Cyclic injection is a process that improves waterflooding efficiency in heterogeneous reservoirs. The concept of cyclic injection is based on (1) pulsed injection and (2) alternating waterflood patterns. Cyclic injection has been successfully applied in a number of sandstone and carbonate oil fields in Russia. In the rest of the world, pulsed injection has had limited application, and only in naturally fractured reservoirs. Although changing the waterflood patterns is a common approach to deal with increasing water cuts, a more systematic approach with both pulsed injection and alternating flow directions is not.Cyclic injection has the greatest potential for improved recovery in heterogeneous, high-permeability-contrast sandstones and in naturally fractured carbonates and dolomites. The efficiency of the process is high in preferentially water-wet rocks saturated with compressible fluids. Capillary pressures and relative permeability effects are responsible for the improved cyclic oil displacement at the micro level. Improved sweep of the less permeable layers in communication with more permeable thief zones, better horizontal sweep achieved by changing waterflood patterns, and alternating the dominance between gravity and viscous forces are the key effects of cyclic injection on the macro level.The potential of cyclic injection at the Lower Tilje/Åre formations of the Heidrun Field in the Norwegian Sea has been evaluated. Some of the reservoir levels are highly heterogeneous, with large permeability contrasts vertically and horizontally. The current drainage strategy for these formations is water injection, with gas lift in producers when needed. Cyclic injection will improve waterflooding efficiency at virtually zero additional cost. Improved sweep, accelerated oil production, and reduced water cut are the main positive effects expected from cyclic waterflooding. The reserves are predicted to increase by 5 to 6% from the targeted reservoirs at Heidrun after 10 years of cyclic waterflooding.

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Thin Gel Treatment of an Oil Producer at the Gullfaks Field: Results and Evaluation. Abstract The use of Na-silicate gel in producers is a method to reduce watercut and improve oil recovery by diverting the flow of water in the reservoir. This has been tested twice at the Gullfaks field in the North Sea and the results are encouraging. This paper focuses on the second treatment at Gullfaks October 1994, where more than 4000 m3 of gelant solution were injected into a partly watered out zone in a producer. The treatment resulted in a reduced watercut and increased oil recovery from the Lower Rannoch formation. Additional oil production of 130,000 Sm3 by the year 2000 is predicted. The added net present value due to this gel treatment is estimated to more than 50 million NOK's at 10% discount rate. Input parameters used to describe the gelation process and the effect of Na-silicate gel in a numerical simulator are given. Introduction High water production is a problem in many North Sea oil fields due to massive water injection. Reducing it while maintaining, or even enhancing, oil recovery from these fields is a major challenge. The high and climbing water production of the Gullfaks and Statfjord fields is illustrated in Fig. 1. In order to cope with the water production problem it is necessary to exploit existing methods to their maximum, and if possible add new techniques for water shut-off to the existing "toolbox". Evaluation of both the reservoir situation and the capability of the techniques available must be carefully performed in order to reach the desired goal. There exist some widely used mechanical methods for zonal isolation. A straddle packer reduces the production pipe inner diameter. A successful application demands that there are no vertical leakage behind the pipe. Another mechanical method is the use of packers. They are easy to apply if the production pipe is in good condition. has an even inner diameter, and the target zone is at the bottom of the well. Some of these packers have the advantage of being retrievable. Cement squeezing is probably still the most frequently used method for zonal isolation. The cement does not enter the matrix of the reservoir. only the perforations and cavities open to flow. If the target zone is at the bottom of the well and there is no leakage behind the pipe, cement will often be the best choice. Cement jobs have low success rate when a leakage at the top of a zone is to be repaired. An interesting set of statistics has been established by Arco on the use of polyacrylamide-chrome gels at Prudhoe Bay for gas shut off. Due to the large numbers of gel jobs performed >30) they have been able to compare with competing methods for gas shut off. Cement squeeze was successful in less than 60% of the gas shut off cases. Recompletion was more efficient, but also more expensive. Gel treatments proved to be a very good alternative. A technical success rate greater than 60% at 75% of the cost of comparable cement squeezes have been achieved. These gel treatments have primarily been performed in wells that had cement squeeze failures. In some cases the right method for zone isolation is obvious, while other situations needs more careful evaluation. A correct understanding of the problem is, however, always needed in order to prescribe a good treatment solution for an unfavourable reservoir situation. The evaluation of the problem becomes more complicated when the target zone is only partly watered out, or when it is in communication with the rest of the reservoir. Evaluation of Potential A history matched Gullfaks Lower Brent reservoir simulation model indicated large remaining volumes of "cellar oil" in some of the fault blocks. This evaluation focused on the G1-fault block, see Fig. 2. A direct approach to reduce watercut and improve oil recovery was believed to be possible by changing the flowpaths of water through the reservoir by treating the injector. However, a study on injector A-15 which is perforated in the water zone concluded that only a weak and delayed increased oil rate could be expected from the injector treatment. The main reason for the poor potential is the pressure communication in the water zone. Pressure differences between zones at the injector vanished before they reached the oil zone. The producer A-13 was, however, recognized as the governing influence on this part of the reservoir. In the continuation of this evaluation study the focus was shifted towards the potential for gel treatment of this producer. Evaluation of production history. A-13 production commenced in February 1988. It has two perforated intervals. Initially it produced approximately 3000 Sm3/d of oil. P. 137