U.S. Department of the Interior

U.S. Geological Survey

Total Petroleum Systems of the

Paleozoic and Jurassic, Greater Ghawar Uplift 

and Adjoining Provinces of

Central Saudi Arabia and

Northern Arabian-Persian Gulf

By Richard M. Pollastro

U.S. Geological Survey Bulletin 2202-H
U.S. Department of the Interior

Gale A. Norton, Secretary

U.S. Geological Survey

Charles G. Groat, Director

Version 1.0, 2003

For more information about the USGS and its products:

Telephone: 1-888-ASK-USGS

World Wide Web: http://www.usgs.gov/

This publication is only available online at:

http://pubs.usgs.gov/bul/b2202-h/

Any use of trade, product, or firm names in this publication is for descriptive purposes only and does not imply 

endorsement by the U.S. Government.
iii

Contents

Foreword ........................................................................................................................................................ 1

Abstract.......................................................................................................................................................... 3

Introduction ................................................................................................................................................... 3

Acknowledgments........................................................................................................................................ 6

U.S. Geological Survey Geologic Provinces of Central Saudi Arabia and Gulf Area........................ 6

Greater Petroleum Systems of the Eastern Arabian Peninsula............................................................ 9

Tectonic Evolution and Structural Setting................................................................................................ 9

Stratigraphy of Central Saudi Arabia and Greater Ghawar Region ................................................... 18

Pre-Khuff Section................................................................................................................. 18

Late Permian Through Jurassic......................................................................................... 20

Central Arabia Qusaiba-Paleozoic Total Petroleum System ............................................................... 24

General Description............................................................................................................. 24

Petroleum Geochemistry .................................................................................................... 24

Source Rocks............................................................................................................... 24

Organic Geochemistry................................................................................................ 29

Maturation, Generation, and Expulsion................................................................... 29

Reservoirs.............................................................................................................................. 39

Seal Rocks............................................................................................................................. 42

Traps and Trap Styles .......................................................................................................... 42

Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System..................................................... 44

General Description............................................................................................................. 44

Petroleum Geochemistry .................................................................................................... 44

Source Rocks............................................................................................................... 44

Organic Geochemistry................................................................................................ 49

Maturation, Generation, and Expulsion................................................................... 49

Reservoirs.............................................................................................................................. 52

Seal Rocks............................................................................................................................. 56

Traps and Trap Styles .......................................................................................................... 56

Assessment Unit Description, Geologic Models, and Assessment Results..................................... 57

Central Arabia Qusaiba-Paleozoic TPS............................................................................ 57

Central Arch Horst-Block Anticlinal Oil and Gas AU (20210101) ......................... 57

North Gulf Salt Basin Structural Gas AU (20210102) ............................................. 65

Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS ................................................................. 65

Horst-Block Anticlinal Oil AU (20210201)................................................................. 65

Salt-Involved Structural Oil AU (20210202) ............................................................. 68

Summary ...................................................................................................................................................... 72

Selected References.................................................................................................................................. 75

Appendix 1. Seventh Approximation Input Form for Central Arch Horst-Block Anticlinal Oil and 

Gas Assessment Unit (20210101), Central Arabia Qusaiba-Paleozoic

Total Petroleum System................................................................................................................ 81

Appendix 2. Seventh Approximation Input Form for North Gulf Salt Basin Structural Gas 

Assessment Unit (20210102), Central Arabia Qusaiba-Paleozoic Total

Petroleum System ......................................................................................................................... 86
iv 

Appendix 3. Seventh Approximation Input Form for Horst-Block Anticlinal

Oil Assessment Unit (20210201), Arabian Sub-Basin Tuwaiq/Hanifa-Arab

Total Petroleum System................................................................................................................ 91

Appendix 4. Seventh Approximation Input Form for Salt-Involved Structural Oil Assessment 

Unit (20210202), Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System........... 96

Figures

1. Diagram showing stratigraphic section, major tectonic events, and stratigraphic

units of petroleum systems of the eastern Arabian Peninsula............................................ 4

2–7. Maps showing:

 2. USGS geologic provinces of central Saudi Arabia and northern Arabian-Persian

Gulf, and details of oil and gas fields and reservoirs ........................................................ 5

 3. Arabian Plate showing general tectonic and structural features, salt basins, and oil 

and gas fields........................................................................................................................... 7

 4. Jurassic intraplatform sub-basins of Arabian-Persian Gulf region................................ 8

 5. Paleozoic and Jurassic total petroleum systems of Gotnia sub-basin........................ 10

 6. USGS geologic provinces, oil and gas field centerpoints, and total petroleum

systems of central Saudi Arabia and northern Arabian-Persian Gulf.......................... 11

 7. Cretaceous, Jurassic, and Paleozoic total petroleum systems and oil and gas field

centerpoints of Rub’al Khali Province (2019).................................................................... 12

8. Sketch block diagrams showing evolution of Arabian Plate tectonics............................ 14

9. Geologic cross section across Saudi Arabia and Qatar..................................................... 15

10. Geologic subcrop map of Hercynian or “Pre-Unayzah” unconformity ............................ 16

11. Structural cross section of central Ghawar field................................................................. 17

12. Chart showing growth history of major tectonic events and relative intensities ........... 19

13. Diagram showing stratigraphic column and tectonostratigraphic events of the

Paleozoic section in Greater Ghawar area ........................................................................... 21

14. General stratigraphic section of the Upper Jurassic Arab Formation ............................. 23

15. Map showing Central Arabia Qusaiba-Paleozoic Total Petroleum System

and assessment units ............................................................................................................... 25

16. Paleoenvironmental map of the Early Silurian showing approximate extent

of the Qusaiba Shale Member of the Qalibah Formation on Arabian Peninsula ............ 26

17–19. Maps showing:

 17. Central Arabia and Rub ’al Khali Basin showing details of oil and gas fields

 producing from the Paleozoic........................................................................................ 27

 18. Geographic extent and present-day zones of hydrocarbon generation

 for Silurian Qusaiba Shale Member ............................................................................. 28

 19. Mean field API gravities and general locations of oil and gas fields in central

 Saudi Arabia and northern Arabian-Persian Gulf producing from Pre-Khuff

 and Khuff or younger formations .................................................................................. 30

20. Diagram showing relation between gamma-ray response and total organic

carbon in transitional-type, basal hot shale of lower Qusaiba Member source rock ... 31

21. Events chart for Central Arabia Qusaiba-Paleozoic Total Petroleum System (202101) . 32

 22. Diagram showing burial history and hydrocarbon generation model for base

of Silurian Qusaiba source rock in Udaynan well ................................................................ 34

23. Diagrams modeling hydrocarbon expulsion history from Qusaiba source rock............. 35
v

24. Diagram showing Khuff and Pre-Khuff section along basin monocline from

Dilam field to Abu Jifan field.................................................................................................... 36

25. Maps of central Arabia and Greater Ghawar area showing expulsion of oil and gas 

from Qusaiba hot shale............................................................................................................. 37

 26. Map showing Central Arabia Qusaiba-Paleozoic Total Petroleum System, active 

source rock, and oil and gas field centerpoints ................................................................... 38

 27. Paleogeographic map during the Early Permian, showing erosion or nondeposition, 

dune fields, probable glacial lake, and dominant wind direction in central Arabian 

Peninsula..................................................................................................................................... 40

28. Isopach map of the Unayzah Formation in central Saudi Arabia...................................... 41

29. Generalized map describing the Khuff Formation in Arabian Peninsula and

Zagros Fold Belt......................................................................................................................... 43

 30. Map showing Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System,

Horst-Block Anticlinal Oil Assessment Unit, and Salt-Involved Structural

Oil Assessment Unit .................................................................................................................. 45

31. Events chart for Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System 

(202102)........................................................................................................................................ 46

32. Map showing oil and gas fields of the Arabian-Persian Gulf with reservoirs

 in Jurassic rocks....................................................................................................................... 47

33. Paleogeographic map of Jurassic sub-basins of Arabian-Persian Gulf region ............. 48

 34. Isopach map of petroleum source-potential units of Upper Jurassic Tuwaiq

Mountain Formation .................................................................................................................. 50

35. Map summarizing present-day extent of thermal maturity levels and distribution of 

source facies for the Jurassic Hanifa Formation................................................................. 51

36. Maps of central Saudi Arabia showing expulsion of oil from Jurassic source rocks ... 53

37. Diagram showing burial history and petroleum generation model for Tuwaiq/Hanifa 

source rocks near Safaniya field ............................................................................................ 54

38. Map showing paleoenvironment and tectonic reconstruction of the Late

Jurassic, late Tithonian of Arabian Plate............................................................................... 55

39. Map showing general structural trends of Greater Ghawar Uplift and

surrounding area ....................................................................................................................... 58

40–46. Plots showing:

 40. Known oil-field size and grown oil-field size versus field discovery year

 for Central Arch Horst-Block Anticlinal Oil and Gas Assessment Unit .................. 60

 41. Known gas-field size versus field discovery year and grown gas-field

 size versus cumulative number of new-field wildcat wells for Central

 Arch Horst- Block Anticlinal Oil and Gas Assessment Unit ..................................... 61

 42. New-field wildcat wells versus drilling completion year, cumulative number

 of oil fields versus field discovery year, and cumulative number of gas fields

 versus field discovery year for Central Arch Horst-Block Anticlinal Oil and

 Gas Assessment Unit...................................................................................................... 62

 43. Known oil-field size and grown oil-field size versus field discovery year for

 Horst-Block Anticlinal Oil Assessment Unit................................................................ 66

 44. New-field wildcat wells versus drilling completion year and cumulative

 number of new-field wildcat wells versus drilling completion year for

 Horst-Block Anticlinal Oil Assessment Unit................................................................ 69

 45. Known oil-field size versus field discovery year and grown oil-field size

 versus field discovery year for Salt-Involved Structural Oil Assessment Unit ..... 71

 46. New-field wildcat wells versus drilling completion year and cumulative

 number of new-field wildcat wells versus drilling completion year for

 Salt-Involved Structural Oil Assessment Unit............................................................. 73
vi

Tables

1. Assessment summary for Central Arabia Qusaiba-Paleozoic Total Petroleum System 

(202101)................................................................................................................................................. 59

2. Known and grown volumes of discovered petroleum and discovery-history sequence

for Central Arch Horst-Block Anticlinal Oil and Gas Assessment Unit (20210101).................. 64

3. Assessment summary results for Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total

Petroleum System (202102)............................................................................................................... 67

4. Known and grown discovered volumes of petroleum resources and discovery-history 

sequence for Horst-Block Anticlinal Oil Assessment Unit (20210201)....................................... 70

5. Known and grown discovered volumes and discovery-history sequence for

Salt-Involved Structural Oil Assessment Unit (20210202)............................................................ 74
Foreword

This report was prepared as part of the U.S. Geological Survey World Petroleum Assessment 2000. The primary 

objective of World Petroleum Assessment 2000 was to assess 

the quantities of conventional oil, gas, and natural gas liquids 

outside the United States that have the potential to be added to 

reserves in the next 30 years. Parts of these assessed volumes 

reside in undiscovered fields whose sizes exceed the stated 

minimum-field-size cutoff value for the assessment unit, 

which is variable but must be at least 1 million barrels of oil 

equivalent. Another part of these assessed volumes occurs 

as reserve growth of fields already discovered. However, 

the contribution from reserve growth of discovered fields to 

resources is not covered for the areas treated in this report.

In order to organize, evaluate, and delineate areas to 

assess, the authors of World Petroleum Assessment 2000 

developed a hierarchical scheme of geographic and geologic 

units. This scheme consists of regions, geologic provinces, 

total petroleum systems, and assessment units. For World 

Petroleum Assessment 2000, regions serve as organizational 

units and geologic provinces are used as prioritization tools. 

Assessment of undiscovered resources was done at the level of 

the assessment unit.

The world was divided into 8 regions and 937 geologic 

provinces. These provinces have been ranked according to 

the discovered known oil and gas volumes (Klett and others, 

1997). Then, 76 “priority” provinces (exclusive of the United 

States and chosen for their high ranking) and 26 “boutique” 

provinces (exclusive of the United States) were selected for 

appraisal of oil and gas resources. Boutique provinces were 

chosen for their anticipated petroleum richness or special 

regional economic or strategic importance.

A geologic province is an area having characteristic 

dimensions of hundreds of kilometers that encompasses a natural geologic entity (for example, a sedimentary basin, thrust 

belt, or accreted terrane) or some combination of contiguous 

geologic entities. Each geologic province is a spatial entity 

with common geologic attributes. Province boundaries were 

drawn as logically as possible along natural geologic boundaries, although in some places they were located arbitrarily 

(for example, along specific water-depth contours in the open 

oceans). Specifically, geologic provinces of the Arabian Peninsula are shown in Pollastro and others (1999).

Total petroleum systems and assessment units were 

delineated for each geologic province considered for assessment. The boundaries of total petroleum systems and assessment units need not be entirely contained within a geologic 

province. Particular emphasis is placed on the similarities of 

petroleum fluids within total petroleum systems, in contrast 

to geologic provinces and plays in which similarities of rocks 

are emphasized.

The total petroleum system includes all genetically 

related petroleum that occurs in shows and accumulations (discovered and undiscovered) generated by a pod or by closely 

related pods of mature source rock. Total petroleum systems 

exist within a limited mappable geologic space, together with 

the essential mappable geologic elements (source, reservoir, 

seal, and overburden rocks). These essential geologic elements 

control the fundamental processes of generation, expulsion, 

migration, entrapment, and preservation of petroleum within 

the total petroleum system.

An assessment unit is a mappable part of a total petroleum system in which discovered and undiscovered oil and gas 

fields constitute a single relatively homogeneous population 

such that the methodology of resource assessment based on 

estimation of the number and sizes of undiscovered fields is 

applicable. A total petroleum system might equate to a single 

assessment unit. If necessary, a total petroleum system may be 

subdivided into two or more assessment units such that each 

assessment unit is sufficiently homogeneous in terms of geology, exploration considerations, and risk to assess individually. 

Differences in the distributions of accumulation density, trap 

styles, reservoirs, and exploration concepts within an assessment unit were recognized and not assumed to extend homogeneously across an entire assessment unit.

A numeric code identifies each region, province, total 

petroleum system, and assessment unit. The criteria for assigning codes are uniform throughout the project and throughout 

all publications of the project. The numeric codes used in this 

study are:

Total Petroleum Systems of the Paleozoic and Jurassic, 

Greater Ghawar Uplift and Adjoining Provinces of

Central Saudi Arabia and Northern Arabian-Persian Gulf

By Richard M. Pollastro
2 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

A graphical depiction that places the elements of the total 

petroleum system into the context of geologic time is provided in the form of an events chart. Items on the events chart 

include (1) the major rock-unit names; (2) the temporal extent 

of source-rock deposition, reservoir-rock deposition, sealrock deposition, overburden-rock deposition, trap formation, 

generation-migration-accumulation of petroleum, and preservation of petroleum; and (3) the critical moment, which is 

defined as the time that best depicts the generation-migrationaccumulation of hydrocarbons in a petroleum system (Magoon 

and Dow, 1994). The events chart serves only as a timeline 

and does not necessarily represent spatial relations.

Probabilities of occurrence of adequate charge, rocks, and 

timing were assigned to each assessment unit. Additionally, 

an access probability was assigned for necessary petroleumrelated activity within the assessment unit. All four probabilities, or risking elements, are similar in application and address 

the question of whether at least one undiscovered field of 

minimum size has the potential to be added to reserves in the 

next 30 years somewhere in the assessment unit. Each risking 

element thus applies to the entire assessment unit and does not 

equate to the percentage of the assessment unit that might be 

unfavorable in terms of charge, rocks, timing, or access.

Estimated total recoverable oil and gas volumes (cumulative production plus remaining reserves, called “known” 

volumes hereafter) quoted in this report are derived from 

Petroconsultants, Inc., 1996 Petroleum Exploration and 

Production database (Petroconsultants, 1996a). To address 

the fact that increases in reported known volumes through 

time are commonly observed, the U.S. Geological Survey (Schmoker and Crovelli, 1998) and the U.S. Minerals 

Management Service (Lore and others, 1996) created a set of 

analytical “growth” functions that are used to estimate future 

reserve growth (called “grown” volumes hereafter). The 

set of functions was originally created for geologic regions 

of the United States, but it is assumed that these regions 

can serve as analogs for the world. This study applied the 

Federal Offshore Gulf of Mexico growth function (developed 

by the U.S. Minerals Management Service) to known oil and 

gas volumes, which in turn were plotted to aid in estimating undiscovered petroleum volumes. These estimates of 

undiscovered petroleum volumes therefore take into account 

reserve growth of fields yet to be discovered.

Estimates of the minimum, median, and maximum number, sizes, and co-product ratios of undiscovered fields were 

made based on geologic knowledge of the assessment unit, 

exploration and discovery history, analogs, and, if available, 

prospect maps. Probabilistic distributions were applied to 

these estimates and combined by Monte Carlo simulation to 

calculate undiscovered resources.

Several illustrations in this report that show boundaries 

of the total petroleum systems, assessment units, and extent 

of source rocks were compiled using Environmental Systems 

Research Institute’s (ESRI) geographic information system 

(GIS) ARC/INFO and ESRI ArcView software. The political 

boundaries shown were taken with permission from ESRI’s 

ArcWorld 1:3M digital coverage; these boundaries are not 

politically definitive and are displayed for general reference 

only. Oil and gas field centerpoints were provided by, and 

reproduced with permission from, Petroconsultants (1996a 

and 1996b).

Unit Name Code

Region Middle East and North Africa 2

Province Greater Ghawar Uplift 2021

Total Petroleum Systems Central Arabia Qusaiba-Paleozoic 202101

Arabian Sub-Basin Tuwaiq/Hanifa-Arab 202102

Assessment Units Central Arch Horst-Block Anticlinal Oil and Gas 20210101

North Gulf Salt Basin Structural Gas 20210102

Horst-Block Anticlinal Oil 20210201

Salt-Involved Structural Oil 20210202
Abstract

The greater Paleozoic and Jurassic petroleum systems of 

the Arabian Peninsula form two of the most prolific petroleum-producing systems in the world. Source rocks of these 

systems extend throughout the eastern Arabian Peninsula and 

Arabian-Persian Gulf. Primary elements of these Paleozoic 

and Jurassic petroleum systems—source, reservoir, and seal 

rocks—are of great areal extent and exceptional quality. The 

combination of these regionally extensive, exceptional petroleum-system elements, and the formation of large subtle structural closures prior to, or coincident with, peak oil generation 

and migration, have produced oil and gas fields with reserve 

volumes second to none.

Two total petroleum systems (TPS), one of Paleozoic 

age and one of Jurassic age, in the central part of the Arabian 

Peninsula are identified in this report. The Central Arabia 

Qusaiba-Paleozoic TPS and the Arabian Sub-Basin Tuwaiq/

Hanifa-Arab TPS of Jurassic age encompass the Greater 

Ghawar Uplift Province (USGS Province 2021) and portions 

of adjoining geologic provinces. Structures that trap hydrocarbons in these systems are mostly (1) large, gentle anticlines formed from reactivated basement fault blocks, (2) salt 

domes that resulted from halokinesis, or (3) structural traps 

resulting from a combination of these two processes. Major 

tectonic events that created these structures resulted from 

early Zagros rifting during the Early Triassic and two Alpine 

tectonic episodes that occurred during the Late Cretaceous 

and middle to late Tertiary.

Hydrocarbons of the Central Arabia Qusaiba-Paleozoic 

TPS are sourced mainly by organic-rich, so-called “hot shale” 

that occurs in the basal part of the Lower Silurian Qusaiba 

Member of the Qalibah Formation. Oil and gas are produced 

mainly from sandstones of the Permian Unayzah and Devonian Jauf Formations, and from basal transgressive marine 

sandstones and cyclic, dolomitic shelf-carbonates of the Late 

Permian Khuff Formation. Two assessment units (AU) are 

recognized in the Central Arabia Qusaiba-Paleozoic TPS that 

are related to type of structural trap and presence of underlying 

Infracambrian salt: (1) the onshore Central Arch Horst-Block 

Anticlinal Oil and Gas AU, and (2) the mostly offshore North 

Gulf Salt Basin Structural Gas AU. The mean total volume 

of undiscovered resource for the Central Arabia QusaibaPaleozoic TPS is estimated at about 108 billion barrels of oil 

equivalent (BBOE).

Oil of the Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS 

is sourced by organic-rich, marine carbonates of the Jurassic 

Tuwaiq Mountain and Hanifa Formations. These source rocks 

were deposited in two of three intraplatform basins during 

the Jurassic and, where thermally mature, have generated a 

superfamily of oils with distinctive geochemical characteristics. Oils were generated and expelled from these source 

rocks beginning in the Cretaceous at about 75 Ma. Hydrocarbon production is from cyclic carbonate-rock reservoirs 

of the Arab Formation that are sealed by overlying anhydrite. 

Several giant and supergiant fields, including the world’s 

largest oil field at Ghawar, Saudi Arabia, produce mostly from 

the Arab carbonate-rock reservoirs. Two assessment units 

are also recognized in the Arabian Sub-Basin Tuwaiq/HanifaArab TPS that are similarly related to structural trap style and 

presence of underlying Infracambrian salt: (1) an onshore 

Horst-Block Anticlinal Oil AU, and (2) a mostly offshore 

Salt-Involved Structural Oil AU. The mean total volume of 

undiscovered resource for the Arabian Sub-Basin Tuwaiq/

Hanifa-Arab TPS is estimated at about 49 billion barrels of oil 

equivalent (42 billion barrels of oil, 34 trillion feet of gas, and 

1.4 billion barrels of natural gas liquids).

Introduction

Three areally extensive, overlapping petroleum systems of Paleozoic, Jurassic, and Cretaceous age (fig. 1) have 

been recognized on the eastern half of the Arabian Peninsula 

(Alsharhan and Nairn, 1997). A fourth, earlier Infracambrian 

(Gulf PetroLink, 2000) petroleum system is found within the 

geographic limits of most rift salt basins of Infracambrian 

age. These four systems extend across eight USGS priority 

provinces (Ahlbrandt and others, 2000). Source, reservoir, 

and seal rocks of great geographic extent characterize each of 

these prolific hydrocarbon-producing systems of the eastern 

Arabian Peninsula. Total petroleum systems identified in 

this report are defined within more local, structurally bound 

provinces, and over a central area of the Arabian Peninsula 

where three intraplatform sub-basins developed during the 

Jurassic. Thus, total petroleum systems (TPS) described here 

are only part of the more areally extensive petroleum systems 

of the eastern Arabian Peninsula. The purpose of this report 

is to describe and outline the geologic framework, tectonic 

history, and characteristics, elements, evolution, and geographic extent and boundaries of the Paleozoic-age, Central 

Arabia Qusaiba-Paleozoic TPS (202101), and the Jurassic-age, 

Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS (202102). The 

geologic information in combination with the exploration 

and production histories is then used to present the geologic 

models for undiscovered petroleum resources for these two 

total petroleum systems. A third TPS, the Cretaceous-Tertiary 

TPS (203001), lies partly within the Arabian sub-basin and 

also extends into the Zagros and Mesopotamian areas (U.S. 

Geological Survey World Energy Assessment Team, 2000).

The central Arabian sub-basin portion of the Arabian Peninsula encompasses the Greater Ghawar Uplift Province (figs. 

