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The Longyearbyen CO2 Laboratory Adventdalen, Svalbard – a test site for
storage, flow and leakage of fluids in an unconventional reservoir
by Snorre Olaussen, Alvar Braathen, Kai Ogata, Kim Senger and Jan
Tveranger
http://co2-ccs.unis.no/
Let’s follow the CO2 from the source
to the solution.
Let’s develop high level, field based,
university studies along the CCS
chain.
Let’s turn Longyearbyen into a high
profile show case as a community
that takes care of its emissions.
Longyearbyen CO2-lab - an unique test site
“everything” within a radius of 7 km
An integrated research and education laboratory at UNIS
Local advantages
Local power plant is “pilot size”
Svalbard is a closed energy system running on locally extracted coal
Reservoir quality sedimentary rocksm
Locally available competence in areas vital to the project
Local attention and acceptance no NIMBUS
Researchers in work by 2011 • Finances: 50% government funding, 50% private funding
• 102 researchers involved, including NRC-funded PhD-Postdoc’s
• Research contributions by; UiBergen and UiOslo => SUCCESS Center UiTø – marine, NTNU – rock properties, UiS - injectivity UNI Research, NGI, IFE, Norsar, NGU, Sintef / BIGCCS Center Current contractors: Consultants, Arctic Drilling, • Scientific inputs and funding by; ConocoPhillips, Statoil, Lundin Norge, Statkraft, Baker Hughes SNSK, LNS, Gassnova • International alliances
The Longyearbyen CO2 laboratory
"The Longyearbyen CO2 lab" concept covers research, monitoring and education. Master/PhD University level courses
Phase 1
Phase 2
Phase 3
Phase 4
Identify the reservoir
Injectivity test
CO2 injection monitoring
CO2 capture
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
-Drilling and coring of wells
-Seismic survey
-Reservoir description/assessment
-Verify injectivity
-Verify storage capacity
-Demonstrate sub surface CO2 storage
-Monitor CO2 behaviour
-Carbon capture from local power plant
CO2 storage in Svalbard
Scientific challenges motivating international
collaboration
High Arctic location, but global challenges
Region sensitive to
climate changes
Svalbard uplifted part of a platform with oil-gas
reserves
Arctic basin
Greenland Svalbard
Russia
Iceland
Tromsø
70oN
Longyearbyen
78oN
Map from Henriksen et al
Well known subsurface Reservoir –seal - pressure – fluid flow
Skrugard
Triassic HC System
Jurassic HCSystem
Triassic and Jurassic HC System
Triassic HC System
Palaeozoic system
Jurassic HC System
Triassic and Jurassic HC System
Spitsbergen Geology and CO2 site
Longyearbyen
N’ern and W’ern rifted
margins
Tertiary Central basin
Mesozoic - Permian
platform succession
Carboniferous basins
Devonian basin
Precambrian Silurian
succession
Metamorphic basement
Main target interval – shallow
marine sst at ~670 m depth
De Geer Formation and
Wilhelmsøya Subgroup
Target interval – shallow marine sst
at ~140 m depth
Helvetiafjellet Formation
Mainly fluvial and shallow marine sand and shale
Regional dip towards SW
Lower parts of stratigraphy exposed some 15 km NE of planned injection site
Large, low angle thrust faults in Jurassic succession
Borehole 3 and 4
Borehole 1 and 2
Section in van Keulen fjorden (Photo A. Braathen)
Find the efficient Trap
No trap but a monocline Outcropping to the north east
Longyearbyen CO2 lab with open reservoir Spill scenario – unconventional reservoir (open aquifer, fracture flow)
Assumed
direction of flow
Permafrost
roof
Effects of CO2 liquid=>gas
transitions?
Effects of permafrost - CO2
hydrate?
Fracture, rock matrix and mineral
interactions => CO2 trapping?
Seismic ; 2D and micro seismic Drilling ; 6 wells deepest 970m Core analysis, Petrophysics, petrology, rock mechanics, porosity , permeability, fracture Water tests/formation test (LOT), fluid flow
Presentation of results - based on;
Well park
Dh3, Dh4, Dh5 and Dh6 Dh1 and Dh2
Area plan, Longyearbyen and vicinity
Well DH 3,4,5 and 6
Well DH 4
N
Establishing seismic base line during winter time (Explosives as source - minor harm on nature)
Seismic surveillance of the reservoir and improvement of the geophysical baselines in Adventdalen
970m
Tight seal
Reservoir unit
Surface
Permafrost 100m thick
Drilling, well design
6 drill holes Drill holes to 516, 860, 403, 970, 182 and 440 m
Full coring; 3250 m core
Slim-hole el-logging
- Drill rig: ONRAM 1500
- Set up: slim-hole, wire-line full coring
- 1000-m deep hole of c. M$ 1
Problem: Well bore stability in fault zone (swelling clay)
Actions: 4 level telescope operation, KCl-mud, cement
Sta
te-o
f-th
e-a
rt w
ell
de
sig
n (
DH
4)
