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Deep coal seams as a greener energy source: a review
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Journal of Geophysics and Engineering J. Geophys. Eng. 11 (2014) 063001 (17pp)
doi:10.1088/1742-2132/11/6/063001
Topical Review
Deep coal seams as a greener energy source: a review A S Ranathunga, M S A Perera and P G Ranjith Deep Earth Energy Laboratory, Department of Civil Engineering, Monash University, Building 60, Melbourne, Victoria, 3800, Australia E-mail:
[email protected] Received 6 May 2014, revised 30 June 2014 Accepted for publication 16 July 2014 Published 6 November 2014 Abstract
Today, coal and oil are the main energy sources used in the world. However, these sources will last for only a few decades. Hence, the investigation of possible energy sources to meet this crisis has become a crucial task. Coal bed methane (CBM) is a potential energy source which can be used to fulfil the energy demand. Since the amount of carbon dioxide (CO2) emitted to the atmosphere from the use of CBM is comparatively very low compared to conventional energy sources, it is also a potential mitigation option for global warming. This paper reviews CBM recovery techniques with particular emphasis on CO2-enhanced coal bed methane (CO2-ECBM) recovery. The paper reviews (1) conventional CBM recovery techniques and problems associated with them, (2) CBM production-enhancement methods, including hydro-fracturing and enhanced CBM recovery techniques, such as N2-ECBM and CO2-ECBM, (3) the importance of the CO2-ECBM technique compared to other methods and problems with it, (4) the effect of CO2 injection during the CO2-ECBM process on coal seam permeability and strength and (5) current CO2-ECBM field projects and their progress. Although conventional CBM recovery methods are simple (basically related to the drawdown of the reservoir pressure to release methane from it), they are inefficient for the recovery of a commercially viable amount of methane from coal seams. Therefore, to enhance methane production, several methods are used, such as hydro-fracturing and ECBM (N2ECBM and CO2-ECBM). The CO2-ECBM process has a number of advantages compared to other methane recovery techniques, as it contributes to the mitigation of the atmospheric CO2 level, is safer and more economical. However, as a result of CO2 injection into the coal seam during the CO2-ECBM process, coal mass permeability and strength may be crucially changed, due to the coal matrix swelling associated with CO2 adsorption into the coal matrix. Both injecting CO2 properties (gas type, CO2 phase and pressure) and coal seam properties (coal rank and temperature) affect this swelling. Although there are many related studies, a number of gaps exist, especially in the area of coal rank and how the effect of other factors varies with the rank of the coal seam. To date, there have been few CO2-ECBM field projects in the world. However, the reduction of CO2 injectability after some time of CO2 injection, due to coal matrix swelling near the well bore, is a common problem in the field. Therefore, various permeability-enhancing techniques, such as hydro-fracturing and injection of an inert gas such as N2 or a mixture of inert gases (N2 + CO2) into the seam to recover the swelled areas are under test in the field. Keywords: CO2 sequestration, coal matrix swelling, enhanced methane recovery, hydrofracturing, permeability, strength reduction (Some figures may appear in colour only in the online journal) 1742-2132/14/063001+17$33.00
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© 2014 Sinopec Geophysical Research Institute Printed in the UK
Topical Review
J. Geophys. Eng. 11 (2014) 063001 3
1. Introduction
deep coal seams may still contain up to 25 m of methane per tonne of coal, adsorbed in the coal. According to White et al (2005) there are around 3010–7840 Tcf (trillion cubic feet) of international CBM resources and around 510 Tcf are recoverable. In Australia, 310 to 410 Tcf of CBM resources are available, while around 60 Tcf are in a recoverable state (White et al 2005). The amount of methane gas formed depends on the rank and the depth of the coal seam (Kim 1977, Eddy et al 1982, Moore 2012). Generally, a higher amount of methane is associated with higher rank coals, as they have been exposed to more severe temperatures and pressures during formation. If the depth effect is considered, the shallower the coal seam, the more potential there is for methane migration to the surface through fractures in the strata above the coal seams. Further, in coal; the surface area on which the methane is adsorbed is very large (20–200 m2 g−1) (Gale and Freund 2001), has low effective porosity and high compressibility, and are dominated by gas adsorption (White et al 2005). Therefore, CBM reservoirs can have as much as five times the amount of gas as that contained in