Technical Achievement 2010 Snøhvit CO

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Classification: Internal Status: Draft Expiry date: 2012-12-31 Page 1 of 132

AU-SNO-00037

Technical Achievement 2010 Snøhvit CO ² Storage:

Snøhvit CO2 Tubåen Fm. storage capacity and

injection strategy study

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Title:

Snøhvit CO2 Tubåen Fm. storage capacity and injection strategy study

Document no. : Contract no.: Project:

TNE RD NEH CO2 Storage

Classification:

Internal

Distribution:

Corporate Statoil Expiry date:

2012-12-31

Status Draft

Distribution date:

2010-06-30

Rev. no.:

1.0

Copy no.:

Author(s)/Source(s):

Ola Eiken, Olav R. Hansen, Bamshad Nazarian, Hilde Hansen, Britta Paasch, Hege M. Norgård Bolås, Svend Østmo, Philip Ringrose

Subjects:

Snøhvit, Tubåen Fm., CO2 injection, storage capacity, injection strategy

Remarks:

Valid from: Updated:

Responsible publisher: Authority to approve deviations:

Techn. responsible TNE RD NEH CST

Techn. responsible Ola Eiken

Date/Signature:

Responsible:

TNE RD NEH CST

Responsible (Name):

Philip Ringrose

Date/Signature:

Approved by (Unit):

TNE RD

Recommended (Name):

Lars Høier

Date/Signature:

Approved by (Unit):

TNE RD NEH

Approved by (Name):

Eli Aamot

Date/Signature:

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Classification: Internal Status: Draft Expiry date: 2012-12-31 Page 3 of 132 Snøhvit CO2 Tubåen Fm. storage capacity and injection

strategy study Doc. No.

Valid from Rev. no. 1.0

2.1 R

EGIONAL DESCRIPTION

... 8

2.2 W

ELL DATA

... 10

2.2.1 Wells across the field ... 10

2.2.2 CO

2

injection well 7121/4-F-2H ... 11

2.2.3 Reservoir and reservoir properties ... 16

2.2.4 Initial reservoir pressure ... 21

2.2.5 Reservoir temperature ... 22

2.2.6 Formation water composition ... 23

2.3 S

EISMIC MAPPING AND DEPTH

-

CONVERSION

... 25

2.3.1 Seismic datasets... 25

2.3.2 Processing parameters ... 26

2.3.3 Pre-injection mapping ... 27

2.3.4 Revised mapping ... 29

2.3.5 Depth conversions ... 34

2.4 T

UBÅEN GEO

-

MODELS

... 35

2.4.1 Existing Models ... 35

2.4.2 New Modelling Approach... 36

2.5 C

LOSED SYSTEM STORAGE CAPACITY

... 37

3 DYNAMIC DATA ... 40

3.1 I

NJECTION SYSTEM

... 40

3.2 W

ELL PRESSURES AND TEMPERATURES

... 43

3.2.1 Wellhead gauges and valves ... 43

3.2.2 Down hole gauge ... 45

3.3 T

IME

-

LAPSE

S

EISMIC

... 47

3.3.1 2009 Acquisition ... 47

3.3.2 2D line ... 49

3.3.3 4D processing... 49

3.3.4 4D response ... 53

3.3.5 Discrimination of pressure and saturation effects ... 61

4 MODELLING AND INTERPRETATIONS ... 74

4.1 F

LOWING AND SHUT

-

IN PRESSURES

, MEG

WASHES

... 74

4.2 F

ALL

-

OFF ANALYSIS

... 76

4.3 F

LOW MODELLING

(E

CLIPSE

) ... 83

4.3.1 Model ... 83

4.3.2 History matching ... 85

4.3.3 History matching; Case 1 ... 87

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4.3.4 History matching; Case 2 ... 92

4.3.5 Further work ... 95

4.4 U

NCERTAINTIES IN FRACTURE PREDICTIONS

... 95

4.4.1 Hydraulic fracturing modes and failure criteria ... 95

4.4.2 Fracture prediction parameters... 97

4.4.3 Fracture predictions: General uncertainty aspects to be addressed ... 97

4.4.4 Estimation of S

3

from leak-off tests ... 98

4.4.5 Vertical extrapolations of S

3

estimates from test location to the interval of interest ... 101

4.4.6 Thermal cooling effect ... 103

4.4.7 Fault reactivation ... 103

4.4.8 Calibration to seismic observations... 106

4.4.9 Summary and recommendations regarding fracture predictions in the Snøhvit field ... 108

5 RECOMMENDED FURTHER DATA ACQUISITION AND ANALYSIS ... 110

5.1 S

UMMARY OF RECOMMENDATIONS

... 110

5.2 W

ELL SHUT

-

INS

... 110

5.3 4D

SEISMIC

... 111

5.4 P

ASSIVE SEISMIC

(

MICROSEISMIC

)... 113

5.5 S

EAFLOOR ELEVATION MONITORING

... 115

5.6 S

EAFLOOR MONITORING

... 116

5.7 D

ETAILED MODELLING AND FORECASTING

... 117

5.8 L

ESSONS LEARNED AND RECOMMENDED FURTHER

R&D

WORK

... 118

6 FUTURE INJECTION STRATEGIES ... 120

6.1 R

E

-

PERFORATE MORE OF

T

UBÅEN

F

M

... 120

6.2 W

ATER PRODUCTION FROM

T

UBÅEN

F

M

... 121

6.3 N

EW INJECTION WELL IN THE

T

UBÅEN

F

M

... 125

7 CONCLUSIONS ... 126

8 ACKNOWLEDGEMENTS ... 128

REFERENCES ... 129

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Abstract

This report summarizes and reviews most of the work done on subsurface aspects of Snøhvit CO2

injection. Input data, current geomodel and flow simulation models are reviewed. The flow rates and well pressure time series, and 4D seismic data, are analysed.

Since CO2 injection started April 2008, the pressure measured in injection well 7121/4-F-2 H has increased more rapidly than predicted, in spite of injection rates of only half the design value. Shut-in pressure is now - June 2010 – about 70 bars higher than the initial pressure. The injection capacity in the well may not be sufficient for the 0.7 megatons per year expected from Melkøya. Improved predictions, as well as plans for increasing well and storage capacity, are needed.

Pressure fall-off during shut-in periods and 4D seismic data which show decay in pressure response away from the injection well, are not compatible with the high permeabilities measured in cores and estimated from logs in the injection well. Our best reservoir model match is obtained with almost an order of magnitude lower effective permeability, even for the most permeable zone, the Tubåen-1. This discrepancy may be explained by lateral heterogeneities such as barriers or channels. This low effective permeability limits the injection capacity of the well. However, the pressure rise is probably not so much influenced by the volume limitation of the injection unit – the Tubåen fault blocks. That is, the main limitation for the current injection well solution at Snøhvit is injection rate and not formation capacity.

