Coal Reservoir Permeability Research Articles

Characteristics and control mechanisms of coalbed permeability change in various gas production stages

According to dimensionless analysis of the coalbed methane (CBM) production data of Fanzhuang block in southern Qinshui basin, the dimensionless gas production rate is calculated to quantitatively divide the CBM well production process into four stages, i.e., drainage stage, unstable gas production stage, stable gas production stage, and gas production decline stage. By the material balance method, the coal reservoir permeability change in different stages is quantitatively characterized. The characteristics and control mechanisms of change in coalbed permeability (CICP) during different production stages are concluded on five aspects, i.e., permeability trend variation, controlling mechanism, system energy, phase state compositions, and production performance. The study reveals that CICP is characterized by first decline, then recovery, and finally by increase and is controlled directly by effective stress and matrix shrinkage effects. Further, the duration and intensity of the matrix shrinkage effect are inherently controlled by adsorption and desorption features.

Geologic controls of the production of coalbed methane in the Hancheng area, southeastern Ordos Basin

The Hancheng area of the southeastern Ordos Basin is a sample area for coalbed methane (CBM) development in China. There are three target coal seams for CBM development in this area, but the gas production of the different coal seams varies significantly. This study investigates the controlling factors of CBM production in the Hancheng area. The results indicate that permeability has the main impact on CBM production in the Hancheng area. Coal types and stress are closely related to fracture development and further impact on the permeability of coal reservoirs in this area. According to the macroscopic coal petrography description, mercury porosimetry experiments and X-CT scanning, bright coal has the largest pore volume and average pore size diameter than those of the other coal types and developed fractures with good openness and connectivity, whereas dull coal has the most undeveloped macropores and fractures. The No. 3 coal seam always has a higher productivity because it mainly consists of bright coal and semi-bright coal and has a relatively shallow buried depth. Therefore, the No. 3 coal seam had the best physical properties as a whole compared to the other coal seams, providing the most favourable conditions for CBM production.

Dynamic permeability change during coalbed methane production and its controlling factors

Coal reservoir permeability, which changes constantly during the exploitation process, is a key factor for determining the production effects and ultimate recovery of coalbed methane (CBM) wells. To calculate the dynamic permeability more accurately, we reviewed the controlling mechanism of coal reservoir permeability and then established three mathematic permeability change models considering the effective stress, matrix shrinkage and gas slippage respectively. Relation between the production data and permeability by adopting the material balance theory was established and then a production data-based theoretical model for calculating the permeability change during the drainage process was derived. Seventeen wells from the Fanzhuang–Zhengzhuang block in the southern Qinshui Basin of China were employed for a case study. The calculated results clearly reflect the dynamic permeability change. The dynamic permeability curves can be divided into “decline type”, “rebound type” and “rising type”. Furthermore, the impacts of pressure drop, daily gas production, and final pressure on permeability change were analyzed. The results show that the rate of permeability change induced by effective stress had a significant positive linear correlation with the pressure drops. A quadratic relationship existed between the rate of permeability change induced by matrix shrinkage and daily gas production rate. The lower final pressure will give rise to the faster permeability change that induced by gas slippage, which indicates a typically exponential relationship.

Theory and technique of permeability enhancement and coal mine gas extraction by fracture network stimulation of surrounding beds and coal beds

The existing reservoir stimulating technologies are only applicable to hard coal but helpless for soft coal, which is one of the main factors hindering the CBM industrialization in China. Therefore, it is urgent to develop a universal stimulating technology which can increase the permeability in various coal reservoirs. Theoretical analysis and field tests were used to systematically analyze the mechanical mechanisms causing the formation of various levels and types of fractures, such as radial tensile fractures, peripheral tensile fractures, and shear fractures in hydraulic fracturing, and reveal the mechanism of permeability enhancement by fracture network stimulating in surrounding beds and coal reservoirs. The results show that multi-staged perforation fracturing of horizontal wells, hydraulic-jet staged fracturing, four-variation hydraulic fracturing and some auxiliary measures are effective technical approaches to fracture network stimulation, especially the four-variation hydraulic fracturing can stimulate the fracture network in vertical and cluster wells. It is concluded that the fracture network stimulating technology for surrounding beds has significant advantages, such as safe drilling operation, strong stimulation effect, strong adaptability to stress-sensitive and velocity-sensitive beds, and is suitable for coal reservoirs of any structure. Except for the limitation in extremely water-sensitive and high water-yield surrounding beds, the technology can be universally used in all other beds. The successful industrial tests in surface coal bed methane and underground coal mines gas extraction prove that the theory and technical system of fracture network stimulating in surrounding beds and coal reservoirs, as a universally applicable measure, will play a role in the CBM development in China.

