CHARACTERIZATION OF UPPER PALAEOZOIC ORGANIC‐RICH UNITS IN SVALBARD: IMPLICATIONS FOR THE PETROLEUM SYSTEMS OF THE NORWEGIAN BARENTS SHELF

Recent discoveries of hydrocarbons along the western margin of the Norwegian Barents Shelf have emphasised the need for a better understanding of the source rock potential of the Upper Palaeozoic succession. In this study, a comprehensive set of organic geochemical data have been collected from the Carboniferous – Permian interval outcropping on Svalbard in order to re‐assess the offshore potential. Four stratigraphic levels with organic‐rich facies have been identified: (i) Lower Carboniferous (Mississippian) fluvio‐lacustrine intervals with TOC between 1 and 75 wt.% and a cumulative organic‐rich section more than 100 m thick; (ii) Upper Carboniferous (Pennsylvanian) evaporite‐associated marine shales and organic‐rich carbonates with TOC up to 20 wt.%; (iii) a widespread lowermost Permian organic‐rich carbonate unit, 2–10 m thick, with 1–10 wt. % TOC; and (iv) Lower Permian organic‐rich marine shales with an average TOC content of 10 wt.%. Petroleum can potentially be tied to organic‐rich facies at formation level based on the gammacerane index, δ¹³C of the aromatic fraction and/or the Pr/Ph ratio. Relatively heavy δ¹³C values, a low gammacerane index and high Pr/Ph ratios characterize Lower Carboniferous non‐marine sediments, whereas evaporite‐associated facies have lighter δ¹³C, a higher gammacerane index and lower Pr/Ph ratios.     

PETROLEUM SYSTEMS OF THE WEST IBERIAN MARGIN: A REVIEW OF THE LUSITANIAN BASIN AND THE DEEP OFFSHORE PENICHE BASIN

The relatively well‐studied Lusitanian Basin in coastal west‐central Portugal can be used as an analogue for the less well‐known Peniche Basin in the deep offshore. In this paper the Lusitanian Basin is reviewed in terms of stratigraphy, sedimentology, evolution and petroleum systems. Data comes from published papers and technical reports as well as original research and field observations. The integration and interpretation of these data is used to build up an updated petroleum systems analysis of the basin. Petroleum systems elements include Palaeozoic and Mesozoic source rocks, siliciclastic and carbonate reservoir rocks, and Mesozoic and Tertiary seals. Traps are in general controlled by diapiric movement of Hettangian clays and evaporites during the Late Jurassic, Late Cretaceous and Late Miocene. Organic matter maturation, mainly due to Late Jurassic rift‐related subsidence and burial, is described together with hydrocarbon migration and trapping. Three main petroleum systems may be defined, sourced respectively by Palaeozoic shales, Early Jurassic marly shales and Late Jurassic marls. These elements and systems can tentatively be extrapolated offshore into the deep‐water Peniche Basin, where no exploration wells have so far been drilled. There are both similarities and differences between the Lusitanian and Peniche Basins, the differences being mainly related to the more distal position of the Peniche Basin and the later onset of the main rift phase which was accompanied by Early Cretaceous subsidence and burial. The main exploration risks are related to overburden and maturation timing versus trap formation associated both with diapiric movement of Hettangian salt and Cenozoic inversion.     

PETROLEUM GEOLOGY OF THE FULA SUB‐BASIN,MUGLAD BASIN,SUDAN

The Fula sub‐basin is a fault‐bounded depression located in the NE of the Muglad Basin, Sudan, and covers an area of about 3560 km². Eleven oilfields and oil‐bearing structures have been discovered in the sub‐basin. The Lower Cretaceous Abu Gabra shales (Barremian – Aptian), deposited in a deep‐water lacustrine environment, are major source rocks. Reservoir targets include interbedded sandstones within the Abu Gabra Formation and sandstones in the overlying Bentiu and Aradeiba Formations (Albian – Cenomanian and Turonian, respectively). Oil‐source correlation indicates that crude oils in the Aradeiba and Bentiu Formations are characterized by low APIs (<22°), low sulphur contents (<0.2%), high viscosity and high Total Acid Number (TAN: >6 mg KOH/g oil on average). By contrast, API, viscosity and TAN for oils in the Abu Gabra Formation vary widely. These differences indicate that oil migration and accumulation in the Fula sub‐basin is more complicated than in other parts of the Muglad Basin, probably as a result of regional transtension and inversion during the Late Cretaceous and Tertiary. The Aradeiba‐Bentiu and Abu Gabra Formations form separate exploration targets in the Fula sub‐basin. Four play fairways are identified: the central oblique anticline zone, boundary fault zone, fault terrance zone and sag zone. The most prospective locations are probably located in the central oblique anticline zone.     

