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ABSTRACT The new high-strength steels being introduced into the offshore industry have substantially different mechanical properties from traditional structural steels. Since many of the existing design criteria are of considerable age, it is pertinent to examine the suitability of using the same criteria for the new steels. The parameters produced by the standard uniaxial tension test are first reviewed, and the sources of variation affecting the tensile parameters are briefly discussed. The question of the yield:tensile strength ratio is discussed in more depth, and a basic reliability analysis of the behaviour of this ratio with increased strength is presented. The influence of some of the material parameters on the design of components is also considered. INTRODUCTION Throughout most of the history of engineering, the limited capabilities of design have been matched by the nature of the available materials, whose properties were highly variable, usually very anisotropic, and in any case largely outside the control of the engineer. However, the last two centuries have seen an ever-accelerating rise in the sophistication of engineering design and in the control over production, fostering a corresponding need for accurate data on the properties of materials. Although the development of data-gathering might have been driven by the requirements for design, it is not always obvious what parameters should be measured, and what test is most appropriate. Unfortunately, materials testing as a subject has fallen largely out of fashion and tends to be taken very much for granted, despite the importance of the results for design. Of the wide range of tests, the uniaxial tension test is the most useful, and has been standardised for many years. Indeed, it now occupies such a central place in the methodology of design that its results are in danger of being regarded by many engineers not as a guide to performance, but as being sacrosanct. The shortcomings of such a view have been recognised for over fifty years Of particular concern are the effects that such an attitude might have on the deployment of new steels coming into service, whose properties may not be well predicted by the traditional engineering measurements, or whose optimum use may be handicapped by design methods based on old-style steels. The development of steels over the last twenty years has been on substantially different lines from traditional practice, and has necessitated changes in steelmaking that have been nothing short of revolutionary. Accompanying the improvements in steelmaking, the control over processing is now much more precise, which, together with improved sampling and quality control, have resulted in more consistent and better-characterised products. The main impetus behind the development of the modern steels has been the requirement for improved weldability at higher strengths, which has precluded the traditional route of attaining high strength by using high carbon contents.
ABSTRACT As industry moves into deeper water and economical solutions for mooring systems are sought, anchor systems capable of withstanding vertical loads are needed. Current industry standards and API recommendations constrain a mooring line to be tangent to the seabed when a drag embedment anchor is used. This paper shows that current High Holding Power (HHP) anchors such as the Bruce FFTS and Vryhof Stevpris can withstand significant vertical loads, By introducing a mooring line angle at the seabed, the vertical load at the anchor only increases slightly. The technical feasibility and economic benefits of this concept are described. New types of drag embedment anchors specifically designed to withstand vertical loads are also discussed. DRAG ANCHOR TYPES Drag anchors can be grouped in many different categories. For simplicity, they are grouped in this paper into three categories: "old" style "low" efficiency anchors (e.g., LWT, Danforth, Stockless, Bruce Cast), High Holding Power (HHP) anchors (e.g., Bruce FFTS, Vryhof Stevpris), and new generation Vertically Loaded Drag Embedment Anchors (VLA) (e.g., Bruce DENLA, Vryhof Stevmanta), see Figures 1 and 2. The discussion is limited to deeply embedded HHP and VLA anchors in soft cohesive soils. Many of the ideas presented are applicable to anchors in harder soils. It is shown that HHP anchors can resist loading of around 30-40 times their weight, including substantial vertical loads. It is also shown that VIA anchors, after they have been "tripped" or "keyed", can perhaps resist 100-200 times their weight at any angle. CURRENT DESIGN PRACTICES Current mooring design practices for drag anchors require the mooring line always to have tangential contact with the seabed. Reference 1 states "If drag anchors are used, the outboard mooring line length should be sufficient to allow the lines to come tangent to the ocean bottom at the anchor when the system reaches the maximum anticipated offset under the damaged condition". Reference 2 includes a very similar statement. The U.S. Navy"s mooring design manual, Reference 3, states "Drag-embedment anchors are designed to resist horizontal loading. A near-zero angle between the anchor shank and the seafloor (shank angle) is required to assure horizontal loading at the anchor.. .. As the shank angle increases from zero, the vertical load on the anchor increases and the holding power of the anchor decreases". However, one design office in the Department of the Navy typically uses a seabed line angle of 3° as a maximum with no anchor performance reduction. A recent departure from the traditional no uplift at the seabed approach has been ABS approval of a Floating Production System mooring designed to have a seabed line angle of 3.5° in the damaged condition (one-line damaged -100 year hurricane). ABS stated, however, they would not allow a seabed line angle in the intact condition (no damaged lines -100 year hurricane).
