GeolCarp_Vol68_No2_97

GEOLOGICA CARPATHICA

, APRIL 2017, 68, 2, 97 – 108

doi: 10.1515/geoca-2017-0008

www.geologicacarpathica.com

WISSEM DHRAIEF

, FERID DHAHRI

1,2,

IMEN CHALWATI

and NOUREDDINE BOUKADI

University of Tunis El Manar, Faculty of Sciences of Tunis, UR11ES15 Sedimentary Environments, Petroleum systems

and reservoirs characterization, Tunis 2092, Tunisia;



feriddhahri@yahoo.fr

University of Gafsa, Faculty of Sciences of Gafsa, Gafsa 2112, Tunisia

(Manuscript received February 28, 2016; accepted in revised form November 30, 2016)

Abstract: The objective and the main contribution of this issue are dedicated to using subsurface data to delineate a basin

beneath the Gulf of Tunis and its neighbouring areas, and to investigate the potential of this area in terms of hydrocarbon

resources. Available well data provided information about the subsurface geology beneath the Gulf of Tunis. 2D seismic

data allowed delineation of the basin shape, strata geometries, and some potential promising subsurface structures in

terms of hydrocarbon accumulation. Together with lithostratigraphic data obtained from drilled wells, seismic data

permitted the construction of isochron and isobath maps of Upper Cretaceous–Neogene strata. Structural and litho

stratigraphic interpretations indicate that the area is tectonically complex, and they highlight the tectonic control of strata

deposition during the Cretaceous and Neogene. Tectonic activity related to the geodynamic evolution of the northern

African margin appears to have been responsible for several thickness and facies variations, and to have played a significant

role in the establishment and evolution of petroleum systems in northeastern Tunisia. As for petroleum systems in

the basin, the Cretaceous series of the Bahloul, Mouelha and Fahdene formations are acknowledged to be the main source

rocks. In addition, potential reservoirs (Fractured Abiod and Bou Dabbous carbonated formations) sealed by shaly and

marly formations (Haria and Souar formations respectively) show favourable geometries of trap structures (anticlines,

tilted blocks, unconformities, etc.) which make this area adequate for hydrocarbon accumulations.

Keywords: Gulf of Tunis, seismic, well data, isochron, isobath, petroleum system.

Introduction

The Gulf of Tunis is located in northeastern Tunisia (Fig.1),

west of the Sicilian segment of the Apenninic–Maghrebian

Orogen. The strata beneath the Gulf of Tunis constitute an off

shore basin that developed during the Neogene Africa–Europe

collision (Dart et al. 1993; Lentini et al. 1996; Catalano et al.

2011). The geological history of this area is linked to the

evolution of the North African margin guided by transten

sional plate movements between Africa and Eurasia during the

Mesozoic, followed by plate collision during the Neogene

(Stampfli & Borel 2002; Brunet & Cloetingh 2003; Patriat et

al. 2003; Laville et al. 2004; Abrajevitch et al. 2005; Dhahri &

Boukadi 2010; Melki et al. 2010; Catalano et al. 2011;

Roure et al. 2012; Masrouhi et al. 2014; Dhahri et al. 2015).

The architecture of the Gulf of Tunis basin developed mainly

during the Mesozoic, and then was greatly deformed during

the Neogene leading to the inversion of extensional structures

and to the redistribution of subsidence locations. As a part of

Northern Tunisia, this area recorded the Early Mesozoic rifting

resulting in the Tethys opening and created extensional

structures such as horsts and grabens. Subsequent to the

Neogene closure of the Tethyan Ocean, folding and thrusting

occurred together within strikeslip movement and

pullapart basins to make complex structural configurations

within the Neogene basins (Patriat et al. 2003; Roure et

al. 2012).

After the first hydrocarbon discovery was made in the Jebel

Abderrahman structure of the Cap Bon peninsula in 1948,

northeastern Tunisia was an attractive area for hydrocarbon

exploration and several international companies conducted

several onshore and offshore exploration activities with the

partnership of the ETAP (Entreprise Tunisienne d’Activités

Pétrolières). On the basis of several seismic surveys and dril

lings, this exploration led to several offshore and onshore oil

and gas discoveries in the Gulf of Hammamet and Cap Bon

peninsula (Birsa, Yasmin, Tazerka, Belli). These discoveries

were certainly a motivating reason for petroleum companies

to enhance exploration activities in northeastern Tunisia.

