Kimmeridgian Shales Total Petroleum System 

of the North Sea Graben Province 

Bulletin 2204-C 

U.S. Department of the Interior 

U.S. Geological Survey 
Kimmeridgian Shales Total Petroleum System

of the North Sea Graben Province

By Donald L. Gautier

Bulletin 2204-C

U.S. Department of the Interior

U.S. Geological Survey
U.S. Department of the Interior

Gale A. Norton, Secretary

U.S. Geological Survey

Charles G. Groat, Director

U.S. Geological Survey, Reston, Virginia: 2005

Posted online May 2005, version 1.0

This publication is only available online at:

http://pubs.usgs.gov/bul/2204/c

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Although this report is in the public domain, permission must be secured from the individual copyright owners to 

reproduce any copyrighted materials contained within this report.

Suggested citation:

Gautier, Donald L., 2005, Kimmeridgian Shales Total Petroleum System of the 

North Sea Graben Province: U.S. Geological Survey Bulletin 2204-C, 24 p.
iii

Contents

Abstract ................................................................................................... 1

Introduction................................................................................................ 1

Summary of the Geologic History of the North Sea................................................... 2

Pre-Rift Geologic History........................................................................... 2

Syn-Rift Geologic History........................................................................... 9

Post-Rift Geologic History ........................................................................ 9

History of Exploration and Production.................................................................. 10

Total Petroleum System: Kimmeridgian Shales (402501) ............................................. 10

Source Rocks ....................................................................................... 11

Reservoirs .......................................................................................... 11

Pre-Rift Reservoirs of Pre-Jurassic Age ................................................... 11

Pre-Rift Reservoirs of Early and Middle Jurassic Age.................................... 14

Syn-Rift Reservoirs ........................................................................... 14

Post-Rift Reservoirs........................................................................... 14

Seals ................................................................................................ 15

Timing of Oil Migration and Entrapment ......................................................... 15

Assessment Units ....................................................................................... 15

Assessment Unit 1: The Viking Graben (40250101) ............................................. 17

Assessment Unit 2: The Moray Firth/Witch Ground (40250102) .............................. 17

Assessment Unit 3: The Central Graben (40250103)............................................. 19

Undiscovered Resources of the North Sea Graben................................................... 22

References Cited.......................................................................................... 22

Figures

1–4. Maps showing:

1. Location of the North Sea Graben Province (4025), with some nearby

province boundaries, coastlines, and cities.......................................... 3

2. Prominent oil and gas fields of the North Sea ....................................... 4

3. Boundary of the Kimmeridgian Shales Total Petroleum System, with locations

of some oil and gas fields............................................................... 5

4. Structural elements of the North Sea ................................................ 6

5. Stratigraphic summary of the North Sea Graben Province .............................. 8

6. Burial curves for several localities of the northern and central North Sea ............ 12

7–10. Maps showing:

7. Approximate depth to base of Cretaceous rocks in the Central and

Viking Grabens, with names and locations of oil and gas fields .................. 13

8. Boundaries of the Viking Graben Assessment Unit (40250101)..................... 16

9. Boundaries of the Moray Firth/Witch Ground Assessment Unit (40250102)...... 18

10. Boundaries of the Central Graben Assessment Unit (40250103) .................. 20
iv

Table

1. Assessment results summary for the Kimmeridgian Shales Total Petroleum

System 402501, including results for three assessment units ........................... 21

Multiply By To obtain

square kilometer (km2) 0.3861 square mile

meter (m) 3.281 foot

Conversion Factors, Datums, and Other Abbreviations

Datum

Vertical coordinate information is referenced to the North American Vertical Datum of 1988 (NAVD88).

Other abbreviations

AU Assessment Unit

BBO Billion barrels of oil

BCF Billion cubic feet

BTU British thermal unit

TCF Trillion cubic feet

TOC Total organic carbon

TPS Total Petroleum System

U.K. United Kingdom

USGS U.S. Geological Survey

‰ Parts per thousand
Kimmeridgian Shales Total Petroleum System of the


North Sea Graben Province


By Donald L. Gautier 

Abstract 

The North Sea Graben of northwestern Europe, World 

Energy Project Province 4025, is entirely offshore within the 

territorial waters of Denmark, Germany, the Netherlands, 

Norway, and the United Kingdom. Extensional tectonics and 

failed rifting are fundamental to the distribution of oil and gas 

in the province. Accordingly, the geologic history and reservoir rocks of the province are considered in the context of their 

temporal relationship to the principal extension and rifting 

events. The oil and gas accumulations of the province are 

considered part of a single petroleum system: the Kimmeridgian Shales Total Petroleum System (TPS). Source rocks of the 

Kimmeridgian Shales TPS were deposited in Late Jurassic to 

earliest Cretaceous time during the period of intensive extension and rifting. The Kimmeridgian Shales contain typical 

“type II” mixed kerogen. Oil and gas generation began locally 

in the North Sea Graben Province by Cretaceous time and has 

continued in various places ever since. 

Reservoirs are found in strata with ages ranging from 

Devonian to Eocene. Pre-rift reservoirs are found in faultblock structures activated during rifting and can be of any age 

prior to the Late Jurassic. Syn-rift reservoirs are restricted 

to strata actually deposited during maximum extension and 

include rocks of Late Jurassic to earliest Cretaceous age. Postrift reservoirs formed after rifting and range in age from Early 

Cretaceous to Eocene. Seals are diverse, depending upon the 

structural setting and reservoir age. Pre-rift reservoirs commonly have seals formed by fine-grained, post-rift sedimentary 

sequences that drape the Late Jurassic to earliest Cretaceous 

structures. Contemporaneous shales such as the Kimmeridge 

Clay seal many syn-rift reservoirs. Fields with post-rift reservoirs generally require seals in fine-grained Tertiary rocks. 

In most of the North Sea Graben, source rocks have been 

continuously buried since deposition. Structural trap formation has also taken place continuously since Mesozoic time. 

As a result, oil and gas are present in a wide variety of settings 

within Province 4025. 

Assessment units for the World Energy Project were

defined geographically in order to capture regional differences in exploration history, geography, and geological

evolution. Three geographic areas were assessed. The Viking

Graben, in the northern part of the province, includes both

United Kingdom and Norwegian territorial areas. The Moray

Firth/Witch Ground in the west-central part of the province

is entirely in United Kingdom. waters. The Central Graben in

the southern part of the province includes territorial areas of

Denmark, Germany, the Netherlands, Norway, and the United

Kingdom. The North Sea Graben is estimated to contain

between 4.3 and 25.6 billion barrels (BBO) of undiscovered,

conventionally recoverable oil. Of that total, the Viking

Graben is believed to contain 2.2 to 14.8 BBO of undiscovered oil, the Moray Firth/Witch Ground may contain between

0.3 and 1.9 BBO, and the Central Graben was estimated to

contain undiscovered oil resources of 1.7 to 8.8 BBO. Province 4025 was also estimated to hold between 11.8 and 75

trillion cubic feet (TCF) of undiscovered natural gas. Of this

total, 6.8 to 44.5 TCF is thought to exist in the Viking Graben,

0.6 to 3.4 TCF is estimated to be in the Moray Firth/Witch

Ground, and 4.5 to 27.1 TCF of undiscovered gas is estimated

to be in the Central Graben.

Introduction 

The U.S. Geological Survey (USGS), for the purposes of 

conducting its assessment of global oil and gas resources (U.S. 

Geological Survey World Energy Assessment Team, 2000), 

has divided the world into 8 regions and 937 provinces, exclusive of the United States. These provinces were ranked according to their discovered petroleum volumes, which are the sum 

of total cumulative oil and gas production and proved reserves. 

From this ranked list, the 76 highest ranking provinces were 

initially selected for assessment. In addition, another 26 “boutique” provinces were selected for assessment on the basis of 

their regional significance or possible future discoveries of 

petroleum (Klett and others, 1997). 

The North Sea Graben Province of northwestern Europe, 

the subject of this report, is USGS World Energy Project 

province number 4025 and is ranked number 8 among the 76 

world priority provinces in terms of volumes of discovered oil 

and gas. The Anglo-Dutch Basin and Northwest German Basin 

Provinces adjoin the North Sea Graben Province on the south 

and southeast. Taken together, these three provinces account 
2 Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province 

for the vast majority of oil and gas resources in Western 

Europe. The location and boundaries of the North Sea Graben 

Province are shown in figure 1.

In contrast to the adjacent gas-prone Anglo-Dutch and 

Northwest German Basin Provinces, the North Sea Graben 

Province is distinctly oil prone. Statfjord, the largest field in 

Western Europe in terms of recoverable oil, is located in the 

northern part of the province on the boundary between the 

Norwegian and United Kingdom sectors of the North Sea 

(fig. 2). As of 1996, Statfjord was reported to have ultimately 

recoverable resources of 569.5 million m3

 of oil (3.582 billion 

barrels of oil) and 56.4 billion m3

 of natural gas (1.991 trillion 

ft3

 of gas) (Norwegian Petroleum Directorate, 1999).

The Total Petroleum System (TPS) concept (modified 

from Magoon and Dow, 1994) is the basis for this assessment. A TPS is a natural system that encompasses a petroleum 

source rock and all genetically related oil and gas and which 

includes the essential elements and processes that are necessary for the existence of hydrocarbon accumulations. The 

TPS has definite geographic and stratigraphic boundaries. 

