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dc.contributor.authorZhang, Y.
dc.contributor.authorRezaee, Reza
dc.contributor.authorMüeller, T.M.
dc.contributor.authorZheng, G.
dc.contributor.authorLi, J.X.
dc.contributor.authorFan, Y.
dc.contributor.authorZeng, B.
dc.contributor.authorZhou, X.
dc.date.accessioned2022-11-02T05:43:25Z
dc.date.available2022-11-02T05:43:25Z
dc.date.issued2020
dc.identifier.citationZhang, Y. and Rezaee, R. and Müeller, T.M. and Zheng, G. and Li, J.X. and Fan, Y. and Zeng, B. et al. 2020. Permeability inversion using induced microseismicity: A case study for Longmaxi shale gas reservoir. Interpretation. 8 (2): pp. SG21-SG31.
dc.identifier.urihttp://hdl.handle.net/20.500.11937/89555
dc.identifier.doi10.1190/int-2019-0182.1
dc.description.abstract

We predict the flow permeability and its spatial distribution for the Longmaxi shale gas reservoir using microseismicity induced during hydraulic fracturing stimulation. In the time-of-occurrence versus distance-from-injector plot, we find that microseismic points exhibit a parabolic envelope, which we interpret as a triggering front. This reveals that fluid pressure diffusion is at least one of underlying mechanisms of microseismicity generation. We derive the large-scale equivalent diffusivity from the triggering front plot and thereafter obtain a 3D diffusivity map of the heterogeneous reservoir by solving an eikonal-like equation suggested previously. During this process, we apply kriging interpolation to increase the density of sparsely distributed microseismic points. The resulting diffusivity ranges between 1.0 m2·s-1 and 25.85 m2 s-1 with the peak probability attained at 1.8 m2 s-1, which is consistent with the estimate we obtain from the triggering front analysis. We transform the diffusivity map into a permeability map using three different theories of fluid pressure diffusion in porous media. These are the seismicity-based-reservoir-characterization method (SBRC) based on Biot's theory of poroelasticity, the quasi-rigid medium approximation (QRMA) and the deformable medium approximation (DMA) based on the de la Cruz-Spanos theory. The permeability according to QRMA is slightly higher than that from SBRC, yet we observe no significant difference. However, these estimates are both by one order of magnitude higher compared with the permeability estimate from DMA. Furthermore, the permeability from all three theories is much higher than that from previously reported core sample measurements. We interpret this as the difference between large-scale equivalent and matrix permeability and therefore lend weight to the hypothesis that there exist highly conducting fluid pathways, such as natural fractures.

dc.languageEnglish
dc.publisherSOC EXPLORATION GEOPHYSICISTS
dc.subjectScience & Technology
dc.subjectPhysical Sciences
dc.subjectGeochemistry & Geophysics
dc.subjectFLUID TRANSPORT-PROPERTIES
dc.subjectSICHUAN BASIN
dc.subjectEXPLORATION
dc.subjectHETEROGENEITY
dc.subjectPROPAGATION
dc.subjectPOROSITY
dc.subjectPORES
dc.subjectSEM
dc.titlePermeability inversion using induced microseismicity: A case study for Longmaxi shale gas reservoir
dc.typeJournal Article
dcterms.source.volume8
dcterms.source.number2
dcterms.source.startPageSG21
dcterms.source.endPageSG31
dcterms.source.issn2324-8858
dcterms.source.titleInterpretation
dc.date.updated2022-11-02T05:43:25Z
curtin.departmentWASM: Minerals, Energy and Chemical Engineering
curtin.accessStatusFulltext not available
curtin.facultyFaculty of Science and Engineering
curtin.contributor.orcidRezaee, Reza [0000-0001-9342-8214]
curtin.contributor.researcheridRezaee, Reza [A-5965-2008]
dcterms.source.eissn2324-8866
curtin.contributor.scopusauthoridRezaee, Reza [39062014600]


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