conventional sandstone reservoirs. According to Levy et al (1997) and Bustin and Clarkson (1998), the gas adsorption capacity of coal is generally assumed to be dependent on pressure, temperature and coal characteristics. Both pressure and temperature increase with depth, and their opposed effects are super-imposed on each other (Kim 1977), resulting in a maximum gas adsorption capacity at a certain depth. Up to a depth of 2000 m, the effect of the temperature increment will be negligible compared to the effect of the pressure increment. However, at greater depths the temperature effect will become more and more important (Kim 1977, Levy et al 1997, Bustin and Clarkson 1998) (see figure 1). According to Metcalfe et al (1991), the available gas content in coal seams (GIP, gas-in-place) can be determined as follows (equation (1));
It is a well-known fact that world energy consumption is increasing with the growing population and around 81% of this demand is fulfilled from the fossil fuel sources with oil (32.4%) and coal (27.3%) being the major sources (IEA 2013). However, these sources will remain only for four to five decades, which emphasizes the importance of searching for new energy sources (Che et al 2013). Coal bed methane (CBM) is a potential energy source which can be used to fulfil the energy demand (Wilson et al 1995, Narasimhan et al 1998, White et al 2005). CBM is an economic source of pipeline-quality methane that is generated and stored in coal beds. It is a widely occurring, exploitable resource that can be easily recovered and used near the well or where any gas-pipeline infrastructure currently exists. Since CBM is a clean-burning fuel, it decreases the emission of anthropogenic CO2, which is a well-known greenhouse gas. Hence, CBM production becomes an additional advantage as a potential mitigation option for global warming. There are several methods in use to recover CBM from the coal seams. Among them CBM recovery via CO2 injection into deep coal seams has obtained a lot of attention because it enhances the recovery of CBM compared to conventional CBM recovery methods such as reservoir pressure depletion. It also has multiple advantages compared to other CO2 sequestration methods, as summarized in table 1. This implies the importance of deep coal seams as a CO2 storage medium due to the potential for the recovery of a vast quantity of methane during the sequestration process.
2. CBM recovery process Methane (CH4) is a major component (95%) of natural gas and a relatively inexpensive, clean-burning fuel. CBM refers to CH4 trapped in coal beds, which has been naturally formed during the coalification process. Therefore, deep coal seams represent large unconventional sources of natural gas. Coal comprises 85–95% of organic materials called maceral, which consists of precursor plant materials and is the main contributor for methane production in coal. If the methane production process in coal is considered, the cellulose and lignin-based plant material available in the coal maceral, including oxygen-containing moieties, such as carboxyl, hydroxyl or ketone functional groups are first fermented by normal bacteria present in coal into simple fermentation products such as acetate, methanol, formate and/or CO2 and H2 and eventually biodegraded into methane by methanogens (kind of microorganisms in coal that produce methane as a metabolic by product in anoxic conditions) (Lal and Priyangshu 2011). This methane is then either adsorbed onto the coal surface or dispersed in the pores. The methane generated during the above process is either adsorbed onto the coal surface or dispersed in the pores. According to Gale and Freund (2001), around 200 m3 of methane may have been generated for each tonne of coal formed. Most of this methane is subsequently lost, but undisturbed
GIP = 1. 36 × ρ B × V × h,
(1)
where ρB is the bulk density and h is the thickness, which can be determined directly from conventional logs, and V is the gas content, which can be determined either by direct or indirect methods, as described below. • Direct methods The direct methods measure the gas content using drill cuttings or conventional cores. Although there are several methods in use which are known as direct methods, that used by Seidle et al (1996) (equation (2)) is the most accurate method, as it considers all the available gas-in-place (Metcalfe et al 1991)
V (t ) = VLD [1– (6/π 2 ) exp {−π 2t (D / r 2 )}] − VL,
(2)
where VLD is lost plus desorbed gas contents, VL is lost gas, and D/r2 is the effective diffusional time constant. Here D is diffusivity and r is the average radius of the particles. • Indirect method Indirect methods infer the gas content using a sorption isotherm and pressure data. A sorption isotherm describes 2
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Table 1. Advantages and disadvantages of different types of CO2 sequestration method.
