Design of Simultaneous Enhanced Oil Recovery and Carbon Dioxide Storage Applied to a Heavy Oil Field Offshore Trinidad
- Lorraine Sobers (Imperial College) | Martin Julian Blunt (Imperial College) | Tara C. LaForce (Imperial College)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 30 October-2 November, Denver, Colorado, USA
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 5.2.1 Phase Behavior and PVT Measurements, 4.3.4 Scale, 5.7.2 Recovery Factors, 6.5.2 Water use, produced water discharge and disposal, 4.6 Natural Gas, 2.4.3 Sand/Solids Control, 6.5.1 Air Emissions, 1.14 Casing and Cementing, 5.4 Enhanced Recovery, 5.3.2 Multiphase Flow, 5.4.1 Waterflooding, 5.4.3 Gas Cycling, 5.4.2 Gas Injection Methods, 4.2 Pipelines, Flowlines and Risers, 5.2 Reservoir Fluid Dynamics, 5.2.2 Fluid Modeling, Equations of State, 5.1.1 Exploration, Development, Structural Geology, 3.1.6 Gas Lift, 5.5 Reservoir Simulation
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We have developed an injection strategy to recover moderately heavy oil and store carbon dioxide (CO2) simultaneously. Our compositional simulations are based on PVT-matched properties of oil found in an unconsolidated deltaic, sandstone deposit in the Gulf of Paria, offshore Trinidad. In this region oil density ranges between 940 and 1 010 kg/m3 (9-18 degrees API). We use counter-current injection of gas and water to improve reservoir sweep and trap CO2 simultaneously; water is injected in the upper portion of the reservoir and gas is injected in the lower portion. The two water injection rates investigated, 100 and 200m3/d, correspond to water gravity numbers 6.3 to 3.1 for our reservoir properties. We have applied this injection strategy using vertical producers with two injection configurations: single vertical injector and a pair of horizontal parallel laterals. Eight simulation runs were conducted varying injection gas composition for miscible and immiscible gas drives, water injection rate and injection well orientation. Our results show that water over gas injection can realize oil recoveries ranging from 17 to 30%. In each instance more than 50% of injected CO2 remained in the reservoir with less than 15% of that retained CO2 in the mobile phase.
Trinidad and Tobago CO2 emissions are mainly from the consumption of fossil fuels, the manufacture of cement petrochemical and other industrial plants. Twenty-two percent of emissions are relatively pure streams (>95% CO2) of CO2 emitted at low pressure from seven methanol plants and eleven ammonia plants at the Point Lisas Industrial Estate. Figure 1 shows the location of the Point Lisas industrial plant in relation to oil fields in southern Trinidad.
Between 1973 and 1990, several immiscible CO2 pilot projects were conducted in the Forest Reserve sand found in the onshore Oropuche and Forest Reserve fields (Mohammed-Singh and Singhal, 2005). CO2 was piped 42 km and compressed in four stages, from atmospheric pressure to 68 bar (6.8MPa), between an ammonia plant at Point Lisas and the Forest Reserve oil field. Our area of interest, the Soldado oil fields, in the Gulf of Paria, lies between 40 and 55 km offshore of the Point Lisas Industrial Estate.
In this paper we propose that CO2 from these industrial sources is injected into a heavy oil field in the S-759 area (640 acres) shown in Figure 1 for both enhanced oil recovery and storage. These unconsolidated Pliocene reservoirs were deposited as part of the deltaic Orinoco river system characterized by distributary channel fills (James, 2000). The estimated original oil in place is 22 MMBO distributed across two packages of the Forest Reserve sand, 4B and 4C. The ultimate recovery factor has been estimated to be only 16% with gas lift (Lougheide et al., 2004).
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