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Operating practices for in-situ combustion
In-situ combustion requires standard field equipment for oil production, but with particular attention to air compression, ignition, well design, completion, and production practices.
Air-compression systems are critical to the success of any in-situ combustion field project. Past failures often can be traced to poor compressor design, faulty maintenance, or operating mistakes. See Compressors for a detailed discussion of compressors and sizing considerations. Other discussions are available in Sarathi.
The factors to be considered when selecting compressors include peak air requirements, injection pressure, capital cost, power requirements, operation and maintenance costs, and other relevant technical and economic parameters specific to the field considered. Compressor terminology varies among manufacturers. It is best to obtain a complete description including compressor, driver, interstage cooling system, and all ancillary equipment, including control and safety systems from each vendor being consulted.
Air compression causes high temperatures because of the large heat capacity (cp/cv ratio). Compressor design must consider these high temperatures to ensure continuous, sustained operations free from the corrosive effects of air and the explosion hazards of some lubricating fluids. Mineral oils are not recommended. Synthetic lubricants withstand the higher temperatures and offer lower volatility and flammability than conventional lubricants.
Ignition and maintenance of high combustion temperatures, especially in heavy oil projects, are the most critical factors of an in-situ combustion project. Shallcross presented a complete review of ignition methods. The following is a summary of this study.
Ignition can occur spontaneously if the oil is reactive, the reservoir temperature is high enough, and the reservoir is reasonably thick. Various models have been proposed to determine the time for spontaneous ignition.
When spontaneous ignition does not occur or is not desired (i.e., in heavy oil reservoirs, where it is important to maintain high combustion temperatures), the most appropriate ignition method depends on the reservoir and the equipment available on site.
Downhole gas-fired burners allow good control of the temperature of injected gases and may be operated at a greater depth than other methods. The disadvantages include the need to run multiple tubing strings in the injection wells. Some particulates such as soot may be carried into the formation if the gas does not burn cleanly.
Catalytic heaters run at lower temperatures but are sometimes prohibitively expensive. Electrical heaters can be lowered with a single cable, can provide excellent temperature control, and can be reused repeatedly. There is, however, a depth limitation because of electrical power losses in the cable.
Chemically enhanced ignition does not have a depth limitation but may require handling and storage of dangerous materials. Fuel packs are not recommended because of poor temperature control and nonuniform ignition across the entire reservoir thickness. Well damage from elevated temperatures and plugging by particulate matter may occur.
Steam may be used to locally increase reservoir temperature and facilitate auto ignition. It suffers from depth limitation because of wellbore heat losses, but when the conditions are right, it can be a very simple and effective method for ignition.
Well design and completions
Wells used in in-situ combustion must be designed to account for several factors amplified by the combustion, namely high temperature, corrosive environment, and sand and clay control. Safe operations should be the primary concern.
Typical well designs for injection and production are shown in Figs. 1 and 2. Completion type and design depends on the reservoir being considered. Laboratory testing for sand control and completions can help to determine the best completion technique for a given field. Care must be taken to cement the wells properly. There are cement formulations that are stable at high temperatures. Openhole completions may be used in conjunction with slotted liners, screens, gravel packs, or various other sand and clay control methods. To maximize productivity, producing wells should be completed toward the bottom of the zone of interest to take advantage of gravity drainage and avoid hot gases as long as possible. Rat holes have been used successfully in certain heavy oil combustion projects to increase the effect of gravity drainage.
Injection and production practices
Safe air injection requires that the surface injection equipment and the injection well are free of hydrocarbons. All lubricants used in compression and downhole operations should be synthetic or nonhydrocarbon types. All of the following must be clean and hydrocarbon free:
- Work strings
- Injection strings
Personnel at all levels should be aware of the importance of preventing hydrocarbons in the injection wells. As a safety measure to protect injection wells if the compressor is shut down, a system to prevent backflow of oil from the formation must be present at every injection well.
Downhole temperatures in producing wells increase as displaced oil, hot water, and steam fronts reach the well. Producers are preserved by downhole cooling and proper material selection. Fig. 3 provides an estimate of the water requirements to maintain bottomhole temperature no higher than 250°F as a function of oil and water production rate and formation flowing temperature. Significant additional oil recovery can be obtained from hot wells with downhole cooling, especially if the well is completed in the lower section of the producing zone to maximize gravity segregation in the reservoir. In many cases, after the combustion front has moved through the well, it is possible to convert the former producer to a new air injector, thus realizing significant cost reductions over the life of the project.
Fig. 3 – Water needed to cool hot wells.
Monitoring is crucial for proper combustion operations. In addition to testing individual producers for oil and water rates, injected fluids must be measured. Also, produced gases must be measured and analyzed to determine the efficiency of the combustion operation. Downhole temperature measurements are essential to calculate the size and location of the burned zone. Flowline temperatures can indicate thermal stimulation or downhole problems.
Combustion projects generate waste water, flue gases, and pollutants from compression and oil-handling equipment. Local pollution disposal regulations must be consulted before designing any in-situ combustion operation.
In general, environmental problems are similar to those posed by steam injection. The produced water may contain H2S and/or CO2, which may require special handling and anticorrosion equipment. Flue gases may contain hydrocarbons, H2S, CO2, CO, and other trace amounts of sulfur gases. Table 1 summarizes the various pollution-control systems suitable for combustion projects and their recommended applications. Sarathi also provides detailed descriptions of the various types of systems and their uses. Other problems that can be encountered are sand production, corrosion, emulsions, well failures, and compressor failures.
- Sarathi, P. 1999. In-Situ Combustion Handbook Principles And Practices. Report DOE/PC/91008-0374, OSTI ID 3175 (January).
- Shallcross, D.C. 1989. Devices and Methods for In-Situ Combustion Ignition. Report No. DOE/BC/14126-12 (DE 89000766). Washington, DC: US Dept. of Energy.
- Burger, J.G. 1976. Spontaneous Ignition in Oil Reservoirs. SPE Journal 16 (2): 73-81. SPE-5455-PA. http://dx.doi.org/10.2118/5455-PA
- Tadema, H.J. and Weidjeima, J. Spontaneous ignition of oils. Oil & Gas J. 68 (50).
- Smith, D.K. 1976. Cementing, Vol. 4. Richardson, Texas: Monograph Series, SPE.
- Ramey, H.J.J., Stamp, V.W., Pebdani, F.N. et al. 1992. Case History of South Belridge, California, In-Situ Combustion Oil Recovery. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 22–24 April. SPE-24200-MS. http://dx.doi.org/10.2118/24200-MS
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