Download Maturity and source-rock potential of Palaeozoic sediments in the

Maturity and source-rock potential of Palaeozoic sediments in the
NW European Northern Permian Basin
Jon H. Pedersen1, Dag A. Karlsen1, Jan E. Lie2, Harald Brunstad2 and
Rolando di Primio3
1
Department of Geosciences, University of Oslo, PO Box 1047 Blindern, N-0316 Oslo, Norway
(e-mail: [email protected])
2
RWE Dea Norge AS, PO Box 243 Skøyen, N-0213 Oslo, Norway
3
GeoForschungsZentrum Potsdam, Telegrafenberg, D-14473 Potsdam, Germany
ABSTRACT: The Northern Permian Basin is located in the offshore area SSW of
Norway, NNW of Denmark and east of Scotland. This basin is filled mainly by
Lower Permian aeolian desert sediments and volcanics, plus Upper Permian
evaporitic sediments. The aeolian sandstone is an excellent reservoir rock and is
generally capped by thick layers of salt that potentially form a tight cap rock. The
highest risk in the petroleum exploration of the Palaeozoic Northern Permian Basin
is linked to the presence of source rocks. Palaeozoic source-rock candidates in the
Northern Permian Basin area may be present among Lower Palaeozoic marine
sediments, within Devonian–Carboniferous lacustrine/deltaic pre- and syn-rift
sediments and as Permian marine shales. This study investigates Lower Palaeozoic
marine shales, lacustrine Devonian mudstones, Carboniferous mudstones and coals
and marine Permian shales in order to assess the thermal maturity, source-rock
potential and distribution of Palaeozoic sediments in the Northern Permian Basin
region. The majority of the investigated samples were within the oil window in terms
of thermal maturity. Lower Palaeozoic marine sediments may have generated both
oil and gas, while Upper Palaeozoic coals and mudstones are dominantly gas-prone
source rocks. Middle Permian marine shales (Kupferschiefer) are a good oil-prone
source rock. Generation and expulsion of hydrocarbons from Lower Palaeozoic
source rocks in the eastern parts of the Northern Permian Basin probably began in
the Upper Silurian, with peak oil generation in Carboniferous times. Upper
Palaeozoic rocks in the same area matured rapidly in Early Triassic times. The likely
presence of multiple Palaeozoic source rocks suggests that hydrocarbons were
generated in the Northern Permian Basin.
KEYWORDS: Palaeozoic, source rocks, Northern Permian Basin, new play, petroleum exploration
INTRODUCTION
The offshore areas of Norway have been extensively explored
for petroleum resources since the first major oil discovery (the
Balder Field) in 1967. In the North Sea, exploration activities
have been focused on the Mesozoic Moray Firth Basin and the
Central Graben and Viking Graben systems, proving the
existence of an excellent marine Upper Jurassic shale as source
rock for the many petroleum discoveries made in the North Sea
region (Field 1985; Northam 1985; Chung et al. 1992; Cornford
1998). In contrast to this, Upper Palaeozoic source and
reservoir rocks dominate in the southern parts of the North Sea
covering the Southern Permian Basin. Here, Upper Carboniferous (Westphalian) coals are the main source for gas trapped
in Permian reservoirs (Maynard et al. 1997). In the Baltic Sea
region, east of the North Sea, Lower Palaeozoic petroleum
systems are documented, from which commercial quantities of
petroleum are produced (Brangulis et al. 1993; Zdanaviciute &
Lazauskiene 2004). In the northern North Sea region, only one
Petroleum Geoscience, Vol. 12 2006, pp. 13–28
occurrence of commercial quantities of oil is related to Palaeozoic source rocks, namely the Beatrice Field offshore Scotland.
Most of the oil in this field is sourced from Devonian lacustrine
source rocks (Peters et al. 1989). Palaeozoic plays and possible
source-rock occurrences in the North Sea and on the margins
of the north Atlantic Ocean have been discussed previously,
for example by Stemmerik et al. (1990), Gérard et al. (1993),
Christiansen et al. (1993), Karlsen et al. (1995), Sørensen &
Tangen (1995), Bugge et al. (2002) and Pedersen (2002). The
work of these authors suggests that Palaeozoic source rocks are
likely to exist in the Northern North Sea and the Norwegian
Sea. Occurrences of insoluble bitumen (residual oil) in Upper
Palaeozoic reservoir rocks in the Norwegian Embla Field
(Bharati 1997) and findings of possible pre-Jurassic oils in
inclusions in authigenic minerals from the Ula Field (Karlsen
et al. 1993) indicate that Palaeozoic petroleum may have
saturated migration paths in the Northern North Sea,
before Mesozoic source rocks became mature. Oil staining and
1354-0793/06/$15.00 2006 EAGE/Geological Society of London
14
J. H. Pedersen et al.
Fig. 1. (a) Study area and well
database. Main structural elements and
sample locations are indicated. Dashed
lines are offshore national borders.
(b) Pre-Zechstein depth map of the
Northern Permian Basin (NPB) and
North Sea region. Warm colours
indicate highs, cold colours indicate
basins. The black line defines the
outline of the NPB referred to in this
study.
bitumen in Palaeozoic rocks in southern parts of Norway and
Sweden strongly indicate that oil has been generated and
expelled from Lower Palaeozoic marine shales in these areas
(Dons 1956; Eakin 1989; Olaussen et al. 1994; Buchardt &
Hansen 2000).
STUDY OBJECTIVES
Petroleum exploration focusing on Palaeozoic sections in the
Northern Permian Basin area has been limited to date, and little
has been done to investigate the possible Palaeozoic petroleum
system(s) of the Northern Permian Basin. This study aims to
improve understanding of the thermal maturity and petroleum
potential of the Palaeozoic marine and continental sediments
believed to be present in the Northern Permian Basin. To do
this, analyses are made of Lower and Upper Palaeozoic
source-rock samples from wells and outcrops which may
represent sediments present in the Northern Permian Basin. An
attempt is also made to give a generalized picture of subsidence
and source-rock maturation in the eastern parts of the study
area and a tentative petroleum system is proposed, with
Palaeozoic source, reservoir and cap rocks.
REGIONAL GEOLOGICAL FRAMEWORK OF THE
STUDY AREA
The Northern Permian Basin (NPB) is bordered in the north by
the Norwegian mainland, in the south by the prominent Danish
Ringkøbing–Fyn High, in the east by the Swedish mainland and
in the west by the offshore shelf of Scotland and the Mid North
Sea High (Figs 1a, b). The Caledonian Deformation Front
(CDF) is considered to be an important structural element in
the NPB (Fig. 1a). Note that the Palaeozoic structural elements
are heavily overprinted by Mesozoic rifting and graben formation in the central parts of the North Sea. In Late Cambrian to
Early Ordovician times the black, organic-rich marine mud
known as the Alum Shale was deposited in a marine anoxic
shallow shelf environment that covered much of Scandinavia
and the Baltics (Andersson et al. 1985; Thickpenny & Leggett
1987). In Ordovician to Silurian times, the depositional
environment became more oxic, and marine clays and carbonates were deposited in southern Scandinavia (Möller 1987).
During the Late Silurian, the collision between the continental
plates of Laurentia and Baltica closed the Iapetus Ocean and
resulted in the formation of Laurussia. In the collision zone
between the two continents, the Caledonian mountain range
Palaeozoic source rocks, Permian Basin
was formed and the sedimentary environment in southern
Norway changed from marine to continental. The denudation
of the Caledonian mountain range continued into the Devonian
and led to a collapse of the mountain range. This, in turn, led to
an extensional regime, with reactivation of Caledonian thrusts
and formation of half-graben in which continental sediments
were deposited (Coward 1995; Marshall & Hewett 2003).
During the Devonian vast amounts of sand, eroded from the
remains of the Caledonian mountain range, were deposited
over the North Sea region, forming the Old Red and the
Buchan sandstones. The extensional regime in a continental
setting probably lasted into the Carboniferous. During the
Early Carboniferous, the sedimentary environment changed
from dominantly continental to a more diverse facies with
marine, deltaic and fluvial sedimentation (Bruce & Stemmerik
2003). A narrow seaway advanced from the southern parts of
the UK into the eastern parts of the North Sea, through the
NPB and into the Oslo Graben area (Olaussen 1981). During
Late Carboniferous to Early Permian time rifting and extrusive
volcanism were common in the NPB region (Glennie et al.
2003). The rifting resulted in the formation of the Skagerrak
Graben and the Oslo Graben (Husebye et al. 1988; Ro et al.
1990). In the NPB offshore SW Norway, N–S-trending rift
graben, such as the Krabbe and Kreps fault zones were formed,
possibly due to rifting and reactivation of old weakness zones in
the crust (see Fig. 1 for location). By the onset of the Permian,
the climate became drier as a response to the formation of the
supercontinent Pangaea (Glennie 1997) and this led to desert
formation in the Southern Permian Basin (SPB) and the NPB
during the Early Permian. Permian aeolian sands (the Auk
Formation in the Rotliegend Group) are present in the NPB, as
evidenced by Norwegian wells 2/1-7 and 3/5-1 and Danish
wells D-1 and Elna-1. In the distal parts of the NPB sedimentation was probably dominated more by flash floods and
ephemeral lakes, while desert lake and sabkha deposits may
have been the prevailing sediment types in the central parts of
the NPB (Sørensen & Martinsen 1987). In mid-Permian times
sea water transgressed rapidly from the north and quickly
flooded the NPB and the SPB. In the marine environment that
followed, an organic-rich mud (Kupferschiefer) was deposited
over most of the North Sea and NPB areas (Glennie et al.
2003). Subsequently, following episodic marine flooding of the
NPB and SPB, the sea water evaporated and carbonates and
large amounts of salts were precipitated and accumulated on
the seafloor. The thick layers of evaporitic sediments include
halite, dolomite and anhydrite (Glennie et al. 2003). The salts,
with their capabilities for plastic deformation, are excellent cap
rocks for gas accumulations in the SPB and are known from a
number of wells in the North Sea area, such as in Norwegian
wells 2/1-7, 3/7-2 and 7/3-1 and Danish wells D-1 and
Felicia-1A. At the end of the Permian the continental landmasses of today’s NW Europe had migrated northwards and
this changed the environment from desert to semi-arid conditions. During the Triassic thick layers of continental sediments accumulated in the eastern part of the NPB due to
thermal post-rift subsidence. In Danish well Felicia-1A, 3190 m
of Triassic sediments overlay Upper Permian Zechstein
deposits. For a more detailed description of the formation of
Palaeozoic basins of NW Europe, see Coward (1995).
THE SAMPLE SET
The samples in this study were selected in order to get the best
possible understanding of the distribution, thermal maturity
and petroleum potential of Palaeozoic sediments in the NPB
area. The samples are listed in Table 1. Cuttings and core
15
samples of Devonian, Carboniferous and Permian rocks were
collected from 31 wells in the Norwegian, Danish and UK parts
of the North Sea. Core samples from two onshore Swedish
wells penetrating Upper Cambrian–Lower Ordovician marine
shales were also collected, together with Lower Carboniferous
lacustrine shale samples from outcrops in the Midland Valley,
Scotland. Samples from onshore locations may represent
Palaeozoic sediments offshore, although this is not proven by
wells. In all, 189 samples made up the initial database for this
study, but some samples were subsequently discarded due to
contamination or uncertain age. Finally, only samples with total
organic carbon (TOC) contents exceeding 1 wt% were regarded
as source-rock candidates and included in this study. The final
sample set was made up of seven coal samples, 27 mudstone
samples and 24 shale samples, ranging in age from Cambrian to
Permian (Fig. 2).
