This study utilises seismic data to improve understanding of the subsurface fluid flow behaviour in the Taranaki and Great South Basins offshore New Zealand. The aim of this study is to characterise fluid flow features and to investigate their genesis, fluid origins and implications for subsurface fluid plumbing system by integrating seismic interpretation and 3D petroleum systems modelling techniques. After an early phase studying Pliocene pockmarks in the Taranaki Basin, this study has been focused on the subsurface fluid plumbing system and on the fluid expulsion history in the Great South Basin. The Taranaki Basin lies on the west coast and offshore of the North Island, New Zealand. The seismic interpretation revealed that paleo-pockmark formation in the study area relates to fluid escape due to a rapid sediment loading environment in a distal fan setting. Seismic analysis rules out any links between the paleo-pockmarks and faulting. The relationship between paleo-pockmark occurrence and fan depositional thickness variations suggests that pore-water expulsion during overburden progradation is the most likely cause of the paleo-pockmarks. The rapid sediment loading generated overpressure which was greatest on the proximal fan due to a lateral gradient in overburden pressure. Fluids were consequently forced towards the fan distal parts where, eventually, the pore pressure exceeded the fracture gradient of the seal. The Great South Basin lies off the southern coast of the South Island of New Zealand and is located beneath the modern shelf area. Evidence for past and present subsurface fluid flow in this basin is manifested by the presence of numerous paleo-pockmarks, seabed pockmarks, polygonal fault systems, bright spots and bottom simulating reflections (BSR), all of which help constrain aspects of the overburden plumbing system and may provide clues to deeper hydrocarbon prospectivity in this frontier region. The various types of fluid flow features observed in this study are interpreted to be caused by different fluid origins and mechanisms based on evidences from seismic interpretation in the study area. The possible fluid origins which contribute to fluid flow features in the Great South Basin are compactional pore water as well as biogenic and thermogenic hydrocarbons. Using 3D seismic attribute analysis it was possible to highlight the occurrence of these features, particularly polygonal faults and pockmarks, which tend to be hosted within fine-grained sequences. Paleo- and present-day fluid flow features were investigated using 3D basin and petroleum systems modelling with varying heat flow scenarios. The models predict that thermogenic gas is currently being generated in mid-Cretaceous sedimentary sequences and possibly migrates along tectonic faults and polygonal faults feeding present-day pockmarks at the seabed. The models suggest that biogenic gas was the main fluid source for the Middle Eocene paleo-pockmarks and compactional pore fluid may be the main fluid contributor to the Late Eocene paleo-pockmarks. Different heat flow scenarios show that only mid-Cretaceous source rocks have reached thermal maturity in the basin, whilst Late Cretaceous and Paleocene source rocks would be largely immature. The observations and interpretations provided here contribute to the ongoing discussion on basin de-watering and de-gassing and the fluid contributors involved in pockmark formation and the use of pockmarks as a potential indicator of hydrocarbon expulsion. It is clear from this study that seismically-defined fluid flow features should be integrated into petroleum systems modelling of frontier and mature exploration areas in order to improve our understanding on fluid phases, their migration routes, timings and eventual expulsion history.

