Optimization of Tertiary Water-Alternate-CO2 Flood in Jilin Oil Field of China: Laboratory and Simulation Studies

Abstract

Abstract Most of the low permeability oil reservoirs in Jilin oil field of China have reached their economic limit of production by waterflooding and even many wells have been abandoned due to low productivity. Interest in recovery enhanced technology of tertiary miscible or immiscible CO2 flooding is increasing in these low permeable reservoirs. In this paper, a laboratory study using a high-pressure PVT cell and a simulation study using full-field fully equation-of-state (EOS) compositional reservoir modeling were undertaken to optimize the design of a miscible or immiscible CO2 flood pilot project for the Xinli Unit in Jilin oil field. The laboratory study includes phase behavior analysis, asphaltene deposition assessment, and minimum miscibility pressure (MMP) determination in the CO2 corefloods. Based on building a full-field 3D geologic model and history matching waterflood performance, a preliminary CO2 flood reservoir modeling has been used to distinguish displacement mechanisms and reservoir performance of natural depletion, continued waterflooding, continuous CO2 and water-alternate-CO2. The simulation study and the pilot test showed water-alternate-CO2 after waterflooding is an effective method of improved oil recovery for the low permeability reservoir and it can appreciably reduce water production and enhance oil recovery. Simulation studies has also been completed to determine an optimal water-CO2 ratio, optimal CO2 slugs and optimal CO2 injection rate. The pilot operation is now well implementing according to above-mentioned study achievements. Future plans for water-alternate-CO2 optimization include continuation of performance monitoring to help optimize tapering strategy in order to enhance further oil recovery in the low permeability oil reservoir. Introduction CO2 injection into tertiary oil reservoirs has been widely accepted as an effective technique for enhanced oil recovery (EOR). The use of CO2 as a method of enhanced oil recovery has been studied since the early 1950's[1] and its use grew significantly in the 1970s and 1980s[2]. It is used as an EOR process where it is injected following either natural drive or waterflooding in order to recover additional oil. The means by which CO2 increases oil recovery includes oil swelling, the reduction of oil viscosity, the reduction of oil density, the extraction or vaporization of oil, the reduction of interfacial tension, solution CO2 gas drive, increase in the injectivity, the acidization of carbonate formations and miscibility effects[3,4,5]. Oil displacement by CO2 flooding strongly depends on factors, which are related to the phase behavior of CO2-crude oil mixtures. Reservoir's temperature and pressure and crude oil composition are the main agents in this respect. Dominated displacement characteristics for a given CO2-displacement falls into one of the four regions as outlined in the Tab. 1 [6]. The process of oil displacement by CO2 flooding was shown in Fig. 1. CO2 injection as non-thermal EOR processes involves three major types, i.e., continuous CO2 flooding, water-alternating-gas (WAG) flooding, and cyclic CO2 stimulation (or huff 'n' puff). Each of these methods have their advantages and disadvantages, as summarized in literature [7]. Continuous CO2 flooding disadvantage lies in the high mobility of the gas that limits the vertical and the areal sweep efficiencies of the gas injection. For CO2 huff 'n' puff, there are two major disadvantages, i.e., relatively low recovery with respect to continuous flooding or WAG and operates in a relatively narrow range to optimize miscibility through changes in reservoir pressure.