NEWS RESEARCH EVENTS Industry & Practice Development & Technology Conferences & Seminars 7 1 0 2 / 6 e u s s I e Journal Pipeline Technology Journal OFFSHORE PIPELINES: THE NEXT BIG THING IN PIPELINE DEVELOPMENT? www.pipeline-journal.net ISSN 2196-4300
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Offshore Pipelines: The next big thing in pipeline development The boom of the past 20 years, especially in oil and gas pipelines onshore transport, has resulted in remarkable developments in construction, materials and predictive operations (safety, PIMS, repair, etc.). Remarkable projects overcoming mountains, densely populated areas, deserts and lakes have been realized with high engineering skills. Due to problems identified by the meticulous monitoring of the operation of transport pipelines, engineers and scientists have continuously implemented rec- ommendations and changes in the construction, operation and maintenance of existing pipelines. PIPELINE TECHNOLOGY JOURNAL 3 EDITORIAL Dr. Klaus Ritter Editor in Chief In Germany, for example, this has led to a 90% reduction in the frequency of not planned shut- downs for operational reasons within 30 years. Take a look at the last issue of ptj for details about this stunning development. Today, Pipelines are safe worldwide. Nonetheless, the res- ervations of the population, especially in the industrialized countries, have risen sharply with regard to new construction measures. Today we need to pay more attention to offshore pipelines, because the world’s hunger for energy will not decrease so quickly. On the other hand, more and more onshore oil and gas storage facilities are being shut down and more and more offshore storage facilities are being developed. The research and development focus here is somewhat different - especially in the field of materials. However, there is also much room for improvement regarding security and operational issues. The Pipeline Technology Conference will become more involved in this area in the future and will provide operators, administrators, as well as technology and service providers with a plat- form for the exchange of scientific and technical development. The present ptj and the 13th ptc standing before us offer a good start. We are working constantly to uphold the continuous exchange within the international pipeline community. You are welcome to make use of the extensive opportunities we created. Kindly find additional information on our websites or contact us directly via mail: • firstname.lastname@example.org • www.pipeline-journal.net • www.pipeline-conference.com Yours, > Dr. Klaus Ritter, President EITEP Institut
4 PIPELINE TECHNOLOGY JOURNAL THIS ISSUE’S COMPLETE CONTENT DECEMBER 2017 / ISSUE 6 TECHNICAL ARTICLES RESEARCH / DEVELOPMENT / TECHNOLOGY Inspecting Pipelines With Discovery™, The World’s Only Subsea CT Scanner Jennifer Briddon / Ben Metcalfe Tracerco Risk Reduction of Dropped Objects on Pipelines around Offshore Platforms Henning Bø TDW Offshore Services Systematic Handling and “Live” Repair of Gas Pipeline Leaks Asle Venas / Jens P. Tronskar / Lee Chon Gee DNV GL Integrity of Subsea Pipeline Butt Welds through Design, Construction & Operational Life Harry Cotton / Istvan Bartha Wood plc. Innovative Technology of Non–Contact Magnetic Tomography for Subsea Pipeline N. H. A. Ahmad / R. Z. Ismail / M. P. Othman / I. Kolesnikov Transkor (M) Sdn Bhd / PETRONAS Ultra-deep Water Gas Pipelines Collapse and Consequences Hossein Pirzad / Leif Collberg / Samaneh Etemadi EGIS / DNV GL / University of Oslo REPORTS CONFERENCES / SEMINARS / EXHIBITIONS www.linkedin.com/groups/4740567 ptc 2018 Preview www.twitter.com/pipelinejournal ptj Job & Carrer Market www.facebook.com/ Pipeline.Technology.Conference Company Directory www.pipeline-journal.net Event Calender 06 16 26 50 62 68 78 82 84 87 Chinese Gas Market on the Rise – Impact on the Pipeline and Pipe Industry (Preliminary Understanding)38Regional Report
INSPECTING PIPELINES WITH DISCOVERY™, THE WORLD’S ONLY SUBSEA CT SCANNER Jennifer Briddon > Tracerco; Ben Metcalfe > Tracerco As an increasingly large number of ‘unpiggable’ pipe systems approach the end of their design life, Operators are requiring new and innovative inspection technolo- gies to verify that their pipelines remain safe for continued operation. An inspecti- on technique now available to operators is Tracerco’s Discovery™, the world’s only subsea Computed Tomography (CT) scanner. Discovery™ is a non-intrusive external scanning technique which does not affect the operation of the pipe and does not require removal of any external coating applied to the pipe, being equally adept at scanning through 50mm of heavy concrete weight coats as it is at scanning through micron-thick fusion bonded epoxy coatings.
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 7 Having now performed over 1000 scans on pipelines, flowlines and risers in the Gulf of Mexico, and a similar number across the various North Sea sectors, Discovery™ has prov- en itself across a wide variety of pipe systems, a selection of which will be discussed in this paper and include: piggyback pipe systems, pipe-in-pipe systems, pipe bundles and heavy concrete weight coated pipes. In addition to providing high quality wall thickness measurement data, Discovery™ can also concurrently provide an assessment of the flow conditions inside the pipeline. This means that, at the same time as determining a pipe- line’s ongoing integrity, the Operator can enhance their understanding of the fluid con- ditions enabling improved inhibition strategies, as well as allowing for a safe method to determine the cause of any pipeline blockage, enabling targeted remediation strategies. As well as discussing previous projects, this paper will outline the developments taking place with Discovery™, including Tracerco’s innovative ‘fast scanning’ technique, an ap- proach that can provide basic information about a pipe’s condition in only a tenth of the time it would take for a conventional CT assessment of the pipe. INTRODUCTION Discovery™ is the world’s only subsea Computed Tomog- raphy (CT) scanner. It is a non-intrusive external scanning technique which does not affect the operation of the pipe. It also does not require removal of any external coating ap- plied to the pipe, being equally adept at scanning through 50mm of heavy concrete weight coats as it is at scanning through micron-thick fusion bonded epoxy coatings. CT scanners are particularly suited for scanning pipelines that, for various reasons, may be difficult to inspect by conventional techniques, such as in-line inspection or local inspections such as UT or PEC. Reasons a pipeline may be considered difficult to inspect or unpiggable include: • • No pig traps installed or pig traps removed • Multi-diameter pipes • Tight bends in the line, particularly those associated with smaller diameter pipes Pipe cleanliness - deposit or build up inside the pipe bore which may not be controlled by any existing applied inhibition mechanisms Internal coatings or linings External coatings • • • Additional metal items such as heating elements, centralizers or piggyback pipe supports Low or even no flow rate • • Dead legs • Pipe-in-pipe or multi-pipe systems In these situations, an operator may be forced to simply ‘manage’ their pipeline with assessments and models which, while useful, can be limited by the information they are built on. In turn, this can lead to over-conserva- tive approaches which could prematurely incorrectly ‘fail’ a perfectly operational line. This is a particular concern for lines approaching the end of their design lives and where information pertaining to their historic operation may be unreliable or unavailable. Having now performed over 1000 scans across more than twenty different scanning campaigns in the Gulf of Mexi- co alone, Discovery™ is already providing Operators with an additional tool to help ensure the long term safe and efficient operation of their pipelines. INTRODUCTION TO COMPUTED TOMOGRAPHY (CT) Although many people will have experience with CT scanning, either through its use in non-destructive testing (particularly of small, complex components) or through its extensive use in diagnostic medicine (indeed, it has been reported that there are over 72 million CT scans performed every year in the United States of America alone), relatively few people will have much experience with how CT works. The first thing to know about CT scanning is that, whilst it is generally thought of as a modern technique, it traces its origin to 1885 and the discovery of ‘X-Rays’. Developments with x-ray continued over the next few decades but for CT scanning the next key date was 1917 and the development of the ‘Radon Transform’ method. This was further refined in 1937 in the Algebraic Reconstruction Technique (ART) although it wasn’t until 1967 that computers of sufficient power were available to enable the development of the first CT machine with the first CT reconstruction (of a head) being performed in 1971. From this point on, developments
8 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY in CT scanning occurred rapidly, with the second and third generation of CT scanning machines (consisting of mul- tiple detectors for the second generation and rotation of source and detectors around the item for the third genera- tion CT scanners) following in only 1973 and 1975 and with superfast CT being developed in 1985. Since this time the majority of improvements to the CT scanning technique have been associated with improving the speed and reso- lution and understanding and handling any of the ‘detec- tion artefacts’ which can occur in any CT reconstruction. The basic principle behind CT scanning (and, of course, Discovery™) is relatively simple – the CT beam passes through a material and the density of this material can then be calculated by how much the beam is weakened. This weakening of the beam is due to the ‘attenuation coefficient’ of the material and it is different for various materials or for different combinations of materials in the beam’s path (Figure 1). Figure 1: Simple Density Measure These multiple line of sight measurements are taken and converted into a grid of values of density by use of recon- struction models. The whole process is easiest to consider as being like a Sudoku puzzle, in particular the challenging ‘Killer Sudoku’ variant. Unlike in traditional Sudoku puz- zles, with Killer Sudoku you have a grid with values at the end and from this you work out what sum gives the correct answer (Figure 2). Now, whilst a 9 x 9 Killer Sudoku grid would be a normal (if tough) challenge for a daily commut- er, for industrial CT scanners the grid is many times larger. Hence why it is only really possible to ‘solve’ a CT scan by the use of computers and iterative algorithms and why the most major developments in CT scanning have all occurred in parallel with improvements in computing. Figure 2: Two of the Many Possible Solutions to a Simple Killer Sudoku Puzzle CT scanning has several advantages over traditional radi- ography. Firstly, CT has an inherent high-contrast resolu- tion which means that much lower differences in physical density can be seen than could be seen by traditional ra- diography. Secondly, CT does not superimpose the image of one area over that of another (for example the opposite pipe wall). Finally, due to the method by which CT works and reconstructs, a CT scan is immune to the effects of the item inside the pipe. DISCOVERY™ Discovery™ is the world’s only subsea computed to- mography scanner. Completing its first full, commercial scanning campaign in 2015; since that time there have been a further two major evolutions of the Discovery™ instrument with the current fleet consisting of four of the latest versions of Discovery™. As of November 2017, Discovery™ has successfully performed over 1000 full scans in the Gulf of Mexico alone and with new projects occurring regularly, this value is expected to increase significantly in the forthcoming years. As with other non-intrusive techniques, Discovery™ is an external scan, which means that it requires full circumfer- ential access to the pipeline it is scanning. Unlike other external scan techniques however, a Discovery™ CT scan does not require coating removal. This is because the source within Discovery™ produces a mono-energetic gamma ray beam which is powerful enough to pass
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 9 through denser materials such as steel. By comparison, a medical CT scan uses an X-ray source, which is lower energy and less ionizing, making it safer for the person being scanned, but this lower energy means that the beam cannot even pass through bone. Each individual Discovery™ scan produces a 15mm image ‘slice’ of the pipeline; in order to provide scan data for a larger section, Discovery™ is able to crawl along the outside of the pipeline. As with other inspection tech- niques, Discovery™ is able to take the information from each ‘slice’ and position it to provide a wall thickness map of the entire scanned length for the full 360 degrees of the pipeline (Figure 3). Table 1: Discovery™ and ILI Standard Reporting Tolerances The Discovery™ CT scanners currently in operation are, due to the radial space available between source and de- tector, able to scan pipelines with an outer diameter up to 27 inches (including coating). Tracerco has also performed feasibility studies which have confirmed that the technique can be scaled up to larger outer diameter pipes, up to ap- proximately 50 inches, should a market need be identified. Discovery™ detection limits, according to the defect classes as laid out by the Pipeline Operators Forum ‘Specifications and Requirements for Intelligent Pig In- spection of Pipelines’ , are provided in Table 1. As can be seen in Table 1, the standard Discovery™ report- ing tolerances are comparable with reporting tolerances provided by other non-destructive testing techniques such as magnetic flux leakage (MFL) in-line inspection. PROJECTS In this section, we will be looking at various different types of unpiggable and difficult to inspect pipe systems and identifying what a Discovery™ scan can provide which other techniques cannot. Figure 3: Wall Thickness Colour Map Produced by Discovery™
10 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY PIGGYBACK PIPE SYSTEMS PIPE-IN-PIPE SYSTEMS Although the presence of a piggyback pipe does not make the pipe setup itself unpiggable, the piggyback pipe can prevent access to a large area of the pipe for the majority of externally applied inspection techniques. Couple this with a pipeline which is unpiggable by a different means (for example sharp bends, un-barred tees or heavy depos- its in the line) then Discovery™ could be the solution. Fig- ure 4 shows a piggyback pipe setup from a series of scans performed by Tracerco in the Billingham, UK test facility. Pipe-in-pipe systems have proven themselves to be a particularly common pipe system for a Discovery™ inspection, as they present a particular challenge to the current conventional inspection techniques, since the annulus typically presents an impassable barrier due to the differing material. Furthermore, pipe-in-pipe systems may also include heating elements or electrical tracing around the pipe, as well as spacers which can further add to the scan difficulty for many inspection techniques. Since Discovery™ operates externally and each scan generates a complete image of the pipe with every rotation around the pipe, the only issue for scanning a pipe-in- pipe system is ensuring that sufficient time has elapsed to ensure an adequate amount of data and consequently an acceptable reporting tolerance has been achieved. The Discovery™ scan image produced in Figure 5 is of a pipe-in-pipe which can be seen to be in a generally good condition with regards the wall thickness, for both the inner and outer pipes. The pipe an- nulus can be seen to be air filled with no water or product present, which confirms to the operator that there are no leaks in either inner or outer pipe. The transported material within the pipe in Figure 5 at the time of the scan was water which was not a requirement of the Discovery™ scan; had the pipeline been transporting oil at the time of the measurement then Discovery™ would have been easily able to reproduce the flow regime at the time of the scan (see Sections 2.5 and 2.6). In addition, the Operator was able to determine that their inner (product) pipe was slightly off-centre compared to the outer (carrier) pipe, in spite of the presence of centralizers. Although this variation was not of concern to this Operator, it indicated that movement (buckling) of the internal pipe with respect to the outer pipe was possible, even with centralizers, and that Discovery™ could also be used to identify this move- ment. This scenario has been reproduced and scanned in the Tracerco facility in Billingham, UK (Figure 6). As can be clearly seen in Figure 6, the extent of the inner pipe movement with respect to the outer pipe can clearly be identified and measured. In addition, Discovery™ was able to measure wall thickness to within its standard stated tolerance for all positions on the inner pipe and with only a slight increase in tolerance for the touching posi- tions on the outer pipe. This sample pipe clearly shows that Discovery™ can be used to monitor pipe-in-pipe systems Figure 4: Discovery™ CT Scan of a Piggyback Pipe In Figure 4, both main and piggyback pipe are clearly visi- ble and measurable at all positions, even the areas of wall in closest proximity, something which could be challeng- ing for many of the current ‘traditional’ inspection tech- niques. In order to enable Discovery™ to clamp around the pipelines, an additional external clamping system was devised; this is visible in the various circles and lines around the outside of the reconstructed image which are the bolts and tie-pins used in the clamp. The pipe sample scanned in Figure 4 was a 219.1mm outer di- ameter, 15.9mm wall thickness pipe with various defects ma- chined into it; in every scan, Discovery™ was able to provide wall thickness measurements to within its stated tolerance.
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 11 Figure 5: Discovery™ CT Scan of a Pipe-in-Pipe where inner pipe buckling could be expected to occur, in or- der to ensure the ongoing integrity and safety of the system. Figure 6: Discovery™ CT Scan of a Pipe-in-Pipe Showing Extreme Pipe Movement CONCRETE WEIGHT COATED PIPE Providing both additional weight and pro- tection against damage, concrete weight coatings have proven to be a popular external coating for many subsea pipelines. Unfortunately, for operators of unpigga- ble concrete weight coated pipelines, the external coating can also significantly limit the effectiveness of any external scan of the pipeline, as the vast majority of externally applied inspection techniques require direct contact with the pipeline metal. Previously, where an Operator required an inspection of a concrete weight coated pipe, they may have had to resort to removal of the coating in order to allow for an external inspection. This has both safety and cost implications for an Operator, as the coating removal pro- cess is both time consuming and indeed not without risk to both people and the pipeline itself. In addition, the coating must also be acceptably replaced following completion of the scanning campaign if the Operator does not wish to cause a potential future failure by either damage or corrosion. An example of a concrete weight coated pipe sample, representative of those which have previously been scanned by Discovery™, is provided in Figure 7, with the actual wall thickness measurements reported by ultra- sonic measurements provided in Figure 8. Figure 7: Concrete Weight Coated Pipe Section and Discovery™ View Figure 8: Wall Thickness Measurements Produced by Discovery™ Compared to UT Measurements
12 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY PIPE BUNDLES Although the dimensions of the current Discovery™ CT scanners preclude it from scanning a majority of pipe bundles, Discovery™ has proven itself capable of scan- ning pipe bundles of a smaller diameter. In Figure 9, a Discovery™ CT scan of a pipe bundle shows that Discov- ery™ is easily able to scan through the outer carrier pipe and into the production and gas lift lines without any significant reduction in scan quality (and consequently wall thickness analysis quality). Indeed, even the rust accumulated at the bottom of this test piece was clearly visible and its extent measurable in the scan. Figure 9: Discovery™ CT Scan of a Pipe Bundle es’ outer diameter (including coating), a feasibility study has been performed by Tracerco which demonstrates that it would be possible to extend the Discovery™ system to a larger diameter pipe, although the increased diameter may also result in increased scan times. GENERAL FLOW AND PRODUCTION ASSURANCE Due to the method by which Discovery™ operates, it is possible to generate an accurate recreation of the actual product flowing conditions whilst the pipeline is in opera- tion. For an Operator, this has many advantages as it enables them to identify areas of concern, such as slugging, water hold-up or erosion, which can have a significant impact on the operational life of the pipeline or its components, whilst at the same time potentially being very difficult to identify and isolate by other monitor- ing techniques. An example of Discovery™ flow as- surance capabilities at work, Figure 10 shows the hydrate formation and dissociation loop, as seen by Discovery™ in a series of CT scans performed at the client’s test facility. In the images shown in Figure 10, the hydrate can be clearly seen to be forming around the edges of the pipe at various ‘seed’ positions, be- fore progressing to a partial block- age. In the test facility, the hydrate blockage was removed from the pipeline by heating, a process which is not necessarily practical for use in an offshore environment. In the scans shown in Figure 10, Discov- ery™ was later confirmed to be iden- tifying to within 0.01g/cc changes in density associated with the change in fluid pressure within the pipeline. In Figure 9, several straight lines can also be seen, inter- secting various pipe walls. These lines are CT detection artefacts, caused by the reduction in beam intensity at positions tangential to the pipe wall. Detection arte- facts such as these are a well known phenomenon in CT scanning and Tracerco has several different techniques (varying for pipe setups) to minimise the effect of these artefacts on the wall thickness analysis results. Although the current Discovery™ system is only available to scan pipelines or bundles up to approximately 27 inch- BUILD-UP AND BLOCKAGES One area where Discovery™ can be of particular assis- tance to Operators is in the diagnosis and monitoring of build-up and blockages within a pipeline. This production assurance assessment can be provided to an Operator for any pipeline where sufficient scan data has been obtained and can be used to enable them to monitor for known issues or potentially to identify unexpected ones (Figure 11 and Figure 12).
