Adsorption of Pure Carbon Dioxide on Wet Argonne Coals at 328.2 K

Energy & Fuels 2009, 23, 1107–1117

1107

Adsorption of Pure Carbon Dioxide on Wet Argonne Coals at 328.2 K and Pressures up to 13.8 MPa S. A. Mohammad, J. S. Chen, J. E. Fitzgerald, R. L. Robinson, Jr., and K. A. M. Gasem* School of Chemical Engineering, Oklahoma State UniVersity, Stillwater, Oklahoma 74078 ReceiVed October 9, 2008. ReVised Manuscript ReceiVed NoVember 21, 2008

Carbon dioxide (CO2) adsorption isotherms were measured on five different rank coals at 328.2 K and pressures up to 13.8 MPa using a volumetric method. Specifically, Beulah Zap, Illinois #6, Pocahontas #3, Upper Freeport, and Wyodak coals from the Argonne premium coal sample program were used for these isotherm measurements. These newly acquired data are compared to our previous data on dry coals. As expected, the adsorption on the wet coals is lower than that on the dry coals. At 7 MPa, Pocahontas, Upper Freeport, Illinois #6, Wyodak, and Beulah Zap coals exhibited, respectively, about 19, 17, 48, 76, and 79% reduction in the amount adsorbed on the wet coal when compared to the adsorption on the dry coal. These reductions in CO2 adsorption correlate positively with the amount of moisture present on the coal. The isotherms on wet coals were measured at their equilibrium moisture content. The adsorption isotherm for each of the wet coals exhibited a Gibbs adsorption maximum between 8 and 12 MPa and occurred at a higher pressure than that of the dry coal. The simplified local-density/Peng-Robinson model was used to correlate the adsorption data. The model was found capable of representing precisely the CO2 adsorption on both dry and wet coals. Specifically, the overall weighed average absolute deviation (WAAD) for the five dry and wet coals was 0.99 and 0.42, respectively. Nevertheless, more rigorous accounting for the water interactions with the coal matrix and the competitive adsorption between water and CO2 would provide an even more realistic description of coal-bed gas adsorption phenomenon on wet coals.

1. Introduction The long-range goal of the authors is to develop reliable models to predict the adsorption behavior of supercritical gases on coals, with specific applications to (a) coal-bed methane production and (b) the use of coal beds to sequester the greenhouse gas carbon dioxide. To achieve that goal, we have performed both experimental1-3 and modeling4-8 studies. Developing adsorption models to describe adsorption behavior on coals is complicated by (a) the difficulty in characterizing the coal matrix adequately and (b) assessing the effect of water (found in essentially all coal beds) on the adsorption behavior. Water can significantly affect gas adsorption capacity by blocking the porous adsorbent structure and limiting the accessibility of an adsorbing gas, such as methane.9 The * To whom correspondence should be addressed. Fax: 405-744-6338. E-mail: [email protected]. (1) Hall, F.; Zhou, C.; Gasem, K. A. M.; Robinson, R. L., Jr. Adsorption of pure methane, nitrogen, and carbon dioxide and their binary mixtures on wet fruitland coal. In Eastern Regional Conference and Exhibition, Charleston, SC, 1994. (2) Sudibandriyo, M.; Pan, Z.; Fitzgerald, J. E.; Robinson, R. L.; Gasem, K. A. M. Adsorption of methane, nitrogen, carbon dioxide, and their binary mixtures on dry activated carbon at 318.2 K and pressures up to 13.6 MPa. Langmuir 2003, 19 (13), 5323–5331. (3) Gasem, K. A. M.; Robinson, R. L., Jr.; Fitzgerald, J. E.; Pan, Z.; Sudibandriyo, M. Sequestering carbon dioxide in coalbeds. DE-FC2698FT40426, prepared for the U.S. Department of Energy, 2003. (4) Zhou, C.; Hall, F.; Gasem, K. A. M.; Robinson, R. L., Jr. Predicting gas adsorption using two-dimensional equations of state. Ind. Eng. Chem. Res. 1994, 33 (5), 1280–1289. (5) Gasem, K. A. M.; Fitzgerald, J. E.; Pan, Z.; Sudibandriyo, M.; Robinson, R. L., Jr. Modeling of gas adsorption on coalbeds. In Eighteenth Annual International Pittsburgh Coal Conference, Newcastle, Australia, 2001. (6) Gasem, K. A. M.; Sudibandriyo, M.; Fitzgerald, J. E.; Pan, Z.; Robinson, R. L., Jr. Measurement and modeling of gas adsorption on selected coalbeds. In AIChE Spring National Meeting, New Orleans, LA, 2002.

adsorption of gases on wet coals has also demonstrated that water can significantly affect the adsorption capacity for coalbed gases (methane, nitrogen, and CO2). Joubert et al.10 observed that moisture on coals can reduce methane adsorption by as much as 40% on Pittsburgh coal and 15% on Pocahontas coal. Levy et al.11 observed that 4% moisture can reduce the methane adsorption by as much as 60% from that of the dry coal. Similarly, Clarkson and Bustin12 showed that 2% moisture can cause 20% reduction of both methane and CO2 adsorption capacity on a wet coal when compared to the adsorption on the dry coal. In addition, our own measurements on wet Illinois coal have shown that 9% moisture can cause 50% reduction of CO2 adsorption at 3 MPa. These results demonstrate the significant effect of moisture on gas adsorption behavior. In our earlier studies,13-15 we have measured pure and mixedgas adsorption isotherms on wet coals. However, these coals were less well-characterized than the Argonne premium coal samples. The Argonne premium coal sample program was initiated to provide the scientific community with the highest (7) Pan, Z.; Sudibandriyo, M.; Fitzgerald, J. E.; Robinson, R. L., Jr.; Gasem, K. A. M. Equilibrium models for coalbed methane production and carbon dioxide sequestration. In International Petroleum Environmental Consortium (IPEC) Conference, Albuquerque, NM, 2002. (8) Fitzgerald, J. E.; Robinson, R. L.; Gasem, K. A. M. Modeling highpressure adsorption of gas mixtures on activated carbon and coal using a simplified local-density model. Langmuir 2006, 22 (23), 9610–9618. (9) Muller, E. A.; Hung, F. R.; Gubbins, K. E. Adsorption of water vapor-methane mixtures on activated carbons. Langmuir 2000, 16 (12), 5418–5424. (10) Joubert, J.; Grein, C. T.; Bienstock, D. Effect of moisture on methane capacity of coals. Fuel 1974, 53, 186–191. (11) Levy, J. H.; Day, S. J.; Killingley, J. S. Methane capacities of bowen basin coals related to coal properties. Fuel 1997, 9 (76), 813–819. (12) Clarkson, C. R.; Bustin, R. M. Binary gas adsorption-desorption isotherms: Effect of moisture and coal composition upon carbon dioxide selectivity over methane. Int. J. Coal Geol. 2000, 42, 241–271.

