bluuebunny/crossref_metadata_2025 huggingface dataset:
Verification of Jackup Leg-to-Hull Beam Model Interaction Using Super Elements
Authors: Maison J.R. , Lewis D.
Published: October 2008

The design of leg members for a mobile offshore drilling unit (jackup) with guides, is driven by the loads introduced at the lower guide. The selection of the optimum leg member sizes for the many environmental loading possibilities represents a major effort in the design of jackups. In an attempt to control the time and cost of analysis, a simplified beam model of the leg to hull connection has been used. This "pitch fork" beam model developed and calibrated in the late 1970's, combines the effect of different leg to hull positions into a single representative case.

The evolution in finite element technology allows for re-examination of the "pitch fork" beam model. New rig design and the desire to extend the operational envelope of existing designs have stimulated a reappraisal of the simplified beam model approach. The accuracy of the beam model is investigated using a detailed finite element plate model of an entire leg of a jackup. The effects of structural details including member eccentricities and gusset reinforcements are accurately accounted for in the analysis. The FEA superelement method makes the problem computationally manageable.

A typical load case for the GORILLA Class jackup operating m the North Sea is studied. The loading is applied to the simplified beam model and to two superelement models that represent the extreme conditions of leg to hull position. In one superelement model the lower guide on the hull aligns with a main horizontal leg member. The second model has the lower guide vertically positioned mid way between horizontals.

The "pitch fork" beam model is calibrated against the results of the superelement derived loads. Optimization methods are used to adjust the properties in the beam model to match the results of the superelements.

BACKGROUND:

The structural design of a jackup depends upon the load transfer between the hull and the supporting legs. The means of load transfer directly affects the size of leg members and thus drives the weight and cost of the jackup. The load transfer mechanism for the GORILLA Class jackup is used for illustration, although the concepts are generally applicable to other designs.

The jackup GORILLA is configured with a triangular shaped hull and three support legs. Each of the legs is square in plan view. The leg is constructed from vertical members positioned at each corner and crosslinked tubulars. A "K" brace lattice design of main horizontal and vertical diagonal tubes is used. Other smaller pipes provide horizontal support to the joint intersection of the main diagonal and horizontal members. The main horizontal and vertical diagonal tubular members are the same size.

A typical leg construction is shown in Figure 1. The vertical post at each corner of the leg is a built-up member, triangular in plan view, with one flat surface (back plate) facing the leg center. This surface is extended to form a lip which slides through channel shaped guide members attached to the top and bottom of the hull.
The Application of Risk Assessment in Offshore Projects
Authors: Comer P.J. , Eades M.J.
Published: October 2008

1. INTRODUCTION

The past ten or so years have seen a steady increase in the use of risk assessment to help improve the safety of offshore facilities. This process started with the requirements for "Concept Safety Evaluations" in the Norwegian sector of the North Sea, and has gathered pace since the Piper Alpha disaster and especially since the publication of the Cullen Report in November last year. Lord Cullen has recommended a fundamental change in the regulation of offshore safety on the UK Continental Shelf; he has proposed that the current prescriptive regulations are replaced by goal setting regulations. This approach is broadly similar to that of new regulations in the Norwegian sector which came into force in January this year. An integral part of both approaches is in the use of risk assessment methods to demonstrate that an adequate level of safety has been achieved.

This means that risk assessment can no longer be seen as an academic discipline practised by the safety department and their consultants. It is going to become the basis of key and costly decisions and will be an important aspect of the interaction with the regulatory authorities. It will be important that the management of operating companies, at all levels, understand the principles, the shortcomings and the ways in which risk assessment should and should not be used.

2. WHAT IS RISK ASSESSMENT?

Risk assessment is a generic term covering a wide range of techniques used to assess the level of safety by considering both the magnitude of harm or damage and likelihood of such harm occurring. Such assessments can be qualitative or quantitative or a mixture of the two.

A risk assessment will therefore involve some assessment of the damage and an assessment of likelihood. Such assessments can be presented in simple qualitative scales or be fully quantified to result in a numeric value of risk. A Quantitative Risk Assessment (QRA) can involve the use of a variety of methods or models ranging from simple correlations to complex computer codes; these will include methods for the assessment of the consequences of releases including dispersion models, flame radiation models, explosion models etc.; models for assessing the impact or damage resulting from the fire or explosion or impact; data on the likelihood of failures of various items of equipment and on the likelihood of alternative outcomes, for example, ignition and methods for utilising that data; and methods for summarising and presenting the results in a useable manner.

