bluuebunny/crossref_metadata_2025 huggingface dataset:
GEOCHEMICAL CHARACTERIZATION AND RELATIONSHIP OF OILS AND SOLID BITUMENS FROM SE TURKEY
Authors: Mueller E. , Philip R. P. , Allen J.
Published: December 2007

Solid bitumens from the Seridhalivein, occurring in the Upper Cretaceous—Palaeocene Germav Formation, and five oils from different oilfields in SE Turkey, were investigated by a variety of organic geochemical methods. Based on biomarker distributions (pristane/phytane, carbon number preference (CPI), Norhopane/hopane, extended hopane distribution, pregnanes/regular steranes), a marine carbonate depositional environment is inferred for the source of these oils. The oils are “early mature‘, as indicated by their ethylcholestane 20S/20S + 20R ratios, and the 17α(H), 21β(H)‐bishomohopane 22S/22S + 22R ratios. Differences in relative abundance of some compounds typical of higher salinities in the depositional environment (docosane, pregnane) suggest different sources of facies variations within a common source. No aromatic sulfur compounds were detected in the oils.

The solid bitumens were characterized by a high abundance of dibenzothiophenes, naphthalenes, phenanthrenes and their alkyl‐substituted homologues in the aromatic fractions, and an abundance of n‐alkanes in the saturate fraction. The high maturity of the solid bitumen (epi‐impsonite, R %equiv. ? 1.2) makes an interpretation on the origin of these substances difficult. An origin due to biodegradation of sulfur‐rich oil is excluded, since the alkane and aromatic fractions do not show signs of a severe microbial degradation. The absence of sulfur compounds in the oil extracts and the pyrolysis products of the asphaltene fraction show genetic differences between the oils and solid bitumens of SE Turkey. Pyrolysis of the asphaltenes from the bitumen extracts and of the unextracted bitumens produced sulfur compounds similar to those found in the aromatic fraction.
QUANTITATIVE MODELLING OF SALT AND SEDIMENT INTERACTIONS: EVOLUTION OF A NORTH LOUISIANA SALT DIAPIR
Authors: Petersen K. , Lerche I.
Published: December 2007

The restoration of sections involving salt structures is complicated, because it is often difficult to understand fully the dynamics of the system. The occurrence of hydrocarbons is often associated with traps in the vicinity of, or directly adjacent to, salt structures; different methods to delineate the combined evolution of salt and sediments have therefore been developed. Because dynamical parameters are rarely known more accurately than within an order of magnitude, intrinsic uncertainties are introduced in any model based on assumptions concerning the dynamical behaviour of salt and sediments.

A quantitative approach is presented here, guided by observed geometries of the salt‐sediment interface and of the bed horizons from seismic and/or well data. This novel procedure considers the salt‐sediment system as composed of geometric shapes that are allowed to vary with time when calculating the salt‐sediment evolution. By letting sedimentary beds move around the developing salt structure, the influence of the uprising salt on the evolving bed geometries above and around the salt is depicted. Because the predicted present‐day bed geometries must also be in accord with applied control criteria (such as the change in salt volume with time, the geometry of the depositional surface with time, and the compaction history), additional constraints are put on the parameters controlling the evolution of the salt shape.

The capability of being able to follow the changing bed geometries with time allows the strain in the sediments through time to be traced. The stresses that generated the deformations in the sediments can then be inferred through application of the theory of elasticity. Furthermore, the combined evolutionary picture may be used to assess thermal “focusing” through time by a highly conductive salt structure, because the salt and bed geometries are known at each instant.

A case history from the North Louisiana Salt Basin shows aspects of different combinations of control criteria on salt‐sediment evolution. Information is thus provided on the importance of evaluating the data and control criteria necessary for constraining the possible evolution histories.

It is suggested that the novel inverse procedure presented here will improve understanding of the combined evolution of salt and sediments, and is therefore of significance in hydrocarbons exploration.
GEOCHEMISTRY, ISOTOPIC COMPOSITION AND ORIGIN OF THE BEDA DOLOMITES, BLOCK NC74F, SW SIRT BASIN, LIBYA
Authors: Garea B. B. , Braithwaite C. J. R.
Published: December 2007

The Middle Palaeocene Beda Formation, penetrated by wells in block NC74F in the SW Sirt Basin, is dominated by lagoonal, intertidal, and supratidal rocks including evaporites originally deposited in a restricted shallow lagoon.

In the area studied, about 60% of the formation has been dolomitized. Dolomite occurs predominantly replacing precursor carbonate mudstones, although pore‐filling cements line moulds and vugs. Replacive crystals are euhedral to subhedral, finely to very finely crystalline, and generally less than 0.03 mm in diameter. They are non‐ferroan, and show a uniform dull‐to‐moderate orange luminescence. Crystals forming cements are coarser, up to 0.35 mm in diameter, and are characteristically baroque.

Geochemical data indicate that the Beda dolomites have high strontium, low iron, and low manganese contents. They are also depleted in 18O, with negative δ18O values averaging ‐3.63% (PDB). The 13C values show a more marine δ13C isotopic signature, with an average δ13C value of +3.33% (PDB).

The petrographic and geochemical characteristics of the Beda dolomites and their association with evaporites supports a model of early, near‐surface, dolomitization resulting from hypersaline brine refluxion.
INFLUENCE OF DEPOSITIONAL ENVIRONMENT ON DIAGENESIS AND RESERVOIR QUALITY: TIRRAWARRA SANDSTONE RESERVOIR, SOUTHERN COOPER BASIN, AUSTRALIA
Authors: Rezaee M. R. , Lemon N. M.
Published: December 2007

Mechanical compaction and quartz cementation are the most important diagenetic controls on the reservoir quality of the Late Carboniferous ‐ Early Permian fluvio‐deltaic Tirrawarra Sandstone in the Cooper Basin of South Australia. The magnitude of these two diagenetic events is controlled by the mineralogical composition of the sandstones.

