Storage and Production Aspects of Reservoir Fluids in Sedimentary Core Rocks

Summary Microscopic flow simulation of digital rock cores plays a crucial role in understanding and predicting fluid behavior in porous media, applicable across a range of energy technologies including carbon sequestration, hydrogen storage, geothermal energy, and fuel cells. Permeability is a key parameter for quantifying fluid flow in porous media. Utilizing the Stokes equation in 3D digital rocks to perform pore-scale simulations can estimate the core’s equivalent permeability, but simulations of digital cores with complex pore structures and a large number of voxels require extremely high computational costs. This study introduces a novel method for microscopic flow simulation in digital rocks, which simplifies the 3D pore-scale simulation into multiple decoupled 2D ones. By this decoupled simulation approach, the expensive simulation based on the Stokes equation is conducted only on 2D domains, and the final 3D simulation of the Darcy equation using the finite difference method (FDM) is very cheap. The proposed method is particularly suitable for isotropic or relatively homogeneous rock samples, enabling accurate estimation of equivalent permeability and reconstruction of fine-scale pressure and velocity fields. It also offers significant advantages in computational efficiency, making large-scale and complex flow simulations feasible. Keywords Stokes equation, Velocity field, Equivalent permeability, Digital rock, Microscopic flow simulation

As conventional gas supplies decline, unconventional sources of gas, like coalbed methane (CBM), will become increasingly important in Canada. Canada has over 700 Tcf of CBM gas resource in place, comparable to the U.S. resource. Canada now has the world's largest "dry" coal play and it is estimated (as shown below) that CBM will grow to 2 - 3 Bcf/d in production over the next 10 – 20 years and lead to recovery of up to 75 Tcf of gas. Since 2000, increased drilling activity has led to over 3,000 CBM wells and 150 MMcf/d of CBM production in Canada today, with both estimated to grow substantially in 2005 and beyond. CBM will become an increasingly important part of Canada's gas supply. Introduction Coalbed methane (CBM) is simply the natural gas that is generated by coal seams during the coalification process. It is "sweet gas" (not sour), is largely comprised of methane (>90%), and is similar to the natural gas that is burned in homes. In Alberta, the Department of Energy (DOE) refers to CBM as natural gas from coal, or NGC, to associate it with existing regulations which govern the production of natural gas. In British Columbia (BC), it is referred to by the Ministry of Energy and Mines (MEM) as coalbed gas, or CBG. Regardless of the name used, it is the same gas. CBM reservoirs are classified as "unconventional" and have gas storage and production mechanisms that distinguish them from conventional reservoirs. Most of the gas in coal is stored in a sorbed state within the coal matrix, physically attached to the complex internal surfaces of the coal as a function of pressure, characterized by sorption isotherms(1, 2). Coals which are suitable for CBM production are naturally fractured, with closely spaced natural fractures, or "cleats," which provide pathways for gas flow from the coal matrix. In many cases, but not all, these cleats are initially full of water, which must be produced to reduce the pressure around the coal matrix allowing the sorbed gas to desorb and become free gas which can then be produced. The gas storage and production mechanisms of coals are comprehensively covered in References (1) and (2) and elsewhere in the oil and gas literature. In Canada, commercial production of CBM has only recently begun. The objective of this paper is to provide a summary of the major coal groups being targeted for development in Canada and an update on the recent evaluation and development. Predictions of future performance will also be presented. CBM History in the U.S. Commercial development of CBM began in the U.S. in the 1980s. Initial efforts to remove the gas from coals were funded by the U.S. Bureau of Mines primarily to improve mine safety. As natural gas value increased, the research began to focus on capturing the CBM for commercial use, and hundreds of millions of dollars were dedicated to research and development projects by the U.S. DOE, the Gas Research Institute (GRI), and the industry(3–7).

