THE GEOLOGY AND HYDROCARBON HABITAT OF THE SARIR SANDSTONE, SE SIRT BASIN, LIBYA

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.     

COAL-GENERATED OIL: SOURCE ROCK EVALUATION AND PETROLEUM GEOCHEMISTRY OF THE LULITA OILFIELD, DANISH NORTH SEA

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.     

CRUDE OIL GEOCHEMISTRY AND SOURCE ROCK POTENTIAL OF THE UPPER CRETACEOUS – EOCENE SUCCESSION IN THE BELAYIM OILFIELDS,CENTRAL GULF OF SUEZ,EGYPT

This study evaluates the petroleum potential of source rocks in the pre‐rift Upper Cretaceous – Eocene succession at the Belayim oilfields in the central Gulf of Suez Basin. Organic geochemical and palynofacies investigations were carried out on 65 cuttings samples collected from the Thebes, Brown Limestone and Matulla Formations. Analytical methods included Rock‐Eval pyrolysis, Liquid Chromatography, Gas Chromatography and Gas Chromatography – Mass Spectrometry. Four crude oil samples from producing wells were characterised using C₇ light hydrocarbons, stable carbon isotopes and biomarker characteristics. The results showed that the studied source rocks are composed of marine carbonates with organic matter dominated by algae and bacteria with minimal terrigenous input, deposited under reducing conditions. This conclusion was supported by n‐alkane distributions, pristane/ phytane ratios, homohopane and gammacerane indices, high concentrations of cholestane, the presence of C₃₀ n‐propylcholestanes, and low diasterane ratios. The source rocks ranged from immature to marginally mature based on the Rock‐Eval T_max together with biomarker maturity parameters. The analysed crude oil samples are interpreted to have been derived from source rock intervals within the Eocene Thebes Formation and the Upper Cretaceous Brown Limestone. The similarity in the geochemical characteristics of the crude oils suggests that there was little variation in the organofacies of the source rocks from which they were derived.     

SEISMIC STRATIGRAPHIC ANALYSIS AND STRUCTURAL DEVELOPMENT OF AN INTERPRETED UPPER CAMBRIAN TO MIDDLE ORDOVICIAN SEQUENCE IN THE NW BLANTYRE SUB‐BASIN,DARLING BASIN (WESTERN NEW SOUTH WALES,AUSTRALIA)

In this paper, a new interpretation is presented of the seismic stratigraphy of units equivalent to the upper Cambrian to middle Ordovician Scropes Range Formation in the NW Blantyre Sub‐basin in the central part of the Palaeozoic Darling Basin, western New South Wales. This succession was previously unrecognised, attributed to the lower part of the overlying Winduck Interval, or regarded as basement. The structural development of the study area is described, and may contribute to a better understanding of the regional stratigraphic evolution of the Lower Palaeozoic section in this part of the Darling Basin This study presents interpretations of a regional two‐dimensional seismic survey which investigated the upper Cambrian to middle Ordovician Scropes Range Formation in the NW Blantyre Sub‐basin. A shallow marine Cambro‐Ordovician succession is well established in the Bancannia Trough in the western Darling Basin but this interval appears to have been ignored in the central Darling Basin where a deeper‐marine environment and suitable kitchen conditions may have provided greater petroleum potential. Data from two shallow wells in the 831 km² study area were available to support the seismic investigations. Seismic sequences were defined by a combination of horizon mapping, the configuration of internal reflections, termination patterns and thicknesses. Six seismic reflection horizons were defined and used to identify five seismic sequences named Units A, B, C, D and E. These features were identified in three seismic lines and demonstrate the continuity of the Scropes Range Formation throughout the NW Blantyre Sub‐basin. All seismic sequence boundaries are based on fair to good continuous markers, with strong amplitudes throughout the study area. The acoustic basement beneath the Scropes Range Formation was metamorphosed in the Delamerian Orogeny (around 500 Ma). Acoustic facies recognized in the three seismic lines can be correlated with sedimentary facies observed in outcrops in the Scropes Range, 130 km west of the study area, and are comparable to acoustic facies in modern fluvial sandstones associated with local braided delta deposits. Complex geological features suggest potential structural and stratigraphic hydrocarbon traps. This study emphasizes the reservoir potential of the Scropes Range Formation in the central Darling Basin where extensive exploration efforts are currently occurring. The detailed interpretation of the seismic stratigraphy may lead to the definition of new exploration plays in this under‐explored region.     

