Paradigm Shift of Corrosion Management Using Integrity Operating Window Programs

Offshore oil and gas production and processing facilities are prone to incidents such as leakage which may escalate thus causing major accidents. These accidents pose a serious threat to personnel and assets. Previously, accident modelling has relied on studying a single event and its impact. It has been witnessed from past events that accidents are caused by combinations of events and therefore, accident modelling must consider multiple sequences of events and interdependent factors. The Floating Liquefied Natural Gas (FLNG) is a complex processing facility where a leakage of liquified natural gas (LNG) may escalate to a range of events such as fire to vapor cloud explosion. The escalation of events is dependent on the multiple intertwined factors evolving with time and space. This study is focussed on developing novel methodologies and models to study the transitional events and their causation during a major event in complex LNG processing facilities. This thesis outlined an extensive literature review and analysis of offshore and marine safety from the perspective of fire and/or explosion accidents. It analysed various causes of fire and/or explosion accidents and proposed a series of countermeasures with respect to different causes. The impact of the cryogenic temperature of LNG on steel structure during its accidental leakage has not been extensively studied. This study modelled an LNG pool formation and the impact of cryogenic temperature on a structural material during an accidental release of LNG. The study confirmed that an instantaneous LNG pool formation does cause immediate failure, however, this may significantly minimise design life of the structure and due attention is needed throughout its service life particularly in the spilled area. Literature review showed that minor leaks occur frequently, and they are often overlooked assuming that they are inconsequential. However, in the case of LNG, it can be too simple to ignore small leak due to the potentiality of causing suitable scenario for fire and explosion event upon rapid vaporisation after the leakage. This study proposed a novel technique for modelling fugitive leakage of LNG in a processing facility. The developed methodology is applied considering three different degrees of congestion and revealed that higher congestion levels present higher flammable hazards than the lower levels of congestion within the acceptable congestion level. As fire is the main cause of accident in oil and gas processing facilities, this study proposed a novel methodology for modelling fire impact assessment in a typical FLNG processing facility using Computational Fluid Dynamics (CFD). Three most credible fire accident scenarios were chosen from among various fire scenarios considered in the FLNG facility. It is found that the scenario in the Mixed Refrigerant Module in the liquefaction process presents the highest risk of fire to both on-board personnel and assets. In a complex processing facility, there is a high likelihood of occurrence of transitional scenarios such as hydrocarbon release, fire, explosion and dispersion of combustion products. Finally, this study modelled potential transitional events and their integrated impact during an accidental release of LNG. This study revealed that in a complex processing facility, transition of events is highly possible, and the impact of such events can be more severe than that of the individual event. This study serves as a comprehensive source of knowledge and technique on which to model various accident scenarios. The study of these scenarios assists in better understanding of accident causation and improves design to prevent causation of such events. The study also provides a practical approach to design safety measure to control and mitigate hazards when prevention is challenging. This thesis will serve as a guiding book to better design of processing facilities and safety measures for a complex processing facility.

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

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.

Benzene is an organic chemical compound with the chemical formula C6H6. The benzene molecule is composed of six carbon atoms joined in a ring with one hydrogen atom attached to each. Acute benzene exposure can cause central nervous system depression. Longterm exposure can result in depression of the blood-forming system and may increase risks associated with anemia and leukemia. The purpose of this research is to identify benzene safe concentration in crude oil processing plant in east java area due to process fugitive emission. Sample is taken from 20 workers include work duration and weight of the worker also crude oil plant air quality monitoring is measured using direct-measure benzene detectors.In the benzene measurement on the crude oil plant in east java area, 2 spot sample is taken with resulting data 0.96 mg/m3 or 0.30 ppm and 0.86 mg/m3 or 0.27 ppm, and according to final manual calculation for safe benzene concentration with the result 1.12 mg/m3 or 0.35 ppm, all of those number are still below safe concentration limit by refer to minister of man power No.13 / MEN / X / 2011 regulation and The Occupational Exposure Limits (OELs) which have been adopted globally as a company standard which is 0.5 ppm as an eight hour time-weighted average (TWA8) and 1.0 ppm as a Short Term Exposure Limit (STEL) (averaged over fifteen minutes). But according to Minimum Risk Level (MRL) ATSDR 2007, those value already above threshold which is 0,009 ppm daily exposure for acute effect and 0,003 ppm daily exposure for chronic effect, Recommendation to control and reduce fugitive emission which resulting in number of benzene is by reviewing engineering design for equipment causing fugitive emission, and since this company regulation for respirator usage in benzene case are 0.5-5.0 ppm must use Half-face mask with organic vapor cartridge, 5.0-25.0 ppm use Full-face mask with organic vapor cartridge, and Greater than 25 ppm use Self-Contained Breathing Air (SCBA) then need to re asses all area which has an obligation to wear personal protective equipment (Half-full / full mask with organic vapor cartridge or Self contain breathing apparatus) by not only based on benzene level but also considering the exposure duration. .

