Cleat Permeability Research Articles

Exponential Growth in San Juan Basin Fruitland Coalbed Permeability With Reservoir Drawdown: Model Match and New Insights

Summary The exponential-growth behavior of coalbed permeability with reservoir pressure depletion has been observed previously at the Fairway wells in the San Juan basin. More recently, the exponential trend has also been confirmed for a group of 10 wells in a region northeast of Fairway. Increase in the absolute permeability of coalbeds is a result of matrix shrinkage caused by gas desorption, which becomes a dominant factor on cleat permeability over the effective-stress effect during reservoir production. A permeability model previously developed by the authors has been revisited in an effort to match the recently published field-permeability data. The Shi and Durucan (S&D) permeability model (2004, 2005a) makes use of a stress permeability relationship reported in the literature for an idealized geometry (matchsticks), in which the permeability varies exponentially with changes in the effective horizontal stress through the use of a constant cleat (pore) compressibility parameter. In this study, a stress-dependent cleat volume compressibility defined by an initial compressibility with a negative exponential decline rate was adopted. By tuning these two parameters, it was possible to achieve a close match to all the field-permeability data by use of a common set of reservoir properties (elastic properties and matrix-shrinkage parameters) that are consistent with the available field and laboratory data in the literature. The matching of the field-permeability data in these two regions of the San Juan basin in this study has further validated the updated S&D permeability model (now with variable cleat-volume compressibility). It has also provided theoretical support for the observed near-exponential growth behavior of coalbed permeability in a producing reservoir. Furthermore, the model has shed new light on the permeability behavior: (1) The exponential growth occurs when the reservoir pressure is reduced to a level generally below the permeability-recovery pressure (the reservoir pressure at which the initial permeability is recovered); (2) The reservoir permeability in these two regions would remain relatively flat at reservoir pressures above the permeability recovery pressure.

Development of a coal shrinkage swelling model accounting for water content in the micropores

Changes in cleat permeability of coal seams are influenced by internal stress, and release or adsorption of gas in the coal matrix during production/injection processes. Coal shrinkage?swelling models have been proposed to quantify such changes; however none of the existing models incorporates the effect of the presence of water in the micropores on the gas sorption of coalbeds. This paper proposes a model of coal shrinkage and swelling, incorporating the effect of water in the micropores. The proposed model was validated using field permeability data from San Juan basin coalbeds and compared with coal shrinkage and swelling models existing in the literature.

Assessment of shrinkage–swelling influences in coal seams using rank-dependent physical coal properties

Characterization of coal reservoirs and determination of in-situ physical coal properties related to transport mechanism are complicated due to having lack of standard procedures in the literature. By considering these difficulties, a new approach has been developed proposing the usage of relationships between coal rank and physical coal properties. In this study, effects of shrinkage and swelling (SS) on total methane recovery at CO2 breakthrough (TMRB), which includes ten-year primary methane recovery and succeeding enhanced coalbed methane (ECBM) recovery up to CO2 breakthrough, and CO2 sequestration have been investigated by using rank-dependent coal properties. In addition to coal rank, different coal reservoir types, molar compositions of injected fluid, and parameters within the extended Palmer & Mansoori (P&M) permeability model were considered. As a result of this study, shrinkage and swelling lead to an increase in TMRB. Moreover, swelling increased CO2 breakthrough time and decreased displacement ratio and CO2 storage for all ranks of coal. Low-rank coals are affected more negatively than high-rank coals by swelling. Furthermore, it was realized that dry coal reservoirs are more influenced by swelling than others and saturated wet coals are more suitable for eliminating the negative effects of CO2 injection. In addition, it was understood that it is possible to reduce swelling effect of CO2 on cleat permeability by mixing it with N2 before injection. However, an economical optimization is required for the selection of proper gas mixture. Finally, it is concluded from sensitivity analysis that elastic modulus is the most important parameter, except the initial cleat porosity, controlling SS in the extended P&M model by highly affecting TMRB.

Controls of Coal Fabric on Coalbed Gas Production and Compositional Shift in Both Field Production and Canister Desorption Test

