bluuebunny/crossref_metadata_2025 huggingface dataset:
A Guide To Flare System Design, With Particular Reference To Offshore Platforms
Authors: McMurray Robert , Oswald Brian J. , Witheridge Rodney E.
Published: October 2008

If an offshore flare system is designed without being integrated from the start with that of the overall platform, the resulting system will be less effective than need be in terms of safety, cost, energy efficiency and operability.

This paper presents a guide to the most important, factors to be considered in designing offshore flare systems, including safety, process requirements and pollution, noise and radiation from flares. The methods used to calculate flare radiation are reviewed critically. Case studies are cited to illustrate the cost and material benefits which can be achieved if the flare system is considered from the outset as an integral part of the production process equipment.

INTRODUCTION

In land based oil fields flaring has not been an important part of the process since the flare could, until recently, be sited well away from the plant and its environmental impact minimised. Engineers were often tempted to write the words ‘To the Flare’ on an arrow pointing off the edge of a process flow sheet and then forget them. Quite often this represented the bulk of the initial design information for the flare system and the detailed design was not considered until near the end of the project. The flare system then had to meet the diverse and often conflicting requirements of a multiplicity of gas sources, making design optimisation difficult if not impossible.

For offshore fields, particularly in deep water locations, the flare is an important part of the process because economics often prohibit locating it sufficiently far away to have no impact on the platform.

It thus needs to be considered in detail at the initial design stage since to some extent the flare system can have a significant influence on the process design and oil production rate. Early consideration makes available a greater number of options and leads to the most efficient and cost effective system.

A previous paperl described how the development of new high technology flares has made on-platform flaring viable, and by eliminating the need for a separate flare platform has resulted in enormous cost savings for deep water locations such as the North Sea. The flare is much closer to the operator and previously used design calculation methods involving many implicit assumptions are no longer satisfactory. Under-design will lead to potentially unsafe operation whereas over-design carries enormous cost penalties. This paper presents a guide to the most important factors in designing offshore flare systems and looks critically into one of the most important aspects - accurate prediction of flare radiation. Case studies are presented which highlight the fact that offshore flare design is not a simple matter and that fairly detailed analysis is required to produce the most economic system.
Buchan Development Project - Conversion Of A Drilling Rig Into Afloating Production Platform
Authors: Logan Barrie L. , Rothwell Eric G.
Published: October 2008

This paper describes the conversion of a Pentagone drilling rig into a floating production facility as part of the development of the Buchan Field, North Sea. It examines the key areas of work involved, the problems encountered and solutions reached in order to provide facilities for a peak production rate of 72,000 BPSD of stabilised crude meeting all current UK statutory requirements.

INTRODUCTION

The Buchan Field is located in the UK sector of the North Sea approximately 160 km E.N.E. of Aberdeen with a water depth over the field between 112m to 118m. The field development is based on subsea completions tied into a subsea manifold, connected in turn by a flexible riser to a floating production platform. 9il export is by tanker from a single point mooring buoy.

The rig selected for conversion was Pentagone 83 ?Drillmaster? built in France in 1973. The technical reasons for the selection of a Pentagone included the advantages of its stability, its load carrying capacity and apparent spaciousness.

This marginal field with a relatively short field life, called for minimum time and capital investment. These concepts and the need to meet all statutory regulations were the guiding factors at all stages of the project.

REMOVAL OF REDUNDANT EQUIPMENT

The philosophy adopted for the removal of existing redundant equipment and materials provided essential space and weight reduction. As the production platform was not required to have drilling or well workover facilities, the strip out naturally centred on existing drilling equipment.

The dry mud bulk silos situated to the rear of the derrick were cut and removed in sections giving a reasonably clear area at top, intermediate and lower decks for additional accommodation.

The cement pump was left for well-kill duty. The mud pumps and associated equipment located on the forward lower deck were taken out through intermediate and top deck cut-outs. Together with the dismantling of five of the seven mud tanks and removal of top deck drill pipe racks this provided space at all three levels forward of the derrick for process and utility equipment.

The principle of the new layout therefore was for non-hazardous and quiet accommodation areas to be placed to the rear of the derrick and process and utility equipment to be placed forward of the derrick.

In conjunction with the key items listed above, a multitude of minor systems and equipment were removed or replaced for various reasons as detailed in later sections. The approximate total permanent weight removed from the existing drilling rig was 1,400 tonnes.

