bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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.
Variable-Speed AC Drives for Drilling Plants
Authors: Haeussler A. , Mohr G.
Published: October 2008

This paper relates to the development work on a system of variable-speed drives consisting of an AC motor and frequency converter for use on drilling rigs. The object is to introduce modern AC drive technology to drilling rigs to replace the conventional DC drive system. The report covers the specification of the crucial requirements, the steps of development and test and results, features and advantages of the drive system.

INTRODUCTION

The converter-fed variable-speed DC motor is nowadays still the standard drive for rotary table and top drives, for draw works, mud and cementing pumps. It satisfies the requirements for drives installed on drilling rigs.

However, DC drives are characterized by their carbon brushes, whose wear is markedly dependent on the prevailing operating and ambient conditions. The material worn away from the brushes can accumulate in the vicinity of the commutator and lead to flashover at the brushes and the commutator. The frequent maintenance and servicing required to prevent malfunctions represent a considerable cost factor.

The motors for rotary table and top drives, for draw works, and in some cases for the pumps, are often located in hazardous zones of the drilling rig.

For this reason the drive motors must be of explosion-proof design. In the case of DC motors the sole possible type of protection is "pressurization" (EExp). This type of protection is costly. Moreover the cooling air must be routed from the safe zone to the motor by means of pipes and the exhaust air from the motor to the safe zone by means of ducts.

In the case of offshore plants air-to-water coolers are often employed, which, however, must also be connected to an air supply system in addition to the water. In both cases considerable expenditure is involved for monitoring of the cooling air and cooling water systems and for purging the motor prior to starting. Apart from the capital outlay for this equipment the maintenance and servicing costs must be taken into consideration.

Line-commutated converters, which are generally in six-pulse bridge connection, exert an influence on the power supply system due to their operating principle, namely phase control of voltage half waves. As a result the reactive power demand on the power supply system and the power factor is a function of the motor speed. Where power is supplied from diesel generators sets, this fact must be borne in mind when dimensioning the units.

In addition rectifiers also generate harmonics of definite orders which cause voltage distortion in the whole network. Additional heating is caused as a result of this distortion, which must be taken into account in dimensioning the generators and the loads.

Where power for the drilling rig is taken from a public supply line, special measures must be taken to meet the power utility regulations with regard to the compensation of reactive power and suppression of harmonics. Such measures may involve considerable additional expenditure.
Structure of Continental Shelf of Morocco Based on Sonobuoy Results
Authors: Holik J.S. , Rabinowitz P.O.
Published: October 2008

Multichannel seismic meaurements (MCS) together with sonobuoy data were analyzed in the shallow water portions «200 m) of the NW African continental margin. The untuned sound source and acquisition techniques were designed for use in deep water. Thus, the shallow water shelf data was reprocessed using velocity filtering. Though the processing improved the data quality, the data is still rather noisy. Refraction velocities obtained from sonobuoy experiments over the shelf, however, yielded excellent measurements. Results here document the seaward extension of major continental structural and geological features such as the Moroccan Meseta, the Atlas mobile belt and the South Atlas Basin.

Introductjon

RN Robert Conrad sailed in the spring of 1983 off Morocco with the intent of collecting multichannel seismic (MCS) data, gravity and magnetics, and conducting sonobuoy reflection/refraction experiments. A primary scientific objective of this cruise was to study the early rifting and separation history of the northwest African margin. The cruise tracks were designed to fill a gap in the existing geophysical data in the area in order to explore the crustal structure of the deep-water (>200 m) portions of this passive continental margin1" Although the geophysical acquisition parameters (untuned sound source and relatively long hydrophone intervals) were designed for deep water experiments, data were also collected over the shallow water portions of the margin. Figure 1 shows the location of the study area as well as the location of the sonobuoy experiments.

