The Experts below are selected from a list of 17754 Experts worldwide ranked by ideXlab platform
Hongqing Song - One of the best experts on this subject based on the ideXlab platform.
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impact of permeability heterogeneity on production characteristics in water bearing Tight Gas reservoirs with threshold pressure gradient
Journal of Natural Gas Science and Engineering, 2015Co-Authors: Mingxu Yu, Hongqing Song, Yuhe Wang, John Killough, Juliana Y LeungAbstract:Abstract In order to investigate the effects of permeability heterogeneity on Gas production in water-bearing Tight Gas reservoirs, the combined series of cores obtained from Sulige Gas field, one of the important water-bearing Tight Gas reservoirs in China, were tested. Based on different scenarios of permeability heterogeneity, the low-velocity non-Darcy flow mathematical models considering threshold pressure gradient (TPG) were established. The finite difference method was applied to numerically solve the nonlinear mathematical model, and the corresponding numerical program was completed. The consistency between the numerical results considering TPG and the experimental data indicates the validity and accuracy of the mathematical models. The numerical and experimental results show that ignoring the influence of TPG in water-bearing Tight Gas reservoirs will lead to inaccurate assessment of the well productivity. For heterogeneous water-bearing Tight Gas reservoir development, the production wells allocated in high permeability region will boost the recovery. However the higher the initial constant production rate, the shorter the stable production time. So an appropriate production rate should be allocated to maximize both the economic and social benefits. This research can quantitatively analyze the impacts of permeability heterogeneity in water-bearing Tight Gas reservoir developments and optimize the production rate and production pressure accordingly.
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productivity equation of fractured horizontal well in a water bearing Tight Gas reservoir with low velocity non darcy flow
Journal of Natural Gas Science and Engineering, 2014Co-Authors: Hongqing Song, Dawei Yang, Mingxu YuAbstract:Abstract Based on the features of Tight Gas reservoirs and considering the existence of threshold pressure gradient (TPG), a new mathematical model was established for low-velocity non-Darcy flow in water-bearing Tight Gas reservoirs. Calculation method of control areas is also presented. Productivity equations of vertical fractured well and horizontal fractured well in Tight Gas reservoirs are obtained with TPG. Influential factors were analyzed to provide theoretical basis for the effective development of Tight Gas reservoirs. According to the numerical results, with the increase of pressure drawdown, both the volumetric flow rate of Gas well and control area grow first and then gradually becomes stable. The influence of TPG on the volumetric flow rate of Gas well is great and cannot be neglected. For fractured horizontal well, Gas well production increases with the increase of flow conductivity capacity and half-length of hydraulic fractures. For certain length of the borehole, when the fracture spacing increases and the number of the fractures decreases, the control area and the volume flow rate of the Gas well decreases. Consequently, there is an optimum allocation among drawdown pressure, fracture half-length, fracture conductivity and fracture spacing to achieve maximum production.
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formation pressure analysis of water bearing Tight Gas reservoirs with unsteady low velocity non darcy flow
Advanced Materials Research, 2011Co-Authors: Hongqing Song, Dong Bo He, Huai Jian YiAbstract:Porous media containing water is the prerequisite of existence of threshold pressure gradient (TPG) for Gas flow. Based on theory of fluid mechanics in porous medium considering TPG, the non-Darcy flow mathematical model is established for formation pressure analysis of water-bearing Tight Gas reservoirs. It could provide semi-analytic solution of unsteady radial non-Darcy flow. According to the solution of unsteady radial non-Darcy flow, an easy and accurate calculation method for formation pressure analysis is presented. It can provide theoretical foundation for development design of water-bearing Tight Gas reservoirs. The analysis of calculation results demonstrates that the higher TPG is, the smaller formation pressure of water-bearing Tight Gas reservoirs spreads. In the same output, the reservoir sweep of non-Darcy Gas flow is larger than that of non-Darcy liquid flow. And the pressure drop near wellbore is smaller than that of non-Darcy liquid flow, which is different from Darcy flow.
Christopher R Clarkson - One of the best experts on this subject based on the ideXlab platform.
