333
Hydrocarbon potential of the Central Spitsbergen Basin
A.
N¢ttvedt, F. Livbjerg, P.S. Midb¢e and E. Rasmussen
Modern oil and gas exploration on Svalbard has not yet resulted in any commercial discoveries. Is this symptomatic of the area,
or may new play concepts and improved exploration techniques change this picture? This is a key question regarding a remote
exploration province where, as we judge it, the hydrocarbon potential has barely been tested successfully, despite the recent
completion of a 14th wildcat.
Post-Devonian sediments cover most of central Spitsbergen south of ls�ordcn and cast of the West Spitsbergen Orogenic Belt.
The basic preconditions for a hydrocarbon discovery seem to be met in general: mature source, reservoir and cap rocks are known
to exist and several closed structures have been mapped. Yet, based on tectonic style, basin filling and timing, the prospectivity of
different exploration sub-provinces can be clearly discriminated between.
Sub-pr()Vince 1- West Spits�rgen Orogenic Belt: The eastern, thin-skinned part of the West Spitsbergen Orogenic Belt (Tertiary)
has a limited hydrocarbon potential. Ramp anticlinal structuring within late Paleozoic-early Mesozoic carbonates and clastics
produced closures, but strong cementation and tectonic fracturing have partly destroyed reservoir quality and cap rock properties.
Sub-province 2- Central Spitsbergen Basin, westflank: The west llank and axial part of the Central Spitsbergen Basin foredeep
also has a limited potential. Blind anticlinal closures in the late Mesozoic-Tertiary overlie deeper ramp anticlines or thrust
duplexes, but with overall poor reservoir quality and cap rock properties. l-ligh thermal maturation indicates a gas prone area.
Sub-province 3- Cemral Spitsbergen Basin eastf/at�k: Improved reservoir quality and maturation profile (north) eastwards arc
negated by a general lack of larger scale structuring along the east llank of the Central Spitsbergen Basin.
Sub-pr()Vince 4- Billefjorden Fault Zone, easrwards: Carboniferous extensional tectonics and fault block rotation produced large
closures, and good quality source, reservoir and cap rocks arc present in Carboniferous-Permian outcrops. However, thermal
maturity varies from oil to gas maturation and reservoir quality is reduced with increasing subsurface depths. Ramp anticlines
(Tertiary) above a Mesozoic decollement produce a second play. Oil prone source rocks are present, but structural closures are
generally small and reservoir and cap rock properties become a problem.
Further eastwards, less structuring reduces the general trap potential. One exception is along the Lom�orden Fault Zone,
where ramp anticlines are also present. Reservoir quality and source rock maturation seem favourable, but present shallow burial
reduces the seal potential.
Introduction
Spitsbergen is the largest island in the Svalbard
Archipelago, which comprises all islands in the area
74-81°N, 10-35°E (Fig. 1). The archipelago covers a
total land area of 62,700 km2, of which approximately
60% is permanently covered by glaciers and inland
icc. Because of the North Atlantic Current, western
sea approaches are ice-free most of the year and the
climate is relatively mild.
Originally, Svalbard was politically a no-man's
land. The archipelago came under Norwegian
sovereignty in 1920. However, according to regu­
lations of 1925, all signatory nations to the Svalbard
Treaty have equal rights of exploration and economic
exploitation of the area. Thday, about half of the total
land area, a little more than 30,000 km2, is preserved
as national parks and reservations and protected
from any industrial development. In essence, only
Bj0rn0ya and central-north Spitsbergen are open for
general exploration.
In this paper, we summarize the hydrocarbon po­
tential of central Spitsbergen, based on results from
a recent joint exploration venture between Store
Norske Spitsbergen Kulkompani (Store Norske) and
Norsk Hydro (Hydro). This is the first attempt to
present an outline of the existing oil industry knowl­
edge on Svalbard, although sporadic contributions
to the hydrocarbon potential of the area have pre­
viously been published (Nagy, 1965; Manum and
Throndsen, 1978; Dalland, 1979; Throndsen, 1979;
M0rk and Bjor0y, 1984; Worsley et al., 1986).
From an exploration point of view, the important
issues are: Have liquid hydrocarbons been generated
on central Spitsbergen? When were they generated?
Are they still there? If so, can they be economi­
cally exploited? These questions are addressed and
discussed below, and the parameters that control
Arctic Geology and Petroleum Potcmial edited by T.O. Vorren, E. Bergsager, 0.A. Dahi-Stamnes, E. Holter, B. Johansen, E. Lie and
T.B. Lund. NPF Special Publication 2, pp. 333-361, Elsevier, Amsterdam. Cl Norwegian Petroleum Society (NPF), 1992
Printed l993
334
the overall hydrocarbon potential of the area are
evaluated.
Exploration history
the general exploration of Svalbard accelerated
at the turn of this century, the possibility of economic
oil and gas discoveries was accordingly considered.
The early exploration history of Svalbard is brilliantly
summarized and described by Hoel (1966)..
Residual oil in Triassic rocks had been reported by
Nathorst in 1910, and in the following years other
oil and gas seeps were also noted. The seeps were
found along the coast, where there is commonly
no permafrost. Further inland, up to several hun­
dred meters of permafrost efe
T ctively seals off any
underground leakage.
Based on the progress of the general geologi­
cal mapping programme, Store Norske attempted
in 1926 to investigate the hydrocarbon potential of
central Spitsbergen. Conditions suitable for hydro­
carbon generation were confirmed, but no wells were
spudded at that stage.
As a consequence of oil and gas discoveries made
in the North American and Canadian Arctic, interest
in Svalbard as an exploration province was renewed
in the late fifties. Companies such as Shell, Standard
Oil of California and Thxaco Inc. were involved.
The two Iauer cooperated through the company
American Overseas Petroleum Ltd. (Amoseas), and
they launched several expeditions to Svalbard in
the early sixties. Other companies such as Norsk
Polarnavigasjon, Russian Tl"ust Arktikugol, lbtal and
Fina soon followed. Extensive structural mapping
and field geological mapping was conducled, and
in 1963 Amoseas acquired the first marine seismic
survey.
Norsk Polarnavigasjon drilled the first well on
Svalbard in 1963, by using light diamond coring
equipment in Gn�nfjorden (Fig. 2). The first deep
wildcat (Ish0gda 1), however, was drilled by Amoseas
in the winter 1965-1966 at Blahuken. Ten subsequent
wells were drilled up to 1977. Several wells had oil
and gas shows, but commercial hydrocarbon volumes
were not proven. Not all drillings were based on
sound mapping and predrilling geological evaluation.
Following an intermediate period of low activ­
ity, exploration interest again increased in the mid­
eighties. Three new wells have been drilled in this
period. The first discovery ever made on Svalbard
was by the 1toms0breen II well at Haketangen. It
tested gas of unknown volumes in Permian carbon­
ates. The Vassdalen II/III wells were dry, but with
gas shows.
A total of flve wells have been drilled on central
Spitsbergen (Fig. 2). Only one of these (Ish0gda 1)
As
A. N¢1/vedt, F. Livbjerg, P.S. Midb¢e and E. Rasmussen
was drilled on a mapped surface closure. 1Wo wells
were drilled in the deepest Central Spitsbergen Basin
syncline, and must be considered stratigraphical test
wells (Grumant I and Vassdalen II/III). The last
two (Gr{lmdalen 1 and Bellsund 1) reached only
shallow depths and did not drill well defined clo­
sures.
After this paper was refereed a 6th well has been
completed. The Hydro well Reindalspasset 1 was
drilled to 2217 m into lower Carboniferous sand­
stones and shales. The well was dry but with gas
shows. At present no other information is available.
Play models
Initially, very simple play models were used in
the hydrocarbon exploration of Svalbard. Prospect
evaluation was based on structural surface mapping
and general source and reservoir rock extrapolations.
Marine seismic data were generally inconclusive,
because of their poor quality. Simple anticlinal struc­
turing within the Mesozoic and late Paleozoic was
the primary exploration target, with the assumption
that surface structures were continuous and sym­
metrical with depth.Play models included middle
Tl"iassic and late Jurassic source beds combined with
late Permian, late Tl"iassic, early Cretaceous and early
Tertiary reservoir formations.
