2D petroleum system analysis of the Tarfaya Basin, on-offshore Morocco, North Africa

Accepted Manuscript 2D petroleum system analysis of the Tarfaya Basin, on-offshore Morocco, North Africa Victoria F. Sachse, Axel Wenke, Ralf Littke, Haddou Jabour, Oliver Kluth, Rainer Zühlke PII:

S0264-8172(16)30261-6

DOI:

10.1016/j.marpetgeo.2016.08.006

Reference:

JMPG 2642

To appear in:

Marine and Petroleum Geology

Received Date: 8 April 2016 Revised Date:

3 August 2016

Accepted Date: 4 August 2016

Please cite this article as: Sachse, V.F., Wenke, A., Littke, R., Jabour, H., Kluth, O., Zühlke, R., 2D petroleum system analysis of the Tarfaya Basin, on-offshore Morocco, North Africa, Marine and Petroleum Geology (2016), doi: 10.1016/j.marpetgeo.2016.08.006. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

ACCEPTED MANUSCRIPT

2D petroleum system analysis of the Tarfaya Basin, onoffshore Morocco, North Africa Victoria F. Sachse1*, Axel Wenke², Ralf Littke1, Haddou Jabour³, Oliver Kluth4, Rainer Zühlke5 1

Institute of Geology and Geochemistry of Petroleum and Coal, Energy and Mineral Resources Group

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(EMR), RWTH Aachen University, Lochnerstrasse 4-20, 52056 Aachen, Germany ² Institute of Earth Sciences, Heidelberg University, 69120 Heidelberg, Germany; now: Statoil ASA, Norway ³ Deutsche Erdöl AG (DEA), 22297 Hamburg, Germany 4

National Office of Hydrocarbons and Mining (ONHYM), Rabat 10050, Morocco

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GeoResources STC, 69120 Heidelberg, Germany; now: Saudi Aramco, EXPEC Advanced Research Center, Dhahran 31311, Saudi Arabia.

*corresponding author: [email protected]

Abstract

This study presents a 2D basin model along a transect crossing the on- and offshore Tarfaya Basin, Morocco, in SE-NW direction. The aim of the project is to investigate the thermal

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evolution of the basin fill and its influence on the petroleum system. The modelling is based on a recently interpreted seismic section and includes new and published geochemical and organic petrological data from five wells. Core samples and cuttings provide information,

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which was used for thermal calibration of the model. Vitrinite reflectance in the Jurassic offshore basin fill reaches more than 1%. The modelled subsidence history, in combination

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with kinetic and geochemical data, were used to model hydrocarbon generation. In order to investigate the temperature, hydrocarbon generation and its timing, two 1D geohistory curves were extracted, one for the onshore inner shelf and one for the offshore deep water area. The modelling results suggest that deepest burial in the modern offshore area occurs at present day, whilst deepest burial in the onshore area occurred during the Oligocene depending on the location on the inner shelf. Based on the burial- and thermal evolution, significant hydrocarbon generation from Lower Jurassic source rocks took place from the Early Cretaceous until the Neogene in the offshore area. In the onshore area, petroleum 1

ACCEPTED MANUSCRIPT generation ceased in the Late Cretaceous. As salt deposition may play an important role in the thermal history in the Tarfaya Basin, a second model including salt was built, indicating increased Early Cretaceous hydrocarbon generation in the offshore area.

Key Words: basin modelling, petroleum system, hydrocarbon generation, maturity, vitrinite

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reflectance, Tarfaya Basin, Morocco, North Africa

1. Introduction

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The aim of this study is to increase the general understanding of the thermal and burial history, hydrocarbon generation potential, and timing of hydrocarbon expulsion in the Tarfaya

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Basin, on- and offshore western Morocco, North Africa (Figure 1). Seismic lines, studies on depositional environment and source rock analyses have been published over the last years, but petroleum systems modelling has not been published so far.

The 2D modelling is based on a basin analysis of Wenke (2014), which includes seismic to

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well tie, detailed seismic interpretation and stratigraphic correlations (sequence stratigraphy). In this study, data sets from five wells were used for the calibration of a 2D petroleum systems model. All wells are located directly on or close to the seismic line used for the

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model. Vitrinite reflectance has been measured on samples from organic rich intervals, allowing for a very good calibration of burial and temperature history.

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The main purpose of this study was to gain information on the maturity of source rock intervals which were previously described or assumed for the Tarfaya Basin. Oil shows in the well Cap Juby-1 have confirmed the existence of a petroleum system in the offshore Tarfaya Basin. Several potential source rock intervals have been proposed: Triassic rift (Triassic event), Lower Jurassic (Jurassic Turnover; Mader and Redfern, 2011), Middle Jurassic (Callovian Carbonate Crisis), Hauterivian black shales related to the Faraoni event Cretaceous OAE- related deposits (Barremian, to Campanian), Paleocene/Eocene (Jabour et al., 2000; Jenkyns et al., 2002; Davison, 2005; Wenke, 2014 and references therein; Figure 2; Table 1). Furthermore, local source rocks are assigned to the Berriasian (Berriasian 2

ACCEPTED MANUSCRIPT Terrestrial Runoff) and Oxfordian (Oxfordian Carbonate Crisis). Intervals with measured organic matter content have been encountered by DSDP Leg 47A, Site 397, drilled on the upper continental rise (northeast of Cape Bojador; Figure 1) containing Neogene and Lower Cretaceous (Hauterivian) sediments. Lower Miocene shales are regarded as potential source

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rocks, containing a mixture of aquatic and terrestrial organic matter (Cornford et al., 1979). Hauterivian mudstones and shales of this succession contain mainly continental organic matter (Cornford et al., 1979; Deroo et al., 1979). DSDP Site 369, drilled on the continental slope, contains Neogene to Lower Cretaceous sediments. Geochemical data support the

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presence of organic-rich shales and marls of Middle Cretaceous (Aptian to Albian) age which may act as potential source rocks (Arthur et al., 1979). These sediments have been eroded

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at Site 397, and the Cenomanian to Turonian sediments are missing at Site 369. Source rocks were described also for the onshore area: Aptian and Albian source rocks, Late Cretaceous organic- rich marls and shales, partly deposited during oceanic anoxic events (OAE 2 and OAE 3; i.e. Kolonic et al., 2005; Sachse et al., 2012a, 2014), and a potential

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Eocene source rock (Kuhnt et al., 2009; Sachse et al., 2011; 2014). Little is known about preCretaceous source rocks in the Tarfaya Basin. Very limited information is available from two wells in proximal inner shelf areas with dark grey to black shales (Wenke, 2014) and

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outcrops from Fuerteventura (Steiner et al. 1998). Bodin et al (2011) describe a 30 m interval of Lower Toarcian shales with a fair to good source rock potential for the eastern Tethyan

