bluuebunny/crossref_metadata_2025_split huggingface dataset:
PALAEOZOIC PRE‐SALT SEDIMETNS IN THE PRECASPIAN PETROLIFEROUS PRPVINCE
Authors: Nevolin N.V. , Fedorov D.L. 
Published: December 2007

The PreCaspian (North Caspian) Basin is located on the SE margin of the Russian Platform, and extends as far south as the north coast of the intra‐continental Caspian Sea. Regional surface elevations here are as much as 24 m below sea‐level. The basin is one of the World's deepest, with basin‐fill sediments exceeding 20 km in thickness. The Proterozoic section, the pre‐slat Palaeozoic section, and the Upper Permian (slat‐bearing) interval are all about 5‐km thick, although as a result of salt movements, the salt‐bearing sequence may be thicker. The basin has a roughly oval outline, and is 900‐km wide, 600‐km is length, and covers around 500,000 sq. km. It is divided into the Central and SE Sub‐basins by the approximately east‐west trending Astrakhan‐Aktyubinsk system of basement highs. A series of massive carbonate build‐ups rim the basin margins.This paper considers the sturcture and hydorcarbons potential of the pre‐salt (Palaeozoic) sedimentary section, whose regional prospectivity has been confirmed by the discovery of a series of “giant” oil, gas and condensate fields, including Tengiz, Karachaganak and Astrakhan. Hydrocarbons in these fields are sourced and reservoired in massive organicrich carbonates of Palaeozoic age.
A NEW FACIES MODEL FOR THE MISOA FORMATION (EOCENE), VENEZUELA'S MAIN OIL RESERVOIR
Authors: Higgs R. 
Published: December 2007

The Misoa Formation has produced an estimated 13 billion barrels of oil, and contains a further 11 billion barrels of proved remaining reserves. The total represents approximately 50% of the proved reserves of the Maracaibo Basin, Venezuela's most productive region. In such a prolific formation, application of an inappropriate facies model to exploration and development can have huge financial consequences, in terms of misplaced wells, missed pools and miscalculated reserves.A deltaic depositional model has been used for exploration and development drilling in the Misoa Formation since the 1960s. However, this deltaic interpretation is doubtful due to the lack of in situ coal beds, palaeosols and other evidence for emergence diagnostic of delta plains. An alternative, tidal‐shelf model is proposed here.
OCEANIC METHANE HYDRATES: A “FRONTIER” GAS RESOURCE
Authors: Max M. D. , Lowrie A. 
Published: December 2007

Methane hydrates are ice‐like compounds consisting of natural gas (mainly methane) and water, whose crystal structure effectively compresses the methane: each cubic metre of hydrate can yield over 150 cu.m of methane. Hydrates “cement” sediments and impart considerable mechanical strength; they fill porosity and restrict permeability. Both biogenic and thermogenic methane have been recovered from hydrates.Hydrates occur in permafrost regions (including continental shelves), and are stable in ocean‐floor sediments below water depths of about 400 m in the “Hydrate Stability Zone” (HSZ). This is a surface‐parallel zone of thermodynamic equilibrium that extends down from the sediment surface to a depth determined by temperature, pressure and local heat flow. Methane and water are stable below the HSZ.Although the economic recovery of hydrates has taken place in Arctic regions, oceanic hydrates offer far greater potential as an energy resource. A variety of traps for methane gas can be formed by oceanic hydrates. In addition to the gas within the hydrates themselves, simple gas traps in closures beneath the HSZ in the vicinity of bathymetric highs, and complex traps involving both hydrate and structural/stratigraphic components, have been observed.It has been estimated that at least twice as much combustible carbon occurs associated with methane hydrates as in all other fossil fuels on Earth. The evaluation of methane in, and associated with, oceanic hydrates therefore constitutes a major energy exploration frontier.
SUBSURFACE TRIASSIC SEDIMENTS IN JORDAN: STRATIGRAPHIC AND DEPOSITIONAL CHARACTERISTICS, AND HYDROCARBON POTENTIAL
Authors: Shinaq R. 
Published: December 2007