At the Tubåen 1, 2, 3 and 4 units the minimum horizontal stress, S3 is estimated to be 429, 421, 419 and 407 bars respectively (most probable values). 10 - 13 bars of tensile strength should be added to obtain the actual (most likely) fracture pressure for tensile failure. This confirms a good safety margin for the 390 bar downhole pressure limitation currently set on injection pressure.

A consequence of the well/near-well capacity limitation is that improved injection capacity could be obtained by a number of well options, such as increased lengths of perforation intervals in Tubåen Fm., a side-track or an additional injection well in Tubåen Fm, placed in the main fault segment.

Further data acquisition and analysis is recommended, in order to obtain better models and predictions.

New data could include sharper well shut-ins (procedures to quickly close valves, in the proper order), 4D seismic surveys approximately every 2^ndyear and a further evaluation of micro-seismic monitoring as a way to control fracturing and potentially to increase well capacity. Further work is recommended on existing data, and on continuing time series from the permanent pressure, temperature and rate gauges, to improve the geology and flow simulation models. In particular, a high-resolution facies model and a finer grid flow model around the well could improve understanding. Such improved models might also be easier to update as injection continues and more data are acquired. We also recommend performing a formal leakage risk analysis.

The addition of a water producer well could give significant additional CO2 storage capacity and potentially solve the challenges related to a pressure increases in the Tubåen Fm. The produced water could potentially be released to the ocean, and the initial flow simulations carried out here suggest this

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is a viable option. Further maturation of this concept should include flow simulations, well design, topside solutions and analysis of the environmental consequences of release to the ocean. Consequence analysis and a careful dialogue with the authorities will be required if this solution is to be implemented.

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1 Introduction

The Snøhvit LNG development, comprising the Snøhvit, Albatross and Askeladd gas reservoirs, was sanctioned 2002 and came on stream 2007. The gas contains 5-8 mol% CO2, which is reduced to less than 50 ppm before the liquefaction process (Maldal and Tappel 2004). Geological storage was evaluated already in Skagen (1991), and later in Hanstveit et al. (2000), and the full CO2 storage concept was described in the PDO document (Maldal 2001), and later on decided. Ocean storage was considered in Kårstad (1999). In 2005 the injection well 7121/4- F-2H was drilled (Arctander 2005), and a 153 km long pipeline was laid from Melkøya to the F-template. Injection commenced April 2008, and about 750 000 tons of CO2 have been injected by the end of June 2010. For the next 30 years, 0.7 Mtons/year is expected to be the injection rate of CO2, giving a total of about 22 million tonnes which shall be geologically stored at the end of the gas production period.

Compositional simulation modelling (Maldal 2004) suggested that the CO₂storage capacity of Tubåen Formation (Fm) in the Snøhvit field area will most probably be sufficient for the whole field life, and that the reservoir pressure is unlikely to exceed 390 bar, which is the current limit set to avoid fracturing. Flow communications from Tubåen Fm in the Snøhvit structure and outwards in the wider basin (and perhaps also with the Stø Fm where sand-sand connection occurs at faults) was expected to reduce build-up of pressure. Also the presence of a compressible gas cap and residual oil in the Tubåen Fm was expected to give sufficient pore space for CO2. However, Maldal (2004) also identified a worst-case scenario with 390 bar exceeded after injection of only 350 000 tons (1/2 year of injection), in the case where the F-segment was completely sealed and no residual hydrocarbons were present.

Injection pressure as measured in the well 7121/4-F-2 H has increased more rapidly than expected, and is at the time of writing about 70 bar above virgin pressure. A lot of work has been done since injection start-up to understand and model the observed pressure development, and to predict its causes (Rasmussen 2010, Statoil 2010). The pressure increase has also received attention from the open press (Teknisk Ukeblad 2010). This report aims at reviewing current knowledge within Statoil, for the benefit of further work on predictions and efficient storage management. Learning’s from this challenging situation will also be useful for CO2 storage in other reservoirs. Public perception of the (still controversial) concept of CCS is at stake if this pioneering project runs into serious trouble or fails.

Interpretation updates and flow models based on the pressure time series and 4D seismic acquired 2009 are presented. Causes of the pressure build-up are discussed, and in particular the relation between well capacity and storage (formation) capacity. Suggestions and recommendations on future data acquisition and further modelling and studies are given.

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2 Static reservoir description

2.1 Regional description

The Snøhvit field is located in the Hammerfest Basin in the western Barents Sea. The basin is bounded by the Troms-Finnmark Fault Complex (in the west), the Asterias Fault Complex (north), the Ringvassøy-Loppa Fault Complex (south) and a flexure against the Bjarmeland Platform in the east. The Snøhvit Field is an elongated E-W trending horst block bounded by normal faults (Figure 1), and located in the central part of the basin (Wennberg et al. 2008). A literature summary and detailed study on the tectonic development of the Hammerfest Basin is reported in Ottesen and Tappel (2003)

In the Triassic to Early Jurassic the Hammerfest Basin was probably a part of a larger epiorogenic depositional regime (Berglund et al. 1986). The rifting of the Hammerfest Basin started in late Early Jurassic. The maximum rifting occurred in the Early Cretaceous, and thermal subsidence continued with some fault reactivation until Late Cretaceous (Wennberg et al. 2008). The deformation was dominated by extension, but reactivation by strike-slip in the Upper Jurassic has also been suggested (Berglund et al. 1986).The domal geometry in the central parts of the basin developed from Middle Jurassic to Early Barremian, and the E-W fault system was formed by flexural extension related to the doming (Linjordet and Grung-Olsen 1992). Most of these faults dip towards the basin axis, where horsts and grabens formed along the crest of the dome.

Due to the opening of the Atlantic margin in the Tertiary, the Hammerfest basin experience several phases of uplift, with a major phase of uplift in Pliocene/Pleistocene. The late uplift in the basin is estimated to be between 700 m and 1100 m (Linjordet and Grung-Olsen 1992), and hence the maximum burial depth and temperature was much greater than today.

The present day stress field in the area is an anisotropic field with N-S oriented (22^o-165^oEast) present day maximum horizontal stress (Ottesen and Tappel 2003). Although the original basin was created during extension it is now in compression.

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Figure 1: Depth map of Top Fuglen Formation with well locations (from Wennberg et al.

2008).

