Poromechanical Response of Naturally Fractured Sorbing Media

Open Access
Author:
Kumar, Hemant
Graduate Program:
Energy and Mineral Engineering
Degree:
Doctor of Philosophy
Document Type:
Dissertation
Date of Defense:
February 08, 2013
Committee Members:
  • Derek Elsworth, Dissertation Advisor
  • Derek Elsworth, Committee Chair
  • Jonathan P Mathews, Committee Member
  • Zuleima T Karpyn, Committee Member
  • Chris Marone, Committee Member
  • Denis Pone, Special Member
Keywords:
  • Coal
  • Shale
  • Permeability
  • Proppant
  • Modeling
  • Simulation
Abstract:
The injection of CO2 in coal seams has been utilized for enhanced gas recovery and potential CO2 sequestration in unmineable coal seams. Injection is advantageous because it may both enhance the production of CH4 and significant volumes of CO2 may be simultaneously stored. Key issues for enhanced gas recovery and geologic sequestration of CO2 include (1) Injectivity prediction: The chemical and physical processes initiated by the injection of CO2 in the coal seam result in significant changes in permeability/porosity (2) Up scaling: Development of a full-scale coupled reservoir model to predict the enhanced production, associated permeability changes and quantity of sequestered CO2. (3) Reservoir Stimulation: Coalbeds are often stimulated by hydraulic fracturing with proppants typically placed into the fractures to retain the improved permeability, however permeability evolution over the long-term remains poorly understood. These issues are largely governed by dynamic coupling of adsorption, fluid exchange and transport and modulated by water content, stress regime, fracture geometry and physicochemical changes in coals which are triggered by CO2 injection. This thesis investigates these complex interactions in coal and in shale through laboratory experiments with full reservoir scale models developed to address key issues. Chapter I of this dissertation explores the effect of gas pressure and stress on the permeability evolution of coalbed methane (CBM) reservoirs infiltrated by carbon dioxide. Typically the recovery of methane induces coal shrinkage and the injection of CO2 induces coal swelling respectively increasing or decreasing permeability for constrained coals. Permeability evolution was quantified for moisture equilibrated and partially dried bituminous coal samples together with the transitions caused by sequential exposure to different gases. The experimental measurements of permeability evolution was conducted on a coal from the Uinta basin infiltrated by helium, methane and carbon dioxide under varying gas pressure (1-8 MPa) and moisture content (1-9% by mass) while subjected to constant applied stresses (10 MPa). Permeability decreases with increased moisture content for all the gases (He, CH4 and CO2). The decrease in He permeability may be as high as ~100 folds if the moisture content is increased from 1% to 9% by mass. Swelling induced by sorption of CH4 and CO2 in the coal matrix reduces permeability by 5 to 10 fold depending on the gas injected and the moisture content. Swelling increases with gas pressure to the maximum (strain based estimation 5%) at a critical pressure (~4.1 MPa) corresponding to maximum adsorption capacity. Beyond this threshold effective stress effects dominate. Permeability evolution was determined in bituminous coal for various moisture contents, effective stresses, and gas pressures to propose a mechanistic model. Also, this model explains the published data for permeability evolution on water saturated Pennsylvanian anthracite coal. This model was used to investigate the performance of prototypical ECBM projects. In particular the effect of the permeability loss examined with the injection of CO2. This response is defined in terms of two conditions: reservoirs either above (under-) or below (above-) the saturation pressure that defines the permeability minima in the reservoir. For oversaturated reservoirs withdrawal will always result in decreased permeability at the withdrawal well unless the critical pressure is transited. Similarly permeability will decrease at the CO2 injection well unless the pressure increase is sufficiently large to overcome the reduction in permeability due to CO2 - typically of order of one to a few MPa. For undersaturated reservoirs the permeability will always increase at the withdrawal well and can only increase at the injection well if the critical pressure is transited and further exceeded by one to a few MPa. These observations provide a rational method to design injection and recovery strategies for ECBM that account for the complex behavior of the reservoir including the important effects of moisture content, gas composition and effective stress. Chapter II of this dissertation explores the effect of CO2 injection on production, permeability evolution and permeability variability using a full scale reservoir model. Enhanced coalbed methane (ECBM) can be recovered by injecting a gas such as carbon dioxide into the reservoir to displace methane. The contrast between density, viscosity, and permeability of the resident and displacing fluids affects the efficiency of ECBM recovery. The prediction of earlier breakthrough becomes complex as the permeability may vary by orders of magnitude during gas injection and methane recovery. Predominantly, the reservoir permeability is modulated by the pore pressure of the sorptive gas (CH4 and CO2) and effective stresses. Here we explore the possibility of early breakthrough and its implications for managing coalbed reservoirs during CO2 assisted ECBM. A coupled finite element (FE) model of binary gas flow, diffusion, competitive sorption and permeability change is used to explore the effect of CO2 injection on net recovery, permeability evolution and injectivity in uniform and homogeneously permeable reservoirs. This effect is evaluated in terms of dimensionless pressure〖 ( p〗_D), permeability ( k_D) and fracture spacing (x_D) on the recovery of methane and permeability evolution for ECBM and non-ECBM scenarios. We have considered two scenarios (4MPa and 8 MPa) of constant pressure injection of CO2 for ECBM. The increase in production rate of CH4 is proportional to k_D but inversely proportional to x_D. Further, a reservoir with initial permeability heterogeneity was considered to explore the effect of CO2 injection on the evolution of permeability heterogeneity – whether heterogeneity increases or decreases. The evolution of permeability heterogeneity is investigated for the same two CO2 injection scenarios. For the specific parameters