bluuebunny/crossref_metadata_2025_split huggingface dataset:
OIL POSSIBILITIES OF DUPLEX STRUCTURES IN THE AMIK‐REYHANLI BASIN, SE TURKEY
Authors: Coskun B. 
Published: December 2007

The Amik ‐ Reyhanli Basin is situated in the south of Turkey, near the Syrian border. The Dead Sea fault, which crosses the Lebanon and enters Turkey in the Antakya region, forms the basin's eastern boundary. Its basement is composed of Upper Cretaceous Koçali‐Karadut ophiolites. Seismic interpretations indicate that a Mio‐Pliocene structure exists in the Amik region, and this was originally interpreted by exploration geologists to be a faulted anticline. However, careful seismic interpretation now suggests that the structure is a “triangle zone”, resulting from activity in the Dead Sea fault‐zone in the east and the Amanos fault to the west. It is suggested that duplex structures related to this triangle zone are present beneath the Cretaceous ophiolites, and constitute oil‐prospective areas.Esso Oil Co. interpreted this positive structure as a faulted anticline, and recently drilled Well Amik‐1, which was dry, in order to test the oil possibilities of Tertiary elastics and carbonates. The well terminated in the Koçali‐Karadut ophiolites. The underlying duplex structures were not reached, and the oil possibilities of Upper Cretaceous and Jurassic‐Triassic carbonates in these duplexes therefore remain to be tested.
LEBANON REVISITED: NEW INSIGHTS INTO TRIASSIC HYDROCARBON PROSPECTS
Authors: Beydoun Z. R. , Habib J. G. 
Published: December 2007

A total of only six exploration wells have been drilled in Lebanon since World War II. The exposed succession consists predominantly of competent carbonates, with only minor occurrences of shales and marls. None of these wells penetrated formations older than the oldest exposed at the suflace, which are of Liassic age. In the majority, reservoirs were invaded by meteoric waters as a result of the proximity of elevated, outcropping recharge areas, inencient seals, or the proximity of major faults. Calculations based on gravity data indicate that the basement beneath the Lebanon uplift is some 3 km below sea level, providing for a sedimentary column over 5,000‐m thick below the Upper Jurassic, most of which is unknown.The Triassic successions in the adjacent Palmyride Basin of Syria and of northern Jordan are, by contrast, well‐known from subsuflace exploration and drilling; over 1,500 m of carbonates, with thinner interbeds of shales and evaporites, are present in the former, where a number of Triassic oil, gas and condensate discoveries have been made. The axis of the Palmyride Basin trends WSW, towards Lebanon, as revealed by isopachs; Upper Triassic (Carnian) evaporites, including major salts, have a similar trend. It has long been proposed that if Triassic evaporites extend to Lebanon, they may provide a major impervious seal between meteoric water‐invaded reservoir strata above, and potentially petroliferous Triassic and Paleozoic successions below.The recent marine reflection‐seismic survey offshore Tripoli (northern Lebanon) has revealed the presence of a deeper and tectonically‐ mobilised salt level, in the core of a compressional structure, directly on trend with the westwards prolongation of the Palmyride salt and peripheral anhydrite basin on the other side of the Levant (Dead Sea) transform fault (lateral slip here <20 km). It has given added credence to the speculative presence of evaporites 650m below the oldest (Liassic) exposures at Nahr Ibrahim, north of Beirut, which were interpreted from an earlier electrical survey.A regional seal in the subsurface of Lebanon is thus assured, and the ingredients for Triassic, hydrocarbon generation, migration, entrapment and preservation can now be regarded as present. Both offshore (deep) and onshore (more shallow) prospects of Triassic age therefore seem attractive. Additionally. well‐penetration and seismic data from Syria indicate the presence of Ordovician andd Silurian successions at least under northern Lebanon. These successions regionally include several organic‐rich source levels. and lie within reach of the drill on the large onshore structures of the Lebanon uplift.A second, east‐west trending, basin of Triassic age (the Hawran Basin) extends under the basalt areas of Jaba1 Druze (Jabal al Arab) in southern Syria and northern Jordan, and into the Risha “panhandle” (NE Jordan), offering a frontier Triassic “play”.
VOLCANOGENIC AND VOLCANICLASTIC RESERVOIR ROCKS IN MESOZOIC‐CENOZOIC ISLAND ARCS: EXAMPLES FROM THE CAUCASUS AND THE NW PACIFIC
Authors: Levin L. E. 
Published: December 2007