The minimum petroleum system is a subset of the TPS within 

which the essential elements and processes have been demonstrated conclusively. An assessment unit (AU) is a mapped volume of rock within a TPS that has sufficiently homogeneous 

geology, exploration history, and risk characteristics to warrant 

treatment of its oil and gas accumulations as a single population for the purposes of analysis. A TPS may include one or 

more AUs, and every AU exists within a TPS. 

An eight-digit numeric code is used to uniquely identify 

each AU with respect to World Energy Project Region, Province, and Total Petroleum System. For example, the Viking 

Graben Assessment Unit is assigned number 40250101. The 

first digit is the region number, indicating the AU is in Europe 

(Region 4). The next three digits uniquely identify the province; in this case, the North Sea Graben is number 025. The 

following two digits (01) refer to the TPS and the final two 

digits are the unique AU number (also 01 in this example). 

Klett and others (1997) established the codes for the regions, 

provinces, and assessment units. The provinces of Europe, 

Region 4, are shown and explained in USGS Digital Data 

Series 60 (DDS–60), which is the primary publication of the 

World Petroleum Assessment 2000 (U.S. Geological Survey 

World Energy Assessment Team, 2000). 

The North Sea Graben is one of the world’s great petroleum provinces. The oil and gas accumulations found there

occur in a variety of structural settings and within reservoir

rocks of various of ages, but almost all originated from shales

that were deposited during a relatively brief stratigraphic

interval encompassing Late Jurassic to earliest Cretaceous

time. This source-rock interval, herein referred to as the

Kimmeridgian shales, is known to have been the source of oil

and gas at various times and places in the North Sea Graben

(Cornford, 1998). Still, it is of such a distinctive and uniform

character as to justify treating all hydrocarbon accumulations

derived from it as belonging to a single Total Petroleum System. That single TPS, herein referred to as the Kimmeridgian

Shales Total Petroleum System (fig. 3), is the dominant geological construct upon which the World Energy Assessment of

the North Sea Graben depends.

The province is located entirely offshore in the North

Sea, within the national jurisdictions of Norway, the United

Kingdom, Denmark, Germany, and the Netherlands. The

province boundaries were established to include the principal

geologic features associated with the Mesozoic rift structures

of the North Sea Graben and adjacent areas. The North Sea

Graben can be conveniently divided into three subbasins

(fig. 4). The Viking Graben is a north-northeast-trending

structure situated in the northernmost part of the North Sea

Graben, located between the East Shetland Platform and the

Horda Platform and Fenno-Scandian Shield. The southernmost part of the North Sea Graben system is a southeastnorthwest-trending rift complex collectively referred to as

the Central Graben. At the juncture of the Central and Viking

Grabens, the Moray Firth/Witch Ground structure is a westtrending extensional feature that terminates near the coast of

the United Kingdom (fig. 4).

The petroleum of the North Sea has been the subject 

of many studies and a vast literature (for example, Glennie, 

1998a). The Kimmeridgian TPS itself was the subject of a 

summary, “Mandal-Ekofisk(!) Petroleum System, Central 

Graben, North Sea” by Chris Cornford, published in Magoon 

and Dow (1994). The following geologic summary relies upon 

this extensive literature. 

Summary of the Geologic History 

of the North Sea 

The extensional tectonics and failed rifting during the 

latest Jurassic and earliest Cretaceous are fundamental to 

understanding oil and gas in the North Sea (Brooks and 

Glennie, 1987; Pegrum and Spencer, 1990). Accordingly, this 

discussion of the geologic history is subdivided into three 

parts with respect to the main episode of rifting. The first section focuses on events and processes prior to rifting (pre-rift). 

Those events and processes that took place during the rifting 

events are called syn-rift. Depositional processes and structural events subsequent to the Late Jurassic/earliest Cretaceous 

are considered post-rift.

Pre-Rift Geologic History 

Only a few tens of wells penetrate basement rocks in the 

vicinity of the North Sea Graben. The wells (Ziegler, 1990) 

contacted Caledonian (Late Ordovician to earliest Devonian) 

basement consisting of intrusive igneous rocks and low- to 

high-grade metamorphic rocks, including metasedimentary 

sequences. These sparse samples, along with observations 

from outcrops in the British Isles, northern Europe, and Scandinavia, are evidence that the North Sea was the site of a major 
Summary of the Geologic History of the North Sea 3

5° 0 5°E 

Norway 

60° Bergen 

United 

Kingdom North

Sea

Edinburgh 

Glasgow 

55° 

Liverpool 

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Figure 1. Location of the North Sea Graben Province (4025), with some nearby province boundaries, coastlines, and cities. 
4 Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province 

4° 2° 0° 2°E 4°E 6°E

60°

58°

56°

54°

Liverpool

Bergen

Glasgow

Edinburgh

United

 Kingdom 

Norway 

North Sea 

Magnus 

Cormorant 

Hutton 

Heather 

Ninian 

Agat 

Snorre 

Murchison 

Statfjord

Gullfaks 

Dunlin 

Brent 

Beryl 

Frigg 

Balder 

Beatrice 

Buchan 

Piper

Claymore 

Balmoral 

Maureen 

Bream 

Brisling 

Forties 

Nelson 

Montrose 

Arboath 

Cod 

Gannet 

Fulmar 

Clyde 

Auk 

Argyll 

Albuskjell 

Ekofisk 

Eldfisk Harald 

Hod 

Dan 

Ann 

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Brae Miller 

0 170 KILOMETERS

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Troll 

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Valhall 

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Figure 2. Prominent oil and gas fields of the North Sea (modified from Glennie, 1998a). 
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Summary of the Geologic History of the North Sea 5

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Figure 3. Boundary of the Kimmeridgian Shales Total Petroleum System, with locations of some oil and 

gas fields. 
SOUTHERN N TH SEA BASIN

VIKING

GRABEN

MORAY FIRTH ASIN

CENTRAL

GRABEN

OR

B

6 Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province 

5° 0° 5°E 10°E 

Norway 

Bergen 

60° HORDA

PLATFORM EAST SHETLAND 

PLATFORM

FLADEN FENNO-SCANDIAN 

GROUND EGERSUND SHIELD 

SPUR BASIN 

WITCH 

GROUND BUCHAN HORST GRABEN

SCOTLAND 

United 

Kingdom North Sea 

Edinburgh 

RINGKOBING - FYN HIGH Glasgow MID-NORTH SEA HIGH 

55° 

ENGLAND 

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Figure 4. Structural elements of the North Sea (modified from Brown, 1991). 
7 

north-south-trending fold belt named the Iapatus Suture. This 

suture extended from what is now the Arctic, between Greenland and Scandinavia, through the North Sea and onto the 

European continent in northern Germany and Poland (Glennie 

and Underhill, 1998; Ziegler, 1990). 

The three-plate convergence of the Caledonian orogeny 

caused the suturing of the Iapatus Seaway. The Caledonides 

are unconformably overlain in much of the North Sea Basin 

by lithologically diverse sedimentary rocks of Devonian age. 

During the Early Devonian, the northern part of the North Sea 

Basin received sediment from the Orcadian Basin, while the 

rest of the North Sea was probably emergent (Ziegler, 1990). 

When marine waters of the proto-Tethys transgressed the 

southern and central North Sea Basin from the south during 

Middle Devonian time, deposition of marine limestone and 

shale was largely confined to the Central Graben, indicating its 

structural configuration for the first time (Downie, 1998). The 

Late Devonian fluvial, alluvial, and lacustrine rocks that are 

present throughout the rest of the North Sea Basin are appropriately considered part of the Old Red Sandstone (Mykura, 

1991) (fig. 5). 

During the Carboniferous to Early Permian, the Hercynian orogeny reflected the transition from a three-plate convergence to a two-plate convergence. The future site of the North 

Sea was well to the north of the active Variscan orogenic belt, 

where African Gondwanaland was colliding with European 

Laurasia (Ziegler, 1990). Even so, the Carboniferous strata 

throughout the North Sea are closely associated with its development (Besly, 1998). Compared to depositional rates in the 

Variscan foreland of the southern North Sea, the central North 

Sea Basin experienced relatively slow sedimentation. Marginal-marine conditions persisted until the Late Carboniferous, 

when deltaic strata with coals and carbonaceous shales were 

deposited throughout the southern and central North Sea (Collinson and others, 1993). The Carboniferous Coal Measures, 

which are thick and economically important as natural-gas 

source rocks in the southern North Sea, are relatively thin and 

poor in organic matter in the Central Graben and are largely 

absent in the Viking Graben. 

Beginning in the Devonian, northwestern Europe drifted 

northward. This latitudinal change, coupled with the intensifying orogenic rain shadow of the Variscan Highlands, caused a 

progressive shift from humid to arid climate and from fluvial/

deltaic to desert sedimentation in the area that would become 

the North Sea Basin (Glennie, 1972, 1997). 

