bluuebunny/crossref_metadata_2025_split huggingface dataset:
GEOLOGY OF THE NORTH FALKLAND BASIN
Authors: Richards P. C. , Fannin N. G. T. 
Published: December 2007

The North Falkland Basin comprises two main structural elements: a north‐south trending graben, termed the North Falkland Graben; and a set of subsidiary basins to the west of this graben, also controlled by north‐south trending extensional faults, but which have been constrained by NW‐SE oriented, reactivated Palaeozoic thrust faults. The North Falkland Graben can be divided, in its northern part, into western and eastern depocentres, which are separated by a north‐south trending intra‐graben high.Early syn‐rift, late syn‐rift, early post‐rift and late post‐rift successions have been identified within the North Falkland Graben. The subsidiary grabens to the west probably contain only early syn‐rift deposits overlain by late post‐rift sediments: these basins were possibly uplifted along the shoulder of the main graben during its mainphase of extension in the Late Jurassic to Early Cretaceous.Although predictions of sediment‐infill type have only been made by regional correlations and seismic facies analysis in these undrilled basins, two major deltaic units of early post‐rift age are confidently inferred to be present in the North Falkland Graben, and to pass laterally into possible anaerobic mudstones of source‐rock quality.This petroleum system will soon be tested by a number of oil companies sharing production licences for the entire axial area of the North Falkland Graben.
THE STRATIGRAPHY AND HYDROCARBON POTENTIAL OF THE RIPHEAN‐VENDIAN (MIDDLE‐LATE PROTEROZOIC) SUCCESSION ON THE RUSSIAN PLATFORM
Authors: Fedorov D. L. 
Published: December 2007

Recent studies of the Riphean‐ Venetian succession of the Russian Platform have indicated that geological factors favourable for the occurrence of hydrocarbons may be present. These factors include substantial thicknesses of sedimentary rocks; the presence of reservoir rocks and seals, together with source rocks containing sapropelic organic matter; and the occurrence of oil shows, indicating that hydrocarbons have been generated. These factors, coupled with a favourable geographic and economic environment, contrast with the low level of exploration in the area.Following an interval of many years, geological studies in the central parts of the Russian Platform recommenced in the 1990s. A network of seismic lines has been shot, and has provided data on deeply‐buried structures in this area, and also on the nature of the lowermost parts of the sedimentary cover. The latter is represented by Proterozoic (Riphean and Vendian) strata, whose petroleum prospectivity on the Russian Platform may be comparable to that of the Siberian Platform.Both the Riphean succession, which was deposited in extensive fault‐bound grabens, and the unconformably overlying Vendian, include very thick sandstones and clay stones. Individual units can be traced on seismic records over distances of tens or even hundreds of km. There is evidence that these sedimentary rocks, particularly those of Vendian age, are of shallow‐ and deep‐marine origin. The high content of sapropelic organic matter which has been recorded in individual units, together with the presence of oil shows, indicate that hydrocarbons have been generated within the Proterozoic interval. Both previous studies in this region, and the more recently‐obtained data, have encouraged exploration to be continued, and have led to the identification of specific targets.
RELATIONS BETWEEN DEPTH OF BURIAL, VITRINITE REFLECTANCE AND GEOTHERMAL GRADIENT
Authors: Suggate R. P. 
Published: December 2007

In wells where the drilled sequence is now at its maximum temperature, relations between depth and vitrinite reflectance show three segments: an upper segment with a linear gradient from 0.2–0.25% Ro at the surface to 0.6–0.7% Ro; a middle segment in which reflectance increases rapidly to c. 1.0% R; and a lower segment in which the gradient is again linear but reflectance increases more rapidly than in the upper segment. With a linear scale for depth, the inflection represented by the short middle segment tends to be obscured by the adoption by some authors of a log scale for reflectance.The depth to the inflection systematically increases with decrease in geothermal gradient, allowing the development of a general diagram relating depth, reflectance and geothermal gradient. In wells where erosion is probable either at the present‐day surface or at an unconformity, the general diagram can be used to estimate former maximum depths of burial and paleogeothermal gradients. These estimates, together with the presence of the inflection in the depth/reflectance relation, should be part of the input into modelling of the thermal history of sedimentary basins when reflectance is used in the model. The inflection is the result of the changing chemistry of vitrinite during oil generation, and the contrast between the depth/reflectance gradients above and below the inflection comparably reflects the contrast in vitrinite chemistry.
PETROLEUM GENERATION IN THE UKRAINIAN EXTERNAL CARPATHIANS AND THE ADJACENT FORELAND
Authors: Koltun Yu. , Espitalié J. , Kotarba M. , Roure F. , Ellouz N. , Kosakowski P. 
Published: December 2007

