Investigation into the Methane Displacement Behavior by Cyclic, Pure

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Investigation into the Methane Displacement Behavior by Cyclic, Pure Carbon Dioxide Injection in Dry, Powdered, Bituminous Indian Coals Santanu Bhowmik and Pratik Dutta* Department of Mining Engineering, Bengal Engineering and Science University, Shibpur, Howrah 711103, West Bengal, India ABSTRACT: Understanding competitive sorption effects for the carbon dioxide
methane system in coal is essential for the implementation of enhanced methane production with concomitant CO2 sequestration in coal. The paper discusses the methane displacement behavior of a set of eight dry, powdered Indian bituminous coal samples when subjected to cyclic, pure CO2 injection, employing a “huff and puff” scheme. The coal samples were partially saturated with methane, and CO2 was then injected at a fixed pressure. This was followed by gas drainage to reduce pressure to the pre-injection level, and about 12
15 such cycles of CO2 injection and gas drainage were carried out. In general, the process successfully displaced the adsorbed methane. The adsorption ratio of CO2/methane was found to be higher than pure gas sorption capacities at the same pressure. Carbon dioxide was preferentially adsorbed into the coals, and during gas drainage, preferential desorption of methane was observed for all coals. The coals also exhibited different methane displacement behavior. For three coal samples, it was possible to recover 1 mol of methane by injecting less than 1 mol of CO2. For the other coal samples, 1.5
2 mol of CO2 was required for 1 mol of methane. However, no relationship could be established between the methane release characteristics of the coals and their petrographic composition.

’ INTRODUCTION Coalbed methane (CBM) reservoir is considered as a dualporosity and single-permeability structure, where more than 95% methane is stored, in an adsorbed state, in the porous spaces of the coal matrix and the remaining gas is stored as free gas in the cleat system.1 The total gas-in-place is governed by the depth, reservoir pressure, temperature, coal type, and coal rank. At a particular pressure, the reservoir may be undersaturated and can adsorb more gas at higher pressures.2 Gas production from the CBM reservoir starts when the reservoir pressure falls below the critical desorption pressure after dewatering of the reservoir, and a significant amount of gas (up to ∼50% of the total gas-in-place) may still remain in the reservoir after the abandonment pressure is reached.3
5 This limitation of gas production from the conventional CBM reservoir can be improved by N2 or CO2 injection, the process known as enhanced coalbed methane (ECBM) recovery. N2 injection enhances methane recovery by lowering the partial pressure of methane in the cleats, which, in turn, results in further desorption of methane from the coal matrix. However, N2 breakthrough at the production well occurs rapidly too, which creates problems by mixing with methane at the production well, requiring additional costs of gas processing for the removal of N2 from the produced gas stream.3 In CO2 ECBM, CO2 is injected into the coal reservoir, where it becomes preferentially adsorbed into the coal matrix with simultaneous desorption of methane into the free state for recovery.3,6 CO2 ECBM not only recovers additional methane but also provides a site for storage of a high volume of anthropogenic CO2 into coal, which, otherwise, will be released to the atmosphere. It has been observed that, at a particular temperature and pressure, CO2 has a much higher adsorption affinity to coal than methane and can become preferentially adsorbed into the coal.4,5,7
13 The strong adsorption characteristics of CO2 can result in rapid and complete displacement of adsorbed methane. The adsorption r 2011 American Chemical Society

ratio of pure CO2/methane is generally 2:1, although varying ratios of as high as 10:1 to less than 2:1 have also been observed depending upon the coal composition and coal rank.7
10,12 Therefore, in terms of pure gas sorption capacity, to displace 1 mol of methane, 2
10 mol of CO2 has to be injected into the coal, with a higher displaced methane/injected CO2 ratio and a lower operational cost of injection.6 On the other hand, the process also offers the added benefit of sequestering the greenhouse gas into unminable coal for a geologically significant time period.14 There are only a few field-based studies on CO2 ECBM/CO2 sequestration, and the number of laboratory studies is also limited. The world’s first large-scale ECBM pilot-scale study was conducted at the Allison Unit of the San Juan Basin in New Mexico, to investigate the feasibility of CO2 sequestration in deep, unminable coal seams.14,15 The Allison Unit was operated by Burlington Resources, in which CO2 injection continued for 6 months after which CO2 breakthrough was observed in the production well. This field test confirmed the feasibility of CO2 sequestration and enhanced gas recovery, but the permeability of the reservoir reduced by 2 orders of magnitude because of coal swelling with CO2 adsorption. In Europe, the first field experiment for CO2 storage was conducted in EC, RECOPOL Project in the Upper Silesian Coal Basin of Poland. CO2 injection started in 2004; however, continuous injection could not be achieved because of the reduction in permeability by coal swelling, and after 5 months, a slow rise in the CO2 concentration in the production well was observed. However, the study indicated that, at higher injection pressure, negative effects for the reduction in the permeability because of coal swelling could be overcome.16 Received: February 23, 2011 Revised: May 12, 2011 Published: May 12, 2011 2730

