bluuebunny/crossref_metadata_2025 huggingface dataset:
FORMATION OF NON‐COMPRESSIONAL SEDIMENTARY BASINS ON CONTINENTAL CRUST: LIMITATIONS ON MODERN MODELS
Authors: Lyatsky H. V.
Published: December 2007

The evolution of non‐compressional sedimentary basins can be modelled in many ways. A number of existing schemes rely on assuming mathematical relationships between such geodynamical parameters as subsidence and heating of a basin and the amount of presumably causative tectonic extension. The usual objective is to determine precisely the geological history of a sedimentary basin, and to predict the unknown parameters.

Models inevitably simplify complex natural systems. Many models of basin formation rely on specific assumptions about the dynamics of the crust (pure‐shear or simple‐shear deformation, the Moho as a passive marker, uniform extension, absence of older weakness zones, certain metamorphic reactions at depth, etc.) and about the structure and geological history of the basin (purely conductive heat transfer, existence of an underlying rift, etc.). Such assumptions cannot always be tested in poorly‐studied regions, and in some cases they contradict the available geological information. For simplification to be valid, the, geological system has to be understood in some detail before model parameters are chosen. Misleading results may be obtained if an inappropriate model is applied, or if its parameters are ill‐constrained.

Many different geodynamical processes may contribute to basin evolution. In the North Sea region, for example, both mantle‐plume activity and mobility of lower‐crustal material are proposed to have occurred in Mesozoic and Cenozoic times. The Jurassic plume may have been influenced in part by ancient lithospheric structure.

The preferred method in basin analysis is the multidisciplinary approach based on a broad range of data, of which quantitative modelling may or may not be a part. In the integrated basin analysis, geological information is used to constrain the interpretation of gravity, magnetic and seismic data, thus revealing the structure of the basin and helping infer its geological history. Combined with geochemical data, these results are a useful guide for hydrocarbons exploration.
THE ORGANIC MATTER IN OIL SHALES FROM THE LOWMEAD BASIN, QUEENSLAND, AUSTRALIA
Authors: Rahman M. , Kinghorn R. R. F. , Gibson P. J.
Published: December 2007

Oil shales contain organic matter from many sources, deposited under a variety of environmental conditions, which influence the potential for their commercial exploitation. Variations in organic matter type within the oil shales of the Lowmead Basin have been identified with reference to an integrated physico‐chemical classification. The pyrolytic yield of the oil shales has been shown to correlate better with this classification than with a purely chemical classification. While the pyrolytic yield, in litres per metric tonne (l/mt), is satisfactory as a commercial assessment of the oil shales, the addition ofTOC data is an additional indicator of the potential quantity and quality of the shale oil.
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”.
THE ROWAN SANDSTONE MEMBER (UPPER JURASSIC TO LOWER CRETACEOUS): STRATIGRAPHIC DEFINITION AND IMPLICATIONS FOR NORTH SEA EXPLORATION
Authors: Wade D.N. , Lawrence D. A. , Riley L.A.
Published: December 2007

The late Volgian to late Ryazanian Rowan Sandstone Member of the Kimmeridge Clay Formation was deposited along the western margin of the South Viking Graben in UK Block 16/12a in response to Late Cimmerian tectonic activity. Initial deposition was within a submarine slope‐apron complex, which evolved in time to a radial basin‐floor submarine fan. Syntectonic activity, eustatic sea‐level changes and pre‐existing basinfloor topography were the major controls on fan morphology and architecture. Coeval submarine‐fan sequences are present in the northen part of Block 16/17 and in Block 15/23 of the Witch Ground Graben, implying that the Fladen Ground Spur continued to be a positive feature throughout the Late Jurassic and into the Early Cretaceous.
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.
SEISMIC‐STRATIGRAPHIC STUDIES OF THE CONTINENTAL SHELF OF SOUTHERN VIETNAM
Authors: Tan Mai Thanh
Published: December 2007

The complex structure of sedimentary basins on the continental shelf of southern Vietnam, and the existence of various kinds of oil and gas traps, has been studied by seismic stratigraphy. Seismic stratigraphy has been used to investigate the sedimentary evolution of these basins: seismic sequences have been delineated, and potential oil and gas traps have been located.
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.
FRACTALS AND THEIR APPLICABILITY IN GEOLOGICAL WIRELINE LOG ANALYSIS
Authors: Pang J. , North C. P.
Published: December 2007

