bluuebunny/crossref_metadata_2025 huggingface dataset:
THE FRAMEWORK OF CHINESE PETROLIFEROUS BASINS
Authors: Huanjiang Chen , Zaucai Sun , Yuchang Zhang
Published: December 2007

The unidirectional‐polycyclic evolution of crustal position, and the regimes of tectonic disturbance are the most important factors which determine the structure of Chinese petroliferous basins, and the habitat of oil and gas. Chinese basins can be differentiated into various prototypes in terms of historical stages and geodynamic mechanisms. If their complex and superimposed configurations are systematically investigated, an appraisal of the undiscovered oil and gas resources of China may be possible.
STYLOLITIC POROSITY IN CARBONATES: A CRITICAL FACTOR FOR DEEP HYDROCARBON PRODUCTION
Authors: Carozzi Albert V. , Bergen Donald Von
Published: December 2007

Petrographic and petrophysical studies were completed on cores from Atokan (Pennsylvanian) carbonate gas reservoirs at depths in excess of 4,000 m in the Chapman Deep field, Delaware Basin, Texas. Porosity concentration is in pure carbonate microfacies of Donezella algal mound, upper inner slope, oolitic shoal and lagoon of a platform depositional model, which are characterized by sutured, medium‐ to high‐amplitude stylolites. The porosity is predominantly stylolitic, enlarged and surrounded by halos of oomoldic, biomoldic, cement‐moldic and vuggy types. Non‐sutured, low‐amplitude stylolites, confined to argillaceous carbonate microfacies, have no influence on porosity development.

The distribution of sutured stylolitization, being microfacies‐controlled, allows the use of a depositional model as a prediction tool for locating reservoir microfacies. Under deep‐burial conditions, sutured stylolite systems are of critical importance. They permit circulation of undersaturated fluids, become themselves reservoirs together with associated types of secondary porosity, and therefore allow deep commercial gas production.
PALYNOLOGICAL ANALYSES IN THE STUDY OF FLUID MIGRATION IN THE OILFIELDS AND GASFIELDS OF WESTERN SIBERIA
Authors: Medvedeva A.M. , Klimushina L.P.
Published: December 2007

A study of microfossils contained in the hydrocarbon fluids derived from four oil‐ and gas‐bearing formations in Western Siberia (of Paleozoic, Jurassic, Neocomian and Albian—Cenomanian ages) has shown the importance of processes of vertical migration in local hydrocarbon accumulations. These processes were found to be concentrated in regions of geological disturbance or intense fracturing of the reservoir rocks.
ZONATION OF OIL AND GAS IN THE HUANGHUA BASIN, CHINA
Authors: Fuhua Liang
Published: December 2007

The hydrocarbons accumulated in the Huanghua Basin, China, show a remarkably complete evolutionary pattern, from immature heavy oils to highly‐mature condensates, and from biogenic to dry gases. This paper presents GC, GC/MS and IR analytical data for n‐alkanes, branched alkanes, steranes and terpanes; and data concerning the physical and chemical properties of these oils and gases, and their carbon isotopic compositions.
SEDIMENTARY HISTORY AND PALEOGEOGRAPHY OF LOWER AND MIDDLE JURASSIC ROCKS, CENTRAL SAUDI ARABIA
Authors: Moshrif Mohamed A.
Published: December 2007

Eight clastic and carbonate lithofacies of Lower and Middle Jurassic age (the Marrat and Dhruma Formations respectively) have been identified. These lithofacies are mainly shales, shales‐and‐siltstones, siltstones‐and‐shales, sandstones, argillaceous limestones, calcarenitic limestones, calcarenites and dolomites. Intraclasts, pellets, oolites, gypsum, algae, and coral reefs were also found to be dominant among these lithofacies. Furthermore, these beds contained either restricted or diversifed biota, with a few sedimentary structures such as lamination, cross‐bedding and common bioturbation. Thus, it is presumed that the Lower and Middle Jurassic rocks in Central Saudi Arabia were deposited in very shallow (i.e. tidal flat and lagoon), shallow‐neritic, and deep‐marine conditions of the Tethys Sea.