10.1021/ef800870a CCC: $40.75  2009 American Chemical Society Published on Web 12/31/2008

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Mohammad et al.

Figure 1. Schematic diagram of the experimental apparatus.

quality of coal samples.16 In this work, we report CO2 adsorption isotherm measurements on five wet Argonne coals. Specifically, we present CO2 adsorption isotherms on Beulah Zap, Illinois #6, Pocahontas #3, Upper Freeport, and Wyodak coals. Three of the five coals reported here were measured as part of a Department of Energy/National Energy Technology Laboratory (NETL) interlaboratory study.17,18 The “round robin” study was organized to (a) assess the reproducibility of CO2/coal adsorption isotherm measurements and (b) develop a standard method for measuring coal adsorption isotherms. Further, we discuss the modeling capabilities of the simplified local-density/ Peng-Robinson model as it pertains to the systems considered in this study. More general, detailed evaluations of our adsorption models will soon appear elsewhere.19 2. Experimental Methods and Procedures 2.1. Adsorption Measurements. The experimental method used in the Oklahoma State University adsorption laboratory is based (13) Fitzgerald, J. E.; Pan, Z.; Sudibandriyo, M.; Robinson, R. L., Jr.; Gasem, K. A. M.; Reeves, S. Adsorption of methane, nitrogen, carbon dioxide and their mixtures on wet Tiffany coal. Fuel 2005, 84 (18), 2351– 2363. (14) Fitzgerald, J. E.; Sudibandriyo, M.; Pan, Z.; Robinson, R. L.; Gasem, K. A. M. Modeling the adsorption of pure gases on coals with the SLD model. Carbon 2003, 41 (12), 2203–2216. (15) Hall, F. E. Adsorption of pure and multicomponent gases on wet fruitland coal. M.S. Thesis, Oklahoma State University, Stillwater, OK, 1993. (16) Vorres, K. S. The Argonne premium coal sample program. Energy Fuels 1990, 4 (5), 420–426. (17) Goodman, A. L.; Busch, A.; Bustin, R. M.; Chikatamarla, L.; Day, S.; Duffy, G. J.; Fitzgerald, J. E.; Gasem, K. A. M.; Gensterblum, Y.; Hartman, C.; Jing, C.; Krooss, B. M.; Mohammed, S.; Pratt, T.; Robinson, R. L., Jr.; Romanov, V.; Sakurovs, R.; Schroeder, K.; White, C. M. Interlaboratory comparison II: CO2 isotherms measured on moisture-equilibrated Argonne premium coals at 55 °C and up to 15 MPa. Int. J. Coal Geol. 2007, 72 (3-4), 153–164. (18) Goodman, A. L.; Busch, A.; Duffy, G. J.; Fitzgerald, J. E.; Gasem, K. A. M.; Gensterblum, Y.; Krooss, B. M.; Levy, J.; Ozdemir, E.; Pan, Z.; Robinson, R. L.; Schroeder, K.; Sudibandriyo, M.; White, C. M. An interlaboratory comparison of CO2 isotherms measured on Argonne premium coal samples. Energy Fuels 2004, 18 (4), 1175–1182. (19) Gasem, K. A. M.; Robinson, R. L., Jr.; Mohammad, S. A.; Chen, J. S.; Fitzgerald, J. E. Improved Adsorption models for coalbed methane production and CO2 sequestration. Final Technical Report, 2005-2007, prepared for Advanced Resources International, 2008.

on a mass balance principle, which employs precise measurements of pressure, volume, and temperature. The experimental apparatus, shown schematically in Figure 1, has been used successfully in previous measurements.2,3,15 Brief descriptions of the experimental apparatus and procedures are provided below. The entire apparatus is maintained in a constant temperature air bath. The equilibrium cell (Figure 1) is filled with the adsorbent to be studied, and the cell is placed under vacuum prior to gas injection. The void (gas) volume, Vvoid, in the equilibrium cell is then determined by injecting a known quantity of helium from a calibrated injection pump (Ruska). Because helium is not significantly adsorbed, the void volume can be determined from measured values of the temperature, pressure, and amount of helium injected into the cell. The mass balance equation is

Vvoid )

(

( P∆V ZT )

pump

P1 P2 Z2T Z1T

)

(1)

cell

where ∆V is the volume of the gas injected from the pump, Z is the compressibility factor of helium, T is the temperature, P is the pressure, subscripts “cell” and “pump” refer to conditions in the cell and pump sections of the apparatus, respectively, and “1” and “2” refer to conditions in the cell before and after injection of gas from the pump, respectively. The helium void volume measurements were performed at the same temperature as the CO2 adsorption isotherms (328.2 K) and over a range of pressures from atmospheric to about 13.8 MPa (2000 psia) in intervals of 1.4 MPa (200 psia). Several injections made into the cell at different pressures show consistency in the calculated void volume. Generally, the void volume calculated from sequential injections varied less than 0.3 cm3 from the average value of approximately 85 cm3. The helium void volume includes all of the volume of the cell section exclusive of the adsorbent volume that is impenetrable to helium gas. The constancy of the calculated void volume from the incremental injections over a range of pressures confirmed the validity of our assumption that adsorption of helium is negligible at the conditions of the measurements. The Gibbs adsorption (also known as the excess adsorption) can be calculated directly from experimentally measured quantities. For pure-gas adsorption measurements, a known quantity, ninj, of gas

Adsorption of Pure CO2 on Wet Argonne Coals

Energy & Fuels, Vol. 23, 2009 1109

Table 1. Analyses of Coals Used in This Study analysesa

Beulah Upper Zap Wyodak Illinois-6 Freeport Pocahontas

carbon (%) hydrogen (%) oxygen (%) sulfur (%) ash (%)

72.9 4.83 20.3 0.80 9.7

Ultimate 75.0 77.7 5.35 5.00 18.0 13.5 0.63 4.83 8.8 15.5

85.5 4.70 7.5 2.32 13.2

91.1 4.44 2.5 0.66 4.8

moisture (%) volume matter (%) fixed carbon (%) ash (%)

32.2 30.5 30.7 6.6

Proximate 28.1 8.0 32.2 36.9 33.0 40.9 6.3 14.3

1.1 27. 1 58.7 13.0

0.7 18.5 76.1 4.7

a

Argonne National Laboratory.