A fractal analysis method (rescaled‐range analysis) was applied to wireline logs through the fluvio‐deltaic Brent Group (Middle Jurassic) in the Dunlin field, northern North Sea, to test the applicability of fractal analysis in geological interpretation of subsurface data. This analysis reveals that the fractal dimensions of gamma‐ray logs range from 1.0025 to 1.1033. A higher fractal dimension may indicate more heterogeneous lithologies or reservoirs. Analysis of the procedures adopted suggests, however, that fractal concepts in wireline log analysis should be treated with caution. Changes in the calculation procedure can cause larger variations in the estimate of the fractal dimension for a single well than is seen between wells. The validity and suitability of fractals in geological wireline log analysis need to be considered carefully.
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.
GEOLOGY OF THE NORTH FALKLAND BASIN
Authors: Richards P. C. , Fannin N. G. T.
Published: December 2007

The North Falkland Basin comprises two main structural elements: a north‐south trending graben, termed the North Falkland Graben; and a set of subsidiary basins to the west of this graben, also controlled by north‐south trending extensional faults, but which have been constrained by NW‐SE oriented, reactivated Palaeozoic thrust faults. The North Falkland Graben can be divided, in its northern part, into western and eastern depocentres, which are separated by a north‐south trending intra‐graben high.

Early syn‐rift, late syn‐rift, early post‐rift and late post‐rift successions have been identified within the North Falkland Graben. The subsidiary grabens to the west probably contain only early syn‐rift deposits overlain by late post‐rift sediments: these basins were possibly uplifted along the shoulder of the main graben during its mainphase of extension in the Late Jurassic to Early Cretaceous.

Although predictions of sediment‐infill type have only been made by regional correlations and seismic facies analysis in these undrilled basins, two major deltaic units of early post‐rift age are confidently inferred to be present in the North Falkland Graben, and to pass laterally into possible anaerobic mudstones of source‐rock quality.

This petroleum system will soon be tested by a number of oil companies sharing production licences for the entire axial area of the North Falkland Graben.
THE STRATIGRAPHY AND HYDROCARBON POTENTIAL OF THE RIPHEAN‐VENDIAN (MIDDLE‐LATE PROTEROZOIC) SUCCESSION ON THE RUSSIAN PLATFORM
Authors: Fedorov D. L.
Published: December 2007

Recent studies of the Riphean‐ Venetian succession of the Russian Platform have indicated that geological factors favourable for the occurrence of hydrocarbons may be present. These factors include substantial thicknesses of sedimentary rocks; the presence of reservoir rocks and seals, together with source rocks containing sapropelic organic matter; and the occurrence of oil shows, indicating that hydrocarbons have been generated. These factors, coupled with a favourable geographic and economic environment, contrast with the low level of exploration in the area.

Following an interval of many years, geological studies in the central parts of the Russian Platform recommenced in the 1990s. A network of seismic lines has been shot, and has provided data on deeply‐buried structures in this area, and also on the nature of the lowermost parts of the sedimentary cover. The latter is represented by Proterozoic (Riphean and Vendian) strata, whose petroleum prospectivity on the Russian Platform may be comparable to that of the Siberian Platform.

Both the Riphean succession, which was deposited in extensive fault‐bound grabens, and the unconformably overlying Vendian, include very thick sandstones and clay stones. Individual units can be traced on seismic records over distances of tens or even hundreds of km. There is evidence that these sedimentary rocks, particularly those of Vendian age, are of shallow‐ and deep‐marine origin. The high content of sapropelic organic matter which has been recorded in individual units, together with the presence of oil shows, indicate that hydrocarbons have been generated within the Proterozoic interval. Both previous studies in this region, and the more recently‐obtained data, have encouraged exploration to be continued, and have led to the identification of specific targets.
RELATIONS BETWEEN DEPTH OF BURIAL, VITRINITE REFLECTANCE AND GEOTHERMAL GRADIENT
Authors: Suggate R. P.
Published: December 2007

In wells where the drilled sequence is now at its maximum temperature, relations between depth and vitrinite reflectance show three segments: an upper segment with a linear gradient from 0.2–0.25% Ro at the surface to 0.6–0.7% Ro; a middle segment in which reflectance increases rapidly to c. 1.0% R; and a lower segment in which the gradient is again linear but reflectance increases more rapidly than in the upper segment. With a linear scale for depth, the inflection represented by the short middle segment tends to be obscured by the adoption by some authors of a log scale for reflectance.