The stratigraphy at the Hammerfest Basin is shown in Figure 2. The lowermost reservoir unit is the Tubåen Formation (Fm) of Early Jurassic (Hettangian – Sinemurian) age. This is a delta plain environment with fluvial distributary channels and some marine-tidal influence (Helgesen and Johansen 2005). Above the Tubåen Fm is the Nordmela Fm of Sinemurian to Pliensbackian age. This is a lower coastal plain depositional environment with brackish, shallow-marine deposits (Wennberg et al. 2008). Following this is the Stø Fm of Early to Middle Jurassic (Pliensbackian-Bajocian) age. This is a shallow-marine environment with alternating lower to upper shoreface deposits (personal communication, Lone Christensen). The Stø Fm is covered by the Fuglen Fm of late Middle Jurassic age. The main reservoirs at Snøhvit are the Tubåen Fm (CO2 injection) and Stø Fm (gas producing reservoir). The Tubåen Fm is dominated by distributary channel facies leading to possible restricted flow compartments (individual channels or channel complexes). The Stø Fm is likely to have better lateral communication because of its shallow marine depositional setting.

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Figure 2: Stratigraphy in the Hammerfest basin (from Wennberg et al. 2008).

2.2 Well data

2.2.1 Wells across the field

Several exploration and production wells have penetrated Tubåen Fm. The geological findings were summarized in Helgesen and Johansen (2005), and further detailed in Johansen et al. (2009). A correlation panel is shown in Figure 3. The Tubåen Fm is sub-divided into 5 zones, with a pinch out of the upper unit, Tubåen 4, towards east. The gamma ray – density/neutron log combination is used to illustrate the variability in sand/shale content across the Snøhvit area. The variation in reservoir properties will be discussed in Section 2.2.3.

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Figure 3: East-west well correlation of Tubåen Fm across the Snøhvit Field, illustrated by the GR and density/neutron log combination distinguishing between sand and shales (from Johansen et al. 2009)

2.2.2 CO

2

injection well 7121/4-F-2H

The well was planned in 2004 (Malm et al. 2004) and drilled between December 7^th2004 to February 6^th 2005 (Arctander 2005). The slot and perforation coordinates are shown in Table 2-1, and various relevant depths are shown in Table 2-2. The well trajectory is shown in Figure 4 and the well design in Figure 5. The well is deviated towards the WNW, with a deviation of about 530 m at Tubåen Fm, where the angle is 27^ofrom vertical. An extended leak-off test in the F-2H well was carried out 13^thJanuary 2005 at 9 5/8” casing shoe in Stø Fm (see depth in Table 2-2). The test results are described and discussed in Raaen (2007), and implications are further discussed in Section 4.4. The well had been cleaned out to 2804 mMD bit depth at February 3^rd2005. The first completion attempt was run from October 5^thto November 23^rd2005 (Storhaug 2006), with perforation done on November 12^th2005.

Neither productivity nor injectivity was tested at that time.

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A second completion operation commenced June 20^th2006, ending in a re-perforation and flowing of the well August 2^nd2006. The completion diagram is shown in Figure 6. The Hold Up Depth (HUD) was established at 2800m and tagged during run 1 in August 2006. During the perforation operation a 6.48 m section of the perforation gun was lost in hole. The top of this ‘fish’ is then at 2793.5 MD, some 1.5 m below the perforated interval. This is planned to be confirmed by a ‘drift-run’ during the upcoming late 2010 well intervention (chapter 6.1).

Well Easting (m) Northing (m)

Surface 501999 7945754

At Tubåen Fm depth 501429 7945892

Table 2-1: Surface and subsurface lateral coordinates of the CO

2

injection well.

Zone MD RT TVD RT TVD SS

Permanent X-mas pressure sensor ~335.5 ~335.5 ~312.5

Water Bottom 341 341 318

Permanent pressure and temperature sensor

1823.53 1805.13 1782.13

Pressure sensor during XLOT 2477.37 2408 2383

Casing shoe during XLOT 2482 2413 2390

TD during XLOT 2518 2445 2422

Top Tubåen Fm. 2677 2586.4 2563

Upper Tubåen Fm perforation Top of zone 2736 2639.4 2616

Bottom of zone 2743 2645.7 2623

Middle Tubåen Fm perforation Top of zone 2748 2650.1 2627

Bottom of zone 2759 2660.1 2637

Lower Tubåen Fm perforation Top of zone 2784 2682.8 2659

Bottom of zone 2794 2691.8 2669

Top Fruholmen Fm. 2798 2695.4 2672

Table 2-2: Depth intervals of Tubåen Fm. in well 7121/4-F-2H [in meters].

Rotary table (RT) was 23.0 m above mean sea level.

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Figure 4: Well trajectory of 7121/4-F-2 H (Arctander 2005). Figure 5: Design of well 7121/4-F-2 H.

Cores were taken at 2520-2586 m MD and 2669-2782 m MD (Gramstad and Mossefinn 2005), which means, that nearly all of the Tubåen Fm (and a few meters of the cap) except Tubåen 1 was cored. However, only 4 core plugs were retrieved from the high porosity/permeability Tubåen 1 interval. These 4 plugs show several Darcy

permeability (3-12 Darcy!) and porosities above 20% (Gramstad and Mossefinn 2005) - but may not be representative of the Tubåen 1 Interval. A normal log suite of GR/DENS/NEU/RT was run across the full Tubåen interval (Statoil 2005). Pressure measurements (MDT) were acquired as well as water samples (Tau 2005).

Measured and calculated logs (CPI) are shown in Figure 7.

After perforation November 12^th2005, no injectivity test were actually planned for, but when placing MEG (Mono Ethylene Glycol) on top of the down hole safety valve (SCSSCV) the injectivity proved to be much lower than expected (Storhaug 2006). During abandonment of this well operation, it was not possible to bull-head into the well, and this led to the second well intervention. Considerations made before re-perforating the well are discussed in Stokkenes (2006). After re-perforation, injectivity was tested on August 4^th2006 (Worren 2006), described and discussed in more detail in Stokkenes (2006). The three injection zones were all fully re-perforated and water produced from all zones combined (Skillingstad 2007). During 4 hours, about 200 Sm³of water was produced, with peak flow of 2000 Sm³/day and average flow of 1220 Sm³/day, at pressure drawdown of 5-8 bar.

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A productivity Index (PI) of 163 Sm³/d/bar was calculated (Skillingstad 2007), and a skin of ~8 was calculated from the pressure build up after shut in. A water injection test was performed, but the well stopped taking volume after about 40 Sm³(equivalent to the riser volume - brine- reaching the perforations), as was the situation in 2005. A second flow test was performed, and the well PI was re-established to 180 Sm³/d/bar, with a skin of ~8.

