bluuebunny/crossref_metadata_2025_split huggingface dataset:
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 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.