bluuebunny/crossref_metadata_2025 huggingface dataset:
ORGANIC GEOCHEMISTRY OF THE GÖYNÜK AND SEYITOMER OIL SHALES OF TURKEY
Authors: Pütün E. , Akar A. , Ekinci E. , Frere B. , Bartle K. D. , Snape C. E. , Citiroglu M.
Published: December 2007

The GCöynük and Seyitomer oil shales overlie coal seams. An investigation of their geochemistry by solid‐state and high‐resolution nuclear magnetic resonance, infra‐red spectroscopy and gas chromatography/mass spectrometry of the extracted bitumen suggests a classification as immature Type I kerogens. However. the n‐alkane distribution is consistent with a substantial input from terrestrial plants.
THE CAUSE AND MECHANISM OF VITRINITE REFLECTANCE ANOMALIES
Authors: Fang Hao , Jianyu Chen
Published: December 2007

The unexpected phenomena that measured vitrinite reflectance (Ro) values are lower (suppression) or higher (enhancement) than expected values at a given regional rank are defined as vitrinite reflectance anomalies. Such phenomena have been found in many basins in China, both in coal seams and in oil source rocks, and representative examples are presented in this paper. The cause and mechanism of vitrinite reflectance anomalies have been investigated by comparing the hydrogen contents and chemical structure of vitrinite macerals from immature Type I, Type II and Type III kerogens, and by studying the effects of early diagenetic oxidation on the thermostability of humic organic matter (OM). The results demonstrate: (1) depending on the anoxic or oxic nature of the depositional conditions, that lignocellulosic tissues can form a series of vitrinite macerals with different initial hydrogen contents and slightly different initial reflectivities; (2) that vitrinite macerals with different initial hydrogen contents have different reaction kinetics, with hydrogen‐poor, oxygen‐rich vitrinite maturing at an enhanced rate compared to vitrinite with a higher hydrogen content and a lower oxygen content; (3) that variations in the hydrogen content and the thermostability of vitrinite macerals are the main causes of Ro suppression and enhancement.
THE TARIM BASIN, NW CHINA: FORMATION AND ASPECTS OF PETROLEUM GEOLOGY
Authors: Wang Q. M. , Nishidai T. , Coward M. P.
Published: December 2007

The formation and evolution since the Sinian of the Tirim Basin, NW China, are introduced in this paper. on the basis of a study of stratigraphical and sedimentaty facies. and an analysis of structura1, features. Mechanisms of basin formation have varied throughout this time, caused by frequent tectonic movements along the southern margin of the Eurasian Plate. As regards petroleum geology. six structural units have been classified from a consideration of the distribution of major source‐rock sequences. An overall evaluation is made concerning hydrocarbon exploration in the individual structural units. Moreover, a general review is presented regarding source rocks, hydrocarbon reservoirs, trap structures, sealing layers and hydrocarbon generation, as well as possible recent exploration successes
LITHOSTRATIGRAPHY OF OIL‐BEARING TERTIARY BIOHERMS IN THE SIRTE BASIN, LIBYA
Authors: Gumati Y.D.
Published: December 2007

In the early Palaeocene, a carbonate platform existed in the southern part of the Sirte Trough (a NW‐trending depression in the eastern Sirte Basin), and a shale basin in the north. A major transgression occurred during the early Palaeocene, and part of the platform subsided, resulting in the formation of a basinal re‐entrant within the carbonate province. A positively northerly‐trending ridge, which was active in the early Palaeocene, persisted within the re‐entrant during the late Palaeocene. This positive element provided a platform on which isolated bioherms grew, surrounded by shale deposits in the subsiding basin. The bioherms began as foraminiferal banks that built‐out on local mounds in shallow water. Sparse coral growth bound coralline detritus, until richer coral development resulted in a large coral reef.

A barrier reef surrounding the re‐entrant developed during the late Palaeocene and grew basinwards, advancing over its own talus. A second major transgression closed the Palaeocene epoch, and clastic deposition over the Sirte Trough terminated reef growth and carbonate deposition.

The reef, back‐reef and basinal environments are each characterized by distinctive lithologies and fauna. The bioherms form excellent hydrocarbon reservoirs in the Intisar A and D fields, which are probably sourced by the Sirte and Hagfa Shales. Six bioherms, some in excess of 300 m in thickness, have been discovered, and some contain commercial oil accumulations.
GRAVITY OVERTURNS, EXTENSION AND BASEMENT FAULT ACTIVATION: REPLY
Authors: Koyi H.
Published: December 2007

HOSPERS (pp. 359–361, this issue) raises two questions on the application of model results in my 1991 paper on the Norwegian‐Danish Basin: (1) unlike the Norwegian‐Danish Basin, the buoyant layer in the models is resting on a flat, horizontal base; and (2) sedementation is not simulated in the models. These two points are not justified because their answers are already in the paper. I am surprised that Hospers did not comment on a horizontal and flat base in the models in earlier correspondence (Hospers, pers. comm., 1990, Koyi, 1991). Here, I will clarify parts of my paper, and draw a general conclusion on the effects of basement faults on diapirism and basin floor slope.
THE RED SEA — GULF OF ADEN: BIOSTRATIGRAPHY, LITHOSTRATIGRAPHY AND PALAEOENVIRONMENTS
Authors: Hughes G. W. , Beydoun Z. R.
Published: December 2007

Sediments of Palaeozoic, Mesozoic and early Palaeogene ages experienced a similar geological history in Ethiopia, Yemen and Somalia. During the late Eocene, however, uplift and differential erosion took place, prior to rift development in the middle Oligocene, when the proto‐Gulf of Aden became established. To a certain extent, a similar sequence of events had also taken place in those regions of Egypt, Sudan, Ethiopia, Yemen and Saudi Arabia which border the Red Sea, but post‐Eocene subsidence is now believed to have commenced during the late Oligocene in the southern Red Sea and progressed later, during the early Miocene, in the northern Red Sea and Gulf of Suez. Timing of this progressive development of the Gulf of Aden rift complex through the Red Sea and Gulf of Suez is well constrained by biostratigraphy, and provides a new approach to the understanding of lithological variations within the region.

