bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geological evolution and hydrocarbon habitat of the ‘Arctic Alaska microplate’
Authors: Hubbard Richard J. , Edrich Steven P. , Rattey R. Peter 
Published: April 2008

Abstract
Depositional sequence mapping has been used to analyse the late Devonian to Recent geologic evolution and hydrocarbon habitat of north Alaska and northwest Canada. Eight depositional megasequences have been identified, each of which records a discrete, major phase of basin evolution. The three oldest megasequences are named the Ellesmerian and reflect deposition on a subsiding fold belt terrane. We name the subsequent two megasequences of early Jurassic to Aptian age, the Beaufortian. They record a 100 Ma period of extension during which a Jurassic failed rift episode was followed by onset of the successful rift episode in the Hauterivian. This extension led to the opening of the oceanic Canada Basin. The final three megasequences record geographically distinct pulses of Brookian orogenesis.
The major proven hydrocarbon habitat occurs on the Barrow Arch of north Alaska. This is a volumetrically large, but greatly restricted, hydrocarbon province, which developed as a result of constructive interference between Beaufortian rift and Brookian orogenic tectonics. Two other, relatively minor, hydrocarbon provinces have also been discovered. They are the Mackenzie Delta and Kugmallit Trough provinces of northwest Canada, which developed in passively subsided basins, located just beyond the influence of Brookian orogenic uplift.
The Northern Gulf Coast Basin: a classic petroleum province
Authors: Fails T. G. 
Published: April 2008

Abstract
The US portion of the Gulf Coast Basin is that country’s greatest petroleum province, having produced about 31% of the oil and about 48% of the gas. Jurassic evaporites, deposited in basins opened by Mesozoic drift, underlie much of an area which received marine, mainly clastic, upper Mesozoic and Cenozoic deposits. Three small tensional basins were filled by late Eocene time. A large paralic basin remains an area of active deposition. Petroleum is produced from Mesozoic carbonates and clastics in the tensional basins, often from salt-related features, and from Cenozoic clastics in the paralic basin, where salt domes are common. Eocene fault-trapped production dominates in salt-free south Texas. Oligocene production, often from diapiric structures, is most important in coastal Texas and southwestern Louisiana. Miocene and younger production, usually salt-related, dominates in onshore and offshore south Louisiana. Favourable factors include large volume deposition and rapid burial, early and continuing structural development, lack of sand cementation and excellent source characteristics.
Geochemistry of carbonate source rocks and crude oils in Jurassic salt basins of the Gulf Coast
Authors: Sassen R. 
Published: April 2008

Abstract
The lower member of the Jurassic Smackover Formation is a source rock for crude oil across the northern Gulf Rim from east Texas to Florida. Type-I crude oils occur in Smackover reservoirs of east Texas, north Louisiana, south Arkansas, and Mississippi, and were generated by algal-derived kerogen preserved in an anoxic environment. Type-II crude oils in Smackover reservoirs of Alabama and Florida reflect an origin from kerogen with a terrestrial component preserved in a less anoxic environment. Thermal maturity differences across the Gulf Rim caused generation and destruction of crude oil to occur at much shallower depths in east Texas, north Louisiana, and south Arkansas than in Mississippi, Alabama and Florida. Jurassic through Cretaceous timing of migration and faulting permitted vertical migration of Type-I Smackover crude oils to many Upper Jurassic, Lower Cretaceous and Upper Cretaceous reservoirs along the Gulf Rim. Vertical migration of Type-II crude oils was less significant, especially in Alabama, because of evaporite barriers to migration. The high contents of hydrogen sulphide and carbon dioxide in deep, hot Smackover reservoirs are related to thermochemical sulphate reduction that has driven early destruction of methane. Compositionally distinct crude oils from Upper Cretaceous and Lower Tertiary siliciclastic source rocks are found in reservoirs south of the Gulf Rim.
Origin of the Infracambrian Salt Basins of the Middle East
Authors: Husseini Moujahed I. , Husseini Sadad I. 
Published: April 2008

