bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Developments in Prediction of Mooring System Damping
Authors: Huse E. 
Published: October 2008

SUMMARY
Previous OTC papers (Refs. 1, 2, 3) have shown that drag forces on the mooring lines can represent the dominating contribution to the surge damping of moored vessels. They have also shown that in order to calculate this damping effect correctly one normally has to take into account the effect of the wave-frequency motions of the vessel, superposed on the low-frequency, resonant motions, whose damping we wish to predict. The present paper suggests a simple and practical procedure for this purpose. It applies the concept of "apparent drag coefficient" in combination with an iterative use of the catenary equations to obtain the low-frequency damping. The range of applicability of this procedure covers most practical mooring configurations. Only in cases of very deep water, heavy lines, and suspended clump weights it may be necessary to use a complete FEM procedure to get the effect of wave-frequency motions and line dynamics accurately described.
The present paper also publishes for the first time results from investigations of the possible heave damping effect of the mooring system. It turns out to be normally negligible for moored ships, moderate but significant for semisubmersibles, and can be dominating the heave damping of spar buoys.

1. INTRODUCTION
An important feature of most moored offshore structures is the pronounced oscillatory motions at their low, resonant frequencies. Together with the motions at wave frequencies they determine peak offsets, peak mooring line loads, riser performance, and other important engineering aspects of the structure. These low frequency oscillations take place outside the frequency range of the waves. They are excited by second order wave forces, by non-linear viscous reaction forces to wave frequency responses, and to some extent by wind gusting.
Since we are dealing with low-damped systems at resonance, the LF (= low frequency) motion amplitudes are very dependent on system damping. Main contributions to for instance the surge damping of a moored vessel are due to wave drift, drag and skin friction on the main structure, and drag forces on the mooring lines.
Until just a few years ago it was customary to assume that the mooring system influenced the motions of a moored structure only by its horizontal stiffness, determining the surge and sway resonant periods of the structure. Any effect of the mooring system upon the damping of resonant motions was neglected, assuming that the drag area of the mooring lines was too small to be significant, compared to the drag damping of the structure itself.
Then in 1986 a first publication was issued, showing that the mooring system can be the main source of surge damping of a moored structure (Ref. 1). Further OTC publications in 1988 and 1989 (Refs.2 and 3) presented different attempts at calculating the surge damping effect of the mooring system, in addition to presenting more experimental information on the subject.
The objective of the present paper is to give a survey of some recent developments of numerical methods to predict mooring line damping.
Loss Control by Subsea Barrier Valve for Offshore Gas Pipeline
Authors: Kunsch J-P. , Sjøen K. , Fanneløp T.K. 
Published: October 2008

Abstract.
Platform-mounted shut-down valves for offshore pipeline systems, are vulnerable to fire and explosion hazards. Should this primary barrier fail, the full inventory of the pipeline could be consumed in the fire. A secondary subsea barrier would reduce substantially the loss of pipeline inventory, but also expose the platform to a new hazard. Valve failure could lead to the formation of gas or oil plumes which could be carried towards the platform. The choice of subsea barrier location, requires a trade-off between these safety concerns. The paper presents one prerequisite for such a trade-off; an analysis of the potential gas loss for different secondary-barrier positions and valve-closing rates when a guillotine break occurs at platform deck level.
The paper gives a detailed study of the flow characteristics close to the valve and over the length of the segment between the barrier valve and the rupture. Particular attention is paid to the boundary conditions at the valve. These have been formulated based on the method of characteristics. Computer simulations using the simplifying assumption of isothermal flow have been compared to the adiabatic case. The differences between these cases have been found to be small.

Problem Discussion.
We consider the situation depicted in Fig. 1. The subsea pipeline is connected to the process equipment on the platform through a vertical segment. In the case of a fire or explosion on the platform, a possible pipeline failure would be at deck level, as indicated by the symbol R. At the broken end a counterpressure of about one bar exists. Two subsea barrier valves, one upstream at location A, the other downstream at location B, are installed to prevent a major loss of gas in case of flowline rupture. It is assumed that the barrier valves start to close at the same time as the guillotine rupture occurs. The aim of the present investigations is to determine the mass loss and flow variables in the pipeline. A good physical discussion of the pipeline break problem without valve is given by [1],[2] and a more detailed mathematical treatment is developed in [3],[4].
The length L of the pipeline segment between the valve and the broken end as well as the valve closing time TClose are considered to be two dominant parameters influencing the rate of outflow. The range of lengths L considered varies from an upper limit of 2000m to a lower limit imposed by the riser height (or ocean depth). The closing time is chosen in the technically realizable range of 40 s to 100 s. Two cases are of interest, one representing flow towards the platform (A) and one away from it (B). The pressure level will in general be higher with flow away from the platform. More important is the pressure gradient in the steady state. For Case B, the break leads to a flow reversal from the steady state direction.
Diverless Maintenance of a Subsea Barrier Valve
Authors: Jefferies A. , Partridge C.C. 
Published: October 2008

ABSTRACT
Subsea barrier valves are used to prevent backflow of an offshore pipeline in the event of an upstream line rupture. These valves are either a ball valve or check valve configuration. As offshore production systems and their associated pipelines move into deeper waters, the maintenance of these valves becomes .more difficult and expensive due to the cost of diving operations. Eventually these valves are placed in locations where the water depth precludes the use of divers for maintenance tasks. It is then necessary to develop alternate maintenance methods for these valves. This paper outlines the development, testing, and deployment of a check type barrier valve for use in water depths beyond diver access. The system follows a maintenance through retrieval approach, using an intervention tool run from the surface on guidelines to retrieve the primary active components to the surface for replacement or repair.

INTRODUCTION
A 10" ANSI 900# (+) check type barrier valve system was developed for installation on a TLP drilling template in the Norwegion sector of the North sea. This template is installed in a water depth of 1010 ft, placing it beyond the depth normally associated with saturation diving operations. With the practical elimination of diver intervention to the barrier valve, and with the increased emphasis on subsea hardware maintenance and repair, the barrier valve system was configured for diverless operation and maintenance.
The barrier valve system includes a retrievable actuator which is used to place the valve in a locked open position to allow the passage of an intelligent inspection pig. This actuator is primarily controlled hydraulically via an acoustic/hydraulic power pack (provided by others). In the event of a control system failure, the valve may be opened via an ROV override feature built into the actuator.
The unique feature of this barrier valve is the ability to retrieve the internal working components as a single cartridge without diver intervention. This is achieved by using a collet type connector to attach the valve cover to the valve body and by using a hydraulically controlled valve intervention tool (VIT) to release and set that connector. The complete system is depicted in Figure 1.

SYSTEM DESIGN AND FUNCITONAL REQUIREMENTS
The barrier valve system was designed to interface with the other systems in the TLP production system, consequently these interface points were documented and set as limiting design criteria. Also, while staying within these criteria, the system was to be able to meet specific functional requirements. The limiting criteria and functional requirements for the system are documented below.

Design Criteria
The barrier valve system was designed to operate in a 10" gas pipeline at the base of the TLP riser, 1010 ft from the surface. The valve was designed for a maximum working pressure of 2285 psi, but unlike ANSI valves which are tested to 1.5 times working pressure, the barrier valve test pressure was 4570 psi (2 × working).
TOGI: Multiphase Flow From Troll to Oseberg
Authors: Lingelem M.N. 
Published: October 2008

ABSTRACT
The TOGI 20" pipeline has been designed to transport unprocessed well fluid 48.5 Km from a subsea installation to an offshore production platform.
The paper describes how the pipeline has been designed to handle potential problems related to multiphase flow transport and gives data from measurements carried out during operation.

INTRODUCTION
Transport of unprocessed well streams have been with the oil and gas industry since it started, The use of the technology however, was limited to short gathering systems and it is fair to state that the underlaying technology was poorly understood,
In recent years the potential of exploring the use of multiphase transport and in particular the transport of unprocessed well streams has been clearly seen. In connection with wellhead platforms and sub sea developments especially the potential savings are most significant.
For multiphase transport lines having a starting point on shore or at a manned offshore platform it is possible to control the liquid accumulation through pigging. In this way production at low flowrates where liquids tend to accumulate can be tolerated as regular pigging (e.g daily) can be carried out to remove excessive liquid.
Multiphase transport lines originating subsea can normally not be pigged on a regular basis as the pigging operation requires the use of a drill rig, For such lines the importance of detail understanding of the multiphase flow is paramount, and the determination of a proper operational envelope is one of the most important tasks of the early design.

