bluuebunny/crossref_metadata_2025_split huggingface dataset:
GEOLOGY OF THE PERMIAN “SUPER‐GIANT” GAS RESERVOIRS IN THE GREATER PERSIAN GULF AREA
Authors: Kashfi M. S. 
Published: December 2007

The Permian Dalan and Khuff Formations contain extensive gas reservoirs in the Greater Persian Gulf area. The Permian transgressive sea covered a vast area in the Middle East, and deposited a fairly thick sequence of shallow, epicontinental carbonates. These carbonates were deposited a fairly thick sequence of shallow, epicontinental carbonates. These carbonates were deposited unconformably on Lower Paleozoic rocks in western Iran and on the basement in Central Arabia. The term “Khuff Formation” has been widely used by oil companies in the region, but its equivalent, the Dalan Formation, is a new name currently being used in Iran.The Permian Basin was an elongate trough, trending NW‐SE, parallel to the Cretaceous‐Tertiary Zagros geosyncline. The deepest part of the Permian Basin was in the extreme SE portion of the trough, in the vicinity of the present Oman Mountains, in which nearly 6,000 ft (1,830 m) of Permian sediments were deposited.Porosity and permeability are generally low in these carbonates. However, secondary fracture porosity and dolomitization are commonly developed throughout these rocks. Permian reservoirs are capped by impervious strata, and the gas seems to be sourced from within the Permian section.
THE RED SEA ‐ GULF OF ADEN: RE‐ASSESSMENT OF HYDROCARBON POTENTIAL Abstract†
Authors: Beydoun Z. R. , Sikander A. H. 
Published: December 2007

THE results and conclusions of the UNDP/World Bank Red Sea ‐ Gulf of Aden Regional Hydrocarbons Study Project (June. 1989‐January, 1992) are summarised. These results were derived from detailed examination of pooled public‐sector date provided to the project by the participating bordering states in the region; these included samples and logs from ca. 56 wells drilled in the two basins (out of a total of 71 wells). and some 30,000 line‐kms of reflection seismic (out of 110.000 km available). well‐logs were digitised and correlated, and basin‐wide biostratigraphic, lithostratigraphic and paleoenvironmental studies, source‐rock organic richness. quality and maturity studies and sedimentological analyses were performed by contracted specialist staff in UK and France, and integrated with basin‐wide seismic structural and isopach mapping for selected regional reflectors/intervals by national task forces in Cairo under project supervision: academically‐derived crustal seismic and other geophysical data, and supervision; academically‐derived crustal seismic and other geophysical data, and industrially‐derived velocity and other borehole data were also integrated for the Red‐Sea.Modelling, utilising recently‐acquired geophysical data, indicates crustal asymmetry for the Red sea rift, with oceanic crust of pull‐apart basin type flooring some portions of offshore Egypt and Sudan on the west, and stretched continental crust underlying the eastern Arabian flank. These results suggest that sinistral strike‐slip processes controlled the intial break‐up of the Arabian Plate shaping the African flank as a sharp plate boundary,. Similar processes appear to have initially shaped the Somalia flank of the Gulf of Aden Rift. Only later did true sea‐floor spreading propagate: 10–12 million years age in the eastern Gulf of Aden; and <ca.5 million years age in the western Gulf of Aden, Afar and the southern/central Red Sea. Biostratigraphic work shows deep subsidence and ocean‐water inundation commenced in the late middle Oligocene in the Gulf of Aden, in the late Oligocene in the southern Red Sea, and in the early Miocene in the central Red Sea/Gulf of suez.
NIAGARAN REEFS OF NORTHERN MICHIGAN, PART I: EXPLORATION PORTRAIT
Authors: Gill D. 
Published: December 2007

