bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Platform Collision Chances
Authors: Massie W.W. , Buijs A.H.E. 
Published: October 2008

ABSTRACT
The chance that a fixed platform is rammed by a passing ship is studied via the use of a fault tree of events which lead to collisions - caused either by technical or navigational failures. It is found for the North Sea that the chance of a collision can be appreciable for a platform located near a busy shipping lane but relatively insignificant for a platform in an isolated location, far from shipping lanes. Appreciable in this context describes a chance comparable to that of a major fire on an offshore platform.
Old and flag of convenience ships are involved in most of the collisions. It is impractical to close the North Sea to all such ships, even though this would reduce the risk of collisions by more than a factor of 2.
In the course of the literature survey, it was found that many mariners use charted offshore platforms as navigational aids; they therefore approach close to them for the sake of positive identification. One practical means of reducing the chance of collisions would be to install racons on each platform so that they could be identified on a radar screen from a distance; this would alleviate the need for this close approach.
A second effective approach is to install a traffic guidance system for groups of platforms near busy shipping lanes. Experience with such a land-based guidance system in the Dover Strait has been very rewarding.

INTRODUCTION
Collisions have occurred between passing vessels and offshore platforms for some time. In the North Sea, a fixed structure in Dutch waters which had just replaced a lightship was rammed by a coastal merchant ship in the late sixties. A more bizarre accident occurred in the eighties when a submerged German submarine rammed a fixed platform in the Norwegian portion of the North Sea. While designers obviously know that a finite chance exists that a platform will be hit by a passing ship, the systematic quantification of this chance has been neglected.
All marine catastrophes (including collisions) can lead to any combination of the following three types of risk: to persons - either those directly involved or as by-standers such as yachtsmen, to property, or to the environment. In another approach, the significance of various risks in the eyes of the public varies depending upon several factors. These are explained in more detail in an appendix derived from [1].

METHOD
Unfortunately, direct data on the risk of collisions between passing ships and offshore structures is incomplete and therefore of limited usefulness; a direct approach by a statistical analysis of data such as that available in [2] will be disappointing, therefore.
An alternative to this direct approach must be found. The alternative chosen for this work was to start with statistical data on ship operational details (such as not having adequate charts on board) and - using this data - construct a fault tree for events which could lead to a collision.
Kittiwake Loading Buoy (KLB): A New Lease on Life
Authors: Vogt C. 
Published: October 2008

ABSTRACT
A large loading buoy, installed for 14 years in a North Sea field, was converted, incorporating the latest technology and operating experience, for a new application as the sole offloading facility in a newly developed oil field. In spite of a significant design change to the mooring of the system the buoy body of approximately 800 tonnes could be reused for 30 more years of service life. An expensive upending operation was avoided by an inshore conversion, executed afloat at a sheltered deep location.

INTRODUCTION
North-Sea oil fields started to be developed some 20 years ago with production platforms. None of the first platforms contained any storage for the produced oil and as pipeline construction was not advanced, efficient offloading into shuttle tankers became a vital requirement. First installations used the conventional CALM buoys which required improvement to cope with the especially harsh environment of the North Sea.
The first tailor-made offloading buoy was conceived and installed in the AUK-Field in 1974, called the ELSBM (Exposed Location Single Buoy Mooring) -&gt; (See reference OTC-Paper 3805).
The ELSBM was in service in this field until 1988, initially operating as the sole system which allowed oil export and towards the end as a stand by system after the tie-in to the FULMAR-Field.
The Operator SHELL-EXPRO, who was preparing the development of the Kittiwake Field, decided to look at the feasibility of reusing the available and redundant ELSBM in this new field.
Engineering of improvement, based on operating experience and implementation of features developed for other offloading systems in the North Sea, were contracted by the Operator in early 1988 to Single Buoy Moorings Inc., whose sister company Gusto had built the original system.
The ELSBM was converted accordingly and is now in operation providing offloading of all produced oil from the Kittiwake Production Platform into shuttle tankers. The refurbished buoy is called KLB (Kittiwake Offloading Buoy).

