Source rock quality and hydrocarbon migration pathways within the greater Utsira High area, Viking Graben, Norwegian North Sea

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

Source rock quality andhydrocarbon migrationpathways within the greaterUtsira High area, VikingGraben, Norwegian North SeaGary H. Isaksen and K. Haakan I. Ledje

ABSTRACT

The greater Utsira High area is located within the southern part ofquadrants 24 and 25 and the northern part of quadrants 15 and 16in the Norwegian North Sea. In this part of the Viking Graben themain exploration play is the submarine fan sands of Paleocene andEocene age. These sands (Balder, Heimdal, and Ty formations)pinch out to the east in blocks 25/8 (Jotun field) and 25/11 (Balderand Grane fields) and along the western margin of the Utsira Highto form a combination of stratigraphic and structural traps. Marinesands of Middle and Late Jurassic age, typically present in rotatedfault blocks, constitute another important play.

Geochemical analyses show that the Upper Jurassic DraupneFormation has a good potential for oil generation along the entirewestern margin and northern nose of the Utsira High. Both upperand lower Draupne source intervals along the western graben mar-gin, however, contain more terrigenous kerogen than in the easternpart of the graben. Such change in organic facies within theDraupne source interval naturally results in a higher proportion ofgas generation and the possibility for generating a more waxy crudethan typically encountered in the Viking Graben. Detection andcharacterization of oil and gas shows within the Tertiary sectionpermit mapping of migration entry points from the Jurassic sourcerocks and help delineate secondary and tertiary migration pathwayswithin the Paleocene–Eocene play.

INTRODUCTION

In this article, we examine the hydrocarbon systems within thesouthern part of quadrants 24 and 25 and the northern part of quad-rants 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 acceptanceAugust 31, 2000.

AUTHORS

Gary H. Isaksen � ExxonMobil UpstreamResearch Company, 3120 Buffalo Speedway,Houston, Texas, 77252;[email protected]

Gary H. Isaksen is research supervisor forpetroleum geochemistry and source rock modelingwith ExxonMobil Upstream Research Company.Isaksen graduated from the University of Bergen,Norway, with an M.S. degree and a Ph.D. inpetroleum geochemistry and petroleum geology.Since joining Exxon in 1985, the major themes ofhis work have been integration of geology andorganic geochemistry, molecular geochemistryresearch, risking of play elements, and seep andproduction geochemistry. During 1993–1995 heworked established and frontier plays within UnitedKingdom and Norwegian territories, and during1997–1999 he worked on regional- and prospect-scale oil and gas assessments within Azerbaijan,Turkmenistan, Uzbekistan, Kazakhstan, and Russia,as well as production geochemistry within fields ofthe South Caspian basin. His current geosciencefocus is on applied research and the transfer ofgeochemical technologies within ExxonMobil’sexploration, development, and productionfunctions.

K. Haakan I. Ledje � Esso Norge AS,N-4033 Forus, Norway;[email protected]

Haakan Ledje is a senior geologist with Esso Norgein Stavanger, Norway. He received his B.Sc. degreein sedimentology in 1983 from the University ofLund, Sweden, and M.Sc. degree in sedimentologyand tectonics in 1985 from the University ofCalifornia, Los Angeles. He also received an MBAdegree in 1993 from the Norwegian School ofManagement, Oslo, Norway. He has broadexperience with hydrocarbon systems studies onthe Norwegian Continental Shelf. During 1998–1999 he was the project leader for ExxonMobil’splay and prospect evaluation offshore mid-Norway.Ledje has special expertise in source rock qualityassessment and hydrocarbon migration analyses.

ACKNOWLEDGEMENTS

This article is published by permission of EssoNorge a.s. and Enterprise Oil Norwegian a.s. Wealso wish to acknowledge Robertson Research In-ternational Ltd., GeoLab Nor a.s., Saga Petroleuma.s., and Conoco Norway Inc. for permission to usesome of their geochemical data in this article.

862 Utsira High Area (Norwegian North Sea)

Figure 1. Location map ofstudy area. Samples were ob-tained from Norwegian quad-rants 24 and 25 and the north-ern part of quadrants 15and 16.

focused our attention on the prospectivity in the UtsiraHigh area, which is a prolific hydrocarbon province,with discovered, producible reserves estimated at 1.0–1.5 billion standard bbl. The main group of fieldswithin this area includes Balder, Grane, Jotun, andHeimdal. This area continues to be prospective; EssoNorge in 1997 alone made a series of successful smallerdiscoveries including 25/8–10, 25/8–11, and 25/10–8.Most oil and gas discoveries to date have been withinthe Eocene and Paleocene submarine-fan sands (Figure2). Recent exploration has tested the prospectivity ofthe Jurassic play along the eastern margin of the gra-ben. An understanding of the source rock qualitywithin the drainage area, hydrocarbon migration path-ways, and the location of migration entry points intoTertiary reservoirs is critical to future explorationwithin this play. The primary source rocks in the areaare organic-rich shales of the Kimmeridgian to Vol-

gian–Ryazanian Draupne Formation. The OxfordianHeather Formation forms a secondary source. Regionalstudies of Draupne (Kimmeridge Clay) and Heatherformations source rock facies and hydrocarbon distri-butions in this part of the Viking Graben have beencarried out by several researchers. Early overviews in-clude those by Skarpnes et al. (1981), Barnard andCooper (1981), and Barnard et al. (1981), who re-ported on source rock quality variations from bulk ker-ogen and pyrolysis data throughout platform and gra-ben areas. Goff (1983), Cornford (1984), Field (1985),Cooper and Barnard (1984), Thomas et al. (1985), andHarris and Fowler (1987) followed with more detailedstudies as more data became available. For example,Thomas et al. (1985) carried out geochemical charac-terization of cores taken at a variety of structural po-sitions in the basin and at different thermal maturitylevels. A common observation from the regional stud-