During Toarcian (Lower Jurassic) time, the Tethys Sea extended towards Arabia, forming an arcuate shoreline around the Pre‐Jurassic sediments. The greater part of the Arabian Peninsula was under very shallow marine (Tethys) water as is shown by the presence of tidal‐flat and lagoon deposits in northern Oman, Rub al‐Khali, parts of the Aden Protectorate and Yemen, central, eastern and NNW Saudi Arabia, the northern edge of Sinai, NW Jordan, Lebanon, central and northern Syria, and west, central and eastern Iraq and Iran (Fig. 5). On the other hand, east and north of this area, very shallow marine deposits overlaid the shallow‐neritic Tethys deposits.

Further expansion of the Tethys Sea transgression occurred during Bajocian‐Bathonian (Middle Jurassic) time, when major parts of the Arabian Peninsula and its neighbouring regions were submerged below shallow‐neritic and deepmarine Tethys conditions (Fig. 6). During this time, shallow‐nentic Tethys conditions extended to include the Oman Mountains, as far west as western Rub al‐Khali, north to include Central Saudi Arabia, running through parts of its northern area and passing under the Saudi Arabia‐Iraq Neutral Zone and reaching SW Iraq, turning west to include part of the area of NW Arabia and reaching NW Jordan. Northern Oman, most of central Rub al‐Khali, eastern Saudi Arabia, western Iran, central and eastern Iraq, and eastern and northern Jordan, were covered by deepmarine Tethys waters (F&. 6). However, simultaneously, SW Arabia, Yemen and the Aden Protectorate display a marked continuous sedimentation of continental and neritic conditions, as neritic deposits narrow toward the north.
THE THREE‐PHASE DEVELOPMENT OF THE PORCUPINE SEABIGHT: BASIN FORMATION AND THE STRUCTURALLY‐DEPENDENT SEDIMENTARY PATTERN.
Authors: Max M.D.
Published: December 2007

The Porcupine Seabight appears to have been formed in three distinct episodes, each reflecting somewhat different structural controls. The oldest episode was rifting and selective crustal thinning associated with Permo‐Triassic taphrogenes, during which there was some dextral movement on NW‐trending faults. The important second episode was probably Mid‐Jurassic to Mid‐Cretaceous, and involved major crustal thinning related to nearby oceanic crust spreading, which initially reactivated and exploited structures in the continental crust while later imposing structural trends more related to the newly‐developing oceanic crust rift‐transform orientations. The last significant phase was one of minor adjustment, mainly by normal faulting of a down‐to‐basin character. Later, minor compression with some folding associated with reactivation along structural lines took place during Tertiary, probably Alpine times, but did not much affect the pattern of sedimentation within the Porcupine Seabight.

A speculative model as to the character of sediments and local sediment distribution related to the structural episodes is proposed.
MULTIREGRESSIONAL MODELS FOR RANGED ESTIMATES OF THE PETROLEUM POTENTIAL OF SEDIMENTARY BASINS
Authors: Resnick Victor S.
Published: December 2007

Reliable estimates of the oil and gas potentials of frontier areas can be made by combining statistical analyses of petroleum data from well‐explored basins world‐wide with models of hydrocarbon‐generation processes. The combined techniques, together with the data collected, have to be guided by a systematic approach in order to produce statistically‐regular results.

The hydrocarbon‐generation models here proposed express geochemical factors and organic matter maturity in terms of available geological parameters (lithology, depth‐distribution and age of rocks, heat‐activation temperatures, etc.). This type of model is applicable to both poorly‐explored and well‐explored basins. The study of the correlation of yield with each geological parameter leads to the expression of hydrocarbon‐generating processes by a set of multiple‐regression models which are of increasing complexity and accuracy, ranging from a simple bulk‐statistical model for unexplored basins, to a sophisticated non‐linear genetic‐statistical model for well‐explored basins.