ABSTRACT A means of providing high efficiency driven plate anchors to satisfy Naval requirements for hurricane moorings in congested, confined or complex seafloor areas is under development. Driven plate anchors resist loading in any direction, including uplift, and offer extremely high holding capacity to size ratios. Where space is limited and drag or clump anchors or stake piles are unsuitable, small, inexpensive plate anchor configurations can provide very large holding capacities and be installed with readily available marine equipment. Driven plate anchors can be fabricated from common structural steel configurations and materials. Anchor installation is achieved by attaching the plate anchor to a structural member, called a follower, and driving it vertically into the seafloor using standard pile driving techniques. The follower is retrieved and the anchor is then loaded to properly position it in the seafloor and verify it's capacity. This paper describes plate anchor theory, installation techniques and the results of proof tests in a number of different seafloor soils. These include soft organic silts, over-consolidated clays, dense sands, glaciated soils and corals. Also included is a brief overview of completed installations and a design guide currently in development by the Navy. INTRODUCTION Downsizing of the Fleet is taxing the Navy's ability to provide secure moorings for the Inactive Fleet. These moorings must be designed for hurricane conditions, and often occur in congested areas and at sites with complex seafloor conditions. Conventional drag and pile anchors are either unsuitable for the site conditions or are extremely expensive. In light of today's shrinking economy and the urgent need to provide new moorings, technology for designing and installing simple plate anchors using common pile driving equipment and marine gear is being developed by the Navy. The technology is proven through many mooring installations, resulting in substantial savings to the Navy. Plate anchors installed using standard pile driving techniques (Pile-Driven Plate Anchors) provide an alternative to conventional anchors that can be used today by the offshore industry. This report is an effort to introduce this new technology to the Offshore Industry. PLATE ANCHOR THEORY Plate anchors are driven into the seafloor with the plate parallel to the direction of driving and then rotated or "keyed" by pulling on the anchor line (Figure 1). The anchor is connected to a structural member called a follower and driven vertically into the seafloor using a pile-driving hammer. The follower is retrieved and the anchor is proof loaded. This can be accomplished either vertically from the installation platform immediately after installation or later by pulling horizontally against another anchor leg. The proofing process keys or rotates the anchor plate to a more resistive position, near-normal to the loading direction. Fig. 1- Driven plate anchor - concept of operation.(Available in full paper) Current techniques for determining the holding capacity of plate anchors have been adapted from conventional foundation design practice. For cohesionless soils (c = O), static anchor holding capacity, F, can be determined by the simplified relationship. (Available in full paper)
ABSTRACT Five years of operating experience with a floating production system mooring are described. In-service chain diameter measurements and cathodic protection levels are described. Detailed examination of removed components shows that wire ropes in a permanent mooring system degrade differently from those on a mobile unit and that careful consideration should be given to minimizing installation damage. Break testing of 84mm ground wires after five years service reveals a loss of strength of only 0.1% to 0.2% per year. Strength reductions of 1.5% to 2% per year are noted for the winch wires. In this case, the fairleader sections of the winch wires have suffered less damage than the winch sections. Chain breaking strength data is presented showing that used f02mm Grade 3 chain from the mooring consistently sustained loads some 13% higher than the catalogue breaking strength of new chain. INTRODUCTION General The AHOO1 floating production facility (FPF) has operated on the Ivanhoe and Rob Roy fields in Block 15/21A of the North Sea since July 1989.1,2,3The AH001 was converted from the semi-submersible support vessel Sedco-Phillips SS (a modified Sedco 700 design). The mooring system comprises twelve combination wire and chain lines, secured to piled anchors in 140 metres of water. These lines are arranged to effectively form six pairs of catenaries as shown in Figure 1. The make up of each line is shown in Figure 2, and summarised in Table 1. Because of the large number of lines, the 100 year return environmental design basis and the high factors of safety, the AHOO1 mooring system is arguably one of the most robust currently in operation in the North Sea. This paper brings together the original design assumptions for the mooring components, the subsea inspection data, and the results from the testing of removed components. Operational History Mooring system performance has generally been good. In particular, the vessel excursion and line tensions are lower than predicted. However, although no line failures have resulted from overstressing, fatigue damage, or corrosion, the AHOO1 has lost a mooring line on two separate occasions. On both occasions, approval was gained from the Certifying Authority to resume and continue production operations with revised operational criteria appropriate to an eleven line system. On neither occasion was the revised operational criteria exceeded. The first incident was due to failure of the bolted connection at the bottom bearing mounting on the line 1 fairleader. The fairleader then detached from the column foundation structure and parted the winch wire. Extensive investigations were conducted to determine the cause of failure, and to assure the integrity of all other components involved. It was concluded that the failure was due to the original bolts being of inadequate section and ductility. The integrity of the mooring system was restored to design levels by correcting these defects.
