The Almy sands in Sublette County, Wyoming have been subjected to various volumetric sweep improvement techniques since September, 1969. This paper describes the first field wide effort to reduce residual oil saturation in the swept area. Initially, a series of crude oil - alkaline agent screening tests were run to select, on the basis of interfacial tension reduction (IFT), the most cost effective alkaline agent. Follow up core tests showed that a combination of soda ash (Na2CO3) and anionic polymer would be effective in reducing oil saturations from 22 to 17 percent pore volume. The core tests also demonstrated that a properly prepared alkaline solution could be injected into the high clay content Almy. On the basis of these test results and ten years of experience injecting clay stabilizers, anionic polymers and wettability alteration products, the decision was made to go polymers and wettability alteration products, the decision was made to go from the start with a total oil recovery program. The original plant design was modified to accommodate the requirements for adding one half million pounds of Na2CO3 in less than a year. This involved installing a second dry solids feed system, interchangeable with the regular polymer unit. Storage capacity at the plant site was increased to 50,000 pounds of dry product and on the Na2CO3 unit a second 100 gallon stainless steel solution tank was put in series with the regular mix tank. Operating people designed and built a rugged, inexpensive product handling system that allows the plant operator to service both feed units in less than one hour a day. Input side control tests include pH, O2, PO4, turbidity, screen factor and viscosity. Hall Plots are the primary monitor of injection well conditions with step rate tests and pressure fall-off measurements used as back up. Producing wells are tested once a month. Data is plotted on a time-rate basis as well as graphed in the form of water-oil ratio (WOR) vs. cumulative oil recovery. Produced water samples are checked for pH, chloride, tracers (thiocyanate and nitrate) and polymer breakthrough. These results are also posted on the individual producing well graphs. posted on the individual producing well graphs. Although only in its third year of operation, the project is far enough along to conclude the following:It is practical and profitable to employ, at the same time, techniques that will improve sweep and lower residual oil saturation.Selecting a "Total Oil Recovery" process and starting it early greatly simplifies plant design.EOR processes requiring fresh water should be started before break through to lower costs and lessen the problems related to lifting, treating and reuse or disposal of produced water. HISTORY AND PRIMARY DEVELOPMENT The Isenhour Field was discovered August 5, 1970, with completion of Isenhour Government #1 for an initial rate of 90 BOPD and no water on 18/64" choke. Initial reservoir pressure was 1,470 PSIG at +3,580' with bottom hole temperature 95F. Isenhour Government #2 and IU #51 were completed in January and February of 1971, respectively. Drilling in the area was unsuccessful until Isenhour Federal #5-17 was completed in 1977. The most recent producers, Isenhour Federal #6-17 and #7-17 were put on in 1978. Cumulative production through September, 1980, when enhanced recovery started, was 473,202 STBO; 15,327 BW; and 761,442 MCF. Figure 1 is a net oil isopach which shows location, structure, and net sand thickness of wells in the field as it is currently defined. Figure 2 traces field performance from August, 1970 through December, 1981, the latest month performance from August, 1970 through December, 1981, the latest month included in this summary. p. 689

New technology based on the use of potassium hydroxide to permanently 11 fix 11 clays in the near wellbore area is taken from the laboratory development status to the field. Injection well treatments using KOH are compared with the normal soak (potassium chloride) and coat (cationic polymer) approach in the same reservoir.

The use of concentrated KOH to stabilize clays is becoming a common practice in Wyoming. Seventy-two injection wells, ranging from single pilots to fieldwide programs, have been treated and monitored since the technology was first introduced in Aug. 1984. This paper summarizes test results that fall into three broad categories: (1) those that increase recoverable reserves, (2) those that speed the rate of waterflood oil recovery, and (3) those that do more harm than good. Wells in the first two groups are examined starting with treatment design and wellsite preparation and moving on through the pumping stages to final evaluation of the results. The mixing and handling of highly alkaline solutions are covered from the service company and operator safety viewpoints, and with respect to the fluid-quality, chemical, and metallurgical requirements for proper placement of the solutions. Two wells are singled out for their special contribution to the learning-curve aspect of this new technology and for their value in helping to avoid making the same mistakes again.

