Chemical flooding is one of the effective methods to recover large volumes of oil from sandstone formations after primary depletion. However, silica dissolution often occurs during Alkaline-Surfactant-Polymer (ASP) flooding, affecting the petro-physical properties of the formation. To address this issue, samples from Berea sandstone formations were treated with various brine solutions, through static tube tests and core flooding experiments. Analytical tests such as DR/2800 spectrophotometer and scanning electron microscope were used to evaluate the silica solubility and the alteration in mineral content. The results indicated that the silicate contents decreased after the saturation due to silica solubility in the solution. Increasing brine salinity to 40,000ppm and introducing Magnesium and Calcium ions to the solution, reduces the silicate contents by 5.03 % and 7.32 %. Moreover, saturating the samples with ASP solution, further reduced the silicate contents by 14.86 %. This reduction is associated with a relative increase in silica solubility and pH of the solution. Silica dissolution affects the pore microstructure, which resulted in increasing the porosity and pore volume after the core flooding. The injection of the ASP solution increased the porosity by 5.83%, thus the pore volume increased from 17.72 to 18.76cc. This is associated with the high silica solubility and the increase of solution pH in the ASP solution. The permeability of the samples generally reduced after the core flooding, due to the silica solubility. However, injecting the ASP solution, resulted in a major reduction of the permeability by more than 75%. These changes in the petro-physical properties can lead to severe formation damage, and affect hydrocarbon production. This study assists in understanding the impact of silica dissolution during ASP treatment and addresses the factors involved. Efficient utilization of chemical flooding can help mitigating silicate scaling within the formation, and extend field productivity.

Graphene oxide (GO), nanographene oxide (nGO) and partially reduced graphene oxide (rGO) have been studied as possible foam stabilizing agents for CO₂ based enhanced oil recovery (EOR). GO was able to stabilize CO₂/synthetic sea water foams. rGO was not able to stabilize foams likely due to the high reduction degree of the material. Particle size had a strong influence on foamability and stability. GO hydrophilicity increased as the particle size decreased and no foams were created when particle size was below 1 µm (nGO). GO brine dispersions showed immediate gel formation, which improved foam stability. Particle growth due to layer stacking was also observed. This mechanism was detrimental for foam formation and stabilization. nGO dispersed in synthetic sea water rapidly formed hydrogels and was not filterable. This work indicates that the particles studied are not suitable for CO₂ EOR purposes.

The Oil reservoirs with low permeability account for a large proportion in the world, they surpass half of the total number of the oil reservoirs in China, it is important to exploit this kind of reservoir effectively. The exploitive results of these reservoir using normal water flooding methods are very poor because of the thine pores, bad connections and so on. However, these problems can be well solved by applying gas injection techniques. In this paper, the effects on the recovery effects exerted by the injection parameters such as the oxygen content in the injected air, the injection speed etc. were studied by several experiments using independently designed equipments aiming at one low permeable sandstone reservoir in China. Several conclusions were made from the experiment results: the best recovery effects can be achieved by injecting the oxygen reduced air with 8% of oxygen at the speed of 0.3ml/min (7.41×10-4PV/min) using the methods of injecting the air slugs and the foaming agent slugs alternately; the best oxidation time of the oil was 168 hours and the final oil recovery could be enhanced by 26.5% in this method. It was also showed by the experiments that the larger the permeability ratio is, the larger the recovery factor will be increased. At last, several equations about relationships between the EOR and the air injection parameters were revealed according to the results of the experiments which may offer some references to the LTO process mechanisms study in the similar oil reservoir.

Water soluble polymers have gained an increasing interest in enhanced oil recovery (EOR) processes, especially as polymer flooding. Despite the fact that the flow of polymer in porous medium has been a research subject for many decades with numerous publications, there are still some research areas that need progress. The prediction of polymer injectivity remains elusive. Polymers with similar shear viscosity might have different in-situ rheological behaviors and may be exposed to different extent of mechanical degradation. Hence, determining polymer in-situ rheological behavior is of great significance for defining its utility. In this study, an investigation of rheological properties and mechanical degradation of different HPAM (partially hydrolyzed polyacrylamide) polymers was performed using Bentheimer sandstone outcrop cores. Results show that, HPAM in-situ rheology is different from bulk rheology measured in rheometer. Specifically, shear thickening behavior occurs at high rates, and near-Newtonian behavior is measured at low rates in porous media. This deviates strongly from measurements in the rheometer. Polymer molecular weight and concentration influence its viscoelasticity and subsequently its flow characteristics in porous media. Exposure to mechanical degradation by flow at high rate through porous media leads to significant reduction in shear thickening and thereby improved injectivity. More importantly, the degraded polymer maintained in-situ viscosity at low flow rates indicating that improved injectivity can be achieved without compromising viscosity at reservoir flow rates. This is explained by reduction in viscoelasticity. Mechanical degradation also leads to reduced residual resistance factor (RRF), especially for high polymer concentrations. For some of the polymer injections, successive degradation (increased degradation with transport length in porous media) was observed. The results presented here may be used to optimize polymer injectivity.

In recent years, machine learning (ML) techniques have emerged as an efficient and effective technology within the petroleum industry. This paper focuses on the current application of ML in enhanced oil recovery (EOR) through CO2 injection, which exhibits promising economic and environmental benefits of climate-change mitigation strategy. Our comprehensive review explores the diverse use cases of ML techniques in CO2-EOR, including aspects such as minimum miscible pressure (MMP) prediction, well location optimization, oil production and recovery factor prediction, multi-objective optimization, Pressure-Volume-Temperature (PVT) properties estimation, Water Alternating Gas (WAG) analysis, and CO2-foam EOR, from 101 reviewed papers. In this comprehensive review, we catalog relative information, including the input parameters, objectives, data sources, train/test/validate information, results, evaluation, and rating score for each area based on criteria such as data quality, ML building process, and analysis of results. We also briefly summarized the benefits and limitations of ML methods in petroleum industry applications. Our detailed and extensive study could serve as an invaluable reference for employing ML techniques in the petroleum industry. Based on the review, we found that ML techniques offer great potential in solving problems in the majority of CO2-EOR areas involving prediction and regression. With the generation of massive amounts of data in the everyday oil and gas industry, machine learning techniques can provide efficient and reliable preliminary results for the industry.