Abstract. We develop a new electrical conductivity equation based on Bussian's model and accounting for the different behavior of ions in the pore space. The tortuosity of the transport of anions is independent of the salinity and corresponds to the bulk tortuosity of the pore space which is given by the product of the electrical formation factor F and the porosity •p.For the cations, the situation is different. At high salinities, the dominant paths for the electromigration of the cations are located in the interconnected pore space, and the tortuosity for the transport of cations is therefore the bulk tortuosity. As the salinity decreases, the dominant paths for transport of the cations shift from the pore space to the mineral water interface and consequently are subject to different tortuosities. This shift occurs at salinities corresponding to ½ / t[+) ~ 1, where • is the ratio between the surface conductivity of the grains and the electrolyte conductivity, and t[+) is the Hittorf transport number for cations in the electrolyte. The electrical conductivity of granular porous media is determined as a function of pore fluid salinity, temperature, water and gas saturations, shale content, and porosity. The model provides a very good explanation for the variation of electrical conductivity with these parameters. Surface conduction at the mineral water interface is described with the Stem theory of the electrical double layer and is shown to be independent of the salinity in shaly sands above 10 -3 mol L -1 . The model is applied to in situ salinity determination in the Gulf Coast, and it provides realistic salinity profiles in agreement with sampled pore water. The results clearly demonstrate the applicability of the equations to well log interpretation of shaly sands.

Abstract. The permeability of a sand shale mixture is analyzed as a function of shale fraction and the permeability of the two end-members, i.e., the permeability of a clay-free sand and the permeability of a pure shale. First, we develop a model for the permeability of a clay-free sand as a function of the grain diameter, the porosity, and the electrical cementation exponent. We show that the Kozeny-Carman-type relation can be improved by using electrical parameters which separate pore throat from total porosity and effective from total hydraulic radius. The permeability of a pure shale is derived in a similar way but is strongly dependent on clay mineralogy. For the same porosity, there are 5 orders of magnitude of difference between the permeability of pure kaolinite and the permeability of pure smectite. The separate end-members' permeability models are combined by filling the sand pores progressively with shale and then dispersing the sand grains in shale. The permeability of sand shale mixtures is shown to have a minimum at the critical shale content at which shale just fills the sand pores. Pure shale has a slightly higher permeability. Permeability decreases sharply with shale content as the pores of a sand are filled. The permeability of sand shale mixtures thus has a very strong dependence on shale fraction, and available data confirm this distinctive shale-fraction dependence. In addition, there is agreement (within 1 order of magnitude) between the permeabilities predicted from our model and those measured over 11 orders of magnitude from literature sources. Finally, we apply our model to predict the permeabilities of shaly sand formations in the Gulf Coast. The predictions are compared to a data set of permeability determination made on side-wall cores. The agreement between the theoretical predictions and the experimental data is very good.

Water chemistry has been shown experimentally to affect the stability of water films and the sorption of organic oil components on mineral surfaces. When oil is displaced by water, water chemistry has been shown to impact oil recovery. At least two mechanisms could account for these effects, the water chemistry could change the charge on the rock surface and affect the rock wettability, and/or changes in the water chemistry could dissolve rock minerals and affect the rock wettability. The explanations need not be the same for oil displacement of water as for water imbibition and displacement of oil. This article investigates how water chemistry affects surface charge and rock dissolution in a pure calcium carbonate rock similar to the Stevns Klint chalk by constructing and applying a chemical model that couples bulk aqueous and surface chemistry and also addresses mineral precipitation and dissolution. We perform calculations for seawater and formation water for temperatures between 70 and 130 • C . The model we construct accurately predicts the surface potential of calcite and the adsorption of sulfate ions from the pore water. The surface potential changes are not able to explain the observed changes in oil recovery caused by changes in pore water chemistry or temperature. On the other hand, chemical dissolution of calcite has the experimentally observed chemical and temperature dependence and could account for the experimental recovery systematics. Based on this preliminary analysis, we conclude that although surface potential may explain some aspects of the existing spontaneous imbibitions data set, mineral dissolution appears to be the controlling factor.

