10 - Enhanced CBM 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.

Seal evaluation and confinement screening criteria for beneficial carbon dioxide storage with enhanced coal bed methane recovery in the Pocahontas Basin, Virginia

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.

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.

Coal seams, particularly deep unmineable coal reservoirs, are the most important geological desirable formations to store CO2 for mitigating the emissions of greenhouse gas. An advantage of this process is that a huge quantity of CO2 can be sequestrated and stored at relatively low pressure, which will reduce the amount of storage cost required for creating additional platform to store it. The study on CO2 storage in coal seam to enhance coal bed methane (ECBM) recovery has drawn a lot of attention for its worldwide suitability and acceptability and has been conducted since two decades in many coalmines. This article focuses on the coal seam properties related to CO2 adsorption/desorption, coal swelling/shrinkage, diffusion, porosity and permeability changes, thermodynamic/thermochemical process, flue gas injection, etc. Here, the performance analysis of both CO2 storage and ECBM recovery process in coal matrixes is investigated based on the numerical simulation. In this study, a one-dimensional mathematical model of defining mass balances is used to interpret the gas flow and the gas sorption and describe a geomechanical relationship for determining the porosity and the permeability alteration at the time of gas injection. Vital insights are inspected by considering the relevant gas flow dynamics during the displacement and the influences of coal swelling and shrinkage on the ECBM operation. In particular, pure CO2 causes more displacement that is more efficient in terms of total CH4 recovery, whereas the addition of N2 to the mixture assists to make quicker way of the initial methane recovery. However, this study will support future research aspirants working on the same topic by providing a clear conception and limitation about this study.

Carbon dioxide (CO2) from energy consumption is a primary source of 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 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 - acre 5-spot pattern indicate that these coals can store 1.27 to 2.25 Bcf of CO2 with an ECBM recovery of 0.48 to 0.85 Bcf. Simulation results of 50% CO2 - 50% N2 injection in the same 80-acre 5-spot pattern indicate that these coals can store 0.86 to 1.52 Bcf of CO2, with an ECBM recovery of 0.62 to 1.10 Bcf. Simulation results of flue gas injection (87% N2 - 13% CO2) indicate that these same coals can store 0.34 to 0.59 Bcf of CO2 at depths of 6,200 ft, with an ECBM recovery of 0.68 to 1.20 Bcf. Economic modeling of CO2 sequestration and ECBM recovery for 100% CO2 injection indicates predominately negative economic indicators for the reservoir depths and well spacings investigated, using natural gas prices ranging from $2 to $12 per Mscf and CO2 credits based on carbon market prices ranging from $0.05 to $1.58 per Mscf CO2 ($1.00 to $30.00 per 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 unmineable coalbeds, could generate significant CO2 sequestration and ECBM potential in Texas low-rank coals.

Modelling desorption-controlled reservoirs is a difficult matter owing to the complex nature of hydrocarbon transport processes. The complexity of enhanced coalbed methane (ECBM) recovery is not only caused by desorption-controlled behaviour of coalbed reservoirs, but also the interaction between coal media and the injected CO2/N2 gas mixture, which changes the coal properties with respect to injection time. In addition, the characterization of coal reservoirs and the determination of in situ coal properties related to the transport mechanism of methane are complicated, as there is a lack of standard procedures in the literature. In considering these difficulties, this study took the approach that relationships between rank and physical properties of coal be used for evaluation purposes. Parametric simulation studies with rank classification provided more representative results for coal reservoirs rather than univariate analysis. Besides coal rank, simulation cases were run for different reservoir types, well patterns, molar compositions of injected fluid and well types. The shrinkage/swelling process was taken into account by making use of the extended Palmer/Mansoori model. As a result, ECBM recovery was studied in field-scale with rank-dependent coal properties and different operational parameters in order to provide an overview. Introduction In the literature, there are parametric simulation studies(1–3) investigating the effect of each coal property on primary and enhanced coalbed methane recoveries. The trend has been generally to change a model parameter in a given range and to observe its impact on total methane recovery. In our previous study, however, a new approach was followed during preparation of input data for a commercial compositional simulator: Computer Modelling Group's GEM module(4, 5). Instead of using a real field or a hypothetical data set, rank-dependent coal properties in the literature were gathered to create a database. This database enabled us to acquire more realistic outputs from the simulator. In this paper, however, the rank-dependent database was used to simulate the effects of different coal properties and operational parameters on ECBM recovery. The following section gives information about these cases. Simulation Cases In this study, four different vertical well cases were run to observe the behaviour of our data set(5). In addition, horizontal well cases were simulated and compared to vertical well cases. All simulations started with the primary recovery of methane (CBM) which takes 10 years. After 10 years, the ECBM recovery technique was used for all cases except the methane-saturated dry coal case. The aim of 10 years primary recovery is to decrease the water saturation in the cleat system and to increase the relative permeability of the gas before the injection of the CO2 or CO2/N2 mixture. As there is initially no water in the fractures of methane-saturated dry coals, ECBM recovery is applied at the beginning. As for other modelling parameters, depth and thickness of the coal seam are taken as 915 m (3,000 ft) and 6.1 m (20 ft), respectively. The average geothermal gradient is about 2.5 to 3 °C/100 m. Initial reservoir temperature is calculated as 45 °C.

