Organic Geochemistry of Lower Cretaceous Travis Peak Formation, East Texas Basin

Shirley P. Dutton, Robert J. Finley, Karen L. Herrington

The Travis Peak Formation produces gas and some oil from low-permeability sandstone in much of east Texas. Organic matter in the Travis Peak occurs as (1) dispersed detrital organic matter in shale, (2) gas, condensate, and oil, and (3) solid hydrocarbon residue in pores in some sandstone. Analysis of the different types of organic matter provides information about the origin of Travis Peak hydrocarbons, the timing of hydrocarbon migration, and the diagenetic and thermal history of the formation.

Kerogen in Travis Peak shales is mainly vitrinite, and most shales contain less than 0.5% total organic carbon, indicating that these are poor hydrocarbon source rocks. Vitrinite reflectance values generally range from 1.0 to 1.2%, although shales in the deeper, downdip part of the formation have R_o values as great as 1.8%. Oil in Travis Peak reservoirs, and probably gas as well, was most likely generated in a source rock other than the interbedded Travis Peak shales.

Samples of Travis Peak oil from Chapel Hill field in Smith County, Texas, show a range of maturity and API gravity from 45° to 58°. The oils were probably all derived from the same source, but have since undergone varying amounts of thermal alteration and cracking. The ^dgr¹³C composition of the saturate fraction of the oils is -26.0 ^pmil (PDB), which indicates that the oil may have come from Jurassic source rocks.

Solid hydrocarbon accumulations, or reservoir bitumen, fill and line pores in some sandstones in the upper 300 ft of the Travis Peak. Among all samples that contain reservoir bitumen, the average volume is 4.6%. Elemental analysis of insoluble kerogen concentrate gives H/C ratios of 0.79-0.90, which suggests the bitumen formed by deasphalting of pooled oil after solution of gas into the oil. The soluble fraction of reservoir bitumen is similar to normal producible oil but enriched in saturates and depleted in aromatics and polars. The ^dgr¹³C composition ranges from -25.9 to -27.1 ^pmil (PDB). The reservoir bitumen was probably derived from oil similar to that currently in some Travis Peak reservoirs.

Reservoir bitumen reduces porosity 3-6 porosity units in some Travis Peak sandstone; permeability may be reduced by one to four orders of magnitude. Zones containing abundant reservoir bitumen could be misinterpreted from neutron and density logs as having a greater volume of porosity filled with mobile hydrocarbons than actually exists.

AAPG Search and Discovery Article #91042©1987 GCAGS and GC-SEPM Section Meeting, San Antonio, Texas, October 28-31, 1987.