SOME THOUGHTS ON THE INFLUENCE OF PRESSURE AND THERMAL HISTORY ASSUMPTIONS ON PETROLEUM SYSTEMS MODELLING

The use of petroleum systems modelling (PSM) requires the integration of the geological sciences with petroleum engineering, physics and chemistry. In a recent paper in JPG (October 2014, vo. 37, pp 329–348), Mahanjane et al. (2014) applied a 1‐D petroleum systems model to the study of maturation and petroleum generation in northern Mozambique. However, PSM cannot divorce itself from the fundamental laws of mechanics and thermodynamics when attempting to derive a thermal history to be used for the modelling of maturation and petroleum generation. As will be shown in this brief Comment, the application of mechanics and thermodynamics to the derivation of the thermal history may require some radical changes to the methods currently used in PSM. Mechanics and thermodynamics require a reducing heat flow during subsidence, but require an increased heat flow during inversion. The failure to apply mechanics and thermodynamics during thermal history derivation in PSM arises from a failure to incorporate the effects of pressure into the kinetic models used for predicting maturation and petroleum generation. Pressure increases the activation energy of endothermic reactions including maturation and petroleum generation in the kinetic model used to predict the reaction rate, and results in higher temperatures being required to produce the same transformation ratio as would be required for the current temperature – time kinetic models. Incorporating pressure should enable the same thermal history obtained from tectonic history‐mechanic‐thermodynamic models to be used as those used to calibrate the thermal history using maturity parameters such as vitrinite reflectance.     

A REVIEW OF PERMO‐TRIASSIC RESERVOIR ROCKS IN THE ZAGROS AREA,SW IRAN: INFLUENCE OF THE QATAR‐FARS ARCH

Four “supergiant” and numerous giant gasfields have been discovered in the Zagros area of SW Iran. The gasfields are concentrated in the eastern part of the foldbelt, in Fars Province and the adjacent offshore, and produce from Permo‐Triassic carbonates equivalent to the Khuff Formation. The carbonates belong to the upper member of the Dalan Formation and the overlying Kangan Formation. Reservoir rock quality is strongly influenced by tectonic setting and depositional environment, and also by diagenesis. The highest quality reservoirs occur in oolitic shoal facies; fracturing (especially in onshore fields) and dolomitisation (in offshore fields) have also influenced reservoir quality. Anhydrite plugging is common in reservoirs in offshore fields, while calcite cementation is dominant in onshore reservoirs. Facies variations in the Dalan‐Kangan Formations appear to correspond to syndepositional palaeohighs and depocentres. In the Eastern Zagros (Fars area), thickening of the Dalan Formation corresponds to a Mid‐Late Permian depocentre referred to here as the Permian Fars Basin. As a result of sea level fall, this depocentre evolved into a hypersaline lagoon with evaporite deposition (Nar Member). In the Triassic, the depocentre evolved into a palaeohigh as indicated by thinning and facies changes in the Kangan Formation. The results of this study draw attention to variations in the reservoir quality of the Dalan‐Kangan Formations. Much of this variation was due to the influence of the Qatar‐Fars Arch.     

THE ORIGIN OF THE PERMO-TRIASSIC GAS ACCUMULATIONS IN THE IRANIAN ZAGROS FOLDBELT AND CONTIGUOUS OFFSHORE AREAS: A REVIEW OF THE PALAEOZOIC PETROLEUM SYSTEM