Drilling for Niagaran (Middle Silurian) pinnacle reefs in northern Michigan dominated the petroleum exploration scene in Michigan for 19 consecutive years (1969–1987). By the end of 1986, cumulative production from the northern reefs reached 268 MM brl (million barrels) of oil and 1.4 Tcf (trillion cubic feet) of gas. This study presents quantitative and graphic summaries of several attributes of exploration and discovery data for this period, which together provide a concise “portrait” of the exploration history of the play. Data subsequently available confirm these trends for more recent years.The success ratio of exploration wildcats peaked at 51–53% during the years 1971‐73, after a “learning period” of three years. Thereafter, it declined gradually to around 16%, which is similar to the average of the US oil industry in the last decade. The success ratio for development drilling peaked at 68% during 1971‐2, and it has fluctuated between 40 and 50 % thereafter.The frequency distribution of field sizes is log‐normal. However, since very small uneconomic or marginally‐economic prospects and fields have either not been drilled or developed, the observed distribution represents only the density distribution of economic fields.The reef fields are rather small. Reef‐substrate areas range from about 40 to about 840 acres, and recoverable reserves range from 30,000 to 22 MM brl of oil equivalent (o.e).The ten largest fields in the play were found by drilling the first 25% of the exploration wells. The discovery per wildcat peaked at 1.55 MM brls o.e. after 500 wildcats, and declined steadily thereafter to a level of 0.02 MM brls o.e. per well after 1,900 wildcats, indicating that the play had reached a state of maturity. About 25% of the discovered reserves were found in 5% of the fields, indicating a more even reserve distribution pattern than in many other plays. Consequently, the relative rate of growth of the discovered reserves has been slower than in other plays.
THE OCCURRENCE AND δ34S OF AUTHIGENIC PYRITE IN MIDDLE JURASSIC BRENT GROUP SEDIMENTS
Authors: Prosser D.J. , Daws J.A. , Fallick A.E. , Williams B.P.J. 
Published: December 2007

Minor amounts of authigenic pyrite are common throughout the Middle Jurassic Brent Group, often being well developed within the delta‐plain fades of the Ness Formation. Petrographic analyses of pyrite samples from the Lyell and Murchison fields reveal two stages of pyrite authigenesis, both of which occurred during an early stage of burial.The first phase of pyrite authigenesis is represented by the development of nodules and finely‐disseminated cement within shale, mudstone, and siltstone fades, and can include the development of bladed marcasite nodules. These cements are interpreted as having formed within organic‐rich sediment soon after deposition, and pre‐date all other authigenic precipitates (typically calcite, quartz and kaolinite). “Early” pyrite cements display a wide range of δ34S(‐14.9 to +42.5% CDT), and some nodules analysed display isotopically‐heavy cores and considerably lighter margins. These isotopically‐zoned nodules are problematical. They could be interpreted as forming via progressive “closed system” bacteriogenic reduction and isotopic fractionation of sea‐water sulphate, with incorporation of heavy H2S into the earliest‐formed pyrite occurring as a result of its upward diffusion through the sediment column, following isotopic fractionation at depth. However, there are a number of problems with this type of interpretation. These include the fact that diffusion will favour the 32S isotope, so that the first‐formed cements should still be isotopically “light” not “heavy”; also, there is a mass‐balance problem, in that no low δ34S sulphides were detected.Coarsely‐crystalline pyrite euhedraform nodular cements mainly within sandstones (δ34S ‐2.6 to +12.8%CDT), and are interpreted as a “later” diagenetic phase. This second phase of sulphide cementation also pre‐dates the main phases of quartz and kaolinite authigenesis within sandstones, but post‐dates an early phase of kaolinite, and may have been partly coeval with some early calcite authigenesis.High organic contents and the early establishment of reducing conditions led to early formation of pyrite within fine‐grained brackish and marine sediments. The lowest measured end‐member δ34S of sandstone‐hosted pyrite cements is less isotopically depleted than that within fine‐grained argillaceous fades, perhaps indicating that sandstone‐hosted pyrite cements began to form subsequent to the onset of burial and bacteriogenic reduction within mudstones. Compaction of marine/brackish‐water shales and mudstones (or sulphate diffusion from these fades) may have supplied an already isotopically‐fractionated source of sulphate to porous sandstone lithologies, where “later” pyrite cements precipitated.
PALINSPASTIC AND CRUSTAL SETTING OF THE EASTERN MEDITERRANEAN
Authors: Hirsch F. , Flexer A. , Rosenfeld A. , Yellin‐Dror A. 
Published: December 2007