Thday we realize that these earlier play con­
cepts were incomplete and to some extent, positively
wrong.Seismic data combined with recent field map­
ping show that the surface anticlines on much of cen­
tral Spitsbergen are related to shallow thrust ramping
from decollement planes in the Mesozoic shales (An­
dresen et al., 1988; N0ttvedt and Rasmussen, 1988).
This means that the anticlinal structuring is gener­
ally not continuous below the Jurassic, sometimes
Tl"iassic, shales. Furthermore, structural closures very
often tend to be asymmetrical with depth. The Ish0g­
da 1 well was drilled on such a closure. From seismic
data, the well can be shown to have been positioned
to the side of the subsurface closure.
Remaining potential
As stated above, no previous wells have success­
fully tested the hydrocarbon potential of central
Spitsbergen. Consequently, it is not possible to take
a statistical approach in order to address the issue
of prospectivity. Based on our current understanding
and seismic mapping programme within the area,
speculative in-place resources in the order of some
hundred trillion Sm3 of gas and some tens of mil­
lion Sm3 of oil might be estimated. As it is further
argued, the area remains a high risk exploration
province, where only sound and careful evaluation
work may ultimately lead to success.
Hydrocarbon potential of the Central Spitsbergen Basin
335
15°
SVALBARD
JAMES I
LAND
NY
FRIESLAND
II
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LAND
SABINE
LAND
NORDENSKIOLD
LAND
AGAROH·
HEER
LAND
NAT HORST
LAND
BELLSUND
WEDEL JARLSBERG
TORELL
LAND
LAND
Fig. 1. Location map.
The Store Norske/Hydro licence group
In 1985, Store Norske and Hydro entered a joint
venture to explore for all natural resources on Sval-
bard with the exception of coal. Store Norske has
been granted operatorship of the activity, whereas
Hydro serves as a technical assistant. The agreement
was founded on Store Norske's position as the major
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Fig. 2. Drilling activity on Svalbard. Data from the Norwegian Petroleum Directorate annual
Trvst Ark11kugol
2352
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337
Hydrocarbon potential ofthe Central Spitsbergen Basin
acreage holder and owner of important infrastruc­
similarly aligned tectonic deformation. Caledonian
ture on central Spitsbergen, and on Hydro's carrying
faulting, folding, thrusting and metamorphism of
of all first phase exploration costs.
pre-Cambrian to middle Ordovician sediments and
In terms of oil and gas, a total of about 6000
2
km on central Spitsbergen has been explored by
the Hecla Hoek basement of Svalbard (Fig.
the group, including Store Norske/Hydro acreage of
2
approximately 3400 km (Fig. 3).
igneous complexes were most intense, and formed
6).
The
Hecla Hoek comprises the economical basement for
hydrocarbon exploration on Svalbard.
The total stratigraphic thickness of the Hecla
Hoek
Database
Since 1985, an extensive
is in the order of 15-20 km and the degree
data acquisition amd map­
of metamorphism and structural complexity varies
ping programme has been accomplished, including
considerably, particularly for the presumably older
three field seasons of geological surface mapping,
parts of the succession. Major difficulties exist in
contouring and sampling and several mariine and
correlation of Hecla Hoek successions between dif­
land seismic surveyings (Figs.
4, 5). The land
seismic
ferent areas, and opposing models from more or
data was acquired by employing the newly developed
less pure compression to major lateral emplacement
Norsk Hydro "snow streamer" technique (Rygg et
of separate tectonic terrains have been put forward
al., this volume).
(Birkenmajer,
The
group
has
also
inherited
an
extensive
and Wright,
1975;
1979).
Krasil'shchikov,
1979;
Harland
database, basically from geological surface mapping,
Following the Caledonian orogeny, Devonian ex­
previously collected by the Amoseas Group in the
tensional shear took place, with the formation of a
early sixties. Numerous vertical sedimentary sections,
thick pile of mostly continental red beds (molasse
structural maps and play maps were produced, which
deposits; Friend and Moody-Stuart,
also formed the basis for subsequent publications
graphic thickness of up to
(e.g. Kellogg
1975).
Detailed surface structural con­
8
1972). A
strati­
km has been reported
in two major, N-S trending Devonian grabens in
6).
tour maps from central-west Spitsbergen by the
north Spitsbergen (Fig.
Amoseas Group link up with mapping further east­
reservoir potential within the succession. Based on
wards by the present Store Norske/Hydro Group
reconnaissance work, source bed potential can also
(Fig.
4).
In total, the Store Norske/Hydro Group
possesses surface structural contour information for
almost the entire central Spitsbergen.
Of the five wells drilled on central Spitsbergen,
(Fig.
2).
1,
Grumant
1
Only the Ish0gda
and Gr0ndalen
1
be tentatively suggested.
The Devonian succession was again partly de­
formed and overthrusted, and displays an angular
the licence group has access to information from
the Ish0gda
There is undoubtedly a
1
wells
unconformity to the overlying Carboniferous. In cen­
tral Spitsbergen this angular unconformity represents
more or less the lower boundary for hydrocarbon
has well logs and data
prospecting, due basically to deep burial and also
sets comparable with modern well information. The
poor seismic data resolution in the Devonian in this
other two have very incomplete data sets.
area.
Geological setting
Svalbard is located in the northwest corner of
the Barents Shelf. The archipelago represents an
uplifted portion of this otherwise submerged shelf,
and the outcropping rock formations are of com­
A stratigraphic section from late Paleozoic through
6,
7; e.g. Nathorst, 1910; Frebold, 1935; Hoe! and Orvin,
1937; Orvin, 1940; Cuthill and Challinor, 1965; Har­
land, 1969, 1972; Birkenmajer, 1972, 1981; Livsic,
1974; Kellogg, 1975; Steel and Worsley, 1984; Steel
et al., 1981, 1985; Worsley et al., 1986). Several ma­
Thrtiary has been preserved on Spitsbergen (Figs.
patible age and lithology to the Barents Sea sub­
jor and minor hiatuses occur. In the CSB axis a total
surface (N0ttvedt et a!., this volume). The uplift is
preserved stratigraphic thickness of close to
most intense in the north and west, leaving pro­
present.
5
km is
gressively older rocks in these directions. A very
Early-middle Carboniferous was basically a period
pronounced synclinal feature, the Central Spitsber­
of extension, with a small component of left-lateral
gen Basin (CSB), covers most of central Spitsbergen
shear (oblique slip) in the mjddle Carboniferous
(Fig.
6).
The basin is bounded by the West Spits­
bergen Orogenic Belt (WSOB) in the west and by
(Gjelberg and Steel,
1981).
Middle Carboniferous
extension concentrated along a few major lineaments
the Billefjorden and Lomfjorden Fault Zones (BFZ
like the BFZ, which caused the formation of the
and LFZ) in the east. The basin boundaries parallel
BilJefjorden Graben (BG) east of it
a dominant NNW-SSE structural grain on Spits­
Areas of major faulting and pronounced graben
bergen, inherited through four main episodes of
formation shifted across Spitsbergen during this pe-
-
A. N¢ttvedt, F. Livbjerg, P.S. Midb¢e and E. Rasmussen
338
KONG KAAl.S LAND
79
7
I
I
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I
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I
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+
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....
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19'0CJ
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\
\
\
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\
\
\
\
SCALE t .SOO 000
SC ALE I :SOO 000
tO S 0
.......
10
20 30 40
lyeeeej
l.aeewl
50 km
I
SCALE t : SOO 000
.....--... - Land register boundary
� Store Norske Sp itsbergen
8IIlllJ Kulkompani A / S (SNSK)
c=J Others
-- --- Territorial border/national
park limit
+
Longitude/latitude Interjection
Fig. 3. Licence map. Data from the Norwegian Petroleum Directorate (1989).
339
Hydrocarbon potemial ofthe Central Spitsbergen Basin
•
SURFACE GEOLOGICAL DATABASE
<m> Mapped areas {by SNSK/NH). larger parts of Spitsbergen have earlier
been mapped by AMOSEAS.
o
Measured profiles (SNSK/NH, AMOSEAS, and selected profiles from
university theses).
x
Samples analysed tor source potential, maturity or porosity /permeability
(SNSK/NH).
