Source rock quality and hydrocarbon migration pathways within the ...
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<strong>Source</strong> <strong>rock</strong> <strong>quality</strong> <strong>and</strong><br />
<strong>hydrocarbon</strong> <strong>migration</strong><br />
<strong>pathways</strong> <strong>within</strong> <strong>the</strong> greater<br />
Utsira High area, Viking<br />
Graben, Norwegian North Sea<br />
Gary H. Isaksen <strong>and</strong> K. Haakan I. Ledje<br />
ABSTRACT<br />
The greater Utsira High area is located <strong>within</strong> <strong>the</strong> sou<strong>the</strong>rn part of<br />
quadrants 24 <strong>and</strong> 25 <strong>and</strong> <strong>the</strong> nor<strong>the</strong>rn part of quadrants 15 <strong>and</strong> 16<br />
in <strong>the</strong> Norwegian North Sea. In this part of <strong>the</strong> Viking Graben <strong>the</strong><br />
main exploration play is <strong>the</strong> submarine fan s<strong>and</strong>s of Paleocene <strong>and</strong><br />
Eocene age. These s<strong>and</strong>s (Balder, Heimdal, <strong>and</strong> Ty formations)<br />
pinch out to <strong>the</strong> east in blocks 25/8 (Jotun field) <strong>and</strong> 25/11 (Balder<br />
<strong>and</strong> Grane fields) <strong>and</strong> along <strong>the</strong> western margin of <strong>the</strong> Utsira High<br />
to form a combination of stratigraphic <strong>and</strong> structural traps. Marine<br />
s<strong>and</strong>s of Middle <strong>and</strong> Late Jurassic age, typically present in rotated<br />
fault blocks, constitute ano<strong>the</strong>r important play.<br />
Geochemical analyses show that <strong>the</strong> Upper Jurassic Draupne<br />
Formation has a good potential for oil generation along <strong>the</strong> entire<br />
western margin <strong>and</strong> nor<strong>the</strong>rn nose of <strong>the</strong> Utsira High. Both upper<br />
<strong>and</strong> lower Draupne source intervals along <strong>the</strong> western graben margin,<br />
however, contain more terrigenous kerogen than in <strong>the</strong> eastern<br />
part of <strong>the</strong> graben. Such change in organic facies <strong>within</strong> <strong>the</strong><br />
Draupne source interval naturally results in a higher proportion of<br />
gas generation <strong>and</strong> <strong>the</strong> possibility for generating a more waxy crude<br />
than typically encountered in <strong>the</strong> Viking Graben. Detection <strong>and</strong><br />
characterization of oil <strong>and</strong> gas shows <strong>within</strong> <strong>the</strong> Tertiary section<br />
permit mapping of <strong>migration</strong> entry points from <strong>the</strong> Jurassic source<br />
<strong>rock</strong>s <strong>and</strong> help delineate secondary <strong>and</strong> tertiary <strong>migration</strong> <strong>pathways</strong><br />
<strong>within</strong> <strong>the</strong> Paleocene–Eocene play.<br />
INTRODUCTION<br />
In this article, we examine <strong>the</strong> <strong>hydrocarbon</strong> systems <strong>within</strong> <strong>the</strong><br />
sou<strong>the</strong>rn part of quadrants 24 <strong>and</strong> 25 <strong>and</strong> <strong>the</strong> nor<strong>the</strong>rn part of quadrants<br />
15 <strong>and</strong> 16 in <strong>the</strong> Norwegian North Sea (Figure 1). We have<br />
Copyright 2001. The American Association of Petroleum Geologists. All rights reserved.<br />
Manuscript received January 26,1999; revised manuscript received June 19,2000; final acceptance<br />
August 31,2000.<br />
AAPG Bulletin, v. 85, no. 5 (May 2001), pp. 861–883 861<br />
AUTHORS<br />
Gary H. Isaksen ExxonMobil Upstream<br />
Research Company, 3120 Buffalo Speedway,<br />
Houston, Texas, 77252;<br />
ghisaks@upstream.xomcorp.com<br />
Gary H. Isaksen is research supervisor for<br />
petroleum geochemistry <strong>and</strong> source <strong>rock</strong> modeling<br />
with ExxonMobil Upstream Research Company.<br />
Isaksen graduated from <strong>the</strong> University of Bergen,<br />
Norway, with an M.S. degree <strong>and</strong> a Ph.D. in<br />
petroleum geochemistry <strong>and</strong> petroleum geology.<br />
Since joining Exxon in 1985, <strong>the</strong> major <strong>the</strong>mes of<br />
his work have been integration of geology <strong>and</strong><br />
organic geochemistry, molecular geochemistry<br />
research, risking of play elements, <strong>and</strong> seep <strong>and</strong><br />
production geochemistry. During 1993–1995 he<br />
worked established <strong>and</strong> frontier plays <strong>within</strong> United<br />
Kingdom <strong>and</strong> Norwegian territories, <strong>and</strong> during<br />
1997–1999 he worked on regional- <strong>and</strong> prospectscale<br />
oil <strong>and</strong> gas assessments <strong>within</strong> Azerbaijan,<br />
Turkmenistan, Uzbekistan, Kazakhstan, <strong>and</strong> Russia,<br />
as well as production geochemistry <strong>within</strong> fields of<br />
<strong>the</strong> South Caspian basin. His current geoscience<br />
focus is on applied research <strong>and</strong> <strong>the</strong> transfer of<br />
geochemical technologies <strong>within</strong> ExxonMobil’s<br />
exploration, development, <strong>and</strong> production<br />
functions.<br />
K. Haakan I. Ledje Esso Norge AS,<br />
N-4033 Forus, Norway;<br />
haakan.karl.ledje@exxonmobil.com<br />
Haakan Ledje is a senior geologist with Esso Norge<br />
in Stavanger, Norway. He received his B.Sc. degree<br />
in sedimentology in 1983 from <strong>the</strong> University of<br />
Lund, Sweden, <strong>and</strong> M.Sc. degree in sedimentology<br />
<strong>and</strong> tectonics in 1985 from <strong>the</strong> University of<br />
California, Los Angeles. He also received an MBA<br />
degree in 1993 from <strong>the</strong> Norwegian School of<br />
Management, Oslo, Norway. He has broad<br />
experience with <strong>hydrocarbon</strong> systems studies on<br />
<strong>the</strong> Norwegian Continental Shelf. During 1998–<br />
1999 he was <strong>the</strong> project leader for ExxonMobil’s<br />
play <strong>and</strong> prospect evaluation offshore mid-Norway.<br />
Ledje has special expertise in source <strong>rock</strong> <strong>quality</strong><br />
assessment <strong>and</strong> <strong>hydrocarbon</strong> <strong>migration</strong> analyses.<br />
ACKNOWLEDGEMENTS<br />
This article is published by permission of Esso<br />
Norge a.s. <strong>and</strong> Enterprise Oil Norwegian a.s. We<br />
also wish to acknowledge Robertson Research International<br />
Ltd., GeoLab Nor a.s., Saga Petroleum<br />
a.s., <strong>and</strong> Conoco Norway Inc. for permission to use<br />
some of <strong>the</strong>ir geochemical data in this article.
