bluuebunny/crossref_metadata_2025 huggingface dataset:
EXPLORATION AND EVALUATION OF THE ZUATA AREA, ORINOCO OIL BELT, VENEZUELA
Authors: Vega Alfredo , de Rojas Isabel
Published: December 2007

Exploration activity in the Zuata area within the Orinoco Oil Belt in Venezuela has included the drilling of 161 wells and the recording of 3,000 km of seismic lines. Based on these results, a productive area of 9,200 sq. km has been defined, containing 79.3 B cu.m. (499 B brl)† of crude oil in‐place, with densities ranging from 1.021 to 0.934 g/cu.cm (7–20 °API).

The principal productive sands are of the Tertiary Officina Formation, deposited during a transgression which occurred in the Miocene. A distinctive feature of the productive formation is its progressive onlap against older rocks (Cretaceous, Paleozoic or Pre‐Cambrian) in a southerly direction which, together with overlying shales, provide the trapping mechanism for the oil which migrated from the north. The productive sands were deposited in a fluvial to coastal plain with deltaic developments. The sands are unconsolidated and fine‐ to very coarse‐grained, with an average porosity of 34% and a permeability of 7μm2(7D). The structure is a monocline dipping 0.5° to 2° to the NE, and the trapping mechanism is principally stratigraphic.

In the 134 producers, 300 tests were completed which resulted in an average production of 25 cu.m/d (160 b/d) per well by beam pumping without dilution or heat. Subsequently, a steam cycle of 5,000 metric tons was injected into 16 wells; production increased to some 200 cu.m/d (1,250 b/d) per well.

For future development, a Priority Area has been selected: this Area covers 3,500 sq kin, and contains 40.5 B cu.m (255 B brl) of crude oil with a density range of 1.014 to 0.993 g/cu.cm (8–11°API). The oil is at an average depth of 610 m, and the average net oil‐sand thickness is 60 m. The oil‐sand is generally divided into three zones separated by shales, and the gross productive thickness is some 110 m.

Similar to Maraven ‘s experience in the oilfields of the Bolivar Coast in Western Venezuela, it may be expected that reservoir compaction will occur, and will be efficiently activated by steam‐soak or “huff and puff’. Based on core compressibility measurements, a recovery factor from compaction drive and solution gas treatments could reach 12 % of the oil in‐place. Under this premise, the Priority Area could have a potential recovery of 4.9 B cu. m. (30.6 B brl), which could support a production of 160,000 cu.m/d(1MM b/d) for 100 years. Any follow‐up steam drive can be assumed to recover at least an additional 10% of the oil in‐place.

A Conceptual Development Plan based on clusters, inclined wells (due to the shallow depth) and steam soak has been proposed, and will be validated by a pilot test consisting of a seven‐well cluster.
RESERVOIR GEOLOGY OF THE CERRO NEGRO STEAM INJECTION AREA, ORINOCO OIL BELT, VENEZUELA
Authors: Antonio Santos C. , Frontado Luis
Published: December 2007

Several very favourable areas were defined in the Orinoco Oil Belt, after intensive geological, exploration and evaluation studies were conducted between 1970 and 1982.

The Cerro Negro project area was selected as the first to be investigated. Subsequently, a small part of this area, covering 5.9 hectares (14.5 acres), and containing about 159,000 cu. m (1 MM** brl) STOIIP of 8 to 11° API, in the objective sand, was chosen in which to initiate the Cerro Negro Steam Injection Project (PIVCN), which is now under development. The Early Miocene Oficina Formation, whose sands constitute the reservoir rock, show a fluvial to deltaic sequence at the base (Morichal Member), a transgressive sequence in the middle section (Yabo‐Jobo Member), and finally a closing prograding sequence (Pilón Member) at the top. Qualitative analyses of the sedimentary section indicate optimum textural, mineralogical and depositional conditions which determined the final configuration of a sequence with excellent reservoir porosity and permeability. The distributary channel facies show the best petmphysical parameters †, (φ35%, φSo:* 30%, Sw: 5%, Vsh:* 6%, K: 50,000md). These values yield an oil content of 2,300 STB/acre‐ft. in the objective sand, namely unit 0–15 of the Morichal Member. Oil entrapment is primarily stratigraphic, and no oil/water contacts or gas caps have been found in the PIVCN project or in the whole of the much larger Cerro Negro area.
COMPARISON OF REFLECTANCE DATA FROM VARIOUS MACERALS FROM SUB‐BITUMINOUS COALS
Authors: Goodarzi Fariborz
Published: December 2007

Reflectance values were determined for selected huminite (eu‐ulminite, eugelinite and phlobaphinite) and liptinite (cutinite and resinite) samples from a 560—m thick unit of lignitic‐sub‐bituminous coals in the Hat Creek coal deposit of British Columbia.