Optimization of Process Parameters for Glycol Unit to Mitigate the Emission of BTEX/VOCs

The decommissioning of the Bishop Tank Farm began as a simple equipment dismantling and removal. However, the presence of soil contamination led to a costly and lengthy site remediation. The successful cleanup of the lease provided valuable lessons in minimizing environmental contamination and managing remediation at oil and gas facilities.

De-manning of offshore processing facilities presents an opportunity for significant CAPEX and OPEX savings for operators, is inherently safer and may be an enabler for marginal oil and gas developments. Unmanned wellhead platforms are common, however de-manning of significant oil and gas processing facilities has not been achieved to-date. This paper presents a conceptual design for a Normally Unmanned Installation (NUI) with full processing of well fluids to export specifications. By using novel and innovative solutions, a design with reduced equipment count, platform weight and attendance is proposed. The design is technically ready for implementation whilst meeting the functional requirements of an offshore processing facility. A functional specification was developed for the platform; it was important that the design is transferrable, therefore this functional specification was kept broad. The platform was expected to process well fluid to typical pipeline export specifications. To test the design, commerciality was tested against a "Reference Case", traditional manned platform. Full subsea processing was investigated but discounted due to a lack of technical readiness. Traditional approaches to platform design were challenged at every level, from platform access methods to the requirement for platform power generation. The key drivers for manning were investigated, identifying the target areas for simplification. An optimal platform design was then identified integrating the latest techniques and technology. The NUI CAPEX was compared versus the Reference Case. Ground-up OPEX estimates were prepared to quantify the reduction in attendance and achievable savings. The resulting NUI design achieves an approximate 60% reduction in equipment weight compared with a traditional manned platform, leading to a CAPEX reduction of around 30%. Significant reduction is achieved by removal of living quarters, and therefore life support systems from the facility. Power import allows maintenance-heavy power generation to be removed. The optimised NUI delivers a reduction in OPEX of around 50% when compared to a traditional manned facility. Digital strategies such as predictive maintenance, robotic inspection and remote monitoring reduce the reactive maintenance hours offshore by up to 85% while maintaining platform availability. Walk-to-Work platform access is a mature technology and offers cost savings when compared with helicopter access and there is the potential for sharing of walk-to-work systems between assets and industries. Walk-to-Work access has the advantage that no permanent living quarters are required. A significant reduction in fabric maintenance manhours is achieved by carrying out inspection remotely. The truly innovative and disruptive solution for unmanned facilities is the subsea factory on the floor. At the time of writing, the technology is not of the required maturity and it does not offer a viable solution. As this technology matures the potential exits to create a truly differentiated, facility of the future.

This paper describes a vapour phase method for cleaning and decontamination of a slug catcher in a gas processing plant. Corrosion and heavy metal losses required the slug catchers to be replaced. Safe decommissioning demanded the elimination of H2S, LEL and pyrophoric iron. Compromised integrity made traditional cleaning methods like circulation or pressure jetting unfeasible. The proposed method significantly reduced decontamination times and the associated effluent. The vapour phase method using degassing chemicals entrained in steam lowered H2S and LEL levels to substantially zero and also neutralized the pyrophoric material. The entire cleaning process was conducted with a temporary H2S scrubber due to unavailability of the process flare. This method did not require the system to be liquid filled or subject to high jetting pressure, making it possible to limit the treatment pressure to below 2 barg, thus minimizing the stress on the structural integrity of the slug catcher. In addition, the slug catcher weak zones were fortified externally in preparation for decontamination. This technique of using steam as a medium to distribute and apply the degassing chemicals throughout the slug catcher has proven to overcome the limitations of conventional cleaning methods. It further provided a viable solution to reducing the time and resources required to achieve substantially zero H2S, LEL and pyrophoric content by half. With traditional cleaning methods, the effluent generated would be substantial, necessitating additional logistical support for transporting the waste from the offshore location. Decontamination in a steam saturated vapour phase reduced the amount of effluent generated significantly, to only one third in comparison. This resulted in a solution that was more economical and environmentally friendly. Effective decontamination eliminated the risk associated with the presence of hydrogen sulfide (H2S) gas and pyrophoric materials, ensuring the slug catcher was decommissioned safely and successfully. For heavily compromised systems and for locations with water supply, waste management or schedule constraints, the vapour phase decontamination process has distinct advantages over conventional methods. The resultant savings in time and resources makes this an attractive option for mainstream oil and gas processing facilities as well.

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.