Figure 10: Hydrate Formation and Dissociation, Discovery™ CT Scans RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 13 For Operators who are aware of blockages or flow re- strictions in their lines then Tracerco has several com- plementary techniques to help localize and pinpoint the issue prior to deployment of Discovery™. Tracerco’s GammaTrac™ is a flow monitoring technique where a radioactive source is injected into the line; monitoring when and how the source exits the line enables for a diagnosis of the extent of any bore restriction. Tracerco’s Explorer™ technology, which operates along a similar principle to Discovery™ but without requiring the same levels of pipeline access, can work as a localising tool, flying along the seabed and pinpointing the location of any bore restriction or blockage. Using either of these inspection techniques prior to deployment of Discov- ery™ can help ensure that the Discovery™ scan is only performed in the most appropriate area, minimising the overall project cost for the Operator. Information on combined flow/production assurance and integrity scanning campaigns performed by Discovery have been published by the Operators Hess  and Shell , both operating in the Gulf of Mexico. In particular, the Hess presentation highlights how Discovery™ was able to identify a build-up of barium sulphate in the pipeline which the Operator is now successfully controlling thanks to the information provided by Discovery™ and supported by other in-field measurements. Just as Discovery™ is able to identify the presence of build-up and blockages, it is also able to identify their ab- sence. In one recent scanning campaign, after the project had concluded the Operator stated that, based on historic modelling data, they had been expecting build-up in their pipeline. When the Discovery™ scans demonstrated that there were no discernible deposits present, they modified their inhibition strategy, reducing the need for costly dis- posal of an environmentally unfriendly product. Figure 11: Asphaltene Deposits Reducing Pipe Bore Cross Section (Discovery™ CT Scan) DEVELOPMENTS AND IMPROVEMENTS SCAN SIMULATION SOFTWARE One area that Tracerco quickly identified for improve- ment was in determining the minimum amount of time required for an image of sufficient quality for analysis to be obtained. To this end, Tracerco has developed an in-house CT scan simulation software which can be used to plot the improvement in image quality with respect to scan time and consequently to determine the point at which increasing the scanning time has no significant effect on the overall image quality (i.e. the point where the natural electrical ‘noise’ is the main contributing factor to any variation). With this information, Tracerco is able to work with our clients, taking their individual wall thickness tolerance needs and translating them into an acceptable scan time. Figure 12: Asphaltene Deposits Blocking Pipeline (Discovery™ CT Scan)
14 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY FAST SCANNING One area which Discovery™ suffers in comparison to existing, traditional inspection techniques is in the speed of inspection and consequently the cost per scan. Whilst the inspection speed for a Discovery™ scan is not directly comparable with that of traditional inspec- tion techniques (as traditional inspection techniques require additional time for coating removal), min- imising the scan time helps ensure that an Operator is able to gain the maximum amount of information from a scanning campaign. At the time of writing, Tracerco’s fast scanning tech- nique had been successfully applied on two projects in the Arabian Gulf and the Gulf of Mexico. In addition, work is currently underway to provide additional tools Figure 13: Flexible Pipe with Missing Armour Wire and Discovery™ Scan View It was with this need in mind that a new and in- novative technique was developed by Tracer- co for use in pipeline inspections. This is the ‘fast scanning’ technique, which was unveiled in November 2017  and which can reduce overall scan time by a factor of five. In summary, it has been proven that it is possible to detect po- tential anomalies and defects by identifying a key characteristic in the scan data prior to a full scan being per- formed. Once this char- acteristic has been identified then a full scan to enable complete characterisation of the defect can be performed whilst, if this characteristic is not present, then this scan can be terminated and the next position scanned. Figure 14: Flexible Pipe Section with Damaged Carcass and Discovery™ Scan View for Discovery™ scanning technicians and, eventually, full automation of this process for use offshore. WOULD YOU LIKE TO KNOW MORE? ANY QUESTIONS LEFT ? THIS PAPER IT WILL BE DISCUSSED AT THE 13TH PIPELINE TECHNOLOGY CONFERENCE
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 15 rable to that of traditional in-line inspection, whilst at the same time being able to reproduce the flowing conditions within the pipeline and all performed non-intrusively from the external of the pipeline. References [1.] [2.] [3.] [4.] [5.] Pipeline Operators Forum, “Specifications and Requirements for Intelligent Pig Inspection of Pipe- lines,” Pipeline Operators Forum, Version 2009. S. Corbineau and B. Metcalfe, “Computed Tomography for Deepwater Pipelines Integrity,” in MCE Deepwater Development, Amsterdam, 2017. J. Harry, “Summary of an Offshore Inspection Campaign with Subsea CT Scanning Technology,” in Subsea Tieback 2016, Houston, 2016. Shell Global, “From Hospital Bed to Seabed,” [Online]. Available: http://www.shell.com/inside-energy/ from-hospital-bed-to-sea-bed.html. [Accessed 20 11 2017]. Tracerco, “Tracerco announce new fast scanning application for Discovery™ pipeline integrity inspections,” 28 11 2017. [Online]. Available: https://www.tracerco.com/news/tracerco-announ- ce-new-fast-scanning-application-for-discovery-pipeline-integrity-inspections. [Accessed 28 11 2017]. Authors Jennifer Briddon Tracerco Integrity Engineer Jennifer.Briddon@Tracerco.com Ben Metcalfe Tracerco Subsea Technical Manager Ben.Metcalfe@Tracerco.com SOFTWARE IMPROVEMENTS As CT reconstruction and analysis is heavily dependent on computing processing power, an area identified by Tracerco for improvement was the bespoke, in-house software designed specifically to analyse pipelines. Cur- rently, the onshore analysis phase is quoted as requiring six weeks following receipt of the data for an analysis to be performed and a report produce. This is based on analysis of a ‘standard’ number of CT scans; if an Opera- tor requires more scans to be performed then the analysis phase can also be expected to increase. In July 2017, Tracerco began work on a project to reduce the required processing power by streamlining and improving the analysis process. This project is now in the testing phase, with initial results indicating the potential to reduce the anal- ysis time for a ‘standard’ number of CT scan significantly. A second phase of this project is scheduled to begin in 2018. INSPECTION OF FLEXIBLE PIPELINES Flexible pipelines present a unique set of challenges to integrity monitoring for most traditional inspection techniques but these are another area where Tracerco has determined that CT scanning could successfully be applied (Figure 13 and Figure 14). Figure 13 and Figure 14 are of flexible pipe samples and a scan produced by Discovery™. The scan clearly demon- strates that Discovery™ can measure flexible pipes and accurately identify failures; a future development identified for flexible pipes will be to enable the Discovery™ software to automatically detect and size these types of defects. CONCLUSION Tracerco’s Discovery™ provides Operators with a tool to help ensure ongoing pipeline integrity and which can be well used as a complementary technique to the more tra- ditional inspection methods. Working with an Operator to ensure the best value from each scan, Discovery™ is able to provide wall thickness measurements to a level compa- 13TH PIPELINE TECHNOLOGY CONFERENCE 12-14 MARCH 2018, ESTREL CONVENTION CENTER, BERLIN, GERMANY ONLY 3 MONTHS LEFT UNTIL PTC SECURE YOUR SEAT NOW WWW.PIPELINE-CONFERENCE.COM/REGISTRATION
RISK REDUCTION OF DROPPED OBJECTS ON PIPELINES AROUND OFFSHORE PLATFORMS Henning Bø > TDW Offshore Services
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 17 ABSTRACT INTRODUCTION The risk of objects being dropped on or around offshore installations is not as rare as is commonly perceived. Such events may occur during offshore construction activities or due to detachment of cargo (such as containers) in busy maritime lanes. In the worst case, the consequenc- es could be catastrophic, leading to functionality and containment loss. To mitigate the risks, T.D. Williamson, Inc., offers its proprietary SmartPlug® pipeline pressure isolation technology that allows an operating facility to be isolated from its surrounding impact zone. Using this non- intrusive pressure isolation tool, any given pipeline section can be isolated at or close to operating pressure. This paper begins by examining published data on the frequency and risks of impact- related incidents offshore, followed by a discussion on measures to mitigate such risks. The paper concludes with four case studies where the SmartPlug technology was used to successfully pro- tect pipeline assets by delimiting the impact zone during heavy lift operations offshore. These applications assume great significance in light of stricter governmental and operator regulations around risk control during offshore construction activities. 1. For an operation in offshore Myanmar, the Smart- Plug tool was installed 500 m from the platform to protect a 36-inch pipeline during the installation of two pipe spools. 2. A 30-inch SmartPlug tool was used to isolate and protect a live gas infield flowline during installation and piling works, 400 m from an offshore platform in Australia. The line was successfully isolat- ed for 6 months while construction activities were underway. Stringent requirements are in place to ensure safe execu- tion of all offshore operations and activities, and operators as well as individuals involved in such operations are obliged to take all necessary precautions. Governmental legislations (Petroleum Acts and similar) require operators to ensure the safety of all individuals directly or indirectly involved in or affected by ALL their (operator’s) operations. Understanding threats and possible failures to normal op- erations are vital in developing effective mitigations and barriers. Operators are obliged to screen and risk assess to mitigate the real threats in their activities whether the risk is prevailing in the activity itself such as construction tasks, operation of pressurized systems, and anchoring or whether the risk is in underlying threats to equipment and systems such as corrosion, erosion, vibration, structural/ material failures, and fire/explosion. A natural and necessary part of offshore operations is the lifting and moving of equipment, which spans a broad range of activities from the lifting of simple equip- ment such as hand tools to major non-routine, one-off lifting of larger structures during offshore installation or construction work Examples of the latter include heavy lifting of modules during construction, modification or removal/decommis- sioning of offshore installations, temporary equipment like pump spreads used during pipeline commissioning activi- ties, jack up rigs being positioned or floating vessels being anchored close to fixed installations. The recommended 3. During the heavy lift of a 600-ton accommo- dation module to an offshore platform above a 14-inch export pipeline offshore Australia, a 14- inch SmartPlug tool was used to isolate a 300 m section of the line. 4. A SmartPlug tool was deployed 700 m from a North Sea platform to protect the 36-inch dry gas pipeline during heavy lift from a vessel to platform. Figure 1: Types of lifts (Source: misc free images)
18 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY Figure 2: Types of impacts (Source: misc free images) practice document DNV-GL RP F107 on Risk Assessment of pipeline protection [Ref. 1] gives a brief overview on general hazards to live pipelines related to impact from different activity, and lists potential consequences. A natural risk following all lifting and moving of equip- ment is the risk of unplanned movement and accelera- tion of the masses resulting in impact with and damage to assets or personnel. As such lifting operations are planned with great care. The weather conditions at sea may add additional risk to lifting operations and to mitigate this, lifting operations are often tied to weather windows. However, as new offshore fields are being con- nected to existing pipeline system while mature fields and assets are changed or decommissioned, the frequency of offshore con- struction and lifting activ- ities will increase as will their duration. damage to pipelines, risers, control umbilicals or other elements that connect the platform with a larger pipe- line system. A scenario of this scale would be consid- ered severe, as the release of hydrocarbons close to the installation carries the po- tential for putting the entire installation at risk, including vessels close to the instal- lation. Even if there is no direct consequence from the dropped object, uncertainty will still prevail with regard to the consequences of the object’s impact with the pipeline and could demand an emergency shut-in of the facility until the safety situation is clarified. FREQUENCY AND RISKS OF IMPACT- RELATED INCIDENTS OFFSHORE But do drop object incidents happen? Yes, dropped objects are real threats, and a good example was in September 2014 when a container, which was in the process of being winched onto a support vessel from the platform, fell into the sea due to a mechanical damage and came to rest close to the subsea pipelines. Fifty-four workers were evac- uated from the platform until the situation was resolved. This single case illustrates that the threat of dropped objects extends far beyond the direct threat of person- Dropping an element during lifting inboard an offshore installation should be considered a major risk, as the platform in most cas- es contains pressurised pipelines with hydrocarbon content. However, dropping a load into the sea in the near proximity of platforms could also cause significant Figure 3: Container incident at Brent Alpha (Source: BBC - left image, Offshore- mag.com - right image)
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 19 nel being struck by unplanned or undesired movement of a lifted object. It presents the larger consequences of damage to the live pipeline systems in the impact zone surrounding the platform that may threaten all personnel on the installation. and management of safety-critical systems often uses the term “ALARP” (“as low as reasonably practicable”) to de- fine a target risk level, where the cost involved in reducing the risk further would be “grossly disproportionate to the benefit of risk reduction that would be achieved” [Ref. 1]. According to DNV-GL RP F107 [Ref. 1] the probability (frequency) of a dropped object is 2.2E-5 per lift, based on statistics of platform crane accident data issued by the UK Department of Energy from the period 1980-1986. Approximately 3.7 million lifts were estimated in this period, where 70% of the dropped objects landed on deck, while 30% were dropped into sea. Probabilities of drop- ping loads lifted to/from vessel by platform crane are in the range from 1.2E-5 (<20 tonnes) to 1.6E-5 (>20 tonnes). Other statistics are also available on the number and frequency of serious dropped object incidents on offshore installations covering other and larger periods of time. According to a report by the Norwegian Petroleum Safety Authority’s (PSA) [Ref. 2] which analysed all investigated lifting incidents on the Norwegian Continental Shelf in the period 2005 – 2010, the highest risks to all lifting activities were dropped objects, failing lifting equipment, or unwanted movement of heavy objects being lifted. The report focuses on the direct causes and root causes of the incidents and covers lifts on both fixed and floating installations, as well as both inboard lifts and lifts be- tween installation and vessels. Resource organizations such as DROPS (Dropped Ob- jects Prevention Scheme), comprise members from both operators and service providers and focus their activities on dropped object prevention awareness and training pro- grammes, including forums to discuss and recommend effective barriers to such incidents. DROPS illustrates the risks with dropping objects by presenting energy calcu- lations of typical objects falling overboard from instal- lations and vessels. It states that anything heavier than a typical 9-10 inch casing has the potential of severely damaging a pipeline at 150-m water depth, including the release of hydrocarbons. [Ref 4] The main conclusion is evident—that the threat of a dropped object offshore is also a threat to the offshore installation, and depending on the size of the dropped object even more so due to the presence of pressurized hydrocarbon contained in the pipelines. MITIGATIONS OF THE RISK ASSOCIATED WITH DROPPED OBJECTS Risk assessment quantifies the risk and aims at identify- ing actions to reduce the probability and/ consequence in order to reduce the overall risk of the unwanted scenario. The target for an acceptable low risk for the planned oper- ations is normally left to the operator to define. Regulation Most mitigation activities are directed towards reducing the impact risk by focusing on the reduction of probability or frequency of the impact, while a few mitigations are presented to reduce the consequence of an impact [Ref. 2]. However, when acknowledging the large scale conse- quences of damage to a live pipeline, the reduction of the potential consequences should be explored and possible solutions should also be evaluated. In the PSA report [Ref. 3], the most common direct causes of incidents are equipment faults, breaches of procedures, or incorrect execution of work. The most frequently occur- ring underlying causes are related to inadequate planning and deficient maintenance of equipment and lack of expertise, and focus on these elements would reduce risk. REDUCTION OF CONSEQUENCE One of the mitigations to reduce consequence is intro- ducing or improving the protection of the pipeline in the area of potential impact, for example, via a tunnel structure. Burying or rock covering the pipeline are other means to reduce the impact or spread the load and thereby reduce the consequence of a dropped object on the pipeline. However, it should be considered that the protection structure in itself may represent a risk of dam- age to pipeline during installation. A protection structure may also prevent the pipeline from sustaining damage but may require repair or replacement post incident to continue offering protection. The pipeline content represents a significant reservoir and is a potential leak point by its very nature. Subsea isolation valves may already exist as parts of a system to minimize the release of hydrocarbons from a damaged pipeline system. These isolation valves may in the first place be installed to protect the platform from issues aris- ing on the platform itself, not damages to subsea parts of the pipeline, but these could still offer some reduction of the consequences of a damaged pipe. There is of course the risk of subsea isolation valves also being subject to the impact from the dropped object. Stopping production is another effective mitigation of risk. This does not protect the pipeline itself from being damaged by a dropped object but effectively removes the risk of release of pipeline content, by making the pipeline free of pressure and hydrocarbon content. Yet, it is acknowledged that stopping production has a cost as- pect that needs to be assessed, particularly with respect to the ALARP principle.
20 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY A comparison can be made to standard lock-out or tag- out procedures in which the energy (pressure, poten- tial, electric, etc.) present in the machinery or system is secured, allowing authorized personnel to enter the work area safely and execute the required intervention work. Similarly, removing the energy source in the pipeline pri- or to significant lifting operation by means of temporarily isolating and de-pressur- izing a portion of the pipeline will reduce the overall consequence of a failed lift or dropped object. This is demonstrated in the case studies below where inline SmartPlug® isolation tools have been used to remove pressure and content from pipe- lines being close to or in the zone where larger lifts have been performed. USING INLINE ISOLATION TOOLS TO MITIGATE RISK During laying of a new 24-inch pipeline, the construction barge was required to initiate pipelay in the near vicinity of the Yadana platform. This introduced a risk of impact to the existing live gas pipeline, with the consequence of creating a gas blowout at the platform, with consequent effects on the construction vessel and the overall environment. Many lifts do not need particular mitiga- tions to reduce the consequences of a failed lift, but some lifts are of such nature that even though the probability of the failure is very small, or remote, its conse- quences would be enormous. A pipeline damaged by a dropped object may have to be shut down until the damage is assessed and if required, repaired. This would natu- rally affect all other connected platforms in the pipeline system. Should the damage cause a leak or rupture, the consequences may extend to include other possible scenarios such as the following: • • • • fatalities due to exposure to the leaking pipe inventory threat to the entire installation or vessels environmental impact of the escaping inventory. full system shut down and depletion until the emis- sion is stopped and scale of damage assessed. cost impact with reporting and investigation process by relevant authorities penalties and emission fees cost of repair and recommissioning of system increased cost due to accelerated schedule to bring production back on track loss of reputation • • • • • Figure 4: Layout of Yadana platform and pipelines (Source: TDW) The solution chosen to mitigate any possible large- scale consequence of a damaged pipeline was to load a 36-inch SmartPlug tool into the launcher at the Yadana platform and pig the tool approx. 200 m into the line in order to establish a double barrier isolation towards the pipeline inventory. While the 200-m isolated section was bled down to ambient pressure, the construction activ- ities were completed while mitigating the risk of a gas blowout at the scene. CASE STUDIES The four case studies presented here highlight the key benefits of using inline isolations as risk mitigation mea- sures in potential dropped object scenarios. ASSET PROTECTION DURING PIPELAY ACTIVITIES The Yadana Platform is connected to the main land of Thailand via a 370-km long, 36-inch gas export pipeline supplying approx. 20% of the gas needs in Thailand. Figure 5: 36-in pipeline isometric (Source: TDW)
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 21 An additional isolation tool was also positioned in the new 24-inch export pipeline. This pipeline was laid dry with a requirement to perform the tie-in to the Yadana platform without flooding the pipeline. To prevent sea- water ingress during the tie-in activities with an open pipeline end exposed to the static head of water, a 24-in SmartPlug tool tool was installed in the pipeline end section as a part of the laying and served as a barrier to protect the diving activities during the tie-in period. ASSET PROTECTION DURING HEAVY LIFT- ING ABOVE A 36-INCH PIPELINE The North Rankin Alpha (NRA) platform is located off the coast of Western Australia on the North West Shelf in the Indian Ocean. Figure 6: 24-in pipeline isometric (Source: TDW) Figure 8: NRA and NRB in the North Rankin Complex (Source: Woodside Energy Ltd.) Both tools were recovered through the receivers at the Yadana platform, after successfully isolating the pipelines for the duration of required intervention and lifting work. As heavy lifting and piling activities were necessary parts of planned construction and installation activities on and around the NRB platform, a 30-inch pipeline run- ning between the Goodwyn Alpha platform and the NRA platform was at risk for potential damages should any of the planned lifting and handling activities result in objects being dropped onto the pipeline. Figure 7: Pipelay activity near the platform (Source: TDW)
22 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY To mitigate the large-scale consequences of a dam- aged pipeline, a 30-inch SmartPlug isolation tool was launched from the NRA platform and pigged a total distance of approx. 700 m into the pipeline. The tool established a double block isolation in the horizontal section at the seabed, approx. 400 m away from the platform and allowed depressurization of this section to ambient pressures. The same pipeline isolation also enabled other planned and required activities to be completed on pipework tying into the 30-inch pipeline, while the production at Goodwyn continued with no shutdown. Figure 9: Overview (Source: Woodside Energy Ltd.) Figure 10: Location of SmartPlug isolation (Based on image: Woodside Energy Ltd.) Figure 11: SmartPlug® isolation tool (Source: TDW)
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 23 ASSET PROTECTION DURING HEAVY LIFTING ABOVE A 14-INCH PIPELINE The Yolla platform is operated by Origin Energy in the Bass Gas Joint Venture for commercializing gas acquired from the Yolla Gas Field in the Bass Strait. It is located offshore in 80 m water. to replace the emergency shutdown valve on the plat- form. During this period of planned work, a SmartPlug tool was used to isolate the 14-inch export pipeline at ambient pressure—first, to enable the ESDV replacement and second, to provide a long-term isolation through- out the heavy lifting operations. TDW used a 14-inch SmartPlug isolation tool introduced through the topside launcher, pigged down the riser and approximately 300 m into the line. The tool provid- ed double block isolation to safely protect the working area for the ESDV replacement. Due to adverse weather conditions, the ESDV instal- lation was delayed and a blind flange was temporarily installed. The tool remained in the pipeline for the next Figure 12: Location of the Yolla Gas Field (Based on map: Geoscience Australia) Phase 1 of the Yolla Mid-Life Enhancement (MLE) project involved upgrading Yolla to a manned platform. Several heavy lifting operations, including the installation of a 600-ton accom- modation module on the Yolla A platform, were to take place above a 14-inch export pipe- line running from the platform to the Lang Lang terminal during the Yolla MLE campaign of 2011/2012. To mitigate risks to platform and per- sonnel from dropped objects and to en- hance overall safety, Origin Energy chose to isolate a section of the pipeline with the TDW SmartPlug isolation tool. The client also had an additional scope Figure 13 14-in pipeline isometric (Source: TDW)
24 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY 8 months, during which the heavy lifting operations and the new ESDV installation works were all successfully completed. ASSET PROTECTION DURING HEAVY LIFTING ABOVE A 36-INCH PIPELINE The isolation was established approx. 700 m into the pipeline, after launching and pigging the tool to location from the platform’s launcher. After an isolation period of 6 days, the tool were unset and retrieved and the pro- duction was resumed. CONCLUSION In 2013, a drilling module was to be installed on a plat- form in the North Sea, which involved a heavy lift directly above the 36-in Statpipe line. As the pipe containing hydrocarbon gas was operating at approx.. 100 bar, any failures during the lift would result in catastrophic conse- quences. Hence, the client chose to involve TDW Offshore Services to deploy a 36-inch SmartPlug tool to provide an isolation, allowing the pipeline to remain at ambient pressure during the short period of heavy lifting activities. The Case Studies presented here illustrate the added benefits of a pressure-free pipeline during heavy lifts. The removal of pipeline pressure and content are a preferred and effective mitigation of the consequences of failure during lifting, and eliminate the potential of a large scale catastrophe due to uncontrolled leakage of pipeline inventory from pressurised pipeline. By using an inline isolation tool, the following benefits are accrued: • Removes pressure and replaces content from live pipelines during lifting activities • Mitigates some of the consequences of a failed lift • Short intervention period results in minimal disrup- tion to the production Easy installation and removal of the isolation tool • References . . . . Health and Safety Executive (HSE) UK http://www.hse.gov.uk/risk/theory/alarpglance.htm DNV-RP-F107 RISK ASSESSMENT OF PIPELINE PROTECTION (2010) Petroleum Safety Authority Norway, PSA - MT58 F12-027 / 580285.00.01 “Analyse av årsaks- sammenhenger til uønskede løftehendelser” DROPS (Dropped Objects Prevention Scheme) http://www.dropsonline.org/assets/docu- ments/DROPS-SubseaDROPS.pdf Author Henning Bø TDW Offshore Services Technical Authority email@example.com Figure 14 36-in pipeline isometric (Source: TDW)
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SYSTEMATIC HANDLING AND “LIVE” REPAIR OF GAS PIPELINE LEAKS Asle Venas > DNV GL - Pipeline Technology; Jens P. Tronskar > DNV GL Deepwater Technology; Lee Chon Gee > DNV GL Deepwater Technology DP2 Vessel “Norman Baltic” at repair location.
