Journal articles on the topic 'Coal matrix shrinkage'
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Zhao, Jun Long, Da Zhen Tang, Hao Xu, Yan Jun Meng, and Yu Min Lv. "A Permeability Model for Undersaturated Coalbed Methane Reservoirs Considering the Coal Matrix Shrinkage Effect." Advanced Materials Research 807-809 (September 2013): 2413–20. http://dx.doi.org/10.4028/www.scientific.net/amr.807-809.2413.
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With the analysis of key elements on the strain state of coal, a permeability dynamic prediction model which is divided by the critical desorption pressure for undersaturated coalbed methane (CBM) reservoirs was established on the basis of pore pressure and considering the matrix shrinkage effect of coal. The law between permeability and pore pressure was analyzed during production with the new model. Through case study, the rationality of the model was also verified. The research shows that the degree of permeability changes mainly depends on the relationship between the critical desorption pressure and the rebound pressure which depends on the strength of the matrix shrinkage. Under the condition of equivalent matrix shrinkage, the reservoirs permeability rebounds better with high Young's modulus and low Poisson's ratio. Adjustment factor contributes to improve the influence of matrix shrinkage on permeability and the larger the matrix shrinkage strength is, the higher the permeability rebounds. PM model and CB model are similar to the new model. PM model limits the matrix shrinkage strength, and CB model is a special case of the new model. Comparing with the well test permeability, the new model is more reasonable to characterize the matrix shrinkage effect in the development process.
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Syahrial, Ego. "Effects Of Matrix Swelling On Coal Permeability For Enhance Coalbed Methane (Ecbm) And Co2 Sequestration Assessment Part I: Laboratory Experiment." Scientific Contributions Oil and Gas 31, no. 3 (March 21, 2022): 1–6. http://dx.doi.org/10.29017/scog.31.3.862.
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It has been reported that coal matrix swelling/shrinkage associated with CO2, adsorption/desorption are typically two to five times larger than that found for methane, yet there has been no direct measurements of this effect on permeability of coals to CO2. The feasibility of ECBM/CO2 sequestration technology depends very much on the magnitude of matrix swelling effect on permeability, especially in deep, low permeability coal seam reservoirs. The main objective of this research is to investigate the effects of coal matrix swelling induced by CO2 adsorption on the permeability of different coals which have been undergoing methane desorption under simulated reservoir conditions in the laboratory. Coal and reservoir properties which may impact upon this behaviour will be identified through extensive laboratory testing. This paper – first of two – presents the procedure for the laboratory tests as well as the findings. In the second part, a field permeability model for enhanced methane recovery and CO2 sequestration, incorporating the findings of the current laboratory tests, would be developed.
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Syahrial, Ego. "Effects Of Matrix Swelling On Coal Permeability For Enhance Coalbed Methane (Ecbm) And Co2 Sequestration Assessment Part Ii: Model Formulation And Field Application." Scientific Contributions Oil and Gas 32, no. 1 (March 17, 2022): 45–55. http://dx.doi.org/10.29017/scog.32.1.832.
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In part II of this two-part paper series, a field permeability model for enhanced methane recovery and CO2 sequestration, incorporating the findings of the current laboratory tests presented in part I is presented. It has been reported that coal matrix swelling/shrinkage associated with CO2, adsorption/desorption are typically two to five times larger than that found for methane, yet there has been no direct measurements of this effect on permeability of coals to CO2. The feasibility of ECBM/CO2 sequestration technology depends very much on the magnitude of matrix swelling effect on permeability, especially in deep, low permeability coal seam reservoirs. The main objective of this research is to investigate and develop numerical models based on the the effects of coal matrix swelling induced by CO2 adsorption on the permeability of different coals which have been undergoing methane desorption under simulated reservoir conditions in the laboratory.
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Robertson, Eric P., and Richard L. Christiansen. "Modeling Laboratory Permeability in Coal Using Sorption-Induced Strain Data." SPE Reservoir Evaluation & Engineering 10, no. 03 (June 1, 2007): 260–69. http://dx.doi.org/10.2118/97068-pa.
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Summary Sorption-induced strain and permeability were measured as a function of pore pressure using subbituminous coal from the Powder River basin of Wyoming, USA, and high-volatile bituminous coal from the Uinta-Piceance basin of Utah, USA. We found that for these coal samples, cleat compressibility was not constant, but variable. Calculated variable cleat-compressibility constants were found to correlate well with previously published data for other coals. Sorption-induced matrix strain (shrinkage/swelling) was measured on unconstrained samples for different gases: carbon dioxide (CO2), methane (CH4), and nitrogen (N2). During permeability tests, sorption-induced matrix shrinkage was demonstrated clearly by higher-permeability values at lower pore pressures while holding overburden pressure constant; this effect was more pronounced when gases with higher adsorption isotherms such as CO2 were used. Measured permeability data were modeled using three different permeability models that take into account sorption-induced matrix strain. We found that when the measured strain data were applied, all three models matched the measured permeability results poorly. However, by applying an experimentally derived expression to the strain data that accounts for the constraining stress of overburden pressure, pore pressure, coal type, and gas type, two of the models were greatly improved. Introduction Coal seams have the capacity to adsorb large amounts of gases because of their typically large internal surface area (30 to 300 m2/g) (Berkowitz 1985). Some gases, such as CO2, have a higher affinity for the coal surfaces than others, such as N2. Knowledge of how the adsorption or desorption of gases affects coal permeability is important not only to operations involving the production of natural gas from coalbeds but also to the design and operation of projects to sequester greenhouse gases in coalbeds (RECOPOL Workshop 2005). As reservoir pressure is lowered, gas molecules are desorbed from the matrix and travel to the cleat (natural-fracture) system, where they are conveyed to producing wells. Fluid movement in coal is controlled by diffusion in the coal matrix and described by Darcy flow in the fracture (cleat) system. Because diffusion of gases through the matrix is a much slower process than Darcy flow through the fracture (cleat) system, coal seams are treated as fractured reservoirs with respect to fluid flow. However, coalbeds are more complex than other fractured reservoirs because of their ability to adsorb (or desorb) large quantities of gas. Adsorption of gases by the internal surfaces of coal causes the coal matrix to swell, and desorption of gases causes the coal matrix to shrink. The swelling or shrinkage of coal as gas is adsorbed or desorbed is referred to as sorption-induced strain. Sorption-induced strain of the coal matrix causes a change in the width of the cleats or fractures that must be accounted for when modeling permeability changes in the system. A number of permeability-change models (Gray 1987; Sawyer et al. 1990; Seidle and Huitt 1995; Palmer and Mansoori 1998; Pekot and Reeves 2003; Shi and Durucan 2003) for coal have been proposed that attempt to account for the effect of sorption-induced strain. Accurate measurement of sorption-induced strain becomes important when modeling the effect of gas sorption on coal permeability. For this work, laboratory measurements of sorption-induced strain were made for two different coals and three gases. Permeability measurements also were made using the same coals and gases under different pressure and stress regimes. The objective of this current work is to present these data and to model the laboratory-generated permeability data using a number of permeability-change models that have been described by other researchers. This work should be of value to those who model coalbed-methane fields with reservoir simulators because these results could be incorporated into those reservoir models to improve their accuracy.
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Yang, Long, Yizhong Zhang, Maolin Zhang, and Bin Ju. "A Novel Semianalytical Model for the Relationship between Formation Pressure and Water Saturation in Coalbed Methane Reservoirs." Energies 16, no. 2 (January 12, 2023): 875. http://dx.doi.org/10.3390/en16020875.
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The accuracy of the relationship between formation pressure and water saturation has a direct impact on predicting the production performance of coal reservoirs. As a result, researchers are becoming more interested in this connection. The most commonly used method to evaluate this connection is the semianalytic method, but it disregards the impact of coal matrix shrinkage on pore compressibility, resulting in inaccurate water saturation estimations for coal reservoirs. A material balance equation that considers the effect of coal matrix shrinkage on cleat porosity and pore compressibility, as well as the gas–water relative permeability curve, is used for the first time in this study to establish a model between pressure and water saturation. Furthermore, this study extends the proposed pressure–saturation model to predict cumulative gas production and gas recovery, resolving the difficult problem of calculating recovery for coalbed methane reservoirs. To verify its accuracy, this study compares the proposed method with numerical simulations and previous methods; the results of the comparison show that the water saturation under formation pressure calculated by the method proposed in this study is closer to the results of the numerical simulation. Sun’s model ignores the effect of matrix shrinkage on pore compressibility, resulting in larger calculation results. The findings of this study indicate that the effect of coal matrix shrinkage on pore compressibility cannot be ignored, and that the proposed method can replace numerical simulation as a simple and accurate method for water saturation evaluation, which can be applied to predict cumulative gas and recovery estimation for closed coalbed methane reservoirs. The proposed method increases the accuracy of the semianalytical method and broadens its application. It is critical for the prediction of coal reservoir production performance and forecasting of production dynamics.
