CO 2 STORAGE AND ENHANCED METHANE PRODUCTION: FIELD TESTING AT FENN-BIG VALLEY, ALBERTA, CANADA, WITH APPLICATION

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1 CO 2 STORAGE AND ENHANCED METHANE PRODUCTION: FIELD TESTING AT FENN-BIG VALLEY, ALBERTA, CANADA, WITH APPLICATION William D. Gunter 1, Mathew J. Mavor 2*, and John R. Robinson 1 1 Alberta Research Council Inc., Edmonton, Alberta, Canada, T6N 1E4 2 Tesseract Corporation, Park City, Utah, USA, ABSTRACT Micro-pilot field tests were performed at Fenn-Big Valley, Alberta, Canada in a four metre-thick Mannville Formation coal seam by injecting four different gas mixtures: 100% CO 2, 47% CO 2-53% N 2, 13% CO 2-87% N 2 and 100% N 2. Before injection, the well was on production for 30 days to obtain gas- and water-productivity data and produced-gas samples for composition determination. The production period was followed by a shut-in test. The pressure data collected during the shut-in period were analyzed to obtain permeability estimates before gas injection. During injection for each micro-pilot, injectivity was maintained at adequate rates (~0.5 (10 6 ) scf/d or 15(10 3 ) m 3 /D) in this low one to four md-permeability Mannville reservoir. Soak periods ranged from 30 to 60 days. Then the well was returned to production for 30 days to determine the well s productivity and composition of the produced gas. This huff and puff test was followed by a final shut-in test to obtain pressure and permeability measurements after injection. These data are being used to calibrate reservoir simulators to estimate the CO 2 storage potential and the enhanced hydrocarbon gas recovery in the design of multi-well pilots and for preliminary economic evaluations. These field tests led to the conclusion that low-permeability coal seams which may not be commercial under primary production could still be CO 2 storage sites with the added benefit of improving the possibilities for commercial gas production. INTRODUCTION The USA is producing over 28 (10 9 ) m 3 per year of CBM from more than 6,000 wells. In energy terms this is equivalent to ~38 (10 6 ) tonnes of coal or 25 (10 6 ) tonnes of oil. Experience in other countries, including Canada, has been for the most part unsuccessful, and where wells have been drilled, these have generally only produced CBM at sub-economic rates. In part, this is due to lower coal permeability. Australia and Canada are the only other countries besides the US to reach commercial production rates, although their total production is presently several orders of magnitude lower than that of the US. The use of enhanced gas recovery methods by injecting waste gas streams in coal reservoirs (ECBM) could improve both production rates and the ultimate recovery of this in-situ resource. CO 2 and/or N 2 injection are such techniques currently being tested. Underground storage of greenhouse gases is one of several possible solutions to reduce their atmospheric release [1]. Possible sites include coal beds, depleted oil and gas reservoirs, abandoned and sealed mines, salt domes, aquifers, and within natural minerals. Storage within coal seams is one of the most attractive sites due to the huge coal resources around the world and the fact that CO 2 sorption into coal is high, ranging between 1.8 [2] and ten [3] times the sorptive capacity of methane. The relative sorptive capacity of CO 2 in coal has the added advantage that injection of CO 2 into coal will displace methane. The cost of CO 2 sequestration can be offset if the methane can be captured and sold. Using the captured methane to displace coal for electricity generation can significantly reduce greenhouse gas emissions. To develop this technology for use in Canada, the Alberta Research Council (ARC) initiated a program of work entitled Sustainable Development of Coalbed Methane A Life Cycle Approach to Production of Fossil Energy to study the technical and commercial viability of ECBM using CO 2 waste streams. Funders include Canadian (both Federal and Provincial), United States, UK, Australian, Japanese and Dutch government organizations, major oil and gas companies, oil- and gas-field service companies, electric power utilities, engineering and gas supply companies. The overall program is split into four phases of which the first three have been completed. Phase I was the initial * Corresponding author: mavor@xmission.com