The coefficient of variation associated with each model allows calculation of the confidence interval for estimates of ultimate petroleum potential in terms of physical probability, and is more reliable than the conventional Monte‐Carlo technique.

Based on the same world‐wide petroleum statistics, non‐linear predictive models for the gas/oil ratio and risk exploration factor for unexplored basins have been constructed. The technique of genetic‐statistical modelling (GSM) has then been applied to some well‐explored basins, on the assumption that only early exploration information was available. All the results obtained agree well with later assessments, based on discovery rate projection techniques.
MINERALOGICAL AND GEOCHEMICAL STUDIES OF TERTIARY SEDIMENTS FROM THE EASTERN NIGER DELTA AND THEIR RELATIONSHIP TO PETROLEUM OCCURRENCE
Authors: Odigi Minapuye I.
Published: December 2007

Mineralogical and chemical studies have been made of shale cuttings from the Akiri‐1 well in Oligocene — Miocene sediments of the Niger Delta. The < 2μm fraction from the 2,183 to 3,720m stratigraphic interval was analyzed by X‐ray diffraction. Kaolinite and chlorite are more abundant than other clay minerals. The illiteh mectite composition changes from a phase with 32% illite layers, to one with 82% illite layers over the 3,250 to 3,720m stratigraphic interval. Kaolinite decreased in shallow shales from 22 to 16% and increases to 29% in deep shales. Quartz increases in abundance with depth, while chlorite and plagioclase feldspar show no systematic trend with depth. Calcite is present in small amounts in all the samples.

Variations in the bulk chemical composition of true shale with depth only show significant changes in the K2O and Fe2O3 content: other major chemical constituents show no systematic variations. The potassium appears to be derived from the pore water. The loss of smectite and abundance of Fe coincided with hydrocarbon occurrence. On the basis of the apparent systematic transformation of smectites to illites through mixed layers, the illite/smectite reference interval in the subsurface has been established: this interval coincided with hydrocarbon occurrence.

Mineralogical and chemical changes observed are dependent on the pore system chemistry, the temperature, and possibly compaction effects.
HYDROCARBON POTENTIAL OF THE UPPER JURASSIC/LOWER CRETACEOUS OF THE AUSTRALIAN NW SHELF
Authors: Baird R.A. , Philip R.P.
Published: December 2007

Source‐rock richness, timing of hydrocarbon generation, and thicknesses of potential source shales of the Upper Jurassic/Lower Cretaceous section of the Australian NW Shelf have been examined in order to make predictions as to the hydrocarbon productive of liquid hydrocarbons: the Brows Basin, the Malita Graben/NW Bonaparte Gulf Basin, the Rowley Sub‐basin, and the Vulcan Sub‐basin/Sahul Syncline, respectively.

Recent liquid hydrocarbon discorveries in the Vulcan Sub‐basin, probably source by the Upper Jurassic shales, upgrade all four of these areas, and lead to the conclusion that overall, drilling results on the NW Shelf have to date not been indicative the timing of generation as delineated in this study with the timing of structural development in order to improve chances of success, rather than relying on the size of Structures alone.

A new method of presenting timing of generation, in the form of a “timing‐of‐generation map”, is introduced, where the timing of the progress of significant hydrocarbon generation is contoured over the NW Shelf for each source‐rock section.
GAS‐PRONE SOURCE ROCKS FROM CRATOGENE KAROO BASINS IN TANZANIA
Authors: Kreuser T. , Schramedei R. , Rullkotter J.
Published: December 2007

Source‐rock quality and organic matter maturity of coals and sediments from several Tanzanian Karoo basins (Permian‐Triassic) have been evaluated by microscopic, pyrolytic and geochemical methods. The intracratonic Ruhuhu Basin (SW Tanzania) differs from two peripheral cratogene basins (Mikumi and Rufiji) with respect to the composition of organic matter, thermal evolution and probable hydrocarbon generation in a tensional tectonic stress field of the East African craton at the Palaeozoic/Mesozoic boundary.

