Lithology and fluid prediction from amplitude versus offset (AVO) seismic data

Seismic reflection data as used in the oil industry is acquired and processed as multitrace data with source‐receiver offsets from a few hundred metres (short offset) to several kilometres (long offset). This set of data is referred to as ‘pre‐stack’. The traces are processed by velocity analysis, migration and stacking to yield a data volume of traces with ‘zero‐offset’. The signal‐to‐noise enhancement resulting from this approach is very significant. However, reflection amplitude changes in the pre‐stack domain may also be analysed to yield enhanced rock physics parameter estimates. Pre‐stack seismic data is widely used to predict lithology, reservoir quality and fluid distribution in exploration and production studies. Amplitude versus offset (AVO) data, especially anomalous signals, have been used for decades as indicators of hydrocarbon saturation and favourable reservoir development. Recently, enhanced quantification of these types of measurement, using seismic inversion techniques in the pre‐stack domain, have significantly enhanced the utility of such measurements. Using these techniques, for example, probability of the occurrence of hydrocarbons throughout the seismic data can be estimated, and as a consequence the many pre‐stack volumes acquired in a three‐dimensional (3D) can be survey, reduced to a single, more interpretable volume. The possibilities of 4D time lapse observation extend the measurements to changes in fluid content (and pressure) with time, and with obvious benefits in establishing the accuracy of dynamic reservoir models and improvements in field development planning. As an illustration, recent results from the Nelson Field (UK North Sea), are presented where we show the method by which probability volumes for oil sands may be calculated. The oil–sand probability volumes for three 3D seismic datasets acquired in 1990, 1997 and 2000 are compared and production effects in these data are demonstrated.     

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.     

Pressure distribution in a reservoir affected by capillarity and hydrodynamic drive: Griffin Field, North West Shelf, Australia

The effects of capillarity in a multilayered reservoir with flow in the aquifer beneath have characteristic signatures on pressure–elevation plots. Such signatures are observed for the Griffin and Scindian/Chinook fields of the Carnarvon Basin North West Shelf of Australia. The Griffin and Scindian/Chinook fields have a highly permeable lower part to the reservoir, a less permeable upper part, and a low permeability top seal. In the Griffin Field there is a systematic tilt of the free‐water level in the direction of groundwater flow. Where the oil–water contact occurs in the less permeable part of the reservoir, it lies above the free‐water level due to capillarity. In addition to these observable hydrodynamic and capillary effects on hydrocarbon distribution, the multi‐well pressure analysis shows that the gas–oil contacts in the Scindian/Chinook fields occur at different elevations. For both the Griffin and Scindian/Chinook fields the oil pressure gradients from each well are non‐coincident despite continuous oil saturation, and the difference is not attributable to data error. Furthermore, the shift in oil pressure gradient has a geographical pattern seemingly linked to the hydrodynamics of the aquifer. The simplest explanation for all the observed pressure trends is an oil leg that is still in the process of equilibrating with the prevailing hydrodynamic regime.     

Application of boron isotopes to the understanding of fluid–rock interactions in a hydrothermally stimulated oil reservoir in the Alberta Basin, Canada

Boron isotope ratios of reservoir minerals and fluids can be a useful geothermometer and monitor of fluid–rock interactions. In Cold Lake oil sands of northern Alberta, there is a large variation in δ¹¹B of the produced waters generated during steam injection and recovery of oil and water. The higher temperature waters (～ 200 °C) have isotopically light δ¹¹B values (+ 3‰ to + 14‰) and high B contents (～150 p.p.m.). It is inferred that the range of δ¹¹B values of the hydrothermal fluids results from reaction with the reservoir rock, and is a function of the temperature of the fluid–rock interaction. The distinct B geochemistry of the produced waters can be used to show that there is no detectable mixing of the oil recovery waters with the regional formation waters or shallow groundwater aquifers containing potable water. Examination of B isotope ratios of reservoir minerals, before and after steam injection, allows the evaluation of sources of B in the reservoir. The only significant phase containing B is pumice. It shows generally positive δ¹¹B values before steam injection and negative values after steam, with δ¹¹B as low as ? 28‰. Other possibly reactive phases include clay minerals and organic matter, but their abundance is not great enough to impact on the isotopic composition of the produced waters. This information makes it possible to evaluate the boron isotope fractionation equation derived from experimental data ( Williams LB (2000) Boron isotope geochemistry during burial diagenesis. PhD Dissertation. The University of Calgary, Alberta, Canada; Williams LB, Hervig RL, Holloway JR, Hutcheon I (2001a) Boron isotope geochemistry during diagenesis: Part 1. Experimental determination of fractionation during illitization of smectite. Geochimica et Cosmochimica Acta, in press). The results show that the fractionation curve predicts the difference between δ¹¹B of the pumice and hydrothermal fluids in the Cold Lake reservoir. This not only indicates that the reservoir fluids have approached boron isotope equilibrium with the reservoir rock, but also shows that B isotopes provide a useful geothermometer for hydrothermally stimulated oil reservoirs.     

On sampling the upper crustal reservoir of the NE Pacific Ocean

The oceanic upper crustal reservoir is a 600‐m thick layer of porous and permeable basaltic rock that forms the uppermost igneous basement underlying the global ocean. Pore spaces within this fluid aquifer contain a significant fraction of the global seawater, and active circulation through this reservoir has profound influence on the chemical composition of the ocean, strongly impacting the biological environment near the sea surface. Because of the relative inaccessibility of the deep seafloor, where hydrothermal fluid discharges and seawater re‐charges the oceanic crustal aquifer, our understanding of the dynamic physical, chemical and biological processes is strongly dependent on our ability to obtain uncontaminated samples from this challenging environment. Recent technological advances have addressed some, but certainly not all of these sampling problems, providing new data and samples that test our current hypotheses about the crustal fluid reservoir. Current scientific interest in the sub‐seafloor biosphere has focused on the uppermost igneous oceanic crust as likely to be one of the most habitable environments, because of its porosity and locus of hydrothermal circulation of chemical nutrients. Recent observations indicate that sub‐seafloor crustal environments harbor novel CO₂‐utilizing bacteria (primary producers) that could be a significant source of carbon‐fixation in the ocean, thus broadening possible habitable zones both on Earth and elsewhere where microbial life could exist independent of nutrient input from photosynthesis.     

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.     

Timescales for reaching steady-state fluid flow in systems perturbed by formation of highly permeable faults

We consider the case of an isothermal, fluid‐saturated, homogeneous rock layer with transverse fluid flow driven by an imposed constant fluid pressure gradient. A rupture in the centre of the rock layer generates a highly permeable fault and results in a change of the initially homogeneous permeability distribution. This leads to a perturbation of the fluid flow field and its gradual transition to a new steady‐state corresponding to the new permeability distribution. An examination of this transitional process permits us to obtain an analytical estimation of the transition stage duration. The application of the results obtained to km‐scale faults in crystalline rock bodies leads to the conclusion that the evolution of the fluid velocity field is rather rapid compared with geological timescales.     

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.     

Seismic constraints on the effects of gas hydrate on sediment physical properties and fluid flow: a review

The formation of gas hydrates in marine sediments changes their physical properties and hence influences fluid flow. Here, we review seismic indicators of gas hydrates and relate these indicators to gas hydrate formation and fluid migration. Analyses of seismic data from sediments containing gas and gas hydrates in a variety of locations have shown that the characteristic bottom‐simulating reflector (BSR), which commonly marks the hydrate phase boundary is caused mainly by the presence of gas beneath the gas hydrate stability zone (GHSZ). The amplitude of the BSR is also dependent on the hydrate concentration and on the porosity of the sediment. The presence of gas hydrate alters the elastic properties of sediments, particularly if it cements sediment grains. However, multifrequency studies in various geological provinces show that any loss of reflectivity or blanking observed within the GHSZ is dependent on both the nature of the sediments and concentration of hydrate present. Gas beneath the BSR may cause amplitude anomalies and may result in bright spots and enhanced reflections. The presence of gas beneath the BSR is the primary cause of observed amplitude versus offset (AVO) anomalies, but the amplitude of these anomalies is also dependent on the amount of cementation brought by the gas hydrates within the GHSZ. Fluid migration appears to play an important role in the formation and dissociation of gas hydrates in both active and passive margin settings. Fluid migration in accretionary prisms influences hydrate accumulation and may therefore control the spatial distribution of BSRs. Fluid migration may influence also the type of hydrate formed by bringing thermogenic gas containing higher order hydrocarbons to the GHSZ from below. Fluid advection may cause local dissociation of gas hydrates by bringing heat from below, thus shifting the gas hydrate phase boundary. Fluid flow within the GHSZ is limited by the formation of hydrate in the pore space, which reduces the permeability of the sediment. Features such as pockmarks, acoustic masking and acoustic turbidity are indirect indicators of fluid flow and identification of these features in seismic sections within and beneath the GHSZ may also suggest the formation of gas hydrate.     

Migration of Mn-rich fluids through normal faults and fine-grained terrigenous sediments during early development of the Neogene Vallès-Penedès half-graben (NE Spain)

The Miocene siliciclastic sediments infilling the Vallès‐Penedès half‐graben are affected by two sets of structures developed during the extensional tectonics that created the basin. The first set, represented by extension fractures infilled with mud and sands, is attributed to seismically induced liquefaction. The second set, represented by normal faults, corresponds to a high‐permeability horsetail extensional fracture mesh developed near the surface in the hanging walls of normal faults. The incremental character of the vein‐fills indicates episodic changes in the tectonic stress state and fault zone permeability. Two episodes of fluid migration are recorded. The first episode occurred prior to consolidation and lithification when shallow burial conditions allowed oxidizing meteoric waters to flow horizontally through the more porous and permeable sandy layers. Development of clastic dikes allowed local upward flow and dewatering of the sandy beds. Liquefaction and expulsion of fluids were probably driven by seismic shaking. During the first episode of fluid migration there was no cementation of the sandstone or within the fractures, probably because little fluid was mobilized by the predominantly compaction‐driven flow regime. The second episode of fluid migration occurred synchronously with normal fault development, during which time the faults acted as fluid conduits. Fluids enriched in manganese, probably leached from local manganese oxyhydroxides soon after sedimentation, moved laterally and produced cementation in the sandstone layers, eventually arriving at the more porous and permeable fault pathways that connected compartments of different porosities and permeabilities. Carbonate probably precipitated in fractures saturated with meteoric water near the ground surface at a transitional redox potential. Once the faults became occluded by calcite cement, shortly after fault development, they became barriers to both vertical and horizontal fluid flow.     

Significance of large-scale sand injectites as long-term fluid conduits: evidence from seismic data

Sand injectites and related features that are interpreted to have formed by large‐scale, often sudden, fluid escape in the shallow (typically <500 m) crust are readily imaged on modern seismic data. Many of the features have geometrical similarity to igneous dykes and sills and cross‐cut the depositional stratigraphy. Sand injectites may be multiphase and form connected, high‐permeability networks that transect kilometre‐scale intervals of otherwise fine‐grained, low‐permeability strata. North Sea examples often form significant hydrocarbon reservoirs and typically contain degraded, low‐gravity crude oil. Fluid inclusion and stable isotope data from cements in sand injectites record a mixing of aqueous fluids of deep and shallow origin.     

Experimental study of aqueous fluid infiltration into quartzite: implications for the kinetics of fluid redistribution and grain growth driven by interfacial energy reduction

To investigate the kinetics of interfacial energy‐driven fluid infiltration, experiments were carried out in a quartzite–water system at 621–925°C and 0.8 GPa. Infiltration couples were made by juxtaposing presynthesized dry quartzite cylinders and fluid reservoirs. The infiltration process was confirmed by the presence of pores at the quartzite grain edges. As predicted from theoretical considerations and previous experiments, wetting fluids such as pure water and NaCl aqueous solution infiltrated into quartzite, whereas nonwetting CO₂‐rich fluids did not. Newly precipitated quartz layers at the surfaces of the infiltrated sample proved that infiltration took place by a dissolution–precipitation mechanism. The enhancement of grain growth by fluid infiltration was observed over the entire range of experimental temperatures. The fluid fraction, gauged by the porosity of the run products, increases at the infiltration front and then decreases towards the fluid reservoir to form a high‐porosity zone with a maximum porosity of 2.3–2.9%. As infiltration proceeds, the high‐porosity zone advances like a travelling wave. This porosity wave is probably caused by a grain curvature gradient resulting from preferential grain growth in the infiltrated part of the quartzite, perhaps combined with other factors. The infiltration kinetics were modelled with a steady‐state diffusion model over the high‐porosity zone. The solubility difference between dissolving and precipitating grains was deduced to be 2 × 10^?2?3 × 10^?1 wt %. The experimentally obtained infiltration rate of aqueous fluid in the steady‐state diffusion regime (2 ± 0.5 × 10^?8 m sec^?1 at 823°C) is much faster than the estimated metamorphic fluid flux rates, so that interfacial energy‐driven fluid redistribution in quartz‐rich layers could significantly contribute to the fluid flux in high‐grade metamorphism, at least over a short distance. Cathodoluminescence observations of the run products revealed that the grain growth of quartzite in the presence of fluid proceeds extensively, which would promote the chemical equilibration between fluid and rock more effectively than would volume diffusion in quartz crystals.     

Evaluation of recoverable energy potential from enhanced geothermal systems: a sensitivity analysis in a poro‐thermo‐elastic framework

This study presents application of an efficient approach to simulate fluid flow and heat transfer in naturally fractured geothermal reservoirs. Fluid flow is simulated by combining single continuum and discrete fracture approaches. The local thermal nonequilibrium approach is used to simulate heat transfer by conduction in the rock matrix and convection (including conduction) in the fluid. Fluid flow and heat transfer models are integrated within a coupled poro‐thermo‐elastic framework. The developed model is used to evaluate the long‐term response of a geothermal reservoir with specific boundary conditions and injection/production schedule. A comparative study and a sensitivity analysis are carried out to evaluate the capability of the integrated approach and understand the degree by which different reservoir parameters affect thermal depletion of Soultz geothermal reservoir, respectively. Also observed, there exists an optimum fracture permeability after which the reservoir stimulation does not change the recovery factor significantly. Estimation of fluid temperature by the assumption of local thermal nonequilibrium heat transfer between the fracture fluid and the rock matrix gives fluid temperature of about 3°C less than that of estimated by thermal equilibrium heat transfer at early stage of hot water production.     

Indications of formation water flow and compartmentalization on the flank of a salt structure derived from salinity and seismic data

Vertical and lateral variations in lithology, salinity, temperature, and pressure determined from wireline LAS logs, produced water samples, and seismic data on the south flank of a salt structure on the continental shelf, offshore Louisiana indicate three hydrogeologic zones in the study area: a shallow region from 0 to 1.1 km depth with hydrostatically pressured, shale‐dominated Pleistocene age sediments containing pore waters with sea water (35 g l^?1) or slightly above sea water salinity; a middle region from 1.1 to 3.2 km depth with near hydrostatically pressured, sand‐dominated Pliocene age sediments that contain pore waters that range from seawater salinity to up to 5 times sea water salinity (180 g l^?1); and a deep section below 3.2 km depth with geopressured, shale‐dominated Miocene age sediments containing pore waters that range from sea water salinity to 125 g l^?1. Salt dissolution has generated dense, saline waters that appear to be migrating down dip preferentially through the thick Pliocene sandy section. Sand layers that come in contact with salt contain pore waters with high salinity. Isolated sands have near sea water salinity. Salinity information in conjunction with seismic data is used to infer fluid compartmentalization. Both vertical and lateral lithologic barriers to fluid flow at tens to hundreds of meters scale are observed. Fluid compartmentalization is also evident across a supradomal normal fault. Offset of salinity contours are consistent with the throw of the fault, which suggests that saline fluids migrated before fault formation.     

Geophysical and geochemical evidence of large scale fluid flow within shallow sediments in the eastern Gulf of Mexico,offshore Louisiana

We analyse the fluid flow regime within sediments on the Eastern levee of the modern Mississippi Canyon using 3D seismic data and downhole logging data acquired at Sites U1322 and U1324 during the 2005 Integrated Ocean Drilling Program (IODP) Expedition 308 in the Gulf of Mexico. Sulphate and methane concentrations in pore water show that sulphate–methane transition zone, at 74 and 94 m below seafloor, are amongst the deepest ever found in a sedimentary basin. This is in part due to a basinward fluid flow in a buried turbiditic channel (Blue Unit, 1000 mbsf), which separates sedimentary compartments located below and above this unit, preventing normal upward methane flux to the seafloor. Overpressure in the lower compartment leads to episodic and focused fluid migration through deep conduits that bypass the upper compartment, forming mud volcanoes at the seabed. This may also favour seawater circulation and we interpret the deep sulphate–methane transition zones as a result of high downward sulphate fluxes coming from seawater that are about 5–10 times above those measured in other basins. The results show that geochemical reactions within shallow sediments are dominated by seawater downwelling in the Mars‐Ursa basin, compared to other basins in which the upward fluid flux is controlling methane‐related reactions. This has implications for the occurrence of gas hydrates in the subsurface and is evidence of the active connection between buried sediments and the water column.     

Hydrogeology of the Krafla geothermal system,northeast Iceland

The Krafla geothermal system is located in Iceland's northeastern neovolcanic zone, within the Krafla central volcanic complex. Geothermal fluids are superheated steam closest to the magma heat source, two‐phase at higher depths, and sub‐boiling at the shallowest depths. Hydrogen isotope ratios of geothermal fluids range from ?87‰, equivalent to local meteoric water, to ?94‰. These fluids are enriched in ¹⁸O relative to the global meteoric line by +0.5–3.2‰. Calculated vapor fractions of the fluids are 0.0–0.5 wt% (~0–16% by volume) in the northwestern portion of the geothermal system and increase towards the southeast, up to 5.4 wt% (~57% by volume). Hydrothermal epidote sampled from 900 to 2500 m depth has δD values from ?127 to ?108‰, and δ¹⁸O from ?13.0 to ?9.6‰. Fluids in equilibrium with epidote have isotope compositions similar to those calculated for the vapor phase of two‐phase aquifer fluids. We interpret the large range in δD_EPIDOTE and δ¹⁸O_EPIDOTE across the system and within individual wells (up to 7‰ and 3.3‰, respectively) to result from variable mixing of shallow sub‐boiling groundwater with condensates of vapor rising from a deeper two‐phase reservoir. The data suggest that meteoric waters derived from a single source in the northwest are separated into the shallow sub‐boiling reservoir, and deeper two‐phase reservoir. Interaction between these reservoirs occurs by channelized vertical flow of vapor along fractures, and input of magmatic volatiles further alters fluid chemistry in some wells. Isotopic compositions of hydrothermal epidote reflect local equilibrium with fluids formed by mixtures of shallow water, deep vapor condensates, and magmatic volatiles, whose ionic strength is subsequently derived from dissolution of basalt host rock. This study illustrates the benefits of combining phase segregation effects in two‐phase systems during analysis of wellhead fluid data with stable isotope values of hydrous alteration minerals when evaluating the complex hydrogeology of volcano‐hosted geothermal systems.     

