bluuebunny/crossref_metadata_2025 huggingface dataset:
Curved Flapper Safety Valves Reduce Flow Area Restrictions by 30%
Authors: Going W.S.
Published: October 2008

A new design for surfs- controlled subsurface safety valves significantly reduces the O.D. to I.D. ratio. The development of curved flappers allows a tubing retrievable safety valve to be manufactured within a smaller O.D. housing without sacrificing flow area. Conversely, wireline retrievable safety valves of a fixed O.D. can now have a larger bore. The methods used in the design and manufacture of this new valve type have extensively benefited from advanced technology in both the engineering and manufacturing areas, The net result is a safety valve which allows operators to achieve maximum production rates from their cased hole investment.

INTRODUCTION

In well completions with subsuface safety valves the O.D. of the safety valve is frequently the limiting factor in selecting the tubing and casing size combinations. Consider the ease of a gas well with a flow potential limited by the production tubing frictional losses. Such a well completed with 7-5/6 inch 29.7 lb/ft easing will have a drift I.D. of 6.750 inch. The casing bore is then adequate to run 5-1/2 inch production tubing which has 6.050 inch O.D. couplings. However, when a safety valve is needed, the largest conventional tubing retrievable valve that will fit will be a 3-1/2 inch size with a typical bore of 2.812 inch. As an alternative, the operator may choose to run a wireline retrievable safety valve. In that case, the largest wireline safety valve landing nipple that will run in the casing is the 4-1/2 inch size. The standard I.D. for the 4-1/2 inch wireline safety valve is only 2.125 inch. One operator settled on running 5-1/2 inch tubing above a 4-1/2 inch landing nipple and then running 4-1/2 inch tubing for the balance of the well. With this arrangement, both the smaller tubing I.D. and the wireline retrievable valve create higher frictional losses than the tubing above the safety valve. For these wells a larger I.D. wireline retrievable valve would increase the flow potential.

Several North Sea operators have faced the same options with 10-3/4 inch casing with an I.D. drift as small as 9.504 inch. Their desire is to run 7 inch production tubing, but the O.D. of a 7 inch conventional tubing retrievable safety valve would be 11.000 inch. Some operators have chosen to run 5-1/2 inch tubing retrievable valves with 4.562 inch I.D. Others have selected the 7 inch wireline retrievable valve with a 3.625 inch I.D. Either choice has some limiting effect on the maximum producing rate. SINTEF's safety valve reliability surveys continue to point toward tubing retrievable valves as having the highest reliability.1 This fact makes the choice for wireline valves for high operating cost areas, such as the North Sea, increasingly difficult to justify. By using the curved flapper design, it is now possible to manufacture a full bore 7 inch tubing retrievable safety valve which will run in 10-3/4 inch casing.

VALVE GEOMETRY

Conventional subsurface safety valves typically use a flapper type closure to achieve the maximum I.D.
Scour-induced Free Spans
Authors: Bijker R. , Staub C. , Silvis F. , Bruschi R.
Published: October 2008

The paper reviews the origin and effects of scour induced free spans as part of the self lowering process of submarine pipelines. Aspects of single free span development like initial embedment, the onset of scour, the rate of scour development, relevant stopping criteria, multiple span formation and critical free span development are described and discussed.

1. INTRODUCTION

Self lowering of submarine pipelines is known to happen in several parts of the North Sea.

Regular surveys of self lowering pipelines gave good insight in the overall result of self lowering and self burial.

However, the actual interaction between seabed and pipeline is more complex and is not yet completely understood.

This paper reviews the origin and the effects of scour induced free spans as part of the self lowering process of submarine pipelines in erodible seabeds.

2. SINGLE FRRE SPAN DEVELOPMENT

Immediately after laying of the pipe, it will settle somewhat in the seabed. Because of:Pipeline installation Increased contact pressure at the touchdown point due to the suspended span, and dynamic effects of the laying operation will contribute to initial embedment in the order of 2-3% of the pipediameter (in case of medium sand).Small scale hydrodynamic action Even moderate wave and current actions will induce hydrodynamic forces which lead to, albeit small, lateral motions of the pipeline which will also contribute to initial embedment. Hydrodynamic forces representing 10-20% of the submerged weight have induced cyclic lateral motions and eventually settlement of 5-15% of the pipeline diameter. See Figure 1 and 2.Seabottom unevenness The presence of small scale bottom irregularities at the moment of installation will result in non-uniform contact pressures and thus contribute to non-uniform initial embedment. It may be enough to avoid gaps under the pipeline in the "troughs" and embedment in the seabed corresponding to the average ripple height may be obtained. Scour induced free spans need a start. Sometime, somewhere along the pipeline there must be an onset of scour.

