bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of a Methodology for Safety Assessment of Existing Steel Jacket Offshore Platforms
Authors: Aggarwal R.K. , Bea R.G. , Gerwick B.C. , Ibbs C.W. , Reimer R.B. , Lee G.C.
Published: October 2008

This paper describes a methodology for assessment of the safety of existing steel jacket offshore platforms. The methodology is based on a four-level evaluation process. The first two levels consist of screening of the platforms into one of three categories: "fit for service", "unfit for service", and "marginal", based on qualitative evaluation and simplified quantitative analyses. The higher levels of assessment require detailed computer analyses.

Capacity of the platform and potential consequences associated with the loss of serviceability of the platform are key parameters in this methodology. The capacity characteristics are expressed through a Reserve Strength Ratio (RSR = Ultimate Capacity / Minimum Reference Force). The consequences are expressed through evaluations of life, property, resources, productivity, and environmental implications associated with the proposed platform operations.

A study is currently (1990) underway to present this methodology in the form of a computerized knowledge-based expert system. The organization of the prototype expert system is presented.

INIRODUCTION

Steel platforms have been in use for more than 40 years in the Gulf of Mexico and other offshore areas around the world. At present, there are more than 4,000 offshore platforms in the United States. In the Gulf of Mexico alone in 1987, there were 3,080 platforms, of which 73-percent were in water depths up to 100 ft. and 27-percent were in water depth more than 100 ft. [1].

The structural configuration of these platforms ranges from single-well caissons to multi-leg jackets. In 1987, there were 1,969 wellhead platforms, 355 tender-assisted platforms, and 756 self-contained drilling & production platforms in the Gulf of Mexico [1]. The wellhead platforms are single well caissons or multi-well 4-legged jacket platforms. The tender assisted platforms are usually 4-legged jackets and the self-contained platforms are mostly 8-legged jackets. The design criteria of these platforms has changed significantly over the past 40 years. Many of the early platforms were designed for 25-year return period waves, whereas, since about 1969, the majority of platforms have been designed for 100-year return period waves. The American Petroleum Institute (API) first introduced recommended practices for offshore platforms (API-RP-2A) in 1969, to provide consistency in design, fabrication, and installation of offshore platforms. API has periodically updated the recommendations, and the 18th edition [2] now forms the general standard for design of Gulf of Mexico platforms

The present day Minerals Management Service(MMS), introduced the Outer Continental Shelf (OCS) Order No. 8 in 1979 [3]. More recently, the MMS introduced updated requirements, which largely follow the API guidelines with some additional requirements [4]. Present OCS requirements define the need for periodic assessment of existing platforms for their continued use (Clause 250.142 a)
Metal Annulus Seals for Subsea 'Wellheads: Important Systems Considerations
Authors: Boehm C.F. , Hosie S.
Published: October 2008

The development of metal-to-metal annulus seals involves careful consideration of the environmental and operational requirements of these seals for sub sea wellheads. This paper discusses the development of such a seal with particular emphasis on the testing program which subjected the seal to realistic drilling conditions.

INTRODUCTION

Sub sea wellhead systems are exposed to a variety of severe environments. Some of the most critical wellhead system components are the annulus seals which seal or pack off the successive casing annuli as the well is drilled. True metal-to-metal seals are considered the premium approach for the most harsh conditions. Devising metal seal systems involves not only the usual evaluation of the seal environment, but particular attention to what constitutes a true metal-to-metal seal. Finally, qualification testing of such a seal involves careful consideration of fixture bias, those elements of laboratory testing which do not reflect realistic operational conditions.

SEAL ENVIRONMENT

In drilling a well, particularly sub sea, many conditions occur which could cause scoring damage in the wellhead bore. Wear protectors (wear bushings, bore protectors) are installed and retrieved after each successive drilling operation and can cause damage. Additionally, casing, casing hangers, associated running tools, and test tools are introduced into the wellhead bore and can, if debris is present or vessel offset severe enough, cause scoring damage. The frequency of such damage and its severity is indicated in Figure 1-A. A survey of used wellheads was conducted and the results of typical damage is shown in Figure 1 (1).

When a seal assembly is installed, its outer surface can be damaged because typically the metal seal element's outside diameter is virtually the same as the running tool and the hanger maximum diameters. Assuming a single trip casing-cementing, seal-setting system is run, there is virtually no protection as the seal assembly progresses down the riser bore, through the flex joint, annular BOP element, and past the ram cavities into position in the wellhead housing. Certain factors can make this trip more hazardous:Excessive vessel offset causing severe flex joint angles.Used or worn annular BOP elements, which typically extend into the primary bore of the BOP stack.Rams which have "drifted" into the primary bore of the ram presenters or have bit damage.