Subduction of the Tethys oceanic plate beneath the Lesser Caucasus island are in the Late Creataceous — Eocene produced conditions favourable for the generation and accumulation of hydrocarbons. Subduction of crust in the Transcaucasus Massif led to the formation of various types of trap. Also, geothermal gradients here were high, resulting in the generation of hydrocarbons in shallow‐water sediments on the margins of the Massif, and their accumulation in both sedimentary and volcaniclastic reservoirs (e.g. in the Samgori‐Patardzeuli and Muradkhanly fields).The geodynamic setting of the NW margins of the Pacific Ocean was similar in the Neogene to that of the Transcaucasus Massif. Oceanic crust was subducted during the Oligo‐Miocene, and a series of inter‐are rifts were formed. The principal oilfields of Japan, where accumulations are resrvoired in volcaniclastic strata (Neogene‐Pleistocene) are located here. A possible analogue is the rift located in the southern East Kuril Basin, where the occurrence of petroleum has been inferred. Lithological studies of the Komandorsky Islands, eastern Kamchatka, the Kuril Islands and western Sakhalin indicate that the distribution of the reservoirs depends on the stage of evolution of the rifts and adjacent island arcs.
PETROLEUM IN GLACIALLY‐RELATED SANDSTONES OF GONDWANA: A REVIEW
Authors: Potter P.E. , Franca A.B. , Spencer C.W. , Caputo M.V. 
Published: December 2007

The supercontinent of Gondwana (Antarctica, Africa, Australia, South America, India, the Arabian Peninsula, Madagascar and Sri Lanka) covered more than six times the combined area of the United States and Brazil. In this paper, the petroleum occurrences and potential of glacially‐related rocks of Carboniferous‐Permian age in this vast area are reviewed in terms of basin types, reservoirs, seals, traps and source rocks.Significant amounts of heavy oil, sourced by Precambrian algal‐rich shales, are produced from glacially‐related sandstones in some 20 fields in Oman. Bolivia has 27 oil‐ and gasfields sourced from underlying Devonian shales, and oil production occurs in two fields in nearby Argentina. In Australia, there is production from two basins: the Cooper Basin has 24 productive fields (mostly gas), and the Canning Basin has six small fields. In Brazil, four non‐commercial shows have been found in the Paraná Basin and one in the Amazonas Basin. In Paraguay, southern Africa and India, there is no production from glacially‐related sandstones.Production and shows occur in cratonic basins either in the interior or along the margins of Gondwana, except for those in Bolivia, Argentina and South Africa, which occur in foreland basins.Sandstone reservoirs were deposited mostly as glacial outwash, as small deltas, either in lakes or marine basins, or as turbidites in marine basins bordered by continental ice sheets. Seals are diamictites, mudstones, shales and possibly diabases in the Paraná Basin. Traps include tectonic and salt‐related anticlines as well as pinch‐outs against glacial channels. Glacial outwash and glacio‐marine sandstones are thus important petroleum exploration targets.Commercial production to date is sourced from both older and younger non‐glacial beds. The fields in Oman were sourced by Precambrian algal‐rich shales, and those in Bolivia and adjacent Argentina by Devonian and possibly Silurian organic‐rich shales. The source of the gas in the Cooper Basin is from overlying coal beds. Neither modern marine, high‐latitude muds nor ancient glacially‐influenced marine shales contain sufficient organic material to be considered adequate source rocks.This review indicates that petroleum production in Gondwana's glaciogenic deposits mostly occurs in cratonic and passive margin basins; it occurs wholly in sandstone reservoirs, chiefly in structural traps, and nearly everywhere, reservoirs are sourced by hydrocarbons from non‐glaciogenic shales (either older or younger). The only “glacially unique” features of petroleum in Gondwana deposits are its seals of diamictites, which surely must also be true when considering the petroleum possibilities of older ancient glacial and glacially‐influenced deposits.
NUMERICAL MODELLING OF DIAGENETIC QUARTZ HYDROGEOLOGY AT A GRABEN EDGE: BRENT OILFIELDS, NORTH SEA
Authors: Mullis A.M. , Haszeldine R.S. 
Published: December 2007