Method
Advantages
Disadvantages
References
Deep saline aquifers
• Largest capacity (~250 to 900 Gton carbon)
• Should be at least 800 m below the surface due to the existence of CO2 in high density state and to not mix the saline water with drinking water • Poorly characterized • Greatest geologic uncertainty (existence of faults or fractures) which may lead to back-migration of injected CO2 into the atmosphere sometime after injection • Fractures can be created due to the injection pressure, which may increase the risk of leakage of CO2 • Unknown seal effectiveness • Higher cost of infrastructure such as injection wells, surface equipment and pipe lines • Smaller capacity (~25 Gton carbon) • Limited in number • Risk in contaminating the remaining natural gas reserves with injected CO2
Bachu (2000, 2003) Evans (2009) Sundquist et al (2008)
• Wide distribution
Depleted oil and gas reservoirs
Deep un-mineable coal seams
Mineral Carbonate
• Extensively investigated during the oil exploitation stage • Known seal • Potential fuel recovery to offset cost • Underground and surface infrastructure (wells, equipment and pipelines) is already available • Adjacent to many large power plants • Potential fuel recovery (CBM) to offset cost • As 98% of CO2 is stored in an adsorbed phase and the rest as free gas inside the cleats, CO2 exists in a more stable form in coal seams, which eventually decreases the risk for back-migration • Can store a substantial amount of gas in their pore spaces due to large surface area associated with the micro-pore structure • Due to the formation of stable carbonates with the reaction of CO2 with natural occurring minerals (Mg and Ca), the risk of CO2 back-migration is reduced • These naturally forming carbonates are thermodynamically safe (contain lower energy compared to CO2) • Abundant suitable natural minerals are freely available
• Adsorption of gases into the coal matrix causes large strains to be induced between the adsorbed gas layer and the surface of the pore walls in the coal matrix (coal matrix swelling). It leads to; *great reduction of CO2 permeability in coal seam *influence on the overall strength
Gray (1987) Perera and Ranjith (2012) Perera et al (2011d) Reeves (2001) Stevens et al (2001) Sundquist et al (2008) Viete and Ranjith (2006) White et al (2005)
• Extensive time is required for the process
Howard (2002)
3. Conventional recovery techniques
the methane storage capacity as a function of pressure for a certain temperature condition. A Langmuir isotherm is commonly used to calculate the gas content (equation (3))
V = VM × [bp / (1+bp)],
Bachu (2000) Stevens et al (2001) Sundquist et al (2008)
CBM is conventionally recovered by means of reservoir pressure depletion. Around 98% of gas in deep coal seams is stored as sorbed gas in the coal matrix (Gray 1987) and the remaining gas is stored as free gas in natural fractures and cleats or in dissolved form in water. During the gas recovery process, these adsorbed gases are diffused and desorbed from the coal matrix to the cleat system and eventually produced from it (figure 3). This dual transport mechanism of CH4 in the matrix and cleats determines the primary behaviour of gas production in coals (White et al 2005).
(3)
where VM is the sorption constant, b is the pressure constant and p is the pressure (Metcalfe et al 1991). Figure 2 represents an idealized coal seam gas sorption isotherm showing the relationship between reservoir pressure and gas content for (a) saturated and (b) unsaturated coal seams. The heavy solid line indicates the maximum amount of gas that can be stored at any given reservoir pressure.
3
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Figure 1. Combined effect of pressure and temperature increase with increasing depth on the amount of methane, assuming normal geothermal gradient and hydrostatic pressure (modified after Bustin and Clarkson 1998, Levy et al 1997 and Kim 1977, respectively). (Left panel reprinted from R M Bustin and C R Clarkson 1998 Int J. Coal Geol. 38 3–26, Copyright 1998, with permission from Elsevier. Middle panel reprinted from J H Levy et al 1997 Fuel 78 813–9, Copyright 1997, with permission from Elsevier. Right panel: image in public domain.)
a – Initial reservoir pressure of Coals A & B b - Desorption of pressure of Coal B c - Gas content of Coal B d - Gas content of Coal A
Figure 2. Idealized coal bed gas sorption isotherm. (Reprinted with permission from C M White et al 2005 Energy Fuels 19 659–724.
Copyright 2005 American Chemical Society.)
By reducing the partial pressure of the adsorbed species, physical adsorption can be reversed. Hence, as the first stage of primary depletion, the hydrostatic pressure of the system is reduced through dewatering by beam lift, plunger lift, and/or compression, although many wells flow naturally (Metcalfe et al 1991). In this stage, gas and water flow at a relatively constant rate until a pseudo-steady state is attained. At the end of this stage, the well reaches its minimum bottom-hole pressure. A second stage begins at the pseudo-steady state and is characterized by a decline in gas production and a declining water rate. In this stage, the relative permeability to water decreases, the relative permeability to gas increases, and changes in gas desorption rate are observed. Outer boundary effects become more significant at the end of this stage. A third stage starts when the gas rate has peaked and water production is negligible. A mild gas production decline is observed and is continued for years, and negligible changes in relative permeability are observed. This final stage represents most of the economic life of a coal well (White et al 2005). The three stages of primary coal gas depletion are illustrated in figure 4. The methane removed directly from coal beds is generally of high purity (in excess of 90%), mainly when it is recovered from seams which have never previously been mined. The pressure depletion method is simple but inefficient, as it can recover less than 50% of the gas-in-place (Gale and
Matrix H2 O
CH4
CH4
CH4 + H2O CH4
CH4
H2 O
CH4
Matrix
Figure 3. Current CBM recovery mechanism. (Modified after Metcalfe et al 1991. Copyright 1991, Society of Petroleum Engineers Inc. Reproduced with permission of SPE. Further reproduction prohibited without permission.)
