Petroleum Safety Authority Research Articles

Changes in well control training to meet the challenge of reducing well control incidents

The number of safety related incidents in the Oil and Gas industry has steadily declined over the past 20 years. However, the frequency of well control incidents has not followed the same trend. The Norwegian regulator (Petroleum Safety Authority) has recently documented this finding as related to the Norwegian sector of the North Sea. Globally, the International Association of Oil and Gas Producers (IOGP) Report 637 and recent data from Wild Well Control also support this conclusion – in fact, Wild Well Control data shows that the frequency of well control incidents may be increasing. The loss of experienced personnel due to reduced activity during the COVID-19 pandemic may have contributed to this. Now that activity is increasing again, the industry faces a challenge in recruiting skilled personnel. Current well control courses predominantly cover the well construction process, with minor emphasis on the whole life cycle of the well. However, a significant number (in some areas close to half) of well control incidents occur after the well construction process is completed. Based on analysis of the main contributory factors to well control incidents, IOGP has recently updated Report 476 ‘Recommendations for enhancements to well control training, examination and certification’. This paper reviews the changes to Report 476 and discusses how International Well Control Forum can contribute to reduce the well control incident rate with focus on the Well Control in Design and Lifecycle Management course.

Reducing risk of sexual harassment: a positive duty of care

The oil and gas sector has made progress towards becoming safer and more respectful for all employees. However, recent public reports, including the Western Australian Parliament’s ‘Enough is Enough’, and increasing engagement from National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA), continue to demonstrate that sexual harassment remains pervasive across the industry – 32% of people still experience sexual harassment in their workplace. The social, physical, psychological, and financial costs of sexual harassment are devastating, both to individuals and employers. The damage can carry long-term business and reputational consequences. All Australian employers are under a new, legally enforceable positive duty to take ‘reasonable and proportionate measures’ to prevent sexual harassment. It requires proactive steps to ensure sexual harassment is prevented from happening in the first place. Vicarious liability provisions have been expanded so that employers can now be held accountable – even if no complaints are lodged. Employers require a clear framework to ensure they are meeting their positive duty obligations. There are three key areas that can enable the oil and gas sector to strategically leverage their compliance activities, maximising benefits for their business and for their people. These key areas include: (1) capability and engagement of leaders and management; (2) understanding the risk factors and drivers of sexual harassment for the industry, and for individual organisations; and (3) understanding employee experiences of psychological safety, culture, and behaviours.

Application of Machine Learning Modeling for the Upstream Oil and Gas Industry Injury Rate Prediction

Introduction: Yearly, the International Labor Organization report indicates many workplace accident occurrences. The degree of the happenings depends on the workplace environment setting and the incident regulatory measures implemented. By the nature of its work environment, the oil and gas upstream sector is susceptible to high incident rates. In the current fierce business competition and practices, improving productivity, quality, and other processes, such as Safety, is vital. Implementing well-designed safety procedures is the key to managing and reducing the risk level of workplace incidents. Methods: Recently, the application of Machine learning (ML) modeling for accident/injury prediction has been reported in the construction, mining, transport, and health sectors. Likewise, the objective of this paper was to implement three machine-learning-based models to predict injury rates in a drilling operation. The petroleum safety authority of Norway provided the datasets. First, the dataset was pre-processed, and then the selected features and target dataset were used for the modeling. Finally, the model prediction and performance accuracy analysis were performed. Results: Results showed that multivariable regression (MVR), Random Forest (RF), and Artificial Neural Network (ANN) machine learning algorithms-based models predict the test data with R2 values of 0.9576, 0.793, and 0.97036, respectively. Conclusion: As the common saying goes, 'prevention is better than cure.' For this, implementing methods such as improved work processes and Health, Safety, and Environment (HSE) mitigation procedures, workplace injuries, and accidents allow for reducing the risk level of workplace injuries. The application of integrated machine learning tools, along with carefully built-in workplace accident database implementation, will provide early detection and possible remedial precautions that can be taken to prevent workplace injuries/accidents/fatalities. However, extensive research and development are required to deploy the method in real life. Combining Machine Learning modeling and carefully designed safety measures is vital for successful and robust predictive tools.

