Source rock quality and hydrocarbon migration pathways within the ...

Source rock quality and 

hydrocarbon migration 

pathways within the greater 

Utsira High area, Viking 

Graben, Norwegian North Sea 

Gary H. Isaksen and K. Haakan I. Ledje 

ABSTRACT 

The greater Utsira High area is located within the southern part of 

quadrants 24 and 25 and the northern part of quadrants 15 and 16 

in the Norwegian North Sea. In this part of the Viking Graben the 

main exploration play is the submarine fan sands of Paleocene and 

Eocene age. These sands (Balder, Heimdal, and Ty formations) 

pinch out to the east in blocks 25/8 (Jotun field) and 25/11 (Balder 

and Grane fields) and along the western margin of the Utsira High 

to form a combination of stratigraphic and structural traps. Marine 

sands of Middle and Late Jurassic age, typically present in rotated 

fault blocks, constitute another important play. 

Geochemical analyses show that the Upper Jurassic Draupne 

Formation has a good potential for oil generation along the entire 

western margin and northern nose of the Utsira High. Both upper 

and lower Draupne source intervals along the western graben margin, 

however, contain more terrigenous kerogen than in the eastern 

part of the graben. Such change in organic facies within the 

Draupne source interval naturally results in a higher proportion of 

gas generation and the possibility for generating a more waxy crude 

than typically encountered in the Viking Graben. Detection and 

characterization of oil and gas shows within the Tertiary section 

permit mapping of migration entry points from the Jurassic source 

rocks and help delineate secondary and tertiary migration pathways 

within the Paleocene–Eocene play. 

INTRODUCTION 

In this article, we examine the hydrocarbon systems within the 

southern part of quadrants 24 and 25 and the northern part of quadrants 

15 and 16 in the Norwegian North Sea (Figure 1). We have 

Copyright 2001. The American Association of Petroleum Geologists. All rights reserved. 

Manuscript received January 26,1999; revised manuscript received June 19,2000; final acceptance 

August 31,2000. 

AAPG Bulletin, v. 85, no. 5 (May 2001), pp. 861–883 861 

AUTHORS 

Gary H. Isaksen ExxonMobil Upstream 

Research Company, 3120 Buffalo Speedway, 

Houston, Texas, 77252; 

ghisaks@upstream.xomcorp.com 

Gary H. Isaksen is research supervisor for 

petroleum geochemistry and source rock modeling 

with ExxonMobil Upstream Research Company. 

Isaksen graduated from the University of Bergen, 

Norway, with an M.S. degree and a Ph.D. in 

petroleum geochemistry and petroleum geology. 

Since joining Exxon in 1985, the major themes of 

his work have been integration of geology and 

organic geochemistry, molecular geochemistry 

research, risking of play elements, and seep and 

production geochemistry. During 1993–1995 he 

worked established and frontier plays within United 

Kingdom and Norwegian territories, and during 

1997–1999 he worked on regional- and prospectscale 

oil and gas assessments within Azerbaijan, 

Turkmenistan, Uzbekistan, Kazakhstan, and Russia, 

as well as production geochemistry within fields of 

the South Caspian basin. His current geoscience 

focus is on applied research and the transfer of 

geochemical technologies within ExxonMobil’s 

exploration, development, and production 

functions. 

K. Haakan I. Ledje Esso Norge AS, 

N-4033 Forus, Norway; 

haakan.karl.ledje@exxonmobil.com 

Haakan Ledje is a senior geologist with Esso Norge 

in Stavanger, Norway. He received his B.Sc. degree 

in sedimentology in 1983 from the University of 

Lund, Sweden, and M.Sc. degree in sedimentology 

and tectonics in 1985 from the University of 

California, Los Angeles. He also received an MBA 

degree in 1993 from the Norwegian School of 

Management, Oslo, Norway. He has broad 

experience with hydrocarbon systems studies on 

the Norwegian Continental Shelf. During 1998– 

1999 he was the project leader for ExxonMobil’s 

play and prospect evaluation offshore mid-Norway. 

Ledje has special expertise in source rock quality 

assessment and hydrocarbon migration analyses. 

ACKNOWLEDGEMENTS 

This article is published by permission of Esso 

Norge a.s. and Enterprise Oil Norwegian a.s. We 

also wish to acknowledge Robertson Research International 

Ltd., GeoLab Nor a.s., Saga Petroleum 

a.s., and Conoco Norway Inc. for permission to use 

some of their geochemical data in this article.

Figure 1. Location map of 

study area. Samples were obtained 

from Norwegian quadrants 

24 and 25 and the northern 

part of quadrants 15 

and 16. 

focused our attention on the prospectivity in the Utsira 

High area, which is a prolific hydrocarbon province, 

with discovered, producible reserves estimated at 1.0– 

1.5 billion standard bbl. The main group of fields 

within this area includes Balder, Grane, Jotun, and 

Heimdal. This area continues to be prospective; Esso 

Norge in 1997 alone made a series of successful smaller 

discoveries including 25/8–10, 25/8–11, and 25/10–8. 

