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.

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Carbon Dioxide (CO2) storage and sequestration in unconventional shale resources has been attracting interest since last couple of years due to the very unique characteristics of such formations have made them a feasible option for this object. Shale formations are found all around the world and the conventional assets are easily accessible, and also the huge move of operators toward developing unconventional reservoirs during past years leaves many of such formations ready for sequestering CO2. Today, the use of long horizontal wells that are drilled on a pad has the lowest amount of environmental footprint in which for storage and sequestration purpose also provides much more underground pore spaces available for CO2. In this paper we study the state of the art of the technology of CO2 storage and sequestration and provide different and fresh look for its complex phenomena from a mathematical modeling point of view. Moreover, we hope this study provides valuable insights into the use of depleted shale gas reservoirs for carbon sequestration, which as a result, a cleaner atmosphere will be achieved for the life of our next generations. Also, we present that the depleted shale gas reservoirs are very adequate for this purpose as they already have much of the infrastructure required to perform CO2 injection available in sites.

An integrated unconventional reservoir model that accounts for known mechanisms and nonlinearities affecting modeling of hydraulically fractured wells is developed. In general, modeling and simulation of multi-fractured reservoirs are highly challenging due to the complexity attributed to the flow in this very low permeability and dense structured rock. Pressure-dependent phenomena in reservoir modeling are considered as combined hydraulic and natural fracture conductivity losses, desorption, Klinkenberg gas slippage effect and non-Darcy flow. Integrating these phenomena and analyzing the importance of each parameter in a reservoir model are essential.The proposed model includes three zones, Rock Matrix (I), Induced-Fracture (II) and Hydraulic Fracture (III) that are defined with different characteristics. Pressure dependent permeability is considered for zone II and III, with an exponential relationship between permeability and reservoir pressure. Governing equations of gas flow are non-linear partial differential equations, for all three zones, due to incorporated pressure-dependent phenomena that are solved using the finite difference method. A synthetic case is defined in order to investigate the effect of each individual phenomenon on long-term production. Moreover, a history matching process with Marcellus Shale field production data is performed in order to obtain the most uncertain parameters in the model.Results showed that combined effect of permeability losses of hydraulic and induced-fracture zones results in 15 percent gas production drop in 30 years. Also, it is observed that Klinkenberg effect and non-Darcy flow have insignificant effect on the modeling of shale gas reservoirs, whereas desorption has great contribution on long-term production. It is concluded that the minimum ingredients for an accurate shale reservoir modeling are considering gas desorption phenomena alongside with pressure-dependent permeability for the hydraulic and induced-fractures network. Our simple reservoir modeling approach helps in understanding complex behavior of flow mechanisms in shale plays. Also, this integrated model can be used during optimization of key factors in hydraulic fracturing process and fracture characterization by history matching of production.

We investigate the economic feasibility of the re-fracturing treatment of horizontal wells producing gas from unconventional reservoirs. As a result of advancements in horizontal completions and hydraulic fracturing, the U.S. has been able to economically develop several decades of worth of natural gas from shale deposits. However, a considerable concern has risen on the economic viability of shale gas development with the reasons associated to the very fast production declines as well as recent down-turns of natural gas prices beside the raise in additional costs of new technologies. Therefore, an economic analysis required to investigate the profitability of the secondary enhanced gas recovery method, re-fracturing treatment of unconventional gas resources within the U.S.Net present value (NPV) of cash flows and internal rate of return (IRR) are calculated for different assumed gas prices considering 20 years of natural gas production from a typical unconventional reservoir. A systematic comparison is made for three scenarios, 1) re-fracturing vs. no re-fracturing (the base case scenario) 2) combination of re-fracturing and drilling new well; and 3) time-dependent re-fracturing treatment. This paper incorporated the cost of re-fracturing treatment, the cost of drilling a new horizontal well, the water treatment cost, as well as the current and future price of natural gas in the model. Findings of this work can be used to optimally develop the U.S. shale gas assets. Moreover, operators can have access to an assessment to ensure the economic success of their unconventional horizontal wells in their future re-fracturing treatments. SPE-171009-MS 7