bluuebunny/crossref_metadata_2025 huggingface dataset:
PERMIAN AND TRIASSIC GEOLOGICAL HISTORY AND TECTONICS OF THE MIDDLE EAST
Authors: Sharief Farooq A.
Published: December 2007

The paleogeography postulated from the distribution of Permian and Triassic sedimentary rocks in the Middle East is shown and related to the paleostructure of the region. The Middle East region as defined here includes the Arabian Peninsula, Iran, Iraq, SE Turkey, Syria, Lebanon, Jordan, West Jordan, and the Sinai Peninsula. Within the limits of the area included in this study, a relatively stable pre‐Late Triassic tectonic regime can be recognized and distinguished from a succession of diastrophic events of the Late Triassic epoch, which caused marked changes in the types and distribution of facies.

Excluding NE Iran, the Middle East was stable from Late Cambrian to Middle Triassic times, as it formed a part of the Arabian Massif and much of the Middle East Platform, which is a broad shelf bordering the positive Afro‐Arabian Massif to the NE and east. The sediments of this plarform have undergone no strong deformation and have been subjected only to epeirogenic movements which interrupted sedimentation locally or regionally. However, from Upper Permian through Middle Triassic times, the predominant facies on this shelf was carbonates which unconformably overlie the non‐marine or extremely shallow marine elastics of the Lower Permian or older strata in most of the region.

Upper Triassic strata in the area are markedly different in facies from older beds because of the movement of blocks in Turkey and northern and eastern Iraq and Iran related to the enlargement and broadening of the Tethys. Asa result, much of northern and eastern Iran were separated from the area to the south and west, which continued to be a shelf flanking the Afro‐Arabian Massif. Consequently, three major structural elements existed in the region: the Arabian Shelf, the Tethyan rift zone and the Paleo‐Tethyan trough.
EARTH OUTGASSING AND CARBONATE FACIES DEVELOPMENT vis‐à‐vis MESOZOIC CARBONATES OF HIMALAYA
Authors: Bhat M. I.
Published: December 2007

Carbonate deposition through the Earth's history shows two distinct changes in terms of volume and chemistry. Whereas carbonates comprise a very small percentage of the total sedimentary rocks in the Proterozoic, they constitute 20–25% at the present time. From the Archaean to Early Palaeozoic, carbonates are dominantly dolomites, whereas afterwards they are dominantly limestone. 87Sr/86Sr, δ180 and δ13C trends show an increase with decreasing age.

All these features of carbonate rocks are explicable as being related to the increased episodic outgassing of CO2 and CH4 from the upper mantle throughout the Earth's history.

The Mesozoic carbonates of Himalaya are correlatable with the CO2 outgassing associated with rifting and magmatism during the birth of the Tethys ocean.
NATURAL RADIOACTIVITY OF CLASTIC SEDIMENTS AND THE CONTRIBUTIONS OF U, Thand K
Authors: Dypvik H. , Eriksenf D. Ø.
Published: December 2007

The contributions of uranium, thorium and potassium to the natural radioactivity of shaly sediments have been estimated. Average shales have high contributions from potassium (50%) and Th (40%) and minor contributions from U (10%).
PHYSICAL CONSTRAINTS OF FAULTING IN A GOPRESSURED SEDIMENTARY BASIN*
Authors: Magara Kinji
Published: December 2007

On the basis of the triaxial stress concept, the tectonic stress required for faulting and sliding in a sedimentary basin can be estimated. The horizontal tectonicstress necessary for thrust faulting, for example, increases with depth from the surface to about 9,000 ft (2.7 km), and decreases below 9,000 ft (2.7 km), primarily because of a changing Poisson's ratio. Changing the vertical effective stress caused by generation of abnormal fluid pressure would also change the tectonic stress requirements for faulting.

The internal friction of sedimentary rocks in the subsurface must be exceeded by the tectonic stress applied to the basin for faulting or sliding to take place. Estimates of the internal friction suggest that there is a high probability of faulting at depth if there are thick undercompacted and geopressured sections. Diapirs may also occur in such a physical environment. If the sedimentary rocks are normally compacted and the fluid pressure is hydrostatic from the surface to depth, on the other hand, the rocks are generally too rigid to cause any significant sliding. There would be very little chance of faulting and diapirism in such a case.

