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Shale gas production has been gaining worldwide attention over the past several years. This is due to the economic gas reserves using two current advanced technologies that are horizontal drilling and multistage hydraulic fracturing. Shale has a high total organic content (TOC) that may adsorb significant amount of natural gas. In addition, laboratory and theoretical calculations indicate that organic-rich shales adsorb CO2 preferentially over CH4. Hence, the extent of organic matter in shale plays an important role in determining the feasibility of CO2 injection with potential benefit of enhanced gas recovery (EGR). The performance of CO2 injection and CH4 recovery in shale reservoirs is a complex function of several engineering parameters including fracture half-length, fracture conductivity, and fracture height, operating parameters such as injection volume and injection time, and geologic parameters including reservoir permeability, porosity, and thickness. Nevertheless, the effects of the above uncertain parameters on the process of CO2-EGR are not clearly understood and systematically studied. Therefore, it is absolutely critical to quantify uncertainties and investigate the most important influential parameters controlling this process. In this paper, we employ numerical reservoir simulation techniques to model multiple hydraulic fractures and multi-component Langmuir isotherms. Two scenarios for CO2 injection are investigated when the primary gas production decreases to the economic limit: (1) CO2 flooding in two horizontal wells, and (2) CO2 huff-n-puff in a horizontal well. A series of reservoir simulations based on Design of Experiment (DOE) are performed on the best scenario to investigate the critical parameters that control this CO2-EGR process in the Barnett Shale. This work enables operators to plan ahead of time and optimize a tertiary shale gas production process by considering the different investigated influential parameters.

It is proposed that very low permeability formations are possible candidates for CO 2 sequestration. Further, experimental studies have shown that shale formations have huge affinity to adsorb CO 2 , the order of 5 to 1 compared to the methane. Therefore, potential sequestration of CO 2 in shale formations leading to enhanced gas recovery (EGR) will be a promising while challenging target for the oil and gas industry. On the other side, hydraulic re-fracturing treatment of shale gas wells is currently gaining more attention due to the poor performance of shale gas reservoirs after a couple years of production. Hence, investigating and comparing the performance of CO 2 -EGR with the re-fracturing treatment is essential for the future economic viability of depleted shale gas reservoirs. This paper presents a systematic comparison of the effect of these two processes on improving gas production performance of unconventional reservoirs, which is not well understood and has not been studied thoroughly in the literature.In this paper, a shale gas field data has been evaluated and incorporated in our simulations for both CO 2 -EGR and re-fracturing treatment purposes. Numerical simulations are performed using local grid refinement (LGR) in order to accurately model the non-linear pressure drop. Also, a dual-porosity/dualpermeability model is incorporated in the reservoir simulation model. Further, the uncertainties associated with inter-related set of geologic and engineering parameters are evaluated and quantified for re-fracturing treatment through several simulation runs. This comprehensive sensitivity study helps in understanding the key reservoir and fracture properties that affect the production performance and enhanced gas recovery in shale gas reservoirs.The results showed that re-fracturing treatment outperforms CO 2 -EGR due to the pronounced effect on cumulative methane gas production. Moreover, the sensitivity analysis showed that the characteristics of reservoir matrix including permeability and porosity are the most influential parameters for re-fracturing treatment. The findings of this study recommend hydraulic re-fracturing of shale reservoirs at first for enhancing gas production followed by CO 2 injection at a later time. This work provides field operators with more insight into maximizing gas recovery from unconventional shale gas reservoirs using refracturing stimulation, CO 2 injection, or a combination of both methods.

The advantages of using the low salinity water injection (LSWI) technique to improve oil recovery in carbonates have been reported in the literature; however, the mechanism behind it is still uncertain. In this paper, a geochemical/thermodynamic interpretation of the mechanism controlling oil recovery in carbonates by LSWI is proposed based on a recently published experimental study. The geochemical modeling was performed using two geochemical simulators (UTCHEM and PHREEQC). For the carbonate case considered in this paper, it was found that the wettability alteration was caused mainly by changing the surface charge of the rock rather than by dissolution. The findings cannot be generalized as the LSWI technique is case dependent.

Summary The advantages of using the low-salinity-water-injection (LSWI) technique to improve oil recovery in carbonates are reported in the literature; however, the mechanism behind it is still uncertain. This paper represents a comparison between two geochemical simulators [UTCHEM (UTCHEM manual, 2000) and PHREEQC (Parkhurst and Appelo 2013)] through modeling fluid- and solid-species concentrations of a recently published LSWI coreflood. Moreover, an attempt to interpret the mechanism controlling the LSWI effect on oil recovery from carbonates is presented on the basis of the findings of this work. The LSWI technique is case-dependent, and hence, the findings cannot be generalized.