bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of Ripple Load on the Stress-Corrosion Cracking in Structural Steels
Authors: Pao P.S. , Bayles R.A. , Yoder G.R.
Published: October 2008

The presence of small ripple loading can, under certain circumstances, significantly reduce time-to failure and threshold stress intensity for stress-corrosion cracking (SCC) of steels. A predictive framework for such ripple-loading effects (RLE) is developed from concepts and descriptors used in SCC and corrosion fatigue characterization. The proposed framework is capable of defining critical conditions required for the occurrence of RLE and predicting time-to-failure curves. The agreement between the predicted and laboratory data is excellent.

INTRODUCTION

Stress-corrosion cracking (SCC) is a cracking process caused by the conjoint action of stress and a corrodent. Conceptually, SCC will occur if a sensitive material is exposed to a corrosive environment under sufficient stress for a sufficient length of time. For a structural material which contains a crack or crack-like defect, the resistance to SCC is normally evaluated in terms of the fracture mechanics parameter, KIlscc the threshold stress-intensity factor below which fracture will not occur. The measurement of KIlscc and its application to design of structures for the marine environment commonly presumes sustained or constant load conditions. Applications in the real world, however - including many in offshore platform structures, rarely involve an absolutely constant load condition, but are far more apt to involve the superposition of relatively small amplitude load perturbations or "ripple load". Recent work [1-4] has demonstrated that under such ripple- Ioading conditions, fracture can occur in some cases at stress-intensity levels much less than KIlscc. Thus, the implications of the ripple-load effect (RLE) may be quite serious. An extensive literature survey on ripple-load effects was recently prepared, which cited several examples from both low- and high-strength and ferrous and nonferrous alloy systems [5].

The objective of this paper is to develop the understanding of the RLE and the framework required for the prediction of the RLE. First of all, RLE is investigated in two different classes of steels: the medium strength, high toughness 5Ni-Cr-Mo-V steel and the high strength, low toughness AISI 4340 steel. Secondly, the critical conditions required for a material to exhibit RLE in the marine environment are defined and quantitative prediction of the maximum extent of degradation by the RLE is presented. And finally, the quantitative predictive methodology for time-to-failure curves associated with the ripple-load cracking is offered for a given combination of material and loading conditions.

MATERIALS AND EXPERIMENTAL PROCEDURES

Two steels studied in this investigation are 5Ni- Cr-Mo-V and AH 4340 rolled plate materials. Results of chemical analysis and tensile properties are given in Tables 1 and 2, respectively. Time-to-failure data under SCC and RLE conditions were determined using precracked cantilever-beam specimens.
Deep Sea Mining Technology: Recent Developments and Future Projects
Authors: Bath A.R.
Published: October 2008

During the late 1970s pilot mining tests carried out on manganese nodules in the Pacific and metalliferous mud in the Red Sea demonstrated the technical feasibility of deep sea mining operations. However, the production of manganese nodules on a commercial scale is subject to numerous technical problems. As a result a German/French joint development project has been underway since 1985 into the following key points; nodule pick-up device, locomotion of self propelled collectors, hydraulic lifting of nodules. This paper presents the scope of this R+D program, its main results to date and future prospects.

INTRODUCTION

Ten years ago deep sea mining, i.e. the production of ore-bearing minerals from the deep sea was at a zenith and enjoyed a large amount of interest worldwide. Spring 1978 saw the first continuous pilot scale production of manganese nodules from the floor of the Pacific ocean (OMI Pilot Mining Test) and May 1979 saw the first production of metalliferous sediments from the floor of the Red Sea (Saudi Sudanese Red Sea Commission, Preussag, Pre Pilot Mining Test)..

We now know that these forecasts were incorrect. The start of commercial deep sea mining has moved further away for a number of reasons of which price development in the metal market was undoubtedly one of the more important. This does not mean that development of deep sea mining technologies has ground to a complete standstill. On the contrary; the number of countries in which corresponding research is underway has increased. The USA, Japan, France and Germany have been joined by the USSR, India and Finland. For some years now development work in Germany has concentrated on the development and optimization of critical components and subsystems of deep sea mining techniques, whereby the demand for environmentally non-disruptive production methods has increasingly been taken into account. The following report concentrates on this work where by manganese nodule production technologies represent the major focus.

There follows a brief review of the pilot mining tests executed in the late seventies as an outline of the scope of work.

BRIEF REVIEW OF PILOT OPERATIONS

The first successful pilot mining test on manganese nodules was carried out in 1978 by OMI (Ocean Management Inc.) in which 800 tonnes of nodules were recovered from the floor of the Pacific ocean.

This was a joint venture involving American, Japanese, Canadian and German companies (Fig. 1).