ANALYSIS
The rock samples were cleaned with water, dried at room
temperature and crushed in a steel mill. Aliquots of the
powdered rocks were analysed using a Rock-Eval II unit with
TOC module at the University of Bergen, Norway.
Source-rock extracts were obtained by extracting the crushed
samples with dichlormethane: methanol (97: 3 v/v) for three
hours in a Soxtec extraction unit. The solution was thereafter
concentrated by evaporation of the solvent to a total volume of
3 ml. Gas chromatography–mass spectrometry (GC–MS) analysis of the whole extracted organic matter was performed using
a Fisons GC800 gas chromatograph with a Fisons A200 S
autosampler (10 µl syringe), connected to a Fisons Instruments
MD800 quadrupole mass spectrometer. The chromatographic
column was a Chromapack CP-SIL 5CB-MS FS WCOT fused
silica type column (50 m 0.32 mm i.d., 0.40 µm film thickness). Temperature programme: 80 C–10 C min1–180 C–
1.7 C min1–316 C (30 min) for 80 minutes (180–316 C).
MS details: EI ionization method, SIR collection mode, ions
collected were (m/z) 191, 217, 218, 231, 256, 178, 192 and 198.
Only results from m/z 178, 192 and 198 are presented in this
study. The NSO-1 (North Sea Oil) was used as a reference
sample (Dahlgren et al. 1998). No quantitative standard was
used. Peak heights were used for calculating peak ratios.
In order to assess what type of petroleum products the
collected source-rock samples might generate under thermal
stress (maturation), an open pyrolysis–gas chromatography
(PY–GC) analysis was performed on selected samples of low
maturity at the GeoForschungsZentrum in Potsdam, Germany.
The samples not extracted with solvent were treated with HF
and HCl in order to concentrate the kerogen in the source
rocks. The kerogen concentrates were pyrolysed in an open
pyrolysis unit connected to a nitrogen cold trap and an Agilent
GC 6890A chromatograph equipped with a Flame Ionization
Detector (FID). The chromatographic column was a HP-Ultra
1 dimethyl-polysiloxane-coated column (50 m 0.32 mm i.d.,
0.52 µm film thickness). The kerogen concentrate was first
purged at 300 C for four minutes in order to vent volatile
products prior to pyrolysis, then heated to 600 C in ten
minutes under a helium atmosphere. The petroleum compounds released during the pyrolysis were trapped in a cryogenic nitrogen cold trap. The trap was subsequently heated to
300 C and the mobilized compounds run through the GC–
FID for detection and characterization of the pyrolysate. Flow
was regulated at 30 ml min1, with a split ratio of 1: 15. Peak
areas were used for estimating the relative abundance of
compounds in the pyrolysate.
16
J. H. Pedersen et al.
Table 1. Sample set and analyses performed
Sample
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
Age
Site/well
Depth
(mRKB)
Devonian
Devonian
Devonian
Devonian
Devonian
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
Permian
Permian
Permian
Permian
Permian
Permian
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
Cambr./Ordovic.
Cambr./Ordovic.
Cambr./Ordovic.
Cambr./Ordovic.
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
L. Carboniferous
Cambr./Ordovic.
Cambr./Ordovic.
Cambr./Ordovic.
Cambr./Ordovic.
Cambr./Ordovic.
Cambr./Ordovic.
NO 2/7-21 S
NO 2/7-23 S
NO 2/7-23 S
NO 2/7-26 S
NO 2/7-26 S
NO 2/11-9
NO 2/11-9
NO 2/11-9
NO 2/11-9
NO 2/11-9
NO 2/11-9
NO 2/11-9
NO 25/10-2 R
NO 25/10-2 R
NO 25/10-2 R
DK Felicia-1A
DK Felicia-1A
DK Felicia-1A
DK Gert-3
DK Gert-3
DK P-1
DK P-1
DK P-1
DK Terne-1
DK Terne-1
DK Terne-1
DK Terne-1
UK Midland Valley
UK Midland Valley
UK Midland Valley
UK 14/19-1
UK 14/19-1
UK 14/19-1
UK 14/19-1
UK 14/19-1
UK 15/19-2
UK 15/19-2
UK 15/19-2
UK 15/19-2
UK 20/10a-3
UK 20/10a-3
UK 20/10a-3
UK 20/10a-3
UK 26/7-1
UK 38/16-1
UK 38/16-1
UK 39/7-1
UK 39/7-1
UK 39/7-1
UK 43/2-1
UK 43/2-1
UK 44/2-1
S Närke
S Närke
S Närke
S Öland
S Öland
S Öland
4341.5
4433
4434
4310.5
4396
4213
4214.4
4215.4
4217.4
4220.8
4224
4224.5
3006.6
3008.3
3008.4
5143
5224
5242
4718
4810
3389
3389–3398.5
3398.5
3143–3146
3161–3164
3185–3188
3296–3299
0
0
0
2374.4–2380.5
2441.5–2444.5
2487.2
2487.2
2871.2
2252.5–2264.7
2484.1–2487.2
2578.6–2584.7
2578.6–2584.7
3624.1
3910.6
3956.3
3956.3
1557.9
2002.5
2003.1
3547.9–3550.9
3547.9–3550.9
3560–3563.1
3008.4–3011.4
3063.2–3066.3
2786.2
13.1
18.1
19.3
25
34.5
37.6
Sample type
Core
Core
Core
Core
Core
Core
Core
Core
Core
Core
Core
Core
Core
Core
Core
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Outcrop
Outcrop
Outcrop
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Core
Core
Core
Cuttings
Cuttings
Cuttings
Cuttings
Cuttings
Core
Core
Core
Core
Core
Core
Core
Lithology
Mudstone
Mudstone
Mudstone
Mudstone
Mudstone
Mudstone
Coal
Mudstone
Mudstone
Mudstone
Mudstone
Mudstone
Shale (Kupferschiefer)
Shale (Kupferschiefer)
Shale (Kupferschiefer)
Mudstone
Mudstone
Mudstone
Mudstone
Mudstone
Mudstone
Mudstone
Mudstone
Shale (Dictyonema Sh.)
Shale (Dictyonema Sh.)
Shale (Dictyonema Sh.)
Shale (Alum Shale)
Shale (torbanite)
Shale (torbanite)
Shale (torbanite)
Mudstone
Mudstone
Mudstone
Coal
Shale
Shale
Coal
Shale
Coal
Shale
Shale
Shale
Shale
Mudstone
Mudstone
Coal
Mudstone
Coal
Coal
Carbonaceous shale
Mudstone
Mudstone
Shale (Alum Shale)
Shale (Alum Shale)
Shale (Alum Shale)
Shale (Alum Shale)
Shale (Alum Shale)
Shale (Alum Shale)
Analysis
Rock-Eval,
Rock-Eval,
Rock-Eval,
Rock-Eval,
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval
Rock-Eval
Rock-Eval,
Rock-Eval,
Rock-Eval,
Rock-Eval,
Rock-Eval,
Rock-Eval
Rock-Eval
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval
Rock-Eval,
Rock-Eval,
Rock-Eval,
Rock-Eval
Rock-Eval
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval,
Rock-Eval
Rock-Eval,
Rock-Eval,
Rock-Eval,
Rock-Eval,
Rock-Eval
GC–MS, VR
GC–MS
GC–MS
GC–MS
GC–MS
GC–MS, PY-GC, VR
PY–GC
GC–MS
GC–MS, VR
GC–MS
GC–MS, VR
GC–MS, PY–GC
GC–MS, VR
GC–MS, VR
GC–MS
GC–MS
PY–GC, VR
PY–GC, GC–MS
GC–MS
VR
VR
GC–MS
GC–MS
GC–MS, PY–GC
GC–MS, PY–GC
GC–MS, PY–GC, VR
VR
PY–GC
GC–MS
GC–MS
GC–MS, PY–GC
GC–MS, PY–GC
GC–MS
GC–MS, gas chromatography–mass spectrometry; PY–GC, open pyrolysis–gas chromatography; VR, vitrinite reflectance.
To estimate thermal maturity in addition to Rock-Eval Tmax
and isomerization ratios of methylphenantrene, selected
samples were analysed for vitrinite reflectance at Applied
Petroleum Technology at Kjeller, Norway.
RESULTS AND DISCUSSION
The results discussed below are listed in Tables 2 and 3.
Table 2 contains Rock-Eval and maturity data for all 58
samples, while Table 3 indicates the petroleum potential of
samples with S2 values above 4 mgHC g1 rock. Figures 3, 4,
5 and 6a, b show the kerogen type, petroleum potential and
maturity of the samples. The maturity parameters referred to
in the discussion are Tmax values (the temperature at the
maximum yield on the S2 peak during Rock-Eval analysis),
vitrinite reflectance measurements on selected samples (%Ro),
and calculated ‘vitrinite reflectance’ (%Rc) based on the
Palaeozoic source rocks, Permian Basin
17
Fig. 2. Tentative Palaeozoic and
Mesozoic stratigraphy in the
Norwegian–Danish Basin and the
eastern part of the Northern Permian
Basin, with possible source, reservoir
and cap rocks indicated. The
stratigraphic position of the analysed
samples (sample numbers refer to
Table 1) is marked in the column to the
far right.
isomerization ratios derived from aromatic hydrocarbons
(methylphenantrenes) identified by GC–MS analysis of rock
extracts (Kvalheim et al. 1987).
Lower Palaeozoic source rocks
Rock-Eval Tmax values and calculated ‘vitrinite’ reflectance
values indicate that the samples of Upper Cambrian–Lower
Ordovician marine Alum Shale (samples 53–58) are of low
thermal maturity. The Tmax values for the samples from Närke
(samples 53–55) range from 414 C to 417 C, corresponding to
the shallowest part of the oil window. The samples from Öland
(samples 56–58) appear slightly more mature, with Tmax values
ranging from 425 C to 430 C. The opposite picture emerges
when looking at the calculated ‘vitrinite reflectance’ (%Rc). The
values are lowest for the Öland samples (0.43%Rc and
0.53%Rc), while the Närke samples have values of 0.74%Rc and
0.79%Rc. No real vitrinite reflectance methodology were used
on the Lower Palaeozoic samples in this study, but Bharati et al.
(1995) found the maturity of six Alum Shale samples from
southern Sweden to be immature to early mature (0.25%Ro to
0.45%Ro) based on bituminite reflectance. The Upper
Cambrian–Lower Ordovician Alum Shale and Dictyonema
Shale from the Danish well Terne-1 (samples 24–27) are in a
much more advanced state of maturity, with calculated ‘vitrinite
reflectance’ values of 1.12%Ro and 1.20%Rc. Note that the
Tmax values for samples 24–27 are very low (356 C to 407 C)
and are not believed to give a correct maturity estimate for
these samples.