2 and 4) and portions of adjacent geologic provinces along the 

east-central Arabian Peninsula. The Central Arabia QusaibaPaleozoic and Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total 

Petroleum Systems comprise areas within eastern Saudi 

Arabia, western Qatar, and the adjacent northern portion of the 

Arabian-Persian Gulf (North Gulf), where exceptional geochemical and geologic elements form these two stratigraphically stacked, world-class systems. An estimated two-thirds 

Introduction 3
4 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Figure 1. Stratigraphic section, major tectonic events, and stratigraphic units that make up the Greater 

Paleozoic, Jurassic, and Cretaceous petroleum systems of the eastern Arabian Peninsula. Modified from 

Jawad Ali and Al-Husseini (1996), Wender and others (1998), Janahi and Mirza (1991), Chaube and Al-Samahiji 

(1995), and Mendeck and Al-Madani (1995).

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Figure 1. Stratigraphic section, major tectonic events, and stratigraphic units that make up the Greater

Paleozoic, Jurassic, and Cretaceous petroleum systems of the Eastern Arabian Peninsula. Modified

from Jawad Ali and Al-Husseini (1996), Wender and others (1998), Janahi and Mirza (1991), Chaube

and Al-Samahiji (1995), and Mendeck and Al-Madani (1995).

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Figure 2. USGS geologic provinces of central Saudi Arabia and northern Arabian-Persian Gulf, oil and gas field centerpoints, and 

primary age of reservoir for each field. U.A.E., United Arab Emirates.

Introduction 5

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6 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

of the world’s known ultimately recoverable oil is within, and 

adjacent to, the Arabian-Persian Gulf, where a thick sequence 

of sedimentary rocks was deposited in areally extensive basins 

along the eastern and southern parts of the Arabian Peninsula 

(Abu-Ali and others, 1991; Beydoun, 1991; Cole, Abu-Ali, 

and others, 1994; Cole, Carrigan, and others, 1994; Alsharhan and Nairn, 1997; BP Amoco, 2000; Sharland and others, 

2001). This locale encompasses the area east of the Arabian 

Shield, along the Arabian-Persian Gulf, eastward to the Zagros 

Fold Belt and Oman Mountains, and within the political 

boundaries of Saudi Arabia, Kuwait, Iraq, Qatar, Bahrain, 

United Arab Emirates, Oman, Yemen, and Iran.

The USGS recently estimated that the Middle East and 

North Africa region (USGS Region 2) holds about 765 billion 

barrels of oil (BBO). This volume is 58 percent of the world’s 

total known oil reserves, exclusive of the United States, of 

1,326 BBO. Additionally, 706 BBO (53 percent of the total 

exclusive of the United States) is from provinces within the 

Middle East portion (Klett and others, 1997). Subsequently, 

the U.S. Geological Survey World Energy Assessment Team 

(2000) estimated that of the USGS World Regions, the Middle 

East and North Africa region contains the greatest volume of 

the world’s undiscovered oil and gas resources. In particular, 

the U.S. Geological Survey World Energy Assessment Team 

(2000) reported that USGS Region 2 has the greatest potential 

for undiscovered oil in the world (exclusive of the U.S.) with 

an estimated mean total volume of undiscovered technically 

recoverable oil of about 230 BBO. This represents more than 

35 percent of the world’s total estimated 649 billion barrels 

of undiscovered oil (exclusive of the U.S.). Region 2 ranks 

second on a global scale in undiscovered gas potential with an 

estimated volume of 1,370 trillion cubic feet (TCF)—about 

30 percent of the world’s 4,669 TCF total estimated undiscovered natural gas resource (exclusive of the U.S.). The 

Former Soviet Union (USGS Region 1) ranks first in undiscovered, recoverable natural gas with a mean estimate of 1,611 

TCF. The Former Soviet Union, with a mean undiscovered 

oil volume estimated at 106 billion barrels, ranks second in 

undiscovered oil potential. Finally, Region 2 ranks first in 

mean undiscovered natural gas liquids (NGL) with about 82 

BBNGL. This is about 40 percent of the world’s total estimated undiscovered NGL (U.S. Geological Survey World 

Energy Assessment Team, 2000).

Paleozoic and Jurassic organic-rich source rocks of the 

Arabian-Persian Gulf (hereafter, Gulf) region form two of the 

most prolific petroleum-producing systems in the world (fig. 

1); these systems also include regionally extensive reservoirs 

and seals and large structural traps that combine to form many 

supergiant oil and gas fields. The central Arabian total petroleum systems of Paleozoic and Jurassic age contribute most of 

Saudi Arabia’s 261 billion barrels of proven oil reserves, more 

than one-fourth of the world total, with as much as 1 trillion 

barrels of oil in place (Energy Information Administration, 

2000). Although Saudi Arabia has about 80 oil and gas fields, 

more than half of its oil reserves are contained in only eight 

fields. Two of these eight fields are classified as the world’s 

largest oil fields, both located within the Greater Ghawar 

Uplift Province of this report. Ghawar field, Saudi Arabia, 

produces both oil and gas from the Jurassic and Paleozoic 

systems and has estimated known reserves of about 115 BBO 

and remaining reserves of about 70 BBO. Safaniya field, the 

world’s largest offshore oil field, has estimated reserves of 19 

billion barrels (Energy Information Administration, 2000). 

Immediately south of the Greater Ghawar Uplift Province, 

and in the Rub ‘al Khali Province, a Paleozoic total petroleum 

system encompassing the Rub ‘al Khali Basin is sourced by 

the same Lower Silurian organic-rich shale. In this area, nonassociated gas generated from Silurian shale is produced from 

Permian carbonate reservoirs in North field, the largest single 

gas field in the world, which lies in the offshore gulf waters 

of Qatar and Iran. Within Qatar alone, North field has proven 

reserves estimated at about 300–400 TCFG; total recoverable 

reserves for all of North field are estimated at about 500 TCFG 

(Alsharhan and Nairn, 1997; Al-Siddiqi and Dawe, 1999).

Most oil in the central Arabian intraplatform sub-basin 

was generated and produced from a Jurassic carbonate-rock 

petroleum system (figs. 1 and 4). However, oil generated 

within petroleum systems of Cretaceous and Paleozoic age 

also accounts for production in reservoirs of Cretaceous and 

Paleozoic age from other numerous giant fields in, or adjacent to, the east-central Arabian Peninsula. The east-central 

Arabian Peninsula and Arabian-Persian Gulf area is rich in 

petroleum because this locale was once an areally extensive 

depositional platform along a pre-Mesozoic passive margin 

of Gondwana. Subsequent development of multiple intraplatform basins, extensive source-rock deposition within these 

intraplatform basins, and multiple tectonic stages of compression and extension produced large subtle structural closures 

prior to, or coincident with, peak oil generation and migration. 

Finally, the large petroleum resource base was contained by 

efficient horizontal hydrocarbon migration into traps underlying thick, regionally extensive evaporite seals of Cambrian, 

Permian, Jurassic, and Tertiary age (Murris, 1980; Ayres and 

others, 1982; Beydoun, 1991; Cole, Abu-Ali, and others, 1994; 

Cole, Carrigan, and others, 1994; Alsharhan and Nairn, 1997, 

Konert and others, 2001; Zeigler, 2001; among others).

Acknowledgments

The manuscript has benefited greatly from critical and 

constructive reviews by Tom Ahlbrandt, Chris Schenk, and 

Kathy Varnes. The author thanks Lorna Carter for a constructive edit of the manuscript. The author is grateful to Gulf 

PetroLink, publisher of GeoArabia, for permission to publish 

numerous figures that were modified for this manuscript.

U.S. Geological Survey Geologic

Provinces of Central Saudi Arabia

and Gulf Area

Although focused on the Greater Ghawar Uplift Province 

(2021), the total petroleum systems of this report encompass 

parts of other adjoining structural provinces in central Saudi 
Figure 3. Arabian Plate showing general tectonic and structural features, Infracambrian rift salt basins, and oil and gas fields of Central Arabia and from Al-Husseini (2000).

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8 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Arabia and northern portion of the Gulf area as defined 

by the USGS (Klett and others, 1997; Pollastro and others, 1999). The Interior Homocline-Central Arch Province 

(2020) borders the Greater Ghawar Uplift Province to the 

west (fig. 2). The Interior Homocline-Central Arch Province 

is structurally defined by gently dipping sedimentary rocks 

that extend eastward from the Arabian Shield (fig. 3) into 

the Widyan Basin-Interior Platform Province. This structure 

continues into the Mesopotamian Foredeep Basin Province 

(2024) to the east. The structural transition from the Interior 

Homocline into the Interior Platform is marked by a break in 

slope; flat-lying rocks form a platform or terrace to the east. 

An eastward-trending basement ridge, centered along lat 24° 

N., forms the Central Arabian Arch (fig. 3). The arch extends 

eastward from the Arabian Shield toward the Qatar Peninsula 

and is within the south half of the Interior Homocline-Central 

Arch Province. It separates the northeast-dipping, central 

segment of the stable shelf from the southern, east-dipping 

segment and has a complex geologic history (Al-Kadhi and 

Hancock, 1980). The Central Arabian Arch, which apparently originated during the Precambrian, influenced sedimentation during the Phanerozoic and controls the south plunge 

on hydrocarbon-bearing anticlinal closures to the northeast 

(Ayres and others, 1982). The Central Arabian Arch also 

forms part of the north-northwest structural margin of the 

Rub ‘al Khali Basin Province (2019) to the south (fig. 3). 

The arch was slightly positive during the early Paleozoic, as 

pre-Permian sediments seem to pinch out against it (Powers and others, 1966). Strong upwarping occurred during 

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gure 4. Jurassic intraplatform sub-basins of Arabian-Persian Gulf region. Modified from Murris (1980), Alsharhan and

endall (1986), Alsharhan & Magara (1994), and Grabowski & Norton (1995). U.A.E., United Arab Emirates.

Figure 4. Jurassic intraplatform sub-basins of Arabian-Persian Gulf region. Modified from Murris (1980), Alsharhan and Kendall 

(1986), Alsharhan and Magara (1994), and Grabowski and Norton (1995). U.A.E., United Arab Emirates.
post-Early Devonian and pre-Late Permian times, when older 

sediments were peneplaned and stripped from the crest of the 

arch. Later submergence allowed deposition of Late Permian carbonates directly upon the basement across the axis and 

for some distance to the north and south (Powers and others, 

1966; Alsharhan and Nairn, 1997).

Adjacent to and north of the Greater Ghawar Uplift Province is the Mesopotamian Foredeep Basin Province (2024), an 

area covered by Quaternary fluvial-plain, eolian, and lacustrine deposits. The Mesopotamian Foredeep Basin Province is 

bordered on the east-southeast and east-northeast by the Qatar 

Arch Province (2022) and Zagros Fold Belt Province (2030), 

respectively (fig. 2).

In a global ranking of geologic provinces by known 

petroleum volume (cumulative production plus reserves) in 

terms of billion barrels of oil equivalent (BBOE) exclusive of 

the United States, the USGS showed that the Greater Ghawar Uplift Province, although geographically rather limited, 

ranked third, contributing nearly 8 percent (191.7 BBOE) of 

the world total. The adjacent Mesopotamian Foredeep Basin 

Province ranked second with almost 14 percent (344 BBOE), 

the Rub ‘al Khali Basin Province ranked fifth with about 5 

percent (122.8 BBOE), and the Qatar Arch Province ranked 

sixth with about 4 percent (92.5 BBOE) of the world’s total 

known petroleum volume (Klett and others, 1997; 2000).

Greater Petroleum Systems of the

Eastern Arabian Peninsula

The greater Paleozoic and Jurassic petroleum systems of 

the eastern Arabian Peninsula are extensive in both geographic 

scale and hydrocarbon-producing potential; each includes a 

regionally extensive source facies. For this study, these extensive petroleum systems have been locally partitioned into total 

petroleum systems (Ahlbrandt and others, 2000; Magoon and 

Schmoker, 2000) along a north-south trend. Some of these 

total petroleum systems closely correspond geographically 

to the Late Jurassic intraplatform sub-basins shown in figure 

4 (Murris, 1980; Alsharhan and Kendall, 1986; Al-Husseini, 

1997; Mahmoud and others, 1992; Cole, Abu Ali, and others, 

1994; Cole, Carrigan, and others, 1994; Bishop, 1995; Milner, 

1998; Abu-Ali and others, 1999; Jones and Stump, 1999; Zeigler, 2001). In the USGS World Petroleum Assessment (U.S. 

Geological Survey World Energy Assessment Team, 2000), 

names of the total petroleum systems (TPS) were determined 

by age and (or) geologic names of the major source and 

reservoir rocks. For the assessment of the eastern Arabian 

Peninsula, three separate Paleozoic and Jurassic total petroleum systems are defined and described to more accurately 

represent local variations in the more regionally extensive, 

greater Paleozoic and Jurassic petroleum systems (Ahlbrandt 

and others, 2000). The three Paleozoic total petroleum 

systems are defined from north to south as follows: (1) the 

Paleozoic Qusaiba/Akkas/Abba/Mudawwara TPS (202301), 

described by Fox and Ahlbrandt (2002), encompasses an area 

in Saudi Arabia north of the Central Arabian Arch and Hercynian unconformity, the western and southwestern deserts of 

Iraq, and eastern portions of Syria and Jordan (fig. 5); (2) the 

Central Arabia Qusaiba-Paleozoic TPS (202101), described 

in this report, encompasses the entire Greater Ghawar Uplift 

Province (2021) and portions of surrounding provinces (fig. 

6) including much of the North Gulf Salt Basin (fig. 3); and 

(3) the Silurian Qusaiba TPS (201903) of the Rub ‘al Khali 

Province (2019; fig. 7) that also encompasses much of the 

South Gulf Salt Basin (Schenk and Pollastro, 2000; Pollastro, 

Schenk, and Ahlbrandt, 2002) (fig. 3).

Similarly, the greater Jurassic petroleum system of the 

eastern Arabian Peninsula was locally partitioned into three 

total petroleum systems similar to those of the Paleozoic. In 

Kuwait and the northern part of the North Gulf Salt Basin (fig. 

3) within the Jurassic Gotnia intraplatform sub-basin (figs. 4 

and 5) is the Jurassic Gotnia/Barsarin/Sargelu/Najmah TPS 

(202302), described in Fox and Ahlbrandt (2002) (fig. 5). In 

central Saudi Arabia and northern part of the Gulf, a total 

petroleum system sourced by hydrocarbons from the Jurassic 

Arabian intraplatform sub-basin is designated as the Arabian 

Sub-Basin Tuwaiq/Hanifa-Arab TPS (202102) (figs. 5 and 6). 

The Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS, described 

in this report, encompasses the entire Greater Ghawar Uplift 

Province (2021) and the southern part of the Mesopotamian 

Foredeep Basin Province (2024) in the northern part of the 

Gulf that includes the North Gulf Salt Basin (fig. 3). The 

Jurassic Hanifa/Diyab-Arab TPS (201902) is the TPS designated for the southern part of the Gulf region and Rub ‘al 

Khali Basin Province (2019) of Saudi Arabia, United Arab 

Emirates (U.A.E.), Qatar, eastern Oman, and northeastern 

Yemen (fig. 7).

Tectonic Evolution and

Structural Setting

The present-day Arabian Plate (fig. 3) is bounded by a 

variety of complex tectonic regimes. The southern and western margins of the Arabian Plate are Oligocene-Miocene rift 

margins where spreading and rotation formed the Red Sea and 

Gulf of Aden (fig. 3). The eastern and northern margins of the 

Arabian Plate are compressional tectonic settings that formed 

the Zagros Fold Belt of southwestern Iran, the Simple Fold 

Belt of southwestern Turkey, and the Makran Fold Belt where 

subduction occurs in the Gulf of Oman (fig. 3) (Al-Husseini, 

2000; Sharland and others, 2001; Konert and others, 2001).

Sharland and others (2001) summarized the tectonic evolution of the Arabian Plate in five phases as follows:

1. A Precambrian compressional phase (from 715 to 610 

Ma) of island-arc and microcontinent terrane accretion that led 

to the assembly of the Arabian Plate;

2. A late Precambrian to Late Devonian extensional 

phase (from 610 to 364 Ma) when the plate was located in an 

Tectonic Evolution and Structural Setting 9
Figure 5. Paleozoic Qusaiba/Akkas/Abba/Mudawwara and Jurassic Gotnia/Barsarin/Sargelu/Najmah Total Petroleum Systems of Gotnia sub-basin. Qusaiba-Paleozoic and Jurassic Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum Systems are also shown in lower right portion of map.

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Figure 6. USGS geologic provinces, oil and gas field centerpoints, and Cretaceous-Tertiary, Jurassic, and Paleozoic total petroleum systems of centern Arabian-Persian Gulf. Note location of the Greater Ghawar Uplift Province (2021). U.A.E., United Arab Emirates.
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Figure 7. Cretaceous, Jurassic, and Paleozoic total petroleum systems and oil and gas field centerpoints ofRub 'al Khali Basin Province (2019) and Jurassic South Arabian Gulf intraplatform sub-basin (see figure 4).

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Figure 7. Cretaceous, Jurassic, and Paleozoic total petroleum systems and oil and gas field centerpoints of Rub ‘al Khali Province (2019) in area of Sform sub-basin. 
intracratonic setting in low to moderate latitudes with a passive margin to the Paleo-Tethys Sea. This phase contained the 

first preserved sediment deposited within the extensional rift 

basins formed from the Najd fault system (fig. 3);

3. A Late Devonian to mid-Permian phase (from 364 to 

255 Ma) when the plate was located in a general back-arc setting in moderate southern latitudes and partly coeval with the 

“Hercynian Orogeny.” This phase started and finished with 

extensional stresses, separated by a period of compression;

4. A largely Mesozoic extensional phase (from 255 

to 92 Ma) when the plate was located in an equatorial setting and progressive continental rifting occurred around 

the plate, leading to north- and southeast-facing passive 

margins. Late Permian, Triassic, and Jurassic sedimentation was dominated by carbonate-evaporite deposition, and 

Early Cretaceous was dominated by open-marine mixed 

clastic-carbonate deposits; and

5. A late Mesozoic to present-day phase (from 92 Ma 

to present) during which the plate was located in a compressive, broadly active margin setting in essentially its presentday position. This phase commenced with the onset of the 

first ophiolite obduction in Oman onto the previously passive 

margin with numerous subsequent obductions. This phase 

resulted in development of a narrow foredeep basin, closure 

of the Neo-Tethys Sea (fig. 8), uplift of the Oman Mountains 

and Zagros Fold Belt, and rifting and spreading of the Gulf of 

Aden and Red Sea.

Sharland and others (2001) also described in detail the 

sequence stratigraphy of the Arabian Plate. Through the 

stratigraphy, Sharland and others (2001) identified, dated, 

and correlated maximum flooding surfaces (MFS) across the 

Arabian Plate and provided time lines for chronostratigraphic 

interpretations. These sequence stratigraphic interpretations of 

the Arabian Plate place source, reservoir, and seal lithologies 

in a chronostratigraphic framework and allow identification, 

characterization, and construction of each petroleum system 

element within specific time intervals.

The great hydrocarbon-bearing traps of the Arabian 

Plate subsequently resulted as reactivated structures from 

the Precambrian Amar Collision between about 640 and 620 

million years ago (Ma). The collision occurred along the 

north-trending Amar Suture that bisects the Arabian Peninsula 

at about long 45° E. (fig. 3) and formed a regional, systematic 

and regular north-, northeast-, and northwest-trending structural pattern as a result of compression. For example, Ghawar field and Safaniya field are located on the 500-km-long, 

north-trending En Nala Anticline (fig. 3) (Al-Husseini, 2000). 

Immediately to the east of the En Nala Anticline is the northtrending Qatar Arch, and to the west is another 500-km-long, 

north-trending anticline, the Khurais-Burgan Anticline, that 

extends from Saudi Arabia’s Khurais field to Kuwait’s Burgan 

field, the world’s second largest oil field (fig. 3).

The Amar Collision was followed by a widespread 

extensional collapse of the Arabian Shield between about 620 

and 530 Ma, during which the north-trending anticlines probably remained elevated as elongated horsts bounded by faults 

(Al-Husseini, 2000). During the final extensional stage (about 

570 to 530 Ma), the regional, northwest-trending Najd fault 

system was developed. The Najd fault system dislocated the 

Arabian Shield left-laterally by about 250–300 km during this 

final extensional stage and formed a series of complementary 

northeast-trending rift basins (fig. 3) in the Arabian-Persian 

Gulf, Oman, Yemen, Pakistan, the Rub ‘al Khali Basin, and 

Zagros Mountains (Schmidt and others, 1979; Brown and others, 1989; Loosveld and others, 1996; Oterdoom and others, 

1999; Al-Husseini, 2000; Konert and others, 2001; Sharland 

and others, 2001; Zeigler, 2001). The rift basins are approximately perpendicular to the Najd fault zone and the orogenic 

collision front and are related to escape tectonism (Molnar and 

Tapponier, 1975; Stern, 1994; Webster, 2000; Blood, 2001). 

Major subsiding rift basins of the Arabian-Persian Gulf, 

Oman, and Rub ‘al Khali areas formed during Infracambrian 

and Early Cambrian time. During this period the Arabian 

Plate was close to the equator (Konert and others, 2001), and 

massive salt was deposited in these restricted rift basins early 

in their history (Gorin and others, 1982; Husseini and Husseini, 1990; Mattes and Conway-Morris, 1990; Al-Husseini, 

2000). Oterdoom and others (1999) reported that in Oman, 

this rifting period, which was between about 570 and 530 Ma, 

is represented by deposition of the Infracambrian Huqf Supergroup. In the eastern Arabian Peninsula, these Infracambrian 

rift salt basins include, but are not restricted to, the Hormuz 

Salt basins of the Gulf area and the Ghaba, Fahud, and South 

Oman (Ara) salt basins of Oman (fig. 3). Smaller scale 

Infracambrian rift basins of similar origin and sedimentary fill 

have recently been reported or recognized on seismic profiles 

in the central and eastern portion of the Rub ‘al Khali Basin 

and along the main Najd fault trend (Dyer and Al-Husseini, 

1991; Faqira and Al-Hawuaj, 1998; Milner, 1998; Blood, 

2000, 2001; Al-Husseini, 2000; Konert and others, 2001; Sharland and others, 2001; Zeigler, 2001) (fig. 3). Because these 

rift basins contain thick salt deposits and multiple, stacked 

petroleum systems of Infracambrian through Tertiary age, 

they play an important role in the occurrence and migration of 

hydrocarbons, and in hydrocarbon trap formation throughout 

the eastern Arabian Peninsula.

A thick sequence of Phanerozoic sediments (greater than 

12,000 m) accumulated along the eastern Arabian Peninsula 

and present-day Arabian-Persian Gulf (fig. 9). In this area, a 

pre-Mesozoic depositional basin, the Greater Arabian basin, 

was of extraordinary extent—thousands of kilometers long 

by about 2,000 km wide. From a structural standpoint, it was 

quite flat, thus providing an ideal setting for deposition on a 

large geographic extent of source, reservoir, and seal rocks 

(Murris, 1980; Beydoun, 1991; Cole, Abu Ali, and others, 

1994; Cole, Carrigan, and others, 1994; Alsharhan and Nairn, 

1997). Progressive burial of the geographically extensive 

source, reservoir, and seal rocks on a gentle structural setting 

allowed for efficient horizontal migration that could drain 

large, mature petroleum-generating source areas into extraordinarily large gentle structural closures. In particular, deposition of thick and areally extensive evaporite seals, combined 

Tectonic Evolution and Structural Setting 13
14 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Figure 8. Evolution of Arabian Plate tectonics from early Paleozoic to Late Permian and Triassic, showing Early Devonian “Hercynian” compressional event and Early Zagros rifting event. Modified from McGillivray and Husseini (1992).

