Permeability evolution of propped artificial fractures in coal on injection of CO2

Kumar, Hemant; Elsworth, Derek; Liu, Jishan; Pone, Denis; Mathews, Jonathan P.

doi:10.1016/j.petrol.2015.07.008

Cited by 57 publications

(22 citation statements)

References 45 publications

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“…Furthermore, we used a mechanistic model, developed for permeability evolution in propped artificial fractures in coal (Kumar et al . ) to explain similar permeability observations in artificially fractured shale in the following subsections. Also, we have discussed the implication of organic matter swelling in shales in the last subsection.…”

Section: Discussionsupporting

confidence: 73%

“…The permeability evolution in nonpropped and propped artificial fractures in bituminous and anthracite coal is known to exhibit similar behavior (Kumar et al . ).…”

Section: Resultsmentioning

confidence: 97%

“…Interestingly, the permeability evolution in the propped fractures exhibited behavior similar to that of intact coal (Kumar et al . ). The permeability evolution of the propped fracture in shale upon injection of CO 2 is shown in Fig.…”

Section: Resultsmentioning

confidence: 97%

“…The mechanistic model developed by (Kumar et al . ) assumes that the permeability modulates as a function of proppant embedment and sorption‐induced swelling. The mathematical formulation of their model is presented below.…”

Section: Discussionmentioning

confidence: 99%

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

et al. 2015

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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.

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Section: Discussionsupporting

confidence: 73%

“…The permeability evolution in nonpropped and propped artificial fractures in bituminous and anthracite coal is known to exhibit similar behavior (Kumar et al . ).…”

Section: Resultsmentioning

confidence: 97%

Section: Resultsmentioning

confidence: 97%

Section: Discussionmentioning

confidence: 99%

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

et al. 2015

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“…They ascertained that the higher content of N 2 in the gas mixture, the less permeability reduction occurred through calculating the permeability reduction by adsorption with pressure increase. In the research conducted by Kumar et al (2012Kumar et al ( , 2015 and Wang et al (2012), they intended to investigate permeability evolution more accurately in sorbing materials of coal and shale through observing permeability change by gas adsorption and external stress. Shale is also relevant to sorbing media with methane as adsorbed state like coal.…”

Section: Introductionmentioning

confidence: 99%

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

Seomoon

Lee

Sung

2016

Energy Exploration & Exploitation

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When enhancing coalbed methane recovery using CO 2 or N 2 injection, injected gas flows into coal matrix by diffusion. Gas diffusion velocity varies, depending on gas molecular size and pore geometry which causes different sorption rates of the gas in coal seam. In this aspect, this study provides the fundamental reason for the reduction in gas permeability through cleats and methane recovery during enhanced coalbed methane (ECBM) processes. This reduction occurs not only because of the sorption affinity as reported in previous works, but also because of the characteristics of gas diffusional flow which this study attempted to examine experimentally. From the results obtained by diffusional flow experiment, diffusion coefficient is no longer increased at high pressure. Although CO 2 injection rate is very high, a large amount of CO 2 moves through cleat instead of adsorbed in matrix, which causes early CO 2 breakthrough. In ECBM, N 2 mostly acts as a displacing agent of methane, because co-diffusion of N 2 with methane is more dominant than counter-diffusion owing to its extremely low adsorption affinity. On the other hand, CO 2 is rapidly adsorbed due to its fast increasing rate of diffusion coefficient with pressure increase. Consequently, CO 2 permeability is greatly reduced at the beginning of injection and ultimately becomes the lowest value at the maximum adsorption pressure. Also, delayed methane recovery by fast diffusion and high adsorption affinity of CO 2 occurs accordingly. This study confirms that the CO 2 -N 2 mixed gas injection is advisable comparing to only injecting CO 2 to pursue the prevention of CO 2 injectivity reduction and enhanced methane recovery, simultaneously.

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Gas seepage laws based on dual porosity and dual permeability: Numerical simulation and coalbed methane extraction practice

Qin

Wang

et al. 2021

Energy Science & Engineering

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Coalbed methane (CBM) is the very important unconventional energy resource. Enhancing extraction is the main method to improve the utilization of CBM and prevent coal mine gas disasters. To reveal the laws of gas migration during the underground gas extraction, the paper established the solid‐gas coupling model, regarding coal as the homogeneous elastic medium with dual pore‐fracture structure and dual permeability and considering the gas dynamic diffusion coefficient. Then, the regulations of gas migration in the in‐seam borehole were simulated by the COMSOL Multiphysics software and verified via the field trials of gas extraction. The results revealed that the permeability increased with time due to the coupling of matrix shrinkage and volume compression of coal, in which the matrix shrinkage played a leading role. The gas seepage velocity at the observation points can be divided into three stages: the rapid rise stage, the stable decline stage, and the stable and invariant stage. The gas extraction rate continued decreasing with time and finally tended to a fixed value. In the coal seam #4 of Zhongxing coal mine, the measured flow rates of three in‐seam drilling holes were in good agreement with the simulation results, which verified the correctness of the theoretical coupling model.

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Permeability evolution of propped artificial fractures in coal on injection of CO2

Cited by 57 publications

References 45 publications

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

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

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

Gas seepage laws based on dual porosity and dual permeability: Numerical simulation and coalbed methane extraction practice

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Permeability evolution of propped artificial fractures in coal on injection of CO2

Cited by 57 publications

References 45 publications

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

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

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

Gas seepage laws based on dual porosity and dual permeability: Numerical simulation and coalbed methane extraction practice

Contact Info

Product

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About

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