Show simple item record

dc.contributor.authorBahrami, Hassan
dc.contributor.authorRezaee, M. Reza
dc.contributor.authorJayan, V.
dc.contributor.authorHossain, Mofazzal
dc.date.accessioned2017-03-15T22:06:13Z
dc.date.available2017-03-15T22:06:13Z
dc.date.created2017-02-15T01:16:44Z
dc.date.issued2012
dc.date.submitted2017-02-15
dc.identifier.citationBahrami, H. and Rezaee, M.R. and Jayan, V. and Hossain, M. 2012. Welltest analysis of hydraulically fractured tight gas reservoirs: An Example from Perth Basin, Western Australia. APPEA Journal. 52: pp. 1-12.
dc.identifier.urihttp://hdl.handle.net/20.500.11937/49598
dc.description.abstract

Welltest interpretation requires the diagnosis of reservoir flow regimes to determine basic reservoir characteristics. In hydraulically fractured tight gas reservoirs, the reservoir flow regimes may not clearly be revealed on diagnostic plots of transient pressure and its derivative due to extensive wellbore storage effect, fracture characteristics, heterogeneity, and complexity of reservoir. Thus, the use of conventional welltest analysis in interpreting the limited acquired data may fail to provide reliable results, causing erroneous outcomes. To overcome such issues, the second derivative of transient pressure may help eliminate a number of uncertainties associated with welltest analysis, and provide a better estimate of the reservoir dynamic parameters. This paper describes a new approach regarding welltest interpretation for hydraulically fractured tight gas reservoirs— using the second derivative of transient pressure. Reservoir simulations are run for several cases of nonfractured and hydraulically fractured wells to generate different type curves of pressure second derivative, and for use in welltest analysis. A field example from a Western Australian hydraulically fractured tight gas welltest analysis is shown, in which the radial flow regime could not be identified using standard pressure build-up diagnostic plots. Therefore, it was not possible to have a reliable estimate of reservoir permeability. The proposed second derivative of pressure approach was used to predict the radial flow regime trend based on the generated type curves by reservoir simulation, to estimate the reservoir permeability and skin factor. Using this analysis approach, the permeability derived from the welltest was in good agreement with the average core permeability in the well, thus confirming the methodology’s reliability.

dc.publisherAustralian Petroleum Production and Exploration Association
dc.titleWelltest analysis of hydraulically fractured tight gas reservoirs: An Example from Perth Basin, Western Australia
dc.typeJournal Article
dcterms.dateSubmitted2017-02-15
dcterms.source.volume52
dcterms.source.startPage1
dcterms.source.endPage12
dcterms.source.issn13264966
dcterms.source.titleAPPEA Journal
curtin.digitool.pid248013
curtin.digitool.pid248014
curtin.pubStatusPublished
curtin.departmentDepartment of Petroleum Engineering
curtin.identifier.scriptidPUB-SE-DPE-RR-69024
curtin.accessStatusFulltext not available


Files in this item

Thumbnail
Thumbnail

This item appears in the following Collection(s)

Show simple item record