bluuebunny/crossref_metadata_2025_split huggingface dataset:
A SOURCE BED STUDY OF THE OLIGO‐MIOCENE ASMARI LIMESTONE IN SW IRAN
Authors: Kashfi Mansour S. 
Published: December 2007

Detailed geological and geochemical investigations in the folded belt of the Zagros geosyncline reveal that the source rocks for the very large Asmari oil accumulations may not be the PabdehGurpi and/or Kazhdumi formations as has been suggested; the hydrocarbons are more likely to be indigenous to the Asmari. Most previous investigators have assumed that only organic‐rich marls and shales serve as effective source rocks. However, geochemical analysis shows that the organic content of the Asmari carbonate, although not very rich, compares favourably with the source beds proposed by earlier workers.A rock should not be considered an oil source bed if it does not currently contain at least traces of oil. If the oil had been generated in the Pabdeh‐Gurpi and/or Kazhdumi formations, some hydrocarbons should still be present within these rocks.For all source rocks, there must be a positive relationship between thermal history and oil generation. Consequently, temperature and depth of burial are essential factors in petroleum genesis. The temperature history of the Asmari Formation is related to the thickness of the overlying Teritiary rocks. Maximum burial of the oligo‐Miocene Asmari, throughout most of the folded belt, is assumed to have occured during Early Pliocene time before the last phase of Zagros orogeny.Asmari limestone, therefore, qualifies as a source rock where it is buried deep enough to reach the optimum temperature needed to release its hydrocarbons. Under conditions of lower temprature and shallower burial, the limestones serve only as reservoir rocks.
GEOLOGY AND EXPLORATION IN THE TAKUTU GRABEN OF GUYANA BRAZIL
Authors: Crawford F. D. , Szelewski C. E. , Alvey G. D. 
Published: December 2007

The Takutu basin is a Mesozoic graben 280 km long and 40 km wide in northern Brazil and adjoining Guyana. It occupies an ancient Pre Cambrian shear zone within the heart of the Archean Guyana shield. Metavolcanic rocks and thick Proterozoic quartzites crop out north of the basin. Granitic rocks border the graben on the south and east. Mesozoic basalt forms a band of outcrop along the southern and eastern margins of the modern‐day valley. The basin is filled with up to 5,400m (18,000 ft) of Mesozoic sedimentary rocks, underlain by more than 1,700m (5,600 ft) of mafic volcanics of Jurassic and possibly older (i.e, Proterozoic) ages. Six regional unconformities were recognized within the basin fill.The geologic history of the graben is characterized by one volcanicphase and three depositional phases. Rifting began in Late Triassic to Early Jurassic time with the extrusion of thick Apoteri flow basalts. Lower Jurassic non‐marine clastics of the Manari Formation overlie the eroded basalt. They are overlain by the thick Lower and Middle Jurassic non‐marine salt and gray shale of the Pirara Formation. These sediments were deposited over most of the basin and contain good oil source‐rocks. Middle and Upper Jurassic non‐marine clastics of the Takutu Formation overlie the evaporites. They were deposited in lacustrine and deltaic environments, as interpreted from seismic and well data.There are two contrasting structural styles, of Late Triassic to Early Jurassic, and Cretaceous to Tertiary ages. Block‐faults are common in the pre‐salt section, and non‐piercement halokinetic structures in thepost‐salt rocks. The graben contains a cross‐basin arch, evidence of wrench faults and minor salt solution.Four exploratory wells have been drilled to date. Home Karanambo No. 1 discovered highquality crude oil in the fractured volcanic basement. Seismic stratigraphic interpretations indicate that alluvial fan and deltaic reservoirs may overlie undrilled structures elsewhere in the basin.
LAGOA FEIA FORMATION (LOWER CRETACEOUS), CAMPOS BASIN, OFFSHORE BRAZIL: RIFT VALLEY STAGELACUSTRINE CARBONATERESERVOIRS ‐ I
Authors: Bertani Renato T. , Carozzi Albert V. 
Published: December 2007