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domain of the High Atlas. A 600 m to 1400 m thick succession of argillaceous Silurian shales is present in the adjacent onshore Zag/Tindouf Basin from which a TOC content of 3% has been reported (Lüning et al., 2000; Ordovician-Silurian extinction). Furthermore deposits of the Late Devonian Kellwasser event have been proposed as potential source rocks. Wenke (2014) compiled information on source rock potential based on well data, literature and reported data (Table 1). Potential reservoirs may exist in the Triassic basin fill, where traces of gas and bitumen were mentioned by Wenke (2014) in wells Chebeika-1 and Cap Juby-1. For Middle Jurassic carbonates a technical discovery was reported from well MO-8 (MO: Moroccan; 45 liters; 3

ACCEPTED MANUSCRIPT 33.8°API; Wenke, 2014). This oil accumulation was assigned to Bathonian age, whereas Oxfordian oil shows were reported for MO-3 (API 38°; Wenke, 2014). Gas shows were recognized in well Cap Juby-1. Late Jurassic oil discoveries were reported from wells MO-2 and MO-3 (Tithonian reservoir; API 11.8-12.4° well MO-2), and heavy oil and gas from well

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MO-4. In the Early Cretaceous Tan-Tan delta (Heyman, 1989; Lee at al., 2004), several gas peaks were recognized, e.g. in wells TAR-1, LAY-8-2, LAY-8-3 (Tan Tan Formation). Gas peaks accompanied by “asphalt” (probably a highly viscous bitumen) were reported from wells MO-1, MO-3, and MO-6 (Hauterivian). Gas in wells i.e. LAY-8-2 and LAY-8-3 was

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reported, as well as “asphalt” and oil in well CORC-23-1. Several gas accumulations were recognized in wells (Cap Juby-1, CORC-23-1, EA-1, LAY-8-2, LAY-8-3) for the

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Eocene/Paleocene layers (turbidites and submarine fan sandstones; Heyman, 1989; Lee at al., 2004), as well as oil shows in well 23-1. Some shaly layers of the Early Jurassic, Lower Cretaceous and Neogene are regarded as seals (i.e. Wenke et al., 2011; Wenke, 2014; Figure 2).

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Our study will focus on source rock distribution and facies within the different potential source rock layers as well as burial and temperature history leading to maturation, petroleum generation and expulsion. Also migration trends along the 2D section are discussed as well

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as implications for the petroleum system.

2. Geological Background

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The evolution of the Tarfaya Basin is basically controlled by the post- Variscan break up of Pangea. Initial rifting in the Central Atlantic occurred in the Late Permian (Zühlke et al., 2004, and references therein). Late Permian to Triassic continental red beds and evaporites mark the beginning of the basin formation (i.e. Davison, 2005). Wenke et al. (2011) subdivided the Meso- to Cenozoic development of the Tarfaya Basin into six stages: 1) a rift and sag stage from Tartarian (Late Permian) to Pliensbachian (Early Jurassic); 2) an early drift stage from Pliensbachian/Toarcian to Mid-Late Tithonian (Late Jurassic), 3) a mature drift phase stage from the Late Tithonian to Late Aptian (Early Cretaceous); 4) Early Albian to Maastrichtian (Late Cretaceous) mature drift stage coupled with initial Atlasian compression; 5) mature drift 4

ACCEPTED MANUSCRIPT and initial Atlasian uplift during the Maastrichtian to Early Oligocene (Late Paleogene); 6) the mature drift stage with peak Atlasian uplift and erosion since the Late Oligocene. The longterm structural and stratigraphic development of the Tarfaya Basin is compiled in Figure 2. The oldest Mesozoic sediments of the Tarfaya Basin are of Lower Triassic age and consist of

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continental to restricted marine red conglomerates and sandstones. Marine ingressions in combination with high evaporation rates during the Late Triassic/ Early Jurassic (NorianSinemurian) resulted in the development of a huge salt province. Fault blocks, NE-SW

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striking syn-rift normal faults as well as horst and grabens structures developed during this rift/sag phase (Hafid et al., 2008). The Lower Jurassic post-rift sequence is represented by a

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prograding clastic ramp followed by Middle to LateJurassic carbonate platform (e.g. Wenke et al., 2011; Wenke, 2014). After a major regression at the end of Jurassic, Lower Cretaceous delta systems developed (Tan Tan, Boujdour delta systems; Hafid et al., 2008) which are covered by shallow marine to lagoonal Upper Cretaceous sediments (e.g. El Khatib et al., 1995). Increasing sedimentation rates since the Hauterivian and resulting

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lithostratigraphic pressures triggered the mobilization of the Triassic salt in the western deeper parts of the Tarfaya Basin and rising salt diapirs occurred in the shelf break to basin area of the Tarfaya Basin. Salt movement induced a collapse of the Jurassic slope causing

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the development of growth faults in the Lower Cretaceous shelf break area (Tari et al., 2003; Wenke, 2014). Furthermore, the starting collision between Europe and Africa (Alpine

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orogeny) might has enhanced the diapir rise since the Late Cretaceous (Neumaier et al., 2015). Regional Alpine development with the uplift of the High Atlas resulted in a flexural uplift of the shelf area of the Tarfaya Basin as well as the development of major regional unconformities (Base Cenozoic or Initial Atlasian Unconformity and Intra Oligocene or Peak Atlasian Unconformity; Wenke 2014). The Cenozoic basin fill is dominated by marine intervals in the Paleocene-Eocene, continental sandstones and conglomerates in the Oligocene and sandy limestones of Miocene age (i.e. Davison, 2005; El Khatib et al., 1995). Detailed summaries of the Tarfaya basin evolution are given by Lancelot and Winterer

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ACCEPTED MANUSCRIPT (1980), Davison (2005), and Wenke (2014). A compilation of the lithology and stratigraphy of the Tarfaya Basin is shown in Figure 2.

3. Samples and Methods 3.1. Database

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For the 2D model presented in this paper a NW-SE striking 2D seismic profile was used, covering the onshore part of the Tarfaya Basin in the SE, the slope, and the deeper basin parts in the NW (Figure 4). The stratigraphy of the wells located on the seismic line (well 1)

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and of the projected wells (well 2, well 3, well 4 (“Sondage 1”), and well 5 (“Sondage 2”) were tied to the seismic line of the Cap Juby transect (Wenke, 2014).

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Vitrinite reflectance has been measured in order to establish the present thermal maturation of the sediments and to reconstruct the thermal history of the area. Rock- Eval pyrolysis and TOC data were measured for all potential source rock intervals and together with kinetic data (onshore area Cenomanian, Turonian, and Eocene; Sachse et al., 2011) were used for the

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hydrocarbon modelling in the 2D model. Since the deposits of the Toarcian are regarded as potential source rocks (Jenkyns et al., 2002), they were also taken into account for the model. Jurassic source rock parameters taken from a locality in the Middle Atlas (Sachse et

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al., 2012b) were implemented for the potential Jurassic source rock, due to the lack of in-situ

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parameters for this layer.