Reservoir description
Risk mitigation of the subsurface
Top Reservoir 670m
TD 970m
Upper Triassic to Middle Jurassic sandstones Extension of reservoir body
Sedimentary rock studies
Outcrop and core studies by
3 Master stud, grant for one PhD in 2010.
Foto A. Mørk
Reservoir characterisation
dike
From Riis et 2008
Boreholes Dh3 and Dh4
Boreholes Dh1 and Dh2
Longyearbyen
Mainly paralic, marginal and shallow marine sandstones and shales capped by coarse-grained lag deposits (condensed section)
Cretaceous igneous intrusions (Diabasodden suite); Dolerite sills and dykes
Regional dip towards SW - reservoir section exposed ca.20 km NE of the drilling site (no stratigraphic closure)
Drilled interval
Main target interval at ~670 m depth - L. Jurassic-U. Triassic De
Geerdalen Fm. and Knorringfjellet Fm. (Wilhelmøya Subgroup)
Geologic outline
Drilled plugs for special laboratory studies Top saline aquifer?
Properties of aquifers in drill core => cored three aquifers, but not the target sandstone Plug poro variable => 2-14% Plug perm => low Miniperm air-permeability of sandstone – 2-20 mD … target sandstone not cored => uncertainty, but we expect better sand deeper in aquifer
0
100
200
300
400
500
600
700
800
9000,01 0,1 1 10 100 1000
Dep
th m
Perm Kg(mD)
Relationship between depth and permeability for both Miniperm and ResLab data
Miniperm
650
700
750
800
850
900
950
1000
0 5 10 15 20 25
650
700
750
800
850
900
950
1000
0 0,5 1 1,5 2
Porosity (%)
De
pth
(m
)
Gas Average Permeability (md)
Permeability
Porosity
Wø
Porosity and Permeability for 51 samples from well Dh4
Highest porosity and permeability
Microdarcies permeability
Moderate porosity and permeability
Lowest porosity and permeability
”the Rogers City is clearly demonstrated to be only a local sequestration target with an estimated geological sequestration capacity of 0.13 Gt. In contrast, storage capacity in the Dundee is stimatedat 1.88 Gt”
300m Cored section of the potential reservoir unit (CO2 - storage unit); Upper Triassic to Middle Jurassic Shallow marine sandstones and shales
DH-4
Top Reservoir 670m
750m
800m
850m
900m
TD 970m
950m
700m
30
7
9
6
2
5
11
2
2
10
2
10
4
1
Log from A. Mørk, Sintef
Gross Reservoir Unit 300m Net drilled sandstone of the reservoir unit => 93m Porosity varies from 2 to 18% Permeability varies from 0,1 to 2 mD Highly fractured rock
First gross test interval (870m-970m) => 100m Net sandstone of the first test interval => 33m Net sand/gross first test interval= 0,33 (e.g. possible N/G 0,2-0,3)
Sand-
stone
Test
Inte
rval
1
2
2
1 2
m
Risk mitigation of the subsurface Resevoir properties (e.g. efficient pore volume and fluid flow)
Test equipments (BJ Baker Huges) )
Pressure
Temperature
What is the nature of the microseismic events that started ~17 hours after shut-in of a 5-day water injection experiment? 1) Induced due to water injection experiment? 2) natural local seismicity?
SH1 SH3
SH2
Injection well
North (sketch only,
not to scale)
DH3
Approx.epicentre
Steps towards a good answer:
- include SPITS stations in location
- refine P and S wave velocity model
- find repeater events and provide better depth estimate
for location
- do stress field modeling
Calculation of stress field changes due to filling/draining of reservoirs
Schematic view after Segall et al., 1998
Gas reservoir
Reactiveted
weakness zones
(Conceptual model from Dahm et al., 2010)
Shear stresses at
6 km Depth
and along fault
plane
Skifergassanlegg i USA Foto: Ørjan Ellingvåg Skifergass-boring utløste jordskjelv
Hydraulisk frakturering som brøt opp skiferlag får skylden
for et jordskjelv på 2,2 på Richters skala i England.
How can this rock swallow more than 1000l/min?