Isaksen and Ledje 863

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 andHugin formations. The Upper Jurassic Draupne and Heather for-mations are the main source rocks for oil and gas.

ies published during the early to mid-1980s was thatthe Draupne Formation indeed showed organic faciesvariations but that such intra-Draupne variability (Hucet al., 1985) was only a secondary influence on thedistribution of oil-prone and gas-prone areas in theNorth Sea. Source rock thermal maturity was viewedas the primary control on oil vs. gas.

Cooper et al. (1995) provided a more detailed pic-ture of biomarker and stable carbon isotopic compo-sitions for the Kimmeridge Clay, pointing out that theorganic enrichment was mostly a function of dysaero-bic to anaerobic development within submarine riftsand associated sills. Controls on organic-facies devel-opment of the Draupne Formation were modeled byMiller (1990), using paleoenvironmental, geochemi-cal, and petrophysical data sets, whereas Ungerer et al.(1985) modeled oil and gas yields and migration path-ways in the Frigg area.

Coastal plain and deltaic units in the Middle Ju-rassic Brent and Sleipner/Hugin formations are prev-alent in the North Viking Graben and South VikingGraben, respectively. Such geographically extensivecoaly rocks, however, are not thought to be present inthe greater Utsira High area.

The organic-rich Permian Kupferschiefer Forma-tion was also deposited this far north in the Viking Gra-ben (e.g., well 25/10–2), but is generally too thin toyield significant volumes of oil and gas. Petroleum geo-chemical studies of the Kupferschiefer Formation (akaMarl Slate) were reported by Dungworth (1972) andGibbons (1978), who both recognized its source rockpotential.

Study Objectives

The main objectives of this study were to (1) charac-terize and map the regional source rock quality,(2) measure, and predict beyond points of control, oilvs. gas yields from regionally extensive source rocks,and (3) correlate the molecular signatures from showsand stains to assess their likely origin and secondary-migration and tertiary-migration pathways.

GEOLOGICAL SETT ING

The Utsira High is a large basement high, flanked bythe Viking Graben to the west and the Stord Basin tothe east. The present structural configuration was in-herited from extensional tectonism that occurred inthe late Paleozoic and Mesozoic. At the end of the


Rotliegende, two large intracratonic basins occupied anarea stretching from the Republic of Poland and north-ern Germany to the middle parts of the Viking Graben.The so-called northern Permian Basin is thought tohave been invaded by marine waters from theNorwegian–Greenland Sea in the north, thus formingthe Zechstein Sea. The relatively shallow water depthof large parts of the area (less than 250 m according toSmith [1980] and Gibbons [1987]), combined with anarid climate, led to elevated salinity levels that couldhost only a few adaptable species (Paul, 1986a) and achemically stratified water column (Hirst and Dun-ham, 1963). These resultant organic-rich shales con-stitute the Kupferschiefer Formation. During the latestPermian the global sea level was at a significant lowdue to cooling and contraction of the oceanic litho-sphere (Ziegler, 1988). Over much of the northernPermian Basin, the Kupferschiefer Formation is re-corded as a thin (�0.5 m) black shale (Oszczepalski,1986; Paul, 1986b;). In well 25/10–2 in the NorwegianNorth Sea it occurs as a 5 m section and is readily iden-tified by the gamma-ray logging tool because of its highcontent of radioactive elements.

The Triassic was a period of accelerated crustal ex-tension with the formation of large, rotated faultblocks. Rocks of this age within the Viking Graben aretypically nonmarine clastics with development of redbeds in an arid to semiarid climate. Subsequent riftingand subsidence during the Jurassic Kimmerian tectonicphases resulted in the present structure of the graben.The largest pulse of rifting associated with the mostrapid phase of extension occurred during the MiddleJurassic (mid-Kimmerian phase) (Curtin and Ballestad,1986). Erosion of the uplifted rift flanks led to depo-sition of nonmarine sandstones on the western flank ofthe Utsira High. These Middle Jurassic sandstones areimportant reservoir targets.

Establishment of the rift system in the Late Juras-sic coupled with eustatic sea level rise led to wide-spread transgression and deep-water sedimentation(Ziegler, 1988). Under these conditions the Kim-meridgian to Ryazanian organic-rich shales of theDraupne Formation were deposited. These shales arethe primary source rocks in the Viking Graben. Con-currently, the western margin of the South Viking Gra-ben experienced extensive and rapid syntectonic sedi-mentation from the graben scarps resulting inmass-flow sediments that thin abruptly eastward andinterfinger with the organic-rich shales (Figure 3). Dur-ing the earliest Cretaceous a new rifting phase (lateKimmerian phase) affected the area. This phase reac-

tivated existing faults and created further fault-blockrelief. This late Kimmerian rift phase was mostly con-centrated along the major north-south fault trend tothe west, resulting in an asymmetric Upper Jurassic–earliest Cretaceous basin. More uniform subsidenceoccurred in Cretaceous and Tertiary times (Curtin andBallestad, 1986)

The dominant Tertiary event was the depositionof Paleocene and lower Eocene deep-marine sand-stones. These sands were shed from the uplifted Shet-land Platform to the west and deposited into the basinby eastward-prograding deltaic complexes and turbid-ity currents during low stands of sea level. The Paleo-cene and Eocene sands are the primary reservoir targetsin the Utsira High area.