This paper describes our efforts to use these shallow water data. The data is divided into two parts. The first describes the reprocessing of the MCS data and the second covers the sonobuoy results. Efforts are made to tie the two data sets together in order to determine the structure of the shallow water portions of the Moroccan continental margin.

MCS

After initial processing of the MCS data2, the shallow water portions were reprocessed with the aim of improving the signal to noise ratio. The shallow water on the continental shelf (approx. 200 ms) coupled with the untuned sound source and the fact that a Jurassic carbonate platform of high seismic impedance exists at shallow depth below the shelf3, resulted in a seismic section obscured by ringing. Velocity filtering based on the technique described by Ryu4 was employed in an attempt to remove some of the spurious noise.

The effect of the velocity filtering was to dramatically improve the signal/noise ratio in the common-depth point (COP) gathers. Figure 2A shows a COP gather before filtering and 2B afterwards. The filtering effectively removed both the refraction and the water wave arrivals from the gather as well as much of the ringing in the upper 3 seconds. Although the noise above seafloor could have been removed by a mute during stacking, the ringing below seafloor could only be removed by a process such as velocity filtering.
Advancements in Liquid Hydrocyclone Separation Systems
Authors: Schubert M.F.
Published: October 2008

Since introduction in 1983, the Vortoil ® Hydrocyclone has become widely accepted in the oil and gas industry, with treating capacity of over 7 MM barrels of water per day. This success is largely due to the ability of this technology to meet environmental discharge standards while offering significant installed weight and space savings and reduced operating costs.

Further research has enhanced the separation efficiency of this technology in anticipation of more stringent environmental standards as well as adapting the hydrocyclone for primary separation of produced oil and water. The applications of the hydrocyclone technology to be discussed in this paper are:Hydrocyclone system design,Hydrocyclone designs for enhanced separation,Low pressure operation,Hydrocyclone systems for primary production separation.

Test results have shown significant improvement in oil removal efficiency for deoiling hydrocyclone, enabling lower oil content levels for produced water discharge. The improved designs enhance separation at great 1y reduced pressures. Where insufficient feed pressure exists, systems using correctly designed and operated centrifugal pumps result in a cost effective, low shear solution.

Several field tests have been conducted to evaluate the ability of the hydrocyclone to make bulk oil/water separations. Results have shown that in high water cut product ion, hydrocyclone effectively remove bulk water, leaving less than 1000 ppm oil in the water stream and return a relatively dry oil stream. Conversely, in systems with a relatively low water content, the Dehydration Hydrocyclone has been able to meet BS&W specifications.

INTRODUCTION

The deoiling hydrocyclone provides a cost effective method to handle increasing water production, alleviating bottlenecks in many production systems. The ability to de-bottleneck water treating systems has in many instances a 1lowed operators the flexibility to increase water floods and production rates, thus increasing oil production and extending reservoir 1ife. In order to further expand the applicability of this technology, a two year research program was undertaken to improve efficiency and low pressure operation of the technology.
A Study on Upending Procedure of Prefabricated Tendon of TLP
Authors: Morikawa Masao , Suzuki Hideyuki , Ishikawa Kuniteru , Yoshida Koichiro
Published: October 2008

Research and development of the TLP have been performed in the "Offshore Oil & Gas Production Platform Project" of Japan Ocean Industries Association (JOIA) promoted by the Ministry of International Trade and Industry, Japan (MIT!). In this project, the tendons which are planned to be fabricated and assembled on the land in an overall length will be horizontally towed to the site. After that, they will be installed there. As one of methods for the installation, the tendon in the upending procedure is planned to be dropped under the free falling condition. In the installation under the free falling condition, it is necessary to estimate the maximum stress and the installation time.