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Figure 8. Two important stages in the evolution of Arabian Plate tectonics from a stable shelf setting

during the early Paleozoic to Late Permian and Triassic. 1) Early Devonian "Hercynian" compression,

and 2) Late Permian and Triassic Zagros rifting. Modified from McGillivray and Husseini (1992)
with this gentle structural setting, allowed only minimal loss 

of hydrocarbons through fractures. Trapping in this multiple, 

stacked petroleum systems setting was aided by multiple 

tectonic stages and the halokinesis of thick underlying salt that 

resulted in reactivation or continued growth of primary anticlinal and domal structures. Additionally, peak oil generation 

coincided with major structural growth events in the foreland 

forming the multiple giant and supergiant fields that mark this 

petroleum-rich area along the eastern Arabian Peninsula and 

Gulf area.

During the Devonian, a structural event interpreted as 

a crustal response to compression uplifted central Arabia 

and tilted the Arabian Plate eastward (Husseini, 1991). As a 

result, the northeast margin of Gondwana was transformed 

from a passive to an active compressional margin (Beydoun, 

1991). This major tectonic event, the Hercynian Orogeny, 

had a dramatic effect on the geology of the Arabian Peninsula 

(fig. 8). Changes in basin geometry, regional uplift, basement-cored uplifts, and the evidence of folding and inversion 

tectonics suggest that the Arabian Plate underwent multiple 

phases of compression during the Hercynian Orogeny (Konert 

and others, 2001). In particular, the Hercynian event caused 

reactivation of basement structures and formed major northsouth-trending, basement-involved horst blocks in central and 

eastern Saudi Arabia. These reactivated basement-involved 

structures were later sites of extensive erosion and structural 

trap formation that were favorable for hydrocarbon accumulation (figs. 10 and 11). The north-south-trending Hercynian uplifts, such as Ghawar (on which the Ghawar field is 

located), are bounded by reverse faults (fig. 9), suggesting that 

the uplift was due to a regional compressive stress field.

Following Hercynian uplift, structural development was 

less significant during the Permian, and the Arabian Plate was 

essentially a passive margin setting (McGillivray, 1994). The 

first extensive deposits following the Hercynian Orogeny 

were braided-plain, channel-fill, and eolian clastics resting 

on the angular Hercynian unconformity. The post-Hercynian 

sedimentation pattern then shifted from a primarily siliciclastic 

Figure 9. Geologic cross section across Saudi Arabia and Qatar from Arabian Shield to Arabian-Persian Gulf showing 

basement reverse faults and Precambrian (Infracambrian) salt. Modified from Alsharhan and Nairn (1997) and Konert 

and others (2001). Barbs show relative movement on faults.

Tectonic Evolution and Structural Setting 15

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Figure 9. Geologic cross section across Saudi Arabia and Qatar from Arabian Shield to Arabian-Persian

Gulf. Modified from Alsharhan and Nairn (1994) and Konert and others (2001).
16 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Figure 10. Geologic subcrop map of Hercynian or “Pre-Unayzah” unconformity showing differential erosion of both Hercynian substructures (such as ‘Ain Dar, Shedgum) at Ghawar field and adjacent structures 

(Abqaiq, Waqr), Saudi Arabia. Well cross section for line Y–Y ‘ shown in figure 11. Modified from Wender 

Figureand others (1998). 10. Geologic subcrop map of Hercynian or "Pre-Unayzah" Unconformity showing differential

erosion of both Hercynian substructures (e.g., 'Ain Dar, Shedgum) at Ghawar field and adjacent structures

(e.g., Abqaiq, Waqr), SaudiArabia. Well cross section for line Y-Y' shown in figure 11. Modified from

Wender and others (1998).

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Figure 11. Structural cross section of central Ghawar field showing basement-involved block faulting and HSee figure 10 for location of cross section. Modified from Wender and others (1998). Arrows show moveme

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Figure 11. Structural cross section of central Ghawar field showing basement-involved block faulting and Hercynian growth for Middle Jurassic and for location of cross section. Modified from Wender and others (1998). Barbs show relative movement on faults.
18 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

regime to a prolonged phase of carbonate ramp and platform 

deposition with interspersed clastic episodes. During the 

Triassic, extensional faulting was widespread in response to 

thermal subsidence and stretching of the Arabian Plate. During this Early Zagros extensional event, earlier Hercynian 

structures were reactivated and enhanced. Rifting continued 

along the Zagros Suture and the Neo-Tethys Sea opened (figs. 

3 and 8).

During the Late Triassic and Jurassic, the Arabian-Persian Gulf region was a stable interior platform located along 

the equator (Konert and others, 2001). A period of sea-level 

lowstand in the Early Jurassic is marked by a hiatus of nondeposition and erosion (fig. 1). Subsequent to this depositional 

hiatus, a transgression flooded the Arabian Peninsula and a 

shallow-marine, mostly carbonate platform developed. During 

the Middle and Late Jurassic, continued deposition of mostly 

carbonate and anhydrite beds occurred in warm equatorial latitudes. Sequence stratigraphic studies by Al-Husseini (1997) 

and Sharland and others (2001) show that cyclic changes in 

lithology (mostly carbonate/evaporite) of the Late Jurassic 

section (fig. 1) were due mainly to cyclic changes in relative 

sea level.

Three major post-Jurassic tectonic events were critical to 

major petroleum trap formation and modification that created the giant fields of the Paleozoic, Jurassic, and Cretaceous 

petroleum systems in the Central Arabian sub-basin (Wender 

and others, 1998). These major post-Jurassic tectonic events 

are (1) Early Triassic Zagros Rifting, (2) the First or Early 

Oman Alpine Orogeny, and (3) the Second or Late Alpine 

Orogeny (figs. 1 and 12). These tectonic events will be briefly 

discussed in a later section on trap formation.

Stratigraphy of Central Saudi Arabia 

and Greater Ghawar Region

Pre-Khuff Section

The stratigraphic section of Central Arabia and the 

Greater Ghawar Uplift Province is commonly divided into a 

“Pre-Khuff” and a “Khuff and younger” section (Wender and 

others, 1998). The Precambrian to Lower Cambrian basement rocks of Central Arabia are steeply dipping, fractured 

metasediments (figs. 1 and 13). Because the basement complex was subjected to north-south compression, subsequent 

rejuvenation of the dominant north-south structural elements 

also controlled the structural development of the sedimentary 

cover, and thus influenced the distribution of hydrocarbons in 

the Central Arabian sub-basin. The north-south orientation of 

major basement-involved structures, such as at Ghawar field, 

are easily identified on gravity maps where structural highs are 

generally associated with positive gravity anomalies (Wender 

and others, 1998).

The stratigraphic section varies in the onshore and offshore areas, as the Hormuz Salt is geographically limited to 

the Infracambrian rift basins that mostly underlie the offshore 

Gulf. The Late Permian to Early Triassic Khuff Formation is 

a thick formation consisting of cyclic anhydrite and carbonate 

rock that forms a regional seal for hydrocarbons (figs. 1 and 

13). The Khuff is also locally a petroleum reservoir depending on the presence of dolomite and (or) the ratio of carbonate 

and anhydrite. Pre-Khuff (Cambrian to Late Permian) sediments in the Greater Ghawar area are composed of a massive 

sequence of siliciclastics ranging in thickness from about 

2,450 m in the basinal areas to about 600 m on the crest of the 

Ghawar structure where significant erosion has occurred (figs. 

1 and 13). The Pre-Khuff clastics were deposited in terrestrial 

to shallow-marine environments on the stable passive margin 

of Gondwana. Four erosional events have been recognized in 

the Paleozoic section of the Greater Ghawar area (Wender and 

others, 1998); however, the greatest amount of erosion was the 

result of uplift of the Arabian Plate associated with the Carboniferous Hercynian Orogeny. Variations in thickness of the 

Pre-Khuff section are due to broad epeirogenic uplifts of the 

Arabian Plate, creating intracratonic sag basins with intervening broad arches.

The first unmetamorphosed sedimentary rocks covering 

the Arabian Shield are the carbonates, clastics, and evaporites of Infracambrian age deposited within the rift salt basins 

(fig. 3). The Hormuz Salt (fig. 1) of the Hormuz Series of 

the Gulf is composed of massive salt, anhydrite, limestone, 

dark dolomite, and some red sandstone (Kent, 1970). The 

salt-bearing Infracambrian part of the stratigraphic section of 

the Arabian Plate is best represented by the Huqf Group of 

Oman. In Oman, the Huqf section has been partly exposed in 

two surface outcrops, and has been penetrated by deep drill 

cores. The massive salt of the Ara Formation of Oman is 

laterally equivalent to the Hormuz Series, and was probably its 

genetic continuation before major strike-slip faulting reshaped 

the margins of the rift basins. The salt of the Hormuz depositional megacycle occurs mostly in the offshore Gulf area (fig. 

3), is as much as 2,500 m thick, and has produced numerous 

halokinetic structures (Edgell, 1991; 1996). In the area of 

Ghawar field, mostly Infracambrian clastics that have not yet 

been shown to contain hydrocarbons lie immediately above 

basement accretionary metasediments (fig. 13) (Wender and 

others, 1998).

The earliest post-Najd Rift sediments consist of arkosic 

sandstone and red micaceous siltstones of the Middle Cambrian to Early Ordovician Saq Formation (fig. 13). Although 

gas shows have been recorded in some sandstones of the Saq 

Formation, reservoirs are commonly of poor quality due to 

extensive silica cementation. A stacked sequence of shallowmarine micaceous sandstone and shale of the Middle to Late 

Ordovician Qasim Formation lies above the Saq Formation 

(Williams and others, 1986; King, 1995). In the southern 

Ghawar area, shale units grade into siltstone and shale due 

to epeirogenic uplift of the ancestral Central Arabian Arch 

(Wender and others, 1998).
During the early Paleozoic, Gondwana was at a high 

southern latitude such that glacial and other cold-climate 

systems were active. Glaciation during the Late Ordovician 

affected much of western Arabia, and much of the Ordovician 

section in central Arabia was deposited by glacial-fluvial meltwater from retreating ice (McGillivray and Husseini, 1992). 

During the advance and later retreat of these glacial systems, 

the Zarqa and the Sarah Formations (fig. 13) were deposited 

and represent a complex of glacial and periglacial sequences 

(Vaslet, 1987). Clean, fine- to medium-grained glaciogenic 

sandstones of the Sarah Formation represent a lowstand 

deposit associated with Gondwana glaciation in the Greater 

Ghawar area (Senalp and Al-Laboun, 1996). Sharland and 

others (2001) agreed with the interpretation of Sutcliffe and 

others (2000) that the Zarqa-Sarah sediment system represents 

subglacial valley systems, mostly above sea level, that were 

filled with sediment during ice sheet retreat. Although numerous gas shows have been reported from the Late Ordovician 

Sarah Formation in the Ghawar area, no sustainable flow rates 

have been recorded there owing to low permeability (Wender 

and others, 1998).

Deglaciation during the Early Silurian caused a rise in 

sea level, which resulted in the widespread deposition of the 

upward-coarsening, progradational Qalibah Formation. The 

Qalibah Formation consists of a lower Qusaiba Member and 

an upper Sharawra Member (Husseini, 1991; Mahmoud and 

others, 1992) (fig. 13). Lower Silurian shales representing 

maximum flooding surfaces were deposited over most of the 

Gondwana passive margin shelf (Sharland and others, 2001), 

including the Middle East and Sahara. Regionally correlatable, organic-rich shale showing a distinctive high gamma-ray 

signature on logs persists at the base of the Qusaiba Member. 

This basal, high-gamma unit is referred to as the hot shale (fig. 

13) and is considered the principal source rock for Paleozoic 

hydrocarbons in Saudi Arabia (Abu-Ali and others, 1991; 

Aoudeh and Al-Hajri, 1995; McGillivray and Husseini, 1992; 

Figure 12. Growth history of major tectonic events and their relative intensities at various structures and substructures in Greater 

Ghawar area. Modified from Wender and others (1998).

Stratigraphy of Central Saudi Arabia and Greater Ghawar Region 19

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gure 12. Growth history of major tectonic events and their relative intensities at various structures and substructures

the greater Ghawar area. Modified from Wender and others (1998).
20 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Mahmoud and others, 1992; Cole, Abu Ali, and others, 1994; 

Bishop, 1995; Milner, 1998; Jones and Stump, 1999; Sharland 

and others, 2001).

Significant gas shows have been recorded in the “MidQusaiba Sand,” an informal sandstone and siltstone unit within 

the Qusaiba Member. The Mid-Qusaiba Sand is commonly 

used as a marker bed and represents a progradational, basinfloor fan system related to the Silurian flooding event. The 

overlying Sharawra Member (fig. 13) consists of micaceous 

sandstones, siltstones, and shales, with some recorded gas 

shows; however, formation log analysis indicates that these are 

poor quality reservoirs (Wender and others, 1998). A hiatus is 

observed in the uppermost Early and Late Silurian in the Ghawar area where much of the uppermost part of the Silurian is 

missing, owing to nondeposition (Mahmoud and others, 1992).

Following the Silurian hiatus, fine- to medium-grained, 

fluvial to marginal marine, red-colored sandstones of the 

Late Silurian-Early Devonian Tawil Formation (fig. 13) were 

deposited along with thin, discontinuous beds of micaceous 

siltstone and shale (Wender and others, 1998). The Tawil clastics vary in thickness locally and are considered poor reservoirs because of extensive cementation by silica and kaolinite. 

In contrast, the overlying Early to Middle Devonian shallow 

marine sandstones of the Jauf Formation are of good reservoir 

quality. Overlying the Jauf Formation are very fine grained 

to medium-grained, poor reservoir quality sandstones of the 

Middle to Upper Devonian Jubah Formation (fig. 13).

An extensive period of erosion due to uplift in the early 

Carboniferous forms the Hercynian Unconformity (also 

referred to as the “pre-Unayzah Unconformity”). The Hercynian Unconformity is particularly evident throughout the 

stratigraphic section in the Greater Ghawar Uplift Province 

(fig. 13). For example, about 1,100 m of section was removed 

from the crestal portions of Ghawar field (Wender and others, 

1998). Following the Hercynian Orogeny, middle Carboniferous to Early Permian fluvial and cold-climate dune sands of 

the Unayzah Formation were deposited. The basal Unayzah 

Formation consists of fine- to coarse-grained sandstones that 

filled relict, erosional topography (Al-Laboun, 1987). Glacial sediments, including cold-climate dune fields (Heine, 

in press), of the Lower Unayzah are also recognized in the 

south half of the eastern Arabian Peninsula from the southern 

part of the Greater Ghawar Uplift Province, into the Rub ‘al 

Khali Basin Province, and also in Oman where the Lower 

Unayzah is equivalent to the glaciogenic Al-Khlata Formation (McClure, 1980; Hughes-Clark, 1988; Levell and others, 

1988; Pollastro, 1999). The Unayzah Formation forms the 

principal pre-Khuff hydrocarbon reservoir in the south half 

of the Greater Ghawar area; however, the Unayzah is absent 

due to Hercynian erosion in the northern part of the Arabian 

sub-basin.

Late Permian Through Jurassic 

During the Late Permian, following Unayzah deposition, 

a major marine transgression took place throughout the eastern 

Arabian Peninsula. The transgression coincided with Late 

Permian rifting along the Zagros, opening of the Neo-Tethys 

Ocean, and deposition of the cyclic, dominantly shallow water 

carbonates and evaporites of the Late Permian to Lower Triassic Khuff Formation (Al-Jallal, 1989; 1995). The uppermost 

Khuff is of Early Triassic age. The Khuff ranges in thickness 

from 365 to 490 m over most of central and eastern Arabia, 

but thickens to more than 900 m in the Rub ‘al Khali Basin 

(Al-Jallal, 1995) (figs. 1 and 13).

Transgressive sands and shales occur at the base of the 

Khuff Formation and are commonly referred to as the “basal 

Khuff clastics” or the Basal Khuff Formation. These basal 

clastics were deposited as channel and valley fill sediments on 

an incised Unayzah surface and were followed by the beginning of a significant marine transgression (McGillivray, 1994). 

Late Permian dolomites within the Khuff are major gas reservoirs, particularly along the offshore North Gulf north and 

west of Qatar. In contrast, the regionally extensive anhydrite, 

shale, and tight (low-permeability) carbonates of the Khuff 

Formation form the major regional seal for Pre-Khuff hydrocarbon accumulations in central and eastern Saudi Arabia 

(Al-Jallal, 1995; Wender and others, 1998).

The Triassic was a period of regional uplift (for example, 

Qatar Arch) and transgression (Alsharhan and Kendall, 1986). 

A stable Arabian Shield on the west and southwest of the 

Greater Arabian basin was the source of clastics that spread 

eastward. Following deposition of the Khuff, red beds of 

shale, interbedded with dolomite and evaporites of the Lower 

Triassic Sudair Formation, were formed on a flood-plain 

to lagoonal and tidal flat environment across Saudi Arabia 

(Sharief, 1986; Alsharhan and Nairn, 1997). The Sudair Shale 

is conformably overlain by a upward-coarsening sequence of 

the Middle Triassic Jilh Formation (fig. 1). The Jilh Formation displays a great diversity of siliciclastic and carbonate 

facies because it was deposited in a nonmarine (continental) 

and nearshore to shoreline complex (Sharief, 1986). Overlying the Jilh Formation are thick, continental, siliciclastic rocks 

of the Minjur Formation (fig. 11) that were deposited during 

regression and increased aridity. The Minjur was deposited over a broad area during the Late Triassic and is mostly 

medium grained, poorly sorted, crossbedded quartz sandstone 

with some conglomerate and shale lenses.

Throughout the Jurassic, the Arabian Plate was situated 

in the tropical or subtropical zone where the northeast passive margin of the Afro-Arabian Plate evolved as an extensive 

continental shelf (Murris, 1980; Beydoun, 1991). Deposition 

along the eastern Arabian Plate and Gulf during the Jurassic, 

and much of the Cretaceous, was characterized by platform 

carbonates. During most of the Early Jurassic, a pronounced, 

long-term, sea-level lowstand occurred from Early Zagros 

rifting and structural growth. This resulted in a period of nondeposition marked by a widespread Early Jurassic hiatus (fig. 

1). During the Toarcian stage of the Early Jurassic, a widespread marine transgression caused by a major rise in relative 

sea level flooded the Arabian shelf, forming a shallow-marine 

platform. The Early and Middle Jurassic depositional environment of the central Arabian Plate and the Gulf area varied 
Figure 13. Stratigraphic column and tectonostratigraphic events of the Paleozoic section in 

Greater Ghawar area. Modified from Abu-Ali and others (1999; 2001).

Stratigraphy of Central Saudi Arabia and Greater Ghawar Region 21

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Figure 13. Stratigraphic column and tectonostratigraphic events of the Paleozoic section in greater

Ghawar area. Modified from Abu-Ali and others (1999; 2001).

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22 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

from nondeposition and erosion to an arid clastic platform in 

the west and to a shallow-marine, mostly carbonate platform 

on the north and east (Al-Husseini, 1997). This period is represented by the formation of basal shales, sandy shales, calcareous sandstones, limestones, and dolomites of the Dhruma and 

Marrat Formations (fig. 1). In the Jurassic Arabian sub-basin, 

the Dhruma is recognized as a minor source rock (Cole, Carrigan, and others, 1994), and the Marrat Formation contains 

some reservoir facies.

Differential subsidence within the shelf, combined with a 

relative increase in sea level, led to the formation of relatively 

short lived intraplatform sub-basins (Murris, 1980; Sharland 

and others, 2001; Zeigler, 2001). Three intraplatform subbasins existed in the Arabian-Persian Gulf region during the 

Late Jurassic (fig. 4) and were depocenters for sediments that 

formed the main Jurassic source rocks (Upper Jurassic Hanifa, 

Tuwaiq Mountain, and equivalents), as well as the sites of 

several important reservoirs. These source rocks and reservoir 

rocks together constitute the major Jurassic petroleum systems 

of the eastern Arabian Peninsula. The central Arabian intraplatform sub-basin of onshore east-central Saudi Arabia and 

adjacent offshore Gulf that formed in the late Middle Jurassic (late Callovian) and existed into the Late Jurassic (early 

Kimmeridgian) is the primary focus of this report. A deepwater intraplatform basin, the Gotnia sub-basin, existed in the 

northern Gulf region from Middle Jurassic to Early Cretaceous 

(Christenson and others, 1977; Murris, 1980; Ayres and others, 

1982; Cole, Carrigan, and others, 1994; Al-Husseini, 1997; 

Zeigler, 2001). The Central Arabian sub-basin was separated 

structurally from the northern Gotnia sub-basin (fig. 4) by the 

Rimthan Arch (Langdon and Malacek, 1987). A third, smaller 

and shallower, intraplatform basin to the east, the South Arabian Gulf sub-basin, existed during the Late Jurassic (from late 

Oxfordian to early Kimmeridgian) and was separated from the 

Central Arabian sub-basin by the Qatar Arch (Murris, 1980; 

Alsharhan and Kendall, 1986; Droste, 1990) (fig. 4).

Cyclic changes in sea level during the Middle and Late 

Jurassic led to the development of a stacked series of shallowing-upward, carbonate platform sequences. The basinal facies 

consist of cycles of laminated, organic-rich, lime mud-wackestones. The thickest and most extensive Jurassic source-rock 

facies of central Arabia is the Tuwaiq Mountain Formation. 

It is considered the main Jurassic source rock of this region 

and was deposited in the southern part of the intraplatform 

Central Arabian sub-basin (fig. 4) between reservoir facies 

of the Dhruma (Fadhili zone) and Hanifa Formations (fig. 

1). To the east and south of the Central Arabian sub-basin, 

organic-rich facies of the overlying Hanifa Formation form the 

major source rock for the Jurassic Hanifa/Diyab-Arab Total 

Petroleum System of the intraplatform South Arabian Gulf 

sub-basin (fig. 4) and within the greater Rub ‘al Khali Basin 

proper. In the Central Arabian sub-basin, the organic-rich 

facies of the upper part of the Hanifa is of secondary significance compared to organic facies of the Tuwaiq Mountain 

(Cole, Carrigan, and others, 1994). Overlying the Hanifa 

Formation are dolomites and lime mudstones of the Jubailah 

Formation (fig. 1).

In the Late Jurassic, deposition of four carbonate-anhydrite cycles resulted in the four members of the Arab Formation in ascending order: Arab-D, C, and B, each consisting of a 

lower carbonate rock (grainstone) unit and an upper anhydrite 

unit, and the Arab A carbonate rock unit that is overlain by the 

Hith Anhydrite (figs. 1 and 14). The grainstone units of the 

Arab Formation comprise the most important petroleum reservoirs within the Central Arabian sub-basin and the countries of 

Saudi Arabia, Bahrain, and United Arab Emirates. The evaporite cycles within the Arab Formation provide the seals for the 

B, C, and D reservoirs. A thick sequence of evaporites, the 

Hith Anhydrite, immediately overlies the A Member carbonate 

rock of the Arab Formation, concludes the Jurassic depositional sequence in the area, and forms the principal regional 

seal to Jurassic-sourced hydrocarbons. McGuire and others 

(1993) and Sharland and others (2001) have correlated the 

Arab anhydrites to lowstand wedges and transgressive deposits, and the carbonate rocks to highstand deposits. Al-Husseini 

(1997) interpreted the Arab sequence as a late highstand of the 

Arab, Hith, and Gotnia evaporites.

