Authors; Dr Niels Schovsbo¹, Dr Finn Mørk¹, Dr Henrik Ingerman¹

Affiliation; ¹GEUS

Summary; Rock properties, including geomechanical and petrophysical characteristics, are crucial for assessing CO2 storage safety and viability. In Denmark, the Lower Jurassic Fjerritslev Formation serves as the main seal for key target reservoirs, yet its properties are poorly understood, particularly in the North Sea and western onshore Denmark. Most exploration wells in this area were drilled between the 1950s and 1980s, with limited cores and inadequate log suites. We present an assessment of the Fjerritslev Formation's rock properties in three wells based on a recent screening of cuttings using HH-XRF. Using advanced multilinear regression models, we provide a harmonized dataset that includes volumes of clay, quartz, and carbonate, grain densities, and rock mineral brittleness. This approach offers calibrated measures of Vclay from wireline logs, overcoming traditional pitfalls in defining values and harmonizing between different log types. The results indicate that the Fjerritslev Formation is a thick mudstone with a clay content of 30–50% and total porosities of 10–25%. The rock has a mineralogical brittleness index of 0.4–0.5. Porous beds occur within the shales, highlighting its regional complexity and relevance for CO2 storage.

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Authors; Mr Vincent Jaffrezic¹, Mr Sylvain Thibeau¹

Affiliation; ¹TotalEnergies

Summary;This paper presents the Northern Lights field case where the appraisal well test of Eos (31/5-7) originally suggested a closed reservoir behaviour. This false indication resulted from the drop of the wellbore temperature during the build-up, which was changing the hydrostatic gradient between the pressure gauges and the reservoir as the wellbore fluid becomes denser and the tubing shrank moving the gauges upward. These variations are usually negligible compared to the reservoir signal. However, this was not the case in this thick and highly permeable formation where the reservoir pressure increased rapidly back to the original pressure. It was necessary to correct pressure data for both effects to get a test interpretation consistent with the geology of the storage formation. We will present how these corrections were made and provide recommendations to minimize the effect of temperature transients for future well tests in similar high thickness high permeability formation.

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Authors; Mr Vedran Zikovic¹, Egbert van Riet⁶, Markus Rainer Lüftenegger⁷, Javier Mozas Maradiaga¹, Maartje Koning¹, Benjamin Udo Emmel², Nils Opedal², Ole-André Roli², Andrey Belikov³, María Pérez Fernández⁴, Francesco Crea⁵

Affiliations; ¹TNO, ²SINTEF, ³Eni, ⁴TotalEnergies, ⁵Wintershall Dea, ⁶Shell, ⁷OMV

Summary; This extended abstract showcases a novel approach to well integrity screening developed in the WISCoS project (Well Integrity Storage Complex Screening) by developing a standalone well integrity tool and creating a common approach to well integrity assessment for CCS SLA application.
The developed framework is incorporated into a user-friendly QGIS plugin, enabling visual representation of wells, rapid barrier qualification, and risk-based assessments. It integrates well schematics visualization and barrier assessment while adhering to SLA process requirements to assess the state of each well irrespective of its current use. This innovative approach benefits operators and regulators in the CCS application process by providing a standardized and efficient method for risk assessment. 

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Authors; Dr Behruz Shaker Shiran¹, Mr Bishoy Sadaak², Dr Jonas Solbakken³, Prof. Christina Toigo², Dr Nematollah Zamani¹

Affiliations; ¹Norwegian Research Centre, ²University of Applied Sciences Upper Austria, ³Equinor ASA

Summary; Salt precipitation is a critical challenge that can lead to injectivity impairment during CO2 storage in saline aquifers. This study investigates the impact of salt precipitation on the porosity-permeability correlation and its implications for injectivity. Through experimental analysis, we found that even minor salt precipitation can significantly reduce permeability, despite negligible changes in porosity. Berea sandstone, with its smaller pore radius, exhibited a more pronounced reduction in permeability compared to Bentheimer sandstone under the same conditions. Numerical simulations using TOUGH2 revealed that these differences in porosity-permeability correlation substantially affect the injection pressure over time, highlighting the necessity for accurate experimental evaluation of these correlations prior to numerical modeling.
Our findings emphasize the importance of considering the microscopic and petrophysical properties of reservoir rocks in CO2 storage projects. By tailoring injection protocols and selecting appropriate reservoir sites, the risks associated with salt precipitation can be minimized, ensuring the long-term success of CO2 storage operations. This study contributes to a more comprehensive understanding of the interplay between salt precipitation, porosity, and permeability, aiding in the development of more effective CO2 storage strategies to mitigate global warming.

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Authors; Mr Francisco Lucas Damascena Silva¹, Phd Karen Leopoldino¹, Phd Narelle Maia¹, Sr. Clecio Ribeiro¹, Msc Thiago Barbosa¹, Phd Luis Rodrigues¹, Phd Sebastião Lucena¹, Ms Fabíola Pacheco², Msc Walter Sousa², Phd Manoel²

Affiliations; ¹Federal University Of Ceara, ²Eneva S.A.

