Evaporite Seals Research Articles

The evolution of depletion zones beneath mud volcanoes

Depletion zones are the least well understood component of mud volcanic systems. They are generally difficult to image using reflection seismic data, and have only rarely been identified and described in the subsurface. This study documents 277 mapped depletion zones in the western Nile Cone, offshore Egypt, of which the dimensions and stratigraphic characteristics of a sub-set of 86 depletion zones associated with mud volcanoes of early Pliocene to Recent age are recorded. The primary database used is a large (4,300 km2) 3D seismic survey in which depletion zones can be confidently interpreted using a set of simple criteria. The sub-set of 86 depletion zones were selected for morphometric analysis by virtue of the quality of seismic imaging. The depletion zones are characterised by circular to elliptical planforms with a bowl or conical geometry. They exhibit truncational stratal relationships with their parent stratigraphic unit, which in this area is the Mid-Late Miocene aged OM2 unit, and which occurs directly beneath the Messinian Evaporites. This geometry implies a top-down formation mechanism. Their diameters and relief range from is 600 m–3300 m, and 100 m–740 m, respectively, with a modest scaling relationship between diameter and relief. Flank angles of bowls and cones range from 11⁰ to 41⁰, with a crudely normal distribution, with median and mean values of 26⁰. A model for the evolution of depletion zones in the study area is based on two previous models developed for single source layer plumbing systems and invokes mobilisation of the source layer by sediment collapse and shear-induced liquefaction following initial seal failure by hydraulic fracturing of the evaporite seal. This mechanism may be more widely applicable to mud volcano systems than currently appreciated.

Cyclostratigraphy and eccentricity tunning of the middle Miocene succession, Gulf of Suez, Egypt: Astronomical age dating and undetected hiatus

The middle Miocene Kareem Formation is a major hydrocarbon reservoir in the Gulf of Suez rift basin. The middle Miocene Kareem Formation is a major hydrocarbon reservoir in the Gulf of Suez rift basin. The age of this formation has remained controversial due to the lack of clear marker species and the presence of barren intervals in evaporite seals or sand reservoirs. Furthermore, until now, the absolute age and duration of a well-known recognized hiatus (T40) in this formation has not been estimated. Here, we establish the precise age and extent of the Kareem Formation based on the integration of foraminifer and calcareous nannofossil biostratigraphy, with the establishment of an astronomically tuned timescale (ATS) based on gamma-ray variations of two wells, Gs197-2 in the October Basin and J58-81 in the July Basin. These two wells represent the most complete cored sequence of the Middle Miocene Kareem Formation, recording six calcareous nannofossil, four planktonic, and one benthic foraminiferal biohorizons, that enable us to define the Langhian-Serravalian boundary. According to our new biostratigraphically-supported ATS, we estimate that the Kareem Formation spans from 13.25 to 15 Ma. The T40 hiatus is identified in both wells at the boundary between the Shagar and Rahmi Members, with an estimated duration of ca. 0.26 Myr and 0.18 Myr for Gs197-2 and J58-81, respectively. A pronounced obliquity imprint is recorded in the upper Langhian to Serravalian of Gs197-2 well, right above the T40 hiatus.

Chapter 7 Exploration implications

Abstract Exploration of the Jurassic hydrocarbon system in the Arabian Intrashelf Basin area is in a mature state. Given the scale of the present day anticlinal structures and the adjacent synclines, all of the supergiant conventional fields trapped in huge anticlines have already been discovered. The theme throughout this Memoir has been to present the evolution of the self-contained Callovian–Tithonian Arabian Intrashelf Basin hydrocarbon system. Its size, c. 1200 × 450 km, is greater than that of the UK, larger than the Black Sea and almost as large as Turkey or the area of Texas and New Mexico in the USA. It is geologically much simpler than these regions, both in the exceptionally remarkable continuity of facies within the sequences that developed and filled the intrashelf basin and its relative tectonic simplicity, including up to the present day. The cross-sections, facies maps, depositional profiles and other data and interpretations presented in this Memoir have documented this remarkable continuity. The source rock interval is well-defined everywhere it occurs and is mature; enough oil has been generated and migrated so that every sealed trap with reservoir facies will have oil. Around and within the basin, shallow water ramp facies in each sequence are in the reservoir facies and the early-formed porosity has been preserved. The carbonate seals and, even more so, the evaporite seals are remarkably laterally continuous. Therefore the big issue in future exploration is finding a sealed trap with potential reserves large enough to be worth drilling when compared to known reserves and estimates of future production. This chapter discusses some possibilities for stratigraphic traps and unconventional plays. Potential plays have been and/or can be identified, but finding them in the present day structural setting is likely to be very difficult.

