bluuebunny/crossref_metadata_2025_split huggingface dataset:
ORIGIN OF CRUDE OILS IN OMAN
Authors: Grantham P. J. , Lijmbach G. W. M. , Posthuma J. , Clarke M. W. Hughes , Willink R. J. 
Published: December 2007

The petroleum geochemistry of Oman provides a picture of considerable variey, since crude oils and their source rocks are found both throughout the country and throughout the stratigraphic column from the Infra‐Cambrian to the Tertiary. This paper reviews the geological history history of the area and places the petroleum geochemistry within the geological context.The oils can be geochemically classified into five groups. Three groups can be related to god oil source rocks found in the pre‐Cambrian Huqf Group, the Silurian Safiq and the Cretaceous Natin Formation. Another group of oils probably originates from the Upper Jurassic Diyab Formations, while the fifth group of crudes (named ‘Q’) cannot be correlated to a known source rock, but is inferred to have originated from an unsampled Huqf level.The “Huqf oils” are those that have been correlated to known Infra‐Cambrian Huaf source rocks, and are characterized by a strong C29 sterane predonominance and very light carbon isotope values of around‐36.0%. In contrast, the ‘Q’ crudes, drived from the unknown source are characterized by a C27 strerane predominance and carbon istope ratios of around ‐30.5%. Both the Huaf and ‘Q’ crudes also contain a series of characteristic compounds referred to as the ‘X’ compounds (all isomers of methyle and dimethyl alkanes). Oils reasoned to originate from Silurian Safiq source rocks have a week C29 sterane precominance, a significant content of rearranged steranes and carbon isotope ratios of ‐30.5%. The oils thought to originate from the Jurassic Diyab Formation have a similar sterane distribution but heavier carbon isotope values of around ‐26.5%. Finally, the crude oils from the mid‐Cretaceous Naith Formation source rocks are characteirzed by steranes with an equivalent distribution of C27, C28 and C29 isomers, and carbon isotope values of around ‐26.9%.These variations in biomarker distributions and carbon isotope values are sufficiently distinct to ensure a high degree of certainty in the grouping of the crude oils.
A REVIEW OF THE CTRETACEOUS FORMATIONS IN THE ARABIAN PENINSULA AND GULF: PARTII. MID‐CRETACEOUS (WASIA GROUP) STRATIGRAPHY AND PALEOGEOGRAPHY
Authors: Alsharhan A.S. , Nairn A.E.M. 
Published: December 2007

The stratigraphic sequence of the “Middle” Cretaceus Wasia Group in the Arabian Gulf, and the terminology used, is reviewed. Type sections and synonyms are established for the succession in the United Arab Emirates. An historical introduction provides a key to the understanding of the varied formational and member names in currnet use.Facies distribution maps show tha shallow‐water, predomantly carbonate belts extend across the whole region. Two clastic‐carbonate cycles are apparent in the NE part of the Gulf, the lower Nahr Umr‐Mauddud cycle and an upper Wara‐Mishrif cycle. The Upper cycle is surrounds a slightly deeper intracratonic basin which developed in late Albian‐Earllly Cenomanian time.
THE GEOLOGY OF THE NAFOORA OILFIELD, SIRTE BASIN, LIBYA
Authors: Belazi H. S. 
Published: December 2007

The Nafoora oilfield is situated on a major tectonic uplift in the eastern Sirte Basin, the Amal‐Nafoora High. Four oilfields have been discovered on this uplift – Amal, Rakb, Augila and Naffora.Drilling on this high encountered hydrocarbon entrapment in over a dozen distinct stratigraphic units. These reservoirs range in age from Pre‐Cambrian basement to Miocene sands. The most important reservoirs in the Nafoora field are the sandstones of the Amal (Cambro‐Ordovician) and Maragh (Upper Cretaceous) Formations. Reservoirs in the Upper Cretaceous, Palaeocene and Eocene carbonates are as important as those in the sandstones.
SOURCE‐ROCK GEOCHEMISTRY AND HYDROCARBON GENERATION IN THE JEANNE D'ARC BASIN, GRAND BANKS, OFFSHORE EASTERN CANADA
Authors: von der Dick H. , Meloche J. D. , Gunther P. 
Published: December 2007