The recognized petroleum systems range from MidUpper

Cretaceous to Tertiary series (Mejri et al. 2006; Craig 2009).

The Albian–Turonian petroleum system is wellknown in

North and West Africa (Macgregor 1996; Luning et al. 2004).

In Tunisia, this system comprises the Bahloul, Mouelha and

Fahdene source rocks (Fig. 2). The Abiod Formation

Campanian–Maastrichtian in age is documented as a chalky

limestone fractured reservoir in northeastern and offshore

Tunisia (Bishop 1988; El Euchi et al. 2002). It shows several

accumulations within the Gulf of Hammamet (i.e. Dougga and

Tazerka) (Craig 2009). The Eocene petroleum systems

Tectonosedimentary framework of Upper Cretaceous –Neogene

series in the Gulf of Tunis inferred from subsurface data:

implications for petroleum exploration

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, 2017, 68, 2, 97 – 108

comprises two reservoirs: the Halk el Menzel Formation

Middle to Late Eocene in age and the Fractured limestone of

the Bou Dabbous Formation Ypresian in age (i.e. Belli, Al

Manzah and Beni Khalled fields onshore around Cap Bon).

In the Gulf of Hammamet, the sandy Birsa Formation Miocene

in age exhibits excellent reservoir quality and yields several

oil fields (i.e. Dougga, Tazerka, Oudna, Birsa, Cosmos and

Yasmin).

In the Gulf of Tunis, the presence of Cretaceous source

rocks (Bahloul, Mouelha and Fahdene formations) and potential

reservoirs (Fractured Abiod and Bou Dabbous carbonated

formations) sealed by shaly and marly formations (Haria and

Souar formations respectively and Late Eocene in age)

(Fig. 2) with favourable geometries of trap structures (anti

clines, tilted blocks, unconformities, etc.) make this area ade

quate for hydrocarbon accumulations. However, the fact that

the structure of this area is complex and consistent regional

structural and stratigraphic evaluations are lacking make its

petroleum geology poorly understood. In this paper, we use

offshore and onshore wells and seismic data to bring out new

precisions on the tectonosedimentary evolution and basin

configuration of the Gulf of Tunis with emphasis on its hydro

carbon potential.

Geological setting

The Gulf of Tunis and its onshore restrictions (areas of

Bizerte, Tunis and the Cap Bon Peninsula) are located in

northeastern Tunisia (Fig. 3), southeastward of the Tellian

Sicilian imbricate zone (Fig. 1). This domain represents the

northeastern extension of the Atlas fold belt of Tunisia. It is

tectonically complex and shows various structures which

largely influenced the deposition since Mesozoic times (Ben

Ayed 1993; Bédir et al. 1996; Melki et al. 2010). In this area,

two main fault directions were highlighted; NE–SW thrust

faults and NW–SE normal faults that delimit several subsiding

grabens. In fact, these structures are comparable to these of the

Atlas fold belt of Tunisia, and several structural features high

lighted within the Gulf of Tunis can be clearly interpreted as

offshore extensions of these known at its onshore restrictions

as much as the Zaghouan thrust and the Grombalia graben.

Fig. 1. Tectonic map of the central Mediterranean with main offshore structural features (modified after Ben Avraham et al. 1990; Sartori

et al. 2001; Pepe et al. 2005; Mejri et al. 2006 and Melki et al. 2010).

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Further to the northeast, this structural pattern seems charac

terizing regionally the Pelagian Sea with the remarkable NW–

SEoriented grabens of PantelleriaMalta area (Boccaletti et

al. 1990; Catalano et al. 1995; Accaino et al. 2011).

The Gulf of Tunis belong to the African continental margin

between Sicily Island and northeastern Tunisia where the

Meso–Cenozoic series consist of deep and shallow water

carbo natic and terrigenous rocks designated as the Sicilian–

Maghrebian units (Catalano et al. 1995; Pepe et al. 2005;