Figure 1. Location map of<br />
study area. Samples were obtained<br />
from Norwegian quadrants<br />
24 <strong>and</strong> 25 <strong>and</strong> <strong>the</strong> nor<strong>the</strong>rn<br />
part of quadrants 15<br />
<strong>and</strong> 16.<br />
focused our attention on <strong>the</strong> prospectivity in <strong>the</strong> Utsira<br />
High area, which is a prolific <strong>hydrocarbon</strong> province,<br />
with discovered, producible reserves estimated at 1.0–<br />
1.5 billion st<strong>and</strong>ard bbl. The main group of fields<br />
<strong>within</strong> this area includes Balder, Grane, Jotun, <strong>and</strong><br />
Heimdal. This area continues to be prospective; Esso<br />
Norge in 1997 alone made a series of successful smaller<br />
discoveries including 25/8–10, 25/8–11, <strong>and</strong> 25/10–8.<br />
Most oil <strong>and</strong> gas discoveries to date have been <strong>within</strong><br />
<strong>the</strong> Eocene <strong>and</strong> Paleocene submarine-fan s<strong>and</strong>s (Figure<br />
2). Recent exploration has tested <strong>the</strong> prospectivity of<br />
<strong>the</strong> Jurassic play along <strong>the</strong> eastern margin of <strong>the</strong> graben.<br />
An underst<strong>and</strong>ing of <strong>the</strong> source <strong>rock</strong><strong>quality</strong><br />
<strong>within</strong> <strong>the</strong> drainage area, <strong>hydrocarbon</strong> <strong>migration</strong> <strong>pathways</strong>,<br />
<strong>and</strong> <strong>the</strong> location of <strong>migration</strong> entry points into<br />
Tertiary reservoirs is critical to future exploration<br />
<strong>within</strong> this play. The primary source <strong>rock</strong>s in <strong>the</strong> area<br />
are organic-rich shales of <strong>the</strong> Kimmeridgian to Vol-<br />
862 Utsira High Area (Norwegian North Sea)<br />
gian–Ryazanian Draupne Formation. The Oxfordian<br />
Hea<strong>the</strong>r Formation forms a secondary source. Regional<br />
studies of Draupne (Kimmeridge Clay) <strong>and</strong> Hea<strong>the</strong>r<br />
formations source <strong>rock</strong>facies <strong>and</strong> <strong>hydrocarbon</strong> distributions<br />
in this part of <strong>the</strong> Viking Graben have been<br />
carried out by several researchers. Early overviews include<br />
those by Skarpnes et al. (1981), Barnard <strong>and</strong><br />
Cooper (1981), <strong>and</strong> Barnard et al. (1981), who reported<br />
on source <strong>rock</strong><strong>quality</strong> variations from bulkkerogen<br />
<strong>and</strong> pyrolysis data throughout platform <strong>and</strong> graben<br />
areas. Goff (1983), Cornford (1984), Field (1985),<br />
Cooper <strong>and</strong> Barnard (1984), Thomas et al. (1985), <strong>and</strong><br />
Harris <strong>and</strong> Fowler (1987) followed with more detailed<br />
studies as more data became available. For example,<br />
Thomas et al. (1985) carried out geochemical characterization<br />
of cores taken at a variety of structural positions<br />
in <strong>the</strong> basin <strong>and</strong> at different <strong>the</strong>rmal maturity<br />
levels. A common observation from <strong>the</strong> regional stud-
Figure 2. Lithostratigraphy of <strong>the</strong> greater Utsira High area.<br />
Significant discoveries have been made in <strong>the</strong> Paleocene Balder,<br />
Heimdal, <strong>and</strong> Ty formations <strong>and</strong> in <strong>the</strong> Jurassic Draupne <strong>and</strong><br />
Hugin formations. The Upper Jurassic Draupne <strong>and</strong> Hea<strong>the</strong>r formations<br />
are <strong>the</strong> main source <strong>rock</strong>s for oil <strong>and</strong> gas.<br />
ies published during <strong>the</strong> early to mid-1980s was that<br />
<strong>the</strong> Draupne Formation indeed showed organic facies<br />
variations but that such intra-Draupne variability (Huc<br />
et al., 1985) was only a secondary influence on <strong>the</strong><br />
distribution of oil-prone <strong>and</strong> gas-prone areas in <strong>the</strong><br />
North Sea. <strong>Source</strong> <strong>rock</strong><strong>the</strong>rmal maturity was viewed<br />
as <strong>the</strong> primary control on oil vs. gas.<br />
Cooper et al. (1995) provided a more detailed picture<br />
of biomarker <strong>and</strong> stable carbon isotopic compositions<br />
for <strong>the</strong> Kimmeridge Clay, pointing out that <strong>the</strong><br />
organic enrichment was mostly a function of dysaerobic<br />
to anaerobic development <strong>within</strong> submarine rifts<br />
<strong>and</strong> associated sills. Controls on organic-facies development<br />
of <strong>the</strong> Draupne Formation were modeled by<br />
Miller (1990), using paleoenvironmental, geochemical,<br />
<strong>and</strong> petrophysical data sets, whereas Ungerer et al.<br />
(1985) modeled oil <strong>and</strong> gas yields <strong>and</strong> <strong>migration</strong> <strong>pathways</strong><br />
in <strong>the</strong> Frigg area.<br />
Coastal plain <strong>and</strong> deltaic units in <strong>the</strong> Middle Jurassic<br />
Brent <strong>and</strong> Sleipner/Hugin formations are prevalent<br />
in <strong>the</strong> North Viking Graben <strong>and</strong> South Viking<br />
Graben, respectively. Such geographically extensive<br />
coaly <strong>rock</strong>s, however, are not thought to be present in<br />
<strong>the</strong> greater Utsira High area.<br />
The organic-rich Permian Kupferschiefer Formation<br />
was also deposited this far north in <strong>the</strong> Viking Graben<br />
(e.g., well 25/10–2), but is generally too thin to<br />
yield significant volumes of oil <strong>and</strong> gas. Petroleum geochemical<br />
studies of <strong>the</strong> Kupferschiefer Formation (aka<br />
Marl Slate) were reported by Dungworth (1972) <strong>and</strong><br />
Gibbons (1978), who both recognized its source <strong>rock</strong><br />
potential.<br />
Study Objectives<br />
The main objectives of this study were to (1) characterize<br />
<strong>and</strong> map <strong>the</strong> regional source <strong>rock</strong><strong>quality</strong>,<br />
(2) measure, <strong>and</strong> predict beyond points of control, oil<br />
vs. gas yields from regionally extensive source <strong>rock</strong>s,<br />
<strong>and</strong> (3) correlate <strong>the</strong> molecular signatures from shows<br />
<strong>and</strong> stains to assess <strong>the</strong>ir likely origin <strong>and</strong> secondary<strong>migration</strong><br />
<strong>and</strong> tertiary-<strong>migration</strong> <strong>pathways</strong>.<br />
GEOLOGICAL SETTING<br />
The Utsira High is a large basement high, flanked by<br />
<strong>the</strong> Viking Graben to <strong>the</strong> west <strong>and</strong> <strong>the</strong> Stord Basin to<br />
<strong>the</strong> east. The present structural configuration was inherited<br />
from extensional tectonism that occurred in<br />
<strong>the</strong> late Paleozoic <strong>and</strong> Mesozoic. At <strong>the</strong> end of <strong>the</strong><br />
Isaksen <strong>and</strong>Ledje 863
Rotliegende, two large intracratonic basins occupied an<br />
area stretching from <strong>the</strong> Republic of Pol<strong>and</strong> <strong>and</strong> nor<strong>the</strong>rn<br />
Germany to <strong>the</strong> middle parts of <strong>the</strong> Viking Graben.<br />
The so-called nor<strong>the</strong>rn Permian Basin is thought to<br />
have been invaded by marine waters from <strong>the</strong><br />
Norwegian–Greenl<strong>and</strong> Sea in <strong>the</strong> north, thus forming<br />
<strong>the</strong> Zechstein Sea. The relatively shallow water depth<br />
of large parts of <strong>the</strong> area (less than 250 m according to<br />
Smith [1980] <strong>and</strong> Gibbons [1987]), combined with an<br />
arid climate, led to elevated salinity levels that could<br />
host only a few adaptable species (Paul, 1986a) <strong>and</strong> a<br />
