bluuebunny/crossref_metadata_2025_split huggingface dataset:
Jackup Dynamic Stability Under Extreme Storm Conditions
Authors: Hambly E.C. , Nicholson B.A. 
Published: October 2008

ABSTRACT
Jack-ups have been used extensively in the North Sea as mobile structures and have had a good safety record. This good record has given several operators confidence to consider using jack-ups for the more demanding roles of production for extended periods at deep water locations. This paper examines the margins of safety provided by current regulations for independent leg jack-ups, and argues that larger margins of safety are needed for the more demanding roles of production in deep water.
Safety margins against collapse are examined with dynamic time-domain analyses of the nonlinear interaction of structure and seabed under escalating storm loading. These analyses extend the work of Hambly, Imm and Stahl1. Analyses on a future generation of jack-ups for 120m water depth in the North Sea highlight the fundamental importance of spudcan embedment and horizontal resistance of seabed to sliding of spudcans.

SAFETY FACTORS
Current regu1ations 2–6 and assessment criteria7,8 provide protection to jack-ups against collapse by specifying minimum Safety Factors against particular design loading conditions. The regulations have to cater for a wide variety of units and conditions, and for this reason the definitions are kept relatively simple and have to be interpreted in a robust manner. The Safety Factor against overturning, for example, provides a degree of protection against collapse from a variety of mechanisms including foundation failure and leg breakage. One would not expect a jack-up to collapse by overturning bodily because it is not a rigid body.
The UK Department of Energy Guidance Notes2 (DEn) indicate that structures should be assessed for environmental loads which "shall not be less than those likely to be exceeded on average once only in any period of 50 years" (referred to here as the 50-year load). DEn2 and others3,7 currently permit Safety Factors against overturning to be as low as 1.1. If a jack-up really does have such a low Safety Factor under 50-year loading it is likely to have a Safety Factor of less than 1.0, i.e. be unsafe, under 100-year loading. This can be shown by reference to Table 1 which shows in columns 1 and 2 the increase of wave height in the North Sea with return period as indicated by DEn2. Column 3 shows the increase in wave overturning load on a jack-up leg associated with the increase in wave height in column 2. In particular the overturning load from a 100-year wave is more than 1.1-times the overturning load from a 50-year wave. Dynamic calculations described later for a whole jack-up, as opposed to static calculations for a single leg, also show that the total overturning moment from 100-year loading is more than 1.1-times the total overturning moment from 50-year loading.
The safety record for jack-ups in the North Sea has been good9 even though stability assessments have included minimum Safety Factors close to unity. This is because it has been extremely rare for units to be subjected to loading approaching the maximum design loading while standing in deep water.
Analysis of Vortex-Induced Motions and Drag for Moored Bluff Bodies
Authors: Halkyard J.E. 
Published: October 2008

ABSTRACT
A method of analyzing the vortex induced motions of a moored bluff body is described. A general current profile is assumed. The technique is based on computing modal excitation and damping utilizing "strip" theory for application of empirical amplitude dependent lift and drag forces. The linear second order modal response equations are solved iteratively. The "strip" theory model applies excitation or damping forces dependent upon the local sectional properties and the corresponding reduced velocities. An example using a single degree of freedom model for a deep water tensioned buoyant tower (TBT) is included. Recommendations are made for expansion of a model to include the effect of vortex suppression devices, different shapes and spanwise correlation of excitation forces. Further collection of empirical sectional data is suggested.

GENERAL
As oil and gas field development moves into progressively deeper waters, interest in large floating structures to accomplish such development has grown significantly. In areas where periods of sustained, high velocity currents may be expected, such as the Gulf of Mexico where the loop current and its eddies hold sway, there is concern over predicting the behavior of, and drag forces on, large floating structures subjected to the type of "strumming" experienced by cables and risers subjected to strong currents which has been covered extensively in the literature.
Two structures for which this "strumming" or periodic oscillation associated with vortex shedding is of particular interest are the Spar, Figure 1, and the Tension Buoyant Tower (TBT) Figure 2, which are described in other papers at this conference. Both are large diameter (85 feet - 140 feet) deep draft (400 feet 700 feet) cylindrical floating structures capable of supporting drilling and production equipment to handle several wells and 40,000 - 50,000 barrels/day of oil production. The Spar is free floating, moored by a multipoint catenary mooring consisting of driven piles and wire rope anchor lines. In contrast, the TBT comprises a buoyancy module tethered to the seafloor by a number of steel pipe tendons bundled together as a central stem which locks into a base which is in turn fixed to the seafloor by driven piles. Other structures for which the strumming phenomenon is of interest are the semisubmersible and the tension leg platform.

