scholarly journals Time-lapse difference static correction using prestack crosscorrelations: 4D seismic image enhancement case from Ketzin

Geophysics ◽  
2014 ◽  
Vol 79 (6) ◽  
pp. B243-B252 ◽  
Author(s):  
Peter Bergmann ◽  
Artem Kashubin ◽  
Monika Ivandic ◽  
Stefan Lüth ◽  
Christopher Juhlin
Keyword(s):  
Seismic Data ◽  
Time Lapse ◽  
Data Sets ◽  
Storage Site ◽  
Data Set ◽  
Near Surface ◽  
Static Correction ◽  
Seismic Image ◽  
Static Corrections ◽  
4D Seismic

A method for static correction of time-lapse differences in reflection arrival times of time-lapse prestack seismic data is presented. These arrival-time differences are typically caused by changes in the near-surface velocities between the acquisitions and had a detrimental impact on time-lapse seismic imaging. Trace-to-trace time shifts of the data sets from different vintages are determined by crosscorrelations. The time shifts are decomposed in a surface-consistent manner, which yields static corrections that tie the repeat data to the baseline data. Hence, this approach implies that new refraction static corrections for the repeat data sets are unnecessary. The approach is demonstrated on a 4D seismic data set from the Ketzin [Formula: see text] pilot storage site, Germany, and is compared with the result of an initial processing that was based on separate refraction static corrections. It is shown that the time-lapse difference static correction approach reduces 4D noise more effectively than separate refraction static corrections and is significantly less labor intensive.

Time-lapse acoustic impedance variations during CO2 injection in Weyburn oilfield, Canada

Geophysics ◽  
2019 ◽  
Vol 85 (1) ◽  
pp. M1-M13 ◽  
Author(s):  
Yichuan Wang ◽  
Igor B. Morozov
Keyword(s):  
Oil Recovery ◽  
Seismic Data ◽  
Acoustic Impedance ◽  
Time Lapse ◽  
Time Shift ◽  
Co2 Injection ◽  
Inversion Method ◽  
Data Sets ◽  
Storage Site ◽  
Data Set

For seismic monitoring injected fluids during enhanced oil recovery or geologic [Formula: see text] sequestration, it is useful to measure time-lapse (TL) variations of acoustic impedance (AI). AI gives direct connections to the mechanical and fluid-related properties of the reservoir or [Formula: see text] storage site; however, evaluation of its subtle TL variations is complicated by the low-frequency and scaling uncertainties of this attribute. We have developed three enhancements of TL AI analysis to resolve these issues. First, following waveform calibration (cross-equalization) of the monitor seismic data sets to the baseline one, the reflectivity difference was evaluated from the attributes measured during the calibration. Second, a robust approach to AI inversion was applied to the baseline data set, based on calibration of the records by using the well-log data and spatially variant stacking and interval velocities derived during seismic data processing. This inversion method is straightforward and does not require subjective selections of parameterization and regularization schemes. Unlike joint or statistical inverse approaches, this method does not require prior models and produces accurate fitting of the observed reflectivity. Third, the TL AI difference is obtained directly from the baseline AI and reflectivity difference but without the uncertainty-prone subtraction of AI volumes from different seismic vintages. The above approaches are applied to TL data sets from the Weyburn [Formula: see text] sequestration project in southern Saskatchewan, Canada. High-quality baseline and TL AI-difference volumes are obtained. TL variations within the reservoir zone are observed in the calibration time-shift, reflectivity-difference, and AI-difference images, which are interpreted as being related to the [Formula: see text] injection.

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.