The basic approach of QRA techniques is to analyse a complex system (such as a platform or chemical plant), which contains hazardous materials, hardware, control and safety systems, people and management systems, with the intention of determining:what accidents can occur? - this depends on the scope of the study and may be generated using checklists, HAZOP or previous study experience.how frequently does each accident occur? - a combination of failure rate data and conditional probabilities.
Auk to Kittiwake: 15 Years' Progress in North Sea Jacket Engineering
Authors: Edwards C.D.
Published: October 2008

The Kittiwake oil field has been developed using the first of a new generation of liftable slimline jackets to be installed in the North Sea by Shell UK Exploration and Production, known as Shell Expro, operator in the UK sector the North Sea on behalf of Shell and coventurer Esso Expro. Production began in September 1990 - almost exactly 15 years after Shell Expro began production from Auk, its first North Sea oil field. This paper considers the progress of jacket engineering over these 15 years by comparing two jackets supporting topsides facilities which perform comparable functions in very similar conditions.

INTRODUCTION

The Kittiwake platform is a self contained drilling, production and accommodation platform located in 85 metres of water approximately 100 miles east of Aberdeen in the Central North Sea sector of the UK Continental Shelf. Recoverable oil reserves from the field are approximately 70 million barrels, making Kittiwake one of the smallest North Sea fields to be developed as a standalone facility. Kittiwake was originally part of the Gannet Cluster project which was suspended during the 1986 oil price collapse. It has now been developed using a 4 leg lift installed jacket which supports an integrated deck, living quarters module and drilling mast. The platform has 16 well slots, facilities for up to 36000 barrels of oil production per day, and accommodation for 80 men. Oil is exported via a 2km. long 8 inch diameter pipeline and a loading buoy into shuttle tankers. The Kittiwake tankers are dynamically positioned, enabling them to continue loading oil in rougher seas than moored tankers - an important advantage as Kittiwake has no storage and therefore is shut down when the tanker is not loading. Associated gas is exported via a 2km. long 4 inch diameter pipeline into the nearby Fulmar gas line.

The Kittiwake jacket, which had a lift weight of 5400 tonnes, is supported by twelve 2.134m. diameter skirt piles each driven to 60m. seabed penetration. The jacket framing is depicted in Fig. 1. The four leg structure stands 106.6m. tall and directly supports the 7000 tonne lift weight integrated deck without an intermediate module support frame (MSF). The bracing pattern is very simple, having three X-braced vertical frames and four diamond braced horizontal frames at elevations +14m., -15m., -47m., and -82m. respectively. The nominal lateral dimensions of the jacket are 25m. by 22.6m. at the top, and 38m. square at the base. These plan dimensions are unusually small for the support of a large integrated deck, as Fig. 1 illustrates.

After initial jacket design by Shell Expro, detailed design was undertaken by Earl & Wright, London. RGC, Methil then fabricated the jacket and piles. Installation of the complete platform was performed by HeereMaC using the semi-submersible crane vessel (SSCV) DBI02, under subcontract to McDermott International Inc. It is noteworthy that many of these companies were also principal players in the execution of Shell Expro's Auk project.
The Structural Repair of a North Sea Platform Using Underwater Wet Welding Techniques
Authors: Ibarra S. , Reed R.L. , Smith J.K. , Pachniuk I. , Grubbs C.E.
Published: October 2008

Underwater wet welding repair techniques using ferritic electrodes have, until recently, been limited to low strength steels with carbon equivalents below 0.40% because the fast quench that occurs after welding produces hard heat affected zones susceptible to hydrogen cracking. This paper describes the first documented structural wet weld repair of a North Sea offshore platform constructed with steel that had a carbon equivalent greater than 0.40%. It describes the events that lead to the failure and documents the repair using underwater wet welding techniques.

BACKGROUND

The underwater inspection of an Amoco U.K. North Sea Platform in June 1987 revealed that a diagonal brace connecting Leg B3, at a point 26 feet above water to Leg E3, at a point 36 feet below water (Figure 1) had a severed weld which had connected the brace to the E3 leg node (Figure 2). The failure was the result of ship impact on the brace. Initial structural assessment concluded that the damage did not affect the integrity of the platform and no emergency measures were required. However, in order to prevent further degradation of the damaged member from wave action, the brace was removed in July 1987.

A failure analysis supported by a metallurgical examination of the fracture surface was undertaken by Amoco Corporation Research at Naperville, Illinois. The findings indicated that the failure was the result of the impact loads which occurred when the ship struck the brace. The impact resulted in a circumferential weld metal crack between brace 3Bl and the jacket leg stub JL3E which was located underwater.