SAMPLES ANALYZED

Samples of organically enriched Jurassic shales werecollected from wells in the Norwegian quadrants 15,16, 24, and 25 (Table 1). The study is comprehensivein that 246 samples were analyzed for organic richnessby total organic carbon (TOC), 239 samples were an-alyzed for source quality and thermal maturity byRock-Eval pyrolysis, and 447 readings were taken ofvitrinite reflectance from 12 well profiles. Selectedsamples were also analyzed for their content of cuttingsgas for five well profiles (Table 2) and for fluid inclu-sions from 33 samples (Table 3). A special investiga-tion of shows and stains was performed on the 18 sam-ples listed in Table 4.

RESULTS AND DISCUSSION

Source Rock Quality

Herein, we consider a shale (without hydrocarbonstaining or coaly fragments) to be oil prone when itsoriginal TOC and hydrogen index (HI) exceeds about1.5 wt. % and 250–300 mg HC/g organic carbon (orgC), respectively, and its thermal or solvent extract isdominated by a well-defined distribution of aliphaticcompounds. Further supporting evidence includesrichly fluorescent algal or amorphous organic matter asseen by visual kerogen analyses. In our study area, theseshales also display organic stringers within a laminatedclay matrix (thin-section analyses). Gas-prone shales inthe North Sea are characterized by original HI valuesbelow 200 mg HC/g org C, visually identifiable


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Geoc

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Wel

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Thick

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Mat

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Visu

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Vitri

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Gas-

Pron

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CPI

TOC

(%)

TOC o

(%)

HIHI

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Chem

ical

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tion

Sour

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ting

Num

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ofRe

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C/HI

15/3

-1A

�B

3947

4083

136

960.

68.

487

%1%

12%

1.3

1.0

5.6

5.6

324

385

II/III

-III/

IIGo

odoi

l20

/12/

12C

4083

4753

670

410

0.72

9.4

56%

14%

30%

1.4

1.1

5.9

5.9

9610

0III

Good

gas

40/2

3/23

D47

5349

8623

323

31.

0811

.150

%13

%37

%1.

61.

04.

24.

224

24IV

/III

–31

/4/4

15/3

-2A

�B

4236

4301

6565

0.76

9.6

47%

1%52

%1.

31.

04.

14.

113

629

0III

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IIFa

iroi

l/tra

ns30

/8/8

C43

0143

5251

51–

9.8

––

–1.

21.

04.

94.

980

100

IIIFa

irga

s0/

3/3

D43

5244

0048

480.

9410

.535

%5%

60%

1.4

1.4

2.9

2.9

4141

IV-II

I–

3/3/

315

/3-3

A�

B40

1840

1816

216

20.

618.

50%

0%10

0%0.

91.

06.

26.

215

122

0III

-III/

IIFa

iroi

l/tra

ns13

/6/4

C41

8044

5027

015

00.

8810

.20%

0%10

0%5.

25.

283

100

IIIGo

odga

s14

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D44

5044

5272

72–

10.6

––

–1.

51.

05.

55.

510

515

0III

Good

gas

0/2/

115

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A�

B34

9235

4351

510.

588.

275

%8%

17%

1.2

1.0

6.0

6.0

309

400

III/II

-II/II

IGo

odoi

l27

/6/6

C35

4335

5310

10–

8.2

––

––

–6.

36.

322

930

0III

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IIGo

odoi

l0/

1/1

D35

5335

585

5–

8.2

60%

10%

30%

1.0

1.0

5.6

5.6

275

380

II/II

Good

oil

0/1/

116

/1-2

A�

B22

4222

9856

11–

6.8

70%

20%

10%

––

3.7

3.7

490

510

IIGo

odoi

l0/

1/1

C22

9823

9092

920.

487.

074

%14

%12

%1.

51.

13.

43.

446

249

0II-

II/III

Good

oil

19/1

6/16

D23

9024

2434

340.

467.

010

%20

%70

%1.

91.

13.

93.

925

329

0III

/IIFa

iroi

l14

/4/4

16/1

-3A

–B

2707

2707

00

––

––

––

––

––

––

––

C27

0727

1710

10–

7.2

95%

5%Tr

––

3.9

3.9

275

300

III/II

Fair

oil

0/1/

1D

2717

2730

1313

0.50

7.2

––

–1.

81.

24.

14.

128

430

0III

/IIFa

iroi

l40

/3/3

24/9

-1A

�B

4330

4797

467

467

0.94

10.6

41%

3%56

%1.

61.

05.

47.

814

146

0II/

IIEx

cel.

oil

52/2

9/26

C47

9749

0711

0�11

0�1.