The objective of this study was to determine: (a) the reflectance differences between macerals, especially those of the humocollinite subgroup, and to determine the possibility of the use of the reflectance of the humocollinite maceral as an indicator of rank; (b) the trend of reflectance of humocollinite macerals (kerogen Type III) with depth; and (c) comparison of the reflectance trends of resinite and cutinite (kerogen Type II) with that of the humocollinite macerals (kerogen Type III).

Two types of corpohuminite were found in the same coal: Type 1 phlobaphinite with reflectance lower than eu‐ulminite, and Type 2 phlobaphinite with reflectance higher than eu‐ulminite. Reflectance of eugelinite was higher than corpohuminite and eu‐ulminite.

Kerogen Type III (huminite) in these coals consists of: a) low‐reflecting hydrogen‐rich phlobaphinite Type 1; b) phlobaphinite Type 2 and eu‐ulminite B. with intermediate reflectance and hydrogen content; c) relatively high‐reflecting and perhaps hydrogen‐poor eugelinite. The reflectance of all these macerals increased with depth.
DETERMINATION OF PALEO HEAT‐FLUX FROM FISSION SCAR TRACKS IN APATITE
Authors: Huntsberger T. L. , Lerche I.
Published: December 2007

Three methods are presented for determining paleo heat‐flux from fission scar tracks in detrital apatite collected from wells. The annealing of the fission scar tracks is modelled using time‐temperature integrals assuming first‐order kinetics in agreement with the laboratory experiments over the last fifteen years.

The three methods invert the present‐day fission‐track well data along the burial paths of the sedimentary units.

The first two methods involve inverting the depth‐dependent (a) areal track‐number density per gm of uranium and (b) mean track length to obtain an estimate of the temporal dependence of the paleo heat‐flux. Since these methods tend to overlook short tracks (method (a)), and be biased towards longer tracks (method b)), they tend to provide paleo heat‐flux variations which are too high and too low, respectively. The uncertainty in the determination of paleo heat‐flux variation is also quite high, as is shown by using data from two wells: Kambara‐1 and Curringa‐1 in the NW Canning Basin, Australia.

The third method inverts all of the individual distributions of track lengths at each sampled depth in a well. The sensitivity of this method is much higher than methods (a) or (b). In fact, we are able to determine not only the rate of change of heat‐flux with time but, for the first time, variations in the direction of change of heat‐flux, allowing us to quantify heating and cooling events, as opposed to just heating or cooling events. In addition, we are able to determine the rate constant for track annealing and, in line with qualitative arguments advanced by Gleadow et al (1983), we find that the rate constant appropriate to the multi‐million year time‐scale of subsurfce apatite track annealing is lower, by a factor of about three, than the value advocated from short‐lived (on a geologic time‐scale) laboratory experiments. Detailed track data from two wells, Kambara‐1 and Curringa‐I, yield essentially identical values for the rate constant, but very different thermal history behaviours.
DISPERSED SEDIMENTARY ORGANIC MATTER IN COAL MEASURE HORIZONS, EAST MIDLANDS, UK
Authors: Dobson J. , Kinghorn R.R.F.
Published: December 2007

Five samples of dispersed sedimentary organic matter from the Clay Cross marine band around Gainsborough in the East Midlands of England have been subjected to optical, elemental and stable carbon isotope analysis, together with capillary gas chromatography and gas chromatography — mass spectrometry examinations of their solvent extracts, in an attempt to discern variations in conditions ofdeposition. These results are then compared and contrasted to similar analyses performed upon other lithological units from the same region.
A WORLDWIDE LOOK AT THE CAP‐ROCK PROBLEM
Authors: Grunau Hans R.
Published: December 2007

Geological aspects of the cap‐rock problem were investigated on a worldwide scale in order to provide guide‐lines for assessing the sealing and retention risk in exploration ventures. The most common caprock lithologies are shales and evaporites, which have typical thicknesses of tens to hundreds of meters. Regional seals are often provided by evaporitic sabkha environments and transgressive and regressive shales. Cap‐rocks must be placed in the frame of a hydrocarbon habitat which evolves with time to judge properly the retention risk. Important parameters are rate of diffusion of hydrocarbons through cap‐rocks, and fracture development as a function of the intensity of geomechanical deformation. When losses due to seal failure and diflusion occur, replenishment from an active generation‐migration system may counter‐balance the loss. “Giant” oil‐ and gasfields serve as a yardstick for measuring shale—evaporite ratios and seal depths. Surface seepages can provide a measure of seal failure. As the cap‐rock problem is in an initial stage of research, many uncertainties affect the reliability of semi‐quantitative statements on risks of sealing and retention.
THE PHYSIOGRAPHIC FEATURES OF THE MIOCENE RAS MALAAB GROUP BASIN, SOUTH BAKR OILFIELD, GULF OF SUEZ, EGYPT
Authors: Elzarka Mohamed Hossny , Wally Mokhless M.
Published: December 2007