Effective migration system of coalbed methane reservoirs in the southern Qinshui Basin

Effective migration system of coalbed methane (CBM) reservoir, which was controlled by development degree and opening-closing degree of fractures, determines the permeability of coal reservoir and can be characterized by the pore-fracture system in the extrinsic form. In this paper, based on coal matrix elastic self-regulating effect theory and coal reservoir combined elastic energy theory, the fracture opening-closing degree parameter Δ and the fracture development degree parameter ξ are suggested for the quantitative study of the effective migration system of CBM reservoir in southern Qinshui Basin. Further, the control functions of ξ and Δ to CBM enrichment and high production are discussed. The results show that in present stage the area with high ξ value is located in Anze and Qinyuan, and then Zhengzhuang and Fangzhuang, where fracture development degree is high. The area with high Δ value is located in Zhengzhuang and Fanzhuang, and then Anze and Qinyuan, indicating where coal matrix elastic self-regulating positive effect dominates and fractures tend to be open. Through the comprehensive analysis on ξ and Δ, it can be found that their best match area is located in Zhengzhuang and Fanzhuang, with high values for fracture development degree and opening-closing degree probably bringing about high fluid pressure and good permeability of reservoirs, which are advantageous to an abundant CBM production.

Evaluation of the coal reservoir permeability using well logging data and its application in the Weibei coalbed methane field, southeast Ordos basin, China

Permeability is one of the most critical reservoir evaluation parameters in coalbed methane (CBM) exploration and development. In this study, an improved collection of sheets model was proposed for evaluation of reservoir permeability of the no. 5 coal seam in the Weibei CBM field, southeast Ordos basin, China. The evaluation model is expressed by k = 8.50 × 10− 4 nw 2 ϕ f in which the fracture width (w), fracture density (n), and porosity (φ f) can be obtained by analysis of the deep lateral resistivity logging and micro-sphere focusing logging data. The calculated permeability values are ranging from 0.005 to 2.327 mD across the Weibei coalfield. The regional distribution of permeability is mainly controlled by the factors of burial depth and tectonics stress. The permeability is high in the shallow area and the zone of normal faults, but it is low in the anticline area and the upthrust side of thrust faults. The results show that the calculation method developed in this study is reliable, providing a better understanding of the coal reservoir for CBM exploration in the study area.

Comprehensive Analysis of Factors Affecting Coalbed Methane Productivity: A Case Study of Southern Qinshui Basin

Coalbed methane (CBM) productivity is influenced by various factors. Based on field production data and test data of southern Qinshui Basin, factors including geological factors, engineering factors and drainage factors that affect CBM productivity are analyzed. Analytic hierarchy process (AHP) is introduced to calculate the contribution of each parameter to CBM productivity. A three-level model for evaluating CBM productivity based on AHP is established. The results show that average daily gas production of single well in southern Qinshui Basin increases with gas content, coal seam thickness, permeability, porosity, gas saturation, critical desorption pressure. Filling minerals in pores and fractures of coal can decrease gas content, porosity and permeability of coal reservoir. When burial depth is deeper than 500m or reservoir pressure is greater than 2MPa and burial depth is shallower than 1000m or reservoir pressure is less than 10MPa, CBM productivity is relatively high. According to the calculation, the weight of geological factors, engineering factors and drainage factors are 50%, 25% and 25%, respectively. Reservoir physical properties, geological conditions, fracturing technology and drainage process have the most impact, the weight of which are 33.33%, 16.67%, 11.79%, and 15.00%, respectively.