2 assessment and feasibility of injecting flue gases into the Mannville coals. Phase II was the design and implementation of a CO 2 micro-pilot test. Phase III was the design and implementation of mixed gas micro-pilot tests. Phase IV is the matching of CO 2 -rich sources (both existing and novel) with CBM and the design of further field tests including micro-pilots and multi-well pilots. Each phase follows four steps: (1) The Resource: To characterize the resource properties of Alberta CBM reservoirs and identify the best geological site for a multi-well pilot; (2) Enhanced Production: To assess the CBM reservoir response to injected flue gas compositional changes; (3) Reservoir Simulation Software: To improve the predictive capability of ECBM reservoir simulators; (4) Surface Facilities: To identify flue gas sources and calculate the cost of enriching the CO 2 -component of the flue gas supply and delivery to the CBM reservoir. An iterative process is used combining the data collected from these four steps to complete an economic evaluation of the CO 2 - ECBM recovery process in order to justify a commercial operation. Field testing is a critical component of this technology development and starts with micro-pilot tests and continues through multi-well and pattern testing before reaching commercial production [4]. CO 2 STORAGE/ECBM PROCESS Coal gas reservoirs are dual-storage reservoirs consisting of primary and secondary storage systems. The primary storage system makes up 98% or greater of the reservoir volume and contains organic matter, inorganic material, inherent water, and gas stored within very small pore spaces. Primary system gas storage is dominated by sorption phenomena because of the small size of the pores. During sorption, the molecules are in very close proximity to solid surfaces, are attracted to the solid, and are packed closer together than expected from the pressure conditions. The primary porosity system is relatively impermeable and mass transfer is dominated by diffusion (driven by gas concentration gradients). Commercially productive coal-gas reservoirs contain a well developed secondary storage system dominated by natural fractures. Without natural fractures, commercial production would not be possible. Flow through the secondary storage system is due to pressure gradients between the fracture system and production wells. The majority of gas in a coal gas reservoir diffuses through the primary storage system, desorbs at the interface between the primary and secondary systems, and then flows through the secondary system to wells. The CO 2 -storage/enhanced coalbed methane (ECBM) process works by replacing sorbed methane (CH 4 ) molecules in the primary storage system with the more strongly sorbed CO 2 molecules. For Mannville coals, the selectivity of CO 2 to CH 4 is greater than 2 to 1. The CH 4 molecules are displaced into the coal natural fracture system and to producing wells. The CO 2 is trapped in the primary storage system and there is little breakthrough to production wells until the majority of the well pattern is swept. Further injection of CO 2 would be carried out for storage purposes only after the cessation of production. Hence, as well as enhancing methane production, this technology acts as a CO 2 storage route [5,6]. However, further testing and demonstration is required before this process may be applied to low-permeability reservoirs found elsewhere in the world. An alternative gas for ECBM is N 2, which has a different enhanced recovery mechanism from that of CO 2. N 2 is less sorptive than methane; N 2 sorptive capacity is roughly 50% that of methane for the high volatile bituminous B Mannville coal. The N 2 process works by reducing the partial pressure of methane in the secondary system, increasing the rate of desorption from the primary system, and the rate of methane diffusion through the primary system. Some N 2 sorbs into the primary system but the majority remains in the secondary system. N 2 also increases the coal natural fracture system total pressure, increasing the driving force to push gas through the fracture system to producing wells. One significant difference between N 2 and CO 2 injection is that the N 2 breaks through to the production wells and dilutes the well stream. When N 2 production becomes excessive, the production stream must be processed to reject N 2. Figure 1 illustrates examples of simulation computations of ECBM recovery, schematically depicting the methane recovery rate for two enhanced recovery scenarios, one through injection of pure N 2, the other through injection of pure CO 2. Also shown is the expected recovery without injection (primary production). N 2 injection rapidly increases the methane production rate. The timing and magnitude depends upon the distance between injection and production wells, the natural fracture porosity and permeability, and the sorption properties. N 2 breakthrough at the production well occurs at about half the time required to reach the maximum methane production rate in this ideal case. The N 2 content of the produced gas continues to increase until it becomes