The Cambrian samples from Swedish onshore wells were
found to have high TOC levels of 5.9 wt% to 16.9 wt%
(average TOC value 11.3 wt%) and HI values from
331 mgHC g1 TOC to 1000 mgHC g1 TOC (average HI
value 490.6 mgHC g1 TOC). Note that the HI value of
1000 mgHC g1 TOC for sample 54 is an extremely high
value. The range in HI values for the five other Swedish Alum
Shale samples in this study is 332 mgHC g1 TOC to
431 mgHC g1 TOC (average HI value 363 mgHC g1 TOC)
and are considered more representative for the Alum Shale.
The TOC values of Alum Shale and Dictyonema Shale from
Terne-1 range from 1.08 wt% to 6.1 wt% (average TOC value
3.1 wt%). The HI values are very low, from 5 mgHC g1 TOC
to 88 mgHC g1 TOC (average HI value 28 mgHC g1 TOC),
18
J. H. Pedersen et al.
Table 2. Results from Rock-Eval and maturity analysis
Sample
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
Site/well
Depth
(mRKB)
NO 2/7-21 S
NO 2/7-23 S
NO 2/7-23 S
NO 2/7-26 S
NO 2/7-26 S
NO 2/11-9
NO 2/11-9
NO 2/11-9
NO 2/11-9
NO 2/11-9
NO 2/11-9
NO 2/11-9
NO 25/10-2 R
NO 25/10-2 R
NO 25/10-2 R
DK Felicia-1A
DK Felicia-1A
DK Felicia-1A
DK Gert-3
DK Gert-3
DK P-1
DK P-1
DK P-1
DK Terne-1
DK Terne-1
DK Terne-1
DK Terne-1
UK Midland Valley
UK Midland Valley
UK Midland Valley
UK 14/19-1
UK 14/19-1
UK 14/19-1
UK 14/19-1
UK 14/19-1
UK 15/19-2
UK 15/19-2
UK 15/19-2
UK 15/19-2
UK 20/10a-3
UK 20/10a-3
UK 20/10a-3
UK 20/10a-3
UK 26/7-1
UK 38/16-1
UK 38/16-1
UK 39/7-1
UK 39/7-1
UK 39/7-1
UK 43/2-1
UK 43/2-1
UK 44/2-1
S Närke
S Närke
S Närke
S Öland
S Öland
S Öland
4341.5
4433
4434
4310.5
4396
4213
4214.4
4215.4
4217.4
4220.8
4224
4224.5
3006.6
3008.3
3008.4
5143
5224
5242
4718
4810
3389
3389–3398.5
3398.5
3143–3146
3161–3164
3185–3188
3296–3299
0
0
0
2374.4–2380.5
2441.5–2444.5
2487.2
2487.2
2871.2
2252.5–2264.7
2484.1–2487.2
2578.6–2584.7
2578.6–2584.7
3624.1
3910.6
3956.3
3956.3
1557.9
2002.5
2003.1
3547.9–3550.9
3547.9–3550.9
3560–3563.1
3008.4–3011.4
3063.2–3066.3
2786.2
13.1
18.1
19.3
25
34.5
37.6
TOC
S1
S2
S1+S2
HI
Tmax %Ro %Rc
(wt%) (mgHC g1 rock) (mgHC g1 rock) (Petroleum potential, (mgHC g1 TOC) (C)
mgHC g1 rock)
1.57
1.53
2.12
2.01
1.35
1.39
64.5
1.86
2.76
1.66
2.3
2.74
5.28
5.87
4.25
1.47
1.47
2.17
1.17
2.01
2.5
1.58
1.83
1.08
1.7
6.1
3.53
60.4
23.9
8.32
1.93
1.92
3.07
17.6
8.83
5.59
80.3
6.84
57.6
7.12
4.02
4.55
4.13
2.91
2.02
73.2
1.68
38.7
67.5
14.4
4.43
3.31
12.9
5.98
16.9
11.1
9.8
—
2.4
8.02
17.3
18.9
10.7
0.16
14.9
0.33
0.36
0.31
0.36
0.56
2.93
2.43
2.19
1.86
2.88
3.56
0.41
2.63
0.95
1.56
1.5
0.3
1.73
0.48
0.28
5
1.05
0.71
1.16
1.57
1.37
1.08
1.52
1.25
32.8
1.3
3.75
7.01
6.52
5.83
5.94
0.57
0.28
9.23
0.72
4
2.41
7.77
4.62
0.42
0.84
1.3
1.38
1.38
1.12
0.83
1.81
2.9
4.05
1.96
0.87
0.64
111
0.79
1.09
0.63
1.45
2.08
19.2
29.2
22.2
2.57
5.1
4.8
1.01
4.46
0.94
0.36
0.5
0.16
1.49
0.33
0.16
176
119
29
0.68
1.21
2.02
87.3
8.62
9.86
145
15.4
142
10.4
9.49
8.45
5.62
1.38
0.9
83.3
1
54.8
21
26.6
5.55
1.51
42.7
70.6
73.1
36
35.9
25.1
4.21
10.92
21.38
20.81
11.57
0.8
126.4
1.12
1.45
0.94
1.81
2.64
22.14
31.6
24.43
4.43
7.98
8.36
1.42
7.09
1.89
1.92
2
0.46
3.22
0.81
0.44
180.8
120
29.67
1.84
2.78
3.39
88.37
10.14
11.11
177.8
16.7
145.6
17.41
16.01
14.28
11.56
1.95
1.18
92.56
1.72
58.8
23.44
34.34
10.17
1.93
43.54
71.94
74.43
37.41
36.97
25.9
115
190
191
98
64
46
173
42
39
38
63
76
364
497
523
175
347
221
86
222
38
23
27
15
88
5
5
291
498
348
35
63
66
497
98
176
181
225
246
146
236
185
136
47
44
113
60
142
31
184
125
46
332
c. 1000
431
324
366
—
461
345
344
337
350
437
446
494
504
447
441
438
427
424
421
437
433
421
444
436
443
395
441
361
407
356
366
451
446
426
425
435
452
443
439
432
432
435
434
449
449
433
426
435
431
427
431
441
443
418
430
439
414
414
417
430
430
425
0.69
0.93
1.04
1.05
1.08
0.98
0.76
0.96
1.09
0.98
0.38
0.75
1.24
0.61
1.06
0.92
0.84
0.79
0.61
0.90
1.20
1.12
0.30
0.42
0.45
0.67
0.77
0.98
1.09
0.51
0.92
0.82
0.82
0.82
1.03
0.79
0.74
0.53
0.43
%Ro is measured vitrinite reflectance; %Rc is calculated ‘vitrinite reflectance’, calculated from the four isomers of the aromatic compound methylphenantrene
(%Rc=2.242(F10.166), where F1=(2-MP+3-MP)/(2-MP+3-MP+1-MP+9-MP) (Kvalheim et al. 1987)).
indicating that the Terne-1 samples contains only ‘dead’ carbon
unable to generate any petroleum. The S1 value indicates the
quantity of free hydrocarbons in the sample. The S1 values are
low for all the Lower Palaeozoic samples (range 0.28–
1.73 mgHC g1 rock). This fits well for the low-mature
samples from Öland, but one would expect higher S1 values for
the Terne-1 samples of higher maturity. The observed S1 values
for the Terne-1 samples could, however, reflect a post-mature
source rock which has expelled all free hydrocarbons. The
remaining petroleum potential (S2, mgHC g1 rock) indicates
how much petroleum a source rock is capable of generating at
the present time. The low-mature Swedish Alum Shale samples
19
Palaeozoic source rocks, Permian Basin
Table 3. Samples with remaining petroleum potential (S2>4 mgHC g1 rock) sorted by their S2 values
Sample
Country
Well
Depth
(mRKB)
Age
3
20
18
17
51
43
42
35
41
36
40
38
13
15
58
50
30
14
57
56
53
54
55
29
28
49
48
46
34
7
39
37
Norway
2/7-23 S
4434
Devonian
Denmark
Gert-3
4810
Lower Carboniferous
Denmark
Felicia-1A
5242
Permian
Denmark
Felicia-1A
5224
Permian
UK
43/2-1
3063.2–3066.3 Lower Carboniferous
UK
20/10a-3
3956.3
Lower Carboniferous
UK
20/10a-3
3956.3
Lower Carboniferous
UK
14/19-1
2871.2
Lower Carboniferous
UK
20/10a-3
3910.6
Lower Carboniferous
UK
15/19-2
2252.5–2264.7 Lower Carboniferous
UK
20/10a-3
3624.1
Lower Carboniferous
UK
15/19-2
2578.6–2584.7 Lower Carboniferous
Norway
25/10-2 R
3006.6
Permian
Norway
25/10-2 R
3008.4
Permian
Sweden
Öland
37.6
Cambrian/Ordovician
UK
43/2-1
3008.4–3011.4 Lower Carboniferous
Scotland Midland Valley
0
Lower Carboniferous
Norway
25/10-2 R
3008.3
Permian
Sweden
Öland
34.5
Cambrian/Ordovician
Sweden
Öland
25
Cambrian/Ordovician
Sweden
Närke
13.1
Cambrian/Ordovician
Sweden
Närke
18.1
Cambrian/Ordovician
Sweden
Närke
19.3
Cambrian/Ordovician
Scotland Midland Valley
0
Lower Carboniferous
Scotland Midland Valley
0
Lower Carboniferous
UK
39/7-1
3560–3563.1 Lower Carboniferous
UK
39/7-1
3547.9–3550.9 Lower Carboniferous
UK
38/16-1
2003.1
Lower Carboniferous
UK
14/19-1
2487.2
Lower Carboniferous
Norway
2/11-9
4214.4
Lower Carboniferous
UK
15/19-2
2578.6–2584.7 Lower Carboniferous
UK
15/19-2
2484.1–2487.2 Lower Carboniferous
TOC
S1
S2
HI
Potential
(wt%) (mgHC g1 rock) (mgHC g1 rock) (mgHC g1 TOC)
2.12
2.01
2.5
1.47
4.43
4.13
4.55
8.83
4.02
5.59
7.12
6.84
5.28
4.25
—
14.42
8.32
5.87
9.8
11.11
12.88
5.98
16.94
23.87
60.36
67.48
38.74
73.21
17.57
64.46
57.58
80.29
17.33
2.63
5.09
2.88
4.62
5.94
5.83
1.52
6.52
1.25
7.01
1.3
2.93
2.19
0.83
7.77
0.71
2.43
1.12
1.38
0.84
1.3
1.38
1.05
5
2.41
4
9.23
1.08
14.89
3.75
32.81
4.05
4.46
4.85
5.1
5.55
5.62
8.45
8.62
9.49
9.86
10.4
15.4
19.21
22.24
25.07
26.57
28.96
29.17
35.85
36.03
42.7
70.64
73.05
118.94
175.8
21.03
54.8
83.33
87.29
111.48
141.87
145
191
222
194
347
125
136
186
98
236
176
146
225
364
523
—
184
348
497
366
324
332
c. 1000
431
498
291
31
142
114
497
173
246
180
Fair
Good
Rich
Coal
The indicated potential is based on the S2 values. The S2 values approximately reflect the depth of burial for the samples, as more mature, deeply buried samples
have less remaining potential. The coals all have high S2 values.
have very high S2 values, 25.9–74.43 mgHC g1 rock (average
S2 value 47.2 mgHC g1 rock). The samples from Närke have
higher S2 values than the sample from Öland, which could
indicate a lower thermal maturity for the Närke samples.