A thick calcareous shale of Early/Middle Kimmeridgaiann age is the principal source rock for the oils discovered in the Jeanne d'Arc Basin of the Grand Bankks. This Upper Jurassic source rock forms a geological marker throughout the basin, but is not a stratigraphic marker. Its regional distribution is controlled by the tectonic and sedimentary history and the depositional enviornment.Rift tectonics in the Grand Banks during Oxfordian/Kimmeridgian times formed a series of silled, anoxic basins, which received low input of terrigenoous material from the adjacent continent. This favoured the accumulation of a thick sequence of calcareous shales rich in oil‐prone, amorphous organic matter. The principal source‐rock unit is generally 200‐300m (656–984 ft) thick in the southern and western part of the basin and thickens in the NE to more than 700m (2,296ft). Anoxic conditions were maintained in the NE area throughout the Late Kimmeridgian. While the SW area underwent uplift and was flooded by terrigenous clastics.Detailed geochemical analysis of oils and condensates discovered in many wells allows distinction of two principal oil families of different origins: one of Jurassic source, and the other of a probable Teritary origin. Most oils found in the basin belong to the Jurassic oil family.Distinct regional variations in the maturity and composition of the Jurasssic oil family are evident. These can be explained by the regional maturity pattern of the principal source rock, and by the co‐contribution of a secondary, slightly younger source‐rock interval, which contains a predominantly terrestrial type of organic matter. This secondary source input is recognized in areas where the younger source rock reaches fully‐mature conditions. Condensates in the centre of the basin are derived from the deeply‐buried source beds at present in late‐ to overmature conditions.The Adolphus oil in the centre of the basin represents the second oil family, and is probably derived from a Teritary source rock. No oil‐source correlation could be established due to lack of data and proper cutting samples. However, geological and heat‐flow considerations suggest a Teritary source. Heat‐flow values are high in the Adolphus structure as a result of salt diapirsm and the base of the Tertiary shale section is currently fully mature.
CHRONOSTRATIGRAPHY AND HYDROCARBON PROSPECTS OF THE SAKAKA FORMATION, NORTHERN ARABIA
Authors: Sharief F.A. , Moshrif M.A. 
Published: December 2007

The age of the so‐called Sakaka Sandstone exposed in the al‐Jawf area, northern Saudi Arabia, has in the past been disputed. It is assigned here to the Middle‐ Late Devonian and middle Cretaceous. This age has been established from correlations of surface ‐ subsurface sections utilising palynological and litholgical data, and also from the regional geological framework. The sequence is divided into two units. The lower unit, consisting of clastic and mixed fine‐clastic and calcareous shoreline‐ shallow marine deposits, is considered to be part of the Middle Cretaceous Wasia Formation.The name “Sakaka Formation” is now restricted to the lower unit of the Middle ‐ Upper Devonian sequence. This formation forms a well‐exposed and lithologically‐distinct mappable unit. The type section of the Formation can be designated from a traverse in the al‐ Jawf area, where a thickness of 215.5 m is exposed. The Sakaka Formation conforably overlies the Lower Devonian Jauf Formation, and uncomformably underlies the Middle Cretaceous Wasia Formation. At depth, in the subsurface, the sakaka Formation underlies conformably the Lower Carboniferous Berwath Formation.Reliable relative age‐dating of the sakaka Formation has contributed to investigations of both the history of the Hail Arch, and the economic prospects of the area. This Arch extends throughout the al‐Jawf area, and is probably of PreCambrian age: it was rejuvenated in pre Middle Devonian and pre‐middle Cretaceous times. The Arch separates the Widyan Basin to the east from the Tabuk Basin to the west. The former basin is promising in terms of petroleum exploration owing to its great possible thickness, and the presence of favourable lateral facies changes, and potential source and reservoir rocks; moreover, tectonic activity has resulted in the generation of many traps, including stratigraphic traps. The Sakaka Formation and the overlying Berwath Formation could serve as potential reservoir rocks, capped uncomfortably by fine, argillaceous rocks of the Upper Carboniferous ‐ Lower Permian Unayzah Formation.
RECENT ADVANCES IN THE PETROLEUM GEOLOGY OF CHINA
Authors: Desheng Li 
Published: December 2007

