Petroleum Habitat Research Articles

Geodynamic control on the petroleum habitat of the Uralian Foreland

A comparative study of the Uralian Foreland in the Timan-Pechora and Volga Urals basins reveals considerable differences in structure and petroleum habitat. These differences were in large measure controlled by their geodynamic settings. A typical scenario of the continental marginal basin which subsequently was modified in the foredeep basin took place in the Timan-Pechora basin. The sedimentary fill of the basin is made up of the Phanerozoic deposits only. The principal oil source rock is provided by the prolific Domanik Suite broadly developed in is eastern part of the basin. The mature Domanik source rocks charged the majority of oil and gas fields of the Timan-Pechora Basin. In the Volga Urals basin the sedimentary fill includes two overlapping foredeep sequence – Riphean and Paleozoic, of which the Riphean one is much thicker. The Riphean depocenters were subjected to structural inversion during the docking of the Magnitogorsk island arc to the Uralian margin in the Middle Devonian-Frasnian. The inversion was accompanied by the thickening of the Riphean section due to the reactivation of the pre-existing Precambrian deformation and caused the regional uplift in the Southern Uralian Foreland. This uplift led to shifting of the Domanik troughs to the westerly outboard part of the Volga-Uralian Basin. The Domanik source rock remained immature over much of the Southern Uralian Foreland which is interpreted to be a result of the inversion of the Riphean depocenters and related regional uplift. It is proposed that the enormous clustering of large oil deposits in the Paleozoic section of the south-eastern part of the Volga Uralian Basin was to a much extent produced by the charging from the multi-kilometer thick Riphean section of the Southern Uralian Foreland.

Ресурсный потенциал гряды Чернышева (Тимано-Печорский бассейн) в контексте новых данных о строении и продуктивности соленосных надвиговых поясов

The salt bearing thrust belts are among the most prolific petroleum provinces in the world, including the fold belts flanking the Persian Gulf Basin, the Tarim Basin, the Terek-Sunzha Zone of the Eastern PreCaucasus etc. They are characterized by peculiar structural styles of deformation, large oil and gas pool sizes, significant flow rates. The Chernyshev Swell is among prospective salt bearing thrust belts. It is located in the Cis-Uralian part of the Timan Pechora Basin. Several exploration wells have been drilled in the area so far failed to deliver the anticipated oil and gas deposits. Post mortem study indicated that the main reason for the past failures was the mismatch between the complexities of the geological settings and the used exploration technologies. Integrated study of the area, conducted by the North Uralian Petroleum Company, using modern technologies, including 3D seismic surveying and magnetotelluric sounding, has enabled a far better understanding of this area’s structure and petroleum habitat. It is shown that high petroleum potential is attributed to the transition zone between the Chernyshev Swell and the Kosyu Rogov Foredeep Basin. This study indicated that the area of the Povarnitsa High is of priority interest for explration. This area provides supplementary opportunities in addition to the commercialization of the petroleum exploration potential. It includes production of rare earth and metals in brine of the evaporate deposits. The subsalt reservoirs of the Chernyshev Swell could be used for the storage of gas and CO2 sequestration. Integrated development of the resource potential of the Povarnitsa High may become a key driver of the economic development of the north-eastern part of the Republic of Komi.

Korotaikha Composite Tectono-Sedimentary Element, Northwestern Russia

Abstract The Korotaikha Composite Tectono-Sedimentary Element constitutes the northeastern part of the Timan–Pechora petroleum province. It has evolved through rifting, continental margin development, and a two-stage collisional phase related to the Uralian Orogeny in the Late Artinskian–Late Permian and the Pay-Khoy Orogeny in the Late Triassic. In the course of the later phase, the sedimentary cover was delaminated along the Upper Ordovician evaporites, which produced general uplift. The complex tectonostratigraphic history resulted in the deposition of an up to 15 km-thick sedimentary section that has all the essential ingredients for a prolific petroleum system, including the world-class Domanik source rock and a wide variety of structural and stratigraphic traps. Nevertheless, up to now, no commercial discoveries have yet been made. A review of the geological setting and petroleum habitat suggests that the petroleum systems development was more complex than was assumed previously. The amount of uplift and erosion related to the updip displacement on the salt detachment was underestimated. Reinterpretation of the available data shows the presence of large untested exploration opportunities including duplex thrust sheets and subsalt structures related to squeezed diapirs.