Therefore, the experiments for the upending procedure under the free falling condition were performed in the ship model basin in order to clarify the motion and stresses of the pre-fabricated tendons. After that, the simulation analysis was carried out using the time domain and non-linear FEM program. In this simulation analysis, three types of the drag force coefficients were selected. The experiments of the hydrodynamic forces acting on the oscillating cylinder in the steady flow were performed to obtain the one of the drag force coefficients at the resonant region caused by the vortex induced vibration on the tendon. The results of the simulation analysis were compared with ones of the experiments for the deformation and the stresses of the tendons. When the drag force coefficient which was dependent on the falling velocity was used in the simulation analysis of the upending procedure, the experimental and the calculated results coincide qualitatively and quantitatively.

INTRODUCTION

The offshore oil and gas development is expanding in larger water depth and in severer environment. In this trend, the TLP (tension leg platform) is considered to be the most promising concept. Recently, many kinds of projects and concepts of TLP are presented. In these TLPs, many types of the tendons are also presented. One of the most promising type of the tendons is a light weight tendons which have been selected in the tension leg well platform, called TLWP, in Gulf of Mexico. In the light weight tendon concept, the thickness and the outside diameter can be selected in order to obtain the neutral buoyancy. This type of the tendons can increase the payloads on the deck. The behavior of these tendons are investigated not only the strength in the working condition but also the method in the towing condition and the installation 1,2If the light weight tendons are fabricated by the welding process in their overall length on the land, the cost for the fabrication and the time for the installation are decreased in comparison with the tendons which are connected by the thread joint at the site.
Improvement in Tubular Jacket Closure Weld Fatigue Performance Through Alternative Fabrication Techniques
Authors: Marshall V.G.
Published: October 2008

This paper describes an alternative method for making circumferential brace closure welds in tubular jacket structures from that used in North Sea jacket construction to date.

The method has been developed with the objective of improving quality reliability and fatigue performance in the light of premature service failure of these joints on some structures.

The paper examines the alternative approach against current methods and presents data on fatigue test performance to support the case for S-N curve classification to class F per UK Guidance Notes.

INTRODUCTION

The requirement to weld the tubular intersection joints of large North Sea jackets from both sides, coupled with the need to furnace stress relieve these joints leads to a nodal sub-fabrication construction method. In this approach chord and brace intersection region are fabricated as a can with an array of short stubs shop welded from both sides. These 'nodes' are then incorporated into the structure on the erection site.

Such methodology necessitates the specification of circumferential closure joints between node stubs and incoming brace members.

The closure welds, which generally occur at the first circumferential seam of the brace and often incorporate an internal thickness transition taper are difficult to make since access for welding is available only from the outside.

Furthermore, the reality of heavy jacket construction means that the desired quality of fit up is regularly not achieved and in situ remedial welding is required before closing the joint.

In this paper an alternative strategy for making these in situ closure welds is described, together with the results of tests carried out to prove the fatigue performance of the completed joint detail.

The alternative technique incorporates the use of a permanent steel backing.

While initial reaction to the use of such a detail is generally sceptical it is argued that real benefits are available both in respect of fatigueperformance and construction practice.

CURRENT CLOSURE WELD EXPERIENCE

Method

The present method adopted for making single sided circumferential brace closures is to specify an open root joint using a detail similar to that shown in Figure 1.

The optimum gap for welding such a joint is 4.0 mm although a variation givinggaps between 3.00 mm and 5.00 mm can be accommodated with comfort.

The welding skill level required to make such joints, to a standard requiring freedom from planar type defects, is very high, even under optimum conditions. The environmental conditions prevailing during site construction, coupled with the actual variations in fit up which occur, conspire to disadvantage the most skilled welder to the point where weld quality levels are compromised.
Titanium Stress Joint for a TLP Tendon System
Authors: Valenzuela E.D.
Published: October 2008

This study presents the technical feasibility of replacing a connector and flex-joint with a titanium stress joint and a collet connector as components of a tendon system for a Tension Leg Platform (TLP). A detailed analysis of this new tendon system is presented for 2,000 feet of water depth in the Gulf of Mexico. The main conclusion of this study is that this new approach is feasible and replaces effectively the flex-joint used in previous TLP tendon designs. The new system has no moving parts, long fatigue life and works even better for the deep water cases.

