TY - JOUR
AU1 - Perera, M S, A
AU2 - Ranjith, P, G
AU3 - Ranathunga, A, S
AU4 - Koay, A Y, J
AU5 - Zhao,, J
AU6 - Choi, S, K
AB - Abstract 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. coal-bed methane, recovery techniques, optimization measures, numerical simulation 1. Introduction Fossil fuels such as coal, petroleum and natural gases have long been used to produce energy. These fuels are important as they can be burned, producing significant amounts of energy per unit weight. Of the various fossil fuels, coal-bed methane (CBM), a natural gas extracted from coal beds, has attracted scientific attention in recent years in many countries including Canada, the USA and Australia (Perera et al2011b, 2012b, Ranjith and Perera 2012). This CBM has been formed during millions of years of coalification. Most CBM exists in an adsorbed phase in the coal matrix, with a percentage as free gas in the fracture pore space. To extract CBM, methane is first desorbed from the internal coal surfaces, diffuses through the coal matrix and micro-pores, and then it becomes a free gas that travels into the natural fracture network (or cleats), where it is harvested using a pipe. Today, many advanced technologies exist to identify the potential locations of CBM reservoirs, including the seismic frequency spectrum (Wang 2012). If the available CBM recovery techniques are considered, the traditional CBM recovery technique involves the reduction of overall pressure in the coal seam by dewatering, either by pumping or mining. However, according to recent scientific findings, this CBM recovery process can be greatly enhanced through the injection of some gases, such as carbon dioxide (CO2) or nitrogen (N2), into the coal bed (Fujioka et al1995, White et al2005, Perera et al2010, 2012c, Vishal et al2013a), which is commonly known as enhanced coal-bed methane (ECBM) recovery. In the CO2 injection-enhanced ECBM process (CO2-ECBM), when CO2 is injected into a coal seam, it displaces the CBM due to its higher affinity with coal. This has the added advantage of sequestering carbon dioxide in the coal bed, which reduces the amount of net carbon emissions, making methane extracted using ECBM recovery techniques one of the greenest sources of energy. In Australia, carbon was initially priced at AUD $23/ton (Maimone 2011), which would go a long way towards enhancing the economic viability of ECBM, coupled with increasing gas prices. With regard to the N2-ECBM technique, according to Reeves (2001) the injection of N2 into the coal seam causes the CBM production rate to be significantly increased. This is mainly due to the non-adsorptive nature of N2, which causes it to remain as free gas in the fracture space, resulting in the creation of an imbalance between sorbed and free gas phases inside the coal mass and reduction of the CH4 partial pressure. This process causes the CBM to be released from the adsorbed phase and to move into the free gas phase, which enhances the methane production rate from the coal seam (Reeves 2001, Perera et al2012d). Although the CO2-ECBM and N2-ECBM recovery processes have the ability to enhance the methane production from coal seams, they also have limitations. ECBM is a relatively new technology with relatively few commercial wells to date. Some of the pilot projects include the ARC (Reeves 2003, Reeves and Odinot 2004), RECOPOL (Pagnier et al2006), and MOVECBM (Wageningen and Cuesta 2005) projects. In these projects, ECBM has been used to extract more methane in conventional CBM wells only after the rate of methane production has dropped significantly, because ECBM recovery has many associated economic risks. Drilling wells to deep coal seams is a highly expensive process, and therefore production and field-scale testing have become quite expensive (Ranjith et al2013). This has caused less investment in ventures in which there are significant risks of a limited return on investment. The major costing parameters for the process include; CO2 and N2 injection costs, processing and implementation costs, transportation expenses and the market value of the methane produced. In order to have an economical ECBM process, the value of the produced gas should exceed the production cost plus the cost of transporting the gas, minus the cost of taxes or CO2 credits (Reeves 2003). Therefore, ECBM recovery projects can be made to be more economical by using existing facilities, such as converting production wells for injection and using time-tested technological approaches, such as the organization of injection wells and production wells. However, such optimum recovery scenarios have not been properly studied to date, although such techniques are important to the economic aspect of projects in terms of harvesting an optimum amount of methane with the minimum capital cost. According to Reeves (2003), the lack of knowledge related to the ECBM process has also crucially affected the ECBM process implementation in the field, and according to Pini et al (2006), it is necessary to conduct a broader range of scientific research studies to overcome this issue. Injection of CO2 into deep coal seams causes significant alterations to their chemico-physical structure, where a coal matrix swelling effect created by injecting CO2 is significant (White et al2005). This can start as soon as 1 h after CO2 injection, causing the seam’s permeability to be significantly reduced, and resulting in unpredictable CO2 injectibilities in and CH4 productivities of coal seams (Perera et al2011a, 2011b, 2011c, Perera and Ranjith 2012, Vishal et al2013b, 2013c). According to Perera et al (2011c), this swelling process is heavily dependent on the CO2 phase condition, and super-critical CO2 adsorption-induced swelling is up to two times higher than sub-critical CO2 adsorption-induced swelling. Therefore, the injection of CO2 into the coal seam, particularly under the super-critical conditions which exist below certain depths, greatly reduces flow ability through the coal mass by closing the pore space, consequently creating greater tortuosity for CO2 movement and resulting in less coal mass permeability (Viete and Ranjith 2006, Perera et al2011b, 2012a). In addition, existing safety rules in underground coal mines limit the amount of CO2 permitted in them; the maximum percentage of CO2 in a coal mine should be around 3% of the mine’s air volume. Therefore, there is a risk associated with the injection of CO2 into coal seams during the CO2-ECBM process that may cause the coal seam to be un-mineable forever (Sarmah 2011). However, the significant contribution of the CO2-ECBM process to the mitigation of atmospheric CO2 levels through CO2 sequestration also needs to be considered from the environmental protection perspective (Perera et al2011e). Therefore, performance evaluation of the process under various conditions (different injection gas properties and seam properties) is very important for the optimization of the CO2-ECBM process. In the N2-ECBM technique, the existence of free N2 in the seam causes quicker N2 breakthroughs in the gas produced, which greatly reduces the benefits offered by the process when the higher gas treatment costs are taken into account (Reeves 2001). For instance, specialized equipment is required to separate the N2 from the product gas stream (a mixture of N2 and CH4 (Mazzotti et al2009)), which is quite expensive. This has been observed in both the Tiffany N2-ECBM unit in the San Juan basin as well as the Alberta ECBM project (Reeves and Odinot 2004, Gunter 2009). However, according to current research, there is a significantly higher production potential for the N2-ECBM process compared to the CO2-ECBM process (Perera and Ranjith 2012), which also needs to be considered. Therefore, clearly it is necessary to find the optimum technique for the ECBM process with maximum productivity and minimum risk and environmental impact. Some studies have shown the advantages of flue gas (87% N2 + 13% CO2) injection compared to pure CO2 or N2 injections (Reeves and Schoeling 2000), because the injection of a mixture of N2 + CO2 offers higher methane productivity with an earlier response compared to pure CO2 injection and it sequestrates similar amounts of CO2 due to the higher injection rate. In addition, N2 has some potential to recover CO2 injection-induced swelling (Jasinge et al2011, Perera et al2012b, 2013a, Vishal et al2013a), which also results in a greater injectability of the N2/CO2 mixture compared to pure CO2. Although the use of flue gas seems to be the optimum way to harvest commercially-viable amounts of CBM in an environmentally friendly way, the injection of a CO2/N2 mixture at a predetermined ratio possibly offers a better solution. However, to date few studies have been conducted on the N2 + CO2-ECBM technique. According to the experimental study conducted by Parakh (2007), the injection of 45% N2 + 55% CO2 gas mixture causes an initially high rate of production due to the N2 and the rate gradually becomes slower due to the CO2. The fieldwork in the Fenn Big Valley basin in Alberta, Canada (Gunter 2009, Wong et al2000) involves the injection of different proportions of N2/CO2 (0% N2, 53% N2, 87% N2 and 100% N2) into the 1–4 md low permeable Mannville reservoir using two injection wells. This project illustrates that the injection of a mixture of N2 + CO2 may help reduce the problems associated with CO2 injection-induced coal swelling and early breakthrough with N2 injection, and that flue gas injection avoids the high cost associated with the pure N2/CO2 capture process. However, it is necessary to conduct a comprehensive study to fully understand the process and find the best CO2/N2 composition to achieve optimum productivity and safety advantages related to the ECBM process. The results will be important for ECBM recovery field projects worldwide. In addition, as ECBM recovery is an expensive and time-consuming process, it is necessary to establish appropriate numerical models to find the optimum method to recover a maximum amount of CH4 from a selected coal seam. Among the many field-scale simulators available to simulate gas flow in underground reservoirs, TOUGH 2 (Carneiro 2009), COMSOL (Liu and Smirnov 2009, Perera et al2013b), FEMLAB (Holzbecher 2005) and COMET 3 (Perera et al2012a, 2012b, 2012d, Vishal et al2012, 2013d, 2015), COMET 3 has been identified as one of the most appropriate and user-friendly numerical modeling tools for deep coal seams (Perera et al2012d). Therefore, the main objective of this study is to conduct a comprehensive numerical modeling study using COMET 3 software to investigate the optimizing measures for the ECBM process. Although some experimental, numerical and field studies have been conducted on the ECBM process and production enhancement techniques, none has considered the influences of all the possible primary effective factors for the process, and it has therefore been difficult to obtain comprehensive knowledge of the subject. This study will therefore offer a comprehensive platform for the study of all possible major ECBM process-enhancing techniques. 1.1. Governing equations used Mass conservation equations (equations (1) and (2)) were used to simulate the CH4, CO2, N2 and water flows in the deep coal seam (Sawyer et al1990, Perera et al2011d, 2012d, Ranjith et al2013): ∇.[bgMg(∇pg+γg∇Z)+RswbwMw(∇pw+γw∇Z) ︀]f+qm+qg=(ddt)(φbgSg+RswφbwSw)f1 ∇.[bwMw(∇pw+γw∇Z)]f+qw=(ddt)(φ bwSw)f2 where bn (n = g or w) is the gas or water bulking factor, γn is the gas or water gradient, Rsw is the gas solubility in water, φ is the fracture porosity, z is the elevation, qg is the gas flow rate, qw is the water flow rate, qm is the matrix gas flow rate, Mn = kkm/μn, is the phase mobility, (k-permeability, km-matrix permeability, μn-phase viscosity), Sn is the gas or water saturation, and Pn is the gas or water pressure. Gas adsorption and desorption processes were included in the model using the extended Langmuir model (Perera et al2012c): Ci(Pi)=VLiPiPLi[1+∑j = 13(PPL)j],i=1,23 where VLi is the Langmuir volume, PLi is the Langmuir pressure, Pi is the partial pressure of the gas component, Ci(Pi) is the adsorbed gas concentration at Pi, and P is the total pressure. Fick’s law of diffusion was used to simulate the gas flow through the matrix (equation (4)): qmi=(Vm/τi)[Ci-Ci(Pi)],i=1,24 where, qmi is the gas component flow, Vm is the bulk volume of the matrix element, τi is the sorption time, and Ci is the average matrix gas concentration of gas component i. The corresponding permeability variations in the coal matrix and fracture system were simulated using the Advanced Resources International (ARI) model (equations (5) and (6)): φ=φi[1+cp(P-Pi)]-cm(1-φi)(ΔPiΔCi)(C-Ci)5 kki=(ϕϕi)n6 where cp is the pore volume compressibility, cm is the matrix shrinkage compressibility, φ is the coal mass porosity, φi is the initial coal mass porosity, P is the reservoir pressure, Pi is the initial reservoir pressure, C is the reservoir concentration, Ci is the initial reservoir concentration, k is the reservoir permeability, and ki is the initial reservoir permeability. 2. Model development A 500 m × 500 m × 20 m unmineable coal seam lying 1000 m below the ground surface was considered for the model development, and gas production and injection were carried out at opposite corners of the coal seam, as shown in figure 1. Table 1 shows the model parameters used. First, ordinary methane (CH4) production capacity from the coal bed was examined without using any enhancing technique such as water production or CO2/N2 injection and the CH4 production during 50 years of production was simulated and examined. Figure 1. Open in new tabDownload slide Enhanced coal seam CH4 production process. Figure 1. Open in new tabDownload slide Enhanced coal seam CH4 production process. Table 1. Model parameters. Model parameter . Value . Coal seam moisture content 0.9 cm3/cm3 (Connell et al2011) Coal seam initial permeability 2 md (Connell et al2011) Coal seam porosity 0.015 (Connell et al2011) Coal seam initial temperature 50 °C (Connell et al2011) Exponent of pressure-dependent permeability 3 (Pekot and Reeves 2002) Differential swelling factor for CO2 1.5 (Pekot and Reeves 2002) Relative permeability variation Cooray formula (Akin 2001), residual water and gas contents are 0.05 and 0.01 (cm3/cm3) Initial gas content in the coal seam 100% CH4 (Connell et al2011) Initial pore pressure Calculated from Po = h × ρw × g formula, where h is the depth, ρw is the water density and g is the gravitational acceleration Langmuir parameters Langmuir pressure for CO2 1289 kPa (Balan and Gumrah 2009) Langmuir volume for CO2 55 m3/m3 (Balan and Gumrah 2009) Langmuir pressure for CH4 2529 kPa (Balan and Gumrah 2009) Langmuir volume for CH4 36.48 m3/m3 (Balan and Gumrah 2009) Langmuir pressure for N4 7000 kPa (Balan and Gumrah 2009) Langmuir volume for N4 18 m3/m3 (Balan and Gumrah 2009) Pore volume compressibility for coal 5.000000e-005 1/kPa (Connell et al2011) Matrix shrinkage compressibility for coal 3.850000e-007 1/kPa (Connell et al2011) Model parameter . Value . Coal seam moisture content 0.9 cm3/cm3 (Connell et al2011) Coal seam initial permeability 2 md (Connell et al2011) Coal seam porosity 0.015 (Connell et al2011) Coal seam initial temperature 50 °C (Connell et al2011) Exponent of pressure-dependent permeability 3 (Pekot and Reeves 2002) Differential swelling factor for CO2 1.5 (Pekot and Reeves 2002) Relative permeability variation Cooray formula (Akin 2001), residual water and gas contents are 0.05 and 0.01 (cm3/cm3) Initial gas content in the coal seam 100% CH4 (Connell et al2011) Initial pore pressure Calculated from Po = h × ρw × g formula, where h is the depth, ρw is the water density and g is the gravitational acceleration Langmuir parameters Langmuir pressure for CO2 1289 kPa (Balan and Gumrah 2009) Langmuir volume for CO2 55 m3/m3 (Balan and Gumrah 2009) Langmuir pressure for CH4 2529 kPa (Balan and Gumrah 2009) Langmuir volume for CH4 36.48 m3/m3 (Balan and Gumrah 