An Attribute Perspective on Regulatory Regimes in Risk Governance

Abstract Increasing interest from stakeholders has brought new focus on risk governance and risk regulation, such as the regulator’s execution of duty and tangible results on safety and environmental protection in oil and gas industry. One recent example, from 2019, is the Office of the Auditor General Norway’s (OAG) investigation of the Petroleum Safety Authority’s (PSA) follow-up on health, safety and the environment in the petroleum industry, where the regulatory regime in Norway resting on functional requirements was questioned. Simplistically speaking, there are two current traditions or main schools in regulatory regimes: use of functional requirements associated with co-regulation and use of normative requirements associated with prescriptive regulation. In this paper, we introduce a generic model from an attribute perspective on contrasting, gauging or evaluating the two different regulatory regimes. Furthermore, this approach may explain the controversy regarding the favouring of functional or prescriptive regulatory regimes by the different players in the industry. Our case is based on regulations relating to offshore oil and gas operations, in particular focusing on the Norwegian sector. We use the OAG’s investigation of the PSA and the public reaction as our material because this material is proposed to provide a thorough and valid description of how the effects of the Norwegian regulatory regime are perceived from the outside. We believe that the generic concept presented here is applicable when performing investigations in other industries involved in hazardous activities.

Risk in transit: a case study of the introduction of a new risk definition for risk management in the Norwegian petroleum industry

In 2015, a new risk definition was presented by the Norwegian Petroleum Safety Authority (PSA-N) as a petroleum regulation update and ‘rolled out’ in the PSA-N organisation and the oil and gas industry as a regulatory guideline, changing the definition of risk from ‘the combination of probabilities and consequences’ to ‘the consequences of an activity, with associated uncertainties’. This article reports on research that explores the industrial effects of this change. We have conducted qualitative interviews with both operator employees and consultants, and we have undertaken a qualitative cross-sectional analysis, where we explored how the implementation of the new risk definition is experienced by different actors in the industry. The analysis draws on translation perspectives from institutional theory and focuses on the developments of theory and practice influenced by the interaction between the industry and consultancies, academia and the regulator. We find that the new risk definition has had some practical influence on risk management, particularly exemplified through a generally raised awareness about uncertainty, in addition to some direct effects on risk analysis tools. The study also demonstrates pros et cons with a functional regulatory regime. On one hand it gives the companies significant leeway for them to tailor their treatment and evaluation of uncertainty to the context. On the other hand, with different understandings of uncertainty among the companies, it is more challenging for the regulator to perform audits in a structured manner. Furthermore, the study sheds light on different power aspects that are at play, influencing the interplay between standardised definitions, legislative instruments, practice, experience, and expertise.

Integrated team approach to decommissioning Environment Plan development

The offshore oil and gas industry is facing a significant transition period in the coming decades due to the evolving energy market and aging oil and gas infrastructure. Industry has over 1000 offshore wells to plug and abandon, 57 fixed facilities and over 8000 km of subsea lines to decommission over the coming decades. Most of this significant portfolio is regulated by NOPSEMA (National Offshore Petroleum Safety and Environmental Management Authority) with the expectation that decommissioning involves the full removal of equipment as per Section 572 of the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (Cth) (OPGGS Act). However, other options may be considered if the titleholder can demonstrate that an alternative decommissioning approach delivers equal or better environmental and safety outcomes compared to complete removal. Integration of environment and engineering functions primarily occurs during the process of developing an Environment Plan (EP) and, specifically, the process of identifying environmental hazards (Environmental Hazards Identification, ENVID) and mitigation measures. This paper proposes that improved stakeholder, regulatory, cost and environmental outcomes could be achieved through an earlier integrated approach to planning decommissioning activities. Specifically, co-designing an approach to decommissioning at the earliest stages would inform, for example, approvals strategy and equipment selection. This would ultimately result in improved outcomes without the application of mitigating control measures. The paper will discuss some of the current challenges and outline the value of early identification and understanding of key environmental values and sensitivities to ensure site-specific information is considered during planning stages, later streamlining EP development. A multi-disciplinary decommissioning team in the early stages of project development enhances problem-solving capabilities and ultimately improves environmental and safety outcomes.