Most oil and gas discoveries to date have been within 

the Eocene and Paleocene submarine-fan sands (Figure 

2). Recent exploration has tested the prospectivity of 

the Jurassic play along the eastern margin of the graben. 

An understanding of the source rockquality 

within the drainage area, hydrocarbon migration pathways, 

and the location of migration entry points into 

Tertiary reservoirs is critical to future exploration 

within this play. The primary source rocks in the area 

are organic-rich shales of the Kimmeridgian to Vol- 

862 Utsira High Area (Norwegian North Sea) 

gian–Ryazanian Draupne Formation. The Oxfordian 

Heather Formation forms a secondary source. Regional 

studies of Draupne (Kimmeridge Clay) and Heather 

formations source rockfacies and hydrocarbon distributions 

in this part of the Viking Graben have been 

carried out by several researchers. Early overviews include 

those by Skarpnes et al. (1981), Barnard and 

Cooper (1981), and Barnard et al. (1981), who reported 

on source rockquality variations from bulkkerogen 

and pyrolysis data throughout platform and graben 

areas. Goff (1983), Cornford (1984), Field (1985), 

Cooper and Barnard (1984), Thomas et al. (1985), and 

Harris and Fowler (1987) followed with more detailed 

studies as more data became available. For example, 

Thomas et al. (1985) carried out geochemical characterization 

of cores taken at a variety of structural positions 

in the basin and at different thermal maturity 

levels. A common observation from the regional stud-

Figure 2. Lithostratigraphy of the greater Utsira High area. 

Significant discoveries have been made in the Paleocene Balder, 

Heimdal, and Ty formations and in the Jurassic Draupne and 

Hugin formations. The Upper Jurassic Draupne and Heather formations 

are the main source rocks for oil and gas. 

ies published during the early to mid-1980s was that 

the Draupne Formation indeed showed organic facies 

variations but that such intra-Draupne variability (Huc 

et al., 1985) was only a secondary influence on the 

distribution of oil-prone and gas-prone areas in the 

North Sea. Source rockthermal maturity was viewed 

as the primary control on oil vs. gas. 

Cooper et al. (1995) provided a more detailed picture 

of biomarker and stable carbon isotopic compositions 

for the Kimmeridge Clay, pointing out that the 

organic enrichment was mostly a function of dysaerobic 

to anaerobic development within submarine rifts 

and associated sills. Controls on organic-facies development 

of the Draupne Formation were modeled by 

Miller (1990), using paleoenvironmental, geochemical, 

and petrophysical data sets, whereas Ungerer et al. 

(1985) modeled oil and gas yields and migration pathways 

in the Frigg area. 

Coastal plain and deltaic units in the Middle Jurassic 

Brent and Sleipner/Hugin formations are prevalent 

in the North Viking Graben and South Viking 

Graben, respectively. Such geographically extensive 

coaly rocks, however, are not thought to be present in 

the greater Utsira High area. 

The organic-rich Permian Kupferschiefer Formation 

was also deposited this far north in the Viking Graben 

(e.g., well 25/10–2), but is generally too thin to 

yield significant volumes of oil and gas. Petroleum geochemical 

studies of the Kupferschiefer Formation (aka 

Marl Slate) were reported by Dungworth (1972) and 

Gibbons (1978), who both recognized its source rock 

potential. 

Study Objectives 

The main objectives of this study were to (1) characterize 

and map the regional source rockquality, 

(2) measure, and predict beyond points of control, oil 

vs. gas yields from regionally extensive source rocks, 

and (3) correlate the molecular signatures from shows 

and stains to assess their likely origin and secondarymigration 

and tertiary-migration pathways. 

GEOLOGICAL SETTING 

The Utsira High is a large basement high, flanked by 

the Viking Graben to the west and the Stord Basin to 

the east. The present structural configuration was inherited 

from extensional tectonism that occurred in 

the late Paleozoic and Mesozoic. At the end of the 

Isaksen andLedje 863

Rotliegende, two large intracratonic basins occupied an 

area stretching from the Republic of Poland and northern 

Germany to the middle parts of the Viking Graben. 

The so-called northern Permian Basin is thought to 

have been invaded by marine waters from the 

Norwegian–Greenland Sea in the north, thus forming 

the Zechstein Sea. The relatively shallow water depth 

of large parts of the area (less than 250 m according to 

Smith [1980] and Gibbons [1987]), combined with an 

arid climate, led to elevated salinity levels that could 

host only a few adaptable species (Paul, 1986a) and a 

chemically stratified water column (Hirst and Dunham, 

1963). These resultant organic-rich shales constitute 

the Kupferschiefer Formation. During the latest 

Permian the global sea level was at a significant low 

due to cooling and contraction of the oceanic lithosphere 

(Ziegler, 1988). Over much of the northern 

Permian Basin, the Kupferschiefer Formation is recorded 

as a thin (0.5 m) blackshale (Oszczepalski, 

1986; Paul, 1986b;). In well 25/10–2 in the Norwegian 

North Sea it occurs as a 5 m section and is readily identified 

by the gamma-ray logging tool because of its high 

content of radioactive elements. 

