Odin Petroleum

Odin, Norway

Odin Petroleum

Odin, Norway
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Avseth P.,Odin Petroleum | Skjei N.,Statoil | Mavko G.,Stanford University
74th European Association of Geoscientists and Engineers Conference and Exhibition 2012 Incorporating SPE EUROPEC 2012: Responsibly Securing Natural Resources | Year: 2012

We demonstrate how to characterize and model the effects of heterogenous grain contacts and associated stress sensitivity in reservoir sandstones. We use nested Hashin-Shtrikman modeling, where we first mix loose sands and cemented sandstones to create a patchy cemented high-porosity end-member. Next, we use Hashin-Shtrikman modeling to account for porosity variation between high porosity end-member and mineral point. This approach enable us to honor stress sensitivity in the patchy cemented sandstones, as the loose grain contacts will behave according to Hertzian contact theory. This approach can be used to quantify stress sensitivity in reservoir sandstones where core samples are lacking or inreliable. Future research will focus on validating this approach on real data.

Avseth P.,Odin Petroleum | Skjei N.,Odin Petroleum | Njerve S.,Odin Petroleum | Kugler S.,Statoil
74th European Association of Geoscientists and Engineers Conference and Exhibition 2012 Incorporating SPE EUROPEC 2012: Responsibly Securing Natural Resources | Year: 2012

Rock physics models for stress dependency in reservoir rocks are essential for quantification and interpretation of 4-D seismic signatures during reservoir depletion and injection. In this study, we apply a rock physics modelling approach to quantify seismic time shifts and time shift derivatives associated with stress changes. The time shifts will be a function of the rock stiffness, and it is therefore important to determine the local changes in rock properties before we can predict stress and fluid sensitivity from time shift attributes. We apply this approach to 4 wells in the Visund Field area and compare the results with observed time shift attributes. Using this approach, we estimate the expected pressure change at the different well locations where we have good control of the dry rock properties. With a good understanding of local geology, the approach can also be used to interpret pressure and fluid changes from time shifts in interwell areas.

Lehocki I.L.,Odin Petroleum | Avseth P.A.,Odin Petroleum | Buran H.B.,Lundin Norway | Jorstad A.J.,Lundin Norway
74th European Association of Geoscientists and Engineers Conference and Exhibition 2012 Incorporating SPE EUROPEC 2012: Responsibly Securing Natural Resources | Year: 2012

Present day rock physics properties and associated seismic signatures are controlled by burial history, tectonic events and temperature changes, diagenetic alterations and pressure modifications. Hence, in order to fully understand the seismic signatures of a prospect, we should not only relate rock properties to present day geologic factors (porosity, clay content, mineralogy, in situ pressure, etc.), but honour the geologic processes through time (Avseth and Dræge, 2011). There are very few studies documenting the effect of complex tectonic and uplift on rock physics and seismic properties (e.g., Brevik et al., 2011). Taking into account diagenesis and tectonic events, we can predict compaction trends and associated seismic velocities in areas with more complex burial history involving both mechanical and chemical compaction, as well as uplift episodes and corresponding erosion. The resulting rock physics trends help us to better constrain AVO inversion and classification under such circumstances. We propose a methodology for statistical classification of fluids and facies in uplifted areas. The robustness of the method was validated by comparing the results to the information obtained from newly drilled well situated near the Loppa High in Barents Sea.

Avseth P.,Odin Petroleum | Mukerji T.,Stanford University | Mavko G.,Stanford University | Dvorkin J.,Stanford University
Geophysics | Year: 2010

Rock physics has evolved to become a key tool of reservoir geophysics and an integral part of quantitative seismic interpretation. Rock-physics models adapted to site-specific deposition and compaction help extrapolate rock properties away from existing wells and, by so doing, facilitate early exploration and appraisal. Many rock-physics models are available, each having benefits and limitations. During early exploration or in frontier areas, direct use of empirical site-specific models may not help because such models have been created for areas with possibly different geologic settings. At the same time, more advanced physics-based models can be too uncertain because of poor constraints on the input parameters without well or laboratory data to adjust these parameters. A hybrid modeling approach has been applied to siliciclastic unconsolidated to moderately consolidated sediments. Specifically in sandstones, a physical-contact theory (such as the Hertz-Mindlin model) combined with theoretical elastic bounds (such as the Hashin-Shtrikman bounds) mimics the elastic signatures of porosity reduction associated with depositional sorting and diagenesis, including mechanical and chemical compaction. For soft shales, the seismic properties are quantified as a function of pore shape and occurrence of cracklike porosity with low aspect ratios. A work flow for upscaling interbedded sands and shales using Backus averaging follows the hybrid modeling of individual homogenous sand and shale layers. Different models can be included in site-specific rock-physics templates and used for quantitative interpretation of lithology, porosity, and pore fluids from well-log and seismic data. © 2010 Society of Exploration Geophysicists.

