CO2 injection for enhanced oil recovery in Bakken tight oil reservoirs

Advancements in horizontal drilling with hydraulic fracturing have enabled commercial oil production from Bakken tight oil reservoirs. However, the primary recovery factor remains very low (less than 15%), resulting in the high volume of oil remaining in place. Hence, it is extremely important to investigate the application of enhanced oil recovery methods. Carbon dioxide (CO2) injection as a huff-n-puff process is a preferred approach to improve oil recovery in tight reservoirs. In this work, we present the effect of CO2 molecular diffusion and performed a series of sensitivity studies to quantify the impacts of reservoir properties such as permeability and fracture properties such as fracture half-length, fracture conductivity, number of fractures, and operation parameters such as CO2 injection rate, injection time, soaking time, number of cycle of CO2 huff-n-puff and CO2 diffusivity on the CO2 huff-n-puff process for enhanced oil recovery in the Bakken Formation. A numerical model was built using the typical reservoir and fracture properties from Middle Bakken to simulate CO2 huff-n-puff process. In this process, we consider CO2 molecular diffusion term to swell oil in matrix since Darcy velocity is negligible due to low permeability. The numerical model was validated with field production data from a horizontal well in Middle Bakken. Based on the history matching results, the relative permeability curves such as water-oil relative permeability and liquid-gas relative permeability, are obtained. Furthermore, the wettability for the Middle Bakken is found to be weak water wet. Simulation results show that the most important parameter is CO2 injection rate, followed by CO2 injection time, number of cycle, CO2 diffusivity. The other parameters such as fracture conductivity, CO2 soaking time, permeability and fracture half-length are less sensitive based on the range investigated in this study. The range for the incremental oil recovery factor at 30 years of production is obtained as 2.5% - 9.4%. This work can provide fundamental understanding of the key parameters controlling the CO2 huff-n-puff process for enhanced oil recovery in the Bakken Formation.

CO2 injection is an effective enhanced oil recovery (EOR) method in unconventional oil reservoirs. However, the investigation of CO2 Huff-n-Puff in tight oil reservoirs with nanopore confinement is lacking in the petroleum industry. The conventional models need to be modified to consider the nanopore confinement in both phase equilibrium and fluid transport. Hence, we develop an efficient model to fill this gap and apply it in the field production of the Bakken tight oil reservoir. Complex fracture geometries are also handled in this model. First, we revised the phase equilibrium calculation and evaluated the fluid properties with nanopore confinement. An excellent agreement between this proposed model and the experimental data is obtained considering nanopore confinement. Afterwards, we verified the calculated minimum miscibility pressure (MMP) using this model against the experimental data from rising-bubble apparatus (RBA). We analyzed the MMP and well performance of CO2-EOR in the Bakken tight oil reservoir. Based on the prediction of the field data, the MMP is 5.4% lower than the MMP with bulk fluid when the pore size reduces to 10 nm. Subsequently, we examined the impacts of key parameters such as matrix permeability and CO2 molecular diffusion on the CO2 Huff-n-Puff process. Results show that both CO2 diffusion and capillary pressure effect improve oil recovery factor from tight oil reservoirs, which should be correctly implemented in the simulation model. Finally, we analyzed well performance of a field-scale horizontal well from the Bakken formation with the non-planar fractures and natural fractures. Contributions of CO2 diffusion and capillary pressure effect are also examined in depth in field scale with the complex fracture geometries. The oil recovery factor of CO2 Huff-n-Puff process with both CO2 diffusion and capillary pressure effect increases by as much as5.1% in the 20-year period compared to the case without these factors. This work efficiently analyzes the CO2 Huff-n-Puff with complex fracture geometries considering the CO2 diffusion and nanopore confinement in the field production from Bakken tight oil reservoir. This model can provide a strong basis for accurately predicting the long-term production with complex fracture geometries in the tight oil reservoirs.

Summary Carbon dioxide (CO2) injection is an effective enhanced-oil-recovery (EOR) method in unconventional oil reservoirs. However, investigation of the CO2 huff ’n’ puff process in tight oil reservoirs with nanopore confinement is lacking in the petroleum industry. The conventional models need to be modified to consider nanopore confinement in both phase equilibrium and fluid transport. Hence, we develop an efficient model to fill this gap and apply to the field production of the Bakken tight oil reservoir. Complex-fracture geometries are also handled in this model. First, we revised the phase equilibrium calculation and evaluated the fluid properties with nanopore confinement. An excellent agreement between this proposed model and the experimental data is obtained considering nanopore confinement. Afterward, we verified the calculated minimum miscibility pressure (MMP) using this model against the experimental data from a rising-bubble apparatus (RBA). We analyzed the MMP and well performance of CO2 EOR in the Bakken tight oil reservoir. On the basis of the prediction of the field data, the MMP is 450 psi lower than the MMP with bulk fluid when the pore size reduces to 10 nm. Subsequently, we examined the effects of key parameters such as matrix permeability and CO2 molecular diffusion on the CO2 huff ’n’ puff process. Results show that both CO2-diffusion and capillary pressure effects improve the oil recovery factor from tight oil reservoirs, which should be correctly implemented in the simulation model. Finally, we analyzed well performance of a field-scale horizontal well from the Bakken Formation with nonplanar fractures and natural fractures. Contributions of CO2-diffusion and capillary pressure effects are also examined in depth in field scale with complex-fracture geometries. The oil recovery factor of the CO2 huff ’n’ puff process with both CO2-diffusion and capillary pressure effects increases by as much as 5.1% in the 20-year period compared with the case without these factors. This work efficiently analyzes the CO2 huff ’n’ puff process with complex-fracture geometries considering CO2 diffusion and nanopore confinement in the field production from the Bakken tight oil reservoir. This model can provide a strong basis for accurately predicting the long-term production with complex-fracture geometries in tight oil reservoirs.

Pore-scale analysis of gas huff-n-puff enhanced oil recovery and waterflooding process

Optimization of operational strategies for rich gas enhanced oil recovery based on a pilot test in the Bakken tight oil reservoir

Unconventional oil, such as tight oil and shale oil, has become one of the most significant contributors of oil reservoirs and production growth. Due to low porosity and ultra-low permeability, unconventional oil reservoirs require multistage hydraulic fracturing technique to maximize production. However, the primary recovery remains very low to narrow the profit margin heavily. Although CO2 huff-n-puff process holds great potential to increase oil recovery and has a chance to sequester CO2 to reduce environmental footprint, our current knowledge of the performance of this process is very limited. With numerical simulation, we performed a series of sensitivity work to present the impacts of reservoir properties, fracture properties and operation parameters such as CO2 injection rate, injection time, soaking time, number of cycle of CO2 on enhanced oil recovery in the tight oil formation. What's more, the method of analysis of variance (ANOVA) was used to evaluate the performance of CO2 huff-n-puff process and beneficial result from CO2 EOR technology. Simulation results showed that bottom hold pressure and injection cycles impose more significant impose on oil recovery increment than injection time, injection rate and production time per cycle. Based on the typical reservoir and fracture properties from tight oil reservoir, the numerical models were established to evaluate the performance of four EOR methods: CO2 huff-n-puff, water huff-n-puff, nanofluids huff-n-puff and water alternating gas (WAG). With the comparison of oil recovery and its increment of four EOR methods and depletion method, it is found that CO2 huff-n-puff method would lead to much more incremental oil recovery than other three methods, which reveals its huge potentials of enhancing oil recovery and improving development profit in unconventional reservoirs. The conclusion of this work has the potential to advance our understanding of the role of CO2 in developing unconventional oil reservoirs, which will benefit both energy economy and environment with CO2 geological sequestration.

ABSTRACT: The integration of multi-stage hydraulic fracturing and extended horizontal drilling has markedly advanced oil extraction from the Bakken tight oil reservoir, a prominent unconventional reservoir in the United States. Despite these technological strides, the primary recovery rates from this tight formation have remained suboptimal, leaving a considerable volume of oil unrecovered. This challenge underscores the necessity for innovative Enhanced Oil Recovery (EOR) methods tailored to the unique conditions of the Bakken formation. While CO2 injection has been explored, its effectiveness is limited by the formation's heterogeneity. This study introduces an innovative approach through the application of Fishbone Drilling (FbD) technology, aimed at enhancing recovery efforts in the Bakken formation. Our investigation reveals that FbD, characterized by multiple minor holes branching from the main wellbore, significantly improves hydrocarbon recovery by enhancing reservoir contact and exploiting the existing natural fractures more effectively than traditional methods. The findings indicate that FbD not only promises an increase in hydrocarbon flow but also, through optimization of design parameters, aligns with economic viability over time despite higher initial costs. This paper presents a comprehensive analysis of FbD's optimal design and its efficacy in the Bakken formation, supported by data-driven insights that validate the technology's potential to revolutionize EOR strategies in unconventional reservoirs. Through detailed numerical simulations and comparative analyses, this study highlights the superior performance of FbD over conventional drilling and fracturing methods, proposing a promising avenue for future exploration and development within the unconventional reservoirs. 1. INTRODUCTION The quest for enhanced oil recovery (EOR) techniques in unconventional reservoirs has been a pivotal focus within the energy sector, driven by the imperative need to optimize hydrocarbon extraction from formations like the Bakken tight oil reservoir (Almousa et al., 2023a). Located in the Williston Basin, one of the United States' most expansive unconventional reservoirs, the Bakken formation presents a unique set of challenges and opportunities for EOR strategies (Helms et al., 2023). Hydraulic fracturing and re-fracturing contributed heavily in the oil and gas production in the Bakken as reported by (Dehdouh et al, 2023a). Despite the significant strides made through the integration of multi-stage hydraulic fracturing and extended horizontal drilling, these conventional methods have only marginally improved the primary recovery rates in such tight formations. This scenario underscores the substantial volume of oil that remains untapped, highlighting the critical need for innovative approaches to EOR as detailed by Merzoug et al. (2024).

The most commonly used technology for development of unconventional liquid-rich and light oil reservoirs is horizontal wells combined with large multi-stage hydraulic fracture treatments. However, even with these technological advancements, primary recovery factors are generally less than 10% (Shoaib and Hoffman, 2009) of the original oil in place (OOIP). Logically, operators have investigated the use of waterflooding to improve recovery in some tight oil reservoirs, but the success has been mixed. Low matrix permeability in some unconventional (tight) oil reservoirs will not allow effective displacement or movement of water through the reservoir. In some cases, even flooding with a gas will be a challenge, if matrix permeabilities are too low. This study investigates the feasibility of enhanced oil recovery (EOR) in a prominent tight oil reservoir in North America using cyclic solvent injection (CSI, sometimes referred to as "huff-n-puff") with carbon dioxide (CO2) as the solvent. CSI is a single well process, with the solvent remaining in the vicinity of the wellbore, as flow of the solvent through the reservoir to another well is not necessary. This type of process may be attractive from a capital cost point-of-view, as large expenditures on specialized facilities, in-field pipelines and well conversions are unnecessary. In this study, the success and profitability of huff-n-puff is evaluated for the Bakken tight oil reservoir. Knowledge gained from a parallel study (Kanfar and Clarkson, 2017) served to provide guidelines for optimizing the huff-n-puff process. Importantly, a genetic algorithm (GA) is utilized to find the optimum huff-n-puff program that maximizes net present value (NPV). Optimized parameters include: the number of cycles; duration of injection, soaking and production periods; and the start time of huff-n-puff operations. The target reservoir for evaluation is the US Bakken deep tight oil reservoir in North Dakota. The huff-n-puff EOR scheme was found to be successful, but only after the aforementioned operational parameters are optimized with GA. In particular, it is important to delay huff-n-puff until production rates decline and boundary-dominated flow (after fracture interference) is reached. Importantly, as with the parallel study (Kanfar and Clarkson 2017), the gridding scheme used in the simulation is found to have a profound impact on results of huff-n-puff.

Studying the performance of different techniques to improve oil recovery of tight oil reservoirs have become the main focus of many researchers because of the significant contribution of these reservoirs to the USA daily oil production. Recent studies have shown possibility of using EOR methods to improve oil recovery of tight and ultra-tight oil reservoirs as an attempt to encouagre the development of these reservoirs. This paper studies the feasibility and limitations of applying miscible gas flooding to enhancing oil recovery of tight and ultra-tight formation. A compositional simulation study was conducted and three main factors were used to study the performance of gas flooding; formation permeability, distance between wells, and gas injection period. Five permeability values, 1 md, 0.1 md, 0.01 md, 0.001 md, and 0.0001md, were used to build five simulation models then these models were used to study the performance and define the limitations of gas flooding process for each model. The results of the first part of the compositional simulation study show that the oil recovery has been improved when the miscible gas displacement process was applied to a formation that has permeability larger than 0.01 md becuase gas flooding did not significantly improve oil recovery for the models that have formation permeability less than 0.01 md. Second, we used the distance between the injection and production wells and gas injection period to investigate the performance and the limitations of applying gas flooding on each models. As a result of that, it has been found that formation permeability has a significant effect on the selection of well spacing. Forthermore, the study helped to recommend the well spacing that should be considered for different formation permeability values. Finally, this study promotes the understanding of implementing the miscible gas flooding in tight and ultra-tight oil formation and helps in the selection of the best candidate to apply gas flooding base on its permeability. Furthermore, it helps in optimize the well spacing of tight formation if gas flooding process is considered in future.

Primary oil recovery remains less than 10% in tight oil reservoirs, even after expensive multistage horizontal well hydraulic fracturing stimulation. Substantial experiments and pilot tests have been performed to investigate CO2-EOR potential in tight reservoirs; however, some results conflict with each other. The objective of this paper is to diagnose how these conflicting results occurred and to identify a way to narrow the gap between experimental results and field performance through a comprehensive literature review and data analysis. Peer-reviewed journal papers, technical reports, and SPE publications were collected, and three key steps were taken to reach our goal. First, rock and fluid properties of tight reservoirs in North America and China were compared, and their potential effect on tight oil production was analyzed. Afterward, based on published experimental studies and simulation works, the CO2-EOR mechanisms were discussed, including molecular diffusion, CO2-oil interaction considering nanopore confinement, and CO2-fluid-rock minerals interaction. Subsequently, pilot projects were examined to understand the gap between laboratory works and field tests, and the challenges faced in China's tight oil exploitation were rigorously analyzed. Compared with Bakken and Eagle Ford formation, China's tight oil reservoirs feature higher mud content and oil viscosity while they have a lower brittleness index and formation pressure, leading to confined stimulated reservoir volume and further limited CO2-oil contact. The effect of CO2 molecular diffusion was relatively exaggerated in experimental results, which could be attributed to the dual restrictions of exposure time and oil-CO2 area in field scale. Numerical modeling showed that the improved phase properties in nanopores led to enhanced oil recovery. The development of nano-scale chips withholding high pressure/temperature may advance the experimental study on nano-confinement's effect. Oil recovery can be further enhanced through wettability alteration due to CO2 adsorption on nanopores and reaction with rock minerals. CO2 huff-n-puff operations were more commonly applied in North America than China, and the huff time is in the order of 10 days, but the soaking time is less. Conformance control was essential during CO2 flooding in order to delay gas breakthrough and promote CO2-oil interaction. There is less than 5% of tight oil reserve surrounded by CO2 reservoirs in China, limiting the application of CO2-EOR technologies. An economic incentive from the government is necessary to consider the application of CO2 from power plants, refineries, etc. This work provides an explanation of conflicting results from different research methods and pilot tests, and helps researchers and oil operators understand where and when the CO2-EOR can be best applied in unconventional reservoirs. New directions for future work on CO2-EOR in tight formations are also recommended.

Rapid combustion of fossil fuels in huge quantities resulted in the enormous release of CO2 in the atmosphere. Subsequently, leading to the greenhouse gas effect and climate change and contemporarily, quest and usage of fossil fuels has increased dramatically in recent times. The only solution to resolve the problem of CO2 emissions to the atmosphere is geological/subsurface storage of carbon dioxide or carbon capture and storage (CCS). Additionally, CO2 can be employed in the oil and gas fields for enhanced oil recovery operations and this cyclic form of the carbon dioxide injection into reservoirs for recovering oil and gas is known as CO2 Enhanced Oil and Gas Recovery (EOGR). Hence, this paper presents the CO2 retention dominance in tight oil and gas reservoirs in the Western Canadian Sedimentary Basin (WCSB) of the Alberta Province, Canada. Actually, hysteresis modeling was applied in the oil and gas reservoirs of WCSB for sequestering or trapping CO2 and EOR as well. Totally, four cases were taken for the investigation, such as WCSB Alberta tight oil and gas reservoirs with CO2 huff-n-puff and flooding processes. Actually, Canada has complex geology and therefore, implicate that it can serve as a promising candidate that is suitable and safer place for CO2 storage. Furthermore, injection pressure, time, rate (mass), number of cycles, soaking time, fracture half-length, conductivity, porosity, permeability, and initial reservoir pressure were taken as input parameters and cumulative oil production and oil recovery factor are the output parameters, this is mainly for tight oil reservoirs. In the tight gas reservoirs, only the output parameters differ from the oil reservoir, such as cumulative gas production and gas recovery factor. Reservoirs were modelled to operate for 30 years of oil and gas production and the factor year was designated as decision-making unit (DMU). CO2 retention was estimated in all four models and overall the gas retention in four cases showed a near sinusoidal behavior and the variations are sporadic. More than 80% CO2 retention in these tight formations were achieved and the major influencing factors that govern the CO2 storage in these tight reservoirs are injection pressure, time, mass, number of cycles, and soaking time. In general, the subsurface geology of the Canada is very complex consisting with many structural and stratigraphic layers and thus, it offers safe location for CO2 storage through retention mechanism and increasing the efficiency and reliability of oil and gas extraction from these complicated subsurface formations.

A critical review of CO2 enhanced oil recovery in tight oil reservoirs of North America and China

The pore sizes of unconventional reservoir rock, such as shale and tight rock, are on the order of nanometers. The thermodynamic properties of in-situ hydrocarbon mixtures in such small pores are significantly different from those of fluids in bulk size, primarily due to effect of large capillary pressure. For example, it has been recognized that the phase envelop shifts and bubble-point pressure is suppressed in tight and shale oil reservoirs. On the other hand, the stress-dependency is pronounced in low permeability rocks. It has been observed that pore sizes, especially the sizes of pore-throats, are subject to decrease due to rock deformation induced by the fluid depletion from over-pressurized tight and shale reservoirs. This reduction on pore spaces again affects the capillary pressure and therefore thermodynamic properties of reservoir fluids. Thus it is necessary to model the effect of stress- dependent capillary pressure and rock deformation on tight and shale reservoirs. In this paper, we propose and develop a multiphase, multidimensional compositional reservoir model to capture the effect of large capillary pressure on flow and transport in stress-sensitive unconventional reservoirs. The vapor-liquid equilibrium (VLE) calculation is performed with Peng-Robinson Equation of State (EOS), including the impact of capillary pressure on phase behavior and thermodynamic properties. The fluid flow is fully coupled with geomechanical model, which is derived from the thermo- poro-elasticity theory; mean normal stress as the stress variable is solved simultaneously with mass conservation equations. The finite-volume based numerical method, integrated finite difference method, is used for space discretization for both mass conservation and stress equations. The formulations are solved fully implicitly to assure the stability. We use Eagle Ford tight oil formations as an example to demonstrate the effect of capillary pressure on VLE. It shows that the bubble-point pressure is suppressed within nano-pores, and fluid properties, such as oil density and viscosity, are influenced by the suppression due to more light components remained in liquid phase. In order to illustrate the effect of stress-dependent capillary pressure on tight oil flow and production, we perform numerical studies on Bakken tight oil reservoirs. The simulation results show that bubble-point suppression is exaggerated by effects of rock deformation, and capillary pressure on VLE also affects the reservoir pressure and effective stress. Therefore the interactive effects between capillary pressure and rock deformation are observed in numerical results. Finally, the production performance in the simulation examples demonstrates the large effect of large capillary pressure on estimated ultimate recovery (EUR) in stress-sensitive tight reservoirs.

Conventional oil production has occurred from the Bakken Formation in Saskatchewan since the mid-1950s. However, with successful implementation of multi-fractured horizontal well (MFHW) technology, the low-permeability (unconventional) Bakken has experienced ever increasing E&P activity on both sides of the US/Canada border. Prior to 2005, the Bakken in Saskatchewan had less than 100 active producers in the region but has increased to more than 2,500 producing wells since then (Sekar, 2015). Although improvement in hydraulic fracture properties and infill drilling remain the focus of recovery enhancement from the Bakken, low oil recoveries and steep initial oil decline rates are experienced using primary recovery operations, even after application of MFHW technology. Therefore, many pilots have been executed to determine the viability of waterflooding for maintaining oil rates and improving recoveries through reservoir pressure maintenance and sweep efficiency enhancement. This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken. MFHWs were used as both injectors and producers for this pilot. Five years of production/injection volumes for these wells, along with pressure data, were matched using a black-oil simulator. The calibrated model was then used to predict the long-term performance of the pilot. Finally, this model was used for further investigation of parameters affecting the performance of the waterflood operation along with assessment of EOR (gas injection) schemes applicable to the Bakken Formation. Two important conclusions can be derived from this study: 1) waterflooding can be effective in tight oil reservoirs using MFHWs as injectors and producers and, 2) careful characterization of vertical changes in reservoir quality using laboratory-based measurements are important for improving the quality of the history match and resulting forecast scenarios. For 2), permeability heterogeneity was quantified using profile permeability measurements corrected to ‘in-situ’ stress conditions.

Advancements in horizontal drilling with hydraulic fracturing have enabled commercial oil production from tight oil reservoirs. However, the primary recovery factor remains very low, usually less than 15%. It is a big challenge to supply formation drive energy to sustain production. After hydraulic fracturing, there is often pre-mature water breakthrough or gas channeling when we inject water or gas. Therefore, CO2 huff-n-puff becomes an attractive option to improve oil recovery in tight oil reservoirs. Based on typical reservoir and fracture properties in Ordos Long-7 tight oil reservoir, a compositional reservoir simulation model with hydraulic fracture network was established to evaluate the performance of CO2 huff-n-puff enhanced oil recovery (EOR) method. Through numerical simulation, we perform sensitivity study to explore the impacts of operation parameters such as CO2 injection rate, injection time, soaking time, number of huff-n-puff cycles on EOR performance. Some of these parameters have rarely been investigated for recovery in tight reservoirs, such as in-situ fluid composition, fracture pore volume and hydraulic fracture characterization. Furthermore, correlation analysis is used to evaluate the performance of CO2 huff-n-puff process. In this study, we find that hydraulic fracture morphology and fracture conductivity can have a large impact on the performance of CO2 huff-n-puff. Due to the existence of natural fractures in tight reservoirs and the stimulated reservoir volume, CO2 huff-n-puff can not only mobilize the crude oil near the well, but also have certain recovery effects on the remaining oil between the adjacent wells. Simulation results show that the most important parameter is number of cycles, followed by CO2 injection rate and soaking time. It is found that the optimum injection pressure of CO2 huff-n-puff process can be set around the minimum miscibility pressure (MMP) for CO2 and the crude. We set the soaking time period to be 30 days, injection rate to be 150 ton/day, number of cycles to be 4 for optimized oil recovery. The incremental oil recovery factor after one cycle is 1.59%, and the output-to-input ratio is 1:1.75. The findings in this work have the potential to advance our understandings of the role of CO2 EOR in developing unconventional oil reservoirs, which will benefit both the energy industry and the environment with the potential benefit of CO2 geological sequestration.