bluuebunny/crossref_metadata_2025_split huggingface dataset:
DIAGENESIS OF THE TALISMAN‐1 RESERVOIR SEQUENCE, DAMPIER SUB‐BASIN, WESTERN AUSTRALIA
Authors: Ellis G.K. 
Published: December 2007

The Talisman‐1 well was drilled in 1984 at the NE end of the Dampier Sub‐basin, Western Australia, in permit WA‐191‐P. Testing of the Lower Cretaceous reservoir sequence produced an aggregated flow of 11,239 barrels of oil per day (b/d) from three drill‐stem tests. The reservior sequence consists of Berriasian to Tithonian mass‐flow sandstones (‘B’ and ‘C’ and Sands), and Hauterivian to Valanginian glauconitic shelf snadstones (‘A’ Sand), separated by claystone.An understanding of the diagenetic history of the Talisman‐1 reservoir sequence has been developed from thue integrated evaluation of petrography and petrophysics with hydrocarbon show, sulphur isotope, fromation water and oil composition data. This has, in turn, provided answers concerning controls on reservoir quality and the histroy of oil entrapment in the Talisman structure.Two pyrite/ferroan dolomite‐cemented sandstone intervals, below the present oil‐water contact in the Berriasian to Tithonian reservoir snadstones, are interpreted to have developed at palaeo‐oil‐water contacts in stacked oil accumulations formed during the Late Cretaceous to Early Tertiary. The pyrite and ferroan dolomite are considered to have developed as a result of anaerobic bacterial reduction of formation water sulphate. H2S and CO2 were generated, and reacted with iron derived from dissolution of glauconite to form pyrite and ferron dolomite. Glauconite dissolution has enhanced the porosity and permeability of the reservoir sandstone.Miocene tectonism produced minor faulting in the reservoir sequence, allowing cross‐feed of oil between the stacked “pays”, redistributing the oil accumulation to its present configuration. Lighter hydrocarbons preferentially leaked up the fault during this phase of tectonism, with some accumuluting in thc Hauterivian to Valanginian reservoir sandstone
THE VIKING (ALBIAN) RESERVOIR SANDSTONES OF CENTRAL AND SOUTH‐CENTRAL ALBERTA, CANADA
Authors: Amajor L. C. , Lerbekmo J. F. 
Published: December 2007

Bentonite chronostratigraphy indicates that deposition of the Viking Formation in central and south‐central Alberta and SW Saskatchewan occurred within three chrono‐intervals, informally designated Basal, Lower and Upper. Sandstones of the Basal and Lower Viking times were deposited offshore, while most Upper Viking sands formed along the strandline. In general, these Viking sands trend NW‐SE, are multiple, parallel, discrete units surrounded by wales, and are of varying thicknesses.The shoreline sands, which evolved slightly earlier than Basal Viking time, prograded NE towards the offshore for a maximum distance of about 250 kms, in places overlying the offshore sands. The offshore Basal Viking sands, characteristically thin, were deposited around Hamilton Lake, Provost, and up to Viking Kinsella in Alberta, as well as the Dodsland — Hoosier‐Smiley areas of SW Saskatchewan. The development of the Lower Viking sandbodies occurred slightly later, around the Sullivain, Ewing Lake, Joffre and Joarcam areas, SW and west of the basal sands. These offshore sand units migrated imbricatedly shorewards (SW), in opposition to the sense of progradation of the shoreline units. This SW‐direction of offshore sandridge migration is consistent with their NE flanks being relatively thinner, coarser and cleaner, suggesting NE‐SW flow currents along the NE flanks of ridges, and explains why most hydrocarbon reserves occur on the NE flanks of some of the ridges.The opposed sense of Viking sandstone migration resulted in the development of a thick mudstone interval between the strandline and offshore sandbodies, resulting in the development of a topographic sediment gradient that slopes NE. This pattern of Viking deposition explains the regional NE‐thinning pattern of the Viking Formation in Alberta, rather than it being due solely to a regressive shoreline, as previously thought.In general, Viking sandstone deposition appears to have ceased earlier in the NW than SE, suggesting that the SW source area (in the Nelson Batholith region) persisted longer than the western source area (coast Range area, west of Jasper). Missing, thin stratigraphic sections at the top of the Joli Fou, common in places in the area of the Basal sand deposition, suggest that much of the basal sediments are products of sea‐floor scouring by genetically‐related currents, rather than resulting from an unconformity, as thought by some earlier workers.
THE VIKING (ALBIAN) RESERVOIR SANDSTONES OF CENTRAL AND SOUTH‐CENTRAL ALBERTA, CANADA: Part II. Lithofacies analysis, depositional environments and paleogeographic setting
Authors: Amajor L. C. , Lerbekmo J. F. 
Published: December 2007

