bluuebunny/crossref_metadata_2025_split huggingface dataset:
REVISION OF THE MAHAKAM COAL SERIES: ROCK‐EVAL AND RANK(S) RELATIONS
Authors: Suggate R. P. , Boudou J. P. 
Published: December 2007

Neogene sequences in the Mahakam delta, Indonesia, contain many coals for which abundant analytical and Rock‐Eval data exist. It is essential that raw analytical data are adjusted for the effects of mineral matter, including pyrite, before they are used to calculate atomic H/C and O/C ratios; these ratios are required in order to present the coal series on a van Krevelen diagram.In this paper, a method of adjustment is proposed which allows the definition of a well‐constrained Mahakam coal band; this is comparable to the Late Cretaceous and Tertiary New Zealand coal band and the Japanese Palaeogene coal band. The relationships between: (i) coal rank (using the Rank(S) scale) and Rock‐Eval parameters; and (ii) coal rank and vitrinite reflectance for the Mahakam coals are generally similar to those for the New Zealand coals.
A PRELIMINARY EVALUATION OF LOWER AND MIDDLE CRETACEOUS SOURCE ROCKS IN KUWAIT
Authors: Abdullah F.H.A. , Kinghorn R.R.F. 
Published: December 2007

Large volumes of oil and gas are present in the Arabian‐Iranian Basin; however, most petroleum‐geological investigations here have concentrated on reservoirs and traps, and there have been few efforts to study potential source rocks. This paper evaluates possible source rocks within the Lower to Middle Cretaceous interval in Kuwait, which is one of the main oil‐ and gas‐producing countries in this region.Samples of carbonates and shales from formations within the Thamama and Wasia Groups (Lower and Middle Cretaceous) were collected from five locations in Kuwait. These samples were studied using standard organic‐geochemical methods (TOC and pyrolysis analysis, elemental analyses of kerogens, density separation, and petrographic analyses using transmitted and reflected light microscopy).Most of the kerogens in the studied samples fell between Types II and III. The TOC, kerogen type and maturity of the Sulaiy Formation and parts of the Minagish Formation (Lower Cretaceous) indicate that they supplied hydrocarbons to the reservoirs in Kuwait.
POTENTIAL FOR COAL‐DERIVED GASEOUS HYDROCARBONS IN THE MIDDLE BENUE TROUGH OF NIGERIA
Authors: Obaje N. G. , Abaa S. I. 
Published: December 2007

About 6,000m of alternating marine, paralic, and continental sediments of Cretaceous to Tertiary ages are present in the Benue Trough. Conspicuous amongst these are coal‐bearing strata, of which those in the Middle Benue Trough have attained a high‐ to medium‐volatile bituminous rank.Coal beds are now known to be major sources of associated and non‐associated gases, and increasingly are becoming exploration targets in many parts of the World. In the Middle Benue Trough, the Turonian Awgu Formation, about 400‐m thick, is the main coal‐bearing unit.Maceral analysis of samples from coal seams and from organic matter‐rich interseam sediments obtained from four boreholes and two outcrop sections allowed three petrographic facies to be identified, namely:Vitrinite reflectance values measured on these samples generally increase with depth from 0.74 ‐ 1.25Rm%. At these values, large amounts of volatile matter are yielded in the form of methane, carbon dioxide and water during progressive devolatization of humic organic matter.Organic matter in the underlying dark‐black, carbonaceous marine shales of the Cenomanian Ezeaku and Albian Arufu/Uomba/Gboko Formations may also be at the rank of medium‐volatile bituminous coal, and probably reaches the low‐volatile bituminous stage. These would correspond with the interval of maximum gas generation and the generation of methane, accompanied by strong aromatisation and ring condensation.

