A typical coal seam using the COMET 3 reservoir simulator. A comprehensive numerical modeling study using COMET 3 software to. Autotune-AI is the industry's first reservoir simulation artificial intelligence-based algorithm to transform simulation run time & speed, using one keyword.
AbstractAlthough 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 CO 2 injection, compared to the traditional water removal technique, is true only for high CO 2 injection pressures. Generally, the ECBM process can be accelerated by using increased CO 2 injection pressures and reduced temperatures, which are mainly related to the coal seam pore space expansion and reduced CO 2 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 N 2 into the injecting CO 2 can greatly enhance the methane production process, the safe N 2 percentage in the injection gas should be carefully predetermined as it causes early breakthroughs in CO 2 and N 2 in the methane production well. An increased number of production wells may not have a significant influence on long-term CH 4 production (50 years for the selected coal seam), although it significantly enhances short-term CH 4 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 CO 2 with CH 4. IntroductionFossil 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 al, Ranjith and Perera ). 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 ).
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 (CO 2) or nitrogen (N 2), into the coal bed (Fujioka et al, White et al, Perera et al, Vishal et al), which is commonly known as enhanced coal-bed methane (ECBM) recovery.
In the CO 2 injection-enhanced ECBM process (CO 2-ECBM), when CO 2 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 ), which would go a long way towards enhancing the economic viability of ECBM, coupled with increasing gas prices.
With regard to the N 2-ECBM technique, according to Reeves the injection of N 2 into the coal seam causes the CBM production rate to be significantly increased. This is mainly due to the non-adsorptive nature of N 2, 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 CH 4 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, Perera et al).Although the CO 2-ECBM and N 2-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, Reeves and Odinot ), RECOPOL (Pagnier et al), and MOVECBM (Wageningen and Cuesta ) 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 al). 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; CO 2 and N 2 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 CO 2 credits (Reeves ). 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 , 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 , it is necessary to conduct a broader range of scientific research studies to overcome this issue.Injection of CO 2 into deep coal seams causes significant alterations to their chemico-physical structure, where a coal matrix swelling effect created by injecting CO 2 is significant (White et al). This can start as soon as 1 h after CO 2 injection, causing the seam’s permeability to be significantly reduced, and resulting in unpredictable CO 2 injectibilities in and CH 4 productivities of coal seams (Perera et al, Perera and Ranjith, Vishal et al, ). According to Perera et al , this swelling process is heavily dependent on the CO 2 phase condition, and super-critical CO 2 adsorption-induced swelling is up to two times higher than sub-critical CO 2 adsorption-induced swelling.
Therefore, the injection of CO 2 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 CO 2 movement and resulting in less coal mass permeability (Viete and Ranjith, Perera et al, ). In addition, existing safety rules in underground coal mines limit the amount of CO 2 permitted in them; the maximum percentage of CO 2 in a coal mine should be around 3% of the mine’s air volume. Therefore, there is a risk associated with the injection of CO 2 into coal seams during the CO 2-ECBM process that may cause the coal seam to be un-mineable forever (Sarmah ).
However, the significant contribution of the CO 2-ECBM process to the mitigation of atmospheric CO 2 levels through CO 2 sequestration also needs to be considered from the environmental protection perspective (Perera et al). Therefore, performance evaluation of the process under various conditions (different injection gas properties and seam properties) is very important for the optimization of the CO 2-ECBM process.In the N 2-ECBM technique, the existence of free N 2 in the seam causes quicker N 2 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 ). For instance, specialized equipment is required to separate the N 2 from the product gas stream (a mixture of N 2 and CH 4 (Mazzotti et al)), which is quite expensive.
