Total Petroleum Systems of the Pelagian Province, 

Tunisia, Libya, Italy, and Malta—The Bou Dabbous– 

Tertiary and Jurassic-Cretaceous Composite 

By T.R. Klett 

U.S. Geological Survey Bulletin 2202-D 

U.S. Department of the Interior 

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

Gale A. Norton, Secretary 

U.S. Geological Survey 

Charles G. Groat, Director 

Version 1.0, 2001 

This publication is only available online at: 

http://geology.cr.usgs.gov/pub/bulletins/b2202-d/ 

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


Manuscript approved for publication August 3, 2001 


Published in the Central Region, Denver, Colorado 


Graphics by the author and Gayle M. Dumonceaux


Photocomposition by Gayle M. Dumonceaux


Edited by L.M. Carter

Contents 

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


Abstract ......................................................................................................................................... 2


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


Acknowledgments........................................................................................................................ 3


Province Geology.......................................................................................................................... 3


Tectonic History ................................................................................................................. 5


Stratigraphy ........................................................................................................................ 11


Regional Exploration Activity...................................................................................................... 13


The Bou Dabbous–Tertiary Total Petroleum System (204801).............................................. 14


Source Rocks...................................................................................................................... 15


Overburden Rocks ............................................................................................................. 15


Reservoir Rocks ................................................................................................................. 15


Seal Rocks........................................................................................................................... 15


Trap Types in Oil and Gas Fields ..................................................................................... 15


Assessment of Undiscovered Petroleum....................................................................... 18


The Jurassic-Cretaceous Composite Total Petroleum System (204802)............................. 20


Source Rocks...................................................................................................................... 20


Overburden Rocks ............................................................................................................. 24


Reservoir Rocks ................................................................................................................. 24


Seal Rocks........................................................................................................................... 24


Trap Types in Oil and Gas Fields ..................................................................................... 24


Assessment of Undiscovered Petroleum....................................................................... 24


Summary ........................................................................................................................................ 26


References Cited ......................................................................................................................... 26


Appendices.................................................................................................................................... 28


1. 	Exploration-activity and discovery-history plots for the Bou Dabbous–


Tertiary Structural/Stratigraphic Assessment Unit (20480101)................................... 30


2. 	Exploration-activity and discovery-history plots for the Jurassic-Cretaceous


Structural/Stratigraphic Assessment Unit (20480201).................................................. 88


Figures 

1–4. Maps showing: 

1.	 Central Mediterranean Sea, showing USGS-defined Pelagian Province


(2048), major geologic structures, and location of cross sections...................... 4


2.	 Areal extent of Bou Dabbous–Tertiary Total Petroleum System (204801)


and coinciding Bou Dabbous–Tertiary Structural/Stratigraphic 


Assessment Unit (20480101) in the Pelagian Province.......................................... 5


3.	 Areal extent of Jurassic-Cretaceous Composite Total Petroleum System 


(204802) and coinciding Jurassic-Cretaceous Structural/Stratigraphic 


Assessment Unit (20480201) in the Pelagian Province.......................................... 6


4.	 Sketch maps showing distribution of proven Mesozoic and Cenozoic source


rocks in Tunisia............................................................................................................. 7


III

5. Cross sections through Pelagian Province (2048) ........................................................... 8 

6.	 Columnar section, stratigraphic nomenclature, tectonic events, and 

petroleum occurrence for Tunisia and offshore Libya ................................................... 12 

7. Events chart for Bou Dabbous–Tertiary Total Petroleum System (204801)................. 14 

8.	 Lithofacies map of the Metlaoui Group (excluding the Chouabine and 

Tselja Formations) and locations of fields with reported oil and gas 

volumes in Bou Dabbous–Tertiary Total Petroleum System (204801).......................... 16 

9. Diagrams illustrating selected trap styles in Pelagian Province (2048) ....................... 18 

10.	 Map showing major faults and anticlines in Tunisia, as well as locations of 

oil and gas fields.................................................................................................................... 19 

11.	 Events chart for Jurassic-Cretaceous Composite Total Petroleum 

System (204802) ..................................................................................................................... 23 

12.	 Lithofacies map of the Zebbag Formation and locations of fields with 

reported oil and gas volumes in Jurassic-Cretaceous Composite 

Total Petroleum System (204802)........................................................................................ 25 

Tables 

1.	 Number and sizes of discovered fields for each assessment unit in the 

Pelagian Province (2048) through 1995 ............................................................................. 3 

2.	 Reservoir properties of discovered accumulations for each assessment 

unit in the Pelagian Province (2048) through 1995 .......................................................... 17 

3.	 Estimated sizes, number, and coproduct ratios of undiscovered oil and 

gas fields for each assessment unit in the Pelagian Province (2048) ......................... 21 

4.	 Estimated undiscovered conventional oil, gas, and natural gas liquids 

volumes for oil and gas fields for each assessment unit in the 

Pelagian Province (2048) ..................................................................................................... 22 

IV

Total Petroleum Systems of the Pelagian Province, 

Tunisia, Libya, Italy, and Malta—The Bou Dabbous– 

Tertiary and Jurassic-Cretaceous Composite 

By T.R. Klett 

Foreword 

This report was prepared as part of the U.S. Geological 

Survey World Petroleum Assessment 2000 (U.S. Geological 

Survey World Energy Assessment Team, 2000). The primary 

objective of World Petroleum Assessment 2000 is to assess the 

quantities of conventional oil, natural 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; the cutoff 

varies, but it 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 Assessment Methodology Team 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 total petroleum system or the assessment unit. 

The world was divided into 8 regions and 937 geologic 

provinces. These provinces have been ranked according to the 

discovered known (cumulative production plus remaining 

reserves) 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). 

Total petroleum systems and assessment units were delineated for each geologic province considered for assessment. It 

is not necessary for the boundaries of total petroleum systems 

and assessment units to be entirely contained within a geologic 

province. Particular emphasis is placed on the similarities of 

petroleum fluids within total petroleum systems, unlike 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: 

1

Unit Name Code 

Region Middle East and North Africa 2 

Province Pelagian 2048 

Total Petroleum Systems Bou Dabbous–Tertiary 204801 

Jurassic-Cretaceous Composite 204802 

Assessment Units Bou Dabbous–Tertiary Structural/Stratigraphic 20480101 

Jurassic-Cretaceous Structural/Stratigraphic 20480201 

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 sourcerock deposition, reservoir-rock deposition, seal-rock 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-migration-accumulation 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 are assigned to each assessment unit. Additionally, an 

access probability is assigned for necessary petroleum-related 

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 Minerals Management Service (Lore and others, 1996) created a set of analytical “growth” functions that are used to estimate future reserve growth (that, when added to known volumes, 

is called “grown” volumes hereafter). The set of functions was 

originally created for geologic regions of the United States, but 

the assumption is 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 coproduct ratios of undiscovered fields are made based 

on geologic knowledge of the assessment unit, exploration and 

discovery history, analogs, and, if available, prospect maps. Probabilistic distributions are applied to these estimates and combined 

by Monte Carlo simulation to calculate undiscovered resources. 

Illustrations in this report that show boundaries of the total 

petroleum systems, assessment units, and extent of source rocks 

were compiled using geographic information system (GIS) software. The political boundaries and cartographic representations 

were taken, with permission, from the Environmental Research 

Institute’s ArcWorld 1:3 million digital coverage (1996), have 

no political significance, and are displayed for general reference 

only. Oil and gas field center points were provided by, and 

reproduced with permission from, Petroconsultants (1996a, 

1996b). 

Abstract 

Undiscovered conventional oil and gas resources were 

assessed within total petroleum systems of the Pelagian Province (2048) as part of the U.S. Geological Survey World Petroleum Assessment 2000. The Pelagian Province is located 

mainly in eastern Tunisia and northwestern Libya. Small 

portions of the province extend into Malta and offshore Italy. 

Although several petroleum systems may exist, only two 

“composite” total petroleum systems were identified. Each total 

petroleum system comprises a single assessment unit. These 

total petroleum systems are called the Bou Dabbous–Tertiary 

and Jurassic-Cretaceous Composite, named after the sourcerock intervals and reservoir-rock ages. 

The main source rocks include mudstone of the Eocene 

Bou Dabbous Formation; Cretaceous Bahloul, Lower 

Fahdene, and M’Cherga Formations; and Jurassic Nara 

Formation. Known reservoirs are in carbonate rocks and 

sandstone intervals throughout the Upper Jurassic, Cretaceous, and Tertiary sections. Traps for known accumulations 

include fault blocks, low-amplitude anticlines, high-amplitude 

anticlines associated with reverse faults, wrench fault structures, and stratigraphic traps. 

The estimated means of the undiscovered conventional 

petroleum volumes in total petroleum systems of the Pelagian 

Province are as follows: 

[MMBO, million barrels of oil; BCFG, billion cubic feet of gas; MMBNGL, 

million barrels of natural gas liquids] 

Total Petroleum System MMBO BCFG MMBNGL 

Bou Dabbous–Tertiary 667 2,746 64 

Jurassic-Cretaceous Composite 403 2,280 27 

2 Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta 
Introduction 

Undiscovered conventional oil and gas resources were 

assessed within total petroleum systems of the Pelagian Province (2048) as part of the World Energy Project being conducted 

by the U.S. Geological Survey (USGS). The Pelagian Province 

is a geologic province delineated by the USGS. This study documents the geology, undiscovered oil- and gas-resource potential, exploration activity, and discovery history of this geologic 

province. 

The Pelagian Province is located mainly in eastern Tunisia 

and northwestern Libya (fig. 1). A portion of the province 

extends into Malta and offshore areas of Italy. The province 

area encompasses approximately 294,000 km2. Neighboring 

geologic provinces as delineated by the USGS include the 

Tyrrhenian Basin (4069), Sicily (4066), Mediterranean Basin 

(2070), Sirte Basin (2043), Nefusa Uplift (2049), Hamra Basin 

(2047), Trias/Ghadames Basin (2054), Atlas Uplift (2053), and 

Tellian Foredeep (2052) (Persits and others, 1997). 

Several total petroleum systems may exist in the Pelagian 

Province, but only two “composite” total petroleum systems are 

described in this report. Data available for this study are insufficient to adequately determine the relative contribution of every 

total petroleum system to individual accumulations and therefore preclude further subdivision. The described systems are 

called the Bou Dabbous–Tertiary (204801) and JurassicCretaceous Composite (204802) Total Petroleum Systems, 

named after the source-rock intervals and reservoir-rock ages. 

Both total petroleum systems coincide with the extent of proven 

source rocks within the province and the hypothesized extent of 

petroleum migration from their respective source rocks (figs. 2, 

3, and 4). Due to insufficient data, province and total petroleum 

system boundaries can only be approximately delineated and 

therefore are subject to future modification. 

One assessment unit was defined for each total petroleum 

system; the assessment units coincide with the total petroleum 

systems (figs. 2, 3). The assessment units are named after the 

total petroleum system with a suffix of “Structural/ 

Stratigraphic.” This suffix refers to the progression from a structural and combination trap exploration strategy to a stratigraphic 

trap exploration strategy. 

Volumes of petroleum discovered in each of the total petroleum systems of the Pelagian Province are shown in table 1. 

The Pelagian Province as a whole contains more than 2,300 million barrels (MMB) of known petroleum liquids (estimated total 

recoverable volume, which is cumulative production plus 

remaining reserves and includes approximately 2,240 million 

barrels of oil, MMBO, and 70 million barrels of natural gas 

liquids, MMBNGL) and approximately 17,200 billion cubic feet 

of known natural gas (17.2×1012 CFG or 17.2 TCFG) (Petroconsultants, 1996a). These volumes are greater than those 

shown in table 1 in that the volumes include those from neighboring total petroleum systems that slightly extend into the 

province. The Bou Dabbous–Tertiary Total Petroleum System 

contains a greater volume of known petroleum (approximately 

2,100 MMBO, 15,500 BCFG, and 44 MMBNGL) than the 

Jurassic-Cretaceous Composite Total Petroleum System 

(approximately 103 MMBO, 1,300 BCFG, and 23 MMBNGL). 

Table 1. Number and sizes of discovered fields for each assessment 

unit in the Pelagian Province (2048) through 1995. 

[MMBO, million barrels of oil; BCFG, billion cubic feet of gas; NGL, natural 

gas liquids; MMBNGL, million barrels of NGL. Volumes reported are 

summed for oil and gas fields (USGS defined). Oil and gas fields containing 

known volumes below 1 million barrels of oil or 6 billion cubic feet of gas 

(BCFG) are grouped. Data from Petroconsultants (1996a)] 

Acknowledgments 

I thank Ali M’Rabet of Entreprise Tunisienne d’Activités 

Pétrolières (ETAP) and David Boote and Marc Traut of Occidental Oil and Gas Corporation for their suggestions, and Lorna 

Carter, William Keefer, Katharine Varnes, Gregory Ulmishek, 

and Janet Pitman for their editorial review. I also thank 

Margarita Zyrianova for help in drafting some of the figures. 

Province Geology 

The Pelagian Province generally coincides with the offshore shelf area of east-central Tunisia and northern Libya (figs. 

1, 2). However, the western and southern boundaries are 

onshore. The western boundary is along the North-South Axis 

(fig. 1), a basement-related structural feature bounded by normal 

faults separating the Pelagian Province in eastern Tunisia from 

the Mesozoic fault basin farther west (Bobier and others, 1991). 