The lithostratigraphy and petrography of the Ras Malaab Group were investigated in order to define the physiography and structure of the depositional basin. The Ras Malaab Group consists, from the top, of the Zeit, South Gharib and Belayim Formations.

The basal Belayim Formation consists of carbonate barrier (reefal, lagoonal and marine tidal‐flat carbonates, located from east to west respectively in the basin. Thus. reefal limestones and evaporites are associated within the succession of the Belayim Formation.

The overlying South Gharib Formation is composed of thick evaporite sediments that were deposited in a restricted, subsiding salina basin. Intense subsidence in the western part of the basin is related to faulting.

The Zeit Formation consists of evaporites and fine clastics derived from surrounding land‐masses. The Zeit sequence indicates relatively deeper, semi‐restricted, lagoonal conditions.
PETROLOGY AND KINETICS OF GYPSUM—ANHYDRITE TRANSITIONS
Authors: Billo S. M.
Published: December 2007

Despite suggestions by some workers that most, if not all, the calcium sulphate in natural evaporites was originally deposited as gypsum, controversy concerning the origin of anhydrite has arisen, both because bedded anhydrite is common throughout much of the geologic record, and also as a result of the discovery of the recent anhydrite formations in the UAE, Persian/Arabian Gulf, and other areas. In addition, an inability to synthesize anhydrite in the laboratory under geologically reasonable conditions has caused the reliability of previous experimental methods to be doubted. However, new evidence from studies of chemical kinetics indicates that supersaturation and surface energies in the CaSO4— H2O system may regulate primary anhydrite precipitation. Arguments for and against the universality of gypsum as the sole origin of anhydrite are here related to specific facts and relevant observations from the fields of petrology, geology, and geochemistry.
ENVIRONMENTAL SETTING AND DIAGENESIS OF LOWER PERMIAN PALAEOAPLYSIND BUILD‐UPS AND ASSOCIATED SEDIMENTS FROM BJØRNØYA: IMPLICTIONS FOR THE EXPLORATION OF THE BARENTS SEA.
Authors: Lønøy A.
Published: December 2007

Lower Permian palaeoaplysinid build‐ups, inter‐bedded with inter‐build‐up logoonal sediments occur both on Bjornoya † and in the subsurface of the Barents Sea. They formed on a low‐energy, broad and shallow shelf, and show a cyclic development which was probably related to minor eustic sea‐level changes. During periodic lowering of sea level, build‐ups were subaerially exposed, meteoric diagenesis with Karstification took place within the build‐ups, and hypersaline conditions prevailed in the lagoons.

Most diagenetic changes took place early and include fresh‐water dissolution, dolomitization, evaporite precipitation, and pseudomorphic replacement of evaporites. Fracturing and associated hydrothermal calcite, barite and galena cementation occured during the Early Tertiary opening of the Norwegain‐Greenland Sea, and affected the entire western part of the Barents Shelf.

In the Barents Sea, the palaeoplysinid build‐ups have composite thickness on the order of several hundred metres and are restricted to positive structural elements. They are regarded as potential reservior rocks in this area, partly because of the high porosity of similar build‐ups in Central Spitsbergen. The reservoir quality of the build‐ups on Bjornoya and from the single cored build‐up complex in the Barents Sea is, however, relatively poor. Early Tertiary fracturing increased the permeability of the bulk rock, but also caused leakage of accumulated hydrocarbons.
COMPOSITE CLASSIFICATION OF FRACTURED AND BRECCIATED CARBONATE ROCKSB EXAMPLES FROM THE ORDOVICIAN ELLENBURGER GROUP, WEST TEXAS
Authors: Ijirigho B. T. , Schreiber J. F.
Published: December 2007

The attention paid to rock fracturing in recent years is a result of the discovery of large volumes of hydrocarbons in fractured rock reservoirs. This regional study was conducted in order to facilitate a better understanding of the performance of fractured reservoirs, and to select the proper procedures and well intervals for artificial fracturing.