Oilfields in the Middle Jurassic Brent Group of the East Shetland Basin contain abundant quartz cement, which reduces porosity by 10–15%. This quartz cement is believed to have started to grow at depths of around 2‐3km. Oxygen isotope signatures in diagenetic quartz imply that it grew from meteoric pore waters; however, fluid inclusion temperatures are 30–50d̀C higher than temperatures which should have prevailed at the inferred palaeo‐depth. Large‐scale circulation of hot water has been proposed to explain this “temperature anomaly”, but this is geologically difficult in terms of heat and fluid budgets. Finite‐element fluid‐flow models of a generic fault‐block rift‐basin stratigraphy are used to evaluate two alternative hydrogeological models for deep quartz diagenesis in Brent Group sandstones:

Meteoric waters may have penetrated several kilometeres into the crust before rising rapidly as a hot, isotopically‐evolved fluid;
Cool meteoric waters from the palaeo‐land, fed directly into the Brent Group aquifer, moving tens of kilometres laterally into the basin.

Numerical models show that in this case gravitational penetration of moving fluids to considerable depth in the crust was indeed feasible with a driving head of only 200 m. Fluid velocities were so low (≅ 0.01 m/yr) that the heating effects of the fluids were minimal. Long‐range lateral transport of heat was also inefficient, for fluids tend to emerge along the first major fault plane encountered. Large‐scale mixing within aquifers resulted in a uniform fluid during the start of quartz diagenesis in the Brent Group. This mixing was not sensitive to permeability anisotropy. The slow infiltration of meteoric fluids into Brent Group aquifers is inferred to have maintained a low‐salinity, meteoric isotopic dominance to the pore fluids. These slow, large‐scale lateral flows may have exited from the Brent aquifer at “leak points” on shallow‐buried structures, such as Gullfaks. Degraded oil on the downdip side of Gullfaks also independently suggests an active deep aquifer in the Early Tertiary. Consequently, diagenetic quartz grew at equilibrium temperatures and adopted a meteoric‐dominated isotopic signature. Quartz supply was decoupled from such fluids, and was probably locally‐sourced.
PETROLEUM SYSTEMS AND GLOBAL TECTONICS
Authors: Perrodon A. 
Published: December 2007

Petroleum Systems are currently being studies within the general framework of plate tectonics. This new approach has led to the definition of three types of system in the context of the dynamic evolution of sedimentary basins. These three types are “initial rift”, “continental platform”, and “orogenic‐deltaic” Petroleum Systems. The richness and efficiency of a petroliferous basin often depends on an association between two, or perhaps all three, of these types of system. Foreland basins are perhaps the best example.Plate‐tectonics theory suggests that a mobile lithosphere is the rule rather than the exception. The transfer of both fluids and materials may occur within a sedimentary basin as a result of horizontal or vertical displacement of the lithosphere. Petroleum Systems therefore appear to be a direct consequence of crustal mobility.When hydrocarbons migrate out of a source rock, they may either be dispersed within another lithological unit and effectively “vanish”, be lost by seepage into the atmosphere, or be trapped by some sort of permeability barrier. In the latter case, the resulting hydrocarbon accumulation can be described as a temporary concentration, whose duration essentially depends on the intensity of the incoming fluid flow and the resistance of the permeability barrier(s).The study of a particular Petroleum System within a global geodynamic framework enables the richness (or otherwise) of the oil province in question to be assessed.
THE HYDROCARBON GEOLOGY OF SOUTHERN OFFSHORE MALTA AND SURROUNDING REGIONS
Authors: Bishop W. F. , Debono G. 
Published: December 2007

Studies of more than 10,000 km of geophysical data from an area situated 45 km south of Malta, supported by stratigraphic projections from wells in offshore Sicily, Tunisia and Libya, indicate facies different from the continuous carbonate sequence encountered in wells on the Malta Platform. Geologic structures in the study area range from a broad anticlinal high to complex horst‐and‐graben systems that are mostly of post‐Miocene age. One graben is believed to be an Early Mesozoic rift associated with break‐up of Gondwana, and may contain deep‐water Triassic‐Jurassic strata similar to those of the Ragusa Basin in SE Sicily.Triassic and Jurassic shallow‐water carbonates were penetrated in wells to the north of the study area. These wells also encountered Upper Jurassic — Cretaceous carbonates, which consist mostly of restricted‐shelf dolomites; pelagic limestones are present at one well located in a re‐entrant of the Malta Platform.During Cretaceous time, part of the study area was transitional between platform and basin settings, and the presence of deeper‐water strata, similar to those which provide proved or potential source rocks and seals in Tunisia, is predicted. Shelf‐edge carbonates can provide good reservoirs; rudistid reefs probably developed on bathymetric highs.Based on the temperature gradient in a well near the study area, most of the Cretaceous section, at least in the Mesozoic graben, is capable of peak oil generation. Cretaceous source rocks reached maturity in the SE part of the study area during Miocene times, and elsewhere between the Pliocene and the present day. Restored seismic sections indicate that faults were active and structures developed by the beginning of Tertiary time. Several trap types are present, and the area has the potential to contain major hydrocarbon reserves.
TECTONIC CONTROLS ON THE EVOLUTION OF POROSITY IN THE CRETACEOUS MARDIN GROUP CARBONATES, ADIYAMAN OILFIELDS, SE TURKEY
Authors: Coskun B. 
Published: December 2007