Assuming that the Tirrawarra Sandstones have a common provenance, the nature of the environments in which these sediments were deposited is the principal factor controlling the composition of the framework grains in the unit. Thus, the percentage of rock fragments decreases, and the relative quartz content increases, from the medial part of a braid‐delta to point‐bar and aeolian environments. The content of ductile rock fragments controls the degree of compaction and the development of quartz overgrowths.
INTEGRATED OUTCROP ANALOGUE STUDIES FOR TRIASSIC ALLUVIAL RESERVOIRS: EXAMPLES FROM SOUTHERN GERMANY
Authors: Aigner T. , Asprion U. , Hornung J. , Junghans W.‐D. , Kostrewa R.
Published: December 2007

Outcrops of Upper Triassic (Keuper) alluvial sandstones in South Germany may provide analogues for recently ‐discovered hydrocarbon reservoirs in the North Sea Triassic. Using an integrated approach, reservoir heterogeneities in the outcropping sandstones may be characterized by means of: (1) sequence stratigraphy (including facies and architectural element analysis aided by georadar profiling, and an identification of the hierarchy of sedimentary cycles); and (2) petrophysics (gamma‐ray logging, and porosity and permeability measurements). Primary depositional facies and the stacking patterns of different fluvial cycles within larger‐scale sedimentary cycles play a dominant role in determining the fluid‐flow behaviour of the sandstones.
GEOTHERMAL INVESTIGATIONS IN THE DEAD SEA RIFT ZONE, ISRAEL: IMPLICATIONS FOR PETROLEUM GEOLOGY
Authors: Eppelbaum L. , Modelevsky M. , Pilchin A.
Published: December 2007

Thermal surveys of the Dead Sea — Arava Valley area have been conducted in order to investigate the present‐day geothermal characteristics of the sedimentary cover. Horizontal geothermal gradients have been assessed, and heat‐absorbing and heat‐radiating intervals have been identified. The second temperature versus depth derivative is used as an index of the thermal state of the sedimentary cover. Average vertical gradients are low, and vary between 20° and 30° C/km. Horizontal geothermal gradients in the study area do not usually exceed 1° C/km, although they are higher within the major Dead Sea graben fault zone. Horizontal gradients may cause excess pressures, which influence the direction of fluid flow within the sedimentary cover. Basaltic intrusions may also cause the migration of overheated waters. Analytical methods based on those applied in magnetic prospecting are used for the quantitative interpretation of temperature anomalies, and these methods may contribute to the location of faults and salt domes.
AN EVALUATION OF THE HYDROCARBON POTENTIAL OF THE SEDIMENTARY BASINS OF LIBYA
Authors: Gumati Y. D. , Kanes W. H. , Schamel S.
Published: December 2007

Distinctive structural and stratigraphic styles, together with the timely development of source rocks, reservoirs and seals, have produced in Libya the richest hydrocarbon habitats on the African continent. These habitats are located in the Sirte Basin (29,000 MM brl of proved reserves), and Ghadames Basins and Pelagian Shelf (3,000 MM brls of proved reserves). Significant oil discoveries have also been made in the Murzuk Basin (1,500 MM brl of proved reserves) and the offshore Cyrenaica Platform.

Four major potential source rocks have been identified in Libya: the Sirte shales (Campanian), the Hagfa shales (Palaeocene), the Tanezzuft shales (Silurian), and shales of Devonian age. The Sirte and Hagfa shales have generated hydrocarbons for most of the prolific reservoirs in the Sirte Basin. The Sirte shales supply hydrocarbons to clastic reservoirs of Cambro‐Ordovician age (the Gargaf Group) and Lower Cretaceous age (Nubian sandstones), and also to Upper Cretaceous carbonates. The Hagfa shales source most of the Tertiary reservoirs in the Sirte Basin and possibly the Cyrenaica Platform. Silurian (Tanezzuft) and Devonian shales supply hydrocarbons to reservoirs of Palaeozoic and Mesozoic ages, particularly Silurian and Devonian sandstones in the Ghadames and Murzuk Basins, and the Cyrenaica Platform.

The principal seals in the Sirte Basin are Late Cretaceous and Tertiary shales and anhydrites. Palaeozoic and Mesozoic shales, impermeable carbonates, and occasional anhydrites form the major seals in the Ghadames and Murzuk Basins and the Cyrenaica Platform.
NORTH JIANGSU BASIN, EASTERN CHINA: ACCUMULATION OF IMMATURE OILS AND DIAGENESIS OF PALAEOGENE RESERVOIR ROCKS
Authors: Qiang Jin , Weifeng Wang , Huaimin Xu , Shaochun Yang , Ji Qian
Published: December 2007

Large quantities of immature and low‐maturity oil have been discovered in the North Jiangsu Basin, East China. Intense tectonic activity and the differential accumulation of immature oils during the Palaeogene have resulted in reservoir rocks which have variable sedimentary and diagenetic characteristics. Studies of oil geochemistry and reservoir diagenesis suggest that oil generation and accumulation took place early in the basin's history (i.e. during early diagenesis), significantly inhibiting later modification of the reservoir rocks. There has been no large‐scale tectonic activity since the oil pools formed, and the reservoirs' petrophysical properties and pore construction therefore reflect early diagenesis. Diagenetic modification of the reservoir rocks was more intense below the oil‐water interface where oil did not accumulate. Alteration in these rocks included calcite cementation, the formation of quartz overgrowths, and the development of pressure solution.
GEOLOGY AND PETROLEUM POTENTIAL OF THE KHORAT PLATEAU BASIN IN THE VIENTIANE AREA OF LAO P.D.R.
Authors: Smith P. F. Lovatt , Stokes R.B.
Published: December 2007

The Vientiane area of southern‐central Lao Peoples' Democratic Republic (Laos) includes an extension of the Khorat Plateau Basin, which covers most of neighbouring NE Thailand. This basin contains one producing gasfield and several other gas discoveries. The Vientiane area is in the initial stages of petroleum exploration, and no drilling has yet occurred.