(e.g., CO2) is injected from the pump section into the cell section. Some of the injected gas will be adsorbed, and the remainder, nGibbs unads, will exist in the equilibrium bulk (gas) phase in the cell. A molar Gibbs, as balance is used to calculate the amount adsorbed, nads Gibbs Gibbs nads ) ninj - nunads

(2)

The amount injected can be determined from pressure, temperature, and volume measurements of the pump section

ninj )

( P∆V ZRT )

pump

(3)

The amount of unadsorbed gas is calculated from conditions at equilibrium in the cell Gibbs nunads )

( ) PVvoid ZRT

cell

(4)

where the pressure P is measured after equilibrium is reached in the cell (usually within 6-12 h, depending upon the adsorption capacity of the adsorbent), which occurs when no further change in pressure is observed. In eqs 3 and 4, Z is the compressibility factor of the gas at the applicable conditions of temperature and pressure. The above steps are repeated at sequentially higher pressures to yield a complete adsorption isotherm. The amount adsorbed is usually presented as an intensive quantity (mmol adsorbed/g Gibbs by the mass of adsorbent adsorbent or mmol/g) by dividing nads in the cell. Equations 2-4 reveal that the amount adsorbed may be calculated in a straightforward manner from the experimental measurements of pressures, temperatures, and volumes, coupled with independent knowledge of the gas compressibility factors, Z, from an accurate equation of state. 2.2. Gas Compressibility Factors. As evident from the above discussion, accurate compressibility factors are required for pure CO2 for proper adsorption data analysis. The compressibility factors for pure CO2 were calculated from a highly accurate equation of state.20 Further, for void volume determination, the helium compressibility factor was calculated with an expression based on experimental data from the National Bureau of Standards Technical Note 631 for helium.21 2.3. Materials. The pure CO2 gas used in this work was obtained from Airgas-Pennsylvania with reported purity of 99.99% and was used as received. The Argonne coal samples were obtained from the Argonne National Laboratory, Argonne, IL, in ampoules containing 5 g of 100 mesh material of each coal. The compositional analyses of the Argonne coals are presented in Table 1. The Illinois #6 coal is from the Illinois #6 or Herrin seam; it is a high-volatile bituminous coal. The Wyodak coal is from the Wyodak-Anderson (20) Span, R.; Wagner, W. A new equation of state for carbon dioxide covering the fluid region from the triple point temperature to 1100 K at pressures up to 800 MPa. J. Phys. Chem. Ref. Data 1996, 25, 1509–1590. (21) McCarty, R. D. Thermophysical properties of helium-4 from 2 to 1500 K with pressures to 1000 atm. NBS Technical Note 631, U.S. Department of Commerce, 1972.

seam; it is a sub-bituminous coal. The Upper Freeport coal is a medium-volatile bituminous coal; Pocahontas coal is a low-volatile bituminous coal; and Beulah Zap coal is lignite.16 2.4. Error Analysis. Frequent instrument calibration tests were performed during the course of the experiments. Usually, the calibrations were performed before the adsorption experiments on a new adsorbent sample. The thermocouples and RTDs were calibrated against a Minco platinum reference RTD. Super TJE pressure transducers (range: 0-13.8 MPa) were calibrated using helium as the working fluid against a Ruska deadweight tester, with a calibration traceable to the National Institute of Standards and Technology. Detailed information on the calibration procedure is available elsewhere.15 The uncertainties in the experimentally measured quantities after calibrations were estimated as follows: temperature, 0.1 K; pressure, 6.9 kPa; and injected gas volume, 0.02 cm3. A detailed error analysis was performed to estimate the uncertainty associated with each experimental data point by propagating the errors from the primary measurements of pressure, temperature, and volume. The error analysis indicates that the average uncertainties for the CO2 adsorption measurements are approximately 7-13% for Illinois #6, Upper Freeport, and Pocahontas coals. The higher percentage uncertainty is usually obtained at the higher pressure, mainly because of the lower value of the Gibbs adsorption for CO2 at the higher pressure and the higher uncertainty in the CO2 compressibility factor (because of its proximity to its critical point). The average uncertainties for Beulah Zap and Wyodak coals were around 34%. However, these higher percentage uncertainties are a result of lower adsorption amounts for these two wet coals and amounted to only about 0.06-0.07 mmol/g of error, on average. In our data reduction technique, we accounted for the amount of gas dissolved in the water-rich adsorbed phase; thus, resulting in lower calculated adsorption amounts for higher moisturecontaining coals. The Beulah Zap and Wyodak coals contain 32.2 and 28% moisture, respectively. 2.5. Equilibrium Moisture of Coals. Moisture equilibration of porous adsorbents, such as coals, is usually carried out with the standard American Society for Testing and Materials (ASTM) procedure D1412.22 This method consists of equilibrating the adsorbent samples at 30 °C (303.2 K) in a vacuum desiccator over a saturated solution of K2SO4 to maintain the relative humidity at 96-97%. However, the use of vacuum in a desiccator can often result in condensation problems, thus negating the experiment.10 Therefore, we used a modified method, where the samples were equilibrated under an inert nitrogen atmosphere. The moisture content of the equilibrated sample was then determined by drying a part of the sample under vacuum at around 40 °C (313.2 K) for 48-72 h. The weight of the sample was monitored, and the weight loss after 72 h was taken as the moisture loss. The expected uncertainty in the measured moisture content was estimated to be about 0.1 wt %. The Illinois #6 coal samples were equilibrated using the above method by placing them in a nitrogen atmosphere at 95-100% relativity humidity in a Hotpack model 434300 temperature-humidity chamber. This resulted in a gain of only 1.2% moisture over the equilibrium value reported in the literature.16 Therefore, for the other four Argonne coals, namely, Beulah Zap, Pocahontas, Upper Freeport, and Wyodak coals, the as-received coal sample was placed directly in the equilibrium cell under inert atmosphere. This was performed under the reasonable assumption that further moistening of the coal in the temperature-humidity chamber would not greatly change the coal moisture content from its as-received moisture. Moreover, the direct use of as-received samples minimizes possible oxidation of the samples that can affect the integrity of the coal sample. Great care has been taken by the Argonne National Laboratory to maintain the coal samples at their in-seam conditions.16 Because the objective of our study was to simulate the (22) American Society for Testing and Materials (ASTM). Standard test method for equilibrium moisture of coal at 96 to 97% relative humidity and 30 °C. In Gaseous Fuels; Coal and Coke; ASTM: West Conshohocken, PA, 2000; D1412, pp 99-102.


