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Liu H.,Anhui University of Science and Technology | Sang S.,China University of Mining and Technology | Formolo M.,University of Tulsa | Li M.,Shanxi Coalbed Methane Branch of Huabei Oilfield Company | And 5 more authors.
Energy for Sustainable Development | Year: 2013

Monitoring the production from 94 coalbed methane (CBM) wells in the southern part of the Qinshui Basin of China this study demonstrates production characteristics of CBM wells, and how the incorrect production system, including improper water drainage rates and wellhead pressures, can lead to diminished gas production. Using data from these wells our results suggest that high-production rate wells, medium-production rate wells, low-production rate wells, and drainage wells, are controlled by drainage conditions in addition to the well location and structural geology. The analysis of drainage parameters shows that the maximum wellhead pressure should be maintained around 1.5MPa before stable production, and between 0.10MPa and 0.30MPa after stable production. The most efficient average water production rate is approximately 4m3/day before gas production and should be maintained near 1m3/day during gas production. Initial daily average water production rate should be maintained around 1.5m3/day. Maximum water production rate should be regulated between 4 and 17m3/day. The rate of water level reduction should be within 4m/d and drainage time should be maintained for 50-200days prior to gas production. Implementation of these optimal drainage parameters will promote and sustain peak gas production for several years. In addition, reservoirs with adequate permeability, >0.1mD, are ideal for electric submersible pump systems while sucker-rod pumps are better suited for reservoirs with poor permeability. The combination of these operating conditions and the appropriate pumps optimizes the extraction efficiency and recovery of coalbed methane from the anthracitic coals in the Qinshui Basin. © 2013 International Energy Initiative.

Liu H.-H.,China University of Mining and Technology | Sang S.-X.,China University of Mining and Technology | Li Y.-M.,Shanxi Coalbed Methane Branch of Huabei Oilfield Company | Li M.-X.,Shanxi Coalbed Methane Branch of Huabei Oilfield Company | And 3 more authors.
Zhongguo Kuangye Daxue Xuebao/Journal of China University of Mining and Technology | Year: 2011

Combined with the analysis of engineering data of coalbed methane wells and testing data, a method for production replacement of coalbed methane in developing block of southern Qinshui was put forward by the study on the geological law of enrichment and high-permeability of coal bed and drainage governing factors. The developing blocks were divided into five types of developing units of coalbed methane based on the grade of enrichment and permeability of the coal bed and differential pressure between the formation pressures and the critical desorption pressure. The results suggest that the proportions of different types of developing units in developing blocks are 1.10%, 20.86%, 47.44%, 28.96%, and 1.64%, respectively. The distribution of developing units is affected by the tectonic setting, and accord with coalbed methane gas content of coal seam, coal permeability, and differential pressure between the formation pressures and the critical desorption pressure. The region where the coal reservoir pressure increase from center to around has a small differential pressure between the formation pressure and the critical desorption pressure; the grades of developing units are relatively high. Most regions of study area are flat, and most developing units are located in the regions where the burial depth of coal seam is lower than 1000 m, which is favorable for construction engineering of coalbed methane. Analysis of development technology on production replacement in developing block show that, the later well pattern arrangement should be conducted in the third type of development unit or above and spread around the original multiple well system with a bound of 1000 m burial depth, well pattern can use a layered method based on topographic relief. Secondary, the fracturing and arrangement of small space well pattern should be adopted in the areas where coalbed methane wells have low production, where as the horizontal well technology should be conducted in the smooth region with stable formation and simple structure.

Liu H.,Anhui University of Science and Technology | Sang S.,China University of Mining and Technology | Wang G.G.X.,University of Queensland | Li M.,Shanxi Coalbed Methane Branch of Huabei Oilfield Company | And 7 more authors.
Journal of Petroleum Science and Engineering | Year: 2014

This study performs a block scale investigation on gas content of a coal reservoir in Zhengzhuang Block of the southern Qinshui basin in China. The gas content of Coal Seam No. 3 in this coal reservoir was measured in field and laboratory in conjunction with tests on coal properties such as adsorption isotherm, maximum vitrinite reflectance, coal composition and maceral component etc. Total 36 coal cores collected from 3 adjacent coalmines in the southern Qinshui basin were investigated, including analysis of logging data from the drilling wells. The investigations provided experimental data for block scale modeling and visualization analyses on the correlation between gas content and the key factors such as coal properties and geological conditions of the coal reservoir. Data obtained by field and lab tests were analyzed by statistical models in order to correlate gas content and individual type of coal properties and geological variables. The statistical model was then used to map the gas content of the target coal seam in the studied area, resulting in a flood map of gas content at a 1:50000 scale. The flood map was further visualized with other variables in terms of the properties of coal and coal reservoir and its geological conditions. These visualized maps provide useful geological interpretation for block scale investigation of the comprehensive relationships between the gas content and the coal properties and regional structure in the given coal reservoir. The results show that gas content has little correlation with coal rank, maceral composition, coal thickness, cap and bottom lithology, while it is highly related to the structural properties such as burial depth and effective cover thickness. A stagnant hydrodynamic condition is favorable to the higher gas content on the whole but does not contribute to gas lateral and local variation. Canonical correlation and principal component analysis on the statistical model reveal the key factors that control the gas content are burial depth, effective thickness of overlying strata, groundwater level and moisture content in coal seam. © 2013 Elsevier B.V.

Liu H.,Anhui University of Science and Technology | Sang S.,China University of Mining and Technology | Wang G.G.X.,University of Queensland | Li Y.,Shanxi Coalbed Methane Branch of Huabei Oilfield Company | And 2 more authors.
Energy | Year: 2012

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. © 2012 Elsevier Ltd.

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