In this work, I present a multi-isotopic study (carbon, nitrogen, sulfur, strontium and lead) and Re-Os geochronology in rocks and crude oils of the Sonda de Campeche Petroleum System (SCPS). Since crude oils are complicated chemical systems easily disturbed, the Re-Os isotopic system could be affected if secondary processes perturb crude oils. Therefore, the multi stable isotopic study allows the identification of the presence and grade of these secondary processes in crude oils. The δ13C values of crude oils from the SCPS distinguish between: 1) crude oils with the fingerprint of source rocks of hydrocarbons (-28.3 to -26.7 ‰), and 2) crude oils with the fingerprint of the reservoir rocks (-25.5 to -24.9 ‰). Similarly, the δ15N values reveal that crude oils, during migration or trapping processes mimic the isotopic composition of the reservoir rocks of the Ek-Balam Formation. Furthermore, the δ34S values of crude oils from the SCPS (-8.0 to -2.5 ‰) show an absence of a thermal sulfate reduction (TSR) signature, which likely means that the use of Re-Os systematics in crude oils and rocks in the SCPS is appropriate. Strontium and lead measurements show crude oils have an isotopic composition different from rocks from the Edzna Formation but similar to rocks of the Akimpech and Ek-Balam formations, indicating that crude oils received Sr and Pb from the trapping rocks during migration or trapping processes, producing a isotopic mixing trend with rocks of these formations. Specifically, the lead isotope composition allows the identification of a source of lead never recorded before, the Guichicovi Complex. The isotopic data suggest that this Grenville Complex has been feeding with detrital material to the sedimentary rocks from Bacab, Ek-Balam and Akimpech formations in the SCPS, and in consequence contributing to the final isotopic composition of crude oils as well. Re-Os geochronology of rocks from the Edzna and Akimpech formations (152 ± 4 Ma; and 158.6 ± 5.5 Ma, respectively) provides precise ages of deposition that coincide with the ages proposed in previous studies based on the fossil record. Re-Os geochronology in crude oils yield ages with low uncertainty and moderate MSWD values, reflecting a rapid formation and migration process that occurred during evolution of the SCPS. The age of crude oils (28.3 ± 5.5 Ma) broadly agrees with petroleum generation models proposed by PEMEX.

Les intrusions sableuses (injectites) sont le plus souvent le produit de la remobilisation post-dépositionnelle des sédiments et de l’injection du sable dans les roches environnantes. Bien que reconnues pour la première fois il y a près de 200 ans, elles ne sont réellement étudiées que depuis quelques dizaines d’années, depuis que les concepts sur les environnements de dépôt dans les domaines marins profonds nous permettent de mieux comprendre les processus de mise en place. Cependant, ces processus restent encore aujourd’hui relativement mal compris. Notre approche repose sur l’étude d’injectites dans le bassin du Bas-Congo à partir de données de sismique et de puits que nous comparerons à un système fossile dans le bassin du sud-est de la France. Nous avons montré que :(1) Dans des systèmes de chenaux turbiditiques enfouis, les dépôts de drapage sur les marges et terrasses de chenaux présentent la même signature géophysique que les injectites de type « wing ». Finalement, le seul critère sismique d’identification des injectites est la présence de réflexions sismiques sécantes vis-à-vis de la stratigraphie associée dans le meilleur des cas au soulèvement des réflecteurs sismiques sus-jacents. (2) Des injectites d’échelle sismique en forme de cône et d’assiette ont été identifiées dans le bassin du Bas-Congo. La remobilisation résulte probablement des pressions anormales induites par l’effet de flottabilité des hydrocarbures piégés dans les marges d’un lobe enfoui sous 160 m de sédiment, puis de l’injection soudaine du sable fluidisé associée à la réactivation de failles.(3) Un réseau d’injectites (dykes, sills/wings et laccolites) s’est formé dans le bassin Vocontien entre la fin de l’Albien supérieur et/ou le début du Cénomanien, depuis un chenal turbiditique de l’Albien inférieur-moyen. La mise en place résulte probablement de la compartimentalisation précoce du chenal au cours de son enfouissement et de l’augmentation du taux de sédimentation générant la surpression et de l’apport ultérieur d’importante quantité de fluides profonds déclenchant l’injection. L’injection du sable a été polyphasée : une première injection a formé des sills et une suivante des dykes. Les sills/wings et les dykes se sont propagés latéralement au chenal source sur environ 2 km et vers la surface sur environ 200 m, mettant en évidence une forte remobilisation latérale plutôt que verticale, contrairement à l’idée classiquement admise à partir de l’interprétation des données sismiques.