RESPONSE MODEL
The Spar, TBT and similar structures may be expected to "lock-in" when the Strouhal frequencyfs= So*V/D(1) wherefs= frequency of vortex shedding from a stationary cylinderSo= Strouhal number (0.18 - 0.3 depending on Reynold's number)V= VelocityD= Diameter approaches the natural frequency of the rigid body motion of the structure. The relationship between Strouhal frequency (i.e. the frequency of vortices shed from a stationary cylinder) and the structural natural frequency, fn, is usually represented by the "Reduced Velocity",UR= V/fnD = fs/Sofn (2) wherefn= natural period of structure
Snorre TLP Topside Design
Authors: Nilsen G.B. , Gabrielsen I. , Graff O. 
Published: October 2008

ABSTRACT
This paper gives a brief description of the topside facilities and integrated deck structure for the Snorre TLP which will operate on Block 34/7 in the Norwegian Sector of the North Sea. Features which contribute to safe, simple and weight/space saving solutions are presented. The paper addresses where new technology is applied to achieve the overall goal of optimizing platform topsides. Comparisons with conventional installations in the North Sea will be presented.

TOPSIDE DESCRIPTION

Topside Configuration
An integrated deck concept (Fig. 1) has been chosen for its cost and weight benefits. The rectangular deck - 124.5 m long and 92 m wide - has a total height of 15 m including a 2 m deep double bottom forming the cellar deck. The deck is cantilevered at either end of the TLP by 1l.5 m.
Three main deck levels constitute the overall deck layout: cellar deck, intermediate deck and upper deck. Local mezzanine decks have further been included for support of equipment and facilities.
The main structural girders comprise a combination of trusses and plate girders. The six open trusses form the longitudinal girders of the platform, whereas the plate girders span in the transverse direction, providing partitions between the areas. This gives a safe segregation of hazardous and non-hazardous areas. The intermediate and mezzanine decks are simply supported on the plate girders and contribute little or nothing to the global strength.
The cellar and upper deck sections have their structural configuration determined by the overall structure and contribute to the global strength.
The design of the deck sections has taken into account the requirements for fabrication, lifting, installation and reduction of the structural dead weight to a greatest possible extent.
The deck is constructed and assembled at a main site. However, the deck has been designed such that 17 of the deck sections can be fabricated and outfitted at other sites. These approximately 20 × 20 meters deck sections, or preassemblies as they have been called, were mechanically completed to the largest extent possible at the different yards before being transported and lifted into the main frame.

Topside Layout
The layout meets all of the operational design and safety requirements and at the same time conforms to the normal segregation of hazardous areas found on other Norwegian platforms. The facilities have been layed out in the following sequences (Fig. 2):Living quartersUtility areaDrilling facilitiesWellbay areaProcess areaFlare The main lifeboat station and the Living Quarter is located in the western end on a cantilevered portion of the deck at the maximum distance from the hazardous areas.
Adjacent to the living quarters is the utility area with main power plants and control rooms. Also the 4 × 50% fire water pumps are located in this area directly above the columns. The area adjacent to the utility area contains most of the drilling equipment and other utility systems.
Snorre Project Strategies and Status
Authors: Lappegaard O.T. , Solheim B.J. , Plummer F.B. 
Published: October 2008

ABSTRACT
The Snorre development is one of the most challenging projects carried out in the Norwegian North Sea since the pioneering days of the early and mid 1970s. This paper summarizes these challenges and provides insights into Saga Petroleum's highly leveraged strategies for applying recent technology to develop this deepwater field. The field installations are described with emphasis on technical innovation. This theme is followed up, in more detail, in the other Snorre papers. The status of project manning, progress and cost is summarized as onshore fabrication nears completion.

CHALLENGES
The Snorre field is located west of the Norwegian trench approximately 26 km northeast of the Statfjord field. It is operated by Saga Petroleum on behalf of the nine other partners shown in Fig. 1. The reservoir and deepwater challenges on Snorre coupled with the turbulent oil price fluctuation of the 1980s have caused the project to seek and find innovative development solutions.