Due to irregularities in the seabed and variations in initial embedment, there will most probably, be locations along the pipeline where the scour will be initiated.In case no gaps are present, the onset of scour will occur at locations where the embedment is minimal, or at locations where the soil conditions are such that the wave generated pressure differences between either sides of the pipeline cause the intergranular flow in the sand, under the pipe, to initiate scouring.If small gaps are present, those gaps will cause the onset of scour. Model investigations showed that even in situations with moderate tidal velocities scour under a pipeline will occur due to increased bed shear stresses in almost any small gap below the pipe, also in cases with no sediment transport on the flat seabed. After onset of scour, a scour induced free span will develop:–the gap under the pipe will deepen till equilibrium depth;
Offshore Pipeline Drying With Dry Air and Pigs
Authors: Stowers H.L.
Published: October 2008

A properl cleaned and dried pipeline, offshore or onshore, can be commissioned and operated with dehydrated gas without encountering any internal problems caused by water or solids.... The validity of this statement is slowly being acknowledged by natural gas transmission and distribution companies, primarily those companies that have had serious problems with wet gas, hydrates, freeze ups or equipment damage.

The ability to start up a new or recently hydro-tested dry gas pipeline without encountering any problems caused by the pipeline's internal condition is a compelling reason for cleaning and drying. It completely eliminates any possibility of regulator icing, hydrate formation and damage to delicate seats, seals and meters. Plus, a potential cause of corrosion is removed, the flow efficiency is improved and there will be no dissatisfied customers downstream.

There is no magical cure for a pipeline full of wet gas. Once a pipeline has been commissioned there is no way to avoid the embarrassment of having to spend unbudgeted funds to correct problems.

It is very difficult to dry a pipeline after it has been brought to operating pressure, because the affinity of natural gas for water is reduced drastically as the pressure is increased. At atmospheric pressure natural gas can hold approximately 30 times more water than it can at 600 psig. That means that water left in the pipeline after commissioning can be evaporated at a rate about 30 times slower than at atmospheric pressure. That rate is further reduced by the presence of some 1 to 7 pounds of water per mmscf already in the gas.

Some natural gas transmission companies have begun specifying that their onshore pipelines be dried to a dew point temperature of -38.5 degree F. which corresponds to 7 pounds of water per mmscf. A few offshore gas producers are also using that specification on offshore pipelines built to carry dehydrated natural gas. There continues to be more companies specifying dryness requirements every year and in a few years it will very probably be a standard requirement.

These reasons for cleaning and drying onshore natural gas pipelines also apply offshore where hydrate and internal corrosion problems perhaps cause the greatest concern. The conditions under which hydrates will form are well established and basically involve temperatures, pressures, gas composition and the presence of water. The conditions under which internal corrosion can begin are also well understood and include the presence of water.

If liquid water and water bearing rust and mill scale are removed from the pipeline, then the potential for internal problems caused by those items does not exit.

It is possible to remove the water, rust and mill scale from a pipeline but it is not as easy as running a few pigs. First, the hydrostatic test water is removed with a displacement pig, also called a dewatering pig (of which there are many types). But, the worlds most efficient dewatering pig is not going to dry the wall of the pipe.
Rapid Makeup Coupled Tendon Connection
Authors: Pallini J.W. , Milberger L.J.
Published: October 2008

This paper discusses the design, analysis, and operation of a threaded tendon connection that uses a coupling having dissimilar thread forms on the two ends. This allows makeup of the connection by a partial turn of rotation of the coupling while holding the tendon tubulars fixed.

Also discussed in this paper are possible makeup tools and other features that can be incorporated into the connector.

INTRODUCTION

A TLP typically makes use of tendons, attached to the comer columns of the platform, to moor the platform.

Current and proposed designs for TLP tendons make use of tubular steel members of roughly 24 to 30 inches in diameter having three-quarters of an inch to one and one-half inches wall thickness. These tendons also extend well over 1000 feet in length.

Several methods exist for connection, transportation, and installation for the tendons. Tendons may be fabricated by welding pipe sections together on shore and floating the tendons to the installation site, where they are upended and installed. An alternative method is to deliver the tendon to the installation site, on a boat or barge, in sections. These sections can then be connected, using a derrick barge, and lowered into the water vertically as each section is added. In order to quickly connect the tendon sections, a mechanical connector must be incorporated on the ends of the tendon section.

