Seismic time-lapse monitoring of production is an important tool used to efficiently drain a hydrocarbon reservoir. Repeat seismic surveys may be used, because the seismic method is sensitive to the reservoir fluid. A prominent seismic attribute is the reflectivity (or amplitude) as a function of offset (AVO) which strongly depends on material properties, and hence, on the pore fluid. Repeat surveys, however, are very costly. To reduce the risks, the repeat survey is simulated on a computer for a number of different scenarios. Hence, the objectives of this study are to predict the seismic responses after five years of production of the reservoirs at the well locations, correlate the seismic attributes to fluid conditions in the reservoirs, assess the detectability of changes in AVO attributes due to changes in fluid conditions, and determine which attribute is more diagnostic of fluid changes. Petrophysical models were generated for different pore fluids using well logs from a field in the Gulf of Mexico. Synthetic seismograms were then calculated using a layerstack scheme to study the effects of the reservoir fluids on AVO. Compared to idealized half-space models, it was found that the AVO responses are contaminated by the overburden and the thinness of the reservoir. In order to remove transmission loss due to overburden effects, the synthetic AVO curves were scaled by normalizing an overburden-over-half-space model to an idealized analytical Zoeppritz model. In a second step, an offset-dependent overburden correction was applied using a low order polynomial, which was fitted to the amplitude ratios between the overburden/half-space model and the idealized model. Finally, a zero-offset tuning correction was applied. The results of the AVO analyses showed that some errors were unresolved using the applied overburden and tuning corrections, and amplitudes at large offsets were possibly contaminated by multiples and converted waves. Since there is no shallower production or steam injection for this particular field, the repeat surveys should have the same overburden, tuning, multiple-related and converted wave contamination. It appears reasonable to assume that any changes in amplitude between the repeat surveys would be due to fluid saturation changes. Therefore, it was concluded that it is not necessary to attempt to remove the overburden and tuning effects. Results from the AVO analyses of the uncorrected models showed that AVO attributes should be a useful tool to detect reservoir conditions during the production of the field. Generally, the water-flood changes the AVO by decreasing the intercept and increasing the gradient from the in-situ oil/gas cases. The relative changes in both intercept and gradient due to the water-flood are detectable assuming a 20% relative-change detection threshold, and gradient is more diagnostic because the relative change in gradient is very large compared to that for intercept. / Master of Science

To better study frequency related effects such as attenuation and tuning, we developed a frequency dependent seismic reflection analysis. Comprehensive tests on full waveform synthetics and observations from the Teal South ocean bottom seismic (OBS) data set confirmed that normal moveout (NMO) stretch could distort both frequency and amplitude information severely in shallow events and far offset traces. In synthetic tests, our algorithm recovered amplitude and frequency information ac-curately. This simple but robust target oriented NMO stretch correction scheme can be used on top of an existing seismic processing flow for further analyses. By combining the NMO stretch correction, spectral decomposition, and crossplots of am-plitude versus offset (AVO) attributes, we tested the frequency dependent workflow over Teal south and Ursa field data sets for improved reservoir characterization. As expected from NMO stretch characteristics, low frequencies have been less affected while mid and high frequency ranges were affected considerably. In seismic attribute analysis, the AVO crossplots from spectrally decomposed prestack data confirmed the improved accuracy and effectiveness of our workflow in mid and high frequency regions. To overcome poor spectral decomposition results due to low signal to noise ratio (S/N) in the Teal South application, we also implemented a substack scheme that stacks adjacent traces to increase S/N ratio while reducing the amount of data to process and increasing the accuracy of the spectral decomposition step. Synthetic tests verified the effectiveness of this additional step. An application to the Ursa, Gulf of Mexico, deep water data set showed significant improvement in high frequency data while correcting biased low frequency information.

To better study frequency related effects such as attenuation and tuning, we developed a frequency dependent seismic reflection analysis. Comprehensive tests on full waveform synthetics and observations from the Teal South ocean bottom seismic (OBS) data set confirmed that normal moveout (NMO) stretch could distort both frequency and amplitude information severely in shallow events and far offset traces. In synthetic tests, our algorithm recovered amplitude and frequency information ac-curately. This simple but robust target oriented NMO stretch correction scheme can be used on top of an existing seismic processing flow for further analyses. By combining the NMO stretch correction, spectral decomposition, and crossplots of am-plitude versus offset (AVO) attributes, we tested the frequency dependent workflow over Teal south and Ursa field data sets for improved reservoir characterization. As expected from NMO stretch characteristics, low frequencies have been less affected while mid and high frequency ranges were affected considerably. In seismic attribute analysis, the AVO crossplots from spectrally decomposed prestack data confirmed the improved accuracy and effectiveness of our workflow in mid and high frequency regions. To overcome poor spectral decomposition results due to low signal to noise ratio (S/N) in the Teal South application, we also implemented a substack scheme that stacks adjacent traces to increase S/N ratio while reducing the amount of data to process and increasing the accuracy of the spectral decomposition step. Synthetic tests verified the effectiveness of this additional step. An application to the Ursa, Gulf of Mexico, deep water data set showed significant improvement in high frequency data while correcting biased low frequency information.

