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Strong seismic flat spots are typically associated with the oil/water contact (OWC) in many amplitude-supported deepwater South Atlantic Basin (SAB) discoveries, particularly in relatively shallow (∼2000 mbml), high-porosity unconsolidated Eocene-age reservoirs. These reservoirs contain biodegraded oils that have low API gravity, low gas-oil ratios, high viscosities, and fluid acoustic velocities between 4500 and 5000 ft/s. Often, a mismatch in amplitude is noted when comparing an observed seismic-amplitude response with a synthetic forward model generated using sonic logging data. These observations can be attributed to the high viscosity (low API gravity) of biodegraded oil that can lead to wave-induced heterogeneous pore pressure at logging frequencies, thus deviating from a key assumption in Gassmann's fluid-substitution theory. These dispersion effects can lead to significantly slower acoustic velocities of these oil-bearing reservoirs at seismic frequencies than those measured at logging frequencies. Using a generalized fluid/solid-substitution theory, we model this change in acoustic velocity and find that the theory can explain the observed bright-spot response.

From a geological perspective, the exploration of shale source rocks is relatively straightforward. Advances in stimulation technologies, such as hydraulic fracturing, have made it possible to economically extract hydrocarbons, both liquid and gas, from their respective source rocks. However, the devil is in the details when it comes to “sweet spotting” which shale reservoirs are going to be the best producers. Organic-rich shales are fine grained and tend to be petrophysically challenging and mineralogically and geochemically heterogeneous on the nanoscale. The advent of focused ion beam – scanning electron microscopic (FIB-SEM) techniques now allows us to image the pore networks in the organic matter that generated the hydrocarbons we produce. Two types of pore networks exist in organic-rich shales. One type is water wetting and is associated with the inorganic component of the shale, mostly clays. The other pore network is hydrocarbon wetting and is associated with the porosity that develops in organic matter during maturation and hydrocarbon generation.

Pore fluid pressures encountered in the deep-water Gulf of Mexico typically exceed hydrostatic pressures shortly below the mudline. While pore pressures often become quite high at depth, the overall pressure trend usually falls within a fairly narrow window and—more importantly—the pressures display a rather consistent relationship with measurable rock properties such as velocity, resistivity, and density. The consistency of these trends follows directly from two conditions: the dominance of disequilibrium compaction as the primary source of geopressures in this basin (Osborne et al., 1997, Swarbrick et. al. 2002), and that most parts of the basin are currently at or near their maximum historical effective stress. Disequilibrium compaction leads to a direct relationship between maximum effective stress and porosity; thus, having present day effective stress near its maximum value implies that current porosities indicate current effective stresses and hence current pore fluid pressures. This generally stable behavior has allowed the development and application of a number of pressure-prediction transforms which have facilitated improvements in the safety and efficiency of deepwater drilling (e.g., Eaton, 1975, Gutierrez et al., 2006). (Effective stress is assumed to be the stress acting on the rock frame; in this work, it is taken as equal to the difference between total stress and pore-fluid pressure as proposed by Terzaghi, 1923.)

Models and concepts of sandstone diagenesis developed over the past two decades are currently employed with variable success to predict reservoir quality in hydrocarbon exploration. Not all of these are equally supported by quantitative data, observations, and rigorous hypothesis testing. Simple plots of sandstone porosity versus extrinsic parameters such as current subsurface depth or temperature are commonly extrapolated but rarely yield accurate predictions for lithified sandstones. Calibrated numerical models that simulate compaction and quartz cementation, when linked to basin models, have proven successful in predicting sandstone porosity and permeability where sufficient analog information regarding sandstone texture, composition, and quartz surface area is available. Analysis of global, regional, and local data sets indicates the following regarding contemporary diagenetic models used to predict reservoir quality. (1) The effectiveness of grain coatings on quartz grains (e.g., chlorite, microquartz) as an inhibitor of quartz cementation is supported by abundant empirical data and recent experimental results. (2) Vertical effective stress, although a fundamental factor in compaction, cannot be used alone as an accurate predictor of porosity for lithified sandstones. (3) Secondary porosity related to dissolution of framework grains and/or cements is most commonly volumetrically minor (2%). Exceptions are rare and not easily predicted with current models. (4) The hypothesis and widely held belief that hydrocarbon pore fluids suppress porosity loss due to quartz cementation is not supported by detailed data and does not represent a viable predictive model. (5) Heat-flow perturbations associated with allochthonous salt bodies can result in suppressed thermal exposure, thereby slowing the rate of quartz cementation in some subsalt sands.