With the aid of new seismic data, the structure and stratigraphy of the Vientiane area are described in relation to the region's tectonic history. Some aspects of this history are still poorly understood. We suggest that the age of the regional base‐Khorat unconformity is Late Jurassic instead of Late Triassic as most previous studies have assumed. Recent studies have also shown that the structural inversion of the Khorat Group began in the mid‐Cretaceous and not in the Tertiary.

With reference to published information from petroleum exploration in NE Thailand, new data from Laos are interpreted as showing that the Vientiane area has encouraging petroleum potential. Exploration risk, which is associated with the presence and reservoir quality of the Permian carbonates which form the primary target, is judged to be lowest in traps containing Permian palaeo‐highs.
MID‐CRETACEOUS RUDIST‐BEARING CARBONATES OF THE MISHRIF FORMATION: AN IMPORTANT RESERVOIR SEQUENCE IN THE MESOPOTAMIAN BASIN, IRAQ
Authors: Aqrawi A. A. M. , Thehni G. A. , Sherwani G. H. , Kareem B. M. A.
Published: December 2007

This paper reports on the sedimentology and stratigraphy of the mid‐Cretaceous Mishrif Formation, one of the principal carbonate reservoirs in Central and Southern Iraq. The Cenomanian Mahilban, Maotsi and Fahad Carbonate Formations of Central Iraq are the lateral chronostratigraphical equivalents of the Mishrif and underlying Rumaila Formations of Southern Iraq. Together, these units represent a single mid‐Cretaceous carbonate succession in the Mesopotamian Basin.

The Mishrif Formation in Central Iraq reflects the continuous deposition of shallow‐shelf carbonates; periodic rises in sea level led to episodes of deeper‐water sedimentation, during which the outer‐shelf and basinal deposits of the Rumaila Formation were laid down. A ramped platform was the principal depositional setting for the entire Cenomanianearly Turonian carbonate succession.

The best reservoir conditions in the Mishrif Formation occur in rudist‐bearing facies, such as rudstones and rudistid packstone/grainstones. Reservoir units are characterised by porosities of >20% and by permeabilities of 100 mD to 1 Darcy. Other carbonate facies, such as pelagic mudstone/ wackestones, bioclastic wackestones and peloidal packstones, are less significant as reservoir rocks. All the carbonates were affected by a range of diagenetic processes, among which dissolution and dolomitization led to the formation of secondary porosity; porosity was reduced by compaction, stylolitization, micritisation, neomorphism and cementation.

The Mishrif Formation is divisible by a prominent unconformity into two large‐scale regressive sequences, which are particularly distinguishable in the east of the Mesopotamian Basin. Multiple reservoir units are present in both sequences. The west of the basin is dominated by the lower sequence, which has relatively few reservoir intervals. The shallow‐water reservoir units in the east of the basin are thick, reflecting relatively high subsidence rates throughout the Cenomanian (e.g in the Amara oilfield and nearby areas). Subsidence rates in the western side of the basin were lower, and reservoir units are thinner and more limited. The Mishrif Formation carbonates wedge‐out in the western and SW deserts of Iraq.
AN INTRODUCTION TO THE PETROLEUM POTENTIAL OF NIGER
Authors: Zanguina M. , Bruneton A. , Gonnard R.
Published: December 2007

The Republic of Niger can be divided into two sedimentary and tectonic provinces: a Palaeozoic platform‐type province in the north and west, and a series of Mesozoic grabens in the east.

Thick Palaeozoic successions are present in the NW (in the Tamesna‐Talak area of the Iullemeden Basin), and the NE (in the Djado Basin). The petroleum potential of these areas is not yet proven. By analogy with the Algerian Illizi Basin and the Libyan Murzuk Basin, Silurian source rocks together with Ordovician, Devonian and Carboniferous sandstone reservoir units may occur here.

In East Niger, a complex rift system, whose sedimentary fill ranges in age from Late Jurassic to Early Tertiary, has proven petroleum potential. Reservoir rocks are mainly Cretaceous to Eocene sandstones, sourced by Cretaceous marine shales and Oligocene lacustrine shales.

This paper reviews the petroleum geology of Niger, and assesses potential exploration targets. Commercial developments can shortly be expected following the construction of an export pipeline from Chad to Cameroon, and the resumption of drilling activity in the Agadem and Djado Basins.
AN ASSESSMENT OF IRISH OFFSHORE BASINS AND PETROLEUM PLAYS
Authors: Shannon P. M. , Naylor D.
Published: December 2007