A Paleozoic-sourced oil play in the Jura Mountains of France and Switzerland

Abstract The Jura region of France and Switzerland has significant hydrocarbon potential. This arcuate fold-and-thrust belt, located in front of the Western Alps, is composed of Mesozoic rocks, which overlie the North Swiss Basin Complex filled with Permo-Carboniferous sediments of Late Westphalian–Lower Permian (Autunian) age. The existence of three small producing gas fields, and the presence of recorded oil and gas shows in a number of petroleum wells, indicate the presence of an active petroleum system. Shows occur in stratigraphic horizons that lie beneath the regional Triassic evaporite seal. Very effective Permo-Carboniferous oil-prone source rocks include algal organically rich Autunian shale beds and Stephanian-aged bituminous shales. Carboniferous and Permian coals are also present, which would be excellent sources of gas. The primary reservoir target is the fluviatile Triassic Bunter Sandstone Formation, which is widely developed across the area and thickens to the NE. Reservoir quality is best developed in the cleaner channel sands. The La Chandelière oil field, discovered in 1989 by Exxon, is crucial evidence of the oil potential and trapping mechanism. Geochemical analysis demonstrates that the 41° API oil at La Chandelière is derived from Lower Permian Autunian shales. The trapping mechanism, interpreted from seismic and confirmed by structural modelling, is that of an unreactivated Mesozoic-aged structural high bounded by thrust faults, resulting in a large-scale rollover within the core of the structure. This combination of critical elements sets up the Paleozoic-sourced oil play within the Jura Mountains of France and Switzerland. The Jura is not generally regarded as a major petroleum province. It is a region of complex structuring and mountainous terrain. Switzerland, a country renowned for its beautiful mountain scenery, has no major oil and gas discoveries. However, this poorly explored region has active petroleum systems with good hydrocarbon shows and a number of small gas fields demonstrating hydrocarbon generation. Good-quality source rocks and excellent reservoir development have been proven by drilling, and seismic interpretation has demonstrated the existence of large closures at reservoir level. The La Chandelière oil discovery, in the French Jura, proves the presence of a Paleozoic-sourced oil play.

A facies and palaeogeography-based approach for analysis of petroleum systems in United Arab Emirates

The United Arab Emirates (UAE) is the 8th largest oil producing country and is rich in oil and gas resources. By the end of 2015, 68 oil and 23 gas fields had been discovered. The initial proved and probable (2P) oil, gas and condensate reserves amount to 81,135.9 MMb (million barrels), 192.09 Tcf (trillion cubic feet), and 6496.58 MMb respectively, which are mostly reservoired in the Jurassic and Cretaceous carbonates. With the latest field data, this study attempts to document the salient features of petroleum systems in UAE. Based on depositional facies of source rock intervals, pods of source rocks were delineated. On the basis of an oil- and gas-source correlation, five known petroleum systems were identified and they are Lower Silurian−Upper Permian Khuff gas, northeast foreland Upper Jurassic−Lower Cretaceous gas, Upper Jurassic–Jurassic petroleum, Upper Jurassic/Lower Cretaceous−Lower Cretaceous composite petroleum, and Middle Cretaceous−Middle to Upper Cretaceous/Cenozoic petroleum systems. Of them, the Upper Jurassic/Lower Cretaceous−Lower Cretaceous composite petroleum system contains 73.2% of the total 2P reserves and thus it is the focus of this study. The Upper Jurassic and Lower Cretaceous source rocks consist of argillaceous limestone, mudstone and shale, which were deposited as intrashelf basin facies. The distribution of oil and gas in this system is controlled by the source kitchens and the regional evaporite seal.