The mid‐Cretaceous Mardin Group carbonates constitute the principal reservoir in a number of oilfields near the city of Adiyaman in SE Turkey (the Adiyaman, G. Adiyaman, Cemberlitas, Cukurtas, Bolukyayla and Karakus oilfields). Porosity development in these carbonates was controlled by two phases of brittle deformation. The first of these accompanied the emplacement of the allochthonous Koçali‐Karadut Complex in the Late Cretaceous (Maastrichtian), which principally influenced the development of porosity in the northern oilfields. Subsequently, movement during the Mio‐Pliocene on the transcurrent Adiyaman fault affected porosity development in the south.The topmost unit of the Mardin Group, the Karababa Formation, consists of argillaceous carbonates, whose permeability and porosity were increased as a result of abundant tectonically‐induced microfractures and stylolites. The underlying Derdere Formation includes porous limestones and dolomites, which are the principal reservoir units in the Adiyaman fields.Porosity versus depth and geothermal gradient versus depth curves indicate that porosity trends are controlled principally by the transcurrent Adiyaman fault and its antithetics. The Koçali‐Karadut thrusts have had less influence on the evolution of porosity in the Mardin Group carbonates in the study area.
SEALING CAPACITY OF THE MERCIA MUDSTONE GROUP IN THE EAST IRISH SEA BASIN: IMPLICATIONS FOR PETROLEUM EXPLORATION
Authors: Seedhouse J. K. , Racey A. 
Published: December 2007

In the East Irish Sea Basin of the UK Continental Shelf, hydrocarbon accumulations in the Triassic Sherwood Sandstone Group (SSG) are sealed by the Triassic Mercia Mudstone Group (MMG). The MMG comprises alternating mud‐ and halite‐dominated intervals. Where halites overlie the SSG (e.g. in the Morecambe and Millom gasfields), seal integrity is excellent; however, where the SSG is overlain by mudstones of the MMG (e.g. in the Douglas and Lennox oilfields), seal integrity is variable and is controlled by the capillary entry pressure of hydrocarbons into the pore network of the mudstones.Mercury porosimetry was used to characterise the pore network of the Mercia Mudstone samples from several localities in the East Irish Sea Basin. This data was used to assess seal quality, and thus to calculate theoretical hydrocarbon column heights supportable for a given seal. It appears that the sealing quality of the MMG mudstones and siltstones varies principally with the nature of the pore‐throat network. Fracture filling and pore‐plugging by bitumen representing an earlier oil charge may also have improved seal integrity by blocking pore throats.
THE MIOCENE KAREEM FORMATION IN THE SOUTHERN GULF OF SUEZ, EGYPT: A REVIEW OF STRATIGRAPHY AND PETROLEUM GEOLOGY
Authors: Salah M. G. , Alsharhan A. S. 
Published: December 2007

The middle Miocene Kareem Formation in the Gulf of Suez is up to 500‐m thick, and is composed of interbedded sandstones, shales and carbonates; minor anhydrites are present in the lower part of the formation. The siliciclastics were deposited in alluvial and submarine fans building out from the rift shoulders, while the carbonates and anhydrites were precipitated in local lagoons as a result of sea‐level fluctuations. The formation is divided into the Rahmi and overlying Shagar Members, and is Langhian to Serravallian in age.Three main sandstone lithologies have been identified (quartz arenites, arkoses and quartz wackes) each of which differ in their content of secondary minerals, cements and matrix types, reflecting their differing depositional settings and diagenetic histories.The sandstones of the Kareem Formation form one of the most prolific reservoir lithologies in the Gulf of Suez oil province, and produce oil and/or gas in almost 30 fields. These sandstones have a good reservoir quality throughout the basin, with gross‐ and net‐pay thicknesses of up to 235 m and 195 m, respectively. The sandstones' porosity varies from 9% to 33%, and permeabilities range from 20 md to 730 md. Reservoir quality depends on the sandstones' shaliness, diagenetic history and degree of compaction.The sandstones still have high exploration potential particularly in the southernmost portion of the Gulf of Suez where they are extensive and thick but where there has been little drilling. Organic‐rich shales within the Kareem Formation constitute potential source rocks for oil and gas, especially in the southernmost part of the Gulf of Suez where the geothermal gradient is high and where, according to previous studies, these sediments are located within the oil‐generation “window ”.
GEOHISTORY MODELLING OF CRATONIC BASINS: A CASE STUDY OF THE ORDOS BASIN, NW CHINA
Authors: Jiaren Ye , Mingde Lu 
Published: December 2007