Abstract
During the Infra and Lower Cambrain, the Arabian Gulf and Zagros Mountains (Hormuz Formation), South Oman (Ara Formation), Kerman in Central Iran (Ravar Formation), and the Salt Range Province in Pakistan (Salt Range Formation) were all sites of salt precipitation in subsiding rift basins along the Middle Eastern edge of Gondwanaland. Also from 600 to 540 Ma, a rift system extended westwards from the Sinai Peninsula and North Egypt across NE Africa, while a second rift system (about 600 to perhaps 510 Ma) extended northwards from the Sinai Peninsula across the Jordan Valley and Dead Sea into SE Turkey.
The development of these rifts was contemporaneous with the left-lateral Najd strike-slip fault system which dislocated the Arabian Peninsula by 300 km. The Najd system may be interpreted as a transform fault system which accommodated rifting between NE Egypt, the Jordan Valley, North Pakistan, Kerman and South Oman. The Najd system is parallel to the Zagros Line, and the latter is also the eastern depositional limit of the Infracambrian Hormuz Formation. The Infracambrian Zagros Line may be interpreted as a right-lateral, strike-slip fault system which caused Infracambrian rifting in the Arabian Gulf and Zagros Mountains.
Palaeontological and radiometric age constraints, together with stratigraphic considerations, suggest that the syn-rift evaporites were first precipitated during a transgression which commenced in the Latest Precambrian (600 Ma) and again during a Lower Cambrian regression. The regression terminated a period dominated by marine carbonates and evaporites and initiated the deposition of progradational alluvial to marginal marine sediments. Finally, in the late Lower Cambrian and Middle Cambrian, transgressive marine deposits swept across the Middle East.
Geology and reservoir characteristics of Lower Cretaceous Kharaib Formation in Zakum Field, Abu Dhabi, United Arab Emirates
Authors: Alsharhan A. S. 
Published: April 2008

Abstract
The Zakum oil field is an east-west plunging anticline, located in offshore Abu Dhabi, UAE. The field was discovered in 1963 by seismic survey, and came on production in 1967 at an initial rate of 50 000 bopd from the Lower Cretaceous carbonate sediments. The Zakum structure is a broad asymmetric anticlinal feature characterized by gentle dips throughout; the steepest dips occur in the north and northeast where the average dip is about 2.5°. The structure is about 45 km long and 28 km wide, and has a vertical closure in excess of 1200 ft.
At Zakum field the Lower Cretaceous Thamama Group is a thick shallow-marine carbonate sequence with an average thickness of about 2300 ft, and is divided into four formations: Shuaiba, Kharaib, Lekhwair and Habshan (in descending order). An informal reservoir-oriented classification was set up for this group. It was subdivided into six zones given a numerical notation from top to bottom (Zones I to VI).
The Kharaib Formation represent shallowing upward cycles formed in very shallow epicontinental seas. The energy level grades from low-energy subtidal to high-energy setting at or above wave base. It is characterized by dense-argillaceous pyritic bioclastic lime mudstones/wackestones, peloidal-ooidal packstones/grainstones, dolomitic limestones and thin black shale laminae.
The reservoir quality of the formation is controlled by vertical and lateral distribution of porosity, permeability and stylolites. The porosities ranges from 5 to 28%, and permeabilities from less than 1 to 100 Md. The influence of initial environment of deposition, diagenesis and petrophysical properties on the reservoir characteristics is evaluated.
Sub-salt imaging in the Gulf of Suez
Authors: Zaki R. , McDowell H. , Threadgold I. , Oldfield O. 
Published: April 2008

Abstract
Sub-salt imaging on seismic data is a serious geophysical problem affecting exploration in the Gulf of Suez. Here, thick Miocene evaporite, shale and salt sequences with salt tectonics overlie rift structures involving pre-Miocene and Miocene oil-producing formations. This paper discusses the seismic imaging problems associated with salt swells in the Gulf of Suez and presents experimental work by GUPCO that has provided a better understanding and possible solution to the imaging problem. A realistic model for the Gulf was used to generate synthetic shot records using finite difference modelling. Processing of the simulated data in conjunction with actual field data led to improved understanding of the wave propagation behaviour in the subsurface, and to a realization of the validity of the common midpoint stacking technique and post-stack depth migration.
Petroleum geology of the Niger Delta
Authors: Doust H. 
Published: April 2008

Abstract

The Niger Delta is one of the World’s largest Tertiary delta systems and an extremely prolific hydrocarbon province. It is situated on the West African continental margin at the apex of the Gulf of Guinea, which formed the site of a triple junction during continental break-up in the Cretaceous. Throughout its history, the delta has been fed by the Niger, Benue and Cross rivers, which between them drain more than 10
6
km
2
of continental lowland savannah. Its present morphology is that of a wave-dominated delta, with a smoothly seaward-convex coastline traversed by distributary channels. From apex to coast the subaerial portion stretches more than 300 km, covering an area of 75 000 km
2
. Below the Gulf of Guinea, two enormous lobes protrude a further 250 km into deeper waters.