The requirement for this connector include:Vertical assembly of up to 240 feet length tendon joint.Structural strength equal to or greater than the pipe body.Sufficient fatigue life for the specific application.Operational characteristics which allow for ease of installation.Ability of the connection to seal the tendon from sea water in most cases. These requirements typically lead to classic designs of weld-on threaded joints which make use of a male member (commonly referred to as the pin) on one tubular joint, which makes up to a female member (commonly referred to as the box) on the mating joint. Makeup of the connection normally requires rotation of one of the tubular joints with at least several turns, while holding the other joint fixed. This is a difficult task when dealing with the long tendon joints, particularly when working on a derrick barge which may be moving considerably while floating in the ocean. Performing this task can also require a very large fixture for aligning and rotating the tendon section.

There are also connectors available that snap together by forcing together male and female sections by using a hydraulic makeup tool to provide a high axial makeup force. These connectors usually make use of a shallow thread or annular grooves. This paper is not intended to address these type of connectors nor attempt to compare their load carrying capacities to this Rapid Makeup Coupled Connection.

The connector being presented here makes use of a coupling that contains a different thread type on each end of the coupling. (See Figure 1.)
BX Flange Analysis: Significance of Gasket on Load Capability of a Subsea Connection
Authors: Chang R.T. , Fisher E.A. , Hall G.
Published: October 2008

In this paper, the results of finite element analyses of API BX swivel flanges are presented. The interactions between the flange, the gasket, and the bolt preload are studied and illustrated. Two analytical approaches are explained, one with gasket in the model and the other without. The assumptions made in the analysis are scrutinized. Four failure criteria of a flange connection are identified and discussed for the subsea applications. Based on the comparison between the two models, the significance of gasket inclusion on the load carrying capacity is concluded. For the subsea applications, including the gasket in the analysis gives a more conservative yet realistic prediction than the model without gasket.

INTRODUCTION

Finite element analysis (FEA) has been utilized to determine the load capabilities of flange connections (Refs. 1 & 2). However, most of them were performed without a gasket being included in the FEA model. A Joint Industry Project (JIP) Study 'Swivel Flange Design Practice Development' was sponsored by eight companies and awarded to Cameron Offshore Engineering (COE). The original objective of the study was to determine the load carrying capacity of seventeen swivel flanges so that they may be implemented into the API 17D Specification. As a side-study, the effect of including the gasket in the finite e1ement mathematical model was also investigated. The reason for the side-study was the discovery that the load carrying capacity disclosed by the model with a gasket was lower than the API published data.

Four criteria selected to define the load capabilities of the swivel flanges are:the allowable stresses in the flange and hub bodies,the allowable stress in the bolt,the pressure leakage, andthe hub face separation.

The first three requirements are general for any pressure containing equipment. For subsea connections, the flange face-to-face contact must he maintained so that no seal fretting will occur due to the cyclic loading, It was also found that the load carrying capacity defined by the hub face separation criteria is the most conservative among four.

The finite element model with gasket being included is an elasto-plastic, large displacement, non-linear analysis. There are three load paths through the gasket and the flange face, It was found that the load required to seat the gasket is 40% to 60% of the bolt preload. This significantly reduces the load remaining at the flange contact face. The inclusion of the gasket in the FEA model is the source of the discrepancies between the current study and API PRAC 86-21 (Ref. 3).

TECHNICAL APPROACH TO FLANGE ANALYSIS

Traditional Flange Analysis Approach vs ABAQUS CAXA

Flange connections are axisymmetric in geometry. The makeup load, the pressure load, and the tension are all axisymmetric, only the bending moment is not, In the past, the bending moment was included in the axisysmmetric model by the equivalent tension modeling scheme, that is only valid for one sectional plane.
Sand and Gravel Resources on the Atlantic Continental Shelf: A New Look
Authors: Amato R.V.
Published: October 2008

Sand and gravel maps of the U.S. Atlantic Continental Shelf were recently compiled at a scale of 1:1,000,000 by the Minerals Management Service. The maps cover the North, Mid-, and South Atlantic, and South Florida areas. They show deposits of sand, gravel, silt, and clay as well as differences in mineral content, from carbonate-rich sediments in the South Florida area to quartz-rich sediments north of Cape Hatteras. Sand and gravel volumes were calculated for each of the map areas and include identified and undiscovered resource categories.

The North Atlantic map area contains the greatest thicknesses of sand and gravel-most is concentrated on Georges Bank and Nantucket Shoals. Most of the deposits are of glacial origin and have an average thickness of 15 m. The North Atlantic contains about 1.6×1012m3 of sand and gravel. The area shown on the Mid-Atlantic map lies south of the maximum glacial advance and received large volumes of sand and gravel from meltwater streams. Sand covers most of the Mid-Atlantic Shelf with an average thickness of 6 m and an estimated volume of 4. 0×1011m3. Sand in the South Atlantic map area is richer in carbonate in the southward direction. The South Atlantic is estimated to have 3. 7×1011m3 of sand with an average thickness of 5 m. Sand in the South Florida offshore area is limited to the wider shelf areas from Cape Canaveral to Miami and around the Florida Keys. The sand is predominantly carbonate and averages 4 m in thickness. A volume of 6.3 × 10 10m3 of sand is estimated for this area. Total sand and gravel resources for the entire Atlantic Continnntal Shelf are estimated at 2.4×1012m3. The need for sand and gravel is expected to increase significantly in the next century as the United States rebuilds its infrastructure and onshore deposits are depleted. Offshore sand and gravel may have to be used to meet these needs.