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Su, Xiaoyu, Zengchao Feng, Tingting Cai, and Yongxing Shen. "Coal Permeability Variation during the Heating Process considering Thermal Expansion and Desorption Shrinkage." Adsorption Science & Technology 2022 (March 10, 2022): 1–13. http://dx.doi.org/10.1155/2022/7848388.
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In order to explore the influence of coal deformation caused by temperature and desorption on seepage characteristics in the process of heat injection mining of coalbed methane, the permeability test, thermal expansion, and constant temperature adsorption desorption of coal samples under different temperature and stress states were carried out using the high temperature multifunctional triaxial test system, and the influence of thermal expansion and desorption deformation effect on coal permeability in the process of temperature increase is studied. The results show that (1) with the increase of temperature, the sensitivity of coal thermal expansion deformation to temperature decreases gradually. The thermal expansion deformation makes the coal matrix expand, and the seepage channel is squeezed and the permeability decreases. (2) The effect of thermal expansion deformation is related to the porosity of coal. When the porosity of coal is high, the thermal expansion deformation reduces the permeability; on the contrary, the inward expansion of thermal expansion deformation is limited, and the effect on permeability is weakened. (3) The desorption of coal cause matrix shrinkage. The higher the desorption amount, the more obvious the shrinkage and the higher the permeability. Increasing temperature promotes desorption deformation of coal and increases permeability. (4) In the process of increasing temperature, the change of coal permeability is affected by thermal expansion deformation and desorption deformation. With the increase of temperature, when the influence of thermal expansion deformation on coal permeability is dominant, the permeability decreases gradually, and when desorption deformation is dominant on coal permeability, the permeability increases gradually. (5) With the increase of axial pressure, confining pressure, and pore pressure, the decrease of coal porosity is smaller. When the temperature increases, the temperature corresponding to the minimum permeability point is smaller. The research conclusion provides a basis for the technology of heat injection mining coalbed methane.
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Gorucu, Fatma Burcu, Sinisha A. Jikich, Grant S. Bromhal, W. Neal Sams, Turgay Ertekin, and Duane H. Smith. "Effects of Matrix Shrinkage and Swelling on the Economics of Enhanced-Coalbed-Methane Production and CO2 Sequestration in Coal." SPE Reservoir Evaluation & Engineering 10, no. 04 (August 1, 2007): 382–92. http://dx.doi.org/10.2118/97963-pa.
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Summary Increases in carbon dioxide (CO2) levels in the atmosphere and their contributions to global climate change are a major concern. CO2 sequestration in unmineable coals may be a very attractive option, for economic as well as environmental reasons, if a combination of enhanced-coalbed-methane (ECBM) production and tax incentives becomes sufficiently favorable compared to the costs of capture, transport, and injection of CO2. Darcy flow through cleats is an important transport mechanism in coal. Cleat compression and permeability changes caused by gas sorption/desorption, changes of effective stress, and matrix swelling and shrinkage introduce a high level of complexity into the feasibility of a coal sequestration project. The economic effects of CO2-induced swelling on permeabilities and injectivities has received little (if any) detailed attention. CO2 and methane (CH4) have different swelling effects on coal. In this work, the Palmer-Mansoori model for coal shrinkage and permeability increases during primary methane production was rewritten to also account for coal swelling caused by CO2 sorption. The generalized model was added to a compositional, dual-porosity coalbed-methane reservoir simulator for primary (CBM) and ECBM production. A standard five-spot of vertical wells and representative coal properties for Appalachian coals was used (Rogers 1994). Simulations and sensitivity analyses were performed with the modified simulator for nine different parameters, including coal seam and operational parameters and economic criteria. The coal properties and operating parameters that were varied included Young's modulus, Poisson's ratio, cleat porosity, and injection pressure. The economic variables included CH4 price, CO2 cost, CO2 credit, water disposal cost, and interest rate. Net-present-value (NPV) analyses of the simulation results included profits resulting from CH4 production and potential incentives for sequestered CO2. This work shows that for some coal seams, the combination of compressibility, cleat porosity, and shrinkage/swelling of the coal may have a significant impact on project economics. Introduction In recent years, primary production of natural gas from coal seams has become an important source of energy in the United States. Proven CBM reserves have been estimated at 18.5 Tscf, representing 10% of the total natural-gas reserves in the United States. CBM production started in the early 1980s as a small, high-cost operation but reached 1.6 Tscf in 2002. This was more than 8% of the total US natural-gas production that year (Kuuskraa 2003). The production of CBM reservoirs begins with the pumping of significant volumes of water to lower reservoir pressure and to allow CH4desorption and flow (Stevens et al. 1998). The fraction of the original gas in place typically produced by primary depletion seems to be somewhat controversial. However, according to recent publications, recoveries are often between 20 and 60% of the original gas in place, so that considerable amounts of gas are left behind (Gale and Freund 2001; Stevens et al. 1999; Van Bergen et al. 2001).Because of this, and because of concerns about global warming caused by accumulations of CO2 in the atmosphere (National Energy Technology Laboratory 2003, 2004), new technologies for ECBM production based on the injection of carbon are being investigated in the US, Europe, China, and Japan (Coal-Seq Forum 2004, 2006). In the CO2-ECBM/sequestration process, injected CO2 flows through the cleats in the coal by Darcy flow, diffuses into the coal matrix, and is sorbed by it; CH4 diffuses from the matrix into the cleats, through which it flows to production wells (Sams et al. 2005). The injection of CO2 into coalbeds has many potential advantages: It sequesters CO2, it reduces the production time for CBM, and it increases reserves by improving the recovery of CBM. However, the improved CH4 recovery is accompanied by an increase in costs for CO2 supply, additional drilling, and well and surface equipment. Thus, CO2-ECBM and sequestration are accompanied not only by promised benefits but also by new technical challenges and financial risks.
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Li, Jun Tao. "A New Permeability Model for ECBM and Carbon Dioxide Sequestration Based on Matchsticks Geometry." Materials Science Forum 883 (January 2017): 12–16. http://dx.doi.org/10.4028/www.scientific.net/msf.883.12.
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In the paper a new permeability model based on matchstick model accounting for stress change and matrix shrinkage and swelling caused by gas mixture (CH4 and CO2) is proposed. Finally, a history matching exercise is carried out using field data and experimental data and several models are compared to determine the accuracy of the new model. The modeling results show that the new model can fit the experimental results well. With the exchange of CH4 on coal matrix with CO2, the coal matrix tends to swell and the coal permeability will decrease. So the fracture pressure has better to be high enough to guarantee the easy flow of gases in coal seam. Only when we know the coal permeability change during CO2 injection, can we have better knowledge about the ECBM performance and CO2 sequestration feasibility for a certain coal seam.
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HARPALANI, S., and R. SCHRAUFNAGEL. "Shrinkage of coal matrix with release of gas and its impact on permeability of coal." Fuel 69, no. 5 (May 1990): 551–56. http://dx.doi.org/10.1016/0016-2361(90)90137-f.
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Cheng, Wei, Ruidong Yang, and Qin Zhang. "Origin of a Petrographic Coal Structure and Its Implication for Coalbed Methane Evaluation." Minerals 10, no. 6 (June 16, 2020): 543. http://dx.doi.org/10.3390/min10060543.
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A petrographic coal structure of Late Permian coals from the Liupanshui coalfield, Western Guizhou, SW China, has been distinguished for its novel macro-lithological characteristics. Petrographic, mineralogical and geochemical studies have been conducted for a typical coal sample (No.3 coal, Songhe coalmine, Panzhou County, China) and its geological genesis and significance for coalbed methane (CBM) evaluation is accordingly discussed. It was found that coal is characterized by a banded structure with intensively fractured vitrain sublayers, where a great number of fractures were developed and filled with massive inorganic matter. The study of coal quality, coal petrography, mineralogy and lanthanides and yttrium (REY) geochemistry of the infilling mineral matter (IMM) indicates that this fractured coal structure resulted from the tissues of coal-forming plants or coal matrix shrinkage, as well as the precipitation of calcium rich groundwater and the addition of terrigenous materials. The coal depositional environment and coal-forming plant are considered to have played a role in inducing the special fractures. This provides a scientific reference for the study of CBM for coal with this fractured structure, such as the Late Permian coal from the western border of Guizhou Province, SW China.
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Wang, Chunguang, Yuxiao Zang, Linsen Wang, Zhongwei Chen, Guanglei Cui, Kunkun Fan, and Weitao Liu. "Interaction of Cleat-Matrix on Coal Permeability from Experimental Observations and Numerical Analysis." Geofluids 2019 (November 18, 2019): 1–15. http://dx.doi.org/10.1155/2019/7474587.