The delta sequence comprises an upward-coarsening regressive association of Tertiary clastics up to 12 km thick. It is informally divided into three gross lithofacies: (i) marine claystones and shales of unknown thickness, at the base; (ii) alternations of sandstones, silstones and claystones, in which the sand percentage increases upwards; (iii) alluvial sands, at the top.
Delta structure and stratigraphy are intimately related, the development of each being dependant on the interplay between sediment supply and subsidence rates. The dominant subsurface structures are syn- and post- sedimentary listric normal faults which affect the main delta sequence. They die out upwards into the alluvial sands and sole out at depth near the top of the marine claystones. Major growth-fault trends cross the delta from northwest to southeast, dividing it into a number of structural and stratigraphic belts, called depobelts, which become younger towards the south. The deltaic sequence in each of these depobelts is distinct in age, so that they actually represent successive phases in the delta’s history.

Hydrocarbons have been located in all of the depobelts of the Niger Delta, in good quality sandstone reservoirs belonging to the main deltaic sequence (the ‘paralic sequence’ of common usage). Most of the larger accumulations occur in roll-over anticlines in the hanging-walls of growth faults, where they may be trapped in either dip or fault closures. In the 30 or 50 years since the first discoveries were made, approximately 4 × 10
9
m
3
of oil and an unestablished, but very substantial quantity of associated and unassociated gas have been discovered. Most fields are small, ranging up to 50 × 10
6
m
3
, though several larger fields contain recoverable reserves in excess of 80 × 10
6
m
3
. The hydrocarbons are found in multiple pay sands with relatively short columns, and adjacent fault blocks usually have independent accumulations.
Petroleum geology of the ‘Fossa Bradanica’ (foredeep of the Southern Apennine thrust belt)
Authors: Sella M. , Turci C. , Riva A. 
Published: April 2008

Abstract

The ‘Fossa Bradanica’ is located in Southern Italy, East of the Apennine mountain chain. It has undergone a complex geotectonic evolution: from platform (Mesozoic carbonates) to unstable foreland (Eocene-Miocene) and finally to foredeep of the Apennine thrust belt (Plio-Pleistocene). Petroleum exploration targets in this province are represented by: (a) Gas and oil in carbonates of the pre-Pliocene substratum. In this domain traps are only structural; (b) Gas and subordinately oil in Plio-Pleistocene sands, where structural, stratigraphic and combination traps can be found. The oils produced range in gravity from 3° to 45° API, with prevailing values of 15–20° API. Two families of oils have been recognized: oils generated by a shaly source deposited in oxygenated waters and oils derived from a carbonate source deposited in a euxinic environment. Most of the oils are classified as non-mature or marginally mature oils. Gas is mostly dry: 79% of the gas discovered in Fossa Bradanica being of biogenic, 6% of thermogenic and 15% of mixed origin. Many fields have high CO
2
concentrations (50 to 90% in the carbonates). The CO
2
content decreases, moving upwards in the stratigraphic column.
Lower Permian Rotliegend reservoir of the Southern North Sea gas province
Authors: Glennie K. W. , Provan D. M. J. 
Published: April 2008

Abstract
Rotliegend aeolian sandstone of Early Permian age forms the main producing horizon in the Southern North Sea gas province. Currently some 30–40 fields have been identified in a broad zone measuring 450 by 100 km stretching from the English coast, through the UK and Dutch sectors of the North Sea and on to The Netherlands and West Germany. North Sea field sizes range between 10–300 Bcm (0.3–10.5 TCF). Ultimate recoverable reserves for the province are estimated at some 4250 Bcm (150 TCF). The Rotliegend is underlain by Carboniferous coals and carbonaceous shales, which form the source rock, while Late Permian Zechstein evaporites form the seal. The aeolian sandstones occur interbedded with wadi sandstones and sabkha siltstones. Dune sandstones with large-scale cross bedding generally form the best reservoirs, though even here reservoir quality is highly variable. Core porosities range between 5 and 30% and permeabilities from <1 to 3000 mD. Reservoir impairment through the effects of burial diagenesis (compaction, pressure solution, clay mineral transformations and cementation) is evident in many fields. In others, the occurrence of natural fractures serves to enhance production. As a result, individual well productivities show wide variation.
A regional assessment of the intra-Carboniferous play of Northern England
Authors: Fraser A. J. , Nash D. F. , Steele R. P. , Ebdon C. C. , Fraser A. J. 
Published: April 2008

