Foamed oil emulsions can exhibit significant increases in apparent viscosity due to the entrainment of gas bubbles in the oil. Crude asphaltic components act as natural foaming and emulsifying agents. Their influence causes a large portion of the dissolved gas, which would otherwise be liberated as free gas, to remain entrapped in the water-in-oil emulsion as small bubbles. Such in-situ generation of foamy oil emulsions in the vicinity of the wellbore can have a profound effect on well productivity. This type of formation damage has been found to be fairly common in low gravity oil reservoirs where steamflooding or steam stimulation is used to enhance oil recovery. A novel well stimulation technique, applying a blend of defoaming and demulsifying surface active agents with a bullhead squeezing technique, has proven to be successful in the Cymric and McKittrick fields, California. The cost of incremental oil gained is less than $1.00 per barrel. Introduction Foams have been widely used in petroleum engineering applications for drilling, well stimulation, and sweep efficiency improvement in steam and CO2 enhanced oil recovery processes. In these applications, the foam reduces fluid mobility because of its high apparent viscosity and pore blocking ability. Similarly, indigenous foam resulting from liberation of dissolved gas from oil as it is being produced manifests itself as a kind of formation damage, i.e., a combined foam and emulsion block. All crude oils foam to some degree upon being degassed. Foams from light crudes usually disperse quickly in a few seconds. In contrast, heavy oil foams can be very stable and may persist for several hours. This is observed in wellhead samples from steamflood wells in the San Joaquin Valley, California. Figure 1 highlights heavy oil steamflood fields in the San Joaquin Valley. Heavy oil is produced in the form of a foamy emulsion, having the appearance and consistency of chocolate mousse. Such foamy behavior has also been observed in the heavy oil wells of Alberta and Saskatchewan producing under solution gas drive. Stable oil foams can cause problems in separation equipment, such as liquid carry over into gas lines and serious asphaltene plugging problems in separators and oil and gas lines. For example, production problems have been reported in gas processing equipment in the Jusepin plant in El Furrial field, Venezuela (22 to 33 API crude, containing 1 to 13% asphaltenes) and in the Sullom Voe Terminal in Shetland, U.K., processing Ninian and Brent crudes (37 API). Heavy oils contain relatively little dissolved gas, but their foamy emulsions can sometimes reduce pump efficiency. For this reason, a downhole defoamer treatment apparatus using a hollow sucker rod was first used in 1970. Up to now, formation damage caused by foam blockage has received little attention as a potential production problem. The intent of this paper is to identify the occurrence of foamy oil emulsions in heavy oil reservoirs and possible consequences and impact on oil recovery. Attention is especially drawn to the asphaltic fractions of the oil and their role in bubble formation. Experimental verification of in-situ foam formation under steamflooding conditions is presented. Also discussed is an inexpensive stimulation technique which can be used to enhance heavy oil production in thermal wells. Causes of Formation Damage It is well established that viscous emulsions of oil and water in the formation near the wellbore can drastically reduce the productivity of oil or gas wells. However, relatively little is known about oil-continuous foams or oil-continuous emulsions containing both water droplets and gas bubbles. P. 461

This papef was weparod for preww!tatlon al the Western fleglonal Meeting held m Anchorage, Alaska, 22-24 May 1996 This papa was saiecfed fof presentation by the SPE Program Commifee following revmw of mfomwdlon contamad m an abstract submrited by the auth-m(s) Contents of the pap-af as prasented have not been rewewsd by the Soc)ety of Petroleum Engmaers and are subpct to cmrredon by the author(s) The material, as pfesented, dorn not necemsar!ly rolled any pawilon of the S0c4ety O! Petroleum Engineers or !k merrbbrs Papers presented at SPE meadqs are s.bjti to pubhcatmn rewew by Edtloual Comm!ttee cdthe SoGIety of Petroleum Engmeem Permuston !O CWY IS restrlctd to an abstract of not more than 300 words Illustrations may not be copmd Tha abstraci should contain conspmuous acknowkdgmeni of where and by whom the p+e was presented Wr!le Lbranan SPE, P O 8332836 Richardson. TX 76063-3936 USA, fax 01.214.9S2+435 Abstract

This paper was selected for presentation by an SPE ProgramCommittee following review of information contained in an abstract submhtad by the author(a), Conlenta of the papar, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(a), The material, as presented, clefs not necessarily reflect any position of the Seciaty of Petroleum Engineers, its officers, or members Papara presented at SPE meetings are auwect to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distributmn, or storage of any part of this pap%r for commercial purposes without the witten consent of the Seciety of Petroleum Engineers ia prohibited, Permission to reproduca in print IS restricted to an abatract of not more than 300 words illustrations may not be copied, The abstract must contain conspicuous acknowledgment of tiere and by whom the paper was presented Write Librarian, SPE, P.O. Box 833836. Richardson. TX 75063.3636. U. S.A.. fax 01-972-952.9435. AbstractSteam injection is the most common thermal oil recovery process. It has been used extensively in California heavy oil fields. Uniform steam distribution in multiple-zone, long completion interval, injection wells is extremely difficult to achieve. Consequently, many sands are not effectively heated and produced. Mechanical means for controlling injected fluid are often needed when using a single wellbore. Several techniques have been developed to deal with the steam distribution problem, e.g., concentric injection, limited-entry perforations, dual string injection, and slim-hole injection wells. These techniques have had varying degrees of success.Dual string injection normally separates injected steam into individual zones by using tandem isolation packers. A modification of this design, utilizing a downhole flow splitter, eliminates the need for packers and maintains effective vertical coverage. This paper emphasizes the present design which can provide an economically attractive alternative to the traditional dual string injection and open-ended tubing in cyclic steam stimulation. In addition, the role of foamy oil expansion drive, an important recovery mechanism in the steam injection process, on profile controlling optimization will be discussed.

The economics of a steamflood project are largely dependent upon the rates at which steam is injected and oil is recovered. One of the dominant features of the steam drive process is the tendency of steam to override the reservoir and break through in the producing wells. To accommodate this situation, engineers are challenged to achieve the balance between production of heated oil and by-passed steam. A significant effort is being made to overcome this difficulty with the aid of a by-product gas tracer, carbon dioxide. The isotopic signatures of this non-condensable gas can be used to predict the changes in reservoir dynamics resulting from the reaction of reservoir rock and fluids with injected steam. Steam-enhanced oil recovery often produces large quantities of CO2. Two primary sources are oil derived CO2 and CO2 associated with injected steam. These two distinct sources can be differentiated by the carbon isotopic composition of the CO2. The CO2 generated from oil tends to be depleted in the heavy isotope of carbon, 13C, while water-derived CO2 is enriched in 13C. Results of isotope analyses of CO2 from the Cymric field steamflood show that CO2 in good flood response wells is primarily derived from oil and CO2 in steam breakthrough wells is mainly water/mineral derived. These results suggest that carbon isotopes of CO2 are useful natural tracers for its origin and may be used as a diagnostic and possibly predictive reservoir management tool for monitoring steamflood performance.

No abstract