Assessment of shrinkage–swelling influences in coal seams using rank-dependent physical coal properties

Balan, Huseyin Onur; Gümrah, F.

doi:10.1016/j.coal.2008.09.014

Cited by 57 publications

(24 citation statements)

References 18 publications

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“…Coal with a higher Poisson's ratio results in a higher production rate with the C&B and G&C models but lower values in the S&D and P&M models (Cui and Bustin, 2005;Gu and Chalaturnyk, 2005;Zulkarnain, 2005). Thus, our results show significant influence of Poisson's ratio, which somewhat contradicts finding by Balan and Gumrah (2009) who stateed that Poisson's ratio does not affect CBM recovery.…”

Section: Effect Of Young's Modulus and Poisson's Ratiocontrasting

confidence: 57%

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Fully coupled two-phase flow and poromechanics modeling of coalbed methane recovery: Impact of geomechanics on production rate

Rutqvist

Oldenburg

et al. 2017

Journal of Natural Gas Science and Engineering

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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

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Section: Effect Of Young's Modulus and Poisson's Ratiocontrasting

confidence: 57%

“…The influences of E and ν are investigated in this section. The E and ν values for coal with low, medium and high deformability are listed in Table 3 (Balan and Gumrah, 2009). The methane and gas production rates for three different Young's moduli are compared in Fig.…”

Section: Effect Of Young's Modulus and Poisson's Ratiomentioning

confidence: 99%

Fully coupled two-phase flow and poromechanics modeling of coalbed methane recovery: Impact of geomechanics on production rate

Rutqvist

Oldenburg

et al. 2017

Journal of Natural Gas Science and Engineering

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“…The GEM software has been proven in numerous production studies around the world and is one of the commonly used simulators for unconventional gas reservoirs (ex. Gu and Chalaturnyk, 2005;Wong et al, 2007;Gentzis and Bolen, 2008;Maricic et al, 2008;Balan and Gumrah, 2009;Mora and Wattattenbarger, 2009). …”

Section: Resultsmentioning

confidence: 97%

Horseshoe Canyon and Belly River coal measures, south central Alberta: Part 2 -- Modeling reservoir properties and producible gas

Bustin

2011

Bulletin of Canadian Petroleum Geology

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The gas reserves and well spacing units in the Horseshoe Canyon-Belly River Formation coal measures in Alberta are assigned based on gas-in-place determined by canister desorption tests of coal following ERCB (2010) guidelines. However, substantial gas, which is not measured by desorption tests, also occurs in the free state within the coals as well as adsorbed and in the free state within adjacent fine-grained strata (referred to here as shales) interbedded with the coals. A series of laboratory experiments (matrix flux, volumetric strain, rock mechanics) were conducted to quantify the reservoir properties of the coals and shales and were integrated with the results from field tests (well logs, pressure build-up) to be used as model inputs for a reservoir simulator. The purpose of the modeling was to address two main questions: 1) do variations in the amount of free gas within the matrix porosity of the coal seams affect production; and 2) to what extent is the gas stored within the strata interbedded with the coal seams co-produced?The free gas stored within a coal seam with an effective matrix porosity of 8% is shown to comprise on the order of 25% of the total original gas-in-place. The modeling results show that in high permeability coals (150 mD), an increase in production equivalent to the additional gas-in-place resulting from the free gas occurs after 25 years. Even very low permeability reservoirs (0.3 mD) are modeled to experience an approximately 2% increase in cumulative gas after 50 years of production.Including the gas bearing shales adjacent to the coal seams results in a substantial increase in producible gas. An increase of 144% in the cumulative gas produced after 50 years is observed when shales with a fracture permeability of 0.01 mD, matrix permeability of 1x10 -4 mD, and an effective fracture spacing of 10 m are modeled with coal seams with a fracture permeability of 15 mD. The coal seams, being more permeable than the shales, act as horizontal drains for the over and underlying shale layers. The enhanced production is strongly dependent on the fracture and matrix permeability as well as the fracture spacing of the shales. The spacing of 4 wells/section, assumed in the above model, results in an estimated ultimate recovery (EUR) of 23% of the total original gas-in-place in the coals and 9% in the shales after 50 years of production. Downsizing to 8 wells/section increases the EUR to 35% for the coals and 15% for the shales and to 16 wells/section to 50% for the coals and 22% for the shales. The resulting increase in cumulative production with the decrease to 8 wells/section spacing is 57% and an additional 42% when further decreased to 16 wells/section. RÉSUMÉLes réserves gazières et les unités d'espacement pour les puits dans les séries houillères des formations de Horseshoe Canyon et de Belly River en Alberta sont assignées selon la quantité de gaz en place, ce que l'on détermine par des tests de cylindre de désorption suivant les directives de l'Office de conservation des ressources éner...