During Upper Albian times, the Haplophragmoides gigas and Inoceramus comancheanus sea occupied the interior of the North American continent. Deltas draining the Cordilleran mountains around Jasper and Long. 49d̀ funnelled clastics into the Albertan sector of this sea, particularly during Viking time (early Late Albian). These Viking reservoir sands were distributed along the strandline and offshore environments during a relatively still‐stand phase of the sea.Along the western shoreline, wave, longshore and tidal currents shaped these sands into NW—SE trending barrier islands, comprising 11 sub‐facies (ebb‐tidal delta, marginal spillover channel, middle shoreface, marine shale, upper shore‐beach, dune, back‐barrier mudflat, lagoon‐washover, mixed tidal flat, tidal‐creek channel and overbank), about 32‐m thick and over 116‐kms long. These sandstone islands migrated imbricatedly in a NE direction.In the offshore setting, about 20–250 kms from shore, tidal currents fashioned the sands into NW ‐ SE trending, parallel, linear, large‐scale sandridges, two to 30‐m thick, and about 25‐to 75‐kms long on average. The tidal sandridge sub‐facies, from base to top, include: lower bioturbated, heterolithic, cross‐stratified, upper bioturbated and chert pebble conglomerate units. Deposition of some of the ridges occurred below effective wave‐base. Storm‐and gravity‐induced currents complemented tidal currents in places.
PETROLEUM GEOLOGY OF THE MAKRAN REGION: IMPLICATIONS FOR HYDROCARBON OCCURRENCE IN COOL BASINS
Authors: Khan M. A. , Raza Hilal A. , Alam Shaji 
Published: December 2007

Six basinal elements have been recognized in the Baluchistan Basin on the basis of plate‐tectonic considerations. The Makran forms part of the southernmost coastal accretionary fore‐arc basin, where a more than six‐kms thick, relatively undeformed succession of neritic sediment overlies the turbidites. A reported oil seepage in the north, several gas seepages along the coast, abundant “bright spots” in the seismic profiles offshore, and the occurrence of hydrocarbons in similar geologic settings elsewhere, all support the recently‐emerging impression amongst the petroleum geologists involved in the area that the Makran region may provide a uniquely instructive setting in which to study petroleum occurrence in cool basin environments.Results of recent stratigraphic, sedimentological, tectonic and organicgeochemical studies in the Makran area are presented in this paper, in order better to understand the petroleum geology of the region and its implications for hydrocarbon accumulations.
TECTONIC SUBSIDENCE OF THE SIRTE BASIN, LIBYA
Authors: Gumati Y. D. , Nairn A. E. M. 
Published: December 2007

The Sirte Basin of Libya has a history of faulting and differential subsidence brought about by lithospheric extension during a 25 MM (million) year period beginning in the Late Cretaceous. The first phase of extension and initial subsidence, with faulting and graben formation, occurred from Cenomanian to Campanian times. Following extension. there occurred widespread thermally‐driven subsidence from Maastrichtian through Eocene and Oligocene times, accounting for about half of the total subsidence.Details of basin subsidence, sediment accumulation rates. and facies variations have been reconstructed for the northern Sirte Basin from a suite of approximately 100 completion well logs and numerous seismic lines. These show that at various times in the Late Cretaceous and Paleocene‐Eocene, renewed differential subsidence followed fault reactivation. Tectonic subsidence maps show a sysrematic SE to NW shift in the loci of maximum and minimum subsidence, which parallels the structural trend of the basin. The greatest subsidence observed in the Sirte Trough is 2,085 meters, whereas subsidence of the horsts is generally less than 1,000 meters.The stretching factor (β: in the range of 1.1 to 1.75). corresponds to an extension of 10–75%. with an average of less than 50%. The greatest stretching is associated with the central graben.
TECTONIC EVOLUTION AND HYDROCARBON MIGRATION IN THE HUANGHUA BASIN, NE CHINA
Authors: Fajing Chen , Shulin Zhang 
Published: December 2007

