bluuebunny/crossref_metadata_2025_split huggingface dataset:
EVIDENCE OF PERMO‐CARBONIFEROS GLACIATION IN THE BASAL MURBAT SANDSTONE FORMATION, SOUTHERN REGION, SULTANATE OF OMAN
Authors: Qidwai H.A. , Khalifa M.I. , Ba‐mkhalif Khalid A. 
Published: December 2007

The most massive basal diamictite of the Murbat Sandstone Formation exhibits many sedimentary features which indicate its subglacial deposition. Some of the most important features are: (1)straited and grooved sandstone slivers within the diamictete;(2)striated and faceted clasts; (3)small stratified sandstone lenses within the diamictite; (4)“dropstones” or “out‐of‐size clasts” in the shale; and (5) the large lateraal and vertical extent of the diamictite.The overlying sequence of the Murbat Sandstone Formation consits of an alternating succession of conglaomerate and sandstone followed by silstone and shale, whose sedimentary structures, however, suggest their deposition in deeper‐water basins.The Murbat Sandstone Formation has been assigned to various ages ranging from Infra‐Cambrian to Ordovician by different workers, in view of its isolated occurence and the absence of flora and fauna. The Metal Mining Agency of Japan, however, has dated the Murbat Sandstone Formation as Permo‐Carboniferous, as it uncomfomably overlies Lower Carboniferous dikes of the crystalline Basement. The dikes have been dated by the K‐Ar method.
LATE CENOZOIC THERMAL GRADIENTS IN DEAD SEA TRANSFORM SYSTEM BASINS
Authors: Bein Amos , Feinstein Shimon 
Published: December 2007

Coal‐rank measurements and heat‐flow data from three rhomb‐shaped grabens along the continental portion of the Dead Sea Transform—the Hula Depression, the Sea of Galilee and the Dead Sea Graben—reveal contrasting thermal regimes. The coalification profile the Hula Depression indicates a relatively high thermal gradient, averaging 40d̀C/km, throughout the Late Cenozoic. Similarly, a relatively high heat flow, approx 1.77 HFU, was reported in the Sea of Galilee, 35 km to the south. Coalfieation profile, heat flow data and BHT measurements on the Dead Sea Graben (200 km to the south) reveal a considerably lower thermal regime (approx 0.7 HFU, 2Od̀C/km) that has prevailed since the mid‐Miocene.However, the differences in the thermal regime do not represent different mechanisms of basin formation. With the corroboration of hydrological and geophysical data, it is suggested that the high thermal regime in the two northern basins reflects a regional phenomenon associated with the nearby extensive Golan‐Jeble Druze young volcanic terrain. Therefore, it has no relationship to the mechanism of rhomb‐shaped graben formation, and should not be cited in support of kinematic models requiring a high thermal regime.
THE CAMBRO‐ORDOVICIAN ARABIAN AND ADJOINING PLATES: A GLACIO‐EUSTATIC MODEL
Authors: Husseini M. I. 
Published: December 2007

After a phase of InfraCambrian and Early Cambrian intra‐continental extension and rifting, the Arabian and adjoining plates formed a part of the stable shelf in Gondwanaland from the Middle Cambrian through the Ordovician. The InfraCambrian‐Early Cambrian syn‐rift sedimentary sequences include organically‐rich source rocks and evaporites, while the Cambro‐Ordovician rocks include widespread sandstones which constitute a reservoir.The Ordovician‐Silurian boundary is characterized by glacial advances from Gandwanaland into western Arabia. The final glacial retreat in the Early Silurian was followed by a sharp transgression, which rapidly flooded the Arabian and adjoining plates and deposited organically‐rich transgressive shales. These are a major source rock in the Middle East and North Africa.
STRATIGRAPHY AND EVOLUTION OF THE TERTIARY ARUBA BASIN
Authors: Curet E.A. 
Published: December 2007