chemically stratified water column (Hirst <strong>and</strong> Dunham,<br />
1963). These resultant organic-rich shales constitute<br />
<strong>the</strong> Kupferschiefer Formation. During <strong>the</strong> latest<br />
Permian <strong>the</strong> global sea level was at a significant low<br />
due to cooling <strong>and</strong> contraction of <strong>the</strong> oceanic lithosphere<br />
(Ziegler, 1988). Over much of <strong>the</strong> nor<strong>the</strong>rn<br />
Permian Basin, <strong>the</strong> Kupferschiefer Formation is recorded<br />
as a thin (0.5 m) blackshale (Oszczepalski,<br />
1986; Paul, 1986b;). In well 25/10–2 in <strong>the</strong> Norwegian<br />
North Sea it occurs as a 5 m section <strong>and</strong> is readily identified<br />
by <strong>the</strong> gamma-ray logging tool because of its high<br />
content of radioactive elements.<br />
The Triassic was a period of accelerated crustal extension<br />
with <strong>the</strong> formation of large, rotated fault<br />
blocks. Rocks of this age <strong>within</strong> <strong>the</strong> Viking Graben are<br />
typically nonmarine clastics with development of red<br />
beds in an arid to semiarid climate. Subsequent rifting<br />
<strong>and</strong> subsidence during <strong>the</strong> Jurassic Kimmerian tectonic<br />
phases resulted in <strong>the</strong> present structure of <strong>the</strong> graben.<br />
The largest pulse of rifting associated with <strong>the</strong> most<br />
rapid phase of extension occurred during <strong>the</strong> Middle<br />
Jurassic (mid-Kimmerian phase) (Curtin <strong>and</strong> Ballestad,<br />
1986). Erosion of <strong>the</strong> uplifted rift flanks led to deposition<br />
of nonmarine s<strong>and</strong>stones on <strong>the</strong> western flankof<br />
<strong>the</strong> Utsira High. These Middle Jurassic s<strong>and</strong>stones are<br />
important reservoir targets.<br />
Establishment of <strong>the</strong> rift system in <strong>the</strong> Late Jurassic<br />
coupled with eustatic sea level rise led to widespread<br />
transgression <strong>and</strong> deep-water sedimentation<br />
(Ziegler, 1988). Under <strong>the</strong>se conditions <strong>the</strong> Kimmeridgian<br />
to Ryazanian organic-rich shales of <strong>the</strong><br />
Draupne Formation were deposited. These shales are<br />
<strong>the</strong> primary source <strong>rock</strong>s in <strong>the</strong> Viking Graben. Concurrently,<br />
<strong>the</strong> western margin of <strong>the</strong> South Viking Graben<br />
experienced extensive <strong>and</strong> rapid syntectonic sedimentation<br />
from <strong>the</strong> graben scarps resulting in<br />
mass-flow sediments that thin abruptly eastward <strong>and</strong><br />
interfinger with <strong>the</strong> organic-rich shales (Figure 3). During<br />
<strong>the</strong> earliest Cretaceous a new rifting phase (late<br />
Kimmerian phase) affected <strong>the</strong> area. This phase reac-<br />
864 Utsira High Area (Norwegian North Sea)<br />
tivated existing faults <strong>and</strong> created fur<strong>the</strong>r fault-block<br />
relief. This late Kimmerian rift phase was mostly concentrated<br />
along <strong>the</strong> major north-south fault trend to<br />
<strong>the</strong> west, resulting in an asymmetric Upper Jurassic–<br />
earliest Cretaceous basin. More uniform subsidence<br />
occurred in Cretaceous <strong>and</strong> Tertiary times (Curtin <strong>and</strong><br />
Ballestad, 1986)<br />
The dominant Tertiary event was <strong>the</strong> deposition<br />
of Paleocene <strong>and</strong> lower Eocene deep-marine s<strong>and</strong>stones.<br />
These s<strong>and</strong>s were shed from <strong>the</strong> uplifted Shetl<strong>and</strong><br />
Platform to <strong>the</strong> west <strong>and</strong> deposited into <strong>the</strong> basin<br />
by eastward-prograding deltaic complexes <strong>and</strong> turbidity<br />
currents during low st<strong>and</strong>s of sea level. The Paleocene<br />
<strong>and</strong> Eocene s<strong>and</strong>s are <strong>the</strong> primary reservoir targets<br />
in <strong>the</strong> Utsira High area.<br />
SAMPLES ANALYZED<br />
Samples of organically enriched Jurassic shales were<br />
collected from wells in <strong>the</strong> Norwegian quadrants 15,<br />
16, 24, <strong>and</strong> 25 (Table 1). The study is comprehensive<br />
in that 246 samples were analyzed for organic richness<br />
by total organic carbon (TOC), 239 samples were analyzed<br />
for source <strong>quality</strong> <strong>and</strong> <strong>the</strong>rmal maturity by<br />
Rock-Eval pyrolysis, <strong>and</strong> 447 readings were taken of<br />
vitrinite reflectance from 12 well profiles. Selected<br />
samples were also analyzed for <strong>the</strong>ir content of cuttings<br />
gas for five well profiles (Table 2) <strong>and</strong> for fluid inclusions<br />
from 33 samples (Table 3). A special investigation<br />
of shows <strong>and</strong> stains was performed on <strong>the</strong> 18 samples<br />
listed in Table 4.<br />
RESULTS AND DISCUSSION<br />
<strong>Source</strong> Rock Quality<br />
Herein, we consider a shale (without <strong>hydrocarbon</strong><br />
staining or coaly fragments) to be oil prone when its<br />
original TOC <strong>and</strong> hydrogen index (HI) exceeds about<br />
1.5 wt. % <strong>and</strong> 250–300 mg HC/g organic carbon (org<br />
C), respectively, <strong>and</strong> its <strong>the</strong>rmal or solvent extract is<br />
dominated by a well-defined distribution of aliphatic<br />
compounds. Fur<strong>the</strong>r supporting evidence includes<br />
richly fluorescent algal or amorphous organic matter as<br />
seen by visual kerogen analyses. In our study area, <strong>the</strong>se<br />
shales also display organic stringers <strong>within</strong> a laminated<br />
clay matrix (thin-section analyses). Gas-prone shales in<br />
<strong>the</strong> North Sea are characterized by original HI values<br />
below 200 mg HC/g org C, visually identifiable
Figure 3. Schematic cross section of <strong>the</strong> Central Viking Graben from north of <strong>the</strong> Brae fields in <strong>the</strong> west, through <strong>the</strong> Gudrun field (15/3), to <strong>the</strong> Balder field complex in <strong>the</strong><br />
east. The figure depicts structural styles, maturation levels, <strong>and</strong> preferred <strong>hydrocarbon</strong> <strong>migration</strong> <strong>pathways</strong> <strong>and</strong> entry points into tertiary reservoirs. Gamma-ray log signatures<br />
are added for select wells. The location of <strong>the</strong> cross section is shown in Figure 1.<br />
Isaksen <strong>and</strong>Ledje 865
Table 1. Geochemical Data for Wells Studied*<br />
Visual OMT<br />
Number of<br />
Readings<br />
Ro/TOC/HI Rock-Eval Pyrolysis<br />
Thickness Maturity<br />
<strong>Source</strong> Rock<br />
Rating<br />
Chemical<br />
Kerogen<br />
Classification<br />
TOCo (%) HI HIo TOC<br />
(%)<br />
Vitrinite GCData<br />
Gas-Prone Pr/Ph CPI<br />
Intertinite<br />
Coal<br />
Liptinite<br />
Oil-Prone<br />
Ro (%) LOM<br />
Net<br />
(m)<br />
Net<br />
(m)<br />
Base<br />
(m)<br />
Top<br />
(m)<br />
Well Zone<br />
15/3-1 A B 3947 4083 136 96 0.6 8.4 87% 1% 12% 1.3 1.0 5.6 5.6 324 385 II/III-III/II Good oil 20/12/12<br />
C4083 4753 670 410 0.72 9.4 56% 14% 30% 1.4 1.1 5.9 5.9 96 100 III Good gas 40/23/23<br />
D 4753 4986 233 233 1.08 11.1 50% 13% 37% 1.6 1.0 4.2 4.2 24 24 IV/III – 31/4/4<br />
15/3-2 A B 4236 4301 65 65 0.76 9.6 47% 1% 52% 1.3 1.0 4.1 4.1 136 290 III-III/II Fair oil/trans 30/8/8<br />
C4301 4352 51 51 – 9.8 – – – 1.2 1.0 4.9 4.9 80 100 III Fair gas 0/3/3<br />
D 4352 4400 48 48 0.94 10.5 35% 5% 60% 1.4 1.4 2.9 2.9 41 41 IV-III – 3/3/3<br />
15/3-3 A B 4018 4018 162 162 0.61 8.5 0% 0% 100% 0.9 1.0 6.2 6.2 151 220 III-III/II Fair oil/trans 13/6/4<br />
C4180 4450 270 150 0.88 10.2 0% 0% 100% 5.2 5.2 83 100 III Good gas 14/7/4<br />
D 4450 4452 72 72 – 10.6 – – – 1.5 1.0 5.5 5.5 105 150 III Good gas 0/2/1<br />
