Injection Conformance Control Case Histories Using Gels at the Wertz Field CO2 Tertiary Flood in Wyoming

Abstract

SPE Member Abstract Case histories described in this paper demonstrate the technical and economic value of using a specific work process coupled with advances in gel technology to improve vertical and areal injection fluid distribution at the Wertz Field carbon dioxide (CO2) Tertiary Flood in Bairoil, Wyoming. The Wertzcase histories incorporate results from ten injection well gel conformance workover repairs with fluid performance response at offset producing wells. Post appraisal findings confirmed individual pattern life for tertiary processing was extended by nearly two years resulting in incremental oil recoveries of up to 140,000 barrels per pattern. Introduction The Wertz Tensleep waterflood was developed during 1980 and tertiary recovery was implemented during 1986. Until patented advances in gel technology developed by Marathon Oil Company were released for oil and gas industry use during 1991, typical workovers for controlling vertical and area injection fluid distribution (conformance) were limited to near-wellbore techniques. Most commonly used were low cost sandback operations at $4,000 per treatment and higher cost cement work at $35,000 per repair. Injection profiles often confirmed both methods achieved success for lower zone near-wellbore injection control. However, even the best designed sand and cement work were occasionally rendered ineffective because of behind-pipe channeling between perforation intervals. In addition, neither sand nor cement techniques offered an effective way to repair middle and upper zone injection conformance. Hence the need for an advanced method of injection conformance control. Liquid alpha olefin sulfonate surfactant foam work offered the first step to advancing Wertz injection conformance. These repairs averaged $35,000 per treatment and proved to be a technically viable alternative for temporarily controlling lower, middle, and upper zone injection conformance. Once the surfactant was in place, an in-situ foam was generated for injection fluid diversion. However, only short term and nonpermanent injection conformance control was realized. Foam diversion longevity was reduced considerably when natural fractures were present. By definition, the Wertz Tensleep sandstone is an eolian deposit with a gross thickness of about 470 feet. It has nearly 240 feet of net pay that has an average 10 percent porosity, 13 millidarcy permeability, and some natural fractures. The latter condition makes injection conformance control using foam very difficult, and produces a need for a different workover method. A specific work process and acrylamide-polymer/chromium(III)-carboxylate gel technology offered the next step for improved Wertz injection conformance control. WORK PROCESS ANALYSIS The macro work process analysis map shown in Figure 1 offers one basic engineering approach to identifying candidates for workover repair, which assists with continually improving Wertz Tensleep injection well conformance. For publication, the structure of this map has been intentionally limited in detail and does not show virtually hundreds of minor work process sub-steps contained within each major step. The map also deliberately shows preference for injection over producing well conformance repairs. While some producing well conformance work is necessary, actual experience shows injection well repairs result in the largest incremental reserve impact for extending the economic life of the Wertz Tensleep tertiary operation. P. 469^

Comprehensive Review of Fracture Control for Conformance Improvement in the Kuparuk River Unit - Alaska

“…This also matches what others have seen from fracture control with High MW crosslinked HPAM Gel, as is documented in the following literature. (Borling 1994, Lantz et al 2014, O'Brien et.al. 2007, Pipes et al 2014, Seright 1999, 2000, Sydansk et al 2004, and Vasquez et.…”

Aperture-Tolerant, Chemical-Based Methods to Reduce Channeling

“…In naturally fractured reservoirs, large volumes of Cr(III)-acetate-HPAM gels have been successfully extruded into place to reduce channeling and excess water production. 67,[69][70][71] During gel placement in fractures, the pressure gradient for gel extrusion depends strongly on fracture width and gel composition. 23,72,73 Extrusion experiments directly measure gel properties in fractures, but they are both expensive (for core materials and casting) and time-consuming (two to three days per experiment, with one to two weeks of setup time).…”

“…In contrast, when applied to wells of matrix rock reservoirs involving radial flow, conventional (relatively strong and total-fluid-shutoff) polymer-gel WSO treatments normally require the use of mechanical zone isolation during treatment placement. 70 Mechanical zone isolation often requires costly workover operations. In addition, the use of mechanical zone isolation during water-shutoff-treatment placement is normally not feasible when the well possesses a slottedliner or gravel-pack completion or when the well involves a sub-sea tieback flow line.…”

Using Chemicals to Optimize Conformance Control in Fractured Reservoirs

“…However, after gelant injection stops, even a small density difference ( e g , 1%) between the gelant and the displaced reservoir fluids allows gravity to rapidly drain gelant from at least part of the Generally, gelation times cannot be controlled well enough to prevent gravity segregation between gelant injection and gelation. [31][32][33][34][35][36][37] Alternative to conventional gelant treatments, fonned gels can be extruded into fractures. Since these gels are lo3 to lo6 times mores viscous than gelants,39 gravity segregation is much less important than for gelants.…”