2009) Langmuir pressure for N4 7000 kPa (Balan and Gumrah 2009) Langmuir volume for N4 18 m3/m3 (Balan and Gumrah 2009) Pore volume compressibility for coal 5.000000e-005 1/kPa (Connell et al2011) Matrix shrinkage compressibility for coal 3.850000e-007 1/kPa (Connell et al2011) Open in new tab Table 1. Model parameters. Model parameter . Value . Coal seam moisture content 0.9 cm3/cm3 (Connell et al2011) Coal seam initial permeability 2 md (Connell et al2011) Coal seam porosity 0.015 (Connell et al2011) Coal seam initial temperature 50 °C (Connell et al2011) Exponent of pressure-dependent permeability 3 (Pekot and Reeves 2002) Differential swelling factor for CO2 1.5 (Pekot and Reeves 2002) Relative permeability variation Cooray formula (Akin 2001), residual water and gas contents are 0.05 and 0.01 (cm3/cm3) Initial gas content in the coal seam 100% CH4 (Connell et al2011) Initial pore pressure Calculated from Po = h × ρw × g formula, where h is the depth, ρw is the water density and g is the gravitational acceleration Langmuir parameters Langmuir pressure for CO2 1289 kPa (Balan and Gumrah 2009) Langmuir volume for CO2 55 m3/m3 (Balan and Gumrah 2009) Langmuir pressure for CH4 2529 kPa (Balan and Gumrah 2009) Langmuir volume for CH4 36.48 m3/m3 (Balan and Gumrah 2009) Langmuir pressure for N4 7000 kPa (Balan and Gumrah 2009) Langmuir volume for N4 18 m3/m3 (Balan and Gumrah 2009) Pore volume compressibility for coal 5.000000e-005 1/kPa (Connell et al2011) Matrix shrinkage compressibility for coal 3.850000e-007 1/kPa (Connell et al2011) Model parameter . Value . Coal seam moisture content 0.9 cm3/cm3 (Connell et al2011) Coal seam initial permeability 2 md (Connell et al2011) Coal seam porosity 0.015 (Connell et al2011) Coal seam initial temperature 50 °C (Connell et al2011) Exponent of pressure-dependent permeability 3 (Pekot and Reeves 2002) Differential swelling factor for CO2 1.5 (Pekot and Reeves 2002) Relative permeability variation Cooray formula (Akin 2001), residual water and gas contents are 0.05 and 0.01 (cm3/cm3) Initial gas content in the coal seam 100% CH4 (Connell et al2011) Initial pore pressure Calculated from Po = h × ρw × g formula, where h is the depth, ρw is the water density and g is the gravitational acceleration Langmuir parameters Langmuir pressure for CO2 1289 kPa (Balan and Gumrah 2009) Langmuir volume for CO2 55 m3/m3 (Balan and Gumrah 2009) Langmuir pressure for CH4 2529 kPa (Balan and Gumrah 2009) Langmuir volume for CH4 36.48 m3/m3 (Balan and Gumrah 2009) Langmuir pressure for N4 7000 kPa (Balan and Gumrah 2009) Langmuir volume for N4 18 m3/m3 (Balan and Gumrah 2009) Pore volume compressibility for coal 5.000000e-005 1/kPa (Connell et al2011) Matrix shrinkage compressibility for coal 3.850000e-007 1/kPa (Connell et al2011) Open in new tab The production rate was then accelerated by pumping out formation water at 25 m3/day rate for 10 years. In this stage, the production well was used as a water pumping well to reduce the pressure inside the coal seam. Water production was terminated after 10 years and the well was then used to produce methane from the pressure-reduced coal seam for the remaining 40 years. In all of these cases, the injection well was kept shut when it was in operation. After the first 10 years, the CO2-ECBM technique was then examined by injecting CO2 into the coal seam at 12 MPa injection pressure for 40 years. Effective factors for the CO2-ECBM process were then examined to identify possible ECBM process optimization measures. The effect of CO2 injection pressure was first examined by changing the CO2 injection pressure (12.5, 15, 17.5, 20, 22.5 and 25 MPa) and the formation temperature effect was then examined by changing the coal seam temperature (25, 50, 70, 90 and 110 °C) for methane production for 50 years. In the latter case, CO2 injection pressure and bed moisture content were maintained at 20 MPa and 90%, respectively. The effect of coal seam moisture content on enhanced methane production was then examined by changing the coal seam moisture content (20, 50, 70, 90 and 100%), maintaining the CO2 injection pressure at 20 MPa and coal bed temperature at 50 °C. The effect of coal seam depth on CH4 production was examined by changing the coal seam depth (500, 650, 750, 900, and 1000 m) while maintaining the CO2 injection pressure at 20 MPa, coal bed moisture content at 90% and temperature at 50 °C. After investigating the effects of primary effective factors on the ECBM process, the ability of N2 gas to enhance the ECBM production was examined by mixing the injecting CO2 with various percentages of N2 (20, 40, 60, 80 and 100%). In this case, a 20% N2 + 80% CO2 gas mixture was first considered as the injection gas and the corresponding CH4 production enhancement was examined. The N2 percentage in the injecting gas was then gradually increased to 80% and the corresponding CBM production enhancements were examined. After an analysis of the effects of injection gas and coal seam properties on CH4 production, the potential for ECBM process optimization was examined by changing the production and injection well arrangements. In this case, pure CO2 injection-enhanced CH4 production was considered by maintaining the CO2 injection pressure at 20 MPa, the coal seam depth at 1000 m, the moisture content at 90% and the temperature at 50 °C. The effect of the CO2 injection well arrangement was first examined by changing the number of injection wells (1, 2, 3 and 4) and the influence of the production well arrangement on CH4 production was then examined by changing the number of production wells (1, 2, 3 and 4). 3. Results and discussion 3.1. Comparison of CBM production enhancements through water removal and CO2 injection (CO2-ECBM) As described in the model development section, two main techniques were used to accelerate CH4 desorption: coal seam pore pressure depletion by water removal, and the injection of a higher adsorption capacity gas, CO2. Figure 2 compares the effects of each technique on CH4 production. The figure exhibits a significant CBM production enhancement through water removal, because removal of water from the coal seam reduces the pore pressure inside it, which enhances the CH4 desorption rate (Fujioka et al1995). This can be easily examined in figure 3(a), which shows that the removal of water at 25 m3/day rate for 10 years causes the coal seam mean pore pressure to be reduced by around 42%, which in turn causes the CH4 adsorbed, under high pressure, to be released from the coal matrix, which can subsequently be captured. However, according to figure 2, CBM production enhancement created by the CO2-ECBM technique seems to be much more productive compared to the enhancement through water removal, if an appropriate injection pressure is maintained (Fujioka et al1995). Interestingly, according to figure 2, simply injecting CO2 into the coal seam does not enhance CBM production and it is necessary to maintain an appropriate injection pressure to recover an optimum amount of CBM. For example, for the coal seam under consideration 12 MPa injection pressure creates negligible CBM production enhancement and it is necessary to have a higher injection pressure to cause significant CBM production enhancement (figure 2). This can be clearly seen in figure 3, according to which, at around 12 MPa CO2 injection pressure, the reservoir has a fairly low permeability value (1.3 md), which is even less than the original permeability of the coal seam (2 md). This is because the use of CO2 injection causes pore pressure development to occur in the coal seam, which prevents methane release from the coal mass unless an adequate flow rate is maintained. The coal seam under consideration is at a depth of 1000 m and pore pressure at such a depth will be closer to 10 MPa. According to available flow models (e.g. Darcy equation), in order to maintain a proper flow rate through any medium, there should be an adequate pushing force created by the pressure gap between the injecting fluid and