of the Sleipner, Snøhvit (Barents Sea), In Salah, and
Weyburn-Midale (Saskatchewan, Canada) CCS
projects.
24.7.1 Sleipner CCS Project
Natural gas produced at Sleipner contains about 9.5%
CO 2 . In order to ship this natural gas in a liquid form
(LNG) to customers it has to be cooled to À162
C,
which may cause formation of CO 2 ice aggregates. To
avoid this, most of the CO 2 is captured during production, i.e. removed from the natural gas stream. Before
1996, CO 2 captured from the Sleipner field was
released directly to the atmosphere. A few years
before, in 1991, Norway had established a tax on
CO 2 emissions (in 1999, about 18 US$/ton CO 2 on
emissions of ~1 Mt CO 2 /year). This represented a
considerable financial levy on the operators of
Sleipner. In 1996, Statoil and partners started to inject
CO 2 captured at Sleipner into the Utsira Formation,
and the injection has continued successfully at a rate of
approximately 1 Mt CO 2 /year.
The CCS operation at Sleipner was feasible
because of the properties of the Utsira storage reservoir located near the Sleipner field. The Utsira Sand
sediments are basin-restricted marine lowstand
deposits of Miocene-Pliocene age (Zweigel et al.
2004), only weakly compacted and with high porosity
(30–40%). The sand is very extensive (see Fig. 24.1)
and is in many ways an optimal storage reservoir. At
800 m below seafloor, temperatures and pressures are
about 37
C and 100 bar, which is above the critical
point of CO 2 . As overburden, the Utsira Formation has
a 250 m clay-rich sequence of the Nordland group
which provides the seal, with a further several hundred
metres of coarser-grained Quaternary sediments above
(Zweigel et al. 2004). The mudstones deform in a
ductile manner and stress changes are therefore not
expected to lead to fractures that could provide leakage pathways for the CO 2 .
The injected CO 2 has been monitored by 3D
seismics surveys carried out before, and several times
after, injection started in 1996. The seismic images
show that CO 2 has spread out laterally below nine
distinct stratigraphic layers. A bulk of the CO 2 is still
trapped under these layers and this has reduced the
amount of free CO 2 that has reached the cap rock
(Hermanrud et al. 2009). A much discussed feature of
the seismic images is the presence of a chimney-like
structure in the storage reservoir just above the injector.
This structure possibly formed shortly after injection
commenced, by liquefaction of the sediments breaking
up the thin intra-reservoir shale layers (Hermanrud et al.
2009). Although CO 2 has migrated through what was
thought to be a tight shale layer in the cap-rock and into
an overlaying sand wedge, there are no indications of
further leakage to shallower depths.
24.7.2 Snøhvit CCS Project
Gas produced from the Lower to Middle Jurassic Stø
Formation at Snøhvit contains 5–8% CO 2 . This gas is
transported by pipelines to the processing plant at
Melkøya, where CO 2 is captured and transported back
underground. CO 2 storage started in 2008 with injection
into the early Jurassic Tuba ˚en Formation, which lies
just below the gas-producing Stø Formation In contrast
to the Utsira Sand, the stratigraphic sequences in the
Barents Sea region have experienced a complex history
of burial and later tectonic uplift. The present-day depth
of the Tuba ˚en is about 2,400 m at the injection site, and
temperature and pressure before injection were 95
C
(Hansen et al. 2013) and 240 bars (assuming hydrostatic). The depth and temperature at maximum burial
may however have been more than 3,200 m and 130
C.
After a short period of injection, the operation experienced problems with rapid pressure build-up,
interpreted to be caused by reactions clogging the
pore space and reducing the permeability around the
well (Hansen et al. 2013). In the Tuba ˚en Formation,
these reactions could be: (1) salt formation (scale)
caused by the drying-out of highly saline brine around
the well; or (2) CO 2 hydrate (clathrate) formation. As
CO 2 entered the reservoir at low temperature (4
C) and
pressures were higher than 290 bars (Hansen et al.
2013), the latter is more likely (Kvamme and Tanaka
1995, Duan and Sun 2006), although the highly saline
brine depresses the freezing point of CO 2 hydrate (Duan
and Sun 2006). Salt (halite) formation caused by injection of dry CO 2 has been predicted numerically (Muller
et al. 2009) and in laboratory experiments (Bacci et al.
2013), and although not yet observed in situ, could also
very well be the reason for the pressure build-up. After
the initial pressure build-up was solved by chemical
treatment, the operation continued. Unfortunately, the
tight and compartmentalised Tuba ˚en Formation turned
24 Carbon Capture and Storage (CCS)
599
Weyburn-Midale (Saskatchewan, Canada) CCS
projects.