Avseth P.,Odin Petroleum | Skjei N.,Statoil
Leading Edge (Tulsa, OK) | Year: 2011

Rock physics models for fluid and stress dependency in reservoir rocks are essential for quantification and interpretation of 4D seismic signatures during reservoir depletion and injection. However, our ability to predict the sensitivity to pressure from first principles is poor. The current state-of-the-art requires that we calibrate the pressure dependence of velocity with core measurements. A major challenge is the fact that consolidated rocks often break up during coring, and hence the stress sensitivity is likely to be overpredicted in the laboratory relative to the in-situ conditions (Furre et al., 2009). For unconsolidated sands, acquisition of core samples is not very feasible due to the friable nature of the sediments. One physical model that has been applied to predict pressure sensitivity in unconsolidated granular media is the Hertz-Mindlin contact theory. Several authors (Vernik and Hamman, 2009, among others) have suggested empirical models with fitting parameters that correlate with microcrack intensity, soft porosity, and aspect ratio of the rock, and feasibility studies can be undertaken based on assumptions about these parameters. These models may not be easy to use for poorly to moderately consolidated sandstones with contact cement, where crack parameters and aspect ratios are difficult to quantify. © 2011 Society of Exploration Geophysicists.

Duffaut K.,Statoil | Avseth P.,Odin Petroleum | Landro M.,Norwegian University of Science and Technology
Leading Edge (Tulsa, OK) | Year: 2011

During 4D seismic reservoir characterization, it is important to have reliable rock physics models for both static (e.g., mineralogy, porosity, cement volume) and dynamic (e.g., saturation, pressure, temperature) reservoir parameters. Without a good understanding of reservoir geology and associated static rock physics properties, it is impossible to interpret time-variant changes in pore pressure and saturation (Andersen et al., 2009). The dry rock properties of the reservoir can be obtained from well-log data combined with geological information about mineral composition and rock texture, and Gassmann theory to estimate the effect of pore fluid changes. Normally, core measurements are undertaken to quantify stress sensitivity, but these are often affected by induced fractures caused by the coring acquisition that will enhance the stress sensitivity of the rock (Holt et al., 2005). Duffaut and Landro (2007) showed how calibrated Hertz-Mindlin contact theory could be applied to estimate stress sensitivity on VP/VS ratios in two North Sea oil fields (Statfjord and Gullfaks), in order to explain observed AVO signatures during water injection and associated pore-pressure increase. It was found that loose Gullfaks sands yielded high VP/VS ratios (up to about 7) during water injection, whereas slightly quartz-cemented Statfjord sands yielded more moderate changes in VP/VS ratios (approximately 2). The differences were modeled by varying the number of grain-to-grain contacts. In this paper we further investigate the pressure sensitivity of seismic parameters in these two oil fields, applying the rock physics modeling approach presented by Avseth and Skjei (TLE, this issue), and we demonstrate a good match between rock physics modelling results and seismic observations in terms of VP/VS. The stress sensitivity of VP/V S decreases drastically when sands become cemented, as crack-like porosity at grain contacts are eliminated. © 2011 Society of Exploration Geophysicists.