The concepts developed in this paper may have a practical application in the under‐standing of the physical conditions and constraints of faulting and diapirism in a relatively‐young sedimentary basin with significant geopressuring at depth.
INTERIOR CAVITIES AND EXTERIOR SURFACE TEXTURE OF DETRITAL QUARTZ OF SOME EGYPTIAN CLASTIC SEDIMENTS
Authors: Kholief M. Mahmoud
Published: December 2007

Cavities of freshly fractured surface and the exterior surface texture of detrital quartz grains were examined and photographed with the help of the scanning‐electron microscope at different magnifications. Three formations of Egyptian clastic sediments are used for this purpose namely: (a) Carboniferous sandstone of west‐central Sinai, (b) the so‐called Nubian sandstone of Early Cretaceous(?) age from southern Egypt, and (c) Oligocene sand accumulations from the vicinity of Cairo.

It is concluded from the present study that in most cases the intracrystalline cavities have an average diameter of less than 10 microns. Different shapes can be acquired by these cavities‐ranging between irregular and negative crystal forms. The distribution of ca vities seems to be mainly along the fractures and the planes of growth but random distribution is sometimes observed.

Examination of the surface features also shows that the depositional environment for Sinai and Aswan sandstones is aeolian with more effective diagenetic alteration in the first type of deposit. In the case of Cairo sandstone, the surface impressions of the quartz confirm the alluvial environment of deposition.
RESERVOIR GEOLOGY AND ITS ROLE IN THE DEVELOPMENT OF THE L‐III RESERVOUR, BOMBAY HIGH FIELD, INDIA†
Authors: Bhandari L. L. , Jain S. K.
Published: December 2007

A brief account of the geology of the Bombay High oilfield on the Western Shelf of India is presented. The L‐III reservoir, its development and exploration utilising a 3‐D, 3‐phase black oil mathematical model is discussed in detail.

The Bombay High, a giant offshore located 160km WNW from Bombay city on the Western continental shelf of India, was discovered in 1974. It was put in production in two tears and production has been raised gradually to 240,000 b/d. There commercially exploitable hydrocarbon‐bearing zones–L‐II(limestone), S‐I (sand) and L‐III (limestone) of Miocene age have been identified. At present, the emphasis is on xploration of the L‐III reservoir which contains over 80% of the total reserves of the field. It is composed mainly of wackestone, mudstone and monor packstone. Cyclic sedimentation is identified. Each cycle is represented by four facies: in ascending order they are–lagoonal, algal mound, foraminiferal mound and coastal marsh. The porosity is mainly intergranular, intragranular, moldic, vuggy and microfissures. The solution cavities interconnected by micro‐fissures provide excellent permeability.

It is a saturated reservoir with a large gas cap and extensive aquifer, which has left a narrow strip for locating production wells to give water‐or gas‐free oil production. For optimum location of production wells, a 3‐D, 3‐phase black‐oil mathematical and radial coning model was adopted. This assumes intervening shales to be non‐barrier between sub‐layers, and intervening shales within the resrvoir to be partly in communication, giving due consideration to spatial variaton in porosity and thickness of layers. This has paid dividends and reservoir performance is in conformity with prediction.
CARBONIFEROUS OIL AND GAS PRODUCTION IN THE EASTERN HEMISPHERE ‐ 1
Authors: Meyerhoff A. A.
Published: December 2007

Almost all production from Carboniferous formations in the Eastern Hemisphere comes from the Soviet Union, with less importantproduction from the United Kingdom, the Southern North Sea basin, the N W German basin (from the northern Netherlands to Poland), Algeria, Ghana, the Gulf of Suez, China and Australia. However, Carboniferous coals extending from the eastern part of Great Britain to Poland were the source of the hugegas reserves that are found in Permian and Triassic reservoirs in the Southern North Sea‐N W German basin complex. Production of oil during 1978 was approximately 2,680,000 b/dt and of gas, about 20.8 Bcfldf. The USSR share was about 2.6 MM brl and 5.2 Bcf per day. Carboniferous production, which peaked in 1975, has since declined steadily.

Most of the USSR's Carboniferous production is from marine carbonates andfrom marine to deltaic sandstones in the Volga‐ Urals, Timan‐Pechora and Dnepr‐Donets basins. The latter basin is mainly gas productive. Smaller amounts of hydrocarbons arepresent in marine beds of the North Caspian (Pricaspian) basin of the European USSR and in similar strata of the Chu‐Sarysu basin of Kazakhstan. Some small, but significant, discoveries have been made in carbonates of the southern part of the West Siberian basin. Although the deep Khuff gas of the Middle East is probably mainly of Permian origin, some Late Carboniferous source materials could have generated part of the gas, inasmuch as the base of the Khuff is probably Late Carboniferous.