Freund 2001). For instance, to recover 50% of the gas-in-place in a coal seam, the reservoir pressure needs to be reduced from 13.8 MPa to less than 3.9 MPa (figure 5), which is generally not practical or economical. Hence, a substantial amount of CH4 in coal is left behind with the current operating method. Although hydraulic pressure is used to assist recovery, many wells must be drilled to achieve adequate gas recovery due to the low permeability of deep coal seams. As a consequence, 4
Topical Review
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J. Geophys. Eng. 11 (2014) 063001
Dewatering stage
Stable production stage
Decline stage
Water production rate Methane production rate
Time Figure 4. Typical production curves for CBM (reproduced with permission from Nuccio 2000).
In a typical fracturing process, a pad fluid or fracking fluid such as jellified crude oils, water or acids, is first pumped down into the coal seam through a wellbore to initiate and propagate fractures in the seam. The pad fluid is followed with proppantladen slurry that is introduced through the wellbore into the created fractures. The slurry forces the pad further into the created fractures, thereby extending the fractures while introducing proppants into the crested fracture to maintain the fracture in an open condition at the conclusion of the treatment. Special sand, aluminum spheres, granulated walnut shells or glass beads are often used as proppants during hydro-fracturing (Ruehl 1968, Mazza et al 1981, Holditch et al 1988, Puri et al 1991, Wright et al 1995, Department of Primary Industries 2013). Figure 6 illustrates the process of hydro-fracturing during CBM production. In addition, some gases, such as air, ammonia or carbon dioxide, also are used as the fracking fluid to enhance methane production from coal seams. However, the conventional fracturing techniques are of limited effectiveness if the treatment zone includes a natural fracture or cleat, as the cleat provides a path for the fracturing fluid and diminishes the extent of induced fractures. Fluid loss additives and the like are of limited effectiveness. Therefore, there is a need for an improved method of fracturing coal seams that contain natural fractures in the treated area and Mazza et al (1981) suggested such a method. According to Mazza et al (1981), a coal seam which is to be subjected to hydraulic fracturing is first pre-treated with a material which swells the coal. The swelling of the coal closes the natural fractures or cleats in the coal seam and prevents leakage of fracturing fluid during the subsequent hydraulic fracturing step, thereby enhancing the effectiveness of the hydraulic fracturing. The pre-treatment material may be any fluid which is capable of swelling coal on contact. Preferred pre-treatment materials are ammonia and hydrogen chloride, and liquid ammonia is the most preferred material (Mazza et al 1981). The pre-treatment fluid is injected into the coal seam at a pressure below the fracturing pressure and allowed to stand for a period of time sufficient to allow swelling of the coal. The pre-treated coal seam is subsequently subjected to a conventional hydraulic fracturing treatment. The process enables formation of fractures in a direction away from the natural cleats, greatly increasing the drainage or production rate of methane from the treated area.
Gas Content (cc/g)
25 20
Original gas in place
15 50% of gas in place
10 5 0 0
5
10 Pressure (MPa)
15
Figure 5. Limitation of gas recovery in reservoir pressure depletion. (Modified after Puri and Yee 1990. Copyright 1990, Society of Petroleum Engineers Inc. Reproduced with permission of SPE. Further reproduction prohibited without permission.)
methods such as enhanced CBM recovery are used in order to lessen the drawbacks of reservoir pressure depletion.
4. CBM production improving methods As discussed in the previous section, during primary coal gas depletion, CH4 production declines over time, and most of the target coal seams for CH4 production have extremely low reservoir permeability values. Hence, for economic gas production, it is necessary to increase reservoir permeability. Several methods currently in use in the industry and proposed by researchers are used to increase the permeability of the reservoir and these are considered in the following sections. 4.1. Fracturing of coal seams
CBM production usually begins with the drilling of at least one wellbore into the coal seam. The wellbore may initially produce some water or a small amount of gas from the coal matrix. Sustained production is achieved by performing a fracturing operation on the wellbore. Fracturing of the coal seams is believed to enhance gas recovery by preventing well bore damage, distributing the pressure at or near the well bore and accelerating the dewatering and pressure drawdown in the coal seam. 5
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Steel casing Cement barrier
Fracking fluid, proppants and additives pumped under pressure into coal seam via the well.
