Multiwell 3D distributed acoustic sensing vertical seismic profile imaging with engineered fibers: CO2CRC Otway Project case study

Geophysics ◽  
2021 ◽  
Vol 86 (6) ◽  
pp. D241-D248 ◽  
Author(s):  
Alexey Yurikov ◽  
Konstantin Tertyshnikov ◽  
Roman Isaenkov ◽  
Evgenii Sidenko ◽  
Sinem Yavuz ◽  
...  
Keyword(s):  
Low Cost ◽  
Optimal Solution ◽  
Time Lapse ◽  
Local Area ◽  
Seismic Profile ◽  
Enhanced Backscattering ◽  
Seismic Acquisition ◽  
Vsp Data ◽  
4D Seismic

The 4D surface seismic monitoring is a standard method for reservoir surveillance during the production of hydrocarbons or CO2 injection. However, land 4D seismic acquisition campaigns are often associated with high cost and disruptions to industrial operation or agricultural activities in the area of acquisition. An alternative technique for time-lapse monitoring of the subsurface is the 3D vertical seismic profiling (VSP), which becomes particularly attractive when used with distributed acoustic fiber-optic sensors (DAS) installed in wells. The advantages of 3D DAS VSP include its relatively low cost, minimal footprint on the local area during acquisition, and superior spatial resolution compared to the resolution of geophones. The potential of this technique is explored by processing and analyzing multiwell 3D DAS VSP data acquired at the CO2CRC Otway Project site in Victoria, Australia. The DAS data were recorded using an engineered fiber with enhanced backscattering cemented behind the casing of five wells. The data from each well are processed individually using the same processing flow and then migrated using a 3D migration code tailored to DAS data. Having DAS along the full extent of multiple wells ensures adequate seismic coverage of the area of CO2 injection. The migrated images provide detailed information about the subsurface up to 700 m away from a well and up to 2 km depth. The images are consistent with previously acquired geophone VSP and surface seismic data. The quality of the 3D DAS VSP imaging is comparable or superior to the quality of conventional imaging using geophone data. Therefore, 3D DAS VSP is a demonstrably optimal solution for reservoir monitoring.

Quantifying hydraulically induced fracture height and density from rapid time-lapse DAS VSP

Geophysics ◽  
2020 ◽  
pp. 1-26
Author(s):  
Xiaomin Zhao ◽  
Mark E. Willis ◽  
Tanya Inks ◽  
Glenn A. Wilson
Keyword(s):  
Rock Physics ◽  
Horizontal Wells ◽  
Time Lapse ◽  
Seismic Profile ◽  
P Wave ◽  
Fracture Properties ◽  
Vsp Data ◽  
Rock Physics Modeling ◽  
Physics Modeling ◽  
Fracture Height

Several recent studies have advanced the use of time-lapse distributed acoustic sensing (DAS) vertical seismic profile (VSP) data in horizontal wells for determining hydraulically stimulated fracture properties. Hydraulic fracturing in a horizontal well typically generates vertical fractures in the rock medium around each stage. We model the hydraulically stimulated formation with vertical fracture sets about the lateral wellbore as a horizontally transverse isotropic (HTI) medium. Rock physics modeling is used to relate the anisotropy parameters to fracture properties. This modeling was used to develop an inversion for P-wave time delay to fracture height and density of each stage. Field data from two horizontal wells were analyzed, and fracture height evaluated using this technique agreed with microseismic analysis.