Abstract
Hydrocarbons have been produced from the Carboniferous of the East Midlands since the 1920s. Some 30 discoveries have been made to date and although field sizes are generally small, the relatively low costs have made exploration and development an attractive commercial proposition. Many of the factors which contribute to success in the East Midlands occur in other basins in Northern England but have not produced significant hydrocarbon accumulations. This paper examines the key attributes of the intra-Carboniferous play and through an integrated regional geological framework contrasts the successful East Midlands oil province with the other Carboniferous basins of Northern England.
West Siberian oil and gas superprovince
Authors: Nesterov I. I. , Salvamanov F. K. , Kontorovich A. E. , Kulakhmetov N. K. , Surkov V. S. , Trofimuk A. A. , Shpilman V. I. 
Published: April 2008

Abstract

The West Siberian oil and gas superprovince is an area of more than 2.5 × 10
6
km
2
. The province basin is filled with Cenozoic, Cretaceous and Jurassic platform sediments and, in the north and west also with Triassic and Palaeozoic rocks. The volume of sedimentary platform deposits is more than 9 × 10
6
km
3
which includes 0.75 × 10
6
km
3
of Triassic deposits and 1.3 × 10
6
km
3
of Palaeozoic deposits. The composition of the reservoir rock is terrigenous and it is inferred that Palaeozoic deposits can be represented by carbonates. Sediments accumulated in marine conditions are predominant in the region. Oil and gas pools occur both in marine and continental deposits. The total amount of discovered oil and gas in various plays is distributed as follows: 43% of pools are associated with regional caprocks, 40% with zonal caprocks and 17% with local caprocks.

The largest gas pools are mainly accumulated under regional caprocks and oil pools occur under zonal caprocks. There are no known major gas and oil pools under local caprocks. In future, discoveries of large hydrocarbon accumulations under zonal caps and an increase in discoveries of local reservoirs are confidently anticipated.
Regional studies, basin evaluations and calculations confirm the West Siberian basin to be a superprovince according to its known hydrocarbon potential. However, the regional evaluations do not meet current commercial requirements of the petroleum exploration industry, the main task of which is substantiation of potential reserves in concrete regional, zonal and local layers, ranging in thickness from 10 to 20 m instead of thick formations. Such needs call for development of modern methods such as remote-sensing to assist in oil-and-gas potential predictive exploration. Such methods must later be further developed to identify thicker oil-and-gas reservoirs of several square kilometres in size with less than 5–10 m bed thickness.

The West Siberia basin is being developed very rapidly. It took only eight years from the first small gas field discovery (1953) to the first significant oil production. Since the first oil pipeline installation in 1964 an average of 848 × 10
3
m
3
per day of oil and gas has been produced, and in 1987 production had reached 2.38 × 10
6
m
3
per day.
A palaeomagnetic study of two Precambrian-Cambrian dyke swarms from the Armorican Massif
Authors: Taylor G. K. 
Published: April 2008

Abstract
The palaeomagnetic analysis of two dolerite dyke swarms, metamorphosed during the late stages of the Cadomian Orogeny, is reported. The Vazon dyke swarm of Guernsey, Channel Islands, has yielded a characteristic component of magnetization (D = 199°, I = 48°, a95 = 12°, n = 8 dykes) which is dual polarity, while six other sampled dykes record intermediate field directions. The magnetization is interpreted as being acquired shortly after dyke emplacement and the corresponding palaeomagnetic pole (lat, 9°S; long, 340°E) is in good agreement with previously determined Cambrian poles from Armorica. An emplacement age for the dykes of 560–540 Ma is therefore suggested on the basis of the radiometric ages assigned to these previously published results. The Dahouet dyke swarm of the Baie de St Brieuc was also sampled and has yielded two remanence directions (A and B) common to most sites. The A remanence (D = 198°, I = 2°, a95 = 7°, n = 7 dykes) yields a pole (lat, 37°S; long, 334°) which is interpreted as being an overprint acquired during the Variscan Orogeny and is consistent with Carboniferous results. The B remanence (D = 202°, I = 34°, A95 = 8°, N = 6 dykes) and its corresponding pole (lat, 20°S; long, 335°E) is more ambiguous in its interpretation as it lies between the known Cambrian APW path and a diffuse area of poles associated with overprinting during the Variscan orogeny. A tentative interpretation of this remanence as being Cambrian in origin is consistent with the suggestion that both dyke swarms were emplaced relatively closely in time, as suggested by their similar geological settings.
Cadomian tectonics in northern Brittany
Authors: Brun J. P. , Balé P. 
Published: April 2008

