bluuebunny/crossref_metadata_2025 huggingface dataset:
GEOLOGICAL SYNTHESIS OF THE ORINOCO OIL BELT, EASTERN VENEZUELA
Authors: Isea Andreina
Published: December 2007

The Orinoco Oil Belt, considered to be the largest hydrocarbon accumulation in the world, is located on the southern border of the Eastern Venezuela basin. The stratigraphic column of the area includes rocks of Pre‐Cambrian to Recent ages, but more than 90% of the crude oils are found in Miocene sediments.

Three transgressive‐regressive cycles with wide regional distributions are recognised in the Tertiary system: Cycle 1 includes the La Pascua, Roblecito and Chaguaramas formations of Oligocene age; and Cycles 2 and 3 include the Officina, Upper Chaguaramas and Freites formations of Miocene age. Within the cycles, five lithostratigraphic units are defined, and a sedimento logical model for Units I and III is consequently established, recognizing north‐orientated, wave and tide‐influenced, prograding deltas.

Tensional tectonics characterize the area as having two structural provinces, separated by the Hato Viejo fault system: the Eastern Province, characterized by a transgressive sequence overlying the Pre‐Cambrian basement; and the Western Province, where the Tertiary unconformably overlies Cretaceous and Paleozoic sediments. Hydrocarbon accumulations in the Orinoco Oil Belt predominantly occur in stratigraphic traps, but are controlled by regional structures.

Four types of crude oils are identified, with density values between 8.5 and 13° API. The volume of oil in‐place in the Orinoco Oil Belt totals 187,897 MM†cu. m(1,181 B brl). The largest accumulations are found in the sands of Unit I.
EXPLORATION RESULTS, MACHETE AREA, ORINOCO OIL BELT, VENEZUELA
Authors: Kiser G. Don
Published: December 2007

The Machete Area covers 23,610 sq. km (9,116 sq. miles), of the Orinoco Oil Belt in Venezuela. Based on exploration data from 30 old and 74 new wells, the volume of heavy and extra‐heavy crude oil in‐place is estimated to be 40 B cu. m (255 B brl), ** of which 4 B cu.m (22.5 B brl) are in future potentially recoverable; some 62 B cu.m (2.2 T cu. ft) of natural gas may also be recovered. Drill depths to the base of the producing section vary from 518 to 1,220 m. Net oil sand reaches 116 m in thickness for Tertiary reservoirs, and 46 m for Cretaceous ones. The crude oils average 1,022 kg/cu.m (7° API), and have a content of sulphur and various metallic elements typical of similar crudes; viscosities are slightly higher than in the rest of the Belt.

Production rates of up to 20 cu. m/d (140 b/d) on pump may be increased ten‐fold by steam injection. Dry natural gas flows of 450 cu.m/d are common. The principal geological factors controlling the Machete accumulations differ from those in adjacent areas, and consist of the subsurface extension of the El Baúl Arch which has controlled sand‐shale facies, pinch‐out lines and structural‐stratigraphic trapping of the heavy crude oils and natural gas.
HELIUM‐NITROGEN‐METHANE SYSTEMATICS IN NATURAL GASES OF TEXAS AND KANSAS
Authors: Gold T. , Held M.
Published: December 2007

Gas‐mixing ratios of samples from 1,038 naturalgas wells of the Hugoton/Panhandle fields of West Texas and Kansas are examined, and well‐defined regional systematics are noted. The helium‐nitrogen ratio of all the Texas fields has a nearly constant value (0.077) and a very sharply‐defined upper boundary. In the Kansas fields, a diflerent value is found for that ratio (0.021), but it is also well‐defined over a large region. Theproportion of methane, the principal gas in all the wells, shows a regional dependence within each of the areas. The observed distribution places constraints on the origin of the threegases, and suggests that they all derive from sources deeper than the sedimentary layer.
CONTINENTAL CRUST UNDER THE NW PACIFIC OCEAN
Authors: Choi D.R.
Published: December 2007

Reinterpretation of seismic profiles and DSDP drilling results, together with dredging data from the Japan Trench and Nankai Trough areas, NW Pacific, shows that the so‐called oceanic crust is composed of PreCambrian continental crust, consisting partly of Proterozoic orthoquartzite.

This is supported by paleogeographic evidence, which requires the presence of large continental masses on the present Pacific side of the Japanese islands during Paleozoic‐Mesozoic‐Paleogene times, as source areas for the large volume of sediments carried into the Japanese part of the Tethys.

