bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of the Spar Floating Drilling Production and Storage Structure
Authors: Glanville R.S. , Paulling J.R. , Halkyard J.E. , Lehtinen T.J. 
Published: October 2008

ABSTRACT
The Spar is a deep-draft floating steel caisson, which can be designed to drill, produce and store oil. It is very stable and relatively insensitive to deck loads. Drilling and production equipment are supported on the decks above the waterline. Oil may stored in the lower portion of the hull. The centerwell protects drilling and production risers down to 650 feet. The Spar can be moored with conventional or taut catenary mooring lines using embedment or pile anchors. Because of its deep draft and large displacement mooring line dynamic loads are relatively low. Fabrication and installation plans together with cost estimates are included for a 36-well design for Chevron in the Gulf of Mexico. Predicted motions under normal and maximum sea states are shown together with the results of global motion analysis using both frequency and time domain programs. The sensitivity of the design to mooring parameters, draft, diameter and Spar mass properties is discussed. Potential applications are briefly reviewed.

INTRODUCTION
The concept of a Spar (a slender vertical structure) stable floating ocean platform has been recognized for years. The Flip Ship (Fisher and Spiess, 1963) was built in 1962 as a stable platform for oceanographic measurements. Its favorable motion properties are well documented (Rudnick 1964, 1967, 1971). The potential for use of the Spar in the offshore industry was recognized in the 1970s with the construction of Shell's Brent Spar for oil storage and offloading in the North Sea. Other potential uses and the salient motion properties were discussed by van Santaan and deWerk (1976). Research on the Spar as a storage and/or production vessel was carried out by some oil companies in the mid 1970s, however additional use of the Spar concept did not materialize. It has again recently been proposed as a low cost production facility for remote subsea well sites (Kerckhoff and Pijfers, 1989).
This paper describes a full drilling and production Spar designed for a 2,700 foot water depth in the Gulf of Mexico. Oil storage is not a requirement for this site, but could be a major advantage of the Spar for remote areas of the world. The proposed Spar is an order of magnitude larger (in displacement) than the Brent or Flip designs, however, it retains the stability and simplicity intrinsic to the concept.

SPAR CONCEPT
The Spar is a large, deep draft, cylindrical, floating platform (Figure 1) designed to support drilling and production equipment and to store oil. It is permanently moored with multipoint catenary anchor lines over a multiwell seafloor template. Wells can be drilled and completed with the BOP stack either on the surface or on the seafloor. Risers are held in tension by hydraulic tensioners or by buoyancy modules (Figure 2).
The most obvious features of the Spar are its extreme draft, straight sides, large centerwell, and large displacement (Figure 1).
Rig-Automated Drilling: A New Concept Is Being Proven
Authors: Houston S.J. 
Published: October 2008

1. ABSTRACT
Major advances are being made in the reduction of overal1 platform weight and, hence, overall cost. A principle aim of the project has been the reduction of the number of men from this potentially dangerous work area. One result from the '86' price drop was the coming together of Strachan & Henshaw Ltd. (S&H) in collaboration with four oil companies, three British and one Norwegian with support from the UK Government and European Community to look at reducing considerably the cost of development drilling. The RA-D project which started 4½ years ago ends in late 1991 with 'spudding' (FIG. 1) of the first hole, to initiate the proving tests of the powerful but compact light-weight offshore derrick and pipehandling system. Based on fast handling of single tubulars from 3½" to 20" diameter and rated to 20,000 ft. depths with a 1,000,000 lbs hook load the system is aimed at meeting the requirements of the North Sea and Worldwide.