Multiple fractures initiated at lack of penetration weld defects on the ID of the brace weldment with several fracture initiation sites in the first pass of the weld. Figure 3 shows a cross section of the weld failure which contained a lack of penetration defect, forming a crack like defect in the ID of the weld. The cracking initially propagated in a brittle manner and changed to a ductile shear fracture as it approached the weld cap. There was no evidence of fatigue cracking on the fracture surfaces examined. The impact loads from the ship did not initiate cracking in the brace-to-stub weldment located +26 feet above water. Figures 4 and 5 show cross sections of the +26 foot brace-to-stub weldment. Note that the excessive root pass reinforcement in Figure 4 and the suck back in Figure 5 are defects with smooth contours which would be less likely to propagate as a result of impact. A comparison of the above water and the underwater weldments was also made to determine if there were any significant differences in the chemical composition or mechanical properties between the -36 ft and the +26 ft welds. The testing revealed that both welds had similar weld metal compositions suggesting that they had been welded with the same type of electrodes. The Charpy impact toughness of both weld metals were found to be satisfactory for this service.
Mechanical Creep and Fatigue Behaviour of a Resin-Assembled Steel T-Joint
Authors: Cao Y.M. , Jullien J.F. , Renault J.P. , Lazare F.
Published: October 2008

Elf-Aquitaine in association with Irete (resin manufacturer) and I.N.S.A. of Lyon (Research Institute) have developed a device, based on a resin assembly, designed to repair or reinforce fixed marine steel structures. This paper presents the results of the experimental validation of such a design.

Firstly, the mechanical behaviour of a resin assembled steel T-joint, under incremental static normal and bending loads, was evaluated in laboratory conditions. The selected design based upon the ring-shaped/chord-resin-brace sandwich construction resulted in an excellent behaviour mainly due to the low stress concentrations. Subsequently the creep and fatigue behaviour under normal loads only were tested on a similar T-joint between a chord and a brace.

The brace has a ring welded to its end which encircles the chord; the whole joint is then enclosed in a block of resin. The tests were carried out on specimens with the following dimensions 10" for the chord, 6" for the brace. The mechanical efficiency of the assembly was assessed by strain and displacement gauges.

The analysis of behaviour of the joint submitted to axial statical permanent loads and repetitive loads is presented.

The experimental results show that, for this new joint submitted to static permanent loads, it is necessary to consider the effect of the creep properties on its rigidity under tensile and compressive loads. It should also be noted that the fatigue properties of resin influence the behaviour and the rigidity of the T-joint under the repeated tensile and compressive load.

This steel-resin sandwich assembly is excellent for static and fatigue behaviour. Its efficiency is very dependent on the choice of the resin.

INTRODUCTION

The work reports on the results of creep and fatigue tests on a Resin Assembled Steel T-joint. The resin based assembly method was studied by the Swiss Resin Formula Company IRETE and the French Oil Company ELF Aquitaine, and several patent applications have been filed.

This joint has been design for the replacement or the reinforcement of a damaged structural member of a jacket type steel offshore structure. Following any type of incident, this added member, known as a brace, must be joined to the structure on site and below the water, and must involve minimum work and be the most economical solution possible.

The procedure involves the manufacture of a welded ring spacer which is fitted at each end of the new member. It is constructed in two parts and, for instance, can be assembled by bolting around the chord to be bridged on the site. This ring is dimensioned in such a way that it leaves an annular space, 3 cm for the case studied, around the chord. On site, after positioning the member and holding it temporarily in place, a simple shutter is built up around each assembly surrounding the ring and a portion of the chord and brace.
Main Pass 299 Sulphur Mine: Offshore Design in a Soil Subsidence Bowl
Authors: Camp J.J. , Langley W.E.
Published: October 2008

The structural configuration and design of the Main Pass Block 299 sulphur mine structures is described. These structures are subjected to significant settlement and severe soil movements caused by the extraction of the sulphur ore. The mine structures consist of 14 platforms connected by bridges and one "stand alone" platform.

All sulphur mine platforms are steel jacket structures similar to typical oil and gas structures in the Gulf of Mexico. However, two basic factors related to the sulphur mine operations make these structures different from oil and gas structures: gradual subsidence of the seafloor and a design service life of 40 years. The predicted soil movement induced stresses are so severe at several of the platform sites that 100 ksi yield strength steel has been specified for use in the piles and nonlinear analysis of the piles has been performed.

In addition to incorporating the predicted soil-induced movements of the piles in the design of the structures, platform decks and appurtenances such as boat landings and barge bumpers are designed to be elevated to compensate for the platforms' downward movement.

Bridges are designed to accommodate significant horizontal movements and differential support settlements created by the motion of interconnected platforms.

INTRODUCTION

The Main Pass Block 299 sulphur mine initial development consists of 15 platforms and 13 bridges located in water depths ranging from 208 ft. to214 ft. about 15 miles east of the Mississippi River Delta. Figure 1 is an artist's rendition of the mine development. A salt dome underlies most of the block, which is surrounded by oil and gas platforms. Within the caprock lies a layer of limestone which contains the sulphur ore. The sulphur lies approximately 1500 ft. below the seafloor and the deposit is about 150 ft. thick at its deepest point.

