Because today's oil and gas industry recognizes the value of coalbed methane (CBM) resources, CBM exploration and development activities, once uniquely North American, are now under way on a global scale. Many publications address technically recoverable resources (TRR) of CBM in small geographic areas. However, there is little publicly information about the magnitude of TRR for coalbed methane on a global scale. Uncertainty exists in geologic and engineering data and, consequently, in the results of calculations made with these data. The uncertainty of the problem begs for a probabilistic solution. Our objective was to determine distribution of CBM TRR worldwide. To achieve this goal, we developed a computer program, called Unconventional Gas Resource Assessment System (UGRAS). The program integrates a Monte Carlo technique with an analytical reservoir simulator. The combination provides an excellent means to predict production profiles for a wide variety of reservoir characteristics and producing conditions. Using UGRAS, we established the probabilistic distribution of original gas-in-place (OGIP), TRR and recovery factor (RF) for selected coals in U.S. and derived a representative recovery factor distribution for CBM reservoirs. CBM recovery factors follow a log-logistic distribution, with a P50 of 38%. We extended the distribution of gas recovery factors gained from our analyses of U.S. coals to estimate global CBM TRR. Global technically recoverable CBM is estimated to be 500 (P90) to 3,000 (P10) Tcf, with a P50 value of 1,600 Tcf. UGRAS is a robust tool that may be used to evaluate and rank coalbed methane gas resources worldwide. Results of this work verify the existence of significant technically recoverable coalbed methane resources worldwide and can guide industry to better target its exploitation efforts in coals, worldwide.

Coalbed methane (CBM) produced from subsurface coal deposits, has been produced commercially now for over 30 years in North America, and relatively recently in Australia, China and India. Historical challenges to predicting CBM well performance and long-term production have included: accurate estimation of gas-in-place (including quantification of in-situ adsorbed gas storage); estimation of initial fluid saturations (in saturated reservoirs) and mobile-water-in-place, estimation of the degree of under-saturation (undersaturated coals produce mainly water above desorption pressure); estimation of initial absolute permeability (system); selection of appropriate relative permeability curves; estimation of absolute permeability changes as a function of depletion; prediction of produced gas composition changes as a function of depletion; accounting for multi-layer behavior, and accurate prediction of cavity or hydraulic fracture properties. These challenges have primarily been a result of the unique reservoir properties of CBM. Much progress has been made in the past decade to evaluate fundamental properties of coal reservoirs, but there is still work to be done to obtain accurate estimates of some basic reservoir properties. In recent years, horizontal wells and more complex well architectures and stimulation methodologies have been implemented to improve recovery of CBM. These more complex development options bring with them a new set of challenges for operators producing CBM. The exploitation of more geologically-complex coal with poorer reservoir quality will necessitate new and inventive ways to develop the existing natural gas resources and possibly combine this with new methods to extract energy from the coal in-situ. Development planning in these scenarios will become increasingly complex as will evaluation methods. The purpose of the current work is to review the state-of-the-art in CBM reservoir property and stimulation efficiency evaluation and speculate on possible CBM development scenarios for the future and the technical challenges they will bring. Current and future work required to meet these challenges will be discussed in the hope that industry, academia, and government bodies alike will be proactive in the development of solutions that will make future CBM recovery efficient, economic, and environmentally friendly.

Abstract A significant challenge for Coal Bed Methane producers is dealing with the impacts of high density development needed to effectively recover the natural gas resource. One such concern is the need to meet regulatory requirements for environmental noise as stated in the Energy Resources Conservation Board (ERCB) Directive 038: Noise Control ( ERCB Directive 038 ) and Colorado Oil and Gas Conservation Commission (COGC) Aesthetic& Noise Control Regulations, Series 800 (COGCC Noise Regulations) . Anyone who has ever been involved in the process of complying with regulatory noise standards will agree that it is a complex and challenging task. Some regulated companies struggle through this process often dealing with unfamiliar considerations such as trying to predict facility noise levels before it is even built, or gambling on a best guess as to what is the right, least expensive amount of noise mitigation needed to meet regulatory requirements for environmental and occupational noise. Even the best of intentioned operators fail to hit the mark, sometimes by wide margins and end up with a situation that is potentially worse than when they started. No company wants to go through a process where in the end a lot of time, resources, and public confidence have been lost not to mention now being in a regulatory non-compliant status. This paper will elucidate valuable lessons & experience learned and case histories for the successful approach to noise solutions accepted by regulatory agencies and industry clients. In addition to discussing the complexities of acoustical engineering practices this presentation will also cover the most significant points of ERCB Directive 038 and COGCC Noise Regulations . Introduction The energy needs of North America are continuing to grow nearly exponentially and the desire to have clean energy options makes natural gas an obvious contender. Considering the maturity of conventional gas reservoirs in the Western Canadian Sedimentary Basin (WCSB) and Western United States, the most significant new source of natural gas are unconventional deposits found primarily in coal or shale seams. In the first few years of the new millennium, the base price of natural gas had been very low on the belief that there was an oversupply in the marketplace and incentives were towards renewable energy sources (NEB 2003). Although crude oil prices were rising dramatically, natural gas was not tracking this increase leading to a decline in exploration and replacement of reserves. Change started to occur slowly largely on the hypothesis that carbon dioxide (CO 2 ) from the burning of fossil fuels was the sole driver in climate change (IPCC, 2007) despite the steadily growing volume of peer reviewed scientific literature demonstrating that CO2 is an extremely minor forcing at best (2 - 37). Yet, this anthropogenic caused global warming view dominated in the media coverage and has for a time molded the development of government policy toward the reduction of CO 2 and indeed its reclassification as a pollutant. Regardless, it is becoming increasingly clear that unless we intend to return to the dark ages, North America's energy must come from some non-renewable source given the limited production capabilities of the so called renewable options such as wind and solar. Deep conventional gas reservoirs can only deliver limited supplies and new pool finds that can satisfy the demand are not likely to be discovered in the continental basin. Hence the move to coal bed methane, a readily available source of clean natural gas that can go a long way to meeting the energy demands of North America. However, for coal bed methane to reach its potential operators must find innovative ways to overcome the growing concerns of nearby communities.