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 27 ABSTRACT Offshore pipelines are exposed to many treats and fails from time to time. Such failures represent a major risk for offshore pipeline operators in terms of safety, pollution as well as significant financial risk due to loss of production. Another major risk and challenge is the time and cost to repair the pipeline that have failed. The time is always very critical and if the water depth exceeds diving depth div- er-less repair systems will be required. Such systems are not off the shelf systems and require a lot of tailor-made qualification for the pipeline and on site requirement. cost effective repair method can be selected. DNV GL has prepared several codes that will be relevant with respect to, operation, integrity management, inspection and assessment, as well as repair. The documents contain technical requirements and guidelines, and can be down- loaded from the DNV GL web site (www.dnvgl.com) free of charge. One of these codes is the only offshore pipeline repair guideline DNVGL-RP-F113, Pipeline Subsea Repair. This code has recently been updated based on feedback from many repair cases. See also Figure 1 below. When a pipeline fails, it is very important to systematically handle the damage and repair. Proper failure, root cause analysis is very important to understand what has hap- pened. Then proper analysis of the defected pipeline, risk assessment will also be very important before the most cost effective repair method can be selected. DNVGL has been engaged in many offshore (both shallow water and deepwater) pipeline repair and qualification projects. This also involve live pipeline repairs of leaking gas pipelines. DNVGL has also been working with the leading pipeline operators to develop and qualify new deep-water pipeline repair systems. DNVGL also have issued the only offshore pipeline repair guideline DNV-RP-F113, Pipeline Subsea Repair that can be downloaded from our web site without any cost. This RP has recently been updated based on feedback form many companies. INTRODUCTION Pipelines face many different threats apart from internal and external corrosion third party threats represent major hazards to submarine pipeline. Pipelines may also be damaged during installation and there have been cases where several local buckles over a few kilometer of subsea pipeline have only been detected by the geometry pig after installation. Buckles and dents from third party anchor impact may often contain cracks and if the pipeline is not leaking the damage may still require a repair involving extremely costly cut and replace and associated pipeline shutdown, loss of gas transmission, dewatering and drying after the repair. For cases where the pipeline has sustained damage and is leaking, but the nature of the damage is such that the pipe geometry is still within the original toler- ances, cost optimal local repair methods can be applied. When a pipeline fails, it is very important to systematically handle the damage and repair. Proper failure, root cause analysis is very important to understand what has hap- pened. Then proper analysis of the defected pipeline, risk assessment will also be very important before the most In this paper we are presenting some recent cases of pipelines that where repaired while still in operation in a two step process involving installation of a leak clamp followed by a permanent repair by installation of a welded stand-off sleeve. The welding was depending on the water depth executed in a hyperbaric habitat or in shallow water using purpose built cofferdams. A concept proposed by DNV GL has been successfully applied to repair of leaking submarine pipelines. This paper describes the approach including the initial assessment of the flaw stability and how the repairs can be safely undertaken to restore the pipelines to their original design condition without reduction of pressure or flow rate. The paper de- scribes the method of global and local fracture mechan- ics finite element analyses to assess the stability of the flaws causing the gas leaks and the time frame required to complete the repairs. Further, the development of the welding procedure by weld thermal analyses is described and the full-scale mock-up test with flowing water in the pipe to simulate the forced cooling due to the gas flow. To ensure the safety of the repair crew the concepts involves using a gas containment barrier installed over a traditional mechanical leak clamp. The gas containment barrier is either purged with inert gas or nitrogen or it is maintained with a constant inert gas pressure that is monitored continuously during the repair. In the event of a sudden gas leak into the gas containment barrier a pre-set pressure relief valve will open and dump the gas leak outside the habitat. The pipelines in question have all been gas transmission lines carrying gas to gas fired power plants for which gas pressure reduction or shutdown were completely unacceptable. Future development is expected to involve development of remotely controlled repairs using similar concepts at water depths where diver/welders cannot be employed due to the various country regulations or simply because the water depths are such that divers cannot be used. The methodology according to DNV RP- A203 is described for qualification of new technology for underwater pipeline repairs. Further references are made to the recent updates to the DNV RP-F113 Pipeline Repair
28 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY Then a proper root cause analysis have to be car- ried out. Here the time line for the event leading to the damage, basic cause, immediate cause, etc be studied. Ref also Figure 2. In order to have a better foundation for the selec- tion of the repair method it will in most cases be required to carry out global and local analysis of the pipeline and damage. In some cases it may also be necessary to carry ooy ECA to verify if any crack like defects may continue to grow. See also Figure 3. When it comes to selection of repair the information from the above will make the basis. Very often the cost and consequence of the lost production far exceeds the cost of the repair. Very often a temporary repair clamp will be preferred as the pipeline then can be put back in opera- tion much quicker. However, very often it will be required to make a permanent repair. Such permanent repair can Figure 1: DNV GL pipeline codes relevant for pipeline damage and repair: with regards to requirements for “live” pipeline repairs as part of the repair method qualification based on DNV OS-F101 Submarine Pipelines. NOMENCLATURE CTOD Applied Crack Tip Opening Displacement CMOD Applied Crack Mouth Opening CTODmat Material Fracture Toughness NDT Non Destructive Testing SYSTEMATIC HANDLING OF PIPELINE DAMAGE AND REPAIR When a damage has been discovered on a pipeline it is very important that the sit- uation is handled systematically to avoid un- necessary cost and loss of time, but also to ensure the situation is handled in a way that avoids risk to people and the environment. First of all it is important to carry out a proper pipeline failure assessment. This will involve review of previous inspection reports like ILI, ROV videos etc. It will also normally require further inspections like diver surveys, UT, profile measurements, plastic replicas, etc. such inspections will be very important when carrying out the root cause analysis as well as for select- ing the repair method. It is also important to carry out a pipeline treat analysis in order to understand what have happened. To guide the treat assessment the DNV- RP-F116 can be used. Figure 2: Root cause analysis Figure 3: Defects analysis
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 29 tion to the gas flow or pressure reduction. DNV GL as consultant proposed use of a welded stand-off sleeve but to ensure the safety of the repair crew a second barrier i.e. gas containment/purging system was proposed used to allow removal of hydro- carbon leaks from the repair welding areas. The repair of the pipeline was successfully performed following qualification of the repair procedure, weld thermal analyses, NDT and structural/fatigue assessment of the completed repair. The fire caused by the dredging vessel subsequent to the punching of holes in the gas pipeline is shown in Figure 5. Figure 6 the successfully completed repair. Figure 5: Gas fire caused by gas leak on damaged 22” subsea gas pipeline. Figure 6: Successfully completed and coated repair of the two adjacent leaks seen in the cofferdam. For the repair DNV GL performed the structural assess- ment in Abaqus of the repair and independent weld thermal analyses using the PRCI weld thermal analyses Figure 4: Repair method selection be very time consuming, very costly and may require fur- ther shut down of the pipeline. According to DNVGL-RP-F113 various methods for repair and all requirements to ensure a proper permanent repair can be found. It will also be required to carry out a comprehensive risk assessment as well as cost benefit analysis before the final solution is decided. See also Figure 4. PIPELINE FAILURE CASES Welded repairs may be required where the pipeline is sub- ject to significant axial stress or may be subject to large strain associated with seismic events or soil movement. Further, axial stresses may be imposed on the pipeline due its configuration i.e. at pipeline crossings where there are overbend and sagbend as well as were there are free span causing pipeline sagging. To temporary stop a leak various clamps can be installed as a temporary repair measure but as most leak clamps uses elastomeric seals the life span of the repair cannot be predicted with any certainty and thus the repair can only qualify as a tempo- rary repair as per DNV OS-F101: 2013 . In the following we shall introduce some cases of sub- sea leaks on pipelines design and certified according to DNV OS-F101 that were repaired using welded structural stand-off sleeves installed over leak clamps to provide a permanent repair solution. The first case involved two major leaks and a fire caused by illegal dredging where the dredging vessel punched two large holes in the pipeline. The leaks were stopped by installing two elastomeric type leak clamps. However, due to water ingress the pipeline the line was temporarily shut down for dewatering and drying before resuming operation. As the pipeline was carrying gas to gas fired power plants in densely populated parts of South Asia, it was decided that no further shutdowns were acceptable and a repair solution was requested that would allow on-line or “live” repair to be executed without interrup-
30 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY software tool. Also note the two went holes that were used as inlet and outlet for the nitrogen purging during the welding of the long seam and circumferential stand- off sleeve welds. The gas pipeline permanent repair described above was completed with the pipeline operating at normal operat- ing pressure and gas flow hence, considerable savings in terms of avoidance of outage as well as loss of reputation for the operator where achieved. GLOBAL ANALYSES OF PIPELINE CROSSING To estimate the axial stresses acting on the weld flaw the measurements taken by the divers and data from side sonar was used to establish the global model of the crossing and the leak location. Whilst the pipeline analy- ses were ongoing a temporary leak clamp type Plidco was installed to stop the leak. The pipeline configuration at the leak location is shown in Figure 8 below. The second case involves a gas leak on a pipeline that was detected by a patrol boat. The leak was detected at the sagbend lo- cation of a pipeline crossing with another gas transmission line. A photo of the gas leak as detected, is shown in Figure 7. Figure 8: Sketch showing the global configuration at the pipeline crossing. A finite element model was established in Abaqus version 6.8.2 to estimate the axial stresses acting on the weld flaw the measurements. The model and the steps of the analyses are shown in Figure 9. The results of the global analyses showed that the flaw at the leak location is subject to compressive stresses. However, if the pipeline for some reason i.e. during the repair or by replacement of the pipe supports is lifted 200 mm the stresses will become tensile as shown in Figure 10 and 11. Figure 7: Gas leak detected on a gas transmission pipeline at a pipeline crossing sagbend. The gas leak was inspected by divers af- ter removal of the field joint coating and it was found that there was a 350 mm slot in a double joint with a 50 long central through thickness area. To assess the criticality of the flaw and decide on the per- manent repair solution global finite element analyses was performed of the crossing. The stresses from the global anal- yses was used as input to the local fracture mechanics finite element analyses to estimate the crack driving force and to assess the stability of the flaw. The global and local analyses performed are described in the following two sections. Figure 9: Global analyses model and loading steps.
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 31 LOCAL FLAW STABILITY ANALYSES The global analyses provided input to de- tailed analyses of the girth weld flaw with and without the Plidco leak clamp installed. The flaw was modeled as shown in Figure 12. To assess the impact of the leak clamp on the flaw and crack driving forces (in terms of applied crack tip opening dis- placement- CTOD). The pipe was modeled as shown in Figure 13 with the Plidco leak clamp installed. The boundary conditions and loading of the 3D model is illustrated in Figure 10. The objective of the local fracture mechan- ics FE was to establish the crack driving force CTOD and crack mouth opening displacement CMOD. In Figure 15 the CTOD (and CMOD) are plotted for the different applied pressure levels. It is seen that for low pressures the crack closes (negative CTOD) as a result of the sagging config- uration of the pipeline at the point of leakage (i.e. compressive stresses at 12 o’clock). First at pressures above 4.7 MPa (681 psi) the crack tends to open as the CTOD’s becomes positive. Hence, for this case with the maximum pressure that has been recorded 4.63 MPa (670.8 psi), the CTOD at upper and lower crack front is still negative and no crack initiation is expected. Figure 10: Axial stress results of global analyses. The blue vertical line indicates the leak location. Figure 11: Axial stress pipe lifted 200 mm. Figure 12: Model of girth weld flaw with a leaking area of 50 mm. Figure 13: Geometrical model of pipe girth weld with circumferential through thickness flaw and Plidco leak clamp installed. Figure 14. Boundary conditions and pressures applied to the FE model.
32 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY Nevertheless, the crack might still grow at low pressures due to pressure fluctuations, and from Figure 17 it is seen that with a max pressure fluctuation of 1.31 MPa (~190 psi) a ΔCTOD of about 0.011 mm is obtained and for a typical pressure fluctuation of 0.6 MPa (87.5 psi) the ΔCTOD is about 0.005mm. It should be noted that the pressure fluctuations are rather limited in number (said to be once a day), and with a ΔCTOD of about 0.005mm and 0.011mm, it is found that the crack growth will be limited. In Figure 17 it is clearly seen that the pre-tension of the re- pair clamp onto the pipeline has a beneficial effect on the CTOD and the CMOD. First at pressures above 5.0 MPa (725 psi) the crack tends to open as the CTODs becomes positive. Hence, for this case with the maximum pressure that has been recorded i.e. 4.63 MPa (670.8 psi). Here the upper and lower crack front CTODs have negative values of 0.009mm and no crack extension would occur. Figure 15: CMOD and CTOD derived from FEA with different internal pressure. Figure 18: Applied CTOD compared to minimum weld metal and base metal CTOD values. The local finite element model (FEM) has been generated and analysed, to simulate the part of the pipeline at the leakage together the repair clamp and where the pipeline is subjected to external and internal loads. A detailed 3D FE model with fine mesh with the crack is developed and where the pipeline and repair clamp are modelled as sep- arate bodies that interact through contact surface. Repre- sentative material properties were defined for each part of the assembly, including non-linear behaviour of steel. The preliminary results of the nonlinear finite element analyses reveal that the crack is located in sag bend for the global model where you will find compressive stress- es in the pipe wall at 1 o’clock position of the pipe (at the crack). The analyses also show that with the repair split- sleeve higher compressive stresses are obtained on the outside of the wall, whereas on the inside the compres- sive stresses are reduced. For this global analyses case the structural integrity of the pipeline with the installed repair clamp is believed to acceptable as the CTOD (Crack Tip Opening Displacement) values are much less than the fracture toughness value CTODmat of 0.15mm of the weld metal, giving a very comfortable safety margin of 16 times. However, for global the height of support no.6 has been increased by 0.2 m, the stresses at 12o’clock position are tensile and a CTOD value of 0.111 mm is obtained at the maximum operating pressure of 670 psi and the safety margin for crack propagation is significantly reduced. Nevertheless, the local finite element analyses still reveals that the CTOD value is less than the assumed material toughness value CTODmat of 0.15 mm, giving a Figure 16: Axial stresses and stresses at the crack tip with the Plidco clamp installed. Figure 17: Axial stresses and stresses at the crack tip with the Plidco clamp installed.
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 33 safety margin of 1.35. If one assumes that the crack may propagate into the base material for the same pressure level the safety margin is about 2.36. With a target maxi- mum operating pressure of 700 psi and pressure range of 290 psi, an applied CTOD value of 0.115 mm is obtained which gives to a corresponding safety margin of 1.3, and a crack growth rate at 1.40 mm/year is expected. hydrogen induced weld cracking and risk related to safety in the hyperbaric chamber including potential gas leak from the Plidco clamp seals during welding. The qualification of the hyperbaric weld and associat- ed testing, full scale mock-up as well as the hyperbaric spread is on the critical path. The concept that was cho- sen for the permanent repair is shown in Figure 21. REPAIR SOLUTION The Plidco leak clamp is considered a temporary repair. For permanent repair, this leak clamp needs to be replaced or modified by encapsulation to provide a permanent re- pair with respect to leak. Further, structural reinforcement is considered required to mitigate potential crack growth or unstable fracture of considered damage (i.e. depending on confidence in measured pipeline configuration). Among the local repair options, the method of welded stand-off split sleeve over existing installed leak clamp on “live” pipeline is considered feasible to achieve the key criteria especially the completion date as compared to the option including hot-tap bypass. Welding can be performed on “live” pipeline without inter- ruption. With customized design based on required load and pressure loading capacity, the welded stand-off split sleeve clamp can achieve the required structural integrity and can be engineered and qualified to prove that the repaired location has sufficient capacity to sustain full design pressure and operational axial loads. The risk associated with the offshore support vessel, de- ployment of supports/alignment frames and material han- dling/lifting for clamp installation needs to be identified and mitigated through a structured risk assessment exer- cise including development of mitigation measures during the execution to minimize the potential of compromising the integrity of the crossing pipeline. Typically, a localized repair will require relatively smaller operation compared to replacement of the pipe section by a hot-tap and bypass operation. This inherently reduces the risk of causing dam- age to the PHE pipeline during the repair operation. Welding of stand-off split sleeve over the installed leak clamp will not specifically be limited by the current pipe- line configuration at the crossing. Hyperbaric chamber can be customized to fit with the local profile at the leak location though and excavation of the seabed is required to accommodate the habitat The risk associated with the welding of the stand-off split sleeve over the installed clamp is generally associ- ated with offshore vessel deployment, material handling, installation related risk and diving related risk as well as the risks of welding on the “live” pipeline i.e. burn through, Figure 19: Gas containment barrier installed over Plidco leak clamp and instal- lation of stand-off sleeve with inert gas (Ar) purging hoses. WELDING PROCEDURE AND WELD THERMAL ANALYSES The installation of the stand-off sleeve requires welding onto an in-service pipeline. To facilitate a repair or to install a branch connection using the “hot tapping” technique is used. There are three risks that need to be considered. The first is the risk of burnthrough, where the welding arc caus- es the pipe wall to be penetrated allowing the contents to escape. The second is the risk of hydrogen cracking that arises from the fast cooling rates that tend to be produced by the ability of the flowing contents to remove heat from the pipe wall. The third risk is the risk of gas leak during the repair into the hyperbaric welding habitat. Various methods exist for predicting safe welding param- eters for welding onto in-service pipelines with regard to the risk of both burnthrough and hydrogen cracking. The PRCI Thermal Analysis Model for Hot Tap Welding  was used to predict safe parameters for welding a full-en- circlement stand-off sleeve (33.0 mm thick at fillet weld location) onto a 32 inch diameter by 15.9 mm thick API 5L Grade X65 natural gas pipeline operating over a range of flow conditions. The PRCI model was used to predict safe parameters for welding a full-encirclement stand-off sleeve (33 mm thick at the fillet weld location) onto a 32 inch diameter by 15.9 mm thick API 5L Grade X65 natural gas pipeline operating over a range of flow conditions. A total of six separate cases were modeled so that the effect of temperature, pressure, and flow rate could be
34 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY assessed. Assumptions that were made included an ambient temperature of 60°F, a sleeve temperature of 70°F, and no effect of preheat temperature. Although the actual installation will take place underwater in a hyper- baric chamber (approximately 25 meter water depth), this aspect is beyond the capabilities of the PRCI model however, additional analyses was performed to account for the habitat atmosphere and the effect of thev habitat atmosphere on the heat convection. The flow, temperature and pressure for the reiar condition cases are shown in Table 1. Table 2 shows the results of Case 2, the most critical for burntrough. It is seen that the maximum inner wall temperature is far below 982oC the critical burn through temperature. All cases were mod- elled using the chemical composition of the pipe at the leak conditions. All of the flow conditions that were mod- eled have produced nearly identical weld cooling times and HAZ hardness levels. The conditions for Case 1 (highest volumetric flow rate) produced the shortest weld cooling times and highest HAZ hardness levels and Case 2 (lowest volumetric flow rate) produced longest weld cooling times and lowest HAZ hardness levels. The difference in HAZ hardness between the highest and lowest for the highest heat input level is less than 1 HV. The maximum HAZ hardness for the lowest heat input was estimated at 327.5 HV10. Hence, there is negligible risk og hydrogen induced HAZ cracking. Depending on the level of diffusible hydrogen during welding preheating is recommeded applied in par- ticular for 4 ml/100g of diffusible hydrogen. The weld buttering and the circumferential fillet weld for attaching the stand-off sleeve to the run pipe is shown schematically in Figure 20. FULL SCALE MOCK-UP QUALIFIATION As part of the terms of reference the hyperbaric welding contractor was required to perform hyperbaric welding of a full scale mock-up trial welding the stand-off sleeve onto a sample pipe specifically selected to have chem- istry and mechanical properties almost identical to the two abutting pipes at the leak location, Figure 22, 23. The objective of the full scale mock up trial was apart from checking the HAZ hardness also to perform hydrotest at above 100 bar, Figure 24 and to test the TOFD equipment and NDT contractor for inspection of the long seam and circumferential weld joints, Figure 25. Further, the objective was to compare the measured flaw sizes in the 29 macro sections (Figure 26) taken of the circumferential fillet welds and in particular the weld root flaw heights to the flaw acceptance criteria derived by ECA as per DNV OS-F101 Appendix A requirements  and BS7910:2005 . An example of macro section and hardness records is shown in Figure 27. Figure 20: Circumferential fiullet weld deposition sequence. Case No. 1 2 3 4 5 6 Temperature, °C Pressure, psig 27.7 24.6 26.9 32.6 25.6 27 694.32 400.53 640 709.2 402.16 579.43 Flow Rate, mmscfd 569.61 246.37 391.03 529.41 316.94 425.48 Table 1: Flow conditions during the repair. Case No. Heat input kJ/mm Maximum inner Δt8/5 (sec) wall temp oC 1 2 3 4 5 6 0.6 0.8 1 1.2 1.4 1.6 0.85 1.15 1.46 1.83 2.21 2.61 25 25 25 208 227 245 Table 2: Results of PRCI thermal analyses for flow Case 2 Figure 21: HAZ hardness of untempered buttering bead estimated for various repair flow conditions.
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 35 Figure 22: Full scale water cooled mock-up test sample inside hyperbaric test chamber. Figure 23: Welding of circumferential weld butter layers inside hyperbaric welding chamber. Figure 26: 29 macro sections extracted from circumferential fillet welds. Figure 24: Hydrotesting of completed full scale mock-up repair. Figure 25: Completed seam welds being inspected by TOFD. Figure 27: Typical circumferential weld macro section and hardness records.
36 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY OFFSHORE REPAIR EXECUTION Following the successful welder, hyperbaric welding pro- cedure qualification and the full scale mock-up including hydrostatic testing of the stand-off sleeve pipe sample at 100 bar. The hyperbaric welding habitat and saturation chamber were shipped and loaded on to the DP2 vessel for the offshore repair campaign. Introduction picture shows the DP2 vessel at the repair location. release pressure was installed on the outlet hose to dump the gas outside the habitat. Figure 30 shows the ongoing welding in the habitat. Figure 29: Hyperbaric welding habitat installed on four suction piles. Figure 28: Hyperbaric welding habitat and “safe haven’. Prior to the installation of the habitat 5 suction piles were installed. The first was used as a test pile to check the soil penetration. Figure 28 shows the hyperbaric welding habitat. The test pile was successfully installed after which the four piles that would support the hyperbaric welding hab- itat where installed. The habitat was installed on the four suction piles, as seen in Figure 29 and the habitat door seals where installed and waterproofed before dewatering. Prior to the installation of the habitat divers had re- moved the anodes on Plidco clamp leak and trimmed the bolts to maximize the space for installation of the two gas containment barrier half shells. The bolts on the gas containment barrier were tightened using the prescribed torqueing sequence and the gas containment barrier including the hoses was pressurized to 20 bar using Ar gas. The pressure was thereafter maintained constant at 10 bar during the welding of the stand-off sleeve half shells. In case of sudden gas leak a PRV set at 20 bar Figure 30:Hyperbaric welding ongoing inside habitat. The whole offshore welding operation was completed without any pressure reduction or interruption of the gas flow, a head of schedule and the welds were accepted according to the DNV OS-F101 “Golden Weld principle”  based on 100% GVI, MPI and 100% TOFD/MUT using ECA based flaw acceptance criteria. CONCLUSIONS This paper has presented the approach applied for two cases of successful “live” welded repairs of leaking subsea pipelines using leak clamps and gas containment barriers prior to installation of stand-off sleeves specially designed to fit onto the pipe and the leak clamp. The methodology was successfully applied to repair two pipelines carrying natural gas to gas fired power plants in densely populated cities without pressure reduction or interruption of gas flow.