Since the People's Republic of China was founded in 1949, the area under petroleum exploration has continually expanded. The Chinese petroleum industry has developed rapidly. By 1988, crude oil production was 137 MM tons/year (2.74 MM b/d), and China was the world's fifth‐largest oil‐producing nation.The petroleum geology of China has recently advanced in the following five ways: (1) in the study of non‐marine facies hydrocarbon accumulations; (2) in the study of tectonic types of oil‐and gas‐bearing basins; (3) in facies studies of Meso‐Cenozoic lacustrine deposits; (4) in the theory and practice of composite megastructural oil and gas reserves in the Bohai Gulf Basin; and (5) in research on buried‐hill oil and gas traps. Future in‐depth petroleum‐geological studies and continuing intensive exploration activities will ensure that further oil and gas reserves will be located.
EXPERIMENTALLY‐SIMULATED STYLOLITIC POROSITY IN CARBONATE ROCKS
Authors: Bergen D.Von , Carozzi A.V. 
Published: December 2007

An experimental program of stylolitic porosity development in stylolitic Atokan (Middle Pennsylvanian) limestones under simulated conditions of deep burial has shown that experimental dissolution preferentially occured and developed along existing styloties. The dissolution sequence was as follows: incipient pores following the traces of stylolites, grading into stylolitic lamellar pores, which enlarged eventually into non‐fabric‐selective channels. These stylolite‐controlled conduits were surrounded by adjacent incipient‐to‐complete oomolds, enlarged oomolds, incipient‐to‐complete algal bioclast molds, enlarged biomolds, and halos of intercrystalline porosity to microporosity.Trace element analysis (Mg, Sr, and Ca) of pore‐fluid samples during early phases of experimental deep burial dissolution indicated that slightly less stable protions of carbonates enriched in Mg and Sr dissolved preferentially, as observed also in natural cases. Pyrolysis data indicate that stylolites concerntrated organic matter derived from inter‐stylolite areas. This situation demonstrates the pressure‐solution origin of stylolites.Experimental stylolitic pore networks are similar in type, size, and geometry to natural stylolitic porosity. This preferential dissolution suggests that natural stylolites result from late (post pressure‐solution dissolution, are not necessarily mechanically induced during stylolite formation as sometimes postulated, and act as effective conduits for secondary porosity generation in deeply‐buried carbonate rocks
THE MARDA FAULT: A REMNANT OF AN INCIPIENT ABORTED RIFT IN THE PALEO‐AFRICAN ARABIAN PLATE
Authors: Boccaletti M. , Getaneh A. , Bonavia F. F. 
Published: December 2007

The role played since the Early Jurassic by the Marda Fault Zone (MFZ) in the geodynamic evolution of the Horn of Africa is examined. Three main stages of evolution have been recognized: (a) a Tethyan stage (Jurassic/Early Cretaceous): (b) an Indian stage (Late Cretaceous/Eocene); and (c) an Arabian stage (Oligo‐Miocene/Resent). During the Tethyan stage (which is characterized by the distribution of fauna with a Tethyan affinity), the MFZ probably acted as a major deep‐ rooted transfer fault, connecting overstepping segments of en‐éhelon east‐west strike‐slip faults. Crustal stretching, caused by the southwards drift of Madagascar, was active in the SW region of the Horn of Africa. but was relatively negligible in the NE region. During the Indian stage (involving the NEwards drift of India), the MFZ was still aligned, in the Late Cretaceous, with the paleo‐margins of the Red Sea — bgore the rotation of Arabia away from Africa — and with the oceanic spreading ridges developed in the Mascarene Basin of the Indian Ocean. It was in this stage that the MFZ is interpreted as having acted as an incipient aborted rift, causing the rapid subsidence of the NE region of the Horn of Africa, and consequently the onset of a new depositional cycle. During the Arabian stage (separation of Arabia from Africa), there was a sudden change in the geodynamics of the Horn of Africa: crustal stretching of the Red Sea — Gulf of Aden —Ethiopian Rift Valley triple junction occurred, leaving the segment of the MFZ in the Horn of Africa inactive. These three stages correspond with three important tectonic changes in the Indian Ocean and the Western Mediterranean Region.
PETROLEUM POTENTIAL OF SOUTHERN HISPANIOLA
Authors: Mann P. , Lawrence S. R. 
Published: December 2007