INTRODUCTION

A series of sand and gravel maps were compiled from old and new data at a scale of 1: 1,000,000 for the U. S. Atlantic Continental Shelf 1. Unlike other sand and gravel maps, they focus on standardizing data from many sources including compilation at one scale and use of standard grain sizes and mineral content. The maps also emphasize the potential of the specific resource or deposit for commercial uses. Sand and gravel volumes were calculated from the maps and core hole data to estimate the quantities of potential aggregate available for specific geographic areas--for instance, near major metropolitan centers. The areas covered by the maps are shown in Figure 1.

The Atlantic Continental Shelf is covered by a layer of unconsolidated rock and mineral particles of varying thickness ranging in size from silt to boulders. This layer has been subdivided into geologic units based on grain size and mineral content. Grain size classes are based on the Wentworth scale.
Disturbance and Recolonization Experiment in the Abyssal South Pacific Ocean (DISeOL): An Update*
Authors: Foell E.J. , Schriever Gerd , Bluhm Hartmut , Borowski Christian , Bussau Christian , Thiel Hjalmar
Published: October 2008

The DISCOL study involving a long-term, large-scale, disturbance-recolonization experiment in the abyssal South Pacific Ocean was devised to achieve a better understanding of the rate, sequence, and direction of benthic community re-establishment after severe anthropogenic disturbance of the seabed similar to that expected to result from deep sea floor mining. The project is funded by the German government and has been in progress since February, 1989, when the experiment was initiated during a two-month cruise aboard FS SONNE. After site selection and baseline assessments, a circular area of the seabed was impacted using a specially designed disturber device and then examined during an ini tial post-impact sampling series. The DISCOL site was sampled again during a second cruise in September, 1989, about six months after the impact was created. A third cruise of the recently rebuilt and enlarged FS SONNE will again visit the site in January-February, 1992, in order to carry out another post-impact sampling series three years after the disturbance.

Bottom sediment and biota samples, photo/video images, and other data obtained during the first two cruises are continuing to be evaluated, but some initial results have become available and are summarized in this paper. Experimental studies on large scales have rarely been attempted or successfully carried out in the challenging deep-sea milieu, but are vital to understanding biological processes and evaluating impacts resulting from ocean mining and other future industrial incursions into this largest and least understood of marine environments.

INTRODUCTION

The DISCOL (disturbance-recolonization) experiment in a manganese nodule area of the southeastern Pacific Ocean is funded by the German Federal Ministry for Research and Technology and has been in progress since February, 1989, when a circular 10.8 km2 area of the sea floor at depths near 4150 m and located approximately 650 km southeast of the Galapagos Islands (Figure 1) was selected as the for a large-scale and long-term study.1,2 The site was divided into eight pre-shaped sectors, each consisting of a central and a peripheral region separated by a 350 m wide buffer zone. Five central and five peripheral sector regions, designated according to their compass position prefixed by a C or P respectively, were randomly selected for concentrated study (sectors labelled in Figure 1). After taking a series of pre-impact baseline samples (DISCOL 1/1) to serve as controls, the DISCOL Experimental Area (DEA) was intentionally disturbed with a specially designed eight meter wide "plow harrow" device during the later part of February and in early March of 1989. 3,4 The disturber device was towed across the DEA center a total of 78 times on diametric courses which resulted in a central region of densely clustered plow tracks surrounded by a less severely affected peripheral region as shown in Figure 2.
Jackup Rig Foundation Modelling
Authors: Murff J.D. , Prins M.D. , Dean E.T.R. , James R.G. , Schofield A.N.
Published: October 2008

Centrifuge tests of single jack-up legs on sand seabeds have been used to improve and extend an analytical model of jack-up foundation behavior previously proposed in a joint industry study (3). These enhancements are hased on the data analyzed to date and are still undergoing development. The modified analytical model was used to predict three leg experimental behavior after the model parameters were defined. The-se-predictions compared favorably although several deficiencies were noted. Of primary importance is the observation that the three leg models exhibit significant foundation rotational fixity in both loose and dense sand. These results are most relevant to competent soils where leg penetration is shallow, such as many sites in the Central North Sea.