The nature and tectonic setting of the Eastern Mediterranean Basin are analyzed from geological and geophysical points of view. Palaeozoic and Mesozoic stratigraphy and palaeo‐biogeography suggest that epicontinental Africa, Apulia and Arabia were united almost continuously during the entire Phanerozoic eon, prior to and after the Early Triassic opening of the Mesozoic Tethys. The allochthonous ophiolite‐bearing terranes, that were thrust over the edges of the Gondwanan plate, fit well within a palinspastic model of a single Tethys ocean, north of the African‐Apulian‐Arabian palaeo‐edge.Seismic reflection and refraction studies, together with magnetic and gravimetric measurements of the present Eastern Mediterranean Levantine crust, have revealed a sedimentary succession 13–14 km thick, which presumably includes Palaeozoic‐Early Mesozoic strata overlying crust 8–12 km thick.Geological and geophysical re‐evaluation suggests that the enormously thick sedimentary succession of the Levantine Basin covers a thinned crust of continental origin. The latter consists of Panafrican terranes, possibly including Infracambrian ocean‐crust relics. Its “oceanic”‐like nature is presumably due to subcrustal thermal erosion. The possible existence of a western palaeo‐high offshore the Levant Coast calls for reassessment of hydrocarbon exploration in the Eastern Mediterranean. The previously proposed “hinge belt” along the Levant Coast may merely represent the transition from the eastern platform to a graben that separates the eastern (onshore) from the western (offshore) highs.The passive extensional regime of the Gondwanan Eastern Mediterranean plate during most of the Phanerozoic eon ended with Late Cretaceous‐Palaeogene Alpine compression of its margins, and the activation of the on‐and offshore Levantinid Syrian Arc fold system.
A CRITICAL COMPARISON OF NEURAL NETWORKS AND DISCRIMINANT ANALYSIS IN LITHOFACIES, POROSITY AND PERMEABILITY PREDICTIONS
Authors: Wong P. M. , Jian F. X. , Taggart I. J. 
Published: December 2007

The application of a genetic reservoir characterisation concept to the calculation of petrophysical properties requires the prediction of lithofacies followed by the assignment of petrophysical properties, according to the specific lithofacies predicted. Common classification methods which fulfil this task include discriminant analysis and backpropagation neural networks. While discriminant analysis is a well‐established statistical classification method, backpropagation neural networks are relatively new, and their performance in predicting lithofacies, porosity and permeability, when compared to discriminant analysis, has not been widely studied. This work compares the performance of these two methods in prediction of reservoir properties by considering log and core data from a shaly glauconitic reservoir.The neural network approach, while subject to a degree of trial and error as regards the selection of the optimum configuration of middle nodes, is shown to be capable of excellent performance. In the example problem considered, the neural network approach provided estimates superior to those based on a discriminant analysis approach. Further studies, on different formations, will be required to test the generality of this conclusion, and to refine the selection of neural network parameters.
GEOCHEMICAL CHARACTERIZATION AND RELATIONSHIP OF OILS AND SOLID BITUMENS FROM SE TURKEY
Authors: Mueller E. , Philip R. P. , Allen J. 
Published: December 2007

Solid bitumens from the Seridhalivein, occurring in the Upper Cretaceous—Palaeocene Germav Formation, and five oils from different oilfields in SE Turkey, were investigated by a variety of organic geochemical methods. Based on biomarker distributions (pristane/phytane, carbon number preference (CPI), Norhopane/hopane, extended hopane distribution, pregnanes/regular steranes), a marine carbonate depositional environment is inferred for the source of these oils. The oils are “early mature‘, as indicated by their ethylcholestane 20S/20S + 20R ratios, and the 17α(H), 21β(H)‐bishomohopane 22S/22S + 22R ratios. Differences in relative abundance of some compounds typical of higher salinities in the depositional environment (docosane, pregnane) suggest different sources of facies variations within a common source. No aromatic sulfur compounds were detected in the oils.The solid bitumens were characterized by a high abundance of dibenzothiophenes, naphthalenes, phenanthrenes and their alkyl‐substituted homologues in the aromatic fractions, and an abundance of n‐alkanes in the saturate fraction. The high maturity of the solid bitumen (epi‐impsonite, R %equiv. ? 1.2) makes an interpretation on the origin of these substances difficult. An origin due to biodegradation of sulfur‐rich oil is excluded, since the alkane and aromatic fractions do not show signs of a severe microbial degradation. The absence of sulfur compounds in the oil extracts and the pyrolysis products of the asphaltene fraction show genetic differences between the oils and solid bitumens of SE Turkey. Pyrolysis of the asphaltenes from the bitumen extracts and of the unextracted bitumens produced sulfur compounds similar to those found in the aromatic fraction.
QUANTITATIVE MODELLING OF SALT AND SEDIMENT INTERACTIONS: EVOLUTION OF A NORTH LOUISIANA SALT DIAPIR
Authors: Petersen K. , Lerche I. 
Published: December 2007

