Abstract Reference Number: 1460537
Fluid flow and assessment of the leakage potential in the Snøhvit
reservoir and overburden in the Barents Sea
Alexandros Tasianas
Melanie Darcis
Stefan Buenz
Jurgen Mienert
(1) Department of Geology, University of Tromso, N-9037 Tromsø, Norway. E-mail : [email protected]
(2) Department of Hydromechanics and Modeling of Hydrosystems, University of Stuttgart, DE-70569 Stuttgart, Germany. Email : [email protected]
2) Aims
1) Background
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.
To better understand the pathways and
mechanisms related to fluid flow at
To propose potential leakage scenarios.
To accurately simulate fluid flow with the
aid of realistic geological models.
5) References
3) Methods
4) Study area
• Existing well-log analysis and new well-log creation (using iMOSS
• 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
Seismic data
1) 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, 349-370
2) 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) 1979-1985
3) 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.
5) Results
a) Potential leakage scenarios
CO2 from the Tubåen
partially leak upwards to
the Hekkingen Fm or less
deep formations via faults
(ref.1) and gas chimneys.
i) Models with faults
Fig.1. Study area location
Models with gas
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.
If leaking CO2 reaches the
Top kvitting Fm it can
via pipe
structures, faults, gas
clinoforms of the Torsk
Fm and accumulate under
Unconformity (URU).
pockmarks at the seabed
could indicate further
leakage between the URU
and the seabed via vertical
underlying the pockmarks.
c) Geological modelling
3D 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.
d) Simulation results
Fig.6. Modeled faults in Fig.7. Permeability model for the HIGH generic
case scenario including impermeable continuous
a stair stepped form
and permeable faults (entire and planar view)
(ref .1)
Fig.2. Fluid Fluid-flow simulation results with the «MEDIUM» Scenario, without any faults or
gas chimneys, indicate highest saturation values of CO2 in the interface between
mechanisms reservoir and cap rock with no signs of any CO2 reaching the seabed.
at Snøhvit
4 years
40 years
Potential fluid
migration pathways
b) Pockmarks and fluid flow
After 2 years
80 years
140 years
period is 30 years
location on
3D seismic
6 Km
Fig.10. Generic permeability
After 5 years
model for the MEDIUM case
Fig.11. CO2 saturation distribution with time in
After injection the COyears
2 phase migrates upwards until it encounters the low
Fig.12. CO2 plume evolution for
permeability cap rock. CO2 flows within the reservoir alongside the
the MEDIUM case models of
interface between reservoir and cap rock. This is followed by a slow
the faulted domain after y
upward migration into the cap rock. No leakage (suitable storage site).
number of years of injection.
Large horizontal extension of the CO2 plume (3 Km in diameter after 140
(See fig.1 for location)
e) GHSZ modeling results (ref.3)
Fig.4. Pockmark density and Fig.5. Iceberg ploughmark form
distribution along the seabed and extent
Both Composition 2 (96% CH4, 3% C2H6, 1% C3H8) and 3 (87%
Pockmarks occur in the form of small numerous circular ones, the CH4, 4.5% C2H6, 3.5% C3H8, 1.65% N2, 3.4% CO2) gas hydrates are
“unit pockmarks” (which measure up to 20m wide and up to 1m deep) stable, providing a supplementary sealing effect that prevents any
or much larger asymmetrical ones, the “normal pockmarks” (with potential leaking fluid reaching the seabed. The study area is
diameters of several hundreds of meters and depths reaching 12m). however lying outside the Composition 1 (100% CH4) gas hydrate
Pockmarks are often found within glacial ploughmarks having affected stability field. Any fluid with such composition leaking from the
their internal structure. The distribution of pockmarks can be thus reservoir will thus not form gas hydrates.
controlled by the orientation of the ploughmarks.
Graph 1. Variation of gas hydrate stability zone thicknesses with varying gas
Fig.9. Vertical k model with
gas chimney k values
varying both laterally and
vertically (ref.2)
Cross section
Bottom view
The injection location is the real
location for models including faults,
but at a virtual location for the gas
chimney models
3 Km
4 Km
Black contour for the
CO2 plume
End of injection period (after 40 yrs)
After 2 years
4 Km
3 Km
After 5 years
After 30 years
6) Conclusions
Postinjection (after 300 years)
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)
a. 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) Acknowledgements
The 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.

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