Herbert Scott Hamlin
Wolfberry play combines favorable geology with innovative completion practices to form one of the largest unconventional oil plays in the United States. Wolfberry wells produced almost 55 million barrels of oil in 2011, and potential exists for that figure to double in a few years. Abundant organic carbon, brittle calcareous mudrock, and thin permeable beds form the geologic basis for the play. The Wolfberry concept grew out of preexisting plays in low-permeability sandstones (Spraberry Formation) and detrital carbonates (Wolfcamp interval) and developed in the early 2000’s through the application of modern hydraulic-fracture stimulation technology and refinement of geologic understanding of the reservoir-source-rock system. This presentation covers Wolfberry geology at regional and local scales and is intended to provide a context and reference for exploration and development.
Lower Permian (Wolfcampian and Leonardian Series) stratigraphy in the Midland Basin records deposition in an intracratonic, deep-water basin surrounded by shallow-water carbonate platforms. On the basin floor, siliciclastic, turbidite depositional systems alternate with calcareous, hemipelagic depositional systems in horizontal, laterally persistent layers. Turbidite sandstones form important reservoirs in basin-floor settings. Along the platform margins, slope depositional systems comprise carbonate-dominated clinoforms. Near-slope (periplatform) detrital carbonates (primarily debris flows and turbidites) form important Wolfberry reservoirs. By flooding or exposing the wide platforms, sea-level fluctuation controlled sediment input into the basin. During sea-level lowstands, platforms were exposed, and siliciclastic sediment was transported directly into the basin. During sea-level highstands, flooded platforms became carbonate factories, and sediment input to the basin comprised platform-derived carbonate and hemipelagic (windblown) silt and clay. The hemipelagic depositional system was active throughout the sea-level cycle, and organic matter and siliciclastic silt are abundant in all basinal intervals.
We used wireline logs to correlate and map stratigraphic intervals and drill cores to characterize lithofacies and calibrate wireline logs for lithofacies identification and mapping beyond cored wells. On the basis of lithofacies composition, rock-body geometries, and bedding architecture, we interpreted depositional facies and elements within the sequence stratigraphic and paleogeographic framework.
Siliciclastic intervals include the lower Wolfcamp interval, the Dean Formation, and the lower and upper intervals of the Spraberry Formation. These inferred lowstand intervals comprise submarine fans that extend over 150 mi (241 km) north-south and cover the basin floor. Spraberry and Dean sandstone turbidites are composed of very fine grained sand and coarse silt derived from source areas in the north. Permeable turbidite channel sandstones thin southward, grading into low-permeability turbidite lobes and sheets having widespread lateral continuity. The lower Wolfcamp interval forms a west- and north-thinning wedge of siliciclastics derived from tectonic source areas to the east and south.
Calcareous intervals include the upper Wolfcamp interval, lower and middle Leonard intervals, and middle interval of the Spraberry Formation. These inferred highstand intervals, which form equally widespread layers on the basin floor, are composed of hemipelagic deposits (mudrocks and calcareous mudrocks) and detrital carbonate mass flow deposits. Basinal calcareous intervals are typically thicker, coarser grained, and more permeable near the platforms that supplied the carbonate detritus. In basin-center areas, calcareous intervals are mudrock dominated but include numerous thin, permeable interbeds.
Wolfberry basinal deposits are oil rich, but most lithofacies are relatively impermeable. Mudrocks are organic rich, thermally mature, and oil prone. Sandstones and carbonates are mostly thin and of poor reservoir quality. The Wolfberry reservoir-source-rock system, however, is more than 2,000 ft (610 m) thick, and by means of massive, multistage, hydraulic-fracture stimulation treatments, large volumes of marginal reservoirs are accessed and produced.
Dr. Herbert Scott Hamlin has been a Research Scientist Associate at the Bureau of Economic Geology since September 2007. He obtained his B.A in anthropology and M.A. and Ph.D. in geology from the University of Texas at Austin. His fields of expertise are sedimentary geology, stratigraphy, basin analysis, hydrocarbon reservoir characterization, hydrocarbon play analysis, hydrogeology, groundwater flow modeling, GIS, geostatistics, and relational databases.
Prior to his current work at the BEG he was a Hydrologist at the Texas Water Development Board from 2004 to 2007 where he was involved in groundwater availability modeling. From 1983 to 2001 Dr. Hamlin was a research associate at the BEG, during which time some of his work included investigating petroleum resources in Texas, Wyoming, Australia, and Venezuela and modeling groundwater flow and contaminant transport around salt domes.