(4) La formation de ce large réseau d’injectites a été gouverné par des mécanismes d’hydrofracturation. Par conséquent, sa morphologie a été dépendante des hétérogénéités de la roche hôte (milieu isotrope, fracturé), des directions de paléo-contraintes (σ3 = NW-SE) et de la profondeur d’enfouissement de la source (300-600 m) au moment de l’injection. L’étude de ce réseau fossile permet de définir les relations entre morphologie du réseau injecté et état de contraintes au moment de l’injection. Cette relation peut être extrapolée de façon à contraindre la morphologie des réseaux de subsurface au-delà de la visibilité sismique. (5) Les sables injectés dans des lithologies de faible perméabilité témoignent d’un épisode d’échappement de fluide important dans les bassins étudiés mais ont aussi guidé les fluides longtemps après leur formation. Les injectites contribuent ainsi à l’initiation épisodique et la pérennisation de migrations de fluides dans les bassins sédimentaires. Le processus d’injection est associé à l’échappement brutal de fluides, résultant vraisemblablement d’un évènement tectonique et/ou sédimentaire important, et l’architecture des réseaux d’injectites est gouvernée par les paléo-contraintes locales et les hétérogénéités de la roche hôte. Par conséquent, la caractérisation des réseaux d’injectites est une étape importante dans la compréhension de la plomberie des marges, c'est-à-dire l’évolution post-dépôt des bassins sédimentaires. / Sand intrusions (or injectites) are most often the product of post-depositional remobilization of sand leading to its injection into the surrounding rocks. While injectites were recognized for the first time nearly 200 years ago, their emplacement process has been studied for a couple of decades only, since the concepts of deep sea depositional environments have allowed us to better understand their emplacement processes. However, these processes are still relatively poorly understood. Our approach is based on the study of injectites in the Lower Congo Basin from seismic and well data, which we compare to a fossil system in the SE France basin. We have shown that:(1) In buried turbidite channel systems draping deposits on the channel flanks and terraces of channels have the same geophysical signature as ‘wing-like' injectites. Finally, the only criterion for identifying seismic injectites is the presence of bedding-discordant seismic reflections, and in the best case the associated uplift of the overlying seismic reflectors.(2) Seismic-scale conical and saucer-shaped sand injectites have been identified in the Lower Congo Basin. The remobilization is likely due to overpressuring induced by the buoyancy effect of hydrocarbons trapped in the margins of a lobe buried underneath 160 m of sediment, followed by the sudden injection of fluidized sand associated with fault reactivation of faults (with a possible role of nearby salt diapirs).(3) A network of injectites (dykes, sills/wings and laccoliths) was formed in the Vocontian basin during the late Albian and/or early Cenomanian, from a lower-middle Albian turbidite channel. The emplacement is probably due to the early compartmentalization of the channel during its burial and the increase of the sedimentation rate generating overpressure; and the subsequent large influx of deep fluids triggering injection. The injection of sand was polyphased: a first episode formed the sills and another emplaced the dykes. Sills/wings and dykes propagated about 2 km laterally away from the parent sand body and about 200 m up to the surface, revealing a much more extended lateral than vertical reach, contrary to the classically accepted idea from the interpretation of seismic data.(4) The emplacement of this large network of injectites was governed by hydrofracturing. Therefore, its morphology is dependent on the host rock heterogeneity (isotropy, fractures), the paleo-stress orientation (σ3 = NW-SE) and the burial depth of the source (300-600 m) at the time of injection. The study of this fossil network allows us to define the relationship between morphology of the injected network and stress state at the time of injection. This relationship can be extrapolated to constrain the morphology of subsurface networks beyond seismic visibility.(5) Sands injected into low permeability lithologies bear evidence to a major event of fluid escape in the studied basin, but also channeled fluids long after their formation. In this way, injectites both attest to specific episodes of fluid migration in sedimentary basins and contribute to long-lived re-routing of migrating fluids once emplaced.The injection of sand is associated with the sudden escape of fluids, probably resulting from a significant tectonic and/or sedimentary event; in addition, the architecture of injectite networks is governed by the local paleo-stress and heterogeneity in the host rock. Consequently, characterizing injectite networks is an important step in understanding the plumbing systems of continental margins, i.e. the post-depositional evolution of sedimentary basins.