This has been observed in both the Tiffany N 2-ECBM unit in the San Juan basin as well as the Alberta ECBM project (Reeves and Odinot, Gunter ). However, according to current research, there is a significantly higher production potential for the N 2-ECBM process compared to the CO 2-ECBM process (Perera and Ranjith ), 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% N 2 + 13% CO 2) injection compared to pure CO 2 or N 2 injections (Reeves and Schoeling ), because the injection of a mixture of N 2 + CO 2 offers higher methane productivity with an earlier response compared to pure CO 2 injection and it sequestrates similar amounts of CO 2 due to the higher injection rate. In addition, N 2 has some potential to recover CO 2 injection-induced swelling (Jasinge et al, Perera et al, Vishal et al), which also results in a greater injectability of the N 2/CO 2 mixture compared to pure CO 2. 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 CO 2/N 2 mixture at a predetermined ratio possibly offers a better solution.However, to date few studies have been conducted on the N 2 + CO 2-ECBM technique.
According to the experimental study conducted by Parakh , the injection of 45% N 2 + 55% CO 2 gas mixture causes an initially high rate of production due to the N 2 and the rate gradually becomes slower due to the CO 2. The fieldwork in the Fenn Big Valley basin in Alberta, Canada (Gunter, Wong et al) involves the injection of different proportions of N 2/CO 2 (0% N 2, 53% N 2, 87% N 2 and 100% N 2) into the 1–4 md low permeable Mannville reservoir using two injection wells. This project illustrates that the injection of a mixture of N 2 + CO 2 may help reduce the problems associated with CO 2 injection-induced coal swelling and early breakthrough with N 2 injection, and that flue gas injection avoids the high cost associated with the pure N 2/CO 2 capture process. However, it is necessary to conduct a comprehensive study to fully understand the process and find the best CO 2/N 2 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 CH 4 from a selected coal seam.
Among the many field-scale simulators available to simulate gas flow in underground reservoirs, TOUGH 2 (Carneiro ), COMSOL (Liu and Smirnov, Perera et al), FEMLAB (Holzbecher ) and COMET 3 (Perera et al, Vishal et al, ), COMET 3 has been identified as one of the most appropriate and user-friendly numerical modeling tools for deep coal seams (Perera et al). 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.
Governing equations used. 2 where b n ( n = g or w) is the gas or water bulking factor, γ n is the gas or water gradient, R sw is the gas solubility in water, φ is the fracture porosity, z is the elevation, q g is the gas flow rate, q w is the water flow rate, q m is the matrix gas flow rate, M n = kk m /μ n, is the phase mobility, ( k-permeability, k m-matrix permeability, μ n-phase viscosity ), S n is the gas or water saturation, and P n is the gas or water pressure. Gas adsorption and desorption processes were included in the model using the extended Langmuir model (Perera et al).
6 where c p is the pore volume compressibility, c m is the matrix shrinkage compressibility, φ is the coal mass porosity, φ i is the initial coal mass porosity, P is the reservoir pressure, P i is the initial reservoir pressure, C is the reservoir concentration, C i is the initial reservoir concentration, k is the reservoir permeability, and k i is the initial reservoir permeability. Model developmentA 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.
Table shows the model parameters used. First, ordinary methane (CH 4) production capacity from the coal bed was examined without using any enhancing technique such as water production or CO 2/N 2 injection and the CH 4 production during 50 years of production was simulated and examined. The production rate was then accelerated by pumping out formation water at 25 m 3/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 CO 2-ECBM technique was then examined by injecting CO 2 into the coal seam at 12 MPa injection pressure for 40 years.
Effective factors for the CO 2-ECBM process were then examined to identify possible ECBM process optimization measures. The effect of CO 2 injection pressure was first examined by changing the CO 2 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, CO 2 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 CO 2 injection pressure at 20 MPa and coal bed temperature at 50 °C.
The effect of coal seam depth on CH 4 production was examined by changing the coal seam depth (500, 650, 750, 900, and 1000 m) while maintaining the CO 2 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 N 2 gas to enhance the ECBM production was examined by mixing the injecting CO 2 with various percentages of N 2 (20, 40, 60, 80 and 100%). In this case, a 20% N 2 + 80% CO 2 gas mixture was first considered as the injection gas and the corresponding CH 4 production enhancement was examined. The N 2 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 CH 4 production, the potential for ECBM process optimization was examined by changing the production and injection well arrangements. In this case, pure CO 2 injection-enhanced CH 4 production was considered by maintaining the CO 2 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 CO 2 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 CH 4 production was then examined by changing the number of production wells (1, 2, 3 and 4). Results and discussion 3.1. Comparison of CBM production enhancements through water removal and CO 2 injection (CO 2-ECBM)As described in the model development section, two main techniques were used to accelerate CH 4 desorption: coal seam pore pressure depletion by water removal, and the injection of a higher adsorption capacity gas, CO 2. Figure compares the effects of each technique on CH 4 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 CH 4 desorption rate (Fujioka et al). This can be easily examined in figure, which shows that the removal of water at 25 m 3/day rate for 10 years causes the coal seam mean pore pressure to be reduced by around 42%, which in turn causes the CH 4 adsorbed, under high pressure, to be released from the coal matrix, which can subsequently be captured.