The kH (permeability x height product) was estimated to 15 Dm (Skillingstad 2007).

Figure 6: Completion diagram of well 7121/4-F-2 H (from Storhaug 2006).

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Figure 7: The CPI log from the Tubåen Fm. of the 7121/4-F-2 well, showing the perforated intervals as red

bars. Panel 1) green-shale, orange-sand, red-irreducible oil, blue-water, Panel 2) green-GR, red-calliper, Panel

3) black-calcium, blue-uranium, red-thorium, Panel 4) resistivity logs, Panel 5) red point-core plug density, red

curve-NPHI, blue-RHOB, Panel 6) green-VPVS, blue-dts, red-dt, Panel 7) black dot-core porosity, red-PHIF,

blue-SW, Panel 8) orange-sand flag, grey dot- KLV, blue dot-KLH, red curve-KLOGH. The zonation of Tubåen

Fm is given in the far left column (from Wærum and Skillingstad 2008).

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2.2.3 Reservoir and reservoir properties

The Tubåen Fm reservoir is a transitional fluvial to tidal influenced reservoir, with increasing fluvial influence upwards. In the lower intervals channel sands can be clearly recognized on both the well observations and on the seismic data (chapter 2.3.4).

Structurally the F-segment is an east-west trending fault block north of the main Snøhvit horst. The main fault has some 100 m maximum displacement in the east, leading to strong compartmentalisation in the Tubåen Fm, while the throw diminishes westwards leading to more potential for flow communication. Communication between the Snøhvit main fault segment and the F-segment may occur at a fault ramp approximately 1 km west of F-2 H, or some 4 km further westwards where the fault dies out. Also communication between the Stø Fm in the F-segment and the Tubåen Fm in the main Snøhvit may occur, due to the juxtaposition setting of the two reservoirs (Figure 9).

Cores covering parts of the Tubåen Fm are available from wells 7121/5-3, 7121-/5-1, 7121/4-D-1H, 7121/4-F- 2H, and 7120/6-1. Detailed sedimentological core descriptions and interpretations are given in Helgesen and Johansen (2005). They suggest a marine-influenced depositional setting; i.e. a marginal marine fluvio-deltaic system. The depositional system is interpreted to be a delta plain. Delta plains are extensive areas of low slope that are traversed by distributary channels and they can have subaerial parts and subaqueous parts (Bridge 2003).

The Tubåen Fm thickness increases from east (7121/5-3, 45.6 mTVD) to west (7120/5-1, 132 mTVD) (over a distance of 45-50 km), and the suggested interpretation is a bypass system in the east with deposition of sediments in the west. Hence, east is the proximal and west is the distal part of the system (Helgesen and Johansen 2005). The western part of the area is a lower delta plain setting (marine and tidal features), while the eastern part is suggested to be an upper delta plain (roots and coal layers). Seven facies associations are

recognized: distributary channels, distributary mouth bars, abandoned distributary channels, interdistribuary bays and lakes, bay head deltas, crevasse splays, and back swamps. These are illustrated by the conceptual model shown in Figure 8. Lateral facies relationships are illustrated by the well correlation panel (Figure 3).

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Classification: Internal Status: Draft Expiry date: 201 2- 12 - 31 Page 17 of 132 Snøhvit CO2 Tubåen Fm. storage capacity and injection

strategy study

Doc. No.

Figure 8: Tubåen Fm conceptual model (from Helgesen and Johansen (2005) ).

Figure 9: Structural setting around the 71 21 /4 - F- 2 H well, injecting CO2into the lowermost three zones of the Tubåen Fm.

North 7121/4-F-2H South

Stø

Tubåen

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The main channel flow direction is suggested to be east-west (Helgesen and Johansen 2005), but the meandering shapes also give a large north-south component to the channel direction, see Chapter 2.3.4. In the younger Tubåen Fm intervals, the channels are more easily observed, compared to the very bottom part of the Tubåen Fm.

This can be interpreted as higher sand – shale ratio in the lower part.

The core from the well 7121/4-F-2H (CO2 injector) shows fine-to-medium grained sandstone with some shale intervals. The core interpretation suggest a tidal influenced bay head delta environment in the lower part of Tubåen Fm (above the lowermost perforated interval) and a more fluvial influenced upper part with distributary channel/mouth bar complexes. Vertically, there is an increasing fluvial influence.

Several thin shales are found, and in particular the interval from 2767mMD to 2784mMD may act as a barrier to vertical flow. Also, shale at 2743 m MD (between the two uppermost perforations) could act as a barrier. However, this shale is thinner and may well be penetrated by vertical flow openings throughout the reservoir volume. Shales are also recognized at the base of the middle perforated interval (2757-2760 mMD), at 2716-2717 mMD, at 2712 mMD, and at 2704 mMD.

Thin sections from horizontal core plugs have been studied for textural and reservoir quality analyses (Aase 2005). The study shows that the sandstones are fine-medium grained, well-sorted, and they are pure quartz arenites. The sandstones are exceptionally clean (< 1 % clay matrix) and totally lack feldspar. This gives

permeabilities 50-100 times higher in Tubåen Fm sandstones than “normal” sandstones for the same porosity and grain size. The porosity distribution in the Tubåen Fm is mainly controlled by the amount of quartz cement, but also by sorting and clay content. The permeability variation is controlled by porosity and grain size. The porosities and permeabilities are given in (Gramstad and Mossefinn 2005). The average porosities and permeabilities for each zone are tabulated in Table 2-3.

Low permeability zones are not only controlled by shale intervals in well 7121/4-F-2H. Modal analyses show at least two sandstone levels where the permeability is less than 1 mD, due to the effects of cementation (Aase 2005). This occurs at 2698 mMD and at 2702 mMD. These zones may also act as vertical barriers to fluid flow.

A zone of high permeability (2-12 Darcy measured on core samples) exists at 2782mMD. The actual core plugs are drilled out within a 35 cm interval, from 2781.85 to 2782.20 mMD (Gramstad 2005). The zone is interpreted from logs to be 5m thick, but this does not agree with the MDT mobility measurements at 2784.9 mMD, showing 72.9 mD (Schlumberger 2005). Furthermore, 7 mobility measurements exist between 2784.9 to 2792 mMD with maximum reading at 451.3mD/cp with an average of 217mD/cp. The sandstone in this zone is coarse and well sorted, and a high permeability zone could act as a lateral migration zone for the injected CO2. In addition, the permeability above this zone, at 2765 mMD, is 1.4 mD, and may act as a barrier to vertical flow. These two effects combined will cause the CO2 to move laterally rather than vertically at this point.