These lithological variations have, until now, only been considered on a country‐specific basis, thus hindering establishment of a regional history of sedimentation. The well‐understood and well‐documented lithostratigraphic nomenclature of the Miocene succession of the Gulf of Suez has been used as a reference, or type, with which the lateral facies variations within the Red Sea have been compared. By this method only has it been possible to produce palaeoenvironmental maps for the entire study region, and for each formation and member. Lateral equivalents of the Gulf of Suez Nukhul, Rudeis, Kareem, Belayim, South Gharib. Zeit, Wardan and Shagara Formations have been identified within the Red Sea syn‐rift and post‐rift episodes.
THE SEDIMENTARY EVOLUTION OF THE RED SEA AND GULF OF ADEN
Authors: Crossley R. , Watkins C. , Raven M. , Cripps D. , Carnell A. , Williams D.
Published: December 2007

Onset of rifting, and flooding by marine waters, occurred in the late Oligocene in the Gulf of Aden and southern Red Sea. The northern part of the Red Sea may have been a largely continental rift at this initial stage, but continued rifting established marine conditions throughout the system by the early Miocene. Episodic isolation of the Red Sea system, leading to evaporite deposition in some basins, commenced in the mid‐Miocene and over two kilometres of salt had accumulated in most Red Sea basins by the end of the Miocene.

Re‐establishment of persistently‐marine conditions occurred in the Pliocene, and marine recharge is now sufficiently high to permit vigorous carbonate build‐ups in shallow‐water areas.

Clastic sediment textures suggest that marginal escarpments, which first developed during the onset of rifting, were strongly uplifted in the Pliocene‐to‐Recent period. Subsidence of basin floors seems to have been particularly rapid during the period dominated by salt deposition.

If eruption of sea‐floor basalts in the axial rift areas is excluded, volumetrically important volcanism is centred on the present Afar triangle area, and is confined to the Oligocene and early Miocene. The amount of contemporary volcanic débris in the sandstones is consequently not particularly high. Some sandstones in northern Ethiopia, Sudan and Egypt do contain abundant acidic volcanic clasts, but these are derived from the Proterozoic basement and cause less diagenetic reservoir damage than contemporary glassy volcanic ash.

Sandstones deposited in freely‐drained alluvial fan settings are characterised by early diagenetic kaolinite, whereas those of sabkha and marginal‐marine settings tend to show relatively early diagenetic chlorite. Those alluvial fan sandstones which were subsequently invaded by reduced pore waters expelled from the basin axis, and those in the basin axis, often developed later diagenetic chlorite.
TECTONOSTRATIGRAPHIC FRAMEWORK AND HYDROCARBON POTENTIAL OF THE RED SEA
Authors: Mitchell D.J.W. , Allen R.B. , Salama W. , Abouzakm A.
Published: December 2007

Drainage and sedimenatation patterns, present‐day and historically, relate to major north trending fracture and fault systems, which from topographic breaks in the Precambrain rift shoulders. Extensive Micocene depocentres are developed on the Sudanese and Ethiopian margins.

Basin structure follows a NNW‐SSE down‐to‐the‐basin trend with deep planar crustal faults active at dthe basin margin. Clastic loading in coastal setting resulted in salt withdrawal and gravity sliding on listric faulting, soling‐out into a base ‐salt decolloement. Teh evaporite and postevaporite sequences form a number of linear tectonostraitigraphic zones within the basin, which evaporite sequences form a number of linear tectonostratigraphic zones within the basin, which form play fairways whre the post‐salt section is mature. The axial zone appears to have been a positive feature in the southern Red Sea during the middle‐upper Micocene, separating two salt depocentres. Different structural and facies patterns on either side of the axil zone indicate basin asymmetry in this region.

Attractive pre‐rift source and reservoir rocks are present at outcrop in the Egyptian and southern Red Sea margins, but may have been stripped from the crests of rotated faultblocks, and be overmature for oil whre preseveed in half ‐graben lows.While the post‐salt in the northern Red Sea is immature increaing geothermal gradient and depth of burial result in maturation of the Zeit and basal Wardan Formations tot eh south, where extensive hydreocarbon seepages have been reported. Locally good, maure oil‐prone sources rocks have been encountered in the pre‐salt Mieene sequence offshore, but no equivalent to the “Globigerinal” of the gulf of Suez and Barqan areas has been encountered to‐date. The post‐salt Zeit offers the offers the possibility of cyclical deposition of oil‐prone source, reservoir and seal parasequences in juxtaposition; gas‐prone source rocks are developed in the Tokar Delta of Sudan.

Rotated pre‐evaporite fault blocks are the main play targets in the northern red Sea. To the south, halokinetic stucturing of the post‐salt Miocene results in a number of attractive play types.
THE AGE OF SALT IN THE GULF OF MEXICO BASIN
Authors: Wilson H. H.
Published: December 2007

The assumption that all salt in the Gulf of Mexico basin is Jurassic demands a fixed structural framework since mid‐Jurassic time. This assumption has questionable geological support and is challenged.

Salt in the Salina Basin of southern Mexico has been presumed Jurassic because shallow salt at Chinameca is overlain by ammonite‐bearing Kimmeridgian — early Neocomian limestones which, in turn, are overlain by Oligocene sediments.