Stratigraphy, structure and petroleum exploration play types of the Rioni Basin, Georgia

Abstract The Rioni Basin is an underexplored petroliferous basin located at the Georgian margin of the Black Sea flanked by two folded belts (the Greater Caucasus and the Achara–Trialet Belt). Whereas the stratigraphy of the northern onshore Rioni Basin has elements which are common with that of the offshore Shatsky Ridge, the southern onshore Rioni Basin segment is both stratigraphically and structurally akin to the offshore Gurian folded belt in the eastern Black Sea. In the northern basin segment, the existing oil fields (East and West Chaladidi) and an undeveloped oil discovery (Okumi) are related to either post-salt or pre-salt antiformal traps in detachment folds or in poorly understood stratigraphic pinchouts beneath a regional Upper Jurassic evaporite sequence. In the southern Rioni Basin, the oil in existing fields has either anticlinal four-way closures (Supsa) or a subthrust trap (Shromisubani) related to the leading edge of the north-vergent Achara–Trialet folded belt. Despite the long history of petroleum exploration in the Rioni Basin, these proven plays are not fully understood and systematically explored using modern technology. The existence of an Upper Jurassic regional evaporite seal highlights the possibility of pre-salt plays in the northern part of the basin.

Micropalaeontology and sedimentology of an inter-evaporite Arab-C carbonate exposure, Riyadh, Saudi Arabia

Alternating carbonate and evaporite successions of strata characterise the Late Jurassic, Kimmeridgian–Tithonian, Arab Formation of Saudi Arabia. Outcrops of the Arab Formation are poorly exposed and are mostly studied from subsurface samples, due to dissolution of the evaporites and the collapse of intervening carbonate strata. The type section for this formation is in the subsurface, where a more complete succession is available for study where four carbonate and evaporite members, namely D, C, B and A in ascending stratigraphic order, have been identified. The Arab has important hydrocarbon associations, due to its excellent porosity, permeability and proximity to underlying source rocks and overlying evaporite seals. This study provides new insights into the internal palaeo environment and depositional cyclicity of the Arab C, with implications to improve understanding of microfacies and porosity variations of the reservoir equivalent. The studied section provides a rare datapoint for the proximal palaeoenvironment of the Arab C carbonates that are mostly studied in the subsurface far to the east. Arab Formation carbonates are exposed along road cuts in the city of Riyadh. One recent exposure, 27 ft (8.2 m) thick, provides new micropalaeontological, sedimentological and palaeoenvironmental information for this stratigraphic unit that is otherwise elusive as an exposure. The new section is located next to the flanks of a sinkhole within gently folded strata and implies that the exposure must represent one of the supra-Arab D evaporite members, for which regional mapping indicates assignment to the C member of the Arab Formation. The Arab C consists of a succession of low diversity microfossiliferous wackestones and packstones, in which the red alga Permocalculus cf. iranae and rhaxellid sponge spicules are well represented. The exposure extends the stratigraphic range of Bramkampella arabica from the Sulaiy Formation down section into the older Arab C. Arab C microfacies are interpreted to represent deposition in a normal marine salinity, carbonate platform setting, probably within a shelf lagoon, mostly below fair-weather wavebase and within storm wavebase. Within the succession is a distinctive grainstone bed containing the benthonic foraminifera Everticyclammina kelleri, Kurnubia jurassica, Nautiloculina oolithica, Pseudocyclammina lituus and Redmondoides lugeoni and is considered to represent the top of one high frequency sequence (HFS). Immediately above the grainstone additional strata in the measured section form the base of a second HFS.

Detailed 3-D depositional architecture of Late Jurassic carbonate–anhydrite cycles (Brightling Mine, Weald Basin, UK)

