bluuebunny/crossref_metadata_2025_split huggingface dataset:
DOWNTHROWN TRAPS OF THE NW WITCH GROUND GRABEN, UK NORTH SEA
Authors: Hindle A. D. 
Published: December 2007

The structures drilled to‐date in the NW Witch Ground Graben area have been assigned to two broad categories:(i) Upthrown traps with four‐way dip closure or tilted fault blocks, generally located on the franks of the graben: and(ii) Downthrown traps with closure against a major fault, located downthrown on the main graben border fault systems.Many of the downthrown traps are in fact combination traps, having upthrown fault‐seal and/or stratigraphic elements.A study of trap settings in the NW Witch Ground Graben has led to the following conclusions:1. The success rate for encountering hydrocarbons in upthrown traps and downthrown traps is very similar.2. The common belief that the footwall seal is the most critical element of a downthrown trap is questionable.3. Modern seismic data reveals that a high proponion of unsuccessful exploratory wells were not located on a closed structure. The proportion is similar for upthrown and downthrown trap targets alike.4. There is a lesser chance of the reservoir being absent, or there being no migration route to the trap, in downthrown structures, compared with upthrown ones.5. Carboniferous sediments can be a footwall seal for a downthrown trap in one location, and a reservoir for hydrocarbons in another.6. The structural evolution of the NW Witch Ground Graben, within a framework of three intersecting fault trends, has been ideal for the development of downthrown traps. The distribution of a hydrocarbon source rock, the timing of hydrocarbon migration into these structures, and the suitable distribution of sealing strata adjacent to the border fault of the structure, have also been critical.
DEPOSITIONAL HISTORY OF THE RESERVOIR SANDSTONES, AKPOR AND APARA OILFIELDS, EASTERN NIGER DELTA, NIGERIA
Authors: Amajor L. C. , Agbaire D. W. 
Published: December 2007

A subsurface study of the Agbada Formation in the Akpor and Apara oilfields in the eastern Niger Delta was undertaken in order to determine the depositional development of the reservoir sand‐bodies.In the study area, the formation comprises a maximum of 29 relatively thick sandstones, cyclically interbedded with shales of varying thicknesses. The lowest tow sand units, separated by a shale unit and located near the base, produce petroleium from ten wells in both fields. Each sand‐body exhibits a coarsening‐upward textural gradient.The lower sand‐body (Unit A), which is oval‐shpaed, moderately‐ to poorly‐sorted, fine‐ to very coarse‐grained, carbonaceous, with clay and lignite horizons, is interpreted as a deltaic sand. The unit appears to have migrated landwards (north) (destructive delta), probably as a result of localized transgression, and developed maximum thickness between the two fields.The upper sand (Unit B) is fine‐to‐pebbly in grain size, well‐sorted and glauconitic. Maximum development occurred slightly east of the delat. As the unit prograded in a predominantly southerly direction, genetic currents simultenously caused it to be channelized. This sand‐body is interpreted as an offshore marine bar. The intervening carbonacous shale is thought to be of logoonal origin.Since the geometries of these sand‐bodies are not conclusively delimited by the existing well density, their pinch‐out edges to the north, east and west may constitute prolific stratigraphic traps.
STRUCTURE AND HYDROCARBON POTENTIAL OF THE TARIM BASIN (NW CHINA) FROM SATELLITE IMAGERY
Authors: Nishidai T. , Berry J. L. 
Published: December 2007