Province Geology 3 
4
10°E 12°E 14°E 16°E 18°E 

38° 

ADVENTURE SICILY

PLATEAU 

MALTAGRABEN

MALTA-MEDINA CHANNEL

MEDINAGRABEN 

RAGUSAMALTA 

PLATEAU IONIAN ABYSSAL BASIN 

ISIS HORST 

JARRAFAGRABEN MELITA 

BANK 

MEDINA BANK 

FORE-ARC SCRAPING ZONE 

SIRTE RISE UPPERSIRTE SL

MARAD

OPE

A TROUGH 

MISURATA-SIRTE RIDGE 

SIRTE TROUGH 

CYRENAICA 

LOWER SIRTE SLOPE 

CALTANISSETTA 

BASIN 

MALTA 

TUNISIA 

ASHTART-TRIPOLITANIA BASIN 

LAMPEDU

PLA

SA

TEAU 

TALEMZANEGEFARA ARCH 

PANTELLERIA

GRABEN 

MISURATAVALLEY 

MAGHREBIAN TREND 

LIBYA 

0 50 100 KILOMETERS 

A' 

A 

GAFSA-GEFARA EXTENSIONAL FAULT SYSTEM 

B 

B' beyond map limit 

NORTH-SOUTH AXIS 

N EFUSA ARCH 

Gulf 

of 

Gabes 

Gulf 

of 

Hammamet 

Pelagian 

Sea 

Approximate

eastern limit 

of Triassic salt 

PELAGIAN 

SHELF 

Ionia

Sea 

Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta 36° 34° 

32° 

30° 

Figure 1. Central Mediterranean Sea, showing USGS-defined Pelagian Province (2048), major geologic structures, and location of cro

highs (for example, Isis Horst) are based on seismic data and drawn on 1.0 and 1.8 second two-way travel time intervals (modified from FJongsma and others, 1985). 
10°E 12°E 14°E 16°E 

38° 

36° 

34° 

32° 

Figure 2. Areal extent of Bou Dabbous–Tertiary Total Petroleum System (204801) and coinciding Bou Dabbous–Tertiary Structural/ 

Stratigraphic Assessment Unit (20480101) in the Pelagian Province (modified from Petroconsultants, 1996b; Persits and others, 1997). 

ITALY 

TUNISIA 

MALTA 

LIBYA Country boundary 

Total petroleum system boundary 

Oil field 

Gas field 

Geologic province boundary 

Bou Dabbous–Tertiary 

Total Petroleum System 

(204801) 

Mediterranean 

Sea 

Gulf of 

Hammamet 

Gulf of 

Gabes 

0 150 KILOMETERS

The southern boundary was delineated along an escarpment that 

resulted from uplift of the Talemzane-Gefara and Nefusa Arches 

(fig. 1). The eastern boundary corresponds approximately with 

a fault zone and escarpment that marks the boundary between 

the Pelagian Shelf and Ionian Sea. The northern boundary follows a rift zone between the African and European continental 

plates (fig. 1). 

Several major geologic structures exist within the Pelagian 

Province (fig. 1). Among the more pronounced structural highs 

are the Lampedusa Plateau, Medina Bank, Melita Bank, and Isis 

Horst. The Ashtart-Tripolitania Basin (also called GabesTarab- ulus Basin), Misurata Valley, Jarrafa Graben, and grabens 

associated with the rift zone to the north are major depressions. 

These structures are oriented northwest to southeast. Cross 

section A–A′(fig. 5A) shows the major structural style as alternating horsts and grabens separated by normal faults. 

Tectonic History 

The tectonic evolution of the Pelagian Province controlled 

source- and reservoir-rock deposition, source-rock maturation, 

and petroleum migration and accumulation (Bédir and others, 

1992). 

The Paleozoic record is not well known in the Pelagian 

Province, but based on better known Paleozoic sections of the 

Saharan Platform (partly shown in fig. 5B) in southern Tunisia, 

the area was part of a passive continental margin, containing 

Province Geology 5 
10°E 12°E 14°E 16°E 

38° 

36° 

34° 

32° 

Figure 3. Areal extent of Jurassic-Cretaceous Composite Total Petroleum System (204802) and coinciding Jurassic-Cretaceous 

Structural/Stratigraphic Assessment Unit (20480201) in the Pelagian Province (modified from Petroconsultants, 1996b; Persits and 

ITALY 

TUNISIA 

MALTA 

Jurassic-Cretaceous Composite 

Total Petroleum System 

(204802) 

LIBYA Country boundary 

Total petroleum system boundary 

Oil field 

Gas field 

Geologic province boundary 

Mediterranean 

Sea 

Gulf of 

Hammamet 

Gulf of 

Gabes 

0 150 KILOMETERS

others, 1997). 

Cambrian to Carboniferous clastic rocks. During the Carboniferous, Laurasia collided with Gondwana, marking the Hercynian 

event, resulting in the older Paleozoic section being folded, 

uplifted, and eroded (Aliev and others, 1971; Burollet and others, 1978; Boote and others, 1998). In the Late Carboniferous 

and Permian, several rift basins and grabens formed along the 

northern margin of the African plate by extension as a result of 

the initial breakup of Gondwana and the opening of the Tethyan 

seaway (Guiraud, 1998). Step faulting and subsidence occurred 

north of the Talemzane-Gefara Arch, where Upper Carboniferous and Permian sediments were deposited (fig. 1) (Burollet and 

others, 1978; Guiraud, 1998). 

Extension and subsidence continued into the Triassic and 

Early Jurassic (Morgan and others, 1998). North-southtrending normal faults and east-west-trending transfer faults 

developed at this time, particularly along the North-South Axis 

in eastern Tunisia (Ouali, 1985; Morgan and others, 1998). 

Clastic and carbonate sediments were deposited in the Triassic 

(fig. 5B), as well as evaporites consisting of halite and sulfates 

(Burollet, 1991). Flowage of the evaporites due to sedimentary loading resulted in vertical migration and formation of 

diapirs and subsurface “salt walls” (Burollet, 1991). During 

the Early Jurassic, turbidites, as well as shelf and pelagic 

carbonates, were deposited. 

6 Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta 
Ypresian (Bou Dabbous) Albian (Fahdene) 

Upper Cenomanian to 

lower Turonian (Bahloul) 

Jurassic (Nara) 

GH 

GG 

GH 

GG 

GH 

GG 

GH 

GG 

Figure 4. Distribution of proven Mesozoic and Cenozoic source rocks in Tunisia (modified from 

Entreprise Tunisienne d’Activités Pétrolières, 2000). GH, Gulf of Hammamet; GG, Gulf of Gabes. 

In Middle and Late Jurassic time, the central Atlantic 

Ocean opened between Laurasia and Africa, developing a rift 

zone between the African and European continents. Shelf carbonates were deposited in the Pelagian Province area at this time 

(Burollet and others, 1978; Morgan and others, 1998). Faults 

associated with the opening of the Tethys Ocean and rifting 

between the European and African plates controlled sedimentation from the Middle Jurassic to the present (Morgan and others, 

1998). The depocenter that developed north of the TalemzaneGefara Arch during the Permian shifted northward (Burollet and 

others, 1978). 

During the Early Cretaceous, rifting continued along the 

northern margin of the African plate, resulting in subsidence of 

the Saharan Atlas and the Aures trough of northern Algeria and 

Tunisia (Vially and others, 1994; Guiraud, 1998). Faults associated with rifting continued to control sedimentation (Morgan 

and others, 1998). Clastic alluvial sediments from the Saharan 

Platform were deposited in the southern portion of the Pelagian 

Province whereas open-marine clastic and carbonate sediments 

were deposited in the northern portion (Burollet and others, 

1978). In some areas, sediment thickness was sufficient to initiate flowage of Triassic evaporites that continued into the Late 

Cretaceous (Morgan and others, 1998). The late Paleozoic depocenter that developed north of the Talemzane-Gefara Arch 

migrated northward with the development of a trough in the area 

of the Gafsa-Gefara extensional fault system during the Aptian 

Province Geology 7 
8
 Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta LINE GSI-1 LINE EL (75)-72 LINE GSI-1 0 0 KILOMETERS VER

TICAL EXAGGERATION = 10 

SIC

RAGUSA-MALTA 

PLATEAU 

MALTA-MEDINA 

CHANNEL 

MEDINA 

BANK 

MELITA 

BANK 

MISURATA 

VALLEY 

ASHTART-TRIPOLITANIA 

LIBYA BASIN

6 

5 

4 

3 

2 

1 

0 

Depth, in 

kilometers 

A 

S 

LINE EL (75)-72 

5 

4 

2 

0 

1 

3 

Two-way travel time, 

in seconds 

0 20 KILOMETERS 

SW 

MISURATA VALLEY MELITA BANK MEDINA BANK

VER

TICAL EXAGGERATION = 5.5 

2 

0 

1 

3 

Two-way travel time, 

in seconds 3 1 2 0 

NE 

TRIPOLITANIA BASIN 

0 20 KILOMETERS 

10 

10 

Plio-Recent 

M-U Miocene 

L Miocene 

Eoc-Olig 

U Cretaceous 

L Cretaceous 

U Cret 

L Cret 

Jurassic 

Eocene-Miocene 

VERTICAL EXAGGERATION = 4 

Plio-Recent 

Plio-Recent 

Pre-Cretaceous 

Eocene-Miocene 

Eocene-Miocene 

U Cretaceous 

L Cretaceous 

Cretaceous 

U Cretaceous 

volcanics 

SOUTH N

A 

2

Figure 5. Cross sections through Pelagian Province (2048). 

A, South-to-north cross section A–A′ through Pelagian Basin (modified from Jongsma a

the cross section is shown in seismic lines EL (75)-72 and GSI-1. Heavy vertical line, fault. Location of section, figure 1. 
NORTHWEST 

0 1 2 

3 Ordovician 

B 

TALEMZANE-GEFARA 

ARCH 

Miocene 

Oligocene 

PELAGIAN BASIN HAMRA BASIN 

Upper Cretaceous Lower Cretaceous 

Jurassic 

Triassic 

Silurian 

Devonian 

Lower Carboniferous 

U 

Sil 

Permian 

Upper Carboniferous 

Triassic 

Upper Cretaceous 

U Cret 

Lower Cretaceous 

Jurassic 

Triassic 

Cambrian and 

Ordovician 

Pliocene-Pleistocene 

0 100 KILOMETERS 

Pelagian Province (2048) Hamra Province (2047) 

GAFSA-GEFARA 

EXTENSIONAL 

FAULT SYSTEM 

Depth, in kilometers 

SAHARAN PLATFORM 

B 

Figure 5—Continued. Cross sections through Pelagian Province (2048). B, Northwest-to-southeast cross section B–B′ through Pelagian anand others, 1978; Boote and others, 1998). Dashed lines, approximate position. Location of section, figure 1. 

Province Geology 9

Miocene (nonmarine) sand and mudstone 

Miocene (marine) sand and mudstone 

Paleocene basinal 

mudstone and marl 

Cretaceous limestone and marl 

Eocene shelf limestone 

Oligocene 

limestone/marl 

E 

E 

E 

E E 

O 

O 

P 

P 

WEST EAST 

2,000 

M.S.L. 

4,000 

6,000 

8,000 

10,000 

M.S.L. 

Depth, 

in feet 

2,000 

4,000 

6,000 

8,000 

10,000 

Post Miocene 

Fault 

Unconformity C 

Figure 5—Continued. Cross sections through Pelagian Province (2048). C, Generalized west-to-east cross section through Gulf of Hammamet (modified from Long, 1978). 

(fig. 1) (Burollet and others, 1978). Additionally, uplift and erosion occurred, particularly along the North-South Axis (Burollet 

and others, 1978), resulting in the Austrian Unconformity. 

The African plate began to drift northward during the early 

Late Cretaceous, and this movement has continued to the present 

(Morgan and others, 1998). Rifting occurred along the northern 

margin of the African plate as a result of dextral shearing 

between the African and European plates, developing a complex 

horst and graben system. The grabens trend northwest to southeast and include the Ashtart-Tripolitania Basin and the Misurata 

Valley, and Jarrafa Graben (fig. 1) (Jongsma and others, 1985; 

Hammuda and others, 1991; Guiraud, 1998). Associated fault 

displacements and uplift of horst blocks controlled sedimentation (Morgan and others, 1998). In the Santonian (Late Cretaceous), structural inversion, reverse or thrust faulting, and 

folding occurred (Guiraud, 1998; Morgan and others, 1998). 

Fold belts along the Saharan Atlas, west of the North-South 

Axis, were initiated, whereby Triassic evaporites provided a 

décollement surface (Guiraud, 1998). Gentle uplift occurred 

during the latest Cretaceous to Paleocene (Burollet, 1967a). 

In the early Eocene, west-to-east or west-northwest-to-eastsoutheast transfer faults were reactivated (Morgan and others, 

1998). Sedimentation was controlled by this faulting activity, 

and facies boundaries of Ypresian (lower Eocene) rocks reflect 

the orientation of these strike-slip faults (Bishop, 1988; Morgan 

and others, 1998). The Kabylie microplate collided with the 

African margin in the Oligocene (Jongsma and others, 1985; 

Morgan and others, 1998), marked by an angular unconformity 

at the base of the Oligocene section (Morgan and others, 1998). 

