Gas Injection Evaluated for EOR in Organic-Rich Shale

You have access to this full article to experience the outstanding content available to SPE members and JPT subscribers.

To ensure continued access to JPT's content, please Sign In, JOIN SPE, or Subscribe to JPT

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 core-holder 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.

The results of the experiments in preserved sidewall cores revealed the necessity of knowing the initial volume of oil in place. This prompted development of equipment and procedures to clean, measure porosity, and resaturate samples. The resaturated samples were used in two sets of experiments with CO2. The knowledge of oil saturation enabled the accurate determination of the recovery factor. In the first set of experiments, employing rock and oil from Well 1, the maximum recovery factor was 40% for a 6-day experiment, whereas in the second set of experiments, employing rock and oil from Well 2, the maximum recovery factor was 26% obtained over the course of 4.2 days. This was remarkably rapid, considering the low permeability of the samples, which required 4–5 months, on average, to be resaturated with crude oil, even at 10,000 psig.

Increasing the pressure by 1,000 psig resulted in an improved recovery factor from 44 to 338%, depending on soak time and crude-oil composition. Similarly, moving from continuous flooding to huff ’n’ puff, with soak times of 21 and 22 hours, increased the recovery factor from 78.1 to 464.2%, depending on operating pressure and crude composition.

The authors also studied the effect of MMP on recovery and discovered a major departure from conventional wisdom. Increasing pressure beyond the MMP continues to increase recovery factor in organic-rich shale reservoirs.


  1. CO2 injection through a hydraulic fracture or a network of natural fractures in an organic-rich shale reservoir is a feasible EOR technique that can extract a significant volume of the naturally occurring oil in the rock matrix.
  2. Recovery factor increased with pressure and soak time.
  3. Increasing pressure beyond MMP resulted in additional oil recovery in organic-rich shales.
  4. The changes in CT number as a function of time reveal that CO2 penetrates the rock matrix rapidly after injection is started, indicating transport cannot be modeled solely by Darcy flow, and that additional mechanisms such as diffusion must be accounted for.
  5. The majority of the oil production under huff ’n’ puff injection was observed in the first cycle.
  6. Crude-oil recovery is driven by the vaporization of the intermediate components of the oil into the CO2, and their subsequent condensation once the gas is produced and flashed at room pressure and temperature.

Part II—Mechanisms of Recovery

Background. The authors used CT-­scanning data from nine coreflooding experiments conducted by injecting CO2 in organic-rich shale sidewall cores, two experiments injecting nitrogen (N2), and three further tests of CO2 injection in Berea sandstone, thus providing a baseline for comparison with high-permeability rock. The core plugs were resaturated with crude oil in the laboratory, and the experiments were performed at reservoir pressure and temperature using a novel design that replicates gas injection through a hydraulic fracture.

In this work, the operational guidelines regarding injection pressure and soak time derived directly from experimental observations are explained in light of the new production mechanisms, thus providing the necessary understanding to successfully conduct gas injection in organic-rich, liquid-saturated shale reservoirs. Details and discussions of the experiments and their results are provided in the complete paper.

Summary. The authors introduced slow-kinetics peripheral vaporizing-­condensing gas drive as the main recovery mechanism during gas injection for EOR in organic-rich shale. There are two characteristics setting apart this mechanism, and causing a reduction in efficiency, from the vaporizing-condensing gas drive in conventional rocks. The first is that it is peripheral, and the second is that it has slow kinetics.

In the authors’ experiments, the mass exchange and the potential development of the miscible front occurred close to the borderline of the core sample, and remained there, or slowly moved inward, but did not sweep through the sample. Therefore, oil was not displaced, but vaporized. The volume of crude oil recovered depends on the fraction of the oil that can be vaporized into the volume of gas in the fracture at the specific conditions of pressure and temperature.

The slow-kinetics aspect of the mechanism, causing the second step down in recovery efficiency, was highlighted by CT-scanning data. During the experiments with organic-rich shale, a compositional gradient within the core remained for 6 days. This indicates that transport properties slow down the mass transfer between the injected gas and the crude oil. Inside the core, three regions were observed:

  • An external region where density significantly decreased
  • A central region with no change in density
  • An internal region, where density increased because the vaporization of the hydrocarbon components outweighed the condensation of CO2

Such regions are not present in the experiments conducted in Berea sandstone, where recovery is consistently higher and where CO2 vaporizes all the hydrocarbons that it can until thermodynamic equilibrium is reached. This is not the case for organic-rich shale, because the poor transport slows down the process and global thermodynamic equilibrium is not reached.

Recovery can be maximized by selecting a gas that vaporizes the most hydrocarbon components and operates at the maximum possible pressure. Vaporization of hydrocarbons increases with pressure for the gases commonly used in EOR processes. The importance of the selection of the gas was made clear by the results of the experiments performed with N2. Poor mass transfer in organic-rich shale exacerbates the shortcomings of N2 as an injection gas for EOR, and it should be expected that it also will do so for dry gas.

The composition measurements of the oil, carried out by chromatography, support both the peripheral and the slow-­kinetics aspects of the vaporizing-condensing gas-drive mechanisms.

In the laboratory, the ratio of the fracture pore volume to the reservoir pore volume is much higher than in the field. This implies that an equivalent volume of CO2 to the one dispensed in the laboratory in four cycles would take approximately 80,000 cycles in the field. However, in the field, the ratio of the fracture pore volume to the fracture/reservoir contact surface is much smaller, which means the soak time required will probably be much shorter. The authors estimate that the soak time could be as short as 1 hour, but assumed 6 hours to be more realistic for field operations. This resulted in an overall time frame for the process of approximately 120 years. However, if the volume of the natural fractures, microfractures, and the complexity of the hydraulic fractures is considered, this would be reduced to well below 100 years. Though this number is not to be taken literally, it is an encouraging indication that this process exhibits a reasonable time frame that invites multiple field trials.


  1. A kinetically slow, peripheral vaporizing gas-drive mechanism was determined to be the main factor responsible for recovery under gas injection for EOR in organic-rich shales.
  2. The recovery mechanism proposed provides a plausible explanation of experimental observations and further supports the operational philosophy proposed in the first paper, consisting of performing huff ’n’ puff injection at the highest pressure possible, regardless of MMP.
  3. N2 is much less effective than CO2 in organic-rich shale in conventional reservoirs.
  4. The experimental results have been interpreted from a field standpoint, and the authors believe that obtaining significant incremental recovery in the field in a reasonable time frame is feasible.
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.

Gas Injection Evaluated for EOR in Organic-Rich Shale

01 July 2019

Volume: 71 | Issue: 7