3.2. Organic Petrology and Geochemistry In this study seven samples of Well 1, 11 samples from Well 2 and three samples of Well 3 were used for the vitrinite reflectance measurements, covering various stratigraphic units. The standard procedure for conducting measurements was described by Taylor et al. (1998) and the details of sample preparation and microscopic equipment were summarized in Sachse et al. (2012a). In addition, results on Wells 4 (“Sondage 1”) and 5 (“Sondage 2”) (Sachse et al., 2012; Sachse et al., 2014) were included as well as those of DSDP Wells 397 and 369 (Cornford et al., 1979). 6

ACCEPTED MANUSCRIPT Thirty-two samples of Well 1, 14 samples of Well 2 and three samples of Well 3 have been measured for total organic carbon (TOC) content. For this purpose total inorganic carbon (TIC) and TOC were measured with a LECO RC-412 carbon analyzer via IR adsorption in a two stage measurement process (TOC between 350°C and 520°C; TIC between 520°C and

following the procedure described by Espitalié et al. (1985).

3.3. Basin Modelling

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1050°C). Rock-Eval pyrolysis was performed using a DELSI INC Rock-Eval II instrument

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For the forward modelling approach of petroleum systems various geophysical, geological, geochemical and thermodynamic parameters are combined and converted into a numerical

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model. Finally, this model is used to quantify processes during basin formation. General approaches of this type of basin modelling were described by i.e. Welte and Yükler (1981), Welte et al. (1997) and Hantschel and Kauerauf (2009). Numerical simulations integrating both, onshore and offshore domains of a sedimentary basin have been carried out in 2D

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(e.g., Brandes et al., 2008) and 3D (e.g., Kroeger et al., 2008; Sachse et al., 2016). This study was created using PetroMod 2014 (Schlumberger) software. Based on seismic interpretation, seismic to well ties, well correlation (Wenke, 2014) and literature information

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on basin evolution (i.e. Ranke et al., 1982; Davison, 2005; Hafid et al., 2008), a conceptual model was constructed. Several events (time steps) were considered and brought into a

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temporal framework. Potential events include deposition, non-deposition (hiatus) and erosion which are defined by a specific start and end point in time. This discrete model of the basin history is then transferred into a numerical model, considering physical and chemical properties. The chronostratigraphic subdivision followed the compilation of Wenke (2014) and is based on Choubert et al. (1966), Mitchum et al. (1977) and Ranke et al. (1982) (Figure 2). Assigned paleo water depths were estimated based on eustatic sea level curves (Haq et al., 1987; Haq and Shutter, 2008) and on interpretations based on sequence stratigraphy (Wenke et al., 2011; Wenke, 2014; El Jorfi et al., 2015). Wenke (2014) described six sequences which were identified based on 2nd order sequence stratigraphy and are 7

ACCEPTED MANUSCRIPT separated at the top by major unconformities. Alluvial/fluvial rift-sediments and restricted marine sediments are characteristic for the Permian-Triassic environment (1), which changed to deposition of Jurassic carbonate ramps and platforms (2). Sea level rose during the Late Triassic, increasing during the Early Jurassic. In the Middle Jurassic marine regression was

the late Oxfordian.

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identified. Marine conditions prevailed, with a marine flooding event (marine transgression) in A major forced regression event marks the beginning of the Early

Cretaceous. Renewed transgression occurred since the Valanginian. Early Cretaceous deltaic sediments (3) are covered by open marine fine clastic and carbonate deposits (4),

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which are related to continued transgression during Aptian to Early Turonian age. During the Santonian to Campanian, regression led to fluvial to coastal deposition on the inner to central

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shelf. A clastic shelf margin developed through the Paleogene (5) unconformably overlain by Neogene clastic sediments on the shelf and in the abyssal plain deposited by terrestrial runoff via deltas and widespread bypass sedimentation (6). Transgression prevailed during the Paleocene to Eocene, and switched to regression during the Oligocene to Pliocene-

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Quaternary (El Jorfi et al., 2015). Based on the paleo sea level, the sediment water interface temperature was calculated for latitude 29° in North Africa (Wygrala, 1989). Basal heat flow and erosional events are the most important parameters affecting the burial- and thermal

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history. Temperature is a critical parameter for basin evolution and hydrocarbon formation as organic matter reacts to increasing thermal stress. It is indispensable for the simulation to

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calculate thermal conditions for every time step of the model. The reconstruction of the heat flow history was done using literature information on times of increased heat flow (rifting phases, volcanism etc.) and the geothermal gradient. Rimi (1990) and Zarhloule et al. (2005) postulated geothermal gradients of 23-34°C/km for the entire Atlantic margin and values between 20-30°C/km for the Tarfaya Basin. For the calculation of vitrinite reflectance as a calibration parameter for heat flow modelling during maximum burial (Senglaub et al., 2006), the Easy%Ro algorithm (Sweeney and Burnham, 1990) was used. The algorithm is applicable for a VRr range between 0.3% and 4.6% (Sweeney and Burnham, 1990). For the calibration of the burial and temperature 8

ACCEPTED MANUSCRIPT history the measured vitrinite reflectance values are plotted against the calculated vitrinite reflectance curves. To calibrate the 2D model presented in this study, 1D extractions of the wells were created. In addition extraction points were chosen in the deep offshore (Location A), on the slope (Location B) and in the onshore area (Location C) (Figures 1 and 4) in order

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to illustrate temperature, maturity and petroleum generation histories (Figures 5, 6 and 7).

4. Results and Discussion 4.1. Organic Petrology

A compilation of measured vitrinite reflectance values and geochemical data is given in Table

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2 and Figure 3. The samples of Well 1 and Well 2 show a characteristic pattern of increasing vitrinite reflectance from top to bottom. Highest values of 1.25%VRr were measured for the

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Jurassic/Triassic samples in Well 1, whilst Well 2 shows highest values of 1.1%VRr in the Early Liassic. Samples of Well 1 contain a moderate to high amount of well visible organic particles. Well 3 shows highest values in the Late Jurassic (1.45%VRr). Using fluorescence microscopy algae were visible in one sample (depth 1100 m), showing a bright fluorescence indicating immature organic matter. In the case of a sample from depth 4350 m, which is red

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sediment, a higher maturity was indicated using fluorescence microscopy because of the darker character of the organic material. The same sample showed oxidized organic material under incident white light. The investigated Triassic sample has a coarse grain size and high

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porosity representing a potential reservoir rather than a potential source rock.

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One sample from Well 2 contains a large amount of measurable organic particles but these are mainly composed of resedimented vitrinite. The Cretaceous samples are mature, but have not reached peak oil generation. The Jurassic samples have clearly a higher maturity corresponding to the end of the oil window. Even though low TOC contents were measured in the samples of Well 3, in one sample organic matter was observed using fluorescence microscopy. The brightness of these liptinites matches with the vitrinite reflectance value of 0.44 %, representing immature material. The other samples from this well contain resedimented vitrinite.

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ACCEPTED MANUSCRIPT In addition, published vitrinite reflectance data from previous studies from outcrop (Sachse et al., 2011) and well data (Sachse et al., 2012a, 2014) were considered.

