bluuebunny/crossref_metadata_2025_split huggingface dataset:
MOZAMBIQUE‐MADAGASCAR GEOSYNCLINE, I: DEPOSITION AND ARCHITECTURE
Authors: Kamen‐Kaye Maurice 
Published: December 2007

The Mozambique‐Madagascar geosyncline consists of an open‐ended non‐compressional NNE‐SSW downwarp 1,700 km long in the area of the present Mozambique Channel and its bordering coastal regions. Exposed basement marks the lateral boundaries of the geosyncline, and embayments rather than discrete basins modify its regional geometry. A sedimentary volume of more than 5,000,000 cu km resulted from subsidence and hypersubsidence, not only in the Mozambique Channel but also on the coastal borders, in places relatively close to exposed basement.Continental facies of South African Karroo type dominates the sedimentary columns of the geosynclinal flanks in the Upper Carboniferous to Middle Jurassic interval, but is not yet documented beneath the bathyal and abyssal waters of the intervening Mozambique Channel. Marine facies, mixed facies, and a few continental facies occupy the sedimentary columns of the flanks above the Middle Jurassic. Pelagic facies may be dominant in contemporaneous strata now below the bottom of the Channel.As part of the vast non‐compressional province of the Indian Ocean the Mozambique‐Madagascar geosyncline has been subjected only to epeirogeny. The structural response has been normal faulting, in some places, with major downthrow and in others antithetic with patterns of graben and horst. Volcanism is known to have accompanied the faulting from Late Triassic time onward.Modern consensus invokes a separation of Madagascar from Africa followed by drift along southward, eastward, or NE paths, depending upon individual tectonophysical interpretation, each of the three of which displays weakness. The alternative of separation by subsidence only needs the test of deep drilling under the present Mozambique Channel for support orproof Until then, a tentative scheme of stratal succession is proposed, namely, a relatively‐thin post‐Karroo column in pelagic facies and a relatively‐thick Karroo column in continental and mixed facies.Confirmation of the succession by drilling would provide strong support of a model presenting paleo‐Madagascar as the eastern sector of an Africa that bulged more than once toward the east in post‐Carboniferous time. The corollary of a broad band of reservoir Karroo, under a broad cover of pelagic post‐Karroo, all under the waters of the present Mozambique Channel would be of considerable interest to explorationists.
GEOLOGY AND ENTRAPMENT HISTORY OF THE PORTACHUELO SALINA POOL, TALARA BASIN, PERU
Authors: Hay‐Roe H. , Zuniga J. F. , Montoya A. 
Published: December 2007

Maps of pressure measurements and fluid distribution are important tools in deciphering the geology of complex reservoirs. To understand the original entrapment and present‐day distribution of hydrocarbons in the Salina Pool of Portachuelo Field, NW Peru, we used pressure and production data, in conjunction with a detailed analysis of how the pool is put together structurally and stratigraphically. In Portachuelo up to 45 Lower Eocene (Salina) sands, which can be oil‐, gas‐, or water‐bearing in different wells, have been offset by a veritable maze of normal faults. To reconstruct this jig‐saw puzzle we used “composite” electric logs that provided a close approximation of the Salina sequence prior to faulting.The Salina Pool of Portachuelo offers a challenging place to hunt for commercial oil in a 490‐m sequence of multiple thin (2–10 m) sands within small fault‐blocks. In this search it is helpful to consider the pool as a fluid system in which the reservoir geometry, defined by both stratigraphy and structure, is only one major element; the other two elements are the fluid content of the system and its internal energy, as reflected in the reservoir pressure.Because of the remarkable complexity of the reservoir geometry, it was the present‐day distribution of fluids and pressures that eventually provided the key to the pool's history of entrapment. Only after fluid and pressure variations were interpreted in terms of the structural evolution did it become clear that Portachuelo's oil originally accumulated in a well‐defined anticline. This simple distribution was destroyed by faulting, which thinned and collapsed the anticlinal crest while raising the flanks. Gas, because of its higher mobility, was more widely redistributed than oil or water.
FORMATIONAL WATER CHARACTERISTICS AS AN INDICATOR FOR THE PROCESS OF OIL MIGRATION AND ACCUMULATION AT THE AIN ZALAH FIELD, NORTHERN IRAQ
Authors: EIzarka Mohamed Hossny , Ahmed Walid Abdel Majid 
Published: December 2007

Formational water characterization denotes a chloride‐calcium type in the S1S2A2 class. It indicates a hydrodynamic zone unfavourable for hydrocarbon preservation in the eastern block of the field. These waters have an index of base exchange (IBE) greater than 0.129, indicating connate oil reservoir waters, migrating with oil from the oil source‐beds at the southern parts of the field through connected openings and fault planes.The entrapment of oil took place at the crestal parts of the folded structure to the west and NW of the field. The water moved down‐dip along the eastern flank, creating capillary pressure, forcing the oil to accumulate in subcapillary pores at the top‐most parts of the upper pay‐zone. The latter section became oil‐wet. The oil wettability led to entrapment of a quantity of oil in the subcapillary pores that was then left behind during oil production operations, necessitating secondary recovery methods.The occurrence of more lighter constituents in crudes of the upper pay‐zone than in the lower one is due to fractionation and differentiation during migration.
THE SUBSURFACE GEOLOGY OF THE MEER AREA IN FORTH BELGIUM, AND ITS SIGNIFICANCE FOR THE OCCURRENCE OF HYDROCARBONS
Authors: Vandenberghe N. 
Published: December 2007

In North Belgium, unusually thick Namurian strata are shown to be rrelate to the existence of deep basin. The presence of a listric growth fault is demonstrated in the Upper Carboniferous, somewhat limiting the Namurian Basin.The associated roll‐over structure may contain sandstones with sufficient porosity to become an attractive exploration target for gas.
EFFECTS OF EPIDIAGENESIS ON RESERVOIR CHARACTERISTICS OF ROCKS BENEATH CONCEALED UNCONFORMITIES IN ENGLAND AND THE WESTERN DESERT, IRAQ
Authors: Al‐Gailani M. B. , Ala M. A. 
Published: December 2007

Petrographic and reservoir characteristic studies (porosity and permeability measurements) were carried out on 447 core samples from seven boreholes penetrating concealed unconformities in England and the Western Desert of Iraq. In England, the unconformities occur at the following boundaries: (a) Cretaceous/Devonian; (b) Lower Lias/Rhaeto‐Liassic/Beds of unknown age/Carboniferous Limestone Series; (c)Triassic/Lower Carboniferous; (d) Triassic/Upper Coal Measures (equivalent to Upper Pennsylvanian); and (e) Triassic/Permo‐Trias/Permian. The borehole in the Western Desert of Iraq encountered five unconformities, in successions ranging in age from the Carboniferous to the Cretaceous.The results showed great variations in porosity and permeability in the vicinity of these unconformities. These variations are attributed to diagenetic and epidiagenetic processes which may be summarized as follows: (1) early alteration of unstable components such as feldspars; (2) filling of pores and coating of grains by authigenic clay materials; (3) development of pyramidal or bipyramidal overgrowths on quartz grains; and (4) introduction of late diagenetic poikilotopic sparry calcite and/or dolomite cement.Carbonate rocks are affected by: (1) early dissolution and development of vuggy porosity; (2) dolomitization and dedolomitization; (3) vadose and phreatic cementation; (4) silicification; and (5) modification of porosity and permeability through the growth of new minerals.Finally, on the basis of the results obtained, three models illustrating the evolution of porosity beneath unconformities are proposed.
THE HYDROCARBON EXPLORATION OF THE BASINS OF THE ROSS SEA, ANTARCTICA, FROM MODELLING OF THE GEOPHYSICAL DATA†
Authors: Cook Richard A. , Davey F. J. 
Published: December 2007

Geophysical definition of the three major sedimentary basins of the Ross Sea and scientific drilling on their margins have provided enough information for conceptual models of hydrocarbon generation and source rock character to be applied.The Waples‐Lopatin geochemical model used is an accepted part of preliminary exploration in petroleum frontier areas where data are limited. The model has only a narrow empirical base despite widespread use by the exploration industry, but its value is in the collation and utilization of a variety of parameters which control the physical environment of hydrocarbon generation. This modelling evaluation attempts to overcome the condemnation of a region because of the lack of data rather than the lack of true petroleum potential.In the Ross Sea, the Deep Sea Drilling Project (DSDP) holes 270–273 showed that methane and heavier hydrocarbons are present in the drilled sequences. However, to be significant, they must be indicative of regional generation and not just the result of local anomalies. Modelling shows that there are areas of the Ross Sea where the conditions for hydrocarbon generation should be present and these areas are worthy of future exploration.
A RIFT‐RELATED STRATIGRAPHIC TRAP
Authors: Fagerland Nils 
Published: December 2007

During the prospectivity analysis of the 40 blocks of the 8th Norwegian round of licensing, a potential “giant” stratigraphic trap was discovered. Its evolutionary histroy makes it especially interesting from a regional point of view.Well information from neighbouring blocks and high quality seismic data has made this possible.In block 16/4 in the southern part of the Viking Graben, a combined stratigraphic/structural trap was formed during the Late Paleocene‐Early Eocene.A submarine fan sequence reached across the viking Graben from the Shetland Platform onto the western flank of the Utsira High of block 16/4 during the Early Paleocene. Later, the Tertiary basins sank with the depo‐centers centered over the old graben. This sinking, together with reactivation of old faults in the southern part of block 16/1 and the northern part of block 16/4 during the Late Paleocene‐Early Eocene, created a large trap. This type of trap is typical for early post‐rift sequences where the post‐rift basin development is governed by the old lines of weakness inherited from the underlying aborted rift.
TECTONIC CONDITIONS FOR OIL AND GAS GENERATION AND DISTRIBUTION ON ANCIENT PLATFORMS
Authors: Maximov S. P. , Zolotov A. N. , Lodzhevskaya M. I. 
Published: December 2007

This paper deals with the influence of tectonic factors on teh distribution and generation of oil and gas accumulations in oil‐and gas‐bearing basins ancient platforms. Threee main platform evolutionary stages, with their corresponding structural‐formational associations, may be recognized; the petroleum potential of each stage is different.Important factors are: the intensity of subsidence; the areal distribution of individual formations, and the presence of sulphate‐saltis in teh section, formation regional seals.The influence of inversion processes in the development of “giant”l gas‐condensate accumulations is emphasized, adn the petroleum‐bearing basins of ancient platforms are classified according to their oil and gas reserve.
JURASSIC FORAMINIFERAL FACIES IN THE STATFJORD AREA, NORTHERN NORTH SEA ‐ I
Authors: Nagy Jenö 
Published: December 2007

Core samples from five wells of the Statfjord area were analysed for foraminifera. The material covers the middle and upper parts of the deltaic marine Dunlin Formation and the basal deposits of the deltaic Brent Formation through an interval ranging in age from Pliensbachian to Toarcian or early Bajocian.The quantitative distribution of genera and other major faunal parameters define the following five assemblages which reflect successive steps in the evolution of the depositional basin (in ascending order): the Dentalina‐Nodosaria, Ammodiscus‐Dentalina and Marginulina assemblages developed in a delta‐influenced shelf embayment; the Trochammina‐Verneuilinoides assemblage formed under prodelta conditions; the Ammodiscus assemblage deposited in a delta‐front environment. The specific composition of the assemblages is illustrated by quantitative examples.
CONCEPTS ON THE GENERATION AND ACCUMULATION OF BIOGENIC GAS
Authors: Gang Zhang Yi , Jiang Chen Huan 
Published: December 2007

To help in the search for biogenic gas, parameters affecting its spatial and temporal distribution are delineated here on the basis of recent developments in microbiology and geochemistry. Methane is produced and dissipated at high rates in uppermost sediments. The key to its accumulation lies in the presence of factors which inhibit the metabolism of bacterial methanogens near the surface, and leave them to flourish at greater burial depths. Favourable controlling factors are as follows: a plentiful nutrient supply (mainly carbohydrates), a high SO‐4 content in the bottom water; a post‐oxic sedimentary environment; frequent transgressions and regressions; low temperatures; high pH values; and high depositional rates and pressures.In the course of geological history, biogenic gas could be formed whenever transgressions and regressions have occurred frequently due either to tectonics or Ice Ages; when broad coastal plains were supplied with terrigenous non‐lignin carbohydrates by vast river networks; and when cool climates persisted. Accumulations can be grouped into three major genetical types, i. e. West Siberian (coastal marine facies); Black Sea (transitional marine‐lacustrine facies of restricted basins); and Qaidam (inland brackish lacustrine facies). Some case‐ histories from China and additional information from West Siberia are presented. It seems that many biogenic gasfielh remain undiscovered, and exploration prospects are good.
PART 1: ROCK‐EVALFYROLYSIS AND VITRINITE REFLECTANCE1
Authors: Price Leigh C. , Daws Ted , Pawlewicz Mark 
Published: December 2007

Detailed organic geochemistry has been performed on a large number of Lower Mississippian‐Upper Devonian Bakken shales from the North Dakota portion of the Williston Basin, and 28 oils mainly from Mississippian Madison Group rocks from different basinal areas. Here we report results of Rock‐Eval pyrolysis and vitrinite reflectance (Ro) analyses. Variable paleoheat flows in the Williston Basin caused the threshold of intense hydrocarbon generation to occur at different depths in different basinal areas. In higher paleogeothermal gradient basinal areas, this event occurred at depths of 7,650‐8,000 ft, and at 10,000 ft or deeper in lower paleogeothermal gradient areas of the Basin. Distinct organic metamorphic imprints in Williston Basin sediments were also caused by extreme, but variable, paleoheat flows in the basin, as well as secondary migration of crude oils from deep basinal source areas. The high paleoheat flows are postulated as being due to a Late Cretaceous — Paleocene aborted rift event. Only a small volume of Bakken shales in restricted areas of the Williston Basin was responsible for the oil found reservoired in Mississippian Madison Group rocks. However, this small shale volume has been responsible for a relatively large amount of crude oil.R0 profiles in the Tertiary through Middle Jurassic rocks in the Williston Basin had steep, linear Ro versus depth gradients, with strong reversals of R0 values occurring in the Lower Jurassic rocks. The lower Mesozoic through Paleozoic rocks of the Basin had strongly suppressed R0 values compared to the values in the Tertiary through Middle Jurassic rocks. This was especially true of the R0 values in the Bakken shales. This R0 suppression was due to a change in organic matter (OM) type from oxygen‐rich terrestrially derived OM in the younger rocks, to a hydrogen‐rich marine derived OM in the deeper, older rocks. The threshold of intense oil generation (TIHG) occurred in the Bakken shales of the Williston Basin at R0 values somewhere between 0.9 and 1.7% (best estimate 0.9), as would be read in oxygen‐rich OM. Much higher burial temperatures (and consequently R0 values) than usually held to be necessary were required for both the TIHG as well as mainstage hydrocarbon generation in the Bakken shales. These results are most likely applicable in general to source rocks with hydrogen‐rich OM. The data of this study have major implications to petroleum exploration as well as to petroleum resource assessment.
THE ORINOCO OIL BELT, VENEZUELA
Authors: Martínez Aníbal R. 
Published: December 2007

The Orinoco Oil Belt of Venezuela is a very extensive, non‐discrete, crude‐oil producing area located along the southern third of the Maturín (Eastern Venezuela) basin, north of the Orinoco River and the Guayana Shield. It extends due westwards from Puerto Ordaz for 460km; the main producing areas, defined on the basis of productivity and magnitude of crude oil in‐place, cover 13, 600 sq. km. There are no significant surface indications of petroleum anywhere in the Belt. The first well drilled was La Canoa‐1 in 1936, initiating a stage of exploration which ended in 1967 with publication of a preliminary evaluation of the potential reserves; the Ministry of Energy and Mines, then of Mines and Hydrocarbons, and the State oil company Corporación Venezolana del Petróleo (CVP) completed a second stage of exploration in 1977; Petróleos de Venezuela and its operating companies then drilled 669 wells in five years (1979–83) totalling 643,000 m with 5.5 MM** m of logs, and shot 15,000 km of seismic lines at a cost of $US 615 MM, an effort conservatively estimated as having taken 2,500 man‐years. The main producing areas are, from east to west, Cerro Negro, Pao, Hamaca, San Diego, Zuata, and Machete. Petroleum characterisation in the Belt is based on the study and analysis of 288 samples. Viscosity (dynamic) of the crude oils at reservoir conditions ranges from 2,000 to 7,000 m Pa.s (cp)†.Production rates average 25 cu. m/d(160 b/d), increasing fourfold after steam stimulation. At the end of 1985, production was 13,000 cu.m/d(80,000b/d)†, from the Cerro Negro and Hamaca main producing areas. Operating costs are similar to those in other heavy‐crude oilfields in the basin. The volume of crude oil in‐place is estimated to be 187.8 B cu. m (1,181 B brls), which makes the Orinoco Oil Belt the largest crude oil accumulation in the world. Proved reserves are 4.161 B cu. m (26.170 B brls). and unproved reserves 14.822 B cu. m (93.230 B brls). Investigative activities are underway, particularly in the Cerro Negro and San Diego producing areas. In subsequent papers of this thematic survey, A. Isea presents a geological synthesis of the Orinoco Oil Belt; G. Don Kiser discusses the exploration results of the Machete area; A. Santos and L. Frontado describes the reservoir geology of the Cerro Negro steam‐injection area; and A. Vega and I. de Rojas summarise exploration results from the Zuata area.
GEOLOGICAL SYNTHESIS OF THE ORINOCO OIL BELT, EASTERN VENEZUELA
Authors: Isea Andreina 
Published: December 2007

