Abstract The high pressure high temperature (HPHT) with significantly high contaminants of CO2 and H2S in full well stream demands the selection of Corrosion Resistant Alloy (CRA) pipeline for an offshore gas field. This pipeline system comprises of metallurgically bonded CRA layer produced by roll bonding called Metallurgical Cladded Pipe (MCP) and mechanically expanded and fitted CRA layer in a backing steel called Mechanical Lined Pipe (MLP). This paper outlines specific issues, mitigations and lessons learnt encountered during development phase of the CRA pipeline. Several issues arise during manufacturing and installation of the pipeline such as undulation appearance and rise indications at MLP internal surface, fit-up and girth welding constraint at the pipe end of MLP and MCP during installation phase. Thorough investigation including various inspections and testing on sample pipes were conducted to find the root causes and mitigations to ensure the integrity of the pipeline throughout the operating life. The investigation involved special tests such as pipe coating simulation and non-destructive testing (NDT) on the affected pipes. Specific procedures were developed to address the constraints based on the outcome of the investigation. Findings based on thorough investigations demonstrated that MLP and MCP are able to satisfactorily meet design requirements for the pipeline. Lessons learnt and best practices were also established for future reference in the manufacturing and installation of CRA pipeline.

Abstract Uninterrupted delivery of production chemicals through umbilicals and capillary strings is absolutely critical for oil & gas operators to avoid build-up of solids in wells and flowlines as well as excessive corrosion of the subsea infrastructure. However, flaws in design, poor installation and maintenance of subsea chemical injection systems, or deviating from operational procedures can cause blockages or leaks. In this paper two case histories will be provided about chemical injection failures. One failure is related to the formation of gas hydrates in the umbilical due to malfunctioning of an injection valve. The other failure occurred due to delivery problems due to high viscosity. Some information will be shared on why these failures could occur and improvements to the qualification process to avoid this in the future. Several deepwater operators and service companies developed chemical selection criteria based on the guidelines and recommendations from the 2007-2011 "Blockage Avoidance in Subsea Injection and Control Systems" (BASICS) JIP. Many companies have incorporated these recommendations in a subsea qualification process for deepwater chemicals. Chemical injection failures often relate to mechanical failure or limitations to the subsea injection system rather than to the chemical itself – especially after the JIP recommendations were incorporated. However, a qualified chemical product may cause injection problems if a holistic review of the application is lacking. The case histories will demonstrate the criticality of collaboration between the operator, engineering company and suppliers; sharing system information and operational conditions avoids costly mistakes. The complexity of deepwater chemical qualification is to design experiments that reliably predict field performance from lab testing. Moreover, failure mechanisms, e.g. corrosion, gunking and polymerization, are slow processes and laboratory experiements have to be accelerated to much shorter timescales for chemicals to be deployed quickly in the field to treat the risks they are designed for. With the deepwater boundaries getting pushed to new limits some of the laboratory testing has to be redesigned to assess the risks for these extreme conditions. We will, therefore, provide an overview of the different kind of tests that are required and add some considerations on how the tests can be modified and how the test results are best interpreted for field application.

A major operator in Malaysia planned to drill into a 6,000-ft horizontal thin-oil rim. The three-well campaign posed very challenging well deliveries for the operator due to potential losses to faults and karst zones, high uncertainty of reservoir productivity, long horizontal laterals, and openhole completions containing an Autonomous Inflow Control Device (AICD) with a low solids tolerance. An optimized drill-in fluid (DIF) and delayed filter-cake breaker were designed and tested to address the following challenges: reduced filtrate invasion, a targeted filter-cake breaking delay time, and high well production rates. In addition, there was a need for a mitigation strategy for total losses and the resulting impossibility of placing the delayed breaker across the entire reservoir section. A customized NaCl-based 9.2 lb/gal DIF with an optimally sized ground marble bridging package was designed to facilitate filter-cake removal using a compatible delayed acid-release cake breaker. This was achieved through the addition of special additives in the DIF to increase the acid solubility of the filter cake. The DIF also included special additives proven to facilitate liftoff of filter cake at relatively low differential pressure, and for enhanced thermal stability of the polymers used. Testing confirmed that the DIF filter cake was efficiently removed by the breaker within the customized delay time. Corrosion testing of the metallurgy used in the completion equipment demonstrated low corrosion rates at the expected 265°F bottomhole temperature (BHT) by both DIF and breaker systems. Laboratory test results confirmed a high return permeability of 97.5% using the integrated DIF and breaker system. Three wells were drilled in the thin-oil rim reservoir and were completed using this system without losses. A relatively high ROP of 90 to 175 feet per hour without differential sticking issues maximized drilling efficiency and reduced the overall drilling costs. DIF density and properties were controlled through a dump-and-dilute technique. The wells were drilled to TD, and the completions run without incident. After the breaker was spotted, sufficient delay time was achieved with which to remove the wash pipe prior to closing the reservoir isolation valve. Approximately two months after spotting the first breaker, the wells were brought online, and the actual gas/oil production rates of the three wells were 50% above expectation. This paper presents the design and successful application of an integrated DIF/breaker system for drilling and completing three of the most complex extended-reach wells drilled by the operator in Malaysia. The complementary designs of the DIF and breaker system components contributed to the successful drilling and production results of these three challenging wells.