15/5-1 A B 3492 3543 51 51 0.58 8.2 75% 8% 17% 1.2 1.0 6.0 6.0 309 400 III/II-II/III Good oil 27/6/6<br />
C3543 3553 10 10 – 8.2 – – – – – 6.3 6.3 229 300 III-III/II Good oil 0/1/1<br />
D 3553 3558 5 5 – 8.2 60% 10% 30% 1.0 1.0 5.6 5.6 275 380 II/II Good oil 0/1/1<br />
16/1-2 A B 2242 2298 56 11 – 6.8 70% 20% 10% – – 3.7 3.7 490 510 II Good oil 0/1/1<br />
C2298 2390 92 92 0.48 7.0 74% 14% 12% 1.5 1.1 3.4 3.4 462 490 II-II/III Good oil 19/16/16<br />
D 2390 2424 34 34 0.46 7.0 10% 20% 70% 1.9 1.1 3.9 3.9 253 290 III/II Fair oil 14/4/4<br />
16/1-3 A – B 2707 2707 0 0 – – – – – – – – – – – – – –<br />
C2707 2717 10 10 – 7.2 95% 5% Tr – – 3.9 3.9 275 300 III/II Fair oil 0/1/1<br />
D 2717 2730 13 13 0.50 7.2 – – – 1.8 1.2 4.1 4.1 284 300 III/II Fair oil 40/3/3<br />
24/9-1 A B 4330 4797 467 467 0.94 10.6 41% 3% 56% 1.6 1.0 5.4 7.8 141 460 II/II Excel. oil 52/29/26<br />
C4797 4907 110 110 1.17 11.2 33% 12% 55% 1.6 1.0 3.8 4.8 112 320 III/II-III Good oil 10/9/9<br />
D Not penetrated<br />
24/2-1 A B 4055 4094 39 39 1.00 10.8 55% Tr 45% 1.1 1.1 6.2 6.5 122 200 III-III/II Good gas 4/7/07<br />
C4094 4140 46 46 0.96 10.8 50% Tr 50% 1.3 4.9 5.6 119 280 15.7 III-III/II Fair oil/trans 25/8/8<br />
D 4140 4163 23 23 – 10.8 25% 10% 65% 1.5 1.0 3.4 4.1 150 300 II/II Fair oil 0/2/2<br />
24/12-2 A B 4261 4565 304 304 0.89 10.2 58% 13% 29% 1.4 1.1 4.6 5.1 40 220 III-III/II Fair oil/trans 28/29/29<br />
C4565 4640 75 75 0.92 10.6 50% 40% 10% 1.2 0.9 5.9 5.9 49 49 IV – 4/7/07<br />
D 4640 4955 315 315 1.28 11.6 32% 22% 46% 1.6 1.1 4.5 4.5 15 15 IV/III – 23/21/21<br />
25/4-1 A B 3171 3181 10 10 0.42 6.0 50% 50% Tr – – 8.5 8.5 138 138 III Good gas 4/1/02<br />
C3181 3184 3 3 – – – – – – – – – – – – –<br />
D 3184 3185 1 1 – – – – – – – – – – – – –<br />
25/6-1 A B 2233 2253 20 20 – 6.0 95% 5% 0% 1.0 1.0 7.4 7.4 573 573 II Excel. oil 0/6/4<br />
C2253 2256 3 3 – 6.0 95% 5% 0% 0.8 1.1 3.6 3.6 240 240 III-III/II Fair oil/trans 0/2/2<br />
D 2256 2297 41 41 – 6.0 90% 10% 0% 1.3 1.1 5.5 5.5 374 374 III-III/II Good oil 0/8/8<br />
25/7-2 A – B 4056 4119 63 63 0.88 10.2 95% Tr 5% 1.1 1.0 3.9 8.6 320 740 II-II/III Excel. oil 11/7/7<br />
C4119 4293 174 45 1.00 10.8 – – – 2.1 1.1 1.7 3.2 245 580 II/III-II Good oil 14/2/2<br />
D 4293 4407 114 114 1.14 11.2 75% 10% 15% 2.8 1.1 1.6 5.1 246 830 II Excel. oil 21/7/7<br />
866 Utsira High Area (Norwegian North Sea)<br />
*Zones A B, upper Draupne Fm; Zone C, lower Draupne Fm; Zone D, Hea<strong>the</strong>r Fm; LOM, level of organic maturity; Pr, pristane; Ph, phytane; CPI, carbon preference index (odd/even n-alkanes); TOCo, original total organic carbon; HIo, original hydrogen index.
Table 2. Well-Sections Evaluated for Cuttings-Gas Content<br />
Well<br />
Depth Interval<br />
(m) Age Interval<br />
16/1-1 350–3000 Pleistocene–Upper Cretaceous<br />
16/1-2 300–3000 Pleistocene–Rotliegende (Permian)<br />
16/1-3 2000–3200 Eocene–Zechstein (Permian)<br />
25/8-2 200–2600 Pleistocene–Triassic<br />
25/10-2 2250–3200 Undiff. Tertiary–Rotliegende<br />
Table 3. Samples Analyzed for Possible Content of Fluid<br />
Inclusions*<br />
Well Depth (m) Formation or Age Sample Type<br />
16/1-1 2321 Heimdal Core<br />
16/1-1 2321 Heimdal Core<br />
16/1-1 2330 Heimdal Core<br />
16/1-1 2348 Heimdal Core<br />
16/1-1 2419 Heimdal Core<br />
16/1-1 2427 Heimdal Core<br />
16/1-1 2533 Heimdal Core<br />
16/1-1 2648 Heimdal Core<br />
16/1-2 2102 Heimdal Cuttings<br />
16/1-2 2108 Heimdal Cuttings<br />
16/1-2 2114 Heimdal Cuttings<br />
16/1-2 2240 Upper Jurassic Cuttings<br />
16/1-2 2246 Upper Jurassic Cuttings<br />
16/1-2 2252 Upper Jurassic Cuttings<br />
16/1-2 2258 Upper Jurassic Cuttings<br />
16/1-2 2264 Upper Jurassic Cuttings<br />
16/1-2 2270 Upper Jurassic Cuttings<br />
16/1-2 2273 Late Jurassic Cuttings<br />
16/1-2 2423 Triassic(?) Cuttings<br />
16/1-2 2426 Triassic(?) Cuttings<br />
16/1-2 2429 Triassic(?) Cuttings<br />
25/10-2 1893 Heimdal Core<br />
25/10-2 2013 Heimdal Core<br />
25/10-2 2014 Heimdal Core<br />
25/10-2 2015 Heimdal Core<br />
25/10-2 2015 Heimdal Core<br />
25/10-2 2023 Heimdal Core<br />
25/10-2 2088 Heimdal Core<br />
25/10-2 2100 Heimdal Core<br />
25/10-2 2102 Heimdal Core<br />
25/10-2 2684 Triassic(?) Cuttings<br />
25/10-2 2687 Triassic(?) Cuttings<br />
25/10-2 2690 Triassic(?) Cuttings<br />
*Courtesy of R. J. Pottorf, ExxonMobil Upstream Research Company.<br />
Table 4. Samples Selected for Thermal <strong>and</strong> Solvent<br />
Extraction because of Identified Shows <strong>and</strong> Stains<br />
Well Depth (m) Sample Type<br />
16/1-2 2100 Shale<br />
16/1-2 2130 Shale<br />
16/1-2 2250 Shale/silt/s<strong>and</strong>stone<br />
16/1-2 2102 Silty shale<br />
16/1-2 2108 Silty shale<br />
16/1-2 2114 Silty shale<br />
25/10-2 RE 1983 Shale<br />
25/10-2 RE 2013 Shale<br />
25/10-2 RE 2682 S<strong>and</strong>stone<br />
25/10-2 RE 2713 S<strong>and</strong>stone<br />
25/10-2 RE 3007 Shale (Kupferschiefer)<br />
25/10-2 RE 3009 Conglomerate<br />
25/10-2 RE 3037 Conglomerate<br />
16/1-1 1920 Shale/silt<br />
16/1-1 1936 Shale/silt<br />
16/1-1 2530 Silt/shale<br />
16/1-1 2667 Silt/s<strong>and</strong>stone<br />
16/1-1 2743 S<strong>and</strong>stone/shale<br />
vitrinitic macerals, <strong>and</strong> an aromatic-rich composition.<br />
Assessment of <strong>the</strong> oil vs. gas potential of humic coals<br />
is somewhat more complex. Middle Jurassic humic<br />
coals in <strong>the</strong> North Sea are primarily gas prone but do<br />
have <strong>the</strong> capability to expel aliphatic-rich, volatile oil<br />
(Isaksen et al., 1998a, b). Such coals are known from<br />
<strong>the</strong> Sleipner/Hugin <strong>and</strong> Brent delta systems to <strong>the</strong><br />
south <strong>and</strong> north of our study area, respectively. No<br />
humic coals are thought to be present in <strong>the</strong> area of<br />
<strong>the</strong> Viking Graben to <strong>the</strong> west of <strong>the</strong> nor<strong>the</strong>rn Utsira<br />
High.<br />
The primary source <strong>rock</strong>in <strong>the</strong> Utsira High area is<br />
<strong>the</strong> organic-rich, oil-prone, Kimmeridgian to Volgian–<br />
Ryazanian Draupne Formation. A secondary source<br />
<strong>rock</strong>, which has poor to fair potential for oil, is <strong>the</strong><br />
Oxfordian Hea<strong>the</strong>r Formation. The Permian Kupferschiefer<br />
source is known to extend this far north <strong>and</strong><br />
was penetrated by well 25/10–2. Although <strong>the</strong> Kupferschiefer<br />
shale contains a predominance of oil-prone<br />
algal <strong>and</strong> amorphous organic matter, <strong>the</strong> lackof sufficient<br />
source volume precludes it from contributing<br />
with any significance to <strong>the</strong> reservoired oils in this area.<br />
No contribution from <strong>the</strong> Kupferschiefer Formation<br />
was observed among <strong>the</strong> biomarkers of <strong>the</strong> reservoired<br />
oils. Fur<strong>the</strong>rmore, molecular signatures in oils <strong>and</strong><br />
Isaksen <strong>and</strong>Ledje 867
gases in <strong>the</strong> area do not suggest presence of Middle<br />
Jurassic woody/coaly source <strong>rock</strong>s.<br />
During <strong>the</strong> early Callovian a marine transgression<br />
tookplace throughout <strong>the</strong> Viking Graben. The relative<br />
rise in sea level continued into <strong>the</strong> earliest Cretaceous<br />
with deposition of time-transgressive marine shales of<br />
<strong>the</strong> Draupne Formation. Pyrolysis, solvent extraction,<br />
<strong>and</strong> visual kerogen data (Table 1) show that <strong>the</strong>se<br />
shales contain oil-prone kerogen that has predominantly<br />
liptintic organic matter in <strong>the</strong> form of marine,<br />
algal bodies <strong>and</strong> lipid-rich amorphous material. The<br />
oil-prone nature of <strong>the</strong> amorphous kerogen is supported<br />
by elevated hydrogen indices (400 mg HC/g<br />
org C) <strong>and</strong> paraffinic compositions for those samples<br />