DESCRIPTION OF ORIGINAL AUK-BUOY (ELSBM)
The ELSBM consisted of along, slim, cylindrical buoy with a diameter varying from 8.6 to 12 m and a draft of 52 m. It was anchored to the sea-bed with an eight chain pattern of 3" size chains. A large fender structure with rubber fender elements and wood protection surrounded the top of the buoy providing protection from supply vessels.
A rotating head, permitted weather-vaning mooring and contained storage reels for a single 10" offloading hose string and a mooring hawser. A helideck allowed access for maintenance crew visits.
A 50,000 DWT passive tanker could be moored to offload in sea states of up to 3.6 m significant waves.
The activation of the hose and hawser reel was by a counterweight descending into the center well of the buoy via pulleys and steel cables. The shuttle tanker had to fish a floating pick up line out of the water and then un-reel the hose and mooring hawser by heaving in on this line.
Offshore Sulphur Production
Authors: McKelroy R.S. 
Published: October 2008

INTRODUCTION
Sulphur is an abundant element that has been used by man since ancient times and is today a key basic raw material for the modem chemical industry. The invention of the Frasch hot water mining process in the late 1800's gave the United States a plentiful low cost supply of pure sulphur. The Frasch process makes possible the mining of sulphur from the limestone caprock of offshore salt domes. The latest of these mines is the Main Pass Mine located on Main Pass Block 299 approximately 36 miles east of Venice, Louisiana.

BRIEF HISTORY OF SULPHUR
Sulphur, in the form of sulphides, sulphates, and elemental sulphur, is one of the more abundant elements in the makeup of this planet, ranking eighteenth behind chlorine. The sulphides are among the most common minerals pyrites, galena or lead sulphide, zinc sulphide, and cinnabar or mercury sulphide. Vast beds of gypsum or calcium sulphate are found all over the world, and barite or barium sulphate is widely mined is several countries. Sulphur also occurs in elemental form imbedded in limestone caprock over salt domes, in craters of volcanoes, and encrusting the edges of hot sulphur springs. In addition to the sulphur in caprock limestone, it also occurs in strata bound layers of limestone such as the deposits in West Texas, Poland, Iraq, the Ukraine, the Sinai, and Sicily.
This bright yellow substance that burned with an odd sputtering blue flame, and giving off evil, choking fumes was one of the first elements used by man. Early priests and witch doctors burned sulphur to drive away bad spirits. Later man learned that sulphur fumes would kill insects and take the color out of fur, feathers, and wool. In the ODYSSEY Homer mentions the use of burning sulphur to cure ills and to avert pests. The primary use of sulphur for the past 250 years has been in the production of sulphuric and sulphurous acid. The first production of sulphuric acid in America took place at Philadelphia in 1793 where John Harrison produced 45,000 pounds by burning sulphur in a lead lined box and collecting the fumes in water. The modem chemical industry was born in 1823 when a soda alkali plant using the Leblanc process was built at Liverpool, England. This process starts with the decomposition of common salt by sulphuric acid. The start of the soda alkali industry thereby established a strong demand for the sulphur to produce the required sr, dphuric acid. The bulk of today's sulphur production is used by the fertilizer industry to produce sulphuric acid which is reacted with phosphate rock to produce phosphoric acid, the source of the phosphates in fertilizer.
Sulphur consumption has, for many years, been recognized throughout the world as an index of a country's industrial development and the extent to which its industrial capacity is utilized. About one hundred years ago, Herman Frasch provided momentum to industrial expansion by developing the Frasch process for mining sulphur horn the salt dome deposits along the Gulf Coast.
Field Experience on the Inspection and Performance of Subsea Pipeline Cathodic Protection Systems
Authors: Rippen I.J. 
Published: October 2008

Abstract
DPC has one of the most complex offshore pipeline systems in the world. The field is mature with many of the pipeline CP systems at or approaching the end of their life. A regular inspection program has to be set up to monitor these systems. With good historical inspection data, future inspections are now based on the condition of each individual CP system, rather than carried out at fixed time intervals. This has resulted in significant cost savings. Premature depletion of the pipeline anodes has been seen which is due to a number of factors, including the interaction of pipeline and platform CP systems. With careful planning this same interaction can be used to reduce anode retrofitting costs on pipelines. This has only a marginal cost benefit to DPC, but will have a significant cost benefit in other areas of the world where diving conditions are more severe.

