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Abstract In this paper, the problem of a hydraulic fracture interacting with a pre-existing natural fracture has been investigated by using a cohesive zone finite element model. The model fully couples fluid flow, fracture propagation and elastic deformation, taking into account the friction between the contacting fracture surfaces and the interaction between the hydraulic fracture and the natural fracture. The effect of the field conditions, such as in-situ stresses, and rock and fracture mechanical and geometrical properties, intersection angle and the treatment parameters (fracturing fluid viscosity and injection rate) on the hydraulic fracture propagation behavior has been analyzed. The finite element modeling results provide detailed quantitative information on the development of various types of hydraulic fracture โ natural fracture interaction, fracture geometry evolution and injection pressure history, and allow us to gain an in-depth understanding of the relative roles of various parameters. The value of a parameter calculated as the product of fracturing fluid viscosity and injection rate can be used as an indicator to gauge if crossing or diverting behavior is more likely. In addition, using a finite element approach allows the analysis to be extended to include the effects of fluid leakoff and poroelastic effect, and to study hydraulic fracture height growth through a system of nonhomogeneous layers and their bedding planes.
Creep: A Neglected Phenomenon in Coal Permeability Evolution and Coalbed Methane Production
Danesh, N. N. (School of Mechanical and Mining Engineering, The University of Queensland) | Chen, Z.. (School of Mechanical and Mining Engineering, The University of Queensland) | Aminossadati, S. M. (School of Mechanical and Mining Engineering, The University of Queensland) | Kizil, M.. (School of Mechanical and Mining Engineering, The University of Queensland) | Pan, Z.. (CSIRO) | Connell, L. D. (CSIRO)
Abstract During gas production, coalbed experiences compaction over time when effective stress increases as a result of pressure depletion triggered by escaping gas from micropores through desorption and diffusion. It is deemed that time-dependent compaction deformation (compaction creep) and deterioration of coal structure lead to a decrease in coal permeability. Alteration of compaction rate and permeability of coalbed depends on factors such as coal properties, pore pressure, time, and temperature. Thus far, little studies have been conducted to investigate the impact of compaction creep, viscoelastic, and viscoplastic behavior of coal on permeability. Creep may have such significant impact on coal permeability that its negligence may result in overestimation of Coalbed Methane (CBM) production. Appreciation of creep phenomenon, coal properties such as viscoelasticity and viscoplasticity, and their impact on the interaction of coal permeability and gas production borehole enables optimisation of CBM production. In this study, we aim to examin permeability models and highlight the significance of creep as a factor influencing the evolution of coal permeability and CBM production.
- North America > Canada > Alberta (0.29)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Abstract In this text the authors present a study on the approach of estimating the lost gas during the retrieval process of coal sample within wellbore. A new method is proposed to improve the accuracy of prediction as the traditional methods often give inaccurate predictions. To this end, the major sources of errors with those traditional methods are first analysed. Then the pertinent modifications are made in this proposed method to have these errors minimised. With the present method the following improvements are made. (1) Physically, the transport equation used here for gas flow in the core includes both advection and diffusion effects; in contrast, the traditional methods are fundamentally based on a linear diffusion equation. (2) Geometrically, the present method considers the the actual shape of the core sample (say, a cylinder), while the routine counterparts have to simplify the geometry of the core to be a one-dimensional spherical object. (3) Numerically, the present method employs the actual retrieval history to specify the boundary conditions of the core sample, and uses a neural network technique to best fit the measurements with the numerical solutions obtained. In contrast, the routine counterparts need to assume a constant or a linearly declining boundary condition such that an analytical solution (in a form of a series) can be obtained. When the relevant sorption isothermal curve for the coal is known, the proposed model contains three parameters to be determined, which are related to the effective permeability, the effective diffusion coefficient, and the initial gas content, respectively. These parameters are determined through best-match of the experimental data by the neural network simulations. An application example is presented in this study and it shows that the proposed method can significantly improve the accuracy of prediction for the lost gas volume or the initial gas content than its traditional counterparts.
