CO2 Enhanced Oil Recovery Project Research Articles

Modeling of CO2 solubility in crude oil during carbon dioxide enhanced oil recovery using gene expression programming

CO2 flooding into the petroleum reservoirs has gained much universal attentions owing to the benefits originated from the reduction of greenhouse gas emission and enhanced oil recovery (EOR). Among the all parameters applied for determining the feasibility of a particular CO2 EOR project especially in the miscible mode, solubility of CO2 has a vital function in the design and simulation of the CO2 injection. CO2 solubility has a prominent contribution to reduction of oil viscosity, IFT reduction, and a rise in swelling of crude oil which leads to the oil mobility increases, and improvement in oil recovery. In the present study, gene expression programming (GEP) as a recently developed and powerful soft-computing technique was utilized for establishing new symbolic CO2 solubility correlations in both dead and live oil systems. Moreover, the prediction capability of the artificial neural network (ANN) was also examined. For this reason, a database of wide-ranging operational conditions was undertaken from the open literature. The parameters involved in both ANN and GEP-based schemes are temperature, saturation pressure, oil molecular weight, and oil specific gravity in dead oil model. In addition to these parameters, the impact of bubble point pressure has been introduced in live oil system. At the next step, these datasets were separated into the two subsets of training group to construct the model and testing group to check the model capability. For assessing the efficiency of the suggested tool, several statistical calculations and graphical illustrations were utilized. Extensive error analysis applied for the newly suggested GEP-based correlations represents satisfactory agreement with highly accurate results of AARD=0.0378, and R2=0.9860 in dead oil, and AARD=0.0376, and R2=0.9844 in live oil. In accordance to the results of this study, the best performance of the extended GEP-based tool in this study was demonstrated compared to the studied literature correlations. The results of trend analysis prove that the proposed model has the best match with the measured datapoints as compared with previously published correlations in both dead and live oil systems. The developed ANN model gives slightly better results than GEP-based correlation in live oil; however, in dead oil the GEP-based strategy is more accurate than the ANN technique. At last, it is found out the GEP-based model can serve as reliable and robust method for rapid and efficient estimation of CO2 solubility in dead and live oil systems.

Experimental and Numerical Studies of CO2 EOR in Unconventional Reservoirs

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 179634, “Experimental and Numerical Studies of CO2 EOR in Unconventional Liquid Reservoirs With Complex Fracture Networks,” by Jianlei Sun, SPE, Amy Zou, and David Schechter, SPE, Texas A&M University, prepared for the 2016 SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. The paper has not been peer reviewed. This study investigates oil-production mechanisms from the matrix into the fracture by simulating two laboratory experiments as well as several field-scale studies and evaluates the potential of using carbon dioxide (CO2) huff ’n’ puff to enhance oil recovery in unconventional liquid reservoirs (ULRs) with nanodarcy-range matrix permeability and complex natural-fracture networks. This study explores the mechanisms contributing to oil recovery with numerical modeling of experimental work and investigates the effects of various parameters on oil recovery. Introduction CO2 injection has been recognized as one of the more important and successfully applied enhanced-oil-recovery (EOR) processes in the US since the start of the first commercial CO2-injection project in 1972. Statistics show that, out of the 153 active CO2 EOR projects worldwide, 139 of them are in the US. CO2 flooding is the only EOR method in the US that has been consistent and economical since the drop in oil prices in the 1980s. One of the main advantages of CO2 injection is that CO2 can achieve miscibility with the resident hydrocarbon when minimum miscibility pressure (MMP) is attained. Although CO2 flooding has demonstrated the potential of increasing oil production in conventional reservoirs, if this EOR process were to be applied to ULRs, the oil-recovery mechanism could not be considered the same as that during a conventional CO2 flooding because of the differences in reservoir petrophysical properties, fluid-phase behavior, and the fundamental mass-transfer mechanisms. In general, diffusion during gas injection has been recognized as a critical mechanism that affects the oil recovery in fractured reservoirs. If the diffusive flow in the matrix is being neglected during simulation, the calculated result will underestimate productivity. Furthermore, complex fracture geometry has been proposed for hydraulic fracturing because of the intersection between hydraulic fractures and in-situ natural fractures. Numerous simulation and experimental studies have evaluated production performance of complex fracture networks. However, there is no extensive work regarding the potential of CO2 huff ’n’ puff in complex fracture geometries.