Most of the present NW Pacific was either subaerially exposed or was partly very shallow sea during Paleozoic to Early Mesozoic times, and first became deep sea about the end of the Jurassic.

These conclusions require the fundamental revision of plate‐tectonic models for the geological development of the island arcs and trenches in the NW Pacific region.
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.
ZOOPLANKTON FECAL PELLETS AS A SOURCE OF HYDROCARBONS IN CHALK
Authors: Moussa M. T.
Published: December 2007

Evidence from biochemistry, marine geology and sedimentology shows that chalk could be a source of hydrocarbons, and that some hydrocarbons in some chalk reservoirs could have originated within the chalk. Coccolith ooze, the precursor of chalk, is deposited as the fecal (faecal) pellets of zooplankton, most probably copepods. These fecal pellets contain dihydrophytol which is a precursor of pristane; the latter is a precursor of some crude oil deposits. Zooplankton fecal pellets probably provided the organic source for some of the hydrocarbons in chalk. Some hydrocarbons in marine‐ and lacustrine‐shale source rocks could have originated in much the same way.
POTENTIAL HYDROCARBON‐GENERATING ROCK UNITS WITHIN THE PHANEROZOIC SEQUENCE OF THE OGADEN BASIN, ETHIOPIA: A PRELIMINARY ASSESSMENT USING THE LOPATIN MODEL
Authors: Assefa G.
Published: December 2007

The geochemical parameters of potential source rocks in the Ogaden Basin, Ethiopia are conducive to the presence of gas and oil. This prediction is based on Lopatin's method of calculating the time‐temperature indices of thermal maturation of organic matter in rocks. Paleozoic and Mesozoic rocks, the Bokh Shale and Hamanlei Formation respectively, are estimated to lie in a thermal zone which is appropriate for generation of petroleum, especially gas, at several localities in the Basin.
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.
THE EARLY TO “MIDDLE” CRETACEOUS LITHOSTRATIGRAPHY OF THE CENTRAL NORTH SEA (UK SECTOR)
Authors: Crittenden S. , Cole J. , Harlow C.
Published: December 2007

A revised lithostratigraphical framework of the Early to “Middle” Cretaceous strata of the Central North Sea (UK sector) derived from the rigorous examination of more than 100 commercial boreholes is presented. previously published frameworks have tended toward oversimplification of the Early to “Middle” Cretaceous, as the interval was considered initially to be of minor importance with regard to prospectivity. However:there is a general feeling in the industry that the Early to “Middle” Cretaceous is prospective. particularly with regard to subtle stratigraphical traps like theKilda/BosunandScapafields. It is inevitable that as more attention, due to hydrocarbon exploration, is paid to an interval that the stratigraphical models used progress from the simplistic to the complex. The framework presented here is the result of a pragmatic approach in that it is based upon the integration of previously published schemes. with the erection of new units derived from new analyses and interpretation. The complete lithostratigraphical framework is defined. explained and discussed with reference to borehole examples in the Central North Sea.
VERTICAL HYDROCARBON MIGRATION: A MAJOR EXPLORATION PARAMETER
Authors: Pratsch J.‐C.
Published: December 2007

Most oil‐ and gasfields result from the migration of hydrocarbons from the generating source bed to the resenvoir and trap. Exceptions are producing source‐bed formations (coal‐bed gas, e.g. the Permian Spraberry Trend. West Texas). Where vertical hydrocarbon migration is active. oil/gas accumulations can be found in reservoirs of geological ages which are considerably different from those of the generating source beds. In such cases (eg. the North Sea gas province: Louisiana offshore: Niger Delta: Vienna Basin), early recognition of vertical migration may well bring about the most effective exploration results. In many basins. vertical migration is less evident than lateral migration, leading to distinct, vertically‐stacked hydrocarbon systems isolated from each other (e.g. the Po Valley, Powder River and Sine Basins). Vertical migrotion from one source‐bed level, or the mixing of hydrocarbons from different hydrocarbon systems, occurs where major faults or vertically‐rising materials (salt, igneous rocks) create critical vertical pathways. In such cases, vertical migration can be an important factor in the location and existence of hydrocarbon accumulations.
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.
GEOLOGY OF THE PERMIAN “SUPER‐GIANT” GAS RESERVOIRS IN THE GREATER PERSIAN GULF AREA
Authors: Kashfi M. S.
Published: December 2007

The Permian Dalan and Khuff Formations contain extensive gas reservoirs in the Greater Persian Gulf area. The Permian transgressive sea covered a vast area in the Middle East, and deposited a fairly thick sequence of shallow, epicontinental carbonates. These carbonates were deposited a fairly thick sequence of shallow, epicontinental carbonates. These carbonates were deposited unconformably on Lower Paleozoic rocks in western Iran and on the basement in Central Arabia. The term “Khuff Formation” has been widely used by oil companies in the region, but its equivalent, the Dalan Formation, is a new name currently being used in Iran.