In the Middle East, the Cretaceous stratigraphic section 

is normally divided into three parts, in contrast to the international two-part division. The “Middle” Cretaceous covers 

the time range from above the mid-Aptian unconformity to 

the uppermost Cenomanian-lower Turonian unconformity 

(Alsharhan and Nairn, 1988). During the Early Cretaceous 

(Berriasian), an intraplatform basin had again developed 

in central Arabia in which sediments forming the dark 

mudstones of the lower part of the Sulaiy Formation were 

deposited. Shelf grainstone carbonates then prograded from 

north to south over the lower Sulaiy. The overlying Yamama 

Formation represents the transition from intraplatform basin 

conditions to shelf sedimentation and the existence of a wide 

carbonate rock platform (Murris, 1980; Chaube and Al-Samahiji, 1995). Cyclic sedimentation of the Thamama Group 

shallow-shelf carbonates followed. By mid-Early Cretaceous 

(Barremian) time, a clastic regime occupied the west half of 

the basin pushing the carbonate ramp environment to the east 

(Murris, 1980). The Early Cretaceous Aptian was a period of 

renewed basin-wide inundation, and in late Aptian a shallow 

carbonate rock shelf spread westward over the previously 

deposited clastic rocks. On the fringing shelf margins, rudist 

reefs developed and formed the prolific hydrocarbon reservoirs of the Shu’aiba Formation (fig. 1).

Overlying the Thamama Group are shales, siltstones 

and fine-grained sandstones of the “Middle” Cretaceous 

Wasia Group (fig. 1). There is an obvious division of the 

Wasia Group into the lower, dominantly clastic units of the 

Nahr Umr Formation and upper, predominantly carbonate 

units (Powers, 1968). The lower clastic section is widely 

distributed over most of the Gulf area, where it consists 

of shale with subordinate limestones. Shales of the Nahr 

Umr Formation provide a good regional seal, and locally a 

hydrocarbon source rock, from Oman to Qatar. Farther to 

the west and northwest in Saudi Arabia, clastic units become 

more pronounced in the Wasia Group and are divided into 

the Safaniya and Khajfi Members (Alsharhan and Nairn, 

1988; Christian, 1997). The upper, predominantly carbonate 

part of the Wasia Formation in Saudi Arabia is subdivided 
Stratigraphy of Central Saudi Arabia and Greater Ghawar Region 23

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Figure 14. General stratigraphic section of the Jurassic Arab Formation (Fm) showing Members (Mbr),

stratigraphic units, lithology, intraformational reservoirs (Res), and seal (pink) rocks. Modified from

Hughes (1996).

Figure 14. General stratigraphic section of the Upper Jurassic Arab Formation (Fm) showing 

stratigraphic units, lithology, intraformational reservoirs (Res) and seals (pink), and overlying 

and underlying units (Mbr, member). Modified from Hughes (1996).
24 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

into four members in ascending order as follows: the Wara, 

Ahmadi, Rumaila, and Mishrif (fig. 1). 

During the early Late Cretaceous, widespread clastics of 

the Aruma Group were deposited following a major erosional 

emergence in the Turonian. The lower Laffan and Halul Formations of the Aruma form a first transgressive cycle, whereas 

the Fiqa-Simsima cycle is more directly related to tectonic 

events (Alsharhan and Nairn, 1990). Sediments of the Aruma 

have variable thickness and lithofacies because they were the 

result of a complex response to (1) regional subsidence, (2) 

plate collision and partial subduction to the east, (3) eustatic 

sea-level fluctuations, and (4) differential sedimentation rates 

(Alsharhan and Nairn, 1990). In particular, many of the Hercynian faults bounding the major north-south uplifts in central 

Arabia were reactivated especially during the Late Cretaceous, 

as indicated by dramatic thickening of the Aruma Group on 

the flanks of these uplifts (Konert and others, 2001).

During the Paleocene and early Eocene, much of the 

eastern Arabian Plate was a wide, shallow carbonate and 

evaporitic platform in response to withdrawal to the south 

of the Neo-Tethys Sea. Rocks of Paleocene-Eocene age are 

generally calcareous with typical shallow-water lithologies. 

They vary in thickness, with a maximum-recorded thickness in 

the western part of about 330 m; however, they are more than 

twice as thick to the east. In the foredeep toward the Zagros 

Mountains, these units increase in the amount of clastics they 

contain. Over southern Iraq, Kuwait, Saudi Arabia, Qatar, and 

United Arab Emirates, the shallow-water, Paleogene platform 

deposits generally are assigned to three formations of the Hasa 

Group, in ascending order the Umm Er Radhuma, Rus, and 

Dammam (fig. 1) (Alsharhan and Nairn, 1997). 

Eastern Arabia underwent uplift and subaerial erosion 

from the Oligocene into the Miocene. The Oligocene through 

Pliocene (Neogene) of Saudi Arabia is composed of four formations totaling about 350 m in thickness, which in ascending 

order are the Hadrukh, Dam, Hofuf, and Kharj Formations. 

The early Miocene Hadrukh is mostly nonmarine sandy limestone and calcareous sandstone and is conformably overlain by 

marls, limestone, and claystones of the middle Miocene Dam 

Formation. The late Miocene–early Pliocene Hofuf Formation consists of marls, sandy limestones, conglomerates, and 

argillaceous sandstones of continental origin. The overlying 

Pliocene Kharj Formation consists of irregular-bedded limestone, sand, and gravel conglomerates, with some sediments 

indicating deposition in a freshwater, lacustrine environment 

(Alsharhan and Nairn, 1997).

Central Arabia Qusaiba-Paleozoic 

Total Petroleum System

General Description

The Central Arabia Qusaiba-Paleozoic TPS (202101) 

encompasses an area mostly within Saudi Arabia, Bahrain, 

western Qatar, and northern portions of the Gulf offshore 

within Iran along the Zagros Fold Belt (fig. 15). The Central 

Arabia Qusaiba-Paleozoic TPS includes all of the Greater 

Ghawar Uplift Province and extends into the central part of 

the Interior Homocline–Central Arch Province (2020), the 

western flank of the Qatar Arch Province (2022), the northern 

flank edge of the Rub ‘al Khali Basin Province (2019), the 

southeasternmost parts of the Widyan Basin–Interior Platform Province (2023), and the Mesopotamian Foredeep Basin 

(2024) Province (fig. 15).

The geographic boundaries of the Central Arabia 

Qusaiba-Paleozoic TPS were determined using several criteria, many of which are limited by the geographic extent of the 

source rock, or closely coincide with the geologic boundaries 

forming the Central Arabian intraplatform sub-basin (fig. 4). 

The western boundary of the Central Arabia Qusaiba-Paleozoic TPS (202101) is defined by the absence of the Qusaiba 

hot shale source facies along the Central Arabian Arch and 

Arabian Shield (fig. 3) due to Hercynian uplift and erosion 

(Bishop, 1995; Cole, Carrigan, and others, 1994; Milner, 1998; 

Abu-Ali and others, 1999; Jones and Stump, 1999; Konert and 

others, 2001). The TPS boundary is also limited to the north 

and west by the geographic extent of the Quisaiba hot shale, 

as interpreted by Mahmoud and others (1992), Bishop (1995), 

Jones and Stump (1999), and Konert and others (2001) (figs. 

16, 17, and 18). Structural boundaries used in constructing 

the TPS boundary include (1) the western flank edge of the 

Rub ‘al Khali Basin to the east and southeast; (2) the crestal 

axis of the Qatar Arch to the east and northeast; and (3) the 

Zagros Fold Belt to the north. Many of the oil and gas fields 

that produce from Paleozoic reservoirs, and that are assigned 

to the Central Arabia Qusaiba-Paleozoic TPS, are shown in 

figure 19. 

Petroleum Geochemistry

Source Rocks

An organic-rich shale facies of the Lower Silurian 

Qusaiba Member of the Qalibah Formation is the major source 

rock of the Central Arabia Qusaiba-Paleozoic TPS (Abu-Ali 

and others, 1991, 1999, 2001; Mahmoud and others, 1992; 

Cole, Carrigan, and others, 1994; Bishop, 1995; Milner, 1998; 

Jones and Stump, 1999; Sharland and others, 2001). Early 

Silurian deglaciation resulted in a major sea-level rise and the 

widespread deposition of the upward-coarsening, progradational Qalibah Formation. The Qalibah Formation accumulated in at least two rapidly subsiding regions along the eastern 

Arabian Peninsula (Jones and Stump, 1999). 

The Qalibah Formation consists of a lower Qusaiba 

Shale Member, and upper sandstones, siltstones, and shale 

of the Sharawra Member (fig. 13). The Qusaiba Member is 

composed mostly of shale (mudstone) and thin interbeds of 

siltstone and sandstone; it is divided informally into upper 

and lower parts. On a regional basis, the lower Qusaiba is 

characteristically an upward-coarsening sequence, whereas the 

upper part of the Qusaiba is a fining-upward sequence (Jones 

and Stump, 1999).
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Figure 15. Greater Ghawar Uplift Province and adjacent geologic provinces, Central Arabia Qusaiba-Paleozoic Totaassessment units, and oil and gas field centerpoints in Central Arabia and northern Arabian-Persian Gulf.U.A.E., Uni

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Figure 15. Greater Ghawar Uplift Province and adjacent geologic provinces, Central Arabia Qusaiba-Paleozoic Total Petroleum System, assessmgas field centerpoints in Central Arabian sub-basin of the Arabian-Persian Gulf. U.A.E., United Arab Emirates.
26 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

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Figure 16. Paleoenvironmental map of the Early Silurian showing approximate extent of Qusaiba

Shale Member of the Qalibah Formation on the Arabian Peninsula. Modified from Konert and others

(2001). U.A.E., United Arab Emirates.

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Figure 16. Paleoenvironmental map of the Early Silurian showing approximate extent of the Qusaiba Shale Member of 

the Qalibah Formation on Arabian Peninsula. Modified from Konert and others (2001). U.A.E., United Arab Emirates.
Central Arabia Qusaiba-Paleozoic Total Petroleum System 27

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Figure 17. Central Arabia and Rub 'al Khali basin showing depositional limit, present-day thermal maturity based on vitrinite

reflectance (Ro), oil and gas fields producing from the Paleozoic, and eroded areas of the Silurian Qusaiba source rock. Modified from

Milner (1998).

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Figure 17. Central Arabia and Rub ‘al Khali Basin showing depositional limit, present-day thermal maturity based on vitrinite reflectance (Ro), oil and gas fields producing from the Paleozoic, and eroded areas of the Silurian Qusaiba source-rock. Modified from 

Milner (1998).
28 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Figure 18. Geographic extent and present-day zones of hydrocarbon generation for Silurian Qusaiba Shale Member source facies, 

Arabian Peninsula. Modified from Bishop (1995) and Jones and Stump (1999). On suture zone, sawteeth on upthrown side.

SUTURE ZONE

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Figure 18. Geographic extent and present-day zones of hydrocarbon generation for Silurian Qusaiba Member

source facies of the Arabian Peninsula. Modified from Bishop (1995) and Jones and Stump (1999). On suture

zone, sawteeth on upthrown side.

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The base of the Qusaiba Member contains regionally 

correlative, organic-rich shale with a distinctive high gammaray signal on geophysical logs (fig. 20); this high gamma-ray 

interval is generally referred to as the hot shale. The lower, 

organic-rich part of the Qusaiba Member was deposited as 

a graptolitic sheet of mud on the middle to outer continental 

shelf. This depositional area of the Qusaiba included the 

greater part of the eastern Arabian Plate and North Africa 

during an extensive, rapid and regional transgression as a 

consequence of deglaciation. The basal hot shale of the 

Qusaiba Member is the principal source rock for Paleozoic 

hydrocarbons along the eastern Arabian Peninsula (Beydoun, 

1991; Husseini, 1991; Mahmoud and others, 1992; McGillivray and Husseini, 1992; Abu-Ali and others, 1991; 1999; 

Bishop, 1995; Milner, 1998; Jones and Stump, 1999). Four 

total petroleum systems have been identified along the eastern 

Arabian Plate and Zagros Fold Belt; the Qusaiba Member 

is their source rock and their reservoirs are of Paleozoic age 

(Ahlbrandt and others, 2000; Pollastro and others, 2002).

The Lower Silurian basal Qusaiba Member hot shale 

is a dark-gray to black, commonly microlaminated, euxinic 

shale with as much as 20 weight percent total organic carbon 

(TOC). The hot shale averages about 3–5 weight percent 

TOC in Saudi Arabia (Abu-Ali and others, 1991; 1999; Cole, 

Abu-Ali, and others, 1994; Jones and Stump, 1999) and 6 

weight percent in Iraq (Aqrawi, 1998). The basal hot shale 

maintains good to excellent TOC whether in an immature 

setting or a mature setting (Cole, Abu-Ali, and others, 1994). 

Jones and Stump (1999) suggested that rapid transgression of 

the Qalibah Formation caused displacement of earlier shallowmarine coarse clastics, allowing organic matter to accumulate 

undiluted on the continental shelf of northern Gondwana. 

Sharland and others (2001) interpreted deposition of the hot 

shale facies as a condensed sequence on a sediment-starved 

continental shelf and determined that the hot shale facies is a 

maximum flooding surface. 

The organic-rich, basal hot shale of the Qusaiba Member 

is best developed in the subsurface of eastern-central Saudi 

Arabia and lies immediately above a basal sandstone that varies in thickness between 1 and 30 m. The hot shale has been 

reported to be as much as 75 m in thickness, but commonly is 

about 9–31 m thick (Cole, Abu-Ali, and others, 1994; Jones 

and Stump, 1999). Locally, the Qusaiba Member is absent 

owing to uplift and erosion during the Late Devonian to Carboniferous Hercynian Orogeny (figs. 16 and 18).

Jones and Stump (1999) suggested that the hot shale of 

the Qusaiba Member should contain greater than 2.0 percent 

TOC to be considered a source bed. They calibrated TOC of 

the Qusaiba Member to gamma-ray response in API units and 

found that 150 API units corresponds favorably to greater than 

2.0 percent TOC (fig. 20). Mapping of the hot shale using the 

greater than 150 API unit log signature by Jones and Stump 

(1999) showed that the thickest and richest source rock of 

the Qusaiba occurs on the flanks of depocenters, rather than 

within the depocenters as previously reported by Mahmoud 

and others (1992) and Cole, Abu-Ali, and others (1994). Jones 

and Stump suggested that the hot shale was likely deposited in 

an essentially uniform thickness and subsequently reworked 

and eroded by turbidites that preferentially moved down the 

axes of the Qusaiba depocenters. Mapping of the hot shale by 

Stump and van der Eem (1995) and Jones and Stump (1999) 

showed that the areal extent of favorable Qusaiba Member 

source rock is much greater, particularly in the Rub ‘al Khali 

Basin, than previously shown in studies by Mahmoud and others (1992), Cole, Abu-Ali, and others (1994), Bishop (1995), 

and Milner (1998).

Organic Geochemistry

Oil-oil and oil-source rock correlations by Abu-Ali and 

others (1991) and Cole, Abu-Ali, and others (1994) show 

that oil and condensates from Paleozoic reservoirs of Saudi 

Arabia have been generated from a common source—the basal 

Qusaiba Member hot shale. Oil-to-source rock correlations 

show a high degree of similarity in biomarker distribution 

between extracted bitumen and oils, and an excellent isotopic 

compatibility between extracted kerogen and oils (Mahmoud 

and others, 1992). Organic material in the basal Qusaiba 

Member hot shale consists mostly of oil-prone Type II (amorphous marine algae) kerogens with abundant chitinozoans and 

graptolites.

Paleozoic oils derived from clastic Qusaiba Member 

source beds are geochemically much different from and more 

mature than those generated from younger, carbonate source 

beds of Jurassic and Cretaceous age. The Paleozoic-sourced 

oils have lighter API gravities and lower sulfur and trace-metal 

contents (Abu-Ali and others, 1991). API gravities of Paleozoic oil range from 40° to 53° (fig. 19), whereas Mesozoic 

oils are commonly in the range of 20°–40°. Sulfur content of 

oils from the Qusaiba shale is less than 0.1 weight percent. In 

contrast, oils from Jurassic carbonate source rocks are commonly greater than 1.0 weight percent sulfur. Qusaiba-derived 

oils have an average δ13C isotope ratio of –29.8 ‰ relative to 

the PDB standard, and Mesozoic oils are isotopically heavier, 

averaging –26.5 ‰ (Abu-Ali and others, 1991).

Maturation, Generation, and Expulsion

Several studies have modeled the thermal maturation of 

the basal Qusaiba Member hot shale along the eastern Arabian 

Plate (Abu-Ali and others, 1991; 1999; 2001; Mahmoud and 

others, 1992; Cole, Abu-Ali, and others, 1994; Bishop, 1995; 

Milner, 1998; Jones and Stump, 1999). Figure 17 summarizes 

the thermal maturity of the Qusaiba Member source rock for 

the Central Arabia Qusaiba-Paleozoic TPS. Also, figure 18 

shows present-day geographic zones of oil and gas generation. 

Hydrocarbon maturation and generation for the Central Arabia 

Qusaiba-Paleozoic TPS are also summarized in the total petroleum system events chart of figure 21, and in the burial history 

and hydrocarbon expulsion history of figure 22 and figure 23.

Central Arabia Qusaiba-Paleozoic Total Petroleum System 29
30 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

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Figure 19. Outlines, names, mean field API gravities, and general locations of oil and gas fields

in central Saudi Arabia and northern Arabian-Persian Gulf producing from Pre-Khuff and Khuff or

younger formations. Modified from Abu Ali and others (1999), Al-Husseini (1997), and McGillivray (1994).

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Figure 20. Relation between gamma-ray response versus total organic carbon (TOC) in transitional-type, basal hot shale of lower 

Qusaiba Member source rock, Qalibah Formation. Gamma-ray response of 150 API units closely corresponds to about 2 weight 

percent TOC. Modified from Jones and Stump (1999).

Figure 19 (preceding page). Outlines, names, mean field API 

gravities, and general locations of oil and gas fields in central 

Saudi Arabia and northern Arabian-Persian Gulf producing from 

Pre-Khuff and Khuff or younger formations. Modified from AbuAli and others (1999), Al-Husseini (1997), and McGillivray (1994).

Central Arabia Qusaiba-Paleozoic Total Petroleum System 31

Figure 20. Relation between gamma-ray response versus total organic carbon (TOC) in

transitional-type, basal hot shale of lower Qusaiba Member source rock, Qalibah Formation.

Gamma-ray response of 150 API units closely corresponds to about 2 percent TOC. Modified

from Jones and Stump (1999).

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Figure 21. Total petroleum system events chart for Central Arabia Qusaiba-Paleozoic Total Petroleum System (202101) oGhawar Uplift Province (2021) and surrounding geologic provinces of central Saudi Arabia, showing total petroleum systtiming of trap formation and hydrocarbon generation.

Figure 21. Total petroleum system events chart for Central Arabia Qusaiba-Paleozoic Total Petroleum System (202101) of the Greater Ghawar Uplift rounding geologic provinces of central Saudi Arabia, showing total petroleum system elements and timing of trap formation and hydrocarbon genera
Cole, Abu Ali, and others (1994) showed that present-day 

maturity, as expressed in Ro , at the base of the Qusaiba generally increases from less than 0.5 percent along the exposed 

western rim of the basin in central Saudi Arabia, eastward to 

thermally mature oil generation and expulsion of greater than 

0.7 percent, to mature for gas at greater than 1.3 percent, and 

finally into areas further to the east of greater than 2.0 percent where the Qusaiba is considered spent as a hydrocarbon 

source. Based on the present-day thermal maturity trend of 

the Qusaiba, and the maturity of oils analyzed from fields in 

central Saudi Arabia, they concluded that most oils in these 

fields migrated long distances. The present-day maturity of 

the Qusaiba in the vicinity of the oil fields is insufficient for 

the generation of oil, whereas the API gravities of oils in these 

fields range from 40° to 53°. Therefore, oils in the central 

Arabian fields migrated westerly from downdip and deeper, 

eastern “kitchens” where the Qusaiba source rock is thicker 

and thermally mature for oil (fig. 24). Moreover, the excellent 

seal capacity provided by the overlying Khuff evaporites and 

carbonates contributes to the efficiency of migration and containment of the petroleum system. Burial-history models for 

the Qusaiba Member source rock at locations near the basin 

margin and deep basin are shown in figure 22 and figure 23.

Bishop (1995) calculated maturation and geohistory 

curves of the Lower Silurian Qusaiba source rock and published maps showing present-day level of thermal maturity, 

time of onset of significant oil and gas generation, and 

expected hydrocarbon type for the eastern Arabian Peninsula 

(fig. 18). Bishop (1995) concluded that present-day thermal 

maturities of the lower Qusaiba range from immature to 

overmature (exhausted) over the eastern Arabian Peninsula, 

and that charging of traps with oil, and then gas, from the 

Qusaiba probably began during the Triassic in the South Gulf 

Salt Basin (fig. 3) and progressed southward into the Rub ‘al 

Khali Basin during the Cretaceous. Maturation and generation of Silurian source rocks largely ceased in the early 

Tertiary, but maturation and generation were reactivated by 

the Zagros collision in the Miocene and may be continuing 

into the present day.

Cretaceous, Jurassic, and Silurian source rocks of the 

southern Arabian Peninsula were analyzed by Milner (1998) 

for both source-rock richness (Rock-Eval analysis) and 

thermal maturity (as determined by vitrinite reflectance). 

Milner then used regional geologic and structural framework 

data, combined with heat flow and source-rock quality data, 

to construct burial-history models and map the geographic 

extent of the source facies and maturity stages (fig. 17). 

With the exception of the Paleozoic oil and gas fields of 

central Saudi Arabia, maturity modeling of Silurian-sourced 

hydrocarbons was verified by (1) location of Paleozoic oil 

fields (for example, Sahmah field, Oman) within mapped 

levels of thermal maturity (Ro) for oil generation, and (2) 

occurrence of Paleozoic gas fields (such as Ghawar, Saudi 

Arabia, and North field, Qatar) within the mapped level of 

thermal maturity for gas generation (figs. 17 and 25). Oil 

fields of central Saudi Arabia that produce Silurian-sourced, 

super-light (about 50° API gravity) sweet crude oil lie about 

60 km from a level of maturity indicative of late oil generation. As mentioned previously, oils within these fields are 

believed to have migrated long distances, westward and 

updip, from an eastern, more mature source area, and into 

traps along the basin monocline adjacent to the Arabian 

Shield (fig. 24) (McGillivray and Husseini, 1992; McGillivray, 1994; Cole, Carrigan, and others, 1994).

Jones and Stump (1999) found that the Qusaiba Member 

source-rock facies is gas prone to gas-condensate prone near 

the axis of the Qalibah trough depocenter, and more oil prone 

east and south of the depocenter. The Qusaiba is overmature with respect to oil generation over most of the Central 

Arabian sub-basin, South Arabian Gulf sub-basin, and Rub 

‘al Khali Basin (figs. 17 and 18). Moreover, in a comparison 

of the areal extent of the hot shale in the Central Arabian 

sub-basin, Rub ‘al Khali Basin, and South Arabian Gulf 

sub-basin, Jones and Stump (1999) found that the Qusaiba 

Member source-rock facies extends beyond previously published interpretations by Mahmoud and others (1992), Cole, 

Abu-Ali, and others (1994), and Milner (1998), thus expanding the prospective area for Paleozoic hydrocarbon generation and accumulation (fig. 18).