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“…Injection of pure CO 2 into coal seams usually has a negative effect—coal swelling‐induced permeability decreasing, due to the greater adsorption affinity of CO 2 to coal than of CH 4 . Related studies show that CO 2 injections will cause a reduction in coal permeability by nearly two orders of magnitude, especially near the injection well .…”

Section: Introductionmentioning

confidence: 99%

“…25 Injection of pure CO 2 into coal seams usually has a negative effect-coal swelling-induced permeability decreasing, due to the greater adsorption affinity of CO 2 to coal than of CH 4 . 5,[25][26][27] Related studies show that CO 2 injections will cause a reduction in coal permeability by nearly two orders of magnitude, especially near the injection well. 9,12,15 Even if the CO 2 -ECBM is completed, the decreased coal permeability cannot rebound to initial values, thus results in the deterioration of well injectivity.Another gas injected into coal seams is N 2 , which has a different mechanism of ECBM recovery than CO 2 .…”

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confidence: 99%

Numerical study on enhancing coalbed methane recovery by injecting N₂/CO₂ mixtures and its geological significance

Fan

Wang

Deng

et al. 2019

Energy Science & Engineering

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As an effective carbon utilization technology, the injection of N2/CO2 mixtures into coal seams has significant potential for improving coalbed methane recovery. Considering the technical barrier that injection of pure CO2 decreases the well injectivity index and pure N2 injection leads to the rapid methane recovery, a method of injecting N2‐enriched gas mixtures with a constant component is proposed. In this study, a thermo‐hydro‐mechanical (THM) coupling numerical model for enhanced coalbed methane (CBM) recovery by injecting N2/CO2 mixtures is established. This model includes complex interactions of coal deformation, competitive adsorption, ternary gas seepage, and heat transfer. The THM coupling model is first validated, and then applied to investigate the evolution of mixed gas concentrations, reservoir permeability, reservoir temperature, CH4 production, and N2/CO2 storage during N2/CO2 enhanced CBM recovery. The results show that the displacement radius and concentration of the mixed gas in the coal seam increased with gas injection pressure increase. The concentration of CH4 gradually decreased with time, and the early decline is faster than the later stage. The sweep of the N2 flow accelerates CH4 desorption and migration, promoting a reduction in reservoir temperature near the production well. Reservoir permeability evolution results from the combined effects of ternary gases (CH4, CO2, N2) competitive adsorption, gas pressure, and geostress on the coal seam within the THM fields. At the methane natural depletion stage (within 250 days), the permeability of coal reservoir first decreases and then increases. With the arrival of the N2/CO2 mixture, the permeability decreases dramatically. From the perspective of cumulative CH4 production, the optimal composition is dominated by the synergistic effect of maximizing breakthrough time and minimizing coal matrix swelling. For 30% CO2‐70% N2, the CH4 recovery ratio reached 71.76%, representing an increase of 16.67% compared to natural depletion.

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Assessment of shrinkage–swelling influences in coal seams using rank-dependent physical coal properties

Cited by 57 publications

References 18 publications

Fully coupled two-phase flow and poromechanics modeling of coalbed methane recovery: Impact of geomechanics on production rate

Fully coupled two-phase flow and poromechanics modeling of coalbed methane recovery: Impact of geomechanics on production rate

Horseshoe Canyon and Belly River coal measures, south central Alberta: Part 2 -- Modeling reservoir properties and producible gas

Numerical study on enhancing coalbed methane recovery by injecting N₂/CO₂ mixtures and its geological significance

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Assessment of shrinkage–swelling influences in coal seams using rank-dependent physical coal properties

Cited by 57 publications

References 18 publications

Fully coupled two-phase flow and poromechanics modeling of coalbed methane recovery: Impact of geomechanics on production rate

Fully coupled two-phase flow and poromechanics modeling of coalbed methane recovery: Impact of geomechanics on production rate

Horseshoe Canyon and Belly River coal measures, south central Alberta: Part 2 -- Modeling reservoir properties and producible gas

Numerical study on enhancing coalbed methane recovery by injecting N2/CO2 mixtures and its geological significance

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Numerical study on enhancing coalbed methane recovery by injecting N₂/CO₂ mixtures and its geological significance