PIPELINE TECHNOLOGY JOURNAL 39 Regional Report 1. BACKGROUND Since Deng Xiaoping’s market reform was initiated in 1978, China has shifted from a centrally-planned to a mar- ket-based economy and has experienced rapid economic and social development. With a averaged nearly 10% GDP growth a year - the fastest sustained expansion by a major economy in history - China has lifted more than 800 million people out of poverty. The country is now the world’s second largest economy. Yet China remains a developing country, its per capita income is still a fraction of that in advanced countries and its market reforms are incomplete. Rapid economic as- cendance has brought on many challenges and problems as well, including high inequality; rapid urbanization; chal- lenges to environmental sustainability and air pollution. Beijing without smog vs. with heavy smog By Bobak (Own work) [CC BY-SA 2.5 (https://creativecommons.org/licenses/ by-sa/2.5)], via Wikimedia Commons This map provides near real-time information on particu- late matter air pollution less than 2.5 microns in diameter (PM2.5). Under typical conditions, PM2.5 is the most dam- aging form of air pollution likely to be present, contrib- uting to heart disease, stroke, lung cancer, respiratory infections, and other diseases. After Xi Jinping became President and Li Keqiang as- sumed premiership in March 2013. The new administra- tion has been keen to continue economic and financial reforms in China in the interest of greater long-term and sustainable growth. Especially when air pollution is now so prominent and is affecting people’s choice whether or not to keep living and doing business in these heavily polluted cities and regions. Therefore the reform in energy sector is in fact one of the more important topics Beijing needs to consider. The mindset for China’s energy development is changing from “quantity first” to “quality first,” with top priority given to clean, low-carbon, safe and highly efficient new energy, instead of just ensuring energy supply. During China’s energy transformation process, the share of non-fossil fuel grew to 13.5% in 2016, up 1.4% percentage points from 2015, while the share of coal dropped by 1.7%. Air Quality Real-time Map on May 06, 2017 Source: http://berkeleyearth.org/air-quality-real-time-map/
40 PIPELINE TECHNOLOGY JOURNAL REGIONAL REPORT Although natural gas production and use is rapidly increasing in China, the fuel comprised only 5.9% of the country’s total primary energy consumption compared to the world average 23.7% in 2015 according to data released by Oil and Gas Department, National Energy Administration. Heavy investments in upstream devel- opment and greater import opportunities are supporting significant growth in China’s natural gas sector. Moreover, natural gas as clean energy also meets the requirement of energy structure transformation in China. tinues operations in the entire oil and gas industry value chain. CNPC had total assets of 585,619($M), a revenue of 262,573($M) and 1,512,048 employees in 2016. Sino- pec comes in second with a total assets of 310,726($M), 267,518($M) in revenue and 713,288 employees in 2016. CNOOC as the smallest company of the three, had a total assets of 166,595($M), 65,892($M) in revenue and 100,821 employees in 2016. 2. THE CHINESE GAS INDUSTRY 2.1. MAJOR PLAYERS In the 1980s, China established three ma- jor state-owned enterprises (SOE) - China National Petroleum Corporation (CNPC), China Petroleum and Chemical Corpora- tion (Sinopec), and China National Off- shore Oil Corporation (CNOOC) - to serve in various areas of the oil & gas sector. CNPC was put in charge of most of the country’s onshore upstream assets, and Sinopec was given responsibility for the downstream activities such as refining, distribution, and petrochemicals. China gave CNOOC responsibility to explore and develop oil and gas assets in the offshore areas of China. In the late 1990s, the Chi- nese government reorganized most state-owned oil and gas assets and created separate operating companies or publicly-listed arms of each of the SOEs. These sepa- rate companies are majority-owned by each of the SOE holding companies. In 1998, the government restructured CNPC and Sinopec into two vertically integrated firms that own both up- stream and downstream assets, with CNPC taking some downstream assets and Sinopec acquiring some fields for exploration and production (E&P). CNOOC, which is responsible for offshore oil and gas E&P, has seen its role expand as a result of this industry reconstruction and growing attention to offshore zones and overseas assets. Also, the company has proven to be a growing competitor to CNPC and Sinopec by not only increasing its E&P expenditures in the South China Sea, but also by extending its reach into the downstream sec- tor, particularly in the southern Guangdong Province. China’s major gas industry players (2016) These state-owned enterprises (SOE) lead the natural gas development of China. Similar to oil exploration and production, these companies partner with internation- al companies to develop natural gas projects requiring more technical expertise. China’s natural gas supply sources are shifting towards greater imports and the need to bolster investment. 2.2. PRIVATE COMPANIES Urban gas supply is dominated by two companies, which hold stakes in the majority of municipal gas suppliers. 2.2.1 TOWNGAS The Hong Kong and China Gas Company Limited, com- monly known as Towngas, is the sole provider of towngas in Hong Kong. Founded in 1862, it is one of the oldest listed companies in the territory. In 2006, Hong Kong and China Gas acquired 44% of shares of Panva Gas and became the largest shareholder of Panva Gas.In 2007, the company was renamed, becom- ing Towngas China Company Limited. CNPC is the largest integrated energy company in China. The corporation integrates the business portfolios of an oil company and oilfield service provider, but also con- Towngas China Company Limited, formerly Panva Gas Holdings Limited, is a leading market player in natural
PIPELINE TECHNOLOGY JOURNAL 41 Regional Report gas businesses in China. It principally engaged in the sales and distribution of piped gas in the People’s Repub- lic of China including the provision of piped gas, construc- tion of Gas pipelines, the operation of city-gas pipeline networks, the operation of gas fuel automobile refilling station, and the sale of gas household appliance. It has over 200 projects in mainland China including city- gas, water supply, emerging environmentally-friendly en- ergy and telecommunications. It also engages in property development projects, namely International Finance Cen- tre (15% share), Grand Promenade (50% share) and Grand Waterfront, in Hong Kong with its largest shareholder. Based in Hong Kong, our portfolio currently includes 241 projects in 26 provinces, autonomous regions and municipalities in mainland China, as well as one in Thailand. Towngas portfolio 2016 (Source: Towngas Annual Report 2016) 11923820638301052032042051901921881961932001941171181951972011911991892021981252073731120121212208209210322117675185736717817411211318218368691077072741087117723718629171172184179175170169180114181173176115116106146141001451027174122184092111109127128144158159160281612401014746441511915315415615715523614836969597868788855758821022135052846364104657981807883956555354331267164165162166167252326244951163187168232233140103218221226220216217214215224229223228222227219225230231234235152141139143142653124341351321301311331341221241231371361291623935485960616266778389909192939498991101382412421491501315147201242434594ThailandPhetchabun111BeijingHeilongjiangJilinLiaoningHebeiShanxiInner MongoliaShaanxiNingxiaSichuanChongqingHubeiHunanGuizhouYunnanHenanJiangxiGuangdongGuangxiHainanZhejiangFujianJiangsuAnhuiShandongYellow SeaEast China SeaHong KongLiquefied natural gas receiving stationProvincial natural gas pipeline networkWater / Waste treatment projectsTelecommunication projectsCoal miningTowngas Group Hong Kong headquartersPiped city-gas projects (Towngas)Piped city-gas projects (Towngas China)City high pressure pipeline network /Underground gas storage (Towngas)City high pressure pipeline network(Towngas China)Coal-based chemical processingUpstream projectsCoal logistic projectOilfield projectCNG / LNG refilling stations (Towngas)CNG refilling station (Towngas China)Other projects (Towngas)Other projects (Towngas China) ThailandPhetchabun
42 PIPELINE TECHNOLOGY JOURNAL REGIONAL REPORT 2.2.2 ENN ENERGY GROUP 2.3. PIPELINE IMPORTS Established in 1989 as a natural gas distributor and retailer its strategy today is to grow internationally into a vertically integrated international energy company able to generate returns across the entire natural gas value chain. Phase I of its new Zhoushan LNG Receiving Terminal is expected to be commissioned in mid-2018 with 3 million ton annual capacity and further expansion planned. It already has signed long term gas supply deals with Chev- ron, Total, and Origin to supply half that volume. ENN is also involved in solar energy, clean coal chemical technol- ogy, intelligent and integrated energy systems as well as real estate, culture, health and marine tourism. It has a fast growing natural gas business that supplies city gas to more than 152 cities in China, operates the country’s largest private liquefied natural gas (LNG) and compressed natural gas (CNG) refueling station network and is building the country’s first private LNG receiving terminal in Zhejiang Province. Its gas sales in 2015 were 11.3 Bcm (Billion qubicmeter) The imported pipeline gas was 33.6 Bcm in 2015, mainly from Turkmenistan, Myanmar, Uzbekistan and Kazakhstan. Pipeline Import in 2015 (Source: BP Statistical Review of World Energy 2016) OPERATIONAL LOCATIONS IN CHINA West-to-East Pipeline I West-to-East Pipeline II West-to-East Pipeline III Shaanxi-Beijing Pipeline I Shaanxi-Beijing Pipeline II Shaanxi-Beijing Pipeline III Shaanxi-Beijing Pipeline IV (under construction) Hebei-Nanjing Pipeline Zhong-Wu Pipeline Yong-Tang-Qin Pipeline Qin-Shen Pipeline Sichuan-East Pipeline Tai-Qing-Wei Pipeline Anhui (14 projects) Guangxi (5 projects) 1,050,000 455,000 488,000 902,000 11,000 115,000 94,000 – 151,000 686,000 196,000 Bengbu Bozhou Chaohu Chuzhou Dingyuan County Fengyang Guzhen Jieshou Industrial Zone Laian Luan Quanjiao Suchu Modern Industry Park Suzhou Economic Development Zone 130,000 Yingshang Industrial Park – – Beijing Municipality (1 project) Pinggu 130,000 Fujian (12 projects) 125,000 105,000 149,000 650,000 185,000 390,500 1,060,000 Anxi Dehua Huian Jinjiang Longyan Development Zone Nanan Ningde Ningde Xiapu Yacheng Dongyang Industrial Park Quangang Quanzhou Shishi Yongchun – 320,500 1,355,000 130,000 161,500 – 576,000 1,065,000 Beihai Tieshangang Industrial Park Guigang Guilin Guiping Industrial Park, Guigang City Wuzhou Imported Renewable Resources Processing Park – – Hebei (20 projects) – 10,000 1,360,000 360,000 193,000 335,000 814,000 96,000 90,500 190,000 Baoding Dingzhou Gaocheng Jingxing Langfang Lingshou Luanxian Luquan Luquan Green Island Development Zone Luquan Yian Town Qingyuan County Western Industrial Zone B Rongcheng Shenze Shijiazhuang Wangdu Economic Development Zone Wenan Industrial Park Wuji Xingtang Development Zone Xinji Zhengding New Zone, Shijiazhuang City – 75,000 46,000 3,250,000 – – 86,500 – 225,000 50,000 Henan (11 projects) – 965,000 2,060,000 135,000 330,000 2,452,000 Gongyi Private Technology and Innovation Park Kaifeng Luoyang Ruyang County Ruzhou Shangqiu Weihui City (Tangzhuang Town) Industrial Agglomeration Zone 30,000 Xinan 125,000 Xinan Wanshan Lake Industrial Park Xinxiang Yichuan – 1,245,000 112,000 Hunan (14 projects) 5,090,000 368,000 Changsha Changsha County Chenzhou Suxian Industrial Zone – 488,000 Huaihua 230,800 Liling – Liuyang Industrial Park Ningxiang 445,000 North–western Liuyang 108,000 168,000 Wangcheng 990,000 Xiangtan 80,000 Yanling County 725,000 Yongzhou 1,620,000 Zhuzhou Zhuzhou County 277,000 Jiangxi (1 project) Shangrao Economic Development Zone 151,200 Hangzhou-Jiaxing Pipeline Guangdong (24 projects) Hu-Hang-Yong Pipeline Yong-Tai-Wen Pipeline (under construction) China-Myanmar Pipeline China-Russia East Pipeline (under construction) Xinjiang-Guangdong-Zhejiang Coal to Gas Pipeline (under construction) Gas Project Managed by ENN LNG Import Terminal 7,420,000 – 354,000 323,000 165,000 301,000 Dongguan Dongguan Dongkeng Town 100,000 105,000 Dongyuan 89,000 Fengkai Guangning 83,500 325,000 Heyuan 690,000 Huadu Huaiji 133,000 Jiangmen Hecheng Town Zone Leizhou Lianjiang Lianzhou Luoding Panyu Zone, Guangzhou City 1,795,000 Shantou 1,630,000 Shenzhen Bao’an (Longchuan) Industrial Park Sihui Wuchuan Xinyi Yangxi County Yunan Zhanjiang Zhaoqing Zhaoqing Development Zone 76,500 – 483,000 300,000 305,000 116,000 77,000 1,050,000 928,000 (Source: ENN Energy Annual Report 2016) 10 11 Inner Mongolia (1 project) Shandong (17 projects) Inner Mongolia Jiangsu (13 projects) Tongliao 855,000 564,000 780,000 720,000 605,000 594,000 318,000 750,000 Binzhou Zhanhua Economic – Development Zone Changle County 240,000 Changqing Zone, Jinan City Chengyang Huangdao Jiaonan Jiaozhou Laiyang Liaocheng Qingdao Sino-German Ecopark Rizhao Rizhao Haiyou Economic Development Zone Xintai City Development Zone Yantai Yantai Development Zone Zhucheng Zouping – 545,000 241,000 – 1,980,000 – 763,000 – 288,000 158,000 320,000 385,000 1,850,000 1,055,000 Gaoyou Guannan Development Zone Haian Hongze Huaian Lianyungang Lianyungang Xuyu New Zone Suining Suburb Taixing Wujin Xinghua Yancheng Yancheng Environmental Protection Industrial Park – – 335,000 1,164,000 614,000 1,090,000 – Sichuan (1 project) Liaoning (5 projects) Dayou Linhai Economic Zone, Linghai City 58,000 Huludao 1,042,000 Panjing Chemical Enterprises Zone Xingcheng Yingkou Industrial Park – 137,000 – Hainan (3 projects) Changjiang County 136,000 108,000 Dingan County Ledong County 145,000 Zhoushan (under construction) ZhZhoZho hushushanan ((un(undderder coco tnstnstrucructitiotio ))n)n) ZhZhooushhan (un(underd tnstns ucuctioo )nn Zhoushan (under construction) cc Ningbo Liangshan Prefecture 660,000 Yunnan (2 projects) Kunming City Hi-tech Zone Wenshan 49,000 448,000 Zhejiang (16 projects) 292,000 Haining 111,000 Haiyan 636,000 Huangyan 521,000 Huzhou 255,000 Jinhua 155,000 Lanxi 361,000 Longwan 130,500 Longyou Nanxun 494,000 Ningbo (Yinzhou) 625,000 Ningbo Daxie Development Zone Quzhou Wenzhou Wenzhou Wanquan Light Industrial Base Xiaoshan Yongkang – 380,000 550,000 – 765,000 242,000 Liaoning Province P Beijing eijiBeijing Municipality Municipalapaa Caofeidian Dalian Tianjin Floating Terminal Tianjin Binhai (under construction) Hebei Provincee Qingdao Shandong ong Province Henan Province Jiangsu Jia gsu Province ovi ceece Rudong Anhui Province Shanghai iii Zhejiang Province Jiangxi Province Fujian Province Putian Guangdong angdong Province Dongguan Jiufeng Dapeng Yuedong (under construction) Sichuan Province Hunan Province Yunnan Province Guangxi Province Beihai Tieshan Port Zhuhai Shenzheng (under construction) Hainan Province Total Connectable Population Tota Tota Total Number of projects : : 77,420,000 160
PIPELINE TECHNOLOGY JOURNAL 43 Regional Report 2.4. LNG IMPORTS The imported LNG was 25.8 Bcm, with long-term import contracts from Qatar, Australia, Indonesia, Malaysia, Papua New Guinea and spot imports mainly from Yemen, Algeria, etc. According to an incidents report from incomplete statis- tics released by www.gasshow.com, there were 658 gas explosions in China in 2015, more than 1000 people were injured and 116 killed. LNG Import in 2015 (Source: BP Statistical Review of World Energy 2016 Place of incidents in 2015 Source: http://safety.gasshow.com/ News_20160104/373489.html 2.5. GAS UTILIZATION In 2015, China’s natural gas consumption was 193.1 Bcm. From the consumption structure aspect, the industrial fuel consumption was accounting for 38.2% at a volume of 73.7 Bcm; the urban gas consumption was 62.8 Bcm, accounting for 32.5%; for power generation was 28.4 Bcm, accounting for 14.7%,; while for chemical industry was 28.2 Bcm, accounting for 14.6%. Number of deaths in 2015 Source: http://safety.gasshow.com/ News_20160104/373489.html 3. SOURCES OF GAS In 2015, China’s domestic natural gas production was 135 Bcm. In the same year China has imported pipeline gas and LNG from more than 10 importing countries. The total imported natural gas was 61.4 Bcm. China’s Gas Consumption Structure in 2015 (Source:China Gas Development Report 2016) 2.6. URBAN GAS INCIDENTS 3.1. GAS RESOURCES IN CHINA Annual urban gas consumption in China has been grow- ing for over two decades. However, due to the fact that majority of local governments pay more attention to build more infrastructure as quick as possible and lack of at- tention to maintenance in day-to-day operation, there has been more and more gas related incidents over the years. China’s primary onshore natural gas-producing regions are Sichuan Province in the Southwest (Sichuan Basin); the Xinjiang and Qinghai Provinces in the Northwest (Tarim, Junggar, and Qaidam Basins); and Shanxi Province in the North (Ordos Basin). China has delved into several offshore natural gas fields located in the Bohai Basin and the Panyu complex of the Pearl River Mouth Basin (South
44 PIPELINE TECHNOLOGY JOURNAL REGIONAL REPORT China Sea) and also is exploring more technically chal- lenging areas such as deepwater, coalbed methane, and shale gas reserves with foreign companies. China has found 505 sedimentary basins of different types. Till now the government has approved 1746 leases with the total area of 435.4 million km2. According to the results of new-round evaluation on the nationwide oil and gas resources carried out in 2005, the recoverable resources of conventional oil and gas in China are 25.5 billion ton for oil and 27 Tcm for natural gas. China is also abundant with unconventional oil and gas resources. Results of preliminary evaluation revealed that unconven- tional oil and gas resources are basically equal to con- ventional oil and gas resources in China. As exploration is intensified, there is still room for the increase of uncon- ventional oil and gas resources in China. existing pipelines planned pipelines pipelines in evaluation China’s Major Pipeline Infrastructure Network 3.2.1. Development of West-East Gas Pipeline Geographic location of 51 proved large gas fields in China (Source: Natural Gas Industry B, Volume 2, Issue 1, January 2015, Research Institute of Petroleum Exploration and Development, CNPC) 3.2. PIPELINES As of end of 2015, China has built Shanxi-to-Beijing, West-to-East, Sichuan-to-East, Central Asia and Si- no-Myanmar pipelines. A total length of about 64 thou- sand kilometers. China has constructed 12 LNG terminals with an annual receiving capacity of 43.8 million tons (18.2mcm), built 18 underground gas storages with 5.5 Bcm annual effective working gas capacity, built 6500 CNG/LNG stations and 13 marine LNG stations. A multi- source natural gas supply pattern of “West-to-East, North-to-South, Offshore Gas Going Onshore, Sup- ply-from-Nearby” has been formed. Road map of all three West-East Gas Pipelines Originally known as the First West-East Gas Pipeline which became operational in 2004, the West-East Gas Pipeline Project is now a natural gas supply system stretching from across China from east to west, all three West-East Gas Pipeline projects are in operation now. Consisting of trunk and branch pipelines and gas storages, the project delivers natural gas from Western China and Central Asia to the major target consumer markets in Southeast China, as well as users along the lines. It has a total length of more than 20,000 km, with an annual delivery capacity of 77 Bcm. The First West-East Gas Pipeline is mainly supplied by the Tarim gas province in Xinjiang. It runs from Lunnan Oil and Gas Field in the Tarim Basin to Baihe Town in Shanghai, with a total length of 4,380 km. Consisting of one trunk, three branches and other support pipelines, it can trans- mit 17 billion cubic meters of natural gas each year. The pipeline passes through 10 provinces (municipalities and
PIPELINE TECHNOLOGY JOURNAL 45 Regional Report Construction Site (Source: 2013 CNPC Corporate Social Responsibility Report) 3.2.2. THE MYANMAR-CHINA OIL & GAS PIPELINES autonomous regions), i.e., Xinjiang, Gansu, Ningxia, Shaanxi, Shanxi, Henan, Anhui, Ji- angsu, Shanghai, and Zhejiang. The pipeline was kicked off on July 4, 2002, completed and put into trial operation on October 1, 2004, and became commercial operational on December 30, 2004. The Second West-East Gas Pipeline is mainly supplied by gas from Central Asia. The 8,819km-long pipeline, consisting of one trunk and eight branches, runs from Horgos in Xinjiang, where it is connected with the Central Asia-China Gas Pipeline, to Shanghai and Hong Kong. This pipeline is capable of delivering 30 billion cubic meters annually for over 30 years. It passes through 14 provinces, municipalities and autonomous regions including Xinjiang, Gansu, Ningxia, Shaanxi, Henan, Hubei, Jiangxi, Guangdong, Guangxi, Zhejiang, Shanghai, Jiangsu, Hunan, and Shandong, as well as Hong Kong SAR. Construction of the second pipeline was started in February 2008, and it was completed and put into operation in December 2012. The Third West-East Gas Pipeline is mainly supplied by gas from Central Asia, with SNG in Xinjiang as the supplementary, It runs from Horgos in Xinjiang to Fuzhou in Fujian, crossing Xinjiang, Gansu, Ningxia, Shaanxi, Henan, Hubei, Hunan, Jiangxi, Fujian, and Guangdong. Consisting of one trunk and five branches, it stretches a total length of 6,840km with a designed annual delivery capacity of 30 billion cubic meters. Construction of the third pipeline was started on October 16, 2012, and completed and put into operation in October, 2016. The First, Second and Third West-East Gas Pipelines are interconnected and can be controlled in an integrated manner through the hubs in Zhongwei, Jingbian, Zaoyang and Ji’an. The four major gas provinces including Tarim, Changqing, Sichuan - Chongqing and Qinghai are connected through the Ji-Ning, Zhong- wei-Jingbian, Huai-Wu cross-link lines, and Zhongxian- Wuhan and Sebei-Xining-Lanzhou pipelines, laying a solid foundation for the forming of a nationwide gas pipeline network. Road-Map of Myanmar-China Oil & Gas Pipeline Source: https://www.shwe.org The Myanmar-China Pipeline Project consists of a crude oil pipeline and a natural gas pipeline. The oil pipeline is jointly invested and built by CNPC and Myanmar Oil