PROCESS AND UTILITIES

(a) General

The basic process requirement for Buchan platform was for a simple effective system to separate the oil feedstock from the wells into the component crude oil, gas and water phases. Facilities are designed to produce a peak of 72,000 BPSD of stabilised crude from a feed crude of 33 - 36° API and a G.O.R. of 308 scf/bbl.
Development And Application Of A High Speed Automatic Field Welding Method For Pipeline
Authors: Takeshi Yasuhira , Sakurai Hideo , Bada Toyoaki , Nogami Mitsuo
Published: October 2008

A automatic field welding method of high speed and good reliability was developed with one-side downhill gas metal arc welding (GMAW) method. The results are followings:Diagrams for selection of the appropriate welding conditions in which high efficiency without any defects can be gained in narrow groove welding.A novel groove shape was developed for preventing deposition of copper onto the root bead when the bead was welded from outer side with copper backing from inside.The effect of new-type groove was confirmed by means of a direct observation of root bead with a special device from the reverse side.The new-type groove makes an appropriate welding condition range enlarge and quality and efficiency increases. Copper does not deposit onto root bead even at an experimental welding speed of 210 cm/min.

Introduction

Pipeline installation requires the use of a welding method presenting high pipe-laying efficiency and therefore high welding speed. Also, petroleum and natural gas pipelines require high-quality welds. The present report describes the development of a computer-controlled automatic one-side downhill welding method using high-current-density GMAW with regard to the girth welding of pipe.

In this method, the groove root is made tight and non-gapped, and welding is performed in the narrow gap with little deposit metal, in order to shorten the pipe alignment and welding time. An appropriate procedure for this method was established by developing the downhill welding which uses copper backing on the pipe inside and small diameter solid wire on the pipe outside.

Experimental Procedure

The welding test was conducted by tack-welding the end of a steel pipe ring (5), for which the prescribed pipe and bevel preparation had been made in advance, to an end face of a fixed steel pipe (2)on a stationary frame (1), fitting another steel pipe ring to the other end face of the pipe in the same way, aligning the grooves of the rings, expanding the pipe by internal clamp (4) and performing downhill. GMAW of the pipe by welding machine (3) as shown in Fig. 1. The internal clamp was provided with a backing copper ring fixed into its clamp shoe for alignment so that backing was effected simultaneously with clamping. Chemical elements and mechanical properties of the tested wire were as shown in Table 1. Wire diameters of 0.9 mm and 1.2 mm were studied, and wire 0.9 mm in diameter was decided to be used in the testing because of its less amount of sputtering and greater stability of arc. For the shielding gas, both CO2 and Ar were used. The test results revealed that the narrow-gap one-side downhill welding of pipe performed at high speed by GMAW method involved the problems shown in Table 2.

Basic Shape of Groove

Groove shape largely influences the pipe alignment operation and the selection of appropriate welding conditions. To shorten the aligning time, the groove should preferably be non-gapped, in addition to having root face.
The Development And Proposed Use Of A Wave Force Measurement System
Authors: Mann David P. , Andrews Arthur P.
Published: October 2008

A transducer has been designed to measure the forces, primarily due to waves, experienced by structure!;> at sea. It is designed to be fitted to structures already at sea and does not require mechanical modifications to the structures.

This paper briefly describes the development work leading to the trials at sea of a small scale prototype then discusses the problems that are anticipated for the use of this transducer on larger, full-scale, structures and indicates possible solutions to these problems.

1.Introduction

The National Maritime Institute (NMI), a united Kingdom Government (UKG) research establishment of the Department of Industry, provides a service of measurements at sea. In 1975 a range of research programmes were sponsored by the Ship and Marine Technology Requirements Board (SMTRB) of the UKG to investigate and prOVide basic data about forces exPerienced bytypical structures at sea such as oil rigs due to their inter-reaction with the'natural environment. As part of this research NMI were given charge of the section involving the measurement of forces and environmental conditions experienced by a specially constructed research structure,. intermediate in size between laboratory scale models and full size. This structure located just off the south coast of the UK is referred to as the christchurch Bay Tower (CBT),(Fig. 1). It is 27.8 metres tall and stands in 8.4 metres of water. 128 channels of measurement and environmental data are monitored on a regular basis. [1].

During the initial investigative work for this structure it became readily apparent that forcemeasurement on structures at sea commonly relies on the use of strain gauge devices, normally installed during structure manufacture. Although not proposed for use on the CBT, a requirement was seen for a simpler system of wave force measurement that could be easily attached to existing structures already at sea. As a result of this a technique was proposed whereby pressure changes caused by wave forces rather than by sea surface elevation changes, could be measured. The system that was proposed, shown schematically in Fig. 2, is that a number of flexible, fluid-filled cells, enclosed in a rigid outer casing, are equi-spaced around the structural member of interest. Forces applied to the load ring of this casing are transmitted through to the flexible cells causing changes in their internal pressures. These changes in internal pressures then being measured.