The Triassic was a period of accelerated crustal extension 

with the formation of large, rotated fault 

blocks. Rocks of this age within the Viking Graben are 

typically nonmarine clastics with development of red 

beds in an arid to semiarid climate. Subsequent rifting 

and subsidence during the Jurassic Kimmerian tectonic 

phases resulted in the present structure of the graben. 

The largest pulse of rifting associated with the most 

rapid phase of extension occurred during the Middle 

Jurassic (mid-Kimmerian phase) (Curtin and Ballestad, 

1986). Erosion of the uplifted rift flanks led to deposition 

of nonmarine sandstones on the western flankof 

the Utsira High. These Middle Jurassic sandstones are 

important reservoir targets. 

Establishment of the rift system in the Late Jurassic 

coupled with eustatic sea level rise led to widespread 

transgression and deep-water sedimentation 

(Ziegler, 1988). Under these conditions the Kimmeridgian 

to Ryazanian organic-rich shales of the 

Draupne Formation were deposited. These shales are 

the primary source rocks in the Viking Graben. Concurrently, 

the western margin of the South Viking Graben 

experienced extensive and rapid syntectonic sedimentation 

from the graben scarps resulting in 

mass-flow sediments that thin abruptly eastward and 

interfinger with the organic-rich shales (Figure 3). During 

the earliest Cretaceous a new rifting phase (late 

Kimmerian phase) affected the area. This phase reac- 


tivated existing faults and created further fault-block 

relief. This late Kimmerian rift phase was mostly concentrated 

along the major north-south fault trend to 

the west, resulting in an asymmetric Upper Jurassic– 

earliest Cretaceous basin. More uniform subsidence 

occurred in Cretaceous and Tertiary times (Curtin and 

Ballestad, 1986) 

The dominant Tertiary event was the deposition 

of Paleocene and lower Eocene deep-marine sandstones. 

These sands were shed from the uplifted Shetland 

Platform to the west and deposited into the basin 

by eastward-prograding deltaic complexes and turbidity 

currents during low stands of sea level. The Paleocene 

and Eocene sands are the primary reservoir targets 

in the Utsira High area. 

SAMPLES ANALYZED 

Samples of organically enriched Jurassic shales were 

collected from wells in the Norwegian quadrants 15, 

16, 24, and 25 (Table 1). The study is comprehensive 

in that 246 samples were analyzed for organic richness 

by total organic carbon (TOC), 239 samples were analyzed 

for source quality and thermal maturity by 

Rock-Eval pyrolysis, and 447 readings were taken of 

vitrinite reflectance from 12 well profiles. Selected 

samples were also analyzed for their content of cuttings 

gas for five well profiles (Table 2) and for fluid inclusions 

from 33 samples (Table 3). A special investigation 

of shows and stains was performed on the 18 samples 

listed in Table 4. 

RESULTS AND DISCUSSION 

Source Rock Quality 

Herein, we consider a shale (without hydrocarbon 

staining or coaly fragments) to be oil prone when its 

original TOC and hydrogen index (HI) exceeds about 

1.5 wt. % and 250–300 mg HC/g organic carbon (org 

C), respectively, and its thermal or solvent extract is 

dominated by a well-defined distribution of aliphatic 

compounds. Further supporting evidence includes 

richly fluorescent algal or amorphous organic matter as 

seen by visual kerogen analyses. In our study area, these 

shales also display organic stringers within a laminated 

clay matrix (thin-section analyses). Gas-prone shales in 

the North Sea are characterized by original HI values 

below 200 mg HC/g org C, visually identifiable

Figure 3. Schematic cross section of the Central Viking Graben from north of the Brae fields in the west, through the Gudrun field (15/3), to the Balder field complex in the 

east. The figure depicts structural styles, maturation levels, and preferred hydrocarbon migration pathways and entry points into tertiary reservoirs. Gamma-ray log signatures 

are added for select wells. The location of the cross section is shown in Figure 1. 


Table 1. Geochemical Data for Wells Studied* 

Visual OMT 

Number of 

Readings 

Ro/TOC/HI Rock-Eval Pyrolysis 

Thickness Maturity 

Source Rock 

Rating 

Chemical 

Kerogen 

Classification 

TOCo (%) HI HIo TOC 

(%) 

Vitrinite GCData 

Gas-Prone Pr/Ph CPI 

Intertinite 

Coal 

Liptinite 

Oil-Prone 

Ro (%) LOM 

Net 

(m) 

Net 

(m) 

Base 

(m) 

Top 

(m) 