3 excessive, i.e. 50% or greater. The production increase due to CO 2 injection takes longer to develop. This is due to sorption of CO 2 relatively near the well with the sorbed CO 2 -methane front growing elliptically out from the injection wells. After a sufficient volume of methane has been displaced (roughly 20% of the reservoir volume), the methane productivity increases. Eventually, CO 2 will break through to the production well when sufficient CO 2 has been injected. At breakthrough, in the ideal case, 70% of the reservoir has been swept and the project is terminated. Figure 1: Primary and enhanced recovery methane production rates (after [7]). Burlington Resources Inc. performed a CO 2 storage/ecbm pilot in Fruitland coal seams in New Mexico. The pilot consisted of four CO 2 injection wells drilled between production wells. They injected 98% CO 2 and 2% N 2 for a period of roughly three years at a total rate of between 105,000 and 181,000 m 3 /D. CO 2 breakthrough was negligible but N 2 breakthrough was observed after 3 months as expected from theory. BP-Amoco has been successful at improving hydrocarbon gas recovery with N 2 injection. Injection of N 2 rapidly improved the hydrocarbon gas production rate by a factor of five at their Fruitland coal Simon pilot site in the northwestern portion of the San Juan Basin in Colorado, but N 2 breakthrough was rapid. In the absence of government incentives, the storage/ecbm process must be commercially attractive to interest investors for the large funding required for well facilities and flue-gas collection systems. The source of the injected gases will be flue-gas emissions from power plants (±13% CO 2, ±84% N 2, ±3% others), fertilizer plants, hydrogen plants, or gas-treatment plant byproducts (CO 2 and mixtures of CO 2 and H 2 S). Flue-gas injection may enhance the process economics to the point that large-scale commercial application is possible. Compared to pure CO 2, flue-gas injection requires a higher amount of compression for injecting the same unit of gas down hole. One important component of the process design will be efficient compressors that minimize the volume of CO 2 created relative to the CO 2 injected. This design must also incorporate the economics of pre-treating the flue gas to increase CO 2 concentration and to reject the nitrogen from produced methane. The optimum mix of N 2 and CO 2 in the injection gas depends upon the technical and commercial requirements of the process. If storage volume is the only consideration, the injected gas should be 100% CO 2. If rapid maximization of hydrocarbon gas recovery is the only consideration, the injected gas should be 100% N 2. The commercial and sequestration compromise will be between these two cases. We expect that the optimum commercial application will involve injecting variable gas composition to control storage volumes and the amount of N 2 in the produced gas stream. The range of the N 2 content in the injected gas is likely to be between 25% and 75%. While a storage/ecbm project is theoretically possible, it is necessary to install the project in a phased approach to reduce the chance of geologic, engineering, or economic failure. The costs of a full-field development effort are front-end loaded and result in significant financial risk for the funding parties. Micro-piloting is a first stage in field development once the CBM reservoir is geologically characterized [7].

4 RESOURCE CHARACTERIZATION Potential CBM reservoirs exist throughout the Alberta portion of the Western Canadian Sedimentary Basin, extending from north of Edmonton southwards to the US border. Coals occur in strata ranging in age from Tertiary to Lower Cretaceous, and encompass a stratigraphic interval exceeding 2,500 m in thickness. Coal-bearing strata dip westward, such that stratigraphically shallower coals crop out in the eastern part of the Alberta Plains, but occur increasingly deeper towards the west. Coal seam quality, rank, gas generation potential, permeability and storage potential changes laterally and with increasing depth across the basin. The major coal-bearing formations are in the Mannville Group (Lower Cretaceous), Belly River Formation (Upper Cretaceous), Horseshoe Canyon Formation (Upper Cretaceous), and Scollard Formation (Upper Cretaceous to Paleocene). The coals in the Belly River and Horseshoe Canyon are thin and discontinuous while the coals of the Mannville (Medicine River coals) and Scollard (Ardley coals) are thick and continuous. CBM geological studies at specific sites for the Ardley, Horseshoe Canyon and Mannville coals have been completed. Evaluation wells have been drilled in the deep Mannville (1,300 m), the shallow Ardley (400 to 600 m) and the Horseshoe Canyon (300 m) coal intervals. Core samples were collected and degassed under controlled conditions to estimate gas content. The wells were logged and sorption isotherms were measured on crushed core for CH 4, CO 2 and N 2. In-situ flow-pressure tests were used to estimate permeability. Thick sections of coals were encountered, exceeding three metres in all of the wells. In general, the shallower coals have higher permeability but lower gas contents compared to the deeper Mannville coal. Permeability ranged 100-fold from 0.1 to 10 md. For CO 2 storage, the shallower coals reservoirs are appealing because of the lower drilling costs and the lower compression required to inject CO 2. However, the first ECBM field tests were done in the deeper Mannville coals due to the availability of an existing CBM well. MICRO-PILOT TESTING Micro-pilot tests were carried out on two wells in the Mannville