The Tarim Basin, NW China, whose total area is 560,000 sq. kms, is one of the largest inland basins in the world, with sediments around 15,000 m thick. The Tarim Block is a small continental plate, which is being over‐ridden at its western end from both the north and south, by the Eurasian and Indian continents, respectively. Abundant oil and gas accumulations are predicted to occur within the basin.Detailed analysis of Landsat imagery, integrated with published geological and geophysical data, has provided the basis for a re‐examination of the structural geology of the area, and has enabled a new interpretation of the tectonic development of the northern part of the Tarim Basin to be made.The region discussed in this paper is the northern margin of the Tarim Basin, including the Kalpin Uplift (Kalpintag), North Tarim Depression and Kuruktag Uplift. Remarkable geological structures outcrop in these areas, and are clearly visible on satellite imagery.The NW and SW margins of the Tarim Basin are dominated by compression; while the NE and SE margins are dominated by left‐lateral strike‐slip movements. South of the Kalpintag, west‐directed thrusting occurs in Palaeozoic platform sediments, which may have some production potential where they are buried beneath Neogene sediments.On the NW basin margin; where thrusting is predominant, crustal shortening is estimated to be around 50%. In the Kuqa Depression (the northern sector of the North Tarim Depression), Tertiary evaporites seal Mesozoic source rocks. The configuration above the décollement is discordant, and the spectacular Tertiary surface structures are not very prospective.The Kuruktag (at the NE corner of the Tarim Basin) is an area of compressional grabens which may contain both Mesozoic and Tertiary source rocks. These grabens are potential analogues of basins in southern California.Important structural features interpreted here include several major thrust complexes, and strike‐slip fault systems. In addition to detecting fault traces, a number of important fold structures were mapped and analysed using the imagery, and the resulting maps represent an improvement on existing publications. Tectonic features, particularly folds and faults near the basin margin, may provide traps for hydrocarbon accumulations.As a result of this study, many potential hydrocarbon traps, which merit close attention by geophysical field‐survey techniques such as seismic reflection, have been defined.
THE CHAIDAM BASIN (NW CHINA): FORMATION AND HYDROCARBON POTENTIAL
Authors: Qinmin Wang , Coward M. P. 
Published: December 2007

The Chaidam Basin forms one of the deepest sedimentary basins in the world, with over 14kms of sediment deposited since the Oligocene. Basement rocks consist of: (i) pre‐Sinian gneisses; (ii) Sinian and Lower Palaeozoic sediments folded by the Silurian ‐ Devonian orogeny; (iii) Upper Palaeozoic molasse in a half‐graben produced by the collapse of the Silurian mountain belt; (iv) Carboniferous terrestrial to shallow‐marine facies sediments deposited on the margins of Palaeotethys; and (v) Permo‐Triassic sediments deposited in a back‐arc basin N of the Palaeotethyan subduction zone.Triassic back‐are basin development was followed by thermal subsidence during the Jurassic to Eocene, with a low sedimentation rate, modified by flexural subsidence on the margins of the thickened and uplifted S Qilian Mountains. Gentle folds and SW‐propagating thrusts were developed in Jurassic strata. The region was uplifted as a whole during Early Jurassic and Middle Cretaceous times.The main period of subsidence occurred from the Oligocene to the Recent, producing a deep hinterland basin in western and central Chaidam. Uplift along the Kunlun and the Aerjin Fault Zone provided a ready sediment supply. Basin subsidence throughout the Neogene probably reflects lithospheric flexure due to the loading of the Tibetan lithosphere, although the rapid increase of Sedimentation during the latest Tertiary and Quaternary must reflect rapid Recent uplift of the Tibetan Plateau. During the Pliocene and Pleistocene, there was inversion and shortening of the Basin, associated with reworking of the Mesozoic strike‐slip and thrust faults. Thus, the Aerjin Fault Zone was reactivated to control the shortening direction across the Basin. Mesozoic thrusts were reactivated along the NE margin of the Basin during the Pliocene, but by Pleistocene times, WNW‐trending folds developed throughout the western part of the Basin. There was differential uplift; the zone nearest the Aerjin Fault was uplifted most, causing tilting and variations in sediment thickness and facies from NW and SE.There are numerous source rocks formed by lacustrine facies sediments of Jurassic and Neogene age. The burial history and the timing and location of structural and stratigraphic traps has controlled the locations of the major hydrocarbon occurrences in western and NW Chaidam. An evaluation of hydrocarbon prospectivity is given in the light of the tectonic ‐ stratigraphic framework and basin analysis.
PETROLEUM AT THE ROOF OF THE WORLD: The geological evolution of the Tibet (Qinghai‐Xizang) Plateau Part I
Authors: .Taner I. , Meyerhoffr A. A. 
Published: December 2007

