Evolving accident scenario modelling in complex processing facilities

Prelude Floating Liquefied Natural Gas (FLNG) facility reached a significant milestone in June 2018 when gas was introduced onboard for the first time as part of the facility startup process, loaded from an LNG carrier moored in side-by-side (SBS) configuration. This first offshore LNG SBS operation allowed Prelude’s utilities to switch from running on diesel to running on gas. SBS mooring is the base case configuration for of floading both LNG and Liquefied Petroleum Gas (LPG) into product carriers using Marine Loading Arms (MLA) once the Prelude FLNG facility is fully operational. These complex and weather sensitive operations are expected to take place on a weekly basis. This means critical decisions about weather-window and timing should be supported as much as possible by predictive analysis and modelling of environment forecasts to reduce the risks. Prelude Floating Liquefied Natural Gas (FLNG) is designed to offload Liquefied Natural Gas (LNG) and Liquefied Petroleum Gas (LPG) to carrier vessels moored in a side-by-side (SBS) configuration, using Marine Loading Arms (MLA) technology. For onshore terminals or small/medium FLNG, the traditional design of MLA (Double Counterweight Marine Arm – DCMA), featuring a vertical riser, can be used. However due to the exceptional freeboard of Prelude a new type of MLA was designed, namely the Offshore Loading Arm Footless (OLAF), without vertical riser in order to reach the LNG or LPG manifolds located as far as about 16 meters below the MLA base. Thanks to the OLAF design, the length and weight of the articulated MLA sections is reduced in comparison with conventional DCMA, and so are the dynamic loads applied by the MLA on the vessel manifold, which was mandatory to remain below the acceptable stress limit of standard LNG/LPG carrier manifolds. OLAF employs the field proven targeting system (TS) allowing the connection and disconnection of the MLA to the vessel manifold in dynamic conditions. This paper describes the assumptions and process to design and validate this new system — in terms of overall geometry and structural design, while verifying project feasibility, aiming at a reliable design of all components and minimizing the risks during operations. The key challenges and lessons learnt are also discussed. This innovative type of MLA had to be thoroughly designed and tested before being manufactured and assembled on the FLNG. The innovation management was also coupled with the additional challenge imposed by the expected highly dynamic conditions of relative motion between vessels that were never encountered for such systems in the past. MLA were designed with the objective to cover the operable envelope induced by berthing, mooring and relative motion criteria, so that it should not become an additional criterion in general. Since such an envelope is larger for this offshore application compared to sheltered terminals, this objective was particularly challenging but could be met thanks to the OLAF design. The SBS hydrodynamic numerical model is based on potential theory and includes multi-body coupling, non-linear mooring characteristics and coupling with sloshing. This model was calibrated using wave basin tests with a good agreement, and was used to determine the maximum operable environments and associated MLA envelope, using a 39-year hindcast for various LNG carriers and considering a scenario with different criteria and loading conditions. More than 100,000 time-domain simulations were required to evaluate non-linear quantities on a reduced set of environment ‘bins’. The new OLAF-type MLA was developed using these hydrodynamic simulations. Specific processes — based on spectral screening and selection using relevant criteria — were used to identify and select, in a systematic way, the designing load cases for connecting, connected, and emergency disconnection cases, while complying with the maximum allowable loads of conventional LNG and LPG carrier manifolds. An instrumented 1:4 OLAF scale model was built and tested with 6 degrees of freedom hexapods reproducing the motions on both sides of the OLAF which enabled us to confirm a 10% accuracy of the numerical studies results. The actual OLAF were dynamically tested with a full scale motion simulator before shipment to the yard for installation. The successful first operations were performed safely and confirmed the validity of the design. Measurements are now collected onboard Prelude to verify the design and when possible improve the accuracy of numerical modelling.