Unconformity surfaces have been used to divide the subsurface Triassic sediments of Jordan into five sequences. These sequences show a gradual transition from fluviatile‐deltaic sedimentation during the Permian, to mixed sedimentation of sandstones, silty shales and claystones together with shallow‐water carbonates from the Scythian to the end of the Ladinian. Anhydritic dolomites and evaporites became prevalent during the Carnian‐Norian.Isopach and facies maps for these sequences show that the Triassic sediments of Jordan were deposited in a set of environments which range from fluviatile‐deltaic for the coarse‐grained clastics; to restricted shelf lagoons and tidal‐flat settings for the finegrained clastics; to a shallow carbonate shelf for the fossiliferous carbonates; and restricted shelf lagoons, sabkhas and salinas for the carbonate‐evaporite sequence.
THE CRETACEOUS SERIES IN THE CHAD BASIN, NE NIGERIA: SOURCE ROCK POTENTIAL AND THERMAL MATURITY
Authors: Olugbemiro R. O. , Ligouis B. , Abaa S. I. 
Published: December 2007

The Chad Basin is the largest intracratonic basin in Africa, and one‐tenth of its surface area lies in NE Nigeria. Thermal maturation (mean vitrinite reflectance) and organic‐geochemical (Rock‐Eval pyrolysis) studies have been carried out on Cretaceous shales from the Bima Formation, Gongila Formation and Fika Shale Formation. Samples were derived from the Kanadi and Albarka exploration wells, which are located about 76 km apart in the Nigerian sector of the Chad Basin.The organic matter is predominantly gas prone (Type III kerogen). Its thermal maturity, assessed from vitrinite reflectance and Tmax, indicates that the Gongila Formation and the Bima Formation are within the “oil window”, while the Fika Shale Formation is only partly within it. The “oil window”, deduced from the mean vitrinite reflectance profile, occurs between 1,270m ‐ 2,600m in the Kanadi well, and between 1,985m ‐3,690m in the Albarka well, with respective maturation gradients of 0.52 log%Rm/km (0.41%Rm/km) and 0.41 log%Rm/km (0.34%Rm/km). Eroded thicknesses amount to about 1 km.The upper part of the Fika Shale Formation has the best source‐rock potential in terms of its organic carbon content, but has low thermal maturity. The Gongila Formation is poor in organic carbon and its hydrocarbon potential may already have been exhausted. The Bima Formation is well within the “oil window”, but has only limited potential as a source rock, because of the presence of clastic and inert materials. The potential for gas accumulations, however, exists.
PREHISTORIC, ANCIENT AND MEDIAEVAL OCCURRENCES AND USES OF HYDROCARBONS IN THE GREATER MIDDLE EAST REGION
Authors: Beydoun Z. R. 
Published: December 2007

THE ARABIAN PLATE, and neighbouring parts of Egypt, Turkey, Iran and the southern Caucasus, includes within its boundaries numerous active hydrocarbon seepages. Their origin is related to the beginning of the current tectonic regime, which commenced in Oligocene‐Miocene times. The culmination of Alpine tectonics around the northern edge of this region gave rise to stress regimes that deformed the plate margins and ruptured the integrity of hydrocarbon traps and seals. This resulted in the many seepages recorded throughout the Arabian Plate and adjoining areas to the north.Extensional plate margins bound the Arabian Plate to the SW and south; transform margins are on the west and SE; and collisional margins on the north and NE. It is along these (or along splays from them) that most of the major active seepages occur.The collisional regimes along the Taurus and Zagros foldbelts in the north and NE caused considerable subsurface movement of Cretaceous and older hydrocarbons and their migration and remigration. As folding intensified, inefficient seals were ruptured, and very large volumes of hydrocarbons migrated vertically upwards until trapped close to the surface in vast carbonate reservoirs beneath the regionally‐efficient evaporite seals provided by the Miocene Lower Fars/Gachsaran Formations. Where these seals were thin, poorly‐developed or eroded, major seepages developed, and huge volumes of hydrocarbons may have escaped to the surface. Indeed, there is speculation whether the Zagros foreland basin, overprinted onto the vast NE Arabian Shelf as a result of the Arabian/Eurasian Alpine collision, has not lost more hydrocarbons than it has retained through this process (Beydoun et al., 1992).
PETROLEUM GEOLOGY OF THE TARIM BASIN, NW CHINA: RECENT ADVANCES
Authors: Changlin Gao , Deliao Ye 
Published: December 2007