Quantifying the geometries of evaporite deposits at a <1 km scale is critical in our understanding of similar ancient depositional systems, but is challenging given evaporite mineral dissolution at surface conditions. A high-resolution stratigraphic study of the basal Purbeck Beds in Brightling Mine, UK, provides insight into the three-dimensional architecture, lateral continuity and vertical heterogeneity within an evaporite seal. We conducted a field mapping study, combined with X-ray diffraction, petrographic microscopy, and δ13C and δ18O isotope analysis. The stratigraphic interval contains five facies. In stratigraphic order, these include supratidal porphyritic nodular evaporite, shallow subtidal peloidal packstone with evaporite and two overlying rhythmic sequences of intertidal microbial laminite, subtidal shale, and subtidal laminar marl, capped by nodular anhydrite. The interpreted environment of deposition is a supratidal sabkha subject to periodic flooding in which intertidal (tidal flat) facies and subtidal (shallow marine) facies laterally passed into the evaporative sabkha. The cycles are interpreted as meter-scale shoaling-upward sequences, likely controlled by localized high-frequency changes in relative sea level and/or sabkha hydrology. Spatial patterns in the geometries of key stratigraphic surfaces reveal a subtle depression towards the central western region of the mine seam. The variation in stratal geometries is interpreted as paleotopography and is a function of individual or composite processes related to dissolution, eolian processes, and coastal erosion. These observations indicate a similar mode of deposition to the modern-day sabkha of the Persian Gulf. We conclude that the dynamic process of evaporite deposition led to subtle stratigraphic heterogeneities and changes in bed thicknesses, but largely continuous lateral bedding at an interwell-scale.

About this title ‐ Geology and Hydrocarbon Potential of Neoproterozoic–Cambrian Basins in Asia

This volume provides a comprehensive overview of the geology and hydrocarbon potential of the major Neoproterozoic–Cambrian basins of Asia from Oman, across the Middle East and the Indian Subcontinent, to China and SE Siberia, along with new research on the region. Many of these areas (e.g., Oman, Bikaner–Nagaur Basin in India, South China and SE Siberia) host prolific Neoproterozoic–Cambrian petroleum systems with giant to supergiant fields. Three key elements: (1) tectonic stability, (2) relatively late phase of hydrocarbon generation and (3) presence of an effective evaporite seal, seem to be critical for the development of effective Neoproterozoic–Cambrian petroleum systems. These key elements appear of less consequence for the development of ‘unconventional’ hydrocarbons, and the future prospectivity in many of these basins may lie in the exploration for, and production of, shale gas and shale oil directly from the thermally mature, organic-rich source rocks.

1D PetroMod software modeling of the Basrah oil fields, Southern Iraq

1D (Petromod) hydrocarbon charge modeling and source rock characterization of the Lower Cretaceous and Upper Jurassic underlying the prolific Cretaceous and Tertiary reservoirs in the Basra oilfields in southern Iraq. The study is based on well data of the Majnoon, West Qurna, Nahr Umr, Zubair, and Rumaila oil fields. Burial histories indicate complete maturation of Upper Jurassic source rocks during the Late Cretaceous to Paleogene followed by very recent (Neogene) maturation of the Low/Mid Cretaceous succession from early to mid-oil window conditions, consistent with the regional Iraq study of Pitman et al. (Geo Arab 9(4):41–72, 2004). These two main phases of hydrocarbon generation are synchronous with the main tectonic events and trap formation associated with Late Cretaceous closure of the neo-Tethys; the onset of continent–continent collision associated with the Zagros orogeny and Neogene opening of the Gulf of Suez/Red Sea. Palynofacies of the Lower Cretaceous Sulaiy and Lower Yamama Formations and of the Upper Jurassic Najmah/Naokelekan confirm their source rock potential, supported by pyrolysis data. To what extent the Upper Jurassic source rocks contributed to charge of the overlying Cretaceous reservoirs remains uncertain because of the Upper Jurassic Gotnia evaporite seal in between. The younger Cretaceous rocks do not contain source rocks nor were they buried deep enough for significant hydrocarbon generation.

Paleozoic composite petroleum system of North Africa: hydrocarbon distribution and main controlling factors

North Africa, which is one of the main oil and gas producing regions in the world, is best known for its sub-salt Paleozoic-Triassic reservoirs and Paleozoic source rocks. Hydrocarbon abundance varies greatly from one structural domain to another areally and from one stratigraphic interval to another vertically. Analyses of the essential elements and geological processes of the Paleozoic petroleum system indicate that the distribution of the Lower Silurian shale source rocks, the development of a thick Mesozoic overburden, the presence of the Upper Triassic-Lower Jurassic evaporite seal are the most important factors governing the distribution of the Paleozoic-sourced hydrocarbons in North Africa. The Mesozoic sequence plays a critical role for hydrocarbons to accumulate by enabling the maturation of the Paleozoic source rocks during the Mesozoic-Paleogene times and preserving the accumulated hydrocarbons. Basins and surrounding uplifts, particularly the latter, with a thick Mesozoic sequence and a regional evaporite seal generally have abundant hydrocarbons. Basins where only a thin Mesozoic overburden was developed tend to have a very poor to moderate hydrocarbon prospectivity.