Adverse flex joint angles and protrusions into the primary bore of the BOP stack provide ready agents for damage to the metal seal element's outer surface. This type of damage is most often of a vertical or near vertical nature across the sealing area surface. The metal seal element's inside diameter and the hanger neck sealing surface generally do not suffer scoring damage in the course of running and cementing casing. However, the possibility of entrained solids or cuttings causing an erosive type damage is possible during circulation especially if silky/clay or "gumbo" as commonly found in some locations is present.
Vertically Constructed and Installed Jacket for the Gyda Field
Authors: Harris G. , Stone G.C.H.B.
Published: October 2008

This paper examines the design, construction, 10adout, transportation and installation aspects of the Gyda Jacket. The jacket is a vertically constructed and installed six leg structure with vertical piles in 66 meters water depth. The jacket lift weight was approximately 8200 tones.

The concept was made possible by the new generation of heavy lift crane vessels, which opened the horizons for lifted jackets in the range of 8000 to 10,000 tones.

The new design features are discussed, which included the use of steel castings and the elimination of all internal stiffening of tubular joints. The major features and experiences gained during construction and installation are also discussed, particularly vertical piling. Comparisons are made with conventional barge launched jackets to demonstrate the cost and weight savings. The paper concludes with the major lessons to be learnt for future projects.

INTRODUCTION

The Gyda field is located 28 km. south-east of Ula and 43 km. north of Ekofisk in the Norwegian sector of the North Sea.

The estimated recoverable reserves are about 200 million barrels of stock tank oil, over a production life of 20 years. The planned production race is 60,000 barrels per day of oil and 1.9 million m per day of rich pipeline gas. 32 well slots are to be provided comprising 19 production, 11 water injection and 2 spare. The reservoir requires water injection at an average rate of 65,000 barrels per day.

The development is a single platform comprising four major topsides modules. The Living Quarters, Process/Utilities and Drilling modules are mounted directly on an eight leg Cellar Deck. This Cellar Deck stabs directly into the conventional piled steel jacket.

The jacket stands in 66 meters of water and the seabed comprises 10 meters of level sand with layers of clay beneath. The maximum design wave height is 25 meters and the jacket was designed for all the usual load combinations, including boat impact and earthquake. The jacket was designed for a total operating load of 26,500 tones.

The jacket is 76m high and has a plan area of 54.0m × 25.0m at the top and 58.0m × 38.0m at the base. The jacket is a six leg structure incorporating around 250 members and 109 nodes, see figure 1. It is supported by a total of 20 vertically driven piles 2134mm diameter, four 70m length, at each corner leg, and two 75m length at each centre leg.

The jacket accommodates a total of 32 conductors, eight are 500mm in diameter and tied back from the sub sea wellheads at the drilling template. The remaining 24 are 685mm diameter platform run conductors. There are 13 caissons, of various diameters and termination elevations descending from the topsides facilities, and 4 pre-installed risers.

PROJECT SCHEDULE

The overall project schedule is shown in figure 2. The concept engineering took place in the latter half of 1986. The front end engineering ran from the 5th January 1987 to the end of June, When detailed engineering commenced on the 1st July 1987.
USCG and the TLWP Facilities
Authors: Folse K.A. , Hanke T.A.
Published: October 2008

This paper relates the experience of conoco Inc. in obtaining United states Coast Guard (usa) approval for facilities on the Tension Leg Well Platform (TrnP) located in Green canyon Block 184 in the Gulf of Mexico. Information is presented on the:chronology of key usog communications and TrnP project milestones,evolution of the list of "ship's services" on the TrnP which required usa:; approval,interaction between Conoco and usog on these "ship's services" to 0btain usa:; approval, andvarious certificates and documentation required for the TrnP.

This paper excludes items curler the jurisdiction of the Minerals Management Service (MMS).

INTRODUCTION

An overview of the Jolliet Project management, design, fabrication and instal1ation1 is presented in the paper "Jolliet--The Project." A key element of the project is the TrnP located in Green canyon Block 184. This paper addresses a portion of the TrnP project activities, in particular, the approval by regulatory authorities of the various facilities systems on the TrnP.

At the time the Green canyon TrnP was approved to proceed, the concept was fairly new and as yet untried in the United states. conoco recognized the need to obtain regulatory authority approval to install the TrnP on the outer continental Shelf (OCS). Two regulatory agencies, the united states Coast Guard (usog) and the Minerals Management Service (MMS), would be involved in approval of the TrnP. Structures on the u. s. OCS were divided into fixed, which were curler the jurisdiction of the MMS, and floating which were unclear the jurisdiction of the USOG. The two agencies had agreed to a general division of responsibilitiesfor approval of the various systems on these structures.

The TrnP was designated a floating OCS facility and, therefore, curler usog jurisdiction. he usog took the position that existing rules for M0bile Offshore Drilling Units (mro's) more closely approximated the TrnP and would be used as a startin3' point for review. Also, the usog would review and approve all "ship's services" marine engineering systems to 46 CFR Chapters F and J. The USOG stated that because of differences between mro's and the TrnP, they would remain open to discussion on any issue for which requirements were not specific.