Measurement of seawater average velocity using water bottom multiples from vertical seismic profile surveys

2016 ◽  
Vol 4 (4) ◽  
pp. SQ13-SQ22 ◽  
Author(s):  
Yingping Li ◽  
Ben Hewett
Keyword(s):  
Average Velocity ◽  
Seismic Velocity ◽  
Autonomous Underwater Vehicles ◽  
Time Lapse ◽  
Seismic Profile ◽  
Temporal Variations ◽  
Vertical Seismic Profile ◽  
Velocity Models ◽  
Vsp Data ◽  
Water Bottom

Previous diagnoses of surface seismic velocity models with vertical seismic profile (VSP) data in the Gulf of Mexico have indicated that shallow velocities were poorly constrained by VSP due to ringing caused by multiple casing strings. This ringing also hampered direct measurement of the seawater average velocity (SWAV) at a rig site with direct arrivals of a zero-offset VSP (ZVSP). We have directly measured the SWAV at a rig site with a known water depth by using differential times between primary water bottom multiples (WBMs) and direct first arrivals acquired in a marine VSP survey. We developed a procedure to process ZVSP-WBM signals for SWAV measurement. This WBM method is successfully applied to VSP data recorded at 27 rig sites in the deep-water environments of North and South America. Our results suggest that VSP processors should implement this method and add the SWAV measurement in their future velocity survey reports. We have estimated water bottom depths using differential times. We found that the estimated water depths are comparable with those acquired from sonar measurements by autonomous underwater vehicles, but with large uncertainties. The WBM method is extended by using data from a vertical incidence VSP to measure a profile of the SWAV along the path of a deviated well and evaluate possible lateral variations of SWAV. This method can potentially be applied to a time-lapse VSP to monitor temporal variations of SWAV. We also evaluated the application scope and limitations of the WBM method.

scholarly journals 3D vertical seismic profile acquired with distributed acoustic sensing on tubing installation: A case study from the CO2CRC Otway Project

2019 ◽  
Vol 7 (1) ◽  
pp. SA11-SA19 ◽  
Author(s):  
Julia Correa ◽  
Roman Pevzner ◽  
Andrej Bona ◽  
Konstantin Tertyshnikov ◽  
Barry Freifeld ◽  
...  
Keyword(s):  
Fiber Length ◽  
Fiber Optic ◽  
Signal To Noise Ratio ◽  
Seismic Profile ◽  
Lessons Learned ◽  
Vertical Seismic Profile ◽  
Acoustic Sensing ◽  
Vsp Data ◽  
Distributed Acoustic Sensing

Distributed acoustic sensing (DAS) can revolutionize the seismic industry by using fiber-optic cables installed permanently to acquire on-demand vertical seismic profile (VSP) data at fine spatial sampling. With this, DAS can solve some of the issues associated with conventional seismic sensors. Studies have successfully demonstrated the use of DAS on cemented fibers for monitoring applications; however, such applications on tubing-deployed fibers are relatively uncommon. Application of tubing-deployed fibers is especially useful for preexisting wells, where there is no opportunity to install a fiber behind the casing. In the CO2CRC Otway Project, we acquired a 3D DAS VSP using a standard fiber-optic cable installed on the production tubing of the injector well. We aim to analyze the quality of the 3D DAS VSP on tubing, as well as discuss lessons learned from the current DAS deployment. We find the limitations associated with the DAS on tubing, as well as ways to improve the quality of the data sets for future surveys at Otway. Due to the reduced coupling and the long fiber length (approximately 20 km), the raw DAS records indicate a high level of noise relative to the signal. Despite the limitations, the migrated 3D DAS VSP data recorded by cable installed on tubing are able to image interfaces beyond the injection depth. Furthermore, we determine that the signal-to-noise ratio might be improved by reducing the fiber length.

3D wave-equation interferometric migration of VSP free-surface multiples

Geophysics ◽  
2007 ◽  
Vol 72 (5) ◽  
pp. S195-S203 ◽  
Author(s):  
Ruiqing He ◽  
Brian Hornby ◽  
Gerard Schuster
Keyword(s):  
Wave Equation ◽  
Free Surface ◽  
Signal To Noise Ratio ◽  
Time Lapse ◽  
Seismic Profile ◽  
Velocity Estimation ◽  
Seismic Survey ◽  
3D Surface ◽  
Vsp Data ◽  
Image Volume