The Huanghua Basin is part of a Paleogene “dustpan‐”type fault‐bounded basin. whose tectonic development includes hapgraben to asymmetric and symmetric graben styles. Some half‐grabens later developed into complicated horst‐graben structures.Hydrocarbons normally migrate towards paleo‐swells. The directions in which hydrocarbons migrate in a fault‐bounded basin depend on the structure of the fault‐blocks. In the Cangdong sub‐basin — Kongdian high — Xiaojie sub‐basin complex, which comprises two tilted fault‐blocks and is controlled by two major faults with opposed dips, hydrocarbons migrate towards the high located between the two sub‐basins. The Banqiao sub‐basin — Beidagang high — Qibei sub‐basin complex is also composed of two tilted fault‐blocks. but is controlled by two major faults with the same dip: hydrocarbons migrate towards the high area, and also the gentle slope of the Qibei sub‐basin.In the two horst‐graben structures of the Nanbao graben — Gaoshangbao “low” high —Baigezhuang sub‐graben complex, hydrocarbons principally migrate from the two sub‐basins to the central high. and to the gentle slope of the major graben. Thus, hydrocarbon accumulations are distributed in a circular or semi‐circular configuration around the central oil‐generating sub‐basinsIn a fault‐bounded basin, the fault‐plane may serve as a conduit for hydrocarbon migration, but may also sometimes act as a seal, Hydrocarbons migrate from deeply‐buried to more shallow strata in two distinct ways — along either “staircase” or more simple vertical pathways. Fault‐plane barriers to hydrocarbon migration depend on the disposition of ductile beds on either side of the fault, and other conditions of top‐ and lateral sealing.
EFFICIENCY OF PETROLEUM CONCENTRATION IN MAJOR PETROLIFEROUS BASINS
Authors: Magara K. 
Published: December 2007

The ratio of the concentration (barrels of oil equivalent/sq. km) of accumulated oil in the richest sedimentary basin to that in the poorest basin, among those basins containing “giant” and “super‐giant” fields, is more than 500 to 1. By contrast, the ratio of the richest to the poorest petroliferous basin in terms of average organic concentration may be less than 20 to 1. Such a large discrepancy between these two ratios suggests that organic concentration alone cannot account, for petroleum concentration in commercial reservoirs, because significant quantities of petroleum may be lost to the surface and be disseminated throughout the sedimentary sequence if the trapping conditions are not suitable. Most of this disseminated petroleum cannot be produced economically using present‐day technology.For a more accurate petroleum assessment, the Author stresses the importance of the efficiency of petroleum accumulation and preservation in commercial reservoirs: this may be evaluated as combining (a) the organic concentration of the source rock, (b) the duration of oil generation, (c) the thickness of the oil‐generating “window”, (d) the total geologic age involved, and (e) the fluid expulsion rate, and the presence or absence of undercompacted intervals.Other parameters, such as the trap, reservoir and cap rock, and also the types of organic matter in the source rock, may have a great influence on the efficiency of petroleum concentrations in commercial reservoirs. However, most of these factors are of local significance, and thus are more difficult to generalise than those mentioned above in the context of the global distribution and concentration of oil reserves.
THE JURASSIC HUASTECA SERIES IN THE SUBSURFACE OF POZA RICA, EASTERN MEXICO
Authors: Cantú‐Chapa A. 
Published: December 2007