Considering economic and geological uncertainty in the simulation of realistic investment decisions for CO2-EOR projects in the North Sea

The use of anthropogenic CO2 for enhancing oil recovery from mature oil fields in the North Sea has several potential benefits, and a number of assessments have been conducted. It remains, however, difficult to realistically simulate the economic circumstances and decisions, while including the economic uncertainties that surround the relevant markets and policies, and the geological and technological uncertainties that are inherent to dealing with reservoirs and novel technologies in a challenging environment. A new method is proposed here introducing a unique combination of innovations, that include true limited foresight, project flexibility, and the consideration of realistic investment risk. The value of project is here expressed as the Net Present Value (NPV). These elements are combined in the PSS IV simulator. This is a techno-economic simulator for CO2-enhanced oil recovery (CO2-EOR), which applies limited foresight and Real Options Analysis to make realistic investment decisions on projects with significant uncertainties and thus risk. Consecutive project decisions are taken based on a decision tree. Multiple oil fields can be approached as a single cluster project, which can provide a lower investment hurdle. In a first test case for PSS IV, the Claymore and Scott oil fields are assessed, and it is shown that economic simulations where EOR projects are regarded as a sum of the individual field assessments will undervalue projects. Simulation results show that results are in a realistic range compared to published numbers, with individual project values for the Claymore field on average of 15.8€/barrel (bbl; standard deviation SD=8.3) and for the Scott field of 14.3€/bbl (SD=8.6). Due to the inclusion of uncertainties and the application of limited foresight, results range from −6€/bbl (loss) to over 30€/bbl. In a cluster configuration 5€/bbl of additional value is created.

A multilevel U-tube sampler for subsurface environmental monitoring

Sampling fluid in boreholes is always challenging from the standpoints of maintaining integrity and minimizing contamination. This paper focused on the U-tube sampling technology. Firstly, according to initial development motivation, briefly comparison was conducted with available fluid sampling technologies based on driving forces and sample quality. Then, the development history of the U-tube sampling technology was introduced, as well as a comprehensive investigation of its site applications around the world. In particular, a novel multilevel U-tube sampler was designed in China specifically for shallow subsurface, and it had been proven both technically reliable and economically feasible in several carbon capture, utilization, and storage (CCS/CCUS) projects, including the Shengli CO2-enhanced oil recovery (CO2-EOR) project, the Shenhua CCS demonstration project, and the Jilin CO2-EOR project. Finally, the benefits, drawbacks, and future developments of U-tube sampling technology were pointed out as a conclusion. The U-tube sampler used in shallow subsurface is quite suitable in dedicated monitoring projects which specifically require three-dimensional tracing and accurate fluid analysis in a long term.