This paper describes geohistory modelling as applied to the intracratonic Ordos Basin in NW China; corrections for compaction, the restoration of unconformities and the effects of tectonic subsidence are discussed.The thickness of a modelled layer of sediments can be determined at any time in the past by taking account of a correction for compaction. Also, the effects of eroded layers can be restored automatically if various assumptions are made. Regional studies indicate that the amount of tectonic subsidence in the Ordos Basin can be calculated using a flexural isostatic model (i.e. of regional compensation).The geohistory of Well QS2 in the Ordos Basin was determined, as was that of a 650‐km long, east‐west cross‐section in the centre of the basin, using a modelling programme run on a PC. The results indicate that the Ordos Basin (and possibly also other intracratonic basins) have the following characteristics: first, rates of sedimentary accumulation, total basement subsidence and tectonic subsidence were relatively low; secondly, basement subsidence is dominantly controlled by tectonism; thirdly, the location of the depocentre changes over time; and finally, the intensity of erosion varies in different parts of the basin.
THE DISTRIBUTION OF APTIAN SANDSTONES IN THE CENTRAL AND NORTHERN NORTH SEA (UK SECTORS): A LOWSTAND SYSTEMS TRACT “PLAY”
Authors: Crittenden S. , Cole J. M. , Kirk M. J. 
Published: December 2007

This paper discusses the lithostratigraphy, bio stratigraphy and depositional sequence stratigraphy of the sandstones within the late Aptian Sola Formation in the Central and Northern North Sea (UK sector). The genesis and age of these sandstones are discussed and three depositional models are proposed. These sandstones have reservoir potential, and an exploration strategy is discussed in part two of this paper (referred to hereafter as Crittenden et al., in press).We interpret these sandstones to be the product of mass‐flow sedimentary processes initiated by a tectonically‐induced major fall in relative sea‐level during the late Aptian. Sediments, including sands, which accumulated on the shelfal and shelf/slope break areas of the North Sea during the early Aptian relative sea‐level high were subsequently reworked and eroded; together with the products of erosion of the bedrock geology, they were transported down‐slope into deeper‐water basinal depocentres during the late Aptian.
HYDROCARBON SOURCE POTENTIAL AND MATURATION IN EOCENE NEW ZEALAND VITRINITE‐RICH COALS
Authors: Newman J. , Price L. C. , Johnston J. H. 
Published: December 2007

The results of traditional methods of coal characterisation (proximate, specific energy, and ultimate analyses) for 28 Eocene coal samples from the West Coast of New Zealand correspond well with biomarker ratios and Rock‐Eval analyses. Isorank variations in vitrinite fluorescence and reflectance recorded for these samples are closely related to their volatile‐matter content, and therefore indicate that the original vitrinite chemistry is a key controlling factor. By contrast, the mineral‐matter content and the proportion of coal macerals present appear to have had only a minor influence on the coal samples' properties.Our analyses indicate that a number of triterpane biomarker ratios show peak maturities by high volatile bituminous A rank; apparent maturities are then reversed and decline at the higher medium volatile bituminous rank. The Rock‐Eval S1+ S2 yield also maximizes by high volatile bituminous A rank, and then declines; however, this decline is retarded in samples with the most hydrogen‐rich (perhydrous) vitrinites. These Rock‐Eval and biomarker trends, as well as trends in traditional coal analyses, are used to define the rank at which expulsion of gas and oil occurs from the majority of the coals. This expulsion commences at high volatile A bituminous rank, and persists up to the threshold of medium volatile bituminous rank(c. 1.1% Ro ran. or 1.2% Ro max in this sample set), where marked hydrocarbon expulsion from perhydrous vitrinites begins to take place.