Fractured reservoir characterization of the Longyearbyen CO2 lab
Closed fractures distribution Top reservoir
Fracture characterization
Micro-faults/phyllosilicate-disaggregation and deformation bands
Sealed (mineralized) fractures (veins)
Open fractures distribution Top reservoir
Joints
Shear fractures
Mostly joints and subordinate shear fractures (strike-slip and dip-slip)
Through-going and bed-confined fractures
The net sandstone of the reservoir succession is around 25-
30%; net permeable sandstone close to 10-15%.
Characteristics of the reservoir Open-type
Tight
Good injectivity
Under-pressured
Analyzed interval
~ 100-150 m
~ 200 m
~ 450 m
~ 300 m
Laboratory analyses on rock plugs: • Porosity (low to moderate) => 5 to 18% • Permeability (very low) => 1 to 2 mD • Cap rock permeability (extremely low) => nano-D
Water injection test (870-970 m TD):
• Efficient permeability => 40-50 mD*m
• injectivity vs pressure increasing due to fracture opening and growth
• under-pressure between 30% and 60% of hydrostatic pressure
Outcrop studies:
• Sandstone bodies (e.g. storage units) are laterally continuous
• Highly fractured rocks
21 facies identified and described and included in the models
Simple layer cake model supported by observed lateral continuity of beds
Near-well facies model
Pressure
1000m
0 50 100
500m
10m above msl
Permafrost 100
Bar DH 4
1.
50 bar at 870m (860msl)
33 bar at 180m (170 msl = Festningen Sandstien
400m øvre jura nedre kritt skifer
Abnormal under-pressure (50 bar below hydrostatic) in Upper Triassic sandstone at West Spitsbergen at 870m TVD (856m
below MSL)
2
4 3
1
Reservoir quality and pressure cells
Project targets upper reservoir, 670-705 m
10
30
50
70
90
Pre
ssu
re (
bar)
-20 0 20 40
criticalpoint
Temperature ( C)o
lower
middle
upper?
upperaquifer
Pre
ssure
(bar)
Temperature (o
C)
1
10
100
300
-100 0 50
Triple point
Critical point
Solid Liquid
Vapor
50
-50
Lower reservoir870-970 mCP~70 barMiddle reservoir
770-870 m
CP~60 bar
Upper reservoir670-700 mCP~55 bar
Upper aquifer150-180 m
CP~35 bar?
Targeted reservoir Best properties Best pressure? Less risk for drilling
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
0 100 200 300 400 500 600 700 800
Pressure bar
De
pth
m
7119/9-1 Tromsø Basin
7219/9-1 Tromsø Basin
7219/8-1S Tromsø Basin
7321/7-1 Fingerdjupet
7321/8-1 Fingerdjupet
7321/9-1 Fingerdjupet
7119/12-1 Tromsø Basin
7119/12-3 Tromsø Basin
LOT/FIT
Linear (Hydrostatic gradient)
Reservoir pressure Tromsø Basin and Fingerdjupet Subbasin
Hydrostatic gradient – average salinity
Westward
norge
Underpressure formed by gas production in the Frigg-Heimdal area
Initial pressure gradient before Frigg production 1974
Gas production from Frigg and Heimdal: fluid taken out of the aquifer system - aquifer pressure depleted
Why underpressures - why do they form? Underpressures are reported from eroded basins, e.g. Alberta, Songliao
Swarbrick and Osborne 1998, AAPG Mem. 70
But possible analogue Small effect if any, not applicable
Unlikely, but possible
Investigate further
Investigate further
………. “abnormally low reservoir pressure (0.3–0.4 of hydrostatic pressure), which is related to thick permafrost, is ubiquitous in large and giant gas fields of theYamal and Gydan Peninsulas (Matusevich and others, 1997)”. (Ulmishek 2003)
The subsurface in Adventdalen has experienced two aquifer systems: • An upper slight over pressured saline aquifer system (artesian or mixed with formation
water ) in Festningen Member - High water flow – good permeability – a bit surprise based on porosity permeability measurements.
• A lower severe under pressured aquifer system in Upper Triasi to Middle Jurassic strata . Low permeable rock– good injectivity due to open fractures.
