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Title: Coupled thermal–hydrological–mechanical modeling of CO 2 -enhanced coalbed methane recovery

Abstract

CO 2 -enhanced coalbed methane recovery, also 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 into the atmosphere. Here, CO 2 -ECBM is simulated using a coupled thermal–hydrological–mechanical (THM) numerical model that considers multiphase (gas and water) flow and solubility, multicomponent (CO 2 and CH 4 ) diffusion and adsorption, heat transfer and coal deformation. The coupled model is based on the TOUGH-FLAC simulator, which is applied here for the first time to model CO 2 -ECBM. The capacity of the simulator for modeling methane production is verified by a code-to-code comparison with the general-purpose 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 while considering four different stress-dependent permeability models that have been 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.Our simulations show that the permeability evolution, mechanical stress, and deformation are all affected by changes in pressure, temperature and adsorption swelling, with adsorption swelling having the largest effect.more » The calculated stress changes do not induce any mechanical failure in the coal seam, except near the injection well in one case of a very unfavorable stress field.« less

Authors:
ORCiD logo [1];  [2];  [2];  [3]
  1. China Univ. of Mining and Technology, Jiangsu (China). key Lab. of Coal-based CO2 Capture and Geological Storage, State Key Lab. for Geomechanics and Deep Underground Engineering; Lawrence Berkeley National Lab. (LBNL), Berkeley, CA (United States). Energy Geosciences Division
  2. Lawrence Berkeley National Lab. (LBNL), Berkeley, CA (United States). Energy Geosciences Division
  3. China Univ. of Mining and Technology, Jiangsu (China). key Lab. of Coal-based CO2 Capture and Geological Storage, State Key Lab. for Geomechanics and Deep Underground Engineering
Publication Date:
Research Org.:
Lawrence Berkeley National Lab. (LBNL), Berkeley, CA (United States)
Sponsoring Org.:
USDOE Office of Fossil Energy (FE), Clean Coal and Carbon (FE-20)
OSTI Identifier:
1379888
Grant/Contract Number:
AC02-05CH11231
Resource Type:
Journal Article: Accepted Manuscript
Journal Name:
International Journal of Coal Geology
Additional Journal Information:
Journal Volume: 179; Journal Issue: C; Journal ID: ISSN 0166-5162
Publisher:
Elsevier
Country of Publication:
United States
Language:
English
Subject:
01 COAL, LIGNITE, AND PEAT; 58 GEOSCIENCES; Coupled THM model; CO2 sequestration; CBM production; TOUGH-FLAC; CO2-ECBM

Citation Formats

Ma, Tianran, Rutqvist, Jonny, Oldenburg, Curtis M., and Liu, Weiqun. Coupled thermal–hydrological–mechanical modeling of CO 2 -enhanced coalbed methane recovery. United States: N. p., 2017. Web. doi:10.1016/j.coal.2017.05.013.
Ma, Tianran, Rutqvist, Jonny, Oldenburg, Curtis M., & Liu, Weiqun. Coupled thermal–hydrological–mechanical modeling of CO 2 -enhanced coalbed methane recovery. United States. doi:10.1016/j.coal.2017.05.013.
Ma, Tianran, Rutqvist, Jonny, Oldenburg, Curtis M., and Liu, Weiqun. 2017. "Coupled thermal–hydrological–mechanical modeling of CO 2 -enhanced coalbed methane recovery". United States. doi:10.1016/j.coal.2017.05.013.
@article{osti_1379888,
title = {Coupled thermal–hydrological–mechanical modeling of CO 2 -enhanced coalbed methane recovery},
author = {Ma, Tianran and Rutqvist, Jonny and Oldenburg, Curtis M. and Liu, Weiqun},
abstractNote = {CO 2 -enhanced coalbed methane recovery, also 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 into the atmosphere. Here, CO 2 -ECBM is simulated using a coupled thermal–hydrological–mechanical (THM) numerical model that considers multiphase (gas and water) flow and solubility, multicomponent (CO2 and CH 4 ) diffusion and adsorption, heat transfer and coal deformation. The coupled model is based on the TOUGH-FLAC simulator, which is applied here for the first time to model CO 2 -ECBM. The capacity of the simulator for modeling methane production is verified by a code-to-code comparison with the general-purpose 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 while considering four different stress-dependent permeability models that have been 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.Our simulations show that the permeability evolution, mechanical stress, and deformation are all affected by changes in pressure, temperature and adsorption swelling, with adsorption swelling having the largest effect. The calculated stress changes do not induce any mechanical failure in the coal seam, except near the injection well in one case of a very unfavorable stress field.},
doi = {10.1016/j.coal.2017.05.013},
journal = {International Journal of Coal Geology},
number = C,
volume = 179,
place = {United States},
year = 2017,
month = 5
}

