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Summary A CO2 stimulation process has been designed for heavy-oilreservoirs. The process will be applied by Aminoil U.S.A. in their North Bolsa Strip lease of the Huntington Beach field. High oil viscosity (177 cp) and severe faulting have caused poor performance in early attemptsto waterflood this reservoir. Each producing well is to be treated with 2 to 10 tons of CO2 per foot of net pay. Gases produced are separated cryogenically to produce saleable hydrocarbons and reusable CO2. The processing also eliminates possible emissions that might affect air quality. CO2 is reinjected to improve economics. Introduction Work in the early 1950's by Jersey Production Researchco., Pure Oil CO., and Oil Recovery Corp. identified the potential for using CO2 as an enhanced oil-recovery agent. However, during those early years, the cost of CO2 usually was greater than the price of crude oil, and there was no incentive to commercialize the process. The escalation of incentives, both economic and political, during 1979-80 prompted Aminoil to examinethe possibilities of using CO2 to enhance the recovery of petroleum. It is well recognized that CO2 used to displace oil under miscible conditions represents the ultimate inreducing residual oil saturation in the swept portion ofthe reservoir. Residual oil saturations as low as 5% areobtained easily in the laboratory. Intuitively, recovering most of the oil in the swept region should bethe ultimate goal of a recovery process. Hence, most of the developmental work in the past decade was focused on laboratory and field demonstrations of the miscibledisplacement process. The pioneering effort of Chevronand others at Sacroc, the first commercial CO2 application, represents a significant advance in the art. Because of the great diversity with respect to crudeoil properties and reservoir depth, there are many reservoirs, mostly viscous oil, not amenable to the miscibledisplacement process. The same high incentives apply tothese reservoirs, and this has given rise to rapidly expanding laboratory and field programs to enhance oilrecovery by CO2 under immiscible conditions. The results of these studies on immiscible displacement of viscous crudes have been enlightening. Although immiscible CO2 flooding cannot reduce the residual oil saturation significantly, many candidate reservoirs contain such high initial oil saturations that total recovery-barrels of oil transferred from the reservoir to the stock tank-can exceed the high recoveriesthat characterize the miscible process. The work ofBeeson and Ortl off involving linear laboratory cores demonstrated that the total barrels of oil recovered incremently over waterflood as well as the barrels of oil recovered per thousand cubic feet of CO2 injected were comparable for the two processes. Recent laboratory experiments seem to confirm these earlier results, and at least two companies, Phillips and Champlin Petroleum, are operating field projects involving immiscible CO2flooding. Considering the outstanding success of the huff'n'puff single-well steam stimulation process, it seemed possible that similar technology could be successful with CO2. Preliminary field experiments supported by computer simulation show that, under optimal conditions, single-well stimulation with CO2 may indeed be commercial. The profitable range of oil saturations and viscosity aremore limited than for steam, and, hence, the successratio is expected to be lower. More selectivity and better engineering are necessary to achieve an attractive payout of the higher investment associated with the CO2 process. JPT P. 1805^

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Fluid loss control is often a consideration, if not a major engineering exercise, for a wellbore workover or completion operation. When the mix includes high bottom hole wellbore temperature, high reservoir pore pressure and high reservoir permeability and porosity, then the well killing operation can become very complicated. For these reasons many operations include mechanical means of fluid loss control, thereby achieving positive well control for a long period of time without the worry of reservoir damage by fluid invasion and kill fluid byproducts. However, there are some instances, such as tripping drill pipe or tubing in or out of a well, that mechanical tools are not applicable. Enter chemical fluid loss control. Often referred to as "fluid loss pills," chemical fluid loss control has been associated with everything from shredded newspapers to the latest biopolymers, which may carry carefully engineered bridging solids. While completion operations will hopefully not use bridging solids usually reserved for lost circulation while drilling, the point is that just about everything at hand on a rig location or in a laboratory