inspection and monitoring tools, and (5) more effective integrity management ... in Mooring Systems Possibly Put Floating Structures at Riskâ, Safety Alert. No.
OTC 25134 Mooring Integrity Management: A State-of-the-Art Review Robert B. Gordon, Martin G. Brown and Eric M. Allen, DNV GL
Copyright 2014, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 5–8 May 2014.
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This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.
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Abstract There is consensus within the offshore oil & gas industry that there are too many instances of premature mooring line replacement and failure. In response to this situation, there has been rapid growth in mooring integrity related research and development. It has become difficult to keep track of all of this activity. The purpose of this paper is to provide a comprehensive review of the current state-of-the-art in mooring integrity management. Particular focus is given to coverage of the latest information on mooring failures, component degradation processes, monitoring and inspection technology, and mooring integrity management systems.
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Introduction Production of oil & gas using moored Floating Production Units (FPUs) has been experiencing exponential growth. As of November 2013, there were 277 FPUs in use around the world, of which 62% were FPSOs (Offshore, 2013b). In addition, there are many moored FSOs and CALM buoys. Moored facilities are located in many different operating areas, environments and water depths (Offshore, 2013a). This growth has resulted in a major challenge to operators, designers, mooring component suppliers, installation contractors, regulators, and Class Societies to assure the integrity of these facilities. As the worldwide fleet of FPUs grows, there also is a related growth in the number of aging FPUs, some of which are nearing or have exceeded their original design lives. Any mooring arrangement is an essential subsystem of a FPU. The UK Health and Safety Executive (HSE) classifies a FPU mooring system as a Safety Critical Element within the definition of the Safety Case Regulations in the UK. Mooring incidents on floating units associated with oil & gas production (e.g., FSOs, FPSOs, semisubmersibles, spars, CALM buoys) have been occurring at a high rate (Ma, et al., 2013; Majhi and D’Souza, 2013; Maslin, 2013). These have included premature line replacements as well as single and multi-line breakage. Some incidents resulted in vessel drifting, riser ruptures, production shutdown and hydrocarbon release. The number and severity of these incidents have caused concern by owners, operators, insurers and regulators. According to Oil & Gas UK (2008), “[h]istorically the number of incidents that have occurred with FPSO moorings would suggest that there is room for improvement in the management of FPSO moorings in general.” The launch event for a new Floating Unit Mooring Assessments (FUMA) guidance took place in January 2014. The intended audience are underwriters and brokers with an interest in offshore energy indicating that the insurance industry is carefully weighing mooring risks against rates. Failures have occurred due to a range of causes including overload, fatigue, manufacturing defects (including low metal toughness), out-of-plane bending, and excessive wear and corrosion. Mooring system failures can be of high consequence, potentially resulting in extended production shutdown and installation or commissioning delays. There is clearly a need to focus on mooring integrity management including consideration of hazard identification, organizational issues, inspection, and technology. There is a need for good data on current conditions, understanding of degradation processes, use of best technology to determine safety margins, development of new techniques (e.g.; monitoring) and implementation strategy (including remedial and mitigation measures). Operators have been actively developing Floating Systems Integrity Management (FSIM) (e.g., Lanquetin, 2006; Bhattacharjee, et al., 2009; Geyer, et al., 2009; Wisch and McMaster, 2009). However, practical implementation of an Integrity Management program within a global organization can be difficult. The goal of this state-of-the-art review paper is to summarize key findings and provide a comprehensive list of pertinent literature in the field of mooring integrity. Our hope is that this paper will help individuals and companies (including smaller operators) new to this field get up to speed quickly.
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Existing Industry Guidance The primary industry guidlines for permanent mooring systems are ISO 19901-7 (ISO, 2011) and API RP-2SK (API, 2005). Other pertinent API recommended practices include RP-2I (API, 2008), RP-2SM (API, 2011a), Spec 2F (API, 1997), and Spec 9A (API, 2011b). Class Socities also provide very useful guidance (e.g., ABS, 2009, 2011; BV, 2012; DNV, 2013a, 2013b, 2013c, 2013d). The Mooring Integrity Guidance (Oil & Gas UK, 2008) describes an integrity management system specific to mooring systems. This Guidance is presently being updated with a new version expected during 2014.
