agent distribution and CO2 distribution in CO2 huff and puff under different conditions were further demonstrated. Results show that compared with direct CO2 stimulation, the distribution of remaining oil saturation and reservoir pressure become more uniform and the utilization ratio of CO2 is greatly increased after injecting organic fiber composite gel. It is mainly due to the fact that the injected plugging agents flow preferentially into high water saturation region along the high permeability channels. Then, they can generate the organic fiber composite gel and remain in the channeling paths. As a result, the following injected CO2 will be forced to flow towards oil-rich regions radially and uniformly. Thereby, more CO2 can contact and react with the in-situ oil, resulting much higher oil recovery. In other words, the utilization ratio of CO2 is greatly improved. Taking Jidong oilfield as an example, it has been injected 19.2 x 10(4) t CO2 with the total oil production by 21.1 x 10(4) t. The utilization ratio of CO2 is calculated as high as 1.09. The observations of this study provide the theoretical basis for future application of organic fiber composite gel before CO2 flooding in the water channeling reservoirs.",5,5,3
Oil Recovery,Behavior,"Radovanovic, Anna M.; Pires, Adolfo P.; Peres, Alvaro M. M.",Semi-analytical transient pressure solution for power-law polymer injection in a vertical well,non-Newtonian flow; Enhanced oil recovery; Power-law fluids,FLOW; FLUIDS,"Enhanced Oil Recovery (EOR) is a process that extends reservoir life through field operations that aim to increase reservoir displacement efficiency. Injection of polymeric solutions, which is a chemical EOR process, improves sweep efficiency by decreasing the mobility of the injected fluids. One challenge in polymer flooding is to model the non-Newtonian rheological behavior of the injected solutions due to the complex interdependence between fluid flow velocity, fluid viscosity and shear rate. Proper reservoir management requires a thorough understanding of non-Newtonian fluid flow behavior through porous media, thus the need for new and improved mathematical models that describe the transient pressure behavior in wells. In this work we consider the flow of non-Newtonian pseudoplastic fluids in homogeneous isotropic porous media. To describe the rheological polymer behavior, we used the well-known power-law model, which leads to a nonlinear problem. In this paper, a novel semi-analytical solution is obtained by combining spatial domain discretization with pseudotime, so the flow problem is rewritten as a system of linear equations in Laplace domain. We also presented a variation of the proposed solution by assuming a pseudostationary behavior of the non-Newtonian velocity. Both approaches are compared to previously published approximated analytical solutions. One interesting aspect of our work is that it can be extended to more realistic polymer rheological models.",0,1,0
Oil Recovery,Behavior,"Nekoeian, Sahand; Aghajani, Masoud; Alavi, Seyed Mehdi",Experimental study of the surfactants effects on gas phase mass transfer coefficients in gas condensate reservoirs,Gas condensate reservoirs; Local equilibrium assumption; Gas phase mass transfer coefficients; Surfactants; Specific interfacial area; Spreading coefficients,ORGANIC-CHEMICALS; POROUS-MEDIA; WETTABILITY ALTERATION; LIQUID VOLATILIZATION; THERMAL-DIFFUSIVITY; DISSOLUTION; RECOVERY; OIL; CONDUCTIVITY; TRANSPORT,"Surfactant flooding in gas-condensate reservoirs, shown to be an effective treatment method to remediate condensate blockage in near well bore regions, have been the focus of several studies in the recent decades. However, the effect of these chemicals on the gas phase mass transfer coefficients has not been yet addressed though they have to be incorporated in non-equilibrium compositional simulators to imitate the reservoir behavior reliably. Besides, any knowledge of the overall effect of the surfactants on these coefficients can shed light on the side effects of the surfactant flooding on mass transfer phenomenon and evaluate its suitability as a treatment strategy. In this study, separate empirical correlations were developed for methane and isobutane representing light and intermediate components respectively in the absence and the presence of surfactants at the temperature of 40 degrees C. In all the developed correlations for both components in the presence of surfactants, while spreading coefficient has a positive exponent, equilibrium adsorption constant possesses a negative exponent. This implies that surfactants with a larger former parameter and a smaller latter parameter like SDS have more opportunity to enhance the volumetric mass transfer coefficient. The results also confirm the positive effect of pore gas velocity on gas phase mass transfer coefficients even in low gas flow rates. Similarly, this effect has already been reported in NAPL (Non Aqueous Phase Liquid) volatilization related studies. Effective diffusion coefficient, condensate saturation, mean grain size, component type, surfactant type and residual water saturation were also shown to affect these mass transfer coefficients. In addition, it has been shown that surfactants which are conventionally believed to reduce volumetric mass transfer coefficients in gas-liquid systems like bubble columns, improve gas phase mass transfer coefficients in gas condensate reservoirs. This improvement is considered a drawback for the cited technique.",0,0,1
Oil Recovery,Behavior,"Ranjbar, Ehsan; Ghaderi, Seyyed M.; Nourozieh, Hossein; Kumar, Anjani; Takbiri-Borujeni, Ali",Two-phase and three-phase equilibrium K-values for modelling of non-condensable gas Co-Injection processes,Thermal recovery; Heavy oil; Gas; Modelling; K-value,VAPOR-LIQUID-EQUILIBRIA; CARBON DIOXIDE-WATER; METHANE PLUS WATER; COLD LAKE BITUMEN; SOLUBILITY MEASUREMENT; PHASE-EQUILIBRIA; NATURAL GASES; AQUEOUS NACL; NITROGEN; PRESSURES,"To improve the efficiency of Steam Assisted Gravity Drainage process (SAGD), a small amount of non-condensable gases can be added to steam. The non-condensable gas creates an insulation film at the top of the steam chamber as a result of gas accumulation. This could prevent heat loss to the overburden, increase steam chamber propagation in the lateral direction, and consequently improve the SAGD performance. Field-scale modelling and simulation of non-condensable gas injection in a hybrid SAGD process requires a comprehensive numerical model that includes variety of mechanisms involved in the processes. During the steam/non-condensable gas co-injection, the non-condensable gas may partially be dissolved in bitumen and water, accounting for a portion of gas production from the chamber. Therefore, in order to accurately model the non-condensable gas injection process, the partitioning of the gas among the phases (oleic and aqueous) must be well understood. The most significant challenge of modelling multi-phase equilibrium in gas/bitumen/water systems is the lack of three-phase equilibrium data. This study presents a methodology to generate two-phase and three-phase K-values from the experimental solubility data. The data for binary systems at certain temperatures and pressures is translated into equilibrium K-values. The K-values were calculated either from a correlation representing the phase behavior data or from an equation of state coupled with Henry's law. Then, the generated two-phase and three-phase K-values were directly implemented in reservoir simulators to account for component partitioning in different phases. The results indicate that the generated K-values would be applicable for different types of bitumen.",2,2,0
Oil Recovery,Behavior,"Amadu, Mumuni; Pegg, Michael J.",Analytical derivation of a pH dependent contact angle equation and the relationship to industrial processes of energy concerns,Wettability; Point of zero charge pH; Surface potential; Surface charge density; Silanol,SURFACE-CHARGE; OIL-RECOVERY; WETTABILITY ALTERATION; ISOELECTRIC POINTS; WATER INTERFACE; ADSORPTION; SILICA; SALINITY; MINERALS; BEHAVIOR,"Regarding Young's equation, three fundamental interfacial energies of interfacial tensions can be identified. One of these interfacial energies relevant to our purpose is that related to the solid-liquid interface and it can be pH dependent. Intermolecular theory of surface tension links the solid-liquid interfacial tension or energy to surface charge species of solids. These species are electrostatic and depend on the pH of the aqueous medium in contact with the solid surface. Therefore, a theoretical relationship between contact angle and pH of some kind is worth exploring based on the fundamental theories of pH dependent solid-liquid interfacial tension, given the pH dependent electric double layer. A review of the literature dealing with the pH-dependent contact angle shows that polynomial curves have been fitted to contact angle versus pH data. Based on established theoretical works dealing with surface charge theories related to the electric double layer found in the literature, we have derived a pH dependent contact angle equation that describes trends in published experimental data with a high degree of regression coefficient. We have also theoretically and experimentally validated our model. The industrial significance of our model lies in the fact that the solution for pH, when the derivative is equated to zero, gives the point of zero charge pH of solid surface, which is an approach that has already been used in published works without any theoretical justification. The relationship of our model to industrial operations of energy and environmental significance has been discussed.",3,3,1
Oil Recovery,Behavior,"Pu, Wan-fen; Gong, Xiao-long; Chen, Ya-fei; Liu, Xue-li; Hui, Jian; Guo, Chen; Varfolomeev, Mikhail A.",Oxidation kinetic evaluation of the low temperature oxidized products of Tahe heavy oil characterized by the distributed activation energy model,Heavy oil; Low temperature oxidation; Oxidized product; Oxidation kinetic; Coke deposition; DAEM,IN-SITU-COMBUSTION; PRESSURE AIR INJECTION; LIGHT CRUDE-OIL; SARA FRACTIONS; BEHAVIOR; COKING; PREDICTABILITY; RECOVERY; TG,"In view of the significance of low temperature oxidation (LTO) for in-situ combustion (ISC) of heavy crude oil and to provide further data for Tahe ISC numerical simulation, this research aimed to investigate the non-isothermal oxidation behavior of heavy oil after static LTO reactions. Thermogravimetric (TG) and differential scanning calorimetry (DSC) techniques were used to characterize oxidation behavior, and distributed activation energy method (DAEM) was used to calculate kinetic parameters. The results showed that the non-isothermal oxidation process of static LTO oxidized oil was the result of the interaction between residue and coke, and coke can significantly reduce the activation energy of oxidized oil. Only one HTO region was identified for the coke from DTG/DSC curves, and it had the lowest activation energy (114.57 kJ/mol) and the highest heat enthalpy (24.3 kJ/g), indicating high oxidative activity with maximum heat release potential. A satisfactory corresponding relation between DTG and DSC curves was presented for all samples in FD and HTO regions, which indicated that the sequential reaction mechanisms, fuel deposition and combustion, were undergone. In LTO region, there was a temperature difference between the peaks of the mass loss and heat flow, indicating that the LTO process was more complex with a multi-step control mechanism should be considered to analyze and simulate the LTO stage.",3,3,1
Oil Recovery,Behavior,"Han, Lihong; Yin, Fei; Yang, Shangyu; Liu, Wei; Deng, Yong",Coupled seepage-mechanical modeling to evaluate formation deformation and casing failure in waterflooding oilfields,Well integrity; Waterflooding; Formation deformation; Casing failure; Coupled model,WATER INJECTION; FLUID; RESERVOIR; STORAGE; SLIP,"Waterflooding implemented to enhance oil recovery could concomitantly induce formation deformation and casing failure. The adverse responses should be evaluated to ensure the safety and performance of wells. A coupled seepage-mechanical model is developed to analyze the responses of formation and wells in waterflooding oilfields. The fluid-solid coupling method is employed to capture the flow and deformation in interlayers. The behavior of casing is predicted from the mechanical interaction among the wellbore-cement sheathcasing system. This model is validated by the analytical result. Results indicate that injection-production unbalance causes nonuniform pressurization or depletion in formation. Under pressurization, the vertical displacement along wellbore increases with the increases of axial position and time and displays a sharp rise in mudstone layer. There is an offset in mudstone layer. Casing stress increases under continuous pressurization or depletion, and stress concentration occurs in the mudstone interval. The predicted casing yield situation is consistent with the failure location in oilfield. The incongruous displacement in mudstone is the mechanism of casing deformation. Sustaining injection-production balance and adopting no-cementation operation are the possible strategies for mitigating the adverse effects of waterflooding. The findings can be applied to evaluate and manage formation response and casing integrity in waterflooding oilfields.",3,3,2
Oil Recovery,Behavior,"Patil, Abhay; Sundar, Shyam; Delgado, Adolfo; Gamboa, Jose",CFD based evaluation of conventional electrical submersible pump for highspeed application,CFD; High speed pumps; Losses; Dimensional analysis; Viscous flow; Axial thrust,FLOW,"Fluctuations in oil prices have negatively affected the petroleum industry, prompting to look for innovative ways to optimize oil recovery. One of the current approaches to optimize oil production is to employ high-speed ESPs with Permanent Magnet Motors (PMM) that allow reducing the pump size while increasing the operating envelop. Standard affinity laws are a useful tool to provide a preliminary estimate of common pump performance. However, there is a need to understand the detailed variation in the flow variables and losses incurring due to fluid-geometry interactions at high rotational speeds. To evaluate the hydraulic performance of a mixed flow pump, Computational Fluid Dynamics (CFD) simulations were performed at rotational speeds ranging from 3600 rpm to 20000 rpm using fluids with different viscosities. Fluid behavior is studied by observing the change in flow parameters with rotational speed. Similitude analysis is utilized to characterize the pump performance. The numerical results yielded improved pump hydraulic performance with an increase in rotational speeds which is attributed to reduced separation losses mainly in the diffuser section. Research is concluded with further evaluation of the complete stage including secondary leakage flow path on flow variables and axial thrust forces.",4,4,0
Oil Recovery,Behavior,"Ahmadi, Pouyan; Shahsavani, Behnam; Malayeri, Mohammad Reza; Riazi, Masoud",Impact of different injection sites on the water and oil exchange in a fractured porous medium for different polymers: A visual study,Viscosity; Shear rate; Polymer injection; Recovery factor; Water flooding; Fractured medium,GRAVITY CURRENTS; FLOW; RHEOLOGY; FLUID; CARBOXYMETHYLCELLULOSE; POLYACRYLAMIDE; IMBIBITION; BEHAVIOR,"This study aimed at investigating the impact of injection sites including i) matrix and ii) fracture when polymers of PVA, PAM, and CMC are injected at different concentrations within a fractured medium. The experimental results showed that PAM for all concentrations had a high recovery factor (RF) when its injection site is matrix and also at low concentrations. PAM has performed better due to its higher viscosity as well as its high capillary pressure in water-wet condition. In different pore sizes, the amount of shear rate that will be applied to the polymers will vary, which is why in the case of PAM injection in the fracture, the tendency of polymer to penetrate through the grains is more than fracture. CMC at low concentrations of 100 and 1000 ppm cannot wash the oil effectively. However, for a concentration of 5000 ppm, it has maximum breakthrough time as well as the maximum RF of 96% and 83% when it is injected via the matrix and fracture, respectively. These efficiencies are approximately 15% and 10% higher than that of PAM although PAM is more viscous of nearly threefold. PVA can ultimately sweep 12% of the OOIP when its 5000-ppm solution is injected from the matrix.",4,4,0
Oil Recovery,Behavior,"Han, Pu; Geng, Jiaming; Bai, Baojun",Investigation on transport behavior of nanogel in low permeable porous medium,Nanogel; Filtration; Membrane; Transport,LINKED POLYMER MICROSPHERES; WATER,"Nano-sized crosslinked polymeric particles (nanogels) have the advantages of both nanoparticles and hydrogels for enhanced oil recovery in the oil and gas industries. Although some encouraging progress in the application has been made, the transport behavior of nanogels through porous media are still not clear. In this work, a series of filtration experiments using membrane filter were performed to study the effect of nanogel diameter, pore size, and differential pressure on the transport behavior. The equilibrium filtration rate, which is a key parameter to indicate the transport behavior during steady state, increased from 0.19 to 5.71 mL/min when the pore size changed from 0.05 to 0.8 pm, and increased from 1.02 to 1.99 mL/min when the differential pressure raised from 10 to 30 psi. Experimental results demonstrated nanogels present smaller diameter (105.7 nm) and lower absolute value of zeta-potential ( -18.9 mV) in 10 wt% NaCl solution than distilled water (295.3 nm and - 82.5 mV). The higher salt concentration resulted in a better nanogel injectivity (equilibrium filtration rate increased from 0.77 to 4.52 when NaCl concentration changed from 0 to 10 wt%), which indicated the diameter of nanogel is a more determining factor than the nanogel strength. When the pore size was smaller than similar to 3 times of the naongel diameter, the equilibrium filtration rate became independent to the differential pressure and nanogels started to form face plugging on the membrane. The core filtration tests demonstrated that the nanogels maintained similar transport behavior through the limestone cores and membrane filters that the resistance factor is 26.59 in membrane and 18.56 in core with similar pore diameter. The transport behaviors of nanogel and corresponding mechanisms are summarized by the matching relationship between the diameter of nanogel and the pore size in low permeable porous medium.",4,4,0
Oil Recovery,Behavior,"Morte, Matthew; Hascakir, Berna",Characterization of complex permittivity for consolidated core samples by utilization of mixing rules,Microwave; Complex permittivity; Mixing rule; Electromagnetic heating,DIELECTRIC-PROPERTIES; OIL-RECOVERY; ELECTRICAL-PROPERTIES; CONSTANT; MHZ,"Candidacy of any reservoir as a microwave absorber is predicated on the complex permittivity of the sample. Modeling both the penetration and absorption dynamics of the electromagnetic wave in the reservoir is dependent on realistic estimation of this parameter. Therefore, it becomes necessary to understand the inherent intricacies of complex permittivity in the reservoir. Reservoirs are comprised of both a void space represented by the porosity parameter as well as the rock matrix and can be treated as a binary mixture of the two. Mixing rules can then be introduced and have been shown to be a viable means of estimating the dielectric response. The behavior of the bulk material is considered to be an extension of the isolated contribution of the separate parts. Therefore, by characterizing the response of the individual components of the mixture, the overall response can be estimated. Utilization of mixing rules enables efficient estimation of the dielectric properties anywhere in the reservoir as a function of the rock matrix, fluid saturation, and porosity. The absorptive capacity of the reservoir can then be described which is used to screen the efficacy of the material for microwave introduction. Both the real and imaginary components of complex permittivity are measured on nine consolidated core samples of varying lithology and fluid saturation over the frequency range of 400 MHz to 6 GHz. Experimental data is compared to various mixing rules commonly implemented to determine validity and viability of the estimation of complex permittivity for consolidated samples.",4,4,2
Oil Recovery,Behavior,"Zhou, Ming; Yi, Rongjun; Gu, Yinghua; Tu, Hongjun",Synthesis and evaluation of a Tetra-copolymer for oil displacement,Synthesis; AM/DAAM/AMPS/DMAM Tetra-copolymer; Orthogonal test; Characterization; Viscosity retention rate; Enhancing oil recovery,PARTIALLY HYDROLYZED POLYACRYLAMIDE; MECHANICAL DEGRADATION; ACRYLAMIDE; RECOVERY; POLYMERS; MICROSPHERES; RHEOLOGY; BEHAVIOR,"In this paper, acrylamide (AM), 2-acrylamide-2-methylpropane sulfonic acid (AMPS), diacetone acrylamide (DAAM) were used as the basic monomers, and N, N-dimethylacrylamide (DMAM) with hydrophobic groups was introduced as the fourth monomer. The AM/DAAM/AMPS/DMAM Tetra-copolymer was synthesized by aqueous solution polymerization using the redox system of potassium persulfate and sodium bisulfite as initiator. The synthesis conditions of the copolymer were optimized by orthogonal test with five factors and four levels. The structure of the copolymer was characterized by FTIR and the thermal stability of the copolymer was analyzed by TGA. Relevant experimental results showed that the viscosity retention rate of the copolymer was higher than that of HPAM at the same temperature, salinity and shear rate. The viscosity retention rate of the copolymer was 72.7% after aging 30 days at 90 degrees C in the solution with 15000 mg/L the total salinity. The oil displacement experiment showed that the average recovery of the polymer flooding with 1000 mg/L prepared copolymer was as high as 10.8%.",4,4,9
Oil Recovery,Behavior,"Sinha, Vineet; Ahmeda, Ramadan; Akhtar, Tarek; Shah, Subhash; Amani, Mahmood",Rheology and hydraulics of polymer-based foams at elevated temperatures,Foam; Polymer; Stimulation; Rheology; Hydraulics; Drilling,CONSTITUTIVE EQUATION; DRILLING FOAMS; FLOW BEHAVIOR; AQUEOUS FOAMS; FLUID-FLOWS; VISCOSITY; SUSPENSION,"Foam has been successfully used for different operations like well stimulation, drilling, enhanced oil recovery (EOR), cleanout, and acidizing operations in the oil and gas industry. Additionally, the low liquid content of foam provides a distinct advantage in terms of lesser material requirements. However, accurate prediction of rheology is necessary for the success of field operations, which requires a rheological model that incorporates the effect of temperature on foam properties as it circulates downhole. In the present investigation, polyanionic cellulose (PAC) based foam was generated using nitrogen as the gas phase and its rheology was determined using a recirculating flow loop that has three pipe viscometers (3.05, 6.22, and 12.7 mm ID) and a fully-eccentric annular section (9.53 mm OD x 12.57 mm ID). Experiments were conducted within the temperature range of 24 to 149 degrees C and at various foam qualities (gas phase volume fraction). The foam was circulated at different flow rates and the differential pressure across each pipe section was recorded. All tests were conducted at 6.89 MPa. The foams displayed power-law fluid behavior in the shear rate range tested (100-5000 s(-1)), which is often experienced in the wellbore. Like its base liquid, polymer foam exhibited thermal thinning and a significant rheology change with temperature. Only high-quality foam (75%) at ambient temperature (24 degrees C) showed yielding behavior, which was measured in a pipe viscometer under static condition. The disappearance of yield stress at elevated temperature could be attributed to thermal thinning of the liquid phase that weakens the strength of bubble structure. Experimental data is used to develop new correlations to predict power-law fluid parameters as a function of temperature, base fluid properties, and foam quality. Moreover, the measurements are compared with the predictions of existing models, and discrepancies are observed, which could be attributed to the variation in foam generation technique, the nature and concentration of polymer, and the concentration of surfactant used in the experiments in which data was obtained to develop the models. Furthermore, annular pressure loss measurements obtained at low temperatures (24 and 79 degrees C) show predominantly good agreement with predictions of a hydraulic model that uses the new correlations. Discrepancies increased with temperature as the foam becomes unstable due to thermal thinning of the liquid film and subsequent weakening of bubble structure.",5,5,1
Oil Recovery,Behavior,"AlZayer, Ahmed; Sanaei, Alireza; Mohanty, Kishore; Sepehrnoori, Kamy",Experimental and numerical investigation of mutual solvents for EOR applications,Carbonated water; Diethyl ether; Mutual solvents; EOR; Carbonate rocks,,"More than half of the oil discovered in existing oil reservoirs is left behind after primary and secondary recovery. It is essential to increase oil recovery from existing fields to meet future oil demand. The injection of solvents, an established enhanced oil recovery (EOR) technique, has shown significant improvement in oil recovery over conventional water floods. However, injection of pure solvent slugs is expensive for field operators. To mitigate this problem, recent literature has proposed the use of brines that are saturated with mutual solvents (which dissolve in both oil and water phases). In this paper, we investigate the behavior of two mutual solvents, carbon dioxide (CO2) and diethyl ether (DEE). We have performed several core-floods in sandstone and carbonate cores. Injecting CO2-rich brine (carbonated water) into sandstone cores did not improve oil recovery. However, there was an improvement in oil recovery as a result of carbonated water injection in carbonate cores, which also displayed significant plugging during the experiment. There was also a noticeable improvement in oil recovery in the case of DEE-rich brine, but without any plugging issues. Mutual solvents dissolved in oil, swelled oil, and decreased oil viscosity which mobilized the oil. The experimental work was corroborated with numerical modeling to reproduce the results of both the solvents. Although the simulator is capable of handling rock-fluid interactions, such as mineral dissolution, the exact nature of the grain mobilization and pore-throat plugging was not incorporated in the numerical model. As a result, the simulator was unable to fully mimic the experimental observations of carbonated water floods. In contrast, since there was no apparent nor significant rock-fluid interaction in the DEE-rich brine case, it was successfully matched by the simulator.",5,5,2
Oil Recovery,Interfacial Tension,"Mukhamatdinov, Irek I.; Aliev, Firdays A.; Acosta, Anabel Sosa; Vakhin, Alexey V.",A new approach for measuring rheology of polymer solutions in reservoir conditions,Polymer; Polyacrylamide; Rheology; Wettability; Interfacial tension,ENHANCED OIL-RECOVERY; HEAVY OIL; WATER; NANOPARTICLES; SURFACTANT; ADSORPTION; NETWORKS,"The simulation of flow processes under reservoir condition is a hard task. Viscosity of polymer solution in porous media depends on adsorption of polymers on mineral substrates. Specific features characterize filtration of polymer solutions in porous media. Here, we propose a new approach to evaluate the rheology of polymers that considers fluid interactions with mineral surfaces. The principle of this method is as follows: measuring viscosity of ""mineral-in-polymer"" suspension. Hence, this approach needs simple equipment rather than complex core flooding system. The laboratory selection of effective polymer and its optimum concentration is carried out by the proposed approach. It is crucial for primary screening of some polymers. The presence of dispersed minerals in model suspensions influences the surface tension between the polymer solution and solid surface with various chemical nature. In order to justify this method, we used minerals with different chemical nature such as dispersed calcite and dolomite, and two widely used polyacrylamide type polymers that differ in molecular masses. We observed that viscosities between various suspensions differ several times due to the surface nature. We also determined the correlation between the viscosity of model suspension and contact angle. The latter is determined by chemical nature of minerals.",0,0,1
Oil Recovery,Interfacial Tension,Wang Tianyuan; Yu Li; Xiu Jianlong; Huang Lixin; Cui Qingfeng; Ma Yuandong,A mathematical model for microbial enhanced oil recovery considering the double-bacterial competition mechanism,Microbial enhanced oil recovery; Mathematical model; Double-bacterial; Competition,,"Considering the influence of reservoir on microbial growth and the competition of microbial community on nutrition, a mathematical model for microbial enhanced oil recovery considering the double-bacterial competition mechanism is established. The components of this mathematical model consist of oil, water, microbe 1, microbe 2, nutrients, metabolite) and metabolite2. The equations of this numerical model take into account the decay and growth of microorganisms, nutrient consumption, metabolism production, chemotaxis, convection-dispersion, water viscosity increment, oil viscosity reduction, interfacial tension reduction, adsorption, and desorption. In this study, three numerical examples were performed to analyze the double-bacterial competition mechanism and the effects of product interaction on improving oil recovery through a simulator developed according to our mathematical model. We found that (1) Under different double-bacterial growth models (symbiotic effect, repressive effect and no effect), there is a big difference in product concentration and oil displacement efficiency; (2) Double-bacterial growth model can better simulate actual reservoir application of microbial flooding technology than single microbial model; (3) Double-bacterial growth model with different products can increase oil recovery by up to 12.3% compared with water flooding.",1,3,2
Oil Recovery,Interfacial Tension,"Leitenmueller, Verena; Rupprecht, Bernhard J.",A multidisciplinary approach for chemical EOR screening: Understanding alkali-oil interaction by the use of petroleum geochemistry,Biodegradation; Phase screening; Potassium carbonate; Reservoir engineering; Organic geochemistry; ASP flooding; Chemical flooding,INTERFACIAL-TENSION; VIENNA BASIN; SYSTEMS; MECHANISMS,"Alkali-based chemical enhanced oil recovery is used to increase the incremental oil production and relies on the interaction of alkali lye with crude oil. Optimizing the chemical formulation depends on screening multiple alkali concentration ranges to maximize the generated emulsion volume. However, the strong chemical variation of the crude oil, caused by biodegradation within the reservoirs, and its influence on generating in-situ soaps has never been studied in detail. In this paper, organic geochemical oil characterization was combined with phase screening data. Thereby, differences in terms of initial crude oil composition (slightly degraded, moderate degraded, and heavy degraded oils), but also regarding the excess alkali-equilibrated oil phase, and the hydrocarbons which are included in the in-situ soap (emulsion phase) were worked out. Different alkalis, concentration ranges, and water-oil-ratios were studied, to understand the control mechanism for the in-situ soap generation. The formed emulsions were observed over time (emulsion stability) and classified into possible emulsion types. Alterations caused by the alkali-oil interaction were quantified by the use of organic geochemistry. The degree of biodegradation seems to be an important control mechanism. Slightly degraded oils do not interact with the alkali lye due to a high content of non-polar compounds such as alkanes and isoprenoids. Moderately and heavily degraded oils show varying interactions with the alkali solution. The degree of interaction depends on the used degradation type, the alkali type as well as on the used concentration. Moderately degraded oils interact in a lower concentration range compared to heavily degraded oils, which show an increased non-soap forming acid content. Phase experiments conducted over a long period of time (100 days) were used to determine which emulsion types (micro or macro) were formed. Stable micro emulsions were preferably generated over time in formulations prepared with potassium carbonate (K2CO3). In contrast, formulations containing sodium carbonate (Na2CO3) hardly did not generate stable micro emulsions. The composition of alkali-equilibrated oil differs from the initial oil composition and shows a strong dependency of the used alkali type. Potassium carbonate caused mild alterations of the moderately and heavily degraded oils, whereas the impact of sodium carbonate was more severe. In addition, dissolution of naphthalenes, steranes, hopanes, and parts of the generated in-situ soap into the aqueous phase, was observed during the performed phase experiments of the moderately degraded oils (at the elevated pH values).",2,2,0
Oil Recovery,Interfacial Tension,"Paternina, Christian A.; Londono, Alexandra K.; Rondon, Miguel; Mercado, Ronald; Munoz, Samuel",Influence of salinity and hardness on the micellization of an extended surfactant studied by turbidimetry,Micellization; Extended surfactant; Salinity; Hardness; Turbidity,PHASE-BEHAVIOR; MICELLES; WATER; SHAPE; SIZE,"The injection of surfactants as the active component of Enhanced Oil Recovery (EOR) formulations is the current chemical method with the more promising potential because it produces substantial reduction of oil/water interfacial tension. However, the molecular arrangements depending on salinity and hardness, is not well understood. This is a key factor when trying to understand the solubilization of oil and the retention of surfactant during EOR processes. Nevertheless, the formation of micelles is one of the phenomena most affected by the salt concentration but, usually, this parameter is not considered. In this work, the micellization of a commercial extended surfactant at different concentrations and several salinities and hardness is studied. Results showed that size, shape and/or number of micelles are affected by the salinity and hardness. The explanations for this fact include the formation and re-solubilization of calcium soaps, salting-out phenomena and the electric charge shielding, which affect the micellar packing factor. The re-arrangement of molecules, depending on the electrolytes in solution, could favor the formation of spherical, rod-like micelles, and eventually the co-existence of both, or even other types of aggregates and it could be inferred by the analysis of set of data obtained from simple and cheap technique as turbidimetry and complimentary verified by a more sophisticated technique such like DLS.",2,2,1
Oil Recovery,Interfacial Tension,"Amadu, Mumuni; Pegg, Michael J.",Analytical derivation of a pH dependent contact angle equation and the relationship to industrial processes of energy concerns,Wettability; Point of zero charge pH; Surface potential; Surface charge density; Silanol,SURFACE-CHARGE; OIL-RECOVERY; WETTABILITY ALTERATION; ISOELECTRIC POINTS; WATER INTERFACE; ADSORPTION; SILICA; SALINITY; MINERALS; BEHAVIOR,"Regarding Young's equation, three fundamental interfacial energies of interfacial tensions can be identified. One of these interfacial energies relevant to our purpose is that related to the solid-liquid interface and it can be pH dependent. Intermolecular theory of surface tension links the solid-liquid interfacial tension or energy to surface charge species of solids. These species are electrostatic and depend on the pH of the aqueous medium in contact with the solid surface. Therefore, a theoretical relationship between contact angle and pH of some kind is worth exploring based on the fundamental theories of pH dependent solid-liquid interfacial tension, given the pH dependent electric double layer. A review of the literature dealing with the pH-dependent contact angle shows that polynomial curves have been fitted to contact angle versus pH data. Based on established theoretical works dealing with surface charge theories related to the electric double layer found in the literature, we have derived a pH dependent contact angle equation that describes trends in published experimental data with a high degree of regression coefficient. We have also theoretically and experimentally validated our model. The industrial significance of our model lies in the fact that the solution for pH, when the derivative is equated to zero, gives the point of zero charge pH of solid surface, which is an approach that has already been used in published works without any theoretical justification. The relationship of our model to industrial operations of energy and environmental significance has been discussed.",3,3,1
Oil Recovery,Interfacial Tension,"Masoudi, Mohammad; Khosravi, Maryam; Rostami, Behzad; Abolhosseini, Pejman",Effect of Benard-Marangoni flow on the bypassed oil recovery: Micromodel study,Cold gas injection; Thermal marangoni flow; Benard-marangoni convection; Micromodel experiment; Dead-end pore; Matrix/fracture system,PLUS N-ALKANE; INTERFACIAL-TENSION; SURFACE-TENSION; MASS-TRANSFER; MULTIPHASE FLOW; CONVECTION; CO2; FLUID; CELLS; LAYER,"This paper presents an experimental study to show the impact of Benard Marangoni flow (type of Marangoni convective flow caused by temperature variation on the interface of fluids) on fluid flow in porous media. The importance of marangoni mechanism has been rarely addressed in the oil recovery mechanisms in the related literature. In this regard, cold gas (Carbon dioxide or methane) has been injected into a fractured system to recover the bypassed oil in matrix via convective fluxes induced by interfacial tension gradient. Results demonstrate that the thermal Marangoni flow improves oil recovery significantly by enhancing the flux of oil/injectant from/into the matrix. Furthermore, the amount and rate of oil recovery are proportional to Marangoni number. Marangoni flow in carbon dioxide injection is much stronger than methane injection, owing to larger amount of interfacial tension gradient.",3,3,2
Oil Recovery,Interfacial Tension,"Hamidian, Ramtin; Lashkarbolooki, Mostafa; Amani, Hossein","Ion type adjustment with emphasize on the presence of NaCl existence; measuring interfacial tension, wettability and spreading of crude oil in the carbonate reservoir",Spreading; Wettability; IFT; EOR; Salt; Ionic strength,SURFACE FREE-ENERGY; SMART-WATER; SALINITY; RECOVERY; INJECTION; CHALK; ADHESION; SEAWATER; EOR; COEFFICIENT,"Finding the high-performance anions and cations in the aqueous solutions are crucially required during the smart water injection make it the main core of many enhanced oil recovery (EOR) studies. Nevertheless the previously published literature revealed a lack of understanding about the synergistic or antagonistic effect of NaCl (as the most abundant salt in the sea water) and other salts with the same ionic strength on the interfacial tension (IFT), wettability alteration and spreading coefficient. Therefore, the main purpose of this study is aimed on this concern. To reach this goal, the dynamic IFT values of crude oil/different aqueous solutions with ionic strength of 0.7M and contact angle values between these phases on the oil wet carbonate surface soaked under different times in the prepared aqueous solutions are measured. After that, the measured values are used to calculate the spreading coefficient and distribution capability of oil and water phases on the carbonate rock surface. The obtained results revealed that to change the wetting state of carbonate rock toward a more water wet state, a synergistic effect was observed between NaCl and salts containing sulfate anion, i.e. Na2SO4. and MgSO4.",4,4,0
Oil Recovery,Interfacial Tension,"Soori, Tejaswi; White, Andrew R.; Ward, Thomas",Immiscible fluid displacement in a porous media: Effect of surfactants introduced ab initio versus surfactants formed in-situ,Enhanced oil recovery; Alkali flooding; Surfactant flooding; Porous media; Capillary flows; Immiscible flows,LIQUID-LIQUID DISPLACEMENT; INTERFACIAL REACTION; FILM THICKNESS; VISCOUS-FLUID; GAS-BUBBLES; OIL; ADSORPTION; DEPOSITION; TRANSPORT; DYNAMICS,"Experiments were performed to study the immiscible displacement of oil from a capillary tube using an aqueous phase fluid. One set of experiments were performed where surfactant was introduced into the aqueous phase liquid at concentrations below the critical micellar concentration prior to displacement, i.e. ab initio. In a second set of experiments surfactant was formed at the interface in-situ via a saponification chemical reaction. For both experiment conditions we measured surface tension using the pendant drop method to estimate adsorption and desorption Biot numbers for the ab initio case; whereas for surfactant produced via chemical reaction this data provided an estimate for rates of change in surface tension that were used to estimate a Damkohler number. The results suggest that surfactants created via saponification reaction tend to have an effect on the interface and film thickness that is entirely absent in non-reactive immiscible displacement experiments.",4,4,0
Oil Recovery,Interfacial Tension,"Al-Khafaji, Arije; Wen, Dongsheng",Quantification of wettability characteristics for carbonates using different salinities,Low salinity flooding; Enhanced oil recovery; Carbonate reservoir; Wettability; Interfacial tension; Adhesion force,OIL-RECOVERY; CRUDE OILS; INTERFACIAL ACTIVITY; SMART WATER; INJECTION; BRINE; IONS; ASPHALTENE; RESERVOIR; TENSION,"Low salinity water flooding has received strong interest recently. It has been reported that injecting low salinity water can improve oil recovery in carbonate reservoirs through wettability alteration, whose mechanism however remains unclear, especially regarding the contributions from adsorbed polar organic components. This work investigates systematically the key parameters that govern the complex interactions of rock/brine/crude oil in carbonate reservoirs. The effects of crude oil composition and salinity on surface wettability alteration are studied by using three types of dead oil from Norwegian and North Sea with various acid numbers and two types of carbonate rocks (outcrop-calcite and subsurface-dolomite). Ion-substitution-adsorption is evaluated using the infrared spectrometer (IFR) and energy-dispersive X-ray spectroscopy (EDX). Oil/brine interactions by means of the interfacial tension (IFT) and contact angle as a function of oil composition, rock type, and salinity are experimentally investigated. The IFR and EDX data indicate a compositional change when the carbonate minerals are in touch with saline solutions, supporting the proposed rock-brine interaction mechanism. The salinity effect is more salient at the liquid/rock interface than the liquid/liquid interface, and the response to the brine composition is highly dominated by the oil composition with respect to its content of polar organic components. There is a reduction of contact angle as the seawater water is diluted twice while its influence on the IFT is small, and the effect is more pronounced for dolomite rock, showing different results for different crude oils used. This suggests that the wettability alteration of carbonate rock is an intricate phenomenon that is influenced not only by the salinity but also by the chemical composition of crude oil and rock mineralogy. A combination of three possible mechanisms, including multiple ion exchange, EDL expansion (electrokinetics repulsive), and salting-out, is discussed to illustrate the mechanism of wettability alteration during low salinity injection.",5,6,1
Oil Recovery,Interfacial Tension,"Orrego-Ruiz, Jorge A.; Medina-Sandoval, Camila F.; Castillo Hinds, Carmen; Villar-Garcia, Alvaro; Rojas-Ruiz, Fernando A.",FT-ICR MS determination of the role of naphthenic acids on the stabilization of alkali/surfactant/polymer emulsified effluents: A field study,Microemulsions; Enhanced oil recovery; ASP flooding; Surfactants; Emulsion stability; FT-ICR MS,ENHANCED OIL-RECOVERY; RESONANCE MASS-SPECTROMETRY; INTERFACIAL-TENSION; PHASE-BEHAVIOR; CRUDE OILS; SURFACTANT; ASPHALTENES; ADSORPTION; STABILITY; EMULSIONS,"Numerous Alkali/Surfactant/Polymer flooding (ASP) projects have been developed worldwide. Nevertheless, some disadvantages have limited the success of ASP during the execution in field, such as injection lines scaling and strong emulsification of the produced fluids. Commonly, appropriate formulations for particular reservoir conditions are selected after a series of evaluation steps. These includes tests of surfactants, polymers and commercially available alkali, based on the reservoir temperature, reservoir salinity, reservoir water pH, rock permeability, formation type and adsorption of the surfactant on the matrix rock, to obtain the highest oil recovery at the lowest cost. As part of the different strategies adopted for increasing the oil recovery factor, San Francisco oil field, Huila Colombia, was selected in 2012 for ASP flooding application at pilot scale. After two years of injection, ASP effluents affected considerably the quality of water and its treatment for reinjection. The present work focuses on the compositional study of the production effluents obtained after ASP flooding. A detailed analysis using Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) allowed disclosing the role of natural organic acids on reducing the interfacial tension which in turn entailed highly stable microemulsions. Together with the added surfactant, naphthenic acids (because of the alkaline pH) prompts the formation of these thermodynamically stable oil in water systems. A test using an acid free oil proved that the formation of microemulsions strongly depends on naphthenic acids presence. Additional tests using oils with different acidity showed the dependence on the naphthenics acids structure over the emulsion stability. The results obtained in this study stands out FT-ICR MS as a prominent tool on understanding breaking and/or clarifying treatment processes from a molecular level point of view and thus, could help on proposing a correct and cost effective water treatment.",5,5,2
Oil Recovery,Values,"Cuijpers, M. C. M.; Boot, M. D.; Deen, N. G.; Golombok, M.",Sulphur and viscosity reductions in heavy hydrocarbons by subcritical water processing,Subcritical water; Sulphur; Viscosity; Enhanced cracking,ENHANCED OIL-RECOVERY; SUPERCRITICAL WATER; RICE BRAN; EXTRACTION; CONVERSION; PRODUCTS; REMOVAL; ALKALI; ACID,"Viscosity and sulphur content are two important properties of heavy hydrocarbons for downstream processing. Both properties can be significantly reduced in value by processing in subcritical water. Subcritical water has advantages over steam recovery methods in terms of viscosity and sulphur reduction as well as energy consumption. In order to understand the mechanism of subcritical water treatment, the chemical structure of pre- and post-processed heavy hydrocarbons are compared to each other. For subcritical water processing, viscosity reduction coincides with a reduction in average molecular weight, average carbon chain length between branching points, and sulphur content, along with an increase in volatility and H2S production. This suggests that not only are C-C bonds cracked, but also C-S-(C) bonds. Subsequent comparison of subcritical water results with those obtained for pyrolysis treatment shows that the former is faster and more effective.",1,1,0
Oil Recovery,Values,"Karacan, C. Ozgen",An ANCOVA model for porosity and its uncertainty for oil reservoirs based on TORIS dataset,Mean value; Depositional system; Multi-linear regression; Reservoir assessment; ANCOVA; TORIS,PERMEABILITY PREDICTION; SEDIMENTARY; NORTH; SANDSTONE; EOCENE; ROCKS,"Porosity is one of the most important parameters to assess in-place oil or gas in reservoirs, and to evaluate recovery from enhanced production operations. Since it is relatively well-established to determine porosity using different laboratory and field methods, its value is usually determined at many locations across a reservoir as part of the common practice to capture reservoir heterogeneity and the variability in values. This suite of measurements and the distribution of values are most valuable for probabilistic reservoir assessments, and for spatial modeling if the exact data locations are known. Despite the importance of individual measurements to set the range of values for probabilistic studies, it is not always possible to access these data due to confidentiality. In most cases, commercial or publicly available databases that assessments may rely on usually report only mean values of porosity, like any other reservoir data, or they may not report a value at all. This makes both quantifying the mean value and the uncertainty around it difficult for probabilistic assessments. In this study, the TORIS (Tertiary Oil Recovery Information System) dataset of the National Petroleum Council and the U.S. Department of Energy was used to model porosity and the uncertainty around predicted values. TORIS is an integrated dataset of production data, reservoir properties, and project databases of crude oil reservoirs in the United States. The model presented in the paper was based on ANCOVA (Analysis of Co-Variance) of data from 1038 reservoirs from the TORIS dataset for porosity prediction, validation and testing for quantitative and qualitative parameters that may be readily available in most cases, and to estimate uncertainty around the mean values. This model also explored association of porosity values to different parameters, and to different depositional systems and diagenetic overprint conditions. Furthermore, an ANN (Artificial Neural Network) model was created to compare the predicted values of both models. Results showed that the ANN model was able to represent more of the variability, however it lacked the insights that might be gained from the ANCOVA model.",1,1,0
Oil Recovery,Values,"Zhou, Kaibo; Zhang, Shuo; Huang, Zhen; Zhang, Jianyu",An improved TSVD-GCV inversion algorithm of pore size distribution in time-domain induced polarization using migration Hankel matrix,Time-domain induced polarization; Pore size distribution; Migration Hankel matrix; Backus-Gilbert theory; TSVD-GCV,PARAMETER DETERMINATION; NOISE-REDUCTION; PERMEABILITY; SVD; RESERVOIR; IMAGES,"Reservoir porosity obtained from time-domain induced polarization (TDIP) well logging plays a vital role in estimating the hydraulic properties and obtain the reservoir parameters in a water-flood oil-field. Improving the inversion accuracy of the reservoir porosity can enhance the oil recovery in the water-flood oil-filed. Evaluating reservoir pore size distribution through induced polarization decay curve is confronted with the problems of poor applicability of data pre-processing, low accuracy and lacking of evaluation criteria for inversion results of pore size distribution. The basic principles of TDIP are introduced and the relationship between pore relaxation time and pore diameter is given. Combining the mathematical characteristics of polarization decay curve data, the performance and the limitations of existing pre-processing algorithms are analyzed and pointed out, respectively. An improved data pre-processing algorithm using the spatial characteristics of linear transformation based on migration Hankel matrix is proposed, and this method improves the inversion accuracy of pore size distribution greatly. In the engineering application, 2-logarithmic sampling method is proposed to sample the polarization decay data for more efficient petroleum exploration with less sample points. The different regularization methods, regularization matrix and regularization parameter determination methods are compared and analyzed for the inversion of the pore size distribution. The numerical simulation experimental results show that the stability and accuracy of Truncated Singular Value Decomposition - Generalized Cross Validation (TSVD-GCV), Truncated Singular Value Decomposition - L Curve (TSVD-L) and Tikhonov-I-L are appropriate for the inversion of pore size distribution. Because of the truth that the pore size distribution of rock is unknown, Backus-Gilbert (BG) theory is introduced to evaluate the inversion results of rock polarization decay curve data of a mining area in Jilin Province. The rock sample experiment shows that the TSVD-GCV inversion algorithm has the best performance.",1,1,5
Oil Recovery,Values,"Leitenmueller, Verena; Rupprecht, Bernhard J.",A multidisciplinary approach for chemical EOR screening: Understanding alkali-oil interaction by the use of petroleum geochemistry,Biodegradation; Phase screening; Potassium carbonate; Reservoir engineering; Organic geochemistry; ASP flooding; Chemical flooding,INTERFACIAL-TENSION; VIENNA BASIN; SYSTEMS; MECHANISMS,"Alkali-based chemical enhanced oil recovery is used to increase the incremental oil production and relies on the interaction of alkali lye with crude oil. Optimizing the chemical formulation depends on screening multiple alkali concentration ranges to maximize the generated emulsion volume. However, the strong chemical variation of the crude oil, caused by biodegradation within the reservoirs, and its influence on generating in-situ soaps has never been studied in detail. In this paper, organic geochemical oil characterization was combined with phase screening data. Thereby, differences in terms of initial crude oil composition (slightly degraded, moderate degraded, and heavy degraded oils), but also regarding the excess alkali-equilibrated oil phase, and the hydrocarbons which are included in the in-situ soap (emulsion phase) were worked out. Different alkalis, concentration ranges, and water-oil-ratios were studied, to understand the control mechanism for the in-situ soap generation. The formed emulsions were observed over time (emulsion stability) and classified into possible emulsion types. Alterations caused by the alkali-oil interaction were quantified by the use of organic geochemistry. The degree of biodegradation seems to be an important control mechanism. Slightly degraded oils do not interact with the alkali lye due to a high content of non-polar compounds such as alkanes and isoprenoids. Moderately and heavily degraded oils show varying interactions with the alkali solution. The degree of interaction depends on the used degradation type, the alkali type as well as on the used concentration. Moderately degraded oils interact in a lower concentration range compared to heavily degraded oils, which show an increased non-soap forming acid content. Phase experiments conducted over a long period of time (100 days) were used to determine which emulsion types (micro or macro) were formed. Stable micro emulsions were preferably generated over time in formulations prepared with potassium carbonate (K2CO3). In contrast, formulations containing sodium carbonate (Na2CO3) hardly did not generate stable micro emulsions. The composition of alkali-equilibrated oil differs from the initial oil composition and shows a strong dependency of the used alkali type. Potassium carbonate caused mild alterations of the moderately and heavily degraded oils, whereas the impact of sodium carbonate was more severe. In addition, dissolution of naphthalenes, steranes, hopanes, and parts of the generated in-situ soap into the aqueous phase, was observed during the performed phase experiments of the moderately degraded oils (at the elevated pH values).",2,2,0
Oil Recovery,Values,"Canbolat, Serhat; Parlaktuna, Mahmut",Analytical and visual assessment of fluid flow in fractured medium,Fluid flow; Natural fracture; Equivalent fracture aperture (EFA); Improved cubic law (ICL),LOCAL CUBIC LAW; ROCK; CONDUCTIVITY; EQUATION,"Most reservoirs consist of natural and artificial fractures, including isolated microscopic fissures. These fractures form complicated paths for reservoir characterization and fluid movement that ultimately impacts production performance and ultimate recovery. That's why recovery estimations of fractured reservoirs are considered to be extremely challenging due to complexity and heterogeneity of the geological patterns. Oil production from fractured reservoirs results in varying saturation values throughout the reservoir. This is due to the microscopic fissures and heterogeneity of the fracture environment, which could not be swept thoroughly. Higher production/injection ratios also enhance the fingering effect by passing oil through the reservoir. In this study, naturally and artificially fractured cores were used. Analytical and experimental calculations were performed in order to understand the physical structure of the cores. Moreover, in the literature the analytical solutions of the fractures were defined by cubic law (CL), local cubic law (LCL) and modified cubic law (MCL). However, due to the lack of consideration of fracture properties with limited experimental work, there needs still work on this field. Equivalent fracture aperture (EFA) measurements were done by microscope and compared with the analytical calculations. Laboratory results were defined by the equation developed for predicting equivalent fracture apertures as Improved Cubic Law (ICL). Shrinkage in equivalent fracture aperture was also defined by ICL observed by microscope. Using ICL, analytical calculations were done in different environments. Equivalent fracture apertures were calculated for all the experimental flow rates under laminar flow. ICL has worked with the fractured cores flow definition whereas not for homogeneous cores. That's why due to higher calculated values and the 15% error on EFA, a correction coefficient (C) included to the CL equation for the tortuosity or the roughness effect This result was in th error range of previous results and gave more realistic estimation with respect to the previous studies carried out Finally, C coefficient was calculated in a range of 0.53-0.65.",3,3,0
Oil Recovery,Values,"Ziabakhsh-Ganji, Zaman; Nick, Hamidreza M.; Bruhn, David F.",Investigation of the synergy potential of oil and geothermal energy from a fluvial oil reservoir,Geothermal energy; Thermal enhanced heavy oil recovery (TEOR); Heterogeneity; Net to gross (N/G); Net present value (NPV),HEAT-RECOVERY; HOT-WATER; HETEROGENEITY; CONNECTIVITY; PERFORMANCE; FLOW; INJECTION; EXPLOITATION; AQUIFER; SYSTEM,"Geothermal projects, as renewable energy projects, are not economically attractive in most places of the world at the current state of development; for this reason, subsidies are required by energy and environmental authorities in order to increase the interest in such projects. In this paper, we assess and model strategies for integration of geothermal energy with oil productions of the Moerkapelle oil field in the Netherlands. To do so, numerical simulations have been employed to analyse the feasibility of a fluvial oil reservoir for the synergy potential of oil and geothermal energy exploitation. In order to implement the simulation studies, single phase and two-phase non-isothermal fluid flow modelling are utilized for the geothermal well doublet system and for water flooding in an oil reservoir (including facies heterogeneity), respectively. A series of simulations have been conducted to investigate how hot water from a geothermal reservoir beneath a heavy oil reservoir in the fluvial sedimentary system of the West Netherlands Basin can be used for Thermal Enhanced Oil Recovery (TEOR) and geothermal energy production. This study finds that the high degree of heterogeneity in fluvial oil reservoirs could significantly affect oil recovery improvement and hence the synergy strategy. High values of a) Net to gross (N/G) b) Bottom Hole Pressure (BHP) and c) horizontal wellbore length are favourable for oil recovery. In contrast, wide horizontal wellbore spacing and high oil viscosity have an adverse effect on oil recovery enhancement. Furthermore, the results display that the enhanced oil production helps to reduce the required subsidy for a single doublet geothermal project up to 100%. Consequently, the extra amount of oil produced by utilising the geothermal energy, could make the geothermal business case independent and profitable.",3,3,1
Oil Recovery,Values,"Han, Pu; Geng, Jiaming; Bai, Baojun",Investigation on transport behavior of nanogel in low permeable porous medium,Nanogel; Filtration; Membrane; Transport,LINKED POLYMER MICROSPHERES; WATER,"Nano-sized crosslinked polymeric particles (nanogels) have the advantages of both nanoparticles and hydrogels for enhanced oil recovery in the oil and gas industries. Although some encouraging progress in the application has been made, the transport behavior of nanogels through porous media are still not clear. In this work, a series of filtration experiments using membrane filter were performed to study the effect of nanogel diameter, pore size, and differential pressure on the transport behavior. The equilibrium filtration rate, which is a key parameter to indicate the transport behavior during steady state, increased from 0.19 to 5.71 mL/min when the pore size changed from 0.05 to 0.8 pm, and increased from 1.02 to 1.99 mL/min when the differential pressure raised from 10 to 30 psi. Experimental results demonstrated nanogels present smaller diameter (105.7 nm) and lower absolute value of zeta-potential ( -18.9 mV) in 10 wt% NaCl solution than distilled water (295.3 nm and - 82.5 mV). The higher salt concentration resulted in a better nanogel injectivity (equilibrium filtration rate increased from 0.77 to 4.52 when NaCl concentration changed from 0 to 10 wt%), which indicated the diameter of nanogel is a more determining factor than the nanogel strength. When the pore size was smaller than similar to 3 times of the naongel diameter, the equilibrium filtration rate became independent to the differential pressure and nanogels started to form face plugging on the membrane. The core filtration tests demonstrated that the nanogels maintained similar transport behavior through the limestone cores and membrane filters that the resistance factor is 26.59 in membrane and 18.56 in core with similar pore diameter. The transport behaviors of nanogel and corresponding mechanisms are summarized by the matching relationship between the diameter of nanogel and the pore size in low permeable porous medium.",4,4,0
Oil Recovery,Values,"Hamidian, Ramtin; Lashkarbolooki, Mostafa; Amani, Hossein","Ion type adjustment with emphasize on the presence of NaCl existence; measuring interfacial tension, wettability and spreading of crude oil in the carbonate reservoir",Spreading; Wettability; IFT; EOR; Salt; Ionic strength,SURFACE FREE-ENERGY; SMART-WATER; SALINITY; RECOVERY; INJECTION; CHALK; ADHESION; SEAWATER; EOR; COEFFICIENT,"Finding the high-performance anions and cations in the aqueous solutions are crucially required during the smart water injection make it the main core of many enhanced oil recovery (EOR) studies. Nevertheless the previously published literature revealed a lack of understanding about the synergistic or antagonistic effect of NaCl (as the most abundant salt in the sea water) and other salts with the same ionic strength on the interfacial tension (IFT), wettability alteration and spreading coefficient. Therefore, the main purpose of this study is aimed on this concern. To reach this goal, the dynamic IFT values of crude oil/different aqueous solutions with ionic strength of 0.7M and contact angle values between these phases on the oil wet carbonate surface soaked under different times in the prepared aqueous solutions are measured. After that, the measured values are used to calculate the spreading coefficient and distribution capability of oil and water phases on the carbonate rock surface. The obtained results revealed that to change the wetting state of carbonate rock toward a more water wet state, a synergistic effect was observed between NaCl and salts containing sulfate anion, i.e. Na2SO4. and MgSO4.",4,4,0
Oil Recovery,Degrees C.,"Nekoeian, Sahand; Aghajani, Masoud; Alavi, Seyed Mehdi",Experimental study of the surfactants effects on gas phase mass transfer coefficients in gas condensate reservoirs,Gas condensate reservoirs; Local equilibrium assumption; Gas phase mass transfer coefficients; Surfactants; Specific interfacial area; Spreading coefficients,ORGANIC-CHEMICALS; POROUS-MEDIA; WETTABILITY ALTERATION; LIQUID VOLATILIZATION; THERMAL-DIFFUSIVITY; DISSOLUTION; RECOVERY; OIL; CONDUCTIVITY; TRANSPORT,"Surfactant flooding in gas-condensate reservoirs, shown to be an effective treatment method to remediate condensate blockage in near well bore regions, have been the focus of several studies in the recent decades. However, the effect of these chemicals on the gas phase mass transfer coefficients has not been yet addressed though they have to be incorporated in non-equilibrium compositional simulators to imitate the reservoir behavior reliably. Besides, any knowledge of the overall effect of the surfactants on these coefficients can shed light on the side effects of the surfactant flooding on mass transfer phenomenon and evaluate its suitability as a treatment strategy. In this study, separate empirical correlations were developed for methane and isobutane representing light and intermediate components respectively in the absence and the presence of surfactants at the temperature of 40 degrees C. In all the developed correlations for both components in the presence of surfactants, while spreading coefficient has a positive exponent, equilibrium adsorption constant possesses a negative exponent. This implies that surfactants with a larger former parameter and a smaller latter parameter like SDS have more opportunity to enhance the volumetric mass transfer coefficient. The results also confirm the positive effect of pore gas velocity on gas phase mass transfer coefficients even in low gas flow rates. Similarly, this effect has already been reported in NAPL (Non Aqueous Phase Liquid) volatilization related studies. Effective diffusion coefficient, condensate saturation, mean grain size, component type, surfactant type and residual water saturation were also shown to affect these mass transfer coefficients. In addition, it has been shown that surfactants which are conventionally believed to reduce volumetric mass transfer coefficients in gas-liquid systems like bubble columns, improve gas phase mass transfer coefficients in gas condensate reservoirs. This improvement is considered a drawback for the cited technique.",0,0,1
Oil Recovery,Degrees C.,"Kanimozhi, B.; Thamizhmani, Vivek; Pranesh, Venkat; Senthil, S.; Selvakumar, Arun T.",Kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection,Carbonate reservoir; Fines migration; Water saturation; Heat transfer; Permeability decline; Pressure change,OIL-RECOVERY; RESERVOIR ROCKS; OIL/BRINE/CARBONATE SYSTEM; SLOW MIGRATION; WETTABILITY; FILTRATION; SURFACE; FIELD; PH,"Kaolinite clay fines are prevalent in sandstone porous media and it has great impacts on permeability and well productivity decline. High temperature sandstone formations detach the fines from the pore surface and migrate along with the permeating fluid. At some point the fine particles are strained in the pore throats, which leading to permeability damage and well productivity decline. To the best of our knowledge this phenomenon is not well explored in the high temperature carbonate media. Since most of the world's oil reserves are held in carbonate media and its worth to explore the formation damage, especially due to fines migration during higher reservoir temperature at these formations composed of carbonate minerals. Hence, this paper presents laboratory modeling of kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection. In this paper, we have conducted three sets of coreflood experiments in the temperature ranges of 100 degrees C 150 degrees C, and 200 degrees C. Kaolinite suspension water has been injected into the porous limestone core at these temperature regimes to investigate the possibility of permeability and injectivity deterioration. The main experimental results showed there is an increase in water saturation and heat transfer rates. Concentration of fines surges with increasing PVI and permeability declines with increasing time. Pressure elevates with enhancing PVI, but it plummets after some time. Significantly, the water discharge rate declines for increasing suspension injection and on the other side, for fresh water injection, the rate of water discharge rises steadily. Furthermore, the electrical and thermal conductivities of effluent kaolinite colloid were higher. Moreover, experimental model were tested against statistical based optimizational model, response surface methodology (RSM). These results revealed good agreement and, hence, this paper has explicated the importance of kaolinite clay fines suspension transport in high temperature carbonate reservoirs.",3,3,0
Oil Recovery,Degrees C.,"Ziabakhsh-Ganji, Zaman; Nick, Hamidreza M.; Bruhn, David F.",Investigation of the synergy potential of oil and geothermal energy from a fluvial oil reservoir,Geothermal energy; Thermal enhanced heavy oil recovery (TEOR); Heterogeneity; Net to gross (N/G); Net present value (NPV),HEAT-RECOVERY; HOT-WATER; HETEROGENEITY; CONNECTIVITY; PERFORMANCE; FLOW; INJECTION; EXPLOITATION; AQUIFER; SYSTEM,"Geothermal projects, as renewable energy projects, are not economically attractive in most places of the world at the current state of development; for this reason, subsidies are required by energy and environmental authorities in order to increase the interest in such projects. In this paper, we assess and model strategies for integration of geothermal energy with oil productions of the Moerkapelle oil field in the Netherlands. To do so, numerical simulations have been employed to analyse the feasibility of a fluvial oil reservoir for the synergy potential of oil and geothermal energy exploitation. In order to implement the simulation studies, single phase and two-phase non-isothermal fluid flow modelling are utilized for the geothermal well doublet system and for water flooding in an oil reservoir (including facies heterogeneity), respectively. A series of simulations have been conducted to investigate how hot water from a geothermal reservoir beneath a heavy oil reservoir in the fluvial sedimentary system of the West Netherlands Basin can be used for Thermal Enhanced Oil Recovery (TEOR) and geothermal energy production. This study finds that the high degree of heterogeneity in fluvial oil reservoirs could significantly affect oil recovery improvement and hence the synergy strategy. High values of a) Net to gross (N/G) b) Bottom Hole Pressure (BHP) and c) horizontal wellbore length are favourable for oil recovery. In contrast, wide horizontal wellbore spacing and high oil viscosity have an adverse effect on oil recovery enhancement. Furthermore, the results display that the enhanced oil production helps to reduce the required subsidy for a single doublet geothermal project up to 100%. Consequently, the extra amount of oil produced by utilising the geothermal energy, could make the geothermal business case independent and profitable.",3,3,1
Oil Recovery,Degrees C.,"Ramcharan, Tamitha; Hosein, Raffie",Radio Frequency Heating combined with Solvent Extraction- A method for oil recovery from surface oil sands,Radio-frequency heating; Organic solvent; Oil sands; Bitumen recovery; New method,,"Trinidad has oil sands resources of about 2 billion barrels of oil on land. However, due to the relatively small extent and surface location (about 10,000 acres and with depths varying from surface to less than 500 feet), large scale surface mining and in-situ methods such as SAGD and VAPEX that are applied to recover oil from Canadian oil sands, are not practical. From experimental and simulation studies conducted, a new method was developed to commercially recover oil from Trinidad's surface oil sands. The open literature shows Radio Frequency Heating (RFH) to be more practical than electrical resistive heating (ERH) for surface oil sands. RFH is cheaper, quicker and heating is uniform and deeper than ERH, with oil recoveries ranging from 50 to 80%. Experimental studies show the viscosity of Trinidad oil sand oil to be greater than 10,000 cp and temperatures greater than 170 degrees C are required for the oil to flow. The power requirement for applying RFH at this temperature is greater than 25 kW (kW) and very costly. In addition, vaporisation of oil components occurs at these high temperatures, which is not environmentally safe for surface application. This new oil recovery method uses RFH at low power (1 kW) with a locally extracted organic solvent. The RFH system designed and assembled consists of an RFH chamber, signal generator and low power amplifier (1 kW). Samples of oil sands were heated in the chamber to 100 degrees C using a low frequency of 11.5 MHz and a citrus oil extracted in house was injected. Bitumen recoveries in the range 60-70% were achieved after three cycles of solvent injection and RFH. Experimental studies conducted show that Trinidad oil sands have a clay content in the range of 10-20%, are water wetting with a water saturation in the range 10-20% and have relative permittivities in the range 38-100. From this data, a new mathematical correlation was developed to obtain permittivities of oil sands which can be used with industry software to simulate oil recovery by RFH. Simulation studies show that for a 70% recovery from three cycles, eight gallons of solvent per cycle are required with RFH at a temperature of 100 degrees C. The data from the experimental and simulation studies show that with a heating cost of 2.50 USD to produce a barrel of oil, a solvent cost of 16 USD/barrel and with drilling, equipment and operational costs, and this method is viable at an oil price over 25 USD/barrel. The low cost and minimal environmental impact of this new method makes it very attractive for oil extraction from surface oil sands.",4,4,1
Oil Recovery,Degrees C.,"Hong, Eunji; Jeong, Moon Sik; Lee, Kun Sang",Optimization of nonisothermal selective plugging with a thermally active biopolymer,Microbial enhanced oil recovery (MEOR); High-temperature reservoir; Selective plugging; Nonisothermal biokinetics; Leuconostoc mesenteroides,ENHANCED OIL-RECOVERY; LEUCONOSTOC-MESENTEROIDES; BIOSURFACTANT PRODUCTION; KINETICS; TEMPERATURE; MODEL; DEXTRANSUCRASE; RESERVOIRS; METABOLISM; TRANSPORT,"A novel concept of microbial enhanced oil recovery (MEOR) under nonisothermal conditions was developed based on temperature-dependent biokinetics. The model specified the use of temperature-triggered Dextran (a biopolymer) produced by Leuconostoc mesenteroides (a microbe). The effects of environmental temperature on microbial growth and biopolymer production were validated and calibrated using the cardinal temperature model and experimental results. Various biokinetic parameters and a permeability reduction factor were also obtained to within approximately 2% error of those previously reported sandpack experiment. Based on the developed nonisothermal biokinetic model and the permeability reduction factor, thermally active MEOR was analyzed for a high-temperature reservoir. The results suggested the influences of injection parameters, such as injected nutrient concentration, rate, and temperature, on oil recovery factor. Higher nutrient concentrations resulted in increased Dextran production, thereby increasing oil recovery by selective plugging. On the other hand, injection rate and temperature were related to Dextran distributions. Higher injection rates led to lower Dextran concentrations with wider distributions. The injection temperature controlled the location of trapped Dextran in porous media, thereby influencing oil recovery. Through the optimization process, the injection design was determined with a rate of 30 m(3).day(-1), temperature of 5 degrees C, and nutrient mole fraction of 0.009. The suggested optimal injection design resulted in the largest oil recovery (39%) for a highly heterogeneous layered reservoir.",4,4,1
Oil Recovery,Degrees C.,"Zhou, Ming; Yi, Rongjun; Gu, Yinghua; Tu, Hongjun",Synthesis and evaluation of a Tetra-copolymer for oil displacement,Synthesis; AM/DAAM/AMPS/DMAM Tetra-copolymer; Orthogonal test; Characterization; Viscosity retention rate; Enhancing oil recovery,PARTIALLY HYDROLYZED POLYACRYLAMIDE; MECHANICAL DEGRADATION; ACRYLAMIDE; RECOVERY; POLYMERS; MICROSPHERES; RHEOLOGY; BEHAVIOR,"In this paper, acrylamide (AM), 2-acrylamide-2-methylpropane sulfonic acid (AMPS), diacetone acrylamide (DAAM) were used as the basic monomers, and N, N-dimethylacrylamide (DMAM) with hydrophobic groups was introduced as the fourth monomer. The AM/DAAM/AMPS/DMAM Tetra-copolymer was synthesized by aqueous solution polymerization using the redox system of potassium persulfate and sodium bisulfite as initiator. The synthesis conditions of the copolymer were optimized by orthogonal test with five factors and four levels. The structure of the copolymer was characterized by FTIR and the thermal stability of the copolymer was analyzed by TGA. Relevant experimental results showed that the viscosity retention rate of the copolymer was higher than that of HPAM at the same temperature, salinity and shear rate. The viscosity retention rate of the copolymer was 72.7% after aging 30 days at 90 degrees C in the solution with 15000 mg/L the total salinity. The oil displacement experiment showed that the average recovery of the polymer flooding with 1000 mg/L prepared copolymer was as high as 10.8%.",4,4,9
Oil Recovery,Degrees C.,"Sinha, Vineet; Ahmeda, Ramadan; Akhtar, Tarek; Shah, Subhash; Amani, Mahmood",Rheology and hydraulics of polymer-based foams at elevated temperatures,Foam; Polymer; Stimulation; Rheology; Hydraulics; Drilling,CONSTITUTIVE EQUATION; DRILLING FOAMS; FLOW BEHAVIOR; AQUEOUS FOAMS; FLUID-FLOWS; VISCOSITY; SUSPENSION,"Foam has been successfully used for different operations like well stimulation, drilling, enhanced oil recovery (EOR), cleanout, and acidizing operations in the oil and gas industry. Additionally, the low liquid content of foam provides a distinct advantage in terms of lesser material requirements. However, accurate prediction of rheology is necessary for the success of field operations, which requires a rheological model that incorporates the effect of temperature on foam properties as it circulates downhole. In the present investigation, polyanionic cellulose (PAC) based foam was generated using nitrogen as the gas phase and its rheology was determined using a recirculating flow loop that has three pipe viscometers (3.05, 6.22, and 12.7 mm ID) and a fully-eccentric annular section (9.53 mm OD x 12.57 mm ID). Experiments were conducted within the temperature range of 24 to 149 degrees C and at various foam qualities (gas phase volume fraction). The foam was circulated at different flow rates and the differential pressure across each pipe section was recorded. All tests were conducted at 6.89 MPa. The foams displayed power-law fluid behavior in the shear rate range tested (100-5000 s(-1)), which is often experienced in the wellbore. Like its base liquid, polymer foam exhibited thermal thinning and a significant rheology change with temperature. Only high-quality foam (75%) at ambient temperature (24 degrees C) showed yielding behavior, which was measured in a pipe viscometer under static condition. The disappearance of yield stress at elevated temperature could be attributed to thermal thinning of the liquid phase that weakens the strength of bubble structure. Experimental data is used to develop new correlations to predict power-law fluid parameters as a function of temperature, base fluid properties, and foam quality. Moreover, the measurements are compared with the predictions of existing models, and discrepancies are observed, which could be attributed to the variation in foam generation technique, the nature and concentration of polymer, and the concentration of surfactant used in the experiments in which data was obtained to develop the models. Furthermore, annular pressure loss measurements obtained at low temperatures (24 and 79 degrees C) show predominantly good agreement with predictions of a hydraulic model that uses the new correlations. Discrepancies increased with temperature as the foam becomes unstable due to thermal thinning of the liquid film and subsequent weakening of bubble structure.",5,5,1
Oil Recovery,Heat,"Ranjbar, Ehsan; Ghaderi, Seyyed M.; Nourozieh, Hossein; Kumar, Anjani; Takbiri-Borujeni, Ali",Two-phase and three-phase equilibrium K-values for modelling of non-condensable gas Co-Injection processes,Thermal recovery; Heavy oil; Gas; Modelling; K-value,VAPOR-LIQUID-EQUILIBRIA; CARBON DIOXIDE-WATER; METHANE PLUS WATER; COLD LAKE BITUMEN; SOLUBILITY MEASUREMENT; PHASE-EQUILIBRIA; NATURAL GASES; AQUEOUS NACL; NITROGEN; PRESSURES,"To improve the efficiency of Steam Assisted Gravity Drainage process (SAGD), a small amount of non-condensable gases can be added to steam. The non-condensable gas creates an insulation film at the top of the steam chamber as a result of gas accumulation. This could prevent heat loss to the overburden, increase steam chamber propagation in the lateral direction, and consequently improve the SAGD performance. Field-scale modelling and simulation of non-condensable gas injection in a hybrid SAGD process requires a comprehensive numerical model that includes variety of mechanisms involved in the processes. During the steam/non-condensable gas co-injection, the non-condensable gas may partially be dissolved in bitumen and water, accounting for a portion of gas production from the chamber. Therefore, in order to accurately model the non-condensable gas injection process, the partitioning of the gas among the phases (oleic and aqueous) must be well understood. The most significant challenge of modelling multi-phase equilibrium in gas/bitumen/water systems is the lack of three-phase equilibrium data. This study presents a methodology to generate two-phase and three-phase K-values from the experimental solubility data. The data for binary systems at certain temperatures and pressures is translated into equilibrium K-values. The K-values were calculated either from a correlation representing the phase behavior data or from an equation of state coupled with Henry's law. Then, the generated two-phase and three-phase K-values were directly implemented in reservoir simulators to account for component partitioning in different phases. The results indicate that the generated K-values would be applicable for different types of bitumen.",2,2,0
Oil Recovery,Heat,"Cheng, Gang; Pang, Zhanxi; Jiang, Yanming; Wang, Bo; Yu, Xiaogang",Thermodynamic analysis and prediction of reservoir temperature distribution for steam stimulation,Steam stimulation; Temperature distribution; Heat conduction; Heat convection; Energy balance equation,ASSISTED-GRAVITY-DRAINAGE; HEAT-TRANSFER; OIL-RECOVERY; POROUS-MEDIA; THERMAL RECOVERY; DISPLACEMENT; INJECTION; FLOW,"During steam stimulation of horizontal wells in heavy oil reservoir, it is necessary to estimate the reservoir temperature distribution, which has a huge impact on oil production and ultimate oil recovery. Most of previous models were derived based on infinite boundary condition and constant fluid velocity, which were not consistent with real situation of reservoir. In this paper, new energy balance equations combined with mobile boundary conditions were developed for increasing the accuracy of predicted results. Based on dimensionless conversion and numerical analysis, the optimum solution of equation system could be easily obtained, and its good performance in predicting temperature distribution was also validated. Moreover, thermodynamic mechanism of hot fluid, latent heat and sensible heat of steam, and their contributions to heating reservoir were also discussed to investigate the heat transfer pattern in reservoir. Finally, factors that could influence the reservoir temperature distribution were analyzed. It is found that: (a) both the heat conduction and the heat convection contribute to the heat transfer in hot liquid zone, and the heat convection predominates; (b) both the condensation front and heat front move outward with the injection of steam, but their expanding rates gradually drop with time; (c) as the radius increases, the radial fluid velocity will go down, leading the heat convection effect to be weakened and the heat conduction effect to become obvious; (d) there are some factors that can influence the reservoir temperature distribution including steam injection duration, fluid velocity, volumetric heat capacity of fluid, steam quality and thermal conductivity of reservoir.",2,2,2
Oil Recovery,Heat,"Kanimozhi, B.; Thamizhmani, Vivek; Pranesh, Venkat; Senthil, S.; Selvakumar, Arun T.",Kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection,Carbonate reservoir; Fines migration; Water saturation; Heat transfer; Permeability decline; Pressure change,OIL-RECOVERY; RESERVOIR ROCKS; OIL/BRINE/CARBONATE SYSTEM; SLOW MIGRATION; WETTABILITY; FILTRATION; SURFACE; FIELD; PH,"Kaolinite clay fines are prevalent in sandstone porous media and it has great impacts on permeability and well productivity decline. High temperature sandstone formations detach the fines from the pore surface and migrate along with the permeating fluid. At some point the fine particles are strained in the pore throats, which leading to permeability damage and well productivity decline. To the best of our knowledge this phenomenon is not well explored in the high temperature carbonate media. Since most of the world's oil reserves are held in carbonate media and its worth to explore the formation damage, especially due to fines migration during higher reservoir temperature at these formations composed of carbonate minerals. Hence, this paper presents laboratory modeling of kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection. In this paper, we have conducted three sets of coreflood experiments in the temperature ranges of 100 degrees C 150 degrees C, and 200 degrees C. Kaolinite suspension water has been injected into the porous limestone core at these temperature regimes to investigate the possibility of permeability and injectivity deterioration. The main experimental results showed there is an increase in water saturation and heat transfer rates. Concentration of fines surges with increasing PVI and permeability declines with increasing time. Pressure elevates with enhancing PVI, but it plummets after some time. Significantly, the water discharge rate declines for increasing suspension injection and on the other side, for fresh water injection, the rate of water discharge rises steadily. Furthermore, the electrical and thermal conductivities of effluent kaolinite colloid were higher. Moreover, experimental model were tested against statistical based optimizational model, response surface methodology (RSM). These results revealed good agreement and, hence, this paper has explicated the importance of kaolinite clay fines suspension transport in high temperature carbonate reservoirs.",3,3,0
Oil Recovery,Heat,"Pu, Wan-fen; Gong, Xiao-long; Chen, Ya-fei; Liu, Xue-li; Hui, Jian; Guo, Chen; Varfolomeev, Mikhail A.",Oxidation kinetic evaluation of the low temperature oxidized products of Tahe heavy oil characterized by the distributed activation energy model,Heavy oil; Low temperature oxidation; Oxidized product; Oxidation kinetic; Coke deposition; DAEM,IN-SITU-COMBUSTION; PRESSURE AIR INJECTION; LIGHT CRUDE-OIL; SARA FRACTIONS; BEHAVIOR; COKING; PREDICTABILITY; RECOVERY; TG,"In view of the significance of low temperature oxidation (LTO) for in-situ combustion (ISC) of heavy crude oil and to provide further data for Tahe ISC numerical simulation, this research aimed to investigate the non-isothermal oxidation behavior of heavy oil after static LTO reactions. Thermogravimetric (TG) and differential scanning calorimetry (DSC) techniques were used to characterize oxidation behavior, and distributed activation energy method (DAEM) was used to calculate kinetic parameters. The results showed that the non-isothermal oxidation process of static LTO oxidized oil was the result of the interaction between residue and coke, and coke can significantly reduce the activation energy of oxidized oil. Only one HTO region was identified for the coke from DTG/DSC curves, and it had the lowest activation energy (114.57 kJ/mol) and the highest heat enthalpy (24.3 kJ/g), indicating high oxidative activity with maximum heat release potential. A satisfactory corresponding relation between DTG and DSC curves was presented for all samples in FD and HTO regions, which indicated that the sequential reaction mechanisms, fuel deposition and combustion, were undergone. In LTO region, there was a temperature difference between the peaks of the mass loss and heat flow, indicating that the LTO process was more complex with a multi-step control mechanism should be considered to analyze and simulate the LTO stage.",3,3,1
Oil Recovery,Heat,"Ramcharan, Tamitha; Hosein, Raffie",Radio Frequency Heating combined with Solvent Extraction- A method for oil recovery from surface oil sands,Radio-frequency heating; Organic solvent; Oil sands; Bitumen recovery; New method,,"Trinidad has oil sands resources of about 2 billion barrels of oil on land. However, due to the relatively small extent and surface location (about 10,000 acres and with depths varying from surface to less than 500 feet), large scale surface mining and in-situ methods such as SAGD and VAPEX that are applied to recover oil from Canadian oil sands, are not practical. From experimental and simulation studies conducted, a new method was developed to commercially recover oil from Trinidad's surface oil sands. The open literature shows Radio Frequency Heating (RFH) to be more practical than electrical resistive heating (ERH) for surface oil sands. RFH is cheaper, quicker and heating is uniform and deeper than ERH, with oil recoveries ranging from 50 to 80%. Experimental studies show the viscosity of Trinidad oil sand oil to be greater than 10,000 cp and temperatures greater than 170 degrees C are required for the oil to flow. The power requirement for applying RFH at this temperature is greater than 25 kW (kW) and very costly. In addition, vaporisation of oil components occurs at these high temperatures, which is not environmentally safe for surface application. This new oil recovery method uses RFH at low power (1 kW) with a locally extracted organic solvent. The RFH system designed and assembled consists of an RFH chamber, signal generator and low power amplifier (1 kW). Samples of oil sands were heated in the chamber to 100 degrees C using a low frequency of 11.5 MHz and a citrus oil extracted in house was injected. Bitumen recoveries in the range 60-70% were achieved after three cycles of solvent injection and RFH. Experimental studies conducted show that Trinidad oil sands have a clay content in the range of 10-20%, are water wetting with a water saturation in the range 10-20% and have relative permittivities in the range 38-100. From this data, a new mathematical correlation was developed to obtain permittivities of oil sands which can be used with industry software to simulate oil recovery by RFH. Simulation studies show that for a 70% recovery from three cycles, eight gallons of solvent per cycle are required with RFH at a temperature of 100 degrees C. The data from the experimental and simulation studies show that with a heating cost of 2.50 USD to produce a barrel of oil, a solvent cost of 16 USD/barrel and with drilling, equipment and operational costs, and this method is viable at an oil price over 25 USD/barrel. The low cost and minimal environmental impact of this new method makes it very attractive for oil extraction from surface oil sands.",4,4,1
Oil Recovery,Heat,"Morte, Matthew; Hascakir, Berna",Characterization of complex permittivity for consolidated core samples by utilization of mixing rules,Microwave; Complex permittivity; Mixing rule; Electromagnetic heating,DIELECTRIC-PROPERTIES; OIL-RECOVERY; ELECTRICAL-PROPERTIES; CONSTANT; MHZ,"Candidacy of any reservoir as a microwave absorber is predicated on the complex permittivity of the sample. Modeling both the penetration and absorption dynamics of the electromagnetic wave in the reservoir is dependent on realistic estimation of this parameter. Therefore, it becomes necessary to understand the inherent intricacies of complex permittivity in the reservoir. Reservoirs are comprised of both a void space represented by the porosity parameter as well as the rock matrix and can be treated as a binary mixture of the two. Mixing rules can then be introduced and have been shown to be a viable means of estimating the dielectric response. The behavior of the bulk material is considered to be an extension of the isolated contribution of the separate parts. Therefore, by characterizing the response of the individual components of the mixture, the overall response can be estimated. Utilization of mixing rules enables efficient estimation of the dielectric properties anywhere in the reservoir as a function of the rock matrix, fluid saturation, and porosity. The absorptive capacity of the reservoir can then be described which is used to screen the efficacy of the material for microwave introduction. Both the real and imaginary components of complex permittivity are measured on nine consolidated core samples of varying lithology and fluid saturation over the frequency range of 400 MHz to 6 GHz. Experimental data is compared to various mixing rules commonly implemented to determine validity and viability of the estimation of complex permittivity for consolidated samples.",4,4,2
Oil Recovery,Relative Permeability,"Wang, Shuoliang; Yu, Chunlei; Sang, Guoqiang; Zhao, Qianhui",A new numerical simulator considering the effect of enhanced liquid on relative permeability,Enhanced liquid; Flow velocity; Relative permeability; Numerical simulation,STATE 2-PHASE FLOW; POROUS-MEDIA; OIL-RECOVERY; FLUID; PLANAR; MODEL,"Enhanced liquid treatment magnifies the difference of fluid flow velocity between borehole and inter-well zones. The flow velocity will influence the relative permeability and change the percolation law in the oil-water two phase flow. In this study, we conduct three group experiments with different permeability using 15 artificial cores. The unsteady-states measurement method is used to test the relative permeability curve at different velocities. We found that relative permeability would be affected by the testing velocity based on the experimental results. A new relative permeability equation considering flow velocity is established, which indicates that higher oil recovery can be obtained by an early enhanced liquid treatment. There is also a critical velocity with different permeability. If the flow rate (v(w)) of the enhanced liquid treatment is larger than the critical velocity, the treatment will improve the oil recovery. On the contrary, if the v(w) of the enhanced liquid treatment is larger than the critical velocity, the treatment will reduce the oil recovery. We summarize the new relative permeability equation and implement it to the numerical simulation model. The new simulator is validated with the three-parallel sand-pack experiment and the actual China offshore oilfield model. The new simulator could predict oil production accurately after enhanced liquid treatment.",1,1,0
Oil Recovery,Relative Permeability,"Kim, Tae Wook; Vittoratos, Euthymios; Kovscek, Anthony R.",Recovery efficiency of a 28 degrees API crude-oil system as a function of voidage replacement ratio,Water flooding; Voidage replacement; Laboratory studies; Improved oil recovery,SOLUTION-GAS DRIVE; RELATIVE PERMEABILITY,"Crude-oil recovery processes with a voidage replacement ratio (VRR = injected volume/produced volume) less than 1 combine solution gas drive mechanisms and viscous crude-oil displacement. Previous laboratory and field studies have shown that a VRR less than 1 for a period of time is optimal for recovery of some viscous and heavy crude oils that form emulsions and/or bubbly oil in situ. This study extends understanding of the effect of VRR to recovery of live, less-viscous crude oils from sands. The crude oil used is roughly 28 degrees API, has a dead-oil viscosity of 26 cP, a live-oil viscosity of 0.41 cP, and an asphalt content of 2.1 wt%. It is found in the laboratory that the final crude-oil recovery (70.5%) using a 0.01 PV/h depletion rate and VRR equal to 0.7 is more than 8% greater than recovery with VRR equal to 1 (65.1%). Recovery using a 0.001 PV/h depletion rate with VRR equal to 0.7 (79.1%) was nearly the same as the sum of oil recoveries for solution gas drive (VRR = 0, 24.5%) plus waterflooding (VRR = 1, 53.4%). For these two depletion rates, the oil recovery obtained using VRR equal to 0.7 is more favorable than VRR = 1 (waterflooding). Relative permeability was inferred from experimental results. Substantial critical gas saturations (8.1-16.1%) also contributed to oil production. A concave shape of the oil/water relative permeability curve indicated an emulsion-like effect that also promoted recovery when the VRR was less than 1.",1,1,0
Oil Recovery,Relative Permeability,"Karacan, C. Ozgen",An ANCOVA model for porosity and its uncertainty for oil reservoirs based on TORIS dataset,Mean value; Depositional system; Multi-linear regression; Reservoir assessment; ANCOVA; TORIS,PERMEABILITY PREDICTION; SEDIMENTARY; NORTH; SANDSTONE; EOCENE; ROCKS,"Porosity is one of the most important parameters to assess in-place oil or gas in reservoirs, and to evaluate recovery from enhanced production operations. Since it is relatively well-established to determine porosity using different laboratory and field methods, its value is usually determined at many locations across a reservoir as part of the common practice to capture reservoir heterogeneity and the variability in values. This suite of measurements and the distribution of values are most valuable for probabilistic reservoir assessments, and for spatial modeling if the exact data locations are known. Despite the importance of individual measurements to set the range of values for probabilistic studies, it is not always possible to access these data due to confidentiality. In most cases, commercial or publicly available databases that assessments may rely on usually report only mean values of porosity, like any other reservoir data, or they may not report a value at all. This makes both quantifying the mean value and the uncertainty around it difficult for probabilistic assessments. In this study, the TORIS (Tertiary Oil Recovery Information System) dataset of the National Petroleum Council and the U.S. Department of Energy was used to model porosity and the uncertainty around predicted values. TORIS is an integrated dataset of production data, reservoir properties, and project databases of crude oil reservoirs in the United States. The model presented in the paper was based on ANCOVA (Analysis of Co-Variance) of data from 1038 reservoirs from the TORIS dataset for porosity prediction, validation and testing for quantitative and qualitative parameters that may be readily available in most cases, and to estimate uncertainty around the mean values. This model also explored association of porosity values to different parameters, and to different depositional systems and diagenetic overprint conditions. Furthermore, an ANN (Artificial Neural Network) model was created to compare the predicted values of both models. Results showed that the ANN model was able to represent more of the variability, however it lacked the insights that might be gained from the ANCOVA model.",1,1,0
Oil Recovery,Relative Permeability,"Hannon, Michael J., Jr.; Tucker, Yael Tarlovsky; Soeder, Daniel J.","Quantifying the effects of gaseous pore pressure and net confining stress on low-permeability cores using the ""RaSSCAL"" steady-state permeameter",Core analysis; Unconventional oil & gas; Shale; Permeability,,"Subsurface engineering systems undergo large changes in pore pressure, which can have drastic effects on their ability to transport and store fluids. For rock samples retrieved from conventional reservoirs, standard core analysis procedures provide suitable estimates of petrophysical properties, such as porosity and permeability. However, performing similar investigations on low-permeability systems like shales and tight gas sands remains a challenge. Steady-state gas permeametry is considered the gold standard for analyzing low-permeability cores, but researchers often forego it in favor of faster but less reliable methods. Attempting a conventional permeability test on a tight plug sample typically results in miniscule flow rates that only expensive, specialized equipment can measure directly. Furthermore, these time-consuming tests are best run multiple times under varying ranges of pore pressure and confining stress. Doing so allows one to anticipate suitably the changes in permeability that will occur because of the expected changes in reservoir conditions. This study describes the methodology of the Randolph Steady-State Core Analysis Laboratory (RaSSCAL), a new experimental design and data analysis algorithm that accounts for changes in permeability over the range of pore pressures and confining stresses that occur during processes like unconventional hydrocarbon recovery and geologic carbon sequestration. Routine steady-state core analysis requires relatively small pressure drops across the sample so a uniform apparent permeability can be assumed. The approach outlined here enables an effective interpretation of core-flood data in the presence of arbitrarily large pressure gradients. The experiment maintains a near-constant pressure difference of arbitrary magnitude across a core-plug sample and indirectly measures the flow rate induced by that gradient using a differential pressure transmitter. Tests were performed on a Marcellus Shale sample from Bedford, Pennsylvania and an Oriskany Sandstone sample from Berkeley Springs, West Virginia over a wide array of pore pressures and net confining stresses using helium and methane gas. Having a quantifiable understanding of how the permeability of the system may change during the various stages of subsurface activity should significantly enhance the ability to optimize design outcomes. This will ultimately lead to improved oil and gas recovery and better predictions of injectivity and storage capacity during carbon-storage operations.",4,4,0
Oil Recovery,Relative Permeability,"Hong, Eunji; Jeong, Moon Sik; Lee, Kun Sang",Optimization of nonisothermal selective plugging with a thermally active biopolymer,Microbial enhanced oil recovery (MEOR); High-temperature reservoir; Selective plugging; Nonisothermal biokinetics; Leuconostoc mesenteroides,ENHANCED OIL-RECOVERY; LEUCONOSTOC-MESENTEROIDES; BIOSURFACTANT PRODUCTION; KINETICS; TEMPERATURE; MODEL; DEXTRANSUCRASE; RESERVOIRS; METABOLISM; TRANSPORT,"A novel concept of microbial enhanced oil recovery (MEOR) under nonisothermal conditions was developed based on temperature-dependent biokinetics. The model specified the use of temperature-triggered Dextran (a biopolymer) produced by Leuconostoc mesenteroides (a microbe). The effects of environmental temperature on microbial growth and biopolymer production were validated and calibrated using the cardinal temperature model and experimental results. Various biokinetic parameters and a permeability reduction factor were also obtained to within approximately 2% error of those previously reported sandpack experiment. Based on the developed nonisothermal biokinetic model and the permeability reduction factor, thermally active MEOR was analyzed for a high-temperature reservoir. The results suggested the influences of injection parameters, such as injected nutrient concentration, rate, and temperature, on oil recovery factor. Higher nutrient concentrations resulted in increased Dextran production, thereby increasing oil recovery by selective plugging. On the other hand, injection rate and temperature were related to Dextran distributions. Higher injection rates led to lower Dextran concentrations with wider distributions. The injection temperature controlled the location of trapped Dextran in porous media, thereby influencing oil recovery. Through the optimization process, the injection design was determined with a rate of 30 m(3).day(-1), temperature of 5 degrees C, and nutrient mole fraction of 0.009. The suggested optimal injection design resulted in the largest oil recovery (39%) for a highly heterogeneous layered reservoir.",4,4,1
Oil Recovery,Algorithm,"Hussain, Masroor; Ansari, Shahab U.; Manzoor, Tareq; Ahmad, Aijaz; Khan, Khurram Imran",Performance analysis of parallel stabilized mixed Galerkin method for three-dimensional transient Darcy flow using mesh reordering techniques,OpenMP; Mesh reordering; Stabilized mixed methods; Transient Darcy flow; Shared memory,COMPUTATIONAL FLUID-DYNAMICS; FINITE-ELEMENT FORMULATION; WAY PARTITIONING SCHEME; NUMERICAL-SOLUTION; OIL-RECOVERY; SIMULATION,"This study is related to parallel stabilized mixed Galerkin method for 3-D transient flow through porous media using OpenMP specifications for shared type memory architectures. The stabilized mixed Galerkin formulation employs standard finite elements and first-order backward difference for transient analysis. The computational complexity of the finite element method increases by increasing the number of elements requisite for large and complicated systems specifically for petroleum crude reservoirs, which leads to a large number of data elements for high performance. The shared memory architecture provides a platform for solving such difficult and big problems of new areas. In parallel finite element methods, the mesh reorganizing/partitioning is considered to be a significant preprocessing process to improve efficiency. The focus of the present case-study is to analyze the performances of octree-based and multilevel-based mesh reordering techniques. The analysis is carried out by running the parallel Darcy flow algorithms on AMD Opteron processors using tetrahedral and hexahedral meshes. The performance of the algorithm is estimated by computing the respective execution time, running time and algorithm efficiency. Major findings of this study are: (1) the octree-based mesh reordering outclasses multilevel graph-based method by at least 200% in terms of execution time, (2) the hexahedral meshes which are structured meshes show better scalability as compared to the tetrahedral meshes by a factor of 5, and (3) finally, octree mesh reordering demonstrates poor scalability in multithreaded environment as compared to multilevel graph partitioning method due to O(P-2) overhead.",0,0,0
Oil Recovery,Algorithm,"Zhou, Kaibo; Zhang, Shuo; Huang, Zhen; Zhang, Jianyu",An improved TSVD-GCV inversion algorithm of pore size distribution in time-domain induced polarization using migration Hankel matrix,Time-domain induced polarization; Pore size distribution; Migration Hankel matrix; Backus-Gilbert theory; TSVD-GCV,PARAMETER DETERMINATION; NOISE-REDUCTION; PERMEABILITY; SVD; RESERVOIR; IMAGES,"Reservoir porosity obtained from time-domain induced polarization (TDIP) well logging plays a vital role in estimating the hydraulic properties and obtain the reservoir parameters in a water-flood oil-field. Improving the inversion accuracy of the reservoir porosity can enhance the oil recovery in the water-flood oil-filed. Evaluating reservoir pore size distribution through induced polarization decay curve is confronted with the problems of poor applicability of data pre-processing, low accuracy and lacking of evaluation criteria for inversion results of pore size distribution. The basic principles of TDIP are introduced and the relationship between pore relaxation time and pore diameter is given. Combining the mathematical characteristics of polarization decay curve data, the performance and the limitations of existing pre-processing algorithms are analyzed and pointed out, respectively. An improved data pre-processing algorithm using the spatial characteristics of linear transformation based on migration Hankel matrix is proposed, and this method improves the inversion accuracy of pore size distribution greatly. In the engineering application, 2-logarithmic sampling method is proposed to sample the polarization decay data for more efficient petroleum exploration with less sample points. The different regularization methods, regularization matrix and regularization parameter determination methods are compared and analyzed for the inversion of the pore size distribution. The numerical simulation experimental results show that the stability and accuracy of Truncated Singular Value Decomposition - Generalized Cross Validation (TSVD-GCV), Truncated Singular Value Decomposition - L Curve (TSVD-L) and Tikhonov-I-L are appropriate for the inversion of pore size distribution. Because of the truth that the pore size distribution of rock is unknown, Backus-Gilbert (BG) theory is introduced to evaluate the inversion results of rock polarization decay curve data of a mining area in Jilin Province. The rock sample experiment shows that the TSVD-GCV inversion algorithm has the best performance.",1,1,5
Oil Recovery,Algorithm,"Ni, Hong-mei; Liu, Yong-jian; Fan, Ying-cai",Optimization of injection scheme to maximizing cumulative oil steam ratio based on improved artificial bee colony algorithm,Artificial bee colony algorithm; Steam flooding; Chaos optimization operator; Adaptive recombination; Random perturbation,PERFORMANCE; SYSTEM,"To address the optimization of injection scheme of steam flooding, an injection optimization method of steam flooding based on improved artificial bee colony (IABC) algorithm is proposed. Firstly, a mathematical model of steam flooding scheme optimization is established, and then the IABC algorithm is used to solve the model and optimize the injection scheme of steam flooding. In the IABC algorithm, we introduce a chaos optimization operator to generate initial solutions and apply an adaptive recombination operator to ensure the diversity of the population. In addition, we use a random perturbation operator based on the evolutionary stagnation step to improve the search ability of artificial bee colony algorithm. The experimental results show that the established model is accurate and the optimization algorithm is effective. It can be seen that the injection scheme of steam flooding optimized by the IABC algorithm can increase more cumulative oil steam ratio and cumulative oil production than that optimized by similar algorithms. The proposed method can obtain maximum recovery, and can significantly improve economic efficiency.",3,3,1
Oil Recovery,Algorithm,"Hannon, Michael J., Jr.; Tucker, Yael Tarlovsky; Soeder, Daniel J.","Quantifying the effects of gaseous pore pressure and net confining stress on low-permeability cores using the ""RaSSCAL"" steady-state permeameter",Core analysis; Unconventional oil & gas; Shale; Permeability,,"Subsurface engineering systems undergo large changes in pore pressure, which can have drastic effects on their ability to transport and store fluids. For rock samples retrieved from conventional reservoirs, standard core analysis procedures provide suitable estimates of petrophysical properties, such as porosity and permeability. However, performing similar investigations on low-permeability systems like shales and tight gas sands remains a challenge. Steady-state gas permeametry is considered the gold standard for analyzing low-permeability cores, but researchers often forego it in favor of faster but less reliable methods. Attempting a conventional permeability test on a tight plug sample typically results in miniscule flow rates that only expensive, specialized equipment can measure directly. Furthermore, these time-consuming tests are best run multiple times under varying ranges of pore pressure and confining stress. Doing so allows one to anticipate suitably the changes in permeability that will occur because of the expected changes in reservoir conditions. This study describes the methodology of the Randolph Steady-State Core Analysis Laboratory (RaSSCAL), a new experimental design and data analysis algorithm that accounts for changes in permeability over the range of pore pressures and confining stresses that occur during processes like unconventional hydrocarbon recovery and geologic carbon sequestration. Routine steady-state core analysis requires relatively small pressure drops across the sample so a uniform apparent permeability can be assumed. The approach outlined here enables an effective interpretation of core-flood data in the presence of arbitrarily large pressure gradients. The experiment maintains a near-constant pressure difference of arbitrary magnitude across a core-plug sample and indirectly measures the flow rate induced by that gradient using a differential pressure transmitter. Tests were performed on a Marcellus Shale sample from Bedford, Pennsylvania and an Oriskany Sandstone sample from Berkeley Springs, West Virginia over a wide array of pore pressures and net confining stresses using helium and methane gas. Having a quantifiable understanding of how the permeability of the system may change during the various stages of subsurface activity should significantly enhance the ability to optimize design outcomes. This will ultimately lead to improved oil and gas recovery and better predictions of injectivity and storage capacity during carbon-storage operations.",4,4,0
Oil Recovery,Algorithm,"Naik, Pratik; Aramideh, Soroush; Ardekani, Arezoo M.",History matching of surfactant-polymer flooding using polynomial chaos expansion,Surfactant-polymer flooding model; History matching; Calibration; Polynomial chaos expansion; Genetic algorithm; Kriging,GLOBAL SENSITIVITY-ANALYSIS; WIENER-HERMITE EXPANSION; UNCERTAINTY QUANTIFICATION; GENETIC ALGORITHMS; RESERVOIR SIMULATION; MODEL TURBULENCE; OPTIMIZATION; PARAMETERS; CALIBRATION,"This paper proposes a robust framework for history matching which employs a sequential execution of sensitivity analysis, proxy modeling and inverse optimization to determine the optimized parameter space of model parameters. A mechanistic surfactant-polymer (SP) flood model is considered for history matching with an ultimate goal of accurately calibrating models that describe physical subprocesses of surfactant flooding, polymer flooding and displacement process. The employed model calibration algorithm starts with Sobol sensitivity analysis which reduces the large uncertain space of model parameters to determine the most important stochastic variables. The resulting low-dimensional parameter space is then represented via appropriate orthonormal basis of polynomial chaos expansion (PCE-proxy). An inverse optimization problem is then posed that minimizes the miss-fit between PCE-proxy response and experimental observations by employing a Genetic Algorithm. Finally, the epistemic uncertainty in PCE-proxy is quantified by combining it with a Gaussian regression process called Kriging. We use this framework to calibrate the SP flood model by history matching a single coreflood experiment for quantities of interest such as pressure drop profile and cumulative oil recovery curve. We then show that the calibrated model is successfully able to predict all our quantities of interest for two other coreflood experiments without any ad-hoc tuning of parameters. The proposed proxy-accelerated inverse optimization framework shows significant promise for model calibration or to improve the quality of history matched results.",5,5,0
Oil Recovery,Hydraulic Fracture,"Phan, T. N.; Zapata, Y. M.; Kabir, C. S.; Pigott, J. D.; Pranter, M. J.; Reza, Z. A.",Probing hydraulically-fractured wells in unconventional shale reservoirs under cyclic CO2 injection: Variation of thermophysical properties,Unconventional reservoirs; CO2 cyclic injection; Exploring variation of thermophysical properties; Understanding injection-soaking-production cycles; Realistic oil recovery with large number of cycles; Molecular diffusion yields 6% incremental oil,OIL RESERVOIRS,"Despite the recent growth in oil production from unconventional reservoirs, existing hydraulically-fractured horizontal wells face challenges of poor recovery with the rapid production decline over a short life span. Enhanced recovery techniques, such as cyclic CO2 injection can be a solution to this impending problem and lead to energy independence for the foreseeable future. However, mechanisms occurring around the hydraulically fractured wells are far from fully understood. The primary motivation of this study revolves around addressing this limitation. Specifically, we explored the evolution of various thermophysical properties occurring around hydraulically-fractured wells in liquid-rich unconventional reservoirs using a holistic, integrated modeling framework. Available well-logs and other data from Howard County in the Midland Basin formed the basis for constructing representative 3D structural models that capture the Midland Basin stratigraphy. We used a simulator to create multistage hydraulic fractures that allowed integration into numerical reservoir-flow simulation models. Then, both convective and diffusive flow within a multicomponent compositional simulation modeling paradigm is used to examine the role of molecular diffusion in performance under cyclic CO2 injections in hydraulically-fractured well. The simulation results indicate that molecular diffusion yields an incremental oil recovery of 6% compared to models that do not. Our analysis reveals different thermophysical properties transition from near wellbore regions to outer regions into the rock matrix. Changes in total mole fractions of CO2, methane, and hydrocarbons with C7+ fraction, pressure and saturation variation, viscosity reduction and the surface tension over 14 injection-soaking-production cycles are tracked. The analyses of the evolution of these thermophysical properties provide us with means to evaluate the efficiency of the solvent injection process. The simulation results explain how, when, and where CO2 disperses into the reservoir.",0,0,0
Oil Recovery,Hydraulic Fracture,"Chen, Zan; Lin, Menglu; Wang, Shuhua; Chen, Shengnan; Cheng, Linsong",Impact of un-propped fracture conductivity on produced gas huff-n-puff performance in Montney liquid rich tight reservoirs,Un-propped fracture; Huff-n-puff; Liquid rich tight reservoir; Reservoir simulation,,"Studies have shown that the gas huff and puff injection potentially perform better than the continuous gas flooding in enhancing the hydrocarbon recovery in the liquid rich tight reservoirs. During the fracturing stimulation, only part of the induced hydraulic fractures is propped because proppants cannot be carried to the fracture tips. Moreover, some secondary and tertiary fractures may be too narrow to accommodate any proppants. The conductivity of the unpropped fractures is highly dependent on the variation of the in-situ pressure and may be open and close periodically during the huff-n-puff cycles. In this study, the stress-dependent fracture conductivity and its impact on the produced gas huff-n-puff performance are investigated in a liquid rich tight reservoir, considering the existence of the large amount of the unpropped fractures. The experimental data of stress-dependent fracture conductivity is employed first to simulate the dynamic conductivity during the depletion and the gas huff and puff cycles. A reservoir model is then constructed and history-matched based on the reservoir fluid samples and the field production data collected from the Montney liquid rich tight reservoir in Western Canada. Performance of the produced gas huff-n-puff is examined in the targeted reservoir and results show that contributions of the unpropped fractures cannot be ignored, which leads to 7.8% more condensate (i.e., oil) production and 2.8% higher in barrel of oil equivalent (BOE), compared to the case with propped fractures only. The effects of complex fracture geometry and the cluster completion are also investigated and results show that the unpropped fracture contributions towards the condensate production and BOE are even more pronounced in the complicated scenarios. The condensate oil and BOE are 42.0% and 22.9% higher in complex fracture geometry case and 12.4% and 5.6% higher in the fractures with multiple clusters than those scenarios with propped fractures only. This paper provides a better understanding on the potential performance of enhanced hydrocarbons recovery in liquid rich tight gas reservoirs via gas huff-n-puff operations.",3,3,0
Oil Recovery,Hydraulic Fracture,"Zhao, Jinsheng; Li, Tiantai; Shi, Yu; An, Chongqing; Liu, Yueliang",A new sinking agent used in water-control fracturing for low-permeability/bottom-water reservoirs: Experimental study and field application,Water-control fracturing; Low permeability; Bottom-water reservoirs; Barrier; Fracture height,MODEL,"Hydraulic fracturing is widely applied in tight reservoirs for hydrocarbon recovery. However, as for bottom water reservoirs, the created vertical hydraulic fractures can readily penetrate into the bottom-water layer, leading to a drastic increase of water cut when the pay-zones are too thin and the barrier lying between the pay-zone and bottom water are quite weak. In this work, a new sinking agent is used in hydraulic fracturing for water control in the low-permeability/bottom-water reservoirs. The settlement velocity and the plugging ability of this new sinking agent as well as the flow conductivity of the sinking-agent barrier is measured and compared with that of the other six commonly used sinking agents. We finally investigate the placement rule of the new sinking agent by varying the concentration of the carrying fluid and sand ratio in the modeling fracture. Filtration test show that this new sinking agent can form a barrier, which can strongly plug fracturing fluid. When the closure pressure range is in the range of 6.9 MPa-69.0 MPa, conductivity of the barrier formed by this new sinking agent is at a low level of 2.9 mu m(2)cm to 1.5 mu m(2)cm. With a given sand ratio and carrying-fluid concentration, the barrier formed in the fracture by the new sinking agent is more uniform than the other sinking agents. Based on the field application in a low-permeability/bottom-water reservoir, the usage of this new sinking agent increases oil recovery but decreases the water cut compared to other sinking agents.",3,3,2
Oil Recovery,Hydraulic Fracture,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Oil Recovery,Mathematical Model,"Radovanovic, Anna M.; Pires, Adolfo P.; Peres, Alvaro M. M.",Semi-analytical transient pressure solution for power-law polymer injection in a vertical well,non-Newtonian flow; Enhanced oil recovery; Power-law fluids,FLOW; FLUIDS,"Enhanced Oil Recovery (EOR) is a process that extends reservoir life through field operations that aim to increase reservoir displacement efficiency. Injection of polymeric solutions, which is a chemical EOR process, improves sweep efficiency by decreasing the mobility of the injected fluids. One challenge in polymer flooding is to model the non-Newtonian rheological behavior of the injected solutions due to the complex interdependence between fluid flow velocity, fluid viscosity and shear rate. Proper reservoir management requires a thorough understanding of non-Newtonian fluid flow behavior through porous media, thus the need for new and improved mathematical models that describe the transient pressure behavior in wells. In this work we consider the flow of non-Newtonian pseudoplastic fluids in homogeneous isotropic porous media. To describe the rheological polymer behavior, we used the well-known power-law model, which leads to a nonlinear problem. In this paper, a novel semi-analytical solution is obtained by combining spatial domain discretization with pseudotime, so the flow problem is rewritten as a system of linear equations in Laplace domain. We also presented a variation of the proposed solution by assuming a pseudostationary behavior of the non-Newtonian velocity. Both approaches are compared to previously published approximated analytical solutions. One interesting aspect of our work is that it can be extended to more realistic polymer rheological models.",0,1,0
Oil Recovery,Mathematical Model,Wang Tianyuan; Yu Li; Xiu Jianlong; Huang Lixin; Cui Qingfeng; Ma Yuandong,A mathematical model for microbial enhanced oil recovery considering the double-bacterial competition mechanism,Microbial enhanced oil recovery; Mathematical model; Double-bacterial; Competition,,"Considering the influence of reservoir on microbial growth and the competition of microbial community on nutrition, a mathematical model for microbial enhanced oil recovery considering the double-bacterial competition mechanism is established. The components of this mathematical model consist of oil, water, microbe 1, microbe 2, nutrients, metabolite) and metabolite2. The equations of this numerical model take into account the decay and growth of microorganisms, nutrient consumption, metabolism production, chemotaxis, convection-dispersion, water viscosity increment, oil viscosity reduction, interfacial tension reduction, adsorption, and desorption. In this study, three numerical examples were performed to analyze the double-bacterial competition mechanism and the effects of product interaction on improving oil recovery through a simulator developed according to our mathematical model. We found that (1) Under different double-bacterial growth models (symbiotic effect, repressive effect and no effect), there is a big difference in product concentration and oil displacement efficiency; (2) Double-bacterial growth model can better simulate actual reservoir application of microbial flooding technology than single microbial model; (3) Double-bacterial growth model with different products can increase oil recovery by up to 12.3% compared with water flooding.",1,3,2
Oil Recovery,Mathematical Model,"Ni, Hong-mei; Liu, Yong-jian; Fan, Ying-cai",Optimization of injection scheme to maximizing cumulative oil steam ratio based on improved artificial bee colony algorithm,Artificial bee colony algorithm; Steam flooding; Chaos optimization operator; Adaptive recombination; Random perturbation,PERFORMANCE; SYSTEM,"To address the optimization of injection scheme of steam flooding, an injection optimization method of steam flooding based on improved artificial bee colony (IABC) algorithm is proposed. Firstly, a mathematical model of steam flooding scheme optimization is established, and then the IABC algorithm is used to solve the model and optimize the injection scheme of steam flooding. In the IABC algorithm, we introduce a chaos optimization operator to generate initial solutions and apply an adaptive recombination operator to ensure the diversity of the population. In addition, we use a random perturbation operator based on the evolutionary stagnation step to improve the search ability of artificial bee colony algorithm. The experimental results show that the established model is accurate and the optimization algorithm is effective. It can be seen that the injection scheme of steam flooding optimized by the IABC algorithm can increase more cumulative oil steam ratio and cumulative oil production than that optimized by similar algorithms. The proposed method can obtain maximum recovery, and can significantly improve economic efficiency.",3,3,1
Oil Recovery,Mathematical Model,"Liu, Changwei; Li, Kewen; Tian, Xiaoming; Zhao, Guoxiang; Chen, Youguang; Mahlalela, B. M.",Experimental studies on production performance of oil reservoirs with bottom water,Bottom-water reservoir; Horizontal well; Physical model; Optimal production pressure,LEG,"Water coning is a major problem in oil reservoirs with bottom water. It reduces the oil production and overall oil recovery. Excessive water production causes corrosion problems in production facilities and increases the cost of water disposal. This may cause the early shutdown of oil wells. In this study, an experimental apparatus has been designed and developed to physically model an oil reservoir with bottom water. The reservoir model was transparent and the change in water coning could be visualized. Many water-flooding tests were conducted at different pressures and oil viscosities ranging from 22 to 260 mPa s. The effects of production pressures and oil viscosity on oil production were investigated. The results indicated that for a medium oil viscosity of 74 mPa s, the optimal production pressure was about 0.054 bar. For minimum and maximum oil viscosity (22 mPa s and 260 mPa s), the smaller the production pressure, the larger the water breakthrough time and oil recovery. Five types of flooding characteristic curves were used to characterize the water-cut variation, and their applicability were compared and analyzed. The water drive curves were fitted using the water-cut models and the oil ""reserves"" (originally placed in the reservoir model) were predicted using the mathematical models with the experimental data. The results indicated that the Maksimov model of water-drive characteristic curve is more suitable to match the water production performance. Most interestingly, when applying the most suitable model Maksimov water-drive characteristic curve to predict oil reserves, the cases with optimal production pressures have a greater accuracy.",5,5,0
Oil Recovery,Separation,"Nekoeian, Sahand; Aghajani, Masoud; Alavi, Seyed Mehdi",Experimental study of the surfactants effects on gas phase mass transfer coefficients in gas condensate reservoirs,Gas condensate reservoirs; Local equilibrium assumption; Gas phase mass transfer coefficients; Surfactants; Specific interfacial area; Spreading coefficients,ORGANIC-CHEMICALS; POROUS-MEDIA; WETTABILITY ALTERATION; LIQUID VOLATILIZATION; THERMAL-DIFFUSIVITY; DISSOLUTION; RECOVERY; OIL; CONDUCTIVITY; TRANSPORT,"Surfactant flooding in gas-condensate reservoirs, shown to be an effective treatment method to remediate condensate blockage in near well bore regions, have been the focus of several studies in the recent decades. However, the effect of these chemicals on the gas phase mass transfer coefficients has not been yet addressed though they have to be incorporated in non-equilibrium compositional simulators to imitate the reservoir behavior reliably. Besides, any knowledge of the overall effect of the surfactants on these coefficients can shed light on the side effects of the surfactant flooding on mass transfer phenomenon and evaluate its suitability as a treatment strategy. In this study, separate empirical correlations were developed for methane and isobutane representing light and intermediate components respectively in the absence and the presence of surfactants at the temperature of 40 degrees C. In all the developed correlations for both components in the presence of surfactants, while spreading coefficient has a positive exponent, equilibrium adsorption constant possesses a negative exponent. This implies that surfactants with a larger former parameter and a smaller latter parameter like SDS have more opportunity to enhance the volumetric mass transfer coefficient. The results also confirm the positive effect of pore gas velocity on gas phase mass transfer coefficients even in low gas flow rates. Similarly, this effect has already been reported in NAPL (Non Aqueous Phase Liquid) volatilization related studies. Effective diffusion coefficient, condensate saturation, mean grain size, component type, surfactant type and residual water saturation were also shown to affect these mass transfer coefficients. In addition, it has been shown that surfactants which are conventionally believed to reduce volumetric mass transfer coefficients in gas-liquid systems like bubble columns, improve gas phase mass transfer coefficients in gas condensate reservoirs. This improvement is considered a drawback for the cited technique.",0,0,1
Oil Recovery,Separation,"Skjefstad, Havard S.; Stanko, Milan",Experimental performance evaluation and design optimization of a horizontal multi-pipe separator for subsea oil-water bulk separation,Compact separation; Pipe separation; Oil-water separation; Subsea separation; Modular design; Energy efficient production,,"Subsea separation of produced water increases the recovery rates for brown field installations. Removing produced water on the seabed increases production rates, removes topside produced water bottlenecks and enables better utilization of existing topside facilities. Existing subsea bulk water separator technologies are limited to gravity and compact gravity vessel types, as seen on Troll and Tordis, and the pipe separator installed at Marlim, which are large, heavy and costly installations. In order to make the business case for subsea produced water separation more attractive, there is a need to reduce the weight and areal footprint of separator designs. It is also important to develop separator solutions that can be qualified for a wide range of field operating conditions. This paper presents the experimental testing of a novel produced water separator design, the Multiple Parallel Pipe Separator (MPPS). The design uses multiple horizontal pipe segments in parallel for liquid-liquid separation, with inclined outlet pipe segments for increased water holdup and eased water extraction. Experiments are performed on a two-pipe prototype. A limited test matrix was run to investigate the best location for water extraction. Three tapping locations were tested. Experiments displayed oil re-entrainment along the inclined extraction pipe, and the best extraction point was found to be close to the horizontal to inclined transition. Using the identified tapping location, a detailed performance mapping was performed at total flow rates from 300 to 700 L/min and water cuts ranging from 30 to 90%. The performance mapping was performed with three different inlet configurations, a normal inlet, a tangential inlet, and a tangential inlet accompanied with novel phase re-arranging internals. Best separator performance was achieved for the tangential inlet with internals configuration, displaying efficiencies in the range 78.8-100%. A dispersion layer was observed in the separator pipes for total flow rates above 350 L/min. At low water extraction rates, this forming dispersion layer was observed to migrate completely into one of the two separator branches at random. The uneven splitting of the dispersion layer was observed to strengthen when changing from a normal to a tangential inlet configuration. The installation of phase-rearranging internals eliminated the uneven splitting of the dispersion layer, resulting in an even phase distribution between the two separator branches.",2,2,3
Oil Recovery,Separation,"Patil, Abhay; Sundar, Shyam; Delgado, Adolfo; Gamboa, Jose",CFD based evaluation of conventional electrical submersible pump for highspeed application,CFD; High speed pumps; Losses; Dimensional analysis; Viscous flow; Axial thrust,FLOW,"Fluctuations in oil prices have negatively affected the petroleum industry, prompting to look for innovative ways to optimize oil recovery. One of the current approaches to optimize oil production is to employ high-speed ESPs with Permanent Magnet Motors (PMM) that allow reducing the pump size while increasing the operating envelop. Standard affinity laws are a useful tool to provide a preliminary estimate of common pump performance. However, there is a need to understand the detailed variation in the flow variables and losses incurring due to fluid-geometry interactions at high rotational speeds. To evaluate the hydraulic performance of a mixed flow pump, Computational Fluid Dynamics (CFD) simulations were performed at rotational speeds ranging from 3600 rpm to 20000 rpm using fluids with different viscosities. Fluid behavior is studied by observing the change in flow parameters with rotational speed. Similitude analysis is utilized to characterize the pump performance. The numerical results yielded improved pump hydraulic performance with an increase in rotational speeds which is attributed to reduced separation losses mainly in the diffuser section. Research is concluded with further evaluation of the complete stage including secondary leakage flow path on flow variables and axial thrust forces.",4,4,0
Oil Recovery,Separation,"Morte, Matthew; Hascakir, Berna",Characterization of complex permittivity for consolidated core samples by utilization of mixing rules,Microwave; Complex permittivity; Mixing rule; Electromagnetic heating,DIELECTRIC-PROPERTIES; OIL-RECOVERY; ELECTRICAL-PROPERTIES; CONSTANT; MHZ,"Candidacy of any reservoir as a microwave absorber is predicated on the complex permittivity of the sample. Modeling both the penetration and absorption dynamics of the electromagnetic wave in the reservoir is dependent on realistic estimation of this parameter. Therefore, it becomes necessary to understand the inherent intricacies of complex permittivity in the reservoir. Reservoirs are comprised of both a void space represented by the porosity parameter as well as the rock matrix and can be treated as a binary mixture of the two. Mixing rules can then be introduced and have been shown to be a viable means of estimating the dielectric response. The behavior of the bulk material is considered to be an extension of the isolated contribution of the separate parts. Therefore, by characterizing the response of the individual components of the mixture, the overall response can be estimated. Utilization of mixing rules enables efficient estimation of the dielectric properties anywhere in the reservoir as a function of the rock matrix, fluid saturation, and porosity. The absorptive capacity of the reservoir can then be described which is used to screen the efficacy of the material for microwave introduction. Both the real and imaginary components of complex permittivity are measured on nine consolidated core samples of varying lithology and fluid saturation over the frequency range of 400 MHz to 6 GHz. Experimental data is compared to various mixing rules commonly implemented to determine validity and viability of the estimation of complex permittivity for consolidated samples.",4,4,2
Oil Recovery,Foam,"Fathollahi, Alireza; Rostami, Behzad; Khosravi, Maryam",Fluid displacement mechanisms by foam injection within a microfluidic matrix-fracture system,Enhanced oil recovery (EOR); Foam injection; Matrix-fracture micromodel; Viscous cross-flow; Effect of gravity force,OIL DISPLACEMENT; FLOW; TRANSPORT; TEMPERATURE; GENERATION; STABILITY; DRAINAGE; MODEL; GLASS,"In this study, the researchers visually investigated changes in the saturation of fluids and the oil recovery factor (RF) during foam injection in a two-dimensional matrix-fracture micromodel system. The effects of the 1) presence of oleic phase (comparison of the results of foam injection tests with and without oil), 2) viscous force (comparison of the results of foam and gas injection tests), and 3) gravity force (comparison of the results of gas/foam injection tests in vertical and horizontal states) were mechanistically studied. The results showed that the presence of oleic phase has the potential to cause foam to degrade at the beginning of the test. However, as the experiment advanced and oil saturation was reduced, foam injection resulted in the recovery of the fluid in the matrix. Pressure decline in the fracture due to the high viscosity of the foam acted as a driving force perpendicular to the fracture in the matrix and caused a viscous cross-flow leading to a dramatic increase in oil recovery. Although the gravity force reduced the foam stability due to the foam film drainage process and the gravity segregation of gas and surfactant solution, a comparison of the performances of gas and foam in the vertical state revealed the superiorly of foam injection.",4,4,2
Oil Recovery,Foam,"AlQuaimi, B., I; Rossen, W. R.",Characterizing foam flow in fractures for enhanced oil recovery,,,"Gas is used in displacing oil for enhanced oil recovery because of its high microscopic-displacement efficiency. However, the process at the reservoir scale suffers from poor sweep efficiency due to density and viscosity differences compared to in-situ fluids. Foam substantially increases the viscosity of injected gas and hence improves the sweep. Foam rheology in 3D geological porous media has been characterized both theoretically and experimentally. In contrast, the knowledge of foam flow in fractured porous media is far less complete. A companion paper (AlQuaimi and Rossen, 2017c), We focused on foam generation and propagation in a fully characterized model fracture. Here we focus on foam rheology in the same model fracture. This investigation is conducted by varying superficial velocities of gas and surfactant solution. We find in this model fracture the same two foam-flow regimes central to the understanding of foam in 3D porous media: a low-quality regime where pressure gradient is independent of liquid velocity and a high-quality regime where pressure gradient is independent of gas velocity. The transition between regimes is less abrupt than in 3D porous media. Our study directly relates flow regime to foam texture through observation of bubble size, bubble trapping and mobilization, and foam stability as functions of superficial velocities which allows comparison with our understanding of the mechanisms behind the two flow regimes in 3D porous media. Additionally, foam is shear-thinning in both regimes. However, the mechanisms thought to be behind the two flow regimes in 3D porous media do not appear in our model fracture. Foam is not at the limit of stability in the high-quality regime. Mobility in the high-quality regime, instead, reflects reduced and fluctuating foam generation at high foam quality. Moreover, bubble size is not fixed at approximately pore size, the mechanism thought to control the low-quality regime in 3D porous media. Instead, bubbles are much smaller than pores. Finally, for this model fracture, the investigation of vertical flow reaches the same findings as for horizontal flow, with somewhat lower pressure gradient.",5,6,1
Oil Recovery,Foam,"Sinha, Vineet; Ahmeda, Ramadan; Akhtar, Tarek; Shah, Subhash; Amani, Mahmood",Rheology and hydraulics of polymer-based foams at elevated temperatures,Foam; Polymer; Stimulation; Rheology; Hydraulics; Drilling,CONSTITUTIVE EQUATION; DRILLING FOAMS; FLOW BEHAVIOR; AQUEOUS FOAMS; FLUID-FLOWS; VISCOSITY; SUSPENSION,"Foam has been successfully used for different operations like well stimulation, drilling, enhanced oil recovery (EOR), cleanout, and acidizing operations in the oil and gas industry. Additionally, the low liquid content of foam provides a distinct advantage in terms of lesser material requirements. However, accurate prediction of rheology is necessary for the success of field operations, which requires a rheological model that incorporates the effect of temperature on foam properties as it circulates downhole. In the present investigation, polyanionic cellulose (PAC) based foam was generated using nitrogen as the gas phase and its rheology was determined using a recirculating flow loop that has three pipe viscometers (3.05, 6.22, and 12.7 mm ID) and a fully-eccentric annular section (9.53 mm OD x 12.57 mm ID). Experiments were conducted within the temperature range of 24 to 149 degrees C and at various foam qualities (gas phase volume fraction). The foam was circulated at different flow rates and the differential pressure across each pipe section was recorded. All tests were conducted at 6.89 MPa. The foams displayed power-law fluid behavior in the shear rate range tested (100-5000 s(-1)), which is often experienced in the wellbore. Like its base liquid, polymer foam exhibited thermal thinning and a significant rheology change with temperature. Only high-quality foam (75%) at ambient temperature (24 degrees C) showed yielding behavior, which was measured in a pipe viscometer under static condition. The disappearance of yield stress at elevated temperature could be attributed to thermal thinning of the liquid phase that weakens the strength of bubble structure. Experimental data is used to develop new correlations to predict power-law fluid parameters as a function of temperature, base fluid properties, and foam quality. Moreover, the measurements are compared with the predictions of existing models, and discrepancies are observed, which could be attributed to the variation in foam generation technique, the nature and concentration of polymer, and the concentration of surfactant used in the experiments in which data was obtained to develop the models. Furthermore, annular pressure loss measurements obtained at low temperatures (24 and 79 degrees C) show predominantly good agreement with predictions of a hydraulic model that uses the new correlations. Discrepancies increased with temperature as the foam becomes unstable due to thermal thinning of the liquid film and subsequent weakening of bubble structure.",5,5,1
Oil Recovery,Natural Fractures,"Canbolat, Serhat; Parlaktuna, Mahmut",Analytical and visual assessment of fluid flow in fractured medium,Fluid flow; Natural fracture; Equivalent fracture aperture (EFA); Improved cubic law (ICL),LOCAL CUBIC LAW; ROCK; CONDUCTIVITY; EQUATION,"Most reservoirs consist of natural and artificial fractures, including isolated microscopic fissures. These fractures form complicated paths for reservoir characterization and fluid movement that ultimately impacts production performance and ultimate recovery. That's why recovery estimations of fractured reservoirs are considered to be extremely challenging due to complexity and heterogeneity of the geological patterns. Oil production from fractured reservoirs results in varying saturation values throughout the reservoir. This is due to the microscopic fissures and heterogeneity of the fracture environment, which could not be swept thoroughly. Higher production/injection ratios also enhance the fingering effect by passing oil through the reservoir. In this study, naturally and artificially fractured cores were used. Analytical and experimental calculations were performed in order to understand the physical structure of the cores. Moreover, in the literature the analytical solutions of the fractures were defined by cubic law (CL), local cubic law (LCL) and modified cubic law (MCL). However, due to the lack of consideration of fracture properties with limited experimental work, there needs still work on this field. Equivalent fracture aperture (EFA) measurements were done by microscope and compared with the analytical calculations. Laboratory results were defined by the equation developed for predicting equivalent fracture apertures as Improved Cubic Law (ICL). Shrinkage in equivalent fracture aperture was also defined by ICL observed by microscope. Using ICL, analytical calculations were done in different environments. Equivalent fracture apertures were calculated for all the experimental flow rates under laminar flow. ICL has worked with the fractured cores flow definition whereas not for homogeneous cores. That's why due to higher calculated values and the 15% error on EFA, a correction coefficient (C) included to the CL equation for the tortuosity or the roughness effect This result was in th error range of previous results and gave more realistic estimation with respect to the previous studies carried out Finally, C coefficient was calculated in a range of 0.53-0.65.",3,3,0
Oil Recovery,Natural Fractures,"Aghabarari, Amirhossein; Ghaedi, Mojtaba",A new simulation approach to investigate reinfiltration phenomenon in fractured porous media,Naturally fractured reservoirs; Reinfiltration; Grey relational analysis; Simulation; Block to block interaction,RECOVERY,"The reinfiltration is a common phenomenon in fractured reservoirs and severely influence production rate. Despite the efforts made to study the reinfiltration process experimentally or theoretically, still there is not a comprehensive study that investigates all the affecting parameters. In this paper, a new approach to specify the reinfiltrated oil into the matrix block and drained oil from the matrix block in a commercial simulator has been introduced. Moreover, a new dimensionless parameter showing the degree of reinfiltration has been defined. Then, by using the proposed simulation method, the impact of different reservoir parameters has been examined. The investigated parameters are: porosity, permeability, matrix block dimensions, matrix and fracture compressibility, rock type and different type of reservoir's fluids. Finally, the grey relational analysis (GRA) was used to determine factors that have a significant influence on reinfiltration process. Results show that matrix block permeability-porosity factor has the highest impact on reinfiltration process.",4,5,0
Oil Recovery,Natural Fractures,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Oil Recovery,Spontaneous Imbibition,"Rao, Xiang; Cheng, Linsong; Cao, Renyi; Li, Ning; Jiang, Jun; Wang, Lizhun",A novel 3D green element method to simulate counter-current spontaneous imbibition considering the effect of gravity,Green element method; Counter-current spontaneous imbibition; Gravity effect; 3D core,OIL-RECOVERY; WATER-WET; WETTABILITY; FORMULATION; ABSORPTION; MATRIX,"This paper firstly proposes a novel three-dimensional (3D) Green element method (GEM). We have proven it by theoretical error analysis that, the novel GEM with the third-order accuracy, has good convergence and stability, which are the advantages that previous GEMs do not have. This novel method is used to numerically simulate 3D core's counter-current imbibition process with gravity effect, and 1D, 2D and 3D models are implemented to depict good convergence and accuracy of proposed method. Compared with finite difference method (FDM) used by many previous studies, the novel method has the same advantage as previous GEMs, that it requires less elements to achieve a good agreement between simulation results and experiment data. Moreover, specific gravity effect is analyzed, and three typical stages of gravity effect are divided. In summary, the novel 3D GEM and corresponding 3D simulator are effective to simulate counter-current imbibition of the real 3D core considering the effect of gravity.",0,0,0
Oil Recovery,Spontaneous Imbibition,"Amadu, Mumuni; Pegg, Michael J.",Analytical solution to spontaneous imbibition under vertical temperature gradient based on the theory of spontaneous imbibition dynamics,Spontaneous imbibition; Capillary pressure; Dimensionless time; Dimensionless distance; Equilibrium; Temperature gradient,CAPILLARY RISE; OIL RECOVERY; GRAVITY,"In this work, we have theoretically studied the imbibition process related to a block in a fractured carbonate reservoir under an assumed constant, vertical temperature gradient, G(T). An analytical solution to an ordinary differential equation we developed has been obtained using a computer program, and the original Washburn law normally valid for isothermal conditions of spontaneous imbibition has been found to hold true for G(T) equal to zero. The theoretical results of our study show that the space and time evolution of the imbibition front is strongly dependent on surface tension and dynamic viscosity of the imbibing fluid under a given temperature gradient. We have also validated our model against experimental data from a literature source based on spontaneous imbibition into a Hele Shaw Cell under longitudinal temperature gradient. The general conclusion of our study is that spontaneous imbibition in fractured carbonate reservoirs will be accelerated the higher the temperature of the injected water. This corresponds to a negative temperature gradient where the temperature of the injected water exceeds the ambient temperature of the reservoir.",5,4,3
Porous Media,Relative Permeability,"Wang, Shuoliang; Yu, Chunlei; Sang, Guoqiang; Zhao, Qianhui",A new numerical simulator considering the effect of enhanced liquid on relative permeability,Enhanced liquid; Flow velocity; Relative permeability; Numerical simulation,STATE 2-PHASE FLOW; POROUS-MEDIA; OIL-RECOVERY; FLUID; PLANAR; MODEL,"Enhanced liquid treatment magnifies the difference of fluid flow velocity between borehole and inter-well zones. The flow velocity will influence the relative permeability and change the percolation law in the oil-water two phase flow. In this study, we conduct three group experiments with different permeability using 15 artificial cores. The unsteady-states measurement method is used to test the relative permeability curve at different velocities. We found that relative permeability would be affected by the testing velocity based on the experimental results. A new relative permeability equation considering flow velocity is established, which indicates that higher oil recovery can be obtained by an early enhanced liquid treatment. There is also a critical velocity with different permeability. If the flow rate (v(w)) of the enhanced liquid treatment is larger than the critical velocity, the treatment will improve the oil recovery. On the contrary, if the v(w) of the enhanced liquid treatment is larger than the critical velocity, the treatment will reduce the oil recovery. We summarize the new relative permeability equation and implement it to the numerical simulation model. The new simulator is validated with the three-parallel sand-pack experiment and the actual China offshore oilfield model. The new simulator could predict oil production accurately after enhanced liquid treatment.",1,1,0
Porous Media,Relative Permeability,"Du, Dongxing; Zhang, Dan; Li, Yingge; Dong, Xu; Sun, Zhifeng; Chao, Kun",Numerical investigations on the inlet and outlet behavior of foam flow process in porous media using stochastic bubble population balance model,Inlet behavior; Outlet behavior; Foam flow; Porous media; Stochastic bubble population balance model; Foam relative permeability reduction factor,CO2 STORAGE; OIL; SIMULATION; CO2-EOR; MOTION; TRANSIENT; VISCOSITY,"Numerical investigations were carried out with special attentions on the inlet and outlet behaviors of foam flow process in a homogeneous porous media with confined entrance and exit boundaries. The Stochastic Bubble Population (SBP) balance model, which usually involves two parameters of the bubble generation rate K-g and the maximum bubble density n(infinity) for bubble number prediction, was employed to study the dynamic foam generation and development process in porous media. With introduction the K-fp parameter to take into account the foam phase relative permeability reduction effect, the control equations of the two-phase flow process in a two-dimensional computational domain were solved with the IMPES algorithm and the inlet and outlet behavior of the foam displacement process were scrutinized based on detailed analysis of the bubble density, water phase pressure and water phase saturation distributions in porous medium. Numerical results showed a clear entrance effect of higher water saturation, lower pressure gradient and developing bubble density in the inlet region of the porous media in the transient foam displacement process, whereas the confined exit results in elevating water saturation and decreasing pressure gradient towards the outlet of the core. Parametric studies on K-g, n(infinity), K-fp and inlet & outlet sizes D indicate higher bubble generation rate could remarkably suppress the entrance region in the foam seepage process, while the higher maximum bubble number did not lead to obvious change of the foam flow behavior in the inlet and outlet region, although it could produce higher absolute values of bubble density and pressure drop along the core. With lower K-fp values, the strong foam flooding behavior could be properly predicted with much higher pressure drop and lower water saturation. Two dimensional numerical results at various inlet and outlet sizes clearly show the confined geometry effect on foam flow characteristics with smaller sizes corresponding to longer inlet and outlet regions. Computational domain and numerical results were validated through comparisons with corresponding experimental setup and CT measurement results. It is observed that, the numerical simulation could reproduce not only qualitatively but also quantitatively the experimentally obtained water saturation distribution and pressure drop result. It is concluded that the mechanistic stochastic bubble population model could be reasonably employed on prediction of the inlet and outlet behavior in the transient foam flow process in the homogeneous porous media.",1,1,2
Porous Media,Relative Permeability,"Wang, Lei; Liu, Changwei; Jiang, Ping; Zhang, Hui; Tian, Xiaoming; Zhao, Nan; Mahlalela, B. M.",Characterization of two-phase flow in porous media using global mobility,Global mobility; Production performance; Water/polymer flooding; Two phase flow,SPONTANEOUS WATER IMBIBITION,"Proper characterization of multi-phase flow in porous media is of significant importance in selecting and optimizing the performance of a given oil reservoir. The main factors influencing the characterization of multi-phase flow in porous media include: microscopic pore structure, movable fluid saturation, nonlinear seepage characteristics and clay minerals composition, and etc. However, it is very difficult to quantitatively study the multiphase flow process in porous media, because there is no clear relationship between the oil production rate and the physical parameters of oil reservoir, particularly in low permeability reservoirs. Furthermore, on-going research activities has led to the discovery that it has been a challenge to tell why two oil reservoirs with the same degree of permeability (i.e. low permeability) have far different production performances. In an attempt to comprehend this challenge, a concept of global mobility by Li and Horne (2005, 2006) derived from the Li-Horne model was proved to be a new approach for evaluating the seepage capacity in imbibition system, because it can unify oil and water phase mobility into one model and take many static and dynamic physical parameters into accounts. In this paper, the global mobility concept is applied and verified to characterize the mobility of a multiphase flow and evaluate the production performance from core to field scale. Comparisons between the global mobility concept and other characterization methods were conducted based on various flooding experiments and field data tests from rock/oil/water systems and rock/oil/polymer systems with different porosities and permeabilities. The results showed that there is a linear relationship between the global mobility and the production performance which is better than the other methods, and the application range of the global mobility was extended. In addition, a convenient and empirical approach was proposed to obtain the global mobility with relative permeability data. Its feasibility has been preliminarily proved through five case studies, and the demonstration is that the global mobility could be an effective parameter to characterize a two-phase flow in porous media and evaluate the production performance for field application.",1,3,4