Nine of the 15 platforms will serve as bridge supports (three of which will also support helidecks). The other platforms include a Loading & Storage, Power Plant, Living Quarters & Warehouse, and two Production platforms. The stand-alone platform is the Facilities platform. Plans call for the present Production platforms to be relocated, as well as new ones installed in other areas of the mine, once the sulphur is exhausted in the initial mining regions. Several of the bridge support platforms and bridges are also designed to be relocated.

The Frasch mining process will be utilized to extract the sulphur. Water produced at the Power Plant platform and from brine wells located on Bridge Support 2 will be pumped to the Power Plant Module to be chemically treated and heated. Water will then be piped to the two Production platforms where it will be injected into the sulphur formation. Molten sulphur will be recovered at the Production platforms and pumped to the Storage platform. The sulphur is to be stored in two 90 ft. diameter by 40 ft. high tanks. The sulphur will finally be loaded into specially built double-hulled barges and taken to an onshore terminal near Port Sulphur, La.
TOGI Pull-In and Connection Systems
Authors: Bakken C.
Published: October 2008

A unique and prototype pull-in and connection system were developed for the TOGI project. The offshore pull-in of the 20" pipeline and service lines and cable were performed without any problems. The mechanical and electrical connections became more problematic than envisaged. Supplementary methods and equipment had to be developed during the offshore phase for some of the operations. The paper will present design characteristics and experiences during testing and operations.

INTRODUCTION

For pull-in and connections on the TOGI template the following tools were developed:Pull-in tool for 20" pipeline and service lines and cableConnection tool for horizontal hub connections of20" pipelineService lines to manifoldX-mas tree to manifoldPig module to manifoldElectrical bridge connection tool for connection of inductive connectors between cable termination and manifold.Control pod running tool for electrical connections between control pod and manifold. Fig 1 shows the pull-in and connection areas on the template.

The tools developed during the offshore phase for rectification work were:Honing tool for repair of 20" outboard hub.ROV operated brushing tool for 20" and 11" hubs.ROV operated brushing tool for electrical female receptacles.ROV operated inspection tool. The main parameters for the design and operation of the pull-in and connection systems have beenfirst end tie-in of pipeline and service lines and cableall modules on the Template to be independent retrievableall metal to metal seals to be replaceabledual electrical connections for each welldesign life of 18 yearsdiverless operations This paper is one in a series of six which are presented at the OTC 1991.

DESIGN OF PULL-IN AND CONNECTION TOOLS

Pull-in Tool

The pull-in tool system consists of:Pull-in Tool (PLT)Alignment Funnel/Lock Down structures being part of the TemplatePipeline/Service Line Termination

A common pull-in tool was developed for both 20" pipeline and the service lines and cable. Fig. 2 shows the main features of the tool.

The functional requirements of the tool are:Direct pull-in from lay barge for both 20" pipeline and service lines and cable.All tool operations shall be fully reversible at any point in the operation.The tool shall be able to lock itself down to the template.In case of hydraulic failure, the PLT shall be retrievable by means of ROV override.Pull-in angle of the pipeline shall be within +/- 4 degrees. Final alignment to achieve the connecting tolerances of +/- 0.25 degrees shall be performed by the Pull-in Tool.The hub shall feature a removable hydrostatic pressure cap which prevents flooding during pipeline laying.Flooding of the pipeline shall be from the laydown head at Oseberg prior to connection. The pressure shall be equalised over a pressure cap which shall remain fitted until making the 20" connection.To remove the pull-in head.The tool shall be deployed by the use of drill string and guidewire techniques.The pull-in force for pipeline is estimated to be 60 tonnes.
TOGI Service Lines and Cable Installation: Concept Selection and Field Experience
Authors: Meling J. , Sunde L.A.
Published: October 2008

This paper presents the concept for the TOGI service lines and cable bundle used to provide hydraulic and electric power and chemical injection fluid for the TOGI Subsea Station. The paper also presents the fabrication and installation methods used and some of the technical challenges experienced during the fabrication and installation phases. The paper includes descriptions of MSV "Regalia" used as the laying vessel and the water jetting system CAPJET 500 used for trenching.

INTRODUCTION

The TOGI service lines and cable bundle consists of three 34 mm ID duplex steel service, and one 75 mm OD electrical cable. The length of the service lines and cable bundle is 48km equal to the distance between the Subsea Station at Troll and the Oseberg Field Center. The waterdepth at the end points is 303m and llOm, respectively. See Fig. 1.

The four bundle elements were all prefabricated onshore in their full lengths and stored on three service line installation reels, and one carousel type basket for the cable.

