Optimizing Oil Recovery and Carbon Dioxide Storage in Heavy Oil Reservoirs
- Lorraine Sobers (Imperial College) | Tara C. LaForce (Imperial College) | Martin Julian Blunt (Imperial College)
- Document ID
- Society of Petroleum Engineers
- Trinidad and Tobago Energy Resources Conference, 27-30 June, Port of Spain, Trinidad
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 5.3.2 Multiphase Flow, 5.4.2 Gas Injection Methods, 4.3.4 Scale, 6.5.1 Air Emissions, 6.5.7 Climate Change, 5.4.10 Microbial Methods, 5.4.1 Waterflooding, 5.4.3 Gas Cycling, 5.4 Enhanced Recovery, 5.2 Reservoir Fluid Dynamics, 5.7.2 Recovery Factors, 5.2.1 Phase Behavior and PVT Measurements, 5.2.2 Fluid Modeling, Equations of State, 1.2.3 Rock properties, 2.4.3 Sand/Solids Control, 5.10.1 CO2 Capture and Sequestration, 5.5 Reservoir Simulation
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We study the design of enhanced oil recovery in heavy oil reservoirs combined with CO2 storage using field-scale reservoir simulation. We consider properties typical of fields offshore Trinidad and Tobago with oils whose density ranges between 940 and 1010 kg/m3 (9-18 degrees API). We first tune a three-parameter Peng-Robinson equation of state to match measured PVT data. We use experimental design to study the influence of oil properties, phase behavior and injection design on oil recovery and net CO2 storage. Carbon dioxide injection into heavy oil reservoirs enhances oil recovery through the mechanisms of crude viscosity reduction, oil swelling and immiscible gas drive. The process involves significant recycling of the injected CO2, but the reservoir is managed to keep as much of the injected CO2 as possible underground.
The motivation for this work is to improve recovery from the heavy oil fields offshore and onshore Trinidad, which potentially have access to a relatively pure carbon dioxide feed (97-99% CO2) from the petrochemical industries at the nearby Point Lisas Industrial estate. At ambient conditions the heavy oil viscosity ranges from 1,000-10,000 mPa.s. Although the viscosity can be much lower at reservoir conditions (5-20 mPa.s), it is difficult to maintain economic production rates. Carbon dioxide injection into heavy oil reservoirs can enhance recovery through the mechanisms of crude viscosity reduction, oil swelling and immiscible gas drive and can also be a means of carbon sequestration. In the past CO2 needed to be purchased for enhanced oil recovery operations and so gas cycling was a means of reducing the cost. However, with increasing efforts to reduce carbon emissions, environmental considerations could lead to an economic framework where value was associated with the permanent storage of CO2 in the subsurface and so the field would be managed to minimize gas recycling. We investigate the impact of water alternating gas (WAG) injection on production rates, vertical sweep efficiency and gas stream composition as the first stage in developing an injection strategy that favours carbon storage.
Most of the literature discusses carbon storage in aquifers since this has the largest storage potential (Bachu and Adams 2003), while discussion of oil reservoirs normally focuses on relatively light oils where miscibility between the injected CO2 and oil is possible, with relatively little analysis of heavy oil reservoirs (Bachu 2000). The Weyburn enhanced oil recovery (EOR) project in Canada stands apart from other CO2 EOR projects around the world in that it relies entirely on anthropogenic carbon emissions and operations (Monea 2004). The project was preceded by a reservoir simulation investigation into the possibility of co-optimization of carbon storage and oil production. This is a conventional, light oil field (oil density of 848 kg/m3 and oil viscosity of 4.7 mPa.s; (Malik and Islam 2000) . The project uses a combination of horizontal CO2 injectors, vertical water injectors and vertical producers. Achieving miscibility was argued to be important to achieve co-optimization, along with CO2 injection into bottom waters. Unless light hydrocarbon fractions (C2-C6) are injected with the carbon dioxide stream to reduce the minimum miscibility pressure (MMP) of the crude to reservoir pressure, this cannot apply to heavy oil recovery.
Kovscek and Cakici (2005) proposed a C2-C6 and carbon dioxide injection feed mix in their simulated injection design to investigate EOR-CO2 storage co-optimization of a moderately heavy crude (density 910 kg/m3). They first considered injection of a mix of CO2 (67% mol fraction) and hydrocarbon gases (C2-C4) to ensure miscibility. Then they studied the injection scheme and suggested that WAG is detrimental to storage because water reduces the capacity of the reservoir to store CO2. This contrasts with the work of Qi et al. (2009) for a light oil field with first-contact miscibility with the injected CO2, who suggest injecting more water than the traditional optimal WAG ratio to force the injected CO2 through the reservoir, and to aid capillary trapping.
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