Mohammad et al.

Table 2. Parameters for CO2 Solubility in Water at Multiple Temperatures constant

value

a b1 b0 c1 c0

272.21 -332.637 1.06683 19.18 -0.05609

units of constant MPa K-1 MPa-1 MPa-1K-1

conditions of a coal-bed reservoir while measuring adsorption isotherms (in terms of pressure, temperature, and moisture content), measuring the isotherms at their as-received or in-seam moisture values was considered greatly beneficial. These isotherms can be considered to be measured near or at the equilibrium moisture content of the coals. In the present context, the term “wet” coal is used to signify saturation of coal with adsorbed moisture. For adsorption measurements on the dry Argonne coals, the coal samples were dried under vacuum in an equilibrium cell at 353 K for 36 h as per the NETL drying protocol before being used in the adsorption measurements. The adsorption data on dry coals were measured in an earlier work.23 2.6. Gas Solubility in Water. In previous studies3,15 performed by Oklahoma State University on wet adsorbents, we included a term in eq 2 to account for the amount of gas, nsol, dissolved in the water. Gibbs Gibbs nads ) ninj - nunads - nsol

(5)

To calculate the CO2 gas dissolved in water for use in eq 5, literature data24-26 were used to construct an empirical relationship for CO2-water solubility at temperatures from 313.2 to 348.2 K. In the 0-15 MPa range, the empirical function represents their data with an average absolute deviation of 1.5%. Thus, the mole fraction of CO2 present in water at temperature T (in K) and pressure P (in MPa) is given as

xCO2 )

P a + (b1 + b0T)P + (c1 + c0T)P2

(6)

Table 2 lists the parameter values for this correlation. The amount of CO2 dissolved in water was taken (approximately) as the product of this mole fraction and the amount of water (in moles) in the system. Further, the amount of CO2 dissolved in water per unit mass of coal is expressed as

nsol )

xCO2nwater mcoal

(7)

where nwater is the amount of water (in moles) and mcoal is the mass of coal in the system. As evident from the above discussion (eq 5), accounting for the solubility of gas in the water-rich adsorbed phase lowers the calculated Gibbs adsorption values. In the above, we have assumed that all of the water present in the system is adsorbed, and therefore, the amount of gas dissolved in water was estimated on the basis of all of the water present in the system. In addition, this means that we have assumed that the CO2 bulk-gas phase was free from water (i.e., that yCO2 ) 1, where y is the gas-phase mole fraction). 2.7. Adsorption Measurements on Wet Coals. For the adsorption isotherm measurements on the wet coals, care was taken to (23) Arumugam, A. High pressure adsorption of pure coalbed gases on dry coals. M.S. Thesis, Oklahoma State University, Stillwater, OK, 2004. (24) Dhima, A.; de Hemptinne, J.; Jose, J. Solubility of hydrocarbons and CO2 mixtures in water under high pressure. Ind. Eng. Chem. Res. 1999, 38 (8), 3144–3161. (25) King, A. D. J.; Coan, C. R. Solubility of water in compressed carbon dioxide, nitrous oxide and ethane. Evidence for hydration of carbon dioxide and nitrous oxide in the gas phase. J. Am. Chem. Soc. 1971, 93 (8), 1857– 1862. (26) Weibe, R.; Gaddy, V. The solubility of carbon dioxide in water at various temperatures from 12 to 40 °C and at pressures to 500 atm, critical phenomena. J. Am. Chem. Soc. 1940, 62, 815–817.