Five classification schemes are proposed for fracture, breccia, porosity and permeability developments, as revealed by mega‐ and microscopic examination of cores, thin‐sections and outcrop samples. A composite classification combines the attributes of the other schemes in an attempt to predict residual porosity and permeability on a reservoir scale. Various genetic types of breccia were encountered in this study, but those of tectonic origin predominate and control hydrocarbon production.

At the initial time of fracturing, porosities range from low in crackle breccia, to very high in random and pheno‐breccias. With moderate cementation, random and pheno‐breccias remain the most porous and permeable structures, However, with a high degree of cementation, porosity and permeability become negligible in crackle breccia, and very low or absent in pheno‐breccia. The degree of cementation which controls residual porosity depends on the availability of mineral‐laden solutions.
THERMAL MATURATION HISTORY OF THE SIRTE BASIN, LIBYA
Authors: Gumati Y. D. , Schamel S.
Published: December 2007

The high degree of thermal maturity observed in shallow sediments in the western part of the Sirte Basin, Libya, requires higher geothermal gradients and/or thicker overburden in the past than exist today.

The degree of thermal maturity of the Upper Cretaceous shales, the regional structure, and the subsidence history of the basin all indicate that over 3,000 m of section was removed from the western flank of the basin by uplift and erosion in the mid‐Tertiary. Vitrinite reflectance values in wells suggest that gradients of 1.6d̀FC/100 ft to 1.8d̀FC/100 ft existed in the western region at the time of peak thermal activity, in contrast with a general basin average of 1.2 d̀F/ l00ft
THE HYDROCARBON POTENTIAL AND TECTONICS OF INDOCHINA*
Authors: Hayashi M.
Published: December 2007

The region under discussion is that part of Indochina which includes Vietnam, Laos, Kampuchea and eastern Thailand. The Kontum Massif composed of a metamorphosed basement complex, is the core of the Indochina region, and crops out from eastern Vietnam to Laos and Kampuchea. The concept of concentric growth of orogenic belts along the periphery of this massif seems to have been accepted as being within the scope of the classic theory of orogeny. The application of a modem plate‐tectonic hypothesis with the aid of Landsat image analysis, has, however, enabled a new interpretation of the tectonic development of the area to be made.

The hydrocarbon potential of Indochina is here investigated, based on this interpretation of the region's tectonic development, and taking account of the morphological and textural characteristics detected from Landsat imagery. Three areas: (1) the Mekong Delta. (2) the Khorat Plateau, and (3) the Hanoi Basin‐gulf of Tonkin, are selected for detailed discussion of their hydrocarbon potential.
STRUCTURAL CONTROL OF NEOGENE SEDIMENTATION IN THE MAE SOT BASIN (THAI‐BURMESE BORDER): IMPLICATIONS FOR OIL‐SHALE RESERVES
Authors: Stokes R. B.
Published: December 2007

The Mae Sot Basin is here interpreted as a tilted fault‐block bounded on the east by a normal fault which, acting as a growth fault, controlled sedimentation during the Neogene. It is suggested that oil‐shale reserves are greater than those currently estimated, and that they may be greatest near the eastern margin of the basin due to the development of a thicker sequence here, and repetition of the facies at depth in sedimentary cyclothems.
SURFACE AND DEEP STRUCTURAL CONTROL OF THE NW CARBONIFEROUS BASIN OF IRELAND: SEISMIC PERSPECTIVES OF AEROMAGNETIC AND SURFACE GEOLOGICAL INTERPRETATION
Authors: Price C. , Max M. D.
Published: December 2007

A detailed study of the magnetic and seismic data in and adjacent to the NW Carboniferous Basin of Ireland suggests that surface faults, mainly in the Carboniferous and Devonian rocks, are directly related to regional faults on older subjacent basement. These regional faults have controlled the tectonics of the area since the Late PreCambrian.

The primary faults are associated with the steeply‐dipping fault zone whose presence is marked by the Fair Head‐Clew Bay magnetic linear (FCL). The FCL can be traced to the east where it becomes concident with the Highland Boundary Fault zone of Scotland. The Highland Boundary Fault maarks the southern limit of the Dalradian rocks. and was a plate margin beignning in Late Combrian‐ Early Ordovician (Grampian)times. In ireland, the FCL also marks this Lower Paleozoic plate boundary. Associated secondary magnetic linears (linears) indicate the presences of other basement fault caused by mkovement on the FCL, which were rejuvencated during the Upper Paleozoic.