In PETRONAS, there are on-going initiatives at petrochemical plants, gas processing plants, Upstream's well engineering and retail business in pursuing the digitilisation in line with the Industrial Revolution (IR) 4. The aim of the initiatives is basically to improve the efficiency of critical processes thus at the end will reduce overall cost and improve production margin and revenue/profitability. This paper will present the initiative of PETRONAS' Pipeline fraternity consisting of pipeline experts, managers and engineers in the development of intelligent and integrated pipeline integrity management system. The system is designed to have minimal people intervention as data will be automatically uploaded by Inspection & Maintenance (I & M) vendors and field technicians through interface software and utilising artificial intelligence/ machine learning for descriptive, predictive and prescriptive analytics. It is envisaged that by having the system, critical decision-making pertaining to integrity, safety and reliability of pipeline system could be done in ‘split seconds’ extending the asset's life and eliminating unwanted incidents i.e. leak/rupture. Furthermore, standardisation of pipeline risk and integrity software/tools among Operating PETRONAS Units (OPU)/regions will provide cost savings in the long term compared to current practice of having off-the-shelf software/tools. Integration of relevant corporate software/tools and the intended software/ tools will further provide cost savings in terms of database management and enhanced efficiency. There are few other initiatives running in parallel with the i-PIMS i.e. using advanced acoustic emission technology to detect corrosion anomalies using new developed sensors and also establishing algorithms/analytics for corrosion's growth, location and position throughout pipeline length; formation of dynamic free spanning for offshore pipeline; and predicting/monitoring 3rd party impact occurrence. Development of pipeline predictive analytics is to gain significant improvement in PIMS for better integrity status verification, faster decision making and optimization for I&M activities. The overall outcome/results/algorithms will be integrated into i-PIMS as part of final assessment. It is PETRONAS' aspiration that eventually, descriptive analytic of i-PIMS i.e. critical pipeline integrity performance indicators and critical processes can eventually able to be accessed via mobile apps which will be a ‘pace-setter’ in overall pipeline integrity management scheme i.e. ‘effectively managing pipeline at fingertips’.