Introduction

An independent leg jack-up rig (ILJU) can be idealized as a portal frame as shown schematically in Figure 1. The deck is relatively rigid and the legs act as simple beam columns. Horizontal loads induce swaying of the structure with the deck responding approximately as a single degree of freedom system. As such, the jack-up response is very sensitive to the degree of rotational 'fixity' of the spud can foundation. For a given static load, the deck-leg moment, a key response variable, can vary by a factor of two depending on the foundation fixity condition. Furthermore, the natural period of the structure can also vary by a factor of two. (A stiffer foundation reduces the moment and the natural period.) A more detailed discussion of these interrelationships is given in Refs. 2, 3, and 4. For economic reasons, a jack-up is typically operated near its maximum safe water depth. Therefore, the foundation stiffness assessment often strongly impacts rig selection. This issue has been particularly important in the Central North Sea where, at the outset, water depths dictate the use of larger rigs.

The spud can fixity is, of course, highly dependent on the nature of the seabed on which it rests. The importance of the foundation behavior has motivated considerable research in recent years, for example see Refs. 2, 3, and 4. While substantial progress has been made in quantifying spud can stiffness, there remains a high level of uncertainty in this process. The study reported herein is intended to extend previous work on this topic (2, 3), and to provide a progress report on an ongoing experimental program.

This paper reports the results of extensive centrifuge model tests on spud can foundations supported on uniform sand seabeds. The test conditions were varied to include a range of sand densities (loose, medium dense, and dense), spud can shapes (flat and conical), and load paths. Both single leg and three leg models were tested. The results have been interpreted in the context of a theoretical 'macroscopic' plasticity model where the total spud can response is idealized as an elastic, work-hardening plastic element. The work-hardening parameter in this case is taken to be the penetration depth of the spud can into the soil.
Control and Dynamics During Lift Installation of the Snorre TLP Concrete Foundation Templates
Authors: Lange F.C. , Hetland Steinar , Knudsen J.
Published: October 2008

The paper describes installation aspects of the Snorre Concrete Foundation Templates (CFT'S). The method used to bring the CFT"S to the correct penetration is described as well as the use of the SSCV DB102 to control the CFT during this part of the operation. Results from the preparatory Dynamic Analysis are discussed to indicate the dynamics in the hoist arrangement during the phase where the SSCV is "flied" to the seabed via the hoist wires and CFT. Offshore measurements were performed on the hoist forces and CFT motions. Analysis of some of these measurements are compared with the anticipated responses. It is shown that the positioning requirements and the dynamics involved in such an operation are well controlled.

INTRODUCTION

In June 1991 the Semi-submersible Crane Vessel (SSCV) DB102 lift installed four Concrete Foundation Templates (CFT"S) at the Snorre Field in the Norwegian sector of the North Sea. The installation was performed by HeereMac v.o.f. (HeMc) under subcontract to Norwegian Contractors as. (NC). The operator of the field, Saga Petroleum as. had granted NC an EPCI contract for fabrication and installation of the CFPS.

Each CI?T had a weight of around 6000 tonnes and had to be dual crane lifted and lowered to a depth of 310 meters to function as suction anchors for the Snorre Tension Leg Platform (TLP) tethers. The application of the CFT's required accurate positioning on the seabed to within 0.5 m. It was also required that the penetration in the seabed was performed with sufficient control to avoid damaging the soil structure. For this reason the SSCV was used to control the rate of lowering and the inclination of the CFT during its initial penetration. To ensure positioning within the required tolerance the CFT was guided by the SSCV until a penetration of 4 meters in the seabed was reached, after which the rigging was disconnected and the CFT was brought farther down to 12 meters penetration. The first four meters took about three and a half hours during which the SSCV was "flied" to the soil by its crane system, which very much governed the dynamic characteristics of the combined SSCV/CFT system. To avoid soil collapse in this phase it was necessary to impose relatively strict weather limitations on the installation.

The CFT Lifts showed the first use of the Display, Logging and Simulation (DLS) system installed on the SSCV during the previous winter by which hookloads and SSCV motions could be monitored and stored. The DLS system enables actual display of relevant data and (ballast) simulation of, in particular, heavy lifts to ensure a safe operation (Refer also to Reference 1). In order to monitor the CFT motion during installation the CFT'S were equipped with a temporary acceleration package. This package was capable of logging and storing the acceleration of the CFT during the whole installation sequence but was not part of the instrumentation needed for the operation.
Response of Tension Leg Platform to Wave Drift Forces
Authors: Li Tousun , Kareem Ahsan
Published: October 2008

The wave drift forces on tension leg platforms (TLP) are contributed by second-order potential and viscous wave load effects, the fluctuations in wave surface elevation and the influence of platform displaced position on the wave excitation. These forces are expressed in terms of in-phase and out-of-phase drift forces. In this study, computationally efficient time domain and frequency domain based schemes are developed to evaluate the TLP response to drift forces. These schemes retain the statistical relationship that exists among these drift forces and the first-order wave forces which is important for the combined response analysis. A parameter study is conducted to delineate the relative significance of different drift forces for several representative sea-states.

