Journal of Petroleum Geology

Published by Wiley
Online ISSN: 1747-5457
Print ISSN: 0141-6421
The Lower Eocene El Garia Formation forms the reservoir rock at the Ashtart oilfield, offshore Tunisia. It comprises a thick package of mainly nummulitic packstones and grainstones, with variable reservoir quality. Although porosity is moderate to high, permeability is often poor to fair with some high permeability streaks.The aim of this study was to establish the relationships between log-derived data and core data, and to apply these relationships in a predictive sense to un-cored intervals. The main objective was to predict from measured logs and core data the limestone depositional texture (as indicated by the Dunham classification), as well as porosity and permeability. A total of nine wells with complete logging suites, multiple cored intervals with core plug measurements together with detailed core interpretations were available. We used a fully connected multi-layer perceptrons network (MLP, a type of neural network) to establish possible non-linear relationships. Detailed analyses revealed that no relationship exists between log response and limestone texture (Dunham class). The initial idea to predict Dunham class and subsequently use the classification results to predict permeability could therefore not be pursued. However, further analyses revealed that it was feasible to predict permeability without using the depositional fabric, but using a combination of wireline logs and measured core porosity. Careful preparation of the training set for the neural network proved to be very important. Early experiments showed that low to fair permeability (1–35 mD) could be predicted with confidence, but that the network failed to predict the high permeability streaks. 'Balancing' the data set solved this problem. Balancing is a technique in which the training set is increased by adding more examples to the under-sampled part of the data space. Examples are created by random selection from the training set and white noise is added. After balancing, the neural network's performance improved significantly. Testing the neural network on two wells indicated that this method is capable of predicting the entire range of permeability with confidence.
An Upper Cretaceous succession has been penetrated at onshore well 16/U-1 in the Qamar Basin, eastern Republic of Yemen. The succession comprises the Mukalla and Dabut Formations which are composed of argillaceous carbonates and sandstones with coal layers, and TOC contents range up to 80%. The average TOC of the Mukalla Formation (24%) is higher than that of the Dabut Formation (1%). The Mukalla Formation has a Rock-Eval Tmax of 439–454 °C and an HI of up to 374 mgHC/gTOC, pointing to kerogen Types II and III. The Dabut Formation mainly contains kerogen Type III with a Tmax of 427–456°C and HI of up to 152 mgHC/gTOC. Vitrinite reflectance values ranging between 0.3 and 1.0% and thermal alteration index values between 3 and 6 indicate thermal maturities sufficient for hydrocarbon generation. Three palynofacies types were identified representing marine, fluvial-deltaic and marginal-marine environments during the deposition of the Mukalla and Dabut Formations in the late Santonian — early Maastrichtian.
Isopach-lithofacies maps, presented in this paper as maps showing depositional axes (depo-axes) for successive informal lithostratigraphic groups of sedimentary units, are applied to outline the tectonic history of Iraq. Five geosynclinal stages are recognistd:(a) Intra-Cratonic Bacinal stage, (b) Early Orthogeosynclinal stage, (c) Late Orthogeo-synclinal stage, (d) Idiogeosynclinal stage and (e) Exogeosynclinal stage. In general, throught those stages, depo-axes were always migrating away from the tectonically-elevated crustal elements during tectomic events and advancing towards them after the lapse of each tectonic pulse when normal sedimentation was resumed. The pattern. History and position of the axes of deposition determined the hydrocarbon migration directions:these were generally from the ENE towards the WSW of iraq.
This study reports aqueous solubilities of crude oil distillation fractions over the carbon number range C1-C34as a function of: temperature (100° to 400° C), pressure (100 to 2,000 bars), NaCl concentration, and gas in solution (N2, CO2, CH4). Experimental parameters were designed so that conditions within a petroleum basin would be duplicated. Increases in temperature increased crude oil solubility, and the higher molecular weight species were affected more positively than lower molecular weight species. Increases in pressure or salinity decreased solubility. The presence of gas in solution increased the solubility of high molecular weight hydrocarbons (> C24) over all temperatures, and increased the solubility of lower molecular weight hydrocarbons at high temperatures (> 180–260°C). Gas decreased the solubility of low molecular weight hydrocarbons at low temperatures. Hydrocarbon solute compositional changes were also examined as a function of the above parameters. At high temperatures, both increasing gas concentration and increasing temperature caused hydrocarbon solutes to become compositionally more similar and eventually identical to the original distillation fraction. The high molecular weight hydrocarbons and saturated hydrocarbons, especially the n-paraffins, were taken into solution in progressively greater concentrations over the aromatic and low molecular weight hydrocarbons. Thus, the strong preferential uptake of low molecular weight and aromatic hydrocarbons into solution at lower temperatures was reversed.
Canada is blessed with numerous large and small sedimentary basins, both onshore and offshore, many of which have hardly been probed for their hydrocarbon potential. Only the most promising aspects of this potential can be highlighted in a brief review such as this, and hence the objectives of the report are (i); to present a regional assessment of the onshore and offshore basins in Canada and to document reservoir units for both conventional and non-conventional hydrocarbon occurrences within the basin fills which may yield significant discoveries in the future (Map 1), and (ii) to emphasize Canada's political-investment environment, and the roles of Petro-Canada, Native Land claims, etc., since most, if not all, of the exploratory targets mentioned require large financial commitments and stable domestic and global conditions. Previous publications provided essential information to substantiate and/or alter views and projections expressed. Only summary papers are referred to in this review, and we apologize to authors whose views we have used but not acknowledged.
Anhydrite, gypsum and halite evaporites of Middle Miocene age occurring in the Gulf of Suez area constitute more than 50% of the total rock components. They are intercalated mainly with shales and also subordinate carbonate and sandstone layers. Examination of several evaporite samples under both binocular and petrographic microscopes reveals the presence of inclusions of various types hosted by gypsum crystals. Solid inclusions are composed mainly of minute calcareous particles, fine pyrite crystals and residual organic matter, while liquid inclusions, which are more frequent, exist in a uniphase or biphase state. A light hydrocarbon in the form of oil or gas constitutes one of these phases, while the other is a brine. Most of these inclusions are of primary origin and have been developed during the growth of the hosted minerals. Based on the assemblage of these inclusions, it can be assumed that the evaporitic environment of deposition, with its reducing condition and high salinity, is favourable for the generation of oil from accumulated organic matter. Also, the presence of a carbonate mineral trapped by gypsum indicates the possible mixing of marine water with a brine of restricted occurrence.