The Development of Coal Reservoir Fracture and its Geological Controls in Zhengzhuang Block, Southern Qinshui Basin, China

Coal reservoir system is the key factors influencing the permeability of coal seam, the study of the development extent of the fracture is very beneficial for the large-scale commercial exploitation of coalbed methane. From the metamorphic degree of coal rock, maceral, coal characteristics and mineral filling these aspects ,this article discusses the control mechanism of the fracture system development. It is pointed out that the development degree of system is the direct factors influencing the coal reservoir permeability and fracture system development is influenced by many factors. The fillings in crack can block the fracture and reduce the permeability of coal reservoirs.

Coal Reservoir Permeability in the Gemudi Syncline in Western Guizhou, China

Coal reservoir permeability is an important parameter to used to evaluate coalbed methane resource potential and select favorable zones. This article presents a research on Gemudi syncline. The coal reservoir permeability was largely studied by a considerable amount of geological data obtained from mercury injection experiments, scanning electron microscope observation, and gas/water phase permeability tests. The results revealed that the macro-fractures are especially developed in Gemudi syncline. The micro-fractures and micro-pores of Gemudi syncline are also well developed. The pores, of which the diameters are less than 0.10 μm, occupy the biggest proportion, above 70%. Most pores are open. The measured permeability of the samples varies from 0.33 to 6.69 mD, although most are higher than 0.5 mD. Considering the Mopan mountain mine, which has similar conditions with Gemudi syncline, it is thought that the permeability of coal seams in Gemudi syncline is comparatively high. But the large amount of micropores in this region, which have strong adsorption, may cause coalbed methane desorption difficulty when exploiting.

Coal matrix deformation characteristics in the process of carbon dioxide displacing different gas saturation coal-bed methane

It is fundamental that changes in coal reservoir permeability are researched, in particular, the accurate determination of variations in the coal matrix caused by CO2 replacing CH4 at different gas saturation conditions. Based on the surface free energy, the extended Langmuir isothermal adsorption model, combined with CO2 replacing CH4 in experimental trials, and calling on the more general principles and characteristics of the field, mathematical models describing the coal matrix as it undergoes different processes such as CO2 injection and desorption were established. Combined with laboratory data about CO2 replacement under different methane saturation conditions, a law governing the variations in coal matrix CO2 replacement under different methane gas saturation conditions was obtained. The results showed that: in the injection process, the coal matrix expansion rate caused by CO2 or CH4 was exponentially increased with the CO2 pressure increase, the expansion caused by CO2 was far greater than the expansion caused by CH4 in the desorption process, the coal matrix shrinkage caused by CO2 or CH4 was exponentially increased with the pressure decrease, the shrinkage caused by CO2 was larger than the shrinkage caused by CH4 under the same pressure and different gas saturation, the total shrinkage in the desorption process in the coal matrix was greater than the total expansion in the injection process. At higher gas saturations, the total coal matrix shrinkage volume exceeded the total expansion corresponding to pressure points higher in the desorption process.

Simulation of Pressure Transient Behavior for Asymmetrically Finite-Conductivity Fractured Wells in Coal Reservoirs

Based on Fick’s law in matrix and Darcy flow in cleats and hydraulic fractures, a new semi-analytical model considering the effects of boundary conditions was presented to investigate pressure transient behavior for asymmetrically fractured wells in coal reservoirs. The new model is more accurate than previous model proposed by Anbarci and Ertekin, SPE annual technical conference and exhibition, New Orleans, 27–30 Sept 1998 because new model is expressed in the form of integral expressions and is validated well through numerical simulation. (1) In this paper, the effects of parameters including fracture conductivity, coal reservoir porosity and permeability, fracture asymmetry factor, sorption time constant, fracture half-length, and coalbed methane (CBM) viscosity on bottomhole pressure behavior were discussed in detail. (2) Type curves were established to analyze both transient pressure behavior and flow characteristics in CBM reservoir. According to the characteristics of dimensionless pseudo pressure derivative curves, the process of the flow for fractured CBM wells was divided into six sub-stages. (3) This paper showed the comparison of transient steady state and pseudo steady state models. (4) The effects of parameters including transfer coefficient, wellbore storage coefficient, storage coefficient of cleat, fracture conductivity, fracture asymmetry factor, and rate coefficient on the shape of type curves were also discussed in detail, indicating that it is necessary to keep a bigger fracture conductivity and fracture symmetry for enhancing well production and reducing pressure depletion during the hydraulic fracturing design.