Turbidite reservoirs in deep-water depositional systems, such as the oil fields in the offshore Gulf of Mexico and North Sea, are becoming an important exploration target in the petroleum industry. Accurate seismic reservoir characterization, however, is complicated by the heterogeneous of the sand and shale distribution and also by the lack of resolution when imaging thin channel deposits. Amplitude variation with offset (AVO) is a very important technique that is widely applied to locate hydrocarbons. Inaccurate estimates of seismic reflection amplitudes may result in misleading interpretations because of these problems in application to turbidite reservoirs. Therefore, an efficient, accurate, and robust method of modeling seismic responses for such complex reservoirs is crucial and necessary to reduce exploration risk. A fast and accurate approach generating synthetic seismograms for such reservoir models combines wavefront construction ray tracing with composite reflection coefficients in a hybrid modeling algorithm. The wavefront construction approach is a modern, fast implementation of ray tracing that I have extended to model quasishear wave propagation in anisotropic media. Composite reflection coefficients, which are computed using propagator matrix methods, provide the exact seismic reflection amplitude for a stratified reservoir model. This is a distinct improvement over conventional AVO analysis based on a model with only two homogeneous half spaces. I combine the two methods to compute synthetic seismograms for test models of turbidite reservoirs in the Ursa field, Gulf of Mexico, validating the new results against exact calculations using the discrete wavenumber method. The new method, however, can also be used to generate synthetic seismograms for the laterally heterogeneous, complex stratified reservoir models. The results show important frequency dependence that may be useful for exploration. Because turbidite channel systems often display complex vertical and lateral heterogeneity that is difficult to measure directly, stochastic modeling is often used to predict the range of possible seismic responses. Though binary models containing mixtures of sands and shales have been proposed in previous work, log measurements show that these are not good representations of real seismic properties. Therefore, I develop a new approach for generating stochastic turbidite models (STM) from a combination of geological interpretation and well log measurements that are more realistic. Calculations of the composite reflection coefficient and synthetic seismograms predict direct hydrocarbon indicators associated with such turbidite sequences. The STMs provide important insights to predict the seismic responses for the complexity of turbidite reservoirs. Results of AVO responses predict the presence of gas saturation in the sand beds. For example, as the source frequency increases, the uncertainty in AVO responses for brine and gas sands predict the possibility of false interpretation in AVO analysis.

The progressive growth of onshore shale production (both gas and liquids) to replace depleting and aging oil fields may benefit from the use of surface seismic shear wave data analysis for full characterization of shale reservoir properties and lead to optimum development of these resources. This includes descriptions of azimuthal anisotropy (HTI - transverse isotropy with a horizontal symmetry axis) for characterization of fractures and internal fracture systems. The objective of this study is to document a predicted distortion in polarization of propagating seismic shear waves upon reflection at a subsurface interface and to propose a correction to this distortion. The polarization distortion occurs even in wholly isotropic media. This correction is based on an understanding of shear amplitude behavior as a function of the reflection incidence angle, particularly differences in the reflection angle relation for different shear components. This study includes a demonstration of the efficacy of the proposed correction by applying it to simulated and real direct shear-wave source data. Such corrections should result in a minimized polarization distortion in the reflection process. The apparent consistency of a null value (zero crossing) of the SV-SV reflectivity (near 20-24 degrees) for common density and velocity contrasts as well as the remarkably regular behavior of the SV-SV and SH-SH reflectivity curves following a linear relation in sin2 and tan2 of the incidence angle and offers the opportunity for a simple and stable correction with minimal sensitivity to detailed knowledge of contrasts in velocity and density. The only independent information required for the correction is the angle of incidence where the SV-SV and SH-SH reflections vanish and the range of these angles is typically quite limited. Some key questions were addressed in gaining an understanding of shear wave polarization distortion upon reflection for varying model data: 1) how do we address reflected polarization distortion for purely isotropic medium for varying incidence angles? 2) How do we apply this correction for an isotropic and anisotropic media for both simulated and actual field data 3) How do we address applications to real data and how distorted amplitudes can be corrected to identify actual subsurface HTI anisotropy. Significantly, the polarization distortion correction is implemented as a simple extension of the established Alford rotation for normal incidence shear reflections of varying polarization. This extension leads to the improved analysis of direct shear-source 3D data with inherently distorted polarization. Thus, analysis may be applied to estimate HTI anisotropy previously not realizable in finite offset data subject to polarization distortion. Example applications to actual field data are included. Note that the polarization correction does remove the AVO effects often exploited in analysis of P-P data where polarization is not an issue that is, the AVO amplitude effect is essentially removed from the SV-SV and SH-SH oriented direct shear-wave profiles, which permits proper analysis of the polarization. Further, additional analysis of the polarization correction on field data with documented anisotropy will be required to fully develop the usefulness of this proposed correction. / text