Abstract This paper presents results of a simulation study designed to evaluate the applicability of Arps' [1945] decline curve methodology for assessing reserves in coalbed methane reservoirs . We simulated various coal properties and well/operational conditions to determine their impact on the production decline behavior as quantified by the Arps decline curve exponent, b . We then evaluated the simulated production with Arps' rate-time equations at specific time periods during the well's production decline period and compared estimated reserves to the "true" value ( defined in this paper as the 30 -year cumulative production volume ). To satisfy requirements for using Arps' models, all simulations were conducted using a constant bottomhole flowing pressure condition in the wellbore. The significant results from our study include: All of the computed values of the long-term decline exponents were within the limits originally defined by Arps, i.e ., 0.0 < b < 1.0. Agreement between Arps' recommended b -exponent range and our results using simulated performance data also suggests that, if applied under the correct conditions, the Arps rate-time models are appropriate for assessing reserves in coalbed methane reservoirs; The Arps b -exponents were not constant during the production decline period. For many simulated cases, the early decline behavior (within a few years after reaching the peak production rate) appeared to have exponential decline but eventually became more hyperbolic later in the well's life. Use of Arps' exponential model early in the production history in those wells with long-term hyperbolic decline behavior tended to underestimate gas reserves; The largest reserve estimate errors typically occurred during the first few years after reaching the peak production rate and during the initial production decline period. For those wells exhibiting long-term hyperbolic behavior, the initial reserve estimate errors underestimated reserves by as much as 20 to 30 percent; Heterogeneities in coal properties cause the production declines to deviate from exponential to hyperbolic. Properties having the largest impact on the production decline behavior include the shape of the adsorption isotherm, cleat permeability anisotropies, the shape of cleat gas-water relative permeability curves, stress-dependent cleat permeability and porosity, and layered coal seams with differences in initial reservoir pressures; We also observed a strong influence of well flowing pressure conditions as modeled with a bottomhole flowing pressure constraint. For all other properties and conditions being equal, wells with lower bottomhole flowing pressures exhibited more long-term hyperbolic behavior as defined by higher Arps b -exponents. Introduction Unconventional natural gas resources — tight gas sands, naturally-fractured gas shales, coalbed methane, and deep basin-centered gas systems — comprise a significant percentage of our domestic natural gas resource base identified to date and represent an important source for future natural gas production and reserve growth. According to Kawata and Fujita [2001], the coalbed methane (CBM) resource-in-place in North America is estimated to total more than 3,000 Tcf. While the resource base is large, the unique gas storage and flow properties characteristic of CBM reservoirs make efficient and effective gas recovery technically difficult. Of the total resource in place, the total technically recoverable gas is estimated to be 98 Tcf.

Abstract Nitrogen coiled tubing fracturing is the predominant method for completing and stimulating dry coalbed methane (CBM) formations, such as the Horseshoe Canyon in the Western Canadian Sedimentary basin. A typical well has an average of 20 pay zones that are stimulated individually. The coal cleats are fractured by pumping nitrogen at high rates through coiled tubing (CT) into perforations isolated by straddle assembly. Currently energy that can be delivered to the coalface of these dry CBM wells has been limited by the friction pressure through (CT). Efforts to increase the energy have involved increasing CT size and increasing surface horsepower. Economics and logistics practically limit the pipe size to 2 7/8 in. for deeper wells and 3¼ in. for shallow wells using CT fracturing technique. This paper discusses the development of a technique which initially eliminates the CT friction limits on transferring energy to coalface. A large-volume pressure pulse is released downhole during the fracturing process to create an order of magnitude change in available energy at the fracture face, compared to current dynamic fracturing processes. The additional energy is dissipated by increasing the surface cleat area exposed. The development of the technique and field tests results will be discussed. Introduction The Horseshoe canyon dry coal formations have been commercially exploited since late 2000. From the beginning it was clear the Horseshoe Canyon CBM play was a unique CBM play, it is set apart by consisting of a dry under pressured coal. The coal therefore does not require dewatering before production. The coal consists of multiple thin seams, ranging from 10 - 30 seams per well. The coal seam thickness ranges lies between 0.1 and 2.5 meters. ( Fig 1 - Horseshoe Canyon CBM log) The production rates from these CBM wells dictates that a efficient drilling and completion model be adopted in order to be economic. The current model that is utilized is the wells are drilled with coiled tubing drilling rigs, cased and cemented. Wireline perforating crews are then dispatched to perforate the zones of interest in a rig less operation. The individual coal seams are then stimulated via the injection of dry nitrogen at high rates through a coiled tubing reel that is equipped with a fracturing isolation tool. The dry coal has not responded well to any other form of stimulation. The lack of success of more traditional stimulation methods is deemed to be damage to the dry under pressured coal seams.

ABSTRACT A number of laboratory studies on coalbed methane (CBM) have provided data for the relative permeability of coal to gas and water, which are needed to analyze CBM reservoirs, particularly in numerical simulation. The relative permeability curves of coal to gas and water are determined using the two methods used in the petroleum reservoir engineering, namely, the steady or unsteady state displacement methods. In most cases, the unsteady state displacement method is used because this method is relatively fast to carry out. In this method, the non-wetting fluid is displaced by the wetting fluid, and the effluent production and pressure history are used to back out the relative permeability of coal to gas and water. One of the problems encountered in the displacement methods is the question of coal wettability. Many researchers studying this area have considered that coal is water-wet. However, it is a well-known fact that a large amount as much as 95% of methane is adsorbed on the internal surface of coal matrix. Therefore, coal could be regarded at least as initially gas-wet. The wettability of coal will depend on the flow characteristics of coal, that is, whether methane flows in the matrix. This paper investigates a number of wettability of coal scenarios and discusses the approaches used by various investigators, for instance, pre-heating the coal sample before any testing, and using a non-adsorbable gas, pointing out their limitations from the viewpoint of CBM reservoir simulation. The likely dependence of relative permeability of coal on flow pressure is also addressed. INTRODUCTION The earliest studies in numerical simulation of CBM date back to 1970's (Price and Abdalla, 1972). At the time, the principal objective was degasification of coal seams for mine safety to keep coal mining safe from explosions rather than CBM production to use as an unconventional gas resource. Since then, there has been continued research in CBM simulation as most of the simulators used for CBM production were often based on conventional (sandstone) reservoir models that have been modified to accommodate coal properties. In recent years, advanced simulators that are specific to CBM reservoirs have been developed to incorporate CBM reservoir parameters such as the relative permeability, which controls the well and the reservoir performance. The objective of this paper is to examine the past relative permeability measurement studies and identify problems posed by coal compared to typical reservoir rocks such as sandstone and carbonates. WHAT IS COALBED METHANE? Coal is "the black rock that burns" (Land and Rice, 1993). It is defined as a readily combustible rock that contains more than 50% by weight and more than 70% by volume of carbonaceous material including inherent moisture formed by compaction and induration (hardening of sediment) of various altered plant remains. The type of plant materials, degree of metamorphism, and the range of impurity characterize coal (Bates and Jackson, 1980). A coal seam is a bed of coal, and the natural gas or methane produced from coal seams is referred to as coalbed methane (CBM).