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solid bitumen as a determinant of reservoir quality in an unconventional Tight Gas siltstone play
International Journal of Coal Geology, 2015Co-Authors: James M Wood, Hamed Sanei, Mark E Curtis, Christopher R ClarksonAbstract:Abstract In this study of the Triassic Montney Tight Gas siltstone play in the Western Canadian Sedimentary Basin petrophysical measurements of drill-core samples (porosity, pore throat size, water saturation and grain size) are integrated with Rock-Eval TOC data, organic petrography observations and SEM imaging to show that reservoir quality in the Gas window is strongly influenced by the pervasive presence of pore-occluding solid bitumen (and pyrobitumen at higher thermal maturity). The solid bitumen formed as a pore-filling liquid oil phase that was diagenetically and thermally degraded with further burial and increase in temperature. The proportion of solid bitumen filling the intergranular paleopore network can be expressed as bitumen saturation, and this attribute is found to be the dominant control on pore throat size and absolute permeability. The samples with low bitumen saturation and large pore throat radius (> 0.01 μm) have water saturations that generally increase as pore throat size diminishes, a relationship consistent with capillary theory for conventional water wet conditions. The samples with high bitumen saturation and small pore throat radius (
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characterization of organic matter fractions in an unconventional Tight Gas siltstone reservoir
International Journal of Coal Geology, 2015Co-Authors: Christopher R Clarkson, James M Wood, Hamed Sanei, Omid H Ardakani, Chunqing JiangAbstract:Abstract This paper on core samples collected from the Triassic Montney Formation Tight Gas reservoir in the Western Canadian Sedimentary Basin (WCSB) illustrates that operationally-defined S1 and S2 hydrocarbon peaks from conventional Rock–Eval analysis may not adequately characterize the organic constituents of unconventional reservoir rocks. Modification of the thermal recipe for Rock–Eval analysis in conjunction with manual peak integration provides important information with significance for the evaluation of reservoir quality. An adapted method of the analysis, herein called the extended slow heating (ESH) cycle, was developed in which the heating rate was slowed to 10 °C per minute over an extended temperature range (from 150 to 650 °C). For Montney core samples within the wet Gas window, this method provided quantitative distinctions between major organic matter (OM) components of the rock. We show that the traditional S1 and S2 peaks can now be quantitatively divided into three components: (S1 ESH ) free light oil (S2a ESH ) fluid-like hydrocarbon residue (FHR), and (S2b ESH + residual carbon) solid bitumen (more refractory, consolidated bitumen/pyrobitumen). The majority of the total organic carbon (TOC) in the studied Montney core samples consists of solid bitumen that represents a former liquid oil phase which migrated into the larger paleo-intergranular pore spaces. Physicochemical changes to the oil led to the precipitation of asphaltene aggregates. Subsequent diagenetic and thermal cracking processes further consolidated these asphaltene aggregates into “lumps” of solid bitumen (or pyrobitumen at higher thermal maturity). Solid bitumen obstructs porosity and hinders fluid flow, and thus shows strong negative correlations with reservoir qualities such as porosity and pore throat size. Although the FHR fraction constitutes a small portion of the total rock mass and volume in Montney samples it has important implications for reservoir quality. This fraction represents a thin film of condensed, heavy molecular hydrocarbon residue covering surfaces of the present-time pore spaces and may represent the lighter component of the paleo-oil that migrated into Tight interstices in the Montney reservoir. The FHR fraction potentially plays an important role in wettability alteration by creating hydrophobic matrix pore networks in portions of the reservoir that were not already filled with solid bitumen.