prevent moisture loss during the experiments. The coal samples were handled in a chamber filled with nitrogen. Because the evacuation step during the void volume measurement and at the beginning of the isotherm can result in moisture loss, the system pressure was not reduced below 21 kPa at 328.2 K. This is slightly above the vapor pressure of water at this temperature, and this minimizes any potential water being removed from the coal surface. Further, before the start of the CO2 adsorption experiment, about 0.35 MPa of CO2 gas was injected into the cell to flush any remaining helium gas out. The CO2 gas was then evacuated until the pressure was again about 21 kPa, and the flushing procedure was performed once more. To test for any moisture loss during the experiment, two additional checks were performed. First, the equilibrium cell/coal sample was weighed before and after the adsorption isotherm. There was no (significant) mass loss observed from the equilibrium cell at the end of the isotherm. Second, the helium void volume was measured before and after the adsorption isotherm. The helium void volumes measured were within the experimental uncertainty of our void volume measurements (about 0.3%). The constancy in the calculated void volume further indicated that there was no significant moisture loss during the experiment. Given the size of our volumetric apparatus, any miniscule amount of water leaving the coal surface would introduce an uncertainty in the isotherm measurement, which is well within the reported experimental uncertainty of the isotherm, as obtained by multivariate error propagation. These uncertainty estimates for each data point of each isotherm are included with Gibbs adsorption data. 2.8. Coal Swelling. Another aspect of supercritical gas adsorption on coals is the potential swelling of coal caused by adsorbates, such as CO2. Some investigators believe that adsorption of CO2 can significantly alter the porous coal structure, and these changes, if left unaccounted for, can result in large errors in the modeling of supercritical CO2 adsorption on coals. In fact, several researchers have attempted to model the swelling of coal by incorporating volumetric corrections to the adsorption isotherm equations. Ozdemir et al.27 and Dutta et al.28 used different adsorption models to study the volumetric effects of CO2 adsorption on coals. Romanov et al.29 have also attempted to interpret the volumetric changes in coals under CO2 pressure. Pan and Connell,30 balancing the change in surface energy because of adsorption to the change in elastic energy of the coal matrix, developed a theoretical model to describe adsorption-induced coal swelling. Recently, Day et al.31 measured swelling on coals and corrected their adsorption measurements to account for volumetric changes to the sample. These corrections involved adjusting the void volume to account for an increased volume of coal sample. We have measured helium void volume before and after each adsorption isotherm experiment. The constancy of the calculated void volume within its experimental uncertainty of 0.3% indicated that there was no irreversible change to the volume of the sample. This result is also supported by the findings of Day et al.,31 who found the coal swelling to be entirely reversible. Although Day et al.31 then applied a correction to the isotherm, we have used a constant void volume in our data reduction procedures. Thus, the adsorption data reported (27) Ozdemir, E.; Morsi, B. I.; Schroeder, K. Importance of volume effects to adsorption isotherms of carbon dioxide on coals. Langmuir 2003, 19 (23), 9764–9773. (28) Dutta, P.; Harpalani, S.; Prusty, B. Modeling of CO2 sorption on coal. Fuel 2008, 87 (10-11), 2023–2036. (29) Romanov, V.; Soong, Y.; Schroeder, K. Volumetric effects in coal sorption capacity measurements. Chem. Eng. Technol. 2006, 29 (3), 368– 374. (30) Pan, Z.; Connell, L. D. A theoretical model for gas adsorptioninduced coal swelling. Int. J. Coal Geol. 2007, 69 (4), 243–252. (31) Day, S.; Fry, R.; Sakurovs, R. Swelling of Australian coals in supercritical CO2. Int. J. Coal Geol. 2008, 74 (1), 41–52.



Table 3. Gibbs Adsorption of Pure CO2 on Wet Beulah Zap Coal at 328.2 K

Table 7. Gibbs Adsorption of Pure CO2 on Wet Wyodak Coal at 328.2 K

pressure (MPa)

Gibbs adsorption (mmol/g)

σ Gibbs (mmol/g)

pressure (MPa)


σ Gibbs (mmol/g)

1.02 1.50 2.82 4.22 5.91 7.15 8.35 9.71 11.05 12.04 13.57

0.135 0.179 0.262 0.324 0.372 0.369 0.357 0.327 0.312 0.248 0.089

0.053 0.053 0.052 0.052 0.051 0.051 0.053 0.068 0.094 0.107 0.120

0.47 0.76 1.46 2.77 4.22 5.64 7.01 8.35 9.67 10.92 12.35 13.92

0.041 0.067 0.130 0.233 0.319 0.372 0.411 0.417 0.420 0.424 0.368 0.254

0.048 0.048 0.048 0.048 0.048 0.048 0.049 0.063 0.074 0.084 0.099 0.101

Table 4. Gibbs Adsorption of Pure CO2 on Wet Illinois #6 Coal at 328.2 K pressure (MPa)


σ Gibbs (mmol/g)

0.42 0.79 1.56 2.23 2.87 4.27 5.62 7.02 8.34 9.69 11.04 12.41 13.88

0.146 0.231 0.356 0.440 0.511 0.634 0.701 0.765 0.791 0.800 0.777 0.716 0.644

0.052 0.052 0.051 0.051 0.050 0.050 0.049 0.049 0.063 0.065 0.075 0.092 0.088

Table 5. Gibbs Adsorption of Pure CO2 on Wet Pocahontas #3 Coal at 328.2 K pressure (MPa)


σ Gibbs (mmol/g)

0.40 0.77 1.49 2.84 4.25 5.63 6.99 8.33 9.69 10.34 12.16 13.11

0.281 0.439 0.605 0.764 0.854 0.901 0.915 0.908 0.868 0.840 0.730 0.674

0.040 0.040 0.040 0.039 0.038 0.038 0.037 0.038 0.048 0.050 0.068 0.075

Table 6. Gibbs Adsorption of Pure CO2 on Wet Upper Freeport Coal at 328.2 K pressure (MPa)


σ Gibbs (mmol/g)

0.40 0.81 1.47 2.86 4.24 5.64 7.00 8.35 9.67 10.75 12.31 13.86

0.239 0.363 0.482 0.624 0.698 0.739 0.756 0.758 0.742 0.737 0.667 0.593

0.043 0.043 0.042 0.042 0.041 0.041 0.040 0.041 0.052 0.056 0.073 0.082

in this study are under the assumption that there is no appreciable swelling of the coal.

3. Results The experimental data for the CO2 adsorption on Beulah Zap, Illinois #6, Pocahontas #3, Upper Freeport, and Wyodak coals are listed in Tables 3-7, respectively. All adsorption measurements are reported on a dry-mass basis. Included in Tables 3-7