Fracking fluid is recovered from the well Gas is released from coal into fractures
Fractures are held open by proppants
Pressurized fracking fluid causes progressive fracking of the coal
(a)
Fracture simulation – flow in of fracking fluid
Gas and water are pumped into surface
Pressure is released and fractures contract
(b)
Coal seam gas well – removal of fracking fluid
(c)
Coal seam gas well – post recovery of fracking fluid
Figure 6. Schematic diagram of hydraulic fracturing in CBM production. (Department of Primary Industries 2013. © State of New South
Wales through the Department of Trade and Investment, Regional Infrastructure and Services 2013)
Although hydraulic fracturing is most often effective in increasing the near wellbore permeability in the coal seam, the effectiveness of the process depends on the thickness of the coal seam, and it is not economical for thin coal seams. Furthermore, hydraulic fracturing is not environmentally desirable when there is an active aquifer immediately adjacent to the coal seam, because the created fractures may extend into the aquifer, which will then permit unwanted water to invade the coal seam and the wellbore. According to some laboratory evidence, fracturing fluids can lead to long-term loss in coal permeability due to sorption of the fracturing fluids in the coal matrix causing swelling, and due to the plugging of the coal cleat or natural fracture system by unrecovered fracturing fluids. Therefore, Puri et al (1991) introduced another method to increase the permeability of coal seams by introducing a predetermined volume of gas that causes coal to swell into a coal seam through a wellbore. The rate of injection of the gas is controlled such that the adsorption and swelling of the coal is maximized adjacent to the wellbore. The pressure within the coal seam is maintained so that the desired volume of the gas will contact a desired area of the coal seam adjacent to the wellbore. The pressure within the coal seam is relieved prior to the pressure within the coal seam decreasing to some stabilized pressure by permitting the injected gas and other fluids to flow out from the wellbore at a rate essentially equivalent to the maximum rate permitted by the wellbore and surface wellbore flow control equipment. A relatively rapid outflow of fluids is desired and is believed to cause uneven stress fractures within the coal, the formation of hydrates with the natural coal fracture system and the dissolution of some mineral matter within the coal by the action of the acid solution created, all of which are believed to increase the near wellbore permeability of the coal. Further, Every and Luino Dell’Osso (1977) proposed a technique for recovering methane from a coal seam, where a displacing gas, such as carbon dioxide or nitrogen, is introduced into the coal seam through an injection well and held there for a sufficient period to enable a substantial amount of methane to be desorbed from the surfaces of the coal seam. Following the hold period, the injected displacing gas and desorbed methane are recovered through a recovery well or wells spaced from the injection well. The process is repeated to recover sufficient methane and is commonly known as enhanced coal-bed methane (ECBM) recovery.
4.2. ECBM recovery
Coal acts as a massive adsorbent bed (Puri and Yee 1990) and this adsorbent bed can be regenerated by not only using pressure depletion, but also by inert gas stripping, as well as by displacement desorption (Ruthven 1984, Yang 1987). Inert gas stripping is accomplished by reducing the partial pressure by introducing a low-adsorbing gas at constant pressure. In displacement desorption, another gas with higher adsorption capacity is injected into the coal seam, which displaces the adsorbed gas in the coal seam. In general, recovering CH4 using any of these methods is known as ECBM recovery. ECBM recovery can be achieved using several recovery agents, including N2, CO2, flue gas, compressor gas and other industrial off-gases (White et al 2005, Syed et al 2013). However, of the numerous patents documenting ECBM (Every and Luino Dell’Osso 1977, Puri and Stein 1989, Puri and Pendergraft 1995, Seidle et al 1996), most have focused on N2 and CO2 injection. 5. N2-enhanced coal bed methane (N2-ECBM) recovery In conventional primary recovery, the loss of reservoir pressure reduces the available energy until fluids stop flowing into the wellbore, resulting in low CH4 recovery. Laboratory research has shown that CH4 sorbed on coal can be stripped by N2 without reducing the system pressure. Moreover, with the energy supplied by N2 injection, the reservoir pressure could be maintained or increased while concurrently desorbing CH4 from the coal matrix and allowing it to diffuse through the cleat network system (White et al 2005). Hence, N2-injection ECBM is capable of recovering 90% or more of gas-in-place in the coal seam (Puri and Yee 1990). N2-ECBM works by lowering the partial pressure of CH4 to increase desorption (figure 7). N2 injection quickly increases methane production rates, while N2 breakthrough at the production well also occurs rapidly. (see figure 8) (Gale and Freund 2001, White et al 2005). The timing and magnitude depends on the distance between the injection and production wells, and the natural fracture porosity, permeability and sorption properties of the coal. The N2 content of the produced gas continues to increase until it becomes excessive (50% or greater), at which point injection would probably be halted (Gale and Freund 2001). 6
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Matrix
Matrix N2
CH4 CH4
CH4
CH4
N2
CH4
CH4 + H2O + N2
CH4 CO2
CH4
CO2
CO2
CH4
CO2
CO2
CH4
CH4
CH4 + H2O + CO2
Matrix
Matrix
Figure 9. CO2-enhanced CBM mechanism. Figure 7. N2-enhanced CBM mechanism. (Modified after Metcalfe
et al 1991. Copyright 1991, Society of Petroleum Engineers Inc. Reproduced with permission of SPE. Further reproduction prohibited without permission.) Primary production
CO2 -ECBM
Methane recovery rate
N2-ECBM
scale numerical model and found that approximately 218 Mm3 of CO2 can be sequestered in place of 74 Mm3 of CH4, which elaborates that approximately thrice the volume of CO2 can be sequestered in place of every volume of CH4 for high rank coals. Field applications and laboratory experiments have shown that this ratio could be even larger at depths greater than 800 m, where gaseous CO2 changes to super-critical CO2 (Hall et al 1994). The depth interval for CO2-ECBM is expected to be the same as that for CBM production (500– 1500 m). Around 98% of CO2 exists in an adsorbed phase on the walls of the coal micro-pores, while the rest remain as free gas inside the cleats (Harpalani and Schraufnagel 1990, Shi and Durucan 2005, White et al 2005, Perera and Ranjith 2012). Therefore, CO2 exists in a more stable form and remains stored within the seam, providing the seam is never disturbed (Gale and Freund 2001) (figure 9), which will eventually decrease the risk of back-migration.