More than 1500 trillion cubic feet (Tcf) of gas reserves have been discovered in Permo-Triassic carbonates sealed by thick Triassic anhydrites in the Zagros Foldbelt (SW Iran), the southern part of the Gulf (Iran, Qatar, and Abu Dhabi) and Saudi Arabia. This paper discusses the origins of this gas in terms of source rock distribution and thermal maturation through time (as indicated by modelling), regional variations in thermal maturation (as indicated by cumulative isopachs), and long-range migration and accumulation of hydrocarbon prior to the Zagros orogeny. The sequence of events leading to the present-day distribution of gas accumulations is reconstructed in detail.
The only important source rocks so far identified in the Late Proterozoic to Late Triassic succession are organic-rich, radioactive shales which are dated as Llandoverian (early Silurian). Oil generation began in the Middle Jurassic in areas of greatest subsidence, while the gas window was reached locally as early as the Middle Cretaceous. Huge volumes of oil, then of gas, accumulated in a few major regional highs and salt-related structures prior to the Zagros orogeny. Part of the gas was lost during Zagros folding as some of the anticlines were breached, and another portion, possibly associated with light oil, remigrated into unbreached Zagros anticlines.
Among critical parameters essential to the appraisal of the numerous Permo-Triassic prospects present in Lurestan, Fars and in the Iranian Offshore, three are discussed in this paper, namely (i) the location of prospects in comparison to pre-Zagros regional highs and to reconstructed pre-Zagros gas accumulations; (ii) the characteristics of potential reservoir intervals in the Dalan/Kangan Formation; and (iii) the extent of the Dashtak evaporitic seal. The distribution of surface oil, bitumen and gas seepages together with indirect hydrocarbon indications provides an additional exploration tool.     

AN INTRODUCTION TO THE PRECAMBRIAN PETROLEUM SYSTEM IN THE SANKURU‐MBUJI‐MAYI‐LOMAMI‐LOVOY BASIN,SOUTH‐CENTRAL DEMOCRATIC REPUBLIC OF CONGO

This study presents a preliminary assessment of the petroleum potential of the Meso‐Neoproterozoic Mbuji‐Mayi Supergroup in the Sankuru‐Mbuji‐Mayi‐Lomami‐Lovoy Basin in the southern‐central Democratic Republic of Congo. This basin is one of the least explored in Central Africa and is a valuable resource for the evaluation of the petroleum system in the greater Congo Basin area. Highly altered carbonates (potential reservoir rocks) and black shales (potential source rocks) are present in the Mbuji‐Mayi Supergroup, which can be divided into the BI and overlying BII groups (Stenian and Tonian, respectively). For this study, samples of the BIe to BIIe subgroups from five boreholes and two outcrops were evaluated with petrographic, petrophysical and geochemical analyses. Carbonates in the BIe to BIIe subgroups with reservoir potential include oolitic packstones and grainstones, stromatolitic packstones and boundstones, various dolostones, and brecciated and zoned limestones. Thin section studies showed that porosity in samples of these carbonates is mainly vuggy and mouldic with well‐developed fractures, and secondary porosity is up to 12%. Black shales in the BIIc subgroup have TOC contents of 0.5–1%, and the organic matter is interpreted to have been derived from precursor Type I / II kerogen. The thermal maturity of asphaltite in carbonate samples is indicated by Raman spectroscopy‐derived palaeo‐temperatures which range from ～150 to ～260°C, which is typical of low‐grade metamorphism. Raman reflectance (R_mcR_o%) values on asphaltite samples were between 1.0 and 2.7%, indicating mature organic matter corresponding to the oil and wet gas windows. Source rock maturation and primary oil migration are interpreted to have occurred during Lufilian deformation (650–530 Ma). The solid asphaltite present in fractures in the dolostones of the BIIc subgroup may represent biodegraded light oil from an as‐yet unknown source which probably migrated during the Cambrian‐Ordovician (～540–480 Ma). This migration event may have been related to the effects of the peak phase of Lufilian deformation in the Katanga Basin to the SE. This study is intended to provide a starting‐point for more detailed evaluations of potential hydrocarbon systems in the Sankuru‐Mbuji‐Mayi‐Lomami‐Lovoy Basin and the adjacent greater Congo Basin area.     

CRUDE OIL GEOCHEMISTRY AND SOURCE ROCK POTENTIAL OF THE UPPER CRETACEOUS – EOCENE SUCCESSION IN THE BELAYIM OILFIELDS,CENTRAL GULF OF SUEZ,EGYPT

This study evaluates the petroleum potential of source rocks in the pre‐rift Upper Cretaceous – Eocene succession at the Belayim oilfields in the central Gulf of Suez Basin. Organic geochemical and palynofacies investigations were carried out on 65 cuttings samples collected from the Thebes, Brown Limestone and Matulla Formations. Analytical methods included Rock‐Eval pyrolysis, Liquid Chromatography, Gas Chromatography and Gas Chromatography – Mass Spectrometry. Four crude oil samples from producing wells were characterised using C₇ light hydrocarbons, stable carbon isotopes and biomarker characteristics. The results showed that the studied source rocks are composed of marine carbonates with organic matter dominated by algae and bacteria with minimal terrigenous input, deposited under reducing conditions. This conclusion was supported by n‐alkane distributions, pristane/ phytane ratios, homohopane and gammacerane indices, high concentrations of cholestane, the presence of C₃₀ n‐propylcholestanes, and low diasterane ratios. The source rocks ranged from immature to marginally mature based on the Rock‐Eval T_max together with biomarker maturity parameters. The analysed crude oil samples are interpreted to have been derived from source rock intervals within the Eocene Thebes Formation and the Upper Cretaceous Brown Limestone. The similarity in the geochemical characteristics of the crude oils suggests that there was little variation in the organofacies of the source rocks from which they were derived.     