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characterization of Tight Gas reservoir pore structure using usans sans and Gas adsorption analysis
Fuel, 2012Co-Authors: Christopher R Clarkson, M Agamalian, Robert Marc Bustin, Lilin He, Melissa Freeman, Andrzej Pawel Radlinski, Yuri B Melnichenko, T P BlachAbstract:Small-angle and ultra-small-angle neutron scattering (SANS and USANS) measurements were performed on samples from the Triassic Montney Tight Gas reservoir in Western Canada in order to determine the applicability of these techniques for characterizing the full pore size spectrum and to gain insight into the nature of the pore structure and its control on permeability. The subject Tight Gas reservoir consists of a finely laminated siltstone sequence; extensive cementation and moderate clay content are the primary causes of low permeability. SANS/USANS experiments run at ambient pressure and temperature conditions on lithologically-diverse sub-samples of three core plugs demonstrated that a broad pore size distribution could be interpreted from the data. Two interpretation methods were used to evaluate total porosity, pore size distribution and surface area and the results were compared to independent estimates derived from helium porosimetry (connected porosity) and low-pressure N2 and CO2 adsorption (accessible surface area and pore size distribution). The pore structure of the three samples as interpreted from SANS/USANS is fairly uniform, with small differences in the small-pore range (<2000 A), possibly related to differences in degree of cementation, and mineralogy, in particular clay content. Total porosity interpreted from USANS/SANS is similar to (but systematically higher than) helium porosities measured on the whole core plug. Both methods were used to estimate the percentage of open porosity expressed here as a ratio of connected porosity, as established from helium adsorption, to the total porosity, as estimated from SANS/USANS techniques. Open porosity appears to control permeability (determined using pressure and pulse-decay techniques), with the highest permeability sample also having the highest percentage of open porosity. Surface area, as calculated from low-pressure N2 and CO2 adsorption, is significantly less than surface area estimates from SANS/USANS, which is due in part to limited accessibility of the Gases to all pores. The similarity between N2 and CO2-accessible surface area suggests an absence of microporosity in these samples, which is in agreement with SANS analysis. A core gamma ray profile run on the same core from which the core plug samples were taken correlates to profile permeability measurements run on the slabbed core. This correlation is related to clay content, which possibly controls the percentage of open porosity. Continued study of these effects will prove useful in log-core calibration efforts for Tight Gas.
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integration of microseismic and other post fracture surveillance with production analysis a Tight Gas study
Journal of Natural Gas Science and Engineering, 2011Co-Authors: Christopher R Clarkson, Joshua BeierleAbstract:Abstract Quantitative production analysis of Tight Gas reservoirs has historically been a challenge due to complex reservoir characteristics (ex. lateral and vertical heterogeneity, stress-sensitivity of permeability and porosity), induced hydraulic fracture properties in vertical wells (ex. multi-phase flow, conductivity changes, complex fracture geometries), operational complexities (ex. variable back-pressure, liquid-loading) and data quality (infrequent rate or flowing pressure reporting). All of these challenges conspire to make extraction of reservoir ( kh and OGIP ) and hydraulic fracture properties ( x f and fracture conductivity) soley from production/flowing pressure data difficult, often resulting in non-unique answers. In recent history, there has been the added complication that Tight Gas (and most recently shale Gas) reservoirs are now being exploited with horizontal wells, often stimulated using multiple hydraulic fracture stages, which imparts greater complexity on the analysis. Flow regime identification, which is critical to the correct analysis, is more complicated than ever owing to the number of possible flow regimes encountered in such wells. A case study is presented in which it is demonstrated that modern post-fracture surveillance data, such as microseismic and post-frac production logging, aids in both model identification and model calibration, which is critical to the analysis of hydraulically-fractured horizontal wells completed in Tight Gas formations. A workflow is presented in which offset vertical wells (to the horizontal wells) are first analyzed to obtain estimates of kh and hydraulic fracture properties, followed by commingled stage and single-stage production analysis of the multi- (transverse) hydraulic fracture horizontal wells. Microseismic data is incorporated into the analysis of the horizontal wells to 1) understand the orientation and degree of complexity of the induced hydraulic fractures and 2) constrain interpretations of effective hydraulic fracture lengths from production data analysis. It is also demonstrated that once the commingled stage analysis of the horizontal wells is completed, the total interpreted effective hydraulic fracture half-length may be allocated amongst the stages using a combination of production logs and tracer logs. The primary contribution of the current work is the presentation of workflows, emphasizing the integration of various data sources, to improve production analysis of multi-frac’d horizontal wells completed in Tight Gas formations. In addition to the workflows, it is shown that a combination of advanced production analysis approaches, including methods analogous to classic pressure transient analysis, production type-curve matching and simulation, may be necessary to arrive at a unique analysis.
Hamed Sanei - One of the best experts on this subject based on the ideXlab platform.