Abstract There is concern within some factions of the energy industry about an approaching energy crisis. In the case of hydrocarbons, eventually there will be a maximum peak in global production. The question is if it will occur sooner or later, and if it will happen because of depletion or because of substitution to other energy sources - perhaps unconventional or non-fossil. This does not preclude hydrocarbon shortages that might still occur due to temporary factors such as political instability and lack of investment. Although the past is not always an indication of the future, an analysis of global market shares (i.e. the mix) for solids, liquids and gases from the year 1850 to 2005, leads to a model that permits a reasonable forecast of the global possibilities of future methane and hydrogen economies. It is concluded that if there is a supply problem in the future it will not be the result of depletion, but rather the failure of society to invest in the research and development of technology needed to provide conventional and unconventional hydrocarbons, as well as alternatives such as hydrogen, on a timely basis. Proper development of these resources will lead to sustainable and efficient global economic growth. Introduction Jules Verne (1828–1905), the father of science fiction, wrote several books using ideas that eventually became reality. Some examples include: "From the Earth to the Moon" in 1866, "Twenty Thousand Leagues Under the Sea" in 1870 where he envisions submarines, "Robur the Conqueror" in 1886 where he describes the precursor of helicopters, and "The Mysterious Island" in 1875 where he wrote: Yes, my friends, I believe that water will one day be employed as fuel, that hydrogen and oxygen which constitute it, used singly or together, will furnish an inexhaustible source of heat and light, of an intensity of which coal is not capable." Vaitheeswaran (2003) asks "could the man who forecast the development of such technological marvels as submarines, helicopters, and space travel have gotten energy right too?" We believe that the answer is most likely positive, as discussed in this paper. Hydrogen accounts for approximately 75% of the universe's mass and is the most abundant of all elements. Stars are made mainly of hydrogen. However, hydrogen does not generally exist in a free state in earth. Consequently, it has to be extracted from different materials including, for example, biomass, fossil fuels and water. This means that it takes energy to free hydrogen for use, no matter how it is produced. As a result, hydrogen is not strictly an energy source but an energy carrier much in the same way as electricity.

Abstract Material balance analysis is a fundamental technique for estimating gas-in-place. It can be achieved using: Static material balance, using static (shut-in) reservoir pressures, where a plot of static p/z versus cumulative gas production is created to estimate original-gas-in-place (OGIP) or Flowing material balance where gas rates and flowing pressures are used to estimate average reservoir pressure. The flowing material balance concept of Agarwal-Gardner (1999) was extended to dry coalbed methane (CBM) reservoirs by Clarkson et al. (2007a) and Gerami et al. (2007) and to 2-phase (gas and water) CBM wells by Clarkson et al. (2007b). The present study further enhances the flowing material balance for dry CBM reservoirs by presenting a p/z* implementation of the concept. This application, while accounting for the distinguishing characteristics of a CBM reservoir, uses the industry-standard practice of p/z material balance to calculate original-gas-in-place. As with the Agarwal-Gardner approach, the flowing p/z* method can be applied to variable gas rates and/or flowing pressures conditions. In the present work, the derivation and iterative procedure of calculations are explained. Several test cases based on dry/immobile water saturation using real and synthetic data were generated. The resulting estimates of OGIP calculated from implementation of flowing p/z* material balance show excellent agreement and the estimated OGIP's are reliable. Introduction Material balance is the application of mass balance to a producing reservoir. As gas is produced, the reservoir pressure declines. By monitoring the cumulative gas production and the average reservoir pressure, and using the PVT properties of gas, one can determine OGIP and the remaining gas-in-place. Material balance analysis, although simple and more reliable than volumetrics calculation, does suffer from a number of shortcomings and limitations. For example, to measure the average reservoir pressure the well has to be shut-in and that means loss of production. Among other complexities are: low permeabilities lead to poor pressure build-ups (long-buildup times required) pressure build-up can be masked in multiple coal seams reservoir can be recharged from aquifers CBM reservoirs have additional complexities. The gas storage mechanism as well as the compressibility of CBM reservoirs is dominated by adsorption. These and other CBM-specific characteristics have to be accounted for in any material balance calculations.

ABSTRACT Coalbed Methane (CBM), also known as Coal Seam Gas (CSG) or Coal Seam Methane (CSM) in Australia is fast becoming a significant contributor to the country's energy needs. The potential coal seams for methane production in Australia are found in coal zones that are Jurassic to Permian in age with coal ranks ranging from sub-bituminous to low volatile bituminous coals. Many Australian coal seams contain high volumes of methane gas upto 25 m3 per tonne. Australia began producing CBM in 1988 but it was not until 1996 when the commercial CBM production started in the state of Queensland. Australia has total CBM reserves of about 300 to 500 Tcf (8.6 to 14.3 trillion m3). With the total amount of CBM in-place reserves worldwide estimated to be between 3,500 and 95,000 Tcf (100 and 272 trillion m3), CBM is considered one of the world's largest sources of fossil fuel. In the United States, the total CBM in-place reserves are estimated at 749 Tcf (21.4 trillion m3), and CBM now represents almost 10% of its domestic natural gas production. Canada has just begun producing gas from CBM reservoirs and its estimated in-place CBM reserves are about 1,300 Tcf (37 trillion m3). In Australia, as CBM is seen as a clean and pipeline-quality energy, it is rapidly developing. Along with the large CBM resource, the main drivers for this move are the continuously reducing cost of coal seam gas production, and the depleting conventional energy resources. A number of sophisticated CBM reservoir simulation and exploitation tools have been developed by the University of New South Wales and CSIRO to simulate the conventional CBM production as well as the CBM recovery using multi-component gases. In the field, Australia looks toward enhancing CBM recovery by injecting nitrogen and or carbon dioxide to increase CBM extraction. This paper will focus on how Australia is maximizing its CBM production. INTRODUCTION Coal is "the black rock that burns" (Land and Rice, 1993). It is defined as a readily combustible rock that contains more than 50% by weight and more than 70% by volume of carbonaceous material including inherent moisture formed by compaction and induration (hardening of sediment) of various altered plant remains. The type of plant materials, degree of metamorphism, and the range of impurity characterize coal (Bates and Jackson, 1980). A coal seam is a bed of coal, and the natural gas or methane produced from coal seams is referred to as coalbed methane (CBM). CBM production began initially to keep coal mining safe from explosions. If the methane-air mixture was in the range of 5 to 15%, methane would be explosive (Cervik, 1967). However, with the global oil production decline and the coalbed methane being a clean-burning fuel compared to the conventional fossil fuels, it has become an important resource that can assist in addressing the world's growing energy needs. In Canada, since 2000, there has been an increase in CBM exploration due to increasing natural gas prices, increased natural gas demand both domestically and internationally, development of new technologies, and the maturation of the Western Canadian Sedimentary Basin (Beaton, 2007). It is expected that CBM will contribute significantly to future natural gas supply. Currently, it is contributing nearly 10% of the U.S. gas needs.