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Mooring Failures The key to improving mooring system integrity is to learn from past failures. Some of the literature dealing with historical mooring failures is identified in this section. The Noble Denton Phase 1 Mooring Integrity JIP (Brown, et al., 2005; Noble Denton Europe, 2006) included a survey of mooring failures. Most of the failure data available was from the North Sea where there are statutory requirements for reporting mooring incidents to the UK HSE. Based on data for the period 1980 to 2001, they reported that, on average, an FPU will experience a mooring line failure every 9 years. Failures were most frequent at terminations (fairleads, bending shoes, hawse pipes, etc.), the touchdown region on the seafloor and at connectors. Many failure mechanisms were examined including corrosion and wear, friction induced bending, unintended line disconnection, and unbalanced set-up pretensions. This relatively high failure rate of permanent mooring systems raised concern in the offshore industry. One response has been more open communication between operators, regulators and the mooring service industry through forums such as the Mooring Integrity User Group (MIUG). This group, which evolved from the Noble Denton Mooring Integrity JIPs, is organized by Arun Duggal of SOFEC, and meets twice a year during the FPSO Research Forum (www.fpsoforum.com). Many valuable mooring integrity presentations are archived at this web site. Recently Ma, et al. (2013) reported on mooring failures occurring during the period 2001 to 2011. They report on a total of 21 mooring incidents including 8 major incidents. The major incidents included multiple line failure, loss of station keeping, emergency production shutdown, and damage to risers with associated hydrocarbon leak. They concluded that the annual probability of mooring system (i.e.; multiple line) failure is on the order of 3x10-3. A number of failure mechanisms were identified including some considered relatively novel such as out-of-plane bending, chain hockling/twisting/knotting, flawed flash butt welds, low fracture toughness and pitting corrosion. A number of mooring lines failed or were found to be under-strength because improper weld repairs were performed on defects. In the majority of instances, mooring line failures occurred at an interface or discontinuity. Majhi and D’Souza (2013) report on premature mooring line replacement as well as failures during the period 2000 to 2011. They reported 23 documented FPU mooring failures with 4 FPUs having sustained total mooring system failure with associated riser failure and field shut-down. Twenty FPUs required partial or complete mooring replacements and repair on at least 150 mooring lines. Kvitrud (2013) describes 13 failures of mooring lines in Norway during the period 2010-2013. Although most of these are Mobile Drilling Units, some of the failures were for permanently moored facilities (Navion Saga FSO, Norne FPSO, Petrojarl Varg FPSO). Failures are reported as caused by a mixture of overload, fatigue and mechanical damage. Very useful information on individual mooring failures are provided by Smedley (2009), Wang, et al. (2009), L’Hostis (2011), BOEMRE (2011), Finucane (2012), and Leeuwenburg (2012).
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Failure Modes This section discusses recent advances in understanding causes and modeling the effects of the primary mooring failure modes. Fatigue Fatigue damage is accumulated in a mooring line component as a result of cyclic loading. Prediction of fatigue damage relies on empirical data (e.g., S-N fatigue curves). Fatigue life is a function of cyclic loading (tension, bending, twisting), corrosion, wear, and initial defects. Tension-Tension Fatigue of Large Diameter High Strength Chain Grade R5 chain (178 mm diameter) is currently in production. Cañada (2008) of the chain manufacturer Vicinay Cadenas presented plans for delivering R6 and R7 grade chain in the next few years. However, the fatigue performance of higher grade chain is not well understood. Existing chain S-N curves are based mainly on fatigue data obtained in the 1990s (e.g., Stiff, et al., 1996). The maximum diameter tested was 76 mm for studless and 100 mm for stud link chain in steel grades R3 and R4. Fatigue testing of large diameter (127 mm), high strength (R5) mooring chains in seawater is currently being undertaking by TWI as part of a JIP (TWI, 2012). This JIP is also working to establish a better understanding of failure mechanisms including crack initiation/propagation, corrosion/fatigue/wear interaction, residual stress/mean stress and the effect of proof loading. FEA will be used for the prediction of residual stresses and fatigue endurance.
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Out-of-Plane Bending and Twist Induced Fatigue
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The combined effect of tension and out-of-plane bending (OPB) of links can result in fatigue failure at terminations such as fairleads and hawse pipes (Morandini and Legerstee, 2009). Interlink friction tension bending fatigue and, where applicable, wheel fairlead tension bending fatigue should be addressed in the design of permanent mooring systems. Buoys and clump weights are also likely to introduce bending effects which may have an undesirable impact on the fatigue life (Noble Denton, 2006). Melis, et al. (2005) identified the mechanism of OPB, which explains the extensive fatigue damage experienced on the Girassol CALM buoy chain. They describe a full scale test program having the capacity to apply inter-link rotation to a pretensioned chain. They explain the OPB mechanism and provide an empirical relationship to predict the OPB stresses in the chain links as a function of pretension and interlink rotation. The OPB stress relationship obtained was applied to the failed mooring chain of the offloading buoy with reasonable agreement. Jean, et al. (2005) summarize a methodology developed to estimate the fatigue damage in chain subjected to bending. The methodology is applied to the design of the connecting arm of the Girassol CALM buoy. They found that although the methodology accurately predicts the fatigue failures of Girassol, it tends to be overly conservative when applied to other systems. Rampi and Vargas (2006) performed OPB fatigue testing on smaller chain sizes (40 mm). The test rig included scale models of the chain hawse pipe. Both a chain hawse with internal curvature where a link rests on the entrance (similar to the Girassol CALM buoy), and a straight chain hawse based on current design practice were used. Measured OPB stresses were reported. Fatigue loading in the OPB mode was applied for several configurations. The two hawse configurations exhibited different stress levels and fatigue performance. Lassen, et al. (2009) describe the behavior of chain segments subjected to pretension and a rotation angle at the segment end based on experiments and FEA. They describe a full scale test using 125 mm diameter studless chain which supports the assumption that the chain segment behaves semi-rigidly under high tension due to locking of the inter-link hinge mechanism. OPB stresses are significant for critical links close to the end hang-off, and this effect must be taken into account when carrying out fatigue life predictions. They recommend a hot spot method for fatigue life predictions. Under a combined loading mode, defined by tension and OPB, the maximum principal stress range in the link bend area must be determined by refined finite element analysis. Subsequently, the fatigue life can be predicted by using an appropriate hot spot S-N curve. The OPB Chain JIP, led by SBM Offshore, issued its final report to JIP particpants in July 2013 (Rampi, 2013). Although this report is propriatary to JIP participants, the findings may eventually provide guidance to the industry in this area. Mooring chain can twist in response to torque generated in the adjacent elements of a mooring or even be inadvertently installed in a twisted condition. For example, L’Hostis (2011) stated that twist in chain links is the most likely failure mechanism for the Dalia P5 anchor line fatigue failure. Ridge, et al. (2006) present experimental and theoretical results on the torsional response of large mooring chain. In another experimental study, Ridge, et al. (2011) investigated the effect of initial twist on the fatigue life of studless chain using 16 mm studless chain. Twist levels of up to 24° per link were examined. The measured effects of initial twist on fatigue life were found to be small. The authors advise that practical reasons remain for continuing to minimize twist in mooring chain, and that caution should be applied in extrapolating their results to predict the effect of twist in full scale offshore mooring chains.
Hostile environments such as seawater can accelerate the initiation and growth of fatigue cracks, particularly in the presence of mean tensile stresses. Mooring line failures have occurred due to crack propagation in chain links. The crack propagation is accelerated by corrosion. Fretting-type fatigue cracking can occur around the interlink region where wear patterns indicate that there is significant sliding and rotating at the interlink region (Noble Denton, 2006). At present there is little data available indicating how the break strength of long term deployed mooring components will be reduced by wear, corrosion (including pitting) and the possible development of small fatigue cracks (Morandini and Legerstee, 2009). No technology currently exists which can reliably check for small fatigue cracks underwater. Loose chain studs are recognized to be involved in crack propagation and fatigue of chain link material. Offshore oil industry experience with studded chains has shown that during use, the studs frequently loosen, and the seat of the stud is often the initiation point for fatigue cracking (Lee and Hua, 1994). Consequently, there are prescribed re-certification protocols to determine the presence and the degree of looseness of studs. However, it is worth stressing that if the studs stay tight the fatigue endurance of studded chain is superior to that of studless chain. Lassen, et al. (2005) present experimental fatigue crack growth behavior for R4S grade steel in seawater. The measured growth rates were compared with rates for medium strength carbon manganese steels found in recommended practice (i.e., BS7910). The presented growth rates are well within the scatter band given for these steels in air and free corrosion. They established a linear elastic fracture mechanics model to study the fatigue behavior in a studless chain link. The model was used to construct S-N curves that are consistent with experimental fatigue lives and the design curve given in DNV-OS-E301 (DNV, 2013a). Growth rates are consistent with tested fatigue lives. Lardier, et al. (2008) describe an analysis method to assess mooring reliability under combined fatigue cracking and
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corrosion wastage using the 2-dimensional Paris-Erdogan equation. The corrosion was treated by considering diameter reduction and the fatigue crack growth rate for the splash zone, main catenary and on-bottom regions. A fatigue reliability case study of studless chain links was carried out to illustrate the effect of corrosion. Sensitivity to initial crack size, crack aspect ratio and the material correlation between links was investigated. The case study found that the splash zone has an important effect on the failure probability of the entire mooring line, especially under long-term corrosion. Stress Concentration More and more use is being made of advanced Finite Element Analysis for calculating chain stress concentration factors (SCFs). For example, Vargas, et al. (2004) presented SCFs from nonlinear FEA with contact for studless 133 mm mooring chain in a seven pocket fairlead. The computed SCFs of the studless link interacting with the fairlead pocket were 15% higher than the corresponding SCFs in a chain link away from the fairlead. Wear
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Chain wear is most prevalent at terminations (e.g., hawse pipes, fairleads) and the sea floor touchdown (“thrash zone”) area (Noble Denton, 2006). Brown, et al. (2005) found that chain wear and corrosion in the thrash zone on a North Sea FPU was significantly higher than specified in mooring design codes. The wear appeared to be more pronounced on the less heavily loaded leeward lines, which appears to be due to the greater interlink rotation occurring on the leeward lines. Brown, et al. (2010) report confirmation that wear can be faster on leeward lines and that certain weighted chain designs are susceptible to local rotations at the weight per meter discontinuity. UK HSE Safety Notice 3/2005 (HSE, 2005) warns UK Continental Shelf (UKCS) FPSO and FSU operators about the risk of excessive wear to the top sections of their mooring chains. This was based on the experience of several UKCS FPSOs that experienced premature mooring chain wear due to trumpet contact. Duggal and Fontenot (2010) note that “wear between links can also be an issue when the relative motions between links exceed 0.5 degrees (this depends on tension level) or the chain is in dynamic contact with a hard surface either at the fairlead or the seabed.” It is important to make baseline measurements of the as-built chain and use the same procedure to measure the chain diameter during every inspection. The fairlead design impacts the long-term wear and fatigue performance of the chain at the fairlead. Consideration should be made of using a larger top chain size than the minimum required to accommodate uncertainties in wear rate. The designer should protect the chain from wear by making surfaces contacting the chain softer than the chain. Brown, et al. (2010) present a practical method to estimate mooring line wear and corrosion which is calibrated against field measurements. They note that wide variation exists in the observed chain link wear rate within the inter-grip region. They conclude that the variations must be due, in part, to variations in vessel motions. They report wear rates up to 3-4 mm per year. Brown, et al. (2005) note that “there is little data available which indicates how the break strength of long term deployed mooring components will be reduced by wear, corrosion including pitting and the possible development of small fatigue cracks. Thus to assess long term integrity with any confidence it is recommended that break tests on a statistically representative sample number of worn components should be undertaken.”
