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Analyses of vertical fractures are of great interest in characterizing the fluid flow and minimum in situ stress direction in reservoirs. Fractures are responsible for permeability anisotropy in a reservoir. Fractures can be the cause of migration of hydrocarbons, leakage of drilling fluid and even release of gases like methane on seabed. There is a need to extensively study the small-scale fractures, embedded in host rock to understand the challenges in exploitation of fractured reservoirs. Nowadays, technologies for carbon capture and storage (CCS) are gaining popularity. CCS involves massive injection of carbon dioxide into the subsurface, thereby altering the stress state in the reservoir. Fractures play a vital role in the mobilization of CO2. Knowledge about fracture systems in the subsurface formation can help estimate a threshold value of volume to be injected. This may prevent leakage of gas to atmosphere in case of onshore reservoir or into the ocean water for offshore reservoir and potential seismic hazard induced by injection activities. Presence of small scale fractures can be detected in the drilled cores. However, this gives us information about fractures over a very small area only. By using seismic attributes, we get such information on a broader scale. The importance of this work may be realized by considering the cost involved in drilling a borehole. It is to be noted that tremendous amount of seismic data acquired over some of the major fractured reservoirs in the world are already available. And the expressions for numerical computation of seismic attributes using fracture parameters are straightforward and simple. Long-wavelength equivalent orthorhombic (ORT) media and monoclinic media typically characterize the anisotropy induced by a set (or two sets orthogonal to each other) of vertical parallel fractures and two non-orthogonal sets of vertical fractures respectively, embedded into a transversely isotropic medium with a vertical symmetry axis (VTI). In nature, transverse isotropy is usually displayed by sedimentary rocks, planar igneous bodies and floating ice sheets. The equivalent stiffness matrix for the Vertically Fractured media with Transverse Isotropy (VFTI) and monoclinic media are derived from the background stiffness coefficients and fracture weaknesses parameters. The goal of this thesis work is to accurately model fractures and analyze the fracture response in normal move-out velocities (defined by traveltimes) and gradient term in the reflection coefficient of the amplitude vs azimuth attributes for different wave modes. These responses are based on changes in the orientation of fracture sets and the magnitude of fracture weaknesses. These seismic data, acquired over a fractured reservoir can also be inverted for the azimuth angles of fracture sets present in the host rock. In the first part, study has been carried upon VFTI media. A term called eccentricity of the normal move-out (NMO) velocities ellipse is defined. We will see the sensitivities towards fracture weaknesses in the eccentricity term for pure wave modes (PP, S1S1, S2S2) and converted wave modes (PS1, PS2, S1S2). Similar study on amplitude vs azimuth (AVAz) analyses of fractured media is done. Sensitivities towards fracture weaknesses in the gradient term of reflection coefficients for pure wave modes (PP, SVSV, SHSH) and converted wave modes (PSV, PSH and SVSH) are determined. In the second part, fracture response in NMO velocities and gradient term in the reflection coefficient of AVAz attributes for different wave modes are observed for monoclinic media. Inverse modeling study that aims to determine the orientation of fracture systems from the given seismic data has been carried out. The error in azimuth angle of fracture sets for such inversion technique has been calculated. Finally, sensitivities towards fracture parameters established from both attributes are compared. The advantages and limitations of both data sets are then discussed. Apart from a standard model, the study has also been carried upon two arbitrary models, the VTI background medium of which are derived from upscaling of well log data. Generalized conclusions about the applicability of results so obtained have been made.

Natural fractures are essential elements which can be commonly observed in reservoirs. The saying that "All reservoirs should be considered fractured until proven otherwise. (Narr et al., 2006)" is the best portrayal of its universality. The study of fracture systems is of great importance since it has been proven to have a strong impact on reservoir characteristics. The goal of this thesis is to figure out the relationship between seismic signatures and vertically fractured media. In this thesis, first the effective VTI medium is obtained from well log data by using Backus averaging theory. Then, the effective ORT medium is constructed based on Schoenberg-Helbig model by embedding one vertical fracture set into VTI host medium. By comparing the anisotropy parameters, it is possible to detect one single fracture set between the host and effective media. The combination of more vertical fracture sets (not parallel) and VTI background medium is supposed to provide effective MONO medium. However, two perpendicular fracture sets result in effective ORT medium. When summing up uniformly distributed vertical fractures within azimuthal angle [−90◦, 90◦], the effective VTI medium is provided. Numerical tests are performed to simulate more realistic fracture distributions by using Gaussian functions. The results show that it is very hard to distinguish between different fracture distributions through seismic signatures. However, for models in this study, certain geophysical methods can be applied to detect different distributions. This is very model-dependent. Therefore, in the future, more work should be done to obtain further correlation between seismic signatures and fracture systems.

