Quantitative estimation of overpressure caused by gas generation and application to the Baiyun Depression in the Pearl River Mouth Basin,South China Sea

Hydrocarbon generation can yield high fluid pressures in sedimentary basins as the conversion of solid kerogen to hydrocarbons can result in an increase in fluid volume. To quantify the relationship between gas generation and overpressure in source rocks, a set of equations for computing the pressure change due to gas generation has been derived. Those equations can be used to quantitatively estimate overpressure generated by type III kerogen in source rocks by considering gas generation and leakage, gas dissolution in formation water and residual oil, thermal cracking of oil to gas, and hydrocarbon episodic expulsion from source rocks. The equations also take consideration of other factors including source rock porosity, transformation ratio, total organic carbon (TOC), hydrogen index, and compressibility of kerogen, oil, and water. As both oil and gas are taken into account in the equations, they can also be used to estimate the evolution of overpressure caused by hydrocarbon generation of type I and type II kerogen source rocks. Sensitivity analyses on the type III kerogen source rock indicate that hydrogen index is the most influential parameter for overpressure generation, while TOC and residual gas coefficient (β: ratio of residual gas over the total gas generated) have a moderate effect. Overpressure can be generated even if the gas leakage/loss in the source rock is up to 80% of the total gas generated. This suggests that the internal pressure seal of the source rock is not a critical factor on the pressure change as long as the source rocks are capable of sealing liquid oil. The equations were applied to evaluate the overpressure in the Eocene–Oligocene Enping Formation source rocks due to hydrocarbon generation in the Baiyun Depression, the Pearl River Mouth Basin by considering the source rock properties, hydrocarbon generation history, and hydrocarbon expulsion timing. Two episodes of overpressure development due to gas generation and release were modeled to have occurred in the Enping Formation source rock since 16 Ma. The overpressure release at 10.2–5.3 Ma via hydrocarbon expulsion was apparently related to the Dongsha phase of tectonic deformation, whereas the pressure release at 2–0 Ma was due to pressure generation that was exceeded the fracture‐sealing pressure in the source rocks.     

Overpressure and petroleum generation and accumulation in the Dongying Depression of the Bohaiwan Basin, China

The occurrence of abnormally high formation pressures in the Dongying Depression of the Bohaiwan Basin, a prolific oil‐producing province in China, is controlled by rapid sedimentation and the distribution of centres of active petroleum generation. Abnormally high pressures, demonstrated by drill stem test (DST) and well log data, occur in the third and fourth members (Es3 and Es4) of the Eocene Shahejie Formation. Pressure gradients in these members commonly fall in the range 0.012–0.016 MPa m^?1, although gradients as high as 0.018 MPa m^?1 have been encountered. The zone of strongest overpressuring coincides with the areas in the central basin where the principal lacustrine source rocks, which comprise types I and II kerogen and have a high organic carbon content (>2%, ranging to 7.3%), are actively generating petroleum at the present day. The magnitude of overpressuring is related not only to the burial depth of the source rocks, but to the types of kerogen they contain. In the central basin, the pressure gradient within submember Es32, which contains predominantly type II kerogen, falls in the range 0.013–0.014 MPa m^?1. Larger gradients of 0.014–0.016 MPa m^?1 occur in submember Es33 and member Es4, which contain mixed type I and II kerogen. Numerical modelling indicates that, although overpressures are influenced by hydrocarbon generation, the primary control on overpressure in the basin comes from the effects of sediment compaction disequilibrium. A large number of oil pools have been discovered in the domes and faulted anticlines of the normally pressured strata overlying the overpressured sediments; the results of this study suggest that isolated sandstone reservoirs within the overpressured zone itself offer significant hydrocarbon potential.     