However, according to figure, CBM production enhancement created by the CO 2-ECBM technique seems to be much more productive compared to the enhancement through water removal, if an appropriate injection pressure is maintained (Fujioka et al). Interestingly, according to figure, simply injecting CO 2 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 ). This can be clearly seen in figure, according to which, at around 12 MPa CO 2 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 CO 2 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, the CO 2 permeability inside the coal seam increases with a rise in injection pressure (figure ), even though pore pressure inside the seam increases accordingly (figure ). This is because, although there is a pore pressure development with CO 2 injection, the pushing force for the injected CO 2 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, the injection pressure should be greater than 15 MPa for the coal seam to have permeability enhancement. Variation of seam pressure and permeability under water removal and CO 2 injection.This finding confirms the need for an appropriate numerical model to decide the required CO 2 injection pressure for field-scale CO 2-ECBM projects to achieve maximum production enhancement. Factors affecting the CO 2-ECBM processThe applicability of the CO 2-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. Effect of coal seam properties 3.2.1.1. Temperature.The effect of temperature on the CO 2-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 CO 2 injection pressure at 20 MPa and coal seam moisture content at 90% (figure ).
According to figure, an increase of temperature from 25 to 50 °C causes CH 4 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 CH 4 production enhancement may be due to the fact that the increase of temperature from 25 to 50 °C causes the CO 2 phase condition inside the coal seam to be changed from sub- to super-critical. According to Perera et al , super-critical CO 2 has higher sorption capacity in coal compared to sub-critical CO 2. Therefore, this higher sorption capacity may cause higher CH 4 desorption from the coal seam, resulting in higher CH 4 production. This can be confirmed by observing the coal seam porosity and permeability alterations (closer to the CO 2 injection point) during the CO 2-ECBM process (figure ). According to figure, 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.
Variations of the seam porosity and permeability with increasing temperature.However, if the seam permeability is considered (figure ), a similar pattern can be seen with gas production (figure ), 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 CO 2 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 CO 2 molecules with increasing temperature may also have a significant influence on the permeability reduction, as the kinetic energy of the CO 2 molecules increases with rising temperatures (Skawinski et al, Perera et al), which reduces the CO 2 adsorption rate into coal and consequently reduces CH 4 production.
Moisture content.The effect of coal seam moisture content on enhanced CH 4 production was then considered for 50 years of production by changing the moisture content to 20, 50, 70, 90 and 100%, when CO 2 injection pressure was 20 MPa and coal seam temperature was 50 °C (figure ). According to figure, up to 50% moisture content, enhanced coal-bed CH 4 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 CO 2 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 CO 2 and CH 4 movement to reduce significantly (Skawinski et al), resulting in a reduction in CO 2 adsorption capacity and CH 4 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 ). According to figure, 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 ). This affects the CO 2 movement inside the coal seam and eventually delays the CO 2 adsorption process into the coal matrix, which consequently reduces the CH 4 production. 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, both seam porosity and permeability remained stable after around 50% bed moisture content.
According to the studies by Anderson et al , 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.