An important factor for the injectivity modelling and prediction is the estimated height-integrated permeability (kH product) over each flowing interval. Values have been estimated for the three perforated zones in Table 2-4.

The lowermost interval constitutes 93% of the kH product of the perforated zones in the wellbore. The value of 40 Dm should be plenty for CO2 injection rates of ~1500 m³/day or less (even 5 Dm should be sufficient), for a laterally homogeneous reservoir.

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MDT measured mobility (Schlumberger 2005) is compared with core plug measured permeability in Figure 10. In Stø Fm and in most of Tubåen Fm the two kinds of measurements seem to be in good agreement. In the upper part of Tubåen 1 (marked with red circles in Figure 10), the permeability measurements in the core plugs are far higher than in the permeability estimates calculated from the MDT pressure measurements. Figure 7 confirms good agreement between the porosity and permeability measured from cores and the estimated values from the electrical logs.

Figure 10: The mobility measured by the MDT tool is compared with the permeability measured on core plugs for the 7121/4-F-2 H well.

Based on initial testing of the well, flowing with 1500Sm³/D of water and a PI of 163 Sm³/D/bar (Skillingstad 2007), the kH product can be interpreted to about 25Dm. This is lower than what had been interpreted from logs (40Dm), but of the same order as the 10.5 Dm estimated from the Tubåen Fm water production test (DST) in the Tubåen 3 zone in well 7121/4-1 in (2497.6 - 2504.2 m RKB) (Milter et.al. 2001).

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Table 2-3: Average Petrophysical parameters for the reservoirs in the Snøhvit area. The lowermost zone averages are from the F-2 H well. NGR-NetGrossRatio, PHITC-TotalPorosity, SWT-water saturation, SWT_J-water saturation from J-curve, KLOGH-permeability horizontal, KLOGH_HM-permeability Harmonic average, KLOGH_GM permeability geometric average (Based on Wærum and Skillingstad 2008 model, new interpretation 2010, pers. com. Eva Holand)

Depth MD Core Porosity Core

Permeability Log Porosity Log

Permeability kH product

Stø 2540-2570 16-17% ~500mD 16-17% 700mD 21000mD.m

Stø2570-2588 10-11% ~10mD 10% 10mD 180mD.m

Tubåen 2680-2690 12-16% 10-100mD 12-16% 10-800mD 10000mD.m Tubåen 2736-2743 10-18% 7.7-450mD 15-16% 100-400mD 2400mD.m

Tubåen 2748-2759 9-11% 0-197mD 10% 10-50mD 550mD.m

Tubåen 2784-2794 No Core No Core 20% 4000mD 40000mD.m

Table 2-4: The well data from 7121/4-F-2H perforation intervals summarized and data sources

compared. The three lower zones were perforated in 2005 and 2006. Data summarized from

Figure 7.

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2.2.4 Initial reservoir pressure

All recorded pressure points from exploration wells in Stø and Tubåen Fms in the Snøhvit area, shown in Figure 11, fits reasonably well to a straight line with a pressure gradient of 0,1046 bar/m. The reservoir pressure in 7121/4- F-2 H was measured (in RUN 2) by the MDT tool during logging operations in January 2005, see Figure 12 (log data are found in Schlumberger 2005), and falls on the same curve. The pressure at any given depth can then be described by:

Pressure[bar] = 0,1046[bar/m]*Depth[mbSL] + 15,054[bar]

Figure 11: RFT measured pressures in all exploration wells in the Snøhvit area. From Milter et al.

(2001).

Wærum and Skillingstad (2008) found all recorded pressure points in the water zone of Stø and Tubåen Fm in 7121/4-F-2 H to fall on a straight line corresponding to a fluid density of 1.08 kg/m³. This is in fair accordance with other wells in the Snøhvit area (Figure 11). It is lower than what could be expected from the measured water density of 1098 kg/m³of the water sample taken from Tubåen Fm (chapter 2.2.6). The apparent “overpressure” of 15 bar requires an average fluid density of 1138 kg/m³from the seafloor and down to top Stø Fm to explain the

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observed pressure data by hydrostatic conditions. Initial pressures at the middle of the three perforations in

Figure 12: Measured MDT pressures in 7121/4-F-2 H well. Pressures are given in bar. For illustration is the water line with a density of 1.03 sg shown (in brown).

2.2.5 Reservoir temperature

The temperature-depth dependence of Stø Fm and Tubåen Fm at the Snøhvit field might be accurate to within +/- 2^oC, based on numerous well tests and measurements during logging:

T (°C) = 0.0269 * depth (m TVD MSL) + 28.1 (Vika 2008) An earlier formula, probably less accurate, was:

T (°C) = 0.0420 * depth (m TVD MSL) – 10 (Malm 2004)

The recorded well temperatures in 7121/4-F-2 H are shown in Figure 13. During logging run #4A the maximum recorded temperature was 96°C on January 29^th2005. The measured temperatures are lower than the model, and this is explained by cooling of the near-well area before the actual temperature reading was done. Above the reservoir a linear temperature gradient is assumed and the seabed temperature is about 4^oC. This gives a temperature gradient of ~4.3°C /100 m above the Stø Fm.

Most probable virgin temperatures at the perforations are then 98-100 ^oC.

7121/4-F-2 H are estimated to be 287.5, 288.8 and 292.1 bars.

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Figure 13: Temperatures recorded during MDT logging in 7121/4-F-2 H in January 2005.

2.2.6 Formation water composition

In well 7121/4-F-2H, (Tau 2005), formation water samples from Stø 5, Tubåen Fm and Fruholmen Fm were taken (Tau 2005, Skillingstad 2007, Wærum and Skillingstad 2008). The samples were collected 29^thJanuary 2005, the Tubåen samples at a depth of 2788 m MDRKB (level of the lowermost perforation, in Tubåen 1) in one 1-gallon and two 450 cm³chambers. Reservoir conditions at sampling were 294 bar and 93.5 ^oC. The samples were analysed by West Lab, and results were reported in Tau (2005). Physical properties of the water are shown in Table 2-5 and ion composition in Table 2-6.

Prior to the injectivity test in 7171/4-F-2 H, water was produced against the test separator on Polar Pioneer from the well on 4^thAugust 2006 (Skillingstad 2007). For about 4 hours, water was produced at rates of up to 2000 Sm³/d, and averaging 1220 Sm³/day. A volume of about 200 Sm³was produced. Water composition of this formation water is reported in Skillingstad (2007) and shown in Table 2-5 and Table 2-6.

