A study on the carbon dioxide injection into coal seam aiming at enhancing coal bed methane (ECBM) recovery

Carbon dioxide (CO2) from energy consumption is a primary anthropogenic greenhouse gas. Injection of CO2 in coalbeds is a plausible method of reducing atmospheric emissions, and it can have the additional benefit of enhancing methane recovery from coal. Most previous studies have evaluated the merits of CO2 disposal in high-rank coals. The objective of this research is to determine the technical and economic feasibility of CO2 sequestration in, and enhanced coalbed methane (ECBM) recovery from, low-rank coals in the Texas Gulf Coast area. Our research included an extensive coal characterization program, deterministic and probabilistic simulation studies, and economic evaluations. We evaluated both CO2 and flue-gas injection scenarios. In this study, coal-core samples and well pressure transient test data were obtained for characterization of Texas low-rank coals. Simulation studies evaluated the effects of well spacing, injectant fluid composition, injection rate, and dewatering on CO2 sequestration and ECBM recovery. Probabilistic simulation of 100% CO2 injection in an 80-ac five-spot pattern indicates that Wilcox Group coals can store 1.27–2.25 bcf of CO2 at depths of 6200 ft (1890 m), with an ECBM recovery of 0.48–0.85 bcf. Simulation results of 50% CO2–50% N2 injection in the same 80-ac five-spot pattern indicate that these coals can store 0.86–1.52 bcf of CO2, with an ECBM recovery of 0.62–1.10 bcf. Simulation results of flue-gas injection (87% N2–13% CO2) indicate that these same coals can store 0.34–0.59 bcf of CO2 with an ECBM recovery of 0.68–1.20 bcf. Economic modeling of CO2 sequestration and ECBM recovery for 100% CO2 injection indicates predominantly negative economic indicators for the reservoir depths and well spacings investigated, using natural gas prices ranging from $2 to $12/mscf and CO2 credits based on carbon market prices ranging from $0.05 to $1.58/mscf CO2 ($1.00 to $30.00/ton CO2). Injection of flue gas (87% N2–13% CO2) results in better economic performance than injection of 100% CO2. Moderate increases in either gas prices or carbon credits could generate attractive economic conditions that, combined with the close proximity of many CO2 point sources near unminable coalbeds, could generate significant CO2 sequestration and ECBM potential in Texas low-rank coals.

A feasibility study of ECBM recovery and CO2 storage for a producing CBM field in Southeast Qinshui Basin, China

Coal samples of different rank were extracted in the laboratory with supercritical CO2 to evaluate the potential for mobilizing hydrocarbons during CO2 sequestration or enhanced coal bed methane recovery from deep coal beds. The concentrations of aliphatic hydrocarbons mobilized from the subbituminous C, high-volatile C bituminous, and anthracite coal samples were 41.2, 43.1, and 3.11 ?g g-1 dry coal, respectively. Substantial, but lower, concentrations of polycyclic aromatic hydrocarbons (PAHs) were mobilized from these samples: 2.19, 10.1, and 1.44 ?g g-1 dry coal, respectively. The hydrocarbon distributions within the aliphatic and aromatic fractions obtained from each coal sample also varied with coal rank and reflected changes to the coal matrix associated with increasing degree of coalification. Bitumen present within the coal matrix may affect hydrocarbon partitioning between coal and supercritical CO2. The coal samples continued to yield hydrocarbons during consecutive extractions with supercritical CO2. The amount of hydrocarbons mobilized declined with each successive extraction, and the relative proportion of higher molecular weight hydrocarbons increased during successive extractions. These results demonstrate that the potential for mobilizing hydrocarbons from coal beds, and the effect of coal rank on this process, are important to consider when evaluating coal beds for CO2 storage.