selected, the model results demonstrate that: (1) The injection of CO2 in coalbed reservoirs increases the production nearly 10 fold. (2) At higher injection pressures the recovery is rapid and the production increases dramatically - the production increases 2 fold on increasing the CO2 injection pressure from 4 MPa to 8 MPa (3) However, CO2 breakthrough occurs earlier at higher injection pressures. (4) The permeability heterogeneity in the reservoir is reduces after a threshold time (~500 days) although the overall heterogeneity is increased relative to the initial condition is overall increased for both non-CO2 and CO2 injection scenarios. This indicates that the homogenizing influence of CO2-sorption-swelling is outpaced by CH4-desorption-shrinkage and effective stress influences. This leaves the reservoir open to short-circuiting and earlier breakthrough of CO2 rather than having this effect damped-out by the homogenizing influence of swelling. (5) The cumulative volume of CO2 produced and stored in the reservoir is proportional to the injection pressure. Chapter III explores the effect of proppant embedment on permeability evolution in artificial fractures created by hydraulic fracturing. Proppant are often placed in hydraulic fractures to retain the enhanced permeability for extended periods. However, the permeability enhancement may be mitigated due to proppant embedment into the natural/artificial fractures of coalbed methane reservoirs. The reduction in fracture aperture occurs either when CO2-induced coal softening causes proppant penetration into the coal fracture surface or coal swelling encroaches into the propped facture during CO2 assisted enhanced coalbed methane recovery. While coal swelling is a well-established phenomenon, there is limited investigation into coal softening under stressed conditions. Here we investigate permeability transformations at simulated insitu conditions through a suite of laboratory experiments conducted on selected high-rank coals and a granite cores with an artificial saw-cut fracture containing proppant. The permeability of the artificial fracture is measured for both non-sorbing gas (He) and a sorbing gas (CO2) at constant confining stress of 10MPa. Permeability was also measured with an idealized case of a uniform monolayer of #70-140 mesh proppant sand within the fracture. The increase in He permeability may be as high as ~10 fold if monolayer proppant is sandwiched in the coal or granite fracture. Similar increase is observed in the case of sorptive gas (CO2) permeability. An exponential increase in permeability is observed with gas pressure for both coal and granite without proppant as expected. However, the permeability decreases due to coal swelling and then increases due to reduced effective stress with gas pressure in case of propped fracture on injection of CO2. Optical profilometry pre- and post experimental suite is used to quantify proppant embedment, if occurs, in the coal fracture surface. Infrequent and isolated pits, similar to the size of a sand grain, were observed post experimental suite. Sparsely distributed surface indentation on completion of experimental suite, suggests an insignificant contribution of coal softening towards permeability reduction. Thus, a large reduction in permeability can only be attributed to coal swelling. The increase in surface roughness post exposure to CO2 by about a fraction of microns indicates a slight irreversible structural rearrangement with CO2 uptake and loss. A mechanistic model is developed to explain the permeability evolution in a propped artificial fracture on injection of CO2. The permeability evolution trends alike ‘U-shape’ with gas pressure at constant confining stress. The excellent fit between model and experimental observations indicates a robustness of the model however more work is needed for the model to run in predictive capacities. Chapter IV reports measurements of permeability evolution in shales infiltrated separately by non-sorbing (He) and sorbing (CO2) gases under varying gas pressures, confining stresses and deviatoric stresses. Experiments are completed on Pennsylvanian shales containing both natural and artificial fractures under non-propped and propped conditions. We use observations for permeability evolution in other sorbing media (coal, Kumar et al., 2012) to codify the response for shale. It is observed that for a naturally fractured shale, the He-permeability increases by ~15% as effective stress is reduced by increasing the gas pressure from 1 MPa to 6 MPa at constant confining stress of 10 MPa. Conversely, the CO2-permeability reduces by a factor of two under similar conditions. Permeability of the core recovers to the original magnitude when the core is resaturated by a non-adsorbing gas, despite prior CO2 exposure. A second core is split with a fine saw to create a smooth artificial fracture and the permeabilities measured for both non-propped and propped fractures. The He-permeability of a monolayer sand-propped artificial fracture is ~2-3 fold that of a non-propped fracture. Upon increasing the gas pressure, the He-permeability of the propped fracture increases under constant confining stress. Conversely, the CO2-permeability of the propped fracture decreases by between one-half to one-third as the gas pressure increases from 1 to 4 MPa at a constant confining stress. We attribute the reduction in permeability to sorption-induced swelling in the organic material of the shale. The permeability of the non-propped shale fracture increases with gas pressure, at constant confining stress, due to the absence of rock bridges that commonly occur in naturally fractured samples. Although the permeability evolution of non-propped and propped artificial fractures in shale are found to be similar to those observed in coal, the extent of permeability reduction by swelling is much lower in shale due to its lower organic content. The surface roughness and peak-to-valley differential for the artificial fracture surfaces are quantified by optical profilometry. Initial values of surface roughness and peak-to-valley differential height are 4.1 m and 77.9 m, respectively, which increases to 6.1 m and 122.4 m at completion of experiments - indicating the significant influence of proppant indentation into the surface of the fracture in shale. A mechanistic model representing permeability evolution in sorbing media is applied to describe permeability evolution in shale. This model characterizes the 'U-shaped' variation of permeability with gas pressure typical for sorbing media and apparent for shales.