Interferometric migration of free-surface multiples in vertical-seismic-profile (VSP) data has two significant advantages over standard VSP imaging: (1) a significantly larger imaging area compared to migrating VSP primaries and (2) less sensitivity to velocity-estimation and static errors than other methods for migration of multiples. In this paper, we present a 3D wave-equation interferometric migration method that efficiently images VSP free-surface multiples. Synthetic and field data results confirm that a reflectivity image volume, comparable in size to a 3D surface seismic survey around the well, can be computed economically. The reflectivity image volume has less fold density and lower signal-to-noise ratio than that obtained by a conventional 3D surface seismic survey because of the relatively weak energy of multiples and the limited number of geophones in the well. However, the efficiency of this method for migrating VSP multiples suggests that it might sometimes be a useful tool for 4D seismic monitoring where reflectivity images can be computed quickly for each time-lapse survey.

Dual-well 3D vertical seismic profile enabled by distributed acoustic sensing in deepwater Gulf of Mexico

2015 ◽  
Vol 3 (3) ◽  
pp. SW11-SW25 ◽  
Author(s):  
Han Wu ◽  
Wai-Fan Wong ◽  
Zhaohui Yang ◽  
Peter B. Wills ◽  
Jorge L. Lopez ◽  
...  
Keyword(s):  
Gulf Of Mexico ◽  
Velocity Model ◽  
Seismic Profile ◽  
Seismic Survey ◽  
Vertical Seismic Profile ◽  
Acoustic Sensing ◽  
Velocity Models ◽  
Vsp Data ◽  
Distributed Acoustic Sensing

We have acquired and processed 3D vertical seismic profile (VSP) data recorded simultaneously in two wells using distributed acoustic sensing (DAS) during the acquisition of the 2012 Mars 4D ocean-bottom seismic survey in the deepwater Gulf of Mexico. The objectives of the project were to assess the quality of DAS data recorded in fiber-optic cables from the surface to the total depth, to demonstrate the efficacy of the DAS VSP technology in a deepwater environment, to derisk the use of the technology for future water injection or production monitoring without intervention, and to exploit the velocity information that 3D VSP data provide for evaluating and updating the velocity model. We evaluated the advantages of DAS VSP to reduce costs and intrusiveness, and we determined that high-quality images can be obtained from relatively noisy raw 3D DAS VSP data, as evidenced by the well 1 image, probably the best 3D VSP image we have ever seen. Our results also revealed that the direct arrival traveltimes can be used to assess the quality of an existing velocity model and to invert for an improved velocity model. We identified issues with the DAS acquisition and the processing steps to mitigate them and to handle problems specific to DAS VSP data. We described the steps for conditioning the data before migration, reverse time migration, and postmigration processing to reduce noise artifacts. We outlined a novel first-break picking procedure that works even in the absence of a strong first arrival and a velocity diagnosis method to assess and validate velocity models and velocity updates. Finally, we determined potential applications to 4D monitoring of fluid movement around producer or injector wells, identification of active salt movements, and more accurate imaging and monitoring of complex structures around the wells.

Semiquantitative 4D seismic interpretation integrated with reservoir simulation: Application to the Norne field

2018 ◽  
Vol 6 (3) ◽  
pp. T601-T611
Author(s):  
Juliana Maia Carvalho dos Santos ◽  
Alessandra Davolio ◽  
Denis Jose Schiozer ◽  
Colin MacBeth
Keyword(s):  
Simulation Model ◽  
Reservoir Simulation ◽  
History Matching ◽  
Time Lapse ◽  
Seismic Signal ◽  
Seismic Interpretation ◽  
Production Forecast ◽  
Seismic Acquisition ◽  
Reservoir Simulation Model ◽  
4D Seismic