where <strong>the</strong> amorphous material accounts for <strong>the</strong> bulk<br />
of <strong>the</strong> kerogen. We do not imply a common origin for<br />
<strong>the</strong> algal <strong>and</strong> amorphous material. Although some percentage<br />
of <strong>the</strong> amorphous material may be linked to<br />
an algal origin through bacterial degradation (seen as<br />
severely degraded algal bodies), <strong>the</strong> bulkof <strong>the</strong> amorphous<br />
material may indeed have been enriched by<br />
o<strong>the</strong>r mechanisms, such as a predominantly bacterial<br />
origin or a preferential adsorption of amorphous material<br />
on certain clays (Mayer, 1994). For <strong>the</strong> most part,<br />
<strong>the</strong>se shales are interpreted to have accumulated under<br />
anoxic bottom-water conditions that helped preserve<br />
<strong>the</strong>ir oil-prone nature. The presence of finely laminated<br />
shales suggests a lackof, or low abundance of,<br />
grazing or burrowing organisms. Oil-prone organic<br />
matter may also be preserved under suboxic conditions<br />
(Isaksen <strong>and</strong> Bohacs, 1995).<br />
From its wire-line log response (gamma-ray, resistivity,<br />
<strong>and</strong> sonic log signatures), we subdivided <strong>the</strong><br />
Draupne Formation into an upper <strong>and</strong> lower unit (Figure<br />
4). The Upper Jurassic sequence on <strong>the</strong> west side<br />
of <strong>the</strong> Viking Graben contains extensive mass-flow<br />
sediments in <strong>the</strong> Brae Formation, representing rapid<br />
syntectonic sedimentation from <strong>the</strong> graben escarpment<br />
(Figure 5). The s<strong>and</strong>s of <strong>the</strong> Brae Formation are interbedded<br />
with open-marine sediments of <strong>the</strong> Draupne<br />
Formation <strong>and</strong> pinch out eastward (Figure 3). As a result,<br />
<strong>the</strong> Upper Jurassic has a complex lithofacies distribution<br />
<strong>and</strong> has seen a dilution of <strong>the</strong> oil-prone kerogen<br />
of <strong>the</strong> basinal Draupne shale by l<strong>and</strong>-derived<br />
gas-prone kerogen, especially along <strong>the</strong> western graben<br />
margin. Although such mass-flow deposits can oxygenate<br />
anoxic sediments or anoxic <strong>and</strong> stratified bottom<br />
waters, <strong>the</strong> presence of low amounts of oxygen is not<br />
considered detrimental to preservation of organic matter<br />
(Heinrichs <strong>and</strong> Reeburgh, 1987; Lee, 1992). In our<br />
opinion, <strong>the</strong> type of organic matter exerts a far greater<br />
868 Utsira High Area (Norwegian North Sea)<br />
control on oil vs. gas potential than does <strong>the</strong> oxidation<br />
of organic matter <strong>within</strong> <strong>the</strong> dysoxic zone.<br />
Interpretations of seismic data <strong>and</strong> wire-line log responses<br />
for <strong>the</strong> Upper Jurassic sediments enabled <strong>the</strong><br />
construction of an Upper Jurassic isopach map as<br />
shown by Figure 6. This has been extended with earlier<br />
work (Isaksen et al., 1997) to include <strong>the</strong> South Viking<br />
Graben in <strong>the</strong> greater Sleipner–Tiffany–Brae area. In<br />
this context, <strong>the</strong> Upper Jurassic isopach thicknesses<br />
represent <strong>the</strong> sedimentary section from base Callovian<br />
to base Cretaceous. In <strong>the</strong> graben area, between <strong>the</strong><br />
Balder <strong>and</strong> Gryphon fields, <strong>the</strong> Upper Jurassic attains<br />
thicknesses of 3 km, of which a considerable thickness<br />
constitutes <strong>the</strong> coarser clastics shed off from <strong>the</strong> East<br />
Shetl<strong>and</strong> Platform.<br />
Rock-Eval pyrolysis <strong>and</strong> TOC analyses (Table 1)<br />
were carried out on 14 wells <strong>within</strong> <strong>the</strong> greater Utsira<br />
High area to evaluate <strong>the</strong> organic richness, <strong>quality</strong>, <strong>and</strong><br />
<strong>the</strong>rmal maturity of source intervals. To compare <strong>and</strong><br />
assess source <strong>rock</strong>s, which are currently at different<br />
maturities, we used a technique derived from <strong>the</strong> work<br />
of Cooles et al. (1986) <strong>and</strong> Pepper (1991), whereby<br />
measured hydrogen index (HI) <strong>and</strong> TOC values are<br />
back-calculated to <strong>the</strong>ir original (immature) HI o <strong>and</strong><br />
TOC o values according to <strong>the</strong>ir <strong>the</strong>rmal history. The<br />
oil vs. gas potential of <strong>the</strong>se <strong>rock</strong>s (Figure 7) follow <strong>the</strong><br />
definitions discussed previously.<br />
The HI is commonly used as an approximation of<br />
<strong>the</strong> hydrogen content of <strong>the</strong> kerogen <strong>and</strong> thus as an<br />
indicator of <strong>the</strong> source <strong>rock</strong><strong>quality</strong> in terms of oilgeneration<br />
vs. gas-generation potential. This is not necessarily<br />
<strong>the</strong> case for source <strong>rock</strong>s that have a predominance<br />
of terrigenous higher plant organic matter (type<br />
III) because resinite macerals can contribute to <strong>the</strong> HI<br />
value but have a poor potential for generation of C 8<br />
aliphatic <strong>hydrocarbon</strong>s (Isaksen et al., 1998a). The HI<br />
can be plotted against <strong>the</strong> T max to classify kerogen<br />
types <strong>and</strong> evaluate <strong>the</strong> level of <strong>the</strong>rmal (organic) maturity<br />
(Figure 8). This chemical kerogen classification<br />
shows that both upper <strong>and</strong> lower Draupne source intervals<br />
along <strong>the</strong> western graben margin contain more<br />
type III <strong>and</strong> III/II kerogen than in <strong>the</strong> eastern part of<br />
<strong>the</strong> graben (Figure 9A, B). This is in agreement with<br />
<strong>the</strong> expected strong terrigenous influx of woody material<br />
associated with <strong>the</strong> rapid syntectonic sedimentation<br />
from <strong>the</strong> graben scarps. The eastward extension<br />
of type III kerogen seems to be associated with <strong>the</strong> easternmost<br />
extension of mass-flow sediments from <strong>the</strong><br />
western graben margin.<br />
To fur<strong>the</strong>r investigate <strong>the</strong> indications of dilution of<br />
<strong>the</strong> oil-prone kerogen of <strong>the</strong> Draupne shale along <strong>the</strong>
western graben margin, <strong>the</strong> content of visual organic<br />
matter type (OMT) was plotted for <strong>the</strong> analyzed wells<br />
(Figure 10A, B). Wells along <strong>the</strong> eastern margin consistently<br />
show a higher content of oil-prone liptinite<br />
kerogen macerals for both <strong>the</strong> upper <strong>and</strong> lower<br />
Draupne formations. Wells along <strong>the</strong> western margin<br />
of <strong>the</strong> graben conversely have more vitrinite (gas-<br />
Figure 4. Subdivision of <strong>the</strong><br />
Jurassic sedimentary section<br />
based on wire-line log signatures.<br />
The logs shown are<br />
gamma-ray, sonic, <strong>and</strong> resistivity.<br />
The right column shows <strong>the</strong><br />
calculated percent TOCbased<br />
on <strong>the</strong> technique by Passey et<br />
al. (1990).<br />
prone) kerogen content. Incorporation of visual kerogen<br />
data allows <strong>the</strong> interpreter to better assess whe<strong>the</strong>r<br />
<strong>the</strong> oil-prone vs. gas-prone nature of <strong>the</strong> source <strong>rock</strong>is<br />
primarily due to organic matter type or organic matter<br />
degradation through severe oxidation.<br />
The ratings of both upper <strong>and</strong> lower Draupne<br />
source intervals (Figure 11A, B) indicate that a<br />
Isaksen <strong>and</strong>Ledje 869