Additionally, a fractured mobile terrane developed along the 

north edge of the Pelagian area, leaving the southern portion 

(most of the Pelagian Province, fig. 1) a passive platform 

attached to the African plate (Jongsma and others, 1985). 

Tectonic activity in late Oligocene to Miocene time resulted in 

nondeposition or erosion over much of the area (Burollet, 1967a 

and b). A disconformity between Miocene and older beds is 

present in eastern Tunisia, whereas an angular unconformity 

exists elsewhere (Burollet, 1967b). In some areas, the entire 

Paleogene section was removed (fig. 5C). 

Deformation due to crustal shortening occurred north and 

west of the North-South Axis from late Miocene until early 

Pleistocene (Burollet, 1991; Morgan and others, 1998). Uplift 

of areas east of the North-South Axis resulted in erosion 

(Bishop, 1975; Salaj, 1978). The fault systems of the Pantelleria Graben, Malta Graben, Malta-Medina Channel, and Medina 

Graben (fig. 1) began to develop in the late Miocene to early 

Pliocene; and deformation continues to the present, resulting 

from rifting and east-to-west dextral movements (Jongsma and 

others, 1985). Fault systems, developed earlier in the Pelagian 

Province area (south of the Pantelleria Graben, Malta Graben, 

Malta-Medina Channel, and Medina Graben), continued to subside and control deposition. Locally, relatively greater amounts 

of subsidence occurred, such as in the Gulf of Hammamet 

(Burollet and others, 1978). Orogenic movement is presently 

occurring in northern Tunisia (Burollet and others, 1978). 

Magmatic activity has occurred throughout the area (fig. 

1), much of it occurring in the Aptian to Paleocene due to rifting 

on the Pelagian Shelf and in the Neogene to Quaternary due to 

the Alpine (Atlassic) collision and subsequent opening of the 

western Mediterranean (Finetti, 1982; Wilson and Guiraud, 

1998; Guiraud, 1998). 

The present-day geothermal gradients are variable across 

the Pelagian Province, but observed trends correspond to the 

recent structural evolution of the area. Values in offshore areas 

range from about 3.5° to 4.5°C/100 m (Lucazeau and Ben Dhia, 

1989) and are higher than values in onshore areas. 

10 Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta 
Stratigraphy 

The regional stratigraphy is variable across the Pelagian 

Province, and stratigraphic nomenclature varies among authors 

and countries. Throughout the Mesozoic and Cenozoic, openmarine conditions existed generally in the northern part of the 

province, whereas neritic shelf conditions existed in the southern part (Burollet and others, 1978). Little information exists 

for rocks older than Triassic or Jurassic (Burollet, 1990). This 

study uses primarily the nomenclature given by Entreprise 

Tunisienne d’Activités Pétrolières (1997) for the Tunisian portion of the province and Hammuda and others (1991) for the 

Libyan portion. Columnar sections, stratigraphic nomenclature, 

and correlations are shown in figure 6. 

Triassic rocks can be separated into two main intervals, a 

lower clastic interval and an upper evaporite interval (Bishop, 

1975). The lower clastic interval includes sandstone and mudstone of the Bir El Jaja, Ouled Chebbi, and Kirchaou or Trias 

Argilo-Greseux Inferieur Formations (fig. 6). Depositional 

facies were continental in the southern portion of the Pelagian 

Province, grading into shallow marine facies northward. The 

northern limit of the clastic interval is not known (Bishop, 

1975). The Kirchaou or Trias Argilo-Greseux Inferieur Formation provides major oil and gas reservoirs in the Saharan Platform basins of Libya, Tunisia, and Algeria. Between the clastic 

and evaporite intervals is a dolomitic section equivalent to the 

Azizia, Trias Carbonate, and Trias Argilo-Greseux Superieur 

(TAGS) Formations (fig. 6). The upper evaporite interval contains interbedded anhydrite, salt, and dolostone (Busson, 1967; 

Bishop, 1975). 

The Jurassic and Lower Cretaceous sections contain 

mostly carbonate rocks, representing increasingly deeper 

marine to pelagic deposition northwestward (Burollet and others, 1978). Lagoonal, deltaic, and terrigenous facies were 

present in the south and southwest, which migrated northward 

through time until the Aptian (Bishop, 1975; Burollet and others, 1978; M’Rabet, 1984). These landward deposits include 

sandstone of the Upper Jurassic M’Rabtine Formation, Upper 

Jurassic to Lower Cretaceous Meloussi Formation, and Lower 

Cretaceous Boudinar Formation (fig. 6). Marine deposits 

include limestone, dolostone, and marl (Salaj, 1978) of the 

Jurassic Nara Formation and Upper Jurassic to Lower Cretaceous Sidi Khalif and M’Cherga Formations (fig. 6). Micrite 

and mudstone were deposited in the deep marine environments 

(Bishop, 1975). 

Deposition of condensed sections, as well as the development of shoal facies and some reefs, occurred along the NorthSouth Axis during the Jurassic and Early Cretaceous (Bishop, 

1975; Salaj, 1978; Burollet and others, 1978). Farther east and 

to the south, pelagic sediments were deposited in a subsiding 

depositional trough that existed in the present-day Gulf of Gabes 

area (fig. 1) (Salaj, 1978; Burollet and others, 1978). 

A maximum flooding event occurred during the Barremian 

to Aptian (Early Cretaceous; Bishop, 1975; Salaj, 1978). 

Barremian rocks consist of limestone, marl, and interbedded 

sandstone and shale of the Bouhedma and M’Cherga Formations, and the Sidi Aïch sandstone (Bishop, 1975; Salaj, 1978; 

Entreprise Tunisienne d’Activités Pétrolières, 1997). 

Aptian and Albian rocks include limestone, dolostone, 

sandstone, mudstone, marl, and some evaporites of the Orbata, 

Serdj, Hameima, and Lower Fahdene Formations (Burollet and 

others, 1978; Salaj, 1978). The Orbata Formation (or Orbata 

member of the Gafsa Formation in earlier publications) is limestone and dolostone (Bishop, 1975). The Serdj Formation is a 

reef limestone that is laterally equivalent to the Orbata Formation and overlain by clastic sediments of either the deeper 

marine Hameima Formation or Lower Fahdene (also called the 

Mouelha) Formation (fig. 6) (Burollet and others, 1978). 

Unconformably overlying the Orbata Formation is the 

Albian to Turonian Zebbag Formation (fig. 6). Zebbag sediments were deposited on a shallow marine carbonate platform in 

the Gulf of Gabes area and central Tunisia (Bishop, 1988). Subtidal conditions existed in central Tunisia and in the area of the 

present-day Gulf of Gabes coast, where lagoonal mudstone, 

dolostone, and anhydrite were deposited (Bishop, 1975; Bishop, 

1988). Reefs, reefoid facies, and rudist banks are also present 

(Bishop, 1975; Burollet and others, 1978). In the Pelagian Province, the Zebbag Formation is limestone, dolostone, and bioclastic rocks, and is laterally equivalent to basinal mudstone and 

argillaceous limestone of the Fahdene and Bahloul Formations 

(Bishop, 1988). The Fahdene Formation is a dark-gray mudstone and the Bahloul Formation is a dark-colored, laminated, 

euxinic, argillaceous limestone (Burollet and others, 1978; 

Bishop, 1988). 

The Turonian to Campanian Aleg Formation overlies the 

Fahdene, Bahloul, and Zebbag Formations. Rocks of the Aleg 

Formation include mudstone, limestone, and marl (Bishop, 

1975; Salaj, 1978). The Bireno, Miskar, and Douleb Formations 

are equivalent to some intervals of the Aleg Formation (fig. 6). 

Both the Bireno and Douleb Formations are, in part, laterally 

equivalent to, or are members of the Miskar Formation. These 

formations consist of limestone, dolostone, and marl (Salaj, 

1978; Entreprise Tunisienne d’Activités Pétrolières, c. 1999). 

The Miskar Formation represents a rudist bank or banks on the 

shelf edge or slope (Bishop, 1988; Knott and others, 1995). 

During the Campanian to Maastrichtian (latest Cretaceous), chalky limestone, micrite, and marl of the Abiod Formation were deposited over the Aleg Formation (Burollet and 

others, 1978; Salaj, 1978; Bishop, 1975). The Santonian Jamil 

Formation and Campanian to Maastrichtian Bu Isa Formation 

are laterally equivalent, in part, to the Aleg and Abiod Formations (fig. 6). 

Overlying the Abiod and Bu Isa Formations is the Maastrichtian to Thanetian (Paleocene) El Haria Formation, a gray, 

black, or brown mudstone, containing some thin limestone beds 

in the lower part (Burollet, 1967b; Bishop, 1975). The El Haria 

Formation covers much of the Pelagian Province but is absent in 

the southern and southwestern portions, as a result of either nondeposition or removal by erosion (Bishop, 1975). The Al Jurf, 

Ehduz, and part of the Bilal Formations are laterally equivalent 

to the El Haria Formation (fig. 6). 

The Thanetian to Lutetian Metlaoui Group overlies the El 

Haria Formation and consists of rocks representing lagoonal, 

carbonate ramp, and marine deposition. The lowermost beds are 

the Tselja (oldest) and Chouabine Formations (fig. 6). The 

Tselja Formation is represented by evaporites (including 

gypsum) and dolomitic rocks; the Chouabine Formation is 

Province Geology 11 
12


QU

ATERNARY 

Pliocene 

Paleocene 

Miocene 

Oligocene 

Eocene 

Late 

Early 

Late 

Middle 

Early 

Late 

Middle 

Early 

Piacenzian 

Zanclean 

Messinian 

Tortonian 

Serravallian 

Langhian 

Burdigalian 

Aquitanian 

Chattian 

Rupelian 

Priabonian 

Bartonian 

Lutetian 

Ypresian 

Thanetian 

Danian 

Maastrichtian 

Campanian 

Santonian 

Coniacian 

Turonian 

Cenomanian 

Albian 

Aptian 

Barremian 

Hauterivian 

Valanginian 

Berriasian 

Tithonian 

Kimmeridgian 

Oxfordian 

Callovian 

Bathonian 

Bajocian 

Aalenian 

Toarcian 

Pliensbachian 

Sinemurian 

Hettangian 

Rhaetian 

Norian 

Carnian 

Ladinian 

Anisian 

Scythian 

TRIASSIC JURASSIC CRETACEOUS PALEOGENE NEOGENE 

Red Beds/Caliche 

Porto Farina 

Segui Raf Raf

Beglia 

Oued Bel Khedim 

Somaa t 

Saouaf 

Birsa a 

Kechabta 

O. Melah 

Hakima 

Aïn Grab 

Messiouta Oued Hammam Ramla Salammbo 

Numidian 

Flysch 

Vascus Horizon 

Fortuna Ketatna 

Bouloufa 

Tanit 

Jebs 

Metlaoui Faid 

Cherahil 

Reineche 

El Garia 

Tselja 

Bou Dabbous 

Halk 

El 

Menzel 

Souar 

Souar 

El Haria 

Berda Abiod Merfeg Abiod

Aleg Kef Miskar Douleb 

Bireno 

Bahloul 

Beida 

Zebbag 

Lower Fahdene (Mouelha) 

Isis Upper Fahdene

Hameima 

Orbata Serdj

Sidi Aïch 

Boudinar 

DL 101 

Bouhedma/Mrhila M'Cherga 

Asf Meloussi er 

Sidi Khalif 

Ressas 

Upper Nara M'Rabtine 

Sebaia Tlalett Smida Kh. El Miit F. Tat. Brourmet Techout 

Krachoua 

Middle Nara 

Mestaoua 

Abreghs 

Zmilet Haber (B Horizon) 

Bhir Lower Nara/Oust

Adjadj Messaoudi 

"Trias Evaporitique" Rheouis Mhira 

TAGS 

Rehach 

Touareg 

Mekraneb 

Azizia/"Trias Carbonate" 

Kirchaou Trias Argilo-Greseux Inferieur (TAGI) 

Ouled Chebbi 

Bir Mastoura/Bir El Jaja H

Un

A

Un

O

Un

P

Un

BrePa

Tetprojoin spr

Racen

ReLocMorela

De

ComicNo

5.5 

11 

16.5 

24 

36 

55 

66 

100 

140 

160 

183 

210 

230 

242 

250 

Ma Chronostratigraphy Lithostratigraphy, Tunisia T

Mahmoud 

Oum 

Douil 

Alalgah 

Makhbaz 

Jamil 

Bu Isa 

Volcanics 

Volcanics 

Al Jurf Ehduz 

FBilal arwah 

Group 

Telil 

Group 

Taljah Jirani Dolo. 

Dahman Lst. 

