Title page for ETD etd-07292012-174652

Type of Document Master's Thesis
Author Torsch, William C
URN etd-07292012-174652
Title Thermal and pore pressure history of the Haynesville Shale: A numerical study of hydrocarbon generation, overpressure, and natural hydraulic fractures
Degree Master of Science (M.S.)
Department Geology & Geophysics
Advisory Committee
Advisor Name Title
Nunn, Jeffrey Committee Chair
Dahi, Arash Committee Member
Hanor, Jeffrey Committee Member
  • Haynesville Shale
  • fractures
  • pore pressure
  • hydrocarbon generation
  • north Louisiana
Date of Defense 2012-06-22
Availability unrestricted
New drilling technology has led to a revival of drilling in mature petroleum basins such as the Haynesville Formation in east Texas and north Louisiana. In north Louisiana, the Upper Jurassic (Kimmeridgian) aged Haynesville shale has a basinward SW dip and is located at depths ranging from around 10,500 ft to the northeast and 14,000 ft to the southwest with local minimums at the Sabine and Monroe Uplifts. Formation thickness ranges from 100 to 400 feet. Prolific natural gas production is attributed to relatively high average porosity (8 to 14%) and a high geopressure gradient > 0.9 psi/ft. (Wang and Hammes, 2010). Using subsurface data, 1-dimensional and 2-dimensional models across the North Louisiana Salt Basin were created to estimate the thermal, pressure, and fluid flow histories of the Haynesville Shale. Disequilibrium compaction from rapid sedimentation in the low permeability (nanodarcy) Haynesville Shale coupled with hydrocarbon generation has resulted in high pore pressures ranging from about 7000 psi to 12000 psi. Hydrocarbon generation resulted in a maximum pressure increase of 500 psi at 88 Ma; however models created with and without hydrocarbon generation produced nearly identical results for present day pore pressure indicating that disequilibrium compaction is the most significant mechanism in generating overpressure. Updip fluid migration to the Sabine Uplift within the Haynesville Shale and underlying Smackover Limestone has resulted in abnormally high fluid pressures on the Sabine Uplift. 1D and 2D models did not calculate pressures in excess of the fracture gradient; however natural fractures likely aided in lateral fluid migration within the Haynesville Shale. A 3D model that incorporates fluid migration from the entire basin and the East Texas Salt Basin is needed to accurately estimate the pressure history of the Haynesville Shale.
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