• Thereby under initial conditions there is an efficient seal between the two aquifer systems
970m
Tight seal
Reservoir unit
Surface
Permafrost 100m thick
Lower aquifer system- under pressure
Upper aquifer system slight over pressure
• Sandstone bodies (e.g. storage units) are lateral continuous
• Low to moderate pore volumes but very low permeability
• Fractures are the main fluid flow conduits
• Efficient permeability (fractures) 40-50md
Preliminary summary and conclusions
Cap rock properties and pressure
RISK MITIGATION
Fluid migration in and around faults Ground water or Hydro Carbons - the economic aspect …
Fault
core
Dewey Bridge Mbr
Throw ~ 30 m
Navajo Sst
Entrada Fm
Slick Rock Mbr
Up-fault fluid migration causing footwall sweeping by reducing fluids seen as
bleaching by dissolution of FeO minerals in high Poro-Perm eolian sandstone
Fault
core
Throw ~ 21 m
Outside Arches National Park, Utah, USA
East San Rafael Swell, Utah, USA
Up-fault flow of reducing
fluids seen as bleaching by
dissolution of FeO minerals
in fractured damage zone in
tidally deposited shale and
mudstone
J. Entrada Fm
Navajo Sst
Bubbling of CO2 along fault plane,
Utah,USA
Well park and monitoring wells (including proposed new wells in black)
Well park and monitoring wells
P-sensor at 870 m
P-sensor at 170 m
Injection well
P-sensor on anulus 3C geophone string
5 geophones to 300 m «Blow-out» from 180 m
– 60 l/min
«Blow-out» from 175 m – 120 l/min
«Blow-out» from 170 m – 25 l/min
«Blow-out» from 180 m – 50 l/min
Injection
LOT
LOT
Position of new drill holes; Dh5, Dh6 (Dh 3 and Dh 4 are existing drill holes)
Geophone a
Geophone a
Planned infrastructure and position of present drill holes (Dh 3 and 4) and planned new drill holes 5 – 6. The drill rig will be positioned over each of the new locations for a period of time.
Dh 4 Dh 5. 33 x 0518939 UTM 8681094
Dh 3
Dh 6 33 X 0518857 UTM 8681080
Protective zone
Reservoir bodies as input to a “Ness analogue” Depositional setting and sequence stratigraphy of the Helvetiafjellet
Formation at Fleksurfjellet, Svalbard
(Johannenssen & Olaussen, 1984 Statoil report)
“Blow out” well DH5, 175m Festningen Member, Adventdalen
Over pressure at 175 m depth Artesian water flow (120 l/min) from saline aquifer, leakage clogged by 120 m ice plug after 48 h.
1000m
0 50 100
500m
10m above msl
Permafrost 100 -110m
Bar DH 4
37 bar at 870m (860msl)
24 -25 bar at 170m Festningen Sandstone
400m Upper Jurassic – Lower Cretaceous shale
Pressure plot from DH 4
CURRENT KEY
CHALLENGES
1) Succeed with technical
operations in the High Arctic
2) Better understand the rocks
at 180-700 m depth
3) Risk of leakage
=> tests of summer 2011
4) Injectivity with time,
volume available for CO2
storage =>
cont. exploration in 2012
CONFIRMED RESERVOIR
CONFIRMING CAP ROCK
RESERVOIR QUALITY?
PERMAFROST-LEAKAGE
ENVIRONMENT?
5) Access to CO2 • Import • Research capture • Full scale capture
The project has identified 6 important issues to be addressed for further work next year
• What do we need to map to better understand the reservoir?
(geophysical and geological studies). • The fractures gradually expanding (not stepwise) and how do we further
test this hypothesis, could more geophones record this? • Fracture pressure (LOT) • The injection tests this far only on the lower 100 m (“worst” part) out of
the 300 m section • Are shales of the reservoir section fractured and contributing to
injectivity?
More questions than first spud in 2007
But; • We definitely have and efficient seal for a certain pressure
• There are storage capacity and injcetivity in the main aquifer
• LOT suggest no problem to held an considerable column of
buoyant fluid before reaching fracture pressure
• Surprisingly pressure regimes
• Although well known subsurface – surprises “you learn as
long as you drill”
• Need real stuff within next three years
http://co2-ccs.unis.no/
CF Fm
HF Fm
RF Fm
124.68m
186.54m
172.16m
0.2mm
0.5mm
0.5mm
14% quartz cement
7% modal porosity
15% qtz cement
4% modal porosity
Preliminary sandstone data, Helvetiafjellet Fm. (HF Fm)
11% siderite cement,
11% other cements
3% modal porosity
MBE Mørk
CO2-brine flooding experiments at reservoir conditions, ongoing
samples information next slide
Effective permeability decreases by 73 %
0,00
0,02
0,04
0,06
0,08
0,10
0,12
0,14
0 50 100 150 200
Ab
solu
te P
erm
ea
bil
ity
(m
D)
Overburden pressure (bar)
Unfractured core
Fractured core
Effective permeability decreases by 24 %
Permeability variations for fractured and unfractured core versus overburden (confining) pressure. Sample from Wilhelmøya Subgrp.