An interpretable and augmented machine-learning approach for causation analysis of major accident risk indicators in the offshore petroleum industry

The offshore petroleum industry faces continuous stress and threats of major accidents. A complete and well-designed spectrum of indicators could help identify and improve the understanding of the status of all relevant hazards for managing various risks on offshore installations. The Petroleum Safety Authority (PSA) in Norway develops a project of extended indicators, i.e., “Trends in risk level” (RNNP), which uses an assortment of risk indicators to reflect the status and trend of the risk level. However, a simple statistical approach is insufficient to see into the causes behind the risk indicators. This paper proposes an interpretable and augmented machine-learning approach for causation analysis of major accident indicators. The proposed methodology integrates the K-means SMOTE technique for data augmentation to promote the performance of machine-learning algorithms. Armed with the analytical approach, the problem of lack of sample data is solved and the importance of the features of risk indicators is analyzed. Furthermore, a case study is presented to augment and analyze the two types of risk indicators associated with major accidents recorded from 2005 to 2021. The effectiveness of the proposed approach is demonstrated by the case study. It can provide an effective tool to help find out which type of features deserves more attention in risk management and target risk reduction measures that could be taken to strengthen safety on offshore installations.

Regulator Analyzes Australia’s Decommissioning Challenge

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 208483, “Is Australia Prepared for the Decommissioning Challenge? A Regulator’s Perspective,” by David Christensen and Andrew Re, National Offshore Petroleum Safety and Environmental Management Authority. The paper has not been peer reviewed. _ The Australian offshore petroleum industry has been in operation since the early 1960s and at the time of writing has approximately 57 platforms, 11 floating facilities, 3500 km of pipelines, and 1,000 wells in operation. Many offshore facilities are now approaching the end of their operational lives. Modeling has estimated Australia’s combined offshore petroleum industry decommissioning liability (including wells, pipelines, subsea equipment, and facilities) to be $40.5 billion. The purpose of the complete paper is to highlight the importance and benefit of adopting best practices when planning for decommissioning throughout the life cycle of a petroleum project. Introduction Australia’s offshore petroleum decommissioning challenge is significant given its remote location, limited availability of specialist services, and the relative infancy of its offshore industry in undertaking large-scale decommissioning projects. Recent events in Australia have shown that the industry is, broadly speaking, unprepared for decommissioning. Australian Regulatory Approach The Offshore Petroleum and Greenhouse Gas Storage (OPGGS) Act of 2006 and associated regulations provide the legal framework for the exploration and recovery of petroleum and greenhouse gas activities in Australian Commonwealth waters (those areas that are more than 3 nautical miles from the territorial sea baseline). The key principle underpinning the OPGGS Act and regulations is that responsibility for ensuring the health and safety of workers and the protection of the environment lies with those who create the risks. An objective-based regulatory regime sets requirements that must be achieved but does not prescribe how those requirements must be met. The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) has been established and appointed under the OPGGS Act as regulator for health and safety, structural (well) integrity, and environmental management of petroleum activities in Australian waters (3–200 nautical miles offshore) and in coastal waters (0–3 nautical miles offshore) where regulatory powers and functions have been conferred. Section 572, Maintenance and Removal of Property. Section 572 of the OPGGS Act establishes requirements for maintenance and removal of property by the titleholders, along with exemptions and obligation provisions. Section 572(2) of the OPGGS Act provides that a titleholder must maintain in good condition and repair all structures that are, and all equipment and other property that is, in the title area and used in connection with operations. Section 572(3) of the OPGGS Act provides that a titleholder must remove from the title area all structures that are, and all equipment and other property that is, neither used nor to be used in connection with the operations in which the titleholder is or will be engaged.

Concurrent 23. Presentation for: Cradle to grave: planning for all well decommissioning

Presented on Thursday 19 May: Session 23 As the Australian offshore oil and gas sector continues to mature, there is an increasing level of activity in the final phase of the well lifecycle: well decommissioning (well abandonment). Several decommissioning projects are either already in progress or being planned in Australian waters. Since the 1960s, the eventual decommissioning of wells has been an expectation within the law. Whilst this fundamental obligation has not changed, the expectations for the management of offshore wells and equipment have changed for both the industry and regulators. In the meantime, the number of unused wells grew. In 2021, the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) published a Decommissioning Compliance Strategy and Decommissioning Compliance Plan. From this, all wells will have been risk assessed and have accepted abandonment plans in place by the end of 2023, and all wells will be permanently abandoned within 3 years of cessation of well operation by the end of 2025. The industry has an immediate challenge catching up on the backlog of abandoning wells, some of which have been in an unused state for decades. Going forward, well abandonment should be actively considered throughout the well lifecycle, including design, construction and operation phases. This will enable decommissioning objectives to be achieved in a safe, timely and efficient manner. This paper will provide an overview of recent domestic and international developments related to well decommissioning, from a regulatory perspective, and the importance of proactive well decommissioning planning and collaboration. To access the presentation click the link on the right. To read the full paper click here

