Development and Testing of a Foam-Gel Technology to Improve Conformance of the Rangely CO2 Flood

Summary Thirty-six thousand four hundred barrels of CO2 gelled foam were successfully placed via an injector well into the Rangely Weber Sand Unit in Colorado. The treatment objectives were (1) to improve volumetric conformance in this CO2 flood by reducing excessive CO2 breakthrough through fractures, and (2) to increase oil recovery from the associated producers. Local reservoir characteristics indicate the need for a large-volume treatment to achieve these goals. The required treatment volume is beyond the economic limits of standard gel systems. Foam gel technology is one way to economically achieve in-depth conformance improvement at Rangely by replacing 60 to 80% of the liquid phase by the less expensive CO2 phase. A gelled foam system was specifically designed for application to Rangely conformance problems. The field-tested surfactant/gel system was designed according to the following criteria:to produce strong and robust gelled foams under the harsh pH conditions of a CO2 flood,to provide enough gelation delay to achieve the injection of a large foam volume with manageable injectivity reduction, andto considerably reduce the unit cost of the treatment fluid relative to standard non-foamed gel systems. This paper describes the methodology used to design and test the optimum gelled foam system for Rangely. Laboratory results are presented to support the chemicals system selection, including gelation kinetics experiments, surfactant selection, and corefloods with supercritical CO2 at field conditions. The candidate well selection process is described, including injection profile surveys, offset well response, and bypassed reserves calculation. Data taken during the injection phase of the program, including injectivity history and on-site quality control monitoring of the chemical system behavior, are given. Finally a preliminary assessment of the impact of the treatment on CO2 cycling rates and incremental oil production is presented. Introduction Oil recovery efficiency in CO2 floods can be substantially reduced if premature CO2 breakthrough occurs at offset producers through fractures. Injector polymer gel treatments have successfully improved volumetric sweep in some CO2 field projects.1 CO2 diversion from the fracture network to the adjacent matrix rock resulted in the recovery of additional oil reserves. However, the volume of injector polymer gel treatments can be limited by cost, which in turn limits the potential impact on reservoir sweep. If there is significant crossflow between the thief zone and the remainder of the reservoir, larger treatment volumes impact sweep over a large volume of the reservoir, thereby improving incremental oil recovery.2 Gelled foam technology is one way to economically increase the treatment volume when reservoir characteristics dictate the need for in-depth conformance improvement. Fluid costs can be substantially reduced if 60 to 80% of the expensive aqueous phase can be replaced by a cheap, readily available phase such as CO2 The major difference between gelled foams and aqueous foams is that, after some time, the liquid phase of the gelled foam gels, thereby greatly enhancing the mechanical stability of the foam lamellae network. Ideally the liquid phase of the gelled foam system will not gel during the injection phase. Thus the system behaves like a foam during injection, and, after gelling, it behaves like a gel by forming a flow barrier. Thus the treatment volume can be cost-effectively increased if the foam can be generated/propagated in the fracture network, the gelation of the liquid phase of the foam can be delayed, and the gelled foam can provide sufficient flow resistance to divert reservoir drive fluids. An additional benefit of CO2 entrained in the gel volume is that the system will be less dense than "traditional" gel treatments. This reduced density will make it easier to place the gelled foam where the less dense CO2 travels in the reservoir, i.e., in the upper regions of fractures or thief zones. Mechanistic studies of gelled foam for waterflood diversion have been conducted in etched glass micromodels.3,4 It was found that, below a critical pressure gradient, gelled foam barriers efficiently render porous media impermeable to gas or liquid flow. Above the critical pressure gradient, the gelled lenses rupture, creating a conductive path for the injected fluid. Although the gelled foam lamellae rupture, some of the gel debris remains in pore throats and continues to provide a resistance to flow. The critical pressure gradient depends on foam quality, gel strength, and rock permeability. Based on these preliminary results, a study was undertaken to develop a gelled foam conformance control system for field application. Rangely field was selected as the first target to test this technology. A miscible CO2 flood was initiated in the Rangely Weber Sand Unit in 1986. The field-wide performance of the CO2 project has been successful. However, excessive CO2 cycling through fractures has resulted in inadequate volumetric sweep in some areas of the field. Large-volume injector gel treatments (10,000 to 15,000 bbl) have been conducted, which were successful at improving CO2 utilization.5 However, the magnitude of the CO2 breakthrough problem in specific field areas justifies the placement of even larger slugs to significantly impact volumetric sweep. The successful implementation of a large-volume gelled foam treatment could result in reduced operating costs (OPEX) and increased ultimate recovery. In this paper we report results on the laboratory development of a CO2 gelled foam conformance control system and its performance in a field trial conducted in one Rangely field injector well. Field and Well Selection The Rangely field is located in Rio Blanco County, Colorado, U.S.A. It is the largest field in the Rocky Mountain region in terms of daily and cumulative oil production.