Importance of Pressure Management in CO2 Storage
- Trine Simmenes (Statoil) | Olav R. Hansen (Statoil) | Ola Eiken (Statoil) | Gunn Mari Grimsmo Teige (Statoil) | Christian Hermanrud (Statoil ASA and University of Bergen) | Stian Johansen (Statoil) | Hege Marit Nordgaard Bolaas (Statoil) | Hilde Hansen (Statoil)
- Document ID
- Offshore Technology Conference
- Offshore Technology Conference, 6-9 May, Houston, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2013, Offshore Technology Conference
- 4.1.5 Processing Equipment, 5.1.5 Geologic Modeling, 4.1.2 Separation and Treating, 5.1.1 Exploration, Development, Structural Geology, 1.7.5 Well Control, 4.6 Natural Gas, 1.7 Pressure Management, 5.2 Reservoir Fluid Dynamics, 2.1.1 Perforating, 4.2 Pipelines, Flowlines and Risers
- Pressure control, Snohvit, CO2 storage
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CO2 injection implies displacement of water, and thus aquifer pressure build-up or displacement of water to other rocks. Both may be problematic. Pressure build-up may result in seal failure and / or restrict injection rates, whereas displacement of brine to other rocks may have undesired effects on the environment, such as contamination of potable drinking water. CO2 storage capacity also depends on pressure management, especially in closed systems where displaced water cannot be adequately displaced in the subsurface or vented to the surface.
Fluid pressure management at individual storage sites will be planned based on theoretical considerations as well as practical experience. The theoretical work includes analyses of widely different subjects such as stress tensor analyses, fracture propagation dynamics, reservoir connectivity and 3D permeability distributions. Practical experience will come from a growing number of injection sites, of which the experiences from the ongoing Snøhvit CO2 injection project are currently the most important.
Statoil has injected CO2 at Snøhvit since 2008. Injection took place in the Tubåen formation which underlies the Stø Formation natural gas reservoir. Fracturing of the caprock from the CO2 injection could thus result in CO2 leakage to the overlying producing reservoir. The CO2 injection resulted in an initial well pressure increase, probably caused by precipitation of salt in the near wellbore area. This challenge was resolved by injection of methylethylenglycol (MEG). Continuous downhole pressure measurements nevertheless documented a continuous pressure increase, albeit at a lower rate. This pressure increase was interpreted as evidence of insufficient far-field permeability to displace formation water laterally rather than of storage space shortage.
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