Assessment of 4D seismic repeatability and CO2 detection limits using a sparse permanent land array at the Aquistore CO2 storage site

Geophysics ◽  
2015 ◽  
Vol 80 (2) ◽  
pp. WA1-WA13 ◽  
Author(s):  
Lisa A. N. Roach ◽  
Donald J. White ◽  
Brian Roberts
Keyword(s):  
Co2 Storage ◽  
Time Lapse ◽  
Data Sets ◽  
Storage Site ◽  
Processing Sequence ◽  
Time Migration ◽  
Receiver Array ◽  
Co2 Detection ◽  
4D Seismic ◽  
The Impact

Two 3D time-lapse seismic surveys were acquired in 2012 and 2013 at the Aquistore [Formula: see text] storage site prior to the start of [Formula: see text] injection. Using these surveys, we determined the background time-lapse noise at the site and assessed the feasibility of using a sparse areal permanent receiver array as a monitoring tool. Applying a standard processing sequence to these data, we adequately imaged the reservoir at 3150–3350 m depth. Evaluation of the impact of each processing step on the repeatability revealed a general monotonic increase in similarity between the data sets as a function of processing. The prestack processing sequence reduced the normalized root mean squared difference (nrms) from 1.13 between the raw stacks to 0.13 after poststack time migration. The postmigration cross-equalization sequence further reduced the global nrms to 0.07. A simulation of the changes in seismic response due to a range of [Formula: see text] injection scenarios suggested that [Formula: see text] was detectable within the reservoir at the Aquistore site provided that zones of greater thickness than 6–13 m have reached [Formula: see text] saturations of greater than 5%.

Land FWI in the Delaware Basin, west Texas: A case study

2020 ◽  
Vol 39 (5) ◽  
pp. 324-331
Author(s):  
Gary Murphy ◽  
Vanessa Brown ◽  
Denes Vigh
Keyword(s):  
Seismic Data ◽  
Waveform Inversion ◽  
Surface Velocity ◽  
High Signal ◽  
Data Sets ◽  
Data Set ◽  
Low Frequencies ◽  
Near Surface ◽  
Delaware Basin ◽  
West Texas

As part of a wide-reaching full-waveform inversion (FWI) research program, FWI is applied to an onshore seismic data set collected in the Delaware Basin, west Texas. FWI is routinely applied on typical marine data sets with high signal-to-noise ratio (S/N), relatively good low-frequency content, and reasonably long offsets. Land seismic data sets, in comparison, present significant challenges for FWI due to low S/N, a dearth of low frequencies, and limited offsets. Recent advancements in FWI overcome limitations due to poor S/N and low frequencies making land FWI feasible to use to update the shallow velocities. The chosen area has contrasting and variable near-surface conditions providing an excellent test data set on which to demonstrate the workflow and its challenges. An acoustic FWI workflow is used to update the near-surface velocity model in order to improve the deeper image and simultaneously help highlight potential shallow drilling hazards.

Fully automated near-surface analysis by surface-consistent refraction method

Geophysics ◽  
2016 ◽  
Vol 81 (4) ◽  
pp. U39-U49 ◽  
Author(s):  
Daniele Colombo ◽  
Federico Miorelli ◽  
Ernesto Sandoval ◽  
Kevin Erickson
Keyword(s):  
Surface Analysis ◽  
Seismic Data ◽  
Linear Equations ◽  
Time Shift ◽  
Data Sets ◽  
Time Lags ◽  
Data Set ◽  
Near Surface ◽  
Seismic Acquisition ◽  
Key Aspects

Industry practices for near-surface analysis indicate difficulties in coping with the increased number of channels in seismic acquisition systems, and new approaches are needed to fully exploit the resolution embedded in modern seismic data sets. To achieve this goal, we have developed a novel surface-consistent refraction analysis method for low-relief geology to automatically derive near-surface corrections for seismic data processing. The method uses concepts from surface-consistent analysis applied to refracted arrivals. The key aspects of the method consist of the use of common midpoint (CMP)-offset-azimuth binning, evaluation of mean traveltime and standard deviation for each bin, rejection of anomalous first-break (FB) picks, derivation of CMP-based traveltime-offset functions, conversion to velocity-depth functions, evaluation of long-wavelength statics, and calculation of surface-consistent residual statics through waveform crosscorrelation. Residual time lags are evaluated in multiple CMP-offset-azimuth bins by crosscorrelating a pilot trace with all the other traces in the gather in which the correlation window is centered at the refracted arrival. The residuals are then used to build a system of linear equations that is simultaneously inverted for surface-consistent shot and receiver time shift corrections plus a possible subsurface residual term. All the steps are completely automated and require a fraction of the time needed for conventional near-surface analysis. The developed methodology was successfully performed on a complex 3D land data set from Central Saudi Arabia where it was benchmarked against a conventional tomographic work flow. The results indicate that the new surface-consistent refraction statics method enhances seismic imaging especially in portions of the survey dominated by noise.