4.2. TOC and Rock-Eval pyrolysis

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Quantity and quality of organic matter was analyzed using TOC and Rock- Eval pyrolysis data. Rock- Eval measurements provide information to calculate the hydrocarbon generation potential of the organic matter. Oldest available samples originate from the Triassic layer in Well 1, and the Early Liassic in Well 2. Thus both wells cover multiple potential source rock

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units. Highest TOC values are reached for the Early Cretaceous TanTan Formation in Well 2, with values up to 1.2%. Moderate values are reached in the Albian layers above (0.5%).

show values of up to 0.5%.

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Middle and Late Jurassic samples show low TOC values of up to 0.4%. Liassic samples

Generally higher values are reached in Well 1, where Triassic sedimentary rocks show TOC values of up to 1.5%. Oligocene/Eocene sediments show values of up to 2.6%, whilst the

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layers in between fluctuate between 0.2 and 1.1% (Table 2).

Rock- Eval results for Well 1 show highest S1 values of up to 15 mg/g rock for samples from the Triassic-Jurassic, whereas the highest S2 values were measured for Oligocene/Eocene

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samples (up to 10 mg/g rock) (Table 2). Calculated HI values (HI=(100*S2)/TOC) vary

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between 5 (Late Jurassic Kimmeridgian-Tithonian) and 370 mg HC/g TOC (Eocene). Highest S1 and S2 values for Well 2 were measured in the Early Cretaceous succession (S1: 11 mg/g rock; S2: 5 mg/g rock). HI values for this unit reach 432 mg HC/g TOC. Samples of Jurassic and Triassic age usually have a high S1 value in comparison to S2. This can be caused by the presence of migrated oil, but a contamination of samples by organicbased drilling fluids is most likely. The evaluation of the Rock-Eval data of the measured samples shows that nearly all samples have a low potential for oil or gas generation. Only two samples, one of Oligocene age (depth 1400 m, Well 1) and one of Eocene age (depth 1500 m, Well 1) show a high HC generation potential (kerogen type-II). All other samples 10

ACCEPTED MANUSCRIPT show source rock qualities corresponding to kerogen type-II/III or even type IV (“dead” carbon) according to measured HI/OI values. The maturity of a potential source rock sample can also be estimated by the Production Index (PI) and Tmax. It is conspicuous that the samples are separated into two groups, those with a high PI and those with a low PI.

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Regarding the Oligocene and the Eocene sample, the PI is very low with a Tmax < 430°C leading to the conclusion of an immature organic material. This interpretation matches with the results of vitrinite reflectance measurement, which also predict immature organic matter. The deeper samples show higher PI, but still very low Tmax values. The presence of migrated

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oil generally leads to an anomalously high PI value and could be an explanation for the values between 2200 and 4792 m, or alternatively an oil based drilling mud, which seems to

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be more likely.

The kerogen in most samples from Well 2 is type II/III. Only two samples (depths 605 m, 2296 m), show mixtures of kerogen type I and II. HI values range from 38 to 432. Tmax values are highly variable ranging from 403°C to 475 °C. In general, the data indicate increasing

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maturity towards the deeply buried, Jurassic intervals, whereas the samples from less than 2300 m depth are immature/very early mature. This is also in agreement with information from DSDP Leg 397, showing immature source rocks in the entire succession (Neogene to

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Early Cretaceous).

Based on Rock-Eval data, the offshore samples show lower source rock quality compared to

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those published for the onshore area (Sachse et al., 2011, 2012a, 2014), where source rock potential was confirmed for the Albian, Cenomanian to Coniacian, and Eocene age. Differences in quality might be related to lateral facies heterogenities. In summary, a low organic carbon content for both the carbonate and clastic samples from the Jurassic to lowermost Cretaceous was identified for offshore samples from this study, as the sediments were deposited in a marine setting with a starting build-up of a shelf system, but mixed with terrestrial input which was transported over the shelf. Lower Cretaceous sediments which were deposited in a deltaic system, include high amounts of oxidized terrestrial material. This 11

ACCEPTED MANUSCRIPT material was probably transported over a long distance from the Zag/Tindouf Basin to the coastal area and deposited in the area of the Tan Tan Delta. Conservation of the organic matter in this depositional environment is not favoured, due to dilution with fluviatile, organicpoor sediments. During the Upper Eocene/Lower Oligocene fine grained sediments were

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deposited representing a mixture of marine and terrestrial organic matter. Regarding the presence of a Toarcian source rock, Wenke (2014) has shown that Well 1 reaches clinoforms of a prograding Jurassic clastic ramp of Toarcian age which might result in a high sediment flux disturbing the source rock deposition. Steiner et al. (1998) identified a Toarcian

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black shale on top of oceanic crust exposed on Fuerteventura. It is therefore possible that

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Early Jurassic source rocks are present in distal direction of well 1 (see also Table 1). Results on organic matter distribution in the Tarfaya Basin are similar to those obtained for the continental margins of offshore Pakistan (Arabian Sea; Littke et al., 1997) and Peru (Reimers and Suess, 1983). These authors pointed out, that organic matter preservation is highly depending on the location of the oxygen minimum zone (OMZ), which is controlled by

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factors such as water depth, the location of currents as well as water circulation and wind directions, and the amount of bioproductivity (upwelling and inflow of nutrients and terrigenous organic matter). Highest preservation of organic matter was achieved for the

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water column within the upper and central part of the OMZ, whereas lower values were measured for increasing water depth. Highest TOC and HI values occur in Arabian Sea

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samples where the OMZ hits the slope area (Littke et al., 1997). Same holds true for the continental margin offshore Peru, but there the interaction of the Peru Current system and the shelf-slope morphology is the controlling factor for the preservation of the organic matter (Reimers and Suess, 1983). Considering these findings a modern organic matter deposition and preservation and the shift of the Moroccan coastline during the Jurassic, Cretaceous and Cenozoic (Einsele and Wiedmann, 1982; Figure 8), the shift of ocean currents, water depth and upwelling zones (Lüning et al., 2004; Kolonic et al., 2002; Kuhnt et al., 2001, 2005), the assumption of decreasing amounts of organic matter with water depth and towards the offshore is reasonable. Furthermore, the varying Cenomanian-Turonian sedimentation rates 12

ACCEPTED MANUSCRIPT calculated for the deep offshore Tarfaya Basin exceeding 0.1 cm/ky (DSDP 367; NzoussiMbassi et al., 2003) to ca. 1.1-1.7 cm/ky at Tarfaya and around 10-22 cm/ky for continental shelves (Senegal; Kolonic et al., 2002; Nzoussi-Mbassi et al., 2003) impact the preservation conditions of the organic matter. A good example showing the importance of the above

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mentioned parameters is the Tarfaya Turonian black shale, which was deposited in a deep shelf area (200-300 m water depth; Einsele and Wiedmann, 1982),. The Turonian does not show high organic matter quantity and quality in the present-day offshore area, but high

4.3.

2D numerical modelling

4.3.1 Input and Requirements

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source rock potential in the onshore coastal area (Sachse et al., 2011, 2012b, 2014).