Porous Media,Relative Permeability,"Merey, Sukru",Prediction of transport properties for the Eastern Mediterranean Sea shallow sediments by pore network modelling,Two-phase flow; Porous media; Pore network; Methane; Methane hydrates; Mediterranean sea,HYDRATE-BEARING SEDIMENTS; STRATIGRAPHIC TEST WELL; WATER-RETENTION CURVE; GAS-PRODUCTION; RELATIVE PERMEABILITY; POROUS-MEDIA; METHANE HYDRATE; DEPRESSURIZATION; SIMULATIONS; SATURATION,"The Eastern Mediterranean Sea has gas hydrate potential as well as its conventional natural gas potential. Numerical simulations are crucial to predict gas and water production from gas hydrate reservoirs because they are needful to determine gas production strategies. However, the transport properties of the Eastern Mediterranean Sea shallow sediments are missing in literature. In this study, the transport properties (porosity, absolute permeability, relative permeability, and capillary pressure) of the Eastern Mediterranean Sea shallow sands were estimated by pore network simulations with OpenPNM. In order to generate pore networks in the conditions of the Eastern Mediterranean Sea, the core data of Ocean Drilling Program Leg 160 was evaluated in this study. In pore network simulations, it was observed that porosity and absolute permeability increase as pore diameter and throat diameter increase. On the other hand, capillary pressure decreases. The fitting parameters to OpenPNM modelling data for the relative permeability equation of Stone were calculated as: 0.02-0.14 for S-rw, 1.8-3.57 for n(g) and 1.9-6.0 for n(w) . The fitting parameters to OpenPNM modelling data for the capillary pressure equation of Van Genuchten were calculated as: 0.866-0.945 for m and 1.375 x 10(4) -5.90 x 10(5) Pa for P-0. These parameters were suggested for numerical gas hydrate production simulations in the Eastern Mediterranean Sea. Numerical simulations at different cases were held by HydrateResSim for gas hydrates to investigate the effect of transport properties on gas and water production in the conditions of the Eastern Mediterranean Sea. It was observed that gas production, water production and production time were significantly affected by transport properties.",4,4,1
Porous Media,Relative Permeability,"Hong, Eunji; Jeong, Moon Sik; Lee, Kun Sang",Optimization of nonisothermal selective plugging with a thermally active biopolymer,Microbial enhanced oil recovery (MEOR); High-temperature reservoir; Selective plugging; Nonisothermal biokinetics; Leuconostoc mesenteroides,ENHANCED OIL-RECOVERY; LEUCONOSTOC-MESENTEROIDES; BIOSURFACTANT PRODUCTION; KINETICS; TEMPERATURE; MODEL; DEXTRANSUCRASE; RESERVOIRS; METABOLISM; TRANSPORT,"A novel concept of microbial enhanced oil recovery (MEOR) under nonisothermal conditions was developed based on temperature-dependent biokinetics. The model specified the use of temperature-triggered Dextran (a biopolymer) produced by Leuconostoc mesenteroides (a microbe). The effects of environmental temperature on microbial growth and biopolymer production were validated and calibrated using the cardinal temperature model and experimental results. Various biokinetic parameters and a permeability reduction factor were also obtained to within approximately 2% error of those previously reported sandpack experiment. Based on the developed nonisothermal biokinetic model and the permeability reduction factor, thermally active MEOR was analyzed for a high-temperature reservoir. The results suggested the influences of injection parameters, such as injected nutrient concentration, rate, and temperature, on oil recovery factor. Higher nutrient concentrations resulted in increased Dextran production, thereby increasing oil recovery by selective plugging. On the other hand, injection rate and temperature were related to Dextran distributions. Higher injection rates led to lower Dextran concentrations with wider distributions. The injection temperature controlled the location of trapped Dextran in porous media, thereby influencing oil recovery. Through the optimization process, the injection design was determined with a rate of 30 m(3).day(-1), temperature of 5 degrees C, and nutrient mole fraction of 0.009. The suggested optimal injection design resulted in the largest oil recovery (39%) for a highly heterogeneous layered reservoir.",4,4,1
Porous Media,Relative Permeability,"Modaresghazani, J.; Moore, R. G.; Mehta, S. A.; van Fraassen, K. C.",Investigation of the relative permeabilities in two-phase flow of heavy oil/water and three-phase flow of heavy oil/water/gas systems,Relative permeability; Heavy oil; Two-phase and three-phase flow; Water flood; Drainage and imbibition,POROUS-MEDIA; OIL,"An experimental study was conducted to investigate two-phase and three-phase relative permeability behavior in a multi-phase flow, which involved a typical Canadian bitumen. A series of isothermal core flood experiments were conducted on an unconsolidated core composed of cleaned Athabasca sand matrix and relative permeabilities of the involved phases were determined. Drainage and imbibition processes for two-phase water/oil flow and oil saturation reversal in a three-phase oil/water/gas flow, which is encountered in a typical air injection process were examined. A history matching technique was used to determine relative permeabilities for two-phase water/oil and gas/liquid systems. A strong hysteresis was observed in both wetting phase and non-wetting phase relative permeabilities. The endpoint relative permeability of oil was higher than the end-point relative permeability of water by two orders of magnitude in two-phase water/oil experiments. Similar end-point relative permeability ratio was observed in two-phase liquid/gas experiments. Using the determined relative permeabilities for two-phase flows, Stone's first and second model and Baker's interpolation model were used to predict the fluid production in the three-phase flow. Despite showing a satisfactory prediction for liquid production, all models showed a significant deviation for produced gas at the early stages of the three-phase flow experiment.",5,6,0
Porous Media,Relative Permeability,"Yang, Xu; Guo, Boyun",Productivity analysis of multi-fractured shale oil wells accounting for the low-velocity non-Darcy effect,Low-velocity non-Darcy; TMS; Shale oil; Productivity; Cluster spacing,THRESHOLD PRESSURE-GRADIENT; LOW-PERMEABILITY RESERVOIR; PRODUCTION PERFORMANCE; MATHEMATICAL-MODEL; POROUS-MEDIA; FLUID-FLOW; BEHAVIOR,"Well productivity of the Tuscaloosa Marine Shale (TMS) trend located in Louisiana and Mississippi presents a significant challenge. Well productivity declines rapidly for some reasons not known to the operators. By taking advantage of the concept of apparent matrix permeability, a semi-analytical model was developed in this investigation considering the low-velocity non-Darcy effect. An iterative procedure is proposed to calculate the oil production rate of multi-fractured horizontal shale oil wells. Field case studies of the Eagle Ford Shale (EFS) and TMS wells indicated that the productivity model considering low-velocity non-Darcy is consistent with field data, with a relative error of less than 10%. The low-velocity non-Darcy phenomenon may harm the TMS oil production rate as high as 29.7%. Sensitivity analysis demonstrates that low permeability reservoirs are more likely to be affected by non-Darcy behavior. The apparent matrix permeability declines severer in low permeability than in high permeability reservoirs, thus reducing well productivity more significantly in the low-permeability TMS trend. The oil production rate of Darcy flow increases with increasing fracture conductivity. However, this benefit was hindered by non-Darcy effect. A larger fracture half-length favors oil production, although it reduces the non-Darcy effect slightly. Besides, reducing the cluster spacing can mitigate the adverse impact of low-velocity non-Darcy, thus enhancing the shale oil production rate. Therefore, there is a vast potential for enhancing oil productivity in the TMS trend by reducing perforation cluster spacing.",5,5,0
Porous Media,Relative Permeability,"Lei, Gang; Liao, Qinzhuo; Patil, Shirish; Zhao, Yang",Effect of clay content on permeability behavior of argillaceous porous media under stress dependence: A theoretical and experimental work,Argillaceous porous media; Permeability; Stress sensitivity; Theoretical model; Experimental tests,RELATIVE PERMEABILITY; FRACTAL MODEL; SANDSTONE; POROSITY,"Prediction of permeability behavior of argillaceous porous media (APM) is a major challenge for science and engineering, despite considerable advances in using both theoretical and experimental means over the last few decades. Specifically, the effect of clay content on stress sensitivity of APM is still an open question. In this paper, laboratory tests are conducted to investigate the effect of clay content on behavior of permeability for artificial argillaceous sandstone samples under stress dependence. Then a corresponding theoretical model for stress dependent permeability of APM based on fractal theory is derived to interpret the experimental results. The predicted results from the developed theoretical model are consistent with those determined by experimental tests, which verifies the developed model. The proposed model can be invoked to effectively study the coupled flow-deformation behavior in APM. The results show that the normalized permeability increases with increasing the power law index, increasing elastic modulus, increasing rock initial porosity, and decreasing clay content at a given effective stress. This work provides a comprehensive experimental and theoretical study on stress-dependent permeability in APM, which is beneficial to study the effect of clay content on permeability behavior of APM under stress dependence. In addition, with this proposed model, we can conduct the estimation of specific parameters (e.g., the structure of pore surface, the fractal dimension of pore, the maximum pore radius, the minimum pore radius, clay content, initial irreducible water saturation, and rock elastic modulus) using inverse modeling approaches.",5,5,1
Porous Media,Relative Permeability,"Li, Caoxiong; Lin, Mian; Ji, Lili; Jiang, Wenbin",Multiphase flow in tight sandstone: An improved application for 3D intermingled fractal model,Tight sandstone; Fractal; Mineral component; Multiphase displacement,DYNAMIC CONTACT-ANGLE; WATER RELATIVE PERMEABILITY; GAS-RESERVOIRS; POROUS-MEDIA; THERMAL-CONDUCTIVITY; LIQUID INFILTRATION; SIZE DISTRIBUTION; 2-PHASE FLOW; UNITS MODEL; PREDICTION,"Multiphase displacement in tight sandstone is fundamental and critical for tight oil production. Micropores dominate the pore space in tight sandstone. Microscopic mineral components in micropores substantially influence the multiphase displacement behavior. Pore size distribution exhibits a self-similar or fractal property, similar to inorganic mineral grains. Utilizing fractal theory eases the rebuilding of the flowing space and calculation of relative permeability. As an improvement of previous work, we successfully extended the 3D intermingled fractal model (3D IFM). The extended 3D IFM can evaluate multiphase flow behavior in tight sandstone, considering fractal characteristics of pore size distribution and mineral grain distribution. The fractal information of pores and mineral properties are obtained by scalable scanning electron microscopy (SEM) and energy dispersive spectroscopy(EDS) images, respectively. This method is useful and reliable for calculating relative permeability and residual saturation. The method is also successfully used to evaluate the influence of oil-water viscosity ratio, mineral components and formation depth on multiphase displacement behavior, proving its convenience and potential in rapidly evaluating multiphase displacement behavior in tight sandstone.",5,5,4
Porous Media,Rock,"Jiang, Shuaishuai; Chen, Xuehua; Qi, Yingkai; Jiang, Wei; Zhang, Jie; He, Zhenhua",Seismic numerical analysis for partially gas-saturated porous rocks by an extended local Rytov Fourier approximation based on the diffusion-viscous theory,Rytov approximation; Diffusive and viscous wave equation; Attenuation; Dispersion; Gas-saturated reservoir,ELASTIC-WAVES; MIGRATION; SIMULATION,"The frequency-dependent attenuation and velocity dispersion of seismic responses are closely related to hydrocarbon reservoirs. To further investigate the characteristics of seismic responses caused by pore fluid-bearing reservoirs, the role of gas saturation is analyzed in seismic responses of sand reservoirs characterized by the patchy saturation model. To this end, a novel wave extrapolation method is developed based on the diffusive-viscous wave equation (DVWE) as well as a scheme for an extended local Rytov Fourier (ELRF) approximation within the extrapolation depth interval. Our proposed method considers the presence of fluid mixtures in the porous media, resulting in seismic attenuation and dispersion by the mechanism generally known as wave-induced fluid flow (WIFF). This method enables an accommodation for the lateral variations in slowness, diffusion coefficient and viscosity. Subsequently, the extrapolation is adopted to model the synthetic seismic data of a distributary channel model. During this modeling, a gas-water saturated sand reservoir embedded into one of the channels was used to comparatively analyze the distinct features on its seismic synthetic data. We exhibited the numerical simulation results using the proposed wave extrapolation method here and the traditional acoustic wave equation (AWE) method. A comparison of the simulation results, demonstrates that our proposed numerical method can depict the seismic dispersion and frequency-dependent attenuation as well as the phase delay effects associated with gas-water-saturated sand reservoirs. Furthermore, we compare the seismic responses by changing the gas saturations of the sand reservoir. The gas saturation of the reservoir has significant effects on the seismic characteristics of the numerical modeling data. The numerical modeling method improves our understanding of the mechanisms of seismic frequency-dependent characteristics associated with gas saturations and potentially contributes to better insights into gas reservoir indicators derived from seismic field data.",1,1,5
Porous Media,Rock,"Sarris, Ernestos; Gravanis, Elias; Ioannou, Ioannis",A novel methodology for synthesizing the wetting capillary pressure curve of rocks through sorptivity data,Capillary pressure curve; Synthetic reconstruction of wetting curve; Van Genuchten model; Sorptivity test; Finite element analysis; Back analysis,MODEL; HYSTERESIS; EQUATION; DRAINAGE; BRICK,"Capillary pressure as a function of moisture content is an essential element in the modelling of multiphase flow in porous media, such as rocks. The constitutive relationship predicting the capillary pressure as a function of fluid saturation in these materials has been the focus of many studies in the literature, as the direct experimental determination of the former is usually time-consuming and not quite straightforward, owing to the topologically complicated pore structure of rocks. In this paper, we perform a systematic analysis of the interrelation between capillary pressure curves (CPC) and the corresponding imbibition curves to evaluate the parameters influencing the entire diffusive process. The aim is the reconstruction of the wetting CPC from sorptivity test data through back analysis, within the framework of the Van Genuchten model. We perform numerical simulations with finite elements, using as input synthetic models of CPC with one, two and three degrees of freedom, the latter being the widely accepted Van Genuchten model. The effectiveness and the limitations of the different models used and the sensitivity of the imbibition curves to each degree of freedom are investigated and critically evaluated. The whole investigation is assisted by theoretical estimations of the sorptivity coefficient, as a function of the model parameters and the measured quantities. The results of our analysis provide not only a clarification of the aforementioned interrelation, but also a relatively simple procedure for reconstructing synthetically the wetting CPC.",2,3,0
Porous Media,Rock,"Sergeev, Stanislav; Ryzhikov, Nikita; Mikhailov, Dmitry",Laboratory investigation of sound induced by gas flow in porous media,Acoustic emission; Gas flow; Porous medium; Laboratory study,,"This paper is devoted to studying the parameters of acoustic signals induced by fluid flow in porous media. The setup design and technique of acoustic measurements are described in detail. Sound induced by nitrogen flow in different types of carbonate rocks and sandstones is measured and analyzed. Limestone samples generate acoustic signals within a frequency range from 2 to 30 kHz. Sound in sandstone is significantly different from that in the limestone samples and occurs in a frequency range from 1 to 5 kHz. For limestone samples, sound generation is observed at lower flow rates than for sandstone due to earlier transition to a non-Darcy flow regime. From complementary analysis of hydrodynamic parameters of experiments, it is inferred that acoustic signals in rock samples appear only when the Forchheimer number exceeds values in the range 0.3-0.4. It is demonstrated that the recorded sound is mainly produced in the relatively thin near-surface zone of rock samples.",2,4,1
Porous Media,Rock,"Kanimozhi, B.; Thamizhmani, Vivek; Pranesh, Venkat; Senthil, S.; Selvakumar, Arun T.",Kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection,Carbonate reservoir; Fines migration; Water saturation; Heat transfer; Permeability decline; Pressure change,OIL-RECOVERY; RESERVOIR ROCKS; OIL/BRINE/CARBONATE SYSTEM; SLOW MIGRATION; WETTABILITY; FILTRATION; SURFACE; FIELD; PH,"Kaolinite clay fines are prevalent in sandstone porous media and it has great impacts on permeability and well productivity decline. High temperature sandstone formations detach the fines from the pore surface and migrate along with the permeating fluid. At some point the fine particles are strained in the pore throats, which leading to permeability damage and well productivity decline. To the best of our knowledge this phenomenon is not well explored in the high temperature carbonate media. Since most of the world's oil reserves are held in carbonate media and its worth to explore the formation damage, especially due to fines migration during higher reservoir temperature at these formations composed of carbonate minerals. Hence, this paper presents laboratory modeling of kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection. In this paper, we have conducted three sets of coreflood experiments in the temperature ranges of 100 degrees C 150 degrees C, and 200 degrees C. Kaolinite suspension water has been injected into the porous limestone core at these temperature regimes to investigate the possibility of permeability and injectivity deterioration. The main experimental results showed there is an increase in water saturation and heat transfer rates. Concentration of fines surges with increasing PVI and permeability declines with increasing time. Pressure elevates with enhancing PVI, but it plummets after some time. Significantly, the water discharge rate declines for increasing suspension injection and on the other side, for fresh water injection, the rate of water discharge rises steadily. Furthermore, the electrical and thermal conductivities of effluent kaolinite colloid were higher. Moreover, experimental model were tested against statistical based optimizational model, response surface methodology (RSM). These results revealed good agreement and, hence, this paper has explicated the importance of kaolinite clay fines suspension transport in high temperature carbonate reservoirs.",3,3,0
Porous Media,Rock,"Aghabarari, Amirhossein; Ghaedi, Mojtaba",A new simulation approach to investigate reinfiltration phenomenon in fractured porous media,Naturally fractured reservoirs; Reinfiltration; Grey relational analysis; Simulation; Block to block interaction,RECOVERY,"The reinfiltration is a common phenomenon in fractured reservoirs and severely influence production rate. Despite the efforts made to study the reinfiltration process experimentally or theoretically, still there is not a comprehensive study that investigates all the affecting parameters. In this paper, a new approach to specify the reinfiltrated oil into the matrix block and drained oil from the matrix block in a commercial simulator has been introduced. Moreover, a new dimensionless parameter showing the degree of reinfiltration has been defined. Then, by using the proposed simulation method, the impact of different reservoir parameters has been examined. The investigated parameters are: porosity, permeability, matrix block dimensions, matrix and fracture compressibility, rock type and different type of reservoir's fluids. Finally, the grey relational analysis (GRA) was used to determine factors that have a significant influence on reinfiltration process. Results show that matrix block permeability-porosity factor has the highest impact on reinfiltration process.",4,5,0
Porous Media,Rock,"Wang, Shibin; Chen, Fuhu; Guo, Jianchun; Li, Yang; Zhao, Feng; Zhou, SiYan",Adsorption damage of hydroxypropyl guar gum to porous media composed of quartz,Guar gum; Adsorption; Quartz; Porous media; Hydrogen bond,NONIONIC SURFACTANT; NATURAL SURFACTANT; WATER; MECHANISM; SILICA; SAND,"Hydroxypropyl guar gum (HPG) is widely used in the hydraulic fracturing of sand rock gas reservoirs. The HPG residue can severely damage the rock surface of the reservoirs owing to the interaction between the HPG molecular chain and the rock surface, which results in adsorption and retention of HPG. To confirm the interaction between HPG and rock, the adsorption properties of HPG on a rock surface were investigated. The dependence of HPG adsorption on HPG concentration, pH, and temperature is discussed, and the adsorption force between HPG and quartz is also studied. With an increase in HPG concentration and pH, the amount of adsorbed HPG increases. The amount of adsorption increases first with temperature and then decreaseds. According to infrared spectroscopy and Zeta potential results, there is a weak chemical bond between HPG and quartz particles. Hydrogen bonding is the main force, which results in the adsorption and retention of HPG in porous media.",4,4,4
Porous Media,Rock,"Tolmacheva, K. I.; Boronin, S. A.; Osiptsov, A. A.",Formation damage and cleanup in the vicinity of flooding wells: Multi-fluid suspension flow model and calibration on lab data,Flooding wells; Injectivity decline; Suspension filtration; Formation damage; Colmatation,DEEP-BED FILTRATION; POROUS-MEDIA; PLANE WALL; TRANSPORT; SPHERE; ENTRAINMENT; DEPOSITION; SIMULATION; PARTICLES; MECHANICS,"Injection of water into a rock formation through the flooding wells is a common practice to maintain 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, which are introduced either externally (untreated water) or internally (e.g., particles detached from the inner surface of a pipeline due to erosion and abrasion as well as mineral particles detached from pore surface). In the framework of the two-fluid approach, we formulate mathematical model for filtration of a particle-laden suspension in the vicinity of flooding wells. Two mechanisms affecting transport of non-colloidal fines are considered: trapping and mobilization. Trapped particles reduce permeability and porosity of the rock, which leads to the injectivity decline of the well. The model contains minimal set of tuning parameters describing particle trapping and mobilization rates. This is achieved by critical overview of existing models. We calibrate suspension filtration model against existing experimental (laboratory) data on fines mobilization and trapping in porous media. A parametric study of different flooding scenarios is carried out numerically. In particular, we investigate the effectiveness of periodic flooding regime, when the periods of injection are followed by flowback in order to wash out trapped fines from the near-wellbore zone and restore well injectivity. Implications to formation damage and cleanup phenomena peculiar to hydraulic fracturing and drilling are discussed. Practical recommendations are given.",5,5,0
Porous Media,Rock,"Lei, Gang; Liao, Qinzhuo; Patil, Shirish; Zhao, Yang",Effect of clay content on permeability behavior of argillaceous porous media under stress dependence: A theoretical and experimental work,Argillaceous porous media; Permeability; Stress sensitivity; Theoretical model; Experimental tests,RELATIVE PERMEABILITY; FRACTAL MODEL; SANDSTONE; POROSITY,"Prediction of permeability behavior of argillaceous porous media (APM) is a major challenge for science and engineering, despite considerable advances in using both theoretical and experimental means over the last few decades. Specifically, the effect of clay content on stress sensitivity of APM is still an open question. In this paper, laboratory tests are conducted to investigate the effect of clay content on behavior of permeability for artificial argillaceous sandstone samples under stress dependence. Then a corresponding theoretical model for stress dependent permeability of APM based on fractal theory is derived to interpret the experimental results. The predicted results from the developed theoretical model are consistent with those determined by experimental tests, which verifies the developed model. The proposed model can be invoked to effectively study the coupled flow-deformation behavior in APM. The results show that the normalized permeability increases with increasing the power law index, increasing elastic modulus, increasing rock initial porosity, and decreasing clay content at a given effective stress. This work provides a comprehensive experimental and theoretical study on stress-dependent permeability in APM, which is beneficial to study the effect of clay content on permeability behavior of APM under stress dependence. In addition, with this proposed model, we can conduct the estimation of specific parameters (e.g., the structure of pore surface, the fractal dimension of pore, the maximum pore radius, the minimum pore radius, clay content, initial irreducible water saturation, and rock elastic modulus) using inverse modeling approaches.",5,5,1
Porous Media,Rock,"Wei, Shuaishuai; Shen, Jinsong; Yang, Wuyang; Li, Zhenling; Di, Shuhua; Ma, Chao",Application of the renormalization group approach for permeability estimation in digital rocks,Renormalization group approach; Permeability; Anisotropic block; Digital rocks; Reservoir characterization,LATTICE BOLTZMANN METHOD; THIN-SECTIONS; FLOW SIMULATION; POROUS-MEDIA; FLUID; RECONSTRUCTION; PREDICTION; ACCURACY; IMAGES; MODEL,"Rock permeabilities are typically calculated by applying some empirically derived relationships or expressions, which normally result in rough or erroneous values. Given advanced computing and smart techniques, rock samples acquired in boreholes or on outcrops can be imaged and broken down into small digital rocks. The renormalization group approach with isotropic block (RGAWIB) has been applied to calculate the permeability of digital rocks. The RGAWIB proposed by King can accurately derive the effective permeability if the pore structure is described correctly by the separated grid blocks. For King's method, the permeability of the grid block is assumed to be isotropic, which is not suitable for significant variance in neighboring permeabilities. In this study, we adopted discrete blocks with anisotropic permeability for the upscaling process of renormalization, which provided reasonable results for large perturbations of permeability in neighboring grid blocks. We assumed that the anisotropic block held different permeabilities in three orthogonal directions and calculated the effective permeabilities of idealized porous media and digital rocks by a renormalization group approach with anisotropic block (RGAWAB). Moreover, a permeability distribution method is presented in this paper. The original permeability distribution of an idealized porous media was calculated, along with the permeability distributions of the digital core data available in the literature in the x, y, and z directions using the method developed in this study. Then, we calculated the effective permeabilities of the digital rocks using RGAWAB in the x, y, and z directions, respectively. We compared the results with the absolute permeabilities calculated by the lattice Boltzmann method, which showed that the permeability calculation method was feasible for digital rocks.",5,5,2
Porous Media,Multiphase Flow,"Hemmingsen, Casper Schytte; Glimberg, Stefan Lemvig; Quadrio, Nathan; Volcker, Carsten; Nielsen, Kenny Krogh; Walther, Jens Honore; Byrne, Michael; Engsig-Karup, Allan P.",Multiphase coupling of a reservoir simulator and computational fluid dynamics for accurate near-well flow,Multiphase flow; Porous media; CFD; Near-wellbore; Reservoir simulation,TRANSPORT,"Near-well flow analysis is an important tool for gaining detailed insight of the flow behaviour and for improving well design and production optimization of real reservoirs. One challenge of accurate numerical modelling of the flow field in the vicinity of the well is related to the scale disparity factor in space and time. The numerical scale gap between the reservoir and the wellbore justifies the representation of a well as a point or line sink/source term in traditional reservoir models. However, standard numerical techniques for reservoir simulation are incapable of resolving the near-singular character of the pressure field in the vicinity of the well. Under the assumption that all length scales have impact on flow patterns, we present a proof-of-concept study aimed at improving the quality of the numerical simulation by considering the geometry and fluid flow near the wellbore in a fully connected system, thus accounting for the fine scale phenomena by means of a hybrid Navier-Stokes/Darcy wellbore model coupled with a full scale reservoir model. A weak coupling method based on fixed-point iterations, that preserves the mass flux transport across the coupled interface, while adjusting productivity indices, is demonstrated via numerical experiments. Several different numerical experiments are performed to demonstrate the versatility and the improved well performance insight that the coupled method offers, including horizontal well inflow profile, influence of formation damage and optimal well configuration.",1,2,1
Porous Media,Multiphase Flow,"Wang, Lei; Liu, Changwei; Jiang, Ping; Zhang, Hui; Tian, Xiaoming; Zhao, Nan; Mahlalela, B. M.",Characterization of two-phase flow in porous media using global mobility,Global mobility; Production performance; Water/polymer flooding; Two phase flow,SPONTANEOUS WATER IMBIBITION,"Proper characterization of multi-phase flow in porous media is of significant importance in selecting and optimizing the performance of a given oil reservoir. The main factors influencing the characterization of multi-phase flow in porous media include: microscopic pore structure, movable fluid saturation, nonlinear seepage characteristics and clay minerals composition, and etc. However, it is very difficult to quantitatively study the multiphase flow process in porous media, because there is no clear relationship between the oil production rate and the physical parameters of oil reservoir, particularly in low permeability reservoirs. Furthermore, on-going research activities has led to the discovery that it has been a challenge to tell why two oil reservoirs with the same degree of permeability (i.e. low permeability) have far different production performances. In an attempt to comprehend this challenge, a concept of global mobility by Li and Horne (2005, 2006) derived from the Li-Horne model was proved to be a new approach for evaluating the seepage capacity in imbibition system, because it can unify oil and water phase mobility into one model and take many static and dynamic physical parameters into accounts. In this paper, the global mobility concept is applied and verified to characterize the mobility of a multiphase flow and evaluate the production performance from core to field scale. Comparisons between the global mobility concept and other characterization methods were conducted based on various flooding experiments and field data tests from rock/oil/water systems and rock/oil/polymer systems with different porosities and permeabilities. The results showed that there is a linear relationship between the global mobility and the production performance which is better than the other methods, and the application range of the global mobility was extended. In addition, a convenient and empirical approach was proposed to obtain the global mobility with relative permeability data. Its feasibility has been preliminarily proved through five case studies, and the demonstration is that the global mobility could be an effective parameter to characterize a two-phase flow in porous media and evaluate the production performance for field application.",1,3,4
Porous Media,Multiphase Flow,"Sarris, Ernestos; Gravanis, Elias; Ioannou, Ioannis",A novel methodology for synthesizing the wetting capillary pressure curve of rocks through sorptivity data,Capillary pressure curve; Synthetic reconstruction of wetting curve; Van Genuchten model; Sorptivity test; Finite element analysis; Back analysis,MODEL; HYSTERESIS; EQUATION; DRAINAGE; BRICK,"Capillary pressure as a function of moisture content is an essential element in the modelling of multiphase flow in porous media, such as rocks. The constitutive relationship predicting the capillary pressure as a function of fluid saturation in these materials has been the focus of many studies in the literature, as the direct experimental determination of the former is usually time-consuming and not quite straightforward, owing to the topologically complicated pore structure of rocks. In this paper, we perform a systematic analysis of the interrelation between capillary pressure curves (CPC) and the corresponding imbibition curves to evaluate the parameters influencing the entire diffusive process. The aim is the reconstruction of the wetting CPC from sorptivity test data through back analysis, within the framework of the Van Genuchten model. We perform numerical simulations with finite elements, using as input synthetic models of CPC with one, two and three degrees of freedom, the latter being the widely accepted Van Genuchten model. The effectiveness and the limitations of the different models used and the sensitivity of the imbibition curves to each degree of freedom are investigated and critically evaluated. The whole investigation is assisted by theoretical estimations of the sorptivity coefficient, as a function of the model parameters and the measured quantities. The results of our analysis provide not only a clarification of the aforementioned interrelation, but also a relatively simple procedure for reconstructing synthetically the wetting CPC.",2,3,0
Porous Media,Multiphase Flow,"Zhang, Qingfu; Yao, Jun; Huang, Zhaoqin; Li, Yang; Zhang, Kai",Hybrid multiscale method for numerical modeling of coupled flow and geomechanics,Multiscale finite element method; Multiscale mimetic finite difference method; Coupled geomechanics and flow simulation,FINITE-ELEMENT-METHOD; MULTIPHASE FLOW; POROUS-MEDIA; ELLIPTIC PROBLEMS; 2-PHASE FLOW; SIMULATION; REDUCTION,"Geomechanical characteristics should be simulated accurately given their significant effects on the whole flow patterns in porous media. However, the coupled geomechanics and flow simulation imposes severe computational challenges to the computer resources. Therefore, the demand for accurate and efficient numerical techniques is widely increasing in applications. In this work, a hybrid multiscale algorithm is developed for solving coupled flow and geomechanics problems. Two sets of multiscale basis functions for the coupled problems are constructed, respectively. Multiscale Finite Element Method (MsFEM) is adopted to solve the local solid deformation problems within coarse cells to construct displacement basis functions. To generate conservative velocity and pressure fields, the flow basis functions are constructed using the Multiscale Mimetic Method. The proposed hybrid multiscale method is appealing for its advantage of solving coarse-scale problems while capturing fine-scale information. Numerical results are presented to demonstrate the accuracy and efficiency of the proposed multiscale method. The comparisons between MsFEM and the standard method tell us that the multiscale method is a promising method for coupled geomechanics and reservoir simulations.",3,3,2
Porous Media,Multiphase Flow,"Masoudi, Mohammad; Khosravi, Maryam; Rostami, Behzad; Abolhosseini, Pejman",Effect of Benard-Marangoni flow on the bypassed oil recovery: Micromodel study,Cold gas injection; Thermal marangoni flow; Benard-marangoni convection; Micromodel experiment; Dead-end pore; Matrix/fracture system,PLUS N-ALKANE; INTERFACIAL-TENSION; SURFACE-TENSION; MASS-TRANSFER; MULTIPHASE FLOW; CONVECTION; CO2; FLUID; CELLS; LAYER,"This paper presents an experimental study to show the impact of Benard Marangoni flow (type of Marangoni convective flow caused by temperature variation on the interface of fluids) on fluid flow in porous media. The importance of marangoni mechanism has been rarely addressed in the oil recovery mechanisms in the related literature. In this regard, cold gas (Carbon dioxide or methane) has been injected into a fractured system to recover the bypassed oil in matrix via convective fluxes induced by interfacial tension gradient. Results demonstrate that the thermal Marangoni flow improves oil recovery significantly by enhancing the flux of oil/injectant from/into the matrix. Furthermore, the amount and rate of oil recovery are proportional to Marangoni number. Marangoni flow in carbon dioxide injection is much stronger than methane injection, owing to larger amount of interfacial tension gradient.",3,3,2
Porous Media,Multiphase Flow,"Modaresghazani, J.; Moore, R. G.; Mehta, S. A.; van Fraassen, K. C.",Investigation of the relative permeabilities in two-phase flow of heavy oil/water and three-phase flow of heavy oil/water/gas systems,Relative permeability; Heavy oil; Two-phase and three-phase flow; Water flood; Drainage and imbibition,POROUS-MEDIA; OIL,"An experimental study was conducted to investigate two-phase and three-phase relative permeability behavior in a multi-phase flow, which involved a typical Canadian bitumen. A series of isothermal core flood experiments were conducted on an unconsolidated core composed of cleaned Athabasca sand matrix and relative permeabilities of the involved phases were determined. Drainage and imbibition processes for two-phase water/oil flow and oil saturation reversal in a three-phase oil/water/gas flow, which is encountered in a typical air injection process were examined. A history matching technique was used to determine relative permeabilities for two-phase water/oil and gas/liquid systems. A strong hysteresis was observed in both wetting phase and non-wetting phase relative permeabilities. The endpoint relative permeability of oil was higher than the end-point relative permeability of water by two orders of magnitude in two-phase water/oil experiments. Similar end-point relative permeability ratio was observed in two-phase liquid/gas experiments. Using the determined relative permeabilities for two-phase flows, Stone's first and second model and Baker's interpolation model were used to predict the fluid production in the three-phase flow. Despite showing a satisfactory prediction for liquid production, all models showed a significant deviation for produced gas at the early stages of the three-phase flow experiment.",5,6,0
Porous Media,Multiphase Flow,"Li, Caoxiong; Lin, Mian; Ji, Lili; Jiang, Wenbin",Multiphase flow in tight sandstone: An improved application for 3D intermingled fractal model,Tight sandstone; Fractal; Mineral component; Multiphase displacement,DYNAMIC CONTACT-ANGLE; WATER RELATIVE PERMEABILITY; GAS-RESERVOIRS; POROUS-MEDIA; THERMAL-CONDUCTIVITY; LIQUID INFILTRATION; SIZE DISTRIBUTION; 2-PHASE FLOW; UNITS MODEL; PREDICTION,"Multiphase displacement in tight sandstone is fundamental and critical for tight oil production. Micropores dominate the pore space in tight sandstone. Microscopic mineral components in micropores substantially influence the multiphase displacement behavior. Pore size distribution exhibits a self-similar or fractal property, similar to inorganic mineral grains. Utilizing fractal theory eases the rebuilding of the flowing space and calculation of relative permeability. As an improvement of previous work, we successfully extended the 3D intermingled fractal model (3D IFM). The extended 3D IFM can evaluate multiphase flow behavior in tight sandstone, considering fractal characteristics of pore size distribution and mineral grain distribution. The fractal information of pores and mineral properties are obtained by scalable scanning electron microscopy (SEM) and energy dispersive spectroscopy(EDS) images, respectively. This method is useful and reliable for calculating relative permeability and residual saturation. The method is also successfully used to evaluate the influence of oil-water viscosity ratio, mineral components and formation depth on multiphase displacement behavior, proving its convenience and potential in rapidly evaluating multiphase displacement behavior in tight sandstone.",5,5,4
Porous Media,Formation,"Hemmingsen, Casper Schytte; Glimberg, Stefan Lemvig; Quadrio, Nathan; Volcker, Carsten; Nielsen, Kenny Krogh; Walther, Jens Honore; Byrne, Michael; Engsig-Karup, Allan P.",Multiphase coupling of a reservoir simulator and computational fluid dynamics for accurate near-well flow,Multiphase flow; Porous media; CFD; Near-wellbore; Reservoir simulation,TRANSPORT,"Near-well flow analysis is an important tool for gaining detailed insight of the flow behaviour and for improving well design and production optimization of real reservoirs. One challenge of accurate numerical modelling of the flow field in the vicinity of the well is related to the scale disparity factor in space and time. The numerical scale gap between the reservoir and the wellbore justifies the representation of a well as a point or line sink/source term in traditional reservoir models. However, standard numerical techniques for reservoir simulation are incapable of resolving the near-singular character of the pressure field in the vicinity of the well. Under the assumption that all length scales have impact on flow patterns, we present a proof-of-concept study aimed at improving the quality of the numerical simulation by considering the geometry and fluid flow near the wellbore in a fully connected system, thus accounting for the fine scale phenomena by means of a hybrid Navier-Stokes/Darcy wellbore model coupled with a full scale reservoir model. A weak coupling method based on fixed-point iterations, that preserves the mass flux transport across the coupled interface, while adjusting productivity indices, is demonstrated via numerical experiments. Several different numerical experiments are performed to demonstrate the versatility and the improved well performance insight that the coupled method offers, including horizontal well inflow profile, influence of formation damage and optimal well configuration.",1,2,1
Porous Media,Formation,"Kanimozhi, B.; Thamizhmani, Vivek; Pranesh, Venkat; Senthil, S.; Selvakumar, Arun T.",Kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection,Carbonate reservoir; Fines migration; Water saturation; Heat transfer; Permeability decline; Pressure change,OIL-RECOVERY; RESERVOIR ROCKS; OIL/BRINE/CARBONATE SYSTEM; SLOW MIGRATION; WETTABILITY; FILTRATION; SURFACE; FIELD; PH,"Kaolinite clay fines are prevalent in sandstone porous media and it has great impacts on permeability and well productivity decline. High temperature sandstone formations detach the fines from the pore surface and migrate along with the permeating fluid. At some point the fine particles are strained in the pore throats, which leading to permeability damage and well productivity decline. To the best of our knowledge this phenomenon is not well explored in the high temperature carbonate media. Since most of the world's oil reserves are held in carbonate media and its worth to explore the formation damage, especially due to fines migration during higher reservoir temperature at these formations composed of carbonate minerals. Hence, this paper presents laboratory modeling of kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection. In this paper, we have conducted three sets of coreflood experiments in the temperature ranges of 100 degrees C 150 degrees C, and 200 degrees C. Kaolinite suspension water has been injected into the porous limestone core at these temperature regimes to investigate the possibility of permeability and injectivity deterioration. The main experimental results showed there is an increase in water saturation and heat transfer rates. Concentration of fines surges with increasing PVI and permeability declines with increasing time. Pressure elevates with enhancing PVI, but it plummets after some time. Significantly, the water discharge rate declines for increasing suspension injection and on the other side, for fresh water injection, the rate of water discharge rises steadily. Furthermore, the electrical and thermal conductivities of effluent kaolinite colloid were higher. Moreover, experimental model were tested against statistical based optimizational model, response surface methodology (RSM). These results revealed good agreement and, hence, this paper has explicated the importance of kaolinite clay fines suspension transport in high temperature carbonate reservoirs.",3,3,0
Porous Media,Formation,"Zhang, Yizhong; Zhang, Maolin; Mei, Haiyan; Zeng, Fanhua",Study on salt precipitation induced by formation brine flow and its effect on a high-salinity tight gas reservoir,Core flooding test; Salt precipitation; Formation brine flow; Core evaporation test; Microscopic visual flooding; Tight gas reservoir,CO2 INJECTION; NUMERICAL-SIMULATION; POROUS-MEDIA; EVAPORATION; SHALE,"For the tight gas reservoir with high salinity formation water, the flow of formation brine may cause salt precipitation and thus promote scale formation. Salt deposition and the accompanying scale formation as well as swelling and shrinkage of clay minerals may cause blockage of the pore and throats, which will significantly reduce permeability and the subsequent gas production rate. In this study, the influence of salt precipitation/dissolution on the physical properties of a tight gas reservoir is studied. Core analyses, core flooding tests, core evaporation tests, and microscopic visual flooding inspections are carried out on core samples extracted from the Shahejie Formation. To simulate the depletion production process in the subsurface, brine flow characteristics are studied by core flooding tests with pressure reduction at a formation temperature of 115 degrees C and with the change of pressure ranging from 30 to 1 MPa. The potential changes in physical properties including permeability, porosity, pore radius, pore size distribution, and surface area are analyzed by core evaporation tests. To show the brine flow and geometry of salt deposits in the pore structure, visual brine flooding is observed under high magnification microscope. Photos of the pore structure at different stages of salt precipitation are recorded. The results reveal that salt dissolution/precipitation has a significant impact on flow-through characteristics, and it can be divided into three stages during the depletion process. The damage of salt to the core permeability could reach more than 90%, and it increases gradually with the reduction of porosity and initial permeability and the increase of specific area. The maximum formation damage caused by salt precipitation is realized when the salt crystal size and pore throat diameter are close in size. The semi-empirical Carman-Kozeny equation together with porosity and grain diameter is used to estimate the permeability after precipitation.",4,4,5
Porous Media,Formation,"Tolmacheva, K. I.; Boronin, S. A.; Osiptsov, A. A.",Formation damage and cleanup in the vicinity of flooding wells: Multi-fluid suspension flow model and calibration on lab data,Flooding wells; Injectivity decline; Suspension filtration; Formation damage; Colmatation,DEEP-BED FILTRATION; POROUS-MEDIA; PLANE WALL; TRANSPORT; SPHERE; ENTRAINMENT; DEPOSITION; SIMULATION; PARTICLES; MECHANICS,"Injection of water into a rock formation through the flooding wells is a common practice to maintain 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, which are introduced either externally (untreated water) or internally (e.g., particles detached from the inner surface of a pipeline due to erosion and abrasion as well as mineral particles detached from pore surface). In the framework of the two-fluid approach, we formulate mathematical model for filtration of a particle-laden suspension in the vicinity of flooding wells. Two mechanisms affecting transport of non-colloidal fines are considered: trapping and mobilization. Trapped particles reduce permeability and porosity of the rock, which leads to the injectivity decline of the well. The model contains minimal set of tuning parameters describing particle trapping and mobilization rates. This is achieved by critical overview of existing models. We calibrate suspension filtration model against existing experimental (laboratory) data on fines mobilization and trapping in porous media. A parametric study of different flooding scenarios is carried out numerically. In particular, we investigate the effectiveness of periodic flooding regime, when the periods of injection are followed by flowback in order to wash out trapped fines from the near-wellbore zone and restore well injectivity. Implications to formation damage and cleanup phenomena peculiar to hydraulic fracturing and drilling are discussed. Practical recommendations are given.",5,5,0
Porous Media,Formation,"Li, Caoxiong; Lin, Mian; Ji, Lili; Jiang, Wenbin",Multiphase flow in tight sandstone: An improved application for 3D intermingled fractal model,Tight sandstone; Fractal; Mineral component; Multiphase displacement,DYNAMIC CONTACT-ANGLE; WATER RELATIVE PERMEABILITY; GAS-RESERVOIRS; POROUS-MEDIA; THERMAL-CONDUCTIVITY; LIQUID INFILTRATION; SIZE DISTRIBUTION; 2-PHASE FLOW; UNITS MODEL; PREDICTION,"Multiphase displacement in tight sandstone is fundamental and critical for tight oil production. Micropores dominate the pore space in tight sandstone. Microscopic mineral components in micropores substantially influence the multiphase displacement behavior. Pore size distribution exhibits a self-similar or fractal property, similar to inorganic mineral grains. Utilizing fractal theory eases the rebuilding of the flowing space and calculation of relative permeability. As an improvement of previous work, we successfully extended the 3D intermingled fractal model (3D IFM). The extended 3D IFM can evaluate multiphase flow behavior in tight sandstone, considering fractal characteristics of pore size distribution and mineral grain distribution. The fractal information of pores and mineral properties are obtained by scalable scanning electron microscopy (SEM) and energy dispersive spectroscopy(EDS) images, respectively. This method is useful and reliable for calculating relative permeability and residual saturation. The method is also successfully used to evaluate the influence of oil-water viscosity ratio, mineral components and formation depth on multiphase displacement behavior, proving its convenience and potential in rapidly evaluating multiphase displacement behavior in tight sandstone.",5,5,4
Porous Media,Formation,"Zhang, Lei; Wu, Feipeng; Pu, Chunsheng",Mechanism of formation of chromium acetate(Cr3+)/ phenol-formaldehyde resin prepolymer(PRP) complex and its compound cross-linking reaction with polymer for conformance control,Oil production; Polymer gel; Conformance control; Chromium acetate; Phenol-formaldehyde,WATER SHUTOFF; NONIONIC POLYACRYLAMIDE; PROFILE CONTROL; POROUS-MEDIA; GEL SYSTEMS; RESERVOIR; CARBOXYLATES; GELATION,"For the heterogeneous oil reservoir with high water cut, the conformance control by using polymer gels is good for increasing oil production and decreasing excessive water. However, facing the current situation of low oil prices, how to improve the exploitation efficiency and reduce the production cost in the maximum extent are still drawing the attention of petroleum engineers. Therefore, it is necessary to further study the polymer gels to achieve this purpose. Among the polymer gels, the polymer/Cr3+ system and polymer/phenolic-formaldehyde compounds system are the most common used, which are suitable for the low temperature reservoir and high temperature reservoir, respectively. Based on the properties of each other, the combination of Cr3+ and phenolformaldehyde resin prepolymer (PRP) as a type of cross-linking agent can not only improve the thermal stability of polymer/Cr3+ gel, but also enable polymer/PRP gel to be applied to low-medium temperature reservoirs, which can further improve the application effect of polymer gels. However, the mechanism of compound crosslinking reaction of Cr3+ -PRP and polymer is still unclear. In this paper, the properties of Cr3+-PRP solution is first tested and then the process of crosslinking reaction of Cr3+-PRP and polymer is study. In the Cr3+-PRP solution, a new polynuclear olation complex ion of chromium (Cr3+-PRP complex) is formed, of which the properties is different from PRP solution or chromium acetate solution. The cross-linking reaction of Cr3+-PRP complex and polymer is compound. During the compound reaction at the temperature of 45 degrees C, the reaction of Cr3+ and polymer has an impact on that of PRP and polymer, so that the reaction of Cr3+-PRP complex and polymer is different from the superposition of the two reaction processes of Cr3+/polymer system and PRP/ polymer system. The formed Cr3+-PRP complex can resist salt to 70,000 mg/L. The experimental results can provide a theoretical guidance for the high efficient practical application of conformance control by using polymer/Cr3+ system or polymer/phenolic-formaldehyde compounds system.",5,5,4
Porous Media,Polymer,"Radovanovic, Anna M.; Pires, Adolfo P.; Peres, Alvaro M. M.",Semi-analytical transient pressure solution for power-law polymer injection in a vertical well,non-Newtonian flow; Enhanced oil recovery; Power-law fluids,FLOW; FLUIDS,"Enhanced Oil Recovery (EOR) is a process that extends reservoir life through field operations that aim to increase reservoir displacement efficiency. Injection of polymeric solutions, which is a chemical EOR process, improves sweep efficiency by decreasing the mobility of the injected fluids. One challenge in polymer flooding is to model the non-Newtonian rheological behavior of the injected solutions due to the complex interdependence between fluid flow velocity, fluid viscosity and shear rate. Proper reservoir management requires a thorough understanding of non-Newtonian fluid flow behavior through porous media, thus the need for new and improved mathematical models that describe the transient pressure behavior in wells. In this work we consider the flow of non-Newtonian pseudoplastic fluids in homogeneous isotropic porous media. To describe the rheological polymer behavior, we used the well-known power-law model, which leads to a nonlinear problem. In this paper, a novel semi-analytical solution is obtained by combining spatial domain discretization with pseudotime, so the flow problem is rewritten as a system of linear equations in Laplace domain. We also presented a variation of the proposed solution by assuming a pseudostationary behavior of the non-Newtonian velocity. Both approaches are compared to previously published approximated analytical solutions. One interesting aspect of our work is that it can be extended to more realistic polymer rheological models.",0,1,0
Porous Media,Polymer,"Mukhamatdinov, Irek I.; Aliev, Firdays A.; Acosta, Anabel Sosa; Vakhin, Alexey V.",A new approach for measuring rheology of polymer solutions in reservoir conditions,Polymer; Polyacrylamide; Rheology; Wettability; Interfacial tension,ENHANCED OIL-RECOVERY; HEAVY OIL; WATER; NANOPARTICLES; SURFACTANT; ADSORPTION; NETWORKS,"The simulation of flow processes under reservoir condition is a hard task. Viscosity of polymer solution in porous media depends on adsorption of polymers on mineral substrates. Specific features characterize filtration of polymer solutions in porous media. Here, we propose a new approach to evaluate the rheology of polymers that considers fluid interactions with mineral surfaces. The principle of this method is as follows: measuring viscosity of ""mineral-in-polymer"" suspension. Hence, this approach needs simple equipment rather than complex core flooding system. The laboratory selection of effective polymer and its optimum concentration is carried out by the proposed approach. It is crucial for primary screening of some polymers. The presence of dispersed minerals in model suspensions influences the surface tension between the polymer solution and solid surface with various chemical nature. In order to justify this method, we used minerals with different chemical nature such as dispersed calcite and dolomite, and two widely used polyacrylamide type polymers that differ in molecular masses. We observed that viscosities between various suspensions differ several times due to the surface nature. We also determined the correlation between the viscosity of model suspension and contact angle. The latter is determined by chemical nature of minerals.",0,0,1
Porous Media,Polymer,"Zampieri, M. F.; Quispe, C. C.; Moreno, R. B. Z. L.",Model upsizing for integrated evaluation of polymer degradation and polymer flooding lab data,Enhanced oil recovery; Polymer flooding; Simulation; Polymer degradation; Model upsizing,ENHANCED OIL-RECOVERY; SURFACTANT,"In oil recovery operations through polymer flooding, it is essential that the polymer maintains its stability until near the producer well, avoiding degradation phenomena. The present paper seeks to assess the representation of the degradation effects associated with polymer flooding for heavy oil recovery through one-dimension simulation models with different sizes. Base models were developed using data from the literature and previous lab work. The models consider adsorption, accessible pore volume, residual resistance factor, polymer concentration and non-Newtonian effects. Aiming at including degradation effects, a methodology of model size increase was developed, allowing to combine the evaluation of long-term dependent effects with displacement mechanisms. A sensitivity analysis was performed for the degradation, considering four levels of polymer half-life time. The lab-scale models were submitted to an upsizing procedure, generating models 100 times and 10.000 times bigger. The outcomes showed that the higher the level of the reaction frequency factor, the faster the degradation process. In the presence of original and degraded polymers in the porous media, we observed two advance fronts. The front of the degraded polymer advanced faster for a higher reaction frequency factor, while the advance front of the original polymer was delayed. We analyzed the results in terms of cumulative produced water, cumulative produced oil, average pressure, oil recovery factor, cumulative mass of the injected polymer, cumulative mass of the degraded polymer, water phase saturation, and water phase viscosity. The procedure for model upsizing was matched using a linear scaling factor. The method permits parameters found in laboratory experiments to be simulated in field-scale. Normalized results allowed comparing the impact of the main physical phenomena related to polymer flooding in the mentioned results, independent of the model size.",3,3,0
Porous Media,Polymer,"Han, Pu; Geng, Jiaming; Bai, Baojun",Investigation on transport behavior of nanogel in low permeable porous medium,Nanogel; Filtration; Membrane; Transport,LINKED POLYMER MICROSPHERES; WATER,"Nano-sized crosslinked polymeric particles (nanogels) have the advantages of both nanoparticles and hydrogels for enhanced oil recovery in the oil and gas industries. Although some encouraging progress in the application has been made, the transport behavior of nanogels through porous media are still not clear. In this work, a series of filtration experiments using membrane filter were performed to study the effect of nanogel diameter, pore size, and differential pressure on the transport behavior. The equilibrium filtration rate, which is a key parameter to indicate the transport behavior during steady state, increased from 0.19 to 5.71 mL/min when the pore size changed from 0.05 to 0.8 pm, and increased from 1.02 to 1.99 mL/min when the differential pressure raised from 10 to 30 psi. Experimental results demonstrated nanogels present smaller diameter (105.7 nm) and lower absolute value of zeta-potential ( -18.9 mV) in 10 wt% NaCl solution than distilled water (295.3 nm and - 82.5 mV). The higher salt concentration resulted in a better nanogel injectivity (equilibrium filtration rate increased from 0.77 to 4.52 when NaCl concentration changed from 0 to 10 wt%), which indicated the diameter of nanogel is a more determining factor than the nanogel strength. When the pore size was smaller than similar to 3 times of the naongel diameter, the equilibrium filtration rate became independent to the differential pressure and nanogels started to form face plugging on the membrane. The core filtration tests demonstrated that the nanogels maintained similar transport behavior through the limestone cores and membrane filters that the resistance factor is 26.59 in membrane and 18.56 in core with similar pore diameter. The transport behaviors of nanogel and corresponding mechanisms are summarized by the matching relationship between the diameter of nanogel and the pore size in low permeable porous medium.",4,4,0
Porous Media,Polymer,"Zhang, Lei; Wu, Feipeng; Pu, Chunsheng",Mechanism of formation of chromium acetate(Cr3+)/ phenol-formaldehyde resin prepolymer(PRP) complex and its compound cross-linking reaction with polymer for conformance control,Oil production; Polymer gel; Conformance control; Chromium acetate; Phenol-formaldehyde,WATER SHUTOFF; NONIONIC POLYACRYLAMIDE; PROFILE CONTROL; POROUS-MEDIA; GEL SYSTEMS; RESERVOIR; CARBOXYLATES; GELATION,"For the heterogeneous oil reservoir with high water cut, the conformance control by using polymer gels is good for increasing oil production and decreasing excessive water. However, facing the current situation of low oil prices, how to improve the exploitation efficiency and reduce the production cost in the maximum extent are still drawing the attention of petroleum engineers. Therefore, it is necessary to further study the polymer gels to achieve this purpose. Among the polymer gels, the polymer/Cr3+ system and polymer/phenolic-formaldehyde compounds system are the most common used, which are suitable for the low temperature reservoir and high temperature reservoir, respectively. Based on the properties of each other, the combination of Cr3+ and phenolformaldehyde resin prepolymer (PRP) as a type of cross-linking agent can not only improve the thermal stability of polymer/Cr3+ gel, but also enable polymer/PRP gel to be applied to low-medium temperature reservoirs, which can further improve the application effect of polymer gels. However, the mechanism of compound crosslinking reaction of Cr3+ -PRP and polymer is still unclear. In this paper, the properties of Cr3+-PRP solution is first tested and then the process of crosslinking reaction of Cr3+-PRP and polymer is study. In the Cr3+-PRP solution, a new polynuclear olation complex ion of chromium (Cr3+-PRP complex) is formed, of which the properties is different from PRP solution or chromium acetate solution. The cross-linking reaction of Cr3+-PRP complex and polymer is compound. During the compound reaction at the temperature of 45 degrees C, the reaction of Cr3+ and polymer has an impact on that of PRP and polymer, so that the reaction of Cr3+-PRP complex and polymer is different from the superposition of the two reaction processes of Cr3+/polymer system and PRP/ polymer system. The formed Cr3+-PRP complex can resist salt to 70,000 mg/L. The experimental results can provide a theoretical guidance for the high efficient practical application of conformance control by using polymer/Cr3+ system or polymer/phenolic-formaldehyde compounds system.",5,5,4
Porous Media,Porous Medium,"Du, Dongxing; Zhang, Dan; Li, Yingge; Dong, Xu; Sun, Zhifeng; Chao, Kun",Numerical investigations on the inlet and outlet behavior of foam flow process in porous media using stochastic bubble population balance model,Inlet behavior; Outlet behavior; Foam flow; Porous media; Stochastic bubble population balance model; Foam relative permeability reduction factor,CO2 STORAGE; OIL; SIMULATION; CO2-EOR; MOTION; TRANSIENT; VISCOSITY,"Numerical investigations were carried out with special attentions on the inlet and outlet behaviors of foam flow process in a homogeneous porous media with confined entrance and exit boundaries. The Stochastic Bubble Population (SBP) balance model, which usually involves two parameters of the bubble generation rate K-g and the maximum bubble density n(infinity) for bubble number prediction, was employed to study the dynamic foam generation and development process in porous media. With introduction the K-fp parameter to take into account the foam phase relative permeability reduction effect, the control equations of the two-phase flow process in a two-dimensional computational domain were solved with the IMPES algorithm and the inlet and outlet behavior of the foam displacement process were scrutinized based on detailed analysis of the bubble density, water phase pressure and water phase saturation distributions in porous medium. Numerical results showed a clear entrance effect of higher water saturation, lower pressure gradient and developing bubble density in the inlet region of the porous media in the transient foam displacement process, whereas the confined exit results in elevating water saturation and decreasing pressure gradient towards the outlet of the core. Parametric studies on K-g, n(infinity), K-fp and inlet & outlet sizes D indicate higher bubble generation rate could remarkably suppress the entrance region in the foam seepage process, while the higher maximum bubble number did not lead to obvious change of the foam flow behavior in the inlet and outlet region, although it could produce higher absolute values of bubble density and pressure drop along the core. With lower K-fp values, the strong foam flooding behavior could be properly predicted with much higher pressure drop and lower water saturation. Two dimensional numerical results at various inlet and outlet sizes clearly show the confined geometry effect on foam flow characteristics with smaller sizes corresponding to longer inlet and outlet regions. Computational domain and numerical results were validated through comparisons with corresponding experimental setup and CT measurement results. It is observed that, the numerical simulation could reproduce not only qualitatively but also quantitatively the experimentally obtained water saturation distribution and pressure drop result. It is concluded that the mechanistic stochastic bubble population model could be reasonably employed on prediction of the inlet and outlet behavior in the transient foam flow process in the homogeneous porous media.",1,1,2
Porous Media,Porous Medium,"Sergeev, Stanislav; Ryzhikov, Nikita; Mikhailov, Dmitry",Laboratory investigation of sound induced by gas flow in porous media,Acoustic emission; Gas flow; Porous medium; Laboratory study,,"This paper is devoted to studying the parameters of acoustic signals induced by fluid flow in porous media. The setup design and technique of acoustic measurements are described in detail. Sound induced by nitrogen flow in different types of carbonate rocks and sandstones is measured and analyzed. Limestone samples generate acoustic signals within a frequency range from 2 to 30 kHz. Sound in sandstone is significantly different from that in the limestone samples and occurs in a frequency range from 1 to 5 kHz. For limestone samples, sound generation is observed at lower flow rates than for sandstone due to earlier transition to a non-Darcy flow regime. From complementary analysis of hydrodynamic parameters of experiments, it is inferred that acoustic signals in rock samples appear only when the Forchheimer number exceeds values in the range 0.3-0.4. It is demonstrated that the recorded sound is mainly produced in the relatively thin near-surface zone of rock samples.",2,4,1
Porous Media,Porous Medium,"Anwar, Ishtiaque; Chojnicki, Kirsten; Bettin, Giorgia; Taha, Mahmoud Reda; Stormont, John C.",Characterization of wellbore casing corrosion product as a permeable porous medium,Casing corrosion; Leaky wellbore; Sustained casing pressure; Transmissivity; Corrosion product,NON-DARCY FLOW; GEOLOGIC STORAGE ENVIRONMENTS; GAS-WELLS; EFFECTIVE PERMEABILITIES; LABORATORY MEASUREMENTS; FORCHHEIMER EQUATION; NONLINEAR FLOW; CARBON-STEEL; FLUID-FLOW; INTEGRITY,"Leakage along wellbores is of concern for a variety of applications, including sub-surface fluid storage facilities, geothermal wells, and CO2 storage wells. We have investigated whether corroded casing is permeable to gas and can serve as a leakage pathway along wellbores. Three specimens were prepared from laboratory steel plates corroded using different mechanisms to reflect different possible field conditions and produce a variety of corrosion rates. Single-phase gas flow measurements were made under a range of gas pressures to investigate flow in both the viscous and visco-inertial flow regimes. Tests were conducted at different confining stresses (range from 3.45 to 13.79 MPa) following both loading and unloading paths. The gas flow test results suggest corroded casing can serve as a significant leakage path along the axis of a wellbore. Transmissivity was found to be sensitive to the variation in confining stress suggesting that the corrosion product is deformable. Gas slip factors and the coefficients of inertial resistance of the corrosion product were comparable to those available in the literature for other porous media. Post-test examination of the corrosion product revealed it to be a heterogeneous, mesoporous material with mostly non-uniform slit type porosity. There was no discernable difference in the composition of corrosion product from specimens corroded by different mechanisms.",4,4,0
Porous Media,Porous Medium,"Han, Pu; Geng, Jiaming; Bai, Baojun",Investigation on transport behavior of nanogel in low permeable porous medium,Nanogel; Filtration; Membrane; Transport,LINKED POLYMER MICROSPHERES; WATER,"Nano-sized crosslinked polymeric particles (nanogels) have the advantages of both nanoparticles and hydrogels for enhanced oil recovery in the oil and gas industries. Although some encouraging progress in the application has been made, the transport behavior of nanogels through porous media are still not clear. In this work, a series of filtration experiments using membrane filter were performed to study the effect of nanogel diameter, pore size, and differential pressure on the transport behavior. The equilibrium filtration rate, which is a key parameter to indicate the transport behavior during steady state, increased from 0.19 to 5.71 mL/min when the pore size changed from 0.05 to 0.8 pm, and increased from 1.02 to 1.99 mL/min when the differential pressure raised from 10 to 30 psi. Experimental results demonstrated nanogels present smaller diameter (105.7 nm) and lower absolute value of zeta-potential ( -18.9 mV) in 10 wt% NaCl solution than distilled water (295.3 nm and - 82.5 mV). The higher salt concentration resulted in a better nanogel injectivity (equilibrium filtration rate increased from 0.77 to 4.52 when NaCl concentration changed from 0 to 10 wt%), which indicated the diameter of nanogel is a more determining factor than the nanogel strength. When the pore size was smaller than similar to 3 times of the naongel diameter, the equilibrium filtration rate became independent to the differential pressure and nanogels started to form face plugging on the membrane. The core filtration tests demonstrated that the nanogels maintained similar transport behavior through the limestone cores and membrane filters that the resistance factor is 26.59 in membrane and 18.56 in core with similar pore diameter. The transport behaviors of nanogel and corresponding mechanisms are summarized by the matching relationship between the diameter of nanogel and the pore size in low permeable porous medium.",4,4,0
Porous Media,Porous Medium,"Agista, Madhan Nur; Andersen, Pal Ostebo; Yu, Zhixin",Modelling nanofluid injection in porous media,,CORRELATION EQUATION; NANOPARTICLES; FILTRATION; ADSORPTION; TRANSPORT; FLOW,"In this study, we developed a scaled advection-dispersion-reaction type model to simulate simultaneous injection of nanoparticle (NP) and tracer into porous media. Different particle types and experimental conditions (systematic variations of concentrations and injection rates for five NP types) led to different characteristics in the effluent profile. The deposition term was assumed linear in rate and concentration, but was required to have a rate dependent collector efficiency to explain the experimental observations. The adsorption term was assumed linear in concentration which could be used to interpret four tests (where a parameter was varied). The fifth required a Langmuir adsorption isotherm to be explained, related to the finite adsorption capacity of the porous medium. In all tests where the NP concentration was reduced, the observations could only be explained assuming the adsorption was irreversible. The interpreted experimental behavior could be classified into deposition dominated or adsorption dominated flow regimes depending on the magnitude of the dimensionless numbers derived from the scaled model. Guidelines for systematic measurements and interpretations are proposed.",5,5,1
Porous Media,High Temperature,"Kanimozhi, B.; Thamizhmani, Vivek; Pranesh, Venkat; Senthil, S.; Selvakumar, Arun T.",Kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection,Carbonate reservoir; Fines migration; Water saturation; Heat transfer; Permeability decline; Pressure change,OIL-RECOVERY; RESERVOIR ROCKS; OIL/BRINE/CARBONATE SYSTEM; SLOW MIGRATION; WETTABILITY; FILTRATION; SURFACE; FIELD; PH,"Kaolinite clay fines are prevalent in sandstone porous media and it has great impacts on permeability and well productivity decline. High temperature sandstone formations detach the fines from the pore surface and migrate along with the permeating fluid. At some point the fine particles are strained in the pore throats, which leading to permeability damage and well productivity decline. To the best of our knowledge this phenomenon is not well explored in the high temperature carbonate media. Since most of the world's oil reserves are held in carbonate media and its worth to explore the formation damage, especially due to fines migration during higher reservoir temperature at these formations composed of carbonate minerals. Hence, this paper presents laboratory modeling of kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection. In this paper, we have conducted three sets of coreflood experiments in the temperature ranges of 100 degrees C 150 degrees C, and 200 degrees C. Kaolinite suspension water has been injected into the porous limestone core at these temperature regimes to investigate the possibility of permeability and injectivity deterioration. The main experimental results showed there is an increase in water saturation and heat transfer rates. Concentration of fines surges with increasing PVI and permeability declines with increasing time. Pressure elevates with enhancing PVI, but it plummets after some time. Significantly, the water discharge rate declines for increasing suspension injection and on the other side, for fresh water injection, the rate of water discharge rises steadily. Furthermore, the electrical and thermal conductivities of effluent kaolinite colloid were higher. Moreover, experimental model were tested against statistical based optimizational model, response surface methodology (RSM). These results revealed good agreement and, hence, this paper has explicated the importance of kaolinite clay fines suspension transport in high temperature carbonate reservoirs.",3,3,0
Porous Media,High Temperature,"Hong, Eunji; Jeong, Moon Sik; Lee, Kun Sang",Optimization of nonisothermal selective plugging with a thermally active biopolymer,Microbial enhanced oil recovery (MEOR); High-temperature reservoir; Selective plugging; Nonisothermal biokinetics; Leuconostoc mesenteroides,ENHANCED OIL-RECOVERY; LEUCONOSTOC-MESENTEROIDES; BIOSURFACTANT PRODUCTION; KINETICS; TEMPERATURE; MODEL; DEXTRANSUCRASE; RESERVOIRS; METABOLISM; TRANSPORT,"A novel concept of microbial enhanced oil recovery (MEOR) under nonisothermal conditions was developed based on temperature-dependent biokinetics. The model specified the use of temperature-triggered Dextran (a biopolymer) produced by Leuconostoc mesenteroides (a microbe). The effects of environmental temperature on microbial growth and biopolymer production were validated and calibrated using the cardinal temperature model and experimental results. Various biokinetic parameters and a permeability reduction factor were also obtained to within approximately 2% error of those previously reported sandpack experiment. Based on the developed nonisothermal biokinetic model and the permeability reduction factor, thermally active MEOR was analyzed for a high-temperature reservoir. The results suggested the influences of injection parameters, such as injected nutrient concentration, rate, and temperature, on oil recovery factor. Higher nutrient concentrations resulted in increased Dextran production, thereby increasing oil recovery by selective plugging. On the other hand, injection rate and temperature were related to Dextran distributions. Higher injection rates led to lower Dextran concentrations with wider distributions. The injection temperature controlled the location of trapped Dextran in porous media, thereby influencing oil recovery. Through the optimization process, the injection design was determined with a rate of 30 m(3).day(-1), temperature of 5 degrees C, and nutrient mole fraction of 0.009. The suggested optimal injection design resulted in the largest oil recovery (39%) for a highly heterogeneous layered reservoir.",4,4,1
Porous Media,High Temperature,"Zhang, Yizhong; Zhang, Maolin; Mei, Haiyan; Zeng, Fanhua",Study on salt precipitation induced by formation brine flow and its effect on a high-salinity tight gas reservoir,Core flooding test; Salt precipitation; Formation brine flow; Core evaporation test; Microscopic visual flooding; Tight gas reservoir,CO2 INJECTION; NUMERICAL-SIMULATION; POROUS-MEDIA; EVAPORATION; SHALE,"For the tight gas reservoir with high salinity formation water, the flow of formation brine may cause salt precipitation and thus promote scale formation. Salt deposition and the accompanying scale formation as well as swelling and shrinkage of clay minerals may cause blockage of the pore and throats, which will significantly reduce permeability and the subsequent gas production rate. In this study, the influence of salt precipitation/dissolution on the physical properties of a tight gas reservoir is studied. Core analyses, core flooding tests, core evaporation tests, and microscopic visual flooding inspections are carried out on core samples extracted from the Shahejie Formation. To simulate the depletion production process in the subsurface, brine flow characteristics are studied by core flooding tests with pressure reduction at a formation temperature of 115 degrees C and with the change of pressure ranging from 30 to 1 MPa. The potential changes in physical properties including permeability, porosity, pore radius, pore size distribution, and surface area are analyzed by core evaporation tests. To show the brine flow and geometry of salt deposits in the pore structure, visual brine flooding is observed under high magnification microscope. Photos of the pore structure at different stages of salt precipitation are recorded. The results reveal that salt dissolution/precipitation has a significant impact on flow-through characteristics, and it can be divided into three stages during the depletion process. The damage of salt to the core permeability could reach more than 90%, and it increases gradually with the reduction of porosity and initial permeability and the increase of specific area. The maximum formation damage caused by salt precipitation is realized when the salt crystal size and pore throat diameter are close in size. The semi-empirical Carman-Kozeny equation together with porosity and grain diameter is used to estimate the permeability after precipitation.",4,4,5
Porous Media,High Temperature,"Zhang, Lei; Wu, Feipeng; Pu, Chunsheng",Mechanism of formation of chromium acetate(Cr3+)/ phenol-formaldehyde resin prepolymer(PRP) complex and its compound cross-linking reaction with polymer for conformance control,Oil production; Polymer gel; Conformance control; Chromium acetate; Phenol-formaldehyde,WATER SHUTOFF; NONIONIC POLYACRYLAMIDE; PROFILE CONTROL; POROUS-MEDIA; GEL SYSTEMS; RESERVOIR; CARBOXYLATES; GELATION,"For the heterogeneous oil reservoir with high water cut, the conformance control by using polymer gels is good for increasing oil production and decreasing excessive water. However, facing the current situation of low oil prices, how to improve the exploitation efficiency and reduce the production cost in the maximum extent are still drawing the attention of petroleum engineers. Therefore, it is necessary to further study the polymer gels to achieve this purpose. Among the polymer gels, the polymer/Cr3+ system and polymer/phenolic-formaldehyde compounds system are the most common used, which are suitable for the low temperature reservoir and high temperature reservoir, respectively. Based on the properties of each other, the combination of Cr3+ and phenolformaldehyde resin prepolymer (PRP) as a type of cross-linking agent can not only improve the thermal stability of polymer/Cr3+ gel, but also enable polymer/PRP gel to be applied to low-medium temperature reservoirs, which can further improve the application effect of polymer gels. However, the mechanism of compound crosslinking reaction of Cr3+ -PRP and polymer is still unclear. In this paper, the properties of Cr3+-PRP solution is first tested and then the process of crosslinking reaction of Cr3+-PRP and polymer is study. In the Cr3+-PRP solution, a new polynuclear olation complex ion of chromium (Cr3+-PRP complex) is formed, of which the properties is different from PRP solution or chromium acetate solution. The cross-linking reaction of Cr3+-PRP complex and polymer is compound. During the compound reaction at the temperature of 45 degrees C, the reaction of Cr3+ and polymer has an impact on that of PRP and polymer, so that the reaction of Cr3+-PRP complex and polymer is different from the superposition of the two reaction processes of Cr3+/polymer system and PRP/ polymer system. The formed Cr3+-PRP complex can resist salt to 70,000 mg/L. The experimental results can provide a theoretical guidance for the high efficient practical application of conformance control by using polymer/Cr3+ system or polymer/phenolic-formaldehyde compounds system.",5,5,4
Porous Media,Reaction,"Zampieri, M. F.; Quispe, C. C.; Moreno, R. B. Z. L.",Model upsizing for integrated evaluation of polymer degradation and polymer flooding lab data,Enhanced oil recovery; Polymer flooding; Simulation; Polymer degradation; Model upsizing,ENHANCED OIL-RECOVERY; SURFACTANT,"In oil recovery operations through polymer flooding, it is essential that the polymer maintains its stability until near the producer well, avoiding degradation phenomena. The present paper seeks to assess the representation of the degradation effects associated with polymer flooding for heavy oil recovery through one-dimension simulation models with different sizes. Base models were developed using data from the literature and previous lab work. The models consider adsorption, accessible pore volume, residual resistance factor, polymer concentration and non-Newtonian effects. Aiming at including degradation effects, a methodology of model size increase was developed, allowing to combine the evaluation of long-term dependent effects with displacement mechanisms. A sensitivity analysis was performed for the degradation, considering four levels of polymer half-life time. The lab-scale models were submitted to an upsizing procedure, generating models 100 times and 10.000 times bigger. The outcomes showed that the higher the level of the reaction frequency factor, the faster the degradation process. In the presence of original and degraded polymers in the porous media, we observed two advance fronts. The front of the degraded polymer advanced faster for a higher reaction frequency factor, while the advance front of the original polymer was delayed. We analyzed the results in terms of cumulative produced water, cumulative produced oil, average pressure, oil recovery factor, cumulative mass of the injected polymer, cumulative mass of the degraded polymer, water phase saturation, and water phase viscosity. The procedure for model upsizing was matched using a linear scaling factor. The method permits parameters found in laboratory experiments to be simulated in field-scale. Normalized results allowed comparing the impact of the main physical phenomena related to polymer flooding in the mentioned results, independent of the model size.",3,3,0
Porous Media,Reaction,"Soori, Tejaswi; White, Andrew R.; Ward, Thomas",Immiscible fluid displacement in a porous media: Effect of surfactants introduced ab initio versus surfactants formed in-situ,Enhanced oil recovery; Alkali flooding; Surfactant flooding; Porous media; Capillary flows; Immiscible flows,LIQUID-LIQUID DISPLACEMENT; INTERFACIAL REACTION; FILM THICKNESS; VISCOUS-FLUID; GAS-BUBBLES; OIL; ADSORPTION; DEPOSITION; TRANSPORT; DYNAMICS,"Experiments were performed to study the immiscible displacement of oil from a capillary tube using an aqueous phase fluid. One set of experiments were performed where surfactant was introduced into the aqueous phase liquid at concentrations below the critical micellar concentration prior to displacement, i.e. ab initio. In a second set of experiments surfactant was formed at the interface in-situ via a saponification chemical reaction. For both experiment conditions we measured surface tension using the pendant drop method to estimate adsorption and desorption Biot numbers for the ab initio case; whereas for surfactant produced via chemical reaction this data provided an estimate for rates of change in surface tension that were used to estimate a Damkohler number. The results suggest that surfactants created via saponification reaction tend to have an effect on the interface and film thickness that is entirely absent in non-reactive immiscible displacement experiments.",4,4,0
Porous Media,Reaction,"Kang, Kang; Abdelfatah, Elsayed; Pournik, Maysam",Nanoparticles transport in heterogeneous porous media using continuous time random walk approach,Continuous time random walk; Particle tracking; Nanoparticles; Heterogeneity; Simulation,DISPERSION; SCALE; TRANSITION; DIFFUSION,"Reservoir heterogeneities and reactive processes strongly affect the fluid flow in porous media. The mechanism of transport and reaction of the fluid varies from pore-to core-scales, leading to the discrepancies between theoretical predictions and experimental observations, which are caused by the anomalous diffusion. Also, the reactive processes in porous media may alter reservoir properties in different spatial and temporal scale, varying subsequent transport and reaction behaviors. In this article, the coupled transport and reaction process in heterogeneous porous media is studied. The Continuous Time Random Walk (CTRW) framework incorporating particle tracking (PT) method is proposed to simulate the transport and reaction processes at pore-scale and show macroscopic behavior at core-scale. Utilizing the CTRW-PT approach, the motion of solute particles is described as a combination of random independent spatial and temporal increments in each walk step. The particle transition distance and time are chosen from a joint space-time probability density function by a stochastic process. The modeling of reaction is followed by the modeling of transport and updates the change of porous media with its effect on following transport and reaction. Simulations of non-reactive tracer and reactive nanofluid flow under different heterogeneity, injection flow rate and rate of reaction were performed. By adjusting the ensemble parameter beta and t(2) the effects of the above factors on flow behavior are accounted. The concentration profiles with time are displayed to show the effect of heterogeneity, flow rate and rate of reaction on anomalous behavior. Higher level of heterogeneity, higher flow rate and rate of reaction are captured by smaller beta and larger t(2) quantitatively, representing more anomalous flow behavior. The breakthrough curves from CTRW-PT simulation well match the experimental as well as Advection-Diffusion-Reaction Equation (ADRE) modeling results in most cases. The CTRW results also better match the experimental results than the ADRE as the anomalous behavior becomes significant. It is also found that CTRW-PT simulation as a statistical approach is more computationally efficient than solving the ADRE.",5,5,2
Porous Media,Reaction,"Zhang, Lei; Wu, Feipeng; Pu, Chunsheng",Mechanism of formation of chromium acetate(Cr3+)/ phenol-formaldehyde resin prepolymer(PRP) complex and its compound cross-linking reaction with polymer for conformance control,Oil production; Polymer gel; Conformance control; Chromium acetate; Phenol-formaldehyde,WATER SHUTOFF; NONIONIC POLYACRYLAMIDE; PROFILE CONTROL; POROUS-MEDIA; GEL SYSTEMS; RESERVOIR; CARBOXYLATES; GELATION,"For the heterogeneous oil reservoir with high water cut, the conformance control by using polymer gels is good for increasing oil production and decreasing excessive water. However, facing the current situation of low oil prices, how to improve the exploitation efficiency and reduce the production cost in the maximum extent are still drawing the attention of petroleum engineers. Therefore, it is necessary to further study the polymer gels to achieve this purpose. Among the polymer gels, the polymer/Cr3+ system and polymer/phenolic-formaldehyde compounds system are the most common used, which are suitable for the low temperature reservoir and high temperature reservoir, respectively. Based on the properties of each other, the combination of Cr3+ and phenolformaldehyde resin prepolymer (PRP) as a type of cross-linking agent can not only improve the thermal stability of polymer/Cr3+ gel, but also enable polymer/PRP gel to be applied to low-medium temperature reservoirs, which can further improve the application effect of polymer gels. However, the mechanism of compound crosslinking reaction of Cr3+ -PRP and polymer is still unclear. In this paper, the properties of Cr3+-PRP solution is first tested and then the process of crosslinking reaction of Cr3+-PRP and polymer is study. In the Cr3+-PRP solution, a new polynuclear olation complex ion of chromium (Cr3+-PRP complex) is formed, of which the properties is different from PRP solution or chromium acetate solution. The cross-linking reaction of Cr3+-PRP complex and polymer is compound. During the compound reaction at the temperature of 45 degrees C, the reaction of Cr3+ and polymer has an impact on that of PRP and polymer, so that the reaction of Cr3+-PRP complex and polymer is different from the superposition of the two reaction processes of Cr3+/polymer system and PRP/ polymer system. The formed Cr3+-PRP complex can resist salt to 70,000 mg/L. The experimental results can provide a theoretical guidance for the high efficient practical application of conformance control by using polymer/Cr3+ system or polymer/phenolic-formaldehyde compounds system.",5,5,4
Porous Media,Transfer,"Nekoeian, Sahand; Aghajani, Masoud; Alavi, Seyed Mehdi",Experimental study of the surfactants effects on gas phase mass transfer coefficients in gas condensate reservoirs,Gas condensate reservoirs; Local equilibrium assumption; Gas phase mass transfer coefficients; Surfactants; Specific interfacial area; Spreading coefficients,ORGANIC-CHEMICALS; POROUS-MEDIA; WETTABILITY ALTERATION; LIQUID VOLATILIZATION; THERMAL-DIFFUSIVITY; DISSOLUTION; RECOVERY; OIL; CONDUCTIVITY; TRANSPORT,"Surfactant flooding in gas-condensate reservoirs, shown to be an effective treatment method to remediate condensate blockage in near well bore regions, have been the focus of several studies in the recent decades. However, the effect of these chemicals on the gas phase mass transfer coefficients has not been yet addressed though they have to be incorporated in non-equilibrium compositional simulators to imitate the reservoir behavior reliably. Besides, any knowledge of the overall effect of the surfactants on these coefficients can shed light on the side effects of the surfactant flooding on mass transfer phenomenon and evaluate its suitability as a treatment strategy. In this study, separate empirical correlations were developed for methane and isobutane representing light and intermediate components respectively in the absence and the presence of surfactants at the temperature of 40 degrees C. In all the developed correlations for both components in the presence of surfactants, while spreading coefficient has a positive exponent, equilibrium adsorption constant possesses a negative exponent. This implies that surfactants with a larger former parameter and a smaller latter parameter like SDS have more opportunity to enhance the volumetric mass transfer coefficient. The results also confirm the positive effect of pore gas velocity on gas phase mass transfer coefficients even in low gas flow rates. Similarly, this effect has already been reported in NAPL (Non Aqueous Phase Liquid) volatilization related studies. Effective diffusion coefficient, condensate saturation, mean grain size, component type, surfactant type and residual water saturation were also shown to affect these mass transfer coefficients. In addition, it has been shown that surfactants which are conventionally believed to reduce volumetric mass transfer coefficients in gas-liquid systems like bubble columns, improve gas phase mass transfer coefficients in gas condensate reservoirs. This improvement is considered a drawback for the cited technique.",0,0,1
Porous Media,Transfer,"Nekoeian, Sahand; Aghajani, Masoud; Alavi, Seyed Mehdi",Experimental study of gas phase mass transfer coefficients in gas condensate reservoirs,Gas condensate reservoirs; Compositional simulators; Local equilibrium assumption; Mass transfer coefficients; Specific interfacial area; Effective diffusion coefficients,ORGANIC-CHEMICALS; LIQUID VOLATILIZATION; POROUS-MEDIA; DISSOLUTION; DIFFUSION; TRANSPORT,"Gas condensate reservoirs as a proportion of worldwide gas reservoirs experiencing retrograde condensation throughout their production period have been consistently attracting research interests in recent decades. However, their compositional simulators usually consider local equilibrium assumption and neglect the non-equilibrium effect represented by gas phase mass transfer coefficients. Since no independent research has yet targeted mass transfer coefficients in gas condensate reservoirs, in this study, a series of flow tests were carried out using a novel experimental setup to address the issue. Correspondingly, separate empirical correlations were developed for methane and isobutane representing light and intermediate components respectively at two temperatures, thus two condensate saturation ranges. The results confirm the positive effect of pore gas velocity on gas phase mass transfer coefficients reported in NAPL volatilization related studies even in low gas flow rates. Also temperature, effective diffusion coefficient, condensate saturation, mean grain size and component types were shown to affect these coefficients.",0,0,1
Porous Media,Transfer,"Cheng, Gang; Pang, Zhanxi; Jiang, Yanming; Wang, Bo; Yu, Xiaogang",Thermodynamic analysis and prediction of reservoir temperature distribution for steam stimulation,Steam stimulation; Temperature distribution; Heat conduction; Heat convection; Energy balance equation,ASSISTED-GRAVITY-DRAINAGE; HEAT-TRANSFER; OIL-RECOVERY; POROUS-MEDIA; THERMAL RECOVERY; DISPLACEMENT; INJECTION; FLOW,"During steam stimulation of horizontal wells in heavy oil reservoir, it is necessary to estimate the reservoir temperature distribution, which has a huge impact on oil production and ultimate oil recovery. Most of previous models were derived based on infinite boundary condition and constant fluid velocity, which were not consistent with real situation of reservoir. In this paper, new energy balance equations combined with mobile boundary conditions were developed for increasing the accuracy of predicted results. Based on dimensionless conversion and numerical analysis, the optimum solution of equation system could be easily obtained, and its good performance in predicting temperature distribution was also validated. Moreover, thermodynamic mechanism of hot fluid, latent heat and sensible heat of steam, and their contributions to heating reservoir were also discussed to investigate the heat transfer pattern in reservoir. Finally, factors that could influence the reservoir temperature distribution were analyzed. It is found that: (a) both the heat conduction and the heat convection contribute to the heat transfer in hot liquid zone, and the heat convection predominates; (b) both the condensation front and heat front move outward with the injection of steam, but their expanding rates gradually drop with time; (c) as the radius increases, the radial fluid velocity will go down, leading the heat convection effect to be weakened and the heat conduction effect to become obvious; (d) there are some factors that can influence the reservoir temperature distribution including steam injection duration, fluid velocity, volumetric heat capacity of fluid, steam quality and thermal conductivity of reservoir.",2,2,2
Porous Media,Transfer,"Kanimozhi, B.; Thamizhmani, Vivek; Pranesh, Venkat; Senthil, S.; Selvakumar, Arun T.",Kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection,Carbonate reservoir; Fines migration; Water saturation; Heat transfer; Permeability decline; Pressure change,OIL-RECOVERY; RESERVOIR ROCKS; OIL/BRINE/CARBONATE SYSTEM; SLOW MIGRATION; WETTABILITY; FILTRATION; SURFACE; FIELD; PH,"Kaolinite clay fines are prevalent in sandstone porous media and it has great impacts on permeability and well productivity decline. High temperature sandstone formations detach the fines from the pore surface and migrate along with the permeating fluid. At some point the fine particles are strained in the pore throats, which leading to permeability damage and well productivity decline. To the best of our knowledge this phenomenon is not well explored in the high temperature carbonate media. Since most of the world's oil reserves are held in carbonate media and its worth to explore the formation damage, especially due to fines migration during higher reservoir temperature at these formations composed of carbonate minerals. Hence, this paper presents laboratory modeling of kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection. In this paper, we have conducted three sets of coreflood experiments in the temperature ranges of 100 degrees C 150 degrees C, and 200 degrees C. Kaolinite suspension water has been injected into the porous limestone core at these temperature regimes to investigate the possibility of permeability and injectivity deterioration. The main experimental results showed there is an increase in water saturation and heat transfer rates. Concentration of fines surges with increasing PVI and permeability declines with increasing time. Pressure elevates with enhancing PVI, but it plummets after some time. Significantly, the water discharge rate declines for increasing suspension injection and on the other side, for fresh water injection, the rate of water discharge rises steadily. Furthermore, the electrical and thermal conductivities of effluent kaolinite colloid were higher. Moreover, experimental model were tested against statistical based optimizational model, response surface methodology (RSM). These results revealed good agreement and, hence, this paper has explicated the importance of kaolinite clay fines suspension transport in high temperature carbonate reservoirs.",3,3,0
Porous Media,Temperature Distribution,"Cheng, Gang; Pang, Zhanxi; Jiang, Yanming; Wang, Bo; Yu, Xiaogang",Thermodynamic analysis and prediction of reservoir temperature distribution for steam stimulation,Steam stimulation; Temperature distribution; Heat conduction; Heat convection; Energy balance equation,ASSISTED-GRAVITY-DRAINAGE; HEAT-TRANSFER; OIL-RECOVERY; POROUS-MEDIA; THERMAL RECOVERY; DISPLACEMENT; INJECTION; FLOW,"During steam stimulation of horizontal wells in heavy oil reservoir, it is necessary to estimate the reservoir temperature distribution, which has a huge impact on oil production and ultimate oil recovery. Most of previous models were derived based on infinite boundary condition and constant fluid velocity, which were not consistent with real situation of reservoir. In this paper, new energy balance equations combined with mobile boundary conditions were developed for increasing the accuracy of predicted results. Based on dimensionless conversion and numerical analysis, the optimum solution of equation system could be easily obtained, and its good performance in predicting temperature distribution was also validated. Moreover, thermodynamic mechanism of hot fluid, latent heat and sensible heat of steam, and their contributions to heating reservoir were also discussed to investigate the heat transfer pattern in reservoir. Finally, factors that could influence the reservoir temperature distribution were analyzed. It is found that: (a) both the heat conduction and the heat convection contribute to the heat transfer in hot liquid zone, and the heat convection predominates; (b) both the condensation front and heat front move outward with the injection of steam, but their expanding rates gradually drop with time; (c) as the radius increases, the radial fluid velocity will go down, leading the heat convection effect to be weakened and the heat conduction effect to become obvious; (d) there are some factors that can influence the reservoir temperature distribution including steam injection duration, fluid velocity, volumetric heat capacity of fluid, steam quality and thermal conductivity of reservoir.",2,2,2
Porous Media,Temperature Distribution,"Hong, Eunji; Jeong, Moon Sik; Lee, Kun Sang",Optimization of nonisothermal selective plugging with a thermally active biopolymer,Microbial enhanced oil recovery (MEOR); High-temperature reservoir; Selective plugging; Nonisothermal biokinetics; Leuconostoc mesenteroides,ENHANCED OIL-RECOVERY; LEUCONOSTOC-MESENTEROIDES; BIOSURFACTANT PRODUCTION; KINETICS; TEMPERATURE; MODEL; DEXTRANSUCRASE; RESERVOIRS; METABOLISM; TRANSPORT,"A novel concept of microbial enhanced oil recovery (MEOR) under nonisothermal conditions was developed based on temperature-dependent biokinetics. The model specified the use of temperature-triggered Dextran (a biopolymer) produced by Leuconostoc mesenteroides (a microbe). The effects of environmental temperature on microbial growth and biopolymer production were validated and calibrated using the cardinal temperature model and experimental results. Various biokinetic parameters and a permeability reduction factor were also obtained to within approximately 2% error of those previously reported sandpack experiment. Based on the developed nonisothermal biokinetic model and the permeability reduction factor, thermally active MEOR was analyzed for a high-temperature reservoir. The results suggested the influences of injection parameters, such as injected nutrient concentration, rate, and temperature, on oil recovery factor. Higher nutrient concentrations resulted in increased Dextran production, thereby increasing oil recovery by selective plugging. On the other hand, injection rate and temperature were related to Dextran distributions. Higher injection rates led to lower Dextran concentrations with wider distributions. The injection temperature controlled the location of trapped Dextran in porous media, thereby influencing oil recovery. Through the optimization process, the injection design was determined with a rate of 30 m(3).day(-1), temperature of 5 degrees C, and nutrient mole fraction of 0.009. The suggested optimal injection design resulted in the largest oil recovery (39%) for a highly heterogeneous layered reservoir.",4,4,1
Porous Media,Temperature Distribution,"Zhang, Yizhong; Zhang, Maolin; Mei, Haiyan; Zeng, Fanhua",Study on salt precipitation induced by formation brine flow and its effect on a high-salinity tight gas reservoir,Core flooding test; Salt precipitation; Formation brine flow; Core evaporation test; Microscopic visual flooding; Tight gas reservoir,CO2 INJECTION; NUMERICAL-SIMULATION; POROUS-MEDIA; EVAPORATION; SHALE,"For the tight gas reservoir with high salinity formation water, the flow of formation brine may cause salt precipitation and thus promote scale formation. Salt deposition and the accompanying scale formation as well as swelling and shrinkage of clay minerals may cause blockage of the pore and throats, which will significantly reduce permeability and the subsequent gas production rate. In this study, the influence of salt precipitation/dissolution on the physical properties of a tight gas reservoir is studied. Core analyses, core flooding tests, core evaporation tests, and microscopic visual flooding inspections are carried out on core samples extracted from the Shahejie Formation. To simulate the depletion production process in the subsurface, brine flow characteristics are studied by core flooding tests with pressure reduction at a formation temperature of 115 degrees C and with the change of pressure ranging from 30 to 1 MPa. The potential changes in physical properties including permeability, porosity, pore radius, pore size distribution, and surface area are analyzed by core evaporation tests. To show the brine flow and geometry of salt deposits in the pore structure, visual brine flooding is observed under high magnification microscope. Photos of the pore structure at different stages of salt precipitation are recorded. The results reveal that salt dissolution/precipitation has a significant impact on flow-through characteristics, and it can be divided into three stages during the depletion process. The damage of salt to the core permeability could reach more than 90%, and it increases gradually with the reduction of porosity and initial permeability and the increase of specific area. The maximum formation damage caused by salt precipitation is realized when the salt crystal size and pore throat diameter are close in size. The semi-empirical Carman-Kozeny equation together with porosity and grain diameter is used to estimate the permeability after precipitation.",4,4,5
Porous Media,Foam Flow,"Du, Dongxing; Zhang, Dan; Li, Yingge; Dong, Xu; Sun, Zhifeng; Chao, Kun",Numerical investigations on the inlet and outlet behavior of foam flow process in porous media using stochastic bubble population balance model,Inlet behavior; Outlet behavior; Foam flow; Porous media; Stochastic bubble population balance model; Foam relative permeability reduction factor,CO2 STORAGE; OIL; SIMULATION; CO2-EOR; MOTION; TRANSIENT; VISCOSITY,"Numerical investigations were carried out with special attentions on the inlet and outlet behaviors of foam flow process in a homogeneous porous media with confined entrance and exit boundaries. The Stochastic Bubble Population (SBP) balance model, which usually involves two parameters of the bubble generation rate K-g and the maximum bubble density n(infinity) for bubble number prediction, was employed to study the dynamic foam generation and development process in porous media. With introduction the K-fp parameter to take into account the foam phase relative permeability reduction effect, the control equations of the two-phase flow process in a two-dimensional computational domain were solved with the IMPES algorithm and the inlet and outlet behavior of the foam displacement process were scrutinized based on detailed analysis of the bubble density, water phase pressure and water phase saturation distributions in porous medium. Numerical results showed a clear entrance effect of higher water saturation, lower pressure gradient and developing bubble density in the inlet region of the porous media in the transient foam displacement process, whereas the confined exit results in elevating water saturation and decreasing pressure gradient towards the outlet of the core. Parametric studies on K-g, n(infinity), K-fp and inlet & outlet sizes D indicate higher bubble generation rate could remarkably suppress the entrance region in the foam seepage process, while the higher maximum bubble number did not lead to obvious change of the foam flow behavior in the inlet and outlet region, although it could produce higher absolute values of bubble density and pressure drop along the core. With lower K-fp values, the strong foam flooding behavior could be properly predicted with much higher pressure drop and lower water saturation. Two dimensional numerical results at various inlet and outlet sizes clearly show the confined geometry effect on foam flow characteristics with smaller sizes corresponding to longer inlet and outlet regions. Computational domain and numerical results were validated through comparisons with corresponding experimental setup and CT measurement results. It is observed that, the numerical simulation could reproduce not only qualitatively but also quantitatively the experimentally obtained water saturation distribution and pressure drop result. It is concluded that the mechanistic stochastic bubble population model could be reasonably employed on prediction of the inlet and outlet behavior in the transient foam flow process in the homogeneous porous media.",1,1,2
Porous Media,Foam Flow,"AlQuaimi, B., I; Rossen, W. R.",Characterizing foam flow in fractures for enhanced oil recovery,,,"Gas is used in displacing oil for enhanced oil recovery because of its high microscopic-displacement efficiency. However, the process at the reservoir scale suffers from poor sweep efficiency due to density and viscosity differences compared to in-situ fluids. Foam substantially increases the viscosity of injected gas and hence improves the sweep. Foam rheology in 3D geological porous media has been characterized both theoretically and experimentally. In contrast, the knowledge of foam flow in fractured porous media is far less complete. A companion paper (AlQuaimi and Rossen, 2017c), We focused on foam generation and propagation in a fully characterized model fracture. Here we focus on foam rheology in the same model fracture. This investigation is conducted by varying superficial velocities of gas and surfactant solution. We find in this model fracture the same two foam-flow regimes central to the understanding of foam in 3D porous media: a low-quality regime where pressure gradient is independent of liquid velocity and a high-quality regime where pressure gradient is independent of gas velocity. The transition between regimes is less abrupt than in 3D porous media. Our study directly relates flow regime to foam texture through observation of bubble size, bubble trapping and mobilization, and foam stability as functions of superficial velocities which allows comparison with our understanding of the mechanisms behind the two flow regimes in 3D porous media. Additionally, foam is shear-thinning in both regimes. However, the mechanisms thought to be behind the two flow regimes in 3D porous media do not appear in our model fracture. Foam is not at the limit of stability in the high-quality regime. Mobility in the high-quality regime, instead, reflects reduced and fluctuating foam generation at high foam quality. Moreover, bubble size is not fixed at approximately pore size, the mechanism thought to control the low-quality regime in 3D porous media. Instead, bubbles are much smaller than pores. Finally, for this model fracture, the investigation of vertical flow reaches the same findings as for horizontal flow, with somewhat lower pressure gradient.",5,6,1
Horizontal Wells,Drilling,"Li, Xin; Gao, Deli; Lu, Baoping; Zeng, Yijin; Ding, Shidong; Zhou, Shiming",A prediction model of the shortest drilling time for horizontal section in extended-reach well,Shortest drilling time; Extension ability; Horizontal section; Maximum ROP; Drilling safety; Economic benefits,LIMIT,"Drilling the horizontal extended-reach well (ERW) with the shortest time is of great significance for drilling safety, efficiency and economic benefits. Moreover, the reservoir damage can be reduced or eliminated only when the well's horizontal section is drilled fast enough. In this paper, considering the effects of horizontal well's extension ability on the rate of penetration (ROP) and tripping in/out velocity, a prediction model of the shortest drilling time for horizontal section in ERW is established. The horizontal ERW Z-42 is analyzed, predicting its shortest drilling time in horizontal section. Results show that the predicted shortest drilling time is mainly dependent on its maximum ROP and maximum tripping in/out velocity in horizontal section. Specifically, the maximum ROP must satisfy four constraints, and the predicted maximum tripping in/out velocity must meet three constraints. Moreover, the predicted shortest time of drilling process in horizontal section is very close to the actual time in Z-42 well. In addition, the actual ROP and tripping in/out velocity in horizontal section should be as close as possible but strictly less than the predicted maximum ROP and maximum tripping in/out velocity to avoid drilling hazards. The shortest drilling time is not fixed and can be predicted in real time. Furthermore, in order to reduce the drilling time, it is necessary to reduce the times of tripping as much as possible to shorten the total drilling time of horizontal section. The model provides a practical tool to predict the shortest drilling time for horizontal section in ERW.",0,0,8
Horizontal Wells,Drilling,"Eren, Tuna; Polat, Can",Well efficiency assessment in geothermal fields for horizontal drilling,Geothermal field; Horizontal wells; Cost analysis; Well efficiency; Thermal energy; Drilling engineering; Reservoir engineering,HYDRATE,"A research study is conducted to evaluate the well efficiency assessment of horizontal wells in geothermal fields. The study is comprised of developing the field by means of drilling 15 wells, and conducting reservoir simulation. Drilling planning of vertical and horizontal wells are studied together with their respective time and cost estimates. The time estimate of horizontal geothermal wells is benchmarked to previously drilled vertical and horizontal oil wells, since the data belonging to horizontal wells was not available for study. The findings indicate that the horizontal drilling scenario would take only 7 months more than the vertical drilling scenario. Monetary wise; horizontal wells for a geothermal field is estimated to be drilled 41% more in cost. A hypothetical geothermal field model is generated for the simulations, using TOUGH2. The simulations of four scenario sensitivity analyses reveal that drilling of horizontal wells provide efficient energy extraction out of a geothermal field, in comparison having the wells drilled vertically. The approach provides powerful comparison without having made any investment in the hypothetically simulated geothermal field. The study is a novel in kind since in country such as Turkey there is no horizontal well drilled within the geothermal fields. The analysis of the results indicate that energy production from the horizontal wells are greater than the energy production of vertical wells, definitely paying off the additional investment costs for horizontal drilling and completion.",1,1,8
Horizontal Wells,Drilling,"Wang, Dongying; Wang, Zhiming; Zeng, Quanshu",An experimental study on gas/liquid/solid three-phase flow in horizontal coalbed methane production wells,Gas/liquid/solid three-phase flow; Coalbed methane; Horizontal well; Flow pattern; Height of coal particle bed; Explicit equation,SAND-DEPOSITION VELOCITY; RESERVOIR ROCKS; LIQUID; GAS; PARTICLES; TRANSPORT,"Coal particles caused by well drilling and completion, hydraulic fracturing, and formation pressure decreasing would migrate into the horizontal well carried by fracturing flow-back fluid, formation water and CBM, and then deposit on the low side of pipe leading to the decrease of cross section area of pipe for flow and even blocking of the pipe. The purpose of current research was to obtain the flow pattern while there was stationary solid particle bed on the low side of the pipe and an explicit equation to predict the height of solid particle bed was proposed. In this study, with the coal particle, water, and air as the solid, liquid, and gas phases respectively, gas/liquid/ solid three-phase flow experiments in horizontal well were carried out and 4 crucial factors including different water flow rate, gas flow rate, coal particle size, and coal particle mass concentration were considered. Fluid's real apparent velocity was defined and used to analyze the distribution of flow pattern coordinate points. Results show that the flow pattern coordinate points determined by real gas apparent velocity and real water apparent velocity distribute near the flow pattern transition lines of Taitel and Dukler flow pattern map. Besides, coal particle size, water flow rate, and gas flow rate have obvious impact on the height of coal particle bed and the coal particle mass concentration has a negligible effect while the height of interface between gas layer and water layer is only dramatically affected by the gas flow rate. At last, an explicit equation for predicting the cross section area of coal particle bed based on the experimental data was proposed which is crucial to predict the flow pattern and calculate the pressure drop in horizontal well. The predicting cross section area of coal particle bed is in good agreement with the measured cross section area of coal particle bed and the average relative differences are 9.38% and 13.45% for stratified smooth flow and stratified wavy flow respectively. The equation is applicable for a range of coal particle size (8-30 mesh) and water apparent velocity (0.025-0.123 m/s).",2,2,4
Horizontal Wells,Drilling,"Li, Xin; Gao, Deli; Lu, Baoping; Zeng, Yijin; Zhang, Jincheng",Study on modified maximum extension length prediction model for horizontal wells considering differential sticking,Horizontal well; Maximum extension length; Differential sticking; Drilling fluid density; Casing running down/pulling out speed,EXTENDED-REACH LIMIT,"Maximum extension length prediction model for horizontal wells can be used to evaluate the horizontal well's extension capability and predict its maximum measured depth, which is of great significance to the production and economic benefits of horizontal wells. However, the differential sticking is not considered in previous prediction model. To overcome this shortcoming, a modified model considering differential sticking is established based on constraints of wellbore stability, differential pressure, and filtration loss simultaneously during the drilling, tripping processes and static state. Then a horizontal well is analyzed and its maximum extension length is predicted. Results show that within the conventional mud weight window, three ranges of drilling fluid density can be determined, including the first range, the second range and the reasonable range of drilling fluid density. However, only the reasonable range of drilling fluid density can satisfy all constraints of the modified prediction model, including the wellbore stability, differential pressure, and filtration loss simultaneously. Compared with the original model, the predicted well's maximum extension length decreases when the differential sticking is considered. However, it is more accurate, avoiding drilling hazards in actual drilling operation due to the excessive designed measured depth and unreasonable drilling parameters. Moreover, the maximum speeds of casing running down/pulling out are also determined and added to the modified model. Therefore, the modified model with reasonable drilling fluid density and adjusted running down/pulling out speed is the optimal modified model to predict maximum extension length and avoid differential sticking, which can also ensure that the horizontal well's designed measured depth can be successfully achieved. This study is of great significance to improve the prediction accuracy of horizontal well's maximum extension length and avoid drilling hazards, especially the differential sticking. Moreover, it also plays a guiding role in the selection of reasonable drilling fluid density during horizontal drilling.",3,4,3
Horizontal Wells,Drilling,"Han, Yiwei; Ai, Zhijiu; Kuang, Yuchun; Liu, Jianxun; Yang, Wenwu",Nonlinear dynamic modeling of drill string in horizontal well - A geometrically exact approach,Horizontal drill string; Nonlinear dynamics; Geometrically exact model; Quadrature element method,FINITE-ELEMENT FORMULATION; 3-DIMENSIONAL BEAM THEORIES; SPATIAL BEAMS; DRILLSTRINGS; SPACE; PIPE; ROD,"A new nonlinear dynamic model of drill string in horizontal well is established based on geometrically exact beam theory and quadrature element method. The model proposed in this paper takes into account the geometric nonlinearity of the drill string and the nonlinear contact between the drill string and the borehole. Benefiting from the accuracy of the geometric description of the geometrically exact beam, the model uses a geometrically exact method to describe the contact between the drill string and the borehole. Comparison with experimental results shows that the geometrically exact model can accurately describe the nonlinear characteristics of the drill string. Finally, the characteristics of the movement of drill string under different drilling pressure and rotation speed are analyzed. Drilling pressure and rotational speed have an effect on the buckling of the drill string. Before buckling, the drill string moves periodically at the bottom of the wellbore. After buckling, the movement of the drill string becomes disordered. The model presented in this paper provides a new method for dynamic analysis of drill string.",3,3,10
Horizontal Wells,Drilling,"Wang, Xueying; Ni, Hongjian; Wang, Ruihe",Experimental study on toolface disorientation and correction during slide drilling,Slide drilling; Stick-slip motion; Toolface disorientation; Toolface hysteresis; Toolface correction,FACE-CONTROL; TORQUE,"Toolface control is an important issue when drilling directional wells with steerable motors. In this paper, a new experimental apparatus has been built to study the toolface behavior while slide drilling. In experiments, weight on bit and toolface orientation during the simulated slide drilling are recorded and analyzed. Experimental results indicate that axial slick-slip motion of the drillstring that occurs in the presence of large friction causes toolface disorientation. In addition, the phenomenon of toolface hysteresis in horizontal wells is identified. The asymmetric loading and unloading rates of weight on bit result in toolface hysteresis, and toolface hysteresis worsens toolface disorientation. A new method of correcting toolface by quickly eliminating toolface hysteresis is proposed. Four torque-related parameters are used in the method, and each has a specific implication. The proposed method has been examined using the experimental apparatus and has been proven to work. The experimental results and related analysis in this paper can help to further improve the efficiency of toolface control during slide drilling.",4,4,1
Horizontal Wells,Drilling,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Horizontal Wells,Drilling,"Li, Xin; Gao, Deli",Study on mud weight window prediction model and safety additional value of horizontal well in shales considering effects of Well's extended-reach limit,Mud weight window; Safety additional value; Horizontal well; Extended-reach limit; Shale gas field,STABILITY,"Safety additional value is always added to the conventional mud weight window (MWW) to ensure the drilling safety in shales. However, the safety additional value is usually an empirical value. Since the horizontal well usually has a long horizontal section in shales, failing to accurately predict the wells MWW and corresponding safety additional value in shales may result in serious drilling hazards. In order to ensure that the horizontal well can reach the designed horizontal-section length in shales, the conventional MWW needs to be modified and the calculated value of safety additional value should also be given. In this paper, considering the effects of horizontal wells extended-reach limit and its horizontal-section limit (HSL) on the wells MWW in shales, the drilling process, tripping process and six constraint conditions are considered simultaneously. Results of the case study indicate that the corresponding safety additional value is calculated instead of using an empirical value. Moreover, the predicted MWW becomes narrower as the designed horizontal-section length is increased. In addition, in order to obtain a wider MWW, tripping velocity should be lower if the economic benefits can be satisfied. Additionally, the drilling pump with higher rated pressure is also necessary. Taking the maximum HSL as the objective function, there exists an optimal drilling fluid density, which is crucial for production in shales. The calculated value of safety additional value and the modified MWW can ensure the horizontal well reach the designed horizontal-section length, obtaining enough production and economic benefits as well as avoiding drilling hazards in shales.",5,6,1
Horizontal Wells,Drilling,"Albattat, Rami; Hoteit, Hussein",Modeling yield-power-law drilling fluid loss in fractured formation,Lost-circulation; Loss of drilling fluid; Mud loss; Flow in fractured formation; Yield power law; Herschel-Buckley; Cauchy momentum equation; Fracture ballooning,MATERIAL SELECTION GUIDELINES; PERFORMANCE; FLOW,"Loss of circulation during drilling is a pressing problem that typically occurs when significant volumes of the drilling fluid leak to the surrounding formation. In fractured media, circulation loss is often a sudden event which may interrupt the drilling operations, increase nonproductive time, and add complexity in controlling the fluid flow and wellbore stability. Developing models to predict the fluid leak dynamics and identify the suitable loss-control-material (LCM) is of significant interest to the industry. In this work, simulation and analytical models are developed to model the dynamics of fluid loss for power-law drilling fluids from the wellbore to a surrounding fractured medium. The model is based on the Cauchy momentum equation and accounts for the key predominant flow mechanisms, including the non-Newtonian behavior of the drilling fluid (mud) using a power-law model. Experiments from the literature are used to assess the behavior of mud loss into a single horizontal fracture, which includes the effects of mud rheology and yield stress. We show that previous unsuccessful attempts to match the experimental data using analytical models are related to the assumption of uniform fracture aperture. Simulations are then used to demonstrate that a slight deformation in the fracture walls leads to a significant deviation in the analytical model predictions, and therefore the dynamics of fracture opening is a critical parameter that should be carefully assessed. In other related experiments, the analytical model also failed to capture the mud invasion distance within the fracture as a function of pressure drop and the mud properties. To address this issue, a modified analytical model that accounts for non-parallel fracture walls is proposed. The new model allows to quickly assessing the impact of nonuniform fracture apertures. It can serve as a screening tool to evaluate mud invasion distance as a function of fracture geometry, mud rheological properties, and pressure drop resulting from the well depth, injection rate, and mud density.",5,5,3
Horizontal Wells,Method,"Li, Yaohua; Song, Yan; Jiang, Shu; Jiang, Zhenxue; Yang, Wei; Wang, Qianyou; Liu, Dan",Tight reservoir oiliness numerical simulation based on a Markov chain Monte Carlo (MCMC) method: A case study of the upper Triassic Yanchang-6 formation (T(3)ch(6) Fm.) outcrop of Ordos Basin,Reservoir oiliness; Fractures; Lithofacies; Bayesian; MCMC,FRACTURED HORIZONTAL WELL; UNCERTAINTY QUANTIFICATION; WESTERN INTERIOR; ORGANIC-MATTER; STRATIGRAPHY; PRESSURE; MODEL; BAYES; FLOW,"Numerical simulation of the tight reservoir oiliness has always been an important issue in tight oil resources exploration. It is hard to take some special situations into simulations such as the micro-nano thermodynamic system, the multi-fluid phase behavior, and the superimposed tectonic stress field of tight oil reservoirs. In our research, we use MCMC methods to simulate the tight reservoir oiliness constrained by some visualized, spatial-related and interacted geological parameters based on the statistic Bayesian theory, instead of taking the complicated accumulation mechanism into consideration. In this research, we built a posterior probability density distribution (Post-PDD) matrix using the spatial relation between oiliness, fracture, and lithofacies parameters of a typical Yanchang tight oils outcrop. In the simulation, one Monte Carlo Step (MCS) was settled N = 80 x 36 x 5000, where 80 and 36 represent the horizontal and longitude grid number respectively, and 5000 represents the sampling times for each grid. In total, simulations of 50000 MCSs were made for each realization. For the simulation results, the variation in the fluctuating trends of the fitted and actual values matched well with the analytic variogram for the MCMC realizations. Additionally, we found that the simulation uncertainty was consistent with the reservoir heterogeneity. Even though the lamina, intercalation or the barrier was not defined in the grid model, the oiliness realization of the different types was remarkably consistent with the reservoir heterogeneity, which may be caused by the sedimentary rhythm similitude between different scale sedimentary cycles, particularly in the lacustrine tight reservoir.",1,1,1
Horizontal Wells,Method,"Hemmingsen, Casper Schytte; Glimberg, Stefan Lemvig; Quadrio, Nathan; Volcker, Carsten; Nielsen, Kenny Krogh; Walther, Jens Honore; Byrne, Michael; Engsig-Karup, Allan P.",Multiphase coupling of a reservoir simulator and computational fluid dynamics for accurate near-well flow,Multiphase flow; Porous media; CFD; Near-wellbore; Reservoir simulation,TRANSPORT,"Near-well flow analysis is an important tool for gaining detailed insight of the flow behaviour and for improving well design and production optimization of real reservoirs. One challenge of accurate numerical modelling of the flow field in the vicinity of the well is related to the scale disparity factor in space and time. The numerical scale gap between the reservoir and the wellbore justifies the representation of a well as a point or line sink/source term in traditional reservoir models. However, standard numerical techniques for reservoir simulation are incapable of resolving the near-singular character of the pressure field in the vicinity of the well. Under the assumption that all length scales have impact on flow patterns, we present a proof-of-concept study aimed at improving the quality of the numerical simulation by considering the geometry and fluid flow near the wellbore in a fully connected system, thus accounting for the fine scale phenomena by means of a hybrid Navier-Stokes/Darcy wellbore model coupled with a full scale reservoir model. A weak coupling method based on fixed-point iterations, that preserves the mass flux transport across the coupled interface, while adjusting productivity indices, is demonstrated via numerical experiments. Several different numerical experiments are performed to demonstrate the versatility and the improved well performance insight that the coupled method offers, including horizontal well inflow profile, influence of formation damage and optimal well configuration.",1,2,1
Horizontal Wells,Method,"Jin, Licong; Tao, Lei; Li, Decai",Injection fall-off analysis and interpretation of horizontal wells in polymer flooding,Fall-off test; Type curve; Polymer flooding; Horizontal well; EOR,PRESSURE DERIVATIVE ANALYSIS,"Petrocedeno is located in the southeast of Venezuela, which is an onshore heavy oil field with average viscosity about 5000 cP. In order to increase the oil recovery, polymer injection is planning in the pilot. The fall-off test, one approach to analyse the polymer properties in reservoirs directly, is also planned after polymer injection. In order to investigate whether fall-off test could provide sensible data for injection of Non-Newtonian fluids in horizontal wells and hence establish an optimal strategy for implementing such test, simulation work and analytical studies have been performed in this paper. The aim of this paper has been to analyse polymer fall-off interpretation method in Petrocedeno, and then to provide feasible suggestion or guidance for polymer fall-off implementation in the real pilot where the injection wells are horizontal.",1,1,1
Horizontal Wells,Method,"Zhang, Jiali; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Gao, Jian",A weak fluid supply model for transient pressure analysis in vertically fractured wells from tight gas reservoirs: A case study,Unconventional reservoirs; Weak fluid supply; Vertically fractured well; Pressure transient behaviors; Case study; Parameter estimation,SEMIANALYTICAL MODEL; HORIZONTAL WELLS; BEHAVIOR; NETWORKS,"An interesting phenomenon of weak fluid supply (WFS) has been observed in tight gas reservoirs from the Ordos Basin. To facilitate parameters evaluation and productivity estimations of those well, this paper presents a new WFS model for transient pressure analysis in vertically fractured wells from tight gas reservoirs. In the new model, a WFS pressure and a WFS index are first introduced to describe the weak fluid supply boundary. Based on that, a mathematical model is developed with considering WFS, finite-conductivity fractures, and stress-sensitive effect. Using perturbation transformation method and semianalytical method, the proposed mathematical model is solved with effects of wellbore storage and skin factor. Following that, the model verification, sensitivity study, and field application are performed. Results shows that the WFS causes a rapid drop after ""hump"" at the late stage in the pressure curves. The start time of ""hump"" decreases as the WFS index increases. When the WFS pressure is bigger than zero, the pressure derivative curves exhibit a significant ""hump"", and it is more obvious with the increase in the WFS pressure. When the WFS pressure is equal to zero, the pressure derivative curves directly drop, which is assemble to the effect of constant pressure boundary. When the WFS index is zero, the pressure derivative curve in the late period is a unit-slope line, demonstrating a closed boundary effect. The field application in the well Z1 from the Ordos Basin shows that a ""hump"" caused by WFS does appears at the late stage in the pressure curves. By using the WFS model, the estimated reservoir permeability and drainage radius are 0.524 mD and 451.68 m. The WFS pressure and WFS index are respectively estimated as 0.13 and 0.022 by the WFS model. It demonstrates the applicability of the new proposed WFS model, which also provides a good understanding of transient pressure behaviors and accurate estimation of reservoir parameters for fractured wells with WFS.",1,1,1
Horizontal Wells,Method,"Zhang, Rui; Li, Yinghao; Yang, Bin; Jia, Zongyi; Zhang, Feng; Wang, Ruihe; Li, Na; Zhou, Xianhai",A segmenting method of long horizontal wellbore for staged sand control completion based on multi-dimension sequential clustering,Sand production; Staged completion; Multi-dimension sequential clustering; Critical wellbore pressure of sanding onset; Water breakthrough time,INFLOW-CONTROL DEVICES; GAS-RESERVOIRS; OPTIMIZATION; PRESSURE,"For horizontal well, the uniform measure of completion for sand control in the whole horizontal wellbore will cause local sand control failure or excessive sand control, even a decrease in production. An effective measure solved the problem is to segment long horizontal wellbore and conduct completion with staged sand control. In this paper, taking into consideration impacts of reservoir properties heterogeneity, the heel-toe effect of wellbore flow and the different distance between wellbore and water-oil contact (WOC) on sand production along long horizontal wellbore, the difference (CWP - p(wf)) between critical wellbore pressure of sanding onset (CWP) and wellbore flowing pressure (p(wf))and water breakthrough time (T) of each micro section of horizontal wellbore are used to make up vector components and selected as segmenting indexes, further mull-dimension sequential clustering method is employed to segment horizontal wellbore according to the principle of location contiguity and similarly of CWP - p(wf) and T between micro intervals. Then the segmenting method for sand control completion together with water control in horizontal wells is proposed. Furthermore, the segmentation method is utilized in investigating staged sand and water control in TP65 well of T block in Shengli Oilfield, and the optimal number and location of segments for the well are given. This research can provide a new theoretical and quantitative method for staged sand control completion in horizontal well. And it also can be regarded as a fundamental platform to investigate other kinds of wellbore staging problems, such as staged fracturing.",2,3,3
Horizontal Wells,Method,"Chu, Hongyang; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Liu, Wenyuan",Estimating carbon geosequestration capacity in shales based on multiple fractured horizontal well: A case study,Multiple fractured horizontal well; CO2 geosequestration; Shale reservoirs; Semi-analytical method; Transient pressure response,TRANSIENT PRESSURE BEHAVIOR; ENHANCED GAS RECOVERY; STORAGE CAPACITY; CO2 STORAGE; NUMERICAL-SIMULATION; SEQUESTRATION; RESERVOIR; MODEL; FEASIBILITY; ADSORPTION,"Nowadays, shale reservoirs have been though as good candidates for CO2 geosequestration for reduction of carbon emission. When estimating the carbon geosequestration capacity, multiple fractured horizontal well (MFHW) is a prerequisite for consideration when shale reservoirs are included in candidate geological sites, as it is one of the critical factors for the successful development of shale reservoirs. In order to perfect our previous works, a new model is proposed to calculate the carbon geosequestration capacity of depleted shale reservoirs based on MFHW. The methodology calculates carbon geosequestration capacity of shale reservoirs by considering Knudsen diffusion, molecular diffusion, supercritical Langmuir adsorption, stimulated reservoir volume (SRV), and stress-sensitivity of the permeability. Utilizing the perturbation transformation technique, finite difference method, and Laplace transform technique, our method is more in accordance with the actual situations, allowing us to accurately estimate the carbon storage capacity by capturing the transient pressure response of the MFHW. A field case from the Ordos Basin in China presents that the CO2 geosequestration capacity is proportional to the dimensionless fracture half-length and conductivity. The properties of hydraulic fractures only affect the early period of the CO2 geosequestration process. For the adsorption coefficient and flow coefficient ratio, with the change of these parameters, the middle and late periods of the CO2 geosequestration process are mainly influenced.",2,2,4
Horizontal Wells,Method,"Li, Zhenglan; Duan, Yonggang; Wei, Mingqiang; Peng, Yu; Chen, Qingxuan",Pressure performance of interlaced fracture networks in shale gas reservoirs with consideration of induced fractures,Interlaced fracture networks; Shale gas; Secondary induced fractures; Flux distribution; Pressure performance,HORIZONTAL WELLS; SEMIANALYTICAL MODEL; TRANSIENT PRESSURE; METHANE; FLOW; PERMEABILITY; MECHANISMS; ADSORPTION; BEHAVIOR,"Multi-stage fracturing in shale gas reservoirs may create complex fracture network around horizontal wellbore, due to the widely-distributed natural fractures. However, little work has been done to investigate the effects of secondary fractures on well testing models for shale gas reservoirs. In this paper, a more comprehensive model was developed for interlaced fracture networks in shale gas reservoirs with consideration of multiple transport mechanisms and different flow states. By employing the source function and Laplace transformation, the line sink solutions for four kinds of flow states were unified. Based on the discretization method and unified line sink solution, the pressure responses for interlaced fracture networks with infinite conductivity were obtained. Type curves were plotted and typical flow regimes of this model were identified. In order to have a further understanding of the effect of induced fractures, the slope curves of pseudo-pressure derivative were introduced to analyze the interference between fractures. The influences of the angel and the length of induced fractures on the well testing curves were simulated by the semi-analytical model for the first time. Then, the flux distributions of interlaced fracture networks were simulated and discussed for achieving significant advice. Finally, the proposed model was verified by a simplified case and a field case. The presented model will be helpful for understanding the transient performance of multi-stage fractured horizontal wells with consideration of induced fractures.",3,3,0
Horizontal Wells,Method,"Scelsi, G.; De Bellis, M. L.; Pandolfi, A.; Musso, G.; Della Vecchia, G.",A step-by-step analytical procedure to estimate the in-situ stress state from borehole data,In situ stress; Borehole; Breakout failure; Tensile failure; Rock mechanics; Analytical procedure,WELL; MAGNITUDE; MODEL; PERMEABILITY; ORIENTATION; STABILITY; BREAKOUTS; FAILURE; DAMAGE; SEA,"Knowledge of the in situ stress state of rock mass is fundamental for engineering, geological and geophysical applications. In situ stress state determination requires in principle the evaluation of the three principal stresses and the related principal directions, but it is widely recognized in the literature that the maximum horizontal stress is the most difficult component to accurately estimate. In the context of borehole methods, this paper proposes a step-by-step analytical procedure to estimate some bounds to the maximum horizontal stress, starting from a geomechanical description of the rock and relying on information generally available in the engineering practice. The procedure is divided in substeps, each one requiring additional information about the mechanical properties of the rock and on the geometrical properties of the failed portion of rock: more information available implies a lower uncertainty on in situ stress estimate. Furthermore, since the proposed procedure is analytical, it allows a complete and very easy implementation in a spreadsheet. The aim of the work is thus to provide a rigourous but simple analytical tool that can be used in engineering practicte to estimate some bounds to the maximum horizontal in situ stress state. The approach is finally validated by means of both numerical simulations, performed with a sophisticated numerical tool, and experimental field data coming from the literature.",3,3,0
Horizontal Wells,Method,"Han, Yiwei; Ai, Zhijiu; Kuang, Yuchun; Liu, Jianxun; Yang, Wenwu",Nonlinear dynamic modeling of drill string in horizontal well - A geometrically exact approach,Horizontal drill string; Nonlinear dynamics; Geometrically exact model; Quadrature element method,FINITE-ELEMENT FORMULATION; 3-DIMENSIONAL BEAM THEORIES; SPATIAL BEAMS; DRILLSTRINGS; SPACE; PIPE; ROD,"A new nonlinear dynamic model of drill string in horizontal well is established based on geometrically exact beam theory and quadrature element method. The model proposed in this paper takes into account the geometric nonlinearity of the drill string and the nonlinear contact between the drill string and the borehole. Benefiting from the accuracy of the geometric description of the geometrically exact beam, the model uses a geometrically exact method to describe the contact between the drill string and the borehole. Comparison with experimental results shows that the geometrically exact model can accurately describe the nonlinear characteristics of the drill string. Finally, the characteristics of the movement of drill string under different drilling pressure and rotation speed are analyzed. Drilling pressure and rotational speed have an effect on the buckling of the drill string. Before buckling, the drill string moves periodically at the bottom of the wellbore. After buckling, the movement of the drill string becomes disordered. The model presented in this paper provides a new method for dynamic analysis of drill string.",3,3,10
Horizontal Wells,Method,"Wang, Xueying; Ni, Hongjian; Wang, Ruihe",Experimental study on toolface disorientation and correction during slide drilling,Slide drilling; Stick-slip motion; Toolface disorientation; Toolface hysteresis; Toolface correction,FACE-CONTROL; TORQUE,"Toolface control is an important issue when drilling directional wells with steerable motors. In this paper, a new experimental apparatus has been built to study the toolface behavior while slide drilling. In experiments, weight on bit and toolface orientation during the simulated slide drilling are recorded and analyzed. Experimental results indicate that axial slick-slip motion of the drillstring that occurs in the presence of large friction causes toolface disorientation. In addition, the phenomenon of toolface hysteresis in horizontal wells is identified. The asymmetric loading and unloading rates of weight on bit result in toolface hysteresis, and toolface hysteresis worsens toolface disorientation. A new method of correcting toolface by quickly eliminating toolface hysteresis is proposed. Four torque-related parameters are used in the method, and each has a specific implication. The proposed method has been examined using the experimental apparatus and has been proven to work. The experimental results and related analysis in this paper can help to further improve the efficiency of toolface control during slide drilling.",4,4,1
Horizontal Wells,Method,"Ma, Yongfeng; Yu, Rangang",New analytical methods to evaluate uncertainty of wellbore stability,Wellbore stability; Uncertainty evaluation; Analytical model; Monte Carlo method; Sensitivity analysis,FAILURE CRITERIA; STRENGTH CRITERIA; LOGGING PROBLEMS; MODEL; COULOMB; ROCKS; LIMIT,"The uncertainties of the inputting parameters lead to the uncertainty of the wellbore stability. In view of this, two analytical methods were proposed to address the problem, based on second order Taylor series expansion and Rosenbluthe method. Using two analytical methods, the collapse and fracture pressures were calculated in the form of the probability distribution. To accomplish the calculation above, the mean and standard deviation of input parameters were firstly determined based on well log data. Especially, a new method of sensitivity analysis was proposed to quantify the effect of the input parameter on the uncertainty of the wellbore stability, through the way that one parameter changes the uncertainty while other parameters keep initial uncertainties. Additionally, two analytical methods were validated by Monte Carlo simulation. The results show that the probability distributions agree very well between analytical methods and Monte Carlo method. According to the new method of sensitivity analysis, the horizontal maximum stress is the most sensitive parameter for the collapse pressure, and the horizontal minimum stress has the maximum effect on the fracture pressure.",5,6,1
Horizontal Wells,Transient Pressure,"Liu, Qingling; Tian, Shouceng; Yu, Wei; Li, Gensheng; Sheng, Mao; Sepehrnoori, Kamy; Shen, Zhonghou",A semi-analytical model for simulation of fluid flow in tight rock with irregular fracture geometry,Semi-analytical model; Transient pressure behavior; Vertical fractured well; Complex fracture geometries,PRESSURE-TRANSIENT ANALYSIS; HORIZONTAL WELLS; CONDUCTIVITY,"Numerous micro-seismic and laboratorial studies show that hydraulic fracture is usually with complex geometries, such as plugged fracture, asymmetry and non-plane. It is a challenging task to recognize the complex fracture and obtain reliable fracture parameters through transient pressure analysis. In this work, we extend the semi-analytical model by Zhou a al. (2013) to analyze transient pressure behavior of a fractured vertical well with complex fracture geometries. We verified the semi-analytical model by a numerical reservoir simulator on a planar fracture. Then, based on this model, we made a systematical discussion about the transient pressure behavior of the planar fracture with varying conductivity, asymmetric fracture and non-planar fracture. Results show that when the fracture conductivity is varying along the fracture path, the influence of fracture zone conductivity on the transient pressure behavior gradually decreases with the distance from the wellbore growing. Besides, we found that the fracture asymmetry is against for the fluid flow in the fracture, and it decreases the slope of transient pressure behavior curve and enlarge pressure drop. In addition, the non-planar fracture is usually with severe fracture width restriction around the wellbore, which will induce pseudo-radial flow in the fracture at early times and large pressure drop in the fracture. Furthermore, the influences of varying conductivity, fracture asymmetry and non-plane on transient pressure behavior are obvious for fracture with average small-to-middle conductivity (average dimensionless fracture conductivity ranging from 0.1 to 50); the influences become negotiable for fracture with average high-to-infinite conductivity (average dimensionless fracture conductivity ranging from 50 to 1000). This work can provide critical insights into understanding the effect of complex fracture geometry on transient pressure behavior of fractured vertical well in tight oil reservoir.",1,2,0
Horizontal Wells,Transient Pressure,"Zhang, Jiali; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Gao, Jian",A weak fluid supply model for transient pressure analysis in vertically fractured wells from tight gas reservoirs: A case study,Unconventional reservoirs; Weak fluid supply; Vertically fractured well; Pressure transient behaviors; Case study; Parameter estimation,SEMIANALYTICAL MODEL; HORIZONTAL WELLS; BEHAVIOR; NETWORKS,"An interesting phenomenon of weak fluid supply (WFS) has been observed in tight gas reservoirs from the Ordos Basin. To facilitate parameters evaluation and productivity estimations of those well, this paper presents a new WFS model for transient pressure analysis in vertically fractured wells from tight gas reservoirs. In the new model, a WFS pressure and a WFS index are first introduced to describe the weak fluid supply boundary. Based on that, a mathematical model is developed with considering WFS, finite-conductivity fractures, and stress-sensitive effect. Using perturbation transformation method and semianalytical method, the proposed mathematical model is solved with effects of wellbore storage and skin factor. Following that, the model verification, sensitivity study, and field application are performed. Results shows that the WFS causes a rapid drop after ""hump"" at the late stage in the pressure curves. The start time of ""hump"" decreases as the WFS index increases. When the WFS pressure is bigger than zero, the pressure derivative curves exhibit a significant ""hump"", and it is more obvious with the increase in the WFS pressure. When the WFS pressure is equal to zero, the pressure derivative curves directly drop, which is assemble to the effect of constant pressure boundary. When the WFS index is zero, the pressure derivative curve in the late period is a unit-slope line, demonstrating a closed boundary effect. The field application in the well Z1 from the Ordos Basin shows that a ""hump"" caused by WFS does appears at the late stage in the pressure curves. By using the WFS model, the estimated reservoir permeability and drainage radius are 0.524 mD and 451.68 m. The WFS pressure and WFS index are respectively estimated as 0.13 and 0.022 by the WFS model. It demonstrates the applicability of the new proposed WFS model, which also provides a good understanding of transient pressure behaviors and accurate estimation of reservoir parameters for fractured wells with WFS.",1,1,1
Horizontal Wells,Transient Pressure,"Cao, Jie; Zhang, Nan; Johansen, Thormod E.",Applications of fully coupled well/near-well modeling to reservoir heterogeneity and formation damage effects,Well/near-well modeling; Iterative coupling; Heterogeneity; Crossflow; Formation damage,HORIZONTAL WELLS; FLOW; PRODUCTIVITY; PERFORMANCE,"Applications of a new well/near-well fluid flow modeling scheme to heterogeneous reservoirs and formation damage are presented in this paper. This well/near-well model is based on an analytically solution of an axial-radial productivity model for steady state flow in wells and near-well reservoirs, in which wellbore hydraulics and heterogeneity in the near-well region are incorporated. The numerical model includes a reservoir region describing both radial and axial reservoir flow. It can be used as a stand alone simulator, or it can be coupled with a reservoir simulator, using a new iterative coupling scheme described in this paper. When coupling with the reservoir simulator, the reservoir region in the well/near-well model is shared by and computed in both models, which ensures the stability and convergence of the iterative coupling scheme. A new coupling approach is presented without needing to determine any partial derivatives. The capabilities of the modeling methodology are demonstrated through applications in three challenging cases: highly heterogeneous reservoir, well/reservoir crossflow, and formation damaged reservoirs. In the highly heterogeneous near-well reservoir case, results show that the model is stable for a wide range of permeabilities with large contrasts. The detailed permeability information from well logging can be fully taken into account in this model. The model determines pressure distribution and volumetric flow rates including flow directions, therefore enabling the model to estimate crossflow as negative flow rates, for example when the well is producing from several non-communicating regions. Furthermore, the well/near-well model is iteratively coupled with a reservoir simulator such that the well completion effects are taken into consideration in large scale simulations. The transient case of this coupling to evaluate formation damage along a horizontal well is then presented. The model is not limited to single phase flow. A two phase flow example coupling the well/near-well model and a streamline reservoir model is finally presented.",1,2,5
Horizontal Wells,Transient Pressure,"Youssef, AbdAllah A.",Inflow performance relationship of vertical wells in fractured vuggy media during semi-steady state flow regime,IPR; Error parameter and fractured-vuggy reservoirs,HORIZONTAL WELL; PERMEABILITY; BEHAVIOR; POROSITY; MODEL,"The inflow performance relationship (IPR) is one of the essential key parameters that control the fluids production/injection rate from wells. The presence of the vugs in addition to fractures in carbonate reservoirs introduce many difficulties related the estimation of IPR of future wells. In this study, a novel analytical IPR of dual-permeability, triple porosity model is derived for the first time. The introduced IPR formula is derived for the standard scenario model of a vertical and fully penetrating well in a circular reservoir under single-phase flow of slightly compressible fluid. The three governing flow equations (matrix flow equation, fracture flow equation and interaction between vugs and other two continuum equation) are solved simultaneously as a system of differential equations for semi-steady state (SSS) flow regime. The generated SSS IPR is the same as Darcy's straight line IPR multiplied by an error parameter (E-23) which is bounded between zero and one. A detailed investigation of the effect of the reservoir petro-physical parameters like storativities, inter-porosities and fracture to matrix permeability ratio are presented. The newly presented IPR of dual-permeability, triple porosity system can be reduced to sub-models IPRs by further modification of error parameter to fit sub-model as single permeability, triple porosity (E-13) or dual permeability, dual porosity (E-22). The presented IPR formula has the advantage of dividing the pressure drop of the fluid flow to two components, one for the internal resistance between different continuums (which is resented by E) and the other one is the radial flow in the same continuum toward/from well-bore. The generated IPR model is double verified using both cell pressure centred finite volume numerical simulation and conventional pressure transient analysis.",2,2,0
Horizontal Wells,Transient Pressure,"Chu, Hongyang; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Liu, Wenyuan",Estimating carbon geosequestration capacity in shales based on multiple fractured horizontal well: A case study,Multiple fractured horizontal well; CO2 geosequestration; Shale reservoirs; Semi-analytical method; Transient pressure response,TRANSIENT PRESSURE BEHAVIOR; ENHANCED GAS RECOVERY; STORAGE CAPACITY; CO2 STORAGE; NUMERICAL-SIMULATION; SEQUESTRATION; RESERVOIR; MODEL; FEASIBILITY; ADSORPTION,"Nowadays, shale reservoirs have been though as good candidates for CO2 geosequestration for reduction of carbon emission. When estimating the carbon geosequestration capacity, multiple fractured horizontal well (MFHW) is a prerequisite for consideration when shale reservoirs are included in candidate geological sites, as it is one of the critical factors for the successful development of shale reservoirs. In order to perfect our previous works, a new model is proposed to calculate the carbon geosequestration capacity of depleted shale reservoirs based on MFHW. The methodology calculates carbon geosequestration capacity of shale reservoirs by considering Knudsen diffusion, molecular diffusion, supercritical Langmuir adsorption, stimulated reservoir volume (SRV), and stress-sensitivity of the permeability. Utilizing the perturbation transformation technique, finite difference method, and Laplace transform technique, our method is more in accordance with the actual situations, allowing us to accurately estimate the carbon storage capacity by capturing the transient pressure response of the MFHW. A field case from the Ordos Basin in China presents that the CO2 geosequestration capacity is proportional to the dimensionless fracture half-length and conductivity. The properties of hydraulic fractures only affect the early period of the CO2 geosequestration process. For the adsorption coefficient and flow coefficient ratio, with the change of these parameters, the middle and late periods of the CO2 geosequestration process are mainly influenced.",2,2,4