Hydrocarbons in terrigenous Carboniferous rocks in Egypt are believed to have originated in non‐Carboniferous beds; the petroleum in the Carboniferous sandstone reservoirs of Ghana, China and Australia is generally indigenous, and is non‐marine to deltaic. Oil and gas in the Carboniferous strata of Algeria are in marine and deltaic beds and are partly indigenous. The huge Carboniferous gas reserves in Permian, Triassic and, to a lesser extent, Carboniferous reservoirs of the Southern North Sea‐NW German basin are of non‐marine origin. The source materials were the Upper Carboniferous coals of the same area.

The volume of produced Carboniferous oil is about 23 B brl, 21 B brl of it from the Volga‐Urals basin alone. About 63 Tcf of gas has been produced, 51 Tcf from the Southern North Sea‐NW German basin. This volume of gas includes Carboniferous gases in Permian and Triassic reservoirs. Proved and probable reserves of Carboniferous oil are about 13 to 14 B brland 85 Tcf, of which more than 50 Tcf remains in the Netherlands “giant Groningen Barents Sea extensions of the Timan‐Pechora basins, and ‐just possibly ‐ in several Chinese basins. The Arabian Gulf(Persian Gulf) also has a very largegas potential, but thegas, mainly in the Khuff, is of unknown origin and may wellnot be Carboniferous. (The Chu‐Sarysu basin, USSR, could also be important.)
SEQUENTIAL DEVELOPMENT OF HANIFA FORMATION (UPPER JURASSIC) PALEOCNVIRONMENTS AND PALEOGEOGRAPHY, CENTRAL SAUDI ARABIA
Authors: Moshrif Mohamed A.
Published: December 2007

The Hanifa Carbonate lithofacies (Upper Jurassic) started to develop during Early Kimmeridgian time, when an extensive area in central Arabia was covered by relatively deep marine waters. These rock units were formed along a shoreline, resulting in sucessive lagoonal and tidal‐flat belts, the deposition of pelleted and laminated calcilutites and gypsum, and a restricted fauna. The open shelf lay east of the lagoon zone, accounting for the development of oolites, coral reef and calcarenites, and a diversified fauna on the deeper shelf.

At its maximum extent, the “Hanifa Sea” reached west nearly as far as the city of Riyadh in central Saudia Arabia, and extended NE and east, covering Kuwait, Iraq, Oman and Iran. South of Riyadh, the Hanifa lithofacies may be traced towards the SE over the Rub‐al‐Khali area, and SW over Yemen and the Aden Protectorates. North and NW of Riyadh, these same Upper Jurassic shallow‐marine rock units developed over Jordan, Syria, Lebanon, Palestine and northern Sinai, and most probably extended over northern Africa.

Although the sediments forming the lower part of the Hanifa suggest that during Early Kimmeridgian tima a transgressive phase began, and most likely continued during part of the Middle Kimmeridgian, a regressive stage ensued towards the end of th Kimmeridgian, when the upper part of the Hanifa was deposited.
OIL AND GAS ACCUMULATIONS IN OVERTHRUST BELTS ‐ II
Authors: Pratsch J.‐C.
Published: December 2007

The occurrence of oil‐and gasfields in overthrust belts follows the same principles that operate in normal basins. There is no essential difference, and, in order to avoid any personal bias or dogma, examples of productive areas in overthrust belts should speak for themselves. The examples below are selected only on the basis of available data. More examples would improve understanding but would not change the basic principles described. Unfortunately, the most convincing examples are locked away in company files.
SOME CONSEQUENCES OF FAULTING IN THE PRESENCE OF A SALT ROCK INTERVAL
Authors: Jenyon Malcolm K.
Published: December 2007

Movement (and diapirism) in salt rock is frequently associated with faulting. In some cases, as in the Southern North Sea Zechstein, the association is clearly demonstrable. In other cases, more subtle effects occur. There is a variety of phenomena which may be observed under different geological circumstances in the salt‐fault association, and this paper discusses some of the more frequently‐encountered of these, offering some rather speculative suggestions as to the mechanisms which may be involved.

Comment is also made upon apparent inconsistencies existing in currently‐held views on deformation in salt rock, and on the initiatory causes of diapirism.