The mining system comprised:the converted drill ship. SEDCO 445a 5500 m long pipe stringa towed collector

Two types of hydraulic lifting systems were tested successfully:an air lift systema pump lift system (multistage mixed flow pumps)

Two different nodule collector concepts were tested (Fig. 2):hydraulicmechanical

The overall system design had a mining rate of around 30 t/h.
MWD VSP and Checkshot Surveys Using the Drill Bit as a Downhole Energy Source
Authors: Rector J.W. , Marion B.P.
Published: October 2008

Vertical Seismic Profiling (VSP) has been used over the past decade to provide seismic images near a wellbore and to make time-to-depth calibrations of surface seismic data. A new wellbore seismic technique, the TOMEX® Survey, uses the vibrations produced by a drill bit while drilling as a downhole seismic energy source to produce VSP data. No downhole instrumentation is required to acquire the data, and the data recording does not interfere with the drilling process. Hence, there is no loss of rig time and MWD (measurement-while-drilling) borehole seismic data is acquired. Rig time savings are particularly important on offshore wells where the daily cost of rig time can be very high. The continuous signals generated by the drill bit during drilling are monitored with a reference sensor attached to the top of the drillstring. The reference sensor signals are processed in combination with the signals from receivers placed at or near the earth's surface to produce VSP data. In a marine environment, sensors are deployed on the ocean bottom. Results from a land test well demonstrate that the processed drill-bit source data are virtually identical to conventional VSP data. Offshore tests demonstrate that drill-bit VSP data quality offshore is superior to that on land.

INTRODUCTION

Vertical Seismic Profiling (VSP) consists of recording seismic data using a surface energy source and a receiver lowered by a wireline into a borehole. VSP surveys are used like checkshot surveys to convert surface seismic sections to depth. They are also used to estimate formation interval velocities. The reflected energy recorded in VSP surveys are used to image formations near the wellbore and to predict formations yet to be encountered by the drill bit. One disadvantage of VSP is that the drilling activity must cease while the data are being recorded.

The TOMEX Survey, or drill-bit VSP, uses the natural vibrations created by the drill bit during the drilling of a well as a downhole energy source. No downhole instrumentation is required, so there is no lost rig time and, complications of open-hole wireline operations are avoided. Offshore, the savings in rig time achieved by a drill-bit VSP versus conventional VSP is often greater than the cost of the entire survey.

Ideally, an explorationist wants the information obtained with a VSP to be available while the well is being drilled, because the ability to locate the seismic target with respect to the current drill-bit position could enormously reduce drilling expenditures. However, prior to acquiring the VSP, the driller must trip out of the hole, and in many cases, a wiper run must be performed to condition the borehole walls. This drilling inactivity period can be rather long. Hence, VSPs are usually performed during the final logging run, after it is too late to affect the drilling plan. By contrast, drill-bit VSP data are acquired and processed as drilling proceeds.
Emerging Technology in Borehole Geophysics With Multiple Applications in Drilling, Production, Exploration, and Enhanced Oil Recovery
Authors: Kfaveness A.
Published: October 2008

In this study, it is demonstrated that sonic pulses of sufficient strength and suitable frequencies can be emitted from a borehole energy source concurrently while drilling oil and gas wells and that these pulses can be used to scan or "look ahead" of the drill bit to determine the character and the structural conditions of the materials to be drilled. Additionally, such pulses can be used to provide continuous inverse three dimensional 96 trace Vertical Seismic Profiles (VSP) to map the geology immediately surrounding the borehole to distances of 6000 feet or more (faults, reefs, salt overhangs, etc.).

INTRODUCTION

Recent developments in borehole geophysics can reduce the hazards and improve the chances for success when drilling for oil and gas. Seismic Telemetry Logging uses sonic pulses and seismic techniques to scan or "look ahead" of the drill bit to determine the character and the structural conditions of the materials to be drilled. Fracture prone formations and over pressured gas zones can be detected before they are penetrated by the bit, thus permitting mud weights to be altered in sufficient time to prevent lost circulation and dangerous blowouts. Additionally, the degree of compaction, the dipping attitude of the bedding and the position of formations below the borehole are determined so that drilling programs may be optimized and good casing seats can be established.

The same sonic pulses monitor the position of the drill bit and may therefore be used to detect deviations from a true vertical drilling path (crooked holes) and guide directional wells to planned objectives.

Also, precise measurements are made of sonic transit times in materials drilled, thus providing a continuous velocity log, density log and porosity log as the drilling progresses. Productive horizons associated with nearby faults, reefs, salt intrusions and porous sand bodies are mapped, hence the drill can be deflected into them at the best possible position.. Sometimes such reservoirs are barely penetrated or missed entirely, resulting in large and possibly unnecessary expenditures for marginal wells or dry holes.

It is significant to note that this information is obtained without lowering wire lines or measuring devices into the well and that it is done without interrupting or interfering with the drilling operations. Sonic telemetry procedures are used to transmit the data to the surface in less than 30 seconds. The results are, therefore, available immediately on the rig floor where they may be used to alter or optimize the drilling program.