Figure 5. Main depositional<br />
environments for <strong>the</strong> Upper Jurassic<br />
Draupne Formation. The<br />
extensive mass-flow sediments<br />
represent syntectonic sedimentation<br />
from <strong>the</strong> western graben<br />
escarpment. As a result, offshore,<br />
marine shales are interbedded<br />
with mass-flow sediments.<br />
Shoreface sedimentation<br />
dominated around <strong>the</strong> Utsira<br />
High.<br />
predominantly gas-prone organic facies was deposited<br />
in <strong>the</strong> graben west of blocks 16/1 <strong>and</strong> 25/10. We interpret<br />
<strong>the</strong> decrease in oil potential to be mainly due<br />
to <strong>the</strong> syntectonic influx of turbidites with terrigenous<br />
organic matter during <strong>the</strong> Kimmeridgian period. The<br />
870 Utsira High Area (Norwegian North Sea)<br />
magnitude of a potential decrease in <strong>the</strong> oil-prone nature<br />
of <strong>the</strong> kerogen during accumulation under more<br />
oxic conditions (i.e., oxygen-rich turbidite currents)<br />
remains unresolved. Laminated blackshales sampled<br />
from wells drilled on structural highs suggest a sparse
Figure 6. Isopach map (contours<br />
given in meters) of <strong>the</strong><br />
Upper Jurassic representing <strong>the</strong><br />
section between <strong>the</strong> base Callovian<br />
<strong>and</strong> <strong>the</strong> base Cretaceous.<br />
Isaksen <strong>and</strong>Ledje 871
Figure 7. <strong>Source</strong> richness <strong>and</strong><br />
source <strong>quality</strong> chart for <strong>the</strong> upper<br />
<strong>and</strong> lower Draupne formations.<br />
Each data point represents<br />
<strong>the</strong> average weighted<br />
values from cuttings or core<br />
samples from <strong>the</strong> interval. The<br />
four samples from <strong>the</strong> Lower<br />
Jurassic at <strong>the</strong> base of <strong>the</strong> chart<br />
denote HI values less than 100<br />
mg/g organic carbon.<br />
benthic fauna at <strong>the</strong>se locations. It seems probable,<br />
however, that <strong>the</strong> Draupne shales experienced a higher<br />
degree of dilution by coarser clastics as well as periodic<br />
oxygenation from turbidite currents in basinal positions<br />
connected with debris <strong>and</strong> turbidite flows from<br />
<strong>the</strong> western basin margin. For <strong>the</strong> upper Draupne, <strong>the</strong><br />
gas-prone organic facies is confined to block24/12,<br />
whereas for <strong>the</strong> lower Draupne gas-prone organic facies<br />
also extends into block15/3 to <strong>the</strong> south. The<br />
potential for <strong>the</strong> Draupne Formation to generate oil<br />
improves toward <strong>the</strong> east, from a mixed gas-prone <strong>and</strong><br />
oil-prone organic facies in <strong>the</strong> eastern parts of blocks<br />
24/12 <strong>and</strong> 15/3 to an oil-prone organic facies closest<br />
to <strong>the</strong> Utsira High. At <strong>the</strong> time of our study, no source<br />
<strong>rock</strong>samples were available from <strong>the</strong> Beryl field (UK<br />
9/13) source kitchen (north of 5930N).<br />
<strong>Source</strong> Rock Thermal Maturity<br />
T max measurements from Rock-Eval pyrolysis span a<br />
range from immature (430C) to fully mature (455C)<br />
(Figure 8). Care was taken to avoid T max data derived<br />
from shales stained by in-migrated <strong>hydrocarbon</strong>s (typ-<br />
872 Utsira High Area (Norwegian North Sea)<br />
ically seen as a bimodal S 2 peak). As a fur<strong>the</strong>r control<br />
on <strong>the</strong> <strong>the</strong>rmal maturity vs. depth trend, comparison<br />
was made with vitrinite reflectance (% R o) measurements<br />
on Middle Jurassic coals <strong>and</strong> coaly shales from<br />
locations throughout <strong>the</strong> entire Viking Graben where<br />
such <strong>rock</strong>s are present (Sleipner/Hugin <strong>and</strong> Brent delta<br />
systems). The resultant <strong>the</strong>rmal maturity vs. depth relation<br />
is illustrated in Figure 12. T max <strong>and</strong> % R o data<br />
suggest that early to peakoil generation from <strong>the</strong><br />
Draupne shale occurs between an R o equivalent of<br />
0.62% <strong>and</strong> 0.88% corresponding to depths of 3400–<br />
4400 m below sea floor. Late oil generation occurs at<br />
R o 1.1%, corresponding to a depth of approximately<br />
5000 m below sea floor.<br />
SECONDARY MIGRATION OF<br />
OIL AND GAS<br />
Evidence for Migration into Tertiary Strata<br />
Proof of <strong>hydrocarbon</strong> <strong>migration</strong> from Jurassic source<br />
<strong>rock</strong>s to Tertiary reservoir <strong>rock</strong>s is given by <strong>the</strong> accu-
mulations at <strong>the</strong> Balder, Hanna, Grane, Jotun, <strong>and</strong><br />
Ringhorne fields. In o<strong>the</strong>r areas, evidence for <strong>migration</strong><br />
into <strong>the</strong> Tertiary <strong>and</strong> Cretaceous sections is shown by<br />
<strong>the</strong> presence of oil shows <strong>and</strong> stains or <strong>the</strong>rmogenic gas<br />
<strong>within</strong> an o<strong>the</strong>rwise <strong>the</strong>rmally immature section. Core<br />
<strong>and</strong> cuttings samples were analyzed for <strong>the</strong> presence of<br />
inclusions with possible <strong>hydrocarbon</strong>s. Molecular characterization<br />
of such <strong>hydrocarbon</strong> inclusions can provide<br />
important insights to paleo<strong>migration</strong> events (Isaksen<br />
et al., 1998b). In this study, no fluid inclusions<br />
were found (Table 3). The absence of fluid inclusions<br />
is due to paleotemperatures <strong>and</strong> present-day temperatures<br />
cooler than required for <strong>the</strong> formation of inclusions.<br />
One such process, quartz overgrowth, does not<br />
start until temperatures of approximately 80C are<br />
reached.<br />
Thermogenic gases were discovered in <strong>the</strong><br />
Paleocene–Eocene of wells 16/1–1 (Figure 13), 16/1–<br />
Figure 8. Evaluation of source<br />
<strong>rock</strong> <strong>the</strong>rmal maturity <strong>and</strong> <strong>quality</strong>.<br />
Roman numerals denote <strong>the</strong><br />
predominant organic-matter<br />
type, whereas <strong>the</strong>rmal maturity<br />
levels are given by Rock-Eval<br />
T max values <strong>and</strong> vitrinite reflectance<br />
(% R o).<br />
2 (Figure 14), <strong>and</strong> in <strong>the</strong> <strong>the</strong>rmally immature Upper<br />
Jurassic sections of wells 16/1–2, 16/1–3 (Figure 15),<br />
<strong>and</strong> 25/8–2 (Figure 16). Thermogenic <strong>hydrocarbon</strong> gas<br />
is also present <strong>within</strong> <strong>the</strong> Upper Cretaceous to Upper<br />
Jurassic section (2200–3200 m) in well 25/10–2RE<br />
<strong>and</strong> is especially pronounced <strong>within</strong> <strong>the</strong> Rotliegende<br />
s<strong>and</strong>stones (Permian) at 2900–3000 m (Figure 17).<br />
Three <strong>rock</strong>samples from <strong>the</strong> Permian section (one<br />
from 3007 m <strong>within</strong> <strong>the</strong> Kupferschiefer shale <strong>and</strong> two<br />
<strong>within</strong> <strong>the</strong> Rotliegende conglomerates at 3009 <strong>and</strong><br />
3037 m) were analyzed by <strong>the</strong>rmal evaporation–gas<br />
chromatography) (Figure 18), pyrolysis–gas chromatography,<br />
solvent extraction, liquid chromatography,<br />
<strong>and</strong> gas chromatography of <strong>the</strong> saturate <strong>hydrocarbon</strong><br />
fraction (Figure 19) to checkfor presence of<br />
free <strong>hydrocarbon</strong>s <strong>and</strong> to ascertain whe<strong>the</strong>r a secondary<br />
<strong>migration</strong> pathway may exist <strong>within</strong> <strong>the</strong> Rotliegende<br />
at this location. The <strong>the</strong>rmal evaporation–gas<br />
Isaksen <strong>and</strong>Ledje 873