For shale gas reservoirs, the combined study of adsorbed and absorbed gases provides a better description of gas storage mechanism and characterizes the original gas-in-place. Two shale samples were taken and a series of isothermal gas sorption, porosity and total organic carbon experiments were conducted. Then, gas sorption and stress equations were combined to evaluate the mechanism of gas storage by analyzing the effective porosity of sorbed gas. Absorbed gas is usually linked with adsorbed gas and about 22% is contributing in connection with total gas storage capacity but previous studies had ignored such gas in calculation of total gas storage capacity. Therefore, present study is considered the sorbed gas which is the combination of adsorbed and absorbed gases and presenting new sights to comprehend the gas storage mechanism and to characterize the shale gas-in-place. Results revealed from this study that sorption model is providing better descriptions than Langmuir model and close matched with experimental data. Analysis of effective porosity is important to depict the shale gas reservoirs. Shale gas-in-place was measured using different methods e.g. previous and new proposed method and observed that when using new proposed method the total gas storages were found higher at low pressure because of absorbed gas input as compare to previous methods. Further, the total gas storages capacity is increases further according to the adsorption and absorption behavior as pressure increases. This study presents sorbed gas mechanism and might be useful for characterizing the shale gas reservoirs.

Process-based reconstruction of digital rock based on discrete element method considering thermal-mechanical coupling effect and actual particle shape

Simultaneous determination of permeability and diffusivity subject to dynamic sorption in gas shales

ABSTRACT: In the context of the global energy transition and the drive towards achieving net-zero carbon emissions, unconventional gas extraction methods have gained significant attention. This paper presents an advanced fully coupled thermo-hydro-mechanical (THM) model for enhancing methane (CH4) production and simultaneously storing carbon dioxide (CO2) in fractured coal seams. Our innovative approach integrates the complex interactions between thermal, hydraulic, and mechanical processes within the fracture network, addressing the dynamic evolution of matrix and fracture permeability ratios. By injecting CO2 into coal seams, methane is desorbed and produced more efficiently, while CO2 is securely stored within the fractures and pores of the coal matrix. The proposed model investigates the dual benefits of enhanced CH4 production and CO2 storage, offering a sustainable solution for energy production and greenhouse gas mitigation. Comprehensive simulations demonstrate the model's effectiveness in improving gas recovery rates and provide insights into the long-term stability of CO2 storage in geological formations. This study highlights the critical role of THM coupling in fracture networks and the dynamic permeability changes, ensuring a robust and efficient process for both gas extraction and CO2 sequestration, thereby contributing to the goals of the energy transition and net-zero carbon targets. 1. INTRODUCTION The burgeoning energy demands of rapidly developing nations such as China and India have propelled coal seam gas (CSG), primarily methane (CH4), to the forefront as a significant energy resource. Simultaneously, escalating concerns over climate change have underscored the urgency for effective carbon dioxide (CO2) sequestration methods. Injecting CO2 into coal seams emerges as a promising strategy that not only facilitates long-term CO2 storage but also enhances CH4 recovery, offering a dual benefit of energy production and greenhouse gas mitigation (Gunter et al., 1998; Luo et al., 2013). Despite the potential, the application of CO2 enhanced CH4 recovery and the simultaneous decarbonization faces substantial obstacles. Key among these are the complex multiphysics phenomena inherent in the process, including gas adsorption/desorption, diffusion, and the mechanical deformation of coal matrices (Bustin et al., 2016). The multiscale heterogeneity of coal seams—characterized by variations in porosity, permeability, and the presence of natural fractures—further complicates predictive modelling and optimization efforts. These challenges necessitate sophisticated modelling approaches to accurately simulate and manage the gas transport and storage mechanisms within coal seams.

Unconventional petroleum reservoirs, such as shale gas and tight oil reservoirs, have changed the entire energy equation in the world. An accurate and efficient reservoir simulator is essential for the development and management of these reservoirs and the optimization of their production schedules. However, the gas storage and transport mechanisms in ultra-tight matrix, including gas adsorption/desorption, non-Darcy flow, and surface diffusion, are different from those in conventional petroleum reservoirs. In addition, hydraulic fracturing techniques are often required to achieve their economical production, which leads to existence of complex fracture networks in the unconventional reservoirs. These features of unconventional reservoirs make their accurate numerical simulations a big challenge. In this paper, we develop a simulator for fractured unconventional reservoirs, which takes the specific gas storage and transport mechanisms into consideration, employs a multiple interacting continua (MINC) model to handle well connected natural fractures, utilizes an embedded discrete fracture model to simulate large-scale disconnected hydraulic fractures, and uses a coupled model to efficiently describe multi-scale fractures with irregular geometries. To reduce the computational time, parallel computing techniques are also employed, with which large-scale reservoir simulation cases can be finished in practical time. From the numerical experiments, we can see that reasonable physical phenomena is captured and accurate predictions are performed by this simulator.