INTRODUCTION

Figure 1 shows the general layout of a TLP platform with a tendon system anchored to the foundation template. The purpose of this study is to demonstrate the technical feasibility of replacing the connnector and flex-joint used in conventional TIP tendon design, with a titanium stressjoint and collet connector tha thas a stinger. The titanium stress joint provides the required flexibility for the maximum angular offset at both ends of the tendon. The collet connector provides the latching capabilities of the tendon to the receptacle of the foundation template. A stress joint connection at the bottom or top receptacles induce high bending moments at both ends of the tendon due to the lateral motion of the TLP. The stinger increases significantly the strength of the connector to resist high bending moments. The new tendon system uses the stinger approach at both ends of the tendon.

Hutton and Jolliet, the only two TLP platforms installed as of 1992, use a flex-joint at both ends of the tendon system. Hutton TIP uses at the bottom a Vicker's connector design with a collet locking system that engages the male stinger into the female receptacle located on the ocean floor. The Murdock flex-joint is built into the anchor housing. The fabrications of these joints use alternate layers of elastomer and partial spheres of stainless steel reinforcements to provide the required axial and angular spring area to accommodate a maximum angular offset of 16.6 degrees. The design of the tendon system for Snorre TLP follows very closely the design adopted for Hutton.

Jolliet follows a different design with a different latching mechanism at the bottom. Figure 2 shows the approach used in Jolliet for the bottom connection. The fabrication of the receptacle for the bottom tendon connection uses a load ring forging that has a cone shaped rolled plate skirt. The load ring assembly is welded into a structural stiffener fabrication which makes up the foundation template. The shroud of the connector has a slot that allows the lateral engagement of the male back flange of the tendon. The load ring and skirt assembly match the outward orientation of the tendon receptacle slot. The flex-joint is a ring built into the bottom part of the tendon. Several layers of elastomer bearings and metal sheets define the flex-joint. The fabrication of thetop tendon connection receptacle also uses a load ring forging with a cone shaped rolled plate skirt.
Enhanced Safety With New Subsea Intervention BOP for Horizontal Wells
Authors: Eriksen Gunnar , Bergum Bernt , Møsvold Harald
Published: October 2008

Of the three subsea wells, drilled so far at the Oseberg field, two wells (drilled in 87/88) have a slight deviation to the true vertical, while the third well has been horizontally drilled (91) in the Gamma North Reservoir. This well will be producing gas for injection into the Oseberg Alpha Reservoir,

To enable service of horizontal parts of this last drilled well, use of coiled tubing operations will be necessary. When introducing coiled tubing in operations with X-mas tree and completion/workover riser from a floater, a safety problem occurred with respect to shut in of the well,

This ended up with the Subsea Well Intervention BOP (SWIB) where Ram Blow-out-preventer technology was used. Additionally, in order to ensure safe operation in case the floating rig drifting off location, an Emergency Quick Disconnect Package (EQDP) was placed on top of the SWIB.

INTRODUCTION

The Gamma North reservoir was developed by Norsk Hydro and its five partners*, as part of the Oseberg phase two development, and completed in October 1991. The Oseberg Field is located in blocks 30/6 and 30/9 in the Norwegian Sector of the North Sea. The Gamma North Structure, part of block 30/6, was decided to be developed with one subsea well, in order to exploit its gas reserves for reinfection into the main Oseberg reservoir.

However, the nature of the structure also allowed the development of a thin oil layer, which required the drilling of a horizontal section of approximately 700 m. This means that the subsea well, located approximately 9 km. away from the Oseberg C platform as shown in Fig. 1, initially will be producing 10.000bbl/d (max) of oil through an 8" pipeline before the gas production starts. Additionally a 3" service line and an electro-hydraulic umbilical were installed connecting the Gamma North satellite to the Oseberg C platform.