Global carbon emissions are driving the maritime industry toward cleaner fuels, with LNG already established as a transitional option that reduces SOx, NOx, and particulate emissions relative to conventional marine fuels and in line with decarbonisation strategies. This research aimed to explore the transition of offshore and marine platforms from conventional marine fuels to cleaner alternatives, with liquefied natural gas (LNG) emerging as the principal transitional fuel. Subsequently, floating liquefied natural gas (FLNG) platforms are increasingly being deployed to harness offshore gas resources, yet they face critical challenges related to weight, space, and energy efficiency. The study proposes pathways for transitioning FLNG energy systems from LNG to zero-carbon fuels, such as hydrogen derived directly from LNG resources, to optimise fuel supply under the unique operational constraints of FLNG units. The work unifies the independent domains of pure-fuel and blending-fuel processes for LNG and hydrogen, viewed in the context of thermodynamic processes, to optimise hydrogen–LNG co-firing gas turbine performance and meet the base power line of 50 MW. Furthermore, the research article will contribute to the development of other floating production platforms, such as FPSOs and FSRUs. It will be committed to clean energy policies that mandate support for green alternatives to hydrocarbon fuels.

This article deals with the development of a numerical tool based on an integrated synthesis model to carry out the first project cycle of floating liquefied natural gas (FLNG) platforms to produce, process, store, and export liquefied natural gas (LNG). The topside configuration, tank geometry and capacity, production levels, equipment list, environmental and operating conditions, classification society requirements, structure, stability, and seakeeping are considered in a single synthesis model, generating a sufficiently large number of solutions. The case generation and the evaluation process are performed hierarchically, dividing the parameters into groups to better solve the solution space, which cannot be achieved with conventional techniques such as traditional point-based design. This methodology is applied as a case study to design three FLNG platforms with different production levels (2, 3, and 4 million metric tons per year). Performance parameters are defined and evaluated, optimizing downtime, structural mass, and load capacity. The resulting platforms are compared to existing FLNG dimensions. Essential conclusions are drawn about design improvements, such as key dimensions, quantity, and configuration of tanks, freeboard specifications, and operating draft. The developed synthesis framework proved to be a quick and useful tool for the early stages of the FLNG project.

During 2022, Mozambique successfully joined the list of Liquefied Natural Gas (LNG) producing countries with the launch of a Floating Liquefied Natural Gas (FLNG) development project. It consists of six deep-water development wells targeting a giant gas reservoir and feeding one FLNG unit with a nominal capacity of 3.4 MTPA of LNG production. The aim of this work is to share the subsurface work that has been performed to support the start-up operations, including real-time well monitoring and interesting reservoir insights. The wells real-time monitoring was made possible thanks to the Eni Digital Oil Field (e-dof™) system, which allowed reservoir teams in Mozambique and Italy to access real-time data and efficiently follow-up offshore operations. During the start-up of the FLNG, the Inflow Performance Relationship (IPR) of each well over time was monitored by performing frequent Multi-Rate (MR) tests at the test separator, acquiring robust data for comparison with the Wet Gas Flow Meter (WGFM) installed in every well and the Real Time Virtual Flowing Metering (RTVFM), an online, in-house tool for real-time production estimation. Additionally, every build-up is being analyzed using Pressure Transient Analysis (PTA) to confirm reservoir properties and well damage. High-resolution bottomhole pressure gauges were also monitored to detect any dynamic interference within the wells and conduct Rate Transient Analysis (RTA), a powerful tool for flow regimes identification and contacted Gas Initially In Place (GIIP) estimation. The reservoir is being efficiently monitored with the above-described workflow, confirming that wells deliverability meets production targets, and achieving optimum reservoir management of the field during start-up operations. In this framework, the e-dof™ system in place has allowed to close the spatial gap within the offshore operators and the working teams in Mozambique and in Italy. Additionally, the study of wells dynamic interactions, coupled with standard and flowing material balance methods, made possible to infer about reservoir hydraulic communication and estimating the contacted GIIP. These estimates were found to be consistent with the 3D reservoir model, confirming its representativeness for long-term production forecasts. Besides, the RTVFM, characterized by high reliability and integration within the e-dof™ system, proved to be a cost-effective solution to introduce measurement redundancy in the system, acting as a back-up of the WGFMs and avoiding the need for eventual expensive offshore interventions. In this work, it is described how the start-up of Eni's first FLNG development in Mozambique is being managed from a reservoir perspective, using the most cutting-edge tools to guide the analysis and most importantly the real-time data availability thanks to the e-dof™ system in place. The integration of the deployed tools, which are being continuously improved, produced exciting achievements and interesting results, whose uncertainty will be reduced as more data will become available.

