Equinor (Norway)

Tidal reservoirs exhibit complex sedimentary architectures that remain a major challenge to capture in subsurface geological models. In particular, predicting the influence of sedimentary heterogeneities on fluid-flow behavior across multiple spatial scales still remains a major challenge. Simplified or generic modeling approaches often fail to represent the multiscale elements that are characteristic to tidal deposits, resulting in uncertainty in flow predictions and reservoir performance. This limitation is especially critical for geo-energy applications, where reliable forecasts are required to design efficient injection, storage, or drainage strategies.This study adopts a scale-aware approach based on the concept of the Representative Elementary Volume (REV), defined as the minimum volume over which a heterogeneous property, such as permeability, can be considered effectively homogeneous. Identification of the REV at relevant modelling scales enables consistent upscaling of petrophysical properties and reduces uncertainty in geological models and flow simulations. As such, REV-based approaches are essential for building robust geo-models that capture key geological heterogeneities and support reliable performance forecasting for subsurface energy applications.The methodology is demonstrated using reservoir rocks from the Viking Graben (Norway), comprising the Middle Jurassic Brent Group, where the reservoir interval represents a highly heterogeneous tidal depositional system. Detailed sedimentological core logging of selected intervals with pronounced heterogeneity is used to identify the principal lithofacies within the reservoir. For each lithofacies, sketch-based geological models are constructed to capture characteristic heterogeneity, such as key architectural elements, facies proportions, and spatial relationships. This sketch-based approach enables transparent and concept-driven representation of the geological complexity for each lithofacies. For each lithofacies model, the REV is systematically calculated for single-phase flow, resulting in a lithofacies-specific REV. Together, these models form a REV library in which each lithofacies is associated with a representative scale that captures its characteristic heterogeneity. This library provides a transferable framework that can be applied to similar reservoirs worldwide, supporting improved upscaling and flow modeling in data-limited subsurface energy applications.

The Paleocene and Early Eocene stratigraphic succession in the central North Sea records a period of substantial tectonic uplift and several climatic perturbations in the adjacent hinterland. Eastern progradation of the UK shelf and a series of turbidite deposits have previously been linked to several phases of inferred regional uplift. The regional uplift phases caused major increases in sedimentation rates in the North Sea basin and an extensive reorganization of the sediment routing systems. The relative importance of allogenic and autogenic forcings on the sediment supply, depositional patterns and basin-wide geomorphology, however, remains debated. Several authors have suggested that the uplift is a response to activity of the Icelandic Plume.This study incorporates high-resolution 3D seismic and well-log data to conduct a regional reconstruction of the Paleocene – Early Eocene stratigraphic succession in the central North Sea. We investigate key stratigraphic surfaces to link the temporal along-strike variability of erosion and deposition in the Montrose and Moray Groups. Seismic attribute analysis of over 90 000 km2 of 3D seismic data is used to investigate the geomorphology and paleogeography of several interpreted intervals, including clinoform geometry, shelf-edge trajectories, submarine channels, and deep-marine fan systems, providing insights into sediment transport pathways and depositional processes.Preliminary results indicate pronounced along strike variability throughout the Paleocene and Early Eocene in sediment thickness and geomorphology. In the earliest Paleocene the basin was dominated by deep-marine sedimentation, with several submarine fans being deposited in the Moray Firth, Southern Viking Graben and Central Graben. Throughout the Paleocene, the shelf prograded and the basin was infilled. Thick clinoforms, large submarine fans, and extensive shelf progradation during key stratigraphic intervals indicate increased sediment input, suggesting changes in sediment connectivity between hinterland source areas and offshore sinks driven by variations in erosion and runoff. The presence of erosional fluvial networks incised into older marine sediments indicates subaerial conditions during the latest Paleocene to Early Eocene in the Moray Firth. The subaerial erosional networks are associated with a progradation of the coast by tens of kilometers, suggesting a major base-level change, driven by extensive tectonic uplift. This enables detailed observations of geomorphic responses to tectonic and climatic forcings in the entire fluvial to deep-marine sediment routing system.