The Aruba Basin (offshore Venezuela) is asymmetric, with the basin axis aligned parallel to, and just to the south of the Aruba uplift. The sedimentary section consists mostly of clays and shales, deposited since the Oligence, or possibly late Eocene, on a Crataceous basement of oceanic affinity. This monotonous lithology makes it difficult to compile a useful stratigraphic subdivision, but three seismic‐stratigraphic units separated by unconformities have been distinguished, and are known as the Lower, Middle and Upper Sequences.Sedimentation began in abyssal‐to‐bathyal depths, after the rapid subsidence of a weathered, volcanic terrain; the rate of sedimentation exceeded that of subsidence, causing a gradual shallowing of the sea‐floor. The sedimentation rate during deposition of the Middle Sequence was sufficiently high to prevent normal compaction, thus causing a thick zone of abnormally high pressures. Deformation by faulting as well as folding was contemporaneous with sedimentaion and subsidence.The main source area for the sediments lies to the south; the Aruba High has acted prinicpally as a sediment trap. On the north flank of the basin, some (bio‐)clastic contribution from the island may be expected.The type of organic matter in sediments penetrated by the three wells off shore Aruba, as determined by pyrolysis, is mostly gas‐prone Type III kerogen. The TOC is fairly low—1% on average; but microscopic inspection revealed that a high percentage of the organic matter consists of amarphous kerogen. Due to the low geothermal gradient (1d̀ F/100 ft), this organic matter is immature. Another drawback for the development of petroleum accumulations if the limited areal distribution of carrier and reservoir rocks. These two factors seriously restrict the petroleum potential of the Aruba BasinHowever, there are indications from which the generation of petroleum can be deduced. In the deeper parts of the basin to the south of the island, sufficiently high temperatures may have been reached for Oligocene and older, sediments to be within the “oil window”; and the platform area in the SW may be underlain by older, more mature sediments. Further exploration on the north flank of the Aruba Basin and on the SW is considered to be justified, based on the inferred presence there of both source and reservoir rocks.
THE TECTONIC FRAMEWORK AND REGIONAL HYDROCARBON PROSPECTIVITY OF THE GULF OF ADEN
Authors: Bott W.F. , Smith B.A. , Oakes G. , Sikander A. H. , Ibraham A. I. 
Published: December 2007

The Gulf of Aden rifting predates that in the Red Sea. Isolated sub‐basins developed during the earliest Oligocene following a major emergent (erosional) period during the latest Eocene. Marine sedimentation began in the middle‐to‐late Oligocene and progressed upwards from marginal marine to bathyal environments with significant turbidite input (primarily on the Yemen side).Stretched and dike‐invaded continental crust exists in water depths greater than 1,000 m in some areas. Sea‐floor spreading began in the late Miocene and progressed westward into the Afar region. Only limited faulting has affected the post‐rift, uppermost Miocene to Recent section, which is primarily dominated by prograding sequences and thermal subsidence.With over 40,600 square kilometres of continental shelf in less than 300 m of water, the Gulf of Aden is a frontier exploration area. Only minimal exploration work has been carried out in the offshore, including twelve wells resulting in one sub‐commercial discovery and numerous indications of hydrocarbons. Thw wells drilled to‐date have encountered source, reservoir and seals in both the pre‐rift and syn‐rift section. Heat flow and thermal modelling has shown that the Gulf of Aden continental margins are not areas of excessive heat flow, and hydrocarbon generative “kitchens” can be mapped in the pre‐rift sequence.The hydrocarbon prospectivity of the Gulf of Aden differs from that in the Red Sea in that the primary hydrocarbon plays are found in the pre‐rift exploration plays exist in horst and rotated fault‐blocks within NW‐SE trending sub‐basins controlled by Upper Jurassic to Lower Cretaceous tensional tectonies. A combination structural‐stratigraphic trap has proved hydrocarbons beneath the pre‐Oligocene erosional unconformity.Syn‐rift exploration for clastic reservoirs sealed by anhydrites exists in early Oligocene transtensional sub‐basinse. The primary structure traps are rollover anticlines associated with listric growth faults. Source maturity is a significant risk for syn‐rift plays.
HYDROCARBONS HABITAT IN A TRIASSIC‐TO‐CRETACEOUS SUB‐ANDEAN SETTING: NEUQUÉN BASIN, ARGENTINA
Authors: Uliana M. A. , Legarreta L. 
Published: December 2007