The Kizomba A and B projects, located on Block 15 offshore Angola, are world-scale production systems that set the pace for development of large, deepwater fields. The field layouts are unique in that they both combine a surface wellhead platform (SWHP) in close proximity to a spread-moored, floating production, storage, and offloading vessel (FPSO). This paper illustrates one of the many technical achievements that were essential to the success of Kizomba A and B projects: the integrated design of the close-moored system. The design, construction, and installation of large floating vessels in close proximity presents challenges for managing interfaces between the major Engineering, Procurement, and Construction (EPC) contractors. Any change by one contractor to a key connecting system can affect the coupled motions and integrity of components designed by other contractors. Achieving the project targets for safe separation between the SWHP and FPSO required diligent coordination and an effective communication effort. This paper also discusses the project's approach for effective interface management and close coordination to achieve safe and successful installation of the Kizomba A and B SWHP and FPSO facilities. Realizing the benefits of the Kizomba A and B field development architecture required establishing a confident basis for the separation distance and design of the fluid transfer lines (FTLs) between the SWHP and the FPSO. Because of the close proximity of the SWHP to the FPSO, establishing the separation distance and relative motions between the platforms through all load conditions was a key factor for design of the FTLs. Furthermore, the potential effects of hydrodynamic coupling, the subject of many technical papers on deepwater design, also warranted careful consideration. The design methodology outlined in this paper accounts for coupling between two floating vessels due to hydrodynamic interaction of the interconnecting systems. Kizomba A and B Overview The Kizomba A and B developments are located 370 km northwest of Luanda, Angola in water depths between 1,000 and 1,200 m. The developments each have estimated recoverable resources of 1 billion barrels of oil, and are based on virtually identical production systems, with peak capacities of 250,000 barrels of oil per day. There are four major systems associated with the Kizomba A and B developments:The tension leg platform (TLP) was selected as the SWHP. The TLP supports the drilling and well workover system for developing and maintaining up to 36 production and injection wells. The TLP does not support any production facilities, except a manifold system to combine the wellstream from each well and to transfer the produced fluids to the FPSO via FTLs. These lines are suspended below water between the TLP and FPSO.The FPSO is spread-moored in close proximity (nominally 200 m) to the TLP. The FPSO supports oil and gas processing facilities and stores the oil until it can be offloaded onto shuttle tankers.

Fluor provides services for major Russian project

Research on Energy Consumption Optimization Model for Compressor Units in Oil and Gas Processing Facility

Subsea operations represent a critical component in the production value chain of most Gulf of Mexico Deepwater assets. These operations provide many unique challenges, including flow assurance of the production streams. Complexity in production fluid chemistry, avoidance and management of problematic production conditions (slugging, gas lift control, hydrates, wax, asphaltenes, etc), and management of the overall subsea facilities for optimum production are all parts of the subsea flow assurance area. The main objective of this paper is to describe the work that was performed during a pilot test of a real time based flow assurance tool built for operations support. The tool consisted of a real time information system kernel coupled with anoffline model for ‘what-if’ scenarios and automatic lookahead functions. The simulator supports operations through intelligent alerts to operators and technical subsea experts. The tool entitled, ‘Advanced Warning System (AWS),’ was built and tested on-line for several weeks at one of Na Kika's oil loops. Introduction Subsea operations represent a critical component in the production value chain of most Gulf of Mexico Deepwater assets. Flow assurance of the production streams constitutes one of the many unique challenges these assets face. Avoidance and management of problematic production conditions such as slugging, gas lift control and hydrates are flow assurance issues that deserve special attention. With this motivation, a BP Gulf of Mexico Deepwater project team initiated a pilot project to implement an online tool coupled with alarm systems and independent analytical tools to run non-specific scenarios. The Na Kika North Oil Loop was chosen for this implementation due to its unique configuration, complexity and level of instrumentation. Field Description The Na kika base development consists of five oil and gas fields in the Mississippi Canyon area of the Gulf of Mexico tied-back to a central floating oil and gas processing facility. The water depths for each of the fields range from 5,800 ft to 7,000 ft and are offset between 6 to 13 miles from the facility. The individual fields are named Ariel, Kepler, Fourier, Herschel, and east Anstey. Additionally, the fields aredeveloped utilizing three unique gathering flow loops with their produced fluids routed back to the floating production facility. The Ariel and Kepler oil fields were developed with a 10' × 16' pipe-in-pipe (PIP), 25-mile flowloop to the northwest of the production facility. These fields include five subsea oil wells (i.e. Ariel: A1, A2 and A3 and Kepler: K1 and K2); each one of them daisy-chained within the northern loop route. The north loop is unique as the flowline route is generally downhill towards the host. The water depths along the route range from approximately 5,800 ft (shallowest) at the well locations to 6,340 ft at the host. This oil loop was selected for the pilot.

New source air permitting of oil and gas processing equipment ranges from fairly simple procedures under the Texas Natural Resource Conservation Commission (TNRCC) standard exemption list and the New Mexico Environment Department (NMED) registration regulations to an extremely complicated procedure requiring a federal Prevention of Significant Deterioration (PSD) and/or non-attainment review. The following topics relating to obtaining air pollution construction permits for processing equipment will be addressed in this paper: Type of permit/exemption/registration necessary for constructionSpecific permit/exemption/registration requirementsNew Source Performance Standards (NSPS) Subparts KICK, LLL, GG, K, Ka, and Kb Concepts outlined in this paper pertain to air pollution New Source Review (NSR). Owners and operators of oil and gas processing and production facilities that propose new or modified facilities should be aware of the regulations and interpretations contained in this paper. The primary effects of the 1990 Clean Air Act amendments on NSR requirements are identified.