Accaino et al. 2011). In this location, the analyses of the

sedi mentary sequence driven from well data, shows many

tectono sedimentary events as well as stratigraphic gaps,

unconformities, reworked rocks and fauna and thickness

varia tions. The oldest crossed series are these of Middle to

Late Triassic (Norian–Landinian) with carbonates and gypsum

facies reached at the depth of 1080 m in the well 2 (Fig. 3)

where they are unconformably overlaid by a Palaeocene

series. The well 5 crosses more than 900 m of Cretaceous

series (from 1400 m to 2361 m depth) (Figs. 4 and 5). These

series are assigned to Hauterivian–Maastrichtian times and

comprise four lithostratigraphic formations of open marine

environment: the M’Cherga Formation (Valanginian–Aptian)

made of marls, shales and limestones, the Fahdene Formation

(Albian–Cenomanian) comprising shales, limestones and marls

including the terminal horizon of the Bahloul facies made up

of about 15 m of thin laminated organic rich limestone for

ming the top of the Cenomanian stage and acknowledged as

an excellent source rock in northcentral Tunisia, the Aleg

Formation (Turonian–Santonian) made of marls and shales

alternating with thin limestones layers, and the Abiod

Formation (Campanian–Maastrichtian) dominantly made up

of limestones with argillaceous basinal level.

The Abiod Formation is sealed by the open marine marls

and shales of Haria Formation of Maastrichtian–Palaeocene

age. The Lower Eocene series (Bou Dabbous Formation) con

sists of deep water dark micritic carbonates which is overlain

by the Middle to Upper Eocene series made up of shales and

marls (Souar Formation). This latter evolves eastward, to rich

shelf carbonate facies with nummulitic limestones and dolo

mites (Halk El Menzel Formation) in the Pelagian Shelf

(Bonnefous & Bismuth 1982). The Oligocene series overlay

unconformably the Miocene ones. They display considerable

thickness reduction and are absent in several localities (i.e. in

wells 2 and 5) (Fig. 4). They are made of silstones, mudstone

and sandstones forming a siliciclastic sequence acknowledged

as Fortuna Formation assigned to Oligocene–Early Miocene

age. Near the Cap Bon peninsula, the Oligocene series are

made of rich fauna sandstone acknowledged as the Korbous

Formation. The complete Neogene series begins with the

Fortuna Formation succeeded by the siliciclastic Messiouta

(Burdigalian), then the transgressive conglomeratic luma

chellic Aïn Grab Formation (Burdigalian) (Ben IsmailLattrache

& Bobier 1984) and Oum Douil group (Langhian‒Messinian)

(Biely et al. 1972). This latter is made of a mixture of sands,

clays, gypsum and carbonates. It is commonly divided into

several formations that fluctuate laterally to respective partial

lithostratigraphic equivalents (Fig. 2). In the Gulf of Tunis

Oum Douil group comprise an evaporitic sequence topped by

carbonate strata Serravalian in age (Mellaha Formation) and

a sequence of clays with carbonates (Kechabta Formation). To

the north of the study area, petroleum wells cross a rich

coquina sequence of grey shale with some sandy beds and

gypsum acknowledged as Souaf Formation Serravallian–Early

Tortonian in age (Burollet 1956). According to Burollet

(1951), Pliocene series are mainly made of sands and sand

stones with few intercalations of clays and carbonates. Near

the Gulf of Tunis and the Bizerte coast they begin with

an evaporitic unit called Oued Bel Khedim Formation followed

Fig. 2. Synthetic scheme of the Gulf of Tunis lithostratigraphy (from Late Cretaceous to Neogene) showing several Neogene hiatus and lateral

facies variations.

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by a transgressive rich planktonic microfauna unit of grey

shale Zanclean‒Early Piacenzian in age (Raf Raf Formation).

This latter contains locally a conglomeratic basinal level and

some interbedded sandy lenses. It is overlaid by a shallow

marine facies made of bioclastic calcareous sand with some

clay intercalations (Porto Farina Formation) (Burollet 1951).

Data set and methodology

In the Gulf of Tunis several seismic sections and petroleum

wells (Fig. 3) were carried out after geophysical surveys

performed by petroleum companies. Seismic surveys have

delineated several subsurface features and seismically mapped

anomalies that deserve more recognition. It is why several

wells were drilled in selected zones to explore some promising

structures and reservoir targets and to calibrate seismic sec

tions. For most of the drilled wells in the Gulf of Tunis, the

fractured formations of the Campanian–Maastrichtian (Abiod)