Lower Permian rocks in northwestern Europe are mostly 

referred to as the Rotliegend Group (fig. 5). The Lower 

Rotliegend, which forms much of the sedimentary section in 

Germany and Poland, is not prominent north of the Mid-North 

Sea High (fig. 4). On the other hand, the Upper Rotliegend 

is present in the northern Permian Basin, which includes the 

northwestern part of the Central Graben, the Moray Firth/

Witch Ground, and the southernmost part of the Viking Graben. The Rotliegend is incompletely known because drilling 

commonly stops well above the Permian. Glennie (1998b) 

suggested that facies relationships in the Upper Rotliegend of 

Summary of the Geologic History of the North Sea 

the northern Permian Basin are similar to those in the large 

gas fields of the southern North Sea. Thus, he expected mainly 

desert nonmarine deposits dominated by fluvial, eolian, and 

lacustrine facies. 

The Late Permian Zechstein transgression brought marine 

waters from the Boreal sea southward, far into northwestern 

Europe (Kiersnowski and others, 1995). Global sea-level rise 

at the end of the Permian glaciation triggered rapid advance of 

the Zechstein Sea. The entry point of Zechstein waters into the 

area of the North Sea is subject to dispute (Taylor, 1998), but 

most workers agree that the Boreal waters entered through a 

restricted passageway and that both the northern and southern 

Permian basins were well below sea level. The desertification of northern Europe, combined with restricted circulation, 

caused evaporitic conditions throughout the Zechstein Sea. 

Rocks of the Zechstein Group, which include thick

evaporites, are found mainly in the two east-west-trending subbasins (the northern and southern Permian basins),

separated by the North Sea High (Mid-North Sea High and

Ringkobing-Fyn High of fig. 4). The evaporites cover much

of the southern North Sea, extending westward through

Germany and Poland, through the Netherlands to eastern

England. In the northern Permian basin, Zechstein deposits

accumulated in what are now the Moray Firth/Witch Ground

and the southern Viking Graben. Salt becomes scarce northward, with no halite known north of lat 50°50′N. Throughout

most of the Central Graben, Viking Graben, and Moray Firth/

Witch Ground, the Zechstein salts are not sufficiently thick to

serve as a robust seal. More importantly, except in the Central

Graben, the thickness is insufficient to result in major diapiric

structures. However, in those areas where salt structures are

significant, such as the Danish sector, salt structures control

hydrocarbon accumulation.

By earliest Triassic time, the Zechstein Sea had retreated

to the Arctic, and a complex rift system had begun to disrupt

both the Variscan fold belt and the Permian basins. Triassic

rifting was tearing apart the Pangean supercontinent along lines

separating Fennosarmatia from Laurentia-Greenland and opening the Tethys rift system (Ziegler, 1990; Glennie, 1998b). Red

beds accumulated in discontinuous continental basins formed

by the rift system. Despite the structural elements introduced

by incipient rifting, the northern and southern Permian basins

are recognizable on isopach maps of the Triassic (Ziegler,

1990), and major depositional patterns that originated in the

Permian persisted throughout the Triassic. South of the MidNorth Sea High, Triassic sedimentary sequences display great

lateral continuity and abundant evaporite facies. Bundsandstein

(equivalent to the Bacton Group) red beds formed under a

variety of nonmarine desert conditions, but they conformably

overlie the Zechstein (Tucker, 1991).

Marine transgression in latest Triassic to earliest Jurassic time established a stable connection from the Boreal

Sea to Tethys and effectively ended Triassic sedimentation

patterns. Shallow-marine conditions existed over most of the

North Sea Basin and much of northern Europe throughout

the Early Jurassic. In most areas, Jurassic rocks are marine
8 Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province 

50 

100 

150 

200 

250 

300 

350 

400 

450 

AGE (Ma) 

CENOZOIC 

LOWER ROTLIEGEND GP 

GROUP 

YOREDALE “ SERIES” CARBONIFEROUS LS

DUNLIN GROUP LIAS GROUP 

HEGRE

 GROUP 

BANKS GP 

HAISBOROUGH GP 

FLADEN GP 

SKAGERRAK 

SMITH BANK 

CORMORANT 

SEISMIC MARKER 

MID-CIMMERIAN 

UNCONFORMITY 

CYCLE -

CALEDONIDES 

JURASSIC 

TRIASSIC 

PERMIAN 

CARBONIFEROUS 

DEVONIAN 

SILURIAN 

ORDOVICIAN 

CENTRAL SOUTHERN 

H O R D L A N D A N D N O R D A L A N D G R O U P S 

S H E TL A N D G RO U P C H A LK GRO U P 

H U M B E R G R O U P 

Z E C H S T E I N G R O U P 

U P P E R R O T L I E G E N D G R O U P 

HEATHER 

BRENT GROUP 

BACTON GROUP 

COAL MEASURES 

WEST SOLE GROUP 

STATFJORD FM PENARTH GROUP 

 FORMATION 

 FORMATION 

 FORMATION 

C R O M E R K N O L L G R O U P 

BASE CRETACEOUS 

S A A L I A N U N C O N F O R M I T Y 

V A R I S C A N O R O G E N Y 

C A L E D O N I A N O R O G E N Y 

C A L E D O N I A N P L A T E C Y C L E VARISCAN PLATE I N T R A P L A T E D E F O R M A T I O N 

O L D R E D S A N D S T O N E 

KIMMERIDGE CLAY, MANDAL & DRAUPNE FORMATIONS 

P A L E O G E N E R E S E R V O I R S 

CRETACEOUS 

NORTHERN 

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Figure 5. Stratigraphic summary of the North Sea Graben Province (modified from Brennand and others, 1998). 
9 

shale sequences containing relatively low percentages of

organic matter and little sandstone. But in Germany, uppermost Lower Jurassic (Toarcian) sediments accumulated under

near-anoxic conditions, preserving high concentrations of

organic matter. As a result, the Toarcian Posidonia shales are

petroleum source rocks in Lower Saxony (Kockel and others,

1994). This North Sea–North German shale basin lasted until

the Bajocian, when the Central Atlantic rift opened and a rift

dome formed in the North Sea.

The North Sea Dome is an extensional uplift covering

an area of approximately 700,000 km2, centered near the

junction of the Central Graben, Moray Firth/Witch Ground,

and Viking Graben (Ziegler, 1990). The dome, which is

represented in the sedimentary section of the North Sea by the

mid-Cimmerian unconformity (fig. 5) (Underhill and Partington, 1994), fundamentally altered sedimentation patterns in

northwestern Europe, with particular effect in the North Sea

Basin. Because Middle Jurassic sedimentary sequences contain prolific reservoirs of oil and gas, this stratigraphic interval has been documented in detail from logs and seismic lines

(Morton and others, 1992; Steel and Ryseth, 1990). The rising

dome shed sediment to incipient rift basins adjacent to the

Moray Firth/Witch Ground and Central Graben, where thin

sequences of coal-bearing fluvial sandstone accumulated. In

the Central Graben, as much as 1,000 m of nonmarine rocks

was deposited, while a clastic wedge advanced southward into

the southern North Sea and as far as Lower Saxony. Domederived sediments are most important in the Viking Graben,

where the Brent Group provides reservoir rocks for some of

the largest North Sea oil fields (Pegrum and Spencer, 1990;

Johnson and Fisher, 1998). The Brent clastic wedge advanced

northward in and adjacent to the Viking Graben, reaching its

maximum extent at about lat 62°N. during the early Middle

Jurassic (late Bajocian) (fig. 5). The Brent comprises a wide

variety of depositional environments, including channel

sandstones that form major oil and gas reservoirs and various

coastal-barrier and delta-plain sediment packages.

Syn-Rift Geologic History 

By latest Jurassic (Callovian) time, accelerating extension and subsidence caused marine transgression throughout 

the North Sea Graben, halting the northward advance of the 

Brent clastic wedge. The principal phase of extension began in 

Late Jurassic (Middle Oxfordian) time and continued into the 

earliest Cretaceous (Berriasian). Increased subsidence in all 

three grabens (Viking, Moray Firth/Witch Ground, and Central 

Grabens) was accompanied by shoreline retreat and basin 

deepening. Marine sediments accumulated throughout the 

graben system, including the site of the North Sea Dome. 

Late Jurassic extension formed a series of long, narrow,

interconnected basins, open northward to the Boreal sea and

southward to Tethys. Except for coarse siliciclastic deposits

derived from erosion of local structures, sediment consisted

of fine-grained mudstones, commonly laminated and rich in

organic matter. Most rapid sedimentation occurred during the

Summary of the Geologic History of the North Sea 

Late Jurassic near the major bounding fault systems of the

grabens. At places in the western Viking Graben, Kimme

ridgian shales are more than 2,000 m thick. In much of the

Central Graben, sediment thickness exceeds 1,000 m. In the

deepest parts of the Danish Central Graben, Upper Jurassic

rocks are more than 4,000 m thick.