The restoration of sections involving salt structures is complicated, because it is often difficult to understand fully the dynamics of the system. The occurrence of hydrocarbons is often associated with traps in the vicinity of, or directly adjacent to, salt structures; different methods to delineate the combined evolution of salt and sediments have therefore been developed. Because dynamical parameters are rarely known more accurately than within an order of magnitude, intrinsic uncertainties are introduced in any model based on assumptions concerning the dynamical behaviour of salt and sediments.A quantitative approach is presented here, guided by observed geometries of the salt‐sediment interface and of the bed horizons from seismic and/or well data. This novel procedure considers the salt‐sediment system as composed of geometric shapes that are allowed to vary with time when calculating the salt‐sediment evolution. By letting sedimentary beds move around the developing salt structure, the influence of the uprising salt on the evolving bed geometries above and around the salt is depicted. Because the predicted present‐day bed geometries must also be in accord with applied control criteria (such as the change in salt volume with time, the geometry of the depositional surface with time, and the compaction history), additional constraints are put on the parameters controlling the evolution of the salt shape.The capability of being able to follow the changing bed geometries with time allows the strain in the sediments through time to be traced. The stresses that generated the deformations in the sediments can then be inferred through application of the theory of elasticity. Furthermore, the combined evolutionary picture may be used to assess thermal “focusing” through time by a highly conductive salt structure, because the salt and bed geometries are known at each instant.A case history from the North Louisiana Salt Basin shows aspects of different combinations of control criteria on salt‐sediment evolution. Information is thus provided on the importance of evaluating the data and control criteria necessary for constraining the possible evolution histories.It is suggested that the novel inverse procedure presented here will improve understanding of the combined evolution of salt and sediments, and is therefore of significance in hydrocarbons exploration.
GEOCHEMISTRY, ISOTOPIC COMPOSITION AND ORIGIN OF THE BEDA DOLOMITES, BLOCK NC74F, SW SIRT BASIN, LIBYA
Authors: Garea B. B. , Braithwaite C. J. R. 
Published: December 2007

The Middle Palaeocene Beda Formation, penetrated by wells in block NC74F in the SW Sirt Basin, is dominated by lagoonal, intertidal, and supratidal rocks including evaporites originally deposited in a restricted shallow lagoon.In the area studied, about 60% of the formation has been dolomitized. Dolomite occurs predominantly replacing precursor carbonate mudstones, although pore‐filling cements line moulds and vugs. Replacive crystals are euhedral to subhedral, finely to very finely crystalline, and generally less than 0.03 mm in diameter. They are non‐ferroan, and show a uniform dull‐to‐moderate orange luminescence. Crystals forming cements are coarser, up to 0.35 mm in diameter, and are characteristically baroque.Geochemical data indicate that the Beda dolomites have high strontium, low iron, and low manganese contents. They are also depleted in 18O, with negative δ18O values averaging ‐3.63% (PDB). The 13C values show a more marine δ13C isotopic signature, with an average δ13C value of +3.33% (PDB).The petrographic and geochemical characteristics of the Beda dolomites and their association with evaporites supports a model of early, near‐surface, dolomitization resulting from hypersaline brine refluxion.
INFLUENCE OF DEPOSITIONAL ENVIRONMENT ON DIAGENESIS AND RESERVOIR QUALITY: TIRRAWARRA SANDSTONE RESERVOIR, SOUTHERN COOPER BASIN, AUSTRALIA
Authors: Rezaee M. R. , Lemon N. M. 
Published: December 2007