The Campos Basin is one of the coastal basins of eastern Brazil formed during the separation of the African and South American continental blocks. The Lagoa Feia Formation consists of the sediments deposited during the rift valley stage of the Campos Basin, and varies from 200 m to more than I, 500m in thickness. 17 microfacies were recognized, and are grouped into four main sequences, dominated respectively by terrigenous supplies, ostracods, pelecypods and basic volcaniclastics.The vertical sequence of microfacies and the associations of syndepositional diagenetic minerals were used to reconstruct the general environment of deposition. It consisted of saline alkaline lakes, oscillating between a playa lake stage with ostracod microfacies and a pluvial lake stage with pelecypod microfacies.Five diagenetic stages were recognized: syndepositional alteration of lithics to trioctahedral smectites, early dolomitization, early silicification, early cementation by bladed rim calcite and zeolites; fresh water vadose, consisting mainly of dissolution of bioclasts and lithics; fresh water phreatic, with sparite cementation and neomorphism; mixed saline‐fresh water, represented mainly by silicification; and burial with compaction, late dolomitization and partial conversion of smectites to illite.Pelecypod‐rich limestones with primary interparticle, secondary intraparticle, moldic and moldic‐enlarged porosities constitute the main potential reservoirs. The ideal conditions for the generation and preservation of such reservoirs consisted of periods of exposure followed by rapid lake expansion and burial. In this manner, the secondary porosity formed in the vadose fresh water environment was preserved or only partially occluded by calcite cementation during fresh water phreatic conditions.
THE PETROLEUM RESOURCES OF THE MIDDLE EAST: A REVIEW
Authors: Beydoun Z. R. 
Published: December 2007

The area under review is the Arabian Peninsula, Fertile Crescent and parts of SE Turkey and SW Iran (Arabian Plate plus Levant). Petroleum production is essentially from the eastern part or the Iraq‐Iran‐Arabia basin. Published proved oil reserves at the start of 1985 were estimated at 398.7 B† brl (barrels) and those for natural gas at 869.95 T‡ cu. ft (53 B tonnes and 24.8 T cum respectively) amounting to 57% of estimated world oil reserves and 25.6% of world gas reserves. The region produced 21.2% of world production in 1984 (but had produced 38.8% in 1974, the drop being due to non‐technical reasons). The oil reserves are attributable to some 290 producing fields and undeveloped discoveries, 25 of which are “supergiant” and 69 of which are “giant” in size. Only about 122 of these fields and discoveries are actually producing (excluding Turkey's 30 which account for little of the total).The reasons for the prolific oil abundance lie principally in the repeated extensive deposition of organically‐rich source rocks under anoxic conditions in the right juxtaposition with very permeable extensive reservoirs and sealed by regionally extensive efficient seals over several intervals of geological time, charging extremely large anticlinal traps formed by a variety of structure‐forming mechanisms available at optimum hydrocarbon maturation and migration times. Accumulations occur in Paleozoic sands in southern Oman charged from Infra‐Cambrian source rocks, and in Middle and Upper Jurassic carbonates and Lower and Middle Cretaceous carbonates and sanhtones in the central part of the basin (the Gulf), and the Zagros fold belt, as well as in the Oligo‐Miocene carbonates in the latter charged by vertical migration from the Cretaceous. The NW‐most part has heavier Middle‐Upper Cretaceous and some Miocene oil of differing origin and Triassic light oil, gas and condensate extending into central Syria. Subordinate Paleogene heavy oil occurs in the Kuwait‐Basra area. Other new discoveries of Mesozoic and Paleogene age have occurred in Jordan and North and South Yemen.All Middle East countries with the exception of Lebanon now either have established production or discoveries under assessment. Even in the main basin, exploration has not been intensive and future efforts including enhanced recovery methods will lead to considerable success and are expected to add new reserves equal to those now established for oil and probably more than those now estimated for gas, with a 50% chance of success. Saudi Arabia, Iraq and UAE are ranked highest, but small basins outside the main area will yield important finds by utilisation of the latest in geophysical and geochemical methods.
PATTERNS OF HYDROCARBON OCCURRENCES IN THE VIKING FORMATION, ALBERTA, CANADA
Authors: Amajor L. C. 
Published: December 2007

Most NW‐SE trending, offshore, tide‐generated reservoir sandstones in the Lower Cretaceous Viking Formation of Alberta and Saskatchewan produce oil and/or gas from their NE flanks. This is because stronger tidal currents sorted and shifted finer sediments from the NE to the SW in the direction of sandbody migration. Thus, the NE flanks are older, thinner, coarser and better sorted with good reservoir characteristics. Post‐despositional tilting, however, provided optimal conditions for oil and gas entrapment.This pattern of hydrocarbon occurrence may be more profitable if applied to the exploration and development of oil and gas in the less‐developed sand units.
NEW EVIDENCE FOR A PETROLEUM SOURCE ROCK IN A MIOCENE EVAPORITE SEQUENCE, GULF OF SUEZ, EGYPT
Authors: Kholief M. M. , Barakat M. A. 
Published: December 2007