and the Eocene (Bou Dabbous) were the primary objectives of

exploration. After the consultation of available subsurface

data in the ETAP, petroleum wells allowed us to draw litho

stratigraphic columns used to correlate the lateral variations of

facies and thickness and to calibrate seismic section. Seismic

data are used to examine the structure of the study area and to

draw isochron and isobath maps. Structural mapping has been

the most important application of seismic data. Nevertheless,

stratigraphic and structural interpretation of seismic lines

consists in the selection of sets of seismic horizons on different

wells to extract subsurface geological information. The struc

tural interpretation of a complete seismic survey allows us to

draw isochron maps commonly used for interpreting changes

in thickness between interpreted horizons and to furnish 3D

representation (X, Y, time) of the geological setting of the

study area. Throughout the structural interpretation of seismic

lines, the information on sediment velocities allows us to

Fig. 3. Simplified geological map of northeastern Tunisia with location of used data: W1–W9: petroleum wells, SL1–SL3: seismic lines.

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convert the isochron maps into isobath maps (X, Y, depth)

(Rey & Galeotti 2008). These latter were produced by con

verting isochron maps using the velocity information derived

from checkshot data. In this work, the compilation and treat

ment of data have been performed using the KINGDOM

Software marketed by the software company Seismic Micro

Technology Inc. This tool let us to delineate and interpret

several horizons in order to define and describe better the

structural development of the study area. Formation tops from

well data have been used for guidance in the seismic interpre

tation and isochron and isobath maps have been created for the

top of the Bou Dabbous and Abiod formations by plotting the

horizons corresponding to respective reflecting levels on the

available seismic sections. These maps are used to give an idea

of the structural configuration at depth (Majithia 1997). Four

onshore petroleum wells (W1, W7, W8 and W9), five offshore

ones (W2, W3, W4, W5 and W6) are used for calibration of

2D seismic sections (Fig. 3). W3 and W6 wells do not reach

the Cretaceous series it is why they are not illustrated within

the correlations. W3 reached the UpperMiddle Miocene series

at a total depth of 2328 m. however W6 reached the Upper

Eocene series at a total depth of 1418 m. Depth measurements

are commonly referenced for all wells to the Rotary Kelly

Bushing (RKB) which coincide with the depth origin “0 m”

(Figs. 4 and 5).

Results and discussions

Lithostratigraphy and deposition

To understand the stratigraphy and the spatial variation of

deposition of Late Cretaceous–Neogene series in the Gulf of

Tunis, two correlation lines (Figs. 4 and 5) were drawn using

both onshore and offshore petroleum wells along the N‒S and

WNW‒ESE directions.

The N–S oriented correlation line (Fig. 4) starts from the

offshore well 2 to the north, to the onshore well 7 to the south.

However the WNW‒ESE one (Fig. 5) starts from the onshore

well 1 to the WNW to the onshore well 8 to the ESE near the

northern coast line of the Cap Bon peninsula and passing by

the offshore wells 4 and 6 (Fig. 2). These correlations show

that to the north, ~1080 m thick of Palaeocene–Pliocene series

overlay unconformably a thick Triassic salt body (from

1080 m depth to the final depth of 3705 m). In this locality, the

Eocene series are absent and a hiatus is highlighted between

the conglomeratic lumachellic carbonates of Aïn Grab and the

clays of Haria Formation. Both 5 and 7 wells cross the Upper

Cretaceous and Neogene series. They are (and so well 4) used

for the description and the correlation of the Upper Cretaceous

series. Based on the thickness and facies description, the

Upper Cretaceous series seem to be less impacted by the tec

tonic and eustatic factors compared to the Neogene series.

However three complete Upper Cretaceous formations are

recognized within wells 5 and 7 (Fig. 5). The correlation of

these formations shows that their amount of thickness increases

from north (370 m in well 5) to south (520 m in well 7). This

thickness variation can be interpreted as a result of tectonic

activity during the Late Cretaceous. According to Melki et al.

(2010) the thickness of Cretaceous series near the Gulf of

Tunis shows considerable variation from 2341 to 477 m indi

cating high and low zones structures guided by faults. The

thickness of the Abiod Formation increase from ~120 m in

well 5 to ~256 m in well 7. This is indeed due to the tectonic

activity but the fact that this formation ends with an erosion

surface in well 5 make ambiguous the precision of the faults

offset value. In fact, the eastern margin of the Tunisian domain

was subjected to an extensional tectonic regime during the

Cretaceous. The Early Cretaceous extension is a continuance

of the Triassic–Early Cretaceous rifting known at Tethys scale

and resulted in the occurrence of normal and strikeslip faulting,

graben, subsidence, halokinesis and volcanism (Guiraud et al.