1711

.233

%12

%55

%1.

61.

03.

84.

811

232

0III

/II-II

IGo

odoi

l10

/9/9

DN

otpe

netra

ted

24/2

-1A

�B

4055

4094

3939

1.00

10.8

55%

Tr45

%1.

11.

16.

26.

512

220

0III

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IIGo

odga

s4/

7/07

C40

9441

4046

460.

9610

.850

%Tr

50%

1.3

4.9

5.6

119

280

15.7

III-II

I/II

Fair

oil/t

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25/8

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4140

4163

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6145

6530

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40.

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65.

140

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III-II

I/II

Fair

oil/t

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28/2

9/29

C45

6546

4075

750.

9210

.650

%40

%10

%1.

20.

95.

95.

949

49IV

–4/

7/07

D46

4049

5531

531

51.

2811

.632

%22

%46

%1.

61.

14.

54.

515

15IV

/III

–23

/21/

2125

/4-1

A�

B31

7131

8110

100.

426.

050

%50

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––

8.5

8.5

138

138

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8431

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2233

2253

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–6.

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%5%

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01.

07.

47.

457

357

3II

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6/4

C22

5322

563

3–

6.0

95%

5%0%

0.8

1.1

3.6

3.6

240

240

III-II

I/II

Fair

oil/t

rans

0/2/

2D

2256

2297

4141

–6.

090

%10

%0%

1.3

1.1

5.5

5.5

374

374

III-II

I/II

Good

oil

0/8/

825

/7-2

A–

B40

5641

1963

630.

8810

.295

%Tr

5%1.

11.

03.

98.

632

074

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Exce

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C41

1942

9317

445

1.00

10.8

––

–2.

11.

11.

73.

224

558

0II/

III-II

Good

oil

14/2

/2D

4293

4407

114

114

1.14

11.2

75%

10%

15%

2.8

1.1

1.6

5.1

246

830

IIEx

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oil

21/7

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Table 2. Well-Sections Evaluated for Cuttings-Gas Content

WellDepth Interval

(m) Age Interval

16/1-1 350–3000 Pleistocene–Upper Cretaceous16/1-2 300–3000 Pleistocene–Rotliegende (Permian)16/1-3 2000–3200 Eocene–Zechstein (Permian)25/8-2 200–2600 Pleistocene–Triassic25/10-2 2250–3200 Undiff. Tertiary–Rotliegende

Table 4. Samples Selected for Thermal and SolventExtraction because of Identified Shows and Stains

Well Depth (m) Sample Type

16/1-2 2100 Shale16/1-2 2130 Shale16/1-2 2250 Shale/silt/sandstone16/1-2 2102 Silty shale16/1-2 2108 Silty shale16/1-2 2114 Silty shale25/10-2 RE 1983 Shale25/10-2 RE 2013 Shale25/10-2 RE 2682 Sandstone25/10-2 RE 2713 Sandstone25/10-2 RE 3007 Shale (Kupferschiefer)25/10-2 RE 3009 Conglomerate25/10-2 RE 3037 Conglomerate16/1-1 1920 Shale/silt16/1-1 1936 Shale/silt16/1-1 2530 Silt/shale16/1-1 2667 Silt/sandstone16/1-1 2743 Sandstone/shale

Table 3. Samples Analyzed for Possible Content of FluidInclusions*

Well Depth (m) Formation or Age Sample Type

16/1-1 2321 Heimdal Core16/1-1 2321 Heimdal Core16/1-1 2330 Heimdal Core16/1-1 2348 Heimdal Core16/1-1 2419 Heimdal Core16/1-1 2427 Heimdal Core16/1-1 2533 Heimdal Core16/1-1 2648 Heimdal Core16/1-2 2102 Heimdal Cuttings16/1-2 2108 Heimdal Cuttings16/1-2 2114 Heimdal Cuttings16/1-2 2240 Upper Jurassic Cuttings16/1-2 2246 Upper Jurassic Cuttings16/1-2 2252 Upper Jurassic Cuttings16/1-2 2258 Upper Jurassic Cuttings16/1-2 2264 Upper Jurassic Cuttings16/1-2 2270 Upper Jurassic Cuttings16/1-2 2273 Late Jurassic Cuttings16/1-2 2423 Triassic(?) Cuttings16/1-2 2426 Triassic(?) Cuttings16/1-2 2429 Triassic(?) Cuttings25/10-2 1893 Heimdal Core25/10-2 2013 Heimdal Core25/10-2 2014 Heimdal Core25/10-2 2015 Heimdal Core25/10-2 2015 Heimdal Core25/10-2 2023 Heimdal Core25/10-2 2088 Heimdal Core25/10-2 2100 Heimdal Core25/10-2 2102 Heimdal Core25/10-2 2684 Triassic(?) Cuttings25/10-2 2687 Triassic(?) Cuttings25/10-2 2690 Triassic(?) Cuttings

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

vitrinitic macerals, and an aromatic-rich composition.Assessment of the oil vs. gas potential of humic coalsis somewhat more complex. Middle Jurassic humiccoals in the North Sea are primarily gas prone but dohave the capability to expel aliphatic-rich, volatile oil(Isaksen et al., 1998a, b). Such coals are known fromthe Sleipner/Hugin and Brent delta systems to thesouth and north of our study area, respectively. Nohumic coals are thought to be present in the area ofthe Viking Graben to the west of the northern UtsiraHigh.