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Tau (2005) Skillingstad (2007) Wærum and Skillingstad (2008) (7121/4-1)

pH (20^oC) 4.9 6.1 6.2

Density (15^oC) [g/cm³] 1.098 1.099 1.104

Resistivity (20^oC) [ohm m] 0.065 0.059 0.06

Compressibility (estimated) [10^-5/bar] 3.72

Table 2-5: Physical properties of Tubåen Fm water samples from 7121/4-F-2 H.

Tau (2005) Skillingstad (2007)

Wærum and Skillingstad

(2008) (7121/4-1)

Wærum and Skillingstad

(2008) Stø Fm

Sea water

Concentration [mg/l]

Concentratio [mg/l]

Sodium, Na 43700 48900 56418 50728 10800

Calcium, Ca 5640 6070 4628 4167 411

Magnesium, Mg 589 598 477 520 1290

Barium, Ba 177 145 4 7 10-20

Strontium, Sr 373 378 207 237 8.1

Potassium, K 6570 834 496 6803 392

Iron, Fe 44.1 68,4 n.a. 13.6 0.0034

Chloride, Cl 85100 86700 96418 95271 19400

Sulphate, SO4 38 30 210 233

Bikarbonat, HCO3- 408 482 1618

Total alkalinity 518

Total Dissolved Solids 142749 144000 159340 159598

Table 2-6: Ion composition of the Tubåen Fm water samples from 7121/4-F-2 H.

Analysis of several components related to environmental restrictions regarding discharged produced water was planned for. For this analysis the water samples were acidified (5 ml 4N H2SO4 to 500 ml water sample) immediately after the 1-gallon chamber was drained. The acquired samples were stored on gas bottles- These were supposed to be analyzed for Phenols, PAH and NDP by Sintef. The report from Sintef (referred in Tau 2005) states that these samples were not fit for analysis by their method. The samples contained high concentrations of unknown components (from the drilling mud) that made identification of the wanted components impossible. BTEX has been analysed by West lab and the data are given in Table 2-7.

Table 2-7: Aromatic components in the formation water [mg/l], from Tau (2005).

Benzene 0.10

Toluene < 0.02

Ethylbenzene < 0.02

Xylene < 0.04

BTEX (sum) 0.160

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A water production test (in Stø Fm) was carried out in exploration well 71 21 /4 - 1 (Norman 1984 ), but an analysis of thi s water has not been found. It is recommended to acquire additional water samples in case of a new well penetrating Tubåen Fm. The purpose would be to gain further confidence, in case of release to the ocean of produced formation water in the future.

2.3 Seismic mapping and depth - conversion

2.3.1 Seismicdatasets

The coverage of modern seismic surveys above the Snøhvit reservoir is shown in Figure 14. A 3–D survey covering the Snøhvit structure with an E- W line direction was shot in 1997, and another more “4D frie ndly” survey (with overlapping swaths and shooting straight lines instead of shooting for coverage) was shot in 2003, now oriented N- S, and covering also the Albatross field. In addition a set of 2D baselines for monitoring (with multiple

streamers densel y spaced) were shot 2006. A smaller (8 km x 8 km) 3- D area was shot for monitoring purpose in 2009, centred at the CO2injection well (yellow frame in Figure 14). One of the 2D lines was also repeated during the 2009 data acquisition campaign. Results from the monitoring are described in chapter 3.3. Acquisition parameters for the various surveys are summarized in Table 2- 8. Options for future acquisition are discussed in chapter 5.4.

Figure 14: Coverage map of modern seismic surveys above the Snøhvit reservoir.

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Survey ST9705 ST0306 ST0608 ST09005 ST09005 (2D)

Date acquired 23.5–10.6 1997 23.7-17.8 2003 16.8–26.8 2006 24.8-09.09 2009 17.8 2006

Vessel Geco Beta Ramform Victory Western

Monarch

Western Pride Western Pride

Shooting direction 90 degrees 0.0 degrees 0.0 degrees

Source tow depth 5 m 5 m 8 m 5 m 8 m

Source length 14 m 15 m

Source width 16 m 20 m 16 m 20 m 16 m

No. of subarrays 3 3 3 3 3

Source x-line sep. 50 m 50 m N A 50 m N A

Source volume 3397 in³ 3090 in³ 5085 in³ 5085 in³ 5085 in³

No. of sources 2 2 1 2 1

Shotpoint interval 12.5 m (18.75 m) 18.75 m 18.75 m 18.75 m 18.75 m Streamer type Nessie III digital PGS Reduced

Diameter hydro- streamer

Q Marine Q Marine Q Marine

No. of cables 8 10 10 8 10

Cable separation 100 m 100 m 37.5 m 100 m 50 m

Swath separation 400 m 400 m N A 400 m N A

Cable length 3600 m 3600 m 3600 m 3600 m (4000 m) 3600 m (4000 m)

Near offset 305 m 150 m 205 m 157

Group interval 12.5 m 12.5 m 12.5 m 12.5 m 12.5 m

Group length 16,13 m 12.5 m DGF 31,25 m DGF 31.25 m DGF 31,25 m

Tow depth 7 m 7 m 10 m 7 m 10 m

Bin-size acq. 6,25 x 25 m 6.25 x 25 m 6.25 x 18.75 m 6.25 x 25 m 6.25 x 25 m

Record length 5000 ms 5000 ms 7000 ms 5000 ms 5000 ms

Table 2-8: Acquisition parameters for modern seismic surveys covering the Snøhvit field.

2.3.2 Processing parameters

The structural mapping has been based on the first processing of the ST0306 seismic dataset. The processing sequence (CGG 2005) consisted of:

• Reformat, seis/nav merge, despike and edits

• Re-sample and noise attenuation, tidal correction Q-compensation

• Radon demultiple

• Binning, trace restoration and DECON

• Kirchhoff pre-stack time migration

• Spherical divergent correction, mutes and stacks

• Inverse Q-filtering

• Velocity update and NMO

The version of ST0306 from the 4D processing (ST0306D10) may also be used within this 8 km x 8 km 4D area.

Details on the 2010 seismic processing are reported in Hvidsten (2010), and further discussed in chapter 3.3.

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2.3.3 Pre- injection mapping

A mapping of Tubåen Fm based on the ST030 6 survey was reported in Høyen (2006). A depth map of the greater Snøhvit / Albatross area is shown in Figure 15, and a more detailed map around the 71 21 /4 - F- 2 H well is shown in Figure 16. Høyen (2006) mapped several intra - Tubåen reflections based on incr eased resolution seismic. The Top Tubåen reflection onlaps the Intra Tubåen reflector eastwards. The thickness of Tubåen Fm increases westwards, the thickness variations are small in the F- segment however. Total Tubåen Fm thickness in F- segment is 45 - 55 ms . An amplitude map of the base Tubåen / top Fruholmen reflection is shown in Figure 17, indicating the variation in reflectivity at Top Fruholmen. Also the low amplitude areas caused by gas in the shallower sediments east and west of Snøhvit F- 2 H CO2inje ctor are indicated by red circles.