The Lower Permian sediments and coals and the Upper Permian sediments of the Ruhuhu Basin exhibit moderate source‐rock properties. They were not subjected to significant subsidence and are moderately mature source rocks. They possibly experienced temperatures in the range 60–110d̀ and vitrinite reflectance values of 0.5—0.8 were attained, thus placing them within the “oil window”. Kerogen Type III is typical for all the basins, and productivity indices indicate moderate to advanced stages of evolution.

The coastal basins differ in most parameters. The sediments do not have source‐rock properties. High vitrinite reflectance values (1.0–2.0%) imply a higher degree of thermal maturation, and geochemical results confirm that organic matter in these sediments is postmature, and that hydrocarbon generation, if it occurred at all, ceased some time ago. The assumption of a stable geothermal gradient from Late Palaeozoic to recent times, combined with field observations, leads to the conclusion that no significant overburden has covered the Ruhuhu Basin. A mean subsidence of 1, 5OO‐3,000 m, depending on basin type and stratigraphic position, seems realistic, and this overburden is provided by the sediments of the “younger Karoo cycle” (Triassic). No post‐Karoo sedimentary cover was deposited in the Ruhuhu Basin. Migration probably occurred in Jurassic times, shortly after the end of the Karoo sedimentary cycle, and it is presumed that no significant tectonic activity during the Cenozoic affected pre‐existing accumulations. The chances that commercial volumes of hydrocarbons (mainly gas) await discovery are fair
THE JURASSIC FACIES IN THE LEVANT
Authors: Hirsch F. , Picard L.
Published: December 2007

The Triassic‐Liassic contact in the Levant is a distinct sedimentary break expressed by lateritic palaeosols (Mishhor) or volcanics (Asher).

A marine platform carbonate regime began in the Pliensbachian (Ardon‐Nirim) and continued in the Toarcian (Qeren‐Nirim). It was interrupted by Toarcian‐Aalenian clastics in the Negev, adjacent Sinai and along a belt crossing Central Israel into South Anti‐Lebanon (Inmar‐Rosh Pinna). In Northern Israel, Lebanon and North Anti‐Lebanon it persisted without interruption through the Oxfordian (Haifa or Kesroaune).

Bajocian lithofacies vary from being mixed in the Negev (Daya), to largely marly in Sinai (Maghara), and to monotonous Bajocian‐Oxfordian platform‐carbonates (Haifa) in the north. Bajocian‐Bathonian lithofacies in the Coastal Plain consist of Haifa carbonates, interwedged by oolitic shoals (Sederot) and spiculites (Barnea). Paralic clastics dominate the early Bathonian in the south (Safa‐Sherif), followed by middle‐late Bathonian micrites and marls (Kehailia/Karmon). The latter characteristic body of shales continues to the Callovian, and in the Coastal Plain separates the Bathonian carbonates from the early Callovian calcarenites (Brur).

Callovian‐Oxfordian platform micrites are interwedged by marls and biostromes in the Negev (Zohar‐Beersheba) but may consist of bioherms (Nir'Am) in the Coastal Plain. A complete or partial hiatus of the middle‐late Callovian coincides with the extension of the transgressive onlap of early Oxfordian shales (Kidod) from North Sinai to South Anti‐Lebanon, crossing the Coastal Plain and Central Israel.

Kimmeridgian oolites, shales and occasionally sands (Halutza) terminate the Jurassic cycle, ending in a regional uplift followed by subaerial denudation or submarine canyons (Gevar‐Am).

The palaeotectonic setting of the Jurassic in Israel and adjacent Sinai, prior to Infra‐Cretaceous truncation, consists of the Negev High which extends to the coastal plain area (Beersheba nose), separating the North Sinai Maghara Basin from the Central Israel‐Hermon trough, the latter being disturbed by Lartet's (1869) Neogene‐Quaternary wrench movement of over 100 km sinistral displacement. A rather shallow platform in the north includes Galilee, Lebanon and North Anti‐Lebanon.