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The 2D model event history consists of 29 preserved layers (Figure 4), and 35 events in total. Based on sequence stratigraphic interpretations by Wenke et al. (2011) and El Jorfi et al. (2015), six erosional events/ unconformities were assigned to the model (Table 3). The earliest one occurred at the end of the Late Triassic (top Rhaetian), a second erosional event was assigned to the Toarcian, and a third occurred at the end of the Late Jurassic

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(Tithonian). A small amount of erosion was assumed for the Latest Aptian and major erosion events for the Late Cretaceous (Maastrichtian) and to Mid-Oligocene when multiple layers down to the Albian were eroded. For the Toarcian, Late Jurassic and Oligocene erosion

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events, the erosional thickness was assigned as increasing from the slope towards the inner

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shelf (Wenke, 2014; El Jorfi et al., 2015). Present maximum burial depths of Triassic sediments are at ~11 km (Figure 4). Triassic salt bodies were identified in the deeper parts of the Tarfaya Basin (e.g. Davison, 2005; Wenke, 2014) which were basinward mobilized during the Early Cretaceous (Hauterivian to Aptian) due to strongly increased sediment input (Wenke, 2014; Tari et al., 2013). In the model setup, salt bodies were assigned using the facies piercing tool of the PetroMod software (Figure 4). As salt has a higher thermal conductivity compared to shales or sandstones, the correct assignment of salt is necessary for modelling the temperature field through time. Furthermore, the salt layer might have played a role in the petroleum system of the Tarfaya 13

ACCEPTED MANUSCRIPT Basin, by forming an effective seal, and influencing the thermal regime due to “chimney effects” above the salt and thermal blanketing below. Table 3 summarizes the lithologies, deposition and erosion ages of the different layers. For reconstruction of the paleo temperatures since the Tartarian (Late Permian), the heat

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flow was set to maximum values of 70 mW/m² both for volcanic phases (Canary Island formation since the Oligocene) and the Toarcian to Tithonian rift phase. Thus, 70 mW/m² are assigned for the offshore area of the Tarfaya Basin continuously decreasing towards the

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shallow offshore and present day onshore area. For the Cretaceous lowest values of 45 mW/m² in the onshore area and 50 mW/m² in the offshore Tarfaya Basin are assigned

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(compare Neumaier et al., 2015). As the deepest burial is achieved at present- day in the deeper, offshore part of the Tarfaya Basin, the earlier, elevated heat flow values do not play a major role for present- day maturity and model calibration, but lead to an early petroleum generation starting in the Jurassic.

In the 2 D model hydrocarbon generation is investigated from various source rock layers with

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the following properties: Eocene: TOC of 2 %, HI of 550 mgHC/gTOC; Santonian: 1.5 % TOC, HI of 450 mgHC/gTOC: Coniacian: TOC of 1 %, 450 mgHC/gTOC; Cenomanian and Turonian: 3 % TOC, HI of 600 mgHC/ gTOC, same for the Oxfordian. Albian and Aptian:

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TOC of 1 %; HI of 100 mgHC/g TOC: Lower Cretaceous (i.e. Hauterivian): was not considered as a potential source rock. Data on samples from DSDP Leg 397 revealed TOC

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values between 0.6 and 1.0%, but the predominance of terrestrial organic matter (Cornford et al., 1979; Deroo et al., 1979) suggests a low source rock potential. For the Eocene, Cenomanian, and Turonian the kinetics presented from Sachse et al. (2011) were adopted, for the Albian and Aptian the kinetics from Pepper and Corvi (1995; Type II). Callovian and Toarcian potential source rocks were modelled as Type I/II kerogen with a measured TOC of 4% and a HI of 450 mg HC/ g TOC, based on average values measured for a Pliensbachian source rock in the Ait Moussa area of the Middle High Atlas (Sachse et al., 2012b). The reaction kinetics were also adopted from this location (Sachse et al., 2012b). The Rhaetian 14

ACCEPTED MANUSCRIPT layer was assumed to have source rock potential with a TOC content of 1.5%, HI of 150 mgHC/gTOC and a Type III Pepper and Corvi (1995) kinetics was assigned. It should be noted, that the assigned source rock parameters might lead to a slight overestimation in the offshore area with respect to petroleum generation potential, as average values including

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onshore data were assigned and not only the low values revealed in offshore wells. Reservoirs and seals were defined following literature information (see Introduction; Heyman, 1989; Lee at al., 2004; Wenke et al., 2011; Wenke, 2014; El Jorfi et al., 2015). Petrophysical

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4.3.2. Thermal and maturity evolution

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properties assigned to the layers are summarized in Table 4.

Thermal calibration of the 2 D models was performed by comparing the measured vitrinite reflectance data with calculated data from the same wells as described above. The present day onshore area reached its deepest burial before the onset of basin inversion at the beginning of Paleogene (Figure 7A). In our model eroded sediments reached a total

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thickness of up to 1.2 km, increasing towards the east. Deepest burial of the sediments in the offshore area is reached at present day. Our results support thermochronological analyses by Sehrt (2014) and seismic velocity analysis by Wenke (2014), who calculated that rock

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uplift and exhumation resulted in the erosion of 1.0 to 1.6 km thick Cretaceous to Paleogene sediments in proximal onshore parts of the NE Tarfaya Basin. Further, the magnitude of

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erosion increased from west to east in the onshore Tarfaya Basin. For the deep offshore of the basin 800 m of eroded Late Cretaceous are assumed (Figures 5A; 6A) Generally, burial phases which were followed by erosion are not affecting the present-day maturity, as the deepest burial and thus highest temperatures are achieved at present-day (Figures 5A, B; 6A, B). For the Toarcian layer the assigned burial and erosion history leads to present-day temperatures of up to 220°C in the offshore and 160°C in the onshore area (Fig. 5B, 6B, 7B, 9), both corresponding to the dry gas window (Fig. 10). Post-Berriasian layers are in the main 15

ACCEPTED MANUSCRIPT oil window at present-day. Eocene and Lower Oligocene layers offshore and Barremian to Aptian layers onshore have only reached the early oil window (Fig. 10). All layers above can be regarded as immature (Fig. 10). Temperature increased significantly from the Jurassic to the Cretaceous and again slowly since the Oligocene in the offshore area (Fig. 9).

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Temperature increased constantly during the Jurassic in the onshore Tarfaya Basin, and high temperatures were reached from the Late Cretaceous until the Oligocene (Figs. 7, 9). Then, a cooling event started, leading to present-day temperatures of 160°C for the Toarcian

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and 54°C for the Cenomanian (Fig. 7) in the onshore area.

The consequences of this basin development for temperature and maturation history are

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shown in Figures 9 and 10. The temperature and maturity distribution shows a clear trend, with highest temperatures and thus maturities reached in the offshore Tarfaya Basin decreasing towards the onshore part.