Amplitude variation with offset (AVO) signatures in vertically transverse isotropic (VTI) media vary as the degree of the anisotropy contrast between layers varies. When the contrasts in two parameters (δ and ε) that quantify the VTI elastic anisotropy are varied, the fraction of energy that reflects from a given layer interface as a mode converted shear wave (R[subscript PS]) also varies for specified angles of incidence. Mode-converted (PS[subscript V]) AVO crossplots may potentially be used to map stratigraphic layers exhibiting intrinsic VTI anisotropy with the moderate to high degrees of weak elastic anisotropy that are often attributed to shale formations. Calculated values of reflected, mode-converted energy as a function of angle of incidence (R[subscript PS](i)) are plotted to determine what mode-converted seismic data indicate about the degree of VTI weak elastic anisotropy present in a given layer. These computations involve varying the degree of weak elastic anisotropy, in this case contrasts in Thomsen’s δ and ε parameters, so that the relationship between these parameters and the amplitude variation with offset (AVO) signature can be quantified. Once this relationship is understood, it may be possible to delineate sweet spot areas of shale formations in seismic data according to how the representative points plot on an AVO crossplot. For such crossplots, the y-intercepts of the reflectivity curves in a particular parameterized space are plotted on the x-axis while the slopes of the parameterized reflectivity curves in this parameterized space are plotted on the y-axis. The grouping of points on the mode-converted AVO crossplots according to the contrast in Thomsen’s δ and ε parameters for weak elastic anisotropy is encouraging. This grouping implies that it may indeed be possible to use an AVO attribute map to characterize a given organic shale formation according to its degree of intrinsic VTI anisotropy. This attribute map would be calibrated to known production data in the locality in order to locate which areas of the mode-converted AVO crossplot predict a likely production sweet spot. / text

We present a new method to stabilize the three-term AVO inversion using Curvelet and Wavelet transforms. Curvelets are basis functions that effectively represent otherwise smooth objects having discontinuities along smooth curves. The applied formalism explores them to make the most of the continuity along reflectors in seismic images. Combined with Wavelets, Curvelets are used to denoise the data by penalizing high frequencies and small contributions in the AVO-cube. This approach is based on the idea that rapid amplitude changes along the ray-parameter axis are most likely due to noise. The AVO-inverse problem is linearized, formulated and solved for all (x, z) at once. Using densities and velocities of the Marmousi model to define the fluctuations in the elastic properties, the performance of the proposed method is studied and compared with the smoothing along the ray-parameter direction only. We show that our method better approximates the true data after the denoising step, especially when noise level increases.