La compréhension d'un système pétrolier nécessite la caractérisation pétrographique de tous les éléments et les processus le composant. Dans ce travail, plusieurs exemples de roches mères, roches réservoirs et roches couvertures provenant de bassins pétroliers différents, ont été étudiés afin de décrire les méthodes pétrographique classiques et mettre en place des nouvelles. Ces dernières telles que : la création d'une cinétique de transformation d'un kérogène composé de deux types de matière organiques (programmation), analyse macérale et l'étude des microfractures par analyse d'images, la diffraction à rayon X ainsi que la tomographie ont permis la caractérisation de la roche mère. Quant aux roches réservoirs, les méthodes d'analyse d'image des propriétés pétrophysiques, la microscopie MSCL ainsi que les paramètres de mouillabilité permettent la description de la qualité de ces réservoirs et leurs préservations au cours du temps à cause des phénomènes de recristallisation, dissolution, circulation de fluide et de réaction TSR/BSR. Les roches couvertures étudiées dans ce travail sont celles des argilites callovo-oxfordienne, utilisant la diffraction à rayon X ainsi que l'analyse d'image et la tomographie. Ces méthodes ont facilité la compréhension de leurs comportements au cours du temps, leurs capacités de sorption/désorption et leurs fiabilités de stockage de déchets nucléaire. Enfin, la modélisation pétrolière avec Petromod permet de déterminer les fonctionnements des systèmes pétroliers. La modélisation par percolation est plus proche de la réalité des bassins pétroliers que celle de Darcy/Hybride / Understanding oil systems requires petrographic characterization of all elements and process that compose it. In this work, several examples of source rocks, reservoir rocks and seal from different petroleum basins have been studied in order to describe conventional petrographic methods and develop new ones. The new ones as: a program of transformation kinetic of kerogene composed of two types of organic matter, maceral analysis and microfractures study using images analysis, the diffraction X-ray and tomography allowed source rock description. As for, reservoir rocks, methods of petrophysical characterization by images analysis, MSCL Microscopy and wettability parameters permit reservoir quality description and their preservation over time due to recrystalization and dissolution phenomena, fluid flow and TSR/BSR reaction. The cap rocks studied in this thesis are those of Callovo-Ordovician argillites, using X-Ray diffraction as well as images analysis and tomography. Those methods facilitated the understanding of argillites behavior over time, their sorption/desorption ability and their reliability of nuclear waste storage. Finally, Modeling using Petromod helps to determine petroleum systems functioning. Modeling by percolation method gives results closer to oil basins reality, than by Darcy/Hybrid method

Thesis (PhD)--Stellenbosch University, 2015. / ENGLISH ABSTRACT: This study investigates the crustal structure, and assesses the qualitative and quantitative impacts of crust-mantle dynamics on subsidence pattern, past and present-day thermal field and petroleum system evolution at the southern South African continental margin through the application of a multi-disciplinary and multi-scale geo-modelling procedure involving both conceptual and numerical approaches. The modelling procedure becomes particularly important as this margin documents a complex interaction of extension and strike-slip tectonics during its Mesozoic continental rifting processes. Located on the southern shelf of South Africa, the Western Bredasdorp Basin (WBB) constitutes the focus of this study and represents the western section of the larger Bredasdorp sub-basin, which is the westernmost of the southern offshore sub-basins. To understand the margin with respect to its present-day structure, isostatic state and thermal field, a combined approach of isostatic, 3D gravity and 3D thermal modelling was performed by integrating potential field, seismic and well data. Complimenting the resulting configuration and thermal field of the latter by measured present-day temperature, vitrinite reflectance and source potential data, basin-scale burial and thermal history and timing of