Objective and Scope (25-74 words) During High Speed Flushing (HSF) of two water injection flowlines (WIFL) located at offshore Sabah, Malaysia at water speed of 3.0m/s, internal Fusion Bonded Epoxy (FBE) coating flakes were observed being ejected from end of flowline by ROV. There were concerns that the dis-bonded FBE flakes would block the wells during operation causing a reduction in the water injection performance. The objective of this qualitative root cause analysis is to determine the likelihood of further internal FBE coating disbondment during operation and assess whether the water injection flowlines internal FBE coating failure is localize or systemic. Systemic failure is defined as the location of the internal FBE coating disbondment has no specific pattern and is randomly distributed throughout the entire flowlines. Localize failure is defined as the failure pattern is discernible and limited to a few specific linepipe along the flowlines. Methods and procedures, process (75-100 words) The qualitative roots cause assessment of the internal FBE coating disbondment consists of the following work streams: Review of Shell Group past experience with internal FBE coated WIFL; Review of Internal and external FBE Coating Manufacturing Record; PLET's main piping video inspection; Flowline in-line visual inspection; Laboratory testing on failed FBE flakes and internally FBE coated spare linepipe. Results, observations, conclusions (100-200 words) In conclusion, there is no evidence to suggest that the FBE disbondment in the water injection flowlines was a systemic failure or that further application of flow would cause more coating to detach from the flowlines. It is deemed that the internal FBE disbondment is high likely localized based on the following observations: The total area of dislodged FBE coating from both the WIFLs is equivalent to approximately 30% of the internal FBE coated area of a single 12m long linepipe. No indication that there were issues with the coating application process in factory. The internal FBE coating application in the coating plant is a fully automated and continuous process. Based on a review of the FBE coating manufacturing record, there is no evidence indicates that the linepipe internal FBE coating disbondment is due to external localized overheating during external FBE application. New/novel information (25-75 words) The water injection flowlines had started its operation since September 2015 and the wells performance is closely monitored by WRFM team. To date there is no decline in water injectivity being observed or reported for all water injection wells. Hence, the qualitative root cause analysis approach employed by the project team is deemed a workable analysis method in concluding the water injection flowlines internal FBE coating failure is localize and low likelihood of further disbondment during operation.

Objectives/Scope This paper is about a study on the impact(s) of elemental and ionic mercury (Hg) to carbon steel corrosion in sweet and sour environments with and without Corrosion Inhibitor(CI) injection. Methods, Procedures, Process Evaluation on the effect of Hg deposition and the corrosion behavior via Corrosion rate using Linear Polarization Resistance (LPR), solution properties, surface profile and corrosion product analysis are performed. Low pressure bubble test and autoclaves test are conducted under multiple variables to study the corrosion rate behavior. Fluid Analysis is performed using ICP-OES and XRD to analyse the chemical reaction of the fluid. Surface analysis is conducted using Visual inspection and XRF. Results, Observations, Conclusions The bubble test analysis shows that elemental and ionic Hg does not affect the corrosion rates under CO 2 environment. Likewise, in H 2 S-containing environment, elemental Hg do not effect H 2 S corrosion evidence by the low pre-corroding corrosion rate. However, ionic Hg is observed to influence H 2 S corrosion where higher corrosion rate is measured. This is potentially due to the reaction between ionic Hg and H 2 S lead to the formation of HgS, depriving carbon steel inhibitive effect by H 2 S. The addition of Corrosion Inhibitors is observed does not reduce the corrosion rate probably due to the reaction between the ionic Hg and the sulphide element from the CI resulted into decreasing of filming tendency. HPRCE Autoclave result shows that CI had successfully reduce the corrosion rate to the targeted corrosion rate provided higher CI injection dosing is introduced.Significant HgS spectrum observed during XRD analysis reflecting ionic Hg mighthave reacted with H 2 S and CI. This supported that the presence of ionic Hg might have interfered the inhibitive mechanism of the CI and delayed the formation of passive layer on the metal. ICP-OES and XRF indicated Hg traces potentially due to high reaction rate between ionic Hg and injected CI thus accelerated the formation of HgS. Novel/Additive Information CI formulation without any sulphide composition should be used if ionic Hg is present in order to ensure the CI effectiveness and it consumption during operation. In the event where the CI formulation cannot be changed, an enhanced pre-qualification evaluation as conducted in this study is to be carried out if ionic Hg is detected in the system to ensure the CI is effective and compatible to be injected.

Managing pipeline integrity revolves around abundance of data and information from monitoring of safe operating limits, inspections and maintenance. Those data and information may come from real-time/on-line systems, manually input ad-hoc, manually input from inspections and maintenance carried out on a particular pipeline. The oil and gas pipeline industry have sort of mature with respect to having a software/tool in aiding and assisting personnel in performing risk, fitness-for-service, repair assessments, and executing management of change for a pipeline system; and many more assessments/analyses. Nevertheless with the invent of analytics, there is strong need to explore the new ways of working with those abundance data and information OR maximising the utilisation of the data and information for the benefit of assessing or evaluating pipeline's risk and integrity to predict 'accurately' risk and integrity so that specific and cost-effective actions and mitigations can be deployed within a stipulated period of time. In those regard, PETRONAS is actively working with industry to establish predictive analytics for critical offshore and onshore pipelines' threats/anomalies i.e. internal corrosion and free span for offshore; and external corrosion and geotechnical hazard for onshore. This paper will dwell on the principles, concepts and methodology of predictive analytics tools for the development. It is envisaged that eventually those threats/anomalies will be analytics-managed to eliminate unwanted incidents to PETRONAS's offshore and onshore pipelines. In addition, analytics-pipeline integrity management will also likely to provide 'accurate' prediction of 'future' pipeline integrity.