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Energy & Fuels The Alberta micropilot project was conducted in the lowpermeability Manville formation coals of the Fenn-Big valley in Canada.17 A “huff and puff” scheme was followed, where CO2 injection was followed by a shut-in period for allowing CO2 to soak with subsequent desorption of methane. It was possible to maintain high CO2 injectivity through this alternating injection and shut-in sequence. CO2 injection was not affected by coal swelling. On the contrary, CO2 injection increased the effective and absolute permeability, which, in turn, enhanced the methane production.6,17 Possibly, coal swelling by CO2 injection was offset by shrinkage of the coal matrix with methane desorption. Furthermore, injection of CO2 helped in maintaining high pressure in the reservoir, preventing fracture closure with a reduction in pressure. The results also indicated that lowpermeability coals that are not suitable for primary CBM production may be suitable for ECBM by the “huff and puff” scheme. Similar to the test conducted at Alberta, another micropilot test for CO2 sequestration and ECBM was conducted at the South Qinshui Basin in the Shanxi province of China. It was observed that the injectivity declined during injection but rebounded after an extended production period.18 The Southwest Regional Partnership on Carbon Sequestration (SWP) started an ECBM field validation test at the Pump Canyon Project of the San Juan Basin by CO2 injection into the lateCretaceous Fruitland coals to determine the most suitable technologies for carbon capture, storage, and sequestration. The injection continued with monitoring, verification, and accounting methods to track the movement of injected CO2, and a geologic characterization and reservoir modeling was implemented to understand the reservoir characteristics.19 Several researchers conducted laboratory experiments on the effectiveness of CO2 and/or N2 injection for enhanced gas recovery. Fulton et al.20 conducted sorption of methane on dry and wet core samples and studied methane release by cyclic CO2 injection after the partially methane-saturated coal stopped desorption from the conventional process. It was observed that the repeated injection of CO2 stripped the sorbed methane completely. Reznik et al.21 conducted CO2 injection on methane and water-saturated coal cores and observed that methane recovery increased with an increase in the injection pressure. Chaback et al.22 performed a simulation study for ECBM with pure components and mixtures of CO2 and N2 on powdered coal samples. They found that, in every case, the recovery of methane enhanced by more than a factor of 2 and most of the methane was produced much earlier compared to the conventional CBM process. Shimada et al.23 investigated sorption isotherms of N2, CH4, and CO2 on dry, powdered samples from the Akabira coal mine, Ishikari coalfield, Japan, and experimentally studied methane desorption characteristics by injecting N2/CO2 and their mixtures. It was found that the preferential adsorption of CO2 was significantly higher than that of N2 and CH4, and gas injection displaced almost all sorbed methane from coal. Tang et al.4 and Jessen et al.24 investigated N2, CH4, and CO2 sorption and displacement of methane by N2 and/or CO2 on powdered coal samples from the Powder River Basin. Experimental recoveries of original gas-in-place for methane were more than 94% in both of the cases. Yu et al.25 conducted a laboratory experiment on coals of the Qinshui Basin of North China to simulate the field-like situation of ECBM by CO2 injection with one injector and one producer well setup. The primary production results of CBM obtained with this setup were compared to the results of ECBM to understand the effect of CO2 injection on

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Table 1. General Information about Coal Samplesa name

a

location

depth (m)