The Tibet (Qinghai‐Xizang) Plateau is underlain by many thousands of mters of Ordovician (and possibly Cambrian) through Middle Eocene, gently‐dipping, essentially undeformed, stable platform sequences. These are largely qf shallow‐water, marine‐shelf origin in the Ordovician‐Triassic sections, but are of mixed continental and marine facies in the Jurassic through Midle Eocene sections. Two east‐west fault troughs ‐ the Banggong Co ‐ Nu Jianand Indus River ‐Yarlung Zangbo ‐ contain thick sections of Triassic, Jurassic, and/or Cretaceous marine flysch associated with ophiolites. The only severe deformation to affect the plateau was during the Mesozoic, and it was concentrated close to the through‐going east‐west fractures.Post‐early Eocene beds are entirely continental, and are concentrated nsmall‐to‐large grabens. One of these, the Lunpola Basin, has been moderately explored. Drilling here during the 1970s recovered small amounts of heavy, biodegraded oil of non‐marine origin, from a sectionthat ranges in age from Middle Eocene through QuaternaryPlateau‐wide stratigraphic studies reveal that the Ordovician through Early Carboniferous, and Late Permian through Middle Eocene, sections were deposited on a monolithic stable block. All were deposited in essentially warm tropical seas in close proximity, as demonstrated by the, facies, faunas, and floras. These same studies, plus related tectonic investigations, reveal that the through‐going east‐west fracture zones, popularly interpreted as “sutures,” are not sutures at all. Rather, the facies belts in rocks of all ages studied in detail routinely cross the so‐called “sutures,” commonly at very sharp angles, proving that these east‐west fault zones exerted no control overthe general lithofacies deposition patterns of the Himalaya‐Tibet block. The oniy facies control exerted by the fracture zones was in the small, narrow troughs that developed along them. Thus, the Himalaya‐Tibet block behaved as a single structural unit through time, and was never segmen red in to various microcontinents.Although some potential for commercial petroleum discoveries exists in the post‐middleEocene grabens. the greatest potential of the Himalaya‐Tibet block is in the Paleozoic‐Mesozoicsection. with its promise of multiple source‐beds. reservoirs, traps, and seals. We predict that, one day, this “roof of the world” will host many petroleum Jields.
A REVIEW OF THE CRETACEOUS FORMATIONS IN THE ARABIAN PENINSULA AND GULF: PART III. UPPER CRETACEOUS (ARUMA GROUP) STRATIGRAPHY AND PALEOGEOGRAPHY
Authors: Alsharhan A.S. , Nairn A.E.M. 
Published: December 2007

A historical review of the development of the stratigraphy of Upper Cretaceous rocks in the Arabian Peninsula and Gulf provides a partial explanation for many of the different formational names. A type section is presented for the United Arab Emirates, and lithofacies variations within the region are related to it. In addition to the simple model of migration of predominantly shallow‐water facies belts across a shelf, the Upper Cretaceous also contains deep‐water facies due to the onset of plate‐margin tectonic activity, which resulted in the emplacement of the Hawasina complex and the Semail ophiolites of Oman.As observed in the earlier mid‐ and Lower Cretaceious rocks, two cycles can be recognized. These are found in the SE part of the region, in contrast with the mid‐Cretaceous, where two cycles are more clearly recognized in the NE area.
SALINE DEPOSITS AND ALKALINE MAGMATISM: A GENETIC MODEL
Authors: Momenzadeh M. 
Published: December 2007

The temporal and spatical coincidence of saline deposits with rifting and alkaline magmatism is now widely accepted. The congruency of these three phenomena implies, logically, their trilateral genetic inter‐relationship. Conventional models for the formation of saline deposits, i.e. the “evaporation process”, cannot be properly applied to giant saline deposits, such as those of the Mediterranean and Red Sea basinsThe alternative “Volcanogenic Model” proposed here offers a genetic explanation for these problems. This Model is compared with both the conventional evaporation model and the deep‐basin evaporation model of fSchmalz. Well‐known saline‐surface basins (e.g. the Red Sea, East African rift system, Dead Sea, Mediterranean, Circum‐Atlantic, Zechstein, and Asian InfraCambrian — Lower Cambrian), and “Kuroko” and “Black Smoker” depostis, are briefly reviewed. The role of alkaline and calc‐alkaline magmatism in producing saline‐surface deposts and the application of the Volcanogenic Model in each case is discussed, and conclusions concerning the suitability of the new model are drawn.
POLLEN TRANSLUCENCY AS A THERMAL MATURATION INDICATOR
Authors: Lerche I. , McKenna T. E. 
Published: December 2007