0
1
2
Injection begins
3
4
5
6
7
8
Time
Figure 8. CH4 production profiles with N2 and CO2 injection. (Adapted with permission from C M White et al 2005 Energy Fuels 19 659–724. © 2005 American Chemical Society.)
6.1. Importance of CO2-ECBM recovery
Coal seams are frequently located near large point sources of CO2 emissions, specifically power generation plants that upsurge the facility for CO2 capture for the ECBM process (Reeves 2001, Sundquist et al 2008). Moreover, coal has a larger surface area associated with the micro-pore structure compared with the conventional reservoirs of a given volume of rock, so that it can store a substantial amount of CO2 within its pore spaces (Harpalani and Schraufnagel 1990, Stevens et al 2001, Perera and Ranjith 2012). For example, worldwide coal bed CO2 sequestration capacity is around 225 Gton and the combined Bowen and Sidney basins in eastern Australia can store about 11.2 Gton of CO2 (White et al 2005). Therefore, the CO2-ECBM process would also contribute to a reduction of the atmospheric CO2 level. To significantly reduce global emissions to pre-industrial levels, huge volumes of CO2 must be sequestered. For example, a large coal-fired power plant emits about 8 million tons of CO2 annually. At the pressures and temperatures expected for sequestration reservoirs, the volume required to sequester CO2 as a super-critical fluid is about 10 million cubic metres (Mm3) per year. According to the research (Stevens et al 2001, Bachu 2003, Metz et al 2005, White et al 2005, Benson and Cole 2008, Perera and Ranjith 2012), deep un-mineable coal seams are the most economical sources to store CO2 as it has the ability to counter-balance the sequestration cost with
6. CO2-enhanced coal bed methane (CO2-ECBM) recovery CO2 has a significantly higher affinity to adsorb into coal matrix than methane (refer to figure 9). Therefore, when CO2 is injected into the coal seam, it improves the recovery of CH4 by directly displacing the methane. In addition, CO2 injection also causes the reduction of the effective partial pressure of the CH4 (Stevens et al 2001), which eventually causes the adsorbed methane to be desorbed from the coal matrix. According to White et al (2005), 5 to 15 Gton of CO2 in the world can be sequestered in coal beds by the profit gained from CH4 production by ECBM. Laboratory isotherm measurements demonstrate that medium to high rank coal can adsorb approximately twice as much CO2 by volume as methane, and the common assumption is that, for higher rank coals, the ECBM process stores 2 moles of CO2 for every mole of CH4 desorbed (White et al 2005). However, some researchers have determined that some low rank coals may adsorb as much as 10 moles of CO2 for every mole of CH4 (White et al 2005). Vishal et al (2013c) investigated the feasibility of CO2 driven enhanced CBM recovery in Indian coals (coal type-black coal) using a field 7
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Absolute adsorption
5
4
Maximum Sorption
4
3
3
2
2
1
1
0
0 0
5
10
15
Volumetric Strain (εv)
5
Maximum swelling (Vol %)
Swelling (%)
0.002
6
6
0.001
0 0
2
8 4 6 Sorbed Volume (ml/g)
10
Figure 11. The relationship between sorbed volume and the
Sorption (%)
volumetric strain. (Reprinted with permission from S Harpalani and G Chen 1995 Fuel 74 1491–8. Copyright 1995, with permission from Elsevier.)
Figure 10. The relationship between the degree of swelling and
CO2 adsorption capacity. (Reprinted with permission from S Day et al 2010 Energy Fuels 24 2777–83. Copyright 2010 American Chemical Society.)
