bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of Pile Foundation Bias Factors Using Observed Behavior of Platforms During Hurricane Andrew
Authors: Aggarwal R.K. , Litton R.W. , Cornell C.A. , Tang W.H. , Chen J.H. , Murff J.D.
Published: October 2008

The performance of more than 3,000 offshore platforms in the Gulf of Mexico was observed during the passage of Hurricane Andrew in August 1992. ?IMs event provided an opportunity to test the procedures used for platform analysis and design. A global bias was inform for overall platform capacity and loads in the Andrew Joint Industry Project (JIP) Phase 1.1 It was predicted that the pile foundations of several platform should have failed, but did not. ?lime results indicated that the biases specific to foundation failure modes may be higher than those of jacket failure modes. ?Ile biases in predictions of foundation failure modes were therefore investigated further in this study. ?he work included capacity analysis and calibration of predictions with the observed behave for 3 jacket platforms and 3 caissons using Bayesian updating. Bias factors for two foundation failure mess, lateral shear and overturning, were determined feat structure. Foundation capacity estimates using conventional methods were found to be conservative y biased overall.

Introduction

Hurricane Andrew was a very intense storm that passed through the Gulf of Mexico in August 1992. While most of the Gulf of Mexico platforms were not adversely affected by Andrew, twenty eight steel jacket platforms were significantly damaged. All of these were installed during 1948 to 1969 and were located in water depths up to 143 feet. In addition, forty seven caissons, nstalled during 1979 to 1991 in water depths up to 113 feet, were also significantly damaged. While foundation failure was identified as the primary cause of damage to most caissons, it was identified as the cause for damage of only one steel jacket platform.

An extreme event such as Andrew provides a unique opportunity to study offshore structures tested under fill scale field conditions. By reviewing the platforms that survived, were damaged or failed during the hurricane it is possible to improve our understanding of the behavior of platform during large storm. In October, 1993, Phase I of a joint industry project, "Hurricane Andrew - Effects on Offshore Platforms,''1'3 was completed. This project established that there was bias in the safety factor (capacity to load ratio) by combining the analytical and observed behavior of 13 jacket platforms. The inform bias is characterized as a correction needed to bring analytical results to agreement with the observed results.

The capacity analysis performed in Phase I of the Andrew JIP indicated that failure of foundation elements should have occurred in a majority of platforms analyzed, Since this was not observed during post-Andrew inspections, it was concluded that the deterministic analysis was conservatively biased. An overall (system) correction factor, with a mean of 1.2 was established. This correction factor was not specific to any particular failure mode in the jacket structure m its foundation but rather included failures of all types.
A Procedure for Predicting the Fatigue Damage of Structural Members in Unsteady Winds
Authors: Vandiver J. Kim , Fei Chen Yang , Campbell R. Brad , Rudge Daniel
Published: October 2008

The practice of assuming fill, steady state, vortex-induced vibration response, to wind is excessively conservative [1]. This paper presents a practical methodfor estimating the reduction of the fatigue damage rate due to the naturalunsteady fluctuations in wind speed. Two dimensionless parameters are shown tobe particularly important. The first is the ratio of the lock-in bandwidth tothe turbulence intensity level of the wind. The second is the ratio of thelength of time the wind speed remains in the lock-in interval to the rise timeof the member to steady state response levels. The paper also shows that onemust account for the discrete nature of wind speed and direction scatterdiagrams in estimating the probability of occurrence of the critical windspeed.

Introduction

A 1992 review [2] of state-of-the-art design calculations for wind-inducedfatigue damage of structural members revealed substantial excess conservatismdue to the assumption of steady state structural response to wind. Further workwas recommended to establish the effect of unsteady wind speed variations, turbulence, and finite structural response rise time. These factors have nowbeen investigated by means of wind tunnel tests, analysis of extensive NorthSea wind records, and development of appropriate dynamic and probabilisticmodels.

The theoretical results, wind tunnel data, and statistical analysis of the winddata have been published in two recent papers and a Ph.D. thesis [3, 4 &5]. This paper synthesizes these results in the form of a proposed, practicalprocedure for predicting the fatigue life of structural members excited byvortex shedding in wind.

In this paper the members are assumed to vibrate in the first mode in thecross-flow direction. The only types of members studied are restrained at bothends, with boundary conditions which may vary from pinned to fixed. Otherstructural configurations such as cantilevers could be addressed by the methodsdescribed here, but no emphasis has been given to such applications in thisstudy.