Figure 15: Depth map of top Tubåen Fm, from Høyen (2006) . Study area outlined by red rectangle, for blow up see Figure 16.

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Figure 16: Detailed depth map of Top Fruholmen Fm., as the 2005 interpretation study stored in OW (pew). The dashed outline shows the area of the 2009 survey.

Figure 17: Amplitude map of the base Tubåen Fm / top Fruholmen Fm reflection, from Høyen (2006) .

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2.3.4 Revised mapping

Revised seismic interpretation of Tubåen Fm has been ongoing since 2009. For the work the initial processing of the ST0306 seismic data is used in order to cover the greater Snøhvit area. Detailed work around the injector 7121/4-F-2 H is based on the 2010 processed seismic data. This has revealed considerable lateral variation in reflectivity within the F-segment, probably a response to geological inhomogeneities. The surface seismic ties to the synthetic seismic derived from well 7121/4-F-2 H is shown in Figure 18. Marked reflections arise at the base of Tubåen Fm / top Fruholmen Fm boundary as well as top Stø Fm.

Figure 18: Seismic tie to well 7121/4-F-2 H.

Amplitudes in the lower part of Tubåen Fm are shown in Figure 19, revealing the considerable lateral changes.

There is a potential for mapping individual channel bodies within the greater Snøhvit Tubåen Fm. Channel widths range from 100 m to 3-400m with map able channel lengths of several km, crossing several fault blocks (see Figure 19 and Figure 20). Shallow high-amplitude reflections in an area east of the injection well, presumably caused by shallow gas, clearly cast shadows beneath, as illustrated in Figure 23.

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Figure 19: RMS instantaneous amplitude in the lower part of Tubåen Fm (36 ms below mapped top Tubåen reflector). Magenta arrows indicate examples of channels interpreted at this level.

Figure 20: RMS amplitudes in Tubåen 1. Channel forms are clearly distinguished in this interval

and heterogeneity observed around the injector well.

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An example of a wide channel is shown in Figure 21 , from the lowermost part of Tubåen Fm. The high amplitudes could be interpreted as a channel showing differential compaction. This could indicate that the higher amplitudes reflect sand - rich facies in that interval. Well logs (71 20/6 - 1 & 71 21 /4 - F- 2- H) show in this interval low gamma ray values (Figure 22), i.e. low shale content and coincide with the high amplitudes. The shallower sections in the Tubåen Fm do not reveal such clear channel forms. It might be possible to work out a correlation between amplitudes and facies in the shallower Tubåen Fm intervals, but this requires more work.

Channel forms can also be distinguished by using frequency decomposition techniques as illustrated in Figure 24 and Figure 25.

Recommended future work include producing attribute maps which reflect facies distribution for all Tubåen Fm intervals. These data should then be exported into RMS and conditioned to the log and core data in order to

Figure 21 : Example of a wide channel in the north - western part of the area displaying high amplitudes (lnea) and differential compaction. This could indicate presence of sand - filled facies.

produce a geomodel which is conditioned on log, core and seism ic data.

320m

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Figure 22: Left: LFP-GR (blue) and LFP-SAND (yellow) logs with top and base Tubåen Fm picks (purple) for injector well 7121/4-F-2 H. Right: Seismic section (lmig16) showing injector well 7121/4-F-2 H with picks and corresponding depths in time.

Figure 23: Amplitudes of shallow gas and deeper horizons, in a perspective view.

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Figure 24: Amplitude extracted along the interpreted seismic surface on Top Fruholmen (left), RGB-blended image 16 ms above Top Fruholmen Fm (right). The blending was based on three extracted frequency cubes of 12, 32 and 54 Hz from the same seismic cube.

F-segment

Figure 25: Seismic time slice parallel to the Top Fruholmen / Base Tubåen Fm. showing

meandering channels across the Snøhvit main segment, as well as across the CO

2

injection

reservoir, the F-segment.

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2.3.5 Depth conversions

The most recent depth conversion in the Snøhvit area has been reported by Johansen et al. (2009). Stacking velocities have been included from the seabed to top Fuglen Fm. and a linear velocity trend in the interval between top Fuglen Fm and top Fruholmen Fm, as shown in Figure 26. Høyen (2006) gave special attention to the northern and westerly areas, where gas push down anomalies are found. The corrections (Karlsen and Christensen 2006) was done in RMS and included flattening of time horizons below the anomalies and applying the same time shift on the subsequent deeper formations. The difference time map is shown in Figure 27. In 2007 a PSDM processing was performed to compensate the shallow gas effect, particular west of the 7121/6-1 well (Karlsen 2007).

Seabed Vint = 1484 m/s

Base Tertiary

Top Kolje

V stack

(‘automatically’ picked stacking velocities)

Top Knurr Top Hekkingen

Top Fuglen

Top Stoe5 Top Nordmela

Top Tubåen

TopTriassic

V

linear trend

V

linear trend

V

linear trend

V

linear trend

Figure 26: Depth conversion method used in Johansen et al. (2009)

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Figure 27 Map of time correction caused by shallow gas.

2.4 Tubåen geo - models

2.4.1 Existing Models

The Snøhvit PDO geo - model was compiled in 2001 (Malm et al. 2001 ), with volumes and uncertainties described in Siring 2001 . A lot of effort has been put into a detailed Stø model, while the Tubåen Fm reservoir was originally modelled with only one layer, 100 m thick and with constant properties. An update of the reservoir model was made in Karlsen 2007 and consisted of a combined Stø Fm and Tubåen Fm model. The 2007 geomodel had initially 10 layers in Tubåen Fm. In 2009, another model was bu ilt (Johansen et al. 2009 ). The aim of this model was to include seismic data from the new survey of the Askeladd Field, from improved imaging in the Snøhvit gas- cloud area, and to get a better representation of the Tubåen Fm in the Snøhvit field , as compared to the previous model. The focus was the CO2injection.