The Permian Basin was an elongate trough, trending NW‐SE, parallel to the Cretaceous‐Tertiary Zagros geosyncline. The deepest part of the Permian Basin was in the extreme SE portion of the trough, in the vicinity of the present Oman Mountains, in which nearly 6,000 ft (1,830 m) of Permian sediments were deposited.

Porosity and permeability are generally low in these carbonates. However, secondary fracture porosity and dolomitization are commonly developed throughout these rocks. Permian reservoirs are capped by impervious strata, and the gas seems to be sourced from within the Permian section.
THE RED SEA ‐ GULF OF ADEN: RE‐ASSESSMENT OF HYDROCARBON POTENTIAL Abstract†
Authors: Beydoun Z. R. , Sikander A. H.
Published: December 2007

THE results and conclusions of the UNDP/World Bank Red Sea ‐ Gulf of Aden Regional Hydrocarbons Study Project (June. 1989‐January, 1992) are summarised. These results were derived from detailed examination of pooled public‐sector date provided to the project by the participating bordering states in the region; these included samples and logs from ca. 56 wells drilled in the two basins (out of a total of 71 wells). and some 30,000 line‐kms of reflection seismic (out of 110.000 km available). well‐logs were digitised and correlated, and basin‐wide biostratigraphic, lithostratigraphic and paleoenvironmental studies, source‐rock organic richness. quality and maturity studies and sedimentological analyses were performed by contracted specialist staff in UK and France, and integrated with basin‐wide seismic structural and isopach mapping for selected regional reflectors/intervals by national task forces in Cairo under project supervision: academically‐derived crustal seismic and other geophysical data, and supervision; academically‐derived crustal seismic and other geophysical data, and industrially‐derived velocity and other borehole data were also integrated for the Red‐Sea.

Modelling, utilising recently‐acquired geophysical data, indicates crustal asymmetry for the Red sea rift, with oceanic crust of pull‐apart basin type flooring some portions of offshore Egypt and Sudan on the west, and stretched continental crust underlying the eastern Arabian flank. These results suggest that sinistral strike‐slip processes controlled the intial break‐up of the Arabian Plate shaping the African flank as a sharp plate boundary,. Similar processes appear to have initially shaped the Somalia flank of the Gulf of Aden Rift. Only later did true sea‐floor spreading propagate: 10–12 million years age in the eastern Gulf of Aden; and <ca.5 million years age in the western Gulf of Aden, Afar and the southern/central Red Sea. Biostratigraphic work shows deep subsidence and ocean‐water inundation commenced in the late middle Oligocene in the Gulf of Aden, in the late Oligocene in the southern Red Sea, and in the early Miocene in the central Red Sea/Gulf of suez.
HYDROCARBON POTENTIAL OF SANDSTONE RESERVOIRS IN THE NEOGENE EAST SLOVAKIAN BASIN PART I: A PETROGRAPHIC EXAMINATION OF LITHOLOGY, POROSITY, AND DIAGENESIS
Authors: Reed J. K. , Gipson M. , Neese D. G.
Published: December 2007

Core description and petrographic analyses were utilized to study East Slovakian Basin sandstone reservoirs. Reservoir development is largely dependent on the original sandstone composition, which is influenced by deposition in a deltaic setting, local sourcing and volcanic activity. Sandstones are texturally and mineralogically immature lithic and feldspathic arenites. The presence of unstable lithic grains and feldspars contributes to low, irregular reservoir porosity, due to deformation by compaction, and susceptibility to chemical alteration. Reservoir quality is also influenced by the subsequent diagenesis of the sandstones, which is driven by high heat flow. Lithic fragments and feldspars alter readily to form authigenic/diagenetic mineral suites, which tend to occlude porosity; however, dissolution of some of these grains also enhances secondary porosity development. Most observed porosity in the basin sandstones is secondary, developing from dissolution of both carbonate cement and unstable framework grains. Porosities suggest a weak decreasing trend with depth of burial. However, detailed examination of several localities reveals that porosity development is strongly influenced by local factors (e.g. structural evolution, sandstone lithology, and the distribution of volcanics). Sandstones of the East Slovakian Basin are generally not good hydrocarbon reservoirs (particularly for liquid hydrocarbons), due to the presence of unstable framework grains, early carbonate cementation and authigenic/diagenetic mineral suites. Exceptions are found when dissolution of cement and framework grains results in significant secondary porosity.
NIAGARAN REEFS OF NORTHERN MICHIGAN, PART I: EXPLORATION PORTRAIT
Authors: Gill D.
Published: December 2007