Abstract Many wells around the world suffer from compromised integrity in the form of leaking annular cement sheaths. Fixing leaking annular cement barriers is generally a labor intensive and costly proposition, particularly in offshore environments. If the leaking cement sheath is opposite a creeping shale or salt formation, there is a possibility of such a mobile formation "healing" the voids, cracks and annuli in the cement sheath and re-establishing annular barrier integrity. Such "healing" can be relatively easily achieved using heaters deployed in the wellbore without the need to create annular access. Large scale "shale-as-a-barrier (SAAB)" rock mechanics tests were carried out in the investigation reported here using a custom-built temperature-controlled triaxial frame to test shale core samples with an inner borehole. This borehole contained a simulated casing string and an annular cement sheath, which could be compromised either by using rubble-ized cement in the annulus or using repeated pressure cycles in the wellbore to attempt to create a micro-annulus at the casing-to-cement interface. The integrity of the annular barrier (or lack thereof) was probed throughout the test using pressure pulse decay experiments, and at the end of the test by breakthrough testing. The creep rate in the North Sea Lark shale was beneficially manipulated using elevated shale sample temperature. In the experiments with rubble-ized cement, it was found that thermally stimulated shale creep can plug the cracks, fractures and voids present within the cement material effectively to form a barrier. In the experiments with intact cement subjected to casing pressure cycles, evidence was obtained that thermally stimulated creep can support the annular cement barrier. The effect of elevated temperature, representing the effect of the deployment of a heater in an actual well setting, proved crucial to magnify and accelerate the creep phenomenon responsible for plugging the flow paths in the compromised cement. With many hundreds of thousands of wells around the work already leaking (or potentially leaking at some point in the future) and/or showing casing pressure at surface because of compromised annular cement barriers, it is important to find (cost-)effective long term remedial solutions. For wells intersection shale or salt formations that either creep at in-situ stress and temperature conditions, or can be induced to creep through thermal stimulation, the remediation using such creep to restore and improve the cement barrier is simple, practical (can be deployed with existing downhole heaters), cost-effective, and is expected to last for an indefinite timeframe. It thereby has the potential to revolutionize P&A operations on wells with compromised integrity.

Summary As part of the energy transition and the aim to reduce greenhouse gas emissions, more carbon in the form of carbon dioxide (CO2) will be captured and stored underground in wells intersecting suitable reservoirs for storage in future. The long-term integrity of such wells is a considerable concern, given that CO2 can react with Portland cement and steel, which can erode well barriers over time. Moreover, low temperatures and temperature cycling in injection and storage wells can lead to cement cracking and debonding from casing, creating annular flow paths for CO2 to surface and allowing for CO2 to attack cement more severely. In this paper, we report on an investigation into using creeping shale formations as alternative annular barriers providing integrity during CO2 injection and long-term storage. Building upon previous work done as part of our ongoing shale-as-a-barrier (SAAB) investigation, rock mechanical laboratory investigations were conducted into the behavior of shale creep in wells experiencing CO2 injection. A special experimental setup was constructed to be able to establish an annular shale barrier at simulated field conditions (using either in-situ formation temperature or thermal stimulation) and then testing this barrier during simulated CO2 injection conditions. During CO2 injection, the well will experience significant reductions and increases in temperature, which can lead to, e.g., the debonding of cement from the casing and the formation of a microannulus that compromises the annular barrier. Note that temperature cycling in wells is a leading cause of the loss of annular isolation and the associated flow to surface of formation fluids and gases in oil and gas wells. In the experiments, shale barriers were first generated and verified at a variety of in-situ and elevated temperatures (which affect shale creep rate). These barriers were then subjected to a significant temperature reduction, as well as temperature cycling with wellbore temperatures reaching a low value of −14°C (7°F), followed by periods where temperature was allowed to rise back up to in-situ conditions. In all cases, the shale barrier continued to function and maintain annular pressure integrity, indicating that well temperature reduction and cycling associated with CO2 injection will not negatively affect it. This is a promising result and insight because the same cannot be guaranteed for a Portland cement barrier. In addition, shale barriers are impervious to any chemical attack by CO2 and are expected to last for a very long time period, given that we are dealing with actual caprock material. Carbon storage wells present new challenges to well construction. These include the low absolute temperatures and large cyclic temperature cycles during CO2 injection, which could lead to cement debonding and microannulus formation providing a pathway for CO2 migration to the surface, as well as chemical attack of cement and casing by CO2 during long-term storage. This work shows that creeping shale formations can deal with both challenges and provide a superior annular isolation solution when compared with conventional Portland cement. The work could have large positive implications for how (barriers in) carbon storage wells will be constructed in the future, and how permanent storage of CO2 underground can be achieved.

Efficient and high-quality processing and visualization of Distributed Acoustic Sensing (DAS) data are essential for human and computer interpretation. Due to the large volume of data in its raw format, the information contained within DAS data are often extracted in predefined data features for practical analysis. Spectral features, those computed from data after a Discrete Fourier Transform (DFT), such as Frequency Band Energy (FBE), are commonly used in interpretation. Harmonizing feature data from different interrogator units (IUs) while maintaining information content is key for machine-learning applications and end-user interpretation. This work demonstrates that this can be achieved by using textbook time-series signal processing for spectral features - along with a novel data-driven method for estimating depth and time-varying noise in DAS data. Several data examples from the in-well environment are presented to illustrate how good practice impacts the result. It is shown that DAS data contains additive noise which have quasi-static Gaussian properties when looking at data in terms of strain (not strain rate). When subtracting the predicted noise from the power spectral densities (PSD) prior to estimating spectral features, we remove the variations in energy level over depth typically observed. We correlate these variations in noise to changes in temperature and mechanical strain of the fiber as observed in low-frequency (LF) DAS, and speculate that this is due to effectively changing the back scattering intensity pattern and thus the fiber as seen by the IU. Data from two different commercial DAS interrogators are compared, and it is shown that feature data from these two boxes are comparable after the suggested processing flow.