Temperature-Rising Desorption of CBM

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.

Evaluation of the synergetic gas-enrichment and higher-permeability regions for coalbed methane recovery with a fuzzy model

Determination of the synergetic region with both coalbed methane (CBM) enrichment and higher permeability and its distribution is fundamentally crucial to optimize well design and pattern arrangement for CBM recovery from coal. To address this issue, a predictive model was developed based on fuzzy theory by taking into account the main geological factors that affect the gas enrichment and permeability in coal reservoirs. Following the statistical analysis on a number of geological parameters, Euclid approach degree (a comprehensive evaluation coefficient) and fuzzy matter-elements were determined and integrated into the model. The information entropy method was used to evaluate the effect weight of each geologic factor on overall object of the synergetic gas-enrichment and higher-permeability region. The model was applied to the coal seam No. 3 of a developing coal block in the south of Qinshui basin as an example. The results show that the geological factors such as coal rank, gas saturation, coping thickness, transitional coal structure, and volatile content determine the distributions of the synergetic gas-enrichment and higher-permeability region with higher weight coefficients over 9%. Compared with these key factors, the factors such as coal thickness, gas content, methane concentration, ash content, principal stress difference, fracture density, porosity, and burial depth have only the weight coefficients of <5% and their effects on the synergetic region are very limited. The other factors including reservoir temperature, groundwater level, minimum principal stress, and water content exhibit the moderate impact featured by the weight coefficients varying from 5% to 9%. The model prediction provided a flood/contour map to visualize the synergetic gas-enrichment and higher-permeability regions. With this map, the selected coal block can be classified as extremely favorable, favorable, relatively favorable and unfavorable areas for CBM recovery based on the Euclid approach degree. The extremely favorable and favorable areas mainly distribute in the center and the southwest of the coal block; the relatively favorable area locates in most part of the coal block; unfavorable area dispersedly distributes in the south along the east-west direction. The distribution of the synergetic regions is obviously controlled by the coal structure. The prediction results were verified with the distributions of most CBM wells performed in the same coal block, showing that the model prediction is reasonably agreeable with reality. The model developed in this study can be used as a feasible tool to predict the favorable well locations and optimize the well patterns for CBM recovery.

Modelling permeability for coal reservoirs: A review of analytical models and testing data

Abstract As with other reservoir types permeability is a key controlling factor for gas migration in coalbed methane reservoirs. The absolute permeability of coal reservoirs changes significantly during gas production, often initially decreasing but then increasing as the reservoir pressure and gas content is drawn down. It has also been observed to decrease markedly during CO2 injection to enhance coalbed methane recovery. In order to predict gas migration models for coal permeability must represent the mechanisms leading to these observed behaviours. The permeability of coal reservoirs behaves in a similar fashion to other fractured reservoirs with respect to effective stress, decreasing exponentially as the effective stress increases. However a unique effect of coal is that it shrinks with gas desorption and swells with adsorption. Within the reservoir this swelling/shrinkage strain leads to a geomechanical response changing the effective stress and thus the permeability. Modelling coal permeability incorporating the impacts from both effective stress and coal swelling/shrinkage dates back about 25 years. Since then a number of permeability models have been developed. In recent years this topic has seen a great deal of activity with a growing body of research on coal permeability behaviour and model development. This article presents a review of coal permeability and the approaches to modelling its behaviour. As an important part of this, the field and laboratory data used to test the models are reviewed in detail. This article also aims to identify some potential areas for future work.