source rock maturation, petroleum generation, expulsion, migration and accumulation were forwardly simulated using a 3D basin modelling technique. This hierarchical modelling workflow enables geologic assumptions and their associated uncertainties to be well constrained and better quantified, particularly in three dimensions. At present-day, the deep crust of the WBB is characterised by a tripartite density structure (i.e. prerift metasediments underlain by upper and lower crustal domains) depicting a strong thinning that is restricted to a narrow E-W striking zone. The configuration of the radiogenic crystalline crust as well as the conductivity contrasts between the deep crust and the shallow sedimentary cover significantly control the present-day thermal field of the study area. In all respects, this present-day configuration reflects typical characteristics of basin evolution in a strike-slip setting. For instance, the orientations of the deep crust and fault-controlled basin-fill are spatially inconsistent, thereby indicating different extension kinematics typical of transtensional pull-apart mechanisms. As such, syn-rift subsidence is quite rapid and short-lived, and isostatic equilibrium is not achieved, particularly at the Moho level. Accompanied syn-rift rapid subsidence and a heat flow peak led to petroleum preservation in the basin since the Early Cretaceous. Two additional post-rift thermal anomalies related to the Late Cretaceous hotspot mechanism and Miocene margin uplift in Southern Africa succeeded the syn-rift control on maturation. This thermal maturity of the five mature source rocks culminated in four main generation and three main accumulation phases which characterise the total petroleum systems of the WBB. The Campanian, Eocene and Miocene uplift scenarios episodically halted source maturation and caused tertiary migration of previously trapped petroleum. Petroleum loss related to the spill point of each trap configuration additionally occurs during the Late Cretaceous-Paleocene and Oligocene-Early Miocene. The timing and extent of migration dynamics are most sensitive to the geological scenario that combined faulting, intrusive seal bypass system and facies heterogeneity. In fact, for models that do not incorporate facies heterogeneity, predicted past and present-day seafloor leakage of petroleum is largely underestimated. This complex interplay of generation and migration mechanisms has significant implications for charging of petroleum accumulations by multiple source rocks. Due to early maturation and late stage tertiary migration, the syn-rift source rocks particularly Mid Hauterivian and Late Hauterivian source intervals significantly control the extent of petroleum accumulation and loss in the basin. Lastly, the modelled 3D crustal configuration and Mezosoic to Cenozoic thermal regime of the WBB dispute classic uniform lithospheric stretching for the southern South African continental margin. Rather, this PhD thesis confirms that differential thinning of the lithosphere related to a transtensional pull-apart mechanism is the most appropriate for accurately predicting the evolution of basin and petroleum systems of the margin. Also, the presented 3D models currently represent the most advanced insights, and thus have clear implications for assessing associated risks in basin and prospect evaluation of the margin as well as other similar continental margins around the world. / AFRIKAANSE OPSOMMING: Hierdie studie ondersoek die korsstruktuur en evalueer die kwalitatiewe en kwantitatiewe impakte van kors-mantel-dinamika op insinkingspatroon, die termiese veld en petroleumstels evolusie aan die suidelike Suid-Afrikaanse kontinentale grens, in die hede en die verlede, deur die toepassing van ’n multidissiplinêre en multiskaal-geomodelleringsprosedure wat beide konseptuele en numeriese benaderings behels. Die modelleringsprosedure veral is belangrik aangesien hierdie kontinentale grens ’n komplekse interaksie van uitbreidings- en strekkingsparallelle tektoniek gedurende die Mesosoïese vastelandskeurprosesse daarvan dokumenteer. Omdat dit op die suidelike platvorm van Suid-Afrika geleë is, maak die Westelike Bredasdorp Kom (WBK) die fokus van hierdie studie uit, en verteenwoordig dit die westelike deel van die groter Bredasdrop-subkom, wat