The pressure exerted on the immersed casing is dependant upon:atmospheric pressuredepth of immersion below lowest tide leveltide height at any given timedensity of sea waterforce due to tidal velocitywave heightforces due to waves, e.g. drag, inertia and slam
The Influence of Chain Friction on Anchor Pile Design
Authors: Vivatrat Vitoon , Valent Philip J. , Ponterio Albert A.
Published: October 2008

This paper presents a simple and versatile computer procedure for estimating the influence of chain friction on the pile load in an anchor pile-chain system. The chain-soil interaction is modeled in terms of the chain embedment depth, chain characteristics and soil strength profile.

Example predictions are presented to illustrate the relative magnitudes of the vertical and horizontal components of the pile load, and the effects of the embedment depth, chain size and pretension. A limited comparison with some measurements of chain friction at shallow depth is also presented.

Introduction

Anchor piles have been used offshore to provide anchor points for mooring purposes for centenary-moored floating platforms (Figure 1) and are a leading candidate for anchoring the lines of guyed tower platforms. The mooring line has been connected at an intermediate position along the pile length (Figure 2(a)), or at the pile head with the head below or at the mud line (Figure 2(b) and 2(c».

Positioning the pile head and chain connection at the muddling (Figure 2(c)) facilitates full inspection and refurbishment of the chain in long-term moorings. On the other hand, the bending stresses in the pile can be significantly reduced by connecting the anchor chain to the pile at a point below the pile head. The reduction results primarily from the additional end restraint provided by the soil above the chain connection.

In practice, the chain connection point has been located as far down the pile as its mid-point, e.g., see Reference (1). The pile and chain are installed by driving the pile and the reconnected chain together. After some tensioning, the chain will assume a configuration as schematically shown in Figure 1.

A pile-chain connection below the mud line implies that the load applied to the pile will have both a vertical and a horizontal component. The relative values of these two load components vary with the chain configuration, which in turn depends on the tension applied to the end of the anchor chain at the mud line. This paper discusses the influences of the chain soil interaction on the line tension at the pile connection. Example predictions from a proposed computational procedure are presented to illustrate the effects of embedment depth, chain size and pretension.

2. Previous Work

Previous studies of the influence of "chain-soil interaction on chain tension can be divided into two groups: those related to the dragging friction and those related to chain embedment.

Dragging friction on anchor chains was usually studied in the field or in laboratories by dragging a length of loose-ended chain in contact with soil. The results can be presented in terms of an "efficiency" ratio (i.e., dragging resistance divided by weight of chain in air) as summarized in Table 1. The chain in his case generally does not cut into the soil and may not be in full contact with the soil.

Interaction between soil and embedded chain was considered by Reese (4) and Gaunt and Cox (5).
Method for Laying and Connecting Intrafield Flowline Bundles in Deep Water
Authors: Coleman James T. , Saliger Kenneth C. , Yancey I.R.
Published: October 2008

This paper presents a method for simultaneously latching both ends of a floating flow line bundle remotely to two subsea structures and laying on the seafloor without the use of divers. The entire multiplied bundle is fabricated onshore, fitted with end termination assemblies and pressure tested prior to launching. The bundle is then launched and towed near the surface to the installation site. Drawdown cables pivoted on the sea floor are attached to each bundle end and to heave compensated surface winches. Both ends are then hauled down and mechanically latched to the sea floor structures. The entire bundle takes an inverted catenaries configuration. With the two surface support vessels controlling the pipe bundle end tensions and a control vessel acoustically monitoring the bundle configuration, the pipe stresses are determined and controlled within allowable limits. After mechanical attachment to the sea floor structures, the buoys are selectively released allowing the flow line bundle to lay on the sea floor.

A specially designed connector tool, run from each surface support vessel, completes the installation by remotely removing the test cap from the bundle end pipe mandrel and hydraulically connecting the bundle to the subsea structures.

This method was successfully demonstrated during 1980 in the Gulf of Mexico on a commercial installation.

Introduction

Offshore exploration drilling is continually moving into deeper water. This presents an ever increasing challenge to deepwater subsea production systems. Since the mid-60's Mobil has been active in the development of deepwater production systems. In the early development stages, it was realized that pipe laying tension forces to control bending and collapse stresses using conventional pipe laying techniques were water depth related and, therefore, posed some finite practical water depth limitation. In addition, remote, driverless second end connections would be complicated and difficult in deepwater.

Various feasibility and trade-off studies were conducted and resulted in the concept of "The Simultaneous Drawdown Method". This paper presents "The Simultaneous Drawdown Method" for installing flow line bundles up to 12,000 feet in length for water depths in excess of 1,000 feet.

A flow line bundle is defined as two or more pipes in a common carrier with single piece, multi-bore end terminations. Both ends of the buoyant bundle are hauled down and latched to seafloor structures with the bundle taking the shape of an inverted centenary. This method has the following advantages: (See Figure I)Eliminates the complications of a second end connection by making two first end connections simultaneously.Allows installation forces and pipeline stresses to become insensitive to water depth.Has the unique ability to install a bundle whose length is less than water depth.Provides for the entire flow line bundle to be fabricated and tested onshore prior to mobilization offshore.
Stand-By Rescue Ships - Their Roles and the Factors Involved in Performing Them
Authors: Sykes John , Hibbett Hollobone
Published: October 2008

This paper is based on a study, led by the author, which was completed in 1981 for the UK Department of Energy and which led to the publication of Draft Guidance Notes for the operation of Rescue Ships in the UK Sector of the North Sea. The paper examines the requirements for independent rescue facilities for offshore installations and concludes that such facilities are needed. It goes on to discuss the requirements of such vessels in material and personnel terms. In particular it considers the relevant topics of vessel design, pick-up boat design, propulsion and launching systems, medical capabilities, communications and personnel selection and training Its conclusions highlight the main features of the Draft Guidance Notes for Rescue Ship Operations.

INTRODUCTION

Stand-by Vessels have been required by law to be stationed in the vicinity of offshore installations in the North Sea for several years. They were first introduced in the UK Sector after the loss of the drilling rig Sea Gem in December 1965 when 13 people died. British law demands that a vessel shall be present within 5 nautical miles of every offshore installation when it is manned, ready to give assistance in the event of an emergency on or near-the installation. The vessel is required to be capable of accommodating and providing first aid to all persons who may be on the installation at any time and to have primary and secondary means of communication with the installation. More detailed requirements for the vessels are issued by the UK Department of Trade. The Department?s Surveyors are required to have issued a Certificate of Survey for each vessel before United Kingdom Offshore Operators Association members will employ it as a Stand-by Vessel in the UK Sector. Similar arrangements exist in other North Sea Sectors. Thus it is that all operators of offshore rigs and platforms in the North Sea have employed certified vessels to stand by within 5 nautical miles of their installations at all times.

Perhaps because these vessels have sometimes been chartered more to fulfill the requirements of the law than because of any conviction that they are needed for a practical purpose, they have tended to be of a standard sufficient to obtain a Certificate of Survey but no more. It can, and has been, argued that this standard is insufficient for the role they are there to fulfill, but before this can be examined, it must be clearly established that a genuine role exists. If it does, the capabilities of vessels needed to perform it can then be assessed. The study upon which this paper is based set out to do this.

CONDUCT OF STUDY

The study took the form of some fifty so discussions with a very wide variety of companies and organizations connected with Stand-by Vessels and visits to Stand-by Vessels operating offshore. The people performing the study, and subsequently drafting the guidelines had considerable marine and offshore industry management experience but had no vested interest in the outcome of the study.
The Tarsiut Island Monitoring Program
Authors: Weaver J.S. , Berzins William
Published: October 2008

This paper presents a description of the monitoring programs used during construction of Tarsiut Island and during the drilling of the Tarsiut N-44 exploration well. The objectives of this program were threefold:To ensure that the island was constructed according to acceptable design standards.To ensure that the island performed satisfactorily under the imposed environmental loads throughout the drilling of the Tarsiut N-44 exploration well.To collect data that could be used to streamline the design of future islands.

A description of the monitoring strategy and instrumentation is presented. Typical results are reviewed and recommendations for future programs are given.

INTRODUCTION

Tarsiut Island was the first artificial caisson-retained exploration drilling island constructed in the Beaufort Sea. The island was built during 1980 and 1981 by Canadian Marine Drilling Ltd. on behalf of the operator, Gulf Canada Resources Inc. A description of the design and construction of the island is presented by Stenning and Fitzpatrick (1983).

The layout and dimensions of the island are summarized in Figure 1. This drawing represents the island as it was designed for drilling the first exploration well during the 1981-82 winter.

The island represents a benchmark in the design of Arctic drilling platforms. It was not only the first caisson retained island in the Arctic, but was also the first island to be built outside the 1and fast ice zone. Furthermore, Tarsiut was regarded as the prototype of possible future production platforms in the Beaufort Sea. With this in mind, Gulf et al committed to an extensive monitoring program, the objectives of which were threefold:To ensure that the island was constructed according to acceptable design standards.To ensure that the island performed satisfactorily under the imposed environmental loadings throughout its design life.To collect data that could be used to streamline the design of future is1ands.