46 PIPELINE TECHNOLOGY JOURNAL REGIONAL REPORT and Gas Enterprise (MOGE). The gas pipeline is jointly invested and built by CNPC, MOGE, Daewoo International, KOGAS, IndianOil and GAIL. The Myanmar-China Gas Pipeline starts at Ramree Island on the western coast of Myanmar and ends at Ruili in Chi- na’s Yunnan Province. Running in parallel with the Myan- mar-China Crude Oil Pipeline, the crude pipeline is 1,016 mm in diameter with a distance of 793 km in Myanmar. It can deliver 5.2 Bcm/a upon completion of the Phase I project, and 12 Bcm/a upon completion of the Phase II project. Pursuant to the cooperation agreement, four gas off-take stations (Kyaukphyu, Yenangyaung, Taungtha and Mandalay) were established to unload less than 20% of the pipeline’s total delivery in Myanmar. the sales and purchase agreement for gas to be sup- plied via the eastern route (Power of Siberia gas pipe- line). The 30-year agreement provides for Russian gas deliveries to China in the amount of 38 Bcm per year. Gas supplies will start in December 2019 through a 3,000 kilometers pipeline. In September 2016, Gazprom and CNPC signed the EPC contract to construct a crossing under the Amur River within the trans-border section of the Power of Siberia pipeline. Construction in the Chinese territory started in April 2017. In May 2017, a temporary two-way checkpoint was opened on the Russian-Chinese border to provide unfettered access to the border area for construction equipment and personnel. On April 10, 2017, the Myanmar-China Oil & Gas Pipelines project was officially put into operation on the Maday Island in Myanmar as an oil tanker started offloading 140,000 tons of crude oil from Azerbaijan at the Bay of Bengal. 4. POLICY FRAMEWORK 4.1. THE 13TH FIVE-YEAR PLAN On 4 July 2017, the National Development and Reform Commission (NDRC) published a “Notice on Opinion of Accelerating and Advancing the Utilization of Natural Gas” (Circular 1217) on its website. This policy, jointly promulgated by NDRC and twelve other governmental agencies, had been under discussion for over a year before its final release. For this purpose, the NDRC has set forth the ground rules for this initiative, namely, (a) guidance for plans and policies, (b) reform and innovation through market open- ness, (c) advancement of the entire industry while focus- ing on key areas, and (d) cooperation between industries to promote healthy development. The target is that the consumption percentage of natural gas will constitute 10% in 2020 and 15% in 2030, while the underground effective work volume of natural gas will be 14.8 billion cubic meters in 2020 and 35 billion cubic meters in 2030. Circular 1217 also encourages participation of various entities through multiple ways such as pipeline gas, CNG, LNG, LPG, etc. Maday Island Port Source: http://www.cnpc.com.cn/en/nr2015/201502/2cea- 6be48e4e43e7a4bcfa77080d8314.shtml Maday Island is located at the southeastern part of Kyaukpyu. The Port of Maday Island consists of a 300Kt crude oil terminal, a workship dock, a 650,000 cubic meter water tank, a 38km-long channel, and a 1.2 Mcm oil tank farm. A 300Kt oil tanker has moored at the port and began to unload crude from the Middle East. 3.2.3. POWER OF SIBERIA The Power of Siberia gas trunkline will transport gas from the Irkutsk and Yakutia gas production centers to con- sumers in Russia’s Far East and China (eastern route). In May 2014, Gazprom and China National Petroleum Corporation (CNPC) signed China’s Energy Consumption Targets (Source: Natural Gas Industry B, 2017, CNPC )
PIPELINE TECHNOLOGY JOURNAL 47 Regional Report NDRC also provided an outline of key policies, including but not limited to: Energy cooperation plays a big role in this initiative. On May 12, 2017, Chinese NDRC and NEA have published a white paper on this sector of the BRI. • • • • The encouragement of the exploitation of domestic conventional gas, deepwater and unconventional gas. Participation by private companies in overseas natural gas exploitation, LNG procurement, and the construction and development of LNG receiving ter- minals and pipelines will also be encouraged. The pricing mechanism for industrial gas and resi- dential gas will become more market-oriented and improved to remove intermediate links and any unreasonable allocation of price on power transporta- tion and distribution. The establishment of a mechanism to provide free- dom to select source and means of supply. The provision of local government financial support to projects promoting pipeline construction, LNG filling stations, and increased capacity of existing LNG re- ceiving terminals. In addition, NDRC and NEA also released in this May “Me- dium - and Long-term Oil and Gas Pipeline Planning”. The Planning points out that China will take into full account natural gas and LNG markets, domestic and internation- al resources, pipeline and sea transportation ways, and will accelerate the construction of natural gas pipeline network, adhering to the principles of “to transport the natural gas from the West to the East, to transmit natu- ral gas from the North to the South, and to land offshore natural gas”. By 2025, a national fundamental network of “major interconnection and local network” for natural gas will be gradually formed. The Belt and Road Initiative seeks to foster energy coop- eration in order to jointly build up an open, inclusive, and beneficial community of shared interests, responsibility and destiny. The Initiative also aims to improve regional energy safety and to optimize the distribution of energy resources. It will integrate regional energy markets and push forward the green and low-carbon development of regional energy. By doing so, the scheme will meet increasing demand for energy and advance economic development in countries involved in the Initiative. The white paper also emphasized on openness and inclusiveness of this cooperation, importance of policy coordination within projects and further cooperation with all related international organizations such as UN, G20, BRICS and IEA etc. 5.2. MARKET-ORIENTED REFORM China’s rapidly growing natural gas demand over the past few years has opened up opportunities for independent Chinese energy companies to operate in the LNG space and in unconventional gas production. In 2013, JOVO Group became the first private Chinese company to own a majority stake in a regasification terminal, and the company signed a long-term contract with Malaysia’s Petronas, marking the first private com- pany to hold a long term LNG purchase agreement. The government initiated a new policy in early 2014 to allow access rights to third party companies for supplying natural gas to LNG termi- nals, providing more supply opportunities from firms involved along the entire 5. OUTLOOK 5.1. BELT AND ROAD INITIATIVE (BRI) Simply explained, Belt and Road Initiative (BRI) is China’s top-down plan to build new ports, roads, railways, oil and gas pipelines, power plants, and special economic zones across Asia and Africa in an attempt to integrate the en- tire region into a massive market spanning 60 countries and a third of the world’s GDP. LNG value chain, from the upstream gas procurement to the downstream distribution. In recent years, Sinopec has established such companies as Sichuan Natural Gas Investment Co., Ltd., Sichuan Nat- ural Gas Chuandong Energy Co., Ltd. and Sinopec Chongq- ing Natural Gas Pipeline Co., Ltd. through cooperation with main local gas companies, local governments and other relevant enterprises in the energy industry in Sichuan and Chongqing. On March 1, 2016, PetroChina and Chongq- ing Gas Group established a joint venture – Chongqing
48 PIPELINE TECHNOLOGY JOURNAL REGIONAL REPORT Natural Gas Pipeline Co., Ltd., which is the first joint venture about natural gas pipelines established by Pet- roChina nationwide together with a local gas company. Overall, opening of national oil and gas pipelines will be inevitable, and natural gas pipeline networks of diversi- fied investment subjects will increase. 5.3. OPPORTUNITIES AND CHALLENGES The U.S. Energy Information Administration (EIA) esti- mates from its most recent report on shale oil and gas resources that China’s technically recoverable shale gas reserves are 31.6 Tcm, the largest shale gas reserves in the world. The technology required for an efficient and safe E&P out of these reserves in China is however not quite there yet, there is still a long way to go before China can take full advantages of its gas reserves. 5.4. TERRITORIAL DISPUTE IN THE SOUTH CHINA SEA Asia’s robust economic growth boosts demand for energy in the region. EIA projects total liquid fu- els consumption in Asian countries outside the Organization for Economic Cooperation and Develop- ment (OECD) to rise at an annual growth rate of 2.6%, growing from around 20% of world consumption in 2008 to over 30% of world con- sumption by 2035. Similarly, Shale Gas Reserve Holders Territorial Dispute in the South China Sea
PIPELINE TECHNOLOGY JOURNAL 49 Regional Report Authors Dr. Klaus Ritter EITEP Institute President Ritter@Eitep.de Jing Yuan Gao EITEP Institute Freelancer Gao@Eitep.de Euro Institute for Information and Technology Transfer non-OECD Asia natural gas consumption grows by 3.9% annually, from 10% of world gas consumption in 2008 to 19% by 2035. EIA expects China to account for 43% of that growth. With Southeast Asian domestic oil production projected to stay flat or decline as consumption rises, the region’s countries will look to new sources of energy to meet domestic demand. China in particular promotes the use of natural gas as a preferred energy source and set an ambitious target of increasing the share of natural gas in its energy mix from 3% to 10% by 2020. The South China Sea offers the potential for significant natural gas discoveries, creating an incentive to secure larger parts of the area for domestic production. Continued territorial disagreements by countries bor- dering the South China Sea, including ownership of the Spratly and Paracel Islands, have hindered efforts for joint exploration of hydrocarbon resources in the area. It is very clear that the chinese government is willing to further develop its natural gas industry. Not only does it fits into their energy structure reform, it also helps reduce air pollution. Despite the slowdown due to consistent low oil price, Beijing is determined to develop country’s natural gas industry. If what happened in the past 30 years in China in terms of reform and development is any indication, we should expect a dynamic and fast growing natural gas industry. References • • • • • • • • • • • • • China overview: http://www.worldbank.org/en/country/china/overview The U.S. Energy Information Administration (EIA): https://www.eia.gov/beta/international/ analysis.cfm?iso=CHN Real-time air quality map: http://berkeleyearth.org/air-quality-real-time-map/ Exploration and development of large gas fields in China since 2000: NDRC article: http://www.bakerbotts.com/ideas/publications/2017/07/ndrc-new-policy http://www.ndrc.gov.cn/zcfb/zcfbghwb/201707/t20170712_854432.html White Paper China NEA: http://www.nea.gov.cn/2017-05/12/c_136277478.htm Sinopec: http://www.sinopec.com/listco/en/investor_centre/reports/2016/ http://www.sinopecgroup.com/group/en/companyprofile/Companyreportsandpublications/ CNPC: http://www.cnpc.com.cn/en/2015AnnualReportonline/2015_Annual_Report_online.shtml http://csr.cnpc.com.cn/csr/xhtml/PageAssets/CSRReport2012.pdf Natural Gas Industry B CNOOC: http://www.cnooc.com.cn/col/col7151/index.html Power of Siberia: http://www.gazprom.com/about/production/projects/pipelines/built/ykv/ Oilsns ENN Energy: http://ir.ennenergy.com/en/ir/financial_results.php http://www.enn.cn/wps/portal/ennen/profile/!ut/p/b1/04_SjzQzMTA3MjG2NNWP0I_KSyzL- TE8syczPS8wB8aPM4s2CnNwdnQwdDdxdfJ0MHIPd3cwtg5wMjUyN9HOjHBUBRE1f7w!!/?pa- geid=profile Towngas: https://www.towngas.com/en/Investor-Relations/Financial-Information/Annual-Re- port/2017/Annual-Report-2016 http://www.sohu.com/a/112371546_225752
ASSURING THE INTEGRITY OF SUBSEA PIPELINE BUTT WELDS THROUGH DESIGN, CONSTRUCTION AND OPERATIONAL LIFE Harry Cotton > Wood plc.; Istvan Bartha > Formerly Wood plc.
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 51 ABSTRACT Subsea pipelines may be designed, using strain based approaches, to operate under thermal longitudinal tensile stress levels approaching and exceeding the pipe material yield strength. A particular concern is the integrity of the butt welds made using the mechanised methods required for economic pipe lay from a barge offshore. Weld flaws such as lack of fusion or penetra- tion are unavoidable which presents a concern that they may propagate by fatigue and fracture, under operation- al stresses, to cause hydrocarbon release. The most severe stresses were predicted for the in-place cases due to thermal loading limited by controlled lateral buckling. The cyclic loading due to shut downs was signif- icant and there were tensile stress levels approaching and exceeding the yield strength. These were justified using strain based design approaches based on DNV-OS-F101 (Ref 01) and SAFEBUCK (Ref 03). This includes ECA to confirm the integrity of the welds with quality levels (max- imum allowable flaw size, Toughness) which are practical to achieve and agree with the welding contractor. The weld integrity is confirmed by fracture mechanics analysis, called engineering critical assessment (ECA), which predicts a maximum allowable flaw size for the automatic ultrasonic testing (AUT) conducted on the pipe lay vessel (barge). An important input to the ECA is the weld toughness (fracture initiation resistance) determined by fracture mechanics tests on welds at minimum design temperature. For pipelines conveying sour hydrocar- bon additional fracture mechanics testing in simulated internal H2S environment was required which recorded significant reduction in toughness through the effects of corrosion. The toughness levels were in some cases insufficient for the ECA to confirm weld integrity using the published equations (BS7910, DNV-OS-F101). The problem was resolved by detailed 3D finite element analysis (FEA) of flaws assumed in the butt welds to improve accuracy of analysis and reduce excess conservatism. The management of ECA and associated design and con- struction activities (e.g. WPQT, AUT) to minimise the risk to project schedule is discussed. Published documents (e.g. DNV-OS-F101, EPRG) provide weld maximum allow- able flaw sizes based on previous ECA and/or large scale tests as an alternative to ECA but they have not yet been widely adopted for subsea design/construction projects. According to DNV-OS-F101, such confirmation of integrity by ECA is mandatory for nominal tensile strain levels ex- ceeding 0.4% strain in operating pipelines and regardless of strain level if the specified workmanship acceptance criteria, for non-destructive testing (NDT), are to be relaxed. The ECA is a fracture mechanics based calculation proce- dure relating the three main variables controlling failure through fatigue, fracture/plastic collapse from planar flaws: 1. Stress (cyclic and static) 2. Material Properties (Toughness /fracture resistance determined in tests) 3. Flaw size. If two of these variables are known a safe limit for the third can be estimated for avoidance of such failure. The general approach is as follows: 1. Assume initial flaw (Maximum acceptable by NDT) 2. Predict growth of the flaw under cyclic loading during installation and over the operating life. 3. Predict if the grown flaw will initiate fracture under the maximum tensile stress (strain). The latter step involves predicting a minimum toughness requirement to be achieved in fracture mechanics testing of trial welds. Finally the paper reviews how the integrity of the butt welds in the operating pipelines is managed by external survey, monitoring of operating conditions and in-line inspection. FLAW SIZE GENERAL INTRODUCTION This paper is based on experiences in application of ECA, of butt welds, in the design and construction of carbon steel (X65/X70) subsea pipelines/flowlines for the pro- duction of hydrocarbons. Installation was from lay vessels using S lay or J lay, rather than reeling, so that the installation tensile stress levels were maintained below the yield strength. The welding on the lay vessels is conducted using mech- anised gas metal arc welding (GMAW bug and band). The procedures are developed for high speed (productivity) to minimise costly barge time. Welding is typically conduct- ed with the torch restricted to the joint outside using a narrow weld groove (narrow gap) to minimise the amount of filling required. Precise control of the initial joint fit up and electrode tip position by the operator through each weld pass is essential to avoid defects. Some incidence of planar flaws such as lack penetration or fusion are unavoidable with the currently available technology.
52 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY ACCEPTANCE CRITERIA For many years, the empirical workmanship of the pipe- line welding standard API 1104 (Ref 02) have allowed such flaws for inspection by radiography with maximum length of 25mm (1 inch) surface breaking and 50mm embedded (2 inch). Inspection by radiography using photographic film has largely been replaced by AUT for welding pipelines on a lay vessel. Nevertheless, the API 1104 criteria remain an industry recognised acceptable quality level for pipeline welding and similar criteria have been adopted by other codes (Ref 01,04) such as those of DNV-OS-F101 (Ref 01) specifically for AUT (See Table 1 below). Flaw Height mm Length mm External Surface Breaking Embedded Internal Surface Breaking (Root) 4 4 4 25 50 25 Table 1 Maximum allowable flaw Sizes (AUT workmanship criteria) DNV- OS-F101 2013 (> 25mm thickness example). Flaw sizes presented do not include any deduction for AUT sizing tolerance. Those presented in DNV- OS-F101 have 1mm deducted for AUT sizing accuracy. Any restriction to the above workmanship criteria can be difficult to agree with installation contractors. It pres- ents concerns of excessive stringency resulting in high weld repair rates slowing production. Repairing of welds requires halting the pipe lay vessel and excavation of the defect by arc air gouging and/or grinding then re-welding using manual welding processes (e.g. GSFCAW, SMAW). The final inspection is by manual ultrasonic testing (MUT) which is less reliable than the AUT applied to the original production weld. Furthermore, the mechanical properties of the repair weld tend to be inferior to the original weld. Considering the above, an objective of the ECA at the design stage is to justify flaw sizes at least equal to the workmanship criteria by refinement of design, stress anal- ysis and ECA methodology. In addition, there are potential advantages in using ECA to relax the workmanship. However, limits are typically placed on the relaxation due to concerns that otherwise the contractor will have reduced incentive to maximise quality and the frequency of flaws could rise. One approach is to define an allowable flaw size locus (Fig 1) which complies with the workmanship criteria lengths restriction at 4mm height (Table 1) but allows lon- ger lengths for smaller heights. The allowable flaw sizes (Fig 1) are of equivalent severity to the stated workman- ship criteria dimensions (Table 1) in terms of toughness requirement predicted in ECA. Some projects have allowed significant relaxations to the actual workmanship criteria sizes (Table 1) based on ECA. The level of relaxation varies between projects depending on the perceived conservatism (safety margins) of the Figure 1: Example of maximum allowable flaw size locus based on ECA. It is consistent with the AUT workmanship criteria of DNV-OS-F101 2013 (Table 1 above) for 4mm flaw height but defines longer lengths for smaller heights (<4mm) and gives lengths for larger heights (>4mm). (Flaws exceeding 4mm height only acceptable if they actually comprise a number of flaws above each other and interacting (i.e stacked).) Flaw sizes presented do not include any deduction for AUT sizing tolerance. ECA, reliability of the welding and AUT, consequences of failure, operational inspectability and economic consider- ations. However, according to DNV–OS-F101 relaxation of the workmanship criteria is not appropriate if the nominal strain level exceeds 0.4%. FATIGUE The ECA includes assessment to account for possi- ble crack extension due to fatigue crack growth under longitudinal cyclic loading in installation and in-place (operation). The cyclic loading is predicted to occur during installation under the effect of waves causing vessel motion and in operation, at lateral buckles, due to shut downs (thermal/pressure cycles). Another source of in- place fatigue is vortex induced vibration (VIV) at spans but on the projects experienced this was prevented by intervention where necessary to limit span lengths below the critical length at which the vibration occurs. The prediction of fatigue crack growth is based on a nu- merical integration of the Paris Law and detailed equa- tions are given in BS7910 (Ref 06). The fatigue loading during installation was typically pre- dicted to only cause a small amount of crack extension (e.g. <0.7mm) but that in operational growth was more severe (e.g. 1.4 mm) (Table 2). Stage Initial AUT After Installation with maximum vessel hold time. 25 years Operational shut downs Flaw Dimensions, mm Height Length 4.0 4.7 6.1 25 27 30 Table 2 Example of internal (root) surface breaking flaw fatigue growth through installation and operation exposed to wet hydrocarbon including H2S. 16 inch OD, 25mm thickness.