at Fenn-Big Valley using a huff and puff scheme. The Fenn-Big Valley site was chosen because of previous work done by Gulf Canada: the reservoir properties were known, the productivity was in the range of a BP-Amoco ECBM micro-pilot, the permeability level is common in Alberta and the area contains a huge resource of CBM if enhanced recovery is significant. The total Mannville coal thickness in two seams was metres. The coal was gas saturated and the CBM gas-in-place volume was estimated to be 106(10 6 ) m 3 /km 2 or 9.7(10 9 ) scf/mi 2. The CO 2 storage capacity is approximately 0.4(10 6 ) tonnes/km 2 or 10 6 tons/mi 2. These volumes of CBM are commercial if high enough production rates can be achieved. The huff and puff scheme involved two micro-pilot tests performed in each of two wells. The first well was tested with pure CO 2 and, a year later, with flue gas (13% CO 2, 87% N 2 ). The second well was tested with pure N 2 and, a month later, with synthetic flue gas (47% CO 2 and 53% N 2 ). Each test consisted of an injection, a soak and a production period (i.e. huff and puff) into/from a single well test using a fixed flue-gas composition. Detailed descriptions of each test are reported in [8]. The data collected from each micro-pilot were history matched with numerical reservoir simulators. A spreadsheet model was developed to evaluate the cost of different options for securing various CO 2 -enrichred compositions from waste flue-gas streams to be supplied as injection-gas streams to the ECBM site. An old well, FBV 4A, had previously been recompleted in the Mannville coals and produced by primary methods by Gulf Canada and was used for the first micro-pilot test of pure CO 2 injection. The test sequence is illustrated in Figure 2. The well was produced on primary followed by a build-up test to estimate permeability (4 md). This was followed by a CO 2 injectivity/fall-off test using a 12 tonne slug of liquid CO 2 to ensure that we could inject under fracturing pressure. A short production period followed. As this test was successful, it allowed the testing program to continue for a prolonged injection of twelve 15 tonne slugs of CO 2. Permeability and injectivity changes were calculated after the addition of each slug. The permeability changes are shown in Figure 3. Injectivity and pressure differential versus the CO 2 injection volume for the pure CO 2 micro-pilot are shown in Figure 4 for each of the 12 CO 2 injection periods. The pressure differential required for each injection period decreased by roughly 55% over the 12 injection periods from 6,100 kpa to 2,700 kpa. Injectivity increased from 5.5 m 3 /D-kPa for the first injection

5 period to 13.6 m 3 /D-kPa for the final injection period, an increase of 147%. This was followed by a long soak period before the final production test. These tests were promising and it was decided to drill a new well. Figure 2: FBV 4A CO 2 micro-pilot test. Figure 3: FBV 4A permeability changes (after [8]). Figure 4: FBV 4A CO 2 injectivity (after [8]). Our explanation for the unexpected relatively high injectivity follows. When injecting gas, two competing processes affect both the absolute permeability and the relative permeability to gas [9,10]. The increase in pressure during injection balloons natural fractures and increases porosity, relative permeability to gas, and absolute permeability. Also during injection, adsorption of CO 2 tends to swell the coal matrix which reduces natural fracture porosity and absolute permeability offsetting the gain in permeability. The gain in permeability due to the injection pressures was substantially greater than the loss due to swelling during injection. After injection, during shut-in periods or subsequent production, the swelling effects reduce the permeability to levels below the original permeability. A new well (FBV 5) was drilled 493 metres north of the existing FBV 4A well. The FBV 5 well was placed on production for 30 days with artificial lift as necessary to obtain gas and water productivity data and produced gas samples for composition determination. The production period was followed by a shut-in test. The pressure data collected during the shut-in period were used to obtain permeability estimates prior to flue-gas injection. Figure 5 illustrates the pressure history for the various micro-pilot tests carried out in the new well. At first, several water-injection tests were used to determine the absolute primary permeability (1 md). The first micro-pilot in the new well was a 100% liquid N 2 injection with an oxygen tracer. The oxygen was used to determine that the test was confined to the coal reservoir and was added in small amounts [11]. After N 2 injection, a fall-off test (soak period) was completed followed by a production period. The well was then shut in before the second micro-pilot injection was started. The second micro-pilot was an equal mixture of liquid CO 2 and liquid N 2 and followed the same steps as the N 2 micro-pilot. Details of the test sequence are found in Reference [8].