Squeezed diapirs of the Chernyshev Swell (the Timan Pechora Basin): integrated study and petroleum habitat

Squeezed diapirs of the Chernyshev Swell (the Timan Pechora Basin): integrated study and petroleum habitat

Possible Bornu Basin Hydrocarbon Habitat—A Review

An attempt is made in this article to examine and assess the possible petroleum habitat in the Bornu Basin, which is the Nigerian portion of the Mega-Chad Basin that has been found to host oil and gas in commercial quantities in Niger, Chad and Cameroon. The presence of three of the fundamental geological factors (source rock, reservoir rock and seal/trap) for commercial hydrocarbon accumulation was assessed in the light of existing information. Available geochemical information reveals that the shales of the Bima, Gongila and Fika Formations in the Bornu Basin contain sufficient organic matter for hydrocarbon generation. Limited existing geochemical data suggest that the quantity and quality of the organic matter in the shales vary widely with the TOC of most samples ranging from 0.54 wt% - 1.25 wt% and the HI from 11 - 173.80 mg/g in intervals with Tmax in the range of 365°C - 519°C. In addition, the kerogen type is predominantly type III with minor type II, thus suggesting a predominant gas prone basin. Possible reservoir rocks occur as sand/sandstone beds within the Bima, Gombe, and Kerri-Kerri, as well the Gongila Formation which also contains much shale and limestone. Both stratigraphic and structural trapping conditions exist in the Bornu Basin. The structural traps were presumably formed during the widespread Santonian tectonic inversion that affected the entire Mega-Chad Basin. It is suggested that deeper drilling into the sands and sandstone of the untested Bima Formation that could host hydrocarbon of commercial quantities, as evidenced by the discoveries at deeper depths in the neighbouring Termit Basin, was desirable.

Seismic interpretation, structural analysis, and fractal study of the Greater Ughelli Depobelt, Niger Delta Basin, Nigeria

A major feature of the habitat of petroleum in the Niger Delta Basin is the association of petroleum traps with growth faults. Because of the significant role of these faults in hydrocarbon accumulation and redistribution in the basin, a good understanding of the timing of fault motion has now been shown to be vital for successful exploration of fault-bounded prospects. In most petroleum habitats, structural elements such as fault patterns, their kinematics, geometry, timing, and size of the structures control the distribution of hydrocarbons in adjacent fault blocks. The success or otherwise of an exploration well in such areas depends on the location of such a well relative to the structural closure interpreted from the seismic data. Experience has shown that detailed structural analysis of prospective fields can provide a reliable kinematic and growth history upon which risks associated with fault movement, trap integrity and structure, geometry/size modification can be evaluated before deciding on the drilling location.

Methanogenic biodegradation of petroleum in the West Siberian Basin (Russia): Significance for formation of giant Cenomanian gas pools

Approximately 1700 tcf (48 trillion m3) of dry gas (99% methane) reserves and resources occur in western Siberia, mostly in shallow (1500 m [4921 ft]) Cenomanian pools in the northern part of the basin. This dry gas constitutes about 11% of the world's conventional gas endowment and about 17% of the annual gas production. The origin of the dry gas has been debated extensively over the last 45 yr but remains controversial. Widely discussed hypotheses on the origin include early-mature thermogenic gas from coal, primary microbial gas from dispersed organic matter or coal, and thermogenic gas from deep source rocks. However, all these hypotheses are in some ways inconsistent with the molecular or isotopic composition of the gases or the results of basin and petroleum systems modeling. Here, I present geochemical and geological evidence that a significant (although yet not quantified) part of the shallow dry gas in the northern West Siberian Basin originated from methanogenic biodegradation of petroleum. Circumstantial evidence includes the occurrence of heavily biodegraded oil legs and residual oil in many Cenomanian gas pools, as well as geochemical evidence of heavy to slight biodegradation in Jurassic–Albian reservoirs commonly underlying the Cenomanian pools. Direct evidence includes, most importantly, 13C-enriched CO2 in pools with biodegraded oil (although data are limited), which indicates 40–70 wt.% conversion of oil-derived CO2 to secondary microbial methane. Distinctive hydrocarbon molecular and isotopic compositions of most gases in Cenomanian pools (average dryness C1/(sum C1-C5) is 0.9976; average 13C of methane is 51.8) suggest that they represent mixtures of biodegraded thermogenic gases from deep, mainly Jurassic, source rocks and secondary microbial methane with an occasional small addition of primary microbial methane. Contribution of early-mature coal-derived gas is possible in areas with the most significant thermal stress of Hauterivian–Aptian sediments but remains speculative. Review of petroleum habitats of five representative oil-gas-condensate fields in western Siberia (including the world's second largest gas field, Urengoyskoe) suggests that methanogenic biodegradation may best explain the observed distribution and properties of fluids in the shallow reservoirs of those fields. Recognition of secondary microbial gas in western Siberia helps explain the observed dominance of gas in the shallow, cool northern part of the basin, where conditions were more favorable for prolonged petroleum biodegradation than in the central and southern parts of the basin. Secondary microbial gas has been recognized worldwide and may (1) represent a volumetrically significant exploration target in shallow reservoirs (perhaps more significant than primary microbial gas) and (2) indicate effective thermogenic petroleum systems in the deeper sections. Large volumes (up to 66,500 tcf [1884 trillion m3]) of secondary microbial methane could have been generated from biodegraded petroleum accumulations worldwide. Although a part of that gas accumulated as oil-dissolved, free, and hydrate-bound gas, most gas apparently escaped into the overburden, atmosphere, and ocean and could have affected global climate in the geologic past.