Downward hydrocarbon migration predicted from numerical modeling of fluid overpressure in the Paleozoic Anticosti Basin,eastern Canada

The Anticosti Basin is a large Paleozoic basin in eastern Canada where potential source and reservoir rocks have been identified but no economic hydrocarbon reservoirs have been found. Potential source rocks of the Upper Ordovician Macasty Formation overlie carbonates of the Middle Ordovician Mingan Formation, which are underlain by dolostones of the Lower Ordovician Romaine Formation. These carbonates have been subjected to dissolution and dolomitization and are potential hydrocarbon reservoirs. Numerical simulations of fluid‐overpressure development related to sediment compaction and hydrocarbon generation were carried out to investigate whether hydrocarbons generated in the Macasty Formation could migrate downward into the underlying Mingan and Romaine formations. The modeling results indicate that, in the central part of the basin, maximum fluid overpressures developed above the Macasty Formation due to rapid sedimentation. This overpressured core dissipated gradually with time, but the overpressure pattern (i.e. maximum overpressure above source rock) was maintained during the generation of oil and gas. The downward impelling force associated with fluid‐overpressure gradients in the central part of the basin was stronger than the buoyancy force for oil, whereas the buoyancy force for gas and for oil generated in the later stage of the basin is stronger than the overpressure‐related force. Based on these results, it is proposed that oil generated from the Macasty Formation in the central part of the basin first moved downward into the Mingan and Romaine formations, and then migrated laterally up‐dip toward the basin margin, whereas gas throughout the basin and oil generated in the northern part of the basin generally moved upward. Consequently, gas reservoirs are predicted to occur in the upper part of the basin, whereas oil reservoirs are more likely to be found in the strata below the source rocks. Geofluids (2010) 10 , 334–350     

Relationship between deformation bands and petroleum migration in an exhumed reservoir rock,Los Angeles Basin,California, USA

An oil‐bearing sandstone unit within the Monterey Formation is exposed in the Los Angeles Basin along the Newport‐Inglewood fault zone in southern California. The unit preserves structures, some original fluids, and cements that record the local history of deformation, fluid flow, and cementation. The structures include two types of deformation bands, which are cut by later bitumen veins and sandstone dikes. The bands formed by dilation and by shear. Both types strike on average parallel to the Newport‐Inglewood fault zone (317°–332°) and show variable dip angles and directions. Generally the older deformation bands are shallow, and the younger bands are steep. The earlier set includes a type of deformation band not previously described in other field examples. These are thin, planar zones of oil 1–2 mm thick sandwiched between parallel, carbonate‐cemented, positively weathering ribs. All other deformation bands appear to be oil‐free. The undeformed sandstone matrix also contains some hydrocarbons. The oil‐cored bands formed largely in opening mode, similar to dilation bands. The oil‐cored bands differ from previously described dilation bands in the degree of carbonate cementation (up to 36% by volume) and in that some exhibit evidence for plane‐parallel shear during formation. Given the mostly oil‐free bands and oil‐rich matrix, deformation bands must have formed largely before the bulk of petroleum migration and acted as semi‐permeable baffles. Oil‐cored bands provide field evidence for early migration of oil into a potential reservoir rock. We infer a hydrofracture mechanism, probably from petroleum leaking out of a stratigraphically lower overpressured reservoir. The deformation bands described here provide a potential field example of a mechanism inferred for petroleum migration in modern systems such as in the Gulf of Mexico.     

Effects of episodic fluid flow on hydrocarbon migration in the Newport‐Inglewood Fault Zone,Southern California

Fault permeability may vary through time due to tectonic deformations, transients in pore pressure and effective stress, and mineralization associated with water‐rock reactions. Time‐varying permeability will affect subsurface fluid migration rates and patterns of petroleum accumulation in densely faulted sedimentary basins such as those associated with the borderland basins of Southern California. This study explores the petroleum fluid dynamics of this migration. As a multiphase flow and petroleum migration case study on the role of faults, computational models for both episodic and continuous hydrocarbon migration are constructed to investigate large‐scale fluid flow and petroleum accumulation along a northern section of the Newport‐Inglewood fault zone in the Los Angeles basin, Southern California. The numerical code solves the governing equations for oil, water, and heat transport in heterogeneous and anisotropic geologic cross sections but neglects flow in the third dimension for practical applications. Our numerical results suggest that fault permeability and fluid pressure fluctuations are crucial factors for distributing hydrocarbon accumulations associated with fault zones, and they also play important roles in controlling the geologic timing for reservoir filling. Episodic flow appears to enhance hydrocarbon accumulation more strongly by enabling stepwise build‐up in oil saturation in adjacent sedimentary formations due to temporally high pore pressure and high permeability caused by periodic fault rupture. Under assumptions that fault permeability fluctuate within the range of 1–1000 millidarcys (10^?15–10^?12 m²) and fault pressures fluctuate within 10–80% of overpressure ratio, the estimated oil volume in the Inglewood oil field (approximately 450 million barrels oil equivalent) can be accumulated in about 24 000 years, assuming a seismically induced fluid flow event occurs every 2000 years. This episodic petroleum migration model could be more geologically important than a continuous‐flow model, when considering the observed patterns of hydrocarbons and seismically active tectonic setting of the Los Angeles basin.     

Application of fluorescence lifetime measurements on single petroleum-bearing fluid inclusions to demonstrate multicharge history in petroleum reservoirs

Petroleum-bearing fluid inclusions emit fluorescent light when excited with UV or visible light. The fluorescence decay time of the emission is dependent upon the wavelengths of the excitation and emission light, and the chemical composition of the petroleum oil. In general heavy oils have short lifetimes, whereas the emission from light oils is much longer lived. One can thus use plots of the fluorescence lifetime versus emission wavelength ( τ – λ plots), to show even subtle changes in the chemical composition of the entrapped oil. As a consequence, these τ – λ plots can be used for fluid inclusion research to discriminate different oil populations in situ . In particular, it is demonstrated that τ – λ plots discriminate two sets of inclusion oils in each of four North Atlantic basins [Jeanne d'Arc Basin (Newfoundland), Porcupine Basin (Ireland), Clair field West of Shetland (UK) and Kangerlussuaq Basin (East Greenland)] where multistage oil charge is inferred from other geological evidence.     

The salt chimney effect: delay of thermal evolution of deep hydrocarbon source rocks due to high thermal conductivity of evaporites

Half of the topseals to the world's largest oilfields are evaporites. Rock salt has a thermal conductivity two to four times greater than that of other sedimentary rocks found in oil‐ and gas‐bearing basins. Strong heat conduction through evaporites can increase the geothermal gradient above evaporite deposits, resulting in a positive thermal anomaly and above‐average temperature while simultaneously decreasing the geothermal gradient below evaporites, resulting in a negative thermal anomaly. Most Triassic–Jurassic hydrocarbon source rocks in the Kuqa Basin, western China, are overlain by ~1500‐m‐thick Tertiary evaporites with underlying Cretaceous sandstones and mudstones. Directly measured strata temperatures indicate an obvious break in the steepness of the geothermal gradient above and below Paleogene evaporites, with a significantly steeper geothermal gradient above the evaporites. Simulations of the thermal evolution of source rocks based on data collected from well Kela‐2 indicate that if the thickness of evaporites (mainly rock salt and anhydrite rock) in overlying rocks above source rocks increases compared with the thickness of siliciclastic rocks in the overlying rocks, then strata temperatures and vitrinite reflectance in Jurassic source rocks will decrease accordingly. Our thermal simulations based on the thickness and thermal conductivity of evaporites accurately coincide with previous studies based on homogenization temperatures, hydrocarbon–water contact retrospection, and carbon isotope results from natural gases. The gas generation center located in the Kalasu Tectonic Belt today is also sealed in an evaporite‐related structural trap that formed at this time. Therefore, the speculated natural gas generation times not only correlate with the evaporite‐related structural trap formation, but the calculated maturity of deep source rocks below the evaporites also coincides with current gas reserves. And our studies can help to find the deep oils and gases under thick evaporites.     

Permian bivalve molluscs from the Gai-As Formation,northern Namibia: systematics,taphonomy and biostratigraphy

Fossil bivalves from two horizons in the Gai-As Formation of NW Namibia are tentatively correlated with mid-Permian taxa of the Passa Dois Group of Brazil, supporting the concept that the Paraná Basin extended into Africa. The Namibian fauna includes a new genus and species, Huabiella compressa, which was previously confused with Brazilian taxa. The taphonomy of the bivalve-rich strata indicates deposition under the influence of episodic events, such as storms. The Gai-As Formation directly overlies the mesosaurid-bearing deposits of the Huab Formation, indicating a significant unconformity when compared with the more complete succession of the Passa Dois Group, Paraná Basin, Brazil. The studied bivalve assemblages are no younger than 265±2.5 Ma (mid-Permian), based on U/Pb radiometric dating of zircons from tuffs.     

Geothermometry and geobarometry of overpressured environments in Qiongdongnan Basin,South China Sea*

We demonstrate the use of PVT fluid inclusion modelling in the calculation of palaeofluid formation pressures, using samples from the YC21‐1‐1 and YC21‐1‐4 wells in the YC21‐1 structural closure, Qiongdongnan Basin, South China Sea. Homogenisation temperatures and gas/liquid ratios were measured in aqueous fluid inclusions, and associated light hydrocarbon/CO₂‐bearing inclusions, and their compositions were determined using a crushing technique. The vtflinc software was used to construct P–T phase diagrams that enabled derivation of the minimum trapping pressure for each order of fluid inclusion. Through the projection of average homogenisation temperatures (155, 185.5 and 204.5°C) for three orders of fluid inclusion on the thermal‐burial history diagram of the Oligocene Yacheng and Lingshui formations, their trapping times were constrained at 4.3, 2.1 and 1.8 Ma, respectively. The formation pressure coefficient, the ratio of fluid pressure/hydrostatic pressure established by PVT modelling coupled with DST data, demonstrates that one and a half cycles of pressure increase–discharge developed in the Yacheng and Lingshui formations for about 4.3 Ma. In comparison, the residual formation pressure determined by 2D numerical modelling in the centre of LeDong depression shows two and a half pressure increase–discharge cycles for about 28 Ma. The two different methods suggest that a high fluid potential in the Oligocene reservoir of the YC21‐1 structure developed at two critical stages for regional oil and natural gas migration and accumulation (5.8 and 2.0 Ma, respectively). Natural gas exploration in this area is therefore not advisable.     

Fluid mapping in deeply buried Ordovician paleokarst reservoirs in the Tarim Basin,western China

The storage spaces within deeply buried Ordovician paleokarst reservoirs in the Tarim Basin are mostly secondary and characterized by strong heterogeneity and some degree of anisotropy. The types of fluids that fill the spaces within these reservoirs are of great importance for hydrocarbon exploration and exploitation. However, fluid identification from seismic data is often controversial in this area because the seismic velocity for this particular reservoir could be significantly influenced by many factors, including pore shapes, porosity, fluid types, and mineral contents. In this study, we employ the differential effective medium‐Gassmann rock physics model to interpret and discuss the characteristics of conventional karstic carbonate reservoirs in the Tarim Basin that are filled with different fluids (oil, gas, and water) using logging data and thus objectively build corresponding fluid identification criteria. These criteria are subsequently evaluated by amplitude versus offset (AVO) forward analysis based on typical logging data and further applied to ascertain the reservoir fluid types in two different areas in the Tarim Basin based on prestack inversion results. For conventional carbonate reservoirs, gas can be distinguished from heavy oil and water, but heavy oil and water are broadly similar on seismic data. For condensate carbonate reservoirs, water can be differentiated from light oil (i.e., condensates) and gas, but light oil and gas demonstrate substantial similarities in terms of their seismic responses. The predicted fluid results are in good agreement with the results of drilling and oil testing. In particular, modeling the seismically resolvable reservoirs in the carbonate strata in the Tarim Basin, which have needle‐ and sphere‐shaped storage spaces (pore aspect ratio > 0.3) and clay content that is lower than 5%, indicates that fluid properties could be properly evaluated if the porosity is larger than 5% for conventional carbonate reservoirs and >7% for condensate carbonate reservoirs.     

Basin‐scale fluid movement patterns revealed by veins: Wessex Basin,UK

Calcite veins at outcrop in the Mesozoic, oil‐bearing Wessex Basin, UK, have been studied using field characterization, petrography, fluid inclusions and stable isotopes to help address the extent, timing and spatial and stratigraphic variability of basin‐scale fluid flow. The absence of quartz shows that veins formed at low temperature without an influence of hydrothermal fluids. Carbon isotopes suggest that the majority of vein calcite was derived locally from the host rock but up to one quarter of the carbon in the vein calcite came from CO₂ from petroleum source rocks. Veins become progressively enriched in source‐rock‐derived CO₂ from the outer margin towards the middle, indicating a growing influence of external CO₂. The carbon isotope data suggest large‐scale migration of substantial amounts of CO₂ around the whole basin. Fluid inclusion salinity data and interpreted water‐δ¹⁸O data show that meteoric water penetrated deep into the western part of the basin after interacting with halite‐rich evaporites in the Triassic section before entering fractured Lower and Middle Jurassic rocks. This large‐scale meteoric invasion of the basin probably happened during early Cenozoic uplift. A similar approach was used to reveal that, in the eastern part of the basin close to the area that underwent most uplift, uppermost Jurassic and Cretaceous rocks underwent vein formation in the presence of marine connate water suggesting a closed system. Stratigraphically underlying Upper Jurassic mudstone and Lower Cretaceous sandstone, in the most uplifted part of the basin, contain veins that resulted from intermediate behaviour with input from saline meteoric water and marine connate waters. Thus, while source‐rock‐derived CO₂ seems to have permeated the entire section, water movement has been more restricted. Oil‐filled inclusions in vein calcite have been found within dominant E‐W trending normal faults, suggesting that these may have facilitated oil migration.     

Diagenesis of the Amposta offshore oil reservoir (Amposta Marino C2 well,Lower Cretaceous,Valencia Trough,Spain)

Samples from the Amposta Marino C2 well (Amposta oil field) have been investigated in order to understand the origin of fractures and porosity and to reconstruct the fluid flow history of the basin prior, during and after oil migration. Three main types of fracture systems and four types of calcite cements have been identified. Fracture types A and B are totally filled by calcite cement 1 (CC1) and 2 (CC2), respectively; fracture type A corresponds to pre‐Alpine structures, while type B is attributed to fractures developed during the Alpine compression (late Eocene‐early Oligocene). The oxygen, carbon and strontium isotope compositions of CC2 are close to those of the host‐rock, suggesting a high degree of fluid‐rock interaction, and therefore a relatively closed palaeohydrogeological system. Fracture type C, developed during the Neogene extension and enlarged by subaerial exposure, tend to be filled with reddish (CS3r) and greenish (CS3g) microspar calcite sediment and blocky calcite cement type 4 (CC4), and postdated by kaolinite, pyrite, barite and oil. The CS3 generation records lower oxygen and carbon isotopic compositions and higher ⁸⁷Sr/⁸⁶Sr ratios than the host‐limestones. These CS3 karstic infillings recrystallized early within evolved‐meteoric waters having very little interaction with the host‐rock. Blocky calcite cement type 4 (CC4 generation) has the lowest oxygen isotope ratio and the most radiogenic ⁸⁷Sr/⁸⁶Sr values, indicating low fluid‐rock interaction. The increasingly open palaeohydrogeological system was dominated by migration of hot brines with elevated oxygen isotope ratios into the buried karstic system. The main oil emplacement in the Amposta reservoir occurred after the CC4 event, closely related to the Neogene extensional fractures. Corrosion of CC4 (blocky calcite cement type 4) occurred prior to (or during) petroleum charge, possibly related to kaolinite precipitation from relatively acidic fluids. Barite and pyrite precipitation occurred after this corrosion. The sulphur source associated with the late precipitation of pyrite was likely related to isotopically light sulphur expelled, e.g. as sulphide, from the petroleum source rock (Ascla Fm). Geofluids (2010) 10 , 314–333     

The origin of overpressure in 'old' sedimentary basins: an example from the Cooper Basin, Australia

Overpressure in ‘old’ sedimentary basins that have not undergone rapid, recent sedimentation cannot be easily explained using traditional burial‐driven mechanisms. The last significant burial event in the Cooper Basin, Australia, was the Late Cretaceous deposition of the Winton Formation (98.5–90 Ma). Maximum temperature in the basin was attained during the Late Cretaceous, with cooling beginning prior to 75 Ma. Hence, overpressure related to rapid burial or palaeomaximum temperatures (e.g. hydrocarbon generation) must have developed prior to 75 Ma. Retaining overpressure for 75 Ma in ‘old’ basins such as the Cooper Basin requires extremely low seal permeabilities. An alternative explanation is that overpressure in the Cooper Basin has been generated because of an increase in mean stress associated with an increase in horizontal compressive stress since Late Cretaceous times. Structural observations and contemporary stress data indicate that there has been an increase in mean stress of approximately 50 MPa between Late Cretaceous times to that presently measured at 3780 m. The largest measured overpressure in the Cooper Basin is 14.5 MPa at 3780 m in the Kirby 1 well. Hence, disequilibrium compaction driven by increasing mean stress can explain the magnitude of the observed overpressure in the Cooper Basin. Increases in mean stress (tectonic loading) may be a feasible mechanism for overpressure generation in other ‘old’ basins that have undergone a recent increase in horizontal stress (e.g. Anadarko Basin).     

FT-IR measurements of petroleum fluid inclusions: methane, n-alkanes and carbon dioxide quantitative analysis

A recent advancement in petroleum geochemistry is to model fossil oil composition using microthermometric and volumetric data acquired from individual fluid inclusion analysis. Fourier transform infrared (FT‐IR) microspectroscopy can record compositional information related to gas (CH₄ and CO₂) and alkane contents of petroleum inclusions. In this study, a quantitative procedure for FT‐IR microspectrometry has been developed to obtain, from individual fluid inclusions, mol percentage concentrations of methane, alkanes and carbon dioxide as constraints to thermodynamic modelling. A petroleum inclusion in a sample from the Québec City Promontory nappe area was used as standard to record a reference spectrum of methane. The analytical procedure is based on the measurement of CH₄/alkane and CH₄/CO₂ band area ratios. CH₄/alkane infrared band area ratio is obtained after spectral subtraction of the reference methane spectrum. This area ratio, affected by absolute absorption intensities of methane, methyl and methylene, provides a molar CH₄/alkane ratio. Methyl/methylene ratio (CH₂/CH₃) ratio is obtained following procedures established in previous work. CO₂/CH₄ concentration ratio is estimated from relative absolute absorption intensities. Application to natural inclusions from different environments shows good correlation between FT‐IR quantification and PIT (petroleum inclusion thermodynamic) modelling.     

Hydrogeochemical dynamics affecting steam‐heated pools at El Chichón Crater (Chiapas – Mexico)

El Chichón is an active volcano located in the north‐western Chiapas, southern Mexico. The crater hosts a lake, a spring, named Soap Pool, emerging from the underlying volcanic aquifer and several mud pools/hot springs on the internal flanks of the crater which strongly interact with the current fumarolic system (steam‐heated pools). Some of these pools, the crater lake and a cold spring emerging from the 1982 pumice deposits, have been sampled and analysed. Water–volcanic gas interactions determine the heating (43–99°C) and acidification (pH 2–4) of the springs, mainly by H₂S oxidation. Significantly, in the study area, a significant NH₃ partial pressure has been also detected. Such a geochemically aggressive environment enhances alteration of the rock in situ and strongly increases the mineralization of the waters (and therefore their electrical conductivity). Two different mineralization systems were detected for the crater waters: the soap pool‐lake (Na⁺/Cl^? = 0.4, Na/Mg>10) and the crater mud pools (Na⁺/Cl^? > 10, Na/Mg < 4). A deep boiling, Na⁺‐K⁺‐Cl^?‐rich water reservoir generally influences the Soap Pool‐lake, while the mud pool is mainly dominated by water‐gas–rock interactions. In the latter case, conductivity of sampled water is directly proportional to the presence of reactive gases in solution. Therefore, chemical evolution proceeds through neutralization due to both rock alteration and bacterial oxidation of ammonium to nitrate. The chemical compositions show that El Chichón aqueous fluids, within the crater, interact with gases fed by a geothermal reservoir, without clear additions of deep magmatic fluids. This new geochemical dataset, together with previously published data, can be used as a base line with which to follow‐up the activity of this deadly volcano.     

A comprehensive review of hydrocarbons and genetic model of the sandstone‐hosted Dongsheng uranium deposit,Ordos Basin,China

The Dongsheng uranium deposit, the largest in situ leach uranium mine in the Ordos Basin, geometrically forms a roll‐front type deposit that is hosted in the Middle Jurassic Zhiluo Formation. The genesis of the mineralization, however, has long been a topic of great debate. Regional faults, epigenetic alterations in surface outcrops, natural oil seeps, and experimental findings support a reducing microenvironment during ore genesis. The bulk of the mineralization is coffinite. Based on thin‐section petrography, some of the coffinite is intimately intergrown with authigenic pyrite (ore‐stage pyrite) and is commonly juxtaposed with some late diagenetic sparry calcite (ore‐stage calcite) in primary pores, suggesting simultaneous precipitation. Measured homogenization temperatures of greater than 100°C from fluid inclusions indicate circulation of low‐temperature hydrothermal fluids in the ore zone. The carbon isotopic compositions of late calcite cement (δ¹³C_VPDB = ?31.0 to ?1.4‰) suggest that they were partly derived from sedimentary organic carbon, possibly from deep‐seated petroleum fluids emanating from nearby faults. Hydrogen and oxygen isotope data from kaolinite cement (δD = ?133 to ?116‰ and δ¹⁸O_SMOW = 12.6–13.8‰) indicate that the mineralizing fluids differed from magmatic and metamorphic fluids and were more depleted in D (²H) than modern regional meteoric waters. Such a strongly negative hydrogen isotopic signature suggests that there has been selective modification of δD by CH₄±H₂S±H₂ fluids. Ore‐stage pyrite lies within a very wide range of δ³⁴S (?39.2 to 26.9‰), suggesting that the pyrite has a complex origin and that bacterially mediated sulfate reduction cannot be precluded. Hydrocarbon migration and its role in uranium reduction and precipitation have here been unequivocally defined. Thus, a unifying model for uranium mineralization can be established: Early coupled bacterial uranium mineralization and hydrocarbon oxidation were followed by later recrystallization of ore phases in association with low‐temperature hydrothermal solutions under hydrocarbon‐induced reducing conditions.     

Geomorphic Methods in Oil and Gas Prospecting

The structural-geomorphic technique advocated for use in oil and gas prospecting is based on the influence of geologic structure on the development and appearance of surface relief. Structural-geomorphic analysis is most effective in areas where inherited surface forms predominate; it is more difficult to apply in areas with a young, dynamic surface relief. The morphometric school in structural analysis focuses on map measurements of drainage patterns, valley asymmetry, stream orders and slopes. The genetic school emphasizes study of the origin and age of surface forms. Another geomorphic method in oil and gas prospecting is the paleogeomorphic technique, based on the prediction of the occurrence of hydrocarbons in stratigraphic and lithologic traps associated with the regional pinch-out of permeable rocks. Structural-geomorphic maps showing types of surface relief and their relationship to geological structure are an important aid in oil and gas prospecting.     