are the Gibbs adsorption data and the expected experimental uncertainties for each datum. The Gibbs adsorption data on three of the coals, namely, wet Beulah Zap, Illinois #6, and Pocahontas coals, were published in a NETL interlaboratory study.17 The remaining two coals in this study (wet Pocahontas and Upper Freeport coals) are new additions to this set of data that were not published earlier. The main objective of the NETL interlaboratory study17 was to investigate the reproducibility of CO2/coal adsorption isotherm measurements among different laboratories. In contrast, the objective of our study is to investigate the effect of water present in coals on the experimental data reduction and model analysis of these isotherms. The adsorption data published earlier17 did not include accounting for the solubility of CO2 in adsorbed water and, thus, differ from the results presented here. Neglecting the solubility in the earlier work was part of a specified data reduction procedure provided by NETL and designed to ensure consistent data reductions among the participating laboratories in that study. The subtraction of dissolved CO2 in adsorbed water yields the actual amounts adsorbed on the wet coals, leading to lower values of the Gibbs adsorption than previously published.17 For the higher moisture-containing coals in this study, this correction is significant, and it also affects the model analysis of these isotherms. To highlight this difference, Figure 2 presents a comparison of CO2 adsorption data on wet Beulah Zap coal published in Goodman et al.17 and that used in this study. As evident from the figure, accounting for the gas solubility in adsorbed water can result in quite different calculated values of Gibbs adsorption. Figures 3-7 illustrate the Gibbs adsorption of CO2 on Beulah Zap, Illinois #6, Pocahontas #3, Upper Freeport, and Wyodak coals used in this study, respectively. The CO2 adsorption on each of the dry coals is also illustrated for comparison. Also shown in Figures 3-7 are the representations obtained from the simplified local-density/Peng-Robinson (SLD-PR) model, as described in section 4. For each coal, the CO2 adsorption on the wet coal was lower than that on the dry coal. Further, the reduction in the gas adsorbed from that on dry coals appears to be correlated positively with the moisture content of the coal. Specifically, the Pocahontas, Upper Freeport, Illinois #6, Wyodak, and Beulah Zap coals, respectively, exhibited about 19, 17, 48, 76, and 79% reductions in the adsorption on the wet coals at 7 MPa when compared to the adsorption on the dry coals. Figure 8 compares the Gibbs adsorption of CO2 on all five wet coals and also illustrates the SLD-PR model representations. The adsorption isotherm for each of the wet coals exhibits a maximum between


Mohammad et al.

Figure 2. CO2 adsorption on wet Beulah Zap coal at 328.2 K: effect of gas solubility in water.

Figure 3. CO2 adsorption on wet and dry Beulah Zap coal at 328.2 K.

8 and 12 MPa. For each case, the adsorption maximum on the wet coal occurs at a higher pressure than that for the dry coal. 4. SLD-PR Modeling In this work, we have used the simplified local-density (SLD) model to describe the adsorption behavior of CO2 on five Argonne coals. The SLD model accounts for the fluid-fluid and fluid-solid interactions in a slit-shaped pore. The model was first developed by Rangarajan et al.,32 who used the van der Waals equation of state (EOS) to provide the fluid-fluid (32) Rangarajan, B.; Lira, C. T.; Subramanian, R. Simplified local density model for adsorption over large pressure ranges. AIChE J. 1995, 41 (4), 838–845. (33) Chen, J. H.; Wong, D. S. H.; Tan, C. S.; Subramanian, R.; Lira, C. T.; Orth, M. Adsorption and desorption of carbon dioxide onto and from activated carbon at high pressures. Ind. Eng. Chem. Res. 1997, 36 (7), 2808– 2815.

interaction information. Over the years, researchers have used different EOSs, including the Peng-Robinson, Bender, and Elliot-Suresh-Donohue EOSs to provide fluid-fluid interaction information.33-36 Recently, Fitzgerald37 applied the SLD model with a modified Peng-Robinson (PR) EOS to represent precisely the high-pressure adsorption of CO2, nitrogen, meth(34) Puziy, A. M.; Herbst, A.; Poddubnaya, O. I.; Germanus, J.; Harting, P. Modeling of high-pressure adsorption using the bender equation of state. Langmuir 2003, 19 (2), 314–320. (35) Soule, A. D.; Smith, C. A.; Yang, X.; Lira, C. T. Adsorption modeling with the ESD equation of state. Langmuir 2001, 17 (10), 2950– 2957. (36) Yang, X.; Lira, C. T. Theoretical study of adsorption on activated carbon from a supercritical fluid by the SLD-ESD approach. J. Supercrit. Fluids 2006, 37 (2), 191–200. (37) Fitzgerald, J. E. Adsorption of pure and multi-component gases of importance to enhanced coalbed methane recovery: Measurements and simplified local-density modeling. Ph.D. Dissertation, Oklahoma State University, Stillwater, OK, 2005.



Figure 4. CO2 adsorption on wet and dry Illinois #6 coal at 328.2 K.

Figure 5. CO2 adsorption on wet and dry Pocahontas #3 coal at 328.2 K.

ane, ethane, and their mixtures on dry and wet coals and activated carbons. The SLD model is only briefly outlined below, but a detailed description can be found elsewhere.19 For the slit geometry, the SLD model assumes the adsorbate molecules reside within a two-surface slit, as shown in Figure 9. The distance between the slit surfaces is L, and the position of a molecule within the slit is z. The position, z, is orthogonal to the solid surface formed by carbon atoms. A number of assumptions were used in developing the SLD model:32 (1) The chemical potential at any point near the adsorbent surface is equal to the bulk phase chemical potential. (2) The chemical potential at any point above the surface is the sum of the fluid-fluid and fluid-solid interactions. (3) The attractive potential between the fluid and solid is independent of the number of molecules at and around the point. Hence, at equilibrium, the chemical potential of the fluid, µ,

is expressed as the sum of the fluid-fluid and fluid-solid potentials at a position, “z”, as follows: µ(z) ) µff(z) + µfs(z) ) µbulk

(8)

where subscript “bulk” refers to bulk fluid, “ff” refers to fluid-fluid interactions, and “fs” signifies fluid-solid interactions. The chemical potential of the bulk fluid can be expressed in terms of fugacity as µbulk ) µ0(T) + RT ln(fbulk/f0)

(9)

where subscript “0” designates the reference state and “f ” refers to fugacity. Similarly, the chemical potential from fluid-fluid interactions is µff(z) ) µ0(T) + RT ln(fff(z)/f0) where “fff(z)” is fluid fugacity at a position z.

(10)


Mohammad et al.

Figure 6. CO2 adsorption on wet and dry Upper Freeport coal at 328.2 K.

Figure 7. CO2 adsorption on wet and dry Wyodak coal at 328.2 K.