Anhydrite, gypsum and halite evaporites of Middle Miocene age occurring in the Gulf of Suez area constitute more than 50% of the total rock components. They are intercalated mainly with shales and also subordinate carbonate and sandstone layers. Examination of several evaporite samples under both binocular and petrographic microscopes reveals the presence of inclusions of various types hosted by gypsum crystals. Solid inclusions are composed mainly of minute calcareous particles, fine pyrite crystals and residual organic matter, while liquid inclusions, which are more frequent, exist in a uniphase or biphase state. A light hydrocarbon in the form of oil or gas constitutes one of these phases, while the other is a brine. Most of these inclusions are of primary origin and have been developed during the growth of the hosted minerals.Based on the assemblage of these inclusions, it can be assumed that the evaporitic environment of deposition, with its reducing condition and high salinity, is favourable for the generation of oil from accumulated organic matter. Also, the presence of a carbonate mineral trapped by gypsum indicates the possible mixing of marine water with a brine of restricted occurrence.
SUBSURFACE GEOLOGY OF THE MIOCENE GHARANDAL GROUP IN THE SOUTH BAKR OILFIELD, GULF OF SUEZ, EGYPT
Authors: Elzarka Mohamed Hossny , Wally Mokhless M. 
Published: December 2007

The mineralogical composition of the Miocene Gharandal group has been studied petrographically, and has been confirmed by chemical analyses and Differential Thermal and X‐Ray Diffraction analyses (DTA andXRDA). These investigations have been supplemented by geological mapping, which has revealed the geological setting and paleoenvironmental conditions of the Lower Miocene Gharandal group at the South Bakr oilfield.The lithic association of the Nukhul and Rudeis formations indicates that deposition took place in a shallow‐marine environment in the sublittoral zone. The mineral association of the rocks of the Kareem Formation suggests a semirestricted environment, where the chemical conditions changed from weakly‐oxidising to slightly reducing during the deposition of these sediments. The lithic association of the rocks of the Kareem Formation indicates that their deposition occurred in a barred basin. The basin was affected by gentle subsidence, which might be associated with post Early Miocene growth‐faulting in its western section.The rocks of the Gharandal group represent the lower section of an evaporite cycle of deposition.The structure and variation of the thickness and facies has led the Authors to present some deductions concerning the paleoenvironmental conditions under which the investigated rocks were formed.
THE DISTRIBUTION OF MAJOR OIL AND GAS RESERVES IN REGIONAL BASIN STRUCTURES – AN EXAMPLE FROM THE POWDER RIVER BASIN, WYOMING, USA
Authors: Pratsch J.‐C. 
Published: December 2007

The location and geographic distribution of oil and gas reserves within a producing basin often indicate that a remarkable concentration of reserves has taken place in a small area. The concentration of reserves is the result of secondary hydrocarbon migration, itself governed by the basin‐wide regional structure which was present at the time of migration. These factors permit the definition of the most prospective areas of a new basin or play at an early stage in the exploration cycle. Basic geochemical data are required for the definition of critical details of the effective generative depocentre, and regional geological‐geophysical data are required to establish regional structures near particular source‐bed levels, or near top Basement as the deepest prospective level. Other data commonly utilized in the early stages of exploration, such as basin classification schemes, reservoir bed studies and tectonic analyses, are rather less important in forward basin evaluation.A particularly clear example of the importance of the regional basement structure in the concentration of oil reserves exists in the Powder River Basin, Wyoming, USA. Cumulative oil production here was over 1.9 B brls** in 1984 from more than 460 oilfields and pools. However, 1.5 B brls (79% of the basin output) were produced from only 22 fields (4.7% of the number of fields and pools in the basin). It is also remarkable that all 22 major oilfields in the Powder River Basin are located on positive Bouguer gravity anomalies, which are expressions of deep basement irregularities. Regional lateral oil migration in the Powder River Basin appears to have utilized routes resulting from Laramide deformation (Late Cretaceous ‐ Paleocene).The resultant basin structure was accentuated by regional structural‐topographic anomalies, which became sites of major structural and stratigraphic traps. In this case regional gravity maps seem to show sufficient details of the deep structure for the accurate definition of major exploration targets.The Powder River Basin is thus an excellent example of the importance of regional geological and geophysical reconnaissance data aimed at, and available for, the definition of major migration pathways at an early stage of hydrocarbon exploration. When combined with geochemical data, such an approach will become the basis for forward exploration in all known basins.
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.
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.