Depth.The effect of depth on total CH 4 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, where it can be seen that coal seam CH 4 production reduces with increasing depth, and an increase of depth from 500 to 1000 m (100%) causes CH 4 production to be reduced by around 59%. According to Perera et al , 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 CO 2 adsorption and CH 4 desorption, resulting in the reduction in CH 4 production rates. The effect of coal seam depth on enhanced CH 4 production.This was demonstrated by checking the seam porosity and permeability behaviors at each depth increment and the results are shown in figure, 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 CO 2 movement inside the coal seams and eventually reduces CO 2 adsorption into the seam, resulting in reduced CH 4 desorption. In addition, the reduction of pore space itself affects the CO 2 adsorption and methane desorption processes in the coal seam. Variations of the seam porosity and permeability with increasing seam depth. Effect of injecting gas properties 3.2.2.1. Injection pressure.The effect of CO 2 injection pressure on enhanced CH 4 production was then examined by changing CO 2 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, coal seam methane production increases exponentially with increasing CO 2 injection pressure, and the increase of injection pressure from 12.5 to 25 MPa (100%) causes the coal seam’s CH 4 production to increase by around 347%. This is due to the fact that increased injection pressure produces a greater CO 2 adsorption capacity in the coal seam, which enhances the CH 4 desorption rate (Bae and Bhatia ). Figure shows the variations of seam porosity and permeability (near the injection point) with increasing injection pressure.
According to figure, there is a trend for continuously increasing coal seam porosity with increasing CO 2 injection pressure, probably due to pore space expansion with the effective stress reduction created by the increased injection pressure. Figure shows how the corresponding coal seam permeability varies, which is also an exponentially increasing trend. This seam permeability enhancement under increased injection pressure enhances CO 2 flow ability through the seam and corresponding CO 2 adsorption process into the coal matrix, which consequently enhances methane production. Variations of seam porosity and permeability with increasing CO 2 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 CO 2 into the atmosphere. Hawkes et al showed that the most critical orientation for the opening of fractures is on a plane normal to the minimum in situ stress component ( σ 3), and therefore fracture formation may occur once the pore pressure ( P u) exceeds σ 3. 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, σ g = h × ρ r × g, where h is the depth (1000 m), ρ r is the rock density (2.5 g cm -3) and g is the gravitational acceleration (9.8 m s -2) (Sheory, Ranjith et al), which is equal to 24.5 MPa. Therefore, for safety reasons, the maximum safe CO 2 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 CH 4 production to be changed by around 347%, 59%, 27% and 4.2% respectively. It is therefore clear that CO 2 injection pressure is the most influential factor for the CO 2-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 CO 2-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. 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 N 2 into the injecting CO 2.
The percentage of added N 2 was changed (20, 40, 60, 80 and 100%) and the corresponding CH 4 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 N 2 in the injecting gas was then examined by checking the leakage of CO 2 and N 2 from the production well during the 50 year production period, because mixing any other gas (CO 2/N 2) with the CH 4 produced incurs high cost because the gas produced needs to be cleaned. This step was therefore used to identify the best N 2 percentage in the injection gas to enhance CH 4 production with minimal contaminant gas.Figure shows how CH 4 production is enhanced by the injection of N 2 + CO 2 gas into the coal seam. According to figure, a clear enhancement of methane production can be observed with the addition of N 2 into the injecting CO 2 and this enhancement appears to increase in line with the percentage of N 2 in the injecting gas. For example, increasing the N 2% in the injecting gas from 20 to 80% causes the CH 4 production to be increased by around 1360%, which is significant (figure ). This was expected, because N 2 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 CH 4, resulting in the release of additional amounts of CH 4 from the coal mass (Reeves ).
Although CO 2 adsorption also creates a significant increase in methane production through the replacement of methane with CO 2, the process takes a significant time compared to the production enhancement which occurs due to the pressure imbalance created by N 2 between the sorbed and free gas phases. Therefore, in short-term production, the influence of N 2 is much greater and production increases proportionally with the increasing N 2 percentage in the injecting gas.
CH 4 production enhancement with N 2% in N 2 + CO 2 injection.Figure shows how coal seam porosity and permeability vary by increasing the N 2 percentage in the injecting gas; according to this, there is a significant pore space increment with increasing N 2%, probably as a result of the release of CH 4 molecules from the existing pore space (figure ). In addition, seam permeability also seems to increase significantly when the N 2% in the injecting gas is raised, and this is the governing factor for the CO 2 movement inside the seam and consequently for the observed enhanced methane production.