STRATIGRAPHIC CONTROLS ON PALAEOZOIC PETROLEUM SYSTEMS, GHADAMES BASIN, LIBYA

The distribution of oil‐ and gasfields in the Libyan Ghadames Basin is strongly influenced by the stratigraphic architecture of the Silurian‐Devonian succession. This interval encompasses part of two (second‐order) super‐sequences separated by the Caledonian unconformity: (i) a late Ashgillian‐Silurian super‐sequence, comprising the Melez Chograne‐Memouniat periglacial lowstand, the Tanezzuft transgressive to early highstand shales and the Acacus Formation late highstand systems tracts; and (ii) the lower part of a composite Devonian‐Carboniferous super‐sequence terminated by the Hercynian unconformity, which includes the lowstand Tadrart fluvial‐shallow marine sands, the Ouan Kasa (transgressive) and the Aouinet Ouinene transgressive to early highstand systems tracts of Devonian age. Hydrocarbon accumulations in Acacus, Tadrart and later Devonian reservoirs have been charged from a basal Silurian (Tanezzuft Formation) “hot” radioactive shale source rock. The Acacus and Tadrart sandstones provided regional migration conduits sealed by intra‐Acacus, intra‐Devonian (Emghaet Formation) and Permian (Bir Al Jaja Formation) shales. Regional stratigraphic continuity of these migration conduits permitted the development of low to moderate impedance petroleum systems dominated by lateral migration. Basin reconstructions and burial history modelling suggest three expulsion peaks from the basal Tanezzuft Formation source rock, preceding major periods of Hercynian, Austrian and Alpine (mid‐late Tertiary) uplift and exhumation. Hydrocarbons trapped prior to the Hercynian event were dispersed during later periods of structural deformation. Some pre‐Austrian accumulations may have survived locally in more robust traps. However, most if not all of the oil‐ and gasfields discovered in the Late Silurian ‐ Devonian succession were probably charged during the Late Cretaceous—Early Tertiary, only to suffer partial dispersal during later uplift, tilting and flushing. Three petroleum systems can be distinguished within the basin: (i) a Tanezzuft ‐Acacus system to the north; (ii) a Tanezzuft ‐ Tadrart system to the south; and (iii) a Tanezzuft ‐Acacus/Tadrart(+) system in the centre, with some leakage into overlying Devonian and Carboniferous sandstones locally.     

SEDIMENTOLOGY,GEOCHEMISTRY AND RESERVOIR POTENTIAL OF SANDSTONES IN THE SILURIAN AKKAS FORMATION,WESTERN IRAQ

The source rock potential of “hot shales” in the Silurian Akkas Formation in Iraq has been investigated by numerous studies, but the reservoir potential of sandstone intervals in the formation has received less attention. This study investigates the sedimentology and geochemistry of sandstones from the Akkas Formation in the Akkas‐1, Akkas‐3 and KH5/6 wells in western Iraq. The composition of sandstone samples from the Akkas wells is similar; in general they are classified as sub‐litharenites, quartz‐arenites and sub‐arkoses. Scanning electron microscopic analysis identified extensive microporosity and good pore connectivity, suggesting that these sandstones have the potential to form hydrocarbon reservoirs. The sandstones from the KH5/6 well are more lithic‐rich than those from the Akkas wells and are classified as sub‐litharenites. They have larger, more connected pores and better reservoir potential. Low permeability shale intervals within the Akkas Formation and the conformably‐underlying Ordovician Khabour Formation form barriers to hydrocarbon migration into the Akkas and Khabour sandstones. Hydrocarbon migration from the Akkas “hot shales” in the Akkas field is therefore controlled by faulting and fracturing. Petrographic and whole rock geochemical analyses showed that the composition of sandstones in the Akkas Formation is different from that of sandstones in the Khabour Formation. The chemical alteration index ranges from 77.39 to 87.06%, indicating intense weathering of the provenance area before sandstone deposition. The studied samples are texturally mature which indicates good potential for fluid storage capacity. A decrease in feldspar content in the Akkas Formation is attributed to possible recycling of sediments from the Khabour Formation into the Akkas Formation following the Hirnantian glaciation, or to longer distance transportation from the source area.     

