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Biosimulytics focuses on developing a platform that enables biopharma companies to shorten the time to market of new drug compounds by simulating lead optimization, one of the most challenging steps of the drug development process. This process relies on tedious laboratory experiments to crystallize and further characterize candidate drug molecules. Biosimulytics’ patented platform computes the most stable crystal structure, making drug development faster, more cost-effective and with less risk.

It has been well documented that the pre-stack seismic attributes can be an efficient tool for hydrocarbon exploration and pore fluid detection using techniques like Amplitude Versus Offset (AVO) analysis. These studies mainly focus on siliciclastics rather than carbonates as fluid effects in carbonate rocks can be masked by their complex pore structure. These fluid detection seismic attributes usually reside on a linear background model for P- and S-velocities of the water-saturated rocks, and any deviation from this trend is assigned to the possible pore fluid changes. This means that fake (or even missed) fluid effects can be detected in carbonate rocks if the fluid detection seismic attributes, which designed for siliciclastics, are used. This can mainly be related to the nonlinearity of background model in carbonates due to their varying pore structure. In this study, both well logs and seismic data from a carbonate sequence are used to show that the correlation between P- and S-velocities in water-saturated carbonates becomes more linear when considering P-velocity squared versus the product of the P- and S-velocities. Furthermore, this linear version is used for detecting the fluid anomalies, and being compared with other various fluid factors to highlight the gas saturated interval. The modified fluid attribute displays the gas-saturation brighter than the alternatives, although, in this case, all the studied indicators perform well and consistently.

The northern North Sea is a very active oil and gas exploration region, where several commercial discoveries have been made over recent years. The Lower Cretaceous sands within the Agat Formation is a reservoir play that has been targeted for decades. The quality and distribution pattern of the sand within the Agat Formation varies over the area, making it challenging to map the Agat play. A high-quality regional dataset is a valuable tool for interpretation and attribute generation to map out and correlate the different Agat sand packages and fairways.

In this exclusive interview for AI and Technology Magazines, Agnès Boudot, EVP, HPC & Cloud Solutions, discusses her decades of HPC experience and how Viridien is collaborating with new clients to tailor and optimize their HPC and cloud environments.

This article highlights some important outcomes from an integrated study in the Anadarko Basin. Newly generated data is presented and discussed across the study area. The main aspects discussed here focus on 1) basin evolution, which has played an important role in source maturity and hydrocarbon generation. 2) Source rock characterization, including source rock properties and quantification of the hydrocarbon content performed with a newly developed pyrolysis method and 3) reservoir characterization based on the integration of regional information and data generated from seismic reservoir characterization. These aspects are discussed to assess their implications on hydrocarbon distribution within unconventional resources from Woodford and Mississippian section. In the last section of this article, we propose a play assessment workflow that could be applied to address uncertainties associated with these plays. This workflow comprises 1) a regional or basin-scale evaluation based on 3D petroleum system modelling (3D PSM) and 2) a more detailed evaluation based on the integration of seismic reservoir characterization into petroleum systems modeling on a local scale.

In an exclusive interview with Frontier Energy Network, Emmanuel Nformi, Viridien’s Business Development Manager, Sub-Saharan Africa, Earth Data, and Samuel Essoh, Geoscience Director, PETROCI, spoke about the relationship forged with Côte d’Ivoire’s General Directorate of Hydrocarbons (DGH) and NOC, PETROCI Holding (PETROCI) since 1999 and the mutual benefits gained.

FWI velocity models do not necessarily ensure an optimal flattening of common image gathers (CIG). A fundamental reason for this is that mid to high wavenumbers are brought into the model by the reflection amplitudes, which are only partly explained by changes in velocity. A residual low wavenumber update of the model is then frequently done with the consequence that the positioning of small-scale events in the model may no more be consistent with the migrated image. In this paper we first highlight and illustrate the above mentioned pitfalls. We then propose an innovative workflow based on FWI-guided tomography.

Interbed multiples cause artifacts in subsurface images because they are incorrectly migrated when using standard primary-based migration algorithms. While surface-related-multiple-elimination has been well established as a standard step in seismic processing, the usage of interbed multiple attenuation (IMA) remains low due to various practical challenges such as inaccuracy in prediction, difficulty in subtraction, and prohibitively high compute cost. We propose a workflow with a few strategies to improve the applicability of IMA. Using a 3D field data example, we demonstrate the effectiveness of our workflow in predicting and attenuating interbed multiples. We also illustrate how the removal of interbed multiples can help with accurate interpretation of subsurface geology.

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