seismic acquisition
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2022 ◽  
Vol 41 (1) ◽  
pp. 8-8
Author(s):  
Keith Millis ◽  
Guillaume Richard ◽  
Chengbo Li

In the life cycle of a seismic product, the lion's share of the budget and personnel hours is spent on acquisition. In most modern seismic surveys, acquisition involves hundreds of specialized personnel working for months or years. Seismic acquisition also must overcome potential liabilities and health, safety, and environmental concerns that rival facility, pipeline, construction, and other operational risks. As only properly acquired data can contribute effectively to processing and interpretation strategies, a great deal of importance is placed on acquisition quality. Arguably, many of the advances the seismic industry has experienced find their origin arising from advances in acquisition techniques. Full-waveform inversion (FWI), for example, can reach its full potential only when seismic acquisition has provided both low frequencies and long offsets.


First Break ◽  
2022 ◽  
Vol 40 (1) ◽  
pp. 97-107
Author(s):  
A. Crosby ◽  
D. Ablyazina ◽  
J. Naranjo ◽  
O. Adamovich ◽  
A. Ourabah ◽  
...  

2022 ◽  
Vol 41 (1) ◽  
pp. 19-26
Author(s):  
Patrick Charron ◽  
Erwan L'Arvor ◽  
Jens Fasterling ◽  
Guillaume Richard

TotalEnergies SE and partners Shell and PetroSA recently completed the acquisition and processing of a large (10,000 km2) ultra-sparse (200 m between streamers) marine seismic acquisition survey off the west coast of South Africa in block 5/6/7 using a large PGS Titan Class Ramform vessel. The sparse design enabled fast acquisition and low survey cost and health, safety, and environment exposure. Advances in sparse processing enabled high-quality final seismic data consistent with the exploration objectives. In addition, DUG optimized the 4D regularization/interpolation parameters to approach the near offsets differently than the offsets with more complete coverage to help several processing steps. The survey was designed to be upgradable to a higher-resolution survey if needed via the addition of a custom regular infill pattern, either in its entirety or over targeted areas.


2021 ◽  
Author(s):  
Nawaf Alghamdi ◽  
Hamad Alghenaim

Abstract The paper illustrates the value of seismic data in different environments after assessing the benefits and costs of processes such as seismic acquisition, seismic processing and seismic interpretation. Global examples from conventional and unconventional fields are discussed to show how seismic data plays a significant role in determining low-risk and high-reward wells and also eliminating the high-risk and low-reward wells. This paper shows an example of a conventional field in the state of Kansas, USA, where the net present value (NPV) increased by more than 17 times when 3D seismic data was acquired, while in an unconventional field the commercial success rate rose from 30% to 70% due to 3D seismic acquisition. However, two offshore fields in the Republic of Trinidad and Tobago are discussed to show that the NPV as impacted by advanced seismic processing was more than 111 ($M). Another example comes from Viking Field, a conventional field in Canada, where the NPV was increased from 3800 ($M) to 5000 ($M) when the seismic data was re-processed. Furthermore, the value of investing in seismic data was investigated and quantified by comparing two synthetically modeled scenarios in Saudi Arabia. Overall, the four examples from North America, Central America and Saudi Arabia illustrate that investment in seismic data has a positive impact on both conventional and unconventional fields. That provides strong evidence to encourage more investments in geophysical technologies.


2021 ◽  
Author(s):  
Dustin Blymyer ◽  
Klaas Koster ◽  
Graeme Warren

Abstract Summary Compressive sensing (CS) of seismic data is a new style of seismic acquisition whereby the data are recorded on a pseudorandom grid rather than along densely sampled lines in a conventional design. A CS design with a similar station density will generally yield better quality data at a similar cost compared to a conventional design, whereas a CS design with a lower station density will reduce costs while retaining quality. Previous authors (Mosher, 2014) have shown good results from CS surveys using proprietary methods for the design and processing. In this paper we show results obtained using commercially available services based on published algorithms (Lopez, 2016). This is a necessary requirement for adoption of CS by our industry. This report documents the results of a 108km2 CS acquisition and processing trial. The acquisition and processing were specifically designed to establish whether CS can be used for suppression of backscattered, low velocity, high frequency surface waves. We demonstrate that CS data can be reconstructed by a commercial contractor and that the suppression of backscattered surface waves is improved by using CS receiver gathers reconstructed to a dense shot grid. We also show that CS acquisition is a reliable alternative to conventional acquisition from which high-quality subsurface images can be formed.


2021 ◽  
Author(s):  
Ramy Elasrag ◽  
Thuraya Al Ghafri ◽  
Faaeza Al Katheer ◽  
Yousuf Al-Aufi ◽  
Ivica Mihaljevic ◽  
...  

