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Collaborating Authors
Garrity, Robert
Mooring Integrity Issues and Lessons Learned Database - DeepStar® Project 20401
Spong, Robert (Spire Engineering) | Garrity, Robert (ExxonMobil) | Thompson, Clay (Occidental US Offshore) | Yan, Xiaoyan (Chevron) | Gabrielsen, Øystein (Equinor ASA) | L’Hostis, Didier (Total Energies) | Heyl, Caspar (Shell) | Minnebo, Joerik (SOFEC, Inc.) | Naciri, Mamoun (SBM Offshore) | Roberts, Craig (Spire Engineering) | Byatt, David (Spire Engineering)
ABSTRACT Mooring failures have been a recurring issue in the offshore industry, and failures continue to occur across the offshore Floating Production System (FPS) fleet. Many of these recurring failures appear to be from similar degradation mechanisms as past events. To better understand these trends and learn from these events, DeepStar® Project 20401 - Database of Mooring Integrity Issues and Lessons Learned was initiated. The project primarily consisted of the collection and assessment of mooring integrity data on failures, pre-emptive replacements and repairs observed on FPS permanent mooring systems. Additionally, chain corrosion/wear data was collected and summarized as part of the project. When available the data was collected from published sources. However, most of the integrity data came from the eight operator and mooring consultancies companies participating in the project. This paper describes the project data collection, the deliverables and key observations from the mooring integrity database developed as part of the project. The observations presented within the paper provide unique insight into predominate degradation mechanisms, observed consequences and estimated failure rates of mooring lines.
Bowties for Offshore Platforms High Consequence Risks
Slatnick, Sam (ExxonMobil) | Angevine, Doug (ExxonMobil) | Cranefield, Jack (ExxonMobil) | Maddox, Chris (ExxonMobil) | Garrity, Robert (ExxonMobil) | Moczulski, Michal (ExxonMobil) | Younan, Adel (ExxonMobil)
Abstract Bow-ties are increasingly used in multiple industries to effectively manage risks during operation. Benefits of bow-ties include clear communication, operator ownership, relationship between safeguards for various threats and consequences, and the visibility of safeguard health during operations. In oil and gas, the main application of bow-ties has been to manage high consequence risks pertaining to process safety, i.e. loss of primary containment of hazardous substances. Unlike onshore facilities, escape from hazards can be inhibited by limited egress and evacuation options can be compromised as part of the events themselves, which heightens the potential number of fatalities in an offshore process safety event. Additionally, while the root cause of a good proportion of incidents originates from process safety hazards, many significant events have originated from offshore and marine structure hazards as well. Since offshore structural and marine failures are not always driven by loss of primary containment, the use of bow-ties in offshore structures and marine is less established. This paper introduces the use of bow-ties and associated principles as tools to manage all offshore risks, both process-safety and structural or marine related. It evaluates the application of bow-ties for a range of high consequence risk scenarios specific to fixed and floating offshore platforms, and provides simplified bow-ties for a range of different types of assets. Though it represents a less conventional approach than those commonly employed for offshore failure scenarios, use of bow-ties can support effective management of these risks, especially those requiring proactive management of safeguards, particularly ice feature overload, offshore collisions, multi-line mooring failures, and loss of floating stability.
- Europe (1.00)
- Asia (0.69)
- North America > United States > Texas (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Mooring systems (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Floating production systems (1.00)
- Health, Safety, Environment & Sustainability > Safety > Process safety (0.97)
- Well Drilling > Drilling Equipment > Offshore drilling units (0.93)
Abstract Mooring tensioning systems for offshore floaters have evolved from rotary windlasses on ships into multiple options nowadays. These options include fixed or movable winches, either linear or rotary, driven by electric or hydraulic, and the most recent in-line tensioners which remove the on-vessel equipment. Selection of a tensioning system directly affects mooring performance and installation, hull design, as well as overall project cost, schedule, operability and reliability. This paper compares a combination of seven types of tensioning system for the mooring system of a deepwater platform. The options under consideration for the tensioning system include fixed or movable, electric or hydraulic driven, and on-hull or in-line tensioner. The pros and cons of different alternatives are evaluated in terms of design, installation, and operating considerations, and are compared against criteria including Technology Readiness, Cost and Schedule, Installation, Layout, Maintenance, In-service Tension Adjustment, HSSE (Health Safety Security Environment) Risk, and Track Record. It is found that all options, fixed or movable, electric or hydraulic driven, and on-vessel or in-line tensioners have their advantages and disadvantages, and need to be evaluated systematically to fit different projects’ needs. Fixed hydraulic chain jacks remain the most popular choices for production semis, with 12 applications out of 24 since the year 1994. Movable options have merits over fixed ones in capital expenditure, especially with high numbers of lines. However, movable options require extra equipment and operations to relocate the tensioning system and thus have shortcomings in mooring installation, tension adjustment, and HSSE risk. An electric option has advantage in maintenance, because it does not require a HPU and has no hydraulic oil or flexible pipes to be replaced. However, electric options are heavy and large, with complicated gear boxes, and require a specialized