Geothermal and Heavy-Oil Resources in Texas: Direct Use of Geothermal Fluids to Enhance Recovery of Heavy Oi

Abstract
In a five-county area of South Texas, geopressured-geothermal reservoirs in the Paleocene-Eocene Wilcox Group lie below medium- to heavy-oil reservoirs in the Eocene Jackson Group. This fortuitous association suggests the use of geothermal fluids for thermally enhanced oil recovery (TEOR). Geothermal fairways are formed, where thick deltaic sandstones are compartmentalized by growth faults. Wilcox geothermal reservoirs in South Texas are present at depths of 11,000 to 15,000 ft (3,350 to 4,570 m) in laterally continuous sandstones 100 to 200 ft (30 to 60 m) thick. Permeability is generally low (typically 1 md), porosity ranges from 12 to 24 percent, and temperature exceeds 250°F (121°C). Reservoirs containing medium (20° to 25° API gravity) to heavy (10° to 20° API gravity) oil are concentrated along the Texas Coastal Plain in the Jackson-Yegua Barrier/Strandplain (Mirando Trend), Cap Rock, and Piercement Salt Dome plays and in the East Texas Basin in Woodbine Fluvial/Deltaic/Strandplain Sandstone and Paluxy Fault Line plays. The Jackson-Yegua Barrier/Strandplain (Mirando Trend) is the most favorable play for TEOR of medium to heavy oil because of the abundance of candidate reservoirs, relative simplicity of reservoir architecture, and shallow depth of burial. Updip pinch-out of shallow barrier bar/strandplain sandstones largely controls the distribution of medium-to heavy-oil reservoirs in the Jackson Group. Subtle structure, small faults, and sandstone-body pinch-outs form lateral barriers of the reservoirs. Structural, depositional, and diagenetic variations cause reservoir compartmentalization. The medium- to heavy-oil reservoirs are typically porous (25 to 35 percent) and permeable (100 to 1,000 md), slightly clayey, fine-to medium-grained sand and sandstones. Calcite-cemented zones of low porosity (approximately 5 percent) and permeability (approximately 0.01 md) compartmentalize the reservoirs. Injection of hot, moderately fresh to saline brines will improve oil recovery by lowering viscosity and decreasing residual oil saturation. Smectite clay matrix could swell and clog pore throats if injected waters have low salinity. The high temperature of injected fluids will collapse some of the interlayer clays, thus increasing porosity and permeability. Reservoir heterogeneity resulting from facies variation and diagenesis must be considered when siting production and injection wells within the heavy-oil reservoir. The ability of abandoned gas wells to produce sufficient volumes of hot water over the long term will also affect the economics of TEOR.
Authors
Steven J. Semo
Timothy G. Walter
Citation

Seni, S. J., and Walter, T. G., 1993, Geothermal and Heavy-Oil Resources in Texas: Direct Use of Geothermal Fluids to Enhance Recovery of Heavy Oil: The University of Texas at Austin, Bureau of Economic Geology, Geological Circular 93-3, 52 p. doi.org.10.23867/gc9303D.

ISSN
2475-3637
Number of figures
34
Number of pages
52
Publisher
The University of Texas at Austin, Bureau of Economic Geology
Series
Geological Circular
Year
1993