During the summer of 1990 the TOGI service lines and cable bundle were successfully installed between the TOGI Subsea Station and the Oseberg Field Centre. The laying and later trenching of the three duplex service lines and the electrical cable marked the completion of four years period of engineering, fabrication and installation efforts, starting with the conceptual engineering in mid 1986 and ending up with the fabrication and installation contract which in spring 1989 were awarded to Ugland Coflexip A/S (UCAS), a joint venture between Ugland Offshore and Coflexip Norge. The work included new installation methods and equipment not earlier used in the offshore pipeline industry.

This paper is one in a series of six, which are presented at the OTC 1991.

TOGI CONTROL BUNDLE CONCEPT

The TOGI subsea wells are controled and monitored via a multiplexed electro-hydraulic system operated from the Oseberg A platform some 48 km away. The hydraulic supply and communication lines are gathered into a service line and cable bundle, consisting of three separate 34 mm ID duplex steel service lines and one 75 mm OD electrical cable, as shown in Fiq. 2. One of the service lines is used for chemical injection, and the other two for hydraulic pressure supply. The electrical power and signal cable consists of 12 pairs of conductor elements, where the control signals and power supply are transferred through common elements.

The bundle concept was established in the basic engineering phase of the project, and the following principles were adopted for the specification of service lines:One dedicated high pressure line (345 bar) for the surface controlled subsurface safety valves (SCSSV's) and one separate medium pressure line (207 bar) for the X-mas tree valve functions.One chemical injection feeder line with distribution chokes to each tree.No hydraulic fluid return lines.No spare lines, neither for the chemical injection nor the hydraulic system.
Transpacific Tow Oceanographic Criteria
Authors: Vermersch J.A.
Published: October 2008

Planning the Harmony and Heritage jacket tows from Korea to the Santa Barbara Channel required assessment of meteorological and oceanographic conditions. This paper describes the data bases and methodology used to determine the probabilities of exceeding specified wind speeds and seastates along various tow routes and at different times of year. The method considers the effects of both extratropical storms and tropical cyclones.

INTRODUCTION

Planning long, open-ocean tows requires knowledge of the expected ocean environment over the towing route. Transoceanic tows of jackets (or any structure) require knowledge of wind and wave conditions to specify an optimum tow route, tug requirements, allowable towing season, tiedown configuration, and any special structural modifications. Additionally, some rare, extreme target wind event must be chosen in order to determine barge stability requirements. Exxon recently towed two of the world's largest steel jackets, Harmony and Heritage, from Ulsan, Korea to the Santa Barbara Channel, California. This paper describes the development of tow wind and wave criteria for tows over various transpacific routes and during all seasons.

A common approach in the design of permanent, fixed structures is to specify the condition which has 0.01 probability of occurrence in a random year, the so-called "100-year return period" event. In a 20 year lifetime, the risk of the structure encountering this event is 1-(1-.01)20 - 0.18. Note that this is not the risk of structural failure, merely the risk of exceeding a given environment. Factors of safety are used in design to reduce the risk of failure by several orders of magnitude below 0.18. Shorter term operations such as exploration drilling, offshore construction or oceanic towing also require specification of some design environment, but here the frequency of occurrence of the selected design event varies considerably. Some operators choose to specify the 10 year return period storm, others prefer the 0.1 percent exceedence condition, and some specify a total risk of encounter over the duration of the operation. For long open-ocean tows, Exxon has historically selected the 5% tow risk seastate and the 1% tow risk wind speed as the tow criteria. It is not the intent of this paper to propose a risk management philosophy, but rather to present the methods by which these criteria were established for the Harmony and Heritage transpacific tows. This paper will first discuss the methods and results describing the extratropical environment, then the tropical cyclones, and finally present the combined, year-round wave and wind criteria.

TOW ROUTES

Initially, three routes were considered from Ulsan, Korea to the Santa Barbara Channel (Figure 1). The northernmost route is a great circle passing near the Aleutian Islands. The middle route is a rhumbline at about 34.5 degrees north, and the southernmost route, designated "southern", passes near Hawaii. The initial towing strategy was to avoid the peak typhoon season, approximately July-November, necessitating a winter tow.
Site Location Survey for the Heritage Platform
Authors: Siciliano R.J. , Nordin J.K. , Irick J.T. , Grundmeier B.L. , Taylor S.L.
Published: October 2008

This paper describes a geophysical and geotechnical site survey for the Heritage Platform to assess jacket levelness and water depth. Data were obtained from deep-tow seismic and cone penetrometer equipment which were positioned within the survey area through the use of an on-bottom network of medium frequency acoustic transponders. This allowed the high degree of seafloor mapping accuracy to be carried through to jacket placement. Upon set-down, the jacket was found to be well within the required levelness tolerance and in a water depth within one foot of the design specifications. This application demonstrates the accuracy with which the methods described in the paper can characterize the seafloor for engineering applications.

INTRODUCTION

The Heritage Platform was one of two jackets installed in 1989 as part of the Santa Ynez Unit Expansion Project. Harmony was installed in the Summer of that year in approximately 1200 feet of water. Heritage was installed in the Fall in about 1075 feet of water. The near surface soils in the vicinity of the Heritage location consist of a thin clay layer at the surface with thickness varying between 0 and 20 feet. This clay layer is commonly characterized as being seismically transparent since it is faintly recorded on high resolution sub-bottom profiler records. Immediately below the clay is a stratum of dense sand. This uppermost sand stratum extends to a depth of about 90 feet. Below that penetration, layers of stiff clay and silty clay, ten to twenty feet thick, alternate with other sand strata several tens of feet thick (1).

The top surface of the uppermost sand layer is cut by numerous channels formed by ancient turbidity flows. The thickness of the surficial clay varies with the presence or absence of these channels; being thin over high areas such as channel levees or interchannel highs and thicker where channels are present. The seafloor and the top surface of the sand slope to the southwest with a gradient of about 1 to 2 percent.

The bottom framing of the Heritage jacket was designed to match the slope of the seafloor as determined from regional bathymetry and sub-bottom profiler data obtained in the early 1980's. The mudmats were sized to penetrate through the soft surficial clay and bear on top of the dense sand just below. These early surveys indicated that the thickness of the clay and the seafloor slope were fairly constant over the area selected for jacket placement.

However, a detailed review of data from soil borings performed in 1984 and drop cores from a pipeline survey in 1988 indicated that the clay thickness was considerably more variable than originally thought. More variability in the clay layer thickness implied a more irregular bearing sand surface. This suggested the possibility that the jacket could exceed the levelness tolerance by as much as 1.4 degrees upon set-down on the seafloor. Correcting levelness after set-down would have been difficult because of the size of the jacket and stiffness of the sand layer.
Newest Experiences on Shielded Metal Arc Welding of Grade X-80 Pipes
Authors: Dittrich S.
Published: October 2008

A significant part of the future gas pipelines in Alaska and Canada will probably be constructed by using the new ultra high tensile steel X 80. This will be the first time that pipe materials of such high strength have to be welded under field conditions in a major project. The Arctic environment conditions will additionally be another challenge. This paper deals first with the weldability of the pipe material in conjunction with the use of cellulose and low hydrogen electrodes. Furthermore, all relevant welding procedures and combinations are discussed including vertical-up and vertical-down welding. The electrodes designed for these purposes are ready for use and proved by various test procedures. The actual results will be reported in this paper. The field welding experiences with low hydrogen downhill electrodes refer to a 2 mile demonstration line which has been constructed in South Germany in 1985.

Introduction

The transportation of gas over very long distances is the more efficient, the more of the original gas pressure can be maintained. This requires, at least for the first part of such lines, pipe materials with a higher yield and tensile strength than given by the present conventional API steel grades X 65 or X 70. The necessary steel development was taken up in the early eightees by several manufacturers in the world and can in the meantime be regarded as completed. The result of this development was the new line pipe steel X 80 with a minimum yield strength of 80 KSI and a minimum tensile strength of 90 KSI.

The first major use of X 80 is intended for the construction of the Yukon Pacific gas Line in Alaska as well as for the new Transit Gas Lines from the Yamal Peninsula in North Siberia to East and Central Europe. Besides these, several shorter X 80 lines are in planning to connect West and East Germany.

Weldability of X 80 Pipes

The question of weldability is mainly relevant for the optional use of cellulose electrodes which are generally characterized by a very high hydrogen input. From all field welding experiences gained so far it is wellknown that the most important objective is to guarantee a crackfree heat effected zone in the root pass area. This area is the most sensitive one because of the additional notch effect from inside of the pipe and the effect of pipe movements before the hot pass is fully completed. These two effects can result in the formation of root cracks, if the Carbon equivalent of the pipe material is too high or the preheating temperature too low.

Since the increased yield and tensile strength of the new steel X 80 is achieved only by a subsequent accelerated cooling after the thermo-mechanically controlled rolling process and not by a correspondingly increased Carbon equivalent, the weldability of this steel is on the same level as the thermo-mechanically treated steel X 70 which has in the meantime successfully been welded for more than 20 years.
The Brage Platform: A New Generation of Gravity-Base Structures
Authors: Helland K. , Kvalstad T.J. , Karlsen V. , Fjeld S. , Hermstad J.M.
Published: October 2008

This paper describes the main features of the concrete gravity base platform designed for the Brage field in the Northern North Sea. This design concept encompasses several new design features. The traditional caisson is not used and the necessary strength and stiffness is provided by the base slab and skirts. The well conductors are guided outside the towers which are slimmer than previous concrete platforms. The global wave forces are thus reduced and the foundation can be simplified.