A vitrinite‐fusinite coal facies, which is vitrinite‐dominated with minor amounts of liptinite and variable amounts of inertinite; the content of mineral matter is low.
A trimaceritic coal facies, which is vitrinite‐dominated with moderate amounts of liptinite and inertinite; the content of mineral matter is low.
A shaley coal facies, which is dominated by mineral matter, with variable amounts of vitrinite, liptinite and inertinite.
A NEURAL‐NETWORK APPROACH TO KNOWLEDGE‐BASED WELL INTERPOLATION: A CASE STUDY OF A FLUVIAL SANDSTONE RESERVOIR
Authors: Wong P. M. , Tamhane D. , Wang L. 
Published: December 2007

This paper presents a new approach to well interpolation using interpolation neural networks (INETs). Traditional methods such as geostatistics have been applied to the spatial mapping of reservoirs. However, these methods are not able to make use of qualitative information, such as previously‐constructed “expert knowledge ” in the form of iso‐porosity contours or structural maps of sand body geometry, in a simple manner.This paper demonstrates the usefulness of INET via a case study of a fluvial sandstone reservoir at an oilfield in the Asia Pacific region. The proposed method is applied to porosity interpolation based on data from spatially‐dispersed wells and regional geological knowledge. The results from this study show that an INET is not only able to incorporate expert advice, but also that it is easy to implement in a desktop computer or workstation. This allows an effective transfer of geological knowledge to reservoir modelling.
THE NATURE AND PRESERVATION OF ORGANIC MATTER IN HOLOCENE LACUSTRINE/DELTAIC SEDIMENTS OF LOWER MESOPOTAMIA, SE IRAQ
Authors: Aqrawi A. A. M. 
Published: December 2007

Organic‐geochemical studies of sediments at the surface and in shallow boreholes in the Tigris‐Euphrates Delta of SE Iraq are integrated in this paper with sedimentological and stratigraphic studies. Limited organic preservation was found to have occurred in surface sediments from marshland areas (“Ahwar”), although organic‐rich sediments were observed within older Holocene borehole sequences.Reeds of Phragmites and Typha sp. are the main source of organic material in both the surface and the underlying sediments in this area. Petrographic studies indicated that this material consists mainly of “immature” components such as woody structures, algal amorphous and herbaceous matter, with some marine structures and pollen.The principal factor controlling organic‐matter preservation in this arid deltaic setting seems to have been the comparatively high rate of sedimentation, particularly in the early‐middle Holocene. Most of these organic‐rich sediments (5–15% TOC) are overlain by middle Holocene brackish/marine sediments of the transgressive Hammar Formation. The organic‐rich sediments are generally older than these transgressive sediments (i.e. 6,000–9,000 years BP, according to their location within the study area).
ANALOGUE MODELLING: FROM A QUALITATIVE TO A QUANTITATIVE TECHNIQUE — A HISTORICAL OUTLINE
Authors: Koyi H. 
Published: December 2007

Analogue modelling is a simplification of Nature; using this method, structures formed due to the deformation of rocks, whose in situ properties may be poorly known, can be modelled and investigated. Our lack of knowledge about “real” rocks is one of the major limitations to any kind of modelling of deformation. However, unlike their counterparts in Nature, the initial (undeformed) stages of analogue models can be documented, and can easily be compared with their later, deformed stages. This comparison is essential to gain an understanding of the evolution of the resulting structures. Analogue modelling is a relatively simple and inexpensive technique which can be very valuable as long as its limitations are well understood.In rock mechanics, real rocks are strained over human time scales. As many of the properties of rocks are time‐dependent, the results of this type of experiment cannot directly be extrapolated to geologic time scales. Instead, modellers diminish the temporal and spatial dimensions by substituting carefully‐chosen analogue materials for real rocks. Unlike field geologists, analogue modellers are able to follow the development of their models in a fixed reference frame.Cloos (1955) noted that: “Many interpretations would never have been published if the author had only once tried his suggested mechanism of folding or faulting in an experiment….”; he also concluded that “[analogue] experimenting is a good deal of fun”!
MULTIPLE PETROLEUM SYSTEMS IN TERTIARY EXTENSIONAL BASINS, EAST CHINA: A CASE STUDY OF THE GUNAN‐FULIN BASIN
Authors: Jianyu Chen , Shuifu Li , Ying Xiong , Yanpong Bi 
Published: December 2007