Reservoir and Reserve Challenges
The nature of the Snorre reservoir and the vast areal extent have made it necessary to drill a relatively large number of wells to develop the reserves. Compared to other large fields in the shallower waters of the Norwegian sector (Fig. 2), Snorre has lower reserves which are spread over the same area as Statfjord and Oseberg, and over a much larger area than Gullfaks. On the other hand, the number of wells which must be drilled is comparable. Thus, the reserves that can be recovered per well on Snorre are, on average, significantly less.
The reservoir is located about 2500 meters below sea level. It consists of two sandstone formations, the Statfjord (Jurassic) and the Lunde (Triassic). The recoverable reserves are:Oil - 122 million cubic meters (770 million barrels)Gas - 7 billion cubic meters (250 BCF)Liquids - 3 million tonnes. A total of 68 million cubic meters (430 million barrels) of oil will be produced during the first phase of development. This will be the first time that the Lunde formation has been produced.
In Fig. 3 a cross-section of the Lunde formation is shown through one of the more prolific areas. Most of the oil is located in the D, E, and F units. In the same manner as for the Statfjord formation, major faults with large throws divide the reservoir into fault blocks. Minor faults further subdivide the reservoir. The transmissibility of the faults is uncertain. The reservoir contains over-pressured, highly under-saturated oil. It must be developed by water injection pressure maintenance since no significant aquifer support is expected. The complex fluvial reservoir, low dip, and anticipated poor vertical communication were judged to be unsuitable for successful gas injection pressure maintenance. In addition, for the Lunde, the lateral continuity of the fluvial sandstones is considered to be limited.
In order to achieve a satisfactory level of recovery, water injection will take place from the start of production. The plan for developing the total reserves calls for 93 wells to be drilled.
Troll Oseberg Gas Injection (TOGI) Development
Authors: Boge M. 
Published: October 2008

ABSTRACT
In 1986 the Oseberg partners decided to replace the planned water injection scheme by gas injection.
Pressure maintenance by gas of the Oseberg reservoir instead of water is estimated to increase the overall oil recovery by approximately 7% or 75 mill bbls. In addition 21 water injection wells are saved. Approximately 75% of the injected gas will be recovered.
The Troll-Oseberg Gas Injection (TOGI) development was initiated to supply gas to Oseberg from the nearby Troll field. The gas is produced by a subsea station with 5 wells, and transported unprocessed through a 48 km long pipeline to Oseberg.
The subsea station is remotely controlled and monitored from Oseberg.
This 3 bill NOK project operated by Norsk Hydro started production in January 1991 after 4 1/2 years development.

INTRODUCTION
In order to further improve the oil recovery from the Oseberg field reservoir an external gas supply for injection purposes was sought for to replace a planned and comprehensive water injection scheme for the Oseberg reservoir.
This triggered a study directed towards a deepwater development of part of the nearby giant Troll field gas reserves for injection gas delivery to Oseberg, 48 km away, for improved reservoir pressure maintenance.
The Troll-Oseberg Gas Injection (TOGI) development was initiated by Norsk Hydro and presented to the Oseberg and Troll field partners in the spring of 1986, and was met with their approval.
4 1/2 years of novel technology development, testing, installation and completion work has now passed and the TOGI development is preesently in operation and gas is being produced from the Troll deepwater station in 303 meters of water by the Troll field licensees, and transported and sold to the Oseberg field licensees to enhance the Oseberg oil recovery with approx. 7%.
Two percent, up to one trillion scf. of the large Troll reserves will be injected into Oseberg over a twelve year period. 75% of this gas will be recovered and sold after year 2002, when Oseberg goes into its gas production phase.
This paper will addressThe impact on Oseberg of gas injection vs. water injection.A brief presentation of the contractual agreements between the two license groups.A conceptual description of the TOGI development.a presentation of TOGI project contracts and organization principles. Norsk Hydro is the operator of both the Oseberg project and the TOGI project.
This paper is one in a series of six which are presented at the OTC 1991.

Impact on Oseberg - Advantage of Gas Infection
The Oseberg field is located approximately 140 km west of Bergen, Norway, fig. 1. The phase I development of this field consisted of a field centre (the 'A' and the 'B' platforms), an oil pipeline (28") to shore and an oil terminal onshore for storage and export of the crude oil. Phase I also included two subsea wells.
The main Oseberg reservoir is split in three different structures, the Alpha structure, The Alpha North structure and the Gamma structure, fig. 2.
Subsea Processing and Control System in the GA-SP Project: Testing of the Prototype System
Authors: Nordvik H.S. , Sarshar M.M. , Taylor M. 
Published: October 2008

Abstract
The subsea production and processing developed under the "GA-SP" project involved two stages of separation, leading to production of exportable quality crude oil by pipeline. The produced gas is transported along a separate line. Key elements of the subsea process system are described in this paper. A prototype system was developed during the second phase of the project. This system was tested under dry and submerged conditions in a drydock. Key features of the prototype system and the tests earned out are described. Prototype testing has proved the viability of the GA-SP system and has helped to identify areas requiring particular attention and improvement for future field applications.