The platform can be installed over predrilled wells. Necessary skirt penetration is achieved and the soil strength improved by the application of suction under the skirts.

The paper describes the platform and the investigations conducted to substantiate its feasibility. It is shown that the large caisson, normally a prime element of gravity base structures, can be deleted for multishaft platforms and soft soil. Buoyancy in floating phases during construction is achieved by compressed air under the skirts. Main dimensions of the platform are governed by requirements of floatability during offshore tow and dynamic behaviour in operation rather than strength in operation. Thus a reduction in material quantities and construction time of about 40% is achieved. Towout without a heavy topside load is necessary to take full advantage of the platform concept.

INTRODUCTION

The majority of offshore concrete gravity structures has been of the so called caisson and tower type. This concept is composed of a deck supported by a number of towers projecting from a voluminous caisson. The caisson is a closed box with an upper and a lower level slab or assembly of domes. It is subdivided in cells by straight (Sea Tank, Andoc) or circular (Condeep) partition walls.

The caisson is used to serve three or four purposes:Act as structural element of adequate strength and stiffness to absorb the tower bending moments with acceptable deformations. The top and bottom slabs act as beam flanges and the partition walls as webs.Act as a foundation which transfers the functional and environmental forces on the platform to the subsoil with adequate safety. On soft soils the caisson will be fitted with skirts which penetrate down to soil layers of adequate bearing capacity.Act as a buoyancy volume in the temporary phases of floating construction, transportation and installation. Towout with the topsides installed is thereby possible.In many cases the caisson is used for temporary crude storage. Recent platforms in very soft soil e.g. Gullfaks C, have been fitted with very deep skirts, i.e. more than 20 m. Other platforms have been designed to obtain the necessary buoyancy from the volume of the towers alone, independent of the caisson. New offshore cranes of huge capacity can now be used to install the topsides and inshore deck mating is not a major asset.

For Norsk Hydro's 136 m deep Brage field in the Northern North Sea, several platform designs of traditional tower and caisson type were conceived.
Analysis of the Spar Floating Drilling Production and Storage Structure
Authors: Glanville R.S. , Paulling J.R. , Halkyard J.E. , Lehtinen T.J.
Published: October 2008

The Spar is a deep-draft floating steel caisson, which can be designed to drill, produce and store oil. It is very stable and relatively insensitive to deck loads. Drilling and production equipment are supported on the decks above the waterline. Oil may stored in the lower portion of the hull. The centerwell protects drilling and production risers down to 650 feet. The Spar can be moored with conventional or taut catenary mooring lines using embedment or pile anchors. Because of its deep draft and large displacement mooring line dynamic loads are relatively low. Fabrication and installation plans together with cost estimates are included for a 36-well design for Chevron in the Gulf of Mexico. Predicted motions under normal and maximum sea states are shown together with the results of global motion analysis using both frequency and time domain programs. The sensitivity of the design to mooring parameters, draft, diameter and Spar mass properties is discussed. Potential applications are briefly reviewed.

INTRODUCTION

The concept of a Spar (a slender vertical structure) stable floating ocean platform has been recognized for years. The Flip Ship (Fisher and Spiess, 1963) was built in 1962 as a stable platform for oceanographic measurements. Its favorable motion properties are well documented (Rudnick 1964, 1967, 1971). The potential for use of the Spar in the offshore industry was recognized in the 1970s with the construction of Shell's Brent Spar for oil storage and offloading in the North Sea. Other potential uses and the salient motion properties were discussed by van Santaan and deWerk (1976). Research on the Spar as a storage and/or production vessel was carried out by some oil companies in the mid 1970s, however additional use of the Spar concept did not materialize. It has again recently been proposed as a low cost production facility for remote subsea well sites (Kerckhoff and Pijfers, 1989).

This paper describes a full drilling and production Spar designed for a 2,700 foot water depth in the Gulf of Mexico. Oil storage is not a requirement for this site, but could be a major advantage of the Spar for remote areas of the world. The proposed Spar is an order of magnitude larger (in displacement) than the Brent or Flip designs, however, it retains the stability and simplicity intrinsic to the concept.

SPAR CONCEPT

The Spar is a large, deep draft, cylindrical, floating platform (Figure 1) designed to support drilling and production equipment and to store oil. It is permanently moored with multipoint catenary anchor lines over a multiwell seafloor template. Wells can be drilled and completed with the BOP stack either on the surface or on the seafloor. Risers are held in tension by hydraulic tensioners or by buoyancy modules (Figure 2).