6 The fourth micro-pilot was conducted by injecting the flue gas, which contained 13% CO 2, off an under-balanced drilling compressor. It was conducted in the old recompleted well after over a year soak of the first 100% CO 2 micro-pilot. As illustrated by Figure 6, after a short production period, approximately 200 tonnes of flue gas were injected followed by a soak and a production test. Details of the test sequence are recorded in [8]. Figure 5: FBV 5 N 2 and N 2 CO 2 micro-pilots. Figure 6: FBV 4A flue gas micro-pilot. In summary, for each micro-pilot, injectivity was maintained at adequate rates (~0.5 (10 6 ) scf/d or 15 (10 3 ) m 3 /D ) in this low-permeability Mannville reservoir. Soak periods ranged from 30 to 60 days. Then the wells were returned to production for 30 days to determine each well s productivity and produced-gas composition. This huff and puff test was followed by a final shut-in test to obtain pressure and permeability measurements after injection. These data sets are being used to calibrate reservoir simulators to estimate the CO 2 storage potential and the enhanced hydrocarbon gas recovery in the design of the multi-well pilot. SOFTWARE ASSESSMENT Initially, five simulation software products were tested to assess their potential for modelling the ECBM process. All five were found to be adequate for predicting primary production of CBM. Only four products were suitable for modelling enhanced CBM production using N 2 or CO 2 injection, and only three were suitable for modelling flue gas injection. All four micro-pilots have been matched in pressure and flow-rate performances. However, the reservoir simulation products, in their current forms, were not capable of accurately predicting the produced-gas compositions observed during the field tests [12]. Improved understanding of the process mechanisms (e.g. mixed gas sorption on the micropore surfaces, mixed gas diffusion into/out of the coal matrix, coal matrix swelling and shrinkage due to sorption of gases and changes in effective stress, and water movement between the coal matrix and cleats) is needed to guide the future development of simulation models. After initial improvements to the simulators, most of the tested models have been successful in history matching the compositional data collected in the pure CO 2 micro-pilot injection test by using a dynamic permeability function and by varying relative diffusion rates of the gaseous components between the coal matrix and the cleats [13]. Further improvements to these models will be required to successfully match all the micro-pilot data. The final strategy will be to use the history match of one micro-pilot to predict another micro-pilot s performance, followed by predicting the performance of the multi-well pilot at the chosen site. SURFACE FACILITIES A flow process was designed for a representative commercial project that determined mass and energy balances for the overall surface facilities that are being considered for the injection-gas source for a commercial ECBM project. Capital and operating costs are estimated based on the flow process. Using these data, a spreadsheet model was developed [14] to be used as the basis for an economic evaluation. A beta version of the model has been completed and is currently being evaluated. The model has the capability to handle feed-gas compositions ranging from representative flue gas (e.g. 12% CO 2, 88%N 2 ) to 98% CO 2 based on solvent technology for capturing CO 2 ; to assess other processing alternatives; and to be used for the non-commercial demonstration pilot phase as well. Work is in progress to enhance the model and to collect data for the purpose of evaluating other capture technologies.

7 ECONOMICS From an economic perspective based on the spreadsheet model, flue gas injection offered better performance than pure CO 2 injection (ignoring the possibility of a CO 2 credit/trading system). Typically, it takes two to three molecules of CO 2 injected per molecule of methane produced for the Mannville coals. Assuming that the cost of CO 2 is US$ 1/Mscf, this cost corresponds to a cost of US $2 to 3/Mscf of produced CBM for the injected CO 2, which until recently was close to the wellhead price of natural gas without even considering well drilling, surfacefacility and production operating costs. An alternative is to use flue-gas streams, a mixture of CO 2 and N 2, as an injectant. Compared to CO 2, little of the N 2 is retained in the CBM reservoir. Typically for pure N 2, only 0.5 molecules of N 2 are retained for each molecule of methane produced, and methane production is enhanced more quickly than for CO 2 injection. However, N 2 breakthrough at production wells also occurs quickly, necessitating an extra processing step to separate N 2 from the produced process