Gas breakthrough pressure for hydrocarbon reservoir seal rocks: implications for the security of long‐term CO2 storage in the Weyburn field

AbstractThis paper reports a laboratory study of the gas breakthrough pressure for different gas/liquid systems in the Mississippian‐age Midale Evaporite. This low‐permeability rock formation is the seal rock for the Weyburn Field in southeastern Saskatchewan, Canada, where CO2 is being injected into an oil reservoir for enhanced recovery and CO2 storage. A technique for experimentally determining CO2 breakthrough pressure at reservoir conditions is presented. Breakthrough pressures for N2, CO2 and CH4 were measured with the selected seal‐rock samples. The maximum breakthrough pressure is over 30 MPa for N2 and approximately 21 MPa for CO2. The experimental results demonstrate that the Weyburn Midale Evaporite seal rock is of high sealing quality. Therefore, the Weyburn reservoir and Midale Beds can be used as a CO2 storage site after abandonment. The measured results also show that the breakthrough pressure of a seal rock for a gas is nearly proportional to the interfacial tension of the gas/brine system. The breakthrough pressure of a CO2/brine system is significantly reduced compared with that of a CH4/brine system because of the much lower interfacial tension of the former. This implies that a seal rock that seals the original gas in a gas reservoir or an oil reservoir with a gas cap may not be tight enough to seal the injected CO2 if the pressure during or after CO2 injection is the same or higher than the original reservoir pressure. Therefore, reevaluation of the breakthrough pressure of seal rocks for a given reservoir is necessary and of highest priority once it is chosen as a CO2 storage site.

Subsalt (pre-Jurassic) exploration play in the northern Lusitanian basin of Portugal

Petroleum potential of the Triassic synrift Silves Formation of the Lusitanian basin, Portugal, was long considered poor because of the perceived overmaturity of prerift Paleozoic source rocks involved in Hercynian deformation. Field sampling of Silurian graptolitic, black shales along the eastern margin of the Lusitanian basin has revealed equivalent Ro maturity levels as low as 1.04% (late oil window), however, indicating that locally, the Silurian had significant generative potential (primarily gas) in post-Hercynian time. Current data do not permit realistic modeling of the first phase of petroleum generation from the Silurian. A second phase of hydrocarbon generation was initiated by reburial during the Mesozoic development of the Lusitanian basin. Oil extracts from transitional dolomite reservoirs at the base of the evaporite seal overlying the Silves Formation have been correlated with a lower Paleozoic source rock based on biomarker analysis. Hence, a subsalt petroleum system (Silurian source, Triassic reservoir, Jurassic seal) has been documented. A depositional model has been constructed to predict fairways for optimal synrift reservoir sand development that can be used to high-grade structural traps defined by seismic data. Traps (fault blocks and wrench-related folds) in place by the Early Cretaceous should have received gas charge from Silurian source rocks that entered the gas window in the Late Jurassic. Additionally, Tertiary regional inversion south of the Nazar wrench zone may locally juxtapose presently mature Lias source rocks against potential Silves reservoirs in trap geometries along the wrench.

