Page 103 - Fundamentals of Enhanced Oil and Gas Recovery

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Enhanced Oil Recovery Using CO 2

Oil recovery from a slim tube depends not only on CO 2 oil phase behavior,
but also on displacement rate and the level of dispersion, which in turn depends
on displacement rate and the particle diameter of the packing material [20,70].

3.5 CO 2 INJECTION FACILITIES AND PROCESS DESIGN
CONSIDERATIONS
3.5.1 Surface Facilities
When a reservoir becomes a candidate for a CO 2 flood, whether miscible or immisci-
ble, it requires a special gathering of surface facilities. CO 2 is first supplied through
pipelines by a high-pressure compressor, if sufficient pressure is not satisfied. Then it is
directly injected into the reservoir through the injection well, which is located near
the production well. Indeed, wells are spaced from each other depending on the
injection pattern. CO 2 will then assist oil flow to the production wells. Some of this
CO 2 might be stored within the reservoir, but the remaining ones will be produced as
it can be dissolved in oil or as it breaks through the production path. Commonly,
water will also be produced. This amount of water could be sourced from a previous
water flood process, water alternative CO 2, or even formation water. When these pro-
ducts get into a high-pressure separator, CO 2 will be separated and then transmitted
to a recycling compressor. Recycled CO 2 will be injected again for economic and
environmental considerations. Produced oil and water will undergo a separation pro-
cess in which water will be directed for disposal and oil for sales [13,71].

3.5.2 Process Design Considerations

After a reservoir is nominated for a CO 2 flood and a surface facilities configuration is
designed, several further factors should be accounted for the project to be continued
in an economic fashion. First of all, the CO 2 availability is of high concern. Majorly,
CO 2 is sourced either from the atmosphere (anthropogenic CO 2 ) or from natural gas
decomposition (flue gas). Availability is also affected greatly by the costs of transporta-
tion. Based on availability, an optimum slug size of injection CO 2 can be determined.
Secondly, the corrosion potential should be evaluated carefully. CO 2 water mixture
can be very corrosive, resulting in serious damages to flow lines and facilities. In order
to prevent loss of cost due to corrosion, a dehydration unit is customarily installed in
CO 2 -transporting pipelines to release CO 2 from water. In addition, flow lines are
normally coated with some especial materials that are resistant to CO 2 corrosion.
Thirdly, the potential of asphaltene deposition occurrence needs to be predicted. As
CO 2 interacts with the oil, asphaltenes instability arises, which may lead to formation
damage because of permeability impairment [73]. It has also the potential to damage