RESERVOIR SANDSTONES OF THE CRETACEOUS NAPO FORMATION U AND T MEMBERS IN THE ORIENTE BASIN,ECUADOR: LINKS BETWEEN DIAGENESIS AND SEQUENCE STRATIGRAPHY

This paper investigates whether diagenetic alterations in sandstones and resulting changes in reservoir quality are influenced by depositional environments and sequence stratigraphy. The study focusses on the Cretaceous U and T sandstone members of the Napo Formation in the Oriente Basin of Ecuador. The sandstones were deposited in fluvial, transitional and marine environments, and comprise Lowstand (LST), Transgressive (TST) and Highstand Systems Tract (HST) deposits. The data were obtained by detailed petrographic observations supported by microprobe, stable isotope, and fluid inclusion analyses. The sandstones consist of fine- to medium-grained quartzarenites and subarkoses. Diagenetic events include cementation by chlorite, early and late kaolinite/dickite, early and late carbonates (siderite, Fe-dolomite/ankerite), and quartz. Early (eogenetic) processes included formation of chlorite grain coatings, kaolinite pore filling, and siderite (SI) cementation. Chlorite is absent in TST sandstones but was found frequently in LST-HST sandstones. Early kaolinite is not present in LST sandstones but occurred frequently in LST-HST sandstones. The distribution of mesogenetic cements relative to sequence stratigraphy is different in the U and T units. In the U sandstones, calcite is frequent in LST deposits and absent in the LST-HST. Fe-dolomite/ankerite is abundant only in the TST. S2 siderite is present in the TST and LST, but absent in the LST-HST. Quartz cement and kaolinite/dickite are equally distributed in all systems tracts. In the T sandstones Fe-dolomite/ankerite is only abundant in the TST, whilst calcite, quartz and dickite have similar distributions in all the systems tracts. The distribution of kaolinite cement is interpreted to be the result of relatively more intense meteoric-water flux occurring during sea-level fall, whereas chlorite cement may have formed through burial diagenetic transformation of precursor clays e.g. berthierine which was precipitated in mixed marine-meteoric waters in tidal channel and estuarine environments. Chlorite cement in the T and U sandstones appears to have retarded development of quartz overgrowths, and 12–13% primary porosity is retained. The T sandstones (LST-HST) contain up to 4% chlorite cement. Little evidence for chemical compaction was found with the exception of occasional concave-convex grain contacts. Eogenetic siderite appears to have helped to preserve reservoir quality through supporting the sandstone framework against further compaction, but mesogenetic calcite has considerably reduced primary porosity. Eogenetic siderite (SI) was partly replaced by later carbonate cements such as late siderite (S2) and Fe-dolomite. Although there appears to be a relationship in the Napo Formation between the occurrence of siderite SI and sequence stratigraphy, the relationship may change when original volumes of siderite are considered. There is likewise partial replacement of early kaolinite and recrystalization to dickite which masks the amount of original early kaolinite. Since the amount of early kaolinite could not be confirmed, the relationship to sequence stratigraphy is tentative. Only chlorite seems to have a clear relationship to sequence stratigraphic framework in the Napo Formation. The high intergranular volume (IGV) of the sandstones indicates that cementation played a more important role than mechanical and chemical compaction in both Napo Formation sandstone members. Later dissolution of feldspar grains and siderite cements was the main process of secondary porosity development (up to 11% in the U sandstones).     