Recent oolites from the Bahama Banks are shown to contain 1.23–4.13 wt% organic carbon of algal origin, chiefly in the form of proto-kerogen. Characterization of the ogranic matter by routine optical and chemical means revealed that, although it is immature, it has a very high potential for generating petroleum hydrocarbons.It is suggested that with rise in temperature due to burial, and perhaps to catalytic influence of the host sediments, this proto-kerogen of algal-amorphous facies would, through time, generate significant amounts of hydrocarbons. In those oolite deposits with adequate porosity, the hydrocarbons could accumulate as petroleum.
The lithofacies distribution of the Permian-Triassic sequence across the Middle East region shows a great diversity of depositional sedimentary facies laterally as well as vertically. During Permian-Middle Triassic time, a clastic-carbonate shelf facies characterizes most of the Middle East region. This platform facies is marked by a number of depositional sedimentary facies which is related to a wide variety of environments, from non-marine, supratidal and restricted marine shelf to open-sea and deeper-shelf deposition. The distribution of the Upper Triassic lithofacies is marked by sharply-differentiated depositional patterns. Except for Iran, N Iraq, SE Turkey and central Syria, the passage from the Middle Triassic to the Upper Triassic in the region is marked either by non-deposition or continental strata, or carbonate-evaporite sequence. Marine, carbonate and shale deposits of open-shelf facies continued to be formed in W Iran, N Iraq and SE Turkey. A large amount of richly fossiliferous clastic, neritic deposits accumulated in central and E parts of Iran. In contrast, a terrigenous-flysch-like sequence continued to accumulate in the extreme NE Iran since early Triassic time.
It has been reported that the upper 400 km of the Earth has outgassed 1015 tons of petroleum-related fluid over the past 300 m.y. Assuming Fischer-Tropsch reactions and crustal entrapment, 0.1% of this quantity can account for the entire amount of petroleum estimated to be in the Earth's crust. An attempt is made to define the past and present nature of this deep source for non-biogenic petroleum. The principal data are seismic, and the nature of the matter found in natural diamonds from continental sources. It is concluded that: 1) diamonds formed over the depth range = or <70 to = or <370 km in a partially molten silicate environment that contained C and H components. 2) From top to bottom, the growth environment ranged from aqueous, carbonate-rich and felsic to aqueous, H-rich and ultramafic. 3) Petroleum and petroleum-forming constituents were present throughout. 4) The depth range of diamond formation correlates with the present depth profile of the suboceanic asthenosphere. It is concluded that this region of the Earth has not changed much since the earliest known time of diamond formation. The discovery of solid hydrocarbon in a diamond cube suggests that the hydrocarbon content of the upper region of the asthenosphere may be twice that indicated by occluded fluid alone. Outgassing of this would have permitted crustal accumulation of = or <105 tons/km2 in a 10 m.y. span of Cainozoic time, consistent with the existence of Cainozoic petroleum fields. By analogy with N2 outgassing, it is estimated that approx 1015 tons of non-biogenic petroleum remain to be outgassed from the Earth.-P.Br.
The Blue Nile Basin, a Late Palaeozoic - Mesozoic NW-SE trending rift basin in central Ethiopia, is filled by up to 3000 m of marine deposits (carbonates, evaporites, black shales and mudstones) and continental siliciclastics. Within this fill, perhaps the most significant source rock potential is associated with the Oxfordian-Kimmeridgian Upper Hamanlei (Antalo) Limestone Formation which has a TOC of up to 7%. Pyrolysis data indicate that black shales and mudstones in this formation have HI and S2 values up to 613 mgHC/gCorg and 37.4 gHC/kg, respectively. In the Dejen-Gohatsion area in the centre of the basin, these black shales and mudstones are immature for the generation of oil due to insufficient burial. However, in the Were Ilu area in the NE of the basin, the formation is locally buried to depths of more than 1,500 m beneath Cretaceous sedimentary rocks and Tertiary volcanics. Production index, Tmax, hydrogen index and vitrinite reflectance measurements for shale and mudstone samples from this areas indicate that they are mature for oil generation. Burial history reconstruction and Lopatin modelling indicate that hydrocarbons have been generated in this area from 10Ma to the present day.
Three superimposed pressure systems are present in the Yinggehai Basin, South China Sea. A number of commercial, thermogenic gas accumulations have been found in an area in which shale diapirs occur. Because the reservoir intervals are shallow and very young, they must have filled with gas rapidly. The thick (up to 17 km) Tertiary and Quaternary sedimentary succession is dominated by shales, and is not disrupted by major faulting in the study area, a factor which seems to have had an important effect on both hydrocarbon generation and fluid migration.Organic-matter maturation in the deepest, most overpressured compartment has been significantly retarded as a result of the combined effects of excess pressure, the presence of large volumes of water, and the retention of generated hydrocarbons. This retardation is indicated by both kerogen-related parameters (vitrinite reflectance and Rock-Eval Tmax); and also by parameters based on the analysis of soluble organic matter (such as the C15+ hydrocarbon content, and the concentration of isoprenoid hydrocarbons relative to adjacent normal alkanes).In contrast to this, organic-matter maturation in shallow, normally-pressured strata in the diapiric area has been enhanced by hydrothermal fluid flow, which is clearly not topography-driven in origin. As a result, the hydrocarbon generation “window” in the basin is considerably wider than could be expected from traditional geochemical modelling.These two unusual and contrasting anomalies in organic-matter maturation, together with other lines of evidence, suggest that there was a closed fluid system in the overpressured compartment until shale diapirs developed. The diapirs developed as a result of the intense overpressuring, and their growth was triggered by regional extensional stresses. They served as conduits through which fluids (both water and hydrocarbons) retained in the closed system could rapidly migrate. Fluid migration led to the modification of the thermal regime and the enhancement of organic maturation, as well as the accumulation of commercial volumes of gas in a relatively short time interval.
The role played since the Early Jurassic by the Marda Fault Zone (MFZ) in the geodynamic evolution of the Horn of Africa is examined. Three main stages of evolution have been recognized: (a) a Tethyan stage (Jurassic/Early Cretaceous): (b) an Indian stage (Late Cretaceous/Eocene); and (c) an Arabian stage (Oligo-Miocene/Resent). During the Tethyan stage (which is characterized by the distribution of fauna with a Tethyan affinity), the MFZ probably acted as a major deep- rooted transfer fault, connecting overstepping segments of en-éhelon east-west strike-slip faults. Crustal stretching, caused by the southwards drift of Madagascar, was active in the SW region of the Horn of Africa. but was relatively negligible in the NE region. During the Indian stage (involving the NEwards drift of India), the MFZ was still aligned, in the Late Cretaceous, with the paleo-margins of the Red Sea — bgore the rotation of Arabia away from Africa — and with the oceanic spreading ridges developed in the Mascarene Basin of the Indian Ocean. It was in this stage that the MFZ is interpreted as having acted as an incipient aborted rift, causing the rapid subsidence of the NE region of the Horn of Africa, and consequently the onset of a new depositional cycle. During the Arabian stage (separation of Arabia from Africa), there was a sudden change in the geodynamics of the Horn of Africa: crustal stretching of the Red Sea — Gulf of Aden —Ethiopian Rift Valley triple junction occurred, leaving the segment of the MFZ in the Horn of Africa inactive. These three stages correspond with three important tectonic changes in the Indian Ocean and the Western Mediterranean Region.
The occurrence of methane and heavier homologues and unsaturated hydrocarbons was recorded in 226 soil gas samples recovered from a study area in the Pomeranian Synclinorium, NW Poland. Samples were collected at stations located along three survey lines (I–I', II–II’ and III–III') at a 200 m spacing. Concentrations of methane, total alkanes (C2-C4) and total alkenes (C2-C4) reached 13.7 vol. %, 18.4 ppm and 0.56 ppm, respectively. Soil gas alkanes heavier than methane were interpreted to be derived from subsurface hydrocarbon accumulations. These hydrocarbons migrated up into the near-surface zone along structural discontinuities and fractures which were observed on seismic profiles. The migration rate of hydrocarbons from subsurface accumulations towards the surface was determined by the ethane/ethylene (C2/C2=) ratio. The statistical distribution of the ethane:propane (C2/C3) ratio and plots of the C2/C3+C4 and C1/C2+C3 ratios indicated that accumulations of condensate, gas or oil with a gas cap probably occur in the study area. Variations in normalized values of total alkane C2-C4 concentrations allowed surface geochemical anomaly zones to be identified. These anomaly zones were evidence for the occurrence of subsurface hydrocarbon accumulations. Hydrocarbon accumulations are most likely to occur beneath the central part of profile II–II' and may also occur in the SW and NE parts of profile III–III' where both the Carboniferous and the Zechstein Main Dolomite are prospective. In these areas, hydrocarbon accumulations may occur in fault-bounded anticlinal highs. Surface geochemical anomalies also confirm the presence of a non-commercial hydrocarbon accumulation in the Main Dolomite which was discovered by the D-1 well, and the possibility of another subsurface accumulation in an adjacent tectonic block. Soil gas analyses combined with seismic data provide evidence for the hydrocarbon prospectivity of the study area.
Substantial published and unpublished data contradict accepted laws of organic metamorphism. Significant amounts of C15+ hydrocarbons and kerogen with significant generation potential exist in sediments which have been buried at high temperatures for long periods of geologic time. Graphite formation and greenschist metamorphism do not occur at model-predicted burial times and temperatures. Maturation levels for sediments with long (up to 240Ma) burial times are much lower than expected, and conversely, higher than expected for sediments with short (2Ma) burial times. The threshold of intense petroleum generation is not detectable in Plio-Miocene sediments at minimum temperatures of 160oC. Contrary to accepted thought, there is no evidence from the natural system that petroleum generation-maturation reactions have first-order reaction kinetics. By contrast, a substantial body of evidence from petroleum generation-maturation laboratory studies carried out in closed water-wet systems show that these reactions are characterized by multiple-order reaction kinetics. Geologically older sediments clearly tend to be more organically mature than younger sediments at the same burial temperatures. However, this correlation is more a reflection that older sediments have had a greater chance of being affected by a major geologic event with an accompanying high heat flow. The major conclusions of this paper are that: 1) geologic time has no observable effect on organic metamorphism; 2) vitrinite reflectance can be used as an absolute paleogeothermometer; 3) the accepted models of organic metamorphism at the very least need substantial revision. -from Author
Before replying to James Kohsmann's discussion of the Price (1983) paper, I wish to correct two errors in that paper. In the abstract I stated: "The threshold of intense petroleum generation is not detectable in Plio-Miocene sediments at minimum temperatures of 160°C" (Price, 1983, p. 5). I should have said ". . . in Pliocene and Miocene sediments with hydrogen-rich organic matter at minimum temperatures of 160°C." In the Fig. 19 caption, in a classic demonstration of Murphy's Law, a line was dropped during printing so that the last sentence of that caption read: "This equation can only be applied to coals or rocks with Type I organic matter". The sentence should have read: "This equation can only be applied to coals and rocks with Type III organic matter. It cannot be applied to rocks with Type I organic matter."+
This paper proposes that plate-tectonic processes do not necessarily cause continental drift, and that sialic blocks the size of Australia or larger are fixed relative to eachother. Continental drift has not yet been geodetically demonstrated and the geologic evidence for it has been repeatedly challenged or refuted. New lines of evidence presented here against drift include: absence of the low-velocity zone under Shields; deep continental lithospheric roots; absence of continental hot-spot trails; absence of significant offset between Greenland and Ellesmere Island; internal contradictions in paleomagnetic data, and between paleomagnetic and paleogeographic data; Cenozoic tectonism and horizontal compression at supposed passive margins; and absence of an adequate plate-driving force for plates with continental (non-subductable) leading edges. The hypothesis of plate tectonics with fixed continents predicts that high-precision geodetic measurements now in progress will find no separation of Eurasia and North America no matter how long they are continued. It implies some form of slow subduction at supposed passive margins such as the east coast of North America.
Detailed petrographic studies of Recent dolomites from the coastal sabkha of Abu Dhabi using SEM and Energy Dispersive X-ray (EDX) analyses indicate that most of the dolomite started to form in “micro-niches” (i.e. small isolated pore spaces) within the carbonate sediments. These micro-niches tend to retain connate waters, becoming anoxic and supporting specific microbial activity which ultimately results in the formation of dolomite. This novel concept may help to explain the origin of many dolomite types, since recently deposited carbonate sediments have high porosities (up to 60%) and the pore spaces may serve as nucleation sites or “stations” for dolomite formation. The combination of neighbouring micro-niches in a porous carbonate may result in dolomitization of an entire stratum. Six dolomite types were reported from the studied sediments in the Abu Dhabi sabkha. These were pustular and cluster dolomite; dolomites associated with clay minerals and with evaporites; and dolomites associated with microbial mats and foraminiferal tests.
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.
Source rock abundance through geological time cannot be measured in absolute quantitative terms. The source rocks of giant fields, which are known in most cases, can serve as an appropriate yardstick for a percentage allocation of source rocks to geological time intervals, based on ultimately recoverable reserves. This yardstick is used to relate source rock percentages per time interval to in situ reserves and resources of oil and gas worldwide, both conventional and unconventional. Necessary corrections are made. On this basis it appears that the Cretaceous is the most important oil-generating period (49%), while the Tertiary is the most important gas-generating period (76%). For total hydrocarbons in terms of oil equivalents, the most important hydrocarbon-generating intervals are the Tertiary (69%), followed by the Cretaceous (25%), the Jurassic (4%) and the Triassic to Paleozoic (2%). The percentages refer to source-rock age and not to time of generation. All estimates have to be regarded with much caution. They represent an approach to the problem rather than a solution. Major uncertainties still exist. It must be stressed that the problem of source rock abundance should be seen in a wider hydrocarbon habitat context, especially in the light of retention. The important role of bacterial gas and gas hydrates is emphasized.
The main oil-and gasfields of Venezuela.  
Structural elements of the Gulf of Paria pull-apart basin (see location in Fig. 1). Metamorphic rocks in the Paria Peninsula continue in the Northern Range of Trindad. Cretaceous rocks of the Interior Range of Venezuela (Fig. 1) continue beneath thin cover in the north, but lie deeply buried beneath in the south. The thrust front of the Interior Range in Venezuela corresponds to the Central Range of Wnidad. The Southern Range of M d a d is the eastward continuation of a diapairic trend that begins in the Maturin Basin.  
Compilation of kitchen areas reported in the literature for Upper Cretaceous source rocks (La Luna and Querecual Fms). These limited areas, the earliest of which developed in the Eocene, are not sufficient to have supplied Venezuela's huge petroleum resources, which amount to around 1.5 trillion brl oil.  
Palaeogeographic reconstruction for the Early-Middle Eocene. The Mirador and Misoa Formation sandstones form important, quartz-rich reservoirs in the west, in Colombia's Llanos Basin (Fig. 1) and in the Maracaibo Basin. Rivers draining north from the Guayana Shield must also have deposited large quantities of sands in the east. Oil generated during Late Cretaceous - Eocene orogeny could have been housed in such reservoirs.  
Venezuela's most important hydrocarbon reserves occur in the intermontane Maracaibo Basin and in the Eastern Venezuela foreland basin. Seeps are abundant in these areas. Lesser volumes occur in the Barinas-Apure foreland basin. Most of the oil in these basins was derived from the Upper Cretaceous La Luna Formation in the west and its equivalent, the Querecual Formation, in the east. Minor volumes of oil derived from Tertiary source rocks occur in the Maracaibo and Eastern Venezuela Basins and in the Falcdn area.
Uncertainties remain concerning the common assumption that economic oil pools result only from deep, catagenic oil generation. These uncertainties stem from the many geological criteria that point to early oil entrapment and, furthermore, from the failure to resolve problems of oil migration out of, and through, consolidated sediments. Early oil emplacement is indicated by the preferential charging of paleostructures, inhibition of diagenesis and compaction by reservoired oil, folded oil-water contacts, and by evidence supporting the immaturity of huge heavy-oil deposits. The uncemented and uncompacted nature of the Athabasca “tar sands”, the perfect preservation of fossil wood within them, and the tilted oil-water contacts at the Athabasca, Peace River and Cold Lake accumulations, support geological deductions of very-early oil emplacement, and geochemical criteria for its immaturity. If such huge volumes of oil are immature, this would be in harmony with geological observations which conclude that pools of mature oil most probably result from in-reservoir maturation of early-expelled, biogenically-generated heavy oil and methane. Hydrocarbons that remain in source rocks are maturated during burial, but are immobilised by progressive loss of effective permeability.
Condensates are present in the PY30–1 structure in the Panyu Uplift, Pearl River Mouth Basin. Biomarkers and compound-specific stable carbon isotope ratios of three condensate and two source rock samples indicate that the condensates were generated by lacustrine mudstones and coals in the Oligocene Enping Formation with a minor contribution from mudstones in the Eocene Wenchang Formation. Elevated vitrinite reflectance values, high smectite-illite transformation ratios, and elevated fluid inclusion homogenization temperatures (about 100®C higher than normal borehole temperatures) point to the influence of hydrothermal fluids at the PY30–1 structure. Hydrocarbon migration was found to have occurred at the same time as hydrothermal activity. Modelling of formation pressure evolution in the Wenchang and Enping Formation source rocks in the Baiyun Depression, adjacent to the south of the Panyu Uplift, suggest that there were three episodes of overpressure release at approximately 40–37 Ma, 33–31 Ma and 16–10 Ma. Overpressure release was probably induced by uplift and erosion during the Zhuqiong, Nanhai and Dongsha phases of tectonic deformation, respectively. The third episode of overpressure release coincided with the main phase of hydrocarbon migration. The accumulation of condensates at the PY30–1 structure probably followed hydrocarbon expulsion from source rocks as a result of overpressure release in the adjacent Baiyun Depression. Vertical migration into overlying reservoir rocks occurred through faults associated with a fluid diapir which is present at the core of the PY30-I structure. The faults are pathways along which petroleum can migrate up to shallow reservoirs.
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.
Location map of the studied region.
Profile sections across the Zagros Range of SW Iran showing variations in configuration of the depositional basins, based on isopach maps in Falcon ( 1958). I: Middle Miocene; 2. Oligocene -Lower Miocene; 3. Upper Cretaceous -Eocene, 4: Lower · Middle Cretaceous.
Schematic sectio~ in the Zagros • Taurus orogenic belt, illustrating the relationship between the gcowarpings and the various tectonic elements in the region.
Megascale monoclinal flexures (“geowarpings”) with maximum angles of dip ranging from 5° to 13° occur in the Zagros-Taurus range of Iraq and Iran. They face south and SW, with amplitudes of 1.4 to 14.44 kms and axial lengths of 43 to 230 kms. Their axes are parallel to the host mountain range and lie in an en échelon configuration, and many are located in the high mountain zone, at or close to the mountain front (i.e. the border with the foothills zone). Neotectonic and stratigraphic evidence suggests the contemporaneous development of these flexures with their host fold-belt during the collision of the Eurasian and Afro-Arabian Plates, which culminated during Upper Miocene-Pliocene time. Differential vertical movements caused greater shortening and thickening in the upwarded regions (10–33%), which lie closer to the plate suture zones, compared to the downwarped regions (3–17%). Development of the geowarpings resulted in circumstances favourable for hydrocarbon generation in downwarped regions, where source rocks were buried sufficiently deeply to produce oil and gas; this then migrated upwards to be trapped in the growing folds, and was sealed by Miocene evaporites. On the other hand, upwarped regions were elevated, and suffered extensive erosion, leading to a reduction in the depth of burial of potential source rocks, and consequently limited possibilities of hydrocarbon generation. Furthermore, the non-deposition and/or erosion of Miocene evaporites in upwarped regions led to the dissipation of considerable volumes of the hydrocarbons which might have been generated. The effect of geowarpings on oil and gas reserves is evident from the distribution of oil- and gasfields, which are almost exclusively located in the downwarped foothills zone. Geowarpings may be located in the Taurus Range of E Turkey and NE Syria, but a lack of accurate data makes this difficult to investigate. Further studies are needed to develop an efficient exploration plan for oil and gas in that area.
Published data from an organic geochemical study of Recent oolites from the Bahamas and teh kPersian Gulf suggest that petroleum‐bearing oolites may be the source, as well as the reservoir, of the hydrocarbons they contain. This paper advances a scheme for the generation of leached oolites with oomodic porosity, petroleum‐bearing oolites could be viewed as integrated source‐resrvoir rocks.
The occurrence of oil-and gasfields in overthrust belts follows the same principles that operate in normal basins. There is no essential difference, and, in order to avoid any personal bias or dogma, examples of productive areas in overthrust belts should speak for themselves. The examples below are selected only on the basis of available data. More examples would improve understanding but would not change the basic principles described. Unfortunately, the most convincing examples are locked away in company files.
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.
Large quantities of immature and low-maturity oil have been discovered in the North Jiangsu Basin, East China. Intense tectonic activity and the differential accumulation of immature oils during the Palaeogene have resulted in reservoir rocks which have variable sedimentary and diagenetic characteristics. Studies of oil geochemistry and reservoir diagenesis suggest that oil generation and accumulation took place early in the basin's history (i.e. during early diagenesis), significantly inhibiting later modification of the reservoir rocks. There has been no large-scale tectonic activity since the oil pools formed, and the reservoirs' petrophysical properties and pore construction therefore reflect early diagenesis. Diagenetic modification of the reservoir rocks was more intense below the oil-water interface where oil did not accumulate. Alteration in these rocks included calcite cementation, the formation of quartz overgrowths, and the development of pressure solution.
A total of six giant gasfields each with proven reserves of more than 100 billion cubic metres are present in the Ordos and Tarim Basins, China. The gasfields are Sulige, Yulin, Wushenqi, Da'niudi and Jingbian in the Ordos Basin, and Kela 2 in the Tarim Basin. In this paper, we report on the geochemical characteristics of the natural gas at these fields based on studies of gas composition (150 samples), together with stable isotope data (143 samples) and helium isotope data (21 samples). Results show that the gases have high contents of C1-4 alkanes (generally over 90%) and minor contents of CO2 (below 3%). The generally high δ13C values of C1-C4 hydrocarbons indicates a significant contribution from humic source rocks such as Permian-Carboniferous and Mid-Lower Jurassic coal measures. δ13 C1, δ13C2, δ13C3 and δ13C4 values for gases in Upper Palaeozoic reservoirs were -35 to -32‰, -28 to -24‰, -27 to -24‰, and -23.5 to -22‰, respectively. The δ13CiC4 value is higher than that of the δ13CnC4•He3/He4 ratios vary from 10-7 to 10-8, indicating that the helium is of crustal (as opposed to mantle) origin. The CH4/ He3 ratio is 1010 - 1011, indicating that the CH4 is of biogenic origin. None of the data is consistent with an abiogenic origin for gas in the Ordos Basin.
A number of commercial hydrocarbon accumulations, which include oil and gas, are now known in southern England. Investigations into the organic maturity and hydrocarbon potentials of sedimentary rocks in the area suggest that the Jurassic Lias, Oxford Clay and Kimmeridge Clay units are the most probable sources for these hydrocarbon accumulations. The Lias on the southern side of the Purbeck-Isle of Wight Disturbance appears to be the main source of the Dorset oils (Wytch Farm and Kimmeridge Bay) on the bases of adequate maturity, n-alkane distribution, alkane ratios and stable carbon and hydrogen isotope ratios. On the basis of organic maturity, the oil accumulations in the Weald and the adjacent Hampshire areas are considered to be composed of varying contributions of bitumen generated from the three Jurassic source formations. Application of the modified Lopatin method of basin modelling suggests the Lias in the Weald as the probable source for the natural gas deposit at Godley Bridge in Surrey and predicts a possible Liassic sourced wet-gas field in the Dorset-Isle of Wight area.
The evolution of the Earth's atmosphere has been explained by a diffusion model that obeys first order kinetics. By assuming that the same rate law governs the diffusion of petroleum compounds that are known to exist in the upper mantle, we find that 1.5 × 1015 tons have diffused out during the past 3.1 billion years. If 0.1% of this primordial petroleum has undergone crustal migration and entrapment, deposits totalling 1.5 × 1012 tons are now present in the Earth's crust. Assigning a 0.3 recovery factor, this is equivalent to about 3 trillion barrels.
The accumulation of natural gas in commercial volumes is a function of the dynamic equilibrium between its rates of generation and dissipation. It is proposed here that four fundamental factors control the formation of gasfields: two relate to generation, and two to dissipation. Details of these four factors are discussed. It is suggested that there exist plentiful supplies of “young” gas, located in relatively stable structural environments during post peak-generation stages, retained in place by efficient seals.
Numerous deep seismic and borehole studies have been made in the Dnieper-Donets Paleorift (Ukraine), and, when combined with studies of oil- and gasfield distribution, indicate that there exists an interesting relationship between deep lithospheric structure and evolution, and the hydrocarbon potential of the Paleorift. It has been found that hydrocarbon accumulations tend to be associated with slopes in the Moho discontinuity, where most faults are located, and also where the basement and the lower layers of sedimentary cover have been fragmented by faults. These areas are the most promising for exploration. These facts could imply an abiogenic, mantle origin for oil and gas. Alternatively, the hot mantle ascending beneath the Dnieper-Donets Paleorift may have created thermodynamic or fluid-flow conditions within the sedimentary cover which were favourable for the transformation of biogenic material into oil and gas. In this case, mantle fluid-flow along faults assisted the migration of hydrocarbons and its accumulation in traps.
Fluid inclusions in halite and bitumens in rock salt in Upper Permian Zechstein evaporites in West Poland were studied in locations where the evaporites lie above oil and gas reservoir rocks. The samples were taken from halite intercalated within the Basal Anhydrite; this unit lies above the Main Dolomite which serves as both source rock and reservoir. Samples came from a depth of 2.3–3.2 km. A characteristic feature of the fluid (gas-brine) inclusions was their high methane content together with the occasional presence of bitumen globules of near-spherical form. Geochemical analyses of the bitumen in bulk samples of rock salt (including content and distribution of n-alkanes and isoprenoids, and carbon isotope ratios) suggest an algal origin, similar to that of the oil in the underlying source rocks. For comparison, we studied fluid inclusions in halite from Zechstein evaporites in northern Poland, where hydrocarbon accumulations do not occur in underlying strata and where mostly single-phase (brine) inclusions with a low methane content have been recorded. However, published data indicate that similar inclusions to those occurring in the Zechstein of West Poland (comprising brine with a high methane content, bitumen films and/or oil droplets) are present in other salt-bearing sequences, where their origin is related to the thermal degradation of organic material dispersed within the salt itself. Accordingly, such fluid inclusions in an evaporite succession can only be considered to form a geochemical aureole where the bitumens in the rock salt (including those in the fluid inclusions in halite) can be compositionally linked to those in the associated oil accumulation.
Tectonic activity offshore China during the Late Miocene and Quaternary (“neotectonism”) generated unconformities, resulted in depocentre migration, created new faults and initiated earthquake activity. This episode of structural disturbance, which occurred during post-rift thermal subsidence, modified pre-existing hydrocarbon accumulations and formed new pools. Constructive effects of neotectonism occurred in the Bozhong Depression, Zhu #2 Depression and the Yinggehai Basin. These effects included the formation of new structural traps, migration routes and source kitchens. Destructive effects occurred in the Xihu Depression where oil/gas fields were partially breached by post-trap peneplanation and faulting. There are pools with active gas leakage through neotectonic faults and this seems to suggest a dynamic balance between outboard leakage of gas and inboard migration of hydrocarbons. This paper summarizes understanding of the past 15 years of offshore exploration in China which has primarily focused on Neogene reservoirs. Data used for this report include extensive coverage of conventional P-wave and multi-component 2D and 3D seismic data, drilling results and extensive geochemical and geological analyses.
The general concept of petroleum formation by biogenic mechanisms has been firmly entrenched for a long time, but there has been no accumulation of convincing experimental evidence in support of this belief. If, on the other hand, a juvenile origin is considered, rigorous mathematical and experimental treatments are possible. This is done here. The mathematical foundation of the juvenile petroleum model is drawn from the model that has quantitatively explained the formation of the atmosphere, the oceans, and surficial carbonaceous matter by outgassing of the Earth. Experimental data for the abundance of juvenile precursors of petroleum — H2, CO, alcohols and hydrocarbons — are obtained from diamond carriers which crystallized in the upper mantle 3.1 billion years ago. The correlation that exists world-wide between the distribution of petroleum accumulations and regions that have experienced diastrophism is interpreted as demonstrating a direct relationship between plate tectonics and channels of precursor outflow from the upper mantle to crustal traps. The conversion of precursors to petroleum is assigned to maturation processes. The theoretical coefficient of juvenile petroleum production is compared with coefficients of petroleum accumulation derived from published data on 78 giant petroleum accumulations. Agreement is found in all cases. The various “proofs” of a biological origin for petroleum are examined and found to be inconclusive. It is concluded that recognition of a mainly juvenile origin has been clouded by traces of biologically-derived compounds and fossils that are merely intrinsic to the sedimentary nature of “source rock” and reservoirs. Limitations of the juvenile petroleum model and its possible value for petroleum exploration are discussed.
A modelling study aimed at providing a better understanding of the hydrocarbon accumulations on the SW flank of the Dead Sea graben in Israel has been performed. It considers the recent geochemical finding that the source rock of the hydrocarbon occurrences in the area is the Senonian bituminous chalk and marl, buried in the central Dead Sea graben. The study investigates the effect of the regional geological and hydrogeological conditions, associated with the physical properries of the rock and fluids, on the migration and types of hydrocarbon accumulations. The investigation was performed by means of a three-phase, two-dimensional, numerical reservoir simulator. Typical cross-sections, through potential anticlinal hydrocarbon traps, were considered. The study analyses possible hydrodynamic flushing in the water-flow direction, as well as counter-current migration in a direction opposite to the potentiometric water gradients, from the Dead Sea graben upwards. In addition to conventional hydrodynamic traps. the study includes the case of downdip entrapment due to low permeability regions. It is concluded that: (i)from the hydrodynamic point of view, the easiest oil migration path is through Paleozoic — Triassic formations: (ii) the high water salinity of these beds facilitates the up-structure oil flow in a direction opposite to the water current movement: (iii) the Jurassic beds are probably impregnated by oil and gas coming from Triassic strata through faults: (iv) undiscovered structural traps are likely to contain mostly gas; and (v) down-faulted blocks adjacent to sealing faults. or to low-permeable regions (including permeable faults), are potential oil traps.
A-form (megalospheric) nummulite morphology (after Racey, 1992).
Lithostratigraphic correlation for offshore Tunisia and offshore Libya, showing the approximate relative positions of the nummulitic reservoirs of the El Garia Formation (Tunisia) and the Jdeir Formation (Libya).  
Eocene nummulite accumulations, also referred to as nummullte “banks”, form Important hydrocarbon reservoirs in Tunisia and Libya and may constitute exploration targets in other parts of North Africa, the Mediterranean and the Middle East. Porosities commonly average 10–20% and permeabilities 10–50md. Foraminifera of the genus Nummulites may comprise up to 98% of the bioclasts in these carbonate reservoirs, although only one or two species may be present. The absence of associated fauna is generally taken to indicate an oligotrophic depositional environment. In this paper, the palaeoecology of the genus Nummulites is discussed together with depositional models for two nummulitic carbonate reservoirs — the Middle Eocene Seeb Limestone of Oman and the Early Eocene El Garia/Jdeir Formation of Tunisia and Libya. The El Garia and Seeb Limestone Formations were deposited in ramp settings, and comprise a series of amalgamated sheets or low-relief banks. In the Hasdrubal field offshore Tunisia, where the El Garia Formation constitutes the reservoir rock, most of the nummulites have been redeposited from shallow into deeper waters whilst in the Bourri field (offshore Libya) they occur as an in situ “bank”. Nummulite accumulations often show evidence that both physical reworking (scouring, winnowing and imbrication) and biological processes (reproduction strategies and bioturbation) have influenced their formation. A general model is outlined for discriminating between physically and ecologically produced biofabrics, and the implications for reservoir quality are discussed.