Major hydrocarbon accumulations are located in western Ukraine within the Mesozoic‐Cenozoic flysch sequence in the frontal parts of the External Carpathians, and in the adjacent autochthonous foreland. The accumulations occur in three different structural settings: in the Carpathian flysch belt; in the pre‐Neogene foreland autochthon; and in Miocene foredeep molasse. The petroleum potential of organic‐rich rocks belonging to a number of different sedimentary cycles and tectonic units was studied by Rock‐Eval pyrolysis.Two significant organic‐rich units, both with a basin‐scale distribution, occur within the External Carpathians: (i) a unit comprising the Lower Cretaceous Shypot and Spas Formations; and (ii) the Oligocene‐Lower Miocene Menilite Formation. The Menilite Formation includes the principal source rocks in this area, although Lower Cretaceous source rocks may also have generated hydrocarbons. Thermal maturation of the flysch and consequent petroleum generation resulted mainly from tectonic burial during Miocene overthrusting. In the external parts of the Carpathian Flysch Belt, oil generation in the Menilite Formation begins at a depth of around 4.2 km and ceases at around 6 km. In more internal tectonic units, a “frozen oil kitchen” occurs at shallower depths, indicating an increasing amount of tectonic uplift and erosion.The autochthonous foreland is part of the SW margin of the East European Platform, and is partially overthrust by the Carpathian orogen. Rocks belonging to several different sedimentary cycles are present here. Pre‐Mesozoic rocks in the foreland are overmature, at least within the central and SE parts of the study area. Petroleum accumulations are therefore most probably confined to the Mesozoic‐Cenozoic sedimentary cover, within which the Middle Jurassic Kokhanivka Formation has the highest generation potential.
HYDROCARBON POTENTIAL OF THE INTRACRATONIC OGADEN BASIN, SE ETHIOPIA
Authors: Hunegnaw A. , Sage L. , Gonnard R. 
Published: December 2007

The intracratonic Ogaden Basin, which covers one‐third of the Democratic Republic of Ethiopia, developed in response to a tri‐radial rift system which was active during Late Palaeozoic to Mesozoic times. Thick Permian to Cretaceous sequences, which principally occur in the SW and central parts of the basin, have proved petroleum potential. Reservoir rocks are mainly Permian to Lower Jurassic sandstones (the Calub and Adigrat Formations), and Callovian limestones (the Upper Hamanlei Formation). Source rocks are organic‐rich Permian, Lower Jurassic and Callovian‐Oxfordian lacustrine and marine shales.This paper reviews the petroleum geology of the Ogaden Basin and assesses potential exploration targets. Successful exploration can be expected in view of the recent discovery of the Calub gas and gas/condensate field, and the occurrence of significant shows in the centre of the basin together with seeps along the margin.
ABNORMAL ORGANIC‐MATTER MATURATION IN THE YINGGEHAI BASIN, SOUTH CHINA SEA: IMPLICATIONS FOR HYDROCARBON EXPULSION AND FLUID MIGRATION FROM OVERPRESSURED SYSTEMS
Authors: Hao Fang , Li Sitian , Dong Weiliang , Hu Zhongliang , Huang Baojia 
Published: December 2007

