AVO attribute inversion for finely layered reservoirs

Geophysics ◽  
2006 ◽  
Vol 71 (3) ◽  
pp. C25-C36 ◽  
Author(s):  
Alexey Stovas ◽  
Martin Landrø ◽  
Per Avseth
Keyword(s):  
Seismic Data ◽  
Rock Physics ◽  
Time Lapse ◽  
Oil Saturation ◽  
Seismic Properties ◽  
Seismic Input ◽  
Fluid Properties ◽  
Random Variability ◽  
Net To Gross ◽  
Avo Attributes

Assuming that a turbidite reservoir can be approximated by a stack of thin shale-sand layers, we use standard amplitude variaiton with offset (AVO) attributes to estimate net-to-gross (N/G) and oil saturation. Necessary input is Gassmann rock-physics properties for sand and shale, as well as the fluid properties for hydrocarbons. Required seismic input is AVO intercept and gradient. The method is based upon thin-layer reflectivity modeling. It is shown that random variability in thickness and seismic properties of the thin sand and shale layers does not change significantly the AVO attributes at the top and base of the turbidite-reservoir sequence. The method is tested on seismic data from offshore Brazil. The results show reasonable agreement between estimated and observed N/G and oil saturation. The methodology can be developed further for estimating changes in pay thickness from time-lapse seismic data.

scholarly journals Time-Lapse Seismic Monitoring of Onshore Reservoirs in Niger Delta, Field ‘K’ as a Case Study

2017 ◽  
Vol 1 (1) ◽  
pp. 23-27 ◽  
Author(s):  
A. Ogbamikhumi ◽  
T. Tralagba ◽  
E. E. Osagiede
Keyword(s):  
Seismic Data ◽  
Acoustic Impedance ◽  
Niger Delta ◽  
Rock Physics ◽  
Time Lapse ◽  
Seismic Survey ◽  
Impedance Change ◽  
Data Set ◽  
Reservoir Fluid ◽  
4D Seismic

Field ‘K’ is a mature field in the coastal swamp onshore Niger delta, which has been producing since 1960. As a huge producing field with some potential for further sustainable production, field monitoring is therefore important in the identification of areas of unproduced hydrocarbon. This can be achieved by comparing production data with the corresponding changes in acoustic impedance observed in the maps generated from base survey (initial 3D seismic) and monitor seismic survey (4D seismic) across the field. This will enable the 4D seismic data set to be used for mapping reservoir details such as advancing water front and un-swept zones. The availability of good quality onshore time-lapse seismic data for Field ‘K’ acquired in 1987 and 2002 provided the opportunity to evaluate the effect of changes in reservoir fluid saturations on time-lapse amplitudes. Rock physics modelling and fluid substitution studies on well logs were carried out, and acoustic impedance change in the reservoir was estimated to be in the range of 0.25% to about 8%. Changes in reservoir fluid saturations were confirmed with time-lapse amplitudes within the crest area of the reservoir structure where reservoir porosity is 0.25%. In this paper, we demonstrated the use of repeat Seismic to delineate swept zones and areas hit with water override in a producing onshore reservoir.

Common-focus point-based target-oriented imaging approach for continuous seismic reservoir monitoring

Geophysics ◽  
2018 ◽  
Vol 83 (4) ◽  
pp. M41-M48 ◽  
Author(s):  
Hongwei Liu ◽  
Mustafa Naser Al-Ali
Keyword(s):  
Seismic Data ◽  
Rock Physics ◽  
Time Lapse ◽  
Velocity Estimation ◽  
Estimation Methods ◽  
Data Sets ◽  
Data Set ◽  
Velocity Models ◽  
Reservoir Monitoring ◽  
Focus Point

The ideal approach for continuous reservoir monitoring allows generation of fast and accurate images to cope with the massive data sets acquired for such a task. Conventionally, rigorous depth-oriented velocity-estimation methods are performed to produce sufficiently accurate velocity models. Unlike the traditional way, the target-oriented imaging technology based on the common-focus point (CFP) theory can be an alternative for continuous reservoir monitoring. The solution is based on a robust data-driven iterative operator updating strategy without deriving a detailed velocity model. The same focusing operator is applied on successive 3D seismic data sets for the first time to generate efficient and accurate 4D target-oriented seismic stacked images from time-lapse field seismic data sets acquired in a [Formula: see text] injection project in Saudi Arabia. Using the focusing operator, target-oriented prestack angle domain common-image gathers (ADCIGs) could be derived to perform amplitude-versus-angle analysis. To preserve the amplitude information in the ADCIGs, an amplitude-balancing factor is applied by embedding a synthetic data set using the real acquisition geometry to remove the geometry imprint artifact. Applying the CFP-based target-oriented imaging to time-lapse data sets revealed changes at the reservoir level in the poststack and prestack time-lapse signals, which is consistent with the [Formula: see text] injection history and rock physics.

