bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Mooring Method for Installation of Enserch Mooring Legs Garden Banks 388 FPF
Authors: Honig H.J. , Koolwijk W. 
Published: October 2008

ABSTRACT
In the fall of 1994 HeereMac v.o.C installed the 12 mooring legs for Enserch Exploration's Floating Production Facility in Garden Banks Block 388 in the Gulf of Mexico with the SSCV Balder. The installation of the catenary mooring system, each leg comprising several raying sections of spiral strand wire and chain, required sufficient handling and manocuvrarability power of the vessel, while enough holding capacity and stiffness of the system had to be provided.
The most important aspects of the actual installation of the mooring legs are explained, for example, the w of a purpose built tipping winch.
The method selected by HeereMac for station-keeping the Balder was to use a minimum number of anchor lines in combination with a tug, in order to maintain position and at the same time have an easy and controlled method of manoeuvring to a new position. Themethod of station-keeping the SSCV in this way is part of a development towards full position control with a spread of tugs. In this paper the station-keeping system is described and the offshore experiences with the system are discussed. Some future developments with respect to tug-assisted station-keeping systems are highlighted.

INTRODUCTION
In November 1994 HeereMac v.o.f installed the mooring system for the Ensach Garden Banks Floating Production Facility (FPF). The installation took place in Garden Banks Block 388 in the Gulf of Mexico and was performed by the Semi-Submersible Crane Vessel (SSCV) Balder. The water depth at the installation site varied from 2100 ft. to 2550 tl.. The FPF mooring system consisted of 12 mooring lines in a regular pattern (at intervals of 30 degrees) with leg lengths varying between 7650 ft. and 9000 ft. (see Figure 1). Allmooring leg components were delivered by Enserch to the HeereMac base port in Fonrchon (Louisiana), where all components werechecked and marked, and trial tit-ups were performed. The mooring leg components were transported from the base pat to the installation site on three barges, a 250 tl. × 72 tl. barge for the transport of the chains of the fust six mooring lines, a 260 ft. × 72 tt. barge for the chains of the remaining six mooring lines, and the MWW03, a 400 tl. × 105 ft. barge, for the transport of all the othermooring leg components.
Only twice was it necessary to transfer a full batch of all components of six mooring legs from the cargo barge to the &ck of the SSCV (see SSCV deck lay-out, Figure 2). Before the job started all systems had been extensively tested in order to avoid surprises during the installation. Each anchor had to be set within an envelope measuring 100 ft.perpendicular to the leg and 50 ft. along the leg direction around the anchor setting co-ordinates.. The anchor lines had to be installed within a corridor of 50 R. on either side of the target-setting line. This paper gives a description of the project and the installation aspects. Special attention is paid to the station-keeping of the SSCV.
Dynamics of a Near- Surface Pipeline Tow
Authors: Binns Jonathan  R. , Marcollo Hayden , Hinwood Jon , Doctors Lawrence  J. 
Published: October 2008

1. Introduction
This project arose from a series of experiments carried out by the Melbourne node of the Australian Maritime Engineering Cooperative Research Centre (AMECRC) at Monash University in 1993 for the Australian Marine and Offshore Group Pty Ltd. During these experiments, a model pipeline string simulating a 400 m long full-scrde pipe was tested for a 15 km near-surface tow to deep water. The pipe was made approximately neutrally buoyant by the use of buoyancy cans and chains. It then acted as a beam excited by the waves.
The main concerns for this operation were that, under all expected wave conditions, the pipe stresses should not be excessive, and an estimate for the power required to tow the pipe should be determined for a range of waves and towing speeds. It was considered that an experimental study was necessruy because of uncertainties and the non-linear nature of the processes.
This paper reports on an experimental and computational sequel to the original testing project, aimed at developing and veri&ing a numerical model of the pipeline response to wave action. The overall aims of the research conducted were to uncover the relationships controlling the transverse vibration of a smooth pipeline at near-surface depths in waves by including towing speed and back tension. In the following sections, the problem is specified, the numerical method developed and sample output fi-om the numerical method presented. Sections 5 and 6 describe the experimental procedure and results. Sections 7 and 8 compare the numerical results, draw conclusions and suggest some applications of the results.