Assumptions, Definitions and Objectives

Accepted practice in the industry today is to compute D,,, the steady statefatigue damage rate that results from wind at the critical wind speed, V,, which causes maximum vibration response. This damage rate is then multiplied bythe fraction of the year that the wind is expected to blow at or near to thecritical velocity for that member. [n this paper three adjustment factors, YoY1 and Y1introduced, so as to obtain theadjusted damage rate, D,, as shown below,

(MATHEMATICAL EQUATION AVAILABLE IN FULL PAPER)

The first two factors, Y0 and Y1, account forthe unsteady behavior of natural winds and the finite rise time required by thestructural member to reach steady state, given the wind is at the critical windspeed. The third correction factor, Ybin, accounts for the use ofdiscrete wind speed and direction scatter diagrams rather than smooth windspeed probability density functions.
The Heidrun Field - Development Overview
Authors: Mitcha J.L. , Morrison C.E. , de Oliveira J.G.
Published: October 2008

Heidrun an oil and gas field lying in 345 meters of water off the coast of Norway. has been developed using the world's first concrete Tension Leg Platform (TLP). The TLP substructure. comprised of the Hull and Module Support Beams (MSB'S) is built of high strength lightweight aggregate concrete. The MSB concept eliminated the need for a module support frame and enabled the modules to be mated will the SUbStIUCIUI＿Cby ballasting and de ballasting, without the use of expensive heavy Lift vessels. The TLP topsides consists of five main modules and a drilling rig. The design concept of these large modules as self contained elements enabled them to be pre-commissioned to a Large extent at the fabrication yards, prior to load out. Sixteen tubular steel Tethers anchor the platform to four concrete Foundations on the seabed. These Foundations were towed to the field and Lowered into position by ballasting. again without the use of heavy lift vessels. Installation of a sub sea Well Template enabled the first wells to be pre-drilled and pre-completed before the platform was towed to the field. enabling an early production start after platform instillation. TIVO oil export pipe-Lines and one gas export line were completed onshore then MCI towed to the field using the controlled depth tow method. Titanium is used for the platform Drilling Riser, providing the same strength as conventional materials but with considerable weight savings. Produced oil from Heidrun is offloaded directly into shut ankles, without intermediate storage, using the innovative Submerged Turret Loading technology.

THE HElDRUN FIELD

Introduction. This paper first describes the main parameters of the field and the phases of the project development from discovery to first oil. The main components of the platform, sub sea development and export system arc described. The project organization is outlined. A description of the pre-operations drilling program is given. Construction of the concrete hull, fabrication of the topsides modules and marine operations. including module transportation and platform installation, arc reviewed. Emphasis is placed upon the novel aspects ofthc field development.

Field Location and Environment, Heidrun, which is an oil field with associated gas and gas cap, is located under the stormy waters of the Norwegian Sea, 175 kilometers from the coast. and covers an area of 38 square kilometers (9,000 acres). Water depth at the field is 345 meters. Fig. 1 shows the field location.

Discovery. The License for Conoco to explore and appraise the Heidrun field was awarded in 1984 and the first WCII was drilled in August of that year. The first well was a dry hole but the second WCII. completed in June 1985. encountered a 137 meler oil column in the Lower Jurassic Tile Formation, In addition. the upper part of the Tile Formation and the Middle Jurassic Fangst Group were found to be gas bearing, Seven more wells drilled on the block to confirm and delineate the field. Flow rates from the tests merged up to 930 m3 (6,000 barrels) per day.
Seismic Exposure and Site Response Characteristics for Offshore Platform Design
Authors: Grouse C.B.
Published: October 2008

Members of Panel 5 (P5) of the International Standards Organization (ISO) Working Group 3 (WG3) have developed earthquake design criteria for inclusion in 1S0's design guidelines for fixed offshore platforms. One of the components of these criteria was a procedure to determine the shape and level of the elastic design spectrum to be used in the computation of the design earthquake loads. The shape of the spectrum depends not only on the local geology at the platform site but also on the seismotectonic zone of the site region. The level of the spectrum depends on the seventy of the ground-motion seismic hazard.

Introduction

Various working groups and technical panels under the 1S0 have been working during the last several years to develop guidelines for the design of fixed offshore platforms worldwide. Several panels were convened to address aspects of earthquake resistant design including:seismic exposure and site response characteristics,structural and foundation design considerations,operation and performance issues, andprobability based earthquake load and resistance factor design concepts.

The members of WG3/P5 were responsible for developing the earthquake loading and response criteria within the framework of the Load and Resistance Factor Design (LRFD) approach, which has also been incorporated into the API RP2A guidelines for fixed offshore platform design.' A summary of the earthquake LRFD guidelines developed for the initial edition of the 1S() guidelines can befound in a paper by Bea3, published in these proceedings. A necessary component of the earthquake guidelines was the determination of the earthquake loads, which involved specification of elastic designs spectra. The procedure to specify the spectra is the subject of this paper.

