A considerable amount of chemical knowledge of marine sediments has been acquired in recent years but has not yet been utilized by paleomagnetists. On the other hand, geochemists are often unaware of the usefulness of numerous magnetic techniques. In this review we try to bridge this gap, and in particular, we outline many of the chemical and magnetic principles that should allow paleomagnetists to better identify and understand chemical changes that affect the magnetic properties of marine sediments. The chemical principles include those for distinguishing the four major sources of sediments (continental, biological, authigenic/hydrogenous, volcanic/hydrothermal) from one another by determining elemental abundance distributions, as well as for investigating the stabilities of mineral phases relative to changes in pE and pH. The magnetic principles include the effects of authigenesis and diagenesis on magnetic properties, particularly on the direction and intensity of natural remanent magnetization (NRM). These principles are then applied to several sedimentary cores obtained from the Pacific Ocean. It is shown that although low‐temperature oxidation of titanomagnetites occurs in some of these cores, such oxidation has had only a minor effect on altering the NRM in most cases. On the other hand, some ferromanganese phases are magnetic and form authigenically in the marine environment. At least one of these phases, probably todorokite, sometimes carries a remanence sufficiently large to mask the depositional remanence carried by the titanomagnetite grains.

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Areal and vertical distributions of petroleum viscosities within heavy oil reservoirs are important in designing well completions, optimizing field development and planning thermal and other recovery operations. Viscosities of oils in closely-spaced reservoir zones in heavy oil fields can vary substantially. Unfortunately, oil samples are often unavailable or too small for conventional laboratory viscosity measurements. In such cases, correlations between heavy oil viscosity and geochemical, chemical and physical parameters can be valuable for estimating working viscosities. Various geochemical-viscosity correlations were evaluated using a suite of heavy crude oils (API gravities < 150) from fields in the San Joaquin Valley, California. Whole, dewatered, crude oils where studied. Kinematic viscosities were measured at multiple temperatures. Elemental, organic acid, pour point and gravity analyses were completed, followed by compound class separations and gas chromatographic analyses. Statistical methods were used to assess correlations of various parameters with viscosity. Results were compared with correlations reported in the literature and evaluated in terms of linkage to models of field-wide degradation processes believed to account for formation of the heavy oils, with the goal of assessing these predictive models for viscosity variations with applications to viscosity mapping.

A PNS logging program was designed to evaluate the economic potential of vertical steamflood expansion and to identify bypassed oil, based on a comparison of oil saturations from a Pulsed Neutron Spectroscopy (PNS) log to conventional core in a Kern River field well. In the comparison, PNS log oil saturations agreed with those from conventional core within 5.4 saturation units 68% of the time (log accuracy: 1 = 5.4). From multiple passes of the PNS log, it was found, for one effective pass at 60 feet/hour that the measurement repeats within 5.7 saturation units 68% of the time (log precision: 1 =5.7). After the comparison of log to core, a multiwell logging program was designed to determine oil saturations for several reservoir zones above and below existing steam flood zones. The results were used to optimize patterns for future steamflooding. In addition, oil saturations were obtained for zones within the existing steam flood to determine the economic value and risk for producing bypassed oil. For a proposed vertical expansion project, Expected Value Decision Analysis showed a benefit/cost ratio of 39/1 of running three PNS logs in the project area. The fraction of the total uncertainty associated with simulated production was reduced from 72% before to 39% after running the PNS logs. In addition, the PNS logs identified several million barrels oil in place that had not responded to conductive heating. Introduction Determination of oil saturation through time in heavy oil steam flood programs is necessary for effective heat management and optimum field development. ft is difficult to obtain accurate water and oil saturations from logs to monitor depletion in the Kern River field (see Figure 1 for location map) due to fresh formation waters, low production rates, extreme temperature variations, complex wellbore mechanicals, and varying steam saturations. Other thin conventional coring, the Pulsed Neutron Spectroscopy (PNS) log, or Carbon/Oxygen log, has been the only viable method to measure saturations. For existing projects, accurate oil saturation determination is necessary to assess whether or not efficient steam processing of zones is occurring (Figure 2). P. 347