team. Without on-hull tensioning and handling systems, the in-line tensioners may significantly reduce capital expenditure. Additionally, they eliminate the notorious problem of splash-zone corrosion since the top chain is completely submerged underwater. However, this system requires surface vessel intervention for tensioning and re-tensioning, and increases project execution and schedule risk. All of these need to be taken into consideration starting from early through execution phases of projects. As the offshore industry moves forward with emerging new technologies, projects usually involve multiple choices as well as technical uncertainties and financial risks. Most projects with mooring systems will encounter the similar challenges on selecting a reliable and cost effective tensioning system. This paper can serve as a reference for a major capital project that is going to select the most suitable tensioning system. With the state-of-the-art information and industry practice on mooring tensioning systems, this paper can also service as a reference for updating new versions of API and ISO station-keeping codes.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
Abstract With a goal to improve the overall reliability of moorings used by MODUs (Mobile Offshore Drilling Units), this paper reviews gaps and issues in design standards and operation practices. MODU moorings stay at one location for a short term, compared to tens of years for permanent moorings on production facilities. While the exposure time to the environment is relatively shorter, mobile moorings have been seen to experience a sizable number of failures ironically. Probability of failure has been high on the order of 10. Improving reliability of MODU moorings may be achieved through two sides, i.e. better design standards and more rigorous operation practices. On the design side, there appears to be a lack of clear guidance on designing a mobile mooring system to a proper return period. The gap is prominent especially for moorings in tropical cyclone (aka hurricane or typhoon) areas. Current industry codes and standards do not have a clear guidance on what return period shall be used as a minimum to account for the risk associated with close proximity and failure consequence. Some guidance is provided in API RP-2SK, but it is limited to applications in Gulf of Mexico. This paper attempts to close the gap by proposing minimum return periods to be used and requiring a quantitative risk assessment (QRA) to justify the numbers for any region with tropical cyclones. Guidance on performing a QRA is provided, and aspects on how to produce trustworthy results are discussed. On the operation practice side, issues and gaps are identified and reviewed. Often times, MODU moorings do not receive a sufficient amount of attention in system design, deployment, inspection, and equipment maintenance. Common issues are summarized to raise awareness and best practices are presented.
Abstract This paper provides an overview of the first documented industry intervention involving replacement of a permanent mooring system due to seabed trenching near the suction piles. Another unique aspect of this intervention was the use of readily available hardware for installing a temporary mooring system to minimize operational risks. Brown-field interventions are often required to address mooring integrity issues or life extensions. These are more challenging than new (green-field) designs and installations due to existing infrastructure. This includes the Floating Production Storage and offloading System (FPSO) hull, risers and flowlines. Also, the production shutdown has to be minimized while maintaining operational safety. The present paper summarizes mooring integrity issues and the complete mooring system replacement of the Serpentina FPSO offshore Equatorial Guinea (EG) within ten years of service. A partial mooring replacement campaign was initially planned to address wire rope degradation and chain chafing damage on selected legs. However, seabed trenches near the suction piles, discovered at a late stage, required a complete change in the project plans. The revised scope included installation of a new set of anchors and off the shelf mooring hardware for all nine anchor legs, to address the risk of potential mooring failure in an expedient manner. Installation of new anchors and mooring lines for this project was executed in roughly 6 months from the discovery of the trenches. The planning and execution of this fast track project is discussed, along with the multiple challenges that needed to be addressed. Industry has limited experience in seabed-trenching related mooring issues and associated mitigation. The importance of seabed trench inspection for taut-mooring systems is discussed. Finally, lessons learned in planning and execution of the project in safe and expedient manner is summarized.
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Silver Pit Basin > Block 49/30c > Davy Fields > Brown Field > Rotliegend Formation (0.99)
- Africa > Equatorial Guinea > Gulf of Guinea > Block B > Zafiro Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > South Viking Graben > Block 9/15b > Alvheim Field > Boa Field > Heimdal Formation (0.98)
- Europe > United Kingdom > North Sea > Northern North Sea > South Viking Graben > Block 9/15a > Alvheim Field > Boa Field > Heimdal Formation (0.98)
ABSTRACT The standard approach in mooring design and analysis of offshore structures evaluated the mooring system response and anchor foundation in two separate processes. The most commonly used marine anchors for offshore oil and gas operations are drag embedment anchors. These types of foundation exhibit noticeable translation through the installation and design conditions. It is not customary to actively account for the foundation translation in the mooring analysis. This paper discusses the impact of utilizing a coupled analysis approach of both the mooring response and the anchor response. The example application illustrated will include a comparison between the coupled and non-coupled approach for analysis of a semi-submersible drilling unit using conventional drag embedment anchors.