Large magnitude movement on these fault‐systems commenced druging the Early Paleozoic and continued through the Devonian, with lesser magnitude movement continuing until after the Carboniferous. The abrupt change from the more than 4,500 m of Paleozoic sediments present south of the FCL to approximately 1,500 m of sediments to the north is a result of complex wrench‐faulting, shown by flower structures in seismic profiles, Fold orientations and fold and fault deflections near the major sinistral fault are also consistent with formation within a sinistral strain field.
EVIDENCE FOR NON‐COLLISION GEOLOGY IN THE MIDDLE EAST
Authors: Kashfi M.S.
Published: December 2007

It is customary to interpret ophiolite belts, including those of the Middle East, as remnants of oceanic crust. However, the mere presence of an ophiolite belt by itself is not proof that it is the site of a former subduction zone.

It is argued in this paper that no subduction zone is, or ever was, present in the Middle East. Earthquake‐intensity and earthquake‐epicentre maps show that shocks of magnitude 6.5 and greater (Richter scale) take place in many areas far removed from proposed subduction zones. Even the major proposed subduction zone of the Middle East‐the Zagros “suture” or Zagros “crush zone”‐ has no associated volcanic rocks, and therefore lacks the lithological suit which typifies so‐called subduction zones. Moreover, basement‐rock exposures and basement reached in deep boreholes indicate that at least the major part of the Zagros Fold Belt is underlain by continental, non‐oceanic crust.

The fact that identical lithofacies of the same, late PreCambrian through Early Tertiary, are present on both sides of the alleged subduction zone should be enough to give one cause for thought. Well‐known and closely related faunas have been described from Early and Late Paleozoic strata on both sides of the Zagros suture for many decades.

Disagreements among plate tectonicists are many. Some advocate the former presence of two or more plates in this region; others have postulated several microplates; other workers support island‐are interpretations; almost all favour the existence of at least one suture zone that marks the locus of a continent‐continent collision. Nearly all of these hypothese are mutually exclusive. Most would cease to exist if the field data were honoured. These data show that there is nothing in the geologic record to support a separation in the past of Arabia‐Africa from the remainder of the Middle East.
GEOHISTORY, THERMAL HISTORY AND HYDROCARBON GENERATION HISTORY OF NAVARIN BASIN COST NO. 1 WELL, BERING SEA, ALASKA
Authors: Cao S. , Lerche I.
Published: December 2007

Using a one‐dimensional model, we numerically simulate with time the geological processes of sedimentary deposition, compaction, fluid flow, heat flow and hydrocarbon generation. Input well data, in the form of present‐day formation thicknesses, porosity with depth, thermal gradient, vitrinite reflectance with depth, and fluid overpressure with depth constrain the dynamical model. We present model results for the Navarin Basin COST No. 1 well, including reconstructions of burial history, fluid flow history, thermal history and hydrocarbon generation history.

We also demonstrate how important geophysical variables (such as permeability, porosity, fluid pressure, fluid‐flow rate, and thermal maturity indicators) vary with depth and time. Comparison of the model results with observed data illustrates and emphasizes the capabilities of the modelling procedure.

The significance of the dynamical model is that it permits a quantitative assessment to be made of (i) the timing and depth locations of the generation and migration of hydrocarbon in a basin, relative to the formation of structural and stratigraphic traps: (ii) the timing of the production of overpressuring and fracturing within a basin: and (iii) the effect of cementation and dissolution on the retention of hydrocarbons in a trap. The model also enables an assessment to be made of the most likely prospective areas for hydrocarbon accumulation in a basin.
A MODEL THAT QUANTITATIVELY EXPLAINS GEODYNAMICS:
Authors: Giardini A.A. , Melton C.E.
Published: December 2007