The depth to the inflection systematically increases with decrease in geothermal gradient, allowing the development of a general diagram relating depth, reflectance and geothermal gradient. In wells where erosion is probable either at the present‐day surface or at an unconformity, the general diagram can be used to estimate former maximum depths of burial and paleogeothermal gradients. These estimates, together with the presence of the inflection in the depth/reflectance relation, should be part of the input into modelling of the thermal history of sedimentary basins when reflectance is used in the model. The inflection is the result of the changing chemistry of vitrinite during oil generation, and the contrast between the depth/reflectance gradients above and below the inflection comparably reflects the contrast in vitrinite chemistry.
PETROLEUM GENERATION IN THE UKRAINIAN EXTERNAL CARPATHIANS AND THE ADJACENT FORELAND
Authors: Koltun Yu. , Espitalié J. , Kotarba M. , Roure F. , Ellouz N. , Kosakowski P.
Published: December 2007

Major hydrocarbon accumulations are located in western Ukraine within the Mesozoic‐Cenozoic flysch sequence in the frontal parts of the External Carpathians, and in the adjacent autochthonous foreland. The accumulations occur in three different structural settings: in the Carpathian flysch belt; in the pre‐Neogene foreland autochthon; and in Miocene foredeep molasse. The petroleum potential of organic‐rich rocks belonging to a number of different sedimentary cycles and tectonic units was studied by Rock‐Eval pyrolysis.

Two significant organic‐rich units, both with a basin‐scale distribution, occur within the External Carpathians: (i) a unit comprising the Lower Cretaceous Shypot and Spas Formations; and (ii) the Oligocene‐Lower Miocene Menilite Formation. The Menilite Formation includes the principal source rocks in this area, although Lower Cretaceous source rocks may also have generated hydrocarbons. Thermal maturation of the flysch and consequent petroleum generation resulted mainly from tectonic burial during Miocene overthrusting. In the external parts of the Carpathian Flysch Belt, oil generation in the Menilite Formation begins at a depth of around 4.2 km and ceases at around 6 km. In more internal tectonic units, a “frozen oil kitchen” occurs at shallower depths, indicating an increasing amount of tectonic uplift and erosion.

The autochthonous foreland is part of the SW margin of the East European Platform, and is partially overthrust by the Carpathian orogen. Rocks belonging to several different sedimentary cycles are present here. Pre‐Mesozoic rocks in the foreland are overmature, at least within the central and SE parts of the study area. Petroleum accumulations are therefore most probably confined to the Mesozoic‐Cenozoic sedimentary cover, within which the Middle Jurassic Kokhanivka Formation has the highest generation potential.
STATISTICAL ANALYSIS OF SYN‐RIFT SEDIMENTS: AN EXAMPLE FROM THE SARIR SANDSTONE, MESSLAH FIELD, SIRTE BASIN, LIBYA
Authors: Gras R.
Published: December 2007

The Messiah field, located in Arabian Gulf Oil Concessions 65 and 80 in the SE Sirte Basin, Libya, is a large combined structural‐stratigraphic trap on the flank of the Messiah High. The basement rocks of the Messiah High are onlapped by the Lower Cretaceous Sarir Sandstone, where the pay is trapped. The thickness of the Sarir Sandstone reservoir has been analysed using a statistical approach. Regression of the thickness of the Sarir Sandstone indicates that the unit wedges out against basement. The reservoir geometry developed as a result of syn‐rift tilting of the Basement and truncation at the top of the Sarir Sandstone. Post‐rift deformation of the Messiah field is restricted to subsidence with minor tilting, without significant faulting. The results of the linear regression are relevant to the exploration for similar traps in the area of the Messiah High.
HYDROCARBON POTENTIAL OF THE INTRACRATONIC OGADEN BASIN, SE ETHIOPIA
Authors: Hunegnaw A. , Sage L. , Gonnard R.
Published: December 2007

The intracratonic Ogaden Basin, which covers one‐third of the Democratic Republic of Ethiopia, developed in response to a tri‐radial rift system which was active during Late Palaeozoic to Mesozoic times. Thick Permian to Cretaceous sequences, which principally occur in the SW and central parts of the basin, have proved petroleum potential. Reservoir rocks are mainly Permian to Lower Jurassic sandstones (the Calub and Adigrat Formations), and Callovian limestones (the Upper Hamanlei Formation). Source rocks are organic‐rich Permian, Lower Jurassic and Callovian‐Oxfordian lacustrine and marine shales.