Concurrent 15. Presentation for: Guidance document: Incident Management Teams – Knowledge requirements for responding to marine oil spills

Presented on Wednesday 18 May: Session 15 The National Offshore Petroleum Safety and Environmental Authority undertakes the assessment of environmental plans and oil pollution emergency plans for petroleum activities in Australian Commonwealth waters. In 2019, the Australian Petroleum Production and Exploration Association’s Oil Spill Preparedness and Response Working Group (OSPRWG) developed a work program to address identified Incident Management Team (IMT) training issues, with an aim to develop industry good practice guidance in relation to IMT skills, competencies and oil spill training. The OSPRWG has now produced a guidance document on IMT oil spill training, that was developed in collaboration with the Australian Marine Oil Spill Centre and peer reviewed by Oil Spill Response Limited. The guideline should facilitate a greater and more coordinated mutual aid IMT oil spill capability within the Australian offshore petroleum industry. To access the presentation click the link on the right. To read the full paper click here

Concurrent 23. Presentation for: Safety zones and decommissioning

Presented on Thursday 19 May: Session 23 Australia’s oil and gas sector expects approximately 56 billion (AUD) to be expended for decommissioning costs over the next 50 years. The view of the National Offshore Petroleum Safety and Environmental Management Authority is that the designated decommissioning approach must provide equal or better environmental outcomes when compared to full removal of the infrastructure (considered the ‘best case’ expectation under current legislation) and meets as low as reasonably practicable (ALARP) levels of risk. Decommissioning alternatives are generally evaluated through a comparative multicriteria assessment approach, for example, a net environmental benefit analysis-based comparative assessment (NEBA-CA). Decommissioning options cover a range of possibilities, from full removal to leaving subsea structure in situ (in part or in whole). NEBA-CAs we have conducted suggest that some subsea structures are projected to generate significant ecological and social value over multiple generations to come. Thus, in these cases, management in situ can provide greater benefits to the public when compared to full removal. During operation, oil and gas assets typically incorporate a safety zone. If subsea structure is selected to be managed in situ, a question that arises is, should the safety zone be maintained or removed? Our experience indicates that if the safety zone is removed after decommissioning an asset that is left in situ, there may likely be a greater adverse impact on ecological and social values, depending upon the asset location. This abstract showcases the value of the use of safety zones to maximise environmental value while managing risk. To access the presentation click the link on the right. To read the full paper click here

Guidance document: Incident Management Teams – Knowledge requirements for responding to marine oil spills

The National Offshore Petroleum Safety and Environmental Authority undertakes the assessment of environmental plans and oil pollution emergency plans for petroleum activities in Australian Commonwealth waters. In 2019, the Australian Petroleum Production and Exploration Association’s Oil Spill Preparedness and Response Working Group (OSPRWG) developed a work program to address identified Incident Management Team (IMT) training issues, with an aim to develop industry good practice guidance in relation to IMT skills, competencies and oil spill training. The OSPRWG has now produced a guidance document on IMT oil spill training, that was developed in collaboration with the Australian Marine Oil Spill Centre and peer reviewed by Oil Spill Response Limited. The guideline should facilitate a greater and more coordinated mutual aid IMT oil spill capability within the Australian offshore petroleum industry.

Safety zones and decommissioning

Australia’s oil and gas sector expects approximately 56 billion (AUD) to be expended for decommissioning costs over the next 50 years. The view of the National Offshore Petroleum Safety and Environmental Management Authority is that the designated decommissioning approach must provide equal or better environmental outcomes when compared to full removal of the infrastructure (considered the ‘best case’ expectation under current legislation) and meets as low as reasonably practicable (ALARP) levels of risk. Decommissioning alternatives are generally evaluated through a comparative multicriteria assessment approach, for example, a net environmental benefit analysis-based comparative assessment (NEBA-CA). Decommissioning options cover a range of possibilities, from full removal to leaving subsea structure in situ (in part or in whole). NEBA-CAs we have conducted suggest that some subsea structures are projected to generate significant ecological and social value over multiple generations to come. Thus, in these cases, management in situ can provide greater benefits to the public when compared to full removal. During operation, oil and gas assets typically incorporate a safety zone. If subsea structure is selected to be managed in situ, a question that arises is, should the safety zone be maintained or removed? Our experience indicates that if the safety zone is removed after decommissioning an asset that is left in situ, there may likely be a greater adverse impact on ecological and social values, depending upon the asset location. This abstract showcases the value of the use of safety zones to maximise environmental value while managing risk.