2. INTRODUCTION
The RA-D concept was conceived during an exploratory visit by S&H engineers a few years ago, to the North Cormorant offshore platform whilst looking for ways in which the company's handling capability could be applied offshore. An investigation into the automation of drilling followed after a serious paralyzing accident to a floorman when handling drill collars which was just one of the many hazardous jobs in drilling and indeed the oil industry.
Drilling rig automation is a long held ambition of many offshore Operators. A number of automated drilling projects have been undertaken around the world as a result of the drilling industry's great interest in automation. Drillers see automation offering them smaller, lighter rigs with lower manning levels which will reduce the risks of injury and at the same time, reduce platform size and cost. Drilling rig designers see that automated rigs are now more feasible as a result of better and more reliable components available from other allied industries. There have been significant improvements in the elements of automated drilling systems, from the sensors and computers needed to control them, to the automatic torque wrenches and power swivels which manipulate the drill string coupled with the versatility of automated pipe handling systems.
However 'progress' results from a desire of man to improve what he has but unfortunately the changes that 'progress' requires are not always readily accepted by him.
The 'Cullen' report makes 106 recommendations relating to safety management, design and equipment, planning and provision for emergencies, Whilst not addressing drilling specifically, there was a very clear message that industry must develop equipment which is reliable and reduces manning on the platform, Each Operator will be required with its contractors to provide a safety case demonstrating that the safety management system of the design build and operation of the installation and equipments are as safe as reasonably possible.
S&H came into the rig design business from a non-oil industry background.
Installing a Flowline Using a Snubbing Unit
Authors: Baugus V.E. 
Published: October 2008

ABSTRACT
A flowline for a subsea well was installed from a platform. The flowline was composed of a 100 foot long flexible pipe jumper and integral joint oil well tubing. A snubbing unit was used to make the tubing connections while an anchored boat pulled the pipe through a J-tube.

INTRODUCTION
In late 1989 a third exploratory well was drilled on East High Island block A-370. This well, in 371 feet of water, encountered Enough reserves to justify a subsea completion but not a platform. A key part of this development was the flowline which would connect the subsea tree to the existing "A" platform about a mile away. This paper discusses the design and installation of that flowline.

BACKGROUND
During the planning phase of the project it was determined that there was a J-tube on the platform which was empty. This J-tube was pointed within 8 or 9 degrees of straight at the subsea wellhead. There wasn't any equipment on the production deck that would interfere with access to the top of the J-tube and a compressor on the drilling deck was surplus and could be moved. This situation presented an opportunity to reduce costs by installing the flowline from the platform instead of using a pipe lay barge.
The idea of assembling the flowline on the platform grew out of past experience with putting in sub sea vent lines using a reverse J-tube method. This earlier work was loosely based on an Exxon patent1, since expired. The vent lines were assembled at the boat dock level of the platform using 6" Sch. 80 pipe, a slip bowl, alignment clamps and welding. The pipe invariably had to be restrained from "running away" down the J-tube until several hundred feet were pushed out onto the ocean floor.
The significant differences for the flowline were the smaller size, at 3½ inches OD; the greater length, at 5600 feet; the higher pressure rating, at 3500 psig; and the need for greater accuracy at the destination.

DESIGN

Threaded Joints
Because of the time required to weld and x-ray high strength or heavy wall pipe, the use of threaded connections was investigated as a cost effective alternative.
One result of choosing platform assembly of the flowline is the requirement that the pipe be fed down through the J-tube in a reverse pull. This means that virtually the entire flowline must traverse the curve at the bottom of the J-tube without damage. The radius of this curve is 100 feet. While welded flowlines are often pulled through J-tubes, threaded joints are not usually subjected to this kind of treatment. In order to obtain the highest possible joint strength, an early decision was made to investigate the various premium oil well tubing threads. It was felt that the special thread profiles and metal to metal seals offered by some of these joints might provide a reasonable solution to the bending problem.
Curved Flapper Safety Valves Reduce Flow Area Restrictions by 30%
Authors: Going W.S. 
Published: October 2008

ABSTRACT
A new design for surfs- controlled subsurface safety valves significantly reduces the O.D. to I.D. ratio. The development of curved flappers allows a tubing retrievable safety valve to be manufactured within a smaller O.D. housing without sacrificing flow area. Conversely, wireline retrievable safety valves of a fixed O.D. can now have a larger bore. The methods used in the design and manufacture of this new valve type have extensively benefited from advanced technology in both the engineering and manufacturing areas, The net result is a safety valve which allows operators to achieve maximum production rates from their cased hole investment.