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Gas transport through porous coal contains gas laminar flow in the cleat network and gas adsorption/diffusion in the matrix block. Since permeable capacity of the cleat is greater than that of the matrix, change of the matrix pressure readily lags behind change in the cleat pressure. Such unsynchronized pressure changes can result in a complex compatible deformation of a cleat-matrix system, significantly affecting the coal permeability. In this paper, we investigated the cleat-matrix interaction on coal permeability by using a modified pressure pulse decay method integrated with numerical analysis. The experimental results indicate that the bulk volume of the coal sample rapidly expanded at the beginning of gas injection, and then the volume expansion rate of the coal sample slowed down as the downstream pressure of the coal sample gradually equilibrated with the upstream pressure. During this process, the coal permeability was observed to gradually decrease with time. Numerical analysis results indicate that gas transport from the cleat to the matrix can attenuate the differential pressure between the cleat and the matrix. A smaller ratio of initial matrix permeability to initial cleat permeability can prolong decay duration of the differential pressure inside the cleat-matrix system. Although the coal sample is subjected to a stress-controlled condition, the coal permeability response to gas diffusion is closer to the case using a constant volume boundary. The dynamic change of coal permeability is significantly affected by the cleat-matrix interaction, in cases where the short-term change is mainly attributable to the cleat network and the long-term change is controlled by matrix swelling/shrinkage.
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Li, Bo, Junxiang Zhang, Zhiben Ding, Bo Wang, and Peng Li. "A dynamic evolution model of coal permeability during enhanced coalbed methane recovery by N2 injection: experimental observations and numerical simulation." RSC Advances 11, no. 28 (2021): 17249–58. http://dx.doi.org/10.1039/d1ra02605d.
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A dynamic evolution model of coal permeability during CH4 displacement by N2 injection was proposed, considering the combined effects of matrix swelling/shrinkage and effective stress, for providing a reference on N2-ECBM.
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Gao, Xu, Chao Liu, Zhonghe Shui, and Rui Yu. "Effects of Expansive Additives on the Shrinkage Behavior of Coal Gangue Based Alkali Activated Materials." Crystals 11, no. 7 (July 14, 2021): 816. http://dx.doi.org/10.3390/cryst11070816.
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The suitability of applying shrinkage reducing additives in alkali activated coal gangue-slag composites is discussed in this study. The effect of sulphoaluminate cement (SAC), high performance concrete expansion agent (HCSA) and U-type expansion agent (UEA) on the reaction process, shrinkage behavior, phase composition, microstructure and mechanical properties are evaluated. The results show that the addition of SAC slightly mitigates the early stage reaction process, while HCSA and UEA can either accelerate or inhibit the reaction depending on their dosage. The addition of SAC presents an ideal balance between drying shrinkage reduction and strength increment. As for HCSA and UEA, the shrinkage and mechanical properties are sensitive to their replacement level; excessive dosage would result in remarkable strength reduction and expansion. The specific surface area and average pore size of the hardened matrix are found to be closely related with shrinkage behavior. SAC addition introduces additional hydrotalcite phases within the reaction products, while HCSA and UEA mainly result in the formation of CaCO3 and Ca(OH)2. It is concluded that applying expansive additives can be an effective approach in reducing the drying shrinkage of alkali activated coal gangue-slag mixtures, while their type and dosage must be carefully handled.
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Dunlop, Erik C. "A new concept for the extraction of gas from Permian ultra-deep coal seams of the Cooper Basin, Australia: Expanding Reservoir Boundary Theory." APPEA Journal 60, no. 1 (2020): 296. http://dx.doi.org/10.1071/aj19011.
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An alternative geomechanical reservoir boundary condition is proposed for ultra-deep coal seams of the Cooper Basin in central Australia. This new concept is embodied within the author’s ‘Expanding Reservoir Boundary (ERB) Theory’, which calls for a paradigm shift in gas extraction technology, diametrically opposed to current practices. As with shale, full-cycle, standalone commercial gas production from Cooper Basin ultra-deep coal seams requires a large stimulated reservoir volume (SRV) having high fracture surface area for gas desorption. This goal has not yet been achieved after 13 years of trials because, owing to the bipolar combination of shale-like reservoir properties and coal-like geomechanical properties, these poorly cleated, inertinitic coal seams exhibit ‘hybrid’ characteristics. Stimulation techniques adopted from other play types are incompatible with the highly unfavourable combination of nanoDarcy-scale permeability, ‘ductility’ and high stress. Nevertheless, gas flow potential counterintuitively increases with depth, contingent upon the creation of an effective SRV. Optimum reservoir conditions occur at depths beyond 9000 feet (2740 m), driven by dehydration, high gas content, gas oversaturation, overpressure and a rigid host rock framework. The physical response of ultra-deep coal seams and the surrounding host rock to pressure drawdown is inadequately characterised. It remains to be established how artificial fracture and coal fabric aperture width change due to the competition between desorption-induced coal matrix shrinkage and compaction caused by increasing effective stress. Studies by the author suggest that pressure arching may ultimately control gas extraction efficiency. Harnessing this geomechanical phenomenon could resolve the technical impasse that currently inhibits commercialisation. Pressure arching neutralises SRV compaction by deflecting stress to adjacent strata of greater integrity. These strata then function as an abutment for accommodating increased stress outside the SRV. This shielding effect allows producing ultra-deep coal seams to progressively de-stress and ‘self-fracture’ naturally, in an overall state of shrinkage-induced tensile failure. An ‘expanding reservoir boundary and decreasing confining stress’ condition is generated by the combined, mutually sustaining actions of coal matrix shrinkage and sympathetic pressure arch evolution. This causes the SRV to steadily increase in size and permeability. Cooper Basin ultra-deep coal seams may be effectively stimulated by harnessing this self-perpetuating, depth-resistant mechanism for creating permeability and surface area. The ultra-deep coal seams may be induced to pervasively ‘shatter’ or ‘self-fracture’ naturally during production, independent of ‘brittleness’, analogous to the manner in which shrinkage crack networks slowly form, in a state of intrinsic tension, within desiccating clay-rich surface sediment.
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Syahrial, Ego. "Reservoir Simulator For Improved Recovery Of Coalbed Methane (Icbm) Part Ii : Effect Of Coal Matrix Swelling And Shrinkage." Scientific Contributions Oil and Gas 32, no. 3 (March 17, 2022): 193–200. http://dx.doi.org/10.29017/scog.32.3.850.
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Sequestration of CO2 in deep unmined coal seams is currently under development for improved recovery of coalbed methane (ICBM) as well as permanent storage of CO2. Recent studies have shown that CO2 displaces methane by adsorbing more readily onto the coal matrix compared to other greenhouse gases, and could therefore contribute towards reducing global warming. In order to carry out a more accurate assessment of the potential of ICBM and CO2 sequestration, field based numerical simulations are required. Existing simulators for primary CBM (coalbed methane) recovery cannot be applied since the process of CO2 injection in partially desorbed coalbeds is highly complex and not fully understood. The principal challenges encountered in numerical modelling of ICBM/CO2 sequestration processes which need to be solved include: (1) two-phase flow, (2) multiple gas components, (3) impact of coal matrix swelling and shrinkage on permeability, and (4) mixed gas sorption. This part II of this two-part paper series describes the development of a compositional simulator with the impact of matrix shrinkage/swelling on the production performance on primary and echanced recovery of coalbed methane. The numerical results for enhanced recovery indicate that matrix swelling associated with CO2 injection could results in more than an order of magnitude reduction in formation permeability around the injection well, hence prompt decline in well injectivity. The model prediction of the decline in well injectivity is consistent with the reported field observations in San Juan Basin USA. Also, a parametric study is conducted using this simulator to investigate the effects of coal properties on the enhancement of methane production efficiency based on published data.
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Ma, Dong Min, Ya Bing Lin, and Wei Ma. "Temperature-Rising Desorption of CBM." Advanced Materials Research 524-527 (May 2012): 364–70. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.364.
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In order to study the effects of CBM temperature-rising desorption, the isothermal adsorption /desorption experiments on three coal-ranks （anthracite，coking coal and lignite）at different temperatures were designed based on the traditional CBM decompression desorption. The experimental results show that temperature-rising desorption is more effective in high-rank coal and raising the temperature of high-rank coal reservoir can reduce the negative effect of Coal Matrix Shrinkage in the process of production and improve the permeability of coal reservoir. It is also revealed that the technique of temperature-rising desorption used in higher-rank coal reservoir can enhance CBM recovery ratio. This study has provided theoretical support for the application of temperature-rising desorption technique to practical diacharging and mining projects and can effectively solve gas production “bottleneck” problem.
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Palmer, Ian, and John Mansoori. "How Permeability Depends on Stress and Pore Pressure in Coalbeds: A New Model." SPE Reservoir Evaluation & Engineering 1, no. 06 (December 1, 1998): 539–44. http://dx.doi.org/10.2118/52607-pa.