4.3.3. Salt Piercing Model

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Salt movements are known for the offshore Tarfaya Basin and were considered in a second model to study the effects of slightly higher temperatures and maturities above the salt due to its higher thermal conductivity compared to other sedimentary rocks. In contrast sub-salt

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sediments reach slightly lower maturities. In this model the onshore layers close to the coast up to the Bathonian reach 205°C and are in the dry gas window (2- 4%VRr) (Fig. 11). The

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Oxfordian (coastal) reaches the late or main oil window. In the offshore area Valanginian/Berriasian sediments reach the late or main oil window If present, Cenomanian and Turonian sediments will be in the early oil generation stage in the deep offshore (max. 110°C), but immature in the onshore area (max. 55°C). The youngest onshore sediments in the early oil window are Albian, with max. temperatures of 65°C (Figure 11A). The entire layer stack above never reached temperatures above 60°C, and remained immature (Figure 11B). Petroleum generation histories for the Toarcian layer are shown for Locations A, B and C in Figure 12. Significant variations for present- day 16

ACCEPTED MANUSCRIPT values are not given, but the influence of salt definitely affected paleo petroleum generation, especially during the Cretaceous in the deeper offshore (Fig. 12). Higher TR were achieved much earlier in the deeper offshore moderately increasing during the Cretaceous. A second generation pulse was observed since the Eocene. Comparing to the no salt model, a higher

4.4.4. Petroleum Generation and Expulsion

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maturity on the shelf is observed and lower maturity in the deep offshore.

Initial petroleum generation in the deep offshore parts of the Tarfaya Basin started after the

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deposition of the Toarcian sediments. Highest transformation ratio values are reached at present-day (95-98%), but increased significantly during the Early Cretaceous and

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continuously in the Paleogene and Neogene (Figure 5B). Middle Jurassic potential source rocks (i.e. Callovian) started petroleum generation in the Late Jurassic, with transformation ratios continuously increasing during the Early Cretaceous (45%) and moderately increasing during the Late Cretaceous and Paleogene. Maximum values of 88 % are reached at present

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day. Early Cretaceous (Aptian) potential source rocks started generation in the offshore parts of the Tarfaya Basin in the late Late Cretaceous. Transformation ratio increased during the Paleogene, reaching highest values of 43% at present-day. Stratigraphically higher potential

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source rocks, if present (Cenomanian, Turonian), would have started generation in the latest Cretaceous, with higher TR values since the Oligocene reaching maximum values of 33 %

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recently. Even the Eocene sediments, if present as potential source rocks, would reach a TR value of 20 %.

Lower maturities are generally reached on the shelfal and onshore parts of the Tarfaya Basin. The only layer which reaches maximum transformation ratio values of >90 % in the entire onshore area is the Toarcian (Figure 7B). In the onshore area transformation started in the Middle Jurassic, increased significantly during the Late Jurassic to Early Cretaceous and moderately during the Paleogene to Neogene. Potential Callovian source rock layers started generation in the Late Jurassic, smoothly increasing during the Early Cretaceous, and

17

ACCEPTED MANUSCRIPT significantly increasing in the Late Cretaceous. In the Miocene a maximum of 90 % TR was reached. Hydrocarbon generation in the Albian source rock layer started in the latest Cretaceous, and approached final transformation ratio values of 4 % in the Late Miocene. These values

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decrease further to the east. The potential Cenomanian source rocks also reach low TR values of 3 % since the Miocene. Late Cretaceous source rocks have TR values of <2 %, whereas the Eocene source rocks show no generation. In summary, the latter source rocks

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have not generated significant amounts of hydrocarbons in the onshore Tarfaya Basin.

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5. Conclusions

2D modelling of an east- west trending transect through the on- and offshore Tarfaya Basin provides insights into the burial-, thermal- and maturation history, the petroleum generation from various source rock levels and the respective timing of expulsion. In contrast to the onshore area, where Late Cretaceous to Paleogene basin inversion resulted in erosion and

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uplift (see Sehrt, 2014), the offshore basin was continuously buried until present-day, with the exception of short-term uplift and minor erosion. Highest temperatures in the offshore basin are reached at present day. In the onshore area, they occurred in the Oligocene.

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Maturation of organic matter and petroleum generation are strongly related to temperature history, with major phases during the Early Cretaceous and the Oligocene/Miocene in the

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offshore area.

2D modelling covers Toarcian, Callovian, Aptian, Albian, Cenomanian, Turonian, and Eocene potential source rocks. The results clearly show, that Jurassic sediments are the most important source rocks in the Tarfaya Basin, provided that they developed across the entire basin. Late Cretaceous potential source rocks, if present in the offshore area, locally entered the oil window since the Miocene/ Pliocene and may have marginally contributed to hydrocarbon generation. This matches with observations from DSDP Site 397 which indicate immature organic matter in the Hauterivian (Cornford et al., 1979), depending on the exact 18

ACCEPTED MANUSCRIPT location of the source rock layer. The presence and spatial distribution of potential Late Cretaceous organic rich sediments in the offshore basin has to be proven by future wells. Further, geochemical analysis of selected samples of Well 1 and 2 support the previous published results on the source rock intervals, but show a lower quality of the organic matter

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in the offshore area. This might be related to the best preservation conditions in the shallow parts of the continental margin as compared to the deeper margin, where labile, marine organic matter is greatly degraded. Similar situations exist at present-day at oxygen-depleted margins such as offshore Pakistan or Peru. Consequently a restriction for significant

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petroleum generation in the offshore area could be possible, but remains questionable as especially the most important source rock layers are not sufficiently tested due to poor

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sample availability and quality (i.e. Jurassic). Possible reservoir rocks include the Tithonian carbonates located at short migration distances from source rocks. However, reservoir distribution is highly depending on transgressive/regressive cycles and lateral facies heterogeneities. Acknowledgements

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We thank DEA for financial support. ONHYM is gratefully acknowledged for data supply and logistic support. Particularly we thank Lahcen Boutib and Abdelouahed Lmoubessine for an excellent introduction to the regional geology in the field. Furthermore, this paper greatly

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an earlier draft.

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benefitted from constructive comments by Christian Brandes and an anonymous reviewer on

6. References

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Tables Table 1 Compilation of source rock parameters, used for petroleum system modelling (based on Wenke, 2014). Wells: CJ-1: Cap Juby; PC: Puerto Cansado; MO: Moroccan Wells; *used for modelling. Kerogen Type

Indications / Reference

≤3

HI (mgHC/ gTOC) 150-450

Paleocene/Eoc ene*

Coniacian*

PaleoceneEocene temperatur e maximum OAE-3

II/III

Sachse et al., 2011

≤7

≤ 740

II

Santonian*

OAE-3

≤ 5.6

≤ 700

Campanian

OAE-3

≤ 4.5

≤ 650

Turonian*

OAE-2

≤8.5

Cenomanian*

OAE-2

≤16. 8 (3)

Albian*

OAE-1c

Aptian*

OAE-1b

I/II

I/II

≤600

I/II

≤780

I/II

≤3

≤150400

II/III

≤1.3 5 (1)

≤200 (100)

III/IV

≤200

III/IV

≤200

III/IV

-

III

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≤ 6 (DSDP 369)