THE HYDROCARBON PROSPECTIVITY OF LOWER OLIGOCENE DEPOSITS IN THE MARAGH TROUGH, SE SIRT BASIN, LIBYA

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.     

DEPOSITIONAL ENVIRONMENTS AND RESERVOIR ASSESSMENT OF LATE CRETACEOUS SANDSTONES IN THE SOUTH CENTRAL KIRTHAR FOLDBELT, PAKISTAN

Sandstones of Late Cretaceous (Campanian‐Maastrichtian) age constitute much of the Pab and Mughal Kot Formations, which are well exposed in western Pakistan. In the south central part of the Kirthar foldbelt, these units attain thicknesses ranging up to 350m and are dominated by quartzose sandstones with subordinate argillites and marls, all deposited on the western continental margin of the Indo‐Pakistan Plate. Seven sedimentologic logs, measured through this sandy sequence along a strike‐wise extent of some 290 km, provide new data on the palaeoenvironments and dispersal patterns represented in these rocks and on their reservoir potential. The eight main facies were formed by a range of sand‐transporting mechanisms that includes classical turbidity flows, storm‐ and river flood‐generated underflows, high and low‐energy tractional flows, storm‐ and fair weather wave reworking, and local slope failure and remobilisation. The four facies associations comprise a Shoreface Association, a Shelfal Delta Lobe Association, a Deeper Shelf/Ramp Association (the distal equivalent of the Shelfal Delta Lobe Association), and a deep‐water Submarine Fan Lobe Association. Facies distributions and palaeoflow patterns demonstrate the existence of two depositional systems in this area during the Late Cretaceous. Sandbodies formed in a NW‐prograding submarine fan dominate a southern system, while in the north of the study area, storm‐ and river flood‐influenced shelfal sands were conveyed to the west and WNW. Here, sediment‐gravity flows evolved from east to west, following a broadly across‐shelf pattern from cross‐bedded sandstones to graded turbidites. Sandstone petrography suggests supply from the uplifting Indo‐Pakistan Shield to the east, feeding a broad, west‐facing shelf or clastic ramp characterised by Mutti‐type “shelf‐lobes”. At outcrop, these sandstones possess low porosities but other reservoir characteristics (total sand thickness, percent sand, sand‐body geometry, vertical and lateral connectivity, The authors acknowledge the financial assistance of the Pakistan Science Foundation for the fieldwork. Most of the analytical and laboratory work was carried out at Keele University under the auspices of the Commonwealth Fellowship Scheme. The principal author thanks the Association of Commonwealth Universities for financial support and the School of Earth Sciences and Geography, Keele University, for providing facilities. Special thanks are due to P. Greatbatch, D. Wilde and A. Lawrence (Keele University) for technical and drafting assistance. Andrew Brown (ENI‐Lasmo, London), John Warburton and Simon Beswetherick of Lasmo Oil (Pakistan) Ltd. were most helpful and their sponsorship of new biostratigraphical analyses is also acknowledged. Thanks are due to the Centre of Excellence in Mineralogy, University of Balochistan for granting leave to the principal author. We much appreciated helpful discussions with John Smewing (Earth Resources Ltd, Swansea, UK) and Stuart Burley (BG Group), whose perceptive comments on an earlier draft of this paper were most valuable.     

Hydrocarbon potentiality, burial history and thermal evolution for some source rocks in October oil field, northern Gulf of Suez, Egypt

This paper attempts to apply a one dimensional model on four source rocks (Belayim, Lower Rudeis, Thebes, and Brown Limestone formations), in East Warda concession, October oil field, throughout the different geological times. Moreover, the fundamental aspects of the petroleum system in the study area is evaluated through studying maturation and hydrocarbon potential in order to gain an understanding of onset of oil generation and expulsion. The position of three wells (syn. or pseudo wells) is proposed based on the available geological and thermal data. Also, the existing temperature database is enhanced by using the available temperature data for 220 wells in the Gulf of Suez and the Red Sea, 53 wells in the Mediterranean Sea, 29 wells in the Nile delta, 7 wells in Sinai, 2 wells in Upper Egypt and 39 wells in the Western desert. Finally, the timing of oil generation for Belayim, Thebes, Lower Rudeis and Brown Limestone source rocks in the Northern Gulf of Suez area is updated. From this study we conclude that, the cumulative yield of the Belayim and Lower Rudeis formations is lower than that of the Thebes and Brown Limestone formations.     

MIDDLE MIOCENE DASHAVA FORMATION SANDSTONES, CARPATHIAN FOREDEEP, UKRAINE

Middle Miocene (Sarmatian) sandstones in the Ukrainian Carpathian Foredeep are important exploration targets for natural gas. In this paper, we report on petrophysical studies on core samples of these sandstones with which we integrate wireline log data from 42 boreholes. Sarmation siltstones and sandstones in the study area are assigned to the lower part of the Dashava Formation. Seventeen units (LD 17 to LD 1:0.05 to 5m thick) are recognized in this formation on the basis of lithostratigraphy and log response. Sandstone content is highest within three lithostratigraphic complexes corresponding to units LD17-LD14, LD9-LD8 and LD5-LD3.
During the Sarmatian, the Carpathian Foredeep was characterized by two depositional systems: a basinal turbidite system, and a second, more mixed system. Important controls on sedimentation included basin configuration and water depth, the occurrence of turbidity and other currents, and the location of provenance areas. Clastic material was delivered to the basin by rivers and ephemeral streams mostly from the Carpathian foldbelt. The content of sandy material within the Sarmatian succession increases from NW to SE, and from the central portion of the Krukenychy depression to the margins of the basin.     

LOWER CRETACEOUS PALYNOLOGY AND SANDSTONE DISTRIBUTION IN THE SCAPA FIELD, U.K. NORTH SEA

Three discrete turbidite sandstone bodies form the Scapa Sandstone Member reservoir units within the limestone, marl and conglomerate sequence of the Early Cretaceous Valhall Formation in the Scapa field (UK North Sea Block 14/19). Eighteen palynological zones have been established for the Valhall Formation, designated as VA in the early Aptian through VR in the latest Ryazanian. Scapa reservoir sandstones are restricted to the late Hauterivian VF to early Valanginian VQ zones. Black, anoxic mudstones of the Fischschiefer Member form a widespread intra- early Aptian correlation marker at the base of zone VA in the upper Valhall Formation.
The zonal scheme is based principally on dinocyst distribution, relative abundance and palynomorph associations. Additional micropalaeontological evidence from the top of the Valhall Formation to the top of the Scapa Sandstone Member (zones VA through VF) provides furthrr refinement.
Vertical and lateral variations in the age and abundance of reworked palynomorphs reflect a multisource origin for the Scapa Sandstone Member and deposition via several individually distinct, but coalescing, fan systems. An understanding of sandstone distribution within the Valhall Formation has been determined by the integration of the palynological zonation with wireline log correlation. lithofacies studies and reservoir pressure data.     

Effects of composition, texture and diagenesis on porosity, permeability and oil recovery in a sandstone reservoir

Relationship among depositional texture, composition, diagenesis, porosity, permeability, initial water saturations and residual oil saturations have been investigated in a set of sandstone samples from a North American oil reservor. Pointcount, compositional and textural data obtained from thin sections were used.Grain size, sorting and mineralogy are closely interrelated. As grain size increases, sorting decreases and the proportion of readily soluble detrial grains increases.The type and extent of diagenetic alteration is related to grain size. Silica cement as overgrowths is more common in finer-grained sandstones with abundant monocrystalline quartz, whereas carbonate cement is more common in coarsergrained sandstones. Carbonate dissolution is extensive in some intervals in the reservoir.Sandstone samples were subdivided into tow subgroups in which relationshiops among grain size, porosity and permeability are significantly different: Sandstones with less than 13% porosity are strongly influenced by carbonate cement which controls porosity and permeability, independently of variations of grain size and sorting. Sandstones having porosity greater than 13% have undergone extensive carbonate dissolution, and coarse-grained sandstones have more secondary porosity than the finer-grained due to dissolution of unstable constituents. Both porosity and permeability are positively correlated with grain size in these samples.Initial (connate) water saturation increases with grain size because of the strong correlation between increasing grain size and polycrystalline grains which have intra-grain microporosity. Increasing heterogeneity with increasing grain size is thought to contribute to higher residual oil saturations in coarser-grained, more poorly sorted sandstones. A decrease in oil recovery efficiency with increasing grain size and permeability may be predicted for other sandstone reservoir rocks deposited in similar types of environments.     

ORGANIC GEOCHEMISTRY OF OIL AND NATURAL GAS IN THE WEST DIKIRNIS AND EL‐TAMAD FIELDS,ONSHORE NILE DELTA,EGYPT: INTERPRETATION OF POTENTIAL SOURCE ROCKS

Crude oil in the West Dikirnis field in the northern onshore Nile Delta, Egypt, occurs in the poorly‐sorted Miocene sandstones of the Qawasim Formation. The geochemical composition and source of this oil is investigated in this paper. The reservoir sandstones are overlain by mudstones in the upper part of the Qawasim Formation and in the overlying Pliocene Kafr El‐Sheikh Formation. However TOC and Rock‐Eval analyses of these mudstones indicate that they have little potential to generate hydrocarbons, and mudstone extracts show little similarity in terms of biomarker compositions to the reservoired oils. The oils at West Dikirnis are interpreted to have been derived from an Upper Cretaceous – Lower Tertiary terrigenous, clay‐rich source rock, and to have migrated up along steeply‐dipping faults to the Qawasim sandstones reservoir. This interpretation is supported by the high C₂₉/C₂₇ sterane, diasterane/sterane, hopane/sterane and oleanane/C₃₀ hopane ratios in the oils. Biomarker‐based maturity indicators (Ts/Tm, moretanes/hopanes and C₃₂ homohopanes S/S+R) suggest that oil expulsion occurred before the source rock reached peak maturity. Previous studies have shown that the Upper Cretaceous – Lower Tertiary source rock is widely distributed throughout the on‐ and offshore Nile Delta. A wet gas sample from the Messinian sandstones at El‐Tamad field, located near to West Dikirnis, was analysed to determine its molecular and isotopic composition. The presence of isotopically heavy δ¹³ methane, ethane and propane indicates a thermogenic origin for the gas which was cracked directly from a humic kerogen. A preliminary burial and thermal history model suggests that wet gas window maturities in the study area occur within the Jurassic succession, and the gas at El‐Tamad may therefore be derived from a source rock of Jurassic age.     

DIAGENETIC ALTERATIONS AND RESERVOIR QUALITY EVOLUTION OF LOWER CRETACEOUS FLUVIAL SANDSTONES: NUBIAN FORMATION,SIRT BASIN,NORTH‐CENTRAL LIBYA

Lower Cretaceous meandering and braided fluvial sandstones of the Nubian Formation form some of the most important subsurface reservoir rocks in the Sirt Basin, north‐central Libya. Mineralogical, petrographical and geochemical analyses of sandstone samples from well BB6–59, Sarir oilfield, indicate that the meandering fluvial sandstones are fine‐ to very fine‐grained subarkosic arenites (av. Q₉₁F₅L₄), and that braided fluvial sandstones are medium‐ to very coarse‐grained quartz arenites (av. Q₉₆F₃L₁). The reservoir qualities of these sandstones were modified during both eodiagenesis (ca. <70°C; <2 km) and mesodiagenesis (ca. >70°C; >2 km). Reservoir quality evolution was controlled primarily by the dissolution and kaolinitization of feldspars, micas and mud intraclasts during eodiagenesis, and by the amount and thickness of grain‐coating clays, chemical compaction and quartz overgrowths during mesodiagenesis. However, dissolution and kaolinitization of feldspars, micas and mud intraclasts resulted in the creation of intercrystalline micro‐ and mouldic macro‐porosity and permeability during eodiagenesis, which were more widespread in braided fluvial than in meandering fluvial sandstones. This was because of the greater depositional porosity and permeability in the braided fluvial sandstones which enhanced percolation of meteoric waters. The development of only limited quartz overgrowths in the braided fluvial sandstones, in which quartz grains are coated by thick illite layers, retained high porosity and permeability (12–23% and 30–600 mD). By contrast, meandering fluvial sandstones underwent porosity loss as a result of quartz overgrowth development on quartz grains which lack or have thin and incomplete grain‐coating illite (2–15% and 0–0.1 mD). Further loss of porosity in the meandering fluvial sandstones occurred as a result of chemical compaction (pressure dissolution) induced by the occurrence of micas along grains contacts. Other diagenetic alterations, such as the growth of pyrite, siderite, dolomite/ankerite and albitization, had little impact on reservoir quality. The albitization of feldspars may have had minor positive influence on reservoir quality through the creation of intercrystalline micro‐porosity between albite crystals. The results of this study show that diagenetic modifications of the braided and meandering fluvial sandstones in the Nubian Formation, and resulting changes in reservoir quality, are closely linked to depositional porosity and permeability. They are also linked to the thickness of grain‐coating infiltrated clays, and to variations in detrital composition, particularly the amounts of mud intraclasts, feldspars and mica grains as well as climatic conditions.     

RESERVOIR POTENTIAL OF DEEP‐WATER LACUSTRINE DELTA‐FRONT SANDSTONES IN THE UPPER TRIASSIC YANCHANG FORMATION,WESTERN ORDOS BASIN,CHINA

This paper investigates the reservoir characteristics of deep‐water lacustrine‐delta sandstones in the Upper Triassic Yanchang Formation in the western Ordos Basin, north‐central China. The Yanchang Formation has previously been interpreted as a shallow‐water lacustrine deltaic succession, and this interpretation has been used to guide petroleum exploration activities which have however met with only limited success. The present study integrates thin‐section, wireline log, X‐ray diffraction and SEM data from wells in the western Ordos Basin to determine the sedimentary and diagenetic characteristics of sandstones in the C6 and C4+5 sub‐members of the Yanchang Formation, and to interpret the units' depositional environment. The C6 and C4+5 sub‐members in the study area are composed of: mudstones and fine‐grained sandstones, which are interpreted as deep‐water pro‐delta deposits; laterally‐extensive sand sheets (outer delta‐front deposits); and small‐scale distributary channel and mouth bar sandbodies (inner delta‐front deposits). The sandstones have reservoir potential but diagenesis has had a range of effects on reservoir quality. Compaction together with cementation by calcite and clay minerals including chlorite and kaolinite may have affected pore throat geometry and permeability adversely. However dissolution of feldspars and calcite cement created secondary porosity. Hydrocarbon accumulations may occur in delta‐front channel and mouth bar sandbodies. Core studies show that some sandstone intervals have relatively good reservoir properties with porosity up to 15% and permeability up to 9mD.     