Abstract Four distinct, sequential phases comprise a recommended process for coalbed methane (CBM) prospect assessment: initial screening, reconnaissance, pilot testing, and final appraisal. A stepwise approach through these four phases provides for a program of progressively ramping work and cost, while creating a series of discrete decision points at which analysis of results and risks can be assessed. While covering each of these phases in some degree, this paper focuses on the third, the pilot testing phase - that which normally takes place after reconnaissance, but before final appraisal. A step-wise, phased CBM prospect assessment process allows us to: gain local knowledge early at low cost; progressively acquire appropriate data to systematically assess the geological situation and reservoir conditions; define and attempt to fill knowledge gaps that represent risk and uncertainty; increasingly understand the distributions of key parameters that control reserves, deliverability, and value, and; stage expenditures and provide multiple decision points through the process. In the coalbed methane prospect assessment process, the pilot test serves the same function as a conventional exploration well. If it proves successful, then the prospect can be considered to be a discovery and be appraised for development. Only by drilling, completing and producing a cluster of wells in a CBM pilot test, short of proceeding directly to a partial development, are we able to locally dewater and depressurize the coal seam to be tested and thereby desorb and deliver measurable volumes of gas. If correctly implemented, the appraisal and pilot tests allow us to assess the local variability of key reservoir parameters, collect the information necessary to simulate the reservoir's producibility, and thereby estimate potential project reserves to a reasonable degree of accuracy. This paper contains roughly 30 specific recommendations and the fundamental rationale behind each recommendation to help ensure that a CBM pilot will fulfill its primary objectives of demonstrating whether the subject coal reservoir will desorb and produce consequential gas, and to gather the data critical to risk and evaluate the prospect at the next, perhaps most critical, decision point. These objectives must be met in a timely manner. To do this, the specifications for the pilot are often not those which will be used for an optimized well or optimized development pattern in terms of costs or production. This is intentional. The goals of piloting are different than that of development, so the recommended design is different. The design recommendations focus on collecting superior data for the parameters key for interpretation and simulation of the reservoir, retaining flexibility in the face of the level of uncertainty remaining after the reconnaissance phase, and getting to a definitive answer on the coal reservoir's viability in an acceptable time frame. Detailed data analysis methods for coalbed methane are not covered here as most are well covered in the literature. Rather, discussions of the importance, use and potential pitfalls of data collected at the various phases of the assessment process are included. Simple examples and field examples alike are used to highlight the purpose and importance of various aspects of the data gathering and analysis. A general history matching process, valid at the pilot stage and beyond, is formulated and presented to guide the engineer.

Abstract Commercial CBM production is almost exclusively through reservoir pressure depletion (primary recovery). Enhanced coalbed methane recovery (ECBM), involving injection of pure N2/CO2 or a mixture of the two, such as power plant flue gas, is a technology that has the potential to recover a larger fraction of methane in place without excessively reducing the reservoir pressure. CO2-ECBM has an added benefit that a potentially large volume of greenhouse gas can be stored in deep coal seams globally. The use of numerical models is essential in the development of the ECBM and CO2 storage technology. The quasi-steady state Fickian diffusion equation, together with the Langmuir equation, has been almost exclusively used in numerical simulation of primary coalbed methane production. Assuming that the individual gas component in a multicomponent system diffuses independently, the quasi-steady state Fickian diffusion equation can be readily extended to model mixed-gas diffusion. In the recent years, attempts have been made to use this approach, in conjunction with the extended Langmuir equation, to model ECBM/CO2 storage field pilots as well as laboratory flooding tests. However, this modelling approach for mixed-gas diffusion lacks theoretical rigour as the interaction between different gas components is not accounted for, though the practical significance of doing so in coalbeds is not well understood at present. A reservoir simulation sensitivity study on the Yubari CO2 storage pilot project, Japan, is presented. The sensitivity study with CO2 and CH4 sorption times indicates that the sorption time for CO2 has a much pronounced impact on the back-produced gas composition. The study has also highlighted the limitation of the extended Langmuir equation for ternary system predictions. Although inconclusive, the sensitivity results suggest that the N2 component sorption in the coalbed reservoir is over-estimated by at least 20% by the model. Introduction Coal seams differ from conventional gas reservoirs in that adsorption is the main storage mechanism. Over the last two decades coalbed methane (CBM) has become an important source of (unconventional) natural gas supply in the US. Current commercial CBM production is almost exclusively through reservoir pressure depletion (primary recovery), which causes incremental desorption of methane in a manner determined by the sorption isotherm. This production technique is simple but has long been recognised to be rather inefficient, given that the sorption isotherm is nonlinear and skewed towards the low-pressure end, which means that a large portion of the methane-in-pace is only available to production at low reservoir pressures. In the early 90's, enhanced coalbed methane recovery (ECBM), involving injection of N2 or CO2, is proposed as a more efficient means for recovery of a larger fraction of methane in place without excessively lowering the reservoir pressure (e.g. Puri and Yee, 1990). Injection of N2 or CO2 reduces the partial pressure of methane in the reservoir, which promotes methane desorption from the coal matrix. Of the two injectants, N2 injection has a better sweeping efficiency since it has a much lower sorption capacity than CO2 (and methane), and thus a larger proportion of the injected gas would remain in the free gas phase. On the other hand, CO2 has a greater affinity to coal than methane. The sorption capacity ratio between CO2 and CH4 in coal seams is typically between 2 to 10 depending on coal rank (thermal maturity). CO2-ECBM thus has an added benefit that a potentially large volume of greenhouse gas can be stored in deep coal seams globally. A number of field ECBM/CO2 storage pilot projects have recently been carried out in North America, Europe (Poland), China and Japan. The Allison Unit pilot, which is located in the Northern New Mexico part of the San Juan Basin, represents the world's first field trial of CO2-ECBM (Reeves et al., 2003). The San Juan Basin is one of the most prolific CBM developments and is well studied and characterised. The pilot area consists of 4 CO2 injecting wells and 16 producing wells, drilled on a 320-acre spacing. CO2 injection started in April 1995, after approximately six years of primary production, and was suspended in August 2001.