The Upper Jurassic Bazhenov Formation in the central West Siberian Basin is a classic marine black shale unit containing abundant Type II kerogen with high oil-generation potential. These shales source around 90% of the oil in the West Siberian Basin. They also contain oil accumulations in unconventional self-sourced reservoirs. Reservoir zones are generally small and are located along fault planes. Primary oil migration was focused along fracture networks adjacent to the fault zones. Oil charging took place in the Tertiary and oil generation and expulsion in the Bazhenov Formation led to overpressuring. In the study area between the Surgut and Nyalinsk arches in the centre of the basin, faulting and fracturing took place in Eocene to Quaternary time. The faulting led to local increases in the thermal maturity of the Bazhenov Formation. Exploration risk in the self-sourced Bazhenov Formation reservoirs mainly relates to seismically-defined regional faults or to transverse faults.
Rayleigh-Taylor instabilities occur when low-density layers of viscous fluids are overlain by denser layers. Gravity overturn of such instabilities leads to the rise of the unstable light (source) fluid as diapirs (e.g. of salt) through the denser (overburden) layers (e.g. of clastic sediments). Lateral extension or movements of faults in the bottom boundary at any stage during such gravity overturns are expected to have a great effect on the geometry, growth rate and location of any salt structures. Two groups of material models, each consisting of three series, were used to study the effect of uniform extension, and the non-uniform extension due to reactivation of pre-existing basement faults, on gravity-driven overturns at different stages. The model results are used to comment on recent interpretations of how halokinesis and extension interacted in the North Sea.
The area reviewed covers some 825 000 sq.kims. Since the early 1960s, 52 exploration wells have been drilled in the Red Sea, leading to four undeveloped (mainly gas-condensate and dry gas) discoveries; twelve exploration wells have been drilled in the Gulf of Aden since the late 1970s, leading to one undeveloped oil discovery. Numerous surface oil seeps in the Red Sea testify to oil generation, while many of the drilled wells have also had shows. The syn- and post-rift Neogene stratigraphy of the Red Sea is very similar to that of the prolific oil-producing Gulf of Suez graben, with source, reservoir and sea rocks widely present; pre-Neogene rocks, however, are only present in patches, and include some marine Paleogene and Late Cretaceous sediments on older continental clastics in the northern half, and marine Jurassic on Basement in the southernmost sector. The tectonic evolution of the two rift basins is here discussed, and evidence for the areal extent of oceanic floor or stretched continental crust, for episodic or continuous extension and sea-floor spreading, and for pre-rift doming and fracturing, is reviewed. It is concluded that episodic extension and spreading have occurred, and may be more advanced in the Gulf of Aden than elsewhere. Hydrocarbon play in the Red Sea is principally Neogene, and traps are provided by rotated Basement fault-blocks and horsts in the pre-evaporite sequence, and by salt flowage and piercement, together with stratigraphic pinch-out, in the post-evaporite sequence. In the Gulf of Aden, the main play is in the pre-rift Paleogene sequence. -from Author
Successful hydrocarbon exploration in frontier basins of the developing world is mutually beneficial to the oil industry, and for the economic development of the country concerned. Exploration has proved to be difficult when the basin is overlain by two or more countries. A market survey of the petroleum industry indicated that, to be successful, promotional efforts should include the entire frontier basin rather than one part of it. The Red Sea/Gulf of Aden Basin was chosen by the World Bank as a prototype of regional basin promotion for reasons both of geology and economic development.Following detailed discussions with the seven governments involved, and the industry likely to be interested, a detailed work plan was produced. Funding came from several donor agencies. Specialized analytical investigations were undertaken with respect to source-rock geochemistry, palaeontology, sedimentology and heat-flow studies.Pivotal to implementation was the provision of data from the governments. The presence of the World Bank as an intermediary between governments and industry provided the required clarity and transparency for the process, free of normal confidentiality issues. The participating governments have expressed a strong desire to preserve the results through the conversion of the project work-station in Cairo into a regional research centre.
The Gulf of Aden rifting predates that in the Red Sea. Sea-floor spreading began in the late Miocene and progressed westward into the Afar region. Only limited faulting has affected the post-rift, uppermost Miocene to Recent section, which is primarily dominated by prograding sequences and thermal subsidence. The wells drilled to- date have encountered source, reservoir and seals in both the pre-rift and syn-rift section. Heat flow and thermal modelling has shown that the Gulf of Aden continental margins are not areas of excessive heat flow, and hydrocarbon-generative "kitchens' can be mapped in the pre-rift sequence. The hydrocarbon prospectivity of the Gulf of Aden differs from that in the Red Sea in that the primary hydrocarbon plays are found in the pre-rift sequences. -from Authors
Onset of rifting, and flooding by marine waters, occurred in the late Oligocene in the Gulf of Aden and southern Red Sea. The northern part of the Red Sea may have been a largely continental rift at this initial stage, but continued rifting established marine conditions throughout the system by the early Miocene. Episodic isolation of the Red Sea system, leading to evaporite deposition in some basins, commenced in the mid-Miocene and over two kilometres of salt had accumulated in most Red Sea basins by the end of the Miocene. Re-establishment of persistently-marine conditions occurred in the Pliocene, and marine recharge is now sufficiently high to permit vigorous carbonate build-ups in shallow-water areas. Clastic sediment textures suggest that marginal escarpments, which first developed during the onset of rifting, were strongly uplifted in the Pliocene-to-Recent period. Subsidence of basin floors seems to have been particularly rapid during the period dominated by salt deposition. If eruption of sea-floor basalts in the axial rift areas is excluded, volumetrically important volcanism is centred on the present Afar triangle area, and is confined to the Oligocene and early Miocene. The amount of contemporary volcanic débris in the sandstones is consequently not particularly high. Some sandstones in northern Ethiopia, Sudan and Egypt do contain abundant acidic volcanic clasts, but these are derived from the Proterozoic basement and cause less diagenetic reservoir damage than contemporary glassy volcanic ash. Sandstones deposited in freely-drained alluvial fan settings are characterised by early diagenetic kaolinite, whereas those of sabkha and marginal-marine settings tend to show relatively early diagenetic chlorite. Those alluvial fan sandstones which were subsequently invaded by reduced pore waters expelled from the basin axis, and those in the basin axis, often developed later diagenetic chlorite.
