Current challenges at CO 2 Sites

Transcription

1 Current challenges at CO 2 Sites Ola Eiken et al., Statoil R&D Force seminar on injection safety 4 th December 2013 Offshore Sleipner Onshore In Salah Sub-sea Snøhvit 1 - Classification: External

2 Snøhvit Sleipner In Salah 2 - Classification: External

3 Pressure [bar] solid liquid vapor Temperature [ o C] 3 - Classification: External

4 Sleipner Permeability In Salah Snøhvit Porosity 4 - Classification: External

5 Accumulated injected CO2 [million tons] Year 5 - Classification: External

6 Sleipner CO 2 injection 6 Wellhead pressure Date Wellhead pressure (bar)

7 Utsira formation 7- Classification: Internal

8 Utsira Formation Sand wedge Nordland Shale Utsira Fm Hordaland Fm Ref. SACS project (SINTEF) 8 - Classification: Internal

9 Top Utsira Fm. time map Sleipner A Deep Shallow CO 2 injection point Domal trap. Low relief. Sleipner A protected. 9 - Classification: Internal

10 Time-lapse seismic data 1994 Sleipner CO 2 injection Utsira Fm CO 2 plume in map view Classification: Internal

11 Gravity monitoring 2002, 2005, 2009, 2013 Further monitoring at Sleipner Seafloor mapping 2006 In-situ CO 2 density: 720 +/- 80 kg/m 3 Maximum dissolution rate: 1.8% per year 11 - Classification: External

12 12 - Classification: External Fracture in block 16/4

13 The In Salah CO 2 storage site Gas from other fields Amine C0 2 removal Gas production (5 wells) CO 2 injection (3 wells) Cretaceous sequence (900m) Carboniferous mudstones (950m) 13 - Classification: Internal

14 14 In Salah Surface Deformation Japex/JGI Study Comments: Period 2004 to 2008 Japan Geophysics Institute; Onuma & Ohkawa (2008) Based on Differential (DInSAR) method Subsidence seems to follow subsurface fault pattern Uplift pattern is clearly centered on injection wells with elongation in NW-SE stress direction 2007/3/3 2006/12/ /7/1 2006/2/ /9/ /6/ /2/ /12/ /10/9 2004/7/31 No explanation of calibration or reference point given

15 Geomechanical modelling at In Salah Extensively studied as part of a Joint Industry Project ( ). InSAR monitoring data provided a unique opportunity to understand pressure propagation and rock mechanical deformation Key published papers include: Vasco et al. (2008, 2010) Ringrose et al. (2009, 2013) Mathieson et al. (2010) Rutqvist et al. (2010) Bissel et al. (2011) Gemmer et al. (2012) Oye et al. (2013) Map of surface uplift May mm uplift Modelled rock strain (section) Injection Unit 15 Classification: Internal

16 Lawrence Berkeley analysis of InSAR Vasco et al. (2008, 2010) developed a geophysical inversion method infer subsurface pressure and flow from InSAR surface deformation data Their model required a vertical tensile source at 1.8 km [3.5 km long and 100 m vertically], which turned out to be an excellent prediction of subsequent observations They also showed that variation in elastic moduli is important for a good prediction Observation vs. prediction from Vasco et al., 2010 Longitude (Degrees) Longitude (Degrees) 16 Classification: Internal

17 Snøhvit CO 2 injection 17 - Classification: Internal

18 10m Snøhvit injection well 2km Depth map of base Tubåen Fm. Perforated zones 18 - Classification: External

19 Cumulative injection Cumulative injected mass (tons) Date 19 - Classification: Internal

20 Estimated downhole shut-in pressure Pressure [bar] Date Classification: Internal

21 Snøhvit CO 2 monitoring CO 2 injection well CO 2 injection well Pressure 10 bar 4D seismic acquisition 4 months Time Cumulative injected mass [tons] Top Fuglen Fm. Base Tubåen Fm. baseline 2003 repeat 2009 difference Amplitude changes Modelled CO 2 saturation and pressure increase Increasing amplitude 0.5 km 21 - Classification: External

22 Is there enough room for CO 2 storage? Ehlig-Economides & Economides (2010) concluded for a closed volume: the volume of liquid or supercritical CO 2 to be disposed cannot exceed more than about 1% of pore space. [And that this] renders geologic sequestration of CO 2 a profoundly non-feasible option for the management of CO 2 emissions. This provoked a strong reaction from the proponents of CCS that large-scale geological CO 2 storage is feasible. Most people agree that you cannot inject very much fluid into a confined box. There are three important limiting factors: 1. The size of the box (the storage unit) 2. The properties of the box boundaries (faults and shale sealing units) 3. The ability of the box to absorb increased pressure (rock and fluid compressibility). Zhou et al. (2008) concluded that: Storage efficiency is ~0.5% for closed systems But that a semi-closed system with a seal permeability of m 2 (0.01 md) or greater behaves essentially as an open system with respect to pressure buildup (due to brine leakage). 22

23 Conclusions In highly varable and complex reservoirs, single wells have injected several hundred thousand tons of CO 2 per year. Surface geophysical and well pressure monitor data give rich information on the storage behaviour. Dynamic modelling to match the data is still challenging, and there is room for further model improvement. The actual plume development has been strongly controlled by geological factors which we learned about during injection. High-quality monitor data lowers the detection threshold for any potential leakage. At Sleipner and Snøhvit 4D seismic monitoring is of sufficient quality to confirm that there are no signs of leakage into the overburden. At In Salah, In SAR data has proven particularly valuable in monitoring pressure distribution. We expect detailed site characterization, monitoring and well solutions to increase the storage capacity on a case by case basis, as the site specific knowledge develops Classification: External

24 Thank you Current challenges at CO 2 sites Ola Eiken oei@statoil.com, tel: Classification: External