Visualization of CO2 EOR by Molecular Diffusion in Fractured Chalk

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170920, “Visualization of CO2 EOR by Diffusion in Fractured Chalk,” by øyvind Eide, SPE, Martin A. Fernø, SPE, and Arne Graue, SPE, University of Bergen, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed. This work demonstrates that molecular diffusion may be a viable oil-recovery mechanism in fractured reservoirs during injection of carbon dioxide (CO2) for enhanced oil recovery (EOR). The oil-production rate from diffusion alone, however, depends heavily on the distribution of CO2 within the fracture network and fracture spacing. A numerical sensitivity analysis, using a validated numerical model that reproduced the experiments, showed that the rate of oil production during CO2 injection declined exponentially with increasing diffusion lengths from the CO2-filled fracture and the oil-filled matrix. Introduction Compared with other EOR methods based on gas injection, CO2 injection has many beneficial properties, among them that CO2 lowers the gas/oil interfacial tension and reduces oil viscosity and density, resulting in increased oil mobility and oil swelling. The main drawback with injecting gas is the high mobility, a factor especially true in fractured reservoirs. The success of a potential CO2 EOR project increases when key driving forces for oil displacement during a CO2 injection are identified. In a highly fractured reservoir, molecular diffusion could be an important driving mechanism; however, it would require high fracture density. Molecular diffusion is the mixing of fluids caused by random motion of molecules, and its calculation is described in detail in the complete paper. Diffusion is often neglected as a production mechanism during modeling of CO2 injection in oil reservoirs because it is computationally expensive to handle and is assumed to be of minor importance. While this might be true for most conventional reservoirs, it is not true for heavily fractured reservoirs and in laboratory experiments, where the diffusion distances are much smaller. Experimental Setup Fluids. A one-component pure mineral oil (decane) was used as the oleic phase in the experiment to achieve first-contact- miscible conditions with CO2 at pressures below 10 MPa to eliminate the effect of oil composition and to promote repeatability between tests. Core Material. Outcrop Rørdal chalk from Denmark was used in this study as an analog for North Sea chalk reservoirs. It has a composition of mainly calcite (99%) and some quartz (1%) and consists mainly of coccolith deposits. The Rørdal chalk is a homogeneous chalk type with similar porosity and permeability values between sister core plugs. Core Preparation. A smooth-walled, artificial, longitudinal fracture was cut in Core Plug C1 using a band saw. A constant fracture aperture of 1 mm was maintained by use of a polyoxymethylene (POM) spacer. The spacer consisted of three large void compartments separated by support columns, and flow between each void was through grooves to allow for fluid transport. The permeability of the fracture was several orders of magnitude higher than that of the matrix. Experimental Setup. The scanner was a fourth-generation medical computed-tomography (CT) scanner with a scanning time of 3 minutes and a pixel resolution of 160×160 Μm and a slice thickness of 500 Μm. The core was first scanned to localize its position and to ensure a vertical fracture plane. The core was then vacuum evacuated before a 100% dry image was measured. A 100%- CO2 image was obtained after the core was fully saturated with CO2. The system was then depressurized, vacuum evacuated, and fully saturated with oil before the oil calibration scan was obtained. All 100%-saturation scans were performed at experimental pressure and temperature (10.7 MPa and 42°C, respectively). The mineral oil decane was used in all tests. The test conditions used ensured supercritical CO2 conditions and first-contact miscibility between CO2 and decane. The confinement pressure was kept 1 MPa above the line pressure.

Improvement of Environmental Monitoring Technology on the basis of Carbon Mass Balance during CO2-enhanced Oil Recovery and Storage

Abstract This study reviewed the emission inventory of carbon injection, production, storage, and emission. Results indicated that only approximately 95% of injected CO2 can be measured. Approximately 92% to 95% of carbon was stored, 0.01% was leaked from soil, and the residual 5% may have come from leak paths or may have leaked from near-surface sources, such as underground water, through biological metabolism. To develop a carbon mass balance model for CO2 enhanced oil recovery projects, the emission part from soil and underground water, as well as the fixation by vegetation, should be carefully measured. The residual 5% that remains unmeasured should be proven, i.e., whether such amount is derived along leak paths or is emitted from near-surface sources. Findings could highlight the fate of carbon, provide some suggestions to guide the selection of environmental monitoring technology, and aid in establishing a common methodology to identify leak risks for carbon storage projects.

Reservoir Engineering Aspects of Pilot Scale CO2 EOR Project in Upper Mississippian Formation at Wellington Field in Southern Kansas

A DOE sponsored pilot-scale project has been funded in which 30,000 metric tons of CO2 will be injected in the upper part of the Mississippian reservoir to verify CO2 Enhanced Oil Recovery (EOR) potential at Wellington field in South Kansas. Many conventional Mississippian oilfields in Kansas are going through final stages of water flooding and are at CO2 miscible or near miscible conditions. Wellington Field represents a typical Kansas Mississippian reservoir with very well documented production/injection history and proven performance and, therefore, it is ideal candidate for CO2 EOR. The main objective of this work is to evaluate reservoir properties, predict reservoir response, and evaluate possible risks for CO2 EOR in the Mississippian reservoir at Wellington Field.