- North America > United States (0.46)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Europe > United Kingdom > North Sea > Central North Sea > Outer Moray Firth Basin > Block 15/21 > Ivanhoe Field > Piper Formation (0.94)
- Europe > United Kingdom > North Sea > Central North Sea > Outer Moray Firth Basin > Block 15/21a > Rob Roy Field > Piper Formation (0.94)
1.ABSTRACT The resonant response of moored floating structures due to low-frequency excitation is controlled primarily by the effective damping coefficient of the structure. A Joint Industry Project addressed the feasibility of predicting the various components of the damping coefficient, with particular emphasis on the wave drift damping, and the damping caused by the mooring lines, about which considerable uncertainty exists. Laboratory and full scale data were used, and new predictive tools were developed to obtain benchmark estimates. 2.INTRODUCTION Studies on the dynamic behavior of moored structures have demonstrated the importance of dynamic amplification phenomenal resulting in changes in the API recommended practice (Triantafyllou et al. 1985, Tein et al. 1987, Kwan 1990). One of the principal outstanding issues is the accurate evaluation of the damping coefficient controlling the slowly varying motions of moored systems. The large mass of moored structures and the relatively small effective stiffness constant of the mooring system provide low natural periods, of the order of 100$, while the total effective damping is often well below the critical damping, As a result, low frequency excitation, such as the slowly varying wave drift forces and the unsteady wind forces, can excite resonant oscillations of considerable amplitude. This is of great import ante to mooring system design, since at resonance the maximum amplitude of motion, and hence the peak slowly varying forces in the mooring lines, are controlled primarily by damping. Damping consists of several components, caused by: unsteady drag and lift forces acting on the structure (including current-induced damping); wave drift damping; wind damping; and mooring damping. Considerable uncertainty exists about the magnitude of two of the most important components of damping: the wave drift damping and the mooring damping. The uncertainty is caused by the nature of wave drift damping, which is a small quantity to measure; and because it is caused by a complex nonlinear mechanism, numerical calculations are difficult to perform. In the case of mooring line damping, the uncertainty lies in the drag coefficient, which can be amplified by various mechanisms from a nominal value of 1.2 to a value in excess of 3.0. A one-year Joint Industry Project (JIP), entitled "Mooring Line Damping and Current Loads", was conducted by Noble, Denton & Associates, Inc. and the MIT Testing Tank Facility to address the principal issues in predicting the damping coefficient of floating structures and obtain benchmark estimates. The project was supported by Amoco Production Co., Arco Oil & Gas Co., BP Exploration Inc., El Dorado Engineers Inc., Exxon Production Research Co., NCEL, and Reading & Bates Drilling Co. 3.DAMPING OF MOORED STRUCTURES The following sources of damping were initially considered: Wave drift damping The discovery of wave-drift damping was made with systematic and accurate experimental measurements starting in the early 1970's (Remery & Hermans 1971). The identification of the wave-drift damping was made by Withers & van Sluijs (1979) who showed that this damping force is (i) proportional to the square of the wave height; and @) a function of ambient wave frequency.