The primary source rock in the Utsira High area isthe organic-rich, oil-prone, Kimmeridgian to Volgian–Ryazanian Draupne Formation. A secondary sourcerock, which has poor to fair potential for oil, is theOxfordian Heather Formation. The Permian Kupfer-schiefer source is known to extend this far north andwas penetrated by well 25/10–2. Although the Kup-ferschiefer shale contains a predominance of oil-pronealgal and amorphous organic matter, the lack of suffi-cient source volume precludes it from contributingwith any significance to the reservoired oils in this area.No contribution from the Kupferschiefer Formationwas observed among the biomarkers of the reservoiredoils. Furthermore, molecular signatures in oils and


gases in the area do not suggest presence of MiddleJurassic woody/coaly source rocks.

During the early Callovian a marine transgressiontook place throughout the Viking Graben. The relativerise in sea level continued into the earliest Cretaceouswith deposition of time-transgressive marine shales ofthe Draupne Formation. Pyrolysis, solvent extraction,and visual kerogen data (Table 1) show that theseshales contain oil-prone kerogen that has predomi-nantly liptintic organic matter in the form of marine,algal bodies and lipid-rich amorphous material. Theoil-prone nature of the amorphous kerogen is sup-ported by elevated hydrogen indices (�400 mg HC/gorg C) and paraffinic compositions for those sampleswhere the amorphous material accounts for the bulkof the kerogen. We do not imply a common origin forthe algal and amorphous material. Although some per-centage of the amorphous material may be linked toan algal origin through bacterial degradation (seen asseverely degraded algal bodies), the bulk of the amor-phous material may indeed have been enriched byother mechanisms, such as a predominantly bacterialorigin or a preferential adsorption of amorphous ma-terial on certain clays (Mayer, 1994). For the most part,these shales are interpreted to have accumulated underanoxic bottom-water conditions that helped preservetheir oil-prone nature. The presence of finely lami-nated shales suggests a lack of, or low abundance of,grazing or burrowing organisms. Oil-prone organicmatter may also be preserved under suboxic conditions(Isaksen and Bohacs, 1995).

From its wire-line log response (gamma-ray, resis-tivity, and sonic log signatures), we subdivided theDraupne Formation into an upper and lower unit (Fig-ure 4). The Upper Jurassic sequence on the west sideof the Viking Graben contains extensive mass-flowsediments in the Brae Formation, representing rapidsyntectonic sedimentation from the graben escarpment(Figure 5). The sands of the Brae Formation are inter-bedded with open-marine sediments of the DraupneFormation and pinch out eastward (Figure 3). As a re-sult, the Upper Jurassic has a complex lithofacies dis-tribution and has seen a dilution of the oil-prone ker-ogen of the basinal Draupne shale by land-derivedgas-prone kerogen, especially along the western grabenmargin. Although such mass-flow deposits can oxygen-ate anoxic sediments or anoxic and stratified bottomwaters, the presence of low amounts of oxygen is notconsidered detrimental to preservation of organic mat-ter (Heinrichs and Reeburgh, 1987; Lee, 1992). In ouropinion, the type of organic matter exerts a far greater

control on oil vs. gas potential than does the oxidationof organic matter within the dysoxic zone.

Interpretations of seismic data and wire-line log re-sponses for the Upper Jurassic sediments enabled theconstruction of an Upper Jurassic isopach map asshown by Figure 6. This has been extended with earlierwork (Isaksen et al., 1997) to include the South VikingGraben in the greater Sleipner–Tiffany–Brae area. Inthis context, the Upper Jurassic isopach thicknessesrepresent the sedimentary section from base Callovianto base Cretaceous. In the graben area, between theBalder and Gryphon fields, the Upper Jurassic attainsthicknesses of 3 km, of which a considerable thicknessconstitutes the coarser clastics shed off from the EastShetland Platform.

Rock-Eval pyrolysis and TOC analyses (Table 1)were carried out on 14 wells within the greater UtsiraHigh area to evaluate the organic richness, quality, andthermal maturity of source intervals. To compare andassess source rocks, which are currently at differentmaturities, we used a technique derived from the workof Cooles et al. (1986) and Pepper (1991), wherebymeasured hydrogen index (HI) and TOC values areback-calculated to their original (immature) HIo andTOCo values according to their thermal history. Theoil vs. gas potential of these rocks (Figure 7) follow thedefinitions discussed previously.

The HI is commonly used as an approximation ofthe hydrogen content of the kerogen and thus as anindicator of the source rock quality in terms of oil-generation vs. gas-generation potential. This is not nec-essarily the case for source rocks that have a predom-inance of terrigenous higher plant organic matter (typeIII) because resinite macerals can contribute to the HIvalue but have a poor potential for generation of C8�

aliphatic hydrocarbons (Isaksen et al., 1998a). The HIcan be plotted against the Tmax to classify kerogentypes and evaluate the level of thermal (organic) ma-turity (Figure 8). This chemical kerogen classificationshows that both upper and lower Draupne source in-tervals along the western graben margin contain moretype III and III/II kerogen than in the eastern part ofthe graben (Figure 9A, B). This is in agreement withthe expected strong terrigenous influx of woody ma-terial associated with the rapid syntectonic sedimen-tation from the graben scarps. The eastward extensionof type III kerogen seems to be associated with the east-ernmost extension of mass-flow sediments from thewestern graben margin.