Topological Network Inversion Method of Fire Source Location for Liquefied Natural Gas (LNG) Storage

The conflict over the proposed LNG hub in Western Australia’s Kimberley region and the politics of time

Experimental study on responsiveness of multi-spectrum infrared flame detectors to diffuse flames partially hidden by obstacles installed in oil and gas processing facilities

Floating liquefied natural gas (FLNG) cryogenic hoses can be employed for the transmission of liquefied natural gas (LNG). Usually, U-shaped metal bellows can be applied as the inner lining of FLNG cryogenic hoses. In installation, positioning and other working conditions, torsion is one of the main loads, and torsional buckling instability is a major failure mode of U-shaped metal bellows of FLNG cryogenic hoses. In the current research, the buckling instability of bellows under torsional loads has been investigated in detail, the mechanical mechanism of deformation in torsional buckling mode of bellows has been analyzed and the influence of the structural design parameters on the stability performance has been summarized. It was seen that the axis of the bellows was presented as a spiral line shape during the torsional buckling stage. At the same time, the torsional buckling properties of toroid and spiral bellows were analyzed. The obtained results showed that the torsional buckling stability of the spiral bellows was weaker than that of the toroid bellows and increase of the spiral angle of the spiral bellows intensified this trend. In addition, the post-buckling analysis of U-shaped bellows under torsional loads was carried out by means of experiments and finite element simulation. It was shown that the results obtained from finite element (FE) analysis in this research presented a relatively accurate critical torque value and a consistent buckling instability mode, compared with the experimental results. On this basis, the effects of common defects such as thickness thinning on the torsional stability of bellows were investigated. Considering the geometric defect of thickness thinning, the error of FE analysis was reduced further, and it was found that the defect could significantly decrease the stability of the bellows. The above analysis results could provide a reference for structural design and post-buckling analysis of bellows.