Despite numerous salt penetrations elsewhere in the Salina Basin, the Chinameca limestone has not been encountered. Instead, the non‐piercing salt massifs directly underlie Oligo‐Miocene beds, which have also been found intercalated with the salt. Two wells that have traversed the salt found Oligocene sediments below.

Field checks in the Chinameca limestone type‐locality reveal that these beds are both strongly folded and heavily brecciated. They do not overlie the salt normally, and are interpreted as slumped masses that slid from elevated fault scarps onto Oligocene evaporites during Oligocene block movements.

Geological evidence supports the conclusion that the Salina salt is Oligocene, and was deposited during the worldwide Oligocene eustatic drop. Because the Salina salt is stratigraphically continuous with the salt in offshore Campeche, this also is deemed to be Oligocene.

The Challenger salt has been dated as Jurassic on the basis of one palynomorph‐bearing sample cored from the cap rock of the Challenger knoll. However, the Challenger salt is in continuity with the Campeche evaporites, which suggests that it, too, is Oligocene. In view of the wide range of datable detrital material recovered from Salina salt samples, the dating of Challenger salt from a single sample of insoluble residue cap‐rock is considered premature.

On the north side of the Gulf, evidence for Oligocene salt obtained earlier from the Belle Isle salt dome is supported by the presence of intra‐Frio evaporites encountered in two deep exploration wells.

The probability of large deposits of Tertiary evaporites in the Gulf of Mexico leads to the interpretation that the evolution of the Gulf Basin was governed by a sequential process of deep crustal extension that persists until the present day, rather than an exclusively Jurassic extensional event as is currently accepted.
SAMGORI FIELD, REPUBLIC OF GEORGIA: CRITICAL REVIEW OF ISLAND‐ARC OIL AND GAS
Authors: Patton D. K.
Published: December 2007

The Samgori field in the Republic of Georgia (CIS) has produced more than 165 million brls of oil since its discovery in 1974, and the development of recently‐discovered deep gas is now under way. The field produces oil from an Eocene volcaniclastic section which has been interpreted as being associated with an island arc. Available data from the field include well logs, porosity and permeability measurements from cores, chemical analyses of fluids produced, and reservoir‐performance history. These data comprise the basis for an investigation of generation, migration and entrapment of hydrocarbons.

The Samgori field provides evidence that requisite parameters for significant accumulations of oil and gas are present in Georgia. The existence of other large fields depends primarily upon the occurrence of suitable reservoir rocks. Volcanogenic rocks offer potential reservoirs, but the importance of enhanced secondary porosity development must be emphasized. Regional porosity within the volcaniclastic section has developed as a result of zeolitization coupled with fracturing, a situation evidenced by infiltration of meteoric water over large distances. In view of this, reasonable possibilities exist for the occurrence of similar reservoirs nearby. The ability to predict zeolitization and fracturing elsewhere in Georgia would be critical to exploration success.
HYDROCARBON POTENTIAL OF SANDSTONE RESERVOIRS IN THE EAST SLOVAKIAN BASIN, PART 2: ZEOLITES AND CLAY MINERALS
Authors: Reed J. K. , Gipson M. , Vass D.
Published: December 2007

Zeolites and authigenic/diagenetic clay minerals in Neogene sandstones of the East Slovakian Basin are closely related to the presence of locally‐abundant tuffs and tuffaceous sediments. In tuffs, plagioclase crystals, glass shards, and volcanic rock fragments alter to zeolites and clay minerals. In sandstones, zeolites are formed both from the direct alteration of volcanic rock fragments, and as authigenic pore‐filling minerals; clay minerals occur as diagenetic products of both volcanics and feldspars. Zeolites present include erionite, clinoptilolite, mordenite, analcime, and minor offretite, phillipsite, and laumontite. Authigenic/diagenetic clay minerals include smectite, illite, chlorite, and kaolinite. Vertical and lateral distributions of authigenic/ diagenetic mineral assemblages tend to follow published models. A complete paragenetic model of the occurrences of these minerals within the basin is not currently possible with the present, limited database.

Diagenetic/authigenic mineral suites in sandstone hydrocarbon reservoirs present special problems for exploration and production technology. These problems include: (1) well‐log distortions; (2) reservoir permeability reduction through diagenesis; and (3) reduction of permeability through interactions between diagenetic clay minerals and zeolites and incompatible fluid systems. Recognition of problematic mineral suites in this study allows for the application of accepted technological solutions, which in turn could result in the increase of recoverable reserves in addition to those added by exploration efforts.
THE TALARA FOREARC BASIN, NW PERU: DEPOSITIONAL MODELS OF OIL‐PRODUCING CENOZOIC CLASTIC SYSTEMS
Authors: Carozzi A. V. , Palomino J. R.
Published: December 2007

The Talara Basin is an unusual forearc basin, inasmuch as it displays many features which are not characteristic of such a tectonic context. These features apparently result from the basin's location at the intersection of the Amazonas Aulacogen, the Andean orogenic belt, and the subduction zone of the Peru‐Chile Trench. The history of the Talara forearc basin is dominated by exlensional rather than compressional tectonic activity, which reached a peak after the Eocene in association with low‐angle gravity slides. This tectonism began with a prolonged synsedimentary phase, which, during the Paleocene‐Eocene, generated a complex system of horsts and grabens bounded by major high‐angle normal faults trending NE‐SW and NW‐SE. Closely related to repeated phases of uplift and erosion in the eastern Andean source areas, this structural pattern controlled unusually thick and coarse clastic sedimentation during the Paleocene‐Eocene; a thickness of about 22,000 ft has been preserved, from which volcanics are essentially absent.

