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Nair, Aravind (DNV GL) | Jaiswal, Vivek (DNV GL) | Fyrileiv, Olav (DNV GL) | Vedeld, Knut (DNV GL) | Zheng, Haining (ExxonMobil) | Huang, Jerry (ExxonMobil) | Tognarelli, Michael (BP) | Goes, Rafael (Petrobras) | Bruschi, Roberto (Saipem) | Bartolini, Lorenzo (Saipem) | Vitali, Luigio (Saipem)
To date, there are no publicly available, validated tools or industry accepted guidelines for the assessment of Vortex-Induced Vibration (VIV) fatigue of rigid Jumper (spool) systems. The existing state of practice has been to treat rigid jumper systems as free spanning pipelines and apply the associated design principles in DNV GL recommended practice DNV-RP-F105/DNVGL-RP-F105 (Free Spanning Pipelines). However, widely used rigid jumper systems such as the M-shape jumper systems are subjected to complex flow fields around their legs and bends and fall outside of the test data used to generate the free-span response model in DNV GL Recommended Practice (RP). A Joint Industry Project (JIP) ‘Jumper VIV JIP’ that included BP, ExxonMobil, Petrobras, Saipem and DNV GL was conducted between Dec. of 2014-2016 to collectively tackle the technical issues related to the VIV design of rigid jumper systems.
Through the JIP study, measured responses from ExxonMobil's jumper tow test data were used to develop new response curves for jumper systems in pure-current condition. Curves for in-line and cross-flow responses were initially developed by classifying the measured responses into in-line or cross-flow directions and compared against the existing DNVGL-RP-F105 response curves. Due to potential ambiguity in classification and application to Jumper Design, a more general curve that does not rely on directional classification has also been generated. Due to the differences in behavior of rigid jumper systems to that of free spanning pipelines, a new VIV guidance report was developed as part of the JIP deliverable. Principles and philosophies in the DNV-RP-F105 were followed in the development, but with the intent of identifying unique behavior of jumper systems for a subsequent update of the RP.
This paper presents the Guidance notes from the JIP and forms the first release of Jumper VIV fatigue assessment approach to the Industry. ExxonMobil's model test data, the only known test data available in the industry, was used in the development of unique response model and the new design guidance. The paper includes the new response model along with VIV screening, safety factors and unique considerations required for fatigue assessment of jumper systems.
Mooring line tension monitoring is required for permanently moored floating offshore platforms by some regional regulators and classification societies. This requirement is typically satisfied by installing physical sensors that directly measure the line tension. Experience shows these sensors have relatively short life compared to the platform operational life and consequently they need to be changed several times thereby increasing the operational expenses. It is also possible that changing the sensors in the field may not be feasible due to access and safety issues or it may be prohibitively expensive, which could lead to the platform operating without meeting the regulations.
This paper presents a machine learning based model, which we call ‘virtual sensor’, for predicting the mooring line tensions based on the platform’s heading, horizontal position and six-degrees-of-freedom (6-dof) rigid body motions. The model’s development and testing are demonstrated with the help of data generated through numerical simulations of a permanently moored semi-submersible. When deployed in field, the inputs to the virtual sensor would be obtained from the global position system (GPS) and accelerometers. Both the GPS and accelerometer are cheaper to install and maintain, reliable and easy to replace.
The neural network model is pre-trained using a dataset of 5000 static simulations and further fine-tuned with 48 dynamic simulation cases. Model performance on four mooring lines are presented in the study. The accuracy of the model was assessed by determining the percentage of predictions with errors within ±5% of the simulated mooring line tensions. Three of the mooring lines achieved accuracy greater than 90% and one mooring line achieved 77% accuracy. The relevant limitations of the study and future work are discussed in the paper.