Simultaneously with deposition of the early Late Jurassic to earliest Cretaceous (Oxfordian to Berriasian, but mainly 

Kimmeridgian) shales, uplift and erosion of various structural 

blocks generated coarse sandstones and conglomerates deposited in fans near the base of the fault blocks (Cornford and 

Brooks, 1989). Each of the sandstones, being locally derived, 

displays individual characteristics. For example, the Brae Formation consists of westward-thinning, coarse clastic wedges 

deposited adjacent to a growth fault on a compacting hanging-wall syncline in the southern Viking Graben. The Piper 

Formation in the Moray Firth/Witch Ground is a sandstonerich marine deposit of equivalent age to the Kimmeridge Clay, 

variously interpreted to be a shallow-marine deltaic deposit 

or a fluvial system. The Fulmar Formation also comprises a 

series of shallow-marine shoreline sequences deposited in the 

Central Graben. Each of the coarse siliciclastic deposits was 

derived locally and interfingers with the fine-grained, organiccarbon-rich shales of the Kimmeridge Clay and equivalent 

formations (Cornford, 1998). 

In the Viking Graben and the Moray Firth/Witch Ground, 

extensional structures consist of complex sets of half-grabens 

arranged more or less symmetrically about the basin axis. 

Uplift of the footwall and subsidence of the hanging wall 

characterize most fault-bounded traps, and subaerial erosion 

of the uplifted footwall blocks provided a sediment supply for 

accompanying deposition adjacent to the fault on the hanging 

wall (Glennie, 1998a). In the Viking Graben, relief of

1,500 m can be documented on such structures (Ziegler, 

1990). In the Central Graben the structural pattern is different, 

typically consisting of uplifted horst blocks and intervening 

basins. The difference in structural style is further complicated 

by the presence of thick Zechstein evaporites beneath the 

Central Graben, which have reacted to stresses by differential 

diapiric flow (Pegrum and Spencer, 1990). 

Post-Rift Geologic History 

Near the end of the Jurassic, the extensional axis shifted

westward to the proto-Atlantic basin. Rifting in the North

Sea had largely ceased by the end of Early Cretaceous time

(Ziegler, 1990). Steep geothermal gradients associated with the

extensional tectonics decayed, and the regional pattern became

one of gradual cooling and associated subsidence, especially

near the axis of the abandoned rift, where post-rift sediments

accumulated to greatest thickness. The only real exception to

the tectonic quiescence was in the Moray Firth/Witch Ground,

where uplift interrupted the burial history and coarse clastic

sediment accumulated to form the reservoirs of a few fields,

such as Claymore (Cornford, 1998). To the south, Late Cretaceous to earliest Paleocene post-rift rocks are dominated by
10 Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province 

fine-grained pelagic carbonates (chalks) (Hancock and Scholle,

1975). Little or no chalk is found north of lat 57°N.

Cretaceous sedimentation subdued the topography, but 

during the early Tertiary, broad regional subsidence continued 

as the steep thermal gradient of the rift faded away (Bowman, 1998; Cornford, 1998; Glennie, 1998a; Ziegler, 1990). 

Post-rift sediments as much as 3,000 m thick accumulated in 

the Viking Graben. The Tertiary sedimentary sequences are 

mainly marine mudstones with locally significant submarine 

fans. Fans deposited during the Paleocene and Eocene are 

particularly significant (Reynolds, 1994). Subsidence and 

sedimentation have continued in many areas throughout the 

Tertiary and Quaternary. The great isostatic differences resulting from erosion of uplifted blocks and accompanying rapid 

sedimentation in subbasins and half-grabens probably initiated 

salt tectonics in the Central Graben (Bain, 1993). Salt movement has continued into the Holocene.

History of Exploration and Production 

North Sea exploration actually began onshore in 1959

with the discovery of the Groningen gas field in the Netherlands by Shell and Esso. To Shell and Esso geologists, the

thick, high-quality Rotliegend reservoirs of Groningen suggested that similar reservoirs might lie offshore (Glennie,

1997). Exploration based on the Groningen geologic model

began in German waters, resulting in scientifically successful

but economically untenable discoveries of low-BTU gas. The

U.K. offshore exploration that began in 1964 discovered some

of the largest fields of the southern gas province (Brennand and

others, 1998). Within 1 year, more than 20 TCF of gas had been

discovered. This volume proved to be enough to glut the U.K.

monopoly gas market (Glennie, 1997), at least temporarily.

Discouraged by the local gas market in the U.K., explorationists began looking elsewhere in the offshore. Drill-stem 

tests detected oil in Danish Danian chalks in 1966 and in chalk 

reservoirs of similar age in the Valhal field of the Norwegian 

sector in 1967. In 1969, Phillips found oil in the structure that 

would be named Ekofisk, the largest field in the Central Graben. Ekofisk provided ample incentive for further exploration, 

leading to a series of discoveries of additional chalk fields in 

Danish and Norwegian waters. The following year, Forties, 

one of the largest North Sea oil fields, with reservoirs in Paleocene marine sandstones, was discovered by British Petroleum 

in U.K. waters. 

Following the discoveries in the Central Graben, intense 

seismic acquisition around the North Sea allowed identification of numerous buried structures in the Central Graben, 

Moray Firth/Witch Ground, and Viking Graben. In 1971, 

Shell/Esso drilled a large buried structure in the Viking Graben 

and discovered Brent field. Brent reservoirs were a novelty, 

consisting of mid-Jurassic deltaic sandstones of pre-rift 

origin. The discovery of Brent field, with 2 billion barrels of 

recoverable liquids, prompted a new exploration strategy in 

the North Sea, resulting in numerous discoveries, especially 

in the Viking Graben. Also in 1971, Argyll field was discovered, demonstrating that Auk field (discovered 1969) was not 

a unique example of substantial oil reservoirs in Paleozoic 

rocks. Pursuit of the Brent exploration model, seeking shallow-marine or marginal-marine sandstone reservoirs in fault 

blocks, resulted in the discovery of 10 major fields during the 

following 4 or 5 years, including Statfjord, which was discovered by Mobil Corporation in 1974.

 During the same period, exploration by Occidental in the 

somewhat neglected area of the Moray Firth/Witch Ground 

found Piper and Claymore fields. Piper and Claymore share a 

pre-rift reservoir age with the large Brent fields of the Viking 

Graben but, like Magnus field in the far north of the province, 

have reservoirs of shallow-marine, coastal origin. 

In about 1975, the attention of the explorationists turned 

from the deltaic/shallow-marine sandstones of the pre-rift 

sequences back to the Upper Jurassic, seeking hard-to-locate, 

coarse-grained syn-rift reservoirs immediately adjacent to 

major fault blocks. This effort resulted in the discovery of 

North Brae field and others in the Viking Graben and in the 

discovery of Ula and Fulmar fields to the south. 

Application of greatly improved seismic geophysics facilitated exploration for more subtle traps. Discovery of the Frigg 

gas field in the Viking Graben and Beatrice and Buchan fields 

in the Moray Firth/Witch Ground demonstrated the viability 

of exploration there. By the early 1980s, however, most of the 

U.K. Central Graben had been made available for leasing, and 

it was becoming clear that the sizes of fields being found had 

declined significantly. Exploration strategy changed somewhat in response, as companies began exploring for smaller 

fields in the hundreds-of-millions-of-barrels volume range. 

The strong downward pressure on oil prices in the mid-1980s 

forced a more cautious strategy as companies became frugal 

with exploration money. The world oil glut was felt strongly 

in the North Sea, and producers curtailed production between 

1985 and 1990. That this decline was largely due to market 

conditions was demonstrated in the early 1990s, when rising 

prices associated with the first Persian Gulf War encouraged 

increased production in the North Sea oil fields. 

Development in the North Sea as a mature petroleum 

province continues with drilling of development wells, development of satellite pools, and application of enhanced recovery techniques to improve production from older fields. At the 

same time, explorationists continue to find new (albeit much 

smaller) oil fields that, together with applications of enhanced 

oil recovery technology to older fields, help to maintain North 

Sea oil production. 

Total Petroleum System: 

Kimmeridgian Shales (402501) 

The predominance of source rocks of a narrow stratigraphic interval and similar lithologic character leads to the 
11 

definition of a single petroleum system. The Kimmeridgian 

Shales Total Petroleum System is defined to include all the 

oil-prone areas of the North Sea Graben. The single petroleum 

system includes the Viking Graben, the Moray Firth/Witch 

Ground, and the Central Graben. The TPS includes as a subset 

the “Mandal-Ekofisk(!) Petroleum System” as defined and 

described by Cornford (1994). Much of the following summary of the Kimmeridgian Shales TPS relies on that publication and on other work by Cornford and his colleagues (for 

example, Cornford, 1998). The decision to treat the entire 

North Sea Graben system as a single TPS was made for the 

sake of simplicity—a detailed analysis of source rock/hydrocarbon relationships in the context of local time/temperature 

exposure is beyond the scope of this paper and of the World 

Energy Project assessment. 

Source Rocks 

Upper Jurassic marine shales are important petroleum 

source rocks worldwide (Ulmishek and Klemme, 1991). 

Global sea-level rise, coupled with high organic productivity 

and increasing water depths, resulted in anoxic bottom waters 

in areas of closed bathymetric basins. The result was thick 

accumulations of moderately organic carbon-rich shales, with 

localized areas of highly organic rich sediment preserved in 

deep basins. 

Rifting reached maximum intensity in the North Sea during Late Jurassic and earliest Cretaceous time (Ziegler, 1990). 

