Conformance issues have plagued the SACROC miscible CO 2 flood for many years resulting in poor sweep efficiency and in some cases no sweep with CO 2 channeling between wells in major conduits within hours. These conformance problems have led to very high producing GOR's and CO 2 gross utilization ratios as well as significant amounts of by-passed pay and unprocessed reservoir volume. Conformance problems can be addressed in several ways which can be characterized as mechanical (in the wellbore), near wellbore, and/or in-depth treatments in the reservoir. All of these methods have been utilized with varying degrees of success at SACROC. Recently the most long-term success is with large volume gel polymer treatments which plug high permeability channels and conduits and divert injected CO 2 to unswept portions of the reservoir. These treatments generally involve injecting 20,000 barrels or more of polymer gel consisting of Chromium crosslinked medium and high molecular weight polyacrylate polymer. Gel concentrations typically increase from 5000 ppm at the start to as much as 12,000 ppm in the later stages. One of the keys to the success of these treatments is a final, tail-in stage of very high concentration polymer (> 30,000 ppm) or even cement in certain cases to prevent breakdown of the near wellbore gel when the well is returned to injection or production. These treatments have been implemented in project areas as a result of CO 2 early breakthrough and in project areas prior to CO 2 injection startup which has resulted in different degrees of success. This paper will discuss 1) candidate selection, 2) treatment design, 3) treatment timing, 4) discussion of results and 5) conclusions with future recommendations. In summary we have concluded that improving CO 2 utilization is most effective with large volume treatments. Additionally, maximum benefit is realized when the treatments are implemented prior to CO 2 injection in a new set of patterns.

Carbon Dioxide (CO2) has been used to enhance oil recovery for several decades in both miscible and immiscible floods depending on the type of oil and class of reservoir. Numerous CO2 floods are presently active in four countries with the majority in the Permian Basin of the U.S. where both naturally occurring CO2 and pipeline infrastructure exist and where over 50 million barrels of incremental oil per year are produced. Estimates indicate that additional billions of barrels of oil could be produced in the U.S. alone with CO2 flooding if CO2could be economically delivered to the producing states' oil fields. California has the second highest potential of any state to produce oil with CO2 flooding but has no naturally occurring deposits of CO2 or CO2 pipeline infrastructure. This paper presents the results of a study of the CO2 flood potential of California oil reservoirs and the possible sources of CO2 for California enhanced oil recovery projects. Introduction In President Bush's recently released National Energy Policy, the authors estimate there to be 60 billion barrels of oil (Bbo) remaining in existing U.S. oil fields which could be recovered using enhanced oil recovery (EOR)techniques.1 One such proven EOR technique is to inject CO2 into oil reservoirs, CO2 being an inexpensive solvent with a low minimum miscibility pressure (MMP) in oil. Oil recovery is enhanced when injected CO2 either displaces residual oil completely or decreases its viscosity and increases its volume and cycles through the reservoir, being produced with the oil, separated from it and re-injected. Laboratory experiments with CO2 and oil began over 50 years ago, the first field test was started in New York in 19492, the first full-scale flooding of an oil reservoir began in Oklahoma in 19583 and today seventy five floods are active in the U.S., Canada, Turkey and Trinidad.4 The two basic types of CO2 flood are miscible, where the CO2 acts as a true solvent and becomes one liquid phase with the oil, and immiscible, where the reservoir pressures are insufficient to reach miscibility.5 Most CO2 floods are of the miscible type where CO2 is either continuously injected or intermittently injected with alternating injections of water. (Fig. 1) Water alternating gas (WAG) floods, where CO2 and water are alternately injected in short or long duration cycles, or in unequal ratios over time, were developed to reduce channeling and early CO2breakthrough to producing wells. The major performance characteristics of CO2flooding are: up to an additional 8% to 16% of original oil in place (OOIP)can be produced as a result of miscible injection depending on reservoir depth and numerous other factors including peculiarities of the reservoirs and the oils they contain; most CO2 floods are preceded by water floods, and incremental oil production can be 20% to 30% of cumulative primary and secondary recovery; maximum CO2 flood oil recovery rate can be estimated to be the mature waterflood rate plus 10%of the water injection rate; the average net utilization of CO2 is 4 to 6 thousand cubic feet per barrel of oil (mcf/bo) produced and, average gross utilization, after accounting for recycling, is 8 to 15 mcf/bo. Ideal CO2 flood candidates are homogeneous oil reservoirs which are at depths greater than 2000 feet, produce oil of 25 API or higher, can attain reservoir pressures higher than MMP and have high oil saturations and no thief zones. Since the Permian Basin dominates in both the number of floods and incremental oil produced, most of the world's CO2 flooded reservoirs have been dolomites with low permeability. About a quarter of CO2 floods have been conducted in sandstones, with the remainder in limestones and siliceous carbonates. Reservoir and operational problems encountered in CO2 flooding include reservoir heterogeniety, fracturing and thief zones, lack of fault containment, gravity override, early CO2 breakthrough, equipment corrosion, under- and over-design of facilities, and high pressure equipment and personnel safety concerns.

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SPE Members Crosslinked polymer treatments are being implemented on both the injection and production-side in central Kansas to increase production-side in central Kansas to increase oil production and reduce water-oil ratios. In the past few years, Murfin Drilling Company has utilized these gel treatments and have had both successes and failures. This paper presents the results of two injection-side paper presents the results of two injection-side projects in the Lansing-Kansas City projects in the Lansing-Kansas City formation and four producing-side treatments in the Arbuckle formation from an independent oil operator's point of view. The Lansing-Kansas City formation is a sequence of limestone reservoirs separated by shales. When these reservoirs are simultaneously waterflooded, usually the highest permeability zone takes the majority of the brine, causing poor sweep efficiency in the waterflood. Injection of gelled polymners can plug these high permeability polymners can plug these high permeability zones thus increasing the waterflood sweep efficiency. Results from two projects in Decatur and Graham Counties will be discussed. The Arbuckle formation is typically a dolimitic limestone reservoir underlain by bottom water. Water coning usually occurs due to gradients in flow potential established around the wellbore by oil production. If vertical permeability exists, production. If vertical permeability exists, this difference in flow potential causes mobile water to flow into the wellbore. Gelled polymer treatments can reduce the permeability to this mobile water, thus permeability to this mobile water, thus reducing the producing water-oil ratio., Typically, a sharp decrease in WOR is noted immediately following a treatment. This decrease is followed by an increasing WOR AS the oil production gradually resumes its normal decline. Four treatments conducted in Ellis, Graham, and Rooks Counties Bill be discussed. P. 941

This paper describes the development of the Kansas Technology Transfer Model (KTTM) which is proposed as a regional model for the development of other technology-transfer programs for independent operators throughout other oil producing regions in the United States. The KTTM is an expansion and adaptation of the University of Kansas Tertiary Oil Recovery Project (TORP) concept of oilfield technology transfer to independent oil producers. The KTTM is the product of a grant from the United States Department of Energy (DOE) in August 1992 to the Kansas University Energy Research Center to develop a technology transfer model which could be utilized nationwide. The focus of the KTTM is to assist in reducing the rate of well abandonment in the near term and to increase oil recovery using conventional technology. Included is the linkage of the regional model with the national technology transfer plan, and the methodology to adapt the model on a regional basis. The technology transfer plan also includes an evaluation technique to measure the process.