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.
STRUCTURAL AND TECTONIC SYNTHESIS FOR THE PERTH BASIN, WESTERN AUSTRALIA
Authors: Harris L. B. 
Published: December 2007

The Perth Basin is localised by reactivation of Neoproterozoic shear zones on the western margin of the Archaean Yilgarn Craton in Western Australia. While Ordovician to Silurian sandstones were deposited in the northern Perth Basin, the earliest sediments elsewhere are Middle Carboniferous to Permian in age. A sinistral transtensional regime, during which the main architecture of the basin was established, developed during NE‐SW extension between Greater India and Western Australia in the Permo‐Triassic. NW‐SE shortening with continued NE‐SW extension resulted in sinistral transpression in the late‐Early to Middle Triassic. Sag‐phase sedimentation in the LateTriassic followed this oblique rifting event.An analogy may be made between the Perth Basin and the Permo‐Carboniferous to Jurassic Karoo basins in southern and central Africa and Madagascar. Deposition of the Karoo sequence took place within pull‐apart and transtensional basins resulting from sinistral reactivation of basement shear zones. The Indian Gondwana Supergroup, and an equivalent sequence in Antarctica, were deposited within normal fault‐bounded graben. The Late Paleozoic to Early Mesozoic formation of the Perth Basin, the Karoo basins of Africa and Madagascar, and the Gondwana basins of India was due to intraplate stress resulting from convergence along the Panthalassa margin of Gondwanaland. Late‐Early to Middle Triassic compressional events in all basins mark terminal collision along the Panthalassa margin.The latest Triassic to Early Jurassic marks a new rifting event due to regional east‐west to WNW‐ESE extension, producing dextralplus normal displacements on many NW‐to NNW‐striking structures, and essentially normal displacements on north‐ to NNE‐striking faults. NW‐SE extension during the Upper Jurassic culminated in the NW separation of Greater India and the formation of oceanic crust in the Neocomian, and resulted in the superposition of structures developed in a dextral transtensional regime. Conjugate strike‐slip faults and minor thrust faults formed during the post‐Neocomian, with approximately north‐south compression and east‐west extension. Precambrian gneisses, granitoids and metasediments of SW Western Australia have been deformed during basin development, and dole rite dyke intrusion during the Carboniferous to Middle Triassic is restricted to these terranes.The sequence of events proposed herein for the Perth Basin is in agreement with the tectonic framework of a large portion of Gondwanaland. A better knowledge of the structural history of the Perth Basin may aid the interpretation of seismic and remote‐sensing data in the search for further hydrocarbon occurrences.
ALBIAN CLASTICS IN THE WESTERN ARABIAN GULF REGION: A SEDIMENTOLOGICAL AND PETROLEUM‐GEOLOGICAL INTERPRETATION
Authors: Alsharhan A. S. 
Published: December 2007

Clastic sediments of Albian age are widely distributed throughout the Arabian Gulf, varying in thickness from less than 78 m to more than 390 m. The transition from sandstones in the northern part of the western Arabian Gulf (South Iraq, Kuwait and eastern Saudi Arabia) to shales in the SW and southern part (Qatar, United Arab Emirates and Oman) shows vertical and lateral variations. A complex nomenclature has been applied to different fades across the region, and the sediments may have several formation and member names (such as Nahr Umr and Burgan Formations, or Khafji and Safaniya Members).Clastic sediments of Albian age provide hydrocarbon source rocks, reservoirs and seals. Major reservoirs occur in sandstones to the north, and have a limited reservoir potential in offshore Qatar. Distal shales are a major seal in offshore Qatar, the United Arab Emirates and Oman. Local source‐rock potential exists in the northern part of the Arabian Gulf and in the extreme SE of Saudi Arabia (in the Rub Al Khali Basin).
DEPOSITIONAL MODELS AND RESERVOIR PROPERTIES OF MIOCENE REEFS, VISAYAN ISLANDS, PHILIPPINES
Authors: Carozzi A. V. 
Published: December 2007

