CO2 adsorption the numerical simulations and the controlling factors to low rank coal

International Conference on Earth Science, Mineral, and Energy

地球科学;矿业工程;能源学

Rahim, A.^1,2 ; Surjono, S.S.^1 ; Amijaya, D.H.^1

Geological Engineering Department, Faculty of Engineering, Universitas Gadjah Mada, Indonesia^1

Earth Resources Engineering, Kyushu University, Japan^2

关键词: Adsorption capacities;    Adsorption parameters;    Compositional reservoir simulators;    Enhanced methane recovery;    Fracture permeability;    Injection pressures;    Numerical simulation studies;    Reservoir parameters;   

Others  :  https://iopscience.iop.org/article/10.1088/1755-1315/212/1/012016/pdf
DOI  :  10.1088/1755-1315/212/1/012016

来源: IOP

【 摘 要 】

Carbon Capture Sequestration (CCS) in unmineable coal seams questionably gives benefits for the commercial success through potential release of additional methane during the injection of CO2 adsorbs into the coal seams, the process known as enhanced coalbed methane (ECBM) recovery. However, a significant concern lies in the loss of injectivity due to reduction in permeability by coal matrix swelling occurences with CO2 adsorption although this effect can be partially be offset with 'huff and puff' scheme of cyclic CO2 injection followed by extraction of the released methane. The paper discusses the results of a numerical simulation study carried out with GEM compositional reservoir simulator to evaluate the effects of uncertainties in various reservoir parameters on the overall volume of CO2 storage and additional methane recovery of low rank coalfield. A 12-15m thick seam at shallow depth, 50-75 m was considered for fluid flow simulation study. While some information on the reservoir setting was obtained through literature and personal communication with the CBM operators, the rest of the information was derived through laboratory studies. The reservoir parameters considered for the study are injection pressure, adsorption capacity, cleat permeability and porosity, and initial gas saturation. A 100-acre drainage area with 5-spot vertical well pattern was considered with one central injector and four producers on four corners of the study area. The maximum allowable injection pressure was estimated to be 7500 kPa at the reservoir setting. The injection pressure was varied from 1000 kPa to 7500 kPa in the simulation. A number of adsorption isotherms were established in the laboratory. The variations in the adsorption parameters observed through the isotherms were considered as uncertainty in the storage capacities. Significant variations were observed due to the variation in adsorption isotherms both for CO2 storage and additional methane recovery. Fracture permeability was varied from 3 md to 200 md, which is the range of permeability observed in the coalfield is around 100-200 mD. The results of simulation indicate a strong influence of porosity on the CO2 storage and ECBM recovery. Fluid flow simulation study shows that variation in sorption time has no significant effect for a low permeability situation while some marginal effect in high permeability situation. Cleat porosity was varied from 1 % to 10 %. Within this range of porosities, enhanced methane recovery varied from 1 % to 10 % relative to the primary recovery but the volume of stored CO2 did not vary significantly. Lastly, the pore pressure, adsorption and gas saturation of CO2 sequestered volume and additional methane recovery were found to increase substantially.