Samdun Ghalil 

Tajoura Hallab

Nummulites vascus Zone 

Dirbal 

Ras Abdjalil 

Al Mayah 

Bir Sharuf Tubtah Sidi Bannour

Marsa Zouaghah 

Sbabil Assabria 

Jdeir 

Chouabine 

Lithostratigraphy, Offshore Libya 

Pr

Un

Gattar 

M 

L 

E 

Melquar

Zelf

Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta 

Oil NGL Gas Proven carbonate 

reservoirs Seal marking the Potential carbonate stratigraphic extent reservoirs of TPS's 

Proven clastic Source rocks reservoirs 

Possible 

Potential clastic reservoirs source rocks 

Figure 6. Columnar section, stratigraphic nomenclature, tectonic events, and petroleum occurrence for Tunisia and offshore Libya (modified from E

Pétrolières, 1997; Hammuda and others, 1991). Stratigraphic column for Tunisia represents all areas of Tunisia, including the Pelagian Province (2048TPS, total petroleum system. 
represented by glauconitic and phosphatic beds (Burollet and 

others, 1978; Bishop, 1988). Above and partially equivalent to 

the Chouabine Formation are rock units that represent a continuous set of lagoonal to open-marine depositional facies. These 

units include the Faid Formation, representing an evaporitic 

anhydrite and dolostone facies; the Ain Merhotta Formation, 

restricted shelf gastropod facies (not shown in fig. 6); the El 

Garia Formation, shallow-shelf nummulitid facies; and the Bou 

Dabbous Formation, deep-water globigerinid facies (Bishop, 

1988; Loucks and others, 1998). The Libyan Jirani Dolomite 

and Jdeir Formation are laterally equivalent to the Metlaoui 

Group (fig. 6). 

Rocks of the middle to upper Eocene are mudstone and 

limestone of the Souar Formation, and are laterally equivalent to 

evaporites of the Jebs Formation (Bishop, 1988). Some 

coquinoid nummulitic carbonate rocks are present in the Souar 

Formation, such as the Lutetian Reineche Formation (fig. 6) 

(Bishop, 1975). The Oligocene Unconformity marks the top of 

the Souar and laterally equivalent formations. 

Immediately overlying the Oligocene Unconformity is 

mudstone with interbedded fine-grained sandstone containing 

some nummulitic limestones, called the Nummulites vascus 

horizon (Bishop, 1975; Burollet and others, 1978; Salaj, 1978; 

Hammuda and others, 1991). 

Rocks representing a succession of terrigenous to marine 

depositional facies overlie the Nummulites vascus horizon 

(Bishop, 1975; Burollet and others, 1978; Salaj, 1978). Each 

depositional facies type carries a different formation name. The 

most landward formation is the Fortuna Formation, capped by 

continental rocks of the Messiouta Formation. Nearshore 

marine rocks are represented by limestone of the Ketatna Formation, which interfingers with offshore mudstone of the Salammbo Formation (Schwab, 1995). The Libyan equivalents to the 

Ketatna and Salammbo Formations are the Dirbal and Ras Abdjalil Formations (Hammuda and others, 1991) (fig. 6). The ages 

of all these formations range from Rupelian to Burdigalian 

(Oligocene to Miocene; fig. 6). Tectonic activity during the late 

Oligocene and early Miocene resulted in erosion and nondeposition. Basal Miocene sediments are commonly conglomeritic 

and unconformably overlie older sediments (Burollet, 1967b). 

Upper Miocene rocks include (1) the transgressive limestone of the Aïn Grab Formation; (2) marls of the Mahmoud 

Formation; (3) a sandy sequence represented by the Beglia, 

Saouaf, Birsa, Oum Douil, and part of the Segui Formations; 

and (4) lagoonal and brackish-water sediments (including anhydrite; Jongsma and others, 1985) of the Messinian Oued Bel 

Khedim and Marsa Zouaghah Formations (Burollet and others, 

1978; Salaj, 1978) (fig. 6). The top of the Miocene is marked by 

an angular unconformity, above which lower Pliocene sediments 

were deposited during marine transgression (Bishop, 1975; 

Burollet and others, 1978). 

During the Pliocene, strong local subsidence occurred in 

troughs and basins, into which thick accumulations of terrigenous and marine clastic sediments were deposited (Bishop, 

1975; Burollet and others, 1978). Formations include the Raf 

Raf and Porto Farina Formations, both laterally equivalent to 

parts of the Segui and Sbabil Formations (fig. 6). 

Quaternary deposits include clastic terrigenous and marine 

sediments (Burollet and others, 1978). 

Regional Exploration Activity 

As of 1996, more discoveries were made in reservoirs of 

the Bou Dabbous–Tertiary Total Petroleum System than in reservoirs of the Jurassic-Cretaceous Composite (figs. 2 and 3). 

Most of the larger oil and gas fields in both total petroleum systems were discovered since 1970 (Appendices 1 and 2), 

although a few earlier discoveries had been made in the JurassicCretaceous Composite Total Petroleum System. 

Most of the exploration in Tunisia was in the Pelagian 

Province, beginning in the early 1950’s. Fewer than 10 newfield wildcat wells were drilled in most years until the early 

1970’s. Since the early 1970’s, however, the number of newfield wildcat wells drilled per year increased, and the number 

peaked in the early 1980’s to more than 20 new-field wildcat 

wells per year; drilling then generally decreased until the middle 

1990’s. Exploration by foreign companies in Tunisia between 

the early 1960’s and the 1970’s was limited. Throughout the 

1970’s and 1980’s, however, Tunisia revised its legislation and 

introduced measures to encourage foreign companies to explore 

and develop oil and gas resources (Davies and Bel Haiza, 1990; 

Montgomery, 1994). 

In the Libyan portion of the Pelagian Province, exploration 

activity appeared greatest in the early 1960’s with about six to 

seven new-field wildcat wells per year and again from the late 

1970’s to early 1980’s with as many as six new-field wildcat 

wells per year. Few new-field wildcat wells were drilled from 

the mid 1980’s to 1996. 

In 1955, the Libyan government implemented the Libyan 

Petroleum Law, designed to attract foreign interest (Nelson, 

1979). In the early 1970’s, however, the Petroleum Law was 

amended as a result of nationalization of oil companies, thereby 

reducing the control of oil- and gas-related activities by foreign 

companies. Furthermore, U.S. and U.N. sanctions imposed on 

Libya in the late 1980’s and early 1990’s discouraged foreign 

participation and restricted the available resources required for 

exploration and development (Arab Petroleum Research Center, 

1998; Petzet, 1999). In the late 1980’s, however, new terms to 

encourage foreign interest were introduced, which were still in 

effect as of 1996. 

From the late 1970’s until the late 1980’s, the exploration 

and production of fields in a portion of offshore Tunisia and 

Libya were suspended pending adjudication of the TunisianLibyan demarcation line in the Gulf of Gabes (Nelson, 1979). 

The conflict was resolved in 1988 when Libya and Tunisia 

agreed to create a joint oil exploration company to operate in 

this area (called the 7th November concession) (Arab Petroleum 

Research Center, 1998). 

A large portion of the Pelagian Province is offshore (fig. 1), 

and water depths in that portion are generally less than 400 m. 

The greatest water depth is in the Malta Trough, which has a 

maximum depth of 1,715 m (Jongsma and others, 1985). As of 

1996, wells were drilled in water as deep as 351 m (Petroconsultants, 1996a). 

A basic infrastructure has been established in the Pelagian 

Province whereby tanker terminals and a pipeline network are 

capable of transporting petroleum from most of the major producing fields to port cities in Tunisia and Libya (Arab Petroleum 

Research Center, 1998). 

Regional Exploration Activity 13 
Province Name: P

elagian Basin (2048) TPS Name: Bou Dabbous-Tertiary (204801) 

Author(s): 

T.R. Klett Date: 9-3-99 

Cretaceous 

ROCK UNIT 

SOURCE ROCK 

RESERVOIR ROCK 

SEAL ROCK 

OVERBURDEN ROCK 

TRAP FORMATION 

GENERATIONPRESERVATION 

CRITICAL MOMENT 

PETROLEUM 

SYSTEM EVENTS 

GEOLOGIC TIME 

SCALE 

0 

100 

200 

50 

150 

250 

Paleogene 

Jurassic 

Triassic 

Permian 

65 

E 

E 

E 

E 

M 

M 

L 

L 

L 

L 

Neogene 

24 

Pal 

Eoc 

Olig 

Mio 

Plio 

ACCUM

ULATION 

M

IGRATION•

BRS 

AG 

KET 

REI 

JDE 

BOU 

144 

Figure 7. Events chart for Bou Dabbous–Tertiary Total Petroleum System (204801). 

BRS, Birsa; AG, Aïn Grab; KET, Ketatna; REI, Reineche; JDE, Jdeir, BOU, Bou Dabbous. 

The Bou Dabbous–Tertiary Total Petroleum 

System (204801) 

The Bou Dabbous–Tertiary Total Petroleum System 

extends from northern Tunisia to offshore Libya, from the northwest to the southeast portion of the Pelagian Province (figs. 1 

and 2). This total petroleum system and corresponding assessment unit generally coincide with the potential extent of petroleum being generated by, and migrating from, Eocene (Bou 

Dabbous) source rocks. Where present, the Upper Cretaceous 

to Paleocene El Haria mudstone separates this total petroleum 

system from the underlying Jurassic-Cretaceous Composite 

Total Petroleum System. An events chart (fig. 7) summarizes 

14 Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta 
the ages of source, reservoir, and seal rocks; the timing of trap 

development; and generation and migration of petroleum. 

Eocene extension and fault reactivation controlled the distribution of depositional facies of the Metlaoui Group (Morgan 

and others, 1998). Neogene subsidence resulted in deposition of 

turbidite-fan deposits and invoked maturation of Cretaceous and 

Eocene source rocks and petroleum migration (Bédir and others, 

1992). Petroleum migration most likely occurred from late 

Miocene to Quaternary (Bédir and others, 1992). Potential traps 

for petroleum accumulations were developed in the late 

Miocene and Quaternary as a result of compression by reactivating older structures (Bédir and others, 1992). 

Several fields with reported production from Oligocene 

and Miocene reservoirs exist in the Gulf of Hammamet where 

the Bou Dabbous source rocks have not been mapped (figs. 2, 4, 

and 8). Although the Bou Dabbous Formation is assumed to be 

the most likely source rock, Cretaceous source rocks may have 

been a major supply of petroleum to these fields. If this is the 

case, then a portion of the discovered and undiscovered petroleum included with the Bou Dabbous–Tertiary Total Petroleum 

System (approximately 8 to 10 percent of the known oil and 3 

to 5 percent of the known gas; approximately 10 to 25 percent 

of the undiscovered oil and 5 to 25 percent of the undiscovered 

gas) should be included with the Jurassic-Cretaceous Total 

Petroleum System. 

Source Rocks 

The primary source rock is dark-brown marl and mudstone 

of the lower Eocene (Ypresian) Bou Dabbous Formation (or lateral equivalents) (Macgregor and Moody, 1998; Entreprise 

Tunisienne d’Activités Pétrolières, c. 1999). Various authors 

have mapped the extent of the Bou Dabbous Formation differently (compare figs. 4 and 8). However, this formation generally 

follows an arcuate and elongate trend extending from the northwest to the southeast portions of the province (fig. 2). 

The Bou Dabbous Formation contains type I and II kerogen 

and ranges in thickness from 50 to 300 m (Entreprise Tunisienne 

d’Activités Pétrolières, c. 1999). Total organic carbon content 

(TOC) of the Bou Dabbous ranges from 0.4 to 4 percent, and 

maturation is described as early mature to mature (Entreprise 

Tunisienne d’Activités Pétrolières, c. 1999). This source rock 

most likely became mature in the Miocene to Pleistocene (Bédir 

and others, 1992), and the generated petroleum migrated laterally into adjacent, juxtaposed reservoirs and vertically along 

faults or fractures. 

The API gravity of oil generated from the Bou Dabbous 

source rock ranges from 18o to 53o; the mean is 36o (Petroconsultants, 1996a; GeoMark, 1998). Sulfur content ranges from 

0.2 to 0.6 percent; the mean is 0.4 percent (GeoMark, 1998). 

Overburden Rocks 

Overburden rocks are variable across the Pelagian Province 

area mainly due to erosion and nondeposition during the Oligocene and Pliocene deformation (fig. 5C). Eocene, Miocene, 

and Pliocene rocks make up most of the overburden. In some 

areas, large portions of the Paleogene section (Paleocene, 

Eocene, and Oligocene) were removed by erosion during preMiocene deformation (fig. 5C). Smaller portions of Miocene 

rocks were removed, in turn, by erosion before and during the 

Pliocene. Both Mesozoic and Cenozoic rocks are thickest in the 

Ashtart-Tripolitania Basin and in the central part of the Gulf of 

Hammamet. A Quaternary section of variable thickness covers 

much of the area. 

Reservoir Rocks 

Known reservoir rocks include members of the lower 

Eocene Metlaoui Group (the laterally equivalent members of 

Bou Dabbous Formation), such as the El Garia fractured limestone; Jirani dolostone, Jdeir limestone, and Reineche limestone, as well as the Oligocene to Miocene Ketatna limestone 

and the middle Miocene Aïn Grab limestone and Birsa sandstone. The Oligocene to Miocene Fortuna sandstone may be a 

potential reservoir. Figure 8 shows the distribution of the Metlaoui Group reservoirs and source rock, as well as locations of 

fields having reported oil and gas in reservoirs of the Bou Dabbous–Tertiary Total Petroleum System. Names of laterally 

equivalent rock units are given in figure 6, and known reservoir 

properties are given in table 2. 

Volumetrically, most of the discovered petroleum, as of 

1996, is in Metlaoui Group reservoirs (approximately 1,900 

MMBO and 15,000 BCFG), although a significant volume of 

petroleum was discovered in Miocene-age reservoirs (approximately 175 MMBO and 400 BCFG). 