The effect of poroelastic properties of the shale matrix on gas storage and transport mechanisms has gained significant attention, especially during history-matching and hydrocarbon production forecasting in unconventional reservoirs. The common oil and gas industry practice in unconventional reservoir simulation is the extension of conventional reservoir simulation that ignores the dynamic behavior of matrix porosity and permeability as a function of reservoir effective net stress. This approach ignores the significant impact of the poroelastic characteristics of the shale matrix on hydrocarbon production. The poroelastic characteristics of the shale matrix highly relate to the shale matrix geomechanical properties, such as the Young’s Modulus, Poisson’s ratio, bulk modulus, sorption behavior, total organic content (TOC), mineralogy and presence of natural fractures in the multi-scale shale structure. In this study, in order to quantify the effect of the poroelasticity of the shale matrix on gas production, a multi-continuum approach was employed in which the shale matrix was divided into organic materials, inorganic materials and natural fractures. The governing equations for gas transport and storage in shale were developed from the basic fundamentals of mass and momentum conservation equations. In this case, gas transport in organics was assumed to be diffusive, while gas transport in inorganics was governed by convection. Finally, a fracture system was added to the multi-scale shale gas matrix, and the poroelastic effect of the shale matrix on transport and storage was investigated. A modified Palmer and Mansoori model (1998) was used to include the pore compression, matrix swelling/shrinkage and desorption-induced deformation of shale organic matter on the overall pore compressibility of the shale matrix. For the inorganic part of the matrix, relations between rock mechanical properties and the pore compressibility were obtained. A dual Langmuir–Henry isotherm was also used to describe the sorption behavior of shale organic materials. The coupled governing equations of gas storage and transport in the shale matrix were then solved using the implicit finite difference approach using MATLAB. For this purpose, rock and fluid properties were obtained using actual well logging and core analysis of the Marcellus gas well. The results showed the importance of the poroelastic effect on the pressure response and rate of gas recovery from the shale matrix. The effect was found to be mainly due to desorption-induced matrix deformation at an early stage. Coupling the shale matrix gas production including the poroelastic effect in history-matching the gas production from unconventional reservoirs will significantly improve engineering completion design optimization of the unconventional reservoirs by providing more accurate and robust production forecasts for each hydraulic fracture stage.

Field observations frequently demonstrate stress fluctuations resulting from the reservoir depletion. The development of reservoirs, particularly the completion of infill wells and refracturing, can be significantly impacted by stress changes in and around drainage areas. Previous studies mainly focus on plane fractures and few studies consider the influence of complex transport and storage mechanism and irregular fracture geometry on stress evolution in shale gas reservoirs. Based on the embedded discrete fracture model (EDFM) and finite-volume method (FVM), a coupled geomechanics/fluid model has been successfully developed considering the adsorption, desorption, diffusion and slippage of shale gas. This model achieves coupling simulation of natural fractures, hydraulic fractures with complex geometry, storage and transport mechanism, reservoir stress, and pore-elastic effect. The open-source software OpenFOAM is used as the main solver for this model. The stress calculation and productivity simulation of the model are verified by the classical poroelasticity problem and the simulation results of published research and commercial simulator with EDFM respectively. The simulation results indicate that σxx, σyy, σxy and Δσ changes with time and space due to the time effect and anisotropy of formation pressure depletion; Due to the influence of different mechanisms on shale gas storage and transport, the reservoir pressure and stress distribution under different mechanisms are different; Among them, the stress with full mechanisms differs the most compared to the stress without any mechanism. The reservoir with stronger stress sensitivity (smaller Biot coefficient) is less sensitive to formation pressure depletion, and the stress variation range is smaller. For reservoirs with weak stress sensitivity, formation pressure depletion is more likely to lead to stress reversal. Under the influence of fracture geometry, the pressure depletion regions caused by the three types of fracture geometry are approximately rectangular, parallelogram and square, respectively. The corresponding σxx, σyy and Δσ also have great differences in spatial distribution and values. Therefore, the time effect, shale gas storage and transport mechanism and the influence of complex fracture geometry should be considered when predicting pressure depletion induced stress under the condition of simultaneous production. This study is of great significance for understanding the evolution law of stress induced by pressure consumption, as well as the design of infill wells and repeated fracturing.