Satgram

Raniganj Formation, Raniganj coalfield

190

Bogra

Do

160

Narayankuri

Do

Kalimati

Barakar Formation, Raniganj coalfield

172

Mehaladih

Do

201

SKAC2

South Karanpura coalfield

938

15th seam

Jharia coalfield

520

16th bottom seam

Do

450

46

Except SKAC2, information are reproduced by Dutta et al.39

CH4 production and gas sequestration. Busch et al.10,26 and Mazumder et al.27 conducted methane displacement studies for CO2 sequestration and observed preferential adsorption of CO2 and preferential desorption of methane for high-rank coals because of the higher affinity of CO2 into coal. However, contrary to this, Busch et al.26 also observed preferential adsorption of methane and preferential desorption of CO2 for some additional coals. Kemeny and Harpalani28 studied the preferential sorption properties of CH4 and CO2 and their impact on methane displacement and gas recovery. It was concluded that gas recovery was enhanced by the injection of CO2. The complex process of enhancement was due to the combination of preferential sorption into coal and the reduction in partial pressures of the adsorbate gas. Clarkson and Bustin29 investigated the effect of moisture, injection pressure, and gas composition on CO2 selectivity for both dry and wet, medium-volatile bituminous coals. They concluded that very poor correlation exists between the above-mentioned factors and preferential sorption behavior. Wei et al.30 conducted experiments for ECBM/CO2 sequestration on large grain coal samples (0.2
0.25 mm) with N2
CO2 mixed gas injection and reported that injection of mixtures of N2 and CO2 reduced the methane recovery compared to pure CO2 injection. The above-mentioned laboratory studies indicate that the preferential CO2 sorption/methane displacement phenomenon may not be universal and may need to be further investigated. Also, no such study has been reported on Indian coals. Furthermore, laboratory studies on cyclic CO2 injection are limited. In this paper, an attempt has been made to evaluate CO2-enhanced methane recovery using a “huff and puff” scheme. This involves injection of CO2 into the injector well, shutting off the well for a predetermined period for soaking of CO2, allowing methane to desorb, and then producing methane from the production well.31 Investigations conducted on oil recovery using the “huff and puff” scheme with cyclic CO2 injection reported that this combined method increases the overall oil recovery even at lower reservoir pressures32,33 The cyclic CO2 injection and its effects, preferential sorption behavior of CO2 over methane, and their interactions with different coal type are also analyzed. The gas production from the conventional pure gas adsorption results are compared to methane-displacement test results to compare the gas recovery. Coal Samples. Eight coal samples were collected from the eastern part of India, where major coal mining and CBM activities are concentrated. Five of the samples belong to the Raniganj coalfield; two of the samples belong to the Jharia coalfield; and the remaining sample belongs to the South Karanpura coalfield. Information about the source of the coal 2731

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Figure 1. Schematic diagram of the experimental setup for methane adsorption and displacement studies.

samples are given in Table 1. All samples, except those from the South Karanpura coalfield, were collected from freshly exposed faces of underground coal mines. The South Karanpura coal, SKAC2, was collected from a CBM drilling well. Upon collection, coal blocks were immediately wrapped tightly with plastic, indexed, and transported to the laboratory. The blocks were then crushed, in stages, to different size fractions. After crushing, the samples were kept in airtight packets and refrigerated to prevent oxidation. On average, 350
400 g samples between
100 and þ150 mesh size (0.100
0.149 mm) were used for sorption experiments. Samples were dried by keeping them in a vacuum-oven chamber maintained at 105 °C for 48 h. The step also ensured that the samples were degasified.34 Before the start of the experiment, a small amount of coal (∼1 g) was used for proximate analysis, following the standard American Society for Testing and Materials (ASTM) procedures.35 Another part of the sample was used for coal petrographic analysis at the Central Institute for Mining and Fuel Research, Dhanbad, India, following the relevant Indian Standard IS 9127.36 Methane Adsorption Isotherm and Displacement Tests. A high-pressure manometric gas-sorption apparatus was constructed similar to the one explained by Dutta et al.,37 the schematic diagram of which is shown in Figure 1. The sample cell was modified to accommodate a column-like coalpack. The reference and sample cells were connected to the pressure transducers (accuracy of 0.05% on a full scale) to monitor pressure variation within the cells. Needle and metering valves were introduced for precise control on gas flow during the tests. The entire setup was immersed in a constant temperature water bath maintained at 40 °C ((0.1 °C). The internal volumes of the reference and sample cells were calibrated by dosing helium and employing the real gas law. Gas compressibility factors were determined using the Span
Wagner equation of state.38 For the partial adsorption of methane, compressibility values were determined using the experimental pressure, temperature, and mole fraction of methane in the void space of the sample cell. The sample cell was filled up with the coalpack and compacted before the experiment by repeatedly filling and compressing to reduce plastic deformation. The void volume within the cell was similarly calibrated by helium expansion before the adsorption test. Methane was then injected into the reference cell, and the volumetric method was employed to establish the adsorption