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Snøhvit CO2 Tubåen Fm. storage capacity and injection

In the 2009 model, a more detailed geological study of the Tubåen Fm was done. The Tubåen Fm geological model and the corresponding simulation grid were refined, from 10 to 64 layers in the geomodel and from 1 to 5 sub grids in the simulation grid. Tubåen Fm was subdivided into 5 different zones, resulting in a more detailed reservoir model (from 1 to 5 zones). Core description and biostratigraphy (Helgesen and Johansen, 2005), and facies were used to establish a reservoir zonation in Tubåen Fm. A net-property modelling approach was taken for distributing both porosity and permeability. All parameters were modelled with a kriging approach, and as an alternative, porosity and permeability was also modelled by stochastic simulations. Only smaller changes were made to the petrophysical model, such as a new porosity estimate (PHIT). The VSH and KLOGH model, and the cut-off used for gas and oil zones did not change in the new model. A new water saturation model was made, based on new SCAL measurements. The porosity and permeability was modelled based on field wide

observations and correlation lengths as a random field, however tied into the well data, prior to up-scaling. The model was built in RMS.

Increasing from one to five zones in Tubåen Fm geological model was necessary as only one zone did by no means capture the geological variation within the formation. Five zones allowed for more geological variation as different zones could be assigned different values and distributions. In particular, any barriers within the formation could be included. These barriers are crucial for CO2 flow and volume estimates.

While the main faults are clearly imaged by the seismic, there may be sub-seismic faults of importance for the reservoir properties. The effect of sub-seismic faults on the Stø Fm has been addressed in Ottesen and Tappel (2003), but the effect on the Tubåen Fm has so far not been investigated. The previous fault seal studies have been focused on the Stø Fm, however the two studies Ottesen and Tappel (2003) and Worthington (2008) showed the clay content in Tubåen Fm to be much higher than in Stø Fm, and then small faults are likely to reduce permeabilities much more than in a sand-rich formation. It is therefore recommended that a more detailed study on sub-seismic faults and their consequences on flow properties should be investigated for Tubåen Fm on Snøhvit.

2.4.2 New Modelling Approach

A new modelling approach is suggested as CO2 storage requires a geological model focusing only on the Snøhvit field and CO2 related issues, e.g. local barriers to flow, reservoir and cap rock geometry, and cap rock integrity.

The geological model should include a facies model of the Stø Fm and Tubåen Fm, as well as the caprock intervals Nordmela and Fuglen Fms. This would give a better basis for injection strategy and for the prediction of CO2

migration and storage volumes. We would like to capture all possible geological scenarios, and will aim at alternative geological models for uncertainty studies. The models will be built in RMS.

In the short term we suggest a ‘log-based’ facies model as input to the geological model. This should include sand/shale relationships, low/high permeability zones, thin/thick layers, good/poor reservoir zones and barriers to flow. In the longer term we suggest doing a detailed ‘core-based’ facies analysis, where both well and core data are included to define a facies model for the Tubåen and Stø Fms. This will include a detailed sedimentological study from cores, as well as permeability and porosity data from cores and core plugs. A result of this will be a detailed depositional model, which will include a higher zonation of the Tubåen Fm than previous models. For

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Snøhvit CO2 Tubåen Fm. storage capacity and injection

instance, the Tubåen 1 zone could be divided into three zones, a.o. based on permeability, with a high permeability zone in the upper part of Tubåen 1. This high permeability zone may have a large effect on where the CO2 flows.

We will make sure that the up-scaling method honours the geological variation and that all necessary geological input is included in the reservoir model for best results. The geologist making the geomodel should be involved in the reservoir model build to ensure that all necessary geological input is included. Otherwise important and valuable geological information may be lost and hence affect the result of the study and the final decisions made.

2.5 Closed system storage capacity

Storage potential of a closed volume is determined by the volume compression of water, oil and gas, and expansion of the pore space, as well as the pressure increase. In the following we give estimates of the different factors contributing to the closed system storage capacity. The connected pore volume of Tubåen Fm is uncertain, pending on seal properties of faults and vertical communication between zones. Pore volume estimates are shown in Table 2-9, with a maximum of 2.584 x 10⁹m³for the greater Snøhvit area.

Communication out of this volume is also possible.

Greater Snøhvit area Inside ’Snøhvit main’ F-segment Pore volume

[10⁶m³]

Area [10⁶m²]

Pore volume [10⁶m³]

Area [10⁶m²]

Pore volume [10⁶m³]

Area [10⁶m²]

Tubåen 4.2 563 302 258 105 152 61

Tubåen 4.1 101 294 44 102 29 61

Tubåen 3 758 360 307 119 140 61

Tubåen 2 712 363 274 121 132 62

Tubåen 1 450 358 189 121 93 62

Total 2 584 1 677 1 072 569 548 307

Table 2-9: Pore volumes and areas for Tubåen Fm.

Compressibility of water with 13% salinity (Table 2-6) is, according to Osif (1988) 3.72 x 10^-5bar^-1.

The most recent estimate of pore volume compressibility for Tubåen Fm has been made by Gemmer and Hettema (2010), and is:

Base case, Cpp=0.8 x 10^-5bar^-1 Low case, Cpp= 0.3 x 10^-5bar^-1 High case, Cpp=3.6 x 10^-5bar-1

These estimates have significant uncertainties, as they are based on core and log data, and no field-scale calibration is available. Specific uncertainties are (Gemmer and Hettema 2010) i) assumption of no elastic contrast between reservoir and surroundings, ii) assumption that the samples used for the triaxial tests are

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Classification: Internal Status: Draft Expiry date: 201 2- 12 - 31 Page 38 of 132

representative for Tubåen Fm. They recommend to carry out geomechanical modelling to address i), which should lead to a large reduction in the uncertainty of Cpp

A 4 m gas cap was encountered in the uppermost zone of Tubåen Fm. in well 71 21 /4 - 1, drilled high on the Snøhvit structure. A minimum gas volume has been calculated; see Figure 28 and Table 2- 10. A gas expansion factor (Bg) of 0.0046 has been used in the calculations giving a total of 262 mil l Sm³gas initially in place.

Figure 28 Map of possible gas cap extension in Tubåen Fm (

10⁶m³

Bulk volume 9.0

Net volume 8.7

Pore volume 1.4

Hydrocarbon PV 1.2

Gas Initially In place 262

Table 2- 10: Volume estimate of gas cap in Tubåen Fm, all in 10⁶m³.

The Tubåen Fm. is not fully delineated, as minor gas volumes also may exists in other zones close to the top of the structure or in higher areas of the F- segment, such as west of the F- 2 H well and east of the 6- 1 well. Any residual oil present in Tubåen Fm will also be compressed. This has been discussed in Maldal (2004) .

For a ‘tank’ of volume V infinite permeability and average pressure increase p, storability given by rock and water compressibility is given by:

m = V = p (cp+cw) V

Possible closure at Top Tubåen level -

2451mTVDSS

Technical Achievement 2010 Snøhvit CO

AU-SNO-00037