Integrating Geomechanical Data Optimizes Completions Design
Authors: Carpenter Chris 
Published: March 2019

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191768, “Integrating Rock Properties and Fracture-Treatment Data To Optimize Completions Design,” by Eric Bruesewitz, SPE, Hawkwood Energy; Jessica Iriarte, SPE, Well Data Labs; Joel Mazza, SPE, Carrie Glaser, and Eric Marshall, Fracture ID; and Scott Brooks, Hawkwood Energy, prepared for the 2018 SPE Liquids-Rich Basins Conference—North America, Midland, Texas, USA, 5–6 September. The paper has not been peer reviewed.
In the process of analyzing treatment responses that occur during hydraulic fracturing, several variances in treating pressure exist that are not readily explained by examining the surface pressures and pipe friction in isolation. These variances are also apparent when looking at bottomhole injectivity. This paper demonstrates how engineers can take advantage of their most-detailed completions and geomechanical data by identifying trends arising from past detailed treatment analyses.
Introduction
The Eagle Ford Shale was deposited in the Late Cretaceous Period in a marginal to open marine setting. The Lower Cretaceous part can be divided into two second-order transgressive/regressive cycles that have been labeled lower and upper Eagle Ford. The deposition of these units varies across the formation as a result of topography at the time of deposition. Therefore, operators in the Eagle Ford and other shale plays must account for changing stratigraphy and facies to locate horizontal wells properly for optimal perforation intervals.
This study is based on integrated geomechanical data, metered high-frequency treatment data, and post-job reports. The data set used for this study corresponds to six wells completed in the Lower Bench of the Eagle Ford formation in Brazos and Burleson counties in Texas. Integration of completions, drilling, and geomechanical data has been analyzed before in the literature. Those authors observed an increase in pressure in several stages with higher Young’s modulus and lower gamma ray values, in which they were forced to pump an extra wellbore volume of clean fluid (sweep) to place the designed proppant volume. These sweeps accounted for more than 20,000 bbl of additional fluid pumped.
The wells analyzed in this study presented data showing multiple examples of difficult-to-treat stages, in which unplanned sweeps had to be pumped and screenouts occurred frequently. Because the treating-pressure anomalies were correlated with mechanical rock properties in other unconventional plays, it was suspected that similar investigation may yield savings, efficiency, and productivity improvements in the Eagle Ford.
Methodology
The six wells of this study similarly consist of an approximately 7,600-ft lateral completed with 5.5-in. casing and approximately 150-ft stage lengths for a total of 283 stages analyzed. The fracture-treatment design consisted of proppant ramps of 100-mesh and 40/70 white sand placed primarily with slickwater. However, the completion design of four wells included cross-linked gel to place the highest proppant concentrations ranging between 3.0 and 4.0 lbm/gal. All six wells were recorded and processed for geomechanical properties such as Young’s modulus and Poisson’s ratio; a subsequent petromechanical model; and high-frequency fracture-treatment data (treating pressures, rates, and fluid and proppant volumes) and perforation data. The geo mechanical data gathered along the wellbore were divided and assigned to each stage, matching the measured depths to compare variables across data sets. Then, these data sets were standardized to a common format, screened for quality control, normalized, and analyzed with a data-management application.