Cradle to grave: planning for all well decommissioning

As the Australian offshore oil and gas sector continues to mature, there is an increasing level of activity in the final phase of the well lifecycle: well decommissioning (well abandonment). Several decommissioning projects are either already in progress or being planned in Australian waters. Since the 1960s, the eventual decommissioning of wells has been an expectation within the law. Whilst this fundamental obligation has not changed, the expectations for the management of offshore wells and equipment have changed for both the industry and regulators. In the meantime, the number of unused wells grew. In 2021, the National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) published a Decommissioning Compliance Strategy and Decommissioning Compliance Plan. From this, all wells will have been risk assessed and have accepted abandonment plans in place by the end of 2023, and all wells will be permanently abandoned within 3 years of cessation of well operation by the end of 2025. The industry has an immediate challenge catching up on the backlog of abandoning wells, some of which have been in an unused state for decades. Going forward, well abandonment should be actively considered throughout the well lifecycle, including design, construction and operation phases. This will enable decommissioning objectives to be achieved in a safe, timely and efficient manner. This paper will provide an overview of recent domestic and international developments related to well decommissioning, from a regulatory perspective, and the importance of proactive well decommissioning planning and collaboration.

Optimising Subsea Well Source Control Timeframes

ABSTRACT In response to the Montara and Macondo subsea well incidents in 2009–10, the industry's knowledge of and ability to respond to a subsea source control (SSC) event has greatly improved. Industry has invested heavily in its response capabilities and established best practices to resolve future incidents that may arise in the offshore oil and gas operations. The investment has driven rapid advancements in science, engineering, and new technological equipment developments to establish a higher standard for SSC preparedness and readiness. The industry now has a high confidence in its ability to deal with a subsea well release. The growth in capability has led to many variations in equipment and response plans, which has led to complexity in an already highly technical field. To reduce the complexity, common understanding is required of all the actions that comprise a SSC response, the linkages and dependencies between all the actions, and the critical path items that influence the overall timeframes of regaining control of the well. With a common understanding of the response plan comes enhanced industry, regulator and community confidence in the ability of the oil and gas industry to appropriately manage its environmental and social impacts. To help with this effort, the International Association of Oil and Gas Producers (IOGP) has produced reports 592, 594 and 595. Report 594 is a guideline that can be used to support subsea source control response planning and Report 595 addresses capping stack design and operational reliability. IOGP Report 592 - Subsea Capping Response Time Model Toolkit User Guide, was completed in December 2019. It was jointly developed by IOGP and the Australian National Offshore Petroleum Safety and Environmental Authority (NOPSEMA). This report involved the creation of a digital subsea response time model that is freely available with a number of different software templates. The objective was to create a common standardized document that described the processes for preparing and implementing a subsea well blowout response in a timeline format, and in doing so, identify and communicate critical path activities, areas that can be prioritised pre-response, be easily transferrable to other parties to support mutual aid activities and, should the need arise, be used as an actual response project planning tool. This paper informs readers of these resources and explains the reasoning behind their creation.

Paradoxes of power: Dialogue as a regulatory strategy in the Norwegian oil and gas industry

This paper explores how the Petroleum Safety Authority Norway applied dialogue as a key feature in the regulatory strategy and practice over a ten-year period from 2009 to 2019. The analysis, drawing on theories on regulation and sensemaking, explores power relations and identity construction in encounters between the regulator and regulatees. The data material comprises texts from web-sites, documents, investigation reports and focus group interviews. We conclude that the dialogue is embedded with paradoxes, infused with power, yet functions as a potent policy instrument. The power base of the regulatory authorities partly depends on enterprises’ and the industry’s need for a good reputation. We expand the theoretical framework by highlighting paradoxes of power and introducing the concepts of ‘sensesharing’ and ‘conditional sensegiving’.

Deferred maintenance – a major industry challenge?