Background

A primary ingredient in earthquake resistant design of offshore platforms is the specification of elastic design spectra that are used to calculate the earthquake loads. In the API RP2A guidelines' a simple procedure is provided to obtain these spectra in lieu of a site-specific study. According to these guidelines, the only parameters required to obtain the 5% damped elastic design spectrum for a particular offshore site are the local soil type at the site and the seismic zone in which the site is located. The local soil types in the API RP2A guidelines are (1) bedrock (Soil Type A), (2) shallow stiff soil (Soil Type B), and (3) deep stiff soil (Soil Type C). A site dependent spectral shape is presented in the API RP2A guidelines for each of these soil type. Seismic zonation maps for the offshore areas of the United States are also provided in these guidelines. Zones are designated as O, 1, 2, 3, 4, or 5, where Zone O represents negligible seismic hazard (e.g. Gulfof Mexico) and Zone 5 represents the highest seismic hazard (e.g. Gulf of Alaska). The API RP2A guidelines provide a table listing the ground accelerations for these zones, which range from O(Zone O) to 0.40g (Zone 5) in uneven increments.
Region and Site Specific Design Guidelines for the Northeastern Venezuela Development
Authors: Gajardo E. , Pagá M. , Sully J.P.
Published: October 2008

Several site specific studies were performed for the northeastern Venezuelan offshore development in order to determine the environmental parameters for the engineering design. The geotechnical parameters were obtained from the analysis of the soil borings, in situ tests and the high resolution seismic surveys. An evaluation of the seismic hazard was done, based on a detailed neotectonic study, the compilation of historical and instrumental seismological information, and an attenuation relationship developed for the studied area. Seismic response analyses were performed using the seismic parameters and dynamic characteristics obtained from the soil borings and in situ tests of shear waves, The met-ocean design loads of the local conditions were obtained from mathematical modeling bawd on in situ and regional measurements.

This study defines the platforms design conditions based on a probabilistic reliability approach and it has been used, among others, as a basis for the earthquake design guidelines proposed by the International Standards Organization. A sensitivity analysis was performed starting from the uncertainties of all the input parameters, in order to obtain the best estimate average design spectrum and associated coefficient of variability. The specific approach was to maintain the same safety index adopted by API RP2Adc, with a 'bias' modification factor that relates the site nominal spectra with the spectral acceleration that would lx used in order to satisfy the API requirements.

The results of this approach make possible the use of site specific detailed environmental data and the proven standard process established on the API RP2 codes, with significant cost reduction in terms of both platform and foundation design. The considerable amount of tectonic, seismological, and geotechnical information was the principal factor allowing the above methodology.

Introduction

This paper summarizes the environmental design loads to be applied in areas with WCII known site specific or local parameters and its associated uncertainties. Its make use of standard and recognized design criteria with the advantage of keeping the safety index and substantial cost reduction.

Seismic Hazard

Geology and regional tectonics. The north-west region of Venezuela shows a very complex tectonic setting controlled by the interaction of the Caribbean and South American Plates. The main active faults are El Pilar and Caribe with EW orientation and many other secondary faults with NWSE trend (Fig. 1 and 3).

Seismic Hazard Evaluation., The seismic hazard is defined as the level or value of the parameter representing ground movement (maximum acceleration, for example) that has a specific probability of being exceeded during particular defined period of time. Usually, what is obtained is the annual probability from which any other time span can be obtained.

The parameters were obtained from the existing data bases and a seismic attenuation relationship was developed for the region
Typhoon Emergency Response Planning for the South China Sea
Authors: Corona E.N. , Lynch R.D. , Riffe D. , Cardone V.J. , Cox A. , Chen H.
Published: October 2008

This paper describes the development, implementation and performance of a comprehensive typhoon emergency response plan (ERP) utilized during 1995 by Arco China Inc (ACI) for their offshore Hainan Is. South China Sea development. An important component of the enhanced plan is a new system to forecast winds and sea stales generated by tropical cyclones (TC) built around known uncertainties in forecasts of cyclones and well proven numerical models of the TC surface wind field and (he spectral wave field. The forecast system provides specification of time histories of the winds and waves at the site for the nominally predicted track as well as the probabilities of exceedance of critical evacuation Thresholds of wind speed and sea slate. The ERP and forecast system were operated throughout the 1995 typhoon season and evaluated at the Yacheng development, which was seriously threatened by 15 tropical cyclones between June and November. The response to these threats in terms of interruption of operations, partial or total evacuation of offshore personnel and average downtime is describe and compared to previous experiencewhich used more conventional forecast services evaluation has shown [he new system to provide significant benefit in terms of safety, efficiency and cost savings. The wind and sea slate forecast histories provided year-round by the forecast system are also of significant benefit to the management of floating production systems.