die verste wes is van die suidelike aflandige subkomme. Om die grens met betrekking tot sy huidige struktuur, isostatiese staat en termiese veld te verstaan, is ’n kombinasie benadering bestaande uit isostatiese, 3D-gravitasie- en 3D- termiese modellering gebruik deur potensiëleveld-, seismiese en boorgatdata te integreer Ondersteunend totot die gevolglike konfigurasie en termiese veld van die laasgenoemde deur middel van hedendaagse temperatuur, soos gemeet, vitriniet-refleksiekoëffisiënt en bronpotensiaal data, komskaal-begrawing en termiese geskiedenis en tydsberekening van brongesteentematurasie, is petroleumgenerasie, -uitwerping, -migrasie en -akkumulasie in die toekoms gesimuleer deur gebruik te maak van ’n 3D-kommodelleringstegniek. Hierdie hierargiese modelleringswerkvloei maak dit moontlik om geologiese aannames en hulle geassosieerde onsekerhede goed aan bande te lê en beter te kwantifiseer, veral in drie dimensies. In die hede word die diep kors van die WBK gekarakteriseer deur ’n drieledige digtheidstruktuur (met ander woorde voorrift-metasedimente onderlê deur bo- en benedekors domeine) wat dui op ’n baie wesenlike verdunning, beperk tot ’n dun O-W-strekkingsone. Die konfigurasie van die radiogeniese kristallyne kors, sowel as die konduktiwiteitskontraste tussen die diep kors en die vlak sedimentêre dekking, beheer grotendeels die hedendaagse termiese veld van die studiearea. Hierdie hedendaagse konfigurasie weerspieël in alle opsigte tipiese eienskappe van kom-evolusie in ’n skuifskeur omgewing. Byvoorbeeld, Die oriëntasies van die diep kors en verskuiwingbeheerde komsedimentasie byvoorbeeld is ruimtelik inkonsekwent en dui daardeur op verskillende ekstensiekinematika, tipies van transtensionale tensiemeganisme. As sulks, is sin-rift-versakking taamlik vinnig en kortstondig, en word isostatiese ekwilibrium nie by die Moho-vlak, in die besonder, bereik nie. Samehangende sin-rift vinnige versakking en hittevloeihoogtepunt het gelei tot petroleum behoud in die kom sedert die vroeë Kryt. Twee bykomende post-rift termiese anomalieë wat verband hou met die laat Kryt-“hotspot” meganisme en die Mioseense kontinentale grensopheffing in Suidelike Afrika het die sin-rift-beheer met maturasie opgevolg. Hierdie termiese maturiteit van die vyf gematureerde brongesteentes het in vier hoofgenerasie- en drie hoofakkumulasie fases, wat die totaliteit van die petroleumstelsels van die WBK karakteriseer, gekulmineer. Die Campaniese, Eoseense en Mioseense opheffings senarios het episodies bronmaturasie gestop en tersiêre migrasie van petroleum wat vroeër opgevang was veroorsaak. Addisioneel vind petroleumverlies gekoppel aan die spilpunt van elke opvanggebiedkonfigurasie tydens die laat Kryt-Paleoseen en Oligoseenvroeë Mioseen plaas. Die tydstelling en omvang van migrasiedinamika is die sensitiefste vir die geologiese scenario wat verskuiwing, seëlomseilingstelsel en fasiesheterogeniteit kombineer. Trouens, vir modelle wat nie fasiesheterogeniteit inkorporeer nie, is voorspellings van vroeëre en huidige seebodemlekkasie van petroleum grotendeels onderskattings. Hierdie komplekse wisselwerking van generasie- en migrasiemeganismes het beduidende implikasies vir die laai van petroleumakkumulasies deur veelvoudige brongesteentes. Vanweë vroeë maturasie en laatstadiumtersiêre migrasie, oefen die sin-rift-brongesteentes, veral middel Hauterivium- en laat Hauteriviumbronintervalle, beduidende beheer oor die omvang van petroleumakkumulasie en -verlies in die kom uit. Laastens weerspreek die gemodelleerde 3D-korskonfigurasie en Mesosoïese-tot-Senosoïesetermiese regime van die WBK ’n klassieke uniforme litosferiese rekking vir die suidelike Suid- Afrikaanse kontinentale grens. Inteendeel, hierdie PhD-proefskrif bevestig dat ’n differensiële verdunning van die litosfeer, gekoppel aan ’n transtensiemeganisme, die beste geskik is om ’n akkurate voorspelling oor die evolusie van kom- en petroleumstelsels van die kontinentale grens mee te maak. Verder, verteenwoordig die 3D-modelle, wat hier aangebied word, tans die mees gevorderde insigte, en het hierdie modelle dus duidelike implikasies vir die assessering van verwante risiko’s in kom- en petroleum teikene valuering van die kontinentale grens, so wel as van ander soortgelyke kontinentale grense regoor die wêreld.