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This paper (SPE 52607) was revised for publication from paper SPE 36737, first presented at the 1996 SPE Annual Technical Conference & Exhibition, Denver, 6-9 October. Original manuscript received for review 25 October 1996. Revised manuscript received 17 August 1998. Paper peer approved 1 September 1998. Summary In naturally fractured formations such as coal, permeability is sensitive to changes in stress or pore pressure (i.e., changes in effective stress). This paper presents a new theoretical model for calculating pore volume (PV) compressibility and permeability in coals as a function of effective stress and matrix shrinkage, by means of a single equation. The equation is appropriate for uniaxial strain conditions, as expected in a reservoir. The model predicts how permeability changes as pressure is decreased (i.e., drawdown). PV compressibility is derived in this theory from fundamental reservoir parameters. It is not constant, as often assumed. PV compressibility is high in coals because porosity is so small. A rebound in permeability can occur at lower drawdown pressures for the highest modulus and matrix shrinkage values. We have also history matched rates from a boomer well in the fairway of the San Juan basin by use of various stress-dependent permeability functions. The best fit stress/permeability function is then compared with the new theory. P. 539
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Anggara, Ferian, Kyuro Sasaki, and Yuichi Sugai. "NUMERICAL MODELLING AND SIMULATION OF CO2 –ENHANCED COAL-BED METHANE RECOVERY (CO2-ECBMR): THE EFFECT OF COAL SWELLING ON GAS PRODUCTION PERFORMANCE." Journal of Applied Geology 7, no. 2 (July 27, 2015): 102. http://dx.doi.org/10.22146/jag.26983.
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This presents study investigate the effect of swelling on gas production performances at coal reservoirs during CO2-ECBMR processes. The stressdependent permeability-models to express effect of coal matrix shrinkage/swelling using Palmer and Mansoori (P&M) and Shi and Durucan (S&D) models were constructed based on present experimental results for typical coal reservoirs with the distance of 400 to 800 m between injection and production wells. By applying the P&M and S&D models, the numerical simulation results showed that CH4 production rate was decreasing and peak production time was delayed due to effect of stress and permeability changes caused by coal matrix swelling. The total CH4 production ratio of swelling effect/no-swelling was simulated as 0.18 to 0.95 for permeability 1 to 100 mD, respectively. It has been cleared that swelling affects gas production at permeability 1 to 15 mD, however, it can be negligible at permeability over 15 mD.
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Robertson, Eric P., and Richard L. Christiansen. "A Permeability Model for Coal and Other Fractured, Sorptive-Elastic Media." SPE Journal 13, no. 03 (September 1, 2008): 314–24. http://dx.doi.org/10.2118/104380-pa.
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Summary This paper describes the derivation of a new equation that can be used to model the permeability behavior of a fractured, sorptive-elastic medium, such as coal, under variable stress conditions. The equation is applicable to confinement pressure schemes commonly used during the collection of permeability data in the laboratory. The model is derived for cubic geometry under biaxial or hydrostatic confining pressures. The model is designed to handle changes in permeability caused by adsorption and desorption of gases onto and from the matrix blocks in fractured media. The model equations can be used to calculate permeability changes caused by the production of methane (CH4) from coal as well as the injection of gases, such as carbon dioxide, for sequestration in coal. Sensitivity analysis of the model found that each of the input variables can have a significant impact on the outcome of the permeability forecast as a function of changing pore pressure; thus, accurate input data are essential. The permeability model also can be used as a tool to determine input parameters for field simulations by curve fitting laboratory-generated permeability data. The new model is compared to two other widely used coal-permeability models using a hypothetical coal with average properties. Introduction During gas production from a coal seam, as reservoir (pore) pressure is lowered, gas molecules, such as CH4, are desorbed from the matrix and travel by diffusion to the cleat (natural-fracture) system where they are conveyed to producing wells. Fluid movement in coal is controlled by slow diffusion within the coal matrix and is described by Darcy flow within the fracture system, which is much faster than the contribution of diffusion. A coal formation typically is treated as a fractured reservoir with respect to fluid flow, meaning that the sole contributor to the overall permeability of the reservoir is the fracture system, and the contribution of diffusion through the matrix to total flow is neglected. Coalbeds are unlike other nonreactive fractured reservoirs because of their ability to adsorb (or desorb) large amounts of gas, which causes swelling (or shrinkage) of the matrix blocks. Coalbeds have the capacity to adsorb large amounts of gases because of their typically large internal-surface areas, which can range from 30 to 300 m2/g (Berkowitz 1985). Some gases, such as carbon dioxide, have a higher affinity for the coal surfaces than others, such as nitrogen (N2). Knowledge of how the adsorption or desorption of gases affects coal permeability is important not only to operations involving the production of natural gas from coalbeds, but also to the design and operation of projects to sequester greenhouse gases in coalbeds (RECOPOL 2005). Laboratory measurements of permeability using coal samples can be used to gain insight into field-scale permeability changes and to determine key-coal-property values necessary for field-scale simulation. A number of permeability models derived for sorptive-elastic media such as coals have been detailed in the literature and include those proposed by Gray (1987), Sawyer et al. (1990), Seidle and Huitt (1995), Palmer and Mansoori (1998), Pekot and Reeves (2003), and Shi and Durucan (2003). These models were derived to mimic field conditions, and they assume a matrix-block geometry described as a bundle of vertical matchsticks under a uniaxial stress regime (Palmer and Mansoori 1998; Seidle et al. 1992). However, in the laboratory, permeability typically is measured by use of hydrostatic (biaxial) core holders, which apply a single confining pressure to all external points of the core inside the holder. This is obviously different from the stress conditions encountered in the field, which typically are characterized as being under uniaxial stress as noted previously. Moreover, on a laboratory scale, coal matrix blocks may be approximated better by cubic instead of matchstick geometry, as will be discussed later in this paper. A recent study (Robertson and Christiansen 2005c) compared the accuracy of three field-permeability models when applied to laboratory-generated, sorption-affected permeability data and found that none of the three was able to match the data accurately. A model specifically derived for laboratory coreflooding conditions would be expected to provide a more reasonable match of permeability results. This paper describes the derivation of a new model that describes the permeability behavior of a fractured, sorptive-elastic medium, such as coal, under typical laboratory conditions where common radial and axial pressures are applied to a core sample during permeability measurements. The new model can be applied to fractured rock formations where the matrix blocks contribute neither to the porosity nor to the permeability of the overall system, but where adsorption and desorption of gases by the matrix blocks cause measurable swelling and shrinkage, respectively, and thus affect permeability.
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Levine, Jeffrey R. "Model study of the influence of matrix shrinkage on absolute permeability of coal bed reservoirs." Geological Society, London, Special Publications 109, no. 1 (1996): 197–212. http://dx.doi.org/10.1144/gsl.sp.1996.109.01.14.
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Mazumder, Saikat, Michael Scott, and Jessica Jiang. "Permeability increase in Bowen Basin coal as a result of matrix shrinkage during primary depletion." International Journal of Coal Geology 96-97 (July 2012): 109–19. http://dx.doi.org/10.1016/j.coal.2012.02.006.
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Connell, Luke D., S. Mazumder, Regina Sander, Michael Camilleri, Zhejun Pan, and Deasy Heryanto. "Laboratory characterisation of coal matrix shrinkage, cleat compressibility and the geomechanical properties determining reservoir permeability." Fuel 165 (February 2016): 499–512. http://dx.doi.org/10.1016/j.fuel.2015.10.055.
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Thompson, Matthew B., Jan Bon, Mike Vatan, and Mohammad Zaman. "Effects of rapid gas decompression on coal seam gas swellables." APPEA Journal 62, no. 2 (May 13, 2022): S187—S191. http://dx.doi.org/10.1071/aj21166.
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Thousands of non-stimulated coal seam gas (CSG) wells in Queensland’s Surat Basin rely on swellable packers as the first line of defence against interburden solids production and poor well run life. This paper is aimed at understanding some of the impacts of long-term well operations on swellable performance from rapid changes in downhole pressure. For the first time, rapid gas decompression (RGD) effects on CSG swellables were experimented on in a quantitative manner as an analogue to underbalanced workover and pump trip conditions. RGD has the potential to break down swellables due to rapid release of high-pressure methane diffused in the rubber matrix resulting in a flow path for interburden solids. Five commonly available swellables from the CSG market were lab-tested for rapid decompression with methane at operational conditions. Coupon samples were swollen to representative conditions and placed in an autoclave under high-pressure methane, then rapidly decompressed in cycles. Results of this study showed relatively low levels of physical degradation under test conditions but shrinkage effects varied between products largely grouped into material properties, confirmed with separate ambient shrinkage test. As such, the focus on swellable placement geometry remains paramount.
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Syahrial, Ego. "Reservoir Simulator For Improved Recovery Of Coalbed Methane (Icbm) Part I: Model Formulation And Comparison." Scientific Contributions Oil and Gas 32, no. 3 (March 17, 2022): 169–78. http://dx.doi.org/10.29017/scog.32.3.848.