Seismic response to the fluid substitution of oil with water and CO2 in a reservoir is analysed. A model consisting of horizontal layers based on the upscaling of well log data is studied. An interval of the model is selected as the reservoir background and then it is horizontally cracked. The model of alternating solid and fluid layers is employed. And the method of propagator matrix is applied to derive the slowness surfaces. It has been found that there are 3 propagating modes in the horizontally cracked reservoir with fluid saturation, namely fast-P-, slow-P- and S-wave. Under seismic frequency (0-100 Hz), only fast-P-wave is weakly dispersive. The travel time analysis suggests that the overall P/fast-P-wave travel time is more sensitive to fluid substitution compared to that of S/slow-P-wave. And it is possible to identify fluid substitution from oil to CO2 through P/fast-P travel time when the fracture relative thickness phi = 0.001. Changing the period of the alternating layers H from 1 m to 5 m has no significant impact on the travel time. And it is almost impossible to detect fluid substitution through the travel time with such a low phi = 0.0001. Gradual replacement from oil to water results in an apparent ‘linear change’ to the P/fast-P travel time as a function of oil saturation. To obtain P-fast-P-wave reflectivity from overburden to the reservoir, the reservoir is regarded as an effective VTI layer. For phi = 0.001, the reflectivity varies much from oil to CO2 saturation and the reflectivity change from oil to water is noticeable. H has only a tiny impact on the reflectivity. For lower phi = 0.0001 only the substitution from oil to CO2 is visible on R0 – R2 cross plot. The mixed-phase saturation for oil replaced by CO2 behaves like a linear effect to R0 – R2 as a function of oil saturation. The seismic modelling of the acoustic wave equation by frequency-domain finite-difference method for the model with phi = 0.0001 yields the synthetic seismograms. And the result is consistent with the phenomenon mentioned above. The simulation for phi = 0.001 is suffered from high noise, thus, not displayed. For comparison to the theory for porous media, Biot-Squirt poroelastic mechanism is also applied to the model background to make the reservoir background porous. The reservoir background with porosity phi = 0.001 is studied as an example. The result indicates that there is only a moderate reflectivity variation for the fluid substitution from oil to water/CO2. The travel time is almost the same with oil, water and CO2 saturation.

The Carbon Capture and Storage project that is taking place at the Sleipner field involving the injection of CO2 into Utsira sandstone reservoir at 1012 m below sea level. The migration of CO2 must be monitored to understand the amount and composition of CO2 inside the reservoir. The goal of this study is to estimate petrophysical parameters such as CO2 saturation and its mixing type inside the reservoir by jointly inverting P-wave velocity and resistivity model. CO2 saturation estimated from joint rock physics inversion can reach 68% with an uncertainty of around 20%. The same test also shows that the Brie exponent for CO2 higher than 15% is of around 7, suggesting the mixing type of brine and CO2 is somewhere between uniform and patchy. These results are variable depending on the chosen parameters. The study shows that two different geophysical methods can be combined to provide complementary information for discrimination of CO2 saturation and its mixing type.

Sleipner field (North Sea) is the first largest CO2 storage site, where the Carbon Dioxide is reinjected into the Utsira Sandstone. The main aim of this work is to obtain an estimate of the CO2 saturation by using AVO techniques. Some other effects responsible for the energy loss, amplitude reduction and phase shift of the wave due to scattering and intrinsic attenuation, might mislead quantitative results if they are not considered. In order to account those effects. The study of reflection and transmission coefficients for elastic/elastic and elastic/viscoelastic models are performed. Secondly, several attenuation models are simulated increasing their complexity from a three layers model with a thick partially saturated sandstone (viscoelastic and poroelastic) embedded into shales, to a 28 layers model of sandstones with variable thickness and CO2 saturations interbedded with thinner shales. Results show that viscoelastic and poroelastic sandstones are equivalent to elastic ones. Therefore, attenuation effects can be neglected. Elastic AVO analysis is carried out using the OptAVO tool. First, a feasibility study is performed based on well log and rock physics information, where three different fluid distributions are tested using Biot s theory and Brie s equation (e exponent equal to 1, 5 and 40). Then, the AVO inversion is performed via least squares fitting of the seismic amplitudes with the optimal reference curves. As expected, the AVO results are strongly influenced by the type of fluid distribution. For instance, patchy saturation (e=1) shows the highest saturations levels, while an average mixing law (e=5) suggests much lower saturations. The CO2 estimation ambiguity from the elastic reflectivity results need to be addressed in the future and better constraints must be included into the modeling stage in order to mitigate it.