Controls on structural styles, basin development and petroleum prospectivity in the Midland Valley of Scotland

Integration of well-calibrated seismic data from the Firth of Forth with field and subsurface data from neighbouring onshore areas provides important new insights into the structural evolution and petroleum habitat in the Midland Valley of Scotland. The results demonstrate that the NNE–SSW striking Midlothian–Leven Syncline, and its flanking Burntisland and D’Arcy-Cousland anticlines, developed as major growth folds during the Late Palaeozoic under a predominantly dextral strike-slip regime. These syn-sedimentary folds controlled depositional thicknesses, facies and dispersal patterns in Early to Late Carboniferous (Viséan-Westphalian) times. Structural geometries suggest that the folds experienced tightening during Late Carboniferous (Variscan) deformation events before being transected by E-W striking dykes and extensional faulting during the Late Carboniferous (Westphalian D) and Early Permian. Although direct evidence for the basin's post-Permian burial history is no longer present, it can be inferred that the area had at least 1 km of cover prior to Paleogene uplift. The new understanding of the eastern Midland Valley's structural and subsidence history provides the means by which the occurrence of petroleum in the basin can be explained. Burial of Lower Carboniferous (Mississippian) oil-shale source rocks beneath the Midlothian–Leven Syncline now appears to have been the primary driver in the maturation and up-dip migration of waxy crude oil into age-equivalent clastic reservoirs located in the adjacent anticlines, rather than oil generation by direct contact between the source rocks and igneous intrusions. Initial oil charging is thought to have taken place during the Late Carboniferous, was renewed during Mesozoic reburial and appears to continue locally today despite the detrimental effect of significant Early Cenozoic uplift. It is now evident that the basin's limited exploration success has been almost entirely governed by the presence of unbreached palaeostructures lying directly up-dip from an oil kitchen, developed in the core of the Midlothian–Leven Syncline during Late Carboniferous and Mesozoic-Recent burial.

Basement reactivation and inversion mechanisms in the Timor and Norwegian seas

The North East Atlantic Margin and Australian North West Shelf share similar tectonic evolutions. Both are passive margins of similar age and size, both experienced significant periods of reactivation, inversion and volcanism, and both host significant oil and gas resources. The main differences between these two margins lie in their modern tectonic settings and hydrocarbon resources. The North West Shelf occurs at a present-day collisional plate boundary, the dynamics of which strongly control the location of oil and gas reserves, whereas the North East Atlantic has not yet entered a collisional phase. The North West Shelf tends to be gas prone, in contrast to its European counterpart. Recent mapping of Neogene to Recent modification across the North West Shelf highlights the influence of inherited basement architecture, long-wavelength strain partitioning and continuous flexural deformation. Similarities in the structural evolution of these two margins, especially in terms of the role of the basement structure, episodic modification, the location and extent of Cenozoic inversions and the role of inversion in controlling hydrocarbon distribution, illustrate the importance of these issues in passive margin development. Lessons learned from the Australian example include that structural inheritance has an overwhelming control on later reactivation, and that even small amounts of shortening strain (1–2%) can lead to significant modifications of structural traps and petroleum habitats.

