Viability of Gas-Injection EOR in Eagle Ford Shale Reservoirs
Authors: Carpenter Chris 
Published: December 2018

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191673, “Dynamic Data Analysis With New Automated Work Flows for Enhanced Formation Evaluation,” by Safian Atan, SPE, Arashi Ajayi, Matt Honarpour, Edward Turek, SPE, Eric Dillenbeck, and Cheryl Mock, BHP, and Mahmood Ahmadi and Carlos Pereira, MI3 Petroleum Engineering, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed.

Gas-injection huff ’n’ puff enhanced-oil-recovery (EOR) techniques have the potential to improve liquid hydrocarbon recovery in ultratight, unconventional reservoirs. This paper studies the technical and economic viability of this EOR technique in Eagle Ford shale reservoirs using natural gas injection, generally after some period of primary depletion, typically through long, hydraulically fractured horizontal-reach wells.

Reservoir-Analysis Work Flow Model Description. A compositional, fine-scale, dual-porosity, dual-permeability, symmetry-element numerical model was used in this study to model the current primary depletion and the EOR huff ’n’ puff process. In this study, the element of symmetry, which represents the bottom half of a cluster within a fracturing stage, is being extended to include three wells to allow the investigation of the effect of interference and containment on pad-level cyclic-gas-injection deployment.

Production and injection of the entire well come from all active stages in each well, with equal weighting. The production and the injection for each cluster in every well are calculated proportionally by use of these assumptions.

Model Input. The complete paper describes the critical input for the numerical model, including fracture half-length and fracture height, shape factor, absolute and relative permeability, and pressure/volume/temperature (PVT).

History-Matching Work Flow. Because the history-matching solution is known to be highly nonunique, a comprehensive probabilistic approach was used to identify the realistic solution space. To facilitate this process, the authors used a three-step approach:

Identify the solution space through parametric study.

Perform combinatorial analysis of predetermined variables and understand available solutions within the solution space.

Fine-tune history matching to identify the correct combination of parameters for probable solutions.

Characterizing the Performance of Cyclic Natural-Gas Injection

The compositional fluid-flow analysis of the combined sample of the separator liquid and gas at reservoir conditions indicated a volatile oil in the reservoir. To evaluate the phase behavior of the mixture, the original oil and the gas supplied for injection purposes were mixed at different ratios. For each mixture, the calibrated equation of state (EOS) is used to evaluate the resulting phase diagram and fluid properties by modeling a constant-composition-expansion experiment at reservoir conditions.

The 1979 Peng-Robinson EOS with nine components was used to model the PVT changes resulting from the composition changes related to each injection ratio. As the composition changes, the phase behavior and the fluid properties also change. The fluid system in the reservoir gradually changed from a volatile oil to a gas condensate.

Results show that when injected-gas makeup is 20% or greater, the phase behavior changes from volatile oil to gas condensate. When the mixture consists of more than 70% injected gas, at any pressure below 6,000 psi, there is a possibility that condensation can occur.