In conventional well logging it is customary to stop the drilling and remove the drill string and the drill bit from the borehole while the logging is in progress. This is not necessary with the new method. Here the log is obtained while the drilling continues.
The Bullwinkle Project: An Overview
Authors: Sterling G.H. , Krebs J.E. , Dunn F.P.
Published: October 2008

The Bullwinkle platform is located in Green Canyon area, Gulf of Mexico in 1353 feet of water. It is the largest steel offshore platform in the world, located in the deepest water and is taller than the world's highest building.

The platform took five years to design, build and install. Seventy-five thousand tons of steel were used to build this structure, of which 49,000 tons were in the jacket, 13,000 in the conductors, 11,000 in the piling and 2,000 in the deck.

This paper discusses the planning, phased bid/award and schedule control and gives a broad overview of the building and installation process. Several companion. Papers (1-11), give specific details of the platform design and construction.

INTRODUCTION

In May 1983, Shell Offshore Inc. (SOl) acquired Blocks 65 and 109, Green Canyon area, for a lease bonus of $30.1MM. In April 1984, Block 64 was acquired for an additional $4.4MM. The leases on all three blocks are 100% owned by SOl. This prospect area (Fig. 1) was code named Bullwinkle by SOl's explorationists, a name that continued throughout development.

The discovery well was drilled in October 1983 on Green Canyon Block 65. A total of four wells and four sidetracks were drilled in the three blocks to evaluate and delineate the reservoirs. Evaluation of development alternatives had been underway concurrent with field exploration, and in June 1985 construction of a platform was begun in accordance with the schedule shown in Fig. 2. Platform installation was completed in late September 1988. The basic characteristics of the platform are described in detail in companion papers (1-11), but Fig. 3 provides some basic information on forces, weights and dimensions.

Development drilling is presently underway, with initial production scheduled to begin in 1989 while drilling continues. Oil production is expected to peak at 50,000 barrels per day, with natural gas production reaching 90 million cubic feet per day in 1992.

The Bu11wink1e project will cost about $500MM excluding lease bonus costs. About 50% of the project costs was spent to build and install the platform. The other 50% will be spent for development drilling, permanent production facilities and a pipeline system.

PLANNING

Various concepts for field development received consideration during the early engineering efforts. These included (i) two fixed platforms, each With 24 well slots; (ii) one fixed platform with 50 slots; (iii) a compliant tower. Based on in-house estimates of project costs the single fixed platform, with capability to handle two drilling rigs and 60 wells, was chosen. The project schedule noted in Fig. 2 was developed with an early June 1988 target date for launch. That launch time was chosen to avoid the spring weather, and to allow sufficient time for offshore work before the major part of the hurricane season. Figure 4 dramatically shows the statistical .significance of working offshore early in the hurricane season.
High Ni Alloy (Type 825) Clad Pipe Manufactured by UOE Process
Authors: Tsuji M. , Kobayashi Y. , Suga M. , Urne K. , Torna H. , toh M.
Published: October 2008

About 3000 tons of 42%Ni alloy clad X65 UOE pipes were manufactured by two manufacturing processes; application of TMCP to clad plate rolling without pipe heat treatment and as-quenching type heat treatment on the clad pipe. In both processes, use of low carbon materials as clad metal and backing steel achieved high corrosion resistance and good mechanical properties.

INTRODUCTION

As development of oil or natural gas in deep sour well have been active in recent years, the use of corrosion resistant alloy line pipes is increasing. Duplex stainless steel pipe is successfully used for the transportation of corrosive liquid containing CO2-Cl in the North Sea1), Alaska2) and outlier places. Coping with the demands for corrosion resistant alloy pipes, manufacturing procedures and properties of five kinds of corrosion resistant alloy solid pipes were standardized as API Spec. 5LC in 1988. Transportation of oil and gases containing H2S requires use of high Ni alloy pipe from the aspect of corrosion resistance. However low yield strength of the high Ni alloys increases wall thickness of solid alloy pipes, which results in a large increase of material cost. Therefore, high Ni alloy clad pipe, which consists of the inner layer of high Ni alloy and the backing layer of high strength carbon steel, deserves much attention because of its economical configuration.

Under the circumstances mentioned above, manufacturing technologies of internal clad pipe have been developed through the UOE process using high Ni alloy clad plate rolled in integrated processes. The girth welding and induction hot-bending technologies have been also established. Using those manufacturing technologies, about 3000 tons of 42%Ni alloy-clad X65 pipe for submarine pipeline were recently produced.

In the present paper are introduced the corrosion resistance of 42%Ni alloy, manufacturing technologies and production results of the pipe. Test results of the girth welding and the induction hot-bending of the clad pipe are also described.