Abstract
Major Cadomian structures of northern Brittany, France, are reviewed from the Léon region in the west to the Mancellian region in the east. The whole region is dominated by a NE trending structural grain. From the NW to the SE three main tectonic units have been distinguished: (a) the Trégor volcanic and plutonic belt; (b) the Baie de St Brieuc metamorphic-thrust belt and (c) the Guingamp-St Malo high temperature belt. Principal strain trajectories, finite strain measurements, shear criteria and geochronological data are used to establish a kinematic model of Cadomian deformation. The three units have been thrust over each other and towards the SW at 590–580 Ma. An extrapolation at a regional scale is made using available geophysical data (gravimetry, magnetism and SWAT seismic lines). A new model for oblique thrusting toward the SW along an ENE trending plate boundary is proposed.
Cadomian strike-slip tectonics in NE Brittany
Authors: Treloar P. J. , Strachan R. A. 
Published: April 2008

Abstract

The Precambrian basement of NE Brittany contains a number of NNE-trending migmatite belts of Cadomian (
c.
540 Ma) age. These are heterogeneously reworked by subvertical, ductile shear zones which occur both within individual migmatite belts, and along their boundaries with low-grade Brioverian metasediments. The shear zones are characterized by blastomylonitic fabrics, penetrative sub-horizontal or gently-plunging stretching lineations, and shear criteria which indicate a consistent subhorizontal, sinistral strike slip sense of movement. The migmatite belts, and the greenschist facies Brioverian metasediments imbricated with them along the strike-slip zones, form the St Malo Terrane deformed at
c.
540 Ma. This terrane is bounded to the NW and SE by two lithologically and metamorphically distinct terranes, the St Brieuc and Mancellian terranes respectively. Boundaries between the three terranes are inferred to be crustal scale sinistral strike-slip zones. The St Brieuc Terrane was also deformed and metamorphosed in a transpressive setting either prior to or during amalgamation with the St Malo Terrane at
c
. 540 Ma. The Cadomian belt of northern Brittany is interpreted as a sinistrally transpressive strike-slip belt related to deformation in the hanging-wall of an oblique subduction zone located to the north, and across which there is likely to have been substantial lateral displacement.
Late Precambrian foliated plutonic complexes of the Channel Islands and La Hague: early Cadomian plutonism
Authors: Power G. M. , Brewer T. S. , Brown M. , Gibbons W. 
Published: April 2008

Abstract
The foliated granitic rocks of the Channel Islands and La Hague are predominantly quartz dioritic in composition with some granodiorite and minor granite. Their variably developed foliation is of post-solidification origin. Greenschist facies metamorphism affects some rocks as does patchy very low grade metamorphism. Field relations show that the granites are younger than the pre-Icartian metasedimentary gneisses and older than the post-Cadomian igneous complexes but there are no contacts with the Brioverian Supergroup. Isotopic age data are very unsatisfactory but suggest a possible age span of 700–580 Ma.

168 geochemical analyses show that the rocks are calc-alkaline, the majority are metaluminous with Na
2
O greater than K
2
O and that they have the characteristics of normal volcanic arc granites. Trace element plots show that there are differences in the suites of analyses from Guernsey, Sark, Alderney and La Hague reflecting minor differences in their source materials. REE plots for 34 rocks all show strong fractionation of LREEs regardless of rock composition and most show HREE depletions. These patterns are interpreted as originating in the source and suggest an origin by high pressure melting of predominantly basaltic compositions.

The evidence supports the model of Dupret
et al.
(1990) for a major period of Cadomian crustal growth by progressive cratonization of a basin and arc system but extension of the model on a more regional basis is difficult because of the uncertain status of neighbouring terranes.