Abstract This chapter presents a vast and complex reservoir history-matching case for the Troll field on the Norwegian Continental Shelf. It follows the same history-matching procedure as in the previous chapter. The Troll examples serve as a further confirmation of the learnings and recommendations coming out of the REEK experiments, and the examples illustrate the properties of the history-matching problem when conditioning on production rates. In addition, it uses the adaptive pluri-Gaussian method for parameterizing facies uncertainties and updating these in the history matching. The examples start with a standard history-matching procedure, computing global updates. After that, examples illustrate how the results improve when one properly accounts for uncertainties in the model controls and the facies parameterization. Finally, an adaptive localization scheme reduces the impact of spurious correlations and significantly improves the history-matching results.

Abstract This chapter presents a simple but realistic history-matching case for a model of reservoir named REEK that we use to illustrate the crucial properties of the history-matching problem when conditioning on production rates. We start with a standard HM procedure computing global updates and demonstrating how we improve the results when properly accounting for uncertainties in model controls, dependency of measurement errors, and introducing localization schemes to reduce the impact of the spurious correlations appearing when using a limited sample size. We run multiple experiments and demonstrate correlation-based adaptive localization for the history-matching update. The history-matching problem is inherently under-determined because many different parameter updates give an equally good fit to the data. The final algorithm solves for the minimum geologically consistent update of the uncertain model parameters, providing a good fit to the data.

Stainless steel flange assemblies on an offshore platform experienced crevice corrosion after the bolting was switched from galvanized steel to 25Cr (chromium) super-duplex. Crevice corrosion initiated from the external marine atmosphere, which led to suspicions that the zinc coating on the galvanized bolting was responsible for the many decades of crevice corrosion prevention. Using sea salt layers to simulate marine conditions, electrochemical-based tests were conducted to explore whether zinc could galvanically protect nearby stainless components. Overall, it was demonstrated that zinc/galvanized materials can provide effective polarization protection under relatively dry salt film conditions.

Abstract Drilling automation has emerged as a transformative force in the oil and gas industry, revolutionizing traditional drilling operations to enhance efficiency, safety, and cost-effectiveness. Central to its successful implementation are robust verification and validation (V&V) processes, which ensure the reliability, accuracy, and safety of automated systems. This paper explores the V&V of applications deploying wellbore protection and drilling optimization Advisors integrated with automated drilling control systems (ADCS). Drilling automation applications performing wellbore protection (e.g., pack-off, hookload, over-torque, among others) and drilling optimization functions (e.g., rate-of-penetration (ROP) optimization) are deployed on an edge device connected to an automated rig control system (ADCS). The Advisors parameterize existing capabilities of the ADCS to carry out protection and optimization tasks. The interplay between Advisors and the ADCS is evaluated using a simulated rig environment at different levels: system integration test (SIT) and hardware-in-the-loop (HIL). A variety of test cases are executed to assess how each Advisor performs in conjunction with the ADCS and how stable the integration is under both normal and contingency conditions. Each Advisor performs a self-assessment of its readiness to execute its function safely. The ADCS determines how to assign control of rig activities based on the availability of Advisors. The first layer of V&V, using SIT, simulates surface and downhole sensor signals that are ingested by the Advisors to test the interoperable system. The second layer, using HIL, generates sensor signals via actual programmable logic controllers (PLCs) to achieve a more realistic representation of the rig site. A series of tests enables a thorough assessment of whether each interoperable function between Advisor and ADCS meets design requirements (verification). Furthermore, the execution of these tests in the presence of multiple stakeholders (i.e., operators, drilling contractors, service companies) ensures that the systems perform as intended under real-world conditions (validation). Given the high stakes in drilling operations—including financial risks and environmental concerns—a comprehensive V&V framework is essential. With this approach, potential flaws are detected early in the process and can be resolved during the development phase. This paper presents a summary of the test cases executed for each Advisor across all rounds of testing, along with the corresponding learnings toward achieving seamless interoperability at the rig site. All tests were witnessed by multiple stakeholders representing operators, drilling contractors, service companies, and even assurance and risk management auditors.