CORROSION RESISTANCE OF 42%NI ALLOY

High CO2 contents in aqueous liquids cause rapid weight loss type corrosion and the corrosion loss is increased as service temperature is high. The Cr content of the alloy is essential to improve the corrosion resistance in CO2 or CO2-Cl environments. Therefore, l3%Cr martensite stainless steel and 22%Cr or 25%Cr duplex stainless steel will be selected for use in such environment. The duplex stainless steel can be used for higher temperature service because of their higher Cr content.

The presence of H2S causes sulfide stress corrosion cracking in martensite stainless steel and duplex stainless steel. Another effect of H2S is to exacerbate chloride stress corrosion cracking (SCC) at high temperatures. On the contrary, high Ni alloys are generally characterized by good corrosion resistance in non-oxidizing acids and SCC resistance in Cl containing solutions at high temperatures.
The Oseberg Reservoir Management Planning: A Case History From the Oseberg Field
Authors: Torvund T.
Published: October 2008

The Norwegian Oseberg Field came on stream in December 1988. The reserve estimate for the field is currently 209 million Sm3 (3.31 billion stb) of oil and 92 billion Sm3 (3.25 TScf) of gas.

The reservoir management planning prior to production start up has focused on optimizing the original production plan for the Oseberg reservoirs and investigate dynamically key elements in the plan in several long-term reservoir tests.

This paper demonstrates reservoir management as a key element in the process of optimization of offshore developments and the importance of having some flexibility in the development plan to accommodate new knowledge and new technology.

INTRODUCTION

The main factors influencing an offshore field's profitability is the geology and reservoir conditions, the development solution and the oil price. While the price remains uncertain throughout the life of the field, the development solution is traditionally decided while there still is much uncertainty as to the interpretation of how the reservoir will behave during production.

Important reservoir aspects are at this stage inferred from extrapolation of static data obtained during drilling, short drill-stem tests and from geological and geophysical work. More accurate knowledge of reservoir behavior is typically obtained after regular production has started, when dynamic reservoir information is being gained.

In such a situation where much uncertainty exists it is important to give the development solution flexibility for possible adjustments to cost-effective improvements. It is equally important to actively search for new information about the reservoir that may lead to improvements in the plan and in the production operations.

The Oseberg Field is a major oil field located in the Norwegian part of the North Sea. The field was discovered in 1979. The Field Development Plan of the Oseberg Field was decided in the end of 1983. From then and until the production start-up in December 1988, the Plan has seen two significant modifications which both have originated from the process of optimizing the reservoir management of the field.The production mechanism of one of the major structures has been altered from water injection to gas injection to increase recovery. This has been made possible by import of unprocessed gas from the giant Troll East Field.The average production capacity from the field has increased from 204.000 to 340.000 stb/d.

In addition, a long-term reservoir test has taken place, which not only has provided valuable dynamic information about the reservoir prior to regular production, but also given income to the Oseberg owners.

This paper will give an outline of the reservoir management planning process for Oseberg. The background for and the consequences to reservoir management by the improvements to the development plan and by the long term-reservoir test will be presented
Operational Limitations of Offshore Crane Vessels
Authors: Clauss G.F. , Riekert T.
Published: October 2008

The paper analyzes the limiting conditions of crane vessel operations with special emphasis on large semisubmersibles. As reference structures a barge with 500 t crane capacity, a ship with 1,800 t capacity and a semisubmersible with two revolving 6,000 t cranes, are investigated. Model tests in irregular seas and specific wave groups demonstrate the significance of coupled resonance motions of vessel and suspended load for crane operations with semisubmersibles. 'With barges and ships resonance is of minor in1.portance due to high damping.

The mass of the suspended load and the sling length are decisive parameters for the motion characteristics of crane vessels. The transfer function of the vertical load motion, which is selected as limiting quantity, has been determined experimentally for each of the three vessels. Depending on this parameter and the maximum allowable load motion the limiting wave heights for crane vessel operations are compiled.

INTRODUCTION

Offshore oil production in deeper and more hostile locations of the North Sea will require an investment of $15 to $20 for each barrel of future oil output. Consequently, the crude oil price collapse in 1986 - taking the value of a barrel of Brent oil down to $10 - stopped most industrial developments. The challenge, however, also provoked new ideas and concepts like floating production systems, compliant structures and light-weight platforms. A major incentive for economic field developments was the advent of giant crane vessels. With maximum load capacities of up to 14,000 tollS complete jackets, topsides, foundations, templates etc. can bc installed or removed, mostly by tandem crane operations. Installation costs are reduced up to 40 percent as the saving on steel for "slimline" jackets amounts to 20 perccnt in relation to the conventional launching method. Even greater stec1 weight savings - up to 40 percent - are being made by constructing an integrated deck rather than building a series of modules in individual shipyards [1-8]. further, offshore work requirements - costing five times more than for the same work onshore - are reduced considerably, testing and commissioning of platform decks is accomplished onshore and weather window limitations are less significant. Based on data of 2nd, 3rd and 4th-Generation North Sea platforms Vugts [9] estimates substantial cost savings by favouring an installation by crane vessc1 above traditional launching (Fig. 1).