Recent commercial discoveries offshore Palawan have propelled the Philippines into the list of oil‐ and gas‐producing countries, and have focussed on the importance of Miocene reefs as reservoirs. This new situation has motivated the update of earlier depositional‐diagenetic models for the Miocene reefs in the Visayan Islands, which is presented in this paper. These reefs consisted of an association of corals, red algae, bryozoans, and encrusting foraminifers, which formed wave‐resistant, constructed, barrier‐and‐atoll systems along the edge of narrow shelves, with associated back‐reef patch reefs and frontal pinnacle reefs. The latter also grew on structural and depositional highs and plaforms among deeper water carbonate mudstones and shales.Reservoirs developed in all the various types of buildups by extensive burial dissolution, often preceded (with the exception of some pinnacle reefs) by subaerial exposure generating secondary porosity by vadose to phreatic undersaturated dissolution. Seals were generally provided by overlying basinal carbonate mudstones and shales, and by andesitic volcaniclastics and basaltic lava flows. Source beds were mature, basinal, bituminous carbonate mudstones and shales, and migration of hydrocarbons was mainly updip, complicated by local structural conditions.
A PRACTICAL CLASSIFICATION OF KEROGENS RELATED TO HYDROCARBON GENERATION
Authors: Rahman M. , Kinghorn R.R.F. 
Published: December 2007

The present classification systems of kerogens have many shortcomings, especially in respect of amorphous kerogens which have, so far, remained undifferentiated in relation to hydrocarbon generation. Hence, a practical classification method based on density separation, elemental composition and optical characteristics, which discriminatingly identifies kerogens with indications of their hydrocarbon potential, has been developed.The method first divides the whole range of kerogens into liptinite and humic groups. The liptinitic kerogens are subdivided into Hyperliptinites (prolific oil sources); Mesoliptinites (which are oil‐prone); Metaliptinites (gas‐prone); and Hypoliptinites (having no potential for hydrocarbons). The humic kerogens are similarly divided into subgroups consisting of Hyperhumics (with some gas potential); Mesohumics (mainly gas sources); and Hypohumics (organic materials with no potential for hydrocarbon generation).
SUPERPOSED DEFORMATION IN THE NORTHERN SUEZ RIFT, EGYPT: RELEVANCE TO HYDROCARBONS EXPLORATION
Authors: Moustafa A.R. , Khalil M.H. 
Published: December 2007

Detailed subsurface studies of the northern part of the Suez Rift and adjacent areas indicate the superposition of two different episodes of deformation. During the earlier (Late Cretaceous) phase of deformation, folds with NE‐SW oriented axes were formed in northern Egypt as a result of convergence between Africa and Eurasia and the closure of the Neotethys. During the later (early Miocene) deformation., NW‐oriented normal faults were formed as a result of the opening of the Suez Rift.Borehole data have shown that a belt of NE en échelon folds with NE‐SW axes exists in the subsurface in the northernmost part of the rift, between Ayun Musa and the Sukhna‐1 well, soulth of Geble Ataqa. This fold belt represents the SW continuation of the en échelon folds exposed in the Mitla Pass, to the NE of the rift. Another pre‐rift structure is the offshore extension of the Wadi Araba structure as a SE‐facing monocline. This offshore structure also represents the continuation of the Geble Somar structure, on the eastern shoulder of the Suez Rift. The Geble Somar and Wadi Araba Structures represent the southernmost prerift folds in northern Egypt. Pre‐rift folds in the study area stood high above sea‐level during the Palaeocene and early Eocene. Upper Cretaceous and/or older rocks in the cores of these folds were later unconformably covered by middle Eocene rocks. The presence of Late Cretaceous folds should be taken into consideration when exploring for hydrocarbons in this part of the Suez Rift.Borehole data in NE Egypt also indicate the presence of Late Cretaceous folds underneath the almost flat‐laying Tertiary rocks in the northern part of the Eastern Desert. These folds are condidered to be potential hydrocarbon traps in this relatively poorly‐explored area.
OIL AND GAS POTENTIAL OF THE PRERIF FORELAND BASIN, ONSHORE NORTHERN MOROCCO
Authors: Pratsch J.‐C. 
Published: December 2007

