Excessive water production is a significant challenge during hydrocarbon production from oil and gas reservoirs, and it is typically controlled by polymer gel placement. However, the fundamental process in terms of how precisely this gel reduces water production in gas reservoirs is rarely reported. The objective of paper is to investigate the impact of cross-linked polyacrylamide (poly­(acrylamide-co-acrylic acid) partial sodium salt) gel as a relative permeability modifier for a sandstone/gas/water system and provides insights into the detailed in situ gel behavior inside the porous medium. Stronger gels increased water retention inside the porous media yet decreased the lubrication effect of the gel. Moreover, as the water flow rate increased (during imbibition), the water relative permeability reduction decreased, which is attributed to (a) gel shear thinning behavior and (b) reduction in the residual gas saturation. However, the gel showed shear thickening behavior during gas flow. At low gas flow rates, gel performance is mainly controlled by the gel lubrication effect, while at higher gas flow rates, the significance of gel rigidity is greatly increased. These effects were associated by gas diffusion and gas dissolution in the gel, which in turn expanded the gel layer and reduced gas permeability. Moreover, we identified two counteracting mechanisms (i.e., water retention and lubrication effects) responsible for the disproportionate permeability reduction. In addition, we identified a critical flow rate above which the gel treatment becomes unsuccessful as both effects (i.e., water retention and lubrication) were significantly reduced. These findings thus provide novel insights into the factors leading to successful gel placement to better control water production.

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Development of shale gas reservoirs is the fastest growing area on a large scale globally due to their potential reserves. CO2 has a great affinity to be adsorbed on shale organic surface over CH4. Therefore, CO2 injection into shale reservoirs initiates a potential for enhanced gas recovery and CO2 geological sequestration. The efficiency of CO2 enhanced gas recovery (CO2-EGR) is mainly dominated by several shale properties and engineering design parameters. However, due to the heterogeneity of shale reservoirs and the complexity of modeling the CO2–CH4 displacement process, there are still uncertainties in determining the main factors that control CO2 sequestration and enhanced CH4 recovery in shale reservoirs. Therefore, in view of the previous sensitivity analysis studies, no quantitative framework, accurate CO2-EGR modeling, or design process has been identified. Thus, this work aimed to provide a practical screening tool to manage and predict the efficiency of enhanced gas recovery and CO2 sequestration in shale reservoirs. To meet our objectives, we performed correlation analysis to identify the strength of the relationship between the examined shale properties and engineering design parameters and the efficiency of CO2-EGR. Data for this study was gathered across publications on a wide subset of numerical modeling studies and experimental investigations. The sensitivity of data was further improved by a hybrid approach adopted for handling the missing values to avoid bias in our data set. Our results indicate that CO2 flooding might be the best applicable option for CO2 injection in shale reservoirs, whereas the huff-and-puff scenario does not seem to be a viable option. The efficiency of CO2-EGR increases as the pressure difference between injection pressure and reservoir pressure increases. The results show that shallow shale reservoirs with high fracture permeability, total organic content, and CO2–CH4 preferential adsorption capacity are favorable targets for CO2-EGR. Moreover, our results indicate that a successful hydraulic-fracture network with effective values of fracture permeability and conductivity is essential for a higher CO2-EGR efficiency. Well spacing and fracture half-length are crucial engineering features in CO2-EGR process design that must be carefully optimized due to their negative effect on CH4 production and positive effect on CO2 storage. Our statistical analysis lays a foundation for efficient CO2-EGR design and implementation and presents an important contribution to the field of reaching the target of net-zero CO2 emissions for energy transitions.

Surfactants are favorable chemical additives that are widely utilized in enhanced oil recovery (EOR) due to their inherent abilities such as wettability alteration and interfacial tension (IFT) reduction. However, most of the commercially available surfactants are expensive, hazardous to the environment, and can readily adsorb on the surface of the porous rocks. The present work investigates the possible application of a novel plant-based natural surfactant derived from the weed, Eichhornia crassipes, for EOR. The wettability alteration and IFT measurements have been performed in reservoir-like conditions (i.e., high temperature and pressure). Adsorption of the surfactant at the oil−water interface has been studied. In addition, the effect of the natural surfactant on the rheological behavior of xanthan gum has been analyzed over a wide range of shear rates, frequencies, and temperatures. Further, core flooding experiments have been carried out by injecting the surfactant−polymer slugs of different concentrations into the sandstone core sample under reservoir-like conditions. Effective reduction values of ∼37−41% in IFT and ∼43% in wettability were observed with increasing surfactant concentration. Moreover, enhancement in the rheological properties and 13.3−22.4% additional oil recovery demonstrate the possible applications of this natural surfactant−polymer system in EOR.

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