Surface-consistent matching filters for time-lapse seismic processing

Geophysics ◽  
2013 ◽  
Vol 78 (5) ◽  
pp. M29-M41 ◽  
Author(s):  
Mahdi H. Almutlaq ◽  
Gary F. Margrave
Keyword(s):  
Least Squares ◽  
Synthetic Data ◽  
Spectral Ratio ◽  
Time Lapse ◽  
Mean Value ◽  
Baseline Survey ◽  
Data Sets ◽  
Data Set ◽  
Near Surface ◽  
The Time Domain

We evaluated the concept of surface-consistent matching filters for processing time-lapse seismic data, in which matching filters are convolutional filters that minimize the sum-squared error between two signals. Because in the Fourier domain a matching filter is the spectral ratio of the two signals, we extended the well-known surface-consistent hypothesis such that the data term is a trace-by-trace spectral ratio of two data sets instead of only one (i.e., surface-consistent deconvolution). To avoid unstable division of spectra, we computed the spectral ratios in the time domain by first designing trace-sequential, least-squares matching filters, then Fourier transforming them. A subsequent least-squares solution then factored the trace-sequential matching filters into four operators: two surface-consistent (source and receiver) and two subsurface-consistent (offset and midpoint). We evaluated a time-lapse synthetic data set with nonrepeatable acquisition parameters, complex near-surface geology, and a variable subsurface reservoir layer. We computed the four-operator surface-consistent matching filters from two surveys, baseline and monitor, then applied these matching filters to the monitor survey to match it to the baseline survey over a temporal window where changes were not expected. This algorithm significantly reduced the effect of most of the nonrepeatable parameters, such as differences in source strength, receiver coupling, wavelet bandwidth and phase, and static shifts. We computed the normalized root mean square difference on raw stacked data (baseline and monitor) and obtained a mean value of 70%. This value was significantly reduced after applying the 4C surface-consistent matching filters to about 13.6% computed from final stacks.

Acquisition footprints and seafloor coupling in multicomponent OBC seismic data

Geophysics ◽  
2010 ◽  
Vol 75 (1) ◽  
pp. Q11-Q20 ◽  
Author(s):  
R. James Brown
Keyword(s):  
Seismic Data ◽  
Oscillatory Motion ◽  
P Wave ◽  
Spatial Period ◽  
Data Sets ◽  
Ocean Bottom ◽  
Data Set ◽  
Spectral Analyses ◽  
Step Process ◽  
Static Correction

In four-component (4-C) towed ocean-bottom-cable (OBC) data sets, acquisition footprints are often observed. Sometimes these exhibit a spatial period equal to the length of the receiver cable. I have analyzed a 2D 4-C OBC data set, looking at common-offset gathers (COG), spectral analyses, and hodogram analyses of the direct P-wave first breaks. The acquisition footprint is seen to be directly related to the following effects observed on a few of the multicomponent receivers, namely, those nearest to the towing vessel: significant delays on the inline component though not on the downgoing direct-P first breaks; depletion of higher frequencies (narrower bandwidth) on the inline component; and oscillatory motion closer to the vertical on the direct-P first breaks equivalent to decreased amplitude on the in-line component. This is interpreted to be a result of the towing procedure wherein the leading end of the cable, with the first few receiver modules, is raised from the seafloor and laid down again, relatively lightly, on top of seafloor material that might be poorly consolidated, while the trailing receivers are pulled through and down into this material. For these leading receiver modules, this results in poor inline horizontal coupling (i.e., slipping) and delayed P-S onsets due to their vertically higher positions (relative to the trailing receivers) and quite high near-seafloor [Formula: see text] ratios. To rectify this problem in future acquisition, a longer lead-in cable should prevent lifting of the leading receivers and allow all of them to couple with the seafloor in the same way. For data already acquired with an acquisition footprint on the inline component, a two-step process involving surface-consistent deconvolution or trace equalization and static correction is proposed.