Fontaine, et al. (2012a, 2012b) reported results from the SCORCH JIP dealing with forensic investigation of severely corroded (pitted) chain recovered offshore West Africa. Their tentative conclusion is that the pitting corrosion is due to Microbiologically Influenced Corrosion (MIC). Load tests on the recovered chain showed surprisingly good residual strength despite large reduction in cross-sectional area. Three-dimensional laser imaging of some of the chain links was performed to define the surface geometry. The SCORCH JIP will also be providing to its members a design guidance and analytical tools for specifying wire ropes and chains to maximize their service life for given site conditions (particularly in tropical waters). The presence of MIC in the deepwater GOM is reported by Miller (2012). In a follow-up to the SCORCH JIP, AMOG Consulting is leading the “Finite Element Analysis of Residual Strength of Severely Corroded/Worn Chain” (FEARS) JIP (AMOG, 2012). As the name states, this JIP will use FEA to model the residual strength of corroded and worn chain using the actual geometry of recovered links. The FEA results will be benchmarked against load test results. Gao, et al. (2005) developed a time variant overload reliability analysis of a mooring system due to corrosion deterioration. The analysis makes use of a probabilistic model for uniform corrosion to predict the strength degradation. A nonlinear FEA is used to calculate the breaking strength. They found that the annual failure probability increases significantly as the chain is corroded. The number of chain links in the splash zone is small, but these links are subjected to more severe corrosion deterioration and consequently dominate the strength of the whole corroded mooring line. Melchers, et al. (2007) describe a procedure for estimating the corrosion loss of low-alloy steel chain under continued immersion corrosion conditions. The procedure includes the effects of water temperature, salinity, water velocity, and surface roughness on steel corrosion under field conditions. Since the working of the chain does not allow corrosion products (rust)
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to build up on the critical contact surfaces, erosion due to wear and abrasion can be estimated separately. Two example applications are given. Duggal and Fontenot (2010) state that corrosion rates for connectors are similar to chain except if cathodic protection is used. Chaplin, et al. (2008) discuss degradation of wire rope mooring lines in SE Asian waters. In the majority of wire rope systems deployed, unless fully sheathed in plastic, the actual life of the rope has been found to be less than that of the installation. This requires an integrity management program that includes life prediction, inspection and replacement. The authors discuss the efficacy of various options such as zinc wires. Case studies are described illustrating how service life can be influenced by the local conditions. Primary factors in determining long term life are the weight of zinc coating on wires, the effectiveness of lubricant as a blocking compound, and especially the rate of zinc dissolution. The rate of zinc dissolution is accelerated by sea water temperature. This is a major difference between some tropical locations and the North Sea. Corrosion rate recommendations based on North Sea experience are not appropriate for tropical waters. Fontaine, et al. (2009) describes a proposed semi-empirical model for seawater corrosion of six strand wire rope. The model includes the local effects of water temperature, oxygen concentration, flow velocity, together with the location of the wire within the internal rope structure and the zone location along the rope. The analytical formulation of the model is supported by physical considerations, and calibration of the model parameters is performed against a large set of experimental results available in the literature. Duggal and Fontenot (2010) state that wire rope wires near the socket continue to break over time and are corroded to the center of the rope (unsheathed wire with no bend stiffener). Typically wire rope segments are electrically isolated from the connecting components using Orkot or equivalent bushings and washers although there is some debate about whether or not this is good practice. They state that “[i]t is our experience from surveys and from recovered wire rope that these anodes are depleted much faster than expected, even if the socket coatings are in good condition.” The cause is not well understood. There is concern that “inspection of the wire’s condition at the socket or in the bend stiffener is very difficult and possibly cannot be determined.”
