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The efficient use of depleted gas reservoirs for hydrogen storage is a promising solution for transitioning to carbon-neutral energy sources. This study proposes an analytical framework for estimating hydrogen storage capacity using a comprehensive material balance approach in depleted gas reservoirs. The methodology integrates basic reservoir engineering principles with thermodynamic considerations to accurately estimate hydrogen storage capacity in both volumetric drive and water drive gas reservoirs through an iterative approach based on mass conservation and the real gas law. This framework is implemented in a Python program, using the CoolProp library for phase behavior modeling with the Soave–Redlich–Kwong (SRK) equation of state. The methodology is validated with numerical simulations of a tank model representing the two reservoir drive mechanisms discussed. Also, a case study of a synthetic complex reservoir demonstrates the applicability of the proposed approach to real-world scenarios. The findings suggest that precise modeling of fluid behavior is crucial for reliable capacity estimations. The proposed analytical framework achieves an impressive accuracy, with deviations of less than 1% compared to estimates obtained through numerical simulations. Insights derived from this study can significantly contribute to the assessment of strategic decisions for utilizing depleted gas reservoirs for hydrogen storage. [ABSTRACT FROM AUTHOR]

The Embedded Discrete Fracture Model (EDFM) has emerged as a prominent piece of technology used for embedding the hydraulic behavior of rock joints in reservoir numerical models. This paper critically reviews its fundamentals, the latest developments, and opportunities for further research. The literature is extensive regarding novel algorithms attempting to reach more accurate and computationally effective estimates. While hydraulic fracture models seem suitable for their purposes, their assumptions might be excessively simplistic and unrealistic when assessing naturally fractured reservoirs. The paper begins by examining fractures as physical characteristics and the key mechanisms to be considered when integrating them into numerical flow simulators. The use of the EDFM technique shows promise for simulating capillary continuity and buoyancy effects in multiphase and multicomponent cases. However, there are significant limitations that hinder its widespread field-scale adoption for reservoir performance evaluation. In this regard, the lack of public-domain realistic benchmarks to validate and compare the potential of each method reinforces the difficulties of performing broader applications of the EDFM techniques in large-scale models. [ABSTRACT FROM AUTHOR]

Conventional Carbon Capture and Storage (CCS) operations use the direct injection of CO2 in a gaseous phase from the surface as a carbon carrier. Due to CO2 properties under reservoir conditions with lower density and viscosity than in situ brine, CO2 flux is mainly gravity-dominated. CO2 moves toward the top and accumulates below the top seal, thus reinforcing the risk of possible leakage to the surface through unexpected hydraulic paths (e.g., reactivated faults, fractures, and abandoned wells) or in sites without an effective sealing caprock. Considering the risks, the potential benefits of the interplay between CO2 and an aqueous solution of formate ions (HCOO¯) were evaluated when combined to control CO2 gravity segregation in porous media. Three combined strategies were evaluated and compared with those where either pure CO2 or a formate solution was injected. The first strategy consisted of a pre-flush of formate solution followed by continuous CO2 injection, and it was not effective in controlling the vertical propagation of the CO2 plume. However, the injection of a formate solution slug in a continuous or alternated way, simultaneously with the CO2 continuous injection, was effective in slowing down the vertical migration of the CO2 plume and keeping it permanently stationary deeper than the surface depth. [ABSTRACT FROM AUTHOR]

This study aims to numerically assess the impact of wettability and relative permeability hysteresis on hydrogen losses during underground hydrogen storage (UHS) and explore strategies to minimize them by using an appropriate cushion gas. The research utilizes the Carlson model to calculate the saturation of trapped gas and the Killough model to account for water hysteresis. By incorporating the Land coefficient based on laboratory-measured data for a hydrogen/brine system, our findings demonstrate a significant influence of gas hysteresis on the hydrogen recovery factor when H2 is used as a cushion gas. The base model, which neglects the hysteresis effect, indicates a recovery factor of 78% by the fourth cycle, which can be improved. In contrast, the modified model, which considers hysteresis and results in a trapped gas saturation of approximately 17%, shows a hydrogen recovery factor of 45% by the fourth cycle. Additionally, gas hysteresis has a notable impact on water production, with an observed 12.5% increase in volume in the model that incorporates gas hysteresis. Furthermore, optimization of the recovery process was conducted by evaluating different cushion gases such as CO2, N2, and CH4, with the latter proving to be the optimal choice. These findings enhance the accuracy of estimating the H2 recovery factor, which is crucial for assessing the feasibility of storage projects. [ABSTRACT FROM AUTHOR]

During oil and gas reservoir development, multi-stage horizontal wells (MFHWs) and hydraulic fracturing techniques can effectively increase estimated ultimate recovery. However, there still lacks an understanding of the three-dimensional (3D) pressure transient behaviors of multi-stage fractured horizontal wells with secondary fractures. To narrow this gap, a three-dimensional numerical well-test model based on a discrete fracture model and unstructured tetrahedral grids is developed to study the pressure transient behaviors of MFHWs with secondary fractures. The pressure transient solutions of MFHWs with secondary fractures have been demonstrated by model verifications. The results show that the proposed model can accurately capture the complex transient flow around fractures, including early radial flow that is not easily captured by two-dimensional numerical well test models. The proposed model classifies the flow regimes of a MFHW as: wellbore storage and skin effects, early radial flow, bilinear flow, linear flow, elliptical flow, pseudo radial flow, and pseudo-boundary dominated flow. It is found that the fracture geometry has a relatively large effect on the shape of the pressure derivative curve in this work. The hydraulic fracture half-length has the greatest impact on the pressure transient behaviors of the MFHW, followed by fracture height and secondary fracture half-length, as found in this study. Additionally, fracture parameters are evaluated, and actual well testing data are interpreted, taking into account the fracture height. This work is meaningful to understand the three-dimensional pressure transient behaviors of MFHWs with secondary fractures. [ABSTRACT FROM AUTHOR]