Fig. 4. Surface geological database.
riod (partial basin inversion), with coarse-grained
infill of up to 2 km locally (Gjelberg and Steel,
1981). In central-east Spitsbergen, the subsidence
pattern changed from broader subsidence and some
minor faulting along the BFZ in Famennian-Na­
murian times to major downfaulting and halfgraben
formation, e.g. BG, in Bashkirian times. A thick,
discontinuous succession of non-marine coal-bear­
ing strata i n the early Carboniferous is succeeded
by up to 1 km of alluvial red beds, marine car-
bonates and evaporites in the middle carboniferous
(Fig. 7).
During the late Carboniferous, Permian and Meso­
zoic, Svalbard became a stable platform area, drifting
slowly northwards. The late Carboniferous-Permian
section consists of limestones, dolomites and evap­
orites grading upwards into cherty limestones and
shales/siltstones (Fig. 7). The Mesozoic typically con­
sists of repeated cycles of siliciclastic coastal and
deltaic progradations into a wide shelf basin. The
A. N¢uvedt, F. Livbjerg, P.S. Midb¢e and £. Rasmussen
340
FJORDEN
SEISMIC DATABASE· SPITSBERGEN
MARINE SEISMIC SURVEYS
NH 8509, lsljorden
NH 8510, Van Keulenljorden
NH 8511, Storljorden
NH 8706, lsfjorden
POL INV (1984)
559km
74 km
301km
300km
310 km
1544km
LAND SEISMIC SURVEYS
Advenldalen 1985 (NH)
Advenldalen-Eskerdalen 1987 (NH)
NH 8802, NordenskiOid/Sabine Land
BP 88, Heer Land (out oltotal312 km)
NH 8903, NordenskiOid/Sabine Land
KV 89 (Petroarctic AS)
4km
35km
300 km
94km
100km
30km
563km
2107km
Total
Fig. S. Seismic database.
passage from early Permian carbonates and evap­
orites to late Permian and lfiassic clastics marks
the drift towards higher, 45-50° paleolatitudes (Steel
and Worsley, 1984). During early to middle Jurassic,
Spitsbergen was repeatedly uplifted, leaving only a
thin, discontinuous and condensed section (Fig. 7).
Numerous well developed upward coarsening se­
quences from shales and siltstones to variable sand­
stones in the lfiassic and early Jurassic, pass into
more homogenous shales in the late Jurassic-early
Cretaceous (M0rk et al., 1982; Dypvik, 1980). A pro­
nounced, transgressive deltaic sandstone unit (Fest­
ningen Sandstone) in the Barremian is overlain by
a series of stacked shelf sandstones and siltstones
in the Aptian-Albian (Fig. 7; Nagy, 1970; Steel and
Worsley, 1984). The opening of the Arctic Basin in
late Cretaceous caused northwards uplift and pro­
gressive northwards bevelling on the basal Tertiary
unconformity. In central Spitsbergen, Aptian-Albian
strata are overlain, with a slight angular unconfor­
mity, by the Tertiary section.
The Tertiary deformation of Svalbard was caused
by Eocene right lateral transpression (highly oblique
compression), succeeding Paleocene right lateral
transtension, as Greenland slid by Svalbard dur­
ing the opening of the North Atlantic-Arctic basins
341
Hydrocarbon potemial ofthe Central Spitsbergen Basin
•
NORDAUSTLANDET
•
tP
(\ KONG KARLS
'V L AND
BARENTS0VA
D
Tertiary
CJ
Jurassic/Cretaceus
BFZ
=
BILLEFJORDEN FAULT ZONE
Triassic
LFZ
=
LOMFJORDEN FAULT ZONE
0
[I]
-
Carboniferous/Permian
Devonian
Hecla Hoek
9
BJ0RN0VA
Fig. 6. Geological map.
342
A. N¢t/l'edt, F. Livbjerg,
f!
CD
Cll
>-
j
0
CD
...
0
>
..
�
Q;
.. iii
:r:
0
z;
CD
1/)
"'
a: 0
iii >.
:;
0
c ?:
u (ij
Q.
=
0
u �
u
� <
CD
(ij F
5
P.S. Midb¢e and E. Rasmussen
GROUP
FORMATION
UpWit and
eroslon
22.5
Eat•n•ion
38
Van Mljenfjorden
55
(1.5·2.5km)
4·12%
85
100
Comprea·
sional
Carollnefjellet
( Terlloryl
Adventdalen
5-20%
141
(festningen
s.a.ndstone)
Uttle
(800·1800m)
Janusfjellel
160
176
195
212
Sanendalen
223
Barentsoya
(300·600m)
230
Tempeltjorden
251
(300·400m)
Gipsdalen
(400·1800m)
Kapp Starostln
Nordenskloldbreen
315
360
389
HC Basement
Hecla Hoek east of
Billefjorden Faull Zone
395
Hecla Hoek Complex
Shale (potential source formations
In gre&n)
Coal
Sandstone (potential reservoir
formations In orange)
Limestone end dolomite (potential
reservoir formations In dark blue)
Gypsum
I anhydrite
Petroleum Geology
Central Spitsbergen
Fig. 7. Petroleum geological synthesis for central Spitsbergen. Stratigraphy is from N�uvedt etal. (this volume).
Hydrocarbon potential oftlze Central Spitsbergen Basin
(Harland, 1969; Lowell, 1972, Harland and Horsfield,
1974; Kellogg, 1975; Steel et al., 1985). The angle of
convergence is assumed to have been small (2-4°),
but during several hundreds of kilometers of right
slip, a few tens of kilometers of compressive plate
closure took place, causing the WSOB and CSB to
the east of it (Fig. 6; Nsmvedt et al., 1988a).
The Tertiary CSB may be regarded partly as a
foreland basin, with cyclic infill of mixed continen­
tal-marine clastics. An overall transgressive package,
from coalbearing sandstones to marine sandstones
and shales, characterizes the transtensional phase,
whereas a large scale regressive package, from ma­
rine shales to continental sandstones and shales,
characterizes the shift towards transpressional con­
ditions (Fig. 7; Kellogg, 1975; Steel et aL, 1981,
1985). The shift in tectonic regime is evidenced also
by a shift from easterly to westerly sediment input,
reflecting growing compression in the WSOB.
Recent work by the Store Norske/Hydro Group
and also several others emphasizes the compres­
sional aspects of the WSOB (Craddock et al., 1985;
Bergh et al., 1988; Dallmann, 1988; Dallmann et al.,
1988; Maher, 1988; N0ttvedt and Rasmussen, 1988;
N0ttvedt et al., 1988b; Dallmann and Maher, 1989;
Maher et al., 1989; Bergh and Andresen, 1992) as
opposed to the simple strike slip model advocated by
Lowell (1972). The present view is that the WSOB
represents a classic foreland fold and thrust belt, de­
coupled from the dextral shear along the paleoplate
boundary (Faleide et al., 1988; Maher and Crad­
dock, 1988; N0ttvedt et al., 1988b). A total Thrtiary
stratigraphy of up to 2.5 km is presently preserved
in the CSB centre, but from vitrinite reflectance
data, an additional 1 km of Tertiary strata (now
eroded) is suggested to have been present (Manum
and Throndsen, 1978).
Greenland and Svalbard finally rifted apart in
early Oligocene, transforming the previously sheared
margin into a passive margin. No surface exposures
exist, but from seismic data a thick Cenozoic clastic
wedge is present off West Spitsbergen.
Hydrocarbon prospectivity
The hydrocarbon prospectivity of central Spitsber­
gen is discussed in detail below. A summary of the
hydrocarbon potential of the area, as evaluated by
the Store Norske/Hydro Group, is included in Fig. 7.
Reservoir potential
Large parts of the Spitsbergen stratigraphy are
dominated by fine-grained clastics, carbonates and
anhydrites. In between, sandstones with assumed
343
excellent primary reservoir quality occur (Fig. 7).
The reservoir potential is reduced in various degree,
however, by quartz cementation due to overloading.
A reservoir potential also exists in carbonates with
secondary porosity and in solution breccias within
mixed evaporitic and dolomitic strata. The main
potential reservoir wnes are described below.
Billefjorden Group
The Billefjorden Group (Fig. 8; Thurnaisian-Na­
murian) was. deposited during initial, flexural ex­
tension along the BFZ with deposition in a large,
widespread basin. Middle Carboniferous erosion,
however, later confined the early Carboniferous sec­
tion to some extent to the present BG (Fig. 9).