The island of Hispaniola (Dominican Republic and Haiti) lies within the North Caribbean strike‐slip plate boundary zone. The post‐Eocene history of Hispaniola is marked by strike‐slip accretion of crustal fragments onto a Late Cretaceous‐Eocene island arc.Three onshore Neogene clastic basins have been the focus of petroleum exploration in Hispaniola. Oil production was achieved by drilling sugace anticlines in the Azua Basin in South‐Central Hispaniola (Dominican Republic) during World War II (Maleno and Higuerito fields). More modem seismic exploration has been carried out in the Enriquillo, San Juan and Cibao Basins, but has not resulted in production.Recent surface and seismic stratigraphic mapping has elucidated the geoiogic history of Southem Hispaniola. It consists of several Late Cretaceous‐Eocene oceanic and island‐arc terranes separated by E‐Wto NW/SE‐striking “ramp” or thrust‐bound clastic basins of Neogene age (San Juan, Azua and Enriquillo). Basin edges are marked by either basinward‐verging thrust or reverse faults, or strike‐slip faults. Basin centres are characterised by gentle folds at shallow depths and high‐angle faults and associated folds at greater depths. The easternmost area of the three ramp basins (Azua and eastern Enriquillo) has been overprinted by more intense shortening caused by local NE‐ward “indentation” of the Beata Ridge, an area of elevated Caribbean sea‐floor south of Hispaniola.The stratigraphy of Southem Hispaniola is characterised by two depositional phases. During the first phase, deep‐water pelagic sedimentary rocks of Eocene to Middle Miocene age accumulated on the leading‐edge of the intra‐oceanic Caribbean Plate. Following Early Miocene transpressional juxtaposition of the intra‐oceanic plate with the Cretaceous‐Eocene island‐arc core of the island. Late Miocene‐Early Pliocene clastic rocks derived from the island‐arc core filled the developing Azua‐San Juan ramp basin system. In the Plio‐Pleistocene, shallow‐marine/lagoonal sediments filled the Enriquillo Basin, while residual fluvio‐deltaic sedimentation continued in the Azua Basin.Oil‐prone source rocks are predicted in deep‐water carbonate rocks of the Sombrerito Formation (Early Miocene) and hemi‐pelagic mudstones of the Trinchera Formation (Middle to Late Miocene). Reservoirs occur in carbonates of the Sombrerito Formation and sandstones of the Trinchera and Arroyo Blanco Formations.Maturity modelling shows that hydrocarbon generation largely pre‐dates Plio‐Pleistocene folding and uplift. Shallow. late‐formed structural traps in the Azua Basin have been charged by remigrated hydrocarbons. Unrecognised and undrilled deeper parent structures are predicted at depth in the Azua Basin, but require modem seismic data to confirm their existence. Existing seismic data identify undrilled prospects in the Enriquillo and San Juan Basins.
EXPLORATION POTENTIAL OF TRINIDAD AND TOBAGO
Authors: Rohr G. M. 
Published: December 2007

The Maturin Basin of eastern Venezuela, including Trinidad. has produced approximately 9.5 billion brls of oil, and is the site of significant new discoveries at El Furrial and El Carito. The present structural basin was formed by oblique compression during Oligocene to Miocene time, with the northem flank being a folded and thrusted terrane over‐riding the South American continental margin. This deformed northern flank extends into the subsurface to the basin axis, and includes the southern half of the onshore and offshore territory of the Republic of Trinidad and Tobago. The basin was infilled from west to east by deep‐marine shales, turbidites, pelagic oozes and deltaic sediments of Neogene age. Deltaic sands form the reservoirs of all the important oilfields in the basin. Oil occurrence on the northern flank of the basin is associated with thrust‐related structures in Venezuela and wrench‐related structures in Trinidad.There are many excellent prospects along the flanks of wrench‐related ridges with diapiric cores in the Trinidad and Tobago portion of the basin. Late Pliocene and Pleistocene deltaic sands shale‐out northwards in very thick aggradational lobes, enhancing the prospectivity of the southern flanks of these ridges. The prospectivity of the fold‐and‐thrust belt in Trinidad and Tobago is limited by the distribution of reservoir facies in pre‐Pliocene sediments. Candidates for non‐deltaic reservoirs are Miocene limestones, Oligocene sheet‐sands, Eocene turbidites and Cretaceous fractured argillites.
GRAVITY OVERTURNS, EXTENSION, AND BASEMENT FAULT ACTIVATION
Authors: Koyi H. 
Published: December 2007