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The Gryphon Alpha FPSO (Maersk, 2011; Finucane, 2012), a turret moored FPSO operating in the UKCS, experienced a multiple mooring line failure under storm conditions in February 2011. The initial line failure was attributed to the failure of a flash butt weld failure. Once this line failed, thruster issues resulted in the FPSO becoming beam on to the waves resulting in failure of three additional lines. Kvitrud (2013) noted that the Petrojarl Banff FPSO multiple mooring line failures that occurred in December 2011 started with a chain failure initiated at the fairlead probably due to overload. The floating storage unit Navion Saga at the Volve field in the North Sea experienced two mooring line breaks in steel wire ropes in 2011 (Aksnes, et al., 2013). All fractured strands had cup and cone failure indicating ductile overload. Investigations of the broken ropes indicated that high stresses near the wire socket induced by large bending moments in leeward mooring lines could be the cause of failure. A numerical model investigation by Aksnes, et al. (2013) showed that the connecting link plate between the upper chain segment and the upper wire segment, which lies initially on the seabed, lifts off the seabed during storm conditions. When this occurs, the link plate and the wire socket fall to the seabed at a higher speed than the upper wire segment. This results in significant dynamic tension at the fairlead, which results in small curvature in the wire near the socket. Potential Contributing Factors Manufacturing Defects MMS Safety Alert No. 259 (MMS, 2008) identified “catastrophic failures in mooring systems” as possibly putting floating structures at risk. This was based on the Kikeh spar mooring shackle failure, which was determined to be caused by improper heat treatment resulting in low toughness (Cottrill, 2008; McMaster, et al., 2010; Hughes and Flores, 2010; Ma, et al, 2013). At the time the Kikeh shackle failed, Chevron’s Tahiti spar was scheduled for installation in the US Gulf of Mexico. The Tahiti mooring system also made use of shackles of similar size from the same manufacturer. One of the Tahiti shackles was tested and also failed at a load well below its rated strength due to low toughness. This delayed the Tahiti Spar installation by one year in order to replace the shackles. Heat treating after casting apparently resulted in a metal being unable to meet “Charpy” standards for material “toughness.” The MMS advised operators to (1) include sufficient Charpy testing requirements in the specifications to insure that materials and manufacturing process will produce a product of sufficient toughness, (2) review their specifications requirements to insure testing and manufacturing produces a product that will meet the usage demands, (3) review their requirements for both destructive and non-destructive testing of critical elements, (4) insure their test coupons are properly representative, and (5) review their requirements for equipment inspection and handling to insure no damaging techniques are employed in transportation or installation. Ku and Gallagher (2013) describe incidents in which, “[p]ost-failure analyses indicated that manufacturing processes were defective for each case,” namely related to post-weld heat treatment.
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Installation and Accidental Damage
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Majhi and D’Souza (2013) report that a majority of the early mooring line replacements considered in their study were attributed to installation damage and systemic defects not accounted for in design. They noted that engagement of the installation contractor frequently occurs late in the design stage. Consequently, communication between installation and design teams can be less than ideal. Unsheathed spiral strand wire can be easily damaged during handling and installation and can birdcage if twisted. There have been several instances in the industry where sheathed spiral strand and polyester rope has been damaged while retrieving installation equipment or pulling in risers (Duggal and Fontenot, 2008; Trower, 2011). Polyester rope is easily damaged during installation and it is common to always include a spare rope segment while the system is being installed to ensure that the installation can go on while rope damage is being evaluated (Duggal and Fontenot, 2008). Consequently, well defined installation equipment and procedures are required. Petrobras has experienced damaged and severed polyester lines during installation. This damage was due to interference with work wires during normal operations, and was not due to normal operational loads. Ayers (2001) found that the general effect of external damage to the midline polyester rope body is to reduce the residual breaking strength of the rope assembly. A given damage level can produce different levels of residual strength, depending on the rope design, the splice design, and their interaction. Generally the splice region is weaker than the rope body. Otten and Leite (2013) report on the Thunder Hawk semisubmersible dropped chain/polyester/chain mooring line. Both polyester and sheathed spiral strand rope are subject to damage due to dropped objects and riser pull-in/payout procedures. The sheathing is prone to damage but wire rope is less susceptible to total failure compared to polyester rope if damaged. There have been several instances of anchor leg damage caused during riser pull-in (Duggal and Fontenot, 2008). Numerical models of the ‘As-Installated’ condition (including any installation damage) of the mooring system should be developed as part of the Mooring Integrity Management program. Perinet, et al. (2006) provide lessons learned from their experience in installing deepwater FPSO mooring systems in West Africa.
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Current industry design codes lack comprehensive guidance on a number of important design considerations such as transient environmental loading (e.g., W. Africa squalls), fatigue damage due to Out-of-Plane Bending (OPB), and degradation models for wear and corrosion (Majhi and D’Souza, 2013). Also, guidance for turret mooring design, in which transient yaw responses can be significant, is generally lacking. Additional industry guidance is needed for fairlead design to minimize chain twist and OPB. The role of local Finite Element Analysis to estimate the magnitude of hot-spot stresses and Stress Concentration Factors should also be considered in industry design codes. It is not uncommon for a mooring system to be “over-optimized” for modest cost savings in procurement, but resulting in a mooring system that is not robust to uncertainties in component degradation, loading, etc. Moorings should be designed to ensure that the coupling segments between wire and ground chain segments never touch the seabed, or that they are always on the seabed (Aksnes, et al., 2013).
