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CO2 miscible flooding case studies

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Carbon dioxide (CO2) flooding is a process whereby carbon dioxide is injected into an oil reservoir in order to increase output when extracting oil. There have been more CO2 projects than any other type of miscible flood.

The three examples reviewed below are considered typical of such applications:

SACROC four-pattern flood

This project has been completed. It was thoroughly waterflooded before starting miscible injection. This sequence allows a straightforward evaluation of increased recovery because of miscible displacement.

Fig. 1 shows the oil-production rate for the end of the waterflood and the miscible flood. Actual field data are represented by the solid curve, and the forecast decline curve for a continuing waterflood is shown as the dotted curve. The difference between the actual field rate and the forecast waterflood decline represents increased recovery resulting from the miscible project (shaded area); the amount is given in million stock tank barrels (MMSTB). Additional reservoir performance data, including primary plus secondary (P + S), miscible, and total recovery, are given in the upper-right-hand box as a percent original oil in place (OOIP). These data are given in terms of cumulative recovery to date as well as projected ultimate recovery.

After completing the waterflood in 1981, the CO2 flood was initiated with the same wells and injection patterns. The four-pattern area encompasses 600 acres and 19 MMSTB (3.0 million m3) OOIP. The well pattern is an inverted nine-spot with 40-acre well spacing. Shortly after starting CO2 injection, there was an increase in oil-production rate. The enhanced oil recovery (EOR) of 1.7 MMSTB (0.3 million m3) is equivalent to 9% OOIP, which, when added to primary plus secondary recovery (57% OOIP), gives a total recovery of 66% OOIP. Net CO2 use was 3.2 Mscf/STB of increased recovery (570 std m3/m3).

This project demonstrated that incremental oil can be recovered by a miscible flood after an efficient waterflood. In this case, water injectivity after CO2 injection was higher than during the waterflood, thus enabling oil to be recovered more quickly.

Fig. 2 illustrates the comparison of actual miscible flood performance to that predicted with a four-component compositional simulator. The Todd-Longstaff mixing model[11] was used to account for viscous fingering, and phase behavior was represented by a pseudoternary diagram. Two major empirically based physical parameters, Sorm and a viscous-fingering parameter, were used to model local displacement and sweep efficiencies. Sorm was based on laboratory displacement tests using representative samples of reservoir rock and fluids. The first step in simulation was to history match the waterflood. This enabled fine-tuning of the reservoir description model. The compositional simulator was then used to calculate performance of the miscible flood without further adjustment to any match parameters.

As shown in Fig. 2, the simulation of cumulative oil recovery vs. cumulative injection for the miscible flood agrees reasonably well with actual field results. The produced water/oil ratio from the simulation is also in reasonable agreement with field results. Waterflood sweep efficiency was 74%, and the miscible flood sweep efficiency was 44%. These sweep efficiencies were determined from analysis of the simulation studies.

Means San Andres Unit

This field, located in the eastern edge of the Central Basin Platform of the Permian Basin, produces primarily from the Permian-aged San Andres formation. It was discovered in 1934; waterflooding began in 1963. The field was developed initially on 40-acre spacing and subsequently drilled to 20-acre spacing after the start of waterflooding. The flooding pattern was first peripheral, then a three-to-one line drive, and finally an inverted nine-spot that proved most efficient for this reservoir.

Reservoir characteristics are

  • Porosity of 9%
  • Permeability of 20 md
  • Swi of 35%
  • Tr of 95°F
  • Net-to-gross ratio of 0.18
  • Oil gravity of 29°API
  • μoi of 6 cp.

An oil viscosity of 6 cp makes the waterflood mobility ratio relatively high. From pressure cores and laboratory corefloods, waterflood residual oil saturation was estimated to be 34% of pore volume. A CO2 miscible project was evaluated with laboratory investigations, field pilots, and reservoir simulations. The pilot tests indicated that CO2 could successfully mobilize the waterflood residual oil. Even though it is difficult to determine the governing mechanisms for improved oil recovery, it appears that after the initial direct displacement of oil by the solvent bank, lighter components of the remaining oil are recovered by extraction.

