Permeability evolution in sorbing media: analogies between organic‐rich shale and coal

Abstract

Shale gas reservoirs like coalbed methane (CBM) reservoirs are promising targets for geological sequestration of carbon dioxide (CO 2 ). However, the evolution of permeability in shale reservoirs on injection of CO 2 is poorly understood unlike CBM reservoirs. In this study, we report measurements of permeability evolution in shales infiltrated separately by nonsorbing (He) and sorbing (CO 2 ) gases under varying gas pressures and confining stresses. Experiments are completed on Pennsylvanian shales containing both natural and artificial fractures under nonpropped and propped conditions. We use the models for permeability evolution in coal (Journal of Petroleum Science and Engineering, Under Revision) to codify the permeability evolution observed in the shale samples. It is observed that for a naturally fractured shale, the He permeability increases by approximately 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 CO 2 permeability reduces by a factor of two under similar conditions. A second core is split with a fine saw to create a smooth artificial fracture and the permeabilities are measured for both nonpropped and propped fractures. The He permeability of a propped artificial fracture is approximately 2-to 3fold that of the nonpropped fracture. The He permeability increases with gas pressure under constant confining stress for both nonpropped and propped cases. However, the CO 2 permeability of the propped fracture decreases by between one-half to one-third as the gas pressure increases from 1 to 4 MPa at constant confining stress. Interestingly, the CO 2 permeability of nonpropped fracture increases with gas pressure at constant confining stress. The permeability evolution of nonpropped and propped artificial fractures in shale is found to be similar to those observed in coals but the extent of permeability reduction by swelling is much lower in shale due to its lower organic content. Optical profilometry is used to quantify the surface roughness. The changes in surface roughness indicate significant influence of proppant indentation on fracture surface in the shale sample. The trends of permeability evolution on injection of CO 2 in coals and shales are found analogous; therefore, the permeability evolution models previously developed for coals are adopted to explain the permeability evolution in shales.

Characteristics of Clay-Abundant Shale Formations: Use of CO2 for Production Enhancement

“…Therefore, the injection of CO 2 into shale causes its adsorbed methane to be replaced by the injected CO 2 , resulting in greater shale gas production. For example, according to Figure 15, gas adsorption capacity increases with the increase of pressure, while the adsorption capacity of CO 2 is much stronger than that of CH 4 , and the ratio between them is around 3. Similar experimental values have been verified by other researchers, and the ratio of CO 2 to methane adsorption capacity in shale is around 5.3 to 1 [36] The gas sorption process in shale formations is dependent on the type of gas molecules and the CEC of the clay minerals.…”

“…Of all the varieties of unconventional gas sources (shale gas, coal-bed methane, tight gas, and gas hydrates), more than 63% comes from shale, and the gas produced from shale is commonly known as shale gas. However, the extremely low permeability of shales is the major barrier to shale gas production and various permeability-enhancement techniques are therefore used to enhance shale gas productivity in the field [3,4]. Of these, hydraulic fracturing is one of the most commonly-used techniques.…”

Elastic–Brittle–Plastic Behaviour of Shale Reservoirs and Its Implications on Fracture Permeability Variation: An Analytical Approach

“…Due to the significance of micro-cracks in shale reservoirs, these findings imply an immediate need for better understanding of the mechanisms of compression-induced fracture initiation and growth in shales. Although studies related to hydraulic fracturing cover this topic to some extent, the relevant micro-scale phenomena are not well understood and cannot be properly predicted, especially for highly anisotropic rocks with sparse organic contents such as shales (Kumar et al 2016). Such studies can be even more important when considering the CO 2 injection for sequestration and production enhancement purposes.…”

Analysis of methane recovery through CO2–N2 mixed gas injection considering gas diffusion phenomenon in coal seam

“…According to the previous research, it is known that the reduction in permeability halts at a critical pressure corresponding to the point at which maximum adsorption is achieved and then increase as a consequence of diminishing effective stress (Kumar et al, 2010(Kumar et al, , 2016Wang et al, 2012). In this study, analysis of permeability change was based on the Palmer and Mansoori model which consists of the sum of pore strain and sorption strain, but experiments were conducted under same effective stress to analyze the permeability change by only sorption strain considering diffusion phenomenon in coal.…”

“…Shale is also relevant to sorbing media with methane as adsorbed state like coal. Thus, according to the research by Kumar et al (2010Kumar et al ( , 2016, shale is a promising area because of geological sequestration of carbon dioxide, but permeability reduction is very small than that of coal due to adsorption characteristic of matrix.…”