Integrated CCS Aspect into CO2 EOR Project Under Wide Range of Reservoir Properties and Operating Conditions

Carbon Capture and Storage (CCS) aspects can be combined with enhanced oil recovery (EOR) aspects for environmental responsibility and project economics. Oil Field in Pattani Basin, Gulf of Thailand is one candidate for this process integration. However, because of unique field characteristics like the number of reservo irs, and lack of data on fluid composition, and rock properties, full detailed reservoir simulations are hard to accomplish. Hence, this study proposes the use of numerical s imulations with generalized field parameters to briefly quantify the potential for integrating CCS and EOR in Pattani Bas in oil reservo irs. GEM composition reservo ir simulator was used for comparison of six operating conditions: 1) Natural Production, 2) Waterflooding, 3) Gasflooding, 4) S ingle Cycling Water Alternated Gas (WAG), 5) Double Cycling WAG, and 6) Simultaneous Water Alternated Gas (SWAG).Two levels fractional factorial experimental design techniques were applied to reduce the number of required simulation runs. Central composite design was utilized additionally if assumptions in the fractional factorial design were vio lated. By using statistical analysis, important input parameters called factors were determined. Regression analyses of important factors to responses of interests (incremental recovery factor, required gas injection volume and gas storability) were used to establish a metamodel.Our results suggest that for general Pattani Basin oil reservo irs the most preferab le technique is SWAG method with CO2 injection because it provides highest recovery factor and gas storage volume. Using a higher CO2 portion in SWAG injection stream can further increase recovery factors. When using natural gas as the injection gas, the most preferab le method in terms of recovery factor is the double cycling WAG method followed by the s ingle cycling WAG method.

Overview of the Bell Creek Combined CO2 Storage and CO2 Enhanced Oil Recovery Project

The Plains CO2 Reduction (PCOR) Partnership, led by the Energy & Environmental Research Center, is working with Denbury Onshore LLC (Denbury) to characterize and monitor a large-scale CO2 enhanced oil recovery (EOR) and CO2 storage project at the Bell Creek oil field located in southeastern Montana, USA. Denbury owns and operates the field and will carry out the commercial EOR project. The PCOR Partnership is applying an integrated approach to site characterization, modeling, predictive simulation, risk assessment, and monitoring to improve understanding of the interrelationship between CO2 storage and EOR in a clastic reservoir.

CO2 Enhanced-Oil-Recovery Project Injects New Life Into Madison Reservoir in Wyoming

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 152862, ’Beaver Creek Madison CO2 Enhanced-Oil-Recovery Project: Case History - Riverton, Wyoming,’ by Charles A. Peterson, SPE, Edward J. Pearson, SPE, and Veronica T. Chodur, SPE, Devon Energy, and Carlos Periera, M3 Petroleum Engineering, prepared for the 2012 SPE Improved Oil Recovery Symposium, Tulsa, 14-18 April. The paper has not been peer reviewed. The Madison reservoir, located in the Beaver Creek field, 14 miles south-southeast of Riverton, Wyoming, (Fig. 1) is found at an average depth of 11,235 ft, making it among the deepest CO2 enhanced-oil-recovery (EOR) projects in the United States. The Beaver Creek Madison project is the most recent CO2 EOR project in Wyoming. With a preproject oil production of 43 million bbl, this flood is projected to increase recovery by 11.1 million bbl, or 10% of the estimated 109 million bbl of original oil in place. Early CO2-flood response has been increased production from a preflood rate of 280 BOPD to the current rate of 5,100 BOPD. Introduction The Beaver Creek field produces from 12 different formations, ranging from the shallow Lower Tertiary Ft. Union formation at 1,150 ft to the Mississippian Madison formation at depths down to 11,664-ft true vertical depth. To date, the field has produced in excess of 80 million bbl of oil and 800 Bcf of gas. The Madison reservoir itself produced 44.6 million bbl of oil up through the beginning of the EOR flood. The Madison project, designed as a combination peripheral and gravity-stable CO2 EOR project, began construction in 2007, with initial CO2 injection in July 2008. Since then, production increased from 280 BOPD to more than 5,100 BOPD as of January 2012 and recovered an incremental oil volume in excess of 2.6 million bbl through the end of 2011. Field History and Madison Development The Beaver Creek field was discovered in June 1938 with the drilling of the Standolind (Amoco) Beaver Creek Unit (BCU) 1. The well is still active today, having produced more than 38 Bcf and still flowing at 176 Mcf/D. In January 1954, the Madison reservoir was discovered with the drilling of Standolind’s BCU 30 to a depth of 11,447 ft. The Madison oil-production rate peaked at 8,797 BOPD in November 1962 (Fig. 2). Production remained fairly stable until 1966, when the reservoir’s oil rate began declining while water production increased. Production eventually stabilized in 1999 and remained at approximately 280 BOPD until the beginning of the CO2-flood project. Through this period, the reservoir produced a total of 44.6 million bbl of oil, 12.8 Bcf of gas, and 282.5 million bbl of water.