The MMS had jurisdiction over drilling and production systems (industrial systems). The requirements of the MMS for fixed platforms were familiar to conoco, but the detailed assignment of jurisdiction over TrnP facilities to either USOG "ship's services" or MMS industrial systems was not clear early in the TrnP design phase.
Wave-Loading Experiments on Elements of Jackup Legs at Large Scale
Authors: Schuurmans S.T. , Lagers G.H.G.
Published: October 2008

Results of wave loading experiments on chord sections and isolated bays of two typical jack-up leg designs are discussed. The tests were carried out at a large scale (approx. 1:2 for chords and approx. 1:4 for bays) in regular and random waves with large wave heights (up to 2.4 metres). This large scale is necessary to obtain flow conditions which are representative for full scale offshore conditions.

INTRODUCTION

Wave induced forces are a major contribution to the overall loading on a jack-up platform. They play an important role in the design of a jack-up platform or in the analysis of existing jack-ups, when their fitness for use at a specific site is considered.

While a large amount of experimental data has been gathered on smooth and rough circular cylinders in planar oscillatory flow and in waves, very little information is available fromtests with jack-up legs in such conditions. Itis generally assumed in the jack-up industry that the wave loading on jack-up platforms canbe based on experimental data obtained in stationary flow in wind tunnels. In view of the application of such platforms in deeper water and more severe environmental conditions, this situation is not satisfactory.

Therefore, a joint industry project was carried out to improve knowledge and understanding of the wave loading on jack-up legs. The basic objectives of this project were:to determine wave forces on typical jack-up legs under representative wave conditions and with the smallest possible scale effects andto achieve results for engineering applications which have a more general bearing than on the tested legs only.

This paper describes some results of wave loading experiments on elements (chords and isolated bays) of jack-up legs, carried out within the scope of this joint industry project. In view of the second objective, smaller elements (chords) were tested beside larger elements (bays) to enable determination of interaction coefficients. Bracings were not tested separately in this programme, because a large amount of literature is already available on circular members in stationary and oscillating flow. For the extrapolation of the laboratory data to full scale offshore conditions, it is essential to obtain these data in post-criticalflow conditions. To achieve the required Reynolds- numbers, the tests were therefore carriedout at a large scale (approx. 1:2 for the chords and approx. 1:4 for the bays) in regular and irregular waves with large wave heights (maximum wave height in irregular wave trains up to 2.4 metres).

This paper concentrates on the execution and the results of the wave loading experiments. In future publications, attention will be focused on the composition of elementary results to bay and leg results and the comparison of the composed results with measured results to check on interactions.
Wave Run-Up and Wave Forces on a Truncated Cylinder
Authors: Niedzwecki J.M. , Duggal A.S.
Published: October 2008

The results of a small scale experimental study to investigate the wave run-up and wave forces on a truncated cylinder, representing a single TLP leg, are presented. The investigation examines the wave run-up and in-line wave force conditions resulting from both regular and random waves. Surface adhering wave gages and a shear type load-cell design were developed for use in the study. Time series data around the cylinder and the sensitivity of the observations to wave steepness and scatter parameter are presented. For the random wave cases, attention is focused upon the relationship between the front and back of the truncated cylinder. Information on the transfer function, coherence, phase and total force are presented and discussed.

Introduction

The prediction of wave run-up and the associated wave forces on coastal structures and deepwater platforms has been of interest to the offshore community for many years. During this time, the engineering applications have included the design of piers, lighthouses, conical islands, fixed offshore platforms, and more recently the design of tension leg platforms (TLP's). As the focus for engineering design has changed the analytical and numerical tools available have significantly improved (Kim and Yue, 1989). However, these tools have been calibrated with only a limited amount of laboratory and field data.

The objectives of this study were to:to provide new laboratory data on truncated cylinders subject to regular and random waves, andto examine this data utilizing variety of statistical analysis tools in an attempt to provide new insight into the wave run-up problem.

In what follows, a perspective of where the results from this study fit into the current open-literature is provided through a brief review of previous experimental studies. Next, a description of the experimental setup and procedures is presented. The results for the regular and random wave cases are presented and discussed in sequence in separate subsections.

Previous Experimental Studies

Previous experimental studies have generally focused upon 1.) very large diameter structures in shallow water including man-made islands, and 2.) single and pile groups extending from the seafloor through the free-surface. Table 1 presents a comparative view of many of the earlier studies. Of particular interest are the range of parameters which have been examined.

The first three studies, listed in Table 1, are concerned with the wave elevation distribution around large circular islands and lighthouses. The tests conducted were for a rather limited range of wave interaction parameters with a scatter parameter greater than 0.6 in all cases. However results from all three investigations showed good agreement with linear diffraction analysis. Isaacson (1978) proposed a cnoidal wave theory approach to estimating the run-up on large circular cylinders in shallow water and showed that, though the cnoidal theory underestimated the experimentally measured wave run-up, it provided better estimates than linear diffraction analysis.
A New Locating Towed System for Mapping Smal Buried or Exposed Sealines
Authors: Kuhn H.W. , Robach F. , Schnepp G. , Guilhamat B.
Published: October 2008

Locating buried small diameter sealines (say < 10") with conventional geophysical methods has always been a problem for the off-shore oil industry. Standard towed survey tools, based on reflection seismics or proton magnetometers, suffer from their lack of resolution and sensitivity. The towed magnetometer, developed by the CEA, thanks to its very high sensitivity (0.01 nT) and measuring rate, allows small diameter sealines to be accurately detected. Moreover, when simultaneous injection in the sealine of an electric low frequency signal is performed, even cables or flexible pipes with little magnetization are detected.