Offshore industry assets are capital intensive and downtime can have severe financial consequences. Additive manufacturing (AM) based supply chains can potentially offer offshore industry stakeholders a strong value and a competitive advantage, from lower costs and lead times to greater flexibility and agility. However, the current adoption level of AM for the offshore industry is very limited, despite the consensus that such technology could have potential applications for spare parts, repair and even new builds. While adoption of additive manufacturing could be a source of positive change, inadequate understanding of requirements regarding approval, qualification and certification processes required by regulatory authorities could hinder the progress of AM adoption in the offshore industry. Currently, there are only a handful of additive manufacturing standards available for early adopters of AM technology. Hence, costly and time-consuming nonstandard testing to ensure the integrity of the 3D printed parts is deterring the wider applications of additive manufacturing in the offshore sector, underscoring the need to develop optimal practice guidelines and standards from design to part build to operation. This paper aims to highlight several key challenges that hinder the adoption of AM in the offshore sector and to propose various solutions that can help to overcome these.
In-service inspection plays a critical role in the integrity management of mooring systems of floating production and drilling units, as mooring failures have been a big issue in the offshore industry in recent years. Inconveniently or unfortunately, these offshore mooring systems cannot be easily inspected. Best inspection practices are needed, as they can potentially prevent mooring incidents or pre-emptive replacements caused by degradation mechanisms, such as fatigue and corrosion. Other than the limited guidance provided in API RP-2I through its revision in 2008, there is not much information available on where, what, and how to inspect chain, wire ropes, polyester ropes, and connectors in an offshore mooring system. This paper elaborates on some best practices and recommendations regarding in-service mooring inspection that were learned from field experience and collected data. A documentation of best inspection practices may prove itself useful for operators, contractors, classification societies, and regulatory agencies. Not only may such documentation improve the integrity and reliability of mooring systems, it can also make inspection practices more efficient and effective.
In the North Sea, hydrocarbon release (HCR) from offshore topside piping that is inherently degrading because of vibration-induced fatigue (VIF) has been a significant challenge. This challenge is further exacerbated when the operating assets are located in Arctic environments, especially because of higher temperature gradients and other operational challenges. The result is a significant increase of VIF failure of topside piping, which causes a higher risk of potential HCR in Arctic environments. The “zero oil spill” requirement in the Arctic region requires operators to follow stringent guidelines to mitigate the risk of VIF failure of topside piping. In this regard, this paper demonstrates the application of the Bayesian network (BN) for risk-based fatigue integrity assessment of the topside piping. The value of the calculated risk depends upon the values of likelihood of failure (LoF) and consequence of failure (CoF). The value of LoF in turn depends upon the measured vibrational velocity (coupled with the vibration assessment criteria of the Energy Institute guidelines) and probabilistically estimated remnant fatigue life (RFL) of topside piping. Likewise, the CoF has been assessed from safety, environmental, and business perspectives. The BNs have been modelled using GeNIe and have been utilized to estimate the risk. The outcome of the fatigue integrity assessment using the proposed approach is the categorization of piping into various risk groupings. Piping in the high-risk category is thereby prioritized for inspection, thus preventing HCR in the fragile Arctic region. An illustrative case study, demonstrating the usability of the proposed approach, is presented.
The rapid growth in demand for hydrocarbons and the decline of production in existing fields have induced the petroleum industry to extend their exploration and production activities to the Arctic regions (Basel et al., 2008; Hasle et al., 2009). The U.S. Geological Survey finds that the Arctic region holds approximately 22% of the world’s undiscovered conventional oil and natural gas resource base, approximately 30% of the world’s undiscovered natural gas resources, approximately 13% of the world’s undiscovered oil resources, and approximately 20% of the world’s natural gas liquid (NGL) resources (Gautier et al., 2009). However, Artic petroleum operations have undergone quite stringent regulatory requirements, due to higher environmental sensitivity (Regjeringen, 2014). Hence, the exploitation of the Arctic reserves depends on the level of technology, as well as assessment and control readiness levels at the design, construction, and operational (i.e., inspection, maintenance, and modification) phases. For instance, compared to non-Artic regions, these regions have higher temperature gradients and increased susceptibility to brittle fracture of metals, human factors, etc. (Basel et al., 2008; Ratnayake, 2017). Hence, it is vital to develop effective methodologies to assess the risk of potential failures.
