Evaluation of the CO2 Storage Capacity of the Captain Sandstone Formation
- Min Jin (Heriot-Watt U.) | Eric James Mackay (Heriot-Watt U.) | Martyn Quinn (British Geological Survey) | Ken Hitchen (British Geological Survey) | Maxine Akhurst (British Geological Survey)
- Document ID
- Society of Petroleum Engineers
- SPE Europec/EAGE Annual Conference, 4-7 June, Copenhagen, Denmark
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 1.6.6 Directional Drilling, 2.4.3 Sand/Solids Control, 6.5.1 Air Emissions, 5.1.1 Exploration, Development, Structural Geology, 1.1 Well Planning, 5.8.2 Shale Gas, 5.5 Reservoir Simulation, 4.1.2 Separation and Treating, 1.7 Pressure Management, 2.2.2 Perforating, 4.3.4 Scale, 6.5.3 Waste Management, 5.1.2 Faults and Fracture Characterisation, 5.4.1 Waterflooding, 5.4.2 Gas Injection Methods, 5.6.1 Open hole/cased hole log analysis, 1.6 Drilling Operations, 5.5.11 Formation Testing (e.g., Wireline, LWD), 5.1.5 Geologic Modeling, 5.4 Enhanced Recovery
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The volume of CO2 that can be stored in the Captain Sandstone saline aquifer in the North Sea was investigated by building a geological model and performing numerical simulations. These simulations were also used to calculate the best position for the injection wells, and the migration and ultimate fate of the CO2.
The overall migration of CO2 and the pressure response over the entire saline aquifer was studied by the calculated injection of 15 million tonnes CO2 per year. The injection rate was restricted to a maximum of 2.5 million tonnes CO2 per year for each of a possible 12 wells considered. An important objective was to predict how to avoid flow of the injected CO2 toward potential leakage points, such as the sandstone boundaries and faults. The migration of injected CO2 towards existing oil and gas fields was also a determining factor.
The summary conclusions are:
- The Captain Sandstone saline aquifer has significant potential CO2 storage capacity. Even with all boundaries closed to flow, the probable storage capacity is calculated to be about 358 million tonnes, giving a storage efficiency of 0.6% of pore volume, with an expected operating life-span of 15-25 years.
- The possible storage capacity of the formation may be at least four times greater if the aquifer boundaries are open. This increase would be a result of displacement of salt water, and not CO2.
- The storage capacity if the sandstone is closed to flow may be increase from 358 to 1668 million tonnes of CO2 by significant additional investment in 15 to 20 water production wells.
- Injection of up to 2.5 million tonnes CO2 per year in one well has an impact on the pressure throughout the entire formation, and thus interference between different injection locations must be considered.
Keywords: CO2, CCS, Storage Capacity, Saline Aquifer
Carbon Capture and Storage (CCS) is considered to be an important means of reducing greenhouse gas emissions. CO2 may be stored in depleted oil and gas fields, deep saline aquifers or unmineable coal seams. Of these options, deep saline aquifers have the greatest storage potential both world-wide (IPCC, 2005) and in the UK(Scottish Carbon Capture and Storage, 2009). However, there is much uncertainty in the size and structure of aquifers compared to hydrocarbon reservoirs and evaluation of CO2 storage capacity is therefore a key step in the appraisal of CO2 storage sites. The objective of study was to assess the CO2 storage capacity of the Captain Saline Aquifer using the dynamic method (Jin et al., 2010, Smith et al., 2012). Throughout this paper the Captain Sandstone saline aquifer is referred to as Captain, which is differentiated from the Captain hydrocarbon field, currently operated by Chevron, by referring to the latter as the Captain Field.
The process was to build a 3D statistical geological model of Captain in Petrel (Schlumberger, 2009), using data supplied by the British Geological Survey (BGS), other project partners and from the open literature, and then use this geological model to build a dynamic reservoir simulation model which would run using ECLIPSE (Schlumberger, 2010). The ECLIPSE model was then used to calculate storage capacity, taking into account factors such as injectivity, well placement, and uncertainty in the geological model and conditions at the system boundaries.
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