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Collaborating Authors
Delmar Systems
Mooring Tensioning Systems for Offshore Platforms: Design, Installation, and Operating Considerations
Wu, Yongyan (Aker Solutions) | Wang, Tao (Aker Solutions) | Ma, Kai-tung (Chevron) | Heyl, Caspar (Shell) | Garrity, Robert (Delmar Systems) | Shelton, John (Delmar Systems)
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.
Mitigating Risk in Shallow Water and Arctic Station-Keeping
Pasternak, Jason D. (Delmar Systems) | Hersley, Mark (Delmar Systems) | Farrell, Mikaela (Delmar Systems)
Station-keeping in harsh environments requires substantial planning and additional contingency considerations over less extreme environments. Arctic drilling often has biological and other natural considerations, such as whale migration seasons and ice flow. In order to overcome these issues, drilling work is done seasonally, with watch vessels present at all times to ensure that the drilling vessel has an adequate T-time to get off of location. This leads to significant down time from "near misses" and moving the rig to / from location. Tropical drilling requires significant planning around possible cyclonic activity, referred to as hurricanes in the GoM. There are several actions that are taken to mitigate the risks and consequences of sudden cyclones, including the use of DP vessels, stronger preset mooring systems, or stacking older rigs during hurricane season. DP vessels are not capable of the tight watch circles that drilling requires in shallower water depths without utilizing a mooring system, and stacking rigs is a costly activity. The expenses due to lost drilling time associated with the aforementioned phenomena easily reaches hundreds of millions of dollars annually on a global scale. In order to help reduce these costs, a reliable mechanical quick release device can be used to reduce T-times, and allow MODUs to leave locations in considerably less time. The design and testing of a mechanical quick release device from concept to prototype testing, potential cost savings from the utilization of such a device, and potential uses to enhance the drilling capabilities of DP vessels will be presented in this paper.
DP Vessel Passive Quick Release Contingency Mooring Systems
Pasternak, Jason (Delmar Systems) | Alonso, Daniel (Delmar Systems) | Garrity, Robert (Delmar Systems) | Shelton, John (Delmar Systems)
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 A finite element procedure is utilized to verify the results of a laboratory testing program on suction caisson foundations. A set of model caisson foundations was designed, fabricated, and instrumented for testing in the laboratory under simulated TLP loading. The caissons were made with length-to-diameter ratios of 2, 4, 6, and 12 to study the effect of increasing caisson length on penetration resistance and pullout capacity, as well as the feasibility of using suction as the method of installation. The simulated TLP loading was in the form of static and cyclic tension. Measurements of total foundation capacity, displacements, and pore water pressures inside and in the vicinity of the model caissons were made. The pullout capacity of the model caissons was clearly defined under both drained and undrained loading conditions. Results of the experimental program have shown that the rate of pullout loading had a significant influence on the capacity. The results of the testing program were instrumental in devising a limit equilibrium method to estimate the static pullout capacity of the caissons. The finite element results duplicated the behavior of the model caissons in both the drained and undrained pullout conditions and validated the proposed limit equilibrium design method. Introduction Traditionally, suction caissons have been built with length-todiameter (L/D) ratios, or aspect ratios, of approximately 0.5 to 2, e.g., Gullfaks C (Tjeita et aL, 1990), Snorre TLP (Fines et al., 1991; Stove et aL, 1992), Europipe (Tjelta, 1994), etc. These structures are located in the North Sea, the foundation material in the deeper waters is predominantly dense sand and stiff clay. In normally consolidated clay, however, foundation capacity is derived mainly from increased soil shear strength with depth.
- North America > United States > Texas (0.47)
- Europe > Norway > North Sea (0.34)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/10 > Gullfaks Sør Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/10 > Gullfaks Sør Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 50 > Block 34/10 > Gullfaks Sør Field > Lista Formation (0.99)
- (12 more...)