scholarly journals Effect of grain-scale gas patches on the seismic properties of double porosity rocks

2016 ◽  
Vol 208 (1) ◽  
pp. 432-436 ◽  
Author(s):  
Stanislav Glubokovskikh ◽  
Boris Gurevich
Keyword(s):  
High Frequency ◽  
Low Frequency ◽  
Rock Physics ◽  
Time Lapse ◽  
Double Porosity ◽  
Ultrasonic Velocities ◽  
Seismic Properties ◽  
Partially Saturated ◽  
Frequency Regime ◽  
Wave Induced

Time-lapse ultrasonic measurements constitute a tool to establish and calibrate rock physics models for surface seismic monitoring of partially saturated rocks. This workflow requires one to take into account seismic dispersion caused by frequency-dependent wave-induced fluid flow. We develop a theory of squirt flow in rocks saturated with a viscoelastic material containing isolated gas patches between compliant intergranular contacts. This model is valid for the entire frequency range, from seismic to ultrasonic. In the limit of full saturation the derived equations reduce to the Gassmann equations in the low-frequency regime and traditional squirt theory in the high-frequency regime. The model prediction of ultrasonic velocities versus saturation matches with experimental observations.

Fluid-pressure discrimination in anisotropic reservoir rocks — A sensitivity study

Geophysics ◽  
2005 ◽  
Vol 70 (3) ◽  
pp. O1-O11 ◽  
Author(s):  
Alexey Stovas ◽  
Martin Landrø
Keyword(s):  
Pore Pressure ◽  
Seismic Data ◽  
Seismic Anisotropy ◽  
Fluid Pressure ◽  
Rock Physics ◽  
Time Lapse ◽  
Reservoir Rock ◽  
Sand Layer ◽  
Weak Anisotropy ◽  
Fluid Saturation

We investigate how seismic anisotropy influences our ability to distinguish between various production-related effects from time-lapse seismic data. Based on rock physics models and ultrasonic core measurements, we estimate variations in PP and PS reflectivity at the top reservoir interface for fluid saturation and pore pressure changes. The tested scenarios include isotropic shale, weak anisotropic shale, and highly anisotropic shale layers overlaying either an isotropic reservoir sand layer or a weak anisotropic sand layer. We find that, for transverse isotropic media with a vertical symmetry axis (TIV), the effect of weak anisotropy in the cap rock does not lead to significant errors in, for instance, the simultaneous determination of pore-pressure and fluid-saturation changes. On the other hand, changes in seismic anisotropy within the reservoir rock (caused by, for instance, increased fracturing) might be detectable from time-lapse seismic data. A new method using exact expressions for PP and PS reflectivity, including TIV anisotropy, is used to determine pressure and saturation changes over production time. This method is assumed to be more accurate than previous methods.

scholarly journals TIME-LAPSE POROSITY AND VELOCITY ANALYSIS USING ROCK PHYSICS MODELS IN NIGER DELTA, NIGERIA

2021 ◽  
Vol 5 (2) ◽  
pp. 47-52
Author(s):  
Emmanuel Aniwetalu ◽  
Akudo Ernest ◽  
Juliet Ilechukwu ◽  
Okechukwu Ikegwuonu ◽  
Uzochukwu Omoja
Keyword(s):  
Oil And Gas ◽  
Seismic Velocity ◽  
Water Saturation ◽  
Rock Physics ◽  
Time Lapse ◽  
Fluid Substitution ◽  
Average Value ◽  
Velocity Models ◽  
Fluid Properties ◽  
Average Water

The analysis of 3-D and time-lapse seismic data in Isomu Field has offered the dynamic characterization of the reservoir changes. The changes were analyzed using fluid substitution and seismic velocity models. The results of the initial porosity of the reservoirs was 29.50% with water saturation value of12%.The oil and gas maintained saturation values of 40% and 48% with average compressional and shear wave velocities of 2905m/s and 1634m/s respectfully. However, in fluid substitution modelling, the results reflect a change in fluid properties where average gas and oil saturation assume a new status of 34% and 24% which indicates a decrease by 14% and 16% respectively. The average water saturation increases by 30% with an average value of 42%. The decrease in hydrocarbon saturation and increase in formation water influence the porosity. Thus, porosity decreased by 4.16% which probably arose from the closure of the aspect ratio crack due to pressure increase.

