Farnsworth Field CO2-EOR Project: Performance Case History

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 The paper has not been peer reviewed.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 paper presents a numerical study of CO2 enhanced oil recovery (EOR) and storage in partially depleted reservoirs. A field-scale compositional reservoir flow model was developed for assessing the performance history of a CO2 flood and optimizing oil production and CO2 storage in the Farnsworth Field Unit (FWU), Ochiltree County, Texas. A geocellular model was constructed from geophysical and geological data acquired at the site. The model aided in characterization of heterogeneities in the Pennsylvanian-aged Morrow sandstone reservoir. Seismic attributes illuminated previously unknown faults and structural elements within the field. A laboratory fluid analysis was tuned to an equation of state and subsequently used to predict the thermodynamic minimum miscible pressure (MMP). Datasets including net-to-gRose ratio, volume of shale, permeability, and burial history were used to model initial fault transmissibility based on the Sperivick model. An improved history match of primary and secondary recovery was performed to set the basis for a CO2 flood study. The performance of the current CO2 miscible flood patterns were subsequently calibrated to historical production and injection data. Several prediction models were constructed to study the effect of recycling, addition of wells and/or new patterns, water alternating gas (WAG) cycles and optimum amount of CO2 purchase on incremental oil production and CO2 storage in the FWU. The history matching study successfully validated the presence of the previously-undetected faults within FWU that were seen in the seismic survey. The analysis of the various prediction scenarios showed that recycling a high percentage of produced gas, addition of new wells and a gradual reduction in CO2 purchase after several years of operation would be the best approach to ensure a high percentage of recoverable incremental oil and sequestration of anthropogenic CO2 within the Morrow reservoir.

CO2 storage potential during CO2 enhanced oil recovery in sandstone reservoirs

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

CO2 injection is an effective method for enhanced oil recovery (EOR). The Pennsylvanian Morrowan sequence of the panhandle of Texas through Southeast Colorado in the United States currently presents an opportunity for CO2 EOR and carbon sequestration. The Farnsworth Unit (FWU) of Ochiltree County, Texas operated by Chaparral Energy L.L.C. is the site of a CO2-EOR project using anthropogenic CO2. The Southwest Regional Partnership on Carbon Sequestration is working closely with Chaparral Energy to study the effectiveness of large-scale CO2 injection into the FWU. This paper presents the reservoir fluid model for the FWU. It includes a comprehensive PVT analysis of fluid that has been tuned to an equation of state (EOS) with 9 components. After tuning, the experimental and simulated data had an excellent match. A series of slim tube simulated experiments were carried out to determine the minimum miscibility pressure (MMP). The C7+ fractions were split into two pseudo-components with appropriate critical properties without affecting the actual fluid properties. This aided in optimizing the predictions even while using fewer pseudo components to characterize the fluid. Simulation of the MMP using the EOS tuned fluid was conducted and the predicted MMP was close to the experimental value with an error less than five percent. A sensitivity analysis was also conducted with varying impurities in the CO2 injection fluid to analyze the effect of recycle gas on the MMP. The approach used in this study demonstrated an improved strategy in lumping and splitting of compositions to ensure accuracy in reservoir fluid characterization. Introduction Fluid characterization plays an important role in the compositional simulation of enhanced oil recovery processes (EOR) like miscible gas flooding. Black oil models do not efficiently deal with the complexities of phase behavior in the case of compositional modelling. This makes the use of compositional fluid characterization essential.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180408, “Integrating Enhanced-Oil-Recovery and Carbon-Capture-and-Storage Projects: A Case Study From Farnsworth Field, Texas,” by Robert Balch, New Mexico Institute of Mining and Technology, and Brian McPherson, University of Utah, prepared for the 2016 SPE Western Regional Meeting, Anchorage, 23–26 May. The paper has not been peer reviewed. The Southwest Partnership on Carbon Sequestration (SWP) is one of seven large-scale demonstration projects sponsored by the US Department of Energy. The SWP has a goal of permanently sequestering more than 1 million t of carbon dioxide (CO2) in an active enhanced-oil-recovery (EOR) project in a mature waterflood in the Anadarko Basin. Goals of the project include optimizing the balance between EOR and storage, ensuring storage permanence, and developing best practices for carbon storage using man-made CO2. Introduction The goal of the project is to inject at least 1 million t of CO2 into an active oil field undergoing EOR over a 4- to 5-year period. All CO2 used in the project is anthropogenic and would otherwise be vented to the atmosphere. Much of this injected CO2 will be trapped permanently in the subsurface. A primary objective is to quantify CO2 storage and better understand conditions and characteristics that promote such storage. Background. The project site is located in the Anadarko Basin, a deep structural basin approximately 70,000 sq miles in size and primarily located in the northern Texas panhandle and western Oklahoma and extending into eastern Colorado and western Kansas. The basin is a mature oil-and-gas-production province but without access to natural CO2 sources. These factors combine to make the Anadarko an excellent region for combined EOR and carbon-storage projects using anthropogenic CO2. The target formation for the CO2-storage study addressed by this paper is the oil-bearing upper Morrow sandstone, informally designated the Morrow B. The Morrow Formation at Farns worth is an incised valley filled with coarse sandstone that has produced more than 19 million bbl of oil and 44 Bcf of gas. The formation lies at an average depth of 7,750 ft and contains rock with permeability ranging from 10 to 500 md, placing it well within the range needed for CO2 injection and storage. Preliminary estimates of CO2-storage capacity of the Morrow within the Farnsworth Unit (FWU) exceed 25 million t. To date, all CO2 has been delivered from two anthropogenic sources. Much of this injected CO2 is being trapped permanently in the subsurface in the Morrow B formation. The site operator is injecting CO2 in the center well of five-spot well patterns. The project started with three initial patterns in December 2010, and more patterns are to be added as CO2 is purchased and more recycled CO2 becomes available. As of May 2015, there were 13 operating patterns. The plan is to have approximately 25 patterns in operation.