The Tarim Basin is located in the Xijiang Uygur Autonomous Region of NW China, and covers an area of about 560,000 sq. km. At dawn on September 22nd, 1984, Well Shashen‐2 (drilled by a team from the Ministry of Geology and Mineral Resources) blew‐out spectacularly when it penetrated Ordovician dolomites at a depth of 5,392m. The blow‐out marked the discovery of a highly‐productive oil‐ and gasfield, from which daily output has reached 1,000 m3 oil and 2 MM (million) m3 gas.Over the last decade or so, 560,000 km of gravimetric surveys (scale l.106) and 338,000 km of airborne magnetic surveys (1:200,000) have been completed. Some 200,000 line‐km of 2‐D seismic profiles and 10,000 km of 3‐D surveys have also been carried out, and more than 200 wells have been drilled. Twenty‐two oilfields producing from ten stratigraphic intervals, four of which have reserves of more than 100 million tons, have been discovered or explored, indicating that the future prospects for petroleum exploration in the basin are very favourable (Kang and Huang, 1992; Jia, 1991a; 1991b). Annual production in the Tarim Basin reached 2,300,000 t in 1995 (Kang et al, 1996).
PETROLEUM GEOLOGY: TWO DECADES OF CHANGE
Authors: Hobson G.D. 
Published: December 2007

SOME TWENTY YEARS AGO, Dr E.N. Tiratsoo (whom I had known since the mid‐1930s) visited me at the Royal School of Mines, and told me of his plans to set up a new “journal of petroleum geology”.The Journal has now reached its twentieth volume.Thinking especially about the United Kingdom, the past twenty years have also seen the publication of the proceedings of four major conferences held in London, on the geological results of North Sea oil exploration, as well as other similarly‐based books from Norwegian sources. Somewhat earlier, the European Branch of the Organic Geochemistry Group of the Geochemical Society was formed. A European geophysics‐based society has also appeared, and a vigorous petroleum group was formed in the Geological Society in 1980. There has been a proliferation in literature (both books and journals) dealing with the geology of oil and gas. It is against this background that the Journal of Petroleum Geology has succeeded.
BURIAL AND THERMAL HISTORY MODELLING OF THE GAFSA‐METLAOUI INTRACONTINENTAL BASIN (SOUTHERN TUNISIA): IMPLICATIONS FOR PETROLEUM EXPLORATION
Authors: Hlaiem A. , Biju‐Duval B. , Vially R. , Laatar E. , M'Rabet A. 
Published: December 2007

This paper is a contribution to the evaluation of the petroleum potential of southern Tunisia. Its purpose is to report on the burial and thermal histories of the Gafsa‐Metlaoui Basin and the surrounding area in the time interval between the Triassic and the Quaternary. We have used a one‐dimensional deterministic model, which enabled us to integrate the burial and thermal influences on potential source rocks with kinetic parameters, in order to define the timing of hydrocarbon generation and expulsion in relation to the main structural episodes in the study area.The Mesozoic burial history of this basin is characterized by two principal phases of rifting, each of which was followed by a brief episode of thermal (post‐rift) subsidence. The first phase occurred during the Triassic and Jurassic, and was related to the breakup of Gondwana; the second phase occurred during the Cretaceous and Early Tertiary, and was related to the opening of the neo‐Tethyan Mediterranean Sea. Geothermal studies of this basin have allowed us to determine an average surface heat flow of 60 m W/sq. m and an average geothermal gradient of about 25.5d̀C/km. Middle Jurassic source rocks expelled oil from the Cenomanian (about 100 million years ago) to the Quaternary.
RELATIONSHIPS BETWEEN HYDROCARBON GENERATION, COAL TYPE AND RANK FOR MIDDLE EOCENE COALS, BULLER COALFIELD, NEW ZEALAND
Authors: Norgate C. M. , Boreham C. J. , Kamp P. J. J. , Newman J. 
Published: December 2007