PETROLEUM GEOLOGY AND HYDROCARBON POTENTIAL OF THE ADRIATIC BASIN,OFFSHORE CROATIA

Offshore Croatia is a relatively underexplored area with no oilfields currently on production. Exploration commenced in 1970 and several biogenic gas fields were subsequently discovered producing from shallow Plio‐Pleistocene reservoir rocks in the northern Adriatic area; however, exploration wells drilled for oil in Mesozoic carbonates have failed, although several wells encountered oil shows. Using data from the Croatian and Italian Adriatic, we provide in this paper some new insights into the Mesozoic palaeogeography and hydrocarbon plays of offshore Croatia. Offshore Croatia has been divided into three areas – north, central and south – with distinctive geological characteristics and hydrocarbon systems. The effects and importance of halokinesis in the eastern Adriatic is described and its influence on the petroleum systems is discussed. The evaluation of a modern, regional, high‐resolution dataset has enhanced our understanding of the Adriatic Basin and supports the presence of petroleum systems with potential mature source rocks in shales from the Triassic succession, supplying reservoir rocks in Jurassic and Cretaceous carbonate platform margins/slope talus plays, and Cenozoic siliciclastic plays.     

PETROLEUM SYSTEMS MODELLING IN A FOLD‐AND‐THRUST BELT SETTING: THE INVERTED CAMEROS BASIN,NORTH‐CENTRAL SPAIN

The Mesozoic Cameros Basin, northern Spain, was inverted during the Cenozoic Alpine orogeny when the Tithonian – Upper Cretaceous sedimentary fill was uplifted and partially eroded. Tar sandstones outcropping in the southern part of the basin and pyrobitumen particles trapped in potential source rocks suggest that hydrocarbons have been generated in the basin and subsequently migrated. However, no economic accumulations of oil or gas have yet been found. This study reconstructs the evolution of possible petroleum systems in the basin from initial extension through to the inversion phase, and is based on structural, stratigraphic and sedimentological data integrated with petrographic and geochemical observations. Petroleum systems modelling was used to investigate the timing of source rock maturation and hydrocarbon generation, and to reconstruct possible hydrocarbon migration pathways and accumulations. In the northern part of the basin, modelling results indicate that the generation of hydrocarbons began in the Early Berriasian and reached a peak in the Late Barremian – Early Albian. The absence of traps during peak generation prevented the formation of significant hydrocarbon accumulations. Some accumulations formed after the deposition of post‐extensional units (Late Cretaceous in age) which acted as seals. However, during subsequent inversion, these reservoir units were uplifted and eroded. In the southern sector of the basin, hydrocarbon generation did not begin until the Late Cretaceous due to the lower rates of subsidence and burial, and migration and accumulation may have taken place until the initial phases of inversion. Sandstones impregnated with bitumen (tar sandstones) observed at the present day in the crests of surface anticlines in the south of the basin are interpreted to represent the relics of these palaeo‐accumulations. Despite a number of uncertainties which are inherent to modelling the petroleum systems evolution of an inverted and overmature basin, this study demonstrates the importance of integrating multidisciplinary and multi‐scale data to the resource assessment of a complex fold‐and‐thrust belt.     

PETROLEUM SYSTEMS OF THE BONGOR BASIN AND THE GREAT BAOBAB OILFIELD,SOUTHERN CHAD

The Bongor Basin in southern Chad is an inverted rift basin located on Precambrian crystalline basement which is linked regionally to the Mesozoic – Cenozoic Western and Central African Rift System. Pay zones present in nearby rift basins (e.g. Upper Cretaceous and Paleogene reservoirs overlying Lower Cretaceous source rocks) are absent from the Bongor Basin, having been removed during latest Cretaceous – Paleogene inversion-related uplift and erosion. This study characterizes the petroleum system of the Bongor Basin through systematic analyses of source rocks, reservoirs and cap rocks. Geochemical analyses of core plug samples of dark mudstones indicate that source rock intervals are present in Lower Cretaceous lacustrine shales of the Mimosa and upper Prosopis Formations. In addition, these mudstones are confirmed as a regional seal. Reservoir units include both Lower Cretaceous sandstones and Precambrian basement rocks, and mature source rocks may also act as a potential reservoir for shale oil. Dominant structural styles are large-scale inversion anticlines in the Lower Cretaceous succession whilst underlying “buried hill” -type basement plays may also be important. Accumulations of heavy to light oils and gas have been discovered in Lower Cretaceous sandstones and basement reservoirs. The Great Baobab field, the largest discovery in the Bongor Basin with about 1.5 billion barrels of oil in-place, is located in the Northern Slope, a structural unit near the northern margin of the basin. Reservoirs are Lower Cretaceous syn-rift sandstones and weathered and fractured zones in the crystalline basement. The field currently produces about 32,000 barrels of oil per day.     