Summary The production rates of coalbed gas wells commonly vary significantly, even in the same field with similar reservoir permeability and gas content. The compositional variation in produced gas is also not everywhere predictable, although in most fields produced gas becomes progressively enriched in CO2 through the production life of a reservoir, such as parts of the San Juan basin. In contrast, it is generally observed that the ratio of CO2:CH4 declines with time during field and laboratory desorption testing of coal cores. In this study, we investigate numerically the importance of coal fabric, namely cleat spacing and aperture width, on the performance of coalbed gas wells and gas compositional shifts during production. Because of the cubic relationship between fracture permeability and fracture aperture width (and thus fracture porosity) for a given cleat permeability, the production profile of coal seams varies depending on whether the permeability is distributed among closely spaced fractures (cleat) with narrower apertures or more widely spaced fractures (cleat) with wider apertures. There is a lower fracture porosity for coal with widely spaced fractures than for coal with closely spaced fractures. Therefore, the relative permeability to gas increases more rapidly for coals with more widely spaced cleats as less dewatering from fractures is required, assuming that the fractures are initially water saturated. Increase in cleat spacing from 0.01 to 10 cm significantly enhances the peak gas production and shortens the period to reach peak production. The main stage of gas production is controlled by equilibrium desorption of gas from coals due to the relatively slow changes in reservoir pressure. The enrichment of CO2 in the production gas with time occurs because of the stronger adsorption of coals for CO2 than CH4. However, during desorption of coal cores, CO2 desorbs more rapidly than methane because desorption rate is governed more by diffusion than by sorption affinity, and CO2 has much higher effective diffusivity in microporous coals than CH4. Therefore, during canister desorption, there is a rapid increase in CO2 concentration in the desorbed gas followed by a steady decline in CO2 concentration, in contrast to the progressive enrichment of CO2 in produced gas from wells.

Sensitivity Study of Coalbed Methane Production With Reservoir and Geomechanic Coupling Simulation

Abstract Permeability of coal seams is one of the key factors for the success of coalbed methane (CBM) developments. It is dominated by cleat permeability in coal, which is very sensitive to the change of effective stresses. The coal matrix shrinkage due to methane production also influences cleat permeability. Using an explicit-coupling simulation method, which simultaneously simulates multiphase fluid flow and coal deformation, and a coupling permeability model, which considers the effects of the effective stress change and coal matrix shrinkage on cleat permeability, the sensitivity of CBM production to ten engineering, geologic, and coal intrinsic parameters such as cleat permeability, cleat spacing, well control area, depth, and methane content, etc., were studied in this paper. These parameters are stress and matrix shrinkage related parameters or have significantly influences on CBM production identified from previous studies. The production rate and final gas recovery from conventional simulations and coupling simulations are also compared. Of the parameters studied, permeability, cleat spacing, and in situ stresses were found to be the most sensitive parameters that influence CBM production. Medium sensitivity was found for the coefficient of matrix shrinkage, the Langmuir volume, pressure gradient, and well control area, while the least sensitive parameters included Poisson's ratio, Young's modulus, and the Langmuir pressure. Introduction With reserves of 84 ˜ 262 trillion m3 (2,980 ˜ 9,260 trillion ft3) all over the world(1), coalbed methane (CBM) has come to represent a real gas supply to meet current and future natural gas demands. In the United States, CBM accounted for 10% of dry gas reserves and 8% of dry gas production in 2003(2). The worldwide development of CBM is also accelerating in many other countries such as China, Canada, and Australia. The success of CBM developments depends on many factors, but specific properties of a coal seam remain the fundamental controlling factor. Many people have investigated the effects of coal seam properties on CBM production and recovery(3–6). The studies of Sawyer et al. indicated that cleat (fracture) permeability and relative permeability, not gas diffusion, control long-term productivity, and that optimum well spacing also depends on cleat permeability(3). Reid et al.'s results showed that permeability, initial desorption pressure, and drainage area are the most important reservoir parameters for CBM production(4). Young et al. pointed out that permeability, well spacing, and the degree of coal saturation have the greatest impacts on the long-term performance of CBM wells(5). A completed parametric study by Roadifer et al. illustrated that for coal-only reservoirs (without adjacent sand layers), the five parameters having the most impact on the peak gas rate are, in order of highest to lowest, permeability, free gas saturation, degree of saturation of the coal, damage skin factor, and thickness(6). The results of the above-mentioned studies clearly indicate that cleat permeability is likely the most important factor for CBM production. However, in all these investigations, permeability was considered as a constant.

Drawdown Induced Changes in Permeability of Coalbeds: A New Interpretation of the Reservoir Response to Primary Recovery