1987; Boccaletti et al. 1990; LaaridhiOuazza 1994; Laaridhi

Ouazza & Bédir 2005; Gabtni et al. 2011). However the Late

Cretaceous extension is related to another rifting oriented

NE–SW related to a tectonic motion between the African and

Eurasian plates and responsible for NE–SW crustal extension

and magmatism along NW–SE basement faults (Fairhead

1988; Guiraud & Maurin 1992; Guiraud et al. 2005). In eastern

Tunisia, NW–SE extensional structures have been highlighted

and are associated with a high geothermal gradient and nume

rous oil and gas fields (LaaridhiOuazza 1994; Laaridhi

Ouazza & Bédir 2005; Gabtni et al. 2011; MattoussiKort et

al. 2015). Given that the crustal extension of the eastern

margin of Tunisia prevailed until the Late Cretaceous, it led to

a basin configuration that was controlled the deposition of

postCretaceous series as much as Ypresian ones.

The transgressive Haria Formation seems to be spread

throughout the Gulf of Tunis despite a nearby uplifted area,

where the Triassic bodies like as in well 1 where probably

totally eroded. Based on well data that crosses this formation,

its thickness ranges from 73 m in well 2 (partially eroded) to

245 m in well 5. This thickness variation is due to local total or

partial erosion and to the inherited basin floor configuration

characterized by high and low zones during the Late Creta

ceous (Melki et al. 2010). Unfortunately, few wells crossed the

total thickness of the Eocene series. The Lower Eocene series

recognized in the offshore petroleum wells of the Gulf of

Tunis show some similarity to the globigerina facies acknow

ledged for the Ypresian shaly limestones of northcentral

Tunisia. However, based on planktonic microfauna content the

facies encountered within the offshore wells near the Gulf of

Tunis seems to come from deeper water conditions with

an open marine connection. The Souar Formation is crossed

by three offshore wells (4, 5 and 6) in the central part of the

Gulf of Tunis where its thickness does not exceed 152 m.

However, in the onshore well 7 it reaches a thickness of 323 m

(Fig. 5). In fact this Formation shows considerable thickness

variations and it is topped by an erosion surface. It is missed in

several localities (i.e. wells 1, 2 and 5), nevertheless, it can

reach 800 m in the onshore Cap Bon area (Ben IsmailLattrache

& Bobier 1984). The Oligocene series are generally missing in

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the offshore wells of the Gulf of Tunis except in well 6 where

they reach shallow marine facies 600 m thick (Korbous

Formation). In fact, the gap of the Oligocene series is corre

lated to a regional hiatus highlighted for a large part of Tunisia

(Burollet 1956; Yaich et al. 2000). Toward the Cap Bon, these

series evolve into their siliciclastic equivalent of the Fortuna

Formation (Fig. 2). The Oligocene deposition seems to be con

trolled by coeval tectonic activity responsible for a high zone

to the northwest of the study area. The Miocene series also

shows considerable thickness and facies variation from the

northwest to the southeast of the study area with erosion at

both basinal and top surfaces. The thickest series were crossed

in wells 1, 3 and 8 with thicknesses of 1019 m, 1175 m and

711 m respectively. To the northwest, these series show

a facies of marine marginal setting with fluvial sediments

input. They are made up of four distinctive formations super

imposed downwards as follow: Oued Bel Khedim, Kechabta,

Oued El Melah and Mellaha (Fig. 5, W1). To the southeast and

near the Cap Bon area, these formations evolve progressively

into siliciclastic and shallow marine facies of Fortuna and

Oum Dhouil formations. Farther, in the Gulf of Hammamet,

the Miocene series comprises the socalled Birsa Formation

Serravalian in age and made of a sequence of sands deposited

within a shoreface to lower shoreface environment acknow

ledged as the dominant reservoir within this area (Portolano et

al. 2000). In the central part of the Gulf of Tunis (well 3), the

Late Miocene series are made of claystone and exceeds

a thickness of 1170 m making it the thickest sequence known

in this part of the Mediterranean and it seems to be tectonically

controlled.