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 53 The predicted crack growth rate depends on the materi- al type and the environment defined by a fatigue crack growth laws (FCGL) based on upper bound fits to results of fracture mechanics fatigue tests in relevant environ- ments (Fig 2). There are published FCGL in BS7910 for steels in air (non-corrosive) but none strictly applicable to the corrosive environments to which surface breaking flaws in pipelines are subjected. steel (Ref 08). Therefore, the published FCGL for marine environments (Ref 06) are potentially non-conservative since they are valid for higher frequencies representative of wave loading (0.2Hz). A FCGL based on fatigue tests in simulated sea water CP environment, with low frequency, should be considered for assessment of external flaws unless there is confidence in the reliability of the field joint coating to protect much of the external surfaces. It should be noted that in addition to fatigue crack growth assessment the design check based on S-N curves is mandatory (Ref 01). These typically predict longer fatigue lives, even including the required safety factor cycles (e.g. design factor=3), compared to the fatigue crack growth assessment. The S-N curves , like FCGL as discussed above, must take account of the effects of the environ- ments in reducing fatigue life through the effects of corrosion. For this purpose , WGK projects engaged TWI to conduct project specific fatigue tests on as-welded specimens (without introduced notches or cracks) to fa- tigue testing at low frequency (<0.01Hz) in simulated H2S environment (Ref 08). TOUGHNESS TOUGHNESS REQUIREMENT The ECA predicts the toughness test result requirement for the assumed flaw (Section 2.0) after fatigue crack growth (Section 3.0) not to initiate fracture under the maximum in-place tensile stress. The methodology follows DNV-OS-F101 (Ref 01) which refers to BS7910 failure assessment diagram (FAD) approaches (Ref 06) for the detailed equations. Howev- er, the level of conservatism of these methods for strain (stress) levels much in excess of elastic design limits, in operating pipelines, is not trusted. Fortunately, there have been considerable advances in methods of detailed 3D FEA of flaws to predict crack driving force and confirm ECA, of operating pipelines, for strain levels up to at least 0.8 % strain. This allows designs with strain levels exceeding 0.4% to be justified potentially removing the need for expensive interven- tion (e.g. sleeper, planned buckle) to maintain strains below this limit. According to DNV-OS-F101 such 3D FEA is required, for operating pipelines, if the strain levels exceed 0.4% when the single edged notch bend (SENB) test is used and regardless of strain level for the less conservative single edged notch tension (SENT) test. An example of the relationship between ECA predicted toughness requirements and applied true strain is shown in Fig 4 comparing BS7910 FAD and 3D FEA crack mod- elling. The internal weld root flaw of 4mm x 25mm initial size grown by fatigue (Table 2) was assumed. Figure 2: Example of fatigue crack growth rate data The internal hydrocarbon environment includes water and CO2 which is corrosive to carbon steel so that corrosion inhibitor is normally injected but it is not fully effective. Furthermore, in some cases H2S is present which assists crack growth by causing hydrogen, generated by corro- sion reactions, to be absorbed by the steel. To address these concerns WGK design/construction projects have engaged TWI to conduct fracture mechan- ics fatigue testing, in simulated internal environments, on representative test welds to generate FCGL for ECA. The main environmental variables are pH, the partial pressures of H2S and CO2, temperature and the concen- tration of corrosion inhibitor. The effects of the internal environment can more than double the crack growth compared to that predicted in air. A further consideration is that a pipeline shut down, causing a stress cycle, can take 12 or more hours. This potentially gives more time for detrimental effects of corrosion and hydrogen to increase the incremental crack growth. Therefore, the testing frequency is much slower (e.g. <0.01Hz) than normally applied (Ref 08) for fatigue testing (e.g. wave loading , 0.2Hz) requiring long testing programmes which need to be started at a sufficiently early stage in the project schedule (Section 6). It should be noted that the above frequency effect also applies to flaws breaking the external surfaces exposed to the marine environment with cathodic protection (CP) which can also cause hydrogen to be absorbed into the
54 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY The minimum specified tensile properties of the seamless pipe were assumed (X65, 450 MPa SMYS, Temperature de-rating at 80°C) represented by a stress/strain curve showing typical Luder behaviour (Fig 3). This was consis- tent with the original FEA based stress analysis of lateral buckling which predicted the stress (strain) levels assumed in ECA. The weld metal strength was specified to exceed the pipe maximum strength but this was not accounted for in the ECA following the BS7910 guidance that in general the minimum tensile properties of the parent material, weld and heat affected zone (HAZ) should be assumed. Figure 3: Luder stress/strain curve assumed for seamless pipe. The effects of weld residual stress on toughness require- ment is included in both curves (Fig 4) using the BS7910 methodology in which it is assumed equal to the yield strength but with some relaxation under the applied stress. There is no widely accepted approach for including residual stress directly into the FEA models. In the case presented the BS7910 FAD 2B (Note 1) ap- proach (Fig 4, Plot A) appears to over predict toughness requirement , according to FEA (Fig 4 Plot B) below about 0.6% strain (i.e. over conservative) but under predicts at higher strains (i.e. non-conservative above 0.6% strain). TOUGHNESS TESTING (MECHANICAL PROPERTIES) GENERAL The main toughness testing method to support ECA of subsea pipelines, for at least the past 25 years, has been SENB crack tip opening displacement (CTOD) tests on specimens of full pipe thickness (Ref 10). A set of three tests are notched in the weld metal centre line and at three to six in the fusion line (HAZ) and tested at the min- imum design temperature (MDT). Toughness is typically recorded as single CTOD (Note 1) values at maximum load with fracture mode being ductile tearing. The level of toughness achieved varied widely between the different projects with it being difficult to always guarantee a mini- mum CTOD toughness much in excess of 0.3 mm. The previous plots of J-Integral toughness requirement verses applied strain are presented again in Fig 5 in terms of CTOD toughness. This indicates (Fig 5 , Plot A) that using the BS7910 FAD approach above a strain of only about 0.25% the 0.3mm minimum CTOD result is not al- ways sufficient to justify workmanship criteria flaws size after fatigue crack growth (Table 2). In such cases the re- finement of the analysis using FEA crack modelling may be used, to remove excess conservatism and help justify acceptability of the test result (Fig 5, Plot B). Figure 5: Example of the relationship between CTOD toughness and true strain. BS7910 FAD approach (Plot A) is compared to FEA based methods (Plot B). In BS7910 assessment the uniaxial stress/strain has been elevated to take account of operating hoop stress (Von Mises effect, Equation A.8, Ref 01). Weld axial misalignment and toe stress concentration effects excluded for comparative purposes. Figure 4: Example of the relationship between toughness as J Integral and true strain. BS7910 FAD approach (Plot A) is compared against FEA based methods (Plot B). In BS7910 assessment the uniaxial stress/strain has been elevated to take account of operating hoop stress (Von Mises effect, Equation A.8, Ref 01). Weld axial misalignment and toe stress concentration effects excluded for comparative purposes. The CTOD parameter has now been replaced by the J inte- gral according to DNV-OS-F101 (Ref 01) and BS7910 (Ref 06). Testing laboratories now adopt standardised practice (Ref 10) to determine both measures of toughness in the
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 55 same SENB test. The parallel sets of results indicate that the previous conversion factor of BS7910 2005 ,used to estimate CTOD requirement from J integral in ECA, were somewhat over conservative (Fig 5 , Plot C) compared to those in BS7910 2013 (Fig 5 Plot A) which were shown to be more accurate but still conservative. SSC tends to initiate from zones of susceptible micro structure such as hard weld HAZ, under the influence of stress, even in the absence of pre-existing weld flaws. The severity of environment depends on the H2S concentra- tion and the pH as defined in NACE MR 0175/ISO 15156 (Ref 09, Fig 6 below). Furthermore, in general higher toughness levels may be demonstrated by the SENT test, loaded primarily in ten- sion, compared to the SENB test which is loaded in bend- ing to cause a more severe condition in terms of crack tip constraint. It can be argued that the tension loading of the SENT test is more representative of pipeline butt welds which are subjected to mainly membrane stress (axial) through the wall thickness even if subjected to bending across the pipe sections. The SENT test has been widely applied for ECA of high strains occurring in pipe reeling for a number years (Ref 07). It has also replaced SENB test as the primary frac- ture mechanics specimen geometry in DNV-OS-F101 (Ref 01) for ECA of installation and operating cases and been recently standardised (Ref 11). Nevertheless, the SENB retains popularity for ECA of op- erating pipelines. It is sometimes preferred as providing an additional margin of conservatism against the uncer- tainties in testing and ECA (e.g. Table 7, Item 14). SENB also has the advantage, compared to SENT, that it can be used for ECA of operating pipelines up to 0.4% nominal strain without the need for FEA crack modelling (Ref 01) which requires specialised software and resourc- es not yet widely available. Of course this advantage is lost in the unlucky event that the SENB toughness results are insufficient so that the FEA modelling is required in an attempt to reduce excess conservatism of the ECA. Advances in software, hardware and more harmonisation of FEA modelling procedures will hopefully help to pop- ularise this powerful method for ECA of operating pipe- lines.These developments should also assist the populari- sation of the SENT test. H2S EFFECTS In the case of some pipelines the hydrocarbon conveyed was predicted to possibly become contaminated by H2S after some years of operation. It is widely recognised that in the presence of wet H2S carbon steels are susceptible to sulphide stress cracking (SSC) due to hydrogen gener- ated by corrosion reactions being absorbed by the steel to embrittle it (Ref 09). In order to ensure resistance to SSC the pipe welds must be specified with some restriction on hardness (250 Hv10 in weld root) and chemical (Ref 09). However, these precautions do not ensure that the H2S will not reduce resistance to crack propagation from pre-existing weld flaws (i.e. reduce toughness). In order to address these concerns some projects required fracture mechanics tests in simulated internal H2S environ- ments to support ECA of the pipelines. They were predicted to be subjected to nominal tensile strains below 0.3%. The effects of hydrogen in reducing toughness tend to increase with reduction in the strain rate (loading rate, Ref 13,18). Therefore, to represent pipeline welds conser- vatively the loading rate must be much slower than a conventional fracture mechanics test sometimes re- quiring a number of days to complete the loading cycle. Alternatively, tests may be conducted under a constant load, corresponding to a given applied toughness level, for longer periods (e.g. 30 days). The WGK projects assessed pipelines which could be sub- jected to the maximum stress for a month or more so a 30 day constant load SENB test was selected. The loss of load within the 30 day period test is indicative of signifi- cant crack propagation assisted by the H2S environment. In this event the test is classed as a failure and the actual toughness is somewhat lower than that corresponding to the test load. On the other hand, tests which last 30 days with no detectable load drop indicate that the increase in specimen crack size, during the test period, was insignif- icant and that the test applied toughness level is conser- vative (See Table 7, Items 16 and 17). Using the above approach, the degree of weld metal toughness degradation through the effects of H2S has varied between different projects. In one case when test- ing in a relatively severe environment (Case 1, Fig 6) the toughness was completely diminished from about 0.4mm CTOD recorded in air to <0.04mm in the H2S environment. The level of toughness corresponded to flaw sizes well below the workmanship criteria. Other projects testing in less severe environments (Case 2, Fig 6 below) , with different welding procedures and specimen dimensions, indicated that the air toughness (0.7mm) reduced signifi- cantly (<0.4mm) in the H2S environment yet it equated to the workmanship criteria in ECA modified by 3D FEA..
56 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY Figure 6: Diagram indicating relative severity of environments (NACE MR0175/ ISO 15156, Ref 09). There is no standardisation of toughness testing pro- cedures for H2S environments. This is an area of active research by TWI and DNV (Ref 12,14). Factors to consider are as follows: • • • • Determination of R curve or single value toughness. • • Definition of test failure • Measurement of active propagation in the test. Loading rate. Specimen geometry (SENT or SENB). Increasing load or constant load test. Environmental conditions (pH, H2S, inhibitor). a few welds in the pipeline. An example is the case of a pipeline in which the tensile strains were below 0.15 % ex- cept in the event of formation of an unplanned buckle in which they could be significantly elevated (0.26% nominal strain). However, only 2 welds could be subjected to the elevated strain (Fig 07) and it would be restricted to only about a third of their circumferences (Fig 08). Further- more, probabilistic buckling analysis following SAFE- BUCK (Ref 03) indicated that the buckle had less than a 6% probability of forming. Figure 7: Stress Distribution along Flowline Lateral Buckling (2 welds corre- spond to 25m (0.025 km)) exceeding about 0.15% strain Furthermore, there is a need for research (Ref 12,14) to clarify how the toughness in H2S environment is related to hardness, micro-structure, steel composition and toughness in air. CONSERVATISM OF ECA In applying ECA, prior to construction, the approach is to hypothesise a weld flaw assuming that the relevant vari- ables (Table 7) happen to coincide at worst case levels. This intuitively appears to be excessively pessimistic and potentially over conservative but it is otherwise difficult to justify the assessment. There is still insufficient published guidance to use probabilistic fracture mechanics ap- proaches on design projects. Possible refinements to reduce conservatism, which have been reviewed on WGK projects, are as follows: 1. Take account of weld metal over matching (Item 8, Table 7) the pipe strength, by FEA crack modelling in- cluding the different tensile properties of the pipe and weld. The separate cases of pipe with lower bound and upper bound tensile properties were assessed. 2. Take account of through life reduction in tensile stress (Item 12, Table 7) with repeated cycles. A further conservatism of the operational ECA is that the assumed worst case cyclic and maximum tensile stress are associated with lateral buckles and localised to only Inner Circumference Mid-Wall Outer Circumference 3,5E-03 3,0E-03 2,5E-03 2,0E-03 1,5E-03 1,0E-03 5,0E-04 0,0E+00 i n a r t S l a i x A e u r T 0 10 20 30 40 50 60 70 80 90 Angle Around Circumference (Degrees) - 0 at Highest Strain Position Figure 8: Stress Distribution around Circumference at the Crown of Lateral Buckle (60 degrees corresponds to <0.15% strain). As explained above, repair welds have presented concern since they have tended to have inferior toughness and ten- sile properties to the production welds and are inspected by MUT which is less reliable than the original AUT. However, this must be considered against the unlikely event of a repair weld , which are typically required for less than 2% of the production welds, occurring in the localised high stress zone with a “new” significant flaw reintroduced. A methodology to estimate probability of failure from in- formation of the type described above would be beneficial.
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 57 DELIVERABLE Product composition CONTENT H2S level Design or stress Stress input data for ECA. Pipe analysis reports dimensions and grade Design Max flaw size and toughness re- Operational ECA Linepipe specification/ quirement under operational stress Linepipe tensile properties. Weld- RESPONSIBILITY Owner/Operator Design Contractor Design Contractor Owner (or Design Contrac- procurement ability. Achievable HAZ CTOD. tor or Installation Contractor) Welding specification Weld toughness and strength test- Installation Final Installation stress levels ing requirement. Misalignment level. analysis report Installation ECA Welding procedure qualification Final ECA Max flaw size and toughness re- quirement under installation stress Toughness levels and weld metal strength levels. Max flaw size and toughness Design Contractor (or requirements under all stress (In- Installation contractor) AUT qualification AUT sizing accuracy and confirma- stallation and operation). AUT acceptance criteria tion of probability of detection. Max allowable flaw size for AUT interpreter. Installation contractor Installation contractor Table 3 Project activities related to ECA and division of responsibility Design Contractor Installation contractor Installation contractor Installation contractor between the different parties including owner/operator, design contractor and installation contractor (welding contrac- tor). It is important that these activities be co-ordinated between the different parties and the departments within them. The schedule risks in ECA and their mitiga- tions are summarised in Table 4. Previous projects, limiting nominal ten- sile strains below 0.4%, have relied on the installation contractor to complete the final ECA of installation and in-place (Operational) cases even when the in- place design was the responsibility of a separate design contractor. In this case the ECA is not reported until the in-place detailed design is largely complete. This presents the risk that if the ECA does not conclude achievable criteria (AUT, tough- ness) it is difficult and costly to revise the original design analysis in an attempt to reduce stress levels assumed. At the later stages of a project, approaching installa- MANAGEMENT OF ECA IN DESIGN AND CONSTRUCTION The ECA is effectively part of the design process to confirm integrity of the welds. It is also concludes the maximum allowable flaw size of the AUT accep- tance criteria for sentenc- ing the welds on the pipe lay vessel. Therefore, pipe lay cannot begin until the ECA is completed and agreed with all parties so it presents a schedule risk which must be managed. The ECA is related to various activities including design analysis, pipe and weld specification, test- ing and AUT qualification which provide input data to ECA and/or depend on its conclusion. The Table 3 summarizes how the responsibility for these activities may be divided RISK CAUSE CONSEQUENCE MITIGATION Ensure design stress analysis Integrity ECA is not Pipeline failure Reduced life and ECA is conducted by competent consultants and conservative Restricted operation verified. Sub-sea repair Ensure material/weld testing Monitor pipeline operation against design assump- tions. Ensure ECA assumed flaw size and mechanical properties are conservative but practical to achieve. is sufficient and verified. Ensure ECA is conducted by competent consultants and verified. Specify minimum toughness requirement prior to Enquire achievable contract award. toughness (CTOD) prior to Ensure pipe (free issued) contract award (Request has required weldability and historical data). toughness levels. ECA method is excessively conservative Welding proce- dure qualification AUT criteria too test results in air stringent. are lower than expected Slow welding speed/ high repair rate. Schedule risk/ Installation cost Predicted Stress level is too high and equates to stringent flaw size. Welding proce- dure qualification test results in H2S environment are lower than expected Table 4 Risks in ECA and mitigation Include ECA in design stage Do not leave ECA (installa- Delay to to confirm acceptability of tion and operation) just to installation start stress levels. installation contractor! Ensure suitable test method and interpretation of results. Only specify H2S tough- ness testing if there Early testing on representa- is a credible risk of tive test welds prior to welding significant H2S. procedure qualification Do not specify as a “nice to may be needed. have” H2S rating.
58 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY Flaw Dimensions ,mm Item Variable Height , 3 4 5 Length 90 35 25 1 The flaw sizes assumed in ECA correspond to the maxima accepted by AUT but increased by the maximum predicted under-sizing tolerance. The AUT is proven by qualification to confirm the sizing tolerance and that there is at least a 90% probability of detecting the ECA maximum allowable flaw sizes with 95% confidence (Ref 01). Table 5 DNV-OS-F101 Generic ECA Allowable flaw sizes (>16 inch OD), 25mm thickness, 0.4% applied strain maximum. Fracture mechanics toughness requirement J 0.5=400 N/mm, J1.0 = 600 N/mm. X65 pipe. Flaw Dimensions ,mm Height Length , t Length ( t= 25mm), mm 3 4 5 7t 5t 3t 175 125 75 Table 6 Allowable flaw sizes by EPRG Tier 2, 25mm thickness, 0.5% applied strain maximum. No fracture mechanics test results requirement. X65 pipe. tion start, the projects become more schedule driven and there may not be the time and resources available for the detailed analysis needed to conclude ECA to the full satisfaction of all parties. The above risks may be mitigated by the design con- tractor conducting a fully detailed ECA , including 3D FEA if necessary, as part of the design process even when the maximum nominal tensile strain has been agreed as less than 0.4%. The schedule risks are further aggravated if the project requires fatigue and/or fracture testing in the H2S en- vironment (Section 3.0, 4.2.2). This is due to the uncer- tainty in methods and results which will be obtained and the long test durations required (Section 3.0, 4.2.2). This can be mitigated by conducting early testing at the design stage, on representative test welds, prior to the main welding procedure qualification test (WPQT) by the appointed installation contractor. ALTERNATIVE TO ECA As discussed above, ECA may require significant re- sources on a project for analysis, management and even negotiation. It presents uncertainty in results of analysis and testing to present a schedule risk. It is interesting to question if there are cases where the integrity of pipeline butt welds, subject to inspection by AUT, can be assured without ECA provided the internal environment is not sour. According to DNV-OS-F101, the ECA is not strictly re- quired for strain levels below 0.4%. It is sufficient to assure resistance to fracture/fatigue by charpy impact testing, fatigue assessment using S-N curves and AUT meeting the applicable workmanship criteria (Table 1 be- low) for non-sour environments. 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 Flaw are assumed to be sharp and crack-like. Maximum weld axial weld misalignment causing SCF. Fatigue is assumed to occur at maximum rates (Upper bound FCGL). The very maximum number of stress /cycles (operational shut downs) anticipated is assumed. Wall thickness assumed is reduced below the nominal to account for manufacturing tolerance and corrosion. Lower bound tensile properties and sometimes also upper bound. Typically the weld metal is assumed to match the pipe in strength and over matching is not considered Weld residual stress equal to the yield strength after welding. The stresses (strains) assumed are derived with conservative assumptions. The worst case flaw is assumed to occur at a position, along the pipeline, of maximum cyclic and static stress such as the crown (extrados) of a lateral buckle. The maximum lateral buckling tensile stress is assumed at the end of life when the flaw has grown to its maximum size by fatigue. The toughness levels are the minimum recorded in tests sometimes using a conservative loading mode (SENB). Specimens are deep notched in the mid thickness zone which is conservative in terms of constraint for shallow surface breaking flaws. However, possible differences in micro structure through the thickness are not normally evaluated. The accuracy and conservatism of the numerical models is uncertain. The test conditions for environmental fatigue and fracture testing (H2S, pH, temperature) are selected to be worst case but this can be difficult to judge considering the different environmental cases. The environmental fatigue and fracture testing tests have to be restricted to practical durations. The fatigue test frequency is more rapid than actual shut downs but tests indicate that 0.01Hz is sufficiently slow to be conservative in some cases(Ref 08). The toughness tests, in H2S environment, are not normally loaded for more than 30 days which is regarded as sufficient for SSC tests (Ref 09). However, very slow active crack propagation, which could become significant after a number of years of operation, may not be detectable through the test period or unambiguously discerned in post test examination of the crack tip region. Table 7 Conservatism of Assumptions in ECA The DNV-OS-F101 generic criteria give allowable flaw siz- es, based on DNV previous ECA, subject to achievement of specified toughness levels defined as a J integral R curve. They are a welcome development and could avoid the need for full ECA analysis in future projects.