A model for pore pressure-dependent cleat permeability is presented for gas-desorbing, linear elastic coalbeds under uniaxial strain conditions experienced in producing reservoirs. In the model, changes in the cleat permeability of coalbeds, which are idealised to have a bundled matchstick geometry, is controlled by the prevailing effective horizontal stresses normal to the cleats. Variations in the effective horizontal stresses under uniaxial strain conditions are expressed as a function of pore pressure reduction during drawdown, which includes a cleat compression term and a matrix shrinkage term that have competing effects on cleat permeability. A comprehensive analysis has revealed that the shape of the stress – pore pressure curve is predominantly determined by the magnitude of recovery pressure and rebound pressure relative to the initial reservoir pressure. A total of five possible scenarios have been identified with regard to response of the horizontal stress function to reservoir drawdown. When applied to four coalbed wells at two separate sites in the fairway of the San Juan basin, the model predictions at one site, where the three wells have shown increased absolute permeability during gas production, are in excellent agreement with the published pore pressure dependent permeability changes that were obtained independently from history matching the field production data. At a separate site the model correctly predicts, at least qualitatively, a strong permeability rebound at lower drawdown pressures that has been inferred through history matching the production data. An analysis of the effects of initial reservoir pressure on the response of effective horizontal stress to drawdown was carried out, with reference to the range of pressure likely to be encountered in the San Juan basin. The implications of this in terms of pore pressure dependent permeability are discussed.

Use of clay-mineral alteration patterns to define syntectonic permeability of joints (cleat) in Pennsylvania anthracite coal

Joints (cleat) in Pennsylvania anthracite contain two distinct clay-mineral assemblages, both of which formed by alteration of preexisting kaolinite at peak metamorphic conditions during the Alleghanian orogeny. The first assemblage, NH 4-illite or pyrophyllite ± quartz, formed by reaction of kaolinite with methane-rich fluids derived from within the coal. The second assemblage, sudoite ± tosudite ± rectorite ± berthierine, formed by the reaction of kaolinite with ferromagnesian-bearing hydrothermal fluids which must have come from outside the coal. In an earlier paper, we suggested that the first assemblage indicated clay diagenesis in low-permeability environments, and that the second assemblage indicated clay diagenesis in high-permeability environments. If this premise is correct, then the distribution of clay-mineral alteration assemblages serves to define syntectonic permeability variations in coal cleat. The first assemblage dominates in the coal matrix itself, in isolated cleat, in cleat that parallel the regional trend of Alleghanian folds, and in the mirror portions of cleat oriented perpendicular to the fold trends, suggesting that these regions are low-permeability environments. The second assemblage dominates in the hackle fringe of interconnected cleat that trend perpendicular to the strike of the Appalachian orogen, suggesting that these regions are high-permeability environments. Our results emphasize that syntectonic cleat permeability is a function of cleat orientation, macroscopic cleat interconnectivity and orientation, as well as microscopic cleat-surface morphology.

Estimation of changes in fracture porosity of coal with gas emission

This paper discusses the results of a laboratory study aimed at measuring the changes in the coal matrix volume with release of gas, and estimating the resulting changes in the cleat porosity and permeability of coal. The volumetric strain of the matrix of coal samples held at constant external pressure was measured with decreasing concentration of methane. From the results and a simple geometry for fractured reservoirs, the variations in the cleat porosity and permeability with decreasing pressure were estimated. It is shown that the coal matrix volume decreases steadily as the methane pressure decreases. This matrix volumetric strain results in an increase in the cleat porosity of coal of as much as 80%, depending on the initial cleat porosity. This in turn results in as much as a sixfold increase in the cleat permeability of the coal. There is a linear relation between the coal matrix volumetric strain and the quantity of gas desorbed.

Improved Procedures for Collection and Interpretation of Coal-Gas Reservoir Gas Content and Natural Fracture Geometry Data

The validity of quantitative coal-gas reserve analyses depends upon the accuracy of formation evaluation data used as input parameters for reservoir simulation of fluid productivity. Coal-gas reservoir deliverability is strongly influenced by gas-in-place resources, natural fracture (cleat) permeability, and gas desorption and diffusion characteristics. Estimates of these parameters are predicted upon knowledge of coal core-gas content and cleat geometry. Ironically many accepted procedures for collecting and interpreting these data are still incomplete, and therefore coal-gas reserve analyses commonly are erroneous. Improved procedures for collecting and interpreting gas content and cleat geometry data are highlighted using eight Gas Research Institute Fruitland Formation (Upper Cretaceous) wells in the San Juan basin (Colorado and New Mexico). Fruitland gas content values, in places, have been underestimated by 30-85% (786 SCF ton vs. 122 to 557 SCF/ton, dry, mineral-matter-free basis), and therefore the corresponding gas-in-place resource estimates are commensurably conservative. Gas desorption measurements must be performed at reservoir temperature: dry, mineral-matter-free normalizations and canister headspace corrections must be performed correctly; and gas composition must be periodically quantified to correctly estimate the actual methane reserves and sorption time. Collection of cleat geometry data on whole cores is routinely biased because only the most apparent cleat systemsmore » are analyzed. Detailed macroscopic and X-ray radiograph data on cleat geometry for slabbed polished blocks should be collected as a function of bed thickness, lithology, and interconnectivity to further define core-scale cleat permeability and diffusion coefficient distributions.« less