Seal Rocks 

Seals include Eocene and Miocene mudstone and carbonate rocks (compact micrite, for example) (Entreprise Tunisienne 

d’Activités Pétrolières, c. 1999). Mudstone of the Cherahil and 

Souar Formations and their lateral equivalents provide seals for 

many of the Eocene reservoirs (Macgregor and Moody, 1998). 

Trap Types in Oil and Gas Fields 

Generally, traps were developed by the formation of horst 

blocks and associated pinchouts during the Cretaceous to Paleocene, by reactivation of these horsts during the Miocene to 

Quaternary (fig. 9A), and by folding and subsequent faulting 

(fig. 9B) (Bédir and others, 1992; Entreprise Tunisienne 

d’Activités Pétrolières, c. 1999). Most of the discovered oil and 

gas fields (having reported petroleum in reservoirs within the 

Bou Dabbous–Tertiary Total Petroleum System as of 1996) are 

associated with low-amplitude anticlines, high-amplitude anticlines associated with reverse faults (inversion anticlines), 

wrench fault structures, and stratigraphic features (Petroconsultants, 1996a; Entreprise Tunisienne d’Activités Pétrolières, c. 

1999). Accumulations in combination structural-stratigraphic 

traps are also common. Potential traps may be associated with 

The Bou Dabbous–Tertiary Total Petroleum System (204801) 15 
9°E 11°E 

37° 

LIBYA 

TUNISIA 

ALGERIA 

0 100 KILOMETERS 

Mediterranean 

Sea 

Gulf of 

Hammamet 

Gulf of 

Gabes 

Oil field 

Gas field 

Nummulitid wackestone/packstone/grainstone 

Nummulithoclastic packstone 

Bioclastic wackestone with Nummulites debris 

Gastropod coquina 

Globigerinid mudstone/marl (Bou Dabbous) 

Red algal-echinoid packstone/grainstone 

Lagoonal/supratidal mudstone/wackestone and dolostone 

Evaporite, some with terrigenous clastics 

EXPLANATION 

35° 

33° 

Figure 8. Lithofacies map of the Metlaoui Group (excluding the Chouabine and Tselja Formations) and locations of fields with reported oil 

and gas volumes in Bou Dabbous–Tertiary Total Petroleum System (204801) (modified from Bishop, 1988; Petroconsultants, 1996b). Dashed 

lines, approximate location. White areas, rock section is absent. 

16 Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta 
Table 2. Reservoir properties of discovered accumulations for each assessment unit in the Pelagian Province (2048) through 1995. 

[nd, either no data or insufficient data. Data from Petroconsultants (1996a)] 

The Bou Dabbous–Tertiary Total Petroleum System (204801) 17

1,000 

2,000 

3,000 

4,000 

Depth (m) 

1,000 

Depth (m) 

1,500 

2,000 

Southwest 

West East 

Northeast 

Kerkennah West Permit 

Ezzaouia Field 

El Biban Field 

Metlaoui Fm 

Top Cenomanian 

M Zebbag anhydrite 

M Zebbag dolostone 

Top Cretaceous Unconformity 

Lower Zebbag 

Orbata Fm 

Sidi Aïch Fm 

Bouhedma Fm

Meloussi Fm 

Top Jurassic 

M'Rabtine Fm 

Sidi Aïch, Bouhedma, 

and Meloussi Fms 

Upper M'Rabtine Fm

Top Jurassic 

M Zebbag 

anhy 

L Zebbag

Orbata Fm 

A 

B 

Neogene and Quaternary 

tension and reactivation 

Eocene strike slip, 

extension 

Cretaceous erosion 

Jurassic and Cretaceous uplift 

Figure 9. Diagrams illustrating selected trap styles in Pelagian Province (2048). A, Schematic cross section through Kerkennah West Permit, 

onshore eastern Tunisia (modified from Bishop, 1988). B, Schematic cross section through Ezzaouia (onshore) and El Biban (offshore) fields, 

southern Tunisia (modified from Entreprise Tunisienne d’Activités Pétrolières, c. 1999). Red, gas accumulation; green, oil accumulation. No 

horizontal scale. 

salt ridges and diapirs (Entreprise Tunisienne d’Activités 

Pétrolières, c. 1999), as well as Paleogene stratigraphic 

pinchouts and turbidites above and below the Oligocene 

Unconformity (Bédir and others, 1992). The locations of major 

faults (mostly extensional) and major anticlines in Tunisia and 

offshore areas to the east, as well as field locations, are shown in 

figure 10. Fault systems in the Gulf of Gabes area trend 

generally northwest-to-southeast, whereas fault systems in the 

Gulf of Hammamet area trend generally west-to-east. 

Assessment of Undiscovered Petroleum 

One assessment unit was identified for the Bou Dabbous– 

Tertiary Total Petroleum System, the Bou Dabbous–Tertiary 

Structural/Stratigraphic Assessment Unit (20480101) (fig. 2). 

As of 1996, forty-six fields reported petroleum volumes in reservoirs of the corresponding total petroleum system, and these 

fields are allocated to this assessment unit. Of these, 27 are oil 

18 Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta 
10°E 

36° 

34° 

32° 

0 100 KILOMETERS 

V 

V 

V 

V 

V V 

V 

V 

V 

V V 

V 

V V 

V 

V 

V 

V 

V 

V 

V 

V 

VC 

VC 

Talemzane-Gefara Arch 

Country boundary 

Extensional or strike-slip faults 

Oil field 

Gas field 

Compressional fault 

Oil and gas field 

V 

VC Cenozoic volcanism 

Mesozoic volcanism 

Major anticline 

Major graben 

Outcropping Triassic extrusives 

Subsurface salt diapirs 

Deep fault 

TUNISIA 

Mediterranean 

Sea 

LIBYA 

ALGERIA 

ALGERIA 

Gulf of 

Gabes 

Gulf of 

Hammamet 

Figure 10. Major faults and anticlines in Tunisia, as well as locations of oil and gas fields (modified from Entreprise Tunisienne 

d’Activités Pétrolières, 2000). Dashed lines, approximate location; hachured lines, faults showing direction of down-thrown blocks. 

The Bou Dabbous–Tertiary Total Petroleum System (204801) 19 
fields, 14 are gas fields, and 5 fields are not classified because 

they contained less than 1 MMBOE. Combined, these fields 

contained 2,114 MMBO, 15,509 BCFG, and 44 MMBNGL, as 

known volumes (table 1) (Petroconsultants, 1996a). Minimum 

field sizes of 4 MMBO and 24 BCFG were chosen for this 

assessment unit based on the field-size distribution of discov�

ered fields. 

At the end of 1995, the exploration density was approxi�

mately 15 new-field wildcat wells per 10,000 km2. Exploration 

activity was not consistent through time, peaking from the 

1970’s to the early 1980’s, and experiencing a resurgence start�

ing in the early 1990’s. Exploration appears to be in a moder

ately mature stage across much of the area. The overall success 

rate has been approximately 26 discoveries per 100 new-field 

wildcat wells (or about one discovery per four new-field wildcat 

wells). As of 1996, offshore fields existed in water depths that 

range from about 4 to 350 m, averaging about 135 m. The sizes 

of oil and gas fields discovered have generally decreased through 

time and with respect to exploration activity. Trends in field 

sizes or number of discoveries with respect to exploration activ�

ity (number of new-field wildcat wells drilled) are not apparent. 

Plots showing exploration activity and discovery history are pre�

sented in Appendix 1. 

Exploration of structural and combination traps is 

expected to continue, and many more fields, both oil and gas, 

could be discovered. Discoveries in structural and stratigraphic 

traps involving the Metlaoui Group reservoirs are likely to be 

smaller than existing accumulations, whereas discoveries in the 

Birsa sandstone may contribute larger volumes to reserves than 

in the past. Stratigraphic traps involving the Fortuna sandstone 

and lateral equivalents may also contain important 

accumulations. 

This study estimates that about one-half of the total number 

of fields (discovered and undiscovered) of at least the minimum 

size has been discovered. The estimated median size and num�

ber of undiscovered oil fields are 12 MMBO and 30 fields; the 

same values for undiscovered gas fields are 60 BCFG and 15 

fields. The ranges of number, size, and coproduct-ratio esti�

mates for undiscovered fields are given in table 3. 

The estimated means of the undiscovered conventional 

petroleum volumes are 667 MMBO, 2,746 BCFG, and 64 

MMBNGL (table 4). The mean size of the largest anticipated 

undiscovered oil and gas fields is 110 MMBO and 283 BCFG, 

respectively. 

The Jurassic-Cretaceous Composite Total 

Petroleum System (204802) 

The Jurassic-Cretaceous Composite Total Petroleum Sys�

tem extends across most of the Pelagian Province. This sys�

tem and corresponding assessment unit (Jurassic-Cretaceous 

Structural/Stratigraphic Assessment Unit, 20480201) generally 

coincide with the potential extent of petroleum migration from 

Jurassic and Cretaceous source rocks. As mentioned previ�

ously, the Upper Cretaceous to Paleocene El Haria mudstone 

separates this total petroleum system from the overlying 

Tertiary total petroleum system. Where the El Haria 

mudstone is absent in the southern part of the Pelagian Prov�

ince, the total petroleum system boundary is approximated by 

the Cretaceous-Paleocene boundary. Triassic evaporites and 

Lower Jurassic carbonate rocks separate this total petroleum 

system from any underlying systems. An events chart (fig. 11) 

summarizes the ages of source, reservoir, and seal rocks; the 

timing of trap development; and generation and migration of 

petroleum. 

During the Jurassic and Early Cretaceous, faulting and 

strong local subsidence defined deep-water basins separated by 

uplifted fault blocks, which consisted of slope and carbonate 

platform deposits (Morgan and others, 1998). The deep-water 

basins allowed deposition of organic-rich sediments and 

turbidite fan deposits (Bédir and others, 1992; Morgan and 

others, 1998). 

Transpression and inversion during the Late Cretaceous 

and Paleogene caused uplift and erosion of carbonate platforms that formed previously along fault zones. These struc�

tural events, as well as more recent deformation, provided traps 

for petroleum accumulations (Bédir and others, 1992; Morgan 

and others, 1998). Petroleum generation occurred throughout 

the Tertiary. 

Source Rocks 

The primary source rocks are mudstone of the Jurassic 

Nara Formation, Lower Cretaceous M’Cherga Formation, 

Albian Lower Fahdene Formation, and Cenomanian to Turonian 

Bahloul Formation. According to Entreprise Tunisienne 

d’Activités Pétrolières (c. 1999), the Jurassic Nara Formation 

source rock exists in an elongated northwest to southeast trend 

from central Tunisia through the Gulf of Gabes and extending 

along the coast into Libya. Cretaceous source rocks are present 

throughout much of the Pelagian Province, although the distri�

bution of the Bahloul Formation is limited to an arcuate and 

elongate, northwest to southeast trend (fig. 4). Combined, one 

or more of the Jurassic and Cretaceous source rocks are present 

across most of the province. 

Source rock properties are described by Entreprise Tunisi�

enne d’Activités Pétrolières (c. 1999) as follows: 

1. The Nara Formation source rocks are thin black mudstone with alternating limestone; approximately 80 m thick; 

contain as much as 2 percent TOC; maturation described as 

mature to late mature. 

2. The M’Cherga Formation source rocks are light- to 

dark-gray calcareous and dolomitic mudstone containing type II 

kerogen; as much as 100 m thick; contain 0.2–3 percent TOC; 

maturation described as mature to late mature. 

3. The Lower Fahdene Formation source rocks are dark 

pelagic marl with interbedded limestone containing type II and 

III kerogen; as much as 150 m thick; contain 0.5–3 percent 

TOC; maturation described as early mature to mature. 

4. The Bahloul Formation source rocks are laminated 

black argillaceous limestone containing type II kerogen; 

approximately 20 m thick; contain as much as 14 percent TOC; 

maturation described as early mature to mature. 

20 Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta 
Table 3. Estimated sizes, number, and coproduct ratios of undiscovered oil and gas fields for each assessment unit in the Pelagian Pr

[MMBO, million barrels of oil; BCFG, billion cubic feet of gas; CFG/BO, cubic feet of gas per barrel oil, not calculated for gas fields; BNGL/MMCFliquids or barrels of total liquids per million cubic feet of gas. BNGL/MMCFG was calculated for USGS-defined oil fields whereas BL/MMCFG was 

Shifted mean, mean size of accumulation within a lognormal distribution of field sizes for which origin is selected minimum field size] 

The Jurassic-Cretaceous Composite Total Petroleum System (204802) 21

22
Table 4. Estimated undiscovered conventional oil, gas, and natural gas liquids volumes for oil and gas fields for each assessment 

[MMBO, million barrels of oil; BCFG, billion cubic feet of gas; NGL, natural gas liquids; MMBNGL, million barrels of NGL. 