Hydrogen (H2) is a clean source of energy and a promising solution in the energy transition due to its vast energy content and potential of zero greenhouse gas emissions. Storing hydrogen to meet present and future energy demands requires a large storage volume which is only available in subsurface reservoirs such as salt caverns, depleted oil and gas fields, and deep saline aquifers. Despite the high demand for Underground Hydrogen Storage (UHS) technology as part of a full H2-value chain, there is especially limited knowledge of the transport behavior of hydrogen in porous media [1]. With its charging and discharging operations, the storage of hydrogen in a porous reservoir formation undergoes a transient flow process, influenced by coupled thermo-hydro-mechanical processes between hydrogen, the formation fluid, the solid components of the rock, and the prevailing temperature and pressure regime, which repetitively changes under geotechnical utilization [2]. In consequence of cyclic storage operations, variations in effective mechanical stresses can affect the pore space geometry and may lead to irreversible deformation and weakening of reservoir and cap rocks.Here, we present first results of an experimental laboratory study focussing on fluid substitution experiments (gas replacing brine) on various sandstone core samples sourced from Bad Bentheim and the Stuttgart formation. The study was specifically designed to replicate the unique reservoir conditions of the Stuttgart formation at the Ketzin site in Germany (confining pressure = 150 bar, pore pressure = 25 to 75 bar, temperature = 37 °C). In the frame of the national-funded GEOZeit project, long-term flow experiments are carried out to determine  the evolution of relative permeability of H2-brine and CH4-brine systems in dependence of the number of load cycles. Alongside, measurements of electrical resistivity and ultrasonic wave velocities at each brine/gas saturation state are performed. This enable us to derive the saturation level and to understand the spatial distribution of liquid and gaseous phases in the pore space of our sample material. The experiments are complemented by a range of additional tests, including chemical analyses and microstructural investigations using XRD, SEM, and optical microscopy. Our results are expected to improve the understanding of coupled hydromechanical processes and their impact on reservoir properties during geotechnical operations, and to also provide the necessary parameters for large-scale modelling and up-scaling, required to assess the feasibility of storage, production, and monitoring of hydrogen gas in porous geological formations. [1] Heinemann, N., Alcalde, J., Miocic, J. M., Hangx, S. J. T., Kallmeyer, J., Ostertag-Henning, C., Strobel, G. J., Hassanpouryouzbanda, A., Schmidt-Hattenberger, C., Edlmann, K., Wilkinson, M., Thaysen, E. M., Bentham, M., Haszeldine, R. S., Carbonell, R., Rudloff, A. (2021). Enabling large-scale hydrogen storage in porous media – The scientific challenges. Energy & Environmental Science, 14(2), 853–864. https://doi.org/10.1039/D0EE03536J
 [2] Ershadnia, R., Singh, M., Mahmoodpour, S., Meyal, A., Moeini, F., Hosseini, S. A., Sturmer, D. M., Rasoulzadeh, M., Dai, Z., Soltanian, M. R. (2023). Impact of geological and operational conditions on underground hydrogen storage. International Journal of Hydrogen Energy, 48 (4), 1450-1471. https://doi.org/10.1016/j.ijhydene.2022.09.208.