stream [15] prior to sale. An economic analysis of a commercial operation in the Mannville coals was made using production curves similar to those in Figure 1 based on the field-test parameters to calculate the wellhead CBM price required for the project to break even [16,17]. Injection of a typical flue gas from a coal-fired power plant (i.e. 87%N 2 and 13%CO 2 ) was compared to injection of pure CO 2 purchased at a price of US $1/Msf. The production economics suggest that flue gas-ecbm is more economical than CO 2 -ECBM, requiring only a wellhead price of US $1.58 to break even compared to US $2.89 for CO 2 -ECBM where two molecules of CO 2 are stored in the CBM reservoir for every molecule of CBM produced. However, this has to be balanced against the fact that it may be advantageous, both environmentally and economically, to store CO 2 in geological formations in the future. DISCUSSION The greater CO 2 injectivity may have been caused by a permeability increase during injection due to ballooning of the fractures. While a decrease in permeability was observed for the falloff periods after injection ceased as shown in Figure 3, permeability while injecting was greater than during the falloff periods after injection. Unfortunately, we were unable to obtain accurate permeability estimates during injection. Weakening of the coal matrix by CO 2 may have caused greater ballooning of the natural fracture system (resulting in greater permeability during injection) than possible with the other gases. CO 2 was injected in alternating injection-falloff periods. We believe that the alternating sequence improved injectivity and we received a patent for this process [10]. The improved injectivity may have been the result of coal failure resulting from weakening by CO 2. The shut-in periods resulted in more weakening that may have been possible without shut-in periods. In flue gas injection, the CO 2 will remain adsorbed in the coal, while the majority of the N 2 injected will be produced along with the hydrocarbons. Initially, most of the CBM is adsorbed onto the micropore surfaces in the coal matrix. Enhanced production is influenced by two different mechanisms. By introduction of a lower adsorbing gas such as N 2 to the CBM reservoir, the partial pressure of methane is reduced in the cleat system and methane desorbs from the coal matrix diffusing into the cleat system. By the introduction of a higher adsorbing gas such as CO 2 to the coalbed methane reservoir, the methane is directly displaced from the coal matrix into the cleat system. Production rate depends on the injection pressure, the efficiency of movement of the CBM from the adsorbed state in the coal matrix into the cleat or fracture system of the coal, and the permeability of the cleats, the pathway to the wellbore. Technical issues that will have to be addressed in the next phase of development are flue gas conditioning, compression and delivery, and also methane / nitrogen separation. Flue gas injection appears to enhance methane production to a greater degree than possible with CO 2 alone, while still trapping the CO 2 in the reservoir. Based on numerical simulations, flue gas injection will increase the methane production rate to more than four times the primary production rate within one year of injection for the Upper Mannville coals. However, break-through of N 2 will have occurred. Enhancement is lower with pure CO 2 but break-through of CO 2 does not occur for many years after most of the methane has been displaced.

8 SUMMARY We conducted an extensive testing program on two wells completed in Medicine River Coal seams in the Alberta Plains region. By sequential injection, soak, and production tests, along with accurate bottom-hole pressure and produced-gas composition monitoring, we were able to increase our understanding of the enhanced coalbed methane - CO 2 storage process. The detailed data resulted in conclusions that were opposite to general beliefs before the project started. It was generally thought that CO 2 injection would be hindered by coal swelling caused by CO 2 sorption. We found the opposite to be the case as CO 2 injectivity was greater through the use of alternating injection shut-in sequences and perhaps as a result of coal weakening. It was also thought that any injection into a coal seam with one md permeability would be difficult. We found that injection increased the absolute permeability and effective permeability to gas to a level that allowed easy injection. We have also found the data to be very useful to investigators who are developing reservoir simulation software to model primary and enhanced recovery from coal seams. These data can serve as history-matching files to test the accuracy of the modelling methods. The calibration of the numerical simulators