This study presents development and application of a fully coupled two-phase (methane and water) and poromechanics numerical model for the analysis of geomechanical impact on coalbed methane (CBM) production. The model considers changes in two-phase fluid flow properties, i.e., coal porosity, permeability, water retention, and relative permeability curves through changes in cleat fractures induced by effective stress variations and desorptioninduced shrinkage. The coupled simulator is first verified for poromechamics coupling and simulation parameters of a CBM reservoir model are calibrated by history matching against one year of CBM production field data from Shanxi Province, China. Then, the verified simulator and calibrated CBM reservoir model are used for predicting the impact of geomechanics on production rate for twenty years of continuous CBM production. The simulation results show that desorption-induced shrinkage is the dominant process in increasing permeability in the near wellbore region. Away from the wellbore, desorptioninduced shrinkage is weaker and permeability is reduced by pressure depletion and increased effective stress. A sensitivity analysis shows that for coal with a higher sorption strain, a larger initial Young's modulus and smaller Poisson's ratio promote the enhancement of permeability as well as the production rate. Moreover, the conceptual model of the cleat system, whether dominated by vertical cleats with permeability correlated to horizontal stress or with permeability correlated to mean stress can have a significant impact on the predicted production rate. Overall, the study clearly demonstrates and confirms the critical importance of considering geomechanics for an accurate prediction of CBM production. (1) A fully coupled two-phase flow and poromechanics model for methane recovery (2) Simulation parameters are calibrated by history matching against field data (3) The geomechanics behaviors significantly affect the prediction of CBM production

Understanding methane adsorption behavior on deep shales is crucial for estimating the original gas in place and enhancing gas recovery in deep shale gas formations. In this study, the methane adsorption on deep shales within the lower Silurian Longmaxi formation from the Sichuan Basin, South China was conducted at pressures up to 50 MPa. The effects of total organic carbon (TOC), temperatures, clay minerals, and moisture content on the adsorption capacity were discussed. The results indicated that the methane excess adsorption on deep shales increased, then reached its peak, and finally decreased with the pressure. The excess adsorption data were fitted using the adsorption models, and it was found that the Dubinin–Radushkevich (D–R) model was superior to other models in predicting the methane adsorption behavior. The methane adsorption capacities exhibited strong positive correlations with the TOC content and negative relationships with clay minerals. The methane excess adsorption decreased with the temperature, while the opposite trend would occur once it exceeded some pressure. The presence of the moisture content on deep shales sharply decreased the methane adsorption capacities, and the reduction of the adsorption capacity decreased with the pressure. The moisture would occupy the adsorption sites in the shale pores, which could result in the methane adsorption capacity that decreased.

CO 2-enhanced coalbed methane recovery, known as CO 2-ECBM, is a potential win-win approach for enhanced methane production while simultaneously sequestering injected anthropogenic CO 2 to decrease CO 2 emissions to the atmosphere. In this paper, CO 2-ECBM is simulated using a coupled thermal-hydrological-mechanical (THM) numerical model that accounts for multiphase (gas and water) flow and solubility, multicomponent (CO 2 and CH 4) diffusion and adsorption, as well as heat transfer and coal deformation. The coupled model is based on the TOUGH-FLAC simulator, applied here for the first time for modeling CO 2-ECBM. The capacity of the simulator for modeling methane production is first verified by code-to-code comparison with the generalpurpose finite element solver COMSOL. Then the TOUGH-FLAC simulator is applied in an isothermal simulation to study the variations in permeability evolution during a CO 2-ECBM operation, considering four different stress-dependent permeability models implemented into the simulator. Finally, the TOUGH-FLAC simulator is applied in non-isothermal simulations to model THM responses during a CO 2-ECBM operation. The simulations show that permeability evolution, mechanical stress, and deformation are all affected by changes in pressure, temperature and adsorption swelling, with adsorption swelling having the biggest impact. The calculated stress changes did not induce any mechanical failure in the coal seam except near the injection well in one case of a very unfavorable stress field. Keywords: Coupled THM model; CO 2 sequestration; CBM production; TOUGH-FLAC, CO 2-ECBM Highlight: (1) Coupled thermal-hydrological-mechanical (THM) numerical modeling of CO 2-ECBM (2) Application of the TOUGH-FLAC simulator for CO 2-enhanced coalbed methane recovery (3) Code-to-code comparison between TOUGH-FLAC and the finite element solver COMSOL (4) Mechanical failure occurs near the injection well in the coal seam with an extensional in situ stress state