ORGANIC GEOCHEMISTRY OF BARENTS SEA PETROLEUM: THERMAL MATURITY AND ALTERATION AND MIXING PROCESSES IN OILS AND CONDENSATES

The petroleum system in the Barents Sea is complex with numerous source rocks and multiple uplift events resulting in the remigration and mixing of petroleum. In order to investigate the degree of mixing, 50 oil and condensate samples from 30 wells in the SW Barents Sea were geochemically analysed by GC‐FID and GC‐MS to evaluate their thermal maturity and secondary alteration signatures. Saturated and aromatic compounds from C₁₄–C₁₈ and biomarker range (C₂₀₊) hydrocarbons were compared with light (C₄‐C₈) hydrocarbon alteration and maturity signatures from a previous study. The geochemical data demonstrate that petroleum generation occurred from the early‐ to late‐oil/condensate window, correlating to calculated vitrinite reflection values of between 0.7%R_c and 1.9%R_c. Two maturation traits are in general present in the oil samples analysed and indicate mixing of petroleum phases: a C₂₀₊ fraction which represents a possible “black‐oil ‐related” signature; and a C_20‐ fraction, which is probably a more recent oil charge. However, maturity variations are less pronounced in condensates, which in general exhibit higher generation temperatures than oils but are influenced by severe phase fractionation effects. The samples are characterised by diverse biodegradation signatures including depletion of C_15‐ saturated compounds, almost complete removal of n‐alkanes, elevated Pr/n‐C₁₇ values, high 17α(H), 25‐norhopane content, and a reverse trend in methylated naphthalene distribution. However, the presence of the more recent, unaltered light hydrocarbon charge together with the oil with a palaeo‐biodegraded signature is clear evidence that mixing has occurred. A cross‐plot of C₂₄‐tetracyclic terpane/C₃₀αβ‐hopane versus C₂₃‐C₂₉‐tricyclic terpane/C₃₀αβ‐hopane can be used to discriminate between Palaeozoic/Triassic and Jurassic‐generated petroleums in the Barents Sea region, since it appears to be maturity independent.     

TRIASSIC – QUATERNARY SEQUENCE STRATIGRAPHY OF THE TARFAYA BASIN (MOROCCAN ATLANTIC): STRUCTURAL EVOLUTION,EUSTASY AND SEDIMENTATION

This paper discusses the seismic and sequence stratigraphy of the Tarfaya Basin passive continental margin in southern Morocco and investigates the implications for the basin's petroleum geology. Analyses of a new database consisting of SGY 2D seismic lines and wells indicate that the sedimentary succession on the Tarfaya margin can be divided into ten seismic sequences within four major transgressive‐regressive cycles separated by regional unconformities. Variations in the stratigraphic architecture of the margin suggest that regional tectonic influences have episodically overprinted global eustatic signals. A number of clastic reservoirs and source rock intervals have been identified in this margin, but only Jurassic carbonate and Cretaceous clastic plays have been tested on the shelf area. Cretaceous submarine fans and Tertiary turbidite systems in deep‐water areas remain untested and may have major hydrocarbon potential.     