La marge algérienne est un domaine complexe, bordé au sud par les zones internes des Maghrébides (AlKaPeCa) qui chevauchent les zones externes telliennes vers le sud. La partie offshore de ce système constitue un bassin d‘arrière arc où s‘est déposée une série sédimentaire mio-pliocène reposant sur un substratum de nature et d‘origine variables spatialement. L'objectif de ce travail a consisté à analyser et modéliser le fonctionnement des systèmes pétroliers et à quantifier les volumes d‘hydrocarbures accumulés. Avant de procéder aux différentes modélisations numériques, stratigraphiques et thermiques, un modèle géologique conceptuel a été élaboré sur la base des données de géologie de terrain et de sismiques. La continuité terre- mer du socle kabyle a permis une extrapolation stratigraphique entre des formations oligo-miocènes en affleurement et les unités acoustiques définies dans le bassin offshore. L‘analyse tectonique dans les deux domaines a abouti à une évolution en trois phases : (1) syn-rift où le bassin a été ouvert en transtension à partir de l‘Oligocène supérieur-Aquitanien, (2) phase post-rift durant laquelle il y a eu le développement des bassins intra-arcs, la collision AlKaPeCa- Afrique et le magmatisme, (3) phase d‘inversion où la marge devient active essentiellement à partir du Quaternaire. En définissant l‘ensemble des éléments des systèmes pétroliers avec des incertitudes variables, la simulation du fonctionnement de ces derniers par modélisation de bassin 2D/3D a montré des possibilités d‘accumulation d‘huile et de gaz majoritairement près de la marge, entre 20 et 65 km de la côte avec un maximum de portée de 70 km dans le golfe de Bejaia. / The Algerian margin is a complex domain, limited to the south by the Maghrebian internal zones (AlKaPeCa) that overthrust the external Tellian zones southward. The offshore part of this system constitutes a back-arc basin, where a mio-pliocene sedimentary series were deposited over a substratum of laterally variable origin and nature. The goal of the present work consisted in analyzing and modelling the petroleum system at work and calculating hydrocarbon volumes. Before proceeding to different numerical basin, stratigraphic and thermal modelling, a conceptual geological model is required and was performed based on field geological studies and stratigraphic and structural interpretations of the seismic profiles. The extension of the continental crust beyond the foot of the margin, allows determining a chronostratigraphic model by extrapolation of the outcroping oligo-miocene formations onshore to the acoustic pre-messinian units defined in the offshore basin. Besides, a tectonic analysis in both onshore and offshore domains gave rise to three main steps of evolution: (1) syn-rift phase where the basin was opened by transtension since Late Oligocene- Aquitanian, (2) post-rift phase in which intra-arc basins were developed, AlKaPeCa and Africa docked and magmatism activity took place, (3) inversion phase where the margin became active mainly since Quaternary times. After defining the different petroleum system elements taking into account variable uncertainties, the 2D/3D petroleum system model depicts possibilities of oil and gas accumulations mainly close to the margin, between 20 to 65 km from the coastline to the north with a maximum range of 70 km in the Bejaia Gulf.