The ideas expressed and the geological interpretations made, are based on the study of current seismic data which has, where possible, been related to released well information.
PLATE TECTONICS WITH FIXED CONTINENTS: A TESTABLE HYPOTHESIS ‐ II
Authors: Lowman Paul D.
Published: December 2007

The first part of this paper was published in Journ. Petrol. Geol. 8(4) 373–388. The Author here concludes his presentation: the Summary and Conclusions, and the references which follow, apply to both sections.
MORPHOSTRUCTURAL ANALYSIS AS AN AID TO HYDROCARBON EXPLORATION IN THE AMAZONAS BASIN, BRAZIL
Authors: de Miranda F. P. , Hora M. P. P. da Boa
Published: December 2007

A significant contribution to regional studies in the Amazonas Basin has been provided by the morphostructural analysis of MSS‐LANDSAT and SLAR imagery. The interpretation of remote sensing data led to the detection of many morphostructural anomalies in the Upper Amazonas Basin. A comparison between these anomalies and the available geological and geophysical data permitted the definition of two distinct morphostructural domains in this region. The first comprises a set of E‐W anomalies, located in a thinner sedimentary cover portion of the Upper Amazonas Basin. This feature was tentatively attributed to a prominent basement hinge line. The second morphostructural domain embraces anomalies situated where the sedimentary pile exceeds 1,600 m. In this domain, many anomalies seem to be related to ENE‐striking reverse faults. These morphostructural anomalies are arranged along ENE and E‐W aeromagnetic trends forming morphostructural trends.

Analysis of MSS‐LANDSA T and SLAR imagery near the boundary between the Middle and Lower Amazonas basins indicates that several morphostructural anomalies are aligned in well‐defined directions, also suggesting the presence of morphostructural trends. These trends, often striking ENE, lie among zones with sharp magnetic gradients interpreted as expressions of basement compositional boundaries. Such morphostructural trends are also found near positive small‐wavelength magnetic anomalies, interpreted as possible grabentype structures.
THE EVOLUTION OF OCEAN BASINS DURING CENOZOIC TIME
Authors: Orlenok V. V.
Published: December 2007

Evidence has accumulated steadily during recent years to show that ocean basins are quite young, certainly younger than Paleozoic and PreCambrian. The most common mechanism invoked to explain the relatively youthful age of ocean basins is through sea‐floor spreading, i.e. by the theory of plate‐tectonics; however, the Author believes that it can be explained more logically by a process of “oceanization”, for which clear evidence was shown in 149 of the first 493 DSDP† boreholes. The oceans began to form during the Middle Jurassic (the oldest marine strata penetrated in the boreholes), about 170 MM years‡ ago. Beginning in the Paleogene, the oceans began to deepen more rapidly. This deepening was accompanied by the effusion of great thicknesses of plateau basalt. The sinking process was made possible by the thickening of the asthenosphere beneath the ocean basins, a process which is continuing towards the continents as these become “oceanized”. It is to be expected that the entire process will be completed within the next 30 to 50 MM years.
THE EXPULSION CRITERION IN THE EVALUATION OF THE PETROLEUM SOURCE BEDS OF THE TERTIARY NIGER DELTA
Authors: Ejedawe J. E.
Published: December 2007

Semilog plots of hydrocarbon ratios with depth for four wells in the offshore Niger Delta show that hydrocarbon expulsion has occurred at an interval shallower than the geochemically‐acceptedtop of the oil‐generative window (OGW), This shallow expulsion zone, which spans the maturation range 0.3‐0.6% RO, is related to the transformation of resinite‐ and sporiniterich organic matter to hydrocarbons. The deeper generation/expulsion zone (conventional OGW) has not released its generated hydrocarbons, presumably because of overpressure development.

The critical hydrocarbon saturation at the onset of migration is 10–22 mg per gm organic carbon. Within the expulsion zone, expulsion efficiency varies considerably (10–81%; average 50%), and expulsion ceases when the hydrocarbon saturation falls 10–60% below the critical saturation level.

