Pressure Measurements for Monitoring CO2 Foam Pilots

Summary A considerable portion of the world's hydrocarbon endowment is in carbonate reservoirs. Carbonate reservoirs usually exhibit low porosity and may be fractured. These two characteristics along with oil-to-mixed wet rock properties usually result in lowered hydrocarbon recovery rates. When enhanced oil recovery (EOR) strategies are pursued, the injected fluids will likely flow through the fracture network and bypass the oil in the rock matrix. The high permeability in the fracture network and the low equivalent porous volume result in early breakthrough of the injected fluids. Infill drilling programs and well conformance strategies—mostly gas and water shutoff—have been effectively used to mitigate the early breakthrough and increase oil recovery. In most cases, however, 40 to 50% of the original oil in place (OOIP) is not produced. A large number of EOR field projects in carbonate reservoirs have been referenced in the literature since the early 1970s. These field projects demonstrate the technical feasibility of various EOR methods in carbonate reservoirs. However, because of the collapse in oil prices, most of the aforementioned project plans have been abandoned. This paper presents a comprehensive compilation of EOR (Gas, Chemical, and Thermal methods) field experiences in carbonate reservoirs within the US, as an attempt to identify key variables and project design parameters for future evaluation and revitalization of mature carbonate reservoirs. Carbon dioxide flooding [continuous or water-alternating gas (WAG)] is the dominant EOR process used in the US This is because of the high availability of low-cost CO2. CO2 EOR in particular represents the logical first step towards viable geologic carbon storage and sequestration. EOR chemical methods in carbonate reservoirs, especially polymer flooding, have been widely tested in US carbonate reservoirs. However, EOR chemical methods have made a marginal contribution, relatively, in terms of total oil recovered. Our study includes a brief overview of current laboratory (e.g. wettability changes and novel chemical additives) and field (e.g. injectivity enhancement) experiences in EOR chemical methods in carbonate formations. A brief discussion surrounding the screening methods used to identify viable EOR opportunities in carbonate fields based on past and present experiences is also included. Introduction Carbonate reservoirs are naturally-fractured geologic formations characterized by heterogeneous porosity and permeability distributions. In the case of low porosity and low permeability carbonate rocks (more specifically rock matrices), the fluid flow in the reservoir can be completely dependent on the fracture network while the matrix only plays a source role (analogous to tight sand formations and natural gas flow). In the case of porous carbonate rocks, fracture networks can cause uneven sweeping of the reservoir, leading to early breakthrough of injected fluids in the producing wells and resulting in low recovery factors. The abundance of carbonate reservoirs has been the subject of numerous studies attempting to characterize their heterogeneities, classify different types of fractured reservoirs, and determine how rock and fluid properties have an impact on ultimate recovery (Roehl et al. 1985; Allan and Qing Sun 2003; Carr et al. 2001; Grave et al. 2000; Benson et al. 1998; Wardlaw 1996). The TORIS database (maintained by the US Department of Energy) indicates 22% of the OOIP in the US is contained in shallow-shelf carbonate reservoirs. Currently in the US, these types of reservoirs exist in more than 14 states with over 70% of the OOIP located in reservoirs in Texas and New Mexico, mostly concentrated in the Permian Basin (Nuckols 1992, Xie et al. 2005). Over the last three decades, primary production, waterflooding, and CO2 floods, combined with infill drilling programs, have been the most widely used recovery methods. However, other EOR strategies have been tested in the past and there are currently several active research programs seeking alternatives to increase the recovery factor of these mostly light crude-oil reservoirs economically. Although the Permian Basin (west Texas and southeast New Mexico) can be considered mature, its potential for improved oil recovery is still very high. A recent study reports that there is an estimated 30 billion barrels of mobile oil in the Permian Basin, reiterating the strategic importance of EOR technologies for carbonate reservoirs and their impact on US oil production (Nuckols 1992; Xie et al. 2005; Seethepalli et al. 2004; Moritis 2004; Cole 2003; Moritis 2003; Dutton et al. 2004).