using these field data have allowed predictions to be made on commercial opportunities for CO 2 storage-ecbm production for Mannville coals. The combination of these three observations suggests that low-permeability coal seams that may not be commercial under primary production could still be CO 2 -storage sites with the added benefit of improving the possibility for commercial gas production. ACKNOWLEDGEMENTS Many of the procedures and applications discussed here were previously developed during Consortium funded work at Fenn-Big Valley and were reported in an IEA report evaluating the potential for CO 2 storage/ecbm pilots in China, Australia, India, and Poland. REFERENCES 1. Gunter, W.D., S. Wong, D.B. Cheel, and G. Sjostrom Large CO 2 sinks: Their role in the mitigation of greenhouse gases from an international, national (Canadian) and provincial (Alberta) perspective. Applied Energy, Vol. 61: Yee, D., J.P. Seidle and W.B. Hanson Gas sorption on coal and measurement of gas content. In: Law. B.E. and D.D. Rice (eds.): Hydrocarbons from Coal, AAPG Studies in Geology #38, American Association of Petroleum Geologists, Tulsa, Oklahoma: Mavor, M., T. Pratt, and R. DeBruyn Study quantifies Powder River coal seam properties. Oil and Gas Journal, Vol. 97, No. 17, (April 26, 1999): Mavor, M.J., W.D. Gunter, J.R. Robinson, D.H.-S. Law, and J. Gale Testing for CO 2 sequestration and enhanced methane production from coal. SPE Paper 75680, presented at the SPE Gas Technology Symposium, May 30-April 2, Calgary, 14 p. 5. Gunter, W.D., T. Gentzis, B.A. Rottenfusser, and R.J.H. Richardson Deep coalbed methane in Alberta, Canada: A fuel resource with the potential of zero greenhouse gas emissions. Energy Conversion and Management, Vol. 38S: S217-S Wong, S., C. Foy, W.D. Gunter, and T. Jack Injection of CO 2 for enhanced energy recovery: Coalbed methane versus oil recovery. In: Eliasson, B., P.W.F. Riemer and A. Wokaun (eds.): Proceedings of the 4 th International Conference on Greenhouse Gas Control Technologies, Elsevier Science Ltd., Oxford International Energy Agency Greenhouse Gas R&D Programme Enhanced Recovery of Coalbed Methane with Carbon Dioxide Sequestration Selection of Possible Demonstration Sites. International Energy Agency Greenhouse Gas R&D Programme Report Number PH3/34, 178p. 8. Mavor, M.J., W.D. Gunter, and J.R. Robinson Alberta multiwell micro-pilot testing for CBM properties, enhanced methane recovery and CO 2 storage potential. SPE Paper 90256, SPE Annual Tech. Conf., Houston, TX (Sept , 2004).

9 9. Mavor, M.J. and W.D. Gunter Secondary porosity and permeability of coal vs. gas composition and pressure. SPE Paper 90255, SPE Annual Tech. Conf., Houston, TX (Sept , 2004). 10. Gunter, W.D., M.J. Mavor, and D.H-S. Law Process for Recovering Methane and/or Sequestering Fluids, United States Patent 6,412,559 (July 2, 2002). 11. Puri, R., R. Volz, and D. Duhrkopf A micro-pilot approach to coalbed methane reservoir assessment. In: Proceedings Intergas 95, The University of Alabama, Tuscaloosa (May 14-20, 1995), Paper 9556, Law, D.H.-S., L.G.H. van der Meer, M.J. Mavor, and W.D. Gunter Modelling of carbon dioxide sequestration in coal beds: A numerical challenge. In: Williams, D., B. Durie, P. McMullan, C. Paulson, and A. Smith (eds.): Proceedings of the 5 th International Conference on Greenhouse Gas Control Technologies, Cairns, Australia, CSIRO Publishing: Law, D.H.-S., L.G.H van der Meer, and W.D. Gunter Comparison of numerical simulators for greenhouse gas sequestration in coalbeds, part IV: History match of field micro-pilot data. In: Proceedings of the 7 th International Conference on Greenhouse Gas Control Technologies, Volume 2, Poster, Vancouver, BC, September 5-9, Macdonald, D., S. Wong, W.D. Gunter, R. Nelson, and W. Reynan Surface facilities computer model: An evaluation tool for enhanced coalbed methane. In: Gale, J. and Y. Kaya (eds.): Proceedings of the 6 th International Conference on Greenhouse Gas Control Technologies, Pergamon: Ivory, J., W.D. Gunter, D.H.-S. Law, S. Wong, and X. Feng Recovery of CO 2 from flue gas, CO 2 sequestration, and methane production from coalbed methane reservoirs. In: Proceedings of the International Symposium on Ecomaterials, Ottawa, August 20-23, 2000: Wong, S., W.D. Gunter, D.H.-S. Law, and M.J. Mavor Flue gas injection and CO 2 sequestration in coalbed methane reservoirs: economic considerations. In: Williams, D., B. Durie, P. McMullan, C. Paulson, and A. Smith (eds.): Proceedings of the 5 th International Conference on Greenhouse Gas Control Technologies, Cairns, Australia, CSIRO Publishing: Wong, S., W.D. Gunter, and M.J. Mavor, Economics of CO 2 sequestration in coalbed methane reservoirs. In: Proceedings of SPE/CERI Gas Technology Symposium 2000, SPE 59785, April 3-5, Calgary, Alberta: