Sensitivity study of rock-physics parameters for modeling time-lapse seismic response of Norne field

Geophysics ◽  
2013 ◽  
Vol 78 (6) ◽  
pp. D511-D523 ◽  
Author(s):  
Amit Suman ◽  
Tapan Mukerji
Keyword(s):  
Seismic Response ◽  
Pore Pressure ◽  
History Matching ◽  
Joint Inversion ◽  
Rock Physics ◽  
Clay Content ◽  
Time Lapse ◽  
Fluid Substitution ◽  
Seismic Modeling ◽  
Sensitive Parameters

Time-lapse seismic modeling is an important step in joint inversion of time-lapse seismic and production data of a field. Rock-physics analysis is the basis for modeling the time-lapse seismic data. However, joint inversion of both types of data for estimation of reservoir parameters is highly nonlinear and complex with uncertainties at each step of the process. So it is essential, before proceeding with large-scale history matching, to investigate sensitive rock-physics parameters in modeling the time-lapse seismic response of a field. We used the data set of the Norne field to investigate sensitive parameters in time-lapse seismic modeling. We first investigated sensitive parameters in the Gassmann’s equation. The investigated parameters include mineral properties, water salinity, pore pressure, and gas-oil ratio. Next, we investigated parameter sensitivity for time-lapse seismic modeling of the Norne field. The investigated rock-physics parameters are clay content, cement fraction, average number of contact grains per sand, pore pressure, and fluid mixing. We observed that the average number of contact grains per sand had the most impact on time-lapse seismic modeling of the Norne field. The clay content was the most sensitive parameter in fluid substitution for calculating seismic velocities of the Norne field. Salinity and pore pressure had minimal impact on fluid substitution for this case. This sensitivity analysis helps to select important parameters for time-lapse (4D) seismic history matching, which is an important aspect of joint inversion of production and time-lapse seismic modeling of a field.

Seismic monitoring of a CO2 flood in a carbonate reservoir: A rock physics study

Geophysics ◽  
1998 ◽  
Vol 63 (5) ◽  
pp. 1604-1617 ◽  
Author(s):  
Zhijing Wang ◽  
Michael E. Cates ◽  
Robert T. Langan
Keyword(s):  
High Resolution ◽  
Pore Pressure ◽  
Rock Physics ◽  
Fluid Substitution ◽  
High Porosity ◽  
High Permeability ◽  
Pressure Buildup ◽  
Reservoir Rocks ◽  
Velocity Changes

A carbon dioxide (CO2) injection pilot project is underway in Section 205 of the McElroy field, West Texas. High‐resolution crosswell seismic imaging surveys were conducted before and after CO2 flooding to monitor the CO2 flood process and map the flooded zones. The velocity changes observed by these time‐lapse surveys are typically on the order of −6%, with maximum values on the order of −10% in the vicinity of the injection well. These values generally agree with laboratory measurements if the effects of changing pore pressure are included. The observed dramatic compressional ([Formula: see text]) and shear ([Formula: see text]) velocity changes are considerably greater than we had initially predicted using the Gassmann (1951) fluid substitution analysis (Nolen‐Hoeksema et al., 1995) because we had assumed reservoir pressure would not change from survey to survey. However, the post‐CO2 reservoir pore fluid pressure was substantially higher than the original pore pressure. In addition, our original petrophysical data for dry and brine‐saturated reservoir rocks did not cover the range of pressures actually seen in the field. Therefore, we undertook a rock physics study of CO2 flooding in the laboratory, under the simulated McElroy pressures and temperature. Our results show that the combined effects of pore pressure buildup and fluid substitution caused by CO2 flooding make it petrophysically feasible to monitor the CO2 flood process and to map the flooded zones seismically. The measured data show that [Formula: see text] decreases from a minimum 3.0% to as high as 10.9%, while [Formula: see text] decreases from 3.3% to 9.5% as the reservoir rocks are flooded with CO2 under in‐situ conditions. Such [Formula: see text] and [Formula: see text] decreases, even if averaged over all the samples measured, are probably detectable by either crosswell or high‐resolution surface seismic imaging technologies. Our results show [Formula: see text] is sensitive to both the CO2 saturation and the pore pressure increase, but [Formula: see text] is particularly sensitive to the pore pressure increase. As a result, the combined [Formula: see text] and [Formula: see text] changes caused by the CO2 injection may be used, at least semiquantitatively, to separate CO2‐flooded zones with pore pressure buildup from those regions without pore pressure buildup or to separate CO2 zones from pressured‐up, non‐CO2 zones. Our laboratory results show that the largest [Formula: see text] and [Formula: see text] changes caused by CO2 injection are associated with high‐porosity, high‐permeability rocks. In other words, CO2 flooding and pore pressure buildup decrease [Formula: see text] and [Formula: see text] more in high‐porosity, high‐permeability samples. Therefore, it may be possible to delineate such high‐porosity, high‐permeability streaks seismically in situ. If the streaks are thick enough compared to seismic resolution, they can be identified by the larger [Formula: see text] or [Formula: see text] changes.