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solid bitumen as a determinant of reservoir quality in an unconventional Tight Gas siltstone play
International Journal of Coal Geology, 2015Co-Authors: James M Wood, Hamed Sanei, Mark E Curtis, Christopher R ClarksonAbstract:Abstract In this study of the Triassic Montney Tight Gas siltstone play in the Western Canadian Sedimentary Basin petrophysical measurements of drill-core samples (porosity, pore throat size, water saturation and grain size) are integrated with Rock-Eval TOC data, organic petrography observations and SEM imaging to show that reservoir quality in the Gas window is strongly influenced by the pervasive presence of pore-occluding solid bitumen (and pyrobitumen at higher thermal maturity). The solid bitumen formed as a pore-filling liquid oil phase that was diagenetically and thermally degraded with further burial and increase in temperature. The proportion of solid bitumen filling the intergranular paleopore network can be expressed as bitumen saturation, and this attribute is found to be the dominant control on pore throat size and absolute permeability. The samples with low bitumen saturation and large pore throat radius (> 0.01 μm) have water saturations that generally increase as pore throat size diminishes, a relationship consistent with capillary theory for conventional water wet conditions. The samples with high bitumen saturation and small pore throat radius (
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characterization of organic matter fractions in an unconventional Tight Gas siltstone reservoir
International Journal of Coal Geology, 2015Co-Authors: Christopher R Clarkson, James M Wood, Hamed Sanei, Omid H Ardakani, Chunqing JiangAbstract:Abstract This paper on core samples collected from the Triassic Montney Formation Tight Gas reservoir in the Western Canadian Sedimentary Basin (WCSB) illustrates that operationally-defined S1 and S2 hydrocarbon peaks from conventional Rock–Eval analysis may not adequately characterize the organic constituents of unconventional reservoir rocks. Modification of the thermal recipe for Rock–Eval analysis in conjunction with manual peak integration provides important information with significance for the evaluation of reservoir quality. An adapted method of the analysis, herein called the extended slow heating (ESH) cycle, was developed in which the heating rate was slowed to 10 °C per minute over an extended temperature range (from 150 to 650 °C). For Montney core samples within the wet Gas window, this method provided quantitative distinctions between major organic matter (OM) components of the rock. We show that the traditional S1 and S2 peaks can now be quantitatively divided into three components: (S1 ESH ) free light oil (S2a ESH ) fluid-like hydrocarbon residue (FHR), and (S2b ESH + residual carbon) solid bitumen (more refractory, consolidated bitumen/pyrobitumen). The majority of the total organic carbon (TOC) in the studied Montney core samples consists of solid bitumen that represents a former liquid oil phase which migrated into the larger paleo-intergranular pore spaces. Physicochemical changes to the oil led to the precipitation of asphaltene aggregates. Subsequent diagenetic and thermal cracking processes further consolidated these asphaltene aggregates into “lumps” of solid bitumen (or pyrobitumen at higher thermal maturity). Solid bitumen obstructs porosity and hinders fluid flow, and thus shows strong negative correlations with reservoir qualities such as porosity and pore throat size. Although the FHR fraction constitutes a small portion of the total rock mass and volume in Montney samples it has important implications for reservoir quality. This fraction represents a thin film of condensed, heavy molecular hydrocarbon residue covering surfaces of the present-time pore spaces and may represent the lighter component of the paleo-oil that migrated into Tight interstices in the Montney reservoir. The FHR fraction potentially plays an important role in wettability alteration by creating hydrophobic matrix pore networks in portions of the reservoir that were not already filled with solid bitumen.
Yili Kang - One of the best experts on this subject based on the ideXlab platform.