In the Billefjorden area three sandprone levels
are present (Gjelberg, 1984; Gjelberg and Steel,
1981). The lowermost Triungen Member· of the
H0rbyebreen Formation measures up to 125 m. It
consists of fluvial sandstones and conglomerates in­
terbedded with siltstones, shales and coals. Net sand
thickness is 30-80 m, with moderate to good sand
body communication and good measured porosities
and permeabilities (Table 1).
The overlying Hoelbreen Member consists of flu­
vial sandstones interbedded with thicker siltstones,
shales and coalbeds. Thtai vertical thickness is 80140 m, with net sand values around 30%. Although
the sandstones have good porosities and permeabili­
ties, their reservoir potential is limited by a moderate
sand body communication (Thble 1).
Most promising is the Namurian Sporeh0gda
Member of the Svenbreen Formation, which con­
sists of up to 90 m of stacked, fluvial sandstones
including 2-10 m thick units of clean, medium­
to coarse-grained quartz sandstones (Fig. 9). Sand
body communication is, on the whole, good and
high porosities and permeabilities (Thble 1) give the
Sporeh0gda Member an excellent reservoir potential.
The seismic data suggest a subsurface continuation
of the Billefjorden Group southward along the BG.
Although paleogeographic variations certainly exist,
it is expected that the Billefjorden Group main­
tains overall the same sedimentary facies with good
primary reservoir potential.
On the other hand, how does the reservoir qual­
ity change with increasing burial depth? In surface
outcrops there is a marked contrast from low to
moderate porosity, quartz cemented Tertiary and
Cretaceous sandstones to generally good porosities
in the Carboniferous sandstones, although these are
all primary clean quartz sandstones which have been
exposed to approximately similar burial depths. The
different porosity gradients are coupled to variable
diagenetic conditions between the CSB and BG. It
344
A. N¢t/l'edt, F. Livbjerg,
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ffi
Hiatus
Fig. 8. Schemalic lilhoslraligraphy of lhe Upper Paleozoic in lhe Billefjorden area. Oala on Early-Middle Carboniferous is from Gjelberg
(19S4). Chronology is no110 scale.
Hydrocarbon potential ofthe Central Spitsbergen Basin
345
Fig. 9. Isopach and paleogeographic maps, Early Carboniferous (Billefjorden Group). Paleogeography is modified from Gjelberg (1984).
TABLE 1
Characteristicsand reservoir quality of Paleozoic sandstone reservoirs, central Spitsbergen
Formation/
member
Area of
exposures
Total sand
thickness
Sandbody
communication
Porosity
Permeability
20-25%
good
Kapp Starostin Fonnation
Sassendalen
25m
probably good
Nordenskioldbreen Fonnation
Minkinfjellet Member
Northern Bilnzow
Land
2-4layers of
5-10m
good
11-27%
average 22%
90-1800mD
average 1000mD
Ebbadalen Formation
Nonhern Billefjord·
Gipsdalen
50-80 m
good
4-26 %
average 13%
average 240mD
Billefjorden Group
Sporch0gda Member
Nonhern Billefjord
50-90m
excellent
5-26%
average 20%
100-4500mD
average 1900mD
Billefjorden Group
Hoelbreen Member
Nonhern Billefjord
30-40m
moderate
16-25%
average 20%
3-2300mD
average 730mD
Billefjorden Group
Thungen Member
Nonhcrn Billefjord
30-80m
moderate to
12-31%
average 19%
27-6000mD
average 2300mD
is a problem, therefore, to what depth will there be
reservoir potential preserved in the Carboniferous
sandstones in the subsurface BG?
Ebbadalen Formation
The Ebbadalen Formation (Bashkirian) is r,estrict­
ed depositionally to the BG (Fig. 10). The southward
continuation of this syn-rift package has been seismi­
cally mapped. The formation is well exposed in the
Billefjorden area, and consists of up to 1 km of dom­
inantly alluvial fan red beds (Odellfjellet Member)
good
0-900 mD
along the BFZ, grading eastward (basinward) into
carbonates and anhydrites of highly restricted marine
and sabkha origin (lricolorfjellet Member; Figs. 8,
10; Gjelberg and Steel, 1981; Gjelberg, 1984; Steel
and Worsley, 1984). The up to 80 m thick Ebbaelva
Member below consists of well sorted, medium- to
coarse-grained fluvial sandstones. Measured porosi­
ties are as high as 26% (Thble 1). Given good
sand body communication, this member holds a very
good reservoir potential. The sandstones are south­
easterly derived, and reservoir potential is dependent
A. N¢ttvedt, F. Livbjerg. P.S. Midb¢e and E. Rasmussen
346
,..
�Z:J-­
e;::;:r-C"'
!::::) :=".:""'...
B--
\
Fig.
10.
\
Isopach and paleogeographic maps, Bashkirian (Ebbadalen Formation and equivalents). Paleogeography is modified rrom
Gjelberg (1984).
on a southward subsurface distribution as shown
mixed limestone and dolomite facies (Fig. 8). In
in Fig. 10. The lowermost Anservika Member is
outcrops around Billefjorden many intervals show
composed of poorly sorted, mostly fine-grained, con­
good secondary porosities. Up to 40 m thick bio­
tinental red beds, with overall poor reservoir poten­
herms
tial.
30-40%. Limited lateral distribution of the porous
Equivalent deposits are exposed along the west
coast of Spitsbergen (Fig. 10). The distribwtion of
(Paleoaplysina)
have visual porosities up to
zones makes them prone to stratigraphical entrap­
ment in the subsurface.
these sediments is not completely outlined, but they
The prospectivity of the porous carbonates is lim­
are most likely confined to similar N-S graben struc­
ited, however, by a very low degree of lateral pre­
dictability. Moreover, their signature is generally
tures (Gjelberg, 1984).
beyond seismic resolution, eliminating the possibil­
Nordenskioldbreen Formation
ity of using advanced seismic interpretation tech­
The Minkinfjellet Member (Moscovian) of the
niques.
Nordenski6ldbreen Formation also occurs within the
BG (Steel and Worsley, 1984). It represents the
Solution breccias: Anhydrites are found in the
later stage of the syn-rift package described above,
Minkinfjellet and Tricolorfjellet Members (Bash­
and consists dominantly of anhydrites and carbon­
kirian-Moscovian) as well as in the Gipshuken
ates with some 5-10 m thick layers of sandstone
Formation (Artinskian) above (Fig. 8; Lauritzen,
with interesting porosities and permeabilities in its
1981; Steel· and Worsley, 1984). In outcrops, Gip­
lower pan (Thble 1). The sandstones are present
shuken Formation often has porous carbonate solu­
only in a few localities in the Billefjorden area, and
tion breccias associated with the anhydrites, resulting
most likely represent easterly sourced, shallow ma­
from dissolution of gypsum/anhydrite in thinbeddcd
rine sandridges. Equivalent sandstones are assumed
carbonate/evaporite units. Along the northeastern
to be present in the subsurface of the southerly
part of Billefjorden a more than 10 km long section
plunging BG.
of the Minkinfjellet Member is exposed. It contains a
continuous unit of carbonate solution breccias, with
Paleozoic carbonates: The Nordenskioldbreen
Formation
(Moscovian-Sakhmarian)
consists
of
a maximum thickness of more than 100m. The visual
porosity of these breccias is mostly very good.
Hydrocarbon potential ofthe Central Spitsbergen Basin
It may be speculated that the anhydrite solu­
tion postdates the late Thrtiary erosion and thus
can be expected to be present only near exposed
surfaces. However, drilling problems with lost mud
circulation in wells penetrating the Gipshuken For­
mation indicate that solution phenomena exist also
in the subsurface, and that solution breccias might be
prospective reservoirs (Fig. 7).
Tempelfjorden Group
The Permian Tempelfjorden Group includes the
Kapp Starostin Formation of Kungurian to Thtarian
age (Fig. 8). The formation is dominated by spi­
culitic cherts and various chertified clays, carbonates,
siltstones and sandstones deposited on a shallow
to deep marine shelf (Fig. 11; Steel and Worsley,
1984;). A glauconitic sandstone unit, which is only
partly chertified, is present in the upper part of the
formation in northern areas. It lacks quartz cement,
and outcrops partly as loose sand. The unit has been
measured to more than 100 m thick to the north
of Isfjorden and up to 30 m thick south of Isfjor­
den. Here, porosities of more than 20% have been
observed (Thble 1). The reservoir potential might
be increased by fracturing of the brittle cherts. The
prospectivity is, however, dependent on a subsurface
confirmation of glauconitic sandstones further south
than proposed in Fig. 11.