An extract from the criteria is given in Table 5. However, they have not been accepted on previous WGK projects in favour of full ECA for the below possible reasons: 1. The pipelines were subjected to significant fatigue loading so that fatigue crack growth prediction would be still be required. 2. The tabulated allowable flaw heights, including an allowance for the fatigue crack growth, were regarded as too restrictive. 3. The toughness requirements, in terms of J integral R curve, exceeded what the contractor was confident to achieve based on previous experience mainly using single value SENB CTOD testing. 4. The criteria were not valid for some pipelines since 5. the product contained significant H2S. In one case the pipeline was subjected to longitudinal strain levels above 0.4% strain with tensile operating hoop stress. According to DNV-OS-F101, the tabu- lated flaw sizes are not valid, for such a stress state, without verification by FEA crack modelling. Full ECA also allows the project specific parameters (dimensions, material properties) to be assessed to allow the margins of acceptability to be transparently clarified. The EPRG criteria (Ref 15) give allowable flaw sizes (Table 6 below), for nominal strains up to 0.5%, which are much larger than the workmanship criteria (Table 1). These are based on large scale tests on butt welded pipes, with introduced flaws, correlated with charpy test results. The previous revision of the EPRG criteria are now stated in onshore pipeline welding standards (Ref 16) and there is reported (Ref 15) to be at least one case of their application to a subsea pipeline but this unusual in WGK experience. These criteria offer potential advantages in avoiding the need for ECA and fracture mechanics testing to justify acceptance criteria much in excess of the workmanship criteria. However, like the DNV-OS-F101 generic crite- ria the stated flaw sizes would typically require some reduction to account for fatigue crack growth and are apparently not valid for pipelines conveying products containing significant H2S. The criteria depend on pipe and weld metal tensile test requirements which are slightly more onerous than the DNV-OS-F101 requirements but typically achievable. There is no requirement to conduct facture mechanics tests with confirmation of toughness relying on Charpy impact testing. The EPRG criteria are a departure from offshore pipe- line industry practice where project specific fracture mechanics testing and ECA are required to relax the workmanship criteria (Ref 01). It appears that for such a change in approach to be widely accepted there would need to be further alignment of opinion between the technical authorities, operators and authors of applica- ble standards (Ref 01,15,16). ASSURING INTEGRITY THROUGH OPERATION The above discussion relates to the measures taken, in pipeline design and construction, to assure resistance to failure from the weld flaws in operation. This section dis- cusses how the risk of such failure is managed through the pipeline operating life. Failures of subsea pipelines initiat- ed by weld flaws are rare and no reports were available to the authors. Nevertheless, the risk cannot be dismissed as insignificant and needs to be managed through operation. Following completion of pipelay the installation con- tractor is required to submit copies of relevant as built records including the identity of pipes laid at successive locations along the pipeline, AUT reports and records of repair welding. This information may be included in asset integrity management database/ software with design and as-built data being fully searchable , interrelated and corresponded to the GPS positions along the pipeline. The displacement of the pipelines, particularly at buck- les, is monitored following pipelay, hydro-test and after operation start. This includes sonar (acoustic) technology and contact methods using remotely operated vehicle (ROV) to quite accurately measure the out of straightness (OOS), displacements and actual bend radius of the buck- les. This geometric information may be used to adjust the FEA model to re-estimate strain (stress) levels more Inspection Solutions for Non-Piggable Pipelines World Wide Self propelled BiDi Tethered Inspection Tool Technology is a cost efficient approach. www.ktn.no Norway • Germany • France • Spain • Scotland O f fi c e L o c a t i o n s : KTN NORWAY Postbox 109 Ytre Laksevåg 5848 Bergen NORWAY
60 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY accurately. In the event that the strain levels, significantly exceed that in the original design, it should be possible to identify welds in the section of concern and the presence of weld flaws from the AUT records. Managing Director Technical Services at Germany’s biggest pipeline operator, Open Grid Europe, and Dirk Strack, Technical Director at TAL Group. 2. The use of 3D FEA crack modelling allows improve- Management of integrity of strain based design pipelines, through operation, has been previously reviewed (Ref 17). In summary the below relevant information is recorded though pipeline operation and may be added to the asset integrity management software/database: 1. Monitoring of the operating conditions as follows: a. Temperatures and pressures b. Number and magnitude of operational shut downs. c. Product water analysis including, pH,CO2, salts, 3. acetic acid, inhibitor concentration and H2S levels. 2. Periodic external survey of the pipeline by ROV (GVI) and acoustic methods (SSS). In this way the OOS can be assessed and bend radius of the buckles related to the strain levels is recorded. In line inspection (ILI) using UT and magnetic flux leakage (MFL) pigs. These can assess the extent of metal loss , due to corrosion/erosion, in the buckle area. Furthermore, certain ILI technologies such as UT pigs with angle probes, orientated in axial direc- tions, are quite reliable to assess circumferential weld flaws and their possible operational growth. Based on the above, the validity of original assumptions in the ECA regarding cyclic and static stress levels, flaw sizes, wall thickness and environmental conditions may be re-evaluated. A numerical model of the pipeline, with special attention to sections subject to lateral buckling, may be maintained throughout the operational life, periodically updated with the results from survey and monitoring (1,2 above) to con- firm that the applied strains are aligned with the original design and ECA and allow the remaining fatigue life to be re-estimated. Inclusion of weld flaw assessment (ECA) in this process may be appropriate in cases where they are considered to present a significant risk. An example of this is the coincidence of significant weld flaws, detected by the original AUT, in high strain locations particularly if ILI results provide evidence of them propagating. The steps to be taken in the event that the above, routine measures, indicate that the tensile strain levels exceed that predicted in the original design have been previously reviewed (Ref 17). CONCLUSIONS 1. all presentations held during our conferences and all publications released by EITEP are checked by the AdCo before cleared for publication. The Advisory Committee is currently led by Heinz Watzka, former ment of accuracy of ECA , based on BS7910 FAD approach, with the below benefits: a. The 3D FEA modified ECA can be used to help justify weld integrity with tensile strain levels exceeding 0.4%. to potentially remove the need for expensive intervention (e.g sleeper, planned buckle) to maintain strains below this limit. b. For strain levels below about 0.4% the over conservatism of ECA, based on BS7910, may be reduced by the 3D FEA to justify relaxation in the concluded acceptance criteria for WPQT tough- ness test and/or AUT. This reduces the likely hood of contractor quality problems in WPQT (Toughness test failure) or production welding (e.g. high weld repair rate, low production rates). c. The 3D FEA justifies use of SENT test rather than SENB test to further avoid over conservatism in testing to potentially enhance the benefits described above (a, b). 3. The ECA requires to take account of the effects of H2S in the product conveyed, in reducing weld toughness, if its concentration is predicted to become significant. There is a need for further research to develop suit- able testing methods and understand the sensitivity of measured toughness to environmental conditions, specimen geometry, loading mode and metallurgy. 4. The ECA requires to take account of possible exten- sion of flaws, in operation, by fatigue crack growth including the effects of the internal corrosive environ- ment in accelerating the growth rate. The latter has been achieved by project specific fatigue crack growth testing in simulated internal operating environment. 5. The design contractor should conduct a fully detailed ECA , even when the agreed maximum strain is less than 0.4%, rather than relying on the installation con- tractor at a later stage in the project if their contract excludes in place design and the installation stresses, by S lay or J lay, are less severe than predicted in oper- ation (e.g. lateral buckling). This approach minimises the schedule risk in the event of WPQT results which are unacceptable according to the contractor ECA ne- cessitating further advanced ECA and /or design work (stress analysis to reduce in-place stresses) at a late stage in the project when design is largely complete. 6. There is a need for development of probabilistic ECA procedures, for use on design projects, to enable the level of conservatism in ECA to be better quantified. 7. The generic criteria of DNV-OS-F101 presents al- lowable flaw sizes , relaxed from the workmanship criteria, as an alternative to full project specific ECA. These have not been applied to WGK projects to date considering lack of confidence in achievability
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 61 in the toughness levels required, possible stringency in flaw heights including fatigue crack growth and restriction to non sour service. 8. The EPRG Tier 2 criteria presents allowable flaw sizes , relaxed from the workmanship criteria, as an alter- native to ECA and fracture mechanics testing based on previous large scale tests correlated with charpy results. There applicability would be restricted in the event of predicted significant fatigue crack growth or sour conditions as explained above (7.). Moreover, to be widely accepted on subsea pipeline projects, without project specific fracture mechanics testing, there would need to be further alignment of opinion between the technical authorities, operators and au- thors of applicable standards (Ref 01,15,16). 9. Following completion of design and pipeline installa- tion there is a need to assure continued integrity of the butt welds, with flaws, through pipeline operation. This is achieved by collation of design and as-built data (e.g. AUT reports) and by periodic survey (ROV GVI, SSS, OOS) through operation together with monitoring of operational parameters (e.g. pressure, temperature shut downs).The data collected can be used to update a numerical model of the pipeline to re-estimate the static and cyclic stress levels to com- pare with those of the original design and re-estimate remaining fatigue life. Inclusion of ECA in this pro- cess may be appropriate depending on the location and size of weld flaws as indicated by the original AUT reports and subsequent ILI. API AUT BS CP CTOD DNV ECA EPRG Nomenclature American Petroleum Institute MUT Manual ultrasonic testing Automatic Ultrasonic Testing MFL NDT British Standard Magnetic flux leakage Non destructive testing Cathodic protection Crack tip opening displace- ment Det Norske Veritas Engineering Critical Assess- ment OOS ROV Out of straightness Remotely operated vehicle SENB Single edged notch bend SENT Single edge notch tension SMYS Specified minimum yield European Pipeline Research Group Failure assessment diagram SMAW Shielded metal arc welding Finite Element Analysis Sulphide Stress Cracking Fatigue crack growth law Side scan sonar strength SSC SSS References 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. DNV-OS-F101 (2013), Det Norske Veritas, Offshore Standard DNV-OS-F101, Submarine Pipeline Systems, October 2013 API Standard 1104 (21th Edition: 2013), Welding of Pipelines and Related Facilities. SAFEBUCK III, Safe Design of Pipelines with lateral buckling. Design Guideline. BS 4515-1:2009, Specification for welding of steel pipelines on land and offshore. Carbon and carbon manganese steel pipelines BS EN ISO 15653: 2010, Metallic materials - Method of test for the determination of quasi-static fracture toughness of welds. BS 7910 (2013)Guide on Methods for Assessing the Acceptability of Flaws in Metallic Structures DNV-RP-F108 (2006) Fracture Control for Pipeline Installation Methods Introducing Cyclic Plastic Strain, January 2006 Design of pipelines subject to lateral buckling to resist corrosion fatigue, R J Pargeter and D P Baxter ,TWI Ltd ,Paper presented at Corrosion 2009, Atlanta, Georgia, USA, 22-26 March 2009. Paper # 09090. NACE MR0175/ISO 15156, Petroleum and Natural Gas Industries Materials for Use In H2S Cont- aining Environments in Oil and Gas Production ISO 15653:2010 Metallic materials -- Method of test for the determination of quasistatic fracture toughness of welds BS 8571:2014: Method of test for determination of fracture toughness in metallic materials using single edge notched tension (SENT) specimens Fracture Toughness Testing of Steels Subject to Sour Service, NA00533, 22/03/2012, http:// www.twi-global.com. Proceedings of the ASME 2010 29th International Conference on Ocean, Offshore and Arctic Engineering, OMAE 2010 ,June 6-11, 2010, Shanghai, China , Effects of strain rate on fracture toughness in sour environment , Yuan Wen Guo ,Xu Da Qin , Wu You You , Jens P. Tronskar DNV GL forms new JIP , DNV GL JIP investigates evaluation methodology for fractures and cracks in sour service environments , Oil Online Press - February 25th, 2015 EPRG guidelines on the assessment of flaws in transmission pipeline girth welds _Revision 2014, R Andrews, Prof Rudi Denys, Dr Gerhard Knuaf, Dr Mures Zarea, Journal of Pipeline Engineering, Vol 14, No 1, March 2015. BS EN 12732:2013 +A1 2014, Gas Infrastructure-Welding steel pipework-Functional requirements. Integrity management of Pipelines Subject to High Strain, Colin McKinnon, Emil Maschner, Harry Cotton, Carlos Herraez, Mike Cook, Justin Crapps, PRCI, 20th JT<, 3-8 May, 2015, Paris France. Fracture Mechanics Techniques for Assessing the Effects of Hydrogen on Steel Properties , Mo- hamad J Cheaitani and Richard J Pargeter, TWI Ltd, Granta Park, Great Abington, Cambridge, CB21 6AL, Paper presented at the International Steel and Hydrogen Conference, 28 September 2011. FAD FEA FCGL GMAW GPS Global Positioning System GSFCAW Gas shielded flux cored arc Gas metal arc welding HAZ ILI welding Heat affected zone In line inspection (e.g.Intelligent pig inspection) GVI TWI UT General visual inspection The Welding Institute Ultrasonic testing VIV Vortex induced vibration WPQT Welding Procedure Quali- fication MDT Minimum design temperature WGK Wood Group Kenny Harry Cotton Wood plc. Senior Materials Consultant firstname.lastname@example.org Authors Istvan Bartha Formerly Wood plc. Senior Integrity Engineer
AN INNOVATIVE TECHNOLOGY OF NON –CONTACT MAGNETIC TOMOGRAPHY METHOD FOR SUBSEA PIPELINE Norhaziyah Afiqah Ahmad > Transkor (M) Sdn Bhd; Raja Zahirudin Bin Raja Ismail > Petroliam Nasional Berhad, PETRONAS; Muhamad Paizal Othman > Transkor (M) Sdn Bhd; Igor Kolesnikov > Transkor (M) Sdn Bhd
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 63 ABSTRACT BASIC PRINCIPLES OF MAGNETIC TOMOGRAPHY METHOD (MTM) In-Line Inspection (ILI) tools are most widely used to inspect pipeline structures and employ standard pro- cedures of pipeline inspection even today. The major challenge of operator companies is to inspect non-pig- gable pipelines, due to their limited access. Most In-Line Inspection (ILI) methods, such as pigging, require a launcher/receiver and require operations to stop for the inspection procedure to take place. In recent years, a non-contact Magnetic Tomography Method (MTM) has been introduced as a non-intrusive method, which is able to inspect ferrous magnetic pipe- lines without contact. MTM technology was originally used as a conventional onshore pipeline inspection tool. After several years, an innovative research and development program on the technology, by PETRONAS Carigali Sdn Bhd and LLC R&DC Transkor-K, introduced the AQUA MTM Technol- ogy; which is capable of inspecting subsea pipelines without contact. Now, this technology is commercially available for the oil and gas industry. This paper briefly discusses the application of the non-contact magnetic tomography method for subsea pipelines. INTRODUCTION As the drop in oil prices eventually affects economic conditions, the world faces extraordinary challenges; especially for exporter countries. Aging and deteriorating pipelines can cause catastrophes if pipeline conditions remain unknown. Pipeline Integrity Management issues are intrinsically associated with pipeline safety to avert adverse predic- aments and mishaps. At the same time, most operators are looking into cost planning in order to carry out inspec- tion and maintenance activities for their pipelines. In-line inspection tools are a common method used for pipeline inspections; particularly for piggable pipelines. The purpose of an in-line inspection is to detect size and locate flaws and defects within pipe walls . Problems arise when they are unable to inspect non-piggable pipe- lines due to limited access. MTM technology is a holistic solution method to inspect the technical condition of a pipeline by scanning and detecting magnetic field chang- es reflected from a combination of stress and defects without contact. Adopted from land applications, AQUA MTM technology is used for subsea pipeline applications with Remote Operated Vehicle (ROV) support. THEORY The Magnetic Tomography Method is the non-destructive testing and technical diagnostic of extended ferromag- netic structures using the magnitude of mechanical stress combined with metal defects based on the Villari effect. The change of ferro-magnet magnetization under the influence of mechanical deformations, such as stretching, twisting and bending, is known as the Villari effect . AQUA MTM technology evaluates local changes of the magnetic field of mechanical stresses and defects to give the degree of danger of anomalies based on the Integral Risk Factor [F]. The Integral Risk Factor [F] can be defined as the degree of concentration of the complex (longitudi- nal, hoop, shear, etc.) stresses in an anomaly . From the inspection’s results, the Integral Risk Factor [F] is used for further pipeline integrity management assessment. The aim of AQUA MTM technology is to locate the dan- ger and assess how critical it is. MTM and AQUA MTM inspections are convenient and reliable tools for estimat- ing pipeline burst strengths in both onshore and offshore conditions. By using these technologies, clients are able to determine the condition of their pipelines. TECHNICAL REQUIREMENT OF AQUA MTM AQUA MTM indicates the essential parameters of quality as follows: • • • Probability of Detection (POD) Probability of Identification (POI) Confidence Level (CL) Technical requirement above are intrinsically associated with high quality of data collection and analysis purpose. Probability of Detection is the probability associated with anomaly that under the influence of stresses that differ from the minimum ones more than for 0.005 SMYS will be detected. Whilst Probability of Identification (POI) is determination of anomalies danger by the degree of concentration of mechanical stresses. Confidence Level is statistical expression to describe the accuracy in which with the set level of confidence. AQUA MTM Technology is applicable and designed to inspect horizontal pipeline for underwater. AQUA MTM Technology can detect the stresses within the range of mechanical stresses on de- fective sections of 30-80% of SMYS. The high POD great- er than 85% would be achieved at the level of stresses on defective sections of 55-65 % of SMYS.
64 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY OVERALL PROCESS OF AQUA MTM INSPECTION Figure 1: Probability of Detection of Magnetic Anomalies at various Mechanical Stresses in defects Area MAGNETIC FIELD PROPERTIES AQUA MTM technology depicts two different magnetic properties of the ferrous magnetic pipe during scanning: Figure 2: Magnetic Properties of ferrous magnetic pipe- without stress Figure 4: flow process of AQUA MTM Technology inspection AQUA MTM Technology inspection only require the sup- port from remote operated vehicle (ROV) to do underwa- ter pipeline inspection. During the inspection, AQUA MTM data would be collected and recorded. In order to ensure high quality of the data collection, the equipment needs to comply according the AQUA SKIF scanning procedure. After all data is collected, the data will then be analyzed and processed. Figure 3: Magnetic Properties of ferrous magnetic pipe- with stresses The change of local mechanical stress modifies magneti- zation of the pipeline, which is reflected in the magnetic field would be detected by AQUA MTM. Data analyzing process involves the process of the magnetic field analysis, stress analysis and danger of degree calculation. Results will then be presented in the final report.
AQUA MTM OPERATIONAL Figure 5: flow process of AQUA MTM operation Pipeline Data Gathering: AQUA MTM inspection requires the gathering of technical information of the pipeline such as length of the pipe, nominal diameter, Specific minimum yield strength (SMYS), operating pressure and etc. The information gathered will be used for further calculation. The calculation to be used is ASME B31G for determining the remaining strength of the corroded pipe- lines and Russian standard RD 102-008-2002. Equipment Inspection: Before inspection, the used equipment needs to be inspected and tested to ensure the equipment is in a good condition and ready for the operation. AQUA MTM Equipment Setup: AQUA MTM Equipment is also known as the “AQUA SKIF”. This device would be installed on the ROV and integrated for the inspec- tion process. During setup, AQUA SKIF will be attached in best way to ensure minimum disturbance that could interfere with the input signal. Interfacing: At this stage, AQUA SKIF would be inter- faced and checked again on the equipment condition. Interfacing process involves visual inspection, power supply testing, communication testing and functionality testing. All tests need to be passed to ensure the equip- ment is fully ready before undergo dry and wet tests. Dry Test: Dry Test is testing of the equipment in the connection with ROV in dry condition. At this stage, input and output signal would be checked. The quality of the signal during dry test must be good. Wet Test: Wet test is testing of the equipment in the con- nection with ROV in wet condition. Equipment attached to the ROV is immersed into the water. The overall data acquisition capability is checked to ensure smooth signal from input and output. RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 65 Pipeline Magnetic Field Calibration: AQUA SKIF needs to calibrate the magnetic field at the location of the pipeline. At this stage the ROV needs to move to an area with no pipeline or any other metal objects to identify the natural magnetic field of the inspection location. This step en- sures that all the collected magnetic field signals reflect- ed would be detected by the AQUA SKIF. AQUA MTM Inspection: At this stage, an engineer needs to monitor the output signal collected from AQUA MTM monitoring software and a second engineer will kay in all remarks and events during inspection for the data analyzing purposes. AQUA MTM OPERATIONAL Value 10-9 ±100 Starting with 2.8 mm (max. 50mm) ≤ 15 D ≤ 3 D <1.8 662X282X128 8.95 100 100 % Parameter Magnetic field strength, Tesla Range of measurement, µT Range of nominal wall thickness of object External diameter of inspected pipelines 4’’ ≤ D ≤ 48’’ Admissible deviation from axis of OC: vertically horizontally Speed range, m/s Dimension of Underwater Unit, mm Weight of Underwater Unit, kg Length of inspected section, Minimum, m Completeness of registration along the pipe Step of scanning, max., m Threshold of detection Error of odometer distance measurement Current from any direction relative to ROV heading Maximum Length inspected the site Minimum distance from inspected pipeline to a parallel pipe or steel The intersection with pipeline cables, or communications Residual magnetization pipeline (post-production or ILI) 0,02 0,001F ≤ 1,5 % 0.78 m/sec No limitation 1D of the biggest neighboring no limitations should not exceed 50% of the thresh- old measurements Table 1: AQUA MTM specification
66 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY AQUA MTM DATA ANALYZING Figure 6: AQUA MTM Raw Data Figure 7: AQUA MTM analyzing process. mines which are more danger ones and where the danger is located. Anomalies were classified as following: State of Metal: State of Metal determines the physical condition of the pipe. This describes the stress detected due to metal condition without the application of external loading. State of Metal 1 2 3 Range of F Meaning Recommendation 0... 0.2 INADMISSIBLE urgent repair 0.2... 0.55 ADMISSIBLE 0.55... 1 GOOD scheduler repair, monitoring no repair, monitoring Figure 8: Different States of Metal Stress Deformed State: Stress Deformed State describes the stress detected with the effect of the external forces and inter- nal loading. From the inspection results, AQUA MTM is also able to determine the safe operat- ing pressure for the pipeline. This results help to determine if the pipe- line operates within the safe pressure level or not. Results revealed the predicted features of the defect would be detected such as crack-like defect, weld defects, general corrosion and etc. PRINCIPLE BENEFIT OF AQUA MTM AQUA MTM Technology gives benefits to pipeline operators regarding technical and operational aspects. Figure 9 shows the advantages of this technology which is more economic and reliable. AQUA MTM RESULTS AND EVALUATION AQUA MTM TECHNOLOGY LIMITATION The main purpose of this technology is to determine the technical condition of the subsea pipeline. This technol- ogy is able to classify the anomalies whereby it deter- Every technology has their own limitations. AQUA MTM technology is limited only to inspect ferrous magnetic materials pipeline. This technology is even able to inspect
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 67 measure stress caused by the defect and identifies their type, location and orientation of the stress area. In addi- tion, this technology also can determine the critical defect that contributed to the dangerous conditions. Presence of magnetic mass between AQUA ASKIF and pipeline will affect the input signal and will eventually lead to low quality of data. CONCLUSION AQUA MTM technology presents an alternative to the In- Line Inspection method to determine the integrity of the pipeline management. An advantage utilizing this tech- nology is the cost factor. References [1.] [2.] [3.] [4.] [5.] [6.] [7.] [8.] [9.] Alfred Barbian, Michael Beller; In-Line Inspection of High Pressure Transmission Pipeline: State-of-the Art and Future Trends; 18th World Conference on Nondestructive Testing, 16-20 April 2012, Durban South Africa. Victor Makhov, Linar Khusnutdinov; Report of AQUA MTM Inspection SKOPL 239 6” FL-454- ICCP, 2013. Vadim Belotelov, Igor Kolesnikov, Svetlana Kamaeva; Report of SKGPL 400 (Silk 329) B12 to B11DRA ; AQUA MTM Inspection Work For Subsea Pipeline ;2016 NySearch; Testing Program for Remote Inspection using magnetic Tomography Website ; oos.my/our technology; oilfield Offshore Services Sdn Bhd. KeXi liao, Quaanke Yao, Chun Zhang; Principle and Technical Characteristics of Non-Contact Magnetic Tomography Method Inspection For Oil and Gad Pipeline; 2011. Website http:// transkorgroup.com; magnetic Tomography Method Vladimir Mokshanov, Rezayat Pipelines Company Ltd. The Alternative to the In-Line Inspection Exists. KeXi Liao and Chun Zhang. Standard and Application by Using Non- Magnetic Tomography Method for Pipeline Technical Conditions Diagnosis. 2011 [10.] Website http:// www.petronesia.co.id; Non Contact magnetic Tomography Figure 9: advantages of this technology which is more economic and reliable. various sizes of pipeline diameter, but the equipments distance to the pipeline must not be more than 15 times the pipeline diameter. AQUA MTM is unable to measure the geometry of the defect that gives the specific dimension, it is capable to Norhaziyah Afiqah Ahmad Transkor (M) Sdn Bhd Pipeline Integrity Engineer email@example.com Raja Zahirudin Bin Raja Ismail Petroliam Nasional Berhad, PETRONAS Principal Engineer (Pipeline Integrity) firstname.lastname@example.org Author Muhamad Paizal Othman Transkor (M) Sdn Bhd Executive Director email@example.com Igor Kolesnikov Transkor (M) Sdn Bhd Technical Director of Traskor-K firstname.lastname@example.org
ULTRA-DEEP WATER GAS PIPELINES Collapse and Consequences Hossein Pirzad > The School of Energy, Geoscience, Infrastructure and Society (EGIS); Leif Collberg > DNV GL ; Samaneh Etemadi > Department of Chemistry, University of Oslo
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 69 ABSTRACT INTRODUCTION Ultra-deep water gas pipelines will be playing a major role in tomorrow’s energy supply. Diminishing onshore and shallow water gas resources together with geo-po- litical and energy security concerns will be leaving no al- ternative but to accelerate the development of ultra-deep water reserves. Thick wall pipeline requirement to resist the collapse pressure is one of the most challenging aspects of such fields in terms of pipe design. In addition to direct costs of installing tremendous amounts of extra steel, there would also be a substantial carbon footprint in the global atmosphere. DNV-OS-F101 is the most popular design code address- ing the failure modes of offshore pipelines including sys- tem collapse. The standard and its partial safety factors are based on reliability analyses. There have been some efforts to improve the characteristic capacity of pipes towards more economic but still safe structures. Among them, there is a recent work to improve the pipe fabrica- tion factor (αfab) of heat treated UOE line pipes. This paper will discuss the consequences of system collapse of gas pipelines in ultra-deep waters at de- pressurized shutdown condition. DNV-OS-F101 requires ‘’Medium’’ or ‘’High’’ safety classes for such a failure regardless of its spatial or temporal extents. Zero hydro- carbon release policies of oil companies and regulators are presumably the most important factor implying such a requirement. Hydrate formation phenomenon will occur in case of any puncture in the pipe wall where the (LTHP) water enters the pipeline at a temporary shut-down condition due to the external over-pressure. As a result of water ingress, hydrates will form and partially or even com- pletely block the collapsed pipeline. This will result in preventing further release of gas to ocean, hence ‘’Low’’ safety class would be allowed in that particular load scenario which is likely to be the governing one in terms of wall thickness calculations. ABBREVIATIONS CAPEX CFD FEA GHGE LTHP SRA SURF UOE = Capital Expenditure = Computational Fluid Dynamics = Finite Element Analysis = Green House Gas Emissions = Low Temperature High Pressure = Structural Reliability Analysis = Subsea, Umbilical, Riser and Flowline = U-Shape, O-Shape and Expanded (a line pipe manufacturing method) Viability of natural gas projects is strongly dependent on gas supply security in comparison with oil develop- ment projects which appear to be solely dependent on per barrel price. Natural gas being a cleaner fossil fuel and a traditional source for producing electricity will be remaining a major slice of world’s energy demand in the near and far future. European gas grid robustness has been the topic of some researches (ARXIV, 2016). The main motivation behind this paper had been the Eastern Mediterranean gas prospects (European Commission, 2016). Some of the proposed subsea pipeline routes meant to fuel Europe from the Eastern Mediterranean reserves shall be installed in Ca. 3000m of ultra-deep water depths (EMODNET, 2016). However, the finding is basically applicable to any ultra-deep water pipeline. Very high external pressure exerted by water column on a subsea pipeline laid on deep oceans floor requires heavy wall cross section pipe in order to be able to resist system collapse as the governing failure mode. Thick line pipe is not only difficult to be sourced out of pipe mills but also expensive to transport, weld and install, hence is often a showstopper for large diameter trunk lines to be installed at ultra-deep waters. DNV-OS-F101 suggest below chain of formulas for pipe- line collapse: (1) (2) (3) (4) (5) Where pe, pmin, pc (t), γm, γSC, pel(t), E, η, pp(t), fo, D, t, fy, αfab, Dmax and Dmin are external pressure, minimum internal pressure, collapse capacity, material safety factor, safety class factor, elastic collapse capacity, Young modulus, usage factor, plastic collapse capacity, out-of-roundness, pipe diameter, pipe wall thickness, minimum specified yield strength, pipe fabrication factor, maximum pipe diameter and minimum pipe diameter respectively (DNV- OS-F101, 2013). Code calibration procedure of today’s modern design codes including DNV-OS-F101 are based on partial safety factors derived from probabilistic analyses. In other words, partial safety factors allow covering the implicit uncertainties in material properties, manufacturing “Thick wall pipeline requirement to resist the collapse pressure is one of the most chal- lenging aspects of such fields in terms of pipe design. Hossein Pirzad
70 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY methods, installation condition, etc. in nominal target fail- ure probability, whilst the expected reliability of system including gross errors is aimed to be within an acceptable target frame. DNV allow any deviation from its require- ments provided a documented proof that the risk associ- ated with the particular failure mode as well as the overall risk of system failure remain within targeted frame (DNV- OS-F101, Sec.1 A401). A recent development has aimed to replace DNV recommended αfab=0.85 for UOE pipes with αfab=1.0 with the condition of conducting some heat treatments after the cold expansion process, similar to what happens to line pipes during anti-corrosion coating process (Liessem et. al., 2007). Marley et. al. (2012), as another work focused on SRA side, have summarised various collapse design equations including Haagsma’s which is also recommended by DNV-OS-F101. More recent collapse pressure test data are then used to update the random model uncertainty and eventually presenting a new code calibration. In this paper the focus will be on the environmental con- sequences when an ultra-deep water gas pipeline fails in a particular load scenario. Such consequences, along with the other safety and economic ones, are represented in formula (1) by γSC SAFETY CLASSES ‘’Safety Class’’ of any segment of pipeline represents the safety, environmental and economic consequences of its failure, hence, it dependents on the contents of pipe- line, its location and the operational phase whether it is temporary or not. Table 1 (DNV-OS-F101) summarises the definitions of ‘’Low’’, ‘’Medium’’ and ‘’High’’ safety classes. Table 1 - Safety Classification (DNV-OS-F101)
RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 71 will not lead to a considerable gas leakage. This argu- ment is based on water ingress phenomenon into the pipeline and hydrate formation that will lead to blockage of pipeline so that further gas release will be halted. Hence, Low safety class can be considered valid in this particular scenario. There is a tendency to assume that the pipeline installa- tion is the governing case in terms of wall thickness cal- culations even though it is categorised under Low safety class due to the bending moment within sagbend region. However, such an assumption cannot be generalised for all possible pipe sizes, material grades, water depths and installation fleet. GAS HYDRATE FORMATION Gas hydrate formation has always been a flow as- surance challenge for relatively long gas pipelines. Seawater cools down the gas inside the pipeline to the hydrate formation temperature where crystalized natural gas blocks the flow and creates a lot of operational and main- tenance issues for the operator of pipelines. Figure 1 (Heriot Watt University, 2016) illus- trates a typical appear- ance of gas hydrate. S.Mokhatab et. al. (2007) have summarised the most popular strategies to cope hydrate formation issues in subsea pipelines. The suggestions are mainly preventive and categorised under water removal, thermal γSC in formula (1) is the direct representative of safety class in calculating nominal wall thickness to resist sys- tem collapse as a limit state. The standard, per note 3 of Table 1 (DNV-OS-F101), re- quires special consequence evaluation to justify a safety class “Low” during any temporary phases after commis- sioning including depressurised pipelines in shut-down state. When comparing all possible consequences of any potential failure during pre-commissioning (a before commissioning phase) with the consequences of a failure during shutdown (an after commissioning phase), both events will cause similar repair costs and the same delay in the start-up date. Safety concerns cannot be very different too. Therefore, the assumed environmental consequences caused by leakages and massive hydrocarbon release is understood to be the only reason behind such a requirement, while as argued in this paper, such a major gas release will not occur in the very particular case of an ultra-deep water gas pipeline in shut-down state. Table 2 - Safety Class Resistance Factor (DNV-OS-F101) Each category has a defined safety class factor based on Table 2 (DNV-OS-F101). The factor associated with safe- ty class Medium is approxi- mately 10% higher than the one with Low safety class. The resulting required wall thickness will then ap- proximately be 5% to 10% higher for Medium safety class compared to Low safety class. Collapse of ultra-deep water gas pipeline under depressurised shut-down condition, as one of the likely governing load cases, Figure 1 - Gas Hydrate in Pipelines (Heriot Watt University, 2016).
