The low recovery and high oil volume remaining in shale oil reservoirs are a strong motivation to investigate the application of enhanced oil recovery methods in these reservoirs. This paper presents the potential of applying cyclic CO 2 injection to improve the recovery factors of shale oil reservoirs. Cyclic CO 2 injection could be an effective technique to improve the oil recovery of this type of reservoirs for several reasons. It is a single-well process; well-to-well connectivity is not required, the hydraulic and natural fractures provide a large contact area for the injected gas to penetrate and diffuse into the lowpermeability matrix; and the payback period of the cyclic CO 2 injection process is short compared with the other flooding process. Very limited numerical and laboratory studies are available to study the feasibility of CO 2 huff-n-puff for shale oil reservoirs. Latest numerical studies have revealed that CO 2 huff-n-puff technique could be an effective method to increase recovery factors of shale oil reservoirs. In order to support the numerical studies results, a laboratory study was conducted using shale cores from Mancos and Eagle Ford. The aim of this study is to evaluate the potential of cyclic CO 2 injection. Many design parameters such as soaking period, soaking pressure, and numbers of cycles were considered to evaluate the feasibility of cyclic CO 2 injection. The laboratory results indicate that cyclic CO 2 injection improved recovery of shale oil cores from 33% to 85% depending on the shale core type and the other operating parameters. These results have shown that cyclic CO 2 injection is a promising method to improve the recovery of shale oil reservoirs. Also this study aided to develop a better understanding of the performance of cyclic CO 2 in shale oil reservoirs.

Low oil recovery in shale oil reservoirs and vast shale reservoir volumes stimulate our efforts to investigate the application of enhanced oil recovery methods in shale oil reservoirs. A recent numerical study has indicated that cyclic gas injection could be an effective method to increase the oil recovery of shale oil reservoirs, and gas channeling can be mitigated. This paper presents our experimental verification and quantification of the potential to improve oil recovery by cyclic gas injection in shale oil reservoirs. Core plugs of Barnett, Marcos and Eagle Ford shales were used. The oil used was Mineral oil (Soltrol 130) and the gas used was Nitrogen. Unfractured cores were used in the experiments. The effects of cyclic time and injection pressure on oil recovery, among other parameters, were investigated. Our results also showed that cycle gas injection could increase the recovery from 10 to 50% depending on the injection pressure and shale core type. This study shows that one of the important mechanisms of cyclic gas injection is the pressure effect that causes a large pressure drawdown during the production phase. The cyclic gas injection provides an effective and practical method to improve oil recovery in shale reservoirs because the gas needed is available in liquid-rich shale plays.

Summary Nanoscale porosity and permeability play important roles in the characterization of shale-gas reservoirs and predicting shale-gas-production behavior. The gas adsorption and stress effects are two crucial parameters that should be considered in shale rocks. Although stress-dependent porosity and permeability models have been introduced and applied to calculate effective porosity and permeability, the adsorption effect specified as pore volume (PV) occupied by adsorbate is not properly accounted. Generally, gas adsorption results in significant reduction of nanoscale porosity and permeability in shale-gas reservoirs because the PV is occupied by layers of adsorbed-gas molecules. In this paper, correlations of effective porosity and permeability with the consideration of combining effects of gas adsorption and stress are developed for shale. For the adsorption effect, methane-adsorption capacity of shale rocks is measured on five shale-core samples in the laboratory by use of the gravimetric method. Methane-adsorption capacity is evaluated through performing regression analysis on Gibbs adsorption data from experimental measurements by use of the modified Dubinin-Astakhov (D-A) equation (Sakurovs et al. 2007) under the supercritical condition, from which the density of adsorbate is found. In addition, the Gibbs adsorption data are converted to absolute adsorption data to determine the volume of adsorbate. Furthermore, the stress-dependent porosity and permeability are calculated by use of McKee correlations (McKee et al. 1988) with the experimentally measured constant pore compressibility by use of the nonadsorptive-gas-expansion method. The developed correlations illustrating the changes in porosity and permeability with pore pressure in shale are similar to those produced by the Shi and Durucan model (2005), which represents the decline of porosity and permeability with the increase of pore pressure in the coalbed. The tendency of porosity and permeability change is the inverse of the common stress-dependent regulation that porosity and permeability increase with the increase of pore pressure. Here, the gas-adsorption effect has a larger influence on PV than stress effect does, which is because more gas is attempting to adsorb on the surface of the matrix as pore pressure increases. Furthermore, the developed correlations are added into a numerical-simulation model at field scale, which successfully matches production data from a horizontal well with multistage hydraulic fractures in the Barnett Shale reservoir. The simulation results note that without considering the effect of PV occupied by adsorbed gas, characterization of reservoir properties and prediction of gas production by history matching cannot be performed reliably. The purpose of this study is to introduce a model to calculate the volume of the adsorbed phase through the adsorption isotherm and propose correlations of effective porosity and permeability in shale rocks, including the consideration of the effects of both gas adsorption and stress. In addition, practical application of the developed correlations to reservoir-simulation work might achieve an appropriate evaluation of effective porosity and permeability and provide an accurate estimation of gas production in shale-gas reservoirs.