Introduction

The intensity and track of tropical cyclones are notoriously difficult to predict accurately. Faced with such uncertainties offshore operators in areas affected by cyclones (e.g. South China Sea, Gulf of Mexico, NW Australia) typically base response decisions on the predict entry of a tropical cyclone into a large watch circle, without regard to knowledge of quantifiable factors such as the uncertainty and confidence in the predicted track of a particular system, and the surface wind speed and wave height history to be expected at the offshore work site for the specific event, Such a strategy could lead tounnecessary false alarms resulting in risks to life and equipment caused by the evacuation and shutdown process, and costly downtime. Conversely, simple distance-to-site weighted decisions fail to account for the sometimes significant winds and seas generated by large but distant storms or storms with anomalous circulations, such as typhoon-northeast monsoon hybrid events in the South China Sea. This paper describes the development, implementation and performance of an enhanced emergency response plan (ERP) of Arco China Inc. (ACI), whose operations were greatly expanded in 1995 in terms of construction and drilling activities and the number of offshore personnel. The update of the ERP was considered necessary because past experience raised serious concerns that previous practices might entail considerable risk when they lead to unnecessary evacuations of large numbers of offshore personnel.
Experience in Float Over Integrated Deck - Design and Installation
Authors: Sigrist J.H. , Naudin J.C.
Published: October 2008

ADSTRACT

Since early 1980, Technip-Geoproduction (TPG), as designer or as installation contractor, has been using with success the float over system "UNIDECK-TPG" for the transportation and installation of integrated decks for offshore platforms. The concept offers the advantages of significant savings in transportation and installation cost by minimizing the installation time and offshore hook-up and eliminating the need for a heavy Lift derrick barge.

The paper describes the technology used for the installation, the required engineering studies, the consequences of using such a concept on platform design and the selection of an appropriate barge size to be used.

INTRODUCTION

TPG has developed the integrated deck concept, called UNIDECK-TPG, with the objective at minimizing the overall cost by offering the advantage of having a deck which can be installed on a jacket as a single unit, filly completed and tested without using a conventional crane barge.

The concept has been successfully used several times in both favorable and more severe sea conditions with deck weight ranging from 2,500 to 9,500 metric tons.

The technology combines ballasting and jacking to improve the stability of the cargo barge during the transportations phase and by jacking to provide a safe and quick transfer of the deck weight onto the pre-installed jacket.

After having designed platforms in shallow waters as jack-up, this method was used first by TPG for (Fig. 1) :KOC Southern Gas Project (in early [980),the Ethylene Offshore Terminal in Egypt for EGPC (2,300 tons),the relocation of Zakurn Accommodation Platform (7,000 tons) for ADMA OPCOthe ADNOC Khuff Gas Production Platform (2,500 tons),

and recently for :" the North Field Qatargas Process and Utilities Platform (7,500 tons),the COB-PI Production Platform, for Sonangol and for Elf Exploration Angola (9,500 tons) for which TPG acted as general contractor. The deck has been installed early 1996 with 1.2 m significant wave height. This is the first time that such installation method has been used in the long swell of south Atlantic Ocean.

The UNIDECK-TPG method is applicable to three main categories :in shallow water where there is not sufficient draft for a derrick barge to enter the site," when heavy lift derrick barges are not readily available resulting in a prohibitive mobilization cost,when an integrated deck would be too heavy for existing derrick barge.

In each case, the installation method can be adapted to the environmental conditions and to the weight and final elevation of the deck so as to minimize the cost of the operation.
Installation of the Troll Phase I Gravity Base Platform
Authors: Andenæs E. , Skomedal E. , Lindseth S.
Published: October 2008

The TROLL Phase 1concrete Gravity Base Platform is located in 303 m of water in the Norwegian Trench some 80 kilometers northwest of Bergen. The platforms wi11be a major gas supplier to the European market far into the next century. This paper describes the major aspects in the design, preparation and performance of the platform installation operation.

The extreme height of the structure was a challenge for design and performance of the marine operations, particular when passing a "shallow area" with minimum depth of237 m. The foundation soils at the Troll Field required skirt piles to record breaking 36 m depth in order to sustain the extreme North Sea weather conditions.

The potential of intolerable horizontal soil pressure on the skirt walls from large soil displacements during penetration was the dominating aspect of the skirt penetration. Extensive engineering supplemented with model testing and planning were conducted in the development of systems and procedures for monitoring and manipulation of acting loads on the skirt walls.

The success of the design, planning and performance of the operation is documented through comparison between observed and predicted performance of main operation parameters.

Introduction

Field Information, The TROLL Phase 1Gas Platform was installed in May 1995. The Troll Field is located in the Norwegian sector of the North Sea. The platform will be a major supplier of gas to the European market far into the next century. Design operating life is 70 years and the maximum production rate some 84 × 106 Sm3/day (3 BCF/day).

Norske Shell was appointed as field development operator in 1988. The contract for engineering, procurement and construction of the concrete Gravity Base Structure (GBS) including tow out and installation of the platform at the Troll Field was given ?)Seconded to Norske Shell during project.

Tables and figures at the end of the paper, to the Aker company Norwegian Contractors in March 1991,. Watoil will take over as production operator in June 1996.

Platform Design and Site Conditions. The Troll Field is in the Norwegian Trench. At the platform location the water depth is 303 m, The upper 74 m of soil consists of more or less normally consolidated, homogeneous clay. From seabed to 16.5 m depth the clay is sofi to firm with high plasticity. This layer is called Soil Unit I. In Soil Unit 11, below 16,5 m, the plasticity becomes medium. The strength increases gradually by depth, A summary of soil data is given in Figure 1.