The Author has studied 120 cores containing ammonites and lamellibranchs of Middle and Late Jurassic ages selected from the 230 wells drilled in the Poze Rica district, eastern Mexico. The wells are spread over an area of 8,000 sq. km.The Huasteca Series is a marine sedimentary sequence that ranges in age from Bathonian to late Tithonian, and is about 1,000‐m thick. This unit is subdivided into ammonite zones and substages which have previously been established by the Author. These zones are: Wagnericeras, Kepplerites, Reineckeia, Discosphinctes, Ataxioceras, Idoceras, Virgatosphinctes, Mazapilites, Suarites, and Parodontoceras‐Salinites.The restricted vertical distribution of these fossils and the general availability of gamma‐ray logs from the wells has made it possible for the first time to delimit the lateral facies changes that took place, especially in the late Bathonian—middle Callovian (calcarenite‐shale‐silstone) and in the early Tithonian (calcarenite‐argillaceous limestone). Structural and isopach maps for each interval show the presence in the northern half of the study area of the NW‐SE striking La Mesa syncline, and, in the southern half of the area, the east‐dipping Sultepec homocline.The transgressive phase of Huasteca Series sedimentation began during Bathonian time in the NW part of this region. Evaporites and calcarenites were deposited above rocks of continental origin. This transgression advanced progressively during Callovian to Kimmeridgian time towards the central and eastern parts of the area, where the initial marine deposits overlie igneous, metamorphic, and continental sedimentary rocks. The last phase of this transgression took place during early Tithonian time in the SE part of the Poza Rica district. It is represented here by the San Andrés was deposited on the same types of rocks—igneous, metamorphic, and continental‐sedimentary. Remnants of this late transgressive phase, characterized by calcarenites and deposited on continental sediments, are preserved in very limited areas NE of the Poza Rica district.Beginning in Kimmeridgian time, two well‐defined depocentres developed. The Huizotate Basin, with argillaceous limestones and shales of the Tamán Formation, formed in the central part of the district, while the Papantla Platform with calcarenite units of the San Andrés Member (Tamán Formation) formed around the northern, eastern, and SE margins. These depocentres are named here for the first timeAn important result of this study is that it explains the presence in structural traps of hydrocarbons of Middle and Late Jurassic ages
PETROLEUM SYSTEMS: MODELS AND APPLICATIONS
Authors: Perrodon A. 
Published: December 2007

The term “petroleum system”— barely twenty years old — incorporates a new view of the formation of hydrocarbon accumulations. The concept is based on an orderly sequence of geological phenomena, starting with the genesis of oil or gas, which then migrates and is finally trapped. This sequence of events depends closely on the geodynamics of the sedimentary basin, which is determined by global plate‐tectonics.The main petroleum system models can therefore be defined in terms of the major types of basin. There are three main systems—continental rift, platform, and orogenic—each of which has a number of variants: continental rifts provide good conditions for oil generation, vertical migration and accumulation at various levels; by contrast, platform systems encourage the formation of reservoirs at the expense of source rocks and long, lateral migration paths, which frequently form tar‐belts; and orogenic systems encourage entrapment in zones little affected by tectonic movements, accompanied by frequent surface shows.The “petroleum system” concept describes the dynamic, mobile formation of petroleum pools, and has a number of implications for exploration strategy.
THE JIUXI BASIN, HEXI CORRIDOR, NW CHINA: FORELAND STRUCTURAL FEATURES AND HYDROCARBON POTENTIAL
Authors: Wang Q. M. , Coward M. P. 
Published: December 2007

The Jiuxi (Western Jiuquan) Basin, located in the west of the Hexi Corridor, NW China, is a foreland basin which has been active since the Early Jurassic. It was formed as a consequence of the progressive northwards migration of the North Qilian thrusts in response to sinistral shearing along the 2,000‐km long Aerjin (Altun) Fault. Sedimentary deposits in the basin are controlled not only by foreland loading and thrusting, but also by the development of listric normal faults at high angles to the thrust belt. At the junctions of these two sets of faults, thick organic‐rich sediments and reservoirs have accumulated.During the Tertiary and Quaternary, thrusts propagated along the foot‐wall of the North Qilian Fault, truncating earlier‐formed oil pools and source‐rock layers and thereby causing great difficulties for petroleum exploration. A basin development model is proposed in this paper from cm integrated study of sedimentary fades, drilling and seismic data, structural analyses and cross‐section reconstructions.The average northwards movement in the frontal zone of the North Qilian Mountains since the Pliocene is estimated at about 8 mm/yr. Therefore, about one‐half of the Jurassic‐Cretaceous oil‐bearing basin could be buried beneath the Laojunmiao and North Qilian Marginal Faults, and is virtually untouched by drilling.Source rocks in the basin are black, lacustrine shales of Late Jurassic through Early Cretaceous ages, with a maximum thickness of up to 1.2 km in the Qingxi Depression. The generation of liquid hydrocarbons began in the Late Cretaceous or mid‐Oligocene; seven stratigraphical reservoirs, ranging in age from Silurian to Miocene, are described — anticlinal. fault‐ and “buried‐hill” structures are the most important traps.The petroleum potential of individual depressions is discussed, and suggestions for potential regional oil prospects are made.
OIL SOURCE ROCK POTENTIAL OF THE LACUSTRINE JURASSIC SIM UUJU FORMATION, WEST KOREA BAY BASIN Part II: Nature of the organic matter and hydrocarbon‐generation history
Authors: Massoud M. S. , Scott A. C. , Killops S. D. , Mattey D. , Keeley M. L. 
Published: December 2007