Fig. 2 presents some data of semisubmersible crane vessels (SSCV), ships or barges [10]. N'ote the dramatic increase of lifting capacity. Amazingly just the load sensitive scmisubmersibles made thc running. Of course, thcir excellent motion behaviour in the seaway is a major advantage and sheer size with options for two cranes of large load capacity, outreach and lifting height combined with a flexible ballasting system outmatches other concepts in delicate offshore lifting operations.
Multibeam Swath Surveying: A New Opportunity
Authors: Bennett J.D.
Published: October 2008

The recent development of a new generation of shallow and deep water multi-beam echo sounders will enhance exploration and production in water depths up to and beyond 1000 meters.

They will also enable many established and developing countries to assess and develop resources contained within their Exclusive Economic Zone's (EEZ's), both on the continental shelf and to full ocean depth.

Multi-beam echo sounders are set to revolutionize the world of ocean charting. Instead of collecting sparse amounts of data in single lines of soundings, by utilizing a multi-beam sonar, large areas of seabed can be surveyed equivalent to a swath of twice the water depth, with a contoured chart being available in real time. Several sonars are available on the market, all of which significantly reduce the ship time required to conduct seabed charting, whilst at the same time contributing to an overall increase in the quality of the final chart.

This paper identifies the potential in the fitment of such a sonar to an ocean going ship to chart specific exploration areas or the recently created EEZ's and also in the provision of a complete Hydrographic and oceanographic service which will be available to the Commercial and Research communities.

1 INTRODUCTION

Deep water oil and gas exploration is a growing area as shallow water sedimentary basins become exhausted and oil companies turn to deep waters. Having located oil and gas for production, further surveys are required to enable the laying of deep water installations and pipelines.

Any exploration work requires cood seabed charting and swath sonars are able to chart large areas of the seabed, both on the continental shelf and at full ocean depth, in a cost effective manner.

As we develop the capability to work in deeper waters, the exploration and exploitation of Exclusive Economic Zones (EEZ's) becomes more feasible. The United Nations Convention on the Law of the Sea in 1982 defined certain exclusive rights of coastal States, out to 200 miles or more from their coastlines.

During the next decade and into the early part of the 21st Century, the need for reliable surveys of the EEZ'swill increase rapidly as countries seek to exploit the diverse range of living, mineral and energy giving resources contained within them. The importance of well planned, efficient, effective and environmentally sympathetic development of these EEZ' s must not be underestimated. EEZ 's cover almost 40% of the Seas and Oceans; they are crucial for the survival of mankind and we must avoid polluting and destroying their sensitive ecosystems in the current search for relatively short term material gains. Thus, to be able to plan, manage and police the necessary activities in EEZ waters, high quality governments as being the first requirement.
A Procedure To Evaluate Pile Drivability in the Difficult Soil Conditions of the Southern Part of the Gulf of Guinea
Authors: Puech A. , Poulet D. , Boisard P.
Published: October 2008

This paper presents a method for evaluating the soil resistance to driving in the hard clays, very dense sands and rock strata encountered offshore Angola. The method is calibrated on typical case histories where 48" O.D. platform piles and 30" .D. conductor pipes were instrumented during driving. Results are applicable on most of the oil fields located in the southern part of the continental shelf of the Gulf of Guinea.

INTRODUCTION

The Gulf of Guinea is a zone of intense oil field developments. In the southern part of the Gulf, i.e. roughly south of the equator line, the continental shelf consists of a narrow band (50 to 100km wide) extending from Cap Lopez (Gabon) to Moss Medes (Angola) (Fig. 1). The water depth increases gently from 20 to 200m from east to west then dips suddenly to 1000m. The zone is characterized by a common geological history. The submarine canyon of the Congo river is the only outstanding topographic accident.

In the past few years, several oil companies had to face serious platform installation problems due to major difficulties encountered during pile driving operations. Three types of problems have been identified:development of strong set-up effects in hard clays during add-on welding,premature refusal of piles in very dense sands,collapse of pile toes on limestone layers.

The paper addresses these different topics and presents a procedure to predict the soil resistance to driving in the specific soil conditions of the region. The method is based on the experience gained during the first phase of development of oil fields located offshore Angola and operated by ELF AQUITAINE. Its application may be extended to the southern part of the continental shelf of the Gulf of Guinea, wherever quite similar subsurface soil conditions prevail (South Gabon, offshore Congo, offshore Cabinda).