More than 50 new Liquefied Natural Gas (LNG) importterminals are currently proposed for North America. Each of these developments will face the challenges of risk management and public risk perception. They are all dependent on support from local elected leadership and on a plan and ability to manage public communication. Failure to address these issues may cause rejected developments, lost opportunities and significant non-return costs. The questions of facility safety and security are raised as stakeholders and interest groups ask ‘what if’ questions regarding possible accident scenarios, such as ‘What is the maximum hazard area if a storage tank collapses, a LNG carrier is penetrated, or an offloading accident occurs?’ The questions are often characterized by misconceptions, but are nevertheless of vital importance. In order to answer thesequestions, safety and security aspects of LNG transport, storage and re-gasification must be communicated appropriately. How can the facility be perceived as ‘safe’ given the severity of the worst possible consequences from major accidents? Safety can be assured and enforced through compliance with a pre-defined set of risk acceptance criteria. These criteria can be absolute and tangible, or they may be more abstract. Different practices are accepted in different regions, countries, and states, as well as in different industry segments. Ideally, risk acceptance criteria should be regulated by authorities. This provides non-biased definition of safety and can remove safety as the alibi to oppose industrial developments. The debate can then focus on the real drivers for opposition such as deteriorated property values, deterioration of aesthetics and restrictions of pleasure craft activities in waterways also used by LNG carriers. Developers may use compliance with internationally recognized risk acceptance criteria if not enforced by regulators. It can be helpful in communication with stakeholders and gives credibility to safety documentation. Documentation of compliance with risk acceptance criteria provides answers to ‘How can I be safe without zero risk?’ Introduction North America is facing an increasing demand for natural gas; however, the domestic natural gas supply is decreasing. It is predicted that the United States will face a natural gas supply gap of about 5 trillion cubic feet by 2020 [1]. Therefore, the need for imports of LNG will continue to increase. In addition, the profitability and relatively low potential environmental impact from LNG will spur many projects over the next several years. Safety and security issues are brought to the fore when these projects are proposed. How should the risk associated with existing and proposed projects be presented to and perceived by the public? Stakeholders, including facility owners, public, and regulatory agencies, often have different points of view concerning LNG risk. The decision-making process concerning the projects becomes challenging when conflicts exist between the different parties. What risks are acceptable for the public? This paper will address the issue of risk acceptance criteria associated with LNG facilities.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23615, ’Floating CNG: A Simpler Way To Monetize Offshore Gas,’ by David Stenning, SPE, John Fitzpatrick, and Mark Trebble, Sea NG, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed. Monetizing offshore gas by compressing and shipping it in floating compressed-natural-gas (FCNG) carriers is simpler and, in most cases, less expensive than liquefying and shipping it in floating liquefied-natural-gas (FLNG) carriers. Seaborne compressed-natural-gas (CNG) transport requires essentially the same infrastructure as pipeline export, except that the gas is compressed into a ship rather than a pipeline. FCNG provides a new way to add to the world’s natural-gas supply by allowing smaller offshore gas fields to be exploited economically. Introduction Many offshore gas fields are too small or too remote to produce by pipeline to shore. The liquefied-natural-gas (LNG) industry has advanced to fill the need with respect to larger gas fields by creating an FLNG production concept where an LNG processing and refrigeration plant, complete with LNG storage, is integrated into a ship or barge and moored at a gas field. LNG ships are then used to offtake the LNG and deliver it to markets, where it is stored and regasified as needed. A simpler and less expensive way to produce gas from many fields is to avoid liquefaction altogether and instead compress the gas into CNG ships, which then deliver it to regional markets. Virtually all floating production, storage, and offloading (FPSO) ships in operation today treat and compress natural gas, either to reinject associated gas or to export it by pipeline. This is the same technology required to produce CNG offshore. CNG vs. LNG To transport natural gas efficiently, its density must be increased. The principal way to achieve this is by decreasing temperature or increasing pressure. Decreasing the temperature to −162°C causes it to condense to a liquid at ambient pressure and results in a volume ratio of 600:1. Compressing the gas to 275 bar at ambient temperature squeezes the gas to a dense gaseous phase with a volume ratio of 300:1. For many projects, CNG is a lower cost solution. In the past, no CNG ships were developed or approved, so this more-economical CNG solution was ignored. A decade of work on the regulations, engineering, and full-scale fatigue testing has paved the way for the first commercial CNG ships. FCNG: A Shuttle Tanker Operation An FCNG production vessel is a traditional gas floating production and offloading (FPO) unit with a high-pressure gas transfer system to load Coselle CNG shuttle ships instead of a subsea pipeline. CNG is transferred at near-ambient temperatures, so the hoses and transfer systems are the same as those used to transfer high-pressure gas and well fluids onto an FPO unit.

Liquefied natural gas (LNG) terminals, one of the lifeline facilities, need to be protected by a proper seismic design against extreme earthquakes. An LNG terminal consists of a series of process facilities that are connected by pipelines of various sizes. Boil-off gas (BOG) compressor is one of the critical process facilities whose failure will cause the functional failure of the LNG terminal. Process facilities, including BOG compressor, other than LNG storage tanks and pipes, have not been a major concern in terms of the seismic performance evaluation. In this study, the seismic performance of a BOG compressor is evaluated and the seismic fragility functions are presented. An integrated system of a BOG compressor is modeled by a 3 dimensional finite element modeling scheme. A series of time history analyses are conducted to monitor the behavior of anchor bolts, one of the most critical elements in the BOG compressor. To develop fragility curves, a set of 20 ground motions are selected from a database of the historic earthquake accelerations. Fragility curves are developed based on the maximum likelihood estimation approach with respect to the strength limit states. When an earthquake load is applied to the BOG compressor, the main motor is likely to overturn and the flywheel is likely to slide, and, consequently, anchor bolts will be subjected to tension and shear force, respectively. It is concluded that the BOG compressor is safe against the design level earthquake

Background.Storage tanks in oil and gas processing facilities contain large volumes of flammable compounds. Once the fuel-air mixture is ignited, it may break out into a large fire or explosion. The growing interest in monitoring air quality and assessing health risks makes the evaluation of the consequences of a fire an important issue. Atmospheric dispersion models, which allow for simulation of the spatial distribution of pollutants, represent an increasingly widespread tool for this type of evaluations.Objectives.The present study discusses the set up and results of a modeling study relevant to a hypothesized fire in an oil refinery.Methods.After choosing the most suitable dispersion models, i.e. the Lagrangian model SPRAY and the puff model CALPUFF, estimation of the required input data is discussed, focusing on the source variables, which represent the most uncertain input data. The results of the simulations were compared to regulatory limits to effectively evaluate the environmental consequences. Finally, a sensitivity analysis was employed to identify the most influential variables.Results.The simulation results revealed that ground concentration values were far below the cited long-term limits. However, the most interesting outcome is that depending on the dispersion model and the source type modeled, different results may be obtained. In addition, the sensitivity study indicates that the source area is the most critical variable, since it determines a significantly different behavior depending on the modeled source types, producing, in some cases, variability in the pollutant ground concentrations on selected receptors up to +/− 60%.Conclusions.Depending on the selected model and the algorithms available to describe the physics of emission, the results showed a different sensitivity to the input variables. Although this can be explained from a mathematical point of view, the problem remains of choosing case by case the option that best approximates the real behavior of the incidental source under investigation.Competing Interests.The authors declare no competing financial interests.

Gas leak detection in oil and gas processing facilities is a critical component of the safety production monitoring system. Non-contact detection technology based on infrared imaging has emerged as a vital real-time monitoring method due to its rapid response and extensive coverage. However, existing pixel-level segmentation networks face challenges such as insufficient segmentation accuracy, rough gas edges, and jagged boundaries. To address these issues, this study proposes a novel pixel-level segmentation network training framework based on anchor box annotation and enhances the segmentation performance of the YOLOv8-seg network for gas detection applications. First, a dynamic threshold is introduced using the Visual Background Extractor (ViBe) method, which, in combination with the YOLOv8-det network, generates binary masks to serve as training masks. Next, a segmentation head architecture is designed, incorporating dynamic kernels and multi-branch collaboration. This architecture utilizes feature concatenation under deformable convolution and attention mechanisms to replace parts of the original segmentation head, thereby enhancing the extraction of detailed gas features and reducing dependency on anchor boxes during segmentation. Finally, a joint Dice-BCE (Binary Cross-Entropy) loss, weighted by ViBe-CRF (Conditional Random Fields) confidence, is employed to replace the original Seg_loss. This effectively reduces roughness and jaggedness at gas edges, significantly improving segmentation accuracy. Experimental results indicate that the improved network achieves a 6.4% increase in F1 score and a 7.6% improvement in the mIoU (mean Intersection over Union) metric. This advancement provides a new, real-time, and efficient detection algorithm for infrared imaging of gas leaks in oil and gas processing facilities. Furthermore, it introduces a low-cost weakly supervised learning approach for training pixel-level segmentation networks.