The original CO2 project of 167 patterns on approximately 6,700 acres (which contained 82% of OOIP) was expanded to 7,830 acres as evaluation of performance indicated additional prospective areas. Factors affecting process design were:

  • Oil viscosity of 6 cp
  • High minimum miscibility pressure (MMP)
  • Low formation parting pressure that make operating pressure a critical factor.

On the basis of the MMP estimation of 1,850 to 2,300 psi by slimtube experiments and the formation parting pressure of approximately 2,800 psi, a 2,000-psi operating pressure was selected.

Assessment of the economic viability of CO2 miscible flooding was based on pattern-element simulations for representative project areas that were then used in a scaleup program to forecast total project incremental recovery. A 2:1 water-alternating-gas (WAG) ratio and primary CO2 slug size of 0.40 hydrocarbon pore volume (HCPV) were selected as optimum. Updated simulations after gaining operating experience indicated that a CO2 slug size of 0.60 HCPV was better.

Results of the infill-drilling program and CO2 flood combined for a total unit oil production increase from approximately 8,500 B/D in 1983 to approximately 16,000 B/D in 1987, as illustrated in 'Fig. 3. Much effort has been made to distinguish between the contributions of infill drilling, improved waterflooding, and miscible displacement.

Originally incremental oil recovery resulting from infill drilling was projected to be 5.3% OOIP, while the incremental recovery resulting from CO2 flooding was to be 7.1% OOIP. These recovery estimates have increased over time as a result of an effective reservoir management program. Current estimates of recovery resulting from primary and waterflooding methods exceed 30% of OOIP, and incremental recovery resulting from the miscible CO2 flood is more than 15% of the OOIP.

Utilization of new infill wells for injectors helped minimize downhole mechanical problems. A continuous injection-well profiling program is maintained for flood-management purposes. Increasing the WAG frequency minimized gas breakthrough between some WAG injectors and offsetting producers experiencing rapid gas breakthrough. While a detailed history-matching simulation of the test did not indicate solvent channeling through known, high-permeability leached layers to be a problem, all other indicators suggested otherwise. Dealing with leached pathways continues to be a challenge. History matching also indicated some loss of CO2 into the basal water zone.

Several production enhancements have improved field and miscible project performance. First, a 360-acre, nine-pattern pilot was implemented in the North Dome to evaluate the Lower San Andres (LSA) potential. Results showed that additional reserves could be captured from this deeper horizon, although produced-water volumes exceeded initial projections and limited near-term LSA development because of facility constraints. Once water-handling issues were addressed, 59 additional wells were deepened to the LSA in 1992. Performance of these wells provided more insight into factors affecting reservoir performance and resulted in the deepening of an additional 81 injectors and producers and upgrading of facilities to handle more water and gas.

Several different types of profile modifications were attempted throughout the 1990s. Early foam and polymer treatments were discontinued because of limited, short-term benefits. Preliminary results from a recent conformance program indicate the possibility to mechanically isolate mature intervals and redirect CO2 into oil-bearing intervals that would otherwise remain uncontacted.

The miscible project performance is exceeding previous recovery projections. To better characterize the reservoir and improve business decisions for the asset, a detailed geologic study incorporating engineering and geologic data was used to provide the framework for 3D, three-phase reservoir simulation. Benefits of the study include increasing original oil in place (OOIP) by 40%, identifying the potential in the residual oil zone found below the observed oil/water contact in the LSA, and gaining a better understanding of reservoir continuity using flow units identified with sequence stratigraphy.

Future possibilities for the miscible project include

  • Expanding the CO2-flood project on the basis of the geologic study
  • Continuing the mechanical-isolation program to maximize sweep efficiency
  • Fine tuning other programs such as varying WAG ratios to further optimize flood performance and enhance profitability.

