Factors influencing porosity and permeability, Wilcox Group (Eocene), Karnes County, Texas

Petrographic and petrophysical data from 57 sandstone samples collected from the available parts of a 2500 ft section of core (-5094 ft to -7474 ft) recovered from the Seaboard Oil Kolodziejcyk #1 well in southeastern Karnes County were used to determine the diagenetic changes within the rocks and their effect on porosity and, indirectly, permeability. The core penetrated deposits of shoreface (with probable tidal channel and/or small (tidal?) delta), tidal flat and bay-lagoon environments. Framework grain mineralogy is similar for samples regardless of environment of deposition. The sandstones are chiefly fine to very fine and well sorted with an average composition of Q₅₉ F₁₆ R₂₅; matrix values range from 0 to 46 percent and cement values range from 8 to 34 percent. Permeability values range from nil to over 650 millidarcies. Porosity values, also determined by gas injection, range from 6 to 36 percent and thin section determined porosity values range from 0 to 20 percent. Petrophysically-determined porosity has a positive correlation with both "petrophysical" and "petrographic" porosity. Initial porosity of sand was reduced by the following sequence of partly overlapping events: bioturbation penecontemporaneous with deposition; compactional rotation of framework grains; compactional deformation of ductile grains; and precipitation of authigenic quartz, kaolinite, calcite, ferroan calcite and dolomite cement. A few samples lost most porosity due to bioturbation penecontemporaneous with deposition but the majority lost about 12 percent due to compactional effects followed by up to 30 percent loss by cementation. Up to 21 percent porosity resulted from the dissolution of calcite from sandstone by natural acid formation water at about the maximum depth of burial. This secondary porosity formed by the dissolution of both calcite cement and calcite-replaced framework grains (chiefly plagioclase) and is most pronounced in shoreface and tidal channel sandstones. Secondary porosity is identified by patchy distribution of calcite cement, locally oversized pores (where framework grains were replaced and the replacement calcite and adjacent calcite cement were removed), ragged edges on some quartz overgrowths in samples without calcite that are the result of corrosion of quartz grain margins by calcite, and skeletonized plagioclase grains in samples without calcite cement. Because essentially all effective porosity in these Wilcox sandstones at present is secondary porosity, porosity is not a function of depth in the well studied. If secondary porosity like that in Wilcox sandstones forms elsewhere in the Gulf Coast and other basins, good reservoir sandstones will exist at depths greater than expected under normal conditions in the subsurface

Name thesis:degree_name

Master of Arts

Level thesis:degree_level

Masters

Discipline thesis:degree_discipline

Earth and Planetary Sciences

Grantor

University of Texas at Austin

Year dc:date.issued

1977

Author dc:creator

• Stanton, George Duwe, 1949-

Advisor dc:contributor.advisor

• McBride, Earle F.

• Karnes County sandstone
• Wilcox Group sandstone
• Texas sandstone
• Texas sandstone porosity
• Texas sandstone permeability
• Texas sandstone diagenesis
• Sandstone porosity factors
• Sandstone permeability factors
• Wilcox sandstones

Statement dc:rights

• Copyright © is held by the author. Presentation of this material on the Libraries' web site by University Libraries, The University of Texas at Austin was made possible under a limited license grant from the author who has retained all copyrights in the works.

Language dc:language.iso

en

Identifier URI

https://doi.org/10.26153/tsw/52256

OAI identifier oai:identifier

oai:repositories.lib.utexas.edu:2152/125696