THE HYDROCARBON POTENTIAL OF LEBANON: NEW INSIGHTS FROM REGIONAL CORRELATIONS AND STUDIES OF JURASSIC DOLOMITIZATION

This paper presents an updated review of the petroleum prospects of Lebanon. We briefly describe the known hydrocarbon shows in Lebanon and compare them with adjacent countries, leading to the construction of a model for hydrocarbon migration which takes into account regional facies and reservoir correlations.The oldest exposed rocks in Lebanon are the Jurassic carbonates of the Kesrouane Formation (over 1,000m thick). This formation can be divided into a basal unit dominated by seepage‐reflux stratabound dolostones (the Chouane Member,) and an overlying limestone‐prone unit (the Nahr Ibrahim Member). A two‐stage dolomitisation model for the Jurassic carbonates in Lebanon has recently been proposed by the authors. According to this model, second‐stage Late Jurassic hydrothermal dolomitisation is believed to have occurred as a result of the circulation of mixed dolomitising fluids along faults. Hence, the resulting dolostones are fault‐controlled and strata‐discordant, and may occur at any level within the Kesrouane Formation, locally redolomitising the Chouane Member dolostones and replacing the Nahr Ibrahim Member limestones. In this paper, we discuss the implications of diagenesis (especially dolomitisation) on the petroleum prospects of the Kesrouane Formation in Lebanon. The hydrothermal fault‐related dolostones possess porosities of up to 20%, which result from intercrystalline and mouldic porosity enhancement. Porosities in the stratabound reflux dolostones (Early Jurassic) and limestones are much lower.The fact that most of the Jurassic system in onshore Lebanon was affected by meteoric diagenesis during the Late Jurassic ‐ Early Cretaceous and the Cenozoic may downgrade hydrocarbon prospectivity. However, offshore areas far from the meteoric realm may have been less (or not at all) affected by meteoric invasion. If effective seals are present there, these areas may host promising Jurassic reservoir units.We also review the prospectivity of unexposed Triassic potential reservoir units in onshore Lebanon (e. g. the “Qartaba” structure). By analogy with the Syrian portion of the Palmyride Basin, Triassic strata here may include both reservoir units and evaporite seals.

Dolomite: occurrence, evolution and economically important associations

Dolomite is not a simple mineral; it can form as a primary precipitate, a diagenetic replacement, or as a hydrothermal/metamorphic phase, all that it requires is permeability, a mechanism that facilitates fluid flow, and a sufficient supply of magnesium. Dolomite can form in lakes, on or beneath the shallow seafloor, in zones of brine reflux, and in early to late burial settings. It may form from seawater, from continental waters, from the mixing of basinal brines, the mixing of hypersaline brine with seawater, or the mixing of seawater with meteoric water, or via the cooling of basinal brines. Bacterial metabolism may aid the process of precipitation in settings where sulfate-reducing species flourish and microbial action may control primary precipitation in some hypersaline anoxic lake settings. Dolomite is a metastable mineral, early formed crystals can be replaced by later more stable phases with such replacements repeated a number of times during burial and metamorphism. Each new phase is formed by the partial or complete dissolution of an earlier dolomite. This continual re-equilibration during burial detracts from the ability of trace elements to indicate depositional conditions and resets the oxygen isotope signature of the dolomite at progressively higher temperatures. Because subsurface dolomite evolves via dissolution and reprecipitation, a bed of dolomite can retain or create porosity and permeability to much greater burial depths and into higher temperature realms than a limestone counterpart. Dolomitization also creates new crystals, with new rhomb growth following the dissolution of less stable precursors. Repetition of this process, without complete pore cementation, can generate intercrystalline porosity a number of times in the rock's burial history. Intercrystalline porosity is a highly interconnected style of porosity that gives dolomite reservoirs their good fluid storage capacity and efficient drainage. The fact that many dolomite reservoirs formed via brine reflux means that they sit beneath an evaporite seal in both platform and basinwide evaporite settings. The same association of evaporites (sulfate source) and entrained hydrocarbons means that burial conditions are also suitable for thermochemical sulfate reduction and the precipitation of base metals. This tends to occur at higher temperatures (>60°C–80°C) and so the resulting dolomites tend to be ferroan and consist of saddle-shaped crystals.