To further investigate the indications of dilution ofthe oil-prone kerogen of the Draupne shale along the


Figure 4. Subdivision of theJurassic sedimentary sectionbased on wire-line log signa-tures. The logs shown aregamma-ray, sonic, and resistiv-ity. The right column shows thecalculated percent TOC basedon the technique by Passey etal. (1990).

western graben margin, the content of visual organicmatter type (OMT) was plotted for the analyzed wells(Figure 10A, B). Wells along the eastern margin con-sistently show a higher content of oil-prone liptinitekerogen macerals for both the upper and lowerDraupne formations. Wells along the western marginof the graben conversely have more vitrinite (gas-

prone) kerogen content. Incorporation of visual kero-gen data allows the interpreter to better assess whetherthe oil-prone vs. gas-prone nature of the source rock isprimarily due to organic matter type or organic matterdegradation through severe oxidation.

The ratings of both upper and lower Draupnesource intervals (Figure 11A, B) indicate that a


Figure 5. Main depositionalenvironments for the Upper Ju-rassic Draupne Formation. Theextensive mass-flow sedimentsrepresent syntectonic sedimen-tation from the western grabenescarpment. As a result, off-shore, marine shales are inter-bedded with mass-flow sedi-ments. Shoreface sedimentationdominated around the UtsiraHigh.

predominantly gas-prone organic facies was depositedin the graben west of blocks 16/1 and 25/10. We in-terpret the decrease in oil potential to be mainly dueto the syntectonic influx of turbidites with terrigenousorganic matter during the Kimmeridgian period. The

magnitude of a potential decrease in the oil-prone na-ture of the kerogen during accumulation under moreoxic conditions (i.e., oxygen-rich turbidite currents)remains unresolved. Laminated black shales sampledfrom wells drilled on structural highs suggest a sparse


Figure 6. Isopach map (con-tours given in meters) of theUpper Jurassic representing thesection between the base Cal-lovian and the base Cretaceous.


Figure 7. Source richness andsource quality chart for the up-per and lower Draupne forma-tions. Each data point repre-sents the average weightedvalues from cuttings or coresamples from the interval. Thefour samples from the LowerJurassic at the base of the chartdenote HI values less than 100mg/g organic carbon.

benthic fauna at these locations. It seems probable,however, that the Draupne shales experienced a higherdegree of dilution by coarser clastics as well as periodicoxygenation from turbidite currents in basinal posi-tions connected with debris and turbidite flows fromthe western basin margin. For the upper Draupne, thegas-prone organic facies is confined to block 24/12,whereas for the lower Draupne gas-prone organic fa-cies also extends into block 15/3 to the south. Thepotential for the Draupne Formation to generate oilimproves toward the east, from a mixed gas-prone andoil-prone organic facies in the eastern parts of blocks24/12 and 15/3 to an oil-prone organic facies closestto the Utsira High. At the time of our study, no sourcerock samples were available from the Beryl field (UK9/13) source kitchen (north of 59�30�N).

Source Rock Thermal Maturity

Tmax measurements from Rock-Eval pyrolysis span arange from immature (430�C) to fully mature (455�C)(Figure 8). Care was taken to avoid Tmax data derivedfrom shales stained by in-migrated hydrocarbons (typ-

ically seen as a bimodal S2 peak). As a further controlon the thermal maturity vs. depth trend, comparisonwas made with vitrinite reflectance (% Ro) measure-ments on Middle Jurassic coals and coaly shales fromlocations throughout the entire Viking Graben wheresuch rocks are present (Sleipner/Hugin and Brent deltasystems). The resultant thermal maturity vs. depth re-lation is illustrated in Figure 12. Tmax and % Ro datasuggest that early to peak oil generation from theDraupne shale occurs between an Ro equivalent of0.62% and 0.88% corresponding to depths of 3400–4400 m below sea floor. Late oil generation occurs atRo � 1.1%, corresponding to a depth of approximately5000 m below sea floor.

SECONDARY MIGRATION OFOIL AND GAS

Evidence for Migration into Tertiary Strata

Proof of hydrocarbon migration from Jurassic sourcerocks to Tertiary reservoir rocks is given by the accu-


Figure 8. Evaluation of sourcerock thermal maturity and qual-ity. Roman numerals denote thepredominant organic-mattertype, whereas thermal maturitylevels are given by Rock-EvalTmax values and vitrinite reflec-tance (% Ro).

mulations at the Balder, Hanna, Grane, Jotun, andRinghorne fields. In other areas, evidence for migrationinto the Tertiary and Cretaceous sections is shown bythe presence of oil shows and stains or thermogenic gaswithin an otherwise thermally immature section. Coreand cuttings samples were analyzed for the presence ofinclusions with possible hydrocarbons. Molecular char-acterization of such hydrocarbon inclusions can pro-vide important insights to paleomigration events (Is-aksen et al., 1998b). In this study, no fluid inclusionswere found (Table 3). The absence of fluid inclusionsis due to paleotemperatures and present-day tempera-tures cooler than required for the formation of inclu-sions. One such process, quartz overgrowth, does notstart until temperatures of approximately 80�C arereached.