• Long Samples (30-40 cm) from Dh4
• At 180 bar overburden pressure
• Brine is displaced by liquid CO2 at reservoir condition
• Absolute permeability with brine flooding is 0.02 mD
• CO2 dispalces 52% of initial water in place
Uplifted part of the Barents Sea
• Most of Svalbard is made up
of sedimentary rocks.
• They can store CO2, oil-gas
or groundwater
• Rocks of mainland Norway
have few storage
possibilities
• Wrong type of rock
• Utilized land
• Conflicts of interests
Svalbard
Barents
Sea
Bjørnøya
Norway
Well designs and monitoring scheme (not to scale)
Conductor
c 80 m
NQ casing
300 m
BQ casing
420 m
Cement
Cement
TD = 435m
Cement
c. 200 m
Open well
Dh4 Dh6 Dh5 Dh3
Conductor
c 80 m
TD 181m
Open well
96 mm With retrivable
casing
Conductor
c 80 m
geophones
TD 403m
Cement
Open well
Cut 56 and
66 mm rod
350 m
P-t sensor 171
181
300
309
420
435
P-t sensor
Tests
Tests
Tests
HQ casing
171m
Baseline study - marine geology studies
2
4 3
1
Test very positive But still some questions.
• Measured incipient pressure and temperature at 870m below surface; 30°C and less than 30 bar (50 bar lower pressure than hydrostatic – there must be an efficient seal)
• Pumped 14M3 Polymer at 124bar pressure drop to 60bar after 12hr. (Low
matrix permeability)
• Stepwise pressure injection test up to 1000/l min and 140 bar max pressure. The 12hr’s 500l/min - All in all 390m3 (The reservoir swallow large volume of water probably by gradual increased fracturing of the reservoir)
• Pumped 16M3 Polymer at max 167bar and 1500l/min pressure drop to 67bar after 19hr (Geophones; unclear results)
• 5 days test. More than 2000m3 injected with slight increase in pressure.
Pressure decreases after shut in - slow (to slow) return to original pressure (Some resistance from the reservoir as expected )
Depth (m) Porosity (%) Permeability (md) Depth (m) Porosity (%) Permeability (md)
672.50 7.35 0.03 771.14 13.18 No Flow
673.68 5.73 0.09 776.22 13.04 0.045
674.38 14.73 0.14 779.07 10.18 0.02
674.95 18.68 1.79 780.40 13.82 0.032
675.49 18.06 1.11 780.60 10.5 0.022
676.30 16.47 1.17 783.00 4.79 No Flow
676.88 16.64 1.78 784.30 8.99 No Flow
677.14 15.92 0.61 788.22 12.39 No Flow
677.92 15 0.097 791.10 10.11 No Flow
678.32 10.54 0.57 791.86 8.43 No Flow
678.88 13.12 0.047 792.09 13.16 No Flow
680.27 8.73 0.09 799.16 10.43 No Flow
681.59 12.47 0.1 803.29 8.79 No Flow
682.08 13.9 0.82 857.50 16.1 0.051
682.27 12.53 0.22 858.31 14.72 0.071
687.22 8.95 0.056 858.38 11.21 0.04
688.45 18.71 0.025 859.34 14.64 0.095
688.71 8.97 No Flow 860.44 13.57 0.051
691.72 9 0.68 867.76 8.17 No flow
692.38 11.05 No Flow 875.36 15.67 0.126
694.08 19.62 0.73 875.93 10.83 0.07
695.11 11.21 0.04 897.08 8.37 No flow
695.25 14.67 0.06 900.97 10.41 No flow
695.28 16.53 0.25 920.70 2.31 No flow
705.25 13.05 No Flow 969.64 5.93 No flow
762.20 6.2 No Flow
Open section of well;
interval used for well test
Data from Farokhpoor et al. (2010)
n=51
-Moderate to low porosity – very low to not
measurable permeability
-Fracture pore volume needs to be established
-Rock permeability insignificant compared to
fracture permeability
Porosity and permeability data – host rock
70m
191;3
177,5
DH 6 DH 5
179,5
168,5 FS
SB
Festningen Member
Ullaberget Member
TD at 182,5m rkb
(182)
(185)
70m
Nearby outcropping strata of the Barremian Helvetaifjellet Formation (Midtkandal et al. 2007)
DH 5, 11m pay
DH 6, 16,5m «pay»
Distance between wells 70m
Samples
• 45 core samples: 500-600 cm3 (12-85 cm long cores)
• 9 core samples: 5-10 cm for fluid analyses
• 20 water samples: 25-500 ml
• 10 gas samples: 10 ml («Analyse av gassen som boblet opp i DH5 fra 180m tyder på at det er ca 99.5% CH4 og 0.5% CO2»)