Abstract This paper presents the design, analysis, and installation of the suction pilesand polyester mooring system for LLOG's OPTI-EX Semi-submersible productionfacility installed in 3,100 ft water depth at Mississippi Canyon. Mooringsystem design began in October 2010 and the facility was hooked-up " storm safe" in July 2011, with the mooring system and suction pile design, CVA (CertifiedVerification Agent) approval, fabrication, and installation occurring inparallel and completed in ten (10) months. Non-linear polyester stiffness curves Also presented in the paper is the design and project-specific load-elongationtest procedure for the polyester rope. The results from the load-elongationtest procedure were used to derive the static and dynamic non-linear polyesterrope stiffness curves as well as the load dependant permanent elongation fordirect input into the mooring analysis. Fabricated suction pile padeyes Due to the fast-track schedule of the project, cast suction pile mooringpadeyes, with typically long lead times, were deemed as impractical for thefacility. Instead, fabricated suction pile plate padeyes were utilized andexamined in detailed Finite Element Analyses (FEA), accounting for non-linearchain shackle - padeye interactions and non-linear material properties. Pre-lay mooring lines / Facility hookup The entire mooring system, including the polyester rope, was preset on theseafloor using LLOG's existing contracted Anchor Handling Vessel (AHV). Thepolyester rope was approved for pre-lay on the seafloor due to its constructionand dual jacketing system which provides soil filtration for the load bearingsubropes. When the facility was towed out to location, all twelve (12) mooringlines were hooked-up in seven (7) days. The ability to preset the entiremooring system reduced critical path time for hook-up of the facility andminimized the facility's exposure to tropical storms in a partially mooredcondition during installation. Information presented in this paper will be of interest to polyester mooringsystem designers and engineers, polyester mooring system and platformoperators, polyester rope manufacturers and users, and regulatoryagencies. Introduction The OPTI-EX Facility was built by Exmar Offshore Company on speculation. Thehull was delivered to Kiewit Offshore Services Shipyard in Ingleside, TX andmated there with the topsides in 2009. In August of 2010 LLOG agreed topurchase the Facility from Exmar, stipulating an aggressive schedule with theFacility to be towed out and installed on location by July 2011. Delmar wasawarded the engineering, procurement, construction, and installation (EPCI)mooring contract in late September, 2010, and work on the mooring systembegan. The mooring system is a twelve (12) line chain-polyester-chain mooringconfiguration in approximately 3,100-ft water depth. The final mooring designconfiguration resulted in 107mm R4 studless platform and ground chain. Thepolyester rope is Whitehill's VETS 370 construction rope with a MBL of 1,100-mTand an average overall diameter of ~205-mm. Delmar's patented subsea connectorwas used to connect the ground chain to the suction piles.
As offshore fields become more densely occupied with energy infrastructure, it has become necessary to more closely examine the risks and associated consequences of deepwater operations that were previously deemed acceptable. As moored MODU (Mobile Offshore Drilling Unit) risk assessments have evolved, the utilization of DP (Dynamically Positioned) vessels is often perceived to be a "safer" alternative. However, when examining historical statistics for sudden hurricanes with respect to DP vessel T-time, drive offs, and drift offs in a modern drilling scenario, the idea of DP operations being lower risk alternatives is often far from true. This paper will utilize statistical information for failure probabilities and associated consequences for a conventional DP drilling operation in comparison to a DP drilling operation utilizing a passive contingency mooring system. Although the main driver for DP contingency mooring systems should be risk mitigation, considerable savings may be seen by operators through less DP thruster use, reducing fuel costs. A properly designed contingency mooring system could be used to keep station under normal operating conditions, allowing considerable cost savings until larger storms arrive at the drilling location. The principle function of a contingency mooring system for DP vessels is to mitigate the risks associated with operating events, not extreme weather events, such as hurricanes. Given that purpose, a reliable emergency quick release is discussed within this paper as an integral part of the contingency mooring system. A detailed risk assessment and cost comparison, in conjunction with mooring and hydrodynamic analyses of a proposed hybrid DP and contingency mooring system, will be presented in this paper.
