AT0001D. Atlas of Major Texas Gas Reservoirs, by E. C. Kosters and others. 161 p., 459 figs., 77 tables, 4 oversize color plates, 1989. ISBN: 978-1-970007-00-8. doi.org/10.23867/AT0001D. Downloadable PDF. To purchase this publication in book format, please order AT0001.

Deep-water sandstones of the Oligocene-age Hackberry unit of the Frio Formation contain significant quantities of oil and gas remain potentially one of the most productive exploration targets in southeast Texas. The Hackberry is a wedge of sandstone and shale containing bathyal fauna that separates upper Frio barrier-bar-strandplain sandstones from lower Frio neritic shale and sand. Major Hackberry sandstones lie atop a channeled unconformity that forms the base of the unit. Sandstones in a typical sand-rich channel at Port Arthur field grade upward from a basal, confined channel-fill sandstone to more widespread, broad, fan-channel deposits. Topmost are proximal to medial fan deposits and overbank turbidite deposits. The sequence suggests that Hackberry sandstones were laid down by an onlapping submarine canyon-fan complex deposited in canyons that eroded headward into the contemporaneous Frio barrier system. Regional maps and seismic interpretations outline a network of sand-filled channels extending from the barrier toward the southeast.

tectonics - the intrusion of Danbury Dome and the development of a salt-withdrawal basin. At Port Arthur, low-displacement, long-lived faults formed on a sand-poor shelf margin contemporaneously with broad salt uplifts and basins. Variability in styles is related to the nature and extent of Frio sedimentation and shelf-margin progradation and to the presence or absence of salt. Structural styles that are conducive to the development of large geothermal reservoirs include blocks between widely spaced growth faults having dip reversal, salt-withdrawal basins, and shale-withdrawal basins. These styles are widespread on the Texas Gulf Coast. However, actually finding a large reservoir depends on demonstrating the existence of sufficient sandstone with adequate quality to support geopressured geothermal energy production.

Three areas in the Texas Gulf Coast region with different depositional settings, structural styles, and sandstone distribution were studied with well log and seismic data to evaluate some of the controls on subsurface conditions in geopressured aquifers. Structural and stratigraphic interpretations were made primarily on the basis of well log correlations. Seismic data confirm the log interpretations but also are useful in structure mapping at depths below well control.

The Port Arthur field, Jefferson County, Texas, was selected as a prospective watered-out gas field that is favorable for application of secondary enhanced gas recovery methods. This field contains multiple watered-out gas reservoirs, multiple thick aquifers, and gas stringer sandstones at depths of 10,850 to 11,700 ft. Sidewall core data show that the average porosity is 30 percent and average permeability is 60 md. Reservoir simulation studies predict that 5.10 x 1,000,000,000 standard cubic feet of gas can be recovered by natural flow from the 'C' sandstone over an 8-year period by reducing reservoir pressure from 6,632 to 4,309 psig. The break-even gas price is $2.40 per thousand standard cubic feet for a 15-percent rate of return after payment of Federal income taxes. Results of reservoir modeling also predict that a field test would pay off the original investment in 3 years.

This report documents the results of the first year of a two-year examination of the geologic and engineering attributes of the major oil-producing reservoirs of Texas. The goals of year one of this program include: (1) Collect, collate, and synthesize geologic, engineering, and production data on major Texas oil reservoirs. Reservoirs that have produced more than 10 million barrels of oil were included in the initial data base. (2) Develop geologically related familes of reservoirs, called plays. A hydrocarbon play is a group of geologically related fields having basically the same source-reservoir-trap controls. Primary groupings are by similar reservoir genetic facies. Further subdivision is usually by trap type. (3) Using data from files of the Texas Railroad Commission and other public sources, characterize each defined oil play in terms of: (a) recoverable reserves, (b) volume of in-place oil, (c) petrophysical properties of the reservoir, (d) trapping mechanism, (e) fluid properties, (f) drive mechanism, (g) reservoir management practices and conventional well spacing, and (h) calculated oil recovery efficiency. (4) Select those plays which, because of their large volume of in-place oil, low recovery efficiencies, and favorable reservoir and fluid properties, are primary coandidates for more detailed geologic and engineering analysis. Suchmore » candidate plays are the targets for significant improvement of ultimate production. (5) Evaluate comparative recovery efficiency as a function of well spacing. (6) Accomplish a preliminary examination of the utility of generic reservoir facies models in prediction of reservoir compartmentalization and heterogeneity, and thus as predictors of reservoir performance. 8 figures, 4 tables.« less

External and internal continuity of Tertiary sandstones are controlled by various factors including structural trends, sand body geometry, and the distribution of mineral framework, matrix, and intersticies within the sand body. Except for the limits imposed by faults, these factors are largely inherited from the depositional environment and modified during sandstone compaction and cementation. Sandstone continuity affects energy exploration and production strategies. The strategies range in scope from regional to site-specific and closely parallel a sandstone hierarchy. The hierarchy includes subdivisions ranking from genetically related aquifer systems down to individual reservoirs within a fault-bounded sandstone. Volumes of individual reservoirs are 50% less to 200% more than estimated from conventional geologic mapping. In general, mapped volumes under-estimate actual volumes where faults are nonsealing and overestimate actual volumes where laterally continuous shale breaks cause reductions in porosity and permeability. Gross variations in these pore properties can be predicted on the basis of internal stratification and sandstone facies. Preliminary analyses indicate that large aquifers are found where barrier and strandplain sandstones parallel regional faults or where fluvial (meandering) channels trend normal to regional faults. Within these sand bodies, porosity and permeability are highest in large-scale crossbedded intervals and lowest in contorted, bioturbated, andmore » small-scale ripple cross-laminated intervals.« less