Abstract Acquiring surface seismic data can be challenging in areas of intense human activities, due to presence of infrastructures (roads, houses, rigs), often leaving large gaps in the fold of coverage that can span over several kilometers. Modern interpolation algorithms can interpolate up to a certain extent, but quality of reconstructed seismic data diminishes as the acquisition gap increases. This is where vintage seismic acquisition can aid processing and imaging, especially if previous acquisition did not face the same surface obstacles. In this paper we will present how the legacy seismic survey has helped to fill in the data gaps of the new acquisition and produced improved seismic image. The new acquisition survey is part of the Mega 3D onshore effort undertaken by ADNOC, characterized by dense shot and receiver spacing with focus on full azimuth and broadband. Due to surface infrastructures, data could not be completely acquired leaving sizable gap in the target area. However, a legacy seismic acquisition undertaken in 2014 had access to such gap zones, as infrastructures were not present at the time. Legacy seismic data has been previously processed and imaged, however simple post-imaging merge would not be adequate as two datasets were processed using different workflows and imaging was done using different velocity models. In order to synchronize the two datasets, we have processed them in parallel. Data matching and merging were done before regularization. It has been regularized to radial geometry using 5D Matching Pursuit with Fourier Interpolation (MPFI). This has provided 12 well sampled azimuth sectors that went through surface consistent processing, multiple attenuation, and residual noise attenuation. Near surface model was built using data-driven image-based static (DIBS) while reflection tomography was used to build the anisotropic velocity model. Imaging was done using Pre-Stack Kirchhoff Depth Migration. Processing legacy survey from the beginning has helped to improve signal to noise ratio which assisted with data merging to not degrade the quality of the end image. Building one near surface model allowed both datasets to match well in time domain. Bringing datasets to the same level was an important condition before matching and merging. Amplitude and phase analysis have shown that both surveys are aligned quite well with minimal difference. Only the portion of the legacy survey that covers the gap was used in the regularization, allowing MPFI to reconstruct missing data. Regularized data went through surface multiple attenuation and further noise attenuation as preconditioning for migration. Final image that is created using both datasets has allowed target to be imaged better.


2021 ◽  
Author(s):  
Mohamed Mahgoub ◽  
Guillaume Cambois ◽  
James Cowell ◽  
Suaad Khoori

Abstract The advances in seismic acquisition systems, especially onshore nodes, have made it possible to acquire ultra-dense 3D surveys at a reasonable cost. This new design enables accurate processing sequences that deliver higher resolution images of the subsurface. These images in turn lead to enhanced structural interpretation and better prediction of rock properties. In 2019, ADNOC and partners acquired an 81 square kilometer ultra-high density pilot survey onshore Abu Dhabi. The receivers were nimble nodes laid out on a 12.5x12.5m grid, which recorded continuously and stored the data on a memory chip. The sources were heavy vibrators sweeping the 2-110 Hz frequency range in 14 seconds on a 12.5x100m grid. 184 million traces per square kilometers did make such small area, the densest 3D seismic survey ever recorded. The single sensor data were expectedly very noisy and the unconstrained simultaneous shooting required elaborate deblending, but we managed these steps with existing tools. The dense 3D receiver grid actually enabled the use of interferometry-based ground-roll attenuation, a technique that is rarely used with conventional data due to inadequate sampling, but that resulted in increased signal-to-noise ratio. The data were migrated directly to depth using a velocity model derived after five iterations of tomographic inversion. The final image gathers were made of 18 reciprocal azimuths with 12.5m offset increment, resulting in 5,000 fold on a 6.25x6.25m grid. The main structural interpretation was achieved during the velocity model building stage. Key horizons were picked after the tomographic iterations and the velocity model was adjusted so that their depth matched the well markers. Anisotropic parameters were adjusted to maintain gather flatness and the new model was fed to the next iteration. This ultimately resulted in flat image gathers and horizons that tied to the wells. The final high-resolution data provided a much crisper image of the target clinoforms and faults. This resulted in a more detailed interpretation of the reservoirs. The data was subjected to pre-stack stratigraphic inversion. The availability of low frequency signal (down to 3 Hz) means that less well constraints are needed for the inversion. Preliminary results are particularly encouraging. Amplitude variations with azimuth have yet to be analyzed but data density bodes very well for the process. Ultra-dense 3D seismic acquisition is feasible and results in a step change in image quality. Structural and stratigraphic interpretation provided a more detailed image of faults and clinoforms. Stratigraphic inversion benefited from the low frequencies of the vibrator source and the increased spatial resolution.


2021 ◽  
Author(s):  
Saif Ali Al Mesaabi ◽  
Guillaume Marie Cambois ◽  
James Cowell ◽  
David Arnold ◽  
Mohamed Fawzi Boukhanfra ◽  
...  