Abstract Polyester is the most widely used synthetic fiber in modern mooring systems. Though its use is widespread, very simplistic models of its nonlinear load-elongation behaviors are typically utilized in mooring analyses for predicting maximum line tensions and facility offsets. This oversimplified approach can lead to under/over conservative results affecting both mooring system and riser design. A more accurate approach is to separate the permanent elongation of the rope from its non-linear rope stiffness properties. Handling these variables (stiffness and permanent elongation) independently is key in accurately representing the mooring system's response. Different mooring scenarios (e.g. MODUs, FPSOs, SPARs) are affected in different ways by the use of an oversimplified load-elongation model of polyester behavior. This study will address these affects for both a Semi-submersible and an FPSO under metocean conditions typical of the Brazilian basins. Through a detailed rope testing plan, rope non-linearities and length effects as a function of mean load and frequency of loading oscillations can be fully captured for use in mooring analyses, better predicting actual mooring system responses. One such rope testing plan will be discussed and shown how the data is analyzed and prepared for use in the mooring analysis. By modeling the true non-linear stiffness and being able to capture the permanent non-recoverable elongation of fiber mooring ropes in a mooring analysis, the designer can more accurately assess the vessel motions during a storm event and more effectively plan component lengths such that re-tensioning operations will not significantly impact the facility's ability to operate. Such accurate vessel motions and offsets from this analysis method also aid greatly in the riser and other system designs that are integral parts of permanently moored facilities. Hydrodynamic Model Overview For the semi-submersible examined in this case study, a generic Mobile Offshore Drilling Unit (MODU) model was created with symmetry along each horizontal axis. This symmetry, in conjunction with an assumed flat seafloor, allowed for metocean conditions to be applied only on one quadrant of the model to determine the controlling environment direction. The chosen base model was a modified Aker H-3 Series semi-submersible. The approximate vessel dimensions are ~74m×63m with a operating draft displacement of ~28,000 mt. The following figure shows the hydrodynamic model of the semi-submersible that was created in AQWA and used to generate the RAOs and wave drift forces.
Abstract This paper provides a comparison of the performance of fiber rope mooring systems when assessed with the original API RP 2SM 1st Edition recommended method of modeling EA (Young's Modulus × Cross Sectional Area) with an upper and lower bound linear fiber rope stiffness as compared to modeling the true non-linear stiffness behavior exhibited by fiber ropes. API RP 2SM 1st Edition recommended modeling the stiffness of fiber ropes via an upper and lower bound method - a linear Post Installation stiffness and a linear Storm stiffness. The second edition of the document addresses stiffness behavior under near static loading, low frequency dynamic loads, and wave (high) frequency dynamic loads which provides information to capture the true non-linear stiffness behavior of fiber ropes with non-recoverable elongation. Both stiffness models are analyzed for a truss SPAR and the results are compared showing the difference between the two stiffness models. Additionally, the assessment will capture permanent or non-recoverable rope elongation due to a hurricane event and its impact on mooring system performance. Accurate estimates of permanent elongation are also important for length management issues, especially for permanently moored facilities. Introduction Fiber mooring ropes have non-linear stiffness characteristics which generally increase based on their mean load. To most accurately analyze a mooring system it is important to model the fiber mooring rope with its true non-linear stiffness and separate out the permanent non-recoverable elongation. Considerable thought must be given to testing the fiber rope properly so that true stiffness values and accurate non-recoverable elongation based on mean loading can be captured. Original fiber mooring designs utilized an upper and lower bound stiffness method which essentially linearized the stiffness of the rope in a mooring analysis. This practice allowed the designer to utilize commercial software with little or no modification to their analysis method. Prudent designers have been able to utilize high enough upper bound linear stiffness values to get a good estimate of peak mooring line tensions while also finding a suitable lower bound stiffness which can capture the maximum vessel offsets. The analysis method described in this paper utilizes a true non-linear stiffness model that also accounts for the frequency of loading oscillations. The method also accounts for permanent non-recoverable elongation of the fiber rope which allows the designer to analyze how much longer each line would be after a given metocean event. It is common for permanently moored facilities with fiber mooring lines to have to re-tension after a significant storm event to get back to their design location and operating tensions. This is due to the fact that the storm event will permanently change the lengths of the fiber ropes dependant on what their individual loading was during the storm. By modeling the true non-linear stiffness and being able to capture the permanent non-recoverable elongation of fiber mooring ropes in a mooring analysis, the designer can more accurately assess the vessel motions during a storm event and more effectively plan component lengths such that re-tensioning operations will not significantly impact the facility's ability to operate. Such accurate vessel motions and offsets from this analysis method would also aid greatly in the riser and other system designs that are integral parts of permanently moored facilities.