Using an inversion technique, we show that pollen translucency with depth can be used as a quantitative tool to estimate the thermal history of sedimentary sequences. The overall trend of translucency is a decrease with increasing depth. In this study, three wells in southern Louisiana were examined, each having Carya (a pollen genus including present‐day Pecans and Hickories) translucency measurements with depth, and one of the wells containing measurements of vitrinite reflectance with depth. High sedimentation rates (>250 ft/MM yrs of shale) require the use of a fluid flow/compaction burial history program linked with the Carya inversion algorithm. Thermal history is estimated by the interaction of a heat flux taken to be linear in time, and a time‐temperature integral for the inversion of Carya translucency. The former involves β, a linear heat‐flux coefficient to be determined, while the latter involves two previously unknown constants: TC, a critical temperature, below which the translucency is stable (no carbonization), and TD, a scaling constant, roughly analogous to a doubling temperature. TD and Tc are chemical constants, and should be consistent in the three wells, while β should be consistent when determined independently by vitrinite reflectance and Carya translucency inversions. Grid searches for an acceptable solution in TC vs. TD vs. βspace were carried out for each of the three wells to determine the best TD TC and β for each well. A goodness‐of‐fit criterion, contoured in TD vs. TC vs. βspace, defines a volume of solutions within fixed error limits. Estimates of TD= 75 ± 30°K and TC= 290 + 20°K, for the genus Carya, are consistent for all of the wells. Acceptable β ranges, determined by the Carya inversion, overlap for the neighbouring wells. and the ranges are also consistent with β determined by the independent inversion of vitrinite reflectance in one of the wells. We conclude that Carya translucency can be used as a quantitative thermal indicator. Application of the inverse method to translucency measurements on other palynomorphs having longer. or different, age ranges than the Eocene‐Recent lifetime for Carya is recommended.
GEOLOGIC RATIONALE FOR HYDROCARBON EXPLORATION IN THE CARIBBEAN AND ADJACENT REGIONS
Authors: Pindell J. L. 
Published: December 2007

Sedimentary basins in the Caribbean and adjacent areas are assessed in terms of the plate‐tectonic and paleogeographic history of the regions. Primary phases of development were rifting and passive margin development during Jurassic‐Cretaceous drift of North from South America; and the Late Cretaceous to Recent relative eastwards migration of the Caribbean Plate from the eastern Pacific area to its present position between North and South America.Two primary stratigraphic suites of rock occur in the Caribbean region: (I) autochthonous Jurassic, Cretaceous and Cenozoic passive margin sediments deposited along the rifted margins of North and South American basement: and (2) allochthonous oceanic crustal and magmatic arc rocks and overlying sedimentary units of the migrating Caribbean Plate. The tectonic boundary between these suites coincides roughly with the limit of circum‐Caribbean thrusted metamorphic/mafic rocks above the formerly passive Proto‐Caribbean shelf rocks (episutural foredeep basins), and juxtaposition youngs from west (latest Cretaceous in southern Yucatan) to east (late Neogene in Trinidad). Although Jurassic rift/early drift‐related source rocks occur in some areas. such as in Cuba—Bahamas. the primary source rocks in both suites were deposited well after rifting in the “medial” Cretaceous. Basin development during the Late Cretaceous to Recent tectonic juxtaposition of the two suites (i.e. Caribbean migration) directly controlled both clastic reservoir facies deposition and hydrocarbon maturation in many areas around the Caribbean. Basin development, source and reservoir rock deposition, and maturation of source rocks in all basins in the region can be directly related to plate‐tectonic evolution. A satisfactory understanding of the hydrocarbon potential of the Caribbean/northem South American province therefore requires a full appreciation of the region's plate‐tectonic evolution.
SEDIMENTARY BASINS OF THE NE CARIBBEAN PLATE BOUNDARY ZONE AND THEIR PETROLEUM POTENTIAL
Authors: Larue D. K. , Warner A. J. 
Published: December 2007