Well Zone 

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 

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 

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 

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 

C4301 4352 51 51 – 9.8 – – – 1.2 1.0 4.9 4.9 80 100 III Fair gas 0/3/3 

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 


C4180 4450 270 150 0.88 10.2 0% 0% 100% 5.2 5.2 83 100 III Good gas 14/7/4 

D 4450 4452 72 72 – 10.6 – – – 1.5 1.0 5.5 5.5 105 150 III Good gas 0/2/1 

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 

C3543 3553 10 10 – 8.2 – – – – – 6.3 6.3 229 300 III-III/II Good oil 0/1/1 

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 

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 

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 

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 

16/1-3 A – B 2707 2707 0 0 – – – – – – – – – – – – – – 

C2707 2717 10 10 – 7.2 95% 5% Tr – – 3.9 3.9 275 300 III/II Fair oil 0/1/1 

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 

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 

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 

D Not penetrated 

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 

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 

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 


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 

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 

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 

C3181 3184 3 3 – – – – – – – – – – – – – 

D 3184 3185 1 1 – – – – – – – – – – – – – 

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 

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 

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 

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 

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 

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 


*Zones A B, upper Draupne Fm; Zone C, lower Draupne Fm; Zone D, Heather 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 

Well 

Depth Interval 

(m) Age Interval 

16/1-1 350–3000 Pleistocene–Upper Cretaceous 

16/1-2 300–3000 Pleistocene–Rotliegende (Permian) 

16/1-3 2000–3200 Eocene–Zechstein (Permian) 

25/8-2 200–2600 Pleistocene–Triassic 

25/10-2 2250–3200 Undiff. Tertiary–Rotliegende 

Table 3. Samples Analyzed for Possible Content of Fluid 

Inclusions* 

Well Depth (m) Formation or Age Sample Type 

16/1-1 2321 Heimdal Core 








16/1-2 2102 Heimdal Cuttings 



16/1-2 2240 Upper Jurassic Cuttings 






16/1-2 2273 Late Jurassic Cuttings 

16/1-2 2423 Triassic(?) Cuttings 















*Courtesy of R. J. Pottorf, ExxonMobil Upstream Research Company. 

Table 4. Samples Selected for Thermal and Solvent 

Extraction because of Identified Shows and Stains 

Well Depth (m) Sample Type 

16/1-2 2100 Shale 

16/1-2 2130 Shale 

16/1-2 2250 Shale/silt/sandstone 

16/1-2 2102 Silty shale 



25/10-2 RE 1983 Shale 

25/10-2 RE 2013 Shale 

25/10-2 RE 2682 Sandstone 

25/10-2 RE 2713 Sandstone 

25/10-2 RE 3007 Shale (Kupferschiefer) 

25/10-2 RE 3009 Conglomerate 

25/10-2 RE 3037 Conglomerate 

16/1-1 1920 Shale/silt 

16/1-1 1936 Shale/silt 

16/1-1 2530 Silt/shale 

16/1-1 2667 Silt/sandstone 

16/1-1 2743 Sandstone/shale 

vitrinitic macerals, and an aromatic-rich composition. 

Assessment of the oil vs. gas potential of humic coals 

is somewhat more complex. Middle Jurassic humic 

coals in the North Sea are primarily gas prone but do 

have the capability to expel aliphatic-rich, volatile oil 

(Isaksen et al., 1998a, b). Such coals are known from 

the Sleipner/Hugin and Brent delta systems to the 

south and north of our study area, respectively. No 

humic coals are thought to be present in the area of 

the Viking Graben to the west of the northern Utsira 

High. 

The primary source rockin the Utsira High area is 

the organic-rich, oil-prone, Kimmeridgian to Volgian– 

Ryazanian Draupne Formation. A secondary source 

rock, which has poor to fair potential for oil, is the 

Oxfordian Heather Formation. The Permian Kupferschiefer 

source is known to extend this far north and 

was penetrated by well 25/10–2. Although the Kupferschiefer 

shale contains a predominance of oil-prone 

algal and amorphous organic matter, the lackof sufficient 

source volume precludes it from contributing 

with any significance to the reservoired oils in this area. 

No contribution from the Kupferschiefer Formation 

was observed among the biomarkers of the reservoired 

oils. Furthermore, molecular signatures in oils and 


gases in the area do not suggest presence of Middle 

Jurassic woody/coaly source rocks. 

During the early Callovian a marine transgression 

tookplace throughout the Viking Graben. The relative 

rise in sea level continued into the earliest Cretaceous 

with deposition of time-transgressive marine shales of 

the Draupne Formation. Pyrolysis, solvent extraction, 

and visual kerogen data (Table 1) show that these 

shales contain oil-prone kerogen that has predominantly 

liptintic organic matter in the form of marine, 

algal bodies and lipid-rich amorphous material. The 

oil-prone nature of the amorphous kerogen is supported 

by elevated hydrogen indices (400 mg HC/g 

org C) and paraffinic compositions for those samples 

where the amorphous material accounts for the bulk 

of the kerogen. We do not imply a common origin for 

the algal and amorphous material. Although some percentage 

of the amorphous material may be linked to 

an algal origin through bacterial degradation (seen as 

severely degraded algal bodies), the bulkof the amorphous 

material may indeed have been enriched by 

other mechanisms, such as a predominantly bacterial 

origin or a preferential adsorption of amorphous material 

on certain clays (Mayer, 1994). For the most part, 

these shales are interpreted to have accumulated under 

anoxic bottom-water conditions that helped preserve 

their oil-prone nature. The presence of finely laminated 

shales suggests a lackof, or low abundance of, 

grazing or burrowing organisms. Oil-prone organic 

matter may also be preserved under suboxic conditions 

(Isaksen and Bohacs, 1995). 