The clastics of the Liassic‐Bathonian part of the sequence are connected with the wearing‐down of the Arabian Massif in the south and SE. Yet the thickening of the early Oxfordian shales in the offshore wells points to derivation from some landmass in the west, now hidden beneath the Mediterranean.
OIL GENERATION AND MIGRATION WITHIN MARINE CARBONATE SEQUENCES ‐ A REVIEW
Authors: Ferguson J.
Published: December 2007

Recent literature on carbonate source rocks is reviewed, particular importance being attached to those papers which give details of lithology and depositional environment, as well as details relating to the organic matter in the rock. It is demonstrated that depositional and environmental criteria which have been applied to other source rocks are equally valid for carbonates. Evidence is presented which upholds the view that clay mineral catalysis is minimal in these rocks. Another feature which is emphasised is that of “self‐sourcing”I.t is suggested that the evidence presented in the papers reviewed calls for the recognition of two modes of “self‐sourcing” i.e. the oil or gas canbe truly indigenous and formed where it is found, or it can have migrated within the carbonate complex. Supporting evidence ?om experimental work, both published and unpublished, is presented to support the main conclusions of the paper.
THE PLESHET BASIN: A NEWLY‐DISCOVERED LINK IN THE PERIPHERAL CHAIN OF BASINS OF THE ARABIAN CRATON
Authors: Cohen Z. , Flexer A. , Kaptsan V.
Published: December 2007

Evaluation of existing magnetometric, gravimetric, seismic and well data indicates that a large basin, some 300 km long, 100 km wide and up to 13.5 km deep, occupies the greater part of the Sinai‐Israel offshore area. The basin, referred to here as the Pleshet Basin, is flanked by a series of magnetic and gravimetric anomalies, interpreted as being caused by basement highs.

None of the wells drilled in the basin penetrated the Jurassic section. It is suggested, however, that the thick sedimentary sequence filling the basin includes strata of Paleozoic to Quaternary age.

Wells drilled in the SE part of the basin showed an increase in clastic content in a NW direction. The source of these clastics is therefore to be sought in the west. It is perhaps the basement ridge that presumably forms the western flank of the basin, or even a large land‐mass further away.

The Pleshet Basin occupies a position similar to that of the prolific basins of the Middle East within the unstable shelf belt that surrounds the Arabo‐Nubian Massif. It here postulated that the Pleshet Basin is a potentially hydrocarbon‐generative depression.
RELATIONSHIPS BETWEEN REGIONAL HYDROGEOLOGY AND HYDROCARBON OCCURRENCES IN MICHIGAN, USA
Authors: Vugrinovich R.
Published: December 2007

Compilation of hydrologic data for deep aquifers in the Michigan Basin makes it feasible to test the hydraulic theory of hydrocarbon migration in Michigan. Comparison of equipotential surfaces and patterns of hydrocarbon deposits shows that commercial oil deposits in most aquifers and the more prolific gas deposits in the St. Peter Sandstone are preferentially associated with regional groundwater discharge areas, as predicted by the hydraulic theory. Shallow natural gas deposits occur in regional groundwater recharge areas of Devonian and Mississippian aquifers. The gases in these deposits have chemical compositions suggesting a biogenic origin. Their occurrence in regional recharge regions is believed to be due to a combination of high interfacial methane‐water tension due to low subsurface temperature and pressure and water‐saturated, gas‐impermeable rock surrounding the deposits.
ISOSTATIC BALANCE DURING SEDIMENT LOADING AND UNLOADING IN CONTINENTAL MARGINS
Authors: Magara K.
Published: December 2007

The initiation of a sedimentary basin may be explained by a mechanism which is related to global tectonics and sea‐floor spreading. Once the initial shape of a basin is formed, the sediments which were removed and transported from the nearby inland area will be deposited in the basin, where active burial and compaction take place under conditions of isostatic balance.

Cambining concepts of isostasy and sediment compaction, both the subsidence of the crust and the rise or fall of the sedimentary surface in a continental margin basin can be estimated. The first model proposed is here applied to four major basins–the Mississippi, Mackenzie, Niger and Amazon. The sedimentary surface, in general, tends to rise as the radio of depositional area to erosional area decreases and/or porosity at the base of the sedimentary basin increases (undercompaction).