Volumes of undisc

whereas volumes of total liquids (oil plus NGL) were calculated for USGS-defined gas fields. Largest anticipated undiscovered field is in units of 

fields. Results shown are estimates that are fully risked with respect to geology and acccessibility. Undiscovered volumes in fields smaller than th

excluded from the assessment. Means can be summed, but fractiles (F95, F50, and F5) can be summed only if a correlation coefficient of +1.0 is a

Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta 
Province Name: Pelagian Basin (2048) TPS Name: J

urassic-Cretaceous Composite (204802) 

Author(s): 

T.R. Klett Date: 9-3-99 

Cretaceous 

ROCK UNIT 

SOURCE ROCK 

RESERVOIR ROCK 

SEAL ROCK 

OVERBURDEN ROCK 

TRAP FORMATION 

GENERATIONPRESERVATION 

CRITICAL MOMENT 

PETROLEUM 

SYSTEM EVENTS 

GEOLOGIC TIME 

SCALE 

0 

100 

200 

50 

150 

250 

Paleogene 

Jurassic 

Triassic 

Permian 

65 

144 

E 

E 

E 

E 

M 

M 

L 

L 

L 

L 

Neogene 

24 

Pal 

Eoc 

Olig 

Mio 

Plio 

ACCUMULATION MIGRATIONMCH/SA 

SRJ 

LF 

BAH 

ZEB 

EH 

BIR 

DOU 

AB 

MEL 

MR 

NA 

NA 

? 

? 

Figure 11. Events chart for Jurassic-Cretaceous Composite Total Petroleum System 

(204802). Query means extent uncertain. EH, El Haria; AB, Abiod; DOU, Douleb; BIR, Bireno; BAH, Bahloul; ZEB, Zebbag; LF, Lower Fahdene; SRJ, Serdj; MCH, M’Cherga; SA, 

Sidi Aïch; MEL, Meloussi; MR, M’Rabtine; NA, Nara. 

Oil generation from the Nara Formation probably began in 

the early Tertiary (fig. 11), although generation may have begun 

as early as the Late Cretaceous in deeper basins (Bédir and 

others, 1992). Peak petroleum generation of the other source 

rocks generally occurred during the Miocene to Pliocene 

(Entreprise Tunisienne d’Activités Pétrolières, c. 1999). Petro�

leum migrated vertically along faults and fractures, and laterally 

into adjacent reservoirs. 

The Jurassic-Cretaceous Composite Total Petroleum System (204802) 23

The API gravity of oil generated from the Jurassic and 

Cretaceous source rock ranges from 28o to 37o; the mean is 33o 

(Petroconsultants, 1996a; GeoMark, 1998). The sulfur content 

ranges from 0.2 to 0.4 percent, with a mean of 0.3 percent 

(GeoMark, 1998). 

Overburden Rocks 

Cretaceous and Cenozoic rocks make up most of the overburden. As with the overlying Bou Dabbous–Tertiary Total 

Petroleum System, overburden rocks are variable across the area 

(fig. 5). In addition to strata removed by erosion during the Cen�

ozoic (previously described in the Bou Dabbous–Tertiary Total 

Petroleum System section), minor amounts of Lower Cretaceous 

and Upper Cretaceous to Paleocene rocks are also absent (figs. 

5B and 6). 

Reservoir Rocks 

Known reservoir rocks include: (1) Middle to Upper Juras�

sic Nara Formation dolomite or dolomitic limestone and M'Rab�

tine sandstone; (2) Lower Cretaceous Meloussi and Sidi Aïch 

sandstone and Orbata and Serdj carbonates; and (3) Upper Cre�

taceous Zebbag, Isis, and Bireno, Douleb, and Miskar carbon�

ates and Abiod fractured chalk (table 2, fig. 6). Figure 12 shows 

the distribution of Zebbag Formation reservoirs, as well as loca�

tions of fields having reported oil and gas volumes from reser

voirs within the Jurassic-Cretaceous Composite Total Petroleum 

System. 

Most of the discovered oil volumes in this total petroleum 

system, as of 1996, appears to be in Lower Cretaceous Bireno 

(approximately 38 MMBO) and Jurassic (approximately 34 

MMBO) reservoirs, whereas most of the discovered gas appears 

to be in Upper Cretaceous Abiod fractured reservoirs (approxi�

mately 1,000 BCFG). 

Seal Rocks 

Seals include Upper Jurassic to Lower Cretaceous mudstone of the M’Cherga Formation; various Lower to Upper Cre�

taceous mudstone and carbonate rocks, including Aleg 

mudstone; and Upper Cretaceous to Paleocene El Haria mudstone (Macgregor and Moody, 1998; Entreprise Tunisienne 

d’Activités Pétrolières, c. 1999). 

Trap Types in Oil and Gas Fields 

As with the Bou Dabbous–Tertiary Total Petroleum 

System, trap types of known accumulations include fault blocks, 

low-amplitude anticlines, high-amplitude anticlines associated 

with reverse faults (inversion anticlines), wrench fault structures, 

and stratigraphic traps (fig. 9A and B). Volumetrically, most of 

the discovered oil in the Jurassic-Cretaceous Total Petroleum 

System appears to be in anticlinal traps, whereas most of the 

discovered gas appears to be in fault-related traps. 

Assessment of Undiscovered Petroleum 

One assessment unit was identified for the Jurassic-Creta�

ceous Composite Total Petroleum System, Jurassic-Cretaceous 

Structural/Stratigraphic Assessment Unit (20480201) (fig. 3). 

As of 1996, twenty-six fields reported petroleum volumes in 

reservoirs of the corresponding total petroleum system, and 

these fields are allocated to this assessment unit. Of these dis�

covered fields, 11 are oil fields, 6 are gas fields, and 9 fields are 

not classified because they contain less than 1 MMBOE. Com�

bined, these fields contain 103 MMBO, 1,301 BCFG, and 23 

MMBNGL, as known volumes (table 1) (Petroconsultants, 

1996a). Minimum field sizes of 1 MMBO and 6 BCFG were 

chosen for this assessment unit based on the field-size distribu�

tion of discovered fields. 

At the end of 1995, the exploration density was approxi�

mately eight new-field wildcat wells per 10,000 km2. Explora�

tion activity has been variable through time and appears to be in 

an immature stage. The overall success rate is approximately 14 

discoveries per 100 new-field wildcat wells (or about one dis�

covery per seven new-field wildcat wells). As of 1996, offshore 

fields existed in water depths that range from about 5 to 82 m, 

averaging about 46 m. The size and number of oil fields appear 

to have increased with respect to exploration activity, whereas 

trends for gas fields were not apparent. Additionally, more 

recent oil field discoveries have been made at shallower depths. 

Plots showing exploration activity and discovery history are pre�

sented in Appendix 2. 

Exploration for structural and combination traps is 

expected to continue, resulting in the probable discovery of 

more fields, both oil and gas. Discoveries in structural and 

stratigraphic traps involving Zebbag (and lateral equivalents), 

Douleb, and Abiod reservoirs will most likely continue as 

exploration progresses seaward into deeper water. Some of 

these discoveries may be substantial. More discoveries may 

also be made in Jurassic rocks, but these may be few and small 

due to the limited extent of mature source rocks and reservoirs. 

This study estimates that about one-fourth of the total num�

ber of fields (discovered and undiscovered) of at least the minimum size has been discovered to date. The estimated median 

size and number of undiscovered oil fields are 5 MMBO and 38 

fields; the same values for undiscovered gas fields are 25 BCFG 

and 28 fields. The ranges of number, size, and coproduct-ratio 

estimates for undiscovered fields are given in table 3. 

The estimated means of the undiscovered conventional 

petroleum volumes are 403 MMBO, 2,280 BCFG, and 27 

MMBNGL (table 4). In addition, the mean size of the largest 

anticipated undiscovered oil and gas fields is 66 MMBO and 

285 BCFG, respectively. 

24 Total Petroleum Systems, Pelagian Province, Tunisia, Libya, Italy, Malta 
9°E 11°E 

37° 

? 

? 

? 

? 

LIBYA 

TUNISIA 

TUNISIA 

ALGERIA 

Transitional 

Fault 

Shelf calcarenite 

Dolostone and dolomitic limestone (mostly supratidal?) 

Anhydrite 

Basinal 

Conglomerate 

0 100 KILOMETERS 

Mediterranean 

Sea 

Oil field 

Gas field 

Gulf of 

Hammamet 

Gulf of 

Gabes 

35° 

33° 

Figure 12. Lithofacies map of the Zebbag Formation and locations of fields with reported oil and gas volumes in Jurassic-Cretaceous 

Composite Total Petroleum System (204802) (modified from Bishop, 1988; Petroconsultants, 1996b). White areas, rock section is absent. 

Queries mean extent uncertain. 

The Jurassic-Cretaceous Composite Total Petroleum System (204802) 25 
Summary 

Two “composite” total petroleum systems, the Bou Dabbous–Tertiary and Jurassic-Cretaceous Composite, are identified 

in the Pelagian Province (2048). The Bou Dabbous–Tertiary 

Total Petroleum System (204801) and corresponding assessment 

unit coincide with the potential extent of petroleum migration 

from Eocene source rocks. The Jurassic-Cretaceous Composite 

Total Petroleum System (204802) and corresponding assessment 

unit coincide with the potential extent of petroleum migration 

from Jurassic and Cretaceous source rocks. The Upper Cretaceous to Paleocene El Haria mudstone separates the two total 

petroleum systems over much of the area. 

It is likely that much of the petroleum in the Gulf of Hammamet area was derived from Cretaceous source rocks. If this is 

the case, then the discovered and undiscovered oil and gas volumes of the Bou Dabbous–Tertiary Total Petroleum System 

should be included in the Jurassic-Cretaceous Composite Total 

Petroleum System. 

The primary source rock of the Bou Dabbous–Tertiary 

Total Petroleum System is dark-brown marl and mudstone of the 

lower Eocene Bou Dabbous Formation, which became mature in 

the Miocene to Pleistocene. Known reservoir rocks include lateral equivalents of the lower Eocene Bou Dabbous Formation, 

such as the El Garia fractured limestone; Eocene Jirani dolostone, Jdeir limestone, and Reineche limestone; Oligocene to 

Miocene Ketatna limestone; and the middle Miocene Aïn Grab 

limestone and Birsa sandstone. Seals include Eocene and 

Miocene mudstone and carbonate rocks. Known accumulations 

are in fault blocks, low-amplitude anticlines, high-amplitude 

anticlines associated with reverse faults, wrench fault structures, 

and stratigraphic traps. 

The primary source rocks of the Jurassic-Cretaceous Composite Total Petroleum System include mudstone of the Jurassic 

Nara Formation, Lower Cretaceous M’Cherga and Lower Fahdene Formations, and Upper Cretaceous Bahloul Formation. Oil 

generation probably began in the early Tertiary, and peak petroleum generation likely took place in the Miocene and Pliocene. 

Known reservoir rocks include the Nara Formation dolomite or 

dolomitic limestone; Upper Jurassic M’Rabtine sandstone; 

Lower Cretaceous Meloussi and Sidi Aïch sandstone and Orbata 

and Serdj carbonates; and Upper Cretaceous Zebbag, Isis, 

Bireno, Douleb, and Miskar carbonates and Abiod chalk. Seals 

include Upper Jurassic to Lower Cretaceous mudstone of the 

M’Cherga Formation, various Lower to Upper Cretaceous mudstone and carbonate rocks, and the Upper Cretaceous to Paleocene El Haria mudstone. Trap types of known accumulations 

include fault blocks, low-amplitude anticlines, high-amplitude 

anticlines associated with reverse faults, wrench fault structures, 

and stratigraphic traps. 

The estimated mean undiscovered conventional petroleum 

resources in the Bou Dabbous–Tertiary Total Petroleum System 

are 667 MMBO, 2,746 BCFG, and 64 MMBNGL. The estimated mean undiscovered conventional petroleum resources in 

the Jurassic-Cretaceous Composite Total Petroleum System are 

403 MMBO, 2,280 BCFG, and 27 MMBNGL. The combined 

estimated mean undiscovered conventional petroleum resources 

of both total petroleum systems of the Pelagian Province are 

1,070 MMBO, 5,026 BCFG, and 91 MMBNGL. 

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Jongsma, D., van Hinte, J.E., and Woodside, J.M., 1985, Geologic structure and neotectonics of the North African Continental Margin south 

of Sicily: Marine and Petroleum Geology, v. 2, p. 156–179. 

Klett, T.R., Ahlbrandt, T.S., Schmoker, J.W., and Dolton, G. L., 1997, 

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CD-ROM. 

Knott, I., Moody, R., and Sandman, R., 1995, Coniacian-Turonian carbonates of the Miskar Field, offshore Tunisia [abs]: American Association of Petroleum Geologists Bulletin, v. 79, no. 8, p. 1227. 

Long, M., 1978, Tertiary oil discoveries whet explorer interest off Tunisia: 

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Ross, K.M., 1996, Summary of the 1995 assessment of conventionally 

recoverable hydrocarbon resources of the Gulf of Mexico and 

Atlantic Outer Continental Shelf: Minerals Management Service 

OCS Report MMS 96-0047, 67 p. 

Loucks, R.G., Moody, R.T.J., Bellis, J.K., and Brown, A.A., 1998, Regional 

depositional setting and pore network systems of the El Garia Formation (Metlaoui Group, Lower Eocene), offshore Tunisia, in 

Macgregor, D.S., Moody, R.T.J., and Clark-Lowes, D.D., eds., Petroleum geology of North Africa: Geological Society, London, Special 

Publication 132, p. 355–374. 