Abstract This paper presents the formulation of a mooring line dynamics model through the use of the lumped mass method. Important aspects of the formulation and solution using finite difference schemes are highlighted and a step by step solution procedure is indicated. A model to account for both friction and suction effects as well as the lifting and grounding of nodes is discussed in some detail. Results are presented which illustrate the seabed interference effects upon the total dynamic solution. The implications which these results have for the nodal lifting/grounding model are further discussed. Introduction For many years the inclusion of mooring line effects in the analysis of the motions of moored floating structures has been carried out through the use of quasi-static methods, In this approach, as the floater moves under the action of wind, waves and current, the mooring line is assumed to take up a new static position; therefore the static tension at the top of the mooring line is calculated for each new fairlead position. The assumption made to justify this approach is that the motion of the floater is slow enough to make any induced dynamic effects negligible. However, there are two problems wit h this approach. Firstly, having made this assumption, it is not then possible to demonstrate its validity - a full dynamic analysis would be needed for this. Secondly, any mot ions induced at wave frequency are ignored. The amplitude of the wave frequency motions are certainly much smaller than the horizontal root mean square excursions of the floater, but these cannot be neglected until their effects can be quantified. Ideally, therefore, a dynamic model should be developed. With the advent of moorings in very deep water the exclusion of dynamic effects becomes harder to justify. This has been recognised by the American Petroleum Institute (API) whose guidelines recommend that dynamic analysis methods be used in preference to quasi-static design tools. Further justification for the development of a dynamic mooring capability arises when studying the coupled floater/ mooring line system. Usually the analysis of either of these components is carried out in isolation from the other. This means that for the analysis of mooring lines, the endpoint displacement is already assumed, implying that the mooring line has no influence upon the motions of the floater. Conversely, when determining the motions of a moored floater, the effects of the mooring line are incorporated as a static modification to the hydrostatic restoration matrix. Although various attempts have been made to couple the analysis of the two components, all have resulted in a simplification of one or both of the separate analyses. Given these clear requirements for the development of a dynamic mooring line model, a choice must then be made regarding the theoretical approach to be adopted and the degree of simplification required. An excellent survey of the analysis of mooring lines can be found in reference (7), and although somewhat dated, this survey contains explanations of the principal methods for analysing this class of problem.
ABSTRACT Ageing platforms form a substantial portion of the platform inventory in the Gulf of Mexico, and to a lesser degree, elsewhere. The need for assessment of these platforms is highlighted by the recent issue of Draft Section f 7of AH RP 2A-WSD. Although platform maintenance has been ongoing for decades, it still lacks uniformity consistency and an integrated approach for planned maintenance. This paper outlines such an approach, discusses the essential elements of a planned maintenance program, provides guidelines for survey planning and assessment of damage and presents damage threshold guidelines. The paper is based on extensive work carried out by Amoco in the North Sea, and later used as a basis for planned maintenance work in the Gulf of Mexico and elsewhere. INTRODUCTION The Gulf of Mexico (GOM) is the birthplace of the offshore platform in the early forties. It is currently populated with over 4000 fixed platforms of all configurations, in water depths up to 1350 feet. While platforms are maintained and repaired when needed, there is no industry guideline for uniform procedures for accumulating, documenting and evaluating quality survey data. With a sharp increase in the number of ageing platforms, maintenance has become essential. The authors suggest that an integrated approach be established leading to a uniform and cost effective maintenance program, which combines all tasks essential for platform assessment, including underwater surveys and data management. API has recognized the need for uniform assessment guidelines, and has completed a Draft Section 17 "Assessment of Existing Platforms" of RP 2A-WSD currently out for industry comment. The draft is mainly based on GOM experience. This paper is one of six papers being presented at the OTC, each dealing with a specific aspect of the assessment process. WHAT IS AN INTEGRATED APPROACH? The approach is an integrated maintenance program, referred to as Planned Maintenance. The program is based on over a decade of extensive maintenance work performed by Amoco in the North Sea. As a result, damage assessment and cost effective underwater surveys became routine, and platform repairs and strengthening minimal. A similar approach for the GOM region tailored by each operator for his platform inventory needs, would go a long way to establishing industry accepted guidelines, and provide a basis for similar guidelines elsewhere. The paper is not intended as a blueprint for such guidelines, but highlights the important tasks associated with an integrated approach, with emphasis placed on gathering and management of quality data, and subsequent damage assessment. Platform Performance History: Factors affecting platform performance history are outlined in Figure 1. These are "Quality" and "Exposure". As platforms age their resistance to loads generally decrease while their exposure to loads increase. The installation date is a key indicator of platform structural integrity, in that it reflects the state of the design and fabrication technology and code requirements at the time. Thus, the figure points out that older platforms benefit from more survey and assessment attention.