The Gunan‐Fulin Basin, a small, extensional basin of Tertiary age, is located within the Shenglipetroleum “province” which structurally corresponds to the Jiyan megabasin in East China. The Lower Tertiary succession in the Gunan‐Fulin Basin is dominated by the Eocene‐lower Oligocene Shahejie Formation, which is divided into four members. Major source rocks are present in the Es3 Member (Eocene), and the Es 1 Member (Oligocene). Both units were deposited during lacustrine transgressions in the Early Tertiary. They are composed of dark, organic‐rich mudstones and oil shales of lacustrine origin, and contain good quality Type I‐II kerogen. The Es 1 source rock was deposited in a saline lake occasionally invaded by the sea, while the Es3 unit was laid down in a fresh‐water lake.The maturity and characteristics of these source rocks and the related crude oils can be distinguished on the basis of their biomarker contents. Es 1 source rocks and related oils are of relatively low maturity, while those of Es3 derivation are mature to highly‐mature. There are therefore two separate petroleum systems in the Gunan‐Fulin Basin — Eocene and Oligocene.These petroleum systems are isolated hydraulically, and have independent migration pathways in which fault planes and unconformity surfaces play important roles. The distribution of oil accumulations in the two systems is different as a result of faulting. Oil from the Eocene source rocks is trapped in reservoirs which are distributed stratigraphically from the basement to the Tertiary, while oil from the Oligocene source rock is confined to Oligocene and Miocene reservoir rocks.The existence of multiple petroleum systems is an important feature of Tertiary extensional basins in East China, and results from multiple phases of block faulting and a high geothermal gradient.
GEOCHEMICAL CHARACTERISTICS AND THERMAL MATURITY OF OILS FROM THE THRACE BASIN (WESTERN TURKEY) AND WESTERN TURKMENISTAN
Authors: Gürgey K. 
Published: December 2007

Crude oils in the Thrace Basin (western Turkey) and western Turkmenistan are believed to have been generated by a common Oligocene siliciclastic source rock. This widespread source rock extends over the area between western Turkey and the eastern South Caspian Basin. Oils from three Eocene reservoirs in the Thrace Basin and from four Pliocene reservoirs onshore western Turkmenistan were analyzed to investigate and compare their source‐rock characteristics. In order to understand controls on the timing of hydrocarbon generation and source‐rock maturation in both basins, the results of quantitative basin modelling were compared with those of geochemical analyses.The results indicate that all the oil samples exhibit similar geochemical characteristics, such as IP13‐IP20 acyclic isoprenoid, terpane, regular sterane, methylsterane, and dinosterane profiles. The low tricyclic/pentacyclic terpane ratios, low C29 norhopane/C30 hopane ratios and low diasterane/regular sterane ratios, and the presence of 18α (H)30 oleanane and gammacerane further support a common source or source facies. Based on these observations, it is concluded that shallow‐marine clastics of Oligocene age constitute source rocks in both basins.The oils are of low maturity (Req(%) < 0.60), as indicated by their low ethylcholestane 20S/20S+20R, 17α (H), 21β (H)‐bishomohopane 22S/22S+ 22R, and high 17β (H), 21α (H) moretane/17β (H), 21α (H) hopane ratios. However, oils from west Turkmenistan appear to be more mature than those from the Thrace Basin. This is consistent with their earlier generation, which resultedfrom the higher sedimentation rate and higher heating rate. Present‐day reservoir depths and temperatures appear to play only a minor role in determining the oils' maturities.
CRETACEOUS SOURCE ROCKS AT THE ABU GHARADIG OIL‐ AND GASFIELD, NORTHERN WESTERN DESERT, EGYPT
Authors: Khaled K. A. 
Published: December 2007