the medium. Apparently, 12 MPa injection pressure is insufficient to create such a force. According to figure 3, the CO2 permeability inside the coal seam increases with a rise in injection pressure (figure 3(b)), even though pore pressure inside the seam increases accordingly (figure 3(a)). This is because, although there is a pore pressure development with CO2 injection, the pushing force for the injected CO2 increases with the increasing injection pressure. This results in a higher flow rate and a higher rate of production at higher injection pressures, because both coal permeability and adsorption processes are dependent on injecting gas properties, such as pressure and phase. According to figure 3, the injection pressure should be greater than 15 MPa for the coal seam to have permeability enhancement. Figure 2. Open in new tabDownload slide Comparison of coal seam CH4 production enhancement by water removal and CO2 injection methods. Figure 2. Open in new tabDownload slide Comparison of coal seam CH4 production enhancement by water removal and CO2 injection methods. Figure 3. Open in new tabDownload slide Variation of seam pressure and permeability under water removal and CO2 injection. Figure 3. Open in new tabDownload slide Variation of seam pressure and permeability under water removal and CO2 injection. This finding confirms the need for an appropriate numerical model to decide the required CO2 injection pressure for field-scale CO2-ECBM projects to achieve maximum production enhancement. 3.2. Factors affecting the CO2-ECBM process The applicability of the CO2-ECBM process in any coal seam is mainly governed by the seam’s permeability and its adsorption process. In turn this largely depends on the injecting gas and the coal seam’s chemico-physical properties, such as injecting gas pressure, phase and composition and coal seam depth, temperature, bed moisture content and rank. 3.2.1. Effect of coal seam properties 3.2.1.1. Temperature. The effect of temperature on the CO2-ECBM process was first considered for 50 years of production time by changing the temperature to 25, 50, 70, 90 and 110 °C while maintaining the CO2 injection pressure at 20 MPa and coal seam moisture content at 90% (figure 4). According to figure 4, an increase of temperature from 25 to 50 °C causes CH4 production to be enhanced by around 27%, and a further increase of temperature up to 110 °C causes it to decline by around 40%. The initial CH4 production enhancement may be due to the fact that the increase of temperature from 25 to 50 °C causes the CO2 phase condition inside the coal seam to be changed from sub- to super-critical. According to Perera et al (2011c), super-critical CO2 has higher sorption capacity in coal compared to sub-critical CO2. Therefore, this higher sorption capacity may cause higher CH4 desorption from the coal seam, resulting in higher CH4 production. This can be confirmed by observing the coal seam porosity and permeability alterations (closer to the CO2 injection point) during the CO2-ECBM process (figure 5). According to figure 5, coal seam porosity decreases as the temperature rises, probably due to thermal expansion of the coal matrix with increasing temperature, which reduces the pore space. Figure 4. Open in new tabDownload slide The effect of temperature on coal seam enhanced CH4 production. Figure 4. Open in new tabDownload slide The effect of temperature on coal seam enhanced CH4 production. Figure 5. Open in new tabDownload slide Variations of the seam porosity and permeability with increasing temperature. Figure 5. Open in new tabDownload slide Variations of the seam porosity and permeability with increasing temperature. However, if the seam permeability is considered (figure 5(b)), a similar pattern can be seen with gas production (figure 4), where an increase of temperature from 25 to 50 °C causes the permeability to be enhanced, and a further increase of temperature up to 110 °C causes it to decline. The initial permeability increment as the temperature increase from 25 to 50 °C is possibly related to the CO2 phase transmission creating production enhancement, while the latter permeability reduction with increasing temperature mainly relates to the previously mentioned temperature increment creating seam porosity reduction, which occurs due to thermal expansion of the coal matrix. Apart from this, kinetic energy enhancement in the injecting CO2 molecules with increasing temperature may also have a significant influence on the permeability reduction, as the kinetic energy of the CO2 molecules increases with rising temperatures (Skawinski et al1991, Perera et al2012b), which reduces the CO2 adsorption rate into coal and consequently reduces CH4 production. 3.2.1.2. Moisture content. The effect of coal seam moisture content on enhanced CH4 production was then considered for 50 years of production by changing the moisture content to 20, 50, 70, 90 and 100%, when CO2 injection pressure was 20 MPa and coal seam temperature was 50 °C (figure 6). According to figure 6, up to 50% moisture content, enhanced coal-bed CH4 production decreases with increasing moisture content, and the increase of moisture content from 20 to 50% (150%) causes the enhanced methane production to be reduced by 6.3%. This is due to the fact that the amount of CO2 that can be injected into the coal seam is highly dependent on the available pore space. The presence of water causes the coal mass pore space available for CO2 and CH4 movement to reduce significantly (Skawinski et al1991), resulting in a reduction in CO2 adsorption capacity and CH4 production capacity from the coal seam. This was confirmed by checking the coal seam porosity and permeability alterations, which occurred with changes in moisture content (figure 7). According to figure 7(a), increasing the moisture content from 20 to 50% causes coal seam porosity to be significantly reduced due to the pore space occupied by the higher number of water molecules. This pore space reduction increases the tortuosity for gas molecules, resulting in reduced permeability in the coal seam (figure 7(b)). This affects the CO2 movement inside the coal seam and eventually delays the CO2 adsorption process into the coal matrix, which consequently reduces the CH4 production. Figure 6. Open in new tabDownload slide The effect of bed moisture content on coal seam enhanced CH4 production. Figure 6. Open in new tabDownload slide The effect of bed moisture content on coal seam enhanced CH4 production. Figure 7. Open in new tabDownload slide Variations of seam porosity and permeability with increasing moisture content. Figure 7. Open in new tabDownload slide Variations of seam porosity and permeability with increasing moisture content. The effect of bed moisture content was then considered for higher moisture content (50–100%), and according to figure 7, both seam porosity and permeability remained stable after around 50% bed moisture content. According to the studies by Anderson et al (1956), before reaching the critical moisture content, the water molecules occupy some of the adsorption sites in any porous medium, and after saturation point, the excess water stays in a free state and does not affect the gas sorption capacity. This is believed to be the reason for the observed stable porosity and permeability and consequently the gas production after 50% moisture content. 