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Sequestration of CO2 in deep unmined coal seams is currently under development for improved recovery of coalbed methane (ICBM) as well as permanent storage of CO2. Recent studies have shown that CO2 displaces methane by adsorbing more readily onto the coal matrix compared to other greenhouse gases, and could therefore contribute towards reducing global warming. In order to carry out a more accurate assessment of the potential of ICBM and CO2 sequestration, field based numerical simulations are required. Existing simulators for primary CBM (coalbed methane) recovery cannot be applied since the process of CO2 injection in partially desorbed coalbeds is highly complex and not fully understood. The principal challenges encountered in numerical modelling of ICBM/CO2 sequestration processes which need to be solved include: (1) two-phase flow, (2) multiple gas components, (3) impact of coal matrix swelling and shrinkage on permeability, and (4) mixed gas sorption. The objective of this part I of this two-part paper series is to develop a two-phase, multi-component CH4-CO2 simulator for use in the assessment of CO2-ICBM recovery and CO2 sequestration potential of coal seams. The developed formulation was tested and compared to model the improved coalbed methane (ICBM) recovery with pure CO2 injection using a published data.
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Yan, Xinlu, Songhang Zhang, Shuheng Tang, Zhongcheng Li, Yongxiang Yi, Qian Zhang, Qiuping Hu, and Yuxin Liu. "A Comprehensive Coal Reservoir Classification Method Base on Permeability Dynamic Change and Its Application." Energies 13, no. 3 (February 3, 2020): 644. http://dx.doi.org/10.3390/en13030644.
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Due to the unique adsorption and desorption characteristics of coal, coal reservoir permeability changes dynamically during coalbed methane (CBM) development. Coal reservoirs can be classified using a permeability dynamic characterization in different production stages. In the single-phase water flow stage, four demarcating pressures are defined based on the damage from the effective stress on reservoir permeability. Coal reservoirs are classified into vulnerable, alleviative, and invulnerable reservoirs. In the gas desorption stage, two demarcating pressures are used to quantitatively characterize the recovery properties of permeability based on the recovery effect of the matrix shrinkage on permeability, namely the rebound pressure (the pressure corresponding to the lowest permeability) and recovery pressure (the pressure when permeability returns to initial permeability). Coal reservoirs are further classified into recoverable and unrecoverable reservoirs. The physical properties and influencing factors of these demarcating pressures are analyzed. Twenty-six wells from the Shizhuangnan Block in the southern Qinshui Basin of China were examined as a case study, showing that there is a significant correspondence between coal reservoir types and CBM well gas production. This study is helpful for identifying geological conditions of coal reservoirs as well as the productivity potential of CBM wells.
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Chu, Yapei, Jianguo Zhang, Dongming Zhang, Man Wang, Yujie Wang, and Zehua Niu. "Experimental study on the fissure structure and permeability evolution characteristics of coal under liquid nitrogen freezing and freeze–thaw." Physics of Fluids 34, no. 12 (December 2022): 126601. http://dx.doi.org/10.1063/5.0125381.
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Liquid nitrogen (LN2) fracturing technology as a kind of waterless fracturing technology has received extensive attention in recent years. In order to investigate the evolution law of fissure structure and seepage characteristics of coal samples under LN2 freezing and freeze–thaw, the evolution of fissure of coal samples before and after LN2 freeze–thaw was monitored by micro-computed tomography, the change of permeability of coal samples under different LN2 freezing time and freeze–thaw cycles was measured, and the damage mechanism of LN2 freezing and freeze–thaw to coal was discussed. The experimental results show that (1) LN2 freeze–thaw can cause the shrinkage of the coal matrix, resulting in damage to the fissure structure of the coal sample, which promotes the initiation, expansion, and extension of fissure of coal sample to form new fissure and, finally, forms a fracture network. (2) The permeability and the increment of permeability of coal samples increase with increase of LN2 freezing time and the number of freeze–thaw cycles under different gas pressure and confining pressure condition. (3) Under the same freezing time, the permeability growth rate of coal samples under LN2 freeze–thaw condition is significantly greater than that of coal samples under LN2 freezing condition. (4) The frost-heave force and thermal stress are the main factors leading to the damage, promoting fissure formation and increasing permeability of coal samples LN2 freezing and freeze–thaw. This study provides a theoretical basis for the understanding of fracturing technology with LN2.
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Wei, Mingyao, Chun Liu, Yingke Liu, Jishan Liu, Derek Elsworth, Osvaldo A. F. A. Tivane, and Chao Li. "Long-term effect of desorption-induced matrix shrinkage on the evolution of coal permeability during coalbed methane production." Journal of Petroleum Science and Engineering 208 (January 2022): 109378. http://dx.doi.org/10.1016/j.petrol.2021.109378.
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Reisabadi, Mohammadreza Zare, Manouchehr Haghighi, Mohammad Sayyafzadeh, and Abbas Khaksar. "Effect of matrix shrinkage on wellbore stresses in coal seam gas: An example from Bowen Basin, east Australia." Journal of Natural Gas Science and Engineering 77 (May 2020): 103280. http://dx.doi.org/10.1016/j.jngse.2020.103280.
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Connell, L. D. "A new interpretation of the response of coal permeability to changes in pore pressure, stress and matrix shrinkage." International Journal of Coal Geology 162 (May 2016): 169–82. http://dx.doi.org/10.1016/j.coal.2016.06.012.
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Wang, Man, and Junpeng Zou. "A Novel Permeability Model of Coal Considering Gas Slippage and Gas Sorption-Induced Strain." Energies 15, no. 16 (August 20, 2022): 6036. http://dx.doi.org/10.3390/en15166036.
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As an unconventional natural gas, coalbed methane (CBM) has been recognized as a significant fuel and chemical feedstock that should be recovered. Permeability is a key factor that controls CBM transport in coal. The slippage effect is an influential phenomenon that occurs during gas penetration processes, especially in low-permeable media. Apparent permeability may differ greatly from intrinsic permeability due to gas slippage. However, the gas slippage effect has not been considered in most analytical permeability models. Based on the cubic law, a new analytical model suited for the permeability analysis of coal under different stress conditions is derived, taking into consideration gas slippage and matrix shrinkage/swelling due to gas desorption/adsorption. To enhance its application, the model is derived under constant hydrostatic stress and pore pressure. The new analytical model is then compared with the existing models, and its reliability is verified by the comparison between the analytical prediction and the experimental permeability data under different stress conditions.
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Zang, Jie, Ze Ma, Yong Ge, and Chengxin Li. "Influences of Coal Properties on the Principal Permeability Tensor during Primary Coalbed Methane Recovery: A Parametric Study." Geofluids 2021 (August 14, 2021): 1–17. http://dx.doi.org/10.1155/2021/2097503.
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Coal permeability is intrinsically anisotropic because of the cleat structure of coal. Therefore, coal permeability can be denoted by a second-order tensor under three-dimensional conditions. Our previous paper proposed an analytical model of the principal permeability tensor of coal during primary coalbed methane (CBM) recovery. Based on this model, 18 modeling cases were considered in the present study to evaluate how the principal permeabilities were influenced by representative coal properties (the areal porosity, the internal swelling ratio, and the Young modulus) during primary CBM recovery. The modeling results show that with regard to the influences of the areal porosity on the principal permeabilities, an increase in cleat porosity reduces the sensitivity of each principal permeability to pore pressure change. The magnitudes of the principal permeabilities are positively proportional to the internal swelling ratio. The principal permeabilities thus tend to monotonically increase with a depletion in the pore pressure when the internal swelling ratio increases. Because the internal swelling ratio represents the extent of gas-sorption-induced matrix deformation, an increase in the internal swelling ratio increases desorption-induced matrix shrinkage and thus induces an increase in permeability. The principal permeabilities are positively proportional to the isotropic principal Young moduli and the synchronously changing anisotropic principal Young moduli. On the other hand, the principal Young modulus within the plane of isotropy influences the principal permeabilities within this plane in diverse patterns depending on both the dip angle of the coalbed and the pitch angle of the cleat sets. The principal permeability perpendicular to the plane of isotropy is positively proportional to this principal Young modulus, and this correlation pattern is independent of both the dip angle and pitch angle.
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Hu, Qiujia, Shiqi Liu, Shuxun Sang, Huihuang Fang, Ashutosh Tripathy, Ling Yan, Mengfu Qin, and Chonghao Mao. "Numerical analysis of drainage rate for multilayer drainage coalbed methane well group in Southern Qinshui basin." Energy Exploration & Exploitation 38, no. 5 (August 6, 2020): 1535–58. http://dx.doi.org/10.1177/0144598720946494.
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Multilayer drainage is one of the important technologies for coalbed methane (CBM) production in China. In this study, a multi-field fully coupled mathematical model for CBM production was established to analyze the multilayer drainage of CBM well group in southern Qinshui basin. Based on the numerical simulation results, the characteristics of CBM well production under different drainage rates and key factors influencing the CBM production were further discussed. The results show that the effect of an increased drainage rate on gas production of CBM wells and CBM recovery of No.3 coal seam is not significant. However, it significantly improved the gas production of CBM wells and CBM recovery of No.15 coal seam. After a long period of production, the CBM content in No.3 coal seam has reduced to a low level and the pressure drop potential of No.3 coal seam is insignificant, which are important reasons for the insignificant increase of CBM production even under a drainage rate of 2 to 7 times. Conversely, No.15 coal seam has larger residual CBM content and increasing the drainage rate can significantly improve the pressure drop and superimposed well interference of No.15 coal seam, which means No.15 coal seam has greater production potential than No.3 coal seam. Therefore, it is recommended to improve the gas production and CBM recovery in No.15 coal seam by increasing the drainage rate, and the average hydraulic pressure drop should be 0.018–0.031 MPa/day. The influence of effective stress is weak in No.3 and No.15 coal seam, and the coal seam permeability is largely influenced by the shrinkage of coal matrix caused by CBM desorption. This indicates the feasibility of increase in gas production from CBM wells by increasing the drainage rate.