347
Sassendalen Group
The Sassendalen Group (Scythian-Ladinian) is
dominated by deeper marine shales and siltstones
(Figs. 7, 12; M0rk et al. 1982). Three large-scale
upward coarsening sandstone sequences are present
along the west coast, representing prograding delta
front sequences. Most of the sandstones have poor
reservoir quality because of a poor degree of sorting
and high mud content. Cleaner sandstones occur, but
they seem to be generally tightly cemented by quartz
overgrowth. The Sassendalen Group is therefore
considered to have overall low reservoir potential.
Kapp Toscana Group
The Kapp Thscana Group (Ladinian-Bathonian)
represents a partly condensed section (Fig. 7). On
Spitsbergen the Ladinian to Norian Tchermakfjellet
and De Geerdalen Formations constitute the main
part of the group. The overall setting is typically shal­
low marine shelf, but in western areas there are delta
plain sediments present (Fig. 13; M0rk et al., 1982).
From several measured profiles, net sand values of
30-40% are indicated for the two formations. The
sandstones are chemically immature and mostly very
fine-grained, but medium-grained sandstones up to
20 m thick have been measured in southwest Spits­
bergen. The sandstone porosity, which is partly a
result of secondary solution of unstable framework
•
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Fig.
11.
Isopach :�nd paleogeographic m:�ps, Late Permian (Thmpelrjorden Group).
111"
Q
A. N¢/lvedt, F. Livbjerg, P.S. Midb¢e and E. Rasmussen
348
78°
78°
.,.
DOu•crop
.
12.
Fig.
(1982).
Fig.
Isopach and paleogeographic maps, Early-Middle Triassic (Sassendalen Group). Paleogeography is modified from M!llrk e1 al.
13. Isopach and paleogeographic maps, La1e 1tiassic-Early Jurassic (Kapp Toscana Group). Paleogeography is modified from M!llrk
(1982).
el al.
349
Hydrocarbon potential ofthe Central Spitsbergen Basin
17.
Fig. 14. Isopach and
(1984).
paleogeographic maps,
Barremian (Helvetiafjellet Formation).
grains, is as high as 16%. The reservoir potential is
limited by very low permeabilities and by an observed
low degree of sand body communication.
The Rhaetian to Bathonian Wilhelm0ya Forma­
tion comprises the uppermost part of the group
(Worsley, 1973). Clean quartz sandstones are ex­
posed on the islands east of Spitsbergen, suggesting
a phase of deltaic progradation from the east (M0rk
et at., 1982; Dypvik et at., 1985). Along the east coast
of Spitsbergen, up to 40 m of porous sandstones have
been measured. The deltaic development terminates
near the present coast line, however, so that thinner
sandlayers are expected in the central Spitsbergen
subsurface.
Helvetiafjellet Formation
The HelvetiafjeUet Formation has an overall trans­
gressive character, with a basal sheet of stacked,
medium- to coarse-grained, fluvial quartz sandstones
(Festningen Member), passing upwards into coastal­
deltaic, interbedded sandstones, siltstones, shales
and coals (Figs. 7, 14; Steel and Worsley. 1984;
Nemec et at., 1988). The thickness of the formation
ranges up to 100 m, with net sand values varying
between 60 and 80%. A porosity map is shown in
Fig. 15. Fair to good porosities have been mea­
sured in eastern areas, but a marked decrease occurs
Paleogeography
is modified from Steel and Worsley
westward into the CSB and against the WSOB. In
areas where the formation is sufficiently buried to be
prospective, the porosity is less than 8% on average.
The reduction of porosity is mainly due to quartz
cementation, and the porosity map clearly reflects
the configuration of the CSB.
Carolinefjellet Formation
Along the west coast, stacked coastal sandstones
of the carolinefjellet Formation (Aptian-Albian)
immediately overlie the Helvetiafjellet Formation
(Fig. 7). These are clean quartz sandstones with ini­
tial reservoir quality, but with presently poor porosi­
ties. Eastwards, the carolinefjellet Formation typ­
ically consists of alternating heterolithic sandstone
and siltstone members of shallow marine origin
(Nagy, 1970; Steel, 1977). The heterogeneities re­
duce the reservoi r potential.
Firkanten Formation
The Firkanten Formation (Paleocene) is overall
transgressive, but consists internally of a stacked
series of regressive increments. The lower part of
the formation comprises cyclic sequences of shales,
siltstones, sandstones and coals of fl.uviodeltaic ori­
gin, passing upwards into a unit of stacked, clean
quartzarenites of delta front/shallow marine origin
350
A. N¢1/vedt, F. Livbjerg, P.S. Midb¢e and E. Rasmussen
t7•
, ..
POROSITY
HELVInAI'.IILT
LE
I'ORIIATION
78.
Fig.
15. Porosity map. Helvetiafjellet Formation.
(Figs. 7, 16; Steel et al., 1981; Steel and Wors­
ley, 1984; N�ntvedt, 1985). A predominant northerly
and easterly sediment source makes northern and
eastern areas most sandprone, with net sand values
ranging between 40 and 70%. The sandstone porosity
is severely reduced by quartz cement, and is less than
8% on average in areas where the formation is in a
prospectively buried position (Fig. 17).
There are also younger Tertiary sandprone forma­
tions, but they are not sufficiently buried at present
to represent prospective reservoirs.
Source potential
Potential source rocks occur at several levels in
the central Spitsbergen stratigraphy with variable
thickness and quality (Fig. 7). Most prominent and
well known are the Mesozoic black shales. A less
well known source potential exists in the Paleozoic
section, and to some extent in the Thrtiary coal beds.
A brief description of the main potential source beds
is given below.
Horbybreen Formation
The Hoelbreen Member of the H0rbybreen For­
mation (Visean), consists of dark floodbasin shales
and coals, with a reasonable source potential (Figs. 7,
8). The Hoelbreen Member, some 40-140 m thick,
is developed along the BG. TOC values vary consid­
erably and kerogen type III predominates, giving a
potential mainly for gas.
Vitrinite data from outcrops in eastern Isfjorden
suggest oil maturation in this region. From kero­
gen maturation modelling, the Hoelbreen Member
passes slowly into the gas window southwards along
the plunging BG (Figs. 1, 6).
Svenbreen Formation
The Birger Johnsonfjellet Member of the Sven­
breen Formation (Visean) consists of lacustrine
organic-rich shales and coals, with excellent source
potential (Figs. 7, 8; Abdullah et at., 1988). The
Birger Johnsonfjellet Member is observed only in
outcrops in the Billefjorden area, where it ranges
from 20-50 m in thickness. It originated as freshwa­
ter lake deposits in depressions along the BFZ, but it
is presently preserved mainly to the east of the BFZ,
in the BG. Average TOC reaches 40%, and the coaly
shales have kerogen type I and II, making them an
exceptionally rich source rock for oil.
Because of slightly less burial, the Birger John­
sonfjellet Member is slightly less mature than the
Hoelbreen Member.
Nordenskioldbreen Formation
The Nordensk.ioldbreen Formation limestones,
dolomites and minor sandstones have organic­
rich intervals with a limited source bed potential
(Figs. 7, 8). Most important are the Brucebyen Beds
(Asselian) in eastern Isfjorden, some 5-10 m thick,
which have TOC values between 1 and 30% and pre­
dominance of kerogen type II and III. This gives a
local potential for oil, but the limited total thickness
reduces the volume generation potential.
From preliminary kerogen maturation studies, the
Brucebyen Beds are assumed to be gas mature in
central-southeastern and oil mature in northeastern
Nordenski61d Land (Figs. 1, 6). In present high
outcrops in Sassenfjorden-Billefjorden they are low
mature.
Barentsoya Formation
The Barents0ya Formation (Smithian-Ladinian)
of the Sassendalen Group consists predominantly
of dark marine shales and interbedded siltstones
with variable source potential (Fig. 7; see also M0rk
et a!., 1982; M0rk and Bjor0y, 1984). On central
Spitsbergen, the formation varies between 300 and
600 m in thickness. Thickness variations are partly
tectonically controlled, however, as the formation
served as one of the major decollement units for the
early Tertiary compression.