- Europe > United Kingdom > North Sea (0.44)
- Europe > Norway > North Sea (0.44)
- Europe > Netherlands > North Sea (0.44)
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- Summary/Review (0.34)
- Research Report > New Finding (0.34)
Abstract API-RP2A "Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms" will be updated with a new section "Assessment of Existing Platforms to Demonstrate Fitness For Purpose," which is currently in "draft" status. This paper addresses specific mitigation and operation actions that can be used to bring a platform structure into compliance with these guidelines. These actions can generally be categorized as:reduction of loading, increasing of strength, and/or reduction of consequences. Introduction The American Petroleum Institute (API) formed a Task Group (TG) in 1992 to develop procedures to assess existing offshore platforms to demonstrate Fitness-For-Purpose (FFP). As part of this TG, a sub group was formed to develop recommended practices related to operations and mitigation methods that could be employed on platforms that would allow them to meet FFP guidelines. The intent of this paper is to provide background information and a detailed list of references that will assist engineers in developing platform specific actions. This paper is referenced from the draft version of the assessment guidelines (Ref. 1) of API-RP2A and is offered as additional commentary by the members of the API sub-group. The approaches described here are a compilation of methodologies that range from the very simple and obvious to those which may require significant engineering and construction efforts. Many of the references will guide the practicing engineer to historical projects that faced the issues of required upgrades and/or mitigation of consequences. The specific tasks listed benefit one or more of the following broad categories:reduction of loading, increasing of strength, and/or reduction of consequences. Where appropriate for each of the actions listed, a general description of the benefits, possible negative consequences, interactions, and relevant references are given. Reduction of Loading Reduction of Vertical Gravity Loading: A prime example that can be accounted for in the assessment of existing platforms is to accurately determine actual deck weights. Most platforms, when they are designed, use area live loading procedures to account for undetermined facility designs. Once installed, the actual equipment loading may be substantially less than what was used in the original structural design. Additionally, the structure may have been designed for a platform rig, but now accommodates cantilever jack-up rig drilling operations, which do not impose any direct gravity loading on the platform. In many instances, revised upper bounds of deck payload can be established for future operations which can be subsequently used in a platform assessment. As an example, a specific jacket may have been originally designed for a 21,000 kip deck payload, but henceforth could be limited to only 13,000 kips. Appropriate operational procedures would then be necessary to ensure that the revised deck payload criteria are observed. Other related jacket vertical load reductions can come from a partial removal of unneeded deck structures. Conversely, jacket vertical loading can also be reduced by increasing platform buoyancy. Obviously, any net increases in load over the original design must be accounted for in the assessment process.
ABSTRACT An API task group has developed a process for the assessment of existing platforms to determine their fitness for purpose. This has been released as a draft supplement to API RP 2A-WSD, 20 edition. Details and the background of this work are described in a companion paper. The assessment of a platform's fitness for purpose involves firstly a definition of the platform's exposure; and secondly, an evaluation of the platform's predicted performance relative to the assessment criteria associated with that exposure. This paper deals with platforms in the high exposure category. That is, platforms whose potential failure consequences, in terms of potential life loss and environmental damage, are significant. The criteria for placement of a platform in a high exposure category are explained, as are the performance criteria demanded of these high exposure platforms. In the companion paper, the metocean assessment process and associated API-developed acceptance criteria are highlighted. This paper addresses primarily ice and seismic loading assessments and associated API-developed criteria, which are based on over thirty years of successful offshore operation and field experience, as well as extrapolation of land-based performance criteria. Three West Coast, USA production platforms are used for illustration. EXPOSURE CATEGORY ‘Exposure’ comprises threats to life safety and to the environment. The platform assessment criteria discussed in this paper deal with that small subset of the industry's domestic production platforms whose loss of serviceability would have both severe life safety and pollution consequences. A manned, non-evacuated platform category has been defined as a condition in which a platform is actually and continuously occupied by persons accommodated and living thereon, and it is not intended that they be evacuated during an environmental design event? Assessment of a manned platform in seismic prone regions is suggested to be triggered when on average five or more persons are present on the platform at any one time. This implies that some of the smaller production platforms offshore California, which are lightly manned or have no sleeping accommodations onboard, and which also have little potential for pollution, do not fall into the high consequence exposure category. To categorize a platforms pollutive potential as having an unacceptable impact on the environment requires the evaluation of a number of factors. Will the producing wells flow naturally in the unlikely event of the failure of one or more of their subsurface safety valves? Is there normally a large amount of oil stored on the platform? Is the local marine environment particularly sensitive? Is local cleanup equipment likely to be unavailable or ineffective? If the answer to most of these questions is yes, then the platform may be considered one with the potential for "Significant Environmental Impact". Note, some production platforms offshore California should not be classified as having ‘significant environmental impact’ potential, due first to the inability of the producing wells to flow freely without the assistance of downhole pumps, second to low onboard oil inventories, and third to the small heavy oil leakage potential from the export pipeline in the event the pipeline or riser is severed.