I. INTRODUCTION

In addition to the wave forces at the typical wave frequencies in a sea-state, a compliant structure experiences slowly varying wave drift forces. These forces originate from various mechanisms involving the nonlinearity of the viscous drag term, nonlinearity in the potential forces, variations in free water surface elevation near TLP columns and the nonlinear feedback of the structural response to the wave loads. The tension leg platform has low natural frequencies in the compliant modes, i.e., motion in horizontal plane. The wave drift force at the difference frequency contributes significantly to its horizontal displacement. In view of the complexity ofloading and TLP response characteristics, an enhanced response prediction capacity with respect to the environmental loads promises to provide useful input to the reliable design of TLPs in deep water. This paper focuses on the computation of waveinduced drift forces and associatedplatform response utilizing computationally efficient schemes developed in this study.

Many researchers (e.g., de Boom et al, 1985) have described the drift forces on a TLP as a result of the second-order terms in the wave diffraction force. This force is often called potential drift force. Others (Finnigan et al., 1984 and Botelho et al .,1984, Salvensen et al., 1982) have focussed on the fact that the drag force on the TLP components can cause viscous drift force resulting from the nonlinearity in Morisonls drag force formulation. Normally the wave forces on a TLP are calculated at their undisplaced position. McIver (1976) and Rainey (1977) have emphasized that the wave effects on TLPs should be evaluated at their displaced position. In regular waves, by neglecting this effect one may underestimate response by a steady offset. In random wave conditions, this offset results in another form of drift force (Li, 1988, Li and Kareem, 1992c), which herein is called displacement feedback drift force. In this study, numerical scheme were developed, in both time and frequency domains, to describe the TLP response induced by different drift forces on TLP horizontal motion. It is noted that the total drift force is not a simple summation of the individual drift forces.
Development and First Use of the Jolliet TLWP Tendon Inspection System
Authors: Hein N.W. , Warren D.H. , Saffrhan R.W.
Published: October 2008

The development and installation of the Jolliet Tension Leg Well Platform (fLWP) included several innovative designs and novel equipment developments. One of these novel developments included the in-situ tendon inspection system. This system, based on the ultrasonic inspection method, was successfully developed and used offshore for the baseline inspection of the 12 TLWP tendons and length adjustment joint threads. This paper details the original design requirements, the development and field testing of the system, and the use of the system offshore in the Gulf of Mexico. Additionally, the results of the inspection, proving the value of the extra care in the on-land fabrication of the tendons, confirmed the high quality of these components since there were no reportable flaw indications detected in any of the inspected components.

Introduction

The Jolliet Field Tension Leg Well Platform (fLWP) currently holds the world's deepwater record for a petroleum production platform. 1,2 This platform is located approximately 170 miles southwest of New Orleans, Louisiana, in the Gulf of Mexico on Green Canyon Block 184. The platform is moored in a water depth of over 1760 feet.

The major system that provides for the functioning of the TLWP is the mooring system. The main components of the mooring system's 12 tendons are shown in Figure 1. Figures 2 and 3 present detail schematic drawings of the top and bottom connectors and the tendon pipe. These components are circurnferentially welded together to make up the required tow-out leg lengths of approximately 1685 feet. This leaves the top of the tendons approximately 68 feet below the water surface to the top of the tie-down porch. The 12 tendons are positioned in groups of three around each of the four corner columns. The detail design of the TLWP is discussed in Reference 3.

Previous papers have described the development of the novel tendon pipe materials and the fabrication of these tendons 4,5 The design and modelling requirements of the TLWP tendons were also previously discussed. 6 Based on this criteria, the specific requirements for the insitu tendon inspection system were described in Reference 7. A description of the preliminary tendon inspection system was presented in Reference 8.