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isotherm up to a maximum pressure of ∼3500 kPa. CO2 injection to displace the adsorbed methane commenced thereafter. Before the start of the displacement test, the gas chromatograph (GC) with a thermal conductivity detector (TCD) was kept dry at 150 °C for ∼2 h and calibrated by a standard process using known gas compositions from the calibration gas cylinder. The remaining free methane was vented out from the reference cell to the atmosphere, and a vacuum pump was used for degasifying it. A small gas sample (∼1 cm3) was collected from the sample cell and fed to the GC to check the initial composition of gas in the sample cell before CO2 injection. At first, the reference cell was filled with CO2, and after reaching pressure equilibrium, a “huff” of it was injected into the sample cell. Special care was taken to maintain a difference of ∼300
400 kPa between the reference and sample cells before injection to restrict the backflow of gas to the reference cell from the sample cell. Upon CO2 injection, pressure in the sample cell increased abruptly and then started to decrease gradually because of adsorption of CO2 into the coalpack. When pressure variation within the sample cell became negligible ((2 kPa) for a period of 1.5
2 h, the pressure value was recorded and a small gas sample (∼1 cm3) was fed to the GC to know the molar composition of the gases in the free state. The number of moles of CO2 injected from the reference cell was calculated by mass balance using the real gas law, and compressibility factors were determined from the Span
Wagner equation of state at experimental pressure
temperature conditions for pure CO2. The number of moles of CO2 as well as CH4 in free and adsorbed states within the sample cell was similarly calculated by the mass balance equation and compressibility factors for gas mixtures, which were determined from the knowledge of gas composition at experimental temperature and pressure conditions. Thereafter, the pressure in the sample cell was reduced (on an average of 100 kPa within 30
40 s) to the pre-injection level by carefully venting outgas from the sample cell to the atmosphere, simulating the “puff” scenario. After the vent-out valve was closed, pressure in the sample cell increased slightly (∼10
15 kPa) as a result of gas desorption, with a lowering of pressure in the cell. The number of moles “vented out” was taken into consideration to determine the adsorbed- and free-state individual gas mole components at the end of gas venting. For the calculation of “vented-out” moles, a couple of valid assumptions were made. First, the gases escaped mainly from the free state and not from the adsorbed state. Second, gas composition in the sample cell just after venting out was the same as the post-injection equilibrium composition. Finally, when the equilibrium pressure was reached after gas desorption, a small gas sample was again fed to the GC to obtain the molar gas compositions of the gases in free as well as adsorbed states. For each GC analysis, the samples were collected twice, the individual mole fraction for methane and CO2 in the mixture was calculated by the weighted mean of the two readings, and finally, the mole fractions were reported in a percentage basis. The difference between two GC readings was ∼1%. For the GC analyses, the pressure reduction in the sample cell was strictly maintained within 10 kPa. The mole fractions of CH4 and CO2 in the free and adsorbed states at each step were calculated from pressure, temperature, and gas compressibility factors, employing the real gas law and Span
Wagner equation of state.38 The entire process was repeated, and on an average, 12
15 such steps were carried out for each methane displacement test. The test was terminated when the CO2 concentration in the sample cell reached 20
22%. At each injection step, ∼0.7
1.0 2732

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methane sorption, ∼11
12 h was allowed to reach the equilibrium, as indicated in Figure 2. For methane displacement, ∼6 h and ∼45 min were sufficient to attain the equilibrium for each CO2 injection/adsorption and CH4
CO2 desorption, respectively. After first injection, successive injections were carried out at an ∼8 h interval. For all steps, the injection pressure, the pressure increment in the sample cell for CO2 injection, and the minimum pressure after gas venting to the atmosphere were closely maintained to keep the values more or less constant.

mmol/g CO2 was injected to keep the increase in total pressure in the sample cell to ∼100 kPa upon CO2 injection. For pure

’ RESULTS AND DISCUSSION Proximate and Petrographic Analyses. The results of proximate and petrographic analyses of the coal samples are given in Table 2. The proximate analysis was carried out after drying of the samples, as explained earlier, and therefore, the moisture content is representative of the residual moisture of the petrographic analyses samples. The results of petrographic analyses are reproduced by Dutta et al.39 for all samples, except SKAC2. Indian coals generally have very high ash content. The

Figure 2. Equilibrium time for pressure in the sample cell for methane pure adsorption isotherms.

Table 2. Proximatea and Petrographicb Analyses of Coal Samples name of

moisture

volatile

the sample

(%)

matter (%)

ash (%)

fixed

vitrinite

semivitrinitec

liptinite

inertinite

mineral

mean

carbon (%)

(%)

(%)

(%)

(%)

matter (%)

Ro (%)

Satgram

4

40

17

39

49.7

0.8

11.3

27.2

Bogra

7

38

10

45

73.9

0.4

4.2

15.8

11 5.7

0.64

0.61

Narayankuri Kalimati

7 1.2

41 36

15 28

37 34.8

73.9 12

0.8 1.3

6 7.3

11.4 61.3

7.9 18.1

0.64 0.96

Mehaladih

1.1

35

30

33.9

16.7

2.3

8.3

64.6

8.1

0.96

SKAC2d

3.5

36

32

28.5

(9.3)

(0.5)

(0.3)

(53.4)

(36.5)

(1.94)

15th seam

1.2

45

20

33.8

86.1

0.2

0.2

5.5

8

1.29

16th bottom

6

35

34

25

58.4

2.3

0.3

33.7

5.3

1.11

seam a Proximate analysis is conducted as per ASTM D3172-07a.35 b Petrographic analysis is performed as per IS 9127.36 Except for SKAC2, values are reproduced by Dutta et al.39 c Transition between vitrinite and fusinite.41 d Petrographic analysis is not available for SKAC2, and results of SKAC1 (values shown in parentheses) are used.