The 472 m high structure including topsides is the tallest structure that has ever been moved on the earth's surface. An artists view of the platform is shown in Figure 2. The substructure is made of concrete and is a Co deep SP-4 -19-R design, comprising skirt piles, 19 caisson cells, one Siegel and four shafts. Figure 3 provides a general view and a cross section.
Popeye Project: An Overview
Authors: McLaughlin D.C. , Atford B.J.
Published: October 2008

This paper presents an overview of the Shell Offshore Inc. (S01) Popeye Project, a remote subsea gas development in 2040 ft. of water in the Gulf of Mexico (ref. OTC Papers 8126, 8127, 8128, and 8169 for more technical details). Planning and execution of the Project required a balance throughout between proven methods, cost reduction, requirement for extending technology, and the desire to develop a system which could be used as a stepping stone to future deep water prospects. Popeye was successful]y installed and started up in January 1996. It represents application of an innovative, yet cost-effective, field development system which advanced the state of deep water subsea technology.

Introduction

In 1985, S01 discovered Popeye, a gas field in the Green Canyon Area. A total of nine exploratory wells were drilled, and a four-block unit was approved in 1988. Sol is the operator and has a 37.5% interest. Partners include Mobil Exploration and Producing Co. BP Exploration Inc. (12.5%), and CNG Producing Co (37.5%), who purchased half of S01's share and joined the other Unit participants in 1992.

Joint subsurface and surface development study were initiated in 1989, including consideration of a wide range of compliant structure, floating, and subsea options, processing options, and numbers of wells. With reserves smaller and riskier than originally anticipated, economic evaluations led to a focus by 1990 on satellite subsea development. Subsea feasibility and preliminary design studies addressed technical References and Figures follow paper and cost issues over the next year. However, low product prices made even a subsea solution marginally economic.

S01 formed a Popeye Subsea Team in 199 I (the genesis of current Subsea Systems Team) to tackle the dilemma of how to make Popeye an economically attractive development, while dealing with the severe application requirements of high pressure, deep wsster, and long offset distance. An additional challenge was the desire to utilize technology which could be a springboard for many other, even deeper S01 prospects.

The challenge was met and the development plan approved by the Popeye Partners in March 1993. Key elements of the plan were phased development utilizing fewer, high rate wells, and smaller flowlines and topside facilities. Also, several innovations promised reduced costs and better economics over traditional subsea practices, and represented necessary evolvement for the future. The Popeye Project Team was formed and the project successfully executed by January 1996, Despite difficulties which more than doubled the duration of planned drilling activities, the Project was within original budget and only 3 months later than original schedule.

System Description

The Popeye reserves were deposited in two separate reservoirs within Green Canyon Blocks 72, 73, 116, and 117. The phased development plan includes two Phase 1 subsea wells, directionally drilled from the subsea system location between the reservoirs on Block I 16 to bottom hole locations on Blocks 73 and I I6.
Popeye Project: Completion Riser/Workover Control System
Authors: Guinn R.M. , Parks W.C. , Forster L.D. , Pritchard J.J.
Published: October 2008

In 1993, at the beginning of the Popeye Project, Shell Offshore Inc. (S01) entered into an innovative commercial agreement with Sonsub Inc. (Sonsub) to develop a technological first in the area of completion work over riser systems, Sonsub would design, manufacture and test a new concentric bore Completion Riser/Work over Control System rated for use in water depths of up to 6,000 ft. SOI would then lease the equipment on an as needed basis from Sonsub. This type of relationship proved to be an efficient approach of introducing new technology to the industry and managing the higher costs of deepwater developments.

Introduction

As the industry continues to extend subsea developments to deeper waters with higher pressure reservoirs, the operating limits of the required equipment (such as subsea trees, wellheads, drilling rigs, lay barges, etc.) are being constantly stretched. The commercial issues involved in funding these deepwater developments are also becoming increasingly more complex due to the high costs of the equipment and the ever important length of time to first production.

One of the key equipment components necessary to complete and operate developments is the completion riser and work over control system. This paper will brieflyoutline the methodical approach taken by Sonsub and SOI throughout the initial design, manufacturing and testing.

Stages and it will describe the commercial arrangement between S01 and Sonsub. It will also briefly describe the unique and universal Completion Riser Work over Control System and narrate the results of its first offshore use on the Popeye Project. A summary will follow of the ongoing additions/modifications necessary to meet the world record water depth requirements of S01's Mensa Project.