Barremian

OAE-1a

≤1.3 5

Hauterivian

Faraoni

≤0.5

Berriasian

Terrestrial Runoff

≤0.5

≤1

TOC(%)* HI(mg/g TOC) * 2 550

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TOC (%) Shelf Slope

Sachse et al., 2011; 2014 Sachse et al., 2011; 2014 Sachse et al., 2011; 2014 Sachse et al., 2011; 2012; 2014 Sachse et al., 2011; 2012; 2014 Sachse et al., 2011; 2014 i.e. CJ-1; MO-2; MO4; MO-7; PC-1 (Wenke, 2014) i.e. CJ-1; MO-2; MO4; MO-7; PC-1 (Wenke, 2014) i.e. CJ-1; MO-2; MO4; MO-7; PC-1 (Wenke, 2014) Poor in MO wells; (Wenke,

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Event

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Source Rock Unit

1 450 1.5 450

3 600 3 600 1 100 1 100

ACCEPTED MANUSCRIPT Carbonate Crisis

≤2.4 9

≤2.49

-

Callovian*

Carbonate Crisis

≤2.4 9

≤2.49

-

Toarcian*

Toarcian turnover

≤0.3;

Triassic (Rhaetian*)

Triassic Event

≤2.5

≤1; ≤8.89 DSDP well547B ≤0.63

SilurianOrdovician

Extinction

-

2014) Poor in CJ1; (Wenke, 2014) Poor in CJ1; (Wenke, 2014) PC-1;CJ-1; (Wenke, 2014)

-; I

≥300

II/III

-

-

4 450

CJ-1; (Wenke, 2014) no; (Wenke, 2014)

1.5 150

SC

-; 550

3 600

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Oxfordian*

Depth (m)

Stratigraphic Unit

1

970

1

1100

1

1200

1

1300

Middle to Late Miocene Middle to Late Miocene Middle Miocene Middle Miocene Oligocene Early/Middle Eocene Hauterivian

1 1 1 1 1

1600 1700 1800 2050 2200

1

2300

1 1 1

3100 3300 3385

TOC (%)

S1 (mg/ g rock)

Berriasian to Valanginian Berriasian to Valanginian Berriasian to Valanginian Kimmeridgian/ Tithonian Kimmeridgian/ Tithonian Oxfordian? Oxfordian? Oxfordian?

-

1.02

HI (mg/g OI TOC) (mg/gT OC) 63

0.12

0.98

0.17

238

2.3 2.7

1.10

167

-

0.8

0.78

225

66

0.10

0.61

208

60

0.24

6.49

141

279

0.34

9.89

131

369

1 0.49

372

0.63

291

0.05

0.34

397

48

0.09

0.30

248

37

0.14

0.03

374

5

0.65 0.6

-

0.76 0.54 0.43

0.2

417

0.13

413

0.15

412

0.14

425 420

0.04 0.03

421

0.13

418

0.13

441

0.13

417

0.23

-

0.82

56

0.7

-

-

48

1.1 0.09

PI

11

0.14

0.07

Tmax (°C)

0.49

1.18

0. 39 0. 47 0. 45 -

-

S2 (mg/ g rock)

0.77

0. 37 -

EP

1400 1500

AC C

1 1

VR r (% ) -

TE D

Well

M AN U

Table 2 Compilation of TOC, Rock- Eval pyrolysis and vitrinite reflectance data measured for Wells 1, 2 and 3.

0.71 0.1

0.04

419

6

-

-

6.72

0.6

252

79

4.05

0.62

148

115

3.25

0.36

91

84

0.92 0.87 0.9

ACCEPTED MANUSCRIPT

3800

1

4025

1

4120

1

4300

1

4350

1

4400

2 2 2 2 2 2 2

2

2

2

302305 404407 433,5438,5 604605,8 20012002 21012103 21962198 2296, 52297, 5 3295, 03298, 0 3455, 03458, 0 3650, 03657,

Albian? Albian? Albian?

Early Cretaceous Early Cretaceous Early Cretaceous Kimmeridgian?

AC C

2

Triassic

-

0.7

-

0.6

8.86

6.01

6.4

0. 85

14.9 2

0.8

-

0.8

1. 25

1.5

-

0.67

5.28

3.62

0. 68 -

Kimmeridgian?

0.18

0.33

0.42

1.10

0.64

0.5

0.56 0.2

0.95

53

120

-

0.97

-

0.83

-

0.85

-

0.78

32

132

76

2.11

134

142

-

0.52

0.67

0.63

534 49

94 173

419

0.17

0.05

0.25

75

78

419

0.13

432

76

416

-

-

-

-

-

99

93.05

403

-

-

-

-

0.93

-

-

-

-

318

105

-

0.67

0.06

0.42

0.19

5.25

-

-

0.42

10.4 5

0.80

0.8

-

-

-

-

0.3

0.5

3.25

1.63

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

0.5

Malm/ Dogger 0.43

Early Liassic 1. 2

-

1.21

Kimmeridgian?

1. 11

0.97

25

94

121

-

39

359

77

0.96

7.51

-

1. 12

116

1.3

-

0. 59 0. 58 0. 67 0. 68

0.35

-

RI PT

1

0.89

SC

3750

0. 64

M AN U

1

Jurassic/ Triassic Intermediate Jurassic/ Triassic Intermediate Jurassic/ Triassic Intermediate Jurassic/ Triassic Intermediate Jurassic/ Triassic Intermediate Jurassic/ Triassic Intermediate Jurassic/ Triassic Intermediate

TE D

3645

EP

1

0.35

ACCEPTED MANUSCRIPT

3 3

3

1. 12

-

-

-

-

38

14

475

-

0.13

0.5

0.06

0.19 46

1. 06 0. 44

1. 25

0.53

0.06

0.25

-

-

-

-

0.36

0.21

-

1. 45

-

RI PT

2

1. 07

-

35

473

-

-

-

-

-

-

-

-

-

-

SC

2

-

-

M AN U

2

0 3668, Early Liassic 03669, 8 3807, Early Liassic 03811, 0 3926, Early Liassic 03929, 5 958,0Early 955,9 Cretaceous 1213, Late Jurassic 01214, 5 1456, Late Jurassic 01458, 5

-

-

0.19

TE D

Table 3 Input data for modelling of burial- and temperature history of the 2D section. The assigned lithologies vary laterally from the deep offshore to the shelfal part, but a vertical heterogeneity was not assigned. Event Name

35

Pliocene to Quaternary

34 33

Miocene Lower Miocene Erosion Upper Oligocene Oligocene

33.9

29

Lower Oligocene Eocene

28

Paleocene

77.4

27

Erosion Upper Cretaceous Santonian Coniacian

31 30

26 25

AC C

32

Age at base (Ma)

Lithology Basin Shelf

5.3

Shale Conglomerates 20.64

HF (mW/m²) Average 50

16 19

Silt Shaly Sandstone Silt Shaly Sandstone

19.34 20.2

50 50

23

20.89

65

21.51

70

24.11

55

25

55

26

50

83.4

Carbonate, Silt and Shale Carbonate, Silt and Shale Carbonate, Silt and Shale Carbonate, Silt and Shale Carbonate, Silt and Shale Carbonates and Shales