Figure compares the CO 2, N 2 and CH 4 presents in the coal seam after 50 years of 80% CO 2 + 20% N 2 injection. According to the figure, a large amount of CO 2 remains in the coal matrix after the injection period, probably due to the replacement of existing methane by CO 2 through sorption (figure ). This is confirmed by figure, which shows negligible amounts of CH 4 in the coal seam closer to the CO 2 injection well.
It may need more time for this remaining CO 2 to diffuse to a greater distance and produce the remaining CH 4 from the seam. In relation to the amount of N 2 remaining in the coal seam after this 50 year period, figure shows only a very small amount of N 2 remains in the coal matrix after the injection period, and the proportion of CO 2 to N 2 in the coal matrix is much less than the 5:1 proportion injected.
This is because injecting N 2 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 N 2 remaining in the coal seam after the production process. This confirms the minor influence of N 2 in the injection gas on post-injection gas production. Figure compares the CO 2, N 2 and CH 4 present in the coal seam after 50 years of 20% CO 2 + 80% N 2 injection. According to the figure, although there is a 1: 5 proportion of CO 2: N 2 in the injecting gas, the remaining N 2 in the seam after 50 years’ injection is much less than the CO 2. This again proves that N 2 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 CO 2 in the seam. However, when figures and are compared, it can be clearly seen that a lower amount of methane gas exists in the coal seam after 20% CO 2 + 80% N 2 injection compared to the 80% CO 2 + 20% N 2 injection. This exhibits the greater degree of gas production enhancement created by N 2 during the injection period. CO 2, N 2 and CH 4 in the coal seam after 50 years of 20% CO 2 + 80% N 2 injection.However, since N 2 basically is present as a free gas in the coal mass, there is a high risk associated with the leaking of injected N 2 with the produced gas via the CH 4 production well. Therefore, this was checked in the next stage of the study. According to figure, N 2 starts to leak through the production well some time after the N 2 + CO 2 injection and that leakage rate increases in line with the N 2 percentage in the injecting gas.
On the other hand, according to figure, the injection of a N 2 + CO 2 mixture also has significant influence on CO 2 breakthroughs in the gas being produced, although the leakage initiates a long time after the N 2 leakage initiation and the leakage amount is more than a thousand times smaller than that of N 2. According to figure, increasing the N 2 percentage in the injecting gas from 20 to 80% causes the total N 2 and CO 2 leakage during 50 years of production to increase by around 1360% and 98%, respectively, which implies that changing the N 2 percentage more than 10 times significantly affects N 2 leakage compared to that of CO 2. This implies that N 2 leakage should be a more important consideration when deciding the N 2 percentage in the injecting gas in field projects. Comparison of effect of N 2% in the injecting gas on N 2 and CO 2 leakage.Therefore, it is very important to decide the best combination of N 2 and CO 2 in the injecting gas to minimize the risks associated with the ECBM process while maximizing CH 4 production. According to figure, the addition of more than 60% N 2 in the injecting gas seems to create very rapid N 2 and CO 2 leakage rates. Therefore, the injecting gas should contain less than 60% N 2 to ensure safe methane recovery enhancement.
Interestingly, this implies that the widely used flue gas injection (80% N 2 + 20% CO 2) in ECBM field projects is not a favorable option. If the effect of the N 2 percentage in the injecting gas on methane production enhancement is then considered, according to figure, having more than 40% N 2 in the injecting gas causes the production of greater amounts of N 2 than CH 4. Therefore, the desired N 2 percentage in the injecting gas should be less than or equal to 40%. Now, if figure is considered, increasing the N 2 percentage in the injecting gas from 0 to 20%, 20 to 40%, 40 to 60% and 60 to 80% causes CH 4 production to be enhanced by around 16.5%, 19.5%, 21.4% and 21.7%, respectively. Therefore, at least 40% N 2 in the injecting gas is required to enhance methane production by a significant amount. Therefore, while considering the effect of both CO 2/N 2 leakage and CH 4 production enhancement, 40% N 2 + 60% CO 2 is the best injecting gas combination for an effective CO 2 + N 2-ECBM process to enhance methane recovery safely from the selected coal seam.