A quality assurance program was implemented in order to achieve the first objective. The second objective was satisfied by monitoring the response of the island under ice and gravity loads. This " operational monitoring" program was implemented during the drilling activities on the island and was integrated into the alert and evacuation procedures.

A comprehensive research program was put into effect to satisfy the third objective. This work was primarily orientated to collecting data on winter ice forces and island response to these forces. Geotechnical data on caisson "setdown" pressures, island settlements, and ground temperatures were al so collected as part of the research program.

The remainder of this paper describes the monitoring strategy and instrumentation for each of the monitoring programs. Examples of typical results are presented and recommendations for future monitoring programs are also given.
Anchor Holding Tests in the Norwegian Trench
Authors: Void R.C. , Eie John
Published: October 2008

Two series of pulling tests, made on four types of commercial 3-ton anchors at 300 m water depth in the open sea west of Bergen, are reported. The first series included full instrumentation of the anchors while in the second series only anchorline tensions were measured. The seabed consisted of soft silty clay. The resulting holding capacities were extrapolated to larger size anchors.

INTRODUCTION

The depression known as the Norwegian Trench runs for some 400 n. miles parallel to the coast of south Norway. Its width varies between 30 and 60 n. miles and its depth between 300 and 800 m. Being much deeper than the North Sea in general it presents difficulty for pipelaying between the petroleum fields on the Norwegian Shelf and mainland Norway. Since the surficial seabed sediments are very soft there has been concern as to the anchor holding capacity for operation of lay barges.

The Statoil/Mobil group in 1977 undertook to investigate the performance and holding capacity of various anchor types by means of large-scale field testing in the Trench. The test program was part of the Statfjord Transportation System Project and based on a contract between Statoil and Oil Industry Services A/S. A cooperation agreement was made between OIS, Lindboe and NOTEBY. The Central Institute of Industrial Research and A/S Teleplan were engaged for specialized instrumentation.

PHASES OF PROGRAM

The work was performed in partly overlapping phases as follows:Planning of test proceduresPreparation and calibration of instrumentationProviding vessels, anchors and equipmentSampling and testing of seabed soilsFunctional pre-testing in sheltered waters (fjords)Main testing at seaData processing, reporting and evaluation

TEST SITE AND SOIL CONDITIONS

Based on a seabed soil survey a test location (B) was selected at a water depth of about 300 m, as seen in Fig. 1. The exact test positions and points of soil sampling are shown in Fig. 2. The geotechnical data of the seabed soil are presented in Fig. 3, which shows that the upper 8 m or more consists of normally consolidated clay of high plasticity (CH) with some organic content and an undrained shear strength increasing from about 2.5 to about 12.5 kN/m2 with depth. The indicated further linear increase is from borings for other projects in the Trench.

TEST ANCHORS

Four types of anchor were tested: Stevin, Flipper-Delta, Bruce Mark 2 and Baldt stockless, as Shown in Fig. 4. An instrument box (165x200x1860 mm) was welded to the upper side of the anchor shank, and small brackets for a soil sampler were welded on the anchor fluke. The total mass of each anchor was 3750 kg (3.75 metric tons) including the instrument box. 2 The fluke area ranged from 1.0 m2 for the Baldt anchor to 3.6 m for the Stevin. All anchors except the Bruce were hinged.
Improvements to Frequency-Domain Riser Programs
Authors: Mclver D.S. , Lunn T.S.
Published: October 2008

This paper develops and demonstrates the improvements to frequency domain riser analysis obtained by including a wave surface correction and by calculating forces at the displaced riser position. The range of validity is extended to higher waves without a significant increase in program running costs.

Comparisons of running costs and results are made against two time domain programs. Significant improvements to the bending moment range are obtained and therefore to the fatigue damage estimates for regular waves.

INTRODUCTION

Frequency-domain riser programs are now firmly established as important riser design tools. Their merit lies in their very much lower solution costs compared with time-domain programs while still offering an acceptable degree of accuracy.

The time-domain solution of the idealised riser problem is clearly the more accurate method. Its cost, although large for regular waves, is acceptable provided only a limited number of cases are being considered. However, for a fatigue ana1ys is either a 1arge number of regu1 are wave solutions are required or the response to a synthesized irregular wave must be obtained. The cost can be prohibitive using a time-domain program.