Figure 3. Methane and CO2 pure, excess adsorption isotherms, by Dutta et al.39 (blank symbols are for CH4, and filled symbols are for CO2). 2733

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Table 3. Summary of Methane and CO2 Pure Adsorption Experimentsa maximum experimental

maximum CH4 excess

maximum experimental

maximum CO2 excess

pressure for CH4 (kPa)

adsorption (mmol/g, daf)

pressure for CO2 (kPa)

adsorption (mmol/g, daf)

Satgram

4194

0.5567

5784

1.6536

Bogra

5085

0.8389

5750

1.9183

Narayankuri

6858

0.6536

5855

2.3051

Kalimati

5838

0.4511

4956

0.8114

Mehaladih

7782

0.5823

5380

0.9340

SKAC1

5705

0.6998

5488

1.0574

15th seam 16th bottom seam

6856 7038

0.6931 0.7843

5428 5604

1.1053 1.2787

coal sample

a

Results are obtained from the absolute adsorption values reported by Dutta et al.39

Figure 4. Methane excess adsorption before CO2 injection and CO2 excess adsorption after CO2 injection, respectively (blank symbols are for CH4, and filled symbols are for CO2).

ash content of the samples ranges from 19 to 34%. Raniganj formation coals have higher moisture but low to moderate ash content than the other samples. The volatile matter of the coal samples ranges from 35 to 48%. The mean vitrinite reflectance, Ro, representative of the maturity of the coal samples, varies from 0.61 to 1.29%, indicating that the coals are bituminous. As per the information given in Table 2, Jharia coals are the most mature, followed by the Barakar and Raniganj formation coals. The petrographic analysis of the SKAC2 sample is not available, and that of the SKAC1 sample, which is located close to the SKAC2 sample, was used. Methane and CO2 Adsorption Isotherms on Coal Samples. The complete methane and CO2 absolute adsorption isotherms were established at 30 °C, from
100 to þ150 mesh size (0.100
0.149 mm) sample for all coals, except SKAC2, as part of a different research and reported elsewhere.39 However, for completeness and comparison, the corresponding excess adsorption graphs are presented in Figure 3 and the experimental results are summarized in Table 3. All data are reported on a dry and ashfree (daf) basis at the standard temperature and pressure (15.5 °C and 101.3 kPa). For SKAC2, sorption isotherm test

data are not available, and therefore, the result of the SKAC1 sample, which is located in the vicinity, is reported. The maximum uncertainty for the pure isotherm measurements varied from 5.6 to 8.6%. It can be seen from Figure 3 that all isotherm graphs follow type-I behavior for both methane and CO2. The lowest ranked Raniganj formation coals show a continuous increasing trend in the experimental pressure range, for both methane and CO2, than the higher ranked Barakar, South Karanpura and Jharia coals. The data presented in Table 3 show variation in methane excess sorption capacity from a minimum of 0.4511 mmol/g for the Kalimati coal to a maximum of 0.8389 mmol/g for the Bogra coal. Similarly, the CO2 excess sorption capacity varies from a minimum of 0.8114 mmol/g for the Kalimati coal to a maximum of 2.3051 mmol/g for the Narayankuri coal. The coal samples show markedly separable isotherm graphs with their origin and location, except the CH4 isotherm of the Bogra sample. The ratio of CO2/CH4 pure, excess adsorption at an experimental pressure of 800 kPa is shown in Table 5. These values are reproduced by Dutta et al.39 to compare to the CO2/methane excess adsorption ratio at the final partial pressure of CO2 in the methane displacement tests. 2734

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Table 4. Summary of Methane and CO2 Adsorption in Displacement Tests maximum experimental pressure

maximum CH4 excess adsorption

maximum partial pressure

maximum CO2 excess adsorption

for CH4 (kPa)

(mmol/g, daf)

for CO2 (kPa)

(mmol/g, daf)