Background

During the early planning stages of Popeye, SOI had recognized many new technological issues that would have to be solved in order to develop Popeye and its other deepwater prospects in the Gulf of Mexico, Sonsub had also surveyed several offshore operators, including SOI, in regards to a 'Universal' deepwater completion riser and work over control system which would accommodate existing equipment from the various subsea equipment manufacturers. Various types of riser and riser coupling designs, riser spider designs, riser handling methods and various controls equipment packages were reviewed. Operations off shore were discussed in detail and, while several operators expressed a preference for a conventional dual-bore, integral non jacketed riser, most recognized that the existing designs for these types of risers were not adequate for deepwater applications, especially in water depths beyond 3,000 ft. Most operators also acknowledged the suitability of a concentric riser, if a reliable method of accessing both bores was available.
The Unusual Construction Aspects of China's Yacheng 13-1 Gas Pipeline - The World's Second Longest Subsea Pipeline
Authors: Woolgar A.F. , Wilburn J.S. , Zhao X.
Published: October 2008

There are many unusual construction aspects relating to China's Yacheng 13-1 Pipeline. Initially planned as an onshore pipeline it was later to becomeAsia's longest subsea pipeline.

The route chosen resulted in an offshore pipeline requiring many unique andinnovative construct ion techniques as well as unusual pipeline installationconstraints.

The pipeline was installed in two phases. The first phase of 707km was to bethe longest pipeline ever constructed within one lay season and with one layvessel in a continuous programme. Upon completion of the second phase of pipelay works, the world's longest ever subsea pipeline flooding in one run of778kms was to follow.

The Yacheng 13-1 construction requirements for pipelay and post installationworks, including testing and commissioning were extremely demanding.

This paper details how these requirements were met. It covers routeselection constraints, construction techniques utilised and the demandingpigging and pre-commissioning operations performed.

INTRODUCTION

By means of the Yacheng 13- 1 Pipeline, sales quality gas will betransported directly from the offshore facilities via a subsea, 28 inch (711mm) outside diameter (OD) pipeline, 778kms in length, to an onshore facilitynear Hong Kong at Black Point, where it will be treated, metered and delivered. The South China Sea map indicating the pipelines layout is shown in Figure1.

A portion of the gas stream and condensate will be sent via a 14 inch(356mm) OD, subsea pipeline, 91 kms in length directly to a shore facility nearNanshan on Hainan Island, where the natural gas and condensate will beseparated for delivery and storage respectively.

Installation of the 778kms of 28 inch trunkline was awarded to a SaipemSpA/European Marine Contractors Joint Venture (SEJV) in two phases. Phase 1, installation of 707kms, in April 1993, and Phase II, installation of theremaining 71kms of 28 inch including the installation of a 91 km 14 inchpipeline, in April 1994.

The owners of the system are Arco China Inc., China National Offshore OilCorporation (CNOOC) and Kuwait Foreign Petroleum Exploration Company(KUFPEC).
Some Corrosion Concerns for Girth Welds in CRA Clad and Lined Flowlines
Authors: Craig B.D.
Published: October 2008

Introduction

It is common practice in the petroleum industry to apply two ASTM standard corrosion tests (o corrosion resistant alloys (CRAs) as a means to determine their relative corrosion resistance compared to other alloys and as a quality control method to ensure no manufacturing processes have promised this corrosion resistance. The ASTM G 48 test for pitting resistance in ferric chloride solution is applied in both cases above and the ASTM A 262 Practice E is used in the latter. The A 262 Practice E is also required by API 5LD. Although the G 48 test has generally been successfully applied for ranking the pitting resistance of stainless steel and some nickel base alloys the application of the G 48 and A 262 tests for manufacturing control and for the evaluation of welding procedures has been less than satisfactory, often leadingto conflicting results.

This paper will not attempt to explore all of the myriad problems that have been encountered in applying these two tests but instead on two speed problems that are consistently encountered in evaluating the welding of CRA lined and clad Iine pipe. These two problems are the testing of the inside surface of the liner and red pass of a girth weld to determine the effect of discolouration (heat tint) on the corrosion resistance of the weldment and selective corrosion of the test coupon from the backside (i.e. the side of the cladding or liner on the side nearest the steel) of the test coupon in preference to the root bead side.

In both cases the tests are carried out using the G 48 Method A, generally at 22-25° C for 72 hours.

Standard Test Method and Variations

The standard G 48 and A 262 tests specific that the test specimens be polished to a uniform finish on all surfaces with a 120-grit abrasive paper.

Figure 1 shows how manufacturers and test laboratories often prepare the test coupon. It is obvious that this means of coupon preparation will not test the actual surface properties of the material tier fabrication and furthermore, it is doubtful that the pitting behavior will be affected at all for a coupon of this type regardless of the condition of the inside surface of the clad or liner weldment. Yet it is in keeping with the requirements for coupon preparation according to A 262 and G 48.

For clad and lined pipe welds it is imperative that the back side of the coupon representing the side facing the steel be thoroughly machined to remove iron contaminants that can compromise the test results by producing premature pitting and corrosion on that side before pitting can proceed on the root side of the coupon.

