The problem of using normalized rms in a sliding window to compare seismic tracesDISCUSSIONOn: “Imaging the Aquistore reservoir after 36 kilotonnes of CO2 injection using distributed acoustic sensing.” Harris, K., White, D.J., Samson, C., 2017. Geophysics 82 (6), M81–M96and “Initial 4D seismic results after CO2 injection start-up at the Aquistore storage site.” Roach, L.A.N., White, D.J., Roberts, B., Angus, D., 2017. Geophysics 82 (3), B95–B107.

Geophysics ◽  
2021 ◽  
pp. 1-9
Author(s):  
Balazs Nemeth ◽  
Christian Escalante
Keyword(s):  
Sliding Window ◽  
Time Lapse ◽  
Co2 Injection ◽  
Storage Site ◽  
Seismic Surveys ◽  
Start Up ◽  
Distributed Acoustic Sensing ◽  
Difference Calculation ◽  
Difference Volume ◽  
4D Seismic

Two papers published in Geophysics use the normalized rms (NRMS) calculation in a sliding window to compare traces and to create a ‘difference nrms’ volume. The authors use the derived difference volume to show the presence of apparent time-lapse anomaly between two seismic surveys. In this discussion we point out that the used methodology does not allow a robust comparison of seismic traces. We recommend the use of simple amplitude difference calculation between volumes to show the presence of time-lapse anomalies, instead of the used methodology.

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.

3D DAS-VSP Illumination Modeling for CO2 Plume Migration Monitoring in Offshore Sarawak, Malaysia

2021 ◽  
Author(s):  
Pankaj Kumar Tiwari ◽  
Zoann Low ◽  
Parimal Arjun Patil ◽  
Debasis Priyadarshan Das ◽  
Prasanna Chidambaram ◽  
...  
Keyword(s):  
Dynamic Simulation ◽  
Seismic Velocity ◽  
Time Lapse ◽  
Carbonate Reservoir ◽  
Fiber Optic Sensor ◽  
Co2 Injection ◽  
Storage Site ◽  
Plume Migration ◽  
Co2 Plume ◽  
4D Seismic

Abstract Monitoring of CO2 plume migration in a depleted carbonate reservoir is challenging and demand comprehensive and trailblazing monitoring technologies. 4D time-lapse seismic exhibits the migration of CO2 plume within geological storage but in the area affected by gas chimney due to poor signal-to-noise ratio (SNR), uncertainty in identifying and interpretation of CO2 plume gets exaggerated. High resolution 3D vertical seismic profile (VSP) survey using distributed acoustic sensor (DAS) technology fulfil the objective of obtaining the detailed subsurface image which include CO2 plume migration, reservoir architecture, sub-seismic faults and fracture networks as well as the caprock. Integration of quantitative geophysics and dynamic simulation with illumination modelling dignify the capabilities of 3D DAS-VSP for CO2 plume migration monitoring. The storage site has been studied in detailed and an integrated coupled dynamic simulation were performed and results were integrated with seismic forward modeling to demonstrate the CO2 plume migration with in reservoir and its impact on seismic amplitude. 3D VSP illumination modelling was carried out by integrating reservoir and overburden interpretations, acoustic logs and seismic velocity to illustrate the subsurface coverage area at top of reservoir. Several acquisition survey geometries were simulated based on different source carpet size for effective surface source contribution for subsurface illumination and results were analyzed to design the 3D VSP survey for early CO2 plume migration monitoring. The illumination simulation was integrated with dynamic simulation for fullfield CO2 plume migration monitoring with 3D DAS-VSP by incorporating Pseudo wells illumination analysis. Results of integrated coupled dynamic simulation and 4D seismic feasibility were analyzed for selection of best well location to deploy the multi fiber optic sensor system (M-FOSS) technology. Amplitude response of synthetic AVO (amplitude vs offsets) gathers at the top of carbonate reservoir were analyzed for near, mid and far angle stacks with respect to pre-production as well as pre-injection reservoir conditions. Observed promising results of distinguishable 25-30% of CO2 saturation in depleted reservoir from 4D time-lapse seismic envisage the application of 3D DAS-VSP acquisition. The source patch analysis of 3D VSP illumination modelling results indicate that a source carpet of 6km×6km would be cos-effectively sufficient to produce a maximum of approximately 2km in diameter subsurface illumination at the top of the reservoir. The Pseudo wells illumination analysis results show that current planned injection wells would probably able to monitor early CO2 injection but for the fullfield monitoring additional monitoring wells or a hybrid survey of VSP and surface seismic would be required. The integrated modeling approach ensures that 4D Seismic in subsurface CO2 plume monitoring is robust. Monitoring pressure build-ups from 3D DAS-VSP will reduce the associated risks.

