Published by the DTI Oil & Gas Directorate for the reservoir engineering and IOR community in the UK.
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Subsurface Issues for CO₂ Flooding of UKCS Reservoirs

Eugene Balbinski (eugene.balbinski@ecl-winfrith.com) of ECL Technology Ltd summarises work undertaken for the DTI SHARP Programme.  This concerns the subsurface issues related to CO2 flooding in UKCS reservoirs and was presented at the recent DTI IOR Research Dissemination Seminar (Authors: Stephen Goodyear, Ian Hawkyard, Jeff Masters, Claire Woods).

Tertiary CO₂ injection in onshore North American fields is a successful IOR technique, where the CO₂ is sourced from natural CO₂ reservoirs. Concern over greenhouse gas emissions has renewed interest in the potential for CO₂ flooding in the UKCS. CO₂ would be captured onshore, e.g. from power station emissions, and injected into UKCS reservoirs to improve recovery and leave CO₂ trapped in the reservoirs at the end of project life.

In onshore North American fields tertiary CO₂ injection regularly achieves incremental oil recoveries in the range 4-12% STOIIP. Retained gas volumes are typically 10-25% HCPV for tertiary CO₂ floods. The incremental oil production, expressed in reservoir barrels, is generally between 0.5 and 1.0 of the volume retained in the reservoir.

CO₂ injection is more complex than hydrocarbon gas injection from a sub-surface standpoint. Up to 5 phases can co-exist in the reservoir. Dissolved CO₂ changes the reservoir chemistry, reducing brine pH, dissolving carbonate minerals, increasing CaCO₃ scale in wells and affecting the performance of scale inhibitor treatments.

CO₂ is expected to be miscible or nearly miscible with the oil at the current pressures and original temperatures of most UKCS fields. No established guidelines exist for CO₂/hydrocarbon binary interaction coefficients in EOS models of UKCS oils.

Although UKCS fields are at higher pressures than onshore CO₂ projects, the higher temperatures compensate to give similar CO₂ densities at reservoir conditions in both UKCS and Permian Basin floods. Consequently, similar quantities of CO₂ would be required to sweep a given reservoir volume in both cases.

Comparison of CO₂ Density at Onshore North American and UKCS Reservoir Conditions
Compositional simulation of WAG has shown that cooling in waterflooded zones of the reservoir may affect project performance. Significantly more CO₂ is required at the lower temperature because its density increases, but the MMP decreases and the density differences between CO₂ and the oil and water are reduced, or even reversed, which will improve sweep. Gas utilisation can be improved by reducing the operating pressure to near the MMP.

Compositional simulation of GSGI shows that gas utilisation can also be improved by operating at reduced pressures, even where these are significantly below the MMP. This underlines the importance of having a well characterised EOS model that allows project performance to be assessed over a range of operating conditions.

Use this link to access the full paper:

www.dti-sharp.co.uk/dissemination/openreports/ CO2_IOR_seminar_02.pdf

Subsurface issues for CO₂ flooding of UKCS reservoirs, Stephen Goodyear, Ian Hawkyard, Jeff Masters, and Claire Woods, DTI Improved Oil Recovery Dissemination Seminar, Aberdeen, June 2002.

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