During the last 15 years, polymer gels have become an accepted technology for improving volumetric sweep efficiency in heterogeneous waterfloods. Water injected subsequent to the gel treatment ideally enters previously unswept zones with significant mobile oil saturation. Results from several field projects in four hydrocarbon basins in Argentina and Venezuela are described based on the application of two available polymer gel technologies: Marcit and Unogel. The types of reservoirs and reservoir conditions where polymer gels have been successful, and unsuccessful, are illustrated. Fundamental reservoir rock and fluid characteristics, reservoir temperatures, polymer gel designs, and project evaluation are presented for each of the field projects. A high temperature (275ºF) reservoir is included. In multi-layered reservoirs where crossflow is believed to be limited, one strategy is to inject a small gel volume in order to improve the vertical profile in the near wellbore region. If crossflow is believed to exist between layers or within a layer, signficant gel volumes are recommended for deeper placement in the offending zones so that water cannot easily bypass the gel treatment. Gel formulation is a fundmental issue. Traditionally, minimum polymer concentrations of at least 3000 ppm have been recommended for injection well gel treatments. Lower polymer concentrations were believed to be ineffective. A large scale and ongoing field project is presented in which low concentration polymer gels have been successful. In the same field project, the results of multiple gel treatments in the same injection well are discussed. Introduction This paper will summarize polymer gel applications in three basins in Argentina and the Lake Maracaibo basin in Venezuela (Figure 1 and 2), using two of the most widely applied polymer gel technologies: Marcit[1] and Unogel.[2] Several of the case studies presented in the following paragraphs included extensive pre-treatment diagnostics. Due to the space limitations, those procedures are not discussed in detail. Marathon's patented Marcit gel technology was developed for application in naturally fractured reservoirs and was first applied in the Tensleep and Phosphoria reservoirs of northwest Wyoming. The Unogel technology was developed and patented by Union Oil Company of California (Unocal), primarily for use in high temperature (>250ºF) reservoirs. Although somewhat less versatile than the Marcit gels, Unogel has shown promise in high temperature reservoir applications. Both Marcit and Unogel gelants are typically formulated using a partially hydrolyzed polyacrylamide polymer (PHPA). The primary difference lies in the crosslinking mechanism. Marcit gels are crosslinked with a metal ion (Chromium III) while the Unogel technology requires an organic crosslinker and a stabilizing agent for delayed gelation. Although polymer gels evolved from the application of polymers for mobility control, gel treatments are not designed to improve an adverse mobility ratio. One of the primary criteria for polymer gel applications are reservoirs with low oil recovery efficiency and, in many cases, such reservoirs exhibit an adverse mobility ratio. However, the primary objective of any polymer gel treatment is selective permeability reduction due to reservoir heterogeneity. Oil viscosity is not, in itself, an important consideration for well selection or treatment design.
From April through August of 2009, seven producing wells in the Spring Creek field in the Bighorn Basin of Wyoming were treated with chromium acetate crosslinked polyacrylamide in an attempt to reduce water production, lower fluid levels and achieve more drawdown, resulting in improved oil production. The wells were chosen because of their high productivity, high water cut, suboptimal operation because of pump limitations, and in some cases, marginal economics. The volume of the gel treatments, which were pumped through tubing with a packer above the productive formations, ranged from 8000 bbls to 11,500 bbls depending on the theoretical maximum productivity of each well when pumped off. The Spring Creek field produces out of the fractured Tensleep sandstone, and the fractured Phosphoria carbonate. The main drive mechanism is bottom water, but reinjection of produced water contributes to some reservoir sweep. After the seven wells were aggressively treated and returned to production, water rates were reduced by 72%, unfortunately oil rates were reduced by 56%. Following the treatments, however, the total oil production for the areas surrounding the treated wells had increased. It is believed that the increase in oil production is attributed to the diversion of the drive water to other unswept parts of the reservoir with higher oil saturation. The large size of the treatments and extent of penetration through the fractures played a significant role in accomplishing this diversion. In similar wells treated with a smaller volume of gel, water reduction was not as significant, oil loss was not as great, and the increase in area oil production and added reserves was not as observable. This paper quantifies the favorable effects and economics of this larger more aggressive gel treatment strategy.
In December 2003, a pilot polymer gel treatment was implemented in the Vizcacheras Field located in Western Argentina's Cuyo Basin. The project included one injection well polymer treatment with the primary objective of improving volumetric sweep efficiency in the subject pattern and, consequently, improving oil recovery. A secondary goal was to reduce water production in the offset producers. The Vizcacheras Field is a mature waterflood that was discovered in 1965. Upon implementation of the polymer gel pilot in December 2003, field production was 8635 BOPD from 162 producing wells with an average water cut of 96%. The production comes from two heterogeneous fluvial sandstone formations: Papagayos and Barrancas. Approximately 31% of the total oil production comes from the Barrancas formation, the target of this project. This conformance improvement project began in 2002 with laboratory studies, initial polymer gel treatment design, tracer studies and numerical simulation. The gel chemistry included a medium molecular weight, partially hydrolyzed anionic polyacrylamide polymer crosslinked with chromium acetate. After a monitoring period, positive results were observed in five of twelve offset producers and an expansion project was designed. The following paragraphs will describe the petrophysical characteristics of the Barrancas formation, including an overview of the field production and waterflood history, as well as the design, implementation, and evaluation of the polymer gel pilot project. Introduction The Vizcacheras Field is part of a larger block of the same name located in the southeastern region of Cuyo Basin in the province of Mendoza, Argentina. The western boundary of the field is the La Ventana Area and the northern boundary is the West Zampal Area (Figure 1). The field includes two primary reservoirs: the Barrancas formation and the Papagayos formation. As of November 2005, the total field production was 9,140 BOPD (1,453 m3/d) at an average water cut of 96.1%. Cumulative oil production at that date was 331 MMBLS (52.7 MMm3). Objective In December of 2003, a water conformance pilot was performed in the Barrancas formation. The Barrancas formation discovery well was the LJx-1 drilled in 1962, although initial oil production did not occur until mid-1966. The project objective was to reduce injectivity in the high permeability layers ("thief zones") between the injection wells and the associated producing wells, thereby diverting injected water into unswept rock. If successful, the pilot was expected to include several benefits:Improved volumetric (vertical and areal) sweep efficiency in the injector-producer pattern;Increased oil recovery factor due to incremental oil production;Reduced water injection volumes and, consequently, less water production.
Excessive water production from the Monterey Formation of the Sockeye Field offshore Santa Barbara, California led the operator to consider polymer gel water shutoff treatments. Field water rates were approaching the limit of the platform water handling capacity and threatened to curtail future development and/or require a multi-million dollar facility expansion. By utilizing chromium crosslinked polyacrylamide gel technology, the operator significantly reduced the water production. However, after gel treatments were injected and the wells were returned to service, both water and oil production were significantly lower. The operator subsequently stimulated the wells with acid and saw significant increases in oil rates while maintaining a reduction in water production.The result of combining the water shutoff treatments with the stimulation was a lowered water production rate and increased oil rate that neither technique would have yielded on its own. At this time, four wells have been treated with both gel and acid and one has been treated with gel alone. Of the four treated with gel and acid, three had reduced water rates and three had increased oil rates. Moreover, all gel treatments were pumped down production tubing without the need of a rig, using the vendor's self-contained trailer that included all mixing and pumping equipment. While not specifically designed for offshore use, this equipment greatly simplified logistics and the total cost was low enough that the economics could be based solely on savings in water handling costs.
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