Introduction
DPC operates one of the most complex offshore areas in the world, in terms of number of platforms and number of pipelines (Figure 1). There are 2 main fields, Fateh and South West Fateh and 2 smaller fields, Falah and Rashid. The fields are characterized by a large number of jackets in relatively shallow water linked by short in-field pipelines (typically 10,000 ft.) carrying waterflood water and gas lift gas to the platforms and produced fluids from the platforms. The fields are linked by longer transfer pipelines (typically 40,000-50,000 ft). In total there are 76 jackets. Water depths vary from 100 ft to 191 ft with an average of 144 ft. The oldest jackets and pipelines are 22 years old. There are 112 pipelines in service, with a total length of 276.7 miles. Line sizes range from 4" to 42", with the majority of the lines in the 12" to 18" range.

Cathodic Protection Inspection History

Early Life of the Field
Originally all the pipelines were electrically isolated from the platforms, using insulation flanges. The platforms and pipelines are protected by sacrificial anodes. As these systems were then relatively new, the levels of cathodic protection (CP) were good. Annual dip check readings were started on the platforms, taking readings on each leg and on each riser. Due to the risks of entanglement of the reference electrode lowered in the water with the jacket structural members, readings were only taken down to -25ft.
Over a period of time shorting occurred over the insulation flanges, such that pipeline anodes were protecting platforms and vice versa. Whilst it is not cost effective to have pipeline anodes protecting platforms, in a few instances this was certainly the case. The first platform, "C", was retrofitted in 1983 (ref. 1). The CP system on "C" platform was designed for a 10 year life; after 15 years the potentials were -940mV (ref Ag/AgCl), with most of the anodes totally consumed. The platform was being protected by the pipeline anodes.
The Further Development of the Ekofisk Field: "In-Fill" Drilling Taken One Step Further
Authors: Croucher T.M. 
Published: October 2008

ABSTRACT.
This paper reviews the planning, preparation and initial implementation of drilling operations for the latest phase of development of Phillips Petroleum's Ekofisk Field in the Norwegian Sector of the North Sea. This development includes the addition of 32 new production and injection wells to the existing t 80 well field. The unique aspect of the project was that, at the time of conception of the project, only 8 spare slots were available on existing structures, and preliminary economics proved the addition of a new structure unfavorable. The decision to utilize existing structures for the additional wells created many challenges for Phillips Petroleum Norway's engineers and this paper describes a number of the more interesting and unexpected of those challenges and their solutions.

BACKGROUND.
The Ekofisk field is the largest of the Phillips Norway Group's seven field " Greater Ekofisk" operation, located in the south west corner of the Norwegian sector of the North Sea. An overview of the " Greater Ekofisk" infrastructure is shown in fig.1. The Ekofisk field itself now comprises three production and two injection platforms, as well as eight other accommodation, process and transportation facility platforms.
Production from the Ekofisk field peaked in 1980 with production figures of 618rO00 BOPD and 1,860 NMSCFD of gas. production decline, led to the evaluation and pilot study of a field water injection program. In 1986, the Ekofisk field water injection program commenced from the 2/4 Kilo injection platform (30 well slots capacity). Water injection into the Ekofisk reservoir reached 375rO00 BWPD in 1990 into a total of 20 wells.
Positive results prompted Phillips to evaluate further development of water injection coverage, as well as adding producers to optimize recovery from the reservoir. The location of 2/4 Kilo, near the north end of the Ekofisk field, limits access to the center and south end of the field for injection purposes. Also, in 1986r nearly all 56 well slots located on the three Ekofisk production platforms, 2/4 Alpha (16 slots), 2/4 Bravo (24 slots) and 2/4 Charlie (16 slots) had been utilized. As a result, studies were initiated to evaluate the options for increasing the number of well slots at different locations in the field. Various scenarios were considered including new wellhead platforms, cantilever extensions to existing structures, and modifications to existing facilities. The decision was finally made a) to modify two of the existing production platforms (2/4 Alpha in the South of the field, and 2/4 Charlie near the field center) to add eight extra well slots on each structure, and b) to modify one of the bridge support tripods at the south end of the Ekofisk complex to accept a wellhead module for eight water injection wells. The location of the bridge support was ideal, in that it gave access to center and southern areas of the field for improved water injection coverage. The new injection platform was assigned the designation - 2/4 W.
A Design Review of Diverless Subsea Production Systems
Authors: Rodda N. , White J. 
Published: October 2008

ABSTRACT
The paper presents a design review of major diverless subsea development schemes covering concept, prototype and live installations. The paper describes the main features and maintenance intervention philosophies of these developments and highlights those design principles developed in the last decade which are likely to be in use during the early 1990's.
Several distinct development themes are identified in the paper including: the use of established drilling technology as a means of retrieving modules; the use of special purpose remote vehicles to retrieve modules or single components; and the use of commercially available ROV's to replace individual components. Each of these main intervention methods can be applied to diverless subsea developments.