Horizontal Wells,Transient Pressure,"Li, Zhenglan; Duan, Yonggang; Wei, Mingqiang; Peng, Yu; Chen, Qingxuan",Pressure performance of interlaced fracture networks in shale gas reservoirs with consideration of induced fractures,Interlaced fracture networks; Shale gas; Secondary induced fractures; Flux distribution; Pressure performance,HORIZONTAL WELLS; SEMIANALYTICAL MODEL; TRANSIENT PRESSURE; METHANE; FLOW; PERMEABILITY; MECHANISMS; ADSORPTION; BEHAVIOR,"Multi-stage fracturing in shale gas reservoirs may create complex fracture network around horizontal wellbore, due to the widely-distributed natural fractures. However, little work has been done to investigate the effects of secondary fractures on well testing models for shale gas reservoirs. In this paper, a more comprehensive model was developed for interlaced fracture networks in shale gas reservoirs with consideration of multiple transport mechanisms and different flow states. By employing the source function and Laplace transformation, the line sink solutions for four kinds of flow states were unified. Based on the discretization method and unified line sink solution, the pressure responses for interlaced fracture networks with infinite conductivity were obtained. Type curves were plotted and typical flow regimes of this model were identified. In order to have a further understanding of the effect of induced fractures, the slope curves of pseudo-pressure derivative were introduced to analyze the interference between fractures. The influences of the angel and the length of induced fractures on the well testing curves were simulated by the semi-analytical model for the first time. Then, the flux distributions of interlaced fracture networks were simulated and discussed for achieving significant advice. Finally, the proposed model was verified by a simplified case and a field case. The presented model will be helpful for understanding the transient performance of multi-stage fractured horizontal wells with consideration of induced fractures.",3,3,0
Horizontal Wells,Transient Pressure,"Sureshjani, Mohammadhossein Heidari; Ahmadi, Mohammad; Fahimpour, Jalal",A generalized approach for fast estimation of reservoir permeability distribution from analysis of pressure transient data,Pressure transient analysis; Permeability heterogeneity map; Inverse problem,GRADUAL DEFORMATION; WELL,"Estimation of permeability variation from analysis of pressure transient data is very challenging. Such problem may not have a unique solution and cannot be analyzed with classic well-test models. The available models for fast estimation of permeability map are restricted to several assumptions such as existence of pure radial or linear flow in an infinite medium. Such assumptions may be violated in real applications. To handle pressure transient analysis in heterogeneous reservoirs, more flexible models are needed to be applicable for majority of real well tests. In this work, a generalized approach is developed to estimate reservoir permeability variation from analysis of pressure transient data. For non-radial flow regimes, we show that the permeability rings should be defined non-circular. In flow geometries other than radial, we may not be able to use radius of investigation. Accordingly, we propose the use of pressure drop at the boundary of region of investigation instead. The average permeability in non-circular rings can produce satisfactory derivative predictions. Inspired by this observation, we developed an inverse procedure to estimate equivalent average permeability along with appropriate inner and outer ring boundaries. After estimation of equivalent permeabilities from the inverse procedure, the 2D permeability map is estimated through a minimization process. The defined objective function represents the difference of geometric average of realizations and equivalent average permeabilities from the inverse procedure. Using such form of definition, there is no need to perform any flow simulation during minimization process. We applied the procedure to back calculate the permeability variation around a horizontal well from analysis of its pressure derivative data. In addition, the uncertainty of the estimation and prediction was evaluated. The results reveal the strength of the proposed methodology for pressure transient analysis of heterogeneous reservoirs.",3,3,0
Horizontal Wells,Transient Pressure,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Horizontal Wells,Oil Production,"Phan, T. N.; Zapata, Y. M.; Kabir, C. S.; Pigott, J. D.; Pranter, M. J.; Reza, Z. A.",Probing hydraulically-fractured wells in unconventional shale reservoirs under cyclic CO2 injection: Variation of thermophysical properties,Unconventional reservoirs; CO2 cyclic injection; Exploring variation of thermophysical properties; Understanding injection-soaking-production cycles; Realistic oil recovery with large number of cycles; Molecular diffusion yields 6% incremental oil,OIL RESERVOIRS,"Despite the recent growth in oil production from unconventional reservoirs, existing hydraulically-fractured horizontal wells face challenges of poor recovery with the rapid production decline over a short life span. Enhanced recovery techniques, such as cyclic CO2 injection can be a solution to this impending problem and lead to energy independence for the foreseeable future. However, mechanisms occurring around the hydraulically fractured wells are far from fully understood. The primary motivation of this study revolves around addressing this limitation. Specifically, we explored the evolution of various thermophysical properties occurring around hydraulically-fractured wells in liquid-rich unconventional reservoirs using a holistic, integrated modeling framework. Available well-logs and other data from Howard County in the Midland Basin formed the basis for constructing representative 3D structural models that capture the Midland Basin stratigraphy. We used a simulator to create multistage hydraulic fractures that allowed integration into numerical reservoir-flow simulation models. Then, both convective and diffusive flow within a multicomponent compositional simulation modeling paradigm is used to examine the role of molecular diffusion in performance under cyclic CO2 injections in hydraulically-fractured well. The simulation results indicate that molecular diffusion yields an incremental oil recovery of 6% compared to models that do not. Our analysis reveals different thermophysical properties transition from near wellbore regions to outer regions into the rock matrix. Changes in total mole fractions of CO2, methane, and hydrocarbons with C7+ fraction, pressure and saturation variation, viscosity reduction and the surface tension over 14 injection-soaking-production cycles are tracked. The analyses of the evolution of these thermophysical properties provide us with means to evaluate the efficiency of the solvent injection process. The simulation results explain how, when, and where CO2 disperses into the reservoir.",0,0,0
Horizontal Wells,Oil Production,"Eren, Tuna; Polat, Can",Well efficiency assessment in geothermal fields for horizontal drilling,Geothermal field; Horizontal wells; Cost analysis; Well efficiency; Thermal energy; Drilling engineering; Reservoir engineering,HYDRATE,"A research study is conducted to evaluate the well efficiency assessment of horizontal wells in geothermal fields. The study is comprised of developing the field by means of drilling 15 wells, and conducting reservoir simulation. Drilling planning of vertical and horizontal wells are studied together with their respective time and cost estimates. The time estimate of horizontal geothermal wells is benchmarked to previously drilled vertical and horizontal oil wells, since the data belonging to horizontal wells was not available for study. The findings indicate that the horizontal drilling scenario would take only 7 months more than the vertical drilling scenario. Monetary wise; horizontal wells for a geothermal field is estimated to be drilled 41% more in cost. A hypothetical geothermal field model is generated for the simulations, using TOUGH2. The simulations of four scenario sensitivity analyses reveal that drilling of horizontal wells provide efficient energy extraction out of a geothermal field, in comparison having the wells drilled vertically. The approach provides powerful comparison without having made any investment in the hypothetically simulated geothermal field. The study is a novel in kind since in country such as Turkey there is no horizontal well drilled within the geothermal fields. The analysis of the results indicate that energy production from the horizontal wells are greater than the energy production of vertical wells, definitely paying off the additional investment costs for horizontal drilling and completion.",1,1,8
Horizontal Wells,Oil Production,"Cheng, Gang; Pang, Zhanxi; Jiang, Yanming; Wang, Bo; Yu, Xiaogang",Thermodynamic analysis and prediction of reservoir temperature distribution for steam stimulation,Steam stimulation; Temperature distribution; Heat conduction; Heat convection; Energy balance equation,ASSISTED-GRAVITY-DRAINAGE; HEAT-TRANSFER; OIL-RECOVERY; POROUS-MEDIA; THERMAL RECOVERY; DISPLACEMENT; INJECTION; FLOW,"During steam stimulation of horizontal wells in heavy oil reservoir, it is necessary to estimate the reservoir temperature distribution, which has a huge impact on oil production and ultimate oil recovery. Most of previous models were derived based on infinite boundary condition and constant fluid velocity, which were not consistent with real situation of reservoir. In this paper, new energy balance equations combined with mobile boundary conditions were developed for increasing the accuracy of predicted results. Based on dimensionless conversion and numerical analysis, the optimum solution of equation system could be easily obtained, and its good performance in predicting temperature distribution was also validated. Moreover, thermodynamic mechanism of hot fluid, latent heat and sensible heat of steam, and their contributions to heating reservoir were also discussed to investigate the heat transfer pattern in reservoir. Finally, factors that could influence the reservoir temperature distribution were analyzed. It is found that: (a) both the heat conduction and the heat convection contribute to the heat transfer in hot liquid zone, and the heat convection predominates; (b) both the condensation front and heat front move outward with the injection of steam, but their expanding rates gradually drop with time; (c) as the radius increases, the radial fluid velocity will go down, leading the heat convection effect to be weakened and the heat conduction effect to become obvious; (d) there are some factors that can influence the reservoir temperature distribution including steam injection duration, fluid velocity, volumetric heat capacity of fluid, steam quality and thermal conductivity of reservoir.",2,2,2
Horizontal Wells,Oil Production,"Ziabakhsh-Ganji, Zaman; Nick, Hamidreza M.; Bruhn, David F.",Investigation of the synergy potential of oil and geothermal energy from a fluvial oil reservoir,Geothermal energy; Thermal enhanced heavy oil recovery (TEOR); Heterogeneity; Net to gross (N/G); Net present value (NPV),HEAT-RECOVERY; HOT-WATER; HETEROGENEITY; CONNECTIVITY; PERFORMANCE; FLOW; INJECTION; EXPLOITATION; AQUIFER; SYSTEM,"Geothermal projects, as renewable energy projects, are not economically attractive in most places of the world at the current state of development; for this reason, subsidies are required by energy and environmental authorities in order to increase the interest in such projects. In this paper, we assess and model strategies for integration of geothermal energy with oil productions of the Moerkapelle oil field in the Netherlands. To do so, numerical simulations have been employed to analyse the feasibility of a fluvial oil reservoir for the synergy potential of oil and geothermal energy exploitation. In order to implement the simulation studies, single phase and two-phase non-isothermal fluid flow modelling are utilized for the geothermal well doublet system and for water flooding in an oil reservoir (including facies heterogeneity), respectively. A series of simulations have been conducted to investigate how hot water from a geothermal reservoir beneath a heavy oil reservoir in the fluvial sedimentary system of the West Netherlands Basin can be used for Thermal Enhanced Oil Recovery (TEOR) and geothermal energy production. This study finds that the high degree of heterogeneity in fluvial oil reservoirs could significantly affect oil recovery improvement and hence the synergy strategy. High values of a) Net to gross (N/G) b) Bottom Hole Pressure (BHP) and c) horizontal wellbore length are favourable for oil recovery. In contrast, wide horizontal wellbore spacing and high oil viscosity have an adverse effect on oil recovery enhancement. Furthermore, the results display that the enhanced oil production helps to reduce the required subsidy for a single doublet geothermal project up to 100%. Consequently, the extra amount of oil produced by utilising the geothermal energy, could make the geothermal business case independent and profitable.",3,3,1
Horizontal Wells,Oil Production,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Horizontal Wells,Oil Production,"Liu, Changwei; Li, Kewen; Tian, Xiaoming; Zhao, Guoxiang; Chen, Youguang; Mahlalela, B. M.",Experimental studies on production performance of oil reservoirs with bottom water,Bottom-water reservoir; Horizontal well; Physical model; Optimal production pressure,LEG,"Water coning is a major problem in oil reservoirs with bottom water. It reduces the oil production and overall oil recovery. Excessive water production causes corrosion problems in production facilities and increases the cost of water disposal. This may cause the early shutdown of oil wells. In this study, an experimental apparatus has been designed and developed to physically model an oil reservoir with bottom water. The reservoir model was transparent and the change in water coning could be visualized. Many water-flooding tests were conducted at different pressures and oil viscosities ranging from 22 to 260 mPa s. The effects of production pressures and oil viscosity on oil production were investigated. The results indicated that for a medium oil viscosity of 74 mPa s, the optimal production pressure was about 0.054 bar. For minimum and maximum oil viscosity (22 mPa s and 260 mPa s), the smaller the production pressure, the larger the water breakthrough time and oil recovery. Five types of flooding characteristic curves were used to characterize the water-cut variation, and their applicability were compared and analyzed. The water drive curves were fitted using the water-cut models and the oil ""reserves"" (originally placed in the reservoir model) were predicted using the mathematical models with the experimental data. The results indicated that the Maksimov model of water-drive characteristic curve is more suitable to match the water production performance. Most interestingly, when applying the most suitable model Maksimov water-drive characteristic curve to predict oil reserves, the cases with optimal production pressures have a greater accuracy.",5,5,0
Horizontal Wells,Oil Production,"Yang, Xu; Guo, Boyun",Productivity analysis of multi-fractured shale oil wells accounting for the low-velocity non-Darcy effect,Low-velocity non-Darcy; TMS; Shale oil; Productivity; Cluster spacing,THRESHOLD PRESSURE-GRADIENT; LOW-PERMEABILITY RESERVOIR; PRODUCTION PERFORMANCE; MATHEMATICAL-MODEL; POROUS-MEDIA; FLUID-FLOW; BEHAVIOR,"Well productivity of the Tuscaloosa Marine Shale (TMS) trend located in Louisiana and Mississippi presents a significant challenge. Well productivity declines rapidly for some reasons not known to the operators. By taking advantage of the concept of apparent matrix permeability, a semi-analytical model was developed in this investigation considering the low-velocity non-Darcy effect. An iterative procedure is proposed to calculate the oil production rate of multi-fractured horizontal shale oil wells. Field case studies of the Eagle Ford Shale (EFS) and TMS wells indicated that the productivity model considering low-velocity non-Darcy is consistent with field data, with a relative error of less than 10%. The low-velocity non-Darcy phenomenon may harm the TMS oil production rate as high as 29.7%. Sensitivity analysis demonstrates that low permeability reservoirs are more likely to be affected by non-Darcy behavior. The apparent matrix permeability declines severer in low permeability than in high permeability reservoirs, thus reducing well productivity more significantly in the low-permeability TMS trend. The oil production rate of Darcy flow increases with increasing fracture conductivity. However, this benefit was hindered by non-Darcy effect. A larger fracture half-length favors oil production, although it reduces the non-Darcy effect slightly. Besides, reducing the cluster spacing can mitigate the adverse impact of low-velocity non-Darcy, thus enhancing the shale oil production rate. Therefore, there is a vast potential for enhancing oil productivity in the TMS trend by reducing perforation cluster spacing.",5,5,0
Horizontal Wells,Oil Production,"Du, Qingjun; Hou, Jian; Zhao, Fan; Zhou, Kang; Liu, Wenbin; Liu, Yongge",A new organic fiber composite gel as a plugging agent for assisting CO2 huff and puff in water channeling reservoirs,CO2 utilization ratio; Organic fiber composite gel; Water channeling reservoir; Real rock plate experiment; Numerical simulation,ENHANCED OIL-RECOVERY; DIFFUSION-COEFFICIENTS; N-PUFF; CARBON-DIOXIDE; INJECTION; PERFORMANCE; SIMULATION; PROPANE; METHANE; SHALE,"The utilization of CO2 for enhancing oil recovery is an environmentally friendly way to dispose the industrial CO2 emissions. CO2 utilization ratio is defined as the volume ratio of produced oil to injected CO2. CO2 huff and puff technology can further improve oil recovery in high water cut reservoirs. However, as the huff and puff cycle increase, gas channeling is easy to happen and the utilization ratio of CO2 is reduced. Organic fiber composite gel is an effective plugging agent for gas channel. The major objective of this paper is to study the mechanisms of increasing CO2 utilization by injecting organic composite gel as the plugging agent. A large scale (40 cm*40 cm*3 cm) natural rock model with grooves is used to simulate the experimental conditions such as channeling channel and horizontal well. Two groups of experiments of direct CO2 huff and plugging agent assisted CO2 huff and puff were conducted. By comparing the pressure changes during the experiments, the mechanism of blocking the channel, balancing the CO2 displacement front and improving the utilization ratio of CO2 were analyzed. The experimental process was fitted by reservoir numerical simulation, and the remaining oil distribution, plugging agent distribution and CO2 distribution in CO2 huff and puff under different conditions were further demonstrated. Results show that compared with direct CO2 stimulation, the distribution of remaining oil saturation and reservoir pressure become more uniform and the utilization ratio of CO2 is greatly increased after injecting organic fiber composite gel. It is mainly due to the fact that the injected plugging agents flow preferentially into high water saturation region along the high permeability channels. Then, they can generate the organic fiber composite gel and remain in the channeling paths. As a result, the following injected CO2 will be forced to flow towards oil-rich regions radially and uniformly. Thereby, more CO2 can contact and react with the in-situ oil, resulting much higher oil recovery. In other words, the utilization ratio of CO2 is greatly improved. Taking Jidong oilfield as an example, it has been injected 19.2 x 10(4) t CO2 with the total oil production by 21.1 x 10(4) t. The utilization ratio of CO2 is calculated as high as 1.09. The observations of this study provide the theoretical basis for future application of organic fiber composite gel before CO2 flooding in the water channeling reservoirs.",5,5,3
Horizontal Wells,Semianalytical Model,"Liu, Qingling; Tian, Shouceng; Yu, Wei; Li, Gensheng; Sheng, Mao; Sepehrnoori, Kamy; Shen, Zhonghou",A semi-analytical model for simulation of fluid flow in tight rock with irregular fracture geometry,Semi-analytical model; Transient pressure behavior; Vertical fractured well; Complex fracture geometries,PRESSURE-TRANSIENT ANALYSIS; HORIZONTAL WELLS; CONDUCTIVITY,"Numerous micro-seismic and laboratorial studies show that hydraulic fracture is usually with complex geometries, such as plugged fracture, asymmetry and non-plane. It is a challenging task to recognize the complex fracture and obtain reliable fracture parameters through transient pressure analysis. In this work, we extend the semi-analytical model by Zhou a al. (2013) to analyze transient pressure behavior of a fractured vertical well with complex fracture geometries. We verified the semi-analytical model by a numerical reservoir simulator on a planar fracture. Then, based on this model, we made a systematical discussion about the transient pressure behavior of the planar fracture with varying conductivity, asymmetric fracture and non-planar fracture. Results show that when the fracture conductivity is varying along the fracture path, the influence of fracture zone conductivity on the transient pressure behavior gradually decreases with the distance from the wellbore growing. Besides, we found that the fracture asymmetry is against for the fluid flow in the fracture, and it decreases the slope of transient pressure behavior curve and enlarge pressure drop. In addition, the non-planar fracture is usually with severe fracture width restriction around the wellbore, which will induce pseudo-radial flow in the fracture at early times and large pressure drop in the fracture. Furthermore, the influences of varying conductivity, fracture asymmetry and non-plane on transient pressure behavior are obvious for fracture with average small-to-middle conductivity (average dimensionless fracture conductivity ranging from 0.1 to 50); the influences become negotiable for fracture with average high-to-infinite conductivity (average dimensionless fracture conductivity ranging from 50 to 1000). This work can provide critical insights into understanding the effect of complex fracture geometry on transient pressure behavior of fractured vertical well in tight oil reservoir.",1,2,0
Horizontal Wells,Semianalytical Model,"Zhang, Jiali; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Gao, Jian",A weak fluid supply model for transient pressure analysis in vertically fractured wells from tight gas reservoirs: A case study,Unconventional reservoirs; Weak fluid supply; Vertically fractured well; Pressure transient behaviors; Case study; Parameter estimation,SEMIANALYTICAL MODEL; HORIZONTAL WELLS; BEHAVIOR; NETWORKS,"An interesting phenomenon of weak fluid supply (WFS) has been observed in tight gas reservoirs from the Ordos Basin. To facilitate parameters evaluation and productivity estimations of those well, this paper presents a new WFS model for transient pressure analysis in vertically fractured wells from tight gas reservoirs. In the new model, a WFS pressure and a WFS index are first introduced to describe the weak fluid supply boundary. Based on that, a mathematical model is developed with considering WFS, finite-conductivity fractures, and stress-sensitive effect. Using perturbation transformation method and semianalytical method, the proposed mathematical model is solved with effects of wellbore storage and skin factor. Following that, the model verification, sensitivity study, and field application are performed. Results shows that the WFS causes a rapid drop after ""hump"" at the late stage in the pressure curves. The start time of ""hump"" decreases as the WFS index increases. When the WFS pressure is bigger than zero, the pressure derivative curves exhibit a significant ""hump"", and it is more obvious with the increase in the WFS pressure. When the WFS pressure is equal to zero, the pressure derivative curves directly drop, which is assemble to the effect of constant pressure boundary. When the WFS index is zero, the pressure derivative curve in the late period is a unit-slope line, demonstrating a closed boundary effect. The field application in the well Z1 from the Ordos Basin shows that a ""hump"" caused by WFS does appears at the late stage in the pressure curves. By using the WFS model, the estimated reservoir permeability and drainage radius are 0.524 mD and 451.68 m. The WFS pressure and WFS index are respectively estimated as 0.13 and 0.022 by the WFS model. It demonstrates the applicability of the new proposed WFS model, which also provides a good understanding of transient pressure behaviors and accurate estimation of reservoir parameters for fractured wells with WFS.",1,1,1
Horizontal Wells,Semianalytical Model,"Chu, Hongyang; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Liu, Wenyuan",Estimating carbon geosequestration capacity in shales based on multiple fractured horizontal well: A case study,Multiple fractured horizontal well; CO2 geosequestration; Shale reservoirs; Semi-analytical method; Transient pressure response,TRANSIENT PRESSURE BEHAVIOR; ENHANCED GAS RECOVERY; STORAGE CAPACITY; CO2 STORAGE; NUMERICAL-SIMULATION; SEQUESTRATION; RESERVOIR; MODEL; FEASIBILITY; ADSORPTION,"Nowadays, shale reservoirs have been though as good candidates for CO2 geosequestration for reduction of carbon emission. When estimating the carbon geosequestration capacity, multiple fractured horizontal well (MFHW) is a prerequisite for consideration when shale reservoirs are included in candidate geological sites, as it is one of the critical factors for the successful development of shale reservoirs. In order to perfect our previous works, a new model is proposed to calculate the carbon geosequestration capacity of depleted shale reservoirs based on MFHW. The methodology calculates carbon geosequestration capacity of shale reservoirs by considering Knudsen diffusion, molecular diffusion, supercritical Langmuir adsorption, stimulated reservoir volume (SRV), and stress-sensitivity of the permeability. Utilizing the perturbation transformation technique, finite difference method, and Laplace transform technique, our method is more in accordance with the actual situations, allowing us to accurately estimate the carbon storage capacity by capturing the transient pressure response of the MFHW. A field case from the Ordos Basin in China presents that the CO2 geosequestration capacity is proportional to the dimensionless fracture half-length and conductivity. The properties of hydraulic fractures only affect the early period of the CO2 geosequestration process. For the adsorption coefficient and flow coefficient ratio, with the change of these parameters, the middle and late periods of the CO2 geosequestration process are mainly influenced.",2,2,4
Horizontal Wells,Semianalytical Model,"Li, Zhenglan; Duan, Yonggang; Wei, Mingqiang; Peng, Yu; Chen, Qingxuan",Pressure performance of interlaced fracture networks in shale gas reservoirs with consideration of induced fractures,Interlaced fracture networks; Shale gas; Secondary induced fractures; Flux distribution; Pressure performance,HORIZONTAL WELLS; SEMIANALYTICAL MODEL; TRANSIENT PRESSURE; METHANE; FLOW; PERMEABILITY; MECHANISMS; ADSORPTION; BEHAVIOR,"Multi-stage fracturing in shale gas reservoirs may create complex fracture network around horizontal wellbore, due to the widely-distributed natural fractures. However, little work has been done to investigate the effects of secondary fractures on well testing models for shale gas reservoirs. In this paper, a more comprehensive model was developed for interlaced fracture networks in shale gas reservoirs with consideration of multiple transport mechanisms and different flow states. By employing the source function and Laplace transformation, the line sink solutions for four kinds of flow states were unified. Based on the discretization method and unified line sink solution, the pressure responses for interlaced fracture networks with infinite conductivity were obtained. Type curves were plotted and typical flow regimes of this model were identified. In order to have a further understanding of the effect of induced fractures, the slope curves of pseudo-pressure derivative were introduced to analyze the interference between fractures. The influences of the angel and the length of induced fractures on the well testing curves were simulated by the semi-analytical model for the first time. Then, the flux distributions of interlaced fracture networks were simulated and discussed for achieving significant advice. Finally, the proposed model was verified by a simplified case and a field case. The presented model will be helpful for understanding the transient performance of multi-stage fractured horizontal wells with consideration of induced fractures.",3,3,0
Horizontal Wells,Semianalytical Model,"Prakasa, Bona; Muradov, Khafiz; Davies, David",Principles of rapid design of an inflow control device completion in homogeneous and heterogeneous reservoirs using type curves,Inflow control devices; Intelligent well completion; Horizontal well; Heel-to-toe effect; Inflow rate distribution,HORIZONTAL WELLS; PRESSURE-DROP,"This paper discusses the development and application of universal type-curves for the design of Advanced Well Completions (AWCs) equipped with passive (non-adjustable), flow control devices {a.k.a. Interval Control Devices (ICDs)}. This work provides an innovative, rapid approach to their design without the need for numerical simulators. AWCs equipped with ICDs aim to delay the early breakthrough of unwanted fluids in wells constructed close to a reservoir fluid contact. An uneven inflow profile due to reservoir permeability heterogeneity, multiple fluid contacts or an undulating well path needs to be managed. In addition, the Heel-to Toe effect (HTE) by frictional pressure loss due to fluid flow along the length of the completion interval also promotes a non-uniform inflow profile. The main AWC design challenge is to balance the trade-off between loss in well productivity from the added flow restrictions and the benefit of an improved inflow profile. This paper reviews the development of the analytical modelling of the inflow performance of horizontal wells with ICD completions, It presents new semi-analytical, mathematical models describing the ability of AWCs to mitigate production problems created by (reservoir) permeability heterogeneity and the (in-well) HTE. New dimensionless numbers allow the development of universal type-curves (TCs) for AWC design. The new workflow is illustrated for several case studies and the results validated by their good agreement with calculations made with the standard ""well-reservoir"" numerical simulator employed by engineers for this task. This novel approach for rapid analysis of the implications of well log data, such as that obtained shortly before the beginning the installation of the well completion, is the latest addition to the well completion engineering toolbox.",3,5,0
Horizontal Wells,Semianalytical Model,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Horizontal Wells,Semianalytical Model,"Yang, Xu; Guo, Boyun",Productivity analysis of multi-fractured shale oil wells accounting for the low-velocity non-Darcy effect,Low-velocity non-Darcy; TMS; Shale oil; Productivity; Cluster spacing,THRESHOLD PRESSURE-GRADIENT; LOW-PERMEABILITY RESERVOIR; PRODUCTION PERFORMANCE; MATHEMATICAL-MODEL; POROUS-MEDIA; FLUID-FLOW; BEHAVIOR,"Well productivity of the Tuscaloosa Marine Shale (TMS) trend located in Louisiana and Mississippi presents a significant challenge. Well productivity declines rapidly for some reasons not known to the operators. By taking advantage of the concept of apparent matrix permeability, a semi-analytical model was developed in this investigation considering the low-velocity non-Darcy effect. An iterative procedure is proposed to calculate the oil production rate of multi-fractured horizontal shale oil wells. Field case studies of the Eagle Ford Shale (EFS) and TMS wells indicated that the productivity model considering low-velocity non-Darcy is consistent with field data, with a relative error of less than 10%. The low-velocity non-Darcy phenomenon may harm the TMS oil production rate as high as 29.7%. Sensitivity analysis demonstrates that low permeability reservoirs are more likely to be affected by non-Darcy behavior. The apparent matrix permeability declines severer in low permeability than in high permeability reservoirs, thus reducing well productivity more significantly in the low-permeability TMS trend. The oil production rate of Darcy flow increases with increasing fracture conductivity. However, this benefit was hindered by non-Darcy effect. A larger fracture half-length favors oil production, although it reduces the non-Darcy effect slightly. Besides, reducing the cluster spacing can mitigate the adverse impact of low-velocity non-Darcy, thus enhancing the shale oil production rate. Therefore, there is a vast potential for enhancing oil productivity in the TMS trend by reducing perforation cluster spacing.",5,5,0
Horizontal Wells,Semianalytical Model,"Hu, Xiaohu; Yu, Wei; Liu, Malin; Wang, Mingwei; Wang, Weihong",A multiscale model for methane transport mechanisms in shale gas reservoirs,Semi-analytical model; Complex hydraulic fractures; Shale gas; Multiple horizontal wells; Nanopores,HYDRAULIC-FRACTURE GEOMETRY; HORIZONTAL WELLS; PRODUCTION SIMULATION; SEMIANALYTICAL MODEL; COMPREHENSIVE MODEL; COMPLEX FRACTURES; FLOW; NETWORKS; PERMEABILITY,"We presented an efficient semi-analytical model-based analysis of methane transport in shale reservoirs including multiple horizontal wells with nanopores and complex hydraulic fractures. Multiple important gas transport mechanisms in nanopores such as gas desorption, gas slippage and diffusion and pressure-dependent fracture conductivity are fully incorporated in the model. Both simple and complex fractures in multiple shale-gas wells can be easily and effectively dealt with in accordance with the discretization approach, which does not require detailed gridding like numerical model. The superposition principle is utilized to capture the interactions between all fracture segments in order to accurately simulate real gas transport from matrix to fractures and finally from fractures to wellbores. We verified the semi-analytical model against a numerical compositional reservoir model for two shale-gas wells with multiple simple planar hydraulic fractures considering the gas desorption effect. The semi-analytical model was used to analyze ultimate gas recovery of different complex hydraulic fracture patterns in a two-well scenario, which were generated from a complex fracture propagation model with and without considering natural fractures. In addition, it was applied to perform field-scale simulation with multiple wells and complex fracture geometries in accordance with microseismic data. The simulation results show that multiple gas transport mechanisms, pressure-dependent fracture conductivity and complex fracture geometries play an important role in controlling well productivity and gas recovery, which should be properly accounted for in the physical model in order to achieve more accurate long-term production forecasting of multiple-fractured shale-gas horizontal wells.",5,6,1
Horizontal Wells,Hydraulic Fracture,"Phan, T. N.; Zapata, Y. M.; Kabir, C. S.; Pigott, J. D.; Pranter, M. J.; Reza, Z. A.",Probing hydraulically-fractured wells in unconventional shale reservoirs under cyclic CO2 injection: Variation of thermophysical properties,Unconventional reservoirs; CO2 cyclic injection; Exploring variation of thermophysical properties; Understanding injection-soaking-production cycles; Realistic oil recovery with large number of cycles; Molecular diffusion yields 6% incremental oil,OIL RESERVOIRS,"Despite the recent growth in oil production from unconventional reservoirs, existing hydraulically-fractured horizontal wells face challenges of poor recovery with the rapid production decline over a short life span. Enhanced recovery techniques, such as cyclic CO2 injection can be a solution to this impending problem and lead to energy independence for the foreseeable future. However, mechanisms occurring around the hydraulically fractured wells are far from fully understood. The primary motivation of this study revolves around addressing this limitation. Specifically, we explored the evolution of various thermophysical properties occurring around hydraulically-fractured wells in liquid-rich unconventional reservoirs using a holistic, integrated modeling framework. Available well-logs and other data from Howard County in the Midland Basin formed the basis for constructing representative 3D structural models that capture the Midland Basin stratigraphy. We used a simulator to create multistage hydraulic fractures that allowed integration into numerical reservoir-flow simulation models. Then, both convective and diffusive flow within a multicomponent compositional simulation modeling paradigm is used to examine the role of molecular diffusion in performance under cyclic CO2 injections in hydraulically-fractured well. The simulation results indicate that molecular diffusion yields an incremental oil recovery of 6% compared to models that do not. Our analysis reveals different thermophysical properties transition from near wellbore regions to outer regions into the rock matrix. Changes in total mole fractions of CO2, methane, and hydrocarbons with C7+ fraction, pressure and saturation variation, viscosity reduction and the surface tension over 14 injection-soaking-production cycles are tracked. The analyses of the evolution of these thermophysical properties provide us with means to evaluate the efficiency of the solvent injection process. The simulation results explain how, when, and where CO2 disperses into the reservoir.",0,0,0
Horizontal Wells,Hydraulic Fracture,"Liu, Qingling; Tian, Shouceng; Yu, Wei; Li, Gensheng; Sheng, Mao; Sepehrnoori, Kamy; Shen, Zhonghou",A semi-analytical model for simulation of fluid flow in tight rock with irregular fracture geometry,Semi-analytical model; Transient pressure behavior; Vertical fractured well; Complex fracture geometries,PRESSURE-TRANSIENT ANALYSIS; HORIZONTAL WELLS; CONDUCTIVITY,"Numerous micro-seismic and laboratorial studies show that hydraulic fracture is usually with complex geometries, such as plugged fracture, asymmetry and non-plane. It is a challenging task to recognize the complex fracture and obtain reliable fracture parameters through transient pressure analysis. In this work, we extend the semi-analytical model by Zhou a al. (2013) to analyze transient pressure behavior of a fractured vertical well with complex fracture geometries. We verified the semi-analytical model by a numerical reservoir simulator on a planar fracture. Then, based on this model, we made a systematical discussion about the transient pressure behavior of the planar fracture with varying conductivity, asymmetric fracture and non-planar fracture. Results show that when the fracture conductivity is varying along the fracture path, the influence of fracture zone conductivity on the transient pressure behavior gradually decreases with the distance from the wellbore growing. Besides, we found that the fracture asymmetry is against for the fluid flow in the fracture, and it decreases the slope of transient pressure behavior curve and enlarge pressure drop. In addition, the non-planar fracture is usually with severe fracture width restriction around the wellbore, which will induce pseudo-radial flow in the fracture at early times and large pressure drop in the fracture. Furthermore, the influences of varying conductivity, fracture asymmetry and non-plane on transient pressure behavior are obvious for fracture with average small-to-middle conductivity (average dimensionless fracture conductivity ranging from 0.1 to 50); the influences become negotiable for fracture with average high-to-infinite conductivity (average dimensionless fracture conductivity ranging from 50 to 1000). This work can provide critical insights into understanding the effect of complex fracture geometry on transient pressure behavior of fractured vertical well in tight oil reservoir.",1,2,0
Horizontal Wells,Hydraulic Fracture,"Wang, Dongying; Wang, Zhiming; Zeng, Quanshu",An experimental study on gas/liquid/solid three-phase flow in horizontal coalbed methane production wells,Gas/liquid/solid three-phase flow; Coalbed methane; Horizontal well; Flow pattern; Height of coal particle bed; Explicit equation,SAND-DEPOSITION VELOCITY; RESERVOIR ROCKS; LIQUID; GAS; PARTICLES; TRANSPORT,"Coal particles caused by well drilling and completion, hydraulic fracturing, and formation pressure decreasing would migrate into the horizontal well carried by fracturing flow-back fluid, formation water and CBM, and then deposit on the low side of pipe leading to the decrease of cross section area of pipe for flow and even blocking of the pipe. The purpose of current research was to obtain the flow pattern while there was stationary solid particle bed on the low side of the pipe and an explicit equation to predict the height of solid particle bed was proposed. In this study, with the coal particle, water, and air as the solid, liquid, and gas phases respectively, gas/liquid/ solid three-phase flow experiments in horizontal well were carried out and 4 crucial factors including different water flow rate, gas flow rate, coal particle size, and coal particle mass concentration were considered. Fluid's real apparent velocity was defined and used to analyze the distribution of flow pattern coordinate points. Results show that the flow pattern coordinate points determined by real gas apparent velocity and real water apparent velocity distribute near the flow pattern transition lines of Taitel and Dukler flow pattern map. Besides, coal particle size, water flow rate, and gas flow rate have obvious impact on the height of coal particle bed and the coal particle mass concentration has a negligible effect while the height of interface between gas layer and water layer is only dramatically affected by the gas flow rate. At last, an explicit equation for predicting the cross section area of coal particle bed based on the experimental data was proposed which is crucial to predict the flow pattern and calculate the pressure drop in horizontal well. The predicting cross section area of coal particle bed is in good agreement with the measured cross section area of coal particle bed and the average relative differences are 9.38% and 13.45% for stratified smooth flow and stratified wavy flow respectively. The equation is applicable for a range of coal particle size (8-30 mesh) and water apparent velocity (0.025-0.123 m/s).",2,2,4
Horizontal Wells,Hydraulic Fracture,"Chu, Hongyang; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Liu, Wenyuan",Estimating carbon geosequestration capacity in shales based on multiple fractured horizontal well: A case study,Multiple fractured horizontal well; CO2 geosequestration; Shale reservoirs; Semi-analytical method; Transient pressure response,TRANSIENT PRESSURE BEHAVIOR; ENHANCED GAS RECOVERY; STORAGE CAPACITY; CO2 STORAGE; NUMERICAL-SIMULATION; SEQUESTRATION; RESERVOIR; MODEL; FEASIBILITY; ADSORPTION,"Nowadays, shale reservoirs have been though as good candidates for CO2 geosequestration for reduction of carbon emission. When estimating the carbon geosequestration capacity, multiple fractured horizontal well (MFHW) is a prerequisite for consideration when shale reservoirs are included in candidate geological sites, as it is one of the critical factors for the successful development of shale reservoirs. In order to perfect our previous works, a new model is proposed to calculate the carbon geosequestration capacity of depleted shale reservoirs based on MFHW. The methodology calculates carbon geosequestration capacity of shale reservoirs by considering Knudsen diffusion, molecular diffusion, supercritical Langmuir adsorption, stimulated reservoir volume (SRV), and stress-sensitivity of the permeability. Utilizing the perturbation transformation technique, finite difference method, and Laplace transform technique, our method is more in accordance with the actual situations, allowing us to accurately estimate the carbon storage capacity by capturing the transient pressure response of the MFHW. A field case from the Ordos Basin in China presents that the CO2 geosequestration capacity is proportional to the dimensionless fracture half-length and conductivity. The properties of hydraulic fractures only affect the early period of the CO2 geosequestration process. For the adsorption coefficient and flow coefficient ratio, with the change of these parameters, the middle and late periods of the CO2 geosequestration process are mainly influenced.",2,2,4
Horizontal Wells,Hydraulic Fracture,"Ghosh, Sayantan; Busetti, Seth; Slatt, Roger M.",Analysis and prediction of stimulated reservoir volumes through hydraulic fracturing: Examples from western Arkoma Basin,,,"Geologic models built from well logs and natural fracture (NF) parameters obtained at shale and carbonate outcrops/quarries were employed in understand artificial hydraulic fracture (HF) propagation and stimulated reservoir volume (SRV) geometries. We applied field HF treatment parameters from an Arkoma Basin well, located 20-25 miles (32-40 km) east of the studied quarries. We matched the microseismic cloud (MC) geometries of three field stages, followed by sensitivity analyses of various HF treatment and reservoir parameters. Geometry matches reveal that the average NF permeability in the Viola Group Limestone is nearly eight times that in the Woodford Shale. The sensitivity analyses (forward modeling) disclosed several likely outcomes. First, a minor (5x10(-6)) increase in the minimum horizontal tectonic strain and ensuing increase in the minimum horizontal stress resulted in a sizeable transformation of the SRV geometry. Second, pumping at a higher net pressure (ISIP increased from 6500 to 7000 psi) diminished the stimulation volume and opened more previously non-dilatable NFs closer to the wellbore. Higher net pressure also triggered more stimulation downward and out of the target zone in the studied area. Third, halving the number of NFs and doubling their final storage apertures significantly magnified the fracturing-fluid efficiency (i.e., lowered leak off into NFs) in areas where it was restricted from flowing through non-dilatable NFs. Additionally, this modification caused greater lateral growth and comparatively large downward (out of target zone) growth of the HF and NF reactivation front, lowering the effectiveness of the HF job. However, halving the number of NFs and doubling their final storage apertures did not result in a substantial change in the SRV geometry upon allowing fluid flow through non-dilatable NFs. Fourth, altering the well-landing depth within the Woodford Shale did not result in a major shift in the overall stimulation geometry or volume. Most importantly, the simulated hydraulic fractures emanating from the wellbore do not span the entire recorded microseismic cloud length and height.",4,4,1
Horizontal Wells,Hydraulic Fracture,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Horizontal Wells,Hydraulic Fracture,"Hu, Xiaohu; Yu, Wei; Liu, Malin; Wang, Mingwei; Wang, Weihong",A multiscale model for methane transport mechanisms in shale gas reservoirs,Semi-analytical model; Complex hydraulic fractures; Shale gas; Multiple horizontal wells; Nanopores,HYDRAULIC-FRACTURE GEOMETRY; HORIZONTAL WELLS; PRODUCTION SIMULATION; SEMIANALYTICAL MODEL; COMPREHENSIVE MODEL; COMPLEX FRACTURES; FLOW; NETWORKS; PERMEABILITY,"We presented an efficient semi-analytical model-based analysis of methane transport in shale reservoirs including multiple horizontal wells with nanopores and complex hydraulic fractures. Multiple important gas transport mechanisms in nanopores such as gas desorption, gas slippage and diffusion and pressure-dependent fracture conductivity are fully incorporated in the model. Both simple and complex fractures in multiple shale-gas wells can be easily and effectively dealt with in accordance with the discretization approach, which does not require detailed gridding like numerical model. The superposition principle is utilized to capture the interactions between all fracture segments in order to accurately simulate real gas transport from matrix to fractures and finally from fractures to wellbores. We verified the semi-analytical model against a numerical compositional reservoir model for two shale-gas wells with multiple simple planar hydraulic fractures considering the gas desorption effect. The semi-analytical model was used to analyze ultimate gas recovery of different complex hydraulic fracture patterns in a two-well scenario, which were generated from a complex fracture propagation model with and without considering natural fractures. In addition, it was applied to perform field-scale simulation with multiple wells and complex fracture geometries in accordance with microseismic data. The simulation results show that multiple gas transport mechanisms, pressure-dependent fracture conductivity and complex fracture geometries play an important role in controlling well productivity and gas recovery, which should be properly accounted for in the physical model in order to achieve more accurate long-term production forecasting of multiple-fractured shale-gas horizontal wells.",5,6,1
Horizontal Wells,Measurement,"Gao, Jianshen; Rao, Liting",Analysis and comparison of azimuthal resistivity measurement modes for laterolog tool,Azimuthal resistivity measurement; Azimuthal electrode array; Adjustable current mode; Laterolog tool; Numerical simulation,MUD-FILTRATE INVASION; NUMERICAL-SIMULATION,"Though proposed previously, the azimuthal focusing modes applied to laterolog tool still need to be researched. A three-dimensional numerical simulation process is first applied to analyze the azimuthal resistivity measurement of deep measurement of dual laterolog tool adopting four modes, i.e., independent current-emitting mode, passive equipotential mode, independent current-adjusting mode and potential-measuring mode. Afterwards, three typical formation models, i.e., a formation model with a resistivity anomaly contacting the borehole wall, a formation model with a resistivity anomaly non-contacting the borehole wall and a formation model with asymmetrical horizontal or downward mud invasion in horizontal well, are developed to test the four modes and the integrated performances of the four modes are revealed. Two tests are carried out to test the independent current-adjusting mode. It has been demonstrated that overall the potential-measuring mode manifests the least ideal measured results, and it only possesses slightly qualitative measurement in the formation model with a resistivity anomaly non-contacting the borehole wall. The independent current-emitting mode can realize qualitative measurement in all the three formation models, but the measured azimuthal difference is indistinctive especially in the case of asymmetrical mud invasion in horizontal well. The passive equipotential mode exhibits an indigent effect, nevertheless it can quantitatively characterize the electrical difference in the formation model with a resistivity anomaly contacting borehole wall. The independent adjustable current mode is the optimum choice because it possesses the relatively perfect performance in all the three cases, especially in the extremely common asymmetrical mud invasion occurring in horizontal well. It has a relative measured error changing from 0.10% to 4.09% and can be adopted to uncover formation characteristics, and it should be the best azimuthal focusing mode employed by the laterolog tool for the azimuthal resistivity measurement.",0,0,4
Horizontal Wells,Measurement,"Premanadhan, V. K.; Hernandez-Perez, V; Teik, Wan Thiam; Nguyen Dinh Tam; Bratland, Ove; Loh, W. L.",Experimental investigation of interfacial waves in stratified liquid-liquid flows in horizontal pipelines: Characteristics and pressure gradients,Liquid-liquid flow; Interfacial waves; Interfacial friction factor; Pressure drop; Two-fluid model,FRICTION-FACTOR; 2-PHASE; EQUATION; REGIMES; HOLDUP; DROP,"The increasing use of commercial flow simulators in the oil and gas industry provides the impetus to accurately model multiphase flows in pipelines. The current work investigates stratified oil-water flows in horizontal pipelines by experimentally measuring interfacial deformations, correlating them to interfacial friction. The derived interfacial model is then implemented into the two-fluid model to predict pressure losses in pipelines. An experimental campaign was undertaken using process oil (rho = 845kg/m(3), mu = 0.03Pa. s) and water as the test fluids in acrylic pipes of 40 mm diameter, with objectives of capturing interfacial deformations via image processing techniques, while also measuring pressure gradients in the pipe. The interfacial deformations were seen to increase with increasing flow velocities, plateauing with wave amplitudes of 3 mm. Further tests with identical fluids, conducted on larger diameter pipes (54.8 mm and 108.4 mm) also showed similar trend. Wave aspect ratios were correlated with a modified Froude number, linking the interfacial deformations to input flow variables. An empirical equation, utilizing the amplitude of interfacial deformations as roughness heights is derived for the interfacial friction factor. Incorporating the derived equation into the one dimensional two-fluid model, pressure losses were calculated and compared against experimental pressure drop measurements conducted in current work, as well as with those in literature. The performance of this model is also compared with existing prediction models and is found to provide improved accuracies across wide range of viscosity ratios and pipe diameters.",2,2,0
Horizontal Wells,Measurement,"Zhang, Rui; Li, Yinghao; Yang, Bin; Jia, Zongyi; Zhang, Feng; Wang, Ruihe; Li, Na; Zhou, Xianhai",A segmenting method of long horizontal wellbore for staged sand control completion based on multi-dimension sequential clustering,Sand production; Staged completion; Multi-dimension sequential clustering; Critical wellbore pressure of sanding onset; Water breakthrough time,INFLOW-CONTROL DEVICES; GAS-RESERVOIRS; OPTIMIZATION; PRESSURE,"For horizontal well, the uniform measure of completion for sand control in the whole horizontal wellbore will cause local sand control failure or excessive sand control, even a decrease in production. An effective measure solved the problem is to segment long horizontal wellbore and conduct completion with staged sand control. In this paper, taking into consideration impacts of reservoir properties heterogeneity, the heel-toe effect of wellbore flow and the different distance between wellbore and water-oil contact (WOC) on sand production along long horizontal wellbore, the difference (CWP - p(wf)) between critical wellbore pressure of sanding onset (CWP) and wellbore flowing pressure (p(wf))and water breakthrough time (T) of each micro section of horizontal wellbore are used to make up vector components and selected as segmenting indexes, further mull-dimension sequential clustering method is employed to segment horizontal wellbore according to the principle of location contiguity and similarly of CWP - p(wf) and T between micro intervals. Then the segmenting method for sand control completion together with water control in horizontal wells is proposed. Furthermore, the segmentation method is utilized in investigating staged sand and water control in TP65 well of T block in Shengli Oilfield, and the optimal number and location of segments for the well are given. This research can provide a new theoretical and quantitative method for staged sand control completion in horizontal well. And it also can be regarded as a fundamental platform to investigate other kinds of wellbore staging problems, such as staged fracturing.",2,3,3
Horizontal Wells,Measurement,"Wang, Dongying; Wang, Zhiming; Zeng, Quanshu",An experimental study on gas/liquid/solid three-phase flow in horizontal coalbed methane production wells,Gas/liquid/solid three-phase flow; Coalbed methane; Horizontal well; Flow pattern; Height of coal particle bed; Explicit equation,SAND-DEPOSITION VELOCITY; RESERVOIR ROCKS; LIQUID; GAS; PARTICLES; TRANSPORT,"Coal particles caused by well drilling and completion, hydraulic fracturing, and formation pressure decreasing would migrate into the horizontal well carried by fracturing flow-back fluid, formation water and CBM, and then deposit on the low side of pipe leading to the decrease of cross section area of pipe for flow and even blocking of the pipe. The purpose of current research was to obtain the flow pattern while there was stationary solid particle bed on the low side of the pipe and an explicit equation to predict the height of solid particle bed was proposed. In this study, with the coal particle, water, and air as the solid, liquid, and gas phases respectively, gas/liquid/ solid three-phase flow experiments in horizontal well were carried out and 4 crucial factors including different water flow rate, gas flow rate, coal particle size, and coal particle mass concentration were considered. Fluid's real apparent velocity was defined and used to analyze the distribution of flow pattern coordinate points. Results show that the flow pattern coordinate points determined by real gas apparent velocity and real water apparent velocity distribute near the flow pattern transition lines of Taitel and Dukler flow pattern map. Besides, coal particle size, water flow rate, and gas flow rate have obvious impact on the height of coal particle bed and the coal particle mass concentration has a negligible effect while the height of interface between gas layer and water layer is only dramatically affected by the gas flow rate. At last, an explicit equation for predicting the cross section area of coal particle bed based on the experimental data was proposed which is crucial to predict the flow pattern and calculate the pressure drop in horizontal well. The predicting cross section area of coal particle bed is in good agreement with the measured cross section area of coal particle bed and the average relative differences are 9.38% and 13.45% for stratified smooth flow and stratified wavy flow respectively. The equation is applicable for a range of coal particle size (8-30 mesh) and water apparent velocity (0.025-0.123 m/s).",2,2,4
Horizontal Wells,Measurement,"Li, Zhan-dong; Pang, Hong; Xu, Jinze; Li, Zhong; Zhang, Hai-xiang; Liu, Yi-kun","Case study of sandbody architecture and quantitative parameters of the farsource sandy braided river: Saertu Oilfield, Daqing, China",Sandy braided river; Architecture parameters; Falling-siltseam; Physical simulation; Daqing oilfield,SEQUENCE STRATIGRAPHY; RESERVOIR ANALOG; BASIN; CHANNELS; HETEROGENEITY; DIMENSIONS; SANDSTONE; PATTERNS; ELEMENTS; SYSTEMS,"Aimed at the braided river sandbodies deposited in the pure oil area of western Saertu Oilfield in the Songliao Basin, Daqing, Placanticle, the sedimentary physical simulation experiments were designed. The characteristics of channel bar microfacies were identified and analyzed by four rounds of experiments. Based on the measurement results, the correlation parameter model of the braided river reservoir architecture was established by describing the geometric occurrence of the structures of the single-phase braided river sandbodies and channel bar. Combined with prototype sedimentation simulation experiment, the internal quantitative architecture of far-source sandy braided river was researched by identifying and analyzing the interface of individual well. The interfaces of the 5th-order, 4th-order and 3rd-order architectures were emphatically analyzed and the inter-well quantitative architecture model was established. The research results showed that the interlayer in the center of channel bar was approximately horizontal, with dip angle of about 1 degrees. In short-axis toward end direction, the dip angle of the architecture interface of accretionary body was 2-4 degrees. Combined with the internal dip angle and occurrence of channel bar sandbodies, the interface of the accretionary body in the central part of channel bar was parallel, with dip angle of no more than 2 degrees. The dip angle of the accretionary body in water flow direction was large, which was 2 degrees-5 degrees. On this basis, the size of braided river, channel bar and accretionary body was calculated quantitatively in the target area, and different orders of braided river sandstone reservoirs were described.",3,3,0
Horizontal Wells,Measurement,"Li, Xin; Gao, Deli; Lu, Baoping; Zeng, Yijin; Zhang, Jincheng",Study on modified maximum extension length prediction model for horizontal wells considering differential sticking,Horizontal well; Maximum extension length; Differential sticking; Drilling fluid density; Casing running down/pulling out speed,EXTENDED-REACH LIMIT,"Maximum extension length prediction model for horizontal wells can be used to evaluate the horizontal well's extension capability and predict its maximum measured depth, which is of great significance to the production and economic benefits of horizontal wells. However, the differential sticking is not considered in previous prediction model. To overcome this shortcoming, a modified model considering differential sticking is established based on constraints of wellbore stability, differential pressure, and filtration loss simultaneously during the drilling, tripping processes and static state. Then a horizontal well is analyzed and its maximum extension length is predicted. Results show that within the conventional mud weight window, three ranges of drilling fluid density can be determined, including the first range, the second range and the reasonable range of drilling fluid density. However, only the reasonable range of drilling fluid density can satisfy all constraints of the modified prediction model, including the wellbore stability, differential pressure, and filtration loss simultaneously. Compared with the original model, the predicted well's maximum extension length decreases when the differential sticking is considered. However, it is more accurate, avoiding drilling hazards in actual drilling operation due to the excessive designed measured depth and unreasonable drilling parameters. Moreover, the maximum speeds of casing running down/pulling out are also determined and added to the modified model. Therefore, the modified model with reasonable drilling fluid density and adjusted running down/pulling out speed is the optimal modified model to predict maximum extension length and avoid differential sticking, which can also ensure that the horizontal well's designed measured depth can be successfully achieved. This study is of great significance to improve the prediction accuracy of horizontal well's maximum extension length and avoid drilling hazards, especially the differential sticking. Moreover, it also plays a guiding role in the selection of reasonable drilling fluid density during horizontal drilling.",3,4,3
Horizontal Wells,Measurement,Xi Yan; Li Jun; Zha Chunqing; Guo Boyun; Liu Gonghui,A new investigation on casing shear deformation during multistage fracturing in shale gas wells based on microseism data and calliper surveys,Multistage fracturing; Shear deformation; Finite-element; Microseismic; Multi-finger callipe,PRESSURE; VOLUME,"Casing shear deformation has become a serious problem in the development of shale gas fields, which is believed to relate to fault slipping caused by multistage fracturing. This paper presents a new investigation aiming at understanding the reduction of casing inner diameter after fault slipping under different conditions, according to microseism data and calliper surveys. A mathematical model, which was verified by measurement results, was established to build a relationship between microseism moment magnitude and slip distance. A 3D numerical model, which was verified by physical model experiments, was developed to quantify the relationships between slip distance and the reduction of casing inner diameter. And then the relationships among microseism moment magnitude, slip distance and the reduction of casing inner diameter were established. The influence of casing internal pressure, slip distance, mechanical parameters of cement sheath, and casing thickness on the reduction of casing inner diameter was analyzed. The mathematical calculation results showed that with the increase of the degree of moment magnitude, the radius and slip distance increase, and with the increase of stress drop, the radius decreases and the slip distance increases. The numerical analysis results showed maintaining high pressure, increasing the elasticity modulus and decreasing the Passion ratio of cement sheath and increasing the casing thickness were beneficial to decrease the reduction of casing inner diameter. Keeping the designed horizontal segment of well trajectory away from the fracture-developed area, or be parallel to natural fracture can decrease the slip distance of fault, which can decrease the reduction of casing inner diameter. Finally, some effective measures to reduce or prevent casing shear deformation were recommended.",4,8,3
Horizontal Wells,Measurement,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Horizontal Wells,Well Testing,"Gao, Jianshen; Rao, Liting",Analysis and comparison of azimuthal resistivity measurement modes for laterolog tool,Azimuthal resistivity measurement; Azimuthal electrode array; Adjustable current mode; Laterolog tool; Numerical simulation,MUD-FILTRATE INVASION; NUMERICAL-SIMULATION,"Though proposed previously, the azimuthal focusing modes applied to laterolog tool still need to be researched. A three-dimensional numerical simulation process is first applied to analyze the azimuthal resistivity measurement of deep measurement of dual laterolog tool adopting four modes, i.e., independent current-emitting mode, passive equipotential mode, independent current-adjusting mode and potential-measuring mode. Afterwards, three typical formation models, i.e., a formation model with a resistivity anomaly contacting the borehole wall, a formation model with a resistivity anomaly non-contacting the borehole wall and a formation model with asymmetrical horizontal or downward mud invasion in horizontal well, are developed to test the four modes and the integrated performances of the four modes are revealed. Two tests are carried out to test the independent current-adjusting mode. It has been demonstrated that overall the potential-measuring mode manifests the least ideal measured results, and it only possesses slightly qualitative measurement in the formation model with a resistivity anomaly non-contacting the borehole wall. The independent current-emitting mode can realize qualitative measurement in all the three formation models, but the measured azimuthal difference is indistinctive especially in the case of asymmetrical mud invasion in horizontal well. The passive equipotential mode exhibits an indigent effect, nevertheless it can quantitatively characterize the electrical difference in the formation model with a resistivity anomaly contacting borehole wall. The independent adjustable current mode is the optimum choice because it possesses the relatively perfect performance in all the three cases, especially in the extremely common asymmetrical mud invasion occurring in horizontal well. It has a relative measured error changing from 0.10% to 4.09% and can be adopted to uncover formation characteristics, and it should be the best azimuthal focusing mode employed by the laterolog tool for the azimuthal resistivity measurement.",0,0,4
Horizontal Wells,Well Testing,"Jin, Licong; Tao, Lei; Li, Decai",Injection fall-off analysis and interpretation of horizontal wells in polymer flooding,Fall-off test; Type curve; Polymer flooding; Horizontal well; EOR,PRESSURE DERIVATIVE ANALYSIS,"Petrocedeno is located in the southeast of Venezuela, which is an onshore heavy oil field with average viscosity about 5000 cP. In order to increase the oil recovery, polymer injection is planning in the pilot. The fall-off test, one approach to analyse the polymer properties in reservoirs directly, is also planned after polymer injection. In order to investigate whether fall-off test could provide sensible data for injection of Non-Newtonian fluids in horizontal wells and hence establish an optimal strategy for implementing such test, simulation work and analytical studies have been performed in this paper. The aim of this paper has been to analyse polymer fall-off interpretation method in Petrocedeno, and then to provide feasible suggestion or guidance for polymer fall-off implementation in the real pilot where the injection wells are horizontal.",1,1,1
Horizontal Wells,Well Testing,"Premanadhan, V. K.; Hernandez-Perez, V; Teik, Wan Thiam; Nguyen Dinh Tam; Bratland, Ove; Loh, W. L.",Experimental investigation of interfacial waves in stratified liquid-liquid flows in horizontal pipelines: Characteristics and pressure gradients,Liquid-liquid flow; Interfacial waves; Interfacial friction factor; Pressure drop; Two-fluid model,FRICTION-FACTOR; 2-PHASE; EQUATION; REGIMES; HOLDUP; DROP,"The increasing use of commercial flow simulators in the oil and gas industry provides the impetus to accurately model multiphase flows in pipelines. The current work investigates stratified oil-water flows in horizontal pipelines by experimentally measuring interfacial deformations, correlating them to interfacial friction. The derived interfacial model is then implemented into the two-fluid model to predict pressure losses in pipelines. An experimental campaign was undertaken using process oil (rho = 845kg/m(3), mu = 0.03Pa. s) and water as the test fluids in acrylic pipes of 40 mm diameter, with objectives of capturing interfacial deformations via image processing techniques, while also measuring pressure gradients in the pipe. The interfacial deformations were seen to increase with increasing flow velocities, plateauing with wave amplitudes of 3 mm. Further tests with identical fluids, conducted on larger diameter pipes (54.8 mm and 108.4 mm) also showed similar trend. Wave aspect ratios were correlated with a modified Froude number, linking the interfacial deformations to input flow variables. An empirical equation, utilizing the amplitude of interfacial deformations as roughness heights is derived for the interfacial friction factor. Incorporating the derived equation into the one dimensional two-fluid model, pressure losses were calculated and compared against experimental pressure drop measurements conducted in current work, as well as with those in literature. The performance of this model is also compared with existing prediction models and is found to provide improved accuracies across wide range of viscosity ratios and pipe diameters.",2,2,0
Horizontal Wells,Well Testing,"Li, Zhenglan; Duan, Yonggang; Wei, Mingqiang; Peng, Yu; Chen, Qingxuan",Pressure performance of interlaced fracture networks in shale gas reservoirs with consideration of induced fractures,Interlaced fracture networks; Shale gas; Secondary induced fractures; Flux distribution; Pressure performance,HORIZONTAL WELLS; SEMIANALYTICAL MODEL; TRANSIENT PRESSURE; METHANE; FLOW; PERMEABILITY; MECHANISMS; ADSORPTION; BEHAVIOR,"Multi-stage fracturing in shale gas reservoirs may create complex fracture network around horizontal wellbore, due to the widely-distributed natural fractures. However, little work has been done to investigate the effects of secondary fractures on well testing models for shale gas reservoirs. In this paper, a more comprehensive model was developed for interlaced fracture networks in shale gas reservoirs with consideration of multiple transport mechanisms and different flow states. By employing the source function and Laplace transformation, the line sink solutions for four kinds of flow states were unified. Based on the discretization method and unified line sink solution, the pressure responses for interlaced fracture networks with infinite conductivity were obtained. Type curves were plotted and typical flow regimes of this model were identified. In order to have a further understanding of the effect of induced fractures, the slope curves of pseudo-pressure derivative were introduced to analyze the interference between fractures. The influences of the angel and the length of induced fractures on the well testing curves were simulated by the semi-analytical model for the first time. Then, the flux distributions of interlaced fracture networks were simulated and discussed for achieving significant advice. Finally, the proposed model was verified by a simplified case and a field case. The presented model will be helpful for understanding the transient performance of multi-stage fractured horizontal wells with consideration of induced fractures.",3,3,0
Horizontal Wells,Well Testing,"Sureshjani, Mohammadhossein Heidari; Ahmadi, Mohammad; Fahimpour, Jalal",A generalized approach for fast estimation of reservoir permeability distribution from analysis of pressure transient data,Pressure transient analysis; Permeability heterogeneity map; Inverse problem,GRADUAL DEFORMATION; WELL,"Estimation of permeability variation from analysis of pressure transient data is very challenging. Such problem may not have a unique solution and cannot be analyzed with classic well-test models. The available models for fast estimation of permeability map are restricted to several assumptions such as existence of pure radial or linear flow in an infinite medium. Such assumptions may be violated in real applications. To handle pressure transient analysis in heterogeneous reservoirs, more flexible models are needed to be applicable for majority of real well tests. In this work, a generalized approach is developed to estimate reservoir permeability variation from analysis of pressure transient data. For non-radial flow regimes, we show that the permeability rings should be defined non-circular. In flow geometries other than radial, we may not be able to use radius of investigation. Accordingly, we propose the use of pressure drop at the boundary of region of investigation instead. The average permeability in non-circular rings can produce satisfactory derivative predictions. Inspired by this observation, we developed an inverse procedure to estimate equivalent average permeability along with appropriate inner and outer ring boundaries. After estimation of equivalent permeabilities from the inverse procedure, the 2D permeability map is estimated through a minimization process. The defined objective function represents the difference of geometric average of realizations and equivalent average permeabilities from the inverse procedure. Using such form of definition, there is no need to perform any flow simulation during minimization process. We applied the procedure to back calculate the permeability variation around a horizontal well from analysis of its pressure derivative data. In addition, the uncertainty of the estimation and prediction was evaluated. The results reveal the strength of the proposed methodology for pressure transient analysis of heterogeneous reservoirs.",3,3,0
Horizontal Wells,Well Testing,"Nie, Ren-Shi; Zhou, Hao; Chen, Zhangxin; Guo, Jian-Chun; Xiong, Yu; Chen, Yang-Yang; He, Wen-Fa",Investigation radii in multi-zone composite reservoirs,Investigation radius; Composite reservoir; Well test; Pressure wave,FRACTURED VERTICAL WELL; HORIZONTAL WELL; DIFFUSIVE LEAKAGE; FLOW; BEHAVIOR; TESTS; CONDUCTIVITY; AQUIFERS; MODEL,"In petroleum reservoir engineering, an investigation radius is a basic, practical and meaningful parameter to evaluate the controlled area of a well. The investigation radius in homogeneous reservoirs is usually calculated by an explicit function related to the square root of time. At present, no research on investigation radii in multi-zone composite reservoirs has been found in the literature. In this work, first, we presented an application problem for which the commercial software Saphir cannot interpret an investigation radius in multi-zone composite reservoirs. Then, based on the investigation radius in homogeneous reservoirs, we firstly derived a calculation formula for the investigation radius in a multi-zone composite reservoir by the assumption of homogeneous properties in each zone. Compared with the formula for homogeneous reservoirs, the formula for multi-zone composite reservoirs is more complicated and shows a nonlinear implicit function in time. By use of the newly derived formula of the investigation radius, given a group of reservoir parameters, we numerically calculated the dynamical investigation radii with the elapse of time for both 2-zone and 3-zone composite reservoirs. Accordingly, we plotted a series of relationship curves for the investigation radii with time affected by model parameters, such as permeability, porosity and total compressibility. The relationship curves obviously show the multi-zone properties of a reservoir. The relationship curves of N-zone composite reservoirs can reflect (N-1) inflection points and an inflection point represents a response of pressure wave to an interface between two neighboring zones. Finally, we used real reservoir parameters from an example well in a 2-zone composite reservoir to calculate the investigation radius. In summary, the newly derived formulas have been shown in this work to be a convenient and practical new tool to calculate the investigation radii in composite reservoirs.",4,4,3
Horizontal Wells,Well Testing,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Horizontal Wells,Well Testing,"Liu, Changwei; Li, Kewen; Tian, Xiaoming; Zhao, Guoxiang; Chen, Youguang; Mahlalela, B. M.",Experimental studies on production performance of oil reservoirs with bottom water,Bottom-water reservoir; Horizontal well; Physical model; Optimal production pressure,LEG,"Water coning is a major problem in oil reservoirs with bottom water. It reduces the oil production and overall oil recovery. Excessive water production causes corrosion problems in production facilities and increases the cost of water disposal. This may cause the early shutdown of oil wells. In this study, an experimental apparatus has been designed and developed to physically model an oil reservoir with bottom water. The reservoir model was transparent and the change in water coning could be visualized. Many water-flooding tests were conducted at different pressures and oil viscosities ranging from 22 to 260 mPa s. The effects of production pressures and oil viscosity on oil production were investigated. The results indicated that for a medium oil viscosity of 74 mPa s, the optimal production pressure was about 0.054 bar. For minimum and maximum oil viscosity (22 mPa s and 260 mPa s), the smaller the production pressure, the larger the water breakthrough time and oil recovery. Five types of flooding characteristic curves were used to characterize the water-cut variation, and their applicability were compared and analyzed. The water drive curves were fitted using the water-cut models and the oil ""reserves"" (originally placed in the reservoir model) were predicted using the mathematical models with the experimental data. The results indicated that the Maksimov model of water-drive characteristic curve is more suitable to match the water production performance. Most interestingly, when applying the most suitable model Maksimov water-drive characteristic curve to predict oil reserves, the cases with optimal production pressures have a greater accuracy.",5,5,0
Horizontal Wells,Stress,"Li, Yaohua; Song, Yan; Jiang, Shu; Jiang, Zhenxue; Yang, Wei; Wang, Qianyou; Liu, Dan",Tight reservoir oiliness numerical simulation based on a Markov chain Monte Carlo (MCMC) method: A case study of the upper Triassic Yanchang-6 formation (T(3)ch(6) Fm.) outcrop of Ordos Basin,Reservoir oiliness; Fractures; Lithofacies; Bayesian; MCMC,FRACTURED HORIZONTAL WELL; UNCERTAINTY QUANTIFICATION; WESTERN INTERIOR; ORGANIC-MATTER; STRATIGRAPHY; PRESSURE; MODEL; BAYES; FLOW,"Numerical simulation of the tight reservoir oiliness has always been an important issue in tight oil resources exploration. It is hard to take some special situations into simulations such as the micro-nano thermodynamic system, the multi-fluid phase behavior, and the superimposed tectonic stress field of tight oil reservoirs. In our research, we use MCMC methods to simulate the tight reservoir oiliness constrained by some visualized, spatial-related and interacted geological parameters based on the statistic Bayesian theory, instead of taking the complicated accumulation mechanism into consideration. In this research, we built a posterior probability density distribution (Post-PDD) matrix using the spatial relation between oiliness, fracture, and lithofacies parameters of a typical Yanchang tight oils outcrop. In the simulation, one Monte Carlo Step (MCS) was settled N = 80 x 36 x 5000, where 80 and 36 represent the horizontal and longitude grid number respectively, and 5000 represents the sampling times for each grid. In total, simulations of 50000 MCSs were made for each realization. For the simulation results, the variation in the fluctuating trends of the fitted and actual values matched well with the analytic variogram for the MCMC realizations. Additionally, we found that the simulation uncertainty was consistent with the reservoir heterogeneity. Even though the lamina, intercalation or the barrier was not defined in the grid model, the oiliness realization of the different types was remarkably consistent with the reservoir heterogeneity, which may be caused by the sedimentary rhythm similitude between different scale sedimentary cycles, particularly in the lacustrine tight reservoir.",1,1,1
Horizontal Wells,Stress,"Scelsi, G.; De Bellis, M. L.; Pandolfi, A.; Musso, G.; Della Vecchia, G.",A step-by-step analytical procedure to estimate the in-situ stress state from borehole data,In situ stress; Borehole; Breakout failure; Tensile failure; Rock mechanics; Analytical procedure,WELL; MAGNITUDE; MODEL; PERMEABILITY; ORIENTATION; STABILITY; BREAKOUTS; FAILURE; DAMAGE; SEA,"Knowledge of the in situ stress state of rock mass is fundamental for engineering, geological and geophysical applications. In situ stress state determination requires in principle the evaluation of the three principal stresses and the related principal directions, but it is widely recognized in the literature that the maximum horizontal stress is the most difficult component to accurately estimate. In the context of borehole methods, this paper proposes a step-by-step analytical procedure to estimate some bounds to the maximum horizontal stress, starting from a geomechanical description of the rock and relying on information generally available in the engineering practice. The procedure is divided in substeps, each one requiring additional information about the mechanical properties of the rock and on the geometrical properties of the failed portion of rock: more information available implies a lower uncertainty on in situ stress estimate. Furthermore, since the proposed procedure is analytical, it allows a complete and very easy implementation in a spreadsheet. The aim of the work is thus to provide a rigourous but simple analytical tool that can be used in engineering practicte to estimate some bounds to the maximum horizontal in situ stress state. The approach is finally validated by means of both numerical simulations, performed with a sophisticated numerical tool, and experimental field data coming from the literature.",3,3,0
Horizontal Wells,Stress,"Ghosh, Sayantan; Busetti, Seth; Slatt, Roger M.",Analysis and prediction of stimulated reservoir volumes through hydraulic fracturing: Examples from western Arkoma Basin,,,"Geologic models built from well logs and natural fracture (NF) parameters obtained at shale and carbonate outcrops/quarries were employed in understand artificial hydraulic fracture (HF) propagation and stimulated reservoir volume (SRV) geometries. We applied field HF treatment parameters from an Arkoma Basin well, located 20-25 miles (32-40 km) east of the studied quarries. We matched the microseismic cloud (MC) geometries of three field stages, followed by sensitivity analyses of various HF treatment and reservoir parameters. Geometry matches reveal that the average NF permeability in the Viola Group Limestone is nearly eight times that in the Woodford Shale. The sensitivity analyses (forward modeling) disclosed several likely outcomes. First, a minor (5x10(-6)) increase in the minimum horizontal tectonic strain and ensuing increase in the minimum horizontal stress resulted in a sizeable transformation of the SRV geometry. Second, pumping at a higher net pressure (ISIP increased from 6500 to 7000 psi) diminished the stimulation volume and opened more previously non-dilatable NFs closer to the wellbore. Higher net pressure also triggered more stimulation downward and out of the target zone in the studied area. Third, halving the number of NFs and doubling their final storage apertures significantly magnified the fracturing-fluid efficiency (i.e., lowered leak off into NFs) in areas where it was restricted from flowing through non-dilatable NFs. Additionally, this modification caused greater lateral growth and comparatively large downward (out of target zone) growth of the HF and NF reactivation front, lowering the effectiveness of the HF job. However, halving the number of NFs and doubling their final storage apertures did not result in a substantial change in the SRV geometry upon allowing fluid flow through non-dilatable NFs. Fourth, altering the well-landing depth within the Woodford Shale did not result in a major shift in the overall stimulation geometry or volume. Most importantly, the simulated hydraulic fractures emanating from the wellbore do not span the entire recorded microseismic cloud length and height.",4,4,1
Horizontal Wells,Stress,Xi Yan; Li Jun; Zha Chunqing; Guo Boyun; Liu Gonghui,A new investigation on casing shear deformation during multistage fracturing in shale gas wells based on microseism data and calliper surveys,Multistage fracturing; Shear deformation; Finite-element; Microseismic; Multi-finger callipe,PRESSURE; VOLUME,"Casing shear deformation has become a serious problem in the development of shale gas fields, which is believed to relate to fault slipping caused by multistage fracturing. This paper presents a new investigation aiming at understanding the reduction of casing inner diameter after fault slipping under different conditions, according to microseism data and calliper surveys. A mathematical model, which was verified by measurement results, was established to build a relationship between microseism moment magnitude and slip distance. A 3D numerical model, which was verified by physical model experiments, was developed to quantify the relationships between slip distance and the reduction of casing inner diameter. And then the relationships among microseism moment magnitude, slip distance and the reduction of casing inner diameter were established. The influence of casing internal pressure, slip distance, mechanical parameters of cement sheath, and casing thickness on the reduction of casing inner diameter was analyzed. The mathematical calculation results showed that with the increase of the degree of moment magnitude, the radius and slip distance increase, and with the increase of stress drop, the radius decreases and the slip distance increases. The numerical analysis results showed maintaining high pressure, increasing the elasticity modulus and decreasing the Passion ratio of cement sheath and increasing the casing thickness were beneficial to decrease the reduction of casing inner diameter. Keeping the designed horizontal segment of well trajectory away from the fracture-developed area, or be parallel to natural fracture can decrease the slip distance of fault, which can decrease the reduction of casing inner diameter. Finally, some effective measures to reduce or prevent casing shear deformation were recommended.",4,8,3
Horizontal Wells,Stress,"Ma, Yongfeng; Yu, Rangang",New analytical methods to evaluate uncertainty of wellbore stability,Wellbore stability; Uncertainty evaluation; Analytical model; Monte Carlo method; Sensitivity analysis,FAILURE CRITERIA; STRENGTH CRITERIA; LOGGING PROBLEMS; MODEL; COULOMB; ROCKS; LIMIT,"The uncertainties of the inputting parameters lead to the uncertainty of the wellbore stability. In view of this, two analytical methods were proposed to address the problem, based on second order Taylor series expansion and Rosenbluthe method. Using two analytical methods, the collapse and fracture pressures were calculated in the form of the probability distribution. To accomplish the calculation above, the mean and standard deviation of input parameters were firstly determined based on well log data. Especially, a new method of sensitivity analysis was proposed to quantify the effect of the input parameter on the uncertainty of the wellbore stability, through the way that one parameter changes the uncertainty while other parameters keep initial uncertainties. Additionally, two analytical methods were validated by Monte Carlo simulation. The results show that the probability distributions agree very well between analytical methods and Monte Carlo method. According to the new method of sensitivity analysis, the horizontal maximum stress is the most sensitive parameter for the collapse pressure, and the horizontal minimum stress has the maximum effect on the fracture pressure.",5,6,1
Horizontal Wells,Stress,"Albattat, Rami; Hoteit, Hussein",Modeling yield-power-law drilling fluid loss in fractured formation,Lost-circulation; Loss of drilling fluid; Mud loss; Flow in fractured formation; Yield power law; Herschel-Buckley; Cauchy momentum equation; Fracture ballooning,MATERIAL SELECTION GUIDELINES; PERFORMANCE; FLOW,"Loss of circulation during drilling is a pressing problem that typically occurs when significant volumes of the drilling fluid leak to the surrounding formation. In fractured media, circulation loss is often a sudden event which may interrupt the drilling operations, increase nonproductive time, and add complexity in controlling the fluid flow and wellbore stability. Developing models to predict the fluid leak dynamics and identify the suitable loss-control-material (LCM) is of significant interest to the industry. In this work, simulation and analytical models are developed to model the dynamics of fluid loss for power-law drilling fluids from the wellbore to a surrounding fractured medium. The model is based on the Cauchy momentum equation and accounts for the key predominant flow mechanisms, including the non-Newtonian behavior of the drilling fluid (mud) using a power-law model. Experiments from the literature are used to assess the behavior of mud loss into a single horizontal fracture, which includes the effects of mud rheology and yield stress. We show that previous unsuccessful attempts to match the experimental data using analytical models are related to the assumption of uniform fracture aperture. Simulations are then used to demonstrate that a slight deformation in the fracture walls leads to a significant deviation in the analytical model predictions, and therefore the dynamics of fracture opening is a critical parameter that should be carefully assessed. In other related experiments, the analytical model also failed to capture the mud invasion distance within the fracture as a function of pressure drop and the mud properties. To address this issue, a modified analytical model that accounts for non-parallel fracture walls is proposed. The new model allows to quickly assessing the impact of nonuniform fracture apertures. It can serve as a screening tool to evaluate mud invasion distance as a function of fracture geometry, mud rheological properties, and pressure drop resulting from the well depth, injection rate, and mud density.",5,5,3
Horizontal Wells,Fracture Networks,"Zhang, Jiali; Liao, Xinwei; Chen, Zhiming; Zhao, Xiaoliang; Gao, Jian",A weak fluid supply model for transient pressure analysis in vertically fractured wells from tight gas reservoirs: A case study,Unconventional reservoirs; Weak fluid supply; Vertically fractured well; Pressure transient behaviors; Case study; Parameter estimation,SEMIANALYTICAL MODEL; HORIZONTAL WELLS; BEHAVIOR; NETWORKS,"An interesting phenomenon of weak fluid supply (WFS) has been observed in tight gas reservoirs from the Ordos Basin. To facilitate parameters evaluation and productivity estimations of those well, this paper presents a new WFS model for transient pressure analysis in vertically fractured wells from tight gas reservoirs. In the new model, a WFS pressure and a WFS index are first introduced to describe the weak fluid supply boundary. Based on that, a mathematical model is developed with considering WFS, finite-conductivity fractures, and stress-sensitive effect. Using perturbation transformation method and semianalytical method, the proposed mathematical model is solved with effects of wellbore storage and skin factor. Following that, the model verification, sensitivity study, and field application are performed. Results shows that the WFS causes a rapid drop after ""hump"" at the late stage in the pressure curves. The start time of ""hump"" decreases as the WFS index increases. When the WFS pressure is bigger than zero, the pressure derivative curves exhibit a significant ""hump"", and it is more obvious with the increase in the WFS pressure. When the WFS pressure is equal to zero, the pressure derivative curves directly drop, which is assemble to the effect of constant pressure boundary. When the WFS index is zero, the pressure derivative curve in the late period is a unit-slope line, demonstrating a closed boundary effect. The field application in the well Z1 from the Ordos Basin shows that a ""hump"" caused by WFS does appears at the late stage in the pressure curves. By using the WFS model, the estimated reservoir permeability and drainage radius are 0.524 mD and 451.68 m. The WFS pressure and WFS index are respectively estimated as 0.13 and 0.022 by the WFS model. It demonstrates the applicability of the new proposed WFS model, which also provides a good understanding of transient pressure behaviors and accurate estimation of reservoir parameters for fractured wells with WFS.",1,1,1
Horizontal Wells,Fracture Networks,"Li, Zhenglan; Duan, Yonggang; Wei, Mingqiang; Peng, Yu; Chen, Qingxuan",Pressure performance of interlaced fracture networks in shale gas reservoirs with consideration of induced fractures,Interlaced fracture networks; Shale gas; Secondary induced fractures; Flux distribution; Pressure performance,HORIZONTAL WELLS; SEMIANALYTICAL MODEL; TRANSIENT PRESSURE; METHANE; FLOW; PERMEABILITY; MECHANISMS; ADSORPTION; BEHAVIOR,"Multi-stage fracturing in shale gas reservoirs may create complex fracture network around horizontal wellbore, due to the widely-distributed natural fractures. However, little work has been done to investigate the effects of secondary fractures on well testing models for shale gas reservoirs. In this paper, a more comprehensive model was developed for interlaced fracture networks in shale gas reservoirs with consideration of multiple transport mechanisms and different flow states. By employing the source function and Laplace transformation, the line sink solutions for four kinds of flow states were unified. Based on the discretization method and unified line sink solution, the pressure responses for interlaced fracture networks with infinite conductivity were obtained. Type curves were plotted and typical flow regimes of this model were identified. In order to have a further understanding of the effect of induced fractures, the slope curves of pseudo-pressure derivative were introduced to analyze the interference between fractures. The influences of the angel and the length of induced fractures on the well testing curves were simulated by the semi-analytical model for the first time. Then, the flux distributions of interlaced fracture networks were simulated and discussed for achieving significant advice. Finally, the proposed model was verified by a simplified case and a field case. The presented model will be helpful for understanding the transient performance of multi-stage fractured horizontal wells with consideration of induced fractures.",3,3,0
Horizontal Wells,Fracture Networks,"Tang, Xuefeng; Chen, Zhiming; Chu, Hongyang; Liao, Xinwei; Chen, Haoshu; Zhang, Jiali",Well testing interpretation for horizontal well with hydraulic fractures and interconnected micro-fractures,Shale oil; Well testing; Complex fracture networks: fractured horizontal well,,"As hydraulic fracturing technology has been widely used in practices, drilling a fractured horizontal well (FHW) is a common measure to improve the ultimate recovery of shale oil reservoirs. Many microseismic data show that multi-scale fracture networks can be generated along those FHW, including hydraulic fracture networks and natural fracture networks. The hydraulic fracture networks are comprised of hydraulic fractures (HF) and interconnected micro-fractures (IMF). To facilitate the productivity estimation, the first and primary work is to analyze the transient pressure responses of those wells. However, due to the complex geometries of HF and IMF, analyzing the pressure responses of those FHW is challenging. Thus, lots of work need to be done. In this paper, a well testing model of FHW is developed with the hydraulic fracture networks and natural fracture networks using a semi-analytical approach. The semi-analytical approach is presented by discretizing both HF and IMF into fracture segments. The Laplace transformation, source function, and superposition principle are used to solve the well testing model. With model solutions, we can obtain the pressure response of the FHW. Then, a numerical verification is presented to verify the reliability of the proposed model. Sensitivity analysis is also conducted to study the impacts of different parameters on the pressure responses. Finally, we use this model to perform a type-curve matching and evaluate the stimulation effectiveness on an actual well from the Jimusar Sag. The results show that pressure response of a FHW with complex fracture networks can be divided into six flow regimes, including: (1) first bilinear flow, (2) ""IMF-HF"" support, (3) second bilinear flow, (4) formation linear flow, (5) crossflow from matrix to natural fracture networks, and (6) pseudo radial flow. Sensitivity analysis shows that with the increase of HF number, HF length, or HF conductivity, the phenomenon of ""IMF-HF"" support becomes weaker. With the increase of the IMF number, IMF length, or IMF conductivity, the phenomenon of ""IMF-HF"" support becomes stronger. Different flow regimes have different features, which provides a good guideline for parameter estimation of fracture networks.",4,4,4
Horizontal Wells,Fracture Networks,"Hu, Xiaohu; Yu, Wei; Liu, Malin; Wang, Mingwei; Wang, Weihong",A multiscale model for methane transport mechanisms in shale gas reservoirs,Semi-analytical model; Complex hydraulic fractures; Shale gas; Multiple horizontal wells; Nanopores,HYDRAULIC-FRACTURE GEOMETRY; HORIZONTAL WELLS; PRODUCTION SIMULATION; SEMIANALYTICAL MODEL; COMPREHENSIVE MODEL; COMPLEX FRACTURES; FLOW; NETWORKS; PERMEABILITY,"We presented an efficient semi-analytical model-based analysis of methane transport in shale reservoirs including multiple horizontal wells with nanopores and complex hydraulic fractures. Multiple important gas transport mechanisms in nanopores such as gas desorption, gas slippage and diffusion and pressure-dependent fracture conductivity are fully incorporated in the model. Both simple and complex fractures in multiple shale-gas wells can be easily and effectively dealt with in accordance with the discretization approach, which does not require detailed gridding like numerical model. The superposition principle is utilized to capture the interactions between all fracture segments in order to accurately simulate real gas transport from matrix to fractures and finally from fractures to wellbores. We verified the semi-analytical model against a numerical compositional reservoir model for two shale-gas wells with multiple simple planar hydraulic fractures considering the gas desorption effect. The semi-analytical model was used to analyze ultimate gas recovery of different complex hydraulic fracture patterns in a two-well scenario, which were generated from a complex fracture propagation model with and without considering natural fractures. In addition, it was applied to perform field-scale simulation with multiple wells and complex fracture geometries in accordance with microseismic data. The simulation results show that multiple gas transport mechanisms, pressure-dependent fracture conductivity and complex fracture geometries play an important role in controlling well productivity and gas recovery, which should be properly accounted for in the physical model in order to achieve more accurate long-term production forecasting of multiple-fractured shale-gas horizontal wells.",5,6,1
Horizontal Wells,Horizontal Section,"Li, Xin; Gao, Deli; Lu, Baoping; Zeng, Yijin; Ding, Shidong; Zhou, Shiming",A prediction model of the shortest drilling time for horizontal section in extended-reach well,Shortest drilling time; Extension ability; Horizontal section; Maximum ROP; Drilling safety; Economic benefits,LIMIT,"Drilling the horizontal extended-reach well (ERW) with the shortest time is of great significance for drilling safety, efficiency and economic benefits. Moreover, the reservoir damage can be reduced or eliminated only when the well's horizontal section is drilled fast enough. In this paper, considering the effects of horizontal well's extension ability on the rate of penetration (ROP) and tripping in/out velocity, a prediction model of the shortest drilling time for horizontal section in ERW is established. The horizontal ERW Z-42 is analyzed, predicting its shortest drilling time in horizontal section. Results show that the predicted shortest drilling time is mainly dependent on its maximum ROP and maximum tripping in/out velocity in horizontal section. Specifically, the maximum ROP must satisfy four constraints, and the predicted maximum tripping in/out velocity must meet three constraints. Moreover, the predicted shortest time of drilling process in horizontal section is very close to the actual time in Z-42 well. In addition, the actual ROP and tripping in/out velocity in horizontal section should be as close as possible but strictly less than the predicted maximum ROP and maximum tripping in/out velocity to avoid drilling hazards. The shortest drilling time is not fixed and can be predicted in real time. Furthermore, in order to reduce the drilling time, it is necessary to reduce the times of tripping as much as possible to shorten the total drilling time of horizontal section. The model provides a practical tool to predict the shortest drilling time for horizontal section in ERW.",0,0,8
Horizontal Wells,Horizontal Section,"Zhang, Rui; Li, Yinghao; Yang, Bin; Jia, Zongyi; Zhang, Feng; Wang, Ruihe; Li, Na; Zhou, Xianhai",A segmenting method of long horizontal wellbore for staged sand control completion based on multi-dimension sequential clustering,Sand production; Staged completion; Multi-dimension sequential clustering; Critical wellbore pressure of sanding onset; Water breakthrough time,INFLOW-CONTROL DEVICES; GAS-RESERVOIRS; OPTIMIZATION; PRESSURE,"For horizontal well, the uniform measure of completion for sand control in the whole horizontal wellbore will cause local sand control failure or excessive sand control, even a decrease in production. An effective measure solved the problem is to segment long horizontal wellbore and conduct completion with staged sand control. In this paper, taking into consideration impacts of reservoir properties heterogeneity, the heel-toe effect of wellbore flow and the different distance between wellbore and water-oil contact (WOC) on sand production along long horizontal wellbore, the difference (CWP - p(wf)) between critical wellbore pressure of sanding onset (CWP) and wellbore flowing pressure (p(wf))and water breakthrough time (T) of each micro section of horizontal wellbore are used to make up vector components and selected as segmenting indexes, further mull-dimension sequential clustering method is employed to segment horizontal wellbore according to the principle of location contiguity and similarly of CWP - p(wf) and T between micro intervals. Then the segmenting method for sand control completion together with water control in horizontal wells is proposed. Furthermore, the segmentation method is utilized in investigating staged sand and water control in TP65 well of T block in Shengli Oilfield, and the optimal number and location of segments for the well are given. This research can provide a new theoretical and quantitative method for staged sand control completion in horizontal well. And it also can be regarded as a fundamental platform to investigate other kinds of wellbore staging problems, such as staged fracturing.",2,3,3
Horizontal Wells,Horizontal Section,"Wang, Dongying; Wang, Zhiming; Zeng, Quanshu",An experimental study on gas/liquid/solid three-phase flow in horizontal coalbed methane production wells,Gas/liquid/solid three-phase flow; Coalbed methane; Horizontal well; Flow pattern; Height of coal particle bed; Explicit equation,SAND-DEPOSITION VELOCITY; RESERVOIR ROCKS; LIQUID; GAS; PARTICLES; TRANSPORT,"Coal particles caused by well drilling and completion, hydraulic fracturing, and formation pressure decreasing would migrate into the horizontal well carried by fracturing flow-back fluid, formation water and CBM, and then deposit on the low side of pipe leading to the decrease of cross section area of pipe for flow and even blocking of the pipe. The purpose of current research was to obtain the flow pattern while there was stationary solid particle bed on the low side of the pipe and an explicit equation to predict the height of solid particle bed was proposed. In this study, with the coal particle, water, and air as the solid, liquid, and gas phases respectively, gas/liquid/ solid three-phase flow experiments in horizontal well were carried out and 4 crucial factors including different water flow rate, gas flow rate, coal particle size, and coal particle mass concentration were considered. Fluid's real apparent velocity was defined and used to analyze the distribution of flow pattern coordinate points. Results show that the flow pattern coordinate points determined by real gas apparent velocity and real water apparent velocity distribute near the flow pattern transition lines of Taitel and Dukler flow pattern map. Besides, coal particle size, water flow rate, and gas flow rate have obvious impact on the height of coal particle bed and the coal particle mass concentration has a negligible effect while the height of interface between gas layer and water layer is only dramatically affected by the gas flow rate. At last, an explicit equation for predicting the cross section area of coal particle bed based on the experimental data was proposed which is crucial to predict the flow pattern and calculate the pressure drop in horizontal well. The predicting cross section area of coal particle bed is in good agreement with the measured cross section area of coal particle bed and the average relative differences are 9.38% and 13.45% for stratified smooth flow and stratified wavy flow respectively. The equation is applicable for a range of coal particle size (8-30 mesh) and water apparent velocity (0.025-0.123 m/s).",2,2,4
Horizontal Wells,Horizontal Section,"Li, Xin; Gao, Deli",Study on mud weight window prediction model and safety additional value of horizontal well in shales considering effects of Well's extended-reach limit,Mud weight window; Safety additional value; Horizontal well; Extended-reach limit; Shale gas field,STABILITY,"Safety additional value is always added to the conventional mud weight window (MWW) to ensure the drilling safety in shales. However, the safety additional value is usually an empirical value. Since the horizontal well usually has a long horizontal section in shales, failing to accurately predict the wells MWW and corresponding safety additional value in shales may result in serious drilling hazards. In order to ensure that the horizontal well can reach the designed horizontal-section length in shales, the conventional MWW needs to be modified and the calculated value of safety additional value should also be given. In this paper, considering the effects of horizontal wells extended-reach limit and its horizontal-section limit (HSL) on the wells MWW in shales, the drilling process, tripping process and six constraint conditions are considered simultaneously. Results of the case study indicate that the corresponding safety additional value is calculated instead of using an empirical value. Moreover, the predicted MWW becomes narrower as the designed horizontal-section length is increased. In addition, in order to obtain a wider MWW, tripping velocity should be lower if the economic benefits can be satisfied. Additionally, the drilling pump with higher rated pressure is also necessary. Taking the maximum HSL as the objective function, there exists an optimal drilling fluid density, which is crucial for production in shales. The calculated value of safety additional value and the modified MWW can ensure the horizontal well reach the designed horizontal-section length, obtaining enough production and economic benefits as well as avoiding drilling hazards in shales.",5,6,1
Horizontal Wells,Channeling,"Li, Zhan-dong; Pang, Hong; Xu, Jinze; Li, Zhong; Zhang, Hai-xiang; Liu, Yi-kun","Case study of sandbody architecture and quantitative parameters of the farsource sandy braided river: Saertu Oilfield, Daqing, China",Sandy braided river; Architecture parameters; Falling-siltseam; Physical simulation; Daqing oilfield,SEQUENCE STRATIGRAPHY; RESERVOIR ANALOG; BASIN; CHANNELS; HETEROGENEITY; DIMENSIONS; SANDSTONE; PATTERNS; ELEMENTS; SYSTEMS,"Aimed at the braided river sandbodies deposited in the pure oil area of western Saertu Oilfield in the Songliao Basin, Daqing, Placanticle, the sedimentary physical simulation experiments were designed. The characteristics of channel bar microfacies were identified and analyzed by four rounds of experiments. Based on the measurement results, the correlation parameter model of the braided river reservoir architecture was established by describing the geometric occurrence of the structures of the single-phase braided river sandbodies and channel bar. Combined with prototype sedimentation simulation experiment, the internal quantitative architecture of far-source sandy braided river was researched by identifying and analyzing the interface of individual well. The interfaces of the 5th-order, 4th-order and 3rd-order architectures were emphatically analyzed and the inter-well quantitative architecture model was established. The research results showed that the interlayer in the center of channel bar was approximately horizontal, with dip angle of about 1 degrees. In short-axis toward end direction, the dip angle of the architecture interface of accretionary body was 2-4 degrees. Combined with the internal dip angle and occurrence of channel bar sandbodies, the interface of the accretionary body in the central part of channel bar was parallel, with dip angle of no more than 2 degrees. The dip angle of the accretionary body in water flow direction was large, which was 2 degrees-5 degrees. On this basis, the size of braided river, channel bar and accretionary body was calculated quantitatively in the target area, and different orders of braided river sandstone reservoirs were described.",3,3,0
Horizontal Wells,Channeling,"Du, Qingjun; Hou, Jian; Zhao, Fan; Zhou, Kang; Liu, Wenbin; Liu, Yongge",A new organic fiber composite gel as a plugging agent for assisting CO2 huff and puff in water channeling reservoirs,CO2 utilization ratio; Organic fiber composite gel; Water channeling reservoir; Real rock plate experiment; Numerical simulation,ENHANCED OIL-RECOVERY; DIFFUSION-COEFFICIENTS; N-PUFF; CARBON-DIOXIDE; INJECTION; PERFORMANCE; SIMULATION; PROPANE; METHANE; SHALE,"The utilization of CO2 for enhancing oil recovery is an environmentally friendly way to dispose the industrial CO2 emissions. CO2 utilization ratio is defined as the volume ratio of produced oil to injected CO2. CO2 huff and puff technology can further improve oil recovery in high water cut reservoirs. However, as the huff and puff cycle increase, gas channeling is easy to happen and the utilization ratio of CO2 is reduced. Organic fiber composite gel is an effective plugging agent for gas channel. The major objective of this paper is to study the mechanisms of increasing CO2 utilization by injecting organic composite gel as the plugging agent. A large scale (40 cm*40 cm*3 cm) natural rock model with grooves is used to simulate the experimental conditions such as channeling channel and horizontal well. Two groups of experiments of direct CO2 huff and plugging agent assisted CO2 huff and puff were conducted. By comparing the pressure changes during the experiments, the mechanism of blocking the channel, balancing the CO2 displacement front and improving the utilization ratio of CO2 were analyzed. The experimental process was fitted by reservoir numerical simulation, and the remaining oil distribution, plugging agent distribution and CO2 distribution in CO2 huff and puff under different conditions were further demonstrated. Results show that compared with direct CO2 stimulation, the distribution of remaining oil saturation and reservoir pressure become more uniform and the utilization ratio of CO2 is greatly increased after injecting organic fiber composite gel. It is mainly due to the fact that the injected plugging agents flow preferentially into high water saturation region along the high permeability channels. Then, they can generate the organic fiber composite gel and remain in the channeling paths. As a result, the following injected CO2 will be forced to flow towards oil-rich regions radially and uniformly. Thereby, more CO2 can contact and react with the in-situ oil, resulting much higher oil recovery. In other words, the utilization ratio of CO2 is greatly improved. Taking Jidong oilfield as an example, it has been injected 19.2 x 10(4) t CO2 with the total oil production by 21.1 x 10(4) t. The utilization ratio of CO2 is calculated as high as 1.09. The observations of this study provide the theoretical basis for future application of organic fiber composite gel before CO2 flooding in the water channeling reservoirs.",5,5,3
Horizontal Wells,Formation Damage,"Hemmingsen, Casper Schytte; Glimberg, Stefan Lemvig; Quadrio, Nathan; Volcker, Carsten; Nielsen, Kenny Krogh; Walther, Jens Honore; Byrne, Michael; Engsig-Karup, Allan P.",Multiphase coupling of a reservoir simulator and computational fluid dynamics for accurate near-well flow,Multiphase flow; Porous media; CFD; Near-wellbore; Reservoir simulation,TRANSPORT,"Near-well flow analysis is an important tool for gaining detailed insight of the flow behaviour and for improving well design and production optimization of real reservoirs. One challenge of accurate numerical modelling of the flow field in the vicinity of the well is related to the scale disparity factor in space and time. The numerical scale gap between the reservoir and the wellbore justifies the representation of a well as a point or line sink/source term in traditional reservoir models. However, standard numerical techniques for reservoir simulation are incapable of resolving the near-singular character of the pressure field in the vicinity of the well. Under the assumption that all length scales have impact on flow patterns, we present a proof-of-concept study aimed at improving the quality of the numerical simulation by considering the geometry and fluid flow near the wellbore in a fully connected system, thus accounting for the fine scale phenomena by means of a hybrid Navier-Stokes/Darcy wellbore model coupled with a full scale reservoir model. A weak coupling method based on fixed-point iterations, that preserves the mass flux transport across the coupled interface, while adjusting productivity indices, is demonstrated via numerical experiments. Several different numerical experiments are performed to demonstrate the versatility and the improved well performance insight that the coupled method offers, including horizontal well inflow profile, influence of formation damage and optimal well configuration.",1,2,1
Horizontal Wells,Formation Damage,"Cao, Jie; Zhang, Nan; Johansen, Thormod E.",Applications of fully coupled well/near-well modeling to reservoir heterogeneity and formation damage effects,Well/near-well modeling; Iterative coupling; Heterogeneity; Crossflow; Formation damage,HORIZONTAL WELLS; FLOW; PRODUCTIVITY; PERFORMANCE,"Applications of a new well/near-well fluid flow modeling scheme to heterogeneous reservoirs and formation damage are presented in this paper. This well/near-well model is based on an analytically solution of an axial-radial productivity model for steady state flow in wells and near-well reservoirs, in which wellbore hydraulics and heterogeneity in the near-well region are incorporated. The numerical model includes a reservoir region describing both radial and axial reservoir flow. It can be used as a stand alone simulator, or it can be coupled with a reservoir simulator, using a new iterative coupling scheme described in this paper. When coupling with the reservoir simulator, the reservoir region in the well/near-well model is shared by and computed in both models, which ensures the stability and convergence of the iterative coupling scheme. A new coupling approach is presented without needing to determine any partial derivatives. The capabilities of the modeling methodology are demonstrated through applications in three challenging cases: highly heterogeneous reservoir, well/reservoir crossflow, and formation damaged reservoirs. In the highly heterogeneous near-well reservoir case, results show that the model is stable for a wide range of permeabilities with large contrasts. The detailed permeability information from well logging can be fully taken into account in this model. The model determines pressure distribution and volumetric flow rates including flow directions, therefore enabling the model to estimate crossflow as negative flow rates, for example when the well is producing from several non-communicating regions. Furthermore, the well/near-well model is iteratively coupled with a reservoir simulator such that the well completion effects are taken into consideration in large scale simulations. The transient case of this coupling to evaluate formation damage along a horizontal well is then presented. The model is not limited to single phase flow. A two phase flow example coupling the well/near-well model and a streamline reservoir model is finally presented.",1,2,5
Horizontal Wells,Inflow Profile,"Hemmingsen, Casper Schytte; Glimberg, Stefan Lemvig; Quadrio, Nathan; Volcker, Carsten; Nielsen, Kenny Krogh; Walther, Jens Honore; Byrne, Michael; Engsig-Karup, Allan P.",Multiphase coupling of a reservoir simulator and computational fluid dynamics for accurate near-well flow,Multiphase flow; Porous media; CFD; Near-wellbore; Reservoir simulation,TRANSPORT,"Near-well flow analysis is an important tool for gaining detailed insight of the flow behaviour and for improving well design and production optimization of real reservoirs. One challenge of accurate numerical modelling of the flow field in the vicinity of the well is related to the scale disparity factor in space and time. The numerical scale gap between the reservoir and the wellbore justifies the representation of a well as a point or line sink/source term in traditional reservoir models. However, standard numerical techniques for reservoir simulation are incapable of resolving the near-singular character of the pressure field in the vicinity of the well. Under the assumption that all length scales have impact on flow patterns, we present a proof-of-concept study aimed at improving the quality of the numerical simulation by considering the geometry and fluid flow near the wellbore in a fully connected system, thus accounting for the fine scale phenomena by means of a hybrid Navier-Stokes/Darcy wellbore model coupled with a full scale reservoir model. A weak coupling method based on fixed-point iterations, that preserves the mass flux transport across the coupled interface, while adjusting productivity indices, is demonstrated via numerical experiments. Several different numerical experiments are performed to demonstrate the versatility and the improved well performance insight that the coupled method offers, including horizontal well inflow profile, influence of formation damage and optimal well configuration.",1,2,1
Horizontal Wells,Inflow Profile,"Prakasa, Bona; Muradov, Khafiz; Davies, David",Principles of rapid design of an inflow control device completion in homogeneous and heterogeneous reservoirs using type curves,Inflow control devices; Intelligent well completion; Horizontal well; Heel-to-toe effect; Inflow rate distribution,HORIZONTAL WELLS; PRESSURE-DROP,"This paper discusses the development and application of universal type-curves for the design of Advanced Well Completions (AWCs) equipped with passive (non-adjustable), flow control devices {a.k.a. Interval Control Devices (ICDs)}. This work provides an innovative, rapid approach to their design without the need for numerical simulators. AWCs equipped with ICDs aim to delay the early breakthrough of unwanted fluids in wells constructed close to a reservoir fluid contact. An uneven inflow profile due to reservoir permeability heterogeneity, multiple fluid contacts or an undulating well path needs to be managed. In addition, the Heel-to Toe effect (HTE) by frictional pressure loss due to fluid flow along the length of the completion interval also promotes a non-uniform inflow profile. The main AWC design challenge is to balance the trade-off between loss in well productivity from the added flow restrictions and the benefit of an improved inflow profile. This paper reviews the development of the analytical modelling of the inflow performance of horizontal wells with ICD completions, It presents new semi-analytical, mathematical models describing the ability of AWCs to mitigate production problems created by (reservoir) permeability heterogeneity and the (in-well) HTE. New dimensionless numbers allow the development of universal type-curves (TCs) for AWC design. The new workflow is illustrated for several case studies and the results validated by their good agreement with calculations made with the standard ""well-reservoir"" numerical simulator employed by engineers for this task. This novel approach for rapid analysis of the implications of well log data, such as that obtained shortly before the beginning the installation of the well completion, is the latest addition to the well completion engineering toolbox.",3,5,0
Crude Oil,Heavy Oil,"Mandal, Arnab; Mahto, Vikas; Purohit, Subodh; Nihalani, M. C.",Evaluation of synthesized polymeric additives as paraffin inhibitors for wax dissolution in the petroleum reservoir rock,Crude oil; Paraffin inhibitor; Contact angle hysteresis; Sandstone core,POUR POINT DEPRESSANT; FLOW PROPERTIES,"Precipitation of paraffin in petroleum reservoir rock can be a challenge to oil productivity for oil and gas industries. Paraffins exist in equilibrium with the crude oil under normal reservoir temperature and pressure. During the flow of crude oil through the petroleum formation, the proportion of lighter ends in crude oil underwent variation on account of localized pressure fluctuations. It led to reduction in solubility of heavy molecular weight hydrocarbons and they precipitate in the form of wax in the pores of reservoir rock. In this paper, wax deposition from crude oil was investigated using an experimental set up. The crude oil was characterized as medium heavy and waxy crude oil. Two paraffin inhibitors were synthesized in laboratory based on amination reaction of maleic anhydride with unsaturated amines. The monomer formed underwent free radical polymerization at 75 degrees C. The synthesized inhibitor was doped in crude oil to check wax dissolution through pores as compared to commercial paraffin inhibitors. In addition, the core was aged with crude oil for 15 days and alteration in its wettability was evaluated through changes in contact angle hysteresis with paraffin dissolution. It was found that synthesized paraffin inhibitors showed higher contact angle hysteresis as compared to commercial paraffin inhibitors, indicating excellent solubilisation of wax deposit in the pores of core.",0,0,0
Crude Oil,Heavy Oil,"Gazulla, M. F.; Andreu, C.; Rodrigo, M.; Orduna, M.; Ventura, M. J.; Montolio, F. J.",New methodology for the determination of sodium in light and heavy petroleum products,Sodium; Crude oil; Fuel oil; Thermal treatment; ICP-OES,METAL ANALYSIS; CRUDE-OIL; ICP-OES,"Sodium represents an important issue to a refinery plant, as it causes catalyst deactivation and by-products corrosion. A method to determine sodium in vacuum gas oils (VGOs) was developed in a previous work, but this method is not suitable for other type of petrochemical materials, such as crude oils (CO) or fuel oils (FO), that also need a control of the sodium concentration. The great difference between the physical and chemical properties of the petrochemical products make them challenging to analyze and to develop one method suitable for all of them. Thus, samples were classified in light, medium, or heavy according to their API gravity number and the sample preparation methodology was optimized depending on the type of sample. The aim of this work is to develop a methodology with different sample treatment conditions which make it versatile and appropriate for any type of light and heavy petroleum products in a relative short time to be used as a control method and with a quantification limit lower than 1 mg.kg-1. The different sample preparation treatments were set up by incinerating the sample in a new piece of equipment designed and assembled by the Instituto de Tecnologia Ceramica (ITC), which was modified to adjust the thermal treatment conditions to the requirements of the sample matrix. Different experiments were carried out modifying not only the heating rate ramp and time of dwelling at maximum temperature but also the atmosphere conditions, working in reducing or oxidizing conditions depending on the matrix sample in order to achieve the complete incineration of the sample without analyte loss. Following this working procedure, a methodology for the determination of sodium was achieved, being able to select a different sample preparation treatment depending on the classification of the petroleum products according to their API gravity number. In this regard, two different sample preparation treatments were optimized, one for light petroleum products, incinerating the sample in 90 min and working in a reductive atmosphere; and another for the heavy ones, which principle modifications included the introduction of an oxygen stream in the last ramp of the heating cycle and a diminution in the heating rate in the first stage of incineration. The developed method for the determination of sodium in petroleum products is a fast and accurate method than can be used as a control one, as the total analysis time is much lower than that of the standardized methods and can be applied to any type of petroleum product. Moreover, the quantification limit reached is lower than 1 mg.kg-1, which is in accordance with the refining industry requirements.",0,0,1
Crude Oil,Heavy Oil,"Kim, Tae Wook; Vittoratos, Euthymios; Kovscek, Anthony R.",Recovery efficiency of a 28 degrees API crude-oil system as a function of voidage replacement ratio,Water flooding; Voidage replacement; Laboratory studies; Improved oil recovery,SOLUTION-GAS DRIVE; RELATIVE PERMEABILITY,"Crude-oil recovery processes with a voidage replacement ratio (VRR = injected volume/produced volume) less than 1 combine solution gas drive mechanisms and viscous crude-oil displacement. Previous laboratory and field studies have shown that a VRR less than 1 for a period of time is optimal for recovery of some viscous and heavy crude oils that form emulsions and/or bubbly oil in situ. This study extends understanding of the effect of VRR to recovery of live, less-viscous crude oils from sands. The crude oil used is roughly 28 degrees API, has a dead-oil viscosity of 26 cP, a live-oil viscosity of 0.41 cP, and an asphalt content of 2.1 wt%. It is found in the laboratory that the final crude-oil recovery (70.5%) using a 0.01 PV/h depletion rate and VRR equal to 0.7 is more than 8% greater than recovery with VRR equal to 1 (65.1%). Recovery using a 0.001 PV/h depletion rate with VRR equal to 0.7 (79.1%) was nearly the same as the sum of oil recoveries for solution gas drive (VRR = 0, 24.5%) plus waterflooding (VRR = 1, 53.4%). For these two depletion rates, the oil recovery obtained using VRR equal to 0.7 is more favorable than VRR = 1 (waterflooding). Relative permeability was inferred from experimental results. Substantial critical gas saturations (8.1-16.1%) also contributed to oil production. A concave shape of the oil/water relative permeability curve indicated an emulsion-like effect that also promoted recovery when the VRR was less than 1.",1,1,0
Crude Oil,Heavy Oil,"Ge, Haixia; Zhang, Zhihuan","Origin and accumulation of Paleogene oil in Qingdong sag, Jiyang depression, eastern China",Oil-source correlation; Heavy oil; Biodegradation; Oil charging orientation; Accumulation characteristics; Qingdong Sag,FLUID INCLUSION; PETROLEUM; GEOCHEMISTRY; BASIN; INDICATORS; FIELD,"This study reports on the geochemical examination of 18 core samples and 22 crude oil samples from the Qingdong and Dongying sags. Both conventional and heavy oils coexist in the Qingdong Sag, with the heavy oil resulting from biodegradation. Based on the oil-source rock correlation, the conventional oil mainly originates from the Es-3(1) source rock in the central and northern sub-sags, with the biodegraded oil in the western slope having been derived from the Es-4(u) source rock in the central and northern sub-sags. The biodegraded oil in the transition belt is mostly derived from the Dongying Sag (Es-4(u)). The biodegraded oil in the Qingdong-5 area originated from the Es-4(u) member near the Qingdong-5 area in the southern sub-sags. Two stages of oil charging were identified in the Qingdong Sag based on the basin modelling. The first stage occurred during the deposition of the Dongying Formation (Ed) in the Paleogene, and the second stage occurred during the deposition of the Guantao Formation from the Neogene to Quaternary (Ng-Q). The conventional oil in the central and northern parts of the study area mainly accumulated during the second stage and migrated both laterally through the sand-bodies and vertically along the steep faults. The heavy oil in the transition belt mostly accumulated during the second stage, migrating a long distance along the en-echelon step-fault zone, and suffered severe biodegradation. Both stages of oil charging were responsible for the heavy oil in the Qingdong-5 area and the western slope. The former migrated a short distance before being trapped, while the latter moved long distance along the fault strike. The oil charged during the first stage was subject to alteration, eventually being mixed with oil from the second charging event.",1,1,1
Crude Oil,Heavy Oil,"Leitenmueller, Verena; Rupprecht, Bernhard J.",A multidisciplinary approach for chemical EOR screening: Understanding alkali-oil interaction by the use of petroleum geochemistry,Biodegradation; Phase screening; Potassium carbonate; Reservoir engineering; Organic geochemistry; ASP flooding; Chemical flooding,INTERFACIAL-TENSION; VIENNA BASIN; SYSTEMS; MECHANISMS,"Alkali-based chemical enhanced oil recovery is used to increase the incremental oil production and relies on the interaction of alkali lye with crude oil. Optimizing the chemical formulation depends on screening multiple alkali concentration ranges to maximize the generated emulsion volume. However, the strong chemical variation of the crude oil, caused by biodegradation within the reservoirs, and its influence on generating in-situ soaps has never been studied in detail. In this paper, organic geochemical oil characterization was combined with phase screening data. Thereby, differences in terms of initial crude oil composition (slightly degraded, moderate degraded, and heavy degraded oils), but also regarding the excess alkali-equilibrated oil phase, and the hydrocarbons which are included in the in-situ soap (emulsion phase) were worked out. Different alkalis, concentration ranges, and water-oil-ratios were studied, to understand the control mechanism for the in-situ soap generation. The formed emulsions were observed over time (emulsion stability) and classified into possible emulsion types. Alterations caused by the alkali-oil interaction were quantified by the use of organic geochemistry. The degree of biodegradation seems to be an important control mechanism. Slightly degraded oils do not interact with the alkali lye due to a high content of non-polar compounds such as alkanes and isoprenoids. Moderately and heavily degraded oils show varying interactions with the alkali solution. The degree of interaction depends on the used degradation type, the alkali type as well as on the used concentration. Moderately degraded oils interact in a lower concentration range compared to heavily degraded oils, which show an increased non-soap forming acid content. Phase experiments conducted over a long period of time (100 days) were used to determine which emulsion types (micro or macro) were formed. Stable micro emulsions were preferably generated over time in formulations prepared with potassium carbonate (K2CO3). In contrast, formulations containing sodium carbonate (Na2CO3) hardly did not generate stable micro emulsions. The composition of alkali-equilibrated oil differs from the initial oil composition and shows a strong dependency of the used alkali type. Potassium carbonate caused mild alterations of the moderately and heavily degraded oils, whereas the impact of sodium carbonate was more severe. In addition, dissolution of naphthalenes, steranes, hopanes, and parts of the generated in-situ soap into the aqueous phase, was observed during the performed phase experiments of the moderately degraded oils (at the elevated pH values).",2,2,0
Crude Oil,Heavy Oil,"Zhang, Jian; Chen, Xiao-Ping; Xu, Jing-yu",Rheological characteristics of unstable heavy crude oil-water dispersed mixtures,Heavy crude oil; Unstable mixtures; Apparent viscosity; Oil-water mixture,VISCOSITY PREDICTION; STABILITY; EMULSIONS; BEHAVIOR; FLOW; INVERSION,"The rheological characteristics of unstable heavy crude oil-water dispersed mixtures were investigated to improve pipeline transportation. The viscosity of heavy crude oil is 5439 mPa s, and density is 955 kg/m(3) at 30 degrees C. A series of factors, including oil volume fraction, shear rate, and temperature, was considered systematically to investigate the phenomenon of phase inversion and stability of oil-water mixtures. The results show that the apparent viscosity of a heavy crude oil-water mixture reaches its maximum value at the phase inversion point, and that the non-Newtonian fluid characteristics of unstable heavy crude oil-water mixtures are different than those of fine emulsions or light oil-water mixtures. The addition of emulsifier influences the apparent viscosity and phase inversion point by changing the droplet size distribution. Furthermore, the apparent viscosity of a heavy crude oil-water mixture continues to increase as the median diameter of the dispersed phase decreases. All these are beneficial to the analysis of the rheological characteristics of heavy crude oil-water dispersed mixtures.",2,2,6
Crude Oil,Heavy Oil,"Sanchez, S.; Ascanio, G.; Sanchez-Minero, F.; Mendez, F.; Aguayo, J. P.; Ramirez-Jimenez, E.; Alonso-Ramirez, G.",Conjugate thermal-hydrodynamic model for the study of heavy oil transport,temperature-dependent properties; Dynamic viscosity; Scale analysis; Conjugate phenomenon; Lubrication theory,LIGHT CRUDE-OIL; RHEOLOGICAL PROPERTIES; ELECTROOSMOTIC FLOW; FALSE TRANSIENT; PIPELINE; VISCOSITY; TEMPERATURE; LAMINAR; SIMULATION; CONDUCTION,"In the present work, the thermal impact induced by the environment on the hydrodynamics of heavy oil transport in pipelines is analyzed. Here, the thermal dependence of the dynamic viscosity of heavy oils, in addition to the mechanical heating caused by viscous dissipation are taken into account; therefore, the mathematical models that represent the flow and temperature fields of the heavy oil have to be solved in a coupled manner. Moreover, given that the pipeline is protected by a thermal insulation (soil), the domain of study defines a conjugate system between the heavy oil, the pipeline and the soil, which indicates that before knowing the temperature in the fluid region, temperatures in the other two zones must be calculated. To define properly how thermal energy is transferred and generated during the crude oil transport, the analysis is carried out in dimensionless form, solving the conjugate mathematical model by using numerical approaches and simplified asymptotic approximations. The main results reveal that the transport of heavy oils is seriously affected by a small reduction in temperature, increasing substantially the dynamic viscosity and the flow rate is reduced significantly in comparison with the case of a full thermal insulation condition. Then, we can infer that when the losses of thermal energy and its effects on the hydrodynamics are controlled, an efficient transport process is obtained. Employing the asymptotic analysis, results show that such a condition can be achieved by two ways: the first one by improving the thermal insulation, and the second one by optimizing the ratio of the internal radius to the length of the pipeline or increasing the volumetric flow rate, which indicates that the conjugate phenomenon is a modified version of the Graetz-Nusselt problem.",3,3,0
Crude Oil,Heavy Oil,"Pu, Wan-fen; Gong, Xiao-long; Chen, Ya-fei; Liu, Xue-li; Hui, Jian; Guo, Chen; Varfolomeev, Mikhail A.",Oxidation kinetic evaluation of the low temperature oxidized products of Tahe heavy oil characterized by the distributed activation energy model,Heavy oil; Low temperature oxidation; Oxidized product; Oxidation kinetic; Coke deposition; DAEM,IN-SITU-COMBUSTION; PRESSURE AIR INJECTION; LIGHT CRUDE-OIL; SARA FRACTIONS; BEHAVIOR; COKING; PREDICTABILITY; RECOVERY; TG,"In view of the significance of low temperature oxidation (LTO) for in-situ combustion (ISC) of heavy crude oil and to provide further data for Tahe ISC numerical simulation, this research aimed to investigate the non-isothermal oxidation behavior of heavy oil after static LTO reactions. Thermogravimetric (TG) and differential scanning calorimetry (DSC) techniques were used to characterize oxidation behavior, and distributed activation energy method (DAEM) was used to calculate kinetic parameters. The results showed that the non-isothermal oxidation process of static LTO oxidized oil was the result of the interaction between residue and coke, and coke can significantly reduce the activation energy of oxidized oil. Only one HTO region was identified for the coke from DTG/DSC curves, and it had the lowest activation energy (114.57 kJ/mol) and the highest heat enthalpy (24.3 kJ/g), indicating high oxidative activity with maximum heat release potential. A satisfactory corresponding relation between DTG and DSC curves was presented for all samples in FD and HTO regions, which indicated that the sequential reaction mechanisms, fuel deposition and combustion, were undergone. In LTO region, there was a temperature difference between the peaks of the mass loss and heat flow, indicating that the LTO process was more complex with a multi-step control mechanism should be considered to analyze and simulate the LTO stage.",3,3,1
Crude Oil,Heavy Oil,"Adewunmi, Ahmad A.; Kamal, Muhammad Shahzad; Solling, Theis Ivan; Salami, Babatunde Abiodun",Palm oil fuel ash (POFA) as a demulsifier for crude oil emulsions: Performance and mechanism,Emulsion; Seawater; Oil; POFA; Demulsification,IN-WATER EMULSIONS; EFFICIENT DEMULSIFICATION; MAGNETIC NANOPARTICLES; BY-PRODUCT; ADSORPTION; MICROWAVE; STRENGTH; COMPOSITE; OXIDE; WASTE,"The petroleum industry is greatly in need of smart and cheap demulsifiers to break heavy crude oil emulsions. This study investigates the performance of palm oil fuel ash (POFA) as a demulsifier of crude oil emulsions produced during hydrocarbon exploration. Highly stable water-in-oil (W/O) emulsions having water:oil ratio of 7:3 were prepared under room temperature (25 degrees C) at a mixing speed of 1500 rpm. Demulsification performance of various concentrations of POFA (1 wt% to 9 wt%) was performed using the bottle test method at 60 degrees C and 80 degrees C. Experimental results show that POFA can effectively break the emulsion and separates water/oil into phases. The emulsion containing 3 wt% POFA exhibited the highest water/oil separation with demulsification efficiencies (DEs) of 99.28% and 99.71% at 60 degrees C and 80 degrees C, respectively. Additionally, a comparison between POFA and a commercial demulsifier (poloxamer - 407) showed that POFA can compete favorably with demulsifiers regularly applied in oil fields. Optical electron microscope analysis revealed the morphology of water and oil phases after emulsion separation. Results from the rheological measurements established the capacity of POFA to be able to destabilize the natural emulsifiers existing at the water/oil interface. Interfacial tension results show that POFA particles have a strong tendency to diminish the water/oil interfacial films. An investigation of the demulsification mechanism reveals that silica in POFA plays a critical role in the breaking of stable crude oil emulsions. Certainly, POFA will be a promising demulsification material for separating or removing water from all forms of emulsions produced in the oil fields.",5,5,2
Crude Oil,Heavy Oil,"Kamel, Abdulrahim; Alomair, Osamah; Elsharkawy, Adel",Measurements and predictions of Middle Eastern heavy crude oil viscosity using compositional data,Heavy oil; Viscosity; Correlation; Corresponding state; Equation of state,EQUATION-OF-STATE; RESERVOIR FLUIDS; MODEL; PRESSURE,"Determining the viscosity of heavy crude oil is important in the field of petroleum science, and reservoir simulators are routinely used to achieve this goal. In this study, a new empirical model for predicting heavy-oil viscosity is presented. The model was developed using the compositional data of 28 heavy crude oil samples from the Middle East. Viscosity measurements from 196 data points in the 20-80 degrees C temperature range were used during model development, and another 47 viscosity measurements were used to validate the model. The compositional and viscosity measurements were also used to evaluate the accuracy of previously published methods for predicting heavy-oil viscosities. These methods include corresponding-states models, residual viscosity models, and equations-of-state-based models. The study reveals that none of the previously published methods adequately predict the viscosities of heavy crude oils. On the other hand, it shows that the new empirical model is able to predict the viscosities of heavy oils with an average relative error of 3.8%. The proposed model is much simpler and easier to use than existing methods.",5,5,2
Crude Oil,Heavy Oil,"Yang, Zhe; Li, Meijun; Cheng, Dingsheng; Xiao, Hong; Lai, Hongfei; Chen, Qingyao",Geochemistry and possible origins of biodegraded oils in the Cretaceous reservoir of the Muglad Basin and their application in hydrocarbon exploration,Geochemical characteristics; Biodegraded oil; Cretaceous; Muglad basin; WCARS,ABU GABRA FORMATION; CRUDE OILS; ORGANIC-MATTER; TRIAROMATIC STEROIDS; PETROLEUM GEOLOGY; CRATONIC REGION; TARIM BASIN; SUDAN; DEGRADATION; ROCKS,"The Muglad Basin is one of the largest petroliferous basins within the Central and Western African Rift System (WCARS). A total of 42 oil samples including light, normal and heavy crude oils from the Cretaceous reservoirs of the Muglad Basin were systematically analyzed to fully understand their geochemical characteristics and possible origins. The results of oil-oil correlation show that these Cretaceous crude oils are genetically identical and derive from the same source kitchen. Differences in physical properties and geochemical compositions may be attributed to secondary alteration, such as biodegradation. Lightly, moderately and severely biodegraded oils can be divided on the basis of the relative abundance of n-alkanes and acyclic isoprenoids in the oils and the presence of ""humps"" on gas chromatogram baselines, as well as of the relative abundance of 25-norhopanes. The biodegradation degree of Cretaceous oils in the Muglad Basin is closely related to the burial depth of oil reservoirs and the distance between the locations of oil reservoirs and adjacent faults. This study may have practical application for further petroleum exploration and development in the Muglad Basin.",5,5,3
Crude Oil,Model,"Karacan, C. Ozgen",An ANCOVA model for porosity and its uncertainty for oil reservoirs based on TORIS dataset,Mean value; Depositional system; Multi-linear regression; Reservoir assessment; ANCOVA; TORIS,PERMEABILITY PREDICTION; SEDIMENTARY; NORTH; SANDSTONE; EOCENE; ROCKS,"Porosity is one of the most important parameters to assess in-place oil or gas in reservoirs, and to evaluate recovery from enhanced production operations. Since it is relatively well-established to determine porosity using different laboratory and field methods, its value is usually determined at many locations across a reservoir as part of the common practice to capture reservoir heterogeneity and the variability in values. This suite of measurements and the distribution of values are most valuable for probabilistic reservoir assessments, and for spatial modeling if the exact data locations are known. Despite the importance of individual measurements to set the range of values for probabilistic studies, it is not always possible to access these data due to confidentiality. In most cases, commercial or publicly available databases that assessments may rely on usually report only mean values of porosity, like any other reservoir data, or they may not report a value at all. This makes both quantifying the mean value and the uncertainty around it difficult for probabilistic assessments. In this study, the TORIS (Tertiary Oil Recovery Information System) dataset of the National Petroleum Council and the U.S. Department of Energy was used to model porosity and the uncertainty around predicted values. TORIS is an integrated dataset of production data, reservoir properties, and project databases of crude oil reservoirs in the United States. The model presented in the paper was based on ANCOVA (Analysis of Co-Variance) of data from 1038 reservoirs from the TORIS dataset for porosity prediction, validation and testing for quantitative and qualitative parameters that may be readily available in most cases, and to estimate uncertainty around the mean values. This model also explored association of porosity values to different parameters, and to different depositional systems and diagenetic overprint conditions. Furthermore, an ANN (Artificial Neural Network) model was created to compare the predicted values of both models. Results showed that the ANN model was able to represent more of the variability, however it lacked the insights that might be gained from the ANCOVA model.",1,1,0
Crude Oil,Model,"Ge, Haixia; Zhang, Zhihuan","Origin and accumulation of Paleogene oil in Qingdong sag, Jiyang depression, eastern China",Oil-source correlation; Heavy oil; Biodegradation; Oil charging orientation; Accumulation characteristics; Qingdong Sag,FLUID INCLUSION; PETROLEUM; GEOCHEMISTRY; BASIN; INDICATORS; FIELD,"This study reports on the geochemical examination of 18 core samples and 22 crude oil samples from the Qingdong and Dongying sags. Both conventional and heavy oils coexist in the Qingdong Sag, with the heavy oil resulting from biodegradation. Based on the oil-source rock correlation, the conventional oil mainly originates from the Es-3(1) source rock in the central and northern sub-sags, with the biodegraded oil in the western slope having been derived from the Es-4(u) source rock in the central and northern sub-sags. The biodegraded oil in the transition belt is mostly derived from the Dongying Sag (Es-4(u)). The biodegraded oil in the Qingdong-5 area originated from the Es-4(u) member near the Qingdong-5 area in the southern sub-sags. Two stages of oil charging were identified in the Qingdong Sag based on the basin modelling. The first stage occurred during the deposition of the Dongying Formation (Ed) in the Paleogene, and the second stage occurred during the deposition of the Guantao Formation from the Neogene to Quaternary (Ng-Q). The conventional oil in the central and northern parts of the study area mainly accumulated during the second stage and migrated both laterally through the sand-bodies and vertically along the steep faults. The heavy oil in the transition belt mostly accumulated during the second stage, migrating a long distance along the en-echelon step-fault zone, and suffered severe biodegradation. Both stages of oil charging were responsible for the heavy oil in the Qingdong-5 area and the western slope. The former migrated a short distance before being trapped, while the latter moved long distance along the fault strike. The oil charged during the first stage was subject to alteration, eventually being mixed with oil from the second charging event.",1,1,1
Crude Oil,Model,"Yuan, Qing; Li, Jingfa; Liu, Hongfei; Yu, Bo; Sun, Dongliang; Deng, Yajun",Parametric regression of a multiparameter thixotropic model for waxy crude oil based on multiobjective strategy,Waxy crude oil; Thixotropic model; Parametric regression; Multiobjective regression strategy; Regression algorithm,YIELD-STRESS,"The waxy crude oil exhibits a time- and shear-dependent non-Newtonian behavior called thixotropic behavior below the gelation temperature. This behavior can be quantitatively described by using a thixotropic model. However, many parameters are commonly contained in a thixotropic model with good-description capacity, and it still remains challenging to obtain high fitting precision and reasonable physical interpretation simultaneously in the process of parametric regression. In this study, based on a representative multiparameter thixotropic model, a multiobjective regression strategy is put forward. The fitting precision and physical interpretation are taken into account in this regression strategy, and their importance can be adjusted dynamically with the structure breakdown of waxy crude oil. In order to successfully achieve the multiobjective regression strategy, a self-adaptive nondominated sorting differential evolution algorithm (self-adaptive NSDE) is proposed. This regression algorithm is independent on the expressions of the regression model, and thus it can also be applied to the multiobjective parametric regression of other complex models including thixotropic models in rheology field and even other models in different fields. Based on experimental data, the parametric regression of a thixotropic model is performed, and the obtained results are analyzed and discussed in detail. It is found that the regressive data exhibit a small deviation at the starting stage of structure breakdown and the equilibrium flow curve can be ensured at the ending stage of structure breakdown. This finding well verifies considerations of multiobjective regression strategy. Compared with previous three regression strategies in the literature reports, the multi-objective regression strategy exhibits advantages in the fitting precision and physical interpretation.",2,2,1
Crude Oil,Model,"Sanchez, S.; Ascanio, G.; Sanchez-Minero, F.; Mendez, F.; Aguayo, J. P.; Ramirez-Jimenez, E.; Alonso-Ramirez, G.",Conjugate thermal-hydrodynamic model for the study of heavy oil transport,temperature-dependent properties; Dynamic viscosity; Scale analysis; Conjugate phenomenon; Lubrication theory,LIGHT CRUDE-OIL; RHEOLOGICAL PROPERTIES; ELECTROOSMOTIC FLOW; FALSE TRANSIENT; PIPELINE; VISCOSITY; TEMPERATURE; LAMINAR; SIMULATION; CONDUCTION,"In the present work, the thermal impact induced by the environment on the hydrodynamics of heavy oil transport in pipelines is analyzed. Here, the thermal dependence of the dynamic viscosity of heavy oils, in addition to the mechanical heating caused by viscous dissipation are taken into account; therefore, the mathematical models that represent the flow and temperature fields of the heavy oil have to be solved in a coupled manner. Moreover, given that the pipeline is protected by a thermal insulation (soil), the domain of study defines a conjugate system between the heavy oil, the pipeline and the soil, which indicates that before knowing the temperature in the fluid region, temperatures in the other two zones must be calculated. To define properly how thermal energy is transferred and generated during the crude oil transport, the analysis is carried out in dimensionless form, solving the conjugate mathematical model by using numerical approaches and simplified asymptotic approximations. The main results reveal that the transport of heavy oils is seriously affected by a small reduction in temperature, increasing substantially the dynamic viscosity and the flow rate is reduced significantly in comparison with the case of a full thermal insulation condition. Then, we can infer that when the losses of thermal energy and its effects on the hydrodynamics are controlled, an efficient transport process is obtained. Employing the asymptotic analysis, results show that such a condition can be achieved by two ways: the first one by improving the thermal insulation, and the second one by optimizing the ratio of the internal radius to the length of the pipeline or increasing the volumetric flow rate, which indicates that the conjugate phenomenon is a modified version of the Graetz-Nusselt problem.",3,3,0
Crude Oil,Model,"Pu, Wan-fen; Gong, Xiao-long; Chen, Ya-fei; Liu, Xue-li; Hui, Jian; Guo, Chen; Varfolomeev, Mikhail A.",Oxidation kinetic evaluation of the low temperature oxidized products of Tahe heavy oil characterized by the distributed activation energy model,Heavy oil; Low temperature oxidation; Oxidized product; Oxidation kinetic; Coke deposition; DAEM,IN-SITU-COMBUSTION; PRESSURE AIR INJECTION; LIGHT CRUDE-OIL; SARA FRACTIONS; BEHAVIOR; COKING; PREDICTABILITY; RECOVERY; TG,"In view of the significance of low temperature oxidation (LTO) for in-situ combustion (ISC) of heavy crude oil and to provide further data for Tahe ISC numerical simulation, this research aimed to investigate the non-isothermal oxidation behavior of heavy oil after static LTO reactions. Thermogravimetric (TG) and differential scanning calorimetry (DSC) techniques were used to characterize oxidation behavior, and distributed activation energy method (DAEM) was used to calculate kinetic parameters. The results showed that the non-isothermal oxidation process of static LTO oxidized oil was the result of the interaction between residue and coke, and coke can significantly reduce the activation energy of oxidized oil. Only one HTO region was identified for the coke from DTG/DSC curves, and it had the lowest activation energy (114.57 kJ/mol) and the highest heat enthalpy (24.3 kJ/g), indicating high oxidative activity with maximum heat release potential. A satisfactory corresponding relation between DTG and DSC curves was presented for all samples in FD and HTO regions, which indicated that the sequential reaction mechanisms, fuel deposition and combustion, were undergone. In LTO region, there was a temperature difference between the peaks of the mass loss and heat flow, indicating that the LTO process was more complex with a multi-step control mechanism should be considered to analyze and simulate the LTO stage.",3,3,1
Crude Oil,Model,"Xu, Zhengjian; Liu, Luofu; Jiang, Shu; Wang, Tieguan; Wu, Kangjun; Feng, Yanjun; Xiao, Fei; Chen, Yingying; Chen, Yiting; Feng, Chenyang","Migration model of hydrocarbons in the slope of the superimposed foreland basin: A study from the South Junggar, NW China",Migration pathway; Migration drive; Migration direction; Migration timing; Slope; Superimposed foreland basin,CRUDE OILS; TARIM BASIN; CARBAZOLE DISTRIBUTIONS; PETROLEUM MIGRATION; SEDIMENTARY BASINS; NITROGEN-COMPOUNDS; SOURCE ROCKS; MATURITY; INCLUSIONS; BENZOCARBAZOLES,"The superimposed foreland basins mainly develop in central-western China, namely the Himalayan foreland basins superimposed on the Indo-China foreland basins. Previous research on hydrocarbon migration predominantly focused on the typical foreland basins and the fore-deep depression of superimposed foreland basins. As a result of multi-superimposition, large hydrocarbon potentials in the slope zones are evaluated, and the hydrocarbon migration shows significant differences with those in the typical foreland basins. Moreover, the hydrocarbon migration models in the slope zone of superimposed foreland basins are poor analyzed. The Chepaizi High in the South Junggar Basin, a typical slope of superimposed foreland basin, has been taken into consideration. Several points have been ascertained. 1) Multistage charging and readjustment events should be the predominant characters. 2) The combination of multi-type sand-bodies, multistage faults and unconformities have formed step-or ""Z""-shaped migration pathways spatially. 3) Hydrocarbons migrated from the areas of high oil potential in the fore-deep depression to those of low oil potential in the slope. 4) The migration models of the J(1)b, K(1)q, N(1)s(1), and N(1)s(2) have been established. Hydrocarbon reservoirs in the slope zones show the shallow accumulation from deep/ distal sources with multiple reservoirs vertically and multi-charging and -readjustments chronologically. 5) The areas of (Wells SM3, C53-C90, and CF2), (Wells SM5, C80, and CF13), and (Wells K8, HG4, SM4, and CF2) can be the favorable targets for the J(1)b, K(1)q, and N(1)s, respectively.",3,3,1