From its wire-line log response (gamma-ray, resistivity, 

and sonic log signatures), we subdivided the 

Draupne Formation into an upper and lower unit (Figure 

4). The Upper Jurassic sequence on the west side 

of the Viking Graben contains extensive mass-flow 

sediments in the Brae Formation, representing rapid 

syntectonic sedimentation from the graben escarpment 

(Figure 5). The sands of the Brae Formation are interbedded 

with open-marine sediments of the Draupne 

Formation and pinch out eastward (Figure 3). As a result, 

the Upper Jurassic has a complex lithofacies distribution 

and has seen a dilution of the oil-prone kerogen 

of the basinal Draupne shale by land-derived 

gas-prone kerogen, especially along the western graben 

margin. Although such mass-flow deposits can oxygenate 

anoxic sediments or anoxic and stratified bottom 

waters, the presence of low amounts of oxygen is not 

considered detrimental to preservation of organic matter 

(Heinrichs and Reeburgh, 1987; Lee, 1992). In our 

opinion, the type of organic matter exerts a far greater 


control on oil vs. gas potential than does the oxidation 

of organic matter within the dysoxic zone. 

Interpretations of seismic data and wire-line log responses 

for the Upper Jurassic sediments enabled the 

construction of an Upper Jurassic isopach map as 

shown by Figure 6. This has been extended with earlier 

work (Isaksen et al., 1997) to include the South Viking 

Graben in the greater Sleipner–Tiffany–Brae area. In 

this context, the Upper Jurassic isopach thicknesses 

represent the sedimentary section from base Callovian 

to base Cretaceous. In the graben area, between the 

Balder and Gryphon fields, the Upper Jurassic attains 

thicknesses of 3 km, of which a considerable thickness 

constitutes the coarser clastics shed off from the East 

Shetland Platform. 

Rock-Eval pyrolysis and TOC analyses (Table 1) 

were carried out on 14 wells within the greater Utsira 

High area to evaluate the organic richness, quality, and 

thermal maturity of source intervals. To compare and 

assess source rocks, which are currently at different 

maturities, we used a technique derived from the work 

of Cooles et al. (1986) and Pepper (1991), whereby 

measured hydrogen index (HI) and TOC values are 

back-calculated to their original (immature) HI o and 

TOC o values according to their thermal history. The 

oil vs. gas potential of these rocks (Figure 7) follow the 

definitions discussed previously. 

The HI is commonly used as an approximation of 

the hydrogen content of the kerogen and thus as an 

indicator of the source rockquality in terms of oilgeneration 

vs. gas-generation potential. This is not necessarily 

the case for source rocks that have a predominance 

of terrigenous higher plant organic matter (type 

III) because resinite macerals can contribute to the HI 

value but have a poor potential for generation of C 8 

aliphatic hydrocarbons (Isaksen et al., 1998a). The HI 

can be plotted against the T max to classify kerogen 

types and evaluate the level of thermal (organic) maturity 

(Figure 8). This chemical kerogen classification 

shows that both upper and lower Draupne source intervals 

along the western graben margin contain more 

type III and III/II kerogen than in the eastern part of 

the graben (Figure 9A, B). This is in agreement with 

the expected strong terrigenous influx of woody material 

associated with the rapid syntectonic sedimentation 

from the graben scarps. The eastward extension 

of type III kerogen seems to be associated with the easternmost 

extension of mass-flow sediments from the 

western graben margin. 

To further investigate the indications of dilution of 

the oil-prone kerogen of the Draupne shale along the

western graben margin, the content of visual organic 

matter type (OMT) was plotted for the analyzed wells 

(Figure 10A, B). Wells along the eastern margin consistently 

show a higher content of oil-prone liptinite 

kerogen macerals for both the upper and lower 

Draupne formations. Wells along the western margin 

of the graben conversely have more vitrinite (gas- 

Figure 4. Subdivision of the 

Jurassic sedimentary section 

based on wire-line log signatures. 

The logs shown are 

gamma-ray, sonic, and resistivity. 

The right column shows the 

calculated percent TOCbased 

on the technique by Passey et 

al. (1990). 

prone) kerogen content. Incorporation of visual kerogen 

data allows the interpreter to better assess whether 

the oil-prone vs. gas-prone nature of the source rockis 

primarily due to organic matter type or organic matter 

degradation through severe oxidation. 

The ratings of both upper and lower Draupne 

source intervals (Figure 11A, B) indicate that a 


Figure 5. Main depositional 

environments for the Upper Jurassic 

Draupne Formation. The 

extensive mass-flow sediments 

represent syntectonic sedimentation 

from the western graben 

escarpment. As a result, offshore, 

marine shales are interbedded 

with mass-flow sediments. 