The most obvious features of the Spar are its extreme draft, straight sides, large centerwell, and large displacement (Figure 1).
Rig-Automated Drilling: A New Concept Is Being Proven
Authors: Houston S.J.
Published: October 2008

1. ABSTRACT

Major advances are being made in the reduction of overal1 platform weight and, hence, overall cost. A principle aim of the project has been the reduction of the number of men from this potentially dangerous work area. One result from the '86' price drop was the coming together of Strachan & Henshaw Ltd. (S&H) in collaboration with four oil companies, three British and one Norwegian with support from the UK Government and European Community to look at reducing considerably the cost of development drilling. The RA-D project which started 4½ years ago ends in late 1991 with 'spudding' (FIG. 1) of the first hole, to initiate the proving tests of the powerful but compact light-weight offshore derrick and pipehandling system. Based on fast handling of single tubulars from 3½" to 20" diameter and rated to 20,000 ft. depths with a 1,000,000 lbs hook load the system is aimed at meeting the requirements of the North Sea and Worldwide.

2. INTRODUCTION

The RA-D concept was conceived during an exploratory visit by S&H engineers a few years ago, to the North Cormorant offshore platform whilst looking for ways in which the company's handling capability could be applied offshore. An investigation into the automation of drilling followed after a serious paralyzing accident to a floorman when handling drill collars which was just one of the many hazardous jobs in drilling and indeed the oil industry.

Drilling rig automation is a long held ambition of many offshore Operators. A number of automated drilling projects have been undertaken around the world as a result of the drilling industry's great interest in automation. Drillers see automation offering them smaller, lighter rigs with lower manning levels which will reduce the risks of injury and at the same time, reduce platform size and cost. Drilling rig designers see that automated rigs are now more feasible as a result of better and more reliable components available from other allied industries. There have been significant improvements in the elements of automated drilling systems, from the sensors and computers needed to control them, to the automatic torque wrenches and power swivels which manipulate the drill string coupled with the versatility of automated pipe handling systems.

However 'progress' results from a desire of man to improve what he has but unfortunately the changes that 'progress' requires are not always readily accepted by him.

The 'Cullen' report makes 106 recommendations relating to safety management, design and equipment, planning and provision for emergencies, Whilst not addressing drilling specifically, there was a very clear message that industry must develop equipment which is reliable and reduces manning on the platform, Each Operator will be required with its contractors to provide a safety case demonstrating that the safety management system of the design build and operation of the installation and equipments are as safe as reasonably possible.

S&H came into the rig design business from a non-oil industry background.
Installing a Flowline Using a Snubbing Unit
Authors: Baugus V.E.
Published: October 2008

A flowline for a subsea well was installed from a platform. The flowline was composed of a 100 foot long flexible pipe jumper and integral joint oil well tubing. A snubbing unit was used to make the tubing connections while an anchored boat pulled the pipe through a J-tube.

INTRODUCTION

In late 1989 a third exploratory well was drilled on East High Island block A-370. This well, in 371 feet of water, encountered Enough reserves to justify a subsea completion but not a platform. A key part of this development was the flowline which would connect the subsea tree to the existing "A" platform about a mile away. This paper discusses the design and installation of that flowline.

BACKGROUND

During the planning phase of the project it was determined that there was a J-tube on the platform which was empty. This J-tube was pointed within 8 or 9 degrees of straight at the subsea wellhead. There wasn't any equipment on the production deck that would interfere with access to the top of the J-tube and a compressor on the drilling deck was surplus and could be moved. This situation presented an opportunity to reduce costs by installing the flowline from the platform instead of using a pipe lay barge.

The idea of assembling the flowline on the platform grew out of past experience with putting in sub sea vent lines using a reverse J-tube method. This earlier work was loosely based on an Exxon patent1, since expired. The vent lines were assembled at the boat dock level of the platform using 6" Sch. 80 pipe, a slip bowl, alignment clamps and welding. The pipe invariably had to be restrained from "running away" down the J-tube until several hundred feet were pushed out onto the ocean floor.

The significant differences for the flowline were the smaller size, at 3½ inches OD; the greater length, at 5600 feet; the higher pressure rating, at 3500 psig; and the need for greater accuracy at the destination.

DESIGN

Threaded Joints

Because of the time required to weld and x-ray high strength or heavy wall pipe, the use of threaded connections was investigated as a cost effective alternative.

One result of choosing platform assembly of the flowline is the requirement that the pipe be fed down through the J-tube in a reverse pull. This means that virtually the entire flowline must traverse the curve at the bottom of the J-tube without damage. The radius of this curve is 100 feet. While welded flowlines are often pulled through J-tubes, threaded joints are not usually subjected to this kind of treatment. In order to obtain the highest possible joint strength, an early decision was made to investigate the various premium oil well tubing threads. It was felt that the special thread profiles and metal to metal seals offered by some of these joints might provide a reasonable solution to the bending problem.