The lowermost, silty shales of the Deltadalen
351
Hydrocarbon potential ofthe Central Spitsbergen Basin
,..
11.
,,.
,..
c:;:;:J -·­
Iiil - ­
o--
7
Fig. 16. Isopach and paleogeographic maps, Paleocene (Firkantcn Formation). Paleogeography is modified from Steel and Worsley
(1984).
Member have an average TOC of less than 1-2%
and predominance of kerogen type III and IV, yield­
ing a poor to moderate potential for gas. The Sticky
Keep Member shales have a higher average TOC of
3-4%, with dominantly kerogen type III and some
type II upwards. Sticky Keep Member has a good
potential for both oil and gas. Black paper shales
of the Botneheia Member show TOC values of 4 6 % on average. Kerogen type II predominates, with
some type III and also type I in between, giving a
rich potential for oil. Source bed quality of the Sticky
Keep and Botneheia Members generally improves
eastwards.
From kerogen maturation modelling, the forma­
tion is gas mature in the CSB trough, oil mature
along the west coast and east of the Longyearbyen­
Svea line and low mature in present outcrops in
Sassendalen and high western Nordenskiold Land
(Figs. 1, 6).
Janusfjellet Formation
The Janusfjellet Formation (Bathonian-Haute­
rivian) consists mainly of dark marine shales and
some siltstones with a good source potential (Fig. 7;
M0rk and Bjor0y, 1984; Dypvik, 1985). The forma­
tion ranges from 300-800 m in thickness in central
Spitsbergen. These are to some extent tectonic thick-
ness variations caused by major Thrtiary decollement
movements in the Jurassic shales.
Black paper shales of the lower Agardhfjellet
Member show an average TOC of 4% and kero­
gen type II and III, implying potential for both oil
and gas. The upper Rurikfjellet Member has a lower
average TOC of 1-2% and contains mainly kerogen
type III, yielding a potential mainly for gas.
The Janusfjellet Formation lies about 400 m above
the Barents0ya Formation. This causes a slight west­
ward shift of kerogen maturation isotherms. The for­
mation is gas mature in the deeper CBS trough, and
it reaches the oil window at the basin flanks, along
the west coast and eastwards close to the traverse
Longyearbyen-Svea. In easterly and high westerly
outcrops it is basically low mature (Figs. 1, 6).
Helvetiafjellet Formation
Coals in the lower part of the Helvetiafjellet For­
mation (Barremian) have a limited source potential
(Fig. 7), with predominantly kerogen type III/IV. The
coals are very thin, however, and are disregarded as a
potential source rock due to volume limitations. They
would not be able to yield significant amounts of hy­
drocarbons on a local or regional scale. A thermal
maturation map for the Helvetiafjellet Formation
coals is shown in Fig. 18.
352
A. N¢/lvedt, F. Livbjerg, P.S. Midbpe and E. Rasmussen
,..
1 7°
13"
11'
��·
17°
HELVETIAI\IELLET FM.
COALS/COALY SHALES
POROSITY
FIIKANQN
FORMATION
-UIIIIII .. .......
7..
7
Fig. 17. Porosity map, Firkantcn Formation.
Fig.
Firkanten Formation
The Firkanten Formation
18. Thermal maturity map, Helvetiafjellet Formation coals.
imum burial has been set to late Eocene-early
(Paleocene),
as de­
Oligocene, immediately prior to rifting between Sval­
scribed above, contains a series of coal beds and
bard and Greenland, and includes about
thin coaly shales in its lower part (Fig. 7). The coals
ditional strata that are believed to have been eroded
1 krn of ad­
are thickest (totalling less than 10 m) and best de­
off the top of the present CSB Tertiary section (see
veloped around the outcropping northeastern and
above; Manum and Throndsen, 1978). Uplift and
northwestern margin of the present Tertiary basin
erosion are assumed to have been spread throughout
remnant. They are overall high quality coals with
the Cenozoic, but with a maximum in the Oligocene
low sulphur and low ash contents, and are presently
as a result of thermal rift flank uplift of Svalbard ad­
being mined by both Norwegians and Russians (Ma­
jacent to the Norwegian-Greenland Sea. Even levels
jor and Nagy, 1972). The kerogen s
i of type III/IV,
of regional uplift have been applied.
yielding a potential mainly for gas.
Vitrinite reflectance data and kerogen maturation
The burial history and modelling results suggest
maximum temperature and peak hydrocarbon gen­
modelling suggest oil maturation towards the center
eration during late Eocene-early Oligocene in the
of the CSB, whereas along the flanks of the basin the
CSB. The CSB axis obviously matured prior to the
coals are presently low to immature (Fig. 19; see also
basin flanks, and also produced gas simultaneously
Manum and Throndsen, 1978). The relatively small
with oil maturation upflanks. This introduces a risk
total thickness limits the volume generation potential.
of gas flushing of upflank reservoirs. The CSB asym­
metry implies major hydrocarbon volume drainage
Maturation
up the east-northeast flank of the basin.
Kerogen maturation for the different source beds
In eastern Isfjorden and northeastern Norden­
has been modelled with the use of Norsk Hydro
skiold Land, the total Tertiary overburden is assumed
inhouse basin modelling software (modified YOkler
to have been less than the previous (late Creta­
model; Yukler and Welte, 1980). The model out­
ceous) erosion at the base Tertiary unconformity.
put has been calibrated against measured vitrinite
This means that hydrocarbon maturation of late Pa­
reflectance data from field samples.
leozoic source beds in the Billefjorden area is likely
In the modelling the present CSB geometry is
to have occurred in the early Cretaceous (Albian).
assumed to mirror maximum burial geometry. Max-
As the regional bedding is assumed to have been
Hydrocarbon potential of the Central Spitsbergen Basin
'
13
1 &'
17°
FIRKANTEN FM.
COALS
353
more or less subhorizontal prior to late Cretaceous
northerly uplift and tilting, this indicates a zero matu­
rity gradient for these source beds for some distance
southwards along the BG (Fig.
6).
However, around
the Sassendalen-Adventdalen area Thrtiary thermal
overprinting occurs, so that further south along the
BG normal Tertiary maturity gradients apply.
Structuring
-
trap style
The central Spitsbergen surface geology is domi­
nated by Thrtiary compression and related structur­
ing (Fig. 20). With little seismic data available, previ­
ous exploration focused on these surface structures,
mostly simple anticlines (e.g. Dalland, 1979). Struc­
tural entrapment caused by older tectonic move­
ments is hidden by the younger sedimentary cover
and. has therefore been unpredictable based on sur­
face mapping alone. Through our present explo­
rational efforts and seismic mapping programme,
however, a structural trap potential can be demon­
strated also for the early to middle Carbonifer­
ous phase of extension. A description of structural
trap styles on central Spitsbergen is given below
Fig. 19. Thermal maturity map, Firkanten Formation coals.
(Fig. 21).
One of the major concerns with respect to struc­
tural entrapment on Spitsbergen has been the re­
gional dip problem. During late Cretaceous-early
Thrtiary northerly uplift, bedding was tilted north­
south by an angle of about 2-3° across north-central
Spitsbergen. The CSB syncline introduces variable,
superimposed dips in an east-west direction. This
means that low relief structures may have severely
reduced or even eliminated closure volumes.
The BG is exposed for about 70 km in the Bille­
fjorden area and it plunges southwards below sea
level immediately south of Pyramiden (Fig.
6).
From
seismic data it can be seen to continue subsurface
along strike for more than
100
km, to the south
of Svea. The basin axis parallels the trajectories of
the present BFZ surface thrust ramp anticlines. The
BFZ itself continues for a distance of about
300 km
onshore in eastern Spitsbergen. A schematic model
of the tectonic evolution along this fault zone is given
....,.... T hru&t or
rovers• fault
r TT
+
+
Normal faun
Antlc:line
::,��::,;:�0
arrows on the
steepest limb)
.W.
Rop•ated tolding
�=== Flexure
o
10km
'------'
Fig. 20. Summary of gross surface structuring on central Spits­
bergen.
in Fig. 22.