Stratigraphic results from eight offshore exploration wells drilled between 1979 and 1983 are described, and the successions penetrated are compared with the adjacent land outcrops and facies; these are also depicted in lithostratigraphic correlation charts/sections for the area. The Oligo-Miocene Shihr Group is divided into formations which are described and correlated between the wells, and a new post-Shihr formation is likewise described and correlated. Mesozoic succession thickness variations or erosion cut-outs and syn- and post-rift sediment thickness increases in some of the wells reflect the extension of structural episodes of uplift and erosion (or of basin subsidence and thick sedimentation) seen on land, into the offshore domain; they highlight the major role these have had on source, reservoir/seal and trap development, within the context of regional and local basin evolution. A number of source rocks, including Upper Jurassic, Upper Cretaceous and Paleocene-Eocene argillaceous sediments, are identified, and the results of oil/oil and oil/source-rock correlations on fluids recovered from Paleogene carbonate reserviors in the Sharmah and Ras Ghashwah wells, and an Upper Cretaceous sandstone reservoir in the Sarar well, are, respectively, correlated with sources in the Paleocene-Eocene formations, and the Upper Cretaceous Mukalla Formation. The geothermal gradient, calculated from differing results in each well, is high, and averages 3.5°C/100m, which indicates an oil “window” ranging between depths of 1,750 m and 3,500 m; this is broadly supported by vitrinite reflectance and Thermal Alteration Index (TAI) measurements carried out on the samples. It is concluded that favourable conditions exist for commercial hydrocarbon accumulations in the offshore area
Detailed geochemical and geothermal studies have been carried out in the Red Sea and Gulf of Aden in order to understand the regional distribution of source rocks through time, and the effects of changing heat flow through time.These studies have shown the presence of generally thin developments of fair to very good quality source rocks. Most of the identified source rocks occur in syn-rift sediments throughout the Red Sea area, but pre-rift source-rock occurrences have been identified in Yemen (Gulf of Aden). Somalia, and to a lesser extent in Egypt. Isolated occurrences of post-rift source rocks have also been identified. The data can be interpreted in the regional context of the sedimentary facies of the region in order to predict possible geographic distribution of source rocks.Maturity gradients determined using vitrinite reflectivity and spore coloration range from low (often in post-rift sections) to high (often in syn- and pre-rift sections). The maturity gradients in many of the sections analysed show intersecting bi-linear trends, suggesting very high palaeogeothermal gradients in sediments close to the rifting centres. In such areas, the oil and gas “windows” are relatively shallow and thin. In areas where crustal thickening has reduced heat flux. hydrocarbon generation may have occurred in the past, but has since ceased.The models derived during this project for source-rock distribution and heat-flow variations are consistent with the tectonic evolution of the basin, and show that there is good potential in parts of the study area for oil generation, accumulation and preservation in pre-rift, syn-rift as well as in post-rift sediments.
Sediments of Palaeozoic, Mesozoic and early Palaeogene ages experienced a similar geological history in Ethiopia, Yemen and Somalia. During the late Eocene, however, uplift and differential erosion took place, prior to rift development in the middle Oligocene, when the proto-Gulf of Aden became established. To a certain extent, a similar sequence of events had also taken place in those regions of Egypt, Sudan, Ethiopia, Yemen and Saudi Arabia which border the Red Sea, but post-Eocene subsidence is now believed to have commenced during the late Oligocene in the southern Red Sea and progressed later, during the early Miocene, in the northern Red Sea and Gulf of Suez. Timing of this progressive development of the Gulf of Aden rift complex through the Red Sea and Gulf of Suez is well constrained by biostratigraphy, and provides a new approach to the understanding of lithological variations within the region.These lithological variations have, until now, only been considered on a country-specific basis, thus hindering establishment of a regional history of sedimentation. The well-understood and well-documented lithostratigraphic nomenclature of the Miocene succession of the Gulf of Suez has been used as a reference, or type, with which the lateral facies variations within the Red Sea have been compared. By this method only has it been possible to produce palaeoenvironmental maps for the entire study region, and for each formation and member. Lateral equivalents of the Gulf of Suez Nukhul, Rudeis, Kareem, Belayim, South Gharib. Zeit, Wardan and Shagara Formations have been identified within the Red Sea syn-rift and post-rift episodes.
The mid-Cretaceous Mardin Group carbonates constitute the principal reservoir in a number of oilfields near the city of Adiyaman in SE Turkey (the Adiyaman, G. Adiyaman, Cemberlitas, Cukurtas, Bolukyayla and Karakus oilfields). Porosity development in these carbonates was controlled by two phases of brittle deformation. The first of these accompanied the emplacement of the allochthonous Koçali-Karadut Complex in the Late Cretaceous (Maastrichtian), which principally influenced the development of porosity in the northern oilfields. Subsequently, movement during the Mio-Pliocene on the transcurrent Adiyaman fault affected porosity development in the south. The topmost unit of the Mardin Group, the Karababa Formation, consists of argillaceous carbonates, whose permeability and porosity were increased as a result of abundant tectonically-induced microfractures and stylolites. The underlying Derdere Formation includes porous limestones and dolomites, which are the principal reservoir units in the Adiyaman fields. Porosity versus depth and geothermal gradient versus depth curves indicate that porosity trends are controlled principally by the transcurrent Adiyaman fault and its antithetics. The Koçali-Karadut thrusts have had less influence on the evolution of porosity in the Mardin Group carbonates in the study area.
Cretaceous carbonates in the Adiyaman region of SE Turkey belong to the Aptian-Campanian Mardin Group and the overlying Karabogaz Formation. The carbonate succession at four well locations are incomplete, with variably extending important unconformities indicating periods of nondeposition and/or erosion. Combined with rapid subsidence and sedimentation effects, these unconformities have resulted in variations in the carbonates' present day burial depths, thereby influencing the regional pattern of source-rock maturation and the timing of oil generation. Burial history curves indicate that the carbonates' maturity increases from SW to NE, towards the Late Cretaceous thrust belt.
Top-cited authors
Hemin Koyi
  • Uppsala University
Henrik I Petersen
  • Geological Survey of Denmark and Greenland
Adnan A. M. Aqrawi
Abdulrahman Alsharhan
  • Middle East Geological and Environmental EST.
Christopher J Talbot
  • Uppsala University