Quantitative application of post-stack inversion of organic-rich shale based on rock physics linear relationship and 3D seismic data, Perth Basin, Western Australia

2014 ◽  
Vol 54 (2) ◽  
pp. 532
Author(s):  
Yazeed Altowairqi ◽  
Reza Rezaee ◽  
Milovan Urosevic
Keyword(s):  
Shale Gas ◽  
Seismic Data ◽  
Rock Physics ◽  
Seismic Inversion ◽  
3D Seismic ◽  
Physical Relationship ◽  
Seismic Properties ◽  
Attribute Analysis ◽  
Exploration And Production ◽  
Compressional Velocity

Unconventional resources such as shale gas have been an extremely important exploration and production target. To understand the seismic responses of the shale gas plays, the use of rock physical relationship is important, which is constrained with geology and formation-evaluation analysis. Since organic-rich shale seismic properties remains poorly understood, seismic inversion can be used to identify the organic-rich shale from barren shale. This approach helps identify and map spatial distributions and of the organic rich shales. This study shows the acoustic impedance (AI), which is the product of compressional velocity and density, decreases nonlinearly with increasing total organic carbon (TOC) content. TOC is obtained using Roc-Eval pyrolysis for more than 120 core shale samples for the Perth Basin. By converting the AI data to TOC precent on the seismic data, we therefore can map lateral distribution, thickness, and variation in TOC profile. This extended abstract presents a case study of the northern Perth Basin 3D seismic with application of different approaches of seismic inversion and multi-attribute analysis with the rock physical relationships.

Rock physics analysis and time-lapse rock imaging of geochemical effects due to the injection of CO2 into reservoir rocks

Geophysics ◽  
2011 ◽  
Vol 76 (5) ◽  
pp. O23-O33 ◽  
Author(s):  
Tiziana Vanorio ◽  
Amos Nur ◽  
Yael Ebert
Keyword(s):  
Seismic Velocity ◽  
Fluid Pressure ◽  
Rock Physics ◽  
Time Lapse ◽  
Seismic Monitoring ◽  
Physical Parameters ◽  
Salt Precipitation ◽  
S Wave ◽  
Seismic Properties ◽  
Small Pore

The fundamental concept of time-lapse seismic monitoring is that changes in physical parameters—such as saturation, pore fluid pressure, temperature, and stress—affect rock and fluid properties, which in turn alter the seismic velocity and density. Increasingly, however, time-lapse seismic monitoring is called upon to quantify subsurface changes due in part to chemical reactions between injected fluids and the host rocks. This study springs from a series of laboratory experiments and high-resolution images assessing the changes in microstructure, transport, and seismic properties of fluid-saturated sandstones and carbonates injected with [Formula: see text]. Results show that injecting [Formula: see text] into a brine-rock system induces chemo-mechanical mechanisms that permanently change the rock frame. Injecting [Formula: see text] into brine-saturated-sandstones induces salt precipitation primarily at grain contacts and within small pore throats. In rocks with porosity lower than 10%, salt precipitation reduces permeability and increases P- and S-wave velocities of the dry rock frame. On the other hand, injecting [Formula: see text]-rich water into micritic carbonates induces dissolution of the microcrystalline matrix, leading to porosity enhancement and chemo-mechanical compaction under pressure. In this situation, the elastic moduli of the dry rock frame decrease. The results in these two scenarios illustrate that the time-lapse seismic response of chemically stimulated systems cannot be modeled as a pure fluid-substitution problem. A first set of empirical relationships links the time-variant effects of injection to the elastic properties of the rock frame using laboratory velocity measurements and advanced imaging.

Prediction of residual oil saturation by using the ratio of amplitude attributes of time-lapse seismic data

Geophysics ◽  
2017 ◽  
Vol 82 (1) ◽  
pp. IM1-IM12 ◽  
Author(s):  
Meng Li ◽  
Zhen Liu ◽  
Minzhu Liu ◽  
Huilai Zhang
Keyword(s):  
Seismic Data ◽  
Time Lapse ◽  
Seismic Interpretation ◽  
Impedance Change ◽  
Residual Oil ◽  
Data Set ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Amplitude Difference ◽  
Fluid Saturation

Subtraction of baseline and monitoring seismic data is a common step in highlighting reservoir changes in time-lapse seismic interpretation. However, ambiguity exists in the interpretation of the amplitude difference, which is controlled by fluid change and reservoir thickness. To estimate the residual oil saturation quantitatively, we have developed a time-lapse seismic interpretation method that uses the ratio of amplitude attributes extracted from the baseline and monitoring seismic data. The relationship between impedance change and the ratio of the baseline and monitoring amplitude attributes is determined to avoid the influence of reservoir thickness. Subsequently, the fluid saturation is calculated from the impedance change by using a proper petrophysical relationship. We have tested our new method on a real time-lapse seismic data set from a water-flooded reservoir in the deepwater area of West Africa. The water-flooded area determined from the amplitude difference does not completely match the production logs because of the influence of variations in the reservoir thickness. However, the residual oil distribution calculated with the proposed method matches the production logs well. The connectivity of sandstone bodies is also evaluated based on an integrated interpretation of estimated oil saturation. With its simple principles and easy accessibility, our method improves the accuracy of time-lapse seismic data interpretation in water-flooded oil reservoirs. Furthermore, the quantitative interpretation of fluid change enables the time-lapse seismic technology to guide reservoir development directly.

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