3.2.1.3. Depth. The effect of depth on total CH4 production was then examined by changing the depth to 500, 650, 750, 900 and 1000 m, while maintaining the coal seam temperature, moisture content and injection pressure at 50 °C, 90% and 20 MPa, respectively. The results are shown in figure 8, where it can be seen that coal seam CH4 production reduces with increasing depth, and an increase of depth from 500 to 1000 m (100%) causes CH4 production to be reduced by around 59%. According to Perera et al (2012a), an increase in coal seam depth causes a significant increase in the in situ stress acting on the coal seam from the surrounding rock mass. This increases the effective stress applied on the coal mass, which increases the tortuosity for gas movement inside the coal seam and reduces the pore space available in the coal seam for CO2 adsorption and CH4 desorption, resulting in the reduction in CH4 production rates. Figure 8. Open in new tabDownload slide The effect of coal seam depth on enhanced CH4 production. Figure 8. Open in new tabDownload slide The effect of coal seam depth on enhanced CH4 production. This was demonstrated by checking the seam porosity and permeability behaviors at each depth increment and the results are shown in figure 9, where it can be seen that both seam porosity and permeability exhibit similar reduction trends with increasing depth, which implies pore space reduction with increasing depth and the permeability reduction is due to the tortuosity increment under reduced pore space conditions. This delays the CO2 movement inside the coal seams and eventually reduces CO2 adsorption into the seam, resulting in reduced CH4 desorption. In addition, the reduction of pore space itself affects the CO2 adsorption and methane desorption processes in the coal seam. Figure 9. Open in new tabDownload slide Variations of the seam porosity and permeability with increasing seam depth. Figure 9. Open in new tabDownload slide Variations of the seam porosity and permeability with increasing seam depth. 3.2.2. Effect of injecting gas properties 3.2.2.1. Injection pressure. The effect of CO2 injection pressure on enhanced CH4 production was then examined by changing CO2 injection pressure (12.5, 15, 17.5, 20, 22.5 and 25 MPa). In order to maintain the injection pressure as a variable in the analysis, all other variables inserted in the model were treated as constants: temperature (50 °C), moisture content (90%), and depth (1000 m). According to figure 10, coal seam methane production increases exponentially with increasing CO2 injection pressure, and the increase of injection pressure from 12.5 to 25 MPa (100%) causes the coal seam’s CH4 production to increase by around 347%. This is due to the fact that increased injection pressure produces a greater CO2 adsorption capacity in the coal seam, which enhances the CH4 desorption rate (Bae and Bhatia 2006). Figure 11 shows the variations of seam porosity and permeability (near the injection point) with increasing injection pressure. According to figure 11(a), there is a trend for continuously increasing coal seam porosity with increasing CO2 injection pressure, probably due to pore space expansion with the effective stress reduction created by the increased injection pressure. Figure 11(b) shows how the corresponding coal seam permeability varies, which is also an exponentially increasing trend. This seam permeability enhancement under increased injection pressure enhances CO2 flow ability through the seam and corresponding CO2 adsorption process into the coal matrix, which consequently enhances methane production. Figure 10. Open in new tabDownload slide The effect of CO2 injection pressure on coal seam enhanced CH4 production. Figure 10. Open in new tabDownload slide The effect of CO2 injection pressure on coal seam enhanced CH4 production. Figure 11. Open in new tabDownload slide Variations of seam porosity and permeability with increasing CO2 injection pressure. Figure 11. Open in new tabDownload slide Variations of seam porosity and permeability with increasing CO2 injection pressure. However, it should be noted that excessive injection pressures may cause hydraulic fractures to be created in the coal seam, resulting in back-migration of injecting CO2 into the atmosphere. Hawkes et al (2005) showed that the most critical orientation for the opening of fractures is on a plane normal to the minimum in situ stress component (σ3), and therefore fracture formation may occur once the pore pressure (Pu) exceeds σ3. This phenomenon can be used to identify fracture formations in the coal seam. Fracture pore pressure was directly taken from the COMET 3 simulator and it was assumed that the third principal stress at 1000 m is equal to the gravitational stress, σg = h × ρr × g, where h is the depth (1000 m), ρr is the rock density (2.5 g cm-3) and g is the gravitational acceleration (9.8 m s-2) (Sheory 1994, Ranjith et al2013), which is equal to 24.5 MPa. Therefore, for safety reasons, the maximum safe CO2 injection pressure was selected as 20 MPa for the modeled coal seam and this pressure is used in the remaining sections. Now, if the effects of all the above factors that influence methane production are compared, a 100% increment in injection pressure (from 12.5 to 25 MPa), depth (500 to 1000 m), temperature (25 to 50 °C) and moisture content (20 to 50%) cause the enhanced coal seam CH4 production to be changed by around 347%, 59%, 27% and 4.2% respectively. It is therefore clear that CO2 injection pressure is the most influential factor for the CO2-ECBM process. In contrast, bed moisture content is the least influential factor. Temperature and depth appear to have moderate influences on methane production during the CO2-ECBM process. However, it should be noted that under actual conditions in deep coal seams, all these parameters are inter-connected. For example, when the seam is deeper, moisture content reduces and temperature increases. The combined effect can be effectively identified if there is a detailed understanding of each individual factor. 3.2.2.2. Injecting gas composition. The next stage of the study examined the effect of injection gas composition on CBM production, and the gas composition was changed by adding N2 into the injecting CO2. The percentage of added N2 was changed (20, 40, 60, 80 and 100%) and the corresponding CH4 production was examined, while maintaining the temperature, moisture content and injection pressure at 50 °C, 90% and 20 MPa, respectively. The risk associated with the N2 in the injecting gas was then examined by checking the leakage of CO2 and N2 from the production well during the 50 year production period, because mixing any other gas (CO2/N2) with the CH4 produced incurs high cost because the gas produced needs to be cleaned. This step was therefore used to identify the best N2 percentage in the injection gas to enhance CH4 production with minimal contaminant gas. Figure 12 shows how CH4 production is enhanced by the injection of N2 + CO2 gas into the coal seam. According to figure 12, a clear enhancement of methane production can be observed with the addition of N2 into the injecting CO2 and this enhancement appears to increase in line with the percentage of N2 in the injecting gas. For example, increasing the N2% in the injecting gas from 20 to 80% causes the CH4 production to be increased by around 1360%, which is significant (figure 13). This was expected, because N2 remains as free gas in the fracture space, which creates an imbalance between sorbed and free gas phases and eventually reduces the partial pressure for CH4, resulting in the release of additional amounts of CH4 from the coal mass (Reeves 2003). Although CO2 adsorption also creates a significant increase in methane production through the replacement of methane with CO2, the process takes a significant time compared to the production enhancement which occurs due to the pressure imbalance created by N2 between the sorbed and free gas phases. Therefore, in short-term production, the influence of N2 is much greater and production increases proportionally with the increasing N2 percentage in the injecting gas. Figure 12. Open in new tabDownload slide CH4 production enhancement with N2 + CO2 injection. Figure 12. Open in new tabDownload slide CH4 production enhancement with N2 + CO2 injection. Figure 13. Open in new tabDownload slide CH4 production enhancement with N2% in N2 + CO2 injection. Figure 13. Open in new tabDownload slide CH4 production enhancement with N2% in N2 + CO2 injection. Figure 14 shows how coal seam porosity and permeability vary by increasing the N2 percentage in the injecting