The fluid-solid interactions are accounted for through a potential energy function. As such, the fluid-solid chemical potential is given as µfs(z) ) NA[Ψfs(z) + Ψfs(L - z)]

(11)

where “NA” is Avogadro’s number, “Ψ(z)” and “Ψ(L - z)” are the fluid-solid interactions for the two surfaces of a slit of length L. Substituting eqs 9-11 into eq 8 provides the equilibrium relationship for adsorption within the slit

(

)

Ψfs(z) + Ψfs(L - z) (12) kT where k is Boltzmann’s constant. The SLD model is a simplification of the local-density theory. According to this theory, the density profile is obtained by fff(z) ) fbulk exp -

minimizing the total energy function, which depends upon all point densities and their spatial derivatives.38 The term “local” refers to the thermodynamic properties of a fluid at any local point z, where an average single density value is calculated, F(z).32 In addition, the SLD model uses mean-field theory in calculating the chemical potential. The mean-field theory replaces all interactions with an effective or average interaction, so that no fluctuations are considered within the slit. Hence, the chemical potential of the fluid at each point is corrected for the proximity of the fluid molecule to the molecular wall of the adsorbent.37 Applying the SLD model, the excess adsorption (nex) is given as (38) Henderson, D. Fundamentals of Inhomogeneous Fluids; Marcel Dekker, Inc.: New York, 1992.



Figure 8. CO2 adsorption on wet Argonne coals at 328.2 K (error bars are included for only one isotherm for clarity).

1 a(T)F P ) FRT (1 - Fb) RT[1 + (1 - √2)Fb][1 + (1 + √2)Fb] (14) where a(T) ) Figure 9. SLD model slit geometry.

b)

Table 8. Fluid Physical Properties (Hernandez et al.40 and Reid

et al.43)

nex )

A 2

right side of slit

left side of slit

(F(z) - Fbulk)dz

0.077796RTC PC

(16)

[ ( ) ( ) ( )]

304.13 7.38 0.3941 195.2 0.71369 -0.44764 2.43752

∫

(15)

The term, R(T), in eq 15 is calculated using the Mathias-Copeman expression

CO2 TC (K) PC (MPa) σff (nm) εff/k (K) C1 C2 C3

0.457535R(T)R2TC2 PC

R(T) ) 1 + C1 1 -

T + TC

C2 1 -

(13)

Here, nex is the excess adsorption of adsorbate in the number of moles per unit mass of adsorbent, and “A” is the surface area of the adsorbate on a particular solid. The lower limit in eq 13 is 3/8σff, which is 3/8 of the diameter of an adsorbed molecule touching the left plane surface. The upper limit is L - 3/8σff, the location of an adsorbed molecule touching the right plane surface. The local density is assumed to be zero for the distances less than 3/8σff away from the wall. The value 3/8σff is chosen to account for most of the adsorbed gas; details are given elsewhere by Fitzgerald.37 The left and right sides of the slit each comprise half of the total surface area, A/2. Following previous studies at Oklahoma State University,37 the PR EOS39 was used to provide the bulk fluid density and fugacity. The EOS, expressed in terms of density, is given as (39) Peng, D.-Y.; Robinson, D. B. A new two-constant equation of state. Ind. Eng. Chem. Fundam. 1976, 15 (1), 59–64.

T TC

2

+ C3 1 -

T TC

3 2

(17)

The regressed coefficients, C1-C340 and the properties for CO2 are given in Table 8. The fugacity of a bulk fluid using PR EOS is ln

fbulk bF a(T)F Pb P - ln ) P 1 - bF RT(1 + 2bF - b2F2) RTF RT

[

[

]

]

a(T) 1 + (1 + √2)Fb ln (18) 2√2bRT 1 + (1 - √2)Fb For adsorbing fluid, the fugacity for fluid-fluid interactions is ln

aads(z)F(z) fff(z) bF(z) ) P 1 - bF(z) RT(1 + 2bF(z) - b2F2(z)) aads(z) Pb P 1 + (1 + √2)F(z)b ln ln (19) RTF(z) RT 2√2bRT 1 + (1 - √2)F(z)b

[

]

[

]

The parameter “aads(z)” in eq 19 varies with the position within the slit. Chen et al.33 provided the equations for “aads(z),” which depends upon the ratio of slit length L to the molecular diameter σff. Previously, Fitzgerald14,37 adjusted the covolume “b” in the PR EOS to improve the predictive capability for adsorption of


Mohammad et al.

Table 9. SLD-PR Model Representation of CO2 Gibbs Adsorption on Dry and Wet Argonne Coals at 328.2 K dry

a

EMCa (%)

A (m2/g)

ess/k (K)

WAADb

A (m2/g)

ess/k (K)

WAAD

Illinois #6 Beulah Zap Wyodak Upper Freeport Pocahontas overall

8.0 32.2 28.1 1.1 0.7

101.61 113.25 121.33 57.10 69.95

18.41 25.41 20.73 32.32 35.22

1.06 0.84 1.63 0.64 0.77 0.99

63.56 26.72 41.78 51.97 60.59

10.89 14.65 6.48 22.46 24.83

0.64 0.25 0.19 0.60 0.44 0.42

EMC ) equilibrium moisture content. b WAAD ) weighted average absolute deviation.

pure gases on activated carbon and coals. The covolume has a significant effect on the local density of the adsorbed fluid near the surface. In addition, the covolume is important in determining the density profile at high pressures. A simple empirical correction was used to account for the repulsive interactions of adsorbed fluid at high pressures. The covolume is corrected by an adjustable parameter, Λb bads ) b(1 + Λb)

(20)

Equation 19 then becomes ln

wet

coal

badsF(z) aads(z)F(z) fff(z) ) P 1 - badsF(z) RT[1 + 2b F(z) - b

[

ln

[

ads

]

2

ads

F(z)2]

-

]

aads(z) 1 - badsF(z) 1 + (1 + √2)F(z)bads ln (21) RTF(z) 2√2badsRT 1 + (1 - √2)F(z)bads

In this work, we have used a fixed value of -0.20 for Λb of all coals. The fluid-solid interaction, Ψfs(z), was represented by Lee’s partially integrated 10-4 potential41 Ψfs(z) ) 4πFatomsεfsσfs2

(

σfs10

4 σfs4 1 5(z′)10 2 i)1 (z′ + (i - 1)σss)4

∑

)

(22) εfs ) √εffεss

(23)

where εfs is the fluid-solid interaction energy parameter and Fatoms ) 0.382 atoms/Å2. The parameters σff and σss signify, respectively, the molecular diameter of the adsorbate and the carbon interplanar distances. The value of carbon interplanar distance was taken to be the value of graphite, 0.335 nm,42 and values of σff and εff were taken from Reid et al.43 The fluid-solid molecular diameter, σfs, and dummy coordinate, z′, are defined as σfs )

