Screening Criteria for Carbon Dioxide Huff 'n' Puff Operations

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 100044, "Screening Criteria for Carbon Dioxide Huff ‘n’ Puff Operations," by L. Mohammed- Singh, SPE, Petrotrin, and A.K. Singhal, SPE, and S. Sim, SPE, Alberta Research Council, prepared for the 2006 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 22-26 April. The full-length paper reviews design and performance data on 16 CO2 huff ‘n’ puff projects in the Forest Reserve oil field of Trinidad and Tobago from the past 20 years. Huff ‘n’ puff operations essentially are near-wellbore stimulation techniques that can lead to increased oil recovery by removal of productivity damage, reduced oil viscosity, increased dissolved-gas content, oil swelling, and vaporization of lighter oil components. Introduction The first huff ‘n’ puff experimental project in Trinidad and Tobago was conducted in 1984 in the Forest Reserve oil field. For the Forest Reserve reservoirs with medium-to-heavy crude oils, viscosity reduction and oil swelling aided by gravity drainage and water encroachment are believed to be the most significant mechanisms contributing to increases in oil recovery. The literature contains many screening criteria for enhanced-oil-recovery processes. However, for CO2 huff ‘n’ puff operations, these are generally included in those for immiscible gas-flooding applications. The full-length paper proposes screening criteria for huff ‘n’ puff operations on the basis of results from the Forest Reserve oil field and other published field tests. Reservoir Description The Forest Reserve oil field contains multiple, stacked, complex deltaic reservoirs. The rock and fluid properties of the four reservoirs (targets for huff ‘n’ puff operations) are listed in Table 1 in the full-length paper. Oil gravity ranges from 14 to 25°API, with in-situ viscosities of 12 to 3,000 cp. Reservoirs are solution-gas drive with contributions from water influx. Operations and Production Response CO2 was compressed to 1,000 psi and injected until desired slug volumes were achieved. Wells were shut in, left to soak for 3 to 5 days, and back flowed. Wells were subjected to several cycles (5 cycles maximum). A total of 2,092 MMcf of CO2 was injected and 101,635 bbl of oil recovered from the 16 wells tested. Responses varied from none to a maximum of 12,000 bbl in one cycle. The production cycle generally lasted more than 6 months and as much as several years in some wells. An average of 6,300 bbl per well was recovered, with one well achieving 31,000 bbl. Some of the wells that showed good responses were in downdip locations and possibly benefited from water influx and gravity drainage during the puff phase. Updip wells that yielded good recoveries also were near faults, which may have helped in providing containment and efficient capture of the mobilized oil. Five wells experienced mechanical difficulties and were excluded from the following analyses.

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