The Viability of Gas Injection EOR in Eagle Ford Shale Reservoirs

Abstract

Gas Injection, Huff-and-Puff Enhanced Oil Recovery (EOR) technique have the potential to improve liquid hydrocarbon recovery in ultra-tight, 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 horizontal reach wells that were hydraulically fractured. To achieve this, three primary steps were undertaken: First, a series of multi-well, compositional simulation models were constructed, calibrated with lab data, and history matched for an extended production period. This effort characterizes a set of equiprobable combinations of fracture and matrix properties, as well as the parametric description of the stimulated reservoir volume. Second, these history matched models were then used to numerically simulate the Gas Injection Huff-and-Puff EOR process to determine a set of optimized operational variables (operating pressures, injection pressure, cycle durations, the corresponding injection rate, and slug size). The results were also sensitized to the effect of geomechanics, containment, as well as the effect of diffusion. The primary source of information that feeds the sensitivity analysis was derived from laboratory work investigating the EOR processes at the core scale. The third and last step, economic analysis was performed using calibrated rate profiles to assess the impact of initial yield and the amount of depletion on value. Resulting analysis provided insight to the economic viability of the EOR deployment at field-scale. Results show that the recovery factor uplift, all things being equal, is a function of the original yield, the amount of depletion, and the minimum operating pressure during the production cycles. In reality, however, equally as critical to the success of an EOR project is the formulation of the deployment strategy - the timing of the development start (forecasted price environment), pad selection, compressor scheduling, injection-soak-production durations, surveillance plans, and mitigation strategies (for poor containment and inefficient compressor utilization). The workflow utilized in this paper both characterizes the uncertainties in an EOR project in the Eagle Ford and provides insight into operating conditions and surveillance recommendations. This is the key for a successful demonstration pilot which can then lead to a field-scale EOR deployment.

Storage Integrity during Underground Hydrogen Storage in Depleted Gas Reservoirs

“…This is particularly dangerous when the high rate of hydrogen injection and withdrawal is implemented, which would further lead to plastic irreversible reservoir deformation and compromise storage integrity [179,235]. The deformation of reservoirs triggered by cyclical stress alteration may also cause reservoir compaction, decreasing formation porosity and hydrogen cycling efficiency [236][237][238]. For the caprock, hydrogen cycling associated stress regime change can weaken the sealing capacity by causing tensile and shear damage [177,179,239].…”

A Review of Gas Injection in Shale Reservoirs: Enhanced Oil/Gas Recovery Approaches and Greenhouse Gas Control

“…However, a long shut-in period would result in a shorter production time. The optimum soaking time can be determined by calculating the gross/net gas utilization [7], as well as associating the cycle numbers and pressure distribution [36]. Some experimental and simulation results indicated that at miscible CO 2 injection condition, a longer soaking period allowed gas to diffuse further into the matrix, leading to a higher accumulative recovery [7,31,32].…”