σff + σss 2

(24)

σss (25) 2 For the adsorbed phase, the slit is divided into two halves and each half is subdivided into 50 intervals. The local density is then calculated by solving eqs 12 and 22 simultaneously for z′ ) z +

(40) Hernandez-Garduza, O.; Garcia-Sanchez, F.; Apam-Martinez, D.; Vazquez-Roman, R. Vapor pressures of pure compounds using the PengRobinson equation of state with three different attractive terms. Fluid Phase Equilib. 2002, 198 (2), 195–228. (41) Lee, L. L. Molecular Thermodynamics of Non-ideal Fluids; Butterworth: Stoneham, MA, 1988. (42) Subramanian, R.; Pyada, H.; Lira, C. T. Engineering model for adsorption of gases onto flat surfaces and clustering in supercritical fluids. Ind. Eng. Chem. Res. 1995, 34 (11), 3830. (43) Reid, R. C.; Prausnitz, J. M.; Poling, B. E. The Properties of Gases and Liquids; McGraw-Hill, Inc.: New York, 1987.

each interval. Once the local density is determined across the slit, the excess adsorption is calculated by integrating eq 13 numerically using Simpson’s rule. The regressions used to determine the model coefficients minimized the weighted root-mean-square (WRMS) of the predicted amounts adsorbed, where the weights were the expected experimental uncertainties. The optimized parameters included surface area “A” for each fluid and solid-solid interaction energy parameter “εss/K”. Moreover, the slit length “L” was fixed at 1.15 nm for each coal. Figures 3-7 present the SLD-PR model representations obtained for the CO2 adsorption on the five Argonne coals used in this work. Table 9 presents the regressed model parameters used to fit the CO2 adsorption data on these coals. It also lists the weighted average absolute deviation (WAAD) for each coal. On average, the SLD-PR model was capable of describing the adsorption behavior of CO2 on both dry and wet coals within the experimental uncertainties. Specifically, the overall WAAD for the five dry and wet coals was 0.99 and 0.42, respectively. Figure 8 illustrates the SLD-PR model representations on all five coals. Some error bars have been omitted in Figure 8 for the sake of clarity. As mentioned previously, the reduction in CO2 adsorption on wet coals correlates positively with the amount of moisture present in the coal. To highlight this, Figure 10 presents this correlation between the reduction in model-regressed CO2 surface areas (from wet to dry coal) and coal moisture content. As evident from Figure 10, the two quantities are correlated with a R2 value of 0.98. Table 9 also shows that the model statistics obtained on the wet coals are better than those obtained for dry coals. This artifact can be attributed to the covolume adjustable parameter, Λb. This parameter has a significant effect on the density calculations at the higher pressures, and we have found that a value of -0.20 for this parameter was suitable for modeling of both wet and dry coals. Further details of this empirical modification can be found elsewhere.19 As mentioned previously, while modeling CO2 adsorption on coals, various authors27,28,31 have applied a term to their isotherm model to account for coal swelling. The SLD model also has the capability to include a swelling index. Specifically, the SLD model parameter “slit length” can be varied with pressure (or density) to account for the change in adsorbent volume with pressure (or density). The slit length represents the effective pore width of the porous adsorbent and, consequently, affects the calculated pore volume of the adsorbent. However, in our modeling efforts on a variety of coals (see Fitzgerald et al.8,14), the SLD model was capable of precise representation of high-pressure, supercritical gas adsorption without the need for correction for swelling. Therefore, our modeling results, to date, did not justify inclusion of the swelling term to this model.



Figure 10. Effect of moisture on the model-regressed CO2 surface areas of Argonne coals.

In this study, water was treated as “pacifying” the coal matrix; i.e., water occupies part of the porous coal surface, thus limiting the accessible space for adsorbing gases, such as CO2. In actuality, the adsorption on a wet coal is less than that on a dry coal partly because water competes with CO2 for the available coal surface, impeding CO2 from accessing this surface. Moreover, while modeling of these systems with the SLD model, the effect of water is reflected in the parameters. Specifically, the model parameter “CO2 surface area” for a wet coal is considerably less than the area accessed by CO2 on the dry coal. This change reflects the effect of water on CO2 adsorption on wet coals, implicitly assuming that the water is sufficiently strongly adsorbed that it denies access by CO2 to a constant portion of the surface area throughout the pressure range of the measurements. Table 9 contains the model surface areas for CO2 adsorption on dry and wet coals. The modeling approach for wet coals that we employed in this study is, currently, the accepted approach in the literature for modeling of such systems. However, there exists a competitive adsorption mechanism between water and other adsorbing gases, such as CO2, that has not been fully addressed in the literature (to our knowledge) or in our current study. In particular, more realistic accounting for (a) interactions between water and the coal surface and (b) competitive adsorption behavior between water and other adsorbing gases are necessary for a more realistic description of coal-bed gas adsorption phenomena on wet coals. This modeling capability, however,

has not yet been fully developed and will be the subject of a future study. 5. Conclusions The adsorption of CO2 was measured on five different rank coals at 328.2 K and pressures up to 13.8 MPa using a volumetric method. The adsorption on the wet coals was lower than that on the dry coal. The adsorption isotherm for each of the wet coals exhibits a maximum between 8 and 12 MPa. The adsorption maximum on the wet coal occurs at a higher pressure than that of the dry coal. The reduction in the gas adsorbed on wet coals from that on dry coals appears to be correlated positively with the moisture content of the coal. This newly acquired adsorption data on the well-characterized Argonne coals under moist conditions should be helpful in delineating the effects of moisture on gas adsorption behavior and in developing models capable of describing water effects on gas adsorption. The SLD-PR model was found capable of representing precisely the CO2 adsorption on dry and wet coals. The overall WAAD for the five dry and wet coals was 0.99 and 0.42, respectively. However, we believe that accurate modeling of gas adsorption on wet coals must include more rigorous accounting for the (1) interactions of water with the coal matrix and (2) competitive adsorption between water and other gases. Acknowledgment. The financial support of the U.S. Department of Energy and Advanced Resources International, Inc. is gratefully acknowledged. EF800870A

Adsorption of Pure Carbon Dioxide on Wet Argonne Coals at 328.2 K

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