Figure 9. Classification of kerogen <strong>quality</strong> <strong>within</strong> <strong>the</strong> (A) upper Draupne <strong>and</strong> (B) lower Draupne formations based on <strong>the</strong> HI data<br />
shown in Figure 7. Note how areas that have higher predicted contents of type III kerogen conform to areas affected most by<br />
syntectonic mass-flow sediments along <strong>the</strong> western graben margin.<br />
chromatography data do not show significant quantities<br />
of free <strong>hydrocarbon</strong>s. Solvent extractable (free) <strong>hydrocarbon</strong>s<br />
observed <strong>within</strong> <strong>the</strong> conglomerates are<br />
likely <strong>the</strong> results of short-distance <strong>migration</strong> (2–30 m)<br />
from <strong>the</strong> Kupferschiefer organic-rich shales.<br />
Migration Model<br />
Marine source <strong>rock</strong>s of <strong>the</strong> Upper Jurassic Draupne<br />
Formation thicken from <strong>the</strong> Utsira High westward into<br />
<strong>the</strong> Viking Graben (Figure 3). Hydrocarbons are likely<br />
to have been generated in large amounts west of <strong>the</strong><br />
Utsira High. Maturation studies indicate that <strong>hydrocarbon</strong><br />
expulsion <strong>and</strong> <strong>migration</strong> started during <strong>the</strong> latest<br />
Cretaceous <strong>and</strong> continues to <strong>the</strong> present day<br />
(Thomas et al., 1985; Dahl et al., 1987; Isaksen et al.,<br />
874 Utsira High Area (Norwegian North Sea)<br />
1998b). Regional <strong>migration</strong> cell mapping at <strong>the</strong> Middle<br />
Jurassic level in <strong>the</strong> Viking Graben indicates a general<br />
basin to margin pathway. These <strong>migration</strong> <strong>pathways</strong><br />
intersect faults at which point vertical leakage through<br />
<strong>the</strong> Cretaceous section is key to charging reservoir intervals<br />
in <strong>the</strong> Tertiary.<br />
Figure 3 illustrates that <strong>the</strong> Jurassic source intervals<br />
are currently mature for generation of <strong>hydrocarbon</strong>s<br />
(% R o 0.6) in <strong>the</strong> center of <strong>the</strong> graben. The<br />
proposed model for migrating <strong>hydrocarbon</strong>s into <strong>the</strong><br />
Tertiary plays in <strong>the</strong> Utsira High area involves <strong>migration</strong><br />
at <strong>the</strong> Draupne source level into <strong>the</strong> adjacent Middle<br />
Jurassic Hugin Formation <strong>and</strong> Sleipner Formation<br />
s<strong>and</strong>stones. Longer distance secondary <strong>migration</strong> involves<br />
eastward lateral <strong>migration</strong> through <strong>the</strong> Jurassic<br />
s<strong>and</strong>stone conduits. Across <strong>the</strong> relatively small faults
Figure 10. Classification of kerogen <strong>quality</strong> <strong>within</strong> <strong>the</strong> (A) upper Draupne <strong>and</strong> (B) lower Draupne formations based on <strong>the</strong> content<br />
of liptinitic, oil-prone organic matter from visual kerogen evaluations.<br />
in <strong>the</strong> Jurassic section, <strong>hydrocarbon</strong>s migrate up along<br />
<strong>the</strong> fault plane <strong>and</strong> into Jurassic conduits on <strong>the</strong> highside<br />
blockor migrate through <strong>the</strong> fault plane <strong>and</strong> into<br />
juxtaposed s<strong>and</strong>stones. In general <strong>hydrocarbon</strong>s migrate<br />
laterally in this fashion until succeeded by vertical<br />
<strong>migration</strong> up fault planes along <strong>the</strong> Utsira High westbounding<br />
fault system.<br />
Major <strong>migration</strong> entry points available were faults<br />
cut through <strong>the</strong> entire Cretaceous succession in <strong>the</strong><br />
eastern part of <strong>the</strong> fault system as it steps up toward<br />
<strong>the</strong> Utsira High. Where Jurassic carrier beds <strong>and</strong> Tertiary<br />
reservoirs are connected, <strong>hydrocarbon</strong>s continue<br />
to move updip into available independent closures or<br />
into combined stratigraphic <strong>and</strong> structural traps at <strong>the</strong><br />
Tertiary level. The <strong>migration</strong> model is supported by<br />
Tertiary <strong>hydrocarbon</strong> shows (e.g., 16/1–1 <strong>and</strong> 16/1–<br />
2) <strong>and</strong> accumulations (e.g., Balder field) located east<br />
of such <strong>migration</strong> entry points. Migration <strong>pathways</strong><br />
through low-permeability conduits (e.g., ratty s<strong>and</strong>s in<br />
<strong>the</strong> Upper Jurassic <strong>and</strong> fractured chalks in Cretaceous)<br />
are likely to be less efficient. The absence of faulting in<br />
<strong>the</strong> Cretaceous section is believed to effectively prevent<br />
<strong>migration</strong> of <strong>hydrocarbon</strong>s into tertiary reservoirs<br />
in <strong>the</strong> central part of <strong>the</strong> graben (e.g., 15/3–1 <strong>and</strong> 15/<br />
3–3).<br />
EXPLORATION SIGNIFICANCE<br />
The key observations from this study are <strong>the</strong> following:<br />
• Both upper <strong>and</strong> lower Draupne formations are effective<br />
source <strong>rock</strong>s <strong>within</strong> <strong>the</strong> greater Utsira High<br />
area.<br />
Isaksen <strong>and</strong>Ledje 875
Figure 11. Expected <strong>hydrocarbon</strong> type generated from mature (A) upper Draupne <strong>and</strong> (B) lower Draupne source <strong>rock</strong>s. The area<br />
outlines are based on TOC o <strong>and</strong> HI o calculations.<br />
• The source <strong>rock</strong><strong>quality</strong> of <strong>the</strong> Draupne Formation<br />
ranges widely from gas-prone along <strong>the</strong> western margin<br />
of <strong>the</strong> graben to oil-prone in <strong>the</strong> east.<br />
• The gas-prone organic facies is believed to be associated<br />
with terrigenous input from westerly derived<br />
mass-flow sediments, which have both diluted <strong>the</strong><br />
oil-prone organic matter <strong>and</strong> introduced a more oxic<br />
depositional environment.<br />
• Migration is considered a significant riskfactor for<br />
any Tertiary prospect west of <strong>the</strong> Utsira High mainbounding<br />
fault.<br />
The exploration significance of <strong>the</strong>se observations<br />
lies in <strong>the</strong>ir use as an aid to predict whe<strong>the</strong>r an area is<br />
likely to be dominated by oil or gas reserves. For a prospect<br />
on <strong>the</strong> Utsira High to be sheltered from gas influx<br />
876 Utsira High Area (Norwegian North Sea)<br />
it may be concluded that three requirements need to<br />
be satisfied: (1) <strong>the</strong> Draupne Formation <strong>within</strong> <strong>the</strong><br />
drainage area needs to be of an oil-prone nature, (2) <strong>the</strong><br />
oil-prone source <strong>rock</strong>must not be <strong>within</strong> <strong>the</strong> gasgeneration<br />
window, <strong>and</strong> (3) <strong>migration</strong> access to <strong>the</strong><br />
gas-prone source kitchen west of <strong>the</strong> Utsira High area<br />
needs to be denied. It follows that it is critical to underst<strong>and</strong><br />
<strong>the</strong> <strong>migration</strong> entry points into <strong>the</strong> Tertiary<br />
section. In <strong>the</strong> graben, downdip from <strong>the</strong> Utsira High,<br />
a thickCretaceous section <strong>and</strong> lackof penetrating<br />
faults prevent effective <strong>migration</strong> from <strong>the</strong> Jurassic into<br />
Tertiary traps. Exploration efforts at Tertiary levels<br />
should <strong>the</strong>refore be focused close to <strong>the</strong> Utsira High in<br />
areas that have thin Cretaceous sediments <strong>and</strong> where<br />
basin-bounding faults are present to provide <strong>the</strong> necessary<br />
<strong>migration</strong> route.