Denver Unit

The Wasson Denver Unit CO2 flood, started in 1983, is one of the larger industry CO2 projects [28,000 acres, 2.1 BSTB (0.33 billion m3) OOIP]. No new wells were drilled initially for this project; however, there was significant reconfiguration of the inverted nine-spot patterns (20-acre well spacing) being used in the waterflood preceding miscible injection. Unit performance is shown in Fig. 4 for the period beginning with the waterflood through the first 19 years of miscible CO2 injection. The reservoir was depressured from 3,200 to 2,200 psi to reduce the amount of trapped CO2. Oil response occurred after approximately 6 to 8 months. Unit oil production rates have been sustained since the start of CO2 injection as a result of response to miscible injection and to the continuing efforts of reservoir management practices that identify more patterns to miscible flood and ways to improve volumetric sweep with well workovers and conversions. The first CO2 production occurred almost simultaneously with incremental oil production.

There are uncertainties in the continued waterflood curve because of the usual difficulties in estimating waterflood decline and additional uncertainties introduced as a result of pattern reconfiguration and other modifications that may have affected future waterflood performance as well as miscible recovery.

Water alternating gas ratio

Different WAG ratios were implemented in different areas of the field to determine the most effective method. In the "Continuous Area," CO2 was injected continuously for approximately 7 years, and then some patterns were converted to 1:1 WAG to reduce CO2 producing rates. Oil rates were sustained after WAG started.

In the "WAG Area," HCPV injection rate was maintained at a level comparable to the Continuous Area. The WAG ratio was approximately 1:1. Incremental production response was poorer than in the Continuous Area, with a maximum of only about 17% of the waterflood oil rate at the start of CO2 injection. In addition, there was about a 30% loss of water injectivity, and injection pressures exceeded fracturing pressure on water cycles. The area was converted to a line drive in 1988.

As a result of the experience described above, a "Hybrid Process" was applied in a final area of the field to capture the early response of continuous injection and the long-term gas management of WAG. In this process, CO2 is injected continuously for 4 to 6 years, followed by 1:1 WAG, until a 60% (or larger) HCPV volume of CO2 is injected. The final phase will be continuous water injection.

The project has performed well overall. There were a few problems in the western part of the field, where the WAG process was used. Water injection at the desired rates was difficult, and solvent was lost to the gas cap in a limited portion of the reservoir. Neither of these was a complete surprise because the operator recognized both as potential problems during the design phase of the project. The slug process used in the eastern part of the field has performed well, and an increase in the CO2 slug size is being considered.

A fully compositional, fieldwide simulation model is being used to match field and individual-well performance. The simulator is then used to identify locations (which may require infill drilling or horizontal wells) for project expansion, which wells to shut in or return to production, where solvent losses are occurring, and needed changes in WAG ratios. Opportunities for infill drilling and pattern conversion were implemented and added several million barrels of recoverable oil.

The original estimated CO2 slug size of 0.4 to 0.6 HCPV has now been increased to 0.72%. The current estimated ultimate EOR is 16.7% OOIP. Continued improvements in reservoir management may improve this outlook.