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Zhang, Lei, Chen Jing, Shugang Li, Ruoyu Bao, and Tianjun Zhang. "Seepage Law of Nearly Flat Coal Seam Based on Three-Dimensional Structure of Borehole and the Deep Soft Rock Roadway Intersection." Energies 15, no. 14 (July 8, 2022): 5012. http://dx.doi.org/10.3390/en15145012.
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Exploring the evolution characteristics of gas seepage between boreholes during the drainage process is critical for the borehole’s layout and high-efficiency gas drainage. Based on the dual-porous medium assumption and considering the effect of stress redistribution on coal seam gas seepage characteristics, a coal seam gas seepage model with a three-dimensional roadway and borehole crossing structure has been established and numerically calculated, concluding that the coal seam is between the drainage boreholes. The temporal and spatial evolution characteristics of gas pressure and permeability help elucidate the gas seepage law of the nearly flat coal seam associated with the deep soft rock roadway and borehole intersection model. The results indicate that: (1) The roadway excavation results in localized stress in some areas of the surrounding rock, reducing the strength of the coal body, increasing the expansion stress, and increasing the adsorption of gas by the coal body. (2) Along the direction of the coal seam, the permeability decreases initially and then increases. The gas pressure in the coal seam area in the middle of the borehole is higher than the pressure in the coal seam around the borehole, and the expansion stress and deformation increase, reducing the permeability of the coal body; when near the next borehole, the greater the negative pressure, the faster the desorption of the gas attracts the matrix shrinkage effect and causes the coal seam permeability rate to keep increasing. (3) The improvement of gas drainage with the overlapping arrangement of two boreholes firstly increases and then decreases as time goes on. (4) When the field test results and numerical simulation of the effective area of gas extraction are compared, the effectiveness of the model is verified. Taking the change of the porosity and the permeability into the model, it is able to calculate the radius of gas drainage more accurately.
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Gao, Changjing, Dameng Liu, Zhentao Li, Yidong Cai, and Yufeng Fang. "Fluid Performance in Coal Reservoirs: A Comprehensive Review." Geofluids 2021 (April 1, 2021): 1–33. http://dx.doi.org/10.1155/2021/6611075.
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The fluids in coal reservoirs mainly consist of different gases and liquids, which show different physical properties, occurrence behaviors, and transport characteristics in the pore-fracture system of coal. In this study, the basic characteristics of fluids in coal reservoirs are firstly reviewed, consisting of coalbed methane (CBM) components and physical properties of CBM/coalbed water. The complex pore-fracture system mainly provides the enrichment space and flow path for fluids, which have been qualitatively and quantitatively characterized by various methods in recent years. Subsequently, this study has summarized CBM adsorption/desorption behaviors and models, the CBM diffusion-seepage process and models, and gas-water two-phase flow characteristics of coal reservoirs. Reviewed studies also include the effects of internal factors (such as coal metamorphism, petrographic constituents, macroscopic types, and pore structure) and external factors (such as pressure, temperature, and moisture content) on CBM adsorption/desorption and diffusion behaviors, and the relationship between three main effects (effective stress, gas slippage effect, and coal matrix shrinkage effect) and the CBM seepage process. Moreover, we also discuss in depth the implication of fluid occurrence and transport characteristics in coal reservoirs for CBM production. This review is aimed at proposing some potential research directions in future studies, which mainly includes the control mechanism of the microscopic dynamics of fluids on CBM enrichment/storage; enhancing CBM desorption/seepage rate; and the synergistic effect of multiple spaces, multilevel flow fields, and multiphase flow in coal reservoirs. From this review, we have a deeper understanding of the occurrence and transport characteristics of fluids in pore-fracture structures of coal and the implication of fluid performance for CBM production. The findings of this study can help towards a better understanding of gas-water production principles in coal reservoirs and enhancing CBM recovery.
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Zhao, Tiantian, Hao Xu, Dazhen Tang, and Peng Zong. "Dual mechanisms of matrix shrinkage affecting permeability evolution and gas production in coal reservoirs: Theoretical analysis and numerical simulation." Journal of Natural Gas Science and Engineering 108 (December 2022): 104844. http://dx.doi.org/10.1016/j.jngse.2022.104844.
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Thararoop, Prob, Zuleima T. Karpyn, and Turgay Ertekin. "Development of a material balance equation for coalbed methane reservoirs accounting for the presence of water in the coal matrix and coal shrinkage and swelling." Journal of Unconventional Oil and Gas Resources 9 (March 2015): 153–62. http://dx.doi.org/10.1016/j.juogr.2014.12.002.
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Dunlop, Erik C., David S. Warner, Prue E. R. Warner, and Louis R. Coleshill. "Ultra-deep Permian coal gas reservoirs of the Cooper Basin: insights from new studies." APPEA Journal 57, no. 1 (2017): 218. http://dx.doi.org/10.1071/aj16015.
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There is a vast, untapped gas resource in deep coal seams of the Cooper Basin, where extensive legacy gas infrastructure facilitates efficient access to markets. Proof-of-concept for the 5 million acre (20 000km2) Cooper Basin Deep Coal Gas (CBDCG) Play was demonstrated by Santos Limited in 2007 during the rise of shale gas. Commercial viability on a full-cycle, standalone basis is yet to be proven. If commercial reservoirs in nanoDarcy matrix permeability shale can be manufactured by engineers, why not in deep, dry, low-vitrinite, poorly cleated coal seams having comparable matrix permeability but higher gas content? Apart from gas being stored in a source rock reservoir format, there is little similarity to other unconventional plays. Without an analogue, development of an optimal reservoir stimulation technology must be undertaken from first principles, using deep coal-specific geotechnical and engineering assumptions. Results to date suggest that stimulation techniques for other unconventional reservoirs are unlikely to be transferable. A paradigm shift in extraction technology may be required, comparable to that devised for shale reservoirs. Recent collaborative studies between the South Australian Department of State Development, Geological Survey of Queensland and Geoscience Australia provide new insight into the hydrocarbon generative capacity of Cooper Basin coal seams. Sophisticated regional modelling relies upon a limited coal-specific raw dataset involving ~90 (5%) of the total 1900 wells penetrating Permian coal. Complex environmental overprints affecting resource concentration and gas flow capacity are not considered. Detailed resource estimation and the detection of anomalies such as sweet spots requires the incorporation of direct measurement. To increase granularity, the authors are conducting an independent, basin-wide review of underutilised open file data, not yet used for unconventional reservoir purposes. Reservoir parameters are quantified for seams thicker than 10feet (3m), primarily using mudlogs and electric logs. To date, ~3750 reservoir intersections are characterised in ~1000 wells. Some parameters relate to resource, others to extraction. A gas storage proxy is generated, not compromised by desorption lost gas corrections. A 2016 United States Geological Survey resource assessment, based on Geoscience Australia studies, suggests that the Play remains a world-class opportunity, despite being technology-stranded for the past 10years. Progress has been made in achieving small but incrementally economic flow rates from add-on hydraulic fracture stimulation treatments inside conventional gas fields. Nevertheless, a geology/technology impasse precludes full-cycle, standalone commercial production. A review of open file data and cross-industry literature suggests that the root cause is the inability of current techniques to generate the massive fracture network surface area essential for high gas flow. Coal ductility and high initial reservoir confining stress are interpreted to be responsible. Ultra-deep coal reservoirs, like shale reservoirs, must be artificially created by a large-scale stimulation event. Although coal seams fail the reservoir ‘brittleness test’ for shale reservoir stimulation practices, the authors conclude from recent studies that pervasive, mostly cemented or closed coal fabric planes of weakness may instead be reactivated on a large scale, to create a shale reservoir-like stimulated reservoir volume (SRV), by mechanisms which harness the reservoir stress reduction capacity of desorption-induced coal matrix shrinkage.
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Olajossy, Andrzej, and Jerzy Cieślik. "Why Coal Bed Methane (CBM) Production in Some Basins is Difficult." Energies 12, no. 15 (July 29, 2019): 2918. http://dx.doi.org/10.3390/en12152918.
