Enhanced oil recovery (EOR) techniques can significantly extend global oil reserves once oil prices are high enough to make these techniques economic. Given a broad consensus that we have entered a period of supply constraints, operators can at last plan on the assumption that the oil price is likely to remain relatively high. This, coupled with the realization that new giant fields are becoming increasingly difficult to find, is creating the conditions for extensive deployment of EOR. This paper provides a comprehensive overview of the nature, status and prospects for EOR technologies. It explains why the average oil recovery factor worldwide is only between 20% and 40%, describes the factors that contribute to these low recoveries and indicates which of those factors EOR techniques can affect. The paper then summarizes the breadth of EOR processes, the history of their application and their current status. It introduces two new EOR technologies that are beginning to be deployed and which look set to enter mainstream application. Examples of existing EOR projects in the mature oil province of the North Sea are discussed. It concludes by summarizing the future opportunities for the development and deployment of EOR.

This paper describes the first comprehensive inter-well field trial of low-salinity EOR. The objective of the trial was to demonstrate that reduced-salinity waterflooding works as well at inter-well distances as it does in corefloods and single well tests. The trial was designed to evaluate two risks: 1) whether mixing or other mechanisms prevent achievement of reduced-salinity improved recovery in the reservoir and 2) whether the adverse mobility ratio between the injected water and the oil bank causes viscous fingering – resulting in mobilized oil being left behind. The demonstration was implemented in a single reservoir zone at the Endicott field (North Slope Alaska). The trial involves an injector and a producer 1040 feet apart. The producer was monitored for changes in watercut and ionic composition. In December 2007, produced saline water was injected to pre-flood the pattern until watercut was over 95%. Reduced-salinity water injection commenced June 2008. The associated EOR response was detected in the producer after three months. Data from a wellhead watercut meter and fluid samples from a test separator both revealed a clear drop in watercut, from 95% to 92%. The timing of the drop in watercut coincided with the breakthrough of reduced-salinity water at the producer. Incremental reduced-salinity EOR oil recovery timing and volume matched behaviors observed in corefloods and single well tests. By May 2009, 1.3 pore volumes of reduced-salinity water had been injected. The incremental oil recovery is equal to 10% of the total pore volume in the swept area. Initial oil saturation at Endicott is 95%. In the pilot area, tertiary reduced-salinity waterflooding is expected to drop residual oil saturation from 41% to 28%, a 13 unit drop in residual oil. The inter-well field trial demonstrates that the identified risks did not impact performance.

This paper was prepared for presentation at the 1999 SPE Asia Pacific Improved Oil Recovery Conference held in Kuala Lumpur, Malaysia, 25–26 October 1999.

This paper presents a new methodology, based on field performance data, for optimally distributing miscible gas to the 70 patterns under water alternating gas flood in the Prudhoe Bay Miscible Gas Project (PBMGP). In addition the new approach controls the timing of the miscible flood expansion to a further 60 waterflood patterns. The guiding philosophy of this approach is to maximize the efficient use of the miscible injectant (MI) by minimizing its wastage. This methodology was implemented in the field in 1991 and is expected to increase by 50% the current volume of oil being mobilized by the Ml. The projected ultimate recovery of 410 - 480 mmstb of oil from the expanded PBMGP is equivalent to the reserves of a major oil field. For comparison the PBMGP reserves are larger than most North Sea projects currently under development. For this reason it is clearly vital to effectively manage a project of this magnitude.