Thermogenic gases were discovered in thePaleocene–Eocene of wells 16/1–1 (Figure 13), 16/1–

2 (Figure 14), and in the thermally immature UpperJurassic sections of wells 16/1–2, 16/1–3 (Figure 15),and 25/8–2 (Figure 16). Thermogenic hydrocarbon gasis also present within the Upper Cretaceous to UpperJurassic section (2200–3200 m) in well 25/10–2REand is especially pronounced within the Rotliegendesandstones (Permian) at 2900–3000 m (Figure 17).Three rock samples from the Permian section (onefrom 3007 m within the Kupferschiefer shale and twowithin the Rotliegende conglomerates at 3009 and3037 m) were analyzed by thermal evaporation–gaschromatography) (Figure 18), pyrolysis–gas chroma-tography, solvent extraction, liquid chromatography,and gas chromatography of the saturate hydro-carbon fraction (Figure 19) to check for presence offree hydrocarbons and to ascertain whether a second-ary migration pathway may exist within the Rotlie-gende 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 datashown in Figure 7. Note how areas that have higher predicted contents of type III kerogen conform to areas affected most bysyntectonic mass-flow sediments along the western graben margin.

chromatography data do not show significant quanti-ties of free hydrocarbons. Solvent extractable (free) hy-drocarbons observed within the conglomerates arelikely the results of short-distance migration (2–30 m)from the Kupferschiefer organic-rich shales.

Migration Model

Marine source rocks of the Upper Jurassic DraupneFormation thicken from the Utsira High westward intothe Viking Graben (Figure 3). Hydrocarbons are likelyto have been generated in large amounts west of theUtsira High. Maturation studies indicate that hydro-carbon expulsion and migration started during the lat-est 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 MiddleJurassic level in the Viking Graben indicates a generalbasin to margin pathway. These migration pathwaysintersect faults at which point vertical leakage throughthe Cretaceous section is key to charging reservoir in-tervals in the Tertiary.

Figure 3 illustrates that the Jurassic source inter-vals are currently mature for generation of hydrocar-bons (% Ro � 0.6) in the center of the graben. Theproposed model for migrating hydrocarbons into theTertiary plays in the Utsira High area involves migra-tion at the Draupne source level into the adjacent Mid-dle Jurassic Hugin Formation and Sleipner Formationsandstones. Longer distance secondary migration in-volves eastward lateral migration through the Jurassicsandstone 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 contentof liptinitic, oil-prone organic matter from visual kerogen evaluations.

in the Jurassic section, hydrocarbons migrate up alongthe fault plane and into Jurassic conduits on the high-side block or migrate through the fault plane and intojuxtaposed sandstones. In general hydrocarbons mi-grate laterally in this fashion until succeeded by verticalmigration up fault planes along the Utsira High west-bounding fault system.

Major migration entry points available were faultscut through the entire Cretaceous succession in theeastern part of the fault system as it steps up towardthe Utsira High. Where Jurassic carrier beds and Ter-tiary reservoirs are connected, hydrocarbons continueto move updip into available independent closures orinto combined stratigraphic and structural traps at theTertiary level. The migration model is supported byTertiary 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 pathwaysthrough low-permeability conduits (e.g., ratty sands inthe Upper Jurassic and fractured chalks in Cretaceous)are likely to be less efficient. The absence of faulting inthe Cretaceous section is believed to effectively pre-vent migration of hydrocarbons into tertiary reservoirsin the central part of the graben (e.g., 15/3–1 and 15/3–3).

EXPLORATION SIGNIF ICANCE

The key observations from this study are the following:

• Both upper and lower Draupne formations are ef-fective source rocks within the greater Utsira Higharea.


Figure 11. Expected hydrocarbon type generated from mature (A) upper Draupne and (B) lower Draupne source rocks. The areaoutlines are based on TOCo and HIo calculations.

• The source rock quality of the Draupne Formationranges widely from gas-prone along the western mar-gin of the graben to oil-prone in the east.

• The gas-prone organic facies is believed to be asso-ciated with terrigenous input from westerly derivedmass-flow sediments, which have both diluted theoil-prone organic matter and introduced a more oxicdepositional environment.

• Migration is considered a significant risk factor forany Tertiary prospect west of the Utsira High main-bounding fault.

The exploration significance of these observationslies in their use as an aid to predict whether an area islikely to be dominated by oil or gas reserves. For a pros-pect on the Utsira High to be sheltered from gas influx

it may be concluded that three requirements need tobe satisfied: (1) the Draupne Formation within thedrainage area needs to be of an oil-prone nature, (2) theoil-prone source rock must not be within the gas-generation window, and (3) migration access to thegas-prone source kitchen west of the Utsira High areaneeds to be denied. It follows that it is critical to un-derstand the migration entry points into the Tertiarysection. In the graben, downdip from the Utsira High,a thick Cretaceous section and lack of penetratingfaults prevent effective migration from the Jurassic intoTertiary traps. Exploration efforts at Tertiary levelsshould therefore be focused close to the Utsira High inareas that have thin Cretaceous sediments and wherebasin-bounding faults are present to provide the nec-essary migration route.