This paper focuses on the development, onshore testing and deployment of the inspection system. The first offshore use of the system for inspecting all 12 TLWP tendons is also discussed, together with presenting actual testing results.
A Comparison of Methods for Predicting Extreme TLP Tendon Tensions
Authors: Hodges S.B. , Chiu Hin , Kan W.C.
Published: October 2008

In this work, three companies undertook analyses of a given tension leg platform (TLP) configuration to predict maximum and minimum tendon tensions in an extreme design storm in the Gulf of Mexico. Each participant used its own analytical methods and experience to analyze the subject TLP. The results of this exercise are presented along with a discussion of the different analytical methods used to arrive at the results. The variability in the results can be attributed to a variety of reasons which can be divided into three general categories: items for which Widely accepted analytical procedures were used by all participants, items for which a combination of analytical and empirical evidence was used, and items for which the participants relied on empirical evidence, past experience and engineering judgement. In general, the magnitude of the variability in the results increased from the first to the third category.

The study also pointed out the relative importance of the various contributions to the tendon tension predictions. In some instances, items with a great deal of uncertainty in their estimated effect turned out to have minimal impact on the final result. The results of this study give some indication of the variability and uncertainty in the available analytical methods which may be useful for the calibration of reliability based design codes.

INTRODUCTION

In the design of a tension leg platform (TLP) the prediction of the extreme maximum and minimum tendon tensions is of the utmost importance. The tendons must be large enough to withstand the most extreme maximum tension and the amount of pretension (or excess of displacement over weight) of the TLP must be large enough that the tendons do not go slack. Since the cost of a TLP is quite sensitive to hull and tendon size (and hence pretension levels as well as maximum tension levels) it is important to accurately predict the tensions.

The results presented in this paper arise from a study conducted by three major oil companies in the context of preparation for a possible joint venture involving a deep water TLP. To come to a better understanding of the companies' analytical methods and design practices, a small study was conducted whereby each participant was provided with the particulars of the same TLP subjected to the same environmental conditions and given the task of predicting maximum and minimum tendon tensions.

The immediate purpose of this exercise was to identify areas in which the participants agreed and disagreed on analytical methods and the selection of design values. However, the results are somewhat more far-reaching when viewed from the point of view of an outside observer interested in TLP design. The study provides three "stateof- the-art", or perhaps more accurately, "state-of-practice", analyses by three different organizations, all well versed in the specific problems of TLP design. Each participant followed rational and Widely accepted design and analysis practices.
A Method for Estimating the Fatigue life of a Conductor Pipe
Authors: Samier Pierre , Lebas Genevieve
Published: October 2008

The purpose of this new method is to calculate the probability of failure by fatigue of a free standing conductor pipe subjected to waves.

This combines two approached;stochastic approach using statistical distribution of sea wave conditions and of fatigue crack initiation time.deterministic approach using standard nonlinear finite element analyses to compute the nonlinear transient response of a conductor pipe to a given set of irregular waves.

Two types of nonlinearity are of importance:soil rheology leading to a nonlinear stiffness matrix,wave loading due to the nonlinear term in the Morison equation which is proportional to the square of the relative velocity between the flexible structure and the water particles.

Experimental data on fatigue measurements (S-N curve) and sea conditions display a high degree of scatter. A deterministic approach adopting a safety margin at every stage may therefore lead to unrealistic design.

The method described below takes into account the sources of randomness, the uncertainties and the nonlinearities. To characterize the scatter in the data, the probability density functions are used.

A fatigue analysis using this method has been carried out for a typical conductor pipe 'in the Guff of Guinea.

A dozen dynamic analyses using generated waves described by different wave heights and associated periods are needed because of nonlinearity and since the stochastic approach requires computing the response of the structure to any irregular wave.

For this study, results show that the conductor pipe is still sfee while the usual deterministic approach leads to a damaged structure.

The end result is no longer an overconservative lifetime but a distribution for the lifetime of the structure.

INTRODUCTION

A free standing conductor pipe is a slender structure commonly used in shallow waters. It gives oil companies much concern in terms of repair, and needs specific dynamic and fatigue studies. For water depths beyond 30m, the structural behavior is critical since a lot of these structures suffer damage due to fatigue. Standard deterministic analyses based on Miner's rule generally confirm that the structural behavior is critical at this depth. However, they predict a much shorter lifetime than the actual one.

Miner's rule is almost universally used today to predict the lifetimes of parts subjected to random amplitudestresses. However, this universality is not immune to criticisms:the method uses an S-N cuNe, or in other words, it omits, by some means, the scatter of the experimental data obtained at constant amplitude cycles,the critical value of 1 for the accumulative damage is also subject to a high degree of uncertainty whichis confirmed by conductor pipe experience and by fatigue tests under variable amplitude stress. The aim of the paper is to provide a more realistic lifetime estimate.
Design Enhancements for Offshore Platform Fire Systems
Authors: Dailey R.E. , Mayhew R.E.
Published: October 2008

Existing firewater/deluge systems on open Gulf of Mexico type offshore platforms were evaluated to improve their operation and reliability, and to reduce maintenance. Pumps, firewater systems and deluge systemswere upgraded to meet performance and reliability criteria developed from field and fire testing as well as survey data. Upgraded systems utilize bronze pumps and valving; fi berglass and alloy piping; and a central manifold design. Deluge nozzle placement changed from impingement spray similar to NFPA 15 requirements to area/density spray similar to NFPA 13 requirements and coverage was increased. Principles of material selection and nozzle placement are applicable to alloffshore facilities where reliable automatic fire control is desired.