Avseth P.,Odin Petroleum | DraGe A.,Statoil
SEG Technical Program Expanded Abstracts | Year: 2011

We present a rock physics study of well log data in the Troll East area, North Sea, where we focus on shallow-marine and deltaic pre- and syn-rift late Jurassic reservoir rocks. These reservoir sandstones are poorly consolidated, and presently buried at around 1100-1200m. However, the rifting phase implied fault-block rotation and differential compaction and burial in the Troll East area. The eastern section of the fault-block was down-tilted relative to the western section. In the post-rift phase, the fault-block subsided, the environment changed to a deep marine setting, and the reservoir sandstones were buried by Cretaceous and Tertiary shales, marls and occasionally sandstones. During Tertiary, there was tectonic inversion, gradual uplift in the east, and regional erosion, before quarternary shallow marine and glaciar sediments deposited. In this study, we investigate the effect of the burial history on the present day rock physics and seismic properties. We demonstrate how important it is to understand not only the present day situation when interpreting rock physics properties, but also the burial history of the rocks. The rocks have "memory" of the stress and temperature history from deposition, via mechanical and chemical compaction, to uplift and present day burial. Therefore we occasionally observe well cemented and high velocity rocks not corresponding with todays temperatures and depths. Finally, we show how we can use porosity logs to derive maximum diagenetic temperature for two wells by combining rock physics and geochemical models. © 2011 Society of Exploration Geophysicists.

Carcione J.M.,National Institute of Oceanography and Applied Geophysics - OGS | Helle H.B.,Odin Petroleum | Avseth P.,Odin Petroleum | Avseth P.,Norwegian University of Science and Technology
Geophysics | Year: 2011

Source rocks are described by a porous transversely isotropic medium composed of illite and organic matter (kerogen, oil, and gas). The bulk modulus of the oil/gas mixture is calculated by using a model of patchy saturation. Then, the moduli of the kerogen/fluid mixture are obtained with the Kuster and Toksöz model, assuming that oil is the inclusion in a kerogen matrix. To obtain the seismic velocities of the shale, we used Backus averaging and Gassmann equations generalized to the anisotropic case with a solid-pore infill. In the latter case, the dry-rock elastic constants are calculated with a generalization of Krief equations to the anisotropic case. We considered 11 samples of the Bakken-shale data set, with a kerogen pore infill. The Backus model provides lower and upper bounds of the velocities, whereas the Krief/Gassmann model provides a good match to the data. Alternatively, we obtain the dry-rock elastic moduli by using the inverse Gassmann equation, instead of using Krief equations. Four cases out of 11 yielded physically unstable results. We also considered samples of the North Sea Kimmeridge shale. In this case, Backus performed as well as the Krief/Gassmann model. If there is gas and oil in the shale, we found that the wave velocities are relatively constant when the amount of kerogen is kept constant. Varying kerogen content implies significant velocity changes versus fluid (oil) saturation. © 2011 Society of Exploration Geophysicists.

Golikov P.,Norwegian University of Science and Technology | Avseth P.,Odin Petroleum | Stovas A.,Norwegian University of Science and Technology | Bachrach R.,Tel Aviv University
Geophysical Prospecting | Year: 2013

In this paper, we create rock physics templates for heterogeneous and anisotropic thin-bedded sand-shale intervals as a function of group angle, net-to-gross, saturation and porosity as variable parameters. These templates are basically cross-plots of acoustic impedance versus P- to S-velocity ratio. We apply these templates to interpret well log data from a vertical and a deviated well, respectively, in a North Sea turbidite system. We are able to infer the shale anisotropic elastic moduli and Thomsen parameters by comparing the measured velocities in a deviated well with the velocities in an adjacent vertical well. Our modeling captures the observed trends in the data as we go from a vertical well to a deviated well through a heterogeneous reservoir saturated with light oil and water. We can clearly see how the reservoir properties changes due to the presence of anisotropy. We also perform an AVO sensitivity study as a function of heterogeneity and hydrocarbon saturation. © 2012 European Association of Geoscientists & Engineers.

Avseth P.A.,Odin Petroleum | Bachrach R.,Tel Aviv University
72nd European Association of Geoscientists and Engineers Conference and Exhibition 2010: A New Spring for Geoscience. Incorporating SPE EUROPEC 2010 | Year: 2010

In this paper we study the effect of shale anisotropy in a deviated well, and we are able to infer the anisotropic elastic moduli and Thomsen parameters by comparing the measured phase velocities in a deviated well with the velocities in an adjacent vertical well. After deriving shale anisotropy parameters, we apply Backus average combined with Gassmann theory to estimate 3D rock physics template models of apparent AI and Vp/Vs values at a given deviation angle (72 degrees), for varying reservoir heterogeneity and saturation. © 2010, European Association of Geoscientists and Engineers.

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