Subsurface Data Reveal Pore-Pressure Variations in Shale Basins

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 4042140, “Regional Pore-Pressure Variations of the Wolfcamp, Dean, Spraberry, and Bone Spring Formations of the Midland and Delaware Basins in the USA,” by Shuvajit Bhattacharya, Ray Eastwood, and Katie Smye, The University of Texas at Austin, et al. The paper has not been peer reviewed. _ The authors study regional pore-pressure variations in the Leonardian and Wolfcampian producing strata (Wolfcamp, Bone Spring, Avalon, Dean, and Spraberry) in the Midland and Delaware Basins of West Texas and southeast New Mexico. Pore pressure is analyzed with a variety of subsurface data, including sonic logs and completions data. Results show that pore pressure is consistently higher in the Wolfcamp Formation (especially Wolfcamp B, C, and D) and Delaware Basin Bone Spring S3 than the Spraberry Formation in the Midland Basin. Introduction Over the years, several studies have been conducted on pore pressure in different shale reservoirs in the Permian Basin. A few recent studies used 3D seismic data to estimate and map pore pressure in the Permian. However, few published studies exist on basinwide variations of pore pressure in producing shale formations in the Permian. Uncertainty persists as to why pore pressure is different in age-equivalent formations in the Delaware and Midland Basins. The authors study regional pore-pressure variation in selected Leonardian and Wolfcampian shale formations at the basin scale, integrating well logs, completions, and reservoir data. The challenges and opportunities presented by different kinds of subsurface data in estimating pore pressure are discussed. Pore-pressure-gradient maps reveal vertical and lateral changes in pore pressure in the Permian Basin. Methods Pore pressure of the Wolfcamp, Dean, Spraberry, Bone Spring, and Avalon Formations in the Midland and Delaware Basins was studied with a combination of sonic logs, instantaneous shut-in pressure (ISIP), diagnostic fluid injection tests (DFIT), mud weight, and other approaches. Pore Pressure From Sonic Logs. Two methods were used for obtaining pore-pressure estimates from sonic logs: Eaton’s approach and the SOPI method that uses sonic, offset well, porosity, and formation-resistivity data. Although resistivity logs were more prevalent than sonic logs in the Midland and Delaware Basins, the presence of both induction logs and laterologs was encountered; mixing the results from both data types would complicate workflow and interpretations. Using Eaton’s approach, a shale normal compaction trend line varying with depth was established. Departures from this trend were used to compute pore pressure using observed sonic travel time. For the SOPI method, wells with petrophysical multimineral model results that accurately characterized variations in lithology and porosity for the formations of interest were used. The sonic log response was forward-modeled using the derived mineral composition and porosity from petrophysical inversion.