Figure 6a shows the very high petroleum potential of the
Swedish low-mature Alum Shales. The Alum Shale of high
maturity from the Terne-1 well has, in contrast, no remaining
petroleum potential, with S2 values from 0.16 mgHC g1 rock
to 1.49 mgHC g1 rock (average S2 value 0.54 mgHC g1
rock).
The Alum Shale is widely distributed on- and offshore
Scandinavia (Andersson et al. 1985) and is one of the Lower
Palaeozoic source rocks of commercial oil and gas fields onand offshore Latvia, Lithuania and Poland (Brangulis et al. 1993;
Schleicher et al. 1998). There are many strong indications that
oil has been generated and expelled from Lower Palaeozioc
source rocks onshore Scandinavia. Oil has been produced from
wells penetrating Upper Ordovician carbonate mounds on
Gotland, Sweden (Sivhed et al. 2004) and live, non-biodegraded
oil is found in fossils in an Ordovician limestone in Österplana,
near lake Vänern in Sweden (Buchardt & Hansen 2000;
Pedersen 2002). Biodegraded oil seeps are present in an
Ordovician carbonate mound in Solberga, close to the Siljan
meteoric impact crater in Sweden (Vlierboom et al. 1986;
Pedersen 2002) and oil staining of Lower Cambrian sandstone
is reported from the Danish island Bornholm (Møller & Friis
1999). In the Oslo Graben, insoluble pyrobitumen is common
in fossils and fractures in Lower Palaeozoic sediments (Dons
1956; N. Spjeldnæs, pers. comm.) and locations of oil stains and
oil remains are also known from this area (S. Dahlgren, pers.
comm., Hanken & Owen 1982; Olaussen et al. 1994). Figure 7
shows solid pyrobitumen in Upper Ordovician rocks from the
Oslo Graben. Condensate-like petroleum is described from
inclusions in hydrothermal quartz veins from the Modum and
Kongsberg area west of Oslo (Karlsen et al. 1993; Munz et al.
1993) and both oil and gas occurs in vesicles in Permian
volcanic intrusions at the south coast of Norway (Dons 1956,
1975). Karlsen et al. (1993) found the maturity of a condensate
from inclusions in hydrothermal quartz at Modum to be
equivalent to 2.5%Ro using the methylphenanthrene index of
Radke (1988). Petroleum from a Permian intrusive close to the
small town of Tvedestrand, southern Norway, was most likely
generated from a marine Type II source rock, based on a
biomarker study of petroleum extracted from the intrusion
(Pedersen 2004, unpublished data). The intrusion may extend
offshore into the Skagerrak Graben, and accordingly cut
through Lower Palaeozoic marine sediments thought to be
present in the NPB area. The numerous occurrences of
petroleum mentioned here strongly suggest that Lower Palaeozoic marine shales have generated and expelled oil in onshore
locations in regions of Scandinavia, and indicate that this also
has occurred offshore southern Norway. Shallow cores and
seismic lines from offshore southern Norway show that Lower
Palaeozoic sediments are present in the Skagerrak area (Smelror
et al. 1997; Rise et al. 1999, fig. 2). In this study, the Alum Shale
stands out as the best Lower Palaeozoic source-rock candidate.
Silurian marine mudstones collected from Danish wells
Slagelse-1 and Pernille-1 had no petroleum potential (TOC
20
J. H. Pedersen et al.
Fig. 4. Mean (measured) vitrinite reflectance (%Ro) of selected rock
samples vs. present burial depth. Numbers refer to sample numbers
in Table 1. Points X and Y represent unpublished data from the
Carboniferous section in Norwegian well 2/10-1 S. Sample Z
(Devonian) is from Norwegian well 2/7-21 S. The majority of
samples fall within the oil window in terms of thermal maturity.
Fig. 3. Hydrogen index (HI) vs. Tmax plot, indicating kerogen type
and maturity of the samples in Table 1. Broken lines indicate
approximate corresponding mean vitrinite reflectance for Type III
kerogen. Type I kerogen (oil-prone) is represented by samples 28 and
29, while Type II kerogen (oil- and gas-prone) is abundant in, for
example, samples 14, 15 and 53. Type III kerogen (gas-prone) is
represented here by the majority of the samples. The Tmax value is an
approximate measure of thermal maturity, but is also influenced by
the kerogen type. Most of the samples are thought to have thermal
maturities corresponding with the upper half of the oil window.
contents 0.15 wt% and 0.43 wt%), but Silurian source rocks are
known from the Baltic Sea and Baltic onshore areas (Brangulis
et al. 1993). Bjørlykke (1974) studied Lower Palaeozoic sediments from the Oslo Graben and found the average contents
of organic carbon to be around 2–5% in Middle Cambrian
Paradoxides Shale, 10% in Alum Shale, 5–10% in the
Dictyonema Shale and 1–3 % in the Lower Ordovician
Didymograptus Shale. The Upper Ordovician Trestaspis Shale
from the Oslo Graben had generally low carbon contents
below 0.5%. Note that the TOC contents in the Dictyonema
Shale appear to be higher in the samples from the Oslo Graben
than in the samples from the Terne-1 well, despite the
post-mature nature of the Lower Palaeozoic sediments in the
Oslo Graben (bituminite reflectance up to 4.8%Ro, Bharati et al.
1995). The analysis made by Bjørlykke (1974) indicates that the
best source-rock facies was developed in the Upper Cambrian
Alum Shale, but also that source rocks may have developed in
Middle Cambrian marine sediments. Based on the aforementioned earlier observations and the analysis presented here,
there is no reason why Lower Palaeozoic marine shales underlying the offshore NPB did not generate and expel oil and gas.
Fig. 5. Thermal maturity of rock extracts and oils derived from
aromatic compounds expressed as calculated ‘vitrinite reflectance’
(%Rc) (Kvalheim et al. 1987) vs. present sample depth. Numbers
refer to sample numbers in Table 1. Samples A and B are Lower
Palaeozoic oils from two locations onshore Sweden – (A) Siljan and
(B) Österplana. Sample C is the Upper Jurassic-sourced NSO-1 oil
from the Oseberg Field. The NSO-1 oil is used here as a reference
oil. The maturity parameter F1 is derived from the four methylphenantrene isomers: F1=(2-MP+3-MP)/(2-MP+3-MP+1-MP+9-MP).
The calculated reflectance values correspond approximately with the
measured vitrinite reflectance values shown in Figure 4.
Devonian source rocks
The Devonian mudstone samples from wells in the Norwegian
Embla Field (samples 1–5) have very low Tmax values (337 C
Palaeozoic source rocks, Permian Basin
21
Fig. 6. Rock-Eval S2 value vs. TOC content. Numbers refer to sample numbers in Table 1. (a) All the samples with TOC exceeding 1 wt%,
i.e. all samples in Table 1. Coals have the highest TOC and S2 values, but note that samples 28, 29, 30, 50, 53, 54 and 55 are lacustrine and marine
shales with very high remaining petroleum potential. (b) Expanded view of the bottom left-hand corner of (a). The majority of samples have
no remaining petroleum potential, but a range of source rock candidates have fair to rich potential. See Table 1 for sample identification.
to 350 C), indicating an immature state of these samples. This
is not coherent with the present-day burial depth (4310.5–
4434 mRKB). Sample 1 is the exception, with a more reasonable Tmax value of 461 C, suggesting a maturity corresponding
to the middle-deepest part of the oil window. Samples 2 to 5
appear to be oil stained (very low Tmax values, high S1 values).
The oil staining may origin from Upper Jurassic marine shales
sourcing the reservoirs of the Embla Field (Bharati 1997) or
from oil-based mud used when drilling the wells. The NPD
well data summary sheet for well 2/7-23 S states that oil-based
mud was used when drilling this well (www.npd.no). Therefore,
the Tmax values of samples 2–5 cannot be interpreted and
sample 1 is believed to best represent the maturity of the
Devonian samples. Vitrinite reflectance measurements on
sample 1 (0.69%Ro) indicate a slightly lower maturity than the
Fig. 7. Scanning electron micrograph (backscattered electrons,
unpolished section) of an Upper Ordovician limestone from the
Oslo Graben (Ringerike). Pyrobitumen (C) appears dark, while
calcite (CaCO3) is light. Quartz (SiO2) is also identified in the rock
section. The cracks in the pyrobitumen are filled with calcite.
Tmax value, but the Tmax maturity is backed up by the maturity
indicated by the calculated ‘vitrinite reflectance’ (0.93%Rc). The
medium-high maturities indicated by the calculated ‘vitrinite
reflectance’ values for samples 2–5 (0.98%Rc to 1.08%Rc) may
be related to mature, migrated oil sourced from deeply buried
Upper Jurassic source rocks, or in the case of well 2/7-23 S, oil
additives in the drilling mud. Bharati (1997) calculated ‘vitrinite
reflectance’ values ranging from 0.93%Rc to 1.13%Rc for oils
from the Embla Field, using methylphenantrene isomers as
described by Radke (1988). Even though samples 2–5 may be
contaminated with migrated oil, they still give some information on TOC and HI. These data should, however, be used
with caution. The TOC values for the Devonian samples range
from 1.35 wt% to 2.12 wt% (average TOC value 1.7 wt%). The
HI values range from 64 mgHC g1 TOC to 191 mgHC g1
TOC (average HI value 132 mgHC g1 TOC). The observed
TOC and HI values classify the Devonian samples as Type III
gas-prone source rocks, at best. As mentioned, samples 2–5
have high S1 values (8.02–18.9 mgHC g1 rock, average S1
value 11 mgHC g1 rock). It is unlikely that the S1 values
observed for samples 2–5 are derived from indigenous oil in the
Devonian mudstones, due to the gas-prone appearance of the
Devonian samples. The S1 value for the assumed uncontaminated sample 1 is perhaps more representative for the
Devonian mudstones, and indicates a small amount of hydrocarbons (2.4 mgHC g1 rock). There is very little remaining
petroleum potential in the Devonian samples, with S2 values
ranging from 0.81 mgHC g1 rock to 4.05 mgHC g1 rock
(average S2 value 2.32 mgHC g1 rock). The distribution of
Devonian sediments in the Norwegian North Sea is not
validated by a statistically relevant number of wells, but the
study of seismic lines (Marshall & Hewett 2003) indicates that
Devonian sediments may exist in many parts of the North Sea,
especially where accommodation space became available by
post-orogenic reactivation of Caledonian thrusts. Half-graben
formed in this way may fringe the CDF (see Fig. 1). Such
graben are known from East Greenland (Surlyk et al. 1986), the
Utsira High in the Northern North Sea (Brekke et al. 2001;
22
J. H. Pedersen et al.
Fig. 8. Simplified geosection across the
western margin of the Utsira High.
Pre-Permian sediments are interpreted
to fill a half-graben probably formed by
extensional reactivation of a Caledonian
structure. Oil staining in Permian
dolomites and pre-Permian sandstone is
reported from well 25/10-4, situated in
an updip position of possible
pre-Permian shales. Adopted from
Brekke et al. (2001).