An integrated study of the generation and expulsion of 

oil and gas from the Qusaiba Member hot shale by Abu-Ali 

and others (1999; 2001) has provided further insight into 

the Central Arabia Qusaiba-Paleozoic TPS. In their study, 

compositional kinetic experiments from control samples were 

combined with a set of historical maps to model the stages of 

source-rock maturation, and petroleum generation and expulsion. Actual and hypothetical wells were used to calibrate 

their model and document hydrocarbon expulsion history from 

different locations in the basin. They found that expulsion of 

oil and gas was limited to a small region in the southeastern 

part of the Central Arabian sub-basin (fig. 25). In the deepest 

part of the Central Arabian sub-basin, the Qusaiba source rock 

was thermally mature by the Late Jurassic, but hydrocarbon 

expulsion was not initiated until the Early Cretaceous (fig. 

23). Oil and gas were expelled simultaneously, but gas expulsion continued for a longer time period. Most of the gas was 

expelled during the Late Cretaceous; expulsion of oil nearly 

ceased after the Late Cretaceous. Oil and gas expulsion are 

linked to three events: (1) primary kerogen cracking, causing 

the first episode of expulsion about 120 Ma; (2) secondary 

cracking of heavy components and oils, causing a second 

episode of expulsion at about 100 Ma; and (3) a later uplift 

and erosional event, resulting in a third pulse of expulsion at 

about 20–10 Ma during which the gas was separated from the 

oil, causing re-migration.

In this report, the combined studies of Abu-Ali and others 

(1991; 1999; 2001), Mahmoud and others (1992), Cole, AbuAli, and others (1994), Bishop (1995), Milner (1998), and 

Jones and Stump (1999), were used to construct the “pod of 

active source rock” for the Central Arabia Qusaiba-Paleozoic 

TPS, shown in figure 26.

Central Arabia Qusaiba-Paleozoic Total Petroleum System 33
34 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Figure 22. Burial history and hydrocarbon generation model for base of the Silurian Qusaiba Member source rock in Udaynan well, 

Saudi Arabia. Well location shown in figure 25. Modified from Wender and others (1998).

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Figure 22. Burial history and hydrocarbon generation model for base of the Silurian Qusaiba

source rock in Udaynan well, Saudi Arabia. Well location shown in figure 25. Modified

from Wender and others (1998).

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Figure 9. Hydrocarbon expulsion history from the Qusaiba source rock is compared for two wells, Udaynan an

The latter well is located in the southeastern part of the area in the middle of the ÒkitchenÓ (Figure 1). The s

based on the Tayma sample.

Figure 23. Hydrocarbon expulsion history from the Qusaiba source rock as modeled in Udaynan well and well about 30 km to the southeast in deepest part of kitchen. Well locations shown in figure 25. Modifieothers (1999).

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Figure 23. Hydrocarbon expulsion history from the Qusaiba Member source rock as modeled in Udaynan well and in hypothetical Model well aboeast in deepest part of kitchen. Well locations shown in figure 25. Modified from Abu-Ali and others (1999).
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Figure 24. Generalized Khuff and Pre-Khuff section along basin monocline from Dilam field to Abu Jifan field, Saushowing regional hydrocarbon migration from mature Qusaiba Member source rock near Abu Jifan field into UnayzaModified from McGillivray (1994).

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Figure 24. Generalized Khuff and Pre-Khuff section along basin monocline from Dilam field to Abu Jifan field, Saudi Arabia (see fig. 25), showing carbon migration from mature Qusaiba Member source rock near Abu Jifan field into Unayzah reservoirs at Dilam. Modified from McGillivray (199
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Figure 25. Central Arabia and Greater Ghawar area showing expulsion of oil and gas from Qusaiba hot shalA, Area of basin which has expelled oil from Qusaiba hot shale. Darker green indicates area that is most maexpelled the greatest amount of oil (25 - 50%). B, Area of basin which has expelled gas from Qusaiba hot shred color indicates area that is most mature and has expelled the greatest amount (20 - >24%) of gas. Locatiand hypothetical Model well of figure 23 and location of cross section of figure 24 are also shown. Modified and others (1999; 2001).

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Figure 25. Central Arabia and Greater Ghawar area showing expulsion of oil and gas from Qusaiba hot shale source rock. A, Area of basin that has hot shale. Darker green indicates area that is most mature and has expelled the greatest amount (25 to 50 percent) of oil. B, Area of basin that has exhot shale. Darker red indicates area that is most mature and has expelled the greatest amount (20 to >24 percent) of gas. Locations of Udaynan and figure 23 and location of cross section of figure 24 are also shown. Modified from Abu-Ali and others (1999; 2001).
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Figure 26. Central Arabia Qusaiba-Paleozoic Total Petroleum System, pod of active source rock, geologic provinces, anoil and gas field centerpoints in Greater Ghawar Uplift Province (2021) and surrounding Provinces. U.A.E., United Ara

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Figure 26. Central Arabia Qusaiba-Paleozoic Total Petroleum System, pod of active source rock, geologic provinces, and oil and gas field centGhawar Uplift Province (2021) and surrounding provinces. U.A.E., United Arab Emirates.
Reservoirs

Primary reservoirs of the Central Arabia Qusaiba-Paleozoic TPS are sandstones of the Permian Unayzah and Devonian Jauf Formations, and in the Gulf portion of the total 

petroleum system, basal transgressive marine sandstones and 

cyclic dolomitic shelf carbonates of the Late Permian Khuff 

Formation (figs. 1 and 13). Other reservoirs include clastics 

of the Pre-Qusaiba section that are fault bounded and sourced 

laterally by down-faulted Qusaiba Shale Member. These PreQusaiba clastic reservoirs include the Cambrian-Ordovician 

Saq Sandstone, shallow-marine sandstones of the Ordovician 

Qasim Formation (Senalp and Al-Duaiji, 2001), and Upper 

Ordovician glacial and periglacial clastics of the Zarqu and 

Sarah Formations (McGillivray and Husseini, 1992). Many of 

these Pre-Qusaiba clastics have had some hydrocarbon shows 

but are poor-quality reservoirs owing to silica cementation.

The Upper Permian Unayzah Formation is a complex 

succession of generally red continental clastics consisting of 

braided-plain, channel-fill, and eolian sand and flood-plain silt 

that were deposited on the pre-Unayzah (Hercynian) unconformity (Senalp and Al-Duaiji, 1995; Evans and others, 1997; 

Konert and others, 2001). Regional surface and subsurface 

data indicate that the Unayzah is widespread over much of 

the eastern Arabian Plate (Al-Laboun, 1987). A recent study 

by Heine (in press) showed that sandstones of the Unayzah in 

the southern Ghawar area are cold-climate (periglacial) dunes 

deposited on an eroded surface that trends across central Saudi 

Arabia, and possibly over Bahrain and Qatar (fig. 27). The 

Unayzah unconformably underlies the Upper Permian Khuff 

Formation. Deposition of continental clastics of the Unayzah 

represents a major change in sedimentation that preceded 

a major marine transgression and widespread deposition of 

carbonates and evaporites of the Khuff Formation.

The Unayzah Formation is composed of cycles of crossbedded, fine- to coarse-grained sandstones, siltstones, and 

claystones with thin beds of argillaceous limestone. In central 

Saudi Arabia, the lowermost part of the Unayzah consists of 

debris-flow gravels and coarse clastics, which infill the Hercynian erosional unconformity on the underlying Qusaiba Shale 

(Senalp and Al-Duaiji, 1995). The Unayzah Formation fines 

upward into more distal, braided-stream bars and channel-fill 

sandstones, and flood-plain siltstones. The cyclic nature of the 

Unayzah suggests a fluctuating sea level. The upper Unayzah 

unit A is the principal reservoir averaging about 20 percent 

porosity. Permeability of several darcys is not uncommon; 

however, both porosity and permeability vary due to kaolinite 

and illite cements (McGillivray and Husseini, 1992). 

In the Greater Ghawar area, the principal Pre-Khuff 

hydrocarbon reservoir in the southern area (Haradh substructure field at Ghawar, and adjacent Sahba, Waqr, and Tinat 

fields; figs. 10 and 19) is the Unayzah Formation, whereas 

the Lower to Middle Devonian Jauf Formation is the main 

producing reservoir in the northern Ghawar area (Ghawar 

substructure fields: Hawiyah, ‘Uthmaniyah, and Shedgum; 

figs. 10 and 19). In the south Ghawar area, the Unayzah is 

generally divided into two sandstone reservoir units separated 

by a siltstone member (Wender and others, 1998). Gas is 

produced from most Paleozoic reservoirs at Ghawar; however, Qusaiba-sourced premium crude is produced from the 

Unayzah at the Tinat field structure immediately to the southeast. The Unayzah is missing in the north half of Ghawar field 

(McGillivray, 1994) but is present in the south half of Ghawar, 

where it thickens from 0 to greater than 152 m [500 ft] at Tinat 

field (fig. 28). Porosity of the upper Unayzah-A pay zone 

ranges from 5 to 25 percent and averages about 12 percent 

(Wender and others, 1998).

The shallow marine sandstones of the Devonian Jauf reservoir in the Ghawar area are well developed and commonly 

display high (30 percent) porosities at a depth of 4,260 m. In 

the northern Ghawar area, the Jauf reservoir ranges in thickness from 89 to 145 m. The giant gas-condensate discovery 

at the Hawiyah substructure field at Ghawar is in Jauf sands. 

The Jauf sandstones are fine to medium grained, are weakly 

cemented by authigenic illite clay, and lack the silica cement 

that is prevalent and detrimental to reservoir quality of most 

other Pre-Khuff sandstones. The authigenic illite is thought 

to inhibit quartz cementation and to preserve porosity. At 

Ghawar field, and at Abu Sa’fah field in the offshore to the 

northeast of Ghawar (fig. 19), the Jauf reservoir is sealed by a 

distinctive shale-silt layer that is referred to informally as the 

D3B zone (fig. 13) (Wender and others, 1998).

The Late Permian–Early Triassic Khuff Formation 

unconformably overlies the Unayzah Formation. Gas was discovered in carbonate rock reservoirs of the Khuff in the Awali 

field domal structure of Bahrain in 1949. The Khuff Formation is ranked as the largest reservoir formation of non-associated gas in the world with recoverable reserves estimated at 

about 750 TCF (Konert and others, 2001). Khuff reserves 

include the largest gas field in the world at North dome (field), 

Qatar (figs. 3 and 19) discovered in 1971; its total reserves are 

estimated at 500 TCF (Alsharhan and Nairn, 1997, p. 574). 

The Khuff Formation produces primarily gas that probably 

formed by the cracking of oil (Bishop, 1995). Locally, the 

quality of Khuff gas depends upon the amounts of non-hydrocarbon gases, mainly H2

S, CO2, and N2. The amount of H2S 

increases with increasing temperature and depth, reflecting 

in-place conversion of hydrocarbon gases to H2S by the thermochemical reduction of anhydrite sulfate (Konert and others, 

2001).

In eastern Saudi Arabia, the Khuff Formation is divided 

into five units or members designated as Khuff A through E. 

However, throughout the Gulf region the Khuff may comprise 

as many as seven designated units or members (Al-Jallal, 

1995). Most of the Khuff is composed of carbonates and 

evaporates; major siliciclastic facies increase towards the 

west. As many as four of the five units may be reservoirs and 

correspond to four depositional carbonate-anhydrite cycles 

where transgressive carbonate rocks are capped by regressive anhydrite facies (fig. 13). The Khuff Formation thickens 

from about 260 m in southwestern Saudi Arabia to more than 

915 m in the central Rub ‘al Khali Basin, 1,220 m in Oman, 

Central Arabia Qusaiba-Paleozoic Total Petroleum System 39
Figure 27. Arabian Peninsula during Early Permian showing area of erosion or nondeposition (blue dashed lines), knowdune fields (yellow area), probable glacial lake (blue area), and dominant wind direction across central eroded portion of Modified from Heine (in press).

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Figure 27. Arabian Peninsula during Early Permian showing area of erosion or nondeposition (blue dashed lines), known Unayzah dune fields able glacial lake (blue area), and dominant wind direction (arrow) across central eroded portion of Arabian Peninsula. Modified from Heine (in 
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Figure 28. Isopach map of the Unayzah Formation in central Saudi Arabia showing the Unayzah absent over the anorth half of Ghawar field and the Unayzah thickening to the north and south of this area. Contour interval 100 ftMcGillivray (1994).

Figure 28. Isopach map of the Unayzah Formation in central Saudi Arabia, showing the Unayzah absent over the area of Riyadh and north field and the Unayzah thickening to the north and south of this area. Contour interval 100 ft. Modifed from McGillivray (1994).
42 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

and 1,520 m in Iran. Typical thickness for the Khuff ranges 

between 370 m and 490 m over most of central and eastern 

Arabia (Al-Jallal, 1995).

The basal Khuff section consists mostly of siliciclastics 

throughout southern Arabia. The “basal Khuff clastics” are 

shale, carbonaceous shale, limestone streaks, and incised 

channel-fill sandstones. Channel-fill sandstones of the basal 

Khuff clastics are as much as 18 m in thickness and generally 

cut deeply into the Unayzah Formation. In Hazmiyah field 

of central Saudi Arabia (fig. 19), the reservoir occurs entirely 

within these channel sandstones in the basal Khuff (Senalp 

and Al-Duaiji, 1995).

The Unayzah and basal Khuff sandstones form the 

principal reservoirs in central Saudi Arabia; however, widespread reservoir quality variations occur in these sandstone 

reservoirs owing to heterogeneous sedimentary facies and 

diagenetic history (Aktas and Cocker, 1995; Polkowski, 1997). 

Depositional facies strongly influenced porosity evolution in 

these sands: both porosity and permeability generally decrease 

with cementation and silt and clay content and increase with 

increasing grain size and cement dissolution.

Many of the Khuff carbonate units were deposited as a 

restricted evaporitic, carbonate shelf facies and include subtidal carbonate sand shoals, lagoons and bars that spread out as 

sheets across long distances, along with intertidal and supratidal sabkha facies. Evaporites were deposited over a great 

extent of the area; the present-day total anhydrite thickness is 

107 m or more. In general, the best reservoirs are in highenergy carbonate buildups consisting of oolitic grainstones 

and intertidal dolomite mudstones formed during sea-level 

highstands at the shelf edge and along the shallow carbonate 

shelf (fig. 29); these were capped by impermeable anhydrite 

deposited during sea-level lowstands. Khuff carbonate reservoirs at Dammam and Abu Sa’fah fields are examples of such 

buildups. Wells producing from these reservoirs at Dammam 

and Abu Sa’fah commonly contain considerable amounts of 

non-hydrocarbon gases, particularly H2S. Quality of Khuff 

reservoirs is variable, and porosity of these reservoirs is highest where anhydrite percentage is lowest. Areas of high porosity in carbonate rocks of the Khuff in Iran, Qatar, and Bahrain 

define a broad belt of shallow shelf breaks that once bordered 

a restricted evaporitic carbonate shelf (fig. 29) (Al-Jallal, 

1995). At Ghawar, anhydrite has reduced porosity of Khuff 

carbonates considerably; however, good reservoir porosity in 

the Khuff in central Arabia is attributed to the presence of the 

basal sandstone unit.

Seal Rocks

Many of the Ordovician sandstone reservoirs of the 

Sarah and upper Qasim Formations are sealed by the overlying Early Silurian Qusaiba Shale; however, lower sandstone members of the Qasim showing reservoir potential are 

sealed by the intraformational Ra’an Shale Member. The 

Lower Ordovician, informal Saq A sandstone unit of the Saq 

Formation is sealed by the lower Hanadir Member of the 

Qasim Formation (fig. 13).

Reservoir sandstones of the Devonian Jauf Formation are 

capped by a very distinctive shaly unit informally referred to 

as the “D3B” stratigraphic marker or zone (fig. 13). The D3B 

Zone lies directly on the Jauf sandstones at Ghawar and is recognized by high resistivities on electric logs, and high velocities on sonic logs (Wender and others, 1998). The D3B Zone 

is better developed to the northeast of Ghawar where it forms 

the seal for Jauf gas-condensate accumulations in the northern 

Gulf at Abu Sa’fah field, about 70 km north of Bahrain (fig. 

19). The D3B Zone was probably deposited during a rise in 

sea level and may represent a condensed section (Wender and 

others, 1998).

Impermeable units within the Permian lower Khuff Formation combine to form the primary seal for clastic reservoirs 

of the underlying Unayzah Formation. These impermeable 

anhydrites and carbonate rocks, and shale beds of the Khuff 

Formation also constitute the major regional seal for the Central Arabia Qusaiba-Paleozoic TPS; however, local intraformational seals within the Khuff are important for many of the 

Khuff reservoir units. Shales and tight carbonate rocks of the 

basal Khuff were deposited over a widespread area during the 

Late Permian sea-level rise. The basal Khuff forms the top 

seal to the Permian Unayzah reservoir in four-way structural 

closures in the southern Ghawar area (Wender and others, 

1998). The basal Khuff also forms the top seal to the Devonian Jauf reservoirs in unconformity-related traps at Ghawar. 

Hercynian faults are also important as lateral seals in controlling hydrocarbon accumulations in the Ghawar area (Wender 

and others, 1998). The Khuff Formation also forms the seal 

for hydrocarbon accumulation in Unayzah reservoirs in updip, 

oil and gas fields of central Arabia (figs. 19 and 29) where the 

Qusaiba source rock is immature.

Anhydrite of the Khuff Formation evaporite facies was 

deposited over an extensive area of the Arabian shelf (fig. 29). 

Shelf-edge oolitic grainstone and intertidal dolomite reservoirs 

of the Khuff Formation are sealed by overlying cyclic, regressive anhydrite beds of the Khuff that were deposited during 

sea-level lowstands.

Traps and Trap Styles

Traps are mostly structural and related to basement block 

faulting, tectonic salt movement and deformation (halokinesis), and wrench faulting. Complex structural-stratigraphic 

traps also occur on flanks of Hercynian structures. Basement 

fault blocks are the result of preexisting zones of weakness established during accretion of the Arabian Plate in the 

Precambrian. High-angle reverse faulting occurred in central 

Saudi Arabia paralleling and overlying these zones of weakness (Husseini, 1991; Al-Husseini, 2000). Large, generally 

north trending, fault-bounded blocks developed from the 

Hercynian tectonic event (figs. 8 and 10). Structurally high 

blocks also coincide with major Bouguer gravity positives 
Figure 29. Major environments of deposition and regional facies of the Khuff Formation over the 

eastern Arabian Peninsula and Zagros Fold Belt. Modified from Al-Jallal (1995).

Central Arabia Qusaiba-Paleozoic Total Petroleum System 43

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Figure 29. Major environments of deposition and regional facies of the Khuff Formation over the eastern

Arabian Peninsula and Zagros fold and thrust belt. Modified from Al-Jallal (1995)

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44 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

and consist of either horst-block trends developed in relay 

patterns or east-tilted fault blocks with major bounding faults 

on the west flank (McGillivray and Husseini, 1992). Similarly, structures formed and modified from halokinesis of the 

underlying Hormuz Salt in the North Gulf Salt Basin (fig. 3) 

are also major trap-forming mechanisms of the Central Arabia 

Qusaiba-Paleozoic TPS.

Major trap formation and modification in the Central Arabian sub-basin, which includes both reactivated basement fault 

blocks and structures related to movements of Infracambrian 

salt, occurred in four main tectonic stages: (1) the Carboniferous Hercynian Orogeny; (2) Early Triassic Zagros rifting and 

opening of the Neo-Tethys Sea (fig. 8); 3) the First Alpine 

Orogeny during the Late Cretaceous (Coniacian-Campanian), 

associated with the collision event that led to the emplacement of the Semail Ophiolite Complex in Oman; and (4) the 

Second Alpine Orogeny during the middle to late Tertiary, 

associated with the opening of the Red Sea and collision of the 

Arabia and Eurasia plates (Wender and others, 1998). These 

main tectonic stages are shown in the trap formation column 

of the Central Arabia Qusaiba-Paleozoic TPS events chart of 

figure 21. Although many of the structures at Ghawar show 

major growth during the Carboniferous Hercynian event (figs. 

10 and 12), other fields nearby that involve basement-related 

fault structures, including Abqaiq and Udaynan, indicate 

non-Hercynian growth and a much younger origin. These 

younger, “late” structures, which initiated major movement 

of Infracambrian salt that formed the domes of Dammam and 

Awali fields, were created during major uplift and erosion 

associated with the Late Cretaceous First Alpine Orogeny 

(Wender and others, 1998).

Several fields in central Saudi Arabia (fig. 19) that produce Silurian-sourced, super-light, sweet crude oil from both 

structural and stratigraphic traps in siliciclastics of the Permian 

Pre-Khuff Unayzah Formation are recent discoveries. Seismic 

profiles and structural map geometries of these fields suggest wrench faulting of the early to middle Paleozoic section 

with associated drape and drag of the overlying Paleozoic and 

Mesozoic section (Simms, 1995). Seismic sections in this area 

reveal that the basement and Paleozoic section are faulted with 

many reverse faults. The wrench fault system was initiated 

during the Hercynian Orogeny in the Middle Devonian and 

reactivated during periods of rifting and subduction along the 

Arabian Plate boundaries (Simms, 1995). 

Stratigraphic traps also occur in some of the Paleozoic 

fields of central Saudia Arabia. Three types of stratigraphic 

traps have been identified along the Hawtah and Nuayyim 

structural trends in the Permian Unayzah sandstones of these 

Pre-Khuff fields (fig. 19). These stratigraphic traps are 

described as follows: (1) isolated reservoir sands that pinch 

out updip to the west, forming stratigraphic traps along the 

east flank of the Hawtah and Nuayyim trends; (2) truncation traps of upper Unayzah sandstones below the regional 

Pre-Khuff Unconformity; and (3) combination structuralstratigraphic traps where reservoir sand facies pinch out across 

structural highs (Evans and others, 1997).

Arabian Sub-Basin Tuwaiq/HanifaArab Total Petroleum System

General Description

The Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS 

(202102) encompasses an area mostly within Saudi Arabia, 

western Qatar, and northern Gulf offshore of southern Iran 

along the Zagros Fold Belt (fig. 30). The Arabian Sub-Basin 

Tuwaiq/Hanifa-Arab TPS includes the entire Greater Ghawar 

Uplift Province and extends into the central part of the Interior 

Homocline-Central Arch Province (2020), the western flank 

of the Qatar Arch Province (2022), the north edge of the Rub 

‘al Khali Basin Province (2019), and the southeasternmost 

parts of both the Widyan Basin-Interior Platform (2023) and 

Mesopotamian Foredeep Basin (2024) Provinces (fig. 30). 

Petroleum system elements of the Arabian Sub-Basin Tuwaiq/

Hanifa-Arab TPS are included on the total petroleum system 

events chart of figure 31; source, reservoir, and seal rocks are 

generally outlined in the stratigraphic section showing the 

Greater Jurassic Petroleum System in figure 1. The Arabian 

Sub-Basin Tuwaiq/Hanifa-Arab TPS includes Ghawar field, 

as well as several other supergiant Jurassic oil fields of the 

central Arabian Peninsula such as Berri, Abqaiq, Abu Sa’fah, 

Khurais, Khursaniyah, and Dukhan (fig. 32).

