Numerical study on injection of flue gas as a heat carrier into coal reservoir to enhance CBM recovery

Mu, Yongliang; Fan, Yu; Wang, Jiren; Fan, Nan

doi:10.1016/j.jngse.2019.103017

Cited by 29 publications

(13 citation statements)

References 50 publications

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“…Detailed parameters used in the simulation are compiled in Table 4. The increase in temperature and the pressure of injected CO 2 favors the transport of carbon dioxide, thereby enhancing methane recovery; the presence of water in the coal deposit may decrease coal permeability, and, as a consequence delay CO 2 adsorption inhibiting the migration of carbon dioxide [33][34][35][36].…”

Section: Resultsmentioning

confidence: 99%

Research on the Processes of Injecting CO2 into Coal Seams with CH4 Recovery Using Horizontal Wells

et al. 2020

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The paper presents a research study on modeling and computer simulation of injecting CO2 into the coal seams of the Upper Silesian Coal Basin, Poland connected with enhanced coal bed methane (ECBM) recovery. In the initial stage of the research activities, a structural parameter model was developed specifically with reference to the coal-bearing formations of the Upper Carboniferous for which basic parameters of coal quality and the distribution of methane content were estimated. In addition, a lithological model of the overall reservoir structure was developed and the reservoir parameters of the storage site were analyzed. In the next stage of the research, the static model was supplemented with detailed reservoir parameters as well as the thermodynamic properties of fluids and complex gases. The paper discusses a series of simulations of an enhanced coalbed methane recovery process with a simultaneous injection of carbon dioxide. The analyses were performed using the ECLIPSE software designed for simulating coal seam processes. The results of the simulations demonstrated that the total volume of CO2 injected to a designated seam in a coal mine during the period of one year equaled 1,954,213 sm3. The total amount of water obtained from the production wells during the whole period of the simulations (6.5 years) was 9867 sm3. At the same time, 15,558,906 sm3 of gas was recovered, out of which 14,445,424 sm3 was methane. The remaining 7% of the extracted gas was carbon dioxide as a result of reverse production of the previously injected CO2. However, taking into consideration the phenomena of coal matrix shrinking and swelling, the total amount of injected CO2 decreased to approximately 625,000 sm3.

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Section: Resultsmentioning

confidence: 99%

Research on the Processes of Injecting CO2 into Coal Seams with CH4 Recovery Using Horizontal Wells

et al. 2020

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“…Under the pressure gradient, the methane and water continue to flow to the surface well. e process can be described by the fluid continuity equation [18]:…”

Section: Fluid Seepage Control Equationmentioning

confidence: 99%

Numerical Simulation Research on Hydraulic Fracturing Promoting Coalbed Methane Extraction

Fan

Shu

Huo

et al. 2021

Shock and Vibration

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Although hydraulic fracturing technology has been comprehensively investigated, few scholars have studied the influence of hydraulic fracturing on the effect of coalbed methane (CBM) extraction, and few considered the interaction between water and CBM in the research process, which is not conducive to guiding the engineering design of hydraulic fracturing wells. In this work, a hydraulic-mechanical-thermal coupled model for CBM extraction in hydraulic fracturing well is established; it combines gas-liquid two-phase infiltration, where nonisothermal adsorption is also considered. The COMSOL Multiphysics software is used to carry out the numerical simulation study of the CBM extraction process in hydraulic fracturing well and analyze the influence of coalbed permeability, initial methane pressure, and fracture length on CBM extraction in hydraulic fracturing well, and the results show that the hydraulic-mechanical-thermal coupled model for CBM extraction can be used for CBM extraction research in hydraulic fracturing well. The initial coalbed permeability, initial gas pressure, and fracture length all affect the migration speed of CBM to surface well in different ways and have a greater impact on the CBM production rate of hydraulic fracturing well. The greater the initial coalbed permeability and methane pressure are, the longer the fracture length is and the greater the CMB production rate of hydraulic fracturing well is. The change trend of coalbed permeability during the extraction process of surface fracturing well is directly related to the state of the reservoir. The factors of stress, temperature, and CBM desorption jointly determine the increase or decrease of coal seam permeability.

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“…The relative permeability models of Eqs. ( 39) and ( 40) at saturation S w are widely used [52]. Gas slippage is not considered, and the gas/water endpoint relative permeability is calibrated in this study; a dynamic effective permeability model may be expressed as…”

Section: Governing Equation Of the Mechanical Fieldmentioning

confidence: 99%

The Role of Coal Mechanical Characteristics on Reservoir Permeability Evolution and Its Effects on CO2 Sequestration and Enhanced Coalbed Methane Recovery

Han

Liang

et al. 2020

Geofluids

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Elastic modulus is an important parameter affecting the permeability change in the process of coalbed methane (CBM)/enhanced coalbed methane (ECBM) production, which will change with the variable gas content. Much research focuses on the constant value of elastic modulus; however, variable stiffness of coal during CO2 injection has been considered in this work. The coupled thermo-hydro-mechanical (THM) model is established and then validated by primary production data, as well as being applied in the prediction of CO2/N2-ECBM recovery. The results show that the harder coal seam is beneficial to primary production, while the softer coal seam results in greater CO2/N2-ECBM recovery and CO2 sequestration. N2 and CO2 mixture injection could be applied to balance early N2 breakthrough and pronounced matrix swelling induced by CO2 adsorption, and to prolong the process of effective CH4 recovery. Besides, reduction in stiffness of coal seam during CO2 injection would moderate the significant permeability loss induced by matrix swelling. With the increase of the weakening degree of coal seam stiffness, CO2 cumulative storage also shows an increasing trend. Neglecting the weakening effect of CO2 adsorption on coal seam stiffness could underestimate the injection capacity of CO2. Injection of hot CO2 could improve the permeability around injection well and then enhance CO2 cumulative storage and CBM recovery. Furthermore, compared with ECBM production, injection temperature is more favorable for CO2 storage, especially within hard coal seams. Care should be considered that significant permeability change is induced by mechanical characteristics alterations in deep burial coal seams in further study, especially for CO2-ECBM projects.

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Numerical study on injection of flue gas as a heat carrier into coal reservoir to enhance CBM recovery

Cited by 29 publications

References 50 publications

Research on the Processes of Injecting CO2 into Coal Seams with CH4 Recovery Using Horizontal Wells

Research on the Processes of Injecting CO2 into Coal Seams with CH4 Recovery Using Horizontal Wells

Numerical Simulation Research on Hydraulic Fracturing Promoting Coalbed Methane Extraction

The Role of Coal Mechanical Characteristics on Reservoir Permeability Evolution and Its Effects on CO2 Sequestration and Enhanced Coalbed Methane Recovery

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