2 Predictions of Pipe Motions

2.1 Problem Formulation
The first task in predicting the pipe motions was to derive the differential equation governing the motion of the pipe. This was done by balancing the forces on a small element of pipe. The element of pipe considered is shown in Figure 1. This is the standard element used in vibrational analysis of a beam with the inclusion of the hydrodynamic forces. In the figure, V is the internal shear force due to the adjacent pipe elements, M is the internal bending moment and T is the tension force supplied by the adjacent pipe elements. The pipe is considered to be neutrally buoyant. Hence, its weight has not been included. The virtual mass in the equation consists of the actual mass of the pipe element plus the added mass. The hydrodynamic loading for a slender cylinder is assumed to be described by the Morison equation with drag and inertia coefficients taken from Sarpkaya and de St.Q. Isaacson (1981).

2.2 Equations of Motion
The final differential equation is
(Available In Full Paper)
where p is the water density, d is the pipe diameter and Cd and Cm are the Morison drag and inertia coefficients. Also in Equation (l), EI is the bending stiffness of the pipe, T is the tension in the pipe, A is the cross-sectional area of the pipe and & is the velocity of the water due to wave action.
High Integrity Pressure Protection Systems for Production Applications
Authors: Langvik S. , Aarebrot E. 
Published: October 2008

ABSTRACT
Through the use of a High Integrity Pressure Protection System (HIPP$) the flare capacity of a well head platform can be reduced to the flowrate required for depressurisation. The HIPPS may also be used to reduce the are capacity of a process plant. By the use of HIPPS, the discharge of hydrocarbons or carbon dioxide due to venting/flaring is reduced.
This paper describes the development of HIPPS for the Sleipner B-platform offshore Norway. A 20" multiphase pipeline is protected against overpressure by two 20" quick acting shut down valves (QW installed in series, instead ofpressure safety valves. The valves have been qualified for operation in well stream at a shut-in pressure of 336 bar, and have a closing time of 2 seconds. Each of the QSKS has independent, fail safe instrumentation circuits. A parallel rain of QSV.s has been installed due to the testing requirements. The estimated saving using HIPPS on SLB was $25 mill.
The paper also discuss existing and new applications of the HIPPS.

INTRODUCTION
The Sleirmer Vest is a gas field, containing 33 billion Sm 3 of sales gas 29 million of code oil and; mill. tons of NGL. The development consists of two platforms, a wellhead platform (SLB), and a gas treatment platform (SLT). Platform production is 20.5 mill Sm3/Dof sales gas and 450 Sm3/hrof condensate(including NGL). Sleipner Vest will come on stream in 1996.
The well head platform is connected to the treatment platform via a 20" multiphase pipeline. The Sleipner Vest interfiled pipeline has a design pressure of 160 barg, while the wellhead shut-in pressure on Sleipner B is 336 barg. It is therefore necessary to protect the pipeline against the wellhead pressure. The flowrate in the pipeline is 250 kg/s. The main scenarios for over pressure in the pipeline was considered to be hydrate formation, pigging and closing of the inlet valve on Sleipner T.
A flare system designed for blocked outlet, i.e. fill flow, is Expensive at the high flow rate required (250 kg). It was therefore decided to use a HIPPS. The HIPPS on Sleipner B is shown in figure 1.

PROBLEM DESCRIPTION
For this paper HIPPS is defined to be a system for Over pressure protection of process equipment by utilizing dedicated shutdown valves. The HIPPS system protects the equipment against over pressure by closing down the source of the over pressure.
HIPPS has been used offshore in production systems for several applications, mostly for tie-ins of new fields to existing platforms, or as a modification to platforms where the flare capacity is limiting for the oil production. A number of different valve types, instrumentation concepts, valve configuration etc. has been used. In terms of equipment, valve configuration etc.
API RF'14C, ref. /1/, has traditionally been used for design of process safety systems offshore, but does not describe the application of HIPPS. Overpressure protection by the use of double shut down valves is permitted for wells, but the use of additional PSVS are still recommended by API.
Analysis of Jack-Up Units During Transit With Legs Lowered
Authors: Chakrabarti Partha , Halbleib Byron , Laird John 
Published: October 2008

ABSTRACT
Conventionally jack-up units are transported from one location to another with the majority of their legs extended above the hull. On certain occasions, due to possible storm conditions, they must lower their legs below the hull significantly to maintain expected vessel motions within an acceptable level. During a storm, the unit will respond with six degrees of motion while afloat. The extended portion of the legs below the hull will be subjected to drag loads. Unlike the condition with legs extended in air, analysis of a jack-up with its legs lowered below the hull has not been widely reported in published literature. The present paper reports the motion analysis of a jack-up for different leg drafts and indicates the safe limits up to which the leg can be extended below the hull without overstressing it.