Anisotropy has proved to be a reliable means for determination of the rock properties necessary to characterize the subsurface. VTI is a form of anisotropy which provides an estimate of the layered earth. This report summarises a work done on well data acquired in one well in Cote d Ivore. The data consisted P- and S-waves velocities and density of isotropic thin layers at different fluid saturations. Backus averaging was used for creation of the effective medium in the form VTI. Stiffness coefficients of the effective media were then determined from which the vertical P- and S-waves velocities were calculated. Additionally, the three anisotropy parameters, epsilon, delta and gamma were calculated for each fluid saturation. Analysis of the variation of all the five parameters has been made, from which the P-wave velocity has been found to increase when water is in the pores as compared to oil and gas. Fluid substitution has been found to have a negligible effect on S-wave velocity and gamma. Gas has also been found to have the largest effect on P-wave anisotropy. The moveout parameter delta has been observed to have a more complex response to fluid substitution bringing an attention and a call to revisiting the conclusion that eta is invariant of fluid saturation.

In seismic reservior characterization, it is important that the measured sonic log used is accurate and consistent. Due to anisotropic effects in the reservoir, which is majorly caused as a results of interbedded sequence of sand and shales, sonic log (compressional and shear wave velocities) acquired in vertical wells are different from those acquired in deviated wells. Rock physics models are created for anisotropic heterogeneous sand-shale sequence. These models are varied as a function of angle, porosity, saturation and net to gross. Variation of Thomsen anisotropic parameters and anelliptic parameters as a function of saturation and net-to-gross are investigated in order to understand the significant of anisotropy on these properties. From the rock physics modelling, anisotropic effect becomes more pronounced at high propagation angle and also the variation of the geologic parameters strongly depends on the propagation angle. Anisotropy effects decreases with increasing net-to-gross and anelliptic parameters are more sensitive to fluid saturation compared to Thomsen anisotropy parameters. A method is proposed for anisotropy correction of deviated wells using core measurement (model rock properties) of sand and shale from the study area, the inclination angle of the well and the net to gross ratio of the reservoir. The anisotropy corrected logs are then used for improved rock physics interpretation using the rock physics templates(RPT) and AVO analysis. The proposed correction is lithology dependent and the correction is significant in regions with low net-to-gross. Discrimination of lithologies and fluid saturation on the rock physics template is enhanced as a result of the anisotropy correction. The rock physics templates are constructed for different net to gross and propagation angles for varying fluid saturation in order to account for anisotropic effects. There is better separation of water sands and gas sand on the horizontal RPT(created at 72 deg) compared to vertical RPT(created at 0 deg). Vertical well, deviated well and anisotropy corrected well log data from the North Sea are superimposed on the rock-physics templates. Poor separation of lithology and saturation is observed on the RPT using the deviated well. It can be observed that the anisotropy corrected deviated well follows similar trends as the vertical well. Anisotropy effect on the reservoir properties that are accounted for using the proposed method are clearly seen on 3D rock physics templates. AVO inversion is also performed on the horizon attribute data from study area. The inverted rock physics properties are plotted on the created rock physics models for two vertical wells from the study area. The two vertical wells show different AVO class response. The net-to-gross and porosity are different for the two wells and in general, these observations are constrained by local geology.

We develop two methods to determine; (1) net to gross and hydrocarbon saturation in a mixture of sand and shale. (2) effective properties versus tilt in sand. Backus (1962) and Schoenberg and Muir (1989) averaging are used for the horizontally layered transversely isotropic medium with vertical symmetry axis (VTI), horizontal symmetry axis (HTI) and tilted symmetry axis (TTI) test respectively. A mixture of two points representing sand and shale are picked from Intrabasalt 2 formation (North Sea data) and the effective properties and anisotropic parameters (epsilon, delta and gamma) are computed using matlab algorithm. The modeling results for the VTI, HTI and TTI show that P- wave velocity (Vp ) increases with increasing net to gross and S- wave velocity (Vs ) decreases with increasing net to gross. The anisotropic parameters decrease with increasing net to gross. In the second part, the whole Intrabasalt 2 formation is considered as sand in a tilt form. The modeling results show that P- wave velocity and S- wave velocity increase with increasing tilt angle in sand and the anisotropic parameters of the tilt sand decrease with increasing tilt angle with the exception of anisotropic parameter delta which increases with tilt angle up to 30 degrees and then decreases with increasing tilt angle up to 90 degrees.