scholarly journals Initial 4D seismic results after CO2 injection start-up at the Aquistore storage site

Geophysics ◽  
2017 ◽  
Vol 82 (3) ◽  
pp. B95-B107 ◽  
Author(s):  
Lisa A. N. Roach ◽  
Donald J. White ◽  
Brian Roberts ◽  
Doug Angus
Keyword(s):  
Root Mean Square ◽  
Time Lapse ◽  
Seismic Survey ◽  
Co2 Injection ◽  
Data Sets ◽  
Storage Site ◽  
Mean Square ◽  
Simultaneous Processing ◽  
Start Up ◽  
4D Seismic

The first post-[Formula: see text]-injection 3D time-lapse seismic survey was conducted at the Aquistore [Formula: see text] storage site in February 2016 using the same permanent array of buried geophones used for acquisition of three previous pre-[Formula: see text]-injection surveys from March 2012 to November 2013. By February 2016, 36 kilotons of [Formula: see text] have been injected within the reservoir between 3170 and 3370 m depth. We have developed time-lapse results from analysis of the first post-[Formula: see text]-injection data and three pre-[Formula: see text]-injection data sets. The objective of our analysis was to evaluate the ability of the permanent array to detect the injected [Formula: see text]. A “4D-friendly simultaneous” processing flow was applied to the data in an effort to maximize the repeatability between the pre- and post-[Formula: see text]-injection volumes while optimizing the final subsurface image including the reservoir. Excellent repeatability was achieved among all surveys with global normalized root-mean-square (Gnrms) values of 1.13–1.19 for the raw prestack data relative to the baseline data, which decreased during processing to Gnrms values of approximately 0.10 for the final crossequalized migrated data volumes. A zone of high normalized root-mean-square (nrms) values (0.11–0.25 as compared with background values of 0.05–0.10) is identified within the upper Deadwood unit of the storage reservoir, which likely corresponds to approximately 18 kilotons of [Formula: see text]. No significant nrms anomalies are observed within the other reservoir units due to a combination of reduced seismic sensitivity, higher background nrms values, and/or small quantities of [Formula: see text] residing within these zones.

Noisy 4D seismic data interpretation: Case study of a Brazilian carbonate reservoir

2020 ◽  
Vol 39 (7) ◽  
pp. 488-496
Author(s):  
Lee Jean Wong ◽  
Hamed Amini ◽  
Colin MacBeth
Keyword(s):  
Seismic Data ◽  
Integrated Approach ◽  
Time Lapse ◽  
Data Interpretation ◽  
Carbonate Reservoir ◽  
Multiple Sources ◽  
Data Set ◽  
Campos Basin ◽  
Data Value ◽  
4D Seismic

A legacy seismic data set from 2001 and 2011 was used for time-lapse interpretation over a Brazilian carbonate reservoir in Field-X of Campos Basin. The acquired 4D seismic data set was noisy and initially deemed to be uninterpretable. Pressure data were limited, and the initial simulation model was poorly calibrated. All of these challenges warranted the need to establish an interdisciplinary interpretation workflow. In this paper, we introduce a tiered integrated approach to optimize data value from multiple sources. The results of interwell connectivity from production data analysis were used as a basis for assignment of 4D signal confidence flags, which were later combined with simulation-to-seismic modeling of history-matched realizations, enabling interpretation efforts of the noisy 4D seismic data set. This integrated approach led to identification of the injected water front and a potential sweet spot for an infill well.

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