gas; according to this, there is a significant pore space increment with increasing N2%, probably as a result of the release of CH4 molecules from the existing pore space (figure 14(a)). In addition, seam permeability also seems to increase significantly when the N2% in the injecting gas is raised, and this is the governing factor for the CO2 movement inside the seam and consequently for the observed enhanced methane production. Figure 15 compares the CO2, N2 and CH4 presents in the coal seam after 50 years of 80% CO2 + 20% N2 injection. According to the figure, a large amount of CO2 remains in the coal matrix after the injection period, probably due to the replacement of existing methane by CO2 through sorption (figure 15(a)). This is confirmed by figure 15(c), which shows negligible amounts of CH4 in the coal seam closer to the CO2 injection well. It may need more time for this remaining CO2 to diffuse to a greater distance and produce the remaining CH4 from the seam. In relation to the amount of N2 remaining in the coal seam after this 50 year period, figure 15(b) shows only a very small amount of N2 remains in the coal matrix after the injection period, and the proportion of CO2 to N2 in the coal matrix is much less than the 5:1 proportion injected. This is because injecting N2 largely stays as a free gas in the coal seam, and therefore has a greater tendency to be released from the coal seam with the gas being produced, resulting in lower volumes of N2 remaining in the coal seam after the production process. This confirms the minor influence of N2 in the injection gas on post-injection gas production. Figure 16 compares the CO2, N2 and CH4 present in the coal seam after 50 years of 20% CO2 + 80% N2 injection. According to the figure, although there is a 1 : 5 proportion of CO2 : N2 in the injecting gas, the remaining N2 in the seam after 50 years’ injection is much less than the CO2. This again proves that N2 has a greater tendency to be released from the coal seam with the gas being produced and therefore has a minor influence on post-injection gas production from the seam. This post-injection gas production seems to be mainly governed by the existing CO2 in the seam. However, when figures 15 and 16 are compared, it can be clearly seen that a lower amount of methane gas exists in the coal seam after 20% CO2 + 80% N2 injection compared to the 80% CO2 + 20% N2 injection. This exhibits the greater degree of gas production enhancement created by N2 during the injection period. Figure 14. Open in new tabDownload slide Variations of seam porosity and permeability with increasing N2% in the N2 + CO2 injection. Figure 14. Open in new tabDownload slide Variations of seam porosity and permeability with increasing N2% in the N2 + CO2 injection. Figure 15. Open in new tabDownload slide CO2, N2 and CH4 in the coal seam after 50 years of 80% CO2 + 20% N2 injection. Figure 15. Open in new tabDownload slide CO2, N2 and CH4 in the coal seam after 50 years of 80% CO2 + 20% N2 injection. Figure 16. Open in new tabDownload slide CO2, N2 and CH4 in the coal seam after 50 years of 20% CO2 + 80% N2 injection. Figure 16. Open in new tabDownload slide CO2, N2 and CH4 in the coal seam after 50 years of 20% CO2 + 80% N2 injection. However, since N2 basically is present as a free gas in the coal mass, there is a high risk associated with the leaking of injected N2 with the produced gas via the CH4 production well. Therefore, this was checked in the next stage of the study. According to figure 17, N2 starts to leak through the production well some time after the N2 + CO2 injection and that leakage rate increases in line with the N2 percentage in the injecting gas. On the other hand, according to figure 18, the injection of a N2 + CO2 mixture also has significant influence on CO2 breakthroughs in the gas being produced, although the leakage initiates a long time after the N2 leakage initiation and the leakage amount is more than a thousand times smaller than that of N2. According to figure 19, increasing the N2 percentage in the injecting gas from 20 to 80% causes the total N2 and CO2 leakage during 50 years of production to increase by around 1360% and 98%, respectively, which implies that changing the N2 percentage more than 10 times significantly affects N2 leakage compared to that of CO2. This implies that N2 leakage should be a more important consideration when deciding the N2 percentage in the injecting gas in field projects. Figure 17. Open in new tabDownload slide Leakage of N2 through the production well. Figure 17. Open in new tabDownload slide Leakage of N2 through the production well. Figure 18. Open in new tabDownload slide Comparison of N2 and CO2 leakages and CH4 production enhancement due to N2 + CO2 injection into the coal seam with varying percentage of N2 in the injecting gas. Figure 18. Open in new tabDownload slide Comparison of N2 and CO2 leakages and CH4 production enhancement due to N2 + CO2 injection into the coal seam with varying percentage of N2 in the injecting gas. Figure 19. Open in new tabDownload slide Comparison of effect of N2% in the injecting gas on N2 and CO2 leakage. Figure 19. Open in new tabDownload slide Comparison of effect of N2% in the injecting gas on N2 and CO2 leakage. Therefore, it is very important to decide the best combination of N2 and CO2 in the injecting gas to minimize the risks associated with the ECBM process while maximizing CH4 production. According to figure 19, the addition of more than 60% N2 in the injecting gas seems to create very rapid N2 and CO2 leakage rates. Therefore, the injecting gas should contain less than 60% N2 to ensure safe methane recovery enhancement. Interestingly, this implies that the widely used flue gas injection (80% N2 + 20% CO2) in ECBM field projects is not a favorable option. If the effect of the N2 percentage in the injecting gas on methane production enhancement is then considered, according to figure 18, having more than 40% N2 in the injecting gas causes the production of greater amounts of N2 than CH4. Therefore, the desired N2 percentage in the injecting gas should be less than or equal to 40%. Now, if figure 18 is considered, increasing the N2 percentage in the injecting gas from 0 to 20%, 20 to 40%, 40 to 60% and 60 to 80% causes CH4 production to be enhanced by around 16.5%, 19.5%, 21.4% and 21.7%, respectively. Therefore, at least 40% N2 in the injecting gas is required to enhance methane production by a significant amount. Therefore, while considering the effect of both CO2/N2 leakage and CH4 production enhancement, 40% N2 + 60% CO2 is the best injecting gas combination for an effective CO2 + N2-ECBM process to enhance methane recovery safely from the selected coal seam. 3.3. Influence of production and injection well arrangement on enhanced coal seam CH4 production Gas injection wells and water and methane production wells play a vital role in the ECBM process, and therefore should have a significant influence on the process optimization. This was considered in the next stage of the study, by changing the well arrangement while maintaining the other influencing factors at constant values (temperature, moisture content depth and injection pressure were 50 °C, 90%, 1000 m and 20 MPa, respectively). 