72 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY Figure 2 - Phase envelope, hydrate formation (HF) and water dew point (WD) for natural gas (Petroskills, 2016) solutions, chemical inhibitors and thermodynamic inhibitor where the main aim is to keep the state of natural gas flow outside of hydrate formation envelope presented in Figure 2 (Petroskills, 2016). While hydrate formation inside an operating gas pipe- line is a problem, it can be beneficial when it comes to the safety class selection of collapsed pipelines at de- pressurised shut-down state. In fact, there would be no major gas release to the sea in case an ultra-deep water gas pipeline collapses. Water ingress, in case of a wet buckle, will pull the state of the gas content well into quite stable hydrate forma- tion zone of the envelope, the left hand side of the solid red and green curves of Figure 2 (Petroskills, 2016). Consequently, gas hydrate would block the pipeline and further hydrocarbon release will be limited or fully stopped. The study consists three main parts for both ingress and egress phenomena. Firstly, pipeline thermo-hydraulic behaviour under vari- ous sizes of leakage are assessed. The second part consists of a detailed CFD model in order to simulate the flow regime in the vicinity of the leak and the last section is shaped around hydrate for- mation, transportation and blockage. The last chapter is focused on hydrate formation and relevant risks of blockage in gas pipelines due to the transportation and accumulation of hydrates after they are formed in the case of water ingress. Figure 3 (S.Zhai. et. al., 2015) illustrates a schematic of how hydrates form, travel along the pipeline and accu- mulate in a gas-dominated pipeline. S.Zhai et. al. (2015) have studied deepwater pipe- lines leakage using FEA both on water ingress when external hydrostatic pressure is higher than pipeline internal pressure and gas egress otherwise. Figure 3 – Hydrate Plug Formation in a Gas Dominated System (S.Zhai. et. al., 2015)
ENVIRONMENTAL CONSEQUENCES AND THE BIGGER PICTURE Quantifying the amount of hydrocarbon release on every subsea pipelines project and each failure scenario would be a time consuming and expensive engineering pro- cess. Therefore, DNV-OS-F101 has defined three Low, Medium and High safety classes based on the content fluid, location of installation and the relevant phase of the life cycle. Massive oil-spill or gas release is presum- ably the backbone of such a procedure. In other words, DNV have assumed that any hole or rupture in the pipe wall, even in the depressurised shut-down condition will lead to a massive discharge of hydrocarbon to the sea. Such an approach is under- standable as the standard, like all other design codes, has started to develop from shallow waters where any pipe failure is equivalent to gas release. This is however not the case for ultra-deep water gas pipelines at shutdown condition as argued in this paper where water ingress and hydrate formation would limit the gas release to a very small amount. Table 3 outlines some realistic examples. The different wall thickness requirements vary between safety class Low and safety class Medium. The esti- mated wall thicknesses are based on DNV-OS-F101. All other input data remain unchanged for the sensitivity study purpose at 3000m of water depth. Pipe Data RESEARCH / DEVELOPMENT / TECHNOLOGY PIPELINE TECHNOLOGY JOURNAL 73 producing one ton of steel (Global CCS Institute, 2013), we are now given Ca. 22,000 tons of CO2 certain release to the atmosphere in order to avoid releasing a fraction of Ca. 25000 tonnes natural gas to the sea with very low probability. The carbon footprint of extra steel used in the pipeline will be way higher than 22,000 tons in case the trans- portation, installation and decommissioning footprints are taken into account. GHGE and global warming is now another important as- pect of environmental concerns that countries are com- mitted to take into equation when setting up regulations within their territories (Paris Agreement, 2015). Regulators are now legally committed to take the global impacts of their policies into consideration instead of over-conservatism in caring local environments only. CONCLUSION AND RECOMMENDATION DNV-OS-F101 has normalised the consequences of various pipeline failure modes in three safety class cat- egories. The selection of ‘’Safety Class’’ is a crucial step during pipe design having a direct impact on the select- ed pipe wall thickness. Hydrocarbon content, location and the phase of operation are the three main parame- Safety Class Low Safety Class Medium 30’’ 762.0 X80 39.3 0.5 150 28’’ 711.2 X80 36.9 0.5 150 30’’ 762.0 X80 40.9 0.5 150 28’’ 711.2 X80 38.4 0.5 150 NPS (Nominal Pipe Size) OD (Outer Diameter, mm) Material Grade W.T. (Wall Thickness, mm) Ovality (%) Content density (kg/cum) A simple calcu- lation based on average numbers between 28” and 30” pipes reveals that there would be around 11,000 tons of extra steel production by switching the requirement from ‘Low’ to ‘Medium’ safety class for a 500km long subsea pipeline according to Table 3. By assuming Ca. two tons of CO2 footprint only for Steel mass(kg/m) 700.439 613.619 721.341 637.143 Content mass(kg/m) 55.02 47.86 54.51 47.41 Table 3- Safety Class Low and Medium Comparison
74 PIPELINE TECHNOLOGY JOURNAL RESEARCH / DEVELOPMENT / TECHNOLOGY ters in selecting a safety class for a particular pipeline in a particular load scenario as per Table 1. It is understood that the basis of the categorisation is gas release and its economic, fatal and/or environmental consequences. However, in a very particular case where a depressurized pipeline collapses there would be no major gas release. Instead seawater will enter the pipeline and will form gas hydrates leading to a partial or full blockage. It is hard to conclude whether the system collapse during installation or during the temporary shut-down state be the governing load scenario. The latter, in case of the Medium safety class requirement, would require about 5% thicker wall leading to a demand for thousands of tons of extra high quality steel. Therefore, using the ‘’Low’’ safety class instead of ‘’Medium’’ or ‘’High’’ will be a significant CAPEX saving. A further study by DNV GL can help to include the re- wards of hydrate formation during water ingress into the depressurized gas pipelines at ultra-deep waters. FUNDING This research has not received funding supports from any corporation or commercial entity. References • ARXIV.ORG, 2016. arXiv [online]. Ithaca: Cornell University Library. Available from: http://arxiv.org/pdf/0903.0195v3.pdf [Accessed 01 Jul 2016]. • EMODNET, 2016. Emodnet Bathymetry [online]. Europe: European Marine Obser- vation and Data Network. Available from: http://portal.emodnet-bathymetry.eu/ mean-depth-full-coverage [Accessed 01 Jul 2016]. • European Commission, 2016. Innovation and Networks Executive Agency [online]. European Union: European Commission. Available from: https://ec.europa.eu/ inea/en/connecting-europe-facility/cef-energy/projects-by-country/multi-coun- try/7.3.1-0025-elcy-s-m-15 [Accessed 01 Jul 2016]. • DNV-OS-F101 • Andreas Liessem., Johannes Groß-Weege., Gerhard Knauf and Steffen Zimmer- mann., UOE Pipes For Ultra Deep Water Application – Analytical and FE Collapse Strength Prediction vs. Full-Scale Tests of Thermally Treated Line Pipe. The Seven- teenth International Offshore and Polar Engineering Conference, ISOPE-I-07-499. • Erica Marley., Olav Aamlid. and Leif Collberg., Assessment of Recent Experimental Data on Collapse Capacity of UOE Pipeline. The 2012 9th International Pipeline Conference IPC2012, IPC2012-90698. • Heriot Watt University, 2016. [online]. Edinburgh: Institute of Petroleum Enginee- ring. Available from http://www.pet.hw.ac.uk/research/hydrate/hydrates_why.cfm [Accessed 03 Jul 2016]. • S.Mokhatab., Robert J. Wilkens. and K.J.Leontaritis., 2007. A Review of Strate- gies for Solving Gas-Hydrate Problems in Subsea Pipelines. Energy Sources Part A Recovery Utilization and Environmental Effects Part A(1), 39-45, DOI: 10.1080/009083190933988. • Petroskills, 2016. Tip of The Month: Gas Hydration and Water Dew Point [online]. Available from: http://www.jmcampbell.com/tip-of-the-month/wp-content/ uploads/2011/03/312.png [Accessed 04 Jul 2016]. • S.Zhai, C.Chauvet, R.Azarinezhad, J.Zeng. and A.Priyadarshi., 2015. Discussion of Pipeline Leakage and Hydrate Formation Risks Associated in Deepwater Natural Gas Pipelines. 17th International Conference on Multiphase Production Technology, BHR-2015-H3. • Global CCS Institute, 2013. CCS for Iron and Steel Production [online]. IPCC. Availa- ble from: https://www.globalccsinstitute.com/insights/authors/dennisvanpuyvel- de/2013/08/23/ccs-iron-and-steel-production [Accessed 11 Jul 2016]. • Paris Agreement, 2015. COP21 [online]. Paris Climate Conference. Available from: http://ec.europa.eu/clima/policies/international/negotiations/paris/index_en.htm [Accessed 11 Jul 2016]. Authors Leif Collberg DNV GL Vice President email@example.com Hossein Pirzad The School of Energy, Geoscience, Infrastructure and Society (EGIS) Pipeline Engineer firstname.lastname@example.org Samaneh Etemadi Department of Chemistry, University of Oslo Materials Engineer / Chemist
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76 PIPELINE TECHNOLOGY JOURNAL CONFERENCES / SEMINARS / EXHIBITIONS GET TO KNOW Euro Institute for Information and Technology Transfer Dr. Klaus Ritter President Eitep Conferences & Exhibitions Marketing & Communication Dennis Fandrich Vice President Rana Alnasir-Boulos Vice President Marian Ritter Director Exhibitions Admir Celovic Director Publications Project Assistants As of 01.12.2017 The EITEP Institute is providing Know-How and Technology-Transfer through international Conferences, Semi- nars and Publications. Our primary objective is to foster the international exchange of state-of-the-art-technolo- gies, in order to provide the latest products and services where they are needed. EITEP is organized in two departments, guided an overseen by the company’s president, Dr. Klaus Ritter, who worked as general manager for professional, technical and scientific associations of the German energy and water supply sector before becoming the founder and president of EITEP. Conferences & Exhibitions The department Conferences & Exhibitions is responsible for the organization of EITEP events, which include the upcoming Pipeline Technology Conference and the Pipe and Sewer Technology Con- ference. Also, all exhibitions associated with these events are planed and executed by this department. It is led by Mr. Dennis Fandrich, who is your contact for all matters regarding the Conferences. The exhibitions are organized by Mr. Marian Ritter, he will assist you with all questions regarding the fairs. Marketing & Communication The department Marketing & Communication planes and executes all activities related to the promotion of EI- TEP events and the communication with stakeholders. It is responsible for the publication of professional magazines like the Pipeline Technology Journal (ptj). The department is led by Mrs. Rana Alnasir-Boulos, she is your contact regarding marketing, sales, seminars and special projects. Responsible for our publications is Mr. Admir Celovic. He will assist you with questions regarding the journals edito- rial content and advertisement opportunities. EITEP is supported by the advisory committee AdCo, which consists of 44 senior pipeline professionals from all over the world. They bring in the necessary connection to the profession and valuable technical expertise. To fur- ther support our efforts. All presentations held during our conferences and all publications re- leased by EITEP are checked by the AdCo before cleared for publication. The Advisory Commit- tee is currently led by Heinz Watzka, former Managing Director Technical Services at Germany’s biggest pipeline operator, Open Grid Europe, and Dirk Strack, Technical Director at TAL Group. Additional senior consultants have been recruited as advisors for special issues. Heinz Watzka Dirk Strack
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78 PIPELINE TECHNOLOGY JOURNAL CONFERENCES / SEMINARS / EXHIBITIONS WELCOME TO THE 13TH PIPELINE TECHNOLOGY CONFERENCE EUROPE’S LEADING PIPELINE CONFERENCE AND EXHIBITION PREVIEW 2018 From 12-14 March 2018 Europe’s leading conference and exhibition on high-pres- sure pipeline systems, the Pipeline Technology Conference, will take place for the 13th time. The 13th ptc offers again opportunities for operators as well as technology and service providers to exchange latest onshore and offshore tech- nologies and new developments supporting the energy strategies world-wide. More than 600 delegates are expected to attend the 13th ptc in Berlin. The con- ference will be held in parallel to the 2nd “Pipe and Sewer Conference”. The umbrella of both events will be the “Pipeline-Pipe-Sewer-Technology Conference & Exhibition” (PPST). The practical nature of ptc was always based on the cooperation with our tech- nical and scientific supporters and on a top-class international advisory com- mittee. The conference will feature lectures and presentations on all aspects surrounding oil, gas, water and product pipeline systems.
CONFERENCES / SEMINARS / EXHIBITIONS PIPELINE TECHNOLOGY JOURNAL 79 13TH PIPELINE TECHNOLOGY CONFERENCE 2ND PIPE AND SEWER CONFERENCE 12-14 MARCH 2018, ESTREL CONVENTION CENTER, BERLIN, GERMANY Monday, 12 March 2018 Registration Coff ee (Exhibition Hall) Opening Ceremony Keynote Speech Dr. Gerald Linke, CEO, DVGW, Germany Opening Panel Discussion “Safety” Lunch Break & Poster Session (Exhibition Hall) Inline Inspection Cyber Security Materials Panel Discussion “Construction and Rehabilitation in Megacities” Get together (Exhibition Hall) Inline Inspection Off shore (Materials & Design) Tuesday, 13 March 2018 Leak Detection Trenchless Technologies Asset Management Integrity Management Off shore (Inspection) Leak Detection Construction Water Supply Networks Coff ee Break (Exhibition Hall) Lunch Break & Poster Session (Exhibition Hall) Integrity Management Management & Qualiﬁ cation Fiber Optic Sensing Planning & Design Gas Supply Networks Coff ee Break (Exhibition Hall) Operational Improvements Environmental Maintenance & Impact Repair Valves & Fittings Sewer Networks China Forum Iran Forum India Forum Wednesday, 14 March 2018 Plenary Session “Remarkable Projects” Coff ee Break (Exhibition Hall) Closing Panel Discussion “Public Perception / Social Acceptance” Closing Remarks Lunch Break (Exhibition Hall) Post-Conference Workshops (Wednesday) Post-Conference Seminars (Thursday - Friday) Exhibition (Exhibition Hall) ptc / PASC Exhibition Poster Session Meeting area ptj job & career market Conference Lounge Coﬀ ee Break Lunch Break Get together Exhibition (Exhibition Hall) ptc / PASC Exhibition Poster Session Meeting area ptj job & career market Conference Lounge Coﬀ ee Breaks Lunch Break Exhibition (Exhibition Hall) ptc / PASC Exhibition Poster Session Meeting area ptj job & career market Conference Lounge Coﬀ ee Break Lunch Break
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CONFERENCES / SEMINARS / EXHIBITIONS PIPELINE TECHNOLOGY JOURNAL 81 CONFIRMED EXHIBITORS AS OF 21.12.2017 50 DIFFERENT NATIONS DELEGATIONS FROM 50 DIFFERENT PIPELINE OPERATORS FROM ALL AROUND THE WORLD 600+ DELEGATES 70+ EXHIBITORS 80 PRESENTATIONS 20 TECHNICAL SESSIONS ACCOMPANYING SCIENTIFIC POSTER SHOW THEMATIC FOCUS: COATING CONSTRUCTION CYBER SECURITY INLINE INSPECTION INTEGRITY MANAGEMENT LEAK DETECTION MANAGEMENT + QUALIFICATION MATERIALS OFFSHORE TECHNOLOGIES OPERATIONAL IMPROVEMENTS PLANNING & DESIGN PUBLIC PERCEPTION REPAIR SAFETY TRENCHLESS TECHNOLOGIES
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Inspection Ametek – Division Creaform Germany www.creaform3d.com Applus RTD Germany www.applusrtd.com Leak Detection Asel-Tech Brazil www.asel-tech.com Atmos International United Kingdom www.atmosi.com Entegra United States www.entegrasolutions.com GOTTSBERG Leak Detection Germany www.leak-detection.de OptaSense United Kingdom www.optasense.com Pergam Suisse Switzerland www.pergam-suisse.ch PSI Software Germany www.psioilandgas.com Materials egeplast international Germany www.egeplast.de Monitoring Krohne Messtechnik Germany www.krohne.com PIPELINE TECHNOLOGY JOURNAL 85 COMPANY DIRECTORY CONFERENCES / SEMINARS / EXHIBITIONS Repair CITADEL TECHNOLOGIES United States www.cittech.com RAM-100 United States www.ram100intl.com T.D. Williamson United States www.tdwilliamson.com Research & Development Pipeline Transport Institute (PTI LLC) Russia www.en.niitn.transneft.ru Safety DEHN & SÖHNE Germany www.dehn-international.com/en HIMA Germany www.hima.de TÜV SÜD Indutrie Service Germany www.tuev-sued.de/is Surface Preparation MONTI - Werkzeuge GmbH Germany www.monti.de Valves & Fittings AUMA Germany www.auma.com IMI Precision Engineering Germany www.imi-precision.com Zwick Armaturen Germany www.zwick-armaturen.de
13TH PIPELINE TECHNOLOGY CONFERENCE 12-14 MARCH 2018, ESTREL CONVENTION CENTER, BERLIN, GERMANY 2ND PIPE AND SEWER CONFERENCE 12-14 MARCH 2018, ESTREL CONVENTION CENTER, BERLIN, GERMANY Europe’s Leading Pipeline Conference and Exhibition, taking place at the Estrel Berlin, Berlin, Germany www.pipeline-conference.com International Conference and Exhibition on Pipe and Sew- er Technologies, taking place at the Estrel Berlin, Berlin, Germany www.pipeandsewer.com n o i t c n u n o c n j I Next Issue: February 2018 Pipeline Technology Journal In the next Edition of ptj: Management & Qualification www.pipeline-journal.net BONUS DISTRIBUTION AT PTJ PARTNER EVENTS 41st Offshore Pipeline Technology Conference 27 Feb. - 01 Mar. 2018 Amsterdam, the Netherlands 13th Pipeline Technology Conference (ptc) 12 - 14 March 2018 Berlin, Germany 2nd Pipe and Sewer Conference (PASC) 12 - 14 March 2018 Berlin, Germany Midstream Oil and Gas Congress 2018 26 - 27 March 2018 Copenhagen, Denmark Pumps, Valves, Pipes and Compressor Industrial Exhibition (PVPC) 28 - 29 March 2018 Abu Dhabi, UAE Pipeline Technology Seminar: Life-Cycle Extension 28 - 29 March 2018 Abu Dhabi, UAE Pipeline + Energy Expo 03 - 05 April 2018 Tulsa, OK / United States
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