The Buller Coalfield in the northern portion of the Paparoa Trough (NW South Island, New Zealand) contains a middle Eocene bituminous coal‐bearing succession that exhibits marked variations in both coal rank and type. The across‐basin rank changes result from differential late Palaeogene subsidence of the Paparoa Trough and subsequent inversion. Superimposed upon coalification trends are down‐seam variations in coal type, evidenced by isorank variation in conventional chemical parameters. These type variations are not a consequence of changes in maceral group proportions, which are dominated by vitrinite.Forty‐eight coal samples from fifteen drillholes through the Brunner Coal Measures have been examined for vitrinite reflectance, proximate analysis, specific energy, and sulphur content. Total Organic Carbon (TOC), Rock‐Eval properties and the bulk composition of the bitumen were also determined.All the coals analysed lie within the high volatile bituminous B to medium volatile bituminous coalification stages. Variation in analytical properties within this suite, and more specifically within serial samples, provides insights into the nature of the organic matter comprising the coals. While TOC varies systematically with ash content, reflecting proximity of the depositional mires to fluvial systems, values increase with rank (68–86% ash free). The Hydrogen Index (HI) decreases from 334 to 190 mg hydrocarbons/g TOC over a range of 429 to 470 d̀C Tmax, analogous to the volatile matter content and vitrinite reflectance, respectively. The more perhydrous coal samples at a given rank are characterised by depressed Tmax/vitrinite reflectance and elevated Hi/volatile matter contents.Bitumen and sulphur contents are not the primary control onperhydrous characteristics. The bitumen content crudely corresponds to the S1 peak plus the initial portion of the S2 peak liberated under low temperatures during Rock‐Eval pyrolysis; however, the bulk of the generative potential is associated with the residual kerogen fraction. Suggate (S) Rank and maximum palaeotemperature appear to be the best indicators of coal rank.A period of significant hydrocarbon generation and release begins at Tmax∼440d̀C for the Buller coals. The main oil “window” is defined by the interval 440–455d̀C Tmax or 0.8–1.1% vitrinite reflectance (Romax), and by correlation to maximum palaeo‐temperatures, 125–155d̀C. This is further substantiated by mass balance considerations, which indicate that hydrocarbon generation (Petroleum Generation Index (PG1) > 0.1) was occurring in the coals at a maturity level of O. 7–0.9 % Romax (Tmax 440–444 d̀C) with an increase in PGI between ∼0.9 and 1.1% Romax (∼Tmax 445–455 d̀C). Between PGI 0.1 and 0.4, the expulsion efficiency rapidly increased, presumably due to generation and expulsion of the bulk of the oil.
RIPHEAN HYDROCARBON RESERVOIRS OF THE YURUBCHEN‐TOKHOM ZONE, LENA‐TUNGUSKA PROVINCE, NE RUSSIA
Authors: Kuznetsov V. G. 
Published: December 2007

The Siberian Craton covers an area of about 4.5 million sq. km in northern Russia, of which up to 3.5 million sq. km may be prospective for hydrocarbons. The craton was consolidated in the Early Proterozoic, and above the basement granitoids and gneisses is a variable thickness of sedimentary strata ranging in age from Riphean (Middle‐Late Proterozoic) to Quaternary.Reservoir rocks are known to occur in the interval between the Middle Riphean and the Upper Cretaceous; those of Riphean age have produced oil commercially since 1973. Geochemical data indicate that the oil within the Riphean reservoir rocks was generated by source rocks of Riphean age. Riphean reservoir rocks include both carbonates and siliciclastics, but commercial volumes of hydrocarbons have only been discovered within the carbonates.Three petroleum‐bearing “provinces” or megabasins are located on the Siberian Craton: Lena‐Tunguska, Lena‐Vilyuyand Yenisey‐Anabar. The Yurubchen‐Tokhom Zone in Lena‐Tunguska Province is potentially the most important oil‐producing area in the craton, and comprises a number of distinct fields. Reservoir rocks here consist principally of thick Riphean dolomites. Both the development of reservoir characteristics within these dolomites and the formation of stratigraphic traps are related to an episode of emergence and karstification at the end of the Riphean.
THE LOWER CRETACEOUS PETROLEUM SYSTEM IN NE CHINA
Authors: Lirong Dou 
Published: December 2007

