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A useful first step in the characterization of any new coal area is to compare its characteristics with those of successful CBM projects. Table 2 summarizes the characteristics of several successful projects in the US and includes parameters related to reservoir properties, gas production, gas resources, and economics. The table shows that successful projects have many similarities, including high permeabilities and high gas resource concentration; however, the table does not include aspects such as government incentives or high-value markets, which could elevate a marginal project to commercial status.
Unlike conventional reservoirs, coal seams are the source, trap, and reservoir for coalbed methane (CBM). A comparison of the two reservoir types shows profound differences in reservoir properties, storage mechanisms, flow mechanisms, and production profiles. Understanding the reservoir differences is key to successful evaluation and operation of a CBM project. Coal is a chemically complex, combustible solid consisting of a mixture of altered plant remains. Organic matter constitutes more than 50% of coal by weight and more than 70% by volume. Type refers to the variety of organic constituents.
Unlike conventional reservoirs, coal seams are the source, trap, and reservoir for CBM. A comparison of the two reservoir types shows profound differences in reservoir properties, storage mechanisms, flow mechanisms, and production profiles. CBM reservoirs are layered and contain an orthogonal fracture set called cleats, which are perpendicular to bedding. Because the coal matrix has essentially no permeability, CBM can be produced economically only if there is sufficient fracture permeability. Relative to conventional gas reservoirs, coal seam permeabilities are generally low and may vary by three orders of magnitude in wells separated by distances of less than 500 m.
Summary Coalbed methane (CBM) produced from subsurface coal deposits has been produced commercially for more than 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 sorbed gas storage); estimation of initial fluid saturations (in saturated reservoirs) and mobile water in place; estimation of the degree of undersaturation (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 multilayer 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 obtaining accurate estimates of some basic reservoir and geomechanical properties remains challenging. The purpose of the current work is to review the state of the art in field-based techniques for CBM reservoir-property and stimulation-efficiency evaluation. Advances in production and pressure-transient analysis, gas-content determination, and material-balance methods made in the past 2 decades will be summarized. The impact of these new methods on the evaluation of key reservoir properties, such as absolute/relative permeability and gas content/gas in place, as well as completion/stimulation properties will be discussed. Recommendations on key surveillance data to assist with field-based evaluation of CBM, along with insight into practical usage of these data, will be provided.
Abstract 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 In the design of hydraulic fractures, it is necessary to make simplifying assumptions. Fifty years ago, our industry was mathematically obliged to describe fractures as simple, planar structures when attempting to predict fracture geometry and optimize treatments. Although computing tools have improved, as an industry we remain incapable of fully describing the complexity of the fracture, reservoir, and fluid flow regimes. Generally, we make some or all of the following assumptions:–Simple, planar, bi-wing fractures –Completely vertical fractures with perfect connection to the wellbore –Flow capacity that is reasonably described by published conductivity data –Predictable fracture width providing dependable hydraulic continuity (lateral and vertical continuity) To forecast production from these fractures, we frequently make the additional assumptions:–Reservoir is laterally homogeneous –Modest/no barriers to vertical flow in formation (simplified description of layering compared to reality) However, we must recognize that all of these assumptions are imperfect. This paper will investigate the evidence suggesting that fractures are often subject to:–Complicated flow regimes –Complicated geometry –Irregular frac faces –Imperfect proppant distribution –Imperfect hydraulic continuity –Imperfect wellbore-to-fracture connection –Residual gel damage, possibly including complete plugging or fracture occlusion Additionally, reservoirs are known to contain flow barriers that amplify the need for fractures to provide hydraulic continuity in both vertical and lateral extent. The paper appendix tabulates the results from more than 200 published field studies in which fracture design was altered to improve production. Frequently the field results cannot be explained with our simplistic assumptions. This paper will list the design changes successfully implemented to accommodate real-world complexities that are not described in simplistic models or conventional rules of thumb. Field examples from a variety of reservoir and completion types [tight gas, modest perm oil, coalbed methane, low rate shallow gas, annular gravel packs] will be provided to demonstrate where the field results differ from expectations, and what adjustments are necessary to history-match the results.
Abstract Drilling activity to access natural gas production from coalbeds has increased dramatically in the past decade; however, the percentage of methane that has been converted to economically recoverable reserves remains only a fraction of the potential gas in place. One of the methods widely used to access natural gas from deeper, lower-permeability coal seams, has been with propped hydraulic fracture completions in vertical wellbores. Propped hydraulic fracture completions have been successful in stimulating production from conventional reservoirs from microdarcy to darcy rocks. Effective fracture lengths in excess of 1,000 ft have been documented from pressure transient analysis with skin effects as low as –6.5. Propped hydraulic fracture completions in coalbed natural gas wells have been successful in stimulating production, but have generally under performed the stimulation effects that are observed in conventional sandstone reservoirs. In spite of the fact that coal seam fracture stimulation volumes can be 3,000 to 12,000 lbm/ft of coal, effective fracture lengths are rarely documented beyond 200 ft, and post-fracture skins have been measured near zero or even positive in some cases. It can easily be estimated that if fracturing in coal seams could be brought up to parity with sandstone fracture stimulation, the recoverable reserves from coal seams could be tripled over today's standards. This paper investigates three processes in coalbed fracturing that can inhibit stimulation effects and offers solutions that can increase coal stimulation efficiency.The effects of maximum horizontal stress azimuth in relation to cleat orientation Propped fracture placement efficiency The effects of fracturing fluid damage in coal cleats Introduction The commercial extraction of methane from subsurface coal seams through rotary-drilled wellbores has now entered its third decade. It is estimated that between 3,500 Tcf and 9,500 Tcf of natural gas is contained in subsurface coal seams around the world with anywhere from 1,000 Tcf to 3,000 Tcf in North America alone. From these estimates it is easy to postulate that coalbed natural gas (CBNG) could be significant source of clean burning energy. Unlike sandstone formations, in which natural gas can be trapped and stored in the pore spaces between the sand grains, coalbed natural gas reserves are adsorbed into the coal surface. This means that, coal does not require a structural or stratigraphic trap to store natural gas. The gas remains in the coal and is released only when the pressure in the coal is lowered below a critical point. Fig. 1 shows an example of a comparison plot of gas content and pressure for a coal and various porosity sandstones. This plot demonstrates two main differences between sandstone reservoirs and CBNG. First, it shows the large potential storage capacity of natural gas in coal vs. pore spaces in sandstone, especially when the formation pressure is below 2,000 psi. Secondly, this figure shows the difference in production regimes between sandstones and coal, whereas by 500 psi, most of the gas has already been released from the sandstone formations, but most of the gas still remains in the coal. In addition, coal is often its own source rock for natural gas, either by thermogenic or biogenic processes. However some of richest CBNG reserves have been enhanced by additional adsorption of gas migrating from lower sources. Factors that affect CBNG production The primary factors that affect CBNG productivity aregas content permeability net coal thickness water saturation completion skin and producing pressures