Rapidly deposited marine mudstones, rich in organic matter, 

accumulated widely throughout the rift basins, with depositional thickness locally exceeding 3,000 m. In the North Sea, 

shales believed to have served as petroleum source rocks range 

in age from early Late Jurassic to earliest Cretaceous (Oxfordian to Berriasian), with highly organic-carbon-rich intervals 

found at various stratigraphic levels (Cornford, 1998). These 

organic-matter-rich facies contain from 2 to more than 15 

weight percent total organic carbon (TOC) and are easily 

identified from their high gamma-ray values on logs. For this 

reason these stratigraphic intervals are often called the “Hot 

Shales” of the North Sea. The formations with “Hot Shales” 

include the Kimmeridge Clay in the Moray Firth/Witch 

Ground, the Mandal Formation in the Central Graben, the 

Draupne Formation in the Viking Graben, and the Tau Formation in the Norwegian-Danish Basin. 

Kerogen in the “Hot Shales” is a typical “type II” mixture 

of degraded terrestrial and planktonic marine origin. Detailed 

oil/source-rock correlations and related studies have been done 

on these rocks, such that the oil/source-rock correlation is not 

in doubt (Cornford, 1994, 1998; Underhill, 1998). The source 

rocks containing “Hot Shales” vary in lithology and kerogen 

content. Nevertheless, average source-rock properties have 

been specified by Cornford (1994) for illustrative and calculation purposes. The average “Hot Shale” contains 5 percent 

TOC and has a hydrogen:carbon ratio of 0.9–1.2, with a 

Rock-Eval hydrogen index of 450–600, and a carbon isotopic 

composition of δ13C = –27.6 to –28.7 o/oo. 

Total Petroleum System: Kimmeridgian Shales (402501) 

Rapid sedimentation meant that some of the “Hot Shales” 

were already deeply buried by Cretaceous time. However, 

most of the organic-carbon-rich shales became thermally 

mature with respect to oil generation at various times from the 

Early Cretaceous to the Neogene (fig. 6). Sediment accumulation has been nearly continuous in most of the North Sea 

since the Mesozoic, and in many areas the Kimmeridgian 

shales are presently at their greatest burial depth. Oil generation is thought to have begun in large areas of the North Sea 

by Eocene time. In the Danish and Norwegian Central Graben 

and in the Viking Graben, rapid sediment accumulation in 

Neogene to Holocene time (Cornford, 1986, 1998) accounts 

for much of the thermal maturity of the Kimmeridgian shales. 

In the Moray Firth/Witch Ground and southernmost Viking 

Graben, as well as in the Egersund Basin, uplift since latest 

Cretaceous time has essentially arrested maturation of the 

Kimmeridgian kerogen. 

Depth of burial of Kimmeridgian “Hot Shales” provides 

a reasonably good proxy for thermal maturity (Day and others, 

1981). Figure 7 shows depth of burial of the base Cretaceous 

seismic reflector, as well as the diverse burial histories of the 

Upper Jurassic source rocks. The Central Graben and the 

northern Viking Graben, in particular, display significant burial 

and presumably thermal maturity in Paleogene and Neogene 

time. The southern Viking Graben/Moray Firth/Witch Ground 

area is clearly at much shallower burial depths. 

Reservoirs 

Inasmuch as the entire North Sea Graben system shares a 

single source-rock interval, the reservoirs of the Kimmeridgian Shales Total Petroleum System include virtually all 

possible reservoirs of the North Sea. The reservoirs are by no 

means uniformly distributed in time or space, and their diverse 

character is responsible for much of the geologic complexity of the petroleum distribution. It is convenient to group the 

reservoirs temporally with respect to the timing of the major 

episode of rifting. Accordingly, this paper refers to pre-rift 

reservoirs, syn-rift reservoirs, and post-rift reservoirs. This 

usage is compatible with that commonly used by geologists 

involved with the geologic history and petroleum geology of 

the area (for example, Johnson and Fisher, 1998; Pegrum and 

Spencer, 1990).

Pre-Rift Reservoirs of Pre-Jurassic Age 

Pre-rift reservoirs of pre-Jurassic age contain a relatively

small fraction of North Sea hydrocarbons. In most of the

fields that produce from pre-Jurassic reservoirs, pre-Upper

Jurassic rocks have been stripped away by erosion on the

uplifted footwall. The faulted, eroded reservoirs are in close

proximity to thermally mature source rocks, indicating that

migration distances in these fault-block reservoirs were short.

Pre-Zechstein sequences including Rotliegend sandstones

are reservoirs in Argyll and Auk fields. Buchan field has
12 Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province 

TEMPERATURE, IN DEGREES CELSIUS 

Time (Ma) 

200 150 100 50 0 

0 

20 

 EARLY MIDDLE LATE EARLY TRIASSIC JURAS- JURAS- JURAS- CRETA- LATE

SIC SIC SIC CEOUS

CRETAPALEO- NEOCEOUS GENE GENE

Danish

Central 

IMMATURE Graben 

Inner

Moray

Firth 

EARLY 

MATURE 

MID OIL 

Viking Graben MATURE CONDENSATE 

LATE 

MATURE Norwegian

GAS Central

Graben

THERMAL

GAS 

60 

2 

100 

4 

140180 6 

DEPTH, IN KILOMETERS 

Figure 6. Burial curves for several localities of the northern and central North Sea (modified from Cornford, 1998). 
Brent

Gullfaks

Total Petroleum System: Kimmeridgian Shales (402501) 13 

1° 0° 1°E 2°E 3°E 4°E 5°E 6°E 

62° 

61° 

60° 

59° 

58° 

57° 

56° 

Claymore

More Agat

Thistle

Cormorant

Snorre

Oseberg

Alwyn

Ninian

N

Frigg

Piper

Gannet

Ekofisk

Albuskjell

Andrew

BraeMiller

Buchan

North

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Sea

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100 KILOMETERS 

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Figure 7. Approximate depth to base of Cretaceous rocks in the Central and Viking Grabens with names and locations of certain oil and gas fields (modified from Day and others, 1981). 

0 
14 Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province 

reservoirs in Devonian nonmarine red beds. Zechstein carbonates, especially where they are extensively leached and fractured,

can also be reservoirs, as in Auk and Argyll. Triassic to Lower

Jurassic reservoirs are typically thick fluvial sandstones. According to Brennand and Van Veen (1975), the Zechstein reservoir in

Auk field produces from porosity that was enhanced by intensive

Early Cretaceous weathering. Argyll field, in addition to carbonate reservoirs, produces from sandstones of the Rotliegend. The

largest field in the North Sea that produces from pre-Jurassic reservoirs is Snorre, in the Norwegian sector of the northern Viking

Graben. In Snorre, mudstones of Cretaceous age unconformably overlie and seal Triassic reservoir rocks (Hollander, 1987).

According to Pegrum and Spencer (1990), Triassic and Lower

Jurassic reservoirs in Snorre field are found in tilted fault blocks

that expose 1,000 m of strata to a 300-m oil column.

Pre-Rift Reservoirs of Early and Middle 

Jurassic Age 

Pre-rift reservoirs of Early and Middle Jurassic age are 

considered separately from the pre-Jurassic reservoirs because 

of their substantial contribution to hydrocarbon accumulations 

in the Viking Graben. The oldest Jurassic reservoirs are marginal-marine to nonmarine fluvial sediments of the Statfjord 

Formation. More than 200 m of high-porosity sandstones are 

present at Statfjord, where they conformably rest on nonmarine red beds of Triassic age. These basal Jurassic sandstones are found throughout the Viking Graben, including at 

Statfjord and Beryl fields, where they are overlain by marine 

shales of the Dunlin Group.

Overlying the Statfjord Formation and the Dunlin Group

are strata of the Brent Group, which dominate oil and gas

production in the Viking Graben. The Brent rocks are diachronous, transgressing time and prograding from south to north.

The basal Brent is typically upper shoreface sandstone overlain

by shallow-marine, delta-front sandstones. The best reservoirs

of the Brent Group are in barrier-bar and delta-top deposits

(Budding and Inglin, 1981). Nonmarine rocks containing

carbonaceous shales, coals, and sandstones deposited in various coastal-swamp, alluvial-plain, and back-bay environments

overlie these high-quality reservoirs. The uppermost rocks of

the Brent are transgressive sandstones that are overlain by Late

Jurassic (Callovian and younger) marine shales. The sandstones

of the Brent Group are the main producing reservoirs for most

fields of the northern Viking Graben, including Alwyn, Brent,

Cormorant, Dunlin, Gullfaks, Heather, Hutton, Murchison,

Ninian, and Statfjord. In addition, Middle Jurassic sandstones

are reservoirs in the southern Viking Graben and elsewhere in

the North Sea, as in Bruce, Beryl, and Beatrice in the Moray

Firth/Witch Ground, and in Brisling, Bream, Harald, and others

in and near the Central Graben.