NE China is situated on the pre‐Mesozoic folded belt between the Siberian and Sino‐Korean Cratons. Beginning in the Late Jurassic, the oceanic Izanagi Plate was subducted NW wards beneath the Eurasian Plate, resulting in a change in the structural setting from north‐south compression to NW‐SE extension leading to intracontinental rifting. The Early Cretaceous marked a peak in the development of syn‐rift lacustrine basins, and there are about 200 rift depressions in the study area. Left‐lateral strike‐slip activity on the NE‐SW oriented Tan‐Lu Fault, and a change in the rate and direction of subduction of the Izanagi Plate, ended the syn‐rift stage. Thick, post‐rift lacustrine sequences only developed in the Songliao Basin, and today form source and reservoir rocks at the “giant” Daqing oilfield.Gas‐source rock correlations in the Lower Cretaceous strata of the Songliao Basin, and oil‐source rock correlations in the Erlian and other basins have indicated that all the hydrocarbons were generated in, and have migrated from, Lower Cretaceous source rocks. The Lower Cretaceous syn‐rift sequence has been proved to be a known petroleum system. Twenty‐two oil‐ and gasfields have been found in six basins. Each rift depression constitutes an independent petroleum system, and plays can be divided into four types (boundary fault; deep‐sag; central flexural; and flexural margin), of which the central flexural play is the most prospective. It is anticipated that these small rift basins will become targets for future exploration.
TECTONICS AND SEDIMENTATION WITHIN A MESSINIAN FOREDEEP IN THE CENTRAL APENNINES, ITALY
Authors: Bigi S. , Calamita F. , Cello G. , Centamore E. , Deiana G. , Paltrinieri W. , Pierantoni P. P. , Ridolfi M. 
Published: December 2007

The Marche‐Abruzzi thrust system is part of the Central Apennine fold‐and‐thrust belt of mainland Italy. Our study area covers the SE portion of the Umbria‐Marche‐Abruzzi region and the northern part of the Gran Sasso Mountains. A thick pile of turbidites is exposed in this area; they were deposited within a Messinian foredeep in front of the evolving fold‐and‐thrust belt. We have used regional structural interpretations together with unpublished well‐log and seismic data to construct a cross‐section across the external portion of the thrust system.Our work suggests that: (i) deformation of the sediments in the Messinian foredeep began shortly after their deposition, and continued until the late Pliocene; (ii) the restored (pre‐deformation) width of the basin was approximately twice that of the present‐day basin, and the depocentre migrated eastwards at a rate of about 4 cm/yr; (iii) the geometry and physiography of the Messinian foredeep were controlled by a number of longitudinal and transverse structural features which may be related to foreland ramp activity or to differential flexuring of the Apulian lithosphere, respectively.
THE DIVERSITY OF LATE NEOGENE SEDIMENTARY BASINS GENERATED BY WRENCH FAULTING IN THE EASTERN BETIC CORDILLERA, SE SPAIN
Authors: Montenat C. , D'Estevou Ph. Ott 
Published: December 2007

In this paper, we review the types of sedimentary basins which are generated by wrench faulting with particular reference to the Late Neogene Eastern Betic Shear Zone, a well‐documented segment of the Trans‐Alboran Shear Zone. The general characteristics of this wrench “corridor” are described, including the role of inherited structures. The diversity of basin types is emphasised, as is the coexistence of basins which developed under compressional or extensional regimes.Pull‐apart basins do not appear to be the most widespread type of basin in the Eastern Betic Shear Zone. Rather, compressional “groove‐shaped synclines” which run parallel to master strike‐slip faults (regardless of their orientation or direction of movement) are more typical structures. They are characterised by intense synsedimentary deformation and reworking of sediments, depositional processes being dominated by gravity flows. The basins are relatively short‐lived and generally undergo structural inversion. Sedimentary basins also form in extensional areas, most significantly in the triangular zones which occupy the extensional quadrant of a pseudo‐ conjugate strike‐slip fault system.In the Eastern Betics, it appears that compressional basins are more efficient than extensional basins in terms of their subsidence and sedimentation rates, the thickness of the clastic fill, and the intensity of synsedimentary deformation. Compressional basins may therefore be the more favourable with respect to potential hydrocarbon accumulations.