Storage of hydrogen, natural gas, and carbon dioxide – Geological and legal conditions

Investigation of gas residuals in sandstone formations via X-ray core-flooding experiments: Implication for subsurface hydrogen storage

The role of underground salt caverns for large-scale energy storage: A review and prospects

The understanding of single and multiphase flow behavior in porous media has been improved with the development of in situ saturation measurement techniques such as X-ray Computed Tomography (CT), mainly in specialized core analysis. On the other hand, effective experimental designs are necessary to advance knowledge on operations of Water Alternating Gas (WAG) and Carbon Capture and Storage (CCS) projects. The present study addresses the determination of petrophysical properties concerning fluid storage and displacement in carbonates by using CT images taken during core flooding runs. Eight displacement experiments were carried out in long core to analyze N2 and CO2 flooding under reservoir conditions (from 700 to 7000 psi) at temperatures of 22°C and 65°C. A carbonate core sample of 5 cm diameter by 76 cm long with porosity of 15% from a carbonate outcrop analogous to Brazilian pre-salt reservoir rocks was used in the displacement tests. The mixing of CO2 and brine was a key experimental procedure to evaluate the CO2 trapping. The parameters of porosity, permeability, distribution of initial non-wetting phase, irreducible brine saturation, trapped non-wetting phase saturation, displacement effectiveness and the effect of saturation history were investigated during drainage-imbibition cycles similar to those in the WAG process. Values for Land trapping coefficients were evaluated from on-line X-ray CT scan images. The trapped non-wetting phase saturation ranged from 8 to 16 percent for both N2 and CO2 floods. The results reveal that trapped saturations are higher for higher pressures and higher temperatures. Cross-section images show the enlargement of pore spaces induced by brine-CO2 flooding with a consequent increase of the trapping capacity. Porosity and permeability changed after a CO2 injection, along with the observed formation of short wormholes. In addition, some degree of dissolution of the rock was verified and solid particles of carbonate salts were collected at the outlet of CO2-brine runs. The results obtained emphasize the importance of using high-resolution saturation imaging to provide the main parameters for the experimental evaluation of CO2-WAG processes in carbonates. Introduction Carbon dioxide (CO2) flooding has been considered as one of the most important processes for enhancing oil recovery (EOR) from carbonate reservoirs since the 1980's [1]. Its use, though, is most of the time limited by the availability of an economic source. In the Brazilian pre-salt reservoirs, e.g., Tupi field, the solution gas contains a high proportion of CO2 [2]. The re-injection of the produced CO2 in this case represents the solution of two problems at once. It solves the discard problem, which is of growing environmental concern, at the same time it provides the resource for improving the difficult oil recovery. Both EOR and environmental processes demand new studies covering the application of WAG injection and the safety of geological storage of CO2. The alternating injection of water and gas was conceived in order to compensate the counter tendencies of gas rising upward and water falling downward within the reservoir by ‘breaking-up’ the continuous slug of gas into smaller slugs by alternating water banks [3]. On the other hand, injecting water with miscible gas reduces the instability of the gas/oil displacement, improving the overall sweep efficiency.

Organic matter (OM) serves as the primary source of gaseous hydrocarbons in shales. Fundamental understanding of its permeability and gas production characteristics is vital to optimize shale gas exploitation. The focused ion beam scanning electron microscopy (FIB-SEM) imaging can resolve OM macropores with pore radii ranging from tens to hundreds of nanometers, while pore sizes of sub-resolution OM can be characterized using low-temperature gas adsorption. In this work, we focus on multiscale pore structures of OM and contribute to the development of an efficient pore-network-continuum model for simulating nonlinear gas flow in multiscale OM digital rocks, along with its fully coupled implicit numerical implementation. To demonstrate the influence of OM pore structures on its permeability and transient gas production, we select three types of OM featured by their distinct porosities, connectivity of macropores, and pore morphologies. We show that the high-porosity OM with interconnected macropores exhibits markedly different intrinsic permeability, mechanisms of apparent permeability, gas storage, and production behaviors compared to the medium-porosity and low-porosity OM. Moreover, we propose an empirical formula for OM apparent permeability with respect to an effective characterization length used in the calculation of Knudsen number, which will be the key input to the representative elementary volume (REV) size modeling of shale matrix.