Summary; This study proposes the construction of a 1D geomechanical model based on well profiles from a well located in the Parnaíba Basin, Northeast of Brazil, and on mathematical correlations obtained in the relevant literature to calculate the fault reactivation pressure, using the criterion of Mohr-Coulomb and fracture pressure, using the thermoporoelastic effect. Additionally, a flow model coupled to a 3D geomechanical model was developed, aiming to simulate the model with geomechanical coupling using analytically calculated fracture pressure and fault reactivation pressure data. The 1D geomechanical model will allow describing the poroelastic behavior of the reservoir and the sealing rock, detailing the behavior of the main stresses in the formation and pore pressure, to calculate the maximum pressure that the reservoir can withstand to store the maximum possible amount of CO2, determining the fracture pressure of the cap rock. The flow model coupled to the geomechanical model will describe the gas behavior over the model simulation time. Using the extended 3D geomechanical model, an analysis of fault reactivation will be carried out throughout the entire reservoir and in the regions surrounding it. The 3D coupled model will allow studying the effects of CO2 storage until fracture pressure is reached.

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Authors; Mr Sofianos Panagiotis Fotias¹, Mr Ismail Ismail¹, Dr Efthimios Tartaras², Aristofanis Stefatos²

Affiliations; ¹School of Mining and Metallurgical Engineering, National Technical University of Athens, 15772,   ²Hellenic Hydrocarbons and Energy Resources Management (HEREMA)

Summary; CCS involves capturing CO2 from industrial processes and storing it permanently underground, typically in deep geological formations like saline aquifers or depleted oil fields. Effective deployment hinges on a well-executed Field Development Plan (FDP), crucial for maintaining storage integrity and managing risks such as pressure buildup and geological stability.

Current FDP design heavily relies on manual simulation runs to optimize parameters like well locations and injection/extraction rates, balancing technical, operational, and economic constraints. Traditional methods face challenges due to the complex, nonlinear nature of subsurface reservoirs and the need for extensive computational resources.

To address these challenges, advanced optimization techniques like Bayesian optimization (BO) are proposed. BO has been applied and proven effective in optimizing complex, costly functions, aims to streamline CCS operations by optimizing CO2 injection and brine withdrawal rates. This approach builds on previous research focusing on well location optimization, aiming to enhance CCS efficiency and feasibility at a field level, integrating technical precision with operational flexibility.

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Authors; Ms Varsha Devi¹

Affiliations; Halliburton

Summary; Active CO2 injection sites, spanning from large-scale Enhanced Oil Recovery (EOR) projects to smaller-scale pilots, provide invaluable insights into the practical challenges and successes of carbon dioxide (CO2) storage initiatives. This abstract synthesizes lessons learned from these diverse sites, focusing on technical, operational, and regulatory aspects crucial for successful CO2 injection and long-term storage. Key themes include site selection criteria emphasizing geological suitability, the importance of robust monitoring and verification protocols to ensure secure storage, and effective public engagement strategies to garner local support. Additionally, regulatory frameworks and legal considerations are explored, highlighting the necessity of clear guidelines for navigating permitting, liability, and compliance issues. By synthesizing experiences from active CO2 injection sites, this abstract informs future CCS (Carbon Capture and Storage) projects, fostering improved implementation strategies and advancing global efforts towards carbon neutrality and climate change mitigation.

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Authors; Dr, David Halliday¹, Mathieu Chapelle¹, Mike Branston¹, Ran Bachrach¹

Affiliations; ¹SLB

Summary; Each carbon capture, utilization, and storage site requires a measurement, monitoring, and verification plan, which provides assurance regarding the conformance and containment of the stored CO2 and ensures compliance with regulations.

Time-lapse seismic monitoring is a proven technology for characterizing the subsurface. However, costs associated with the acquisition, processing, and interpretation of conventional time-lapse seismic are high, and a step change in the cost of CO2 monitoring, versus conventional reservoir monitoring, is a common goal across the industry.

In this paper, we propose using the output of dynamic subsurface modelling, to design 4D surveys that target specific changes in a known subsurface model. This is done using a perturbation analysis, based on full-waveform inversion (FWI), that allows the model and perturbation to be synthetically probed with different acquisition geometries, to determine which geometry provides the most cost-effective solution to detect and localise the targeted change.

The 4D FWI workflow is tied to the monitoring plan, associated dynamic modelling and the evergreening of the subsurface model. This means that it is adaptive: the design will vary proportionally as the understanding of the injection site evolves.  

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Authors; Dr Salam Al-Rbeawi¹, Dr Fadhil Kadhim²

Affiliation; ¹Middle East Technical University, ²The University of Technology-Baghdad

Summary; This paper introduces an integrated approach for estimating the key parameters of CO2 storage projects in depleted hydraulically fractured shale reservoirs. Several analytical models are developed for the pressure behavior of CO2 multi-size scales flow mechanisms. Diffusion flow, slip flow, adsorption flow, and Darcy and non-Darcy flow are considered. The flow in the nano-size organic particles, micro-size kerogen particles, and macro-size matrix is analytically described. The flow inside natural fractures in the stimulated and unstimulated reservoir volume as well as the flow of CO2 in hydraulic fractures are modeled.
The study has reached several conclusions. The characteristics of the organic matter, kerogen, and micro-size scale matrix do not significantly impact the pressure distribution and flow regimes. Conversely, the pressure distribution and flow regimes are significantly impacted by the characteristics of hydraulic and natural fractures. The hydraulic fractures may offer a reasonable capacity for CO2 storage, meanwhile the capacity of stimulated and unstimulated reservoir volume is controlled by reservoir configuration and fracture spacing. The constrained pressure may strictly reduce the total capacity of CO2 storage in the reservoir. The total volume of the injected CO2 can be determined from the pressure point when the injection pulse has reached to reservoir boundary.

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