I. MAGNETOMETRY AND ITS APPLICATIONS

Measurement of the Earth's magnetic field using airborne techniques is a standard military approach for submarine locating, and for mapping natural resources in geophysics.

The measurement is based on the principle of proton or electron magnetic resonance which transforms the intensity of a magnetic field H to a proportional frequency F.

The relation is given by Larmor's formula:(Available In Full Paper)

The frequency detector then measures the total field.

The measurement can be made by a moving sensor which is either towed behind an aircraft by a cable which reduces the effect of the magnetism of the carrier, a relatively simple solution, or embarked on the aircraft, which then calls for appropriate compensation techniques.

A fixed magnetic observation station equipped with a total field magnetometer having a relative precision better than a millionth will record time-dependent fluctuations of the magnetic field. Diurnal variations, magnetic storms and pulses are related to the sun?s activity and amount to a thousandth of the Earth's almost constant internal field.

For high sensitivity measurements, a differential technique is used. This eliminates the time dependent fluctuations which are identical at two geographically close points. The use of such a differential technique is standard in aeromagnetic mapping, but in marine applications, it is exceptional.

In submarine archeology for example, the use of three magnetometers towed behind a boat can be used to obtain the differences in total field experienced by the sensors (figure 1). These differential measurements are insensitive to temporal fluctuations, and the interpretation of the anomalies detected can result in the discovery of ancient shipwrecks essentially made of wood.

II. SPECIFICATIONS OF A HIGH SENSITIVITY MAGNETOMETER

Magnetometers available commercially at present, are based on either proton or electron magnetic resonance and are known as proton magnetometers or optically pumped magnetometers. The magnetometers presented here have been developed by the French Atomic Energy Commission (C. E.A.) and are based on simultaneous proton and electron magnetic resonance (Abragam - Overhauser effect) (1).
Towards More Compact and Efficient De-Oiling Equipment
Authors: Plat R. , van den Broek W.M.G.T.
Published: October 2008

The development of a compact oil-water separator is pursued through theoretical and experimental investigation of a number of separation techniques. Plate separation is an effective separation method for oil droplets with a diameter of about 50µm or larger, but ineffective for smaller droplets. Use of gasflotation or of oil coalescence in a porous medium as separation techniques leads to the removal of a part of the smaller oil droplets present in oily waters. To increase the separation efficiency each of the last two techniques will be combined withcentrifugal separation. A design of a separator based on such a combination is presented for both gas flotation and oil coalescence.

INTRODUCTION

De-oiling equipment at offshore oil-production platforms must preferably be light and compact, and the oil concentration of the discharged production water must be below the prescribed limit. In many cases these requirements are not met. This paper describes work on the improvementof de-oiling equipment with respect to size and efficiency. Three de-oiling techniques are studied:Plate separation. This is a suitable technique for the removal of oil droplets above a specific diameter. In practice this diameter is of the order of 50µm.Dissolved gas flotation and oil coalescence in a porous medium. With these two techniques also smaller oil droplets can be removed.

PLATE SEPARATION

A plate separator consists of a pack of parallel plates, through which oily water is led. To enhance the removal of the collected oil the separator is usually placed under an angle with the horizontal, and provided with corrugated platesl. The rise velocity of the oil droplets is determined by the density difference between oil and water and the friction force exerted on the rising oil droplet. It can be shown2 that this results in a stationary rise velocity:(Available In Full Paper)

The use of a plate separator leads to complete removal of all oil droplets above a specific diameter, the critical oil-droplet diameter. The numerical value of this parameter depends on the dimensions of the plate separator and on the velocity of the oily water, and can be calculated as2 :(Available In Full Paper)

In case the angle with the horizontal is larger than about 10 degrees, it is necessary to correct for the tilting of the separator by replacing H by H/cos ? in eq. (2).

Experiments and results

Experiments on plate separation were carried out in straight and in corrugated channels. A flow circuit for oily water with a maximum capacity of 5 m3/h was available for the experiments. We limit ourselves to the discussion of two typical experiments: one on the measurement of the velocity profile inside a corrugated channel and one on the experimental determination of a critical oil-droplet diameter.

Fig. 1 gives a sketch of a corrugated separator channel with dimensions: length 1.50 m, width 0.50 m, height 0.020 m. At a wave-peak (A) and at a wave-trough (B) the velocity profile was measured along a vertical line, with a TNO-Delft laser-doppler anemometer.
Extensive Testing of TFL Techniques in Italy
Authors: Chioetto S. , Donati F.
Published: October 2008

Agip S.p.a. is presently conducting a testing campaign on a complete line of 3 in. (76 mm.) TFL equipment, at a dedicated centre in Cortemaggiore (Italy).