Figure 12. Regional assessment of thermal maturity vs. depthbased on measurements of vitrinite reflectance from humiccoals and shales that have terrigenous macerals.

CONCLUSIONS

• Chemical kerogen classification and source rock py-rolysis show that both upper and lower Draupnesource intervals along the western graben margincontain more terrigenous (type III and III/II) kero-gen than in the eastern part of the graben. Suchchange in organic facies within the Draupne sourcerock naturally results in a higher proportion of gasgeneration upon maturation.

• Good potential for oil generation from Draupne For-mation source rocks exists along the entire westernmargin and northern nose of the Utsira High.

• Thermogenic-hydrocarbon gas was encountered inthe Upper Cretaceous and Tertiary in wells 16/1–1,16/1–2, 16/1–3, 25/8–2, and 25/10–2. These gaseshave migrated into the Cretaceous and Tertiary sed-imentary section from deeper, mature, sections ofthe Draupne and Heather formations.

• Migration entry points into the Tertiary section areprovided by faults cutting through the base Paleo-cene. Unfaulted Cretaceous sections more likely actas a barrier to migration into Tertiary reservoirs.

• No hydrocarbon fluid inclusions were detected inthe samples analyzed. The lack of fluid inclusions ismost likely due to the low thermal maturity level ofthe Tertiary sediments. At most locations the Paleo-cene and Eocene sands are poorly consolidated andhave not been exposed to the diagenetic tempera-tures required (� 80�C) for mineral mobilizationand the formation of fluid inclusions.

• Thermogenic liquid hydrocarbons within the Per-mian conglomerates in well 25/10–2 are derivedfrom the organic-rich Kupferschiefer shales by short-distance migration.

APPENDIX : ANALYTICAL METHODS

Total organic carbon (TOC) and Rock-Eval pyrolysis measurementswere made on a Leco IR 312 carbon analyzer and Delsi Rock EvalII, respectively. Vitrinite reflectance and visual kerogen analyses wereanalyzed according to standard coal methods. Thermoevaporationand pyrolysis–gas chromatography was performed using custom-built systems based on the HP 5790 gas chromatograph (GC)equipped with flame-ionization detectors. The thermal extractionwas done isothermally at 280�C for 3 min. The sample was thenheated at 60�C/min to 610�C, and the volatiles were trapped in liq-uid nitrogen on the head of the GC column (split 60:1). The GChad a 50 m capillary column (5% phenyl-methylsilicone). Initial tem-perature was �20�C followed by a heating rate of 4�C/min to a finaltemperature of 280�C. Cuttings gas, thermal evaporation–gas chro-matography, and pyrolysis analyses were carried out at Exxon Pro-duction Research Company, Houston, Texas.


Figure 13. Well 16/1–1 pro-files of cuttings-gas data show-ing gas-wetness and summedconcentrations of C1 through C4(vol. %). Gas wetness is calcu-lated as 100 [(C2 � C3 � C4)/(C1 � C2 � C3 � C4)]. Ther-mogenic hydrocarbon gas ispresent at 2000–3000 m, withinthe Paleocene–Eocene. No freeliquid hydrocarbons were de-tected (samples were analyzedfrom 1920, 1935, 2530, 2667,and 2743 m [Table 4]), norwere any fluid inclusions de-tected (samples were analyzedfrom the Paleocene at depthsof 2320–2648 m [Table 3]).Levels of organic metamor-phism (LOM) 6 and 8 correlateto vitrinite reflectance values of0.43% and 0.55%, respectively.

Figure 14. Well 16/1–2 pro-files of cuttings-gas data show-ing gas wetness and summedconcentrations of C1 throughC4. Thermogenic hydrocarbongas is present within Eocene,Paleocene, Danian, and Late Ju-rassic at 1700–2500 m. No freehydrocarbon liquids were de-tected (samples were analyzedfrom 2099, 2130, and 2250 m),nor were any fluid inclusionsobserved (analyses within thePaleocene at 2102–2490 m).

Figure 15. Well 16/1–3 profiles of cuttings-gas data showinggas wetness and summed concentrations of C1 through C4. Ther-mogenic hydrocarbon gas is present within the Upper Jurassicinterval at 2600–2800 m.

Figure 16. Well 25/8–2 profiles of cuttings-gas data showinggas wetness and summed concentrations of C1 through C4. Ther-mogenic gas is present with the immature Upper Jurassic from1500 m to total depth drilled.

Figure 17. Well 25/10–2 pro-files of cuttings-gas data show-ing gas wetness and summedconcentrations of C1through C4.


Figure 18. Well 25/10–2RE.Thermoevaporation (S1) of coresamples from (A) Kupferschie-fer shale at 3007 m (sample202087A), (B) Rotliegende con-glomerate at 3009 m (sample202087B), and (C) Rotliegendeconglomerate at 3037 m (sam-ple 202087C). S1 represents thefree hydrocarbons in the rock.


Figure 19. Well 25/10–2RE.Gas chromatograms of the sat-urate hydrocarbon fractionsfrom (A) Kupferschiefer shale at3007 m (sample 202087A), (B)Rotliegende conglomerate at3009 m (sample 202087B), and(C) Rotliegende conglomerateat 3037 m (sample 202087C).


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Source rock quality and hydrocarbon migration pathways within the greater Utsira High area, Viking Graben, Norwegian North Sea

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