INTRODUCTION

The size and nature of an offshore firewaterprotection system depends to a large extent on the operator's emergency response philosophy, but if a firewater system is employed, common prob1ems can be encountered. The author's company offshore fire response guideline states:

"Emp1oyees are expected to utilize provided equipment and training to protect themselves, their fellow employees and, if practical, the facility bycontrolling a fire in its incipient stage. The Company does n2i expect employees tofight severe or escalating fires or to use equipment for which they have not been trained."

The firewater systems provided are typicallyfed by auto-start diesel engine driven pumps and contain both manual fire equipment (hose reels and monitors) and automatic deluge (water spray) segments. The deluge is provided to both assist manual fire fighting and prevent escalation.

FIRE PUMPS

Dual, 100% capacity, fire pumps are providedexcept on gas platforms that can be shut down when a pump is out of service. In such cases, facility blowdown is an alternative means of preventing escalation and only one pump is installed. If possible, pumps are located on different deck levels to prevent a pool firefrom affecting both pumps. A1so, when possible, at least one of the pumps is located in or adjacent to the muster or safe area. Pumps are vertical turbine design driven through a right angle gear, and ratings areeither 1500 or 2500 gpm at 140 psi cellar deck level discharge pressure. Size is dependent on total deluge area, and head-capacity curves meet NFPA 20 requirements. This means that end-of-curve performance is 2250 or 3750 gpm at 90 psi which, without hose and monitor use, wi 11 cover several deluge zones as will beexplained later.

A review of test and maintenance recordsindicated that the average time between overhauls was 3 years for the coated cast iron pumps in general use. A smaller sampling of nickel aluminum bronze pumps was averaging 10 years between overhauls which coincides withmanufacturer's experience overseas. Nickel a1umi num bronze pump assemblies cost three times as much as the cast iron assemblies, butthe longer time between overhauls makes the investment attractive and the greater reliability is a safety bonus.
Dynamic Positioning System Evaluation
Authors: Shatto H.L.
Published: October 2008

Evaluation of dynamic positioning systems consists principally of determining the holding capability against expected weather and the reliability of the DP system in operation. Efforts to quantify reliability, by estimating mean time between failure, now permit several useful risk analysis evaluations. The main considerations for DP evaluation are covered here.

INTRODUCTION

Dynamically positioned vessels have been in operation since 1961, and they have allowed us to do many things that anchored vessels are not able to do. Core holes have been drilled and reentered in over 18,000 ft of water, and oil exploration wells have been drilled in 7500 ft of water. Within anchor depths DP has eliminated the risk of anchor damage to subsea pipelines and facilities. A tracking mode allows a pipe or cable laying vessel to move along a pre-set corridor.

Since its first use in core drilling and then exploration drilling its use has grown to include vessels for pipe laying and cable laying, diving support, heavy lift construction, and search and salvage. Most recently it has found its way to small supply and anchor handling boats which are also useful for light maintenance work on subsea facilities.

For all its virtues, its record has not been unblemished. Failure to hold position in bad weather has been an occasional problem. This is not necessarily because of inadequately designed thrust capacity. More often it is lack of redundancy.

Reliability, or the lack of it, is the most frequent cause of position failure. The mean time between failure (MTBF) of DP systems has ranged from less than one month to well over three years, depending very largely on the level of redundancy provided and the elimination of single point failures. Reliability cannot be measured or calculated with much accuracy, but past experience with many systems, some reasonable estimates of component failure rates, and an understanding of the role of redundancy allow useful estimates to be made. Depending on the job to be done it can be very important to know where in the broad range of MTBFs a particular system falls. Although weather plays an important role in determining DP system reliability, the ability to include weather in estimating system MTBF is fairly recent.

Evaluation of holding capability and reliability along with expected weather exceedance and probable cost to the job for a DP system failure permit a fairly straightforward risk analysis to be made. This provides a rational and reasonably quantitative basis for judging the suitability of an existing DP system or the design of a new one for the particular work that will be required of it. This approach can also be used to quantify justification for additions to redundancy for either new or existing vessels.

This paper does not address the suitability of a vessel regarding seaworthiness, motion characteristics, load carrying, deck space, or the many other things that must be evaluated for a particular job to be done.