EVALUATION OF DRIVING HAZARDS

The development of Block 3, offshore Angola, started in 1985. Four jacket-type platforms have been installed so far in water depths ranging from 65 to 90m. They were founded on 48" O.D. steel pipe piles driven by hammers with rated energies up to 700 kJ (500 000 ft.lbs). The wall thickness of the piles was comprised between 1" and 2". The 30" O.D. conductor pipes were also installed by driving.

Premature refusals of piles and/or conductor pipes were observed during the installation of the first two platforms. Obviously, these difficulties were due to local specificities in the soil conditions:

high degree of heterogeneity of the soil formations, presence of limestone layers with a random distribution, unusual response of some materials to dynamic sollicitations
End Bearing Capacity of Piles in Calcareous Sands
Authors: Golightly C.R. , Nauroy J-F.
Published: October 2008

In this study, laboratory tests simulating the end-bearing of piles founded in silica sand and two calcareous sands at different densities were conducted. Bearing capacities are compared with field test values and theoretical cavity expansion pressures. Limit values for end-bearing based upon compressibility are suggested.

INTRODUCTION

The end-bearing capacity of deep foundations in sand is a complex and poorly understood subject. No recommendations exist which have been proposed by the certification authorities for more compressible sands of different mineralogy notably the biogenic calcium carbonate (calcareous) sands found mostly, although not exclusively, on continental shelves in tropical and sub-tropical regions. Pub1ications within the 1ast fifteen years have shown that pile capacities in such materials are much lower than in silica sands at similar relative densities.

This paper presents the results of model pile axial load tests carried out in a calibration chamber upon a silica sand and two incremented calcareous sands in dense and loose states. The laboratory results are then compared with published field test data and suggested design values are proposed.

Current Methods of Determining End-Bearing Current guidelines for offshore pile design in silica sands (API, 1989) are based upon an extensive back-analysis of pile load tests at penetrations of up to 30m (Dennis and Olson, 1983). Unit end-bearing is expressed as : (MATHEMATICAL EQUATION AVAILABLE IN FULL PAPER)

Where ?y' is the effective overburden pressure and is a bearing capacity factor. It has long been recognized that does not increase linearly with depth, but that the rate of increase reduces with depth. Limiting values used in design are equivalent to values of from equation (1) at an effective overburden pressure of approximately 240 kPa. Another approach includes an empirical method based upon high quality pile load tests, (Coyle and Castello, 1981) avoiding the use of limit values, which is [I1ore realistic, but taking no account of effective stress levels, being in terms of relative penetration. Another method (Randolph, 1985) links qp to Nq using recent correlations which properly model reductions in friction angle with mean effective stress. No recommendations exist in the API guidelines for more compressible sands, although research carried out on behalf of API (Dennis and Olson, 1983) equates medium dense ca1careous sand with loose silica sand and loose calcareous sand with very loose silica sand. A semi empirica1 method (Nauroy et a1., 1986) 1inks unit end-bearing to compressibility and proposes limiting values of qp related to the value of a compressibility index
Major Steel Renewals in FPSa Ballast Tanks Without Ceasing Production
Authors: Nelson P.
Published: October 2008

The number of tanker-based floating production systems and floating storage units in service is increasing. These are often based on older tankers in which the effects of corrosion, particularly in ballast tanks, increases with time. This paper explains why major steel renewals were required in one particular FPSO, the tanker of which was built in 1968. The methods and procedures described should give operators more confidence in repairing their units offshore without shutting down production or taking their vessels out of service.

INTRODUCTION

Tanker-based floating production and storage systems were introduced in the late 70's. They have proved to be fully effective and extremely reliable. Downtime on two FPSOs for which operational data is available have been negligible.

In 1989, however, it became necessary to renew 180 tones of steel in the ballast tanks of the tanker-based floating production storage and offloading facility FPSO II, offshore Palawan in the Philippines. FPSO II is a 127,000 DWT tanker permanently moored at the stern to a catenary anchor leg mooring system. This paper will explain why these renewals were required and how they were safely executed to the satisfaction of the Classification Society and Underwriters without interrupting oil production and export.

HISTORY

FPSO II was a normal trading tanker before her conversion to an FPSO in 1981. Built in 1968, she had one pair of segregated water ballast tanks (3 port and starboard wing tanks) in addition to the fore and aft peak tanks. During her conversion 4 port and starboard wing tanks were converted from oil service to ballast service - see Figure 1. At the same time the deck head structure within all these tanks was coated with coal tar epoxy from the tank top downwards for a distance of 2.4 meters. New anodes were fitted to the bottoms of all cargo and ballast tanks and up to a height of 9.6 meters from the bottom of all ballast tanks.

4 tones of steel were renewed in 3 port and starboard wing tanks in 1984. Additional anodes were fitted on completion of the steel repairs. In the second quarter of 1986, renewal of wasted anodes was carried out in 4 port and starboard ballast tanks and 5 port and starboard slop tanks.