Lucazeau, F., and Ben Dhia, H., 1989, Preliminary heat-flow density data 

from Tunisia and the Pelagian Sea: Canadian Journal of Earth 

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Macgregor, D.S., and Moody, R.T.J., 1998, Mesozoic and Cenozoic 

petroleum systems of North Africa, in Macgregor, D.S., Moody, 

R.T.J., and Clark-Lowes, D.D., eds., Petroleum geology of North 

Africa: Geological Society, London, Special Publication 132, p. 

201–216. 

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3–24. 

Montgomery, S., 1994, Ghadames Basin and surrounding areas—Structure, tectonics, geochemistry and field summaries: Petroleum 

Frontiers, v. 10, no. 4, 79 p. 

Morgan, M.A., Grocott, J., and Moody, R.T.J., 1998, The structural evolution of the Zaghouan-Ressas Structural Belt, northern Tunisia, in 

Macgregor, D.S., Moody, R.T.J., and Clark-Lowes, D.D., eds., Petroleum geology of North Africa: Geological Society, London, Special 

Publication 132, p. 405–422. 

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and Boudjema, A., 1994, Basin inversion along the North African 

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References Cited 27 
Appendices 

Two sets of exploration-activity and discovery-history plots are provided for each of the 

assessment units in the Pelagian Province, one set showing known field sizes (cumulative 

production plus remaining reserves) and another showing field sizes that were adjusted to 

compensate for potential reserve growth that may occur in the next 30 years (labeled “grown”). 

Within each set of plots, oil fields and gas fields are treated separately. The plots include: 

• Cumulative Number of New-Field Wildcat Wells vs. Drilling-Completion Year 

• Number of New-Field Wildcat Wells vs. Drilling-Completion Year 

• Oil- or Gas-Field Size (MMBO or BCFG) vs. Oil- or Gas-Field Rank by Size (With 

Respect to Discovery Halves or Thirds) 

• Number of Oil or Gas Fields vs. Oil- or Gas-Field Size Classes (MMBO or BCFG) (With 

Respect to Discovery Halves or Thirds) 

• Volume of Oil or Gas (MMBO or BCFG) vs. Oil- or Gas-Field Size Classes 

(MMBO or BCFG) 

• Oil- or Gas-Field Size (MMBO or BCFG) vs. Field-Discovery Year 

• Oil- or Gas-Field Size (MMBO or BCFG) vs. Cumulative Number of New-Field 

Wildcat Wells 

• Cumulative Oil or Gas Volume (MMBO or BCFG) vs. Field-Discovery Year 

• Cumulative Oil or Gas Volume (MMBO or BCFG) vs. Cumulative Number of NewField Wildcat Wells 

• Cumulative Number of Oil or Gas Fields vs. Field-Discovery Year 
• Cumulative Number of Oil or Gas Fields vs. Cumulative Number of New-Field 

Wildcat Wells 

• Reservoir Depth, Oil or Gas Fields (m) vs. Field-Discovery Year 

• Reservoir Depth, Oil or Gas Fields (m) vs. Cumulative Number of New-Field 

Wildcat Wells 

• Gas/Oil, Oil Fields (CFG/BO) vs. Mean Reservoir Depth (m) 

• NGL/Gas, Oil Fields (BNGL/MMCFG) vs. Mean Reservoir Depth (m) 

• Liquids/Gas, Gas Fields (BL/MMCFG) vs. Mean Reservoir Depth (m) 

• Number of Reservoirs in Oil Fields vs. API Gravity (Degrees) 
Appendix 1. Exploration-activity and discovery-history plots for the Bou Dabbous-Tertiary 

Structural/Stratigraphic Assessment Unit (20480101). A. Plots of known oil and gas volumes. 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

180

CUM. NEW-FIELD WILDCAT WELLS (No.) 160

140

120

100

80

60

40

20

0

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

DRILLING-COMPLETION YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

20

NEW-FIELD WILDCAT WELLS (No.)18

16

14

12

10

8

6

4

2

0

1952195419561958196019621964196619681970197219741976197819801982198419861988199019921994

DRILLING-COMPLETION YEAR
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

10,000 

KNOWN OIL-FIELD SIZE (MMBO)

1,000

100

10

First third of fields discovered 

Second third of fields discovered 

Third third of fields discovered 

1

0 2 4 6 8 10

OIL-FIELD RANK BY SIZE 
16 to <32

32 to <64

64 to <128

128 to <256256 to <512

512 to <1,024

1,024 to <2,0482,048 to <4,0964,096 to <8,192

8,192 to <16,384

16,384 to <32,768

32,768 to <65,536

65,536 to <131,072

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

8

7 Third third of 

fields 

discovered 

Second third 

of fields 

discovered 

First third of 

fields 

discovered 

OIL FIELDS (No.)

6

5

4

3

2

1

0

1 to <22 to <44 to <8

8 to <16 

>=262,144

131,072 to <262,144

KNOWN OIL-FIELD SIZE (MMBO)
512 to <1,024

1,024 to <2,0482,048 to <4,096

4,096 to <8,192

8,192 to <16,384

16,384 to <32,768

32,768 to <65,536

65,536 to <131,072

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

800

700

VOLUME OF OIL (MMBO) 600

500

400

300

200

100

0

1 to <22 to <44 to <8

8 to <16

16 to <3232 to <64

64 to <128

128 to <256256 to <512 

131,072 to <262,144

>=262,144 

KNOWN OIL-FIELD SIZE (MMBO)
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

10,000 

KNOWN OIL-FIELD SIZE (MMBO)

1,000

100

10

1 

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

10,000 

KNOWN OIL-FIELD SIZE (MMBO)

1,000

100

10

1 

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

3,500

CUM. KNOWN OIL VOLUME (MMBO) 3,000

2,500

2,000

1,500

1,000

500

0

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

3,500

CUM. KNOWN OIL VOLUME (MMBO) 3,000

2,500

2,000

1,500

1,000

500

0

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

30

25

CUM. OIL FIELDS (No.) 20

15

10

5

0

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

30

25

CUM. OIL FIELDS (No.) 20

15

10

5

0

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
RESERVOIR DEPTH, OIL FIELDS (m)

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
RESERVOIR DEPTH, OIL FIELDS (m)

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

14,000

12,000

GAS/OIL, OIL FIELDS (CFG/BO) 10,000

8,000

6,000

4,000

2,000

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

70

NGL/GAS, OIL FIELDS (BNGL/MMCFG) 60

50

40

30

20

10

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

16

RESERVOIRS IN OIL FIELDS (No.)14

12

10

8

6

4

2

0

0 to <10 10 to 

<20 

20 to 

<30 

30 to 

<40 

40 to 

<50 

50 to 

<60 

60 to 

<70 

70 to 

<80 

80 to 

<90 

90 to 

<100 

>=100

API GRAVITY (DEGREES)
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

1,000 

KNOWN GAS-FIELD SIZE (BCFG)

100

10

First third of fields discovered 

Second third of fields discovered 

Third third of fields discovered 

1

0 1 2 3 4 5 6

GAS-FIELD RANK BY SIZE 
12 to <24

24 to <4848 to <96

96 to <192

192 to <384384 to <768

768 to <1,536

1,536 to <3,0723,072 to <6,144

6,144 to <12,288

12,288 to <24,57624,576 to <49,152

49,152 to <98,304

98,304 to <196,608

196,608 to <393,216

393,216 to <786,432

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

6

5 Third third of 

fields 

discovered 

Second third 

of fields 

discovered 

First third of 

fields 

discovered 

GAS FIELDS (No.)

4

3

2

1

0

6 to <12 

>=1,572,864

786,432 to <1,572,864

KNOWN GAS-FIELD SIZE (BCFG)
768 to <1,536

1,536 to <3,0723,072 to <6,144

6,144 to <12,288

12,288 to <24,576

24,576 to <49,15249,152 to <98,304

98,304 to <196,608

196,608 to <393,216

393,216 to <786,432

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

1,400

VOLUME OF GAS (BCFG)1,200

1,000

800

600

400

200

0

6 to <12

12 to <2424 to <4848 to <96

96 to <192

192 to <384384 to <768 

786,432 to <1,572,864

>=1,572,864 

KNOWN GAS-FIELD SIZE (BCFG)
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

1,000 

KNOWN GAS-FIELD SIZE (BCFG)

100

10

1

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

1,000 

KNOWN GAS-FIELD SIZE (BCFG)

100

10

1

0 20 40 60 80 100 120 140 160 180

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

4,000

CUM. KNOWN GAS VOLUME (BCFG)3,500

3,000

2,500

2,000

1,500

1,000

500

0

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

4,000

CUM. KNOWN GAS VOLUME (BCFG)3,500

3,000

2,500

2,000

1,500

1,000

500

0

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

16

14

CUM. GAS FIELDS (No.)12

10

8

6

4

2

0

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

16

14

CUM. GAS FIELDS (No.)12

10

8

6

4

2

0

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
RESERVOIR DEPTH, GAS FIELDS (m)

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
RESERVOIR DEPTH, GAS FIELDS (m)

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

60

LIQUIDS/GAS, GAS FIELDS (BL/MMCFG) 50

40

30

20

10

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m) 
Appendix 1. Exploration-activity and discovery-history plots for the Bou Dabbous-Tertiary 

Structural/Stratigraphic Assessment Unit (20480101). B. Plots of grown oil and gas volumes. 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

180

CUM. NEW-FIELD WILDCAT WELLS (No.) 160

140

120

100

80

60

40

20

0

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

DRILLING-COMPLETION YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

20

NEW-FIELD WILDCAT WELLS (No.)18

16

14

12

10

8

6

4

2

0

1952195419561958196019621964196619681970197219741976197819801982198419861988199019921994

DRILLING-COMPLETION YEAR
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

10,000 

GROWN OIL-FIELD SIZE (MMBO)

1,000

100

10

First third of fields discovered 

Second third of fields discovered 

Third third of fields discovered 

1

0 2 4 6 8 10

OIL-FIELD RANK BY SIZE 
16 to <32

32 to <64

64 to <128

128 to <256

256 to <512

512 to <1,024

1,024 to <2,0482,048 to <4,0964,096 to <8,192

8,192 to <16,384

16,384 to <32,76832,768 to <65,536

65,536 to <131,072

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

8

7 Third third of 

fields 

discovered 

Second third 

of fields 

discovered 

First third of 

fields 

discovered 

OIL FIELDS (No.)

6

5

4

3

2

1

0

1 to <22 to <44 to <8

8 to <16 

>=262,144

131,072 to <262,144

GROWN OIL-FIELD SIZE (MMBO)
512 to <1,024

1,024 to <2,0482,048 to <4,0964,096 to <8,192

8,192 to <16,384

16,384 to <32,76832,768 to <65,536

65,536 to <131,072

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

1,200

VOLUME OF OIL (MMBO)1,000

800

600

400

200

0

1 to <22 to <44 to <8

8 to <16

16 to <3232 to <64

64 to <128

128 to <256256 to <512 

131,072 to <262,144

>=262,144 

GROWN OIL-FIELD SIZE (MMBO)
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

10,000 

GROWN OIL-FIELD SIZE (MMBO)

1,000

100

10

1 

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

10,000 

GROWN OIL-FIELD SIZE (MMBO)

1,000

100

10

1 

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

3,500

CUM. GROWN OIL VOLUME (MMBO) 3,000

2,500

2,000

1,500

1,000

500

0

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

3,500

CUM. GROWN OIL VOLUME (MMBO) 3,000

2,500

2,000

1,500

1,000

500

0

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

30

25

CUM. OIL FIELDS (No.) 20

15

10

5

0

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

30

25

CUM. OIL FIELDS (No.) 20

15

10

5

0

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
RESERVOIR DEPTH, OIL FIELDS (m)

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
RESERVOIR DEPTH, OIL FIELDS (m)

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

14,000

12,000

GAS/OIL, OIL FIELDS (CFG/BO) 10,000

8,000

6,000

4,000

2,000

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

70

NGL/GAS, OIL FIELDS (BNGL/MMCFG) 60

50

40

30

20

10

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

16

RESERVOIRS IN OIL FIELDS (No.)14

12

10

8

6

4

2

0

0 to <10 10 to 

<20 

20 to 

<30 

30 to 

<40 

40 to 

<50 

50 to 

<60 

60 to 

<70 

70 to 

<80 

80 to 

<90 

90 to 

<100 

>=100

API GRAVITY (DEGREES)
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

1,000 

GROWN GAS-FIELD SIZE (BCFG)

100

10

First third of fields discovered 

Second third of fields discovered 

Third third of fields discovered 

1

0 1 2 3 4 5 6

GAS-FIELD RANK BY SIZE 
12 to <24

24 to <4848 to <96

96 to <192

192 to <384384 to <768

768 to <1,536

1,536 to <3,0723,072 to <6,144

6,144 to <12,288

12,288 to <24,57624,576 to <49,152

49,152 to <98,304

98,304 to <196,608

196,608 to <393,216

393,216 to <786,432

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

5

4

Third third of 

fields 

discovered 

Second third 

of fields 

discovered 

First third of 

fields 

discovered 

GAS FIELDS (No.)