Time-lapse (or 4D) seismic attributes are extensively used as inputs to history matching workflows. However, this integration can potentially bring problems if performed incorrectly. Some of the uncertainties regarding seismic acquisition, processing, and interpretation can be inadvertently incorporated into the reservoir simulation model yielding an erroneous production forecast. Very often, the information provided by 4D seismic can be noisy or ambiguous. For this reason, it is necessary to estimate the level of confidence on the data prior to its transfer to the simulation model process. The methodology presented in this paper aims to diagnose which information from 4D seismic that we are confident enough to include in the model. Two passes of seismic interpretation are proposed: the first, intended to understand the character and quality of the seismic data and, the second, to compare the simulation-to-seismic synthetic response with the observed seismic signal. The methodology is applied to the Norne field benchmark case in which we find several examples of inconsistencies between the synthetic and real responses and we evaluate whether these are caused by a simulation model inaccuracy or by uncertainties in the actual observed seismic. After a careful qualitative and semiquantitative analysis, the confidence level of the interpretation is determined. Simulation model updates can be suggested according to the outcome from this analysis. The main contribution of this work is to introduce a diagnostic step that classifies the seismic interpretation reliability considering the uncertainties inherent in these data. The results indicate that a medium to high interpretation confidence can be achieved even for poorly repeated data.

4D seismic interpretation in a Nigerian deepwater field

2015 ◽  
Vol 3 (2) ◽  
pp. SP11-SP19 ◽  
Author(s):  
Oghogho Effiom ◽  
Robert Maskall ◽  
Edwin Quadt ◽  
Kazeem A. Lawal ◽  
Raphael Afolabi ◽  
...  
Keyword(s):  
Management Practices ◽  
Time Lapse ◽  
Seismic Interpretation ◽  
Lessons Learned ◽  
Water Flooding ◽  
Reservoir Architecture ◽  
Depositional Settings ◽  
Seismic Acquisition ◽  
Net To Gross ◽  
4D Seismic

To improve the management of a Nigerian deep water field, two vintages of 4D data have been acquired since field start up in 2005. The first Nigerian 4D seismic (monitor-I) in water depths greater than 1000 m was taken in this field in 2008, and the second monitor (monitor-II) was acquired in 2012. Compared to monitor-I, better geometric repeatability was achieved in monitor-II as the lessons learned from monitor-I were incorporated to achieve better results. The final normalized root mean square of monitor-II fast-track volume was 12% compared to 25% for monitor-I. The improved quality is attributed to improvements in the acquisition methodology and prediction of the effects of currents. Seismic interpretation of the field revealed two distinct turbidite depositional settings: (1) An unconfined amalgamated lobe system with low relief, high net-to-gross reservoir sands that exhibit fairly homogeneous water flooding patterns on 4D and (2) an erosional canyon setting, filled with meander belts having a more complex 3D connectivity within and between the channels resulting in a challenging 4D interpretation. The time lapse data were instrumental for better understanding the reservoir architecture, enabling improved wells and reservoir management practices, the identification of infill opportunities, and more mature subsurface models. We evaluated the seismic acquisition and the 4D interpretation of the deepwater 4D seismic data, highlighting the merits of a multidisciplinary collaborative understanding to time-lapse seismic. At present, the value of information of the 4D monitor-II is conservatively estimated at 101 million United States dollars, equivalent to the cost of a well in this deepwater operating environment.

Frequent 4D monitoring with DAS 3D VSP in deep water to reveal injected water-sweep dynamics

2020 ◽  
Vol 39 (7) ◽  
pp. 471-479 ◽  
Author(s):  
Denis Kiyashchenko ◽  
Albena Mateeva ◽  
Yuting Duan ◽  
Duane Johnson ◽  
Jonathan Pugh ◽  
...  
Keyword(s):  
Deep Water ◽  
Low Cost ◽  
Water Injection ◽  
Time Lapse ◽  
Reservoir Model ◽  
Seismic Profiles ◽  
Vertical Seismic Profiles ◽  
Distributed Acoustic Sensing ◽  
The Impact

Time-lapse monitoring using 3D distributed acoustic sensing vertical seismic profiles (DAS VSPs) is rapidly maturing as a nonintrusive low-cost solution for target-oriented monitoring in deep water. In a Gulf of Mexico field, DAS fibers deployed in active wells enable detailed tracking of the water flood in two deep reservoirs. Multiple tests in adverse well conditions let us understand the impact of source size and other factors on the spatially dependent quality of time-lapse DAS data and prove that excellent image repeatability is achievable under typical field conditions. Frequent repeat surveys allowed us to predict the timing of water arrival in a producer and to observe new water injection patterns that are important for understanding water-flood performance. Going forward, DAS 4D monitoring is envisioned as a tool that can assist with proactive wells and reservoir management, new well planning, and reservoir model updates.