In late 1987 it became evident that major steel renewals would be required in 4 port and starboard wing tanks and in the forepeak tank. These renewals were concentrated in a band 8 m - 18 m above the tank bottoms (moulded depth is 22 m) - see Figure 2. This area is above the fitted anode level, and is about the level at which the ballast water is normally maintained on FPSO II. In a trading tanker the ballast tanks are generally kept either full or empty, but in an FPSO which loads crude oil continuously, the weight distribution is constantly changing. Operational experience has shown that to maintain the ships bending moments, shear forces and trim within an acceptable range it is generally best to keep the ballast tanks only partially full.
Structural Integrity and Design of Tandem Hull Floating Production Platform
Authors: Brown D.T. , Hogan B. , Witz J.A. , Patel M.H.
Published: October 2008

The need for low cost floating platforms for well testing and oil production is not always being adequately met by either new-build semi submersible or ship shape hull forms. The tandem hull platform provides a potential solution. This paper presents methods for design and assessment of the structural integrity of a 'tandem hull' floating production facility. Such vessels consist of a surface piercing hull separated by a small distance from a fully submerged hull directly below it. The gap between the hulls is essentially open with the hulls connected together by short vertical bracing members.

The results presented in this paper are based on a generic tandem hull configuration. It is shown that the vessel has adequate structural integrity, but design of some critical areas of the vessel, particularly in the region of the inter-hull columns, must allow for the high dynamic loads which are a feature of the concept.

1. INTRODUCTION

The tandem hull platform can be regarded as a hybrid of monohull and semi submersible hull shapes. The vessel takes the form of a water surface piercing hull separated by a small distance (typically 4.0 m) from a fully submerged hull directly below it. The gap between the hulls is substantially open with the hulls connected together by short vertical bracing members of rectangular cross-section. Figure 1 shows a perspective view of a typical tandem hull design. The vessel hulls are of the order of 170 m in length with a beam of approximately 38 m. The vessel can carry in the region of 40,000 metric tones of oil storage in the lower hull.

The three major performance requirements for a floating production platform are high load payload capacity for process plant and oil storage, low motion response to waves and low construction cost. Both semi submersibles and monohull vessels have shortcomings when viewed against these criteria.

The tandem hull platform, however, combines the beneficial design features of both conventional monohull vessels and semi submersibles to satisfy the needs of both high payload capacity and low wave induced motion characteristics.

However, the emergence of these special purpose hull configurations requires a unified technical approach to such designs - both to place them within the context of other marine vehicles and also to enable better understanding of their hydrodynamic and structural behavior. This paper presents this approach for the tandem hull form in a floating production platform application where deck payload capacity and low wave induced motions of the stationary vessel are the primary design goals.

The paper presents the overall hydrostatic and hydrodynamic characteristics of the vessel, together with an investigation of its structural integrity and strength. Recommendations for further analysis are also provided.
A Comparative Study Using API RP2A-LRFD
Authors: Ferguson M.C.
Published: October 2008

This paper assesses the benefits offered by API RP2ALRFD. With reference to the Goodwyn 'A' platform, it contrasts the requirements of the draft LRFD version of RP2A with those of the current version and those of NPD. It demonstrates that improvements in reliability offered by API RP2A-LRFD can be achieved without significant change in structure weight.

1.0 INTRODUCTION

1.1 GENERAL

The issue for industry review, just last December of a 'Load Resistance Factor Design' version of API-RP2A (Ref I) marks a major milestone in the history of the API Recommended Practice for Fixed Offshore Platforms. Since it was first issued in 1969, the working stress code RP2A (Ref 2) has become an internationally accepted standard for fixed platforms. The issue of a load resistance factor design version reflects the worldwide trend away from working stress design to reliability based methods.

This paper presents a comparative study using API RP2ALRFD. As a reliability based alternative, the load resistance factor design (LRFD) method offers a more consistent approach to platform safety than does the existing RP2A working stress design (WSD) method.

The study is directed to assessing the benefits of RP2A-LRFD. In the .context of the Woodside Goodwyn'A' platform, comparisons are drawn between RP2A-LRFD requirements and those of RP2A-WSD and the Norwegian Petroleum Directorate (NPD). The work is confined to the in-place strength of the jacket and module support frame (MSF).

The study is based on work performed for Woodside as part of the substructure design for the Goodwyn 'A' Platform. The reliability of the Goodwyn 'A' substructure has been a major focus of the design and results are presented showing the platform reserve capacity, computed using non-linear inelastic ductility analyses.

1.2 RP2A - LOAD RESISTANCE FACTOR DESIGN

One of the great merits of the existing API RP2A, now in its 18th edition, has been the way that sound engineering practices have been presented in a flexible manner such that the designer's judgment and creativity are not inhibited. This is achieved by providing a basic framework for design, accompanied by guidance on problem areas lying outside this framework. These same hallmarks apply also to the RP2ALRFD draft. Although fundamental differences exist between the WSD and LRFD versions, the two documents remain remarkably similar with the LRFD draft containing most of the carefully phrased clauses which are familiar to many practicing engineers.