Drilling for Niagaran (Middle Silurian) pinnacle reefs in northern Michigan dominated the petroleum exploration scene in Michigan for 19 consecutive years (1969–1987). By the end of 1986, cumulative production from the northern reefs reached 268 MM brl (million barrels) of oil and 1.4 Tcf (trillion cubic feet) of gas. This study presents quantitative and graphic summaries of several attributes of exploration and discovery data for this period, which together provide a concise “portrait” of the exploration history of the play. Data subsequently available confirm these trends for more recent years.

The success ratio of exploration wildcats peaked at 51–53% during the years 1971‐73, after a “learning period” of three years. Thereafter, it declined gradually to around 16%, which is similar to the average of the US oil industry in the last decade. The success ratio for development drilling peaked at 68% during 1971‐2, and it has fluctuated between 40 and 50 % thereafter.

The frequency distribution of field sizes is log‐normal. However, since very small uneconomic or marginally‐economic prospects and fields have either not been drilled or developed, the observed distribution represents only the density distribution of economic fields.

The reef fields are rather small. Reef‐substrate areas range from about 40 to about 840 acres, and recoverable reserves range from 30,000 to 22 MM brl of oil equivalent (o.e).

The ten largest fields in the play were found by drilling the first 25% of the exploration wells. The discovery per wildcat peaked at 1.55 MM brls o.e. after 500 wildcats, and declined steadily thereafter to a level of 0.02 MM brls o.e. per well after 1,900 wildcats, indicating that the play had reached a state of maturity. About 25% of the discovered reserves were found in 5% of the fields, indicating a more even reserve distribution pattern than in many other plays. Consequently, the relative rate of growth of the discovered reserves has been slower than in other plays.
THE OCCURRENCE AND δ34S OF AUTHIGENIC PYRITE IN MIDDLE JURASSIC BRENT GROUP SEDIMENTS
Authors: Prosser D.J. , Daws J.A. , Fallick A.E. , Williams B.P.J.
Published: December 2007

Minor amounts of authigenic pyrite are common throughout the Middle Jurassic Brent Group, often being well developed within the delta‐plain fades of the Ness Formation. Petrographic analyses of pyrite samples from the Lyell and Murchison fields reveal two stages of pyrite authigenesis, both of which occurred during an early stage of burial.

The first phase of pyrite authigenesis is represented by the development of nodules and finely‐disseminated cement within shale, mudstone, and siltstone fades, and can include the development of bladed marcasite nodules. These cements are interpreted as having formed within organic‐rich sediment soon after deposition, and pre‐date all other authigenic precipitates (typically calcite, quartz and kaolinite). “Early” pyrite cements display a wide range of δ34S(‐14.9 to +42.5% CDT), and some nodules analysed display isotopically‐heavy cores and considerably lighter margins. These isotopically‐zoned nodules are problematical. They could be interpreted as forming via progressive “closed system” bacteriogenic reduction and isotopic fractionation of sea‐water sulphate, with incorporation of heavy H2S into the earliest‐formed pyrite occurring as a result of its upward diffusion through the sediment column, following isotopic fractionation at depth. However, there are a number of problems with this type of interpretation. These include the fact that diffusion will favour the 32S isotope, so that the first‐formed cements should still be isotopically “light” not “heavy”; also, there is a mass‐balance problem, in that no low δ34S sulphides were detected.

Coarsely‐crystalline pyrite euhedraform nodular cements mainly within sandstones (δ34S ‐2.6 to +12.8%CDT), and are interpreted as a “later” diagenetic phase. This second phase of sulphide cementation also pre‐dates the main phases of quartz and kaolinite authigenesis within sandstones, but post‐dates an early phase of kaolinite, and may have been partly coeval with some early calcite authigenesis.

