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Recently, Enhanced Oil Recovery (EOR) application in offshore oil fields is receiving significant attention. The size of targeted offshore oil fields is generally large, because their Original-Oil-In-Place (OOIP) should be sufficiently large to overcome the high cost of offshore oil field development. Therefore, the amount of recoverable oil using EOR may be enormous. The risks of applying EOR are lower than the exploration for deep-water oil, because EOR except for thermal EOR is usually applied to the already producing oil fields. Because of the above reasons, offshore EOR application has been considered as a highly acceptable option. However, application conditions for offshore oil fields are more complex than onshore oil fields due to the unique parameters present in offshore fields. Therefore, successful EOR application in an offshore oil field requires screening criteria that are different from the conventional onshore screening criteria. A comprehensive database for onshore applications of EOR processes, together with a limited offshore EOR application database, are analyzed in this paper; and the important parameters for successful offshore application are incorporated into the new EOR screening criteria.
In this paper, screening criteria for highly acceptable EOR processes in offshore fields including hydrocarbon (HC) gas miscible, CO2 miscible and polymer are presented. Gas EOR using produced hydrocarbon gas has high potential for light oil recovery in offshore fields because of high availability of injectant and its reduced handling cost. For medium oil and even heavier oil recovery, polymer process is highly acceptable because it is a well proven technology by the earlier onshore and even offshore applications. CO2 miscible process has been proven as a successful technology worldwide, mainly in onshore fields. In many cases, minimum miscibility pressure of CO2 is lower than hydrocarbon gas; hence, the CO2 miscible process has a wider range of field candidates. In view of the current active interests in seeking synergy between CO2 storage and the high efficiency of the CO2-based oil recovery, this process has high potential for offshore EOR application if CO2 can be available economically.
Suggested screening criteria for these EOR processes comprise quantitative boundary and qualitative considerations. Quantitative screening criteria are mostly based on quantifiable data including oil and reservoir properties. Most screening criteria suggested in this paper are generally similar to those previously suggested. Due to the recent significant polymer development efforts and their active applications, however, the difference for oil viscosity criteria in the polymer process is relatively large. There is a high potential for further criteria extension in the polymer process. Qualitative screening considerations mainly focuses on operational issues present in offshore including limited space on the platform, limited disposal option, injectant availability and flow assurance matters (mainly hydrate formation and difficulty in emulsion separation). These considerations are very hard to be quantified and highly depend on operational limitation of each EOR process in specific fields. However, it is found that economical availability of injectant is most critical parameter in early stage of EOR screening.
Korea is well-known worldwide for its proven and established technology of shipbuilding and construction of offshore oilfield development facilities. However, Korean shipbuilding companies are now eagerly seeking new market opportunities to overcome increasing competition and investing huge resources to offshore oilfield production facilities technology R&D, such as for EOR processes. This research is conducted in accordance with such current circumstances in Korea.
As an oil zone thins during the mature stages of a vertical miscible or immiscible flood, oil production becomes dominated by coning of water, gas and / or miscible solvent. This results in lower revenues and increased operating costs which in turn accelerates well abandonment. in contrast to the early operations of a pool, the remaining oil volumes which are increasingly at risk have access to only limited capital. Coning therefore is controlled by conventional techniques such as re-completions, choking back oil production or intermittent operation. As the effectiveness of these techniques becomes reduced, other less conventional approaches are sought.
Such techniques as the placement of polymeric agents or the injection of oil or water to divert the coning fluids, are becoming attractive because of their low capital requirements. in support of the present work, scaled laboratory experiments and numerical simulation studies have demonstrated the recovery benefits using fluid injection as a way to maintain production from a thinning oil sandwich. Currently, Imperial Oil is developing oil re-injection technology to increase recoveries by 1.5 to 3 percent of the original oil-in-place (OOIP) by reducing solvent coning in a number of their vertical miscible flood pools located in the Pembina Nisku area. A pilot project evaluating this technology has been in operation for nearly a year. After overcoming a number of start-up and other operational problems, the pilot has demonstrated that oil re-injection can successfully control GOR. History-matching the pilot performance has confirmed the design approach and performance expectations. Based on the encouraging results, four more projects have been planned for start-up in 1994.
The Pembina Nisku area is located approximately 120 km (72 miles) west of the city of Edmonton, Alberta, Canada (Figure 1). The Pembina Nisku discoveries were the result of a seismic exploration play initiated by Chevron in the mid 1970's.
Imperial Oil Resources Ltd. operates seven vertical miscible floods in this area. These pools are relatively small in areal extent with the OOIP ranging from a low of 1700 km3 (10.7 million STB) to a high of 5000 km3 (31.4 million STB). Vertical miscible floods were initiated in these pools in the 1982 to 1987 time frame. All the miscible floods have now experienced solvent breakthrough and as a result, there has been a rapid decline in oil rates. The pools presently produce approximately 1900 m3/day and this represents a decline of more than sixty percent from their 1988 peak rates.
The Nisku pools have now recovered approximately 88 percent of their reserves with individual pool recoveries approaching 70 percent of the OOIP. The low remaining reserves combined with high individual pool recoveries make it difficult to justify major capital investments to extend the producing life of these pools.