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You must log in to edit PetroWiki. Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. The carbon dioxide gas is injected and alternated with water. CO2 lowers the viscosity of most oils, but may trigger severe asphaltene and scale precipitates.
When conducting a polymer waterflood, a high-molecular-weight and viscosity-enhancing polymer is added to the water of the waterflood to decrease the mobility of the flood water and, as a consequence, improve the sweep efficiency of the waterflood. The primary purpose of adding polymer to most polymer waterfloods is to increase the viscosity of the flood water; however, polymer addition to the flood water in many instances also imparts a secondary permeability-reduction component. Polymer waterflooding is normally applied when the waterflood mobility ratio is high or the heterogeneity of the reservoir is high. Figure 1 shows the polymer waterflooding process. The method shown requires a preflush to condition the reservoir, the injection of a polymer solution for mobility control to minimize channeling, and a driving fluid (water) to move the polymer solution and resulting oil bank to production wells. Mobility ratio is improved and flow through more permeable channels is reduced, resulting in increased volumetric sweep. Waterflooding promotes improved sweep efficiency by improving the mobility ratio. Improved sweep efficiency imparted during polymer flooding is primarily accomplished by increasing the viscosity of the waterflood drive fluid.
This field produces from a structure that lies above a deep-seated salt dome (salt has been penetrated at 9,000 ft) and has moderate fault density. A large north/south trending fault divides the field into east and west areas. There is hydraulic communication across the fault. Sands were deposited in aeolian, fluvial, and deltaic environments made up primarily of a meandering, distributary flood plain. Reservoirs are moderate to well sorted; grains are fine to very fine with some interbedded shales. There are 21 mapped producing zones separated by shales within the field but in pressure communication outside the productive limits of the field. The original oil column was 400 ft thick and had an associated gas cap one-third the size of the original oil column. Porosity averages 30%, and permeability varies from 10 to 1500 md.
Although conformance-improvement gel treatments have existed for a number of decades, their widespread use has only begun to emerge. Early oilfield gels tended to be stable and function well during testing and evaluation in the laboratory, but failed to be stable and to function downhole as intended because they lacked robust chemistries. Also, because of a lack of modern technology, many reservoir and flooding conformance problems were not understood, correctly depicted, or properly diagnosed. In addition, numerous individuals and organizations tended to make excessive claims about what early oilfield gel technologies could and would do. The success rate of these gel treatments was low and conducting such treatments was considered high risk. As a result, conformance-improvement gel technologies developed a somewhat bad reputation in the industry. Only recently has this reputation begun to improve. The information presented in this chapter can help petroleum engineers evaluate oilfield conformance gels and their field application on the basis of well-founded-scientific, sound-engineering, and field-performance merits.
Included are applications of foam for mobility control and for blocking gas. In 1989, Hirasaki reviewed early steam-foam-drive projects. In 1996, Patzek reviewed the performance of seven steam-foam pilots conducted in California. Early and delayed production responses were discussed for these pilots. Gauglitz et al. review a steam-foam trial conducted at the Midway-Sunset field of California.
Bulk foam, as found in the head of a glass of beer or as found in association with cleaning solutions, is a metastable dispersion of a relatively large volume gas in a continuous liquid phase that constitutes a relatively small volume of the foam. An alternate definition of bulk foam is an "agglomeration of gas bubbles separated from each other by thin liquid films." In bulk form, such as in oilfield surface facilities and piping, foams are formed when gas contacts a liquid in the presence of mechanical agitation. As used herein, bulk foams are foams that exist in a container (e.g., a bottle or pipe) for which the volume of the container is much larger than the size of the individual foam gas bubbles. Capillary processes control the formation and properties of foams in porous media.
Currently, the three major applications of conformance improvement oilfield foams are as a mobility control agent during steamflooding, a mobility-control agent during CO2 flooding, and gas blocking/plugging agents placed around production wells, often applied in conjunction with a gas flooding project. Although the use of foams for oil-recovery applications has been actively considered and studied for more than forty years, widespread application of foams for improving oil recovery has not occurred to date. In the pioneering work of the late 1950s and through the early 1970s, foam was identified to be a promising candidate for improving mobility control and sweep efficiency of oil-recovery drive fluids, especially gas-drive fluids. These early workers also noted that oil in porous media often tends to destabilize most aqueous foams and tends to harm oilfield foam performance. A number of the earliest oil industry proponents of the use of foam hoped that foams would eventually lead to routine "air flooding" of reservoirs.
This page provides a brief review of illustrative field applications of polymer waterflooding as reported in the literature. In 1983, Manning et al. published a comprehensive and classic summary of the field results and performance of more than 250 polymer waterflooding projects and provided information relating to the early field applications of polymer waterflooding. Figure 1 shows the incremental oil production response for the North Burbank polymer flood. A polymer waterflooding project that involved a large full-field flooding project at the North Oregon Basin field in Wyoming's mature Big Horn Basin oil-producing area was reported in 1986 to be producing 2,550 BOPD of incremental oil production. It was reported that this polymer flooding project would recover ultimately more than 10 million bbl of incremental reserves from the mature North Oregon Basin field. The field project involved the flooding of both a fractured carbonate formation and a fractured sandstone formation with a polymer flood using partially hydrolyzed polyacrylamide(HPAM).
This page provides SPE members access to the June 2021 issue -- digital, pdf, and online. Digital archive of issues back to January 2020 is available – scroll down from the current issue cover. These are the papers synopsized in JPT this month. They are available to SPE members only through 31 July 2021. There are also links to them at the bottom of each related synopsis.