INTRODUCTION
When a jack-up unit is in a transit condition either during a field move or during ocean tow, there is always a probability that it cou [d be subjected to a storm. For afloat operations, the rig must meet the stability and structural criteria prescribed by the classification societies, such as ABS1. For rigs in severe storm transit condition, ABS requirement states:
Legs are to withstand acceleration and gravity bending moments resulting from the motions in the most severe anticipated environmental transit conditions, together with wind moments correspond ng to a velocity of not less than 51.5 m/s (100 kn). ... Alternately, legs are to withstand a bending moment caused by minimum criteria of a 15 degree single amplitude roll or pitch at a 10 second period, plus 120% of the gravity moment caused by the angle of inclination of the legs. ... Intact stability of the unit is to be investigated ... for a wind velocity of not less than 51.5 M (100 knots).
On many occasions, especially for rigs having relatively long legs, in order to satisfy these criteria, the legs have to be lowered considerably. For example, some Global Marine Jack-up units of Marathon LeTourneau 116-C design with 477 ft of leg, which this paper addresses, require a leg draft of 184 ft to satisfy these criteria.
It is obvious that rig motions are influenced by the draft of its legs. During a storm, the portion of the leg below the hull is subjected to a combination of wave forces, motioninduced drag loads, as well as inertia loads. It is not obvious, though, whether there is a limit for increasing the leg draft in order to meet the ABS criteria without causing structural problems to the portion of the leg extended below the hull. This paper investigates the motion characteristicsof a typical Marathon LeTourneau 116-C jack-up with 477 ft leg length with various leg drafts using 3-dimensional radiation-diffraction theory, and attempts to estimate thesafe limit of the leg draft for the roll/pitch criteria specified by ABS.

MOTION RESPONSE
The hull of the rig has been modelled by using 680 panels as shown in Fig. 1.
Application Of Low Density Foam Pigs Offshore Brazil
Authors: Lima P.C.R. , Alves S.J. 
Published: October 2008

ABSTRACT
In complex offshore installations, such as in the Campos Basin, it is relatively common to encounter pipeline systems where conventional pigs can not be run due to several factors. Changing pipe diameters, and presence of wet Xmas trees and manifolds are the most troublesome ones. In this work a new successful concept of using low cost and low density foam pigs for both liquid removal in wet-gas pipelines, and parafin removal in oil and multiphase flow pipelines, is presented. Experimental work conducted in a 4 in laboratory facility, including a small scale glass manifolds and a 6 in steel manifold proved these pigs to be very effective. The performance of almost all kind of flexible polyurethane foams manufactured in Brazil is evaluated.
Three field tests are also reported. The first low density foam pig operation was performed on a 127 mile long, 16 in diameter wet-gas offshore pipeline where the foam pig showed even higher liquid removal efficiency than the conventional inflatable spheres. The second operation was performed on a 6 mile long, 12 in diameter multiphase production offshore pipeline, which has never been pigged during its 9 year operation, and resulted in the removal of approximately 200 tons of paraffin. Finally, the third successful case is the cleaning of a 2 mile long flexible flow line of a subsea completed satellite well, in which the foam pigs were sent through a 2.5 in gas Lift line, through a wet x-mas tree, not designed to be pigged and then back through the 4 in production flow line.
In spite of the fact that this paper is focusing on condensate and paraffin removal in pipeline, the basic principles can be applied to several kind of operations: general pipeline cleaning; product separation in pipeline; corrosion evaluation; chemical product application.

LOW DENSITY FLEXIBLE FOAM
The developed pigs are manufactured from polyurethane foam block, mainly supplied by flexible foam Brazilian industries. There are two basic polyurethane materials: polyeter and polyester. They present significant differences in chemical and mechanical properties. The foam density range varies from 1.1 to 2.4 lbm/ft3. The pigs are shaped using a special device designed and constructed by PETROBRAS.
The physical properties considered for foam selection were:density;tensile strength;wear resistance;tearing resistance;resilience;elasticity modules;type (closed or open) and size of foam cells.

LABORATORY TESTS
Fig. 1 shows a schematic drawing of the field scale test loop, especially constructed to evaluate the performance of foam pigs. The 157 ft long test loop was composed of a 4 in, such 80 steel pipe, equipped with a 6 in pig launcher, a variable diameter spool piece, a transparent section and a tank to receive the liquid displaced by the pig. The liquid phase was either water or light refined oil. The air was supplied by a 49500 scfld and a 200 psi maximum discharge pressure compressor.
The following laboratory tests were performed:
(Available In Full Paper)
Project Development in a New Era
Authors: Vold Johan Nic 
Published: October 2008