Summary In 1990, a single-well chemical tracer (SWCT) test was performed in Prudhoe Bay to measure the effective waterflood and miscible gasflood residuals over a 12 ft reservoir interval. This is believed to be the first such use of this technology for a hydrocarbon miscible gas. This paper describes how the usual SWCT design was modified to accommodate the miscible gas, the results of the SWCT, which indicate significantly higher residual oil saturation for miscible gasflood than expected from coreflood experiments, and the subsequent simulation of the test which has provided good agreement with the observed results. The paper shows, with compositional simulation support, that the high apparent residual oil saturation was a consequence of incomplete volumetric sweep by the miscible gas and draws on the experiences of this test to make recommendations for the design of future SWCT tests measuring residuals to gasflooding. Introduction The Prudhoe Bay Miscible Gas Project (PBMGP) is the world's largest miscible flood. Prior to startup in 1987, numerous slim tube, coreflood, and phase behavior experiments were carried out to confirm the recovery potential of the process. Since the startup of the PBMGP a fibreglass observation well has been used to observe the flood progress and a sidetrack cored to observe the extent of the gas sweep. In 1990, a single-well chemical tracer (SWCT) test was carried out on a producing well which first measured the effective residual to waterflood and then to miscible gasflood. The attraction of the SWCT was that it investigated a much larger volume of rock than a coreflood and native wettability, away from the wellbore, should be assured. However, it should be recognized that this still only represents a small sample which may not represent the average performance on a broader scale. The tests were successfully carried out although production problems resulted in four tests, instead of the originally planned two, finally being performed. The subsequent analysis suggested an effective residual oil saturation to the miscible flood (Sorm) of 8%±2%. This was somewhat higher than the coreflood observed values of around 2%. Compositional simulation work has since been carried out to model the full suite of tests, including the aborted ones, to ascertain whether this higher value really conflicted with the coreflood results. Throughout the paper the remaining oil saturation following a water- or gasflood is referred to as the effective residual oil saturation since the paper demonstrates that the apparent high residual oil saturation after a miscible gasflood was a consequence of incomplete volumetric sweep. Hence, the measured remaining, or effective, residual saturation could have been lowered further if complete sweep had occurred. The theory behind a SWCT test is described in detail in Ref. 1 and recovery methods in Ref. 2. Background The Prudhoe Bay oil field on the north coast of Alaska is the largest oil field in the USA. The major producing sand is the Sadlerochit, which can be over 400-ft thick in some locations. It is mostly comprised of high-permeability fluvial sands with interbedded shales. Some of these shales are continuous over large areas while the majority are discontinuous over interwell distances. The structural and hydrocarbon histories are documented in Ref. 3, while Ref. 4 covers the reservoir description. Prudhoe Bay is overlain by a large gas cap. All produced gas components not used for fuel or spiked into the export oil line are reinjected either as a lean gas back into the gas cap or as a rich gas into the PBMGP or other projects. Lean gas injection into the gas cap recovers additional relict oil by vaporization. The expansion of the gas cap downwards recovers oil by gravity drainage. Around the periphery of the field there are approximately 200 inverted nine-spot patterns undergoing waterflood or water-alternating miscible gasflood. The general history of the development of Prudhoe Bay is described in more detail in Ref. 5. The PBMGP was preceded by a pilot at Drill Site 13 in 1982 prior to the startup of the central gas facility (CGF) in 1987. The CGF has since been expanded several times and now produces up to 550 mmscf/d of miscible gas. To date, 1.6 trillion scf of miscible gas have been injected. The development of the PBMGP is documented by Refs. 6 and 7. The optimization of the flood is achieved by directing the miscible gas to the most efficient patterns, as described in Ref. 8, and the use of predictive tools described in Refs. 9 and 10. During 1993, the need to sidetrack Injector DS 13-18 provided an opportunity to acquire additional information on the vertical sweep of the injected gas and the extent to which the miscible gas was reducing the oil saturations in this immature pattern (see Ref. 11). Prior to the start of the PBMGP, continuous and water-alternating miscible gas (WAG) floods were carried out on 16 plugs taken from a total of 4 preserved cores. These cores were injected with different miscible gas compositions and varying quantities of between 0.88 and 3.74 stock tank pore volumes. They exhibited residual to miscible gas saturation values between 1.0% and 4.5% (see Ref. 12), with an average of S orm. In 1990, the magnitude of the reserves being booked to the PBMGP warranted the investment in a SWCT test to provide additional confidence that miscible flooding in the field could achieve the low residuals suggested by the preserved state corefloods.