Time-lapse seismic performance of a sparse permanent array: Experience from the Aquistore CO2 storage site

Geophysics ◽  
2015 ◽  
Vol 80 (2) ◽  
pp. WA35-WA48 ◽  
Author(s):  
Don J. White ◽  
Lisa A. N. Roach ◽  
Brian Roberts
Keyword(s):  
Signal To Noise Ratio ◽  
Co2 Storage ◽  
Time Lapse ◽  
Seismic Monitoring ◽  
Storage Site ◽  
Raw Data ◽  
Seismic Surveys ◽  
Monitoring Effort ◽  
Overall Performance ◽  
4D Seismic

A sparse areal permanent array of buried geophones was deployed at the Aquistore [Formula: see text] storage site in Saskatchewan, Canada. The purpose of this array is to facilitate 4D seismic monitoring of [Formula: see text] that is to be injected to the deep subsurface. Use of a sparse buried array is designed to improve the repeatability of time-lapse data and to economize the monitoring effort. Prior to the start of [Formula: see text] injection, two 3D dynamite seismic surveys were acquired in March 2012 and May 2013 using the permanent array. The objective of acquiring these data was to allow an assessment of the data repeatability and overall performance of the permanent array. A comparison of the raw data from these surveys and with a conventional high-resolution 3D vibroseis survey demonstrated that (1) the signal-to-noise ratio for the buried geophones was increased by 6–7 dB relative to surface-deployed geophones and by an additional 20 dB for dynamite relative to a vibroseis source, (2) the use of buried sensors and sources at this site did not appear to be significantly degraded by the effects of ghosting, (3) repeatability for the permanent array data was excellent with a mean normalized root-mean-square (nrms) value of 57% for the raw baseline-monitor difference, (4) the variance of nrms values was higher for shot gathers (18%) compared with receiver gathers (7%), and (5) the raw data repeatability was a factor of three improved over that of comparable surface-geophone data acquired at a nearby location. The use of a sparse buried permanent array at the Aquistore site has demonstrably achieved a reduction in ambient noise levels and overall enhanced data repeatability, both of which are keys to successful 4D seismic monitoring.

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%.

Fluid dynamics at the base of hydrate-bearing sediments at the Vestnesa Ridge inferred from 5 years of high-resolution 4D seismic surveying

2020 ◽  
Author(s):  
Malin Waage ◽  
Stefan Bünz ◽  
Kate Waghorn ◽  
Sunny Singhorha ◽  
Pavel Serov
Keyword(s):  
High Resolution ◽  
Gas Hydrate ◽  
Seismic Data ◽  
Time Lapse ◽  
Stability Zone ◽  
Seismic Surveys ◽  
Free Gas ◽  
4D Seismic ◽  
Hydrate Bearing Sediments ◽  
Hydrate Stability

<p>The transition from gas hydrate to gas-bearing sediments at the base of the hydrate stability zone (BHSZ) is commonly identified on seismic data as a bottom-simulating reflection (BSR). At this boundary, phase transitions driven by thermal effects, pressure alternations, and gas and water flux exist. Sedimentation, erosion, subsidence, uplift, variations in bottom water temperature or heat flow cause changes in marine gas hydrate stability leading to expansion or reduction of gas hydrate accumulations and associated free gas accumulations. Pressure build-up in gas accumulations trapped beneath the hydrate layer may eventually lead to fracturing of hydrate-bearing sediments that enables advection of fluids into the hydrate layer and potentially seabed seepage. Depletion of gas along zones of weakness creates hydraulic gradients in the free gas zone where gas is forced to migrate along the lower hydrate boundary towards these weakness zones. However, due to lack of “real time” data, the magnitude and timescales of processes at the gas hydrate – gas contact zone remains largely unknown. Here we show results of high resolution 4D seismic surveys at a prominent Arctic gas hydrate accumulation – Vestnesa ridge - capturing dynamics of the gas hydrate and free gas accumulations over 5 years. The 4D time-lapse seismic method has the potential to identify and monitor fluid movement in the subsurface over certain time intervals. Although conventional 4D seismic has a long history of application to monitor fluid changes in petroleum reservoirs, high-resolution seismic data (20-300 Hz) as a tool for 4D fluid monitoring of natural geological processes has been recently identified.<br><br>Our 4D data set consists of four high-resolution P-Cable 3D seismic surveys acquired between 2012 and 2017 in the eastern segment of Vestnesa Ridge. Vestnesa Ridge has an active fluid and gas hydrate system in a contourite drift setting near the Knipovich Ridge offshore W-Svalbard. Large gas flares, ~800 m tall rise from seafloor pockmarks (~700 m diameter) at the ridge axis. Beneath the pockmarks, gas chimneys pierce the hydrate stability zone, and a strong, widespread BSR occurs at depth of 160-180 m bsf. 4D seismic datasets reveal changes in subsurface fluid distribution near the BHSZ on Vestnesa Ridge. In particular, the amplitude along the BSR reflection appears to change across surveys. Disappearance of bright reflections suggest that gas-rich fluids have escaped the free gas zone and possibly migrated into the hydrate stability zone and contributed to a gas hydrate accumulation, or alternatively, migrated laterally along the BSR. Appearance of bright reflection might also indicate lateral migration, ongoing microbial or thermogenic gas supply or be related to other phase transitions. We document that faults, chimneys and lithology constrain these anomalies imposing yet another control on vertical and lateral gas migration and accumulation. These time-lapse differences suggest that (1) we can resolve fluid changes on a year-year timescale in this natural seepage system using high-resolution P-Cable data and (2) that fluids accumulate at, migrate to and migrate from the BHSZ over the same time scale.</p>