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The changes in the permeability of coal-bed reservoirs with methane, as associated with gas depletion, are the consequence of two opposing processes, namely geomechanical compaction that narrows down fractures, and matrix shrinkage, which, in turn, widens fractures. Many previous studies on the effects of these processes have emphasised, albeit not always, the circumstances and conditions that led to a greater coal permeability, with a natural decrease in the pore pressure of methane during its production, and, in consequence, to an increase in the cumulative volume of this gas. However, in some coal basins, there are beds where the methane production has failed to reach the appropriate level, whether in economic or engineering terms. This paper identifies some reasons for the failed attempts at well exploration of gas from such coal beds. Specifically, it describes seven parameters to be considered in relation to CBM, including geomechanical parameters such as Young’s modulus, Poisson’s ratio, and the initial porosity, which define coal cleat compressibility, a very important parameter, and parameters related to methane desorption, i.e., desorption-induced volumetric strain, the Langmuir pressure, and the initial pressure of gas within the bed. In addition to cleat compressibility, there are other, equally important parameters, such as the rebound pressure and recovery pressure, which are defined by the following parameters in order of importance: Young’s modulus, desorption-induced volumetric strain, initial pressure of methane, the Langmuir pressure, and Poisson’s ratio. To assess the impact of these parameters on changes in permeability, we used the Cui-Bastin model. The simulation results were analysed to allow us to present our findings.
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Shi, Ji-Quan, and S. Durucan. "A Model for Changes in Coalbed Permeability During Primary and Enhanced Methane Recovery." SPE Reservoir Evaluation & Engineering 8, no. 04 (August 1, 2005): 291–99. http://dx.doi.org/10.2118/87230-pa.
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Summary The natural fracture network of a dual-porosity coalbed reservoir is made up of two sets of orthogonal, and usually subvertically oriented, cleats. Coalbed permeability has been shown to vary exponentially with changes in the effective horizontal stress acting across the cleats through the cleat-volume compressibility, which is analogous to pore compressibility in porous rocks. A formulation for changes in the effective horizontal stress of coalbeds during primary methane recovery, which includes a Langmuir type curve shrinkage term, has been proposed previously. This paper presents a new version of the stress formulation by making a direct link between the volumetric matrix strain and the amount of gas desorbed. The resulting permeability model can be extended readily to account for adsorption-induced matrix swelling as well as matrix shrinkage during enhanced methane recovery involving the injection of an inert gas or gas mixture into the seams. The permeability model is validated against a recently published pressure-dependent permeability multiplier curve representative of the San Juan basin coalbeds at post-dewatering production stages. The extended permeability model is then applied successfully to history matching a micropilot test involving the injection of flue gas (consisting mainly of CO2 and N2) at the Fenn Big Valley, Alberta, Canada. Introduction Over the past 2 decades, coalbed methane (CBM) has become an important source of the (unconventional) natural gas supply in the U.S. On the basis of this experience, CBM has attracted worldwide attention in recent years as a potential clean energy source. Current commercial CBM production occurs almost exclusively through reservoir-pressure depletion, which is simple but considered to be rather inefficient, with an estimated total recovery of generally around 50% (this figure appears to be pessimistic; mature coal plays in the U.S. have now seen recovery of 60 to 80%) of the gas in place. In recent years, enhanced CBM (ECBM) recovery techniques have been proposed as a more efficient means for the recovery of a larger fraction of methane in place. There are two principal variants of ECBM recovery, namely N2 and CO2injection, which use two distinct mechanisms to enhance methane desorption and production. Unlike the primary recovery method, ECBM allows the maintenance of reservoir pressure. The mechanism used in N2 injection is somewhat similar to inert gas stripping because nitrogen is less adsorbing than methane. Injection of nitrogen reduces the partial pressure of methane in the reservoir, thus promoting methane desorption without lowering the total reservoir pressure. On the other hand, CO2 injection works on a different mechanism because it is more adsorbing on coal compared with methane. Carbon dioxide ECBM recovery thus has an added benefit that a potentially large volume of greenhouse gas can be sequestrated in deep coal seams globally.
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Liu, Ang, Shimin Liu, Peng Liu, and Satya Harpalani. "The role of sorption-induced coal matrix shrinkage on permeability and stress evolutions under replicated in situ condition for CBM reservoirs." Fuel 294 (June 2021): 120530. http://dx.doi.org/10.1016/j.fuel.2021.120530.
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Thararoop, Prob, Zuleima T. Karpyn, and Turgay Ertekin. "Numerical studies on the effects of water presence in the coal matrix and coal shrinkage and swelling phenomena on CO2-enhanced coalbed methane recovery process." International Journal of Oil, Gas and Coal Technology 5, no. 1 (2012): 47. http://dx.doi.org/10.1504/ijogct.2012.044177.
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Gao, Li Juan, Xue Fei Zhao, Shi Quan Lai, and Yan Xial Liu. "Carbonization Regime Process of Coal Tar Refined Soft Pitch." Advanced Materials Research 750-752 (August 2013): 1689–95. http://dx.doi.org/10.4028/www.scientific.net/amr.750-752.1689.
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The thermal behavior of coal tar refined soft pitch (CTRSP) was investigated by using polarizing microscope with heating stage and thermogravimetric analyzer. The phenomena of carbonization regime process of CTRSP were observed directly in the micro-picture taken online. The results showed that the carbonization thermal dynamic process of CTRSP is divided into several typical stages. At 30-250°C,there is small molecular evaporation; at 250-390 °C,there is thermal decomposition and small molecular evaporation; at 390-480°C,there is the condensation of small molecules and radicals into macromolecules and directional arrangement generating small spheres; at 480-520°C,there is the coking stage; at 520-560°C, there is the semicokes dehydrogenation and shrinkage. The spherules are formed at about 390°C. The growth process of the spherules is divided into several stages: absorption optical isotropic matrix asphalt to grow, two spherule collision fusion and growth, finally (at 480-520°C) due to gravity is greater than surface tension small spheroid disintegration deformation and became fibrillar semicoke (at 520-560 °C). Thermogravimetric (TG) - differential thermogravimetry (DTG) curve are treated by Freeman-Carrolls non isothermal differential method, coal tar soft pitchs first-order reaction is from 253°C to 325°C, from 370 °C to 413°C two temperature stages, activation energy is 28.575 kJ/mol and 60.210 kJ/mol, pre-exponential factor is 2.328×106and 1.4833×107, respectively. The microscopic picture recording was consistent with thermal heavy kinetic equation and the results confirmed that the chief of thermal decomposition reaction is operated from 253 °C to 325 °C, the most of condensation polymerization reaction is operated from 370 °C to 413 °C.
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Dani, Kamal Chandra, Dharmendra Kumar Gupta, and Pushpa Sharma. "Geomechanics impact due to in-situ and induced stresses during drilling of horizontal and highly deviated coal bed methane wells." IOP Conference Series: Materials Science and Engineering 1248, no. 1 (July 1, 2022): 012074. http://dx.doi.org/10.1088/1757-899x/1248/1/012074.
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Abstract Hydrocarbon exploration is the arduous task. Urgency of hydrocarbon and avengement of technology push operators to recover the unexplored unconventional hydrocarbon like coal bed methane (CBM) which has been discontinued. Limitations such as misunderstanding of geomechanical stress, formation behaviours- abrasiveness, mud properties etc; impaired the drilling performance and leads to well failure. Therefore, wellbore stability due to geomechanical stresses is considered as one of the major stages in well planning and required extensive study. The dominant elements of fascinating the CBM extraction are cost and the currently available technology and poor understanding of reservoir as compare to conventional reservoir. CBM wells fails due to exceeding the limit of tensile and shear strength which includes wellbore collapse, pipe sticking, caving, loss circulation and leads to ruin the operator’s money and time. The stress regimes in induced, in-situ stresses are natural and cannot be change; however study of these stresses and implementation of findings are essential to implement while planning the well and monitoring stresses behaviour during drilling of highly deviate or horizontal wells are key element to successfully develop the coal bed methane reservoir. Effect of geomechanical stresses are experienced while drilling horizontal and highly deviated wells. By considering the effects of in-situ and induced stresses; suitable operational window can be design to reduce the CBM wellbore failure. The present work analyse the geomechanical in-situ and induced stresses which are contributing towards instability of wellbore along with matrix shrinkage effect, outcome of this study can be utilized for the efficient planning of failure-free wellbore operating envelopes for CBM wells.
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Li, Gui Zhong, Ze Deng, Bo Wang, and Meng Geng. "Dynamic Variation Character of CBM Reservoir Permeability during Depletion of High-Rank Coalbed Methane." Advanced Materials Research 233-235 (May 2011): 2267–71. http://dx.doi.org/10.4028/www.scientific.net/amr.233-235.2267.
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China is rich in CBM resources, but so far, some production wells present low production and rapid decline trend. In addition to these objective factors such as low permeability and complexity of geological structure of CBM reservoir, there is still the most important problem during the exploitation techniques that is the lack of understanding to dynamic variation character of CBM reservoir permeability, which leads to the unreasonable work of depletion for coalbed methane.Using P&M model and parameters from 3# coal seam of Shanxi Formation, Permian system in Qinshui basin, the permeability variations of this block (first decline, then ascend, reaching 2.8 times of initial permeability at the end) were analyzed, revealing good depletion prospect of this CBM field, and pointed that the higher Young's modulus is, the more obvious matrix shrinkage is and the higher gas saturation is, the more favor for permeability improvement through sensitivity analysis. Finally, two suggestions were proposed, (1) add the 'permeability variations' to the parameters for CBM block select, which may find the "innate" in the late development of the poor condition of properties easy to improve, develop potential for larger blocks. (2) Adjust and optimize the depletion method (amplitude and frequency of bleeding, pressure reduction) according to the permeability variation characters discussed in this paper
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Durucan, Sevket, Mustafa Ahsanb, and Ji-Quan Shia. "Matrix shrinkage and swelling characteristics of European coals." Energy Procedia 1, no. 1 (February 2009): 3055–62. http://dx.doi.org/10.1016/j.egypro.2009.02.084.