ABSTRACT: Depositional environment and petroleum habitat of cretaceous reservoirs in southern Nagapattinam sub-basin, Cauvery Basin, India

ABSTRACT: Depositional environment and petroleum habitat of cretaceous reservoirs in southern Nagapattinam sub-basin, Cauvery Basin, India

Petroleum habitats of the Atlantic margin of South Africa

Abstract Petroleum system logic is applied along South Africa’s western margin to improve understanding of the observed petroleum habitats and the evaluation of the area’s potential for hosting profitable hydrocarbons. Three major groups of source rocks are identified and, consequently, the source-centred petroleum systems and complementary exploration plays form three major groups: (1) those sourced from syn-rift, Upper Jurassic-Neocomian, generally lacustrine source rock pods; (2) those sourced from Barremian-lower Aptian, generally marine, transitional succession source pods; (3) those possibly sourced from the Cenomanian-Turonian boundary, generally marine, drift succession source pods. These groups are further subdivided into individual petroleum systems in terms of specific individual source rocks, level of certainty, type of hydrocarbon and extent; and into individual exploration plays in terms of stratigraphic level of the reservoir and trap type. The geographic location of the known and actively generating oil and gas pods, whether in the syn-rift or transitional successions, is the major control on the observed distribution of petroleum habitats. The predominantly gas-bearing areas coincide with the main depocentre of the Orange Basin where the lower Aptian source rocks are in the gas window. More oil-bearing areas are predicted outside the depocentre, in deeper water, where the lower Aptian source rocks may become more oil prone and are possibly located in the oil window. These possibly more oil-prone areas coincide with major syn-sedimentary structures and hypothetical deepwater turbidite sandstones. They represent a new frontier for future exploration.

Tertiary Evolution and Petroleum Habitat of the Sauna Basin, South-East Mexico: ABSTRACT

Tertiary Evolution and Petroleum Habitat of the Sauna Basin, South-East Mexico: ABSTRACT

The Habitat of Petroleum in the Brazilian Marginal Basins: A Paleoenvironmental and Biological Marker Approach

A geochemical survey of Brazilian marginal basins using a wide selection of oils and source rocks ranging from Lower Cretaceous to Tertiary in age, has been undertaken. The aims were to review and assess the hydrocarbon source potential, characterize the depositional paleoenvironment of the source rocks and to correlate reservoired oils with their putative source rocks. This approach was based mainly on the distribution and absolute concentrations of biological markers. Integration of the results with geological and paleontological data Provides recognition and differentiation of six source rock systems deposited in the following environments: lacustrine freshwater, lacustrine brackish to saline water marine deltaic with carbonate influence. The analyses of the oil samples reveal significant differences among groups which enable a correlation with putative source rocks laid down in all the six of the above depositional environments. Presently, the Brazilian marginal basins have a potential reserve of about 40 billion barrels of oil-in-place, with 95% of them being sourced by rift-phase lacustrine environments. This study also provides a framework of bulk, elemental, and especially environmental and biological marker characteristics which can be compared with samples from other basins of the world.

Habitat of Petroleum in the Paleozoic Basins of Brazil: A Look Back, a Comparison, a Look Forward

It took almost a century of intermittent petroleum exploration in Brazil's vast Paleozoic basins before continuous production of about 5000 bbl per day of light oil, together with gas, could be established in one of them. Proved volumes of oil equivalent in place so far discovered in Paleozoic reservoirs amount to only 0.6% of the domestic total, but hopes of substantial new finds are great. In the Rio Urucu field of Solimoes basin (Upper Amazon), hydrocarbons are being produced from Early Carboniferous Monte Alegre formation sandstones roofed by evaporites and carbonates of the Carboniferous Itaituba formation which were intruded by thick Juro-Triassic igneous sills and folded during a Cretaceous reactivation event into the present-day shape of gentle anticlinal trends controlled by reverse faulting. The widespread occurrence of igneous intrusions and extrusions in the Solimoes, Amazonas, Parnaiba, and Parana basins is a major problem met by explorationists throughout the years but can be faced with presently available technology, seismic and other. Further investigations in these four basins are needed in order to better define details of basin architecture, configuration of basement, location of the oil kitchens, main carrier beds, windows in the dyke walls through which hydrocarbons could find their waymore » to the traps, etc. Examples from the various basins, along with a comparison to some successful exploration cases in the USA, suggest that the habitat of other commercial oil and gas in the Paleozoic basins of Brazil may be localized in the deeper basinal positions - like in the Rio Urucu trend - but also in the shallow flank areas, where igneous rocks tend to be scarcer and exploration baroquely started.« less