3.3.1. CO2 injection well arrangement. The effect of the CO2 injection well arrangement on the optimization of the ECBM process was first considered. One CO2 injection well was first used and the number of injection wells was then increased to four, as shown in figure 20, and the corresponding variation in CH4 production was examined. As expected, increasing the number of injection wells from one to three caused the CH4 production to be greatly enhanced (155%) (figures 21 and 22). This was expected, as increasing the injection well allows more CO2 to be injected into the coal seam, which enhances the CH4 production process by replacing the existing methane with the injecting CO2. Figure 20. Open in new tabDownload slide Different injection well patterns (Winj is the injection well and Wpro is the production well). Figure 20. Open in new tabDownload slide Different injection well patterns (Winj is the injection well and Wpro is the production well). Figure 21. Open in new tabDownload slide CH4 production with time for different numbers of injection wells. Figure 21. Open in new tabDownload slide CH4 production with time for different numbers of injection wells. Figure 22. Open in new tabDownload slide Change of CH4 production with number of injection wells. Figure 22. Open in new tabDownload slide Change of CH4 production with number of injection wells. However, according to figures 21 and 22, the addition of more than three injection wells causes a reduction in CH4 production. In order to identify the possible reasons for this, pressure development inside the coal seam under each well condition was examined and the results are shown in figure 23. According to the figure, coal seam pore pressure increases significantly with the increasing number of injection wells. This is because the distance between the injecting points reduces in line with the increased numbers of injecting wells, resulting in the pressure contours produced by each CO2 injecting well meeting each other within a shorter time, which causes the buildup of unnecessary pore pressure inside the coal seam. This negatively influences CH4 release from the coal matrix and consequently CH4 production capacity. Figure 24 shows the CO2 and CH4 available in the coal seam after the injection periods, and according to the figure, for more than two wells, CO2 concentration is mainly limited to the surrounding areas of the injecting wells, probably due to the so-called pressure development around each well. If the four injection wells’ condition is considered, the newly-added fourth well at the mid-point injects only a limited amount of CO2 into the coal seam, probably due to the development of pressure in the surrounding area due to CO2 injection by the other wells, which acts as a barrier to CO2 movement. Therefore, the injection capacity of this fourth well is limited. The methane available in the coal seam after the injection period was then examined for each well condition (see figure 25), and the addition of the fourth well at the mid-point makes only a minor contribution to methane production, although a considerable amount of methane remains closer to that well, probably due to the previously mentioned limited CO2 injection capacity through this well. When all of these facts are considered, it is clear that the addition of the fourth well at the mid-point of the seam does not make any significant contribution to methane production; instead it reduces overall production by creating unnecessary pressure in the coal seam, which must be removed to enable optimum gas production from the seam. This finding indicates the importance of numerical models to estimate the performance of injection wells, to facilitate the selection of the optimum number of injection wells for ECBM. This is highly important for the economical aspects of the project. Figure 23. Open in new tabDownload slide CO2 pressure developed after 50 years of CO2 injection using one to four injection well conditions. Figure 23. Open in new tabDownload slide CO2 pressure developed after 50 years of CO2 injection using one to four injection well conditions. Figure 24. Open in new tabDownload slide CO2 available in the coal seam after 50 years of CO2 injection using one to four injection well conditions. Figure 24. Open in new tabDownload slide CO2 available in the coal seam after 50 years of CO2 injection using one to four injection well conditions. Figure 25. Open in new tabDownload slide CH4 available in the coal seam after 50 years of CO2 injection using one to four injection well conditions. Figure 25. Open in new tabDownload slide CH4 available in the coal seam after 50 years of CO2 injection using one to four injection well conditions. In addition, having too many injection wells causes the distance between the injection and production wells to be reduced, resulting in the mixing of injecting CO2 with the CH4 produced. According to Curtis (2006), mixing these two gases will also contribute to the development of additional pore pressure inside the seam, which causes additional production depletion. 3.3.2. CH4 production well arrangement. The effect of production well arrangement was then considered, and the results are shown in figure 26. One production well was used first and the the number of production wells was then increased up to four after which the corresponding variation in CH4 production was examined (figures 27 and 28). According to figures 27 and 28(b), an increase in the number of production wells has an insignificant impact on long-term (50 years) CH4 production, with less than 10% change from one to four wells. However, according to figure 28(a), in the case of short-term CH4 production (10 years), there is a significant increase in CH4 production due to an increment in production. For example, an increase of production wells from one to two results in around 144% increase in 10 year total CH4 production, and an increase from one to four results in around a 430% increase in total CH4 production over 10 years. It is most probable that having more production wells opens more points to the atmosphere, which reduce the average distance that methane has to travel to reach the well. This increases the rate of production and leads to a higher amount of methane produced in the short term. However, in the long term the methane would have more than enough time to travel to wells placed farther away and hence there would be little difference between having one well or four wells. This may be the reason for the significant short-term increase in coal seam CH4 production and the negligible variation in long-term CH4 production with an increased number of production wells. Figure 26. Open in new tabDownload slide Different production well patterns (Winj is the injection well and Wpro is the production well). Figure 26. Open in new tabDownload slide Different production well patterns (Winj is the injection well and Wpro is the production well). Figure 27. Open in new tabDownload slide CH4 production with time for different numbers of production wells. Figure 27. Open in new tabDownload slide CH4 production with time for different numbers of production wells. Figure 28. Open in new tabDownload slide Change of CH4 production with number of production wells. Figure 28. Open in new tabDownload slide Change of CH4 production with number of production wells. In field situations, the short-term benefits of having extra production wells must be balanced against the costs of drilling in order to obtain the optimum number of production wells. This would require the use of an accurate numerical model. 3.3.3. Distance between the injection and production well. According to sections 3.3.1 and 3.3.2, the distance between the CO2 injecting well and the CH4 production well (figure 29) plays an important role in the optimization of the ECBM process, and was therefore was examined in the next stage of the study. In this case, the distance between the two wells was gradually changed (55.6, 141, 282, 424 and 707.1 m) while maintaining the other factors as constants (temperature, moisture content, depth and injection pressure were 50 °C, 90%, 1000 m and 20 MPa). According to figure 30, total CH4 production increases by increasing the distance between the injecting and production wells, which is related to the combined influence of two different processes: (1) a close space between the injecting and production wells causes more CO2 to be injected near the production well that greatly swells the coal matrix around the production well, resulting in reduced permeability; (2) mixing a small amount of CH4 into CO2 causes a large rise in CO2 density, which creates additional pore pressure development in the coal seam (Curtis 2006) Figure 29. Open in new tabDownload slide Distance between injecting and producing wells. Figure 29. Open in new tabDownload slide Distance between injecting and producing wells. Figure 30. Open in new tabDownload slide The effect of changing the distance between injecting well and production well on enhanced CH4 production. Figure 30. Open in new tabDownload slide The effect of changing the distance between injecting well and production well on enhanced CH4 production. Overall, all of these observations indicate the importance of an appropriate numerical model to estimate the optimum distance between the wells to recover the maximum amount of CO2 from a selected coal seam during the CO2-ECBM process. 