The Moore-Holverson-Hill-Aagard waterflood is followed from 1963 start-up to Jan., 1968. The Bartlesville sand body is marginal by normal waterflooding standards, but secondary oil recovery to date and production trends point to an ultimate recovery that will be twice the point to an ultimate recovery that will be twice the average for other "successful" floods in the county. Water quality, wettability and treatment with polymer are documented. Special emphasis is placed on the amount of extra oil produced from areas effected by polymer. Over-all project economics are presented, and the impact of project economics are presented, and the impact of polymer treatment on Aagard lease performance and profit are polymer treatment on Aagard lease performance and profit are studied in detail. Introduction In Southeastern Kansas where waterflooding has been conducted for over 20 years, the better quality reservoirs are gone. Only the marginal prospects are left. Our purpose is to show that good operation, modern petroleum purpose is to show that good operation, modern petroleum engineering, and sound water handling now make it possible to successfully flood many of these marginal sands. possible to successfully flood many of these marginal sands. The paper will outline the early history of the reservoir, detail conditions at the start of the flood, and describe input well behavior and production responses on the Moore and Aagard leases. It will also deal with attempts to "tailor" injection water for better oil recovery. Some of the efforts made during this 4-year study period are destined for the technological junk pile. Several show promise, and one - the highly selective use of polymers promise, and one - the highly selective use of polymers has been very effective. The wide range of crude oil properties and producing formations makes it hard to see water as the best displacing fluid. Yet most decisions concerning source water are based on volume, year-around supply, and corrosion- or scale-forming tendencies. No thought is given to how well the water will displace oil. The objective of the "water treatment program" is to move the fluid from surface to formation without dissolving the lines or plugging so much that pressures go above wellbore limits. It is assumed that once pressures go above wellbore limits. It is assumed that once water moves beyond the inputs its ideal properties take charge and start to move oil toward the producing wells. A good flood water would behave very much like the oil it is trying to displace. Table 1 shows important differences in Bartlesville' crude oil and water. A big unknown is the wetting nature of the two fluids.' Changing water properties to improve oil displacement has been done in the laboratory. When costs enter the picture, field tests are usually turned down. This is because picture, field tests are usually turned down. This is because reservoir rocks represent a huge surface area, and any product added to water to effect a wetting change would be product added to water to effect a wetting change would be absorbed on a small portion of this surface and all further benefit would be lost. However, there is another side to this argument. Water travels from high pressure pump to input wellbore in a few hours and on the way may contact 5,000 to 10,000 sq ft of a known surface. Those who have back-flowed input wells know that important water changes can take place during this short contact time. The trip from input to producing well takes months (or should), and millions of square feet of surface area are contacted. The nature of this surface is largely unknown and all sorts of water-rock equilibria are possible. Because of the large surface area involved, even the slightest reaction can be important, so that a purposeful, though minute, change in water properties can exert great influence on oil recovery. Greenwood County is the third largest secondary oil producing county in Kansas. Most production comes from producing county in Kansas. Most production comes from the Bartlesville sand, which was started under flood in the late 1940's. Secondary oil from the Bartlesville has averaged 90 bbl/acre-ft. Properties of the Bartlesville sand are shown in Table 2. Column 1 is the average of 12 successful water floods. Column 2 is the same data for the Moore-Holverson-Hill-Aagard (MHHA) unit after 4 years of development and operation. By any of the standard yardsticks, the project should be a marginal waterflood. Water saturations are high and oil in place is low. The reservoir is small and the permeability is only about one-tenth of that normally found. Primary recovery was also poor. Although data for all 12 projects are not available, poor. Although data for all 12 projects are not available, six of the 12 studied produced less than 20 bbls/acre-ft ahead of a producing water-oil ratio (field-wide) of 2. JPT P. 1119

Water flooding has focused attention on the problem of scale in producing wells. Four reasons why scale forms are discussed. A new theory which will help explain the severe scale build-up that occurs in many producing wells at the time of water breakthrough is presented. A recently developed family of scale preventives - the controlled solubility phosphates - are described chemically and physically. Factors which influence the performance of these unique phosphates in oilfield brines are evaluated in terms of laboratory test data. Case histories of producing wells treated with controlled solubility phosphates are summarized. The importance of bottom-hole temperature, the role of produced-fluid mineral characteristics and the value of knowing down-hole flow conditions are pointed out. Economic considerations well known to engineers and production men are used to compare the cost of conventional treatment and the cost of the new controlled solubility phosphate scale-prevention approach. Introduction General acceptance of the artificial water drive as a secondary producing mechanism for the recovery of oil has made many petroleum engineers and production men extremely "water conscious" during the last few years. Scale and corrosion problems of a type seldom encountered in primary production soon become evident as leases are placed under flood. In attempting to find solutions to these newly created problems, the oil industry has learned that standard municipal and industrial water-treatment practice is going to be of little value. The reason for this is that, until the oil industry started to emphasize water flooding and the conditioning of produced fluids, no one had ever attempted to make use of water of as poor quality as that now being handled by many secondary-recovery operators. The need for processing brines saturated with corrosive gases, scale-forming minerals and insidious microbiological growths has opened up a completely new field of water-conditioning technology. This paper deals with scale in oilfield brines. Factors which influence the formation of scale are discussed along with how petroleum engineers can get the most out of a unique family of chemicals which will effectively prevent scale.