The frequency-domain method seeks directly, in closed form, the periodic solution to which the time-domain program converges after allowing for the decay of the starting transients. Because of the quasi-1inearisation, an iterative solution is required. The most powerful non-linearity is the relative velocity squared term of the viscous drag. If the approximation to this is not chosen with care, large inaccuracies can resu1tl. In their state-of-the art paper Krolikowski and Gay l rationalise the process of carrying out this 1inearisation using the Describing Function technique. Four specific wave inputs are considered:Regular waveRegular wave with currentRandom waveRandom wave with current.

Extremely good and consistent results are obtained when compared with those of a time-domain program. However, the only non-linear term considered is that of drag. The aim of this paper is to show the improvements obtained by introducing the other non-1inearising features of the problem commonly included in a time-domain analysis. These areWave forces which are calculated at the displaced position of the riser.Allowance for the alternate submergence and emergence of the riser in the region of the wave surface.

The technique of dealing with stroke- or rate-dependent tensioner effects and the only recently recognised Froude-Krylov curvature term2 is discussed briefly, although not included in the numerical comparisons of this paper.

The additional terms are treated only for regular waves with or without a current. The extension to irregular waves has not yet been completed.

GENERAL EQUATIONS OF RISER MOTION

The general equations of motion of a riser are usually formulated on the basis of displacements which are small relative to the length of the riser and deformations which are sufficiently small that the conditions for elastic behaviour are satisfied.
Overview of the Central Cormorant Underwater Manifold Centre Project (1974-1983)
Authors: Bastiaanse Tom , Liles J.R.
Published: October 2008

The Underwater Manifold Centre (UMC), installed in the Central Cormorant field of the North Sea in 1982, is an example of a development that extends frontiers in the area of subsea technology. This paper describes the history of the project and how the combined resources of Shell and Esso brought it to fruition.

Topics discussed in the paper range from tl.-1 project's terms of reference to installation of the UMC to present status of offshore activities and remaining work.

It concludes with a broad summary of what the UMC experience has provided to both Companies to date.

INTRODUCTION

This paper discusses the Central Cormorant Project, in general terms, from its early history to its present status, through to future plans to complete the last of its ten wells. The intention of the paper is to set the stage for four more specialised papers on the UMC, which are also being presented at this conference. These companion papers cover the UMC's design, landtest programme, control system, and insulated pipelines, respectively.

The overall Central Cormorant subsea production system concept is illustrated in Figure 1. The system's basic components consist of:The UMCFacilities on the South Cormorant 'A' platform from which the entire system is controlledSatellite wells tied-back to the UMC, including a special satellite well linked directly to the platformAn overhead drilling rig, andPipelines and control lines that link the system together

Maintenance of the UMC can be accomplished from an overhead vessel or by the use of a unique Remote Maintenance Vehicle (RMV) as illustrated in Figure 2.

The system has Through Flowline (TFL) well serv1c1ng capability and is also capable of injecting chemicals to prevent hydrate formation.

The project's budget is approximately £360 million. From its inception in late 1974 to its projected completion in 1986, over 12 years and 600 man-years of Shell and Esso engineering effort will have been expended.

PROJECT HISTORY: 1974-1982

In late 1974 Shell and Esso formed the Joint Underwater Development Team (JUDT) with the objective of developing an underwater production system suitable for use in the hostile environment of the northern North Sea. The team's initial task was to determine whether available subsea technology existed for this application.

This survey indicated that adequate technology and experience could be made available; mainly as a result of Shell's experience with subsea wells in Brunei and elsewhere and Exxon's experience with their pilot Submerged Production System (SPS) project in the Gulf of Mexico #.

The basic philosophy for the JUDT was to use, as far as possible, proven technology in developing a design that emphasised safety, reliability, flexibility, and ease of maintenance. Not unexpectedly, prior systems did not wholly meet North Sea project criteria, so in-depth screening studies were undertaken by a team composed of technical and managerial personnel from both Companies. This background work took until the middle of 1976.
Side Launch of the Lena Guyed Tower Jacket
Authors: Flood J.K. , Pichini P.O. , Danaczko M.A. , Greiner W.L.
Published: October 2008

The launch of the 27,000-ton Lena jacket was a critical and challenging aspect of the Lena Guyed Tower installation. The Lena jacket was the longest one-piece jacket ever launched, and is the industry'sfirst side launch of a major offshore structure. Although the side launch offered advantages over a conventional end launch, this technique presented unique problems that required extensive analysis and innovative solutions. In addition to requiring significant launch barge modifications, the side launch increased the potential for jacket skewing relative to the barge due to differential friction and caused higher-than normal slamming loads due to high entry velocities.