Abstract Coalbed methane (CBM) reservoirs commonly exhibit two-phase flow (gas+water) characteristics, however commercial CBM production is also possible from single-phase (gas) coal reservoirs, as demonstrated by the recent development of the Horseshoe Canyon coals of western Canada. Commercial single-phase CBM production also occurs in some areas of the low-productivity Fruitland Coal, south-southwest of the high-productivity Fruitland Coal Fairway in the San Juan Basin, and in other CBM-producing basins of the continental United States. Production data of single-phase coal reservoirs may be analyzed using traditional techniques commonly used for conventional reservoirs. Complicating application, however, is the complex nature of coal reservoirs; coal gas storage and transport mechanisms differ substantially from conventional reservoirs. In addition, single-phase coal reservoirs may display multi-layer characteristics, dual porosity behavior, permeability anisotropy etc. The current work illustrates how traditional single-well analysis techniques, such as type-curve and pressure transient analysis, may be altered to analyze single-phase (un-stimulated and hydraulically-fractured) CBM wells. Examples of how reservoir inputs to the type-curves and subsequent calculations are modified to account for CBM reservoir behavior are given. This paper demonstrates, using simulated and field examples, that reasonable reservoir and stimulation estimates can be obtained from production data analysis of coal reservoirs only if appropriate reservoir inputs (i.e. desorption compressibility, fracture porosity) are used in the analysis. As the field examples demonstrate, type-curve and pressure-transient analysis methods for production data analysis are not used in isolation for reservoir property estimation, but rather as a starting point for single- and multi-well reservoir simulation, which is then used to history-match and forecast coal well production (ex. reserves assignment). Coal reservoirs have the potential for permeability anisotropy because of their naturally-fractured nature, which may complicate production data analysis. To study the effects of permeability anisotropy upon production, a 2-D, single-phase, numerical CBM reservoir simulator was constructed to simulate single-well production assuming various permeability anisotropy ratios. Only large permeability ratios (>16:1) appear to have a significant effect upon single-well production characteristics. Multi-layer reservoir characteristics may also be observed with coal reservoirs because of vertical heterogeneity, or in cases where the coals are commingled with conventional (sandstone) reservoirs. In these cases, the type-curve and pressure transient analysis techniques are difficult to apply with confidence. Methods and tools for analyzing multi-layer CBM (+sand) reservoirs are presented. Using simulated and field examples, it is demonstrated that unique reservoir properties may be assigned to individual layers from commingled (multi-layer) production in the simple 2-layer case. Introduction Coal gas (CBM) reservoirs differ substantially from conventional gas reservoirs due to unique gas storage and transport mechanisms. Unlike conventional (sand or carbonate) reservoirs, coals act as source rocks and reservoirs to gas, and the primary gas storage mechanism is through adsorption within the microporous organic fraction, although some gas storage may occur in the free gas state (compressed in pore space), within the larger pores (macropores) and fractures. CBM reservoirs are often naturally-fractured, and may be modeled as dual (fracture+matrix porosity), or even triple porosity (fracture, matrix free- and adsorbed gas) reservoirs. Gas transport mechanisms vary, depending upon the scale and location within the reservoir. For example, gas transport at the scale of the matrix between natural fractures may be due to the mechanism of diffusion whereas Darcy flow occurs in the fracture system. Single or two-phase (gas and water) flow can exist in these reservoirs, and hence relative permeability characteristics can be important.

Abstract Carbon dioxide (CO2) from energy consumption is a primary source of anthropogenic greenhouse gas. Injection of CO2 in coalbeds is a plausible method of reducing atmospheric emissions, and it can have the additional benefit of enhancing methane recovery from coal. Most previous studies have evaluated the merits of CO2 disposal in high-rank coals. The objective of this research is to determine the technical and economic feasibility of CO2 sequestration in, and enhanced coalbed methane (ECBM) recovery from, low-rank coals in the Texas Gulf Coast area. Our research included an extensive coal characterization program, deterministic and probabilistic simulation studies, and economic evaluations. We evaluated both CO2 and flue gas injection scenarios. In this study coal core samples and well transient test data were obtained for characterization of Texas low-rank coals. Simulation studies evaluated the effects of well spacing, injectant fluid composition, injection rate, and dewatering on CO2 sequestration and ECBM recovery. Probabilistic simulation of 100% CO2 injection in an 80-acre 5-spot pattern indicate that these coals can store 1.27 to 2.25 Bcf of CO2 with an ECBM recovery of 0.48 to 0.85 Bcf. Simulation results of 50% CO2 - 50% N2 injection in the same 80-acre 5-spot pattern indicate that these coals can store 0.86 to 1.52 Bcf of CO2, with an ECBM recovery of 0.62 to 1.10 Bcf. Simulation results of flue gas injection (87% N2 - 13% CO2) indicate that these same coals can store 0.34 to 0.59 Bcf of CO2 at depths of 6,200 ft, with an ECBM recovery of 0.68 to 1.20 Bcf. Economic modeling of CO2 sequestration and ECBM recovery for 100% CO2 injection indicates predominately negative economic indicators for the reservoir depths and well spacings investigated, using natural gas prices ranging from $2 to $12 per Mscf and CO2 credits based on carbon market prices ranging from $0.05 to $1.58 per Mscf CO2 ($1.00 to $30.00 per ton CO2). Injection of flue gas (87% N2 - 13% CO2) results in better economic performance than injection of 100% CO2. Moderate increases in either gas prices or carbon credits could generate attractive economic conditions that, combined with the close proximity of many CO2 point sources near unmineable coalbeds, could generate significant CO2 sequestration and ECBM potential in Texas low-rank coals. Introduction Greenhouse gas emissions potentially constitute a major environmental problem. Texas emits approximately 255,651,224 tons[1] of CO2 annually, which is about 10% of the total emitted in the United States. These emissions are mostly from the industrial and electric power sector. Any method that reduces net CO2 emissions would help mitigate the global greenhouse effect. CO2 sequestration in coals is one method that could help achieve this objective. CO2 injected in coal beds may have the dual benefits of CO2 disposal and enhanced coalbed methane recovery. CO2 injection could improve methane recovery and help maintain reservoir pressure, thus reducing operational costs.