- Reservoir Description and Dynamics (1.00)
- Health, Safety, Environment & Sustainability > Environment (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Platform design (0.48)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Offshore pipelines (0.34)
Metocean Criteria/Loads For Use In Assessment Of Existing Offshore Platforms
Petrauskas, Charles (Chevron Petroleum Technology Company) | Finnigan, T.D. (Chevron Petroleum Technology Company) | Heideman, J.C. (Exxon Production Reasearch Co.) | Vogel, M. (Shell Development Co.) | Santala, M. (Exxon Production Reasearch Co.) | Berek, G.P. (Mobil R&D Corp.)
ABSTRACT This paper discusses the basis for the metocean criteria and wave/current deck force calculation procedures that are included in the draft document "API RP2A-WSD, Section 17, Assessment of Existing Platforms". The metocean criteria were developed in 1993 by Work Group 3 on Environmental Loads (WG3) of API Task Group 92-5 "Assessment of Existing Platforms to Demonstrate Fitness for Purpose". The deck force calculation procedures were developed by a sub-group of WG3. Procedures used by WG3 to obtain Gulf of Mexico and West Coast metocean criteria for various exposure categories are described in detail. The recommended procedure for calculating wave/current deck forces is shown to be validated by model-scale wave tank test data. INTRODUCTION The purpose of this paper is to present the basis for the metocean criteria and wave/current deck force calculation procedures that are included in a draft API RP2A document on assessment of existing platforms [1]. The metocean criteria were developed in 1993 by Work Group 3 on Environmental Loads (WG3) of API Task Group 92-5 "Assessment of Existing Platforms to Demonstrate Fitness for Purpose". The deck force calculation procedures were developed by a sub-group of WG3. The metocean criteria consist of the following items:Omni-directiomd wave height vs water depth Storm tide (storm surge plus astronomical tide) Minimum deck height Wave and current direction Current speed and profile Wave period Wind speed The criteria are specified according to geographical region and water depth. At this time only criteria for the Gulf of Mexico (GOM) and three regions off the West Coast are provided. No metocean criteria are provided for Cook Inlet because ice forces dominate. The criteria are further differentiated according to exposure category and type of assessment analysis. There are six exposure categories depending on possible consequences of failure. There are two environmental impact categories:Significant Environmental Impact and Insignificant Environmental Impact; and three life safety categories:Manned-Not Evacuated, Manned-Evacuated, and Unmanned. Each combination of environmental impact category and life safety category represents an exposure category. For each exposure category metocean criteria are provided for two levels of assessment analysis, design level and ultimate strength. The levels of analyses are in increasing complexity and decreasing conservatism. Design level analysis is like that used in new platform design, including the application of all safety factors, the use of nominal rather than mean yield stress, and the one-third increase in allowable stresses. Ultimate strength analysis excludes all sources of conservatism providing an unbiased estimate of platform capacity. Additional details are in [ 1] and [2]. In both levels of analysis, wave forces for specified metocean criteria must be calculated using the methodology of the 20th ed of RP2A given in [3] and [4] with wave kinematics factors that are provided in [1].