Rayleigh‐Taylor instabilities occur when low‐density layers of viscous fluids are overlain by denser layers. Gravity overturn of such instabilities leads to the rise of the unstable light (source) fluid as diapirs (e.g. of salt) through the denser (overburden) layers (e.g. of clastic sediments). Lnteral extension or movements of faults in the bottom boundary at any stage during such gravity overturns are expected to have a great effect on the geometry, growth rate and location of onv salt structures.Two groups of material models, each consisting of three series, were used to study the effect of uniform extension. and the non‐uniform extension due to reactivation of pre‐existing basement faults. on gravity‐driven overturns at different stages. The overburden in a third group model consisted of a stiffer non‐Newtonian fluid. All the models were loose& scaled to an early stage of the North Sea. All the diapirs were upbuilt, because all the overburden was in place from the start.Pre‐extension/prefaulting model diapirs are essentially vertical, symmetrical and finger‐like with circular planforms and with isotropic lateral spacings predictable by Ramberg theory. When reactivated and deformed by Inter extension. these diapirs become inclined in profile, and develop elliptical planforms elongate in the direction of extension. Diapirs which rise in an tnstable sequence already thinned uniformly are only smaller, closer and slower.Post faulting model diapirs (in group 2 models) rise as asymmetric walls or rows of fingers, some above the, fault‐scarps in the basement. others above the fault blocks.Synextension model diapirs rise from a thinning source layer; some are inclined and osymmetric in profile; some hove circular planforms, while others are elliptical and elongate in the extension direction. Synfaulting diapirs which form during reactivation of extensional basement, faults. develop as inclined and asymmetric walls overhanging the fault scarps. Finger‐like diapirs separated from synfaulting walls occur in rows parallel to the faults, and have elliptical planforms elongate in the extension direction or. if located in local regimes of shallow compression, perpendicular to it,When the overburden was non‐Newtonian with a power law component n=8.1. diapirs of the source surfaced only along extensional faults in the overburden.The model results are used to comment on recent interpretations of how halokinesis and extension interacted in the North Sea.
HYDROCARBON ACCUMULATIONS ON THE DEAD SEA GRABEN: A SIMULATION APPROACH
Authors: Braester C. , Fligelman H. , Kashai E. 
Published: December 2007

A modelling study aimed at providing a better understanding of the hydrocarbon accumulations on the SW flank of the Dead Sea graben in Israel has been performed. It considers the recent geochemical finding that the source rock of the hydrocarbon occurrences in the area is the Senonian bituminous chalk and marl, buried in the central Dead Sea graben. The study investigates the effect of the regional geological and hydrogeological conditions, associated with the physical properries of the rock and fluids, on the migration and types of hydrocarbon accumulations. The investigation was performed by means of a three‐phase, two‐dimensional, numerical reservoir simulator. Typical cross‐sections, through potential anticlinal hydrocarbon traps, were considered. The study analyses possible hydrodynamic flushing in the water‐flow direction, as well as counter‐current migration in a direction opposite to the potentiometric water gradients, from the Dead Sea graben upwards.In addition to conventional hydrodynamic traps. the study includes the case of downdip entrapment due to low permeability regions. It is concluded that: (i)from the hydrodynamic point of view, the easiest oil migration path is through Paleozoic — Triassic formations: (ii) the high water salinity of these beds facilitates the up‐structure oil flow in a direction opposite to the water current movement: (iii) the Jurassic beds are probably impregnated by oil and gas coming from Triassic strata through faults: (iv) undiscovered structural traps are likely to contain mostly gas; and (v) down‐faulted blocks adjacent to sealing faults. or to low‐permeable regions (including permeable faults), are potential oil traps.
SCALES OF PERMEABILITY HETEROGENEITY WITHIN THE BRENT GROUP
Authors: Daws J. A. , Prosser D. J. 
Published: December 2007

A selection of Brent Group reservoir sequences from the Murchison field were chosen to study the nature of permeability variation within the Brent Group, with particular emphasis on the Etive Formation, which forms one of the main reservoirs in the field.Preliminary core examination of potential permeability barriers, as identified using wireline log response, has indicated that permeability heterogeneities can be placed into a five‐fold hierarchy. Permeability heterogeneities resulting from depositional or syndepositional processes comprise the first four orders of heterogeneity and include formations, facies transitions, bedding surfaces and laminations. Permeability heterogeneities which are the product of diagenetic processes are classified as fifth‐order heteorgeneities.Two major types of permeability barrier have been identified in core and on wireline logs within the Etive Formation. They include permeability heterogeneities associated with a transition between the two major facies associations (tidal channel and beach/foreshore sandstones); and heterogeneities associated with the development of inactive channel‐fill sandstones and siltstones within the tidal‐channel facies association.A detailed sedimentological model has been developed which demonstrates the complexity of reservoir zonation in the Etive Formation within the Murchison field.