The aim of the testing is to study the functionality and the reliability of each tool, and of the system as a whole, generating an extensive data base on the performance of the system.

This paper is a description of the project and of the test plant that has been dedicated to its development; the procedures that are being followed for the testing, and the logic behind them, are also described.

At the end of the paper, a brief summary of the results that the project has yielded so far is reported, together with some general considerations on the most important problems associated with the use of TFL techniques.

INTRODUCTION

A TFL testing campaign is presently being developed by AGIP in a dedicated R&D centre located at Cortemaggiore, in the north of Italy, on a complete line of 3 in. (76 mm.) TFL equipment

The ultimate aim of the project is the acquisition of the expertise and insight in TFL technology that may eventually lead the company to the choice of TFLsolutions for the maintenance and service of future subsea wells.

So far, in fact, TFL technology has never been adopted by the company for any of its wells, in Italy or abroad, and, although this technology is not new and has already been tested and field-proven by several companies, performance data are still not easily available, and the costs and risks associated with the choice of TFL developments are such thata certain degree of in-house understanding of the capabilities and limits of the technique are felt to be needed, before embarking on a development venture.

The main reason that at first prompted the proposal of a testing campaign on TFL equipment was the foreseeable future necessity to develop subsea wells in very deep waters, such as in the Adriatic basin (water depths from 800 to 1000mts. 1.

The size of 3 in. (76 mm) was selected for the equipment line to be tested, since it appeared to be the most likely choice for a future application.

In the years 1985 and 1986 the pilot plant was set up, complete with flow-line loop and surface TFL facilities, and the equipment to be tested was ordered. The specification of the equipment ordered for testing covered most of the component S used in a typical dual string TFL well completion.

Actual testing started in 1988, and is presently (January 1990) ongoing, followed full-time by a small team of technicians, aided part-time by a TFL specialist from the tools manufacturer.

Close communication and cooperation between test personnel, the manufacturer, and personnel from other companies that also have an interest in TFL testing, has from the start been considered essential to the success of the project, and are constantly contributing to the improvement of the TFL product line, as well as to a better general understanding of the technique.
Design Development of a Soft-Yoke Mooring System for the S236-1 Field in Liaodong Bay, China
Authors: D'Souza A.B. , Huang E.B. , Zhiqiang Zhao , Gui Wen Baa
Published: October 2008

The Suizhong 36-1 (SZ 36-1) Oil Field in northern Bohai Bay in about 30m. water depth is a giant offshore oil fie1d with estimated reserves of 1.2 billion barrels of oil. The development plan requires a Floating Production Storage Unit (FPSU) and a Single Point Mooring (SPM). The SPM is designed for the 10 a-year return non-ice storm and the 25-year storm with 0.24m. first year ice sheet with the FPSU connected. It is also designed for the 50-year ice event with 0.55m. rafted first year ice with the FPSU disconnected. The engineering design of the fixed tower soft-yoke SPM developed for these conditions is presented. Information on system performance analysis, design, procedures for predicting ice loads on SPM and FPSU and on model test results is included.

INTRODUCTION

Field Location

The SZ 36-1 oil field is located in Liaodong Bay in the eastern part of the Bohai Gulf (Fig. 1). The field is about 50 kilometers (km) from shore. It is characterized by heavy, high Viscosity oil, low oil/gas ratio and a loose reservoir which makes the development of the field a technical challenge. It is being explored and developed by Bohai Oil Corporation (BOC) of the China National Offshore Oil Corporation (CNOOC). The discovery and development of the SZ 36-1 oil field was reported in Reference 1. BOC has prepared a field development plan, shown in Fig. 2.

Conceptual design of the engineering facilities conducted by BOC in conjunction with foreign consulting companies has been completed and contracts for fabrication and insta11ation of the facilities are being awarded. The field is expected to be on stream by 1992.

This paper focuses on the preliminary design of the SPM system. Topics specifically addressed are the system design basis, evaluation of alternate SPM systems and selection of a preferred system, system description, mooring analysis and design and model test. The preliminary design may differ from the final design, which will be engineered by an SPM Contractor.

DESIGN BASIS

SPM Location

The coordinate location of the SPM is shown in Figure 2. The mean sea level at the location is 32.80 m. above the seabed with an extreme tidal variation of +2.16, -2.73 m.

Environmental Conditions

SPM environmental design criteria are summarized in Table 1. Of particular concern is the presence of sea ice in the winter.

Ice conditions are categorized into light, ordinary and heavy ice years. In 1ight ice years there will be no ice in the field. In ordinary ice years about half the fie1d will be covered with drift ice with level ice thickness ranging from 5 to 15 cm. and speeds from 0.3 to 0.5 m/s and a maximum of 1.0 m/s. This condition lasts for about 30 days in January and February. The FPSU must remain connected in ordinary ice years.