are desorbed. The CO2 adsorption-induced swelling effect in coal is a well-known fact and has already been observed in large-scale field trials of CO2 injection into coal seams (Day et al 2010). According to Day et al (2010), Perera and Ranjith (2012) and Shi et al (2014), the amount of swelling in coal is directly related to the absolute adsorption capacity of CO2 and the micro-pore capacity or maximum sorption capacity of coal. For instance, at higher adsorption capacities the coal matrix becomes weaker causing minor fractures eventually, generating higher adsorption surfaces and leading to a higher degree of swelling (Viete and Ranjith 2006, Perera and Ranjith 2012), as shown in figure 10. According to Day et al (2010) and Perera and Ranjith (2012), coal matrix swelling for different types of gas adsorption can be determined using the following equation:
the production of a valuable energy source (methane: CH4). According to White et al (2005), compared to the theoretical amount of CO2 generated in the coalification process, most coals contain much less CO2. It implies that, although CO2 is strongly sorbed into the coal matrix, it is difficult to transport away from the coal. Conversely, the solubility of CO2 is significantly impacted by the high salinity of some coal formation waters, which reduces the capability to acidize the water (White et al 2005). These details demonstrate the importance of CO2 sequestration in deep un-minable coal seams which is therefore given special consideration in this paper. However, the production increase due to CO2 injection in the ECBM process requires more time compared to N2 injection (see figure 8). This is due to the sorption of CO2 near the well. The sorbed CO2–CH4 front is expected to grow elliptically out from the injection wells because of coal anisotropy. After a sufficient volume of CH4 has been displaced for the gas drive to become effective, CH4 productivity increases (figure 8). When CO2 breakthrough occurs in the production well, the project would be terminated (Gale and Freund 2001, White et al 2005).
2 , Vs = −0.0037 + 0.1596Vabs + 0.0101Vabs
(4)
where Vs is volumetric swelling percentage and Vabs is the volumetric absolute adsorption percentage. As mentioned above, the coal structure shrinks when the adsorbed gases are desorbed from the matrix, which happens during methane production in coal seams. Harpalanai and Chen (1995) studied the fracture porosity of coal with this gas emission and proposed the following equations to describe the relationship between coal seam pressure with desorbed gas volume (equation (5)) and the amount of matrix shrinkage (equation (6)) during coal seam gas production (figure 11)
6.2. Problems with the CO2-ECBM method
Although the CO2-ECBM process has many advantages, it has some drawbacks due to the significant changes in the chemico-physical properties of coal after the injection of CO2. According to Viete and Ranjith (2006) and Perera and Ranjith (2012) large strains are induced between the surface of the pore walls and the adsorbed gas layer in the coal matrix during CO2 adsorption into the coal matrix, which is commonly known as coal matrix swelling. This greatly reduces the coal seam permeability for CO2 and CH4 movement and creates a profound effect on coal seam overall strength, according to current research findings (Czapliński and Hołda 1982, Shi and Durucan 2005, White et al 2005, Viete and Ranjith 2006, Durucan and Shi 2009, Day et al 2010, Jasinge et al 2011, Perera et al 2011a, Perera and Ranjith 2012). Coal has a polymer-like network structure and is therefore often affected by the gas or solvent with which it is in contact. The coal matrix swells when certain gases are adsorbed onto its surface and shrinks when water and hydrocarbons
Vdes = [VLp / (PL + p)]
(5)
εv = C[VLp / (PL + p)],
(6)
where, Vdes is the volume of gas desorbed from the coal matrix, p is the pore pressure, εv is the volumetric strain of the coal matrix, C is a constant which depends on the properties of coal mass, and VL and PL are, the Langmuir volume and pressure, respectively. In order to understand the coal matrix swelling effect on the CO2-ECBM process in various coal seams for different injection and production scenarios, it is necessary to have detailed knowledge of the factors affecting the swelling process. These are considered in the following sections. 6.2.1. Adsorbing gas type. Coal swells not only for CO2, but
also for other gases. For example, CH4 and N2 also swell coal,
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Volumetric Strain (εv)
J. Geophys. Eng. 11 (2014) 063001
0.025 0.02 N2 CH4 CO2
0.015 0.01 0.005 0 0
1
2
3
4
5
6
7
Pressure (MPa)
Figure 13. Phase diagram for CO2 (reproduced from Perera et al
2011d).
Figure 12. Effect of adsorbing gas type on swelling (reproduced
from Perera and Ranjith 2012).
adsorbing gas phase condition has a significant effect on coal matrix swelling.
although the effect is much less than that of CO2 (Eric and Richard 2005, Day et al 2010, Perera et al 2011c, Perera and Ranjith 2012, Chareonsuppanimit et al 2014, Shi et al 2014). Therefore, methane replacement by CO2 in the CO2-ECBM process will significantly increase the degree of swelling in the coal matrix. However, some other gases, such as H2S, which may be present in flue gas, swells coal more than CO2 (Day et al 2010). Figure 12 further illustrates the effect of adsorbing gas type (CO2, CH4 and N2) on swelling.
6.2.3. Coal rank. Coals are often classified according to their rank as low rank (lignite, around 60–71% carbon content and sub-bituminous coal, around 71–77% carbon content) and high rank (bituminous coal, around 77–87% carbon content and anthracite, more than 87% carbon content) coals. In general, the deeper the coal seam, the higher the rank, and this also explain the effect of coal seam location on the ECBM process. However, some contradictions can be seen in research findings on the effect of coal rank on its swelling. For example, Reucroft and Sethuraman (1987) showed an increasing swelling effect with increasing rank (figure 16). However, Walker et al (1988) observed that increment only for lignite to highly volatile bituminous coal and after that further increasing of rank caused the swelling effect to be reduced with increasing rank (in the anthracite region) (figure 16). This emphasises the importance of further investigations of the effect of coal rank on coal swelling.