The Abu Gharadig oil‐ and gasfield is located in the north of the Western Desert of Egypt. In this paper, the geochemical characteristics of kerogens from Cretaceous shales at this field are described. The shale samples came from the Abu Roash Formation E and G Members (late Cenomanian‐ Turonian), the Bahariya Formation (early Cenomanian) and the Betty Formation (Neocomian‐ Barremian). Kerogen type and quality was evaluated by optical microscopy and by standard methods (elemental analysis, infrared spectroscopy and Rock‐Eval pyrolysis). The results show that the shale samples analysed contain fair to high quantities of organic matter, and that this takes the form of marine amorphous sapropelic and structured liptinite macerals which can be classified as Types I and II kerogens.Maturation indicators and burial history curves indicate that shales from the Abu Roash E and G Members are currently located in the oil‐generation window. Oil generation in these units has taken place since the late Palaeocene‐early Eocene—i.e. since the formation of structural traps in the Abu Gharadig area, which occurred in the Maastrichtian—Eocene. Shales in the Bahariya and Betty Formations passed through the oil window during the Late Cretaceous before the traps were formed, but the shales reached the wet‐gas zone in the late Miocene ‐ early Pliocene.Most of the liquid hydrocarbons in the Abu Gharadig field are sourced by Cretaceous shales in the Abu Roash E and G Members; and most gas is generated by shales in the underlying Bahariya and Betty Formations. The Jurassic Khatatba Formation may also have generated some gas.
VOLCANIC RESERVOIR ROCKS: A CASE STUDY OF THE CRETACEOUS FENGHUADIAN SUITE, HUANGHUA BASIN, EASTERN CHINA
Authors: Jinglan Luo , Chengli Zhang , Zhihao Qu 
Published: December 2007

The lithofacies and reservoir properties of Cretaceous volcanic rocks in the Fenghuadian Suite (Huanghua Basin, eastern China) are described in this paper. Three lithofacies have been identified (pyroclastics, lavas and volcaniclastics) and each has different reservoir potential due to differences in porosity and permeability. Pyroclastics and lavas have better reservoir properties than do volcaniclastic rocks. In the pyroclastics, voids and fractures within brecciated rocks together with dissolution voids and fissures result in highly connected porosity (up to 22%). In the lavas, vesicles, dissolution joints and cooling fissures together with weathering cracks and fissures are abundant and have high connectivity in the upper portions of each volcanic cycle, giving rise to excellent reservoir properties. By contrast, volcaniclastic rocks have low porosities and poor reservoir potential.We suggest that porosity development is partly related to palaeo‐geomorphology. Thus, volcanic rocks in palaeo‐highs and in neighbouring transitional areas have enhanced reservoir properties as a result of weathering and the consequent development of vugs and fissures.Chromatographic analyses of crude oils and rock extracts indicate that the Kong‐2 Member of the Eocene Kongdian Formation, which overlies the Fenghuadian Suite in the study area and which also occurs in the nearby Cangdong Depression, is the principal source of hydrocarbons reservoired in the Fenghuadian Suite. Faults may have acted as conduits for hydrocarbon migration.
OVERPRESSURE DEVELOPMENT AND HYDROFRACTURING IN THE YINGGEHAI BASIN, SOUTH CHINA SEA
Authors: Xinong Xie , Sitian Li , Weiliang Dong , Qiming Zhang 
Published: December 2007

Intensely overpressured compartments are present in the centre of the Yinggehai Basin, South China Sea. In this part of the basin, a diapiric area can be distinguished from a non‐diapiric area; structures in the former area result from shale diapirism at depth, and from the movement of hydrothermal fluids at more shallow levels. In the diapiric zone, the top of the overpressured compartment is relatively shallow (1,500m to 2,500m deep), whereas it is more than 3,200m deep in the non‐diapiric area. The top of the overpressured compartment in the diapiric zone has been raised to relatively shallow levels due to vertical fluid expulsion.Hydrofracturing has occurred in the Neogene‐Quaternary marine sedimentary succession, particularly in mud‐rich intervals such as the Lower Member of the Pliocene Yinggehai Formation. Hydrofracturing may have allowed the rapid lateral and vertical migration of enormous volumes of pore fluids. The presence of additional steeply‐dipping faults in the diapiric area may have led to vertical expulsion of fluids from overpressured compartments to normally‐pressured areas, and caused the top of the overpressured compartment to be uplifted. Gaseous hydrocarbons are assumed to have migrated vertically through fractures around diapiric structures from overpressured to normally‐pressured zones. We believe that this mechanism has had a significant effect on hydrocarbon transport and accumulation in the Yinggehai Basin.
THE GEOLOGY AND HYDROCARBON HABITAT OF THE SARIR SANDSTONE, SE SIRT BASIN, LIBYA
Authors: Ambrose G. 
Published: December 2007