Fracture spacing during hydro‐fracturing of cap‐rocks

Layered low permeability rock units, like shales, represent seals or ‘cap‐rocks’ in a variety of geological settings. A continuous increase in the fluid pressure gradients across a virtually impermeable rock layer will ultimately lead to hydro‐fracturing. Depending on the boundary conditions, such fracturing may lead to the formation of a set of sub‐parallel cracks oriented more or less perpendicular to the cap‐rock layer. In this article, we propose a new numerical model that describes interactions between multiple cross‐cutting fractures in an elastic low permeability rock layer. The width of each fracture and the spacing between them are modeled as a force balance between the fluid pressure and the elastic forces in the cap‐rock and between each fracture. The model indicates that the system of fractures evolves toward a spatially periodic steady‐state distribution with a fixed fracture spacing and aperture. The results are similar for incompressible and compressible fluids. The steady‐state conditions depend on only two dimensionless parameters, and the fracture spacing is only weakly dependent on the cap‐rock thickness. This is in contrast to fracturing produced by simple extension of an elastic rock layer beyond the fracture strength, in which case fracture spacing is proportional to layer thickness.     

Geophysical signatures associated with fluid flow and gas hydrate occurrence in a tectonically quiescent sequence,Qiongdongnan Basin,South China Sea

Interpretation of high‐resolution two‐dimensional (2D) and three‐dimensional (3D) seismic data collected in the Qiongdongnan Basin, South China Sea reveals the presence of polygonal faults, pockmarks, gas chimneys and slope failure in strata of Pliocene and younger age. The gas chimneys are characterized by low‐amplitude reflections, acoustic turbidity and low P‐wave velocity indicating fluid expulsion pathways. Coherence time slices show that the polygonal faults are restricted to sediments with moderate‐amplitude, continuous reflections. Gas hydrates are identified in seismic data by the presence of bottom simulating reflectors (BSRs), which have high amplitude, reverse polarity and are subparallel to seafloor. Mud diapirism and mounded structures have variable geometry and a great diversity regarding the origin of the fluid and the parent beds. The gas chimneys, mud diapirism, polygonal faults and a seismic facies‐change facilitate the upward migration of thermogenic fluids from underlying sediments. Fluids can be temporarily trapped below the gas hydrate stability zone, but fluid advection may cause gas hydrate dissociation and affect the thickness of gas hydrate zone. The fluid accumulation leads to the generation of excess pore fluids that release along faults, forming pockmarks and mud volcanoes on the seafloor. These features are indicators of fluid flow in a tectonically‐quiescent sequence, Qiongdongnan Basin. Geofluids (2010) 10 , 351–368     

Hydrologic and geochemical controls on soluble benzene migration in sedimentary basins

The effects of groundwater flow and biodegradation on the long‐distance migration of petroleum‐derived benzene in oil‐bearing sedimentary basins are evaluated. Using an idealized basin representation, a coupled groundwater flow and heat transfer model computes the hydraulic head, stream function, and temperature in the basin. A coupled mass transport model simulates water washing of benzene from an oil reservoir and its miscible, advective/dispersive transport by groundwater. Benzene mass transfer at the oil–water contact is computed assuming equilibrium partitioning. A first‐order rate constant is used to represent aqueous benzene biodegradation. A sensitivity study is used to evaluate the effect of the variation in aquifer/geochemical parameters and oil reservoir location on benzene transport. Our results indicate that in a basin with active hydrodynamics, miscible benzene transport is dominated by advection. Diffusion may dominate within the cap rock when its permeability is less than 10^?19 m². Miscible benzene transport can form surface anomalies, sometimes adjacent to oil fields. Biodegradation controls the distance of transport down‐gradient from a reservoir. We conclude that benzene detected in exploration wells may indicate an oil reservoir that lies hydraulically up‐gradient. Geochemical sampling of hydrocarbons from springs and exploration wells can be useful only when the oil reservoir is located within about 20 km. Benzene soil gas anomalies may form due to regional hydrodynamics rather than separate phase migration. Diffusion alone cannot explain the elevated benzene concentration observed in carrier beds several km away from oil fields.