Evaluation of the reservoir permeability of anthracite coals by geophysical logging data

Permeability is one of the most significant reservoir parameters. It is commonly obtained by experiment, history simulation, injection/falloff well test and geophysical logging. Among these, geophysical logging remains as the most economic and efficient technique in evaluating coal permeability in the vicinity of an open-hole. In this paper, geophysical logging data are used to evaluate the coal reservoir permeability for the No. 3 coal seam in the southern Qinshui Basin (Fanzhuang and Zhengzhuang coal zones). Ideally coal reservoirs consist of coal matrix and fracture networks that can be represented by a model called a collection of sheets. Based on the model, coal reservoir permeability can be quantitatively calculated using the theoretical formula of kf = 8.50 × 10− 4 w2φf, in which fracture width (w) and fracture porosity (φf) were obtained by dual laterolog and density logging data, respectively. Calculative results show that coal reservoir permeability ranged from 0.017 mD to 0.617 mD for the Fanzhuang coal zone and from 0.047 mD to 1.337 mD for the Zhengzhuang coal zone. The permeability decreases with coal burial depth, reflecting variations in penetration capability of coal reservoirs at varying depths. Comparing results with those from injection/falloff well tests, however, shows that the model-calculated permeability is slightly higher. This is expected because the model did not include the influence from coal anisotropy.

Laboratory characterisation of coal reservoir permeability for primary and enhanced coalbed methane recovery

Coal permeability is highly sensitive to the stress. Meanwhile, coal swells with gas adsorption, and shrinks with gas desorption. Under reservoir conditions these strain changes affect the cleat porosity and thus permeability. Coal permeability models, such as the Palmer and Mansoori and Shi and Durucan models, relate the stress and swelling/shrinkage effect to permeability using an approximate geomechanical approach. Thus in order to apply these models, stress–permeability behaviour, swelling/shrinkage behaviour and the geomechanical properties of the coal must be estimated. This paper presents a methodology for the laboratory characterization of the Palmer and Mansoori and Shi and Durucan permeability models for reservoir simulation of ECBM and CO 2 sequestration in coal. In this work a triaxial cell was used to measure gas permeability, adsorption, swelling and geomechanical properties of coal cores at a series of pore pressures and for CH 4 , CO 2 and helium with pore pressures up to 13 MPa and confining pressures up to 20 MPa. Properties for the permeability models such as cleat compressibility, Young's modulus, Poisson's ratio and adsorption-induced swelling are calculated from the experimental measurements. Measurements on an Australian coal are presented. The results show that permeability decreases significantly with confining pressure and pore pressure. The permeability decline with pore pressure is a direct result of adsorption-induced coal swelling. Coal geomechanical properties show some variation with gas pressure and gas species, but there is no direct evidence of coal softening at high CO 2 pressures for the coal sample studied. The experimental results also show that cleat compressibility changes with gas species and pressure. Then the measured properties were applied in the Shi and Durucan model to investigate the permeability behaviour during CO 2 sequestration in coal.

CBM geology and exploring-developing stratagem in Guizhou Province, China

There are remarkable characteristics of the “one poor, two more, three higher and four bigger” in the coalbed methane (CBM) conditions of Guizhou, China. These show in one aspect the predominance with higher CBM resource accumulation, coal reservoir energy and developing potential in Guizhou, and in another aspect come into being disadvantageous of coal reservoir permeability and recasting. So, new thought and technologies must be sought ask for the CBM development in Guizhou. The authors in the paper considered that it is essential to survey clearly CBM resources in whole province, to analyze the adaptability of various CBM-mining technologies to the geological conditions in Guizhou, and, then, to frame rationally the stratagem and layout of CBM exploration and development aiming at the particularity of CBM geology in the province. In was suggested that near CBM exploration and surface development should be focalized to the Zhina coal field and a CBM pilot test with vertical or cluster wells may be carried into execution using for reference the Jincheng's pattern. As for the Liupanshui and other coal fields, the Huainan's pattern can be used for reference.

Evaluation of coal structure and permeability with the aid of geophysical logging technology

Coal structures and the associated permeability were studied by a combined investigation of geophysical logging data and well tests from coal reservoirs of Huainan and Huaibei coalfields in China. A large amount of the site observations on coal sections of mining faces and the macroscopic investigations on textures of drilling coal cores were carried out, providing experimental information for classification of coal structures. Geophysical log was implemented in 600 boreholes for exploration of coal and coalbed methane (CBM) resources, including 10 CBM wells which were used for permeability tests. The permeability tests were conducted by using injection/fall-off method. The results, together with the log data obtained from geophysical log technologies, have been analysed by using geological statistics, permitting correlation of the permeability of coal seams to the log responses. The correlation developed in this study provides better evaluation of coal reservoir permeability, resulting in an improved CBM exploration in the given coalfields.