This study proposes the screening criteria for optimum CO2 injection to enhanced coalbed methane (ECBM) recovery as well as predicting CO2 storage capacity by developing a novel numerical model based on the characteristic of coal seams and CBM field in South Sumatera Basin, Indonesia. The comparison of primary and enhanced CBM recovery was analysed by performing production forecasting for 30 y of simulation. A sensitivity study was then conducted in order to examine the performance of ECBM under the influences of CBM reservoir properties which are fracture permeability, matrix porosity, reservoir temperature, and coal seam depth. In summary, the reservoir screening criteria for successful application of CO2-ECBM have been fully defined and proposed. The key criteria of reservoir characteristics for successful application of CO2- ECBM are likely to be homogeneous reservoir, simple structure, fracture permeability more than 2 mD, matrix porosity more than 0.5 %, reservoir temperature less than 100 °C, and coal seam depth more than 500 m. Furthermore, the method for estimating CO2 storage capacity in coal seams has been proposed by simplifying the Original Gas in Place (OGIP) volumetric computation which is validated with the numerical model through sensitivity studies. The proposed equation is applicable for 100 % gas saturation in coal matrix and adsorption process as the main and the only storage mechanism in coal seams.

A review of experimental research on Enhanced Coal Bed Methane (ECBM) recovery via CO2 sequestration

Preliminary Understanding of CO2 Sequestration and Enhanced Methane Recovery in Raniganj Coalfield of India by Reservoir Simulation

Challenges and issues for CO2 storage in deep coal seams

Numerical simulations on the performance of CO2 storage and enhanced coal bed methane (ECBM) recovery in coal beds are presented. For the calculations, a one-dimensional mathematical model is used consisting of mass balances describing gas flow and sorption, and a geomechanical relationship to account for porosity and permeability changes during injection. Important insights are obtained regarding the gas flow dynamics during displacement and the effects of sorption and swelling on the ECBM operation. In particular, initial faster CH4 recovery is obtained when N2 is added to the injected mixture, whereas pure CO2 allows for a more effective displacement in terms of total CH4 recovery. Moreover, it is shown that coal swelling dramatically affects the gas injectivity, as the closing of the fractures associated with it strongly reduces coal’s permeability. As a matter of fact, injection of flue gas might represent a useful option to limit this problem.

Coal characterization for ECBM recovery: Gas sorption under dry and humid conditions, and its effect on displacement dynamics

Nitrogen (N2) and carbon dioxide (CO2) gases injection yield substantially various recovery ways. Here, a one-dimensional mathematical model is applied comprising of mass balances for explaining gas sorption and flow, and a geomechanical relationship to describe the permeability changes during gas injection. That’s why numerical simulations for investigating the performance of injecting flue gas mixture in enhanced coal bed methane (ECBM) recovery are represented. Significant intuitive features are found regarding the gas flow dynamics at the time of displacement and influences of sorption on ECBM operation. The study revealed that the injection of pure CO2 causes much reduction in cleat permeability, but pure N2 is injected to increase the permeability without any loss of injectivity. Therefore, pure CO2 causes more efficient displacement in terms of total CH4 recovery, while the addition of N2 to the mixture assists to make quicker the initial methane recovery.

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.

Injection of CO2 into deep unminable coal seams is an option for geological storage of CO2. Moreover, injection of CO2 may enhance the recovery CH4 in these systems making coal reservoirs interesting candidates for sequestration. New analytical solutions are presented for two-phase, three- and four-component flow with volume change on mixing in adsorbing systems. We analyze the simultaneous flow of water and gas containing multiple adsorbing components. The displacement problem is solved by the method of characteristics. Mixtures of N2, CH4, CO2 and H2O are used to represent enhanced coal bed methane recovery processes. The displacement behavior is demonstrated to be strongly dependent on the relative adsorption strength of the gas components. In ternary systems, two types of solutions result. When a gas rich in CO2 displaces a less strongly adsorbing gas (like CH4), a shock solution results. As the injected gas propagates through the system, CO2 is removed from the mobile phase by adsorption, while desorbed gas propagates ahead of the CO2 front. The adsorption of CO2 reduces the flow velocity of the injected gas, delaying breakthrough and allowing for more CO2 to be sequestered per volume of CH4 produced. For injection gases rich in N2, a decrease in partial pressure is required to displace the preferentially adsorbed CH4, and a rarefaction solution results. In quaternary displacements with injection gas mixtures of CO2 and N2, the relative adsorption strength of the components result in solutions that exhibit features of both the N2-rich and CO2-rich ternary displacements. Analytical solutions for enhanced coal bed methane (ECBM) recovery processes provide insight into the complex interplay of adsorption, phase behavior and convection. Improved understanding of the physics of these displacements will aid in developing more efficient and physically accurate techniques for predicting the fate of injected CO2 in the subsurface.