Recently, the potential of enhanced oil recovery (EOR) with CO2 injection in tight oil reservoir has drawn attention. Most of previous studies for CO2 injection in tight oil reservoir have considered only huff-and-puff process. However, CO2 flooding could show further improvement depending on the fracture-reservoir system. To investigate the effects of CO2 flooding and huff-and-puff processes in tight oil reservoir, numerical models incorporating molecular diffusion and stress-dependent deformation mechanisms were generated. In order to model the realistic tight oil reservoir, core and reservoir models were constructed with data from Bakken shale field. Coand counter-diffusive transport is depicted by Sigmund and Wilke correlation. Stress-dependent deformation in tight reservoir is considered by exponential correlation coupled with linear-elastic model. The developed models were used to investigate major factors affecting CO2 injection process such as molecular diffusion, stress-dependent compaction, and conductivity of fracture system. In the proposed model, about 8% of hydrocarbon was recovered during the primary production. Recoveries with CO2 flooding and huff-and-puff following primary production are increased to 18 and 15%, respectively. The main factor which facilitates CO2 flooding is the fracture conductivity of unstimulated zone. Because the middle Bakken formation shows relatively higher permeability and fracture conductivity than other ultra-tight reservoirs, the CO2 displaces the oil between wells with flooding. In case of the reservoir with lower fracture conductivity, on the ther hand, huff-and-puff process is better than flooding process for EOR. In addition, CO2 flooding process showed higher CO2 storage than huff-and-puff process. CO2 flooding method stores 1.7 times higher CO2 than huff-and-puff method. About 91% of injected CO2 is stored for CO2 flooding and about 54% of injected CO2 is stored for huff-and-puff. Therefore, the need to develop CO2 flooding techniques is evident in order to improve not only the oil recovery but the CO2 storage. The investigation of CO2 flooding and huff-and-puff with comprehensive numerical model suggests better understanding and design of CO2 injection in order to improve the efficiency of CO2 EOR and storage in tight oil reservoirs.

Screening and simulation of offshore CO2-EOR and storage: A case study for the HZ21-1 oilfield in the Pearl River Mouth Basin, Northern South China Sea

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).