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The is wide consensus that combustion of fossil fuels and rising greenhouse gas emissions in the atmosphere are accelerating global warming. To avoid the dilemma of need for fossil fuels to provide energy supply and the need to reduce fossil fuel related emissions, it is critical to promote renewable energy as a viable option to satisfy the world's energy requirements. However, employing renewables to generate power necessitates the use of bulk storage to accommodate discrepancies related to where and when renewable energy is produced versus where and when it is needed. Underground hydrogen storage has the potential to support establishment of hydrogen as a reliable source of clean energy across the planet. Where present, depleted oil and gas reservoirs, due to their existing infrastructure, can prove to be an attractive asset for underground hydrogen storage. One of the main challenges involved in the storage of hydrogen in the depleted oil and gas reservoirs is related to wellbore integrity. When hydrogen is injected or produced in the subsurface, it may get bin contact with cement around the wellbores. Hence it is necessary to investigate the effects of hydrogen interacting with the cement sheath. To study this in the laboratory, a core holder capable of simulating the wellbore conditions is used to conduct the tests. A 2" long, 1.5" diameter cement sample was placed inside the core holder and hydrogen was injected into it. Hydrogen was also injected into wet cement slurry to investigate possible stability of the cement samples. The effects of injecting hydrogen on set cement are studied using a CT Scanner which demonstrates if there is any formation of cracks and micro-annuli in the cement. The cement sample is crushed afterwards, and the presence of hydrogen particles in the structure of cement is evaluated by X -Ray Diffraction. A neat 15.5 lbs./gal Class "H" cement which is common in the industry is used in this study. Well integrity is a key success factor to establish the viability of underground hydrogen storage in the subsurface. For that we analyzed if the cement is good enough for hydrogen to be stored in depleted oil and gas reservoirs. We further studied the integrity of newly drilled wells when exposed to hydrogen.

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Although stress-dependent porosity and permeability have been applied to majority of models to calculate effective porosity and permeability, effect of adsorbed gas specified as pore volume occupied by adsorbate is not properly accounted. However, nanoscale porosity and permeability of shale rocks would be significantly reduced, since the pore volume is occupied by layers of adsorbed gas molecules.In this paper, we combine stress and adsorption effects to establish a new correlation of shale porosity and permeability. We calculate the stress-dependent pore volume with a constant pore compressibility and obtain the volume of adsorbate from doing regression analysis for density of adsorbed gas by Dubinin-Astakhov (D-A) equation under the supercritical condition. Lab experiments for methane adsorption in shale are measured by five real core samples. The data of Gibbs adsorption obtained by experiments is converted to absolute adsorption so that it could be used to generate the correlation of stress-dependent porosity and permeability including consideration of adsorption effect.The new generated correlation illustrates that the trend of changes in porosity and permeability with pore pressure is quite similar to the trend calculated by Shi-Durucan (S-D) model in application to coalbed methane, which indicates that porosity and permeability decrease with the increase of pore pressure. This tendency is the inverse of changes in stress-dependent porosity and permeability in relation to pore pressure, which demonstrates that adsorption has a larger influence on pore volume than stress, because more gas attempts to adsorb on surface area of matrix as pore pressure increases. The new correlation is added into a numerical model in field-scale, which successfully matches production data from a horizontal well with multistage hydraulic fractures in Barnett shale reservoir. The simulation results point out that without considering the impact of pore volume occupied by adsorbed gas, cumulative gas production would be greatly overestimated during economical producing period in shale gas reservoirs.Thus, overestimation of porosity and permeability in shale might be avoided by applying the new correlation considering both stress and adsorption effects. The correlation incorporated into numerical simulators could provide accurate estimation and evaluation of gas production.