Palaeozoic petroleum systems of North Africa

Abstract The Palaeozoic petroleum systems of North Africa contain five large giant (&gt; 1 billion barrels of oil equivalent) and 24 giant (&gt; 250 million barrels of oil equivalent) oil and gas fields with total recoverable reserves discovered to date of more than 46 billion barrels of oil equivalent. This article presents a classification of these petroleum systems based upon their productivity and maturity. Productivity of each system has been estimated from the associated hydrocarbon reserves and maturity from an analysis of their geological history ranging from initial genesis to maturity, destruction and final extinction. Key factors controlling both productivity and maturity include hydrocarbon charge, style of drainage and entrapment, and intensity of post-entrapment tectonic, thermal and hydrodynamic destructive processes. The regionally extensive Lower Silurian Tanezzuft Formation is the origin of 80–90% of Palaeozoic sourced hydrocarbons, with a further 10% from the Upper Devonian Frasnian shales, charging a number of intra-Palaeozoic and basal Triassic reservoirs. Triassic fluvial sands are the most important of these, hosting just over half of the total reserves, while Cambro-Ordovician and Lower Devonian F6 sandstone reservoirs are the second and third most significant, respectively. Three categories of Palaeozoic petroleum systems have been identified: (1) Mesozoic to early Tertiary charged systems with Triassic-Liassic shale and evaporite seals in the Mesozoic sag or ‘Triassic’ Basin of the northern Sahara Platform. These include &gt; 78% of the total discovered reserves, with &gt; 56% in the supergiants, Hassi R’Mel and Hassi Messaoud fields (2) Mesozoic to early Tertiary charged systems with intra-Palaeozoic shale seals in basins of south and east of the Triassic Basin. These include &gt; 18% of the total discovered reserves, mostly in the prolific Illizi Basin. (3) Now largely extinct Palaeozoic charged systems with intra-Palaeozoic seals in basins of southwest Algeria and Morocco with 3% of discovered reserves. The productivity of these systems varies considerably. Hassi R’Mel and Hassi Messaoud are classified as super-productive, located on the crests of broad Palaeozoic arches which encouraged extremely efficient lateral migration focusing, and a very high impedance entrapment style. Other petroleum systems within the Triassic Basin are of high productivity with somewhat less effective migration focusing and impedance characteristics. Because of a regional evaporite seal and minimal late stage modification, these systems are all preserved in a mature phase of evolution. Basins south and east of the Triassic Basin are in various stages of destruction with variable productivities reflecting both less robust seals and post-entrapment modification by Austrian and mid-Tertiary uplift, tilting, remigration, spillage and freshwater flushing. The Illizi Basin is the least affected by these late stage destructive processes with some 15% of total discovered reserves still remaining. The Palaeozoic charged systems of southwest Algeria and Morocco were largely destroyed by Hercynian, Austrian and mid-Tertiary deformation. Only the high relief Hercynian anticlines of the Ahnet-Gourara Basin retained their trapping integrity and still reservoir a very significant amount of gas. Apart from scattered hydrocarbon shows and a few small residual accumulations the other basins in this region now all appear to be extinct.

Excess helium and argon of radiogenic origin in Mediterranean brine basins

Extraordinary helium and argon signatures were observed in a recently discovered brine lake district in the eastern Mediterranean Sea at water depths of ∼ 3500 m. In the Urania Basin 4He concentrations are enriched by a factor of up to 32000 compared to normal seawater. Low 3He/ 4He ratios of 1 × 10 −7 and high 40Ar/ 36Ar ratios of up to 470 indicate a radiogenic source. These data represent by far the highest radiogenic supersaturations ever observed in an oceanic environment. We propose a new conceptional model assuming that the Urania Basin is fed by advective transport from a deep fluid reservoir below the Messinian evaporite sequence. The evaporite seal provides the unique condition for accumulating the extraordinary high amounts of radiogenic helium from deep sedimentary strata. Injection of radiogenic helium from brine pools like the Urania Basin may contribute significantly to the inventory of terrigenic helium in the deep waters of the eastern Mediterranean.