Three superimposed pressure systems are present in the Yinggehai Basin, South China Sea. A number of commercial, thermogenic gas accumulations have been found in an area in which shale diapirs occur. Because the reservoir intervals are shallow and very young, they must have filled with gas rapidly. The thick (up to 17 km) Tertiary and Quaternary sedimentary succession is dominated by shales, and is not disrupted by major faulting in the study area, a factor which seems to have had an important effect on both hydrocarbon generation and fluid migration.Organic‐matter maturation in the deepest, most overpressured compartment has been significantly retarded as a result of the combined effects of excess pressure, the presence of large volumes of water, and the retention of generated hydrocarbons. This retardation is indicated by both kerogen‐related parameters (vitrinite reflectance and Rock‐Eval Tmax); and also by parameters based on the analysis of soluble organic matter (such as the C15+ hydrocarbon content, and the concentration of isoprenoid hydrocarbons relative to adjacent normal alkanes).In contrast to this, organic‐matter maturation in shallow, normally‐pressured strata in the diapiric area has been enhanced by hydrothermal fluid flow, which is clearly not topography‐driven in origin. As a result, the hydrocarbon generation “window” in the basin is considerably wider than could be expected from traditional geochemical modelling.These two unusual and contrasting anomalies in organic‐matter maturation, together with other lines of evidence, suggest that there was a closed fluid system in the overpressured compartment until shale diapirs developed. The diapirs developed as a result of the intense overpressuring, and their growth was triggered by regional extensional stresses. They served as conduits through which fluids (both water and hydrocarbons) retained in the closed system could rapidly migrate. Fluid migration led to the modification of the thermal regime and the enhancement of organic maturation, as well as the accumulation of commercial volumes of gas in a relatively short time interval.
COMPRESSIVE NEOGENE‐QUATERNARY TECTONICS IN THE HINTERLAND AREA OF THE NORTHERN APENNINES
Authors: Boccaletti M. , Bonini M. , Moratti G. , Sani F. 
Published: December 2007

The NW‐SE trending Northern Apennine Mountains consist of a series of allochthonous units which were thrust generally to the NE during Neogene crustal shortening, in the direction of a foreland basin to the east andNE. On the hinterland (internal) side of this fold‐and‐thrust belt, a series of small‐scale sedimentary basins developed from the late Miocene and were deformed at the same time. The late Tortonian‐Pleistocene evolution of the Northern Apennines has previously been considered by most authors in terms of a classical model of a NE‐migrating compressional front, which was followed in time and space by a hinterland extensional regime related to the development of the Tyrrhenian Basin.This paper presents new structural data from both the external parts of the Northern Apennines and the late Tortonian‐Pleistocene basins located in the internal sector. In the Northern Apennine thrust belt, reactivation and out‐of‐sequence geometries for the thrust faults have been recorded. In the hinterland basins, compressional deformation has been documented and is usually associated with thrust ramps and regional unconformities. The timing of both thrust reactivation and of the major compressional phases affecting the hinterland basins is closely correlated with periods of magmatic quiescence, and with compressional phases detected in the external margin of the Northern Apennines (the Padan‐Adriatic foredeep).Data presented in this paper indicate that compressional deformation has played a major role in the recent evolution of the Northern Apennines. The mechanism envisaged to explain this tectonic framework takes account of the piggy‐back emplacement of basement thrusts from internal to external sectors, which occurred in post‐Serravallian time. Activity on basement thrusts may have caused reactivation of thrusts in the internal cover sequence, giving rise to out‐of‐sequence geometries and controlling the development and/or deformation of the hinterland basins. This type of structural evolution has resulted in a complex geometry for the thrust sheets, and this must be taken into consideration during re‐interpretation of the structure of the Northern Apennines. It may also have important implications for petroleum exploration.
NEOGENE SEDIMENTATION AND TECTONIC‐EUSTATIC CONTROL OF THE MALAGA BASIN, SOUTH SPAIN
Authors: López‐Garrido A. C. , de Galdeano C. Sanz 
Published: December 2007

Cenozoic sediments in the Málaga area range from the lower Miocene or uppermost Oligocene to the Quaternary. Tortonian (late Miocene) ‐ Quaternary sediments correspond to the fill of the Málaga Basin. Older sediments were laid down before the basin had acquired its present‐day structure. A number of important stratigraphic discontinuities are present within the Cenozoic succession.In the late Oligocene‐early Miocene, sandy sediments and conglomerates assigned to the Alozaina Formation, derived from the basement Malaguide Complex, were deposited in shallow‐marine conditions contemporaneously with deformation in the Internal Zones of the Betic Cordillera. The overlying transgressive Viñuela Formation (late Aquitanian‐early Burdigalian) was deposited in deep‐marine conditions which extended over a somewhat wider area than that occupied by the Málaga Basin. Sedimentation was dominated by classical turbidity currents and high‐density mass flows.Sediments of middle Miocene age are absent. Marine sedimentation resumed in the Tortonian as a consequence of a eustatic sea‐level rise. There was clear tectonic control on the depositional system as indicated both by the occurrence of coarse‐grained detritic sediments, which impeded the development of a bioclastic (carbonate) shelf, and also by the formation of a prominent unconformity. NW‐SE and NE‐SW trending faults, defining subsiding areas and highs, controlled the pattern of sedimentation. Strike‐slip activity on these faults (right‐ and left‐lateral, respectively) was relatively minor compared to dip‐slip activity; normal faults with throws of up to 1 km are known, and result from approximately east‐west extension.The Tortonian succession is overlain unconformably by Pliocene marine deposits which were deposited during an abrupt transgression. Post‐Pliocene sedimentation has been largely continental.
INTERPRETATION OF VITRINITE REFLECTANCE PROFILES IN THE CENTRAL IRISH SEA AREA: IMPLICATIONS FOR THE TIMING OF ORGANIC MATURATION
Authors: Corcoran D. , Clayton G. 
Published: December 2007