The Irish offshore contains a large number of Late Palaeozoic to Cenozoic sedimentary basins, most of which are only lightly explored. These are grouped into the Irish Sea, Celtic Sea and Atlantic Margin basins. The basins developed in response to multi‐phase rifting which preceded the development of the North Atlantic Ocean. The major rift phases occurred during the Permo‐Triassic, Late Jurassic and Early Cretaceous. The Irish Sea basins contain a preserved succession of predominantly Permo‐Triassic and Early Jurassic age, with younger strata largely absent due to Cretaceous and Tertiary inversion. The Celtic Sea basins have a thick series of Triassic to Cretaceous strata, overlain by a generally thin Tertiary succession. The Atlantic Margin basins have a variable sedimentary thickness, with the larger basins characterized by a thick Tertiary succession. Two gasfields are currently in production in the North Celtic Sea Basin, while a number of undeveloped oil and gas accumulations have been discovered in both the North Celtic Sea Basin, and the Porcupine Basin on the Atlantic margin. A wide range of reservoir and source‐rock horizons have been encountered in the various basins. Most of the exploration to date has concentrated upon structural traps, but the recent resurgence of exploration interest is centred mostly upon a variety of stratigraphic traps, especially at Cretaceous and Tertiary levels, similar to successful plays further along strike in the UK and Norwegian sectors of the Atlantic Margin.
THE DISTRIBUTION OF APTIAN SANDSTONES IN THE CENTRAL AND NORTHERN NORTH SEA (UK SECTOR) ‐ A LOWSTAND SYSTEMS TRACT PLAY
Authors: Crittenden S. , Cole J. M. , Kirk M. J.
Published: December 2007

In this paper, we discuss the distribution in the Central and Northern North Sea (UK sector) of the Late Aptian sandstones of reservoir potential which are assigned to members of the Sola Formation. An exploration strategy for these sandstones is proposed, based on sequence‐stratigraphic and palaeogeographic models derived from the examination of numerous wells. The sandstones were deposited by mass‐flow processes as a consequence of a major, tectonically‐induced or enhanced, Late Aptian fall in relative sea‐level. The distribution of these lowstand sandstones, and the facies developed, was controlled by the structure and palaeogeography that existed in the study area both before and after this sea‐level fall.

The pattern of faulting in the study area during Sola Formation deposition is related to Jurassic and older tectonism, which is associated with the development of the proto‐North Atlantic and the thermal subsidence of the North Sea rift system. Faults controlled the areas of sandstone provenance, and also determined the routes by which reworked sediments were transported into depocentres.

We have mapped the distribution of these sandstones using both well and seismic data. Maps of fault patterns, basinal and high areas, and facies distributions have been generated for the top‐ Valhall Formation level (i. e. immediately beneath the Sola Formation), and also for the Sola Formation itself. These maps were used to model the distribution of Aptian lowstand sandstones and prospects in the UK Central and Northern North Sea. This modelling exercise is of relevance for the identification of lowstand sandstones with reservoir potential elsewhere on the NE Atlantic margin.
OXYGENIC KEROGENIZATION OF ASPHALTENES FROM THE DEAD SEA BASIN (ISRAEL)
Authors: Premović P. I. , Zlatković S. B. , Premović M. P. , Tonsa I. R.
Published: December 2007

A kerogen‐like material was generated during a laboratory heating experiment with asphaltenes in the presence of O2. The asphaltenes had been extracted from a floating block of Dead Sea asphalt, and heated at 100 ‐ 200 d̀C for 1–12 days. This oxygenic kerogenization reaction follows first‐order kinetics. The half‐life (t1/2) of the asphaltenes (i.e. the time in which 50% of the asphaltenes had been converted to artificial kerogen) varied from 2,300 days at Od̀C, to 2 days at 100 d̀C. Similar results were obtained with asphaltenes which had been extracted from a number of bitumen‐bearing rocks in the Dead Sea area (from the Amiaz, Ein Boqeq, Nebi Mussa and Ef'e boreholes), and also from sandstones from the Heimar and IPRG boreholes which were impregnated with heavy or asphaltic crudes.

These and other results suggest that low‐temperature (≤100d̀C) oxygenic kerogenization of Dead Sea asphaltenes (with or without the mediation of meteoric waters) may be a pathway for the formation of kerogen. Asphaltenes extracted from other bituminous rocks — the La Luna limestone (U. Cretaceous, Venezuela); the Serpiano marl (M. Triassic, Switzerland); the Messel shale (Tertiary, Germany); and the Aleksinac shale (Tertiary, Yugoslavia) — underwent laboratory kerogenization in a similar fashion to the Dead Sea materials. This suggests that oxygenic kerogenization may be widespread in porous and fractured, bitumen‐bearing rocks.
OCEANIC METHANE HYDRATE: THE CHARACTER OF THE BLAKE RIDGE HYDRATE STABILITY ZONE, AND THE POTENTIAL FOR METHANE EXTRACTION
Authors: Max M. D. , Dillon W. P.
Published: December 2007

Oceanic methane hydrates are mineral deposits formed from a crystalline “ice” of methane and water in sea‐floor sediments (buried to less than about 1 km) in water depths greater than about 500 m; economic hydrate deposits are probably restricted to water depths of between 1.5 km and 4 km. Gas hydrates increase a sediment's strength both by “freezing” the sediment and by filling the pore spaces in a manner similar to water‐ice in permafrost. Concentrated hydrate deposits may be underlain by significant volumes of methane gas, and these localities are the most favourable sites for methane gas extraction operations. Seismic reflection records indicate that trapped gas may blow‐out naturally, causing large‐scale seafloor collapse.