Petroleum Habitat in the Prerift and Synrift Sequences in the Brazilian Sedimentary Basins

The Late Jurassic and Early Cretaceous strata represent the sedimentary sequences deposited during the prerift and synrift tectonic phases in Brazilian basins. These basins developed by crustal thinning and rupture related to the separation of the African and South American continents. Since the beginning of oil exploration in Brazil, 139 oil and gas accumulations have been found in prerift and synrift sediments. Most of these accumulations occur in continental sandstones, but a few of them are also present in lacustrine carbonates and basalts. The hydrocarbon-producing basins in these sequences are Campos, Reconcavo, Tucano-Sul, Sergipe-Alagoas, Potiguar, and Ceara; with a volume of 1.46 {times} 10{sup 9} m{sup 3} (9.21 {times} 10{sup 9} bbl) oil equivalent in place and a proved exploitable reserve of 112.5 {times} 10{sup 6} m{sup 3} (708 {times} 10{sup 6} bbl). Their contribution to the oil industry in Brazil amounts to 340 {times} 10{sup 6} m{sup 3} (2.14 {times} 10{sup 9} bbl) of oil equivalent already produced. In spite of the exploration maturity of the basins, technological advancements will ensure the continuation and refinement of exploration in the Late Jurassic and Early Cretaceous sequences of the producing basins as well as in the potential ones. The volumes ofmore » oil and gas already discovered justify additional investigation in these sequences.« less

The Petroleum Habitat in the Post-Rift Sequences in the Brazilian Sedimentary Basins

The post-rift sedimentary strata of the Brazilian coastal basins are made of two main sequences: the evaporite and carbonatic Albian-Aptian sequence, and the open-marine Late Albian to Recent sequence, both related to the opening of the South Atlantic Ocean. More than 40 billion barrels of oil-equivalent in place has been found in these sequences, mostly in siliciclastic reservoirs above and below the Aptian salt beds. The productive basins are Campos, Espirito Santo, Sergipe-Alagoas, Potiguar, Ceara, and Santos, but the first one is responsible for more than 60% of the original oil in place discovered in these basins. The hydrocarbon origin, migration, and accumulation models in these sequences are discussed and exemplified by some giant oil fields of Campos and Sergipe-Alagoas basins, where oil is trapped in Aptian conglomerates, Albian carbonates, and Upper Cretaceous to Tertiary turbidite sandstones. The cumulative production in these sequences reaches 958.6 million barrels and the proved exploitable reserve amounts reach 2.7 billion barrels of oil-equivalent. Petrobras' exploratory forecast indicates that the post-rift sequences are the most prolific ones in the Brazilian marginal basins. The oil-equivalent that is expected to be discovered, particularly in deep water areas, where giant oil fields (as the Marlim field) have beenmore » found, exceeds the amount that has been discovered until now.« less

Frontier Tertiary Basins with Promising Hydrocarbon Potential, Offshore California

Dwindling domestic petroleum reserves have drawn attention to areas of promising potential within the United States. The federal outer continental shelf (OCS) off of California remains one of the most likely sources of future domestic oil and gas. The Federal Government, as mandated by the OCS Lands Act, must evaluate the OCS for hydrocarbon potential and to make promising areas available for exploration and production. Offshore Eel River basin, for example, contains the extension of the gas-producing Table Bluff trend. Seismic sections display amplitude and velocity anomalies, suggesting the possible presence of gas in offshore structures. Faulting, folding, and a thick Neogene marine section indicate a high probability of traps and source rocks being present. A moderately thick Neogene section and excellent structural development is observed in the southern Point Arena basin. The few wells previously drilled indicate mature source rocks are locally present and fractured reservoir potential is good to excellent. The structural geology of northern Bodega basin resembles that of Point Arena basin. Stratigraphic analogies are also evident, and the Neogene section appears to be thicker. This area should be considered a favorable petroleum habitat. Ano Nuevo basin displays many similarities to the Santa Maria and Salinas basins.more » The structural development provides trapping mechanisms, and the two offshore wells indicate mature source rocks. The reservoir potential is fair to excellent. Capistrano basin may be the least known of all the frontier offshore basins. Structural similarities to the Los Angeles basin suggest the likely formation of trapping mechanisms. Should stratigraphic similarities exist, then its oil and gas potential would be considered quite favorable.« less