This paper discusses the challenges that were faced and the solutions that were developed. Computer analyses and scale model launch tests are also discussed. Particular emphasis is placed on the jacket skewing solution which utilized a special release system similar to that used in the Space Shuttle Program.

INTRODUCTION

Figure 1 depicts the Lena guyed tower jacket on the launch barge. The 1079-foot jacket rested on four transverse skidways on the 580-foot long by 580-foot wide launch barge and overhung the stern and bow of the barge by 194 feet and 305 feet, respectively. As shown in Figure 1 the jacket was offset 20 feet from the barge center line during the transportation and pre-launch operations.

A two-step sequence of the side launch is depicted in Figure 2. The upper diagram shows the barge ballasted to a predetermined starboard heel angle of 7 degrees. At launch, the jacket was freed from the holdback, release mechanisms and began sliding toward the starboard side of the barge. The jacket slid approximately 60 feet, as shown in the lower diagram, before the jacket's center of gravity passed over the tilt pins of the four starboard tilt beams. At this point the tilt beams rotated, and the jacket slid off the tilt beams into the water.

The side and conventional end launch methods were investigated and compared using extel1sive computer analyses the results of which indicated that both methods were feasible. However, the side launch method was selected because it offered several advantages.The side launch saved approximately 3000 tons of structural steel that would have been necessary to sustain the cantilevered loads experienced in an end launch.Because of this reduced weight, the eight main pile 1060-foot lead sections were preinstalled, which reduced offshore installation time.The risk of damage to the jacket and or barge was minimized during the side launch because the time of exposure to winds, seas, and currents was substantially reduced. The duration of the side launch was less than to seconds as compared with 40 seconds for an end launch.
Measured Dynamic Behavior of North Sea Jacket Platforms
Authors: Langen I. , Spidscbe N. , Bruce R.L. , Heavner J.W.
Published: October 2008

The paper presents results from analyses of full scale measurements of the dynamic response of two steel jacket platforms in the North Sea.

The measurements discussed in the paper were, for both platforms, recorded in extreme environmental conditions.

The main emphasis is on describing the structural system behavior, on the composition of the dynamic response and on the evaluation and characterization of the environmental loading mechanisms.

It is found that the stress response is mainly wave induced and quasi-static. The quasi-static response is non-Gaussian and consistent with theoretical predictions based on Morison-type wave loading. Several other non-linear wave load effects are also apparent. The structural system is close to linear in stiffness and mass. The resonant response is, however, non-Gaussian due to nonlinear damping mechanisms.

The paper discusses also the implications which the observed non-linear wave loading and structural damping may have for potential deep water jackets.

INTRODUCTION

In compliance with the requirements of the Norwegian Petroleum Directorate seven fixed platforms in the Norwegian sector of the North Sea have been instrumented for collection of environmental data and platform performance data (E- and P- data). The main purpose of the collection and analyses of this data is "through a check of the design assumptions and platform behavior, to be able to assess the safety of the load carrying structure and foundation in the production phase". An additional purpose is to gain experience with operative platforms that may be useful when considering new platform concepts

The data collection programmes which lasted for periods of two to three years have created a valuable data base for analysis and research on platform behavior in different environmental conditions.

This paper describes the dynamic behavior of two steel jacket platforms in both moderate and extreme environmental conditions, as evaluated from the full scale measurements. Similar results for gravity structures and an articulated tower have been presented in ref. /1/ and /2/.

The main emphasis of this paper is on the description of the behavior of the structural system including the soil-structure interaction, on the composition and nature of the dynamic response and on characterization of the waves and the hydrodynamic loading.

Furthermore, the nature of the observed behavior is compared with theoretical models of the platform behavior arising from the commonly used design assumptions.

DESCRIPTION OF THE PLATFORMS

The two platforms dealt with are Ekofisk 2/4H and Valhall QP. Sketches of the platforms are given in Figure 1.

Both platforms are four legged quarters platforms situated in approximately 70 metres water depth. Ekofisk 2/4H is K- braced with single corner piles while Valhall QP is X-braced with double corner piles. Both platforms are connected to other platforms with bridges.
A Project Management Approach to Design andConstruction of a New Generation Arctic Drilling System
Authors: Loh J.K.S.
Published: October 2008

A second generation drilling system for the Arctic offshore has been designed and constructed by Gulf Canada Resources Inc. This paper describes the decision process that resulted in the implementation of project management approach to the undertaking. A brief description of the organizational structure and control mechanisms used are presented.