Enhancing coalbed methane recovery through injection of CO2 in depleted low pressure coal reservoir is a potential, economic and environmentally suitable solution to reduce greenhouse gas emissions. In India, commercial coalbed methane (CBM) production has been started since 2007 at Raniganj and Sohagpur basins and subsequently to Jharia and Bokaro coalfields. CBM reservoirs are at low pressure, and after some years of production through primary reduction of hydrostatic pressure, rate of recovery declines and harms the well economics. In a secondary drive, the CO2 or CO2 + N2 or other mixture of gases can be injected to enhance the methane recovery and to maintain reservoir pressure. Studies conducted so far support stronger affinity of CO2 to the coal molecule, displacing each methane molecule by 2–3 molecules of CO2. Coal may adsorb more carbon dioxide than methane and that carbon dioxide is preferentially adsorbed onto the coal structure over methane (with 2:1 ratio). High-pressure methane and CO2 sorption measurements were carried out for various coal seams in India. On the basis of CO2 sorption capacity, seam thickness and extension, the suitable sites and their storage capacities estimated to be 4459 Mt for CO2. It is assumed that this quantity of storage is sufficient to store over 20% of total gas emission from the present power plants over their lifetime. The sites close to the operating thermal power units may be the most appropriate for CO2 sequestration as the transportation cost of the gas will be minimum. The rate of CO2 generation and total CO2 generated within the life span of a thermal power station presuming 20 years more from the date will be helpful for enhanced coalbed methane (ECBM) process in the close vicinity of CBM blocks. It is also required that geologic data and experimentally determined mineralization reaction rates and kinetics should be incorporated into geochemical models to predict the permanent storage of CO2 in unmineable deep coals after ECBM recovery.

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.

The transient behaviour of CO2 flow with phase transition in injection wells during geological storage – Application to a case study

Modeling desorption-controlled reservoirs is a struggling issue owing to the complex nature of hydrocarbon transport processes. Complexity of enhanced coalbed methane (ECBM) recovery is not only caused by desorption-controlled behavior of coalbed reservoirs but also the interaction between coal media and injected CO2 / N2 gas mixture, which changes the coal properties with respect to injection time. In addition, the characterization of coal reservoirs and determination of in-situ physical properties related to transport mechanism are complicated due to having lack of a standardized procedure in the literature. By considering these difficulties, a new approach has been developed proposing the usage of relationships between rank and physical properties of coal. Parametric simulation studies with the rank classification provided more representative results for the coal reservoirs rather than the univariate analysis. Besides coal rank, simulation cases were run for different reservoir types, well-patterns, drainage areas, anisotropies, cleat permeabilities, molar compositions of injected fluid and well types. For all these cases, shrinkage/swelling process was also taken into account by making use of extended Palmer/Mansoori model. As a result, ECBM recovery process was studied in detail with rankdependent coal properties and operational parameters in order to prepare a guideline for decision makers. Introduction In the literature, there are parametric simulation studies (1, 2, 3) investigating the effect of each coal property on primary and enhanced coalbed methane recoveries. The trend is generally to change a model parameter in its range and to observe its impact on total methane recovery. In this study, however, a new approach was followed during preparation of input data for a commercial compositional simulator, CMG (Computer Modeling Group) /GEM module. Instead of using a real field or a hypothetical data set, rank-dependent coal properties in the literature were selected to construct a database. This database enabled us to acquire more realistic outputs from the simulator. In the following section, methodology followed up during preparation of rank-dependent coal properties is explained. Methodology Most of the rank dependent coal properties in the literature are provided with respect to vitrinite reflectance and carbon contents of coal. Intervals of these parameters corresponding to a specific coal rank are provided in Table A.1. Moreover, in Table A.2 and Table A.3, simulation inputs with respect to rank of coal are given with their references. Conversion coefficients from field unit to SI unit are provided in Table A.5. Coal is a dual-porosity media including cleats (fractures) and matrix blocks. As Scott (5) stated, indirect measurements using drill stem tests and/or production modeling suggest that cleat permeability is generally ranges between 0.5 and 100 md. Hence, five different permeability cases were selected in the given range. These are 4, 10, 25, 50 and 100 md. When it is compared to cleat permeability, coal matrix permeability is very small. Laubach (6) states that over 95% of the gas in coal is stored in micropores of coal matrix ranging from 0.5 to 1 nm, which causes no effective permeability in matrix. Thus, matrix permeability in our model was defined as 0.001 md.

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

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

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