Laboratory Investigation Targets EOR Techniques for Organic-Rich Shales
Authors: Carpenter Chris 
Published: June 2019

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2890074, “Laboratory Investigation of EOR Techniques for Organic-Rich Shales in the Permian Basin,” by Shunhua Liu, SPE, Vinay Sahni, and Jiasen Tan, SPE, Occidental Oil and Gas, and Derek Beckett and Tuan Vo, CoreLab, prepared for presentation at the 2018 Unconventional Resources Technology Conference, Houston, 23–25 July. The paper has not been peer reviewed.
Commercial production from light oil, organic-rich shales in the Permian Basin has largely come from a solution-gas-drive recovery mechanism as a result of horizontal drilling and multistage hydraulic fracturing. These onshore, capital-intensive developments feature steep production declines and low expected ultimate recoveries. This paper involved laboratory experiments introducing miscible gases into core samples to investigate enhanced oil recovery (EOR) mechanisms for Permian Basin shales to provide information to design field tests for a huff ’n’ puff (HNP) recovery process.
Introduction
The average recovery factor in the un-conventional resources is typically less than 10% with very steep decline rates, indicating enormous potential for EOR. In recent years, research efforts and field pilots of unconventional EOR have targeted the Bakken and Eagle Ford shales. Most focused on miscible-gas (either CO2 or produced gas) injection, while others investigated water-based chemical injection. This paper provides EOR fluid and core analyses in Permian Basin organic-rich shale, an unconventional hydrocarbon growth play with different geological, rock, and fluid properties from those of the Bakken and Eagle Ford plays. The experimental results from this paper were used to calibrate the operator’s unconventional EOR reservoir simulation and field pilot design.
Fluid Experiments
Fluid properties such as equation-of-state (EOS) and minimum miscibility pressure (MMP) are extremely important because they are the fundamental designing parameters for any gas EOR project. In this study, oil and gas samples were collected in the well from perforations inside the Wolfcamp formation of the Permian organic-rich shale. A gas/oil ratio (GOR) of 1230 scf/bbl was chosen to recombine the separator oil and gas on the basis of observed solution GOR values before any increase caused by the flowing bottomhole pressure falling below the bubblepoint pressure.
The pressure/volume/ temperature (PVT) laboratory-testing program consisted of a constant-composition-expansion (CCE) test and a series of swelling tests with CO2. Using the recombined reservoir fluid (with a GOR of 1230 scf/bbl), a CCE test was performed at the reservoir temperature of 162°F to measure the bubblepoint pressure, single-phase oil density, and compressibility. The swelling test results were performed to tune an EOS to be used to calculate oil properties with increasing CO2 concentration during a CO2 flood.
EOS Modeling
An EOS model was generated to match the CCE data, viscosity data, and CO2 swelling-test data. To use this EOS for CO2 reservoir simulation, the reported system components were grouped, but the CO2 component was left ungrouped. Otherwise, it would be grouped with component C2. The minor component N2 was grouped with C1. All C4s and C5 were grouped together, as were the C6s. The C7+ components were divided into three pseudocomponents.