The offshore West Korea Bay (WKB) Basin is one of a series of NE‐SW rift basins which formed in Korea and eastern China over thin continental crust during the Late Mesozoic and Early Cenozoic, and is characterised by a two‐layered structure — a Cenozoic basin is superposed on a pre‐Tertiary basin. In Part I of this paper (Massoud et al., 1991), paraffinic oils recovered from Mesozoic and Tertiary sandstone intervals were found to have been generated from different source beds. Also, a probable thick (400–500 m) Jurassic source bed for the Mesozoic oil was geochemically identified in the basinal offshore area of the lacustrine Sim Uuju sequence penetrated by Well 606In this Paper, the Authors complete the hydrocarbons survey on the formation by studying the type, amount and maturity of organic matter present, and the history of hydrocarbon generation. They conclude that the Jurassic bed could be considered as a major source for the Mesozoic oil in the WKB Basin, provided that it is of a sufficient extent to have produced large volumes of oil.
PETROPHYSICAL CHARACTERISTICS OF THE MIDDLE EOCENE LAUMONTITE TUFF RESERVOIR, SAMGORI FIELD, REPUBLIC OF GEORGIA
Authors: Grynberg M.E. , Papava D. , Shengelia M. , Takaishvili A. , Nanadze A. , Patton D.K. 
Published: December 2007

In the Samgori field, near Tbilisi in the Republic of Georgia, changes in reservoir properties caused by alteration of middle Eocene volcanogenic rocks control the amount of oil and gas these rocks will yield. These changes, which include fracturing, development of vugs, and laumontite zeolitization, impart a vertical and lateral variability, thus giving rise to irregular petrophysical properties of the rock such as filtrational capacity, elastic deformational properties, and productivity. Indicative of such differences is the large variation in initial recovery from one well to another. According to the reservoir model proposed here, productivity at Samgori is dominantly controlled by fracture porosity and permeability. Fractured bodies of oil‐bearing laumontized tuffs are enclosed within a thick layer of andesite‐basalt tuffs and tuffites, which act as a seal. As a result, the fractured tuffs are relatively isolated from the action of geostatic and geotectonic loads, which would otherwise result in closure of the fractures and microfractures. In addition, the fluid pressure of the reservoir tends to maintain open fractures. As fluid pressure declines over the producing life of the field, effective stress increases and the fractures close. This results in the isolation of producing zones and the consequent development of reservoir heterogeneity. An understanding of this effect is essential to proper management of the reservoir so as to ensure optimum recovery of oil.The contribution of matrix porosity to productivity is also recognized. Fluid injection analysis has established that matrix porosity and permeability vary according to lithology, with the highest values in laumontized tuffs: laumontite inter‐crystalline voids can also be observed, using scanning electron microscopy.
PALAEOZOIC SANDSTONE RESERVOIRS OF THE HAMADA BASIN, NW LIBYA: EFFECTS OF SYNSEDIMENTARY PROCESSES ON POROSITY
Authors: Shah S. H. A. , Mansouri A. , Ghoul M. El 
Published: December 2007

The Hamada Basin of NW Libya is an intracratonic basin in which a thick sequence of clastic rocks was deposited during the Palaeozoic. These sediments were derived from a PreCambrian basement of felsic igneous and metamorphic rocks, and include both sands and clays; almost all the clays in formations of Palaeozoic age were produced from the alteration of feldspar. Structures were developed as these sediments were draped over the surface of the basement.Reservoirs in the Lower Palaeozoic (Lower Devonian, Lower Silurian and Cambro‐Ordovician Sandstones) appear to have developed as a result of synsedimentary processes, such as winnowing and washing‐out of clayey material from the sand by percolating waters, and sliding and slumping on the steep depositional surface during or soon after deposition. Oil traps are independent of structural elevation, but appear to have developed on those surfaces which were sufficiently steep to have initiated the above synsedimentary processes.This theory has been successfully tested in many places in the basin, and may provide a lead for exploration in other basins in Libya that have similar geological settings.