Determining a Standard Protocol for Permeability from Thin Section Image Analysis

dc.contributor.advisorHathon, Lori A.
dc.contributor.committeeMemberMyers, Michael T.
dc.contributor.committeeMemberAndrew, Matthew
dc.creatorTripathi, Dutt N.
dc.date.accessioned2018-12-03T14:52:19Z
dc.date.available2018-12-03T14:52:19Z
dc.date.createdMay 2018
dc.date.issued2018-05
dc.date.submittedMay 2018
dc.date.updated2018-12-03T14:52:19Z
dc.description.abstractEstimation of the petrophysical properties of subsurface samples using imaging techniques and image analysis has received a lot of attention in recent years. Most of this has been focused on 3D imaging and subsequent modeling of formation properties, termed Digital Rock Physics, or DRP. This work typically requires that an intact sample of material is available. For cases in which sample type or quality are not sufficient for 3D imaging, or where cost is prohibitive, modeling of petrophysical properties using standard thin section images and image analysis is a viable alternative. We apply a Kozeny-Carman type model to thin section images of samples for which laboratory measurements of porosity and brine permeability were made. This has allowed us to model absolute permeability to within a factor of two for two sandstone samples having laboratory-measured permeabilities of 600mD and 8D respectively. A key input parameter to this model is an estimate of specific surface area. The 2D estimate of specific surface area is defined as the ratio of the total porosity perimeter to the total area analyzed. The normalization to area analyzed allows comparisons to be made among samples of variable grain size, for which different numbers of images must be analyzed. As image magnification changes, and as down-sampling or filtering of the image are applied during analysis, the measure of specific surface area also changes. Apart from this, fractal analysis for sandstones in thin section is performed. This allows us to account for the impact of magnification and processing when modeling permeability from 2D image data. In addition to the 2D image analysis, application of Lattice-Boltzman calculations to high-resolution Micro-CT scans of the same samples provides an additional estimate of permeability. The 3D images of the samples were analyzed with commercially available software. In general, the 2D model performs as well as, or better than, the 3D modeling for estimating absolute permeability. In addition, total porosity from 2D image segmentation agrees to within +/- 2% of laboratory measured porosity, over a range of porosities from 15% - 35%.
dc.description.departmentPetroleum Engineering, Department of
dc.format.digitalOriginborn digital
dc.format.mimetypeapplication/pdf
dc.identifier.urihttp://hdl.handle.net/10657/3605
dc.language.isoeng
dc.rightsThe author of this work is the copyright owner. UH Libraries and the Texas Digital Library have their permission to store and provide access to this work. Further transmission, reproduction, or presentation of this work is prohibited except with permission of the author(s).
dc.subjectThin section image analysis
dc.subjectPetrography
dc.subjectPermeability
dc.subjectPorosity
dc.titleDetermining a Standard Protocol for Permeability from Thin Section Image Analysis
dc.type.dcmiText
dc.type.genreThesis
local.embargo.lift2020-05-01
local.embargo.terms2020-05-01
thesis.degree.collegeCullen College of Engineering
thesis.degree.departmentPetroleum Engineering, Department of
thesis.degree.disciplinePetroleum Engineering
thesis.degree.grantorUniversity of Houston
thesis.degree.levelMasters
thesis.degree.nameMaster of Science

Files

Original bundle

Now showing 1 - 1 of 1
No Thumbnail Available
Name:
TRIPATHI-THESIS-2018.pdf
Size:
3.43 MB
Format:
Adobe Portable Document Format

License bundle

Now showing 1 - 2 of 2
No Thumbnail Available
Name:
PROQUEST_LICENSE.txt
Size:
4.43 KB
Format:
Plain Text
Description:
No Thumbnail Available
Name:
LICENSE.txt
Size:
1.81 KB
Format:
Plain Text
Description: