CO2 Utilization for Enhance Oil Recovery with Huff-N-Puff Process in Depleting Heterogeneous Reservoir

Tertiary oil recovery and CO2 storage from laboratory injection of CO2 or water-saturated CO2 into a sandstone core

Recent advances in carbon dioxide utilization

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200316, “Joint Optimization of Well Completions and Controls for CO2 Enhanced Oil Recovery and Storage,” by Bailian Chen, SPE, and Rajesh Pawar, Los Alamos National Laboratory, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa 18–22 April. The paper has not been peer reviewed. Carbon dioxide (CO2) storage through CO2 enhanced oil recovery (EOR) has been considered an option for larger-scale deployment of CO2 storage because of the economic benefits of oil recovery, 45Q tax credits, and the use of existing infrastructure. The complete paper investigates how optimal reservoir management and operation strategies can be used to optimize both CO2 storage and oil recovery. Results of the authors’ study showed that joint optimization of well completions and well controls can achieve a higher final net present value (NPV) than that obtained from the optimization of well controls only. Introduction In CO2 EOR associated with storage processes, poorly designed well-operating conditions or completions can lead to low oil recovery factors and suboptimal CO2 storage. Co-optimization of oil production and CO2 storage has been recognized as a feasible technique to maximize benefit in terms of oil production and CO2 storage tax credit. To the best of the authors’ knowledge, settings for well completions have not been considered as optimization variables in a CO2 EOR and storage co-optimization process. The objective of this study is to conduct joint optimization of well completions and controls [well rates or bottomhole pressures (BHP)] that maximize life-cycle NPV in CO2 EOR and storage processes and demonstrate the superiority of joint optimization over well-control-only optimization. Optimization Problem In this study, the optimization problem considered is the joint optimization of well completions and well controls for a CO2 EOR and storage process. The mathematical process behind this determination is detailed in the complete paper. The optimization problem was focused on jointly estimating the well completions (i.e., fraction of injection/production well perforations in each reservoir layer) and CO2 injection and oil-production controls that maximize NPV in a CO2 EOR and storage operation. The authors used a newly developed stochastic simplex approximate gradient algorithm to solve the optimization problem. The performance of the joint optimization approach was compared with the performance of the well-control-only optimization approach. In addition, the performance of the co-optimization of CO2 storage and oil-recovery approach was compared with that of the maximization of only-CO2-storage and only-oil-recovery approaches.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 168979, “CO2-Based Enhanced Oil Recovery From Unconventional Reservoirs: A Case Study From the Bakken Formation,” by G. Liu, J.A. Sorensen, J.R. Braunberger, R. Klenner, J. Ge, C.D. Gorecki, E.N. Steadman, and J.A. Harju, University of North Dakota, prepared for the 2014 SPE Unconventional Resources Conference—USA, The Woodlands, Texas, USA, 1–3 April. The paper has not been peer reviewed. In this study, detailed petrophysical and geological field models focusing on the middle and lower members of the Bakken Formation were developed on the basis of field characterization, well-log interpretation, and laboratory core analysis by scanning-electron-microscopy, ultraviolet-fluorescence, and standard-optical-microscopy techniques. A fine-scale model with a pair of horizontal wells was extracted from the initial model (Bailey area) to examine the potential effectiveness of oil-recovery techniques based on carbon dioxide (CO2) injection. The results show that CO2 injection may play a significant role in increasing oil production. Introduction Small improvements in productivity could increase technically recoverable oil in the Bakken by billions of barrels. While the use of CO2 in conventional reservoirs is a widely applied and well-understood practice, its use for enhanced oil recovery (EOR) in tight oil reservoirs is a relatively new concept. The use of CO2 as an injection fluid may reduce the hydrocarbon viscosities in the reservoir and allow additional trapped oil to be produced. Another benefit of CO2 injection is to mitigate climate change by storing CO2 in the reservoir. The Energy & Environmental Research Center has conducted a multidisciplinary research program with the ultimate goal of providing industry with insight regarding the potential to use CO2 for EOR in the Bakken and Three Forks Formations. The Bakken CO2 Enhanced Recovery and Storage Project began in 2012 and was completed in 2013. The objective of this project was to use reservoir characterization and laboratory analytical data (e.g., core analyses, well logs, and oil analyses) coupled with state-of-the-art modeling to examine the viability of using CO2 for simultaneous CO2 storage and EOR in the Bakken. The ultimate goal of the project was to have a Bakken operator apply the knowledge gained from the laboratory, characterization, and modeling activities to a pilot-scale field test of CO2 injection into a Bakken or Three Forks reservoir. The presentation in this paper comprises a discussion of the initial near-wellbore-modeling aspect of the project.

The application of carbon dioxide (CO2) in enhanced oil recovery (EOR) projects is becoming increasingly more interesting in the petroleum industry because it can boost oil production rates while potentially reducing greenhouse gas emissions. The injected CO2 causes oil swelling and viscosity reduction, making it easier to flow through the reservoir fractures. This article studies the performance of the first EOR CO2 project in Croatia, which started operations in 2014 with a capacity of 0.41 million tons per year (Mtpa). The CO2 source is a natural gas processing plant, which released the CO2 into the atmosphere prior to the EOR project. Now, this CO2 is continuously captured, compressed, transported, liquefied, and injected into the EOR fields of Ivanić and Žutica. Tertiary (EOR) oil recovery at these two oil fields is expected to raise the oil recovery factors up to 55% from the previously achieved 9% in the primary stage and 36% in the secondary stage. Besides the EOR project, this article reviews other carbon capture, utilization, and storage (CCUS) projects in Croatia, for the cement industry, power generation, and biofuel production. All these projects combined could bring the total CCUS capacity up to 1.843 Mtpa by 2030.

The Effect of Brine Supply on CO2 Injectivity Impairment Due to Salt Precipitation

Cleaner coal and greener oil production: An integrated CCUS approach in Yanchang Petroleum Group

Numerical simulation and optimization of CO2 utilization for enhanced oil recovery from depleted reservoirs

Technology Update Most domestic conventional oil resources have been produced using primary and secondary recovery techniques, with an average recovery factor estimated at 35%. Additional recovery is possible by using innovative enhanced oil recovery (EOR) techniques. One of these, carbon dioxide (CO2) miscible flooding, is the fastest growing EOR technique in the United States because of the many reservoirs amenable to the process. Current production is almost 310,000 B/D (EOR Survey, Oil and Gas Journal, April 2012), representing approximately 5% of total US oil output. A revised national resource assessment for CO2 EOR conducted by the National Energy Technology Laboratory (NETL) of the United States Department of Energy (DOE) in 2011 indicated that “next generation” CO2 EOR can provide 137 billion bbl of additional, technically recoverable domestic oil, with about half (67 billion bbl) economically recoverable at an oil price of USD 85 per bbl. CO2 EOR has the benefit of sequestering CO2 in oil producing formations and is seen as a critical component of future greenhouse gas management programs. This facet of CO2 EOR produces valuable synergies with the carbon capture, utilization, and storage research program with the DOE’s Office of Fossil Energy. The CO2 EOR process is limited by technology, cost, and the geographic availability of CO2. Technology improvements are needed to increase the displacement efficiency of the process. Not only would advances in displacement efficiency increase oil recovery, it would also lead to the sequestration of additional CO2 volumes. Background The Office of Fossil Energy has historically supported a large number of laboratory and field tests in an effort to improve oil recovery processes. A majority of the projects were related to advanced reservoir characterization, mobility control, and conformance of CO2 flooding. In September 2010, the NETL awarded a number of new research projects to further development of the next generation of CO2 EOR, encouraging applicants to pursue small field or pilot testing. Two of the awarded research projects are related to mobility control in CO2 flooding using nanoparticle technologies. The University of Texas at Austin (UT) is evaluating inexpensive alternative nanoparticles (microscopic particles with at least one dimension less than 100 nm) to provide the large volumes needed for foam stabilization in field-scale CO2 floods. The study entails using low-cost, commercially available “bare” nanoparticles (e.g., silica, fly ash, and iron oxide) and applying a polyethylene glycol (PEG) or other in-house coating to produce low-cost alternatives to develop CO2 foam.

CO2 storage potential during CO2 enhanced oil recovery in sandstone reservoirs

Decarbonising Vietnam's power and industry sectors by carbon capture and storage

Carbon Capture, Utilization, and Storage (CCUS) offers a viable solution to reduce the carbon footprint in the petroleum industry, and foam injection presents a promising method to achieve this while simultaneously increasing oil recovery. In this work, we studied the feasibility of CO2 foam for co-optimizing enhanced oil recovery and CO2 storage in a high-salinity carbonate formation. The simulated hydrodynamic model is a depleted formation containing 30% residual oil, with three mechanisms for CO2 storage: solubility, residual, and mineralization trapping mechanisms. The results showed that after 20 years, oil recovery during foam injection was 2.7 times higher than CO2 injection, and the CO2 stored during foam flooding was 38% higher than CO2 injection. Notably, foam injection also increased CO2 storage capacity by 2.6 times, indicating the potential to store around 2 gigatons of CO2 in the simulated model. This was attributed to the ability of foam to significantly reduce gas mobility and thus form isolated bubbles through its Jamin effect. Residual trapping was the dominant trapping mechanism, contributing to over 70% of the total CO2 trapped, attributed to the reduction in the dissolution of CO2 in brine due to the high salinity of the aqueous medium. CO2 mineralization was also studied, showing the least trapping efficiency and the dissolution trend of all the carbonate minerals. This study illustrates a novel CO2 utilization and storage technique in which CO2 is concurrently sequestered while enhancing oil recovery in a depleted oil reservoir by injecting CO2 as foam. The relevance of this study lies in its potential to provide a dual benefit of reducing greenhouse gas emissions and boosting oil production, offering a sustainable approach for the petroleum industry.

Feasibility evaluation of CO[formula omitted] EOR and storage in tight oil reservoirs: A demonstration project in the Ordos Basin

This paper presents a summary of oil recovery from each of the nine commercial scale CO2 enhanced oil recovery projects in Wyoming along with a brief discussion of the geology of the fields. The current CO2 supply and pipeline system for the State is discussed along with an estimate of potential future production from CO2 enhanced oil recovery (EOR), if widely employed in Wyoming. CO2 injection, production, and pipeline sales data were obtained from the Wyoming Oil and Gas Conservation Commission and supplemented where possible by production data elsewhere in the public domain; all data used is public. Wyoming has world-class fields that have proven to be excellent targets for CO2 EOR. The process has been used in Wyoming since 1986 and there are nine commercial-scale floods that are currently active in the State. The average incremental oil recovery for Wyoming's ongoing CO2 EOR floods is over 10% of original oil in place and the average total incremental oil recovered for all ongoing CO2 floods is over 15 million barrels per reservoir and over 135 million barrels for the State. Since 2010, over 10% of the state's oil production has been incremental oil from CO2 floods. The State has excess CO2 supply that can be used for EOR, the current pipeline system has excess capacity, and the State has many fields within its four main oil producing basins that appear to be amenable to CO2 EOR.

The objective of this paper is to compare oil recoveries by huff ‘n’ puff gas injection using methane (CH4), carbon dioxide (CO2), hydrogen (H2) and rich gas (70% CH4, 20% C3H8, plus 10% C6H14), and to advance some ideas regarding carbon capture, utilization and storage (CCUS) of CO2, and storage of hydrogen when these gases are used in huff ‘n’ puff operations. The procedure considers a real huff ‘n’ puff pilot well in the Eagle Ford shale of Texas with methane injection. Following history match of the pilot well, the injected gas is switched in the reservoir simulator to CO2, H2 and rich gas. Key to success in this process, is geologic containment, which occurs when large volumes of hydrocarbons remain over geologic time in the windows where they were generated. This is the case of the Eagle Ford shale, where hydrocarbons display an upside-down distribution, with oil on the top, condensate in the middle and dry gas at the bottom. Geologic containment permits the implementation of simultaneous huff ‘n’ puff, utilization and storage of CO2 with nil probabilities of leakage. Results show that huff ‘n’ puff gas injection can significantly increase oil recoveries to be 25-35% of the OOIP (depending on the specific injected gas), compared to about 10% by primary means during the simulation time. The benefits of huff ‘n’ puff gas injection are also applicable in other shale reservoirs where oil, condensate and dry gas present an upside down distribution. One example in Canada is the Duvernay shale. Geologic containment allows adequate and safe storage of CO2 and hydrogen without leaks at the end of the huff ‘n’ puff project. This paper also assesses and corroborates the conclusion that "significant improvements in oil recovery can be obtained by injecting gas at larger rates during shorter periods of time (as opposed to injecting gas at smaller rates during longer periods of time)." The same conclusion holds true for methane, CO2, hydrogen and rich gas injection. The novelty of this work is demonstrating the efficiency of CCUS and huff ‘n’ puff gas injection when geologic containment exists in the shale reservoir. It is a solution where everyone benefits and allows to significantly increase oil recoveries, while providing safe storage of CO2 and H2 without any leaks.