The TOGI development.
The TOGI production system will transport gas from the Troll field through a 20" pipeline 48 Km to the Oseberg field where the gas is processed, compressed and injected into the gas cap of the Oseberg reservoir (Fig l). The gas injection improves the total oil recovery by in excess of 7% over the originally planned water injection system.
The TOGI subsea station is located at 303 m of water depth at the south western part of the Troll East field. There are five wells remotely controlled from Oseberg by an electro-hydraulic control system. Methanol is pressurized at Oseberg and injected through a service line into the wells at Troll.
The pipeline has a 0.47 m inner diameter. The riser has an inner diameter of 0.46 m. From the Oseberg B-platform where there are facilities for receiving pigs, there is a 18" 0.41 m inner diameter line approximately 225 m long connecting the pipeline to the slug catcher located in the process facilities on the A-platform (Fig. 2).
Peak daily production is between 10.5 and 12 106Sm3/d. Minimum production rate is 5 106Sm3/d.
The TOGI fluid is at its hydrocarbon and water dew points at reservoir conditions. Maximum liquid drop out is around 3 % (mass) or 0.4 % (vol). No liquids are produced from the reservoir.
The reservoir pressure will fall around15 bar over the 11 year of planned production.
There are several potential problem areas associated with transport of unprocessed well fluid.
Design and Construction of 6,OOO-ton Facilities Module for Main Pass 299 Sulphur Mine
Authors: Nelson C.W. , Moody A.G. 
Published: October 2008

ABSTRACT
The following describes the design, equipment selection, and onshore fabrication of the largest facilities module ever employed in the Gulf of Mexico. Measuring 110 ft. by 220 ft. by 70 ft., the 3 story structure will house Frasch process sulphur mining equipment and will weigh nearly 6,000 tons during lift and over 8,300 tons during operation. Bridge reactions acting on the in-place module result in total operating vertical load of approximately 12,000 tons. A Vierendeel truss structural system was selected for framing the module to allow maximum equipment access and routing flexibility for complex, insulated large diameter process piping. Research and finite element analysis of crimp plate siding behavior in shear was carried out during selection of siding type for the module.
An interactive design sequence was carried out which incorporated in-place operational criteria, onshore fabrication considerations, complex process equipment requirements, plus load-out, ocean transport and offshore lift. Project schedule dictated that design, procurement, and fabrication be fast-tracked with parallel activities accelerated to the maximum extent possible. Design and construction of this largest and most complex module was done concurrently with 52 other components of the project including jackets, decks, process and living quarters modules as well as two 400 ft. by 72 ft. sulphur tankers. Total tonnage of steel structures for the project exceeds 40,000 tons.
The 6000 ton mining module proves the viability and cost-effectiveness of larger modules than commonly used in Gulf of Mexico waters. This technical advance can be matched with economic opportunity for other large-scale offshore installations.

BACKGROUND
The extraction of liquid sulphur has many similarities to and several distinct differences from oil and gas production, both from an historic and functional standpoint. Historically, Frasch process sulphur production was strictly an onshore operation in Texas and Louisiana prior to World War II. In 1951, Freeport Sulphur Company conceived the idea of putting a complete sulphur mining plant on a barge to mine a project at Bay St. Elaine in the Louisiana marshes south of Houma. In 1956, Freeport began development of a major mine 7 miles offshore of Grand Isle, Louisiana, in the open Gulf at an initial water depth of 50 feet. Structural design of the jackets and decks was similar to oil and gas platforms being installed at that time.
One major functional difference between offshore oil and gas platforms of the 1960s and the Grand Isle sulphur mine was major soil subsidence. Removal of sulphur from its naturally formed dome deposit causes subsidence at the ground surface or in offshore cases at the mudline. At Grand Isle, the array of platforms and interconnecting bridges installed in 1960 stretched almost a half-mile across the dome. Maximum subsidence predicted at 30 ft. during design has been actually realized during the 30 year life of the mine, which is still operating today.
The Automation of a Sulphur Mine
Authors: Schmaltz S.M. 
Published: October 2008

ABSTRACT
In December of 1988 a joint venture led by Freeport Sulphur Company discovered a major brimstone deposit of 67,000,000 long tons twenty miles offshore in the Gulf of Mexico. At a production of 2 million tons of sulphur per year this facility will be in operation for the next 30 years. This paper will cover the process of automating the frasch sulphur mine including design and planning, redundancy, reliability, training and configuration. A description of system architecture which allows information for production to be gathered and handled at the facility from process control, production and drilling will be presented. The ability to monitor and control the offshore platform from an onshore facility via satellite communications and the ability to network the process control system with a local area network of host and personal computers will be discussed.