Marshall & Hewett 2003) and from SE Denmark (Krawczyk
et al. 2002). Brekke et al. (2001) described seismic reflectors in
possible pre-Permian shales on the Utsira High that might
represent coals or, contrastingly, volcanic intrusions (Fig. 8). It
is, in this respect, interesting to note that Norwegian well
25/10-4, located updip of these reflectors, was reported to
penetrate oil-stained Upper Permian dolomite and pre-Permian
sandstones (unpublished data). NW of the NPB, lacustrine
sediments with oil-prone source-rock quality were deposited in
Devonian time in the Orcadian Basin (Duncan & Buxton 1995;
Marshall & Hewett 2003). This lacustrine-evaporitic system
stretched from the north of Scotland in the south to the west
coast of Norway in the north (see Fig. 1 for location). A
potential connection from the Orcadian Basin to the assumed
series of half-graben related to the CDF is indicated by
Norwegian well 15/5-3, which contains Devonian mudstones
and minor sandstones. Although highly speculative, it is possible that Devonian lacustrine source rocks may have been
developed in favourable places in the NW and central parts of
the NPB.
Carboniferous source rocks
The Lower Carboniferous (Viséan) samples include shales,
mudstones and coals from Norwegian and Danish wells and
UK wells and outcrops. The Tmax values of the Norwegian
samples from well 2/11-9 (samples 6–12) indicate a maturity
span from early mature to post-mature (437 C to 504 C,
average Tmax value 458 C). This wide range in maturity is
unrealistic, as the samples are from the interval 4213–
4224.5 mRKB. However, more reliable vitrinite measurements
on a coal sample (sample 7, 0.76%Ro), together with calculated
‘vitrinite reflectance’ from samples 7, 9 and 11 (0.96%Rc,
1.09%Rc and 0.98%Rc) suggest that the Norwegian samples are
medium- to late-mature. Two Carboniferous samples from
Norwegian well 2/10-1 S (unpublished data) have vitrinite
reflectance values of 1.23%Ro and 1.02%Ro at depths of
4538 mRKB and 4596 mRKB (samples X and Y, in Fig. 4). The
Danish shale and mudstone samples from wells Gert-3 and P-1
(samples 19–23) have Tmax values from 395 C to 444 C
(average Tmax value 432 C). The Tmax values appear rather low
for the Gert-3 samples (444 C and 436 C), considering the
present burial depth of 4718 mRKB and 4810 mRKB. The
samples (cuttings) could represent low-mature shales from
shallower depths, which have caved into the well. On the other
hand, the measured vitrinite reflectance (0.84%Ro) and calculated ‘vitrinite reflectance’ (0.79%Rc) indicate a higher, and
more plausible, maturity for the Gert-3 samples (medium
mature). The P-1 mudstones have maturities corresponding to
the upper half of the oil window (0.61%Ro and 0.90%Rc). The
measured vitrinite reflectance value of 0.61%Ro is probably
most correct, as the measured sample (sample 22) was collected
from the interval 3389.5–3398.5 mRKB. The samples from the
UK wells (samples 31–52) have Tmax values placing them in the
upper half of the oil window in terms of maturity. The Tmax
values range from 418 C to 452 C, with an average Tmax value
of 435 C. Sample 50 has an unrealistically low Tmax value of
418 C. Vitrinite reflectance measured on coals from the UK
wells in this study (samples 34, 37, 46 and 49) span from
0.51%Ro to 0.82%Ro, with an average value of 0.69%Ro. Some
of the calculated ‘vitrinite reflectance’ values were somewhat
higher, with values ranging from 0.82%Rc to 1.03%Rc (average
value 0.94%Rc). There is, for example, poor correlation
between the measured (0.51%Ro) and calculated (0.82%Rc)
vitrinite reflectance for sample 46 (coal). In this particular case
it is believed that the measured value is the most correct.
Overall, the offshore UK samples appear less mature than
the Norwegian and Danish samples. Three samples of
Lower Carboniferous lacustrine shale from onshore Scotland
(Edinburgh, Midland Valley) are immature, with Tmax values
from 426 C to 451 C, and measured and calculated ‘vitrinite
reflectance’ of 0.30%Ro, 0.42%Rc and 0.45%Rc.
The mudstones from Norwegian well 2/11-9 (samples 6 and
8–12) have TOC values in the range of 1.39 wt% to 2.76 wt%
(average TOC value 2.12 wt%), and HI values ranging from
38 mgHC g1 TOC to 63 mgHC g1 TOC (average HI value
51 mgHC g1 TOC). The Danish shales and mudstones have
TOC values from 1.17 wt% to 2.5 wt% (average TOC value
1.8 wt%), and HI values from 21 mgHC g1 TOC to
222 mgHC g1 TOC (average HI is 79 mgHC g1 TOC). The
Carboniferous offshore UK shale and mudstone samples have
TOC values between 1.92 wt% and 14.4 wt% (average TOC
value 4.80 wt%), and HI values from 31 mgHC g1 TOC to
Palaeozoic source rocks, Permian Basin
236 mgHC g1 TOC (average HI is 143 mgHC g1 TOC).
The lacustrine shales from the onshore Midland Valley of
Scotland have very high TOC values spanning from 8.3 wt% to
60.3 wt%, and HI values from 291 mgHC g1 TOC to
498 mgHC g1 TOC. The Lower Carboniferous coals from
Norwegian well 2/11-9 and the UK wells have TOC contents
ranging from 17.6 wt% to 80.3 wt% (average TOC is 57.1 wt%)
and HI values in the range of 31 mgHC g1 TOC to
497 mgHC g1 TOC (average HI is 198 mgHC g1 TOC).
The variation in TOC and HI observed for the coal samples is
probably due to varying content of clastic material and variations in the maceral composition and thermal maturity.
In general, the samples from Carboniferous mudstones and
Carboniferous coals are gas-prone Type III source rocks.
However, samples 38 and 41 (HI of 225 mgHC g1 TOC and
236 mgHC g1 TOC) suggest that oil-prone Type II/III
Carboniferous shales may be developed in the western parts
(UK) of the NPB. The coals have very high remaining
petroleum potential, with average S2 values of 92.1 mgHC g1
rock. The shale and mudstone samples from the offshore UK
wells have the highest remaining petroleum potential of the
non-coaly samples, with average S1 value 2.99 mgHC g1 rock
and average S2 values of 6.79 mgHC g1 rock. Among the
shale and mudstone samples from Norway and Denmark, only
sample 20, from DK well Gert-3, has any significant remaining
petroleum potential (S2 is 4.46 mgHC g1 rock). The observed
S2 values may reflect the higher maturity of the samples from
Norwegian and Danish areas, but could also indicate a richer
Carboniferous source-rock facies on the UK side of the NPB.
The Lower Carboniferous lacustrine shales from the Midland
Valley of Scotland (samples 28–30) are oil-prone Type I source
rocks, with very high petroleum potential (average S2 values
108 mgHC g1 rock). Bruce & Stemmerik (2003) suggested a
correlation of coals and mudstones from UK well 20/10a-3
(see Fig. 1 for location) to the oil shales of Midland Valley,
onshore Scotland, represented here by samples 28–30.
Upper Carboniferous marine sediments occur in the Oslo
Graben (Olaussen 1981) and Carboniferous shallow-marine,
bioturbated claystones are found in Danish well Ørslev-1.
Furthermore, Carboniferous shales, mudstones, siltstones and
sandstones are present in Danish wells Borg-1, Gert-3, Hans-1
and P-1. These occurrences suggest that Carboniferous sediments may have been deposited over most of the eastern part
of the NPB. The analysed shales in Gert-3 suggest that
gas-prone source rocks may exist locally, where conditions were
favourable for deposition and preservation of organic matter.
Carboniferous mudstones and coal seams in Norwegian wells
2/10-1 S and 2/11-9 indicate a deltaic depositional environment. Volcanoclastic material of assumed Carboniferous age in
well 2/10-1 S indicates that the Carboniferous sediments at this
location were deposited after rifting and volcanism had begun
in the NPB. The Carboniferous rifting probably allowed
continental syn-rift sediments to be deposited in small rift
valleys in the NPB. Volcanic material is not observed in cores
from Norwegian well 2/11-9, suggesting that these sediments
are older than the oldest sediments found in the 2/10-1 S well,
i.e. they may be of pre-rift Lower Carboniferous age. Note that
a gas kick was reported from 2/10-1 S when the drill bit
penetrated Upper Permian Zechstein evaporites and entered
Lower Permian Rotliegend sandstones (2/10-1S Well Data
Summary Sheet, www.npd.no). Because this well terminated in
Carboniferous mudstones, coal seams and volcanic material,
the gas detected in the Rotliegend sandstones in well 2/10-1 S
was most likely generated from Carboniferous sediments. Close
to the UK side of the NPB, the onshore D’Arcy oil field in
Scotland, among others, is charged by the organic-rich lacus-
23
trine shales represented in this study by samples 28-30 (Hallett
et al. 1985). These Midland Valley oil shales were deposited as
organic-rich sediments in a Carboniferous rift basin that extended into the offshore Firth of Forth. Lower Carboniferous
shales of the Firth Coal Fm., possibly related to the Midland
Valley lacustrine system, are found in UK wells 20/10a-3
(Bruce & Stemmerik 2003), 14/19-1 and 15/19-2. Nevertheless, it is not known if the Midland Valley rift graben continues
eastwards into the Norwegian sector of the NPB. There are no
occurrences of Upper Carboniferous (Westphalian) coals in the
NPB known to the authors. The Ringkøbing–Fyn High, which
was probably uplifted in response to the Carboniferous Variscan orogeny, acted as a barrier between the SPB and the NPB
in Late Carboniferous times (Glennie et al. 2003). This may
have hindered development of the Westphalian delta facies of
the SPB type into the NPB. However, this does not exclude
lacustrine, organic-rich sediments from being deposited in parts
of the NPB during Late Carboniferous times, provided that
enough accommodation space existed for lakes or swamps to
develop. Much of the area was, however, affected by uplift
and erosion in Late Carboniferous to Early Permian times
(Sørensen & Martinsen 1987). Although not proven, it seems
likely, by inference, that both marine sediments and continental
pre- and syn-rift sediments, some of which are of source-rock
quality, were deposited in the NPB during the Carboniferous.
Permian source rocks
The Permian samples consist of marine shale (the
Kupferschiefer, also known as Marl Slate or Copper Shale)
from Norwegian well 25/10-2 and mudstones from Danish
well Felicia-1A. The Tmax values of the Norwegian samples
(sample 13–15, Tmax 427 C, 424 C and 421 C) indicate that
these samples are in an immature to early-mature state. The low
maturity is supported by the measured and calculated vitrinite
reflectance (0.38%Ro, 0.75%Rc and 0.61%Rc). The Rotliegend
mudstones from Felicia-1A have remarkably low Tmax values
(sample 16–18 in Table 2, Tmax 437 C, 433 C and 421 C),
considering that the samples came from a depth of 5143–
5242 mRKB. These samples may have reached depths of up to
6 km, before Neogene uplift of around 800 m (Japsen et al.