24.7.1 Sleipner CCS Project
Natural gas produced at Sleipner contains about 9.5%
CO 2 . In order to ship this natural gas in a liquid form
(LNG) to customers it has to be cooled to À162
C,
which may cause formation of CO 2 ice aggregates. To
avoid this, most of the CO 2 is captured during production, i.e. removed from the natural gas stream. Before
1996, CO 2 captured from the Sleipner field was
released directly to the atmosphere. A few years
before, in 1991, Norway had established a tax on
CO 2 emissions (in 1999, about 18 US$/ton CO 2 on
emissions of ~1 Mt CO 2 /year). This represented a
considerable financial levy on the operators of
Sleipner. In 1996, Statoil and partners started to inject
CO 2 captured at Sleipner into the Utsira Formation,
and the injection has continued successfully at a rate of
approximately 1 Mt CO 2 /year.
The CCS operation at Sleipner was feasible
because of the properties of the Utsira storage reservoir located near the Sleipner field. The Utsira Sand
sediments are basin-restricted marine lowstand
deposits of Miocene-Pliocene age (Zweigel et al.
2004), only weakly compacted and with high porosity
(30–40%). The sand is very extensive (see Fig. 24.1)
and is in many ways an optimal storage reservoir. At
800 m below seafloor, temperatures and pressures are
about 37
C and 100 bar, which is above the critical
point of CO 2 . As overburden, the Utsira Formation has
a 250 m clay-rich sequence of the Nordland group
which provides the seal, with a further several hundred
metres of coarser-grained Quaternary sediments above
(Zweigel et al. 2004). The mudstones deform in a
ductile manner and stress changes are therefore not
expected to lead to fractures that could provide leakage pathways for the CO 2 .
The injected CO 2 has been monitored by 3D
seismics surveys carried out before, and several times
after, injection started in 1996. The seismic images
show that CO 2 has spread out laterally below nine
distinct stratigraphic layers. A bulk of the CO 2 is still
trapped under these layers and this has reduced the
amount of free CO 2 that has reached the cap rock
(Hermanrud et al. 2009). A much discussed feature of
the seismic images is the presence of a chimney-like
structure in the storage reservoir just above the injector.
This structure possibly formed shortly after injection
commenced, by liquefaction of the sediments breaking
up the thin intra-reservoir shale layers (Hermanrud et al.
2009). Although CO 2 has migrated through what was
thought to be a tight shale layer in the cap-rock and into
an overlaying sand wedge, there are no indications of
further leakage to shallower depths.
24.7.2 Snøhvit CCS Project
Gas produced from the Lower to Middle Jurassic Stø
Formation at Snøhvit contains 5–8% CO 2 . This gas is
transported by pipelines to the processing plant at
Melkøya, where CO 2 is captured and transported back
underground. CO 2 storage started in 2008 with injection
into the early Jurassic Tuba ˚en Formation, which lies
just below the gas-producing Stø Formation In contrast
to the Utsira Sand, the stratigraphic sequences in the
Barents Sea region have experienced a complex history
of burial and later tectonic uplift. The present-day depth
of the Tuba ˚en is about 2,400 m at the injection site, and
temperature and pressure before injection were 95
C
(Hansen et al. 2013) and 240 bars (assuming hydrostatic). The depth and temperature at maximum burial
may however have been more than 3,200 m and 130
C.
After a short period of injection, the operation experienced problems with rapid pressure build-up,
interpreted to be caused by reactions clogging the
pore space and reducing the permeability around the
well (Hansen et al. 2013). In the Tuba ˚en Formation,
these reactions could be: (1) salt formation (scale)
caused by the drying-out of highly saline brine around
the well; or (2) CO 2 hydrate (clathrate) formation. As
CO 2 entered the reservoir at low temperature (4
C) and
pressures were higher than 290 bars (Hansen et al.
2013), the latter is more likely (Kvamme and Tanaka
1995, Duan and Sun 2006), although the highly saline
brine depresses the freezing point of CO 2 hydrate (Duan
and Sun 2006). Salt (halite) formation caused by injection of dry CO 2 has been predicted numerically (Muller
et al. 2009) and in laboratory experiments (Bacci et al.
2013), and although not yet observed in situ, could also
very well be the reason for the pressure build-up. After
the initial pressure build-up was solved by chemical
treatment, the operation continued. Unfortunately, the
tight and compartmentalised Tuba ˚en Formation turned
24 Carbon Capture and Storage (CCS)
599