The philosophy for all the subsea equipment in the Oseberg Field is to be able to interchange the equipment between the various wells (two subsea wells B49 and B50 were put in operation in 1988).

When completing the horizontally drilled Gamma North well, only minor wireline operations were possible, To be able to service the horizontal part of the well, use of coiled tubing operations are necessary. When this was brought forward, the equipment did not comply with the operating philosophy safetywise. The need for more sophisticated cutting mechanism to cut coiled tubing was looked for. Since the similarity between drilling operation and coiled tubing operations are striking when coming to pressure control, it was obvious to use the same well-known drilling BOP technology for coiled tubing operations. This led to the development of the SWIB, Subsea Well Intervention BOP.

The new Subsea Well Intervention BOP was put on order in May 1991.
An Improved Method for Calculating the Contribution of Hydrodynamic Chain Damping on Low-Frequency Vessel Motions
Authors: Dercksen Albertus , Huijsmans R.H.M. , Wichers J.E.W.
Published: October 2008

The computation of low frequency mooring forces on a tanker exposed to survival conditions requires knowledge of the hydrodynamic excitation and reaction forces. The low frequency excitation is caused by wave drift forces. The reaction forces on the tanker are a combination of added mass forces, wave drift damping forces, viscous forces and damping forces due to interaction with the mooring chains.

Withers [1] showed that for a chain turret moored tanker the interaction forces between the mooring system and the tanker contribute significantly to the low frequency motions of the tanker. In [2] Huijsmans presented an approximate method to include the interaction forces due to high and low frequency motions of the chain-turret moored tanker.

In this paper a direct simulation method for a chain-turret moored tanker will be applied for the correct instantaneous low and high frequency motions ofthe tanker, including the dynamic behaviour of the mooring chains. The latter will be modeled by a lumped mass method.

Comparison will be made of the direct Simulation method and an approximate method using the average chain damping. An evaluation of the chain damping contribution will be made using model test results and computations.

INTRODUCTION

A moored tanker exposed to irregular head seas performs small amplitude wave frequency pitch, heave and surge motions and relatively large amplitude low frequency surge motions around a mean surge displacement. The mean surge displacement and the low frequency surge motions are due to the second order wave drift forces. Since the total damping of the low frequency motions is small, and in irregular head seas the frequency of the slowly varying forces corresponds to the natural surge frequency of the system, resonance occurs. Large low frequency surge motions and consequently large mooring forces may be the result.

For the design of the mooring system, the large amplitude motions and the corresponding forces are required and it is therefore of eminent importance to have knowledge about the low frequency excitation and reaction forces. The excitation and reaction forces as acting on a chain turret moored tanker are given below:current velocity dependent wave drift forces/wave drift damping;relative viscous/current force;relative wind force;inertia force due to virtual mass of thetanker;reaction force caused by the mooringsystem.

All but the last item in the above list have been extensively discussed byWithers [3]. The contribution of the mooring system to the low frequency surge motions has been a subject of considerable attention in the past years.

In a static sense the reaction force on the tanker moored by a chain-turretsystem represents the load displacement curve, being the restoring force. In reality, due to the low and high frequency motions of the turret, the chains are movingthrough the fluid.
Probabilistic Chain Cable Strength and Mooring Reliability
Authors: Luo Yang , Ahilan R.V.
Published: October 2008

ABCTRACT

Based on the strength distribution of individual links, a chain cable strength model which conforms to an asymptotic extreme value distribution is formulated. The subject of probablistic chain breaking strength is investigated and it is found that the variability of link strength is of crucial importance. Based on the formulated chain strength model, the mooring system reliability analysis is subsequently performed. It is concluded that increased variability or reduced mean of link strength will significantly increase the line failure probability and the likelihood of failure occurring in lower sea states. The study also finds that the strength of K4 chains may not necessary be superior to that of ORQ chains if the strength of K4 links has a larger spread.