Influence of production and injection well arrangement on enhanced coal seam CH 4 productionGas 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).
CO 2 injection well arrangement.The effect of the CO 2 injection well arrangement on the optimization of the ECBM process was first considered. One CO 2 injection well was first used and the number of injection wells was then increased to four, as shown in figure, and the corresponding variation in CH 4 production was examined.
As expected, increasing the number of injection wells from one to three caused the CH 4 production to be greatly enhanced (155%) (figures and ). This was expected, as increasing the injection well allows more CO 2 to be injected into the coal seam, which enhances the CH 4 production process by replacing the existing methane with the injecting CO 2. Change of CH 4 production with number of injection wells.However, according to figures and, the addition of more than three injection wells causes a reduction in CH 4 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. 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 CO 2 injecting well meeting each other within a shorter time, which causes the buildup of unnecessary pore pressure inside the coal seam. This negatively influences CH 4 release from the coal matrix and consequently CH 4 production capacity.
Figure shows the CO 2 and CH 4 available in the coal seam after the injection periods, and according to the figure, for more than two wells, CO 2 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 CO 2 into the coal seam, probably due to the development of pressure in the surrounding area due to CO 2 injection by the other wells, which acts as a barrier to CO 2 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 ), 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 CO 2 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. CH 4 available in the coal seam after 50 years of CO 2 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 CO 2 with the CH 4 produced. According to Curtis , mixing these two gases will also contribute to the development of additional pore pressure inside the seam, which causes additional production depletion. CH 4 production well arrangement.The effect of production well arrangement was then considered, and the results are shown in figure. 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 CH 4 production was examined (figures and ). According to figures and, an increase in the number of production wells has an insignificant impact on long-term (50 years) CH 4 production, with less than 10% change from one to four wells.
However, according to figure, in the case of short-term CH 4 production (10 years), there is a significant increase in CH 4 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 CH 4 production, and an increase from one to four results in around a 430% increase in total CH 4 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 CH 4 production and the negligible variation in long-term CH 4 production with an increased number of production wells. Change of CH 4 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. Distance between the injection and production well.According to sections and, the distance between the CO 2 injecting well and the CH 4 production well (figure ) 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, total CH 4 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 CO 2 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 CH 4 into CO 2 causes a large rise in CO 2 density, which creates additional pore pressure development in the coal seam (Curtis ). The effect of changing the distance between injecting well and production well on enhanced CH 4 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 CO 2 from a selected coal seam during the CO 2-ECBM process. ConclusionsThe 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 CH 4 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, CO 2 injection, CO 2 + N 2 gas mixture injection, and change of injection and production well arrangement. According to the results the following major conclusions can be drawn.Although the CO 2-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.
A simulated Top of Structure, depth map from geological data in a full field model. (GSI MERLIN simulator)
Reservoir simulation is an area of reservoir engineering in which computer models are used to predict the flow of fluids (typically, oil, water, and gas) through porous media.
Under the model in the broad scientific sense of the word, they understand a real or mentally created structure that reproduces or reflects the object being studied. The name of the model comes from the Latin word modulus, which means “measure, pattern”. Modeling is one of the main methods of knowledge of nature and society. It is widely used in technology and is an important step in the implementation of scientific and technological progress.
The creation of models of oil fields and the implementation of calculations of field development on their basis is one of the main areas of activity of engineers and oil researchers.
On the basis of geological and physical information about the properties of an oil, gas or gas condensate field, consideration of the capabilities of the systems and technologies for its development create quantitative ideas about the development of the field as a whole. A system of interrelated quantitative ideas about the development of a field is a model of its development, which consists of a reservoir model and a model of a field development process.
The investment project is a system of quantitative ideas about its geological and physical properties, used in the calculations of field development. The field of deposits and deposits is a system of quantitative ideas about the process of extracting oil and gas from the subsoil. Generally speaking, any combination of reservoir models and development process can be used in an oil field development model, as long as this combination most accurately reflects reservoir properties and processes. At the same time, the choice of a particular reservoir model may entail taking into account any additional features of the process model and vice versa.