Journal Article:
Free Publicly Available Full Text
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  • This study presents the development and application of a fully coupled two-phase (methane and water) flow, transport, and poromechanics num erical model for the analysis of geomechanical impacts 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 desorption-induced shrinkage. The coupled simulator is first verified for poromechanics 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,more » the verified simulator and the calibrated CBM reservoir model are used for predicting the impact of geomechanics on the 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, desorption-induced 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 a smaller Poisson's ratio promote the enhancement of permeability as well as an increased 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.« less
  • Development of enhanced geothermal systems (EGS) will require creation of a reservoir of sufficient volume to enable commercial-scale heat transfer from the reservoir rocks to the working fluid. A key assumption associated with reservoir creation/stimulation is that sufficient rock volumes can be hydraulically fractured via both tensile and shear failure, and more importantly by reactivation of naturally existing fractures (by shearing) to create the reservoir. The advancement of EGS greatly depends on our understanding of the dynamics of the intimately coupled rock-fracture-fluid system and our ability to reliably predict how reservoirs behave under stimulation and production. In order to increasemore » our understanding of how reservoirs behave under these conditions, we have developed a physics-based rock deformation and fracture propagation simulator by coupling a discrete element model (DEM) for fracturing with a continuum multiphase flow and heat transport model. In DEM simulations, solid rock is represented by a network of discrete elements (often referred as particles) connected by various types of mechanical bonds such as springs, elastic beams or bonds that have more complex properties (such as stress-dependent elastic constants). Fracturing is represented explicitly as broken bonds (microcracks), which form and coalesce into macroscopic fractures when external load is applied. DEM models have been applied to a very wide range of fracturing processes from the molecular scale (where thermal fluctuations play an important role) to scales on the order of 1 km or greater. In this approach, the continuum flow and heat transport equations are solved on an underlying fixed finite element grid with evolving porosity and permeability for each grid cell that depends on the local structure of the discrete element network (such as DEM particle density). The fluid pressure gradient exerts forces on individual elements of the DEM network, which therefore deforms and fractures. Such deformation/fracturing in turn changes the permeability, which again changes the evolution of fluid pressure, coupling the two phenomena. The intimate coupling between fracturing and fluid flow makes the meso-scale DEM simulations necessary, as these methods have substantial advantages over conventional continuum mechanical models of elastic rock deformation. The challenges that must be overcome to simulate EGS reservoir stimulation, preliminary results, progress to date and near future research directions and opportunities will be discussed.« less
  • The connectivity and accessible surface area of flowing fractures, whether natural or man-made, is possibly the single most important factor, after temperature, which determines the feasibility of an Enhanced Geothermal System (EGS). Rock deformation and in-situ stress changes induced by injected fluids can lead to shear failure on preexisting fractures which can generate microseismic events, and also enhance the permeability and accessible surface area of the geothermal formation. Hence, the ability to accurately model the coupled thermal-hydrologic-mechanical (THM) processes in fractured geological formations is critical in effective EGS reservoir development and management strategies. The locations of the microseismic events canmore » serve as indicators of the zones of enhanced permeability, thus providing vital information for verification of the coupled THM models. We will describe a general purpose computational code, FEHM, developed for this purpose, that models coupled THM processes during multiphase fluid flow and transport in fractured porous media. The code incorporates several models of fracture aperture and stress behavior combined with permeability relationships. We provide field scale examples of applications to geothermal systems to demonstrate the utility of the method.« less