A model is presented that traces quantitatively the history of geodynamic processes, from the time of origin of the Earth to the present time. Initially, the Earth underwent a slow, cool, homogeneous accretion, then a non‐catastrophic formation and melting of the core. Thereupon, the gravitational interaction of the Moon and core produced a thermal power of about 1013 watts. It is this power that creates the buoyant force for the upflow of convection. The convection is shown to serve three function: (1)the transference of heat from the mantle base to the surface for radiation to space: (2)the uplift to the surface and separation from the convection cycle of “incompatible” constituents: and (3) the redistribution of heat from the mantle's base to its body by conductive transfer. The “incompatible” constituents include continental, oceanic, atmospheric. Petroleum and radionuclide materials. They are stored initially in the asthenosphere region up to a limiting capacity that ensures the thermal integrity of the lithospheric shell. The capacity range is regulated by a periodic relief mechanis: namely, a controlled penetration of the lithosphere and eruption of continental and other “incompatible” material to the surface. The transfer of radionuclides to the surface region acts to regulate the conductive thermal loss from the Earth's interior in order to maintain a steady state. Mantle heat lost by removal of radionnuclides is replaced via conductive transfer from the hot, upflowing convection. The mechanisms of cooling in the 400‐km deep surface leg of the convection, the formation of the continents, and the pattern of heat flow from the Earth's surface are analysed in detail. A thermodynamic analysis of the convection cycle is presented, as well as detailed power analyses for the various work functions that are involved in the convection. Values obtained for power input and out put of the convection are in agreement to within 2%.
THE HEZAN UNITS: A FRAGMENT OF THE SOUTH NEO‐TETHYAN PASSIVE CONTINENTAL MARGIN IN SE TURKEY
Authors: Fontaine J. M. , Monod O. , Perincek D.
Published: December 2007

Recent progress in structural and stratigraphic analysis of the allochthonous units situated north of Hazro in the Border Fold zone of SE turkey has shed light on the nature and signijicance of the Gondwanan margin there. Allochthonous material consists of several superimposed units ranging in age from the Early Trias to the Late Senonian (Hezan units), in which the transition between neritic carbonates and the pelagic and detrital facies is well indicated by an Ammonitico‐rosso facies of mid Jurassic age. Above it, ophiolitic material and radiolarites represent the former Tethyan crust and cover. The Hezan units thus belong to the former Gondwanan margin thrust southwards in Lute Cretaceous times, and a tentative reconstruction of its Mesozoic evolution there is facilitated by the absence of later major tectonic events.

This reconstruction shows marked diferences compared with the more complex nearby margins described in the Hellenides or Zagrides, where parallel ridges and troughs reflect crustal extension. By contrast, the simple “staircase”geornetry of the present margin is best interpreted as the result of the fracturing of the Gondwanan continent, separating the Apulian and African Plates as early as the Trias.
COMPARISON OF KEROGEN MATURATION AND ILLITE/SMECTITE SOMPOSITION IN DIAGNESIS
Authors: Velde B. , Espitalié J.
Published: December 2007

Kerogen maturation, estimated from pyrolysis Tmax values is compared with the smectite laayer‐content of the illite/smcetite mineral derived from sediments in six suites from different basins with different ranges of statographic age. The most significant correlations are made when camparing Tmax and estimated percentage kerogen transformation with sample age for the same smecite layer‐content (iso‐smectite content or stage of clay maturation) the percentate transformation of Type III kerogen and smectite layer‐content shows a regulare relationship at the end of the clay reaction series (10 smectite content), which includes the oil and gas potential range for sediments in the 200‐100 MM year age groups. Relations between less mature, more smectic illite/smectite clay minerals and kerogen maturation are not at present clear
THE HYDROCARBON PROSPECTS OF THE RED SEA‐GULF OF ADEN: A REVIEW
Authors: BEYDOUN Z. R.
Published: December 2007

The area reviewed covers some 825,000sq. kms. Since the early 1960s. 52 exploration wells have been drilled in the Red Sea. leading to four undeveloped (mainly gas‐condensate and dry gas) discoveries; twelve exploration wells have been drilled in the Gulf of Aden since the late 1970s, leading to one undeveloped oil discovery. Numerous surface oil seeps in the Red Sea testify to oil generation, while many of the drilled wells have also had shows.

The syn‐and post‐rift Neogene stratigraphy of the Red Sea is very similar to that of the prolific oil‐producing Gulf of Suez graben, with source, reservoir and seal rocks widely present; pre Neogene rocks. however, are only present in patches. and include some marine Paleogene and Late Cretaceous sediments on older continental clastics in the northern half, and marine Jurassic on Basement in the southernmost sector. In the Gulf of Aden, the Neogene is less thickly developed, and lacks the widely‐occurring evaporite sequence of the Red Sea; the marine Paleogene and Creataceous‐Jurassic sequences of the pre‐rift succession are, however, welldeveloped, although the Jurassic is locally removed by block erosion.

The tectonic evolution of the two rift basins is here discussed, and evidence for the areal extent of oceanic floor or stretched coninental crust. for episodic or continuous extension and sea‐floor spreading, and for pre‐rift doming and fracturing, is reviewed. It is concluded that episodic extension and spreading have occurred, and may be more advanced in the Gulf of Aden than elsewhere; this has been accompanied by higher paleo‐temperatures and geothermal gradients along the margins in the past, and high present‐day heat‐flow in the axial regions of both rifts. Overmaturation of the pre‐rift sequence in the southern margins of the Red Sea has resulted, aided by deeper burial, but contrary to prevalent views that the regions is too hot and gas‐prone, black‐oil potential in both basins is present at depths ranging from 1,000 m to a maximum of 4,500 m.

