ABSTRACT: Sedimentary Facies and Petrophysical Characteristics of Cores from the Lower Vicksburg Gas Reservoirs, McAllen Ranch Field, Hidalgo County, Texas
R. P. Langford, W. E. Howard, J. D. Hall, J. Maguregui
As part of an effort funded by the Gas Research Institute, the Department of Energy, and the State of Texas, and with the cooperation of Shell Oil Co., sandstones in the Vicksburg "S" (Oligocene) reservoir were cored in the McAllen Ranch gas Field in the A. A. McAllen B- 17 and B- 18 wells. Detailed correlation of the cores with petrophysical data illustrates the controls of deposition and diagenesis on reservoir quality. The cores were drilled using oil-based mud, and special care in handling minimized evaporation. Core-derived water saturations were compared with log-calculated water saturations. Special core analyses of cementation factor, saturation exponent, and relative permeability were performed. Thin-section petrography and X-ray diffraction were used to determin mineralogy.
The cores consist of prodelta and delta-front facies. The prodelta deposits are laminated shales, siltstones with climbing ripples, and siltstones showing evidence of slumping and liquefaction. Burrows are relatively rare. Plant debris is common.
The distal delta-front deposits are predominantly turbidites consisting of upward-fining sequences that exhibit Bouma a-d intervals and have abrupt, scoured bases. The turbidites generally are thicker and coarser grained higher within the delta front. Cross-stratification evident in oriented core and dipmeter logs indicates northeasterly dispersal of the turbidity currents. Microresistivity curves from the high-resolution dipmeter log match individual turbidites within the core.
The proximal delta-front deposits are upward-coarsening intervals interpreted to be either delta mouth-bar crest or shoreface deposits. Poorly defined laminae are the most common sedimentary structure. Rare scours and rip-up clast beds indicate that periodic storms or floods influenced deposition. In some cores delta-front deposits are overlain by upward-fining units interpreted to be foreshore deposits in which trough cross-strata and subhorizontal laminae alternate. Northwesterly sediment dispersal is indicated by the dips of trough cross-strata in oriented core.
Permeability and porosity generally increase with increasing grain size and are greatest in 1 to 2 ft thick zones within massive and laminated beds in the uppermost delta front. Porous intervals increase in abundance upward within the delta-front sandstones. Permeability variation over two orders of magnitude within the reservoir sands corresponds to diagenetic facies within the core. High permeability occurs only within thin bands. Trough cross-stratified sandstone is commonly porous only near the tops of the foresets.
Differences in the character of the microresistivity curve of the high-resolution dipmeter log correlate with differences in cementation and with different depositional facies within the cores. Comparison of microresistivity logs and cores allows extrapolation of facies and cement characteristics and resulting reservoir properties to uncored intervals with the objective of maximizing recovery of natural gas.
AAPG Search and Discovery Article #90999©1990 GCAGS and Gulf Coast Section SEPM Meeting, Lafayette, Louisiana, October 17-19, 1990