The late Permian Queen Formation (115 m thick) is a succession of mixed clastics, carbonates and evaporites deposited in the northeastern margin of Central Basin Platform of the Permian Basin, west Texas, USA. Depositional facies, stacking patterns of cyclic facies associations and statistical correlation of rock property variations define geologic controls on reservoir rock properties. Textural, compositional, petrophysical and diagenetic variations within lithofacies exhibit systematic changes with stratigraphic position, which can be related to base level changes that were controlled by high-frequency, low-amplitude, sea level fluctuations during a greenhouse period. Ten lithofacies record variations in clastic input, shallow marine carbonate production, and evaporate precipitation in sabhkas and salinas. Four different types of lithofacies associations define: (1) transgressive deltaic deposits; (2) upward-shallowing evaporite and carbonate tidal-flat deposits; (3) transgressive beach ridge and sand flat deposits; and (4) upward-shallowing evaporite salina-sabhka deposits. Stacking patterns of lithofacies associations define sixteen depositional cycles that can be grouped into eight cycle sets. Cycle sets in turn are grouped to define two high-frequency sequences. Sequence 1 progresses from fluvial to carbonate tidal flat cycles. Sequence 2 consists of salina-dominated upward-shoaling cycles. Lateral continuity of cycles indicates restricted sedimentation on low-accommodation inner platform areas updip of prograding highstand platform-margin carbonate buildups, and a long-term trend of accommodation decrease. The Queen Formation contains two reservoir types; (1) siliciclastic reservoirs capped by evaporites and (2) layer-cake carbonate reservoirs. Of the four reservoir zones identified, R11 in lowstand fluvial-deltaic deposits has relatively little cement and the best reservoir characters.

The western portion of the Mississippi/Atwater fold belt in the Gulf of Mexico contains what is known as The Green Knoll Salt Dome. The creation and growth of this salt diapir is punctuated by salt deposition, salt migration, sediment loading, and is linked to the “Frampton” fold belt. An indicator of these growth periods is exhibited in an angular unconformity (halo-kinetic sequence boundary) that flanks the diapir. This unconformity developed during the Miocene-Pliocene chronostratigraphic boundary. The “Redwood” (Green Canyon 1001) prospect was drilled after the discovery of middle Miocene sands containing hydrocarbons in the Mad Dog field (GC 826). The objective Miocene sand in the “Redwood” borehole was thin due to this angular unconformity causing the sand to pinch out. An evaluation of seismic and well log data provided by Bureau of Ocean Energy Management indicated that the unconformity might not provide the seal needed to trap hydrocarbons on the flank of the salt dome, or it did not allow enough sand to be deposited. A palinspastic structural restoration of the Green Knoll Salt Dome revealed that the growth of the Green Knoll and Frampton are connected. It is still possible that if a well were to be drilled further down dip from where The “Redwood” prospect was drilled, one may find a potential hydrocarbon reservoir.