Shoreface sedimentation 

dominated around the Utsira 

High. 

predominantly gas-prone organic facies was deposited 

in the graben west of blocks 16/1 and 25/10. We interpret 

the decrease in oil potential to be mainly due 

to the syntectonic influx of turbidites with terrigenous 

organic matter during the Kimmeridgian period. The 


magnitude of a potential decrease in the oil-prone nature 

of the kerogen during accumulation under more 

oxic conditions (i.e., oxygen-rich turbidite currents) 

remains unresolved. Laminated blackshales sampled 

from wells drilled on structural highs suggest a sparse

Figure 6. Isopach map (contours 

given in meters) of the 

Upper Jurassic representing the 

section between the base Callovian 

and the base Cretaceous. 


Figure 7. Source richness and 

source quality chart for the upper 

and lower Draupne formations. 

Each data point represents 

the average weighted 

values from cuttings or core 

samples from the interval. The 

four samples from the Lower 

Jurassic at the base of the chart 

denote HI values less than 100 

mg/g organic carbon. 

benthic fauna at these locations. It seems probable, 

however, that the Draupne shales experienced a higher 

degree of dilution by coarser clastics as well as periodic 

oxygenation from turbidite currents in basinal positions 

connected with debris and turbidite flows from 

the western basin margin. For the upper Draupne, the 

gas-prone organic facies is confined to block24/12, 

whereas for the lower Draupne gas-prone organic facies 

also extends into block15/3 to the south. The 

potential for the Draupne Formation to generate oil 

improves toward the east, from a mixed gas-prone and 

oil-prone organic facies in the eastern parts of blocks 

24/12 and 15/3 to an oil-prone organic facies closest 

to the Utsira High. At the time of our study, no source 

rocksamples were available from the Beryl field (UK 

9/13) source kitchen (north of 5930N). 

Source Rock Thermal Maturity 

T max measurements from Rock-Eval pyrolysis span a 

range from immature (430C) to fully mature (455C) 

(Figure 8). Care was taken to avoid T max data derived 

from shales stained by in-migrated hydrocarbons (typ- 


ically seen as a bimodal S 2 peak). As a further control 

on the thermal maturity vs. depth trend, comparison 

was made with vitrinite reflectance (% R o) measurements 

on Middle Jurassic coals and coaly shales from 

locations throughout the entire Viking Graben where 

such rocks are present (Sleipner/Hugin and Brent delta 

systems). The resultant thermal maturity vs. depth relation 

is illustrated in Figure 12. T max and % R o data 

suggest that early to peakoil generation from the 

Draupne shale occurs between an R o equivalent of 

0.62% and 0.88% corresponding to depths of 3400– 

4400 m below sea floor. Late oil generation occurs at 

R o 1.1%, corresponding to a depth of approximately 

5000 m below sea floor. 

SECONDARY MIGRATION OF 

OIL AND GAS 

Evidence for Migration into Tertiary Strata 

Proof of hydrocarbon migration from Jurassic source 

rocks to Tertiary reservoir rocks is given by the accu-

mulations at the Balder, Hanna, Grane, Jotun, and 

Ringhorne fields. In other areas, evidence for migration 

into the Tertiary and Cretaceous sections is shown by 

the presence of oil shows and stains or thermogenic gas 

within an otherwise thermally immature section. Core 

and cuttings samples were analyzed for the presence of 

inclusions with possible hydrocarbons. Molecular characterization 

of such hydrocarbon inclusions can provide 

important insights to paleomigration events (Isaksen 

et al., 1998b). In this study, no fluid inclusions 

were found (Table 3). The absence of fluid inclusions 

is due to paleotemperatures and present-day temperatures 

cooler than required for the formation of inclusions. 

One such process, quartz overgrowth, does not 

start until temperatures of approximately 80C are 

reached. 

Thermogenic gases were discovered in the 

Paleocene–Eocene of wells 16/1–1 (Figure 13), 16/1– 

Figure 8. Evaluation of source 

rock thermal maturity and quality. 

Roman numerals denote the 

predominant organic-matter 

type, whereas thermal maturity 

levels are given by Rock-Eval 

T max values and vitrinite reflectance 

(% R o). 

2 (Figure 14), and in the thermally immature Upper 

Jurassic sections of wells 16/1–2, 16/1–3 (Figure 15), 

and 25/8–2 (Figure 16). Thermogenic hydrocarbon gas 

is also present within the Upper Cretaceous to Upper 

Jurassic section (2200–3200 m) in well 25/10–2RE 

and is especially pronounced within the Rotliegende 

sandstones (Permian) at 2900–3000 m (Figure 17). 

Three rocksamples from the Permian section (one 

from 3007 m within the Kupferschiefer shale and two 

within the Rotliegende conglomerates at 3009 and 

3037 m) were analyzed by thermal evaporation–gas 

chromatography) (Figure 18), pyrolysis–gas chromatography, 

solvent extraction, liquid chromatography, 

and gas chromatography of the saturate hydrocarbon 

fraction (Figure 19) to checkfor presence of 

free hydrocarbons and to ascertain whether a secondary 

migration pathway may exist within the Rotliegende 

at this location. The thermal evaporation–gas 


Figure 9. Classification of kerogen quality within the (A) upper Draupne and (B) lower Draupne formations based on the HI data 

shown in Figure 7. Note how areas that have higher predicted contents of type III kerogen conform to areas affected most by 

syntectonic mass-flow sediments along the western graben margin. 

chromatography data do not show significant quantities 

of free hydrocarbons. Solvent extractable (free) hydrocarbons 

observed within the conglomerates are 

likely the results of short-distance migration (2–30 m) 

from the Kupferschiefer organic-rich shales. 