Wavelet-crosscorrelation-based interferometric redatuming in 4D seismic

Geophysics ◽  
2018 ◽  
Vol 83 (4) ◽  
pp. Q37-Q47 ◽  
Author(s):  
Yang Zhao ◽  
Weichang Li
Keyword(s):  
Time Lapse ◽  
Surface Source ◽  
Near Surface ◽  
Ground Roll ◽  
Time Offset ◽  
4D Seismic ◽  
Shallow Structure ◽  
Phase Spectra ◽  
Scattering Noise

Interferometric virtual source (VS) redatuming crosscorrelates downgoing waves with the corresponding upgoing waves to convert records from surface-source gathers to virtual gathers at the buried receiver locations. The assumption is that the VS records show the reduced effects of overburden complexity and therefore provide improved seismic repeatability and image quality. In practice, however, the repeatability and quality of the redatumed data can be degraded by one-sided illumination and inadequate preprocessing. In the presence of complex near-surface structure for land redatuming, the intricate shallow structure and highly variable weathering layers introduce surface multiples, ground-roll/scattering noise, and interference among different wave modes that additionally contaminates the down- and upgoing wavefields. To address these issues, we have developed a new interferometric redatuming method based on crosscorrelation in the wavelet domain. Specifically, by transforming time-offset data into the local time-scale (TS) and local TS-wavenumber domains, we have designed and applied filters on the amplitude of the cross spectra in each domain to suppress the aforementioned artifacts and noise, while maintaining accurate kinematic information by retaining the original phase spectra. The new procedure involves forward wavelet transform of the source records, crosscorrelating the wavelet coefficients, filtering in the corresponding domains, and then inverse wavelet transformation to produce the VS records. Components associated with scattering noise and ground roll can be effectively suppressed because our designed filters tackle their features accurately in the local TS and local TS-wavenumber domains, respectively. We tested the method on data from 13 time-lapse surveys that included a significant repeatability problem across a 17-month survey gap, and we compared the results with results from the conventional VS methods. Our VS method produced the best improvement in imaging and repeatability, a positive step forward for land seismic monitoring.

4D PLANNING AND EXECUTION STRATEGIES FOR AUSTRALIAN RESERVOIR MONITORING PROJECTS

2006 ◽  
Vol 46 (1) ◽  
pp. 67
Author(s):  
A.S. Long ◽  
M. Widmaier ◽  
M.A. Schonewille
Keyword(s):  
Time Lapse ◽  
Seismic Signal ◽  
Reservoir Simulations ◽  
Reservoir Models ◽  
Processing Strategies ◽  
Reservoir Monitoring ◽  
Seismic Acquisition ◽  
4D Seismic ◽  
Interactive Visualisation ◽  
Time Acquisition

Time-lapse (4D) reservoir monitoring is in its infancy in Australia, but is on the verge of becoming a mainstream pursuit. We describe the 4D seismic acquisition and processing strategies that have been developed and proven elsewhere in the world, and customise those strategies for Australasian applications.We demonstrate how a multidisciplinary pursuit of real-time acquisition and processing Quality Control (QC) is an integral component of any 4D project. The acquisition and processing geophysicists must be able to understand all the factors contributing to the 4D seismic signal as they happen. Such an understanding can only arise through rigorous project QC and management using interactive visualisation technology. In turn, the production geologists and reservoir engineers will then receive 4D seismic products that can be robustly and confidently used for the construction of accurate reservoir models and the pursuit of reliable reservoir simulations and forecasts.

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