27

50

85.5 89.3

Carbonates and Shales Carbonates and Shales

27 27

50 50

EP

Event no

28

55.8

SWIT (°C) Average

ACCEPTED MANUSCRIPT 93.5 99.6 112 113

20

Aptian

114.6

19

Barremian

125

18

Hauterivian

130

17

Valanginian

136

16

Berriasian

140

15

Erosion/Hiatus Top Tithonian

141

14

Tithonian

145

13

Kimmeridgian

154

12

Oxfordian

156

Callovian

164

10

Bathonian

165

9

Aalenian

172

8

Erosion/Hiatus Top Toarcian Toarcian Hettangian to

175

Carbonates and Shales Carbonates and Shales Carbonates and Shales Carbonate, silty Shales silty Sandstone, Conglomerates Carbonate, silty Shales silty Sandstone, Conglomerates Carbonate, silty Shales silty Sandstone, Conglomerates Carbonate, silty Shales silty Sandstone, Conglomerates Carbonate, silty Shales silty Sandstone, Conglomerates Carbonate, silty Shales silty Sandstone, Conglomerates Shaly Carbonates silty Carbonates Shaly Carbonates silty Carbonates Shaly Carbonates silty Carbonates Shaly Carbonates silty Carbonates Shaly Carbonates silty Carbonates Shaly Carbonates silty Carbonates Shaly Carbonates silty Carbonates Shales

176 183

Shales Silty Sandstones

7 6

M AN U

TE D

EP

AC C

11

27 27 27 27

50 50 50 50

27

50

RI PT

Turonian Cenomanian Albian Erosion Upper Aptian

27

SC

23 23 22 21

50

27

50

27

50

27

50

27

50

26.79

60

26.18

65

26.18

65

25.18

65

24.19

70

22.52

70

22.26

70

22.24 22.26

65 65

ACCEPTED MANUSCRIPT

4 3 2 1

201 204 228 245

Siltstones Silt, Sand, Shale

22.74

60

Silt, Sand, Shale Silt, Sand, Shale Silt, Sand, Shale Basement

26.88 26.32 24.51 No value

60 60 60

RI PT

Pliensbachian Unconformity Top Rhaetian Rhaetian Carnian Tatarian Basement

5

Table 4 Petrophysical parameters of the rock types used for basin modeling.

20° 0.22 0.21 0.2 0.2

100° 0.26 0.25 0.23 0.23

2720 2720 2740 2664

3.95 2.05 6.5 2.9

3.38 1.99 5.25 2.6

0.2 0.22 0.21 0.19

0.24 0.25 0.24 0.22

2697

2.09

2.02

0.19

0.23

2700 2700 2715

M AN U

TE D

2700 2724

SC

Heat Capacity (cal/gK)

2680 2688 2740 2730

Thermal Conductivity (W/mK) 20° 100° 1.98 1.91 2.31 2.18 3 2.69 2.3 2.18

2.3 2.63

2.18 2.42

0.2 0.2

0.23 0.23

1.64 2 3.17

1.69 1.96 2.81

0.21 0.2 0.22

0.24 0.23 0.26

AC C

Silty Shales Calc. Shales Limestone Shaly Limestones Sandstone Silt Salt Silty Sandstones Marly Limestone Conglomerates Sandstone, Shale, Limestone Mix Shale Marl Sandy Shale

Density (kg/m³)

EP

Lithology

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

Figure 1 Tarfaya Basin and adjacent structural units including well locations in the offshore (MO-2, MO-7, MO-8, Cap Juby, and well 1) and onshore area (wells 2, 3, 4 (Sondage 1) and 5 (Sondage 2) (Sachse et al., 2012a, 2014). Wells are represented by green dots. Overview map based on Arthur et al. (1979) and Hafid et al. (2008), showing the geological subareas of Morocco and its global location (small map lower right). Isolines show the offshore basin extent. Red line indicates location of the modelled transect, based on Wenke et al. (2011, 2014). Small map shows well locations used for modelling and includes the stratigraphy of the onshore Tarfaya Basin (based on Saadi et al., 1985).

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

Figure 2 Late Paleozoic to Cenozoic chrono- and lithostratigraphy for the Tarfaya Basin, modified from Davison (2005), Sehrt (2014) and Wenke (2011). Basin development stages are based on Zühlke et al. (2004). Petroleum system elements adapted from Jabour et al. (2000); Jenkyns et al. (2002); Davison (2005); Wenke (2014).

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

Figure 3 Rock-Eval data OI and HI for Well 1 in the offshore and Well 2 in the onshore Tarfaya Basin. For well locations see Figure 1. For comparison average ranges for the Eocene, Cenomanian, Turonian, Albian and Pliensbachian onshore are included (Sachse et al., 2011, 2012a, b, 2014).

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

Figure 4 D model geometry with well locations used for calibration and extraction points (Location A and B) illustrating the burial-, temperature-, maturation and petroleum generation histories. Red dashed lines show the approx. position of salt diapirs.

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

Figure 5 1D extraction for the deep offshore (Location A) showing the burial history with temperature overlay (A) and (B) the temperature (blue curve), maturity (black curve) and petroleum generation history (red curve) for the Toarcian layer.

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Figure 6 1D extraction for the slope (Location B) showing the burial history with temperature overlay (A) and (B) the temperature (blue curve), maturity (black curve) and petroleum generation history (red curve) for the Toarcian layer.

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

Figure 7 1D extraction for the onshore (Location C) showing the burial history with temperature overlay (A) and (B) the temperature (blue curve), maturity (black curve) and petroleum generation history (red curve) for the Toarcian layer.

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 8 Sketch of the transgressive/regressive intervals, shift of the coastline and depositional environment through time. Modified after Einsele and Wiedmann (1982).

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Figure 9 Temperature pattern of the sediments along the cross section for three events. Late Jurassic (151 Ma), Late Cretaceous (85 Ma) and present-day, without consideration of salt diapirism.

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

Figure 10 Maturity pattern of the sediments for three events. Late Jurassic (151 Ma), Late Cretaceous (85 Ma) and present day.

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Figure 11 Temperature (A) and maturity (B) pattern for the 2D transect including salt diapirism. For maturity legend see Figure 9.

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Figure 12 1D extraction for location A and B showing the differences in petroleum generation history for the Toarcian layer calculating with (dashed lines) and without salt (lines).

ACCEPTED MANUSCRIPT

Highlights-2D petroleum system analysis of the Tarfaya Basin, on-offshore Morocco, North Africa

RI PT

SC M AN U TE D

• • •

EP

•

2D basin/petroleum system modelling of a transect crossing on-offshore Tarfaya Basin, Morocco Maturity, temperature and burial history plots for three key locations (deep offshore, slope and onshore) Testing impact of salt plumes on temperature and maturity development Implementation of geochemical data for the on-offshore area Compilation of source rock data

AC C

•