Abstract Some of the significant strides made in coal stimulation during the last 25 years can be attributed to the development of new-generation fluid systems (i.e., low gel loading fluids with efficient low-temperature breaker systems that cause less polymer damage in coals). All these new developments were implemented to minimize damage in coals, and maximize production. Water fracture treatments in coals completely eliminated polymer damage but did not always maximize production. The use of new-generation crosslinked fluids did provide better half-lengths and conductivities but still left residual damage in coals. Based on production, it was confirmed that the benefits obtained with this fluid system outweighed the damage created. To further reduce the damage in coals and obtain better regained fracture permeability, implementing hybrid fracture treatments in coals was considered in this San Juan basin project. The term "hybrid" in this case refers to a water pad followed by crosslinked fluid sand stages. Potential benefits of this technique in coals include: minimizing damage caused by gel, maximizing regained permeability, containing height growth, and lowering cost. There are two parts to this work. The first part presented in this paper contains the design, implementation, and encouraging initial results obtained from the seven wells in this project, which is in an underpressured area. This is the first project in which hybrid-type treatments have been applied in a low-pressured formation. This paper will discuss the lessons learned from such an application in coals. When sufficient production data becomes available, the second part of this work will quantify the results via reservoir simulation. The second part will also include quantified results from another current hybrid fracture-stimulation project where the coals are slightly overpressured. Introduction Historically water fracture and hybrid fracture treatments have been applied to low-permeability reservoirs in the United States.[1] Since its inception, water fracture treatments have also been applied to coalbed methane (CBM) wells.[2,3,4] Water fracture treatments are used in coals mainly because, unlike crosslinked fluid systems, they do not cause damage to coals; they are also less expensive. However, an industry survey of coalbed methane completions in the six CBM basins in the U.S. has shown that crosslinked fluid fracture treatments have outperformed water fracture treatments.[5] The authors attribute this to the proppant carrying capacity of the new-generation low gel loading fluids with efficient breaker systems. The benefits of obtaining better effective half-lengths with these new fluid systems have outweighed the residual damage created by gel. To further improve regained permeability by reducing residual gel damage and still maintaining proppant carrying capacity, hybrid fracture treatments were considered in this project. According to Rushing et al., [6] hybrid fracture treatments provide the benefits of both gel and water fracture treatments. A logical requirement when considering a water fracture treatment is whether the formation will have sufficient energy to unload additional water. Although a hybrid fracture treatment uses less water than a conventional water fracture treatment, it still uses more water than a conventional gel fluid fracture treatment. Although pressure transient tests revealed that the coals in the project area were underpressured, hybrid fracture treatments were still considered for the project because the wells operate on rod pumps. It was assumed that these pumps would be sufficient to negate the low reservoir pressure in the coal and unload the additional water that would be injected during the stimulation treatment. The additional water would come mainly from an increase in the pad volume; this incremental volume was not expected to affect the relative permeability to gas significantly. The fact that the thin, low-viscosity pad fluid used in hybrid fracture treatments creates more confined fractures was one of the main reason that this type of treatment was considered for this project. The design and implementation of this hybrid fracture treatment for the case wells and the encouraging initial results are discussed in this paper. An evaluation of these fracturing treatments will be made when sufficient data from reservoir simulation becomes available; the analysis will be presented in the second part of this work.

Abstract The purpose of this paper is to show how to estimate geomechanical parameters and subsidence during coalbed methane production using the petrophysical algorithm in an integrated flow model. The integrated flow model has been extended to model production of gas from coalbeds and estimate associated geomechanical properties. The model is applied to coals with desorption properties associated with Fruitland coal and Pocahontas coal. Introduction An integrated flow model combines a petrophysical model with a traditional flow simulator. The integrated flow model was originally devised to assist in the design and analysis of timelapse seismology. 1–3 The petrophysical model can calculate such reservoir geophysical attributes as acoustic impedance, reflection coefficient, shear velocity, and compressional velocity. In this paper, we show how to use the integrated flow model to estimate geomechanical properties, including subsidence, for coalbed methane systems. The petrophysical algorithm in the integrated flow model can be used to calculate geomechanical properties such as Poisson's ratio, Young's modulus, and uniaxial compaction. These properties give us insight into the behavior of the structure of the reservoir and the impact of structural changes on fluid flow. The integrated flow model has been extended to model production of gas from coalbeds. Reservoir geophysical attributes calculated by the petrophysical model are used to estimate geomechanical properties and subsidence. The petrophysical algorithm used in the integrated flow model is described first, followed by a brief description of the coalbed methane model. The simulator is then used to study coals with desorption properties associated with Fruitland coal, San Juan Basin and Pocahontas coal, West Virginia. PETROPHYSICAL ALGORITHM A prototype integrated flow model (IFLO) based on a widely used petrophysical model has been developed and applied to a range of reservoir systems 3,4 . The algorithm for calculating seismic velocities is a rock physics model 5 . We refer to the algorithm used in the integrated flow model as a petrophysical algorithm because of its dependence on rock physics properties and petroleum fluid properties. Shear velocity for an isotropic, homogeneous medium is calculated from the shear modulus µ and bulk density ? B as Equation 1 In this formulation, the shear modulus of dry rock is equal to the shear modulus of rock with pore fluid 5 .

Abstract The early stages of a coalbed methane (CBM) project development often require more extensive use of currently available technologies than can be economically justified when approached from a conventional oil and gas drilling focus. As a result, key evaluation tools and technologies are either omitted or not considered before significant decisions are made regarding viability of a CBM play. Understanding that the various lifecycle phases will each affect different objectives and decision points is important. Following site acquisition and estimating basic drilling costs, at least five lifecycle phases can be identified: Regional Resource Reconnaissance, Local Asset Evaluation, Early Development, Mature Development; and Declining Production. A systematic review of current and recently developed enabling technologies is presented in the context of their potential use and applicability. Environmental risk and other constraints that can impact development vary globally, as do economics and production forecasting. New and emerging chemical technologies, as well as hydraulic fracturing refinements, play key roles in various lifecycle phases and decision making to identify successful CBM development projects as early as possible. The paper presents strategies that can reduce development phase failure risk and help predict or rank production potential. Economic constraints usually become more restrictive as the lifecycle moves to Phase 4 and beyond, but key information needed to enter Phase 4 is often overlooked. Examples of this scenario are presented from a global perspective. Globally, new and existing technologies combined with dynamic gas and electricity markets are changing the nature of CBM development opportunities. More accurate and timely go/no-go information needs to be used in the decision making process. Converting development opportunities to develop-ment successes involves integrating planning and evaluation methods, using targeted development technologies in the proper phase, and managing risk. Introduction Coal's unique gas-storage mechanism is weak Van der Waal's forces holding gas molecules on the coal-matrix surface. Concentration gradient causes gas to be released from the tens to hundreds of square meter surface area per gram of coal. Methane and other light gases diffuse (Ficks Law) from the coal matrix toward a lower concentration. Coal can store many times its equivalent volume in gas because the gas molecules are packed tightly onto the surfaces of the coal. Globally, coal is estimated to hold from 2.980 to 9.260 trillion cubic feet of methane. 1 Gas adsorbed onto and within the coal macerals desorbs through a complex flow path of pores and cleats of varying sizes. The physics of migration is dominated by diffusion or diffusivity at various scales. Some coals are diffusion limited, while others are not. Water, and sometimes gas, exists at equilibrium gas saturation. Concentration gradients are most readily generated by removing this water or gas from the cleat system by reducing pressure. Often, adsorption isotherms are used to help define a relationship between gas storage capacity and reservoir pressure; from this, a critical desorption pressure can be determined. Conventional porous-media fluid-flow concepts, such as Darcy's law, relative permeability, and permeability anisotropy quantify reservoir mechanics after gas is released from the coal matrix. Industry literature provides extensive discussion of all the above subjects. CBM technologies, when viewed from a development lifecycle perspective, illustrate departures from a conventional oil and gas approach and unique enabling aspects of a particular technology.