3

2

1

0

6 to <12 

>=1,572,864

786,432 to <1,572,864

GROWN GAS-FIELD SIZE (BCFG)
768 to <1,536

1,536 to <3,0723,072 to <6,144

6,144 to <12,288

12,288 to <24,576

24,576 to <49,15249,152 to <98,304

98,304 to <196,608

196,608 to <393,216

393,216 to <786,432

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

2,500

VOLUME OF GAS (BCFG) 2,000

1,500

1,000

500

0

6 to <12

12 to <2424 to <4848 to <96

96 to <192

192 to <384384 to <768 

786,432 to <1,572,864

>=1,572,864 

GROWN GAS-FIELD SIZE (BCFG)
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

1,000 

GROWN GAS-FIELD SIZE (BCFG)

100

10

1

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

1,000 

GROWN GAS-FIELD SIZE (BCFG)

100

10

1

0 20 40 60 80 100 120 140 160 180

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

4,000

CUM. GROWN GAS VOLUME (BCFG)3,500

3,000

2,500

2,000

1,500

1,000

500

0

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

4,000

CUM. GROWN GAS VOLUME (BCFG)3,500

3,000

2,500

2,000

1,500

1,000

500

0

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

18

16

14

CUM. GAS FIELDS (No.) 12

10

8

6

4

2

0

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

18

16

14

CUM. GAS FIELDS (No.) 12

10

8

6

4

2

0

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
RESERVOIR DEPTH, GAS FIELDS (m)

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 

FIELD-DISCOVERY YEAR 
RESERVOIR DEPTH, GAS FIELDS (m)

Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

0 20 40 60 80 100 120 140 160 180 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Bou Dabbous-Tertiary Structural/Stratigraphic, Assessment 

Unit 20480101

60

LIQUIDS/GAS, GAS FIELDS (BL/MMCFG) 50

40

30

20

10

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m) 
Appendix 2. Exploration-activity and discovery-history plots for the Jurassic-Cretaceous 

Structural/Stratigraphic Assessment Unit (20480201). A. Plots of known oil and gas volumes. 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

200

CUM. NEW-FIELD WILDCAT WELLS (No.) 180

160

140

120

100

80

60

40

20

0

1940 1950 1960 1970 1980 1990 2000 

DRILLING-COMPLETION YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

16

NEW-FIELD WILDCAT WELLS (No.)14

12

10

8

6

4

2

0

194919511953195519571959196119631965196719691971197319751977197919811983198519871989199119931995

DRILLING-COMPLETION YEAR
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

100

KNOWN OIL-FIELD SIZE (MMBO)

First half of fields discovered 

Second half of fields discovered 10

1

0 1 2 3 4 5 6

OIL-FIELD RANK BY SIZE 
16 to <32

64 to <128

128 to <256256 to <512

512 to <1,024

1,024 to <2,0482,048 to <4,0964,096 to <8,192

8,192 to <16,384

16,384 to <32,768

32,768 to <65,536

65,536 to <131,072

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

6

5 Second half 

of fields 

discovered 

First half of 

fields 

discovered 

OIL FIELDS (No.)

4

3

2

1

0

1 to <22 to <44 to <8

8 to <16

32 to <64 

>=262,144

131,072 to <262,144

KNOWN OIL-FIELD SIZE (MMBO)
512 to <1,024

1,024 to <2,0482,048 to <4,0964,096 to <8,192

8,192 to <16,384

16,384 to <32,76832,768 to <65,536

65,536 to <131,072

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

60

VOLUME OF OIL (MMBO)50

40

30

20

10

0

1 to <22 to <44 to <8

8 to <16

16 to <3232 to <64

64 to <128

128 to <256256 to <512 

131,072 to <262,144

>=262,144 

KNOWN OIL-FIELD SIZE (MMBO)
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

100

KNOWN OIL-FIELD SIZE (MMBO)

10

1

1940 1950 1960 1970 1980 1990 2000

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

100

KNOWN OIL-FIELD SIZE (MMBO)

10

1

0 20 40 60 80 100 120 140 160 180 200

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

250

CUM. KNOWN OIL VOLUME (MMBO) 200

150

100

50

0

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

250

CUM. KNOWN OIL VOLUME (MMBO) 200

150

100

50

0

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

12

10

CUM. OIL FIELDS (No.)

8

6

4

2

0

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

12

10

CUM. OIL FIELDS (No.)

8

6

4

2

0

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
RESERVOIR DEPTH, OIL FIELDS (m)

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
RESERVOIR DEPTH, OIL FIELDS (m)

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

9,000

8,000

GAS/OIL, OIL FIELDS (CFG/BO) 7,000

6,000

5,000

4,000

3,000

2,000

1,000

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

16

NGL/GAS, OIL FIELDS (BNGL/MMCFG) 14

12

10

8

6

4

2

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

9

RESERVOIRS IN OIL FIELDS (No.)

8

7

6

5

4

3

2

1

0

0 to <10 10 to 

<20 

20 to 

<30 

30 to 

<40 

40 to 

<50 

50 to 

<60 

60 to 

<70 

70 to 

<80 

80 to 

<90 

90 to 

<100 

>=100

API GRAVITY (DEGREES)
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

1,000 

KNOWN GAS-FIELD SIZE (BCFG)

100

10

First half of fields discovered 

Second half of fields discovered 

1

0 1 2 3 4

GAS-FIELD RANK BY SIZE 
12 to <24

24 to <4848 to <96

96 to <192

192 to <384384 to <768

768 to <1,536

1,536 to <3,0723,072 to <6,144

6,144 to <12,288

12,288 to <24,57624,576 to <49,152

49,152 to <98,304

98,304 to <196,608

196,608 to <393,216

393,216 to <786,432

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

2

Second half 

of fields 

discovered 

First half of 

fields 

discovered 

GAS FIELDS (No.)

1

0

6 to <12 

>=1,572,864

786,432 to <1,572,864

KNOWN GAS-FIELD SIZE (BCFG)
768 to <1,536

1,536 to <3,0723,072 to <6,144

6,144 to <12,288

12,288 to <24,57624,576 to <49,15249,152 to <98,304

98,304 to <196,608

196,608 to <393,216

393,216 to <786,432

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

900

800

VOLUME OF GAS (BCFG) 700

600

500

400

300

200

100

0

6 to <12

12 to <2424 to <4848 to <96

96 to <192

192 to <384

384 to <768 

786,432 to <1,572,864

>=1,572,864 

KNOWN GAS-FIELD SIZE (BCFG)
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

1,000 

KNOWN GAS-FIELD SIZE (BCFG)

100

10

1

1940 1950 1960 1970 1980 1990 2000

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

1,000 

KNOWN GAS-FIELD SIZE (BCFG)

100

10

1

0 20 40 60 80 100 120 140 160 180 200

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

2,000

CUM. KNOWN GAS VOLUME (BCFG)1,800

1,600

1,400

1,200

1,000

800

600

400

200

0

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

2,000

CUM. KNOWN GAS VOLUME (BCFG)1,800

1,600

1,400

1,200

1,000

800

600

400

200

0

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

7

6

CUM. GAS FIELDS (No.) 5

4

3

2

1

0

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

7

6

CUM. GAS FIELDS (No.) 5

4

3

2

1

0

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
RESERVOIR DEPTH, GAS FIELDS (m)

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
RESERVOIR DEPTH, GAS FIELDS (m)

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

60

LIQUIDS/GAS, GAS FIELDS (BL/MMCFG) 50

40

30

20

10

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m) 
Appendix 2. Exploration-activity and discovery-history plots for the Jurassic-Cretaceous 

Structural/Stratigraphic Assessment Unit (20480201). B. Plots of grown oil and gas volumes. 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

200

CUM. NEW-FIELD WILDCAT WELLS (No.) 180

160

140

120

100

80

60

40

20

0

1940 1950 1960 1970 1980 1990 2000 

DRILLING-COMPLETION YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

16

NEW-FIELD WILDCAT WELLS (No.)14

12

10

8

6

4

2

0

194919511953195519571959196119631965196719691971197319751977197919811983198519871989199119931995

DRILLING-COMPLETION YEAR
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

100

GROWN OIL-FIELD SIZE (MMBO)

First half of fields discovered 

Second half of fields discovered 10

1

0 1 2 3 4 5 6 7 8

OIL-FIELD RANK BY SIZE 
16 to <32

64 to <128

128 to <256256 to <512

512 to <1,024

1,024 to <2,0482,048 to <4,0964,096 to <8,192

8,192 to <16,384

16,384 to <32,768

32,768 to <65,536

65,536 to <131,072

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

5

4 Second half 

of fields 

discovered 

First half of 

fields 

discovered 

OIL FIELDS (No.)

3

2

1

0

1 to <22 to <44 to <8

8 to <16

32 to <64 

>=262,144

131,072 to <262,144

GROWN OIL-FIELD SIZE (MMBO)
512 to <1,024

1,024 to <2,0482,048 to <4,096

4,096 to <8,192

8,192 to <16,384

16,384 to <32,768

32,768 to <65,536

65,536 to <131,072

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

120

VOLUME OF OIL (MMBO)100

80

60

40

20

0

1 to <22 to <44 to <8

8 to <16

16 to <3232 to <64

64 to <128

128 to <256256 to <512 

131,072 to <262,144

>=262,144 

GROWN OIL-FIELD SIZE (MMBO)
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

100

GROWN OIL-FIELD SIZE (MMBO)

10

1

1940 1950 1960 1970 1980 1990 2000

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

100

GROWN OIL-FIELD SIZE (MMBO)

10

1

0 20 40 60 80 100 120 140 160 180 200

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

250

CUM. GROWN OIL VOLUME (MMBO) 200

150

100

50

0

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

250

CUM. GROWN OIL VOLUME (MMBO) 200

150

100

50

0

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

14

12

CUM. OIL FIELDS (No.) 10

8

6

4

2

0

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

14

12

CUM. OIL FIELDS (No.) 10

8

6

4

2

0

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
RESERVOIR DEPTH, OIL FIELDS (m)

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
RESERVOIR DEPTH, OIL FIELDS (m)

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

9,000

8,000

GAS/OIL, OIL FIELDS (CFG/BO) 7,000

6,000

5,000

4,000

3,000

2,000

1,000

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

16

NGL/GAS, OIL FIELDS (BNGL/MMCFG) 14

12

10

8

6

4

2

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

9

RESERVOIRS IN OIL FIELDS (No.)

8

7

6

5

4

3

2

1

0

0 to <10 10 to 

<20 

20 to 

<30 

30 to 

<40 

40 to 

<50 

50 to 

<60 

60 to 

<70 

70 to 

<80 

80 to 

<90 

90 to 

<100 

>=100

API GRAVITY (DEGREES)
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

1,000 

GROWN GAS-FIELD SIZE (BCFG)

100

10

First half of fields discovered 

Second half of fields discovered 

1

0 1 2 3 4

GAS-FIELD RANK BY SIZE 
12 to <24

24 to <4848 to <96

96 to <192

192 to <384384 to <768

768 to <1,536

1,536 to <3,0723,072 to <6,144

6,144 to <12,288

12,288 to <24,57624,576 to <49,152

49,152 to <98,304

98,304 to <196,608

196,608 to <393,216

393,216 to <786,432

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

4

Second half 

of fields 

discovered 

First half of 

fields 

discovered 

GAS FIELDS (No.)

3

2

1

0

6 to <12 

>=1,572,864

786,432 to <1,572,864

GROWN GAS-FIELD SIZE (BCFG)
768 to <1,536

1,536 to <3,0723,072 to <6,144

6,144 to <12,288

12,288 to <24,576

24,576 to <49,15249,152 to <98,304

98,304 to <196,608

196,608 to <393,216

393,216 to <786,432

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

1,000

900

VOLUME OF GAS (BCFG)

800

700

600

500

400

300

200

100

0

6 to <12

12 to <2424 to <4848 to <96

96 to <192

192 to <384384 to <768 

786,432 to <1,572,864

>=1,572,864 

GROWN GAS-FIELD SIZE (BCFG)
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

1,000 

GROWN GAS-FIELD SIZE (BCFG)

100

10

1

1940 1950 1960 1970 1980 1990 2000

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

1,000 

GROWN GAS-FIELD SIZE (BCFG)

100

10

1

0 20 40 60 80 100 120 140 160 180 200

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

2,000

CUM. GROWN GAS VOLUME (BCFG)1,800

1,600

1,400

1,200

1,000

800

600

400

200

0

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

2,000

CUM. GROWN GAS VOLUME (BCFG)1,800

1,600

1,400

1,200

1,000

800

600

400

200

0

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

9

8

7

CUM. GAS FIELDS (No.) 6

5

4

3

2

1

0

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

9

8

7

CUM. GAS FIELDS (No.) 6

5

4

3

2

1

0

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
RESERVOIR DEPTH, GAS FIELDS (m)

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

1940 1950 1960 1970 1980 1990 2000 

FIELD-DISCOVERY YEAR 
RESERVOIR DEPTH, GAS FIELDS (m)

Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201 

0 

500 

1,000 

1,500 

2,000 

2,500 

3,000 

3,500 

4,000 

0 20 40 60 80 100 120 140 160 180 200 

CUM. NEW-FIELD WILDCAT WELLS (No.) 
Jurassic-Cretaceous Structural/Stratigraphic, Assessment 

Unit 20480201

60

LIQUIDS/GAS, GAS FIELDS (BL/MMCFG) 50

40

30

20

10

0

0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 

MEAN RESERVOIR DEPTH (m)