It is more appropriate to leave the root bead and CRA clad or liner inside surface in its original condition in order to determine the behavior of these weldments in service.
Design, Fabrication and Installation of the Mooring System for the Troll B Concrete Oil Production Platform.
Authors: Mørland M. , Frydenlund O.
Published: October 2008

The Troll B Platform is the first purpose built catenary anchored concrete production platform. The project represented a large challenge both to overall project execution and contract strategy as well as within various disciplines. The mooring system represented certainly one of the challenging areas.

In order to safely anchor the platform it was necessary to develop the largest mooring system ever. The design fabrication and finally the installation of the system all represented challenges. The system was, however, installed within planned schedule and budget in July 1995 and has so far functioned according to the expectations.

Introduction

This paper gives a presentation of the development work for the mooring system for the Troll B concrete production platform, see Fig. 1, The presentation includes discussions related to design of the system, based on the given boundary conditions and criteria, as well as fabrication and installation. Technical challenges and considerations to contract strategy in search for the cost optimum system is discussed including aspects related to operational phase, the inspection and maintenance philosophy,

With the size and properties of the platform itself more or less fixed, ref. key in Tableto design a suitable mooring system.

In order to reach a cost effective system it was focused on two overall design principles:Dimensions of the chain and wire should be within certified dimensions (DnV)Installation of the system should be possible from relative conventional marine operation vessels avoiding expensive equipment and vessels.

With the given boundary conditions the mooring system solution is a segment chain/wire rope system with large dimensions, see Table 2 and Table 3.

Design

General. The design of the mooring system for the Troll B platform aimed at an optimisation with respect to both composition of line segments/number of lines and individual segment length and diameter. Fig.2 shows a general view of a mooring line including the positions for the connection and retrieval elements.

The analysis methods described in the following will cover both the mooring lines and special components in the mooring system such as connection and retrieval elements and fait-lead / chain interaction problem.

Design Criteria. The design of the mooring system is governed by statutory requirements as well as functional requirements. The major design requirements are:Safety factors according to NMD (Ref. 1,2).Maximum platform offset of60 meter.All mooring lines to have winches.Passive mooring system, No adjustment of tension during extreme weather conditions,Possibilities of diverless replacement of fairleadsNo retrieval of mooring lines for planned, regular inspection.Installation/Retrieval of mooring lines to be performed by the use of 'conventional' equipment and vessels.Required design life is 25 years
Subsea High Integrity Pressure Protection Systems for high pressure oil and gas developments
Authors: Theobeld M.C.
Published: October 2008

With oil and gas operators now focusing on smaller assets to develop, every opportunity to reduce costs, with due consideration to safety is being carefully considered.

By derating the transportation flowline substantial cost savings are possible. In the past this would not have been allowed for safety reasons, as the flowline was required to be rated to the maximum pressure from the reservoir.

HIPPS is a new subsea technology which allows the high pressure specification flowlines to be safely derated between the manifold and host platform. This is achieved by reliably isolating the high pressure product before the specification break of the lower pressure rated flowline.

The system is designed to failsafe under all operating conditions. Commercial evaluations are given to justifi the technology. The HIPPS control system is described in detail together with summarized reliability data.

Introduction

High Pressure/High Temperature (HP/HT) subsea hydrocarbon developments are now being actively pursued in many Central North Sea areas. These prospects tend not to be large reserves but may have Closed In Tubing Head Pressures (CITHP) in the region of 10,000 psi. This leads to marginal economics of such fields, when the cost of higher specification flowlines are taken into account.

Subsea HIPPS presents an option for justifying HP/HT developments, by allowing high pressure flowlines to be derated to standard pressure flowlines, at considerable overall cost savings.

The HIPPS system provides a reliable failsafe means to protect and isolate the derated flowline at the subsea installation from the high pressure at the wellhead. HIPPS works in parallel with the standard control and safety systems, which would all need to I before HIPPS comes into operation. HIPPS also allows potential cost savings in the topside piping system and a reduction in the platform risk levels by a reduction in system pressure.

The control system for subsea HIPPS is separate from the well control system for the subsea equipment having dedicated power, communication and hydraulic lines, These may be shared in a common umbilical with the production control system, and are integrated into the surface control computer and hydraulic/electrical supply units.

Typical costs savings for a step-out distance of 9 km can be in the region of UK E13 million compared to a fully rated flowline system. This saving may be reduced by selecting a ?no burst' option in order to maximise safety considerations. Based on thorough reliability and risk assessment models Ref. 1 it has been shown the subsea system is extremely safe with the risk of a flowline failure in the order of 1.7E-04 per annum or once per 5900 years.

The control hardware used for subsea HIPPS is based on a thoroughly proven topside, certified fixed logic HIPPS system, which has then been marinised for subsea use. The principle feature for the safety critical controller is its ability for failsafe operation under all modes of failure.
Liuhua 11-1 Development- Phase I Installation
Authors: Sorrel David , Green John D. , Florida Mark J. , Ming Chen , Sheridan John
Published: October 2008

The Liuhua 11-1 Field is situated in 1,020 ft (310 m) of water in the South China Sea. The Liuhua 11-1 Development Project includes a floating production system and floating production, storage and offloading vessel with joining pipelines and risers. The installation occurred in two phases occurring over 12-months to take advantage of two favorable weather seasons.