Abstract A conventional reservoir simulator was modified to model coalbed methane reservoirs using the approach presented by Siedle where an immobile oil phase is used to represent the bulk coal and the gas volume adsorped on the coal's surfaces is computed as solution gas-oil ratio. The simulator was validated against published results from coalbed methane models. The speed of the model was tested for a large problem with 120,000 cells. A dual grid system to model gas desorption, flow through low permeability matrix to high permeability fracture cleats in the coal seam was shown to more accurately reproduce initial delay in gas production while dewatering. Enhanced recovery using N2 and CO2 injection was simulated using single grid and dual grid systems. Expected incremental recovery of methane was obtained using the single grid system. However no additional recovery was obtained using the dual grid system due to extensive bypassing of the injected gas in the fracture grid system. This indicates additional physical mechanisms are at work. Introduction Coalbeds are naturally fractured volumes of coal with the fractures (cleats) usually filled with water. The coal seams have low porosity and low permeability and these micropore spaces too are usually water filled. The methane gas is adsorped on the coal surfaces. When water is produced from the coalbeds, the pressure drops in the fractures and the coal micropores. The adsorped gas is released, flows slowly through the coal microporosity system and then to the high permeability cleats. The classic method for modelling naturally fractured reservoirs is based on the Warren and Root (1) concept. The reservoir shape and volume is represented by a conventional grid cell system with high grid cell porosity and low permeability. The extensive fracture network system is represented by another set of grid cells of the same shape and volume and depth as the matrix grid system. These fracture grid system cells have a porosity such that the volume of the fracture cells is equivalent to the fracture capacity, and a permeability such that the fracture transmissibility based on the grid cell size is equivalent to the transmissibility of the small natural cracks. The two grid cell systems are connected by means of ‘special connections’ between each cell of the matrix grid system with the corresponding fracture cell in the fracture grid system in the same physical space. The special connection transmissibility is calculated based on formulas provided by Warren and Root (1) , and other authors, Thomas et al . (2) , and this reflects the degree of fracturing or the number of cleats in the volume represented by each of the grid cells. If matrix permeability is present, this is referred to as a dual porosity-dual permeability model. Modelling such connected dual grid systems presents severe mathematical difficulties. As an approximation, earlier coalbed methane models such as that presented by Sawyer (3) et al. , and Paul (4) et al . considered only one grid cell system representing the shape and size of the reservoir with fracture permeability and system porosity. The processes that occurred in the matrix system, (desorption and flow of gas through the micropores) are represented by user entered desorption time and diffusion coefficients and then equations presented in the references are used to calculate the amount of gas released into the grid cell system. The amount of gas adsorped on the coal is described using Langmuir's isotherm.

Abstract The injection of carbon dioxide (CO 2 ) in deep, unmineablecoalbeds can enhance the recovery of coalbed methane (CBM) and at the same timeit is a very attractive option for geologic CO 2 storage asCO 2 is strongly adsorbed onto the coal. Existing CBM numerical simulators which are developed for the primary CBM recovery process, have many important features such as: a dual porositysystem; Darcy flow in the natural fracture system; pure gas diffusionand adsorption in the primary porosity system; and coal shrinkage due to gas desorption; taken into consideration. However, process mechanisms become more complex with CO 2 injection. Additional features such as: coal swelling due to CO 2 adsorption on coal; mixed gasadsorption; mixed gas diffusion; and non-isothermal effect for gasinjection; have to be considered. This paper describes the first part of a comparison study between numerical simulators for enhanced coalbed methane (ECBM) recovery with pure CO 2 injection. The problems selected for comparison are intended to exercise many of the features of CBM simulators that are of practical and theoretical interest and to identify areas of improvement for modeling of the ECBM process. The first problem set deals with a single well test withCO 2 injection and the second problem set deals with ECBM recoveryprocess with CO 2 injection in an inverted five-spot pattern. Introduction The injection of carbon dioxide (CO 2 ), a greenhouse gas (GHG), incoalbeds is probably one of the more attractive options of all undergroundCO 2 storage possibilities: the CO 2 is stored and at thesame time the recovery of coalbed methane (CBM) is enhanced. 1 Therevenue of methane (CH 4 ) production can offset the expenditures ofthe storage operation. 2,3 Coalbeds are characterized by their dual porosity: they contain both primary (micropore and mesopore) and secondary (macropore and natural fracture) porosity systems. The primary porosity system contains the vast majority of the gas-in-place volume while the secondary porosity system provides the conduitfor mass transfer to the wellbore. Primary porosity gas storage is dominated by adsorption. The primary porosity system is relatively impermeable due to the small pore size. Mass transfer for each gas molecular species is dominated by diffusion that is driven by the concentration gradient. Flow through the secondary porosity system is dominated by Darcy flow that relates flow rate to permeability and pressure gradient. The conventional primary CBM recovery process begins with a production well that is often stimulated by hydraulic fracturing to connect the wellbore to thecoal natural fracture system via an induced fracture. When the pressure in the well is reduced by opening the well on the surface or by pumping water from the well, the pressure in the induced fracture is reduced which in turn reduces the pressure in the coal natural fracture system. Gas and water begin moving through the natural and induced fractures in the direction of decreasing pressure. When the natural fracture system pressure drops, gas molecules desorbfrom the primary-secondary porosity interface and are released into the secondary porosity system. As a result, the adsorbed gas concentration in the primary porosity system near the natural fractures is reduced. This reduction creates a concentration gradient that results in mass transfer by diffusion through the micro and mesoporosity. Adsorbed gas continues to be released as the pressure is reduced.