1. Introduction
I too will like to thank the organisers for standing so firmly behind this Norwegian day at OTC ?95. I certainly hope that you will benefit from our North Sea experience. We are reasonably proud of what the Norwegian oil industry can offer. I will however at the outset underline that we are fully aware that our recent history is only one of many examples of the dynamic nature of our industry.. ... And although the many short sessions that follow may not allow time for repeating more general points, we are all filly aware that our achievements havenot come about in isolation. Co-operation and competition on a global basis has been a vital ingredient to our current strength.
Our business environment is undergoing rapid and iimdarnental changes, The dramatic downward adjustment in the outlook for oil prices is only one of many challenges facing our industry. Competition for the most attractive assets is intense. A new era has started. Financial strength, technical excellence and world class reputation is required to succeed. But this alone will not be sufficient. The most success lid companies will be the ones with an innovative and focused - but still flexible - organisation. Working more closely together with our suppliers and other oil and energycompanies will also be a prerequisite.
In this new era we have to rethink our project development processes, how to identify new projects and business opportunities. Indeed, creating a shift in our project development capabilities is vital if we are to achieve the required improvement in our profitability.

2 A new era

2.1 Markets
Before I proceed with the topic of project development, let me first briefly touch on someof the issues that are likely to characterise the new era.
Today, our outlook on oil markets is radically different from when most of us were shaping our perceptions about best practice - be it in terms of work processes, technology, control systems, supplier relationships and regulatory framework, For example, the second phase of the 1.7 billion barrel Gullfaks field was approved for development in 1985. That year the oil price expectations were close to 40 94-USD/barrel.
Today new developments have to reach at least 10% real rate of return at 16 USD to be considered. And we are no longer looking towards the oil market to pull us out of our difficulties, In my view, there are limited prospects for sustainable oil price increase. Oil markets will probably be even more volatile and we are preparing for lower growth in Statoil?s main markets.
The gas industry seems however to have a more positive outlook. In Europe, I believe we will see a growth in demand, triggered by economic growth and the increasing efficiency of gas based power generation. Environmental awareness and subsequent legislation are also important factors driving the demand for natural gas. Even gas is suffering from the dramatic increases in consumer government taxes - seemingly approved in support of a better environment.
New Elements in Production Technology and Operations
Authors: Melberg Ole 
Published: October 2008

ABSTRACT
The title of this presentation embraces quite a wide scope, however, focus will be on Mobile Production Systems (MPSS) and in particular on Floating Production, Storage and Offloading Units (FPSOS), for which we are presently witnessing a remarkable boost in interest particularly in the North Sea area.
Over the last 20 years, pioneered by the Argyll TW 58 in 1975, 11 mobile systems have been/ are active in the North Sea, i.e. a growth of one for each second year. In 1994 alone a number of eight mobile production systems were contracted of which seven were FPSOS, This boost is following nine years of successful operation of the Petrojarl I and is also clearly linked to the success of the Kerr-McGee?s Gryphon A project.
The title of this presentation reflects new elements in this business; the upturn in interest for FPSOS introduces new ways of thinking and acting. In this paper, the new elements are divided into the general trends; new commercial elements and new technological elements.

GENERAL TRENDS
Over the last 20 years the industry has seen around 70 applications of MPSS in terms of monohulls, semisubmersibles or jack-up solutions. Out of these a number of 11 are related to the North Sea.
Only 10% of the applications are dedicated New buildings. Monohull solutions, which are normally converted tankers, account for less than 40%. of the cases on a worldwide basis.
This presentation will deal with the business of mobile production systems in general, but the discussions of "new elements" are mainly related to the trends in the North Sea, UK and Norwegian sectors.
The Gryphon A project, see Figure 1, that saw first oil in October of 1993 seems to represent a break-through for the dedicated monohull field development. The positive experiences from 1.5 year of operation on Gryphon has certainly had a positive effect on the dedicated monohull newbuildings seen in 1994.
The MPS applications in the North Sea up to 1994 are shown in Figure 2. There are seven semis of which six are conversions. Three ships, all dedicated newbuilds for production, The West Omikron is a converted jack-up for water injection in the Ekofisk field.
The two main parameters when selecting the concept is the water depth and the presence or not of infrastructure, see Figure 3. The major difference between the semi andthe FPSO is the storage capability and thereby the FPSO?s merit as a stand-alone solution.
The main difference between the floating semi or FPSO and the seabed based jack-up is the water depth.
If pipeline offtake is available the semi or jack-up solutions are attractive, When storage is needed the FPSO is the superior solution.
When designing a system for a number of future fields for which the input parameters are not known, the FPSO solution is the most versatile offering all functions from one vessel only, This is certainly influencing the trend towards monohull solutions when contract duration field lifetime is less than say 10 years.