2002). The calculated ‘vitrinite reflectance’ (0.92%Rc and
1.06%Rc) indicates a lower maturity, corresponding with the
middle part of the oil window. The measured vitrinite reflectance gives a more reliable maturity estimate of 1.24%Ro (late
mature). The Kupferschiefer samples from the 25/10-2 well
have high TOC and HI values, typical of an oil-prone Type II
source rock (average TOC value 5.1 wt%, average HI value
461 mgHC g1 TOC). The mudstone samples from Felicia-1A
have an average TOC value of 1.7 wt% and an average HI value
of 247 mgHC g1 TOC, which means that these samples
are dominantly gas-prone. The early-mature Kupferschiefer
samples have a very high petroleum potential (average S2 value
23.5 mgHC g1 rock) while the late-mature Felicia-1A samples
having, at best, a fair remaining petroleum potential (average S2
value 4.16 mgHC g1 rock). Permian sediments in the NPB
with source-rock potential were most likely deposited in Middle
Permian times, when marine conditions were rapidly established in the NPB and SPB (Glennie & Buller 1983). The
Kupferschiefer is usually thin (1 m) in most known places.
However, from gamma-ray logs from Norwegian 2/10-1 S well,
a thickness of 9 m is inferred, and Kupferschiefer thicknesses
of up to 15 m and 20 m are reported from Norwegian North
Sea and UK North Sea wells (Glennie et al. 2003, fig. 8.21). A
20 m thick Kupferschiefer interval in central parts of the NPB
would certainly be able to charge structures in the potentially
24
J. H. Pedersen et al.
Fig. 9. Classification of petroleum and organic facies based on
molecular composition of pyrolysate (PY–GC; peak area percent;
UCM excluded; P–N–A, paraffinic–napthenic–aromatic; diagram
adopted from Horsfield et al. 1989) Numbers refer to sample
numbers in Table 1 (samples 7, 9, 14, 18, 28, 29, 44, 45, 46, 51, 55
and 56). Devonian and Carboniferous mudstones generate gas and
condensates and are related to a deltaic/terrigenous-dominated
facies. Sample 46 (a Carboniferous coal) may represent a transitional,
paralic environment. Samples 14, 18 (Permian) and 56 (U.
Cambrian–L. Ordovician) generate both gas and oil products during
pyrolysis and represent a marine facies. Samples 28 and 29 are
organic super-rich Carboniferous lacustrine shales, capable of generating high-wax oils.
overlying Rotliegend sandstones with commercial volumes of
black oil. Using the Rock-Eval data from the low-mature
sample 14 from Norwegian well 25/10-2 (Table 2), and
assuming a source-rock density of 2.2 g cm3 and a transformation ratio of 0.7, 1 km2 of 10 m thick Kupferschiefer
would generate at least 106 BBL black oil. However, the
existence of generously developed Kupferschiefer in the NPB
remains speculative. Glennie et al. (2003) reported that the
Kupferschiefer is thin or even absent on the northern flank of
the Ringkøbing–Fyn High. Indeed, the Kupferschiefer appears
to be missing in Danish well Felicia-1A. Instead, about 200 m
of Rotliegend mudstone interbedded with grey sandstones are
found underlying the Upper Permian evaporites (Corbett et al.
2001). The mudstones and sandstones are interpreted as marine
(Fig. 9, sample 18) and the sandstones are possibly turbiditic.
The Felicia-1A mudstones are presently gas-prone (Fig. 3,
samples 16, 17 and 18). The initial petroleum potential of these
mudstones was presumably higher than the limited potential of
today, but there are no observations of oil shows in the
Permian sandstones in the Felicia-1 well. This indicates that the
Permian mudstones in the Felicia-1A well locality never generated any oil, leaving the Kupferschiefer as the best Permian
source-rock candidate in the NPB.
OPEN PYROLYSIS OF PALAEOZOIC SOURCE
ROCKS
Open pyrolysis of kerogen concentrates made from samples 7,
9, 14, 18, 28, 29, 44, 45, 46, 51, 55 and 56 produced results
which correspond quite well with the observations made
from the Rock-Eval analysis described above. The amount of
n-alkanes separated into boiling point cuts (i.e. %C1–C5,
%C6–C14, %C15–C32) detected by GC–FID analysis of the
pyrolysis products is used here to classify the source rocks
(Horsfield et al. 1989). Bharati et al. (1992) demonstrated that
the Alum Shale has a tendency to generate mostly gas and only
a limited amount of aromatic-rich fluid petroleum under
Fig. 10. Pyrolysis-gas chromatograms (PY–GC–FID, open-system
pyrolysis) of two Alum Shale samples from Sweden. C6 etc. refers to
n-alkene/alkane doublets. (a) Närke (sample 55 in Table 1) – the
pyrolysate contains predominantly gas and some aromatic compounds. Note the near absence of alkene/alkane doublets. (b) Öland
(sample 56 in Table 1) – this sample generates the typical alkene/
alkane doublets up to C21 and may represent a richer, more distal
source facies of the Alum Shale than the ‘on-craton’ Närke sample.
Note that both samples have thermal maturity corresponding to the
uppermost part of the oil window.
pyrolysis, despite the oil-prone appearance of this organic-rich
source rock. This was also observed under open pyrolysis in
this study of a low-mature sample from Närke, onshore Sweden
(sample 55, TOC 16.9 wt%, HI 431 mgHC g1 TOC). The
main products generated were gas and aromatic compounds
such as benzene, toluene and 2,5-dimethylthiophene (Fig. 10a).
However, a low-mature sample of Alum Shale from Öland
(sample 56, TOC 11.1 wt%, HI 324 mgHC g1 TOC) yielded
alkene–alkane doublets up to C21 during the same analysis
(Fig. 10b), suggesting that regional differences in petroleum
potential may occur within the Alum Shale lithology. The
sample from Öland may be related to the distal Alum Shale of
the Baltic Basin, while the Närke sample may represent a more
proximal ‘on-craton’ environment, perhaps with more oxygenated palaeo-seafloor conditions. Sediments deposited west of
the Swedish mainland are more likely to have been deposited in
a basinal setting such as in the Baltic Basin, and may have had
better source-rock potential than the ‘on-craton’ sediments.
However, a larger number of representative Alum Shale
samples have to be analysed before any conclusions can be
drawn on this. The Devonian and Lower Carboniferous coals
and mudstones generate only gas under open pyrolysis, while
the Middle Permian Kupferschiefer samples generate oil and
gas products under the same conditions (Fig. 9). The Permian
mudstone from the Felicia-1A well generates mainly gas, but
also a minor oil fraction (Fig. 9, sample 18). Two samples of the
Palaeozoic source rocks, Permian Basin
Fig. 11. Classification of open pyrolysis products from a subset of
samples (7, 9, 14, 18, 28, 29, 44, 45, 46, 51, 55 and 56 in Table 1)
based on their content of an aromatic compound (toluene), an
aromatic sulphur compound (2,5-dimenthylthiophene) and two saturated compounds combined (n-C9+n-C25) (after Horsfield et al.
1989). Carboniferous deltaic mudstones and coals yield aromatic-rich
pyrolysates, while marine U. Cambrian–L. Ordovician and Permian
shales are ‘intermediates’. Note sample 7, a Carboniferous coal from
Norwegian well 2/11-9, whose pyrolysis product appears more
enriched in n-alkanes than the pyrolysates from the other coals in this
study. Pyrolysates from samples 28 and 29 (Carboniferous lacustrine
shales) are dominated by saturated hydrocarbons (n-alkanes).
Lower Carboniferous lacustrine shale from the Midland Valley
generate a high-wax oil, which reflects the excellent source-rock
properties of these lacustrine shales (Fig. 9, samples 28 and 29).
Open pyrolysis experiments also provide information on the
amounts of aromatic (toluene), saturated (n-C9+n-C25) and
sulphuric components (2,5-dimethylthiophene) in petroleum
generated from the investigated kerogen (Horsfield et al. 1989).
Pyrolysis products from organic lean Devonian and Lower
Carboniferous mudstones are seen here to contain high percentages of aromatic compounds, while the majority of
samples, both coals and shales, classify as intermediate, but
biased towards the aromatic corner of Figure 11. None of
the samples classify as sulphur-rich, according to Figure 11.
Pyrolysates from the two Midland Valley lacustrine Type I
samples grade as paraffinic, due to the high content of saturated
hydrocarbons in the pyrolysates.
POTENTIAL PALAEOZOIC PETROLEUM
SYSTEMS IN THE NORTHERN PERMIAN BASIN
Figure 12 shows two possible petroleum systems in the NPB,
with (A) marine Lower Palaeozoic pre-rift and (B) continental
Upper Palaeozoic syn-rift source rocks, post-rift Permian
reservoir and cap rocks, plus the Mesozoic overburden. The
organic-rich Lower Palaeozoic pre-rift shales in the NPB may
have realized much of their petroleum potential already in Late
Silurian–Early Devonian times, especially in areas close to the
CDF (Fig. 1). Much of the NPB area was in a general sense part
of the Silurian foredeep for the Caledonian mountain range.
Today the exposed Alum Shale in the Oslo Graben is postmature in terms of oil and gas generation (Buchardt et al. 1986),
and it certainly is post-mature in the central parts of NPB, in
particular close to the CDF and in the areas underlying the
Central Graben and Viking Graben. However, in areas of
the NPB east of the CDF, the subsidence associated with
Caledonian overthrusting and deposition of erosional products
25
Fig. 12. Conceptual Palaeozoic play model for the Northern
Permian Basin. The source rocks may be pre-rift Lower Palaeozoic
marine sediments (Source A) or syn-rift Upper Palaeozoic lacustrine
sediments (Source B). The reservoir rocks are thought to consist of
Lower Permian aeolian sediments, the seal of Upper Permian
evaporites. Mesozoic sediments make up most of the overburden in
the Northern Permian Basin today.
from the Caledonian mountain range may have been less
pronounced, preserving the petroleum potential of Lower
Palaeozoic shales in this area. Alum Shale from Danish wells
Terne-1 and Slagelse-1 are late-mature to post-mature, but it is
believed that this is related to tectonic subsidence in the
tectonically active Sorgenfrei-Tornquist fault zone, rather than
sensu stricto to deposition of large volumes of clastics derived
from the Caledonian mountain range. Based on this assumption, a ‘tectonically quiet window’ may have existed in the
eastern NPB in Silurian–Devonian times, with limited burial
and subsidence, allowing the Lower Palaeozoic sediments in
this window to mature and expel their petroleum products at
a later stage, perhaps as late as in the Late Carboniferous
(Fig. 13). Pyrobitumen found in fractures in Permian extrusive
lavas in the Oslo Graben (Dons 1956; N. Spjeldnæs, pers.
comm.) suggests that petroleum migration occurred in the Oslo
Graben even in Permian times. Alternatively, the pyrobitumen
may represent re-migration of oil from small Ordovician or
Silurian traps disturbed by tectonic activity in the Early Permian, or petroleum mobilized by hydrothermal systems related
to Permian volcanism. Upper Palaeozoic source-rock candidates in the NPB began to generate and expel hydrocarbons in
Lower Triassic times, in response to post-rift thermal subsidence of up to six kilometres (Fig. 13). Subsidence continued
until the Neogene, when a period of uplift began (600–1000 m
in the eastern NPB, Japsen et al. 2002). The uplift may have
caused re-migration of trapped petroleum, caused by tilting of
reservoirs or phase fractionation due to de-pressurization of the
fluids in the reservoirs. A Gussow/Silverman (Gussow 1954;
Silverman 1965) model of re-migration and sequential trap
filling may apply in this region as in the uplifted Hammerfest
Basin in the Norwegian Barents Sea, for example. It is
considered possible that the tight cap rocks formed by the
Upper Permian evaporites were probably able to retain petroleum in place during the Neogene uplift, and that petroleum
existing before the Neogene uplift is present still in traps below
the salt in the NPB, at least in the form of gas. Re-migrated
liquid petroleum may, furthermore, exist in updip traps. Longchained hydrocarbons are known to have survived in reservoirs
at surprisingly high temperatures (Price 1983), a fact most likely
related to the low degree of catalytic influence of oil which
exists in water-wetted reservoir pore space, and not in contact
with catalytic minerals such as in a source rock. In potential
cases with thin or partly eroded cap rocks, diffusion of methane
through the cap rock may prevent pressure-induced failing of
26
J. H. Pedersen et al.
Fig. 13. Tentative and general burial
curves for the NPB (Skagerrak area),
based on a basin modelling study
including the Felicia-1A well in the
Skagerrak. Palaeozoic source-rock
candidates are indicated by dotted lines.