1. INTRODUCTION

Approximately 85\ of the current semisubmersiblesdeployed in the North Sea are equipped with chain mooring systems. A typical chain mooring line consists of a few thousand links and the strength of the chain is only as strong as its weakest link. However; this fact is usually ignored in conventional mooring analysis and design, and the fitness of the mooring system is assessed based on a nominal chain breaking strength specified by manufacturers and classification societies. This alone could significantly undermine the mooring system reliability.

To improve the understanding of the subject and stimulate interest in this area, an investigation of probabilistic chain cable strength and its impact on mooring systems is carried out. The paper focuses on the following main issues:Probabilistic prediction of chain strength,Parametric effects of links,Impact on mooring reliability,ORQ vs K4 chains.

2. CHAIR STRENGTH HODEL

A typical mooring chain is over 1000m long and has a few thousand links. Assuming that the strength of individual links is independent and follows theGaussian distribution, the probability density function of link strength can be expressed as:(available in full paper) The corresponding cumulative distribution function is given by:(available in full paper) where n and 0 are the mean and the standard deviation of the link strength. The probability distribution function of the strength of the weakest link out of n links is given by:(available in full paper) and the probability density function follows:(available in full paper) where y is the chain strength variable.

Though Eq.(3) and Eq.(4) are exact solutions, the above integrations have to be performed numerically, i.e. no closed form solutions are available. However, as n 00, the above distribution converges to the type I asymptotic extreme value distribution. The probability distribution function can be expressed as [1):(available in full paper)
Thermal Analysis of Subsea Blowout Preventer
Authors: Lin C.R. , Bunch P.D. , Li Yousun , Bacarreca Luis
Published: October 2008

A three dimensional finite element analysis was conducted to investigate the temperature distributions of a subsea High Pressure Blowout Preventer (BOP) Assembly and its constituent elastomer seals. The three operating conditions used to simulate the BOP in 40° F sea water were, (1) normal drilling operation, (2) circulation of a kick, (3) flow testing. In order to calculate the temperatures of the elastomer seals, the Newton Raphson method was applied to develop a numerical scheme for computing coordinate mapping and interpreting the corresponding temperatures from the finite element analysis (FEA) solutions. A comparison between the results of a 2D analytical study and the 3D finite element analysis was also presented and both results demonstrated a similar trend of temperature distributions.

INTRODUCTION AND FINITE ELEMENT MODEL

Up to the present, the blowout preventer, when exposed to well bore at high temperature fluid, was always assembled with high temperature elastomer seals. These high temperature elastomers have a shorter range of useable temperatures than standard temperature elastomers and consequently may cause problems in low temperature environments. Therefore, the purpose of this study was to investigate both elastomer seal temperatures and "Ull" type BOP body temperatures under defined operating conditions. The three operating conditions simulating a 18 ¾"bore, 15,000 psi maximum operating pressure BOP submerged in 40° F water temperature were:(available in full paper)

The finite element method was applied to perform this analysis, using the computer program ANSYS [11. The BOP was modeled with three dimensional isoparametric thermal elements. The symmetry feature of the geometry allowed the BOP to be modeled as an % section for Case I and as % section for Cases II and Ill. Several geometric simplifications were also made. The BOP body, intermediate flange and bonnet were modeled as a continuous solid with the same outside profiles as the intermediate flange. The ram change pistons and cylinders were modeled as solid section within the BOP body and bonnet. The finite element models for the cases 1, 11, and Ill are illustrated in the Figures 1, 2, and 3 respectively. The boundary conditions for each case were:(available in full paper)

Several additional conditions were assumed for all the three cases:100% thermal conductivity wasassumed between the contacting components of the BOP assembly,Heat loss through end flanges and side outlet flanges were ignored; the hub and flange connections onto the body were eliminated and a general configuration of the cross sectional surface representing the interface of the hub to body was assumed to be insulated,internal surfaces exposed to control fluid were assumed to be insulated.