The depositional environments were a series of interfering, transverse and longitudinal, deltaic and submarine fan systems, all of which contain distal portions in which organic‐rich marine shales were deposited. Given these conditions, it is not surprising that the Talara Basin has produced to date more than a billion (109) barrels of oil. Although oil is produced from these depositional systems both on‐ and offshore, the latter environment has been barely explored near the present‐day coastline, and is believed to have enormous potential for future development.
DIAGENESIS OF NON‐MARINE PETROLEUM RESERVOIRS: THE NEOCOMIAN (LOWER CRETACEOUS) SHURIJEH FORMATION, KOPET‐DAGH BASIN, NE IRAN
Authors: Moussavi‐Harami R. , Brenner R. L.
Published: December 2007

Detailed petrologic, sedimentologic and geohistory analyses have been carried out on the Neocomian (Lower Cretaceous) Shurijeh Formation in the eastern part of the Kopet‐Dagh Basin, NE Iran. The results of these analyses show that the diagenetic history of Shurijeh sandstones was affected by their depositional settings, and the subsequent subsidence of these units through meteoric and compactional hydrologic regimes in this part of the Kopet‐Dagh Basin. These rocks consist mostly of sub‐litharenitic redbeds deposited during a regressive phase of sedimentation dominated by rapid siliciclastic sediment supply. The lower and middle portions of the interval studied were deposited in low‐sinuosity braided fluvial systems, and the upper portion was deposited in high‐sinuosity meandering systems.

The porous and permeable sand‐rich units were partially filled by infiltrated clays, and early calcite, anhydrite and silica cements as they subsided through the meteoric regime. In the compactional regime, feldspars altered to clays, dolomite replaced calcite and penetrated authigenic silica, and a late‐stage of calcite cementation and replacement took place. These diagenetic events were followed by partial dissolution of early and late‐stage calcite cements that created secondary porosity in the sandstone units. During the late Miocene—early Pliocene (approximately 10 million years), the Late Alpine Orogeny resulted in the formation of structural traps in the Shurijeh Formation of the Sarakhs area. This was followed by migration of gas into the porous units of this formation, accounting for the Khangiran and Gonbadli gasfields.

Relationships revealed in this study can be used to develop diagenetic models that will help predict diagenetic styles in dominantly non‐marine sandstones in other basins similar to the Kopet‐Dagh of Iran.
BASIN RICHNESS AND SOURCE ROCK DISRUPTION — A FUNDAMENTAL RELATIONSHIP?
Authors: Price L. C.
Published: December 2007

Primary petroleum migration (expulsion from source rocks) remains the least understood parameter controlling the genesis of oil deposits. In spite of this lack of understanding, many petroleum geochemists (including this Author) have previously considered expulsion from organic‐rich, mature source rocks to be very efficient. This viewpoint results from Rock‐Eval analyses of organic‐rich source rocks, analyses which demonstrate a loss of hydrocarbon (HC) generation capacity, by significant reduction in Rock‐Eval hydrogen indices, as such rocks are progressively buried in sedimentary basins. However, this progressive loss of HC generation capacity is not matched by numerically‐equivalent increases either in Soxhlet‐extractable HCs or the Rock‐Eval S1 pyrolysis peak. Thus, we conclude that almost all generated HCs have migrated from the source rocks.

Notwithstanding, the petroleum geochemistry of the Williston Basin (North America) and other considerations strongly suggest that this logic may be flawed. Instead, it appears that most generated HCs may not migrate far from their generation site, but instead are lost before source‐rock samples arrive at the laboratory for analysis. This loss occurs from a HC‐gas volume expansion, which results from the large pressure decreases in rock chips or cores during the trip up the wellbore in the course of drilling operations. The large volume expansions of these HC gases, which are cogenerated and coexist with oil in the source rocks, literally blow most generated oil in source rocks into the drilling mud during the trip uphole.

If most generated HCs do in fact remain in or near their source rocks, then it can be hypothesised that source rocks must be physically disrupted before meaningful expulsion can occur. Faulting, with accompanying significant fracturing, would appear to be the optimum naturally‐occurring process for physical disruption of source rocks. If these hypotheses are valid. intensity of faulting in deeply‐buried HC “kitchens” containing mature source rocks should strongly correlate with increasing basin richness, as defined by recoverable oil divided by basin‐sediment area or volume.

This possible relationship is examined in this Paper; and there is a strong correlation of increasing basin richness with increasing structural intensity over and adjacent to basin depocentres. This correlation thus supports the hypothesis that physical disruption of mature source rocks is a necessary, and previously unappreciated, controlling parameter for oil expulsion. If a relationship between physical disruption of source rocks and oil expulsion indeed exists, then significant implications would follow for:

(1) basin resource assessment;

(2) conventional oil exploration in frontier basins; and

(3) the probable existence of very large, previously unappreciated, oil‐resource bases in fractured, self‐sourced shales.
CUBAN GEOLOGY: A NEW PLATE‐TECTONIC SYNTHESIS
Authors: Iturralde‐Vinent M. A.
Published: December 2007

Cuba is considered here to consist of two separate geological units: afoldbelt and a neoautochthon.

The foldbelt can be subdivided into:

(i) continental units, comprising Mesozoic Bahamian Platform and slope deposits, which are overlain by a Paleocene‐ Late Eocene foreland basin; and the Cuban SW terranes (Guaniguanico, Pinos and Escambray), which were probably originally attached to the Yucatan Platform;

(ii) oceanic units, namely: the northern ophiolite belt; the Cretaceous (?Aptian‐Campanian) volcanic arc, which is overlain by a series of Latest Cretaceous — Late Eocene “piggy‐back” basins; and the Paleocene‐Middle Eocene volcanic arc which is overlain by a late‐Middle — latest Eocene “piggy‐back” basin.