Heavy ice years have taken place three times since 1936 (1936, 1947 and 1949) when the entire field was covered with land fast ice, with level ice thickness ranging from 20-30 cm.
The Application of Ultrasonic Creeping Waves for NDE o Welds in the Offshore and Related Industries
Authors: Sandy P.A. , Swain N.A.
Published: October 2008

ABSTRACAT

This paper outlines the theoretical principles of the ultrasonic technique of creeping waves and discusses their advantages over existing methodology for testing weldments.

In this technique, ultrasound is transmitted by compression waves at a very low angle into the weldment and thereby compliments existing ultrasonic testing by working with in 3-4 mm of the entry surface. Creeping waves can therefore be used to supplement and sometimes replace Magnetic Particle Inspection (MPI) and/or Dye Penetrant Inspection (DPI) for examiningwelds in offshore structures and other structures or vessels requiring defect evaluation at or near the surface.

1.INTRODUCTION

Creeping waves have been around for a number of years, being used in the powergeneration sector for detecting crackingunder cladding of vessels used in reactors. Initial usage of creeping waves in the offshore fabrication industry was to resolve production problems stemming from spurious M.P.I. indications along the toes of submerged arc welds. Details of this and the further practical developments of this are detailed further on in the text. This report covers the practical application of creeping waves, but first it is necessary to give a brief outline of the theory.

2.THEORY

Creeping wave probes consist of twin transducers which generate compression waves at angles between 70° and 90°. The waves from the part of the beam which travel parallel to the surface are called creeping waves (see Fig. 1). The ultrasonic probe also generates shear waves by mode conversion from the compression wave and these have anangle of incidence of 33-38°. Since the creeping wave is derived from the compression wave and travels first beneath the surface, it is unaffected by weld splatter, surface condition or change of geometry such as seen at a weld toe. Because of this tolerance the creeping wave probe can be used in many applications where surface wave probes are totally unsuitable.

It has been found that the type of creeping wave probe used in this work gave the best practical results when usable beam path was kept to a maximum of 60 mm.

3.EQUIPMENT

The equipment used apart from the probe is conventional A-scan portable ultrasonic equipment. The probe found to give the best results is a twin crystal 4 MHZ with crystal sizes of 6x13 mm, with a focus of 10 mm and a squint angle of 20°.

The test block (see Fig. 2) was a piece of BS4360 50D plate material which was similar to the material under test. The dimension of the block was 20 mm thick and approximately 50 mm wide and 300 mm long. The block had 3 notches spark eroded in the surface of 0.25 mm, 0.5 mm, and 0.75 mm depth. The width of these slots was 0.2 mm. Spark erosion was chosen as the method of producing the slots as this technique gave the smallest width with the most consistency and accuracy. The only other ultrasonic equipment required is a twin crystal 0° compression probe of the same frequency as the creeping wave probe.
South Marsh Island 205-A: Lifted Jacket in a Water Depth of 437 ft
Authors: Palmer R.W. , Oksuzler Y. , Campo J.J. , Kessler K.J. , Sanzgiri S.M.
Published: October 2008

The South Marsh Island 205-A platform is located in the Gulf of Mexico off the coast of Louisiana in a water depth of 437 ft. Instead of launching the jacket from the transportation barge, the jacket was lifted from the barge with two derrick barges. The jacket consists of four main legs which frame directly into four skirt sleeves. This is the first such jacket to be designed for the Gulf of Mexico. It is the largest jacket by weight and water depth to be lifted in the Gulf of Mexico and is the deepest four pile jacket installed in the Gulf of Mexico to date.

The design and configuration of the jacket, the development and analysis of the skirt sleeve to leg connection and the installation of the platform are presented in this paper.

INTRODUCTION

South Marsh Island block 205 is operated by Mobil Exploration & Producing U. S., Inc. The contract for the design of the South Marsh Island 205-A platform was awarded to McDermott, Inc. in March, 1988. In an effort to reduce fabrication and installation costs and to enhance the financial return of the field, the feasibility of a lifted jacket with four skirt piles and no main piles was investigated. Gulf of Mexico fabrication and installation contractors were contacted for input concerning fabrication capabilities, limitations, marine equipment capacity and availability. At the same time, Mobil Research and Development Corporation (MRDC) was contacted for information on a skirt sleeve to leg connection that had been developed for the North Sea. Through preliminary analysis along with contractor and MRDC input, it was concluded that the concept was feasible and that cost savings could be realized.

In another effort to reduce costs, an existing deck was salvaged and refurbished for reuse. The deck was a two level, eight leg drilling/production deck that was originally designed for simultaneous operations. For the removal of the deck, it was cut off 2 ft. below the cellar deck and placed on 2 in. circular plates to be later installed on top of the South Marsh Island 205-A jacket.