Crude Oil,Model,"Li, Yi-Long; Wu, Feng; Li, Xiao-Ping; Tan, Xiao-Hua",Experimental study on waterflood development in large-scale karst structures,Karst structure; Waterflood experiment; Large-scale three-dimensional physical model; Two-phase flow of oil/water,FLUID-FLOW; PERMEABILITY; SIMULATION,"On the basis of the seismic data volume of a certain well group unit of the Tahe fracture-vuggy reservoirs, the similarity theory is adopted, and a numerical model with geometric, kinematic, dynamic, and fracture-cavity characteristic parameter similarities is designed. Moreover, a large-scale three-dimensional physical karst cave model is built with the carving technology. The model is used in the experimental study of two-phase flow of oil/ water during waterflood development and in the analysis of relevant influencing factors. Results show that the displacement efficiency of low-high mode is obviously superior to the case of high-low mode. A high crude oil viscosity is found to equate to a low ultimate recovery. High-velocity water flooding improves ultimate recovery but results earlier water breakthrough. Well shutdown improves recovery factor and well shutdown during middle water cut stage achieves optimum effects. Bottom water energy benefits oil reservoir exploitation to some degree.",3,3,2
Crude Oil,Model,"Naderi, Meysam; Khamehchi, Ehsan",Fuzzy logic coupled with exhaustive search algorithm for forecasting of petroleum economic parameters,ARIMA; Bootstrap algorithm; Exhaustive search algorithm; Forecasting oil and gas price and interest rate; Fuzzy logic; Mamdani-type and TSK,OIL PRICE SHOCKS; CRUDE-OIL; NEURAL-NETWORK; MACROECONOMY; PERFORMANCE; COMBUSTION; EMISSION; MODELS; OUTPUT,"In the upstream of oil and gas sector, many development plans and strategic decisions are based on economic calculations. Therefore, it is so important to establish novel models for accurate forecasting of economic variables with minimized error. In this study, two rule-based fuzzy inference systems based on Mamdani-type and TSK models coupled with exhaustive search algorithm are applied to forecast monthly oil price (MOP), daily gas price (DGP), and annually interest rate (AIR). All required data were collected from Central Bank of the Islamic Republic of Iran. In addition, autoregressive integrated moving average (ARIMA) model is used as a reasonable benchmark to identify whether the proposed fuzzy based methods can outperform ARIMA models for forecasting of economic factors. The statistical significance of results is evaluated using a bootstrap algorithm and various error criteria. The results show that Mamdani-type outperforms ARIMA and TSK in MOP, DGP, and AIR forecast. The results indicate that optimized Mamdani-type reduces RMSE by 69.19% MOP prediction, by 84.37% in DGP prediction, and by 93.67% in AIR prediction over benchmark method.",4,4,0
Crude Oil,Model,"Saghafi, Hamid Reza; Rostami, Alireza; Arabloo, Milad",Evolving new strategies to estimate reservoir oil formation volume factor: Smart modeling and correlation development,Oil formation volume factor; Adaptive network-based fuzzy inference system; Genetic programming; PVT data,PVT PROPERTIES; CRUDE-OIL; EMPIRICAL CORRELATION; CO2 SOLUBILITY; SVM FRAMEWORK; PREDICTION; PRESSURE; TEMPERATURE; SYSTEMS; ALGORITHMS,"The precise estimation of oilfield PVT properties is of primary importance for improving field evaluation and development strategies. In the present work, adaptive network-based fuzzy inference system (ANFIS) and genetic programming (GP) models were established for the accurate assessment of reservoir oil formation volume factor (OFVF). A large database including nearly 1200 datapoints from all over the globe was collected for modeling. The performance of the new models was compared to correlations in the existing literature via several graphical and statistical paradigms. Variance approach analysis was implemented to determine the sensitivity of the target parameter as the output with respect to each input variable. It is shown that the highest forecasting accuracy is attained using the developed ANFIS model and GP-based empirical correlation with an average absolute relative deviation (AARD%) of 1.8% and 2.1%, respectively, in comparison to the results obtained from other approaches described in the literature. Lastly, the mathematical techniques designed for estimating OFVF can be of high importance for experts working with reservoir simulation and PVT analysis.",5,5,0
Crude Oil,Model,"Bemani, Amin; Poozesh, Abdolrahman; Bahrami, Masoud; Ashoori, Siavash",Experimental study of asphaltene deposition: Focus on critical size and temperature effect,Asphaltene deposition; Deposition critical size; Temperature effect; Capillary tube; Deposition rate,CRUDE OILS; AGGREGATION; PRECIPITATION; ISLAND; MODEL,"Asphaltene by far is the most problematic part of crude oil that could separate from oil body as a result of any change in system equilibrium. It can deposit at any point along oil flow path which in turn impose series restrictions, and subsequently create major impact on production from economic perspective. In this study, the influence of oil composition, flow rate, and for the first time, temperature on the intensity of deposition process are experimentally investigated. An in-house deposition unit apparatus was utilized which is based on the measurement of pressure drop across the capillary tube. The results indicate that in overall, temperature and oil composition change toward less soluble asphaltene, accelerate deposition process while flow rate enforces further restriction on process. In addition, by devising novel centrifugal based deposition experiments, critical size concept is more effectively addressed. The concept argues that there is a critical value for asphaltene aggregate size, beyond which the deposition will not occur. This critical size is not necessarily influence by hydrodynamic drag like forces.",5,5,2
Crude Oil,Model,"do Carmo, Wesley P.; Lenzi, Marcelo K.; Lenzi, Ervin K.; Fortuny, Montserrat; Santos, Alexandre F.",A fractional model to relative viscosity prediction of water-in-crude oil emulsions,Relative viscosity; Fractional calculus; Petroleum; Emulsions,CALCULUS; SUSPENSIONS; DEMULSIFICATION; AGGREGATION; TEMPERATURE; DERIVATIVES; SPHERES; FLOW,"The objective of this work was to propose a new model based on the theory of fractional calculus to predict the relative viscosity of petroleum emulsions. For this, stable emulsions with water content ranging from 10 to 65 wt % were prepared from three Brazilian crude oils: A (API 24.6), B (API 16.8) and C (API 13.5), with different contents of saturates, aromatics, resins and asphaltenes. Stable emulsions were prepared using an Ultra-Turrax homogenizer and the viscosity data were obtained from an Anton Paar Controlled Rheometer. The proposed fractional model was able to describe the experimental data very well, yielding a mean correlation coefficient (<(R-2)over bar>) above 0.99 in all tests and mean deviations of the order of 6%. For comparison purposes, the models of Mooney (1951) and Pal and Rhodes (1989) were applied to the same experimental data and presented mean deviations of up to 21% and 18%, respectively. Finally, based on the formulated theory, it is shown that the fractional model parameters (k(1), k(2), alpha) may be related to the mass fraction of saturates, aromatics, resins and asphaltenes (SARA) existing in the crude oils.",5,5,2
Crude Oil,Model,"Kamel, Abdulrahim; Alomair, Osamah; Elsharkawy, Adel",Measurements and predictions of Middle Eastern heavy crude oil viscosity using compositional data,Heavy oil; Viscosity; Correlation; Corresponding state; Equation of state,EQUATION-OF-STATE; RESERVOIR FLUIDS; MODEL; PRESSURE,"Determining the viscosity of heavy crude oil is important in the field of petroleum science, and reservoir simulators are routinely used to achieve this goal. In this study, a new empirical model for predicting heavy-oil viscosity is presented. The model was developed using the compositional data of 28 heavy crude oil samples from the Middle East. Viscosity measurements from 196 data points in the 20-80 degrees C temperature range were used during model development, and another 47 viscosity measurements were used to validate the model. The compositional and viscosity measurements were also used to evaluate the accuracy of previously published methods for predicting heavy-oil viscosities. These methods include corresponding-states models, residual viscosity models, and equations-of-state-based models. The study reveals that none of the previously published methods adequately predict the viscosities of heavy crude oils. On the other hand, it shows that the new empirical model is able to predict the viscosities of heavy oils with an average relative error of 3.8%. The proposed model is much simpler and easier to use than existing methods.",5,5,2
Crude Oil,Interfacial Tension,"Leitenmueller, Verena; Rupprecht, Bernhard J.",A multidisciplinary approach for chemical EOR screening: Understanding alkali-oil interaction by the use of petroleum geochemistry,Biodegradation; Phase screening; Potassium carbonate; Reservoir engineering; Organic geochemistry; ASP flooding; Chemical flooding,INTERFACIAL-TENSION; VIENNA BASIN; SYSTEMS; MECHANISMS,"Alkali-based chemical enhanced oil recovery is used to increase the incremental oil production and relies on the interaction of alkali lye with crude oil. Optimizing the chemical formulation depends on screening multiple alkali concentration ranges to maximize the generated emulsion volume. However, the strong chemical variation of the crude oil, caused by biodegradation within the reservoirs, and its influence on generating in-situ soaps has never been studied in detail. In this paper, organic geochemical oil characterization was combined with phase screening data. Thereby, differences in terms of initial crude oil composition (slightly degraded, moderate degraded, and heavy degraded oils), but also regarding the excess alkali-equilibrated oil phase, and the hydrocarbons which are included in the in-situ soap (emulsion phase) were worked out. Different alkalis, concentration ranges, and water-oil-ratios were studied, to understand the control mechanism for the in-situ soap generation. The formed emulsions were observed over time (emulsion stability) and classified into possible emulsion types. Alterations caused by the alkali-oil interaction were quantified by the use of organic geochemistry. The degree of biodegradation seems to be an important control mechanism. Slightly degraded oils do not interact with the alkali lye due to a high content of non-polar compounds such as alkanes and isoprenoids. Moderately and heavily degraded oils show varying interactions with the alkali solution. The degree of interaction depends on the used degradation type, the alkali type as well as on the used concentration. Moderately degraded oils interact in a lower concentration range compared to heavily degraded oils, which show an increased non-soap forming acid content. Phase experiments conducted over a long period of time (100 days) were used to determine which emulsion types (micro or macro) were formed. Stable micro emulsions were preferably generated over time in formulations prepared with potassium carbonate (K2CO3). In contrast, formulations containing sodium carbonate (Na2CO3) hardly did not generate stable micro emulsions. The composition of alkali-equilibrated oil differs from the initial oil composition and shows a strong dependency of the used alkali type. Potassium carbonate caused mild alterations of the moderately and heavily degraded oils, whereas the impact of sodium carbonate was more severe. In addition, dissolution of naphthalenes, steranes, hopanes, and parts of the generated in-situ soap into the aqueous phase, was observed during the performed phase experiments of the moderately degraded oils (at the elevated pH values).",2,2,0
Crude Oil,Interfacial Tension,"Al Hinai, Nasser M.; Myers, Matthew B.; Dehghani, Ali Mousavi; Wood, Colin D.; Valdez, R.; Jin, Fayang; Xie, Quan; Saeedi, A.",Effects of oligomers dissolved in CO2 or associated gas on IFT and miscibility pressure with a gas-light crude oil system,Associated gas; Miscible gas injection; Thickened gas; Equilibrium interfacial tension; Minimum miscibility pressure; First contact miscibility pressure; Cloud point pressure,INTERFACIAL-TENSION; MOLECULAR SIMULATION; CARBON-DIOXIDE; THERMODYNAMIC PROPERTIES; SUPERCRITICAL CO2; DIRECT THICKENERS; PHASE-BEHAVIOR; SOLUBILITY; POLYMERS; HYDROCARBON,"The solubility of an oligomer in a supercritical gas solvent (e.g. CO2 or associated gas (AG) mixture) and the subsequent effects on the phase behaviour, interfacial tension (IFT) and miscibility pressure of the in-situ oil/oligomer-thickened gas system at a molecular level are crucial to understanding and designing a thickened miscible gas injection (MGI) process. We have conducted cloud point pressure measurements, which revealed that the phase behaviour of P-1-D-thickened CO2 would follow a UCST (upper critical solution temperature) trend while P-1-D-thickened AG mixture would lie close to a LCST (lower critical solution temperature) behaviour. Moreover, our measured equilibrium IFTs of crude oil/P-1-D-thickened CO2 system and crude oil/PVEE-thickened CO2 system were found to be slightly lower than those of the crude oil/CO2 system. This results in a slight reduction in the MMP (minimum miscibility pressure) and considerable reduction in the first contact miscibility pressure (P-max). We found the dissolution of P-1-D in the AG mixture to cause an increase in the equilibrium IFT for the crude oil/P-1-D-thickened AG mixture system, resulting in an increase in both of the MMP and P-max. This indicates that the dissolution of an oligomer may have a considerable effect on the crude oil/thickened gas IFT behaviour at a pressure close to the cloud point pressure.",2,2,2
Crude Oil,Interfacial Tension,"Angardi, Vahideh; Mohan, Ram; Shoham, Ovadia",Statistical approach to estimate coalescence of a single droplet at interface affected by aqueous phase composition,Statistical approach; Coalescence Time Measurement; Separation of oil and water dispersions; Single droplet; Droplet size; Viscosity of the continuous phase and the composition of aqueous phase,,"A significant portion of the world's crude oil is produced in the form of oil-water emulsions. The effective separation of oil and water dispersions could be considered as one of the critical steps in determination of the economic and technical success of the petroleum industry for many years. Deep understanding of basic droplet coalescence at the interface and different parameters that are effecting on this phenomenon is essential for characterization of the global phase separation. An experimental investigation of the coalescence of single droplet at the interface of Exxsol-aqueous phase was carried, with emphasis on the effect of aqueous phase composition and droplet size on stability of droplets. A Coalescence Time Measurement (CTM) facility is utilized to measure mean coalescence time at the liquid-liquid interface and examine how it could be affected by droplet size, viscosity of the continuous phase and the composition of aqueous phase, which is crucial for characterization of the global separation process. Moreover statistical analysis of CTM data is conducted to develop relationship among the coalescence time and process controllable variables (droplet size, continuous phase viscosity, interfacial tension, density of dispersed phase and continuous phase, salinity and hydrate inhibitor concentration).",2,2,2
Crude Oil,Interfacial Tension,"Hamidian, Ramtin; Lashkarbolooki, Mostafa; Amani, Hossein","Ion type adjustment with emphasize on the presence of NaCl existence; measuring interfacial tension, wettability and spreading of crude oil in the carbonate reservoir",Spreading; Wettability; IFT; EOR; Salt; Ionic strength,SURFACE FREE-ENERGY; SMART-WATER; SALINITY; RECOVERY; INJECTION; CHALK; ADHESION; SEAWATER; EOR; COEFFICIENT,"Finding the high-performance anions and cations in the aqueous solutions are crucially required during the smart water injection make it the main core of many enhanced oil recovery (EOR) studies. Nevertheless the previously published literature revealed a lack of understanding about the synergistic or antagonistic effect of NaCl (as the most abundant salt in the sea water) and other salts with the same ionic strength on the interfacial tension (IFT), wettability alteration and spreading coefficient. Therefore, the main purpose of this study is aimed on this concern. To reach this goal, the dynamic IFT values of crude oil/different aqueous solutions with ionic strength of 0.7M and contact angle values between these phases on the oil wet carbonate surface soaked under different times in the prepared aqueous solutions are measured. After that, the measured values are used to calculate the spreading coefficient and distribution capability of oil and water phases on the carbonate rock surface. The obtained results revealed that to change the wetting state of carbonate rock toward a more water wet state, a synergistic effect was observed between NaCl and salts containing sulfate anion, i.e. Na2SO4. and MgSO4.",4,4,0
Crude Oil,Interfacial Tension,"Al-Khafaji, Arije; Wen, Dongsheng",Quantification of wettability characteristics for carbonates using different salinities,Low salinity flooding; Enhanced oil recovery; Carbonate reservoir; Wettability; Interfacial tension; Adhesion force,OIL-RECOVERY; CRUDE OILS; INTERFACIAL ACTIVITY; SMART WATER; INJECTION; BRINE; IONS; ASPHALTENE; RESERVOIR; TENSION,"Low salinity water flooding has received strong interest recently. It has been reported that injecting low salinity water can improve oil recovery in carbonate reservoirs through wettability alteration, whose mechanism however remains unclear, especially regarding the contributions from adsorbed polar organic components. This work investigates systematically the key parameters that govern the complex interactions of rock/brine/crude oil in carbonate reservoirs. The effects of crude oil composition and salinity on surface wettability alteration are studied by using three types of dead oil from Norwegian and North Sea with various acid numbers and two types of carbonate rocks (outcrop-calcite and subsurface-dolomite). Ion-substitution-adsorption is evaluated using the infrared spectrometer (IFR) and energy-dispersive X-ray spectroscopy (EDX). Oil/brine interactions by means of the interfacial tension (IFT) and contact angle as a function of oil composition, rock type, and salinity are experimentally investigated. The IFR and EDX data indicate a compositional change when the carbonate minerals are in touch with saline solutions, supporting the proposed rock-brine interaction mechanism. The salinity effect is more salient at the liquid/rock interface than the liquid/liquid interface, and the response to the brine composition is highly dominated by the oil composition with respect to its content of polar organic components. There is a reduction of contact angle as the seawater water is diluted twice while its influence on the IFT is small, and the effect is more pronounced for dolomite rock, showing different results for different crude oils used. This suggests that the wettability alteration of carbonate rock is an intricate phenomenon that is influenced not only by the salinity but also by the chemical composition of crude oil and rock mineralogy. A combination of three possible mechanisms, including multiple ion exchange, EDL expansion (electrokinetics repulsive), and salting-out, is discussed to illustrate the mechanism of wettability alteration during low salinity injection.",5,6,1
Crude Oil,Interfacial Tension,"Orrego-Ruiz, Jorge A.; Medina-Sandoval, Camila F.; Castillo Hinds, Carmen; Villar-Garcia, Alvaro; Rojas-Ruiz, Fernando A.",FT-ICR MS determination of the role of naphthenic acids on the stabilization of alkali/surfactant/polymer emulsified effluents: A field study,Microemulsions; Enhanced oil recovery; ASP flooding; Surfactants; Emulsion stability; FT-ICR MS,ENHANCED OIL-RECOVERY; RESONANCE MASS-SPECTROMETRY; INTERFACIAL-TENSION; PHASE-BEHAVIOR; CRUDE OILS; SURFACTANT; ASPHALTENES; ADSORPTION; STABILITY; EMULSIONS,"Numerous Alkali/Surfactant/Polymer flooding (ASP) projects have been developed worldwide. Nevertheless, some disadvantages have limited the success of ASP during the execution in field, such as injection lines scaling and strong emulsification of the produced fluids. Commonly, appropriate formulations for particular reservoir conditions are selected after a series of evaluation steps. These includes tests of surfactants, polymers and commercially available alkali, based on the reservoir temperature, reservoir salinity, reservoir water pH, rock permeability, formation type and adsorption of the surfactant on the matrix rock, to obtain the highest oil recovery at the lowest cost. As part of the different strategies adopted for increasing the oil recovery factor, San Francisco oil field, Huila Colombia, was selected in 2012 for ASP flooding application at pilot scale. After two years of injection, ASP effluents affected considerably the quality of water and its treatment for reinjection. The present work focuses on the compositional study of the production effluents obtained after ASP flooding. A detailed analysis using Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) allowed disclosing the role of natural organic acids on reducing the interfacial tension which in turn entailed highly stable microemulsions. Together with the added surfactant, naphthenic acids (because of the alkaline pH) prompts the formation of these thermodynamically stable oil in water systems. A test using an acid free oil proved that the formation of microemulsions strongly depends on naphthenic acids presence. Additional tests using oils with different acidity showed the dependence on the naphthenics acids structure over the emulsion stability. The results obtained in this study stands out FT-ICR MS as a prominent tool on understanding breaking and/or clarifying treatment processes from a molecular level point of view and thus, could help on proposing a correct and cost effective water treatment.",5,5,2
Crude Oil,Interfacial Tension,"Adewunmi, Ahmad A.; Kamal, Muhammad Shahzad; Solling, Theis Ivan; Salami, Babatunde Abiodun",Palm oil fuel ash (POFA) as a demulsifier for crude oil emulsions: Performance and mechanism,Emulsion; Seawater; Oil; POFA; Demulsification,IN-WATER EMULSIONS; EFFICIENT DEMULSIFICATION; MAGNETIC NANOPARTICLES; BY-PRODUCT; ADSORPTION; MICROWAVE; STRENGTH; COMPOSITE; OXIDE; WASTE,"The petroleum industry is greatly in need of smart and cheap demulsifiers to break heavy crude oil emulsions. This study investigates the performance of palm oil fuel ash (POFA) as a demulsifier of crude oil emulsions produced during hydrocarbon exploration. Highly stable water-in-oil (W/O) emulsions having water:oil ratio of 7:3 were prepared under room temperature (25 degrees C) at a mixing speed of 1500 rpm. Demulsification performance of various concentrations of POFA (1 wt% to 9 wt%) was performed using the bottle test method at 60 degrees C and 80 degrees C. Experimental results show that POFA can effectively break the emulsion and separates water/oil into phases. The emulsion containing 3 wt% POFA exhibited the highest water/oil separation with demulsification efficiencies (DEs) of 99.28% and 99.71% at 60 degrees C and 80 degrees C, respectively. Additionally, a comparison between POFA and a commercial demulsifier (poloxamer - 407) showed that POFA can compete favorably with demulsifiers regularly applied in oil fields. Optical electron microscope analysis revealed the morphology of water and oil phases after emulsion separation. Results from the rheological measurements established the capacity of POFA to be able to destabilize the natural emulsifiers existing at the water/oil interface. Interfacial tension results show that POFA particles have a strong tendency to diminish the water/oil interfacial films. An investigation of the demulsification mechanism reveals that silica in POFA plays a critical role in the breaking of stable crude oil emulsions. Certainly, POFA will be a promising demulsification material for separating or removing water from all forms of emulsions produced in the oil fields.",5,5,2
Crude Oil,Prediction,"Karacan, C. Ozgen",An ANCOVA model for porosity and its uncertainty for oil reservoirs based on TORIS dataset,Mean value; Depositional system; Multi-linear regression; Reservoir assessment; ANCOVA; TORIS,PERMEABILITY PREDICTION; SEDIMENTARY; NORTH; SANDSTONE; EOCENE; ROCKS,"Porosity is one of the most important parameters to assess in-place oil or gas in reservoirs, and to evaluate recovery from enhanced production operations. Since it is relatively well-established to determine porosity using different laboratory and field methods, its value is usually determined at many locations across a reservoir as part of the common practice to capture reservoir heterogeneity and the variability in values. This suite of measurements and the distribution of values are most valuable for probabilistic reservoir assessments, and for spatial modeling if the exact data locations are known. Despite the importance of individual measurements to set the range of values for probabilistic studies, it is not always possible to access these data due to confidentiality. In most cases, commercial or publicly available databases that assessments may rely on usually report only mean values of porosity, like any other reservoir data, or they may not report a value at all. This makes both quantifying the mean value and the uncertainty around it difficult for probabilistic assessments. In this study, the TORIS (Tertiary Oil Recovery Information System) dataset of the National Petroleum Council and the U.S. Department of Energy was used to model porosity and the uncertainty around predicted values. TORIS is an integrated dataset of production data, reservoir properties, and project databases of crude oil reservoirs in the United States. The model presented in the paper was based on ANCOVA (Analysis of Co-Variance) of data from 1038 reservoirs from the TORIS dataset for porosity prediction, validation and testing for quantitative and qualitative parameters that may be readily available in most cases, and to estimate uncertainty around the mean values. This model also explored association of porosity values to different parameters, and to different depositional systems and diagenetic overprint conditions. Furthermore, an ANN (Artificial Neural Network) model was created to compare the predicted values of both models. Results showed that the ANN model was able to represent more of the variability, however it lacked the insights that might be gained from the ANCOVA model.",1,1,0
Crude Oil,Prediction,"Zhang, Jian; Chen, Xiao-Ping; Xu, Jing-yu",Rheological characteristics of unstable heavy crude oil-water dispersed mixtures,Heavy crude oil; Unstable mixtures; Apparent viscosity; Oil-water mixture,VISCOSITY PREDICTION; STABILITY; EMULSIONS; BEHAVIOR; FLOW; INVERSION,"The rheological characteristics of unstable heavy crude oil-water dispersed mixtures were investigated to improve pipeline transportation. The viscosity of heavy crude oil is 5439 mPa s, and density is 955 kg/m(3) at 30 degrees C. A series of factors, including oil volume fraction, shear rate, and temperature, was considered systematically to investigate the phenomenon of phase inversion and stability of oil-water mixtures. The results show that the apparent viscosity of a heavy crude oil-water mixture reaches its maximum value at the phase inversion point, and that the non-Newtonian fluid characteristics of unstable heavy crude oil-water mixtures are different than those of fine emulsions or light oil-water mixtures. The addition of emulsifier influences the apparent viscosity and phase inversion point by changing the droplet size distribution. Furthermore, the apparent viscosity of a heavy crude oil-water mixture continues to increase as the median diameter of the dispersed phase decreases. All these are beneficial to the analysis of the rheological characteristics of heavy crude oil-water dispersed mixtures.",2,2,6
Crude Oil,Prediction,"Wen, Jiangbo; Luo, Haijun; Long, Zhiqin",Emulsification behaviors of crude oil-water system and its quantitative relationship with exergy loss rate,Crude oil-water system; Flowing; Emulsification behaviors; Mixing degree coefficient; Exergy loss rate,LIQUID-LIQUID; PIPELINE TRANSPORTATION; EFFECTIVE VISCOSITY; FLOW; EMULSIONS; MECHANISMS; PREDICTION; SEPARATION; FLUID,"Emulsification behaviors of crude oil-water system has significant effects on flow pattern and pressure drop of crude oil-water two phase flow. The degree of emulsification, which is greatly affected by shearing intensity, water volume fraction and temperature, can be characterized by emulsified water fraction under flowing conditions. There are eight crude oils were used in emulsification experiments by stirring to study the effects of shear rate, water volume fraction and temperature on the emulsified water fraction under flowing conditions. Complete emulsification was observed below a critical water volume fraction, with the emulsified water fraction equal to the water volume fraction of the system; while there was only incomplete emulsification when the water volume fraction was higher than the critical value, with the emulsified water fraction less than the water volume fraction of the system. A mixing degree coefficient c(m) was proposed to characterize the mixing effect of crude oil-water system. It was found that the value of c(m) getting more close to 1.0 meant the better mixing effect, if not, the mixing effect was worse. For incomplete emulsification, the exergy loss rate during stirring was found to characterize the effects of shear rate, water volume fraction and temperature on the emulsified water fraction under flowing conditions in the unified way. Further, a power law correlation was proposed between the emulsified water fraction under flowing conditions and the exergy loss rate, which can be applied to the process calculation of the multiphase transportation pipelines.",3,4,3
Crude Oil,Prediction,"Naderi, Meysam; Khamehchi, Ehsan",Fuzzy logic coupled with exhaustive search algorithm for forecasting of petroleum economic parameters,ARIMA; Bootstrap algorithm; Exhaustive search algorithm; Forecasting oil and gas price and interest rate; Fuzzy logic; Mamdani-type and TSK,OIL PRICE SHOCKS; CRUDE-OIL; NEURAL-NETWORK; MACROECONOMY; PERFORMANCE; COMBUSTION; EMISSION; MODELS; OUTPUT,"In the upstream of oil and gas sector, many development plans and strategic decisions are based on economic calculations. Therefore, it is so important to establish novel models for accurate forecasting of economic variables with minimized error. In this study, two rule-based fuzzy inference systems based on Mamdani-type and TSK models coupled with exhaustive search algorithm are applied to forecast monthly oil price (MOP), daily gas price (DGP), and annually interest rate (AIR). All required data were collected from Central Bank of the Islamic Republic of Iran. In addition, autoregressive integrated moving average (ARIMA) model is used as a reasonable benchmark to identify whether the proposed fuzzy based methods can outperform ARIMA models for forecasting of economic factors. The statistical significance of results is evaluated using a bootstrap algorithm and various error criteria. The results show that Mamdani-type outperforms ARIMA and TSK in MOP, DGP, and AIR forecast. The results indicate that optimized Mamdani-type reduces RMSE by 69.19% MOP prediction, by 84.37% in DGP prediction, and by 93.67% in AIR prediction over benchmark method.",4,4,0
Crude Oil,Prediction,"Saghafi, Hamid Reza; Rostami, Alireza; Arabloo, Milad",Evolving new strategies to estimate reservoir oil formation volume factor: Smart modeling and correlation development,Oil formation volume factor; Adaptive network-based fuzzy inference system; Genetic programming; PVT data,PVT PROPERTIES; CRUDE-OIL; EMPIRICAL CORRELATION; CO2 SOLUBILITY; SVM FRAMEWORK; PREDICTION; PRESSURE; TEMPERATURE; SYSTEMS; ALGORITHMS,"The precise estimation of oilfield PVT properties is of primary importance for improving field evaluation and development strategies. In the present work, adaptive network-based fuzzy inference system (ANFIS) and genetic programming (GP) models were established for the accurate assessment of reservoir oil formation volume factor (OFVF). A large database including nearly 1200 datapoints from all over the globe was collected for modeling. The performance of the new models was compared to correlations in the existing literature via several graphical and statistical paradigms. Variance approach analysis was implemented to determine the sensitivity of the target parameter as the output with respect to each input variable. It is shown that the highest forecasting accuracy is attained using the developed ANFIS model and GP-based empirical correlation with an average absolute relative deviation (AARD%) of 1.8% and 2.1%, respectively, in comparison to the results obtained from other approaches described in the literature. Lastly, the mathematical techniques designed for estimating OFVF can be of high importance for experts working with reservoir simulation and PVT analysis.",5,5,0
Crude Oil,Prediction,"do Carmo, Wesley P.; Lenzi, Marcelo K.; Lenzi, Ervin K.; Fortuny, Montserrat; Santos, Alexandre F.",A fractional model to relative viscosity prediction of water-in-crude oil emulsions,Relative viscosity; Fractional calculus; Petroleum; Emulsions,CALCULUS; SUSPENSIONS; DEMULSIFICATION; AGGREGATION; TEMPERATURE; DERIVATIVES; SPHERES; FLOW,"The objective of this work was to propose a new model based on the theory of fractional calculus to predict the relative viscosity of petroleum emulsions. For this, stable emulsions with water content ranging from 10 to 65 wt % were prepared from three Brazilian crude oils: A (API 24.6), B (API 16.8) and C (API 13.5), with different contents of saturates, aromatics, resins and asphaltenes. Stable emulsions were prepared using an Ultra-Turrax homogenizer and the viscosity data were obtained from an Anton Paar Controlled Rheometer. The proposed fractional model was able to describe the experimental data very well, yielding a mean correlation coefficient (<(R-2)over bar>) above 0.99 in all tests and mean deviations of the order of 6%. For comparison purposes, the models of Mooney (1951) and Pal and Rhodes (1989) were applied to the same experimental data and presented mean deviations of up to 21% and 18%, respectively. Finally, based on the formulated theory, it is shown that the fractional model parameters (k(1), k(2), alpha) may be related to the mass fraction of saturates, aromatics, resins and asphaltenes (SARA) existing in the crude oils.",5,5,2
Crude Oil,Prediction,"Kamel, Abdulrahim; Alomair, Osamah; Elsharkawy, Adel",Measurements and predictions of Middle Eastern heavy crude oil viscosity using compositional data,Heavy oil; Viscosity; Correlation; Corresponding state; Equation of state,EQUATION-OF-STATE; RESERVOIR FLUIDS; MODEL; PRESSURE,"Determining the viscosity of heavy crude oil is important in the field of petroleum science, and reservoir simulators are routinely used to achieve this goal. In this study, a new empirical model for predicting heavy-oil viscosity is presented. The model was developed using the compositional data of 28 heavy crude oil samples from the Middle East. Viscosity measurements from 196 data points in the 20-80 degrees C temperature range were used during model development, and another 47 viscosity measurements were used to validate the model. The compositional and viscosity measurements were also used to evaluate the accuracy of previously published methods for predicting heavy-oil viscosities. These methods include corresponding-states models, residual viscosity models, and equations-of-state-based models. The study reveals that none of the previously published methods adequately predict the viscosities of heavy crude oils. On the other hand, it shows that the new empirical model is able to predict the viscosities of heavy oils with an average relative error of 3.8%. The proposed model is much simpler and easier to use than existing methods.",5,5,2
Crude Oil,Degrees C.,"Mandal, Arnab; Mahto, Vikas; Purohit, Subodh; Nihalani, M. C.",Evaluation of synthesized polymeric additives as paraffin inhibitors for wax dissolution in the petroleum reservoir rock,Crude oil; Paraffin inhibitor; Contact angle hysteresis; Sandstone core,POUR POINT DEPRESSANT; FLOW PROPERTIES,"Precipitation of paraffin in petroleum reservoir rock can be a challenge to oil productivity for oil and gas industries. Paraffins exist in equilibrium with the crude oil under normal reservoir temperature and pressure. During the flow of crude oil through the petroleum formation, the proportion of lighter ends in crude oil underwent variation on account of localized pressure fluctuations. It led to reduction in solubility of heavy molecular weight hydrocarbons and they precipitate in the form of wax in the pores of reservoir rock. In this paper, wax deposition from crude oil was investigated using an experimental set up. The crude oil was characterized as medium heavy and waxy crude oil. Two paraffin inhibitors were synthesized in laboratory based on amination reaction of maleic anhydride with unsaturated amines. The monomer formed underwent free radical polymerization at 75 degrees C. The synthesized inhibitor was doped in crude oil to check wax dissolution through pores as compared to commercial paraffin inhibitors. In addition, the core was aged with crude oil for 15 days and alteration in its wettability was evaluated through changes in contact angle hysteresis with paraffin dissolution. It was found that synthesized paraffin inhibitors showed higher contact angle hysteresis as compared to commercial paraffin inhibitors, indicating excellent solubilisation of wax deposit in the pores of core.",0,0,0
Crude Oil,Degrees C.,"Zhang, Jian; Chen, Xiao-Ping; Xu, Jing-yu",Rheological characteristics of unstable heavy crude oil-water dispersed mixtures,Heavy crude oil; Unstable mixtures; Apparent viscosity; Oil-water mixture,VISCOSITY PREDICTION; STABILITY; EMULSIONS; BEHAVIOR; FLOW; INVERSION,"The rheological characteristics of unstable heavy crude oil-water dispersed mixtures were investigated to improve pipeline transportation. The viscosity of heavy crude oil is 5439 mPa s, and density is 955 kg/m(3) at 30 degrees C. A series of factors, including oil volume fraction, shear rate, and temperature, was considered systematically to investigate the phenomenon of phase inversion and stability of oil-water mixtures. The results show that the apparent viscosity of a heavy crude oil-water mixture reaches its maximum value at the phase inversion point, and that the non-Newtonian fluid characteristics of unstable heavy crude oil-water mixtures are different than those of fine emulsions or light oil-water mixtures. The addition of emulsifier influences the apparent viscosity and phase inversion point by changing the droplet size distribution. Furthermore, the apparent viscosity of a heavy crude oil-water mixture continues to increase as the median diameter of the dispersed phase decreases. All these are beneficial to the analysis of the rheological characteristics of heavy crude oil-water dispersed mixtures.",2,2,6
Crude Oil,Degrees C.,"Wen, Jiangbo; Luo, Haijun; Long, Zhiqin",Emulsification behaviors of crude oil-water system and its quantitative relationship with exergy loss rate,Crude oil-water system; Flowing; Emulsification behaviors; Mixing degree coefficient; Exergy loss rate,LIQUID-LIQUID; PIPELINE TRANSPORTATION; EFFECTIVE VISCOSITY; FLOW; EMULSIONS; MECHANISMS; PREDICTION; SEPARATION; FLUID,"Emulsification behaviors of crude oil-water system has significant effects on flow pattern and pressure drop of crude oil-water two phase flow. The degree of emulsification, which is greatly affected by shearing intensity, water volume fraction and temperature, can be characterized by emulsified water fraction under flowing conditions. There are eight crude oils were used in emulsification experiments by stirring to study the effects of shear rate, water volume fraction and temperature on the emulsified water fraction under flowing conditions. Complete emulsification was observed below a critical water volume fraction, with the emulsified water fraction equal to the water volume fraction of the system; while there was only incomplete emulsification when the water volume fraction was higher than the critical value, with the emulsified water fraction less than the water volume fraction of the system. A mixing degree coefficient c(m) was proposed to characterize the mixing effect of crude oil-water system. It was found that the value of c(m) getting more close to 1.0 meant the better mixing effect, if not, the mixing effect was worse. For incomplete emulsification, the exergy loss rate during stirring was found to characterize the effects of shear rate, water volume fraction and temperature on the emulsified water fraction under flowing conditions in the unified way. Further, a power law correlation was proposed between the emulsified water fraction under flowing conditions and the exergy loss rate, which can be applied to the process calculation of the multiphase transportation pipelines.",3,4,3
Crude Oil,Degrees C.,"Adewunmi, Ahmad A.; Kamal, Muhammad Shahzad; Solling, Theis Ivan; Salami, Babatunde Abiodun",Palm oil fuel ash (POFA) as a demulsifier for crude oil emulsions: Performance and mechanism,Emulsion; Seawater; Oil; POFA; Demulsification,IN-WATER EMULSIONS; EFFICIENT DEMULSIFICATION; MAGNETIC NANOPARTICLES; BY-PRODUCT; ADSORPTION; MICROWAVE; STRENGTH; COMPOSITE; OXIDE; WASTE,"The petroleum industry is greatly in need of smart and cheap demulsifiers to break heavy crude oil emulsions. This study investigates the performance of palm oil fuel ash (POFA) as a demulsifier of crude oil emulsions produced during hydrocarbon exploration. Highly stable water-in-oil (W/O) emulsions having water:oil ratio of 7:3 were prepared under room temperature (25 degrees C) at a mixing speed of 1500 rpm. Demulsification performance of various concentrations of POFA (1 wt% to 9 wt%) was performed using the bottle test method at 60 degrees C and 80 degrees C. Experimental results show that POFA can effectively break the emulsion and separates water/oil into phases. The emulsion containing 3 wt% POFA exhibited the highest water/oil separation with demulsification efficiencies (DEs) of 99.28% and 99.71% at 60 degrees C and 80 degrees C, respectively. Additionally, a comparison between POFA and a commercial demulsifier (poloxamer - 407) showed that POFA can compete favorably with demulsifiers regularly applied in oil fields. Optical electron microscope analysis revealed the morphology of water and oil phases after emulsion separation. Results from the rheological measurements established the capacity of POFA to be able to destabilize the natural emulsifiers existing at the water/oil interface. Interfacial tension results show that POFA particles have a strong tendency to diminish the water/oil interfacial films. An investigation of the demulsification mechanism reveals that silica in POFA plays a critical role in the breaking of stable crude oil emulsions. Certainly, POFA will be a promising demulsification material for separating or removing water from all forms of emulsions produced in the oil fields.",5,5,2
Crude Oil,Degrees C.,"Kamel, Abdulrahim; Alomair, Osamah; Elsharkawy, Adel",Measurements and predictions of Middle Eastern heavy crude oil viscosity using compositional data,Heavy oil; Viscosity; Correlation; Corresponding state; Equation of state,EQUATION-OF-STATE; RESERVOIR FLUIDS; MODEL; PRESSURE,"Determining the viscosity of heavy crude oil is important in the field of petroleum science, and reservoir simulators are routinely used to achieve this goal. In this study, a new empirical model for predicting heavy-oil viscosity is presented. The model was developed using the compositional data of 28 heavy crude oil samples from the Middle East. Viscosity measurements from 196 data points in the 20-80 degrees C temperature range were used during model development, and another 47 viscosity measurements were used to validate the model. The compositional and viscosity measurements were also used to evaluate the accuracy of previously published methods for predicting heavy-oil viscosities. These methods include corresponding-states models, residual viscosity models, and equations-of-state-based models. The study reveals that none of the previously published methods adequately predict the viscosities of heavy crude oils. On the other hand, it shows that the new empirical model is able to predict the viscosities of heavy oils with an average relative error of 3.8%. The proposed model is much simpler and easier to use than existing methods.",5,5,2
Crude Oil,Degrees C.,"Adeyanju, Olusiji Ayoade; Oyekunle, Layioye Ola",Experimental study of water-in-oil emulsion flow on wax deposition in subsea pipelines,Demulsifier; Average absolute deviations; Pour point depressants; Validated flow facility; Dispersed water globules,CRUDE; DEMULSIFICATION,"Experiments were performed to simulate the deposition of wax in the flow of crude oil emulsions in subsea pipeline using a validated flow facility. Two crude samples and their respective formation water from two oil fields in southern Nigeria were used to synthetize two different emulsified crude oil samples (A and B). The trapping of the water globules in the wax deposits dominates the wax deposition rate initially but later the shear removal and the molecular diffusion dominate leading to decrease in the wax deposition rate. As the water (BS&W) composition in the emulsion increases from 10 to 40%, the pour point temperature (PPT) increases from 30 to 41 degrees C, and the viscosity increases from 40 mPas to 142 mPa at a crude oil temperature of 26 degrees C. The addition of 45 ppm of long chain acrylate ester co-polymer as pour point depressant depressed the dimensionless wax thickness by 37.5% and 34.3% for the blank emulsified crude oil A and B respectively. The effect of the commercial demulsifier to reduce the wax deposition rate was more successful in crude oil A reducing the wax dimensionless thickness by 58.9% and 43.0% when mixture of 25 ppm of the demulsifier and 45 ppm of long chain acrylate ester co-polymer were added to blank emulsified crude oil A and B respectively. The used demulsifier is more effective in crude oil A compared to crude oil B. Efforts should be made to study the effectiveness of different demulsifiers on each emulsified crude oil before their application for water separation.",5,5,3
Crude Oil,Crude Oil-water,"Kim, Tae Wook; Vittoratos, Euthymios; Kovscek, Anthony R.",Recovery efficiency of a 28 degrees API crude-oil system as a function of voidage replacement ratio,Water flooding; Voidage replacement; Laboratory studies; Improved oil recovery,SOLUTION-GAS DRIVE; RELATIVE PERMEABILITY,"Crude-oil recovery processes with a voidage replacement ratio (VRR = injected volume/produced volume) less than 1 combine solution gas drive mechanisms and viscous crude-oil displacement. Previous laboratory and field studies have shown that a VRR less than 1 for a period of time is optimal for recovery of some viscous and heavy crude oils that form emulsions and/or bubbly oil in situ. This study extends understanding of the effect of VRR to recovery of live, less-viscous crude oils from sands. The crude oil used is roughly 28 degrees API, has a dead-oil viscosity of 26 cP, a live-oil viscosity of 0.41 cP, and an asphalt content of 2.1 wt%. It is found in the laboratory that the final crude-oil recovery (70.5%) using a 0.01 PV/h depletion rate and VRR equal to 0.7 is more than 8% greater than recovery with VRR equal to 1 (65.1%). Recovery using a 0.001 PV/h depletion rate with VRR equal to 0.7 (79.1%) was nearly the same as the sum of oil recoveries for solution gas drive (VRR = 0, 24.5%) plus waterflooding (VRR = 1, 53.4%). For these two depletion rates, the oil recovery obtained using VRR equal to 0.7 is more favorable than VRR = 1 (waterflooding). Relative permeability was inferred from experimental results. Substantial critical gas saturations (8.1-16.1%) also contributed to oil production. A concave shape of the oil/water relative permeability curve indicated an emulsion-like effect that also promoted recovery when the VRR was less than 1.",1,1,0
Crude Oil,Crude Oil-water,"Angardi, Vahideh; Mohan, Ram; Shoham, Ovadia",Statistical approach to estimate coalescence of a single droplet at interface affected by aqueous phase composition,Statistical approach; Coalescence Time Measurement; Separation of oil and water dispersions; Single droplet; Droplet size; Viscosity of the continuous phase and the composition of aqueous phase,,"A significant portion of the world's crude oil is produced in the form of oil-water emulsions. The effective separation of oil and water dispersions could be considered as one of the critical steps in determination of the economic and technical success of the petroleum industry for many years. Deep understanding of basic droplet coalescence at the interface and different parameters that are effecting on this phenomenon is essential for characterization of the global phase separation. An experimental investigation of the coalescence of single droplet at the interface of Exxsol-aqueous phase was carried, with emphasis on the effect of aqueous phase composition and droplet size on stability of droplets. A Coalescence Time Measurement (CTM) facility is utilized to measure mean coalescence time at the liquid-liquid interface and examine how it could be affected by droplet size, viscosity of the continuous phase and the composition of aqueous phase, which is crucial for characterization of the global separation process. Moreover statistical analysis of CTM data is conducted to develop relationship among the coalescence time and process controllable variables (droplet size, continuous phase viscosity, interfacial tension, density of dispersed phase and continuous phase, salinity and hydrate inhibitor concentration).",2,2,2
Crude Oil,Crude Oil-water,"Zhang, Jian; Chen, Xiao-Ping; Xu, Jing-yu",Rheological characteristics of unstable heavy crude oil-water dispersed mixtures,Heavy crude oil; Unstable mixtures; Apparent viscosity; Oil-water mixture,VISCOSITY PREDICTION; STABILITY; EMULSIONS; BEHAVIOR; FLOW; INVERSION,"The rheological characteristics of unstable heavy crude oil-water dispersed mixtures were investigated to improve pipeline transportation. The viscosity of heavy crude oil is 5439 mPa s, and density is 955 kg/m(3) at 30 degrees C. A series of factors, including oil volume fraction, shear rate, and temperature, was considered systematically to investigate the phenomenon of phase inversion and stability of oil-water mixtures. The results show that the apparent viscosity of a heavy crude oil-water mixture reaches its maximum value at the phase inversion point, and that the non-Newtonian fluid characteristics of unstable heavy crude oil-water mixtures are different than those of fine emulsions or light oil-water mixtures. The addition of emulsifier influences the apparent viscosity and phase inversion point by changing the droplet size distribution. Furthermore, the apparent viscosity of a heavy crude oil-water mixture continues to increase as the median diameter of the dispersed phase decreases. All these are beneficial to the analysis of the rheological characteristics of heavy crude oil-water dispersed mixtures.",2,2,6
Crude Oil,Crude Oil-water,"Li, Yi-Long; Wu, Feng; Li, Xiao-Ping; Tan, Xiao-Hua",Experimental study on waterflood development in large-scale karst structures,Karst structure; Waterflood experiment; Large-scale three-dimensional physical model; Two-phase flow of oil/water,FLUID-FLOW; PERMEABILITY; SIMULATION,"On the basis of the seismic data volume of a certain well group unit of the Tahe fracture-vuggy reservoirs, the similarity theory is adopted, and a numerical model with geometric, kinematic, dynamic, and fracture-cavity characteristic parameter similarities is designed. Moreover, a large-scale three-dimensional physical karst cave model is built with the carving technology. The model is used in the experimental study of two-phase flow of oil/ water during waterflood development and in the analysis of relevant influencing factors. Results show that the displacement efficiency of low-high mode is obviously superior to the case of high-low mode. A high crude oil viscosity is found to equate to a low ultimate recovery. High-velocity water flooding improves ultimate recovery but results earlier water breakthrough. Well shutdown improves recovery factor and well shutdown during middle water cut stage achieves optimum effects. Bottom water energy benefits oil reservoir exploitation to some degree.",3,3,2
Crude Oil,Crude Oil-water,"Wen, Jiangbo; Luo, Haijun; Long, Zhiqin",Emulsification behaviors of crude oil-water system and its quantitative relationship with exergy loss rate,Crude oil-water system; Flowing; Emulsification behaviors; Mixing degree coefficient; Exergy loss rate,LIQUID-LIQUID; PIPELINE TRANSPORTATION; EFFECTIVE VISCOSITY; FLOW; EMULSIONS; MECHANISMS; PREDICTION; SEPARATION; FLUID,"Emulsification behaviors of crude oil-water system has significant effects on flow pattern and pressure drop of crude oil-water two phase flow. The degree of emulsification, which is greatly affected by shearing intensity, water volume fraction and temperature, can be characterized by emulsified water fraction under flowing conditions. There are eight crude oils were used in emulsification experiments by stirring to study the effects of shear rate, water volume fraction and temperature on the emulsified water fraction under flowing conditions. Complete emulsification was observed below a critical water volume fraction, with the emulsified water fraction equal to the water volume fraction of the system; while there was only incomplete emulsification when the water volume fraction was higher than the critical value, with the emulsified water fraction less than the water volume fraction of the system. A mixing degree coefficient c(m) was proposed to characterize the mixing effect of crude oil-water system. It was found that the value of c(m) getting more close to 1.0 meant the better mixing effect, if not, the mixing effect was worse. For incomplete emulsification, the exergy loss rate during stirring was found to characterize the effects of shear rate, water volume fraction and temperature on the emulsified water fraction under flowing conditions in the unified way. Further, a power law correlation was proposed between the emulsified water fraction under flowing conditions and the exergy loss rate, which can be applied to the process calculation of the multiphase transportation pipelines.",3,4,3
Crude Oil,Waxy Crude Oil,"Mandal, Arnab; Mahto, Vikas; Purohit, Subodh; Nihalani, M. C.",Evaluation of synthesized polymeric additives as paraffin inhibitors for wax dissolution in the petroleum reservoir rock,Crude oil; Paraffin inhibitor; Contact angle hysteresis; Sandstone core,POUR POINT DEPRESSANT; FLOW PROPERTIES,"Precipitation of paraffin in petroleum reservoir rock can be a challenge to oil productivity for oil and gas industries. Paraffins exist in equilibrium with the crude oil under normal reservoir temperature and pressure. During the flow of crude oil through the petroleum formation, the proportion of lighter ends in crude oil underwent variation on account of localized pressure fluctuations. It led to reduction in solubility of heavy molecular weight hydrocarbons and they precipitate in the form of wax in the pores of reservoir rock. In this paper, wax deposition from crude oil was investigated using an experimental set up. The crude oil was characterized as medium heavy and waxy crude oil. Two paraffin inhibitors were synthesized in laboratory based on amination reaction of maleic anhydride with unsaturated amines. The monomer formed underwent free radical polymerization at 75 degrees C. The synthesized inhibitor was doped in crude oil to check wax dissolution through pores as compared to commercial paraffin inhibitors. In addition, the core was aged with crude oil for 15 days and alteration in its wettability was evaluated through changes in contact angle hysteresis with paraffin dissolution. It was found that synthesized paraffin inhibitors showed higher contact angle hysteresis as compared to commercial paraffin inhibitors, indicating excellent solubilisation of wax deposit in the pores of core.",0,0,0
Crude Oil,Waxy Crude Oil,"Sulaiman, Shaharin A.; Chala, Girma T.; Zainur, Muhammad Z.",Experimental investigation of compressibility of waxy crude oil subjected to static cooling,Waxy crude oil; Compressibility; Compression test; Flow restart,GAS VOID FORMATION; START-UP; FLOW; PIPELINE; RESTART; TRANSPORTATION; TEMPERATURE; FLUIDS,"Transportation of waxy crude oil confronts many difficulties due to the formation of gel in the production pipelines, which interrupts the steady production with low transportation efficiency and this later requires a higher pumping pressure to resume the flow. However, the current conventional equation is perceived to be over-predicted, mainly due to low attention given for the compressibility effects. Compressibility of the waxy crude oil has been theoretically reported to have significant influence on the restart pressure of the flow start-up or restart. Moreover, there is limited study on compressibility of waxy crude oil induced by the formation of intra-gel voids as a result of thermal shrinkage encountered during static cooling. This study is, therefore, aimed at investigating the compressibility of waxy crude oil gel experimentally. The experiment included the use of flow loop rig to produce gel at different conditions. The pressure pump rig was designed and fabricated for the compressibility tests. Experiments were conducted at different cooling rates and seabed temperatures. It was observed that higher seabed temperature and slower cooling rates contribute to higher compressibility tendencies. The specimen with faster cooling rates is proven to be less compressible.",2,2,0
Crude Oil,Waxy Crude Oil,"Yuan, Qing; Li, Jingfa; Liu, Hongfei; Yu, Bo; Sun, Dongliang; Deng, Yajun",Parametric regression of a multiparameter thixotropic model for waxy crude oil based on multiobjective strategy,Waxy crude oil; Thixotropic model; Parametric regression; Multiobjective regression strategy; Regression algorithm,YIELD-STRESS,"The waxy crude oil exhibits a time- and shear-dependent non-Newtonian behavior called thixotropic behavior below the gelation temperature. This behavior can be quantitatively described by using a thixotropic model. However, many parameters are commonly contained in a thixotropic model with good-description capacity, and it still remains challenging to obtain high fitting precision and reasonable physical interpretation simultaneously in the process of parametric regression. In this study, based on a representative multiparameter thixotropic model, a multiobjective regression strategy is put forward. The fitting precision and physical interpretation are taken into account in this regression strategy, and their importance can be adjusted dynamically with the structure breakdown of waxy crude oil. In order to successfully achieve the multiobjective regression strategy, a self-adaptive nondominated sorting differential evolution algorithm (self-adaptive NSDE) is proposed. This regression algorithm is independent on the expressions of the regression model, and thus it can also be applied to the multiobjective parametric regression of other complex models including thixotropic models in rheology field and even other models in different fields. Based on experimental data, the parametric regression of a thixotropic model is performed, and the obtained results are analyzed and discussed in detail. It is found that the regressive data exhibit a small deviation at the starting stage of structure breakdown and the equilibrium flow curve can be ensured at the ending stage of structure breakdown. This finding well verifies considerations of multiobjective regression strategy. Compared with previous three regression strategies in the literature reports, the multi-objective regression strategy exhibits advantages in the fitting precision and physical interpretation.",2,2,1
Crude Oil,Waxy Crude Oil,"Coussirat, Vladimir; Amarilla, Fernando; Peruzzo, Pablo J.; Susana Cortizo, M.",Dioctyl fumarate-co-vinyl benzoate copolymers preparation and their performance as flow improvers in waxy crude oils,Fumaric copolymers; Reactivity ratio; Crude oil rheology; Flow improver,POUR-POINT DEPRESSANTS; RADICAL COPOLYMERIZATION; DIISOPROPYL FUMARATE; REACTIVITY RATIOS; LINEAR METHODS; START-UP; INHIBITORS; ACETATE; VISCOSITY; ACRYLATE,"This work presents the synthesis of new copolymers based on dioctyl fumarate (DOF) and vinyl benzoate (VB) and their application as flow improvers in a waxy crude oil. The copolymers were obtained by solution radical polymerization starting from a broad range of monomer compositions (f(DOF)) and characterized by Fourier-transform infrared spectroscopy (FTIR), Proton Nuclear Magnetic Resonance (H-1-NMR) Spectroscopy and Size exclusion chromatography. Results indicated that polymerization yield and molecular weight increases with decrease in f(DOF). Based on the composition of the copolymers the reactivity coefficients of the monomers were obtained, whose product r(1). r(2) = 0.042 indicates a copolymerization behavior with a high tendency to alternating copolymerization. Selected copolymers varying composition or molecular weight, were used as additive at different concentration to evaluate the effect of these variables on their performance as flow improvers in a waxy crude oil composed of paraffin with high average carbon number and a narrow carbon number distribution. The analysis was done through differential scanning calorimetry and rheological measurements. The addition of the lowest molecular weight copolymer resulted in the best efficacy as flow improver, while the highest molecular weight rich in VB copolymer produced an unwanted effect that worsen the flow properties of waxy crude oil at low temperatures.",5,5,0
Crude Oil,Asphaltene,"Al-Khafaji, Arije; Wen, Dongsheng",Quantification of wettability characteristics for carbonates using different salinities,Low salinity flooding; Enhanced oil recovery; Carbonate reservoir; Wettability; Interfacial tension; Adhesion force,OIL-RECOVERY; CRUDE OILS; INTERFACIAL ACTIVITY; SMART WATER; INJECTION; BRINE; IONS; ASPHALTENE; RESERVOIR; TENSION,"Low salinity water flooding has received strong interest recently. It has been reported that injecting low salinity water can improve oil recovery in carbonate reservoirs through wettability alteration, whose mechanism however remains unclear, especially regarding the contributions from adsorbed polar organic components. This work investigates systematically the key parameters that govern the complex interactions of rock/brine/crude oil in carbonate reservoirs. The effects of crude oil composition and salinity on surface wettability alteration are studied by using three types of dead oil from Norwegian and North Sea with various acid numbers and two types of carbonate rocks (outcrop-calcite and subsurface-dolomite). Ion-substitution-adsorption is evaluated using the infrared spectrometer (IFR) and energy-dispersive X-ray spectroscopy (EDX). Oil/brine interactions by means of the interfacial tension (IFT) and contact angle as a function of oil composition, rock type, and salinity are experimentally investigated. The IFR and EDX data indicate a compositional change when the carbonate minerals are in touch with saline solutions, supporting the proposed rock-brine interaction mechanism. The salinity effect is more salient at the liquid/rock interface than the liquid/liquid interface, and the response to the brine composition is highly dominated by the oil composition with respect to its content of polar organic components. There is a reduction of contact angle as the seawater water is diluted twice while its influence on the IFT is small, and the effect is more pronounced for dolomite rock, showing different results for different crude oils used. This suggests that the wettability alteration of carbonate rock is an intricate phenomenon that is influenced not only by the salinity but also by the chemical composition of crude oil and rock mineralogy. A combination of three possible mechanisms, including multiple ion exchange, EDL expansion (electrokinetics repulsive), and salting-out, is discussed to illustrate the mechanism of wettability alteration during low salinity injection.",5,6,1
Crude Oil,Asphaltene,"Orrego-Ruiz, Jorge A.; Medina-Sandoval, Camila F.; Castillo Hinds, Carmen; Villar-Garcia, Alvaro; Rojas-Ruiz, Fernando A.",FT-ICR MS determination of the role of naphthenic acids on the stabilization of alkali/surfactant/polymer emulsified effluents: A field study,Microemulsions; Enhanced oil recovery; ASP flooding; Surfactants; Emulsion stability; FT-ICR MS,ENHANCED OIL-RECOVERY; RESONANCE MASS-SPECTROMETRY; INTERFACIAL-TENSION; PHASE-BEHAVIOR; CRUDE OILS; SURFACTANT; ASPHALTENES; ADSORPTION; STABILITY; EMULSIONS,"Numerous Alkali/Surfactant/Polymer flooding (ASP) projects have been developed worldwide. Nevertheless, some disadvantages have limited the success of ASP during the execution in field, such as injection lines scaling and strong emulsification of the produced fluids. Commonly, appropriate formulations for particular reservoir conditions are selected after a series of evaluation steps. These includes tests of surfactants, polymers and commercially available alkali, based on the reservoir temperature, reservoir salinity, reservoir water pH, rock permeability, formation type and adsorption of the surfactant on the matrix rock, to obtain the highest oil recovery at the lowest cost. As part of the different strategies adopted for increasing the oil recovery factor, San Francisco oil field, Huila Colombia, was selected in 2012 for ASP flooding application at pilot scale. After two years of injection, ASP effluents affected considerably the quality of water and its treatment for reinjection. The present work focuses on the compositional study of the production effluents obtained after ASP flooding. A detailed analysis using Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) allowed disclosing the role of natural organic acids on reducing the interfacial tension which in turn entailed highly stable microemulsions. Together with the added surfactant, naphthenic acids (because of the alkaline pH) prompts the formation of these thermodynamically stable oil in water systems. A test using an acid free oil proved that the formation of microemulsions strongly depends on naphthenic acids presence. Additional tests using oils with different acidity showed the dependence on the naphthenics acids structure over the emulsion stability. The results obtained in this study stands out FT-ICR MS as a prominent tool on understanding breaking and/or clarifying treatment processes from a molecular level point of view and thus, could help on proposing a correct and cost effective water treatment.",5,5,2
Crude Oil,Asphaltene,"Bemani, Amin; Poozesh, Abdolrahman; Bahrami, Masoud; Ashoori, Siavash",Experimental study of asphaltene deposition: Focus on critical size and temperature effect,Asphaltene deposition; Deposition critical size; Temperature effect; Capillary tube; Deposition rate,CRUDE OILS; AGGREGATION; PRECIPITATION; ISLAND; MODEL,"Asphaltene by far is the most problematic part of crude oil that could separate from oil body as a result of any change in system equilibrium. It can deposit at any point along oil flow path which in turn impose series restrictions, and subsequently create major impact on production from economic perspective. In this study, the influence of oil composition, flow rate, and for the first time, temperature on the intensity of deposition process are experimentally investigated. An in-house deposition unit apparatus was utilized which is based on the measurement of pressure drop across the capillary tube. The results indicate that in overall, temperature and oil composition change toward less soluble asphaltene, accelerate deposition process while flow rate enforces further restriction on process. In addition, by devising novel centrifugal based deposition experiments, critical size concept is more effectively addressed. The concept argues that there is a critical value for asphaltene aggregate size, beyond which the deposition will not occur. This critical size is not necessarily influence by hydrodynamic drag like forces.",5,5,2
Crude Oil,Asphaltene,"do Carmo, Wesley P.; Lenzi, Marcelo K.; Lenzi, Ervin K.; Fortuny, Montserrat; Santos, Alexandre F.",A fractional model to relative viscosity prediction of water-in-crude oil emulsions,Relative viscosity; Fractional calculus; Petroleum; Emulsions,CALCULUS; SUSPENSIONS; DEMULSIFICATION; AGGREGATION; TEMPERATURE; DERIVATIVES; SPHERES; FLOW,"The objective of this work was to propose a new model based on the theory of fractional calculus to predict the relative viscosity of petroleum emulsions. For this, stable emulsions with water content ranging from 10 to 65 wt % were prepared from three Brazilian crude oils: A (API 24.6), B (API 16.8) and C (API 13.5), with different contents of saturates, aromatics, resins and asphaltenes. Stable emulsions were prepared using an Ultra-Turrax homogenizer and the viscosity data were obtained from an Anton Paar Controlled Rheometer. The proposed fractional model was able to describe the experimental data very well, yielding a mean correlation coefficient (<(R-2)over bar>) above 0.99 in all tests and mean deviations of the order of 6%. For comparison purposes, the models of Mooney (1951) and Pal and Rhodes (1989) were applied to the same experimental data and presented mean deviations of up to 21% and 18%, respectively. Finally, based on the formulated theory, it is shown that the fractional model parameters (k(1), k(2), alpha) may be related to the mass fraction of saturates, aromatics, resins and asphaltenes (SARA) existing in the crude oils.",5,5,2
Crude Oil,Organic Matter,"Costanzo-Alvarez, Vincenzo; Rapalini, Augusto E.; Aldana, Milagrosa; Diaz, Marisel; Kietzmann, Diego; Paula Iglesia-Llanos, Maria; Cabrera, Ana; Luppo, Tomas; Vallej, Maria D.; Maria Walther, Ana","A combined rock-magnetic and EPR study about the effects of hydrocarbon-related diagenesis on the magnetic signature of oil shales (Vaca Muerta formation, southwestern Argentina)",Rock magnetism; ERR; Oil shales; Organic matter free radicals; Extractable organic matter,ELECTRON-SPIN-RESONANCE; NEUQUEN BASIN; FREE-RADICALS; TECTONIC EVOLUTION; ACQUISITION CURVES; PYRITE FRAMBOIDS; CONTRASTS; SEDIMENTS; VENEZUELAN; FIELD,"A combined study of rock-magnetism and electronic-paramagnetic resonance (EPR) was performed in core samples from an oil well in the Vaca Muerta Formation (SW Argentina). The aim of this work was to characterize the effects of hydrocarbon-related diagenesis on the magnetic signature of oil shales. Similar research has been previously conducted in near-surface sediments affected by oil and gas microseepage, so as to establish a relationship between micromagnetic anomalies and the underlying reservoirs. The EPR technique was employed to measure minute concentrations of organic matter free radicals (OMFRs), Fe3+ and Mn2+. These results, and the concentrations of extractable organic matter (EOM), were compared with mass-specific magnetic susceptibility (chi) and natural remanent magnetization (NRM). The reactive OMFRs, resulting from the thermal degradation of a kerogen that yields a slightly-biodegraded crude oil, seem to have acted on the primary Fe oxides and sulfides through two diagenetic stages. The first stage might have partially dissolved these minerals. Consequently, a number of depth levels show a decrease of both chi and NRM, against an increase of the OMFRs. On the other hand, for a core-interval between 2663 and 2695 m (P18/P24), a second diagenetic stage could have produced partial replacement of framboidal pyrite by authigenic pyrrhotite, as recognized by scanning electron microscopy (SEM), electron X-ray energy dispersion (EDX) experiments and the analysis of the thermomagnetic and IRM curves. Thus, within P18/P24, magnetic parameters increase in direct proportion with the amount of OMFRs. The lithologies encompassed by P18/P24 show small levels of Mn2+, a proxy directly related to calcareous cementation. Moreover, Gamma Ray, resistivity and neutron porosity well logs reveal distinctive features for P18/P24, as well as an increase of hydrocarbon content, contrasting with the rest of the section analyzed. The hydrocarbon-induced magnetic anomalies in these oil shales seem to be conditioned mostly by their petrophysical properties.",5,5,0
Crude Oil,Organic Matter,"Fu, Sheng; Liu, Zhen; Zhang, Yi-ming; Wang, Xin; Tian, Ning; Li, Ling; Wang, Hui-lai; Jiang, Tao","Source rocks geochemistry and oil-source correlation in the Aershan and first member of Tengge'er formations of the Wulan-Hua sag in south of Erlian Basin, Northeastern China",Biomarkers; K1ba source rocks; LK1bt1 source rocks; Oil-source correlation; Wulan-hua sag,ORGANIC-MATTER; NANXIANG BASIN; CRUDE OILS; HYDROCARBONS; INDICATORS; BIOMARKER; INSIGHTS; ORIGIN,"The Wulan-Hua Sag in the south of Erlian Basin has large oil and gas resource, whereas the source rocks genetic potential and oil-rock correlation in its Aershan Formation (K1ba) and First member of Tengge'er Formation (K1bt1) are still unclear. We performed organic geochemistry analyses of oil and mudstone samples to divide crude oil types, evaluate source rock potential, and establish relatively accurate oil-source correlation. The results indicate that the source rocks in K1ba and the Lower interval in First member of Tengge'er Formation (LK1bt1) belong to good source rocks, characterized by high organic matter abundance, oil-prone kerogen type, and relatively high thermal maturity. K1ba and K1bt(1) crude oil samples were divided into two types sourced from different Wulan-Hua source rocks. Type A oil is distributed in the K1ba and LK1bt1 of Saiwusu uplift and Hongjing uplift, and featured by a low gammacerane amounts (the majority of gammacerane/C30H < 0.30), and high Pr/Ph (ranging from 0.18 to 1.18, with mean value of 0.78). It has high mature organic matter mainly originated from terrestrial plant and dominant terrestrial plant. This type of oil was sourced from the K1ba source rocks in the Saiwusu uplift. Type B oil occurs in the LK1bt1 of the Tumuer Uplift and north sub-sag, and have high gammacerane abundance (the majority of gammacerane/(C-30 > 0.3), and low Pr/Ph (ranging from 0.38 to 0.76, with mean value of 0.63). Its organic matter includes dominant terrestrial plant source, and this oil type should be sourced from the LK1bt1 source rocks in the Saiwusu uplift.",5,6,3
Crude Oil,Organic Matter,"Yang, Zhe; Li, Meijun; Cheng, Dingsheng; Xiao, Hong; Lai, Hongfei; Chen, Qingyao",Geochemistry and possible origins of biodegraded oils in the Cretaceous reservoir of the Muglad Basin and their application in hydrocarbon exploration,Geochemical characteristics; Biodegraded oil; Cretaceous; Muglad basin; WCARS,ABU GABRA FORMATION; CRUDE OILS; ORGANIC-MATTER; TRIAROMATIC STEROIDS; PETROLEUM GEOLOGY; CRATONIC REGION; TARIM BASIN; SUDAN; DEGRADATION; ROCKS,"The Muglad Basin is one of the largest petroliferous basins within the Central and Western African Rift System (WCARS). A total of 42 oil samples including light, normal and heavy crude oils from the Cretaceous reservoirs of the Muglad Basin were systematically analyzed to fully understand their geochemical characteristics and possible origins. The results of oil-oil correlation show that these Cretaceous crude oils are genetically identical and derive from the same source kitchen. Differences in physical properties and geochemical compositions may be attributed to secondary alteration, such as biodegradation. Lightly, moderately and severely biodegraded oils can be divided on the basis of the relative abundance of n-alkanes and acyclic isoprenoids in the oils and the presence of ""humps"" on gas chromatogram baselines, as well as of the relative abundance of 25-norhopanes. The biodegradation degree of Cretaceous oils in the Muglad Basin is closely related to the burial depth of oil reservoirs and the distance between the locations of oil reservoirs and adjacent faults. This study may have practical application for further petroleum exploration and development in the Muglad Basin.",5,5,3
Crude Oil,Migration,"Ge, Haixia; Zhang, Zhihuan","Origin and accumulation of Paleogene oil in Qingdong sag, Jiyang depression, eastern China",Oil-source correlation; Heavy oil; Biodegradation; Oil charging orientation; Accumulation characteristics; Qingdong Sag,FLUID INCLUSION; PETROLEUM; GEOCHEMISTRY; BASIN; INDICATORS; FIELD,"This study reports on the geochemical examination of 18 core samples and 22 crude oil samples from the Qingdong and Dongying sags. Both conventional and heavy oils coexist in the Qingdong Sag, with the heavy oil resulting from biodegradation. Based on the oil-source rock correlation, the conventional oil mainly originates from the Es-3(1) source rock in the central and northern sub-sags, with the biodegraded oil in the western slope having been derived from the Es-4(u) source rock in the central and northern sub-sags. The biodegraded oil in the transition belt is mostly derived from the Dongying Sag (Es-4(u)). The biodegraded oil in the Qingdong-5 area originated from the Es-4(u) member near the Qingdong-5 area in the southern sub-sags. Two stages of oil charging were identified in the Qingdong Sag based on the basin modelling. The first stage occurred during the deposition of the Dongying Formation (Ed) in the Paleogene, and the second stage occurred during the deposition of the Guantao Formation from the Neogene to Quaternary (Ng-Q). The conventional oil in the central and northern parts of the study area mainly accumulated during the second stage and migrated both laterally through the sand-bodies and vertically along the steep faults. The heavy oil in the transition belt mostly accumulated during the second stage, migrating a long distance along the en-echelon step-fault zone, and suffered severe biodegradation. Both stages of oil charging were responsible for the heavy oil in the Qingdong-5 area and the western slope. The former migrated a short distance before being trapped, while the latter moved long distance along the fault strike. The oil charged during the first stage was subject to alteration, eventually being mixed with oil from the second charging event.",1,1,1
Crude Oil,Migration,"Xu, Zhengjian; Liu, Luofu; Jiang, Shu; Wang, Tieguan; Wu, Kangjun; Feng, Yanjun; Xiao, Fei; Chen, Yingying; Chen, Yiting; Feng, Chenyang","Migration model of hydrocarbons in the slope of the superimposed foreland basin: A study from the South Junggar, NW China",Migration pathway; Migration drive; Migration direction; Migration timing; Slope; Superimposed foreland basin,CRUDE OILS; TARIM BASIN; CARBAZOLE DISTRIBUTIONS; PETROLEUM MIGRATION; SEDIMENTARY BASINS; NITROGEN-COMPOUNDS; SOURCE ROCKS; MATURITY; INCLUSIONS; BENZOCARBAZOLES,"The superimposed foreland basins mainly develop in central-western China, namely the Himalayan foreland basins superimposed on the Indo-China foreland basins. Previous research on hydrocarbon migration predominantly focused on the typical foreland basins and the fore-deep depression of superimposed foreland basins. As a result of multi-superimposition, large hydrocarbon potentials in the slope zones are evaluated, and the hydrocarbon migration shows significant differences with those in the typical foreland basins. Moreover, the hydrocarbon migration models in the slope zone of superimposed foreland basins are poor analyzed. The Chepaizi High in the South Junggar Basin, a typical slope of superimposed foreland basin, has been taken into consideration. Several points have been ascertained. 1) Multistage charging and readjustment events should be the predominant characters. 2) The combination of multi-type sand-bodies, multistage faults and unconformities have formed step-or ""Z""-shaped migration pathways spatially. 3) Hydrocarbons migrated from the areas of high oil potential in the fore-deep depression to those of low oil potential in the slope. 4) The migration models of the J(1)b, K(1)q, N(1)s(1), and N(1)s(2) have been established. Hydrocarbon reservoirs in the slope zones show the shallow accumulation from deep/ distal sources with multiple reservoirs vertically and multi-charging and -readjustments chronologically. 5) The areas of (Wells SM3, C53-C90, and CF2), (Wells SM5, C80, and CF13), and (Wells K8, HG4, SM4, and CF2) can be the favorable targets for the J(1)b, K(1)q, and N(1)s, respectively.",3,3,1
Crude Oil,Migration,"Wang, Yang; Liu, Luofu; Ji, Huancheng; Song, Guangjian; Wang, Ximeng; Sheng, Yue","Structure of a pre-Triassic unconformity and its hydrocarbon transporting characteristics, Wuerhe-Fengnan area, Junggar Basin, China",Pre-Triassic unconformity; Three-layer structure; Basal conglomerate; Hydrocarbon migration; Transporting efficiency; Junggar Basin,QUANTITATIVE FLUORESCENCE TECHNIQUES; CRUDE OILS; ACCUMULATION; RESERVOIRS; MIGRATION; CONSTRAINTS; ORIGIN; ROCKS,"This study focuses on the qualitative and quantitative evaluation of the transporting capacity of a pre-Triassic unconformity and its influence on hydrocarbon migration in the Wuerhe-Fengnan area, Junggar Basin, China. Based on the lithological and geophysical characteristics of rocks and the geochemical parameters of formation water and hydrocarbon fluids from the unconformity, we identified the structure of the unconformity, analyzed the lithological assemblage through its vertical profile, calculated its transporting efficiency for oil in the Triassic Baikouquan Formation (T(1)b), and tracked the direction of oil migration along it. Four conclusions can be drawn. First, the pre-Triassic unconformity has a complex three-layer structure, including a basal conglomerate, weathering crust, and leached zone from the top to the bottom. Second, different lithologic assemblages form different types of migration pathways, mainly comprising a dual-channel with a sealing layer and a single channel of basal conglomerate. Third, the relative transporting efficiency (RTE) of the basal conglomerate for T(1)b oil migration is primarily controlled by its thickness and porosity. The ATE decreases from the northwest slope and uplifted area to the southeast sag area, with a mean value of 36%. Finally, the quantitative grain fluorescence, quantitative grain fluorescence on extract, and grain containing oil inclusion values confirm that the unconformity is an effective migration pathway for T(1)b oils. Horizontal changes in the oil group components and pyrrolic nitrogen compounds indicate that the T(1)b oils migrated from the southeast sag to the northwest slope and uplifted region along the pre-Triassic unconformity.",5,5,0
Crude Oil,Deposition Rate,"Bemani, Amin; Poozesh, Abdolrahman; Bahrami, Masoud; Ashoori, Siavash",Experimental study of asphaltene deposition: Focus on critical size and temperature effect,Asphaltene deposition; Deposition critical size; Temperature effect; Capillary tube; Deposition rate,CRUDE OILS; AGGREGATION; PRECIPITATION; ISLAND; MODEL,"Asphaltene by far is the most problematic part of crude oil that could separate from oil body as a result of any change in system equilibrium. It can deposit at any point along oil flow path which in turn impose series restrictions, and subsequently create major impact on production from economic perspective. In this study, the influence of oil composition, flow rate, and for the first time, temperature on the intensity of deposition process are experimentally investigated. An in-house deposition unit apparatus was utilized which is based on the measurement of pressure drop across the capillary tube. The results indicate that in overall, temperature and oil composition change toward less soluble asphaltene, accelerate deposition process while flow rate enforces further restriction on process. In addition, by devising novel centrifugal based deposition experiments, critical size concept is more effectively addressed. The concept argues that there is a critical value for asphaltene aggregate size, beyond which the deposition will not occur. This critical size is not necessarily influence by hydrodynamic drag like forces.",5,5,2
Crude Oil,Deposition Rate,"Adeyanju, Olusiji Ayoade; Oyekunle, Layioye Ola",Experimental study of water-in-oil emulsion flow on wax deposition in subsea pipelines,Demulsifier; Average absolute deviations; Pour point depressants; Validated flow facility; Dispersed water globules,CRUDE; DEMULSIFICATION,"Experiments were performed to simulate the deposition of wax in the flow of crude oil emulsions in subsea pipeline using a validated flow facility. Two crude samples and their respective formation water from two oil fields in southern Nigeria were used to synthetize two different emulsified crude oil samples (A and B). The trapping of the water globules in the wax deposits dominates the wax deposition rate initially but later the shear removal and the molecular diffusion dominate leading to decrease in the wax deposition rate. As the water (BS&W) composition in the emulsion increases from 10 to 40%, the pour point temperature (PPT) increases from 30 to 41 degrees C, and the viscosity increases from 40 mPas to 142 mPa at a crude oil temperature of 26 degrees C. The addition of 45 ppm of long chain acrylate ester co-polymer as pour point depressant depressed the dimensionless wax thickness by 37.5% and 34.3% for the blank emulsified crude oil A and B respectively. The effect of the commercial demulsifier to reduce the wax deposition rate was more successful in crude oil A reducing the wax dimensionless thickness by 58.9% and 43.0% when mixture of 25 ppm of the demulsifier and 45 ppm of long chain acrylate ester co-polymer were added to blank emulsified crude oil A and B respectively. The used demulsifier is more effective in crude oil A compared to crude oil B. Efforts should be made to study the effectiveness of different demulsifiers on each emulsified crude oil before their application for water separation.",5,5,3
Crude Oil,Alpha,"Zhou, Xiaoxiao; Lu, Xiuxiang; Song, Xu; Quan, Han; Chen, Kun; Qian, Wenwen; Wang, Zhao; Bai, Zhongkai; Zhang, Jie","Petroleum source of oil seepages in the Kalpin area, NW Tarim Basin, China",Source rock; Carbon isotopes; Biomarkers; Origin of oil seepages; Kalpin area,STABLE CARBON; SOURCE ROCKS; CRUDE OILS; ORGANOSULFUR COMPOUNDS; ISOTOPIC COMPOSITIONS; TAZHONG AREA; MARINE OILS; HYDROCARBON; BIODEGRADATION; SUBSURFACE,"Source rocks in Lower Cambrian (epsilon(1)) and Middle-Upper Ordovician (O2+3) have low S2 values, ranging from 0.01 to 0.34 and 0.01-5.95 mg HC/g Rock, respectively. The averages of TOC are 1.07% and 0.84% for epsilon(1) and O2+3 source rocks, respectively. The equivalent vitrinite reflectance values (VREs) indicate that epsilon(1) rocks are in a high-over mature stage for oil generation, and O-2+(3) rocks are sufficiently mature. Four oil seepages from the Yingshan Formation in the Qingsong quarry of the Aksu area and 34 core samples from epsilon(1) and O2+3 rocks in the Kalpin area were analyzed for stable carbon isotopes. Moreover, 4 oil seepages and 16 core samples were analyzed by gas chromatography-mass spectrometry (GC-MS). Compared with O2+3 rocks, epsilon(1) rocks are characterized by lower values of Gammacerane/C-30 hopane (G/H), C-28/(C-27 + C-28 + C-29) 20R alpha alpha alpha sterane (C-28%), C-29/(C-27 + C-28 + C-29 ) 20R alpha alpha alpha sterane (C-29%), C-26 20S/C-28 20S triaromatic steroids (C-26/C-28), (C-26 + C-27)/C-28 triaromatic steroids and (C-26 20R + C-27 20S)/C-28 20R triaromatic steroids, and higher values of C-21/C-23 tricyclic terpane (C-21/C-23), C-27/(C-27 + C-28 + C-29) 20R alpha alpha alpha sterane (C-27%), and C-35 alpha beta (22R + 22S) homohopane/alpha beta C-30 -hopane (C-35 H/H). The two sets of source rocks have a ""V (C-27 > C-28 < C-29)""-shaped regular sterane distribution pattern, and O2+3 rocks contain triaromatic steranes in abundances as high as those of epsilon(1) rocks. C-28-C-34 25-norhopanes (NHs) indicates that the degree of degradation of oil seepages falls at approximately PM 6, rendering many biomarker parameters ineffective for oil-source correlations, except for triaromatic steriods and carbon isotopic compositions. The values of C-26/C-28, (C-26 + C-27)/C-28 triaromatic steroids and (C-26 20R + C-27 20S)/C-28 20R triaromatic steroids using 0.50, 1.45 and 1.80 as threshold values, respectively, can differentiate epsilon(1) and O2+3 rocks, and oil seepages show a natural affinity to the C-i source rocks. The epsilon(1) rocks have lighter delta C-13 of kerogen and heavier delta C-13 of group compositions than those of O2+3 rocks. The group compositions of oil seepages are depleted in C-13 by approximately 0-1.5 parts per thousand compared with kerogens of epsilon(1) extracts, further suggesting that the oil seepages are comparable to epsilon(1) source rocks consistent with the results of biomarker analysis.",2,2,4
Crude Oil,Alpha,"do Carmo, Wesley P.; Lenzi, Marcelo K.; Lenzi, Ervin K.; Fortuny, Montserrat; Santos, Alexandre F.",A fractional model to relative viscosity prediction of water-in-crude oil emulsions,Relative viscosity; Fractional calculus; Petroleum; Emulsions,CALCULUS; SUSPENSIONS; DEMULSIFICATION; AGGREGATION; TEMPERATURE; DERIVATIVES; SPHERES; FLOW,"The objective of this work was to propose a new model based on the theory of fractional calculus to predict the relative viscosity of petroleum emulsions. For this, stable emulsions with water content ranging from 10 to 65 wt % were prepared from three Brazilian crude oils: A (API 24.6), B (API 16.8) and C (API 13.5), with different contents of saturates, aromatics, resins and asphaltenes. Stable emulsions were prepared using an Ultra-Turrax homogenizer and the viscosity data were obtained from an Anton Paar Controlled Rheometer. The proposed fractional model was able to describe the experimental data very well, yielding a mean correlation coefficient (<(R-2)over bar>) above 0.99 in all tests and mean deviations of the order of 6%. For comparison purposes, the models of Mooney (1951) and Pal and Rhodes (1989) were applied to the same experimental data and presented mean deviations of up to 21% and 18%, respectively. Finally, based on the formulated theory, it is shown that the fractional model parameters (k(1), k(2), alpha) may be related to the mass fraction of saturates, aromatics, resins and asphaltenes (SARA) existing in the crude oils.",5,5,2
Crude Oil,Relative Permeability,"Kim, Tae Wook; Vittoratos, Euthymios; Kovscek, Anthony R.",Recovery efficiency of a 28 degrees API crude-oil system as a function of voidage replacement ratio,Water flooding; Voidage replacement; Laboratory studies; Improved oil recovery,SOLUTION-GAS DRIVE; RELATIVE PERMEABILITY,"Crude-oil recovery processes with a voidage replacement ratio (VRR = injected volume/produced volume) less than 1 combine solution gas drive mechanisms and viscous crude-oil displacement. Previous laboratory and field studies have shown that a VRR less than 1 for a period of time is optimal for recovery of some viscous and heavy crude oils that form emulsions and/or bubbly oil in situ. This study extends understanding of the effect of VRR to recovery of live, less-viscous crude oils from sands. The crude oil used is roughly 28 degrees API, has a dead-oil viscosity of 26 cP, a live-oil viscosity of 0.41 cP, and an asphalt content of 2.1 wt%. It is found in the laboratory that the final crude-oil recovery (70.5%) using a 0.01 PV/h depletion rate and VRR equal to 0.7 is more than 8% greater than recovery with VRR equal to 1 (65.1%). Recovery using a 0.001 PV/h depletion rate with VRR equal to 0.7 (79.1%) was nearly the same as the sum of oil recoveries for solution gas drive (VRR = 0, 24.5%) plus waterflooding (VRR = 1, 53.4%). For these two depletion rates, the oil recovery obtained using VRR equal to 0.7 is more favorable than VRR = 1 (waterflooding). Relative permeability was inferred from experimental results. Substantial critical gas saturations (8.1-16.1%) also contributed to oil production. A concave shape of the oil/water relative permeability curve indicated an emulsion-like effect that also promoted recovery when the VRR was less than 1.",1,1,0
Crude Oil,Relative Permeability,"Karacan, C. Ozgen",An ANCOVA model for porosity and its uncertainty for oil reservoirs based on TORIS dataset,Mean value; Depositional system; Multi-linear regression; Reservoir assessment; ANCOVA; TORIS,PERMEABILITY PREDICTION; SEDIMENTARY; NORTH; SANDSTONE; EOCENE; ROCKS,"Porosity is one of the most important parameters to assess in-place oil or gas in reservoirs, and to evaluate recovery from enhanced production operations. Since it is relatively well-established to determine porosity using different laboratory and field methods, its value is usually determined at many locations across a reservoir as part of the common practice to capture reservoir heterogeneity and the variability in values. This suite of measurements and the distribution of values are most valuable for probabilistic reservoir assessments, and for spatial modeling if the exact data locations are known. Despite the importance of individual measurements to set the range of values for probabilistic studies, it is not always possible to access these data due to confidentiality. In most cases, commercial or publicly available databases that assessments may rely on usually report only mean values of porosity, like any other reservoir data, or they may not report a value at all. This makes both quantifying the mean value and the uncertainty around it difficult for probabilistic assessments. In this study, the TORIS (Tertiary Oil Recovery Information System) dataset of the National Petroleum Council and the U.S. Department of Energy was used to model porosity and the uncertainty around predicted values. TORIS is an integrated dataset of production data, reservoir properties, and project databases of crude oil reservoirs in the United States. The model presented in the paper was based on ANCOVA (Analysis of Co-Variance) of data from 1038 reservoirs from the TORIS dataset for porosity prediction, validation and testing for quantitative and qualitative parameters that may be readily available in most cases, and to estimate uncertainty around the mean values. This model also explored association of porosity values to different parameters, and to different depositional systems and diagenetic overprint conditions. Furthermore, an ANN (Artificial Neural Network) model was created to compare the predicted values of both models. Results showed that the ANN model was able to represent more of the variability, however it lacked the insights that might be gained from the ANCOVA model.",1,1,0
Crude Oil,CO2,"Al Hinai, Nasser M.; Myers, Matthew B.; Dehghani, Ali Mousavi; Wood, Colin D.; Valdez, R.; Jin, Fayang; Xie, Quan; Saeedi, A.",Effects of oligomers dissolved in CO2 or associated gas on IFT and miscibility pressure with a gas-light crude oil system,Associated gas; Miscible gas injection; Thickened gas; Equilibrium interfacial tension; Minimum miscibility pressure; First contact miscibility pressure; Cloud point pressure,INTERFACIAL-TENSION; MOLECULAR SIMULATION; CARBON-DIOXIDE; THERMODYNAMIC PROPERTIES; SUPERCRITICAL CO2; DIRECT THICKENERS; PHASE-BEHAVIOR; SOLUBILITY; POLYMERS; HYDROCARBON,"The solubility of an oligomer in a supercritical gas solvent (e.g. CO2 or associated gas (AG) mixture) and the subsequent effects on the phase behaviour, interfacial tension (IFT) and miscibility pressure of the in-situ oil/oligomer-thickened gas system at a molecular level are crucial to understanding and designing a thickened miscible gas injection (MGI) process. We have conducted cloud point pressure measurements, which revealed that the phase behaviour of P-1-D-thickened CO2 would follow a UCST (upper critical solution temperature) trend while P-1-D-thickened AG mixture would lie close to a LCST (lower critical solution temperature) behaviour. Moreover, our measured equilibrium IFTs of crude oil/P-1-D-thickened CO2 system and crude oil/PVEE-thickened CO2 system were found to be slightly lower than those of the crude oil/CO2 system. This results in a slight reduction in the MMP (minimum miscibility pressure) and considerable reduction in the first contact miscibility pressure (P-max). We found the dissolution of P-1-D in the AG mixture to cause an increase in the equilibrium IFT for the crude oil/P-1-D-thickened AG mixture system, resulting in an increase in both of the MMP and P-max. This indicates that the dissolution of an oligomer may have a considerable effect on the crude oil/thickened gas IFT behaviour at a pressure close to the cloud point pressure.",2,2,2
Crude Oil,CO2,"Saghafi, Hamid Reza; Rostami, Alireza; Arabloo, Milad",Evolving new strategies to estimate reservoir oil formation volume factor: Smart modeling and correlation development,Oil formation volume factor; Adaptive network-based fuzzy inference system; Genetic programming; PVT data,PVT PROPERTIES; CRUDE-OIL; EMPIRICAL CORRELATION; CO2 SOLUBILITY; SVM FRAMEWORK; PREDICTION; PRESSURE; TEMPERATURE; SYSTEMS; ALGORITHMS,"The precise estimation of oilfield PVT properties is of primary importance for improving field evaluation and development strategies. In the present work, adaptive network-based fuzzy inference system (ANFIS) and genetic programming (GP) models were established for the accurate assessment of reservoir oil formation volume factor (OFVF). A large database including nearly 1200 datapoints from all over the globe was collected for modeling. The performance of the new models was compared to correlations in the existing literature via several graphical and statistical paradigms. Variance approach analysis was implemented to determine the sensitivity of the target parameter as the output with respect to each input variable. It is shown that the highest forecasting accuracy is attained using the developed ANFIS model and GP-based empirical correlation with an average absolute relative deviation (AARD%) of 1.8% and 2.1%, respectively, in comparison to the results obtained from other approaches described in the literature. Lastly, the mathematical techniques designed for estimating OFVF can be of high importance for experts working with reservoir simulation and PVT analysis.",5,5,0
Drilling Fluid,Temperature,"Singhal, Vivek; Ashok, Pradeepkumar; van Oort, Eric",X-ray densitometry of drilling fluids at the rig standpipe,Drilling fluid density; X-ray densitometer; Real-time density measurement; High-pressure density meter,ATOMIC-NUMBER; DENSITY; ENERGY; TEMPERATURE; FLOW,"Fluids used during well construction operations serve as a primary barrier for well control, with the fluid density generating sufficient hydrostatic pressure in the fluid column to control downhole formation fluids and gas. Realtime density measurement at the well inlet, where high pressures of many thousands of psi can occur, is highly desirable in order to maintain well control. This improved characterization of the well bore pressure profile allows one to drill wells with narrow drilling margins without non-productive time from well control events, resulting in safer and more cost-effective well construction operations. Gamma ray densitometers are suitable measuring devices for high-pressure density measurement. Typical flow conditions encountered at the inlet, such as a fully filled pipe and a homogeneously mixed mud, are very conducive to their use. In-spite of their high measurement accuracy and relatively fast response times, however, these meters have seen limited adoption in field. This is primarily because the meters come with safety concerns due to the radioactive source required for gamma ray generation. Additionally, the source has to be tracked throughout its life and properly handled during storage, transportation, installation and disposal. Given these concerns and challenges, a majority of oil and gas operating and service companies use manual density measurements at the mud pits using a pressurized mud balance. To help change this rather antiquated and infrequent practice that relies on manual labor, this paper evaluates the feasibility of using a non-radioactive, X-ray based densitometer as an alternative to the gamma ray meter. X-ray densitometry works on the same proven principles as gamma ray densitometry, without the latter's drawbacks. Two X-ray methods, an empirical method and a model-based method (inspired by a technique used in the medical field known as single X-ray absorptiometry) are presented here. Real-time density measurements on the high pressure line with an accuracy of 99% or better and a measurement frequency of 1 Hz are feasible using these methods.",0,0,1
Drilling Fluid,Temperature,"Hao, Shu-Qing",Development of portable drilling fluid and seepage simulation for deep saline aquifers,CO2 sequestration; Borehole stability; Low density (portable) drilling fluid; High-temperature resistant drilling fluid; Deep saline aquifers,RHEOLOGICAL PROPERTIES; STORAGE; CO2; PERFORMANCE,"The development of drilling fluids with low density for deep saline aquifers is in high demand. This study performed several tests to find the optimal formula of drilling fluid that would be suitable under circumstances with high temperatures and salt concentrations similar to deep saline aquifers. Drilling fluids with varying combinations sodium chloride (NaCl), polyacrylamide (PAM), sulfonated lignite (SMC), and sodium carboxymethyl cellulose (Na-CMC) in montmorillonite (Mt) water-based slurry were synthesized and tested. Salt-, SMC-, and temperature-sensitivity analysis was done to investigate effects of ionic strength and temperature on the performance of synthesized drilling fluids. Anti-caving ability tests were performed to check the drilling fluids influence on porosity of aquifer upon application. The results show that NaCl and PAM play a critical role in controlling viscosities and yield values. PAM and Na-CMC contribute to fluid loss characteristics, and PAM contributes to low density too. A deliberately chosen combination of NaCl PAM, SMC, and Na-CMC gives rise to a suitable formula of drilling fluid for temperatures up to 120 degrees C and salt concentrations up to 1.7 M. The simulation of drilling fluid seepage in the borehole based on the ANSYS-Fluent existing codes verifies the performance of the optimal formula and the results imply the effectiveness of the optimal formula on prohibiting the borehole instability. This will even encourage immediate field applications of the optimal formula.",4,5,2
Drilling Fluid,Temperature,"Zhang, Yayun; Gao, Shuyang; Du, Xiaoyu; Chen, Mian; Jin, Yan",Molecular dynamics simulation of strength weakening mechanism of deep shale,Deep shale; Montmorillonite; Hydration; Molecular dynamic simulation; Conduction characteristics; Strength weakening,MONTE-CARLO-SIMULATION; ELASTIC PROPERTIES; K-MONTMORILLONITE; INTERLAYER STRUCTURE; COMPUTER-SIMULATION; WELLBORE STABILITY; NA-MONTMORILLONITE; CA-MONTMORILLONITE; HYDRATED LI; WATER,"Due to the dissimilarities in the hydration characteristics and degree of clay minerals, the wellbore instability and sloughing of deep shale is more sudden and destructive than that of the shallow shale. Previous works mainly consider the effects of temperature and pressure condition on the wellbore instability of deep shale at macroscopic scale, and ignore the microscopic mechanism of strength weakening during hydration and the evolution characteristics of montmorillonite(MMT) hydration under different isomorphic substitutions, temperature and pressure conditions. By considering the characteristics of clay minerals and drilling fluids in deep shales, the molecular dynamics simulations of MMT hydration in deep shale under different isomorphic substitutions, water content, temperature and pressure conditions were carried out to analyze the distribution and conduction evolution characteristics of water molecules and cations, and the response characteristics of crystal elastic parameters during the hydration process. The results indicate that: (1) As the water content increases, the interlayer spacing increases, but it is less sensitive to the temperature and pressure. Moreover, with the increase of water content, water molecules and ions are accelerated to intrude into crystal layer, and the hydration effects are enhanced and the weakening effects on rock strength are increased as well. (2) Both temperature and pressure have significant influences on the hydration characteristics of MMT, but the influential trends are opposite. Increasing temperature promotes the invasion of water molecules and sodium ions into the crystal layer so as to enhance the hydration, the weakening effect on rock strength becomes more remarkable. On the contrary, with the increase of pressure, the diffusion coefficient of water molecules and sodium ions to interlayer decreases which inhibits the weakening effect of clay hydration. (3) The differences of hydration characteristics of MMT with typical isomorphic substitutions are significant. The hydration ability of sodium ion in Fe-substituted MMT was weaker and the diffusion coefficient of water molecules was larger, so that water molecules more easily invade into the crystal layer, and the strength weakening is more significant than that of the Mg-substituted MMT system. Furthermore, the weakening effect is more significant under high temperature and low pressure conditions. The microscopic dynamic mechanism of clay hydration in deep shale can be throughly understood through molecular dynamics simulation, which provides an innovative research approach for the quantitative evaluation of drilling fluid hydration inhibition and microscopic control of clay hydration in deep shale.",4,4,3
Drilling Fluid,Temperature,"Govindu, Abhishek; Ahmed, Ramadan; Shah, Subhash; Amani, Mahmood",Stability of foams in pipe and annulus,Foam stability; Bubble coarsening; Coalescence; Gravity drainage; Half-life; Foam quality,RHEOLOGICAL BEHAVIOR; DRAINAGE,"Foam fluids present numerous advantages for many oil field applications. Due to their bubble structure and a gaseous component, foams exhibit very high viscosity and low density. Low density makes foam an attractive fluid in underbalanced drilling operation in which light fluid is essential to maintain wellbore pressure below pore pressure. Due to its high viscosity, foam exhibits good hole-cleaning performance even at low annular velocities. Nevertheless, foams are thermodynamically unstable fluids and their structures eventually collapse. Foam decays as a function of time and the decay occurs mainly due to bubble coalescence and the gravity drainage of the liquid phase. Maintaining fluid stability is necessary for foam drilling. For a successful drilling operation, the half-life of foam, which is the time taken by foam to drain 50% of its liquid volume, should exceed circulation time. For other applications, such as hydraulic fracturing or cementing, the half-life of foam should exceed the time taken for fluid to reach target zones. In this study, foam stability experiments were conducted in a concentric annulus (50mmx75 mm) and 25 mm pipe sections. The pipe section was transparent to observe drained liquid level. Aqueous, polymer-based, and oil-based foams were considered in the investigation. The effect of gas volume fraction (quality) was studied under static condition. All experiments were performed at 400 kPa and ambient temperature (20 +/- 2 degrees C). Foam quality was increased from 40% to 80%. However, at high qualities (greater than 70%), the oil-based foam was unstable. Hydrostatic pressure data was collected from the annular section and converted into density curves to determine drained liquid volume. In the pipe section, the drainage was physically measured from the liquid level and recorded periodically. A digital camera with a microscope was used to capture foam image in real-time to examine bubble coarsening and foam decay. For a given quality, the polymer-based foam was the most stable, while oil-based foam was the least. For all three types of foams, stability increased with quality. Foams were more stable in the annular section, as compared to the pipe, possibly due to the impact of container wall on bubbles and drained liquid motion. Foam decay and bubble coarsening were observed by comparing bubble sizes in captured images at various times. On average, larger bubbles were observed in higher quality foams. The rate at which foam bubbles coarsening mostly reduced with time.",4,4,5
Drilling Fluid,Temperature,"Al Saedi, A. Q.; Flori, R. E.; Kabir, C. S.",Exploring alteration of near-wellbore geothermal gradient during fluid circulation and production,Time-dependent formation temperature; New analytical models for fluid circulation & production; Solution of temperature diffusivity equation; Transient temperature profiles; Undisturbed formation temperature; Heat flow in and out of wellbore,TEMPERATURE DISTRIBUTION; HEAT-TRANSFER; MODEL; LOGS,"The constant undisturbed formation temperature profile controlling heat transfer into the wellbore appears counterintuitive in light of transient cooling of the formation that occurs upon fluid circulation in drilling and also heating during fluid production. This study presents a mathematical model that shows that the heat transfer occurs from the wellbore/formation interface, not from some distance away from the wellbore wherein the initial formation temperature profile remains undisturbed. This new model allows investigation of heat transfer behavior from the formation into the wellbore during drilling or fluid circulation, and from the wellbore into the reservoir in the production mode. Application of the line-source solution for the temperature diffusivity equation for a steady-state system provides the necessary ingredients for computing the temperature behaviors at different times and radii. This line-source solution can be used throughout the wellbore to determine the undisturbed formation temperature, which may be used to obtain the geothermal gradient dependent on the radius and fluid circulation time. Therefore, the initial geothermal gradient works as a time-dependent variable, and the resultant second-order polynomial relationships can describe the undisturbed formation temperature. This study provides the required tools to assess the wellbore heat-transfer behavior and their effect on the wellbore temperature profiles. Also, the new mathematical model illuminates the impact of heat transfer by comparing its performance with the original formulations. Besides, this paper presents a complete derivation of the line-source solution of the temperature diffusivity equation to justify the proposed approach.",5,5,0
Drilling Fluid,Temperature,"Abid, Khizar; Gholami, Raoof; Tiong, Michelle; Nagaratnam, Brabha; Sarmadivaleh, Mohammad; Mostofi, Masood; Bing, Chua Han; Muktadir, Golam",A pozzolanic supplementary material to reinforce class G cement used for drilling and completion operations,Class G cement; POFA; Nanosilica; Strength enhancement; Extender,FILLER; MICROSTRUCTURE; HYDRATION,"There have been many studies to improve cement integrity under different pressure and temperature conditions where cement degradation is initiated by the mechanical and chemical interactions. Several approaches were presented so far to resolve this issue, many of which are either expensive or inefficient under certain circumstances. In this paper, attempts are made to show the application of Palm Oil Fuel Ash (POFA) as a cheap but efficient supplementary cementing material (SCM) for drilling and completions practices. A series of experiments were conducted to evaluate the changes in the density, free fluid, rheology, weight on cement, compressive strength, matrix structure and composition of the cement modified by POFA. The results obtained indicated that POFA has a hydrophilic surface and can retard pozzolanic reactions. It was appeared that POFA does not significantly change the rheology but may reduce the plastic viscosity. After 24 h and 9 months of curing, 5 wt% POFA based cement appeared to have the highest compressive strength with a very consolidated matrix as observed through XRD, TGA and SEM tests. It was also revealed that nanosilica (NS) may significantly increase the plastic viscosity of the cement while POFA may give a higher strength to the cement in a long curing process. It was then concluded that POFA can be a very good choice to improve the mechanical strength and the matrix structure of the cement under different drilling conditions.",5,5,1
Drilling Fluid,Temperature,"Sinha, Vineet; Ahmeda, Ramadan; Akhtar, Tarek; Shah, Subhash; Amani, Mahmood",Rheology and hydraulics of polymer-based foams at elevated temperatures,Foam; Polymer; Stimulation; Rheology; Hydraulics; Drilling,CONSTITUTIVE EQUATION; DRILLING FOAMS; FLOW BEHAVIOR; AQUEOUS FOAMS; FLUID-FLOWS; VISCOSITY; SUSPENSION,"Foam has been successfully used for different operations like well stimulation, drilling, enhanced oil recovery (EOR), cleanout, and acidizing operations in the oil and gas industry. Additionally, the low liquid content of foam provides a distinct advantage in terms of lesser material requirements. However, accurate prediction of rheology is necessary for the success of field operations, which requires a rheological model that incorporates the effect of temperature on foam properties as it circulates downhole. In the present investigation, polyanionic cellulose (PAC) based foam was generated using nitrogen as the gas phase and its rheology was determined using a recirculating flow loop that has three pipe viscometers (3.05, 6.22, and 12.7 mm ID) and a fully-eccentric annular section (9.53 mm OD x 12.57 mm ID). Experiments were conducted within the temperature range of 24 to 149 degrees C and at various foam qualities (gas phase volume fraction). The foam was circulated at different flow rates and the differential pressure across each pipe section was recorded. All tests were conducted at 6.89 MPa. The foams displayed power-law fluid behavior in the shear rate range tested (100-5000 s(-1)), which is often experienced in the wellbore. Like its base liquid, polymer foam exhibited thermal thinning and a significant rheology change with temperature. Only high-quality foam (75%) at ambient temperature (24 degrees C) showed yielding behavior, which was measured in a pipe viscometer under static condition. The disappearance of yield stress at elevated temperature could be attributed to thermal thinning of the liquid phase that weakens the strength of bubble structure. Experimental data is used to develop new correlations to predict power-law fluid parameters as a function of temperature, base fluid properties, and foam quality. Moreover, the measurements are compared with the predictions of existing models, and discrepancies are observed, which could be attributed to the variation in foam generation technique, the nature and concentration of polymer, and the concentration of surfactant used in the experiments in which data was obtained to develop the models. Furthermore, annular pressure loss measurements obtained at low temperatures (24 and 79 degrees C) show predominantly good agreement with predictions of a hydraulic model that uses the new correlations. Discrepancies increased with temperature as the foam becomes unstable due to thermal thinning of the liquid film and subsequent weakening of bubble structure.",5,5,1
Drilling Fluid,Case,"Chen, Laoyin; Di, Qinfeng; Lou, Erbiao; Zhou, Bo; Zhang, He; Wang, Wenchang; Hu, Feifei",The visualization of rub-impact characteristics of drill string on casing,Rub-impact characteristics; 3D visualization method; Casing wear; Drill string; Finite element model,DYNAMIC-ANALYSIS,"Field experience revealed that a whirling drill string in the wellbore would make severe impact and rubbing against the casing and lead to uneven and random wear of casing. The casing wear due to vibrational impacts of the drill string was also one of the major causes for casing failure, but it was always ignored in the previous studies on casing wear. This work aimed at modelling and intuitively displaying the rub-impact characteristics of drill string and the induced wear on casing. Taking into consideration of the damping of drilling fluid, bit-rock interaction together with the geometric and contact nonlinearity, a drill string dynamic finite element model was established and then solved with the node iteration and the Newmark method. The whirl orbit, whirl velocity and collision characteristics of the drill string were then obtained. Based on these results, a three-dimensional visualization method was established to describe the dynamic features of drill string. The results indicate that the drill string presents a strong nonlinear dynamic behavior and makes frequent impacts against the wellbore, which appears mainly in the low side of borehole and is more serious in the hole section where BHA is located. The hole curvature and surface rotary speed have important influence on the casing wear induced by impact-rub action. A large hole curvature will lead to more serious rub-impact action of the drill pipe on the casing, and a rotary speed closer to the natural frequency of BHA will obviously increase the wear risk of casing.",2,3,3
Drilling Fluid,Case,"Li, Xin; Gao, Deli; Lu, Baoping; Zeng, Yijin; Zhang, Jincheng",Study on modified maximum extension length prediction model for horizontal wells considering differential sticking,Horizontal well; Maximum extension length; Differential sticking; Drilling fluid density; Casing running down/pulling out speed,EXTENDED-REACH LIMIT,"Maximum extension length prediction model for horizontal wells can be used to evaluate the horizontal well's extension capability and predict its maximum measured depth, which is of great significance to the production and economic benefits of horizontal wells. However, the differential sticking is not considered in previous prediction model. To overcome this shortcoming, a modified model considering differential sticking is established based on constraints of wellbore stability, differential pressure, and filtration loss simultaneously during the drilling, tripping processes and static state. Then a horizontal well is analyzed and its maximum extension length is predicted. Results show that within the conventional mud weight window, three ranges of drilling fluid density can be determined, including the first range, the second range and the reasonable range of drilling fluid density. However, only the reasonable range of drilling fluid density can satisfy all constraints of the modified prediction model, including the wellbore stability, differential pressure, and filtration loss simultaneously. Compared with the original model, the predicted well's maximum extension length decreases when the differential sticking is considered. However, it is more accurate, avoiding drilling hazards in actual drilling operation due to the excessive designed measured depth and unreasonable drilling parameters. Moreover, the maximum speeds of casing running down/pulling out are also determined and added to the modified model. Therefore, the modified model with reasonable drilling fluid density and adjusted running down/pulling out speed is the optimal modified model to predict maximum extension length and avoid differential sticking, which can also ensure that the horizontal well's designed measured depth can be successfully achieved. This study is of great significance to improve the prediction accuracy of horizontal well's maximum extension length and avoid drilling hazards, especially the differential sticking. Moreover, it also plays a guiding role in the selection of reasonable drilling fluid density during horizontal drilling.",3,4,3
Drilling Fluid,Case,"Singhal, Vivek; Ashok, Pradeep; van Oort, Eric",High pressure measurement of mud density and flow rate for oil and gas well construction: Making the case for X-Ray metering,Mud density and flow rate measurement; Review of drilling fluid density and flow rate measurement technologies; Mass flow rate measurement for managed pressure drilling operations; X-ray densitometery and flow rate measurement,PARTICLE IMAGE VELOCIMETRY; 2-PHASE FLOW; CORIOLIS; DENSITOMETER; DESIGN; CALIBRATION; COMPOSITES; FLOWMETERS; VELOCITY; FLUID,"With a myriad of flow and density sensors available, it can be difficult to decide on the right metering technology to make density and mass flow rate measurements, that suits both application and cost requirements. Operational specifications listed in product brochures typically apply to tests done under highly controlled conditions and generally fail to account for the extreme variability in flow conditions of drilling and completions fluids in the real world. Thus, time and other resources can be wasted by the end users in trying to validate the various meters. Even when right metering technology is selected the measured values often have low accuracy and low measurement frequency. The intent of this paper is to provide a high level overview of the working principles of some of the main-stream metering technologies, identify applications they are well suited for, clarify their limitations, and provide an overview into current research to address these limitations. The paper will allow the reader to narrow down options for appropriate density and flow metering solutions for particular applications, and at the same time highlight the gaps and needs that need to be addressed by further research and development. The paper also discusses an X-ray based metering technology that overcomes some of the disadvantages and deficiencies of established meters. Recent work on characterizing the drilling fluid density and flow rate at the high pressure well inlet using X-rays has shown that these measurements can now be made with greater than 99% accuracy and at 1 Hz measurement frequency. Such level of accuracy and measurement frequency is not offered by any of the mainstream metering technologies. It is expected that the X-ray based technology when implemented will lead to a step-change improvement in current density and delta flow (flow in - flow out) assessment, and will thereby positively contribute to improved hydraulics management, better and earlier kick detection, and further enhanced managed pressure drilling control. In this paper we build upon the existing work on X-ray based density and flow rate measurements of drilling fluids. Specifically, we discuss preliminary work towards development of a new flow measurement technique which can measure flow rate using an X-ray flat panel detector. Using a flat panel detector offers a cheaper alternative to the existing high speed imaging based flow measurement methods. We also share results from a method developed for real-time calibration of the X-ray detectors. Using the calibration method X-ray measurements are shown to have a repeatability of greater than 99%. A section is also dedicated to characterizing the intensity output from the X-ray source. Finally, we show that X-ray density measurements conducted with static fluids in existing literature remain unaffected when the same density fluid flows through a pipe.",4,4,1
Drilling Fluid,Case,"Maity, Debotyam; Ciezobka, Jordan",Designing a robust proppant detection and classification workflow using machine learning for subsurface fractured rock samples post hydraulic fracturing operations,Artificial neural nets; Image processing; Classifier benchmarking; Unconventional reservoirs; Core sampling; Shale rock,NEURAL-NETWORK; ALGORITHM,"Hydraulic fracturing is a method of reservoir stimulation that enhances the effective permeability of tight unconventional reservoirs such as shale oil and gas. In typical hydraulic fracturing treatments, millions of gallons of water are pumped under pressure into rock formations deep below the earths surface. Proppant particles such as sand are injected as part of the fracturing slurry to hold the hydraulic fractures open, or propped, after high-pressure water injection has ceased. Propped hydraulic fractures provide a conduit for long-term hydrocarbon production, thus being essential to commercial oil and gas production from shale reservoirs. The distribution of the proppant particles can be useful in understanding effectiveness of hydraulic fracturing treatments. It can also help identify both, unstimulated and under-stimulated zones within the reservoirs of interest. These proppant particles can be found in drilling fluid return or in cores, which can be sampled from subsurface. In this study, we highlight the design and development of artificial neural network based workflow that helps identify where proppant particles are located and classifies proppant and various particles of interest. In this study, these particles are limited to naturally occurring calcite or other minerals from subsurface rocks. Various features of interest that help with the classification process have been conceptualized and defined. This method has been verified using controlled test cases and validated using actual samples from subsurface. The designed ANN classifier has also been benchmarked with other classification methods including k-nearest neighbor, naive-Bayes classifiers and Support vector machines. A workflow to process samples from subsurface and quantify proppant distribution for future test programs including potential real time applications has been proposed. Based on this workflow, we share proppant distribution from a Permian Basin case study. We have also compared proppant distribution using our proposed method with results from an independent workflow on a similar dataset, which does not utilize machine learning.",5,5,0
Drilling Fluid,Case,"Galdino, Jonathan F.; Oliveira, Gabriel M.; Franco, Admilson T.; Negrao, Cezar O. R.","Gas kick detection and pressure transmission in thixotropic, compressible drilling fluids",Pressure transmission; Kick; Drilling fluid; Transient flow; Compressible flow; Thixotropy,MATHEMATICAL-MODEL; STRESS; FLOW; WELL; TRANSITION; BUBBLES,"During well drilling operations, unexpected gas influx may take place when the bottom hole pressure falls below the pore pressure. The conventional procedure to control the influx consists of shutting-in the well and waiting for pressure stabilization. The pressures measured at the surface after the well closure and the pit gain are used to estimate the pore pressure, the gas density, and the kick magnitude. However, the drilling fluid compressibility and rheology can undermine pore pressure transmission to the surface, which can affect the pit gain and the well closing pressure. The current work presents a transient compressible isothermal mathematical model to predict pit gain and pressure transmission along the well during gas kicks. The model is based on the balance equations of mass and momentum that are solved by the method of characteristics. Three types of drilling fluids are analyzed: Newtonian, Bingham Plastic and thixotropic. The Darcy's law is used to represent the gas influx through the rock formation. The results indicate that the usual pressure balance used to estimate the pore pressure may lead to mistaken values and also that the drilling fluid compressibility and rheology have considerable effect on the pit gain and on the gas volume that invades the well. In all cases investigated, the gas volume within the well is at least 50% higher than the pit gain. Therefore, drilling fluid compressibility cannot be neglected on the estimation of the formation fluid volume within the well.",5,5,1
Drilling Fluid,Case,"Li, Xin; Gao, Deli",Study on mud weight window prediction model and safety additional value of horizontal well in shales considering effects of Well's extended-reach limit,Mud weight window; Safety additional value; Horizontal well; Extended-reach limit; Shale gas field,STABILITY,"Safety additional value is always added to the conventional mud weight window (MWW) to ensure the drilling safety in shales. However, the safety additional value is usually an empirical value. Since the horizontal well usually has a long horizontal section in shales, failing to accurately predict the wells MWW and corresponding safety additional value in shales may result in serious drilling hazards. In order to ensure that the horizontal well can reach the designed horizontal-section length in shales, the conventional MWW needs to be modified and the calculated value of safety additional value should also be given. In this paper, considering the effects of horizontal wells extended-reach limit and its horizontal-section limit (HSL) on the wells MWW in shales, the drilling process, tripping process and six constraint conditions are considered simultaneously. Results of the case study indicate that the corresponding safety additional value is calculated instead of using an empirical value. Moreover, the predicted MWW becomes narrower as the designed horizontal-section length is increased. In addition, in order to obtain a wider MWW, tripping velocity should be lower if the economic benefits can be satisfied. Additionally, the drilling pump with higher rated pressure is also necessary. Taking the maximum HSL as the objective function, there exists an optimal drilling fluid density, which is crucial for production in shales. The calculated value of safety additional value and the modified MWW can ensure the horizontal well reach the designed horizontal-section length, obtaining enough production and economic benefits as well as avoiding drilling hazards in shales.",5,6,1
Drilling Fluid,Case,"Mitchell, Jonathan; Valori, Andrea; Fordham, Edmund J.",A robust nuclear magnetic resonance workflow for quantitative determination of petrophysical properties from drill cuttings,NMR; Cuttings; Fluorinert; Multinuclear; Fluorine NMR; Porosity; Permeability,SPIN RELAXATION; FLUID; NMR,"Determination of petrophysical parameters from surface measurements of drill cuttings, rather than well logs, has long been a subject of interest in the petroleum industry. Analysis of cuttings is presently included in mud logging workflows, although the methods employed tend to be labor-intensive and inefficient with an emphasis on qualitative lithological and mineralogical descriptors. Nuclear magnetic resonance (NMR) has the potential to deliver rapid formation evaluation at the rig site for near-real-time completion decisions. Despite numerous efforts to demonstrate NMR cuttings analysis, dating back to the 1980s, the technique has yet to achieve commercial success. We suggest this failure is due not to the physics of the measurement, which is understood, but rather to inadequate sample preparation. By centrifuging brine-saturated cuttings from conventional formations under a per-fluorinated oil, and using multinuclear NMR to measure liquid volumes, we obtain accurate porosity and permeability values independent of other measurements. Our robust workflow removes the inconsistencies associated with manual sample preparation. We present two case studies and the important requirements for handling actual drill cuttings.",5,5,2
Drilling Fluid,Density Measurement,"Singhal, Vivek; Ashok, Pradeepkumar; van Oort, Eric",X-ray densitometry of drilling fluids at the rig standpipe,Drilling fluid density; X-ray densitometer; Real-time density measurement; High-pressure density meter,ATOMIC-NUMBER; DENSITY; ENERGY; TEMPERATURE; FLOW,"Fluids used during well construction operations serve as a primary barrier for well control, with the fluid density generating sufficient hydrostatic pressure in the fluid column to control downhole formation fluids and gas. Realtime density measurement at the well inlet, where high pressures of many thousands of psi can occur, is highly desirable in order to maintain well control. This improved characterization of the well bore pressure profile allows one to drill wells with narrow drilling margins without non-productive time from well control events, resulting in safer and more cost-effective well construction operations. Gamma ray densitometers are suitable measuring devices for high-pressure density measurement. Typical flow conditions encountered at the inlet, such as a fully filled pipe and a homogeneously mixed mud, are very conducive to their use. In-spite of their high measurement accuracy and relatively fast response times, however, these meters have seen limited adoption in field. This is primarily because the meters come with safety concerns due to the radioactive source required for gamma ray generation. Additionally, the source has to be tracked throughout its life and properly handled during storage, transportation, installation and disposal. Given these concerns and challenges, a majority of oil and gas operating and service companies use manual density measurements at the mud pits using a pressurized mud balance. To help change this rather antiquated and infrequent practice that relies on manual labor, this paper evaluates the feasibility of using a non-radioactive, X-ray based densitometer as an alternative to the gamma ray meter. X-ray densitometry works on the same proven principles as gamma ray densitometry, without the latter's drawbacks. Two X-ray methods, an empirical method and a model-based method (inspired by a technique used in the medical field known as single X-ray absorptiometry) are presented here. Real-time density measurements on the high pressure line with an accuracy of 99% or better and a measurement frequency of 1 Hz are feasible using these methods.",0,0,1
Drilling Fluid,Density Measurement,"Li, Xin; Gao, Deli; Lu, Baoping; Zeng, Yijin; Zhang, Jincheng",Study on modified maximum extension length prediction model for horizontal wells considering differential sticking,Horizontal well; Maximum extension length; Differential sticking; Drilling fluid density; Casing running down/pulling out speed,EXTENDED-REACH LIMIT,"Maximum extension length prediction model for horizontal wells can be used to evaluate the horizontal well's extension capability and predict its maximum measured depth, which is of great significance to the production and economic benefits of horizontal wells. However, the differential sticking is not considered in previous prediction model. To overcome this shortcoming, a modified model considering differential sticking is established based on constraints of wellbore stability, differential pressure, and filtration loss simultaneously during the drilling, tripping processes and static state. Then a horizontal well is analyzed and its maximum extension length is predicted. Results show that within the conventional mud weight window, three ranges of drilling fluid density can be determined, including the first range, the second range and the reasonable range of drilling fluid density. However, only the reasonable range of drilling fluid density can satisfy all constraints of the modified prediction model, including the wellbore stability, differential pressure, and filtration loss simultaneously. Compared with the original model, the predicted well's maximum extension length decreases when the differential sticking is considered. However, it is more accurate, avoiding drilling hazards in actual drilling operation due to the excessive designed measured depth and unreasonable drilling parameters. Moreover, the maximum speeds of casing running down/pulling out are also determined and added to the modified model. Therefore, the modified model with reasonable drilling fluid density and adjusted running down/pulling out speed is the optimal modified model to predict maximum extension length and avoid differential sticking, which can also ensure that the horizontal well's designed measured depth can be successfully achieved. This study is of great significance to improve the prediction accuracy of horizontal well's maximum extension length and avoid drilling hazards, especially the differential sticking. Moreover, it also plays a guiding role in the selection of reasonable drilling fluid density during horizontal drilling.",3,4,3
Drilling Fluid,Density Measurement,"Singhal, Vivek; Ashok, Pradeep; van Oort, Eric",High pressure measurement of mud density and flow rate for oil and gas well construction: Making the case for X-Ray metering,Mud density and flow rate measurement; Review of drilling fluid density and flow rate measurement technologies; Mass flow rate measurement for managed pressure drilling operations; X-ray densitometery and flow rate measurement,PARTICLE IMAGE VELOCIMETRY; 2-PHASE FLOW; CORIOLIS; DENSITOMETER; DESIGN; CALIBRATION; COMPOSITES; FLOWMETERS; VELOCITY; FLUID,"With a myriad of flow and density sensors available, it can be difficult to decide on the right metering technology to make density and mass flow rate measurements, that suits both application and cost requirements. Operational specifications listed in product brochures typically apply to tests done under highly controlled conditions and generally fail to account for the extreme variability in flow conditions of drilling and completions fluids in the real world. Thus, time and other resources can be wasted by the end users in trying to validate the various meters. Even when right metering technology is selected the measured values often have low accuracy and low measurement frequency. The intent of this paper is to provide a high level overview of the working principles of some of the main-stream metering technologies, identify applications they are well suited for, clarify their limitations, and provide an overview into current research to address these limitations. The paper will allow the reader to narrow down options for appropriate density and flow metering solutions for particular applications, and at the same time highlight the gaps and needs that need to be addressed by further research and development. The paper also discusses an X-ray based metering technology that overcomes some of the disadvantages and deficiencies of established meters. Recent work on characterizing the drilling fluid density and flow rate at the high pressure well inlet using X-rays has shown that these measurements can now be made with greater than 99% accuracy and at 1 Hz measurement frequency. Such level of accuracy and measurement frequency is not offered by any of the mainstream metering technologies. It is expected that the X-ray based technology when implemented will lead to a step-change improvement in current density and delta flow (flow in - flow out) assessment, and will thereby positively contribute to improved hydraulics management, better and earlier kick detection, and further enhanced managed pressure drilling control. In this paper we build upon the existing work on X-ray based density and flow rate measurements of drilling fluids. Specifically, we discuss preliminary work towards development of a new flow measurement technique which can measure flow rate using an X-ray flat panel detector. Using a flat panel detector offers a cheaper alternative to the existing high speed imaging based flow measurement methods. We also share results from a method developed for real-time calibration of the X-ray detectors. Using the calibration method X-ray measurements are shown to have a repeatability of greater than 99%. A section is also dedicated to characterizing the intensity output from the X-ray source. Finally, we show that X-ray density measurements conducted with static fluids in existing literature remain unaffected when the same density fluid flows through a pipe.",4,4,1
Drilling Fluid,Density Measurement,"Govindu, Abhishek; Ahmed, Ramadan; Shah, Subhash; Amani, Mahmood",Stability of foams in pipe and annulus,Foam stability; Bubble coarsening; Coalescence; Gravity drainage; Half-life; Foam quality,RHEOLOGICAL BEHAVIOR; DRAINAGE,"Foam fluids present numerous advantages for many oil field applications. Due to their bubble structure and a gaseous component, foams exhibit very high viscosity and low density. Low density makes foam an attractive fluid in underbalanced drilling operation in which light fluid is essential to maintain wellbore pressure below pore pressure. Due to its high viscosity, foam exhibits good hole-cleaning performance even at low annular velocities. Nevertheless, foams are thermodynamically unstable fluids and their structures eventually collapse. Foam decays as a function of time and the decay occurs mainly due to bubble coalescence and the gravity drainage of the liquid phase. Maintaining fluid stability is necessary for foam drilling. For a successful drilling operation, the half-life of foam, which is the time taken by foam to drain 50% of its liquid volume, should exceed circulation time. For other applications, such as hydraulic fracturing or cementing, the half-life of foam should exceed the time taken for fluid to reach target zones. In this study, foam stability experiments were conducted in a concentric annulus (50mmx75 mm) and 25 mm pipe sections. The pipe section was transparent to observe drained liquid level. Aqueous, polymer-based, and oil-based foams were considered in the investigation. The effect of gas volume fraction (quality) was studied under static condition. All experiments were performed at 400 kPa and ambient temperature (20 +/- 2 degrees C). Foam quality was increased from 40% to 80%. However, at high qualities (greater than 70%), the oil-based foam was unstable. Hydrostatic pressure data was collected from the annular section and converted into density curves to determine drained liquid volume. In the pipe section, the drainage was physically measured from the liquid level and recorded periodically. A digital camera with a microscope was used to capture foam image in real-time to examine bubble coarsening and foam decay. For a given quality, the polymer-based foam was the most stable, while oil-based foam was the least. For all three types of foams, stability increased with quality. Foams were more stable in the annular section, as compared to the pipe, possibly due to the impact of container wall on bubbles and drained liquid motion. Foam decay and bubble coarsening were observed by comparing bubble sizes in captured images at various times. On average, larger bubbles were observed in higher quality foams. The rate at which foam bubbles coarsening mostly reduced with time.",4,4,5
Drilling Fluid,Density Measurement,"Zhang, Quanying; Zhang, Feng; Yuan, Chao; Wang, Xinguang; Zhang, Xiaoyang",A comparative study on the neutron-gamma density and gamma-gamma density logging,Pulsed neutron gamma density; Gamma-gamma density; Logging mechanism; Monte Carlo simulation; Instrument specifications,,"With the increasing demand for the radioisotope-free operations, using pulsed neutron gamma density (NGD) instead of gamma-gamma density (GGD) has become increasingly important for the development of logging while drilling (LWD) technology. However, due to the different logging mechanisms, there are huge differences between GGD and NGD in the instrument designs, measurement methods, and instrument specifications. To further promote the NGD development, a comparative study on GGD and NGD was carried out from theoretical and simulation aspects. Based on the theoretical methods, the differences between GGD and NGD in the gamma sources, field distribution, methods for density measurement and instrument specifications were systematically elaborated. Then, using the Monte Carlo simulation, the GGD and NGD models were built to quantitatively verify the theoretical results. Last, the detailed performances of NGD and GGD methods in different logging environments were compared. Results showed that the theoretical results are highly consistent with the simulation results. The density sensitivity of NGD is less than half that of GGD, but the depth of investigation (DOI) approaches twice that of GGD. The density precision and vertical resolution of NGD are less than those of GGD. Additionally, compared to GGD, NGD also has an excellent performance in different pore fluid and lithology formations, but it is easily affected by borehole factors. The research can provide quantitative performance evaluations for the NGD replacing GGD in LWD logging.",5,5,1
Drilling Fluid,Density Measurement,"Galdino, Jonathan F.; Oliveira, Gabriel M.; Franco, Admilson T.; Negrao, Cezar O. R.","Gas kick detection and pressure transmission in thixotropic, compressible drilling fluids",Pressure transmission; Kick; Drilling fluid; Transient flow; Compressible flow; Thixotropy,MATHEMATICAL-MODEL; STRESS; FLOW; WELL; TRANSITION; BUBBLES,"During well drilling operations, unexpected gas influx may take place when the bottom hole pressure falls below the pore pressure. The conventional procedure to control the influx consists of shutting-in the well and waiting for pressure stabilization. The pressures measured at the surface after the well closure and the pit gain are used to estimate the pore pressure, the gas density, and the kick magnitude. However, the drilling fluid compressibility and rheology can undermine pore pressure transmission to the surface, which can affect the pit gain and the well closing pressure. The current work presents a transient compressible isothermal mathematical model to predict pit gain and pressure transmission along the well during gas kicks. The model is based on the balance equations of mass and momentum that are solved by the method of characteristics. Three types of drilling fluids are analyzed: Newtonian, Bingham Plastic and thixotropic. The Darcy's law is used to represent the gas influx through the rock formation. The results indicate that the usual pressure balance used to estimate the pore pressure may lead to mistaken values and also that the drilling fluid compressibility and rheology have considerable effect on the pit gain and on the gas volume that invades the well. In all cases investigated, the gas volume within the well is at least 50% higher than the pit gain. Therefore, drilling fluid compressibility cannot be neglected on the estimation of the formation fluid volume within the well.",5,5,1
Drilling Fluid,Prediction Model,"Li, Xin; Gao, Deli; Lu, Baoping; Zeng, Yijin; Zhang, Jincheng",Study on modified maximum extension length prediction model for horizontal wells considering differential sticking,Horizontal well; Maximum extension length; Differential sticking; Drilling fluid density; Casing running down/pulling out speed,EXTENDED-REACH LIMIT,"Maximum extension length prediction model for horizontal wells can be used to evaluate the horizontal well's extension capability and predict its maximum measured depth, which is of great significance to the production and economic benefits of horizontal wells. However, the differential sticking is not considered in previous prediction model. To overcome this shortcoming, a modified model considering differential sticking is established based on constraints of wellbore stability, differential pressure, and filtration loss simultaneously during the drilling, tripping processes and static state. Then a horizontal well is analyzed and its maximum extension length is predicted. Results show that within the conventional mud weight window, three ranges of drilling fluid density can be determined, including the first range, the second range and the reasonable range of drilling fluid density. However, only the reasonable range of drilling fluid density can satisfy all constraints of the modified prediction model, including the wellbore stability, differential pressure, and filtration loss simultaneously. Compared with the original model, the predicted well's maximum extension length decreases when the differential sticking is considered. However, it is more accurate, avoiding drilling hazards in actual drilling operation due to the excessive designed measured depth and unreasonable drilling parameters. Moreover, the maximum speeds of casing running down/pulling out are also determined and added to the modified model. Therefore, the modified model with reasonable drilling fluid density and adjusted running down/pulling out speed is the optimal modified model to predict maximum extension length and avoid differential sticking, which can also ensure that the horizontal well's designed measured depth can be successfully achieved. This study is of great significance to improve the prediction accuracy of horizontal well's maximum extension length and avoid drilling hazards, especially the differential sticking. Moreover, it also plays a guiding role in the selection of reasonable drilling fluid density during horizontal drilling.",3,4,3
Drilling Fluid,Prediction Model,"Li, Xiaorong; El Mohtar, Chadi S.; Gray, K. E.",3D poro-elasto-plastic modeling of breakouts in deviated wells,Wellbore breakouts; Mudcake; Deviated wells,BOREHOLE; STRESS; STABILITY; SEEPAGE; OIL,"Borehole breakouts are stress-induced enlargements of the wellbore cross-section. Predicting wellbore breakouts is important for the success of any drilling operation; however, accurate prediction of breakouts in deviated wells can be a technically challenging task. Misalignment between wellbore trajectory and field principal stress orientation along with the strong coupling between fluid flow, stresses and plasticity are some of the factors that makes breakouts in deviates well more challenging. This paper discusses a 3D poro-elasto-plastic numerical modeling approach for breakouts in deviated wells. Dynamic mudcake buildup on the wellbore wall is also incorporated into the numerical model, enabling quantitative analysis of the mudcake effect on the borehole breakout. The influences of well trajectory, fluid seepage between wellbore and formation pores, plastic strain softening of the rock, and dynamic mudcake buildup on the breakout are highlighted and analyzed using numerical examples. The results indicate that the breakout shape of deviated wells is largely dependent on well inclination while its volume can be reduced by mitigating fluid seepage through mudcake buildup. The proposed finite-element modeling approach in this study confirms the need to consider the coupling among these factors when predicting wellbore breakouts in complex geological and drilling conditions.",5,5,0
Drilling Fluid,Prediction Model,"Galdino, Jonathan F.; Oliveira, Gabriel M.; Franco, Admilson T.; Negrao, Cezar O. R.","Gas kick detection and pressure transmission in thixotropic, compressible drilling fluids",Pressure transmission; Kick; Drilling fluid; Transient flow; Compressible flow; Thixotropy,MATHEMATICAL-MODEL; STRESS; FLOW; WELL; TRANSITION; BUBBLES,"During well drilling operations, unexpected gas influx may take place when the bottom hole pressure falls below the pore pressure. The conventional procedure to control the influx consists of shutting-in the well and waiting for pressure stabilization. The pressures measured at the surface after the well closure and the pit gain are used to estimate the pore pressure, the gas density, and the kick magnitude. However, the drilling fluid compressibility and rheology can undermine pore pressure transmission to the surface, which can affect the pit gain and the well closing pressure. The current work presents a transient compressible isothermal mathematical model to predict pit gain and pressure transmission along the well during gas kicks. The model is based on the balance equations of mass and momentum that are solved by the method of characteristics. Three types of drilling fluids are analyzed: Newtonian, Bingham Plastic and thixotropic. The Darcy's law is used to represent the gas influx through the rock formation. The results indicate that the usual pressure balance used to estimate the pore pressure may lead to mistaken values and also that the drilling fluid compressibility and rheology have considerable effect on the pit gain and on the gas volume that invades the well. In all cases investigated, the gas volume within the well is at least 50% higher than the pit gain. Therefore, drilling fluid compressibility cannot be neglected on the estimation of the formation fluid volume within the well.",5,5,1
Drilling Fluid,Prediction Model,"Li, Xin; Gao, Deli",Study on mud weight window prediction model and safety additional value of horizontal well in shales considering effects of Well's extended-reach limit,Mud weight window; Safety additional value; Horizontal well; Extended-reach limit; Shale gas field,STABILITY,"Safety additional value is always added to the conventional mud weight window (MWW) to ensure the drilling safety in shales. However, the safety additional value is usually an empirical value. Since the horizontal well usually has a long horizontal section in shales, failing to accurately predict the wells MWW and corresponding safety additional value in shales may result in serious drilling hazards. In order to ensure that the horizontal well can reach the designed horizontal-section length in shales, the conventional MWW needs to be modified and the calculated value of safety additional value should also be given. In this paper, considering the effects of horizontal wells extended-reach limit and its horizontal-section limit (HSL) on the wells MWW in shales, the drilling process, tripping process and six constraint conditions are considered simultaneously. Results of the case study indicate that the corresponding safety additional value is calculated instead of using an empirical value. Moreover, the predicted MWW becomes narrower as the designed horizontal-section length is increased. In addition, in order to obtain a wider MWW, tripping velocity should be lower if the economic benefits can be satisfied. Additionally, the drilling pump with higher rated pressure is also necessary. Taking the maximum HSL as the objective function, there exists an optimal drilling fluid density, which is crucial for production in shales. The calculated value of safety additional value and the modified MWW can ensure the horizontal well reach the designed horizontal-section length, obtaining enough production and economic benefits as well as avoiding drilling hazards in shales.",5,6,1
Drilling Fluid,Prediction Model,"Sinha, Vineet; Ahmeda, Ramadan; Akhtar, Tarek; Shah, Subhash; Amani, Mahmood",Rheology and hydraulics of polymer-based foams at elevated temperatures,Foam; Polymer; Stimulation; Rheology; Hydraulics; Drilling,CONSTITUTIVE EQUATION; DRILLING FOAMS; FLOW BEHAVIOR; AQUEOUS FOAMS; FLUID-FLOWS; VISCOSITY; SUSPENSION,"Foam has been successfully used for different operations like well stimulation, drilling, enhanced oil recovery (EOR), cleanout, and acidizing operations in the oil and gas industry. Additionally, the low liquid content of foam provides a distinct advantage in terms of lesser material requirements. However, accurate prediction of rheology is necessary for the success of field operations, which requires a rheological model that incorporates the effect of temperature on foam properties as it circulates downhole. In the present investigation, polyanionic cellulose (PAC) based foam was generated using nitrogen as the gas phase and its rheology was determined using a recirculating flow loop that has three pipe viscometers (3.05, 6.22, and 12.7 mm ID) and a fully-eccentric annular section (9.53 mm OD x 12.57 mm ID). Experiments were conducted within the temperature range of 24 to 149 degrees C and at various foam qualities (gas phase volume fraction). The foam was circulated at different flow rates and the differential pressure across each pipe section was recorded. All tests were conducted at 6.89 MPa. The foams displayed power-law fluid behavior in the shear rate range tested (100-5000 s(-1)), which is often experienced in the wellbore. Like its base liquid, polymer foam exhibited thermal thinning and a significant rheology change with temperature. Only high-quality foam (75%) at ambient temperature (24 degrees C) showed yielding behavior, which was measured in a pipe viscometer under static condition. The disappearance of yield stress at elevated temperature could be attributed to thermal thinning of the liquid phase that weakens the strength of bubble structure. Experimental data is used to develop new correlations to predict power-law fluid parameters as a function of temperature, base fluid properties, and foam quality. Moreover, the measurements are compared with the predictions of existing models, and discrepancies are observed, which could be attributed to the variation in foam generation technique, the nature and concentration of polymer, and the concentration of surfactant used in the experiments in which data was obtained to develop the models. Furthermore, annular pressure loss measurements obtained at low temperatures (24 and 79 degrees C) show predominantly good agreement with predictions of a hydraulic model that uses the new correlations. Discrepancies increased with temperature as the foam becomes unstable due to thermal thinning of the liquid film and subsequent weakening of bubble structure.",5,5,1
Drilling Fluid,Prediction Model,"Albattat, Rami; Hoteit, Hussein",Modeling yield-power-law drilling fluid loss in fractured formation,Lost-circulation; Loss of drilling fluid; Mud loss; Flow in fractured formation; Yield power law; Herschel-Buckley; Cauchy momentum equation; Fracture ballooning,MATERIAL SELECTION GUIDELINES; PERFORMANCE; FLOW,"Loss of circulation during drilling is a pressing problem that typically occurs when significant volumes of the drilling fluid leak to the surrounding formation. In fractured media, circulation loss is often a sudden event which may interrupt the drilling operations, increase nonproductive time, and add complexity in controlling the fluid flow and wellbore stability. Developing models to predict the fluid leak dynamics and identify the suitable loss-control-material (LCM) is of significant interest to the industry. In this work, simulation and analytical models are developed to model the dynamics of fluid loss for power-law drilling fluids from the wellbore to a surrounding fractured medium. The model is based on the Cauchy momentum equation and accounts for the key predominant flow mechanisms, including the non-Newtonian behavior of the drilling fluid (mud) using a power-law model. Experiments from the literature are used to assess the behavior of mud loss into a single horizontal fracture, which includes the effects of mud rheology and yield stress. We show that previous unsuccessful attempts to match the experimental data using analytical models are related to the assumption of uniform fracture aperture. Simulations are then used to demonstrate that a slight deformation in the fracture walls leads to a significant deviation in the analytical model predictions, and therefore the dynamics of fracture opening is a critical parameter that should be carefully assessed. In other related experiments, the analytical model also failed to capture the mud invasion distance within the fracture as a function of pressure drop and the mud properties. To address this issue, a modified analytical model that accounts for non-parallel fracture walls is proposed. The new model allows to quickly assessing the impact of nonuniform fracture apertures. It can serve as a screening tool to evaluate mud invasion distance as a function of fracture geometry, mud rheological properties, and pressure drop resulting from the well depth, injection rate, and mud density.",5,5,3