This paper presents the analysis of transient pressure measurements from a recent CO2 foam pilot in East Seminole Field, Permian Basin, USA. A surfactant-stabilized foam was selected to mitigate CO2 EOR challenges in this field by reducing CO2 mobility in an effort toimprove sweep efficiency, oil recovery, and CO2 storage potential. The surfactant system was designed in the laboratory by measuring surfactant adsorption and verifying foam stability. A surfactant-alternating-gas (SAG) injection strategy, with 10 days of surfactant solution followed by 20 days of CO2, began in May 2019. The pilot monitoring program aimed to evaluate reservoir response to foam injection. Surveys included CO2 injection profiles, CO2 tracer tests, collection of injection bottom hole pressure/temperature data, and three-phase flow rates.Injection BHP and temperature data from the downhole pressure gauge (DHPG) was used to evaluate the pilot response during surfactant and CO2 injection. The analysis was conducted by examining the differential pressure (dP) and differential temperature (dT) through time for the first nine SAG cycles. A high-resolution two-dimensional radial flow model was developed to history match the measured transient pressure data. The simulation model included the porosity and permeability distribution from a validated sector-scale model of the pilot pattern and surrounding producers. The radial flow model was used to examine the impact of foam and/or relative permeability on injectivity and mobility reduction when switching between surfactant solution and CO2 in a SAG process.Transient analysis showed that the temperature responses were quite similar during most SAG cycles. On the other hand, differential pressures consistently increased during periods of surfactant injection and decreased during the subsequent CO2 injection periods. The pressure increase (buildup) during surfactant injection was due to a decrease in mobility, showing development of a mobility bank in the reservoir. There are also questions regarding the impact of foam and/or relative permeability on injectivity and mobility reduction when switching between surfactant solution and CO2 in a SAG process.

Experimental and simulation investigations of carbon storage associated with CO2 EOR in low-permeability reservoir

Laboratory study on the rheology properties of nanoparticle-stabilized supercritical CO2 foam

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

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.

The success of foam to reduce CO2 mobility in CO2 enhanced oil recovery and CO2 storage operations depends on foam stability in the reservoir. Foams are thermodynamically unstable, and factors such as surfactant adsorption, the presence of oil, and harsh reservoir conditions can cause the foam to destabilize. Pore-level foam coarsening and anti-coarsening mechanisms are not, however, fully understood and characterized at reservoir pressure. Using lab-on-a-chip technology, we probe dense (liquid) phase CO2 foam stability and the impact of Ostwald ripening at 100 bars using dynamic pore-scale observations. Three types of pore-level coarsening were observed: (1) large bubbles growing at the expense of small bubbles, at high aqueous phase saturations, unrestricted by the grains; (2) large bubbles growing at the expense of small bubbles, at low aqueous phase saturation, restricted by the grains; and (3) equilibration of plateau borders. Type 3 coarsening led to stable CO2 foam states eight times faster than type 2 and ten times faster than type 1. Anti-coarsening where CO2 diffused from a large bubble to a small bubble was also observed. The experimental results also compared stabilities of CO2 foam generated with hybrid nanoparticle–surfactant solution to CO2 foam stabilized by only surfactant or nanoparticles. Doubling the surfactant concentration from 2500 to 5000 ppm and adding 1500 ppm of nanoparticles to the 2500 ppm surfactant-based solution resulted in stronger foam, which resisted Ostwald ripening. Dynamic pore-scale observations of dense phase CO2 foam revealed gas diffusion from small, high-curvature bubbles to large, low-curvature bubbles and that the overall curvature of the bubbles decreased with time. Overall, this study provides in situ quantification of CO2 foam strength and stability dynamics at high-pressure conditions.Article HighlightsA comprehensive laboratory investigation of CO2 foam stability and the impact of Ostwald ripening.Pore-level foam coarsening and anti-coarsening mechanisms insights.