Migration Model 

Marine source rocks of the Upper Jurassic Draupne 

Formation thicken from the Utsira High westward into 

the Viking Graben (Figure 3). Hydrocarbons are likely 

to have been generated in large amounts west of the 

Utsira High. Maturation studies indicate that hydrocarbon 

expulsion and migration started during the latest 

Cretaceous and continues to the present day 

(Thomas et al., 1985; Dahl et al., 1987; Isaksen et al., 


1998b). Regional migration cell mapping at the Middle 

Jurassic level in the Viking Graben indicates a general 

basin to margin pathway. These migration pathways 

intersect faults at which point vertical leakage through 

the Cretaceous section is key to charging reservoir intervals 

in the Tertiary. 

Figure 3 illustrates that the Jurassic source intervals 

are currently mature for generation of hydrocarbons 

(% R o 0.6) in the center of the graben. The 

proposed model for migrating hydrocarbons into the 

Tertiary plays in the Utsira High area involves migration 

at the Draupne source level into the adjacent Middle 

Jurassic Hugin Formation and Sleipner Formation 

sandstones. Longer distance secondary migration involves 

eastward lateral migration through the Jurassic 

sandstone conduits. Across the relatively small faults

Figure 10. Classification of kerogen quality within the (A) upper Draupne and (B) lower Draupne formations based on the content 

of liptinitic, oil-prone organic matter from visual kerogen evaluations. 

in the Jurassic section, hydrocarbons migrate up along 

the fault plane and into Jurassic conduits on the highside 

blockor migrate through the fault plane and into 

juxtaposed sandstones. In general hydrocarbons migrate 

laterally in this fashion until succeeded by vertical 

migration up fault planes along the Utsira High westbounding 

fault system. 

Major migration entry points available were faults 

cut through the entire Cretaceous succession in the 

eastern part of the fault system as it steps up toward 

the Utsira High. Where Jurassic carrier beds and Tertiary 

reservoirs are connected, hydrocarbons continue 

to move updip into available independent closures or 

into combined stratigraphic and structural traps at the 

Tertiary level. The migration model is supported by 

Tertiary hydrocarbon shows (e.g., 16/1–1 and 16/1– 

2) and accumulations (e.g., Balder field) located east 

of such migration entry points. Migration pathways 

through low-permeability conduits (e.g., ratty sands in 

the Upper Jurassic and fractured chalks in Cretaceous) 

are likely to be less efficient. The absence of faulting in 

the Cretaceous section is believed to effectively prevent 

migration of hydrocarbons into tertiary reservoirs 

in the central part of the graben (e.g., 15/3–1 and 15/ 

3–3). 

EXPLORATION SIGNIFICANCE 

The key observations from this study are the following: 

• Both upper and lower Draupne formations are effective 

source rocks within the greater Utsira High 

area. 


Figure 11. Expected hydrocarbon type generated from mature (A) upper Draupne and (B) lower Draupne source rocks. The area 

outlines are based on TOC o and HI o calculations. 

• The source rockquality of the Draupne Formation 

ranges widely from gas-prone along the western margin 

of the graben to oil-prone in the east. 

• The gas-prone organic facies is believed to be associated 

with terrigenous input from westerly derived 

mass-flow sediments, which have both diluted the 

oil-prone organic matter and introduced a more oxic 

depositional environment. 

• Migration is considered a significant riskfactor for 

any Tertiary prospect west of the Utsira High mainbounding 

fault. 

The exploration significance of these observations 

lies in their use as an aid to predict whether an area is 

likely to be dominated by oil or gas reserves. For a prospect 

on the Utsira High to be sheltered from gas influx 


it may be concluded that three requirements need to 

be satisfied: (1) the Draupne Formation within the 

drainage area needs to be of an oil-prone nature, (2) the 

oil-prone source rockmust not be within the gasgeneration 

window, and (3) migration access to the 

gas-prone source kitchen west of the Utsira High area 

needs to be denied. It follows that it is critical to understand 

the migration entry points into the Tertiary 

section. In the graben, downdip from the Utsira High, 

a thickCretaceous section and lackof penetrating 

faults prevent effective migration from the Jurassic into 

Tertiary traps. Exploration efforts at Tertiary levels 

should therefore be focused close to the Utsira High in 

areas that have thin Cretaceous sediments and where 

basin-bounding faults are present to provide the necessary 

migration route.

Figure 12. Regional assessment of thermal maturity vs. depth 

based on measurements of vitrinite reflectance from humic 

coals and shales that have terrigenous macerals. 

CONCLUSIONS 

• Chemical kerogen classification and source rock pyrolysis 

show that both upper and lower Draupne 

source intervals along the western graben margin 

contain more terrigenous (type III and III/II) kerogen 

than in the eastern part of the graben. Such 

change in organic facies within the Draupne source 

rocknaturally results in a higher proportion of gas 

generation upon maturation. 