Abstract. Self-potential electric and magnetic anomalies are increasingly being observed associated with hydrothermal fields, volcanic activity, and subsurface water flow. Until now a formal theoretical basis for predicting streaming potential of porous materials has not been available. We develop here a model giving both the macroscopic constitutive equations and the material properties entering these equations. The material properties, like the streaming potential coupling coefficient, depend on pore fluid salinity, temperature, water and gas saturations, mean grain diameter, and porosity. Some aspects of the model are directly tested with success against laboratory data. The streaming potential increases with temperature, grain size, and gas saturation, and decreases with salinity. At the scale of geological structures the model provides an explanation for the presence of kilometer-scale dipolar self-potential anomalies in geothermal systems and volcanoes. Positive self-potential anomalies are associated with fluid discharge areas, whereas negative self-potential anomalies are associated with fluid recharge areas. Self-potential anomaly maps determined at the surface of active hydrothermal fields appear to be a powerful way of mapping the fluid recharge and discharge areas. In the case of free convection the vorticities of the convection pattern generate a magnetic field. The greater these vorticities, the greater the associated magnetic field. It follows that hydrothermal systems act as natural geobatteries because of the flow of pore fluids in the subsurface of these systems.

a b s t r a c tPockmarks form where fluids discharge through seafloor sediments rapidly enough to make them quick, and are common where gas is present in near-seafloor sediments. This paper investigates how gas might lead to pockmark formation. The process is envisioned as follows: a capillary seal traps gas beneath a fine-grained sediment layer or layers, perhaps layers whose pores have been reduced in size by hydrate crystallization. Gas accumulates until its pressure is sufficient for gas to invade the seal. The seal then fails completely (a unique aspect of capillary seals), releasing a large fraction of the accumulated gas into an upward-propagating gas chimney, which displaces water like a piston as it rises. Near the seafloor the water flow causes the sediments to become ''quick'' (i.e., liquefied) in the sense that grain-to-grain contact is lost and the grains are suspended dynamically by the upward flow. The quickened sediment is removed by ocean-bottom currents, and a pockmark is formed. Equations that approximately describe this gas-piston-water-drive show that deformation of the sediments above the chimney and water flow fast enough to quicken the sediments begins when the gas chimney reaches half way from the base of its source gas pocket to the seafloor. For uniform near-surface sediment permeability, this is a buoyancy control, not a permeability control. The rate the gas chimney grows depends on sediment permeability and the ratio of the depth below seafloor of the top of the gas pocket to the thickness of the gas pocket at the time of seal failure. Plausible estimates of these parameters suggest gas chimneys at Blake Ridge could reach the seafloor in less than a decade or more than a century, depending mainly on the permeability of the deforming near-surface sediments. Since these become quick before gas is expelled, gas venting will not provide a useful warning of the seafloor instabilities that are related to pockmark formation. However, detecting gas chimney growth might be a useful risk predictor. Any area underlain by a gas chimney that extends half way or more to the surface should be avoided.

[1] Recent field investigations of a megadune region of East Antarctica provide evidence that differences in grain size, thermal conductivity, and permeability across a megadune profile are due to spatial accumulation variability in the absence of significant microclimate variations. The megadunes are low-amplitude (2-8 m), long-wavelength (2-5 km) bands with perceptible but low accumulation (less than 40 mm water equivalent (weq) yr À1 ) and accumulation hiatus within several kilometers proximity, as determined by remote sensing, surface feature classification, and ground-penetrating radar profiling. Our hypothesis that accumulation rate impacts the extent of temperature gradient-driven metamorphic growth in low accumulation rate sites is supported by measurements of various firn physical properties. Relatively small differences in accumulation rate (less than 40 mm weq yr À1 ) result in large differences in physical properties, including grain size, thermal conductivity, and permeability, which are apparent in satellite-based microwave data from both passive and active sensors. The differences in physical snow structure between low-accumulation areas and accumulation hiatus areas in the near surface are sufficiently distinct that evidence of past accumulation hiatus should be observable in the physical and chemical properties of an ice core record.

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