In this paper, we consider both the physical properties and the structural integrity of the hydrate stability zone and the associated free gas deposits, with special reference to the Blake Ridge area, SE US offshore, in order to help establish a suitable framework for the safe, efficient, and economic recovery of methane from oceanic gas hydrates. We also consider the potential effects of the extraction of methane from hydrate (such as induced sea‐floor faulting, gas venting, and gas‐pocket collapse). We assess the ambient pressure effect on the production of methane by hydrate dissociation, and attempt to predict the likelihood of spontaneous gas flow in a production situation.
NEW DEVELOPMENTS IN THE PRE‐RIFT PROSPECTIVITY OF THE ERITREAN RED SEA
Authors: Bunter M. A. G. , Debretsion T. , Woldegiorgis L.
Published: December 2007

Northern, central and southern Africa is covered by great thicknesses of Upper Palaeozoic and Mesozoic fluvio‐deltaic and marine siliciclastics, which include important source rocks, reservoirs and seals. In the Eritrean Red Sea, the importance of these rocks has not yet been properly recognised.

The Red Sea initially formed by rifting of the Afro‐Arabian continent in Oligo‐Miocene times. Palaeozoic and Mesozoic rocks were downthrown into the resultant Gulf of Suez/ Red Sea Graben and were rapidly buried by syn‐ and post‐rift sediments. In the Eritrean Red Sea area, pre‐rift rocks are now only exposed in the Danakil Alps at the Straits of Bab el Mandab, on the Eritrean Plateau, in the coastal lowlands north of Massawa, and in isolated outcrops in Ethiopia.

The authors believe that an as‐yet untested pre‐rift “play” is to be found in the Eritrean Red Sea contiguous with the Danakil Alps. In addition, syn‐ and post‐rift “plays” cannot be ruled out in this area. The combination of newly‐mappedpre‐salt structures, containing Jurassic source rocks and Jurassic and Cretaceous reservoir sandstones and carbonates overlain by Tertiary elastics and/or salt, embodies the primary hydrocarbon entrapment model in the area. Secondary hydrocarbon “plays” centre on deformed Miocene siliciclastic seauences in proximity to salt diapirs.
DIAGENESIS AND RESERVOIR DEVELOPMENT OF SANDSTONES IN THE TRIASSIC REWAN GROUP, BOWEN BASIN, AUSTRALIA
Authors: Bashari A.
Published: December 2007

The non‐marine Lower Triassic Rewan Group in the Bowen Basin, Australia, is mainly composed of lithic arenites containing high proportions of volcanic rock fragments. Sublitharenites are also present. The arenites are cemented by abundant authigenic quartz, carbonates and clay minerals. Three separate lithostratigraphic intervals can be identified: a conglomeratic unit at the base; a sequence dominated by lithic arenites in the middle; and a section dominated by sub‐litharenites at the top. Petrographically, the sandstones can be divided into a facies whose quartz content is greater than 75% on a QFR diagram; and a labile or lithic facies which contains less than 75% quartz. There is a progressive change in clay mineral assemblage from one petrofacies to the other.

The volcanic fragments have undergone rapid diagenetic alteration under low temperatures andpressures. Alteration started with pore‐space reduction by compaction and was followed by pore‐fill cementation. Solution at depth, however, has caused secondary porosity to develop. Differences in clay mineralogy and in the overall proportion of clay within the Rewan Group can be explained by differences in permeability and fluid flux, with high permeabilities occurring in the conglomeratic and sublitharenitic intervals. Porosity is best developed where early silicification has enhanced grain support and has minimised the effects of later compaction, and where clay minerals have been leached.
PETROLEUM RESERVES: NEW DEFINITIONS BY THE SOCIETY OF PETROLEUM ENGINEERS AND THE WORLD PETROLEUM CONGRESS
Authors: Martínez A. R. , McMichael C. L.
Published: December 2007

The search for a simple, universal classification of petroleum reserves has become a sort of mythical quest whose importance grew while the international petroleum industry developed. Reserves have always been a fundamental element of the industry, and the need for a uniform set of definitions has been a continuum not only for the operators but also for all the public and private organizations which work in related areas.

The definitions recently adopted by the Society of Petroleum Engineers and the World Petroleum Congresses represent a step forward in this essential issue. This paper summarises the current definitions, and introduces two significant changes: the use of probabilistic methods in reserves assessment; and the provision of an “averaging” period in the determination of applicable economic conditions. The latter seems particularly appropriate for a year such as 1998, considering the recent fall in oil prices.
THE GEOLOGY OF NATURAL GAS IN THE PEOPLE'S REPUBLIC OF CHINA: A REVIEW
Authors: Jianyi Hu , Lirong Dou , Qiming Li
Published: December 2007

Commercial accumulations of natural gas in China have been generated by marine carbonates in Proterozoic and Palaeozoic cratonic basins, and by lacustrine shales and coal measures in Mesozoic‐Cenozoic continental basins. These accumulations occur in reservoir rocks of various types. The Chinese natural gas industry has developed rapidly over the past two decades, and proved reserves of gas have increased accordingly. To date, 138 gasfields and 110 gasfields with oil‐rims have been found in China.

Based on its geological and geochemical characteristics, natural gas can be divided into three principal types: (i) biogenic (bacterial and biode graded) gas; (ii) wet associated gas, sourced from either sapropelic or humic organic matter; and (iii) dry thermal gas, likewise sourced from sapropelic or humic OM.