Time-lapse seismic is a modern technology for monitoring production-induced changes in and around a hydrocarbon reservoir. Time-lapse (4D) seismic may help locate undrained areas, monitor pore fluid changes and identify reservoir compartmentalization. Despite several successful 4D projects, there are still many challenges related to time-lapse technology. Perhaps the most important are to perform quantitative time-lapse and to model and interpret time-lapse effects in thin layers. The former requires one to quantify saturation and pressure effects on rock elastic parameters. The latter requires an understanding of the combined response of time-lapse effects in thin layers and overcoming seismic vertical resolution limitation. / This thesis presents an integrated study of saturation and pressure effects on elastic properties. Despite the fact that Gassmann fluid substitution is standard practice to predict time-lapse saturation effects, its validity in the field environment rests upon a number of assumptions. The validity of Gassmann equations, ultimately, can only be tested in real geological environments. In this thesis I developed a workflow to test Gassmann fluid substitution by comparing saturated P-wave moduli computed from dry core measurements with those obtained from sonic and density logs. The workflow has been tested on a turbidite reservoir from the Campos Basin, offshore Brazil. The results show good statistical agreement between the P-wave elastic moduli computed from cores using the Gassmann equations and the corresponding moduli computed from log data. This confirms that all the assumptions of the Gassmann theory are adequate within the measurement error and natural variability of elastic properties. These results provide further justification for using the Gassmann theory to interpret time-lapse effects in this sandstone reservoir and in similar geological formations. / Pressure effects on elastic properties are usually obtained by laboratory measurements, which can be affected by core damage. I investigated the magnitude of this effect on compressional-wave velocities by comparing laboratory experiments and log measurements. I used Gassmann fluid substitution to obtain low-frequency saturated velocities from dry core measurements taken at reservoir pressure, thus mitigating the dispersion effects. The analysis is performed for an unusual densely cored well from which 43 cores were extracted over a 45 m thick turbidite reservoir. These computed velocities show very good agreement with the sonic-log measurements. This is encouraging because it implies that core damages that may occur while bringing the core samples to the surface are small and do not adversely affect the measurement of elastic properties on these core samples. Should core damage have affected our measurements, we would have expected a systematic difference between properties measured in situ and on the recovered. This confirms that, for this particular region, the effect of core damage on ultrasonic measurements is less than the measurement error. Consequently, stress sensitivity of elastic properties as obtained from ultrasonic measurements are adequate for quantitative interpretation of time-lapse seismic data. / In some circumstances, stress sensitivity may not be obtained by ultrasonic measurements. Cores may be affected by damage, bias in the plugging process and scale effects and therefore may not be representative of the in situ properties. Consequently it is desirable to obtain this dependence from an alternative method. This other approach ideally should provide the pressure - velocity dependence from an intact rock. Few methods can sample the in situ rock. Seismic, for instance, provides in situ information, but lacks vertical resolution. Well logs, on the other hand, can provide high vertical resolution information, but usually are not available before and after production changes. I propose a method to assess the in situ pressure - velocity dependence using well data. I apply this method to a reservoir made up of sandstone. I used 23 wells drilled and logged in different stages of development of a hydrocarbon field providing rock and fluid properties at different pressures. For each well logged at a specific time, pore pressure, velocity and porosity, among other properties, are known. Pore pressure is accessed from a Repeat Formation Tester (RFT). As a field depletes and new wells are drilled and logged, similar data sets related to different stages of depletion are available. I present an approach expanding Furre et al. (2009) study incorporating porosity and obtaining a three dimensional relationship with velocity and pressure. The idea is to help to capture rock property variability. / Quantitative time-lapse studies require precise knowledge of the response of rocks sampled by a seismic wave. Small-scale vertical changes in rock properties, such as those resulting from centimetre scale depositional layering, are usually undetectable in both seismic and standard borehole logs (Murphy et al., 1984). I present a methodology to assess rock properties by using X-ray computed tomography (CT) images along with laboratory velocity measurements and borehole logs. This methodology is applied to rocks extracted from around 2.8 km depth from offshore Brazil. This improved understanding of physical property variations may help to correlate stratigraphy between wells and to calibrate pressure effects on velocities, for seismic time-lapse studies. / Small scale intra-reservoir shales have a very different response from sands to fluid injection and depletion, and thus may have a strong effect on the equivalent properties of a heterogeneous sandstone reservoir. Since shales have very low permeability, an increase of pore pressure in the sand will cause an increase of confining pressure in the intra-reservoir shale. I present a methodology to compute the combined seismic response for depletion and injection scenarios as a function of net to gross (NTG or sand – shale fraction). This approach is appropriate for modelling time-lapse effects of thin layers of sandstones and shales in repeated seismic surveys when there is no time for pressure in shale and sand to equilibrate. I apply the developed methodology to analyse the sand - shale combined response to typical shale and sandstone stress sensitivities for an oil field located in Campos Basin, Brazil. For a typical NTG of 0.6, there is a difference of approximately 35% in reflection coefficient during reservoir depletion from the expected value if these shales are neglected. Consequently, not considering the small shales intra-reservoir may mislead quantitative 4D studies. / The results obtained in this research are aimed to quantify pressure and saturation effects on elastic properties. New methodologies and workflows have been proposed and tested using real data from South America (Campos Basin) datasets. The results of this study are expected to guide future time-lapse studies in this region. Further investigations using the proposed methodologies are necessary to verify their applicability in other regions.

Magister Scientiae - MSc (Earth Science) / The Orange basin is relatively underexplored with 1 well per every 4000km2 with only the Ububhesi gas field discovery. Block 1 is largely underexplored with only 3 wells drilled in the entire block and only well A?F1 inside the 1500km2 3?D seismic data cube, acquired in 2009. This study is a reservoir characterization of well A?F1, utilising the acquired 3?D seismic data and re?analysing and up scaling the well logs to create a static model to display petrophysical properties essential for reservoir characterization. For horizon 14Ht1, four reservoir zones were identified, petro?physically characterized and modelled using the up scaled logs. The overall reservoir displayed average volume of shale at 24%, good porosity values between 9.8% to 15.3% and permeability between 2.3mD to 9.5mD. However, high water saturation overall which exceeds 50% as per the water saturation model, results in water saturated sandstones with minor hydrocarbon shows and an uneconomical reservoir.