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Fluid flow and assessment of the leakage potential in the Snøhvit reservoir and overburden in the Barents SeaAlexandros Tasianas (1), Melanie Darcis (2), Stefan Buenz (1), Jurgen Mienert (1)

(1) Department of Geology, University of Tromso, N-9037 Tromsø, Norway. E-mail : alexandros.tasianas@uit.no (2) Department of Hydromechanics and Modeling of Hydrosystems, University of Stuttgart, DE-70569 Stuttgart, Germany. Email : melanie.darcis@iws.uni-stuttgart.de

5) Results

The Snøhvit reservoir and overburden have been an important location for testing Carbon Capture and Storage (CCS) techniques. Fluid flow in the region is caused mainly by repeated glacial cycles and differential geographic uplift, which caused tilting and spilling of various structural traps in the area. Seismic data interpretation and geological modeling has allowed us to model the local stratigraphy and any potential fluid-flow features and pathways in order to determine how effective CCS would be in the area.

1) Background 2) Aims• To better understand the pathways

and mechanisms related to fluid flow at Snøhvit.

• To propose potential leakage scenarios.

• To accurately simulate fluid flow with the aid of realistic geological models.

OS43A-1790 Abstract Reference Number: 1460537 

3) Methods• Existing well-log analysis and new well-log creation (using

iMOSS software)• Reflector interpretation (using the autotracking method in

Petrel)• Geological model building (via the “Structural framework”

tool in Petrel)• Grid population with porosity and permeability values • Simulation of CO2 flow with the aid of Dumux software

4) Study areaSeismic data3D conventional seismic data related to cube ST0306 from the Hammerfest Sedimentary Basin (HFB), covering the Snøhvit and Albatross fields, (water depth from -511 to -369 ms TWT) and P-Cable high resolution cubes from Snøhvit (water depth from -468 to -425 ms TWT) were used.

6) Conclusionsa. No indication of leakage of CO2 from fluid flow

simulations where no faults and gas chimneys are present.

b. There is leakage of CO2 both in the faulted and gas chimney models (with CO2 reaching the seabed only in the latter ones).

c. The composition 2 and 3 gas hydrates that may form can provide a supplementary sealing effect that prevents any leaking fluid reaching the seabed.

7) AcknowledgementsThe 3D conventional data was acquired in 2003 by PGS Geophysical on request by Statoil ASA for which we are grateful. I would also like to thank CGG Norge for having processed the data sets. I also acknowledge the participants of the cruise carried out in july 2011 for helping acquire the 3D P-Cable high resolution data.

CO2 from the Tubåen Formation (Fm) can partially leak upwards to the Hekkingen Fm or less deep formations via faults (ref.1) and gas chimneys.If leaking CO2 reaches the Top kvitting Fm it can continue migrating upwards via pipe structures, faults, gas chimneys or the clinoforms of the Torsk Fm and accumulate under the Upper Regional Unconformity (URU).The presence of pockmarks at the seabed could indicate further leakage between the URU and the seabed via vertical fluid flow structures underlying the pockmarks.

c) Geological modelling i) Models with faults ii) Models with gas chimney

d) Simulation resultsFluid-flow simulation results with the «MEDIUM» Scenario, without any faults or gas chimneys, indicate highest saturation values of CO2 in the interface between reservoir and cap rock with no signs of any CO2 reaching the seabed.

e) GHSZ modeling results (ref.3)Both Composition 2 (96% CH4, 3% C2H6, 1% C3H8) and 3 (87% CH4, 4.5% C2H6, 3.5% C3H8, 1.65% N2, 3.4% CO2) gas hydrates are stable, providing a supplementary sealing effect that prevents any potential leaking fluid reaching the seabed. The study area is however lying outside the Composition 1 (100% CH4) gas hydrate stability field. Any fluid with such composition leaking from the reservoir will thus not form gas hydrates.

b) Pockmarks and fluid flow

After injection the CO2 phase migrates upwards until it encounters the low permeability cap rock. CO2 flows within the reservoir alongside the interface between reservoir and cap rock. This is followed by a slow upward migration into the cap rock. No leakage (suitable storage site). Large horizontal extension of the CO2 plume (3 Km in diameter after 140 years).

a) Potential leakage scenarios

Pockmarks occur in the form of small numerous circular ones, the “unit pockmarks” (which measure up to 20m wide and up to 1m deep) or much larger asymmetrical ones, the “normal pockmarks” (with diameters of several hundreds of meters and depths reaching 12m). Pockmarks are often found within glacial ploughmarks having affected their internal structure. The distribution of pockmarks can be thus controlled by the orientation of the ploughmarks.

4 years 40 years

80 years 140 years

Fig.10. Generic permeability model for the MEDIUM case scenario

Depending on the leakage mode, models of different types of domain size and grid resolution were created and populated with properties such as porosity (phi) and permeability (k).

Variation in the porosity and permeability values allowed also for extreme cases to be considered; giving rise to MEDIUM, LOW and HIGH case scenarios.

Fig.11. CO2 saturation distribution with time in years

Fig.7. Permeability model for the HIGH generic case scenario including impermeable continuous and permeable faults (entire and planar view) (ref .1)

Fig.6. Modeled faults in a stair stepped form

Fig.9. Vertical k model with gas chimney k values varying both laterally and vertically (ref.2)

Fig.8. P2 Gas chimney characteristics

Fig.12. CO2 plume evolution for the MEDIUM case models of the faulted domain after y number of years of injection. (See fig.1 for location)

The injection location is the real location for models including faults, but at a virtual location for the gas chimney models

After 2 years

After 5 years

After 30 years

Black contour for the

CO2 plume

Fig.4. Pockmark density and distribution along the seabed

Fig.5. Iceberg ploughmark form and extent

Graph 1. Variation of gas hydrate stability zone thicknesses with varying gas composition

Fig.3. Snøhvit subsurface structure from inline 2706 (See fig.1 for location on 3D seismic block ST0306)

Fig.2. Fluid flow mechanisms at Snøhvit

Fig.13. CO2 plume evolution for the MEDIUM case models of the gas chimney domain after x number of years from injection and for a k of 342 mD in the gas chimney. (ref.2) (See fig.1 for location)

Cross sectionBottom view

After 2 years

After 5 years

End of injection period (after 40 yrs)

Postinjection (after 300 years)

The injection period is 30 years

5) References1) Linjordet, A., Olsen, R.G., 1992. The Jurassic Snohvit Gas-Field, Hammerfest Basin, Offshore Northern Norway. Giant Oil and Gas Fields of the Decade 1978-1988 54, 349-3702) Kim, G.Y., Yi, B.Y., Yoo, D. G., Ryu, B.J., Riedel, M., 2011. Evidence of gas hydrate from downhole-logging data in the Ulleung Basin, East Sea. Marine Petroleum and Geology 28 (2011) 1979-

19853) Chand, S., Mienert, J., Andreassen, K., Knies, J., Plassen, L., Fotland, B., 2008. Gas hydrate stability zone modeling in areas of salt tectonics and pockmarks of the Barents Sea suggests an

active hydrocarbon venting system. Mar Petrol Geol 25, 625-636.4) National, Oceanographic, Data, Center, NODC, 2009. World ocean database. http://www.nodc.noaa.gov/OC5/WOD09/pr_wod09.html.5) Sloan, E.D., 1990. Clathrate hydrates of natural gases. M. Dekker, New York.

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6 Km

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N4 Km

4 Km

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E

W

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3 Km

3 Km

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Potential fluid migration pathways

Fig.1. Study area location map