Top of Line corrosion (TLC) has becoming a growing concern for the oil and gas industry over the past recent decades especially on the offshore subsea high temperature and high pressure (HTHP) pipelines. This paper will present the challenges in managing TLC in multiphase wet gas pipelines. It will also cover the design, execution, appropriate inspection and corrosion monitoring to ensure pipeline integrity meeting the intended design life. There are many corrosions prediction modelling softwares available in the open market. However, once TLC is predicted in a pipeline, there are only few mitigation options which are by material selection, chemical injection, routine operation pigging, batch inhibition, etc. New projects are often considering material selection to mitigate TLC. This approach is rather straight-forward, however, high CAPEX is required. As for existing pipelines in operation with TLC, it must depend on effective chemical control (corrosion inhibitor) that could protect both TLC and BLC (bottom of line corrosion) coupled with continuous corrosion monitoring tools. Routine pigging during operation and more frequent inspection could be required too. To date, there is no common standard in testing the effectiveness of volatile corrosion inhibitor (VCI) in mitigating TLC.

The flexible composite pipes are quite suitable for the development of marine oil&gas reservoirs due to the excellent characteristics of design abilities, economics and dynamic behaviors. At present, the theories and methods of the gas permeations in the composite walls have not yet considered the influences of the multiphase flow in the inner pipes. Therefore, the prediction accuracies of the permeation rates are expected to improve for the marine flexible pipelines with significant differences of pressure and temperature drops. In this paper, a comprehensive gas permeation model including gas-liquid two-phase flow is proposed, and the effect of flow patterns on the gas permeation rate and vent period is investigated numerically. The results show that the flow patterns of multi-phase flow have significant impact on the permeation rate of gas due to different pressure drop and temperature drop for the same mass flow rate, and the permeation rate of CO 2 is higher than that of CH 4 under the same working condition.

Closed loop cooling medium systems are fundamental systems offshore oil and gas production facilities. Integrity or fouling issues in cooling loops have the potential to limit or jeopardise oil and gas production. Glutaraldehyde and isothiazolone biocides are reported in current literature as being effective chemistries for use in closed cooling mediums. This study showed these biocides initially display good initial effectiveness at high pH. However, the long-term bacterial control is poor due to a lack of persistency. The longer-term biocidal control of glutaraldehyde was far worse than that of isothiazolone in part due to chemical instability at high pH but also due to glutaraldehyde decomposition products presumably providing a food source for bacteria growth. This hypothesis was confirmed by adding elevated levels of bacteria to glutaraldehyde, which had been aged in a nitrite-based corrosion inhibitor solution. Results were compared with the non-traditional biocides, biguanide and 4,4-dimethyl-oxazolidine for cooling medium treated with a nitrite based corrosion inhibitor. Both biguanide and 4,4-dimethyl-oxazolidine showed significantly greater persistency compared to traditional closed loop biocides.