- Geology > Geological Subdiscipline (0.68)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.67)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Measurement of Shale Anisotropic Permeability and Its Impact on Shale Gas Production
Pan, Zhejun (CSIRO) | Ma, Yong (China University of Petroleum) | Danesh, Nima Noraei (The University of Queensland) | Connell, Luke D. (CSIRO) | Sander, Regina (CSIRO) | Down, David I. (CSIRO) | Camilleri, Michael (CSIRO)
Abstract Gas shales act as both the source rock and reservoir for the petroleum. One of the important characteristics of the reservoir is its low permeability, making gas production difficult. Although economic shale gas production has been achieved through horizontal drilling and multistage hydraulic fracturing, shale reservoir permeability is still one of the critical parameters in the evaluation of a shale gas play. In the present work, experimental measurement of shale anisotropic permeability is determined using a cubic shale sample in a triaxial cell. Anisotropic permeability was measured at a series of gas pressures and confining pressures. A permeability model incorporating stress and Klinkenberg effect was applied to describe the data. The model was applied in the reservoir simulator SIMED II to investigate the impact of anisotropic permeability and its change on shale gas production. Results are compared between using the vertical permeability, horizontal permeability, or anisotropic permeability as the reservoir permeability. The results show that using vertical permeability will significantly underestimate the gas production rate. This demonstrates that measuring directional permeability and using the most appropriate one is important for evaluating shale gas production and development of shale gas assets.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- (5 more...)
Experimental Study of Controlling Factors of the Continental Shale Matrix Permeability in Ordos Basin
Qu, Hongyan (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Zhou, Fujian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Xue, Yanpeng (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Pan, Zhejun (CSIRO)
Abstract Matrix permeability could be a key factor controlling shale gas production from matrix to micro fractures and further to hydraulic fractures in Chinese shales due to the low porosity and permeability, affected by its unique geochemistry and geology settings including the Total Organic Carbon (TOC) content, mineral compositions, pore structure, and deposition environment. This paper aims to study the controlling factors of the matrix permeability in the continental shale formation, Ordos, China, through modified laboratory measurement mothod. In this work, nine shale samples were collected from three wells in Chang 7 member, Yanchang continental formation, Ordos Basin, China, crushed at in-situ water saturation and sieved to certain size (20/40 mesh). Matrix permeability of these samples was measured with modified Pressure-decay method and compard with the results with Pulse-decay method. The reasons for the discrepancy of these results with different methods were analysed. Moreover, the effects of geochemistry and geology factors on matrix permeability were investigated by grouping these crushed samples according to the variation of TOC, mineral compositions and deposition depth. The relationships between shale matrix permeability and TOC as well as depth were established respectively. Furthermore, the effects of other factors such as mineralogical compositions and pore structure parameters were studied through the Scanning Electron Microscope (SEM) and X-ray diffraction (XRD) analysis. The results show that the shale matrix permeability measured by the Pulse-decay method is generally up to two orders of magnitude higher than that by the Pressure-decay method due to the presence of the natural or artificial micro fractures. In addition, the geochemistry and geology parameters including the TOC, mineral compositions, pore structure and deposition environment have significant effects on the shale matrix permeability. Matrix permeability in Yanchang shale formation is strongly related to TOC and the mineral compositionand even at the similar depth, porosity and matrix permeability are different due to the variation of TOC as a result of geological heterogeanity. TOC in Yanchang formation varies considerably in the range of 1.8 wt % to over 11 wt %, resulting in significant changes in matrix permeability ranging from 0.02 nD to 10 nD, resulting from the influence of the organic matter and clay minerals on total pore volume based on the result of SEM and XRD analysis. The accurate measurement of matrix permeability is important for computer simulation modeling of long term shale gas production.
- Asia > China > Shaanxi Province (0.74)
- Asia > China > Shanxi Province (0.64)
- Asia > China > Gansu Province (0.64)
- Research Report > New Finding (0.84)
- Research Report > Experimental Study (0.70)
- Phanerozoic > Mesozoic (1.00)
- Phanerozoic > Paleozoic (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)