Based on wells data, the Pliocene deposition seems to be

widespread in the Gulf of Tunis (Figs. 4 and 5). They occur

with the two discernible facies of Raf Raf and Porto Farina

formations described above. The Raf Raf Formation was

deposited in privileged area extending from the northwestern

part of the study area (near well 1) to the central part of the

Gulf of Tunis near wells 3, 4 and 5 (Figs. 2, 4 and 5). In this

area, the Raf Raf Formation maintains an average thickness

near 300 m but it is absent to the southeast. However the Porto

Farina Formation which overlays the Raf Raf Formation in

Fig. 4. N–S oriented correlation line showing that deposition is affected by halokinesis to the north of the Gulf of Tunis. However Upper

Cretaceous to Eocene series correlates well in its central and southern parts.

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wells 4 and 5 occupies the northern and the central part of the

study area and it exhibit considerable thickness variations (i.e.

669 m in well 2 versus 296 m in well 6). The crossed litho

stratigraphic section in well 3 shows an abrupt lithological

change and disappearance of fossils at the base of the Pliocene

series which is interpreted as a stratigraphic hiatus.

Based upon thickness variations and facies analyses, the

lithostratigraphic sequences of the Gulf of Tunis (at least from

the Late Cretaceous) exhibit several local gaps, erosion sur

faces, hiatus and subsiding zones. This configuration confirms

the coeval eustatic and tectonic control on the sedimentation.

This latter seems to have occurred on horst and graben struc

tured basins where deposition and tectonics are coeval. This

configuration is also documented by Melki et al. (2010) in

northeastern Tunisia.

Structural background and hydrocarbon potential

The analysis of well data provided interesting information

about deposition, facies and thickness variations along the

study area. Based on that, some interpretations are attempted

above. However wells give detailed control on borehole. This

control is nevertheless local when we consider the lateral evo

lution of deposition specially in wide well spacing condition.

This is why we attempt a mapping effort using seismic data to

draw isochron and isobath maps. Isochron and isobath maps

(Figs. 6 and 7) drawn for both tops of the Bou Dabbous and

Abiod formations together with seismic lines (Fig. 8) are used

to determine the structural configuration of the Gulf of Tunis

area and to highlight the tectonic control of the deposition

from Late Cretaceous to Neogene. These maps show that

both Abiod and Bou Dabbous formations were deposited

within a faultassisted basin with horst and graben structures

delineated by three main fault directions NE–SW, NW–SE

and E–W. This structural configuration in horsts and grabens

explains the remarkable variations in thickness of the depo

sition described above.

Concerning the top of the Abiod Formation (Fig. 6), a zone

of maximum depth is defined approximately by the 1.7 second

isochron (Fig. 6a) matching with a depth exceeding 2250 m

Fig. 5. WNW‒ESE oriented correlation line showing significant facies and thickness variations from the northwest to the southeast borders of

the Gulf of Tunis. Several hiatus and gaps are recorded especially within Tertiary series.

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depth is defined approximately by the 1.5 second isochron

matching with a depth exceeding 2000 m below the sea level.

This zone delimits several depocentres that coincide with

graben structures. This implies a continuous tectonic control

guided by the same fault system responsible for the structural

configuration of the Gulf of Tunis as described by Melki et

al. (2010).

Several seismic lines were considered to map the tops of the

Abiod and Bou Dabbous formations. Three seismic lines

(SL1, SL2 and SL3) are presented in Figure 8. Given that the

main significant faults controlling the structural configuration

of the Gulf of Tunis are arranged within two main perpendi

cular directions NE‒SW and NW‒SE, we choose to present

respectively interpreted NW‒SE and NE‒SWoriented seis

mic lines that crosses near the centre of the Gulf of Tunis, to

intersect the maximum of structural features (Fig. 8).

The NW‒SEoriented seismic line (SL1) (Fig. 8a) shows

that the thickness of postCretaceous deposition increases to

the east toward a deep depocentre delineated by several sub

vertical normal faults. This depocentre coincides with the

eastern graben structure shown on the isochron and isobath

maps of Figures 6 and 7. The western and eastern sides of this

graben can be considered as palaeohighs with thin Upper

Cretaceous‒Lower Eocene deposition. This thickness decrease

is due to the tectonic control amplified by halokinesis and ero

sion as highlighted for the Abiod Formation to the northwest

of the study area within the offshore well 1. The postYpresian

deposition records some compressional events especially

above main normal faults in testimony of their Neogene

inversion as occurred in the Northeastern Tunisia and the

Pelagian province after the Africa–Europe convergence

(Morgan et al. 1992; Guiraud 1998; Piqué et al. 1998; Brunet

& Cloetingh 2003; Melki et al. 2010; Dhahri & Boukadi 2010;

Dhahri et al. 2015). However, these deformations are sealed

by an uppermost horizontal level Pliocene–Quaternary in age

suggesting a low angle unconformity above the deformed

zone (Fig. 8).