LRFD however, is an improved approach to structural design which takes into account the possible uncertainties in the applied loads and component resistances. The designation 'load resistance factor design' derives from the concept of factoring both loads and resistances as opposed to the working stress design approach where only the resistance is divided by a factor of safety.
The Concepts of Added Mass and Inertia Forces and Their Use in Structural Dynamics
Authors: Jacobsen V. , Hansen E.A.
Published: October 2008

A discussion on the concepts of added mass and inertia forces is provided combined with illustrative examples. The paper relates to submerged circular cylinders - single or in groups - only, and from an assessment of measured forces and analytical developments it is advocated that the added mass values determined from potential flow theory are adequate also for real flows. A procedure for determining the added mass coefficients for single cylinders and groups of cylinders has been developed, and results are given for 4 different configurations.

INTRODUCTION

Researchers and engineers specializing in hydrodynamics may be exposed to extensive treatments of the subjects on added mass and inertia forces, and they have the opportunity of familiarizing themselves with the underlying physics. This detailed insight and comprehension is not easily transferred to the majority of application oriented engineers, and one is often from basic courses left with the impression that the added mass and inertia forces are phenomena that basically are related to two coefficients that are interrelated by the simple expression C = C +' 1, and that the only problem is to Establish a set of applicable values for one of these coefficients, e.g. from laboratory experiments.

This paper attempts to bridge part of the gap between the two groups of professionals by addressing briefly the fundamentals on this subject and by reviewing well known experimental results from a perspective with emphasis on general physics. Results of recent analytical/ numerical developments are also presented and it is shown that the above simple relation does in fact not apply universally, as it is influenced by the geometric boundary conditions. It is argued that the experimentally derived C values presented in the literature do not provide the basis for an accurate assessment of the added mass applied in determining natural frequencies for the onset of structural vibrations.

SOME FUNDAMENTALS OF ADDED MASS AND INERTIA FORCES

By using the integrated load concept and the added mass or inertia coefficients the actual physics can be easily overlooked: In reality the added mass term reflects the integrated effect of the hydrodynamic pressures which are exerted on a body accelerating in a fluid, whereas the inertia force is the integrated pressures acting on a body exposed to an accelerating fluid. And these two forces are not identical. In fact the latter force is two times larger than the former for the free cylinder case.
In-Situ Pile Segment Model Experiments at Empire, Louisiana
Authors: Bogard J.D. , Matlock H.
Published: October 2008

Fourteen experiments were conducted at Empire, La. using instrumented pile simulation probes to measure lateral pressures and t-z behavior at various times and under a variety of loadings. Three of the fourteen were conducted at the same depth in parallel bore holes and enable comparisons of the effects of two diameters and two end conditions. A detailed presentation of the three sets of results leads to an improved understanding of the significant mechanisms and processes involved in the axial-load behavior of long offshore piles.

Introduction

Two types of instrumented probes have been developed to model segments of long flexible piles. The probes are instrumented to determine in situ the significant soil response parameters under a variety of static and cyclic loading conditions (Refs 1 and 2). The resulting data provide a basis for more rational and reliable axial pile design methods.

Experiments have included consideration of the effects on axial pile capacity of diameter, wall thickness, and setup or consolidation time, plus the effects of displacement and load history, and cyclic degradation.

In 1975 a series of tests on four 50-ft-long pipe piles 14 inches in diameter were performed at Empire, Louisiana for Chevron Oil Field Research Company (Refs 3 and 4). Test depths ranged from 115 to 360 ft. In April, 1984, fourteen experiments were performed with the instrumented model segment probes at the same site. Test depths ranged from 120 to 250 feet, covering the depths reported for Chevron's piles 1 and 2. Eight of the experiments were in a normally consolidated clay from 120 to 160 feet.

The locations of the borings in which the experiments were performed are shown in Fig 1. Also shown are the locations of earlier work at the site, including the original pile tests by TERA, soil borings made by McClelland Engineers, proprietary CPT and pyrometer work done by Fugro Gulf, and experiments with the PLS probe done by the Massachusetts Institute of Technology (Ref 5).

OBJECITVES

The research program was originally proposed as a fundamental study of the response of a normally consolidated clay to a pile under a variety of loading conditions, including comparisons with the Chevron pile tests.

The probes have been successfully deployed at the onshore and offshore sites of three instrumented large-scale pile load tests and at two onshore sites for which parallel large-diameter pile load test data are not available.

The scope included examination of open and plugged end conditions, effects of diameter on setup and shear transfer, degradation under one-way and two-way cyclic loading, and the effects of loading rate on shear-displacement behavior