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comprehensive prediction of dynamic fracture width for formation damage control in fractured Tight Gas reservoir
International Journal of Oil Gas and Coal Technology, 2015Co-Authors: Yili Kang, Lijun You, Long Tang, Zhanghua LianAbstract:Developed fractures are beneficial for the economic and efficient development of Tight Gas reservoir. But they will lead to drill-in fluid loss and induce serious formation damage. Fracture width prediction is the key for reasonable selection of particle size distribution to prevent drill-in fluid loss and control formation damage in fractured Tight Gas reservoir. However, the reservoir fracture width is not constant but changed with effective stress variation induced by drill-in fluid invasion, which make it more difficult for fracture width prediction. In this paper, we develop a comprehensive method to predict the reservoir dynamic fracture width. This method is based on stress-dependent permeability experiment and finite element simulation which are conducted to determine the in-situ fracture width and dynamic fracture width. The in-situ width is used as the initial condition for the simulation. According to the experiment and simulation results for North-Western Sichuan Tight Gas reservoir, the in-situ fracture width is 3.28-18.59 µm and the dynamic fracture width is 17.89-763 µm. Based on the dynamic fracture width prediction, reasonable particle size distribution can be designed to prevent drill-in loss and control formation damage effectively. [Received: January 27, 2014; Accepted: September 20, 2014]
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prevention of fracture propagation to control drill in fluid loss in fractured Tight Gas reservoir
Journal of Natural Gas Science and Engineering, 2014Co-Authors: Yili Kang, Long Tang, Fei ChenAbstract:Abstract Developed fractures are beneficial for the economic and efficient development of Tight Gas reservoir. But they will lead to drill-in fluid loss and induce serious formation damage. Preventing natural fractures propagation is the key to control drill-in fluid loss in the fractured reservoir. Plugging and sealing the fracture loss channel with loss control material (LCM) can improve the fracture propagation pressure (FPP) effectively. However, the main parameters that affect the improved FPP are not clear. To our best knowledge, few papers have been published on the comprehensive parametric analysis for improved FPP to select reasonable LCM and control drill-in loss in fractured Tight Gas reservoir. In this paper, we develop a mathematic model to analyze the parameters that affect the FPP after plugging. Laboratory experiment is conducted to select reasonable LCM based on the parametric analysis. Study results show that formation stress anisotropy, elastic modulus, fracture length, fracture pressure and plugging location are the main parameters that impact the improved FPP. According to the analysis results, maximum plugging pressure and total loss volume before sealing are proposed as the key indexes for LCM selection. Experiment results show that reasonable combination of rigid granule, fiber and elastic particle can create a synergy effect to effectively control drill-in fluid loss in fracture Tight Gas reservoir.
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temporary sealing technology to control formation damage induced by drill in fluid loss in fractured Tight Gas reservoir
Journal of Natural Gas Science and Engineering, 2014Co-Authors: Yili Kang, Lijun You, Dujie ZhangAbstract:Abstract Western Sichuan Tight Gas reservoir is characteristic of developed natural fractures and ultra low matrix permeability. Developed fractures are beneficial for the economic and efficient development of Tight Gas reservoir. But they will lead to lost circulation of drill-in fluid and induce serious formation damage. Moreover, the dynamic fracture width which can reach several hundred microns or millimeter level resulting from drill-in fluid invasion increases the difficulty to solve the problem. To our best knowledge, few papers have been published on the technology that gives a synthetic consideration to both lost circulation control and formation damage prevention in fractured Tight Gas reservoir. In this paper, we develop the temporary sealing technology and propose its key indexes to control drill-in loss in fractured reservoir. Laboratory experiments are conducted to determine the optimal material size, type and concentration to meet the index requirements. Maximum plugging pressure, total loss volume before sealing and permeability recovery rate are the three key indexes for the temporary sealing technology. Results of laboratory experiment considering the three indexes show that the D90 of the bridging particle size distribution should be equal to the maximum dynamic fracture width. The reasonable combination of rigid granule, fiber and elastic particle can create a synergy effect. The optimal concentration for rigid granule, fiber and elastic particle is 5.0%, 3.0% and 2.5% respectively. Based on the temporary sealing technology, the maximum plugging pressure and permeability recovery rate can be improved to 15.0 MPa and 88.6% respectively, and the total loss volume before sealing can be reduced to only 49 mL.