Sedimentary basins in the NE Caribbean Plate Boundary Zone are associated with the evolution of a Cretaceous to Early Tertiary island arc, and with carbonate banks which formed following cessation of volcanism in the Eocene to Oligocene. Neogene sedimentary basins are typically present where crustal blocks in the plate boundary zone have undergone divergence, with or without rotation. Cretaceous through Oligocene basins may also have formed during divergence between crustal blocks, although this is difficult to prove owing to limited exposure and subsequent tectonic deformation. Other basins are associated with localized overthrusting along the plate boundaries.Absence of source rocks and complicated and variable geothermal gradients make the area one of high risk for petroleum exploration. However. the paucity of data collected in the region allows for significant future discoveries, and the presence of minor seeps and traces of petroleum from two wells gives some hope. Finally, there is some evidence that seismic reflection amplitude anomalies may be associated with gas occurrences in the NE Caribbean, such that imaging of “bright spots” may prove to be a successful exploration tool.
ORGANIC GEOCHEMISTRY AND PETROLEUM POTENTIAL OF JAMAICA
Authors: Rodrigues K. 
Published: December 2007

Eleven wells were drilled in Jamaican territory over a 27–year period commencing in 1955: all were abandoned as dry. This study evaluates the island's petroleum potential in the light of new data on the source‐rock quality of the shales penetrated, and on reservoir properties of sandstones and limestones interbedded with these shales.Altogether. 270 representative shales and mudstones were sampled from the Cretaceous Windsor, Hanover and Sunderland Formations, and from the Eocene Richmond and Chapelton Formations. and subjected to standard organic‐geochemical analyses. Data on organic matter quantity, type and maturity indicate good potential for oil generation in the Chapelton Formation. The other formations analysed have < 1.0% total organic carbon. comprising woody and coaly kerogens, with no potential for oil generation.Modal compositions of detrital grains were determined on sandstones sampled for reservoir quality evaluation from four formations. Provenance studies indicate derivation from a magmatic‐arc source, with volcanic lithic fragments and feldspars being the dominant constituents. This unstable mineralogy, combined with rapid sedimentation and location of sedimentary basins close to source areas, implies low porosity and permeability in these sandstones.Other considerations of trap availability, presence and extent of cap rocks. and the likelihood of any petroleum generated being preserved in view of Jamaica's active tectonic history since the Middle Miocene, suggest that conditions for the generation. accumulation and preservation of commercial deposits of petroleum probably may not have existed here.
FLUID MIGRATION ALONG GROWTH FAULTS IN COMPACTING SEDIMENTS
Authors: Hooper E. C. D. 
Published: December 2007

The movement of fluids up growth faults is proposed to be periodic; when faults are active they can concentrate fluid flow, but when inactive, flow is restricted. Higher flow rates are predicted to be caused by fault‐zone permeabilities and fluid potentials increasing at shear stresses close to the shear strength of the rock. In this way, significant flow is confined to the most active sections of moving faults. Since fault activity is related to sediment accumulation rates, the volume of fluid flowing up faults should be greatest when accumulation rates are high.Periodic flow explains the evidence which indicates that faults can be both barriers and avenues of fluid migration. Evidence for growth faults being avenues of fluid migration is shown by fault‐zone mineralization. lowered fluid potentials. thermal anomalies, salinity anomalies. and isotope studies. In contrast, fault‐zone porosity studies. measured flow rates, high juxtaposed fluid potential differences, differential subsidence caused by groundwater production, and hydrocarbon accumulations, all suggest that growth fault zones are of low permeability.The flow of‐oil from large pore spaces into smaller, water‐filled pore spaces requires a large potential gradient. Therefore., faults which cut water‐wet sections with variable vertical permeability are usually poor conduits for oil. In contrast, in hydrocarbon‐saturated homogeneous rocks, such as mature shales. the vertical flow of migrating hydrocarbons may be concentrated by faults. The degree of concentration will depend on the permeability of the fault zone.