The Habitat of Petroleum in the Brazilian Marginal and West African Basins: A Biological Marker Investigation: ABSTRACT

A geochemical and biological marker investigation of a variety of oils from offshore Brazil and west Africa, ranging in age from Lower Cretaceous to Tertiary, has been done, with the following aims: (1) assessing the depositional environment of source rocks, (2) correlating the reservoired oils, (3) comparing the Brazilian oils with their west African counterparts. The approach was based in stable isotope data; bulk, elemental, and hydrous pyrolysis results; and molecular studies involving quantitative geological marker investigations of alkanes using GC-MS and GC-MS-MS. The results reveal similarities between groups of oils from each side of the Atlantic and suggest an origin from source rocks deposited in five types of depositional environment: lacustrine fresh water, lacustrine saline water, marine evaporitic/carbonate, restricted marine anoxic, and marine deltaic. In west Africa, the Upper Cretaceous marine anoxic succession (Cenomanian-Santonian) appears to be a major oil producer, but in Brazil it is generally immature. The Brazilian offshore oils have arisen mainly from the pre-salt sequence, whereas the African oils show a balance between origins from the pre-salt and marine sequences. The integration of the geochemical and geological data indicate that new frontiers of hydrocarbon exploration in the west African basins must consider the Tertiary reservoirsmore » in the offshore area of Niger Delta, the reservoirs of the rift sequences in the shallow-water areas of south Gabon, Congo, and Cuanza basins, and the reservoirs from the drift sequences (post-salt) in the deep-water areas of Gabon, Congo Cabinda, and Cuanza basins.« less

Structural Style and Petroleum Habitat Related to Tectonic Evolution of Potiguar Basin, Brazil: ABSTRACT

The Potiguar basin is the eastermost basin on the Brazilian equatorial margin and covers an area of 48,000 km/sup 2/. The basin extends from about 200 km landward of the coastline out beneath the present continental shelf and slope to a water depth of 2,000 m. It contains a sedimentary sequence more than 8 kim thick, which filled the asymmetric grabens that developed at an early stage of South American/Africa breakup in the Neocomian. Presently, 28 oil fields have been discovered; 23 onshore and 5 offshore. These fields contain proved oil reserves of 35 x 10/sup 6/ m/sup 3/ and occur in structures formed during the stretching and cooling stages of the tectonic evolution of the basin. Two main groups of petroleum habitats are distinguished according to structure type and reservoir-source rock association. During the stretching stage, grabens were formed and filled with lacustrine, deltaic, and deltaic fan sediments. These sediments were affected by gravity sliding, northeast-southwest normal faulting, and east-west strike-slip faulting. These movements created the closures that formed the oil accumulations. Producing reservoirs consist of coarse to fine-grained sandstones closely associated with the source rocks.

SUBSIDENCE, SEDIMENTATION AND PETROLEUM SYSTEMS

Analysis of a number of petroleum provinces has emphasised the importance of sedimentary factors as well as subsidence processes. Subsidence appears to depend on a small number of mechanisms ‐ tectonics, heat flow and gravity. Taking into account thegeodynamic context in which these processes develop, it is possible to compile a classification of subsidence types which is distinct from the usual classifications in terms of basins. The type of subsidence influences the deposition rate, which determines both the potential and the habitat of petroleum. Moreover, existing statistics sho w that the number of “giant”fielako, r thep otential of a petroleum province largely depend on the types of subsidence and subsequent tectonic processes.However, it is also important to consider the history of a basin in terms of flows: geothermal flows from the mantle and crust; and water and hydrocarbon flows through the sedimentary volume. For these flow transfers, climatic and sedimentary factors, as well as variations in sea level, play a role which is as important as subsidence and uplift in controlling the distribution of non‐deposition areas, unconformities, seals and reservoirs. For example, periods of generalized transgression are favorable to both the development of carbonate platforms, and the formation of impervious horizons, seals and source rocks capable of sealing pre‐existing rifts.Therefore, a petroleum province can be considered as the final result of an organized set of geological events (in space and in time) that can be called apetroleum system. In such a system, thesequence ofsubsidencemovements and associatedflows isjust asdecisiveas lithological and geometric factors in the formation of a group of pools. This concept of the succession of geodynamics and sedimentary processes which affect petroleum potential is developed, and specific examples of petroleum systems from the North Sea, the Arabian Platform and the Congo Basin are presented.