The neo‐autochthon is composed of slightly‐deformed, latest Eocene to Recent sedimentary rocks, which unconformably overlie the folded belt.

A large number of tectonic models for the Caribbean area have been published in recent years, but rarely include modern data on the geology of Cuba. The Author here presents a plate‐tectonic model for the western Caribbean which is based on the following premises: (i) opening of the Caribbean took place along several parallel rifts‐zones, and a main transform fault located between the entrance of the Gulf of Mexico and the Demarara Plateau; (ii) the Cretaceous Greater Antilles volcanic arc faced the ProtoCaribbean Sea, and essentially northward‐dipping subduction took place; and (Hi) the western Caribbean Paleocene‐Middle Eocene volcanic arc also faced the Caribbean Sea, with subduction dipping towards the NNW.

Hydrocarbon production in Cuba comes from oilfields located in both continental and oceanic units. The Northern Oil Province coincides with the Bahamian platform and slope deposits and the Guaniguanico Terrain. The Southern Oil Province is represented by the latest Cretaceous — late Eocene sedimentary basins and the Cretaceous volcanic arc.
A GENETIC APPROACH TO THE PREDICTION OF PETROPHYSICAL PROPERTIES
Authors: Jian F. X. , Chork C. Y. , Taggart I. J. , McKay D. M. , Bartlett R. M.
Published: December 2007

The importance of the flow unit approach to reservoir description has been recognised recently, but its application to predict porosity, permeability and water saturation from well logs has not been attempted in previous studies. This Paper describes a genetic approach to reservoir description, which combines lithofacies analysis with discriminant analysis and probability field simulation for the identification and characterisation of flow units on the basis of core and log data.

Lithofacies with distinct depositional, diagenetic and petrophysical characteristics, which essentially act as lithohydraulic flow units, have been identified from cores. A set of discriminant functions is then computed using log data from cored wells to identify lithofacies from wireline logs in uncored wells. Each lithofacies has been found by regression analysis to possess a distinct porosity and permeability relationship. The lithofacies‐specific relationships between sonic travel time and core porosity is also established by regression analysis. Porosity and permeability values predicted from regression analysis lack variability when compared to actual core data. Hence, probability field simulation is applied to add fine‐scale variation to the values predicted from regression analysis.

The techniques described here can be applied to any type of reservoir. The application of these techniques has resulted in an improved prediction of porosity, permeability and water saturation for a shaly, glauconitic reservoir in the North West Shelf area of Australia, where traditional log analysis has been proved to be difficult to apply.
AN EMPIRICAL EXPRESSION FOR PERMEABILITY IN UNCONSOLIDATED SANDS OF THE EASTERN NIGER DELTA
Authors: Owolabi O.O. , Longjohn T.F. , Ajienka J.A.
Published: December 2007

Several correlations for estimating the reservoir permeability from electric well‐log data have previously been developed. Unfortunately, none of these correlations are universally valid, since each correlation is strongly dependent on the local lithology, and the properties and distribution of reservoir fluids in the well. There is therefore a need to develop such a correlation for use in reservoir rocks of the Niger Delta Basin.

Using multiple‐regression analysis, the Authors have developed empirical expressions for permeability in terms of log‐derived porosity and irreducible water‐saturation for unconsolidated sands in the Eastern Niger Delta. A comparison is made between this new expression and those previously proposed, using 218 sets of field‐measured data. Permeability estimated by the newly‐ proposed expression is found to be accurate.

The expression could be valid for other oil‐producing areas, provided that the reservoir rock and fluid properties are similar to those of unconsolidated sands in the Eastern Niger Delta.
MESOZOIC SOURCE ROCKS AND HYDROCARBON POTENTIAL OF THE SEYCHELLES OFFSHORE
Authors: Plummer Ph. S.
Published: December 2007

Three wells in the Seychelles offshore indicate the existence of four potential source‐rock intervals within the Mesozoic succession. Two of these originated during the rift phase that eventually cleaved Gondwana into Eastern and Western blocks — namely, Middle Triassic lacustrine mudstones, and Early/Middle Jurassic deltaic‐lagoonal mudstones. The other two source‐rock intervals were deposited on passive marine shelves during continental drift phases — namely, Late Jurassic to Early Cretaceous mudstones and siltstones during the East‐West Gondwana drift, and Maastrichtian to Paleocene mudstones during the later Seychelles‐India drift.

These source rocks are dominated by terrestrial organic matter. Although TOCs are generally good (greater than 1.0%) and range to excellent (7.82%), potential hydrocarbon yields are generally only poor to fair (less than 6 kg HC/tonne of rock). One good potential yield of 10 kg/tonne has been measured. Maturity data (R0 and Tmax) indicate that, in the wells, the youngest source rock is immature, while the oldest lies in the gas “window”. The Jurassic/Cretaceous source rocks, on the other hand, lie within the oil “window”.

