Summary In this paper, we discuss experimental and theoretical studies on the effects of disproportionate permeability reduction (DPR) (i.e., the ability to reduce relative permeability to water more than to oil). The theoretical part discusses DPR effects by simple analytical arguments, supported by simulations. DPR causes buildup of water saturation in the treated zone to accommodate the water/oil ratio, Fwo, delivered by the reservoir. Core flooding experiments were also carried out, with a DPR gel placed in one half of the core. There is excellent agreement between theory and core flooding results. It was observed that the water saturation in the treated zone increased. Saturation profiles were measured with a CT scanner and is well matched by simulation.

Cyclic waterflooding is an IOR-method that improves oil production in heterogeneous reservoirs with high-permeability contrast. The concept of the method is based on pulsed injection and alternating of waterflood patterns. The main effect induced by the cycling of wells is oil production increase accompanied by water production decrease. The production increase is achieved by improved sweep efficiency in low permeable zones of a reservoir non swept by traditional waterflooding process. The cyclic water injection process was successfully applied in a number of sandstone and carbonate oil fields in Russia, USA and China. The important advantages of the method are virtually zero additional cost and simple implementation procedure. The uncertainty with the method is related to understanding the IOR mechanism, ability to accurately model the process and design a field application. The paper presents the results of the study of cyclic water injection and oil production at a North Sea heterogeneous sandstone reservoir. The study consists of the field history analysis, pre-screening cyclic efficiency estimation and numerical reservoir simulation to design the field application of the IOR-method. The field history analysis shows the presence of cycles in injection and production and their influence on water-cut change. Pre-screening analytical tool was used to perform a wide-range sensitivity analysis with respect to rock-fluid parameters, heterogeneity, cycle length and pressure conditions in order to understand the mechanism and to estimate the IOR potential. Finally the sector model reservoir simulation was used to optimize the cyclic process by alternating the waterflood patterns and to design the field application. The simulations show decrease of water production and improvement of oil production by up to 3% with short time and by 5% with long time cycles. Introduction The cyclic waterflooding improves sweep efficiency in heterogeneous reservoirs. In the IOR-method a combination of two processes of (1) pulsed injection (production) and (2) alternating of waterflood patterns is used. The cyclic waterflooding was successfully applied in a number of sandstone and carbonate oil fields in USA1,2 and Former Soviet Union 3,4,5. The cyclic injection potential was evaluated in a number of studies 3,4,5,6,7,8. Analytical estimation and numerical simulations have shown significant potential with oil production increase by up to 10% and reduction of water-cut by up to 20%. Recent experimental studies 9 have demonstrated improvement of oil recovery under pulsed pressure conditions at laboratory scale. The uncertainty of cyclic waterflooding is related to understanding of the IOR mechanism, ability to model and predict efficiency of the process, and to design a field application for specific reservoir conditions. In this paper we analyze production and injection data, discuss and evaluate parameters that affect cyclic waterflooding, estimate efficiency of the method for different scenarios of field application. Cycling effects which occurred in the production history of a heterogeneous sandstone reservoir were analyzed to evaluate their influence on water-cut behavior. The analytical tool 8,10 was used for screening of the cyclic injection. A wide range sensitivity analysis was performed to estimate efficiency of the cyclic process. Based on the analytical screening results the numerical simulations of cyclic waterflooding were carried out on a sector reservoir model. IOR potential of cyclic reallocation of water injection volumes between well patterns was also estimated.

This paper was adecfed bf pmwnatbn by an SPE Program CommilbeMowing rewiw of intormafii contained In an abafracf 8ubmHfed by the author(s). Contenm of the paper, as presented, have ml taen reviewed by lfw SOcbly of Pelrobum Enginearn and are subjecf to oarreclbn by the author(s). The nwwbd, nY pmsemted, do6a not necewrily Ntbcf any podtii of the SocbIY of Pefrofeum Engineers, W officam, w mentws. POP6M wewnfed at SPE meetirw am 8@cf to publfcatbn revisw by Edbbl Cammlffwa of the society d~~-. Pwmiwbnmqb~mm*M&~wW~tis.lll_tiw Mb~.~ti_*Mtin~wkõ f where and by whom the M b presented. Write Librarian, SPE, P.O. Sox 8S38SS, Rbfwdson, TX 75wHSSE, U.S.A., Tefex 16324S SPEUT.

The dependency of waterflood remaining oil saturation (S or ) on intial water saturation (S wi ), wettability and flow rate has been studied in the laboratory at core scale. For both water-wet and mixed-wet cores, S or was found to be inversely proportional to S wi . For mixed-wet cores, S or was also found to be inversely proportional to the number of pore volumes injected. In contrast, water-wet cores showed a dependency between S or and flow rate, indicating that pore structure plays an important role.The oil saturation development in several waterflooded intervals in the Gullfaks Field has been monitored, mainly by saturation logs, over several years. Oil saturation was found to decrease inversely with time after water breakthrough. Also, an oil saturation distribution with depth, which seems to depend on the balance between capillary and gravitational forces, was found.

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