Time-lapse seismic signal analysis for enhanced oil recovery at Cranfield CO2 sequestration site, Cranfield field, Mississippi

2013 ◽  
Vol 1 (2) ◽  
pp. T157-T166 ◽  
Author(s):  
Julie Ditkof ◽  
Eva Caspari ◽  
Roman Pevzner ◽  
Milovan Urosevic ◽  
Timothy A. Meckel ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Time Lapse ◽  
Seismic Signal ◽  
Injection Well ◽  
Saturation Curve ◽  
Seismic Surveys ◽  
Seismic Amplitude ◽  
The Difference ◽  
Seismic Volumes ◽  
4D Seismic

The Cranfield field in southwest Mississippi has been under continuous [Formula: see text] injection by Denbury Onshore LLC since 2008. Two 3D seismic surveys were collected in 2007 and 2010. An initial 4D seismic response was characterized after three years of injection, where more than three million tons of [Formula: see text] remain in the subsurface. This interpretation showed coherent seismic amplitude anomalies in some areas that received large amounts of [Formula: see text] but not in others. To understand these effects better, we performed Gassmann substitution modeling at two wells: the 31F-2 observation well and the 28-1 injection well. We aimed to predict a postinjection saturation curve and acoustic impedance (AI) change through the reservoir. Seismic volumes were cross-equalized, well ties to seismic were performed, and AI inversions were subsequently carried out. Inversion results showed that the change in AI is higher than Gassmann substitution predicted for the 28-1 injection well. The time-lapse AI difference predicted by the inversion is similar in magnitude to the difference inferred from a time delay along a marker horizon below the reservoir.

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 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.

Imaging the Aquistore reservoir after 36 kilotonnes of CO2 injection using distributed acoustic sensing

Geophysics ◽  
2017 ◽  
Vol 82 (6) ◽  
pp. M81-M96 ◽  
Author(s):  
Kyle Harris ◽  
Don White ◽  
Claire Samson
Keyword(s):  
Time Lapse ◽  
Seismic Survey ◽  
Co2 Injection ◽  
Baseline Survey ◽  
Acoustic Sensing ◽  
Monitoring Wells ◽  
Amplitude Anomaly ◽  
Vsp Data ◽  
Distributed Acoustic Sensing ◽  
Saline Formation

Aquistore is a geologic [Formula: see text] storage project that is using a deep saline formation as a storage reservoir. From April 2015 to February 2016, approximately 36 kilotonnes of [Formula: see text] were injected into the reservoir at a depth of 3130–3350 m. We have developed an analysis of distributed acoustic sensing (DAS) 3D vertical seismic profiling data acquired in February 2016, marking the first seismic survey since injection began. The VSP data were processed in parallel with baseline preinjection data from a November 2013 survey, with the objective of detecting and characterizing the subsurface [Formula: see text] plume and evaluating the repeatability of DAS in a reservoir monitoring project. A single processing sequence was devised that (1) accurately imaged the reservoir for the baseline and monitor data and (2) attained adequate repeatability to observe time-lapse differences related to the presence of [Formula: see text]. Repeatability was somewhat compromised by the less advanced noise cancellation methodology of the DAS system used for the baseline survey. In the final cross-equalized migrated data volumes, normalized root-mean-square ([Formula: see text]rms) difference values of [Formula: see text] were attained at the reservoir level indicating good repeatability compared with most surface seismic studies. An injection-related amplitude anomaly with maximum [Formula: see text]rms values of approximately 0.7 is apparent in the Deadwood Formation of the reservoir, whereas no significant [Formula: see text]rms anomalies were observed near the injection and monitoring wells in the Black Island Member or above the reservoir.

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