Drilling Fluid,Particles,"Pacheco, Laura Villela; de Oliveira Borges, Rodrigo Fernando; de Oliveira, Beatriz Rosas; Scheid, Claudia Miriam; Calcada, Luis Americo",Study on the dissolution kinetics of NaCl in environmentally friendly drilling fluids containing glycerin,Glycerin; Environmental; Drilling fluids; Dissolution kinetics; Mass transfer coefficient,PARTICLES; OIL; KCL,"The oil well drilling process in the pre-salt layer faces some challenges including the salt dissolution on the drilling muds. The dissolution may be harmful to mechanical processes and drastically change fluid properties. With the increasing research for less aggressive fluids, glycerin from biodiesel production meets technical, economic and environmental requirements for fluids formulation. The aim of this work is the study of dissolution kinetics of NaCl in drilling fluids containing glycerin. Experimental dynamic salt concentration profiles in the liquid phase were obtained in a stirred tank. These data were used to evaluate the mass transfer coefficient in different rotation rates and salt concentrations. The mathematical model simulated the process by the application of the mass conservation equations applied on fluid and solid phases. Through experimental analysis and parameter estimation, the kinetics dissolution was evaluated for two types of glycerin, different rotation speeds and salt concentrations.",2,3,1
Drilling Fluid,Particles,"Wang, Dongying; Wang, Zhiming; Zeng, Quanshu",An experimental study on gas/liquid/solid three-phase flow in horizontal coalbed methane production wells,Gas/liquid/solid three-phase flow; Coalbed methane; Horizontal well; Flow pattern; Height of coal particle bed; Explicit equation,SAND-DEPOSITION VELOCITY; RESERVOIR ROCKS; LIQUID; GAS; PARTICLES; TRANSPORT,"Coal particles caused by well drilling and completion, hydraulic fracturing, and formation pressure decreasing would migrate into the horizontal well carried by fracturing flow-back fluid, formation water and CBM, and then deposit on the low side of pipe leading to the decrease of cross section area of pipe for flow and even blocking of the pipe. The purpose of current research was to obtain the flow pattern while there was stationary solid particle bed on the low side of the pipe and an explicit equation to predict the height of solid particle bed was proposed. In this study, with the coal particle, water, and air as the solid, liquid, and gas phases respectively, gas/liquid/ solid three-phase flow experiments in horizontal well were carried out and 4 crucial factors including different water flow rate, gas flow rate, coal particle size, and coal particle mass concentration were considered. Fluid's real apparent velocity was defined and used to analyze the distribution of flow pattern coordinate points. Results show that the flow pattern coordinate points determined by real gas apparent velocity and real water apparent velocity distribute near the flow pattern transition lines of Taitel and Dukler flow pattern map. Besides, coal particle size, water flow rate, and gas flow rate have obvious impact on the height of coal particle bed and the coal particle mass concentration has a negligible effect while the height of interface between gas layer and water layer is only dramatically affected by the gas flow rate. At last, an explicit equation for predicting the cross section area of coal particle bed based on the experimental data was proposed which is crucial to predict the flow pattern and calculate the pressure drop in horizontal well. The predicting cross section area of coal particle bed is in good agreement with the measured cross section area of coal particle bed and the average relative differences are 9.38% and 13.45% for stratified smooth flow and stratified wavy flow respectively. The equation is applicable for a range of coal particle size (8-30 mesh) and water apparent velocity (0.025-0.123 m/s).",2,2,4
Drilling Fluid,Particles,"Fagundes, F. M.; Santos, N. B. C.; Martins, A. L.; Damasceno, J. J. R.; Arouca, F. O.",Gravitational solid-liquid separation of water-based drilling fluids weighted with hematite through the gamma-ray attenuation technique,Gamma-ray attenuation; Water-based drilling fluid; Hematite; Pressure on solids,SHEAR-THINNING FLUIDS; SEDIMENTATION; AGGREGATION; SUSPENSIONS,"Drilling fluids are injected during the drilling process in order to make the operation viable. Some of the desired functions of these fluids are the following: to be pumpable, to clean the well by transporting cuttings to the surface, to suspend the solids in operational stops, to stabilize the walls of the well, to block the pores of the rock formation, to lubricate and cool the drilling bit and other equipment used, and to be chemically stable and inert in relation to damage to the rock formation. The drilling of an oil well is done in stages, as each rock formation demands a specific fluid formulation. These suspensions have a water, oil, air or synthetic base and different substances and incorporated particles, such as viscosifying, sealing, weighting and thickening agents. The drilling fluids studied in this work were produced by a Brazilian petroleum company, differentiated by the amount of the weighting agent (hematite). In this context, this study simulated a standstill operation and evaluated the stability of particles in four water-based drilling fluids through the gamma-ray attenuation technique to determine an equation for pressure on solids for each system. The rheological behavior of the suspensions was also evaluated. The results showed that fluids with higher amounts of hematite had higher viscosity, pseudoplastic and tixotropic behavior, sediment with higher volumetric concentration, greater stability in relation to sedimentation and a small region of clarified liquid. In addition, constitutive equations were determined for pressure on the solids, and the influence of hematite was also verified.",4,4,0
Drilling Fluid,Particles,"Singhal, Vivek; Ashok, Pradeep; van Oort, Eric",High pressure measurement of mud density and flow rate for oil and gas well construction: Making the case for X-Ray metering,Mud density and flow rate measurement; Review of drilling fluid density and flow rate measurement technologies; Mass flow rate measurement for managed pressure drilling operations; X-ray densitometery and flow rate measurement,PARTICLE IMAGE VELOCIMETRY; 2-PHASE FLOW; CORIOLIS; DENSITOMETER; DESIGN; CALIBRATION; COMPOSITES; FLOWMETERS; VELOCITY; FLUID,"With a myriad of flow and density sensors available, it can be difficult to decide on the right metering technology to make density and mass flow rate measurements, that suits both application and cost requirements. Operational specifications listed in product brochures typically apply to tests done under highly controlled conditions and generally fail to account for the extreme variability in flow conditions of drilling and completions fluids in the real world. Thus, time and other resources can be wasted by the end users in trying to validate the various meters. Even when right metering technology is selected the measured values often have low accuracy and low measurement frequency. The intent of this paper is to provide a high level overview of the working principles of some of the main-stream metering technologies, identify applications they are well suited for, clarify their limitations, and provide an overview into current research to address these limitations. The paper will allow the reader to narrow down options for appropriate density and flow metering solutions for particular applications, and at the same time highlight the gaps and needs that need to be addressed by further research and development. The paper also discusses an X-ray based metering technology that overcomes some of the disadvantages and deficiencies of established meters. Recent work on characterizing the drilling fluid density and flow rate at the high pressure well inlet using X-rays has shown that these measurements can now be made with greater than 99% accuracy and at 1 Hz measurement frequency. Such level of accuracy and measurement frequency is not offered by any of the mainstream metering technologies. It is expected that the X-ray based technology when implemented will lead to a step-change improvement in current density and delta flow (flow in - flow out) assessment, and will thereby positively contribute to improved hydraulics management, better and earlier kick detection, and further enhanced managed pressure drilling control. In this paper we build upon the existing work on X-ray based density and flow rate measurements of drilling fluids. Specifically, we discuss preliminary work towards development of a new flow measurement technique which can measure flow rate using an X-ray flat panel detector. Using a flat panel detector offers a cheaper alternative to the existing high speed imaging based flow measurement methods. We also share results from a method developed for real-time calibration of the X-ray detectors. Using the calibration method X-ray measurements are shown to have a repeatability of greater than 99%. A section is also dedicated to characterizing the intensity output from the X-ray source. Finally, we show that X-ray density measurements conducted with static fluids in existing literature remain unaffected when the same density fluid flows through a pipe.",4,4,1
Drilling Fluid,Particles,"Maity, Debotyam; Ciezobka, Jordan",Designing a robust proppant detection and classification workflow using machine learning for subsurface fractured rock samples post hydraulic fracturing operations,Artificial neural nets; Image processing; Classifier benchmarking; Unconventional reservoirs; Core sampling; Shale rock,NEURAL-NETWORK; ALGORITHM,"Hydraulic fracturing is a method of reservoir stimulation that enhances the effective permeability of tight unconventional reservoirs such as shale oil and gas. In typical hydraulic fracturing treatments, millions of gallons of water are pumped under pressure into rock formations deep below the earths surface. Proppant particles such as sand are injected as part of the fracturing slurry to hold the hydraulic fractures open, or propped, after high-pressure water injection has ceased. Propped hydraulic fractures provide a conduit for long-term hydrocarbon production, thus being essential to commercial oil and gas production from shale reservoirs. The distribution of the proppant particles can be useful in understanding effectiveness of hydraulic fracturing treatments. It can also help identify both, unstimulated and under-stimulated zones within the reservoirs of interest. These proppant particles can be found in drilling fluid return or in cores, which can be sampled from subsurface. In this study, we highlight the design and development of artificial neural network based workflow that helps identify where proppant particles are located and classifies proppant and various particles of interest. In this study, these particles are limited to naturally occurring calcite or other minerals from subsurface rocks. Various features of interest that help with the classification process have been conceptualized and defined. This method has been verified using controlled test cases and validated using actual samples from subsurface. The designed ANN classifier has also been benchmarked with other classification methods including k-nearest neighbor, naive-Bayes classifiers and Support vector machines. A workflow to process samples from subsurface and quantify proppant distribution for future test programs including potential real time applications has been proposed. Based on this workflow, we share proppant distribution from a Permian Basin case study. We have also compared proppant distribution using our proposed method with results from an independent workflow on a similar dataset, which does not utilize machine learning.",5,5,0
Drilling Fluid,Flow Rate,"Wang, Dongying; Wang, Zhiming; Zeng, Quanshu",An experimental study on gas/liquid/solid three-phase flow in horizontal coalbed methane production wells,Gas/liquid/solid three-phase flow; Coalbed methane; Horizontal well; Flow pattern; Height of coal particle bed; Explicit equation,SAND-DEPOSITION VELOCITY; RESERVOIR ROCKS; LIQUID; GAS; PARTICLES; TRANSPORT,"Coal particles caused by well drilling and completion, hydraulic fracturing, and formation pressure decreasing would migrate into the horizontal well carried by fracturing flow-back fluid, formation water and CBM, and then deposit on the low side of pipe leading to the decrease of cross section area of pipe for flow and even blocking of the pipe. The purpose of current research was to obtain the flow pattern while there was stationary solid particle bed on the low side of the pipe and an explicit equation to predict the height of solid particle bed was proposed. In this study, with the coal particle, water, and air as the solid, liquid, and gas phases respectively, gas/liquid/ solid three-phase flow experiments in horizontal well were carried out and 4 crucial factors including different water flow rate, gas flow rate, coal particle size, and coal particle mass concentration were considered. Fluid's real apparent velocity was defined and used to analyze the distribution of flow pattern coordinate points. Results show that the flow pattern coordinate points determined by real gas apparent velocity and real water apparent velocity distribute near the flow pattern transition lines of Taitel and Dukler flow pattern map. Besides, coal particle size, water flow rate, and gas flow rate have obvious impact on the height of coal particle bed and the coal particle mass concentration has a negligible effect while the height of interface between gas layer and water layer is only dramatically affected by the gas flow rate. At last, an explicit equation for predicting the cross section area of coal particle bed based on the experimental data was proposed which is crucial to predict the flow pattern and calculate the pressure drop in horizontal well. The predicting cross section area of coal particle bed is in good agreement with the measured cross section area of coal particle bed and the average relative differences are 9.38% and 13.45% for stratified smooth flow and stratified wavy flow respectively. The equation is applicable for a range of coal particle size (8-30 mesh) and water apparent velocity (0.025-0.123 m/s).",2,2,4
Drilling Fluid,Flow Rate,"Singhal, Vivek; Ashok, Pradeep; van Oort, Eric",High pressure measurement of mud density and flow rate for oil and gas well construction: Making the case for X-Ray metering,Mud density and flow rate measurement; Review of drilling fluid density and flow rate measurement technologies; Mass flow rate measurement for managed pressure drilling operations; X-ray densitometery and flow rate measurement,PARTICLE IMAGE VELOCIMETRY; 2-PHASE FLOW; CORIOLIS; DENSITOMETER; DESIGN; CALIBRATION; COMPOSITES; FLOWMETERS; VELOCITY; FLUID,"With a myriad of flow and density sensors available, it can be difficult to decide on the right metering technology to make density and mass flow rate measurements, that suits both application and cost requirements. Operational specifications listed in product brochures typically apply to tests done under highly controlled conditions and generally fail to account for the extreme variability in flow conditions of drilling and completions fluids in the real world. Thus, time and other resources can be wasted by the end users in trying to validate the various meters. Even when right metering technology is selected the measured values often have low accuracy and low measurement frequency. The intent of this paper is to provide a high level overview of the working principles of some of the main-stream metering technologies, identify applications they are well suited for, clarify their limitations, and provide an overview into current research to address these limitations. The paper will allow the reader to narrow down options for appropriate density and flow metering solutions for particular applications, and at the same time highlight the gaps and needs that need to be addressed by further research and development. The paper also discusses an X-ray based metering technology that overcomes some of the disadvantages and deficiencies of established meters. Recent work on characterizing the drilling fluid density and flow rate at the high pressure well inlet using X-rays has shown that these measurements can now be made with greater than 99% accuracy and at 1 Hz measurement frequency. Such level of accuracy and measurement frequency is not offered by any of the mainstream metering technologies. It is expected that the X-ray based technology when implemented will lead to a step-change improvement in current density and delta flow (flow in - flow out) assessment, and will thereby positively contribute to improved hydraulics management, better and earlier kick detection, and further enhanced managed pressure drilling control. In this paper we build upon the existing work on X-ray based density and flow rate measurements of drilling fluids. Specifically, we discuss preliminary work towards development of a new flow measurement technique which can measure flow rate using an X-ray flat panel detector. Using a flat panel detector offers a cheaper alternative to the existing high speed imaging based flow measurement methods. We also share results from a method developed for real-time calibration of the X-ray detectors. Using the calibration method X-ray measurements are shown to have a repeatability of greater than 99%. A section is also dedicated to characterizing the intensity output from the X-ray source. Finally, we show that X-ray density measurements conducted with static fluids in existing literature remain unaffected when the same density fluid flows through a pipe.",4,4,1
Drilling Fluid,Flow Rate,"Sinha, Vineet; Ahmeda, Ramadan; Akhtar, Tarek; Shah, Subhash; Amani, Mahmood",Rheology and hydraulics of polymer-based foams at elevated temperatures,Foam; Polymer; Stimulation; Rheology; Hydraulics; Drilling,CONSTITUTIVE EQUATION; DRILLING FOAMS; FLOW BEHAVIOR; AQUEOUS FOAMS; FLUID-FLOWS; VISCOSITY; SUSPENSION,"Foam has been successfully used for different operations like well stimulation, drilling, enhanced oil recovery (EOR), cleanout, and acidizing operations in the oil and gas industry. Additionally, the low liquid content of foam provides a distinct advantage in terms of lesser material requirements. However, accurate prediction of rheology is necessary for the success of field operations, which requires a rheological model that incorporates the effect of temperature on foam properties as it circulates downhole. In the present investigation, polyanionic cellulose (PAC) based foam was generated using nitrogen as the gas phase and its rheology was determined using a recirculating flow loop that has three pipe viscometers (3.05, 6.22, and 12.7 mm ID) and a fully-eccentric annular section (9.53 mm OD x 12.57 mm ID). Experiments were conducted within the temperature range of 24 to 149 degrees C and at various foam qualities (gas phase volume fraction). The foam was circulated at different flow rates and the differential pressure across each pipe section was recorded. All tests were conducted at 6.89 MPa. The foams displayed power-law fluid behavior in the shear rate range tested (100-5000 s(-1)), which is often experienced in the wellbore. Like its base liquid, polymer foam exhibited thermal thinning and a significant rheology change with temperature. Only high-quality foam (75%) at ambient temperature (24 degrees C) showed yielding behavior, which was measured in a pipe viscometer under static condition. The disappearance of yield stress at elevated temperature could be attributed to thermal thinning of the liquid phase that weakens the strength of bubble structure. Experimental data is used to develop new correlations to predict power-law fluid parameters as a function of temperature, base fluid properties, and foam quality. Moreover, the measurements are compared with the predictions of existing models, and discrepancies are observed, which could be attributed to the variation in foam generation technique, the nature and concentration of polymer, and the concentration of surfactant used in the experiments in which data was obtained to develop the models. Furthermore, annular pressure loss measurements obtained at low temperatures (24 and 79 degrees C) show predominantly good agreement with predictions of a hydraulic model that uses the new correlations. Discrepancies increased with temperature as the foam becomes unstable due to thermal thinning of the liquid film and subsequent weakening of bubble structure.",5,5,1
Drilling Fluid,Flow Rate,"Albattat, Rami; Hoteit, Hussein",Modeling yield-power-law drilling fluid loss in fractured formation,Lost-circulation; Loss of drilling fluid; Mud loss; Flow in fractured formation; Yield power law; Herschel-Buckley; Cauchy momentum equation; Fracture ballooning,MATERIAL SELECTION GUIDELINES; PERFORMANCE; FLOW,"Loss of circulation during drilling is a pressing problem that typically occurs when significant volumes of the drilling fluid leak to the surrounding formation. In fractured media, circulation loss is often a sudden event which may interrupt the drilling operations, increase nonproductive time, and add complexity in controlling the fluid flow and wellbore stability. Developing models to predict the fluid leak dynamics and identify the suitable loss-control-material (LCM) is of significant interest to the industry. In this work, simulation and analytical models are developed to model the dynamics of fluid loss for power-law drilling fluids from the wellbore to a surrounding fractured medium. The model is based on the Cauchy momentum equation and accounts for the key predominant flow mechanisms, including the non-Newtonian behavior of the drilling fluid (mud) using a power-law model. Experiments from the literature are used to assess the behavior of mud loss into a single horizontal fracture, which includes the effects of mud rheology and yield stress. We show that previous unsuccessful attempts to match the experimental data using analytical models are related to the assumption of uniform fracture aperture. Simulations are then used to demonstrate that a slight deformation in the fracture walls leads to a significant deviation in the analytical model predictions, and therefore the dynamics of fracture opening is a critical parameter that should be carefully assessed. In other related experiments, the analytical model also failed to capture the mud invasion distance within the fracture as a function of pressure drop and the mud properties. To address this issue, a modified analytical model that accounts for non-parallel fracture walls is proposed. The new model allows to quickly assessing the impact of nonuniform fracture apertures. It can serve as a screening tool to evaluate mud invasion distance as a function of fracture geometry, mud rheological properties, and pressure drop resulting from the well depth, injection rate, and mud density.",5,5,3
Drilling Fluid,Shale,"Khan, Natasha",Application of integrated clustering and petrophysical-microscopic methods for facies determination of Campanian-Maastrichtian and Danian-Thanetian reservoirs: Constraints for tectonostratigraphic influences on sedimentation across the NW Indian Plate margin,Petrophysics; Cluster analysis; Electrofacies; Sulaiman province,SULAIMAN FOLD-BELT; SEQUENCE STRATIGRAPHY; CLASSIFICATION; PERMEABILITY; SANDSTONE; BASIN; ELECTROFACIES; GLAUCONY; OFFSHORE; POROSITY,"This paper focuses on reservoirs study in tectonostratigraphic perspective using soft computing multivariate statistical technique of clustering analysis (CA) to delineate electrofacies (EF) for rock typing. The EF knowledge was combined with petrophysics, rock fabric number (rfn) and application of microscopic studies comprising thin sections (TS), scanning electron microscopy (SEM), back scattered electron (BSE) and energy dispersive X-Ray spectroscopy (EDS) on fauna acquired from novel drill cuttings of selected wells. The methods were implemented on data of eight exploratory wells from eastern Sulaiman sedimentary basin (Pakistan) to investigate tectonostratigraphic influences and reservoir characteristics of the Campanian-Maastrichtian, and Danian-Thanetian reservoirs. The Danian-Thanetian (Upper and Lower Ranikot Formations) demonstrate good reservoir rocks in the Sulaiman Fold Belt (SFB) and the northern part of the Zindapir (ZA), however, in the Sulaiman Depression (SD), the Danian-Thanetian reservoirs are shale-rich bearing poor reservoir potential based on EF log correlation. The presence of glauconite (Gl) in the Paleocene Ranikot intervals suggests transgressive (TST) or early highstand system tract (HST) for this particular formation. This evidence is further supported by the occurrence of planktonic foraminifera (Pl), the abundance of which is indicative of late TSTs and early stage HSTs. The presence of Pl in the Campanian Parh Limestone indicates an open sea environment. The clay minerals (kaolinite, chlorite, montmorillonite) occurrence in Maastrichtian Pab Sandstone suggest the detrimental effect on reservoir quality, hindering permeability and fluid flow, proposing this particular formation as a tight reservoir. The kaolinite clay type in the Lower Ranikot Sands in the northern part of ZA characterize continental to near-shore sediments, indicative of fluviatile environment. The Maastrichtian Mughal Kot Formation in the SFB indicates arkosic sandstone (feldspar-rich) with some micaceous content and montmorillonite. The findings from the EF correlation of different wells demonstrate that the reservoir rocks in the SD to the southeast are more shale rich in comparison to those encountered in the SFB in the northeast and northwest. The rfn suggests class 1 type rock fabric (grain dominant) for the Cretaceous Parh Limestone. Due to incomplete logging data, it was not possible to derive rfn for Paleocene formations. The results validate the reservoir heterogeneities on microscopic and small-scale using drill cuttings and well logs. Geologically, active tectonics during the Cretaceous and Paleocene, local sea level fluctuations, diagenesis, clay mineralogy and paleo-topography have strongly affected the lateral variation of facies of Campanian-Maastrichtian, and Danian-Thanetian reservoirs. Moreover, regional active tectonics (Himalayan Orogeny) spanning the Cretaceous and Paleogene Periods also played a major role in crafting the reservoir architecture of various rock units. The results demonstrate the Campanian-Maastrichtian and Danian-Thanetian reservoirs as promising exploratory targets in the SFB. The comparison of the achieved outcomes showed a close agreement with the lateral facies variation in Cretaceous (Campanian-Maastrichtian) and Paleocene (Danian-Thanetian) across the study area.",2,2,0
Drilling Fluid,Shale,"Zhang, Yayun; Gao, Shuyang; Du, Xiaoyu; Chen, Mian; Jin, Yan",Molecular dynamics simulation of strength weakening mechanism of deep shale,Deep shale; Montmorillonite; Hydration; Molecular dynamic simulation; Conduction characteristics; Strength weakening,MONTE-CARLO-SIMULATION; ELASTIC PROPERTIES; K-MONTMORILLONITE; INTERLAYER STRUCTURE; COMPUTER-SIMULATION; WELLBORE STABILITY; NA-MONTMORILLONITE; CA-MONTMORILLONITE; HYDRATED LI; WATER,"Due to the dissimilarities in the hydration characteristics and degree of clay minerals, the wellbore instability and sloughing of deep shale is more sudden and destructive than that of the shallow shale. Previous works mainly consider the effects of temperature and pressure condition on the wellbore instability of deep shale at macroscopic scale, and ignore the microscopic mechanism of strength weakening during hydration and the evolution characteristics of montmorillonite(MMT) hydration under different isomorphic substitutions, temperature and pressure conditions. By considering the characteristics of clay minerals and drilling fluids in deep shales, the molecular dynamics simulations of MMT hydration in deep shale under different isomorphic substitutions, water content, temperature and pressure conditions were carried out to analyze the distribution and conduction evolution characteristics of water molecules and cations, and the response characteristics of crystal elastic parameters during the hydration process. The results indicate that: (1) As the water content increases, the interlayer spacing increases, but it is less sensitive to the temperature and pressure. Moreover, with the increase of water content, water molecules and ions are accelerated to intrude into crystal layer, and the hydration effects are enhanced and the weakening effects on rock strength are increased as well. (2) Both temperature and pressure have significant influences on the hydration characteristics of MMT, but the influential trends are opposite. Increasing temperature promotes the invasion of water molecules and sodium ions into the crystal layer so as to enhance the hydration, the weakening effect on rock strength becomes more remarkable. On the contrary, with the increase of pressure, the diffusion coefficient of water molecules and sodium ions to interlayer decreases which inhibits the weakening effect of clay hydration. (3) The differences of hydration characteristics of MMT with typical isomorphic substitutions are significant. The hydration ability of sodium ion in Fe-substituted MMT was weaker and the diffusion coefficient of water molecules was larger, so that water molecules more easily invade into the crystal layer, and the strength weakening is more significant than that of the Mg-substituted MMT system. Furthermore, the weakening effect is more significant under high temperature and low pressure conditions. The microscopic dynamic mechanism of clay hydration in deep shale can be throughly understood through molecular dynamics simulation, which provides an innovative research approach for the quantitative evaluation of drilling fluid hydration inhibition and microscopic control of clay hydration in deep shale.",4,4,3
Drilling Fluid,Shale,"Maity, Debotyam; Ciezobka, Jordan",Designing a robust proppant detection and classification workflow using machine learning for subsurface fractured rock samples post hydraulic fracturing operations,Artificial neural nets; Image processing; Classifier benchmarking; Unconventional reservoirs; Core sampling; Shale rock,NEURAL-NETWORK; ALGORITHM,"Hydraulic fracturing is a method of reservoir stimulation that enhances the effective permeability of tight unconventional reservoirs such as shale oil and gas. In typical hydraulic fracturing treatments, millions of gallons of water are pumped under pressure into rock formations deep below the earths surface. Proppant particles such as sand are injected as part of the fracturing slurry to hold the hydraulic fractures open, or propped, after high-pressure water injection has ceased. Propped hydraulic fractures provide a conduit for long-term hydrocarbon production, thus being essential to commercial oil and gas production from shale reservoirs. The distribution of the proppant particles can be useful in understanding effectiveness of hydraulic fracturing treatments. It can also help identify both, unstimulated and under-stimulated zones within the reservoirs of interest. These proppant particles can be found in drilling fluid return or in cores, which can be sampled from subsurface. In this study, we highlight the design and development of artificial neural network based workflow that helps identify where proppant particles are located and classifies proppant and various particles of interest. In this study, these particles are limited to naturally occurring calcite or other minerals from subsurface rocks. Various features of interest that help with the classification process have been conceptualized and defined. This method has been verified using controlled test cases and validated using actual samples from subsurface. The designed ANN classifier has also been benchmarked with other classification methods including k-nearest neighbor, naive-Bayes classifiers and Support vector machines. A workflow to process samples from subsurface and quantify proppant distribution for future test programs including potential real time applications has been proposed. Based on this workflow, we share proppant distribution from a Permian Basin case study. We have also compared proppant distribution using our proposed method with results from an independent workflow on a similar dataset, which does not utilize machine learning.",5,5,0
Drilling Fluid,Shale,"Li, Xin; Gao, Deli",Study on mud weight window prediction model and safety additional value of horizontal well in shales considering effects of Well's extended-reach limit,Mud weight window; Safety additional value; Horizontal well; Extended-reach limit; Shale gas field,STABILITY,"Safety additional value is always added to the conventional mud weight window (MWW) to ensure the drilling safety in shales. However, the safety additional value is usually an empirical value. Since the horizontal well usually has a long horizontal section in shales, failing to accurately predict the wells MWW and corresponding safety additional value in shales may result in serious drilling hazards. In order to ensure that the horizontal well can reach the designed horizontal-section length in shales, the conventional MWW needs to be modified and the calculated value of safety additional value should also be given. In this paper, considering the effects of horizontal wells extended-reach limit and its horizontal-section limit (HSL) on the wells MWW in shales, the drilling process, tripping process and six constraint conditions are considered simultaneously. Results of the case study indicate that the corresponding safety additional value is calculated instead of using an empirical value. Moreover, the predicted MWW becomes narrower as the designed horizontal-section length is increased. In addition, in order to obtain a wider MWW, tripping velocity should be lower if the economic benefits can be satisfied. Additionally, the drilling pump with higher rated pressure is also necessary. Taking the maximum HSL as the objective function, there exists an optimal drilling fluid density, which is crucial for production in shales. The calculated value of safety additional value and the modified MWW can ensure the horizontal well reach the designed horizontal-section length, obtaining enough production and economic benefits as well as avoiding drilling hazards in shales.",5,6,1
Drilling Fluid,Drill Cuttings,"Khan, Natasha",Application of integrated clustering and petrophysical-microscopic methods for facies determination of Campanian-Maastrichtian and Danian-Thanetian reservoirs: Constraints for tectonostratigraphic influences on sedimentation across the NW Indian Plate margin,Petrophysics; Cluster analysis; Electrofacies; Sulaiman province,SULAIMAN FOLD-BELT; SEQUENCE STRATIGRAPHY; CLASSIFICATION; PERMEABILITY; SANDSTONE; BASIN; ELECTROFACIES; GLAUCONY; OFFSHORE; POROSITY,"This paper focuses on reservoirs study in tectonostratigraphic perspective using soft computing multivariate statistical technique of clustering analysis (CA) to delineate electrofacies (EF) for rock typing. The EF knowledge was combined with petrophysics, rock fabric number (rfn) and application of microscopic studies comprising thin sections (TS), scanning electron microscopy (SEM), back scattered electron (BSE) and energy dispersive X-Ray spectroscopy (EDS) on fauna acquired from novel drill cuttings of selected wells. The methods were implemented on data of eight exploratory wells from eastern Sulaiman sedimentary basin (Pakistan) to investigate tectonostratigraphic influences and reservoir characteristics of the Campanian-Maastrichtian, and Danian-Thanetian reservoirs. The Danian-Thanetian (Upper and Lower Ranikot Formations) demonstrate good reservoir rocks in the Sulaiman Fold Belt (SFB) and the northern part of the Zindapir (ZA), however, in the Sulaiman Depression (SD), the Danian-Thanetian reservoirs are shale-rich bearing poor reservoir potential based on EF log correlation. The presence of glauconite (Gl) in the Paleocene Ranikot intervals suggests transgressive (TST) or early highstand system tract (HST) for this particular formation. This evidence is further supported by the occurrence of planktonic foraminifera (Pl), the abundance of which is indicative of late TSTs and early stage HSTs. The presence of Pl in the Campanian Parh Limestone indicates an open sea environment. The clay minerals (kaolinite, chlorite, montmorillonite) occurrence in Maastrichtian Pab Sandstone suggest the detrimental effect on reservoir quality, hindering permeability and fluid flow, proposing this particular formation as a tight reservoir. The kaolinite clay type in the Lower Ranikot Sands in the northern part of ZA characterize continental to near-shore sediments, indicative of fluviatile environment. The Maastrichtian Mughal Kot Formation in the SFB indicates arkosic sandstone (feldspar-rich) with some micaceous content and montmorillonite. The findings from the EF correlation of different wells demonstrate that the reservoir rocks in the SD to the southeast are more shale rich in comparison to those encountered in the SFB in the northeast and northwest. The rfn suggests class 1 type rock fabric (grain dominant) for the Cretaceous Parh Limestone. Due to incomplete logging data, it was not possible to derive rfn for Paleocene formations. The results validate the reservoir heterogeneities on microscopic and small-scale using drill cuttings and well logs. Geologically, active tectonics during the Cretaceous and Paleocene, local sea level fluctuations, diagenesis, clay mineralogy and paleo-topography have strongly affected the lateral variation of facies of Campanian-Maastrichtian, and Danian-Thanetian reservoirs. Moreover, regional active tectonics (Himalayan Orogeny) spanning the Cretaceous and Paleogene Periods also played a major role in crafting the reservoir architecture of various rock units. The results demonstrate the Campanian-Maastrichtian and Danian-Thanetian reservoirs as promising exploratory targets in the SFB. The comparison of the achieved outcomes showed a close agreement with the lateral facies variation in Cretaceous (Campanian-Maastrichtian) and Paleocene (Danian-Thanetian) across the study area.",2,2,0
Drilling Fluid,Drill Cuttings,"Fagundes, F. M.; Santos, N. B. C.; Martins, A. L.; Damasceno, J. J. R.; Arouca, F. O.",Gravitational solid-liquid separation of water-based drilling fluids weighted with hematite through the gamma-ray attenuation technique,Gamma-ray attenuation; Water-based drilling fluid; Hematite; Pressure on solids,SHEAR-THINNING FLUIDS; SEDIMENTATION; AGGREGATION; SUSPENSIONS,"Drilling fluids are injected during the drilling process in order to make the operation viable. Some of the desired functions of these fluids are the following: to be pumpable, to clean the well by transporting cuttings to the surface, to suspend the solids in operational stops, to stabilize the walls of the well, to block the pores of the rock formation, to lubricate and cool the drilling bit and other equipment used, and to be chemically stable and inert in relation to damage to the rock formation. The drilling of an oil well is done in stages, as each rock formation demands a specific fluid formulation. These suspensions have a water, oil, air or synthetic base and different substances and incorporated particles, such as viscosifying, sealing, weighting and thickening agents. The drilling fluids studied in this work were produced by a Brazilian petroleum company, differentiated by the amount of the weighting agent (hematite). In this context, this study simulated a standstill operation and evaluated the stability of particles in four water-based drilling fluids through the gamma-ray attenuation technique to determine an equation for pressure on solids for each system. The rheological behavior of the suspensions was also evaluated. The results showed that fluids with higher amounts of hematite had higher viscosity, pseudoplastic and tixotropic behavior, sediment with higher volumetric concentration, greater stability in relation to sedimentation and a small region of clarified liquid. In addition, constitutive equations were determined for pressure on the solids, and the influence of hematite was also verified.",4,4,0
Drilling Fluid,Drill Cuttings,"Magalhaes, S. C.; Borges, R. F. O.; Calcada, L. A.; Scheid, C. M.; Folsta, M.; Waldmann, A.; Martins, A. L.",Development of an expert system to remotely build and control drilling fluids,Drilling fluid; Control strategy; Heuristic rules; Density; Rheological properties,,"Drilling processes are viable only if drilling fluid is used. Drilling fluids are responsible for a number of operations, including cooling the system, carrying drill cuttings to surface, transmitting pressure and signals throughout the well and others. Therefore inefficiency during control of the drilling fluid parameters may cause costly and even deadly problems. In a previous work, researchers developed a sensor skid that was capable of reading, in real-time, physicochemical data of drilling fluids. This work expands the concepts and results obtained from that study, allowing automatic control of apparent viscosity and density. Using software, researchers have developed a pilot production plant. The production plant was coupled to the previously fluid monitoring skid, forming a closed hydraulic-electric loop. Some uncertainties had to be overcome, so researchers developed a controller based on Boolean logic and heuristic rules; this controller accounts for the kinetic behavior of the viscosifier, the constant changes of solids manufacturers, and the need to control multiple devices concomitantly. The expert system incorporates human knowledge instead of spending time and resources on calibrating the required classic control parameters. Researchers performed tests of set point tracking and disturbance rejection. The results demonstrated that the proposed control technique was adequate and could be applied as a control strategy to automate the quality control of drilling fluid.",4,5,0
Drilling Fluid,Drill Cuttings,"Mitchell, Jonathan; Valori, Andrea; Fordham, Edmund J.",A robust nuclear magnetic resonance workflow for quantitative determination of petrophysical properties from drill cuttings,NMR; Cuttings; Fluorinert; Multinuclear; Fluorine NMR; Porosity; Permeability,SPIN RELAXATION; FLUID; NMR,"Determination of petrophysical parameters from surface measurements of drill cuttings, rather than well logs, has long been a subject of interest in the petroleum industry. Analysis of cuttings is presently included in mud logging workflows, although the methods employed tend to be labor-intensive and inefficient with an emphasis on qualitative lithological and mineralogical descriptors. Nuclear magnetic resonance (NMR) has the potential to deliver rapid formation evaluation at the rig site for near-real-time completion decisions. Despite numerous efforts to demonstrate NMR cuttings analysis, dating back to the 1980s, the technique has yet to achieve commercial success. We suggest this failure is due not to the physics of the measurement, which is understood, but rather to inadequate sample preparation. By centrifuging brine-saturated cuttings from conventional formations under a per-fluorinated oil, and using multinuclear NMR to measure liquid volumes, we obtain accurate porosity and permeability values independent of other measurements. Our robust workflow removes the inconsistencies associated with manual sample preparation. We present two case studies and the important requirements for handling actual drill cuttings.",5,5,2
Drilling Fluid,Foam,"Govindu, Abhishek; Ahmed, Ramadan; Shah, Subhash; Amani, Mahmood",Stability of foams in pipe and annulus,Foam stability; Bubble coarsening; Coalescence; Gravity drainage; Half-life; Foam quality,RHEOLOGICAL BEHAVIOR; DRAINAGE,"Foam fluids present numerous advantages for many oil field applications. Due to their bubble structure and a gaseous component, foams exhibit very high viscosity and low density. Low density makes foam an attractive fluid in underbalanced drilling operation in which light fluid is essential to maintain wellbore pressure below pore pressure. Due to its high viscosity, foam exhibits good hole-cleaning performance even at low annular velocities. Nevertheless, foams are thermodynamically unstable fluids and their structures eventually collapse. Foam decays as a function of time and the decay occurs mainly due to bubble coalescence and the gravity drainage of the liquid phase. Maintaining fluid stability is necessary for foam drilling. For a successful drilling operation, the half-life of foam, which is the time taken by foam to drain 50% of its liquid volume, should exceed circulation time. For other applications, such as hydraulic fracturing or cementing, the half-life of foam should exceed the time taken for fluid to reach target zones. In this study, foam stability experiments were conducted in a concentric annulus (50mmx75 mm) and 25 mm pipe sections. The pipe section was transparent to observe drained liquid level. Aqueous, polymer-based, and oil-based foams were considered in the investigation. The effect of gas volume fraction (quality) was studied under static condition. All experiments were performed at 400 kPa and ambient temperature (20 +/- 2 degrees C). Foam quality was increased from 40% to 80%. However, at high qualities (greater than 70%), the oil-based foam was unstable. Hydrostatic pressure data was collected from the annular section and converted into density curves to determine drained liquid volume. In the pipe section, the drainage was physically measured from the liquid level and recorded periodically. A digital camera with a microscope was used to capture foam image in real-time to examine bubble coarsening and foam decay. For a given quality, the polymer-based foam was the most stable, while oil-based foam was the least. For all three types of foams, stability increased with quality. Foams were more stable in the annular section, as compared to the pipe, possibly due to the impact of container wall on bubbles and drained liquid motion. Foam decay and bubble coarsening were observed by comparing bubble sizes in captured images at various times. On average, larger bubbles were observed in higher quality foams. The rate at which foam bubbles coarsening mostly reduced with time.",4,4,5
Drilling Fluid,Foam,"Sinha, Vineet; Ahmeda, Ramadan; Akhtar, Tarek; Shah, Subhash; Amani, Mahmood",Rheology and hydraulics of polymer-based foams at elevated temperatures,Foam; Polymer; Stimulation; Rheology; Hydraulics; Drilling,CONSTITUTIVE EQUATION; DRILLING FOAMS; FLOW BEHAVIOR; AQUEOUS FOAMS; FLUID-FLOWS; VISCOSITY; SUSPENSION,"Foam has been successfully used for different operations like well stimulation, drilling, enhanced oil recovery (EOR), cleanout, and acidizing operations in the oil and gas industry. Additionally, the low liquid content of foam provides a distinct advantage in terms of lesser material requirements. However, accurate prediction of rheology is necessary for the success of field operations, which requires a rheological model that incorporates the effect of temperature on foam properties as it circulates downhole. In the present investigation, polyanionic cellulose (PAC) based foam was generated using nitrogen as the gas phase and its rheology was determined using a recirculating flow loop that has three pipe viscometers (3.05, 6.22, and 12.7 mm ID) and a fully-eccentric annular section (9.53 mm OD x 12.57 mm ID). Experiments were conducted within the temperature range of 24 to 149 degrees C and at various foam qualities (gas phase volume fraction). The foam was circulated at different flow rates and the differential pressure across each pipe section was recorded. All tests were conducted at 6.89 MPa. The foams displayed power-law fluid behavior in the shear rate range tested (100-5000 s(-1)), which is often experienced in the wellbore. Like its base liquid, polymer foam exhibited thermal thinning and a significant rheology change with temperature. Only high-quality foam (75%) at ambient temperature (24 degrees C) showed yielding behavior, which was measured in a pipe viscometer under static condition. The disappearance of yield stress at elevated temperature could be attributed to thermal thinning of the liquid phase that weakens the strength of bubble structure. Experimental data is used to develop new correlations to predict power-law fluid parameters as a function of temperature, base fluid properties, and foam quality. Moreover, the measurements are compared with the predictions of existing models, and discrepancies are observed, which could be attributed to the variation in foam generation technique, the nature and concentration of polymer, and the concentration of surfactant used in the experiments in which data was obtained to develop the models. Furthermore, annular pressure loss measurements obtained at low temperatures (24 and 79 degrees C) show predominantly good agreement with predictions of a hydraulic model that uses the new correlations. Discrepancies increased with temperature as the foam becomes unstable due to thermal thinning of the liquid film and subsequent weakening of bubble structure.",5,5,1
Drilling Fluid,Extended-reach Limit,"Li, Xin; Gao, Deli; Lu, Baoping; Zeng, Yijin; Zhang, Jincheng",Study on modified maximum extension length prediction model for horizontal wells considering differential sticking,Horizontal well; Maximum extension length; Differential sticking; Drilling fluid density; Casing running down/pulling out speed,EXTENDED-REACH LIMIT,"Maximum extension length prediction model for horizontal wells can be used to evaluate the horizontal well's extension capability and predict its maximum measured depth, which is of great significance to the production and economic benefits of horizontal wells. However, the differential sticking is not considered in previous prediction model. To overcome this shortcoming, a modified model considering differential sticking is established based on constraints of wellbore stability, differential pressure, and filtration loss simultaneously during the drilling, tripping processes and static state. Then a horizontal well is analyzed and its maximum extension length is predicted. Results show that within the conventional mud weight window, three ranges of drilling fluid density can be determined, including the first range, the second range and the reasonable range of drilling fluid density. However, only the reasonable range of drilling fluid density can satisfy all constraints of the modified prediction model, including the wellbore stability, differential pressure, and filtration loss simultaneously. Compared with the original model, the predicted well's maximum extension length decreases when the differential sticking is considered. However, it is more accurate, avoiding drilling hazards in actual drilling operation due to the excessive designed measured depth and unreasonable drilling parameters. Moreover, the maximum speeds of casing running down/pulling out are also determined and added to the modified model. Therefore, the modified model with reasonable drilling fluid density and adjusted running down/pulling out speed is the optimal modified model to predict maximum extension length and avoid differential sticking, which can also ensure that the horizontal well's designed measured depth can be successfully achieved. This study is of great significance to improve the prediction accuracy of horizontal well's maximum extension length and avoid drilling hazards, especially the differential sticking. Moreover, it also plays a guiding role in the selection of reasonable drilling fluid density during horizontal drilling.",3,4,3
Drilling Fluid,Extended-reach Limit,"Li, Xin; Gao, Deli",Study on mud weight window prediction model and safety additional value of horizontal well in shales considering effects of Well's extended-reach limit,Mud weight window; Safety additional value; Horizontal well; Extended-reach limit; Shale gas field,STABILITY,"Safety additional value is always added to the conventional mud weight window (MWW) to ensure the drilling safety in shales. However, the safety additional value is usually an empirical value. Since the horizontal well usually has a long horizontal section in shales, failing to accurately predict the wells MWW and corresponding safety additional value in shales may result in serious drilling hazards. In order to ensure that the horizontal well can reach the designed horizontal-section length in shales, the conventional MWW needs to be modified and the calculated value of safety additional value should also be given. In this paper, considering the effects of horizontal wells extended-reach limit and its horizontal-section limit (HSL) on the wells MWW in shales, the drilling process, tripping process and six constraint conditions are considered simultaneously. Results of the case study indicate that the corresponding safety additional value is calculated instead of using an empirical value. Moreover, the predicted MWW becomes narrower as the designed horizontal-section length is increased. In addition, in order to obtain a wider MWW, tripping velocity should be lower if the economic benefits can be satisfied. Additionally, the drilling pump with higher rated pressure is also necessary. Taking the maximum HSL as the objective function, there exists an optimal drilling fluid density, which is crucial for production in shales. The calculated value of safety additional value and the modified MWW can ensure the horizontal well reach the designed horizontal-section length, obtaining enough production and economic benefits as well as avoiding drilling hazards in shales.",5,6,1
Drilling Fluid,Fluid Seepage,"Hao, Shu-Qing",Development of portable drilling fluid and seepage simulation for deep saline aquifers,CO2 sequestration; Borehole stability; Low density (portable) drilling fluid; High-temperature resistant drilling fluid; Deep saline aquifers,RHEOLOGICAL PROPERTIES; STORAGE; CO2; PERFORMANCE,"The development of drilling fluids with low density for deep saline aquifers is in high demand. This study performed several tests to find the optimal formula of drilling fluid that would be suitable under circumstances with high temperatures and salt concentrations similar to deep saline aquifers. Drilling fluids with varying combinations sodium chloride (NaCl), polyacrylamide (PAM), sulfonated lignite (SMC), and sodium carboxymethyl cellulose (Na-CMC) in montmorillonite (Mt) water-based slurry were synthesized and tested. Salt-, SMC-, and temperature-sensitivity analysis was done to investigate effects of ionic strength and temperature on the performance of synthesized drilling fluids. Anti-caving ability tests were performed to check the drilling fluids influence on porosity of aquifer upon application. The results show that NaCl and PAM play a critical role in controlling viscosities and yield values. PAM and Na-CMC contribute to fluid loss characteristics, and PAM contributes to low density too. A deliberately chosen combination of NaCl PAM, SMC, and Na-CMC gives rise to a suitable formula of drilling fluid for temperatures up to 120 degrees C and salt concentrations up to 1.7 M. The simulation of drilling fluid seepage in the borehole based on the ANSYS-Fluent existing codes verifies the performance of the optimal formula and the results imply the effectiveness of the optimal formula on prohibiting the borehole instability. This will even encourage immediate field applications of the optimal formula.",4,5,2
Drilling Fluid,Fluid Seepage,"Li, Xiaorong; El Mohtar, Chadi S.; Gray, K. E.",3D poro-elasto-plastic modeling of breakouts in deviated wells,Wellbore breakouts; Mudcake; Deviated wells,BOREHOLE; STRESS; STABILITY; SEEPAGE; OIL,"Borehole breakouts are stress-induced enlargements of the wellbore cross-section. Predicting wellbore breakouts is important for the success of any drilling operation; however, accurate prediction of breakouts in deviated wells can be a technically challenging task. Misalignment between wellbore trajectory and field principal stress orientation along with the strong coupling between fluid flow, stresses and plasticity are some of the factors that makes breakouts in deviates well more challenging. This paper discusses a 3D poro-elasto-plastic numerical modeling approach for breakouts in deviated wells. Dynamic mudcake buildup on the wellbore wall is also incorporated into the numerical model, enabling quantitative analysis of the mudcake effect on the borehole breakout. The influences of well trajectory, fluid seepage between wellbore and formation pores, plastic strain softening of the rock, and dynamic mudcake buildup on the breakout are highlighted and analyzed using numerical examples. The results indicate that the breakout shape of deviated wells is largely dependent on well inclination while its volume can be reduced by mitigating fluid seepage through mudcake buildup. The proposed finite-element modeling approach in this study confirms the need to consider the coupling among these factors when predicting wellbore breakouts in complex geological and drilling conditions.",5,5,0
Drilling Fluid,Low Side,"Chen, Laoyin; Di, Qinfeng; Lou, Erbiao; Zhou, Bo; Zhang, He; Wang, Wenchang; Hu, Feifei",The visualization of rub-impact characteristics of drill string on casing,Rub-impact characteristics; 3D visualization method; Casing wear; Drill string; Finite element model,DYNAMIC-ANALYSIS,"Field experience revealed that a whirling drill string in the wellbore would make severe impact and rubbing against the casing and lead to uneven and random wear of casing. The casing wear due to vibrational impacts of the drill string was also one of the major causes for casing failure, but it was always ignored in the previous studies on casing wear. This work aimed at modelling and intuitively displaying the rub-impact characteristics of drill string and the induced wear on casing. Taking into consideration of the damping of drilling fluid, bit-rock interaction together with the geometric and contact nonlinearity, a drill string dynamic finite element model was established and then solved with the node iteration and the Newmark method. The whirl orbit, whirl velocity and collision characteristics of the drill string were then obtained. Based on these results, a three-dimensional visualization method was established to describe the dynamic features of drill string. The results indicate that the drill string presents a strong nonlinear dynamic behavior and makes frequent impacts against the wellbore, which appears mainly in the low side of borehole and is more serious in the hole section where BHA is located. The hole curvature and surface rotary speed have important influence on the casing wear induced by impact-rub action. A large hole curvature will lead to more serious rub-impact action of the drill pipe on the casing, and a rotary speed closer to the natural frequency of BHA will obviously increase the wear risk of casing.",2,3,3
Drilling Fluid,Low Side,"Wang, Dongying; Wang, Zhiming; Zeng, Quanshu",An experimental study on gas/liquid/solid three-phase flow in horizontal coalbed methane production wells,Gas/liquid/solid three-phase flow; Coalbed methane; Horizontal well; Flow pattern; Height of coal particle bed; Explicit equation,SAND-DEPOSITION VELOCITY; RESERVOIR ROCKS; LIQUID; GAS; PARTICLES; TRANSPORT,"Coal particles caused by well drilling and completion, hydraulic fracturing, and formation pressure decreasing would migrate into the horizontal well carried by fracturing flow-back fluid, formation water and CBM, and then deposit on the low side of pipe leading to the decrease of cross section area of pipe for flow and even blocking of the pipe. The purpose of current research was to obtain the flow pattern while there was stationary solid particle bed on the low side of the pipe and an explicit equation to predict the height of solid particle bed was proposed. In this study, with the coal particle, water, and air as the solid, liquid, and gas phases respectively, gas/liquid/ solid three-phase flow experiments in horizontal well were carried out and 4 crucial factors including different water flow rate, gas flow rate, coal particle size, and coal particle mass concentration were considered. Fluid's real apparent velocity was defined and used to analyze the distribution of flow pattern coordinate points. Results show that the flow pattern coordinate points determined by real gas apparent velocity and real water apparent velocity distribute near the flow pattern transition lines of Taitel and Dukler flow pattern map. Besides, coal particle size, water flow rate, and gas flow rate have obvious impact on the height of coal particle bed and the coal particle mass concentration has a negligible effect while the height of interface between gas layer and water layer is only dramatically affected by the gas flow rate. At last, an explicit equation for predicting the cross section area of coal particle bed based on the experimental data was proposed which is crucial to predict the flow pattern and calculate the pressure drop in horizontal well. The predicting cross section area of coal particle bed is in good agreement with the measured cross section area of coal particle bed and the average relative differences are 9.38% and 13.45% for stratified smooth flow and stratified wavy flow respectively. The equation is applicable for a range of coal particle size (8-30 mesh) and water apparent velocity (0.025-0.123 m/s).",2,2,4
Seismic Data,Properties,"Kim, Hyeonju; Lee, Gwang H.","A deterministic geomodeling case study for a thin clastic reservoir: The Second Wall Creek Sand, Teapot Dome field, Wyoming, USA",Teapot Dome field; Second Wall Creek Sand; Geomodeling; Neural network,CO2 SEQUESTRATION,"In this case study, we geomodeled the Upper Cretaceous Second Wall Creek Sand (SWCS) of the southern Teapot Dome field, Wyoming, USA, using public domain seismic and well-log data. The SWCS is an at-or-below seismic-resolution (about 20 m), fluvial-deltaic reservoir and has been the most productive in the field. The goemodeling procedure consisted of structural modeling of the depth 3-D grid (30 m x 30 m x 1 m cells) and petrophysical modeling for porosity and net-to-gross (N/G). The seismic data were enhanced by spectral balancing to resolve the SWCS. Facies modeling was not necessary because a facies analysis of gamma-ray logs and lithofacies and stratigraphic-discontinuity seismic attributes suggests a uniform facies. The porosity and N/G were modeled by neural network multi-attribute transform (NN-MAT). NN training included the absolute and relative impedances and three representative isofrequencies in addition to the conventional amplitude-and frequency-based attributes. The modeled porosity varies from less than 8% to over 18% with an average of 16.7% which agrees with the reported averages. The modeled N/G values range from about 0.2 to over 0.8 with an average of 0.7 which is greater than the reported average (0.5). The porosity and N/G models may not be optimal because only a few wells and a small number of the time samples for the thin reservoir interval were used in NN training. The geomodeling workflow presented in this study is optimized for thin reservoirs and can be used when facies modeling is difficult because NN-MAT computes petrophysical properties without being guided by facies models.",0,0,3
Seismic Data,Properties,"Pecanha, Alessandra Alves; Lupinacci, Wagner Moreira; Ariza Ferreira, Danilo Jotta; Menezes Freire, Antonio Fernando","A workflow for reservoir characterization applied to presalt coquinas from the Linguado Field, Campos Basin, Brazil",Reservoir characterization; Presalt; Geobody; Porosity modeling; Acoustic inversion; Coquinas,,"Characterization of presalt coquinas reservoirs is a know challenging task due to its facies and, consequently, petrophysical properties heterogeneity and anisotropy. This fact makes the traditional seismic interpretation and well log analysis workflow not enough for the interpreter to address reasonably the reservoir complexity. In this study, a methodology integrating different geological and geophysical interpretation techniques based on data pre-conditioning, model-based seismic acoustic inversion, effective porosity geostatistical modeling using sequential gaussian simulation with collocated co-kriging and geobody interpretation is proposed to obtain maximum information from the available data which consists on post-stack seismic and well logs from the lacustrine coquinas carbonate reservoirs from the Coqueiros Formation located in the Linguado Field on Campos Basin. Acoustic seismic inversion results allowed the interpretation of four new seismic horizons that could individualize two coquinas intervals and effective porosity modeling results allowed the geobody extraction of the coquinas banks that represent the best reservoir facies within the study area with effective porosities between 13 and 30% making it even possible to identify new exploratory areas. Therefore, the proposed workflow is very reliable for coquinas reservoirs characterization and can be applied in other areas.",2,2,2
Seismic Data,Properties,"Wang, Zizhen; Schmitt, Douglas R.; Zhou, Weidong; Wang, Ruihe; Zang, Yanbin; Zeng, Yijin","The stress dependence of velocities and its influencing factors for carbonate rocks in Arab formation, Saudi Arabia",Stress dependence; Static and dynamic modulus; Velocity; Pore structure; Carbonate rocks,SONIC VELOCITY; CLAY CONTENT; ACOUSTIC PROPERTIES; EFFECTIVE PRESSURE; WAVE VELOCITIES; ELASTIC-MODULI; PORE PRESSURE; SEISMIC DATA; POROSITY; ANISOTROPY,"The stress dependence of velocities (SDoV) is important for a variety of geophysical applications, such as pore pressure prediction and 4D seismic monitoring. This study provides a new data base for carbonate rocks. Thirty-seven carbonate samples from the Arab formation with a wide variation of texture, pore type, porosity and permeability were investigated with respect to their SDoV. Different methods, such as SEM, thin section images, and mercury intrusion, are applied to describe the internal structures of the samples. The ultrasonic velocities and the quasi-static strains are measured simultaneously at vacuum dry and hydrostatic conditions with the effective stress varying from 5 MPa to 25 MPa. Based on these measurements, the SDoV of carbonate rocks is analyzed, and the static and dynamic bulk moduli are compared. The results show that the linear Vp-Vs relation is insensitive to the stress change. The variation of Vp/Vs with effective stress deviates from the general trend observed in sandstones, and independent to their porosity. Samples dominated with micro pores (diameter smaller than 10 mu m) have weak SDoV, and samples behaving stronger SDoV are mostly with high porosity and high permeability. More data is required to confirm the role of texture on the SDoV for carbonate rocks. The classical empirical model with a combination of linear dependency and exponential decay is tested to be effective for carbonates by the least-squares fitting. The static to dynamic modulus ratio ranges from 0.3 to 1.0 with significant scatterings. The static bulk modulus becomes more sensitive to the stress change than the dynamic modulus as the effective stress increases.",2,2,4
Seismic Data,Properties,"Choi, Junhwan; Yoon, Daeung; Lee, Sigue; Byun, Joongmoo",Petrofacies characterization using best combination of multiple elastic properties,Petrofacies characterization; Class-Scatter-Matrix (CSM); Multivariate probability density function (PDF); Bayesian inference,,"Elastic properties such as P-impedance and the ratio of P-to S-wave velocity are key features for linking well log data to seismic data for reservoir characterization. Crossplotting methods from well log data are commonly applied to delineate the distribution of petrofacies on the seismic volume. However, only two or three elastic properties (two-or three-dimensional data) can be used in the crossplotting methods because of data visualization issues. Furthermore, the elastic properties used in the crossplotting method have to be chosen subjectively or empirically by a human interpreter. In this study, we propose a new workflow to overcome the limitations of conventional crossplotting methods. We use more than three elastic properties from well log data and apply non-linear transformations to the properties, to improve separability of the non-linear datasets. Then, we choose the best combination of the non-linear transformed elastic properties using class-scatter-matrix based separability measure. Lastly, Bayesian inference with multivariate probability density function (PDF) of petrofacies is performed to predict petrofacies probability volumes in the seismic area. An application to Vincent oil field data demonstrates the effectiveness of the proposed workflow. The accuracy improved from 80.7% to 86.2% and uncertainty is significantly reduced compared to the conventional workflow with crossplotting methods.",3,3,0
Seismic Data,Properties,"Teixeira, Leonardo; Lupinacci, Wagner M.",Elastic properties of rock salt in the Santos Basin: Relations and spatial predictions,Rock salt; Evaporites; Santos basin; Elastic properties; Seismic inversion; Rock physics,WAVE VELOCITIES; TECTONICS; DEFORMATION; EVAPORITES; GEOLOGY; MODULI,"Most subsurface rock models consider salt bodies as homogenous masses and set to evaporite minerals constant values of elastic properties such as density, compressional and shear velocities, Young's modulus and Poisson's ratio. Lithological analyzes of outcrops and wells indicate that evaporites present large vertical and lateral heterogeneities. Recent studies have demonstrated that the knowledge of the elastic properties of rock salt can substantially benefit velocity modeling, seismic imaging, reservoir geomechanical analysis, prediction of well-bore stability and calculation of optimum fluid weight. However, few papers document the spatial estimation of elastic properties for salt formations. We propose an approach to characterize the internal structures of the salt bodies in the Santos Basin, offshore Brazil, using well and 3D seismic data. It starts with a rock-physics analysis at well-log scale, which reveals that the elastic properties of rock salt are highly correlated. Once the relationships of the elastic properties are established, we explore the functionality of the empirical equations as property predictors. We demonstrate that the elastic properties can be empirically estimated from compressional velocity. The comparison between the estimated and the measured well logs validates the estimation. Then, we perform the seismic inversion to generate the spatial distribution of the acoustic impedance. We derive compressional and shear velocities, density, Young's modulus and Poisson's ratio volumes by applying the empirical equations to the acoustic impedance volume. The blind well points out that, through this workflow, the seismic data can successfully predict the elastic properties of the salt formation in undrilled portions.",5,5,0
Seismic Data,Properties,"Ali, Aamir; Younas, Muhammad; Ullah, Matee; Hussain, Matloob; Toqeer, Muhammad; Bhatti, Asher Samuel; Khan, Azhar",Characterization of secondary reservoir potential via seismic inversion and attribute analysis: A case study,Seismic attributes; Post stack colored inversion; Gas saturation; Petrophysics and rock physics; Cross-plots,POST-STACK INVERSION; PAKISTAN; LOG,"Seismic reservoir characterization is a renowned technique to obtain a better understandingand quantification of hydrocarbon bearing reservoirs by integration of seismic attributes, post stack inversion and wireline log analysis. In current case study, a methodology based on these techniques is proposed, and its applicability is tested for delineating the secondary reservoir potential of the Eocene carbonates (Habib Rahi and Sui Upper Limestone) in Qadirpur area, Lower Indus Basin, Pakistan. The application of post stack inversion provides a reasonable estimate of the acoustic impedance and enables the spatial distribution of important petrophysical properties (effective porosity and water saturation) available at sparse well locations. This distribution is facilitated by developing geostatistical relations between seismic and well derived reservoir properties in the range of seismic resolution. The results from all integrated techniques depict fluid saturated zones at Habib Rahi (gas at 907-922 m; water at 953-973 m) and Sui Upper Limestone (gas at 1192-1208 m) levels. The spatial distribution of the reservoir properties (effective porosity and water saturation) obtained via seismic data shows a very good calibration at the location of wells and reflects significant secondary reservoir potential for Eocene carbonates in the study area (effective porosity in the range of 7-26% and water saturation in the range of 35-60%). Furthermore, the methodology tested over here will be advantageous for the characterization of oil/gas reservoirs in various basins of Asia and other parts of world with similar geological settings.",5,5,0
Seismic Data,Fault,"Rjiba, Amira; Aifa, Tahar; Gabtni, Hakim; Ghanmi, Mohamed; Boulares, Achref","Neogene-Quaternary structuring of the Kalaa Khesba Graben, northwestern Tunisia: A push-up inversion structure",Strike-slip; Pull-apart; Lithostratigraphy; Seismic reflection; Gravity,TECTONIC EVOLUTION; POTENTIAL-FIELD; NORTHERN; EXAMPLE; BODIES; REGION; BASIN; ATLAS; FAULT; DEFORMATIONS,"Interpretation of lithostratigraphic, seismic and gravity data from Kalaa Khesba Graben shows (i) lateral and in-depth variation of the lithostratigraphic series, (ii) complex structuring of faulting. Reverse faults affected Paleocene to Quaternary horizons with a duplication of Eocene-Paleocene series occurred at subsurface evidenced within well W6. Isochron, isovelocity and isobath maps, combined with gravity data, show subsurface structures oriented predominantly NW-SE to NS and NE-SW to EW. Faults and horizons on the seismic lines, superimposed to gravity lineaments, reveal negative anomalies occurring at shallow depth. Such features may reflect the existence of low density Neogene-Quaternary series, strike-slips and thrust faults within Kalaa Khesba Graben. Depths deduced from Euler deconvolution solutions vary from 0.5 to 4 km. At subsurface, well log data located in the center of the graben, ensured the presence of Triassic bodies. A model of initiation of Kalaa Khesba Graben through a N160 degrees sigma(1) transpression is proposed.",1,1,0
Seismic Data,Fault,"Li, Xiaopeng; Wang, Hua; Gan, Huajun; Chen, Si; Zhang, Hongwei; Peng, Yuhui","Stratigraphic charactertistic and tectonic control on the paleogene sedimentary evolution of the Baxian Half-graben, Bohai Bay Basin, east China",Baxian sag; Stratigraphic architecture; Facies associations; Depositional evolution,SEQUENCE STRATIGRAPHY; SONGLIAO BASIN; RIVER DELTA; SYN-RIFT; DEPOSITIONAL SEQUENCES; SEISMIC SEDIMENTOLOGY; SHAHEJIE FORMATION; BRAIDED DELTA; PEARL RIVER; ARCHITECTURE,"The depositional and structural development of a deltaic dominated succession, interpreted from seismic data, cores, well curves and lab data, is discussed. The case is from a comprehensive analysis of stratigraphy and the depositional process of a deltaic to continental succession in the early to late Paleogene in the Baxian Half-graben, Bohai Bay Basin, East China. The evolution of three genetic successions with a total thickness of 1000-7000 m, comprising three facies associations, including fan delta, braided-river to shallow water delta and lacustrine deposit, records: a, initial rift stage, b, late rift stage, and c, post-rift stage. (1) The initial rift stage is made up of several fining-upward successions, mainly stacked in retrogradation style that pass from the fan delta plain, through the fan delta front to pro-delta in a deep lacustrine environment. This stage is characterized by high intensity rifting and the deposition was keeping up with subsidence. (2) The late rift stage is made up of several successions stacked in both progradation and retrogradation styles. The succession is defined by braided-river deltas, distributary channels, subaqueous channels, swamp, levees, and fluvial-dominated mouth bar, which are mainly identified using core data. This stage is characterized by a decrease in the intensity of rifting and finer-grained deposits. (3) The post-rift stage is made up of several successions stacked mainly in an aggradation style. Shallow water delta developed in the early phase, and lacustrine deposits developed in the late phase. The transition from initial-rift to late-rift phase is represented by a seismically identifiable regional angular unconformity and an overall upward decrease in the quantity of syn-depositional faults. The late-rift to post-rift evolution is represented by an overall decrease in grain size, decrease in fluvial influence and increase in wave influence. The research process can be a reference for the study of stratigraphic architecture and sedimentary process in other lacustrine basins where tectonic movements are well developed. The achievements of this article can be an important basis for the further exploration in the half-graben.",1,1,2
Seismic Data,Fault,"Huang, Guojiao; Ba, Jing; Du, Qizhen; Carcione, Jose M.",Simultaneous inversion for velocity model and microseismic sources in layered anisotropic media,Microseismic location; Simultaneous inversion; Layered anisotropic media; Seismic tomography,TRAVEL-TIME INVERSION; VALLEY GAS-FIELD; SEISMIC TOMOGRAPHY; LOCAL EARTHQUAKES; CRUSTAL STRUCTURE; ARRIVAL TIMES; P-WAVE; LOCATION; FAULT; ZONE,"Microseismic monitoring is widely applied in fracturing operations, reservoir delineation and water front monitoring. Microseismic inversion generally uses an initial velocity model based on well logs and seismic data from perforation shots. This model is generally not suitable to locate microseismic sources. To reduce errors, we have developed a method that simultaneously updates the velocity model and locates events in space and time. 1-D layered anisotropy with a transversely-isotropic (TI) symmetry is assumed, where the symmetry axis can be arbitrarily oriented. The arrival times and ray paths of the qP, qSV and qSH waves are calculated with a modified multistage shortest path algorithm. Combined with the conjugate gradient method, a damped, minimum-norm, least-squares and constrained problem is solved. The numerical examples show that the proposed algorithm can be used to invert the anisotropic velocity model (elastic moduli and interface depth for each layer) and locate the microseismic sources and their onset times, simultaneously. It is shown that the algorithm is not very sensitive to random noise, which may be contained in arrival times and model anisotropy heterogeneities.",2,2,7
Seismic Data,Fault,"Li, Yongqiang; Sun, Jianfang; Wei, Hehua; Song, Suihong",Architectural features of fault-controlled karst reservoirs in the Tahe oilfield,Karst outcrops; Tahe oilfield; Fault-controlled karst; Architectural features; Production significance,CARBONATE RESERVOIR; TARIM BASIN; PALEOKARST; SYSTEM; ROCKS,"Based on the analysis of the characteristics of modern karst and paleokarst outcrops, this study summarizes the features of subsurface reservoirs by using core, logging, seismic and production data, establishes the structural model of fault-controlled karst reservoirs, and points out the guiding significance of this structural model for development and production in the Tahe oilfield. Modern karst in southern China shows the three-component structural characteristics of fault-controlled karst which are fault core, damage zone, and host rock. The cavern is developed in the fault core and the fracture-vugs are fully developed. Paleokarst outcrops reveal the evolutionary process of fault-controlled karst reservoirs, the characteristics of caverns along the fault and the surrounding fracture-vuggy features. Seismic structure tensor attributes, ant-track attributes and amplitude spectrum gradient attributes are used to describe the external geometry, caverns, and large-scale fractures of fault-controlled karst reservoirs, and the small fractures and vugs can be described by using cores. According to the characteristics of modern karst, paleokarst and subsurface reservoirs, three architectural patterns of fault-controlled cavern complexes, fault-controlled caverns and fault-controlled vugs are summarized. Different architectural patterns of karst reservoirs lead to different production capacities. The architectural patterns have important guiding significance for new drilling and water or gas injection to improve oil recovery.",5,6,3
Seismic Data,Obtaining,"Pecanha, Alessandra Alves; Lupinacci, Wagner Moreira; Ariza Ferreira, Danilo Jotta; Menezes Freire, Antonio Fernando","A workflow for reservoir characterization applied to presalt coquinas from the Linguado Field, Campos Basin, Brazil",Reservoir characterization; Presalt; Geobody; Porosity modeling; Acoustic inversion; Coquinas,,"Characterization of presalt coquinas reservoirs is a know challenging task due to its facies and, consequently, petrophysical properties heterogeneity and anisotropy. This fact makes the traditional seismic interpretation and well log analysis workflow not enough for the interpreter to address reasonably the reservoir complexity. In this study, a methodology integrating different geological and geophysical interpretation techniques based on data pre-conditioning, model-based seismic acoustic inversion, effective porosity geostatistical modeling using sequential gaussian simulation with collocated co-kriging and geobody interpretation is proposed to obtain maximum information from the available data which consists on post-stack seismic and well logs from the lacustrine coquinas carbonate reservoirs from the Coqueiros Formation located in the Linguado Field on Campos Basin. Acoustic seismic inversion results allowed the interpretation of four new seismic horizons that could individualize two coquinas intervals and effective porosity modeling results allowed the geobody extraction of the coquinas banks that represent the best reservoir facies within the study area with effective porosities between 13 and 30% making it even possible to identify new exploratory areas. Therefore, the proposed workflow is very reliable for coquinas reservoirs characterization and can be applied in other areas.",2,2,2
Seismic Data,Obtaining,"Sun, Hong-Mei; Jia, Rui-Sheng; Zhang, Xing-Li; Peng, Yan-Jun; Lu, Xin-Ming",Reconstruction of missing seismic traces based on sparse dictionary learning and the optimization of measurement matrices,Seismic data reconstruction; Compressed sensing; Sparse representation; K-singular value decomposition; Measurement matrix optimization,ROBUST UNCERTAINTY PRINCIPLES; K-SVD; CURVELET-TRANSFORM; INTERPOLATION; ALGORITHM; RECOVERY; SETS; REPRESENTATIONS; PROJECTION,"Due to limitations arising under complicated geological conditions and field collection environments, we often cannot collect complete and regular field seismic data. To solve that problem, the reconstruction of seismic data has been widely studied. In this paper, we propose a reconstruction algorithm for seismic data with missing traces based on sparse dictionary learning and measurement matrix optimization. The algorithm views the seismic data as a matrix. It first uses the neighboring channel to fill in the missing trace and then uses the transposed matrix and applies the K-singular value decomposition (K-SVD) algorithm by columns to train the sample, obtaining an over-complete dictionary that can be used to develop an optimal sparse representation of seismic data. In the process of seismic data reconstruction, we first transpose the seismic data with missing traces, adopt the regularized orthogonal matching pursuit (ROMP) algorithm to obtain optimum estimations of the data in each column and then transpose the matrix to obtain the reconstructed seismic data. To further increase the quality of seismic data reconstructions, the algorithm presented in this paper also introduces the Equiangular Tight Frame (ETF) method to optimize the measurement matrix. The experiments indicate that this paper's algorithm can achieve high-quality reconstructions of seismic data.",2,2,5
Seismic Data,Obtaining,"Zhao, Jing; Ren, Jinchang; Gao, Jinghuai; Tschannerl, Julius; Murray, Paul; Wang, Daxing",Automatic events extraction in pre-stack seismic data based on edge detection in slant-stacked peak amplitude profiles,Automatic event extraction; Pre-stack reflection data; ray tracing; Radon transformation,PICKING; FREQUENCY,"Events picking is one of the fundamental tasks in interpreting seismic data. To extract the correct travel-time of reflected waves, picking events in a wide range of source-receiver offsets is needed. Compared to post-stack seismic data, pre-stack seismic data has an accurate horizon and abundant travel-time, amplitude, and frequency while the waveform of post-stack data is damaged by normal move-out (NMO) applications. In this paper, we focus on automatic event extraction from pre-stack reflection seismic data. With the deep development of oil-gas exploration, the difficulty of petroleum exploration is being increased. Auto recognition and picking of seismic horizon is presented as the basis for oil-gas detection. There is a correspondence between the real geology horizon and events of seismic profiles. As a result, firstly, recognizing and tracing continuous events from real seismic records are needed to acquire significant horizon locations. Picking events is in this context the recognition and tracing of waves reflected from the same interfaces according to kinematics and dynamic characteristics of seismic waves. Current extraction algorithms are well able to trace these events of the seismic profile and are undergoing great development and utilization. In this paper, a method is proposed to pick travel-time and local continuous events based on edges obtained by slant-stacked peak amplitude section (SSPA). How to calculate the SSPA section is discussed in detail. The new method can improve the efficiency and accuracy without windowing and manual picking of seed points. The event curves obtained from both the synthetic layered model and field record have validated the high accuracy and efficiency of the proposed methodology.",4,4,1
Seismic Data,Obtaining,"Ali, Aamir; Younas, Muhammad; Ullah, Matee; Hussain, Matloob; Toqeer, Muhammad; Bhatti, Asher Samuel; Khan, Azhar",Characterization of secondary reservoir potential via seismic inversion and attribute analysis: A case study,Seismic attributes; Post stack colored inversion; Gas saturation; Petrophysics and rock physics; Cross-plots,POST-STACK INVERSION; PAKISTAN; LOG,"Seismic reservoir characterization is a renowned technique to obtain a better understandingand quantification of hydrocarbon bearing reservoirs by integration of seismic attributes, post stack inversion and wireline log analysis. In current case study, a methodology based on these techniques is proposed, and its applicability is tested for delineating the secondary reservoir potential of the Eocene carbonates (Habib Rahi and Sui Upper Limestone) in Qadirpur area, Lower Indus Basin, Pakistan. The application of post stack inversion provides a reasonable estimate of the acoustic impedance and enables the spatial distribution of important petrophysical properties (effective porosity and water saturation) available at sparse well locations. This distribution is facilitated by developing geostatistical relations between seismic and well derived reservoir properties in the range of seismic resolution. The results from all integrated techniques depict fluid saturated zones at Habib Rahi (gas at 907-922 m; water at 953-973 m) and Sui Upper Limestone (gas at 1192-1208 m) levels. The spatial distribution of the reservoir properties (effective porosity and water saturation) obtained via seismic data shows a very good calibration at the location of wells and reflects significant secondary reservoir potential for Eocene carbonates in the study area (effective porosity in the range of 7-26% and water saturation in the range of 35-60%). Furthermore, the methodology tested over here will be advantageous for the characterization of oil/gas reservoirs in various basins of Asia and other parts of world with similar geological settings.",5,5,0
Seismic Data,Fluid Flow,"Jiang, Shuaishuai; Chen, Xuehua; Qi, Yingkai; Jiang, Wei; Zhang, Jie; He, Zhenhua",Seismic numerical analysis for partially gas-saturated porous rocks by an extended local Rytov Fourier approximation based on the diffusion-viscous theory,Rytov approximation; Diffusive and viscous wave equation; Attenuation; Dispersion; Gas-saturated reservoir,ELASTIC-WAVES; MIGRATION; SIMULATION,"The frequency-dependent attenuation and velocity dispersion of seismic responses are closely related to hydrocarbon reservoirs. To further investigate the characteristics of seismic responses caused by pore fluid-bearing reservoirs, the role of gas saturation is analyzed in seismic responses of sand reservoirs characterized by the patchy saturation model. To this end, a novel wave extrapolation method is developed based on the diffusive-viscous wave equation (DVWE) as well as a scheme for an extended local Rytov Fourier (ELRF) approximation within the extrapolation depth interval. Our proposed method considers the presence of fluid mixtures in the porous media, resulting in seismic attenuation and dispersion by the mechanism generally known as wave-induced fluid flow (WIFF). This method enables an accommodation for the lateral variations in slowness, diffusion coefficient and viscosity. Subsequently, the extrapolation is adopted to model the synthetic seismic data of a distributary channel model. During this modeling, a gas-water saturated sand reservoir embedded into one of the channels was used to comparatively analyze the distinct features on its seismic synthetic data. We exhibited the numerical simulation results using the proposed wave extrapolation method here and the traditional acoustic wave equation (AWE) method. A comparison of the simulation results, demonstrates that our proposed numerical method can depict the seismic dispersion and frequency-dependent attenuation as well as the phase delay effects associated with gas-water-saturated sand reservoirs. Furthermore, we compare the seismic responses by changing the gas saturations of the sand reservoir. The gas saturation of the reservoir has significant effects on the seismic characteristics of the numerical modeling data. The numerical modeling method improves our understanding of the mechanisms of seismic frequency-dependent characteristics associated with gas saturations and potentially contributes to better insights into gas reservoir indicators derived from seismic field data.",1,1,5
Seismic Data,Fluid Flow,"Li, Yi-Long; Wu, Feng; Li, Xiao-Ping; Tan, Xiao-Hua",Experimental study on waterflood development in large-scale karst structures,Karst structure; Waterflood experiment; Large-scale three-dimensional physical model; Two-phase flow of oil/water,FLUID-FLOW; PERMEABILITY; SIMULATION,"On the basis of the seismic data volume of a certain well group unit of the Tahe fracture-vuggy reservoirs, the similarity theory is adopted, and a numerical model with geometric, kinematic, dynamic, and fracture-cavity characteristic parameter similarities is designed. Moreover, a large-scale three-dimensional physical karst cave model is built with the carving technology. The model is used in the experimental study of two-phase flow of oil/ water during waterflood development and in the analysis of relevant influencing factors. Results show that the displacement efficiency of low-high mode is obviously superior to the case of high-low mode. A high crude oil viscosity is found to equate to a low ultimate recovery. High-velocity water flooding improves ultimate recovery but results earlier water breakthrough. Well shutdown improves recovery factor and well shutdown during middle water cut stage achieves optimum effects. Bottom water energy benefits oil reservoir exploitation to some degree.",3,3,2
Seismic Data,Fluid Flow,"Ishibashi, Takuya; Watanabe, Noriaki; Tamagawa, Tetsuya; Tsuchiya, Noriyoshi",Three-dimensional channeling flow within subsurface rock fracture networks suggested via fluid flow analysis in the yufutsu fractured oil/gas reservoir,Discrete fracture network (DFN); 3-D channeling flow; Aperture distribution; Critically-stressed fracture; 3-D seismic data; The yufutsu oil/gas field,PERMEABILITY; APERTURE; JOINTS; MEDIA,"The present study explores the fluid flows within the fractured reservoir of the Yufutsu field (Hokkaido, Japan) by using the innovative discrete fracture network models (DFN-HA model), where the critically-stressed fractures are characterized by their heterogeneous aperture distributions depending on their length and shear displacement. Simulation results suggest that the three-dimensional preferential flow paths are originally formed within the fractured reservoir (i.e., 3-D channeling flow), that is exclusively influenced by both connectivity of critically-stressed fractures and pore space connectivity within them. Additionally, the huge difference in oil/gas production between two neighboring wells (approximately 3 orders of magnitude), that is observed in the Yufutsu field, can be reproduced only by the DFN-HA models. The present study suggests that 3-D channeling flow is necessary to be considered carefully in region where the connectivity of critically-stressed fractures is extremely limited. Although it is convenient to model the fractures by pairs of parallel plates with representative aperture values in analyzing fluid flow within fracture networks, such analyses potentially lead to the wrong scenarios for developing the fractured reservoirs because 3-D channeling flow within the reservoirs is never considered (e.g., potentially overestimate the volume containing flowing fluid by more than 25%). Thus, the present study concludes that the fluid flow within fractured reservoirs should be analyzed by DFN-HA model. By continuing such approaches, we will be close to the true images and the new insights into the fluid migration within the fractured systems in Earth's upper crust.",4,4,3
Seismic Data,Hydrocarbon Accumulation,"Yang, Xiao-Fa; Ma, Zhong-Zhen; Zhou, Yu-Bin; Zhang, Zhi-Wei; Liu, Ya-Ming; Wang, Dan-Dan; Zhao, Yong-Bin","Reservoir characteristics and hydrocarbon accumulation of the glauconitic sandstone in the Tarapoa Block, Oriente Basin, Ecuador",Glauconitic sandstone; Reservoir characteristics; Hydrocarbon accumulation; Oriente basin; Ecuador,NAPO FORMATIONS; HOLLIN; ORIGIN; FIELD; OIL,"Although Oriente basin has explored throughout the past fifty years, little is known about the reservoir quality and hydrocarbon accumulation of the Cretaceous Upper T glauconitic sandstones. Until recently, the Upper T has drawn attention due to the commercial oil discovery. Howerer, exploration of glauconitic sandstones is complicated and reservoir quality is difficult to evaluate based on logging and seismic data. The glauconitic sandstones developed in open marine environments, characterized by a framework of glauconite and quartz grains. Diagenesis includes compation, silica overgrowth, feldspars dissolution, iron carbonate cementation. Its porosity ranges 5-20% and less than 500 md permeability. The dominant pore type is intergranular, especially residual intergranular. Glauconitic sandstones have bimodal pore throat size distributions and complex pore geometries. The Upper T glauconitic sandstones are capped by a thin veneer of fossiliferous limestones and laminated to burrowed shales. These large-area matured source rocks close to the glauconitic sandstones are probably the source kitchen in the slope of Oriente Basin. The oil pools are very little relation to structure. A large area of continuous developed glauconitic sandstone reservoirs and adjacent source rocks form an excellent source-reservoir-cap assemblage. Differ from previous views of long-distance migration from the southwest Oriente Basin, we propose that volume flow and diffusive flow are the primary migration and accumulation mechanism for the Upper T reservoir in Tarapoa Block.",0,0,1
Seismic Data,Hydrocarbon Accumulation,Zhu Xiaomin; Liu Qianghu; Ge Jiawang; Dong Yanlei; Zhu Shifa; Tan Mingxuan; Yang Yong,"Reconstruction of sediment-dispersal patterns using seismic sedimentology in the southeastern Zhanhua Sag, Bohai Bay Basin, China",Seismic sedimentology; Sediment-dispersal pattern; Paleogeography; Third member of shahejie formation; Zhanhua sag; Bohai bay basin,MESH PETROLEUM PLAYS; SHALLOW-WATER DELTA; HYDROCARBON ACCUMULATION; SEQUENCE STRATIGRAPHY; FAN-DELTA; DEPRESSION; GEOMORPHOLOGY; EXAMPLE; PALEOGENE; SYSTEM,"Reconstruction of sediment-dispersal patterns not only provides insight into paleogeographic evolution, but also sheds light on facies and reservoir prediction. By integrating core, wireline logs, and 3D seismic data, seismic sedimentologists have discovered several advantages to sediment-dispersal reconstruction and paleogeographic-environment analysis. We have subdivided the third member of the Shahejie Formation (Es3) of the southeastern Zhanhua Sag (Sanhecun Block) into three third-order sequences, namely SQ1, SQ2, and SQ3 from bottom to top. The facies architecture was analyzed by using the seismic sedimentology approach based on 3-D seismic data. Seismic RMS-amplitude stratal slices reveal different characteristics of the lobes among the southwest gentle slope, southern slope-break belt and north fault-controlled slope from source to sink. On the basis of an integrated analysis of well log, core data, seismic facies based on RMS attributes, three depositional environments (e.g., ""fan-delta"", ""turbidite"" and ""lacustrine"" facies) have been recognized. Seismic RMS-amplitude stratal slices indicate that the depositional environments of these sequences evolved from medium-sized gravel-rich fan-delta and turbidite-fan deposits to small-scale mud-rich fan-delta deposits, and lastly to large-scale sand-rich fan-delta deposits. The changes of relative lake level and sediment supply rate control the lithology and size of different depositional systems. This study also suggests that the temporal and spatial evolution and distribution of depositional systems are influenced significantly by paleotopography and slope break in the systems tracts of different sequences of the Es3 in the southeast Zhanhua Sag, Bohai Bay Basin. In addition, fan-delta-front deposits could also be considered as future potential exploration targets because they are relatively sand-or gravel-rich, given the reconstruction of the sediment-dispersal pattern.",2,2,2
Seismic Data,Hydrocarbon Accumulation,"Gao, Huahua; Tong, Xiaoguang; Wen, Zhixin; Wang, Zhaoming",The tectonic evolution of the eastern Mediterranean basin and its control on hydrocarbon distribution,Eastern Mediterranean basin; Prototype basin; Basin evolution; Hydrocarbon accumulation and distribution; Favorable plays,MESSINIAN SALINITY CRISIS; DEEP-SEA FAN; ERATOSTHENES SEAMOUNT; LEVANT BASIN; CRUSTAL THICKNESS; NEOGENE EVOLUTION; SALT TECTONICS; CYPRUS ARC; REGION; COLLISION,"Recent discoveries of giant, deep-water gas fields in the Eastern Mediterranean Basin (EMB) have revealed abundant hydrocarbon resources and significant exploration potential in turbidite and reef reservoirs (e.g., in the Tamar and Levantine fields, and the Zohr and Calypso fields, respectively). However, further exploration is currently constrained by the lack of detailed knowledge on the development of the basin. This paper presents a systematic model of the tectonic evolution of the EMB based on an analysis of new 2D seismic data and relevant published literature, assesses the main petroleum systems operating in the basin, and identifies prospective zones for future exploration. The modeling of a sequence of 12 prototype basins, restored from the seismic data, enable the tectonic evolution of the EMB to be divided into three stages: a rift stage, a 'drift' stage (including post-rift thermal subsidence), and a 'convergence and transformation' stage. This latest stage can be divided into four chronologically and geographically distinct sub-stages. The structural and stratigraphic architecture of the EMB, and hence the hydrocarbon distribution in the basin, evolved during the rifting of continental fragments from Gondwana (e.g., the Tauride-Anatolian plate, and the Kyrenia, Troodos, and Eratosthenes micro-plates), followed by their northward drift and collision with Eurasia. Six hydrocarbon plays are identified in this paper, two of which are previously unrecognized: the Mesozoic intra-platform reef play in the Eratosthenes Seamount, and the Mesozoic and Miocene 'double-stacked' platform-margin reef play in the 'high-low structure belt' south of the Eratosthenes Seamount. These two high-quality reef plays, together with stratigraphic and fault-block traps in the northern Levant Basin, are identified as the most prospective hydrocarbon exploration targets in the EMB.",3,5,1
Seismic Data,Deposition,"Li, Xiaopeng; Wang, Hua; Gan, Huajun; Chen, Si; Zhang, Hongwei; Peng, Yuhui","Stratigraphic charactertistic and tectonic control on the paleogene sedimentary evolution of the Baxian Half-graben, Bohai Bay Basin, east China",Baxian sag; Stratigraphic architecture; Facies associations; Depositional evolution,SEQUENCE STRATIGRAPHY; SONGLIAO BASIN; RIVER DELTA; SYN-RIFT; DEPOSITIONAL SEQUENCES; SEISMIC SEDIMENTOLOGY; SHAHEJIE FORMATION; BRAIDED DELTA; PEARL RIVER; ARCHITECTURE,"The depositional and structural development of a deltaic dominated succession, interpreted from seismic data, cores, well curves and lab data, is discussed. The case is from a comprehensive analysis of stratigraphy and the depositional process of a deltaic to continental succession in the early to late Paleogene in the Baxian Half-graben, Bohai Bay Basin, East China. The evolution of three genetic successions with a total thickness of 1000-7000 m, comprising three facies associations, including fan delta, braided-river to shallow water delta and lacustrine deposit, records: a, initial rift stage, b, late rift stage, and c, post-rift stage. (1) The initial rift stage is made up of several fining-upward successions, mainly stacked in retrogradation style that pass from the fan delta plain, through the fan delta front to pro-delta in a deep lacustrine environment. This stage is characterized by high intensity rifting and the deposition was keeping up with subsidence. (2) The late rift stage is made up of several successions stacked in both progradation and retrogradation styles. The succession is defined by braided-river deltas, distributary channels, subaqueous channels, swamp, levees, and fluvial-dominated mouth bar, which are mainly identified using core data. This stage is characterized by a decrease in the intensity of rifting and finer-grained deposits. (3) The post-rift stage is made up of several successions stacked mainly in an aggradation style. Shallow water delta developed in the early phase, and lacustrine deposits developed in the late phase. The transition from initial-rift to late-rift phase is represented by a seismically identifiable regional angular unconformity and an overall upward decrease in the quantity of syn-depositional faults. The late-rift to post-rift evolution is represented by an overall decrease in grain size, decrease in fluvial influence and increase in wave influence. The research process can be a reference for the study of stratigraphic architecture and sedimentary process in other lacustrine basins where tectonic movements are well developed. The achievements of this article can be an important basis for the further exploration in the half-graben.",1,1,2
Seismic Data,Deposition,Zhu Xiaomin; Liu Qianghu; Ge Jiawang; Dong Yanlei; Zhu Shifa; Tan Mingxuan; Yang Yong,"Reconstruction of sediment-dispersal patterns using seismic sedimentology in the southeastern Zhanhua Sag, Bohai Bay Basin, China",Seismic sedimentology; Sediment-dispersal pattern; Paleogeography; Third member of shahejie formation; Zhanhua sag; Bohai bay basin,MESH PETROLEUM PLAYS; SHALLOW-WATER DELTA; HYDROCARBON ACCUMULATION; SEQUENCE STRATIGRAPHY; FAN-DELTA; DEPRESSION; GEOMORPHOLOGY; EXAMPLE; PALEOGENE; SYSTEM,"Reconstruction of sediment-dispersal patterns not only provides insight into paleogeographic evolution, but also sheds light on facies and reservoir prediction. By integrating core, wireline logs, and 3D seismic data, seismic sedimentologists have discovered several advantages to sediment-dispersal reconstruction and paleogeographic-environment analysis. We have subdivided the third member of the Shahejie Formation (Es3) of the southeastern Zhanhua Sag (Sanhecun Block) into three third-order sequences, namely SQ1, SQ2, and SQ3 from bottom to top. The facies architecture was analyzed by using the seismic sedimentology approach based on 3-D seismic data. Seismic RMS-amplitude stratal slices reveal different characteristics of the lobes among the southwest gentle slope, southern slope-break belt and north fault-controlled slope from source to sink. On the basis of an integrated analysis of well log, core data, seismic facies based on RMS attributes, three depositional environments (e.g., ""fan-delta"", ""turbidite"" and ""lacustrine"" facies) have been recognized. Seismic RMS-amplitude stratal slices indicate that the depositional environments of these sequences evolved from medium-sized gravel-rich fan-delta and turbidite-fan deposits to small-scale mud-rich fan-delta deposits, and lastly to large-scale sand-rich fan-delta deposits. The changes of relative lake level and sediment supply rate control the lithology and size of different depositional systems. This study also suggests that the temporal and spatial evolution and distribution of depositional systems are influenced significantly by paleotopography and slope break in the systems tracts of different sequences of the Es3 in the southeast Zhanhua Sag, Bohai Bay Basin. In addition, fan-delta-front deposits could also be considered as future potential exploration targets because they are relatively sand-or gravel-rich, given the reconstruction of the sediment-dispersal pattern.",2,2,2
Seismic Data,Rift Stage,"Li, Xiaopeng; Wang, Hua; Gan, Huajun; Chen, Si; Zhang, Hongwei; Peng, Yuhui","Stratigraphic charactertistic and tectonic control on the paleogene sedimentary evolution of the Baxian Half-graben, Bohai Bay Basin, east China",Baxian sag; Stratigraphic architecture; Facies associations; Depositional evolution,SEQUENCE STRATIGRAPHY; SONGLIAO BASIN; RIVER DELTA; SYN-RIFT; DEPOSITIONAL SEQUENCES; SEISMIC SEDIMENTOLOGY; SHAHEJIE FORMATION; BRAIDED DELTA; PEARL RIVER; ARCHITECTURE,"The depositional and structural development of a deltaic dominated succession, interpreted from seismic data, cores, well curves and lab data, is discussed. The case is from a comprehensive analysis of stratigraphy and the depositional process of a deltaic to continental succession in the early to late Paleogene in the Baxian Half-graben, Bohai Bay Basin, East China. The evolution of three genetic successions with a total thickness of 1000-7000 m, comprising three facies associations, including fan delta, braided-river to shallow water delta and lacustrine deposit, records: a, initial rift stage, b, late rift stage, and c, post-rift stage. (1) The initial rift stage is made up of several fining-upward successions, mainly stacked in retrogradation style that pass from the fan delta plain, through the fan delta front to pro-delta in a deep lacustrine environment. This stage is characterized by high intensity rifting and the deposition was keeping up with subsidence. (2) The late rift stage is made up of several successions stacked in both progradation and retrogradation styles. The succession is defined by braided-river deltas, distributary channels, subaqueous channels, swamp, levees, and fluvial-dominated mouth bar, which are mainly identified using core data. This stage is characterized by a decrease in the intensity of rifting and finer-grained deposits. (3) The post-rift stage is made up of several successions stacked mainly in an aggradation style. Shallow water delta developed in the early phase, and lacustrine deposits developed in the late phase. The transition from initial-rift to late-rift phase is represented by a seismically identifiable regional angular unconformity and an overall upward decrease in the quantity of syn-depositional faults. The late-rift to post-rift evolution is represented by an overall decrease in grain size, decrease in fluvial influence and increase in wave influence. The research process can be a reference for the study of stratigraphic architecture and sedimentary process in other lacustrine basins where tectonic movements are well developed. The achievements of this article can be an important basis for the further exploration in the half-graben.",1,1,2
Seismic Data,Rift Stage,"Gao, Huahua; Tong, Xiaoguang; Wen, Zhixin; Wang, Zhaoming",The tectonic evolution of the eastern Mediterranean basin and its control on hydrocarbon distribution,Eastern Mediterranean basin; Prototype basin; Basin evolution; Hydrocarbon accumulation and distribution; Favorable plays,MESSINIAN SALINITY CRISIS; DEEP-SEA FAN; ERATOSTHENES SEAMOUNT; LEVANT BASIN; CRUSTAL THICKNESS; NEOGENE EVOLUTION; SALT TECTONICS; CYPRUS ARC; REGION; COLLISION,"Recent discoveries of giant, deep-water gas fields in the Eastern Mediterranean Basin (EMB) have revealed abundant hydrocarbon resources and significant exploration potential in turbidite and reef reservoirs (e.g., in the Tamar and Levantine fields, and the Zohr and Calypso fields, respectively). However, further exploration is currently constrained by the lack of detailed knowledge on the development of the basin. This paper presents a systematic model of the tectonic evolution of the EMB based on an analysis of new 2D seismic data and relevant published literature, assesses the main petroleum systems operating in the basin, and identifies prospective zones for future exploration. The modeling of a sequence of 12 prototype basins, restored from the seismic data, enable the tectonic evolution of the EMB to be divided into three stages: a rift stage, a 'drift' stage (including post-rift thermal subsidence), and a 'convergence and transformation' stage. This latest stage can be divided into four chronologically and geographically distinct sub-stages. The structural and stratigraphic architecture of the EMB, and hence the hydrocarbon distribution in the basin, evolved during the rifting of continental fragments from Gondwana (e.g., the Tauride-Anatolian plate, and the Kyrenia, Troodos, and Eratosthenes micro-plates), followed by their northward drift and collision with Eurasia. Six hydrocarbon plays are identified in this paper, two of which are previously unrecognized: the Mesozoic intra-platform reef play in the Eratosthenes Seamount, and the Mesozoic and Miocene 'double-stacked' platform-margin reef play in the 'high-low structure belt' south of the Eratosthenes Seamount. These two high-quality reef plays, together with stratigraphic and fault-block traps in the northern Levant Basin, are identified as the most prospective hydrocarbon exploration targets in the EMB.",3,5,1
Seismic Data,Fourier,"Ma, Zhengqian; Yin, Xingyao; Zong, Zhaoyun; Song, Mingshui; Wang, Yanguang; Chen, Zuqing; Li, Jinlei; Liu, Xiaojing",Azimuthally variation of elastic impedances for fracture estimation,Azimuthally anisotropic elastic impedance; Fourier series; Fracture orientation; Fracture density; Karhunen-Loeve transformation; 90 degrees ambiguity,SEISMIC AMPLITUDE VARIATION; INVERSION; COEFFICIENTS; PARAMETERS; OFFSET; PROPAGATION; ANISOTROPY; MODELS; FLUID,"Fracture parameters including fracture orientation and fracture density, work as significant information in the fields of the engineering and exploration geophysics. However, it nowadays still remains challenging to concisely and stably estimate those fracture parameters from seismic data due to the limited signal to noise ratio of the azimuthal seismic data. A method based on azimuthally anisotropic elastic impedance (azimuthal AEI) in terms of Fourier series variation with azimuth is proposed to characterize the fracture distribution. Firstly, the azimuthal AEI equation in terms of truncated Fourier series is derived to reduce the number of unknown parameters in the fracture parameters estimation. In addition, KL (Karhunen-Loeve) transformation is used to extract the primary feature of reflection amplitude variation with azimuth and weaken the random noise for azimuthal pre-stack seismic data. And then the azimuthal AEI is estimated from KL transformed azimuthal pre-stack seismic data with the constrained sparse spike inversion method. The fracture orientation without 90 degrees ambiguity can be estimated by an innovative azimuthal AEI equation incorporating the azimuthal AEI equation in terms of Fourier series and the fracture orientation prior information. And the biased estimate for the anisotropic gradient of the azimuthal AEI can be estimated from the second order Fourier coefficient to forecast the fracture density. Besides, we introduce a more convenient way, which is employing the standard deviation of the nature logarithm (SDNL) of the azimuthal AEI in the azimuth domain, than that based on the anisotropic gradient in the fracture density estimation. The synthetic cases demonstrate the rationality and robustness of the innovative primary wave azimuthal AEI equation and the fracture parameters estimation method even with sparse 30 degrees sampling interval in the azimuth. A field data example demonstrates that the proposed method is effective and efficient in the fracture parameters prediction.",0,0,3
Seismic Data,Fourier,"Jiang, Shuaishuai; Chen, Xuehua; Qi, Yingkai; Jiang, Wei; Zhang, Jie; He, Zhenhua",Seismic numerical analysis for partially gas-saturated porous rocks by an extended local Rytov Fourier approximation based on the diffusion-viscous theory,Rytov approximation; Diffusive and viscous wave equation; Attenuation; Dispersion; Gas-saturated reservoir,ELASTIC-WAVES; MIGRATION; SIMULATION,"The frequency-dependent attenuation and velocity dispersion of seismic responses are closely related to hydrocarbon reservoirs. To further investigate the characteristics of seismic responses caused by pore fluid-bearing reservoirs, the role of gas saturation is analyzed in seismic responses of sand reservoirs characterized by the patchy saturation model. To this end, a novel wave extrapolation method is developed based on the diffusive-viscous wave equation (DVWE) as well as a scheme for an extended local Rytov Fourier (ELRF) approximation within the extrapolation depth interval. Our proposed method considers the presence of fluid mixtures in the porous media, resulting in seismic attenuation and dispersion by the mechanism generally known as wave-induced fluid flow (WIFF). This method enables an accommodation for the lateral variations in slowness, diffusion coefficient and viscosity. Subsequently, the extrapolation is adopted to model the synthetic seismic data of a distributary channel model. During this modeling, a gas-water saturated sand reservoir embedded into one of the channels was used to comparatively analyze the distinct features on its seismic synthetic data. We exhibited the numerical simulation results using the proposed wave extrapolation method here and the traditional acoustic wave equation (AWE) method. A comparison of the simulation results, demonstrates that our proposed numerical method can depict the seismic dispersion and frequency-dependent attenuation as well as the phase delay effects associated with gas-water-saturated sand reservoirs. Furthermore, we compare the seismic responses by changing the gas saturations of the sand reservoir. The gas saturation of the reservoir has significant effects on the seismic characteristics of the numerical modeling data. The numerical modeling method improves our understanding of the mechanisms of seismic frequency-dependent characteristics associated with gas saturations and potentially contributes to better insights into gas reservoir indicators derived from seismic field data.",1,1,5
Seismic Data,Karst,"Li, Yi-Long; Wu, Feng; Li, Xiao-Ping; Tan, Xiao-Hua",Experimental study on waterflood development in large-scale karst structures,Karst structure; Waterflood experiment; Large-scale three-dimensional physical model; Two-phase flow of oil/water,FLUID-FLOW; PERMEABILITY; SIMULATION,"On the basis of the seismic data volume of a certain well group unit of the Tahe fracture-vuggy reservoirs, the similarity theory is adopted, and a numerical model with geometric, kinematic, dynamic, and fracture-cavity characteristic parameter similarities is designed. Moreover, a large-scale three-dimensional physical karst cave model is built with the carving technology. The model is used in the experimental study of two-phase flow of oil/ water during waterflood development and in the analysis of relevant influencing factors. Results show that the displacement efficiency of low-high mode is obviously superior to the case of high-low mode. A high crude oil viscosity is found to equate to a low ultimate recovery. High-velocity water flooding improves ultimate recovery but results earlier water breakthrough. Well shutdown improves recovery factor and well shutdown during middle water cut stage achieves optimum effects. Bottom water energy benefits oil reservoir exploitation to some degree.",3,3,2
Seismic Data,Karst,"Li, Yongqiang; Sun, Jianfang; Wei, Hehua; Song, Suihong",Architectural features of fault-controlled karst reservoirs in the Tahe oilfield,Karst outcrops; Tahe oilfield; Fault-controlled karst; Architectural features; Production significance,CARBONATE RESERVOIR; TARIM BASIN; PALEOKARST; SYSTEM; ROCKS,"Based on the analysis of the characteristics of modern karst and paleokarst outcrops, this study summarizes the features of subsurface reservoirs by using core, logging, seismic and production data, establishes the structural model of fault-controlled karst reservoirs, and points out the guiding significance of this structural model for development and production in the Tahe oilfield. Modern karst in southern China shows the three-component structural characteristics of fault-controlled karst which are fault core, damage zone, and host rock. The cavern is developed in the fault core and the fracture-vugs are fully developed. Paleokarst outcrops reveal the evolutionary process of fault-controlled karst reservoirs, the characteristics of caverns along the fault and the surrounding fracture-vuggy features. Seismic structure tensor attributes, ant-track attributes and amplitude spectrum gradient attributes are used to describe the external geometry, caverns, and large-scale fractures of fault-controlled karst reservoirs, and the small fractures and vugs can be described by using cores. According to the characteristics of modern karst, paleokarst and subsurface reservoirs, three architectural patterns of fault-controlled cavern complexes, fault-controlled caverns and fault-controlled vugs are summarized. Different architectural patterns of karst reservoirs lead to different production capacities. The architectural patterns have important guiding significance for new drilling and water or gas injection to improve oil recovery.",5,6,3
Seismic Data,Events,"Huang, Guojiao; Ba, Jing; Du, Qizhen; Carcione, Jose M.",Simultaneous inversion for velocity model and microseismic sources in layered anisotropic media,Microseismic location; Simultaneous inversion; Layered anisotropic media; Seismic tomography,TRAVEL-TIME INVERSION; VALLEY GAS-FIELD; SEISMIC TOMOGRAPHY; LOCAL EARTHQUAKES; CRUSTAL STRUCTURE; ARRIVAL TIMES; P-WAVE; LOCATION; FAULT; ZONE,"Microseismic monitoring is widely applied in fracturing operations, reservoir delineation and water front monitoring. Microseismic inversion generally uses an initial velocity model based on well logs and seismic data from perforation shots. This model is generally not suitable to locate microseismic sources. To reduce errors, we have developed a method that simultaneously updates the velocity model and locates events in space and time. 1-D layered anisotropy with a transversely-isotropic (TI) symmetry is assumed, where the symmetry axis can be arbitrarily oriented. The arrival times and ray paths of the qP, qSV and qSH waves are calculated with a modified multistage shortest path algorithm. Combined with the conjugate gradient method, a damped, minimum-norm, least-squares and constrained problem is solved. The numerical examples show that the proposed algorithm can be used to invert the anisotropic velocity model (elastic moduli and interface depth for each layer) and locate the microseismic sources and their onset times, simultaneously. It is shown that the algorithm is not very sensitive to random noise, which may be contained in arrival times and model anisotropy heterogeneities.",2,2,7
Seismic Data,Events,"Zhao, Jing; Ren, Jinchang; Gao, Jinghuai; Tschannerl, Julius; Murray, Paul; Wang, Daxing",Automatic events extraction in pre-stack seismic data based on edge detection in slant-stacked peak amplitude profiles,Automatic event extraction; Pre-stack reflection data; ray tracing; Radon transformation,PICKING; FREQUENCY,"Events picking is one of the fundamental tasks in interpreting seismic data. To extract the correct travel-time of reflected waves, picking events in a wide range of source-receiver offsets is needed. Compared to post-stack seismic data, pre-stack seismic data has an accurate horizon and abundant travel-time, amplitude, and frequency while the waveform of post-stack data is damaged by normal move-out (NMO) applications. In this paper, we focus on automatic event extraction from pre-stack reflection seismic data. With the deep development of oil-gas exploration, the difficulty of petroleum exploration is being increased. Auto recognition and picking of seismic horizon is presented as the basis for oil-gas detection. There is a correspondence between the real geology horizon and events of seismic profiles. As a result, firstly, recognizing and tracing continuous events from real seismic records are needed to acquire significant horizon locations. Picking events is in this context the recognition and tracing of waves reflected from the same interfaces according to kinematics and dynamic characteristics of seismic waves. Current extraction algorithms are well able to trace these events of the seismic profile and are undergoing great development and utilization. In this paper, a method is proposed to pick travel-time and local continuous events based on edges obtained by slant-stacked peak amplitude section (SSPA). How to calculate the SSPA section is discussed in detail. The new method can improve the efficiency and accuracy without windowing and manual picking of seed points. The event curves obtained from both the synthetic layered model and field record have validated the high accuracy and efficiency of the proposed methodology.",4,4,1
Seismic Data,Fracture Orientation,"Ma, Zhengqian; Yin, Xingyao; Zong, Zhaoyun; Song, Mingshui; Wang, Yanguang; Chen, Zuqing; Li, Jinlei; Liu, Xiaojing",Azimuthally variation of elastic impedances for fracture estimation,Azimuthally anisotropic elastic impedance; Fourier series; Fracture orientation; Fracture density; Karhunen-Loeve transformation; 90 degrees ambiguity,SEISMIC AMPLITUDE VARIATION; INVERSION; COEFFICIENTS; PARAMETERS; OFFSET; PROPAGATION; ANISOTROPY; MODELS; FLUID,"Fracture parameters including fracture orientation and fracture density, work as significant information in the fields of the engineering and exploration geophysics. However, it nowadays still remains challenging to concisely and stably estimate those fracture parameters from seismic data due to the limited signal to noise ratio of the azimuthal seismic data. A method based on azimuthally anisotropic elastic impedance (azimuthal AEI) in terms of Fourier series variation with azimuth is proposed to characterize the fracture distribution. Firstly, the azimuthal AEI equation in terms of truncated Fourier series is derived to reduce the number of unknown parameters in the fracture parameters estimation. In addition, KL (Karhunen-Loeve) transformation is used to extract the primary feature of reflection amplitude variation with azimuth and weaken the random noise for azimuthal pre-stack seismic data. And then the azimuthal AEI is estimated from KL transformed azimuthal pre-stack seismic data with the constrained sparse spike inversion method. The fracture orientation without 90 degrees ambiguity can be estimated by an innovative azimuthal AEI equation incorporating the azimuthal AEI equation in terms of Fourier series and the fracture orientation prior information. And the biased estimate for the anisotropic gradient of the azimuthal AEI can be estimated from the second order Fourier coefficient to forecast the fracture density. Besides, we introduce a more convenient way, which is employing the standard deviation of the nature logarithm (SDNL) of the azimuthal AEI in the azimuth domain, than that based on the anisotropic gradient in the fracture density estimation. The synthetic cases demonstrate the rationality and robustness of the innovative primary wave azimuthal AEI equation and the fracture parameters estimation method even with sparse 30 degrees sampling interval in the azimuth. A field data example demonstrates that the proposed method is effective and efficient in the fracture parameters prediction.",0,0,3
Seismic Data,Fracture Orientation,"Huang, Guojiao; Ba, Jing; Du, Qizhen; Carcione, Jose M.",Simultaneous inversion for velocity model and microseismic sources in layered anisotropic media,Microseismic location; Simultaneous inversion; Layered anisotropic media; Seismic tomography,TRAVEL-TIME INVERSION; VALLEY GAS-FIELD; SEISMIC TOMOGRAPHY; LOCAL EARTHQUAKES; CRUSTAL STRUCTURE; ARRIVAL TIMES; P-WAVE; LOCATION; FAULT; ZONE,"Microseismic monitoring is widely applied in fracturing operations, reservoir delineation and water front monitoring. Microseismic inversion generally uses an initial velocity model based on well logs and seismic data from perforation shots. This model is generally not suitable to locate microseismic sources. To reduce errors, we have developed a method that simultaneously updates the velocity model and locates events in space and time. 1-D layered anisotropy with a transversely-isotropic (TI) symmetry is assumed, where the symmetry axis can be arbitrarily oriented. The arrival times and ray paths of the qP, qSV and qSH waves are calculated with a modified multistage shortest path algorithm. Combined with the conjugate gradient method, a damped, minimum-norm, least-squares and constrained problem is solved. The numerical examples show that the proposed algorithm can be used to invert the anisotropic velocity model (elastic moduli and interface depth for each layer) and locate the microseismic sources and their onset times, simultaneously. It is shown that the algorithm is not very sensitive to random noise, which may be contained in arrival times and model anisotropy heterogeneities.",2,2,7
Seismic Data,Pre-stack Seismic Data,"Ma, Zhengqian; Yin, Xingyao; Zong, Zhaoyun; Song, Mingshui; Wang, Yanguang; Chen, Zuqing; Li, Jinlei; Liu, Xiaojing",Azimuthally variation of elastic impedances for fracture estimation,Azimuthally anisotropic elastic impedance; Fourier series; Fracture orientation; Fracture density; Karhunen-Loeve transformation; 90 degrees ambiguity,SEISMIC AMPLITUDE VARIATION; INVERSION; COEFFICIENTS; PARAMETERS; OFFSET; PROPAGATION; ANISOTROPY; MODELS; FLUID,"Fracture parameters including fracture orientation and fracture density, work as significant information in the fields of the engineering and exploration geophysics. However, it nowadays still remains challenging to concisely and stably estimate those fracture parameters from seismic data due to the limited signal to noise ratio of the azimuthal seismic data. A method based on azimuthally anisotropic elastic impedance (azimuthal AEI) in terms of Fourier series variation with azimuth is proposed to characterize the fracture distribution. Firstly, the azimuthal AEI equation in terms of truncated Fourier series is derived to reduce the number of unknown parameters in the fracture parameters estimation. In addition, KL (Karhunen-Loeve) transformation is used to extract the primary feature of reflection amplitude variation with azimuth and weaken the random noise for azimuthal pre-stack seismic data. And then the azimuthal AEI is estimated from KL transformed azimuthal pre-stack seismic data with the constrained sparse spike inversion method. The fracture orientation without 90 degrees ambiguity can be estimated by an innovative azimuthal AEI equation incorporating the azimuthal AEI equation in terms of Fourier series and the fracture orientation prior information. And the biased estimate for the anisotropic gradient of the azimuthal AEI can be estimated from the second order Fourier coefficient to forecast the fracture density. Besides, we introduce a more convenient way, which is employing the standard deviation of the nature logarithm (SDNL) of the azimuthal AEI in the azimuth domain, than that based on the anisotropic gradient in the fracture density estimation. The synthetic cases demonstrate the rationality and robustness of the innovative primary wave azimuthal AEI equation and the fracture parameters estimation method even with sparse 30 degrees sampling interval in the azimuth. A field data example demonstrates that the proposed method is effective and efficient in the fracture parameters prediction.",0,0,3
Seismic Data,Pre-stack Seismic Data,"Zhao, Jing; Ren, Jinchang; Gao, Jinghuai; Tschannerl, Julius; Murray, Paul; Wang, Daxing",Automatic events extraction in pre-stack seismic data based on edge detection in slant-stacked peak amplitude profiles,Automatic event extraction; Pre-stack reflection data; ray tracing; Radon transformation,PICKING; FREQUENCY,"Events picking is one of the fundamental tasks in interpreting seismic data. To extract the correct travel-time of reflected waves, picking events in a wide range of source-receiver offsets is needed. Compared to post-stack seismic data, pre-stack seismic data has an accurate horizon and abundant travel-time, amplitude, and frequency while the waveform of post-stack data is damaged by normal move-out (NMO) applications. In this paper, we focus on automatic event extraction from pre-stack reflection seismic data. With the deep development of oil-gas exploration, the difficulty of petroleum exploration is being increased. Auto recognition and picking of seismic horizon is presented as the basis for oil-gas detection. There is a correspondence between the real geology horizon and events of seismic profiles. As a result, firstly, recognizing and tracing continuous events from real seismic records are needed to acquire significant horizon locations. Picking events is in this context the recognition and tracing of waves reflected from the same interfaces according to kinematics and dynamic characteristics of seismic waves. Current extraction algorithms are well able to trace these events of the seismic profile and are undergoing great development and utilization. In this paper, a method is proposed to pick travel-time and local continuous events based on edges obtained by slant-stacked peak amplitude section (SSPA). How to calculate the SSPA section is discussed in detail. The new method can improve the efficiency and accuracy without windowing and manual picking of seed points. The event curves obtained from both the synthetic layered model and field record have validated the high accuracy and efficiency of the proposed methodology.",4,4,1
Seismic Data,Reconstruction,Zhu Xiaomin; Liu Qianghu; Ge Jiawang; Dong Yanlei; Zhu Shifa; Tan Mingxuan; Yang Yong,"Reconstruction of sediment-dispersal patterns using seismic sedimentology in the southeastern Zhanhua Sag, Bohai Bay Basin, China",Seismic sedimentology; Sediment-dispersal pattern; Paleogeography; Third member of shahejie formation; Zhanhua sag; Bohai bay basin,MESH PETROLEUM PLAYS; SHALLOW-WATER DELTA; HYDROCARBON ACCUMULATION; SEQUENCE STRATIGRAPHY; FAN-DELTA; DEPRESSION; GEOMORPHOLOGY; EXAMPLE; PALEOGENE; SYSTEM,"Reconstruction of sediment-dispersal patterns not only provides insight into paleogeographic evolution, but also sheds light on facies and reservoir prediction. By integrating core, wireline logs, and 3D seismic data, seismic sedimentologists have discovered several advantages to sediment-dispersal reconstruction and paleogeographic-environment analysis. We have subdivided the third member of the Shahejie Formation (Es3) of the southeastern Zhanhua Sag (Sanhecun Block) into three third-order sequences, namely SQ1, SQ2, and SQ3 from bottom to top. The facies architecture was analyzed by using the seismic sedimentology approach based on 3-D seismic data. Seismic RMS-amplitude stratal slices reveal different characteristics of the lobes among the southwest gentle slope, southern slope-break belt and north fault-controlled slope from source to sink. On the basis of an integrated analysis of well log, core data, seismic facies based on RMS attributes, three depositional environments (e.g., ""fan-delta"", ""turbidite"" and ""lacustrine"" facies) have been recognized. Seismic RMS-amplitude stratal slices indicate that the depositional environments of these sequences evolved from medium-sized gravel-rich fan-delta and turbidite-fan deposits to small-scale mud-rich fan-delta deposits, and lastly to large-scale sand-rich fan-delta deposits. The changes of relative lake level and sediment supply rate control the lithology and size of different depositional systems. This study also suggests that the temporal and spatial evolution and distribution of depositional systems are influenced significantly by paleotopography and slope break in the systems tracts of different sequences of the Es3 in the southeast Zhanhua Sag, Bohai Bay Basin. In addition, fan-delta-front deposits could also be considered as future potential exploration targets because they are relatively sand-or gravel-rich, given the reconstruction of the sediment-dispersal pattern.",2,2,2
Seismic Data,Reconstruction,"Sun, Hong-Mei; Jia, Rui-Sheng; Zhang, Xing-Li; Peng, Yan-Jun; Lu, Xin-Ming",Reconstruction of missing seismic traces based on sparse dictionary learning and the optimization of measurement matrices,Seismic data reconstruction; Compressed sensing; Sparse representation; K-singular value decomposition; Measurement matrix optimization,ROBUST UNCERTAINTY PRINCIPLES; K-SVD; CURVELET-TRANSFORM; INTERPOLATION; ALGORITHM; RECOVERY; SETS; REPRESENTATIONS; PROJECTION,"Due to limitations arising under complicated geological conditions and field collection environments, we often cannot collect complete and regular field seismic data. To solve that problem, the reconstruction of seismic data has been widely studied. In this paper, we propose a reconstruction algorithm for seismic data with missing traces based on sparse dictionary learning and measurement matrix optimization. The algorithm views the seismic data as a matrix. It first uses the neighboring channel to fill in the missing trace and then uses the transposed matrix and applies the K-singular value decomposition (K-SVD) algorithm by columns to train the sample, obtaining an over-complete dictionary that can be used to develop an optimal sparse representation of seismic data. In the process of seismic data reconstruction, we first transpose the seismic data with missing traces, adopt the regularized orthogonal matching pursuit (ROMP) algorithm to obtain optimum estimations of the data in each column and then transpose the matrix to obtain the reconstructed seismic data. To further increase the quality of seismic data reconstructions, the algorithm presented in this paper also introduces the Equiangular Tight Frame (ETF) method to optimize the measurement matrix. The experiments indicate that this paper's algorithm can achieve high-quality reconstructions of seismic data.",2,2,5
Seismic Data,Optimization,"Kim, Hyeonju; Lee, Gwang H.","A deterministic geomodeling case study for a thin clastic reservoir: The Second Wall Creek Sand, Teapot Dome field, Wyoming, USA",Teapot Dome field; Second Wall Creek Sand; Geomodeling; Neural network,CO2 SEQUESTRATION,"In this case study, we geomodeled the Upper Cretaceous Second Wall Creek Sand (SWCS) of the southern Teapot Dome field, Wyoming, USA, using public domain seismic and well-log data. The SWCS is an at-or-below seismic-resolution (about 20 m), fluvial-deltaic reservoir and has been the most productive in the field. The goemodeling procedure consisted of structural modeling of the depth 3-D grid (30 m x 30 m x 1 m cells) and petrophysical modeling for porosity and net-to-gross (N/G). The seismic data were enhanced by spectral balancing to resolve the SWCS. Facies modeling was not necessary because a facies analysis of gamma-ray logs and lithofacies and stratigraphic-discontinuity seismic attributes suggests a uniform facies. The porosity and N/G were modeled by neural network multi-attribute transform (NN-MAT). NN training included the absolute and relative impedances and three representative isofrequencies in addition to the conventional amplitude-and frequency-based attributes. The modeled porosity varies from less than 8% to over 18% with an average of 16.7% which agrees with the reported averages. The modeled N/G values range from about 0.2 to over 0.8 with an average of 0.7 which is greater than the reported average (0.5). The porosity and N/G models may not be optimal because only a few wells and a small number of the time samples for the thin reservoir interval were used in NN training. The geomodeling workflow presented in this study is optimized for thin reservoirs and can be used when facies modeling is difficult because NN-MAT computes petrophysical properties without being guided by facies models.",0,0,3
Seismic Data,Optimization,"Sun, Hong-Mei; Jia, Rui-Sheng; Zhang, Xing-Li; Peng, Yan-Jun; Lu, Xin-Ming",Reconstruction of missing seismic traces based on sparse dictionary learning and the optimization of measurement matrices,Seismic data reconstruction; Compressed sensing; Sparse representation; K-singular value decomposition; Measurement matrix optimization,ROBUST UNCERTAINTY PRINCIPLES; K-SVD; CURVELET-TRANSFORM; INTERPOLATION; ALGORITHM; RECOVERY; SETS; REPRESENTATIONS; PROJECTION,"Due to limitations arising under complicated geological conditions and field collection environments, we often cannot collect complete and regular field seismic data. To solve that problem, the reconstruction of seismic data has been widely studied. In this paper, we propose a reconstruction algorithm for seismic data with missing traces based on sparse dictionary learning and measurement matrix optimization. The algorithm views the seismic data as a matrix. It first uses the neighboring channel to fill in the missing trace and then uses the transposed matrix and applies the K-singular value decomposition (K-SVD) algorithm by columns to train the sample, obtaining an over-complete dictionary that can be used to develop an optimal sparse representation of seismic data. In the process of seismic data reconstruction, we first transpose the seismic data with missing traces, adopt the regularized orthogonal matching pursuit (ROMP) algorithm to obtain optimum estimations of the data in each column and then transpose the matrix to obtain the reconstructed seismic data. To further increase the quality of seismic data reconstructions, the algorithm presented in this paper also introduces the Equiangular Tight Frame (ETF) method to optimize the measurement matrix. The experiments indicate that this paper's algorithm can achieve high-quality reconstructions of seismic data.",2,2,5
Source Rocks,Organic Matter,"Zhang, Tianjiao; Zhang, Shanwen; Meng, Wei; Feng, Yuelin; An, Tianxia",Characteristics and genetic mechanism of carbonate cements in sandstones near the overpressure top surface: A case study of the Niuzhuang Depression in Bohai Bay Basin,Overpressure top surface; Carbonate cements; Carbon and oxygen isotope; Overpressured fluid; Sandstone reservoir,PORE-PRESSURE; RESERVOIR SANDSTONES; DIAGENETIC HISTORY; SHAHEJIE FORMATION; PART 1; ORIGIN; PETROLEUM; FIELD; COMPACTION; EVOLUTION,"Carbonate cements are important authigenic minerals in the sandstone reservoir near the overpressure top surface in the Niuzhuang Depression. However, their genetic mechanism has not been studied in detail. This study uses observations of casting thin sections and cathodoluminescence and micro-area electron probe compositional data to determine that the diagenetic sequence of these carbonate cements is penecontemporaneous dolomite -> calcite filling primary pores -> calcite/iron-bearing calcite filling secondary dissolution pores -> ankerite. The genetic mechanisms of these carbonate cements are analyzed based on the fluid inclusion temperature at different phases of carbonate cementation, carbon and oxygen isotope composition, simulation of the thermal evolution of the hydrocarbon source rock, and elemental chemical composition. Results show that the carbon isotopic compositions of the carbonate cements are affected not only by organic acids released during the maturation of organic matter but also by the dissolution of lacustrine carbonate rock in the fourth member of the Shahejie Formation. Dissolution-reprecipitation of the lacustrine carbonate rocks is responsible for an obvious positive drift in the delta C-13(PDB) values of carbonate cements near the overpressure top surface. There are four phases of carbonate cementation near the top surface of the overpressured zone, with phase IV carbonate cements mainly occurring near the overpressure top surface. Phase I carbonate cements are mainly dolomite, and their formation is related to the decomposition of organic matter by methanogenic bacteria. Phase II carbonate cements are related to Ca2+ and CO32- supersaturation during pore fluid concentration. Phase III carbonate cements result from overpressured fluid that is rich in Ca2+ and Mg2+ and feldspar dissolution caused by overpressure fluid intrusion. Phase IV carbonate cements are derived from CO32- formed by organic acid pyrolysis in late diagenesis, CO32- formed by early carbonate cement dissolution, and Mg2+ and Fe2+ plasma formed by the dissolution of metamorphic rock debris into pore fluid. The formation of phase III and IV carbonate cements is most affected by overpressured hydrocarbon fluids.",1,4,4
Source Rocks,Organic Matter,"Stockhausen, Martin; Galimberti, Roberto; Di Paolo, Lea; Elias, Rouven; Gelin, Francois; Berner, Ulrich; Erdmann, Michael; Pedersen, Jon Halvard; Di Primio, Rolando; Schwark, Lorenz","The Expulsinator device: A new approach for a lab-scaled, near-natural generation- and expulsion simulation",Pyrolysis; Migration; Artificial maturation; Expulsion efficiency; Catagenesis simulation; Source rock characterization,ROCK-EVAL PYROLYSIS; PRIMARY MIGRATION; GAS-CHROMATOGRAPHY; ARTIFICIAL MATURATION; ORGANIC-MATTER; KEROGEN; OIL; DIFFUSION; PRESSURE; WATER,"Investigating hydrocarbon generation and expulsion by pyrolysis is limited by methodologies incapable of simulating conditions close to those prevailing in natural systems. Destructive sample preparation, inappropriate pressure regimes and pyrolysis in closed mode and/or in the absence of water caused results not representative for natural processes. We here present a new approach for a laboratory scaled simulation of generation, primary migration and expulsion under near-natural conditions, using the ""Expulsinator"" device. Near-natural conditions are realized by application of lithostatic pressure onto a source-rock disc with intact pore network and by pyrolysis at the presence of water, conducted in open flow through mode. This study will give a detailed technical description of the apparatus and the methodology to implement an Expulsinator experiment. An Expulsinator experiment generates a combined generation and expulsion profile, resulting in a detailed source rock characterization, incorporating yields for oil and gas, as well as rock deformation data on mm- and mu m-scale. Thus, information is provided about timing and amplitude of generation and expulsion events. The apparatus uses a novel way of continuous sampling during the pyrolysis, enabling product removal from the reactor during the generation and expulsion process. Sampling in open flow-through mode is technically demanding and requires stimulation by a modifier for quantitative removal of the expelled products from the reactor. Test experiments demonstrate that the modifier has no impact onto the expulsion behavior of the source rock. Following the technical description, the generation and expulsion profile of one Expulsinator experiment is discussed. Beside information about timing of product generation and expulsion, the experiment shows the connection between rock expansion/compression and expulsion events. The efficiency of this new methodology is compared with conventional closed hydrous pyrolysis. The results exhibit the advantages of the apparatus: Liquid yields are increased, and hydrocarbon (HC) -gas generation reduced, due to a suppression of secondary reaction by the open setup. Furthermore, conventional pyrolysis achieved lower expulsion rates, due to the absence of lithostatic pressure. The Expulsinator shows high potential for further applications, in particular for implementation of lab-simulation data into numeric models.",2,2,0
Source Rocks,Organic Matter,"Seco, Sergio L. R.; Silva, Ricardo L.; Watson, Neil; Duarte, Luis, V; Pereira, Alcides J. S. C.; Wach, Grant",Application of petrophysical methods to estimate total organic carbon in Lower Jurassic source rocks from the offshore Lusitanian Basin (Portugal),Lusitanian Basin; Lower Jurassic; Well-logs; Passey method; Source rock,RICH FACIES; S. PEDRO; SHALE; PALYNOFACIES; STRATIGRAPHY; EVOLUTION; COIMBRA; EXAMPLE; AGUA,"Lower Jurassic outcrops in the westernmost part of the Lusitanian Basin (Sao Pedro de Moel area, Portugal) reveal three stratigraphic units with source rock potential: i) Unit F from the Coimbra Formation, ii) the Polvoeira Member of the Agua de Madeiros Formation, and iii) the Marly Limestones with Organic-rich Facies Member of the Vale das Fontes Formation. Despite decades of research, these source rocks have not yet been characterised in the offshore areas of the Lusitanian Basin. As a consequence of the discrepancy between organic matter contents in correlative surface-subsurface intervals, this paper investigates the applicability of petrophysical methods to semi-quantitatively estimate total organic carbon (TOC) and delineate source rock intervals in Lower Jurassic (Sinemurian-Pliensbachian) units in the offshore Lusitanian Basin. This study is based on the i) high-resolution stratigraphic correlation between well 14A-1 and the Sao Pedro de Moel section and ii) calibration of the TOC curve calculated for well 14A-1 using the high-resolution TOC datasets from Sao Pedro de Moel. Sonic transit time vs resistivity cross-plot shows that several intervals of the aforementioned lithostratigraphic units deviate from the (organic) lean sediment baseline, interpreted to indicate the presence of hydrocarbons and low-density organic matter. Thermal maturity from cuttings samples were used to estimate vitrinite reflectance for each well point measurement. These values vary between 0.51 and 0.87, indicating that the studied interval has reached the oil generation window. The level of organic metamorphism is in accordance with the hydrocarbon generation window interval, varying between 9.49 and 9.76. Neutron/resistivity, density/resistivity, and sonic/resistivity cross-plots and the petrophysical-based method for TOC calculation outlined in Passey et al. (1990) demonstrate the close similarity between TOC curves calculated for well 14A-1 and TOC measurements from the Sao Pedro de Moel outcrops. This comparison highlights the organic-rich nature of Unit F, the Polvoeira Member and the Marly Limestones with Organic-rich Facies Member in the offshore areas of the Lusitanian Basin and their potential as hydrocarbons source intervals. This work demonstrates a feasible solution to semi-quantitatively estimate TOC in subsurface source rocks when there is large uncertainty regarding sample quality. Delineation of source rock intervals in the offshore wells of the Lusitanian Basin reduces uncertainty, minimises risk, and may aid in new exploration concepts for hydrocarbons offshore Portugal. On a broader scale, this work reinforces the importance of outcrop control to correlate and improve the current knowledge of Portugal's offshore areas.",3,3,2
Source Rocks,Organic Matter,"Cheng, Qingsong; Huang Guanghui; Zhang, Min; Zhang Wenjun; Xi, Liu","Distribution and source significance of 2-methylalkanes in coal-measure source rocks, northwest China",Coal-measure source rock; 2-Methylalkanes; iC(17)-iC(22)-iC(28) triangulation; Biomarker,BRANCHED ALKANES; CYANOBACTERIAL MATS; ANTEISO-ALKANES; MONOMETHYLALKANES; IDENTIFICATION; ANCIENT; ORIGIN; SEDIMENTS; SERIES; SMOKE,"GC-MS analysis was conducted on 59 coal-measure source rock (CSR) samples in the study area. Between nC(14) and nC(38), a series of 2-methylalkanes were detected. The 2-methylalkanes distribution can be summarized into 3 distribution modes: Front peak-type, Middle peak-type and Behind peak-type distribution. The same distribution mode is distributed at different maturity stages, and there are different distribution modes at the same thermal evolution stages, indicating that the distribution was slightly influenced by thermal evolution. C-27-C-28-C-29 regular sterane triangulation is a template which is commonly used to judge the source of organic matter and sedimentary environment. But it is not applicable to judgment of the source of organic matter of coal-measure source rock (CSR) as higher plants are the basic substance. The organic matter constitution in CSR is still complicated, we need to know secondary organic matter in CSR except for plant so as to analyze the sedimentation and diagenetic environment. Within C-17-C-22-C-28 2-methylalkanes (iC(17)-iC(22)-iC(28)) triangulation, samples with Front peak-type distribution of 2-methylalkanes are distributed near the 2-methylalkane C-17 (iC(17)) end member. Samples with Middle peak-type distribution are distributed near the 2-methylalkane C-22 (iC(22)) end member. Samples with Behind peak-type distribution are distributed near the 2-methylalkane C-28(iC(28)) end member. In combination with distribution characteristics of isoprenoid alkenes and biomarker compounds, different regions in the iC(17)-iC(22)-iC(28) triangulation can be divided into different sources of organic matter and sedimentary environment. Based on this, the iC(17)-iC(22)-iC(28) triangulation used to judge the parent material organic matter of CSR was established. In comparison with C-27-C-28-C-29 regular sterane triangulation, it is more effective to judge the source of organic matter in CSR with iC(17)-iC(22)-iC(28) triangulation.",4,4,0
Source Rocks,Organic Matter,"Fu, Sheng; Liu, Zhen; Zhang, Yi-ming; Wang, Xin; Tian, Ning; Li, Ling; Wang, Hui-lai; Jiang, Tao","Source rocks geochemistry and oil-source correlation in the Aershan and first member of Tengge'er formations of the Wulan-Hua sag in south of Erlian Basin, Northeastern China",Biomarkers; K1ba source rocks; LK1bt1 source rocks; Oil-source correlation; Wulan-hua sag,ORGANIC-MATTER; NANXIANG BASIN; CRUDE OILS; HYDROCARBONS; INDICATORS; BIOMARKER; INSIGHTS; ORIGIN,"The Wulan-Hua Sag in the south of Erlian Basin has large oil and gas resource, whereas the source rocks genetic potential and oil-rock correlation in its Aershan Formation (K1ba) and First member of Tengge'er Formation (K1bt1) are still unclear. We performed organic geochemistry analyses of oil and mudstone samples to divide crude oil types, evaluate source rock potential, and establish relatively accurate oil-source correlation. The results indicate that the source rocks in K1ba and the Lower interval in First member of Tengge'er Formation (LK1bt1) belong to good source rocks, characterized by high organic matter abundance, oil-prone kerogen type, and relatively high thermal maturity. K1ba and K1bt(1) crude oil samples were divided into two types sourced from different Wulan-Hua source rocks. Type A oil is distributed in the K1ba and LK1bt1 of Saiwusu uplift and Hongjing uplift, and featured by a low gammacerane amounts (the majority of gammacerane/C30H < 0.30), and high Pr/Ph (ranging from 0.18 to 1.18, with mean value of 0.78). It has high mature organic matter mainly originated from terrestrial plant and dominant terrestrial plant. This type of oil was sourced from the K1ba source rocks in the Saiwusu uplift. Type B oil occurs in the LK1bt1 of the Tumuer Uplift and north sub-sag, and have high gammacerane abundance (the majority of gammacerane/(C-30 > 0.3), and low Pr/Ph (ranging from 0.38 to 0.76, with mean value of 0.63). Its organic matter includes dominant terrestrial plant source, and this oil type should be sourced from the LK1bt1 source rocks in the Saiwusu uplift.",5,6,3
Source Rocks,Organic Matter,"Yang, Zhe; Li, Meijun; Cheng, Dingsheng; Xiao, Hong; Lai, Hongfei; Chen, Qingyao",Geochemistry and possible origins of biodegraded oils in the Cretaceous reservoir of the Muglad Basin and their application in hydrocarbon exploration,Geochemical characteristics; Biodegraded oil; Cretaceous; Muglad basin; WCARS,ABU GABRA FORMATION; CRUDE OILS; ORGANIC-MATTER; TRIAROMATIC STEROIDS; PETROLEUM GEOLOGY; CRATONIC REGION; TARIM BASIN; SUDAN; DEGRADATION; ROCKS,"The Muglad Basin is one of the largest petroliferous basins within the Central and Western African Rift System (WCARS). A total of 42 oil samples including light, normal and heavy crude oils from the Cretaceous reservoirs of the Muglad Basin were systematically analyzed to fully understand their geochemical characteristics and possible origins. The results of oil-oil correlation show that these Cretaceous crude oils are genetically identical and derive from the same source kitchen. Differences in physical properties and geochemical compositions may be attributed to secondary alteration, such as biodegradation. Lightly, moderately and severely biodegraded oils can be divided on the basis of the relative abundance of n-alkanes and acyclic isoprenoids in the oils and the presence of ""humps"" on gas chromatogram baselines, as well as of the relative abundance of 25-norhopanes. The biodegradation degree of Cretaceous oils in the Muglad Basin is closely related to the burial depth of oil reservoirs and the distance between the locations of oil reservoirs and adjacent faults. This study may have practical application for further petroleum exploration and development in the Muglad Basin.",5,5,3
Source Rocks,Oil Field,"Yang, Xiao-Fa; Ma, Zhong-Zhen; Zhou, Yu-Bin; Zhang, Zhi-Wei; Liu, Ya-Ming; Wang, Dan-Dan; Zhao, Yong-Bin","Reservoir characteristics and hydrocarbon accumulation of the glauconitic sandstone in the Tarapoa Block, Oriente Basin, Ecuador",Glauconitic sandstone; Reservoir characteristics; Hydrocarbon accumulation; Oriente basin; Ecuador,NAPO FORMATIONS; HOLLIN; ORIGIN; FIELD; OIL,"Although Oriente basin has explored throughout the past fifty years, little is known about the reservoir quality and hydrocarbon accumulation of the Cretaceous Upper T glauconitic sandstones. Until recently, the Upper T has drawn attention due to the commercial oil discovery. Howerer, exploration of glauconitic sandstones is complicated and reservoir quality is difficult to evaluate based on logging and seismic data. The glauconitic sandstones developed in open marine environments, characterized by a framework of glauconite and quartz grains. Diagenesis includes compation, silica overgrowth, feldspars dissolution, iron carbonate cementation. Its porosity ranges 5-20% and less than 500 md permeability. The dominant pore type is intergranular, especially residual intergranular. Glauconitic sandstones have bimodal pore throat size distributions and complex pore geometries. The Upper T glauconitic sandstones are capped by a thin veneer of fossiliferous limestones and laminated to burrowed shales. These large-area matured source rocks close to the glauconitic sandstones are probably the source kitchen in the slope of Oriente Basin. The oil pools are very little relation to structure. A large area of continuous developed glauconitic sandstone reservoirs and adjacent source rocks form an excellent source-reservoir-cap assemblage. Differ from previous views of long-distance migration from the southwest Oriente Basin, we propose that volume flow and diffusive flow are the primary migration and accumulation mechanism for the Upper T reservoir in Tarapoa Block.",0,0,1
Source Rocks,Oil Field,"Ge, Haixia; Zhang, Zhihuan","Origin and accumulation of Paleogene oil in Qingdong sag, Jiyang depression, eastern China",Oil-source correlation; Heavy oil; Biodegradation; Oil charging orientation; Accumulation characteristics; Qingdong Sag,FLUID INCLUSION; PETROLEUM; GEOCHEMISTRY; BASIN; INDICATORS; FIELD,"This study reports on the geochemical examination of 18 core samples and 22 crude oil samples from the Qingdong and Dongying sags. Both conventional and heavy oils coexist in the Qingdong Sag, with the heavy oil resulting from biodegradation. Based on the oil-source rock correlation, the conventional oil mainly originates from the Es-3(1) source rock in the central and northern sub-sags, with the biodegraded oil in the western slope having been derived from the Es-4(u) source rock in the central and northern sub-sags. The biodegraded oil in the transition belt is mostly derived from the Dongying Sag (Es-4(u)). The biodegraded oil in the Qingdong-5 area originated from the Es-4(u) member near the Qingdong-5 area in the southern sub-sags. Two stages of oil charging were identified in the Qingdong Sag based on the basin modelling. The first stage occurred during the deposition of the Dongying Formation (Ed) in the Paleogene, and the second stage occurred during the deposition of the Guantao Formation from the Neogene to Quaternary (Ng-Q). The conventional oil in the central and northern parts of the study area mainly accumulated during the second stage and migrated both laterally through the sand-bodies and vertically along the steep faults. The heavy oil in the transition belt mostly accumulated during the second stage, migrating a long distance along the en-echelon step-fault zone, and suffered severe biodegradation. Both stages of oil charging were responsible for the heavy oil in the Qingdong-5 area and the western slope. The former migrated a short distance before being trapped, while the latter moved long distance along the fault strike. The oil charged during the first stage was subject to alteration, eventually being mixed with oil from the second charging event.",1,1,1
