A series of experiments have been undertaken to visually observe the formation and growth of bubbles formed when solution gas is released from waterflood residual oil. The experiments were performed using an etched glass micromodel which represented a two-dimensional section of a sandstone core. This micromodel was mounted vertically within a temperature controlled water bath, and the flow of fluids within the micromodel was observed through a microscope and recorded on video. Experiments were performed under water-wet conditions, using a mixture of low boiling point hydrocarbons, which had a positive spreading coefficient for the oil phase in contact with water and its own vapour. In these experiments the gaseous phase was produced by raising the temperature of the micromodel until it reached the bubblepoint of the oil, at atmospheric pressure. The following features were observed:In keeping with the spreading oil, all gas that was generated as bubbles within the oil ganglia from which it was produced. Bubbles did not form in all ganglia, nor did they all form at the same time.As more gas was released from solution, the bubbles expanded, pushing the gas/oil and oil/water interfaces outwards. Buoyancy forces had little initial influence on the expansion, which occurred in all directions.The bubbles themselves were unable to migrate, and the gas remained immobile until the volume of individual bubbles had increased to the extent that adjacent bubbles became connected.The oil phase was transformed from being immobile droplets or ganglia, into films surrounding the gas bubbles, in which the oil was mobile. A mathematical model for the growth of a single bubble has been developed, which includes the effect of gravity as well as capillary forces in controlling the development of the bubble. Calculations using this model show that the initial growth pattern is dominated by capillary forces, but as the bubble becomes larger buoyancy forces start to play an important part in the way that the bubbles grows. Introduction Reservoir depressurisation at a late stage of waterflood production is seen to be an attractive enhanced recovery project for the Brent reservoir in the UK sector of the North Sea1. Lowering the reservoir pressure provides a way of producing some of the solution gas from the oil remaining in the field at the end of the waterflood, and extending the economic life of the field. In the case of Brent, it is expected that field life will be extended by at least ten years, with an increase in gas production of more than 1 Tscf, and of oil and condensate production of 30 MMstb2. Reservoir depressurisation is also thought to have applications in other reservoirs on the UKCS, and the overall potential for increasing hydrocarbon recovery has been estimated to be 0.2 Bstb equivalent at an oil price of $16/bbl3. A considerable amount of research has been undertaken in the past to study depressurisation phenomena associated with natural depletion and solution gas drive in virgin reservoir4–25. Much of the existing literature is focused on the role of nucleation and diffusion in the development of the gas phase, and the occurrence of supersaturation in the oil phase. These processes have been modelled theoretically, and good agreement has been achieved between the models and experimental measurements4–7. More recently, visual studies of the release of solution gas in virgin situations have been reported by Li and Yortsos 31, and the processes have been simulated with pore network models32,33. However, the release of solution gas from waterflood residual oil has received comparatively little attention, and this is the subject of the present paper. In reservoirs that have previously been waterflooded, it is very important to be able to mobilise the gas that is evolved so that it can be recovered at the producing wells. It is well known, however, that when gas is released from solution the gas saturation has to build up to a critical value, Sgc, before it can start to move. This has been observed both in experiments performed with virgin cores7–13, and with cores that were waterflooded before being depressurised 26.
Preliminary results obtained from a program of experimental and theoretical studies examining the uncertainties of waterflooding gas-condensate reservoirs are reported. In spite of high trapped-gas saturations. (35 to 39%). further ag?ravated by an unusual type of hysteresis, recoveries of gas and liquids can be increased over those obtamed under natural depletIOn.
Summary This paper reviews some aspects of the quantitative assessment of two types of enhanced oil recovery (EOR) processes and their potential application to North Sea reservoirs. Calculations are described that were undertaken for a simplified conceptual reservoir model with properties akin to those of the Forties field. Possible initial conditions for EOR operation resulting from various stages of waterflooding are evaluated. The results of EOR assessment calculations using advanced three-dimensional chemical flood and compositional simulators are presented, for both a low-tension aqueous surfactant presented, for both a low-tension aqueous surfactant process and for CO2 displacement in association process and for CO2 displacement in association with a chase water drive. Introduction Development of oil reservoirs in the North Sea is now approaching the stage when the production rate is equal to the annual consumption of about 80 MMtons within the U.K. There are 26 fields where production is already occurring or development is in production is already occurring or development is in progress. The locations of the principal fields are progress. The locations of the principal fields are illustrated in Fig. 1. From the outset it was recognized that secondary recovery should be initiated in the early stages of primary production. This is exemplified by the introduction of water injection in most fields and gas reinjection in some fields as part of the current development plans. Using these methods, the overall oil recovery is expected to be at least 1,400 MMtons, equivalent to 18 years' consumption. The U.K. Dept. of Energy estimates, that the possible recoverable reserves from these fields may be as high as 2,600 MMtons. The remaining unrecovered oil in place after conventional depletion is expected to be about 60 % of the original (i.e., between 2,100 and 3,900 MMtons), which represents a very substantial target for EOR. If the development of s successful EOR process allowed recovery of 10 % or more of the residual oil after waterflooding, the U.K.'s period of self-sufficiency would be extended by several years, with substantial benefit to the probable shortfall in the U.K. energy position in the late 1990's. position in the late 1990's.The U.K. Dept. of Energy has funded an initial study program to determine the research and development in EOR that would be needed for the particular conditions of North Sea reservoirs. This particular conditions of North Sea reservoirs. This program was intended to (1) investigate the program was intended to (1) investigate the applicability of those EOR processes seen as having the best potential and (2) undertake calculations aimed at evaluating the process technology. The ability to predict EOR performance under real reservoir predict EOR performance under real reservoir conditions was considered a key issue. The studies have been undertaken at AEE Winfrith with three teams respectively concerned with the design of high- pressure displacement experiments in long cores, evaluation of mathematical modeling techniques, and quantitative assessment of EOR displacement under various conceptual reservoir conditions. In addition to this conceptual study, a number of more basic research projects have begun at several universities, and the petroleum companies in the U.K. have been encouraged to increase their EOR programs in a collaborative manner. programs in a collaborative manner.This paper highlights some aspects of the assessment studies undertaken at Winfrith and draws attention to some of the features of the supply of EOR materials. JPT P. 1617
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