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 Pennsylvanian–age Morrow sandstone within the Farnsworth field unit of the Anadarko basin presents an opportunity for CO2 enhanced oil recovery (EOR) and sequestration (CCUS). At Farnsworth, Chaparral Energy's EOR project injects anthropogenic CO2 from nearby fertilizer and ethanol plants into the Morrow Formation. Field development initiated in 1955 and CO 2injection started December 2010. The Southwest Regional Partnership on Carbon Sequestration (SWP) is using this project to monitor CO2 injection and movement in the field to determine CO2 storage potential in CO2-EOR projects. This paper presents a field scale compositional reservoir flow modeling study in the Farnsworth Unit. The performance history of the CO2 flood and production strategies have been investigated for optimizing oil and CO2 storage. A high resolution geocellular model constructed based on the field geophysical, geological and engineering data acquired from the unit. An initial history match of primary and secondary recovery was conducted to set a basis for CO2 flood study. The performance of the current CO 2miscible flood patterns were subsequently calibrated to the history data. Several prediction models were constructed including water alternating gas (WAG), and infill drilling using the current active and newly proposed flood patterns. A consistent WAG showed a highly probable way of ensuring maximum oil production and storage of CO2 within the Morrow formation. The production response to the CO2 flooding is very impressive with a high percentage of oil production attributed to CO2 injection. Oil production increasingly exceeded the original project performance anticipated. More importantly, a large volume of injected CO2 has been sequestered within the Morrow Formation. The reservoir modeling study provides valuable insights for optimizing oil production and CO2 storage within the Farnsworth Unit. The results will serve as a benchmark for future CO2–EOR or CCUS projects in the Anadarko basin or geologically similar basins throughout the world.

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.

An experimental study of gas sequestration efficiency using water alternating gas and surfactant alternating gas methods

Technology Focus SPE hosted two enhanced-oil-recovery (EOR) conferences in 2010: One was the 2010 SPE Improved Oil Recovery Symposium in Tulsa and the other was the 2010 SPE EOR Conference at Oil & Gas West Asia, Muscat, Oman. Many other SPE conferences had sessions on EOR technologies. Therefore, it is not surprising that more than 350 papers were presented on the topic in the past year. These papers covered past field-application experiences and accomplishments, current strides, and future directions. As in previous years, when I selected papers to highlight EOR this year, I classified the papers into the categories of gas injection, chemical methods, thermal methods, conformance control, microbial EOR, carbonate-reservoir EOR, reservoir-problem-identification technologies, and novel EOR methods such as low-salinity waterflooding and nanoparticles for EOR. However, it was still quite difficult to select only four to highlight from so many outstanding papers. In the past few EOR features, I highlighted chemical methods, CO2 EOR and sequestration, low-salinity waterflooding, particle gel for conformance control, wettability alteration, and methods to identify reservoir channels. Even though those topics are still quite important and many new ideas and information were presented this year, I decided to give preference to topics not highlighted before and to papers that comprehensively summarize field experiences. Overall, the leading-edge EOR technologies presented in SPE meetings this past year will be applied increasingly on a global scale and will increase the oil recovery of mature oil fields significantly as the technologies mature. EOR Performance and Modeling additional reading available at OnePetro: www.onepetro.org SPE 133089 • “Rock/Fluid Characterization for Miscible-CO2 Injection: Residual-Oil Zone, Seminole Field, Permian Basin” by M.M. Honarpour, SPE, Hess Corporation, et al. SPE 129899 • “Potential for Polymer Flooding Reservoirs With Viscous Oils” by R.S. Seright, SPE, New Mexico Petroleum Recovery Research Center. See SPE Res Eval & Eng, August 2010, page 730. SPE 132487 • “Air Injection in Heavy-Oil Reservoirs—A Process Whose Time Has Come (Again)” by M.G. Ursenbach, SPE, University of Calgary, et al. See J Can Pet Technol, January 2010, page 48. SPE 129925 • “Nanoparticle-Stabilized Supercritical CO2 Foams for Potential Mobility-Control Applications” by David Espinosa, SPE, University of Texas at Austin, et al. SPE 129692 • “Demonstration of Low-Salinity EOR at Interwell Scale, Endicott Field, Alaska” by Jim Seccombe, SPE, BP plc, et al. SPE 139667 • “Tertiary Oil Recovery and CO2 Sequestration by Carbonated-Water Injection” by N.I. Kechut, SPE, Heriot-Watt University, et al. SPE 132359 • “Identifying Injector/Producer Relationships in Waterflood Using Hybrid Constrained Nonlinear Optimization” by H. Lee, University of Southern California, et al.