Source Rocks,Oil Field,"Vega, Bolivia; Kovscek, Anthony R.",A systematic study of internal gas generation in shale source rocks using analog experiments,Rock analog; Gelatin; Fracture; Shale; Source rock; Rock maturation,PRIMARY MIGRATION; GELATIN; PROPAGATION; OIL; MICROFRACTURES; VISUALIZATION; RHEOLOGY,"A two-dimensional Hele-Shaw cell was created to study and visualize hydrocarbon source rock (i.e., shale) elastic-brittle fracture and fracture network propagation mechanisms triggered by internal gas generation and gas build up during maturation of organic components. An analog immature source rock was created using a mixture of gelatin, sugar, and live yeast in pre-determined proportions. This mixture was poured into the Hele-Shaw cell and allowed to gel. The internal gas generated as a result of sugar fermentation by yeast caused pressure build up within the gel that ultimately resulted in the activation of dissipation mechanisms such as gas diffusion and deformation of the gel matrix. These mechanisms are analogous to shale maturation and fluid generation. Image analysis was employed to study and characterize key events such as fracture nucleation, propagation, and coalescence versus time. Derivative parameters such as fracture growth rate, fracture tip pressure, and fracture spatial distribution, among others, were calculated using the image-sourced data and applying Linear Elastic Fracture Mechanics (LEFM) principles. Results showed that the experiments are repeatable within a consistent response range and additional parameters were identified to be useful input for numerical modelling, including nucleation sites, fracture merging angle, merging to nucleation ratio, and fracture connectivity. For a volume of about 100 cm(3) of 11.6% wt food-grade gelatin solution with 0.25% wt. yeast and a sugar/yeast ratio of 3, measured average total gas production was 35 cm(3) (at standard conditions). On an average gelatin matrix area of 400 cm(2), the average total fracture length and fracture density are 106 cm and 0.15 fractures/cm(2), respectively. Average maximum calculated fracture tip pressure and maximum fracture velocity are 0.92 psi and 5.85 x 10(-4)cm/s, respectively. Fracture connectivity was more frequent in the second half of the gas generation process and greater for the older and longer fractures. Average final fracture spacing was 4.42 cm. Connection angles between fractures tended to be closer to 0 degrees than to 90 degrees. Photoelasticity imaging techniques were applied to the experimental setup to visualize the stress field within the sample. The difference of principal stresses was estimated at 3.70 x 10(3) Pa for the tested material late in the maturation process. Results suggest interdependence of gas pressure, gas diffusion, and transient stress field states. The range of laboratory-scaled data are useful as benchmarking parameters for numerical modelling of source rock maturation including geomechanics.",2,2,2
Source Rocks,Oil Field,"Al-Areeq, Nabil M.; Maky, Abubakr F.; Abu-Elata, Ahmed S.; Essa, Mahmud A.; Bamumen, Salem S.; Al-Ramisy, Gamal A.","Comprehensive study on the conventional petroleum system of the Masilah oilfields, Sayun-Masilah Basin, Yemen",Petroleum system; Oil-source rock correlation; Basin modeling; Masilah oilfields; Sayun-Masilah basin; East Yemen,SEDIMENTARY BASINS; GEOCHEMICAL CHARACTERISTICS; SOURCE ROCKS; OIL-FIELD; EVOLUTION; RESERVOIR; GULF; MATURATION; PYROLYSIS; HISTORY,"The Masilah oilfields are rich-oil provinces in the Sayun-Masilah Basin. The petroleum system including essential elements and processes is a very important for understanding and development of oilfield to further explore hydrocarbons in the whole basin. Integrated geochemical, geological, petrological and petrophysical analyses were performed on the source and reservoir rocks in the Masilah oilfields to gives information about the complete petroleum system. The Masilah oilfields filled with syn- and post-rift sediments, including a self-contained source-reservoir system. The geochemical results indicate that the organic-rich shales of the Madbi Formation are considered as oil-source rocks, with high total organic carbon content of more than 5.0 wt% TOC and oil-prone kerogen Types II and I. The Madbi shales are currently characterized by thermally mature level, within the oil generation window. Geochemical biomarker correlations of oil-source rock indicate that there is a genetic link between the oils and the Late Jurassic Madbi shale source rock in the Masilah oilfields. Therefore, the geochemical characteristics of the Madbi source rock have been collaborated into basin models and illustrate that the Madbi source rock had passed the peak-oil generation window during the Late Cretaceous to present-day and that large amounts of oil were generated. The generated oil was expelled and migrated to the overlain Early Cretaceous Qishn clastic reservoir rocks through faults during the Oligocene-Middle Miocene. The oil was then accumulated and trapped into horst and tilted fault blocks that initial formed during the Late Jurassic-Early Cretaceous rifting.",3,3,2
Source Rocks,Sandstone Reservoirs,"Yang, Xiao-Fa; Ma, Zhong-Zhen; Zhou, Yu-Bin; Zhang, Zhi-Wei; Liu, Ya-Ming; Wang, Dan-Dan; Zhao, Yong-Bin","Reservoir characteristics and hydrocarbon accumulation of the glauconitic sandstone in the Tarapoa Block, Oriente Basin, Ecuador",Glauconitic sandstone; Reservoir characteristics; Hydrocarbon accumulation; Oriente basin; Ecuador,NAPO FORMATIONS; HOLLIN; ORIGIN; FIELD; OIL,"Although Oriente basin has explored throughout the past fifty years, little is known about the reservoir quality and hydrocarbon accumulation of the Cretaceous Upper T glauconitic sandstones. Until recently, the Upper T has drawn attention due to the commercial oil discovery. Howerer, exploration of glauconitic sandstones is complicated and reservoir quality is difficult to evaluate based on logging and seismic data. The glauconitic sandstones developed in open marine environments, characterized by a framework of glauconite and quartz grains. Diagenesis includes compation, silica overgrowth, feldspars dissolution, iron carbonate cementation. Its porosity ranges 5-20% and less than 500 md permeability. The dominant pore type is intergranular, especially residual intergranular. Glauconitic sandstones have bimodal pore throat size distributions and complex pore geometries. The Upper T glauconitic sandstones are capped by a thin veneer of fossiliferous limestones and laminated to burrowed shales. These large-area matured source rocks close to the glauconitic sandstones are probably the source kitchen in the slope of Oriente Basin. The oil pools are very little relation to structure. A large area of continuous developed glauconitic sandstone reservoirs and adjacent source rocks form an excellent source-reservoir-cap assemblage. Differ from previous views of long-distance migration from the southwest Oriente Basin, we propose that volume flow and diffusive flow are the primary migration and accumulation mechanism for the Upper T reservoir in Tarapoa Block.",0,0,1
Source Rocks,Sandstone Reservoirs,"Zhang, Tianjiao; Zhang, Shanwen; Meng, Wei; Feng, Yuelin; An, Tianxia",Characteristics and genetic mechanism of carbonate cements in sandstones near the overpressure top surface: A case study of the Niuzhuang Depression in Bohai Bay Basin,Overpressure top surface; Carbonate cements; Carbon and oxygen isotope; Overpressured fluid; Sandstone reservoir,PORE-PRESSURE; RESERVOIR SANDSTONES; DIAGENETIC HISTORY; SHAHEJIE FORMATION; PART 1; ORIGIN; PETROLEUM; FIELD; COMPACTION; EVOLUTION,"Carbonate cements are important authigenic minerals in the sandstone reservoir near the overpressure top surface in the Niuzhuang Depression. However, their genetic mechanism has not been studied in detail. This study uses observations of casting thin sections and cathodoluminescence and micro-area electron probe compositional data to determine that the diagenetic sequence of these carbonate cements is penecontemporaneous dolomite -> calcite filling primary pores -> calcite/iron-bearing calcite filling secondary dissolution pores -> ankerite. The genetic mechanisms of these carbonate cements are analyzed based on the fluid inclusion temperature at different phases of carbonate cementation, carbon and oxygen isotope composition, simulation of the thermal evolution of the hydrocarbon source rock, and elemental chemical composition. Results show that the carbon isotopic compositions of the carbonate cements are affected not only by organic acids released during the maturation of organic matter but also by the dissolution of lacustrine carbonate rock in the fourth member of the Shahejie Formation. Dissolution-reprecipitation of the lacustrine carbonate rocks is responsible for an obvious positive drift in the delta C-13(PDB) values of carbonate cements near the overpressure top surface. There are four phases of carbonate cementation near the top surface of the overpressured zone, with phase IV carbonate cements mainly occurring near the overpressure top surface. Phase I carbonate cements are mainly dolomite, and their formation is related to the decomposition of organic matter by methanogenic bacteria. Phase II carbonate cements are related to Ca2+ and CO32- supersaturation during pore fluid concentration. Phase III carbonate cements result from overpressured fluid that is rich in Ca2+ and Mg2+ and feldspar dissolution caused by overpressure fluid intrusion. Phase IV carbonate cements are derived from CO32- formed by organic acid pyrolysis in late diagenesis, CO32- formed by early carbonate cement dissolution, and Mg2+ and Fe2+ plasma formed by the dissolution of metamorphic rock debris into pore fluid. The formation of phase III and IV carbonate cements is most affected by overpressured hydrocarbon fluids.",1,4,4
Source Rocks,Sandstone Reservoirs,"Wang, Wei; Jiang, Youlu; Yuan, Jing; Liu, Jingdong; Zhang, Shaomin; Swennen, Rudy","Characteristics and migration mechanisms of natural gas in tight sandstone reservoirs in the Longfengshan sag, Songliao Basin, China",Tight sandstone; Hydrocarbon migration; Phase fractionation; Lower cretaceous; Longfengshan sag,PETROLEUM; EVOLUTION; OIL; FRACTIONATION; ACCUMULATION; HYDROCARBONS; SYSTEM; PHASE,"To better understand gas migration and accumulation in tight sandstone reservoirs, we conducted an integrated petrographic and geochemical analysis of hydrocarbon and aqueous fluid inclusions. This analysis was combined with the burial and multistage hydrocarbon charging histories of the reservoir. The variability in the types of hydrocarbon inclusions in the tight sandstone reservoirs can be mapped to identify phase fractionation during burial and migration. The oil-bearing inclusions resulted from the heterogeneous capture of oil generated during the first hydrocarbon charging period, when the sandstones had not yet reached tight reservoir conditions. The gas-bearing inclusions in the tight sandstone reservoirs formed during the phase fractionation of dissolved and free gas due to unstable pressure conditions. The gas-bearing inclusions are characterized by a varying vapor volume fraction (phi(vap)). A higher proportion of gas-bearing inclusions with phi(vap )< 25% was observed near the source rock with TOC content > 1.2%. In contrast, in structural highs, a higher proportion of gas-water inclusions with phi(vap )> 25% was observed, demonstrating that phase fractionation occurred during migration. The GOI data suggest that the dissolved gas migration mainly occurred in the reservoir near the source rock with TOC content > 1.2%. The subsequent free gas separation in relation to upward migration and strata uplift caused free gas to migrate farther into the tight sandstone reservoir. Additionally, the gases displayed benzene/n-hexane ratio, methane and ethane delta C-13 values increasing initially, then decreasing along the migration pathway, recording the phase state evolution of the natural gas during the burial history of the reservoirs.",2,2,0
Source Rocks,TARIM Basin,"Zhou, Xiaoxiao; Lu, Xiuxiang; Song, Xu; Quan, Han; Chen, Kun; Qian, Wenwen; Wang, Zhao; Bai, Zhongkai; Zhang, Jie","Petroleum source of oil seepages in the Kalpin area, NW Tarim Basin, China",Source rock; Carbon isotopes; Biomarkers; Origin of oil seepages; Kalpin area,STABLE CARBON; SOURCE ROCKS; CRUDE OILS; ORGANOSULFUR COMPOUNDS; ISOTOPIC COMPOSITIONS; TAZHONG AREA; MARINE OILS; HYDROCARBON; BIODEGRADATION; SUBSURFACE,"Source rocks in Lower Cambrian (epsilon(1)) and Middle-Upper Ordovician (O2+3) have low S2 values, ranging from 0.01 to 0.34 and 0.01-5.95 mg HC/g Rock, respectively. The averages of TOC are 1.07% and 0.84% for epsilon(1) and O2+3 source rocks, respectively. The equivalent vitrinite reflectance values (VREs) indicate that epsilon(1) rocks are in a high-over mature stage for oil generation, and O-2+(3) rocks are sufficiently mature. Four oil seepages from the Yingshan Formation in the Qingsong quarry of the Aksu area and 34 core samples from epsilon(1) and O2+3 rocks in the Kalpin area were analyzed for stable carbon isotopes. Moreover, 4 oil seepages and 16 core samples were analyzed by gas chromatography-mass spectrometry (GC-MS). Compared with O2+3 rocks, epsilon(1) rocks are characterized by lower values of Gammacerane/C-30 hopane (G/H), C-28/(C-27 + C-28 + C-29) 20R alpha alpha alpha sterane (C-28%), C-29/(C-27 + C-28 + C-29 ) 20R alpha alpha alpha sterane (C-29%), C-26 20S/C-28 20S triaromatic steroids (C-26/C-28), (C-26 + C-27)/C-28 triaromatic steroids and (C-26 20R + C-27 20S)/C-28 20R triaromatic steroids, and higher values of C-21/C-23 tricyclic terpane (C-21/C-23), C-27/(C-27 + C-28 + C-29) 20R alpha alpha alpha sterane (C-27%), and C-35 alpha beta (22R + 22S) homohopane/alpha beta C-30 -hopane (C-35 H/H). The two sets of source rocks have a ""V (C-27 > C-28 < C-29)""-shaped regular sterane distribution pattern, and O2+3 rocks contain triaromatic steranes in abundances as high as those of epsilon(1) rocks. C-28-C-34 25-norhopanes (NHs) indicates that the degree of degradation of oil seepages falls at approximately PM 6, rendering many biomarker parameters ineffective for oil-source correlations, except for triaromatic steriods and carbon isotopic compositions. The values of C-26/C-28, (C-26 + C-27)/C-28 triaromatic steroids and (C-26 20R + C-27 20S)/C-28 20R triaromatic steroids using 0.50, 1.45 and 1.80 as threshold values, respectively, can differentiate epsilon(1) and O2+3 rocks, and oil seepages show a natural affinity to the C-i source rocks. The epsilon(1) rocks have lighter delta C-13 of kerogen and heavier delta C-13 of group compositions than those of O2+3 rocks. The group compositions of oil seepages are depleted in C-13 by approximately 0-1.5 parts per thousand compared with kerogens of epsilon(1) extracts, further suggesting that the oil seepages are comparable to epsilon(1) source rocks consistent with the results of biomarker analysis.",2,2,4
Source Rocks,TARIM Basin,"Xu, Zhengjian; Liu, Luofu; Jiang, Shu; Wang, Tieguan; Wu, Kangjun; Feng, Yanjun; Xiao, Fei; Chen, Yingying; Chen, Yiting; Feng, Chenyang","Migration model of hydrocarbons in the slope of the superimposed foreland basin: A study from the South Junggar, NW China",Migration pathway; Migration drive; Migration direction; Migration timing; Slope; Superimposed foreland basin,CRUDE OILS; TARIM BASIN; CARBAZOLE DISTRIBUTIONS; PETROLEUM MIGRATION; SEDIMENTARY BASINS; NITROGEN-COMPOUNDS; SOURCE ROCKS; MATURITY; INCLUSIONS; BENZOCARBAZOLES,"The superimposed foreland basins mainly develop in central-western China, namely the Himalayan foreland basins superimposed on the Indo-China foreland basins. Previous research on hydrocarbon migration predominantly focused on the typical foreland basins and the fore-deep depression of superimposed foreland basins. As a result of multi-superimposition, large hydrocarbon potentials in the slope zones are evaluated, and the hydrocarbon migration shows significant differences with those in the typical foreland basins. Moreover, the hydrocarbon migration models in the slope zone of superimposed foreland basins are poor analyzed. The Chepaizi High in the South Junggar Basin, a typical slope of superimposed foreland basin, has been taken into consideration. Several points have been ascertained. 1) Multistage charging and readjustment events should be the predominant characters. 2) The combination of multi-type sand-bodies, multistage faults and unconformities have formed step-or ""Z""-shaped migration pathways spatially. 3) Hydrocarbons migrated from the areas of high oil potential in the fore-deep depression to those of low oil potential in the slope. 4) The migration models of the J(1)b, K(1)q, N(1)s(1), and N(1)s(2) have been established. Hydrocarbon reservoirs in the slope zones show the shallow accumulation from deep/ distal sources with multiple reservoirs vertically and multi-charging and -readjustments chronologically. 5) The areas of (Wells SM3, C53-C90, and CF2), (Wells SM5, C80, and CF13), and (Wells K8, HG4, SM4, and CF2) can be the favorable targets for the J(1)b, K(1)q, and N(1)s, respectively.",3,3,1
Source Rocks,TARIM Basin,"Yang, Zhe; Li, Meijun; Cheng, Dingsheng; Xiao, Hong; Lai, Hongfei; Chen, Qingyao",Geochemistry and possible origins of biodegraded oils in the Cretaceous reservoir of the Muglad Basin and their application in hydrocarbon exploration,Geochemical characteristics; Biodegraded oil; Cretaceous; Muglad basin; WCARS,ABU GABRA FORMATION; CRUDE OILS; ORGANIC-MATTER; TRIAROMATIC STEROIDS; PETROLEUM GEOLOGY; CRATONIC REGION; TARIM BASIN; SUDAN; DEGRADATION; ROCKS,"The Muglad Basin is one of the largest petroliferous basins within the Central and Western African Rift System (WCARS). A total of 42 oil samples including light, normal and heavy crude oils from the Cretaceous reservoirs of the Muglad Basin were systematically analyzed to fully understand their geochemical characteristics and possible origins. The results of oil-oil correlation show that these Cretaceous crude oils are genetically identical and derive from the same source kitchen. Differences in physical properties and geochemical compositions may be attributed to secondary alteration, such as biodegradation. Lightly, moderately and severely biodegraded oils can be divided on the basis of the relative abundance of n-alkanes and acyclic isoprenoids in the oils and the presence of ""humps"" on gas chromatogram baselines, as well as of the relative abundance of 25-norhopanes. The biodegradation degree of Cretaceous oils in the Muglad Basin is closely related to the burial depth of oil reservoirs and the distance between the locations of oil reservoirs and adjacent faults. This study may have practical application for further petroleum exploration and development in the Muglad Basin.",5,5,3
Source Rocks,Respect,"Vega, Bolivia; Kovscek, Anthony R.",A systematic study of internal gas generation in shale source rocks using analog experiments,Rock analog; Gelatin; Fracture; Shale; Source rock; Rock maturation,PRIMARY MIGRATION; GELATIN; PROPAGATION; OIL; MICROFRACTURES; VISUALIZATION; RHEOLOGY,"A two-dimensional Hele-Shaw cell was created to study and visualize hydrocarbon source rock (i.e., shale) elastic-brittle fracture and fracture network propagation mechanisms triggered by internal gas generation and gas build up during maturation of organic components. An analog immature source rock was created using a mixture of gelatin, sugar, and live yeast in pre-determined proportions. This mixture was poured into the Hele-Shaw cell and allowed to gel. The internal gas generated as a result of sugar fermentation by yeast caused pressure build up within the gel that ultimately resulted in the activation of dissipation mechanisms such as gas diffusion and deformation of the gel matrix. These mechanisms are analogous to shale maturation and fluid generation. Image analysis was employed to study and characterize key events such as fracture nucleation, propagation, and coalescence versus time. Derivative parameters such as fracture growth rate, fracture tip pressure, and fracture spatial distribution, among others, were calculated using the image-sourced data and applying Linear Elastic Fracture Mechanics (LEFM) principles. Results showed that the experiments are repeatable within a consistent response range and additional parameters were identified to be useful input for numerical modelling, including nucleation sites, fracture merging angle, merging to nucleation ratio, and fracture connectivity. For a volume of about 100 cm(3) of 11.6% wt food-grade gelatin solution with 0.25% wt. yeast and a sugar/yeast ratio of 3, measured average total gas production was 35 cm(3) (at standard conditions). On an average gelatin matrix area of 400 cm(2), the average total fracture length and fracture density are 106 cm and 0.15 fractures/cm(2), respectively. Average maximum calculated fracture tip pressure and maximum fracture velocity are 0.92 psi and 5.85 x 10(-4)cm/s, respectively. Fracture connectivity was more frequent in the second half of the gas generation process and greater for the older and longer fractures. Average final fracture spacing was 4.42 cm. Connection angles between fractures tended to be closer to 0 degrees than to 90 degrees. Photoelasticity imaging techniques were applied to the experimental setup to visualize the stress field within the sample. The difference of principal stresses was estimated at 3.70 x 10(3) Pa for the tested material late in the maturation process. Results suggest interdependence of gas pressure, gas diffusion, and transient stress field states. The range of laboratory-scaled data are useful as benchmarking parameters for numerical modelling of source rock maturation including geomechanics.",2,2,2
Source Rocks,Respect,"Zhou, Xiaoxiao; Lu, Xiuxiang; Song, Xu; Quan, Han; Chen, Kun; Qian, Wenwen; Wang, Zhao; Bai, Zhongkai; Zhang, Jie","Petroleum source of oil seepages in the Kalpin area, NW Tarim Basin, China",Source rock; Carbon isotopes; Biomarkers; Origin of oil seepages; Kalpin area,STABLE CARBON; SOURCE ROCKS; CRUDE OILS; ORGANOSULFUR COMPOUNDS; ISOTOPIC COMPOSITIONS; TAZHONG AREA; MARINE OILS; HYDROCARBON; BIODEGRADATION; SUBSURFACE,"Source rocks in Lower Cambrian (epsilon(1)) and Middle-Upper Ordovician (O2+3) have low S2 values, ranging from 0.01 to 0.34 and 0.01-5.95 mg HC/g Rock, respectively. The averages of TOC are 1.07% and 0.84% for epsilon(1) and O2+3 source rocks, respectively. The equivalent vitrinite reflectance values (VREs) indicate that epsilon(1) rocks are in a high-over mature stage for oil generation, and O-2+(3) rocks are sufficiently mature. Four oil seepages from the Yingshan Formation in the Qingsong quarry of the Aksu area and 34 core samples from epsilon(1) and O2+3 rocks in the Kalpin area were analyzed for stable carbon isotopes. Moreover, 4 oil seepages and 16 core samples were analyzed by gas chromatography-mass spectrometry (GC-MS). Compared with O2+3 rocks, epsilon(1) rocks are characterized by lower values of Gammacerane/C-30 hopane (G/H), C-28/(C-27 + C-28 + C-29) 20R alpha alpha alpha sterane (C-28%), C-29/(C-27 + C-28 + C-29 ) 20R alpha alpha alpha sterane (C-29%), C-26 20S/C-28 20S triaromatic steroids (C-26/C-28), (C-26 + C-27)/C-28 triaromatic steroids and (C-26 20R + C-27 20S)/C-28 20R triaromatic steroids, and higher values of C-21/C-23 tricyclic terpane (C-21/C-23), C-27/(C-27 + C-28 + C-29) 20R alpha alpha alpha sterane (C-27%), and C-35 alpha beta (22R + 22S) homohopane/alpha beta C-30 -hopane (C-35 H/H). The two sets of source rocks have a ""V (C-27 > C-28 < C-29)""-shaped regular sterane distribution pattern, and O2+3 rocks contain triaromatic steranes in abundances as high as those of epsilon(1) rocks. C-28-C-34 25-norhopanes (NHs) indicates that the degree of degradation of oil seepages falls at approximately PM 6, rendering many biomarker parameters ineffective for oil-source correlations, except for triaromatic steriods and carbon isotopic compositions. The values of C-26/C-28, (C-26 + C-27)/C-28 triaromatic steroids and (C-26 20R + C-27 20S)/C-28 20R triaromatic steroids using 0.50, 1.45 and 1.80 as threshold values, respectively, can differentiate epsilon(1) and O2+3 rocks, and oil seepages show a natural affinity to the C-i source rocks. The epsilon(1) rocks have lighter delta C-13 of kerogen and heavier delta C-13 of group compositions than those of O2+3 rocks. The group compositions of oil seepages are depleted in C-13 by approximately 0-1.5 parts per thousand compared with kerogens of epsilon(1) extracts, further suggesting that the oil seepages are comparable to epsilon(1) source rocks consistent with the results of biomarker analysis.",2,2,4
Source Rocks,Respect,"Xu, Zhengjian; Liu, Luofu; Jiang, Shu; Wang, Tieguan; Wu, Kangjun; Feng, Yanjun; Xiao, Fei; Chen, Yingying; Chen, Yiting; Feng, Chenyang","Migration model of hydrocarbons in the slope of the superimposed foreland basin: A study from the South Junggar, NW China",Migration pathway; Migration drive; Migration direction; Migration timing; Slope; Superimposed foreland basin,CRUDE OILS; TARIM BASIN; CARBAZOLE DISTRIBUTIONS; PETROLEUM MIGRATION; SEDIMENTARY BASINS; NITROGEN-COMPOUNDS; SOURCE ROCKS; MATURITY; INCLUSIONS; BENZOCARBAZOLES,"The superimposed foreland basins mainly develop in central-western China, namely the Himalayan foreland basins superimposed on the Indo-China foreland basins. Previous research on hydrocarbon migration predominantly focused on the typical foreland basins and the fore-deep depression of superimposed foreland basins. As a result of multi-superimposition, large hydrocarbon potentials in the slope zones are evaluated, and the hydrocarbon migration shows significant differences with those in the typical foreland basins. Moreover, the hydrocarbon migration models in the slope zone of superimposed foreland basins are poor analyzed. The Chepaizi High in the South Junggar Basin, a typical slope of superimposed foreland basin, has been taken into consideration. Several points have been ascertained. 1) Multistage charging and readjustment events should be the predominant characters. 2) The combination of multi-type sand-bodies, multistage faults and unconformities have formed step-or ""Z""-shaped migration pathways spatially. 3) Hydrocarbons migrated from the areas of high oil potential in the fore-deep depression to those of low oil potential in the slope. 4) The migration models of the J(1)b, K(1)q, N(1)s(1), and N(1)s(2) have been established. Hydrocarbon reservoirs in the slope zones show the shallow accumulation from deep/ distal sources with multiple reservoirs vertically and multi-charging and -readjustments chronologically. 5) The areas of (Wells SM3, C53-C90, and CF2), (Wells SM5, C80, and CF13), and (Wells K8, HG4, SM4, and CF2) can be the favorable targets for the J(1)b, K(1)q, and N(1)s, respectively.",3,3,1
Source Rocks,Thin Sections,"Zhang, Tianjiao; Zhang, Shanwen; Meng, Wei; Feng, Yuelin; An, Tianxia",Characteristics and genetic mechanism of carbonate cements in sandstones near the overpressure top surface: A case study of the Niuzhuang Depression in Bohai Bay Basin,Overpressure top surface; Carbonate cements; Carbon and oxygen isotope; Overpressured fluid; Sandstone reservoir,PORE-PRESSURE; RESERVOIR SANDSTONES; DIAGENETIC HISTORY; SHAHEJIE FORMATION; PART 1; ORIGIN; PETROLEUM; FIELD; COMPACTION; EVOLUTION,"Carbonate cements are important authigenic minerals in the sandstone reservoir near the overpressure top surface in the Niuzhuang Depression. However, their genetic mechanism has not been studied in detail. This study uses observations of casting thin sections and cathodoluminescence and micro-area electron probe compositional data to determine that the diagenetic sequence of these carbonate cements is penecontemporaneous dolomite -> calcite filling primary pores -> calcite/iron-bearing calcite filling secondary dissolution pores -> ankerite. The genetic mechanisms of these carbonate cements are analyzed based on the fluid inclusion temperature at different phases of carbonate cementation, carbon and oxygen isotope composition, simulation of the thermal evolution of the hydrocarbon source rock, and elemental chemical composition. Results show that the carbon isotopic compositions of the carbonate cements are affected not only by organic acids released during the maturation of organic matter but also by the dissolution of lacustrine carbonate rock in the fourth member of the Shahejie Formation. Dissolution-reprecipitation of the lacustrine carbonate rocks is responsible for an obvious positive drift in the delta C-13(PDB) values of carbonate cements near the overpressure top surface. There are four phases of carbonate cementation near the top surface of the overpressured zone, with phase IV carbonate cements mainly occurring near the overpressure top surface. Phase I carbonate cements are mainly dolomite, and their formation is related to the decomposition of organic matter by methanogenic bacteria. Phase II carbonate cements are related to Ca2+ and CO32- supersaturation during pore fluid concentration. Phase III carbonate cements result from overpressured fluid that is rich in Ca2+ and Mg2+ and feldspar dissolution caused by overpressure fluid intrusion. Phase IV carbonate cements are derived from CO32- formed by organic acid pyrolysis in late diagenesis, CO32- formed by early carbonate cement dissolution, and Mg2+ and Fe2+ plasma formed by the dissolution of metamorphic rock debris into pore fluid. The formation of phase III and IV carbonate cements is most affected by overpressured hydrocarbon fluids.",1,4,4
Source Rocks,Thin Sections,"Rubo, Rafael Andrello; Carneiro, Cleyton de Carvalho; Michelon, Mateus Fontana; Gioria, Rafael dos Santos",Digital petrography: Mineralogy and porosity identification using machine learning algorithms in petrographic thin section images,Image segmentation; Artificial neural networks; Random forest; Supervised learning; Optical mineralogy; Carbonate rocks,NETWORKS; LOGS,"Images represent a large and efficient source of geological information from oil exploration. To better analyze them, well-known machine learning algorithms are used to extract mineralogy and porosity data from petrographic thin section images. Microscopic petrographic analysis allows obtaining images from thin sections in the visible spectrum. They are used to evaluate depositional environments and diagenetic processes during the formation of sedimentary basins. However, that is an activity subjected to the petrographer's experience. Data from other sources, such as chemical microanalysis, provide quantitative information that might assist in petrographic evaluation, but they are expensive and time-consuming. The main objective is to create models that systematically interprets mineralogy and porosity from images acquired of optical microscopic analysis using machine learning algorithms, standardizing descriptions and reducing subjectivity and human errors during thin sections analysis. Image segmentation models are created with representative classes of the rocks' mineralogy and porosity. Datasets were selected from images originated from thin sections of carbonate rocks, which are prepared from sidewall core samples of oil wells, specifically from the pre-salt reservoirs of Santos Basin, on the southeast coast of Brazil. These models use discrete convolutional filters followed by artificial neural networks and random forest classifiers. A number of configurations were tested, using different convolutional filters and classifier's parameters. Five models were created: 1. mineralogical model using artificial neural network; 2. mineralogical model using random forest; 3. mineralogical model using random forest validated by chemical measurements; 4. porosity model using artificial neural networks; and 5. porosity model using random forest. They were evaluated through the use of 10-fold cross-validation tests and by correlation with chemical microanalysis. Correlation between the two technique's relative occurrences for each mineral phase shows a root mean square error of 8.99% and a coefficient of determination of 0.82. That demonstrates how well models can generalize.",5,5,4
Source Rocks,Porosity Model,"Panizza, Guido; Ravazzoli, Claudia",An efficient rock-physics workflow for modeling and inversion in anisotropic organic-shales,Shales; Rock physics; Anisotropy; Source rocks,ELASTIC-ANISOTROPY; ULTRASONIC VELOCITIES,"In this work we present a workflow for modeling and inversion of physical parameters using ultrasonic wave velocities measured on dry and saturated samples of Bakken, Bazhenov shales and Niobrara marls. The forward problem is based on the well known theory of Ciz and Shapiro (2007) combined with the anisotropic generalization of two empirical elastic models for the rock matrix: the critical porosity model Nur et al. (1998) and Krief et al. model (1990). Moreover, taking into account the high variability of the physical properties of kerogen and clay minerals, and their influence on the mechanical properties of these rocks, the procedure also involves the numerical inversion of such properties, using an efficient numerical routine. The results found for the effective elastic properties and density of clay minerals and kerogen are reasonable taking into account those published in the reference literature. In all cases the quality of fit between real and synthetic data is analysed by means of an adequate error measure. The stability of the predicted elastic coefficients is verified using strain energy restrictions. The calibrated models are also used to quantify the influence of the effective porosity on the computations and for a fluid substitution problem. Finally, we found that even for weak anisotropy the generalized Krief's model requires at least three empirical parameters. We conclude that our novel anisotropic critical porosity model is a simpler and more efficient choice for rock-physics applications.",5,5,0
Source Rocks,Porosity Model,"Rubo, Rafael Andrello; Carneiro, Cleyton de Carvalho; Michelon, Mateus Fontana; Gioria, Rafael dos Santos",Digital petrography: Mineralogy and porosity identification using machine learning algorithms in petrographic thin section images,Image segmentation; Artificial neural networks; Random forest; Supervised learning; Optical mineralogy; Carbonate rocks,NETWORKS; LOGS,"Images represent a large and efficient source of geological information from oil exploration. To better analyze them, well-known machine learning algorithms are used to extract mineralogy and porosity data from petrographic thin section images. Microscopic petrographic analysis allows obtaining images from thin sections in the visible spectrum. They are used to evaluate depositional environments and diagenetic processes during the formation of sedimentary basins. However, that is an activity subjected to the petrographer's experience. Data from other sources, such as chemical microanalysis, provide quantitative information that might assist in petrographic evaluation, but they are expensive and time-consuming. The main objective is to create models that systematically interprets mineralogy and porosity from images acquired of optical microscopic analysis using machine learning algorithms, standardizing descriptions and reducing subjectivity and human errors during thin sections analysis. Image segmentation models are created with representative classes of the rocks' mineralogy and porosity. Datasets were selected from images originated from thin sections of carbonate rocks, which are prepared from sidewall core samples of oil wells, specifically from the pre-salt reservoirs of Santos Basin, on the southeast coast of Brazil. These models use discrete convolutional filters followed by artificial neural networks and random forest classifiers. A number of configurations were tested, using different convolutional filters and classifier's parameters. Five models were created: 1. mineralogical model using artificial neural network; 2. mineralogical model using random forest; 3. mineralogical model using random forest validated by chemical measurements; 4. porosity model using artificial neural networks; and 5. porosity model using random forest. They were evaluated through the use of 10-fold cross-validation tests and by correlation with chemical microanalysis. Correlation between the two technique's relative occurrences for each mineral phase shows a root mean square error of 8.99% and a coefficient of determination of 0.82. That demonstrates how well models can generalize.",5,5,4
Source Rocks,Migration Pathway,"Wang, Wei; Jiang, Youlu; Yuan, Jing; Liu, Jingdong; Zhang, Shaomin; Swennen, Rudy","Characteristics and migration mechanisms of natural gas in tight sandstone reservoirs in the Longfengshan sag, Songliao Basin, China",Tight sandstone; Hydrocarbon migration; Phase fractionation; Lower cretaceous; Longfengshan sag,PETROLEUM; EVOLUTION; OIL; FRACTIONATION; ACCUMULATION; HYDROCARBONS; SYSTEM; PHASE,"To better understand gas migration and accumulation in tight sandstone reservoirs, we conducted an integrated petrographic and geochemical analysis of hydrocarbon and aqueous fluid inclusions. This analysis was combined with the burial and multistage hydrocarbon charging histories of the reservoir. The variability in the types of hydrocarbon inclusions in the tight sandstone reservoirs can be mapped to identify phase fractionation during burial and migration. The oil-bearing inclusions resulted from the heterogeneous capture of oil generated during the first hydrocarbon charging period, when the sandstones had not yet reached tight reservoir conditions. The gas-bearing inclusions in the tight sandstone reservoirs formed during the phase fractionation of dissolved and free gas due to unstable pressure conditions. The gas-bearing inclusions are characterized by a varying vapor volume fraction (phi(vap)). A higher proportion of gas-bearing inclusions with phi(vap )< 25% was observed near the source rock with TOC content > 1.2%. In contrast, in structural highs, a higher proportion of gas-water inclusions with phi(vap )> 25% was observed, demonstrating that phase fractionation occurred during migration. The GOI data suggest that the dissolved gas migration mainly occurred in the reservoir near the source rock with TOC content > 1.2%. The subsequent free gas separation in relation to upward migration and strata uplift caused free gas to migrate farther into the tight sandstone reservoir. Additionally, the gases displayed benzene/n-hexane ratio, methane and ethane delta C-13 values increasing initially, then decreasing along the migration pathway, recording the phase state evolution of the natural gas during the burial history of the reservoirs.",2,2,0
Source Rocks,Migration Pathway,"Xu, Zhengjian; Liu, Luofu; Jiang, Shu; Wang, Tieguan; Wu, Kangjun; Feng, Yanjun; Xiao, Fei; Chen, Yingying; Chen, Yiting; Feng, Chenyang","Migration model of hydrocarbons in the slope of the superimposed foreland basin: A study from the South Junggar, NW China",Migration pathway; Migration drive; Migration direction; Migration timing; Slope; Superimposed foreland basin,CRUDE OILS; TARIM BASIN; CARBAZOLE DISTRIBUTIONS; PETROLEUM MIGRATION; SEDIMENTARY BASINS; NITROGEN-COMPOUNDS; SOURCE ROCKS; MATURITY; INCLUSIONS; BENZOCARBAZOLES,"The superimposed foreland basins mainly develop in central-western China, namely the Himalayan foreland basins superimposed on the Indo-China foreland basins. Previous research on hydrocarbon migration predominantly focused on the typical foreland basins and the fore-deep depression of superimposed foreland basins. As a result of multi-superimposition, large hydrocarbon potentials in the slope zones are evaluated, and the hydrocarbon migration shows significant differences with those in the typical foreland basins. Moreover, the hydrocarbon migration models in the slope zone of superimposed foreland basins are poor analyzed. The Chepaizi High in the South Junggar Basin, a typical slope of superimposed foreland basin, has been taken into consideration. Several points have been ascertained. 1) Multistage charging and readjustment events should be the predominant characters. 2) The combination of multi-type sand-bodies, multistage faults and unconformities have formed step-or ""Z""-shaped migration pathways spatially. 3) Hydrocarbons migrated from the areas of high oil potential in the fore-deep depression to those of low oil potential in the slope. 4) The migration models of the J(1)b, K(1)q, N(1)s(1), and N(1)s(2) have been established. Hydrocarbon reservoirs in the slope zones show the shallow accumulation from deep/ distal sources with multiple reservoirs vertically and multi-charging and -readjustments chronologically. 5) The areas of (Wells SM3, C53-C90, and CF2), (Wells SM5, C80, and CF13), and (Wells K8, HG4, SM4, and CF2) can be the favorable targets for the J(1)b, K(1)q, and N(1)s, respectively.",3,3,1
Source Rocks,Isotope,"Zhang, Tianjiao; Zhang, Shanwen; Meng, Wei; Feng, Yuelin; An, Tianxia",Characteristics and genetic mechanism of carbonate cements in sandstones near the overpressure top surface: A case study of the Niuzhuang Depression in Bohai Bay Basin,Overpressure top surface; Carbonate cements; Carbon and oxygen isotope; Overpressured fluid; Sandstone reservoir,PORE-PRESSURE; RESERVOIR SANDSTONES; DIAGENETIC HISTORY; SHAHEJIE FORMATION; PART 1; ORIGIN; PETROLEUM; FIELD; COMPACTION; EVOLUTION,"Carbonate cements are important authigenic minerals in the sandstone reservoir near the overpressure top surface in the Niuzhuang Depression. However, their genetic mechanism has not been studied in detail. This study uses observations of casting thin sections and cathodoluminescence and micro-area electron probe compositional data to determine that the diagenetic sequence of these carbonate cements is penecontemporaneous dolomite -> calcite filling primary pores -> calcite/iron-bearing calcite filling secondary dissolution pores -> ankerite. The genetic mechanisms of these carbonate cements are analyzed based on the fluid inclusion temperature at different phases of carbonate cementation, carbon and oxygen isotope composition, simulation of the thermal evolution of the hydrocarbon source rock, and elemental chemical composition. Results show that the carbon isotopic compositions of the carbonate cements are affected not only by organic acids released during the maturation of organic matter but also by the dissolution of lacustrine carbonate rock in the fourth member of the Shahejie Formation. Dissolution-reprecipitation of the lacustrine carbonate rocks is responsible for an obvious positive drift in the delta C-13(PDB) values of carbonate cements near the overpressure top surface. There are four phases of carbonate cementation near the top surface of the overpressured zone, with phase IV carbonate cements mainly occurring near the overpressure top surface. Phase I carbonate cements are mainly dolomite, and their formation is related to the decomposition of organic matter by methanogenic bacteria. Phase II carbonate cements are related to Ca2+ and CO32- supersaturation during pore fluid concentration. Phase III carbonate cements result from overpressured fluid that is rich in Ca2+ and Mg2+ and feldspar dissolution caused by overpressure fluid intrusion. Phase IV carbonate cements are derived from CO32- formed by organic acid pyrolysis in late diagenesis, CO32- formed by early carbonate cement dissolution, and Mg2+ and Fe2+ plasma formed by the dissolution of metamorphic rock debris into pore fluid. The formation of phase III and IV carbonate cements is most affected by overpressured hydrocarbon fluids.",1,4,4
Source Rocks,Isotope,"Zhou, Xiaoxiao; Lu, Xiuxiang; Song, Xu; Quan, Han; Chen, Kun; Qian, Wenwen; Wang, Zhao; Bai, Zhongkai; Zhang, Jie","Petroleum source of oil seepages in the Kalpin area, NW Tarim Basin, China",Source rock; Carbon isotopes; Biomarkers; Origin of oil seepages; Kalpin area,STABLE CARBON; SOURCE ROCKS; CRUDE OILS; ORGANOSULFUR COMPOUNDS; ISOTOPIC COMPOSITIONS; TAZHONG AREA; MARINE OILS; HYDROCARBON; BIODEGRADATION; SUBSURFACE,"Source rocks in Lower Cambrian (epsilon(1)) and Middle-Upper Ordovician (O2+3) have low S2 values, ranging from 0.01 to 0.34 and 0.01-5.95 mg HC/g Rock, respectively. The averages of TOC are 1.07% and 0.84% for epsilon(1) and O2+3 source rocks, respectively. The equivalent vitrinite reflectance values (VREs) indicate that epsilon(1) rocks are in a high-over mature stage for oil generation, and O-2+(3) rocks are sufficiently mature. Four oil seepages from the Yingshan Formation in the Qingsong quarry of the Aksu area and 34 core samples from epsilon(1) and O2+3 rocks in the Kalpin area were analyzed for stable carbon isotopes. Moreover, 4 oil seepages and 16 core samples were analyzed by gas chromatography-mass spectrometry (GC-MS). Compared with O2+3 rocks, epsilon(1) rocks are characterized by lower values of Gammacerane/C-30 hopane (G/H), C-28/(C-27 + C-28 + C-29) 20R alpha alpha alpha sterane (C-28%), C-29/(C-27 + C-28 + C-29 ) 20R alpha alpha alpha sterane (C-29%), C-26 20S/C-28 20S triaromatic steroids (C-26/C-28), (C-26 + C-27)/C-28 triaromatic steroids and (C-26 20R + C-27 20S)/C-28 20R triaromatic steroids, and higher values of C-21/C-23 tricyclic terpane (C-21/C-23), C-27/(C-27 + C-28 + C-29) 20R alpha alpha alpha sterane (C-27%), and C-35 alpha beta (22R + 22S) homohopane/alpha beta C-30 -hopane (C-35 H/H). The two sets of source rocks have a ""V (C-27 > C-28 < C-29)""-shaped regular sterane distribution pattern, and O2+3 rocks contain triaromatic steranes in abundances as high as those of epsilon(1) rocks. C-28-C-34 25-norhopanes (NHs) indicates that the degree of degradation of oil seepages falls at approximately PM 6, rendering many biomarker parameters ineffective for oil-source correlations, except for triaromatic steriods and carbon isotopic compositions. The values of C-26/C-28, (C-26 + C-27)/C-28 triaromatic steroids and (C-26 20R + C-27 20S)/C-28 20R triaromatic steroids using 0.50, 1.45 and 1.80 as threshold values, respectively, can differentiate epsilon(1) and O2+3 rocks, and oil seepages show a natural affinity to the C-i source rocks. The epsilon(1) rocks have lighter delta C-13 of kerogen and heavier delta C-13 of group compositions than those of O2+3 rocks. The group compositions of oil seepages are depleted in C-13 by approximately 0-1.5 parts per thousand compared with kerogens of epsilon(1) extracts, further suggesting that the oil seepages are comparable to epsilon(1) source rocks consistent with the results of biomarker analysis.",2,2,4
Elastic Properties,Method,"Choi, Junhwan; Yoon, Daeung; Lee, Sigue; Byun, Joongmoo",Petrofacies characterization using best combination of multiple elastic properties,Petrofacies characterization; Class-Scatter-Matrix (CSM); Multivariate probability density function (PDF); Bayesian inference,,"Elastic properties such as P-impedance and the ratio of P-to S-wave velocity are key features for linking well log data to seismic data for reservoir characterization. Crossplotting methods from well log data are commonly applied to delineate the distribution of petrofacies on the seismic volume. However, only two or three elastic properties (two-or three-dimensional data) can be used in the crossplotting methods because of data visualization issues. Furthermore, the elastic properties used in the crossplotting method have to be chosen subjectively or empirically by a human interpreter. In this study, we propose a new workflow to overcome the limitations of conventional crossplotting methods. We use more than three elastic properties from well log data and apply non-linear transformations to the properties, to improve separability of the non-linear datasets. Then, we choose the best combination of the non-linear transformed elastic properties using class-scatter-matrix based separability measure. Lastly, Bayesian inference with multivariate probability density function (PDF) of petrofacies is performed to predict petrofacies probability volumes in the seismic area. An application to Vincent oil field data demonstrates the effectiveness of the proposed workflow. The accuracy improved from 80.7% to 86.2% and uncertainty is significantly reduced compared to the conventional workflow with crossplotting methods.",3,3,0
Elastic Properties,Method,"Lin, Zhenzhou; Dong, Huaimin; Pan, Heping; Sun, Jianmeng; Fang, Hui; Wang, Xiaojiang",Study on the equivalence between gas hydrate digital rocks and hydrate rock physical models,Gas hydrate; Filling modes; Rock physical model; Digital rock model; Equivalence analysis,LINEAR ELASTIC PROPERTIES; BEARING SEDIMENTS; QILIAN MOUNTAIN; WAVE VELOCITY; WELL LOGS; PERMAFROST; PERMEABILITY; SIMULATION,"According to the filling modes of gas hydrate in the permafrost, combined with rock physical method, two types of hydrate rock physical models are established by the method of elastic modulus model, including skeleton type hydrate rock physical model and fluid type hydrate rock physical model. Besides, based on the CT scanning images of hydrate reservoir rocks, combined with the numerical simulation method of hydrate distribution, two types of hydrate digital rock models are constructed, which correspond to the hydrate rock physical models. Firstly, time average equations are used to estimate several physical properties of hydrate rocks, the velocities of the hydrate rock are calculated on different models, in order to verify the equivalence between hydrate rock physical models and hydrate digital rock models, and compare the difference between different hydrate filling modes. Secondly, different models are applied to the characteristics analysis of hydrate reservoir rocks. Finally, the theoretical calculation curve is compared with the data of the actual sampling point of the hydrate reservoir, which used to the recognition of hydrate filling modes. It can be seen from the results that there is a good equivalence relationship between the hydrate rock physical models and hydrate digital rock models, and the filling modes of hydrate in this area is more in accordance with the skeleton type models, which means that this method can be used to determine the hydrate filling modes in hydrate reservoirs.",3,3,11
Elastic Properties,Method,"Nicolas-Lopez, Ruben; Valdiviezo-Mijangos, Oscar C.; Melendez-Martinez, Jaime; Levin, Valeriy M.",A multimineral Rock Physics Template built from the Perfectly Disordered Method for shale lithology interpretation,Rock Physics Templates; Perfectly Disordered Method; Self consistent method,MODEL; ATTENUATION; DISPERSION; INVERSION; MECHANICS; RESERVOIR,"In this work, we propose a simple micromechanical model called the Perfectly Disordered Method (PDM) to compute the effective elastic properties of a number of inhomogeneous shale rocks grouped according to their geological ages. This micromechanical model assumes no knowledge about the internal microstructure of these geological materials. Instead, elastic responses are solely computed from the mechanical properties of their comprising individual n minerals. Later, based on the presence of their main composing minerals, the obtained rock's elastic responses are overlapped on lambda-rho vs mu-rho lambda rho - mu rho ternary diagrams (also built by using the PDM) which vertices are either defined by a combination of quartz-feldspar-clay respectively or quartzcalcite-clay. The resulting overlaps generate multimineral Rock Physics Template's (RPTs) that are then used to assist in the lithological characterization of these sedimentary rocks. Identified lithologies include feldspathic siliceous shales as well as siliceous and calcareous shales. These results are comparable to those obtained by the implementation of a micromechanical model called the Self-Consistent Method (SCM) which in contrast requires information about the matrix's rock and their embedded inclusions. Further, the maximum percent errors found between the PDM and the SCM for lambda rho and mu rho up in the ternary diagrams are 3.18% and 6.56% respectively while for shales points the maximum errors for lambda rho and mu rho up are 5.17% and 10.09% respectively. These errors are negligible for practical applications. However, the main advantage of the PDM is that this model is easier to implement than SCM since PDM uses explicit equations to calculate effective properties unlike SCM that uses non-linear equations that must be solved by using iterative methods.",4,4,0
Elastic Properties,Method,"Zhu, Xiao-hua; Li, Bo",Numerical simulation of dynamic buckling response considering lateral vibration behaviors in drillstring,Mechanical behavior; Dynamic analysis; Buckling behavior; Finite element method; Critical length,,"Mechanical behavior of oilwell drillstring coming at the motions of penetrating rock is associated with drilling safety and wellbore quality. A poor performance can be attended by elastic stability loss in a slender drillstring exerting undesired buckling and vibration phenomena in the working process. Devoting to investigating the dynamic buckling behavior is an efficient way to avoid fatigue failure of the drillstring components and enhance drilling rate. A dynamic analysis of the buckling behavior of the entire column considering violent lateral vibrations is presented as a result available. Analytical equations of the drilling system are integrated numerically with finite element method. A virtual contact element implemented between the drillstring and the borehole, in conjunction with Hertzian contact assumption, gives the direct access to calculate the contact force and positions. Lateral deflection, critical length and the effects of drilling parameters and stabilizer on the buckling deformation are captured to experience the realistic buckling response of a typical drillstring in a vertical well. Simulation results indicate that spiral pitch and wave numbers of a nonlinear spiral shape prevailing in the lower zone of drillstring are deeply associated with the cutting force at the bit. Improving a drillstring behavior performance in a real oilfield is observed that this model can assist in evaluating the properties of the working security and buckling resistance with complex boundary conditions.",4,4,0
Elastic Properties,"Well Logs,Well-log Data","Choi, Junhwan; Yoon, Daeung; Lee, Sigue; Byun, Joongmoo",Petrofacies characterization using best combination of multiple elastic properties,Petrofacies characterization; Class-Scatter-Matrix (CSM); Multivariate probability density function (PDF); Bayesian inference,,"Elastic properties such as P-impedance and the ratio of P-to S-wave velocity are key features for linking well log data to seismic data for reservoir characterization. Crossplotting methods from well log data are commonly applied to delineate the distribution of petrofacies on the seismic volume. However, only two or three elastic properties (two-or three-dimensional data) can be used in the crossplotting methods because of data visualization issues. Furthermore, the elastic properties used in the crossplotting method have to be chosen subjectively or empirically by a human interpreter. In this study, we propose a new workflow to overcome the limitations of conventional crossplotting methods. We use more than three elastic properties from well log data and apply non-linear transformations to the properties, to improve separability of the non-linear datasets. Then, we choose the best combination of the non-linear transformed elastic properties using class-scatter-matrix based separability measure. Lastly, Bayesian inference with multivariate probability density function (PDF) of petrofacies is performed to predict petrofacies probability volumes in the seismic area. An application to Vincent oil field data demonstrates the effectiveness of the proposed workflow. The accuracy improved from 80.7% to 86.2% and uncertainty is significantly reduced compared to the conventional workflow with crossplotting methods.",3,3,0
Elastic Properties,"Well Logs,Well-log Data","Lin, Zhenzhou; Dong, Huaimin; Pan, Heping; Sun, Jianmeng; Fang, Hui; Wang, Xiaojiang",Study on the equivalence between gas hydrate digital rocks and hydrate rock physical models,Gas hydrate; Filling modes; Rock physical model; Digital rock model; Equivalence analysis,LINEAR ELASTIC PROPERTIES; BEARING SEDIMENTS; QILIAN MOUNTAIN; WAVE VELOCITY; WELL LOGS; PERMAFROST; PERMEABILITY; SIMULATION,"According to the filling modes of gas hydrate in the permafrost, combined with rock physical method, two types of hydrate rock physical models are established by the method of elastic modulus model, including skeleton type hydrate rock physical model and fluid type hydrate rock physical model. Besides, based on the CT scanning images of hydrate reservoir rocks, combined with the numerical simulation method of hydrate distribution, two types of hydrate digital rock models are constructed, which correspond to the hydrate rock physical models. Firstly, time average equations are used to estimate several physical properties of hydrate rocks, the velocities of the hydrate rock are calculated on different models, in order to verify the equivalence between hydrate rock physical models and hydrate digital rock models, and compare the difference between different hydrate filling modes. Secondly, different models are applied to the characteristics analysis of hydrate reservoir rocks. Finally, the theoretical calculation curve is compared with the data of the actual sampling point of the hydrate reservoir, which used to the recognition of hydrate filling modes. It can be seen from the results that there is a good equivalence relationship between the hydrate rock physical models and hydrate digital rock models, and the filling modes of hydrate in this area is more in accordance with the skeleton type models, which means that this method can be used to determine the hydrate filling modes in hydrate reservoirs.",3,3,11
Elastic Properties,"Well Logs,Well-log Data","Teixeira, Leonardo; Lupinacci, Wagner M.",Elastic properties of rock salt in the Santos Basin: Relations and spatial predictions,Rock salt; Evaporites; Santos basin; Elastic properties; Seismic inversion; Rock physics,WAVE VELOCITIES; TECTONICS; DEFORMATION; EVAPORITES; GEOLOGY; MODULI,"Most subsurface rock models consider salt bodies as homogenous masses and set to evaporite minerals constant values of elastic properties such as density, compressional and shear velocities, Young's modulus and Poisson's ratio. Lithological analyzes of outcrops and wells indicate that evaporites present large vertical and lateral heterogeneities. Recent studies have demonstrated that the knowledge of the elastic properties of rock salt can substantially benefit velocity modeling, seismic imaging, reservoir geomechanical analysis, prediction of well-bore stability and calculation of optimum fluid weight. However, few papers document the spatial estimation of elastic properties for salt formations. We propose an approach to characterize the internal structures of the salt bodies in the Santos Basin, offshore Brazil, using well and 3D seismic data. It starts with a rock-physics analysis at well-log scale, which reveals that the elastic properties of rock salt are highly correlated. Once the relationships of the elastic properties are established, we explore the functionality of the empirical equations as property predictors. We demonstrate that the elastic properties can be empirically estimated from compressional velocity. The comparison between the estimated and the measured well logs validates the estimation. Then, we perform the seismic inversion to generate the spatial distribution of the acoustic impedance. We derive compressional and shear velocities, density, Young's modulus and Poisson's ratio volumes by applying the empirical equations to the acoustic impedance volume. The blind well points out that, through this workflow, the seismic data can successfully predict the elastic properties of the salt formation in undrilled portions.",5,5,0
Elastic Properties,"Well Logs,Well-log Data","Janjuhah, Hammad Tariq; Alansari, Abubaker; Vintaned, Jose Antonio Gamez","Quantification of microporosity and its effect on permeability and acoustic velocity in Miocene carbonates, Central Luconia, offshore Sarawak, Malaysia",Central Luconia; Microporosity; Permeability; Acoustic velocity; Natural gas,DEPOSITIONAL-ENVIRONMENTS; RESERVOIR; CLASSIFICATION; POROSITY; PLATFORMS; MICRITE; HISTORY; BASIN; LOG,"Carbonate reservoirs are mostly considered to be complicated since in the petroleum industry, and because predicting the quality and achieving a high recovery factor from these rocks is challenging. Carbonate rocks have a complex porosity, which often leads to substantial uncertainty in prediction of permeability values for any particular porosity figure. The petrophysical analysis of carbonate reservoirs is and prone to more significant uncertainty. Pore size in carbonates rocks varies from micro to cave system scale. Carbonates with moldic and vuggy porosity usually contribute positively to the hydrocarbon production, yet sometimes these pores are mostly unconnected, thus yielding low flow rates, even though micropores form a high component of the total porosity of a reservoir. This study explores the reservoir properties of carbonate rocks of Central Luconia (Offshore Sarawak, eastern Malaysia), with emphasis on the relevance of microporosity on permeability and acoustic velocity relationships. A petrographic study of 260 samples obtained from the reservoir interval of Well A in the Central Luconia, Malaysia, was conducted to identify pore types (moldic, vuggy, interparticle, intraparticle and fractures) and measure porosity (ranging from 4 to 25%). For microporosity quantification, an enhanced workflow is introduced using the Digital Image Analysis (DIA) technique, where 32 petrographic images of each thin sections were taken under the transmitted light microscope that covers the entire thin section. The DIA technique was then implemented on these petrographic images to quantify the amount of macroporosity. After that, the microporosity was calculated in the following way: the difference in value between the observed macroporosity using DIA, and the total porosity measured on core plugs. Finally, the resulting amount of microporosity was then correlated with acoustic velocity and permeability to determine if significant improvement is achieved in the coefficient of determination (R-2). Moreover, it has increased from 0.55 to 0.67 for the permeability and from 0.61 to 0.87 for the acoustic velocity. The analysis also highlights that those samples with more substantial pores and a high figure ( > 50% of total porosity) of microporosity exhibit slower acoustic velocity for both P and S waves. Also, this study proposed a simple predictive model of elastic properties in the Central Luconian Miocene carbonate, Malaysia.",5,6,0
Elastic Properties,Inversion,"Nicolas-Lopez, Ruben; Valdiviezo-Mijangos, Oscar C.; Melendez-Martinez, Jaime; Levin, Valeriy M.",A multimineral Rock Physics Template built from the Perfectly Disordered Method for shale lithology interpretation,Rock Physics Templates; Perfectly Disordered Method; Self consistent method,MODEL; ATTENUATION; DISPERSION; INVERSION; MECHANICS; RESERVOIR,"In this work, we propose a simple micromechanical model called the Perfectly Disordered Method (PDM) to compute the effective elastic properties of a number of inhomogeneous shale rocks grouped according to their geological ages. This micromechanical model assumes no knowledge about the internal microstructure of these geological materials. Instead, elastic responses are solely computed from the mechanical properties of their comprising individual n minerals. Later, based on the presence of their main composing minerals, the obtained rock's elastic responses are overlapped on lambda-rho vs mu-rho lambda rho - mu rho ternary diagrams (also built by using the PDM) which vertices are either defined by a combination of quartz-feldspar-clay respectively or quartzcalcite-clay. The resulting overlaps generate multimineral Rock Physics Template's (RPTs) that are then used to assist in the lithological characterization of these sedimentary rocks. Identified lithologies include feldspathic siliceous shales as well as siliceous and calcareous shales. These results are comparable to those obtained by the implementation of a micromechanical model called the Self-Consistent Method (SCM) which in contrast requires information about the matrix's rock and their embedded inclusions. Further, the maximum percent errors found between the PDM and the SCM for lambda rho and mu rho up in the ternary diagrams are 3.18% and 6.56% respectively while for shales points the maximum errors for lambda rho and mu rho up are 5.17% and 10.09% respectively. These errors are negligible for practical applications. However, the main advantage of the PDM is that this model is easier to implement than SCM since PDM uses explicit equations to calculate effective properties unlike SCM that uses non-linear equations that must be solved by using iterative methods.",4,4,0
Elastic Properties,Inversion,"Panizza, Guido; Ravazzoli, Claudia",An efficient rock-physics workflow for modeling and inversion in anisotropic organic-shales,Shales; Rock physics; Anisotropy; Source rocks,ELASTIC-ANISOTROPY; ULTRASONIC VELOCITIES,"In this work we present a workflow for modeling and inversion of physical parameters using ultrasonic wave velocities measured on dry and saturated samples of Bakken, Bazhenov shales and Niobrara marls. The forward problem is based on the well known theory of Ciz and Shapiro (2007) combined with the anisotropic generalization of two empirical elastic models for the rock matrix: the critical porosity model Nur et al. (1998) and Krief et al. model (1990). Moreover, taking into account the high variability of the physical properties of kerogen and clay minerals, and their influence on the mechanical properties of these rocks, the procedure also involves the numerical inversion of such properties, using an efficient numerical routine. The results found for the effective elastic properties and density of clay minerals and kerogen are reasonable taking into account those published in the reference literature. In all cases the quality of fit between real and synthetic data is analysed by means of an adequate error measure. The stability of the predicted elastic coefficients is verified using strain energy restrictions. The calibrated models are also used to quantify the influence of the effective porosity on the computations and for a fluid substitution problem. Finally, we found that even for weak anisotropy the generalized Krief's model requires at least three empirical parameters. We conclude that our novel anisotropic critical porosity model is a simpler and more efficient choice for rock-physics applications.",5,5,0
Elastic Properties,Inversion,"Teixeira, Leonardo; Lupinacci, Wagner M.",Elastic properties of rock salt in the Santos Basin: Relations and spatial predictions,Rock salt; Evaporites; Santos basin; Elastic properties; Seismic inversion; Rock physics,WAVE VELOCITIES; TECTONICS; DEFORMATION; EVAPORITES; GEOLOGY; MODULI,"Most subsurface rock models consider salt bodies as homogenous masses and set to evaporite minerals constant values of elastic properties such as density, compressional and shear velocities, Young's modulus and Poisson's ratio. Lithological analyzes of outcrops and wells indicate that evaporites present large vertical and lateral heterogeneities. Recent studies have demonstrated that the knowledge of the elastic properties of rock salt can substantially benefit velocity modeling, seismic imaging, reservoir geomechanical analysis, prediction of well-bore stability and calculation of optimum fluid weight. However, few papers document the spatial estimation of elastic properties for salt formations. We propose an approach to characterize the internal structures of the salt bodies in the Santos Basin, offshore Brazil, using well and 3D seismic data. It starts with a rock-physics analysis at well-log scale, which reveals that the elastic properties of rock salt are highly correlated. Once the relationships of the elastic properties are established, we explore the functionality of the empirical equations as property predictors. We demonstrate that the elastic properties can be empirically estimated from compressional velocity. The comparison between the estimated and the measured well logs validates the estimation. Then, we perform the seismic inversion to generate the spatial distribution of the acoustic impedance. We derive compressional and shear velocities, density, Young's modulus and Poisson's ratio volumes by applying the empirical equations to the acoustic impedance volume. The blind well points out that, through this workflow, the seismic data can successfully predict the elastic properties of the salt formation in undrilled portions.",5,5,0
Elastic Properties,Hydrate,"Lin, Zhenzhou; Dong, Huaimin; Pan, Heping; Sun, Jianmeng; Fang, Hui; Wang, Xiaojiang",Study on the equivalence between gas hydrate digital rocks and hydrate rock physical models,Gas hydrate; Filling modes; Rock physical model; Digital rock model; Equivalence analysis,LINEAR ELASTIC PROPERTIES; BEARING SEDIMENTS; QILIAN MOUNTAIN; WAVE VELOCITY; WELL LOGS; PERMAFROST; PERMEABILITY; SIMULATION,"According to the filling modes of gas hydrate in the permafrost, combined with rock physical method, two types of hydrate rock physical models are established by the method of elastic modulus model, including skeleton type hydrate rock physical model and fluid type hydrate rock physical model. Besides, based on the CT scanning images of hydrate reservoir rocks, combined with the numerical simulation method of hydrate distribution, two types of hydrate digital rock models are constructed, which correspond to the hydrate rock physical models. Firstly, time average equations are used to estimate several physical properties of hydrate rocks, the velocities of the hydrate rock are calculated on different models, in order to verify the equivalence between hydrate rock physical models and hydrate digital rock models, and compare the difference between different hydrate filling modes. Secondly, different models are applied to the characteristics analysis of hydrate reservoir rocks. Finally, the theoretical calculation curve is compared with the data of the actual sampling point of the hydrate reservoir, which used to the recognition of hydrate filling modes. It can be seen from the results that there is a good equivalence relationship between the hydrate rock physical models and hydrate digital rock models, and the filling modes of hydrate in this area is more in accordance with the skeleton type models, which means that this method can be used to determine the hydrate filling modes in hydrate reservoirs.",3,3,11
Elastic Properties,Hydrate,"Zhang, Yayun; Gao, Shuyang; Du, Xiaoyu; Chen, Mian; Jin, Yan",Molecular dynamics simulation of strength weakening mechanism of deep shale,Deep shale; Montmorillonite; Hydration; Molecular dynamic simulation; Conduction characteristics; Strength weakening,MONTE-CARLO-SIMULATION; ELASTIC PROPERTIES; K-MONTMORILLONITE; INTERLAYER STRUCTURE; COMPUTER-SIMULATION; WELLBORE STABILITY; NA-MONTMORILLONITE; CA-MONTMORILLONITE; HYDRATED LI; WATER,"Due to the dissimilarities in the hydration characteristics and degree of clay minerals, the wellbore instability and sloughing of deep shale is more sudden and destructive than that of the shallow shale. Previous works mainly consider the effects of temperature and pressure condition on the wellbore instability of deep shale at macroscopic scale, and ignore the microscopic mechanism of strength weakening during hydration and the evolution characteristics of montmorillonite(MMT) hydration under different isomorphic substitutions, temperature and pressure conditions. By considering the characteristics of clay minerals and drilling fluids in deep shales, the molecular dynamics simulations of MMT hydration in deep shale under different isomorphic substitutions, water content, temperature and pressure conditions were carried out to analyze the distribution and conduction evolution characteristics of water molecules and cations, and the response characteristics of crystal elastic parameters during the hydration process. The results indicate that: (1) As the water content increases, the interlayer spacing increases, but it is less sensitive to the temperature and pressure. Moreover, with the increase of water content, water molecules and ions are accelerated to intrude into crystal layer, and the hydration effects are enhanced and the weakening effects on rock strength are increased as well. (2) Both temperature and pressure have significant influences on the hydration characteristics of MMT, but the influential trends are opposite. Increasing temperature promotes the invasion of water molecules and sodium ions into the crystal layer so as to enhance the hydration, the weakening effect on rock strength becomes more remarkable. On the contrary, with the increase of pressure, the diffusion coefficient of water molecules and sodium ions to interlayer decreases which inhibits the weakening effect of clay hydration. (3) The differences of hydration characteristics of MMT with typical isomorphic substitutions are significant. The hydration ability of sodium ion in Fe-substituted MMT was weaker and the diffusion coefficient of water molecules was larger, so that water molecules more easily invade into the crystal layer, and the strength weakening is more significant than that of the Mg-substituted MMT system. Furthermore, the weakening effect is more significant under high temperature and low pressure conditions. The microscopic dynamic mechanism of clay hydration in deep shale can be throughly understood through molecular dynamics simulation, which provides an innovative research approach for the quantitative evaluation of drilling fluid hydration inhibition and microscopic control of clay hydration in deep shale.",4,4,3
Elastic Properties,Kerogen,"Panizza, Guido; Ravazzoli, Claudia",An efficient rock-physics workflow for modeling and inversion in anisotropic organic-shales,Shales; Rock physics; Anisotropy; Source rocks,ELASTIC-ANISOTROPY; ULTRASONIC VELOCITIES,"In this work we present a workflow for modeling and inversion of physical parameters using ultrasonic wave velocities measured on dry and saturated samples of Bakken, Bazhenov shales and Niobrara marls. The forward problem is based on the well known theory of Ciz and Shapiro (2007) combined with the anisotropic generalization of two empirical elastic models for the rock matrix: the critical porosity model Nur et al. (1998) and Krief et al. model (1990). Moreover, taking into account the high variability of the physical properties of kerogen and clay minerals, and their influence on the mechanical properties of these rocks, the procedure also involves the numerical inversion of such properties, using an efficient numerical routine. The results found for the effective elastic properties and density of clay minerals and kerogen are reasonable taking into account those published in the reference literature. In all cases the quality of fit between real and synthetic data is analysed by means of an adequate error measure. The stability of the predicted elastic coefficients is verified using strain energy restrictions. The calibrated models are also used to quantify the influence of the effective porosity on the computations and for a fluid substitution problem. Finally, we found that even for weak anisotropy the generalized Krief's model requires at least three empirical parameters. We conclude that our novel anisotropic critical porosity model is a simpler and more efficient choice for rock-physics applications.",5,5,0
Elastic Properties,Kerogen,"Han, Xuehui; Nie, Junguang; Guo, Junxin; Yang, Long; Xu, Denghui",Rock physics modelling of elastic properties of organic shale considering kerogen stress and pore pressure distribution,Organic shale; Kerogen stress; Pore pressure; Elastic properties,WAVE-FIELD; MEDIA; PROPAGATION; ORIENTATION; ANISOTROPY; VELOCITY,"Rock physics model for the elastic properties of organic shale is important for shale oil/gas exploration and production. Up until now, little work has been done to investigate the influence of the distributions of the stress in kerogen (kerogen stress) and the pore pressure on the elastic properties of organic shale. In this work, we used the Kuster- Toksoz (KT) model and Gassmann equation to study such effects. The Gassmann equation was applied for the homogeneous kerogen stress or pore pressure case whereas KT model was suitable for the inhomogeneous case. Four cases with different combinations of kerogen stress and pore pressure distributions, for the elastic properties of organic shale, were analysed and the corresponding models were given. Based on these models, a numerical example was studied. The results showed that the distributions of kerogen stress and pore pressure significantly affect the elastic properties of organic shale. The elastic moduli under the inhomogeneous kerogen stress or pore pressure distributions are larger than the homogeneous case, whose magnitude depends on porosity and kerogen content. Furthermore, the joint effects of kerogen stress and pore pressure distributions are similar to those of kerogen stress due to the much smaller effects of pore pressure. Hence, it is essential to consider the effects of the distributions of kerogen stress and pore pressure when building the rock physics model for the elastic properties of organic shale. This work revealed the importance of kerogen stress and pore pressure distributions on the elastic properties of organic shale and hence is helpful for the shale oil/gas exploration and production.",5,5,2
Elastic Properties,Pores,"Janjuhah, Hammad Tariq; Alansari, Abubaker; Vintaned, Jose Antonio Gamez","Quantification of microporosity and its effect on permeability and acoustic velocity in Miocene carbonates, Central Luconia, offshore Sarawak, Malaysia",Central Luconia; Microporosity; Permeability; Acoustic velocity; Natural gas,DEPOSITIONAL-ENVIRONMENTS; RESERVOIR; CLASSIFICATION; POROSITY; PLATFORMS; MICRITE; HISTORY; BASIN; LOG,"Carbonate reservoirs are mostly considered to be complicated since in the petroleum industry, and because predicting the quality and achieving a high recovery factor from these rocks is challenging. Carbonate rocks have a complex porosity, which often leads to substantial uncertainty in prediction of permeability values for any particular porosity figure. The petrophysical analysis of carbonate reservoirs is and prone to more significant uncertainty. Pore size in carbonates rocks varies from micro to cave system scale. Carbonates with moldic and vuggy porosity usually contribute positively to the hydrocarbon production, yet sometimes these pores are mostly unconnected, thus yielding low flow rates, even though micropores form a high component of the total porosity of a reservoir. This study explores the reservoir properties of carbonate rocks of Central Luconia (Offshore Sarawak, eastern Malaysia), with emphasis on the relevance of microporosity on permeability and acoustic velocity relationships. A petrographic study of 260 samples obtained from the reservoir interval of Well A in the Central Luconia, Malaysia, was conducted to identify pore types (moldic, vuggy, interparticle, intraparticle and fractures) and measure porosity (ranging from 4 to 25%). For microporosity quantification, an enhanced workflow is introduced using the Digital Image Analysis (DIA) technique, where 32 petrographic images of each thin sections were taken under the transmitted light microscope that covers the entire thin section. The DIA technique was then implemented on these petrographic images to quantify the amount of macroporosity. After that, the microporosity was calculated in the following way: the difference in value between the observed macroporosity using DIA, and the total porosity measured on core plugs. Finally, the resulting amount of microporosity was then correlated with acoustic velocity and permeability to determine if significant improvement is achieved in the coefficient of determination (R-2). Moreover, it has increased from 0.55 to 0.67 for the permeability and from 0.61 to 0.87 for the acoustic velocity. The analysis also highlights that those samples with more substantial pores and a high figure ( > 50% of total porosity) of microporosity exhibit slower acoustic velocity for both P and S waves. Also, this study proposed a simple predictive model of elastic properties in the Central Luconian Miocene carbonate, Malaysia.",5,6,0
Elastic Properties,Pores,"Han, Xuehui; Nie, Junguang; Guo, Junxin; Yang, Long; Xu, Denghui",Rock physics modelling of elastic properties of organic shale considering kerogen stress and pore pressure distribution,Organic shale; Kerogen stress; Pore pressure; Elastic properties,WAVE-FIELD; MEDIA; PROPAGATION; ORIENTATION; ANISOTROPY; VELOCITY,"Rock physics model for the elastic properties of organic shale is important for shale oil/gas exploration and production. Up until now, little work has been done to investigate the influence of the distributions of the stress in kerogen (kerogen stress) and the pore pressure on the elastic properties of organic shale. In this work, we used the Kuster- Toksoz (KT) model and Gassmann equation to study such effects. The Gassmann equation was applied for the homogeneous kerogen stress or pore pressure case whereas KT model was suitable for the inhomogeneous case. Four cases with different combinations of kerogen stress and pore pressure distributions, for the elastic properties of organic shale, were analysed and the corresponding models were given. Based on these models, a numerical example was studied. The results showed that the distributions of kerogen stress and pore pressure significantly affect the elastic properties of organic shale. The elastic moduli under the inhomogeneous kerogen stress or pore pressure distributions are larger than the homogeneous case, whose magnitude depends on porosity and kerogen content. Furthermore, the joint effects of kerogen stress and pore pressure distributions are similar to those of kerogen stress due to the much smaller effects of pore pressure. Hence, it is essential to consider the effects of the distributions of kerogen stress and pore pressure when building the rock physics model for the elastic properties of organic shale. This work revealed the importance of kerogen stress and pore pressure distributions on the elastic properties of organic shale and hence is helpful for the shale oil/gas exploration and production.",5,5,2
Elastic Properties,Failure,"McKean, Scott H.; Priest, Jeffrey A.",Multiple failure state triaxial testing of the Montney Formation,Unconventional reservoir geomechanics; Multiple failure state; Triaxial test; Elastic anisotropy; Post-peak behaviour; Failure envelope; Montney Formation,ROCK; STRENGTH,"Elastic behaviour controls hydraulic fracture propagation and ultimately, the productivity of unconventional reservoirs. Various index tests and single stage triaxial tests are used to characterize elastic moduli but it can be difficult to obtain enough samples and sufficient information. This is partly due to the fissile nature of shales, which results in a paucity of representative core plugs. It is also partially due to the complex and heterogeneous nature of unconventional reservoir's geomechanical behaviour. The failure mechanics of unconventional rocks are poorly understood and seldom incorporated in hydraulic fracturing or geomechanical models. Yet, failure is major influence on fracture complexity and reservoir drainage volumes. The objectives of this study were to evaluate the variability in geomechanical properties and characterize the post-peak behaviour of a stiff siltstone from the Montney Formation in Alberta, Canada. The multiple failure state triaxial test was used to define the pre-peak elastic behaviour, post-peak behaviour, and failure envelope of a single core plug. This is beneficial for practitioners that are faced with a paucity of samples. The multiple failure state triaxial test is difficult to implement for stiff specimens, which fail in a brittle and unstable manner and a methodology to improve the stability near and beyond sample failure was therefore developed. The results from this study, which were also compared to various index tests and publicly available data, show that the samples had low porosity, low clay, and high stiffness. Significant variability in elastic behaviour was observed due to non-linearities in the loading curve - an effect that overshadowed changes due to confining pressure and highlighted that need for careful consideration of elastic parameter variability. Several oriented samples sets were used to characterize elastic and strength anisotropy. The improved test methodology was able to capture stable post-peak behaviour on almost all the tested samples. Brittle stick-slip failure was observed and an exponential model for approximating post-peak behaviour was presented. The combination of triaxial testing and index testing was able to completely characterize the constitutive law and failure envelope of the samples, save the Biot coefficient. These results can be incorporated into both routine and advanced geomechanical models and hydraulic fracturing simulators.",2,2,1
Elastic Properties,Failure,"Zhu, Xiao-hua; Li, Bo",Numerical simulation of dynamic buckling response considering lateral vibration behaviors in drillstring,Mechanical behavior; Dynamic analysis; Buckling behavior; Finite element method; Critical length,,"Mechanical behavior of oilwell drillstring coming at the motions of penetrating rock is associated with drilling safety and wellbore quality. A poor performance can be attended by elastic stability loss in a slender drillstring exerting undesired buckling and vibration phenomena in the working process. Devoting to investigating the dynamic buckling behavior is an efficient way to avoid fatigue failure of the drillstring components and enhance drilling rate. A dynamic analysis of the buckling behavior of the entire column considering violent lateral vibrations is presented as a result available. Analytical equations of the drilling system are integrated numerically with finite element method. A virtual contact element implemented between the drillstring and the borehole, in conjunction with Hertzian contact assumption, gives the direct access to calculate the contact force and positions. Lateral deflection, critical length and the effects of drilling parameters and stabilizer on the buckling deformation are captured to experience the realistic buckling response of a typical drillstring in a vertical well. Simulation results indicate that spiral pitch and wave numbers of a nonlinear spiral shape prevailing in the lower zone of drillstring are deeply associated with the cutting force at the bit. Improving a drillstring behavior performance in a real oilfield is observed that this model can assist in evaluating the properties of the working security and buckling resistance with complex boundary conditions.",4,4,0
Elastic Properties,Tests,"McKean, Scott H.; Priest, Jeffrey A.",Multiple failure state triaxial testing of the Montney Formation,Unconventional reservoir geomechanics; Multiple failure state; Triaxial test; Elastic anisotropy; Post-peak behaviour; Failure envelope; Montney Formation,ROCK; STRENGTH,"Elastic behaviour controls hydraulic fracture propagation and ultimately, the productivity of unconventional reservoirs. Various index tests and single stage triaxial tests are used to characterize elastic moduli but it can be difficult to obtain enough samples and sufficient information. This is partly due to the fissile nature of shales, which results in a paucity of representative core plugs. It is also partially due to the complex and heterogeneous nature of unconventional reservoir's geomechanical behaviour. The failure mechanics of unconventional rocks are poorly understood and seldom incorporated in hydraulic fracturing or geomechanical models. Yet, failure is major influence on fracture complexity and reservoir drainage volumes. The objectives of this study were to evaluate the variability in geomechanical properties and characterize the post-peak behaviour of a stiff siltstone from the Montney Formation in Alberta, Canada. The multiple failure state triaxial test was used to define the pre-peak elastic behaviour, post-peak behaviour, and failure envelope of a single core plug. This is beneficial for practitioners that are faced with a paucity of samples. The multiple failure state triaxial test is difficult to implement for stiff specimens, which fail in a brittle and unstable manner and a methodology to improve the stability near and beyond sample failure was therefore developed. The results from this study, which were also compared to various index tests and publicly available data, show that the samples had low porosity, low clay, and high stiffness. Significant variability in elastic behaviour was observed due to non-linearities in the loading curve - an effect that overshadowed changes due to confining pressure and highlighted that need for careful consideration of elastic parameter variability. Several oriented samples sets were used to characterize elastic and strength anisotropy. The improved test methodology was able to capture stable post-peak behaviour on almost all the tested samples. Brittle stick-slip failure was observed and an exponential model for approximating post-peak behaviour was presented. The combination of triaxial testing and index testing was able to completely characterize the constitutive law and failure envelope of the samples, save the Biot coefficient. These results can be incorporated into both routine and advanced geomechanical models and hydraulic fracturing simulators.",2,2,1
Elastic Properties,Tests,"Zhao, Xinrui; Sun, Xindi; Zhang, Jihong; Bai, Baojun",Gel composition and brine concentration effect on hydrogel dehydration subjected to uniaxial compression,Compression; Conformance control; Hydrogel; Gel dehydration,PREFORMED PARTICLE GELS; MONOMER CONCENTRATION; ELASTIC-MODULUS; EXTRUSION,"Gel treatment is a process that injects the gel into a reservoir to control the conformance and improve the sweep efficiency of injection fluids. At a certain pressure gradient, the gel dehydrates in a reservoir due to mechanical forces. This work evaluates the effects of the gel composition and brine concentration on gel dehydration under uniaxial compression. A sodium acrylate-co-acrylamide based gel cross-linked with N, N'-Methylenebisacrylamide (MBAA) was used for the study. The compression test is performed with a rheometer with a plate-plate geometry. The gel dehydration under pressure was measured to see how gel dehydration would be impacted by the brine concentration or the change in gel compositions including monomer and crosslinker concentration. Then, the elastic modulus (G') and the loss modulus (G '') of the gels before and after the compression were measured. This process aimed to assess the variations of the gel mechanical properties caused by compression-induced dehydration. The result shows the gel composition has a great impact on the gel dehydration under uni-axial compression. The amount of gel dehydration increases when gel swelling degree increases for all experimental factors. The gel after compression has a lower G' and a higher G '' compared with the gel before compression, indicating damage on gel networks. This work is of significance on optimizing gel treatments for conformance control.",5,5,4
Elastic Properties,Geomechanical,"McKean, Scott H.; Priest, Jeffrey A.",Multiple failure state triaxial testing of the Montney Formation,Unconventional reservoir geomechanics; Multiple failure state; Triaxial test; Elastic anisotropy; Post-peak behaviour; Failure envelope; Montney Formation,ROCK; STRENGTH,"Elastic behaviour controls hydraulic fracture propagation and ultimately, the productivity of unconventional reservoirs. Various index tests and single stage triaxial tests are used to characterize elastic moduli but it can be difficult to obtain enough samples and sufficient information. This is partly due to the fissile nature of shales, which results in a paucity of representative core plugs. It is also partially due to the complex and heterogeneous nature of unconventional reservoir's geomechanical behaviour. The failure mechanics of unconventional rocks are poorly understood and seldom incorporated in hydraulic fracturing or geomechanical models. Yet, failure is major influence on fracture complexity and reservoir drainage volumes. The objectives of this study were to evaluate the variability in geomechanical properties and characterize the post-peak behaviour of a stiff siltstone from the Montney Formation in Alberta, Canada. The multiple failure state triaxial test was used to define the pre-peak elastic behaviour, post-peak behaviour, and failure envelope of a single core plug. This is beneficial for practitioners that are faced with a paucity of samples. The multiple failure state triaxial test is difficult to implement for stiff specimens, which fail in a brittle and unstable manner and a methodology to improve the stability near and beyond sample failure was therefore developed. The results from this study, which were also compared to various index tests and publicly available data, show that the samples had low porosity, low clay, and high stiffness. Significant variability in elastic behaviour was observed due to non-linearities in the loading curve - an effect that overshadowed changes due to confining pressure and highlighted that need for careful consideration of elastic parameter variability. Several oriented samples sets were used to characterize elastic and strength anisotropy. The improved test methodology was able to capture stable post-peak behaviour on almost all the tested samples. Brittle stick-slip failure was observed and an exponential model for approximating post-peak behaviour was presented. The combination of triaxial testing and index testing was able to completely characterize the constitutive law and failure envelope of the samples, save the Biot coefficient. These results can be incorporated into both routine and advanced geomechanical models and hydraulic fracturing simulators.",2,2,1
Elastic Properties,Geomechanical,"Teixeira, Leonardo; Lupinacci, Wagner M.",Elastic properties of rock salt in the Santos Basin: Relations and spatial predictions,Rock salt; Evaporites; Santos basin; Elastic properties; Seismic inversion; Rock physics,WAVE VELOCITIES; TECTONICS; DEFORMATION; EVAPORITES; GEOLOGY; MODULI,"Most subsurface rock models consider salt bodies as homogenous masses and set to evaporite minerals constant values of elastic properties such as density, compressional and shear velocities, Young's modulus and Poisson's ratio. Lithological analyzes of outcrops and wells indicate that evaporites present large vertical and lateral heterogeneities. Recent studies have demonstrated that the knowledge of the elastic properties of rock salt can substantially benefit velocity modeling, seismic imaging, reservoir geomechanical analysis, prediction of well-bore stability and calculation of optimum fluid weight. However, few papers document the spatial estimation of elastic properties for salt formations. We propose an approach to characterize the internal structures of the salt bodies in the Santos Basin, offshore Brazil, using well and 3D seismic data. It starts with a rock-physics analysis at well-log scale, which reveals that the elastic properties of rock salt are highly correlated. Once the relationships of the elastic properties are established, we explore the functionality of the empirical equations as property predictors. We demonstrate that the elastic properties can be empirically estimated from compressional velocity. The comparison between the estimated and the measured well logs validates the estimation. Then, we perform the seismic inversion to generate the spatial distribution of the acoustic impedance. We derive compressional and shear velocities, density, Young's modulus and Poisson's ratio volumes by applying the empirical equations to the acoustic impedance volume. The blind well points out that, through this workflow, the seismic data can successfully predict the elastic properties of the salt formation in undrilled portions.",5,5,0
Drill String,,"Sanchez, Luis; Lapo, Miguel; Zorrilla, Octavio",Torque and drag analysis of a drill string using Sequential Monte Carlos methods,Directional drill string; Torque and drag phenomenon; Unscented kalman filter; Ensemble kalman filter,,"In this work we propose a methodology based on sequential Monte Carlos techniques for the estimation of dynamic systems states arising from the torque and drag phenomena of a directional drill string. This methodology arises from the need to consider the various mechanical factors and the geological parameters that influence the drift deviation, which conduce to no vertical drilling and phenomena of torque and drag. The anticipated model will acquire importance for the evaluation with the different efforts for which it will be in the next stage of the drill string. The methodology is exposed through the reconstruction of states of the synthetic model states proposed by Johancsik, Friesen, and Dawson, using the Sequential Monte Carlo algorithms, the unscented Kalman filter (UKF) and the ensemble Kalman filter (EnKF), observing good adjustment of torsion and drag states estimated by the filters with respect to the real values. Filters performance was evaluated in terms of the mean square error, showing variability of the estimated errors 0.05 for EnKF and 0.01 for UKF and a fast execution of the algorithms 3.07 (seg) for EnKF and 0.48 (seg) for UKF.",0,0,1
Drill String,,"Panayirci, H. Murat",Hole enlargement by drillstring stabilizers,drillstring stabilizers; Steering prediction; Hole quality,,"The goal of this study is to quantify the hole enlargement caused by drillstring stabilizers and the relation of this enlargement to the drilling parameters, contact forces, and rock strength. For this purpose, an extensive test campaign was conducted. In each test, a real-size stabilizer is placed within a predrilled hole in a mortar block. A side force is then applied as the stabilizer is rotated and moved downward. The change in the hole diameter is measured using a laser scanner before and after completing the experiments. The results of these experiments demonstrated the extent of the effect, which the stabilizers can have on the final borehole shape and quality. A simple implementation within an existing in-house steering prediction model is proposed to address this problem. Numerical simulations are presented to show the benefit of capturing borehole enlargement by stabilizers.",1,1,0
Drill String,,"Xu, Honglin; Yang, Bin; Zhang, Zhi; Shi, Taihe",Special considerations to calculate joint strength of premium connections,Premium connection; Joint strength; Make-up torque; Shoulder separation; Theoretical model; Gas well integrity,ROTARY-SHOULDERED CONNECTIONS; LIMITS,"Premium connections, which usually own modified buttress threads, special mental-to-metal seals and torque shoulder, have been increasingly adopted in casing and tubing strings to improve their joint strength and sealing performance in high pressure-high temperature (HPHT) gas wells. Because of complicated geometric structure, it is very difficult to establish an analytical joint strength model for premium connections while typical finite element analysis (FEA) does not also reveal the general failure law. In fact, the coupling joint strength of premium connection will decrease because of the make-up torque resulted from shoulder and the torque shoulder never allows to separate under limit axial working loads. Considering the make-up torque and prevention of shoulder separation, this paper proposes methods to calculate the joint strength of premium connections with API buttress thread teeth based on elastic mechanics. An example is also analyzed by modifying a premium connection from an API 177.8 mm P110 grade buttress thread casing. The results show that the joint strength of the premium connection is largely influenced by the ratio value zeta of the torque resulted from the shoulder to the total torque and that larger or smaller ratio values zeta both decrease the joint strength. To enhance the joint strength and tensile connection efficiency in practice, not only should the total make-up torque be controlled but the ratio values zeta should also be appropriately controlled. The proposed methods more comprehensively reflect the failure patterns of premium connections and their great significance for joint strength calculations, makeup torque control and connection parameter design.",1,1,1
Drill String,,"Hovda, Sigve",Optimal procedures for lowering and applying weight on the bit when starting to drill,Drillstring dynamics; Bit bouncing; Vibrations,SEMIANALYTICAL MODEL; AXIAL MOVEMENTS,"When a drilling activity is started, the bit is typically a few meters above the bottom. First, constant rotation is established, then the bit is lowered slowly onto the bottom to avoid bit bouncing. Once the bit is on bottom, weight on bit is applied by lowering the drillstring even more. In this paper, we propose a procedure that minimizes the axial vibrations involved with these activities. We use two dynamic-semi-analytic-lumped-multi-element models for the axial movement of a vertical drillstring. One model has the assumption that the bit is off bottom and the other model has the assumption that the bit is being on bottom. The algorithm is switching between the two models automatically. The motion of lowering the drillstring involves an acceleration period and a deceleration period. In this paper, we show that minimum vibrations are present when the acceleration and the deceleration are constants and their duration times are equal to the period of the first eigenfrequency. This is not taken into account in current drilling practices. Since the calculations are simple and modern draw-works are programmable, the procedures are suitable for a real-time implementation.",2,2,0
Drill String,,"Chen, Laoyin; Di, Qinfeng; Lou, Erbiao; Zhou, Bo; Zhang, He; Wang, Wenchang; Hu, Feifei",The visualization of rub-impact characteristics of drill string on casing,Rub-impact characteristics; 3D visualization method; Casing wear; Drill string; Finite element model,DYNAMIC-ANALYSIS,"Field experience revealed that a whirling drill string in the wellbore would make severe impact and rubbing against the casing and lead to uneven and random wear of casing. The casing wear due to vibrational impacts of the drill string was also one of the major causes for casing failure, but it was always ignored in the previous studies on casing wear. This work aimed at modelling and intuitively displaying the rub-impact characteristics of drill string and the induced wear on casing. Taking into consideration of the damping of drilling fluid, bit-rock interaction together with the geometric and contact nonlinearity, a drill string dynamic finite element model was established and then solved with the node iteration and the Newmark method. The whirl orbit, whirl velocity and collision characteristics of the drill string were then obtained. Based on these results, a three-dimensional visualization method was established to describe the dynamic features of drill string. The results indicate that the drill string presents a strong nonlinear dynamic behavior and makes frequent impacts against the wellbore, which appears mainly in the low side of borehole and is more serious in the hole section where BHA is located. The hole curvature and surface rotary speed have important influence on the casing wear induced by impact-rub action. A large hole curvature will lead to more serious rub-impact action of the drill pipe on the casing, and a rotary speed closer to the natural frequency of BHA will obviously increase the wear risk of casing.",2,3,3
Drill String,,"Zhang, Qiang; Jiang, Bao; Xiao, Zhongmin; Cui, Wei",Buckling transition process of suspended tubulars during loading and unloading,Suspended tubulars; Helical buckling; Critical load; Finite element; Quasi-static method,BOUNDARY-CONDITIONS; STRINGS; PIPE; CONNECTORS; ROD; FRICTION; BEHAVIOR,"In this paper, we investigate the numerical simulation of the whole buckling transition process during unloading and loading of the compression load with quasi-static method. By using a smaller load increment step, longer calculation time and appropriate damping, this buckling transition is calculated. We find that the tubular deformation evolves from continue-line contact to bottom-top-point, continuous-point, spatial two-point, spatial one-point, planar one-point contact, and finally back to vertical configuration during unloading. This deformation sequence is reversed during loading. During the transition from planar one-point contact to spatial two-point contact deformation, the buckling shape and related physical quantities change abruptly. During unloading and loading, the dimensionless critical loads of the first three buckling deformations are basically the same. For the buckling deformations with spatial two-point and planar one-point contact, and for spatial one-point contact deformation, the critical loads of loading are about 5% and 50% larger than that of unloading, respectively. For the spatial one-point contact deformation with dimensionless length greater than 40 and other buckling deformations with dimensionless length greater than 20, the critical loads obtained in the buckling process remain almost unchanged. It is noted that since the friction effect is not considered in our numerical simulation, the critical loads obtained are the minimum values in the process of buckling transition.",3,3,1
Drill String,,"Zhang, Qiang; Jiang, Bao; Xiao, Zhongmin; Cui, Wei; Liu, Jubao",On the failure configuration of suspended tubular strings when helical buckling just occurs,Suspended tubular strings; Helical buckling; Critical load; Finite element; Dynamic relaxation method,AXIAL LOAD-TRANSFER; ROD; CONNECTORS; FRICTION; BEHAVIOR,"When the sinusoidal buckling of suspended tubular strings is transforming to helical buckling, the deformation changes drastically, which makes the tubular strings extremely unstable. The quantitative description of this buckling configuration in previous theoretical studies is not precise enough. In our current study, dynamic relaxation method is applied to carry out numerical simulation of buckling transition of suspended tubular strings. To obtain stable buckling configurations, larger Rayleigh damping is used to attenuate the dynamic effect. With the increase of axial compression load, the lateral buckling of the suspended strings suddenly becomes spiral shape with two contact points. As the string length increases, the position of the lower contact point remains almost at the same position. While the upper contact point gradually moves upward, and the helix angle between the two points increases and gradually tends to be constant. The maximum contact force is located at the lower contact point, the maximum shear force is located at the bottom of the strings, and the dimensionless distance between the location of the maximum bending moment and the well bottom is about 1.0. These loads, including the maximum contact force, maximum shear force and maximum bending moment, gradually decrease with the increasing string length and tend to be constant. The dimensionless critical load is reduced from 4.41 to 3.81 with the effect of string length. The critical load calculated in this paper is the minimum value when helical buckling just occurs. The results obtained in the current study have wide engineering applications, particularly in failure analysis and prevention of helical buckling.",3,3,2
Drill String,,"Han, Yiwei; Ai, Zhijiu; Kuang, Yuchun; Liu, Jianxun; Yang, Wenwu",Nonlinear dynamic modeling of drill string in horizontal well - A geometrically exact approach,Horizontal drill string; Nonlinear dynamics; Geometrically exact model; Quadrature element method,FINITE-ELEMENT FORMULATION; 3-DIMENSIONAL BEAM THEORIES; SPATIAL BEAMS; DRILLSTRINGS; SPACE; PIPE; ROD,"A new nonlinear dynamic model of drill string in horizontal well is established based on geometrically exact beam theory and quadrature element method. The model proposed in this paper takes into account the geometric nonlinearity of the drill string and the nonlinear contact between the drill string and the borehole. Benefiting from the accuracy of the geometric description of the geometrically exact beam, the model uses a geometrically exact method to describe the contact between the drill string and the borehole. Comparison with experimental results shows that the geometrically exact model can accurately describe the nonlinear characteristics of the drill string. Finally, the characteristics of the movement of drill string under different drilling pressure and rotation speed are analyzed. Drilling pressure and rotational speed have an effect on the buckling of the drill string. Before buckling, the drill string moves periodically at the bottom of the wellbore. After buckling, the movement of the drill string becomes disordered. The model presented in this paper provides a new method for dynamic analysis of drill string.",3,3,10
Drill String,,"Zhu, Xiao-hua; Li, Bo",Numerical simulation of dynamic buckling response considering lateral vibration behaviors in drillstring,Mechanical behavior; Dynamic analysis; Buckling behavior; Finite element method; Critical length,,"Mechanical behavior of oilwell drillstring coming at the motions of penetrating rock is associated with drilling safety and wellbore quality. A poor performance can be attended by elastic stability loss in a slender drillstring exerting undesired buckling and vibration phenomena in the working process. Devoting to investigating the dynamic buckling behavior is an efficient way to avoid fatigue failure of the drillstring components and enhance drilling rate. A dynamic analysis of the buckling behavior of the entire column considering violent lateral vibrations is presented as a result available. Analytical equations of the drilling system are integrated numerically with finite element method. A virtual contact element implemented between the drillstring and the borehole, in conjunction with Hertzian contact assumption, gives the direct access to calculate the contact force and positions. Lateral deflection, critical length and the effects of drilling parameters and stabilizer on the buckling deformation are captured to experience the realistic buckling response of a typical drillstring in a vertical well. Simulation results indicate that spiral pitch and wave numbers of a nonlinear spiral shape prevailing in the lower zone of drillstring are deeply associated with the cutting force at the bit. Improving a drillstring behavior performance in a real oilfield is observed that this model can assist in evaluating the properties of the working security and buckling resistance with complex boundary conditions.",4,4,0
Drill String,,"Wang, Xueying; Ni, Hongjian; Wang, Ruihe",Experimental study on toolface disorientation and correction during slide drilling,Slide drilling; Stick-slip motion; Toolface disorientation; Toolface hysteresis; Toolface correction,FACE-CONTROL; TORQUE,"Toolface control is an important issue when drilling directional wells with steerable motors. In this paper, a new experimental apparatus has been built to study the toolface behavior while slide drilling. In experiments, weight on bit and toolface orientation during the simulated slide drilling are recorded and analyzed. Experimental results indicate that axial slick-slip motion of the drillstring that occurs in the presence of large friction causes toolface disorientation. In addition, the phenomenon of toolface hysteresis in horizontal wells is identified. The asymmetric loading and unloading rates of weight on bit result in toolface hysteresis, and toolface hysteresis worsens toolface disorientation. A new method of correcting toolface by quickly eliminating toolface hysteresis is proposed. Four torque-related parameters are used in the method, and each has a specific implication. The proposed method has been examined using the experimental apparatus and has been proven to work. The experimental results and related analysis in this paper can help to further improve the efficiency of toolface control during slide drilling.",4,4,1
Monte Carlo,,"Sanchez, Luis; Lapo, Miguel; Zorrilla, Octavio",Torque and drag analysis of a drill string using Sequential Monte Carlos methods,Directional drill string; Torque and drag phenomenon; Unscented kalman filter; Ensemble kalman filter,,"In this work we propose a methodology based on sequential Monte Carlos techniques for the estimation of dynamic systems states arising from the torque and drag phenomena of a directional drill string. This methodology arises from the need to consider the various mechanical factors and the geological parameters that influence the drift deviation, which conduce to no vertical drilling and phenomena of torque and drag. The anticipated model will acquire importance for the evaluation with the different efforts for which it will be in the next stage of the drill string. The methodology is exposed through the reconstruction of states of the synthetic model states proposed by Johancsik, Friesen, and Dawson, using the Sequential Monte Carlo algorithms, the unscented Kalman filter (UKF) and the ensemble Kalman filter (EnKF), observing good adjustment of torsion and drag states estimated by the filters with respect to the real values. Filters performance was evaluated in terms of the mean square error, showing variability of the estimated errors 0.05 for EnKF and 0.01 for UKF and a fast execution of the algorithms 3.07 (seg) for EnKF and 0.48 (seg) for UKF.",0,0,1
Monte Carlo,,"Li, Yaohua; Song, Yan; Jiang, Shu; Jiang, Zhenxue; Yang, Wei; Wang, Qianyou; Liu, Dan",Tight reservoir oiliness numerical simulation based on a Markov chain Monte Carlo (MCMC) method: A case study of the upper Triassic Yanchang-6 formation (T(3)ch(6) Fm.) outcrop of Ordos Basin,Reservoir oiliness; Fractures; Lithofacies; Bayesian; MCMC,FRACTURED HORIZONTAL WELL; UNCERTAINTY QUANTIFICATION; WESTERN INTERIOR; ORGANIC-MATTER; STRATIGRAPHY; PRESSURE; MODEL; BAYES; FLOW,"Numerical simulation of the tight reservoir oiliness has always been an important issue in tight oil resources exploration. It is hard to take some special situations into simulations such as the micro-nano thermodynamic system, the multi-fluid phase behavior, and the superimposed tectonic stress field of tight oil reservoirs. In our research, we use MCMC methods to simulate the tight reservoir oiliness constrained by some visualized, spatial-related and interacted geological parameters based on the statistic Bayesian theory, instead of taking the complicated accumulation mechanism into consideration. In this research, we built a posterior probability density distribution (Post-PDD) matrix using the spatial relation between oiliness, fracture, and lithofacies parameters of a typical Yanchang tight oils outcrop. In the simulation, one Monte Carlo Step (MCS) was settled N = 80 x 36 x 5000, where 80 and 36 represent the horizontal and longitude grid number respectively, and 5000 represents the sampling times for each grid. In total, simulations of 50000 MCSs were made for each realization. For the simulation results, the variation in the fluctuating trends of the fitted and actual values matched well with the analytic variogram for the MCMC realizations. Additionally, we found that the simulation uncertainty was consistent with the reservoir heterogeneity. Even though the lamina, intercalation or the barrier was not defined in the grid model, the oiliness realization of the different types was remarkably consistent with the reservoir heterogeneity, which may be caused by the sedimentary rhythm similitude between different scale sedimentary cycles, particularly in the lacustrine tight reservoir.",1,1,1
Monte Carlo,,"Herrera, Maria S.; Ortiz, Alberto; Hryb, Damian; Rendtorff, Nicolas M.",Detectability of smart proppants traced with gadolinium and samarium in the Vaca Muerta formation,Vaca Muerta formation; Traceable proppant; Samarium oxide; Gadolinium oxide; Thermal neutron capture cross section; MCNP; 2010 MSC; 82D75; 65C05,BALL CLAY; PLACEMENT; BEHAVIOR; OXIDE,"The use of smart proppants traced with gadolinium and samarium was evaluated in a realistic model by Monte Carlo simulations. The addition of compounds with high thermal neutron capture cross section, such as gadolinium oxide (Gd2O3) and samarium oxide (Sm2O3) into ceramic proppants, makes them detectable after placement in induced fractures. Proppants traced with different oxide concentrations were studied in a generic borehole-formation-tool configuration, modeled with MCNP. The Vaca Muerta formation model was constructed based on measured geochemical data. A theoretical formation of water-saturated limestone with 20% porosity was also used as a reference case of study. The minimum concentration of gadolinium and samarium oxides needed, in order to make them detectable by logging tools, was determined. In the case of gadolinium, results are in agreement with previous reported values for Gd2O3 addition of about 0.4% by weight of proppant. In the case of samarium, a minimum concentration of 1.25% by weight of Sm2O3 addition could be detected in both Limestone and Vaca Muerta formations.",2,2,0
Monte Carlo,,"Mohankumar, Yashas; Li, Zukui; Huang, Biao",Steam allocation and production optimization in SAGD reservoir under steam-to-oil ratio uncertainty,Nonlinear model predictive control; Steam-to-oil ratio; Nonlinear optimization; Stochastic optimization,MODEL-PREDICTIVE CONTROL; ROBUST; STABILIZATION,"Steam allocation is an important decision for bitumen thermo-recovery using Steam Assisted Gravity Drainage (SAGD) technique. This is due to the significant amount of steam requirement and often limited steam generation capacity. Steam-to-oil ratio (SOR) is an important parameter affecting the production performance. It is necessary to address uncertainty in SOR to prevent constraint violation in SAGD reservoir states such as subcool and also to maximize the overall steam utilization efficiency. In this work, we study the problem of steam allocation and oil production optimization in the SAGD process considering SOR uncertainty. A first principle model for the SAGD process is developed and further incorporated into the Nonlinear Model Predictive Control (NMPC) problem, which enforces the system to be within various constraints while optimizing an economic objective. The uncertainty is dealt with using three methods in this work: (i) open-loop worst-case optimization, (ii) scenario tree based closed-loop optimization and (iii) affine policy based closed-loop optimization. Performances of the above methods are compared through Monte Carlo simulations. Results demonstrate the superiority of affine policy based optimization method, which has around 50% improvement of economic performance over static robust and scenario based method in handling SOR uncertainty.",2,2,1
Monte Carlo,,"Allshorn, Samuel L.; Dawe, Richard A.; Grattoni, Carlos A.",Implication of heterogeneities on core porosity measurements,Porosity; Heterogeneity; Core plugs; Inclusions; Vugs; Clay; CT scanning,,"Heterogeneities within core samples affect the accuracy of the laboratory measured core plug interconnected porosity. The laboratory measures the volume averaged porosity of the interconnected pores, < phi(m) > . For homogeneous cores this is the correct porosity +/- any experimental error. However for heterogeneous cores when any embedded material (unknown or ignored) has a differing porosity, phi(i) to that of the containing outer shell, phi(o), there will be increased uncertainty. We show that the difference between the measured volume averaged porosity, < phi(m) > , and the porosity of the outer shell of the core, phi(o) can be quantified by our Heterogeneity Factor, H. H is defined as (< phi(m), > - phi(0))/phi(o) and given by H = F(R-1), where F is the ratio of the bulk volume of the embedded material to the total core bulk volume (measured), V-Bi/V-Bm and R is the ratio of the embedded and the host outer porosity, phi(i)/phi(o) The core plug homogeneous model can create increased error bounds in porosity for heterogeneous plugs. When H is zero there is no error in the porosity measurement due to heterogeneity, but when H not equal 0 then the differences can be significant and increases the experimental error bound. We present graphs for relevant industry scenarios to demonstrate the effect of any inclusions in the measured porosity. We find that when F is similar to 0.1 i.e., inner included porosity is 10% of bulk volume, the relative error between < phi(m) > and phi(o) can reach similar to 30% and even larger differences when F > 0.1. We then give a real example from a faulted vuggy outcrop carbonate which demonstrates extra porosity uncertainties, even for a very small vug. Finally we discuss the possible effect of embedded clay intrusions emitting adsorbed gas on grain/pore volume determinations of porosity using gas expansion, a common laboratory method of porosity determination. Appreciation of core heterogeneity on the precision of the laboratory porosity measurements is essential to improve the confidence in the error bounds for the quality control of laboratory core porosity measurements, and of the porosity distribution frequency for inputs to statistical methods such as Monte Carlo analysis for oil-in-place estimations, STOIIP.",2,2,2
Monte Carlo,,"Patel, Rajan G.; Jain, Tarang; Trivedi, Japan",Performance of ensemble Kalman filter and Markov chain Monte Carlo under uncertainty in forecast model,Markov chain Monte Carlo; Ensemble Kalman filter; Uncertainty quantification; Polynomial chaos expansion; Reservoir characterization; Data assimilation,DATA ASSIMILATION; QUANTIFYING UNCERTAINTY; PROXY MODELS; SIMULATION; QUANTIFICATION; CONVERGENCE; INFERENCE; FLOW; RML,"Ensemble Kalman filter (EnKF) and Markov chain Monte Carlo (MCMC) are popular methods to obtain the posterior distribution of unknown parameters in the reservoir model. However, millions of simulation runs may be required in MCMC for accurate sampling of posterior as subsurface flow problems are highly nonlinear and non-Gaussian. Similarly, EnKF formulated on the basis of linear and Gaussian assumptions may also require a large number of realizations to correctly map the solution space of the unknown model parameters, ultimately resulting in the high computational cost. Data-driven meta/surrogate/proxy models provide an alternative solution to alleviate the issue of high computational cost. Since these models are not as accurate as numerical solutions of partial differential equations (PDE), their implementation may add an uncertainty in the forecast model. In literature, the effect of uncertainty in forecast model on data assimilation is not well studied, especially with field-scale reservoir models. In this work, we take the opportunity to evaluate and compare the performance of EnKF and MCMC using polynomial chaos expansion (PCE) based forecast model. Proposed forecast model relies on reducing parameter space using Karhunen-Loeve (KL) expansion which preserves the two-point statistics of the field. Random variables from KL expansion and orthogonal polynomials corresponding to the prior probability density function (pdf) form the set of input parameters in PCE. Further, non-intrusive probabilistic collocation method (PCM) is used to compute PCE coefficients. PCE forecast model is then used in EnKF and MCMC to calculate the likelihood of the samples in place of high fidelity full physics simulation runs. A case study is performed using a 3D field scale model of a reservoir located near Fort McMurray in northern Alberta, Canada. Performance of EnKF and MCMC are assessed under forecast model uncertainty using rigorous qualitative and quantitative analysis and posterior distribution characterization. Results clearly depict that, although EnKF provided reliable mean and variance estimates of model parameters, MCMC outperformed the former even under the uncertainty associated with PCE metamodel. Inaccurate initial assumptions of model parameters were successfully handled by MCMC, although, with a longer burn-in period. Furthermore, characterization of posterior demonstrated reduced uncertainty in the estimation of model parameters using MCMC as compared to EnKF. Practical implications of the proposed approach and performance assessment under forecast model uncertainty will be consequential in designing accurate and computationally efficient reservoir characterization workflows and hence, improved decision-making in reservoir management.",3,3,1
Monte Carlo,,"Dachanuwattana, Silpakorn; Yu, Wei; Sepehrnoori, Kamy",An efficient MCMC history matching workflow using fit-for-purpose proxies applied in unconventional oil reservoirs,Assisted history matching; Markov chain Monte Carlo; Proxy; K-nearest neighboring; Unconventional oil reservoirs,,"History matching is a very challenging task because tremendous amount of simulations runs are required to achieve an acceptable accuracy target. In this paper, we develop and evaluate an assisted history matching (AHM) workflow using proxy-based Markov chain Monte Carlo (MCMC) algorithm, which is fully-automated and efficient for application in unconventional reservoirs. We use a synthetic simple case to compare the accuracy between four types of proxies: quadratic polynomial, cubic polynomial, k-nearest neighboring (KNN), and kriging. Also, we investigate the accuracy of proxy in different contexts such as different measurement errors and different quantity of initial simulation points. The results show that kriging proxy is more accurate than KNN proxy and cubic proxy. The quadratic proxy was the least accurate in our evaluations. However, if larger measurement error is introduced, the distinction between accuracy of proxy of the four proxies becomes less clear in spite of their different computational costs. The appropriate number of initial simulation points is another key to improve the AHM workflow efficiency. Incorporating these findings, we implement the AHM workflow on a synthetic field case and successfully perform history matching and uncertainty quantification.",4,4,0
Monte Carlo,,"Diaz-Curiel, J.; Miguel, M. J.; Biosca, B.; Medina, R.",Environmental correction of gamma ray logs by geometrical / empirical factors,Gamma ray; Environmental corrections; Attenuation factor; Build-up factor,,"This paper presents a series of empirical expressions to correct the total natural gamma ray log due to well environmental factors. This correction is focussed on improving the quantification of 40 K, given its application in the computation of the clay content of the different layers crossed during drilling. To date, there are no analytical relationships that make this correction and continuously consider the different diameters of the many existing sondes. There are also no functions that continuously take into account the different combinations of media interspersed between the well walls and the sonde (casing, drill pipe, gravel pack, cement, etc.) for different measurement modes and systems, such as wireline, while drilling. To solve these shortcomings, the relationships developed in this work have cited, in addition to the different well diameters and mud densities, the diameter of the sonde and the environmental parameters as variables with any value and in any possible combination. The obvious advantage of these parametric equations is that they can easily be entered as a subroutine into any code. Unlike the existing correction methods, i.e., empirical charts and curves obtained by simulation codes based on the Monte Carlo method, the relationships developed take into account the variation of the build-up effect that the radiation undergoes as it travels from layers with a certain radioactive emission to the sonde. In addition, another difference is that the relationships generated in this work include the internal diameter of the sonde between its outer walls and the cylindrical radiation detector glass. Starting from the general relationships that consider the attenuation and build-up effects of gamma radiation when passing through a medium, the methodology consisted of establishing an effective distance for the cylindrical geometry in which the source is the well wall, particularized for each effect and each type of tool (centred and eccentred). The resulting correction factors have been contrasted with the most recognized experimental charts in the field of well logging, obtaining a very high correlation and an average deviation of around 1.5%.",4,4,0
Monte Carlo,,"Zhang, Quanying; Zhang, Feng; Yuan, Chao; Wang, Xinguang; Zhang, Xiaoyang",A comparative study on the neutron-gamma density and gamma-gamma density logging,Pulsed neutron gamma density; Gamma-gamma density; Logging mechanism; Monte Carlo simulation; Instrument specifications,,"With the increasing demand for the radioisotope-free operations, using pulsed neutron gamma density (NGD) instead of gamma-gamma density (GGD) has become increasingly important for the development of logging while drilling (LWD) technology. However, due to the different logging mechanisms, there are huge differences between GGD and NGD in the instrument designs, measurement methods, and instrument specifications. To further promote the NGD development, a comparative study on GGD and NGD was carried out from theoretical and simulation aspects. Based on the theoretical methods, the differences between GGD and NGD in the gamma sources, field distribution, methods for density measurement and instrument specifications were systematically elaborated. Then, using the Monte Carlo simulation, the GGD and NGD models were built to quantitatively verify the theoretical results. Last, the detailed performances of NGD and GGD methods in different logging environments were compared. Results showed that the theoretical results are highly consistent with the simulation results. The density sensitivity of NGD is less than half that of GGD, but the depth of investigation (DOI) approaches twice that of GGD. The density precision and vertical resolution of NGD are less than those of GGD. Additionally, compared to GGD, NGD also has an excellent performance in different pore fluid and lithology formations, but it is easily affected by borehole factors. The research can provide quantitative performance evaluations for the NGD replacing GGD in LWD logging.",5,5,1
Monte Carlo,,"Ma, Yongfeng; Yu, Rangang",New analytical methods to evaluate uncertainty of wellbore stability,Wellbore stability; Uncertainty evaluation; Analytical model; Monte Carlo method; Sensitivity analysis,FAILURE CRITERIA; STRENGTH CRITERIA; LOGGING PROBLEMS; MODEL; COULOMB; ROCKS; LIMIT,"The uncertainties of the inputting parameters lead to the uncertainty of the wellbore stability. In view of this, two analytical methods were proposed to address the problem, based on second order Taylor series expansion and Rosenbluthe method. Using two analytical methods, the collapse and fracture pressures were calculated in the form of the probability distribution. To accomplish the calculation above, the mean and standard deviation of input parameters were firstly determined based on well log data. Especially, a new method of sensitivity analysis was proposed to quantify the effect of the input parameter on the uncertainty of the wellbore stability, through the way that one parameter changes the uncertainty while other parameters keep initial uncertainties. Additionally, two analytical methods were validated by Monte Carlo simulation. The results show that the probability distributions agree very well between analytical methods and Monte Carlo method. According to the new method of sensitivity analysis, the horizontal maximum stress is the most sensitive parameter for the collapse pressure, and the horizontal minimum stress has the maximum effect on the fracture pressure.",5,6,1
Steady State,Temperature,"Ossai, Chinedu, I",Pump-off identification with time series analysis of transient water discharge rate,Prognosis; Progressing cavity pump; Pump-off identification; Water discharge rate; Time series; Transition probability,PERFORMANCE; MODEL; GAS,"To advance the prognosis of progressing cavity Pumps (PCPs) used for artificial lifting, the pump-off need to be identified to forestall failure. This study developed a new technique for determining the Pump-off events Activation Times (PATs) of the PCPs using the transient Water Discharge Rates (WDRs) from coal seam gas producing wells. The Gaussian distribution function parameters of the rolling standard deviations of the water discharge rate (RSWR) and the transition probability of the rolling standard deviations of the water discharge rate (TP_RSWR) were used to build the model. By determining the anomalies in the RSWR signals with the bottom-up segmentation technique and computing the statistical characteristics at the changepoint locations, the steady-state of the WDR signals was established. This steady-state signal, which represents the Operation Transition Level (OTL) between the Normal Operation (NOP) and the Pump-off Event (POE) was used for monitoring the transition of the PCPs' operating status. An algorithm was developed in Python and tested it on field data from 36 coal seam gas wells. The performance of my technique was determined with precision, recall and F1 score, which gave an average value of 94.94%, 92.63%, and 93.56% respectively. It is expected that the implementation of this technique in the real-time estimation of PATs will be vital for reducing PCPs faults seeing that poor PATs detection results in PCPs running dry and consequently failures due to the extreme temperatures and abrasions.",0,0,1
Steady State,Temperature,"Goes, Maria Rosa R. T.; Teixeira, Rodrigo G. D.; Tavares, Frederico W.; Secchi, Argimiro R.",Wax appearance and prevention in two-phase flow using the multi-solid and drift-flux model,,THERMODYNAMICS; PRECIPITATION; PREDICTION; EQUILIBRIA; DENSITIES; LIQUIDS,"Wax precipitation may lead to obstruction of pipelines generating significant economic losses. Oil reservoirs, especially in the deepwater sea, are found in extreme conditions of pressure and, during the fluid flow inside the pipelines, the fluid temperature may decrease due to heat transfer to the surrounding (seawater) and phase change, tending to deposit solid particles on the pipeline walls. Within this context, it is important to develop a model that calculates the WAT (wax appearance temperature) of a fluid with known composition and then determine the point where the first paraffin crystal will appear inside a pipeline. The objective here is to provide a two-phase flow model coupled with paraffin precipitation model to calculate WAT inside the pipeline. We used the Drift-Flux Model to describe the two-phase flow in steady state and the Multi-Solid Theory to calculate the WAT. The results for a paraffinic mixture of four components show that the effect of the pressure can be considered negligible on WAT calculation for low pressure systems (< 10 MPa). Analyzing the effect of the fluid composition, the larger the number of light compounds in the mixture, the smaller will be the WAT, at constant pressure. For two different cases, it was determined the point inside the pipeline where the solid particles may deposit. We proposed an algorithm to find the minimum inlet temperature such that does not occur wax precipitation along the pipeline. The algorithm was successfully applied to a case study and may be useful for defining operational conditions to prevent solid blockage of pipelines.",1,1,0
Steady State,Temperature,"Al Saedi, A. Q.; Flori, R. E.; Kabir, C. S.",Exploring alteration of near-wellbore geothermal gradient during fluid circulation and production,Time-dependent formation temperature; New analytical models for fluid circulation & production; Solution of temperature diffusivity equation; Transient temperature profiles; Undisturbed formation temperature; Heat flow in and out of wellbore,TEMPERATURE DISTRIBUTION; HEAT-TRANSFER; MODEL; LOGS,"The constant undisturbed formation temperature profile controlling heat transfer into the wellbore appears counterintuitive in light of transient cooling of the formation that occurs upon fluid circulation in drilling and also heating during fluid production. This study presents a mathematical model that shows that the heat transfer occurs from the wellbore/formation interface, not from some distance away from the wellbore wherein the initial formation temperature profile remains undisturbed. This new model allows investigation of heat transfer behavior from the formation into the wellbore during drilling or fluid circulation, and from the wellbore into the reservoir in the production mode. Application of the line-source solution for the temperature diffusivity equation for a steady-state system provides the necessary ingredients for computing the temperature behaviors at different times and radii. This line-source solution can be used throughout the wellbore to determine the undisturbed formation temperature, which may be used to obtain the geothermal gradient dependent on the radius and fluid circulation time. Therefore, the initial geothermal gradient works as a time-dependent variable, and the resultant second-order polynomial relationships can describe the undisturbed formation temperature. This study provides the required tools to assess the wellbore heat-transfer behavior and their effect on the wellbore temperature profiles. Also, the new mathematical model illuminates the impact of heat transfer by comparing its performance with the original formulations. Besides, this paper presents a complete derivation of the line-source solution of the temperature diffusivity equation to justify the proposed approach.",5,5,0
Steady State,Formation,"O'Reilly, Daniel I.; Haghighi, Manouchehr; Flett, Matthew A.; Sayyafzadeh, Mohammad",Productivity determination for cyclic production using steady state harmonic theory - Application to artificial lift wells,Artificial lift; POC; Well testing; Pulse testing; Productivity index,UNSTEADY LIQUID FLOW; TESTS; PULSE,"In this paper we derive new solutions to the problem of harmonic flow in a bounded porous medium with inclusion of wellbore storage and skin. We present new solutions to varying radial boundary conditions and pay special attention to the cases of pseudo steady and steady state flow. These solutions have a new, special application to cyclically produced wells undergoing artificial lift under these conditions. It is normally difficult for engineers to determine the Productivity Index (PI) or permeability of production wells undergoing cyclic operation. The relationship between bottomhole pressure, cycles, run time % and formation properties is quite non-linear, which we will illustrate here. However, the new theory allows simple determination of PI for such wells. The results will have application to artificially lifted wells or those wells intentionally pulsed in bounded reservoirs. A calculation method is shown for this type of problem along with field application.",0,0,0
Steady State,Formation,"Cao, Jie; Zhang, Nan; Johansen, Thormod E.",Applications of fully coupled well/near-well modeling to reservoir heterogeneity and formation damage effects,Well/near-well modeling; Iterative coupling; Heterogeneity; Crossflow; Formation damage,HORIZONTAL WELLS; FLOW; PRODUCTIVITY; PERFORMANCE,"Applications of a new well/near-well fluid flow modeling scheme to heterogeneous reservoirs and formation damage are presented in this paper. This well/near-well model is based on an analytically solution of an axial-radial productivity model for steady state flow in wells and near-well reservoirs, in which wellbore hydraulics and heterogeneity in the near-well region are incorporated. The numerical model includes a reservoir region describing both radial and axial reservoir flow. It can be used as a stand alone simulator, or it can be coupled with a reservoir simulator, using a new iterative coupling scheme described in this paper. When coupling with the reservoir simulator, the reservoir region in the well/near-well model is shared by and computed in both models, which ensures the stability and convergence of the iterative coupling scheme. A new coupling approach is presented without needing to determine any partial derivatives. The capabilities of the modeling methodology are demonstrated through applications in three challenging cases: highly heterogeneous reservoir, well/reservoir crossflow, and formation damaged reservoirs. In the highly heterogeneous near-well reservoir case, results show that the model is stable for a wide range of permeabilities with large contrasts. The detailed permeability information from well logging can be fully taken into account in this model. The model determines pressure distribution and volumetric flow rates including flow directions, therefore enabling the model to estimate crossflow as negative flow rates, for example when the well is producing from several non-communicating regions. Furthermore, the well/near-well model is iteratively coupled with a reservoir simulator such that the well completion effects are taken into consideration in large scale simulations. The transient case of this coupling to evaluate formation damage along a horizontal well is then presented. The model is not limited to single phase flow. A two phase flow example coupling the well/near-well model and a streamline reservoir model is finally presented.",1,2,5
Steady State,Formation,"Al Saedi, A. Q.; Flori, R. E.; Kabir, C. S.",Exploring alteration of near-wellbore geothermal gradient during fluid circulation and production,Time-dependent formation temperature; New analytical models for fluid circulation & production; Solution of temperature diffusivity equation; Transient temperature profiles; Undisturbed formation temperature; Heat flow in and out of wellbore,TEMPERATURE DISTRIBUTION; HEAT-TRANSFER; MODEL; LOGS,"The constant undisturbed formation temperature profile controlling heat transfer into the wellbore appears counterintuitive in light of transient cooling of the formation that occurs upon fluid circulation in drilling and also heating during fluid production. This study presents a mathematical model that shows that the heat transfer occurs from the wellbore/formation interface, not from some distance away from the wellbore wherein the initial formation temperature profile remains undisturbed. This new model allows investigation of heat transfer behavior from the formation into the wellbore during drilling or fluid circulation, and from the wellbore into the reservoir in the production mode. Application of the line-source solution for the temperature diffusivity equation for a steady-state system provides the necessary ingredients for computing the temperature behaviors at different times and radii. This line-source solution can be used throughout the wellbore to determine the undisturbed formation temperature, which may be used to obtain the geothermal gradient dependent on the radius and fluid circulation time. Therefore, the initial geothermal gradient works as a time-dependent variable, and the resultant second-order polynomial relationships can describe the undisturbed formation temperature. This study provides the required tools to assess the wellbore heat-transfer behavior and their effect on the wellbore temperature profiles. Also, the new mathematical model illuminates the impact of heat transfer by comparing its performance with the original formulations. Besides, this paper presents a complete derivation of the line-source solution of the temperature diffusivity equation to justify the proposed approach.",5,5,0
Steady State,Increase,"Sun, Baojiang; Yang, Caifeng; Wang, Zhiyuan; Wang, Xuerui; Wang, Ning",Methodology for pressure drop of bubbly flow based on energy dissipation,Mechanism; Bubbly flow; Horizontal pipe; Energy dissipation; Pressure drop,MECHANISTIC MODEL; STEADY-STATE; PIPE-FLOW; PART II; COALESCENCE; VISCOELASTICITY; COEFFICIENT; PREDICTION; BREAKAGE; VELOCITY,"Pressure drop of bubbly flow is a widely used parameter in petroleum industry. The energy dissipation rate is induced by three factors, including wall resistance, bubble breakup and coalescence, which is studied here from the perspective of the macroscopic flow and microscopic bubbles. This work details a model using the principle of energy conservation to clarify the mechanism of the pressure drop for turbulent bubbly flow in horizontal pipes. The model was validated via a comparison with experimental data of horizontal bubbly flow collected from nine previous studies with 200 points. Most of the errors are within +/- 20%. The proportions of pressure drop induced by wall resistance, bubble breakup and coalescence were calculated by the model. The results indicate that the largest proportion is from wall resistance, followed by bubble coalescence, with bubble breakup having the smallest proportion. In addition, the trends of proportion induced by the three factors above are analyzed by increasing gas volume fraction and mixture viscosity. The results show that the proportion induced by wall resistance decreases with the increasing volume fraction of the gas, and increases with the increasing mixture viscosity. The proportions induced by the bubble breakup and coalescence in the opposite case.",3,3,1
Steady State,Increase,"Han, Pu; Geng, Jiaming; Bai, Baojun",Investigation on transport behavior of nanogel in low permeable porous medium,Nanogel; Filtration; Membrane; Transport,LINKED POLYMER MICROSPHERES; WATER,"Nano-sized crosslinked polymeric particles (nanogels) have the advantages of both nanoparticles and hydrogels for enhanced oil recovery in the oil and gas industries. Although some encouraging progress in the application has been made, the transport behavior of nanogels through porous media are still not clear. In this work, a series of filtration experiments using membrane filter were performed to study the effect of nanogel diameter, pore size, and differential pressure on the transport behavior. The equilibrium filtration rate, which is a key parameter to indicate the transport behavior during steady state, increased from 0.19 to 5.71 mL/min when the pore size changed from 0.05 to 0.8 pm, and increased from 1.02 to 1.99 mL/min when the differential pressure raised from 10 to 30 psi. Experimental results demonstrated nanogels present smaller diameter (105.7 nm) and lower absolute value of zeta-potential ( -18.9 mV) in 10 wt% NaCl solution than distilled water (295.3 nm and - 82.5 mV). The higher salt concentration resulted in a better nanogel injectivity (equilibrium filtration rate increased from 0.77 to 4.52 when NaCl concentration changed from 0 to 10 wt%), which indicated the diameter of nanogel is a more determining factor than the nanogel strength. When the pore size was smaller than similar to 3 times of the naongel diameter, the equilibrium filtration rate became independent to the differential pressure and nanogels started to form face plugging on the membrane. The core filtration tests demonstrated that the nanogels maintained similar transport behavior through the limestone cores and membrane filters that the resistance factor is 26.59 in membrane and 18.56 in core with similar pore diameter. The transport behaviors of nanogel and corresponding mechanisms are summarized by the matching relationship between the diameter of nanogel and the pore size in low permeable porous medium.",4,4,0
Steady State,Increase,"Bagherzadeh, Hadi; Mansourpour, Zahra; Dabir, Bahram",A coupled DEM-CFD analysis of asphaltene particles agglomeration and fragmentation,Asphaltene; Agglomeration; Fragmentation; DEM-CFD,SIZE DISTRIBUTION; FLUIDIZED-BED; SIMULATION; AGGREGATION; MODEL; KINETICS; FLOW,"In the present paper, a Discrete Element Method-Computational Fluid Dynamics (DEM-CFD) approach along with a new coalescence model is adopted to study agglomeration and fragmentation of asphaltene particles, thoroughly. The collisions of asphaltene particles are investigated in three categories: collisions between individual primary particles (P-P collisions), individual primary particles and flocs (P-F collisions) and between flocs (F-F collisions). In addition, corresponding collision efficiencies have been determined based on the proposed coalescence model. Moreover, the importance of three different fragmentation modes including binary flocs fragmentations (binary fragmentation), detachment of a primary particle from floc (erosion) and splitting of floc into smaller flocs (large-scale fragmentation) is comparatively assessed. Eventually, the effect of fluid velocity and primary particles concentration on the aforementioned processes as well as asphaltene flocs properties are examined. Simulation results reveal P-P collisions contribution decreases continuously to reach a plateau in steady state condition while the contribution of P-F collisions increases initially and then it shows a gentle downward trend. F-F collisions contribution grows constantly up to steady state condition. The P-P and P-F collision efficiencies approximately remain constant whereas F-F collision efficiency continuously increases. In terms of fragmentation modes, contributions of binary fragmentation and erosion gradually decrease while large-scale fragmentation contribution constantly increases before steady state condition.",5,5,1
Steady State,Reservoir Simulation,"Cao, Jie; Zhang, Nan; Johansen, Thormod E.",Applications of fully coupled well/near-well modeling to reservoir heterogeneity and formation damage effects,Well/near-well modeling; Iterative coupling; Heterogeneity; Crossflow; Formation damage,HORIZONTAL WELLS; FLOW; PRODUCTIVITY; PERFORMANCE,"Applications of a new well/near-well fluid flow modeling scheme to heterogeneous reservoirs and formation damage are presented in this paper. This well/near-well model is based on an analytically solution of an axial-radial productivity model for steady state flow in wells and near-well reservoirs, in which wellbore hydraulics and heterogeneity in the near-well region are incorporated. The numerical model includes a reservoir region describing both radial and axial reservoir flow. It can be used as a stand alone simulator, or it can be coupled with a reservoir simulator, using a new iterative coupling scheme described in this paper. When coupling with the reservoir simulator, the reservoir region in the well/near-well model is shared by and computed in both models, which ensures the stability and convergence of the iterative coupling scheme. A new coupling approach is presented without needing to determine any partial derivatives. The capabilities of the modeling methodology are demonstrated through applications in three challenging cases: highly heterogeneous reservoir, well/reservoir crossflow, and formation damaged reservoirs. In the highly heterogeneous near-well reservoir case, results show that the model is stable for a wide range of permeabilities with large contrasts. The detailed permeability information from well logging can be fully taken into account in this model. The model determines pressure distribution and volumetric flow rates including flow directions, therefore enabling the model to estimate crossflow as negative flow rates, for example when the well is producing from several non-communicating regions. Furthermore, the well/near-well model is iteratively coupled with a reservoir simulator such that the well completion effects are taken into consideration in large scale simulations. The transient case of this coupling to evaluate formation damage along a horizontal well is then presented. The model is not limited to single phase flow. A two phase flow example coupling the well/near-well model and a streamline reservoir model is finally presented.",1,2,5
Steady State,Reservoir Simulation,"Berg, Carl Fredrik; Danilova, Anna; Liu, Ming",Upscaling of polymer adsorption,,FLOW; EXPERIENCE; RESERVOIR,"This article considers upscaling of polymer adsorption. Input to adsorption values employed in reservoir simulation models are typically obtained from core plug measurements. There are several orders of magnitude in scale difference between core plugs and grid cells in reservoir simulation models, which foster a need for upscaling of the adsorption values. Polymer concentration distribution on the lithofacies scale is investigated in this article. The effect of diffusion on concentration distribution is investigated analytically. The slow diffusion of polymer molecules retards mixing even at the lithofacies scale. We introduce a formula to estimate the redistribution of polymer due to capillary forces in a layered model, and this formula is validated through numerical simulations. From our considerations we conclude that it is questionable to assume a constant polymer concentration in lithofacies models. This impedes applying steady-state upscaling techniques. Such upscaling techniques will over-predict polymer adsorption. Different methods for upscaling adsorption are presented in this paper, and applied to a simplified layered model and to more realistic fine-scale numerical models based on the SPE10 model. These numerical models were populated with adsorption values obtained from published experiments conducted on samples from the Brent sequence modeled in SPE10. Simulations of tertiary polymer flooding on the upscaled models were compared to simulations of the same flooding sequences on the original fine scale models. The tested upscaling methods include a volume averaging technique employed by other authors, and a method were we distribute the adsorption values by the same functional relationship as in the fine scale model. In addition we introduce upscaling methods were we assign zero adsorption to fine scale grid cells with permeability below a given cut-off value. The cut-off value is obtained from a single phase simulation on the fine scale model. In our models the cut-off value methods yield the best match between the coarse scale and fine scale simulation results. The volume averaging technique over-predict the polymer adsorption. Results from both the lithofacies and geomodel scale indicate a tendency to over-predict polymer adsorption, which could lead to conservative estimates for the effect of polymer flooding.",2,2,1
Steady State,Differential Pressure,"Hannon, Michael J., Jr.; Tucker, Yael Tarlovsky; Soeder, Daniel J.","Quantifying the effects of gaseous pore pressure and net confining stress on low-permeability cores using the ""RaSSCAL"" steady-state permeameter",Core analysis; Unconventional oil & gas; Shale; Permeability,,"Subsurface engineering systems undergo large changes in pore pressure, which can have drastic effects on their ability to transport and store fluids. For rock samples retrieved from conventional reservoirs, standard core analysis procedures provide suitable estimates of petrophysical properties, such as porosity and permeability. However, performing similar investigations on low-permeability systems like shales and tight gas sands remains a challenge. Steady-state gas permeametry is considered the gold standard for analyzing low-permeability cores, but researchers often forego it in favor of faster but less reliable methods. Attempting a conventional permeability test on a tight plug sample typically results in miniscule flow rates that only expensive, specialized equipment can measure directly. Furthermore, these time-consuming tests are best run multiple times under varying ranges of pore pressure and confining stress. Doing so allows one to anticipate suitably the changes in permeability that will occur because of the expected changes in reservoir conditions. This study describes the methodology of the Randolph Steady-State Core Analysis Laboratory (RaSSCAL), a new experimental design and data analysis algorithm that accounts for changes in permeability over the range of pore pressures and confining stresses that occur during processes like unconventional hydrocarbon recovery and geologic carbon sequestration. Routine steady-state core analysis requires relatively small pressure drops across the sample so a uniform apparent permeability can be assumed. The approach outlined here enables an effective interpretation of core-flood data in the presence of arbitrarily large pressure gradients. The experiment maintains a near-constant pressure difference of arbitrary magnitude across a core-plug sample and indirectly measures the flow rate induced by that gradient using a differential pressure transmitter. Tests were performed on a Marcellus Shale sample from Bedford, Pennsylvania and an Oriskany Sandstone sample from Berkeley Springs, West Virginia over a wide array of pore pressures and net confining stresses using helium and methane gas. Having a quantifiable understanding of how the permeability of the system may change during the various stages of subsurface activity should significantly enhance the ability to optimize design outcomes. This will ultimately lead to improved oil and gas recovery and better predictions of injectivity and storage capacity during carbon-storage operations.",4,4,0
Steady State,Differential Pressure,"Han, Pu; Geng, Jiaming; Bai, Baojun",Investigation on transport behavior of nanogel in low permeable porous medium,Nanogel; Filtration; Membrane; Transport,LINKED POLYMER MICROSPHERES; WATER,"Nano-sized crosslinked polymeric particles (nanogels) have the advantages of both nanoparticles and hydrogels for enhanced oil recovery in the oil and gas industries. Although some encouraging progress in the application has been made, the transport behavior of nanogels through porous media are still not clear. In this work, a series of filtration experiments using membrane filter were performed to study the effect of nanogel diameter, pore size, and differential pressure on the transport behavior. The equilibrium filtration rate, which is a key parameter to indicate the transport behavior during steady state, increased from 0.19 to 5.71 mL/min when the pore size changed from 0.05 to 0.8 pm, and increased from 1.02 to 1.99 mL/min when the differential pressure raised from 10 to 30 psi. Experimental results demonstrated nanogels present smaller diameter (105.7 nm) and lower absolute value of zeta-potential ( -18.9 mV) in 10 wt% NaCl solution than distilled water (295.3 nm and - 82.5 mV). The higher salt concentration resulted in a better nanogel injectivity (equilibrium filtration rate increased from 0.77 to 4.52 when NaCl concentration changed from 0 to 10 wt%), which indicated the diameter of nanogel is a more determining factor than the nanogel strength. When the pore size was smaller than similar to 3 times of the naongel diameter, the equilibrium filtration rate became independent to the differential pressure and nanogels started to form face plugging on the membrane. The core filtration tests demonstrated that the nanogels maintained similar transport behavior through the limestone cores and membrane filters that the resistance factor is 26.59 in membrane and 18.56 in core with similar pore diameter. The transport behaviors of nanogel and corresponding mechanisms are summarized by the matching relationship between the diameter of nanogel and the pore size in low permeable porous medium.",4,4,0
