Experimental Evaluation of CO2 Injection in a Heavy Oil Reservoir

Abstract

Abstract The aim of this experimental study was the evaluation of CO2 EOR process in a heavy oil field. The candidate for the injection is an oil field located in Sicily (Italy) using a CO stream from a refinery. 2 CO2 swelling experiments highlighted that at reservoir conditions CO2 may swell the reservoir oil, reducing its viscosity and thus increasing the mobility. Displacement tests were conducted at reservoir conditions on reservoir core plugs and oil. The tests simulated WAG cycles by injecting sequences of CO2 and brine solution. Most of the oil was recovered during the first CO2 step injection. The experiments suggest that the WAG process is not indicated for the viscous heavy oil displacement, but CO2 injection can increase recovery factor in this kind of field. Gaschromatographic analyses have been performed on collected oil sample in order to evaluate a possible change in recovered oil composition. An early production of high MW components respect to lighter components was found and attributed to vaporization mechanisms. The endpoints of water/oil and gas/oil relative permeabilities at reservoir condition have been acquired. The reservoir numerical simulation analysis confirmed the potentiality of the EOR technique, showing that the best CO2 injection scenario yields a 20 years cumulative production almost double than the "do-nothing" case production. Introduction The objective of the study was the experimental feasibility regarding the CO2 injection in a heavy oil reservoir. Previous experimental studies demonstrated good oil swelling due CO2 injection at reservoir condition with a significant viscosity reduction. The field is located in south-east Sicily and has been discovered in the early '80. Heavy oil mineralization (API gravity around 10°) has been detected both into a lower dolomite formation (300 cp viscosity at reservoir conditions) and into limestones of the overlying formation (40 cp viscosity at reservoir conditions). The reservoir depth is more than 3200 mssl, corresponding to an initial pressure and temperature of 326.5 bar (@3200 m) and 102 °C, respectively. The lowermost formation has been put in production in September 1990 with the drilling of five wells, one of which has been sidetracked in 2003. The uppermost formation has never been put in production. In order to optimize the investment, a study has been performed to evaluate carbon-dioxide injection scenarios for the field (both formations), which could be implemented. The reservoir is characterized by the following geological features:• complex and interacting processes of initial facies deposition, progressive faulting/fracturing and several diagenetic phases of secondary porosity creation;• oil migration through the fracture system only. The relevant conceptual model can be summarized by the existence of two main flow components: one vertical (trough fractures) and one layer-driven (pseudo-matrix system, i.e. an interaction between macro-meso porous system and diffuse fractures). In order to improve the oil recovery factor, CO2 injection was proposed, because potential availability of CO2 stream from a refinery plant located near the field. The best CO2 injection scenario, which entails 2 infilling wells and 2 workover operations to add inflow control devices to existing wells, yields a 20 years cumulative production almost double than the "do-nothing" case production. Since the drilling of a new infilling well is yet decided and the near refinery could feed the necessary carbon dioxide, CO2 injection to the field seems to be desirable.