The first SW‒NEoriented seismic line (SL2) (Fig. 8b)

shows an asymmetrical graben structure to the north, limited

by a steeper slope on its northern side affected by subvertical

NE‒SW faults, whereas the southern side shows gentler

scarps. This graben constitutes a depocentre in which Maas

trichtian–Ypresian deposition is relatively thicker than on both

sides regarded as Upper Cretaceous palaeohighs. The middle

part of this seismic line also has a progradingslope toward the

north on which the postYpresian series are deposited. This

slope is associated with erosion surfaces.

The second SW‒NEoriented seismic line (SL3) (Fig. 8c) is

parallel to SL2 (Fig. 3). This line ends toward the north without

crossing the illustrated graben structure northern SL2 (Fig. 8b).

However, it illustrates well the progradation and erosion high

lighted on the southern side of the graben structure within

SL2. In fact, along the progradingslope a significant angular

unconformity is well illustrated: the shales of Souar Formation

overlays unconformably the Eocene to Upper Cretaceous series

respectively from south to north. This configuration is

favou rable for the occurrence of unconformity traps within

dipping strata of the Bou Dabbous and Abiod fractured lime

stones when they are truncated by overlying bedded sealing

lithology as much as the Souar Formation. In such condition,

these unconformities have good prospects for hydrocarbon

accumulation.

Conclusions

Seismic interpretation, isochron and isobath maps together

with well data show that the Gulf of Tunis is affected by three

main fault systems with NE–SW, E–W and NW–SE directions

(Figs. 6 and 7). These fault systems acts together to create

an irregular network of juxtaposed tectonic blocks with

markedly different lithostratigraphic sequences. The deposi

tion rates depend largely on the amount and the sense of the

fault offset bordering each block. The Cretaceous tensional

tectonic regime is responsible for the establishment of horst

and graben structures which controlled later deposition within

the Gulf of Tunis until Ypresian times. At least four depo

centres limited by uplifted areas are prefigured since the

Cretaceous and prevailed until the Ypresian (Fig. 7). It is why

the Upper Cretaceous– Ypresian deposition records remar

kable thickness and facies variations with several unconfor

mities, gaps and erosion along palaeohighs and uplifted blocks

versus thick sequences near the graben structures. The seismic

lines show moderate Neogene shortening events responsible

for gentle folds and inversion of some previous normal faults

especially near the depocentres borders (Fig. 8).

Indeed, the principal targets of the drilled wells in the Gulf

of Tunis were the Eocene Bou Dabbous and the Upper

Cretaceous Abiod formations. Unfortunately no significant oil

reserves were encountered within these formations in all

studied wells. But there are certainly promising hydrocarbon

reservoirs in northeastern Tunisia. This area comprises several

petroleum systems within MidUpper Cretaceous to Tertiary

series (source rocks of Bahloul, Mouelha and Fahdene forma

tions, fractured reservoir of Abiod, Bou Dabbous and Halk el

Menzel formations, siliciclastic reservoir of Birsa Formation).

The real challenge is to understand the structure and the litho

stratigraphy of Cretaceous–Neogene series within this area to

reveal adequate zones for hydrocarbon accumulations. Based

on the interpretations highlighted within this paper, it seems that

the tectonic control widely conditioned the petroleum geology

in northeastern Tunisia. It is why structural surveys should be

done with more care and with emphasis on halo kinesis to

enhance our knowledge of petroleum systems in this area.

Acknowledgements: We would like to thank the Entreprise

Tunisienne d’Activités Pétrolières (ETAP) for providing the

seismic and wells data used in this paper. Igor Broska,

Ján Soták and Milan Kohút from the editorial board are

thanked for their time and valuable remarks. We also thank the

anonymous reviewers for their helpful reviews that improved

the manuscript.

107

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GEOLOGICA CARPATHICA

, 2017, 68, 2, 97 – 108

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