Uncertainty Management in a Major CO2 EOR Project

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137998, ’Uncertainty Management in a Major CO2 EOR Project,’ by P.M. O'Dell, SPE, and Kirby C. Lindsey, SPE, Occidental Oil and Gas, prepared for the 2010 Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, UAE, 1-4 November. The paper has not been peer reviewed. Occidental operates a large turbidite-sandstone reservoir in California that has progressed through primary depletion, limited gasflooding, and extensive waterflooding. Although a CO2-injection project could increase oil reserves significantly and extend productive field life, the project has significant technical and economic challenges. Subsurface uncertainties were evaluated, including the use of a two-stage design-of-experiments approach to choose optimal operator choices, regardless of subsurface uncertainties. Probabilistic production forecasts were prepared for project valuation. Reservoir Model A new geological model was assembled for this enhanced-oil-recovery (EOR) study. There are 14 correlated sands in the reservoir with limited vertical communication between them resulting from on-lapping of the sands and thinning of the intersand shales. Reservoir structure, a pay flag, pay porosity, and clay content were obtained from well-log data. A porosity/permeability transform that is based on significant core data and considers clay content are used to populate properties in the model. Fluid modeling was based on extensive conventional and CO2 laboratory work conducted on a reservoir-oil sample collected in 2000. This sample was not an original-fluid sample, and to account for reservoir and historical variations, different reservoir-fluid compositions were created by varying the molar ratio of oil vs. solution gas in the sample. Simulated CO2-flood performances under the different compositions created in this manner were nearly indistinguishable from one another except for a small change in gas/oil ratio (GOR). Relative permeabilities were modeled with Corey curves that were constructed on the basis of laboratory data. Because history matching had been performed on an earlier model, no history matching was performed here and the model was initialized at or slightly above residual-oil saturation to water (assuming fairly complete waterflood sweep in the subject sands). Most of the existing wells are serviceable and will be used in any future development. The existing well stock and configuration are amenable to 18-acre five-spot patterns. Hypothetical full-interval-completion wells were used in the study rather than actual wells. Bottomhole injection-pressure and -temperature data were calculated on the basis of tubinghead pressure and temperature and variation of CO2 properties through the wellbore. Lift curves were generated with wellbore-modeling software and use of ranges of possible variations in water cut, producing GOR, tubinghead pressure, tubing sizes, oil-production rate, and nominal depth. Because the contemplated project will be a pressure-maintenance project, the composition of the reservoir fluid was assumed to be fixed for the purpose of calculating lift curves. Therefore, any change in the producing GOR would be the result of CO2 breakthrough. Output of the wellbore-modeling software had to be stitched together to account for the compositional change in the fluids being lifted.

CO2 Applications - Discussion and Reply

Discussion and Reply Editor's note: Several readers responded to the Technology Focus article on CO2 Applications written by Sam Gomersall, director of CO2DeepStore, that appeared in the July issue. Excerpts from some of those letters, along with a reply from the author, follow. Discussion Ronald T. Evans, SPE, Denbury Resources, writes: In the Technology Focus article on CO2 Applications (July 2009 JPT, p. 68) the ultimate conclusion that "Enhanced oil recovery (EOR) … is not a CO2-abatement technique" fails to assess CO2 EOR accurately. CO2 EOR projects that use anthropogenic CO2 have the ability to sequester more CO2 than the oil produced will ultimately release. According to the US Department of Energy's National Energy Technology Laboratory (NETL), CO2-EOR projects sequester up to 70% of the CO2 that will ultimately be released by the oil. This report is based on west Texas, water-alternating-gas CO2 EOR projects that inject 5 to 6 Mcf of CO2 for each barrel of oil produced. The report discusses "Next-Generation CO2-EOR Technologies" that have the capacity to inject as much as 160% of the CO2 ultimately released by the oil. Continuous-injection CO2-EOR projects inject 10 to 12 Mcf of CO2 to produce each barrel of oil. Continuous-injection CO2-EOR projects have the capacity to sequester significantly greater CO2 volumes than the oil releases when consumed. Not only does CO2 EOR with anthropogenic CO2 have an important role to play in energy security, it is a significant CO2-abatement technique. It is the only carbon-capture/sequestration (CCS) method that can be conducted today, and it is the only CCS method that produces additional domestic energy and economic benefits while sequestering CO2. For additional reading material, please see: CO2 Enhanced Oil Recovery. World Resources Institute, www.wri.org/publication/content/8355. Tapping into Stranded Domestic Oil: Enhanced Oil Recovery with Carbon Dioxide is a Win-Win-Win. Natural Resources Defense Council, www.nrdc.org/energy/eor.pdf. Storing CO2 with CO2 enhanced oil recovery. US National Energy Technology Laboratory, www.netl.doe.gov/energy-analyses/pubs/Storing%20 CO2%20w%20EOR_FINAL.pdf.