Analyses of numerous beach‐stranded tarballs that are believed to be of indigenous origin reveal, in addition to a source dominated by terrestrial organic matter, the presence of a source rock dominated by marine algal organic matter. Such a source rock may have developed during a Middle Jurassic phase of shallow‐marine carbonate deposition, which shows some affinity to source‐rock quality, and is characterized by an oolitic marker limestone in each well. This oolitic limestone is also a component fades of the carbonate succession that contains the prolific oil‐prone source‐rock fades of the Middle East.
THE ORIGIN AND DIAGENESIS OF SEDIMENTARY ORGANIC NITROGEN
Authors: Baxby M. , Patience R. L. , Bartle K. D.
Published: December 2007

This paper provides an overview of the current state of knowledge concerning the inclusion and transformation of nitrogen in sedimentary organic matter (SOM). The main focus is on petroleum‐forming systems, although some mention is also given to coal.
THE LOCATION OF MAJOR OIL‐ AND GASFIELDS: EXAMPLES FROM THE ANDEAN FORELAND
Authors: Pratsch J.‐C.
Published: December 2007

In all producing basins, most of the oil and/or gas reserves are concentrated in a minority of fields. This distribution of oil and gas reserves is the result of “focusing” during lateral and vertical basin‐wide migration. Although the physico‐chemical and geological processes involved in hydrocarbons migration are not yet fully clarified, lateral migration directions can be established by integrating geological, geophysical and geochemical data. The Petroleum Systems concept is of use here. When combining Petroleum Systems data with well‐controlled regional structure maps, areas of hydrocarbons concentration (i.e. migration focusing) can be defined as areas of the highest exploration potential.

Some basic petroleum‐geological data are reviewed from the Eastern Venezuela Basin and the Llanos Basin region in Colombia. By using published Bouguer gravity maps as regional structural form‐line maps, areas of preferred lateral migration are shown to be areas of maximum hydrocarbon accumulations.

This leads on to an exploration approach in which Petroleum Systems data and regional (gravity or other) structure maps are used to evaluate acreage for its exploration value with a minimum expenditure of time, manpower and related funds.
FACTORS AFFECTING THE DYNAMIC EQUILIBRIUM OF GAS ACCUMULATIONS
Authors: YiGang Zhang
Published: December 2007

The accumulation of natural gas in commercial volumes is a function of the dynamic equilibrium between its rates of generation and dissipation. It is proposed here that four fundamental factors control the formation of gasfields: two relate to generation, and two to dissipation. Details of these four factors are discussed.

It is suggested that there exist plentiful supplies of “young” gas, located in relatively stable structural environments during post peak‐generation stages, retained in place by efficient seals.
STRATIGRAPHY OF THE MERGUI BASIN, ANDAMAN SEA: IMPLICATIONS FOR PETROLEUM EXPLORATION
Authors: Polachan S. , Racey A.
Published: December 2007

Nine formations from the Mergui Basin, Andaman Sea, are described in detail: the Ranong, Yala, Payang, Tai, Kantang, Surin, Trang, Thalang and Takua Pa Formations. Of these, the Ranong, Yala, Tai, Surin and Thalang are described for the first time, while the Payang, Kantang, Trang and Takua Pa are redefined and formally described. The Mergui Basin is a transtensional back‐arc basin, which formed in the Oligocene due to the onset of steady and increasingly oblique convergence between the Indian and SE Asian Plates and the formation of associated strike‐slip faults. The geological history of the Mergui Basin and surrounding areas is briefly summarised. Major similarities between the Mergui Basin and the petroleum‐rich North Sumatra Basin are noted, and the petroleum potential of the Mergui Basin is briefly assessed.
PETROLEUM PROSPECTS OF UPPER TRIASSIC CARBONATES IN NORTHERN IRAQ
Authors: Sadooni F. N.
Published: December 2007

The development of a sedimentary basin during the Late Triassic in northern Iraq marked the initiation of the Neotethys in the region. Sedimentation was influenced by basement block faulting, the disposition of the basin on different tectonic blocks, and the prevalence of arid and semi‐arid climatic conditions. Sediments deposited included carbonates, evaporites and minor clastics. Carbonates were deposited on a shallowmarine shelf (the Kand sub‐basin) that received an influx of clastic material at its western and southern margins. A local salina (the Qara Chauq sub‐basin) also developed, leading to the deposition of bedded anhydrites and halites. Hydrocarbon prospects are restricted mainly to the NW parts of the Kand sub‐basin.
TECTONIC FABRIC OF THE ATLANTIC OCEAN FLOOR: SPECULATION VS. REALITY
Authors: Smoot N. C. , Meyerhoff A.A.
Published: December 2007

Almost all published charts of the world's ocean floors have been drawn deliberately to reflect the predictions of the plate‐tectonics hypothesis. For example, the Atlantic Ocean floor is unvaryingly shown to be dominated by a sinuous, north‐south mid‐ocean ridge, flanked on either side by abyssal plains, cleft at its crest at its crest by a rift valley, and offset at more‐or‐less regular 40‐ to 60‐km intervals by east‐west‐striking fracture zones. However, it is now clear that as new, detailed, bathymetric surveys are being completed, this oversimplified portrayal of the Atlantic Basin is largely wrong. Thousands of bathymetric features present, many of them major, are wholly unexplained by plate tectonics. Others, predicted by plate tectonics, are totally absent. We show, on the basis of specific examples based on real data from the North Atlantic Ocean, that the real bathymetry and the real tectonic fabric are very different from the bathymetry and tectonic fabric protrayed (but rarely documented) in plate‐tectonics publications. A new hypothesis is needed to explain the origin of the real bathymetry and tectonic fabric of the deep oceans. Such a hypothesis could very well provide clues for future petroleum and other mineral exploration along the continental margins.
PALAEOZOIC PRE‐SALT SEDIMETNS IN THE PRECASPIAN PETROLIFEROUS PRPVINCE
Authors: Nevolin N.V. , Fedorov D.L.
Published: December 2007

The PreCaspian (North Caspian) Basin is located on the SE margin of the Russian Platform, and extends as far south as the north coast of the intra‐continental Caspian Sea. Regional surface elevations here are as much as 24 m below sea‐level. The basin is one of the World's deepest, with basin‐fill sediments exceeding 20 km in thickness. The Proterozoic section, the pre‐slat Palaeozoic section, and the Upper Permian (slat‐bearing) interval are all about 5‐km thick, although as a result of salt movements, the salt‐bearing sequence may be thicker. The basin has a roughly oval outline, and is 900‐km wide, 600‐km is length, and covers around 500,000 sq. km. It is divided into the Central and SE Sub‐basins by the approximately east‐west trending Astrakhan‐Aktyubinsk system of basement highs. A series of massive carbonate build‐ups rim the basin margins.