4. Conclusions The optimization of the enhanced coal-bed methane (ECBM) recovery process requires numerical modeling tools to reduce the complexity, cost and extensive time associated with laboratory and field experiments. Although some experimental, numerical and field studies have been conducted on the ECBM process and production enhancement techniques, none of them has considered the influences of all the possible primary effective factors on the process. As a result, it has been difficult to obtain a comprehensive knowledge of the subject. A 3D numerical model was therefore developed using the COMET 3 numerical modeling tool to simulate 50 years of CH4 production from a 1000 m deep 500  ×  500  ×  20 m coal seam. All the possible major CBM production enhancement techniques were tested: changes of seam properties and injection gas properties, water removal, CO2 injection, CO2 + N2 gas mixture injection, and change of injection and production well arrangement. According to the results the following major conclusions can be drawn. Although the CO2-ECBM technique has greater ability to enhance CBM production than the traditional water removal process, it is necessary to maintain appropriate injection practices to obtain optimum gas production. For example, for the coal seam under consideration, the injection of CO2 at 12 MPa pressure did not have a significant influence on CBM production, because CO2 injection under that pressure fails to maintain an adequate flow rate through the coal seam due to insufficient pushing force created by the pressure gap between the injecting CO2 and the coal seam. Coal seam properties have a considerable influence on the CO2-ECBM process, and ECBM production generally reduces with increasing seam temperature for two main reasons: (1) thermal expansion occurs in the coal matrix with increasing temperatures, which reduces the pore space and seam permeability, and therefore CO2 adsorption and methane recovery potential, and (2) with increasing temperature kinetic energy enhancement in the injecting CO2 molecules reduces the CO2 adsorption rate into coal. However, changing the CO2 phase condition from sub- to super-critical with increasing temperature may create a contradictory temperature influence on ECBM production due to the higher sorption capacity of super-critical CO2. Regarding the bed moisture content effect, ECBM production decreases with increasing moisture content up to the critical moisture content of the seam, due to the porosity reduction created by the occupying water molecules. However, further increase of bed moisture content does not have any significant influence on ECBM production, because after the critical point, the excess water stays in a free state and does not affect the seam porosity or gas sorption capacity. Regarding the influence of seam depth on ECBM production, ECBM production greatly reduces with increasing depth, due to the increased effective stress acting on the coal, which reduces the pore space and consequently increases the tortuosity for gas movement inside the coal seam. In turn, both reduce the CO2 adsorption capacity and consequently the CBM production. In addition to the seam properties, injecting CO2 properties also significantly affect the performance of the ECBM process, and CO2 injection pressure and composition are critical. Regarding the injection pressure effect, ECBM production increases exponentially with increasing CO2 injection pressure, due to the expanded pore space and enhanced CO2 adsorption capacity at increased CO2 injection pressures. Interestingly, injection pressure plays a dominant role in the CO2-ECBM process compared to the other factors. For example, in the selected seam, a 100% increment in injection pressure, depth, temperature and moisture content cause ECBM production to be changed by around 347%, 59%, 27% and 4.2%, respectively. However, increasing the injection pressure should be done in a controlled manner to avoid any significant fracture formation in the seam that may lead to CO2 leakage. Regarding the influence of injecting gas composition, the addition of N2 to the injecting gas has considerable potential to enhance the ECBM process, and this enhancement greatly increases as the percentage of N2 in the injecting gas rises. For example, for the seam under consideration, increasing the proportion of N2% from 20 to 80% causes ECBM production to be increased by around 1360%. This is because the ECBM production enhancement caused by N2, which creates an imbalance between sorbed and free gas phases, is produced much more quickly than the ECBM production enhancement that is caused by CO2 through adsorption. Therefore, in short-term production, the influence of N2 is greater during the injection period. However, post-injection gas production is mainly governed by the existing CO2 in the coal seam, because after the injection period only a small amount of N2 remains in the seam. It is very important to decide the best combination of N2 and CO2 in the injecting gas to minimize the risks associated with the ECBM process (mainly the leakage of injecting CO2 and N2 with the gas produced, which causes large purifying costs) while maximizing CH4 production. For the seam under consideration, 40% N2 + 60% CO2 is the best injecting gas combination when both CO2/N2 leakage and CH4 production enhancement are considered. The number of injection and production wells and their arrangement have a significant influence on the enhancement of ECBM production. Regarding the influence of the injection wells, although ECBM production can be significantly increased by increasing the number of CO2 injection wells, too many wells may cause it to be reduced. This is because having wells too close to each other causes the pressure contours produced by each well to coincide, which may cause unnecessary pore pressure development inside the coal seam. For example, for the coal seam under consideration, the addition of more than three injection wells causes production to be reduced instead of enhanced. The reason is that the fourth well has limited ability to spread the injected CO2 into the coal seam, due to the pressure development in the surrounding areas caused by the other injection wells, which acts as a barrier to CO2 movement. Under such conditions, creating additional pressure through this fourth well limits the CO2 spreading ability of the other wells, which negatively influences the ECBM process. Regarding the influence of production wells on the ECBM process, increasing the number of production wells does not have a significant influence on long-term CH4 production (50 years in the selected coal seam), although it has a significant impact on short-term ECBM production (10 years in the selected coal seam). This is because, with an increased number of production wells, the methane needs to travel shorter distances to reach the production wells, which increases the rate of production in the short term. 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TI - Optimization of enhanced coal-bed methane recovery using numerical simulation
JF - Journal of Geophysics and Engineering
DO - 10.1088/1742-2132/12/1/90
DA - 2015-02-01
UR - https://www.deepdyve.com/lp/oxford-university-press/optimization-of-enhanced-coal-bed-methane-recovery-using-numerical-3v5RPIzK9T
SP - 90
VL - 12
IS - 1
DP - DeepDyve
ER -