Abstract In 2017 ADNOC decided to cover the entire Abu Dhabi Emirate, onshore and offshore, with high- resolution and high-fold 3D seismic. Acquisition of the world's largest continuous seismic survey started in late 2018 and is around 77% complete at the time of writing. Data processing is well under way and interpretation of the first delivered 3D cubes is ongoing. Now is an opportune time to review the status of this gigantic project and draw preliminary lessons. Comparison with legacy data shows a massive improvement in deep imaging, which was one of the main objectives of this survey. The basement can clearly be interpreted, while it is hardly visible on legacy data being covered with high energy multiples. A thorough analysis demonstrated that increased offset is the main reason for the uplift. The large fold and the low frequency sweep also help recover signal down to 3 Hz. This extends the bandwidth in the low frequencies by one to two octaves compared to legacy data, which tremendously benefits structural interpretation and stratigraphic inversion.


2021 ◽  
Author(s):  
Cyril Agut ◽  
Tom Blanchard ◽  
Ya-Hui Yin ◽  
Adeoye Adeyemi

Abstract This paper is dedicated to a pre-salt carbonate field located within the Santos Basin, Brazil, comprising thick Aptian reservoirs interspersed with igneous rocks. One of the main challenges for reservoir management is the surface constraint on the gas, as all of the produced gas will have to be reinjected and can be miscible with the in-situ hydrocarbons. The recovery mechanism selected is mainly WAG (water alternating gas) injection, with both producers and injectors equipped with intelligent completions using Inflow Control Valves (ICVs). A 4D seismic monitoring survey is planned to delineate gas and water fronts in reservoir flow units about 10m thick, providing critical information to help piloting a planned 6-month WAG cycle for improved recovery. Seismic imaging is challenging in this case and 4D signal is expected to be weak (±2% dIp/Ip). We propose here, a methodology, based on a 1-D Gassmann fluid substitution model at wells (only limited reservoir fluid PVT data available) to rapidly answer the following pertinent questions as posed by the asset team in charge of the field: From a phenomenological stand-point and neglecting some possible processing, imaging and acquisition challenges, will 4D data (post 4D inversion) detect a gas streak from an injector to a producer? What is the 4D seismic detection limit based on reservoir thickness? What kind of seismic acquisition will assure this detectability? Under the assumptions made in this work, this methodology shows that a permanent system of acquisition seems to be a fit-for-purpose technology for detectability. Further work is however recommended using full complement of a 3D static and dynamic simulation model coupled with a complete fluid PVT model in order to assess more complex 3D dynamic interactions between the injectors and producers.


2021 ◽  
Author(s):  
Rafael Ignacio Celma ◽  
Nepal Singh ◽  
Kamal Ouldamer ◽  
Pascal Debec

Abstract The objective of this project is to simulate elastic logs (sonic P, sonic S and density) through a Petroelastic Model (PEM) for a complex lithology reservoir in the Middle East, that later will be used as input for a new 4D seismic feasibility study. A log conditioning (despike, depth shift, hydrocarbon correction and normalization) and comprehensive petrophysical analysis was first performed, to obtain lithology volumetric, porosity and saturation, that later were used as input for the PEM. Some wells with recorded P and S sonic log were used to conduct different cross plots of elastic properties (e.g. Vp/Vs vs. Acoustic Impedance) in order to understand how lithology, porosity and saturation affect the elastic parameters of the reservoir. After understanding and assessing the elastic behavior with the reservoir properties, three approaches to construct a PEM were tested on this reservoir. The first approach used to construct PEM applying Hashin Shtrikman (H-S) mixt, considering the solid part as a mixture of dolomite and limestone and pore space filled with a mix of oil and water. This model is limited because assumes a homogenous geometry of the pores. To address the pore geometry a Kuster Toksoz (K-T) approach was subsequently tested but the challenge was that there was no clear organization of the aspect ratio (either by lithofacies or petrophysical groups) so the original logs were used to control of the aspect ratio trough a fit function. The third approach was to use a function that models the incompressibility model of the frame (Kdry) with porosity. The result of H-S was a good agreement in the low porosity areas but in the porous intervals, it is observed that the velocities were quite high due the effect of the pore geometry that was not properly assessed by H-S. Despite reasonable reconstructions, K-T was limited by the impossibility to apply it to the wells without sonic P and S (uncalibrated aspect ratio) or a fortiori to a 3D grid. For the Kdry vs. Porosity function the result was very successful since the function is not dependent on the pore geometry, and addresses the ratio issue between solid and pore space. Then with the help of the Gassman Equation, the final Incompressibility Mix Module (Kmix) was calculated and a reconstructed sonic P and S were available for all the wells. The PEM was coded in order to deploy over a 3D property model hence a volumetric elastic model was available to assess the feasibility for new seismic acquisition.


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