High organic contents and the early establishment of reducing conditions led to early formation of pyrite within fine‐grained brackish and marine sediments. The lowest measured end‐member δ34S of sandstone‐hosted pyrite cements is less isotopically depleted than that within fine‐grained argillaceous fades, perhaps indicating that sandstone‐hosted pyrite cements began to form subsequent to the onset of burial and bacteriogenic reduction within mudstones. Compaction of marine/brackish‐water shales and mudstones (or sulphate diffusion from these fades) may have supplied an already isotopically‐fractionated source of sulphate to porous sandstone lithologies, where “later” pyrite cements precipitated.
PROBABLE CRETACEOUS‐TO‐RECENTRIFTING IN THE GULF OF MEXICO BASIN: An answer to Callovian salt deformation and distribution problems? Part 2
Authors: Reed J. M.
Published: December 2007

Part I of this paper (Journ. Petrol. Geol. 17, no. 4, pp. 429–444, hereafter referred to as Reed, 1994a) discussed the deformation and distribution problems presented by the thick Callovian salt found in the Gulf of Mexico Basin, and the enigma it presents to explorationists studying the area. Attempted solutions for the problems were discussed, together with reasons why these solutions have generally not been successful. A radical, new model was presented that would answer most of the salt problems; this model entails continuous rifting in the Gulf from Late Cretaceous to Recent times. This would imply that the Gulf of Mexico is a tectonically‐active basin, in contrast to the more widely accepted passive‐basin theory. This concluding section of the paper discusses evidence from the Gulf which supports the active‐basin theory.
PALINSPASTIC AND CRUSTAL SETTING OF THE EASTERN MEDITERRANEAN
Authors: Hirsch F. , Flexer A. , Rosenfeld A. , Yellin‐Dror A.
Published: December 2007

The nature and tectonic setting of the Eastern Mediterranean Basin are analyzed from geological and geophysical points of view. Palaeozoic and Mesozoic stratigraphy and palaeo‐biogeography suggest that epicontinental Africa, Apulia and Arabia were united almost continuously during the entire Phanerozoic eon, prior to and after the Early Triassic opening of the Mesozoic Tethys. The allochthonous ophiolite‐bearing terranes, that were thrust over the edges of the Gondwanan plate, fit well within a palinspastic model of a single Tethys ocean, north of the African‐Apulian‐Arabian palaeo‐edge.

Seismic reflection and refraction studies, together with magnetic and gravimetric measurements of the present Eastern Mediterranean Levantine crust, have revealed a sedimentary succession 13–14 km thick, which presumably includes Palaeozoic‐Early Mesozoic strata overlying crust 8–12 km thick.

Geological and geophysical re‐evaluation suggests that the enormously thick sedimentary succession of the Levantine Basin covers a thinned crust of continental origin. The latter consists of Panafrican terranes, possibly including Infracambrian ocean‐crust relics. Its “oceanic”‐like nature is presumably due to subcrustal thermal erosion. The possible existence of a western palaeo‐high offshore the Levant Coast calls for reassessment of hydrocarbon exploration in the Eastern Mediterranean. The previously proposed “hinge belt” along the Levant Coast may merely represent the transition from the eastern platform to a graben that separates the eastern (onshore) from the western (offshore) highs.

The passive extensional regime of the Gondwanan Eastern Mediterranean plate during most of the Phanerozoic eon ended with Late Cretaceous‐Palaeogene Alpine compression of its margins, and the activation of the on‐and offshore Levantinid Syrian Arc fold system.
A CRITICAL COMPARISON OF NEURAL NETWORKS AND DISCRIMINANT ANALYSIS IN LITHOFACIES, POROSITY AND PERMEABILITY PREDICTIONS
Authors: Wong P. M. , Jian F. X. , Taggart I. J.
Published: December 2007

The application of a genetic reservoir characterisation concept to the calculation of petrophysical properties requires the prediction of lithofacies followed by the assignment of petrophysical properties, according to the specific lithofacies predicted. Common classification methods which fulfil this task include discriminant analysis and backpropagation neural networks. While discriminant analysis is a well‐established statistical classification method, backpropagation neural networks are relatively new, and their performance in predicting lithofacies, porosity and permeability, when compared to discriminant analysis, has not been widely studied. This work compares the performance of these two methods in prediction of reservoir properties by considering log and core data from a shaly glauconitic reservoir.

The neural network approach, while subject to a degree of trial and error as regards the selection of the optimum configuration of middle nodes, is shown to be capable of excellent performance. In the example problem considered, the neural network approach provided estimates superior to those based on a discriminant analysis approach. Further studies, on different formations, will be required to test the generality of this conclusion, and to refine the selection of neural network parameters.