The Central Irish Sea area, from Kish Bank to St. George's Channel and Cardigan Bay, consists of a series of Late Palaeozoic to Cenozoic extensional and transtensional basins which have experienced a multiphase inversion history. Potential hydrocarbon source rocks of Carboniferous and Jurassic ages have been recognised in this area. In the Kish Bank and Central Irish Sea Basins, maturation modelling of these source rocks is hampered by the severely truncated rock record and by the relative paucity of vitrinite throughout much of the preserved post‐Palaeozoic (Triassic) section.Vitrinite reflectance data from six exploration wells have been used to quantify the peak palaeotemperatures attained by the rocks in this area and to estimate the magnitude of net exhumation at these locations. An apparent palaeogeothermal gradient of ˜26°C/km is recorded by the Jurassic sediments in well 42/21‐1, whereas significantly higher palaeogeothermal gradients of 74–78°C/km are interpreted for the Westphalian/Stephanian sediments in the area. At least two periods of rock exhumation have occurred; during the Late Carboniferous‐Late Permian, and again sometime between the latest Jurassic and early Tertiary. Estimates of net exhumation vary from ˜350 m at well 42/12‐1 to ˜1,900 m at well 42/17–1. Our interpretation suggests that the higher palaeogeothermal gradients recorded by the Westphalian/Stephanian sections reflect elevated heat flows during Stephanian to Early Permian times.
CRETACEOUS CARBONATES IN THE ADIYAMAN REGION, SE TURKEY: AN ASSESSMENT OF BURIAL HISTORY AND SOURCE‐ROCK POTENTIAL
Authors: Demirel I. H. , Guneri S. 
Published: December 2007

The burial history and source‐rock potential of Cretaceous carbonates in the Adiyaman region of SE Turkey have been investigated. The carbonates belong to the Aptian‐Campanian Mardin Group and the overlying Karabogaz Formation. The stratigraphy of these carbonates at four well locations was recorded. At each well, the carbonate succession was found to be incomplete, and important unconformities were present indicating periods of non‐deposition and/or erosion. These unconformities are of variable extent. When combined with the effects of rapid subsidence and sedimentation which took place in the SW of the Adiyaman region during end‐Cretaceous foredeep development, they have resulted in variations in the carbonates' present‐day burial depths, thereby influencing the regional pattern of source‐rock maturation and the timing of oil generation. Burial history curves indicate that the carbonates' maturity increases from SW to NE, towards the Late Cretaceous thrust belt. Predicted levels of maturity for the Mardin Group are consistent with measured geochemical data from three of the wells in the study area (the exception being well Karadag‐1).Three potential source‐rock intervals of Cretaceous age have been identified. Two of these units — the Derdere and Karababa Formations of the Mardin Group — are composed of shallow‐water carbonates which were deposited on the northern margin of the Arabian Platform. The third source‐rock unit, the overlying Karabogaz Formation, is composed of pelagic carbonates which were deposited during a regional transgression. These potential source‐rock intervals contain marine organic matter dominated by Type II kerogen. Total organic carbon contents range from 0.5 to 2.9 %. Time‐temperature analyses indicate that the Mardin Group carbonates are immature to marginally mature at well locations in the SW of the study area, and are mature at western and NE well locations. The onset of oil generation in these Cretaceous source rocks took place between the middle Eocene (48 million yrs ago) and the Oligocene (28 million yrs ago).
THE NATURE AND ORIGIN OF PETROLEUM IN THE CHAIWOPU SUB‐BASIN (JUNGGAR BASIN), NW CHINA
Authors: Huang H. P. 
Published: December 2007