Over the last few decades, there have been a significant number of accidents on crude oil tankers, floating production storage and offloading (FPSO) and offshore units due to fire and explosion, which have resulted in loss of lives, assets, and environmental damage. These incidents increase scrutiny and questions on the current level of safety design in hydrocarbon handling spaces and other high-risk spaces in oil tankers and FPSOs. There are many factors which may contribute to these incidents, including; defects of equipment and components, overlook during design, inappropriate maintenance procedure and history, improper workmanship, and lack of company safety procedures and instruction during maintenance and emergency responses. This study is focused on and has discussed all safety aspects and barriers for the enclosed cargo-handling spaces in tankers and offshore units. Various existing regulations, standards, and guidelines have addressed safety design of enclosed cargo-handling spaces. These requirements and guidelines are referred and investigated to identify typical industry gaps in design and to recommend best engineering practices. The proposed key design recommendations may be considered at the early design stage of new building or conversion projects to enhance the overall safety and to reduce the likelihood of critical safety events.
The offshore and marine industry face many inherent risks such as failure of equipment and structural integrity, collision, grounding, dropped objects, leakages, fire and explosions. Because of the constant transfer and handling of hydrocarbons in operational profile, oil tankers and floating production storage and offloading (FPSO) units have significant potential fire and explosion risks unless sound safety barriers are considered throughout all phases of the design and the construction. Often a FPSO conversion project, which uses an ageing crude oil tanker, is the preferred choice to provide a functioning FPSO facility to the offshore oil production market in timely manner. When compared with newbuilding FPSOs, a conversion project can provide shorter construction schedule and cost reduction benefits. Considerable number of FPSOs operating in the market apply a conversion-type approach, using existing oil tankers to convert to FPSOs. In a FPSO conversion project, the existing cargo pump room is used for the hydrocarbon cargo handling, transfer and offloading operations. The use of the conventional cargo pump room configuration in newly operating FPSOs has come under scrutiny compared with newbuilding projects, which typically install independent cargo pumps, such as a submergible or deepwell type, within each tank which minimizes the risk of hydrocarbon leaks to other confined spaces. The conventional pump room configuration has always presented high risks and concerns due to confined spaces, many potential leak sources, hydrocarbon handling equipment and piping, where leaks can build an explosive environment easily, and the location is situated near the safety critical areas such as accommodation, engine room, and control spaces.
An increasing number of Brazilian floating platform units are currently entering a mature age, inducing numerous asset integrity issues. As corrosion damages FPSOs’ hull structures and outfitting, repairs and/or modifications have to be performed in explosive environment. Those features create important operational challenges, both in terms of safety and production continuity, when hot work techniques are to be used. This is the reason why Cold Pad has developed a cold work technique based on a heavy duty, bonded, mechanical fastener called C-CLAW™. On FPSOs, this novel solution allows today to repair primarily corroded outfitting like handrails, pipe supports, cable trays, electrical boxes and the like. Cold Pad and DNV GL are working together on a design philosophy, a regulatory approach, and a validation programme based on the DNVGL-ST-C501 and the so-called load and resistance factor design (LRFD) format. The article focuses on the application of the regulatory approach for the demonstration of the capacity and reliability of these fasteners. The strength of the bondline and steel fastener components, with their multiple failure mechanisms, are addressed and mainly supported by short-term test results.
The article details the main challenges of that new design approach throughout the service life of bonded fasteners, and includes results and findings related to e.g. strength, susceptibility to temperature, and allowable short-term mechanical capacities based on regulatory safety factors. It also provides the early conclusions in terms of application on FPSOs and recommendations regarding fire hazards. The novelty of these bonded mechanical fastener lies, firstly in the industrial product itself, and secondly in the application of one of the most recognized offshore standards for composite components to derive its regulatory mechanical rated capacity.