PETROLEUM SYSTEMS MODELLING IN A FOLD‐AND‐THRUST BELT SETTING: THE INVERTED CAMEROS BASIN,NORTH‐CENTRAL SPAIN

The Mesozoic Cameros Basin, northern Spain, was inverted during the Cenozoic Alpine orogeny when the Tithonian – Upper Cretaceous sedimentary fill was uplifted and partially eroded. Tar sandstones outcropping in the southern part of the basin and pyrobitumen particles trapped in potential source rocks suggest that hydrocarbons have been generated in the basin and subsequently migrated. However, no economic accumulations of oil or gas have yet been found. This study reconstructs the evolution of possible petroleum systems in the basin from initial extension through to the inversion phase, and is based on structural, stratigraphic and sedimentological data integrated with petrographic and geochemical observations. Petroleum systems modelling was used to investigate the timing of source rock maturation and hydrocarbon generation, and to reconstruct possible hydrocarbon migration pathways and accumulations. In the northern part of the basin, modelling results indicate that the generation of hydrocarbons began in the Early Berriasian and reached a peak in the Late Barremian – Early Albian. The absence of traps during peak generation prevented the formation of significant hydrocarbon accumulations. Some accumulations formed after the deposition of post‐extensional units (Late Cretaceous in age) which acted as seals. However, during subsequent inversion, these reservoir units were uplifted and eroded. In the southern sector of the basin, hydrocarbon generation did not begin until the Late Cretaceous due to the lower rates of subsidence and burial, and migration and accumulation may have taken place until the initial phases of inversion. Sandstones impregnated with bitumen (tar sandstones) observed at the present day in the crests of surface anticlines in the south of the basin are interpreted to represent the relics of these palaeo‐accumulations. Despite a number of uncertainties which are inherent to modelling the petroleum systems evolution of an inverted and overmature basin, this study demonstrates the importance of integrating multidisciplinary and multi‐scale data to the resource assessment of a complex fold‐and‐thrust belt.     

INFLUENCE OF DEPOSITIONAL ENVIRONMENT ON DIAGENESIS AND RESERVOIR QUALITY: TIRRAWARRA SANDSTONE RESERVOIR, SOUTHERN COOPER BASIN, AUSTRALIA

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.     

低孔渗砂岩石油充注临界条件实验——以西峰油田为例

低孔渗砂岩体油藏在中国油气资源勘探中具有十分重要的地位,但不是所有砂岩体都能成藏,只有达到成藏临界条件的砂岩体才能成藏。现今低孔渗砂岩体物性及流体动力条件不能反映成藏期物性和动力条件,因此,研究成藏临界条件具有非常重要的意义。砂岩样品双轴承压充注实验模拟地层条件下石油充注临界条件,证实了石油充注受临界物性和临界注入压差双重控制。首先,通过测定不同物性样品在不同围压和轴压下的临界注入压差,确定出研究区延长组8段（简称长8段）储层临界孔隙度约为10%,低于该临界值则无论流体压差多高均难以使石油注入砂岩样品。其次,编制多样品临界注入压差随埋深变化曲线,发现物性与临界注入压差具有相互耦合关系。最后,建立了石油充注物性-临界注入压差成藏解释图版,成藏期孔隙度大于10%为有效储层,否则为无效储层。并以研究区典型井为例,较好地解释了长8段砂岩体的成藏过程,该解释图版可作为钻前成藏预测的新方法。     

莺歌海盆地LD15-1构造莺黄组砂岩储层的成岩作用

LD15-1构造位于莺歌海盆地中部坳陷,是由泥底辟引起顶部地层向上拱曲而形成的背斜构造。天然气产自莺黄组中、上部砂岩中。粒间原生孔和粒间溶蚀扩大孔是砂岩中极其重要的储集空间。砂岩的成岩作用主要包括压实作用、胶结作用和溶蚀作用。研究表明,莺黄组地层所经受的成岩作用阶段为早成岩阶段及晚成岩阶段A—B期。溶蚀作用对砂岩成为高孔中渗储层贡献较大。深海盆地水道浊积砂、浅海陆架席状砂是良好的储集砂体。巨厚的烃源岩和良好的储集砂体及其与完整圈闭的有机组合,是莺歌海盆地天然气富集的基本因素。     

K-Ar Dating of Authigenic Illites and Its Applications to the Study of Hydrocarbon Charging Histories of Typical Sandstone Reservoirs in Tarim Basin, China

1. Introduction The Tarim basin in China is a large composite superimposed basin, in which the commercial hydrocarbon flows have been discovered at 10 different stratigraphic intervals: Cambrian, Ordovician, Silurian, Devonian, Carboniferous, Triassic, Ju…