Figure 12. Regional assessment of <strong>the</strong>rmal maturity vs. depth<br />
based on measurements of vitrinite reflectance from humic<br />
coals <strong>and</strong> shales that have terrigenous macerals.<br />
CONCLUSIONS<br />
• Chemical kerogen classification <strong>and</strong> source <strong>rock</strong> pyrolysis<br />
show that both upper <strong>and</strong> lower Draupne<br />
source intervals along <strong>the</strong> western graben margin<br />
contain more terrigenous (type III <strong>and</strong> III/II) kerogen<br />
than in <strong>the</strong> eastern part of <strong>the</strong> graben. Such<br />
change in organic facies <strong>within</strong> <strong>the</strong> Draupne source<br />
<strong>rock</strong>naturally results in a higher proportion of gas<br />
generation upon maturation.<br />
• Good potential for oil generation from Draupne Formation<br />
source <strong>rock</strong>s exists along <strong>the</strong> entire western<br />
margin <strong>and</strong> nor<strong>the</strong>rn nose of <strong>the</strong> Utsira High.<br />
• Thermogenic-<strong>hydrocarbon</strong> gas was encountered in<br />
<strong>the</strong> Upper Cretaceous <strong>and</strong> Tertiary in wells 16/1–1,<br />
16/1–2, 16/1–3, 25/8–2, <strong>and</strong> 25/10–2. These gases<br />
have migrated into <strong>the</strong> Cretaceous <strong>and</strong> Tertiary sedimentary<br />
section from deeper, mature, sections of<br />
<strong>the</strong> Draupne <strong>and</strong> Hea<strong>the</strong>r formations.<br />
• Migration entry points into <strong>the</strong> Tertiary section are<br />
provided by faults cutting through <strong>the</strong> base Paleocene.<br />
Unfaulted Cretaceous sections more likely act<br />
as a barrier to <strong>migration</strong> into Tertiary reservoirs.<br />
• No <strong>hydrocarbon</strong> fluid inclusions were detected in<br />
<strong>the</strong> samples analyzed. The lackof fluid inclusions is<br />
most likely due to <strong>the</strong> low <strong>the</strong>rmal maturity level of<br />
<strong>the</strong> Tertiary sediments. At most locations <strong>the</strong> Paleocene<br />
<strong>and</strong> Eocene s<strong>and</strong>s are poorly consolidated <strong>and</strong><br />
have not been exposed to <strong>the</strong> diagenetic temperatures<br />
required ( 80C) for mineral mobilization<br />
<strong>and</strong> <strong>the</strong> formation of fluid inclusions.<br />
• Thermogenic liquid <strong>hydrocarbon</strong>s <strong>within</strong> <strong>the</strong> Permian<br />
conglomerates in well 25/10–2 are derived<br />
from <strong>the</strong> organic-rich Kupferschiefer shales by shortdistance<br />
<strong>migration</strong>.<br />
APPENDIX: ANALYTICAL METHODS<br />
Total organic carbon (TOC) <strong>and</strong> Rock-Eval pyrolysis measurements<br />
were made on a Leco IR 312 carbon analyzer <strong>and</strong> Delsi RockEval<br />
II, respectively. Vitrinite reflectance <strong>and</strong> visual kerogen analyses were<br />
analyzed according to st<strong>and</strong>ard coal methods. Thermoevaporation<br />
<strong>and</strong> pyrolysis–gas chromatography was performed using custombuilt<br />
systems based on <strong>the</strong> HP 5790 gas chromatograph (GC)<br />
equipped with flame-ionization detectors. The <strong>the</strong>rmal extraction<br />
was done iso<strong>the</strong>rmally at 280C for 3 min. The sample was <strong>the</strong>n<br />
heated at 60C/min to 610C, <strong>and</strong> <strong>the</strong> volatiles were trapped in liquid<br />
nitrogen on <strong>the</strong> head of <strong>the</strong> GC column (split 60:1). The GC<br />
had a 50 m capillary column (5% phenyl-methylsilicone). Initial temperature<br />
was 20C followed by a heating rate of 4C/min to a final<br />
temperature of 280C. Cuttings gas, <strong>the</strong>rmal evaporation–gas chromatography,<br />
<strong>and</strong> pyrolysis analyses were carried out at Exxon Production<br />
Research Company, Houston, Texas.<br />
Isaksen <strong>and</strong>Ledje 877
Figure 13. Well 16/1–1 profiles<br />
of cuttings-gas data showing<br />
gas-wetness <strong>and</strong> summed<br />
concentrations of C 1 through C 4<br />
(vol. %). Gas wetness is calculated<br />
as 100 [(C 2 C 3 C 4)/<br />
(C 1 C 2 C 3 C 4)]. Thermogenic<br />
<strong>hydrocarbon</strong> gas is<br />
present at 2000–3000 m, <strong>within</strong><br />
<strong>the</strong> Paleocene–Eocene. No free<br />
liquid <strong>hydrocarbon</strong>s were detected<br />
(samples were analyzed<br />
from 1920, 1935, 2530, 2667,<br />
<strong>and</strong> 2743 m [Table 4]), nor<br />
were any fluid inclusions detected<br />
(samples were analyzed<br />
from <strong>the</strong> Paleocene at depths<br />
of 2320–2648 m [Table 3]).<br />
Levels of organic metamorphism<br />
(LOM) 6 <strong>and</strong> 8 correlate<br />
to vitrinite reflectance values of<br />
0.43% <strong>and</strong> 0.55%, respectively.<br />
Figure 14. Well 16/1–2 profiles<br />
of cuttings-gas data showing<br />
gas wetness <strong>and</strong> summed<br />
concentrations of C 1 through<br />
C 4. Thermogenic <strong>hydrocarbon</strong><br />
gas is present <strong>within</strong> Eocene,<br />
Paleocene, Danian, <strong>and</strong> Late Jurassic<br />
at 1700–2500 m. No free<br />
<strong>hydrocarbon</strong> liquids were detected<br />
(samples were analyzed<br />
from 2099, 2130, <strong>and</strong> 2250 m),<br />
nor were any fluid inclusions<br />
observed (analyses <strong>within</strong> <strong>the</strong><br />
Paleocene at 2102–2490 m).<br />
878 Utsira High Area (Norwegian North Sea)
Figure 15. Well 16/1–3 profiles of cuttings-gas data showing<br />
gas wetness <strong>and</strong> summed concentrations of C 1 through C 4. Thermogenic<br />
<strong>hydrocarbon</strong> gas is present <strong>within</strong> <strong>the</strong> Upper Jurassic<br />
interval at 2600–2800 m.<br />
Figure 16. Well 25/8–2 profiles of cuttings-gas data showing<br />
gas wetness <strong>and</strong> summed concentrations of C 1 through C 4. Thermogenic<br />
gas is present with <strong>the</strong> immature Upper Jurassic from<br />
1500 m to total depth drilled.<br />
Figure 17. Well 25/10–2 profiles<br />
of cuttings-gas data showing<br />
gas wetness <strong>and</strong> summed<br />
concentrations of C 1<br />
through C 4.
Figure 18. Well 25/10–2RE.<br />
Thermoevaporation (S 1) of core<br />
samples from (A) Kupferschiefer<br />
shale at 3007 m (sample<br />
202087A), (B) Rotliegende conglomerate<br />
at 3009 m (sample<br />
202087B), <strong>and</strong> (C) Rotliegende<br />
conglomerate at 3037 m (sample<br />
202087C). S 1 represents <strong>the</strong><br />
free <strong>hydrocarbon</strong>s in <strong>the</strong> <strong>rock</strong>.<br />
880 Utsira High Area (Norwegian North Sea)
Figure 19. Well 25/10–2RE.<br />
Gas chromatograms of <strong>the</strong> saturate<br />
<strong>hydrocarbon</strong> fractions<br />
from (A) Kupferschiefer shale at<br />
3007 m (sample 202087A), (B)<br />
Rotliegende conglomerate at<br />
3009 m (sample 202087B), <strong>and</strong><br />
(C) Rotliegende conglomerate<br />
at 3037 m (sample 202087C).<br />
Isaksen <strong>and</strong>Ledje 881
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