Satgram

3238

0.6473

732

0.7676

Bogra

3446

0.7298

883

1.3024

Narayankuri

3108

0.6744

768

1.1735

Kalimati

3356

0.4576

941

0.9049

Mehaladih

3220

0.5297

877

0.8365

SKAC2

3194

0.6267

846

1.0144

15th seam 16th bottom seam

3144 3207

0.7720 0.9241

839 795

1.0886 1.3571

coal sample

As observed in Table 5, the ratio varies from a minimum of 1.73:1 for the SKAC1 coal to a maximum of 7.03:1 for the Narayankuri coal. However, as discussed by Dutta et al.,39 the CO2/methane excess adsorption ratio reduces with an increasing pressure depending upon the coal composition and rank. Methane and CO2 Excess Adsorption before and after CO2 Injection. The excess adsorption capacity of methane with total pressure before CO2 injection and the excess adsorption capacity of CO2 with corresponding CO2 partial pressure after gas injection for all samples are shown in Figure 4, and the results are presented in Table 4. Methane adsorption before gas injection was conducted up to a pressure of 3100
3450 kPa. On the other hand, CO2 adsorption continued until the CO2 composition in void space of the sample cell reached 20
22%. The partial pressure of CO2 in the sample cell after each cycle was calculated from the gas molar composition in the cell. It can be seen from Table 4 that the excess adsorption for methane ranges from a minimum of 0.4576 mmol/g for the Kalimati coal to a maximum of 0.9241 mmol/g for the 16th bottom seam coal. For CO2, the excess adsorption ranges from a minimum of 0.7676 mmol/g for the Satgram coal to a maximum of 1.3571 mmol/g for the 16th bottom seam coal. It can also be observed that the methane and CO2 excess adsorption capacities in these tests follow the same trend as observed in pure component isotherms explained in a previous section for all coal samples, except for the 15th seam sample. The excess adsorption ratio of CO2/methane at the methane displacement tests was determined from Figure 4 at an experimental pressure of 800 kPa, and the values are shown in Table 5, along with the same ratio determined from the pure sorption tests. However, it may be mentioned here that, because the maximum CO2 partial pressures for the Satgram, Narayankuri, and 16th bottom seam coals were a little below 800 kPa, the adsorption ratios for these samples at 800 kPa were extrapolated from the excess adsorption graphs presented in Figure 4. It can clearly be observed from Table 5 that the CO2/methane excess adsorption ratio is generally higher in methane displacement tests compared to the one determined from pure adsorption tests. The ratio varies from a minimum of 2.61:1 for the 15th seam coal to a maximum of 4.03:1 for the Narayankuri coal. It can be further observed that the ratio increased significantly for the Kalimati (2.35:1
3.58:1), Bogra (2.47:1
3.93:1), and SKAC2 (1.73:1
3.46:1) coals, to a lesser extent for the Mehaladih (2.67:1
3.10:1), 15th seam (2.18:1
2.61:1), and 16th bottom seam (2.25:1
2.96:1) coals, and very slightly for the Satgram coal (3.24:1
3.34:1). For the Narayankuri coal, the reduction in ratio (7.03:1
4.03:1) can be attributed to the comparatively

Table 5. CO2/Methane Adsorption Ratios for Pure/ Preferential Adsorption CO2/CH4 adsorption ratios pure gas sorptiona

methane displacement

(at 30 °C and 800 kPa)

(at 40 °C and 800 kPa)

Satgram

3.24:1

3.34:1

Bogra

2.47:1

3.93:1

Narayankuri Kalimati

7.03:1 2.35:1

4.03:1 3.58:1

coal sample

Mehaladih

2.67:1

3.10:1

SKAC1/SKAC2b

1.73:1

3.46:1

15th seam

2.18:1

2.61:1

16th bottom seam

2.25:1

2.96:1

a Ratios are reproduced by Dutta et al.39 b SKAC1 and SKAC2 are used for pure sorption and displacement studies, respectively.

much lower pure, excess methane adsorption up to ∼500 kPa experimental pressure, as observed in Figure 3. In pure adsorption of methane, the gas stays in the coal structure and, once saturated at a particular pressure, the gas is not released until desorption is initiated by the reduction in pressure. In the methane displacement tests, conducted under this research, pure CO2 was repeatedly injected into the coalpack saturated with methane to release the adsorbed methane. Injection of CO2 into the sample cell reduced the partial pressure of methane in the void space. Concurrently, CO2 was adsorbed into the coal micropores. Some of these smaller micropores could be accessible to CO2 only and not methane because of the smaller kinetic diameter of CO2 molecules,11 while preferential adsorption of CO2 with concomitant desorption of methane could have taken place in some other micropores already occupied by methane. The above two reasons could well be ascribed to the higher CO2/CH4 ratio under the competitive adsorption scenario compared to the pure gas adsorption scenario. Methane Displacement by Cyclic CO2 Injection. As explained earlier, a “huff and puff” scheme was used to evaluate the methane recovery by pure CO2 injection after the coalpack was saturated with methane at a particular pressure. CO2 injection pressure in the current study varied within a narrow range of 4245
4500 kPa, and the impact of injection pressure on methane displacement was not analyzed explicitly. It was observed in the current study that complete stripping of adsorbed methane was achieved much earlier for the Bogra and Mehaladih coals compared to the Satgram and Kalimati coals. For rest of the 2735

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Figure 5. Residual adsorbed methane in coal upon CO2 injection.

Table 6. Test Results of Methane Displacement upon Cyclic CO2 Injection before gas release

after gas release

CO2 adsorbed CH4 displaced fraction of adsorbed CH4 desorbed fraction of adsorbed total fraction CH4 fraction of adsorbed coal samples test cycles

Mehaladih

Narayankuri

(mmol/g)

(mmol/g)

CH4 produced (%)

(mmol/g)

CH4 produced (%)

produced (%)