The present work shows that the middle carbonif­
erous BFZ is a remarkably straight, but relatively
complex fault zone in the subsurface. In seismic data,
the main graben boundary faults have a clear listric
geometry, with little evidence for significant shear
(Fig. 22). The BFZ continues as a narrow, single
fault zone below parts of the subsurface, but below
central-eastern Nordenskiold Land the fault zone
appears to shift laterally for approximately
(Fig. 21).
4 km
A. N¢/tvedt, F. Livbjerg, P.S. Midb¢e and E. Rasmussen
354
CB
WSOB
LFZ
BFZ
Storfjorden
Southern Central Spitsbergen
LEGEND
0
0
0
0
Tertiary
Cretaceous
Jurassic
0
0
(!I
Permian and Carboniferous
WSOB West Spitsbergen Uplift
Devonian
C:SB
Central Spitsbergen Basin
Hecla Hoek
BFZ
Billefjorden Fault Zone
Triassic
LFZ
Lomfjorden Fault Zone
BG
Billefjorden Graben
Fig. 21. Schematic i llustr.ltion of structura l trap styles across southern cen tra l Spitsbergen (van Mijenfjorden) and Edge0ya. Figure is not
to scale.
This structure is very prospective in terms of trap
potential. It stood up high during subsidence and
Carboniferous anhydrites, due to the pre-Tertiary
uplift to the north.
infill of the adjacent graben, and involves folding
Thrust ramping from these decollements gener­
of the previous early Carboniferous stratigraphy into
ated various structures with trap potential such as
a basin parallel, hanging wall anticline (Fig.
23).
ramp anticlines, duplex structures and blind anti­
Southwards, the anticline is cut by normal faults,
clines above these (Fig. 21). A problem is that they
resembling a typical rotated fault block. Moreover,
generally have small closure volumes, partly due to
the structuring was on a scale large enough to make
the high regional dips. Thrust ramping is particu­
structural entrapment possible in spite of the re­
larly concentrated along the BFZ and
gional dip problem.
partly to buttress effects caused by simultaneous,
The north-northwest trending WSOB
for about
300 km
s
i
exposed
onshore in West Spitsbergen and
LFZ, related
deeper rooted reverse movements on these fault
zones (Fig.
22;
Andresen et al., 1988; Dallmann et
it terminates abruptly at Kongsfjorden in tlhe north
al., 1988; Haremo et al., 1988, 1990; N0ttvedt e t al.,
(Fig. 6). It continues southward below the Barents
1988c, fig. 3c; Haremo and Andresen, 1992)
Shelf. Western parts of the WSOB proper are thick
The Ny Friesland uplift between the BFZ and
skinned, bringing up Hecla Hoek basement rocks,
LFZ to the north is essentially a basement inversion
whereas eastern parts are thin skinned, repeating
structure, which becomes Jess important southward
the sedimentary section on imbricated thrust plates.
on Nordenskiold Land (N0ttvedt et al., 1988b).
From seismic and field data thin skinned thrust­
ing is observed to continue eastwards below the
CSB, probably as far east as to Edge0ya (Andresen
Seal potential
et al., 1988; Dallmann et aL, 1988; N�mvedt and
The seal capacity becomes critical to the net
Rasmussen, 1988). The decollement under the thin
prospectivity of the area. Cap rock lithology varies
skinned segment appears to step rapidly up section
throughout the succession, from carbonates and
from the west coast and eastwards into CSB lhassic
evaporites in the Paleozoic, to thick, black shales
and Jurassic black shales. At the same time i t seems
in the Triassic-Jurassic, and finally to various silty
to step down section northwards into Permian and
shales and sandy siltstones in the Cretaceous and
IJydrocarbon potential oftlte Central Spitsbergen Basin
355
late Devonian
Svalbardian
Compressional phase
lower Carboniferous
Pre-rift
extensional
warping
Middle Carboniferous
Billeforden Graben
Rifting -decreasing
subsidence in late
Carboniferous
Jurassic-Cretaceous
Platform subsidence
(Permian-Cretaceous)
Eocene compression
*
Uplift and erosion
� Present situation in Adventdalen-Eskerdalen
Eskerdalen
E
0
0
10
(")
Fig. 22. Schematic illustration of the tectonic evolution along the Billefjorden Faull Zone (BFZ) on nonhcastcm Nordcnskiold Land.
356
A. N¢ttvedt, F. Livbjerg, P.S. Midb¢e and E. Rasmussen
SCHEMATIC MODEL:
Thscana Group may have seal capacity locally, as may
BILLEFJORDEN GRABEN
also thick intrusives
STRUCTURING
(20-60
m) which occur at the
Kapp Toscana/Sassendalen Group level across large
parts of the subsurface CSB.
Helvetiafjellet Formation reservoirs are overlain
by Carolinefjellet Formation sandy siltstones and
shales, some
400-1000
m thick (Fig. 7). The high
sand/silt content is destructive with respect to seal
capacity, however, which is also indicated by high
gas readings through this formation in previous CSB
Fig. 23. Schematic model of
�
Devonian
c::J
Rot•Uon•.l lault
btoek cto*-"'•
structu ring and trap style in the
Billefjorden Graben (BG).
Homogenous shales of the Basilika Formation
overlie the Firkanten Formation reservoirs (Fig. 7).
These vary from
100-300 m in thickness in subcrops
and are expected to have a good seal potential.
Tertiary (Fig. 7). These are assumed to have initially
served as sufficient seals to underlying reservoir for­
mations. Presently, however, seal capacity is assumed
to be reduced. First, the very long time interval
(40 Ma)
wells.
since peak maturation and assumed oil and
Discussion
The discussion of exploration sub-provinces which
is given below,
s
i
applicable to the central Spits­
bergen area, on Nordenskiold, Sabine, Nathorst and
24).
gas expulsion is a concern. Especially lighter hydro­
Heer Lands (Fig.
carbon fractions might have been exposed to long
has an overall sedimentary cover too thin to be
term diffusion. Secondly, extensive
prospective, with relevant source rocks being gen­
(2.5-3
km) late
The area north of Isfjorden
Tertiary tectonic uplift caused excessive strain release
erally exposed. In addition, it
in the buried succession. Conjugate sets of fracturing
complex. South of van Keulenfjorden, on southern
typically cut through the rock formations as a result
Spitsbergen, a definite exploration potential exists.
s
i
structurally very
of late, brittle deformation. Most resistant to such
deformation are the evaporites and, to some extent,
the organic-rich shales.
Birger Johnsonfjellet Member shales serve as
a combined source and cap rock to underlying
Sporeh0gda Member reservoirs. The high organic
content adds positively to the overall seal potential.
Interbedded shale sections may serve as seals to
deeper early Carboniferous reservoirs. Their qual­
ity is variable and probably less predictable on a
subregional basis.
Ebbadalen Formation reservoirs are overlain by,
and interbedded with, thick carbonate and gypsum/
anhydrite strata (Fig. 7). The evaporites probably
represent the most effective cap rocks in the Spits­
bergen stratigraphy, also because they responded
more plastically to the late Tertiary uplift and defor­
mation.
Late
Carboniferous-early
Permian
carbonate
reservoirs have interbedded micrites, dolomites and
anhydrites (Fig. 7). These vary in thickness, but have
a good overall seal potential.
Sassendalen Group shales serve as a seal to Kapp
Starostin Formation reservoirs, and Janusfjel!let For­
BFZ
mation shales serve as a seal to underlying Kapp
Toscana Group reservoirs (Fig. 7). High organic con­
tent and subsurface thicknesses of 600-800 m make
them both good cap rocks. Shales within the Kapp
: 8ihllorden
,..,.It Zone
LFZ : lomtjorOtl'l
hult Zone
Fig. 24. Schematic outline of exploration sub-provinces, central
Spitsbergen.
357
Hydrocarbon potential of the Central Spitsbergen Basin
However, national park regulations constrain our in­
formation database and evaluation ability for this
area.
Prospect ivity of the Paleozoic carbonates is not dis­
cussed here, as carbonate play models mostly define
stratigraphic traps and are therefore difficult to map
with our current database. Carbonate reservoirs may,
in principle, be present anywhere in the subsurface
and there is commonly a good seal potential, espe­
cially in overlying and interbedded evaporite series.
