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Abstract
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.
Introduction
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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