The boundary of the Arabian Sub-Basin Tuwaiq/HanifaArab TPS (fig. 30) was determined primarily by the combined 

geographic extent of the Jurassic (Callovian-Oxfordian) 

source-rock facies of the Tuwaiq Mountain and Hanifa Formations and the shelf facies boundaries of the Jurassic Central 

Arabian intraplatform sub-basin (figs. 4 and 33) (Ayres and 

others, 1982; Chaube and Al-Samahiji, 1995; Cole, Carrigan, 

and others, 1994; Al-Husseini, 1997; Yousif and Nouman, 

1997). To the north and west, the Arabian Sub-Basin Tuwaiq/

Hanifa-Arab TPS is bordered by Jurassic shelf facies (fig. 33) 

(Ayres and others, 1982; Al-Husseini, 1997), which separated 

the Jurassic Arabian intraplatform sub-basin from the Jurassic intraplatform Gotnia sub-basin that corresponds to the 

Gotnia/Barsarin/Sargelu/Najmah TPS (U.S. Geological Survey 

World Energy Assessment Team, 2000; Fox and Ahlbrandt, 

2002). Similar to the Central Arabia Qusaiba-Paleozoic TPS, 

the Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS is also limited on the east by the structural axis of the Qatar Arch. The 

Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS laps onto the 

Central Arabian Arch to the south and southeast, and is further 

constrained by the western flank of the Rub ‘al Khali Basin 

(fig. 3). Fields that produce from Jurassic reservoirs in the 

Arabian-Persian Gulf region are shown in figure 32.

Petroleum Geochemistry

Source Rocks

A major rise in sea level starting in the Callovian, combined with differential subsidence, led to drowning of the 

platform and the formation of the Central Arabian intraplatform sub-basin (Meyer and Price, 1993). The Central Arabian 
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Figure 30. USGS geologic province boundaries, Jurassic oil-field center points, and geographic limits for ArabiTuwaiq/Hanifa-Arab Total Petroleum System (2021002), Horst-Block Anticlinal Oil Assessment Unit and Salt-IOil Assessment Unit. U.A.E., United Arab Emirates.

Figure 30. USGS geologic province boundaries, Jurassic oil-field centerpoints, and geographic limits for Arabian Sub-Basin Tuwaiq/Hanifa-Arab To(202102), Horst-Block Anticlinal Oil Assessment Unit, and Salt-Involved Structural Oil Assessment Unit. U.A.E., United Arab Emirates.
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Figure 31. Events chart for Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System (202102) of the Greater Gand surrounding provinces of the Arabian Peninsula, showing total petroleum system elements and timing of trap formgeneration. [E., Early; M., Middle; L., Late; Paleo., Paleocene; Olig., Oligocene; PP, Pliocene-Pleistocene, Quat., Qua

Figure 31. Events chart for Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System (202102) of the Greater Ghawar Uplift Province and surroArabian Peninsula, showing total petroleum system elements and timing of trap formation and hydrocarbon generation. E., Early; M., Middle; L., Late; Oligocene; PP, Pliocene-Pleistocene; Quat., Quaternary.
Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System 47

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Figure 32. Oil and gas fields of the Arabian-Persian Gulf Region with reservoirs in Jurassic age rocks.

Modified from Al-Husseini (1997).

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Figure 32. Oil and gas fields of the Arabian-Persian Gulf region with reservoirs in Jurassic age rocks. Modified from 

Al-Husseini (1997).
48 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Figure 33. Paleogeography of Jurassic sub-basins of Arabian-Persian Gulf region, showing various facies during 

late Callovian to late Oxfordian centered around the Central Arabian sub-basin. Modified from Cole, Carrigan, and 

others (1994); Christenson and others (1977); Murris (1980); and Ayres and others (1982).

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e 33. Paleogeography of Jurassic intraplatform sub-basins of Arabian-Persian Gulf region during late Callovian to late Oxfordian

ed around the Central Arabian sub-basin. Modified from Cole, Carrigan and others (1994); Christensen and others (1977); Murr

yres and others (1982).

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sub-basin was separated from the deeper, more extensive intraplatform Gotnia sub-basin to the north, and from the shallower 

and shorter lived South Arabian Gulf intraplatform sub-basin 

to the south and east (fig. 33) by shallow grainstone shoals 

and dolomitized facies. Tropical and subtropical climate 

and restricted circulation created anoxic conditions and the 

production, accumulation, and preservation of organic-rich, 

mostly algal material over large parts of the intraplatform 

sub-basins (Cole, Carrigan, and others, 1994). Water depths 

were probably on the order of a few tens of meters; subsidence and depositional rates were minimally different because 

basinal intervals are only slightly thicker than surrounding 

shelf intervals. Deposition of the source facies in the Jurassic 

intraplatform sub-basins was initiated by a eustatic sea-level 

rise (Christenson and others, 1977; Ayres and others, 1982).

The areal extent of the source-rock facies and pod of 

active source rock for the Arabian Sub-Basin Tuwaiq/HanifaArab TPS of this report was mapped from the studies of 

Murris (1980), Ayres and others (1982), Frei (1984), Alsharhan and Magara (1994), Cole, Carrigan, and others (1994), 

Chaube and Samahiji (1995), Al-Husseini (1997), Alsharhan 

and Nairn (1997), Milner (1998), and Zeigler (2001) (figs. 

34 and 35). Two organic-rich intervals of marine carbonates 

and marls of the Central Arabian Sub-Basin Tuwaiq/HanifaArab TPS generate a single superfamily of oils that constitute 

some of the world’s largest single oil-field reserves. These 

excellent source-rock intervals are within the Jurassic Tuwaiq 

Mountain and Hanifa Formations. In the area of the Central 

Arabian sub-basin, the Tuwaiq Mountain Formation is the primary source rock; the Hanifa Formation is also an important 

petroleum source rock in this area, thus forming the “Tuwaiq/

Hanifa Superfamily” of oils for which the total petroleum 

system was designated.

The extent and thickness of this package of source rocks 

in which TOC exceeds 1 weight percent are shown in the 

isopach map of figure 34 (modified from Ayres and others 

(1982) and Cole, Carrigan, and others (1994)). Cole, Carrigan, and others (1994) showed that the Tuwaiq Mountain 

is the main source rock in central Arabia and in the area 

encompassing the Arabian Sub-Basin Tuwaiq/Hanifa-Arab 

TPS of this study. In contrast, the organic-rich facies of the 

Hanifa Formation and its equivalent, the Diyab Formation, 

are the major Jurassic source rocks that generate hydrocarbons produced from Jurassic reservoirs in the Rub ‘al Khali 

Basin and Southern Arabian Gulf intraplatform sub-basin, 

respectively (Ayres and others, 1982).

The Tuwaiq Mountain is as much as 150 m thick (fig. 34) 

in the central part of the Central Arabian sub-basin (Ayres and 

others, 1982; Cole, Carrigan, and others, 1994) and laterally 

equivalent to the Upper Fadhili and Hadriya reservoirs deposited on the carbonate rock platform to the north. In a study of 

samples from wells at Khurais and Ghawar fields, Cole, Carrigan, and others (1994) reported that the Tuwaiq Mountain is 

extremely organic rich: TOC exceeds 13 weight percent and 

averages about 3.5 weight percent. In comparison, the Hanifa 

source rock of central Saudi Arabia is less than 30 m thick and 

averages about 2.6 weight percent TOC. Kerogen in both the 

Tuwaiq and Hanifa source rocks is primarily Type II 

(oil-prone) and is believed to consist primarily of blue-green 

algae (Ayres and others, 1982).

Organic Geochemistry

Oil-to-oil and oil-to-source rock correlations by Cole, 

Carrigan, and others (1994) showed that most of the oil in 

Jurassic reservoirs of eastern Saudi Arabia can be grouped into 

a single superfamily having specific characteristics. Generally, these oils consist of 30–40 percent saturate, 30–45 

percent aromatics, and 20–30 percent resin plus sulfur and are 

classified as aromatic-intermediate oils. Sulfur content is high 

(1–4 percent or greater) and consistent with a marine carbonate source. Most oils from Upper Jurassic Arab and Hanifa 

reservoirs have API gravities ranging from 25° to 35° (Cole, 

Carrigan, and others, 1994). Lower sulfur content is normally 

associated with higher API gravities, as noted for Silurian 

sourced oils.

Jurassic oils have very similar light hydrocarbon characteristics on chromatographs and are quite different from 

deeper Permian reservoir condensates from Silurian sources, 

as previously discussed. Gas chromatograph/mass spectrometer analysis shows that most oils of central Arabia Jurassic 

reservoirs have similar biomarkers, particularly hopane and 

tricycline (m/z 191) and steranes (m/z 217), which are indicative of oils derived from source rocks deposited in a carbonate 

environment under anoxic, reducing conditions (Cole, Carrigan, and others, 1994). Most carbon isotope (δ13C) values 

are between –26.0 and –26.5‰ for immature Tuwaiq Mountain and Hanifa source rocks and show excellent correlation 

to average δ13C compositions (–26.6‰) for whole oils from 

reservoirs of the Jurassic Arab and Hanifa Formations. In 

contrast, the δ13C compositions of hydrocarbons in reservoirs 

of the Permian Khuff Formation range between –28.0 and 

–30.5‰ (Abu-Ali and others, 1991; Cole, Abu-Ali, and others, 1994; Cole, Carrigan, and others, 1994) and are clearly a 

different family of oils than those from the Jurassic Arab and 

Hanifa reservoirs.

The oil-prone Tuwaiq Mountain source interval has 

excellent pyrolysis yields (S2 Rock-Eval yields) averaging 

22.2 mg hydrocarbons/g rock and hydrogen indices greater 

than 600 mg hydrocarbon/g TOC. In contrast, the Hanifa of 

the Central Arabian sub-basin has hydrogen indices less than 

400, tending toward mixed oil and gas formation (Cole, Carrigan, and others, 1994). In summary, Jurassic source rocks 

and oils produced from Arab and Hanifa reservoirs are of 

similar bulk composition, and have similar carbon isotopic, 

gas chromatographic, and biomarker signatures. Additionally, 

Jurassic oils are different from the Silurian Qusaiba-sourced 

oil in Permian Unayzah and Khuff reservoirs.

Maturation, Generation, and Expulsion

Present-day levels of thermal maturity of the source 

rocks for the Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS are 

shown in the map of figure 35. Timing of maturation and the 

generation of hydrocarbons in these source rocks are summarized in the total petroleum system events chart of figure 

Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System 49
50 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Figure 34. Isopach thickness of petroleum source-potential units of Upper Jurassic Tuwaiq Mountain Formation having 

>1.0 weight percent total organic content (TOC). Approximate limit of >1.0 weight percent organic matter shown by query. 

Modified from Cole, Carrigan, and others (1994); and Ayres and others (1982). Contour interval 30 m.

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Figure 34. Isopach thickness of petroleum source-potential units of Upper Jurassic Tuwaiq Mountain Formation having

>1.0 weight percent total organic content (TOC). Approximate limit of >1.0 percent organic matter designated with [?].

Contour interval 30 m. Modified from Cole, Carrigan and others (1994), and Ayres and others (1982)

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Figure 35 (following page). Summary of present-day 

extent of thermal maturity levels as defined by vitrinite 

reflectance (Ro), and distribution of source facies for the 

Jurassic Hanifa Formation in central Saudi Arabia and Rub 

‘al Khali Basin. Modified from Milner (1998). 
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52 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

31, in the maps of figure 36, and in the burial history curve of 

figure 37. Modelling of source rock maturity and time of oil 

expulsion in figure 36 by Cole, Carrigan, and others (1994) 

has shown that the main phase of oil generation began in the 

Cretaceous about 75 Ma (Campanian) for Tuwaiq Mountain/

Hanifa source rocks with greater than 1.0 weight percent 

TOC. In eastern Saudi Arabia and Kuwait this occurred in 

three principal areas, as follows: (1) southwest Kuwait in 

the Gotnia intraplatform sub-basin; (2) west-central northern 

Gulf near Safaniya and Abu Hadriya fields; (3) southwestern 

northern Gulf south of Bahrain at Dammam field, Qatar, and 

to the east and southeast of Ghawar field. According to the 

model of Cole, Carrigan, and others (1994), oil expulsion 

began to cease in portions of the northern Gulf (areas 2 and 

3) about 25 Ma (Oligocene) and in southwestern Kuwait by 

present day. Also, main-phase oil expulsion in Jurassic source 

rocks is occurring today in many parts of the Central Arabian 

intraplatform sub-basin. In contrast, Jurassic source rocks are 

immature to early mature in the northern Gulf, north of Qatar 

along the Qatar Arch, and in the area of Khurais, Abu Jifan, 

and Mazalij fields (fig. 36). Similarly, burial-history modeling in a structurally deep part of the basin west of Safaniya 

field (fig. 37) shows that Jurassic Tuwaiq/Hanifa source rocks 

first entered the main level of thermal maturity for oil generation during the Cretaceous, about 75 Ma. The burial curve of 

figure 37 also shows that the Tuwaiq/Hanifa source rocks near 

Safaniya field are presently in the late stage of oil generation, 

consistent with the “end of oil expulsion to oil preservation” 

stage of figure 36. According to the model of Cole, Carrigan, 

and others (1994), initial generation (early maturity) in these 

Jurassic source rocks occurs at a mean vitrinite reflectance 

(Ro) of about 0.45 percent (fig. 37); thus, rocks having an Ro of less than 0.45 percent are immature. Generation of oil at 

relatively low maturity (Ro equal to 0.45 percent) is due to the 

predominantly high sulfur, type II-S kerogen comprising the 

source rocks. Type II-S kerogen characteristically generates 

hydrocarbons at comparatively low thermal maturity (Baskin 

and Peters, 1992; Lewan, 1998).

At Awali field, Bahrain, Chaube and Al-Samahiji (1995) 

showed that the Hanifa source facies is as much as 46 m 

thick. They concluded that the onset of oil generation in the 

Hanifa at Awali began in the Eocene (about 45 to 50 Ma) and 

charged Jurassic reservoirs; however, to the north and east of 

Awali, oil generation was later, or source rocks are immature 

at present day. This interpretation is comparable to the data of 

Cole, Carrigan, and others (1994). Additionally, in a study of 

the Rub ‘al Khali Basin, Milner (1998) also reported Ro data 

showing comparabIe maturities of the Jurassic Hanifa source 

rock in the southern part of the Greater Ghawar Uplift Province (fig. 35) to those reported by Cole, Carrigan, and others 

(1994) and Chaube and Al-Samahiji (1995).

Reservoirs

Reservoirs of the Arabian Sub-Basin Tuwaiq/HanifaArab TPS and their relation to source and seal rocks are summarized in both the stratigraphic section of figure 1 

(as part of the Greater Jurassic Petroleum System) and the 

total petroleum system events chart of figure 31. Late Jurassic 

(Tithonian) eustatic variations of the Arabian platform resulted 

in the deposition of carbonate rock-anhydrite cycles (figs. 1 

and 14) that constitute the dominant reservoirs and caprocks 

(Arab Formation carbonate rocks and Arab Formation and 

Hith Formation evaporite seal rocks) of the Arabian Sub-Basin 

Tuwaiq/Hanifa-Arab TPS. Late Tithonian evaporitic conditions on a vast platform (fig. 38) produced the Hith Anhydrite 

and formed inland salt lakes in the western structural Rub ‘al 

Khali Basin and intraplatform Gotnia sub-basin (Al-Husseini, 

1997). Any significant loss of hydrocarbons generated within 

this Jurassic system was prevented by the regionally extensive, 

overlying evaporite seals; thus, only limited vertical migration 

occurred. The present-day sabkha depositional setting that 

extends along most of the southern and southwestern coasts 

of the Gulf is an analog for the setting of the Arab and Hith 

Formations (Alsharhan and Whittle, 1995).

The primary reservoirs are commonly 10- to 30-m thick, 

cyclic shallow-water, platform carbonate grainstones of the 

Upper Jurassic Arab Formation (Arab A, B, C, and D). Arab 

D is the primary reservoir with an average porosity of about 

25 percent. Moreover, the Arab D reservoir accounts for 

most of the Jurassic oil production in the Arabian-Persian 

Gulf region, forming many supergiant and giant fields. A 

few reasons why the Arab D reservoir is a prolific producer 

of hydrocarbons are that it is in close stratigraphic position 

above the Tuwaiq Mountain and Hanifa source rocks and is 

sealed regionally by the Arab-D anhydrite (fig. 14). Also, the 

Arab D is the main reservoir at supergiant Ghawar field. The 

Arab D consists of several (at least four) major upward-shoaling cycles that were initiated in deeper water and shoaled to 

near sea level. Porosity and permeability in the reservoir are 

dependent on lithology, especially the type of dolomite present 

in the cycles, and microporosity, all of which play a major role 

in productivity (Bouroullec and others, 1995; Douglas, 1996; 

Cantrell and Hagerty, 1999; Saner and Sahin, 1999; Cantrell 

and others, 2001). For example, the Arab D reservoir at the 

‘Uthmaniyah substructure (fig. 10) field of Ghawar is a 91-m 

thick carbonate rock sequence consisting of various carbonate rock types that exhibit an overall stratigraphic downward 

decrease in porosity with a corresponding increase in dolomite 

content. The granular facies is the most porous and permeable 

lithofacies in the Arab D (Saner and Sahin, 1999).

The Arab D reservoir at Harmaliyah field, Saudi Arabia 

(fig. 32), is characterized by high primary porosity that was 

preserved because of early or pre-burial diagenesis. Porosity 

preservation was not caused by early emplacement of hydrocarbons into an uncompacted reservoir (Purser, 1978; Ibrahim 

and others, 1981). At Ghawar field, Saudi Arabia, Cantrell 

and others (2001) have identified at least five distinct types of 

dolomite in the Arab D reservoir. One dolomite type, referred 

to as the “super-k” type, is medium- to coarse-crystalline dolomite with good reservoir quality and appears to be responsible 

for high fluid flow in the Arab D, “Zone 2” reservoir.
Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System 53

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Figure 36. Maps of central Saudi Arabia and northern Arabian-Persian Gulf area showing hydrocarbon

maturity, generation, and expulsion of oil from Jurassic source rocks at 75 Ma, 50 Ma, 25 Ma, and present

day. Also shown are oil field outlines and isopach thickness of Hanifa Formation with >1.0 percent total

organic carbon (TOC). Approximate limit of >1.0 percent TOC source rock is shown by contour with [?].

Contour interval equals 30 m. Modified from Cole, Carrigan and others (1994) and Ayres and others (1982).

Figure 36. Maps of central Saudi Arabia and northern Arabian-Persian Gulf area, showing hydrocarbon maturity, generation, and 

expulsion of oil from Jurassic source rocks at 75 Ma, 50 Ma, 25 Ma, and present day. Also shown are oil field outlines and isopach 

thickness of Hanifa Formation with >1.0 percent total organic carbon. Approximate limit of >1.0 weight percent TOC source rock shown 

by query. Modified from Cole, Carrigan, and others (1994) and Ayres and others (1982). Contour interval 30 m.
54 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

The Arab Formation is about 150–210 m thick in the area 

of Qatar and Bahrain; the type section for the Arab Formation 

is the Dammam number 7 well (located in Dammam field (fig. 

32) in eastern Saudi Arabia), rather than an outcrop description 

(Alsharhan and Whittle, 1995). In the onshore Qatar area, the 

Upper Jurassic (Arab and Hith Formations) is subdivided into 

the Fahahil, Qatar, and Hith Formations. In offshore Qatar, 

the Qatar and Fahahil Formations are grouped informally as 

the “Arab zone” and are equivalent to the Arab Formation 

defined in Saudi Arabia. The four carbonate rock portions of 

the cycles from top to bottom, however, are referred to as I, 

II, III, and IV and are equivalent to Arab reservoir members A 

through D. The interval consisting of limestone I through III 

(Arab A–C) is formally referred to as the Qatar Formation; the 

lowermost limestone IV (Arab D) is designated as the Fahahil 

Formation, as defined by the Qatar Petroleum Company from 

a well in Dukhan field (Alsharhan and Whittle, 1995). 

Secondary reservoirs of the Arabian Sub-Basin Tuwaiq/

Hanifa-Arab TPS include the porous carbonate-rock units 

within the Hanifa and Tuwaiq Mountain Formations. These 

porous carbonate-rock units are referred to as the Hanifa reservoir facies and the Hadriya reservoir facies, respectively, and 

comprise large-scale upward-coarsening, shallowing-upward, 

carbonate-rock platform sequences (McGuire and others, 

1993). The Hanifa reservoir facies consists of porous (5–30 

percent, mostly microporosity), fine-grained, mud-supported 

limestones and subordinate dolomites with low matrix permeabilities. High-angle fractures are important for production in 

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Figure 37. Burial history and petroleum generation model for Tuwaiq/Hanifa source rocks near Safaniya field.

Modified from Cole, Carrigan and others (1994). VRE, vitrinite reflectance equivalent.

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Figure 37. Burial history and petroleum generation model for Tuwaiq/Hanifa source rocks near Safaniya field. Modified from Cole, 

Carrigan, and others (1994). VRE, vitrinite reflectance equivalent.
these reservoirs. At Abqaiq field (fig. 32), the Hanifa is separated from the Arab D reservoir by more than 135 m of finegrained, impermeable carbonates of the Jubailah Formation. 

The Hanifa source facies is overlain by as much as 106 m of 

the Hanifa reservoir facies, which is in pressure-fluid communication with the Arab D by means of a network of fractures 

through the Jubailah Formation (fig. 1) (Grover, 1993).

The upper portion of the Tuwaiq Mountain Formation 

contains a succession of carbonate grainstones, particularly 

at Berri field, Saudi Arabia (fig. 32), that is referred to as 

the Hadriya reservoir facies. The Hadriya reservoirs consist 

of a basinward succession of coarse-grained, storm-related, 

skeletal and algal grainstone shoal deposits (Koepnick and 

others, 1995; Kompanick and others, 1995). The north-southoriented, wedge-shaped accumulation ranges from 15 to 70 

m in thickness and contains seven wedge-shaped, 5 to 9 m 

upward-coarsening packages. Performance of Hadriya reservoirs is affected by both depositional and diagenetic processes. 

The reservoir structure is multilayered and internally heterogeneous owing to the Hadriya’s sequence framework and 

depositional and diagenetic processes that created horizontal 

and vertical barriers to fluid flow. Shallow-burial, bed-parallel 

diagenesis produced cementation at the tops of parasequences 

impeding vertical cross-flow of fluids within the reservoir. In 

contrast, later cross-cutting diagenetic modifications, which 

include some intragranular microporosity development and 

Figure 38. Paleoenvironment and tectonic reconstruction of the Late Jurassic, late Tithonian of the Arabian 

Plate. By the Tithonian, a series of rift basins had formed and separation from Africa had occurred. Modified from 

Al-Husseini (1998) and Fourcade and others (1993). U.A.E., United Arab Emirates.

Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System 55

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Figure 38. Paleoenvironment and tectonic reconstruction of the Late Jurassic, late Tithonian of the

Arabian Plate. By the Tithonian, a series of rift basins had formed and separation from Africa

had occurred. Modified from Al-Husseini (1998) and Fourcade and others (1993). U.A.E, United

Arab Emirates.
56 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

sparry intergranular cementation, resulted in a major reduction in permeability. The best producing horizons are algal 

grainstones that exhibit lesser depositional heterogeneity and 

greater preservation of primary porosity (Koepnick and others, 

1995). Low-permeability lime mudstones of the lower Hanifa 

Formation provide a seal for the underlying Hadriya reservoir.

Seal Rocks

Seal rocks for the major Arab Formation carbonate-rock 

reservoirs of the Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS 

are anhydrite beds of the Arab and Hith Formations; secondary carbonate-rock reservoirs of the Upper Jurassic Hanifa 

and Jubailah Formations are sealed by overlying fine-grained, 

impermeable carbonate rocks or shales of adjacent formations 

(Alsharhan and Nairn, 1997). Anhydrite beds of the Arab and 

Hith Formations form an excellent cap for the giant oil and 

associated gas accumulations in the Arab carbonate rocks. 