The reservoir model should, of course, be distinguished from its design scheme, which takes into account only the geometric shape of the reservoir. For example, a reservoir model may be a stratified heterogeneous reservoir. In the design scheme, the reservoir with the same model of it can be represented as a reservoir of a circular shape, a rectilinear reservoir, etc.
Layer models and processes for extracting oil and gas from them are always clothed in a mathematical form, i.e. characterized by certain mathematical relationships.
The main task of the engineer engaged in the calculation of the development of an oil field is to draw up a calculation model based on individual concepts derived from a geological-geophysical study of the field, as well as hydrodynamic studies of wells.
Modern computer and computational achievements make it possible to take into account the properties of the layers and the processes occurring in them when calculating the development of deposits with considerable detail.
The possibilities of geological, geophysical and hydrodynamic cognition of development objects are continuously expanding. Yet these possibilities are far from endless. Therefore, there is always a need to build and use such a field development model in which the degree of knowledge of the object and the design requirements would be adequate
Fundamentals[edit]
Representation of an underground fault by a structure map generated by Contour map software for an 8500ft deep gas & Oil reservoir in the Erath field, Vermilion Parish, Erath, Louisiana. The left-to-right gap, near the top of the contour map indicates a Fault line. This fault line is between the blue/green contour lines and the purple/red/yellow contour lines. The thin red circular contour line in the middle of the map indicates the top of the oil reservoir. Because gas floats above oil, the thin red contour line marks the gas/oil contact zone.
Traditional finite difference simulators dominate both theoretical and practical work in reservoir simulation. Conventional FD simulation is underpinned by three physical concepts: conservation of mass, isothermal fluid phase behavior, and the Darcy approximation of fluid flow through porous media. Thermal simulators (most commonly used for heavy crude oil applications) add conservation of energy to this list, allowing temperatures to change within the reservoir.
Numerical techniques and approaches that are common in modern simulators:
Correlating relative permeability
The simulation model computes the saturation change of three phases (oil, water and gas)and pressure of each phase in each cell at each time step. As a result of declining pressure as in a reservoir depletion study, gas will be liberated from the oil. If pressures increase as a result of water or gas injection, the gas is re-dissolved into the oil phase.
A simulation project of a developed field, usually requires 'history matching' where historical field production and pressures are compared to calculated values.It was realised at an early stage that this was essentially an optimisation process, corresponding to Maximum Likelihood. As such, it can be automated, and there are multiple commercial and software packages designed to accomplish just that. The model's parameters are adjusted until a reasonable match is achieved on a field basis and usually for all wells. Commonly, producing water cuts or water-oil ratios and gas-oil ratios are matched.
Other engineering approaches[edit]
Without FD models, recovery estimates and oil rates can also be calculated using numerous analytical techniques which include material balance equations (including Havlena–Odeh and Tarner method), fractional flow curve methods (such as the Buckley–Leverett one-dimensional displacement method, the Deitz method for inclined structures, or coning models), and sweep efficiency estimation techniques for water floods and decline curve analysis. These methods were developed and used prior to traditional or 'conventional' simulations tools as computationally inexpensive models based on simple homogeneous reservoir description. Analytical methods generally cannot capture all the details of the given reservoir or process, but are typically numerically fast and at times, sufficiently reliable. In modern reservoir engineering, they are generally used as screening or preliminary evaluation tools. Analytical methods are especially suitable for potential assets evaluation when the data are limited and the time is critical, or for broad studies as a pre-screening tool if a large number of processes and / or technologies are to be evaluated. The analytical methods are often developed and promoted in the academia or in-house, however commercial packages also exist.
Software[edit]
Many programs are available for reservoir simulation. The most well known (in alphabetical order) are:
Open source:
Commercial:
Application[edit]
Reservoir simulation is ultimately used for forecasting future oil production, decision making, and reservoir management. The state of the art framework for reservoir management is closed-loop field development (CLFD) optimization which utilizes reservoir simulation (together with geostatistics, data assimilation, and selection of representative models) for optimal reservoir operations.
See also[edit]References[edit]
Other references
External links[edit]
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