Stippled lines designate the depth of
oil- and gas-generative zones, while the
arrow indicates relative hydrocarbon
(HC) generation. Peak oil generation
from Lower Palaeozoic source rocks is
believed to have occurred in the
Carboniferous, while peak oil
generation for Upper Palaeozoic source
rocks was reached in Early Triassic
time.
the cap rock, or underspill of oil due to expansion of gas in the
trap during uplift. This diffusion of methane allows oil to be
held back selectively in the trap (Karlsen et al. 2004, fig. 7).
CONCLUSIONS
This study of 58 Palaeozoic marine, deltaic and lacustrine
sediment samples collected from outcrops in Scotland and
from on- and offshore wells in Sweden, Norway, Denmark and
the UK indicates that Palaeozoic sediments with source-rock
qualities are likely to exist in the Northern Permian Basin. The
maturity of the studied samples vary from immature to late
mature with respect to the oil window (vitrinite reflectance
from 0.3%Ro to 1.3%Ro). Upper Cambrian-Lower Ordovician
marine shales from onshore Sweden are immature to low
mature, while samples of the same age from the offshore
Danish well Terne-1 appear to be high- to post-mature.
Devonian mudstones from wells in the Norwegian Embla Field
are in a mid-mature state, while Lower Carboniferous sediments from Norwegian and Danish wells have maturities
corresponding with the middle to late stages of oil generation.
The Norwegian and Danish samples seem to be more mature
than Lower Carboniferous sediments collected from UK wells,
which in general appear mid-mature. Lower Carbonifeorus
lacustrine shales from onshore Scotland (Midland Valley) are
immature. Permian Kupferschiefer collected from Norwegian
well 25/10-2 is in the earliest stage of oil-generating maturity,
while Permian mudstones from Danish Felicia-1A well have
high levels of maturity. In the sample set, kerogen Types I, II
and III were recognized, with Type III kerogen being the most
frequent. Cambrian/Ordovician samples of the marine Alum
Shale have a high petroleum potential and appear to be both
oil- and gas-prone (Type II). Devonian mudstones and Lower
Carboniferous mudstones and coals from Norwegian, Danish
and UK offshore wells were classified as gas-prone, Type III
source rocks, with limited or no remaining petroleum potential.
Two Lower Carboniferous shales from offshore UK wells
15/19-2 and 20/10-a3 have oil-prone source-rock characteristics and Lower Carboniferous lacustrine shales from onshore
Scotland (Midland Valley) were classified as super-rich, oilprone Type I source rocks. The Permian marine Kupferschiefer
from Norwegian offshore well 25/10-2 is an oil-prone Type II
source rock, with a high petroleum potential, while Permian
gas-prone mudstones from Danish Felicia-1A well have only a
fair remaining petroleum potential. Cambrian–Ordovician and
Permian marine shales generated both gas and oil products
when heated and artificially matured (open pyrolysis), while
Lower Carboniferous deltaic coals and mudstones generated
mainly gas. Lower Carboniferous lacustrine shales produced a
high-wax oil during open pyrolysis. The properties of the
analysed samples, together with several known occurrences of
oil stains and pyrobitumen in Palaeozoic rocks from southern
Sweden and the Norwegian Oslo Graben, suggest that petroleum generation, expulsion and migration have taken place in
Palaeozoic times in the Northern Permian Basin. In a conceptual Palaeozoic petroleum system in the eastern part of the
NPB (Skagerrak) it is proposed that Cambrian/Ordovician
marine oil-prone shales and/or lacustrine Devonian/
Carboniferous gas-prone mudstones and coals make up the
source rocks. Permian sandstones and evaporites may form the
reservoir and cap rocks. Potential Lower Palaeozoic source
rocks in the Skagerrak area may have reached peak oil generation during the Carboniferous, while any Upper Palaeozoic
source rocks became mature during rapid post-rift subsidence
in Early Triassic times.
The authors thank RWE Dea Norge for financial support and
permission to publish data. The efforts of NPD (Stavanger,
Norway), GEUS (Copenhagen, Denmark), DTI (Edinburgh,
Scotland) and SGU (Uppsala, Sweden) are gratefully appreciated for
supplying rock samples used in this study. Birger Dahl and the
University in Bergen (Norway) are thanked for providing essential
analytical help. The authors also acknowledge the assistance of the
archive office at RWE Dea Norge. Two anonymous reviewers are
thanked for helpful and constructive comments on an earlier
manuscript, which significantly improved this paper.
REFERENCES
Andersson, A., Dahlman, B., Gee, D.G. & Snäll, S. 1985. The Scandinavian
Alum Shales. Svergies Geologiska Undersökning, Avhandlingar og uppsatsar i A4,
56, 1–50.
Bharati, S., Larter, S. & Horsfield, B. 1992. The unusual source potential of
the Cambrian Alum Shale in Scandinavia as determined by quantitative
pyrolysis methods. In: Spencer, A.M. (ed.) Generation, accumulation and
production of Europe’s hydrocarbons II. Special Publication of the European
Association of Petroleum Geoscientists, 2. Springer-Verlag, Berlin
Heidelberg, 103–110.
Bharati, S., Patience, R.L., Larter, S., Standen, G. & Poplett, I.J.F. 1995.
Elucidation of the Alum Shale kerogen structure using a multi-disciplinary
approach. Organic Geochemistry, 23, 1043–1058.
Bharati, S. 1997. Mobile and immobile migrated hydrocarbons in the Embla Field,
North Sea. PhD thesis. Faculty of Applied Earth Science and Petroleum
Engineering, The Norwegian University of Science and Technology,
Trondheim, Norway.
Palaeozoic source rocks, Permian Basin
Bjørlykke, K. 1974. Depositional history and geochemical composition of
Lower Palaeozoic epicontinental sediments from the Oslo region. Norges
geologiske undersøkelse, 305, 81.
Brangulis, A.P., Kanev, S.V., Margulis, L.S. & Pomerantseva, R.A. 1993.
Geology and hydrocarbon prospects of the Paleozoic in the baltic region.
In: Parker, J.R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th
Conference. Geological Society, London, 651–656.
Brekke, H., Sjulstad, H.I., Magnus, C. & Williams, R.W. 2001. Sedimentary
environments offshore Norway – an overview. In: Martinsen, O.J. &
Dreyer, T. (eds) Sedimentary Environments Offshore Norway – Palaeozoic to
Recent. Norwegian Petroleum Society Special Publication, 10. Elsevier,
Amsterdam, 7–37.
Bruce, D.R.S. & Stemmerik, L. 2003. Carboniferous. In: Evans, D., Graham,
C., Armour, A. & Bathurst, P. (Compilers) (eds) The Millennium Atlas:
petroleum geology of the central and northern North Sea. Geological Society,
London, 83–89.
Buchardt, B. & Hansen, M. 2000. Orthoceratit i olie – en specialitet fra
Ordovicium ved Kinnekulle. Varv, 3, 3–7.
Buchardt, B., Clausen, J. & Thomsen, E. 1986. Carbon isotope composition
of Lower Paleozoic kerogen: Effects of maturation. Organic Geochemistry, 10,
124–134.
Bugge, T., Ringas, J.E., Leith, D.A., Mangerud, G., Weiss, H.M. & Leith, T.L.
2002. Upper Permian as a new play model on the mid-Norwegian
continental shelf: Investigated by shallow stratigraphic drilling. American
Association of Petroleum Geologists Bulletin, 86, 107–127.
Christiansen, F.G., Larsen, H.C., Marcussen, C., Piasecki, S. & Stemmerik, L.
1993. Late Palaeozoic plays in East Greenland. In: Parker, J.R. (ed.)
Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 657–666.
Chung, H.M., Wingert, W.S. & Claypool, G.E. 1992. Geochemistry of oils
in the Northern Viking Graben. In: Halbouty, M.T. (ed.) Giant Oil and
Gas Fields of the Decade 1978–1988. American Association of Petroleum
Geologists Memoir, 54, 277–296.
Corbett, K. P., Leu, W., Edman, J. D. & Jepsen, A. M. 2001. Rotliegend in the
northern Permian Basin, Danish North Sea: Identification of a new source
rock oil system. Abstract presented at the AAPG Annual Meeting: An
Energy Odyssey, Denver, Colorado, 3–6 June 2001.
Cornford, C. 1998. Source rocks and hydrocarbons of the North Sea. In:
Glennie, K.W. (ed.) Petroleum Geology of the North Sea (4th edn). Blackwell
Science Ltd, Oxford, 376–462.
Coward, M.P. 1995. Structural and tectonic setting of the Permo-Triassic
basins of northwest Europe. In: Boldy, S.A.R. (ed.) Permian and Triassic
Rifting in Northwest Europe. Geological Society, London, Special
Publications, 91, 7–39.
Dahlgren, S., Hanesand, T., Mills, N., Patience, R., Brekke, T. &
Sinding-Larsen, R. 1998. Norwegian Geochemical Standard samples: North Sea Oil
–1 (NGS NSO-1). Norwegian Geochemical Standards Newsletter, 3. The
Norwegian Petroleum Directorate, Stavanger, Norway.
Dons, J.A. 1956. Coal blend and uraniferous hydrocarbon in Norway. Norsk
Geologisk Tidsskrift, 36, 250–266.
Dons, J.A. 1975. Oljediabas fra Dyvika. Esso Perspektiv, 4, 16–17.
Duncan, W.I. & Buxton, N.W.K. 1995. New evidence for evaporitic Middle
Devonian lacustrine sediments with hydrocarbon source potential on the
East Shetland Platform, North Sea. Journal of the Geological Society, London,
152, 251–258.
Eakin, P.A. 1989. The origin and properties of uranium–niobium–tantalum
mineralised hydrocarbons at Narestø, Arendal, southern Norway. Norsk
Geologisk Tidsskrift, 69, 29–37.