Maintaining high fluid pressures in older sedimentary basins

High fluid pressures in old geologic basins, where the mechanisms that generate high fluid pressure have ceased to operate, pose the problem of how high fluid pressures are maintained through geologic time. Recent oil and gas exploration reveals that low permeability shales, the source beds for oil and gas, contain large quantities of gas that are now being exploited in many sedimentary basins in North America. No earlier analyses of how to maintain high fluid pressure in older sedimentary basins included a shale bed as a source of adsorbed gas; this is a new conceptual element that will fundamentally change the analysis. Such a large fluid source can compensate for a low rate of bleed off in a dynamic system. If the fluid source is large enough, as the gas within these shale source beds appears to be, there will no appreciable drop in pressure accompanying a low rate of leakage from the basin for long periods. For the dynamic school of basin analysts this may provide the missing piece in the puzzle, explaining how high fluid pressures are maintained for long periods of geologic time in a crust with finite, non-zero permeability. This is a hypothesis which needs to be tested by new basin analyses.     

Weathering of rock art at two sites in the KwaZulu-Natal Drakensberg,southern Africa

Sediments of the Karoo Basin in southern Africa represent one of the world's finest laboratories for investigating sandstone weathering. The natural breakdown of these sandstones, most notably in the Clarens Formation, is destroying much of the indigenous rock art heritage that exists there. In an attempt to elucidate the operative weathering processes, a range of micro-climatic, rock temperature, rock moisture, rock chemistry, and rock property data have been monitored over a 15 year period at two sites in the KwaZulu-Natal Drakensberg. Results suggest that rock moisture regimes and to a lesser extent, rock thermal regimes exert the most damaging influence on San paintings. It is argued that granular disintegration and the enlargement of existing sandstone pores and bedding planes close to the rock surface, facilitate an increasingly dynamic moisture regime, which leads to an accelerating rate of weathering. Recent technological advances in data collection suggest that a re-evaluation of environmental controls may be necessary before weathering, at a scale appropriate to the deterioration of rock art, can be fully understood. The continued existence of indigenous rock art in southern Africa depends on investigations aimed at the development of techniques for its preservation.     

Evaluation of soluble benzene migration in the Uinta Basin

Field sampling and mathematical modeling are used to study the long‐distance transport and attenuation of petroleum‐derived benzene in the Uinta Basin, Utah. Benzene concentration was measured from oil and oil field formation waters of the Altamont‐Bluebell and Pariette Bench oil fields in the basin. It was also measured from springs located in the regional groundwater discharge areas, hydraulically down‐gradient from the oil fields sampled. The average benzene concentration in oils and co‐produced waters is 1946 and 4.9 ppm at the Altamont‐Bluebell field and 1533 and 0.6 ppm at the Pariette Bench field, respectively. Benzene concentration is below the detection limit in all springs sampled. Mathematical models are constructed along a north–south trending transect across the basin through both fields. The models represent groundwater flow, heat transfer and advective/dispersive benzene transport in the basin, as well as benzene diffusion within the oil reservoirs. The coupled groundwater flow and heat transfer model is calibrated using available thermal and hydrologic data. We were able to reproduce the observed excess fluid pressure within the lower Green River Formation and the observed convective temperature anomalies across the northern basin. Using the computed best‐fit flow and temperature, the coupled transport model simulates water washing of benzene from the oil reservoirs. Without the effect of benzene attenuation, dissolved benzene reaches the regional groundwater discharge areas in measurable concentration (>0.01 ppm); with attenuation, benzene concentration diminishes to below the detection limit within 1–4 km from the reservoirs. Attenuation also controls the amount of water washing over time. In general, models that represent benzene attenuation in the basin produce results more consistent with field observations.