• Good potential for oil generation from Draupne Formation 

source rocks exists along the entire western 

margin and northern nose of the Utsira High. 

• Thermogenic-hydrocarbon gas was encountered in 

the Upper Cretaceous and Tertiary in wells 16/1–1, 

16/1–2, 16/1–3, 25/8–2, and 25/10–2. These gases 

have migrated into the Cretaceous and Tertiary sedimentary 

section from deeper, mature, sections of 

the Draupne and Heather formations. 

• Migration entry points into the Tertiary section are 

provided by faults cutting through the base Paleocene. 

Unfaulted Cretaceous sections more likely act 

as a barrier to migration into Tertiary reservoirs. 

• No hydrocarbon fluid inclusions were detected in 

the samples analyzed. The lackof fluid inclusions is 

most likely due to the low thermal maturity level of 

the Tertiary sediments. At most locations the Paleocene 

and Eocene sands are poorly consolidated and 

have not been exposed to the diagenetic temperatures 

required ( 80C) for mineral mobilization 

and the formation of fluid inclusions. 

• Thermogenic liquid hydrocarbons within the Permian 

conglomerates in well 25/10–2 are derived 

from the organic-rich Kupferschiefer shales by shortdistance 

migration. 

APPENDIX: ANALYTICAL METHODS 

Total organic carbon (TOC) and Rock-Eval pyrolysis measurements 

were made on a Leco IR 312 carbon analyzer and Delsi RockEval 

II, respectively. Vitrinite reflectance and visual kerogen analyses were 

analyzed according to standard coal methods. Thermoevaporation 

and pyrolysis–gas chromatography was performed using custombuilt 

systems based on the HP 5790 gas chromatograph (GC) 

equipped with flame-ionization detectors. The thermal extraction 

was done isothermally at 280C for 3 min. The sample was then 

heated at 60C/min to 610C, and the volatiles were trapped in liquid 

nitrogen on the head of the GC column (split 60:1). The GC 

had a 50 m capillary column (5% phenyl-methylsilicone). Initial temperature 

was 20C followed by a heating rate of 4C/min to a final 

temperature of 280C. Cuttings gas, thermal evaporation–gas chromatography, 

and pyrolysis analyses were carried out at Exxon Production 

Research Company, Houston, Texas. 


Figure 13. Well 16/1–1 profiles 

of cuttings-gas data showing 

gas-wetness and summed 

concentrations of C 1 through C 4 

(vol. %). Gas wetness is calculated 

as 100 [(C 2 C 3 C 4)/ 

(C 1 C 2 C 3 C 4)]. Thermogenic 

hydrocarbon gas is 

present at 2000–3000 m, within 

the Paleocene–Eocene. No free 

liquid hydrocarbons were detected 

(samples were analyzed 

from 1920, 1935, 2530, 2667, 

and 2743 m [Table 4]), nor 

were any fluid inclusions detected 


from the Paleocene at depths 

of 2320–2648 m [Table 3]). 

Levels of organic metamorphism 

(LOM) 6 and 8 correlate 

to vitrinite reflectance values of 

0.43% and 0.55%, respectively. 



gas wetness and summed 

concentrations of C 1 through 

C 4. Thermogenic hydrocarbon 

gas is present within Eocene, 

Paleocene, Danian, and Late Jurassic 

at 1700–2500 m. No free 

hydrocarbon liquids were detected 


from 2099, 2130, and 2250 m), 

nor were any fluid inclusions 

observed (analyses within the 

Paleocene at 2102–2490 m). 

878 Utsira High Area (Norwegian North Sea)

Figure 15. Well 16/1–3 profiles of cuttings-gas data showing 

gas wetness and summed concentrations of C 1 through C 4. Thermogenic 

hydrocarbon gas is present within the Upper Jurassic 

interval at 2600–2800 m. 

Figure 16. Well 25/8–2 profiles of cuttings-gas data showing 

gas wetness and summed concentrations of C 1 through C 4. Thermogenic 

gas is present with the immature Upper Jurassic from 

1500 m to total depth drilled. 



gas wetness and summed 

concentrations of C 1 

through C 4.

Figure 18. Well 25/10–2RE. 

Thermoevaporation (S 1) of core 

samples from (A) Kupferschiefer 

shale at 3007 m (sample 

202087A), (B) Rotliegende conglomerate 

at 3009 m (sample 

202087B), and (C) Rotliegende 

conglomerate at 3037 m (sample 

202087C). S 1 represents the 

free hydrocarbons in the rock. 

880 Utsira High Area (Norwegian North Sea)

Figure 19. Well 25/10–2RE. 

Gas chromatograms of the saturate 

hydrocarbon fractions 

from (A) Kupferschiefer shale at 

3007 m (sample 202087A), (B) 

Rotliegende conglomerate at 

3009 m (sample 202087B), and 

(C) Rotliegende conglomerate 

at 3037 m (sample 202087C). 


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