Time-lapse seismic monitoring methodologies applied to the Pyrenees Field, offshore Western Australia

2015 ◽  
Vol 55 (2) ◽  
pp. 412 ◽  
Author(s):  
Ramses Meza ◽  
Guy Duncan ◽  
Konstantinos Kostas ◽  
Stanislav Kuzmin ◽  
Mauricio Florez ◽  
...  
Keyword(s):  
Seismic Response ◽  
Coming Out ◽  
Rock Physics ◽  
Time Lapse ◽  
Reservoir Rock ◽  
Gas Field ◽  
Field Development ◽  
Fluid Saturation ◽  
Band Limited ◽  
4D Seismic

Time-lapse dedicated 3D seismic surveys were acquired across the Pyrenees oil and gas field, Exmouth Sub-basin to map production-induced changes in the reservoir. Rock-physics 4D modelling showed that changes in pore pressure and fluid saturation would produce a time-lapse seismic response of sufficient magnitude, in both amplitude and velocity, to overcome time-lapse noise. The dominant observed effect is associated with gas coming out of solution. The reservoir simulation model forecasted that reservoir depletion would cause gas breakout that would impact the elastic properties of the reservoir. The effect of gas breakout can be clearly observed on the 4D seismic data as a change in both amplitude and velocity. The analysis of the seismic datasets was proven to be enhanced significantly by using inversion methodologies. These included a band-limited extended-elastic impedance (EEI) approach, as well as simultaneous 4D elastic inversion. These datasets, combined with rock physics modelling, enabled quantitative interpretation of the change in 4D seismic response which was a key tool for assisting with the infill well placement and field development strategy.

History matching of CO2flow models using seismic modeling and time‐lapse data

2002 ◽  
Author(s):  
M. Lygren ◽  
E. Lindeberg ◽  
P. Bergmo ◽  
G. V. Dahl ◽  
K. Å. Halvorsen ◽  
...  
Keyword(s):  
History Matching ◽  
Time Lapse ◽  
Seismic Modeling

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.

Pore pressure estimation in reservoir rocks from seismic reflection data

Geophysics ◽  
2003 ◽  
Vol 68 (5) ◽  
pp. 1569-1579 ◽  
Author(s):  
José M. Carcione ◽  
Hans B. Helle ◽  
Nam H. Pham ◽  
Tommy Toverud
Keyword(s):  
Pore Pressure ◽  
Seismic Velocity ◽  
Rock Physics ◽  
Clay Content ◽  
Structural Features ◽  
P Wave ◽  
Velocity Versus ◽  
Seismic Reflection Data ◽  
The North ◽  
Fluid Saturation

A method is used to obtain pore pressure in shaly sandstones based upon an acoustic model for seismic velocity versus clay content and effective pressure. Calibration of the model requires log data—porosity, clay content, and sonic velocities—to obtain the dry‐rock moduli and the effective stress coefficients as a function of depth and pore pressure. The seismic P‐wave velocity, derived from reflection tomography, is fitted to the theoretical velocity by using pore pressure as the fitting parameter. This approach, based on a rock‐physics model, is an improvement over existing pore‐pressure prediction methods, which mainly rely on empirical relations between velocity and pressure. The method is applied to the Tune field in the Viking Graben sedimentary basin of the North Sea. We have obtained a high‐resolution velocity map that reveals the sensitivity to pore pressure and fluid saturation in the Tarbert reservoir. The velocity map of the Tarbert reservoir and the inverted pressure distribution agree with the structural features of the Tarbert Formation and its known pressure compartments.

A feasibility study of CO2 geologic sequestration integrating reservoir simulation, rock-physics theory, and seismic modeling

Geophysics ◽  
2016 ◽  
Vol 81 (5) ◽  
pp. M71-M82 ◽  
Author(s):  
Yanjun Hao ◽  
Dinghui Yang ◽  
Yanjie Zhou
Keyword(s):  
Seismic Response ◽  
Reservoir Simulation ◽  
Rock Physics ◽  
Reservoir Rock ◽  
Seismic Modeling ◽  
Geologic Model ◽  
Simulation Results ◽  
Physics Model ◽  
Rock Physics Model ◽  
Wave Properties

[Formula: see text] capture and sequestration is a promising approach to reduce carbon emission and mitigate the greenhouse effect. We have developed a methodology combining reservoir simulation, rock-physics theory, and seismic modeling to simulate the [Formula: see text] sequestration and monitoring process, based on an idealized geologic model of the Sleipner field. First, we simulated a constant-rate [Formula: see text] injection into the idealized geologic model to study the basics of the two-phase flow involved in [Formula: see text] sequestration. The main features of the [Formula: see text] plume evolution and pressure build-up are captured in the simulation results. In any [Formula: see text] sequestration project, an important part is monitoring [Formula: see text] distribution using seismic methods. The seismic response of the injected [Formula: see text] is controlled by its effect on elastic properties of the reservoir rock. We built a rock-physics model to assess the effect of [Formula: see text] on wave properties. For unconsolidated sand, a sensitivity study found that [Formula: see text] saturation and effective pressure can strongly affect wave properties. Based on the reservoir simulation results and the rock-physics model, seismic modeling is performed at different stages of the injection using the symplectic stereomodeling method. The synthetic seismograms found that the seismic responses of the reservoir are strongly affected by the saturation and pressure change induced by the injection of [Formula: see text], and the seismic response of [Formula: see text] is strong enough to be resolved from seismic data.

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