  1. 1.0 1.1 1.2 Healy, R.N., Holstein, E.D., and Batycky, J.P. 1994. Status of Miscible Flooding Technology. Proc., 14th World Petroleum Congress, Stavanger, 29 May–1 June. 407–416.
  2. Langston, M.V., Hoadley, S.F., and Young, D.N. 1988. Definitive CO2 Flooding Response in the SACROC Unit. Presented at the SPE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 16-21 April 1988. SPE-17321-MS.
  3. Johnston, J.R. 1988. Weeks Island Gravity Stable CO2 Pilot. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, 17–20 April. SPE 17351.
  4. Clark, N.J., Shearin, H.M., Schultz, W.P. et al. 1958. Miscible Drive—Its Theory and Application. J Pet Technol 10 (6): 11–20. SPE-1036-G.
  5. Magruder, J.B., Stiles, L.H., and Yelverton, T.D. 1990. Review of the Means San Andres Unit CO2 Tertiary Project. J Pet Technol 42 (5): 638–644. SPE-17349-PA.
  6. Stiles, L.H. and Magruder, J.B. 1992. Reservoir Management in the Means San Andres Unit. J Pet Technol 44 (4): 469-475. SPE-20751-PA.
  7. Tanner, C.S., Baxley, P.T., Crump III, J.G. et al. 1992. Production Performance of the Wasson Denver Unit CO2 Flood. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 22-24 April 1992. SPE-24156-MS.
  8. Kittridge, M.G. 1993. Quantitative CO2-Flood Monitoring –Denver Unit, Wasson (San Andres) Field. SPE Form Eval 8 (4): 299-305. SPE-24644-PA.
  9. Hsu, C.-F., Morell, J.I., and Falls, A.H. 1997. Field-Scale CO2-Flood Simulations and Their Impact on the Performance of the Wasson Denver Unit. SPE Res Eng 12 (1): 4-11. SPE-29116-PA.
  10. Thai, B.N., Hsu, C.F., Bergersen, B.M. et al. 2000. Denver Unit Infill Drilling and Pattern Reconfiguration Program. Presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 21-23 March 2000. SPE-59548-MS.
  11. Todd, M.R. and Longstaff, W.J. 1972. The Development, Testing, and Application of a Numerical Simulator for Predicting Miscible Flood Performance. J Pet Technol 24 (7): 874–882. SPE-3484-PA.

Noteworthy papers in OnePetro

Harpole, K.J. and Hallenbeck, L.D. 1996. East Vacuum Grayburg San Andres Unit CO2 Flood Ten Year Performance Review: Evolution of a Reservoir Management Strategy and Results of WAG Optimization. Presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, 6-9 October 1996. SPE-36710-MS.

Ring, J.N. and Smith, D.J. 1995. An Overview of the North Ward Estes CO2 Flood. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 22-25 October 1995. SPE-30729-MS.

Brokmeyer, R.J., Borling, D.C., and Pierson, W.T. 1996. Lost Soldier Tensleep CO2 Tertiary Project, Performance Case History; Bairoil, Wyoming. Presented at the Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 27-29 March 1996. SPE-35191-MS.

Flanders, W.A. and DePauw, R.M. 1993. Update Case History: Performance of the Twofreds Tertiary CO2 Project. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1993. SPE-26614-MS.

Bellavance, J.F.R. 1996. Dollarhide Devonian CO2 Flood: Project Performance Review 10 Years Later. Presented at the Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 27-29 March 1996. SPE-35190-MS.

Pittaway, K.R. and Rosato, R.J. 1991. The Ford Geraldine Unit CO2 Flood - Update 1990. SPE Res Eng 6 (4): 410-414. SPE-20118-PA.

Lee, K.H. and El-Saleh, M.M. 1990. A Full-Field Numerical Modeling Study for the Ford Geraldine Unit CO Flood. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 22-25 April 1990. SPE-20227-MS.

Phillips, L.A., McPherson, J.L., and Leibrecht, R.J. 1983. CO2 Flood: Design and Initial Operations, Ford Geraldine (Delaware Sand) Unit. Presented at the SPE Annual Technical Conference and Exhibition, San Francisco, California, 5-8 October 1983. SPE-12197-MS.

Pittaway, K.R. and Runyan, E.E. 1990. The Ford Geraldine Unit CO2 Flood: Operating History. SPE Prod Eng 5 (3): 333-337. SPE-17278-PA.

External links

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See also

Compositional simulation of miscible processes

Miscible flooding

Designing a miscible flood

Waterflood monitoring

Nitrogen miscible flooding case studies

Enriched hydrocarbon miscible flooding case studies