--> Abstract: Diagenetic Patterns of Austin Group and Their Control of Petroleum Potential, by Peter A. Scholle, Kelton Cloud; #90967 (1977).

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Abstract: Diagenetic Patterns of Austin Group and Their Control of Petroleum Potential

Peter A. Scholle, Kelton Cloud

The chalk of the Austin Group shows striking regional variations in porosity, permeability, and trace-element and isotopic geochemistry. Porosity and permeability values are highest across the San Marcos arch, where they average 15 to 30% porosity and 0.5 to 5 md matrix permeability. These values decrease slightly to the north (into the northeast Texas embayment). In northern Mexico, the Austin and its equivalents have about 3 to 8% porosity and permeability values of 0.01 md or less. Porosity and permeability also decrease in downdip sections of the Austin from outcrop to about 4,500-m depth.

The geochemical properties follow similar trends. Outcrop studies show that samples from the San Marcos arch and Sabine uplift have bulk oxygen isotopic values in the range of -2.7 to -4.0 per mil (relative to PDB). In the Rio Grande embayment of South Texas and northern Mexico, these values have shifted to -5.0 to -7.0 per mil, whereas in the northeast Texas embayment they range from -3.5 to -5.0 per mil. In downdip sections near the San Marcos arch, the oxygen isotopic values shift from about -2.8 at the surface to about -8.0 at 4,500 m. Average strontium trace-element values for the Austin Group on the San Marcos arch are 350 to 975 ppm, whereas in the Rio Grande embayment and the northeast Texas embayment they range from 950 to 1,775 ppm.

All chalk undergoes both mechanical and chemical compaction (pressure solution and reprecipitation) when subjected to sufficient differential stress. This stress generally is induced by addition of overburden, but also can be influenced by tectonic stresses and pore-fluid pressures. The presence of fresh (magnesium-poor) water in chalk, in conjunction with elevated differential stress has been shown, both theoretically and in nature, to accelerate chemical compaction greatly. Thus, the lateral and downdip variations in the petrophysical and geochemical properties of the chalk of the Austin Group presumably reflect differences in original thickness of overburden or proximity to zones of major deformation. The noted reduction in porosity between the San Marcos arch and the Rio Grande em ayment could have been produced, in the presence of magnesium-poor fluids, by about a 500-m difference in maximum overburden between the two areas. Greater overburden differences would have been required had marine (or other magnesium-rich) pore fluids been present; less overburden difference would have been needed if differential tectonic stresses were important.

Although the isotopic and trace-element values mentioned are compatible with these conclusions, they do not distinguish among the possible explanations. The smooth shift of isotopic values as a function of present burial depth in downdip sections and of probable paleoburial depths in lateral outcrop sections, indicates that maximum burial depth is the critical factor in porosity loss or retention. Only the rate of porosity loss is affected by water chemistry. Carbon isotopic analyses also rule out vadose diagenesis as having influenced porosity reduction in the Austin to any significant degree.

Oil production from the Austin Group is concentrated in the areas of the San Marcos arch and the Sabine uplift in a belt that is parallel with the outcrop trend and that ranges in depth from 200 to 2,000 m. Cumulative production, as of January 1976, from all fields in the Austin group in Texas totaled about 25 million bbl.
Production of oil and gas from chalks other than the Austin has been significant, although some of these reservoirs may include sandy, calcarenitic, or other impure chalks.

Wells completed in the Austin have a long history of production at rates far lower than initial production. Most recently drilled Austin wells have initial production rates of 200 to 500 BOPD, which decline within months to about 40 BOPD. These production histories indicate that most oil production from the Austin is from fractures. Yet, the concentration of production in areas of least diagenetic alteration, in association with the long histories of slow production, indicate that extended production is probably the result of very slow drainage of oil from the rock matrix. Artificial fracturing, a completion method used on virtually all current Austin wells, enhances both initial and long-term production by allowing shorter drainage paths through a larger number of fractures.

The best future oil and gas discoveries in the Austin and equivalent lithologies will probably be concentrated in three types of areas: (1) where the chalks may have had any type of pore fluid but have not been deeply buried (that is, between 0 and 2,000 m); (2) where marine pore fluids were retained and fresh water was excluded (in such areas, significant matrix porosity can be retained to as much as 3,000 m depth); and (3) where abnormally high pore fluid pressures have reduced effective compressive stresses. Under this condition, burial depth is no longer the controlling factor in porosity loss, and porous chalks can be found at depths from 0 to more than 4,000 m.

Other production may come from areas that have low matrix porosity but intense fracturing (as along sharp flexures or faults), or from areas of abnormal lithology (e.g., bioherms, intrusive volcanic rocks, or calcarenites).

AAPG Search and Discovery Article #90967©1977 GCAGS and GC Section SEPM 27th Annual Meeting, Austin, Texas