Moreover, upward seepage through these caps is rare and has 

occurred only as a result of major faulting over a structure or 

from lateral thinning or wedging out of the anhydrites.

In the Arabian-Persian Gulf region, the Arab Formation 

is overlain by the Upper Jurassic Hith Formation (Murris, 

1980; Ayres and others, 1982; Al-Husseini, 1997; Sharland 

and others, 2001; Zeigler, 2001). A latest Jurassic restrictedshelf, evaporitic environment resulted in the deposition of the 

massive, regionally extensive Hith Formation evaporite (fig. 

38, evaporitic platform). The Hith evaporite forms a regional 

seal for Jurassic reservoirs (Murris, 1980; Yousif and Nouman, 

1997; Al-Husseini, 1997) and thus is the regional seal for the 

Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS of this report.

The Tithonian Stage of the Upper Jurassic was dominated 

by evaporites and shallow marine carbonate rocks that compose the “Arab sequence.” The Arab sequence corresponds to 

the Arab reservoirs and evaporites (Arab A through D) and the 

Hith Formation evaporites (fig. 14). According to Al-Husseini 

(1997), the complete Arab sequence consists of (1) shallowing-upward, shoal-grainstone (transgressive deposits); (2) bedded lagoonal mud/wackestone (maximum flooding surface); 

(3) coarse bioclastic grainstone capped by algal laminates 

(early highstand); and (4) anhydrites (later highstand). Two 

evaporite/salt inland “salinas” (salt lakes) developed in the 

western Rub ‘al Khali Basin and Jurassic Gotnia intraplatform 

sub-basin (Al-Husseini, 1997).

Murris (1980) described Hith evaporite development on 

a shallow platform in a sabkha environment due to an arid 

climate in the late Turonian. Alsharhan and Kendall (1986) 

suggested that the predominance of anhydrite and the occurrence of minor dolomite in the Hith Formation mark a final 

regressive, prograding supratidal phase of Late Jurassic sedimentation. They interpret the Upper Jurassic cycles of marine 

limestone and anhydrites of the Arab and Hith Formations as 

a response to changes in sea level caused by regional epeirogenic movements or by eustasy.

The Upper Jurassic Hith Formation consists of perhaps 

a hundred meters of massive beds of anhydrite showing 

chicken-wire texture with subordinate interbeds of light- to 

dark-colored dolomites (Alsharhan and Kendall, 1994). The 

Arab members A, B, and C consist mostly of anhydrite with 

chicken-wire texture and subordinate dolomite and limestone. 

The Arab D member is mostly limestone and dolomite with 

subordinate anhydrite. At Abqaiq field, the Hith anhydrite is 

128 to 287 m in thickness; the anhydrites of the Arab B and C 

anhydrite sub-members are each about 21 m in thickness and 

the Arab D is about 15 m (Saner and Abdulghani, 1995). At 

Ghawar field, the Hith Formation is about 152 m thick and 

consists of anhydrite with subordinate fine-grained limestone 

and dolomite (Arabian American Oil Company, 1959). The 

anhydrite lithofacies of the Arab D at Ghawar field consists of 

nodular to massive anhydrite, commonly with chicken-wire 

texture (Al-Husseini, 1997; Cantrell and others, 2001).

The seals for Hanifa reservoirs are fine-grained carbonate rocks that commonly leak because of fractures (Alsharhan 

and Nairn, 1997). For example, at Abqaiq field the Hanifa 

reservoir is separated from the giant Arab D reservoir by more 

than 137 m of fine-grained, impermeable carbonate rock of 

the Jubailah Formation, which appears to provide the seal. 

However, this carbonate-rock seal is in places ineffective from 

microfracturing that causes the Hanifa and Arab D reservoirs to be in pressure-fluid communication (Grover, 1993). 

Low-permeability mudstones of the lower Hanifa Formation 

provide a seal for the underlying Hadriya reservoirs of the 

Tuwaiq Mountain Formation; this reservoir/seal relation is 

best developed at Berri field (McGuire and others, 1993).

Traps and Trap Styles

Traps and trap styles of the Arabian Sub-Basin Tuwaiq/

Hanifa-Arab TPS are similar to those discussed in the equivalent “Traps and Trap Styles” section for the Central Arabia 

Qusaiba-Paleozoic TPS. Basement structures in the area of 

the Central Arabian intraplatform sub-basin controlled much 

of the deposition and subsequent structural growth during 

the Jurassic. Traps include (1) anticlines related to basement block faulting; (2) domes from tectonic salt pillows 

or other halokinetic deformation; (3) combined structural 

traps such as salt-assisted fault block traps; (4) combined 

structural/stratigraphic (facies) traps (Alsharhan and Nairn, 

1997). Major trap formation and modification of the Arabian 

Sub-Basin Tuwaiq/Hanifa-Arab TPS are a result of the First 

(Early) and Second (Late) Alpine Orogenic Events of Oman 

(figs. 1 and 31). The Early Alpine Orogeny during the Late 

Cretaceous was associated with the collision event that led to 

the emplacement of the Semail Ophiolite Complex in Oman, 

and the Late Alpine Orogeny during the middle to late Tertiary 

was associated with the opening of the Red Sea and collision 

of Arabia and Eurasia (Wender and others, 1998).
Assessment Unit Description,

Geologic Models, and 

Assessment Results

Central Arabia Qusaiba-Paleozoic TPS

The Central Arabia Qusaiba-Paleozoic TPS is divided 

into two assessment units: (1) a southern, onshore unit is 

called the Central Arch Horst-Block Anticlinal Oil and Gas 

AU (20210101); (2) the North Gulf Salt Basin Structural Gas 

AU (20210102) encompasses the northeast half of the TPS 

that is underlain by the Hormuz Salt (figs. 3 and 15). 

Central Arch Horst-Block Anticlinal 

Oil and Gas AU (20210101)

In the geologic model for the Central Arch Horst-Block 

Anticlinal Oil and Gas Assessment Unit, hydrocarbons 

are sourced by the organic-rich basal shale of the Qusaiba 

Formation and produced from sandstone reservoirs. The 

primary reservoirs are eolian and fluvial sandstones of the 

Lower Permian Unayzah Formation and shallow marine shelf 

sandstones of the Devonian Jauf Formation; some production 

also comes from Ordovician sandstones in the northern and 

western portion of the Central Arch Horst-Block Anticlinal Oil 

and Gas AU. Light sweet oils with high (44°–53°) API gravities and non-associated gas are produced in the central Arabian 

fields (fig. 19) along the western portion of the assessment 

unit and on the Central Arabian Arch. In the western area of 

the assessment unit, gas and mature oils migrated westward 

and updip from a more thermally mature eastern source area 

to the south of Ghawar (figs. 25 and 26). Gas is also produced 

in several fields in horst-block anticlines within the assessment unit, particularly at Ghawar and surrounding structures. 

The primary regional seal, the Permian Khuff Formation, is a 

combination of shale, tight carbonate rocks, and anhydrite.

The geologic model includes multiple styles of trap 

formation as follows: (1) a north-south structural grain where 

anticlines formed by sediments draping over reactivated basement horst blocks (fig. 39); (2) in the central Arabian fields, 

wrench faulting and associated drape- and drag-structures; and 

(3) stratigraphic pinch-out traps in Unayzah sandstones along 

the western margin of the assessment unit.

Characteristics of the discovered and undiscovered 

fields of the Central Arch Horst-Block Anticlinal Oil and Gas 

AU are shown in the input data form of Appendix 1; assessment results for the Central Arch Horst-Block Anticlinal Oil 

and Gas AU are summarized in table 1. Allocations of undiscovered resources to provinces, countries, and onshore or 

offshore areas are reported in U.S. Geological Survey World 

Energy Assessment Team (2000). Details on the USGS data 

input sheets and assessment model and methodology are 

described in Schmoker and Klett (2000). A summary of 

historic exploration and production data of known and grown 

volumes for fields of the Central Arch Horst-Block Anticlinal Oil and Gas AU is shown in figures 40 through 42 and in 

table 2; additional graphs and tables for this assessment unit 

are found in U.S. Geological Survey World Energy Assessment Team (2000).

Since the first discoveries in 1973, through the last 

discovery reported in the Petroconsultants (1996a) database 

to 1995, 14 oil fields and 4 gas fields of minimum size (>20 

MMBO and 120 BCFG, respectively) constitute the total 

known discoveries within the assessment unit (Appendix 1 and 

table 2). Cumulative known oil volume and gas volume from 

the 14 oil fields and 4 gas fields are about 6.2 BBO and 12.1 

TCF of gas (table 2); however, cumulative grown volumes 

are estimated at nearly 12.6 BBO and 25.8 TCF (table 2), 

respectively. The largest oil field in the assessment unit has an 

estimated known volume of about 2 BBO and a grown volume 

of nearly 4 BBO (fig. 40). The range in known volume size 

of the remaining 13 oil fields is between about 70 MMBO 

and 600 MMBO, and the corresponding range in grown size 

volumes between about 90 MMBO and 1.5 BBO, respectively 

(fig. 40). The largest discovered gas field has a known gas 

volume of about 750 BCF and grown gas volume of about 2.4 

TCF (fig. 41); the smallest of the four discovered gas fields 

has a known gas volume of about 300 BCF and a corresponding grown volume of about 1 TCF (fig. 41). 

The historical exploration data of figure 42 show that 

of the 18 new-field wildcats reported in Petroconsultants 

(1996a), 14 were drilled in a 6-year period from 1989 to 

1995. During that 6-year period, 10 oil fields and 4 gas 

fields greater than the minimum size (totaling 14) were discovered (fig. 42), which results in an apparent success ratio 

of 1.0. The surge in exploration and consequent new-field 

discoveries reflects a new play concept and resulting discoveries of oil and gas fields in central Saudi Arabia (fig. 19); 

the high apparent success in exploration was probably guided 

by 3-D seismic surveys.

The input data for assessment of the Central Arch HorstBlock Anticlinal Oil and Gas AU are shown in Appendix 1. 

For this assessment unit, a minimum field size of 20 MMBO 

and the equivalent 120 BCFG was used for undiscovered oil 

and gas fields, respectively. This specific minimum field 

size was determined after reviewing the historical data and 

exploration trends for the region and represents an estimated 

minimum economic field size over the assessment forecast 

period of 30 years.

The historic production data indicate that the median size 

of grown oil fields has changed through time, as displayed 

in discovery thirds on the input data sheet (first page of data 

form, Appendix 1 and table 2). The median size of grown oil 

fields changed from 760 MMBO for the first five fields (first 

discovery third), to 976 MMBO for the second five discovered 

oil fields (second discovery third), to 539 MMBO for the four 

oil fields respresenting the last discovery third (table 2). This 

assessment estimates a median grown size for undiscovered 

oil fields of 100 MMBO for the Central Arch Horst-Block 

Assessment Unit Description, Geologic Models, and Assessment Results 57
58 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Figure 39. General structural trends of Greater Ghawar Uplift and surrounding area, showing primary north-south direction of 

basement and secondary trend due to Najd Fault system. Note how many of the major oil fields align with structures. Modified 

from Al Khatieb and Norman (1982) and Edgell (1992). 

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Figure 39. General structural trends of Greater Ghawar Uplift and surrounding area showing primary

north-south direction of basement and secondary trend due to Najd fault system. Note how many of the

major oil fields align with structures. Modified from Al Khatieb and Norman (1982) and Edgell (1992).
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60 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Figure 40. Plots of A, known oil-field size, and B, grown oil-field size versus field discovery year for Central Arch Horst-Block 

Anticlinal Oil and Gas Assessment Unit (20210101). Data derived and modified from Petroconsultants (1996a, b). MMBO, million 

barrels of oil.

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�� Figure 40. Plots of A, known oil-field size, and B, grown oil-field size versus field discovery year for

Central Arch/Horst-Block Anticlinal Oil and Gas Assessment Unit (20210101). Data derived and

modified from Petroconsultants (1996a, b).

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Assessment Unit Description, Geologic Models, and Assessment Results 61

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Figure 41. Plots of A, known gas-field size versus field discovery year and B, grown gas-field size versus

cumulative (CUM.) number (No.) of new-field wildcat wells for Central Arch/Horst-Block Anticlinal Oil

and Gas Assessment Unit (20210101). Data derived and modified from Petroconsultants (1996a, b).

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Figure 41. Plots of A, known gas-field size versus field discovery year, and B, grown gas-field size versus cumulative (CUM.) number (No.) of new-field wildcat wells for Central Arch Horst-Block Anticlinal Oil and Gas Assessment Unit (20210101). Data derived 

and modified from Petroconsultants (1996a, b). BCFG, billion cubic feet of gas.
62 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

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Figure 42. Historical exploration plots for Central Arch Horst-Block Anticlinal Oil and Gas Assessment

Unit (20210101). A, Number (No.) of new-field wildcat wells versus drilling completion year; B,

Cumulative (CUM.) number of oil fields versus field discovery year; C, Cumulative number of gas fields

versus field discovery year. Data derived and modified from Petrolconsultants (1996a, b).
Anticlinal Oil and Gas AU (Appendix 1). The median field 

size of undiscovered fields in the assessment unit is generally 

expected to decrease with time, as is the case for most basins 

worldwide.

For the minimum number of oil fields, this assessment 

estimates that at least 15 oil fields greater than minimum 

size would be discovered in the assessment unit (Appendix 

1). Although only 14 oil fields of minimum size have been 

discovered through 1999, much opportunity for exploration 

remains for reservoirs outside of the main trend. It is estimated here that the median number of oil fields to be discovered in the assessment unit, at the minimum size, over the 

next 30 years is 90 fields, with a maximum of 180 fields to be 

discovered (Appendix 1).

Co-product ratios, such as the gas/oil ratio (GOR) and the 

natural gas liquids (NGL)/gas ratio (LGR) for oil fields, are 

important because the USGS methodology uses these ratios 

to calculate gas in oil fields and NGL in oil fields. These coproduct ratios are critical and can have significant implications 

for the economic viability of fields, especially small fields. 

The co-product ratios are given in Appendix 1 for the Central 

Arch Horst-Block Anticlinal Oil and Gas AU. Other ancillary 

data, such as API gravity, sulfur content, drilling depths, and 

water depth are also shown on the input form (Appendix 1).

Gas fields were assessed in a similar manner as oil fields. 

Only four gas fields of minimum size have been discovered 

over the period from 1990 to 1995; therefore, historical 

exploration data are limited in both time and number. Median 

grown field size for the four gas fields is 2,033 BCFG (table 

2). This assessment anticipates a median size for undiscovered gas fields of 700 BCFG, and at least 20 fields of minimum size will be discovered for the Central Arch Horst-Block 

Anticlinal Oil and Gas AU (Appendix 1). Estimated median 

number of gas fields to be discovered in the assessment unit, 

at the minimum size over the next 30 years, is 120 fields, 

with a maximum of 220 fields to be discovered (Appendix 

1). Recent reports show that at least four additional new gas 

fields (Niban, Shaden, Manjurah, and South Tinat) have been 

discovered within the Greater Ghawar Uplift Province (2021), 

and within the Central Arch Horst-Block Anticlinal Oil and 

Gas AU, subsequent to completion of the study by the U.S. 

Geological Survey World Energy Assessment Team (2000). 

(See Gulf PetroLink, 1999; Alhajji, 2000; Weekly Petroleum 

Argus, 2000.) Preliminary estimates of the cumulative known 

reserves for two of these newly discovered gas/condensate 

fields (Niban and Shaden) are about 4 TCFG and 6 BBNGL.

A Monte Carlo simulation (Charpentier and Klett, 2000) 

provided the following results for the Central Arch HorstBlock Anticlinal Oil and Gas AU (table 1). Oil in undiscovered oil fields ranges from an F95 (95 percent chance) of 

7.3 BBO to an F5 (5 percent chance) of 32.8 BBO, with a 

mean volume of undiscovered oil of 19.2 BBO. In addition, 

the largest expected undiscovered oil field, at the mean, was 

calculated at about 2.1 BBO. Similarly, the results for undiscovered non-associated gas ranges from an F95 of about 79.5 

TCF to an F5 of 333.0 TCF, with a mean volume of undiscovered gas in gas fields of about 201.6 TCF (table 1). The 

largest expected undiscovered gas field, at the mean, is about 

22.2 TCF. The co-product ratios (Appendix 1) were used to 

calculate a range of associated gas in undiscovered oil fields 

from 10.6 TCF (F95) to 51.1 TCF (F5), with a mean volume 

of associated gas of 28.8 TCF in undiscovered oil fields. The 

volume of NGL in oil fields was calculated in the range from 

586 MMBNGL (F95) to 3.3 BBNGL (F5), with a mean NGL 

volume of 1.7 BBNGL in undiscovered oil fields (table 1).

In summary, a mean undiscovered volume of 19.2 BBO 

in conventional oil fields is anticipated for the Central Arch 

Horst-Block Anticlinal Oil and Gas AU (table 1). A total of 

about 12.6 BBO (grown) in oil fields has already been discovered (table 2), thus about 40 percent of the oil has been discovered in this assessment unit. In contrast, a mean undiscovered 

volume of about 201.6 TCF of gas in gas fields was estimated 

for the assessment (table 1). About 7.4 TCF of gas in gas 

fields was calculated as discovered grown reserves (table 2), 

suggesting that less than 4 percent of the gas in gas fields has 

been discovered in the Central Arch Horst-Block Anticlinal 

Oil and Gas AU. The largest undiscovered gas field estimated 

at the mean is about 22.2 TCF (table 1), an order of magnitude 

larger than the grown reserve volume in any of the discovered 

gas fields from the historical data. Although the discovered 

grown gas volume is minimal (4 percent) compared to the 

mean undiscovered volume (96 percent), large volumes of 

Silurian-sourced non-associated gas reserves are known to 

underlie the supergiant Jurassic oil fields, particularly Ghawar field. These gas volumes are considered to be reserves 

from field growth and not included as separate Paleozoic new 

gas-field discoveries. This is especially critical because the 

assessment process must not double-count fields when the area 

assessed contains stacked total petroleum systems.

In summary, we consider that gas exploration within the 

Central Arch Horst-Block Anticlinal Oil and Gas AU is at an 

immature stage, and that great potential remains particularly 

for new-field discoveries of Silurian-sourced gas in Paleozoic 

reservoirs over the next 30 years in block- and wrench-faulted 

structural traps in central Arabia. Also, discoveries of Paleozoic gas fields have been reported subsequent to the completion of the U.S. Geological Survey World Petroleum Assessment 2000. These newly discovered gas fields are in adjacent 

structures west and south of Ghawar field (Gulf PetroLink, 

1999; Alhajji, 2000; Weekly Petroleum Argus, 2000). Numerous discoveries of large oil fields are also expected from this 

Figure 42 (preceding page). Historical exploration plots for 

Central Arch Horst-Block Anticlinal Oil and Gas Assessment Unit 

(20210101). A, Number (No.) of new-field wildcat wells versus 

drilling completion year; B, Cumulative (CUM.) number of oil fields 

versus field discovery year; C, Cumulative number of gas fields 

versus field discovery year. Data derived and modified from Petroconsultants (1996a, b).

Assessment Unit Description, Geologic Models, and Assessment Results1 63
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������ ������� ������� �� ���� ����� ������� ����� ���� �� ���� ������� ������� ������� �� ������� ��� �������� ������ ���������� ���� ���� � ���� �� ��� ������ �� � ������������� �� ��� ����������� ������ ���� ���������� �� ��� �� ��� �� ��� ����� ������ ������� �������� ��������� ����� ���� ��� ��������� ��� ����� ���� �� ����� ����� ���� ���� �� ������� �� ����� ��� ���������� ��� �� ����� ��� ������� ����� ���� ��� ����� �� �������� ���������� ������ ��� ��� �� ����� �� ��� ���� �� ��� ��������� ������ ��������������� �������� Known (Discovered) Volumes Grown (Discovered) Volu

Field Type Number Number of Fields Oil (MMBO) Gas (BCFG) NGL (MMBNGL) of Fields Oil (MMBO) Gas (BC

Oil Fields 14 6,226 9,815 170 14 12,619 1

Gas Fields 4 0 2,300 173 4 0 

Fields <1 MMBOE 0 0 0 0 0 0 

All Fields 18 6,226 12,115 343 18 12,619 25

Discovery-history sequence Known and grown volumes of petroleum Discovery-History Sequence - Grown (Discovered) Volumes Field Type Year Number of Total Mean M

(End of Period) Fields Volume Size 

Oil Fields Grown Sizes (MMBO) First third 1973-1989 5 3,010 602 

Second third 1990 5 6,727 1,345 Third third 1995 4 2,882 720 All Oil Fields 14 12,619 901 

Gas Fields Grown Sizes (BCFG)

First half 1990-1994 2 3,382 1,691 Second half 1995 2 4,066 2,033 All Gas Fields 4 7,448 1,862 
assessment in less thermally mature areas within the TPS 

boundary and in wrench-faulted structural traps and stratigraphic pinch-out traps along the western flank of the basin. 

These areas for potential new discoveries are (1) to the west of 

Ghawar field and in the southernmost portion of the Widyan 

Basin-Interior Platform Province and Interior Homocline-Central Arch Province, and (2) to the south of Ghawar in a small 

northern portion of the Rub ‘al Khali Basin Province (fig. 15).

North Gulf Salt Basin Structural Gas AU 

(20210102)

The North Gulf Salt Basin Structural Gas Assessment 

Unit is mostly in the northern Gulf offshore and within USGS 

Province 2023 (Mesopotamian Foredeep). In the geologic 

model for the North Gulf Salt Basin Structural Gas AU, 

hydrocarbons accumulated in structural traps that are mainly 

domes over salt diapirs and salt-assisted or salt-enhanced 

horst-block anticlines. In the North Gulf Salt Basin Structural 

Gas AU, the Qusaiba basal hot shale is primarily in the main 

zone of gas generation. Reservoirs consist mostly of cyclic 

grainstones and dolomitic shelf carbonate rocks of the Upper 

Permian Khuff Formation, with production controlled mainly 

by distribution and amount of anhydrite. Some fields in the 

assessment unit produce sour gas and other non-hydrocarbon 

gases. Many of the traps forming the fields of this assessment 

unit were created during post-Hercynian tectonic events, particularly during major uplift and erosion associated with the 

Late Cretaceous First Alpine Orogeny about 80 Ma (Loosveld 

and others, 1996).

Characteristics of the discovered and undiscovered fields 

of the North Gulf Salt Basin Structural Gas AU are shown in 

the input data form of Appendix 2; assessment results are summarized in table 1. Only two known gas fields are assigned to 

the North Gulf Salt Basin Structural Gas AU: G-Structure and 

B-Structure gas fields in the northern Gulf offshore portion 

of Iran; these fields are indicated by the red dots in figure 15. 

Both fields were discovered in 1966; they produce gas from 

the Khuff Formation. B-Structure gas field has an estimated 

recoverable reserve of 50 TCF of gas (8.3 BBOE; Alsharhan 

and Nairn, 1997); median field size calculated from the two 

fields is 17.0 TCF.