INTRODUCTION
Main Pass Block 299, is located (Fig. 1) in 210 feet of water, 20 miles east of the mouth of the Mississippi River in the Gulf of Mexico. The production facilities will incorporate the latest technology based upon previous applications, the company's expertise in offshore sulphur mining and on proprietary mining techniques that use seawater in sulphur mining. The offshore production facility will be installed on a series of offshore platforms (Fig. 2) linked together by more than a mile of bridges. The Main Pass facilities are scheduled for completion in late 1991 with sulphur production beginning soon thereafter.
One of the greatest tools in assisting operations achieve high safety and efficiency goals is through production automation. Improved productivity as well as improved management of production information can be realized from a modern process control system. Through automation and remote monitoring, operating costs can be reduced and production revenues increased. The strategy was to implement a completely integrated information system - one that gives the association of the process operations data with management and business systems data.

AUTOMATION PROCESS

Planning
There are a great number of factors to consider when developing a plan for plantwide process control and flow of information. The needs and requirements of production planning, engineering, maintenance, material handling, scheduling and overall management are unique when it comes to process control data and business information systems. The first step in the planning of the control system was assembling a team of people from the various areas listed above. The company had to make a decision to make available the best that the company has to offer in the areas of production, maintenance and engineering to be a part of the team. Because of their other responsibilities in construction of this facility as well as running existing facilities it is almost impossible for them to spend a majority of their time on process automation alone. Once a team was established then the next step was to set the criteria for controlling the process and the handling of production data.
Results of Standardized Testing on Valve Repair Sealants Used in Subsea Service
Authors: Pennell R. , Baugh B.F. 
Published: October 2008

ABSTRACT
A discussion of the theories of repair sealants on ball valves and testing which has been done on various sealants to determine the basic characteristics of the sealants. Comparative testing has been done on sealants manufactured by 5 different suppliers for flowing losses to the sealing locations, thermal effects, arctic or freezing effects, and ability to bridge a standard .005" gap.

INTRODUCTION
The use and application of sealants to ball valves, both on land and offshore is critical to the long term workability and reliability of many of the valves. In spite of this critical need, little formal testing has been done, documented, and distributed to the industry on this subject. This paper reflects an ongoing testing program to develop technology in this area which will support standardized guidelines for the specification and use of these products.
This program continues and expands upon testing described in 1990 Offshore Technology Conference Paper no. OTC 6393 and titled "THEORY, HISTORY, AND RESULTS ON SEALANTS FOR SUBSEA SERVICE".

DEFINITIONS
Bridging: The ability of a sealant material to span across and seal a gap in a sealing interface.
Penetration number: Depth in tenths of a millimeter that a standard cone penetrates the sample of grease or sealant under prescribed conditions of weight, time, and temperature.
Penetrometer: A device used to measure the penetration of a standard cone in the grease or sealant under standard conditions.
Sealant: A grease-like mixture which is intended to bridge over small gaps in sealing interfaces (i.e. between the ball and seat of a ball valve) and cause effective sealing to occur.
Sealing interface: Any surface along which one part is sealed against another. Most specifically in this discussion, the contact area between the ball and seat of a ball valve.
Unworked: A sample of grease or lubricant which has been subjected to only the minimum handling in transferring it from the sample can to the test apparatus.
Working: Subjecting the lubricant or sealant to any form of agitation or shearing action.

SEALANT SAMPLES USED FOR TESTING
Figure no. 1 gives basic data from each of the sealants/lubricants which were used in this test program. The 8 sealants indicated were purchased from 5 different suppliers, with one supplier providing two samples and one supplier providing three different samples. The chart illustrates that each of the sealants are rated for at least 450 degrees F. service, and are sold both as a lubricant and a sealant.
Figure no. 2 shows 7 of the samples used for the majority of the testing on this project. Each sample was placed in a standard sized can which closely approximates the size of a standard ASTM Penetrometer Cup. The car size selected was A 12.5 OZ. can which is available from grocery stores containing a number of brands of Tuna Fish. The can is 4" in diameter and approximately 2 1/4" tall.