Recovery Factors in High-Pressure Air Injection Projects Revisited
- Dubert Gutierrez (Computer Modelling Group Ltd.) | Archie R. Taylor (Continental Resources Inc.) | Vinodh Kumar (Hilcorp Energy Company) | Matthew G. Ursenbach (U. of Calgary) | Robert G. Moore (U. of Calgary) | Sudarshan A. Mehta (U. of Calgary)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- December 2008
- Document Type
- Journal Paper
- 1,097 - 1,106
- 2008. Society of Petroleum Engineers
- 5.5.8 History Matching, 5.6.2 Core Analysis, 5.5.2 Core Analysis, 5.3.4 Reduction of Residual Oil Saturation, 5.4.2 Gas Injection Methods, 5.5 Reservoir Simulation, 5.4 Enhanced Recovery, 5.1.1 Exploration, Development, Structural Geology, 5.2 Reservoir Fluid Dynamics, 5.4.1 Waterflooding, 4.1.4 Gas Processing, 5.1.2 Faults and Fracture Characterisation, 5.2.1 Phase Behavior and PVT Measurements, 1.6 Drilling Operations, 4.3.4 Scale, 5.7.2 Recovery Factors, 4.5 Offshore Facilities and Subsea Systems, 1.6.9 Coring, Fishing
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High-pressure air injection (HPAI) is an improved-oil-recovery (IOR) process in which compressed air is injected into a deep light-oil reservoir with the expectation that the oxygen in the injected air will react with a fraction of the reservoir oil at an elevated temperature to produce carbon dioxide. The resulting flue-gas mixture provides the main mobilizing force to the oil downstream of the reaction region, sweeping it to production wells. The combustion zone itself may provide a critical part of the sweep mechanism.
In 1994, Fassihi et al. proposed a method for estimating recovery factors of light-oil air-injection projects on the basis of the performance of two successful HPAI projects. Their suggested method relies on the extrapolation of the field gas/oil ratio (GOR) up to an economic limit. In other words, it treats HPAI as an immiscible gasflood and neglects any potential oil that could be recovered by the combustion front. The truth is that, although early production during an HPAI process is caused mostly by repressurization and gasflood effects, once a pore volume of air has been injected, the combustion front becomes the main driving mechanism. Moreover, one of the unique features of air injection is the self-correcting nature of the combustion zone, which promotes good volumetric sweep of the reservoir.
This paper presents laboratory and field evidence of the presence of a thermal front during HPAI operations and evidence of its beneficial impact on oil recovery. An analysis of the three HPAI projects in Buffalo field, which are the oldest HPAI projects currently in operation, shows that only a small fraction of the reservoir has been burned and, if time allows and the projects are managed appropriately, burning of more reservoir volumes could result in much higher oil recoveries than those predicted by the gasflood approach.
HPAI is an emerging technology for the recovery of light oils that has proved to be a valuable IOR process, especially in deep thin low-permeability reservoirs (Erickson et al. 1994; Kumar and Fassihi 1995; Kumar et al. 2007a, 2007b; Fassihi et al. 1996, 1997).
The first extended field test of HPAI began in 1963 on the Sloss field in Nebraska (Parrish et al. 1974a, 1974b), where Amoco's Combination of Forward Combustion and Waterflooding (COFCAW) process was applied as a tertiary-recovery process to a deep (6,200 ft), thin (11 ft), light-oil (38.8°API), watered-out reservoir. This COFCAW pilot recovered 83,992 bbl of oil, which is equivalent to 43% of the oil remaining in the five-spot pattern after waterflood. In 1967, the pilot was expanded from an 80- to a 960-acre project and recovered 527,000 bbl of incremental oil. However, it proved to be uneconomical, with crude-oil prices at less than USD 3/bbl.
The second application of HPAI was the West Heidelberg pressure-maintenance project (Huffman et al. 1983) in the US state of Mississippi, which started in 1971 as a secondary-recovery project in the deep (11,400 ft) Cotton Valley sands. Even though oil prices were less than USD 4/bbl during the early period of the air-injection operations, payout of the project occurred at approximately 2.5 years, and the project continued to be a successful air-injection project. One interesting aspect of this project was the simulation work presented by Kumar (1991), which showed that, although the early production was mainly because of pressure maintenance, more than half of the cumulative oil production was mainly a result of thermal effects.
An important milestone in the advance of HPAI was the implementation of commercial secondary HPAI projects in the North and South Dakota portions of the Williston basin, which started in 1979 and continues to be a technical and economic success (Erickson et al. 1994; Kumar and Fassihi 1995; Kumar et al. 2007a, 2007b; Fassihi et al. 1996, 1997).
The estimation of ultimate recovery in HPAI projects is subject to a high level of uncertainty and requires history matching. Nevertheless, in 1994, Kumar and Fassihi (1995) proposed a method for estimating recovery factors of light-oil air-injection projects on the basis of the performance of two HPAI projects. Their suggested method relies on the extrapolation of the field GOR up to an economic limit. In other words, it considers HPAI as an immiscible gasflood.
This paper intends to challenge that "gasflood" approach with a "combustion" approach, on the basis of laboratory results and field data gathered mostly from the Buffalo field, which comprises the three oldest HPAI projects currently in operation.
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