Each type of gas has its own characteristics in terms of generation, migration, accumulation and distribution. Bacterial gas is concentrated in Quaternary strata (for example, in the Qaidam Basin of NW China); biodegraded gas occurs in shallow strata in the eastern oil provinces, often in association with tar mats. Associated gas occurs mainly in Mesozoic‐Cenozoic continental basins, whereas dry thermal gas is generally confined to Proterozoic and Palaeozoic cratonic basins, especially in West China. Proterozoic and Palaeozoic gas resources make up about one‐half of the Chinese total, and are set to become a major exploration target in the future.
THE GEOLOGY AND HYDROCARBON POTENTIAL OF THE PEEL AND SOLWAY BASINS, EAST IRISH SEA
Authors: Newman P. J.
Published: December 2007

Data from recent exploration campaigns by Elf Exploration UK plc and partners in the Peel and Solway Basins (East Irish Sea) have provided significant new information on the geology and hydrocarbon potential of these previously unexplored areas. In this paper, I present a regional geological framework for the basins based on outcrop studies, potential field data and regional seismic lines. The dominant NE‐SW and NW‐SE structural trends are probably inherited from the Caledonian Orogeny and show evidence of repeated reactivation. Seismic interpretation indicates that the NE‐SW trending faults were important in controlling Early Carboniferous basin development, and that transpressional movement along these faults in response to N‐S compression led to basin inversion during the Variscan Orogeny. New well data indicate that both the Peel and Solway Basins were subjected to major erosion at this time, causing the entire Upper Carboniferous stratigraphy to be removed. Preserved Dinantian facies comprise shallow‐marine sandstones, shales and carbonates in the NE, passing into shallow‐water, high energy carbonates in the SW. A change to E‐W extension during the Permo‐Triassic led to renewed extensional motion on the underlying Caledonian faults, and to the creation of a new system of faults oriented N‐S. The Permian and Triassic sections present in the wells in the Peel and Solway Basins are very similar to those in the numerous exploration wells in the East Irish Sea Basin to the SE. Liassic rocks are partly preserved in both the Peel and Solway Basins. The intra‐basinal highs which separate the basins in this region are thought to have been initiated during Late Cimmerian uplift, and to have been enhanced by Laramide and Alpine phases of uplift. Laramide uplift was also accompanied by the emplacement of WNW‐ESE trending dykes.

Regional stratigraphic information has been combined with apatite fission‐track data and vitrinite reflectance data to constrain these phases of uplift. These data suggest that at the present day, the Peel and Solway Basins are isolated remnants of a previously more extensive cover of Mesozoic rocks. The three exploration wells drilled in the Peel and Solway Basins by Elf Exploration UK plc tested valid Triassic fault‐block traps, but failed to encounter any significant hydrocarbon shows. Variable, but generally good quality reservoirs exist at the top of the Sherwood Sandstone Group. The main control on reservoir quality is the primary sedimentological character of the sandstones, with cementation and compaction locally reducing quality. Over most of the area, evaporites and shales in the Mercia Mudstone Group form a viable top and lateral seal. The main factor preventing development of a viable petroleum system appears to be the absence of significant Carboniferous source rocks.
COAL‐GENERATED OIL: SOURCE ROCK EVALUATION AND PETROLEUM GEOCHEMISTRY OF THE LULITA OILFIELD, DANISH NORTH SEA
Authors: Petersen H. I. , Andsbjerg J. , Bojesen‐Koefoed J. A. , Nytoft H. P.
Published: December 2007

Controversy still exists as to whether coals can source commercial accumulations of oil. The Harald and Lulita fields, Danish North Sea, are excellent examples of coal‐sourced petroleum accumulations, the coals being assigned to the Middle Jurassic Bryne Formation. Although the same source rock is present at both fields, Lulita primarily contains waxy crude oil in contrast to Harald which contains large quantities of gas together with secondary oil/condensate. A compositional study of the coal seams at well Lulita‐IXc (Lulita field) was therefore undertaken in order to investigate the generation there of liquid petroleum.

Lulita‐IXc encountered six coal seams (0.15–0.25 m thick) which are associated with reservoir sandstones. The coals have a complex petrography dominated by vitrinite, with prominent proportions of inertinite and only small amounts of liptinite. Peat formation occurred in coastal‐plain mires; the coal seams at Lulita‐IXc represent the waterlogged, oxygen‐deficient and occasionally marine‐influenced coastal reaches of these mires. Vitrinite reflectance values (mostly 0.82–0.84%Ro) indicate that the coals are thermally mature. Most of the coal samples have Rock‐Eval Hydrogen Index values above 220 mg HC/g TOC, although the HI values may be increased due to the presence of extractable organic matter. Oil‐source rock correlations indicate that there are similarities between crude oil samples (and an oil‐stained sandstone extract) from the Lulita field, and extracts from the Bryne Formation coals immediately associated with the reservoir sandstones; from this, we infer that the coals have generated the crude oil at Lulita. The presence in the coals of oil‐droplets, exsudatinite and micrinite is further evidence that they have generated liquid petroleum. The generation of aliphatic‐rich crude oil by the coals in the Lulita field area, and the coals' high expulsion efficiency, may have been facilitated by a combination of the coals'favourable petrographic composition and their capability to generate long‐chain n‐alkanes (C22+). Moreover; all the Lulita coal seams are relatively thin and this may have facilitated oil saturation to the expulsion threshold. We suggest that during further maturation of the coals, 19–22% of the organic carbon will potentially participate in petroleum‐generation, of which about 42–53% will be in the gas‐range and 47–58% in the oil‐range.
FAULT‐RELATED SOLUTION CLEAVAGE IN EXPOSED CARBONATE RESERVOIR ROCKS IN THE SOUTHERN APENNINES, ITALY
Authors: Billi A. , Salvini F.
Published: December 2007

The deformation associated with a number of kilometre‐scale strike‐slip fault zones which cut through outcropping carbonate rocks in the Southern Apennines was investigated at regional and outcrop scales. These faults trend roughly east‐west and were studied at the Gargano Promontory on the Adriatic Coast (in the Apulian foreland) and in the Matese Mountains, about 120 km to the west (within the Apenninic fold‐and‐thrust belt). The fault zones are 200–300 m wide and typically comprise a core surrounded by a damage zone. Within fault cores, fault rocks (gouges and cataclasites) typically occur along master slip planes; in damage zones, secondary slip planes and solution cleavage are the most important planar discontinuities. The protolith carbonates surrounding the fault zone at Gargano show little deformation, but they are fractured in the Matese Mountains as a result of an earlier thrust phase.