Field, J.D. 1985. Organic geochemistry in exploration of the northern North
Sea. In: Thomas, B.M., Doré, A.G., Eggen, S.S., Home, P.C. & Larsen,
R.M. (eds) Petroleum Geochemistry in Exploration of the Norwegian Shelf. Graham
& Trotman, London, 39–57.
Glennie, K.W. & Buller, A.T. 1983. The Permian Weissliegend of NW
Europe: the partial deformation of aeolian dune sands caused by the
Zechstein transgression. Sedimentary Geology, 35, 43–81.
Glennie, K.W. 1997. Recent advances in understanding the Southern North
Sea Basin: a summary. In: Ziegler, K., Turner, P. & Daines, S.R. (eds)
Petroleum Geology of the Southern North Sea: future potential. Geological Society,
London, Special Publications, 123, 17–29.
Glennie, K.W., Higham, J. & Stemmerik, L. 2003. Permian. In: Evans, D.,
Graham, C., Armour, A. & Bathurst, P. (Compilers) (eds) The Millennium
Atlas: petroleum geology of the central and northern North Sea. Geological Society,
London, 91–103.
Gussow, W.C. 1954. Differential entrapment of oil and gas, a fundamental
principle. American Association of Petroleum Geologists Bulletin, 38, 816–853.
Gérard, J., Wheatley, T.J., Ritchie, J.S., Sullivan, M. & Bassett, M.G. 1993.
Permo-Carboniferous and older plays, their historical development and
future potential. In: Parker, J.R. (ed.) Petroleum Geology of Northwest Europe:
Proceedings of the 4th Conference. Geological Society, London, 641–650.
Hallett, D., Durant, G.P. & Farrow, G.E. 1985. Oil exploration and
production in Scotland. Scottish Journal of Geology, 21, 547–570.
27
Hanken, N.M. & Owen, A.W. 1982. The Upper Ordovician (Ashgill) of
Ringerike. In: Bruton, D.L. & Williams, S.H. (eds) 4th International Symposium
on the Ordovician System, Field Excursion Guide. Palaeontological contributions
from the University of Oslo, 279, 122–131.
Horsfield, B., Disko, U. & Leistner, F. 1989. The microscale simulation of
maturation: Outline of a new technique and its potential applications.
Geologische Rundschau, 78, 631–674.
Husebye, E.S., Ro, H.E., Kinck, J.J. & Larsson, F.R. 1988. Tectonic studies in
the Skagerrak province: the ‘Mobil Search’ cruise. Norges Geologisk Undersøkelse, Special Publication, 3, 14–20.
Japsen, P., Bidstrup, T. & Lidmar-Bergström, K. 2002. Neogene uplift and
erosion of southern Scandinavia induced by the rise of the South Swedish
Dome. In: Doré, A.G., Cartwright, J.A., Stoker, M.S., Turner, J.P. & White,
N. (eds) Exhumation of the North Atlantic Margin: Timing, Mechanisms and
Implications for Petroleum Exploration. Geological Society, London, Special
Publications, 196, 183–207.
Karlsen, D.A., Nedkvitne, T., Larter, S.R. & Bjørlykke, K. 1993. Hydrocarbon
composition of authigenic inclusions: Application to elucidation of petroleum reservoir filling history. Geochimica et Cosmochimica Acta, 57,
3641–3659.
Karlsen, D.A., Nyland, B., Flood, B., Ohm, S.E., Brekke, T., Olsen, S. &
Backer-Owe, K. 1995. Petroleum geochemistry of the Haltenbanken
continental shelf. In: Cubitt, J.M. & England, W.A. (eds) The Geochemistry of
Reservoirs. Geological Society, London, Special Publications, 86, 203–256.
Karlsen, D.A., Skeie, J.E., Backer-Owe, K. et al. 2004. Petroleum migration,
faults and overpressure. Part II. Case history: The Haltenbanken Petroleum Province, offshore Norway. In: Cubitt, J.M., England, W.A. & Larter,
S. (eds) Understanding Petroleum Reservoirs: towards an Integrated Reservoir and
Geochemical Approach. Geological Society, London, Special Publications, 237,
305–372.
Krawczyk, C.M., Eilts, F., Lassen, A. & Thybo, H. 2002. Seismic evidence of
Caledonian deformed crust and uppermost mantle structures in the
northern part of the Trans-European suture zone, SW Baltic Sea. In:
Thybo, H., Pharaoh, T. & Guterch, A. (eds) Geophysical investigations of
the Trans-European suture zone II. Tectonophysics, 360, 215–244.
Kvalheim, O.M., Christy, A.A., Telnæs, N. & Bjørseth, A. 1987. Maturity
determination of organic matter in coals using the methylphenanthrene
distribution. Geochimica et Cosmochimica Acta, 51, 1883–1888.
Marshall, J.E.A. & Hewett, A.J. 2003. Devonian. In: Evans, D., Graham, C.,
Armour, A. & Bathurst, P. (Compilers) (eds) The Millennium Atlas: petroleum
geology of the central and northern North Sea. Geological Society, London, 65–81.
Maynard, J.R., Hofmann, W., Dunay, R.E., Bentham, P.N., Dean, K.P. &
Watson, I. 1997. The Carboniferous of western Europe: the development
of a petroleum system. Petroleum Geoscience, 3, 97–115.
Munz, I.A., Yardley, B.W.D., Banks, D.A. & Wayne, D. 1993. Hydrocarbon
and brine inclusions in quartz veins from basement rocks of south
Norway; evidence for deep penetration of sedimentary fluids? Seventh
meeting of the European Union of Geosciences; abstract supplement.
Terra Abstracts, 5, 464.
Möller, N.K. 1987. A Lower Silurian transgressive carbonate succession in
Ringerike (Oslo region, Norway). Sedimentary Geology, 51, 215–247.
Møller, L.N. & Friis, H. 1999. Petrographic evidence for hydrocarbon
migration in Lower Cambrian sandstones, Bornholm, Denmark. Bulletin of
the Geological Society of Denmark, 45, 117–127.
Northam, M.A. 1985. Correlation of Northern North Sea oils: the different
facies of their Jurassic source. In: Thomas, B.M., Doré, A.G., Eggen, S.S.,
Home, P.C. & Larsen, R.M. (eds) Petroleum Geochemistry in Exploration of the
Norwegian shelf. Graham & Trotman, London, 93–99.
Olaussen, S., Larsen, B.T. & Steel, R. 1994. The Upper Carboniferous–
Permian Oslo rift; Basin fill in relation to tectonic development. Canadian
Society of Petroleum Geologists Memoirs, 17, 175–197.
Olaussen, S. 1981. Marine incursion in Upper Palaeozoic sedimentary rocks
of the Oslo Region, Southern Norway. Geological Magazine, 118 (3),
281–288.
Pedersen, J.H. 2002. Atypical oils and condensates of the Norwegian Continental Shelf
– an Organic Geochemical Study. Cand. Scient. thesis in Geology. University of
Oslo, Norway.
Peters, K.E., Moldowan, J.M., Driscole, A.R. & Demaison, G.J. 1989. Origin
of Beatrice Oil by Co-Sourcing from Devonian and Middle Jurassic
Source Rocks, Inner Moray Firth, United Kingdom. American Association of
Petroleum Geologists Bulletin, 73, 454–471.
Price, L.C. 1983. Geologic time as a parameter in organic metamorphism
and vitrinite reflectance as an absolute paleogeothermometer. Journal of
Petroleum Geology, 6, 5–38.
Radke, M. 1988. Application of aromatic compounds as maturity indicators in
source rocks and crude oils. Marine and Petroleum Geology, 5, 224–236.
Rise, L., Sættem, J., Fanavoll, S., Thorsnes, T., Ottesen, D. & Bøe, R. 1999.
Sea-bed pockmarks related to fluid migration from Mesozoic bedrock
strata in the Skagerrak offshore Norway. Marine and Petroleum Geology, 16,
619–631.
28
J. H. Pedersen et al.
Ro, H.E., Stuevold, L.M., Faleide, J.I. & Myhre, A.M. 1990. Skagerrak
Graben – the offshore continuation of the Oslo Graben. Tectonophysics, 178,
1–10.
Schleicher, M., Köster, J., Kulke, H. & Weil, W. 1998. Reservoir and source
rock characterization of the Early Palaeozoic interval in the Peribaltic
Syneclise, Northern Poland. Journal of Petroleum Geology, 21, 33–56.
Silverman, S.R. 1965. Migration and segregation of oil and gas. In: Young, A.
& Galley, J.E. (eds) Fluids in Subsurface Environments. American Association
of Petroleum Geologists Memoir, 4, 53–65.
Sivhed, U., Erlström, M., Bojesen-Koefoed, J.A. & Löfgren, A. 2004. Upper
Ordovician carbonate mounds on Gotland, Central Baltic Sea: distribution
composition and reservoir characteristics. Journal of Petroleum Geology, 27,
115–140.
Smelror, M., Cocks, L.R.M., Mørk, A., Neumann, B.E.E. & Nakrem, H.A.
1997. Upper Ordovician–Lower Silurian strata and biota from offshore
South Norway. Norsk Geologisk Tidsskrift, 77, 251–268.
Stemmerik, L., Christiansen, F.G. & Piasecki, S. 1990. Carboniferous
lacustrine shale in East Greenland – additional source rock in northern
North Atlantic. In: Katz, B.J. (ed.) Lacustrine basin exploration: case studies and
modern analogs. American Association of Petroleum Geologists Memoir, 50,
277–286.
Surlyk, F., Hurst, J.M., Piasecki, S., Rolle, F., Scholle, P.A., Stemmerik, L. &
Thomsen, E. 1986. The Permian base of the western margin of the
Greenland Sea – A future exploration target. In: Halbouty, M.T. (ed.) Future
petroleum provinces of the world. American Association of Petroleum Geologists
Memoir, 40, 629–659.
Sørensen, S. & Martinsen, B.B. 1987. A paleogeographic reconstruction of
the Rotliegends deposits in the Northeastern Permian Basin. In: Brooks, J.
& Glennie, K. (eds) Petroleum Geology of North West Europe. Graham &
Trotman, London, 497–508.
Sørensen, S. & Tangen, O.H. 1995. Exploration trends in marginal basins
from Skagerrak to Stord. In: Hanslien, S. (ed.) Petroleum Exploration and
Exploitation in Norway. Norwegian Petroleum Society Special Publication, 4.
Elsevier, Amsterdam, 97–114.
Thickpenny, A. & Leggett, J.K. 1987. Stratigraphic distribution and palaeooceanographic significance of European early Palaeozoic organic-rich
sediments. In: Brooks, J. & Fleet, A.J. (eds) Marine Petroleum Source Rocks.
Geological Society, London, Special Publications, 26, 231–247.
Vlierboom, F.W., Collini, B. & Zumberge, J.E. 1986. The occurrence of
petroleum in sedimentary rocks of the meteor impact crater at Lake Siljan,
Sweden. Organic Geochemistry, 10, 153–161.
Zdanaviciute, O. & Lazauskiene, J. 2004. Hydrocarbon migration and
entrapment in the Baltic Syneclise. Organic Geochemistry, 35, 517–527.
Received 28 April 2005; revised typescript accepted 19 October 2005.