Effect of Cyclic Flow Interruptions on Performance of Vertically Directed Miscible Floods
- Ion Adamache (Husky Oil Operations Ltd.) | Kantzas Apostolos (Novacor Research & Technology Corp.) | Frank Mcintyre (Husky Oil Operations Ltd.) | Philip M. Sigmund (U. of Calgary)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- February 1994
- Document Type
- Journal Paper
- 51 - 58
- 1994. Society of Petroleum Engineers
- 3 Production and Well Operations, 5.4.9 Miscible Methods, 5.4.2 Gas Injection Methods, 2 Well Completion, 5.7.2 Recovery Factors, 1.14 Casing and Cementing, 3.3.1 Production Logging, 1.7.5 Well Control, 4.2 Pipelines, Flowlines and Risers, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.2.1 Phase Behavior and PVT Measurements, 5.8.7 Carbonate Reservoir, 1.6 Drilling Operations, 4.1.5 Processing Equipment, 4.3.4 Scale, 2.2.2 Perforating, 1.6.9 Coring, Fishing
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Spatial variation in permeability can result in a wide range of critical rates in heterogeneous carbonate reservoirs undergoing vertical miscible floods. Such situations provide an opportunity for new design strategies where gravity, viscosity, and forces are used to advantage to improve miscible flood performance. One such design strategy is use of cyclic interruptions in the form of well flow shut-in. Field observations and laboratory experiments are presented.
Husky Oil Operations Ltd. runs eight vertical hydrocarbon miscible floods in the Rainbow Lake reefs in northern Alberta. Downward displacement of oil by a less viscous solvent is unstable if a critical displacement rate is exceeded. This instability is observed as viscous fingering of solvent into the oil and is undesirable because it leads to reduced volumetric sweep efficiency. The instability of oil displacement is aggravated by the reservoir vertical permeability variations, as in heterogeneous carbonate reservoirs where spatial variations in vertical permeability can result in areas where the critical rate is exceeded even when the average displacement rate is below the critical value.
Therefore, the miscible flood designer is faced with the problem of operating at very low rates (less than the critical rate applicable to the reservoir) or at higher rates where viscous fingering will occur. This suggests that an optimum displacement strategy that balances the economically attractive features of high production rates against the technical disadvantages associated with viscous fingering should be considered.
In oilfield practice, rate restrictions are applied or workovers are conducted to control excessive gas or solvent production. In workovers, the current perforations are cement squeezed and lower perforations are made in the reef. This procedure is costly and not always successful. Another alternative would be to drill either vertical or horizontal infill production wells. These wells could increase oilfield production while maintaining a reasonable displacement front velocity. The main disadvantages of adding vertical producers are increased costs of drilling and completion and workovers required because of displacement front advancement during vertical miscible displacements. The disadvantage of adding horizontal producers is the cost of drilling and completion, which is approximately twice that of drilling and completing vertical wells. Such operational problems as production logging and gas or water channeling problems may increase exploitation costs further. An alternative to adding horizontal wells could be re-entries from vertical wells. This technology is in a developmental stage and currently cannot be applied fieldwide.
Husky proposed another procedure to optimize the displacement strategy that can improve the vertically directed miscible floods by cyclic flow interruption with periodical shut-ins.1 This concept was based on observations made at the Rainbow Lake field during regularly scheduled plant turnarounds. After production resumed in the miscible floods, wells that had been experiencing declining oil production and increasing GOR often displayed production rate increases and GOR decreases before reverting to the previous increasing GOR trend. Compared with such alternatives as workovers and additional vertical or horizontal producers, cyclic flow interruptions are much less expensive. The only cost is related to production lost during the shut-in, which usually is recovered after production is resumed and the wells produce at higher rates than before the shut-in.
Factors influencing cyclic flow interruptions include reef heterogeneity, problems related to vertical zone isolation, and complexity of the vertical miscible flood processes. However, shut-in effects are difficult to isolate from other effects.
During vertical hydrocarbon miscible flooding, high solvent concentration fingers form. When the wells are shut in, the fingers decay by gravity segregation and contribute to formation of a graded viscosity mixing zone. This reduces the local viscosity contrast between solvent and oil, which inhibits the tendency for fingers to grow after production is resumed.
Shut-in Field Tests
Traditionally, production well control of excessive gas or solvent in vertical hydrocarbon-flooded pools consists of changing the rate by altering choke size, which typically reduces production rates, or a workover to cement the open perforations and perforate lower in the reef. However, situations exist where the active perforations are low in the reef, close to the oil/water contact, and perforating lower is not a workover option. The shut-in procedure that was tested in 1984 at Well 4-32-109-08 W6M in Rainbow Keg River Pool A, where a vertical hydrocarbon multicontact miscible flood was in progress, is an alternative to this type of workover operation for GOR control. Two workovers to isolate the upper perforation were conducted at this well in 1983 because of high gas/solvent cut. The cost was more than $100,000 and 100 days of production were lost but the workover reduced GOR for only 6 months (Fig. 1). Subsequently, the shut-in procedure was applied because workover possibilities were exhausted. This shut-in test was different from the relatively short production interruptions from plant turnarounds that normally take place annually. The well reacted positively to a 2-week shut-in in Jan. 1984 and a 2-week shut-in in Sept. 1984. During these two shut-in cycles, oil rate increased and GOR decreased, compared with the situation before the first shut-in experiment. Additional net production was obtained from Jan. 1984 through March 1985. The only cost of the experiment was lost production, which was recovered quickly by the ˜30-m3/d increased oil production that followed the shut-in period.
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