This paper considers the sturcture and hydorcarbons potential of the pre‐salt (Palaeozoic) sedimentary section, whose regional prospectivity has been confirmed by the discovery of a series of “giant” oil, gas and condensate fields, including Tengiz, Karachaganak and Astrakhan. Hydrocarbons in these fields are sourced and reservoired in massive organicrich carbonates of Palaeozoic age.
A NEW FACIES MODEL FOR THE MISOA FORMATION (EOCENE), VENEZUELA'S MAIN OIL RESERVOIR
Authors: Higgs R.
Published: December 2007

The Misoa Formation has produced an estimated 13 billion barrels of oil, and contains a further 11 billion barrels of proved remaining reserves. The total represents approximately 50% of the proved reserves of the Maracaibo Basin, Venezuela's most productive region. In such a prolific formation, application of an inappropriate facies model to exploration and development can have huge financial consequences, in terms of misplaced wells, missed pools and miscalculated reserves.

A deltaic depositional model has been used for exploration and development drilling in the Misoa Formation since the 1960s. However, this deltaic interpretation is doubtful due to the lack of in situ coal beds, palaeosols and other evidence for emergence diagnostic of delta plains. An alternative, tidal‐shelf model is proposed here.
STRATIGRAPHY AND RESERVOIR POTENTIAL OF THE MESOZOIC KHORAT GROUP, NE THAILAND: Part 2: Diagenesis and Reservoir Quality
Authors: Canham A.C. , Love M.A. , Racey A. , Polachan S.
Published: December 2007

The Mesozoic Khorat Group in NE Thailand consists of a series of continental red‐beds, divided here into five formations, which unconformably overlie the lithologically‐similar Nam Phong Formation. The reservoir quality of the Khorat Group decreases progressively with increasing age, owing to burial compaction and diagenesis. Compactional fabrics suggests a maximum burial depth of more than seven km, although the Sao Khua Formation (in the middle of the Khorat Group) shows early calcite cements which stabilised the sediment fabric at burial depths of about one km. Porosities vary from 11% in the uppermost part of the Khorat Group (Khok Kruat Formation) to 4.9% in the Nam Phong Formation. The ratio of secondary grain‐dissolution porosity to primary porosity increases with age (and depth). Authigenic minerals consist of quartz (1.3 ‐ 9.3%), calcite (0 ‐ 26.5%) and kaolinite (0 ‐ 4.0%). The occurrence of detrital clays (0.8–9.6%) in particular causes downgrading of the porosity of many of the sandstone samples examined.
OCEANIC METHANE HYDRATES: A “FRONTIER” GAS RESOURCE
Authors: Max M. D. , Lowrie A.
Published: December 2007

Methane hydrates are ice‐like compounds consisting of natural gas (mainly methane) and water, whose crystal structure effectively compresses the methane: each cubic metre of hydrate can yield over 150 cu.m of methane. Hydrates “cement” sediments and impart considerable mechanical strength; they fill porosity and restrict permeability. Both biogenic and thermogenic methane have been recovered from hydrates.

Hydrates occur in permafrost regions (including continental shelves), and are stable in ocean‐floor sediments below water depths of about 400 m in the “Hydrate Stability Zone” (HSZ). This is a surface‐parallel zone of thermodynamic equilibrium that extends down from the sediment surface to a depth determined by temperature, pressure and local heat flow. Methane and water are stable below the HSZ.

Although the economic recovery of hydrates has taken place in Arctic regions, oceanic hydrates offer far greater potential as an energy resource. A variety of traps for methane gas can be formed by oceanic hydrates. In addition to the gas within the hydrates themselves, simple gas traps in closures beneath the HSZ in the vicinity of bathymetric highs, and complex traps involving both hydrate and structural/stratigraphic components, have been observed.

It has been estimated that at least twice as much combustible carbon occurs associated with methane hydrates as in all other fossil fuels on Earth. The evaluation of methane in, and associated with, oceanic hydrates therefore constitutes a major energy exploration frontier.
SUBSURFACE TRIASSIC SEDIMENTS IN JORDAN: STRATIGRAPHIC AND DEPOSITIONAL CHARACTERISTICS, AND HYDROCARBON POTENTIAL
Authors: Shinaq R.
Published: December 2007

Unconformity surfaces have been used to divide the subsurface Triassic sediments of Jordan into five sequences. These sequences show a gradual transition from fluviatile‐deltaic sedimentation during the Permian, to mixed sedimentation of sandstones, silty shales and claystones together with shallow‐water carbonates from the Scythian to the end of the Ladinian. Anhydritic dolomites and evaporites became prevalent during the Carnian‐Norian.