Steady State,Field Data,"Xiang, Z.; Kabir, C. S.",Simplified transient-IPR modeling in intermittent gas-lift and plunger-lift systems,Transient IPR; Novel symbolic transient-IPR solution; Gas-lift well modeling; Plunger-lift system modeling; Model validation with field data; Model verification with synthetic data,FLOW-RATE; PERFORMANCE,"By solving the diffusivity equation on a periodic varying production problem, one can arrive at a transient inflow-performance relationship (IPR) model. This IPR model can then be coupled with a wellbore model to understand intermittent deliverability from wells with an artificial-lift system (ALS), such as periodic gas lift and plunger lift. The commercial simulators allowed verification of model results and field data validated the solution approach. In essence, we proposed a new alternative method to obtain the Bessel functions for the proposed transient-IPR method to minimize the undulations associated with the existing solutions. For verification of this simplified IPR modeling approach, we first attempted to replicate two-step flow rates with shut-in periods, such as those associated with a transient flow test. The model successfully reproduced those transient pressure profiles obtained from a rigorous superposition approach, generated with an analytical model. Thereafter, we replicated the results of a coupled wellbore/reservoir model for a gas-lift well, using a numerical simulator. The difference between the results of rigorous simulators and our simplified transient-IPR model turned out to be well within engineering accuracy. Field data from two plunger lift operations validated the transient-IPR model presented in this study. We observed that a smaller period of oscillation translates into a more significant error between the traditional steady-state IPR model and the actual transient-IPR model. This finding suggested the need for the accuracy of the transient-IPR model in ALS to express the realistic rates and pressures. By capturing the essence of transient behavior, we can combat downhole tool failures arising from large pressure fluctuations or issues with surface metering due to higher than expected rates.",0,0,1
Steady State,Field Data,"Ossai, Chinedu, I",Pump-off identification with time series analysis of transient water discharge rate,Prognosis; Progressing cavity pump; Pump-off identification; Water discharge rate; Time series; Transition probability,PERFORMANCE; MODEL; GAS,"To advance the prognosis of progressing cavity Pumps (PCPs) used for artificial lifting, the pump-off need to be identified to forestall failure. This study developed a new technique for determining the Pump-off events Activation Times (PATs) of the PCPs using the transient Water Discharge Rates (WDRs) from coal seam gas producing wells. The Gaussian distribution function parameters of the rolling standard deviations of the water discharge rate (RSWR) and the transition probability of the rolling standard deviations of the water discharge rate (TP_RSWR) were used to build the model. By determining the anomalies in the RSWR signals with the bottom-up segmentation technique and computing the statistical characteristics at the changepoint locations, the steady-state of the WDR signals was established. This steady-state signal, which represents the Operation Transition Level (OTL) between the Normal Operation (NOP) and the Pump-off Event (POE) was used for monitoring the transition of the PCPs' operating status. An algorithm was developed in Python and tested it on field data from 36 coal seam gas wells. The performance of my technique was determined with precision, recall and F1 score, which gave an average value of 94.94%, 92.63%, and 93.56% respectively. It is expected that the implementation of this technique in the real-time estimation of PATs will be vital for reducing PCPs faults seeing that poor PATs detection results in PCPs running dry and consequently failures due to the extreme temperatures and abrasions.",0,0,1
Steady State,Coalescence,"Sun, Baojiang; Yang, Caifeng; Wang, Zhiyuan; Wang, Xuerui; Wang, Ning",Methodology for pressure drop of bubbly flow based on energy dissipation,Mechanism; Bubbly flow; Horizontal pipe; Energy dissipation; Pressure drop,MECHANISTIC MODEL; STEADY-STATE; PIPE-FLOW; PART II; COALESCENCE; VISCOELASTICITY; COEFFICIENT; PREDICTION; BREAKAGE; VELOCITY,"Pressure drop of bubbly flow is a widely used parameter in petroleum industry. The energy dissipation rate is induced by three factors, including wall resistance, bubble breakup and coalescence, which is studied here from the perspective of the macroscopic flow and microscopic bubbles. This work details a model using the principle of energy conservation to clarify the mechanism of the pressure drop for turbulent bubbly flow in horizontal pipes. The model was validated via a comparison with experimental data of horizontal bubbly flow collected from nine previous studies with 200 points. Most of the errors are within +/- 20%. The proportions of pressure drop induced by wall resistance, bubble breakup and coalescence were calculated by the model. The results indicate that the largest proportion is from wall resistance, followed by bubble coalescence, with bubble breakup having the smallest proportion. In addition, the trends of proportion induced by the three factors above are analyzed by increasing gas volume fraction and mixture viscosity. The results show that the proportion induced by wall resistance decreases with the increasing volume fraction of the gas, and increases with the increasing mixture viscosity. The proportions induced by the bubble breakup and coalescence in the opposite case.",3,3,1
Steady State,Coalescence,"Bagherzadeh, Hadi; Mansourpour, Zahra; Dabir, Bahram",A coupled DEM-CFD analysis of asphaltene particles agglomeration and fragmentation,Asphaltene; Agglomeration; Fragmentation; DEM-CFD,SIZE DISTRIBUTION; FLUIDIZED-BED; SIMULATION; AGGREGATION; MODEL; KINETICS; FLOW,"In the present paper, a Discrete Element Method-Computational Fluid Dynamics (DEM-CFD) approach along with a new coalescence model is adopted to study agglomeration and fragmentation of asphaltene particles, thoroughly. The collisions of asphaltene particles are investigated in three categories: collisions between individual primary particles (P-P collisions), individual primary particles and flocs (P-F collisions) and between flocs (F-F collisions). In addition, corresponding collision efficiencies have been determined based on the proposed coalescence model. Moreover, the importance of three different fragmentation modes including binary flocs fragmentations (binary fragmentation), detachment of a primary particle from floc (erosion) and splitting of floc into smaller flocs (large-scale fragmentation) is comparatively assessed. Eventually, the effect of fluid velocity and primary particles concentration on the aforementioned processes as well as asphaltene flocs properties are examined. Simulation results reveal P-P collisions contribution decreases continuously to reach a plateau in steady state condition while the contribution of P-F collisions increases initially and then it shows a gentle downward trend. F-F collisions contribution grows constantly up to steady state condition. The P-P and P-F collision efficiencies approximately remain constant whereas F-F collision efficiency continuously increases. In terms of fragmentation modes, contributions of binary fragmentation and erosion gradually decrease while large-scale fragmentation contribution constantly increases before steady state condition.",5,5,1
Steady State,Wall,"Goes, Maria Rosa R. T.; Teixeira, Rodrigo G. D.; Tavares, Frederico W.; Secchi, Argimiro R.",Wax appearance and prevention in two-phase flow using the multi-solid and drift-flux model,,THERMODYNAMICS; PRECIPITATION; PREDICTION; EQUILIBRIA; DENSITIES; LIQUIDS,"Wax precipitation may lead to obstruction of pipelines generating significant economic losses. Oil reservoirs, especially in the deepwater sea, are found in extreme conditions of pressure and, during the fluid flow inside the pipelines, the fluid temperature may decrease due to heat transfer to the surrounding (seawater) and phase change, tending to deposit solid particles on the pipeline walls. Within this context, it is important to develop a model that calculates the WAT (wax appearance temperature) of a fluid with known composition and then determine the point where the first paraffin crystal will appear inside a pipeline. The objective here is to provide a two-phase flow model coupled with paraffin precipitation model to calculate WAT inside the pipeline. We used the Drift-Flux Model to describe the two-phase flow in steady state and the Multi-Solid Theory to calculate the WAT. The results for a paraffinic mixture of four components show that the effect of the pressure can be considered negligible on WAT calculation for low pressure systems (< 10 MPa). Analyzing the effect of the fluid composition, the larger the number of light compounds in the mixture, the smaller will be the WAT, at constant pressure. For two different cases, it was determined the point inside the pipeline where the solid particles may deposit. We proposed an algorithm to find the minimum inlet temperature such that does not occur wax precipitation along the pipeline. The algorithm was successfully applied to a case study and may be useful for defining operational conditions to prevent solid blockage of pipelines.",1,1,0
Steady State,Wall,"Sun, Baojiang; Yang, Caifeng; Wang, Zhiyuan; Wang, Xuerui; Wang, Ning",Methodology for pressure drop of bubbly flow based on energy dissipation,Mechanism; Bubbly flow; Horizontal pipe; Energy dissipation; Pressure drop,MECHANISTIC MODEL; STEADY-STATE; PIPE-FLOW; PART II; COALESCENCE; VISCOELASTICITY; COEFFICIENT; PREDICTION; BREAKAGE; VELOCITY,"Pressure drop of bubbly flow is a widely used parameter in petroleum industry. The energy dissipation rate is induced by three factors, including wall resistance, bubble breakup and coalescence, which is studied here from the perspective of the macroscopic flow and microscopic bubbles. This work details a model using the principle of energy conservation to clarify the mechanism of the pressure drop for turbulent bubbly flow in horizontal pipes. The model was validated via a comparison with experimental data of horizontal bubbly flow collected from nine previous studies with 200 points. Most of the errors are within +/- 20%. The proportions of pressure drop induced by wall resistance, bubble breakup and coalescence were calculated by the model. The results indicate that the largest proportion is from wall resistance, followed by bubble coalescence, with bubble breakup having the smallest proportion. In addition, the trends of proportion induced by the three factors above are analyzed by increasing gas volume fraction and mixture viscosity. The results show that the proportion induced by wall resistance decreases with the increasing volume fraction of the gas, and increases with the increasing mixture viscosity. The proportions induced by the bubble breakup and coalescence in the opposite case.",3,3,1
Steady State,Volume,"Berg, Carl Fredrik; Danilova, Anna; Liu, Ming",Upscaling of polymer adsorption,,FLOW; EXPERIENCE; RESERVOIR,"This article considers upscaling of polymer adsorption. Input to adsorption values employed in reservoir simulation models are typically obtained from core plug measurements. There are several orders of magnitude in scale difference between core plugs and grid cells in reservoir simulation models, which foster a need for upscaling of the adsorption values. Polymer concentration distribution on the lithofacies scale is investigated in this article. The effect of diffusion on concentration distribution is investigated analytically. The slow diffusion of polymer molecules retards mixing even at the lithofacies scale. We introduce a formula to estimate the redistribution of polymer due to capillary forces in a layered model, and this formula is validated through numerical simulations. From our considerations we conclude that it is questionable to assume a constant polymer concentration in lithofacies models. This impedes applying steady-state upscaling techniques. Such upscaling techniques will over-predict polymer adsorption. Different methods for upscaling adsorption are presented in this paper, and applied to a simplified layered model and to more realistic fine-scale numerical models based on the SPE10 model. These numerical models were populated with adsorption values obtained from published experiments conducted on samples from the Brent sequence modeled in SPE10. Simulations of tertiary polymer flooding on the upscaled models were compared to simulations of the same flooding sequences on the original fine scale models. The tested upscaling methods include a volume averaging technique employed by other authors, and a method were we distribute the adsorption values by the same functional relationship as in the fine scale model. In addition we introduce upscaling methods were we assign zero adsorption to fine scale grid cells with permeability below a given cut-off value. The cut-off value is obtained from a single phase simulation on the fine scale model. In our models the cut-off value methods yield the best match between the coarse scale and fine scale simulation results. The volume averaging technique over-predict the polymer adsorption. Results from both the lithofacies and geomodel scale indicate a tendency to over-predict polymer adsorption, which could lead to conservative estimates for the effect of polymer flooding.",2,2,1
Steady State,Volume,"Sun, Baojiang; Yang, Caifeng; Wang, Zhiyuan; Wang, Xuerui; Wang, Ning",Methodology for pressure drop of bubbly flow based on energy dissipation,Mechanism; Bubbly flow; Horizontal pipe; Energy dissipation; Pressure drop,MECHANISTIC MODEL; STEADY-STATE; PIPE-FLOW; PART II; COALESCENCE; VISCOELASTICITY; COEFFICIENT; PREDICTION; BREAKAGE; VELOCITY,"Pressure drop of bubbly flow is a widely used parameter in petroleum industry. The energy dissipation rate is induced by three factors, including wall resistance, bubble breakup and coalescence, which is studied here from the perspective of the macroscopic flow and microscopic bubbles. This work details a model using the principle of energy conservation to clarify the mechanism of the pressure drop for turbulent bubbly flow in horizontal pipes. The model was validated via a comparison with experimental data of horizontal bubbly flow collected from nine previous studies with 200 points. Most of the errors are within +/- 20%. The proportions of pressure drop induced by wall resistance, bubble breakup and coalescence were calculated by the model. The results indicate that the largest proportion is from wall resistance, followed by bubble coalescence, with bubble breakup having the smallest proportion. In addition, the trends of proportion induced by the three factors above are analyzed by increasing gas volume fraction and mixture viscosity. The results show that the proportion induced by wall resistance decreases with the increasing volume fraction of the gas, and increases with the increasing mixture viscosity. The proportions induced by the bubble breakup and coalescence in the opposite case.",3,3,1
Neural Network,,"Orlov, Denis; Koroteev, Dmitry",Advanced analytics of self-colmatation in terrigenous oil reservoirs,Machine learning; Formation damage; Reservoir properties; Permeability reduction; Fine migration,FINES; FILTRATION; MIGRATION; MODEL,"One of the most significant issues of petroleum engineering nowadays is a decline in productivity and injectivity of wells due to formation damage, which is typically associated with the migration and retention of fines. The prediction of formation damage is a challenging problem due to the lack of information about concentrations and localizations of potential mobile fines in the reservoir. To solve this problem different algorithms of machine learning and data mining were tested: linear regressions, decision trees, random forest, gradient boosting and artificial neural networks. We developed the predictive model of permeability reduction in Vendian deposits (Russia) based on the analysis of rock properties and flooding conditions. This model allowed to describe the dynamic of permeability reduction as a multi-parametric function of injected pore volumes of water. Three defining parameters in the model were unique colmatation characteristics which have been predicted for each core sample. All the features of the self-colmatation process were studied and arranged by their importance. To build the model of permeability reduction we used two approaches. The first one was to discover all possible 2D cross-plot correlations between colmatation characteristics and features (manual analysis). The second is applying machine learning algorithms where all features were taken into account simultaneously. The benefits and disadvantages of both approaches were discussed in details.",0,0,0
Neural Network,,"Kim, Hyeonju; Lee, Gwang H.","A deterministic geomodeling case study for a thin clastic reservoir: The Second Wall Creek Sand, Teapot Dome field, Wyoming, USA",Teapot Dome field; Second Wall Creek Sand; Geomodeling; Neural network,CO2 SEQUESTRATION,"In this case study, we geomodeled the Upper Cretaceous Second Wall Creek Sand (SWCS) of the southern Teapot Dome field, Wyoming, USA, using public domain seismic and well-log data. The SWCS is an at-or-below seismic-resolution (about 20 m), fluvial-deltaic reservoir and has been the most productive in the field. The goemodeling procedure consisted of structural modeling of the depth 3-D grid (30 m x 30 m x 1 m cells) and petrophysical modeling for porosity and net-to-gross (N/G). The seismic data were enhanced by spectral balancing to resolve the SWCS. Facies modeling was not necessary because a facies analysis of gamma-ray logs and lithofacies and stratigraphic-discontinuity seismic attributes suggests a uniform facies. The porosity and N/G were modeled by neural network multi-attribute transform (NN-MAT). NN training included the absolute and relative impedances and three representative isofrequencies in addition to the conventional amplitude-and frequency-based attributes. The modeled porosity varies from less than 8% to over 18% with an average of 16.7% which agrees with the reported averages. The modeled N/G values range from about 0.2 to over 0.8 with an average of 0.7 which is greater than the reported average (0.5). The porosity and N/G models may not be optimal because only a few wells and a small number of the time samples for the thin reservoir interval were used in NN training. The geomodeling workflow presented in this study is optimized for thin reservoirs and can be used when facies modeling is difficult because NN-MAT computes petrophysical properties without being guided by facies models.",0,0,3
Neural Network,,"Karacan, C. Ozgen",An ANCOVA model for porosity and its uncertainty for oil reservoirs based on TORIS dataset,Mean value; Depositional system; Multi-linear regression; Reservoir assessment; ANCOVA; TORIS,PERMEABILITY PREDICTION; SEDIMENTARY; NORTH; SANDSTONE; EOCENE; ROCKS,"Porosity is one of the most important parameters to assess in-place oil or gas in reservoirs, and to evaluate recovery from enhanced production operations. Since it is relatively well-established to determine porosity using different laboratory and field methods, its value is usually determined at many locations across a reservoir as part of the common practice to capture reservoir heterogeneity and the variability in values. This suite of measurements and the distribution of values are most valuable for probabilistic reservoir assessments, and for spatial modeling if the exact data locations are known. Despite the importance of individual measurements to set the range of values for probabilistic studies, it is not always possible to access these data due to confidentiality. In most cases, commercial or publicly available databases that assessments may rely on usually report only mean values of porosity, like any other reservoir data, or they may not report a value at all. This makes both quantifying the mean value and the uncertainty around it difficult for probabilistic assessments. In this study, the TORIS (Tertiary Oil Recovery Information System) dataset of the National Petroleum Council and the U.S. Department of Energy was used to model porosity and the uncertainty around predicted values. TORIS is an integrated dataset of production data, reservoir properties, and project databases of crude oil reservoirs in the United States. The model presented in the paper was based on ANCOVA (Analysis of Co-Variance) of data from 1038 reservoirs from the TORIS dataset for porosity prediction, validation and testing for quantitative and qualitative parameters that may be readily available in most cases, and to estimate uncertainty around the mean values. This model also explored association of porosity values to different parameters, and to different depositional systems and diagenetic overprint conditions. Furthermore, an ANN (Artificial Neural Network) model was created to compare the predicted values of both models. Results showed that the ANN model was able to represent more of the variability, however it lacked the insights that might be gained from the ANCOVA model.",1,1,0
Neural Network,,"Miresmaeili, S. Omid H.; Zoveidavianpoor, Mansoor; Jalilavi, Madjid; Gerami, Shahab; Rajabi, Ali",An improved optimization method in gas allocation for continuous flow gas-lift system,Continuous flow gas-lift system; Artificial Neural Network; Bayesian regularization; Teaching-learning based optimization algorithm,LEVENBERG-MARQUARDT; TLBO; ALGORITHM; DESIGN; WELLS,"The primary objective in the continuous flow gas-lift operations is to inject an optimal gas volume for a group of wells to maximize oil production. Due to the gas supply constraint in an oilfield, optimization of gas injection plays an important role in achieving this goal. In this work, for modeling of gas-lift operation, the potential application of an Artificial Neural Network (ANN) using Bayesian Regularization (BR) is investigated and the results are compared with Levenberg-Marquardt (LM) back-propagation training algorithm. For the optimization, Teaching-Learning-Based Optimization (TLBO) algorithm is applied to simultaneously solve the well-rate and gas-lift allocation problems under the injection capacity constraint. The efficiency of the TLBO is investigated based on (a) convergence rate and (b) the best solution, by comparing its performance with Genetic Algorithm (GA). Extensive published data are used in model development and comparison. The proposed prediction and optimization model is tested in a gas-lift system for a given period of reservoir life. The prediction accuracy produced by the BRNN and the LMNN were 99.9% and 99.5% respectively. Results indicate that the two models have good predictive capability. Also, results show that the BR model appears more robust and efficient than the LM model and for the optimization algorithms, TBLO outperforms GA in the gas allocation mapping for continuous gas-lift system. The simulation results demonstrate the effectiveness of the proposed model on continuous flow gas-lift operations.",3,3,0
Neural Network,,"da Silva Ribeiro, Vanessa de Jesus; de Moraes Oliveira, Gabrielle Fontella; Cristian, Muara; Martins, Andre Leibsohn; Fernandes, Lindoval Domiciano; Vega, Marcia Peixoto",Neural network based controllers for the oil well drilling process,Downhole pressure; Control; Artificial intelligence; Pipe connection; Kick; Lost circulation,CONTROL SCHEME; KICK DETECTION; PRESSURE; PREDICTION; PARAMETERS; SIMULATION; MODELS; TIME,"The oil well drilling is a complex process, requiring that the bottomhole pressure be maintained within an operational window, limited by fracture pressure and pore pressure (and/or wellbore collapse). During the drilling process, there are several phenomena that directly influence the annulus bottomhole pressure: kick, lost circulation, inefficient removal of solids, well length increase, reservoir parameters and pipe connection procedure (surge and swab effects). The main objective of this work is to develop neural network controllers able to regulate the annulus bottomhole pressure under pipe connection procedure, kick and lost circulation disturbances. For this purpose, an experimental drilling unit was built, depicting the oil well drilling process primordial characteristics. Besides, real oil well offshore data were employed for validating the neural network controllers. Neural networks were built for predicting the direct plant dynamics (inverse neural network controller) and the inverse plant dynamics (direct neural network controller). It is noteworthy to mention that direct plant dynamics neural modelling was employed as the nonlinear model of a gain scheduling control approach; in addition, the inverse plant dynamics neural modelling constituted a nonlinear controller, directly predicting the manipulated variable. Both controllers employed real-time neural network training, being, therefore, adaptive schemes for regulating the oil well drilling process, which nature is inherently transient.",3,3,0
Neural Network,,"Huffner, Leonardo Nardi; Trierweiler, Jorge Otavio; Farenzena, Marcelo",Are complex black-box models for Permanent Downhole Gauge pressure estimation necessary?,,GAS-LIFT; OIL PRODUCTION; DESIGN; WELLS,"The Permanent Downhole Gauge (PDG) is a pressure and temperature sensor located subsea near the perforation point in the offshore oil production system. This sensor is very useful in operation problems detection (fouling, valves, plugging, etc.), multiphasic flow analysis, production tests adjustment, control strategy and model identification. Given its location under hazardous conditions, it may come to failure or imprecisions in measurement. The high costs related to the maintenance make it infeasible to perform. To overcome this issue, a methodology based on digital signal processing (DSP) is proposed in order to design a low pass digital filter aiming the PDG pressure reconstruction. The proposed methodology requires no plant model, low computational cost and only the Christmas-Tree pressure measurement. The proposed methodology is compared with two commonly employed black-box methodologies: Neural Network and Transfer Function Estimation. The results show the success of the designed filter and the advantages over the black-box approaches. The estimation of the PDG pressure from three operating wells using real process data was performed.",3,3,0
Neural Network,,"Maity, Debotyam; Ciezobka, Jordan",Designing a robust proppant detection and classification workflow using machine learning for subsurface fractured rock samples post hydraulic fracturing operations,Artificial neural nets; Image processing; Classifier benchmarking; Unconventional reservoirs; Core sampling; Shale rock,NEURAL-NETWORK; ALGORITHM,"Hydraulic fracturing is a method of reservoir stimulation that enhances the effective permeability of tight unconventional reservoirs such as shale oil and gas. In typical hydraulic fracturing treatments, millions of gallons of water are pumped under pressure into rock formations deep below the earths surface. Proppant particles such as sand are injected as part of the fracturing slurry to hold the hydraulic fractures open, or propped, after high-pressure water injection has ceased. Propped hydraulic fractures provide a conduit for long-term hydrocarbon production, thus being essential to commercial oil and gas production from shale reservoirs. The distribution of the proppant particles can be useful in understanding effectiveness of hydraulic fracturing treatments. It can also help identify both, unstimulated and under-stimulated zones within the reservoirs of interest. These proppant particles can be found in drilling fluid return or in cores, which can be sampled from subsurface. In this study, we highlight the design and development of artificial neural network based workflow that helps identify where proppant particles are located and classifies proppant and various particles of interest. In this study, these particles are limited to naturally occurring calcite or other minerals from subsurface rocks. Various features of interest that help with the classification process have been conceptualized and defined. This method has been verified using controlled test cases and validated using actual samples from subsurface. The designed ANN classifier has also been benchmarked with other classification methods including k-nearest neighbor, naive-Bayes classifiers and Support vector machines. A workflow to process samples from subsurface and quantify proppant distribution for future test programs including potential real time applications has been proposed. Based on this workflow, we share proppant distribution from a Permian Basin case study. We have also compared proppant distribution using our proposed method with results from an independent workflow on a similar dataset, which does not utilize machine learning.",5,5,0
Neural Network,,"Azamifard, Arash; Rashidi, Fariborz; Ahmadia, Mohammad; Pourfard, Mohammadreza; Dabir, Bahram",Toward more realistic models of reservoir by cutting-edge characterization of permeability with MPS methods and deep-learning-based selection,Reservoir simulation; Permeability modeling; Multiple point statistics; Deep learning; Geostatistic; Convolutional neural network (CNN),GEOSTATISTICAL SIMULATION; CONDITIONAL SIMULATION; IMAGE; UNCERTAINTY; ALGORITHM; FLOW; CLASSIFICATION; RECONSTRUCTION; HETEROGENEITY; TRANSPORT,"Different sources of data are used to construct a reliable model of reservoir for oil/gas production. This model ought to be matched with the production history of reservoir and also show reliable predictions for future performance. To this end, permeability modeling (characterization of heterogeneity) is crucially important which is proved to be done by Multiple Point Statistics (MPS) recently. Furthermore, deep learning methods are massively used as a promising tool for regression applications. In this study, one MPS method is employed for generating the reservoir realizations. Realizations, alongside their simulation outputs, are utilized for training a convolutional deep network. In this manner, MPS is joined with deep learning to find the most appropriate realization(s) of the reservoir based on the fluid flow simulation. Moreover, unseen MPS realizations as well as another MPS realizations are used to verify the selection ability of trained network. The detailed architecture of convolutional network is illustrated in this study. The purpose of training this network and combination with MPS is to generate the matched realization(s) in history period that also show acceptable reservoir behavior in the future times of reservoir simulation. After training, the actual production data of selected realizations are obtained by simulation the reservoir for history and also future times. The results show that selected realizations efficiently capture the trend of reference behavior. Although these realizations lack identical permeability values, they have same texture of permeability (permeability heterogeneity). Meanwhile, they show acceptable match in reservoir simulation outputs. By proposed workflow, the uncertainty of permeability modeling is considered more exhaustively. It is done by selecting the realizations from enormous possible realizations dataset and providing a deep learning tool which is capable for screening quite large number of realizations. Interesting finding is satisfactory behavior of realization(s) in both history and future periods of reservoir performance.",5,5,1
Neural Network,,"Rubo, Rafael Andrello; Carneiro, Cleyton de Carvalho; Michelon, Mateus Fontana; Gioria, Rafael dos Santos",Digital petrography: Mineralogy and porosity identification using machine learning algorithms in petrographic thin section images,Image segmentation; Artificial neural networks; Random forest; Supervised learning; Optical mineralogy; Carbonate rocks,NETWORKS; LOGS,"Images represent a large and efficient source of geological information from oil exploration. To better analyze them, well-known machine learning algorithms are used to extract mineralogy and porosity data from petrographic thin section images. Microscopic petrographic analysis allows obtaining images from thin sections in the visible spectrum. They are used to evaluate depositional environments and diagenetic processes during the formation of sedimentary basins. However, that is an activity subjected to the petrographer's experience. Data from other sources, such as chemical microanalysis, provide quantitative information that might assist in petrographic evaluation, but they are expensive and time-consuming. The main objective is to create models that systematically interprets mineralogy and porosity from images acquired of optical microscopic analysis using machine learning algorithms, standardizing descriptions and reducing subjectivity and human errors during thin sections analysis. Image segmentation models are created with representative classes of the rocks' mineralogy and porosity. Datasets were selected from images originated from thin sections of carbonate rocks, which are prepared from sidewall core samples of oil wells, specifically from the pre-salt reservoirs of Santos Basin, on the southeast coast of Brazil. These models use discrete convolutional filters followed by artificial neural networks and random forest classifiers. A number of configurations were tested, using different convolutional filters and classifier's parameters. Five models were created: 1. mineralogical model using artificial neural network; 2. mineralogical model using random forest; 3. mineralogical model using random forest validated by chemical measurements; 4. porosity model using artificial neural networks; and 5. porosity model using random forest. They were evaluated through the use of 10-fold cross-validation tests and by correlation with chemical microanalysis. Correlation between the two technique's relative occurrences for each mineral phase shows a root mean square error of 8.99% and a coefficient of determination of 0.82. That demonstrates how well models can generalize.",5,5,4
Compressive Strength,,"Anya, Alexander; Emadi, Hossein; Watson, Marshall",An empirical model for calculating uniaxial compressive strength of oil well cements from ultrasonic pulse transit time measurements,Oil well cement; Uniaxial compressive strength; Correlation; Ultrasonic cement analyzer,CONCRETE,"Thirty-five cement samples were tested in an Ultrasonic Cement Analyzer (UCA) at varying curing conditions and for varying curing times, and then uniaxially compressed to failure in a hydraulic press. An attempt was made, using the ultrasonic transit time data measured with a UCA and the uniaxial compressive strength data measured using a hydraulic press, to derive an empirical model capable of accurately predicting uniaxial compressive strength from the ultrasonic transit time. Using the Levenberg-Marquardt algorithm, the experimental data was fit to two models. In addition to the transit time dependence, the first model presented incorporates a term that accounts for the curing time while the second model contains terms that account for both the curing time and cement composition. The results obtained illustrate the complexity of deriving a correlation with general applicability to all well cements. The best performing model based on both curve fit error and prediction performance for the samples tested was the model that accounted only for the curing time dependency of the cement strength development rate in addition to the measured transit time, indicating that the transit time measurement history is sufficient as a tool for characterizing well cement strength development.",1,1,0
Compressive Strength,,"Panchmatia, Parth; Zhou, Nancy S.; Juenger, Maria; van Oort, Eric",Monitoring the strength development of alkali-activated materials using an ultrasonic cement analyzer,Ultrasonic cement analyzer; Compressive strength; Alkali activated material; Fly ash,,"The ultrasonic cement analyzer (UCA) is used as an aid to develop new cement formulations or perform quality assessment on existing formulations prior to on-site application. The non-destructive UCA technique monitors the strength development of cements by measuring the time required for ultrasonic waves to travel through the cement sample and predicting the strength using empirical correlations, which were developed for ordinary Portland cement slurries. Unfortunately, these empirical correlations cannot be used to accurately predict the strength development for fly ash-based alkali activated materials (AAMs), which are a viable alternative to ordinary Portland cement slurries for oil-well cementing applications. Therefore, a new empirical correlation linking the transit time (i.e. the time required for ultrasonic waves to travel through a unit length of the cement sample) to the compressive strength of fly ash-based AAMs was developed in this study. Class F fly ash was activated by four different alkaline solutions, two sodium hydroxide solutions with 6M and 8M concentrations and two sodium silicate solutions with SiO2/Na2O weight ratio of 0.12 and sodium concentration of 6M and 8M, to produce 4 different slurries which were cured under downhole conditions. 50 mm cubes were crushed to determine the compressive strength of these AAMs after 18, 24, 48, and 72 h of curing. UCA testing was conducted to measure the transit time up to 72 h of curing. Linear regression was performed to develop a correlation linking the measured compressive strength to the measured transit time and AAM mix design parameters. One-way ANOVA analysis revealed that the change in transit time, the concentration of sodium in the activator solution, the SiO2/Na2O weight ratio of the activator solution, and the CaO content of the FA were all significant in predicting the compressive strength of the resulting AAM. The proposed model is applicable for AAMs prepared using Class F fly ash and sodium hydroxide/silicate activating solution with sodium concentration and SiO2/Na2O weight ratio ranging between 6M and 8M and 0 and 0.12, respectively.",2,2,0
Compressive Strength,,"Salah, Mohamed K.; Abd El-Aal, Ahmed K.; Abdel-Hameed, A. T.","Influence of depositional and diagenetic processes on the petrophysical and mechanical properties of Lower Miocene sandstones, Qattara Depression, Northwestern Egypt",Moghra formation; Petrophysics; Mechanical properties; Diagenetic impacts; Sedimentary environment; Qattara depression,UNIAXIAL COMPRESSIVE STRENGTH; SLAKE DURABILITY INDEX; POINT LOAD INDEX; P-WAVE VELOCITY; ENGINEERING PROPERTIES; GEOTECHNICAL PROPERTIES; PHYSICAL-PROPERTIES; IMPACT STRENGTH; WESTERN DESERT; ROCK,"The main objective of this study is to investigate the impact of the depositional and diagenetic processes on the petrophysical and mechanical properties of the Lower Miocene Moghra Formation sandstones exposed at the Qattara Depression, Northwestern Desert, Egypt. We conducted several petrophysical and mechanical investigations on a large number of core samples collected from the study area to determine their petrophysical and mechanical characteristics. Results of petrographical, scanning electron microscope (SEM), and the X-ray diffraction (XRD) analyses revealed that the studied sandstones are composed essentially of quartzarenites with minor limestone and shale intercalations and can be grouped into three sedimentary lithofacies: fossiliferous dolomitic quartzarenites, ferruginous quartzarenites and calcareous quartz arenite. The main diagenetic processes encountered in the Moghra sandstones are compaction, cementation, and dissolution. These processes significantly affected the porosity and influenced the petrophysical and mechanical parameters of the studied sandstones. The Moghra sandstones have average values of 14.51%, 2.24 g/cm(3), 22.38 mD, 45.77%, and 3377 m/s, for porosity (phi), bulk density (rho(b)), permeability (K), irreducible water saturation (S-wirr), and the P- wave velocity (Vp), respectively. In addition, these rocks have average values of 83.98 MPa, 5.97 MPa, and 34.42, for the unconfined compressive strength (UCSdry), the point load strength index (IS50), and the Schmidt hammer number (SHN), respectively. Significant relationships, with moderate/high correlation coefficients, have been obtained between the investigated parameters of the studied sandstones. The studied sandstones, however, showed no clustering of their petrophysical and mechanical properties based on their facies type. The present results indicate that both porosity and bulk density, which are in turn the products of the depositional and diagenetic history of the investigated rocks, are major parameters controlling the other petrophysical and mechanical properties of the studied rocks.",2,2,0
Compressive Strength,,"Matias Paiva, Luanna Carla; Ferreira, Irantecio Mendonca; Martinelli, Antonio Eduardo; de Oliveira Freitas, Julio Cezar; Bezerra, Ulisses Targino",Milled basalt fiber reinforced Portland slurries for oil well applications,Basalt fiber; Oil well cement; Portland cement; Silica flour,MECHANICAL-PROPERTIES; SILICA FUME; CEMENT; CONCRETE; TEMPERATURE; STRENGTH; BEHAVIOR; MICROSTRUCTURE; PERFORMANCE; DURABILITY,"The dispersion of short fibers to oil well Portland slurries may improve the compressive strength and fracture energy of the hardened cementing material. A study was carried out to investigate the effect of the addition of ball-milled basalt fibers (5% BWOC) to Portland slurries. Samples were prepared with and without silica flour (40% BWOC) in the composition and cured for 7 days under different Bottom Hole Static Temperatures (BHST): 80 degrees C (176 degrees F) and 300 degrees C (572 degrees F). The mechanical properties and the microstructure of the hardened pastes were evaluated by compressive strength tests, X-ray diffraction and scanning electron microscopy. The results showed that milling basalt fibers was a cost efficient method to adjust the length of the basalt wool fibers assuring slurry mixing and, therefore, adequate pumpability. The combined addition of silica flour and basalt fibers improved the fracture energy of samples cured at 80 degrees C, therefore below the strength retrogression temperature. Curing at 300 degrees C resulted in significant fiber consumption by pozzolanic reactions that could not be prevented by the addition of silica flour. Therefore, ball-milled basalt fibers can be a cost-efficient and environmental-friendly solution to improve the mechanical properties of oil well cement slurries used below the retrogression temperature.",2,2,7
Compressive Strength,,"Ichim, Adonis; Saleh, Fatemeh K.; Teodoriu, Catalin; Sondergeld, Carl",Investigation of mechanical behavior and physical characteristic of portland cement: Implications for destructive and non-destructive methods,Unconfined compressive strength (UCS); Ultrasonic pulse velocity (UPV); Porosity; NMR,RELAXATION,"Oilfield cements are a key element in well construction, during the operational phase of a well, and after its abandonment. Evaluating and understanding cement properties is crucial, since these properties are used in various engineering designs and calculations. In many scenarios, these properties are assumed constant with time, but an increasing number of studies have shown how properties change with time, temperature, and pressure. This work presents experiments run on API Class G cement mixed with and without additives and cured at 25 degrees C, 50 degrees C, and 75 degrees C, and constant pressure over a total of approximately two years. The influence of time, temperature, and additives on the performance of these cements is evaluated, and destructive and non-destructive testing methods are used to develop correlations to assess cement mechanical properties and to understand the development of porosity and its influence on cement performance. We applied NMR for the non-destructive evaluation of porosity, pore size distribution, cement water saturation, and curing of cement.",3,3,0
Compressive Strength,,"Liu, Houbin; Liu, Teng; Meng, Yingfeng; Han, Xu; Cui, Shuai; Yu, Anran",Experimental study and evaluation for borehole stability of fractured limestone formation,Fractured formation; Mechanical properties; Borehole stability; Collapse pressure; Fracture strike,MODEL,"With the increase of drilling depth, the stability of the borehole in deep fractured formation has received more and more attention. The exploration and development of fractured formations is difficult, because complex conditions such as borehole collapse, circulation loss, pipe-sticking occur frequently, causing huge economic losses and affecting the later drilling operations. Therefore, it is very important to study the stability of fractured formation. Observations of the microstructural characteristics and mechanics performance testing reveal the influence of fracture on the mechanical properties of limestone and enable the establishment of a model of collapse pressure as a function of fracture strike (the angle between the fracture and the maximum horizontal principal stress). The results showed that the fractures have great influence on the mechanical strength of rock and that the compressive strength of rock containing fractures is similar to 30% lower than that of bedrock on average. The influence of different fracture strikes on the stability of the borehole varies, with a maximum effect occurring for fracture orientation of 40 degrees-60 degrees. The model of fractured formation collapse pressure is consistent with the results of mechanical experiments. This research results provide a guiding value for stability studies of fractured formations.",3,5,3
Compressive Strength,,"Tong, Shaokai; Gao, Deli",Elastic-plastic collapse limit analysis of coiled tubing under complex stress state,Collapse limit; Coiled tubing; Twin shear unified strength theory; Yield criterion; Complex stress,,"Collapse failure of coiled tubing (CT) due to complex stresses is an important issue during the operations in the oil and gas wells. This paper presents new analytical models to define the collapse limit of CT and solve the problem of CT failures. Elastic-plastic collapse limit models of CT are established based on the twin shear unified strength theory. The effects of axial force, buckling, and internal pressure on the elastic-plastic collapse limit are analyzed. Moreover, the comparisons among the new model, the existing model and API specification are further discussed. The results indicate that the elastic-plastic collapse limit models determined using the twin shear unified strength theory can describe the mechanical behaviors of CT under complex stress state. Elastic-plastic collapse limits of CT decrease with increasing axial tensile force and increase with increasing axial compressive force. The effect of buckling and bending stress on the elastic-plastic collapse limit cannot be ignored in the analysis of CT collapse. With increasing external pressure, the plastic region keeps extending to the outer surface of CT. Plastic collapse limit is the value of external pressure for which the entire wall thickness of CT becomes plastic. The proposed approach can be used to set the elastic-plastic collapse limits for other oil tubulars.",4,5,0
Compressive Strength,,"Abid, Khizar; Gholami, Raoof; Tiong, Michelle; Nagaratnam, Brabha; Sarmadivaleh, Mohammad; Mostofi, Masood; Bing, Chua Han; Muktadir, Golam",A pozzolanic supplementary material to reinforce class G cement used for drilling and completion operations,Class G cement; POFA; Nanosilica; Strength enhancement; Extender,FILLER; MICROSTRUCTURE; HYDRATION,"There have been many studies to improve cement integrity under different pressure and temperature conditions where cement degradation is initiated by the mechanical and chemical interactions. Several approaches were presented so far to resolve this issue, many of which are either expensive or inefficient under certain circumstances. In this paper, attempts are made to show the application of Palm Oil Fuel Ash (POFA) as a cheap but efficient supplementary cementing material (SCM) for drilling and completions practices. A series of experiments were conducted to evaluate the changes in the density, free fluid, rheology, weight on cement, compressive strength, matrix structure and composition of the cement modified by POFA. The results obtained indicated that POFA has a hydrophilic surface and can retard pozzolanic reactions. It was appeared that POFA does not significantly change the rheology but may reduce the plastic viscosity. After 24 h and 9 months of curing, 5 wt% POFA based cement appeared to have the highest compressive strength with a very consolidated matrix as observed through XRD, TGA and SEM tests. It was also revealed that nanosilica (NS) may significantly increase the plastic viscosity of the cement while POFA may give a higher strength to the cement in a long curing process. It was then concluded that POFA can be a very good choice to improve the mechanical strength and the matrix structure of the cement under different drilling conditions.",5,5,1
Carbonate Cements,,"Yang, Xiao-Fa; Ma, Zhong-Zhen; Zhou, Yu-Bin; Zhang, Zhi-Wei; Liu, Ya-Ming; Wang, Dan-Dan; Zhao, Yong-Bin","Reservoir characteristics and hydrocarbon accumulation of the glauconitic sandstone in the Tarapoa Block, Oriente Basin, Ecuador",Glauconitic sandstone; Reservoir characteristics; Hydrocarbon accumulation; Oriente basin; Ecuador,NAPO FORMATIONS; HOLLIN; ORIGIN; FIELD; OIL,"Although Oriente basin has explored throughout the past fifty years, little is known about the reservoir quality and hydrocarbon accumulation of the Cretaceous Upper T glauconitic sandstones. Until recently, the Upper T has drawn attention due to the commercial oil discovery. Howerer, exploration of glauconitic sandstones is complicated and reservoir quality is difficult to evaluate based on logging and seismic data. The glauconitic sandstones developed in open marine environments, characterized by a framework of glauconite and quartz grains. Diagenesis includes compation, silica overgrowth, feldspars dissolution, iron carbonate cementation. Its porosity ranges 5-20% and less than 500 md permeability. The dominant pore type is intergranular, especially residual intergranular. Glauconitic sandstones have bimodal pore throat size distributions and complex pore geometries. The Upper T glauconitic sandstones are capped by a thin veneer of fossiliferous limestones and laminated to burrowed shales. These large-area matured source rocks close to the glauconitic sandstones are probably the source kitchen in the slope of Oriente Basin. The oil pools are very little relation to structure. A large area of continuous developed glauconitic sandstone reservoirs and adjacent source rocks form an excellent source-reservoir-cap assemblage. Differ from previous views of long-distance migration from the southwest Oriente Basin, we propose that volume flow and diffusive flow are the primary migration and accumulation mechanism for the Upper T reservoir in Tarapoa Block.",0,0,1
Carbonate Cements,,"Zhang, Tianjiao; Zhang, Shanwen; Meng, Wei; Feng, Yuelin; An, Tianxia",Characteristics and genetic mechanism of carbonate cements in sandstones near the overpressure top surface: A case study of the Niuzhuang Depression in Bohai Bay Basin,Overpressure top surface; Carbonate cements; Carbon and oxygen isotope; Overpressured fluid; Sandstone reservoir,PORE-PRESSURE; RESERVOIR SANDSTONES; DIAGENETIC HISTORY; SHAHEJIE FORMATION; PART 1; ORIGIN; PETROLEUM; FIELD; COMPACTION; EVOLUTION,"Carbonate cements are important authigenic minerals in the sandstone reservoir near the overpressure top surface in the Niuzhuang Depression. However, their genetic mechanism has not been studied in detail. This study uses observations of casting thin sections and cathodoluminescence and micro-area electron probe compositional data to determine that the diagenetic sequence of these carbonate cements is penecontemporaneous dolomite -> calcite filling primary pores -> calcite/iron-bearing calcite filling secondary dissolution pores -> ankerite. The genetic mechanisms of these carbonate cements are analyzed based on the fluid inclusion temperature at different phases of carbonate cementation, carbon and oxygen isotope composition, simulation of the thermal evolution of the hydrocarbon source rock, and elemental chemical composition. Results show that the carbon isotopic compositions of the carbonate cements are affected not only by organic acids released during the maturation of organic matter but also by the dissolution of lacustrine carbonate rock in the fourth member of the Shahejie Formation. Dissolution-reprecipitation of the lacustrine carbonate rocks is responsible for an obvious positive drift in the delta C-13(PDB) values of carbonate cements near the overpressure top surface. There are four phases of carbonate cementation near the top surface of the overpressured zone, with phase IV carbonate cements mainly occurring near the overpressure top surface. Phase I carbonate cements are mainly dolomite, and their formation is related to the decomposition of organic matter by methanogenic bacteria. Phase II carbonate cements are related to Ca2+ and CO32- supersaturation during pore fluid concentration. Phase III carbonate cements result from overpressured fluid that is rich in Ca2+ and Mg2+ and feldspar dissolution caused by overpressure fluid intrusion. Phase IV carbonate cements are derived from CO32- formed by organic acid pyrolysis in late diagenesis, CO32- formed by early carbonate cement dissolution, and Mg2+ and Fe2+ plasma formed by the dissolution of metamorphic rock debris into pore fluid. The formation of phase III and IV carbonate cements is most affected by overpressured hydrocarbon fluids.",1,4,4
Carbonate Cements,,"Jiang, Lei; Xu, Zhaohui; Shi, Shuyuan; Liu, Wei","Multiphase dolomitization of a microbialite-dominated gas reservoir, the middle Triassic Leikoupo Formation, Sichuan Basin, China",Microbialite reservoirs; Dolomitization; Meteoric water diagenesis; Sulfate reduction; Hydrothermal fluids,DOLOMITE RESERVOIRS; FEIXIANGUAN FORMATION; CARBONATE RESERVOIRS; CREEK FIELD; TARIM BASIN; POROSITY; EVOLUTION; PRECIPITATION; DELTA-C-13; FACIES,"Microbialites have great economic potentials in hosting hydrocarbons throughout the geological record. Diagenesis, particularly dolomitization, has been proven to be crucial in microbialite reservoir development, however, the impacts of dolomitization on microbialite reservoir quality were not yet clearly understood. In this study, core samples covering the Middle Triassic Leikoupo formation were collected, and combination of petrology, fluid-inclusion microthermometry, and stable and radiogenic isotopes analyses was conducted, aiming at unraveling the origin of the dolomites and their reservoir characteristics in the microbialites from the Sichuan Basin, China. Two types of microbial dolostone reservoir were determined and compared in terms of their dolomitization mechanisms and reservoir characteristics. Organogenic dolomitization mediated by microbial activities probably resulted in the initial biotic dolomicirte (D1) precipitation in sediment pile as a consequence of bacterial sulfate reduction (BSR), characterized by significant delta C-13 depletion compare to the middle Triassic seawater value. An early stage dolomitization, occurred in fluids dominated by seawater was responsible for the precipitation of very fine crystalline dolomite (D2). Burial dolomitization, precipitated medium-to coarsely crystalline dolomite cements (D3) from burial brine in temperatures between 120 degrees C and 160 degrees C and characterized by elevated Sr-87/Sr-86 values and slightly low delta C-13 values. Last hydrothermal dolomitization event, represented by saddle dolomite cement (D4), has probably occurred and is associated with deeply-seated hydrothermal fluids at temperatures > 200 degrees C. Abiotic microbialite dolomudstone reservoir quality (D2) (porosity = 7.4%; permeability = 24.9 mD) superior to the biotic microbial-mediated dolomudstone reservoir (D1) (porosity=1.4%; permeability=0.6 mD). Microbialite dolomudstone reservoirs (D2) are microporous, with the presence of both primary porosity, e.g., framework and interparticle, and secondary porosity, e.g., solution-enlarged and micropores. The wide occurrence of intragranular and micro-fracture, together with the proximity of larger macropores, may increase connectivity and allow for a combined micropore to macropore transport process for natural gases. Micropores in these dolostones were interpreted to be formed by mole to mole replacement of calcite by dolomite. Hence, this study emphasizes the important role of dolomitization in the formation of ancient microporous microbialites reservoirs characterized by low porosity and low permeability.",3,5,0
Carbonate Cements,,"Lai, Jin; Li, Dong; Wang, Guiwen; Xiao, Chengwen; Cao, Juntao; Wu, Chun; Han, Chuang; Zhao, Xinjian; Qin, Ziqiang",Can carbonate cementation be inhibited in continental red bed sandstone?,Red bed; Carbonate cements; Sandstone; Grain coats; Bashijiqike formation; Kuqa depression,TRIASSIC YANCHANG FORMATION; COARSE CLASTIC ROCKS; NORTHERN TARIM BASIN; RESERVOIR QUALITY; KUQA DEPRESSION; PORE STRUCTURE; DEPOSITIONAL FACIES; DIAGENETIC ALTERATIONS; POROSITY PRESERVATION; CRETACEOUS SANDSTONES,"The Lower Cretaceous Bashijiqike Formation in Kuqa depression belongs to a continental red bed sandstone with poor reservoir quality, and is deeply buried to 5.5-7.0 km but some successions can host porosity > 10% and permeability larger than 10 mD. Carbonate cements are important pore-filling constituents, and they control the reservoir quality and heterogeneity of Bashijiqike sandstones. Red hematite-bearing grain-coating clay minerals inhibit the pore occluding quartz cements and preserve intergranular pores. Here we investigate the ability of grain-coating clays to inhibit carbonate cements. Thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), and cathode luminescence (CL) analysis were performed to investigate the petrography, pore systems, diagenesis and diagenetic minerals of the red bed sandstones. The results show the hematite-bearing grain coatings give the ""red bed"" colors of the sandstones. The sandstones are heavily mechanically compacted, and the predominant pore-filling cements include carbonates and clay minerals, while quartz cements are volumetrically not important in reducing porosity. The grain-coating clays are mainly hematite-bearing mixed-layer illite and smectite. The paragenetic sequences of various types and generations of diagenetic events were reconstructed. Sandstones containing effective mixed-layer illite and smectite coatings, in which the intergranular pores can be preserved, have high porosities. Carbonate cement is never found in sandstones with effective grain coating clays, and carbonate cement precipitates where there are no sufficiently thick and continuous grain coats. The clay coatings retard or inhibit eogenetic calcite cements and progressively restrict late-stage carbonate (dolomite) cementation during burial. The hematite-bearing grain-coating clays help the red bed sandstones retain good reservoir quality at great depths.",3,3,3
Carbonate Cements,,"Ye, Ning; Zhang, Shaonan; Qing, Hairuo; Li, Yingtao; Huang, Qingyu; Liu, Di","Dolomitization and its impact on porosity development and preservation in the deeply burial Lower Ordovician carbonate rocks of Tarim Basin, NW China",Tarim basin; Ordovician; Penglaiba formation; Dolomitization; Geochemistry; Porosity development,STRONTIUM ISOTOPIC COMPOSITION; CAMBRIAN-ORDOVICIAN; HYDROTHERMAL ALTERATION; PLATFORM DOLOMITES; MATRIX DOLOMITES; SEA-WATER; ORIGIN; AREA; EVOLUTION; RESERVOIR,"The deeply buried dolostones (> 6000 m) of the Lower Ordovician Penglaiba Formation are currently the key targets of hydrocarbon exploration in the Tarim Basin. Petrographic, isotopic, and fluid inclusion microthermometric data were obtained in an attempt to determine the origin of dolostones and its effect on porosity development. Based on the petrography examination, three matrix dolomites and two dolomite cements were identified: very finely to finely crystalline, nonplanar-a to planar-s (D1) dolomite; finely to medium crystalline, planar-s to planar-e (D2) dolomite; medium to coarse crystalline, nonplanar-a (D3) dolomite; medium to coarse crystalline dolomite cements (Cd and Sd). D1 dolomite, which commonly occurs widely distributed throughout the study area, is characterized with delta C-13(VPDB) values of -2.4 to -0.1%, delta O-18(VPDB) values of -8.1 to -4.1%, and Sr-87/Sr-86 ratios of 0.70899-0.70979, inferring the seawater origin. D2 dolomite, merely confined to one side of the stylolite, has delta C-13(VPDB) values of -1.8 to -0.4%, delta O-18(VPDB) values of -8.3 to -3.7%, and Sr-87/Sr-86 ratios of 0.70871-0.70955, suggesting that D2 is precipitated in shallow-middle burial conditions and the dolomitizing fluids is derived from the residual primitive seawater in the formation. D3 dolomite is considered to be formed at higher temperatures under deep burial conditions considering its crystal textures and the delta O-18(VPDB) values of -9.0 to -6.8%. The two dolomite cements, Cd and Sd dolomites, are characterized with the inclusion T-h values of 119-163 degrees C and Sr-87/Sr-86 ratios of 0.70941-0.70993, inferring the hydrothermal origin. Based on the distribution, petrography and geochemistry data of D1, the mainly hydrological system for dolomitization in the Penglaiba Formation is interpreted to be the seepage-reflux model. Intercrystalline pores and vugs are two types of pores associated with dolomitization, the latter being the most dominant type that is related to hydrothermal dolomitization.",4,4,0
Carbonate Cements,,"Fu, Mei-Yan; Song, Rong-Cai; Gluyas, Jon; Zhang, Shao-Nan; Huang, Qian",Diagenesis and reservoir quality of carbonates rocks and mixed siliciclastic as response of the Late Carboniferous glacio-eustatic fluctuation: A case study of Xiaohaizi Formation in western Tarim Basin,Carbonates; Mixed siliciclastic; Diagenesis; Reservoir quality; Hydrothermal; Glacio-eustatic,SEA-LEVEL FLUCTUATIONS; ISOTOPE STRATIGRAPHY; BACHU AREA; DICKITE; KAOLINITE; EVOLUTION; SEDIMENTS; PLATFORM; FACIES; DOLOMITIZATION,"Late Carboniferous-Permian was a longest-lived and most widespread ice age. The depositional environment, diagenesis and reservoir quality of carbonate rocks as response to the glacio-eustatic changes was analyzed in this study. The Upper Carboniferous Xiaohaizi Formation in the western Tarim Basin is an important oil reservoir. The dolostones from the Xiaohaizi Formation have very good physical properties, with maximum porosity and permeability of 16.6% and 214mD, respectively. The sedimentary facies of the Xiaohaizi Formation consist of carbonate shoals and lagoon on a mixed siliciclastic-carbonate platform. There was a strong heterogeneity of carbonate rocks deposited on shoals. Porous dolostones always alternate with tight sparry allochemical limestones. Based on the petrographic observation and stable isotope measurement, the controlling factors for the heterogeneity and reservoir quality were revealed. The palaeosol, vadose silt, karst breccia, detrital kaolinite, darkening of dolostones and enrichment of O-18 indicate the short-lasting subaerial emergence during the glacial period. During the glacial sea level fall, the mixed siliciclastic and carbonate allochems deposited on bioclastic and intraclastic shoals, while dolomitization of calcic grains occurred under a relatively low-temperature. Through the correlation analysis of physical property, lithology, rock components, ifs suggested that the reservoir quality of the Xiaohaizi Formation was controlled by mixed sedimentation and dolomitization associated with glacio-eustatic fluctuation. M the burial diagenesis, the effect of hydrothermal fluid on physical properties of dolostones with relative high primary porosity was positive, whereas resulted in the poikilotopic calcite cementation. The assembly of fluorite, dickite and authigenic pyrite were indicators for hydrothermal fluid accumulation. The control of glacio-eustatic fluctuations on sedimentation and diagenesis in carbonates could be used to forecast the reservoir quality.",5,5,1
Carbonate Cements,,"Benayad, Soumya; Ysbaa, Saadia; Chaouchi, Rabah; Haddouche, Omar; Kacimi, Aymen; Kaddour, Hichem","Sedimentological characteristics and reservoir quality prediction in the Upper Ordovician glaciogenic sandstone of the In-Adaoui-Ohanet gas field, Illizi basin, Algeria",Saharan platform; Illizi basin; Upper ordovician; Unit IV-3; Glaciogenic deposits; Reservoir characteristics,SEQUENCE STRATIGRAPHY; TUNNEL VALLEYS; NORTH-AFRICA; SUCCESSION; SEDIMENTS; ARABIA,"The Upper Ordovician glaciogenic deposits are thought to have an important quantity of hydrocarbon across North Africa. Insight is provided about the IV-3 reservoir unit in the In-Adaoui-Ohanet field in the Illizi basin of south-east Algeria. The aim is to: 1) describe the lithofacies; 2) interpret the depositional environment; 3) describe the petrographic characteristics; 4) investigate the petrophysical properties; and 5) perform a biostrati-graphic analysis of the unit IV-3 reservoir (Upper Ordovician) in the In-Adaoui-Ohanet field based on the core description and samples collected from the well IA-115. Lithofacies described in the study area are MT1, MT2, MT3, MT6, and MT9. Subglacial tillite is the depositional environment associated with lithofacies MT3, MT6, and MT9. These lithofacies are thought to be deposited medial to a distal fan, whereas lithofacies MT1 and MT2 are thought to be deposited in high-energy flows. Acritarch and Chitinozoan species are the most common biozones described in the study reservoir and they are thought to be affiliated with an Upper Ashgilian stage. Petrographic analysis shows that the study reservoir unit is formed by fine to coarse-grained sandstone. Quartz is considered to be the principal framework mineral (mean, 56.30%). Cementing minerals observed in this reservoir unit are quartz and carbonate. From a compositional point of view, the unit IV-3 reservoir in the In-Adaoui-Ohanet field is predominantly formed by quartz arenites, which are considered to be mature. Additionally, the tectonic setting of these arenites is most likely associated with a passive margin origin. The emphasis throughout this study is on the role of factors such as permeability, carbonate cement, and quartz overgrowth on the reservoir quality of unit IV-3 in the In-Adaoui-Ohanet field. The quality of this reservoir unit is highly influenced by the quartz overgrowth and pores that are plugged by carbonate cement, which dramatically reduces the pore network. An enhanced porosity was observed only in the MT3lithofacies (up to 22.3%). Additionally, from an economic point of view, the study reservoir unit is classified as a tight gas-bearing reservoir.",5,5,2
Aquifer,,"Yu, Qingyan; Mu, Zhenbao; Liu, Pengcheng; Hu, Xiangyang; Li, Yong",A new evaluation method for determining reservoir parameters for the development of edge-water-driven oil reservoirs,Initial gas-in-place; Aquifer energy; Reservoir parameter evaluation; Type curves; Transient aquifer influx,MODEL; WELLS,"Edge-water support is associated with many oil reservoirs. To develop this kind of reservoir, it is helpful to evaluate reservoir parameters such as well initial gas-in-place and aquifer energy. The evaluation of reservoir and aquifer parameters is an important prerequisite in making oil development plan. This paper focused a reservoir parameter evaluation method for use when reservoirs are driven by an edge-aquifer. This paper also proposed no-aquifer influx period-type curves and early aquifer-influx period-type curves that can be matched by well production data to determine reservoir and aquifer parameters. This method considers transient aquifer-influx models; curves are based on the Blasingame advanced production data analysis method and the simple-composite reservoir model. The purpose of the theory is to quantitatively evaluate the well initial gas-in-place, aquifer energy, and other reservoir parameters. This method first divides well history production data into three influx periods: no-aquifer, early aquifer, and middle-late aquifer. The no-aquifer influx period-type curves are matched with the corresponding no-aquifer influx period data, then the dimensionless drainage radius and positioning of the field well production data relative to type curves can be obtained, and next well initial gas-in-place and other reservoir parameters can be calculated by the relevant equations. In the case of the dimensionless drainage radius, the early aquifer-influx period-type curves can be drawn, and the aquifer energy can be determined by matching the early aquifer-influx period data with the corresponding type curves. The method in this paper uses well production data to match. It does not need the reservoir pressure that is measured through well shutting-in and must be used in the empirical aquifer-influx model, which is convenient and more reasonable. The results of a conceptual numerical simulation model indicate that this method is reliable and can help to evaluate oil reservoirs and provide useful guidance in developing oil reservoirs with transient edge-aquifer drives.",2,2,1
Aquifer,,"Amirsardari, Mahdi; Rajabi, Ali; Danaei, Manouchehr; Rashidi, Fariborz",Numerical investigation for determination of aquifer properties in newly developed reservoirs: A case study in a carbonate reservoir,Aquifer; Gas reservoir; Water relative permeability; Numerical modeling; Rock typing,MATERIAL-BALANCE; PORE STRUCTURE; GAS,"Aquifer strength is one of the main parameters in surface water separation facilities design. The material balance method is a common approach to calculate the aquifer strength and water influx in mature reservoirs which are in the second half of their lives. However, this method could not be used for green and newly developed reservoirs. In this type of reservoirs, the suitable vertically and laterally distance between aquifer and perforation intervals in the development wells is a main question which depends on future aquifer behavior. In this study, a methodology has been presented to estimate aquifer properties using water pressure data and also well testing data in a newly developed giant gas field in Middle East. The numerical sector model is used to match simulated water pressure data with actual MDT (Modular Dynamic Tester) data. The water relative permeability for each rock type and vertical-horizontal permeability relationship have been determined in history matching process. The tuned model can be used for the prediction of the aquifer performance and also the water production in future development wells.",3,3,0
Aquifer,,"Ziabakhsh-Ganji, Zaman; Nick, Hamidreza M.; Bruhn, David F.",Investigation of the synergy potential of oil and geothermal energy from a fluvial oil reservoir,Geothermal energy; Thermal enhanced heavy oil recovery (TEOR); Heterogeneity; Net to gross (N/G); Net present value (NPV),HEAT-RECOVERY; HOT-WATER; HETEROGENEITY; CONNECTIVITY; PERFORMANCE; FLOW; INJECTION; EXPLOITATION; AQUIFER; SYSTEM,"Geothermal projects, as renewable energy projects, are not economically attractive in most places of the world at the current state of development; for this reason, subsidies are required by energy and environmental authorities in order to increase the interest in such projects. In this paper, we assess and model strategies for integration of geothermal energy with oil productions of the Moerkapelle oil field in the Netherlands. To do so, numerical simulations have been employed to analyse the feasibility of a fluvial oil reservoir for the synergy potential of oil and geothermal energy exploitation. In order to implement the simulation studies, single phase and two-phase non-isothermal fluid flow modelling are utilized for the geothermal well doublet system and for water flooding in an oil reservoir (including facies heterogeneity), respectively. A series of simulations have been conducted to investigate how hot water from a geothermal reservoir beneath a heavy oil reservoir in the fluvial sedimentary system of the West Netherlands Basin can be used for Thermal Enhanced Oil Recovery (TEOR) and geothermal energy production. This study finds that the high degree of heterogeneity in fluvial oil reservoirs could significantly affect oil recovery improvement and hence the synergy strategy. High values of a) Net to gross (N/G) b) Bottom Hole Pressure (BHP) and c) horizontal wellbore length are favourable for oil recovery. In contrast, wide horizontal wellbore spacing and high oil viscosity have an adverse effect on oil recovery enhancement. Furthermore, the results display that the enhanced oil production helps to reduce the required subsidy for a single doublet geothermal project up to 100%. Consequently, the extra amount of oil produced by utilising the geothermal energy, could make the geothermal business case independent and profitable.",3,3,1
Aquifer,,"Yu, Qingyan; Hu, Xiangyang; Liu, Pengcheng; Jia, Ying; Li, Yong",Researches on calculation methods of aquifer influx for gas reservoirs with aquifer support,Blasingame type-curves; Flowing material balance; Material balance equation; Fetkovich model; Aquifer influx,TIGHT SAND GAS; WELL; OPTIMIZATION; FIELD; MODEL; OIL,"The existence of aquifers in gas reservoirs has important influences on the development of gas wells. Water will invade into gas reservoirs when formation pressure decreases during the production of a gas well and then change the well production characteristics severely. It is very important to research the aquifer invasion mechanisms and evaluate the aquifer influx for good knowing and exploring the gas reservoir. In this paper, we have conducted three methods to research the aquifer influx characteristics by evaluating the value of aquifer influx and aquifer influx rate that vary with the production time. Three methods are the Blasingame method, the FMB (Flowing Material Balance) method and the MBE (Material Balance Equation) method. Based on the Blasingame conventional type-curves, the normalized well production data of a gas well influenced by aquifers can be divided into three influx periods: no-aquifer, early-aquifer and middle-late-aquifer influx period. The no-aquifer influx period production data are used to determine well initial gas in place and as a base, and the early-aquifer influx period production data are used to obtain aquifer influx and aquifer influx rate quantitatively. The novel three methods presented can elucidate the aquifer influx characteristics clearly and determine aquifer influx rate quantitatively just using well dynamic production data based on the Fetkovich model. Meanwhile, a simple numerical simulation model was built to verify the three methods, which shows that these three methods are reliable and really have strong practicability in developing gas field reservoirs with aquifer support.",3,4,1
Aquifer,,"Bardy, Gaetan; Biver, Pierre; Caumon, Guillaume; Renard, Philippe",Oil production uncertainty assessment by predicting reservoir production curves and confidence intervals from arbitrary proxy responses,Uncertainty quantification; Model ranking; Geostatistics; Ensemble methods,MODELS; INTEGRATION; FLOW,"Underground fluid flow in hydrocarbon reservoirs (or aquifers) is difficult to predict accurately due to geological and petrophysical uncertainties. To quantify that uncertainty, several spatial statistical methods are often used to generate an ensemble of subsurface models representing and sampling these uncertainties. However, to predict the uncertainties in terms of flow responses, one needs to run a forward flow simulator (often multiphase flow in transient state) on every model of this ensemble and this generally entails intractable computational costs. Approximate solutions (flow proxies) can help addressing this challenge but introduce physical simplifications whose impact on the uncertainty quantification is difficult to characterize. This paper proposes a workflow to assess the dynamic reservoir behavior uncertainties from an input ensemble of realizations sampling geological and geophysical uncertainties. Analytical reservoir production curves are estimated from proxy distances computed between all ensemble members and from a few accurate flow responses computed on a subset of the ensemble. A randomization process accounting for proxy quality and for model selection is used to assess confidence intervals about reservoir production quantile curves. The process can use both static and dynamic proxies and also permits to compare their efficiency. A case study on a real turbiditic reservoir shows the applicability of the method, and highlights the value of even a simple proxy to increase the confidence about future reservoir production.",4,4,1
Aquifer,,"Hao, Shu-Qing",Development of portable drilling fluid and seepage simulation for deep saline aquifers,CO2 sequestration; Borehole stability; Low density (portable) drilling fluid; High-temperature resistant drilling fluid; Deep saline aquifers,RHEOLOGICAL PROPERTIES; STORAGE; CO2; PERFORMANCE,"The development of drilling fluids with low density for deep saline aquifers is in high demand. This study performed several tests to find the optimal formula of drilling fluid that would be suitable under circumstances with high temperatures and salt concentrations similar to deep saline aquifers. Drilling fluids with varying combinations sodium chloride (NaCl), polyacrylamide (PAM), sulfonated lignite (SMC), and sodium carboxymethyl cellulose (Na-CMC) in montmorillonite (Mt) water-based slurry were synthesized and tested. Salt-, SMC-, and temperature-sensitivity analysis was done to investigate effects of ionic strength and temperature on the performance of synthesized drilling fluids. Anti-caving ability tests were performed to check the drilling fluids influence on porosity of aquifer upon application. The results show that NaCl and PAM play a critical role in controlling viscosities and yield values. PAM and Na-CMC contribute to fluid loss characteristics, and PAM contributes to low density too. A deliberately chosen combination of NaCl PAM, SMC, and Na-CMC gives rise to a suitable formula of drilling fluid for temperatures up to 120 degrees C and salt concentrations up to 1.7 M. The simulation of drilling fluid seepage in the borehole based on the ANSYS-Fluent existing codes verifies the performance of the optimal formula and the results imply the effectiveness of the optimal formula on prohibiting the borehole instability. This will even encourage immediate field applications of the optimal formula.",4,5,2
Aquifer,,"Nie, Ren-Shi; Zhou, Hao; Chen, Zhangxin; Guo, Jian-Chun; Xiong, Yu; Chen, Yang-Yang; He, Wen-Fa",Investigation radii in multi-zone composite reservoirs,Investigation radius; Composite reservoir; Well test; Pressure wave,FRACTURED VERTICAL WELL; HORIZONTAL WELL; DIFFUSIVE LEAKAGE; FLOW; BEHAVIOR; TESTS; CONDUCTIVITY; AQUIFERS; MODEL,"In petroleum reservoir engineering, an investigation radius is a basic, practical and meaningful parameter to evaluate the controlled area of a well. The investigation radius in homogeneous reservoirs is usually calculated by an explicit function related to the square root of time. At present, no research on investigation radii in multi-zone composite reservoirs has been found in the literature. In this work, first, we presented an application problem for which the commercial software Saphir cannot interpret an investigation radius in multi-zone composite reservoirs. Then, based on the investigation radius in homogeneous reservoirs, we firstly derived a calculation formula for the investigation radius in a multi-zone composite reservoir by the assumption of homogeneous properties in each zone. Compared with the formula for homogeneous reservoirs, the formula for multi-zone composite reservoirs is more complicated and shows a nonlinear implicit function in time. By use of the newly derived formula of the investigation radius, given a group of reservoir parameters, we numerically calculated the dynamical investigation radii with the elapse of time for both 2-zone and 3-zone composite reservoirs. Accordingly, we plotted a series of relationship curves for the investigation radii with time affected by model parameters, such as permeability, porosity and total compressibility. The relationship curves obviously show the multi-zone properties of a reservoir. The relationship curves of N-zone composite reservoirs can reflect (N-1) inflection points and an inflection point represents a response of pressure wave to an interface between two neighboring zones. Finally, we used real reservoir parameters from an example well in a 2-zone composite reservoir to calculate the investigation radius. In summary, the newly derived formulas have been shown in this work to be a convenient and practical new tool to calculate the investigation radii in composite reservoirs.",4,4,3
Aquifer,,"Benaafi, Mohammed; Hariri, Mustafa; Bertotti, Giovanni; Al-Shaibani, Abdulaziz; Abdullatif, Osman; Makkawi, Mohammad","Natural fracture system of the Cambro-Permian Wajid Group, Wadi Al-Dawasir, SW Saudi Arabia",Wajid group; Sandstone; Fracture system; Outcrop analogue; Saudi Arabia; Rub' Al-Khali basin,DEPOSITIONAL-ENVIRONMENTS; STRATIGRAPHIC ARCHITECTURE; OUTCROP ANALOG; LAYERED ROCKS; FLUID-FLOW; SANDSTONE; EVOLUTION; BASIN; DEFORMATION; LITHOFACIES,"This study investigates the regional and outcrop-scale fracture system within the Wajid Group exposures in Wadi Al-Dawasir, southwest Saudi Arabia. The Wajid Group is a Cambro-Permian siliciclastic succession that forms the main groundwater aquifers in the study area and is considered as a potential hydrocarbon reservoir in the Rub' Al-Khali Basin. The succession is composed of fluvial, marine, and glacial to glaciofluvial deposits. This study aims to characterize and model the fracture system within the Wajid Group in the Wadi Al-Dawasir area using satellite imagery and direct field measurements. A further study objective is to define the geological factors controlling the fracture distribution within the Wajid Group succession. Five sets of regional-scale fractures (lineaments) were defined: N000 degrees, N015 degrees, N035 degrees, N075 degrees, and N135 degrees. In addition, five sets of the outcrop-scale fractures were delineated: N015 degrees, N035 degrees, N075 degrees, N135 degrees, and N165 degrees. The N135 degrees- and N035 degrees-oriented fracture sets are predominant at the regional scale. At the outcrop scale, however, the N165 degrees- and N075 degrees-oriented fracture sets are predominant. The trace-length of the regional-scale fractures is distributed according to the negative exponential distribution. The fractures within the Wajid Group outcrops are vertical to sub-vertical extensional fractures (mode 1). Those fractures are open, however, and at some localities, they are sealed or coated with calcite or iron oxides. Fracture swarms with an orientation of N015 degrees were also observed in the southeastern part of the study area. Hierarchical outcrop conceptual models of two fracture sets are proposed. The proposed models show that the regional-scale fractures are not influenced by stratigraphic or lithological variations. In contrast, the outcrop-scale fractures are controlled by the stratigraphic, lithological, and diagenetic variations in the fracture-hosting sandstone. The diagenetic characteristics (cementation and dissolution), bed thickness, and porosity of the fracture-hosting sandstone play a key role in the fracture distribution within the Wajid succession. The results of this study contribute to the understanding of groundwater flow behaviour within fractured aquifers in the study area and will help to enhance gas production from fractured hydrocarbon reservoirs in the Rub' Al-Khali Basin.",5,5,0
Heat Transfer,,"Riley, G. A.; Bultongez, K. K.; Derby, M. M.",Oil-water flow regimes in 4-mm borosilicate glass and fluorinated ethylene propylene channels: Effects of wall wettability,Multiphase flow; Fluid dynamics; Oil-water interface; Capillarity,BOILING HEAT-TRANSFER; 2-PHASE FLOW; PRESSURE-DROP; MULTIPHASE FLOW; HORIZONTAL FLOW; CONDENSATION; PATTERNS; MICROCHANNELS; MICROMODEL; PIPES,"Formation water, found in oil deposits, is highly corrosive. By utilizing flow phenomena and surface tension forces in smaller channels (e.g., Eotvos number less than one), these fluids can be separated, thus altering corrosion and the pressure required for transport. This research investigates the effects of wall wettability on oil-water flow regimes and pressure drops. Oil-water flows were studied in 3.5-mm hydrophilic borosilicate glass and 4.0-mm hydrophobic fluorinated ethylene propylene (FEP) channels using Parol 100 mineral oil (i.e., density of 840 kg/m(3) and viscosity of 0.0208 Pa s) and tap water (i.e., 997 kg/m(3) and a viscosity of 0.001 Pa s). For these oil-water combinations, glass was water wetting (i.e., contact angle of 67 degrees for a water droplet submerged in oil on glass) and FEP was water repelling (i.e., contact angle of 93 degrees for a water droplet submerged in oil on FEP) under static conditions. Flow regimes and pressure drops were recorded for a range of oil superficial velocities [i.e., 0.31-3.7 m/s (glass) and 0.23-2.7 m/s (FEP)] and water superficial velocities [i.e., 0.080m/s-5.5 m/s (glass) and 0.060-5.5 m/s (FEP)]. Stratified, intermittent, annular, and dispersed flow regimes were observed in both tubes. Additional inverted and dual flow regimes were observed in the hydrophobic FEP; oil wetted the wall in inverted flows, and flow regimes occurred inside of another flow regime in dual flows (e.g., inverted-annular intermittent). The modified Weber number indicated whether the walls were wetted by oil, mixed oil and water, or water. Pressure drops were found to be correlated to the flow regime with increased pressure drops observed when oil fully or partially wetted the wall.",0,0,2
Heat Transfer,,"Goes, Maria Rosa R. T.; Teixeira, Rodrigo G. D.; Tavares, Frederico W.; Secchi, Argimiro R.",Wax appearance and prevention in two-phase flow using the multi-solid and drift-flux model,,THERMODYNAMICS; PRECIPITATION; PREDICTION; EQUILIBRIA; DENSITIES; LIQUIDS,"Wax precipitation may lead to obstruction of pipelines generating significant economic losses. Oil reservoirs, especially in the deepwater sea, are found in extreme conditions of pressure and, during the fluid flow inside the pipelines, the fluid temperature may decrease due to heat transfer to the surrounding (seawater) and phase change, tending to deposit solid particles on the pipeline walls. Within this context, it is important to develop a model that calculates the WAT (wax appearance temperature) of a fluid with known composition and then determine the point where the first paraffin crystal will appear inside a pipeline. The objective here is to provide a two-phase flow model coupled with paraffin precipitation model to calculate WAT inside the pipeline. We used the Drift-Flux Model to describe the two-phase flow in steady state and the Multi-Solid Theory to calculate the WAT. The results for a paraffinic mixture of four components show that the effect of the pressure can be considered negligible on WAT calculation for low pressure systems (< 10 MPa). Analyzing the effect of the fluid composition, the larger the number of light compounds in the mixture, the smaller will be the WAT, at constant pressure. For two different cases, it was determined the point inside the pipeline where the solid particles may deposit. We proposed an algorithm to find the minimum inlet temperature such that does not occur wax precipitation along the pipeline. The algorithm was successfully applied to a case study and may be useful for defining operational conditions to prevent solid blockage of pipelines.",1,1,0
Heat Transfer,,"Luo, Xiangrong; Qi, Yin; Li, Jianshan; Huang, Penggang; Wang, Shuzhong; Ren, Xiaojuan; Zhang, Pengfei",Convection heat transfer and friction characteristics of liquid CO2-N-2 foam fracturing fluid using C4F9OCH3 as frother,Fracturing; Frother; Heat transfer; Fiction; Foam quality,THERMAL-CONDUCTIVITY; RHEOLOGICAL PROPERTIES; PERFORMANCE; FLOWS,"The liquid CO2-N-2 foam fracturing fluid containing C4F9OCH3 causes no damage to formation, similar to dry CO2 fracturing, can be used to stimulate water sensitivity and low-permeability gas reservoirs. The main objective of this experimental study was to ascertain the convective heat transfer and frictional characteristics of this modified dry fracturing fluid system. A foam fracturing fluid test system was adopted in this study. The results showed that the viscosity of the liquid CO2-N-2 foam fracturing fluid with C4F9OCH3 added was significantly higher compared with the liquid CO2-N-2. The optimum frother concentration was 0.65%. The shear rate had the most significant effect on the convective heat transfer. The pressure had a significant effect on the frictional characteristics of the complex foam fluid due to the compressibility of the internal and external phases. When the flow velocity was greater than 1.4 m/s, the frictional resistance coefficients for foams of different qualities were similar. The velocities in the expression of the generalized Reynolds number, Re', and the generalized Prandtl number, Pr', were not sufficient to describe the influence of the shear rate on the heat transfer. When fitting the convection heat transfer coefficient, the effect of shear rate on coefficient of thermal conductivity was also considered. These results can be used to calculate the temperature field and predict the friction pressure drop in the use of this foam fracturing fluid.",1,1,4
Heat Transfer,,"Cheng, Gang; Pang, Zhanxi; Jiang, Yanming; Wang, Bo; Yu, Xiaogang",Thermodynamic analysis and prediction of reservoir temperature distribution for steam stimulation,Steam stimulation; Temperature distribution; Heat conduction; Heat convection; Energy balance equation,ASSISTED-GRAVITY-DRAINAGE; HEAT-TRANSFER; OIL-RECOVERY; POROUS-MEDIA; THERMAL RECOVERY; DISPLACEMENT; INJECTION; FLOW,"During steam stimulation of horizontal wells in heavy oil reservoir, it is necessary to estimate the reservoir temperature distribution, which has a huge impact on oil production and ultimate oil recovery. Most of previous models were derived based on infinite boundary condition and constant fluid velocity, which were not consistent with real situation of reservoir. In this paper, new energy balance equations combined with mobile boundary conditions were developed for increasing the accuracy of predicted results. Based on dimensionless conversion and numerical analysis, the optimum solution of equation system could be easily obtained, and its good performance in predicting temperature distribution was also validated. Moreover, thermodynamic mechanism of hot fluid, latent heat and sensible heat of steam, and their contributions to heating reservoir were also discussed to investigate the heat transfer pattern in reservoir. Finally, factors that could influence the reservoir temperature distribution were analyzed. It is found that: (a) both the heat conduction and the heat convection contribute to the heat transfer in hot liquid zone, and the heat convection predominates; (b) both the condensation front and heat front move outward with the injection of steam, but their expanding rates gradually drop with time; (c) as the radius increases, the radial fluid velocity will go down, leading the heat convection effect to be weakened and the heat conduction effect to become obvious; (d) there are some factors that can influence the reservoir temperature distribution including steam injection duration, fluid velocity, volumetric heat capacity of fluid, steam quality and thermal conductivity of reservoir.",2,2,2
Heat Transfer,,"Kanimozhi, B.; Thamizhmani, Vivek; Pranesh, Venkat; Senthil, S.; Selvakumar, Arun T.",Kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection,Carbonate reservoir; Fines migration; Water saturation; Heat transfer; Permeability decline; Pressure change,OIL-RECOVERY; RESERVOIR ROCKS; OIL/BRINE/CARBONATE SYSTEM; SLOW MIGRATION; WETTABILITY; FILTRATION; SURFACE; FIELD; PH,"Kaolinite clay fines are prevalent in sandstone porous media and it has great impacts on permeability and well productivity decline. High temperature sandstone formations detach the fines from the pore surface and migrate along with the permeating fluid. At some point the fine particles are strained in the pore throats, which leading to permeability damage and well productivity decline. To the best of our knowledge this phenomenon is not well explored in the high temperature carbonate media. Since most of the world's oil reserves are held in carbonate media and its worth to explore the formation damage, especially due to fines migration during higher reservoir temperature at these formations composed of carbonate minerals. Hence, this paper presents laboratory modeling of kaolinite fines colloidal flow in high temperature porous carbonate media during saline water injection. In this paper, we have conducted three sets of coreflood experiments in the temperature ranges of 100 degrees C 150 degrees C, and 200 degrees C. Kaolinite suspension water has been injected into the porous limestone core at these temperature regimes to investigate the possibility of permeability and injectivity deterioration. The main experimental results showed there is an increase in water saturation and heat transfer rates. Concentration of fines surges with increasing PVI and permeability declines with increasing time. Pressure elevates with enhancing PVI, but it plummets after some time. Significantly, the water discharge rate declines for increasing suspension injection and on the other side, for fresh water injection, the rate of water discharge rises steadily. Furthermore, the electrical and thermal conductivities of effluent kaolinite colloid were higher. Moreover, experimental model were tested against statistical based optimizational model, response surface methodology (RSM). These results revealed good agreement and, hence, this paper has explicated the importance of kaolinite clay fines suspension transport in high temperature carbonate reservoirs.",3,3,0
Heat Transfer,,"Hashish, Refaat G.; Zeidouni, Mehdi",Analytical approach for injection profiling through warm-back analysis in multilayer reservoirs,,TRANSIENT TEMPERATURE BEHAVIOR; WATER GEOTHERMAL-RESERVOIRS; SANDFACE TEMPERATURES; PRESSURE; DRAWDOWN,"Injection profiling in multilayer (stratified) reservoirs is essential for successful water flooding and effective reservoir management. When possible, injection profiling may be achieved via production logging tools (PLT). An alternative approach is to utilize real-time temperature obtained e.g. via fiber optic distributed temperature sensing (DTS) to obtain the injection profiles. Development of modelling tools is required to enable analyzing temperature data to obtain the injection profiling. In this work, an analytical solution is developed to determine the transient temperature distribution in the reservoir during the warm-back period that follows cold fluid injection. The analytical model is used to introduce a temperature inversion approach to obtain the injection profile. The analytical solution is developed for single- and multi-layer reservoirs considering single-phase flow at constant rate over the injection period. The solution considers heat transfer by conduction and convection during the injection period. Warm-back is attained during the subsequent shut-in period through heat transfer by conduction in the reservoir (thermal equilibration) as well as the heat exchange between the completed layers and the surroundings. Heat transfer with the surrounding layers affects the warm-back rate the most for relatively thin layers. The analytical solution is verified through comparison against numerical simulation results obtained using a thermally coupled numerical simulator for single- and multi-layer reservoir cases. Graphical interpretation techniques are introduced by recasting the analytical solution into convenient forms. The graphical techniques are applied to synthetic warm-back data to illustrate their reliability and accuracy in obtaining the injection profile and the thermal front extent (per layer) during the injection period.",4,4,0
Heat Transfer,,"Al Saedi, A. Q.; Flori, R. E.; Kabir, C. S.",Exploring alteration of near-wellbore geothermal gradient during fluid circulation and production,Time-dependent formation temperature; New analytical models for fluid circulation & production; Solution of temperature diffusivity equation; Transient temperature profiles; Undisturbed formation temperature; Heat flow in and out of wellbore,TEMPERATURE DISTRIBUTION; HEAT-TRANSFER; MODEL; LOGS,"The constant undisturbed formation temperature profile controlling heat transfer into the wellbore appears counterintuitive in light of transient cooling of the formation that occurs upon fluid circulation in drilling and also heating during fluid production. This study presents a mathematical model that shows that the heat transfer occurs from the wellbore/formation interface, not from some distance away from the wellbore wherein the initial formation temperature profile remains undisturbed. This new model allows investigation of heat transfer behavior from the formation into the wellbore during drilling or fluid circulation, and from the wellbore into the reservoir in the production mode. Application of the line-source solution for the temperature diffusivity equation for a steady-state system provides the necessary ingredients for computing the temperature behaviors at different times and radii. This line-source solution can be used throughout the wellbore to determine the undisturbed formation temperature, which may be used to obtain the geothermal gradient dependent on the radius and fluid circulation time. Therefore, the initial geothermal gradient works as a time-dependent variable, and the resultant second-order polynomial relationships can describe the undisturbed formation temperature. This study provides the required tools to assess the wellbore heat-transfer behavior and their effect on the wellbore temperature profiles. Also, the new mathematical model illuminates the impact of heat transfer by comparing its performance with the original formulations. Besides, this paper presents a complete derivation of the line-source solution of the temperature diffusivity equation to justify the proposed approach.",5,5,0
Machine Learning,,"Orlov, Denis; Koroteev, Dmitry",Advanced analytics of self-colmatation in terrigenous oil reservoirs,Machine learning; Formation damage; Reservoir properties; Permeability reduction; Fine migration,FINES; FILTRATION; MIGRATION; MODEL,"One of the most significant issues of petroleum engineering nowadays is a decline in productivity and injectivity of wells due to formation damage, which is typically associated with the migration and retention of fines. The prediction of formation damage is a challenging problem due to the lack of information about concentrations and localizations of potential mobile fines in the reservoir. To solve this problem different algorithms of machine learning and data mining were tested: linear regressions, decision trees, random forest, gradient boosting and artificial neural networks. We developed the predictive model of permeability reduction in Vendian deposits (Russia) based on the analysis of rock properties and flooding conditions. This model allowed to describe the dynamic of permeability reduction as a multi-parametric function of injected pore volumes of water. Three defining parameters in the model were unique colmatation characteristics which have been predicted for each core sample. All the features of the self-colmatation process were studied and arranged by their importance. To build the model of permeability reduction we used two approaches. The first one was to discover all possible 2D cross-plot correlations between colmatation characteristics and features (manual analysis). The second is applying machine learning algorithms where all features were taken into account simultaneously. The benefits and disadvantages of both approaches were discussed in details.",0,0,0
Machine Learning,,"Khazali, Nastaran; Sharifi, Mohammad","New approach for interpreting pressure and flow rate data from permanent downhole gauges, least square support vector machine approach",Least square support vector machine (LS-SVM); Machine learning algorithms; Welltesting; Interpreting PDG data,DEW-POINT PRESSURE; TRANSIENT PRESSURE; PREDICTIVE MODEL; GAS; OIL; WELL; CO2; RESERVOIRS; DESIGN; SVM,"Permanent downhole gauges (PDGs) are permanently installed in oil and gas wells to monitor real-time downhole pressure, temperature and sometimes flow rate. Recording these variables continuously plays a key role in reservoir analysis. Conventional welltesting methods as one group of approaches for reservoir characterization are generally used in a way that interpreting the obtained reservoir pressure (reservoir response) will be easy. For this target to be achieved welltesting often deals with constant flow rate sections of data in a short period of time. As an alternative approach, machine learning deals with large volumes of data (which are recorded in a long period of times) to find the relationship among the related variables (Liu and Horne, 2013a). Here, we aim to describe the usage of the least square support vector machine (LS-SVM) as a machine learning method for analyzing data from permanent downhole gauges. This approach is a tool for analysis of data that are in the presence of noise, gaps and outliers which reveals another advantage of using LS-SVM instead of conventional well-testing methods in which designed tools in controlled environments are needed. Last but not least, this method is one of the few ways which can use the flow-rate data with uncertainty. In this document, the application of radial basis function (RBF) as a function approximation for mapping the data to a high dimensional feature space is investigated. The LS-SVM method proved to be successful in predicting pressure especially when the wellbore/reservoir model contains a nonlinear pattern or when the pressure derivative curve has a nonlinear trend. Since PDG records data during production and not during an imposed flow rate condition, the existence of nonlinear features is common which proves the applicability of the presented method.",3,3,0
Machine Learning,,"Liu, Wei; Liu, Wei David; Gu, Jianwei; Shen, Xinpu",Predictive model for water absorption in sublayers using a machine learning method,Water absorption; Machine learning; Feature selection; Dynamic time warping (DTW); Extreme gradient boosting (XGBoost),WELL-RATE FLUCTUATIONS; FEATURE-SELECTION; INTERWELL CONNECTIVITY,"The sedimentary rhythm of Chinese oilfields is complicated and the heterogeneity is extremely strong. Allocating water absorption of each sublayer by dividing coefficient or numeric simulation cannot accurately reflect the actual water injection of the reservoir. Calculation based on water absorption profile monitored on site is the most commonly used method in oil field. However, access to these type of data is limited due to its cost and time related to acquisition. In this study, a machine learning approach was adopted to predict water absorption in sublayer based on geologic and production parameters of injectors and producers. On the one hand, it can save test costs. On the other hand, it can continuously predict water absorption of sublayers, and make up for water injection wells with insufficient injection profiles. A handful of training observations are obtained from on-site monitoring. Interwell connectivity is first conducted to identify connected producers for injectors. Introducing interwell connectivity helps to constitute predictor variables and yield significant improvements in feature selection. Connectivities in the well group are represented by similarity between injection sequence and production sequence, which is computed by Dynamic Time Warping. Average importance of predictors are then measured based on Mean Decrease Impurity, Mean Decrease Accuracy, and Ridge regression. Some relative important features are selected to consist the final predictors. The Extreme Gradient Boosting model is developed and then trained for making predictions given any set of observations. The proposed approach is validated by using actual field case from SL oilfield, China. Results show a significant correlation between predictions and actual value from on-site monitoring.",3,3,2
Machine Learning,,"Maity, Debotyam; Ciezobka, Jordan",Designing a robust proppant detection and classification workflow using machine learning for subsurface fractured rock samples post hydraulic fracturing operations,Artificial neural nets; Image processing; Classifier benchmarking; Unconventional reservoirs; Core sampling; Shale rock,NEURAL-NETWORK; ALGORITHM,"Hydraulic fracturing is a method of reservoir stimulation that enhances the effective permeability of tight unconventional reservoirs such as shale oil and gas. In typical hydraulic fracturing treatments, millions of gallons of water are pumped under pressure into rock formations deep below the earths surface. Proppant particles such as sand are injected as part of the fracturing slurry to hold the hydraulic fractures open, or propped, after high-pressure water injection has ceased. Propped hydraulic fractures provide a conduit for long-term hydrocarbon production, thus being essential to commercial oil and gas production from shale reservoirs. The distribution of the proppant particles can be useful in understanding effectiveness of hydraulic fracturing treatments. It can also help identify both, unstimulated and under-stimulated zones within the reservoirs of interest. These proppant particles can be found in drilling fluid return or in cores, which can be sampled from subsurface. In this study, we highlight the design and development of artificial neural network based workflow that helps identify where proppant particles are located and classifies proppant and various particles of interest. In this study, these particles are limited to naturally occurring calcite or other minerals from subsurface rocks. Various features of interest that help with the classification process have been conceptualized and defined. This method has been verified using controlled test cases and validated using actual samples from subsurface. The designed ANN classifier has also been benchmarked with other classification methods including k-nearest neighbor, naive-Bayes classifiers and Support vector machines. A workflow to process samples from subsurface and quantify proppant distribution for future test programs including potential real time applications has been proposed. Based on this workflow, we share proppant distribution from a Permian Basin case study. We have also compared proppant distribution using our proposed method with results from an independent workflow on a similar dataset, which does not utilize machine learning.",5,5,0
Machine Learning,,"Handhal, Amna M.; Jawad, Shaymaa M.; Al-Abadi, Alaa M.","GIS-based machine learning models for mapping tar mat zones in upper part (DJ unit) of Zubair Formation in North Rumaila supergiant oil field, southern Iraq",Tar mat; GIS; Machine learning; Zubair formation,DATA-MINING TECHNIQUES; SUPPORT VECTOR MACHINE; ENSEMBLE MODEL; GULLY EROSION; RANDOM FOREST; CLASSIFICATION; PERMEABILITY; PREDICTION; EXPLORATION; RESERVOIR,"In this study, three machine learning models, namely, support vector machine, naive Bayes, and random forest, along with the geographic information system, are used to delineate the tar mat occurrence hazard in the upper part of Zubair Formation (named as DJ unit) in Rumaila oil field, southern Iraq. To build these models, a well inventory map that consists of 213 wells (tar and free-tar) is used with five factors that control the mat distribution in the DJ reservoir unit. These factors are porosity, volume of shale, water saturation, DJ unit thickness, and distance to the major fold axis. Multicollinearity and feature selection tests demonstrate that three of the five factors (distance to the major fold axis, water saturation, and porosity) are responsible for the tar distribution in the reservoir unit. The important factors with well inventory are used to develop the machine models and the results are compared using five evaluation measures namely, accuracy, sensitivity, specificity, kappa, and the relative operating characteristics curve. Findings from the models suggest that random forest is the best model, followed by support vector machine with polynomial kernel. The prediction random forest model is used to delineate the mat distribution, and the probability of tar mat occurrence hazard is classified into five zones, namely, very low, low, moderate, high, and very high. The produced hazard map in this study can be used as guide in the drilling of new wells in the considered reservoir unit and in avoiding the drilling of wells where the tar expected to occur.",5,5,0
Machine Learning,,"Rubo, Rafael Andrello; Carneiro, Cleyton de Carvalho; Michelon, Mateus Fontana; Gioria, Rafael dos Santos",Digital petrography: Mineralogy and porosity identification using machine learning algorithms in petrographic thin section images,Image segmentation; Artificial neural networks; Random forest; Supervised learning; Optical mineralogy; Carbonate rocks,NETWORKS; LOGS,"Images represent a large and efficient source of geological information from oil exploration. To better analyze them, well-known machine learning algorithms are used to extract mineralogy and porosity data from petrographic thin section images. Microscopic petrographic analysis allows obtaining images from thin sections in the visible spectrum. They are used to evaluate depositional environments and diagenetic processes during the formation of sedimentary basins. However, that is an activity subjected to the petrographer's experience. Data from other sources, such as chemical microanalysis, provide quantitative information that might assist in petrographic evaluation, but they are expensive and time-consuming. The main objective is to create models that systematically interprets mineralogy and porosity from images acquired of optical microscopic analysis using machine learning algorithms, standardizing descriptions and reducing subjectivity and human errors during thin sections analysis. Image segmentation models are created with representative classes of the rocks' mineralogy and porosity. Datasets were selected from images originated from thin sections of carbonate rocks, which are prepared from sidewall core samples of oil wells, specifically from the pre-salt reservoirs of Santos Basin, on the southeast coast of Brazil. These models use discrete convolutional filters followed by artificial neural networks and random forest classifiers. A number of configurations were tested, using different convolutional filters and classifier's parameters. Five models were created: 1. mineralogical model using artificial neural network; 2. mineralogical model using random forest; 3. mineralogical model using random forest validated by chemical measurements; 4. porosity model using artificial neural networks; and 5. porosity model using random forest. They were evaluated through the use of 10-fold cross-validation tests and by correlation with chemical microanalysis. Correlation between the two technique's relative occurrences for each mineral phase shows a root mean square error of 8.99% and a coefficient of determination of 0.82. That demonstrates how well models can generalize.",5,5,4
Gamma Ray,,"Singhal, Vivek; Ashok, Pradeepkumar; van Oort, Eric",X-ray densitometry of drilling fluids at the rig standpipe,Drilling fluid density; X-ray densitometer; Real-time density measurement; High-pressure density meter,ATOMIC-NUMBER; DENSITY; ENERGY; TEMPERATURE; FLOW,"Fluids used during well construction operations serve as a primary barrier for well control, with the fluid density generating sufficient hydrostatic pressure in the fluid column to control downhole formation fluids and gas. Realtime density measurement at the well inlet, where high pressures of many thousands of psi can occur, is highly desirable in order to maintain well control. This improved characterization of the well bore pressure profile allows one to drill wells with narrow drilling margins without non-productive time from well control events, resulting in safer and more cost-effective well construction operations. Gamma ray densitometers are suitable measuring devices for high-pressure density measurement. Typical flow conditions encountered at the inlet, such as a fully filled pipe and a homogeneously mixed mud, are very conducive to their use. In-spite of their high measurement accuracy and relatively fast response times, however, these meters have seen limited adoption in field. This is primarily because the meters come with safety concerns due to the radioactive source required for gamma ray generation. Additionally, the source has to be tracked throughout its life and properly handled during storage, transportation, installation and disposal. Given these concerns and challenges, a majority of oil and gas operating and service companies use manual density measurements at the mud pits using a pressurized mud balance. To help change this rather antiquated and infrequent practice that relies on manual labor, this paper evaluates the feasibility of using a non-radioactive, X-ray based densitometer as an alternative to the gamma ray meter. X-ray densitometry works on the same proven principles as gamma ray densitometry, without the latter's drawbacks. Two X-ray methods, an empirical method and a model-based method (inspired by a technique used in the medical field known as single X-ray absorptiometry) are presented here. Real-time density measurements on the high pressure line with an accuracy of 99% or better and a measurement frequency of 1 Hz are feasible using these methods.",0,0,1
Gamma Ray,,"Ramos Lopes, Diogo Maia; Neves Andrade, Andre Jose",Lithology identification on well logs by fuzzy inference,Geophysical well logging; Porosity log; Lithology log; Correlation; Fuzzy inference,,"The purpose of this work is to present a fuzzy inference system in order to identify lithologies from wireline logs and core data from a specific borehole and transport this information to nearby uncored wells in the same oilfield. Input variables in this inference system are natural gamma ray log (GR) and porosity logs (density, neutron porosity and sonic) used to obtain M and N parameters from M-N plot in order to reduce the number of variables used and obtaining more discrete numerical intervals for the variables. The database of this inference system is built from the core information with evidence of the presence of recognised lithologies. The response of this inference system (output) is indicated along the depth of uncored boreholes where the lithologies occurring. The proposed methodology was applied to real well log data recorded in two boreholes in the Campo de Namorado (Bacia de Campos, Rio de Janeiro). In general, the system obtained 97% of accuracy, getting the conclusion that the methodology presented is applicable to the mapping of one reservoir layer (sandstone, for example) along oilfield, even at complex geologic scenarios which cause the thickness variations and of the depth of the layer of interest.",3,4,2
Gamma Ray,,"Diaz-Curiel, J.; Miguel, M. J.; Biosca, B.; Medina, R.",Environmental correction of gamma ray logs by geometrical / empirical factors,Gamma ray; Environmental corrections; Attenuation factor; Build-up factor,,"This paper presents a series of empirical expressions to correct the total natural gamma ray log due to well environmental factors. This correction is focussed on improving the quantification of 40 K, given its application in the computation of the clay content of the different layers crossed during drilling. To date, there are no analytical relationships that make this correction and continuously consider the different diameters of the many existing sondes. There are also no functions that continuously take into account the different combinations of media interspersed between the well walls and the sonde (casing, drill pipe, gravel pack, cement, etc.) for different measurement modes and systems, such as wireline, while drilling. To solve these shortcomings, the relationships developed in this work have cited, in addition to the different well diameters and mud densities, the diameter of the sonde and the environmental parameters as variables with any value and in any possible combination. The obvious advantage of these parametric equations is that they can easily be entered as a subroutine into any code. Unlike the existing correction methods, i.e., empirical charts and curves obtained by simulation codes based on the Monte Carlo method, the relationships developed take into account the variation of the build-up effect that the radiation undergoes as it travels from layers with a certain radioactive emission to the sonde. In addition, another difference is that the relationships generated in this work include the internal diameter of the sonde between its outer walls and the cylindrical radiation detector glass. Starting from the general relationships that consider the attenuation and build-up effects of gamma radiation when passing through a medium, the methodology consisted of establishing an effective distance for the cylindrical geometry in which the source is the well wall, particularized for each effect and each type of tool (centred and eccentred). The resulting correction factors have been contrasted with the most recognized experimental charts in the field of well logging, obtaining a very high correlation and an average deviation of around 1.5%.",4,4,0
Gamma Ray,,"Partovi, Seyyed Mohammad Amin; Sadeghnejad, Saeid",Geological boundary detection from well-logs: An efficient approach based on pattern recognition,Geological boundary; Pattern recognition; Well-log; Wavelet transform; Fractal parameter; Optimal wavelet function; ANOVA; Tukey multiple comparison,WAVELET TRANSFORM; RESERVOIR; IDENTIFICATION; CONNECTIVITY; PERMEABILITY; HYDROCARBON; FIELD,"The knowledge of geological strata sequences and their exact boundaries depths is of a great importance in the characterization of oil and gas reservoirs. The aim of automated well-to-well correlation approaches is to facilitate and accelerate the procedure of geological boundary detection. In this study, we implement an automatic well-to-well correlation approach based on pattern extraction from well-logs. The well-log patterns are recognized by calculating several statistical and fractal parameters. As a fractal parameter, we select the wavelet standard deviation exponent, calculated by the discrete wavelet transform. Furthermore, to select the proper wavelet function, as the heart of wavelet transform, the energy to Shannon entropy ratio criterion is implemented. The statistical pattern recognition parameters of this study include average value, maximum to minimum ratio, coefficient of variation, and the trend angle of well-log data (i.e., Gamma ray log) in a window around the geological boundary. Moreover, the analysis of variance (ANOVA) tool and the Tukey multiple comparison method are implemented to evaluate the effectiveness of each parameter (i.e., fractal or statistical parameters) during the determination of boundary depths. The gamma ray logs from three wells of an oil field are used as a dataset for the evaluation of our algorithm. The outputs of our methodology are also compared with the new detrended fluctuation analysis (DFA) method, which show promising outcomes over it. The results show that the average value of the signal, among the analyzed parameters, is the most effective parameter; however, implementing the combination of all fractal and statistical parameters can improve the accuracy of the geological boundary detection.",5,5,0
Gamma Ray,,"Jiang, Shuxian; Mokhtari, Mehdi","Characterization of marl and interbedded limestone layers in the Eagle Ford Formation, DeWitt county, Texas",Eagle ford formation; Marl; Total organic content; Volcanic ash,TOTAL ORGANIC-CARBON; GEOCHEMISTRY; BENTONITE; PATTERNS; SHALES; MODEL; BEDS; ASH,"The Eagle Ford Formation in Texas, USA is composed of marl and interbedded limestone sequences with intermittent layers of volcanic ash. To optimize hydrocarbon recovery from such a heterogeneous formation, it is necessary to have a better understanding of the effects of each individual marl and limestone layer on reservoir properties. The objective of this paper is to characterize and quantify properties of marl and limestone layers in the Eagle Ford Formation, in terms of spectral core gamma ray, elemental concentrations, lithology and organic richness. Moreover, the differences between these layers in micro-scale level were shown through the scanning electron microscope (SEM) images. XRF results show that concentrations of Al2O3, Fe2O3 , Mo, and Zr in marl layers were more than 40% higher than in the interbedded limestone layers. The Eagle Ford samples fall into two groups in the ternary plot. Limestone layers contain calcite content ranging from 55% to 90% and clay content ranging from 5% to 30%, while marl layers contain 30%-70% calcite and around 20%-50% clay. Marl layers have better generative potential than the limestone layers in the Eagle Ford Formation. Moreover, estimation of total organic carbon of the Eagle Ford Formation using Passey's Delta log R method with a correction factor was provided and validated with lab measured data.",5,5,0
Gamma Ray,,"Costanzo-Alvarez, Vincenzo; Rapalini, Augusto E.; Aldana, Milagrosa; Diaz, Marisel; Kietzmann, Diego; Paula Iglesia-Llanos, Maria; Cabrera, Ana; Luppo, Tomas; Vallej, Maria D.; Maria Walther, Ana","A combined rock-magnetic and EPR study about the effects of hydrocarbon-related diagenesis on the magnetic signature of oil shales (Vaca Muerta formation, southwestern Argentina)",Rock magnetism; ERR; Oil shales; Organic matter free radicals; Extractable organic matter,ELECTRON-SPIN-RESONANCE; NEUQUEN BASIN; FREE-RADICALS; TECTONIC EVOLUTION; ACQUISITION CURVES; PYRITE FRAMBOIDS; CONTRASTS; SEDIMENTS; VENEZUELAN; FIELD,"A combined study of rock-magnetism and electronic-paramagnetic resonance (EPR) was performed in core samples from an oil well in the Vaca Muerta Formation (SW Argentina). The aim of this work was to characterize the effects of hydrocarbon-related diagenesis on the magnetic signature of oil shales. Similar research has been previously conducted in near-surface sediments affected by oil and gas microseepage, so as to establish a relationship between micromagnetic anomalies and the underlying reservoirs. The EPR technique was employed to measure minute concentrations of organic matter free radicals (OMFRs), Fe3+ and Mn2+. These results, and the concentrations of extractable organic matter (EOM), were compared with mass-specific magnetic susceptibility (chi) and natural remanent magnetization (NRM). The reactive OMFRs, resulting from the thermal degradation of a kerogen that yields a slightly-biodegraded crude oil, seem to have acted on the primary Fe oxides and sulfides through two diagenetic stages. The first stage might have partially dissolved these minerals. Consequently, a number of depth levels show a decrease of both chi and NRM, against an increase of the OMFRs. On the other hand, for a core-interval between 2663 and 2695 m (P18/P24), a second diagenetic stage could have produced partial replacement of framboidal pyrite by authigenic pyrrhotite, as recognized by scanning electron microscopy (SEM), electron X-ray energy dispersion (EDX) experiments and the analysis of the thermomagnetic and IRM curves. Thus, within P18/P24, magnetic parameters increase in direct proportion with the amount of OMFRs. The lithologies encompassed by P18/P24 show small levels of Mn2+, a proxy directly related to calcareous cementation. Moreover, Gamma Ray, resistivity and neutron porosity well logs reveal distinctive features for P18/P24, as well as an increase of hydrocarbon content, contrasting with the rest of the section analyzed. The hydrocarbon-induced magnetic anomalies in these oil shales seem to be conditioned mostly by their petrophysical properties.",5,5,0
Asphaltene Deposition,,"Wang, Ningyu; Prodanovic, Masa; Daigle, Hugh",Nanopaint application for flow assurance with electromagnetic pig,nanopaint; Superparamagnetic nanoparticles; Flow assurance; Dewaxing; Pigging; Subsea pipeline,WAX PRECIPITATION; OIL; NANOPARTICLES; HYPERTHERMIA; DEPOSITION; WATER; CRYSTALLIZATION; TEMPERATURE; INHIBITORS; INSPECTION,"Wax, hydrates, and asphaltenes precipitate in subsea pipelines and restrict the transport of hydrocarbons. Traditional wax prevention and dewaxing methods include thermal, chemical, and mechanical approaches. This paper investigates a new electromagnetic pigging method combined with a ferromagnetic nanopaint for potentially high heating efficiency and low maintenance cost. The electromagnetic pig could be inserted into the pipeline to generate induction heating; a nanopaint coating on the inner wall of the pipeline enhances the heating effect. To evaluate the effectiveness of the proposed system, we calculate the maximum pig speed, which is the fastest a pig can move through the pipeline and effectively dislodge wax deposits by heating. Systems with a higher maximum pig speed can dewax a pipeline in a shorter time. Numerical models are used to analyze the heating performance for different system configurations. Simulation results show that the proposed pigging tool can effectively heat and melt the deposited wax. The maximum pig speed is a function of the pig induction coil length and radius. The hydraulic shape of the pig does not impact the heating effectiveness.",1,1,3
Asphaltene Deposition,,"Moncayo-Riascos, Ivan; De Leon, Jennifer; Garcia-Martinez, Jorge A.; Garcia-Cruz, Isidoro; Lira-Galeana, Carlos",Multiscale simulation of asphaltene deposition in pipeline flows,Asphaltene deposition; Hematite pipeline; Multi-scale simulations; Molecular dynamics; Dissipative particles dynamics; Reynolds number analysis,DISSIPATIVE PARTICLE DYNAMICS; MOLECULAR-DYNAMICS; OXIDE NANOPARTICLES; CHEMICAL ALTERATION; LANGMUIR ISOTHERM; ADSORPTION; SURFACE; WETTABILITY; OIL; CALCITE,"A novel multi-scale approach to asphaltene deposition in pipeline flows is presented. Pipelines are represented by Hematite (Fe2O3) surfaces, whereas Saturates, Aromatics, Resin and Asphaltene fractions (as provided by a SARA analysis) are used to represent a petroleum fluid. Molecular Dynamics (MD) and Dissipative Particle Dynamics (DPD) simulations are used to describe both the fluids and the fluid/surface interactions. The extent of asphaltene deposition in a pipe is calculated through a balance of adhesion (as calculated through MD simulations of the asphaltene-surface interaction) and drag (as represented by a Poiseuille flow in a shear field) forces, in a system of varying flowrates. Models and methods are validated first by different ways: interfacial tension and the hematite/asphaltene and asphaltene adsorption thickness on a glass surface. Two behaviors were found. The first one shows a clear decrease of asphaltene adsorbed thickness as the drag force increases (for Re < 4000); while for Re numbers higher than 5000 the adsorbed thickness decreases until it reaches a constant value. Thus, an increase in the flow rate allows drag forces to overcome the adsorption potential, reducing the amount of asphaltene adsorbed on the pipe, for a specific flow regime range. In addition, a clear reduction of density of adsorbed asphaltenes is promoted by the drag force. It is suggested that, under turbulent flow conditions, the drag forces allow a removal of molecules located at the external layer of the adsorbed asphaltene on the hematite surface. Drag forces would stabilize asphaltenes at the bulk fluid, since the shear rates could overcome asphaltene aggregation.",2,2,3
Asphaltene Deposition,,"Setaro, Luisa L. O.; Pereira, Veronica J.; Costa, Gloria M. N.; Vieira de Melo, Silvio A. B.",A novel method to predict the risk of asphaltene precipitation due to CO2 displacement in oil reservoirs,Asphaltene precipitation; ASIST method; Oil stability; Solubility parameter; CO2 injection,GAS INJECTION PROCESSES; PRESSURE; TEMPERATURE; DEPOSITION,"A new fully predictive method was developed to calculate the risk of asphaltene precipitation in oil reservoirs based on a modification of the Asphaltene Instability Trend (ASIST) method. For prediction of asphaltene precipitation by oil depletion, this new method simplifies the ASIST method in order to use a minimum number of experimental data. As a novelty, prediction of asphaltene precipitation by CO2 displacement using a modification of the ASIST method is introduced. Both modifications were validated for a large number of oils from the literature. Results show that with both modifications this new method provides better results than previous ones to predict the risk of asphaltene precipitation in oils by depletion and unprecedented good results to evaluate potential asphaltene precipitation in oil reservoirs due to CO2 displacement with requirement of few experimental data. The proposed method may be used in the oil and gas industry to predict the risk of asphaltene precipitation by depletion or by CO2 displacement.",3,3,0
Asphaltene Deposition,,"Ghadimi, Marzieh; Ghaedi, Mojtaba; Amani, Mohammad J.; Malayeri, Mohammad R.",Impact of production operating conditions on asphaltene induced reservoir damage: A simulation study,Asphaltene; Precipitation; Deposition; Damage; Compositional simulation,PRECIPITATION; DEPOSITION; MODEL; REVERSIBILITY; PRESSURE; OILS,"Asphaltene deposition in the near well bore region, tubing and surface facilities causes chronic problems in oil industry. Mechanical, thermal and chemical approaches are frequently being used but each suffers from certain limitations and shortcomings. The utilization of such methods also comes usually with a large price tag as these require mechanical equipment, pumps, new completion and tubing, solvents and chemical materials. Needless to say that these are often performed during well shutdown. The choice of optimal production operating conditions which otherwise would prevent or diminish asphaltene deposition is preferential. In previous studies, producing with low bottom hole pressure (BHP) has been proposed as a viable solution for some of asphaltenic oil fields, but a thorough and detailed study is still lacking. In this study, a comprehensive simulation methodology is developed to tackle impacts of BHP conditions on the asphaltene deposition. An IMPES (Implicit Pressure and Explicit Compositions) cylindrical, compositional simulator is developed which considers asphaltene deposition dynamically. Precipitated asphaltene is considered as a pure dense liquid which is determined by LLE calculation using PR-EoS. The amount of deposition is obtained through three mechanisms of surface deposition, entrainment and pore throat plugging. The permeability reduction is correlated with porosity reduction using a power-law relation. Detailed analysis of the simulated cases reveals that selecting a very low BHP (bellow bubble point pressure) would maintain the reservoir in a desirable pressure range far from the maximum deposition point.",4,4,0
Asphaltene Deposition,,"Ghosh, Bisweswar; Sulemana, Nuhu; Banat, Fawzi; Mathew, Nevin",Ionic liquid in stabilizing asphaltenes during miscible CO2 injection in high pressure oil reservoir,Ionic liquids; Asphaltene inhibition; CO2 injection; Asphaltene onset pressure (AOP),ALKYLBENZENE-DERIVED AMPHIPHILES; 1-BUTYL-3-METHYLIMIDAZOLIUM ACETATE; INFRARED-SPECTROSCOPY; CARBON-DIOXIDE; DISPERSANTS; SOLUBILITY; DEPOSITION; PRECIPITATION; PETROLEUM; MIXTURES,"The potential of ionic liquids to prevent asphaltene precipitation during miscible Carbon dioxide (CO2) flooding was investigated. Asphaltene dispersion tests were performed to compare the effectiveness of commercial inhibitors and the ionic liquids at ambient conditions. Based on the results 1-Butyl-3-methyl-imidazolium bromide [BMIM][Br], Ionic Liquid was selected and asphaltene onset pressure (AOP) was determined at high-temperature high-pressure conditions through isothermal depressurization experiments in PVT cell. The effect of CO2, organic solvents and [BMIM][Br] on AOP were documented and correlated with nodal pressure analysis of the reservoir/wells. The results show a 21% decrease in AOP compared to the untreated oil and about 46% decrease when 35 mol % of CO2 is solubilized in oil. [BMIM][Br] is seen to have higher activity when injected in solution with isopropanol-n-heptane compared to direct addition. The application of [BMIM][Br] in miscible CO2 flooded reservoir is found to have good potential in inhibiting asphaltene deposition within the reservoir and near wellbore nodal conditions.",4,5,1
Asphaltene Deposition,,"Bemani, Amin; Poozesh, Abdolrahman; Bahrami, Masoud; Ashoori, Siavash",Experimental study of asphaltene deposition: Focus on critical size and temperature effect,Asphaltene deposition; Deposition critical size; Temperature effect; Capillary tube; Deposition rate,CRUDE OILS; AGGREGATION; PRECIPITATION; ISLAND; MODEL,"Asphaltene by far is the most problematic part of crude oil that could separate from oil body as a result of any change in system equilibrium. It can deposit at any point along oil flow path which in turn impose series restrictions, and subsequently create major impact on production from economic perspective. In this study, the influence of oil composition, flow rate, and for the first time, temperature on the intensity of deposition process are experimentally investigated. An in-house deposition unit apparatus was utilized which is based on the measurement of pressure drop across the capillary tube. The results indicate that in overall, temperature and oil composition change toward less soluble asphaltene, accelerate deposition process while flow rate enforces further restriction on process. In addition, by devising novel centrifugal based deposition experiments, critical size concept is more effectively addressed. The concept argues that there is a critical value for asphaltene aggregate size, beyond which the deposition will not occur. This critical size is not necessarily influence by hydrodynamic drag like forces.",5,5,2
Buckling,,"Zhang, Qiang; Jiang, Bao; Xiao, Zhongmin; Cui, Wei",Buckling transition process of suspended tubulars during loading and unloading,Suspended tubulars; Helical buckling; Critical load; Finite element; Quasi-static method,BOUNDARY-CONDITIONS; STRINGS; PIPE; CONNECTORS; ROD; FRICTION; BEHAVIOR,"In this paper, we investigate the numerical simulation of the whole buckling transition process during unloading and loading of the compression load with quasi-static method. By using a smaller load increment step, longer calculation time and appropriate damping, this buckling transition is calculated. We find that the tubular deformation evolves from continue-line contact to bottom-top-point, continuous-point, spatial two-point, spatial one-point, planar one-point contact, and finally back to vertical configuration during unloading. This deformation sequence is reversed during loading. During the transition from planar one-point contact to spatial two-point contact deformation, the buckling shape and related physical quantities change abruptly. During unloading and loading, the dimensionless critical loads of the first three buckling deformations are basically the same. For the buckling deformations with spatial two-point and planar one-point contact, and for spatial one-point contact deformation, the critical loads of loading are about 5% and 50% larger than that of unloading, respectively. For the spatial one-point contact deformation with dimensionless length greater than 40 and other buckling deformations with dimensionless length greater than 20, the critical loads obtained in the buckling process remain almost unchanged. It is noted that since the friction effect is not considered in our numerical simulation, the critical loads obtained are the minimum values in the process of buckling transition.",3,3,1
Buckling,,"Feng, Tianheng; Bakshi, Soovadeep; Gu, Qifan; Yan, Zeyu; Chen, Dongmei",Design optimization of bottom-hole assembly to reduce drilling vibration,Drilling vibration; Bottom-hole assembly; Finite element method; Genetic algorithm; Parallel computation,ROD,"Drilling vibration has been considered as one of the major undesirable drill-string dynamics. This paper establishes a framework to optimize the design of the bottom hole assembly (BHA) such that the BHA structure is resilient against vibration. Firstly, a high-fidelity BHA model is established using the finite element method (FEM), which considers the buckling effects caused by the weight on bit (WOB) and the contact between stabilizers and wellbore. Then, vibration indices, such as the BHA strain energy and the stabilizer side force, are derived using the FEM model to evaluate BHA vibration. The stabilizer positions can determine the indices through influencing the boundary conditions; therefore, designing stabilizer positions to reduce drilling vibration can be formulated as an optimization problem to minimize the BHA vibration indices over the operational range. The cost function is non-convex within feasible domain and cannot be expressed explicitly in terms of stabilizer positions. The derivative-free genetic algorithm (GA) is selected to solve the non-convex problem, where parallel computation is implemented to expedite the computational process. For model verification, the finite element analysis of a BHA is conducted and compared against analytical solutions and existing literature and shows a good agreement. A production BHA is optimized following the proposed method. GA can optimize the stabilizer positions with high accuracy and low computational cost. The strain energy and stabilizer side force of the redesigned BHA are significantly reduced compared with the original design, which results in a much better BHA dynamic performance and less drilling vibration.",3,3,1
Buckling,,"Zhang, Qiang; Jiang, Bao; Xiao, Zhongmin; Cui, Wei; Liu, Jubao",On the failure configuration of suspended tubular strings when helical buckling just occurs,Suspended tubular strings; Helical buckling; Critical load; Finite element; Dynamic relaxation method,AXIAL LOAD-TRANSFER; ROD; CONNECTORS; FRICTION; BEHAVIOR,"When the sinusoidal buckling of suspended tubular strings is transforming to helical buckling, the deformation changes drastically, which makes the tubular strings extremely unstable. The quantitative description of this buckling configuration in previous theoretical studies is not precise enough. In our current study, dynamic relaxation method is applied to carry out numerical simulation of buckling transition of suspended tubular strings. To obtain stable buckling configurations, larger Rayleigh damping is used to attenuate the dynamic effect. With the increase of axial compression load, the lateral buckling of the suspended strings suddenly becomes spiral shape with two contact points. As the string length increases, the position of the lower contact point remains almost at the same position. While the upper contact point gradually moves upward, and the helix angle between the two points increases and gradually tends to be constant. The maximum contact force is located at the lower contact point, the maximum shear force is located at the bottom of the strings, and the dimensionless distance between the location of the maximum bending moment and the well bottom is about 1.0. These loads, including the maximum contact force, maximum shear force and maximum bending moment, gradually decrease with the increasing string length and tend to be constant. The dimensionless critical load is reduced from 4.41 to 3.81 with the effect of string length. The critical load calculated in this paper is the minimum value when helical buckling just occurs. The results obtained in the current study have wide engineering applications, particularly in failure analysis and prevention of helical buckling.",3,3,2
Buckling,,"Han, Yiwei; Ai, Zhijiu; Kuang, Yuchun; Liu, Jianxun; Yang, Wenwu",Nonlinear dynamic modeling of drill string in horizontal well - A geometrically exact approach,Horizontal drill string; Nonlinear dynamics; Geometrically exact model; Quadrature element method,FINITE-ELEMENT FORMULATION; 3-DIMENSIONAL BEAM THEORIES; SPATIAL BEAMS; DRILLSTRINGS; SPACE; PIPE; ROD,"A new nonlinear dynamic model of drill string in horizontal well is established based on geometrically exact beam theory and quadrature element method. The model proposed in this paper takes into account the geometric nonlinearity of the drill string and the nonlinear contact between the drill string and the borehole. Benefiting from the accuracy of the geometric description of the geometrically exact beam, the model uses a geometrically exact method to describe the contact between the drill string and the borehole. Comparison with experimental results shows that the geometrically exact model can accurately describe the nonlinear characteristics of the drill string. Finally, the characteristics of the movement of drill string under different drilling pressure and rotation speed are analyzed. Drilling pressure and rotational speed have an effect on the buckling of the drill string. Before buckling, the drill string moves periodically at the bottom of the wellbore. After buckling, the movement of the drill string becomes disordered. The model presented in this paper provides a new method for dynamic analysis of drill string.",3,3,10
Buckling,,"Tong, Shaokai; Gao, Deli",Elastic-plastic collapse limit analysis of coiled tubing under complex stress state,Collapse limit; Coiled tubing; Twin shear unified strength theory; Yield criterion; Complex stress,,"Collapse failure of coiled tubing (CT) due to complex stresses is an important issue during the operations in the oil and gas wells. This paper presents new analytical models to define the collapse limit of CT and solve the problem of CT failures. Elastic-plastic collapse limit models of CT are established based on the twin shear unified strength theory. The effects of axial force, buckling, and internal pressure on the elastic-plastic collapse limit are analyzed. Moreover, the comparisons among the new model, the existing model and API specification are further discussed. The results indicate that the elastic-plastic collapse limit models determined using the twin shear unified strength theory can describe the mechanical behaviors of CT under complex stress state. Elastic-plastic collapse limits of CT decrease with increasing axial tensile force and increase with increasing axial compressive force. The effect of buckling and bending stress on the elastic-plastic collapse limit cannot be ignored in the analysis of CT collapse. With increasing external pressure, the plastic region keeps extending to the outer surface of CT. Plastic collapse limit is the value of external pressure for which the entire wall thickness of CT becomes plastic. The proposed approach can be used to set the elastic-plastic collapse limits for other oil tubulars.",4,5,0
Buckling,,"Zhu, Xiao-hua; Li, Bo",Numerical simulation of dynamic buckling response considering lateral vibration behaviors in drillstring,Mechanical behavior; Dynamic analysis; Buckling behavior; Finite element method; Critical length,,"Mechanical behavior of oilwell drillstring coming at the motions of penetrating rock is associated with drilling safety and wellbore quality. A poor performance can be attended by elastic stability loss in a slender drillstring exerting undesired buckling and vibration phenomena in the working process. Devoting to investigating the dynamic buckling behavior is an efficient way to avoid fatigue failure of the drillstring components and enhance drilling rate. A dynamic analysis of the buckling behavior of the entire column considering violent lateral vibrations is presented as a result available. Analytical equations of the drilling system are integrated numerically with finite element method. A virtual contact element implemented between the drillstring and the borehole, in conjunction with Hertzian contact assumption, gives the direct access to calculate the contact force and positions. Lateral deflection, critical length and the effects of drilling parameters and stabilizer on the buckling deformation are captured to experience the realistic buckling response of a typical drillstring in a vertical well. Simulation results indicate that spiral pitch and wave numbers of a nonlinear spiral shape prevailing in the lower zone of drillstring are deeply associated with the cutting force at the bit. Improving a drillstring behavior performance in a real oilfield is observed that this model can assist in evaluating the properties of the working security and buckling resistance with complex boundary conditions.",4,4,0
Data Assimilation,,"Maschio, Celio; Schiozer, Denis Jose",A new parameterization method for data assimilation and uncertainty assessment for complex carbonate reservoir models based on cumulative distribution function,Reservoir simulation; History matching; Data assimilation and uncertainty assessment; Cumulative distribution function; Complex geological systems; Super-K,PRINCIPAL-COMPONENT ANALYSIS; DIFFERENTIABLE PARAMETERIZATION; OPTIMIZATION; ZONES,"Data assimilation (also known as history matching) and uncertainty assessment is the process of conditioning reservoir models to dynamic data to improve its production forecast capacity. One of the main challenges of the process is the representation and updating of spatial properties in a geologically consistent way. The process is even more challenging for complex geological systems such as highly channeling reservoirs, fractured systems and super-K layered reservoirs. Therefore, mainly for highly heterogeneous reservoirs, a proper parameterization scheme is crucial to ensure an effective and consistent process. This paper presents a new approach based on cumulative distribution function (CDF) for parameterization of complex geological models focused on layered reservoir with the presence of high permeability zones (super-K). The main innovative aspect of this work is focused on a new sampling procedure based on a cut-off frequency. The proposed method is simple to implement and, at the same time, very robust. It is able to properly represent super-K distribution along the reservoir during the data assimilation process, obtaining good data matches and reducing the uncertainty in the production forecast. The new method, which preserves the prior characteristics of the model, was tested in a complex carbonate reservoir model (UNISIM-II-H benchmark case) built based on a combination of Brazilian Pre-salt characteristics and Ghawar field information available in the literature. Promising results, which indicate the robustness of the method, are shown.",1,1,0
Data Assimilation,,"Jiang, Junzhe; Gorell, Sheldon B.",Analysis of localization methods in Ensemble Kalman Filter with SVD analytical solution,Localization; Parameterization; Ensemble Kalman Filter; History Matching; Reservoir Simulation,DATA ASSIMILATION,"When localization methods used in reservoir history matching were introduced from outside the oil and gas industry, the differences between data assimilation for other industries and reservoir history matching were not considered. However, these differences can be extremely important when considering the validity of these methods. This problem is discussed within the context of the roles of covariance localization in detail in this paper. This paper starts with discussion of relations between two significant problems, ill-posedness and spurious correlations, and their solution methods. This analysis leads to a conclusion about two appropriate roles of the covariance localization method. This conclusion is used to validate the cross-covariance localization methods used in reservoir simulation. In addition, for the cross-covariance localization in reservoir history matching, there are many different processes, especially different correlation functions, proposed by different authors. This makes it difficult to choose a proper method when solving history matching or data assimilation problems. The performance of different cross-covariance localization correlation functions is also analyzed theoretically and experimentally in this paper.",1,1,0
Data Assimilation,,"Ranazzi, Paulo Henrique; Sampaio, Marcio Augusto",Influence of the Kalman gain localization in adaptive ensemble smoother history matching,History matching; Ensemble smoother with multiple data assimilation; Kalman gain localization; Uncertainty assessment,DATA ASSIMILATION; FILTER; PARAMETERIZATION; OPTIMIZATION; SCHEME; MODELS,"In reservoir engineering, history matching is the technique of conditioning a reservoir simulation model to the available production data. The reservoir properties have uncertainties which lead to discrepancies between the observed data and the reservoir simulator response, making history matching an indispensable tool in the petroleum industry. The standard Ensemble Smoother with Multiple Data Assimilation (ES-MDA) application has become popular in history matching problems. However, in the standard methodology, the number of iterations must be previously defined by the user, what makes it a determinant parameter in the ES-MDA results. One way to solve this problem is to perform adaptive algorithms: these algorithms keep iterating until they reach desirable matchings with the real data. Furthermore, to apply this method in large-scale reservoirs, it is necessary to use some localization technique to prevent spurious updates and high uncertainty reduction after the ES-MDA is applied. This work evaluates the influence of the distance-based Kalman Gain localization in an adaptive Ensemble Smoother, by applying the mentioned methodology in a large-scale synthetic reservoir model. The experiments showed a connection between the localization parameters and the number of iterations required by the adaptive algorithm. Moreover, the results presented significant reduction in the production data mismatch, regardless the localization, being the mismatch of the prior and posterior models an important parameter to determine the history matching quality.",2,3,1
Data Assimilation,,"Patel, Rajan G.; Jain, Tarang; Trivedi, Japan",Performance of ensemble Kalman filter and Markov chain Monte Carlo under uncertainty in forecast model,Markov chain Monte Carlo; Ensemble Kalman filter; Uncertainty quantification; Polynomial chaos expansion; Reservoir characterization; Data assimilation,DATA ASSIMILATION; QUANTIFYING UNCERTAINTY; PROXY MODELS; SIMULATION; QUANTIFICATION; CONVERGENCE; INFERENCE; FLOW; RML,"Ensemble Kalman filter (EnKF) and Markov chain Monte Carlo (MCMC) are popular methods to obtain the posterior distribution of unknown parameters in the reservoir model. However, millions of simulation runs may be required in MCMC for accurate sampling of posterior as subsurface flow problems are highly nonlinear and non-Gaussian. Similarly, EnKF formulated on the basis of linear and Gaussian assumptions may also require a large number of realizations to correctly map the solution space of the unknown model parameters, ultimately resulting in the high computational cost. Data-driven meta/surrogate/proxy models provide an alternative solution to alleviate the issue of high computational cost. Since these models are not as accurate as numerical solutions of partial differential equations (PDE), their implementation may add an uncertainty in the forecast model. In literature, the effect of uncertainty in forecast model on data assimilation is not well studied, especially with field-scale reservoir models. In this work, we take the opportunity to evaluate and compare the performance of EnKF and MCMC using polynomial chaos expansion (PCE) based forecast model. Proposed forecast model relies on reducing parameter space using Karhunen-Loeve (KL) expansion which preserves the two-point statistics of the field. Random variables from KL expansion and orthogonal polynomials corresponding to the prior probability density function (pdf) form the set of input parameters in PCE. Further, non-intrusive probabilistic collocation method (PCM) is used to compute PCE coefficients. PCE forecast model is then used in EnKF and MCMC to calculate the likelihood of the samples in place of high fidelity full physics simulation runs. A case study is performed using a 3D field scale model of a reservoir located near Fort McMurray in northern Alberta, Canada. Performance of EnKF and MCMC are assessed under forecast model uncertainty using rigorous qualitative and quantitative analysis and posterior distribution characterization. Results clearly depict that, although EnKF provided reliable mean and variance estimates of model parameters, MCMC outperformed the former even under the uncertainty associated with PCE metamodel. Inaccurate initial assumptions of model parameters were successfully handled by MCMC, although, with a longer burn-in period. Furthermore, characterization of posterior demonstrated reduced uncertainty in the estimation of model parameters using MCMC as compared to EnKF. Practical implications of the proposed approach and performance assessment under forecast model uncertainty will be consequential in designing accurate and computationally efficient reservoir characterization workflows and hence, improved decision-making in reservoir management.",3,3,1
Data Assimilation,,"Emerick, Alexandre A.",Analysis of geometric selection of the data-error covariance inflation for ES-MDA,History matching; ensemble data assimilation; ensemble smoother with multiple data assimilation; discrepancy principle,LEVENBERG-MARQUARDT SCHEME; ITERATIVE ENSEMBLE SMOOTHERS; KALMAN FILTER; UNCERTAINTY; REGULARIZATION; OPTIMIZATION; ASSIMILATION; PERFORMANCE; MODELS,"The ensemble smoother with multiple data assimilation (ES-MDA) has become a popular assisted history-matching method. In its standard form, the method requires the specification of the number of iterations in advance. If the selected number of iterations is not enough, the entire data assimilation must be restarted. Moreover, ES-MDA also requires the selection of data-error covariance inflations. The typical choice is to select constant values. However, previous works indicate that starting with large inflation and gradually decreasing during the iterations may improve the quality of the final models. This paper presents an analysis of the use of geometrically decreasing sequences of the data-error covariance inflations. In particular, the paper investigates a recently introduced procedure based on the singular values of a sensitivity matrix computed from the prior ensemble. Also, it introduces a novel procedure to select the number of iterations and the inflation factors. The procedures are evaluated in three reservoir history-matching problems with increasing level of complexity. The first problem is a small synthetic case used to illustrate that the standard ES-MDA scheme with constant inflations may result in overcorrection of the permeability field and that a geometric sequence can alleviate this problem. The second problem is a recently published benchmark (UNISIM-I-H) and the third one is a field case with real production data. The data assimilation schemes are compared in terms of a data-mismatch and a model-change norm. While the former evaluates the ability of the models to reproduce the observed data, the latter evaluates the amount of changes in the prior model. The results indicate that geometric inflations can generate solutions with a desirable good balance between both norms.",5,5,3
Cement Slurry,,"Panchmatia, Parth; Zhou, Nancy S.; Juenger, Maria; van Oort, Eric",Monitoring the strength development of alkali-activated materials using an ultrasonic cement analyzer,Ultrasonic cement analyzer; Compressive strength; Alkali activated material; Fly ash,,"The ultrasonic cement analyzer (UCA) is used as an aid to develop new cement formulations or perform quality assessment on existing formulations prior to on-site application. The non-destructive UCA technique monitors the strength development of cements by measuring the time required for ultrasonic waves to travel through the cement sample and predicting the strength using empirical correlations, which were developed for ordinary Portland cement slurries. Unfortunately, these empirical correlations cannot be used to accurately predict the strength development for fly ash-based alkali activated materials (AAMs), which are a viable alternative to ordinary Portland cement slurries for oil-well cementing applications. Therefore, a new empirical correlation linking the transit time (i.e. the time required for ultrasonic waves to travel through a unit length of the cement sample) to the compressive strength of fly ash-based AAMs was developed in this study. Class F fly ash was activated by four different alkaline solutions, two sodium hydroxide solutions with 6M and 8M concentrations and two sodium silicate solutions with SiO2/Na2O weight ratio of 0.12 and sodium concentration of 6M and 8M, to produce 4 different slurries which were cured under downhole conditions. 50 mm cubes were crushed to determine the compressive strength of these AAMs after 18, 24, 48, and 72 h of curing. UCA testing was conducted to measure the transit time up to 72 h of curing. Linear regression was performed to develop a correlation linking the measured compressive strength to the measured transit time and AAM mix design parameters. One-way ANOVA analysis revealed that the change in transit time, the concentration of sodium in the activator solution, the SiO2/Na2O weight ratio of the activator solution, and the CaO content of the FA were all significant in predicting the compressive strength of the resulting AAM. The proposed model is applicable for AAMs prepared using Class F fly ash and sodium hydroxide/silicate activating solution with sodium concentration and SiO2/Na2O weight ratio ranging between 6M and 8M and 0 and 0.12, respectively.",2,2,0
Cement Slurry,,"Matias Paiva, Luanna Carla; Ferreira, Irantecio Mendonca; Martinelli, Antonio Eduardo; de Oliveira Freitas, Julio Cezar; Bezerra, Ulisses Targino",Milled basalt fiber reinforced Portland slurries for oil well applications,Basalt fiber; Oil well cement; Portland cement; Silica flour,MECHANICAL-PROPERTIES; SILICA FUME; CEMENT; CONCRETE; TEMPERATURE; STRENGTH; BEHAVIOR; MICROSTRUCTURE; PERFORMANCE; DURABILITY,"The dispersion of short fibers to oil well Portland slurries may improve the compressive strength and fracture energy of the hardened cementing material. A study was carried out to investigate the effect of the addition of ball-milled basalt fibers (5% BWOC) to Portland slurries. Samples were prepared with and without silica flour (40% BWOC) in the composition and cured for 7 days under different Bottom Hole Static Temperatures (BHST): 80 degrees C (176 degrees F) and 300 degrees C (572 degrees F). The mechanical properties and the microstructure of the hardened pastes were evaluated by compressive strength tests, X-ray diffraction and scanning electron microscopy. The results showed that milling basalt fibers was a cost efficient method to adjust the length of the basalt wool fibers assuring slurry mixing and, therefore, adequate pumpability. The combined addition of silica flour and basalt fibers improved the fracture energy of samples cured at 80 degrees C, therefore below the strength retrogression temperature. Curing at 300 degrees C resulted in significant fiber consumption by pozzolanic reactions that could not be prevented by the addition of silica flour. Therefore, ball-milled basalt fibers can be a cost-efficient and environmental-friendly solution to improve the mechanical properties of oil well cement slurries used below the retrogression temperature.",2,2,7