Field application of supercritical CO2 (sc- CO2) miscible flooding continues to grow. Optimization of sc- CO2 injection during miscible flooding modes represents one of the dominant factors affecting its performance in carbonate oil reservoirs. The main objective of this study was to investigate the impact of different modes of sc- CO2 miscible injection on oil recovery and injectivity in carbonate rocks. Several modes of sc- CO2 injection modes were investigated including continuous CO2 miscible flooding, water-alternating-gas (WAG), and tapered WAG injection. Five coreflooding experiments were conducted to evaluate oil recovery for different modes of CO2 injection under reservoir conditions. Composite cores of 25 cm length from a specific, producing carbonate reservoir were used in the study. Both horizontal and vertical coreflooding experiments of continuous CO2 injection mode were carried out to compare oil recovery and injectivity during CO2 flooding. Horizontal core flooding experiments under WAG mode was performed at pore pressures of 3,200 psi and 3,800 psi. The experimental results indicate that tertiary oil recovery was influenced significantly by different CO2 injection modes and the direction of displacement. 18.4% and 26.74% of original oil in cores were recovered for horizontal and vertical experiments of continuous CO2 injection modes, respectively. In horizontal WAG experiments with different pore pressures, higher oil recovery was observed at a pore pressure of 3,800 psi compared to 3,200 psi. The marginal increase in incremental oil recovery indicates that pressure increase beyond 3,200 psi will not have a significant impact. The injectivity of different CO2 injection modes is reported in this paper.

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

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 understanding of single and multiphase flow behavior in porous media has been improved with the development of in situ saturation measurement techniques such as X-ray Computed Tomography (CT), mainly in specialized core analysis. On the other hand, effective experimental designs are necessary to advance knowledge on operations of Water Alternating Gas (WAG) and Carbon Capture and Storage (CCS) projects. The present study addresses the determination of petrophysical properties concerning fluid storage and displacement in carbonates by using CT images taken during core flooding runs. Eight displacement experiments were carried out in long core to analyze N2 and CO2 flooding under reservoir conditions (from 700 to 7000 psi) at temperatures of 22°C and 65°C. A carbonate core sample of 5 cm diameter by 76 cm long with porosity of 15% from a carbonate outcrop analogous to Brazilian pre-salt reservoir rocks was used in the displacement tests. The mixing of CO2 and brine was a key experimental procedure to evaluate the CO2 trapping. The parameters of porosity, permeability, distribution of initial non-wetting phase, irreducible brine saturation, trapped non-wetting phase saturation, displacement effectiveness and the effect of saturation history were investigated during drainage-imbibition cycles similar to those in the WAG process. Values for Land trapping coefficients were evaluated from on-line X-ray CT scan images. The trapped non-wetting phase saturation ranged from 8 to 16 percent for both N2 and CO2 floods. The results reveal that trapped saturations are higher for higher pressures and higher temperatures. Cross-section images show the enlargement of pore spaces induced by brine-CO2 flooding with a consequent increase of the trapping capacity. Porosity and permeability changed after a CO2 injection, along with the observed formation of short wormholes. In addition, some degree of dissolution of the rock was verified and solid particles of carbonate salts were collected at the outlet of CO2-brine runs. The results obtained emphasize the importance of using high-resolution saturation imaging to provide the main parameters for the experimental evaluation of CO2-WAG processes in carbonates. Introduction Carbon dioxide (CO2) flooding has been considered as one of the most important processes for enhancing oil recovery (EOR) from carbonate reservoirs since the 1980's [1]. Its use, though, is most of the time limited by the availability of an economic source. In the Brazilian pre-salt reservoirs, e.g., Tupi field, the solution gas contains a high proportion of CO2 [2]. The re-injection of the produced CO2 in this case represents the solution of two problems at once. It solves the discard problem, which is of growing environmental concern, at the same time it provides the resource for improving the difficult oil recovery. Both EOR and environmental processes demand new studies covering the application of WAG injection and the safety of geological storage of CO2. The alternating injection of water and gas was conceived in order to compensate the counter tendencies of gas rising upward and water falling downward within the reservoir by ‘breaking-up’ the continuous slug of gas into smaller slugs by alternating water banks [3]. On the other hand, injecting water with miscible gas reduces the instability of the gas/oil displacement, improving the overall sweep efficiency.

Best Practice for Transitioning from Carbon Dioxide (CO2) Enhanced Oil Recovery EOR to CO2 Storage

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