The relative contribution of the paralic Agbada and marine, pro‐delta Akata source shales to the reservoired hydrocarbons in various areas of the delta depends on the present depth position of top supernormal pressure (Hsnp), relative to the top of the Akata Formation (Hak), and the top of the OGW (Hogw). Since the top of OGW must be above the top of the overpressure (Hogw < Hsnp) for effective hydrocarbon expulsion, three basic models are recognised in the Niger Delta:—

(a) Hak Hsnp > Hogw: developed in the younger offshore and central onshore areas, with the Agbada constituting the major source rock;

(b) Hogw < Hak < Hsnp: developed in the northern frame of the central Niger Delta, with both the Akata and Agbada contributing to the reservoired hydrocarbons; and

(c) Hak Hogw < Hsnp; developed in the older northern fringe of the delta, with the Akata constituting the majar source rock.
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.
THE JURASSIC SYSTEM IN NORTHERN EGYPT: II. Depositional and tectonic regimes
Authors: Keeley M. L. , Wallis R. J.
Published: December 2007

The results are outlined of a detailed sedimentological study made of the Jurassic succession presented in northern Egypt at surface and in the subsurface, largely on the basis of material from over 80 wells. With the benefit of a detailed stratigraphical scheme, it has become possible to map the distribution of fluvio‐deltaic, shelf and open‐marine facies belts. Changes in distribution of facies are attributed to the eustatic interaction between Nubian and Tethyan influences, and to the repeated movement of local faults. Active basins are identified on the basis of static facies. and stacked thick sequences. The pattern of syn‐depositional tectonic activity thus assembled is compatible with existing tectonic models for the Eastern Mediterranean region: indeed, it is used to improve them. The present continental margin to Egypt is shown to have formed during a period of westward‐propagating crustal rifting, over the late Pliensbachian‐Bathonian interval. Evidence is presented for a link between movements within the central/southern African craton, and the sequence of extensional and transtensional activity observed in Egypt during the Jurassic and the “Cimmerian” event. Faults accommodating this strain were mostly orientated NE‐SW, that is, contiguous with the “Syrian Arc”.
HYDROCARBON POTENTIAL OF NORTHERN IRELAND: Part 1. Burial histories and source‐rock potential
Authors: Parnell J.
Published: December 2007

Carboniferous successions may have hydrocarbon source‐rock potential in several districts of Northern Ireland. They have been buried to depths required for hydrocarbon generation beneath younger Carboniferous rocks in the west, and beneath Permo‐Triassic basins in the east. Samples of coals and shales collected from outcrop and boreholes have been less‐deeply buried and are consequently less mature, but upon pyrolysis give good hydrocarbon yielak, which suggests that hydrocarbon generation is likely to have occurred in the basinal districts. Carboniferous rocks in the west, and in adjacent parts of the Republic of Ireland, include numerous shows of solid bitumen, which represent degraded oil residues. However, the coaly nature of much of the carbonaceous sediment suggests that the predominant hydrocarbon product would probably be gas.
HYDROCARBON POTENTIAL OF NORTHERN IRELAND: Part III. Reservoir potential of the Permo‐Triassic
Authors: Parnell J.
Published: December 2007

Thick Permo‐Triassic sandstones occur in two basins in Northern Ireland. The sandstones are fluvio‐deltaic, including an oolitic facies, and are interbedded with mudrocks. They exhibit petrographic features which are typical of red beds and are widely found in the Permo‐Triassic elsewhere in the British Isles. The predominant cements are haematite, potassium feldspar. illite and carbonates. Gypsum, anhydrite and dolomite cements occur in the regions of deepest burial. which represent the basin centres. There was widespread leaching of carbonate/sulphate cements, but calcite is preserved in the oolitic facies and below the sub‐Cretaceous (chalk) unconformity. The dissolution of cements and framework grains was due to leaching by meteoric fluids. Precipitation of kaolinite in secondary pores, and subsequent illitization, represent fluctuations in the meteoric hydraulic head. Deep boreholes exhibit sandstone porosities which indicate that there may be significant reservoir potential where adequate seals and traps are present.
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 Basin

However, 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.
CHARACTERISATION OF LOW MOLECULAR WEIGHT HYDROCARBONS IN FLUID INCLUSIONS FROM FRACTURE‐FILLING ANHYDRITE IN THE SOUTHERN NORTH SEA GASFIELDS
Authors: McNeil B.
Published: December 2007

Studies of crushing crystals while viewing them under a microscope (“stage‐crushing” studies) were carried out on fracture‐filling anhydrites from the Vulcan and Vanguard gasfields in the UK sector of the southern North Sea. These studies were performed after the appearance of clathrate solids during microthermometric freezing experiments which indicated the presence of a gas component within the inclusions. After several attempts at a very difficult analytical technique, a series of photographs were taken of the process whereby the vapour phase in the inclusions expanded. This indicated the existence of a gas under pressure in the inclusions. Gas chromatographic studies suggested the dominance of methane, and that the overall component is comparable to that of the southern North Sea gas reservoirs.
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.