The Jurassic — Lower Cretaceous Sarir Sandstone Cformerly known as the Nubian Sandstone) in the SE Sirt Basin is composed of four members which can be correlated regionally using a lithostratigraphic framework. These synrift sandstones unconformably overlie a little known pre‐rift succession, and are in turn unconformably overlain by post‐rift marine shales of Late Cretaceous age.Within the Sarir Sandstone are two sandstone‐dominated members, each reflecting a rapid drop in base level, which are important oil reservoirs in the study area. Between these sandstones are thick shales of continental origin which define the architecture of the reservoir units. This four‐fold lithostratigraphic subdivision of the Sarir Sandstone contrasts with previous schemes which generally only recognised three members.The sandstones below the top‐Sarir unconformity host in excess of 20 billion barrels of oil in‐place. The dominant traps are structural (e.g. Sarir C field), stratigraphic (e.g. Messla field), hanging‐wall fault plays (e.g. UU1–65 field) and horst‐block plays (e.g. Calanscio field). Three Sarir petroleum systems are recognised in the SE Sirt Basin. The most significant relies on post‐rift (Upper Cretaceous) shales, which act as both source and seal. The Variegated Shale Member of the Sarir Sandstone may also provide source and seal; while a third, conceptual petroleum system requires generation of non‐marine oils from pre‐rift (?Triassic) source rocks in the axis of the Sarir Trough.The intrabasinal Messla High forms a relatively rigid block at the intersection of two rift trends, around which stress vectors were deflected during deposition of the syn‐rift Sarir Sandstone. Adjacent troughs accommodated thick, post‐rift shale successions which comprise excellent source rocks. Palaeogene subsidence facilitated oil generation, and the Messla High was a focus for oil migration. Wrenching on master faults with associated shale smear has facilitated fault seal and the retention of hydrocarbons. In the Calanscio area, transpressional faulting has resulted in structural inversion with oil entrapment in “pop‐up” horst blocks. Elsewhere, transtensional faulting has resulted in numerous fault‐dependent traps which, in combination with stratigraphic and truncation plays, will provide the focus for future exploration.
PORE FLUID EVOLUTION WITHIN A HYDROCARBON RESERVOIR: YACORAITE FORMATION (UPPER CRETACEOUS), NORTHWEST BASIN, ARGENTINA
Authors: Cesaretti N. N. , Parnell J. , Dominguez E. A. 
Published: December 2007

Hydrocarbon and aqueous fluid inclusions in quartz and anhydrite cements in sandstones and carbonates in the upper part of the Yacoraite Formation (Upper Cretaceous) were studied in wells in the Lomas de Olmedo Sub‐basin, Northwest Basin, Argentina.Intergranular, mouldic and vuggy primary porosity in these rocks was reduced by quartz overgrowths, anhydrite cement and bitumen, and was increased by dolomite recrystallization and fracturing. High porosities are thought to reflect high pore fluid pressures; the highest porosities are associated with a greater abundance of secondary fluid inclusions, reflecting healing of microfractures produced by the release of overpressured fluids.Paraffinic (light) and asphaltic (heavy to medium?) hydrocarbon fluid inclusions are recognized by their light‐blue and yellow‐greenish fluorescence colours. In the stratigraphically lower levels of the Yacoraite Formation, reddish‐fluorescent asphaltic fluid inclusions with lower cloud points predominate, whereas in the upper levels, lighter hydrocarbons with higher cloud points, propane, ethane and methane occur in the inclusions.For aqueous fluid inclusions, data from freezing experiments indicate that NaCl‐MgCl2‐Na2SO4‐NaHCO3‐NaCO3 brines were present during cementation with 17equiv. wt. % NaC1. Temperatures during cementation were in the range 121–137°C, indicating that the samples are in the oil and gas window.The petrographic data indicate that a hydrocarbon fluid has been present since early diagenesis began. An increase in burial depth is correlated with an increase in the temperature and pressure in the pore fluids. This caused the maturation of organic matter in the carbonates, generating CO2 and carboxyl ions, which in turn caused carbonate dissolution and anhydrite and dolomite precipitation. In the sandstones, the maturation of oil resulted in bitumen pore‐fillings and secondary fluorescing inclusions.