The PreRif Basin in northern onshore Morocco may contain major oil and gas reserves. This foreland basin is located between the Tertiary‐Recent Rif Orogen to the north and the stable Moroccan Meseta to the south; for the purposes of this paper, it includes the Rharb Basin, an area of strong Neogene subsidence which extends offshore to the west.Prospective sandstone and carbonate reservoirs are present at a number of stratigraphic levels, ranging in age from Triassic and Jurassic to Miocene and Pliocene. Lower and Middle Jurassic shales and carbonates constitute potential source beds for “thermal” oil and gas; biogenic gas is generated within Miocene/Pliocene shales. Potential source beds are expected to have reached thermal maturity in the deepest portions of the present basinal area since the Late Miocene. Seals are provided by intraformational shales, transgressive shales of Tertiary age, Triassic evaporites, and by a thick, complex glidemass (or “olistostrome”) of late Miocene (Tortonian) age. Multiple traps can be expected; they will include anticlines, fault closures, salt‐tectonic features, and structural‐stratigraphic traps.Gravity‐defined low areas in the northern portion of the basin are probably the main generative depocentres. Lateral oil and gas migration has occurred on a regional scale since the Late Miocene, and has continued to the present day.A Jurassic Petroleum System includes the surface oil seeps and shut‐in oilfields of the Sidi Cacem area along the basin's southern flank. A Miocene Petroleum System supplies gas production in the Rharb Basin.The prospective area covers some 15,000 sq. km. Available reconnaissance data include published gravity, magnetic, seismic, and surface‐geological surveys. Modern airborne surveys of prospective areas should be followed by detailed exploration, including 3‐D seismic surveys.New recoverable field reserves may lie in the range of 50 to 150 million barrels oil‐equivalent per discovery; several new discoveries can be expected, leading to new total reserves possibly totalling 0.5 billion barrels oil‐equivalent.
GEOLOGY AND HYDROCARBON POTENTIAL OF DALMA ISLAND, OFFSHORE ABU DHABI
Authors: Salah M. G. 
Published: December 2007

There are eight diapiric islands in the United Arab Emirates sector of the Arabian Gulf: Dalma, Zirkouh, Qarnain, Das, Sir Bani Yas, Arzana, Sir Abu Nuwair and Abu Musa. The origin of these islands, and that of Jebel Dhanna (onshore Abu Dhabi), is related to the diapiric movement of Infra‐Cambrian to Cambrian salt. The islands' stratigraphy, surface geology, and tectonic framework are similar. Dalma Island was chosen for detailed study, and the following lithological units were identified at outcrop: (i) the Hormuz Complex (?Infra‐Cambrian to Lower Cambrian) of salt, anhydrite and dolomite with clastic intervals; (ii) the Lower Fars Equivalent (lower to middle Miocene) of interbedded clastics and carbonates; and (iii) mixed clastics and carbonates (Pliocene to Recent).Halokinesis of the Hormuz Salt has strongly influenced the formation of structural traps in a number of oilfields offshore Abu Dhabi. In areas adjacent to the diapiric islands, subtle traps, such as turtle structures, may be present, similar to those at the Hair Dalma and Dalma oilfields, near Dalma Island, and the Mandous oilfield, near Sir Abu Nuwair Island.
STRATIGRAPHIC AND LITHOLOGICAL CHARACTERISTICS OF UPPER CRETACEOUS CARBONATES IN CENTRAL IRAQ
Authors: Sadooni F. N. 
Published: December 2007

Shallow‐marine carbonates were deposited in Central Iraq during the Late Campanian‐Maastrichtian. These carbonates consist of foraminiferal‐ shoal and bryozoan‐algal‐rudist bank deposits, separated by argillaceous, oligosteginal wackestones and mudstones. The build‐ups are believed to have developed on block‐faulted topographic highs, while marly limestones were deposited in the intervening basinal lows. Based on facies analysis and log characteristics, these sediments are here divided into eight lithostratigraphic units.Recent exploration activities suggest that Upper Cretaceous carbonates represent a promising petroleum “play” in Central and West Iraq, areas in which oil has not previously been discovered. These carbonates differ from those in their type locality in southern Iraq, and in Central Iraq are assigned to the Hartha Formation.The shallow‐marine carbonates of the Hartha Formation have produced oil from a well in Western Iraq, and good oil shows were also indicated in the East Baghdad and Ahdab oilfields.