Reservoir Characterization Using Converted-wave Seismic Data - Case Study from Athabasca Oil Sands

Dumitrescu, Carmen C.; Larson, Glenn; Mayer, F.; Talinga, Draga

doi:10.3997/2214-4609.20140668

Cited by 6 publications

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“…Our workflow for the inversions is shown in Figure 5 and was previously presented at the 76th EAGE Conference & Exhibition (Dumitrescu et al, 2014). In previous studies, NNA for rock properties was used successfully to predict density and porosity changes in the thin Gething Formation channels and the Cadomin gas reservoir in the Western Canadian Foreland Basin (Dumitrescu and Mayer, 2009) and in an oil sands reservoir related to the Long Lake South project (Dumitrescu and Lines, 2010).…”

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confidence: 99%

Resistivity and density estimation from multicomponent seismic data: Case study from the Lower Cretaceous McMurray Formation, Athabasca Oil Sands

Mayer

Dumitrescu

Ltd

et al. 2014

SEG Technical Program Expanded Abstracts 2014

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We present a case study of oil sands reservoir characterization using resistivity and density seismic volumes estimated from multicomponent seismic data. In the Athabasca Oil Sands region of Alberta, the Lower Cretaceous McMurray Formation is the reservoir. In this reservoir the sand can be differentiated from shale based on density. The sands could be wet or bitumen bearing and resistivity proved to be the only property which can differentiate between the two kinds of sands. We estimated resistivity from multicomponent 3D seismic data integrated with cores and wells data. Our workflow includes petrophysical analysis, joint PP-PS prestack inversion and neural network analysis. Joint PP-PS prestack inversion produces very good estimates of the elastic properties: P-and S-wave velocities and density. Neural network analysis is used for density and resistivity estimation. In all neural network analyses the most significant seismic attributes include converted-wave information. Key problems solved include excellent pay characterization, correct flank water mapping and accurate identification of high versus low oil saturation in zones with high salinity bitumen sand.

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Section: Continued From Page 17mentioning

confidence: 99%

Resistivity and density estimation from multicomponent seismic data: Case study from the Lower Cretaceous McMurray Formation, Athabasca Oil Sands

Mayer

Dumitrescu

Ltd

et al. 2014

SEG Technical Program Expanded Abstracts 2014

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Overburden characterization with formation pore pressure and anisotropic stress field estimation in the Athabasca Basin, Canada

Dumitrescu

Talinga

2019

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One of the challenges encountered during the life cycle of an oil-sand thermal-production reservoir is the prediction of the formation pore pressure and in situ stress regime during the assessment phase of the reservoir development and, more importantly, during the development phase. We have investigated the state of formation pore pressure and stress in the overburden — represented by the Clearwater Formation, Grand Rapids Formation, and Colorado Group — of a preproduction oil-sands reservoir situated in the Athabasca Basin of Alberta, Canada. Our methodology integrates pressure data from piezometers, stress data from mini-frac (MF), dipole sonic logs, and elastic properties obtained from multicomponent 3D seismic inversion data. It combines the Terzaghi effective stresses with the Schoenberg and Sayers elastic stiffness matrix for horizontal transversely isotropic fractured materials. The total principal stresses (vertical, minimum, and maximum horizontal stresses) are expressed as functions of the normal fracture weakness (anisotropic correction factor), formation pore pressure, seismic data (Lamé constants), and the Biot-Willis coefficient. The effective principal stresses are estimated from the equivalent total principal stresses and the formation pore pressure multiplied by the Biot-Willis coefficient. On all three overburden intervals analysed, the relations between principal stresses indicate a normal stress regime. The estimated total minimum horizontal stress matches the MF values within 10%. The formation pore pressure, along with the 3D seismically derived estimates of the total and effective principal stresses, allows for better assessment of the caprock integrity and for operational savings based on a reduced number of MF tests. It can also be used for stress estimation within the formations hosting aquifers, which is so important for thermal production. Understanding the subsurface on the reservoir area is important for efficient production, but knowing the subsurface of the overburden is equally important for reducing potential issues due to production.

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Facies analysis using multicomponent seismic data in oil-sands reservoir: Case study from Athabasca Oil Sands

Dumitrescu

Vermeulen²,

Gammie³

et al. 2014

SEG Technical Program Expanded Abstracts 2014

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Reservoir Characterization Using Converted-wave Seismic Data - Case Study from Athabasca Oil Sands

Cited by 6 publications

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Resistivity and density estimation from multicomponent seismic data: Case study from the Lower Cretaceous McMurray Formation, Athabasca Oil Sands

Resistivity and density estimation from multicomponent seismic data: Case study from the Lower Cretaceous McMurray Formation, Athabasca Oil Sands

Overburden characterization with formation pore pressure and anisotropic stress field estimation in the Athabasca Basin, Canada

Facies analysis using multicomponent seismic data in oil-sands reservoir: Case study from Athabasca Oil Sands

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