Abstract This paper presents results from evaluations of geochemical, petrographic and reservoir properties of Powder River Basin, Paleocene Fort Union Formation Canyon seam subbituminous coal at the Triton Federal #21C-2623 coalbed methane well in Campbell County, WY. The core analysis data reveal that at this location the Canyon seam coalbed is a multi-layered reservoir with each layer having different bulk compositional and fluid mobility properties. A very unique reservoir property of this subbituminous coal is its extremely fast gas desorption rate, which, in turn, facilitates a high early time gas production rate from the coalbed reservoir. The core analysis data indicate that the gas desorption rate is dependent on the maceral composition of the bulk coal organic matter. It was found that several commonly used coal and coalbed reservoir property analysis methods required modification to prevent or minimize errors due to subbituminous coal's propensity to undergo aerial oxidation and desiccation. The occurrence of these processes during sample handling, storage or testing causes significant (15% or greater) underestimation errors in key reservoir properties such as the in-situ gas content, moisture holding capacity, sorbed gas composition, and percent gas saturation. Effective methods for avoiding or minimizing subbituminous coal property analysis errors due to oxidation and desiccation are described in this paper. Because these error prone analysis practices have been commonly used in the past, there may be significant potential for large coalbed methane resource and reserve estimate gains in this and other Rocky Mountain region basins. Introduction The Tongue River Member of the late Paleocene Fort Union Formation in the Powder River Basin contains thick beds of subbituminous coal, which are reservoirs for an estimated 24 Tcf (0.68 × 10 12 m 3 ) of coalbed methane resources. 1 The U.S. Potential Gas Committee has estimated that the Powder River Basin contains 9.33 Tcf (0.26 × 10 12 m 3 ) of recoverable coalbed methane resources. 2 A major play area for the commercial production of these coalbed methane resources is located along the eastern flank of this basin, down-dip from large surface coal mines in Campbell County, Wyoming. 1–6 In 1998, coalbed methane production from this play totaled 27.8 Bcf (0.79 × 10 9 m 3 ) from about 650 wells. 7 The coalbed methane wells in this play are relatively shallow, typically only 250 to 1,000 ft deep (76 to 305 m), cost only about $50,000 to drill and complete, and have initial gas production rates ranging from less than 100 up to 1,000 Mscfd (2,832 to 28,320 m 3 /day). 1–6 The use of low-cost, innovative drilling and completion practices have been critical factors in making this coalbed methane play economical. 1,4–6 The average gas reserve finding cost in this coalbed methane play is about $0.25 per Mscf (28.32 m 3 ) which compares favorably with average reserve finding costs of from $0.15 to $0.50 per Mscf (28.32 m 3 ) for conventional on-shore natural gas resources. 7,8 The water production rates from these shallow coalbed methane wells average about 330 STB (52.5 m 3 ) per day. However, the water disposal cost is generally minimal because the coproduced water quality is relatively good, typically less than 2,500 ppm total dissolved solids, enabling beneficial uses or direct discharge, under permit, into surface drainages. 1,3–6 This coalbed methane play is quite unique because several coal properties are strikingly different from those of commercially developed coalbed methane plays in other U.S. basins. 7,8 In particular, the coal rank is much lower, the gas content is typically an order of magnitude lower, the coal moisture content is typically an order of magnitude greater, and the absolute water permeability is typically an order of magnitude greater, ranging from tens of md to more than a Darcy. 4,5

Abstract Naturally occurring microfractures, called cleats, provide the permeability essential for bulk fluid flow in coalbed reservoirs. The bulk fluid flow, in turn, is controlled by the cleat properties, specifically their orientation, spacing, compressibility, and effective porosity. A two parameter, geologic process-based model for predicting the effective cleat porosity of coalbed reservoirs was developed from an analysis of cleat property data for San Juan Basin Fruitland Formation coal. The cleat property data indicate that thermal maturation and effective stress act in opposite directions on the effective cleat porosity of Fruitland Formation coal. These two variables are the basis for the geologic process-based model for calculating effective cleat porosity values. Introduction Coalbed reservoirs in the U.S. contain an estimated 703 Tcf (19.9 × 10 12 m 3 ) of natural gas resources, hold 11.7% (141.4 Tcf; 4.0 × 10 12 m 3 ) of the estimated total recoverable U.S. natural gas resource base, and in 1997 accounted for 6% (1.13 Tcf; 32 × 10 9 m 3 ) of total U.S. natural gas production. 1–4 Coal deposits function as self-sourced natural gas reservoirs wherein the three crucial petroleum system elements of source rock, reservoir and trap are located together in a single geologic unit. Thus, coal deposits represent a relatively simple, low risk exploration situation with respect to locating natural gas accumulations. The major risk in most coalbed methane plays is generally not the drilling of a dry hole; rather it is not being able to produce commercial quantities of natural gas from the reservoir. Naturally occurring microfractures, called cleats, provide the permeability essential for bulk fluid flow in coalbed reservoirs. 5–7 The bulk fluid flow, in turn, is controlled by the cleat physical properties, specifically their orientation, spacing, compressibility, and effective porosity. 6–12 This paper presents results from analysis of the effects of geologic variables on the cleat properties of Upper Cretaceous Fruitland Formation coalbed reservoirs in the San Juan Basin, Colorado and New Mexico. Natural Fracture Origin and Types Natural fractures in rocks have varied origins and are formed when the applied stress exceeds the yield stress of the bulk rock matrix material. The applied stress may be the result of either a physical or chemical process and it may originate either external or internal to the rock body. Natural fracture formation in coalbed reservoirs results from stresses generated by such varied geologic processes as structural deformation, differential compaction and volume contraction. 7,13–17 Five types of natural fractures are distinguishable in coalbed reservoirs. The two most commonly observed types of natural fracture are orthogonal sets of closely spaced subparallel microfractures called face and butt cleats that are oriented essentially perpendicular to the bedding plane. Coal cleats are extension (opening-mode) fractures that form as a result of the stress generated by the volume contraction or shrinkage of the coal matrix as a result of desiccation during thermal maturation. 5,7,17 The face and butt cleats are also referred to as primary and secondary cleats, respectively. By convention, the oldest and generally most prominent of these two microfracture sets is called the face cleat. The butt cleats terminate against face cleats, which is interpreted as indicating that they were formed later in geologic time. 7,17 Three other fracture systems, referred to as tertiary cleats, joints and faults, may also be present in coalbed reservoirs. Tertiary cleats are microfractures whose orientations are different than those of either the face or butt cleats. The tertiary cleats terminate against either face or butt cleats, which is interpreted as indicating that they were formed later in geologic time. Joints and faults are larger-scale fractures that typically cut across coalbeds and non-coal interbeds. 7,15–17