Elevation views of the platform are shown in Figure 1. The eight leg deck is supported by the four corner legs of the jacket and four false legs which are braced into the corner legs below the waterline. The legs are tapered from 36 in. diameter at the top to match the deck legs to 80 in. diameter at the bottom. The spacing of the legs at the top of the jacket is 45 ft. × 125 ft. The legs are battered 1:6 in the transverse direction and 1:12 in the longitudinal direction which results in an essentially square base that is 210 ft. × 208 ft.

The jacket weighs 3810 s. tons in air as weighed with electronic load cells prior to loadout. In order to lower the weight of the jacket for lifting purposes as well as on-bottom weight, approximately 45% of the jacket steel is 50 ksi material.
Two-Phase Flows as a Result of a Subsea Blowout and Their Effect on the Stability of Structures
Authors: Moros T. , Dand I.
Published: October 2008

A number of floating structures have sunk in subsea well blowouts. The cause of rig sinkage has previously been explained by a loss of buoyancy attributed to a density reduction of the surrounding sea by the gas phase. It has been recently shown that this is of secondary importance and the main cause of rig instability are the secondary flows in the water, which are generated as the gas rises to the free surface. In this paper numerical simulations of the two phase flows following a release of gas at the bottom of the sea, for one flow rate and two water depths. are presented. The main findings can be summarised as follows. The dynamic pressure arising from the recirculation of the water is greater than the hydrostatic pressure due to the density defect. A strong jet is formed near the water free surface which in turn affects the dynamics of a floating structure located in the vicinity of the plume. High turbulence levels occur, with frequencies which could coincide with the natural frequency of the structures. Results of the dynamic behavior of a drill ship in such flows, are also discussed.

INTRODUCTION

When a subsea well blows out or an underwater gas pipe line breaks a large amount of gas is released into the water. The gas breaks up into bubbles which rise upwards into a turbulent plume above the release point. As the bubbles rise they carry a considerable amount of water along with them both in their immediate vicinities and in their wakes. These bubbles exert a drag force on the surrounding liquid. A typical value of the Reynolds number for the escaping gas, based on a pipe hole diameter, is of the order of 107. Hence the rising plume is turbulent.

As the plume approaches the free surface most of the gas escapes to the atmosphere while the liquid flow direction changes from predominantly vertical to radial, away from the plume axis. The plume axis however, does not remain at a fixed location. Bubbly plumes are in general laterally unstable. Although the detailed hydrodynamics of the lateral instabilities are rather complicated to analyse and not clearly understood at present, it has been observed that the plume meandering, from its vertical position, is of the order of the plume diameter. This corresponds to a time scale of 1.4 s for a plume rising in 700 m deep water. The flow is rotational and causes massive recirculation of the water.

In most cases, offshore structures or ships are present in the neighborhood of a blowout. The interaction of the two-phase plume with the structure or ships will cause an instability of the floating structure and there are many cases where the structures have been badly damaged. The gas escaping through the free surface is flammable (eg 80% methane) and it is therefore important to predict its dispersion under different weather conditions.
Fire Testing of Valve and Wellhead Equipment to API Specifications
Authors: Guice W.L. , Shinn T.L.
Published: October 2008

Math modeling and test data have been used to predict the temperatures of equipment in API fire testing. The thermal response of these systems is used to select critical parts for fire resistant equipment. Conditions of internal components were found to be calculable based upon the defined test criteria.

Introduction

Interest in fire protection for valve and wellhead components has increased significantly over the past two decades. In most cases, fire protection requires completion costs marginally higher than equipment not so protected, yet the net cost of the completion equipment is very minor when compared to the potential cost of a fire.

This was first dramatically illustrated in the Bay Marchand fire in the Gulf of Mexico, which took months to control, and cost millions. Since this incident, increased awareness of and associated costs of environmental protection have underscored such needs and interest. In addition to rebuilding costs, the price of a well fire must be considered in terms of the future value of the production from a given field or well, rather than the current value. Petroleum price increases and environmental concerns are likely to cause the future demand for fire resistance to grow much faster than the demand for wellhead equipment in general.

Current industry requirements as interpreted by API address two different levels of fire resistance. These levels depend upon the relative proximity of wells. A single isolated (onshore) well which catches on fire and poses no danger to nearby equipment or personnel needs only a system adequate to protect itself. It also has a different fire exposure potential as compared to a well on an offshore platform or a similar situation.

The isolated well, if leaking and burning, will feed its own fire only. If the equipment above the lower master valve is resistant to the expected worst conditions that might occur before the fuel supply is shut off, and the lower master is equipped to completely seal off as a response to this condition, fire safety may be considered adequate. If a worst case scenario is assumed, in which the entire Christmas tree is somehow blown off the well, the well is still a danger only to itself. Fire test criteria for a single isolated well therefore include the assumption that a potential worst case is a fire totally surrounding the well and fed by free convection air and well fluids.