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Wei, Zhijie, and Dongxiao Zhang. "A Fully Coupled Multiphase Multicomponent Flow and Geomechanics Model for Enhanced Coalbed-Methane Recovery and CO2 Storage." SPE Journal 18, no. 03 (April 8, 2013): 448–67. http://dx.doi.org/10.2118/163078-pa.
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Summary Enhanced coalbed-methane (ECBM) recovery by the injection of CO2 and/or N2 is an attractive method for recovering additional natural gas resources, while at the same time sequestering CO2 in the subsurface. For the naturally fractured coalbed-methane (CBM) reservoirs, the coupled fluid-flow and geomechanics effects involving both the effective-stress effect and the matrix shrinkage/swelling, are crucial to simulate the permeability change and; thus gas migration during primary or enhanced CBM recovery. In this work, a fully coupled multiphase multicomponent flow and geomechanics model is developed. The coupling effects are modeled by introducing a set of elaborate geomechanical equations, which can provide more fundamental understanding about the solid deformation and give a more accurate permeability/porosity prediction over the existing analytical models. In addition, the fluid-flow model in our study is fully compositional; considering both multicomponent gas dissolution and water volatility. To obtain accurate gas solubility in the aqueous phase, the Peng-Robinson equation of state (EOS) is modified according to the suggestions of Søreide and Whitson (1992). An extended Langmuir isotherm is used to describe the adsorption/desorption behavior of the multicomponent gas to/from the coal surface. With a fully implicit finite-difference method, we develop: a 3D, multiphase, multicomponent, dual-porosity CBM/ECBM research code that is fully compositional and has fully coupled fluid flow and geomechanics. It has been partially validated and verified by comparison against other simulators such as GEM, Eclipse, and Coalgas. We then perform a series of simulations/investigations with our research code. First, history matching of Alberta flue-gas-injection micropilot data is performed to test the permeability model. The commonly used uniaxial-strain and constant-overburden-stress assumptions for analytical permeability models are then assessed. Finally, the coupling effects of fluid flow and geomechanics are investigated, and the impact of different mixed CO2/N2 injection scenarios is explored for both methane (CH4) production and CO2 sequestration.
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ENGSTRÖM, Gunnar. "Causes of back-trap mottle in lithographic offset prints on coated papers." February 2016 15, no. 2 (March 1, 2016): 91–101. http://dx.doi.org/10.32964/tj15.2.91.
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Back-trap mottle is a common and serious print quality problem in lithographic offset printing of coated papers. It is caused by nonuniform ink retransfer from an already printed surface when it passes through a subsequent printing nip with the print in contact with the rubber blanket in that nip. A nonuniform surface porosity gives rise to mottle. A key parameter in mottling contexts is the coating mass distribution, which must be uniform. Good relationships between mottle and mass distribution have also been reported; the mottle pattern coincides with that of the coating mass distribution. High blade pressures, compressible base papers, and high water pick-up between application and metering, which plasticizes the paper, yield uniform mass distributions, but these parameters might have a detrimental effect on the runnability in blade coating in terms of web breaks. The general opinion has been that nonuniform surface porosity is caused by binder migration and enrichment of binder in the coating surface, more in the high coat weight areas and less in the low coat weight areas. Recent research has suggested that a more probable mechanism is depletion of binder in the coating surface. Nonuniform shrinkage of the pigment matrix (filter cake) formed during the consolidation between the first critical concentration (FCC) and the second critical concentration (SCC) is another possible mechanism. Relevant relaxation times for latex and the time scales for consolidation show that the high coat weight areas shrink more than the low coat weight areas in the coating layer. A recent pilot-scale experiment has shown that the drying strategy did not affect the differences in shrinkage between high and low coat weight areas. The drying strategy has a pronounced impact on mottle. A high evaporation rate at the beginning of the evaporation results in less mottle than a low evaporation rate. The least mottle is obtained if the drying is performed with a gap in the course of evaporation between the FCC and the SCC.
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Miao, Yanan, Chaojie Zhao, and Gang Zhou. "Gas Flowrate Evaluation in Coal Coupling the Matrix Shrinkage Effect Caused by Water Extraction." Journal of Energy Resources Technology 144, no. 3 (June 14, 2021). http://dx.doi.org/10.1115/1.4051301.
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Abstract Estimating production in coal accurately is crucial for promoting the process of safe, efficient, and green coal mining. It has been gradually recognized that horizontal wells with multiple fractures are employed to develop the coal reservoir, which signifies that the linear flow regime will dominate for a rather long time. However, the traditional analysis approaches of transient linear flow regimes may yield the overestimation of coal reservoir property. In this work, a new analytical model was proposed to estimate the rate-transient of wells with multi-fractures in coal reservoir that produce at a constant flowing pressure, which considers multiple flow mechanisms. Especially, the matrix shrinkage effect caused by water extraction from microscopic pores was incorporated, which has never been investigated by current production analysis models. In comparison with the conventional reservoir, the advanced pseudo-pressure and pseudo-time equations incorporating earlier critical mechanisms were established, including the four effects of gas slippage, effective stress, and matrix shrinkage caused by gas desorption/water extraction. In addition, the excellent agreement between the predicted rate by the proposed model and field data was achieved to validate the reliability of proposed models. Furthermore, the sensitivity analysis was carried out to clarify the influence of a series of factors on the seepage mechanism and productivity curve. Results demonstrated that the matrix shrinkage effect caused by water extraction may increase the well production rate in coal reservoirs. Selecting one field case as an example, the production rate predicted by the red curve is obviously higher than that by the green curve, the average discrepancy yields around 39.5%. The relative humidity in the coal matrix will present a positive impact on well production performance. Taking a field case as an instance, when the relative humidity varies from 8% to 14%, the well production sharply increases by about 11.6%.
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Liu, Yanhao, Zuqiang Xiong, and Xiaodong Zhang. "Fracture network characterization of high-rank coal and its control mechanism on reservoir permeability." Frontiers in Earth Science 10 (September 7, 2022). http://dx.doi.org/10.3389/feart.2022.995394.
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Based on the results of previous research on the fracture systems of reservoirs of middle- and low-rank coal, we took high-rank coal in the southern Qinshui Basin as the study object in this paper and summarize the characteristics of both macro- and micro-fractures in reservoirs of different rank coals, establish a geometric model of the fracture network for different rank coals, and explore the mechanism of coal reservoir permeability change under different conditions. The study found that the structure of the fracture network of high-rank coal developed unevenly. The high-rank coal had the characteristics of rift created outside, micro-fracture development, and undeveloped endogenous fracture, which can be used to improve the permeability of the coal reservoir, to a certain extent. We concluded that given the absence of a seepage aisle in the high-rank coal, there is a rapid increase in reservoir permeability from low to high rate during the seepage process of the fracture network. However, the seepage rate in other coal rank reservoirs increases smoothly. Due to fracture compression and coal matrix shrinkage, the permeability of the coal reservoir first decreases and then increases during the drainage stage. At the same rate of pressure drop, the permeability of high-rank coal reservoir decreases at the fastest rate, followed by that of low-rank coal reservoir, and that of middle-rank coal reservoir, in that order.
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Bon, Jan. "Concurrent 6. Presentation for: Effects of rapid gas decompression on coal seam gas swellables." APPEA Journal 62, no. 4 (June 3, 2022). http://dx.doi.org/10.1071/aj21319.
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Presented on Tuesday 17 May: Session 6 Thousands of non-stimulated coal seam gas (CSG) wells in Queensland’s Surat Basin rely on swellable packers as the first line of defence against interburden solids production and poor well run life. This paper is aimed at understanding some of the impacts of long-term well operations on swellable performance from rapid changes in downhole pressure. For the first time, rapid gas decompression (RGD) effects on CSG swellables were experimented on in a quantitative manner as an analogue to underbalanced workover and pump trip conditions. RGD has the potential to break down swellables due to rapid release of high-pressure methane diffused in the rubber matrix resulting in a flow path for interburden solids. Five commonly available swellables from the CSG market were lab-tested for rapid decompression with methane at operational conditions. Coupon samples were swollen to representative conditions and placed in an autoclave under high-pressure methane, then rapidly decompressed in cycles. Results of this study showed relatively low levels of physical degradation under test conditions but shrinkage effects varied between products largely grouped into material properties, confirmed with separate ambient shrinkage test. As such, the focus on swellable placement geometry remains paramount. To access the presentation click the link on the right. To read the full paper click here