INTRODUCTION
This paper which is based on work undertaken by Fuel Subsea Engineering Limited for BP Exploration reviews the design of diverless subsea systems over the last decade to provide a historical context for those engineering issues which will shape current and future development plans.
The scope of the review was not unlimited and therefore criteria had to be established for identifying systems to be considered; these areSystems in productionSystems under developmentConceptual systemsSystems on a global basis The review identified differences and similarities between the diverless subsea system designs by assessing each system in terms of the overall system design and in terms of major subsystems, via:Overall system philosophy and configurationFlowlinesManifold/TemplateXmas treeControl systemMaintenanceIntervention vehicles Eighteen systems were investigated in some detail and a further five systems considered briefly. The systems considered are shown by geographical location in Table 1.
The review of each system was based on the most recent data available in the public domain during the research period. Direct contact with relevant operators, authors or design contractors was not made and therefore it was not possible to verify the published data.
Data sources reviewed were technical proceedings from various conferences including Offshore Technology Conference; Offshore Europe Conference Underwater Technology Conference; offshore Northern Seas Conference; and Deep Offshore Technology Conference and other technical publications, including magazines. The number of individual references was extensive, with over 60 papers being reviewed in the course of the work. For this reason individual references are not given in this paper.

OVERALL SYSTEM PHILOSOPHY AND CONFIGURATION
Reservoir and economic factors are the primary aspects in determining whether a particular hydrocarbon field has the potential for development by subsea means. Once a subsea system is to be considered, the way in which the system is to be installed, operated and maintained is the most significant technical issue. However, there have been almost as many technical solutions proposed as projects undertaken. This lack of consistency is due to the evolving nature of the industry, which has yet to 'mature'.
A Proven Oil/Water/Gas Flowmeter for Subsea
Authors: Martin W.W. , Woiceshyn G.E. , Torkildsen B.H. 
Published: October 2008

ABSTRACT
A static mixing device was tested in combination with a dust-energy gamma volume fraction meter and a venture meter in order to determine if this combination could be used to reliably measure oil-water-gas rates under flow conditions typical for offshore oil and gas production especially in the North Sea. A high-rate test facility was used to circulate oil, water and air or nitrogen at rates of up to 60 m3/hr(l 0000 bbl/d) of liquids and total flow of up to 200 m3hr(30000 bbl/d). The tests were carried out primarily in the unsteady slug and bubble flow regimes with gas volume-fraction up to 100 percent and water-oil ratio up to 60 percent. In order to estimate the accuracy of the meter system under test, the single-phase flow rates of the three components were measured independently upstream of the mixing unit which was placed directly upstream of the dual-energy gamma and venture meters.
The results of the tests carried out with and without the mixing unit show that the mixer eliminates the slip between the gas and liquid phases well enough to obtain repeatable estimates of oil and gas volume fractions within ± 10 percent relative error over the entire range of conditions tested for fractions over 30%. Oil flowrates were also measured to within an accuracy of 10 percent compared to the independent single-phase rates over a wide range of conditions up to percent 70 percent gas volume.
No attempt was made in this study to optimize the performance of the combination of the mixer and two meters but the test results and experience indicate scope for improvements to the arrangement between these three main elements and to the dual-energy gamma technique itself. In addition, a follow-up feasibility and pre-engineering study was carried out to establish design criteria for a subsea meter based on the tested technologies. A prototype subsea meter is under design and further testing is expected to begin late in 1991 in the current phase of the project.

INTRODUCTION
The measurement of oil-water-gas production rates by means other than test separators has been a subject of intense research end development because of its potential to eliminate the need for test separators on platforms, to supplement test-separator capacity for satalite developments and for reservoir monitoring. Many methods based on various physical phenomena (such as gamma-ray attenuation, microwave, capacitance)have been tested with varing degrees of success depending on the composition, flow rates of the phases and flow regime or pattern. In all the cases reported where it is attempted to measure the flow without first separating the phases, slip between the phases causes errors which are too large (much greater than 10 percent) to be considered useful for the range of operating conditions that can be expected for typical offshore wells. In those cases where initial separation of the phases was undertaken prior to single or two-phase measurements, additional uncertainty and/or complexity is introduced which limits the usefulness this approach.