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Scale Risk Management during CO2 WAG in Carbonate FormationsNormal access

Authors: A.S. Ribeiro, E.J. Mackay, L.J.N. Guimarães, M. Jordan and S. Fellows
Event name: IOR 2017 - 19th European Symposium on Improved Oil Recovery
Session: Poster Introductions 1
Publication date: 24 April 2017
DOI: 10.3997/2214-4609.201700302
Organisations: EAGE
Language: English
Info: Extended abstract, PDF ( 2.52Mb )
Price: € 20

In this work we have used commercial software to perform reactive transport simulations of CO2 WAG injection in an oil reservoir, with the objective of assessing the scaling risk associated with CO2 EOR in carbonate formations. Higher WAG ratio promotes faster mineral reactions and severe scale deposition at earlier times. Injection of cooler fluids also enhances calcite and CO2 dissolution in water near the injector wellbore. Finally, the mass of calcite around the producer wellbore changes due to three different mechanisms: (a) brief dissolution caused by arrival of the CO2-rich front, (b) re-precipitation caused by mixing between high HCO3 injected water with high Ca formation water and (c) continuous precipitation caused by evolution of CO2 along the flow path, which occurs continuously after CO2 breakthrough. The results of these calculations allow the critical location where scale damage could occur within a production system to be identified, and a mitigation strategy developed to control its formation, for example via continual injection of scale inhibitor down to the production packer in early field life, reducing the need for batch inhibitor (squeeze) treatments into the reservoir in later field life, thereby significantly reducing OPEX.

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