Methane production from coalbed methane (CBM) fields started as a method for keeping coal mining safe from explosions. Major CBM fields are located in San Juan, Powder River, Forest City, Black Worrier and Illinois. Majority of the US natural gas production comes from coalbed methane formations. These formations also have the potential of carbon dioxide (CO2) storage through enhanced gas recovery operations. Enhanced coalbed methane (ECBM) recovery by injection of gases such as CO2, nitrogen (N2) or a mixture of both gases has been proven to recover additional natural gas resources. Most of the coalbed methane formations contain large amounts of water or can be in communication with an aquifer. As a result a large amount of water is often co-produced during the natural gas extraction. The water being produced from deep formations is not high purity water and contains nitrate, nitrite, and chlorides and has high level of total dissolved solids. Production of methane from CBM is facilitated by the reduction of the methane partial pressure in the coal seam by either pumping the formation water to the surface or by injecting a dissimilar gas. The produced water contains a lot of harmful impurities which should be removed. Therefore, disposal of the produced water is an environmental challenge and accordingly, a reduction of the produced water is enviable. In this paper we present a detailed numerical investigation of the potential reduction in water production during ECBM operations while increasing the methane production. We employ a three-dimensional coalbed model with an aquifer located on the bottom to investigate the amounts of gas and water produced in ECBM operations per volume of coal seam as a function of aquifer strength, cleat spacing and sorption characteristics of the coal. The amount of gas/water that is produced varies extensively depending on the aquifer strength. We demonstrate that injection of CO2 and/or N2 in some settings reduces the water handling problem substantially. CBM is an essential energy source with a lot of formations being exceptional candidates for ECBM recovery processes. The analysis we present in this paper on the water production reduction by using the injection gas which relatively produces less water provides new strategy for future operations.

Although the enhanced coal-bed methane (ECBM) recovery process is one of the potential coal bed methane production enhancement techniques, the effectiveness of the process is greatly dependent on the seam and the injecting gas properties. This study has therefore aimed to obtain a comprehensive knowledge of all possible major ECBM process-enhancing techniques by developing a novel 3D numerical model by considering a typical coal seam using the COMET 3 reservoir simulator. Interestingly, according to the results of the model, the generally accepted concept that there is greater CBM (coal-bed methane) production enhancement from CO2 injection, compared to the traditional water removal technique, is true only for high CO2 injection pressures. Generally, the ECBM process can be accelerated by using increased CO2 injection pressures and reduced temperatures, which are mainly related to the coal seam pore space expansion and reduced CO2 adsorption capacity, respectively. The model shows the negative influences of increased coal seam depth and moisture content on ECBM process optimization due to the reduced pore space under these conditions. However, the injection pressure plays a dominant role in the process optimization. Although the addition of a small amount of N2 into the injecting CO2 can greatly enhance the methane production process, the safe N2 percentage in the injection gas should be carefully predetermined as it causes early breakthroughs in CO2 and N2 in the methane production well. An increased number of production wells may not have a significant influence on long-term CH4 production (50 years for the selected coal seam), although it significantly enhances short-term CH4 production (10 years for the selected coal seam). Interestingly, increasing the number of injection and production wells may have a negative influence on CBM production due to the coincidence of pressure contours created by each well and the mixing of injected CO2 with CH4.

When enhancing coalbed methane recovery using CO2 or N2 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 CO2 injection rate is very high, a large amount of CO2 moves through cleat instead of adsorbed in matrix, which causes early CO2 breakthrough. In ECBM, N2 mostly acts as a displacing agent of methane, because co-diffusion of N2 with methane is more dominant than counter-diffusion owing to its extremely low adsorption affinity. On the other hand, CO2 is rapidly adsorbed due to its fast increasing rate of diffusion coefficient with pressure increase. Consequently, CO2 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 CO2 occurs accordingly. This study confirms that the CO2–N2 mixed gas injection is advisable comparing to only injecting CO2 to pursue the prevention of CO2 injectivity reduction and enhanced methane recovery, simultaneously.