6.2.2. Injecting CO2 phase and pressure. Beyond 7.38 MPa pressure and 31.8 °C temperature CO2 exists in its supercritical condition (figure 13) (Perera et al 2011c, Vishal et al 2013b). It is a well-known fact that the preferable coal seams for the CBM production process are normally present beyond 1000 m depths from the ground surface, where the pressure and temperature are higher than the critical value of CO2 (7.38 MPa and 31.8 °C) and therefore, CO2 is present in the super-critical state (figure 13). Therefore, Perera et al (2011c) conducted a series of triaxial experiments under subcritical and super-critical CO2 adsorptions to investigate the CO2 phase and pressure effect on coal swelling. They measured the radial strain increment in the coal sample during 15 h of sub-critical and super-critical CO2 adsorption with maintaining the system temperature above the critical temperature of CO2 (31.8 °C) (figure 14). According to the results obtained, both sub-critical and super-critical CO2 adsorptions induce a considerable swelling in coal, where, the swelling created by the super-critical CO2 adsorption is more than three times greater than sub-critical CO2 adsorption-induced swelling (figure 14), probably due to the highly chemically reactive nature of super-critical CO2 compared to sub-critical one. This implies that un-mineable coal seams are more vulnerable to the swelling effect. The effect of CO2 pressure on coal swelling has also been studied by Harpalani and Chen (1995), Pan and Connell (2006) and Day et al (2010), who have confirmed the increment of swelling with CO2 pressure (figures 15(a) and (b)). In addition, Day et al (2010) (figure 15(a)) and Pan and Connell (2006) (figure 15(b)) described the behaviour at high pressures where the swelling ratio may decrease after reaching a maximum swelling. Therefore, it is clear that not only gas injection pressure but also the
6.2.4. Temperature. With the increment of temperature,
gas molecules are released from the adsorbed phase as their kinetic energy increases with the temperature, which reduces the gas adsorption capacity in coal (Perera et al 2011d, Perera and Ranjith 2012). According to Perera and Ranjith (2012), Bae and Bhatia (2006) and Kronimus et al (2008), super-critical CO2 is subjected to the temperature effect more significantly than gas or liquid sub-critical CO2. As discussed in the previous section, sorption capacity is directly proportional to coal matrix swelling. Hence, a similar kind of behaviour can be suggested for the temperature effect on swelling (Perera and Ranjith 2012). According to the geothermal lines, underground temperature proportionally increases with depth and therefore, the CO2-ECBMcreated swelling effect should be clearly dependent on the location of the coal seam. Coal swelling during the ECBM process crucially affects the permeability and strength of the coal seam (Czapliński and Hołda 1982, Shi and Durucan 2005, Durucan and Shi 2009, Day et al 2010, Jasinge et al 2011, Perera et al 2011c). Therefore, the following sections discuss how the permeability and strength of coal seams are affected by gas 9
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Sub-critical Near-critical region region
Radial strain increment
0.005
Far-critical region
0.004 Sub-critical CO2
0.003
Super-critical CO2
0.002 0.001 0 0
5
10 Time (hrs)
15
20
Figure 14. Radial strain increments during a 15 h swelling period for sub-critical and super-critical CO2 adsorption at 15 MPa confining pressure (reproduced from Perera et al 2011c). 0.4
0.6 Harpalani and Chen (1995) Day et al. (2010)
0.4 0.2 0
Linear strain (%)
Swelling (%)
0.8
0.3
Pan and Connell (2006)
0.2 0.1 0
0
5 10 Pressure (MPa)
15
0
20
40 60 Pressure (MPa)
80
Figure 15. Effect of CO2 pressure on coal swelling. Reucroft and Sethurman (1987) Walker et al. (1988)
Swelling (%)
1
0.1
0.01 65
75 85 Carbon content (%)
95
Figure 17. Permeability for CO2 movement with injection pressure
Figure 16. Effect of coal rank on coal swelling.
(reproduced from Perera et al 2011b).
phase and pressure, coal rank and temperature during the ECBM process.
injection pressure and CO2 phase transition from sub- to super-critical (figure 17). Moreover, as discussed earlier, coal matrix swelling is also affected by the coal seam temperature (Bae and Bhatia 2006, Perera and Ranjith 2012). Therefore, Perera et al (2012) investigated the temperature effect on coal permeability for CO2 movement using naturally fractured black coal. They observed a significant increase in coal permeability with increasing temperature for higher CO2 injection pressures (>10 MPa), and an insignificant effect on permeability at low CO2 injection pressures (
