SPE 169734 Polymer-Alternating-Gas Simulation—A Case Study

Carbon dioxide has been used commercially to recover oil from reservoirs for more than 40 years. Currently, CO2 flooding is the second most applied enhanced oil recovery (EOR) process in the world behind steam flooding. Water alternating gas (WAG) injection has been a popular method to control mobility and improve volumetric sweep efficiency for CO2 flooding. Average EOR is about 9.7% with a range between 6 and 20% for miscible WAG injection. Despite all the success of WAG injection, sweep efficiency during CO2 flooding is a typical challenge to reach higher oil recovery. We applied polymer-alternating-gas (PAG), in which polymer flooding is combined with miscible CO2 injection, to improve the volumetric sweep efficiency of the WAG process in TR78 of the North Burbank Unit. High heterogeneity and high permeability at the top layers are the two main challenges of the North Burbank Unit. Then, we compared PAG performance with WAG and continuous gas injection (CGI). Polymer concentration and injection slug patterns were optimized during the PAG process. Simulation results show that PAG would increase oil recovery about 14.3% compared with 7.3% for WAG in TR78. This study can not only be used to guide the development of the North Burbank Unit, but also to demonstrate that encouraging recovery can be obtained in high-heterogeneity reservoirs by using PAG. Introduction Worldwide oil production in 2009 was about 31.4 billion bbl, with 3.5% (1.1 billion bbl) of crude oil from EOR (Cabrera and Manrique 2010). Chemical and thermal methods represent 60 to 70% of worldwide EOR production, and gas flooding represents up to 32% of total EOR production. According to the 2012 Worldwide EOR survey (Koottungal 2012), production from US miscible CO2 flooding surpasses the production from steam flooding. Although CO2 flooding is a well-established EOR technique, its density and viscosity nature is a challenge of CO2 projects. Low density (0.5 to 0.8 g/cm 3 ) causes gas to rise upward in reservoirs and bypass many lower portions of the reservoir. Low viscosity (0.02 to 0.08 cp) would lead to poor volumetric sweep efficiency. In heterogeneous reservoirs with highpermeability zones and natural fractures, the condition is even worse (Zhang et al. 2010). The following methods have been studied to improve CO2 flooding performance. WAG. Almost all commercial miscible gas injection projects use WAG to control mobility of gas and alleviate fingering problems. Recovery of WAG is better than gas injection alone, and 80% of commercial WAG projects in the US are economic (Christensen et al. 1998). However, recent studies show that most of the fields could not reach the excepted recovery factor from the WAG process, especially for reservoirs with high-permeability zones or there are naturally fractured (Christensen et al. 2001). Gel. Gel application is considered the most aggressive type of conformance control. Gel acts as a blocking agent to reduce channeling through fractures or high-permeability zones of reservoirs (Ali and Schechter 2013). The most applied gel system in the oil industry for conformance control is hydrolyzed polyacrylamide (HPAM) with Cr (щ) acetate. Woods et al. (1986) presented one of the earliest successful gel treatments for Lick Creek field in Arkansas. Hild and Wackowski (1999) reported a successful gel treatment at the Rangely Weber Sand Unit in northwestern Colorado. In this treatment, a large-volume (10,000 bbl) chromic-acetate acrylamide polymer gel was applied to improve CO2 flooding performance. The cost of the gel treatment was estimated to be around USD 6 to 8/bbl, and the project return rate was 365%. Karaoguz et al. (2007) and Topguder (2010) reported several field applications of gel in Bati Raman field. In General, gels can treat water coning successfully in reservoir with vertical fracture. However, water coning through matrix reservoir is very difficult to be treated