THERMAL AND MATERIAL PROPERTIES

The material properties used in this analysis are:(available in full paper)
Mobile Bay Fairway Field Flowline Project
Authors: Lanan G.A. , Barry D.W.
Published: October 2008

Development of the Fairway Field offshore Mobile Bay, Alabama required installing four flowlines to transport high pressure, hot, sour, and highly corrosive natural gas from wellhead platforms to the Central Facility Platform. New technologies applied on these flowlines included: use of bimetallic pipe to control internal corrosion, installing the pipe in a Zig-Zag configuration to control upheaval buckling, and using continuous steel coiled tubing for utility line bundles. Design, fabrication and installation of the flowlines and utility lines are described.

INTRODUCTION

The Fairway Field is located in the Gulf of Mexico, approximately 4 miles outs ide the entrance of Mobile Bay, Alabama. Offshore facilities are in State waters in Mobile Bay Blocks 113 and 132 (Figure 1). The field is operated by Shell and produces natural gas from the deep Norphlet formation at production rates presently averaging 40 MMcfd per well. In addition to having high wellhead pressures, the gas is hot, sour, highly corrosive and posed special design requirements for the flowlines.

Gas produced from 4 outlying single well platforms is transported through the flowlines to a Central Facility Platform (CFP). There it is dehydrated and piped onshore to the Yellowhammer Gas Plant for treatment prior to sale. Four trunkline between the CFP and the gas plant (16 in. primary gas, 12 in. secondary gas, 8 in. produced water and 6 in. fuel gas line) were laid simultaneously from a single barge during Summer 1990.

FLOWLINE REQUIREMENTS

Lengths of the 4 flowlines connecting the satellite wellhead platforms to the Central Facility Platform are summarized below. A fifth wellhead platform (JC) is connected to the CFP by a bridge.(available in full paper)

Water depths in the Fairway Field range from 39 feet at the deepest wellhead platform to 15 ft at the shallowest point along the flowline routes.

Flowline Design Criteria

Under normal operating conditions, the gas pressure will be reduced at the wellhead to less than 2000 psig. The maximum design operating pressure for the flowlines, however, is defined by the maximum shut-in tubing pressure of 10,600 psig. The gas is produced at temperatures up to 280 deg. F and cooled on the wellhead platforms to a maximum of 230 deg. F before entering the flowlines. The flowlines arenot insulated and are trenched to a minimum depth of 6 ft.

The design natural gas composition includes 2.1 percent hydrogen sulfide, 6.0 percent carbon dioxide, and 4.9 percent water.

Utility Line Requirements

A Utility line bundle was also instilled between each of the 4 satellite wellhead platforms and the wellhead platform (JC) next to the CFP. The utility line bundles each consist of six pipes (air, diesel and water lines at 1.500 in. OD; and methanol, fuel gas and spare lines at 1.000 in. OD) and a 5 kV electrical power/communications cable. Design maximum operating pressures for the utility lines ranged up to 6,000 psig.
Downhole Packers for Use With ESP Completions
Authors: Teifer George
Published: October 2008

This paper will describe how a resettable pump packer was designed and tested for use in the North Sea. A fully reset table packer where the setting forces are locked in can save the operator the cost of a workover in a situation where only minor wellhead repairs are required.