Cleavage surfaces in the damage zone of the studied faults are interpreted to be fault‐propagation structures. Our field data indicate that cleavage‐fault intersection lines are parallel to the normals of fault slip‐vectors. The angle between a fault plane and the associated cleavage was found to be fairly constant (c. 40“) at different scales of observation. Finally, the spacing of the solution cleavage surfaces appeared in general to be regular (with a mean of about 22 mm), although it was found to decrease slightly near a fault plane. These results are intended to provide a basis for predicting the architecture of fault zones in buried carbonate reservoirs using seismic reflection and borehole data.
THE HYDROCARBON PROSPECTIVITY OF LOWER OLIGOCENE DEPOSITS IN THE MARAGH TROUGH, SE SIRT BASIN, LIBYA
Authors: Gruenwald R.
Published: December 2007

The main phase of rifting the Sirt Basin (Libya) had ceased by the mid‐Cretaceous but Alpine‐related tectonic pulses in the late Eocene resulted in northward tilting of the basin. In the Maragh Trough (SE Sirt basin), a regional unconformity consequently separates Eocene carbonates from the overlying Oligocene succession. The unconformity marks a change from Eocene carbonate sedimentation to more mixed shallow‐marine deposition in the Oligocene. A regional transgression re‐established fully marine conditions in the Miocene.

Deeply‐buried (Triassic) source rocks in the Maragh Trough reached peak oil generation during the Oligocene. Two potential reservoir intervals have been identified: upper Eocene rudstones of the Augila Formation, and unconformably‐overlying sandstones of the Lower Oligocene Arida Formation. Mid‐Oligocene shales provide a regional seal.

Facies distributions and reservoir properties are related to rift‐related structural highs. Despite the absence of a nearby source kitchen, Upper Eocene carbonates have been found to be oil‐bearing in the Maragh Trough at wells D1‐ and F1–96. This indicates that hydrocarbons have migrated along graben‐bounding faults from deeply‐buried source rocks to platform and sub‐platform areas. Traps are of combined structural and stratigraphic type.
REEFS IN THE BASINAL FACIES OF THE ZECHSTEIN LIMESTONE (UPPER PERMIAN) OF WESTERN POLAND: A NEW GAS PLAY
Authors: Dyjaczynski K. , Gorski M. , Mamczur S. , Peryt T. M. , Al‐Saad H.
Published: December 2007

Zechstein (Upper Permian) reefs have long been known to occur along the margins of the Polish Zechstein Basin where they host important gas reserves. During the last decade, reefal build‐ups have also been found in the centre of the basin on pre‐Zechstein highs such as the Wolsztyn Ridge in Western Poland. Here, early 2D seismic and subsequent more detailed 3D seismic studies and integrated geophysical and geological interpretations have led to a number of major gas discoveries. The reef complexes in the Koscian– Wielichowo region are thought to have recoverable gas reserves of more than 32B cu m.

The basin‐centre reefs have been identified on the basis of palaeogeographic analysis and from the seismo‐acoustic properties of the Zechstein Limestone of which they are composed. 3D seismic profiles show that the reefs have irregular shapes in map view. Drilling results indicate that their thickness may exceed 80m, but characteristically their thickness decreases sharply at their margins corresponding to a facies change.

In the Wolsztyn Ridge area, the Zechstein Limestone can be divided into five lithological units which are capped by the Werra Anhydrite. Four of these units reflect deposition in subaqueous environments whereas the uppermost unit originated in a very shallow‐water or temporarily subaerial setting. Typical “ecological” bryozoan‐stromatolitic reefs occur in the middle and upper (but not the uppermost) parts of the Zechstein Limestone, while the lower parts are dominated by bioclastic packstones and grains tones. Average reservoir porosity is 10–20%. The permeability varies significantly (0–400 mD) but values of a few tens of mD are common.

The occurrence of intraclastic breccia in many boreholes suggests that the reefs may have developed on local palaeoslopes which are generally of tectonic origin. Blocks of contemporaneously lithifiedZechstein Limestone as well as steeply‐dipping laminar sheets are common in the reefs of the Wolsztyn Ridge and have also previously been recorded in the English Zechstein. Palaeoslopes elsewhere in the Wolsztyn Ridge and possibly also in other parts of the Variscan externides may host similar reefal build‐ups which could be of exploration potential.
WELL LOG CALIBRATION OF KOHONEN‐CLASSIFIED SEISMIC ATTRIBUTES USING BAYESIAN LOGIC
Authors: Taner M. T. , Berge T. , Walls J. D. , Smith M. , Taylor G. , Dumas D. , Carr M. B.
Published: December 2007

We present a new method for calibrating a classified 3D seismic volume. The classification process employs a Kohonen self‐organizing map, a type of unsupervised artificial neural network; the subsequent calibration is performed using one or more suites of well logs. Kohonen self‐organizing maps and other unsupervised clustering methods generate classes of data based on the identification of various discriminating features. These methods seek an organization in a dataset and form relational organized clusters. However, these clusters may or may not have any physical analogues in the real world. In order to relate them to the real world, we must develop a calibration method that not only defines the relationship between the clusters and real physical properties, but also provides an estimate of the validity of these relationships. With the development of this relationship, the whole dataset can then be calibrated.