The well in close proximity to other wells (normally offshore) has a far different environment. Such a well, when burning, presents a danger both to itself and to surrounding wells. Burning fuels from one well might impinge directly against an adjacent one, causing it to be endangered. This potential domino effect suggests that all equipment in the region of exposure should be fire resistant. As a minimum requirement a heat activated master valve shutoff coupled with a fire resistant tubing hanger would serve to shut the well down and minimize the fire.
Upheaval Buckling Failures of Insulated Buried Pipelines: A Case Story
Authors: Nielsen N-J.R. , Lyngberg B. , Pedersen P.T.
Published: October 2008

The first recognized upheaval buckling of a subsea, buried pipeline took place in 1986 in one of Maersk Olie og Gas AS' interfield pipelines in the Danish Sector of the North Sea.

It is the objective of this paper to present the case story of this pipeline upheaval giving a chronological description of all actions taken, in order to re-establish the pipeline integrity.

Based on the upheaval buckling experience within Maersk Olie og Gas AS, a recommendation for the design and installation of buried, hot pipelines is presented.

INTRODUCTION

During the annual pipeline inspection survey in July 1986 along the buried Rolf A/Gorm E two phase pipeline in the Danish Sector of the North Sea, a pipeline section was discovered to have protruded the seabottom, and was standing in an arch. The 17 km long pipeline is an O.D. 8.625" × WT 14.3 mm carbon steel line (API 5L grade X 52). The pipe is insulated with a 2" thick polyethane foam (PUF) of min. density 96 kg/m3 encased in a high density polyethylene (PE) jacket. The exposed PUF at the ends of the PE jacket is sealed with water tight end cap sleeves. A 2" thick concrete weight coating is applied on top of the PE jacket resulting in an overall pipe diameter of 0.45 m. A 3" gas lift line is "piggy backed" to the 8 " pipeline. The pipeline build-up is shown in Figure 1, and a detailed description of the pipeline is given by Pallesen et.al. (1985) in ref. [1].

The pipeline was laid in the summer of 1985 in 40 m water depth utilizing conventional lay barge techniques. Trenching of the line was carried out using water jetting equipment.

The pipeline was brought into service January 1986 for transport of unstabilized hydrocarbons with a temperature of up to 180°F (82°C) from the Rolf satellite field to the central process facility at Gorm.

Upheaval buckling analysis of the 8" line was carried out as part of the design documentation resulting in a lowering requirement of 1.15 m to top of the concrete coated pipe. The certified upheaval buckling calculations were performed according to the state-of-art at that time, i.e. using the "classical" upheaval buckling analysis, where the design criteria against upheaval snap buckling is based upon post buckling equilibrium curves assuming a pipe of uniform weight on a rigid foundation.

Following the detection of the exposure an upheaval buckling research programme was immediately initiated at the Technical University of Denmark. The results from the study showed that the "classical" design approach did not always yield conservative results. Thus, a new and improved theoretical model was developed and made available late 1986, and formed the basis for the repair work. The new design approach has been published in ref. [2], [3] and [4].
Often Overlooked Data Available From a Typical Offshore Subsea Survey
Authors: Mateer M.W.
Published: October 2008

Regular subsea inspect ion of offshore structures to assess the condition of cathodic protect ion systems is a way of 1ife in the Gulf of Mexico. In an effort to collect more useful data, new inspect ion procedures were implemented into the ARCO Oil and Gas Southern District platform inspections to see if it was possible to routinely calculate the current output of anodes using the anode resistance method in NACE RP-01-76. By trial and error, a potential sampling technique was discovered which allows the collection of the kind of potential data needed to calculate anode current with an accuracy similar to that possible with direct measurement with a gauss meter. The speed at which this data can be taken makes this survey technique no more costly than a normal potential survey while providing much more useful data.

INTRODUCTION

A typical underwater potential survey consists of measuring the potential of the structure against a standard reference electrode (usually Ag/AgCl) in order to insure the viability of the cathodic protection system. Although a great deal of data can be obtained, it is usually necessary to limit the scope of the potential survey to keep the time and cost reasonable. When planning for the ARCO Southern District 1989 platform surveys, a complete rethinking of our platform survey requirements was done to try and take the best advantage of the changes caused by the new MMS platform survey requirements.

As part of this rethinking, the idea of using potential measurements to survey anode current output was discussed with the survey contractor. It was felt that a usable correlation could be found between anode potential and anode current output using the calculation method recommended in NACE RP-O1-76. This was considered to be an "easy" addition to our survey that could be accomplished without an increase in effort. The main unknown factor was the proper location of the potential survey points needed to give the proper anode and cathode potentials for the calculation. Ideas on how to obtain the needed data were developed and added to the survey procedures prior to the start of work. In order to have a standard against which to compare the results, an underwater gauss meter was obtained for taking anode current measurements directly from the anode supports. During the surveys, direct current measurements and anode potentials were taken on 57 anodes on 13 different platforms.

ANOOE CURRENT CALCULATIONS

In theory, the output of an anode can be found by using the equation:I = E/R (1) where I is the current, E is the potential difference between the anode and cathode and R is the circuit resistance. Since the current density is much higher at the anode than the cathode and the resistance in the steel is negligible, the circuit resistance can be considered to be the anode to electrolyte resistance.