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Mooring Integrity Management Life Cycle Integrity Management
An effective integrity management system is one that is operational during the entire project life cycle, not limited to just an inspection and monitoring program during the operational phase. Integrity management considerations should also be taken during the design, fabrication and installation phases. Duggal and Fontenot (2010) state that “[g]ood long-term performance starts with design and is also influenced by the installation of the system, and in-service monitoring and maintenance programs.” Stated another way: complex projects should incorporate integrity management considerations within the design phase. Elements of an Integrity Management System A generic Integrity Management System, taken from DNV-RP-F116 (DNV, 2009), is presented in Figure 1. Core processes include: risk assessment and planning; inspection, testing, and monitoring; integrity assessments; mitigation, intervention, and repair. Supplemental, but still necessary, items for practical implementation include: company policies, MOC procedures, and information management. The Mooring Integrity Guidance (Oil & Gas UK, 2008) describes an integrity management system specific to mooring systems. A revised version of the Mooring Integrity Guidance is in preparation and is scheduled for release in 2014. In addition, a recently completed project funded by DeepStar and carried out by AMOG Consulting has resulted in a very comprehensive Mooring Integrity Management Guideline (MIMG). DeepStar is considering releasing the MIMG to API for use in developing an API Recommended Practice in Mooring Integrity Management.
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Management of Change
Company Policy Mitigation, Intervention & Repair
Organization & Personnel
Risk Assessment and IM Planning
Contingency Plans
INTEGRITY MANAGEMENT PROCESS
Reporting & Communication
Integrity Assessment Operational Controls & Procedures
Audit & Review
Inspection, Monitoring & Testing
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Figure 1: Integrity Management System (DNV, 2009)
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A major challenge for any Asset Integrity Management System is to integrate and fully implement the various activities across the organization. This can be a challenge in a large, international company. The AIMS owner needs to assure that clear, standardized guidance is provided to those responsible for carrying out each component. Frequently, those carrying out AIMS related work on a particular asset (e.g., inspection) will be part of a subsidiary business unit (sometimes in a remote part of the world) which does not report directly to the AIMS owner. Individuals responsible for execution of important parts of the AIMS may not be integrity management specialists. This can result in organizational and implementation challenges. Effectively translating AIMS strategies and procedures into actions can be challenging. Agreement on roles and responsibilities for complex processes require careful consideration, and may take years to find the right combination. Therefore, keeping the process simple with respect to implementation is a good rule of thumb. For an effective AIMS, seamless integration is key.
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Monitoring is an important part of mooring integrity and should be enforced an as viable means to address the condition of the mooring system, along with inspection programs. Ideally, mooring system designers should implement mooring monitoring programs to supplement and validate the design assumptions and approach, along with expected performance of the system. A greater level of confidence is achieved when a robust inspection program is combined with a condition monitoring program. The benefits of mooring monitoring systems include having a complete tension record history and an instant warning of line failures (Elman, et al., 2013). Brown, et al. (2005) note that “[g]iven the safety critical nature of mooring lines one might imagine that they would be heavily instrumented with automatic alarms which would go off in case of line failure. In practice many FPSs are not provided with such instrumentation/alarms.” Ma, et al. (2013) state that “[e]very floating system should assess whether it has sufficient monitoring capability to demonstrate that it is safely moored.” The UK HSE (HSE, 2013) states that operators should measure and record mooring line tension, with the intention being to verify mooring line integrity and detect line breakage. They state that various surveillance systems are available in the industry, and if none apply, then positional GPS offset of the floater must be constantly monitored to estimate tension loads. Morandi and Legerstee (2009) state that “[t]ogether with a monitoring of the environmental condition seen by the floating unit, the monitoring of each mooring line composing the station capability of the unit will allow to derive the range of loads imposed to the mooring line together with their frequencies.” Some monitoring methods give more functionality than just detection of one or more failed lines (Oil & Gas UK, 2008). Direct tension measurement, or line angle measurement that leads to a calculated tension, on one or more legs, can provide input data for more in-depth analysis of mooring responses, together with metocean conditions monitoring. Such analysis can confirm that the actual behaviour is consistent with the design. Irani, et al. (2007) describe a marine monitoring system that BP uses on its Gulf of Mexico FPUs. The system includes monitoring of critical environmental parameters such as wind, wave and current conditions. Monitoring of the floating system responses includes vessel motions from DGPS and inertial motions sensors, and mooring line tensions and riser responses. Direct mooring line tension measurements can be made using in-line load cells. These load cells can be located at the base of the chain stopper, windlass, in a shackle load pin, or in-line with the mooring chain (Campman, et al., 2010; Strainstall,
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2009). Lugsdin (2012) describes an acoustic system that can monitor in real time the mooring legs below a turret to assure that the lines are intact. Daran, et al. (2009) and Elman, et al. (2013) describe a new Anchor Leg Load Monitoring System (ALLMS). This system (also marketed under the name Inter-M Pulse) offers an alternative to load cells for direct tension monitoring of mooring lines. The ALLMS system uses both an inclinometer to measure mooring line angle and strain gauges. Data is logged and acoustically transmitted to the surface in case of a loss of tension or periodically to retrieve data series for analysis. The system is integral to the mooring line through an H-link connector. Jacob, et al. (2011) describe a secondary system to continuosly monitor the mooring line tensions for the Cascade Chinook FPSO. This software system simulates the vessel and mooring responses. It accepts as input ROV measured points along the mooring lines. This system is operational on the FPSO. The use of a Differential GPS (DGPS) to monitor vessel excursion and heading can help detecting a change of vessel movement behavior. Any quick drift in the order of minutes that is unrelated to an environmental or external force could be interpreted as a potential mooring line failure, although depth of water will have some influence on whether such a change is likely to be detected. Inspections
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Inspection of permanent mooring systems occurs in numerous phases of an asset’s lifecycle. The first inspection, also known as the baseline inspection, should be performed after mooring system installation. Afterwards, mooring systems should be inspected at various times as dictated by Class or by company requirements. Inspection following extreme environmental events is also common within the industry. For example, the U.S. Bureau of Safety and Environmental Enforcement (BSEE; formerly part of the Minerals Management Service, MMS) has post-hurricane inspection and reporting requirements (MMS NTL No. 2009-G30; MMS 2009). API RP 2I (API, 2008) provides useful inspection guidance and retirement criteria. Mooring inspection methods are discussed in detail in Oil & Gas UK (2008) and Brown, et al. (2010). Brown, et al. (2010) give specific mooring inspection guidance for ROV operators and subsea engineers. Permanent mooring systems are designed using a wear and corrosion allowance. Therefore, a major goal of an inspection program is to validate that the wear and corrosion levels are within the design values. Inspections may also discover anomalies, significant or otherwise.