of CO2 sequestration in coal seams: role of CO2-induced coal softening on injectivity, storage efficiency and caprock deformation. Greenhouse Gas Sciences & Technology., 7, 562-578 (2017). DOI: 10.1002/ghg. AbstractAn effective and safe operation for sequestration of CO 2 in coal seams requires a clear understanding of injection-induced coupled hydromechanical processes such as the evolution of pore pressure and permeability as well as induced caprock deformation. In this study, CO2 injection into coal seams was studied using a coupled flow-deformation model with a new stress-dependent porosity and permeability model that considers CO2-induced elastic property variation. . Based on triaxial compression tests of coal samples extracted from the site of the first enhanced coalbed methane field tests in China, a substantial (one-order-of-magnitude) softening of Young's modulus and increase of Poisson's ratio with adsorbed CO 2 content was observed. Such coal softening was considered in the numerical simulation through an exponential relation between elastic properties (Young's modulus and Poisson's ratio) and CO 2 pressure, considering that adsorbed CO 2 content is proportional to the CO 2 pressure. The results of the numerical simulation show that the combination of softening of the coal and enhancement of Poisson's ratio strongly affects the CO 2 sequestration performance, by decreases of injectivity and stored volume (cumulative injection) during first ten days of injection, and thereafter a softening mediated rebound in permeability tends to increase injectivity and storage with time. A sensitivity study showed that hydromechanical characteristics including large softening coefficient, high initial permeability and porosity, large initial Young's modulus and Poisson ratio and high injection pressure all contribute synergistically to increase CO 2 injectivity and adsorption in coal seams, but also result in larger caprock deformations. Overall, the study demonstrates the importance of considering the CO 2 -induced variations in elastic coal properties when analyzing the performance and environmental impact of a CO 2 -sequestration operation in uminable coal seams.

Efficiently and accurately understanding the fluid flow behavior in ultra-deep natural gas reservoirs is very challenging due to the complex geological environment and the intricate gas properties at high pressure. In this study, a fully coupled fluid flow and geomechanical model was developed to simulate complex production phenomena in ultra-deep natural gas reservoirs. Stress-dependent porosity and permeability models were applied, and then the governing equations of the model were incorporated into COMSOL Multiphysics. Furthermore, the model was verified by the reservoir depletion from the Keshen gas field in China, and the effects of reservoir properties and geomechanics on gas production were discussed. The results showed that the reservoir pressure and water saturation exhibited a significant funnel-shaped decline during the reservoir depletion. The higher relative permeability of the gas phase results in more methane gas production, thereby reducing the average pore pressure and gas saturation near the wellhead. When considering geomechanical effects, the production behavior significantly changes. The predictive value of gas production was higher when the reservoir rock deformation was ignored. The gas production exhibited strong positive correlations with reservoir porosity, fracture permeability, elastic modulus, and Poisson's ratio. Larger porosity, elastic modulus, and Poisson's ratio resulted in smaller deformation, while a smaller fracture permeability leads to larger deformation in ultra-deep natural gas reservoirs.

The quantitative characterization of adsorbed gas and free gas in shale reservoirs is a key issue in exploration and development of shale gas. Thus, the aforementioned topic is of great significance to the evaluation of reserves, the screening of favorable target areas, and the formulation of development plans. However, research on our current understanding of the quantities of adsorbed gas and free gas in deep shale gas reservoirs is still lacking. To address this problem, deep shales from the Longmaxi Formation in southern China were collected to conduct high-pressure isothermal adsorption experiments. The high-pressure isothermal adsorption model was used to describe the adsorption behavior of methane in deep shales, and the adsorbed gas and free gas in the deep shales were characterized quantitatively. The effects of temperature, pressure, and moisture on the adsorbed gas and the density of the free gas were analyzed. The results indicated that the excess adsorption isotherm curve for methane in deep shales increased and then decreased with the increase of pressure, and the modified Langmuir adsorption model may be used to describe the high-pressure adsorption behaviors. The adsorbed gas in shales decreases gradually with the increase of pressure, and the proportion of adsorbed gas and free gas is between 23 and 74% when the pressure reaches 50 MPa. The adsorbed gas in deep shales decreases with an increase of temperature, and the presence of water greatly reduces the adsorption capacity of the deep shale. The pore space occupied by the free gas in shale increased with the increase in the density of the free phase, and the ratio of the adsorbed gas to the free gas decreased. This research provides a useful reference for explaining how to best evaluate shale gas reservoirs, estimate the reserves in deep shales, and evaluate the adsorption and flow capacity of deep shale gas.

No abstract

No abstract