Carbon dioxide foam injection is a promising enhanced oil recovery (EOR) method, being at the same time an efficient carbon storage technology. The strength of CO2 foam under reservoir conditions plays a crucial role in predicting the EOR and sequestration performance, yet, controlling the strength of the foam is challenging due to the complex physics of foams and their sensitivity to operational conditions and reservoir parameters. Data-driven approaches for complex fluids such as foams can be an alternative method to the time-consuming experimental and conventional modeling techniques, which often fail to accurately describe the effect of all important related parameters. In this study, machine learning (ML) models were constructed to predict the oil-free CO2 foam apparent viscosity in the bulk phase and sandstone formations. Based on previous experimental data on various operational and reservoir conditions, predictive models were developed by employing six ML algorithms. Among the applied algorithms, neural network algorithms provided the most precise predictions for bulk and porous media. The established models were then used to compute the critical foam quality under different conditions and determine the maximum apparent foam viscosity, effectively controlling CO2 mobility to co-optimize EOR and CO2 sequestration.

Water alternating gas (WAG) injection process is a proven enhanced oil recovery (EOR) technology with many successful field applications around the world. WAG pilot projects demonstrate that WAG incremental recovery factor typically ranges from 5 to 10% of original oil in place, though up to 20% has been observed in some fields. Despite its proven success, WAG application growth has been very slow. One of the reasons is the unavailability of robust analytical predictive tools that could estimate WAG incremental recovery factor, which is required for preliminary economic analysis before committing to expensive and time-consuming detailed technical studies and field pilot test that often requires a lot of input data. A semi-numerical model for WAG incremental recovery factor prediction was developed based on data mining of published WAG pilots to fill this gap. An extensive review of published WAG pilot projects was carried out, and consequently, 33 projects from 28 fields around the world were selected for this research study. Field WAG incremental recovery factor and parameters with total of one hundred and seventy-seven (177) observations were inputted to the predictive model. A predictive model was developed using both regression and group method of data handling (GMDH) techniques; 70% of the 33 WAG pilot projects data were used as validation, whereas remaining 30% of data set were used for validation. The predictive model results achieved with coefficient of determination (R2) from the regression method were ranging from 0.892 to 0.946 and 0.854 to 0.917 for training and validation sets, respectively. However, the prediction model coefficient of determination (R2) using GMDH method was ranging from 0.964 to 0.981 and 0.934 to 0.974 for training and validation, respectively. The developed predictive model can predict WAG incremental recovery factor versus multiple input parameters that include rock type, WAG process type, hydrocarbon pore volume of injected gas, reservoir permeability, oil gravity, oil viscosity, reservoir pressure, and reservoir temperature. The results of the study demonstrated that few input parameters have a significant impact on WAG incremental recovery factor as reservoir permeability and hydrocarbon pore volume of injected gas. This research study uses a novel approach in pre-defining the expected incremental WAG recovery factor before committing resources for building complex numerical reservoir simulation models and running WAG pilot tests, which are very time-consuming and costly and require extensive data input.

CO2 mobility control improvement using N2-foam at high pressure and high temperature conditions