The Chaiwopu Sub‐basin is a minor extension of the Junggar Basin, hW China, and covers an area of about 2,500 sq. km. It is bounded to the east and north by the Bogda Shan and to the south by the Tian Shan (“Shan” meaning “mountains” in Chinese). Four wells have been drilled in the sub‐basin; condensate and gas have been produced in noncommercial quantities at one of the wells (Well C), but the other three wells were dry. In this paper, I investigate the nature and origin of the petroleum at Well C.Three of the four wells in the Chaiwopu Sub‐basin penetrated the Upper Permian Lucaogou Formation. Previous studies in the Junggar Basin have established that laminated lacustrine mudstones assigned to this formation comprise a very thick high quality source rock. However, the analysis of cores from wells in the sub‐basin shows that the Lucaogou Formation is composed here of shallow lacustrine, fluvial and alluvial deposits which have very low petroleum generation potential. Overlying sediments (Upper Permian, Triassic and younger strata) likewise have little source potential.Around 1,000 m of Upper Permian laminated oil shales crop out at Dalongkou and Tianchi on the northern side of the Bogda Shan. On the southern side of the Bogda Shan, however, only 30 m of Upper Permian oil shales occur at Guodikong. Shales and oil seeps from these locations were analysed using standard organic‐geochemical techniques.The physical properties of the petroleum present at Well C, and its carbon isotope and biomarker characteristics, suggest that it has migrated over long distances from its source rock, although an alternative explanation for its origin is not precluded. Burial history modelling indicates that hydrocarbon generation and migration may have occurred before the uplift of the Bogda Shan in the Late Jurassic—Early Cretaceous, the orogenic episode which resulted in the diflerentiation of the Chaiwopu Sub‐basinfrom the Junggar Basin.
DOLOMITIZATION OF THE EARLY EOCENE JIRANI DOLOMITE FORMATION, GABES‐TRIPOLI BASIN, WESTERN OFFSHORE, LIBYA
Authors: Mriheel I. Y. , Anketell J. M. 
Published: December 2007

Dolomitization in the early Eocene Jirani Formation in the Gabes‐Tripoli Basin (offshore western Libya) occurred in two stages. Stage I dolomites are composed of two types, one associated with anhydrite (Type I) the other anhydrite free (Type II,). The stratigraphic and sedimentological settings together with petrographic and geochemical criteria suggest that dolomitization was effected by refluxed evaporative seawater. Stable isotope and trace element analyses suggest dolomitization of both Types from a fluid of near‐surface seawater composition under oxidising conditions modified by evaporation. Non‐luminescence and lack ofzonation of all the dolomite indicate that the dolomitizing fluids maintained a relatively constant composition. The geologic setting during the early Eocene, interpreted as hypersaline lagoon, supports an evaporative reflux origin for the anhydritic dolomite Type I. Type II developed under less saline conditions in the transition zone between lagoon and open marine shelf.Stage II dolomitization is recorded by negative isotope values in both Types I and II indicating their dissolution and recrystallization (neomorphism) by dilute solutions. A period of exposure of the overlying Jdeir Formation following a relative sea‐level fall allowed ingress of meteoric waters into both the Jdeir and the underlying Jirani Formations. Flushing by meteoric waters also resulted in development of excellent secondaly porosity and caused major dissolution of anhydrite to form the anhydritic‐free dolomite facies typical of Type II. Following, and possibly during, both Stages I and II, low temperature dolomites (Type IIIa) precipitated in pore spaces from residual jluids at shallow burial depths, partially occluding porosity. In the late stage of basin evolution, medium clystalline, pore‐filling saddle dolomite precipitated, causing some filling of mouldic and vuggy porosity (Type IIIb). Very light oxygen isotopic signatures confirm that it developed from high temperature fluids during deep burial diagenesis. Calculation of temperatures and timings of the dolomitization and cement phases show that the main dolomitization phases and Type IIIa cements occurred in the early Eocene, and that the saddle dolomite precipitated in the Miocene; these results are consistent with age relationships established from stratigraphic, petrographic and geochemical signatures. The most common porosity includes intercrystal, vuggy and mouldic types. Porosity is both pre‐dolomitization and syn‐dolomitization in origin, but the latter is the most dominant. Hence, reservoir quality is largely controlled by fluid dynamics.