INTRODUCTION

Gulf Canada Resources Inc. formed a new operating division within its Frontier Department in July, 1981, to take on the task of constructing and putting into operation a new generation Arctic drilling system. The decision to invest $674 million Canadian on the new system was driven by the fact that there was not enough equipment in the Canadian Arctic to adequately explore the vast potential of hydrocarbon reserves in the offshore areas; and that a new technology was needed to extend the drilling season in the harsh ice-covered environment.

The dri11ing fleet, commonly known as the Beaufort Sea Drilling System, consists of:Conical Drilling Unit - a near-circular hull semi-submersible drilling unit moored on location with 12 anchors.Mobile Arctic Caisson - an integrated bottom-founded steel caisson structure.Two Ice Class IV Supply Vessels, also used for towing, anchor handling and ice management.Two Ice Class IV Arctic Ice-breakers.Northern operations bases.Logistic and support sys terns 1inking the bases to the drilling sites.

With the exception of Mobile Arctic Caisson, the system went into operation in the Canadian Beaufort Sea in the summer of 1983, on time and under budget. The caisson is scheduled to be delivered in the summer of 1984. When the caisson is delivered, a capital project of main magnitude, managed by a company that departed from traditional approaches will have been successfully executed. The most important factor that resulted in this success was the implementation of project management approach to the undertaking from start to finish.

PROJECT IDENTIFICATION

In the initial stages of the project identification, management must first set precise objectives, and, then rigorously assess the company's internal capabi1ities to determine whether or not the objectives can be .met. At the same time, external environment, such as government regulations and market demand, must also be evaluated.

In the industrial sector, project objectives are generally to either add new income generating assets, or to offer improved products at competitive prices. It is a complex process to match available internal resources to such objectives. Common sense must prevail, so that the objective can be accomplished without negative impact on other company interests.

In the case of Beau fort Sea Dri11ing Sys tern, Gulf Canada Resources began by assessing dri11ing systems then available on the world-wide market to determine whether or not equipment existed that would satisfy our specific requirements in the Arctic offshore.
The Iwaki Platform in Japan: The Influence of Severe Earthquakes
Authors: Wardell J.B. , Fry R.K.
Published: October 2008

The Iwaki platform-was recently installed in 154 meters of water for developing the Iwaki Gas Field in Japan. The platform is located 40 kilometers off the east coast of northern Honshu, about 250 kilometers northeast of Tokyo, in an area known for severe earthquakes. The design and construction of the platform were dominated by earthquake motion considerations.

INTRODUCTION

The Iwaki platform is the major-component of the Iwaki Gas Development Project. Field operator for the project is Offshore Iwaki Petroleum Co., an affiliate of Teikoku Oil Co. Its partners are East Japan Oil Development 'Co. and Esso Production Japan (EPJ), an Exxon Corporation-affiliate. EPJ is the acting field operator for the planning, engineering, and construction phases of the project.

Planning and engineering design of the platform began in 1978 by Exxon Production Research Co. (EPR). A conventional design concept was developed (Figure 1). The 15000 mt launched jacket is secured to the seafloor with eight 1829 mm (72 in.) main piles and sixteen 2134 mm (84 in.) skirt piles. The module support frame (MSF), which weighs about 1100 mt, is positioned on top of the main piles and supports the modularized deck. The deck consists of nine major module units plus a unique drilling rig, two platform cranes, and various smaller packages.

Topside facilities of the platform are designed for drilling and producing from up to 24 wells. The facilities were designed to handle a production rate of about 2.1 million cubic meters of gas per day. The gas will be dehydrated on the platform and then transported to shore through a 305 mm diameter pipeline. Following processing at an onshore plant, the gas will be delivered to Tokyo Electric Co. 's Hirono power plant.

Platform fabrication was initiated in mid-1981, and offshore installation was completed by year-end 1983. Virtually all construction engineering and land-based fabrication activities were contracted to various Japanese companies, and the offshore installation was contracted to Heerema Marine Contractors (HMC). Numerous aspects of the project were influenced by the consideration of severe earthquake motions.

EARTHQUAKE ENVIRONMENT

Iwaki is the first offshore platform located off the Pacific coast of Japan. It is in an area known for extremely severe earthquakes. Extensive site-specific studies were conducted to develop two distinct design criteria for the platform-strength level and ductility level criteria. The strength level event has a recurrence interval of approximately 200 years, and the recurrence interval of the ductility level event is several thousand years. The ductility level event is generally representative of an earthquake of Richter magnitude 8.0 that occurs at a distance of 42 kilometers from the platform. The shaking associated with the ductility level earthquake may possibly cause liquefaction of the upper portion of the soil hence soil liquefaction was accounted for in the design.