1. INTRODUCTION
The main objective of the GA-SP project has been to develop a subsea production system suitable for the development of satellite marginal fields. This was a joint industry project supported by the European Community and eight major oil companies, An overview of the system and the economics are addressed in a separate paper (OTC 6766). In this paper, some of the key features of the process and control system are highlighted with reference to the extensive testing of the prototype system.
The "Base Case" relates to a satellite field 30 km away from the mother platform. The field consists of four production wells and four water injection wells. A general view of the field scenario is shown in Figure 1.

Design Parameters
The main parameters for the design of the system are summarised in Figure 2. The sensitivity case shows the range of values of interest to the participating oil companies and does not reflect the limits for future field applications.
The requirements for the quality of the processed crude oil was not necessarily the minimum or optimum for the system but was set as a relatively more demanding case in order to export produced oil direct via an existing trunkline. The options for simplifying the process system are discussed in sections which follow. The high export pressure specified for the crude oil was to meet the operating pressure specified for the trunk line.

Process Flow Diagram (PFD)
Figure 3 shows the simplified process flow diagram. Two identical production trains are adopted. Each train serves two wells with an option to divert flow from one train to another via the test meter loop.
Production testing of individual wells is achieved via a by-pass valve leading to the test header. The multiphase test meter enables subsea measurement of individual wells without the need for a test line or a separate test separator.
The separator comprises two stages of gas/liquid separation in order to meet the specified TVP requirements. This leads to production of gas at different pressures (first and second stage separators). An ejector is used to commingle the gas products from the two sources for export via a single line. Oil and water are transported along separate lines for the Base Case. Separate booster pumps are used for each train.
Offshore Minerals in the 21st Century
Authors: Kallaur C.U. 
Published: October 2008

ABSTRACT
This paper presents an overview of the marine minerals program as it exists today in the United States and what is envisioned for the future. It attempts to define a proper role for Government in a market economy that will allow private investment to occur if the market conditions are right. It outlines the program strategy followed by the Office of International Activities and Marine Minerals, Minerals Management Service, U.S. Department of the Interior, and focuses on the question of where the United States as a Nation may wish to be in the 21ST century with respect to a marine minerals program and what needs to be done to get there.

INTRODUCTION
To date, a viable marine minerals industry has' not been established in the Uni ted States. The lack of progress over the last 30 years in establishing such an industry has been well documented in the literature. The lack of progress directly contrasts with the experiences of the United Kingdom and Japan, which have had successful offshore sand and gravel development programs for over 30 years.
Following the establishment of the U. S. Exclusive Economic Zone (EEZ) in 1983 by Presidential proclamation, new opportunities appeared to exist for commercial development. The Minerals Management Service (MMS) of the Department of the Interior, which has the responsibility for managing the mineral resources on the Outer Continental Shelf (OeS) and the EEZ, responded by establishing an office specifically focused on the development of a marine minerals program. This office was originally named the Office of Strategic and International Minerals and has since been renamed the Office of International Activities and Marine Minerals (INTERMAR) to reflect a new responsibility for overseeing the international activities of the MMS.
In addition to the establishment of the EEZ, the renewed interest in a domestic marine minerals industry reflects the strategic importance of certain minerals, the decreasing availability of supplies of construction aggregate onshore and in coastal waters, and the economic benefits that could be reaped domestically if a successful program were established. Recent developments have also identified a widespread need for large amounts of sand for environmental restoration projects.
This paper addresses the possibilities for a domestic marine minerals program in the 21st century and the actions the Government should take to increase the chances of success. It explores the proper role of Government in providing the institutional framework that is necessary for the private sector to make investment decisions, including the removal of perceived obstacles to development. The success stories of other nations that have marine mineral programs may provide some examples. Defining a role for Government involves questions regarding the proper sharing of risk between Government and industry as well as an assessment of the strategic and economic importance of developing both minerals domestically and the required technology.