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Allan, et al. (2013) describe a type of “Progressive Inspection Technique” for offshore mooring systems. The intent of this type of program is to be able to identify equipment that is fit for service and consists of three separate elements: (1) a highlevel general visual inspection (GVI) is performed to identify gross anomalies and damage, (2) upon identification of these anomalous features, a close visual inspection (CVI) is performed to further classify and understand the abnormality, and (3) 3D geometric modeling and Finite Element Analysis are used to quantify the residual strength of the mooring system components. This type of inspection program, which incorporates a number of Welaptega’s measurement and modeling tools, has allowed operators to identify the most severely degraded sections in a mooring system. While attempting to complete tensioning operations of the Thunder Hawk polyester mooring ropes to remove construction stretch, an equipment failure caused a line to fall to the seabed. This mooring line was subsequently recovered. In order to maintain the rope as a spare, a qualification program was proposed. Otten and Leite (2013) describe the testing process to prove the residual strength and fatigue capacity of the rope is adequate for use in operation. The use of the rope as a spare was approved by BSEE. BP’s Mad Dog spar was the first floater in the Gulf of Mexico to incorporate polyester moorings. Two issues before proceeding with the use of polyester were: (1) development of adequate assurance that the mooring could be safely operated over the field life and (2) assuring a high quality product could be manufactured for all the rope segments and test inserts particularly since the spliced end termination is a handmade component (Petruska, et al., 2004). The In-Service Inspection, Repair, and Retirement (IMRR) Plan was developed to ensure the long term integrity of the mooring system. The main objective of the IMRR plan is to identify damage or unusual performance of any component of the mooring system. The IMRR also includes prediction of how a change in material behavior may affect the station keeping ability of the facility. The IMRR also gives specific conditions that would require a shut-in of production and defines what is required before production could commence again. The overall IMRR plan consists of the following: (1) ROV inspection, (2) test insert recovery with associated testing, and (3) mooring tension monitoring. In general, the inspection interval being followed is every 2.5 years, unless inspection was required for another reason (i.e., hurricane, dropped object). The UK HSE issued a safety notice (UK HSE, 2005) for operators who operate weathervaning floaters. The safety notice made reference to a case in which deterioration of chain links due to wear occurred after just 4 years into a 20-year design life. The wear resulted in the chain apparently becoming insufficient to achieve the designed factors of safety. This caused the HSE to issue the notice which requires all operators to inspect the chain connections to the turret. The potential for multiline failure was described as follows (UK HSE, 2005): “[d]efects that affect more than one mooring chain can increase the risk of multiple mooring line or system failure.”