has been tried as a fluid loss control agent. For most of these chemical fluid loss pills, the upper limit of endurance is 275°F (135°C), which is the melting point of processed starch commonly found in fluid loss pills. Also, most commercially available fluid loss pills lose temperature stability as fluid density is increased with water soluble salts. A new fluid loss control pill has been designed to provide effective fluid loss control for 24 hours at 300°F (149°C) in a fluid density up to 12.5 pounds per gallon (1.50 specific gravity). Introduction The emphasis placed on fluid loss control can range from no real concern whatsoever to a major engineering exercise requiring laboratory filtration measurements on actual cores under simulated reservoir conditions, then making return permeability measurements. One important driver in the amount of consideration given to fluid loss control is the location of the well, be it onshore or offshore. Offshore completions get a lot of attention because of safety regulations that mandate a full fluid column in the casing and tubing during the completion, and typical complexity of deviated, high permeability, multi-zone and sometimes multi-lateral wellbores. In an offshore environment you also have to factor in the value of rig time should fluid losses delay the completion process. Additional important factors are the reservoir properties, such as permeability, pressure and temperature. Traditional fluid loss control is achieved by one or more of the following:placing a very high viscosity polymer "pill", either cross linked or linear, across the fluid loss zone, 1, 2 orplacing a "pill" across the fluid loss interval that builds an external and/or internal filter cake.3 Though cross linked cellulose derivatives are gaining popularity, historically, the brunt of viscosity-controlled fluid loss control needs have been placed on the shoulders of linear HEC. Regarding the creation of external and internal filter cake for fluid loss control, the 1990's saw the introduction of specially engineered calcium carbonate bridging solids conveyed with a biopolymer/starch blend that has been coined a "drill-in fluid".4 The drill-in fluids are amongst the most efficient fluid loss control fluids in the oilfield, however, they are usually reserved for open hole completions due to the fear of acid wormholing through the filter cakes in perforations during typical acid cleanup treatments. A recent shift in well completion methodology in the Middle East has brought to light a void in effective fluid loss control for high pressure, hot and highly permeable wells. All these parameters can be relative terms, with different individuals defining their own standards according to what they are familiar with. Work has been done to meet a specific need in a 300–315°F (149–157°C) sandstone reservoir having natural fractures.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe oil industry has long been concerned about the effect of acidizing wells when prepacked screens containing resin coated sand are employed for sand control purposes. Fears of unconsolidating the prepack material have often led to no acid being pumped, or small volumes that are potentially ineffective at removing deep reservoir damage. Previous compatibility tests have been performed at static conditions, where a cured resin coated gravel plug was immersed into hydrochloric and/or HCl:HF acids, and then crushed to see if any resin was removed or weakened compared to an unexposed core plug. These tests were never conducted in a dynamic condition using actual prepacked screen models until now.Laboratory tests were performed on several prepacked screens containing either 20-40 or 40-60 U.S. mesh-cured, resincoated gravel. The types of prepacks tested were dual-screen, single-screen, and Slim-Pak™ screen designs. The objectives of the tests were to determine whether the resin-coated gravel was damaged during the acidizing phase of a gravel-pack completion and to compare the pressure drop in the prepacks. Initially, a baseline was established showing pressure drops at various flow rates while circulating 3% ammonium chloride (NH 4 Cl) brine through the system without a prepacked screen. After placing a prepack in the test fixture, a baseline was established for each prepack screen with 3% NH 4 Cl at 1, 2, 5, 10, and 21 gallons per minute. Prepacks were acidized with 50 gallons per foot 10% hydrochloric acid (HCl) followed by 100 gal/ft of 7½ HCl and 1½ hydrofluoric acid (HF); then 200 gal/ft 3% NH 4 Cl.Continuous flow rate and differential pressure were recorded using a strip chart recorder connected to a turbine flow meter and a differential-pressure transducer.Each test was duplicated to verify reproducibility. After testing, each screen was cut open so that the resin-coated gravel could be examined.