The clustering step reduces the multi‐dimensional data into logically smaller groups. Each original data point defined by multiple attributes is reduced to a one‐ or two‐dimensional relational group. This establishes some logical clustering and reduces the complexity of the classification problem. Furthermore, calibration should be more successful since it will have to consider less variability in the data.

In this paper, we present a simple calibration method that employs Bayesian logic to provide the relationship between cluster centres and the real world. The output will give the most probable calibration between each self‐organized map node and wellbore‐measured parameters such as lithology, porosity and fluid saturation. The second part of the output comprises the calibration probability.

The method is described in detail, and a case study is briefly presented using data acquired in the Orange River Basin, South Africa. The method shows promise as an alternative to current techniques for integrating seismic and log data during reservoir characterization.
FUZZY PARTITIONING SYSTEMS FOR ELECTROFACIES CLASSIFICATION: A CASE STUDY FROM THE MARACAIBO BASIN
Authors: Finol J. J. , Guo Y. K. , Jing X. D.
Published: December 2007

This paper describes a method of advanced data processing for the inverse problem of lithofacies prediction from well logs using fuzzy partitioning systems. A fuzzy partitioning system consists of a set of fuzzy If‐Then rules of the form “If bulk density (pb) is low and neutron porosity (øCNL) is high Then classify pattern x=(pbøCNL) as Fades Fi”. In this paper, we introduce an intelligent method for the problem of fuzzy rule generation based on fuzzy clustering. Fuzzy clustering is used to detect structures in the multidimensional space of the available well log readings. Each cluster detected is a potential fuzzy classification rule. By applying fuzzy validity measures an optimum number of fuzzy clusters can be found. Using this approach, the number of rules, the antecedent membership functions and other parameters that constitute the fuzzy partitioning system are derived in an automatic way.

The aim is to find a minimum set of fuzzy classification rules that can correctly classify all log training patterns. Unlike traditional methods of predicting lithofacies, this approach does not require prior knowledge about the partitioning of the well log readings or any assumption of the facies probability densities. Computer simulations using selected well log responses and facies description from a clastic and carbonate sequence in the Maracaibo Basin (western Venezuela) examine the performance of the fuzzy rule‐based classification approach. The performance of the fuzzy classification method is evaluated against the fades classification results using conventional statistical analysis.
IMMOBILIZATION OF CAPTIVE WILD ANIMALS WITH SUCCINYLCHOLINE USING THE PROJECTILE TYPE SYRINGE
Authors: Heuschele Werner P.
Published: December 2007

Forty‐four trials using succinylcholine chloride to produce immobilization, through temporary muscle paralysis in seventeen species of captive wild animals are reported. It is apparent that there is considerable variation between species with respect to drug dose per pound required to produce complete immobilization and with respect to the margin of safety of the drug. In highly nervous and fractious animals where a risk of death due to shock secondary to fright produced by the immobilization exists, the administration of tranquillizers prior to immobilization is suggested.
Breeding behaviour of the tiger Panthera tigris in Rajasthan
Authors: SANKHALA K. S.
Published: December 2007

This paper described the breeding behaviour of tigers and tigresses as observed in the forests of Rajasthan and in zoological gardens.

The tiger mates and reproduces throughout the year, but March to June is the peak period for births. There is also a second peak period in September. The observations made in the field and zoological gardens are compared. They indicate similarity. Study has shown that the gestation period is 93 to 114 days. Generally two to three cubs are born in one litter and the juvenile sex ratio indicates female predominance. When they reach a length of approximately 2 4 m at 11/2‐2 years, tiger cubs become separated from their mothers and establish territory of their own. At the age of four to five years they become mature. Based on the above data, a plea has been made to restrict shooting of tigers during the peak birth period.
the occurrence of dioctophymiasis in the Maned wolf Chrysocyon brachyurus
Authors: MATERA E. A. , SALIBA A. M. , MATERA A.
Published: December 2007

The authors describe in this paper the occurrence of five cases of dioctophymiasis in Maned wolves Chrysocyon brachyurus belonging to Sao Paulo Zoo. Clinical symptoms are described and the lesions found at post‐mortem examination are noted. Agreeing with the veterinary literature on the subject, they also verify that the infestation is in the right kidney. Finally, they show the possibility of diagnosis by radiography and treatment by nephrectomy.
Breeding the Rhinoceros iguana Cyclura cornuta cornuta at San Diego Zoo
Authors: SHAW CHARLES E.
Published: December 2007

The incubation of a total of 45 eggs of the Rhinoceros iguana Cyclura c. cornuta was attempted. Of these 45 eggs, 12 (26%,) hatched and 13 eggs (28.8%) contained dead embryos or young that died within the egg after slitting the shell. Unfortunately, the total fertility of these 45 eggs is not known, for in 20 of the eggs (44.4%) that spoiled during incubation, fertility was not determined. This contrasts with 100 per cent fertility in a clutch of 17 eggs of the Cuban iguana Cyclura m. macleayi in which there was a hatching rate of 94%.
Halothane inhalation anaesthesia in reptiles and its clinical control
Authors: BONATH KLAUS
Published: December 2007

Inhalation anaesthesia is recommended for small and medium‐sized reptiles (Sauria, Serpentcs, Crocodilia). For large reptiles medicinal muscle relaxation followed by endotracheal intubation and inhalation anaesthesia using an anaesthesia machine is suggested and discussed. Possible methods of monitoring the depth of anacstlicsia by means of simple reflex tests are summarised in an anaesthesia monitoring plan and the simple circulatory and respiratory reactions of anaesthetised reptiles are described; the determining influence of the environmental temperature on the course of anaesthesia and possibilities for reanimation of reptiles under dialation anaesthesia are reported.