This paper reviews the petroleum geology of the Ogaden Basin and assesses potential exploration targets. Successful exploration can be expected in view of the recent discovery of the Calub gas and gas/condensate field, and the occurrence of significant shows in the centre of the basin together with seeps along the margin.
ABNORMAL ORGANIC‐MATTER MATURATION IN THE YINGGEHAI BASIN, SOUTH CHINA SEA: IMPLICATIONS FOR HYDROCARBON EXPULSION AND FLUID MIGRATION FROM OVERPRESSURED SYSTEMS
Authors: Hao Fang , Li Sitian , Dong Weiliang , Hu Zhongliang , Huang Baojia
Published: December 2007

Three superimposed pressure systems are present in the Yinggehai Basin, South China Sea. A number of commercial, thermogenic gas accumulations have been found in an area in which shale diapirs occur. Because the reservoir intervals are shallow and very young, they must have filled with gas rapidly. The thick (up to 17 km) Tertiary and Quaternary sedimentary succession is dominated by shales, and is not disrupted by major faulting in the study area, a factor which seems to have had an important effect on both hydrocarbon generation and fluid migration.

Organic‐matter maturation in the deepest, most overpressured compartment has been significantly retarded as a result of the combined effects of excess pressure, the presence of large volumes of water, and the retention of generated hydrocarbons. This retardation is indicated by both kerogen‐related parameters (vitrinite reflectance and Rock‐Eval Tmax); and also by parameters based on the analysis of soluble organic matter (such as the C15+ hydrocarbon content, and the concentration of isoprenoid hydrocarbons relative to adjacent normal alkanes).

In contrast to this, organic‐matter maturation in shallow, normally‐pressured strata in the diapiric area has been enhanced by hydrothermal fluid flow, which is clearly not topography‐driven in origin. As a result, the hydrocarbon generation “window” in the basin is considerably wider than could be expected from traditional geochemical modelling.

These two unusual and contrasting anomalies in organic‐matter maturation, together with other lines of evidence, suggest that there was a closed fluid system in the overpressured compartment until shale diapirs developed. The diapirs developed as a result of the intense overpressuring, and their growth was triggered by regional extensional stresses. They served as conduits through which fluids (both water and hydrocarbons) retained in the closed system could rapidly migrate. Fluid migration led to the modification of the thermal regime and the enhancement of organic maturation, as well as the accumulation of commercial volumes of gas in a relatively short time interval.
COMPRESSIVE NEOGENE‐QUATERNARY TECTONICS IN THE HINTERLAND AREA OF THE NORTHERN APENNINES
Authors: Boccaletti M. , Bonini M. , Moratti G. , Sani F.
Published: December 2007

The NW‐SE trending Northern Apennine Mountains consist of a series of allochthonous units which were thrust generally to the NE during Neogene crustal shortening, in the direction of a foreland basin to the east andNE. On the hinterland (internal) side of this fold‐and‐thrust belt, a series of small‐scale sedimentary basins developed from the late Miocene and were deformed at the same time. The late Tortonian‐Pleistocene evolution of the Northern Apennines has previously been considered by most authors in terms of a classical model of a NE‐migrating compressional front, which was followed in time and space by a hinterland extensional regime related to the development of the Tyrrhenian Basin.

This paper presents new structural data from both the external parts of the Northern Apennines and the late Tortonian‐Pleistocene basins located in the internal sector. In the Northern Apennine thrust belt, reactivation and out‐of‐sequence geometries for the thrust faults have been recorded. In the hinterland basins, compressional deformation has been documented and is usually associated with thrust ramps and regional unconformities. The timing of both thrust reactivation and of the major compressional phases affecting the hinterland basins is closely correlated with periods of magmatic quiescence, and with compressional phases detected in the external margin of the Northern Apennines (the Padan‐Adriatic foredeep).

Data presented in this paper indicate that compressional deformation has played a major role in the recent evolution of the Northern Apennines. The mechanism envisaged to explain this tectonic framework takes account of the piggy‐back emplacement of basement thrusts from internal to external sectors, which occurred in post‐Serravallian time. Activity on basement thrusts may have caused reactivation of thrusts in the internal cover sequence, giving rise to out‐of‐sequence geometries and controlling the development and/or deformation of the hinterland basins. This type of structural evolution has resulted in a complex geometry for the thrust sheets, and this must be taken into consideration during re‐interpretation of the structure of the Northern Apennines. It may also have important implications for petroleum exploration.
NEOGENE SEDIMENTATION AND TECTONIC‐EUSTATIC CONTROL OF THE MALAGA BASIN, SOUTH SPAIN
Authors: López‐Garrido A. C. , de Galdeano C. Sanz
Published: December 2007

Cenozoic sediments in the Málaga area range from the lower Miocene or uppermost Oligocene to the Quaternary. Tortonian (late Miocene) ‐ Quaternary sediments correspond to the fill of the Málaga Basin. Older sediments were laid down before the basin had acquired its present‐day structure. A number of important stratigraphic discontinuities are present within the Cenozoic succession.

