ABSTRACT

The Tijerina-Canales-Blucher (TCB) Field of Kleberg and Jim Wells Counties, Texas, has produced significant amounts of hydrocarbons from Oligocene Vicksburg sandstones at depths of 7800 feet to 11,800 feet. TCB Vicksburg sandstones were deposited in deltaic to shallow marine environments as evidenced by various sedimentological and biological indicators. Diapirism of Jackson shelf muds coupled with syndepositional growth faulting generated highly faulted rollover elongate anticlines. These faulted, elongate highs along with a stratigraphic variability form the main traps in TCB Field.

Detailed examination of cores from five different Vicksburg sand = shale intervals in Sun Exploration & Production Company's Canales portion of TCB Field aided in delineation of a complex diagenesis related to depositional environment, lithology, burial, and thermal history of the field region. The sandstones vary in lithology from lithic to feldspathic lithic arenites and wackes. A volcanic source during Vicksburgian time is indicated by the presence of high percentages of volcanic rock fragments. This over-abundance of labile constituents is the prime factor that resulted in the "jambalaya" of diagenetic complexities.

Porosity in the TCB Vicksburg sandstones is almost entirely secondary and was generated predominantly by the dissolution of feldspars, volcanic rock fragments, and calcite cement. Permeability was greatly enhanced by dissolution and recrystallization of clayey matrix and carbonate cement. An overall smectite-illite signature pervades the vertical section with an extremely well developed authigenic imprint of highly crystalline kaolinite, chlorite, and illite and many other mineral species superimposed onto the primary signature, especially with depth. The best TCB reservoirs have the largest average grain size and had the greatest amount of feldspars and volcanic rock fragments prior to diagenesis. Evolution of secondary porosity is suggested to be directly related to the generation and migration of hydrocarbons through the Vicksburg host rocks.

The most productive TCB Vicksburg reservoirs are found to be analogous with distributary channel and channel mouth bar facies. Depositional environment facies mud to sand ratios were instrumental in the formation of the diagenetic imprints of the TCB Vicksburg sandstones. Sandstones with initial high detrital clay content stood less chance of becoming reservoir quality rock due to lower initial permeabilities which retarded fluid-rock interaction. The best reservoirs exhibit a high degree of authigenesis with well developed chlorite and/or kaolinite being developed in conjunction with the secondary porosity. Poor quality reservoirs do not exhibit this high degree of crystalline authigenesis.