Hydrocarbon play in the Red Sea is principally Neogene, and traps are provided by rotated Basement fault‐blocks and horsts in the pre‐evaporite sequence, and by salt flowage and piercement, together with stratigraphic pinch‐out, in the post‐evaporite sequence. In the Gulf of Aden, the main play is in the pre‐rift Paleogene sequence, while lower potential also exists in Neogene and Mesozoic successions. The Arabian side of the Red Sea has the widest and most poorly‐explored shelf of the whole region.
THE SUDANESE RED SEA: 1. NEW DEVELOPMENTS IN STRATIGRAPHY AND PETROLEUM‐GEOLOGICAL EVOLUTION.
Authors: Bunter M. A. G. , Magid A. E. M. Abdel
Published: December 2007

The development of the Red Sea‐Gulf of Suez Rift follows two tectonic phases: pre‐rift and syn‐rift: rifting of the Afro‐Arabian craton was initiated in Eo‐Oligocene times. Generally good reservoir‐quality fluvio‐deltaic and marginal‐to fully‐marine Palaeozoic, Mesozoic and lowermost Cenozoic (Palaeogene) rocks had been deposited and are partly preserved.

Marine Upper Cretaceous shales, carbonates and sandstones in the Gulf of Suez change facies to more continental sandstones of the Sudanese Red Sea; similarly, Post‐Cretaceous pre‐rift limestones and shales change facies to shallow‐marine sandstones. Syn‐rift sedimentation on either side of the Red Sea axial trough is essentially identical to that of the Gulf of Suez. As a consequence of this, the Gulf of Suez ingredients of mature oil‐prone source rocks, reservoirs and seals are present in the Sudanese Red Sea. Heat flows are higher in the Red Sea than in the Gulf.

During the early pliocene there was a further episode of doming, further Red Sea extension took place, and the Red Sea attained its current shape.

Remapping of 5,000 kms of 1970's‐vintage seismic data in the Sudanese Red Sea has resulted in recognition of many new prospects, which include: post‐salt prospects, similar in structural style to the structures tested by the successful Sudanese Red Sea Suakin‐1 and Bashayer‐1A gascondensate and dry gas discoveries; base‐evaporite prospects of a structural style virtually untested in the Sudanese Red Sea, but known to be prospective in the Gulf of Suez; and preevaporite prospects with structural styles indentical to those most prospective in the Gulf of Suez.
THE SUDANESE RED SEA: 2. NEW DEVELOPMENTS IN PETROLEUM GEOCHEMISTRY
Authors: Bunter M. A. G. , Magid A. E. M. Abdel
Published: December 2007

From the limited analytical data which is available from the study area, it appears that the Mukawar and Hamait Formations, sandy facies of Upper Cretaceous and Cenozoic age, have little or no hydrocarbon source potential. However, of the twelve Sudanese Red Sea wells, only one penetrated the Mukawar Formation. and the Hamamit is only known in four wells.

On the other hand, the lower to middle Miocene Rudeis. Kareem and Belayim Formations were penetrated in several wells. and may have actually generated black oil in attaining their current levels of thermal maturity. The middle to upper? Miocene Dungunab Formation, which is equivalent to thesouth Gharib Formation of the Gulf of Suez. contains thin. regionallyextensive, intra‐evaporite shales. These are early‐mature in coastal areas but, if developed in the deeper offshore. are likely to be post‐mature and are likely to have generated hydrocarbons. The zeit Formation is of variable thickness. the maxima coniciding with areas of deltaic influence. Although information is limited, it appears that occasional thin shales units may have significam source potential. The areas of more concentrated deltaic sedimentation with in the Zeit Formation are more likely to provide gas‐prone source rocks. The Plio‐pleistocene Abu Shagara Group has no oil source‐potential in the nearshore areas. Potential may improve further offshore. where it is possible that these marine sediments may be richer in organic matter and have been subject to higher heat flow.

Hydrocarbon generation in the Sudanese Red Sea had been influenced by many factors in addition to rift‐controlled subsidence. These include the high thermal conductivity of evaporites, tectonic overpressuring and, in deeper waters, significantly higher levels of heat flow. Lower to middle Miocene source rocks are likely to have generated hydrocarbons at the end of Miocene times, whereas younger source rocks could be generating hydrcarbons at the present.