AN OVERVIEW OF THE PETROLEUM SYSTEMS IN THE IONIAN ZONE,ONSHORE NW GREECE AND ALBANIA

The Ionian and Gavrovo Zones in the external Hellenide fold‐and‐thrust belt of western Greece are a southern extension of the proven Albanian oil and gas province. Two petroleum systems have been identified here: a Mesozoic mainly oil‐prone system, and a Cenozoic system with gas potential. Potential Mesozoic source rocks include organic‐rich shales within Triassic evaporites and dissolution‐collapse breccias; marls at the base of the Early Jurassic (lower Toarcian) Ammonitico Rosso; the Lower and Upper Posidonia beds (Toarcian–Aalenian and Callovian–Tithonian respectively); and the Late Cretaceous (Cenomanian–Turonian) Vigla Shales, part of the Vigla Limestone Formation. These potential source rocks contain Types I‐II kerogen and are mature for oil generation if sufficiently deeply buried. The Vigla Shales have TOC up to 2.5% and good to excellent hydrocarbon generation potential with kerogen Type II. Potential Cenozoic gas‐prone source rocks with Type III kerogen comprise organic‐rich intervals in Eocene–Oligocene and Aquitanian–Burdigalian submarine fan deposits, which may generate biogenic gas. The complex regional deformation history of the external Hellenide foldbelt, with periods of both crustal extension and shortening, has resulted in the development of structural traps. Mesozoic extensional structures have been overprinted by later Hellenide thrusts, and favourable trap locations may occur along thrust back‐limbs and in the crests of anticlines. Trapping geometries may also be provided by lateral discontinuities in the basal detachment in the thin‐skinned fold‐and‐thrust belt, or associated with strike‐slip fault zones. Regional‐scale seals are provided by Triassic evaporites, and Eocene‐Oligocene and Neogene shales. Onshore oil‐ and gasfields in Albania are located in the Peri‐Adriatic Depression and Ionian Zone. Numerous oil seeps have been recorded in the Kruja Zone but no commercial hydrocarbon accumulations. Source rocks in the Ionian Zone comprise Upper Triassic – Lower Jurassic carbonates and shales of Middle Jurassic, Late Jurassic and Early Cretaceous ages. Reservoir rocks in both oil‐ and gas‐fields in general consist of silicilastics in the Peri‐Adriatic Depression succession and the underlying Cretaceous–Eocene carbonates with minimal primary porosity improved by fracturing in the Albanian Ionian Zone. Oil accumulations in thrust‐related structures are sealed by the overlying Oligocene flysch whereas seals for gas accumulations are provided by Upper Miocene–Pliocene shales. Thin‐kinned thrusting along flysch décollements, resulting in stacked carbonate sequences, has clearly been demonstrated on seismic profiles and in well data, possibly enhanced by evaporitic horizons. Offshore Albania in the South Adriatic basin, exploration targets in the SW include possible compressional structures and topographic highs proximal to the relatively unstructured boundary of the Apulian platform. Further to the north, there is potential for oil accumulations both in the overpressured siliciclastic section and in the underlying deeply buried platform carbonates. Biogenic gas potential is related to structures in the overpressured Neogene (Miocene–Pliocene) succession.     

GEOCHEMISTRY OF CRUDE OILS,SEEPAGE OILS AND SOURCE ROCKS FROM BELIZE AND GUATEMALA: INDICATIONS OF CARBONATE‐SOURCED PETROLEUM SYSTEMS

This study reviews the stratigraphy and the poorly documented petroleum geology of the Belize‐Guatemala area in northern Central America. Guatemala is divided by the east‐west trending La Libertad arch into the North and South Petén Basins. The arch is the westward continuation of the Maya Mountains fault block in central Belize which separates the Corozal Basin in northern Belize from the Belize Basin to the south. Numerous petroleum seeps have been reported in both of these basins. Small‐scale oil production takes place in the Corozal Basin and the North and South Petén Basins. For this study, samples of crude oil, seepage oil and potential source rocks were collected from both countries and were investigated by organic geochemical analyses and microscopy. The oil samples consisted of non‐biodegraded crude oils and slightly to severely biodegraded seepage oils, both of which were generated from source rocks with similar thermal maturities. The crude oils were generated from marine carbonate source rocks and could be divided into three groups: Group 1 oils come from the North Petén Basin (Guatemala) and the western part of the Corozal Basin (Belize), and have a typical carbonate‐sourced geochemical composition. The oils correlate with extracts of organic‐rich limestones assigned to the Upper Cretaceous “Xan horizon” in the Xan oilfield in the North Petén Basin. The oils were generated from a single source facies in the North Petén Basin, but were charged from two different sub‐basins. Group 2 oils comprise crudes from the South Petén Basin. They have characteristics typical of carbonate‐sourced oils, but these characteristics are less pronounced than those of Group 1 oils. A mixed marine/lacustrine source facies deposited under strongly reducing conditions in a local kitchen area is inferred. Group 3 oils come from the Corozal Basin, Belize. A carbonate but also a more “shaly” source rock composition for these oils is inferred. A severely biodegraded seepage oil from Belmopan, the capital of Belize, resembles a nearby crude oil. The eastern sub‐basin in the North Petén Basin may potentially be the kitchen area for these oils, and for the seepage oils found in the western part of the Corozal Basin. The seepage oils from the Corozal and Belize Basins are moderately to severely biodegraded and were generated from carbonate source rocks. Some of the seepage oils have identical C_27–29 sterane distributions to the Group 2 oils, but “biodegradation insensitive” biomarker ratios show that the seepage oils can be divided into separate sub‐groups. Severely and slightly biodegraded seepage oils in the Belize Basin were probably almost identical prior to biodegradation. Lower Cretaceous limestones from the Belize Basin have petroleum generation potential, but the samples are immature. The kitchen for the seepage oils in the Belize Basin remains unknown.     