In the CSB, however, there is an overall source rock
problem. The Paleozoic section is thought to lack
good quality source rocks and the uppermost car­
bonate reservoirs become dependent on migration
and filling from Triassic shales above. This is most
likely to have occurred within the WSOB, where
large thrust slabs of Paleozoic carbonates override
Triassic source beds, and possibly to some extent
along the steepest dipping east and west CSB flanks.
In the BG, early Carboniferous source beds are
present, which may have sourced especially the lower
carbonate series reservoirs.
As a consequence of a somewhat unpredictable
reservoir potential and severe mapping difficulties,
overall prospectivity of the Paleozoic carbonates is
regarded as moderate to low.
should be confined to the shallower parts of the
basin. Increasing subsurface depths generally intro­
duce the risk of geochemical ovcrmaturation and lost
reservoir quality. The overall hydrocarbon potential
is considered moderate to low, and the CSB remains
a high risk exploration province.
Sub-province 1 - West Spilsbergen Orogenic Belt
Sm1c111ring:
There is
a
potential for closed structures
in the late Paleozoic and lower Mesozoic,
e.g. thrust ramp anticlines and some blind
anticlines (Fig. 25). Structuring is complex
and difficult to map from seismic data. High
relief, mountainous terrain complicates seis­
mic acqui sition.
Reservoir:
Permian carbonates and Sasscndalcn Group
sandstones are most important. Strong ce­
mentation by carbonate and quartz growth
limits the reservoir quality.
Source:
Sassendalcn Group shales are present, but
with
reduced source bed quality. They are
generally oil mature, but the possibility of
long range migration of gas up along the
CSB west flank must be considered.
Seal:
Sassendalen Group shales cap the reservoir
formations. However, thin sediment cover
and tectonic fracturing limits
the seal poten­
tial.
Classification of exploration sub-provinces
Central Spitsbergen has been divided into four
different exploration sub-provinces (Fig. 24). 'JYpical
examples of the structural character of these are
shown in Figs. 25, 26, 27 and 28, as observed from
seismic reflection profiling in Isfjorden. The follow­
ing s
i
a summary of the prospectivity of individual
sub-provinces.
In conclusion, strong late Thrtiary uplift of central
Spitsbergen suggests that hydrocarbon prospecting
Fig. 25.
Prospec1ivi1y: There is an overall low potential for com­
mercial hydrocarbon discoveries due to poor
reservoir quality and cap rock potential,
as
well as to mapping difficulties.
Sub-province 2 - CSB central-wesl jlnnk
Stn1c111ring:
Large to moderate, blind anticlinal closures
occur in the late Mesozoic and Thrtiary,
overlying thrust ramp anticlines and duplex
structures in the early Mesozoic (Figs. 25,
26).
Example of structural style along the West Spitsbergen Orogenic Belt (WSOB), as seen on seismic data from western Jsfjorden.
A. N¢1/vedt, F. Livbjerg, P.S. Midb¢e and E. Rasmussen
358
....
....
....
....
""'
....
....
,,..
.. ..
....
....
Fig. 26. Example of structural style in the Central Spitsbergen Basin (CSO) deep trough, as seen on seismic data rrom cen tral Isfjorden.
...
-
1)0
100
...
100
...
...
...
-
...
Fig. 27. Example of structural style along the Central Spitsbergen Basin (CSO) cast llank, as seen on seismic data rrom eastern Isrjorden.
Reservoir:
Argillaceous sandstones of the Sasscndalcn
potential for gas and less for oil. Early mi­
and Kapp Toscana Groups and clean quartz
gration of oil into Thrtiary and possibly also
sandstones of the Helvetiafjellet and Firkan­
Cretaceous reservoirs may be an exception,
ten Formations serve as main reservoir units.
however, as they did not mature thermally
However, reservoir quality is limited by over­
below the oil window.
all strong cementation from quartz growth.
Source:
Sasscndalen Group and Janusfjel!el For­
mation shales have good source potential.
These are generally oil mature along the
SeaL·
Sub-province 3 - CSB east flank
Stmcturing:
There is a general westward dip towards
basin rim, but become rapidly gas mature in
the CSD axis. Minor, small scale structural
the subsurface CSD.
overprinting occurs, but with small potential
Sassendalen Group, Janusfjellet Formation
and Basilika Formation (Paleocene) shales
for closures (Fig. 27).
Reservoirs:
Kapp 1bscana Group and Helvetiafjellet
have primary good seal potential. How­
Formation sandstones arc present. Reser­
ever, present potential is reduced upscction
voir quality is overall moderate to poor be­
due to shallow burial. Cretaceous (Aptian­
cause of quartz cementation, but it improves
Albian) shales have reduced seal potential
due 10 high sand and silt content.
eastward.
Source:
Sassendalen Group and Janusfjellet For­
Prospectivity: Limited reservoir and cap rock quality and
mation shales have good source potential.
high thermal maturation suggest a limited
These become gradually oil mature north-
359
Hydrocarbon potetllial ofthe Central Spitsbergen Basin
C - Basa Triassic
E - Intra Upper Carbonifferous
F - Base Mid. - Carbonlfferous
D - Top Hecla Hock
1
.
;
.
Fig. 28. Example of structural style along the Billefjorden Faull Zone (BFZ), as seen in 1l:mpelfjorden.
SeaL·
eastwards, up the CSO cast flank. Long
but with a more unpredictable distribution.
range migration from the CSD central area
Sandstones of the Kapp Starostin Forma­
is plausible, including late stage migration
tion crop out to the northeast, but their
and possible llushing of gas.
southward subsurface extent is speculative.
Jn northern Nordenskiold Land the N-S re­
Kapp Toscana Group sandstones have im­
gional dip exposes the reservoir formations.
proved (good) reservoir potential along the
Southwards, Janusfjellet and Carolinefjellct
Spitsbergen east coast.
formations have fair and moderate seal po­
Prospectivity:
Source:
Birgcr
Johnsonfjcllet Member
There is an overall low potential for hy­
These are low mature in the north and
drocarbon entrapment, due to general lack
probably oil to gas mature on northeast
of structural closures and limited reservoir
Nordenskiold Land. To the south, on Heer
quality.
Land, they are likely in the gas window.
Seal:
Billefjorden Group shales and Gipsdalen
Group carbonates and evaporites along the
BG are expected to have good seal potential.
Rotated fault blocks in the late Paleo­
Sassendalen Group shales are also expected
zoic along the DFZ give a potential for large
to have good seal properties. Janusfjellct
4a -
closures (Fig. 28). Thrust ramp anticlines in
Formation shales have less potential due to
the Mesozoic above provide a second, but
shallow burial.
smaller target.
Eastwards, the early-middle Carboniferous
4b -
Ramp anticlines and basement rooted
section pinches out and Mesozoic shales be­
reverse faults along the LFZ give trap po­
come successively exposed, yielding limited
tential. Thrust ramping i n the area between
OFZ and LFZ i s generally on a much smaller
Reservoir:
rich
source rocks arc anticipated along the BG.
Sub-province 4 - BFZ and eastwards
Stntcturing:
Very
tentials, respectively.
seal potential.
Prospectivity:
There is an overall hydrocarbon potential
scale, and mostly below our seismic grid res­
in the Paleozoic section along the DG (4a),
olution.
with large scale structuring and multi reser­
Good quality sandstone reservoirs of the
voir, source and cap rocks present. The
Billefjorden Group and Ebbadalen Forma­
Mesozoic has a reduced potential, due to
tion are present i n Billefjorden. Porosities
structural closure and reservoir and cap rock
arc expected to be reduced with increas­
quality problems.
ing burial, but presumably remain mod­
Eastwards (4b) there is also a reduced po­
erate also for some distance below cast­
tential, basically because of lack of struc­
ern Nordenskiold Land. Bioherms and sec­
turing and shallow burial. An exception is
ondary solution/solution breccias in the Pa­
along the LFZ, where large scale structuring
leozoic carbonates are expected to occur,
is evident.
360
A. N¢ttvedt, F. Livbjerg,
Acknowledgements
Dypvik, H.,
The authors would like to thank Store Norske and
are indebted to many of our colleagues at Norsk
Hydro for providing pieces of the results presented
here. We further thank Norsk Hydro Research Cen­
tre's technical staff for typing the manuscript and
drafting the figures, and Brian Farrelly and
Pierce for critically reviewing the text.
Elin
1987. Lower Carboniferous coal depositional
13:
953-964.
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1988. Geometry and structural development of the
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