Use of Reservoir Simulation to Forecast Field EOR Response - An Eagle Ford Gas Injection Huff-N-Puff Application

Abstract

Enhanced oil recovery in unconventional plays has been a focus of many E&P operators to increase recovery factors. Conventional displacement-based secondary (e.g. water flooding) and tertiary EOR methods are not viable options due to their low injectivity in these ultra-low permeability formations. As such, huff-n-puff (HnP) EOR techniques involving field gas injection may be the most effective EOR methods to increase the recovery factors from these shale formations. Several numerical reservoir simulation studies have showed the efficiency of CO2 HnP process in shale and tight formations (Yu et al, 2014); however, these studies show little to no field results to support the simulation predictions. This paper describes the conceptual development of the reservoir simulation models to investigate the viability of gas injection HnP in unconventional reservoirs and the results of applying those methods in Eagle Ford field test sites. Single-well and multi-well models with multi-stage hydraulic fractures were constructed and history matched using their primary production period performance. Sensitivity studies were conducted on well communication behavior/impacts, injection gas compositions, injection rates, injection/production cycling, and reservoir fluid types to optimize the pilot project well location(s) and to inform development strategies. Optimal cases from the simulation study were successfully applied to multi-well pads in the Eagle Ford formation across multiple fluid types. The simulation and the field application results were summarized and compared to provide detailed insights of unconventional HnP EOR. This study indicates the importance of confinement of the gases to afford optimal recovery factors during unconventional gas HnP EOR. An optimization engine was used in this study to optimize key operational parameters, such as injection pressures and slug sizes, to maximize recovery and efficiency. The resulting EOR designs were successfully implemented in field operations. Field recovery factors are within 10% of those predicted by simulation, indicating the value of numerical reservoir simulation prior to field trials and subsequent future development.

Impact of in-situ gas liberation for enhanced oil recovery and CO 2 storage in liquid-rich shale reservoirs

“…The CO2 diffusive mass transfer would be predominant in shale oil reservoirs 48 . However, previous studies for CO2 interactions in shale oils have considered phase behaviour pertinent to direct contact between CO2 and oil 4,10,33,35,54,55 . Therefore, it appears that, a comprehensive analysis of CO2 diffusive mass transfer in shale oil is needed to highlight the role of gas liberation mechanism during diffusion of CO2 in shale oil.…”

“…In addition, numerous numerical and simulation studies have been performed on the interactions between CO2 and shale oil formations during huff-n-puff scenarios 4,10,18,32,33 . The fluid model used in these past studies do not capture the mechanism of in-situ gas liberation 34,35 .…”

Performance of CO2 Foam Huff and Puff in Tight Oil Reservoirs

“…Moreover, the role of the injection rate and pressure has also been investigated in numerous research studies (Monger and Coma, 1988;Monger et al, 1991;Shayegi et al, 1996;Song and Yang, 2013;Wang et al, 2013;Yu et al, 2014;Sanchez-Rivera et al, 2015;Wan et al, 2015;Sun et al, 2016;Zhang et al, 2018). Wan et al (2018) and Kerr et al (2020) both showed that higher injection pressure and larger slug size would lead to an increase in the recovery factor (Wan et al, 2018;Kerr et al, 2020). Field and laboratory data indicated that the larger slug size improves oil production (Monger and Coma, 1988;Monger et al, 1991;Cronin et al, 2019).…”

Unconventional hydrocarbon resources: geological statistics, petrophysical characterization, and field development strategies

“…They have far less porosity and permeability. Also, they require stimulation and other conversion or extraction techniques such as enhanced oil recovery (EOR) for a feasible production (Zou et al 2013a;Sprunger et al 2021;Syed et al 2021a;Kerr et al 2020;Li et al 2019a;Hawthorne et al 2019;Jin et al 2019). This makes them economically far more expensive than conventional methods.…”