BIOMARKER CHARACTERISTICS OF POTENTIAL SOURCE ROCKS IN THE JABAL NAFUSAH AREA,NW LIBYA: PETROLEUM SYSTEMS SIGNIFICANCE

The Jifarah Arch of NW Libya is a structurally prominent feature at the eastern end of the regional Talemzane Arch, separating the Ghadamis hydrocarbon province to the south from the offshore Pelagian province to the north. The Arch has experienced a complex structural history with repeated episodes of uplift, exhumation and burial. This paper provides a provisional assessment of its hydrocarbon habitat based on detailed geochemical analyses of potential Triassic, Silurian and Ordovician source rocks encountered by wells drilled in the area. Twenty‐seven core and cuttings samples of marine shales were collected from eight widely‐ dispersed wells and analyzed using standard Rock‐Eval pyrolysis techniques. Kerogen types II‐III were identified in the majority of Triassic samples analysed, indicating a low hydrocarbon generation potential, but oil‐prone Type II kerogen was found in the basal Silurian Tanezzuft Formation and Ordovician Memouniat Formation. The presence of steranes and acyclic isoprenoids suggested variable inputs of algal, bacterial and terrestrial organic matter, while biomarkers including C₃₀‐gammacerane and β–carotene and selected biomarker ratios (Pr/Ph ratio and homohopane index) were used to assess their depositional environment. Results indicate that extended zones with periodic (if not continuous) oxygen‐deficient conditions existed throughout the basin during Late Ordovician and Early Silurian time, favouring the preservation of organic matter. The thermal maturity of the samples was assessed by Rock‐Eval pyrolysis, zooclast reflectance, molecular ratios including C_32‐22S/(22S+22R)‐homohopanes, Ts/(Ts+Tm), C₂₉‐steranes and parameters based on the relative abundance of methylphenanthrene, methyldibenzothiophene and methylnaphthalene isomers. The results indicate significant variability in thermal maturity, with Ordovician and Silurian source rocks ranging from 0.6% to 0.7% VR_o equivalent increasing to 1.0% locally. These values represent palaeo‐maturities achieved at different times in the past and are considered too low to have generated significant volumes of hydrocarbons directly. However the downdip equivalents of these source rocks in the adjacent Ghadamis Basin contributed to prolific petroleum systems. The absence of large petroleum accumulations on the Jifarah Arch contrasts with the western part of the geologically similar Talemzane Arch, which harbours several giant and supergiant oil and gas fields. This difference is attributed both to the complex structural history of the Jifarah Arch, which permitted post‐charge leakage of palaeo‐accumulations, and stratigraphic migration barriers which restricted migration between Tanezzuft source rocks and Ordovician and Triassic reservoirs.     

MATURITY AND PETROLEUM SYSTEMS MODELLING IN THE OFFSHORE ZAMBEZI DELTA DEPRESSION AND ANGOCHE BASIN,NORTHERN MOZAMBIQUE

Petroleum systems analysis and maturity modelling is used to predict the timing and locations of hydrocarbon generation in the underexplored offshore Zambezi Delta depression and Angoche basin, northern Mozambique. Model inputs include available geological, geochemical and geophysical data. Based on recent plate‐tectonic reconstructions and regional correlations, the presence of Valanginian and Middle and/or Late Jurassic marine source rock is proposed in the study area. The stratigraphy of the Mozambique margin was interpreted along reflection seismic lines and tied to four wells in the Zambezi Delta depression. Thermal maturity was calibrated against measured vitrinite reflectance values from these four wells. Four 1‐D models with calibration data were constructed, together with another five without calibration data at pseudo‐well locations, and indicate the maturity of possible source rocks in the Zambezi Delta depressions and Angoche basin. Two 2‐D petroleum systems models, constrained by seismic reflection data, depict the burial history and maturity evolution of the Zambezi Delta basin. With the exception of the deeply‐buried centre of the Zambezi Delta depression where potential Jurassic and Lower Cretaceous source rocks were found to be overmature for both oil and gas, modelling showed that potential source rocks in the remaining parts of the study area are mature for hydrocarbon generation. In both the Zambezi Delta depression and Angoche basin, indications for natural gas may be explained by early maturation of oil‐prone source rocks and secondary oil cracking, which likely began in the Early Cretaceous. In distal parts of the Angoche basin, however, the proposed source rocks remain in the oil window.