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dc.contributor.advisorWattenbarger, Robert A.
dc.creatorAlkouh, Ahmad
dc.date.accessioned2015-01-09T20:25:07Z
dc.date.available2015-01-09T20:25:07Z
dc.date.created2014-05
dc.date.issued2014-04-04
dc.date.submittedMay 2014
dc.identifier.urihttp://hdl.handle.net/1969.1/152548
dc.description.abstractShale gas reservoirs with multistage hydraulic fractures are commonly characterized by analyzing long-term gas production data, but water flowback data is usually not included in the analysis. However, this work shows there can be benefits to including post-frac water flowback and long-term water production data in well analysis. In addition, field data indicate that only 10-40% of the frac water is recovered after the flowback. This work addresses two main question: Where is the rest of the injected frac fluid that is not recovered and what is the mechanism that is trapping it? And how can the water flowback data be used in estimating effective fracture volume using production data analysis tools? A number of simulation cases were run for single and two phase (gas/water) for modeling flowback and long-term production periods. Various physical assumptions were investigated for the saturations and properties that exist in the fracture/matrix system after hydraulic fracturing. The results of these simulations were compared with analytical solutions and data from actual wells using diagnostic and specialized plots. The results of these comparisons led to certain conclusions and procedures describing possible reservoir conditions after hydraulic fracturing and during production. Past publications have suggested that the lost frac water is trapped in the natural fracture or imbibed into the rock matrix near the fracture face. Natural fracture spacing could be a possible explanation of the lost frac water. These concepts are tested and the challenge of simulating a natural fracture with trapped water without imbibition is solved using a new hybrid relative permeability jail. This concept was tested for the period of flowback, shut-in and production. This work presents the benefits of a new method for combining water flowback and long-term water production data in shale gas analysis. Water production analysis can provide effective fracture volume which was confirmed by the cumulative produced water. This will help when evaluating fracture-stimulation jobs. It also shows the benefits of combining flowback and long-term water production data in the analysis of shale gas wells. In some cases, the time shift on diagnostic plots changes the apparent flow regime identification of early gas production data. This leads to different models of the fracture/matrix system. The presented work shows the importance of collecting and including water flowback data in long-term production data.
dc.format.mimetypeapplication/pdf
dc.language.isoen
dc.subjectshale
dc.subjectwater
dc.subjectflowback
dc.subjectproduction analysis
dc.subjectgas
dc.subjectpressure transient
dc.titleNew Advances in Shale Gas Reservoir Analysis Using Water Flowback Data
dc.typeThesis
thesis.degree.departmentPetroleum Engineering
thesis.degree.disciplinePetroleum Engineering
thesis.degree.grantorTexas A & M University
thesis.degree.nameDoctor of Philosophy
thesis.degree.levelDoctoral
dc.contributor.committeeMemberSchechter, David S.
dc.contributor.committeeMemberMaggard, J. Bryan
dc.contributor.committeeMemberSun, Yuefeng
dc.type.materialtext
dc.date.updated2015-01-09T20:25:07Z
local.etdauthor.orcid0000-0003-0437-0626


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