The RESETTABLE PUMP PACKER was designed specifically to overcome this problem. It is unset by straight pull release and automatically "re-cocks" itself to allow for a further setting. It will also totally relax and allow safe manipulation of the string between settings as there is a device to prevent premature resetting

INTRODUCTION

Since the early 1980's ESP's have been run in the North Sea and their-use and application will increase significantly as the larger fields mature and and new fields come on stream. The packers used in ESP completions are essentially dual packers with the long string commonly 4.1/2" tubing and the short string 2.3/8" tubing which is used to allow passage of the heavy duty power cable. They are hydraulically set and released by straight pull on the tubing. They have, however, suffered from the major drawback that once unset they cannot be reset and must be pulled from the well for replacement. On many occasions, immediately after installation, there have occurred minor mechanical or electrical problems at or near the wellhead. This necessitates raising the tubing string to gain access which, of course, unsets the packer. The operator now has a costly and time consuming trip to perform.

Many ESP completions do not include a packer which means that the fluid in the annulus is allowed to find its own level. This practice is not acceptable in the North Sea and so a packer is used to anchor the tubing 'and seal off the annulus. High GOR wells will normally locate the packer near the surface to allow for gas venting. Resettability is not such a strong requirement in gas vented wells as the time taken to pull and re-run a packer to say, 600' is minimal. However, with deep set non-gas vented packers the argument for using a resettable packer is strong as the cost of a workover on an offshore well can exceed one million U.S. dollars. Fig 1 shows a cross section of a typical pump packer. The main string (1) is usually maximised in size and would normally be 4.1/2" OD for a packer set in 9.5/8" casing, 3.1/2" if set in 7.5/8" and 2.7/8" set in 7". The electrical cable string (2) is used to house the electrical penetrator which is normally fed through from the lower end of the packer and sealed off at the top end. A third string is often included and used to attach a pressure/temperature gauge or used for gas venting. Fig 2 illustrates other features such as a chemical injection or instrument line but as packers become multi-stringed there is more potential for "things going wrong" and hence resettability becomes more attractive.
Why That Great Discovery Wasn't So Great: The Limitations of 2D Seismic
Authors: Denham L.R.
Published: October 2008

Many small to medium-sized oil and gas discoveries turn out to be much smaller than anticipated at the time of the discovery. One reason for this is the continued use of conventional 2D seismic data for prospect development and pre-drilling economic evaluation, without ensuring that only dip lines are used for interpretation. The limitations of 2D data have been known for many years1234. A computer model study of a small gas-filled sand bar embedded in shale shows that interpretation of a " bright spot" from a grid of lines with a spacing as small as 500 m can give an area for the amplitude anomaly nearly six times the area of the sand body. This type of error can be avoided by using 3D seismic data for prospect development.

THE PROBLEM

Many small to medium-sized oil and gas prospects me successful in that they are classified as discoveries, and are perhaps even completed and produce hydrocarbons, but are abandoned before even a small fraction of the reserves estimated to be present (before or even after the discovery) have been produced. Sometimes, a 3D seismic survey is used after the discovery to appraise it for efficient development, and this shows that the size of the prospect has been grossly exaggerated in the previous interpretation based on 2D seismic data. In this case, development of the discovery is usually no longer economical. My personal experience is that this kind of problem is more common when the prospect is based solely or mainly on seismic reflection amplitude anomalies (" bright spots") than when there is a defined structural trap. The study reported here was prompted when I was told an operator who had looked at about twenty blocks for a Gulf of Mexico lease sale had decided not to bid on any of the blocks for which he had 3D seismic data.

ANALYZING THE ERRORS- METHOD

To investigate the possible size of errors in the interpretation of a 2D seismic survey, I built a simple computer model of a small gas-filled sand bar. The base of the sand bar was placed on a horizontal surface, to remove the effect of dip as far as possible. Using this model, I generated a grid of four synthetic seismic lines to be interpreted as if they were line shot across a real prospect. Two of the lines wereclose to " dip" lines, that is, lines which are close to normal to the strike of the sand bar, and two were close to strike lines. The synthetic data set showed the expected amplitude anomalies from the sand body.

I interpreted the four lines as if they were real data, and generated a contour map of the amplitude Anomaly. From this map I picked a location for an exploration well. A well in this location on the model would find nearly 5 m of gas-filled sand.