In the late Oligocene‐early Miocene, sandy sediments and conglomerates assigned to the Alozaina Formation, derived from the basement Malaguide Complex, were deposited in shallow‐marine conditions contemporaneously with deformation in the Internal Zones of the Betic Cordillera. The overlying transgressive Viñuela Formation (late Aquitanian‐early Burdigalian) was deposited in deep‐marine conditions which extended over a somewhat wider area than that occupied by the Málaga Basin. Sedimentation was dominated by classical turbidity currents and high‐density mass flows.

Sediments of middle Miocene age are absent. Marine sedimentation resumed in the Tortonian as a consequence of a eustatic sea‐level rise. There was clear tectonic control on the depositional system as indicated both by the occurrence of coarse‐grained detritic sediments, which impeded the development of a bioclastic (carbonate) shelf, and also by the formation of a prominent unconformity. NW‐SE and NE‐SW trending faults, defining subsiding areas and highs, controlled the pattern of sedimentation. Strike‐slip activity on these faults (right‐ and left‐lateral, respectively) was relatively minor compared to dip‐slip activity; normal faults with throws of up to 1 km are known, and result from approximately east‐west extension.

The Tortonian succession is overlain unconformably by Pliocene marine deposits which were deposited during an abrupt transgression. Post‐Pliocene sedimentation has been largely continental.
QATAR'S OIL AND GASFIELDS: A REVIEW
Authors: Al‐Siddiqi A. , Dawe R. A.
Published: December 2007

In this paper, we review the oil‐ and gasfields located within the State of Qatar, and survey the discovery and development of hydrocarbons in Qatar over the past 60 years. This development history can be divided into two phases — before and after 1990. Until 1990, four producing areas had been identified, one onshore and three offshore. The single onshore field (Dukhan) has three oil‐producing reservoirs, beneath which is a non‐associated gas reservoir. Offshore, the first producing area comprises three oil and associated gasfields (Idd El Shargi, Maydan Mahzam and Bul Hanine); while the second is the super‐giant North gasfield. Qatar also shares with Abu Dhabi the offshore Al‐Bunduq gasfield. Although a number of other areas were explored by seismic survey and drilling, no further commercial oil was declared. Since 1990, however, there has been considerable further exploration around the offshore producing areas, and a number of new fields have been discovered (e.g. Al‐Khalij, Al‐Rayyan and Al‐Shaheen).
INTERPRETATION OF VITRINITE REFLECTANCE PROFILES IN THE CENTRAL IRISH SEA AREA: IMPLICATIONS FOR THE TIMING OF ORGANIC MATURATION
Authors: Corcoran D. , Clayton G.
Published: December 2007

The Central Irish Sea area, from Kish Bank to St. George's Channel and Cardigan Bay, consists of a series of Late Palaeozoic to Cenozoic extensional and transtensional basins which have experienced a multiphase inversion history. Potential hydrocarbon source rocks of Carboniferous and Jurassic ages have been recognised in this area. In the Kish Bank and Central Irish Sea Basins, maturation modelling of these source rocks is hampered by the severely truncated rock record and by the relative paucity of vitrinite throughout much of the preserved post‐Palaeozoic (Triassic) section.

Vitrinite reflectance data from six exploration wells have been used to quantify the peak palaeotemperatures attained by the rocks in this area and to estimate the magnitude of net exhumation at these locations. An apparent palaeogeothermal gradient of ˜26°C/km is recorded by the Jurassic sediments in well 42/21‐1, whereas significantly higher palaeogeothermal gradients of 74–78°C/km are interpreted for the Westphalian/Stephanian sediments in the area. At least two periods of rock exhumation have occurred; during the Late Carboniferous‐Late Permian, and again sometime between the latest Jurassic and early Tertiary. Estimates of net exhumation vary from ˜350 m at well 42/12‐1 to ˜1,900 m at well 42/17–1. Our interpretation suggests that the higher palaeogeothermal gradients recorded by the Westphalian/Stephanian sections reflect elevated heat flows during Stephanian to Early Permian times.