Time-dependent stresses and strains in shales are related by the anisotropic creep and relaxation functions. Laboratory measurements of time-dependent creep are often limited to specific composition and mineral distribution. Moreover, creep data acquired for anisotropic rocks using techniques like triaxial loading or nanoindentation usually correspond to specific boundary conditions, and the measured data may not be sufficient to predict creep or relaxation under other modes of deformation. Invoking the correspondence principle, we estimate effective creep and relaxation functions for anisotropic rocks using the effective medium theory. This method can be applied to study the possible links between time-dependent creep/relaxation and other geophysical measurables, such as ultrasonic measurements, well log data, and seismic data. Using well log data for the Eagle Ford shale formation, we quantitatively study the time-dependent relaxation of horizontal stresses upon sudden change in vertical stress.

Utilizing high-resolution transmission electron microscopy (TEM), energy dispersive spectroscopy (EDS) and X-ray diffraction (XRD) techniques, we have studied the transition from shallower smectite-rich mudrocks to deeper illite-rich mudrocks in Pliocene-age turbidite sediments from the northern Gulf of Mexico (GOM). Our objective in this work was to better understand how the smectite-illite transition may affect the onset of geopressuring in GOM sediments. The samples studied were sidewall cores from an offshore Louisiana well. In previous studies of GOM sediments, the smectite-to-illite reaction has mainly been documented in considerably older, Miocene-age sediments. The results of this study elucidate the reaction mechanisms entailed in the transformation of clays in this sediment from smectitic to illitic. We found that the illite formed at the expense of smectite in 2 ways: 1) growth of preexisting discrete illite flakes, and 2) creation of new illite layers within mixed-layer illite-smectite. Also, illitization apparently proceeded via a dissolution/precipitation. Al-conserving reaction rather than a solid-state, layer-conserving reaction. Smectite illitization is commonly believed to require input of K from feldspar dissolution. our XRD results found little correlation between decreases in K-feldspar and increases of illite. However, in 1 instance TEM/EDS analyses indicated the presence of high-charge smectite, which suggests that insufficient K was available for illitization. TEM images also show small packets of authigenic chlorite in illite-rich mudrock. This chlorite may act as a sink for Fe liberated upon smectite illitization.

Summary This investigation was aimed at improving the understanding of P-wave velocity behavior in Tight Gas Sands (TGS) and associated rocks. The specific goal of this study was a determination of the cause(s) of observed Pwave velocity slowdowns often associated with basincentered gas accumulations. The study focused on Cretaceous-age rocks in the Greater Green River Basin (GGRB), Wyoming. Study results indicate that variations in the sonic velocity log and seismic interval velocity responses are related predominantly to lithology. In contrast, gas saturation and abnormal pressures have a comparatively small impact on P-wave velocities at both the regional and field scales. We were unable to confirm the findings of previous studies purporting that seismic velocity could be used to detect abnormal pressures or gas-saturated rocks in the GGRB and call into question the use of velocity anomalies as an exploration tool in the search for gas accumulations in the GGRB. The significant influence of lithology on P-wave velocity response suggests we may apply seismic velocities and related attributes, such as acoustic impedance, to lithology identification in the GGRB.

Rock physics relationships are an essential element in the evaluation and modeling of seismic attributes for hydrocarbon exploration. Integration of laband wellbased data is essential in the development of rock physics models with predictive capability. Our integrated workflow for seismic petrophysics includes detailed petrologic characterization, incorporation of fundamental rock properties controls, rigorous petrophysical evaluation, and the use of a core-calibrated rock physics model. Results from a recent integrated study in the Gulf of Mexico yield further validation of the modulus-based model (Kittridge et al. 2004) and provide essential insights into the transition to consolidated sandstone behavior. The new modulus model is different from existing relationships for clean sandstone and we suggest possible causes.