PREHISTORIC, ANCIENT AND MEDIAEVAL OCCURRENCES AND USES OF HYDROCARBONS IN THE GREATER MIDDLE EAST REGION

THE ARABIAN PLATE, and neighbouring parts of Egypt, Turkey, Iran and the southern Caucasus, includes within its boundaries numerous active hydrocarbon seepages. Their origin is related to the beginning of the current tectonic regime, which commenced in Oligocene‐Miocene times. The culmination of Alpine tectonics around the northern edge of this region gave rise to stress regimes that deformed the plate margins and ruptured the integrity of hydrocarbon traps and seals. This resulted in the many seepages recorded throughout the Arabian Plate and adjoining areas to the north.Extensional plate margins bound the Arabian Plate to the SW and south; transform margins are on the west and SE; and collisional margins on the north and NE. It is along these (or along splays from them) that most of the major active seepages occur.The collisional regimes along the Taurus and Zagros foldbelts in the north and NE caused considerable subsurface movement of Cretaceous and older hydrocarbons and their migration and remigration. As folding intensified, inefficient seals were ruptured, and very large volumes of hydrocarbons migrated vertically upwards until trapped close to the surface in vast carbonate reservoirs beneath the regionally‐efficient evaporite seals provided by the Miocene Lower Fars/Gachsaran Formations. Where these seals were thin, poorly‐developed or eroded, major seepages developed, and huge volumes of hydrocarbons may have escaped to the surface. Indeed, there is speculation whether the Zagros foreland basin, overprinted onto the vast NE Arabian Shelf as a result of the Arabian/Eurasian Alpine collision, has not lost more hydrocarbons than it has retained through this process (Beydoun et al., 1992).

Factors controlling the destruction or preservation of giant light oilfields

Study of a database of 350 giant oilfields show these to be dynamic short-lived phenomena, with a median age of 35 Ma. A third show evidence for post-entrapment destructive processes, particularly erosion, fault leakage, gas flushing and biodegradation. Many cases of biodegradation may occur prior to complete filling of the oilfield. Re-entrapment of oil released from spilling or breached traps is common. The main controls on oilfield preservation are post-entrapment tectonism and seal type, with temperature and hydrodynamic regimes being secondary factors. Destructive processes are concentrated in shallow and deep zones and in seepage-prone traps such as compressional anticlines. Such factors strongly influence the distribution of preserved light oilfields, with preservation potential maximized in tectonically quiescent basins with evaporite seals, e.g. the Middle East and the Permian Basin. More attention is required, particularly in older petroleum systems, to models involving post-entrapment leakage and re-migration.

HYDROCARBONS HABITAT IN A TRIASSIC‐TO‐CRETACEOUS SUB‐ANDEAN SETTING: NEUQUÉN BASIN, ARGENTINA

The Triassic‐Cretaceous Neuquén Basin of west‐central Argentina covers an area of nearly 200,000 sq. km, encompassing the edge of the Andean Cordillera and the adjacent South American foreland. A seven‐km thick sedimentary succession has been developed after three main geotectonic stages: (1) Basin onset and fault‐induced subsidence after Triassic—Early Jurassic extensional collapse of a Late Paleozoic marginal orogenic belt; (2) Middle Jurassic—Paleogene regional subsidence behind a retreating subduction system; (3) Neogene contractional deformation and local load subsidence forced by advancing subduction conditions.Throughout the Jurassic and Cretaceous periods, depositional patterns were related to waxing and waning of a narrow seaway that was connected to the Pacific realm through gaps in the magmatic arc. Widespread anoxia and Type II organic matter preservation occurred in the context of peak transgressions during the Toarcian, Oxfordian, Tithonian, late Valanginian and Hauterivian. A protracted history of regular subsidence and moderate heat flow at a back‐arc position, together with the presence of widespread evaporite seals, has resulted in regional zonation of the hydrocarbon occurrences. The inverted Cordilleran province became largely overmature; an intermediate gas‐condensate to light‐oil belt developed after local drainage from mature source rocks; and a basin fringe belt, that includes mixed and partially‐degraded oil, was charged after lateral migration 20–50 km updip from effective source units.Reservoirs are provided by Jurassic‐Cretaceous marine‐to‐deltaic and fluvial‐to‐aeolian deposits, and ooidal or skeletal limestones and dolostones. A diverse trapping style includes drapes over basement blocks, variably inverted half‐graben features, detached and wrench‐related anticlines, and closures linked to the intrusion of Tertiary magmatic rocks. Perhaps as much as 50% of the discovered reserves lie in fields with a significant‐to‐dominant stratigraphic component. Exploration activity since the beginning of the century established the presence of recoverable reserves of about 2 B brls of oil and 15 T cu. ft of gas.