Phase I, which forms the basis for this paper, was executed during May-July 1995 and includes laying of the moorings for both vessels and the hook-up of the FPS to its moorings. The scope of work and interface management required for installation of 21 mooring legs in this water depth is of particular importance. The vertical lay and tension system designed specifically for this project represented a large financial and engineering investment, The system was designed to lay the eleven mooring legs for the FPS and, ten mooring legs for the FPSO, and to tension the FPSO anchors to 1,323 kips (600 tomes) at the anchor. The system had to handle three sizes of stud link anchor chain and two sizes of bare spiral strand wire rope.

The Phase H installation of February-April 1996 includes connection of the FPSO to its moorings and installation of the three pipelines and their risers.

Introduction

An overview of the Liuhua 11-1 Development Project is presented in OTC 8172 (Ref. 1) and Fig. 1. The development includes a floating production system (FPS), Nanhai 7Tao Zhan, permanently moored over subsea wellheads in 1,020 ft (310 m) of water. Its conversion is detailed in OTC 8187 (Ref. 2). It is a modified semi-submersible drilling rig equipped to provide drilling services and operate the subsea systems. Crude-burning generators on the FPS supply power to an eleetric submersible pump (ESP) in each well. Details of the ESPS are presented in OTC 8176 (Ref. 3).

An overview of the subsea system is presented in OTC 8175 (Ref. 4). Produced well fluids are commingled in a subsea manifold located below the FIN and exported via two 13.5-in. flexible production lines that are linked to the manifold through independent tie-in bases and rigid jumpers. The two production lines together with a 6-in. flexible test line pass along the seabed from the tie-in bases to the floating production, storage and offloading (FPSO) vessel, Nanhai Sheng Li, located approximately 1.8 miles (3000 m) northwest of the FPS (Fig 2). The pipelines are reviewed in OTC 8188 (Ref. 5). They are made of flexible pipe and are connected to dynamic risers supported by discrete buoyancy collars. The pipelines are attached to the FPSO turret in a lazy wave configuration.
Liuhua 11-1 Development-Design and Fabrication Considerations for Nanhai Sheng Li for the FPSO
Authors: Frantz J. Paul , Koster Thomas E. , Yu Liang , Haire William  M. , Shimamura Yoshihide
Published: October 2008

This paper describes the development, design, and fabrication of the crude oil process facilities, and the conversion of an existing tanker for use at the Liuhua 11-1 Field. Over a 16-month period spanning 1994 and 1995, Amoco Orient Petroleum Company, and partners, China Offshore Oil Nanhai East Corporation (CONHE), and Kerr-McGee China Petroleum Ltd., converted a crude oil tanker originally built in 1975 to the Nanhai Sheng Li, the floating production, storage and offloading (FPSO) facility for the Liuhua 11-1 Field, The FPSO will process up to 65,000 BOPD produced from 20 subsea wells located 1.7 miles away. In addition to the processing facilities for produced oil and water, the FPSO has a processed crude oil storage capacity of 715,000 bbls. The ship's propulsion system was removed during the conversion, because the FPSO is permanently moored at site by means of a lo-point, 'soft' mooring. The mooring system was designed to survey the 100-year-retum-period typhoon. Several unique aspects of the ship's conversion process facility, and mooring system design are discussed. Process design aspects include the flexibility to accommodate wide variations in produced water-oil ratio and total volume, the design considerations of the large water and crude processing equipment, vessel motions during operation, and equipment survival during storms. The FPSO design discussion focuses on global hull strength for surviving a 100-year typhoon. Special design requirements for the mooring turret structural integration to the converted tanker are also discussed.

Introduction

The South China Sea hydrocarbon reserves are difficult to develop. The Liuhua 11-1 Field is reasonably typical, but has some unique features:The water depth is approximately 1,020 ft (310m); the location is about 120 miles (200 km) from shore.The metocean environment is such that major storms (typhoons) occur frequently.The site has solitons (internal waves) generated by tidal variations in the Bataan Strait.The crude in the reservoir is parafflnic, asphaltic, and contains both C02 and H2S in moderate quantities.

The primary elements of a successful FPSO are:The shipThe mooring systemThe process facilities

The solution to the FPSO design problem started with the selection of a vessel suitable for service as an FPSO in the design environment. Following this, the mooring system could be designed. The production facilities could be designed to accommodate both the processing requirements and the motions expected of the vessel.

The ultimate requirement for an FPSO is to produce and store crude until it can be off-loaded to a shuttle tanker. In order to do this, it must have a reasonably stable platform and be capable of staying on-station during major storms.