For undiscovered gas fields, the following sizes of grown 

fields were assigned: (1) a minimum field size of 120 BCFG 

(20 MMBOE); (2) a maximum field size of 60 TCF; and (3) 

a median size of 800 BCFG (Appendix 2). The number of 

undiscovered fields at the minimum field size was estimated 

as follows: a minimum of 20, median of 75, and maximum of 

150 (Appendix 2). A Monte Carlo simulation provided the 

following results for the North Gulf Salt Basin Structural Gas 

AU: undiscovered non-associated gas ranges from an F95 of 

about 62.4 TCF to an F5 of 266.5 TCF, with a mean volume 

of undiscovered gas in gas fields of about 153.0 TCF (table 

1). The largest expected undiscovered gas field at the mean 

was calculated at about 22.6 TCF. Using the liquids to gas 

ratio (Appendix 2), the volume of NGL in undiscovered gas 

fields was calculated to range from about 2.5 BBNGL (F95) to 

12.6 BBNGL (F5), with a mean undiscovered volume of NGL 

of about 6.7 BBNGL (table 1). In summary, this assessment 

expects several large gas fields to be discovered during the 

next 30 years, most within the boundaries of Iran in the North 

Gulf offshore portion of the assessment unit, and within saltrelated structural traps.

Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS

The Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS, outlined in figure 30, is divided into two assessment units: (1) the 

Horst-Block Anticlinal Oil AU (20210201), and (2) the SaltInvolved Structural Oil AU (20210202).

Horst-Block Anticlinal Oil AU (20210201)

The Horst-Block Anticlinal Oil AU encompasses the 

onshore portion of the Arabian Sub-Basin Tuwaiq/HanifaArab TPS and is characterized by a primary north-south 

structural grain formed by the draping of sediments over 

reactivated basement fault blocks (fig. 39). These north-south 

structural features include the En Nala, Khurais-Burgan, and 

Maqalah anticlines (fig. 3). Jurassic fields within this assessment unit are Ghawar, Abqaiq, Khurais, Dhib, Bakr, El Haba, 

Suban, Jaladi, Jaham, Faridah, Lughfah, and Jawb fields, 

among several others (fig. 32).

Sourced by the Jurassic Tuwaiq Mountain and Hanifa 

Formations, mature oils averaging about 35°API gravity are 

produced from onshore central Arabian fields that accumulated mostly in cyclic, shallow-water, porous carbonate grainstones and packstones of the Upper Jurassic Arab Formation, 

particularly the Arab D reservoir.

Characteristics of the discovered and undiscovered fields 

of the Horst-Block Anticlinal Oil AU are shown in the input 

data form of Appendix 3; assessment results for undiscovered 

fields are summarized in table 3. A summary of historical 

exploration and production data of known and grown volumes 

for fields of the Horst-Block Anticlinal Oil AU is shown in 

figures 43 and 44 and in table 4; additional graphs and tables 

for this assessment unit are found in U.S. Geological Survey 

World Energy Assessment Team (2000).

Since the first discovery in 1940, through the last discovery in 1984, as reported in the Petroconsultants (1996a) database, 25 oil and no gas fields of minimum size (>20 MMBO 

and 120 BCFG, respectively) constitute the total known discoveries within the assessment unit (Appendix 3 and table 4). 

Cumulative known oil volume and gas volume from the 25 oil 

fields are about 155.1 BBO and 229.6 TCF, respectively, and 

cumulative grown volume for the assessment unit is estimated 

at nearly 196.6 BBO of oil and 286.8 TCF of gas (table 4). 

The largest discovered oil field in the Horst-Block Anticlinal 

Oil AU has an estimated known volume of about 110 BBO, 

and a grown volume of about 140 BBO (fig. 43). This oil 

Assessment Unit Description, Geologic Models, and Assessment Results 65
66 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Figure 43. Plots of A, known oil-field size, and B, grown oil-field size versus field discovery year for Horst-Block Anticlinal Oil 

Assessment Unit (20210201) of Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System. Data derived and modified from 

Petroconsultants (1996a, b). MMBO, million barrels of oil.

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Figure 43. Plots of A, known oil field size and B, grown oil field size versus field discovery year

for Horst-Block Anticlinal Oil Assessment Unit (20210201) of Arabian Sub-Basin

Tuwaiq/Hanifa-Arab Total Petroleum System. Data derived and modified from Petroconsultants (1996a, b).

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68 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

field of such great resource volume is Ghawar field of Saudi 

Arabia. The known volume size range of the remaining 24 oil 

fields is between about 90 MMBO and 15 BBO with a median 

known field size of 1.5 BBO (fig. 43).

The data for new-field wildcat wells in this assessment 

unit show that of the 35 new-field wildcats reported, 28 were 

drilled between 1963 and 1984 (fig. 44), during which 21 of 

the 25 oil fields greater than the minimum size were discovered. The data in figure 44 and figure 43 also suggest that the 

last new-field wildcat well was in 1984 when the last Jurassic 

oil field of the Horst-Block Anticlinal Oil AU was discovered.

The historical production data demonstrate a median 

grown size of oil fields in the assessment unit in discovery 

thirds as follows: first third (1940-1971, eight fields) is 1,980 

MMBO; second third (1978, nine fields) is 973 MMBO, and 

third third (1984, eight fields) is 1,150 MMBO (table 4). The 

median size for undiscovered oil fields is estimated at 100 

MMBO for the Horst-Block Anticlinal Oil AU (Appendix 3).

A median number of 120 undiscovered oil fields greater 

than minimum size is estimated for the assessment unit 

(Appendix 3). Although only 25 oil fields of minimum size 

have been discovered to date, these fields are comparatively 

very large. At a minimum size of 20 MMBO, this assessment 

predicts that numerous fields will be discovered over the next 

30 years within the assessment unit. The minimum number of 

undiscovered fields is 25, with a maximum number estimated 

at 215 fields. The maximum field size for undiscovered oil 

fields was estimated at 6 billion barrels (Appendix 3).

Monte Carlo simulation provided the following results 

for the Horst-Block Anticlinal Oil AU (table 3). Oil in undiscovered oil fields ranges from an F95 of about 11.3 BBO to an 

F5 of about 43.2 BBO, with a mean volume of undiscovered 

oil of 26.7 BBO. In addition, the expected largest undiscovered oil field at the mean was calculated at about 2.7 BBO. 

Associated gas in undiscovered oil fields ranges from about 

6.6 TCF (F95) to 27.0 TCF (F5), with a mean volume of associated gas of 16.1 TCF (table 3).

Mean volume of undiscovered oil in oil fields for the 

Horst-Block Anticlinal Oil AU is about 26.7 BBO (table 3). 

In terms of grown oil volume, about 88 percent of the oil has 

been discovered in this assessment unit. This percentage 

of discovered volume is somewhat skewed to the high end 

because about two-thirds of the total grown oil volume (grown 

discovered reserves plus undiscovered) is in Ghawar field.

In summary, this assessment predicts a good potential 

for numerous discoveries of moderate-size oil fields within 

the Horst-Block Anticlinal Oil AU in block-faulted structures 

to the south and west of Ghawar field. New-field discoveries 

within the assessment unit are predicted: (1) at the south end 

of the Greater Ghawar Uplift Province, (2) in the southeastern 

portion of the Interior Homocline-Central Arch Province, and 

(3) in a small area along the northwest flank of Rub ‘al Khali 

Basin Province immediately south of Ghawar (fig. 30).

Salt-Involved Structural Oil AU (20210202)

A second assessment unit, the Salt-Involved Structural 

Oil AU, encompasses the north half of the Arabian SubBasin Tuwaiq/Hanifa-Arab TPS that is underlain by the 

Infracambrian Hormuz Salt (fig. 3). The geologic model for 

this assessment unit thus describes an area in which halokinetic structures are the primary traps for hydrocarbons; most 

structures are salt domes, salt diapirs, and salt-assisted or 

salt-enhanced horst-block anticlines. Characteristics of the 

discovered and undiscovered fields of the Salt-Involved Structural Oil AU are shown in the input data form of Appendix 

4; assessment results are summarized in table 3. A summary 

of historical exploration and production data of known and 

grown volumes for fields of the Salt-Involved Structural Oil 

AU is given in table 5 and plotted in figure 45 and figure 46.

Through 1995, the Petroconsultants (1996a) database 

suggests that, since the first discovery in 1938 through the last 

discovery in 1978, 12 oil fields and no gas fields of minimum 

size constitute the total known discoveries within the assessment unit (table 5). Cumulative known oil volume and gas 

volume from the 12 oil fields are about 43.8 BBO and 45.7 

TCF, respectively. Equivalent cumulative grown volume for 

the assessment unit is estimated at about 56.1 BBO and 57.4 

TCF of gas (table 5). The largest discovered oil field in the 

assessment unit, Berri field, has an estimated known volume 

of about 12–13 BBO and a grown volume of about 15–16 

BBO (fig. 45). The range in size based on known volume for 

the 12 oil fields is between about 200 MMBO and 13 BBO 

(fig. 45); the median grown field size of all discovered fields 

is about 2.0 BBO (table 5).

The historical exploration and production data for new 

field wildcat wells in this assessment unit show that of the 47 

new-field wildcats reported in the Petroconsultants (1996a) 

database, 36 were drilled between 1963 and 1994 (fig. 46), 

during which 7 of the 12 oil fields greater than the minimum 

size were discovered (fig. 45). The new-field wildcat data 

in figure 46 suggest that the latest surge of exploration was 

between 1987 and 1994, during which time no new Jurassic 

oil field of minimum size (fig. 45) was discovered in the SaltInvolved Structural Oil AU.

From historical production data, we calculate a median 

grown size of oil fields in the assessment unit, in terms of 

discovery halves, as follows: first half (1938-1963, six fields) 

of 5,471 MMBO; and second half (1978, six fields), of 1,008 

MMBO (table 5). The estimated median size for undiscovered 

oil fields is 150 MMBO for the Salt-Involved Structural Oil 

AU (Appendix 4).

A median of 50 undiscovered oil fields greater than 

minimum size was estimated in the assessment unit (Appendix 

4). Although only 12 oil fields of minimum size have been 

discovered to the present time, these discovered fields are 

comparatively very large. At a minimum size of 20 MMBO, 

this assessment expects that several fields within the assessment unit will be discovered during the next 30 years. The 

minimum number of undiscovered fields predicted is 10; the 

maximum number of undiscovered fields is estimated at 100. 

The maximum field size for undiscovered oil fields was estimated at 6 billion barrels (Appendix 4). 

The Monte Carlo simulation provided the following 

assessment results for the Salt-Involved Structural Oil AU 
Figure 44. Plots of A, number (No.) of new-field wildcat wells versus drilling completion year, and B, cumulative (CUM.) number 

of new-field wildcat wells versus drilling completion year for Horst-Block Anticlinal Assessment Unit (20210201). Data derived and 

modified from Petroconsultants (1996a, b).

Assessment Unit Description, Geologic Models, and Assessment Results 69

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Figure 44. Plots of A, number (No.) of new-field wildcat wells versus drilling completion year, and

B, cumulative (CUM.) number of new-field wildcat wells versus drilling completion year for Horst-Block

Anticlinal Assessment Unit (20210201). Data derived and modified from Petroconsultants (1996a, b).

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Discovery-History Sequence - Grown (Discovered) Volumes Field Type Year Number of Total Mean 

(End of Period) Fields Volume Size 

Oil Fields Grown Sizes (MMBO) First third 1940-1971 8 177,779 22,222 

Second third 1978 9 8,991 999 Third third 1984 8 9,815 1,227 All Oil Fields 25 196,585 7,863 

Gas Fields Grown Sizes (BCFG)

First third NA NA NA NA Second third NA NA NA NA Third third NA NA NA NA All Gas Fields NA NA NA 

Known (Discovered) Volumes Grown (Discovered) Volum

Field Type Number Number

of Fields Oil (MMBO) Gas (BCFG) NGL (MMBNGL) of Fields Oil (MMBO) Gas (BCF

Oil Fields 25 155,145 229,615 8,400 25 196,585 286

Gas Fields 0 0 0 0 0 0 

Fields <1 MMBOE 0 0 0 0 0 0 

All Fields 25 155,145 229,615 8,400 25 196,585 286

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Discovery-History SequenceKnown and Grown Discovered Volumes
Figure 45. Plots of A, known oil-field size versus field discovery year, and B, grown oil-field size versus field discovery year for 

Salt-Involved Structural Oil Assessment Unit (20210202) of Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total Petroleum System. Data 

derived and modified from Petroconsultants (1996a, b). MMBO, million barrels of oil.

Assessment Unit Description, Geologic Models, and Assessment Results 71

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Figure 45. Plots of A, known oil-field size versus field-discovery year, and B, grown oil-field size versus

field discovery year for Salt-Involved Structural Oil Assessment Unit of the Arabian Sub-Basin

Tuwaiq/Hanifa-Arab Total Petroleum System. Data derived and modified from Petrolconsultants (1996a, b).

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72 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

(table 3). Oil in undiscovered oil fields ranges from an F95 

of about 5.7 BBO to an F5 of about 26.2 BBO, with a mean 

volume of undiscovered oil of about 15 BBO. The largest 

expected undiscovered oil field at the mean was calculated 

at about 2.2 BBO. Associated gas in undiscovered oil fields 

ranges from about 6.7 TCF (F95) to about 32.0 TCF (F5), with 

a mean volume of associated gas of about 18 TCF (table 3).

At the mean, about 79 percent (15 BBO undiscovered 

versus 56.1 BBO discovered) of the oil in oil fields has been 

discovered in the Salt-Involved Structural Oil AU. In summary, we predict good potential for large, new oil-field discoveries in salt-related structures in the northeast offshore Gulf 

portion of the Salt-Involved Structural Oil AU that are mostly 

within the borders of Iran.

Summary

The sequence stratigraphic, diagenetic, and tectonic 

histories of the Paleozoic and Jurassic sequence of the eastern 

Arabian Peninsula produced an exceptional combination of 

geologic elements and conditions favorable for petroleum 

formation, migration, and accumulation. These exceptional 

elements and conditions include (1) extensive geographic 

distribution of rich, mature source rocks, high-quality reservoir rocks, and highly efficient seal rocks and (2) the formation of large structural traps during or subsequent to peak oil 

and gas generation. These exceptional Paleozoic and Jurassic 

petroleum system elements combine to form one of the most 

prolific hydrocarbon-producing areas in the world.

The two total petroleum systems in central Arabia that 

are described here, the Central Arabia Qusaiba-Paleozoic TPS 

and the Jurassic Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS, 

are a more local part of the greater Paleozoic and Jurassic 

hydrocarbon systems of the eastern Arabian Peninsula. Both 

the Central Arabia Qusaiba-Paleozoic TPS and the Arabian 

Sub-Basin Tuwaiq/Hanifa-Arab TPS encompass the Greater 

Ghawar Uplift Province (USGS Province 2021) and portions 

of surrounding geologic provinces within Saudi Arabia, western Qatar, Bahrain, and the offshore northern Gulf portions of 

southern Iran along the Zagros Fold Belt.

Structures within these two total petroleum systems are 

unusually large, gentle anticlines and, mostly in the offshore, 

salt domes that were formed from reactivated basement fault 

blocks, halokinesis, or a combination of the two processes. 

Most of these structures were initially formed during the Hercynian tectonic event, during which the Arabian Plate underwent multiple phases of compression from the Late Devonian 

to the Early Carboniferous. Three post-Jurassic tectonic 

events are responsible for the formation and modification 

of structures and traps that consequently created oil and gas 

fields of such great magnitude: (1) Early Zagros rifting during 

the Early Triassic; (2) the First Alpine Orogeny during the 

Late Cretaceous; (3) the Second Alpine Orogeny in the middle 

to late Tertiary.

Hydrocarbons of the Central Arabia Qusaiba-Paleozoic 

TPS are sourced mainly by organic-rich hot shale that occurs 

in the basal part of the Lower Silurian Qusaiba Member of 

the Qalibah Formation. The Qusaiba source rock was thermally mature by the Late Jurassic in the deepest parts of the 

sedimentary basin in central Arabia; hydrocarbon expulsion 

began in the Early Cretaceous about 120 Ma. Oil and gas are 

produced from fluvial and eolian sandstones of the Permian 

Unayzah Formation and porous shallow marine sandstones of 

the Devonian Jauf Formation in the central and western parts 

of the Central Arabia Qusaiba-Paleozoic TPS. Oil and gas 

produced from the central Arabian fields and along the Central 

Arabian Arch were generated from the Silurian Qusaiba in an 

eastern, more mature part of the basin, and migrated westward 

and updip into the wrench-faulted structures. In the northern 

Gulf portion of the Central Arabia Qusaiba-Paleozoic TPS, 

basal transgressive marine sandstones and cyclic, dolomitic 

shelf carbonates of the Late Permian Khuff Formation produce 

gas and condensate; some sour gas and other non-hydrocarbon 

gases are also produced from these Khuff reservoirs.

The two assessment units (AU) recognized in the Central 

Arabia Qusaiba-Paleozoic TPS are related to structure type 

and presence of underlying Infracambrian salt: (1) an onshore 

Central Arch Horst-Block Anticlinal Oil and Gas AU, and 

(2) a mostly offshore, North Gulf Salt Basin Structural Gas 

AU. Mean volumes of undiscovered, conventional petroleum 

resources in the Central Arch Horst-Block Anticlinal Oil and 

Gas AU are estimated at about 19 BBO in oil fields, more than 

200 TCF of gas in gas fields, about 29 TCF of associated gas, 

and a total of nearly 18 BBNGL. Mean volume estimates for 

undiscovered gas and NGL in gas fields for the offshore North 

Gulf Salt Basin Structural Gas AU are about 153 TCF and 7 

BBNGL, respectively. The mean total volume of undiscovered, conventional petroleum resource for the Central Arabia 

Qusaiba-Paleozoic TPS is estimated at about 108 BBOE.

Oil of the Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS 

is sourced by organic-rich marine carbonates of the Jurassic 

Tuwaiq Mountain and Hanifa Formations that were deposited in one of three intraplatform basins during the Jurassic 

and form a superfamily of oils with distinctive geochemical 

characteristics. Oils were generated and expelled from these 

source rocks beginning in the Cretaceous. Production is from 

cyclic carbonate-rock reservoirs of the Arab Formation in 

several giant and supergiant fields and including Ghawar field, 

Saudi Arabia.

The two assessment units recognized for the Arabian 

Sub-Basin Tuwaiq/Hanifa-Arab TPS are similarly related 

to structural style and presence of underlying Infracambrian 

salt: (1) an onshore Horst-Block Anticlinal Oil AU, and (2) 

a mostly offshore, Salt-Involved Structural Oil AU. Mean 

undiscovered, conventional petroleum resources in the HorstBlock Anticlinal Oil AU are estimated at about 27 BBO in 

oil fields, about 16 TCF of associated gas, and a total of 642 

MMBNGL. The mean volume estimate for undiscovered oil 

in oil fields for the offshore Salt-Involved Structural Oil AU 

is about 15 BBO; mean undiscovered associated gas and NGL 
Figure 46. Plots of A, number (No.) of new-field wildcat wells versus drilling completion year, and B, cumulative (CUM.) number 

of new-field wildcat wells versus drilling completion year for Salt-Involved Structural Oil Assessment Unit (20210202), Arabian SubBasin Tuwaiq/Hanifa-Arab Total Petroleum System. Data derived and modified from Petroconsultants (1996a, b).

Summary 73

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Figure 46. Plots of A, number (No.) of new-field wildcat wells versus drilling completion year, and

B, cumulative (CUM.) number of new-field wildcat wells versus drilling completion year for Salt-Involved

Structural Oil Assessment Unit (20210202), Arabian Sub-basin Tuwaiq/Hanifa-Arab Total Petroleum

System. Data derrived and modified from Petroconsultants (1996a, b).

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Discovery-History Sequence Known and Grown Discovered Volumes Discovery-History Sequence - Grown (Discovered) Volumes Field Type Year Number of Total Mean 

(End of Period) Fields Volume Size 

Oil Fields Grown Sizes (MMBO) First half 1938-1963 6 35,886 5,981 

Second half 1978 6 20,175 3,363 All Oil Fields 12 56,061 4,672 

Gas Fields Grown Sizes (BCFG)

First third NA NA NA NA Second third NA NA NA NA Third third NA NA NA NA All Gas Fields NA NA NA 

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

Known (Discovered) Volumes Grown (Discovered) Volu

Field Type Number Number

of Fields Oil (MMBO) Gas (BCFG) NGL (MMBNGL) of Fields Oil (MMBO) Gas (BC

Oil Fields 12 43,850 45,680 805 12 56,061 5

Gas Fields 0 0 0 0 0 0 

Fields <1 MMBOE 0 0 0 0 0 0 

All Fields 12 43,850 45,680 805 12 56,061 5

����� �� ����� ��� ����� ���������� ������� ��� ����������������� �������� ��� ������������� ���������� ��� ���������� ���� �����������
volumes in the assessment unit are estimated at about 18 TCF 

and 719 MMBNGL, respectively. The mean total volume of 

undiscovered, unconventional petroleum resource for the Arabian Sub-Basin Tuwaiq/Hanifa-Arab TPS is about 49 BBOE.

In summary, the U.S. Geological Survey World Energy 

Assessment Team (2000) estimates that the Paleozoic and 

Jurassic total petroleum systems of central Arabia contain 

a combined mean undiscovered, conventional petroleum 

resource exceeding 60 BBO, 417 TCF of gas, and about 26 

BBNGL. Combined analysis of both known oil and gas 

reserve volumes with potential undiscovered oil and gas 

volumes of the central Arabian Peninsula implies that this 

historically prolific hydrocarbon-producing area will continue 

to contribute a major supply of petroleum to the world market 

during the next 30 years.

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Contained in this appendix are the detailed input characteristics, selected ancillary data, and country or other land 

parcel allocations of undiscovered resources for Central 

Arch Horst-Block Anticlinal Oil and Gas Assessment Unit 

(20210101). These data were used in the calculations of the 

undiscovered resources, and may be of use to those pursuing 

further analysis of the results.

Appendix 1. Seventh Approximation Input Form for Central Arch Horst-Block 

Anticlinal Oil and Gas Assessment Unit (20210101), Central Arabia 

Qusaiba-Paleozoic Total Petroleum System

Appendix 1 81
82 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

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86 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Contained in this appendix are the detailed input characteristics, selected ancillary data, and country or other land parcel allocations of undiscovered resources for the North Gulf 

Structural Gas Assessment Unit (20210102). These data were 

used in the calculations of the undiscovered resources, and 

may be of use to those pursuing further analysis of the results.

Appendix 2. Seventh Approximation Input Form for North Gulf Structural Gas 

Assessment Unit (20210102), Central Arabia Qusaiba-Paleozoic

Total Petroleum System
Appendix 2 87

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Contained in this appendix are the detailed input characteristics, selected ancillary data, and country or other land parcel allocations of undiscovered resources for the Horst-Block 

Anticlinal Oil Assessment Unit (20210201). These data were 

used in the calculations of the undiscovered resources, and 

may be of use to those pursuing further analysis of the results.

Appendix 3. Seventh Approximation Input Form for Horst-Block Anticlinal

Oil Assessment Unit (20210201), Arabian Sub-Basin Tuwaiq/Hanifa-Arab Total 

Petroleum System

Appendix 3 91
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96 Total Petroleum Systems, Greater Ghawar Uplift, Saudi Arabia, Northern Arabian-Persian Gulf

Contained in this appendix are the detailed input characteristics, selected ancillary data, and country or other land parcel allocations of undiscovered resources for the Salt-Involved 

Structural Oil Assessment Unit (20210202). These data were 

used in the calculations of the undiscovered resources, and 

may be of use to those pursuing further analysis of the results.

Appendix 4. Seventh Approximation Input Form for Salt-Involved Structural

Oil Assessment Unit (20210202), Arabian Sub-Basin Tuwaiq/Hanifa-Arab

Total Petroleum System
Appendix 4 97

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