CO2 produced (%)

cycle 1 cycle 2

0.0800 0.0671

0.0503 0.0398

9.49 7.51

0.0549 0.0425

10.36 8.02

19.85 15.53

0.53 1.79

cycle 3

0.0707

0.0439

8.29

0.0410

7.74

16.03

2.07

cycle 4

0.0316

0.0088

1.66

0.0428

8.08

9.74

1.63

cycle 5

0.0779

0.0509

9.61

0.0409

7.72

17.33

1.94

cycle 6

0.0776

0.0503

9.49

0.0400

7.55

17.04

2.07

cycle 7

0.0291

0.0070

1.32

0.0344

6.49

7.81

3.50

cycle 1

0.0961

0.0517

7.67

0.0549

8.14

15.81

0.66

cycle 2 cycle 3

0.0989 0.0747

0.0523 0.0275

7.76 4.08

0.0449 0.0405

6.66 6.01

14.42 10.09

0.91 1.91

cycle 4

0.0966

0.0521

7.73

0.0436

6.47

14.20

1.85

cycle 5

0.0765

0.0316

4.69

0.0450

6.67

11.36

1.84

cycle 6

0.0947

0.0509

7.55

0.0408

6.05

13.60

1.74

cycle 7

0.0526

0.0104

1.54

0.0344

5.10

6.64

2.45

coal samples, total stripping of adsorbed methane was not achieved at the termination of the tests. This indicates that the injection pressure within the narrow range used in the study was not a significant factor for methane displacement. The residual adsorbed methane after methane displacement with corresponding adsorbed CO2 for each step of CO2 injection in the coal samples is plotted in Figure 5. The figure points out two distinct trends of methane displacement behavior. The higher slope of plots for the Satgram, Bogra, and Mehaladih coals indicates a tendency of these coals to release methane more readily than the rest of the coal samples. Table 6 gives the detailed methane displacement results for seven injection cycles of the Mehaladih and Narayankuri coals to demonstrate these two trends of methane displacement behavior. As can be seen from the table, the amount of CO2 injected for all of the cycles is consistently more for the Narayankuri coal. However, the ratio of CH4 displaced/CO2 adsorbed, shown in Figure 5, is less for this

coal compared to the Mehaladih coal. It can also be observed from Figure 5 that the ratio of total displaced methane/total CO2 adsorbed varies between 0.9 and 1.1 for the Satgram, Bogra, and Mehaladih coals. However, for rest of the coals, the ratio lies between 0.5 and 0.6. Therefore, it can be stated that, for the Satgram, Bogra, and Mehaladih coals, nearly 1 mmol/g CO2 has to be adsorbed to produce 1 mmol/g methane. On the other hand, for rest of the coals, nearly 2 mmol/g or an even higher amount of CO2 has to be adsorbed to release the same amount of methane. It is already established from sorption experiments that the sorption capacity of CO2/CH4 varies from 2:1 to 4:1 or even higher depending upon the pressure and coal type/coal rank, which means that normally 2
4 mol of CO2 would be required to displace 1 mol of adsorbed methane. However, in this cyclic CO2 injection technique, 1 mmol/g CH4 was produced by the adsorption of 1 mmol/g CO2, which supports the enhanced gas recovery at less CO2 consumption, leading to easier release 2736

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Figure 6. Gas release trends because of desorption in methane displacement tests (blank symbols are for CH4, and filled symbols are for CO2).

Figure 7. Methane sorption characteristics because of cyclic CO2 injection.

of methane. The last four columns of Table 6 show the gas desorption behavior of the coals with the reduction of the pressure in the sample cell upon venting of gas to the atmosphere. It can be seen that the fraction of adsorbed methane released for all of the cycles is more for the Mehaladih coal than the Narayankri coal, indicating that the Mehaladih coal not only displaces methane more efficiently upon CO2 injection but also desorbs more methane compared to the Narayankuri coal with pressure depletion. In the cyclic CO2 injection method, methane is produced from the combined process of displacement and desorption, which enhances the total methane recovery significantly. Therefore, it can be concluded from the results presented in Figure 5 and Table 6 that that the Satgram, Mehaladih, and

Bogra coals will be more suitable for ECBM, whereas the other coals, especially the 15th seam and Narayankuri coals, will be more suitable for CO2 sequestration. Another important observation can be made from the data presented in Table 6. The amount of adsorbed methane released with pressure reduction within the sample cell for each cycle is much higher than the amount of CO2 released for both of the coals. The cumulative amount of methane and CO2 desorbed because of gas venting for all samples is plotted in Figure 6. It can be observed from the figure that the amount of released methane is consistently higher than the amount of released CO2 for all coals. Therefore, it can be concluded that, with pressure reduction, preferential desorption of methane takes place for all coals 2737

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Figure 8. Adsorbed CO2/released CH4 ratios and CH4 recovery with coal types and maceral composition.

and CO2 has a higher tendency than methane to remain in coals. Busch et al.26 studied the relative sorption behavior of a set of 15 coal samples from the mixture of CO2 and methane with varying composition. They observed, similar to the findings of this study, preferential adsorption of CO2 and preferential desorption of methane for a few high-rank coals. However, they also observed preferential adsorption of methane and preferential desorption of CO2 for some other low-rank Dutch and American coals. However, the preferential desorption of CO2 has not been observed in the current study on Indian coals. The methane adsorption for partial saturation of the coals up to an experimental pressure of ∼3600 kPa and their desorption behavior because of cyclic, pure CO2 injection is shown in