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comprehensive evaluation of formation damage induced by working fluid loss in fractured Tight Gas reservoir
Journal of Natural Gas Science and Engineering, 2014Co-Authors: Yili Kang, Lijun You, Benjian ZhangAbstract:Abstract Western Sichuan Tight Gas reservoir is characteristic of developed natural fractures and ultra low matrix permeability. Developed fracture is beneficial for the economic and efficient development of Tight Gas reservoir. But it will lead to lost circulation of working fluid and induce formation damage. Lost circulation has frequently occurred during drill-in, completion and test process. Formation damage degree and damage range are the key indexes for the formation damage evaluation. To our best knowledge, few papers have been published on the comprehensive consideration of the above two indexes. In this paper, we conduct laboratory experiments and develop a mathematical model to evaluate the formation damage degree and determine the formation damage range. Based on the study results a formation damage pattern is established to analyze the mechanism and process of the formation damage induced by working fluid loss. The study results show that the average formation damage degree induced by drill-in fluid loss is 68.51% and increases to 78.70% when the kill fluid loss damage is taken into consideration. The radius of formation damage zone induced by working fluid loss is 15.8 m. The formation damage pattern is as follows: First the loss of drill-in fluid induces serious formation damage including sensitive damage, particle plugging and water phase trapping. Then the subsequent loss of kill fluid in the process of completion and test further aggravates the formation damage degree. Finally in the acidizing treatment the acidizing radius cannot exceed the damage zone radius so that the formation damage cannot be completely removed. The comprehensive evaluation and pattern of formation damage are necessary for designing reasonable reservoir protection and damage removal measures for the fractured Tight Gas reservoir.
Mingxu Yu - One of the best experts on this subject based on the ideXlab platform.
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impact of permeability heterogeneity on production characteristics in water bearing Tight Gas reservoirs with threshold pressure gradient
Journal of Natural Gas Science and Engineering, 2015Co-Authors: Mingxu Yu, Hongqing Song, Yuhe Wang, John Killough, Juliana Y LeungAbstract:Abstract In order to investigate the effects of permeability heterogeneity on Gas production in water-bearing Tight Gas reservoirs, the combined series of cores obtained from Sulige Gas field, one of the important water-bearing Tight Gas reservoirs in China, were tested. Based on different scenarios of permeability heterogeneity, the low-velocity non-Darcy flow mathematical models considering threshold pressure gradient (TPG) were established. The finite difference method was applied to numerically solve the nonlinear mathematical model, and the corresponding numerical program was completed. The consistency between the numerical results considering TPG and the experimental data indicates the validity and accuracy of the mathematical models. The numerical and experimental results show that ignoring the influence of TPG in water-bearing Tight Gas reservoirs will lead to inaccurate assessment of the well productivity. For heterogeneous water-bearing Tight Gas reservoir development, the production wells allocated in high permeability region will boost the recovery. However the higher the initial constant production rate, the shorter the stable production time. So an appropriate production rate should be allocated to maximize both the economic and social benefits. This research can quantitatively analyze the impacts of permeability heterogeneity in water-bearing Tight Gas reservoir developments and optimize the production rate and production pressure accordingly.
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productivity equation of fractured horizontal well in a water bearing Tight Gas reservoir with low velocity non darcy flow
Journal of Natural Gas Science and Engineering, 2014Co-Authors: Hongqing Song, Dawei Yang, Mingxu YuAbstract:Abstract Based on the features of Tight Gas reservoirs and considering the existence of threshold pressure gradient (TPG), a new mathematical model was established for low-velocity non-Darcy flow in water-bearing Tight Gas reservoirs. Calculation method of control areas is also presented. Productivity equations of vertical fractured well and horizontal fractured well in Tight Gas reservoirs are obtained with TPG. Influential factors were analyzed to provide theoretical basis for the effective development of Tight Gas reservoirs. According to the numerical results, with the increase of pressure drawdown, both the volumetric flow rate of Gas well and control area grow first and then gradually becomes stable. The influence of TPG on the volumetric flow rate of Gas well is great and cannot be neglected. For fractured horizontal well, Gas well production increases with the increase of flow conductivity capacity and half-length of hydraulic fractures. For certain length of the borehole, when the fracture spacing increases and the number of the fractures decreases, the control area and the volume flow rate of the Gas well decreases. Consequently, there is an optimum allocation among drawdown pressure, fracture half-length, fracture conductivity and fracture spacing to achieve maximum production.
