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Full-waveform inversion (FWI) has demonstrated tremendous potential to provide high-resolution models of the subsurface in different geological settings. However, in complex environments such as salt and subsalt, relying on acoustic approximations in FWI limits the accuracy of Earth models derived from modern field data, and may require complex workflows to mitigate the challenges associated with large elastic parameter variations. Recent case studies highlight this issue and suggest that more accurate models can be produced by elastic FWI using simpler workflows in these areas. In addition to elasticity, wave propagation in the subsurface undergoes anelastic (viscous) effects, especially through absorption in gas-charged layers. Although anelastic effects are known to be significant in many visco-acoustic case studies, few examples consider both elastic and anelastic effects in FWI. In this paper, we present a visco-elastic FWI to invert for P-wave velocity and associated viscosity. We demonstrate our approach using ocean-bottom node data from the Central North Sea in a complex area associated with strong velocity contrasts and shallow absorption anomalies. Results in this area demonstrate that visco-elastic FWI can provide high-resolution viscosity and velocity models, and an FWI Image with improved event continuity, resolution, and signal-to-noise ratio compared to visco-acoustic FWI.

The geological storage of carbon dioxide (CO2) and its benefits in abating unfavourable climate change have existed for decades. Even though the development of technical solutions has been slow, there has been some progress in key areas including several storage projects around the world, nations setting mandates with the hope of reaching net-zero in specific timelines, and establishment of policies and regulations to support the drive. The capture and subsequent storage of CO2 from emitters such as power stations and industrial processes, among others, play a major role in curtailing this threat to the ecosystem. A recent study indicates that the utilisation of Carbon Capture and Storage (CCS) technology could reduce CO2 emissions by 20% by 2050 (Aminu, 2017; Tomi? et al., 2018). The aim of this study is to determine the order of suitability of potential CO2 storage formations in the Gulf of Mexico Outer Continental Shelf (OCS), including both shallow and deep waters. The objectives of the study include screening of the formations with respect to geological suitability and ranking of the screened formations based on technical and techno-commercial considerations.

The Culzean field, in the North Sea, has been producing since 2019 gas condensate from fluvial sandstones located within dipping rotated fault blocks at approximately 4km of depth. Two surveys have been acquired with ocean bottom sensors to image and then monitor the evolution of the reservoir during production. In addition to classical time-lapse seismic processing, a time-lapse FWI has been performed to estimate the velocity variation over the production time. Due to the thick chalk layer located just above the target structure and the dipping nature of the reservoir, 4D FWI is the ideal tool compared to more conventional 1D approach based on time-shift estimations. This fast velocity layer represents a challenge for velocity model building and processing in general as it prevents the penetration of diving waves even with 7km of offset and also generates strong multiple curtains covering the reservoir interval. Despite the shallow water environment and complex geology, the 4D FWI implemented in this project was able to recover velocity variations as weak as 1% after only 3 years of production, providing crucial information that can help reservoir evolution assessment.

High-resolution (HR) site survey acquisitions are traditionally utilized for shallow geohazard investigations and infrastructure planning. However, due to cost reasons, these are often acquired in a sparse 2D manner, and supplemented with conventional multi-streamer 3D seismic imaging aimed at deeper targets. We show how products derived from 100 Hz dual-azimuth (DAZ) full-waveform inversion (FWI) using multi- streamer 3D data, including FWI Imaging, provide a superior uplift in spatial resolution and illumination compared to a combination of both conventional 3D imaging using the same data, and 2DHR site survey data. This is shown to be the case for data and attributes compared against those from a site survey report at various near surface intervals where known geohazards occur. The improved spatial resolution with 100 Hz DAZ FWI can reduce uncertainties in predicting hazards and act as rapidly available supplementary information to a sparser 2DHR survey with less need to acquire a denser 3DHR survey.

Time-lapse (4D) surveys have traditionally been reliant on baseline (base) surveys being well repeated by the monitor to decrease 4D noise. In this case study the monitor was acquired independently from the 3D narrow-azimuth, towed-streamer, hydrophone-only base, and “mixes” two different types of acquisition: a multi-sensor, towed-streamer acquisition for prime coverage and a multi-sensor towed-streamer infill. We describe technologies used to overcome the limitations in 4D repeatability and intra-monitor consistency. 3D Ghost Wavefield Elimination and a novel blind signature inversion method were crucial to create a seamless monitor across the target and to reconcile the signature and ghost differences between the base and monitor. Inconsistent azimuth content between base and monitors introduced complexities for the demultiple process; nevertheless, multiples were successfully attenuated using wave equation deconvolution with joint base and monitor reflectivity imaging. Residual non-repeated 4D noise was attenuated using a curvelet domain 4D co-operative denoise workflow.