Isopach and facies maps for these sequences show that the Triassic sediments of Jordan were deposited in a set of environments which range from fluviatile‐deltaic for the coarse‐grained clastics; to restricted shelf lagoons and tidal‐flat settings for the finegrained clastics; to a shallow carbonate shelf for the fossiliferous carbonates; and restricted shelf lagoons, sabkhas and salinas for the carbonate‐evaporite sequence.
THE CRETACEOUS SERIES IN THE CHAD BASIN, NE NIGERIA: SOURCE ROCK POTENTIAL AND THERMAL MATURITY
Authors: Olugbemiro R. O. , Ligouis B. , Abaa S. I.
Published: December 2007

The Chad Basin is the largest intracratonic basin in Africa, and one‐tenth of its surface area lies in NE Nigeria. Thermal maturation (mean vitrinite reflectance) and organic‐geochemical (Rock‐Eval pyrolysis) studies have been carried out on Cretaceous shales from the Bima Formation, Gongila Formation and Fika Shale Formation. Samples were derived from the Kanadi and Albarka exploration wells, which are located about 76 km apart in the Nigerian sector of the Chad Basin.

The organic matter is predominantly gas prone (Type III kerogen). Its thermal maturity, assessed from vitrinite reflectance and Tmax, indicates that the Gongila Formation and the Bima Formation are within the “oil window”, while the Fika Shale Formation is only partly within it. The “oil window”, deduced from the mean vitrinite reflectance profile, occurs between 1,270m ‐ 2,600m in the Kanadi well, and between 1,985m ‐3,690m in the Albarka well, with respective maturation gradients of 0.52 log%Rm/km (0.41%Rm/km) and 0.41 log%Rm/km (0.34%Rm/km). Eroded thicknesses amount to about 1 km.

The upper part of the Fika Shale Formation has the best source‐rock potential in terms of its organic carbon content, but has low thermal maturity. The Gongila Formation is poor in organic carbon and its hydrocarbon potential may already have been exhausted. The Bima Formation is well within the “oil window”, but has only limited potential as a source rock, because of the presence of clastic and inert materials. The potential for gas accumulations, however, exists.
PREHISTORIC, ANCIENT AND MEDIAEVAL OCCURRENCES AND USES OF HYDROCARBONS IN THE GREATER MIDDLE EAST REGION
Authors: Beydoun Z. R.
Published: December 2007

THE ARABIAN PLATE, and neighbouring parts of Egypt, Turkey, Iran and the southern Caucasus, includes within its boundaries numerous active hydrocarbon seepages. Their origin is related to the beginning of the current tectonic regime, which commenced in Oligocene‐Miocene times. The culmination of Alpine tectonics around the northern edge of this region gave rise to stress regimes that deformed the plate margins and ruptured the integrity of hydrocarbon traps and seals. This resulted in the many seepages recorded throughout the Arabian Plate and adjoining areas to the north.

Extensional plate margins bound the Arabian Plate to the SW and south; transform margins are on the west and SE; and collisional margins on the north and NE. It is along these (or along splays from them) that most of the major active seepages occur.

The collisional regimes along the Taurus and Zagros foldbelts in the north and NE caused considerable subsurface movement of Cretaceous and older hydrocarbons and their migration and remigration. As folding intensified, inefficient seals were ruptured, and very large volumes of hydrocarbons migrated vertically upwards until trapped close to the surface in vast carbonate reservoirs beneath the regionally‐efficient evaporite seals provided by the Miocene Lower Fars/Gachsaran Formations. Where these seals were thin, poorly‐developed or eroded, major seepages developed, and huge volumes of hydrocarbons may have escaped to the surface. Indeed, there is speculation whether the Zagros foreland basin, overprinted onto the vast NE Arabian Shelf as a result of the Arabian/Eurasian Alpine collision, has not lost more hydrocarbons than it has retained through this process (Beydoun et al., 1992).
PETROLEUM GEOLOGY OF THE TARIM BASIN, NW CHINA: RECENT ADVANCES
Authors: Changlin Gao , Deliao Ye
Published: December 2007

The Tarim Basin is located in the Xijiang Uygur Autonomous Region of NW China, and covers an area of about 560,000 sq. km. At dawn on September 22nd, 1984, Well Shashen‐2 (drilled by a team from the Ministry of Geology and Mineral Resources) blew‐out spectacularly when it penetrated Ordovician dolomites at a depth of 5,392m. The blow‐out marked the discovery of a highly‐productive oil‐ and gasfield, from which daily output has reached 1,000 m3 oil and 2 MM (million) m3 gas.

Over the last decade or so, 560,000 km of gravimetric surveys (scale l.106) and 338,000 km of airborne magnetic surveys (1:200,000) have been completed. Some 200,000 line‐km of 2‐D seismic profiles and 10,000 km of 3‐D surveys have also been carried out, and more than 200 wells have been drilled. Twenty‐two oilfields producing from ten stratigraphic intervals, four of which have reserves of more than 100 million tons, have been discovered or explored, indicating that the future prospects for petroleum exploration in the basin are very favourable (Kang and Huang, 1992; Jia, 1991a; 1991b). Annual production in the Tarim Basin reached 2,300,000 t in 1995 (Kang et al, 1996).
PETROLEUM GEOLOGY: TWO DECADES OF CHANGE
Authors: Hobson G.D.
Published: December 2007

SOME TWENTY YEARS AGO, Dr E.N. Tiratsoo (whom I had known since the mid‐1930s) visited me at the Royal School of Mines, and told me of his plans to set up a new “journal of petroleum geology”.The Journal has now reached its twentieth volume.

Thinking especially about the United Kingdom, the past twenty years have also seen the publication of the proceedings of four major conferences held in London, on the geological results of North Sea oil exploration, as well as other similarly‐based books from Norwegian sources. Somewhat earlier, the European Branch of the Organic Geochemistry Group of the Geochemical Society was formed. A European geophysics‐based society has also appeared, and a vigorous petroleum group was formed in the Geological Society in 1980. There has been a proliferation in literature (both books and journals) dealing with the geology of oil and gas. It is against this background that the Journal of Petroleum Geology has succeeded.