Syn-Rift Reservoirs 

Syn-rift reservoirs are restricted to those reservoir rocks

actually deposited during maximum extension. During this

time, the depositional mode in the North Sea Graben changed

from the progradational depositional systems accumulating

outward from the North Sea Dome to that of marine transgression and erosion of local structural relief. Coarse-grained

marine sandstones and conglomerates accumulated adjacent to

fault blocks. These syn-rift deposits display great variation in

thickness, lithology, and reservoir quality and are best developed as reservoirs in the southern Viking Graben, Moray Firth/

Witch Ground, and northern Central Graben. For example, in

the south Viking Graben, submarine fans of the Brae Formation

accumulated adjacent to the Fladen Ground Spur and there provide reservoirs for several fields including Brae and Miller. In

the Moray Firth/Witch Ground, shallow-marine transgressive

sandstones of the Piper Formation overlie Oxfordian-age deltaic sandstones. These are the reservoirs at Piper and Claymore,

the largest fields in the Moray Firth/Witch Ground.

Shallow-marine sandstones of Middle and Late Jurassic 

(Bathonian to Kimmeridgian) age accumulated outside of the 

main rift in the area of Troll field, evidently in response to 

local tectonic uplift in Norway. At Troll, sandstone reservoirs 

have high porosity and permeability, with net sand reservoir 

thickness of more than 200 m. At about 1,000-m depth, Troll 

is the shallowest large field in the North Sea. Shallow marine 

sandstones of Late Jurassic age also form reservoirs far to the 

north in Magnus field in the Viking Graben.

Only the lowermost and oldest part of the Cretaceous 

sequences can be fairly considered syn-rift deposits, and these 

are largely confined to the Moray Firth/Witch Ground, where 

Cretaceous sandstones form reservoirs in Scapa and Claymore 

fields. The sandstone reservoirs were deposited in submarine 

fans adjacent to rapidly eroding fault blocks.

Post-Rift Reservoirs 

Post-rift reservoirs range in age from Early Cretaceous 

to Eocene. South of approximately lat 57°N., Cretaceous and 

earliest Paleocene reservoir rocks are mainly chalk. In fact, 

few reservoirs exist in the Upper Cretaceous except for chalk. 

The chalks are well known for high initial porosities and low 

permeabilities and for their steep porosity decline with depth 

(for example, Scholle, 1977; Taylor and Lapre, 1987). Reservoirs are of acceptable quality where overpressuring, early oil 

migration, or some other mechanism has preserved porosity. 

The chalk reservoirs are commonly found in gravityredeposited settings, such as in slump blocks or debris flows. 

In many cases, the chalk reservoirs are related to salt structures.

Paleocene sandstone reservoirs are best developed in the 

northern Central Graben and the southern Viking Graben. In 

the Central Graben, the provenance of Paleocene sandstones is 

the Caledonian basement in Scotland, the Shetland Platform, 

and as yet unspecified western sources. The best reservoirs 

were deposited as massive, channelized grain-flow deposits. 

Paleocene sandstones are concentrated in the broad central 

trough areas of the former rift basins (Milton and others, 

1990). A fine example of such reservoirs is Forties field, where 
15 

permeabilities of 500 millidarcies and porosities of almost

30 percent are reported for reservoirs hundreds of meters thick 

(Abbotts, 1991). Other well-known fields with Paleocene reservoirs include Maureen, Montrose, Frigg, Heimdal, Balmoral, 

Gannet, and Arbroath (Abbotts, 1991).

Seals 

In contrast to the southern North Sea, where the Zechstein

evaporites serve as a regional permeability barrier for all manner

of hydrocarbon accumulations, in the central and northern North

Sea, the diversity of hydrocarbon accumulations is matched

by the wide variety of seals and traps. Oil and gas accumulations in pre-rift reservoirs commonly are found in tilted fault

blocks where seals are formed by various fine-grained post-rift

sedimentary sequences that drape the Late Jurassic structures.

For example, in the Auk and Argyll fields, where Zechstein

carbonates and Rotliegend sandstones are reservoirs, traps are

sealed by unconformably overlying Cretaceous chalk, by Jurassic claystone, and by low-permeability zones in the Rotliegend

as well as by fine-grained Triassic rocks. In the mid-Jurassic

Brent reservoirs of the Viking Graben, traps are sealed vertically

by unconformably overlying Jurassic and Cretaceous shales.

Lateral seals result from the juxtaposition of shales and reservoir sandstones at fault contacts.

In many syn-rift submarine-fan and turbidite reservoirs, 

such as those of the Brae trend, the seal is temporally equivalent to Kimmeridge Clay. In the Piper and Claymore fields 

of the Moray Firth/Witch Ground, Kimmeridge Clay overlies 

the shallow-marine sandstone reservoirs and provides most 

of the trapping mechanism, although in places fine-grained 

Cretaceous rocks also overlie the reservoir rocks. Similarly, in 

the Central Graben, Kimmeridgian shales that are temporally 

equivalent to the reservoirs seal the Ula and Fulmar fields. In 

syn-rift reservoirs of earliest Cretaceous age, such as those in 

Claymore field, the seals are fine-grained Cretaceous mudstones, marls, and chalks. 

Fields with post-rift reservoirs require fine-grained facies 

in the Tertiary for seals. For example, virtually no chalk fields 

are found where early Tertiary sandstones overlie the chalk. 

Evidently, the sandstones provide a conduit for oil moving out 

of the chalks. Likewise, where post-rift reservoirs are Paleocene and Eocene sandstones deposited in submarine channel 

and fan systems, facies relationships exert primary control on 

oil entrapment. 

Timing of Oil Migration and Entrapment 

In most areas of the North Sea Graben, source rocks have 

undergone almost continuous subsidence and burial since 

their deposition (Cornford, 1994, 1998; Pegrum and Spencer, 1990). A noteworthy regional exception is in the Moray 

Firth/Witch Ground, where thick Kimmeridgian shales had 

only barely reached the oil window before uplift in the Paleogene. In certain restricted areas of greatest subsidence and 

Assessment Units 

most rapid sediment accumulation, the Kimmeridgian source 

rocks attained thermal maturity with respect to oil generation 

as early as Cretaceous time. By Eocene time, oil generation 

was widespread. Subsidence and burial of the source rocks 

continues to this day in most of the North Sea Graben, and, 

with the exception of the Moray Firth/Witch Ground, source 

rocks are currently at their maximum temperature and burial 

depth. In some areas of continuous burial, source rocks have 

exceeded the temperature range for oil generation and have 

reached thermal maturity with respect to gas during Neogene 

to Holocene time. 

Rates of subsidence and burial have been nonuniform 

across the North Sea Graben, with the locus of most rapid 

deposition trending southward through time. As a result, the 

reconstructed burial-history curves of the Viking Graben and 

the Central Graben are somewhat different (fig. 6). Maximum 

subsidence rates in the northern Viking Graben occurred in 

the Late Cretaceous, in the southern Viking Graben and Witch 

Ground during the Early Tertiary, and in the Central Graben 

during the Neogene and Holocene. 

Trap formation in various parts of the North Sea Graben 

has also occurred continuously from latest Jurassic/earliest 

Cretaceous time to the present. For example, the chalkreservoir fields of the southern Central Graben show clear evidence of oil entrapment soon after deposition in the Late Cretaceous (Taylor and Lapre, 1987; Cornford, 1994). However, 

continuous burial and structural accommodation has yielded 

an almost continuous supply of newly generated oil to various structures of the North Sea. A continuous generation and 

migration process by which traps are continually “topped off” 

with new petroleum generated over a wide span of time has 

been postulated (Cornford and Brooks, 1989) to be a major 

factor in the abundance of North Sea oil. 

Assessment Units 

Serious consideration was given to conducting the 

assessment of the North Sea Graben Province on the basis of 

stratigraphically defined AUs (pre-Jurassic reservoirs, post-rift 

reservoirs, and so forth). As the foregoing discussion shows, 

in many ways the geologic setting of petroleum is dominated 

by timing of reservoir deposition with respect to Late Jurassic 

extensional events. Nevertheless, in the end, the assessment 

was based on geographically defined AUs. This approach was 

intended to capture regional differences in exploration history 

and geography and, in addition, to address the significantly 

different geologic histories of various parts of the North Sea 

Graben. As a methodological exercise, the North Sea Graben Province was actually assessed twice—once informally, 

using stratigraphically defined AUs, and once using geographically defined AUs. However, only the geographically 

defined AUs are reported in the final publication as the official 

USGS assessment. The geographically defined AUs are the 

Viking Graben (40250101), the Moray Firth/Witch Ground 

(40250102), and the Central Graben (40250103). 
16 Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province 

5° 0 5°E 

Norway 

60° Bergen 

United 

Kingdom North

Sea

Edinburgh 

Glasgow 

55° 

Liverpool 

0 100 200 300 KILOMETERS 

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Figure 8. Boundaries of the Viking Graben Assessment Unit (40250101). 
17 

Assessment Unit 1: 

The Viking Graben (40250101) 

The Viking Graben is a north-northeast-trending rift 

system that is north of about lat 58°N. and east of long 1°E. 

(fig. 8). Its southern terminus is at its junction with the Central 

Graben and the Moray Firth/Witch Ground (fig. 4). The Viking 

Graben as such extends northward to north of lat 62°N. The 

AU boundary extends beyond the structural extent of the 

Viking Graben to include areas of production or prospective 

production that are genetically related to the accumulations of 

the Viking Graben (fig. 2). Thus, the Viking Graben Assessment Unit extends eastward to near the Norwegian coastline 

and includes the Troll field and adjacent areas. 