Cement Slurry,,"Rodrigues, Elias C.; de Souza Mendes, Paulo R.",Predicting the time-dependent irreversible rheological behavior of oil well cement slurries,Cement paste; Cement slurry; Thixotropy; Fluidity; Constitutive equation; Time-dependent,HYDRATION; PASTES; MODEL,"We propose a constitutive model to describe the rheological behavior of oil well cement pastes. The model is capable of predicting time dependence and irreversibility caused by the continuous hydration process that occurs in oil well cement pastes during cementing operations. The model is developed for a specific cement paste according to a recently proposed method (de Souza Mendes a al., 2018), with a modification to accommodate cement setting predictive capability. The fluidity (reciprocal of viscosity) is directly employed to indicate the structuring level of the microstructure. The model relies on the results of several rheological experiments to determine the nature and parameter values of novel material functions that arise in the model development. The material function that carries the cement setting information is the yield stress function, which turns out to be an exponentially increasing function of time. Except for minor differences observed at low shear rates, good agreement is observed between the data and the model predictions.",3,3,3
Cement Slurry,,"Zeng, Yijin; Lu, Peiqing; Zhou, Shiming; Sang, Laiyu; Liu, Rengguang; Tao, Qian",A new prediction model for hydrostatic pressure reduction of anti-gas channeling cement slurry based on large-scale physical modeling experiments,Cementing; Hydrostatic pressure reduction; Experiment; Multiple fitting; Prediction model,,"Accurate prediction of the change in slurry column pressure during cement slurry weightlessness is important in eliminating the problem of gas channeling in a cemented annulus. However, the factors that incur cement slurry weightlessness are complex and diverse, and the hydrostatic pressure reduction prediction model based on gelling suspension and volume shrinkage needs to be further improved. Therefore, for the new anti-gas channeling cement slurry system, over 120 sets of cement slurry pressure change data have been collected by using a precise pressure conduction measurement device. Based on the experimental data, a multiple regression fitting method was used to establish a nondimensional model for the hydrostatic pressure reduction of cement slurry. The calculation model is easy to use and has a high fitting accuracy (the average prediction error is < 11%). This model comprehensively considers the influence of the anti-gas channeling agent content, gas formation pressure, borehole temperature and geometric parameters on the pressure reduction rate of the cement slurry. This modeling process provides a new solution to establish a more practical and effective prediction model for the hydrostatic pressure reduction of cement slurry.",4,5,4
Cement Slurry,,"Jiang, Chengyang; Yu, Bin; Ma, Qisheng; Dong, Han; Dong, Haijun; Zhao, Hongxiang; Sakinejad, Parastoo; Luo, Yuwei; Tang, Yongchun","Crosslinked polymers as ""smart"" viscosifiers used in hostile environments",Viscosifier; Water-soluble polymer; Crosslink; Molecular modelling; Cementing; Rheology,,"We report the computer-assisted design, syntheses and application of a temperature-responsive, thermally stable and salt resistant polymer viscosifier that is useful in various upstream operations such as well cementing. With the increasing exploration of deep and ultradeep wells, thermally stable and salt resistant viscosifiers that does not adversely increase the viscosity of working fluids at lower temperatures become much desired. In this contribution, we implement the idea of using polymers crosslinked with labile molecules to realize such ""smart"" viscosity modulation. Guided by computational modelling, we demonstrate the right combination of polymer backbones and crosslinkers can lead to desired rheological and thermal characteristics, which are further verified by the improved properties of a cementing slurry system.",5,5,4
Nuclear Magnetic Resonance,,"Elkhateeb, Abdelrahman; Rezaee, Reza; Kadkhodaie, Ali","Prediction of high-resolution reservoir facies and permeability, an integrated approach in the Irwin River Coal Measures Formation, Perth Basin, Western Australia",Electrofacies; Hydraulic flow units; Core analysis; Permeability assessment; Shaly sand; Formation evaluation,,"Traditionally, prediction of facies and permeability for a reservoir rock was one of many challenges in the industry that necessitates advanced and sophisticated evaluation for effective reservoir description. Three wells have been studied in the Perth Basin in Western Australia across the shaly sand of the Irwin River Coal Measures Formation, which contain a comprehensive suite of advanced and conventional logs. Due to the reservoir heterogeneity and the clay distribution, it is very challenging to resolve the effective pore volume, the reservoir facies and how the high permeability zones are distributed within the formation. In this paper, a new technique has been successfully tested on the Shaly Sand by integrating the nuclear magnetic resonance (NMR) and the conventional density log. The method allows the establishment of high-resolution facies classification for the reservoir using an Equivalent Flow Zone Indicator Index (EFZI). The studied core facies have been integrated with the EFZI into a new workflow to distribute facies on a larger scale in the uncored wells. Four hydraulic flow units (HFU) have been defined from one cored well using Flow Zone Indicator approach, with each has a unique FZI value and different permeability model based on core measurements. The EFZI-based high-resolution facies have been validated at several formation depths using the core thin sections to ensure the best calibration will be obtained for facies log, hence the permeability log-to-core match. The methodology will help running an advanced petrophysical analysis for the zone of interest and will reduce the parameters uncertainty. Application of this methodology in the uncored wells has shown very encouraging results, which is believed it can be used in the absence of any core data to resolve the rock typing from the well logs.",3,3,0
Nuclear Magnetic Resonance,,"Min, Byeungju; Sondergeld, C. H.; Rai, C. S.",Investigation of high frequency 1D NMR to characterize reservoir rocks,NMR(nuclear magnetic resonance); High frequency; Internal field gradient; SNR(signal to noise ratio); Echo spacing; Dynamic monitoring; Breakthrough time,,"Typical laboratory Nuclear Magnetic Resonance (NMR) measurements for core analysis are made at a frequency of 2 MHz, principally to verify downhole logging measurements with frequency ranging from 0.7 to 2 MHz. However, higher frequencies have been introduced in measuring shale properties. In this study, we investigate the differences between low frequency (2 MHz) NMR and higher frequency (12 MHz) NMR responses with different TE (Echo Time) ranging from 114 to 300 mu s in various rock types including sandstones and shales. We found that 12 MHz instrument attains a greater SNR (Signal to Noise Ratio) ranging from 7.3 to 9.8 times higher with fewer scans than the 2 MHz instrument. While this is an insignificant factor for highly porous rocks, it is very important when measuring shales, which requires numerous scans to achieve an acceptable SNR levels. This is also significant while tracking time dependent fluid changes in rocks. We demonstrate novel technique of the dynamic monitoring for a CO2 displacement of oil experiment with 12 MHz NMR instrument. T-2 spectra were obtained every 20 min to document the oil saturation profile. From this saturation profile, breakthrough time and residual oil saturation were determined to be 340 min and 54%, respectively. Total porosity measurements were almost identical between 2 MHz and 12 MHz with an average difference of +/- 0.38 p.u. For shale samples only, the difference in porosity measurement was much less, i.e., +/- 0.16 p.u. Our results suggest that higher frequency NMR produces similar total porosity estimates, T-2 geometric means, and T-2 spectra for some conventional sandstones with low paramagnetic mineral content and shale lithologies.",3,3,0
Nuclear Magnetic Resonance,,"Coussirat, Vladimir; Amarilla, Fernando; Peruzzo, Pablo J.; Susana Cortizo, M.",Dioctyl fumarate-co-vinyl benzoate copolymers preparation and their performance as flow improvers in waxy crude oils,Fumaric copolymers; Reactivity ratio; Crude oil rheology; Flow improver,POUR-POINT DEPRESSANTS; RADICAL COPOLYMERIZATION; DIISOPROPYL FUMARATE; REACTIVITY RATIOS; LINEAR METHODS; START-UP; INHIBITORS; ACETATE; VISCOSITY; ACRYLATE,"This work presents the synthesis of new copolymers based on dioctyl fumarate (DOF) and vinyl benzoate (VB) and their application as flow improvers in a waxy crude oil. The copolymers were obtained by solution radical polymerization starting from a broad range of monomer compositions (f(DOF)) and characterized by Fourier-transform infrared spectroscopy (FTIR), Proton Nuclear Magnetic Resonance (H-1-NMR) Spectroscopy and Size exclusion chromatography. Results indicated that polymerization yield and molecular weight increases with decrease in f(DOF). Based on the composition of the copolymers the reactivity coefficients of the monomers were obtained, whose product r(1). r(2) = 0.042 indicates a copolymerization behavior with a high tendency to alternating copolymerization. Selected copolymers varying composition or molecular weight, were used as additive at different concentration to evaluate the effect of these variables on their performance as flow improvers in a waxy crude oil composed of paraffin with high average carbon number and a narrow carbon number distribution. The analysis was done through differential scanning calorimetry and rheological measurements. The addition of the lowest molecular weight copolymer resulted in the best efficacy as flow improver, while the highest molecular weight rich in VB copolymer produced an unwanted effect that worsen the flow properties of waxy crude oil at low temperatures.",5,5,0
Nuclear Magnetic Resonance,,"Heidary, Mohammad; Kazemzadeh, Ezatallah; Moradzadeh, Ali; Bagheri, Ali Mohammad",Improved identification of pay zones in complex environments through wavelet analysis on nuclear magnetic resonance log data,Nuclear magnetic resonance; Spin echo train; Wavelet analysis; Discrete wavelet transform; Transverse relaxation time; Pore fluid transverse relaxation time,NMR; BASIN; GAS; PERMEABILITY; RELAXOMETRY; SATURATION; RESOLUTION; TRANSFORM; VISCOSITY; CURVES,"Identification of pay zones is as a challenging topic in the reservoir characterization. Various methods have been employed to tackle this prominent task. Well logs are one of the most useful means for identifying pay zones, chiefly resistivity logs. However, resistivity measurements in some complex environments such as mixed lithology reservoirs, low resistivity and low contrast pay zones may fail to unveil productive zones. As an essentially lithology-independent tool, nuclear magnetic resonance (NMR) log may be the only approach to deal with detecting such subtleties. Using wavelet analysis technique and the NMR log data, this paper was aimed at identifying hydrocarbon bearing zones in two carbonate reservoirs. Discrete wavelet transform (DWT) was applied to the spin echo train at each depth to extract transverse relaxation time (T-2). By comparing the generated T(2 )log and resistivity log, a striking similarity was found between them. The T-2 log manifested strong correlation with porosity log. Therefore, the DWT was repeatedly applied to the T-2 log so as to remove the correlation. Various wavelets were adopted to remove the effect of porosity from the T-2 log, leading to achieve pore fluid transverse relaxation time, referred to as T(2f )Scrutinizing the T-2f log demonstrated that this log is not only highly functional in detecting productive zones but also highly capable of highlighting the subtle changes of pay zones. Consequently, the T-2f log revealed the latent pay zones unseen by resistivity log.",5,5,1
Nuclear Magnetic Resonance,,"Mitchell, Jonathan; Valori, Andrea; Fordham, Edmund J.",A robust nuclear magnetic resonance workflow for quantitative determination of petrophysical properties from drill cuttings,NMR; Cuttings; Fluorinert; Multinuclear; Fluorine NMR; Porosity; Permeability,SPIN RELAXATION; FLUID; NMR,"Determination of petrophysical parameters from surface measurements of drill cuttings, rather than well logs, has long been a subject of interest in the petroleum industry. Analysis of cuttings is presently included in mud logging workflows, although the methods employed tend to be labor-intensive and inefficient with an emphasis on qualitative lithological and mineralogical descriptors. Nuclear magnetic resonance (NMR) has the potential to deliver rapid formation evaluation at the rig site for near-real-time completion decisions. Despite numerous efforts to demonstrate NMR cuttings analysis, dating back to the 1980s, the technique has yet to achieve commercial success. We suggest this failure is due not to the physics of the measurement, which is understood, but rather to inadequate sample preparation. By centrifuging brine-saturated cuttings from conventional formations under a per-fluorinated oil, and using multinuclear NMR to measure liquid volumes, we obtain accurate porosity and permeability values independent of other measurements. Our robust workflow removes the inconsistencies associated with manual sample preparation. We present two case studies and the important requirements for handling actual drill cuttings.",5,5,2
Long Term,,"Mahdiani, Mohammad Reza; Khamehchi, Ehsan; Suratgar, Amir Abolfazl",Using modern heuristic algorithms for optimal control of a gas lifted field,Genetic algorithm; Grasshopper optimization algorithm; Moth swarm algorithm; Simulated annealing,STABILIZING GAS; OPTIMIZATION; FLOW; DESIGN,"In the gas lift, gas injection rate has an optimum value and increasing or decreasing its amount decreases the oil production rate. This optimum point changes in production time and creates an optimum trajectory. There has previously been much research in this area, but none have used a powerful tool in a dynamic model to find a good optimal path for maximizing the production or NPV in a gas-lifted field. In addition, gas allocation in a time step changes the production of different wells and the pattern of fluid flow and also reservoir pressure decline in the reservoir. This can affect the optimum gas allocation of the next time step, but this has not been analyzed in any of the previous works. In this paper, first, a model of reservoir and well of a gas lift well is developed and using some experimental data points the best-fitted correlations are selected. Then, two common and famous heuristic algorithms (genetic algorithm, simulated annealing), and two recently introduced optimization algorithms (Moth Swarm Algorithm and Grasshopper Optimization Algorithm) are used to find the optimal path of the injection lift gas rates of the wells. Finally, the results of these four algorithms are compared with each other and some other allocation scenarios. In addition, different aspects of the injection and production rates of the different wells and their cumulative rates and NPV paths are analyzed. The results illustrated that using MSA has an optimum point with higher production. In addition, MSA finds a specific control path with a need for lower lift gas and also a smaller compressor. It also has a really different control path with other optimization algorithm paths. In addition, in this paper, a new long term instability in flow is observed, which was explained by the drainage area of each well. This control path of each well was discussed and it was concluded that GA can find the most stable path.",2,2,0
Long Term,,"Leitenmueller, Verena; Rupprecht, Bernhard J.",A multidisciplinary approach for chemical EOR screening: Understanding alkali-oil interaction by the use of petroleum geochemistry,Biodegradation; Phase screening; Potassium carbonate; Reservoir engineering; Organic geochemistry; ASP flooding; Chemical flooding,INTERFACIAL-TENSION; VIENNA BASIN; SYSTEMS; MECHANISMS,"Alkali-based chemical enhanced oil recovery is used to increase the incremental oil production and relies on the interaction of alkali lye with crude oil. Optimizing the chemical formulation depends on screening multiple alkali concentration ranges to maximize the generated emulsion volume. However, the strong chemical variation of the crude oil, caused by biodegradation within the reservoirs, and its influence on generating in-situ soaps has never been studied in detail. In this paper, organic geochemical oil characterization was combined with phase screening data. Thereby, differences in terms of initial crude oil composition (slightly degraded, moderate degraded, and heavy degraded oils), but also regarding the excess alkali-equilibrated oil phase, and the hydrocarbons which are included in the in-situ soap (emulsion phase) were worked out. Different alkalis, concentration ranges, and water-oil-ratios were studied, to understand the control mechanism for the in-situ soap generation. The formed emulsions were observed over time (emulsion stability) and classified into possible emulsion types. Alterations caused by the alkali-oil interaction were quantified by the use of organic geochemistry. The degree of biodegradation seems to be an important control mechanism. Slightly degraded oils do not interact with the alkali lye due to a high content of non-polar compounds such as alkanes and isoprenoids. Moderately and heavily degraded oils show varying interactions with the alkali solution. The degree of interaction depends on the used degradation type, the alkali type as well as on the used concentration. Moderately degraded oils interact in a lower concentration range compared to heavily degraded oils, which show an increased non-soap forming acid content. Phase experiments conducted over a long period of time (100 days) were used to determine which emulsion types (micro or macro) were formed. Stable micro emulsions were preferably generated over time in formulations prepared with potassium carbonate (K2CO3). In contrast, formulations containing sodium carbonate (Na2CO3) hardly did not generate stable micro emulsions. The composition of alkali-equilibrated oil differs from the initial oil composition and shows a strong dependency of the used alkali type. Potassium carbonate caused mild alterations of the moderately and heavily degraded oils, whereas the impact of sodium carbonate was more severe. In addition, dissolution of naphthalenes, steranes, hopanes, and parts of the generated in-situ soap into the aqueous phase, was observed during the performed phase experiments of the moderately degraded oils (at the elevated pH values).",2,2,0
Long Term,,"Chen, Zhifeng; Zhu, S. Sherry",In-situ polymerization of dicyclopentadiene for rock reinforcement,Ring-opening metathesis polymerization; Polydicyclopentadiene; In-situ polymerization; Diffusion; Mechanical property; Rocks,OPENING METATHESIS POLYMERIZATION; ALKYLIDENE COMPLEXES; POLYDICYCLOPENTADIENE; TEMPERATURE; CATALYSTS; RHEOLOGY; KINETICS,"With the advances in the ring opening metathesis polymerization (ROMP) and the recent findings of long term stability of polydicyclopentadiene (pDCPD) in extreme conditions of high temperature and high pressure in water, it's desirable to develop suitable DCPD formulation towards downhole application as sealants or plugs because of its unique advantages as a low viscosity resin to penetrate into rocks and as a cured polymer with high mechanical strength to reinforce rocks. We have optimized the gel time and rheology of the resin before gel point to allow desired diffusion and polymerization of the resin into dry or 50% water saturated rocks. The decrease of rock porosity and permeability confirms the resin diffusion and polymerization inside the rocks. The storage modulus and flexural strength of the rock samples are improved, which favors DCPD's application as sealants, plugs or reinforcements for rock mechanical properties.",2,2,1
Slug Flow,,"Wan, Thiam Teik; Loh, Wai Lam; Dinh Tam Nguyen; Perez, Valente Hernandez; Premanadhan, Vivek Kolladikkal",Diameter scaling correlations for near atmospheric air-water slug velocities in horizontal pipe,Slug velocity; Scaling correlations; Diameter effects; Distribution parameter; Drift constant,LONG BUBBLES; FLOW; MOTION; TUBES,"In this work, an experimental two-phase air-water flow study was undertaken on pipelines with internal diameters of 27.86 mm, 54.78 mm and 108 mm. The slug velocities - diameter scaling correlations for near atmospheric air-water horizontal slug flow is studied. Maintaining near atmospheric conditions, the two-phase flow was established in horizontal pipes with visualization windows constructed out of acrylic. Utilizing high speed visualization techniques, diameter scaling correlations were used to predict mean velocities of slug fronts and slug tails under near atmospheric conditions. The outcomes were also compared with existing literature. It has been found that the correlations improve the predictive ability over a wider range of applications, giving reasonable accuracy from the range of 6.39%-23.24% AAE (average absolute error). Lastly, issues related to assumptions and extension capabilities of current and existing equations are addressed.",4,4,0
Slug Flow,,"Su, Xianbo; Yao, Shun; Song, Jinxing; Wang, Qian; Li, Feng",The discovery and control of slug flow in coalbed methane reservoir,Coalbed methane reservoirs; Slug flow; Permeability; Surface tension; Differential pressure,MODEL,"Slug flow, which can cause severe velocity sensitivity damage to coalbed methane (CBM) reservoirs, tends to happen at the gas-liquid two-phase flow stage during the CBM production process. However, little attention has been paid to this phenomenon. This paper investigates the factors which can influence the forming of slug flow in CBM reservoirs systematically via a series of laboratory experiments and production data from two CBM wells. Results show that a slug flow is more likely to be formed under the conditions of high reservoir permeability, high fluid surface tension and high producing differential pressure. This is because that both the high permeability and high production differential pressure would lead to a high fluid flow velocity that can cause strong Kelvin-Helmholtz instability effect of the interface wave. Then, the strong Kelvin-Helmholtz instability effect will cause the slug flow. Meanwhile, a high fluid surface tension means that the liquid will form slug flow more easily. The most effective way to restrain slug flow is to utilize a fracturing fluid with low surface tension in combination with continuous, slow and stable productions.",4,5,3
Slug Flow,,"Zhu, Jianjun; Zhang, Jiecheng; Cao, Guangqiang; Zhao, Qingqi; Peng, Jianlin; Zhu, Haiwen; Zhang, Hong-Quan",Modeling flow pattern transitions in electrical submersible pump under gassy flow conditions,Flow pattern transition; Mechanistic modeling; Electrical submersible pump; Gas-liquid flow; Bubble behavior,LIQUID PIPE-FLOW; 2-PHASE FLOW; CENTRIFUGAL PUMPS; UNIFIED MODEL; SLUG DYNAMICS; ENTRAINED AIR; PERFORMANCE; ESP; SIMULATION; FRACTION,"Gas entrainment is frequently encountered in electrical submersible pumps (ESP). When occurring, ESP suffers from moderate to severe performance degradation accompanied by unstable operations, depending on the inlet gas volumetric fraction (GVF) and pump rotational speed. The resulted pressure surging and instabilities may cause pump vibrations and short run-life. For a better design of ESP-based production system, the mechanistic model is needed to predict its performance under gas-liquid flow conditions. Similar to multiphase pipe flow, the flow pattern identification and classification inside a rotating ESP is important. In this paper, a new mechanistic model is proposed, which can map different flow patterns inside ESP with gas presence. Experimental results reveal that the boosting pressure of ESP degrades as GVF increases. With ESP's H-Q performance curves obtained, the flow patterns including dispersed bubble flow, bubbly flow, intermittent flow and segregated flow can be identified by deflection points on H-Q curves (Gamboa and Prado, 2008). The transition boundaries between different flow patterns are mapped. Starting from the free body diagram on a stable bubble in the rotating flow field, the transition boundaries of dispersed bubble flow to bubbly flow and bubbly flow to intermittent flow are formulated. Based on the combined momentum equation, the transition criterion of intermittent flow to segregated flow is derived. The flow pattern map predicted by mechanistic model agrees well with that detected from the experimental H-Q curves of ESP under gassy flow conditions.",5,5,0
Overpressure,,"Zhang, Tianjiao; Zhang, Shanwen; Meng, Wei; Feng, Yuelin; An, Tianxia",Characteristics and genetic mechanism of carbonate cements in sandstones near the overpressure top surface: A case study of the Niuzhuang Depression in Bohai Bay Basin,Overpressure top surface; Carbonate cements; Carbon and oxygen isotope; Overpressured fluid; Sandstone reservoir,PORE-PRESSURE; RESERVOIR SANDSTONES; DIAGENETIC HISTORY; SHAHEJIE FORMATION; PART 1; ORIGIN; PETROLEUM; FIELD; COMPACTION; EVOLUTION,"Carbonate cements are important authigenic minerals in the sandstone reservoir near the overpressure top surface in the Niuzhuang Depression. However, their genetic mechanism has not been studied in detail. This study uses observations of casting thin sections and cathodoluminescence and micro-area electron probe compositional data to determine that the diagenetic sequence of these carbonate cements is penecontemporaneous dolomite -> calcite filling primary pores -> calcite/iron-bearing calcite filling secondary dissolution pores -> ankerite. The genetic mechanisms of these carbonate cements are analyzed based on the fluid inclusion temperature at different phases of carbonate cementation, carbon and oxygen isotope composition, simulation of the thermal evolution of the hydrocarbon source rock, and elemental chemical composition. Results show that the carbon isotopic compositions of the carbonate cements are affected not only by organic acids released during the maturation of organic matter but also by the dissolution of lacustrine carbonate rock in the fourth member of the Shahejie Formation. Dissolution-reprecipitation of the lacustrine carbonate rocks is responsible for an obvious positive drift in the delta C-13(PDB) values of carbonate cements near the overpressure top surface. There are four phases of carbonate cementation near the top surface of the overpressured zone, with phase IV carbonate cements mainly occurring near the overpressure top surface. Phase I carbonate cements are mainly dolomite, and their formation is related to the decomposition of organic matter by methanogenic bacteria. Phase II carbonate cements are related to Ca2+ and CO32- supersaturation during pore fluid concentration. Phase III carbonate cements result from overpressured fluid that is rich in Ca2+ and Mg2+ and feldspar dissolution caused by overpressure fluid intrusion. Phase IV carbonate cements are derived from CO32- formed by organic acid pyrolysis in late diagenesis, CO32- formed by early carbonate cement dissolution, and Mg2+ and Fe2+ plasma formed by the dissolution of metamorphic rock debris into pore fluid. The formation of phase III and IV carbonate cements is most affected by overpressured hydrocarbon fluids.",1,4,4
Overpressure,,"Feng, Yuelin; Liu, Hua; Song, Guoqi; Yuan, Feifei; Li, Jun; Jiang, Ziyue",Relationship between decreased pressure gradient and reservoir filling degree of paleogene in Bonan Sag,Overpressure; Decreased pressure gradient; Reservoir filling degree; Bonan sag,BOHAI BAY BASIN; SAND-SHALE SEQUENCE; LATERAL FLUID-FLOW; PORE-PRESSURE; HYDROCARBON MIGRATION; ABNORMAL PRESSURE; OVERPRESSURE; PETROLEUM; ORIGIN; RECOGNITION,"Overpressure plays an important role in oil and gas migration. Decreased pressure gradient, as a characterization of overpressure, refers to the variation range of pressure per unit distance and has great significance for studying the dynamic composition and mechanism of oil and gas migration in the process of hydrocarbon migration. To quantitatively identify the relation between overpressure and hydrocarbon accumulation, this study uses the Es3 Formation in Bonan Sag as an example. The pressure distribution characteristics, the plane decreased pressure gradient characteristics, and their relationship with reservoir filling degree are analyzed using the measured pressure and predicted pressure, combined with the calculation of decreased pressure gradient and reservoir filling degree. Results show that the pressure coefficient of the Es3 Formation in Bonan Sag reaches up to 1.85, the decreased pressure gradient on the plane exhibits heterogeneity, and the decreased pressure gradient of the deep sub-sag belt is the highest, reaching a maximum of 12.1 MPa/km, followed by steep slope and steep fault belts. The gentle slope belt has the lowest decreased pressure gradient of less than 4.4 MPa/km. The corresponding relationship between decreased pressure gradient and reservoir filling degree is different in the four structure belts. The deep sub-sag belt is bounded by the decreased pressure gradient of 9.7 MPa/km. When the decreased pressure gradient is less than 9.7 MPa/km, the reservoir filling degree increases with an increase in the decreased pressure gradient. When the decreased pressure gradient is greater than 9.7 MPa/km, the reservoir filling degree decreases with an increase in the decreased pressure gradient. The corresponding relationship in the steep fault belt is opposite that of the deep sub-sag belt. When the decreased pressure gradient is greater than 4 MPa/km, the reservoir filling degree decreases with a decrease in the decreased pressure gradient, whereas the relationship between the decreased pressure gradient and the reservoir filling degree is weak in the gentle slope belt.",3,3,1
Overpressure,,"Wang, Xiao; He, Sheng; Jones, Stuart J.; Yang, Rui; Wei, Ajuan; Liu, Changhai; Liu, Qiang; Cheng, Chunyang; Liu, Weimin","Overpressure and its positive effect in deep sandstone reservoir quality of Bozhong Depression, offshore Bohai Bay Basin, China",Overpressure; Reservoir quality; Bohai Bay Basin; Shahejie formation; Dongying formation,ANOMALOUSLY HIGH-POROSITY; EFFECTIVE STRESS; NORTH-SEA; SKAGERRAK FORMATION; PORE-PRESSURE; CENTRAL GRABEN; DIAGENESIS; PRESERVATION; PREDICTION; COMPACTION,"Bohai Bay Basin is a Meso-Cenozoic terrestrial sedimentary basin in eastern China. Its offshore regions, including Bozhong and Liaodongwan Depressions, are favourable exploration targets which provide near a half of the petroleum reserves in the basin. Eocene Shahejie (Es) Formation and Oligocene Dongying (Ed) Formations are two important exploration targets in Bozhong Depression, and overpressure is commonly seen in Es and Ed Formations in this area. Our research examined the distribution characteristics of overpressure in the formations and suggest the main mechanism of overpressure is compaction disequilibrium due to the rapid sedimentation rates (similar to 500 m/Ma) of fine-grained sediments in this area. Also, oil and gas generation within the thick mudstones of the two formations has added the magnitude of overpressure. We investigated the reservoir quality especially primary porosity in Es and Ed formations, and their relationship with overpressure. The positive effect of overpressure on reservoir porosity preservation was validated through microscopic observations and vertical effective stress (VES) analysis. We established a quantitative model for evaluating the relationship of overpressure, pore structures, porosity, and VES. The result suggests the overpressure in the targeted formations were primarily originated from undercompaction. The overpressure kept VES from increasing and helped preserve the primary intergranular porosity. The porosity preserved by overpressure can be significantly higher than normally compacted porosity under the same condition of depth and temperature.",5,6,2
Other topics ,,"Umar, Bappah A.; Gholami, Raoof; Downey, William S.; Shah, Afroz A.; Nayak, Prasanta",A novel approach to determine across-fault leakage in CO2 reservoirs,Faults; Column heights; Wettability; Seal; Leakage; CO2,NIGER-DELTA; ORGANIC-MATTER; CONTACT-ANGLE; SEAL ANALYSIS; GOUGE RATIO; STORAGE; WETTABILITY; PRESSURE; TEMPERATURE; ROCKS,"A novel approach to determine across-fault leakage (capillary leakage) in CO2 reservoirs is presented using hybrid modeling. In this approach, two algorithms (Yielding's and Schowalter's) were concurrently used to modeled fault surfaces which removes wettability effect and greatly increased confidence in capillary leakage determination. Here, the Yielding's algorithm was mainly used to discriminate between the individual mineral compositions (based on clay content) of the fault zone, while the Schowalter's algorithm which incorporates wettability values was used to delineate potential leakage areas on the fault surfaces. Wettability values for the dominant mineral constituents for each of the fault zones (Cataclasite zone - quartz, Phyllosilicate zone feldspars & mica, and Clays/Shale smears zone - mica/kaolinite) were selected and modeled based on the percentage of clay content. The results obtained shows reductions in the computed CO2 column heights. This suggests that the proposed approach is a better option for CO(2)A leakage prediction.",0,0,0
Other topics ,,"Quillo, Gustavo Lunardon; Lass, Carolina Vieira; Corazza, Marcos Lucio; Fontana, Eliton; de Lima Luz, Luiz Fernando, Jr.",A concise chemical kinetics algorithm for carbonated brine injection in carbonate reservoirs,Carbonate; Dissolution; Carbonated water injection; Porous medium; Segregated solver; Chemical equilibrium,AQUEOUS-SOLUTIONS; REACTIVE-TRANSPORT; ACTIVITY-COEFFICIENTS; SODIUM-CHLORIDE; SOLUBILITY; DIOXIDE; MODEL; WATER; TEMPERATURES; DISSOLUTION,"A single-cell segregated solver for calculating the behavior of carbonated brine injection in carbonate rocks aiming at carbon geological storage is presented. The approach is designed to represent an element in computational fluid dynamics simulations and enhance customization to include dissolution chemistry by integrating a CO2 solubility model, speciation calculations, mineral dissolution reactions and the consequent change in reservoir properties over time. The equilibrium and dissolution reactions are calculated sequentially, where an adaptive control of the time step ensures that the dissolution rate is computed from the correct equilibrium condition. A pseudo-homogeneous medium represents the reservoir, where alterations in rock structure are computed via a formulation based on Kozeny-Carman. Finally, a stabilization algorithm based on the Bjerrum plot of H2CO3 provides numerical robustness for the speciation calculations. The results can estimate the time frame for the system to reach equilibrium and the corresponding changes in rock structure. The solubility model was validated against experimental data, while the speciation model was compared to more rigorous thermodynamics models such as electrolyte-NRTL and Pitzer, showing minor differences. The algorithm as a whole provides similar results for the pH when compared to a state-of-the-art single-cell model with an extensive chemical system for a real reservoir, proving it can be a viable option for numerical simulations.",0,0,0
Other topics ,,"D'Ottaviano, F.; Patil, P. D.",On the design of stimulation trials in the oil field: A power analysis of intervention studies,,,"An all too often question when designing field trials aimed at the validation of EOR techniques is how long the stimulation should last. In these trials, the stimulation period is proportional to the trial variable cost, hence the question related to period of trial execution. This article uses statistical power analysis to answer such a question. It demonstrates how statistical power of a trial design plays out as a function of its variables: total trial duration, its proportion under stimulation, the magnitude of the stimulation effect, and the level of variability and autocorrelation typically found in well production data.",0,0,0
Other topics ,,"Marefat, H. Ali; Aghdam, Muhammad A. Ashjari; Lie, Knut-Andreas",Preserving vorticity improves the accuracy of multiscale solvers,Vorticity preservation theory; Adaptive grid; Unstructured grid; Multiscale simulation; Restriction-smoothed basis,FINITE-ELEMENT-METHOD; SMOOTHED BASIS METHOD; ELLIPTIC PROBLEMS; UNSTRUCTURED GRIDS; VOLUME METHOD; FLOW; MEDIA; SIMULATION; GENERATION,"Within reservoir management, there is a growing demand for highly accurate and fast reservoir simulators. So-called multiscale methods are designed to preserve fine-scale information accurately in an accelerated coarse-scale computation of fluid flow. In many cases, this requires that coarse partitions are meticulously adapted to prominent geological features that determine flow paths. Partitions that seek to preserve the vorticity from a representative fine-scale flow simulation can be particularly effective to this end. We describe how to incorporate such partitions in the state-of-the-art multiscale restriction-smoothed basis (MsRSB) method, and present a series of two-phase test cases to validate and demonstrate the effectiveness of the resulting method. Our results show that using a nonuniform vorticity-based partition improves the accuracy of the MsRSB solver compared with uniform partitions and nonuniform partitions with a similar number of coarse blocks that adapt to permeability or velocity.",0,0,0
Other topics ,,"Preux, C.; Malinouskaya, I",Reservoir simulation model calibration methodology with polymer flooding based on laboratory experiments,polymer flooding; Simulation; Mobility reduction,FLOW; INJECTIVITY; CHAIN,"Due to its high apparent viscosity, polymer is considered as an alternative to water as injection fluid in hydrocarbon reservoirs. The mobility of the water-polymer mixture is much smaller than that of water alone, which helps prevent undesirable viscous fingering. Nevertheless, the selection of a polymer process involves a procedure for assessing the performance of the polymer in terms of mobility reduction. This procedure involves laboratory experiments in which the pressure losses are measured during polymer displacement, as well as during water displacement. In the next step of the procedure, a model is calibrated by simulation in order to predict the efficiency of the polymer. Although the polymer models traditionally used at this stage are relatively simple, their calibration from the results of the laboratory tests is much more intricate, insofar as the mobility reduction generated by the polymer depends not only on the concentration but also on the temperature, the salinity and the shear rate. In this paper, we put forward a new approach to this multivariate problem and propose a rigorous calibration methodology which allows for a fast physical representativity, thus limiting the number of laboratory experiments. This methodology is the subject of a pending patent application (FR 18/58547).",0,0,0
Other topics ,,"Gonzalez, Shayane Paes; Martins, Jorge Leonardo; Franco, Daniel R.",Evaluation of consolidation parameter data trendings and comparison between prediction models for well-log velocities: A case study from the Namorado Oilfield (southern Brazil),Well-log velocities; Consolidation parameter; Turbidict reservoir; Campos basin,WAVE VELOCITIES; SEDIMENTS; POROSITY; AVO,"The compressional and shear-wave velocities (V-P and V-S) have been used in studies for hydrocarbon exploration over the last decades. Nevertheless, the absence of S-wave velocity records in geophysical surveys is common. In this work, we applied the iterative method proposed by Lee (2006), which allows evaluations of P- and S-wave velocities by estimates of the consolidation parameter alpha. We use well-log datasets from a turbiditic reservoir at Namorado Oilfield (Campos Basin, southeastern Brazil) to test this methodology. Results were further compared to a well-established empirical model (Greenberg and Castagna, 1992). We verified a good agreement for V-S results provided by both methods, and a consistent correspondence between the measured V-P and those calculated by the Lee (2006) method. It was also possible to assume the reliability of the alpha values, although the presence of denser lithologies may produce local artifacts, which affect V-P(alpha) and V-S(alpha) estimates. Furthermore, the results for alpha, V-P(alpha) and V-S(alpha) pointed to: (i) an upward trending for V-P/V-S ratio values, for profile NA-01, that indicate a possible hydrocarbon-filling zone; (ii) the presence of two distinctive alpha data groupings with respect to porosity, which are clearly influenced by the involved type of lithologies; and (iii) the absence of a straightforward relationship between alpha and porosity under pressure conditions.",0,0,0
Other topics ,,"Pehlivanturk, Can; Chen, Dongmei; Ashok, Pradeepkumar; van Oort, Eric",Path advisory for slide drilling using a nonlinear wellbore propagation model and genetic algorithm,Directional drilling; Path optimization; Advisory software,DESIGN,"Directional drilling is a complex operation that is difficult to execute with precision and repeatability. It is challenging to accurately model and predict the results of drilling actions, which leaves much to directional drillers experience. To reduce the impact of uncertainties on the drilling actions and to improve drilling efficiency, an automatic computational framework is proposed for directional drilling to optimize the drilling path and associated actions to drill this path. The proposed framework has low computational overhead and is suitable for real-time application. The framework consists of a nonlinear wellbore propagation model coupled with a genetic algorithm (GA). Using this framework, optimal drilling actions are found automatically with the intent of maximizing the value of the well. A new well path propagation model is developed that maintains an optimal trade off between modeling accuracy and computational overhead. For orientation, a quaternion formulation is used instead of the industry standard Euler angles to avoid singularity problems. The well path optimization problem is formulated by defining suitable cost functions including functions representing production loss, wellbore quality, drilling time, completion cost, and state and input constraints that represent the physical limitations of the directional drilling system. Using this approach, the solution space has trillions of candidate well paths, which makes an exhaustive search impractical for real-time directional drilling advisory and control. In order to address this issue, a GA methodology is applied. Solving the optimization problem generates sets of drilling instructions (e.g slide and rotate instructions for downhole motor drilling) that can be applied to drill practically optimal wells that maximize the value of the well. For most cases, a solution is found in under a minute. Even though the solution could be a local optimal since the optimization problem is non-convex, the optimization framework shows excellent practical results when applied to actual field cases.",0,0,1
Other topics ,,"Li, Chaochun; Ou, Chenghua","Technical recoverable volume quality evaluation of the offshore faulted block oilfields, determined by two-level fuzzy hierarchy technique",Offshore faulted block oilfield (OFBO); Technical recoverable volume quality (TRVQ); Two-level evaluation index system; Two-level fuzzy hierarchy evaluation method; Laminaria oilfield; Liujianfang oilfield,OIL-FIELD; GAS; BASIN; MODEL; ACCUMULATION; RESTORATION; SIMULATION; FRACTURES; SYSTEM; WATER,"Offshore faulted block oilfields with considerable technical development risks are frequently encountered in offshore oilfield exploitation. This paper proposes a two-level fuzzy hierarchy technique for an integrated evaluation of the technical development risk of offshore faulted block oilfields. The proposed technique can classify the technical recoverable volume quality according to the characteristics of offshore faulted block oilfields. It includes a two-level evaluation index and a two-level fuzzy hierarchy evaluation method. We conducted a thorough evaluation of the proposed technique, using actual offshore faulted block oilfields in Australia and China. The results verified the reliability and applicability of the proposed technique.",0,0,2
Other topics ,,"Zhou, Ming; Yi, RongJun; Gu, Yinhua; Zou, Jiaxi; Guo, Xiao",Characterization and evaluation of synthesized ammonia triethyl amide (ATEA) for removing sodium chloride deposition,Ammonia triethyl amide; Sodium chloride; Removing salt deposition; Synthesis; Characterization; Synergy effect,LATTICE ENERGY; NITRILOTRIACETAMIDE; STABILITY; ACID,"Ammonia triethyl amide (ATEA) was synthesized by a new facile one-step method using chloroacetamide and ammonia as raw materials, and its structure was characterized by FTIR and (HNMR)-H-1. TGA showed that the decomposition temperature of compounds was about 110 degrees C, which had good thermal stability. Its performance of inhibiting salt deposition was evaluated and the mechanism of salt inhibition was analyzed systematically. On the one hand, the optimal concentration of ATEA was 10 kg/m(3) and the dispersion rate at this concentration was 79.6%. XRD and SEM analysis confirmed that the structure of NaCl crystal was not changed, but it had a tendency to grow into star-shaped crystal. On the other hand, with the increase of aging time and temperature, the solubilization rate decreased, and with the increase of pH value, the solubilization rate increased first and then decreased. At a concentration of 10 kg/m(3), the solubilization rate was 6.58% after aging 16 days, was 6.35% when pH = 10 and was 5.43% at 95 degrees C. The maximum dispersion rate (88.35%) and the maximum solubilization rate (10.38%) were achieved when the mass concentration ratio of ammonia triethyl amide to potassium ferrocyanide were 6:4 and 7:3, respectively. The experimental results showed that ammonia triethyl amide had good synergy effect with potassium ferrocyanide for removing sodium chloride deposition.",0,0,2
Other topics ,,"Emetere, M. E.",Modified satellite remote sensing technique for hydrocarbon deposit detection,Hydrocarbon deposits; Remote sensing technique; Algorithms; Thermal analysis,MODEL,"Recently, significant reserves of oil were discovered off the coast of Lagos State, southwest Nigeria. The lateral situation or compositions of the oil-bearing deposits is not clear because these findings are based on a particular position of a single well. The conventional methods of oil exploration have shown a fundamental theoretical shortcoming that may not be resolved, hence scientists or professionals may have to keep modifying the theories to explore different geological terrain. In this study, the remote sensing technique was adopted. The dataset were adopted from MERRA, Landsat 8 OLI and ETM imagery. The temperature distributions (soil and geothermal temperature) over the research area were calculated using existing algorithms to compliment the satellite remote sensing results. A prospective hydrocarbon deposits was suggested for further research work.",0,0,2
Other topics ,,"Aarsnes, Ulf Jakob F.; van de Wouw, Nathan",Effect of shock subs on self-excited vibrations in drilling systems,Drill-string vibrations; Stick-slip; Distributed parameter systems; Infinite dimensional systems; Stability; Hyperbolic systems,STICK-SLIP; DYNAMICS; MODEL; BIT; DELAY,"The present paper studies the effect of an axial elastic tool (known as a shock sub), mounted downhole in the drill-string, on the occurrence of axial and torsional self-excited vibrations. In particular, we evaluate the feasibility of stabilizing the axial dynamics, dominated by a bilateral (feedback) coupling between the bit-rock interaction and the drill-string wave-equations, through the insertion of a passive down-hole tool. We consider the problem of unwanted drill-string vibrations and explain how these vibrations relate to the so-called axial instability using a distributed parameter (infinite dimensional) model. The equations describing the feedback system causing this instability are derived and then extended to accommodate for the inclusion of the effect of the shock sub. Conditions for the design parameters of the shock sub needed to avoid axial instability are then derived and their practical feasibility are considered.",0,0,4
Other topics ,,"Bao, Xitao; Yan, Yifei; Wang, Peng; Yang, Jiang; Yan, Xiangzhen; Li, Shunchu",Characteristics of the pressure and pressure derivative response of the CBM well based on the outer boundary condition with parallel faults,CBM; Seepage model; Parallel faults; Similar constructive method; Well testing analysis curves,COALBED METHANE,"In general conditions, there are faults developing in CBM (coalbed methane) reservoirs. Because the faults affect the dynamic response of the pressure and pressure derivative of gas-oil wells, research examining the pressure and pressure derivative response of CBM wells has become a difficult problem. The methods to solve seepage models of CBM reservoirs are also numerous and complicated. In this paper, a seepage model of CBM reservoir with an outer boundary condition of parallel faults is studied using both the CBM seepage model with infinite outer boundary and the mirror solution (the solution of the image well) of the CBM seepage model on parallel faults via the superposition principle. First, a seepage model of CBM with infinite outer boundary is built and solved by the Similar Constructive Method. Next, using the mirror reflection principle, the mirror solution of the CBM model on the parallel fault boundary is obtained. Finally, using the superposition principle of the mirror solution and similar structure solution of the CBM seepage model with infinite outer boundary, the solution of the CBM seepage model with the parallel fault boundary condition is obtained. After Laplace inversion, the diagnostic curves of log-log curve, semilog curve, Primary Pressure Derivative (PPD) curve and Second Logarithmic Pressure Derivative (SLPD) curve of the model are drawn. Next, the characteristics of the pressure and pressure derivative response of the CBM well are obtained based on the boundary conditions with three types of parallel faults. The solution method to solve the CBM seepage model can reduce the threshold and difficulty of the model solution. Four types of model diagnostic curves can replenish the diagnostic tools of the effect of the parallel fault boundary on the CBM well to analyze the effect of the parameters of the parallel fault boundary on the wellbore pressure and pressure derivative of CBM wells.",1,1,0
Other topics ,,"Jiang, Haiyan; Zatcepin, Vladislav; Liu, Wenqiang; Yuan, Shibao; Zhao, Liming; Wang, Boyi",Feasibility analysis of a droppable igniter for in-situ combustion,In-situ combustion; Igniter; Artificial ignition; Solid fuel; Droppable,,"The ignition technology is the key of in-situ combustion, which determines the start of in-situ combustion. This paper proposes a droppable solid fuel igniter for in-situ combustion based on the principle of traditional igniter, which aims to design a droppable solid fuel igniter and demonstrate the feasibility of the igniter. The droppable solid fuel igniter can not only guarantee ignition efficiency, but also avoid the pressure fluctuation caused by lifting artificial igniter in recovery process. Firstly, the structure and fuel of the igniter are designed. Industrial solid fuel with hexamethylenetetramine and multipurpose solid fuel with gangue can both meet the ignition requirements of heat and structure. Then, the feasibility of the igniter is studied by oxidation kinetics and thermodynamics formulas. Finally, the applicable conditions of the igniter are obtained by sensitivity analysis. The results show that the reservoir thickness is the key factor if the igniter length is no more than 20 m. This igniter has strong feasibility if the reservoir thickness is less than 12.8 m, but ignition temperature and initial layer temperature should be considered if reservoir thickness is larger than 12.8 m. In theory, the droppable solid fuel igniter can be used in artificial ignition under certain conditions.",1,1,0
Other topics ,,"Sun, Yanbin; Liu, Zhibin; Dong, Xiaoxu",Rate optimization of fractional flow reservoir model based on the continuous adjoint method,Continuous adjoint approach; Fractional flow reservoir model; Production optimization; Adjoint simulation,,"In this paper, continuous adjoint method is applied to research the rate optimization of fractional flow reservoir model. The continuous adjoint equations are derived by the variational theory and the stable numerical schemes of adjoint equations are obtained through numerical methods. Firstly, the continuous adjoint equations are linear equations and evolve from the end simulation time. The convection velocity direction of the continuous adjoint saturation equation is opposite to the convection direction of the saturation equation. Secondly, the total simulation time has significant impact on the adjoint variables and the adjoint gradient. After water breakthrough in production well, the adjoint variables exhibit spatial variety that gradually changes from production well to injection well. With this observation, we find that this variety is related to the fractional flow function and its derivative value. The sharp change of fractional flow function and its derivative at the end of the simulation time can lead to large fluctuation of the adjoint gradient along the time step. Thirdly, the influence of time interval on optimization results is studied. Increasing the number of time steps will increase the optimal value, but the value of the difference between optimal and initial value will not increase significantly. When the variable number of time steps is adopted, this difference decreases as the number of time steps increases, which indicates that the coarse time step optimization can provide a better initial control value for the fine time step optimization. An adaptive time step from coarse step to fine step is thus recommended for optimization.",1,1,0
Other topics ,,"Apio, Andressa; Dambros, Jonathan W., V; Farenzena, Marcelo; Trierweiler, Jorge O.",Comparison of Kalman filter-based approaches for permanent downhole gauge pressure estimation in offshore oil production,Permanent downhole gauge; Offshore oil production; Kalman filters; Soft sensor,MODEL-BASED CONTROL; DRIVEN SOFT SENSOR; DEEP-WATER; SYSTEMS; DESIGN; FLOW,"The permanent downhole gauge (PDG) pressure is the most important variable to describe the dynamics of an offshore oil well. Unfortunately, this measurement is often unavailable due to premature sensor failure and the considerable price for its replacement. An alternative to dealing with the lack of the PDG pressure measurement is its estimation. For this, Kalman filters are common tools, with which two distinct state estimators (extended and unscented Kalman filters) were proposed in the literature. These approaches have disadvantages related to the requirement for system linearization and the high computational cost, bringing the necessity for new techniques. In this work, five different Kalman filter-based approaches are tested and compared for the PDG pressure estimation. Through simulated and industrial data, the advantages and disadvantages of each filter are pointed. The results broadly show that the cubature Kalman filter returns the best estimation in the industrial case study, in which the model was properly adjusted. Meanwhile, the extended filters have the best performance in the simulated scenarios, considering that the model was not properly adjusted. In addition, the estimation using a single measurement that is highly correlated to the PDG pressure is enough for its estimation.",1,1,0
Other topics ,,"Dieguez-Elizondo, Pedro M.; O'Donohoe, Paul G.; Gil-Lopez, Tomas; Castejon-Navas, Juan; Galvez-Huerta, Miguel A.",Calculation methods of Radon-222 radiological activity for NORM plant with ventilation,Oil; Radon gas; Isotope; Radioactive pollution; Waste disposal,NATURAL RADIATION-EXPOSURE; BUILDING-MATERIALS; RADON EXHALATION; DELAY CHAMBER; EMANATION; RADIOACTIVITY; MITIGATION; HOUSES; THORON; ENTRY,"A procedure is proposed to determine the radiological activity of air present in the working area of a NORM (Naturally-Occurring Radioactive Materials) plant. This NORM plant is located in the United Arab Emirates and is dedicated to the recycling of material and equipment used in oil extraction facilities. Substantial quantities of NORM waste will be present inside the enclosed plant facilities and will exhale significant amounts of Radon-222 into the working environment. The continued inhalation of this gas and its progeny has been shown to cause lung cancer. In order to reduce the concentration level of the aforementioned gas to an acceptable regulatory value, the best solution is by means of mechanical ventilation. The two calculation methods used to analysis the relationship between the ventilation rate and the degree of radioactive contamination are considered. The first being ventilation by perfect dilution, commonly employed in industrial environments with radiological contamination. The second method of analysis is by means of a CFD (Computational Fluid Dynamics) which permits a more precise calculation of the required fresh air quantity and spatial concentrations. Validation was carried out in a small experimental plant space, obtaining results reasonable approximate to those predicted by the computational analysis. The similarities and differences between the respective calculation methods and their respective fields of application are analyzed. It is concluded that for lower air change rates, less than five air changes per hour, the CFD analysis is the most appropriate method. By contrast, when using a higher rate of outside air changes in the plant, the perfect dilution method should be sufficient enough to control the presence of radon and its progeny. Both calculation methods consider the activity of radon and the activity of the most significant radioisotopes of its progeny.",1,1,0
Other topics ,,"Sun, Shiyuan; Meng, Fandong; Yan, Hongfei; Wang, Longyan",Research on HLCO entering the secondary riser of FDFCC unit to improve light aromatics production,FCC; Double riser; Light aromatics; Diesel oil recycle; Hydrofining; FCC; Double riser; Light aromatics; Diesel oil recycle; Hydrofining,,"In the context of prolific chemical raw materials, the flexible dual-riser fluid catalytic cracking (FDFCC) was put forward to increase the yield of light aromatics, in which hydrofining light cycle oil (HLCO) was processed in the second riser under high temperature. The process not only meets the increasing demand for aromatics, but also solves the problem of high aromatics content (more than 50 wt%) of FCC gasoline, which is difficult to meet increasingly stringent gasoline standards. The results of the pilot experiment showed that the optimization reaction temperature of the secondary riser of the FDFCC unit was 575 degrees C, and the content of aromatics in cracked gasoline reached 78 wt% or more. It should be noted that light cycle oil (LCO) should be subjected to deep hydrogenation from the perspective of increasing aromatics production.",1,3,1
Other topics ,,"Nolansnyder, Daniel R.; Parnell, John",Comparative pore surface area in primary and secondary porosity in sandstones,Sandstone; Porosity; Secondary porosity; Pore surface area; Reservoir; Deep biosphere,IMAGE-ANALYSIS; RESERVOIR; DISSOLUTION; PREDICTION; DIAGENESIS; BACTERIA; SEDIMENT; SYSTEMS; GRAIN; OIL,"Primary and secondary porosity in sandstones possess different pore geometry characteristics, but these are not well quantified. The pore surface area in 2 suites of sandstones exhibiting only primary porosity (Permo-Triassic, Northern Ireland) and only secondary porosity (Cambrian, England) were measured using JMicrovision software. The data show pore surface areas per unit pore volume similar to 2.5 times as great in the secondary porosity compared to the primary porosity. This difference is great enough to have a significant impact on properties dependent on pore surface area, including oil production and capacity for microbial colonization in the deep biosphere.",1,1,1
Other topics ,,"Jiang, Han; Daigle, Hugh",Effects of fluids removal and thermal maturation on permeability and pore structure of organic-rich shale: Results from pyrolysis experiments,Organic shale; Permeability; Porosity; Pyrolysis; Maturation,GAS-ADSORPTION; SURFACE-AREA; POROSITY; MULTISCALE; EVOLUTION; TRANSPORT,"Laboratory measurements to determine petrophysical properties such as permeability are critical for shale reservoir characterization. Here we investigate effects of fluids removal and thermal maturation on permeability and pore structure of organic-rich shale. Mature and organic-rich shale samples were pyrolyzed at four temperature levels (110 degrees C, 250 degrees C, 450 degrees C, >= 600 degrees C), and performed nitrogen gas sorption and GRI (Gas Research Institute) permeability measurements after each heating level. Our results show that the measured porosity, permeability and pore structure are sensitive to the pyrolysis temperature. Surface area, N-2 pore volume, GRI porosity and permeability increased as temperature increased, due to a combination of progressive loss of volatiles with increasing temperature and artificially induced thermal maturation at high temperatures. The correlation between gas adsorption and GRI results implies the multiscale pore network features of the samples, wherein a certain fraction of small pores could be partially or completely disconnected from the overall structure. Our work provides insights on useful information about the effects of fluids removal and thermal maturation for sample preparation procedures on laboratory measurements.",1,1,1
Other topics ,,"Liu, Keman; Zhang, Yinghao; Wang, Xiaoxin",Applications of bootstrap method for drilling site noise analysis and evaluation,Drilling site noise; Electromagnetic measurement while drilling (EM-MWD); Drilling; The noise characteristics; Bootstrap method,OIL; CANCELLATION; TELEMETRY,"In order to evaluate the influence of well site noise on MWD telemetry system more accurately and effectively, this paper develops an efficient noise acquisition system to acquire the drilling site noise, which consists of low-noise coupling transformer, low noise preamplifier and tunable filter, usb6259 acquisition card, computer and other components. Although, most methods can be used to estimate noise statistical characteristics and model based on large samples, the Bootstrap method is a computer method, which only requires very little in the way of modelling or analysis noise. Through electromagnetic noise examples from an operating oil field, located near Northwest of China, we demonstrate the drilling site noise data with different drill rigs and in different drill operations were analyzed based on the Bootstrap method and Welch's method. The trial result shows that (i) the system can work easily for the well-site electromagnetic noise real-time acquisition, signal processing and analysis, display and storage; (ii) the power spectral density of well site noise were strongly dependent on the noise which is generated by the industrial equipment operating and drilling conditions in the well site and (iii) the maximum kurtosis of drilling site noise of Electro-Mechanical Drilling Rig is 7.437, which indicate it is not Gauss distribution, but super-Gauss distribution. The findings of our work can help for better understanding of characteristics of drilling site noise. Furthermore, the Bootstrap method is a powerful tool for analysis and evaluation drilling site noise with low cost, and can solve the problem that the practical drilling process data can not be obtained repeatedly. The results can be used to improve MWD, EM-MWD and LWD system designs and optimization studies.",1,1,2
Other topics ,,"Fu, Deliang; Zhou, Shixin; Ma, Yu; Li, Jing; Xu, Guosheng; Tian, Tao; Yang, Fu","Petroleum accumulation history of Nanbaxian belt - Study of gas generation and fluid phase, northern margin of Qaidam Basin, West of China",Type II; Kerogen; hydrocarbon kinetics; Phase behaviour; CO2; Nanbaxian petroleum field,CARBON-DIOXIDE; ASPHALTENE PRECIPITATION; PHYSICAL-PROPERTIES; TARANAKI BASIN; OIL; BEHAVIOR; MIGRATION; SHALE; RESERVOIR; SIMULATION,"To study the phase evolution and the fluid accumulation history of Nanbaxian petroleum field, in this study, a series of anhydrous closed-system gold-tube thermal simulation experiments have been performed on a carbonaceous mudstone (type II kerogen) from the northern margin of the Qaidam Basin in the Xiaomeigou Formation (J(1x)). The hydrocarbon generation kinetics research was used to simulate the gas generation history of Yiliping depression, and the phase characteristics of the evolution were analysed by PVTsim. The influence of kerogen generated CO2 on the fluid phase was discussed that CO2 has a significant influence on the fluid phase at low maturity stage that the fluid phase could be a gas phase under geological condition. As a result, the fluid was migrated to Lower Ganchaigou Formation as gas phase, in the early stage of hydrocarbon accumulation. The fluid phase was gradually transformed into oil phase with the CO2 loss and accumulated as primary reservoir. With the increase of the maturity, the effect of CO2 on the fluid phase gradually decrease. During the Shizigou Formation depression, the tectonic action and the hydrocarbon generated from Yiliping depression led to the evaporation fractionation of the primary reservoir and the gas washing which cause the reconstructed of the primary reservoir in Lower Ganchaigou Formation and form of the secondary reservoir in Shizigou Formation.",1,1,2
Other topics ,,"Li, Hanyong; Chen, Jiaqing; Wang, Jiaqing; Gong, Jing; Yu, Bo",An improved design method for compact vertical separator combined with the theoretical method and numerical simulation,Compact vertical separator; Population balance model (PBM); Volume of fluid (VOF); Droplet sedimentation velocity calculatio model; Droplet diameter,MONTE-CARLO-SIMULATION; BREAKAGE; MODEL,"Hydrocyclone is mostly used in high efficiency and compact separators to simplify the process flow, and reduce the occupied area and weight of separation equipments. However, the separation outer cylinder size is determined by the traditional Stokes law and the size of traditional droplets, the calculation result would be bigger than expected. So, a new improved design method is put forward in this paper. Firstly, the theoretical calculation is conducted on the effective diameter of the dispersed phase oil droplets according to the droplet coalescence principle and the population balance equation (PBE), and then the numerical simulation verification of multiple load cases is conducted on the two possible maximum particle sizes of the oil droplets by means of the VOF multiphase flow model. Then the floating velocity of oil droplets can be obtained by the droplet sedimentation velocity calculation model, and finally, the size of the outer cylinder of the compact vertical separator can be determined. This method can greatly reduce the size of the outer cylinder of the separator and realize the compactness of the overall structure of the separator. The feasibility of the structure and the reliability of the separation effect have also been verified by field tests.",1,2,3
Other topics ,,"Strand, Geir-Ove; Corina, Anisa Noor",On risk control in the well plug and abandonment phase: The case of the Norwegian Continental Shelf,Probabilistic risk assessment; Plug and abandonment; Well safety; Offshore wells,PORTLAND-CEMENT PASTE; METHANE EMISSIONS; ZONAL ISOLATION; NORTH-SEA; WATER; OIL; DISCOVERY; INTEGRITY; SEEPAGE; FAILURE,"Numerous oil and gas wells in the North Sea are now reaching their end of productive life. The main challenges at the end of the well life phase are: (i) how to recover the remaining resources, and (ii) how to plug and abandon (P&A) the wells and associated structures in a cost-efficient way. Well P&A operations could according to a study contribute with up to 25% of the total costs of exploration wells in the North Sea. The long-term sealing capability will also be a critical factor because of substantial costs of potentially having to re-enter a leaking wellbore. Probabilistic risk assessments (PRA) will be key in identification of optimal P&A solutions. The use of PRA in cost and risk control of well systems are not new, however, the amount of research, guidelines and frameworks proposed for PRA of long-term well P&A concepts remain scarce. A literature search revealed only a few methods proposed that may be of some direct relevance to PRA. Most of the available literature is related to leakage risk modelling associated with CO2 capture and storage, which as such may not be directly adoptable to North Sea exploration wells. In this article we: (i) identify and discuss key risk factors for developing a PRA modelling framework for well systems in the P&A phase on the Norwegian Continental Shelf (NCS), and (ii) based on Weibull statistics and a strongest link argument, propose a novel modelling approach to PRA within this framework.",1,1,4
Other topics ,,"Golubev, Ye A.; Martirosyan, O., V; Kuzmin, D., V; Isaenko, S. I.; Makeev, B. A.; Antonets, I., V; Utkin, A. A.",Transformations of natural bitumens of different degrees of metamorphism at a low vacuum heating in the temperature range of 400-1000 degrees C,Natural solid bitumens; Thermal transformations; IR spectroscopy; Raman spectroscopy; Microscopy,RAMAN-SPECTROSCOPY; GLASSY-CARBON; SHUNGITE; GRAPHITIZATION; GRAPHITE; GENESIS,"The results of studying the structural and chemical transformations of natural bitumens of different degrees of metamorphism under heating at a low vacuum (similar to 8 kPa) in the temperature range 400-1000 degrees C are presented. Reducing of the size of supermolecular particles during heating was recorded. A sequent step-by-step transformation of the graphite-like phase in bitumen structure up to shungite stage according Raman spectra characteristics is shown. The samples acquire electrical conductivity through eliminating the hydrocarbon component, before their graphite-like structure of carbon was ordered up to the stage of the higher anthraxolite.",2,2,0
Other topics ,,"Faraji, Foad; Ugwu, Johnson Obunwa; Nabhani, Farhad; Chong, Perk Lin",Development of inflow performance model in high temperature gas-condensate reservoirs,Inflow performance relationship (IPR); Gas condensate reservoirs; Viscosity; Two phase compressibility factor; Analytical condensate well IPR; Pressure build up test,VISCOSITY; PRODUCTIVITY; DENSITY,"Inflow Performance Relationships (IPRs) are important element for reservoir engineers in the design of new wells and also for monitoring and optimizing existing wells. IPRs are used to determine optimum production of gas rate and condensate rate in a well for any specified value of average reservoir pressure and predict the performance. Jokhio and Tiab proposed a simple method of establishing IPR for gas condensate wells. The method uses transient pressure test data to estimate effective permeability as a function of pressure. Effective permeability data used to convert production bottomhole flow pressure into pseudopressure to establish well performance. Despite the effectiveness of the method, single phase correlations were used in PVT calculations of each phase, which over simplified the fluid flow in gas condensate wells. Single phase dry gas equations do not reflect the multiphase flow behaviour of gas condensate wells below the dew point. Due to this limitation Jokhio and Tiab method modified by this study and new analytical IPRs for gas condensate well proposed. The major improvement of the above method is incorporating new viscosity correlation developed by this study and using two-phase compressibility factor as key parameters for predicting gas condensate inflow performance. Therefore, the main contribution of this study is development of viscosity correlation which is a critical issue in predicting gas condensate inflow performance both above and below the dew point. Optimization techniques and nonlinear regression used to develop a new viscosity correlation for high temperature heavy gas condensate reservoirs under depletion. The application of the new model is illustrated with field example for current IPR curves. Compositional simulation study of the well performed in PIPSIM simulator. The proposal approach provides reasonable estimates of simulator input reservoir properties (e.g. IPRs). Accuracy of the new method compared with compositional simulation study. The proposed method presents average absolute relative deviation (AARD) of 5.8% for gas IPR and 7.5% for condensate IPR compare to compositional simulation results. New method provides a tool for quick estimation of gas condensate wells without need of relative permeability curves and expensive and time consuming compositional simulation.",2,2,0
Other topics ,,"Singh, Yogesh B.; Ng, Kim C.",Elucidation of dual-mode inhibition mechanism of a typical polymer-based antiscalant on Red seawater for thermal desalination at higher temperatures and higher concentration factors,Antiscalant; Scales; Inhibition; Seawater desalination; Threshold; Crystal modification,SCALE FORMATION; HEAT-EXCHANGER; FOULING MITIGATION; DEPOSITION; ENERGY; PRECIPITATION; EFFICIENCY; MSF,"Scale deposition in the thermal process for desalination is quite inevitable. This study is about scale formation, crystal modification, and prevention mechanism of a tetrapolymer based antiscalant on Red Seawater. Red seawater at concentration factors (CF) of 1.5 and 2.5 was studied under reflux condition at 70 degrees C and 98 degrees C respectively for seven hours with 1 ppm, 2 ppm, and 4 ppm concentration of the antiscalant. Eventually, the mechanism of inhibitory action of the antiscalant has been reconnoitered after seawater analysis and imaging the morphological changes in the crystal formation patterns with Scanning electron microscope (SEM). The changes in the values of pH, turbidity and alkalinity (both phenolphthalein alkalinity (PA) and total alkalinity (TA)) were measured to apprehend various fluctuations happening as a result of the addition of antiscalant. The variations in the pH of seawater with antiscalant were in concurrence with the changes in alkalinity and was also reflected in turbidity. These changes explicitly demonstrated the threshold mechanism of scale inhibition. SEM micrographs exhibited distorted round shaped depositions supporting crystal modification mechanism as well. The efficiency and dominance of inhibitory mechanism varied from 2 h to 6 h for the antiscalant and was observed to be directly related to CF of seawater used, the temperature applied, and a dose of antiscalant added.",2,2,0
Other topics ,,"Chen, Gang; Fan, Yiren; Li, Quanxin",A study of Coalbed Methane (CBM) reservoir boundary detections based on azimuth electromagnetic waves,Boundary detection; LWD (logging while drilling); Azimuth resistivity; Numerical simulation,,"In this research, a coal-gangue-rock geological model based on geological parameters was established by studying the relationships between different dielectric constants, conductivity and attenuation coefficients, and emission frequencies when electromagnetic waves were propagated in a medium. The effects of the electromagnetic wave energy attenuations on coal-rock interfaces under different electrical parameters, and the variations in boundary reflection energy under different lithological interface conditions were examined. Also, the influences of the coal gangue interlayers on the boundary detections, as well as the theoretical conditions and basis for electromagnetic wave detections at coal-rock interfaces were obtained. On the aforementioned basis, the parameters design method of azimuth electromagnetic wave resistivity logging tool while drilling were proposed. Then, the applicability potential of the proposed electromagnetic wave coal-rock interface identification method was examined. This research content included the influences of the measuring response signals on the instrument itself under different source distances, transmitting frequencies, and coil installation angles. Also, an external influence analysis of the instrument's distance to formation boundaries and the formation resistivity contrasts were studied in detail. The boundary response characteristics of the electromagnetic wave signals under different coil structures and instrument parameters were obtained using numerical simulations. Furthermore, under the many constraint conditions, the basis for selecting the parameters of the instruments which were suitable for underground coal mines was put forward.",2,3,0
Other topics ,,"Olesen, Kristian B.; Fogang, Lionel T.; Palm-Henriksen, Gustav; Alyafei, Nayef; Solling, Theis, I","How a range of metal ions influence the interfacial tension of n-decane/carboxylic acid/water systems: The impact of concentration, molecular- and electronic structure",IFT; Interfaces; Pendent drop; Surfactant,IN-OIL EMULSIONS; WATER-INTERFACE; SURFACE-TENSION; ACIDS; STABILIZATION; SALTS,"The data from more than 700 pendant droplet interfacial tension (IFT) measurements has been scrutinized to reveal the relation between salinity/surfactant structure and IFT in a brine - decane/carboxylic acid system. The large number of measurements enabled an experimental uncertainty of around 1% in the IFT range around 30 mN/m. Thus, small changes and trends in IFT as a function of salinity and surfactant structure become apparent. Five carboxylic acids are chosen to resemble natural naphthenic acids; individually, they only differ by a CH2-group starting from cyclohexane carboxylic acid and ranging to 5-cyclohexyl pentanoic acid. The salt concentration was varied from 0.01 M to 1.0 M for a range of chlorides of monovalent and divalent metal cations: LiCl, NaCl, KCl, MgCl2, CaCl2, SrCl2, BaCl2, and ZnCl2. For Na+, NaBr, NaI, were also investigated. The variation in IFT with salinity and carboxylic acid is subtle with divalent ions, not surprisingly, inducing larger IFT changes than monovalent ones when the concentration is varied. Zn2+ gives rise to a surprisingly large IFT reduction (up to 7.5 IFT units in the range from 0.01M to 1.0 M) and clearly stands out as a special case. For the three smallest chain acids the IFT increases as a function of salinity whereas, for the system involving the two largest ones, 4-cyclohexyl butanoic acid and 5-cyclohexyl pentanoic acid, IFT decreases as a function of salinity. The distinct behavior of Zn2+ and the sudden crossover in the variation of IFT as a function of salinity when increasing the chain length of the carboxylic acid is taken to indicate that structure of both the (solvated) electrolyte and the carboxylic acid-particularly with regard to the orientation at the interface -are important factors in determining the magnitude and variation in IFT as a function of physical parameters.",2,2,0
Other topics ,,"Male, Frank",Assessing impact of uncertainties in decline curve analysis through hindcasting,,GAS-PRODUCTION; SHALE; FALLACY,"This study attempts to characterize the uncertainties in production forecasting for unconventional gas wells through hindcasting. The analysis focuses on how results from decline analyses change as the well population ages. The study is based on publicly available and subscription-based production data on 34,000 shale gas wells in the Marcellus, Fayetteville, Haynesville and Barnett plays. A hindcasting analysis was performed on wells, where production has been forecast using a physics-based decline curve analysis. This allows the accuracy of decline methods to be tested and the nature of errors to be assessed. Based on this analysis, the study identified systematic and random errors that impact estimates of ultimate recovery. Fields where few wells have entered boundary-dominated flow show higher uncertainty for field-wide production forecasts. Uncertainty decreases as more production history is accumulated. The physics-based approach for decline curve analysis is shown to be robust through hindcast analysis. The uncertainty in per-well recoveries for the fields studied are in the range 4-8%. The uncertainty in field-wide average ultimate recovery is less than 4% for three of the fields and 5.6% for the Marcellus. Understanding the sources and magnitudes of errors and uncertainties in estimated ultimate recovery values for unconventional gas wells allows operators to account for these in determining economic outcomes and performing financial planning of wells.",2,2,0
Other topics ,,"de Andrade, Alex R.; Borges, Raiane A.; Guilherme, Hellen C. M.; Pinto, Jose C.; Nele, Marcio",A new loss circulation control strategy combining a cross-linkable polymer and magnetic fluid,Loss of circulation control; Magnetorheological fluid; Cross-linked polymer,,"This work aims to evaluate a new loss of circulation control mechanism combining a smart fluid based on a mixture of a cross-linkable polymer (PVA) solution and magnetic microparticles. This new technology joins the benefits from magnetorheological fluids and cross-linked polymer gels. Magnetorheological fluids (MRF) containing iron particles in different sizes and concentrations were tested as carriers for the cross-linkable polymer. An empirical model with two parameters was also built to formulate MRF compositions able to have a yield stress that minimizes the fluid loss into reservoir. The results showed that MRF rheological properties could be fine-tuned by manipulating the diameter of the iron particles and particle fractions. Different cross-linkers were tested, chromium (III) acetate was the most adequate for PVA crosslinking reaction carried out in the presence of iron particles and under magnetic field. The results demonstrated that a mixture of magnetic particles and crosslinkable polymers has potential application for loss of circulation control.",2,2,2
Other topics ,,"Yu, Yunliang; Niu, Wenqing; Yang, Guang; Niu, Mingxuan; Ma, Shanshan; Tian, Liya","Mechanisms for the accumulation of deep gas in the southern Songliao Basin, China",CO2; CH4; Natural gas reservoir; Volcanic rock; Diffusion coefficient; Songliao basin,GEOCHEMISTRY; AREA; DEPRESSION; RESERVOIR; ROCKS,"The Lower Cretaceous Yingcheng Formation in the southern Songliao Basin contains inorganic CO2, hydrocarbon, and mixed-gas reservoirs and is overlain by Denglouku Formation sandstone hosting secondary hydrocarbon gas reservoirs. We measured the diffusion coefficients of CH4 and CO2 in volcanic rock samples collected from five wells in the Yingcheng Formation. Our results show that the diffusion coefficient of CH4 is greater than that of CO2. Following the accumulation of hydrocarbon gas in the Yingcheng Formation, the region was affected by movement along deep-seated faults, resulting in the upward migration of mantle-derived inorganic CO2 into hydrocarbon gas reservoirs in volcanic rocks of the Yingcheng Formation, displacing pre-existing hydrocarbon gas. The hydrocarbon gas was transported upward into Denglouku Formation sandstone (which has favorable physical properties for gas storage) and was then enriched to form secondary gas reservoirs.",2,2,4
Other topics ,,"Sharma, P.; Salman, M.; Reza, Z.; Kabir, C. S.",Probing the roots of Arps hyperbolic relation and assessing variable-drive mechanisms for improved DCA,Arps DCA & pressure buildup are similar; Theoretical basis for Arps; Obtain b-factor objectively; Arps applies to transient & BDF periods; Shut-in periods need collapsing,DECLINE-CURVE ANALYSIS; RESERVES,"This paper explores the relationship between the natural form of pressure buildup/ falloff response to Arps hyperbolic formula in conventional reservoir systems. The primary motivation stems from the fact that semianalytical proof exists for obtaining average-reservoir pressure from either pressure buildup or falloff response with the rectangular hyperbola method (RHM), whereas the Arps hyperbolic relation is anchored in empiricism. Despite its origin, the hyperbolic relationship has served the industry very well in performance predictions under diverse reservoir-drive mechanisms since its inception in 1945. Most reserves estimation in conventional reservoirs is anchored in Arps decline-curve analysis (DCA) to meet regulatory guidelines. We show that the Arps hyperbolic parameters b and D can be estimated from the RHM, thereby giving credence to its basis. Note that the RH method is a semianalytical proof of pressure-buildup/ falloff relation. We also show that Arps hyperbolic parameter b is tied to the energy support available for production and can be estimated using a type curve instead of the parameter-regression approach. Besides, we point out that well shutin periods need to be collapsed to obtain valid b and D parameters; otherwise, optimistic b values are estimated, leading to performance overprediction. Synthetic examples verified the approach presented here, and several field examples with diverse b-factors validated the overall methodology as espoused here.",3,3,0
Other topics ,,"de Sousa, Matias C.; de Figueiredo, Jose J. S.; da Silva, Carolina B.; Nascimento, Murillo J. de S.",Prediction of S-wave velocity by a hybrid model based on the Greenberg-Castagna equation,Shear wave velocity; Empirical relations; Fluid substitution; Well logs,FLUID SUBSTITUTION; SHEAR; ROCKS; LOGS,"In geophysics, more specifically in rock physics and petrophysics, empirical equations play an important role in data regularization, especially in datasets that are difficult to acquire in situ. In terms of well logging, a common scenario is the absence of shear wave slowness data, which can be handled by different methods that aim filling data gaps (regularization). This work consists of the application of a hybrid approach (based on Greenberg-Castagna method) to estimate S-wave velocity in brine-saturated lithologies on well-log datasets. The combination of local polynomial regressions with a fluid substitution analysis (Gassmann's equation) leads to an effective method of estimating shear wave velocity (V-S) from compressional wave velocity (V-P) when information about lithology and saturation are available. Well-log datasets (from the Norwegian Sea region) are used to demonstrate the feasibility of our methodology and show its usefulness for dataset regularization based on the local information. We selected learning and test wells from the Norne Field, where Lower to Middle Jurassic sandstones behave as hydrocarbon reservoirs. Our results show that the best fitting between the measured and predicted S-wave velocities were obtained from the modified Greenberg-Castagna method (in this work, named calibrated relation), also verified on a well from the North Viking Graben (validation dataset).",3,3,0
Other topics ,,"Alyaev, Sergey; Suter, Erich; Bratvold, Reider Brumer; Hong, Aojie; Luo, Xiaodong; Fossum, Kristian",A decision support system for multi-target geosteering,Geosteering; Sequential decision; Dynamic programming; Statistical inversion; Well placement decision; Multi-objective optimization,MODEL; OPTIMIZATION; UNCERTAINTY; FILTER,"Geosteering is a sequential decision process under uncertainty. The goal of geosteering is to maximize the expected value of the well, which should be defined by an objective value-function for each operation. In this paper we present a real-time decision support system (DSS) for geosteering that aims to approximate the uncertainty in the geological interpretation with an ensemble of geomodel realizations. As the drilling operation progresses, the ensemble Kalman filter is used to sequentially update the realizations using the measurements from real-time logging while drilling. At every decision point a discrete dynamic programming algorithm computes all potential well trajectories for the entire drilling operation and the corresponding value of the well for each realization. Then, the DSS considers all immediate alternatives (continue/steer/stop) and chooses the one that gives the best predicted value across the realizations. This approach works for a variety of objectives and constraints and suggests reproducible decisions under uncertainty. Moreover, it has real-time performance. The system is tested on synthetic cases in a layer-cake geological environment where the target layer should be selected dynamically based on the prior (pre-drill) model and the electromagnetic observations received while drilling. The numerical closed-loop simulation experiments demonstrate the ability of the DSS to perform successful geosteering and landing of a well for different geological configurations of drilling targets. Furthermore, the DSS allows to adjust and re-weight the objectives, making the DSS useful before fully-automated geosteering becomes reality.",3,3,0
Other topics ,,"Prakasa, Bona; Muradov, Khafiz; Davies, David","Linear and radial flow modelling of a waterflooded, stratified, non-communicating reservoir developed with downhole, flow control completions",Intelligent wells; Fractional flow; Autonomous inflow control device; Smart completion; Inflow control device,,"Forecasts of the performance of waterflooded oil-field have been prepared for many years using fractional flow models, such as those by (Buckley-Leverett, 1942) (BL), (Welge, 1952) and (Dykstra-Parsons, 1950) (DP), to estimate the vertical sweep efficiency between wells. These methods, and their later modifications, formed the theoretical basis for designing a water-flooded oil-field. Advanced Well Completions (AWC) incorporating downhole flow control device (FCD) technology have become a proven method for modifying a production well's inflow profile, delaying water breakthrough, improving sweep efficiency and enhancing recovery. This manuscript extends the fractional flow model describing the performance of a waterflooded, stratified-reservoir with an AWC installed in the production well. The piston-like behaviour of the water-front described by previous, semi-analytical models is extended here to the linear and radial flow modelling of more realistic displacement profiles. This paper describes the theoretical basis and application workflow along with several case studies illustrating their performance and value. The accuracy of the new, semi-analytical models are verified by comparison against the results from a numerical reservoir simulator. Model limitations and possible future extension are also discussed. The workflow can be implemented as either a production forecast or a diagnostic tool for an AWC well in a waterflooded oil-field. It provides one missing link between today's AWC design workflows and the long-term value evaluation of a specific AWC design when a commercial numerical simulation software is either not available or too time consuming.",3,3,0
Other topics ,,"Rahman, Rashnur M.; Awoleke, Obadare O.; Goddard, Scott D.",Meta-analysis of propped fracture conductivity data-fixed effects regression modeling,Fracture conductivity; Statistical analysis of pooled data; Regression modeling,,"Previous empirical models of propped fracture conductivity are based either on data sourced from single investigations or on data not in the public domain. In this work, statistically rigorous models of propped fracture conductivity are developed using a database of fracture conductivity experiments reported in technical literature over the last 40 years. The database contains about 2700 data points. Propped fracture conductivity is the dependent variable and proppant type, mesh size, proppant concentration, formation hardness, closure stress, formation temperature, and polymer concentration are the independent variables. The full, original database was pared down to various subsets, each having complete information in relation to some subset of the independent variables. The number of independent variables included in each of the resulting databases varied from three to six. Seventy percent of the data was used to develop the models while thirty percent of the data was used to validate them. Fixed effect models were selected using all subsets regression analysis in three, four, and five experimental factors for each of two types of proppant. The five factor model appeared to be the most useful model for both proppant types from a predictive point of view. Five-factor model predictions also compared favorably with an existing propped fracture conductivity model and different case histories published in literature. This project provides engineers with access to a propped fracture conductivity database based on experiments reported over the past 40 years in technical literature. The models developed based on this database can be used to generate predictions of propped fracture conductivity for a variety of proppant characteristics and formation conditions. Also, the models presented here are based on data from experimental investigations in different laboratories, potentially reducing biases that may be present in single laboratory investigations.",3,3,0
Other topics ,,"Ani, Maureen; Oluyemi, Gbenga; Petrovski, Andrei; Rezaei-Gomari, Sina",Ranking of geostatistical models and uncertainty quantification using Signal Detection Principle (SDP),Reservoir simulation; Multiple realizations; Model ranking; Uncertainty quantification; Signal-to-noise ratio; Dissimilarity measure,,"The selection of an optimal model from a set of multiple realizations for dynamic reservoir modelling and production forecasts has been a persistent issue for reservoir modelers and decision makers. Current evidence has shown that many presumably good reservoir models which originally matched the true historic data did not always perform well in predicting the future of the reservoir as a result of uncertainties. In this paper, a new method for optimal model selection using Signal Detection Principle (SDP) approach is presented. In principle, SDP approach models the dissimilarity between various realizations as a cross-function of spatial distance, statistical correlation and the inherent noise level in the model; while the existing methods estimate the dissimilarity between parameter values of different realizations as a function of distance (statistical or spatial distance) or quality factor. SDP approach fills the model divergence gap by way of classifying the information-bearing patterns in a model as signals, and identifying random patterns which bears no information as noise. Thus, it quantifies the mismatch uncertainty and the inherent fudge in every realization as a measure of the model's reliability. The SDP approach has been validated with historical data, and the results show that the reliability factor of the best model has a value of one. Thus, if the strongest reservoir model has a reliability factor of one, then that model will make approximately the closest and best predictions as the true system in every forecast; whereas if the reliability factor of the model is less than or greater than one, its predictions will always disperse from historical data and is unsuitable for reservoir forecasts. Two examples based on real field data are used to demonstrate the application of SDP approach. In these case examples SDP was used to analyse the difference between the reservoir models in a set of multiple realizations. The target variable in this study was STOIIP (Stock Tank Oil Initially in Place). The results show that the models with a lower reliability factor made similar predictions as the real reservoir data in almost all the forecasts. Similarly, the models with higher reliability factors made dissimilar and more unreliable predictions in most of the forecasts.",3,3,0
Other topics ,,"Shabib-Asl, A.; Plaksina, T.",Selection of decline curve analysis model using Akaike information criterion for unconventional reservoirs,DCA; Information theory; Model selection; Shale wells; Data analytics; Data analysis,,"Petroleum production from unconventional resources (specifically, tight and shale reservoirs) has become a significant portion of the supply in North America which led operating companies to look for more accurate methods for reserve evaluation and production forecasting. Typically, the operators resort to Decline Curve Analysis (DCA) to determine the Estimated Ultimate Recovery (EUR) of hydrocarbon reserves in both conventional and unconventional reservoirs. In shale wells, the best DCA model fitted to the transient flow regimes followed by Boundary Dominated Flow (BDF). Therefore, in this study, we propose a novel framework for systematic DCA model selection using a quantitative measure of goodness of production data fit from shale wells. For this purpose, we selected seven different, most frequently applied DCA models to evaluate large number of wells from the Montney Formation. To collect production data from the Montney wells, we used the GeoSCOUT package. Then, we fed these data into the DCA model selection workflow powered by the Nelder-Mead simplex algorithm and implemented using a computer programming language. The quantitative measure that helps identify the best fit of the data and the model is derived from the Information Theory (IT) and is known as Akaike Information Criterion (AIC). The obtained results show that our DCA model selection framework can identify the most appropriate DCA model for a given production history. Moreover, it gives a specific quantitative measure (AIC) of the fit that can be used for model ranking. The results show that more accurate values of b are necessary in Arps' DCA models to match production data from the Montney shale wells, and identify the Logistic Growth Analysis Model (LGM) is the best fit for the majority of the selected wells followed by Extended Exponential Decline Model (EED), Duong, and Power Law Exponential Model (PLE).",3,3,1
Other topics ,,"Kim, Joonyi; Kang, Byeongcheol; Jeong, Hoonyoung; Choe, Jonggeun",Field development optimization using a cooperative micro-particle swarm optimization with parameter integration schemes,Field development optimization; Drilling time; Well conversion; Cooperative micro-particle swarm optimization (COMPSO); Parameterization,WELL PLACEMENT OPTIMIZATION; JOINT OPTIMIZATION; PARTICLE SWARM; ALGORITHM; UNCERTAINTY,"Non-gradient-based methods can be efficient to find optimal solutions for discrete decision variables of oil field development such as drilling schedule, number of wells, well locations, well types and its conversion times, and operational settings. Particle swarm optimization (PSO), which is a population-based stochastic global search method, has gained considerable popularity in optimization because it has simple and fast search using the speed of a few particles. However, its application to optimal oil field development is still computationally challenging due to many wells, reservoir heterogeneity, discrete variables, and nonlinear constraints. In this study, we introduce cooperative micro-particle swarm optimization (COMPSO), which will enhance the optimization efficiency of PSO for high-dimensional and complex problems by breaking a high-dimensional problem into low-dimensional subcomponents and using a small number of populations. We also propose an advanced parameterization of the decision variables for the efficient optimization of field development. A large 2-dimensional (2D) synthetic field and the 3D PUNQ-S3 benchmark model are used to demonstrate the efficiency of COMPSO and our parameterization schemes. The proposed method shows faster convergence and higher net present value (NPV) solutions than PSO. In the two examples, COMPSO only requires 39% and 16% of reservoir simulation runs to reach the same NPV compared with PSO, respectively. Our parameterization schemes additionally save 56% and 18% of the number of reservoir flow simulations of the COMPSO in the two examples, respectively.",3,3,1
Other topics ,,"Wang, Xingming; Yao, Xingmiao; Hu, Guangmin; Chen, Ping",Drag reduction performance of an axial oscillating tool with different kinds of waveform using a multiscale friction model,Vibration technology; Drag reduction performance; Axial oscillation tool; Multiscale friction model; Waveforms,COILED-TUBING FRICTION; REDUCING TECHNOLOGIES; PLASTIC CONTACT; WELLS; DAHL,"Axial oscillating tools (AOT) are among the most widely used mechanical drag reduction technologies in the drilling field due to their environmental friendliness and ease of use. There are various waveforms of axial oscillating tools because of the differences in their structure and mechanism. However, only the sinusoidal wave is adopted to analyze the performance of axial oscillating tools. This paper widely investigated the types and applications of axial oscillating tools and summarized the idealized waveforms of these tools, which are sinusoidal, triangle, and trapezoid waveforms. To analyze the performance of these waveforms, a multiscale friction model was adopted based on the Dahl model according to the drilling environment. The model was verified using experimental data. The simulation results demonstrated that the magnitude of negative velocity could influence the performance of drag reduction. The greater the negative velocity, the better the performances of drag reduction achieved. For triangle and trapezoidal waves, the time ratio and magnitude of positive displacement in a period did not remarkably affect the performance of drag reduction for certain amplitudes and frequencies. According to the simulation results, when the time ratio of negative velocity was greater than (2/pi)(2), the drag reduction performance of the triangle and trapezoidal waveforms were better than that of the sinusoidal wave. These conclusions can be of benefit for the design of axial oscillating tools to obtain a more efficient performance of drag reduction.",3,3,2
Other topics ,,"Liu, Yiqian; Wang, Chaoyang; Cai, Jingbo; Lu, Hao; Huang, Liaoyun; Yang, Qiang",Pilot application of a novel Gas-Liquid separator on offshore platforms,Offshore platform; Natural gas; Liquid separation; Pilot test,,"Existing devices available on offshore gas/oil platforms are incapable of realizing complete separation of the liquid phase from wet natural gas. This results in eccentric motion of rotors and eventually causes trouble halting of natural-gas compressors. To tackle this problem, use of a novel gas-liquid separator has been reported for offshore oil platform applications. A pilot scale test was performed using the proposed equipment. Results of the test demonstrate that the optimum operating point of the pilot plant corresponds to a flow rate of 90m(3)/h (30 degrees C, 5.0 MPa), and this could be used as a reference for subsequent industrial scale-ups. The results of the pilot test lead to the conclusion that the said novel separator has higher separation efficiency when compared against conventional industrial devices used on oil platforms. Using of the proposed equipment is aimed at alleviating the problem of liquid entrainment of natural gas entering the compressor, increasing compressor service life, and reducing operational and maintenance costs. The proposed study provides a new outlook towards engineering design of offshore-oil-platform equipment of theoretical as well as practical value.",3,3,2
Other topics ,,"Zhao, Jun; Yuan, Songshan; Li, Wei; Ji, Yuqiang; Liu, Kai",Numerical simulation and correction of electric logging under the condition of oil-based mud invasion,Oil-based mud; Numerical simulation; Mud invasion; Resistivity correction,RESERVOIR; LOG,"When high-resistivity oil-based mud infiltrates a permeable formation, the resistivity obtained from logging measurements will increase over time, which affects the accuracy of logging interpretation. The invasion of oil-based mud is affected mainly by the formation's physical properties, pressure difference and invasion time. To improve accuracy of interpretation, it is necessary to correct the resistivity of the formation. In this article, we analyzed the effects of formation physical properties, pressure difference on oil-based mud invasion by a numerical simulation method. And then we simulated the radial distribution of formation resistivity when the oil-based mud invaded the water layer, gas-water layer, and gas layer. Finally, by inverting the true resistivity of the formation, we developed a resistivity correction chart to correct the formation resistivity.",3,3,2
Other topics ,,"Silva, Mario; Stray, Helge; Bjornstad, Tor",Stability assessment of PITT tracer candidate compounds - The case of pyrazines,Partitioning tracers; Inter-well; New compounds; Pyrazines; Stability; Residual oil saturation,GAS CHROMATOGRAPHY-OLFACTOMETRY; COORDINATION POLYMERS; POTENT ODORANTS; ASCORBIC-ACID; FLAVOR; KAOLINITE; ACTIVATION; ADSORPTION; VOLATILES; STATE,"The determination of the residual oil saturation (S-OR) in the volumes swept between injector/producer well pairs is a parameter of major importance for the design and/or evaluation of IOR projects. The number of IOR projects is increasing with the growing number of mature oilfields. The partitioning inter-well tracer test (PITT) is used to measure SOR in waterflooded reservoirs and relies on the use of partitioning and passive tracers. Many PITT were unsuccessful in the past due to a poor knowledge about the compounds used as tracers and to date, very few compounds were developed for this application. New partitioning tracers are needed, and a systematic qualification process is necessary to reduce the risk of costly unsuccessful field tests. In the present document we report and discuss the findings from stability experiments performed on 2 alkylpyrazines, 1 methoxypyrazine, and 2 halogenated pyrazines under investigation for use as oil/water partitioning tracers for determination of the SOR in the inter-well region of water flooded oil reservoirs. The stability of 2,3-dimethylpyrazine, 2,6-dimethylpyrazine, 2-methoxypyrazine, 2-chloropyrazine, and 2-fluoropyrazine in brine solutions was evaluated in batch experiments at temperatures ranging from 25 degrees C to 150 degrees C for 12 weeks, at 3 different pH values and in the presence of typical oil reservoir rock materials (sand-stone, carbonate rock, and clay). Results suggest that 2,3-dimethylpyrazine and 2,6-dimethylpyrazine possess the required stability and absence of significant interaction with the rock substrates. 2-chloropyrazine and 2-fluoropyrazine degrade with a temperature and pH dependent rate but are not influenced by the rock materials. 2-methoxypyrazine exhibits temperature dependent degradation in the absence of any rock substrate and in the presence of sandstone and carbonate rock. A strong interaction was observed between this compound and the clay material (kaolinite) which is responsible for dramatically increasing its degradation rate.",3,3,3
Other topics ,,"Mu, Liang; Ramlov, Hans; Sogaard, T. Max M.; Jorgensen, Thomas; de Jongh, Willem A.; von Solms, Nicolas",Inhibition of methane hydrate nucleation and growth by an antifreeze protein,Hydrate nucleation; Inhibition; Antifreeze protein; Environment friendly,KINETIC INHIBITION; DECOMPOSITION; MECHANISM; CRYSTALS; MEMORY,"Antifreeze proteins (AFPs) are characterized by their ability to protect organisms from subfreezing temperatures. They constitute a class of promising candidates as environmentally kinetic hydrate inhibitors (KHIs). In this study, the effectiveness of an insect cell expressed novel monomeric streptavidin fusion protein version of Rhagium mordax RmAFP1 antifreeze protein (mSA-RmAFP1), and four amino acids (histidine, lysine, tyrosine and proline), on CH4 hydrate nucleation, growth and decomposition was investigated using a rocking cell apparatus, then compared with the commercial inhibitors Polyvinylpyrrolidone (PVP) and Luvicap Bio. It was found that CH4 hydrate nucleation and growth exhibited good repeatable results under experimental conditions. The results showed that 2250 ppm mSA-RmAFP1 can inhibit CH4 hydrate nucleation as effectively as PVP at the same concentration. The histidine, lysine, tyrosine and proline exhibited weak inhibition effect on CH4 hydrate nucleation. The mSA-RmAFP1 decreased CH4 hydrate growth rate and production in the fresh and memory solutions. The CH4 hydrate formed in the solutions containing various tested KHIs present slightly lower onset decomposition temperatures than the non-inhibited system under experimental conditions. The promising performance of the insect cell expressed mSA-RmAFP1 could promote the further development of green hydrate inhibitors. The production of this protein through insect cell line fermentation provides a platform for the future production and optimization of AFPs for hydrate inhibition.",3,3,4
Other topics ,,"Ganjeh-Ghazvini, Mostafa",The impact of viscosity contrast on the error of heterogeneity loss in upscaling of geological models,Heterogeneity loss analysis; Upscaling error; Fine grid model; Two-phase flow,DUAL MESH METHOD; FLOW; PERMEABILITY; SIMULATION,"Multiphase flow simulation is widely used to evaluate different production plans in petroleum engineering. In order to solve the flow equation efficiently, upscaling is applied to transform a fine grid geological model into a coarser one. The coarse model result, however, may be inaccurate due to heterogeneity loss, connectivity distortion and numerical dispersion. Each source of upscaling error has its own influential factors. Knowledge about these factors and error behavior is useful in design of appropriate sizes for coarse grid blocks. Although numerous methods have been developed for upscaling, few works may be found on the related error itself. This paper studies how a major source of upscaling error, heterogeneity loss, changes with viscosity contrast in water-oil displacement The fBm process is used to create very heterogeneous fine models that are upscaled by Renormalization method. For separating the effect of heterogeneity loss from numerical dispersion, refined upscaled models are derived. Water flooding is then simulated on fine and refined upscaled models at 3 different ratios of oil to water viscosity. For each ratio, a heterogeneity loss plot is prepared. This plot is a powerful tool for evaluating the performance of an upscaling method. The result shows the heterogeneity loss error heavily depends on viscosity contrast Moreover, the limit of coarsening is determined for each case and it is discussed why that limit is lower when water has higher viscosity than oil.",4,4,0
Other topics ,,"Hasan, Md Rifat; Reza, M. Toufiq",Hydrothermal deformation of Marcellus shale: Effects of subcritical water temperature and holding time on shale porosity and surface morphology,Hydrothermal fracking; Shale; Enhanced porosity; N-2 adsorption; SEM; BET,NORTHEASTERN BRITISH-COLUMBIA; MISSISSIPPIAN BARNETT SHALE; SUPERCRITICAL WATER; ORGANIC-MATTER; SPONTANEOUS IMBIBITION; GEOLOGICAL CONTROLS; PORE STRUCTURE; GAS SHALES; SYSTEMS; MATRIX,"Low porosity of Marcellus shale often limits the hydrocarbon recovery. To increase shale porosity, hydrothermal deformation (HTD) of Marcellus shale was performed and the effects of subcritical water temperature and reaction time on porosity were evaluated. HTD was performed at 200, 250 and 300 degrees C for one, three and 6h of residence time. Low-temperature N-2 adsorption was used for porosity measurement. Furthermore, the morphology of raw and HTD shale samples was analyzed with scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS), and X-ray diffraction analyzer (XRD). It was observed that shale porosity was significantly enhanced by HTD conditions. For instance, HTD at 300 degrees C for 6 h of residence time, shale porosity increased more than four times compared to raw shale. This porosity was attributed to leaching of calcite, clay and quartz, which is confirmed by analyzing HTD process liquids by Induced Coupled Plasma-Optical Emission Spectroscopy (ICP-OES).",4,5,0
Other topics ,,"Umar, Bappah A.; Gholami, Raoof; Nayak, Prasanta; Downey, William S.; Shah, Afroz A.","Normal fault geometrical trends and interactions in an onshore oilfield Niger Delta Basin, Nigeria",Normal faults; Segmentation; Growth models; Throw; Fault orientations; Interaction,RELAY RAMPS; GROWTH; DISPLACEMENT; NETWORK; LINKAGE; SLIP; DISTRIBUTIONS; DEFORMATION; PROPAGATION; SYSTEM,"Detailed structural analysis of an onshore field was carried out to study the geometry and interactions of the interpreted normal faults. The faults have E-W strike and are dipping towards the south. Majority of the faults are coherently linked with only a few displaying isolated growth model. Throw generally increases with increasing depth. The distribution of the throw on the fault planes shows different geometries ranging from symmetrical with steep gradients at the fault tips and displacement maxima at the center to asymmetrical with steep gradient at one tip. Faults interacted by way of splay and systematically formed relay ramp structures. At depth, splay display isolated fault profile rather than a maxima at the intersections suggesting an unusual interaction at intersection between major fault and splay with low displacement at intersection.",4,4,0
Other topics ,,"Al-Farhan, Mohanad; Oskooi, Behrooz; Ardestani, Vahid E.; Abedi, Maysam; Al-Khalidy, Amar",Magnetic and gravity signatures of the Kifl oil field in Iraq,Magnetic; Gravity; 3D inversion; Weighting matrix; TSVD; Kifl oil field,FAST INVERSION; 3-D INVERSION; BASIN; ANOMALIES; ZONE,"Potential field methods are capable to provide satisfactory results on the tectonics and geology, especially when dealing with the hydrocarbon reservoirs and ore-bearing mineralization. In this study, magnetic and gravity survey were conducted at the west of Kifl area in central Iraq to image the subsurface geological structure and consequently the characteristics of the oil and gas reservoirs. Ground measurements were conducted on an area of 16 by 24 km with a regular grid spacing of 250 m. The results clarified the tectonic setting of the study area, where the fault system in the Kifl oil field was recognized by resembling both magnetic and gravity anomalies with distinct trends along NS and NW. A 3D inversion algorithm based on a weighted minimum length solution was used for reconstruction of the subsurface physical properties of magnetic susceptibility and density contrast. Weighting matrix is composed of multiplication of compactness and depth weighting functions, and truncated singular value decomposition (TSVD) was used for regularization. 3D inversion was first applied to a synthetic model to simulate the geological reality of the study area, while satisfactory results were obtained. Implementing the algorithm on the real potential field data, the physical properties of the hydrocarbon reservoir were determined. Four cross sections have been extracted from the inversion result to show geometric characteristics (depth and shape) of the main reservoir in the Kefl oil field. The results indicated the presence of a fault system in the middle area within a column of sedimentary sequences represented as a graben-horst structure. This phenomenon in the area could be attributed to the tectonic deformation and tension over the area and the Eurasian and Arabian plates collided back to the Permian - Paleocene periods.",4,4,0
Other topics ,,"Zheng, Da; Wang, Wendong; Reza, Zulfiquar",Integrated pore-scale characterization of mercury injection/imbibition and isothermal adsorption/desorption experiments using dendroidal model for shales,Unconventional formation; Theoretical pore-network modeling; Pore-structure characterization; Adsorption/desorption,CONNECTIVITY; BEHAVIOR,"Distinct from conventional reservoirs, shale formations have limited pore connectivity and unique pore spatial-distributions. Consequently, theoretical pore-network models developed for conventional formations are not representative of the pore topology within unconventional rocks. This paper presents a theoretical pore-network model, dendroidal model, based on the analysis of reconstructed pore-scale model extracted from Scanning Electron Microscope images. Dendroidal model is a semi-acyclic model, which characterizes the poor connectivity of void space without sacrificing the interaction between main flow paths. Dendroidal model infers pore-body distribution based on the hysteresis effect of isothermal adsorption/desorption measurements and characterizes pore-throat distribution using mercury injection capillary pressure data. The use of dual-compressibility model in pore-network model construction eliminates the effect of compressibility of both void space and matrix. Total organic carbon (TOC) content and minerology determine the composition of pore bodies and pore throats. The difference in mercury intrusion and extraction caused by trapping hysteresis and contact-angle hysteresis affects the stochastically distributed parameters, including pore-throat length, pore-throat cross-sectional morphology, coordination number and pore-body spatial distribution. We used shale core samples from Marcellus and Wolfcamp formations to validate the dendroidal models by calculating the absolute permeability without slippage effect. This newly developed pore-network model integrates aforementioned seven distinct types of experimental data to capture the realistic pore structures within shales.",4,4,0
Other topics ,,"Asfora, Leonardo; dos Santos, Adriano; Nogueira Duarte, Lindemberg de Jesus",Modeling multiphase jet pumps for gas compression,Mathematical model; Numerical simulation; Multiphase jet pump; Ansys CFX,,"In order to minimize problems and enhance production, many oil-well applications using jet pumps associated with artificial lift systems have been suggested in the literature. In some scenarios, gas from the annulus can be beneficially compressed by using oil-well's production as power fluid. Because multiphase fluids are generally produced, understanding and modeling multiphase jet pumps for gas compression (MJPG) is essential for design applications. Considering homogeneous multiphase flow, a simplified model is proposed and analytical solutions are presented in this article. A detailed analysis of the proposed model is performed and its physical con- sequences are discussed. Very good agreement between the proposed model and the conducted 3D numerical simulations (Ansys CFX 16.0) was observed. Furthermore, in agreement with experimental results reported in the literature, the numerical results showed that the MJPG is highly influenced by mixing process in the throat. Finally, the numerical simulations showed that slippage hinders complete mixing in the throat and reduces pump's efficiency.",4,4,0
Other topics ,,"Malekimostaghim, Ehsan; Gholami, Raoof; Rezaee, Reza; Asef, Mohammad Reza; Zhong, Zhiqi; Sarmadivaleh, Mohammad",A laboratory-based approach to determine Archie's cementation factor for shale reservoirs,Shale; Water saturation; Cementation factor; Porosity; Resistivity,WATER SATURATION; LOG; CORE,"Although production from shale gas reservoirs has been significantly improved in recent years, petrophysical characterization of these unconventional formations is still facing difficulties. Fluid saturation is one of the major petrophysical properties of gas shale reservoirs which has been the subject of many studies. Shale mineralogy, pore structure, water absorption, clay swelling and low permeability are perhaps the main reasons behind the failure of many methods proposed to determine water saturation under these circumstances. The aim of this paper is to show how the cementation factor of Archie's equation can be properly determine for a better estimation of fluid saturation in shale gas reservoirs. A series of tests were conducted on the samples taken from the Carynginia formation of North Perth Basin in Western Australia. The results obtained indicated that the average cementation factor of the samples is around 1.6 which can provide a good estimation of water saturation on the field scale. It appeared that the confining pressure may reduce the porosity of the samples and should be considered when the cementation factor is calculated. It was concluded that Archie's equation can still be a valuable asset for determination of fluid saturation in unconventional reservoirs if the cementation factor is accurately determined.",4,4,1
Other topics ,,"Yang, Shubo; Qiao, Wenxiao; Che, Xiaohua; Ju, Xiaodong",Numerical simulation of acoustic reflection logging while drilling based on a cylindrical phased array acoustic receiver station,Phased array; Azimuth measurement; Scanning-reception; Numerical simulation; Acoustic reflection logging; Logging while drilling,ARC ARRAY; BOREHOLE; FIELD; WAVE,"With the increase of drilling activities, improving the azimuth measurement capability of acoustic logging while drilling (LWD) tools has been an urgent requirement for the petroleum exploration. In this study, a novel acoustic reflection LWD scheme is developed based on a cylindrical phased array (CPA) acoustic receiver station, which is composed of several arcuate phased array (APA) acoustic receiver stations arranged uniformly along the tool axis. The azimuthal performance of the APA and CPA acoustic receiver stations in acoustic reflection LWD with one or two formation interfaces away from the borehole are studied using the finite-difference time-domain method. The simulation results show that the amplitude distribution of reflected waves received by different azimuthal receiver elements is helpful for determining the azimuth angles of formation interfaces. Compared with the individual-reception mode, the azimuth measurement accuracy of the APA acoustic receiver station is greatly improved when working in the scanning-reception mode. Compared with the APA scanning-reception scheme, the CPA scanning-reception scheme performs better in simultaneously measuring the azimuth angles of two reflectors outside the borehole.",4,5,1
Other topics ,,"Goncalves Pereira, Caroline Eulino; da Cruz, Gabriel A.; Pereira Filho, Leonidas; Justino, Lorena R.; Paraiso, Eduardo C. H.; Rocha, Jose M.; Calcada, Luis A.; Scheid, Claudia M.",Experimental analysis of pressure drop in the flow of Newtonian fluid in coiled tubing,Experimental apparatus; Pressure drop; Coiled tubing; Water,LAMINAR,"In order to study the fluid flow in the coiled tubing system, an experimental unit with 376 m of wrapped copper tube with 1/2 in diameter, and similarity to an actual coiled tubing system was built. Pressure transmitters and thermocouples were installed in this unit to monitor pressure and temperature along tube length. Tests were carried out with water, Newtonian fluid, in the flow range between 0.05 and 0.65 m(3)/h, in order to predict pressure drop in each double layer and in the whole coiled tubing system. Flow rate and pressure drop data obtained in the experimental unit allowed the evaluation of critical Reynolds number, friction factor correlations in laminar and turbulent regime, and the influence of the curvature and tube length on pressure drop. A methodology for predicting pressure drop in the coiled tubing system was proposed and the percentage error between the experimental and calculated pressure drop values was less than 5%.",4,4,1
Other topics ,,"Gholampour, F.; Mandiyar, H.",A new correlation for relative permeability in gas-condensate reservoirs,Gas condensate; relative permeability; coupling effect; inertia; inertial number; capillary number,FLOW,"Gas-condensate flow around the wellbore is quite different from conventional gas oil flow. This is mainly due to complicated velocity effects on relative permeability in these very low interfacial tension systems. In the current study, it has been proposed that the desirable velocity effect on gas-condensate relative permeability is the result of inertial force. Having said that, inertial number, which is the ratio of inertial force over capillary force, could be a better candidate compared to capillary number when somebody deals with the modeling of gas-condensate relative permeability. A generalized correlation was obtained for gas-condensate relative permeability with applying this new approach. The results are promising. This approach is not only needs less core data, but also it is much simpler and even more accurate compared to previously developed equations using capillary number.",4,4,1
Other topics ,,"Naderi, Hamed; Fathianpour, Nader; Tabaei, Morteza",MORPHSIM: A new multiple-point pattern-based unconditional simulation algorithm using morphological image processing tools,Geostatistics; Multiple point-based algorithm; Morphological image processing; Training image; Pattern-based simulation,GEOSTATISTICAL SIMULATION; DILATION,"Most simulation algorithms based on Multiple-Point Statistics (MPS) deploy training images that are usually constructed from conceptual 2D or 3D spatial distribution of the reservoir parameters by means of a similarity measure such as Bayesian likelihood probability or pattern-based matching methods to map complicated geological structures and heterogeneities inherent to most petroleum reservoirs. The recent pattern-based MPS algorithms employ common techniques in the course of unconditional simulation. However, there is no guarantee to ensure that the desired targets in the training patterns could have been even captured by a specified search template. That is, the number of training patterns produced by any search template size is always limited, while the data events formed during simulation could potentially show any unexpected patterns. This is where previous algorithms encounter some difficulties in finding actual patterns even if they are equipped with precise pattern recognition measures. To address this issue and avoid extra complexity in the course of simulation, we have proposed a new unconditional pattern-based simulation procedure which deploys the edge-similarity and morphological image processing concepts. In the course of our proposed algorithm, each pattern is temporarily substituted with its edge features followed by performing a k-means classification of their similarity measures using Manhattan distance function for primary infilling of optimum patterns in the simulation grid. Next, through using a combination of morphological operations with automatically determined or user-defined specifications, the algorithm named as MORPHSIM in this context would effectively improves pattern reproduction and structural continuity. Results have shown the strength and flexibility of MORPHSIM in reproducing patterns for unconditional simulations, even when the input training image is poorly constructed and includes just a simple non-stationary structure. The algorithm is not only computationally effective in terms of simulation run time and memory usage relative to FILTERSIM but also can overcome the imperfection of training image by applying morphological image processing filters.",4,4,1
Other topics ,,"Sporin, Jurij; Mrvar, Primoz; Petric, Mitja; Vizintin, Goran; Vukelic, Zeljko",The characterization of wear in roller cone drill bit by rock material-Sandstone,Roller cone bit; Mechanism of drill bit wear; Carbide coating; Erosion channel; Micro crack; Aggressive drill mud,BEHAVIOR; EROSION,"Roller cone drill bit efficiency time during drilling depends, to a large extent, on the properties of the materials from which the components of the roller cone bit are made. The faster the roller cone bit is worn, due to the effects of the rock material through which we drill and the drilling regimes used during the drilling, the worse is the efficiency of drilling and the higher is the number of drill bits needed to drill the well. The aim of our research was to determine the mechanisms of wear on roller cone bit materials according to the characteristics of the steel material of the roller cone bit and the characteristics of the rock material, in this case, sandstone on the drilling regime. The results of the discovered wear mechanisms help us to anticipate the possible improvement of the resistance of the unprotected roller cone bit steel material to excessive wear and, consequently, the longevity of the roller cone bit. For this purpose, we examined the steel materials of the roller cone bit, which we used during well drilling and the rock material, sandstone, through which we drilled with the roller cone bit under consideration. The results of our analysis present the mechanisms that result in the wear of the roller cone bit material under the given conditions of the rock material and the drilling regime. The results of the discovered wear mechanism can be used to improve the material of the roller cone bits in order to achieve a longer operating life and decrease the related costs of drilling.",4,4,2
Other topics ,,"Song, Zhiyong; Chen, Songcan; Zhao, Fengmin; Zhu, Weiyao",Whole metagenome of injected and produced fluids reveal the heterogenetic characteristics of the microbial community in a water-flooded oil reservoir,Subsurface environment; Oil reservoir; Whole metagenome; Porous media; Microbial community,SATURATED POROUS-MEDIA; DEEP SUBSURFACE; RECOVERY; FIELD; MEOR; BIODEGRADATION; DIVERSITY; MICROORGANISMS; WETTABILITY; ANNOTATION,"In order to understand the subsurface microbial community and how it functions in a water-flooded reservoir, the whole metagenome of fluids from production and injection wells were sequenced using next-generation sequencing and then compared. Gene function was annotated by the Kyoto Encyclopedia of Genes and Genomes (KEGG), evolutionary genealogy of genes: Non-supervised Orthologous Groups (eggNOG) and hydrocarbon degradation databases. More biomass was detected in fluid from the injection well than in the production well. As a typical water-flooded reservoir, injection and production communities were dominated by Proteobacteria. In the production metagenome, more genes involved in denitrification and hydrocarbons utilization pathways, reflecting the strict anaerobic and oil-rich conditions in reservoirs. The higher abundance of genes responsible for methyl chemotaxis, aerotaxis and flagella indicate that the community in reservoirs is motivated to access limited nutrients and electron acceptors. Combined with knowledge of porous flow, these metagenome results indicate that the microbial communities detected in produced fluids are actually derived from different habitats in the reservoir, which are established by the chromatographic effect of reservoir flooding. Furthermore, diverse flow patterns at pore scale could affect in situ proliferation and syntrophy between species, which could considerably shift the microbial composition in produced fluids.",4,4,2
Other topics ,,"Khoshnevis, Negar; Khosrokhavar, Roozbeh; Nick, Hamidreza M.; Bruhn, David F.; Bruining, Hans",Injection of disposal water from a geothermal reservoir into a gas reservoir,Water injection; Exergy; Geothermal energy; Synergy; Gas trapping,PERFORMANCE; EXERGIES,"In this paper, we assess and model new strategies for integration of geothermal energy with gas production in the Oude Leede Gas Field in the Netherlands. We investigate the injection of cooled geothermal water into a gas field located just few kilometers away from the geothermal reservoir in the Netherlands. This synergy type can be considered for economic natural gas production from a gas field in the proximity of a geothermal doublet project and improved energy production in the geothermal reservoir. A 3-D model including a gas trapping mechanism was built to study the possible production potential of the gas field. Water flooding compensates pressure loss by reducing the pore space, however it complicates the process by introducing trapped gas. We studied the effect of injection rate, permeability, saturation condition before flooding and reservoir pressure on the ultimate gas recovery and the residual trapped gas saturation. Injecting water will increase the ultimate recovery factor for higher abandonment pressure. Higher water injection rates will keep the reservoir pressure up, increase the trapped gas saturation, and hence reduce the maximum recovery. The presence of heterogeneity and capillary forces has minor effects on the gas recovery factor. The exergy recovery factor of a water injection process is higher than a gas compression process due to the large amounts of energy required for compression. Considering net present value (NPV) analysis for a higher abandonment pressure, water injection is economically preferable, however not feasible. At a lower abandonment pressure, natural gas depletion can easily compete with the water injection process due to the higher costs of water injection and drilling.",4,4,2
Other topics ,,"Gavrilenko, N. A.; Volgina, T. N.; Urazov, E. V.; Gavrilenko, M. A.",Transparent polymer sensor for visual and photometrical detection of thiocyanate in oilfield water,Thiocyanate; Tracer analysis; Polymethacrylate matrix; Colorimetric sensor; Solid phase spectrophotometry; Oilfield water,SOLID-PHASE MICROEXTRACTION; OPTICAL CHEMICAL SENSORS; COLORIMETRIC SENSOR; EXTRACTION; FLOW; PRECONCENTRATION; MATRIX,"A novel colorimetric sensor has been proposed for sensitive and accurate visual and spectrophotometric detection of thiocyanate using polymethacrylate matrix, which also has the potential for use with samples without pretreatment. The determination method is based on shaping of a Fe3+-thiocyanate colored complex into a transparent polymer matrix, followed by measurement of absorbance at 490 nm. The principle of this colorimetric sensor is not ordinary colorimetry, but a new colorimetric strategy that combines solid phase extraction and spectrophotometric determination of thiocyanate following completion of the color change processes. The method ensures determination of 0.8-30.0 mg L-1 of thiocyanate with the detection limit of 0.3 mg L-1. The proposed simple method makes it possible to determine visually in the concentration above 6.0 mg L-1 using a color scale. The test results show that the polymethacrylate matrix can be used for determination of thiocyanate in oilfield water.",4,4,2
Other topics ,,"Zhang, Zhennan; Wang, Zhiyuan; Gao, Yonghai; Li, Hao; Wang, Jintang; Sun, Baojiang",Experimental study on the effect of surfactants on the characteristics of gas carrying liquid in vertical churn and annular flows,Foam; Gas entrainment; Surfactant; Churn flow; Annular flow; Gas carrying liquid; High-speed camera,AIR-WATER; TAYLOR BUBBLES; 2-PHASE FLOW; HUGE WAVE; ENTRAINMENT; MODEL; FOAM; PREDICTION; VELOCITY; REGIMES,"In this paper, air-water and air-SDBS solution vertical pipe flow experiments were carried out at room temperature and pressure. The purpose of this work is to study the effect of surfactants on the characteristics of gas carrying liquid in churn and annular flows by a high-speed camera. The results show that surfactants significantly affect the gas-liquid distribution characteristics in churn and annular flows. The process and degree of momentum transfer between the gas phase and liquid phase also change. With the introduction of surfactants, the bubble entrainment is enhanced while the droplet entrainment is inhibited. In churn flow, surfactants make the way of gas carrying liquid change from the accelerated migration of entrained liquid blocks to the one-way migration of stable waves. In annular flow, surfactants make the way of gas carrying liquid change from the accelerated migration of entrained liquid droplets and wave unidirectional migration to the migration of waves with uniform circumferential and axial distribution. The change of the way of gas carrying liquid caused by surfactants increases the momentum transfer between the gas phase and liquid phase, leading to a significant increase in the pressure drop gradient. The foaming of the liquid film is due to the fact that the wave growing from the liquid inlet can more easily satisfy the conditions of bubble entrainment than droplet entrainment. The gas and liquid flow rates determine the growth characteristics of the wave at the liquid inlet, thus determine the degree of change in the way of gas carrying liquid by surfactants.",4,4,3
Other topics ,,"Wang, Chao-Wen; Jia, Chun-Sheng; Peng, Xiao-Long; Chen, Zhangxin; Zhu, Su-Yang; Sun, Han-Sen; Zhang, Jian","Effects of wellbore interference on concurrent gas production from multilayered tight sands: A case study in eastern Ordos Basin, China",Tight sand gas; Multi-layer; Interlayer interference; Production optimization; Numerical simulation; Ordos basin,NUCLEAR-MAGNETIC-RESONANCE; UNCONVENTIONAL GAS; LINXING AREA; SEMIANALYTICAL MODEL; PICEANCE BASIN; SHALE; RESERVOIRS; PERMEABILITY; TECHNOLOGY; INJECTION,"This paper presents a field-development case study of a tight gas sandstone reservoir in China. The gas production well JK1 in the Linxing-Shenfu Gasfield in Eastern Ordos Basin is concurrent producing from three separate layers, and experienced interlayer interference stage in which gas production dropped to 0 rapidly. The purpose of this study is to investigate the influence of interference between different layers on concurrent production, to explore a reasonable adjustment plan, and finally to enhance the productivity of well JK1. The production history of this well was analyzed and a three-dimensional geological model for it was constructed. The interlayer interference of pay zones and zones combination optimization were simulated for field application. The simulation results show that the interlayer interference is obvious when the three layers have commingled production, the fluids even flow backward to the Upper layer. When the Middle layer is produced with other layers, it is the main water production layer with less gas. The Lower layer has always been the main gas production layer with less water. The optimization results indicate that only the Lower formation produces separately, the gas production is the highest. The optimization of field operational practices was based on the introduction of numerical simulation results enabled a gas production increase from vanishingly low to almost 4500 m(3)/d in the following year. This study can provide an insight on interlayer interference and a good guidance for a production strategy on full field development.",4,5,4
Other topics ,,"Zheng, Mingming; Liu, Tianle; Gao, Zhenyu; Wu, Jingjing; Jiang, Guosheng; Li, Qian; Li, Zhijun; Xie, Lanlan",Simulation of natural gas hydrate formation skeleton with the mathematical model for the calculation of macro-micro parameters,Natural gas hydrate; Digital core; Process parameters; Microscopic pore parameters; Mathematical calculation model,STRATIGRAPHIC TEST WELL; PRESSURE-CORING SYSTEM; PHYSICAL-PROPERTIES; METHANE HYDRATE; SEDIMENTS; DISSOCIATION; STRENGTH,"The quantitative relationship among the four process parameters (bentonite, binders, pressure, and time) of artificial core preparation, two macroscopic physical parameters (permeability and porosity), and three microscopic pore parameters (average pore and throat diameters and pore throat ratio) are investigated through multiple sets of experiments. Further, this research considers the natural gas hydrate formation skeleton in the Mount Elbert Well on Alaska North Slope as the simulated object. The optimal artificial core formula with permeability and porosity similar to the in situ hydrate formation skeleton was optimized by an orthogonal test, the fitting function relationships among these three aspects were obtained, and a relationship model was established. The results demonstrated that the permeability and porosity of the optimal formula are extremely close to the natural formation skeleton, and the microscopic pore morphology is similar to that of the natural cores. The established relationship model can be used to accurately estimate the permeability, porosity, and pore and throat diameters using the four process parameters; in turn, the process parameters also can be estimated. The digital simulation preparation technology of the natural gas hydrate formation skeleton developed in this work can accurately and quickly estimate the macro-micro physical parameters of the artificial hydrate formation skeleton. Further, it can also prepare 60-cm-long cores that can be used in the subsequent experimental study of the physical property response in hydrate formation drilling, playing an important role for the simulation of natural formation skeletons.",4,5,8
Other topics ,,"Zhu, Xiaohua; Liu, Biao",A method to assess the reliability of casings in marine gas reservoirs based on Bayesian theory optimization,Marine gas reservoir; Bayesian theory; Prior information; Assessment method; Comparison,STEAM INJECTION WELLS,"With the exploitation of marine gas fields including Puguang, Yuanba and Longwangmiao in Anyue, casings have been thinned, deformed, ruptured or even broken by various factors after a long time of service. Therefore, it is important to assess the reliability of casings used in marine gas reservoirs. Based on Bayesian theory and the current status, the prior information is used to screen and simplify influencing factors, to optimize models. According to the standard of collapsing strength and the numerical simulation, optimized models to assess the reliability of casings in marine gas reservoirs are established, applied and compared. The results provided by these optimized models showed a downward trend, but the ranges and gradients of variation are quite different. The results calculated for uniform loads and non-uniform loads are close to each other, as indicated by the sensitivity analysis. To make use of the advantages in two assessment methods, first, a preliminary screening to the casings with hidden danger is achieved by the method based on the collapsing strength. Then, the method based on the numerical simulation is used to assess the remaining risky casings.",5,7,0
Other topics ,,"Liang, Jintong; Wang, Hongliang; Blum, Mike J.; Ji, Xinyuan",Demarcation and correlation of stratigraphic sequences using wavelet and Hilbert-Huang transforms: A case study from Niger Delta Basin,Sequence demarcation and correlation; Continuous wavelet transform; Discrete wavelet transform; Hilbert-huang transform; Niger Delta Basin,WELL-LOG DATA; FORMATION INTERFACES; MODE DECOMPOSITION; WALSH TRANSFORM; IDENTIFICATION; ACCOMMODATION; BOUNDARIES; TURBIDITE,"Demarcation and correlation of stratigraphic sequences are particularly significant in hydrocarbon exploration, in which signatures of well logs are commonly used in conventional interpretation methods. In this study, an intelligent and effective way of sequence stratigraphic analysis is proposed through combining the continuous wavelet transform (CWT), the discrete wavelet transform (DWT), and the Hilbert-Huang transform (HHT) together. By using MATLAB software, these mathematical methods (CWT, DWT, and HHT) are applied on GR logs to interpret sequence surfaces and cycles in the Agbada Formation, Niger Delta Basin. Within the context of base-level and A/S variation, the studied interval is interpreted as a long-term (3rd-order) base-level stratigraphic cycle and three middle-term base-level (4th-order) stratigraphic cycles regarding individual well and cross-section. The comparative results indicate that the CWT and DWT, compared with the HHT, have better resolution in identifying base-level cycles and their periodicity. By contrast, the HHT is more suitable to interpret specific positions of sequence surfaces. Generally, together with conventional interpretation methods, the exploratory methods of this study provide a relatively objective and acceptable way in high-resolution (4th-order or lower rank) sequence stratigraphic analysis at scales of hundreds of meters. Besides, a source to sink depositional model is presented as an example to illustrate multiple well log (GR) interpretations. The idea of this study aims to be extended to more studies to reduce subjective uncertainties in model-driven interpretations.",5,5,0
Other topics ,,"Bakker, Steffen; Vralstad, Torbjorn; Tomasgard, Asgeir",An optimization model for the planning of offshore plug and abandonment campaigns,Plug and abandonment; Campaign planning; Decommissioning; Optimization; Mathematical programming; Vehicle routing; Petroleum economics,STOCHASTIC-PROGRAMMING APPROACH; COST,"Plug and abandonment (P&A) operations can be time-consuming and thus very costly, especially for subsea fields. P&A of subsea wells require dedicated vessels such as high cost semi-submersible drilling rigs or lower cost Riserless Light Well Intervention vessels. This paper describes an optimization model that can be used to plan multi-well P&A campaigns by finding cost-efficient vessel routes and allocation of P&A operations to different rigs and vessels. The model's functionality is demonstrated on ten different synthetic cases, generated from realistic data. Results show that significant cost savings can be made by adapting the optimal solutions from this model compared to planning strategies that are currently used by operators, as well as by cooperating across fields and licenses in a large campaign.",5,6,0
Other topics ,,"Hosseini, Seyyed A.",Fault leakage detection and characterization using pressure transient analysis,Linear fluid flow; Pressure transient analysis; Leak detection; Monitoring,CO2 LEAKAGE,"Injection of fluids in deep subsurface geological formations has created a series of challenges in recent decades. Possibility of upward fluid leakage along nearby wells and faults is one of the main issues related to these operations. It is important to ensure that such conduits, if present, can be detected, characterized and treated. Looking for pressure abnormalities in intervals above the injection zones, is one the methods used to monitor for these conduits. We propose an analytical solution to detect and characterize the vertical leakage from a fault of finite length using pressure data collected from monitoring zones. The proposed closed form analytical model would allow to not only distinguish the pressure signal of leakage from a fault of finite length from other possible leakage conduits but also to estimate the leakage rate, length of leaky section of the fault and relative position of the fault with respect to the location of monitoring well.",5,5,1
Other topics ,,"Zhou, Jingao; Deng, Hongying; Yu, Zhou; Guo, Qi; Zhang, Ru; Zhang, Jianyong; Li, Wenzheng",The genesis and prediction of dolomite reservoir in reef-shoal of Changxing Formation-Feixianguan Formation in Sichuan Basin,Sichuan basin; Changxing formation; Feixianguan formation; Reservoir genesis; Reservoir predict,DOLOMITIZATION; CARBONATES; PLEISTOCENE; LIMESTONES; DIAGENESIS,"In the past 20 years, great exploration achievements and new progresses have been made in Permian Changxing Formation(abbreviated as C.F.) and Triassic Feixianguan Formation(abbreviated as F.F.)in Sichuan Basin. The main results and progress include: (1)several gas fields, such as Puguang gasfield, Longgang gasfield, and so on are found; (2)C.F. and F.F. contain 3 third order sequence; (3)the reservoir mainly develop in reef shoal microfacies of platform margin; (4)the gasfields are lithologic pools distributed along platform margin. Although many common views have been achieved, the divergence of reservoir formation is still remained. Based on the study of petrology and diagenesis combined with the analysis datas, the basic reservoir characteristics, pore types and their genesis, dolomization and its influence of the C.F. and F.F. have been clarified in the paper. It is pointed out that the main lithology of the reef shoal dolomite reservoir in C. F. is residual bioclastic dolostone, residual reef framework dolostone and fine-medium crystalline dolostone. The reservoir spaces are dissloved pores and vugs,which formation is closely related to early meteoric water dissolution and shallow burial dolomization. The main lithology of oolitic dolomite reservoir in F.F. is residual oolitic micrite dolostone, residual oolitic silty-fine dolostone and fine crystal dolostone. The storege is mainly intergranular pore, oolitic moldic and their enlarged pore. The mineral composition of oolitic, early freshwater dissolution and dolomization are the main controlling factors of reservoir formation. It is predicted that the platform edge is the favorable distribution area of reef shoal and oolitic shoal dolomite reservoir.",5,10,1
Other topics ,,"Liu Ling; Tang Dazhen; Wo Yujin; Liu Lihui; Sun Wei; Lu Hongme; Yekikang, Mbunkah Quentin","Favorable area prediction of tight sandstone: A case study of the He8 formation in the Kangning area, Eastern Ordos Basin, China",Tight sandstone; Pre-stack elastic parameters; Reservoir prediction; Hydrocarbon detection; Favorable area prediction,GAS; AVO; RESERVOIRS; VELOCITY,"The reservoirs of the Lower Permian He8 formation are typically tight sandstones, which have geologic features such as rapid lateral changes, strong heterogeneities and complex pore structures. Rock physics characteristics are similar between tight sandstones and mudstones, mean while fluid AVO characteristics are unclear. These factors make reservoir prediction and hydrocarbon detection become difficult. The keys to successful exploration are the effective elimination of non-reservoirs, including mudstones and ineffective tight sandstones, and the successful discovery of favorable areas. Rock physics analysis indicates that tight sandstone can be identified by V-p/V-s, while gas-bearing can be distinguished by fluid compressibility. In order to improve inversion accuracy, a new method of favorable area prediction is proposed. Firstly, predict sandstone boundary by V-p/V-s inversion under the control of sedimentary setting. Secondly, distinguish effective reservoirs and gas-bearing areas with porosity inversion and fluid compressibility inversion under the control of sandstone boundary. Finally, confirm favorable areas according to V-p/V-s, porosity and fluid compressibility. The tight sandstones of the He8 formation can be divided into three types. Favorable area I is the first choice of exploration, target followed by the favorable area II, whereas the unfavorable area III is not chosen as exploration target. The new method has achieved excellent results in the favorable area prediction of tight sandstone in the Kangning area and has significant implications for late exploration.",5,7,2
Other topics ,,"Lavrov, Alexandre; Bhuiyan, Mohammad; Stroisz, Anna",Push-out test: Why bother?,Push-out test; Cement; Well cementing; Casing; Bonding,FIBER PULL-OUT; ZONAL ISOLATION; CO2 STORAGE; CEMENT; INTERFACE; INTEGRITY; STRENGTH; STEEL; BOND,"Bonding between cement and steel is currently believed to be of key importance in well integrity since it prevents the development of microannulus. Push-out test is often used to quantify the bonding strength between cement and steel in laboratory. Our experiments reveal a strong size-dependency of the push-out strength measured in these tests: the strength decreases with pipe diameter. This means that the push-out strength is not an intrinsic material parameter (""bonding strength"") and therefore cannot be applied to field conditions before a proper correction is introduced. Such correction should take into account the large difference in diameter between the casing and the pipes typically used in laboratory tests. Finite-element simulations show that the experimentally-observed size-dependency could be, at least partially, explained by cement shrinkage that creates initial normal stress at the interface. The observed push-out strength is then not an intrinsic property of the interface between two materials (which would be an adhesive shear strength) but rather a result of interfacial friction. As the pipe diameter increases, the shrinkage-induced normal stress at the interface decreases, the frictional resistance decreases, and thus the measured push-out strength decreases, too, as observed in the lab tests. Simulations show, however, that shrinkage-induced decrease in push-out strength cannot fully explain the size-dependency since the decrease is much larger in the experiments than in the simulations. Another mechanism that could be at play is the common size effect interfaces become weaker as their size increases because it is more likely that a larger interface contains an initial flaw of a given size. The decrease of push-out strength with pipe diameter has at least two practical implications: (i) the concept of bonding strength is misleading (unless it is specified explicitly that this parameter refers to frictional resistance at the interface rather than to an inherent adhesive strength) and (ii) the results of push-out tests can be used in well design only if a proper correction for the pipe diameter is introduced.",5,5,2
Other topics ,,"Yan, Zhidan; Xu, Wenyi; Ai, Chunwei; Geng, Yanfeng",Parametric study on pump noise processing method of continuous wave mud pulse signal based on dual-sensor,Measurement and logging while drilling; Continuous wave pulse transmission; Pump noise; Weak signal processing; Time-domain delay differential method; Dual-sensor,,"Continuous wave pulse transmission technology has become the forefront development direction of measurement while drilling and logging information transmission with its high transmission rate and strong anti-interference ability. In this paper, the denoising principle of time-domain delay differential method based on two pressure sensors is analyzed in detail. The acquisition signals of two sensors with different sensor intervals and SNRs (Signal-to-Noise Ratio) are constructed. The denoising ability of the time-domain delay differential method in different cases, i.e., stable and unstable pump noise, the amplitude and frequency distortion of the original pulse signal, and the structural change of the original pulse signal, are emphatically studied. Simulations show that this method can effectively suppress the pump noise even when there is a significant fluctuation in the fundamental frequency and amplitude of pump noise. This method can also obtain well-formed reconstructed signal when the pulse signal has high frequency and amplitude distortion. Besides, a general method for deriving an optimal dual-sensor installation interval is discussed for a BFSK (Binary Frequency Shift Keying) transmission signal, which consists of high-frequency and low-frequency carrier waves, and a reference installation interval is given. Finally, this method is applied to denoise the actual dual-sensor acquisition signal, and satisfactory results are obtained.",5,5,2
Other topics ,,"Zhang, Xuan; Han, Ming; Fuseni, Alhasan; Alsofi, Abdulkareem M.",An approach to evaluate polyacrylamide-type polymers' long-term stability under high temperature and high salinity environment,Polyacrylamide-type polymer; Thermogravimetric analysis; High salinity and high temperature; Long-term stability,THERMAL-DEGRADATION; RHEOLOGICAL PROPERTIES; BEHAVIOR,"Water-soluble polymers have been widely used in chemical flooding either independently or as part of surfactant- polymer (SP) and alkaline-surfactant-polymer (ASP) processes. The polymer viscosifies the injected water thereby reducing the displacing fluid's mobility and increasing sweep efficiency. The key to efficient sweep is attaining sustainable mobility control (i.e. maintenance of sufficient viscosity during propagation in the reservoir). Long-term stability is therefore a crucial parameter in the screening of appropriate polymers for application, especially in high temperature and high salinity reservoirs. In general, the evaluation of a polymer solution's long-term stability is a very time-consuming process. There is a need to develop fast and reliable means to assess the feasibility of polymers from a long-term stability standpoint. Different from conventional methods posed in the literature, this paper presents a new facile approach to evaluate the polymers in powder form and identify their molecular decomposition. The approach is correlated and confirmed against conventional longterm stability results obtained from the evaluation of polymer solutions. Thermogravimetric analysis (TGA) was used in this work to study the decomposition of polymers and their individual constituents. The derivative of the TGA curve with respect to temperature, is known as the derivative thermal gravimetric (DTG) thermogram, which can clearly identify differences in decomposition rates of screened polymers. Furthermore, conventional long-term stability tests were performed on polymer solutions prepared in synthetic seawater with a salinity of 57,670 ppm. The solutions were aged at a temperature of 95 degrees C under anaerobic conditions and monitored by rheological measurements for viscosity loss, total organic carbon (TOC) analyses for material loss, and gel permeation chromatography (GPC) for molecular weight loss. The thermal stability of 12 commercial water soluble polymers was tested in this work. The long-term stability results are consistent with the TGA results. The two polymers showing good thermogravimetric stability exhibited significant viscosity retention in conventional long-term stability tests. TOC and GPC results further supported these TGA results. The developed method provides a fast approach to screen polymer candidates for high temperature and high salinity reservoirs.",5,6,2
Other topics ,,"Ji, Lili; Lin, Mian; Cao, Gaohui; Jiang, Wenbin",A multiscale reconstructing method for shale based on SEM image and experiment data,Multiscale pore structure; Multiscale reconstructing method; lREV; Digital-experimental model; Shale,PORE-SPACE RECONSTRUCTION; STOCHASTIC CHARACTERIZATION; PERMEABILITY; SIMULATION; ALGORITHM; SAMPLE,"Owing to the presence of multiscale pore structures, characterization of laminated shales is both extremely difficult and substantially different from that of conventional reservoirs, and defies conventional methodologies. In this paper, a multiscale reconstructing method for shale is proposed to generate 3D layer representative elementary volume (lREV)-scale digital-experimental models to characterize the multiscale pore structure of the shale by means of the combination of a large area SEM image, nitrogen adsorption and pressure pulse decay experiment result. In this method an improved multiscale superposition algorithm is introduced to integrate the reconstructed complex models from nanoscale to mesoscale together, and it can preserve the details and main features enormously of each typical component (nanoscale organic pores in organic matter and pyrites, micro-nano inorganic pores and micro slits) in the shale. Especially, to accurately reproduce the realistic morphology for shale, the proposed method uses the experimental pore size distribution and permeability as constrain conditions to adjust and optimize the lREV-scale digital-experimental model. Our proposed method was tested on Longmaxi and Wufeng shale samples, and the reconstructed lREV-scale digital-experimental model are proved to accurately describe the representative structure of the complex multiscale pore space of the typical layer of the shale. The success of this method provides a promising way for reconstructing more realistic model to continuously and systematically characterize the pore (slits) structure from the nanopore-scale to the lREV-scale. It can advance the understanding of the various gas transport mechanisms at different scales and will be helpful for understanding the quality of the shale reservoir.",5,5,3