An improved permeability model of coal for coalbed methane recovery and CO2 geosequestration

An alternative approach is proposed to develop an improved permeability model for coalbed methane (CBM) and CO2-enhanced CBM (ECBM) recovery, and CO2 geosequestration in coal. This approach integrates the textural and mechanical properties to describe the anisotropy of gas permeability in coal reservoirs. The model accounts for the stress dependent deformation using a stress–strain correlation, which allows determination of directional permeability for coals. The stress–strain correlation was developed by combining mechanical strain with sorption-induced strain for any given direction. The mechanical strain of coal is described by the general thermo-poro-elastic constitutive equations for solid materials under isothermal conditions and the sorption-induced strain is approximated by treating the swelling/shrinkage of coal matrix equivalent to the thermal contraction/expansion of materials. With directional strains, the permeability of coal in any given direction can be modeled based on the theory of rock hydraulics. In this study, the proposed model was tested with both literature data and experiments. The experiments were carried out using a specially designed true tri-axial stress coal permeameter (TTSCP). The results show that the proposed model provides better predictions for the literature data compared with other conventional coal permeability models. The model also gives reasonable agreement between the predicted and measured stress–strains and directional permeabilities under laboratory conditions.

Laboratory Investigation on the Permeability of Coal During Primary and Enhanced Coalbed Methane Production

Abstract Coalbed Methane (CBM) has grown into an important natural gas resource in North America in recent decades. The economical development of CBM heavily relies on coal permeability. The coal permeability is provided through a network of coal cleats and natural fractures. It is greatly affected by the confining stresses and the coal matrix response during gas adsorption and desorption in primary and enhanced recovery processes. This paper is focused on a laboratory investigation of coal permeability variability with different operating parameters. Core flood experiments in coal have been conducted with methane production and methane displacement by CO2. The permeability to different gases (CH4, CO2) under equilibrium conditions was measured at different confining stresses. The coal permeability to helium, which was reported in previous work, provides a comparison baseline. The permeability of a coal core to gases shows a strong dependence on net confining pressure and exhibits strong hysteresis. The CH4 permeability is relatively smaller than the corresponding He permeability, demonstrating a swelling effect of coal by CH4. The adverse effect of CO2 on coal permeability is also shown. The paper focuses on the experimental results obtained to date. Introduction Coalbed methane (CBM) is an unconventional natural gas resource that is gaining increasing worldwide attention. Successful CBM production depends on two factors: coal gas content and reservoir permeability. Coal gas content means the amount of gas presented in coal, and the reservoir permeability reflects the rate of the gas that could be produced. Unlike conventional gas reservoirs, methane is stored by adsorption onto the subsurface of the coal seams. The ability of coal to store gas is a function of coal rank, reservoir temperature and pressure which is related to coal depth. The primary CBM production is to deplete the reservoir pressure to desorb the methane gas from coal. Using CO2 for enhanced CBM production or using coal beds for CO2 sequestration has also received intense research interest in recent years. CO2 has been proven to have more than twice the affinity to coal than CH4(1). Limited studies have shown the concept of CO2-ECBM to be technically viable. However, the mechanisms have not been fully understood. Permeability of coal is recognized as the most important parameter controlling CBM and ECBM (enhanced CBM) production. Coal cleats are responsible for the permeability of coal. Flow through the cleats is dominated by Darcy flow that relates flow rate to permeability and pressure gradient(2). Methane is the major component of the coalbed gas. Measuring coal permeability tomethane is crucial for evaluating CBM production rate. When injecting CO2 into the coalbeds in ECBM production, the interaction of coal with dense CO2 can be inferred from the permeability changes. Measuring coal permeability to CO2 is the fundamental step to investigate the CO2-ECBM process and the potential of CO2 sequestration. Measuring meaningful coal permeability is more difficult than measuring reservoir rock permeability. Only a limited number of research groups have measured the permeability of coal by core flooding, and have pointed out some of the associated difficulties(3–5).