PurposeThis study aims to investigate the risk factors in construction projects in oil and gas processing facilities in Yemen and serves as a case study for developing countries.Design/methodology/approachBy using a questionnaire, data were collected from 201 project managers and engineers employed in different sectors in the oil and gas industry in Yemen.FindingsThe survey analysis based on Kruskal–Wallis test method shows a high degree of agreement on the perceptions of risk factors depending on categories of companies. In other words, the tested risk factors exist in all sectors of oil companies in Yemen and are valid as a measure of risk factors in construction projects in oil and gas organizations in general. Although no evidence suggests that the risk factors differ significantly according to job title, the result of identifiable risk factors according to experience shows a statistically significant difference among participants in terms of their experience. The relative importance of the ranking of risk factors was obtained by the statistical analysis of responses on the impact and likelihood of occurrence of these risks. Findings show that internal risks are the greatest influential factors in construction projects in the oil and gas sector, followed by changes during construction project, government instability, incorrect project cost estimation, government delay in decision making, incorrect project schedule estimation, and political situation and war in the country.Originality/valueThese findings are valuable to organizations that are planning to conduct construction projects for oil and gas processing facilities in Yemen and other nations with similar environments, such as developing countries.

Introduction When Texaco Canada Resources Ltd. opened the $40 million addition to its Bonnie Glen gas processing facHities in June 1982, the three-plant complex located 80 km southwest of Edmonton, became one of Canada's largest natural gas liquids producers. The new Bonnie Glen Solution Plant No.2 can handle 1.4 million cubic metres of gas a day, including a 2780 cubic metre a day fractionation train. The new solution gas processing plant was completed on time and on budget under an engineering, procurement and construction turnkey contract. The Oilfields Texaco's Bonnie Glen complex serves two of Canada's most prolific oilfields, Wizard Lake and Bonnie Glen, discovered within a year of each other in the early 1950s. The Wizard Lake oilfield, about 11 km north of the Bonnie Glen Gas Plant, has an original oil-in-place of 61.2 million cubic metres and has been under pressure maintenance since 1969. The Wizard Lake Miscible Flood is one of the largest and most successful enhanced recovery projects of its type in the world. The project increased the field's recoverable oil by 11 million cubic metres to an estimated 84% of the original oil-in-place. Over the years, some 4.4 million cubic metres of LPG solvent has been injected into its miscible slug. The field, 100% owned by Texaco, can produce up to 8700 cubic metres of oil per day. The Bonnie Glen find differed from Wizard Lake because it had an original primary gas cap overlying the 119 million cubic metres of oil-in-place. This pool, 74% Texaco owned, is not under pressure maintenance. However, ultimate recovery is still expected to be 71% of the original oil-in-place with a production capability of 1300 cubic metres a day. In 1975, the gas cap was unitized and a cycling scheme was brought on-line which has successfully minimized retrograde losses and improved ultimate pool recovery by 4.3 million cubic metres. The Processing Complex The Bonnie Glen gas processing complex today includes three facilities: two solution gas plants, Nos. 1 and 2, each with a 1.4 million cubic-metre-a-day capacity and a cycle plant which has a 3.9 million cubic-metre-a-day capacity to extract natural gas liquids as part of the gas cap cycling project (Fig. 1). The original Bonnie Glen Solution Plant No. 1 came into operation in 1954 with the capacity to handle 790 000 cubic metres of gas a day. It was one of the first gas plants built in Alberta, installed at that time for conservation purposes. Plant No.1 had five integral compressors, a mine sweetening and ambient temperature lean oil absorption systems and a fractionation facility. By 1969, the plant's rated capacity was increased to 1.4 million cubic metres a day through a series of improvements which included the addition of compression, a propane refrigerated gas fractionator downstream of the lean oil absorber and a second depropanizer. Then as now, Plant No.1 extracted more NGL than it could fractionate. The excess raw NGL formed one of the solvent streams injected in the Wizard Lake Miscible Flood.