It is helpful to consider the resources of the Viking Graben

in terms of reservoir age relative to Late Jurassic rifting, with

respect to the relationship of the known and expected undiscovered fields to timing of structural deformation, and to

the timing of oil expulsion, migration, and entrapment. This

stratigraphic basis for analysis follows the usage and strategy of

many explorationists and authors working in the area, including

Fjaeran and Spencer (1991), Johnson and Fisher (1998), and

Pegrum and Spencer (1990).

In the Viking Graben, pre-Jurassic reservoirs are a minor 

part of the petroleum system, with only a few notable fields. 

In contrast, pre-rift rocks of Early to Middle Jurassic age are 

of major significance. The oldest reservoir rocks, such as the 

nonmarine to marginal-marine sandstone reservoirs in the Statfjord field, are in the Statfjord Formation. Rocks deposited as 

part of the so-called Brent Delta in Middle Jurassic time, however, dominate the reservoirs of the Viking Graben (Morton 

and others, 1992; Abbotts, 1991). The diachronous prograding 

sandstones of the Brent Group are involved in the large tilted 

and rotated fault blocks formed during Late Jurassic extension, with westward-dipping blocks on the western side of 

the graben and eastward-dipping blocks on the eastern side. 

Syn-rift Kimmeridgian source rocks, the Draupne Formation, 

reached maturity immediately overlying Brent Group carrier 

beds, from which oil migrated updip to traps at the crests of 

the structures. Early-formed oils migrated into these carrier 

beds to accumulate updip, away from the graben axis. 

Syn-rift hydrocarbon accumulations in the Viking Graben 

are perhaps best known from the Brae trend in the southern 

Viking Graben, where oil migrated short distances at high 

expulsion efficiencies. The oil expelled from Kimmeridgian 

shales accumulated nearby in coarse-grained syn-rift

submarine-fan and turbidite reservoirs. Late-stage gas generation from stratigraphically similar source rocks migrated much 

farther up the flanks of the graben, accumulating in syn-rift 

sandstone reservoirs that in some cases lie outside the graben 

boundaries, as in the Troll field.

All known accumulations in post-rift reservoirs also are

sourced from the Kimmeridgian. Such accumulations are

relatively less significant in the Viking Graben than in the

Central Graben; nevertheless, a few significant fields exist in

post-rift reservoirs. Examples include Balder and Frigg fields.

Assessment Units 

In most cases, syn-rift accumulations lie near faults, which

are invoked as near-vertical migration pathways for fields

with post-rift reservoirs.

Assessment Unit 2: 

The Moray Firth/Witch Ground (40250102) 

The Moray Firth/Witch Ground Assessment Unit

includes that part of the North Sea rift system that is oriented

approximately east-west, between the northeastern coast of

Scotland and the middle of the North Sea. The defined AU

extends well beyond the boundaries of the Mesozoic rift

system itself but is still entirely offshore. The rift system

is between approximately long 1°E. and long 3°W., lying

between lat 57°40′N. and lat 58°40′N. (fig. 9). Included

within this AU are the structures known as the Moray Firth

Basin, the Buchan Horst, and the Witch Ground Graben.

Throughout this text, the area including these structures is

collectively referred to as the Moray Firth/Witch Ground.

The Moray Firth/Witch Ground trends west from the 

junction of the Viking, Central, and Witch Ground Grabens 

that coincided with the central location of the North Sea 

Dome. Rapid subsidence following the doming occurred during the Callovian (late Middle Jurassic) to Kimmeridgian. This 

initial subsidence was accompanied by the marine transgression that deposited both shallow-marine sandstones that later 

were to serve as reservoir rocks and the Upper Jurassic shales 

that are the principal source rocks for hydrocarbons throughout the North Sea Graben Province. Early Cretaceous marine 

sands with provenance in the Scottish Highlands and adjacent 

Shetland Platform largely filled the graben. 

Sedimentation in the Moray Firth/Witch Ground was 

similar to the Central Graben and the southern Viking Graben 

during most of its pre-Tertiary history. However, uplift of the 

Moray Firth/Witch Ground beginning in the Late Cretaceous 

and Paleocene truncated the sedimentary record and abbreviated the time-temperature history. As a consequence, Jurassic 

source rocks in the Moray Firth/Witch Ground are only marginally mature with respect to oil generation in a very limited 

area, and they never achieved thermal maturity with respect to 

oil or gas generation over a wide part of the AU. The continuous deposition and accommodation observed elsewhere in the 

North Sea Graben Province was interrupted after the Cretaceous. The organic-carbon-rich shales of the Jurassic are not 

as rich, and they have not achieved the same level of thermal 

maturity as shales elsewhere in the North Sea. This abbreviated time-temperature history is probably responsible for the 

diminished sizes and number of hydrocarbon accumulations 

found in the Moray Firth/Witch Ground as compared to the 

geologically similar Viking Graben and Central Graben. 

Beatrice field is in the Inner Moray Firth, distant from

any possible mature Upper Jurassic source rock. Beatrice

is believed to have had a different source rock than most

fields of the North Sea, with Middle Jurassic shales or even

Devonian source rocks postulated by Cornford (1986). If this
18 Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province 

Bergen 

Glasgow 

Edinburgh 

Liverpool 

North

Sea

United 

Kingdom 

Norway 

0 100 200 300 KILOMETERS 

5° 0 5°E 

60° 

55° 

Index map �������������������������������������������

�����������

��������������������������������������������������������

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Figure 9. Boundaries of the Moray Firth/Witch Ground Assessment Unit (40250102). 
19 

is correct, Beatrice properly should be considered part of

another petroleum system. The other fields in the AU are clustered near the junction with the Viking and Central Grabens,

where marginally mature Jurassic shales are present. Typical

of the Moray Firth/Witch Ground fields are Buchan and Claymore. Buchan field, on the edge of the Witch Ground, produces from Old Red Sandstone. The sandstone reservoirs are

on the crest of a tilted and eroded fault block. Jurassic source

rocks have evidently provided the charge at Buchan but are

only marginally mature near the field. Claymore field, on the

southwest margin of the Witch Ground, produces from Upper

Jurassic sandstones of the Piper and Sgiath Formations. In

addition to these Jurassic sandstones, production also comes

from overlying Cretaceous sandstones, from unconformably

underlying Carboniferous sandstones, and from Permian

carbonate rocks. Kimmeridgian mudstones provide the cap

rock for most of the reservoirs. At Piper field, the reservoir

is mainly in the shallow-marine and deltaic sandstones of the

Heather Group (Sgiath and Piper Formations). The trapping

structure is a major northwest-southeast fault zone, with dip

closures on the northeast. The Kimmeridge Clay provides

the lateral and top seals, and the trap consists of several tilted

fault blocks.

Assessment Unit 3: The Central Graben 

(40250103) 

The Central Graben is that part of the North Sea Graben

system that extends in a northwest-southeast trend between

about long 5°E. and the Prime Meridian, and between about lat

52°N. and lat 58°N. (fig. 10). The AU is entirely offshore. Its

boundaries extend well beyond the Late Jurassic extensional

structures. Politically, the Central Graben is located in the Norwegian, United Kingdom, and Danish sectors of the North Sea.

In the Central Graben, source rocks are confined to the 

Mandal Formation, also called the Farsund Formation in the 

Tail End Graben (Cornford, 1994), which is equivalent to 

the upper part of the Kimmeridge Clay and Draupne Formation to the north. The Mandal, which reportedly contains an 

average of 8 weight percent TOC, is now thermally mature 

with respect to oil generation over a wide area of the Central 

Graben. In contrast to the Viking Graben, burial has tended to 

increase later in the history of the Central Graben. In addition, 

extensive evaporite deposits of the Zechstein Group underlie 

the Central Graben. Therefore, in addition to the rift-related 

structures that predominate in the Viking Graben and Moray 

Firth/Witch Ground, halokinetic structures have strongly influenced migration pathways in the Central Graben. 

Three broad categories of reservoir and migration pathway

are recognized. The first contains fields with reservoirs of

Jurassic or pre-Jurassic age. The second category is that of the

chalk reservoirs. The third contains fields reservoired in sandstones of submarine fan complexes or related turbidite systems.

In category one, pre-rift or syn-rift reservoir rocks are 

involved in tilted fault blocks. Examples include the Argyll 

Undiscovered Resources of the North Sea Graben 

and Auk fields, where hydrocarbons are trapped in southwestward-dipping, tilted fault blocks. Reservoirs in Argyll are 

Zechstein Group carbonates with fractures and vugular porosity formed during postdepositional uplift, Rotliegend eolianite sandstones, and Devonian fluvial sandstones. In nearby 

Auk field, reservoirs include a Zechstein dolomite, which is 

the most volumetrically important reservoir of the field, the 

Rotliegend, which produces from eolian and fluvial facies, 

and various Cretaceous carbonate rocks. The trap is mainly 

stratigraphic but within a tilted horst block, with erosional 

truncation of Zechstein carbonates, Rotliegend sandstones, and 

Lower Cretaceous breccias beneath a subchalk unconformity. 