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Offshore Information Sheet (OIS) No 4/2013 (UK HSE, 2013) states that an inspection program should take “into account the lessons learned from recent mooring failures during on the United Kingdom Continental Shelf (UKCS) and reflects the emergence of newer, widely accepted codes and standards.” Specifically, OIS 4/2013 states that the termination of the mooring at the turret, and thrash zones in the touchdown zone are areas that have been shown to have increased wear failures, and should be included in any inspection program. Operators are expected to identify critical areas of mooring systems, and prepare inspection schemes representative of the critical areas, in addition to the recommended practices in the Oil & Gas UK’s Mooring Integrity Guidance (Oil and Gas UK, 2008) and Class Society requirements where applicable. The frequency of inspection should increase with age of the mooring. With respect to acceptance criteria for inspections, testing, preventative maintenance, or condition monitoring AIM tasks, the operator should establish clear pass/fail acceptance criteria for all mooring system components. Inspection Techniques
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Hall and Trower (2011) described several state of the art inspection techniques for chain, rope and connector measurements. They describe an optical caliper system that measures mooring chain dimensions for elongation and wear of chain. Measurements are usually concentrated in groups, to build a sample of measurements indicative of larger sections of chain. A typical survey includes groups of measurements in the Splash Zone/Turret Interface, close to connectors near wire/rope sections, and in the touchdown zone. When a dive support vessel is not available, mechanical calipers can be used to measure chain grip zones and other subsea components directly from the FPU in many cases using a mid size ROV. A rope measurement device called the Rope Measurement System (RMS) consisting of four high resolution digital cameras record real time images of the rope’s circumference. Computational algorithms are used that allow for a detailed representation of the rope’s cross-sectional area to be developed in real-time. Birdcaging, wear, cuts, abrasion and changes in diameter can in general be detected by this tool. This provides a means for detecting necking down due to sub rope damage or bulges under the rope sheathing. A change in wire rope diameter can be indicative of corrosion either to the core of the ropes construction or loss of galvanizing to the external wires. A Magnetic Rope Measuring System is also being developed which allows for a full condition assessment of the internal condition of the wire mooring. This technology can help to avoid early replacement of expensive wire ropes by understanding the rate of deterioration. It also can provide a permanent, traceable, and auditable trail of the wire condition. Three dimensional video can allow competent inspectors offshore or following inspection onshore to evaluate the longer term fitness for purpose of joining shackles, ‘H’ shackles, Tri Plates, open and closed type speltor sockets and their bend restrictors, and fiber rope splices (Hall and Trower, 2011). If an inspection indicates damage or other concerns, it is necessary to perform a more detailed diagnosis. This can be achieved by creating a three-dimensional geometric model of the mooring component. This may be used to obtain quantitative data of abnormalities such as length, depth and volume. The geometric data can also be input to other engineering tools such as finite element analysis, which can be used to estimate residual component strength. Lugg and Topp (2006) describe the Alternating Current Field Measurement (ACFM) inspection technique as a viable method for mooring surface crack detection and sizing. Originally developed for the application of inspecting welds for fatigue damage, it is becoming more accepted method for underwater inspection for mooring fatigue cracking. Work is under way to develop ACFM to detect and size defects other than the conventional semi-elliptical fatigue cracks. At present no technology exists which can check for fatigue cracks underwater, particularly in inaccessible areas (Noble Denton, 2006). Risk Based Inspection Programs
Mathisen and Larsen (2004) describe a means for determining when the upper chain segments of an FPU must be removed for non-destructive testing (NDT) using magnetic particle inspection (MPI) at onshore facilities. This requires on-site change out of segments and transportation to shore using anchor handling tugs, an expensive operation. The decision making is aided by a technique based on probabilistic modeling of fatigue crack growth in the structural components and updating of the failure probability on the basis of inspections. An extension from a single chain link to many links, where a fatigue fracture can arise in any chain link, is provided. In Lanquetin, et al. (2007), the operator has included a comprehensive Risk Based Inspection (RBI) Program, in addition to including Class Requirements, for all floating units and buoy type support structures. In general the thought was that “imposing a prescriptive regulatory inspection program, this will not generally be sufficient to guarantee the integrity of the unit on a long life span.” Further guidance is also given regarding the structure of the multi-level RBI approach in combination with structural models, inspection findings and trend analysis, which can help to define where, when and how to inspect.
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As-Built Survey An As-Built Survey should be performed in accordance with API-RP-2I (API, 2008) and the RBI program. This survey should be performed once the mooring system is hooked up to the floater and the lines are tensioned to the designed values. The as built survey serves as the baseline for comparison for all subsequent surveys over the lifecycle. All surveys should be documented accurately and in sufficient detail. The As-Built Survey is also conducted to ensure that the mooring system is connected as designed, to determine if any damage has occurred during installation, and that the twist in the mooring lines is within design margins. As-Built Surveys are generally conducted from the anchor to as close to the surface as is practical. Failure Procedures and Contingency Planning
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The MIG (Oil & Gas UK, 2008) states that a failure procedure and associated phiolosophy should address the following issues: How to identify that a failure has occurred. What actions should be taken when such a failure is suspected; this would likely include a means to check that the failure has occurred (unless obvious), who to notify, whether to shut down production, etc. What Emergency Response analysis services should be in place. What actions should be taken when such a failure has been confirmed; this would likely include at least a temporary production shut down for full evaluation, and subject to the weather forecast or other circumstances, may include down-manning.
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An operator should maintain a sufficient level of spare equipment and procedures to carry out repairs promptly. At least on a temporary basis it may not be necessary to replace like for like.
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Concluding Comments The mooring system is a safety critical element of a FPU. The mooring is expected to keep the FPU on station, within the specified offset limits, for the design life of the facility (typically 20-30 years). It must perform this function in a corrosive, dynamic environment in which inspection is difficult. Lowering the average failure rate to acceptable levels will require progress on many fronts. There is need (to name a few) for (1) better wear and corrosion degradations models, (2) a better understanding of OPB induced fatigue, (3) S-N data for large diameter, higher strength chain grades, (4) better, more reliable inspection and monitoring tools, and (5) more effective integrity management systems that can work across a corporation’s business unit boundaries. The industry is making strides toward improvement in mooring performance through open sharing of mooring failure data through forums such as the Mooring Integrity User Group (www.fpsoforum.com).
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Acknowledgements The authors are grateful to DNV GL management for approving release of this paper. As this is a review paper, we have made heavy reference to many of the original papers, hopefully in an accurate manner. We gratefully acknowledge the efforts of the authors of these papers.
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