The second model proposed may be applicable for areas of carbonate sedimentation; deposition takes place primarily by chemical and biological processes, regardless of inland erosion.
THE FORMATION AND DISTRIBUTION OF MESOZOIC‐CENOZOIC SEDIMENTARY BASINS IN CHINA
Authors: Zaiyi Tian
Published: December 2007

Numerous intraplate, fault‐bounded basins have been developed on the Chinese landmass as a result of interactions between the Pacific, Asian and Indian Plates since Mesozoic‐Cenozoic times. In Eastern China, continental‐rift basins were formed in a geodynamic regime during which the continental crust was stretched and thinned, and moved slowly towards the Pacific Ocean. These rift basins may be distinguished from those in NE, Northern and Southern China, due to differences in basement configuration and evolution.

In Central China, cratonic subsidence depressions exist, with thin‐skinned décollement tectonics, fold belts and minor fore‐deeps. These include the Ordos, Sichuan and Chuxiong Basins, which can be differentiated according to their stage of development.

In Western China, crustal compression resulted in horizontal shortening and vertical thickening; thus, fore‐deep and intermontane basins were developed, usually associated with basement thrust‐faulting.
THE GENESIS OF THE SOUTH CHINA SEA AND ITS HYDROCARBON‐BEARING BASINS
Authors: Dehua Liang , Zonghui Liu
Published: December 2007

The formation of the South China Sea was primarily controlled by the NeoCathaysian and Nanhai tectonic systems (Early Cretaceous‐Early Tertiary, and Late Oligocene‐Early Miocene, respectively). These two tectonic systems are associated with the first and second phases of spreading in the South China Sea, where 33 sedimentary basins have so far been located. Basin generation and development was tectonically controlled, and four basin types have been identified: tensile, tensile‐shear, compressive, and compressive‐shear. Tensile and tensile‐shear basins in the Nanhai system, and the compressive basins in the NeoCathaysian system, have the most promising oil and gas potential.
THE CASE FOR EARLY GENERATION AND ACCUMULATION OF OIL
Authors: Wilson H. H.
Published: December 2007

Uncertainties remain concerning the common assumption that economic oil pools result only from deep, catagenic oil generation. These uncertainties stem from the many geological criteria that point to early oil entrapment and, furthermore, from the failure to resolve problems of oil migration out of, and through, consolidated sediments.

Early oil emplacement is indicated by the preferential charging of paleostructures, inhibition of diagenesis and compaction by reservoired oil, folded oil‐water contacts, and by evidence supporting the immaturity of huge heavy‐oil deposits.

The uncemented and uncompacted nature of the Athabasca “tar sands”, the perfect preservation of fossil wood within them, and the tilted oil‐water contacts at the Athabasca, Peace River and Cold Lake accumulations, support geological deductions of very‐early oil emplacement, and geochemical criteria for its immaturity.

If such huge volumes of oil are immature, this would be in harmony with geological observations which conclude that pools of mature oil most probably result from in‐reservoir maturation of early‐expelled, biogenically‐generated heavy oil and methane.

Hydrocarbons that remain in source rocks are maturated during burial, but are immobilised by progressive loss of effective permeability.
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
JURASSIC MUDROCK FORMATIONS OF SOUTHERN ENGLAND: LITHOLOGY, SEDIMENTATION RATES AND ORGANIC CARBON CONTENT
Authors: Ebukanson E.J. , Kinghorn R.R.F.
Published: December 2007

The Jurassic mudrock formations of Southern England, especially the Lower Lias, Oxford Clay and Kimmeridge Clay, show great variations in lithology, organic content and rates of sedimentation. It is here suggested that the varying sedimentation rates of these formations have been a major contributory factor, resulting in the differences in the organic richness observed between these fine‐grained Jurassic rock units. Variations in lithology have only a minor effect on the organic richness of these sediments, compared with the marked influence of sedimentation rate
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‐basins

In 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 time

An 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 606

In 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.