Using Spoolable Composite Pipe in a Large CO2 Enhanced Oil Recovery Project to Reduce Flowline Installation and Lifecycle Costs

Abstract Historically, steel pipe has been the primary material used in oil and gas production gathering applications. More than 25 years ago, glass fiber-reinforced epoxy (ORE) pipe was introduced to the oil and gas industry, and this material has been used in applications where internal or external corrosion was causing high failure rates and maintenance costs in steel pipelines. ORE pipe (commonly called stick fiberglass) is produced in joints typically just over 9 m (30 ft) in length, which are mechanically joined together during installation. Overall construction costs for steel and ORE pipe are similar. In both steel and ORE, the underlying pipe and construction technologies are mature, and thus it is difficult to reduce total installed costs beyond small increments. More recently, spoolable composite pipe has become a widely accepted alternative to these materials demonstrating lower capital and operating costs for infield gathering and injection applications, as well as improved pipe integrity and field performance. This paper describes a major operator's experience using Fiberspar ® spoolable composite pipe in place of steel and stick fiberglass in one of Canada's most highly visible CO2 enhanced oil recovery (EOR) projects. Fiberspar LinePipe ™ enabled this operator to reduce flowline costs while eliminating corrosion related failures and problems with joint integrity in this hostile producing environment. This paper summarizes actual field experience showing how LinePipe can substantially reduce costs and improve pipe integrity over the producing life of a field. Weyburn Project Overview The Weyburn Oil Field is operated by EnCana and lies on the northwestern rim of the Williston Basin. It is 16 km (10 mi) southeast of Weyburn in southern Saskatchewan. Production began in 1954, and currently there are approximately 990 production and water injection wells in operation. The average daily crude oil production is 2,900 m3/d (c. 18,200 bbl/d). Over its lifetime, the field has produced roughly 55 million m3 (c. 346 million bbl) of oil from primary and waterflood production. The field is currently in production decline, having produced approximately 25% of the estimated recoverable oil reserves. EnCana announced in 1997 that it would develop an EOR project to extend the life of the Weyburn Field by more than 25 years. The project involves a CO2 miscible flood, which is expected to extract an additional 19 million m3 (122 million bbl) or more of oil from the field. Waterflood injection is used to increase reservoir pressure, while pushing oil to producing wells to improve recovery. A miscible flood is an enhanced oil recovery technique where a fluid (CO2) is injected into the reservoir to expand and sweep the oil to the producing wells, increasing recovery rates beyond waterflooding. The Weyburn project is highly significant for three reasons:Apart from giving new life to an old field, the use of CO2 as a miscible flood agent makes Weyburn Canada's largest greenhouse gas sequestration project. For this reason, the Weyburn project is the site of a world-scale research initiative operated under the auspices of the International Energy Agency, which is studying the sequestering of CO2 in an oil reservoir.