Conventional AVO analysis has been used for the past 4 decades to aid in locating oil and gas reservoirs for extraction. It is, however, not possible to use it to acquire information on the porosity of the rock, the fluid saturation or other important petrophysical parameters. In this thesis, I study the effects of attenuation on seismic waveform signatures, due to wave induced fluid-flow. In the first part of the thesis, 2 models were used to synthetically model the attenuation caused by the wave induced fluid-flow: White's model and the double-porosity dual-permeability (DPDP) model. The parameters used for modeling were both synthetic and acquired from real well data of a known oil field off the coast of Norway. White's model was found to model relatively high attenuation (5%) for intermediately consolidated gas reservoirs while oil saturated intermediately consolidated reservoirs showed such low attenuation (0.3%) that it is easy to say that for the real-world situation it would not be detected. The DPDP model seemed to be able to better describe the attenuation and gave attenuations up to 10% for an intermediately consolidated oil reservoir, but due to lack of parameters from well data it was not sufficiently able to model the real-world situation. The synthetic data, however, show interesting characteristics and it is therefore recommended that more and detailed well parameters be acquired if the research should continue. For the second part, Svenska Petroleum Exploration AB and Det Norske Oljeselskap ASA provided stacked seismic data that were spectrally analyzed for hints of attenuation variation with frequency (using Fourier Transform and Complex Spectral Decomposition). Twelve locations, on the stacked seismic cube, were analyzed; six oil saturated; and six (assumed) water saturated. At each location, a main trace was selected along with the two nearby traces on each side of it (five in total). The Complex Spectral Decomposition method seemed unable to correctly break down the stacked section's signal, which is why Fourier Transform was used for further analysis. The frequency analysis showed a peak at ~30 Hz for both oil and water saturated reservoirs which seems like a characteristic frequency of the source, but that was unfortunately not confirmed and not enough time was available to test the assumption. The Fourier transform seems to show some difference between oil and water saturated traces, but that could well be because of lithological differences and not the pore fluid. It is therefore recommended, if research is to be continued, that 4D seismic data is used to analyze the same location with respect to time. It is also recommended that pre-stack or shot data be used as information is lost in stacked data. / Konventionell AVO-analys har använts under fyra deceniär som ett hjälpmedel för att finna olje- och gasreserver, men tekniken kan även användas för att erhålla information om bergets porositet, vätskemättnaden och andra viktiga petrofysiska parametrar. I denna avhandlingen har jag studerat hur våginducerat vätskeflöde påverkar dämpningen av den seismiska vågformssignaturen. I den första delen av avhandlingen användes två metoder för att syntetisk modellera dämpning orsakad av våginducerat vätskeflöde: "White's modell" och "double-porosity dual-permeability (DPDP) modellen". Både syntetiska parametrar och verkliga parametrar från borrhålsdata från ett känt norskt oljefält användes vid modelleringen. White's modell visade sig modellera relativt kraftig dämpning (5%) för medelstarkt konsoliderade gasreservoarer medan för oljereservoarer med motsvaranda konsolidering dämpningen var så låg (0.3%) att det är uppenbart att i en verklig situation skulle dämpningen inte vara mätbar. DPDP modelleringen verkar vara bättre på att beskriva dämpningen och gav dämpningar upp till 10% för en medelstarkt konsoliderad oljereservoar. Brist på parametrar från borrhålsdata gjorde att det inte var möjligt att på ett tillfredställande sätt modellera en verklig situation.Dock visade syntetisk data intressant karaktäristik och det rekommenderas därför att mer och detaljerade borrhålsparametrar mäts om ytterligare forskning om detta ska genomföras. För den andra delen av avhandlingen har Svenska Petroleum Exploration AB och Det Norske Oljeselskap ASA bidragit med stackad seismisk data som även var spectralanalyserad för indikationer på frekvensberoende dämpningsvariationer (utfört med fouriertransform och komplex spectraldekomposition). Tolv områden på den stackade kuben analyserades; sex oljemättade och sex som antogs vara vattenmättade. I varje område valdes en huvudtracé och de två närmaste tracéerna på vardera sida (totalt fem tracéer). Metoden med komplex spectraldekomposition klarade inte att analysera signalen från den stackade sektionen, varför fouriertransform användes för vidare analys. Frekvensanalysen gav en topp vid ~30 Hz för både olje- och vattenmättade reservoarer vilket tycks vara en karaktäristisk frekvens för källan. Detta kunde tyvärr inte bekräftas och tiden räckte inte till för att testa antagandet. Fouriertransformen tycks visa en viss skillnad mellan olje- och vattenmättade tracéer, men det kan också bero på skillnad i litologin snarare än porvätskan. Där för rekommenderas vid fortsättning på denna forskning att 4D seismisk data används för att analysera samma område men med data från olika tidpunkter. Det rekommenderas även att ostackad eller råa skott-data används eftersom väsentlig information kan försvinna när data stackas. / <p>Advisor present: Dr. Chris Juhlin</p><p>Examiner: Dr. Milovan Urosevic</p><p>Opponent: Álvaro Polín Tornero</p>

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Amplitude Variation with Oset (AVO) inversion is one of the techniques that is being used to estimate subsurface physical parameters such as P-wave velocity, S-wave velocity, and density or their attributes. AVO inversion is an ill-conditioned problem which has to be regularized in order to obtain a stable and unique solution. In this thesis, a Bayesian procedure that uses a Multivariate Cauchy distribution as a prior probability distribution is introduced. The prior includes a scale matrix that imposes correlation among the AVO attributes and induces a regularization that provokes solutions that are sparse and stable in the presence of noise. The performance of this regularization is demonstrated by both synthetic and real data examples using linearized approximations to the Zoeppritz equations. / Geophysics