The source of gas in the Suakin‐1 gas‐condenstae and Bashayer‐1 dry gas discoveries is probably in the lower part of the Zeit Formation, an organically‐rich deltaic facies. The condensate at Suakin‐1 is likely to have been sourced from the inter‐evaporitic shales of the underlying Dungunab Formation. Black‐oil shows have been recorded at several Sudanese Red Sea wells and a significant gas‐condensate discovery was made at Barrqan‐1 in the northern part of he Saqdi sector. It has been suggested that reserves of condensate may be as high as half a billion barrels. Oil seeps on the Dahlac and Farasan Islands in the Ethiopin and Saudi sectors provide further grounds for an optimistic view that generation of commercial volumes of oil in the Sudanese Red Sea cannot be ruled our
PROSPECTS FOR PETROLEUM IN LATE PROTEROZOIC/EARLY PALAEOZOIC BASINS OF SOUTHERN‐CENTRAL AFRICA
Authors: Lawrence S. R.
Published: December 2007

Interest has focused on Late Proterozoic/Early Palaeozoic basins in the light of encouraging indications from the Cuvette Centrale of Zaire and the Etosha Basin of northern Namibia.

This paper focuses on the Ncojane‐Nosop (Nama) basin complex, which extends along the southern side of the “Pan‐African” Damara orogenic belt. The basin system is seen as a foredeepforeland development with respect to a Wilson‐cycle ‐ cratonic collision orogenic history.

Stratigraphy and facies developments are used to speculate on the occurrence of source and reservoir rocks. Source rocks would appear to be concetrated in the marginal marine‐lagoonal sediments of the Kuibis and Schwartzrand subgoups of the lower Nama. Reservoirs might occur in reefal or shallow‐water limestones the lower Nama, and in upper Nama “red‐beds” of the Fish River subgropu.

Subsidence‐uplift models are used to predict burial/maturation for the lower Nama. There is a critical late or post‐Nama metamorphism, which effectively destroys the source rocks in the foredeep and increases the general level of maturity some distance from the orogenic front. The occurrence of prospective source‐rock facies and the maturity histroy are used to extrapolate the prospective part of the basin eastwards into Botswana.
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.
MESOZOIC‐PALAEOGENE BASIN DEVELOPMENT WITHIN THE EASTERN MEDITERRANEAN BORDERLAND
Authors: Abu‐Jaber N. S. , Kimberley M. M. , Cavaroc V. V.
Published: December 2007

Pre‐Alpine structures in the SE Mediterranean (Levant) are characterized by regional extensional features, which are associated with opening of the Mediterranean Sea. Marginal marine basins apparently began forming during the Triassic and Jurassic, and reached their apex during the Cretaceous. Stress patterns attributed to early development of the Mediterranean are similar to those seen in the relatively stable adjacent continental margin. The two major structural‐basin trends in the continental margin are orthogonal, e.g. the NW‐SE trend of the Sirhan Basin, and the NE‐SW trend of the Palmyra Basin. The western convergence of these two basins is marked by basaltic flows and volcanoclastic deposits, probably related to basaltic volcanism in the nearby Mediterranean Sea. These two basins maintained a largely unimpeded circulation of seawater with the opening Mediterranean, and therefore they contain few highly carbonaceous beds. Post‐rift shortening apparently produced minor petroleum resources.
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.
PROSPECTIVE PETROLIFEROUS AREAS IN THE EAST CHINA SEA BASIN
Authors: Guochen Wang
Published: December 2007

The East China Sea Basin is a major Cenozoic basin, with a sedimentary fill greater than 10,000 metres in thickness. The evolution of the basin is divisible into four stages‐down‐faulting, fault‐sagging, down‐warping and draping. Tectonic movements were characterized by multiple episodes of spatial differentiation, and tectonic units are divisible into longitudinal zones and latitudinal blocks. Various types of trap structure are present, including Tertiary sandstone traps, basement traps, and reef traps.
ORDOVICIAN GAS ACCUMULATIONS IN EASTERN CHINA
Authors: Jinxing Dai , Yinghe Xia
Published: December 2007

Commercial accumulations of Ordovician natural gas have been discovered in the Bohai Bay Basin, Ordos Basin and Sichuan Basin of eastern China. The total proved gas reserves account for about 4% of the non‐associated gas reserves of P.R. China. Accumulations can be divided into fault‐block, anticlinal and litho‐stratigraphic types. Reservoirs are located in carbonate rocks, and are sourced either from the Ordovician in situ or from the overlying Permo‐Carboniferous coal measures.
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.