CO2Eor and Storage in Oil Reservoir

CO2 injection into tertiary oil reservoirs has been widely accepted as an effective technique for enhanced oil recovery (EOR), and has been used by the oil industry for over 40 years. Concerns over greenhouse gas emissions are leading to the investigation and realisation of its potential as a carbon storage method in recent years. With the right reservoir conditions, injection of CO2 into oil reservoirs can result in incremental oil recovery and permanent storage of CO2 in geological formation. The majority of previous and current CO2 EOR projects use low cost CO2 sources and have good economic returns in terms of high gas utilisation efficiencies (167-227 sm3 CO2/STB oil). The potential of CO2 storage combining EOR is high; approximately 60% injected CO2 can be retained in the reservoir at the CO2 breakthrough if reinjection is not considered. It has been accepted that there is little major technical challenges for CO2 EOR projects, but there are economic constrictions if high cost anthropogenic CO2 (such as from power plant) is used for EOR and storage operations. In this chapter, a general review is given on the CO2 EOR and storage potentials, field screening and economic analysis. A case study for CO2 EOR application in a North Sea field is also presented.

Multicomponent vapor-liquid equilibria measurements for the development of an extractive distillation process for the processing of gas issuing from a CO2 enhanced oil recovery project

This paper provides vapor-liquid equilibria data for the design of the upper section of the all-important column treating the stabilized feed gas from CO/sub 2/ enhanced oil recovery (EOR) projects. Again, the extractive agent is represented by n-pentane. The simulated feed gas containing the methane, liquified petroleum gas (LPG) components, and H/sub 2/S is added to n-pentane to form quasi-binary mixtures. A comparison of the K values obtained by the addition of methane to an otherwise similar methane-free gas shows that the effect of methane on the K values of the other constituents becomes increasingly pronounced as the pressure increases.

CO2 Flood Performance Evaluation for the Cornell Unit, Wasson San Andres Field

Summary A numerical reservoir simulator has been used to predict CO2 enhanced oil recovery (EOR) performance for two process designs, either of which could be implemented at the Cornell Unit, Wasson San Andres field. The two CO2 displacement processes examined are a straight CO2 slug followed by continuous water injection, and a water-alternating-gas (WAG) process with CO2, followed by continuous water injection. Predicted recovery performances were found sensitive to viscous, capillary, and gravity-driven crossflow, as well as to reservoir stratification. Hence, evaluation of alternative process designs was influenced strongly by assumed values of effective vertical permeability within continuous pay intervals, even though the vertical permeability between major pay intervals is effectively zero. Work involving a no-crossflow stratification model of the Wasson pay suggested that a straight CO2 slug process would be preferable to a WAG process. On the other hand, work with a stratification model that allowed intrazone crossflow indicated that recovery could be improved significantly for a given size CO2 slug by means of a WAG process. Introduction Cornell Oil Co. and Markland Oil Corp. operate the Cornell Unit in the Wasson San Andres field, Yoakum County, TX. This 1,923-acre (7.7 x10 M) unit originally contained about 185 million STB (29.4 x 10 stock-tank m) oil. The property was unitized for supplemental recovery, and water injection began in mid-1965. Cumulative oil production before water injection was 18 million STB (2.9 x 10-6 stock-tank m3). As of Jan. 1982, secondary production was an additional 34 million STB (5.4X 10-6 stock-tank m3). A recent infill drilling program has treated a 35-acre (141 640-M) five-spot well configuration over the entire unit in preparation for a CO2 EOR project. This paper describes a numerical simulation study of alternative operating policies for CO2 injection in the Cornell Unit. CO2 Flood Simulator A CO2 flood simulator, using a finite-difference-based compositional model, was used in this study. The simulator was designed to reproduce the effects of major mass-transfer and phase-transport phenomena associated with CO2 EOR. For immiscible conditions, phase equilibria may be input to the simulator to represent EOR mechanisms of oil- phase swelling with condensed CO2 and vaporization (or extraction) of hydrocarbon fractions into the CO2-rich phase. Multiple-contact miscible (MCM) displacement may be represented explicitly with the program by incorporating appropriate phase equilibrium data. However, the philosophy of the modeling technique used in the program is to maintain segregated CO2- and oil-rich regions. By controlling the degree of segregation of these regions through the mixing parameter approach, we may represent the important phenomenon of viscous fingering, characteristic of highly unfavorable mobility ratio displacements, without describing the detailed structure of the unstable frontal advance. Local miscibility is determined by comparing computed pressure with miscibility pressure input to the program as a function of composition. This modeling technique represents miscible displacement and miscible/immiscible transition without describing the detailed compositional path required for explicitly representing MCM displacement. JPT P. 2271^