This paper identifies key areas of concern regarding the use of deferral as a maintenance management tool. As the national regulator for offshore petroleum operations and greenhouse gas storage activities, National Offshore Petroleum Safety and Environmental Management Authority is uniquely positioned to observe the various processes and tools applied by industry in the management of maintenance for offshore facilities, including impacts on safety and the environment, while acknowledging the need for business sustainability. This Extended Abstract provides a regulator’s perspective on the use of ‘maintenance deferral’ by industry as a tool for balancing competing priorities, while ensuring the risks to people and the environment are reduced to a level that is as low as reasonably practicable. It highlights the pitfalls of maintenance deferral that may negatively influence safety and environmental performance over the life of a facility (from construction through to decommissioning) as well as on the business’ bottom line. Learnings identified from non-compliances, improvement recommendations and incidents to promote efficient and effective learning are shared to further enhance existing good practices across the industry.

E&P Notes (December 2020)

E&P Notes (December 2020)

From Completion to Production Without Intervention in a Subsea Well

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30697, “From Completion to Production Without Intervention in a VXT Subsea Completed Well,” by Susanne Loen Ommundsen, Interwell, and Berit Sara Schiefloe and Olle Balstad, Equinor, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4-7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. As part of an improvement program focused on increasing standardization and efficiency on subsea well operations on the Norwegian continental shelf, the operator aimed to standardize future subsea wells using vertical trees (VXT) instead of horizontal trees. This would enable batch completion of several wells with a rig, followed by XT installation with an installation, maintenance, and repair (IMR) vessel, eliminating the need for a rig or lightweight intervention (LWI) vessel. The complete paper describes the development and implementation of a glass-plug solution that closed the technical gaps that had previously inhibited fully intervention-free operation for completion installation. Background and Field Information Trestakk is an oil and gas field in the Norwegian Sea in Block 6406/3. The field lies in 300 m of water approximately 27 km southeast of Åsgard A. Trestakk was discovered in 1986 and the plan for development and operation was approved in 2017. Equinor operates the field with 59.1% ownership interest, with Vår Energi owning the remaining 40.9%. The field development covers a subsea template with four well slots and one satellite well. A total of five wells will be drilled - three for production and two for gas injection. Production from the Trestakk subsea field on Haltenbanken in the Norwegian Sea began 16 July 2019. Trestakk is tied back to the Åsgard A floating production vessel. The Petroleum Safety Authority Norway and the Norwegian Petroleum Directorate approved the application for extending the lifetime of the installation to 2031 as a result of the additional recoverable volumes from Trestakk, for which field production is expected to last for 12 years. The goal for Trestakk was to achieve first recoverable oil at surface as soon as possible. The method selected was deployment of the completion string and VXT from a rig. The proposed solution was a barrier valve to be integrated as part of the completion string. As an operational improvement, the Trestakk team decided to design the wells with the intention of excluding wireline. Common methods for suspension and initiation of subsea wells during blowout-preventer (BOP) removal and VXT installation include installing shallow-set bridge plugs in the tubing or a tubing hanger plug. The plug is then removed using a riserless LWI vessel or rig. This method is often associated with high cost and enhanced operational risk.

An allision risk model for passing vessels and offshore oil and gas installations on the Norwegian Continental Shelf

This article presents a new risk model for estimating the probability of allision risk (the impact between a ship under way and a stationary installation) from passing vessels on the Norwegian Continental Shelf (NCS). Offshore petroleum operators on the NCS are required by the Norwegian Petroleum Safety Authority (PSA) to perform risk assessments to estimate the probability of impacts between ships and offshore installations, both for field related and passing (merchant) vessels. This has typically been done using the aging industry standard COLLIDE risk model, but this article presents a new risk model based on a Bayesian Belief Network (BBN) that can replace the old COLLIDE model for passing vessels. The new risk model incorporates a wider range of risk influencing factors (RIFs) and enables a holistic and detailed analysis of risk factors, barrier elements and dependencies. Even though the risk of allision with passing vessels is very small, the potential consequences can be critical. The new risk model is more transparent and provides a better understanding of the mechanisms behind allision risk calculations. The results from the new model are aligned with industry expectations, indicating an overall satisfactory performance. The article discusses several key elements, such as the use of expert judgement to estimate RIFs when no empirical data is available, model sensitivity, and a comparative assessment of the new risk model to the old COLLIDE model.