We discuss challenges of Distributed Acoustic Sensing (DAS) data in a Vertical Seismic Profile (VSP) setting and propose processing and imaging solutions to overcome these. The context is to review processing challenges and benefits of DAS VSP as a potential cost-effective solution for CO2 storage monitoring. DAS VSP data acquired during a monitor surface seismic acquisition over the Johan Sverdrup field in 2021 provides the means to assess this, with both learnings and uncertainties from this study informing on the potential of this technology in other geological settings. Here, an initial feasibility assessment conducted using a baseline and repeat monitor survey, acquired a few weeks later, indicated the achievable levels of repeatability with this data type. An inclusive pre-processing flow and use of both up-going and down-going wavefields in a tailored imaging routine showcases the level of subsurface illumination and high signal-to-noise levels for 3D reservoir imaging. Finally, subsequent CO2 modelling work provides an understanding of the potential of DAS VSP surveys for future 4D monitoring work for conventional or un-conventional reservoir monitoring

Short period multiple prediction for land data is challenging due to poor imaging of the shallow multiple generators as well little information about the down-going reflection at the weathering layer. Based on multiple imaging of the shallow section, surface-related wave-equation deconvolution has been used in recent years to improve multiple prediction in such areas. We improve the accuracy of wave-equation deconvolution to include an angle dependency of the multiple generator reflectivity. In addition, we modify the approach to handle internal multiple predictions where the lower-generator is provided by surface-related wave-equation deconvolution, and the upper-reflectivity is derived through least-squares inversion. The combined benefit of these two approaches is demonstrated on a land dataset from south Oman.

In recent years, the Brazilian presalt characterization has been a challenging task, either because of the imaging problems associated with complex salt layer geometry (Penna et al., 2019) or due to large heterogeneity in the presalt carbonates reservoir (Oliveira et al., 2018). Some efforts to address these challenges include full-azimuthal acquisitions technologies (nodes acquisition) and new processing techniques and studies to better understanding the geological model. Recent multi-azimuthal seismic data acquisition provides not only better seismic imaging, but also fractures properties through velocity and amplitude changes with azimuth variation, providing a better spatial characterization of the fracture system. We present an azimuthal elastic seismic inversion (Roure et al., 2012) in a Nodes presalt reservoir data, addressing the local fracture system characterization. Fracture parameters are described in terms of the normal and tangential weakness plus fracture strike. Prior to the inversion, an azimuthal seismic preconditioning has also performed on the seismic dataset to attenuate the imaging problems in the reservoir interval and consequently improving the signal-to-noise ratio providing better estimates of the properties of interest. Fracture characterization studies commonly integrates borehole image logs, core data and well test, usually restrict to specific areas around drilled wells. In some cases, tridimensional fracture models are created through geostatistical modelling constrained by seismic attributes. However, those are indirect measures of fractures, with high associated uncertainties. Recent multi-azimuthal seismic data acquisition provides not only better seismic imaging, but also fractures properties through velocity and amplitude changes with azimuth variation, providing a better spatial characterization of the fracture system. We present an azimuthal elastic seismic inversion (Roure et al., 2012) in a Nodes presalt reservoir data, addressing the local fracture system characterization. Fracture parameters are described in terms of the normal and tangential weakness plus fracture strike. Prior to the inversion, an azimuthal seismic preconditioning has also performed on the seismic dataset to attenuate the imaging problems in the reservoir interval and consequently improving the signal-to-noise ratio providing better estimates of the properties of interest.

The imaging of the complex fault system plays an important role in hydrocarbon exploration in Wenchang field since the fault system forms a bridge between the source rocks and reservoirs. However, it is challenging to obtain a high quality depth image of the fault system due to the complex depth velocity and Q absorption effect. In this paper, we demonstrate how a combination of Fault Constraint Tomography (FCT) model building flow and Q-compensated High Fidelity Controlled Beam Migration (QHFCBM) work together to provide a step change in the imaging quality and bring significant impact to the reservoir delineation.