bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.
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.