Uninterrupted delivery of production chemicals through umbilicals and capillary strings is absolutely critical for oil & gas operators to avoid build-up of solids in wells and flowlines as well as excessive corrosion of the subsea infrastructure. However, flaws in design, poor installation and maintenance of subsea chemical injection systems, or deviating from operational procedures can cause blockages or leaks. In this paper two case histories will be provided about chemical injection failures. One failure is related to the formation of gas hydrates in the umbilical due to malfunctioning of an injection valve. The other failure occurred due to delivery problems due to high viscosity. Some information will be shared on why these failures could occur and improvements to the qualification process to avoid this in the future. Several deepwater operators and service companies developed chemical selection criteria based on the guidelines and recommendations from the 2007-2011 "Blockage Avoidance in Subsea Injection and Control Systems" (BASICS) JIP. Many companies have incorporated these recommendations in a subsea qualification process for deepwater chemicals. Chemical injection failures often relate to mechanical failure or limitations to the subsea injection system rather than to the chemical itself – especially after the JIP recommendations were incorporated. However, a qualified chemical product may cause injection problems if a holistic review of the application is lacking. The case histories will demonstrate the criticality of collaboration between the operator, engineering company and suppliers; sharing system information and operational conditions avoids costly mistakes. The complexity of deepwater chemical qualification is to design experiments that reliably predict field performance from lab testing. Moreover, failure mechanisms, e.g. corrosion, gunking and polymerization, are slow processes and laboratory experiements have to be accelerated to much shorter timescales for chemicals to be deployed quickly in the field to treat the risks they are designed for. With the deepwater boundaries getting pushed to new limits some of the laboratory testing has to be redesigned to assess the risks for these extreme conditions. We will, therefore, provide an overview of the different kind of tests that are required and add some considerations on how the tests can be modified and how the test results are best interpreted for field application.

The high pressure high temperature (HPHT) with significantly high contaminants of CO2 and H2S in full well stream demands the selection of Corrosion Resistant Alloy (CRA) pipeline for an offshore gas field. This pipeline system comprises of metallurgically bonded CRA layer produced by roll bonding called Metallurgical Cladded Pipe (MCP) and mechanically expanded and fitted CRA layer in a backing steel called Mechanical Lined Pipe (MLP). This paper outlines specific issues, mitigations and lessons learnt encountered during development phase of the CRA pipeline. Several issues arise during manufacturing and installation of the pipeline such as undulation appearance and rise indications at MLP internal surface, fit-up and girth welding constraint at the pipe end of MLP and MCP during installation phase. Thorough investigation including various inspections and testing on sample pipes were conducted to find the root causes and mitigations to ensure the integrity of the pipeline throughout the operating life. The investigation involved special tests such as pipe coating simulation and non-destructive testing (NDT) on the affected pipes. Specific procedures were developed to address the constraints based on the outcome of the investigation. Findings based on thorough investigations demonstrated that MLP and MCP are able to satisfactorily meet design requirements for the pipeline. Lessons learnt and best practices were also established for future reference in the manufacturing and installation of CRA pipeline.

Pigging is necessary in both the maintenance and inspection of any pipeline, whether subsea or onshore. Operating in challenging environments and carrying potentially corrosive elements within the flow, a pipeline operator needs to be able to make decisions on integrity management based on relevant data. In Line Inspection (ILI) tools are typically deployed every three to seven years and give an operator detailed data on the integrity of their pipeline. However, these tools can be complex to operate, disruptive to operations, expensive to run and sometimes not deployed often enough to give operators a key insight into their pipeline integrity before an incident occurs. This paper will outline a new approach developed by a pioneering service company which enables operators to gather a significant volume of critical integrity data of their pipelines during regular cleaning and maintenance pig runs. The ability to inspect while cleaning reduces the requirement for mobilizing high value, MFL based ILI tools which additionally reduces personnel on board and improves operation economics.

The Thermoplastic Composite Pipe (TCP) has been established for a number of years as a viable alternative to steel and flexible pipe in subsea applications, with various intervention type of applications building track record in the field. After the successful installation of a Thermoplastic Composite Pipe for permanent methanol injection on Chevron's high-pressure Alder field in the North Sea in September 2016, Airborne Oil & Gas moved forward with the installation of a flowline for a full well stream application. The selection of a TCP Flowline ensures a CAPEX reduction as it is manufactured in long continuous length up to 6000 meter and reeled on lightweight transport /installation reels. This allows for reel-lay or surface tow installation with a low-cost installation spread, contrary to steel pipeline requiring slow lay-barges. Furthermore, the TCP flowline can be terminated on the platform and pulled through the I or J tube without the end-fitting, allowing for small and light I or J tubes. The TCP Flowline can be installed in a single pass, optionally with a weight coating to achieve on-bottom-stability and immediate burial with for example a jet trencher if required. This single vessel installation results in the lowest material and installation cost for TCP Flowline compared to the alternatives. Besides the CAPEX reduction, the selection of TCP flowlines ensures a significant OPEX reduction. Integrity management and corrosion prevention in particular have significant impact on operational cost. This is the case for new developments that more often see increasingly challenging environments with H2S, CO2, MIC etc, but also for existing operations that face unplanned shut-downs and repair cost caused by corrosion. The fully bonded TCP Flowline has significant advantages. The TCP does not corrode, has a smooth bore featuring low pressure drop, is collapse resistant to large water depth and combines pressure and tensile strengths with spoolability. The unique and specific properties of TCP make it a cost effective choice for a variety of different applications, from shallow water flowlines, to flexible high pressure jumper spools and deepwater risers.

Super duplex stainless steel tubes in grade SAF2507 have long been used for umbilical application in deep water oil and gas subsea systems. One of the oldest subsea systems installed with super duplex stainless steel tube SAF2507 is at the Åsgard oilfield located in the Norwegian Sea about 200 km offshore of the north part of Norway (figure 1). The Åsgard field comprises of the Midgard, Smørbukk and Smørbukk South deposits, which were discovered in 1981, 1984 and 1985 respectively. Corrosion evaluation of the tubes was presented at EUROCORR 2016, Montpellier, France, September 16th 2016 by Cathrine Holager, Materials Engineer (Aker Solutions) and authored by Karin van Thoor (Aker Solutions) and Sophia Ekman (Sandvik Materials Technology R&D) with the title of "Corrosion Assessment of the 17-year old Åsgard Smørbukk Umbilical". In addition to the previous report, this following article will report on the investigation of the fatigue properties of the tubes in two sections of the umbilical tubing installed in this field. Samples were taken from different areas of the dynamic umbilical, i.e. the splash zone and the most dynamic zone, and evaluated by fatigue testing. High frequency fatigue tests were performed on the samples and showed that fatigue properties did not differ significantly. The tests showed insignificant reduction in the fatigue strength of the tubes used both in the most dynamic part and splash zones. In addition, mechanical properties were evaluated to understand the effect of deformation history from fabrication, service life and sample preparation. No significant effect, besides a slight hardness increase compared to the delivery condition, was observed.

Conventional technologies used for insulation of flowlines in shallow-water fields, based on thermoplastic foams, are over-specified for the conditions. This has driven development of a low-cost alternative based on a low-density polyurethane thermoset foam. This paper will trace the methodology of an active collaboration between Logstor and TechnipFMC to develop and optimize this alternative coating. It will show the evolution of the developments and progress made over the last two years. The coating resembles a pipe-in-pipe system, however the outer steel pipe is replaced with a polyolefin casing. The coating is designed with a tapered end chamfer so that the casing meets the anti-corrosion coating at the pipe ends. Seals here compartmentalize the coating, making the coating on each pipe individually watertight and make the coating compatible with conventional field joint coatings. The development process has been based on critical examination of the pre-existing insulation coating, using FMEA and study of previous project experience, combined with trial manufacture and full-scale testing to simulate all stages of the life-cycle of the coating. Using this approach, it was possible to closely characterize both the manufacturing process and the coating system itself, which in turn enabled the investigators to identify and reduce inefficiencies in the coating design and also identify other areas where improvements would increase reliability. The insulation coating system described in this paper is an alternative to conventional multilayer polypropylene wet insulation technologies for pipelines situated in shallow water with several key advantages that may be of use to the specifying engineer or designer when designing a flowline that requires insulation.

A new gas field development with a challenging environment i.e. high pressure, high temperature and high H 2 S. The corrosion rate prediction performed, the expected metal loss is more than 8 mm thickness reduction within the 25 years design life. PETRONAS has embarked its tailor made qualification tests for qualifying CRA (Alloy 825) Mechanical Lined pipe to its project development. This is the pioneer project for PETRONAS to accommodate high pressure and high temperature service applications with high H 2 S environment. The tests were carried out to assess the susceptibility of liner material Alloy 825 to wrinkle under carbon steel pipeline coating condition, installation strain and operation strain, as well as to study the fatigue cracking behavioral at the seal weld locations due to operational cycles.

Flexible pipeline is a technically and economically viable solution for brownfield's EOR project, and with reference to one of PETRONAS Carigali's recent EOR projects, is the enabler for this EOR development. This paper provides a review of available pipeline solutions to fulfill EOR project's gas and water injection requirements which are vital to the success of the EOR technology implementation. A comprehensive technical assessment addressing the risk, advantages, limitations and also a brief overview on cost benefits have been performed on selected unconventional pipeline technologies, in comparison to rigid pipeline, using one of PETRONAS Carigali's recent EOR projects as the field case study. The EOR project case study key design drivers and constraints, mainly the ultra-shallow water depths ranging between 8m to 50m LAT, congested seabed with existing infrastructures, large areas of coral outcrops at multiple locations and the relatively high design pressures and design temperatures present great challenges in choosing the optimum pipeline solution. Feasibility of available unconventional pipeline technologies are evaluated against the project design drivers and the most viable solution is compared to the conventional rigid pipeline solution. Considerations are also given to design complexity, installation requirements, operation and integrity management. Complete selection criteria and matrixes are provided and supported with market information.

Life extension of offshore assets is a popular and hot topic as Operators are willing to maximize the operation of their platforms in order to increase their economical returns while maintaining satisfactory level of safety and integrity of their asset. The paper will propose a pragmatic, fit for purpose and consistent approach in establishing the baselines for life extension of any type of floating structures: FSO, FPSO, FSRU, FSU, FLNG and FPU. What will be covered by the proposed approach are as follow: Hull structure as a whole, Critical hull structure details Main marine systems including cargo, boiler, steam, seawater and freshwater systems Mooring system as a whole including anchoring system, mooring hardware, turret mechanical and structural components. The proposed methodology will cover the overall Life Extension process in several steps with toll gate at the end of each step in order to facilitate and streamline the decision process. The first steps are rather easy to be implemented and are mainly based on desktop studies with the review of the various reports supporting and detailing the design of the specific floating structure. They will be complemented by review of existing inspection reports covering the main systems as detailed above, and may trigger additional inspection campaigns and systems testing to enable proper understanding of their conditions. In addition the benefits in using proper and efficient Asset Integrity Management Systems from day one to support the overall integrity of the floating structure while enabling Life extension plan will be highlighted and discussed. Such approach will be based on experiences gained throughout several life extension projects conducted by Bureau Veritas for various floating structures operating in different modes and located in various environmental sites.

Current visual assessment of coating damage is performed by experienced inspector. This leads to variation in procedures and decisions among inspectors. Disagreement caused during assessment introduces issue of low reliability and repeatability of assessment results. A software that automatically identifies and determines percentage of defective areas in a given image is presented. Tested on a dataset of structural defects, outcome of the software is validated against answers provided by engineers and inspectors. The software requires an image of coating surface and hints on regions of interest as inputs. Users provide hints by clicking few times on regions they are interested (known as foreground) and not interested in (known as background). With built-in intelligence, the software scans the image and identifies defective areas by comparing colour difference between each pixel and hints user provided. If colour value of a pixel is found to be closer to hints in foreground, it is labelled as defective area and vice versa. Next, percentage of defective area in the image is determined and reported. Dataset of structural defects ( http://xiscobonnin.github.io/resources/#datasets ) with 73 images was used for experimental evaluation. These images come from wide range of engineering scenarios and contain different levels of coating damage. Wide variation that exists in the images would allow comprehensive understanding of performance of the software. Without prior learning, given each image, users provided hints by clicking few times (less than 10) on foreground and background. Machine (or computer) took over the analysis subsequently using algorithm developed based on colour information. Outcome from the software was validated against decisions made by engineers and inspectors. Results are promising with more than 90% of the defective areas successfully identified and in agreement with inspectors’ judgements. Reported percentage of defective areas for each image is also aligned with manually estimated value. This demonstrates that the developed tool is capable of improving process of visual inspection of coating surface. With current state of the art, user's hints have been proven to be very useful in guiding machine or algorithm to segment the image into foreground (region with coating damage) and background (irrelevant region). However, challenges remain for difficult situations such as colour of background being close to foreground and machine is unable to differentiate. Developed software is able to assess condition of coated surface quantitatively based on given image. This minimises the chance of argument over qualitative assessments during inspection. Having standardised tool for assessment would also allow comparison among existing cases. This serves as first step towards capture of experience in the industry through automation. Refinements such as threshold adjustment can be made subsequently to minimise difference between decision made by the software and experienced personnel.