Mechanical compaction and quartz cementation are the most important diagenetic controls on the reservoir quality of the Late Carboniferous ‐ Early Permian fluvio‐deltaic Tirrawarra Sandstone in the Cooper Basin of South Australia. The magnitude of these two diagenetic events is controlled by the mineralogical composition of the sandstones.Assuming that the Tirrawarra Sandstones have a common provenance, the nature of the environments in which these sediments were deposited is the principal factor controlling the composition of the framework grains in the unit. Thus, the percentage of rock fragments decreases, and the relative quartz content increases, from the medial part of a braid‐delta to point‐bar and aeolian environments. The content of ductile rock fragments controls the degree of compaction and the development of quartz overgrowths.
AN EVALUATION OF THE HYDROCARBON POTENTIAL OF THE SEDIMENTARY BASINS OF LIBYA
Authors: Gumati Y. D. , Kanes W. H. , Schamel S. 
Published: December 2007

Distinctive structural and stratigraphic styles, together with the timely development of source rocks, reservoirs and seals, have produced in Libya the richest hydrocarbon habitats on the African continent. These habitats are located in the Sirte Basin (29,000 MM brl of proved reserves), and Ghadames Basins and Pelagian Shelf (3,000 MM brls of proved reserves). Significant oil discoveries have also been made in the Murzuk Basin (1,500 MM brl of proved reserves) and the offshore Cyrenaica Platform.Four major potential source rocks have been identified in Libya: the Sirte shales (Campanian), the Hagfa shales (Palaeocene), the Tanezzuft shales (Silurian), and shales of Devonian age. The Sirte and Hagfa shales have generated hydrocarbons for most of the prolific reservoirs in the Sirte Basin. The Sirte shales supply hydrocarbons to clastic reservoirs of Cambro‐Ordovician age (the Gargaf Group) and Lower Cretaceous age (Nubian sandstones), and also to Upper Cretaceous carbonates. The Hagfa shales source most of the Tertiary reservoirs in the Sirte Basin and possibly the Cyrenaica Platform. Silurian (Tanezzuft) and Devonian shales supply hydrocarbons to reservoirs of Palaeozoic and Mesozoic ages, particularly Silurian and Devonian sandstones in the Ghadames and Murzuk Basins, and the Cyrenaica Platform.The principal seals in the Sirte Basin are Late Cretaceous and Tertiary shales and anhydrites. Palaeozoic and Mesozoic shales, impermeable carbonates, and occasional anhydrites form the major seals in the Ghadames and Murzuk Basins and the Cyrenaica Platform.
GEOLOGY AND PETROLEUM POTENTIAL OF THE KHORAT PLATEAU BASIN IN THE VIENTIANE AREA OF LAO P.D.R.
Authors: Smith P. F. Lovatt , Stokes R.B. 
Published: December 2007

The Vientiane area of southern‐central Lao Peoples' Democratic Republic (Laos) includes an extension of the Khorat Plateau Basin, which covers most of neighbouring NE Thailand. This basin contains one producing gasfield and several other gas discoveries. The Vientiane area is in the initial stages of petroleum exploration, and no drilling has yet occurred.With the aid of new seismic data, the structure and stratigraphy of the Vientiane area are described in relation to the region's tectonic history. Some aspects of this history are still poorly understood. We suggest that the age of the regional base‐Khorat unconformity is Late Jurassic instead of Late Triassic as most previous studies have assumed. Recent studies have also shown that the structural inversion of the Khorat Group began in the mid‐Cretaceous and not in the Tertiary.With reference to published information from petroleum exploration in NE Thailand, new data from Laos are interpreted as showing that the Vientiane area has encouraging petroleum potential. Exploration risk, which is associated with the presence and reservoir quality of the Permian carbonates which form the primary target, is judged to be lowest in traps containing Permian palaeo‐highs.