Figure 7. Methane desorption is plotted as a function of the partial pressure in the sample cell, which was calculated from the knowledge of gas molar composition after each cycle of gas injection. Previous investigations established that, with pressure reduction, the methane desorption line in coals coincides with or lies above the adsorption line.8,39 Quite expectedly, the methane desorption line with cyclic CO2 injection, shown in Figure 7, does not follow the normal desorption path but falls sharply. When pure CO2 is injected, a part of it becomes adsorbed into coal and, simultaneously, adsorbed methane is displaced and released. Later, when gas venting in the sample cell reduces the system pressure, methane is also released by the normal gas desorption process. This 2-fold release of adsorbed methane at 2738

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Energy & Fuels the end of a cycle in the methane displacement test substantially increases the overall methane production, which, otherwise, may remain in the coal as residual methane. As can be observed in Figures 5 and 7, for some coals, almost all of the adsorbed methane can be released, although the CH4 partial pressure remains high (∼2500
3000 kPa). Also, the total pressure is maintained nearly at the injection pressure level in the process. In the conventional method of methane production, the reservoir pressure declines steadily, which results in an increase in effective stress, and this increase in effective stress may reduce the absolute permeability of the fracture system in some CBM reservoirs. The cyclic method of CO2 injection can not only displace a much higher proportion of sorbed methane but can also maintain a high pore pressure in the reservoir, eliminating such possibility of reduction in absolute permeability. Also, as CO2 is injected in a cyclic manner, its partial pressure also increases in successive steps, and as seen in Figure 4, CO2 adsorption increases in methane displacement tests at a much lower pressure than in the pure sorption case. In earlier investigations, Kemmeny and Harpalani28 and Prusty40 conducted methane displacement tests after partial desorption of methane from methane-saturated coals by pure CO2 injection and reached the same conclusion. It is evident from the above observations that CO2, when injected into the coals partially saturated with methane, can displace adsorbed methane and, during gas venting, preferential desorption of methane takes place. Therefore, CO2 not only becomes preferentially adsorbed into the coals but also, once adsorbed, exhibits stronger resistance to desorption than methane. Dutta et al.39 discussed the relative sorption affinity of CO2 and methane in details along with their relationship with rank and coal compositions. However, the study was reported on single gas sorption of these coals to either methane or CO2. Dutta et al.39 also discussed the works of other researchers to relate the relative sorption affinity of coals and their petrographic properties. The focus of the current research was to assess the relative ease with which the coals release adsorbed methane when subjected to cyclic CO2 injection. Panels a
f of Figure 8 give a plot of methane released/CO2 adsorbed ratio as a function of various coal properties. It is evident from the figure that, for the same amount of CO2 injected, the three coal samples, Satgram, Bogra, and Mehaladih, release more methane compared to the other coal samples. However, no relationship is apparent between the ratio and any of the coal properties. It cannot be established, from the limited study carried out thus far, which factor controls the methane release behavior of these coals when subjected to cyclic CO2 injection.

’ CONCLUSION A laboratory investigation was conducted to study the methane displacement and the preferential gas sorption behavior of a set of dry, Indian bituminous coals upon cyclic, pure CO2 injection using the “huff and puff” scheme of gas injection. At first, the samples were partially saturated by pure methane adsorption up to ∼3500 kPa, and then displacement tests were carried out. The following conclusions can be drawn from the study: (a) At the same pressure and temperature, CO2 shows higher affinity to coal than methane with varying coal types and the pure gas sorption data on Indian bituminous coals revealed that, for 1 mmol/g methane adsorption, 1.5
4 mmol/g CO2 is adsorbed (daf). The process of methane displacement by CO2 injection improves the adsorption ratio of CO2/methane

ARTICLE

sorption from the same ratio obtained from pure gas sorption for all coals, except the 15th seam coal. (b) When CO2 is injected it becomes preferentially adsorbed in coal, which, in turn, displaces the adsorbed methane from the adsorbed state and releases it into the free state. Later, methane desorption takes place, while gas is vented out to reach the pre-injection pressure level. The combined effect of these two processes substantially increases the methane recovery. The results of the present study supports this observation for Indian coals. (c) During gas venting, methane is preferentially desorbed compared to CO2. (d) The cyclic method of CO2 injection employing the “huff and puff” technique was able to completely strip the adsorbed methane for four coal samples. For rest of the samples, the ratio of methane recovered/CO2 adsorbed increased significantly. (e) No relationship can be established between the coal composition and rank and the methane release characteristics of the coals studied under the research.

’ AUTHOR INFORMATION Corresponding Author

*Telephone: þ91-33-2668-4561/2/3, ext. 477. Fax: þ91-332668-2916. E-mail: [email protected].

’ ACKNOWLEDGMENT The authors acknowledge the funding received from the Department of Science and Technology, Government of India, for carrying out the research work. ’ REFERENCES (1) Mavor, M.; Nelson, C. R. Coalbed Reservoir Gas-in-Place Analysis; Gas Research Institute (GRI): Chicago, IL, 1997; pp 1.1
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