Chalk Group reservoirs, the second reservoir category,

predominate in the southern part of the Central Graben,

mainly in the Norwegian and Danish sectors. In productive

fields, chalk reservoirs have retained high porosities as a

result of early oil migration and the development of overpressuring. Chalk fields occur in traps with four-way closure,

commonly resulting from the effects of salt diapirism and

structural inversion. Migration into these traps probably

occurred during or shortly after deposition of the Paleocene

mudstone seal. The significance of the Paleocene seals is

demonstrated by the fact that the chalk play is limited to areas

where Paleogene sandstones are absent. Some of the most

important fields in the North Sea have chalk reservoirs. The

largest of these is Ekofisk, where slumping of calcareous

pelagic ooze contributed to the preservation of high porosity

and establishment of a discrete structure/seal pair. Most chalk

fields are found where salt diapirs, piercements, and pillows

have provided local structures and where fine-grained Paleogene mudstones form an effective seal. Prominent chalk fields

include Edda, Ekofisk, Eldfisk, Hod, Dan, and Albuskjell.

Post-rift sandstone reservoirs are the third major reservoir 

type. Most of these reservoirs were deposited within submarine-fan complexes in comparatively deep water. The largest 

fields and best reservoirs, such as Forties, Montrose, and Cod, 

are concentrated in fans deposited near the axis of the Central 

Graben rift system, although significant fields also exist in 

laterally accumulated submarine fans, such as those at Gannet 

field complex. Reservoir porosities of 25–30 percent are common in these sandstones, consistent with relatively shallow 

burial at the time of hydrocarbon entry into the reservoir. Seals 

are provided by overlying and laterally equivalent mudstones 

of Tertiary age. For example, Forties field has a trap that is an 

anticline with four-way dip closure. Reservoirs are massive 

sandstones deposited by turbidity currents. The sandstones 

are stacked and amalgamated, with little or no evidence of the 

fine-grained facies common to submarine fan systems (Bowman, 1998). In addition to Forties, large fields with Paleogene 

sandstone reservoirs include Montrose, Lomond, Cod, Maureen, Arbroath, and Balder. Although the Upper Jurassic Mandal Formation is generally agreed to be the source rock for 

these oil accumulations, several major fields are not underlain 

by thermally mature Upper Jurassic strata, indicating significant lateral hydrocarbon migration into these traps (Cornford, 

1998). This category of field is limited on the eastern side of 
20 Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province 

5° 0 5°E 

Norway 

60° Bergen 

United 

Kingdom North

Sea

Edinburgh 

Glasgow 

55° 

Liverpool 

0 100 200 300 KILOMETERS 

Index map �������������������������������������������

�����������

���������������������������������������

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Figure 10. Boundaries of the Central Graben Assessment Unit (40250103). 
Table 1. Assessment results summary for the Kimmeridgian Shales Total Petroleum System 402501, including results for three assessment units. 

[MMBO, million barrels of oil. BCFG, billion cubic feet of gas. MMBNGL, million barrels of natural gas liquids. MFS, minimum field size assessed (MMBO or BCFG). Prob., probability (including both geologic and accessibility probabilities) of at least one field equal to or greater than the MFS. Results shown are fully risked estimates. For gas fields, all liquids are included under the NGL (natural gas liquids) category. F95 represents a 95-percent chance of at least the amount tabulated. Other fractiles are defined similarly. Fractiles are additive under the assumption of perfect positive correlation. Shading indicates not applicable] 

40250101 

Oil fields 

Gas fields 

Total 

40250102 

Oil fields 

Gas fields 

Total 

40250103 

Oil fields 

Gas fields 

Total 

402501 

Oil fields

Gas fields

Total 

2 2,256 6,730 14,804 7,412 2,090 6,513 15,741 7,419 116 380 991 

12 4,700 13,513 28,785 14,773 173 528 1,226 

1.00 2,256 6,730 14,804 7,412 6,790 20,027 44,527 22,192 289 908 2,216 1,036 1.00 445 592 

2 857 1,923 947 199 666 1,633 758 11 39 102 

12 356 963 1,732 994 16 47 93 

857 1,923 947 555 1,629 3,365 1,752 28 85 196 95 

269 45 1.00 50 

1.00 269 

Undiscovered resources 

ield 

( ) 

( ) ( ) 

Code 

and f MFS Prob. Oil (MMBO) 

type 0-1 F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean 

Gas BCFG NGL MMBNGL 

Viking Graben Assessment Unit 

Moray Firth/Witch Ground Assessment Unit 

Central Graben Assessment Unit 

Undiscovered Resources of the North Sea Graben 21 

2 1,726 4,391 8,833 4,740 1,259 3,424 7,555 3,791 69 201 478 227 

12 3,231 9,169 19,523 10,011 148 445 1,034 500 

1.00 1,726 4,391 8,833 4,740 4,490 12,594 27,079 13,801 218 646 1,512 728 

Total: Kimmeridgian Shales Total Petroleum System 

4,251 11,978 25,560 13,098 3,548 10,603 24,930 11,967 197 620 1,571 717 

8,287 23,646 50,041 25,778 338 1,019 2,354 1,142 

1.00 4,251 11,978 25,560 13,098 11,835 34,250 74,971 37,745 534 1,639 3,924 1,859 1.00 1.00 
22 Kimmeridgian Shales Total Petroleum System of the North Sea Graben Province 

the basin by the absence of Paleogene sandstones but is not 

clearly limited on the western side of the basin. 

Undiscovered Resources 

of the North Sea Graben 

The principal purpose of the USGS World Petroleum

Assessment 2000 was to develop a set of consistent, scientifically grounded estimates of potential additions to reserves

of oil and gas in the most important petroleum provinces of

the world. In the North Sea Graben Province, this assessment was based upon the evaluation of undiscovered oil and

gas resources in the three assessment units (Viking Graben,

Moray Firth/Witch Ground, and Central Graben) of the Kimmeridgian Shales Total Petroleum System.

Probabilistic evaluations were made of the sizes, numbers, and properties of accumulations of oil, gas, and natural 

gas liquids within each AU. Additional information concerning the history of exploration and production within each AU 

was also provided. Details of the input data and results of the 

World Petroleum Assessment 2000, as well as extensive documentation of methodology and background information used 

in the work, are provided in the four-CD publication U.S. Geological Survey Digital Data Series DDS–60, “U.S. Geological 

Survey World Petroleum Assessment 2000—Description and 

Results” (U.S. Geological Survey World Energy Assessment 

Team, 2000).

Important as methodological considerations are, the 

World Petroleum Assessment 2000, at its core, is based upon 

considerations of the local petroleum geology and the history 

of exploration, discovery, and production. The central and 

northern North Sea has been the site of intensive application 

of sophisticated technology since development began in the 

1960s. Because of the extensive literature and detailed public 

data available, this exploration history was highly influential 

in the assessment process. 

In the course of developing preliminary information 

in advance of the formal assessment, several approaches to 

resource analysis in the North Sea were attempted. For example, a numerically based discovery process model was applied 

to the data, with interesting results, some of which have been 

published separately from the World Petroleum Assessment 

2000 report (Drew and Schuenemeyer, 1997). 

As reported in the World Petroleum Assessment 2000 

report (table 1), undiscovered oil resources in the North Sea 

Graben Province as a whole were estimated to range from 4.3 

to 25.6 billion barrels of oil (BBO), with a mean estimate of 

about 13 BBO. In addition to these quantities of undiscovered 

conventional oil and associated and nonassociated natural gas, 

the North Sea Graben Province probably contains significant 

additional amounts of natural gas liquids in both oil and gas 

accumulations. 

Of this province-level total, the Viking Graben was 

believed to contain 2.3 to 14.8 BBO, with a mean estimate of 

7.4 BBO. The Moray Firth/Witch Ground was thought to have 

about 0.3 to 1.9 BBO and a mean value of slightly less than

1 BBO of undiscovered oil. The Central Graben was estimated 

to have undiscovered oil resources of 1.7 to 8.8 BBO, with a 

mean value of 4.7 billion barrels. 

It was also estimated that the province contains 11.8 to 

75.0 trillion cubic feet (TCF) of undiscovered associated and 

nonassociated natural gas in fields larger than 12 billion cubic 

feet (BCF), with a mean estimate of 37.7 TCF. The Viking 

Graben was estimated to contain the most undiscovered 

natural gas, with a range of 6.8 to 44.5 TCF undiscovered and 

a mean value of 22.2 TCF. The Moray Firth/Witch Ground 

was thought to have between 0.6 and 3.4 TCF of undiscovered 

conventional natural gas in fields larger than 12 BCF and a 

mean undiscovered gas resource of about 1.8 TCF. The Central 

Graben was estimated to hold between 4.5 and 27.1 TCF of 

undiscovered gas with a mean estimate of 13.8 TCF in fields 

larger than 12 BCF. 

During the previous USGS world assessment, published 

by Masters and others (1997), an assessment was made of “the 

Central North Sea” of the United Kingdom and Norway, an 

area similar to the North Sea Graben Province of the World 

Petroleum Assessment 2000. In that study, which used different methods, data, and people, undiscovered oil resources 

were estimated to be about 10 BBO, and undiscovered gas 

resources were estimated to be about 40 TCF, provincewide. 

Thus, the mean values of undiscovered oil and gas resources 

in the present study are similar to those of the previous study, 

with the current study reporting slightly more undiscovered oil 

and slightly less undiscovered gas. 

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