A new method developed to evaluate the performance measure of some sub-criteria of the environmental criterion in a Comparative Assessment of various options of the decommissioning of subsea installations in Brazil is presented. The method is based on an adaptation of that proposed by IBAMA in Technical Note N°. 10/2012 (TN 10) used for assessment of environmental impacts required for the licensing of offshore activities in Brazil. By requirement of the Comparative Assessment methodology, there is a need for a numerical evaluation that allows comparing the performance of one alternative over the others. An analytical method was developed based on the combination of environmental attributes that contribute for the magnitude of the impacts (frequency, intensity, extension and duration) and sensitivity of the environmental factors affected (relevance, resilience and reversibility). The importance of the impacts is given by the combination of the environmental sensitivity with the magnitude of the impacts, in the called "Environmental Impact Importance Score Matrix". The proposed method provides a performance measure that allows comparing and prioritizing each decommissioning option according to the proposed criteria. It reduces the subjectivity in assessing the importance of the environmental impacts and provides greater transparency and traceability in the assessment of the impacts. As an example, the proposed method is applied for the decommissioning of a rigid pipeline between two platforms in Campos Basin, where the considered decommissioning options are: (a) complete removal by cut and lift and (b) leave in situ. For this particular case, the assessment of the proposed environmental sub-criteria revealed that Option (b) was the preferred option with respect to the impacts on marine and onshore environment.
Risk Assessments are used to assess the impact of alternativedesigns, changes during operations, and compliance of offshore installations against tolerabilitycriteria. Typically, asset information is used to develop a mathematical model; this can beupdated to reflect changes during the facility's lifecycle. This paper examines how the use ofcloud-based technology to develop a Digital Twin improves efficiency. Allowing projectstakeholders full access to the QRA model also enables greater understanding of hazards.
Digital technology pervades all areas of business and societyand offers great advantages to safety engineering relative to traditional approaches. This paperdemonstrates how cloud basedtools canturn the traditional static QRA process into a living QRA which can be updated throughout aninstallation's lifecycle by creating a digital twin. This type of living QRA allows projectstakeholders to change key parameters and assess the effect of these changes on risk levels. Inaddition, the results can be interrogated down to fundamental levels using a Microsoft Power BIdashboard.
The output of QRAs are usually static reports providing anoverview of the detailed work undertaken and a high-level summary of the results which arecompared with tolerability criteria or to demonstrate ALARP. This paper demonstrates howcustomised internet browser tools utilising 2D and 3D graphics may be built on top of the QRA toextract more detail than previously possible and communicate risks in a flexible and interactiveway. It also shows how consistent data management can form a basis for innovating beyond thetraditional approach. This allows a wider range of stakeholders to determine risk drivers, isolatesingle accident scenarios and filter results to a greater depth than is possible through a paperreport and allow a greater understanding of their hazards.
Digitalisation is an increasingly ‘hot topic’ in the process industry. Making use of new technologies to provide greater insights can aid in better and more timelyhazard management whilst reducing costs to stakeholders. Examples of innovations which promote better assessment are provided.
The Health and Safety Executive's analysis shows poor hazard identification and risk analysis is a causal factor in 12 out of 14 recent major hydrocarbon releases, demonstrating that major accidents could be prevented if workers had a better understanding of major accident hazards (MAHs). Therefore, it is proposed that improving awareness of MAHs across the workforce, both onshore and offshore, would lead to better MAH management and a reduction in major accidents.
Once the domain of process engineers, major accident hazard management has been largely overlooked by much of industry. It was acknowledged as a problem but ignored in the hope that specialists had it under control.
Step Change in Safety's Major Accident Hazard Understanding workgroup responded to this by identifying different job roles (onshore and offshore), evaluating the resources to develop MAH understanding already available and creating a suite of resources to fill the gaps.
These resources include an e-learning tool for onshore (office-based) personnel, bowtie lunch and learn sessions, gap analysis tools to identify training requirements of offshore jobs, senior leaders' workshops and a MAH Awareness programme. The MAH Awareness programme, consisting of short films and presentations which can be customised to suit specific worksites and job roles. Each of the four packs explores different aspects of major accident management including MAH identification and analysis, bowties and safety and environmental critical elements, barrier maintenance, assurance and verification and the importance of taking responsibility of ‘owning’ your barrier.
Analysis of questionnaires completed before and after exposure to the programme demonstrates that knowledge of MAH management increased by approximately 30%. Additionally, the data demonstrates that elected safety representatives have a greater base knowledge of MAHs than the general offshore workforce, as do technical staff compared to non-technical and those employed by operators compared to contractor employees.
Whether this increased knowledge gained through taking part in the MAH Awareness programme is retained or impacts the number of major accidents has not yet been analysed but data such as the number of major accidents, including hydrocarbon releases, will be examined over forthcoming years to evaluate the effectiveness of the resources developed.