The Orinoco Oil Belt, considered to be the largest hydrocarbon accumulation in the world, is located on the southern border of the Eastern Venezuela basin. The stratigraphic column of the area includes rocks of Pre‐Cambrian to Recent ages, but more than 90% of the crude oils are found in Miocene sediments.Three transgressive‐regressive cycles with wide regional distributions are recognised in the Tertiary system: Cycle 1 includes the La Pascua, Roblecito and Chaguaramas formations of Oligocene age; and Cycles 2 and 3 include the Officina, Upper Chaguaramas and Freites formations of Miocene age. Within the cycles, five lithostratigraphic units are defined, and a sedimento logical model for Units I and III is consequently established, recognizing north‐orientated, wave and tide‐influenced, prograding deltas.Tensional tectonics characterize the area as having two structural provinces, separated by the Hato Viejo fault system: the Eastern Province, characterized by a transgressive sequence overlying the Pre‐Cambrian basement; and the Western Province, where the Tertiary unconformably overlies Cretaceous and Paleozoic sediments. Hydrocarbon accumulations in the Orinoco Oil Belt predominantly occur in stratigraphic traps, but are controlled by regional structures. Four types of crude oils are identified, with density values between 8.5 and 13° API. The volume of oil in‐place in the Orinoco Oil Belt totals 187,897 MM†cu. m(1,181 B brl). The largest accumulations are found in the sands of Unit I.
EXPLORATION RESULTS, MACHETE AREA, ORINOCO OIL BELT, VENEZUELA
Authors: Kiser G. Don 
Published: December 2007

The Machete Area covers 23,610 sq. km (9,116 sq. miles), of the Orinoco Oil Belt in Venezuela. Based on exploration data from 30 old and 74 new wells, the volume of heavy and extra‐heavy crude oil in‐place is estimated to be 40 B cu. m (255 B brl), ** of which 4 B cu.m (22.5 B brl) are in future potentially recoverable; some 62 B cu.m (2.2 T cu. ft) of natural gas may also be recovered. Drill depths to the base of the producing section vary from 518 to 1,220 m. Net oil sand reaches 116 m in thickness for Tertiary reservoirs, and 46 m for Cretaceous ones. The crude oils average 1,022 kg/cu.m (7° API), and have a content of sulphur and various metallic elements typical of similar crudes; viscosities are slightly higher than in the rest of the Belt.Production rates of up to 20 cu. m/d (140 b/d) on pump may be increased ten‐fold by steam injection. Dry natural gas flows of 450 cu.m/d are common. The principal geological factors controlling the Machete accumulations differ from those in adjacent areas, and consist of the subsurface extension of the El Baúl Arch which has controlled sand‐shale facies, pinch‐out lines and structural‐stratigraphic trapping of the heavy crude oils and natural gas.
CONTINENTAL CRUST UNDER THE NW PACIFIC OCEAN
Authors: Choi D.R. 
Published: December 2007

Reinterpretation of seismic profiles and DSDP drilling results, together with dredging data from the Japan Trench and Nankai Trough areas, NW Pacific, shows that the so‐called oceanic crust is composed of PreCambrian continental crust, consisting partly of Proterozoic orthoquartzite.This is supported by paleogeographic evidence, which requires the presence of large continental masses on the present Pacific side of the Japanese islands during Paleozoic‐Mesozoic‐Paleogene times, as source areas for the large volume of sediments carried into the Japanese part of the Tethys.Most of the present NW Pacific was either subaerially exposed or was partly very shallow sea during Paleozoic to Early Mesozoic times, and first became deep sea about the end of the Jurassic.These conclusions require the fundamental revision of plate‐tectonic models for the geological development of the island arcs and trenches in the NW Pacific region.