Gas Injection Evaluated for EOR in Organic-Rich Shale
Authors: Carpenter Chris 
Published: June 2019

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190323, “Gas Injection for EOR in Organic-Rich Shale: Part I—Operational Philosophy,” and paper URTeC 2903026, “Gas Injection for EOR in Organic-Rich Shale: Part II—Mechanisms of Recovery,” by Francisco D. Tovar, SPE, Maria A. Barrufet, SPE, and David S. Schechter, SPE, Texas A&M University. Paper SPE 190323 was prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April; paper URTeC 2903026 was prepared for the 2018 Unconventional Resources Technology Conference, Houston, 23–25 July. The papers have not been peer reviewed.
This synopsis contains elements of two papers. In the first, the authors describe their comprehensive experimental evaluation of gas injection for enhanced oil recovery (EOR) in organic-rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic-rich shale reservoirs, whereas tests in resaturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slimtube minimum miscibility pressure (MMP) on recovery. In the second paper, the authors focus on the effect of fluid transport in organic-rich shale on recovery mechanisms under gas injection, and provide the rationale behind the proposed operational philosophy.
Part I—Operational Philosophy
Background. The notion that industry experience in the implementation of gas-injection methods in conventional reservoirs can be applied to unconventional reservoirs is a problematic one. A lack of understanding exists regarding the effect of contrast in mechanisms at the pore scale on the implementation of a gas-injection process. Experimental research so far, though encouraging, suffers from serious limitations. Also, there still is a significant lack of understanding of the mechanisms of recovery under gas injection for enhanced recovery in organic-rich shales.
In this paper, the authors base their investigation on experimental observations made in core plugs extracted from the reservoir interval, and show the development of a coreholder configuration that enables the physical simulation of the injection of gas through a hydraulic fracture in the laboratory. Then, this configuration is used to perform coreflooding experiments at the pressure and temperature conditions seen in the reservoir. Detailed descriptions and results of the experimental work are provided in the complete paper.
Summary. The authors begin by demonstrating that direct gas injection through an organic-rich shale matrix is not possible in a reasonable time frame. That discovery triggered the construction of specialized equipment and the development of a novel injection technique that resembles that of injection through hydraulic fractures. Using that technique,
nine experiments injecting CO2 in preserved organic-rich shale cores were performed. Only three of those experiments recovered a significant volume of oil, and the recovery factor was estimated to be between 18 and 62% of the initial crude-oil volume in the cores.
This demonstrated CO2 can be used to extract the naturally occurring oil in core plugs with extremely low permeability, where gas cannot be injected directly. Also, by coupling the coreflooding equipment developed in-house to a computed-tomography (CT)-scanner, this technology proved able to track the changes in density resulting from the mass exchange between CO2 and crude oil.