INTRODUCTION
In well completions with subsuface safety valves the O.D. of the safety valve is frequently the limiting factor in selecting the tubing and casing size combinations. Consider the ease of a gas well with a flow potential limited by the production tubing frictional losses. Such a well completed with 7-5/6 inch 29.7 lb/ft easing will have a drift I.D. of 6.750 inch. The casing bore is then adequate to run 5-1/2 inch production tubing which has 6.050 inch O.D. couplings. However, when a safety valve is needed, the largest conventional tubing retrievable valve that will fit will be a 3-1/2 inch size with a typical bore of 2.812 inch. As an alternative, the operator may choose to run a wireline retrievable safety valve. In that case, the largest wireline safety valve landing nipple that will run in the casing is the 4-1/2 inch size. The standard I.D. for the 4-1/2 inch wireline safety valve is only 2.125 inch. One operator settled on running 5-1/2 inch tubing above a 4-1/2 inch landing nipple and then running 4-1/2 inch tubing for the balance of the well. With this arrangement, both the smaller tubing I.D. and the wireline retrievable valve create higher frictional losses than the tubing above the safety valve. For these wells a larger I.D. wireline retrievable valve would increase the flow potential.
Several North Sea operators have faced the same options with 10-3/4 inch casing with an I.D. drift as small as 9.504 inch. Their desire is to run 7 inch production tubing, but the O.D. of a 7 inch conventional tubing retrievable safety valve would be 11.000 inch. Some operators have chosen to run 5-1/2 inch tubing retrievable valves with 4.562 inch I.D. Others have selected the 7 inch wireline retrievable valve with a 3.625 inch I.D. Either choice has some limiting effect on the maximum producing rate. SINTEF's safety valve reliability surveys continue to point toward tubing retrievable valves as having the highest reliability.1 This fact makes the choice for wireline valves for high operating cost areas, such as the North Sea, increasingly difficult to justify. By using the curved flapper design, it is now possible to manufacture a full bore 7 inch tubing retrievable safety valve which will run in 10-3/4 inch casing.

VALVE GEOMETRY
Conventional subsurface safety valves typically use a flapper type closure to achieve the maximum I.D.
Scour-induced Free Spans
Authors: Bijker R. , Staub C. , Silvis F. , Bruschi R. 
Published: October 2008

ABSTRACT
The paper reviews the origin and effects of scour induced free spans as part of the self lowering process of submarine pipelines. Aspects of single free span development like initial embedment, the onset of scour, the rate of scour development, relevant stopping criteria, multiple span formation and critical free span development are described and discussed.

1. INTRODUCTION
Self lowering of submarine pipelines is known to happen in several parts of the North Sea.
Regular surveys of self lowering pipelines gave good insight in the overall result of self lowering and self burial.
However, the actual interaction between seabed and pipeline is more complex and is not yet completely understood.
This paper reviews the origin and the effects of scour induced free spans as part of the self lowering process of submarine pipelines in erodible seabeds.

2. SINGLE FRRE SPAN DEVELOPMENT
Immediately after laying of the pipe, it will settle somewhat in the seabed. Because of:Pipeline installation Increased contact pressure at the touchdown point due to the suspended span, and dynamic effects of the laying operation will contribute to initial embedment in the order of 2-3% of the pipediameter (in case of medium sand).Small scale hydrodynamic action Even moderate wave and current actions will induce hydrodynamic forces which lead to, albeit small, lateral motions of the pipeline which will also contribute to initial embedment. Hydrodynamic forces representing 10-20% of the submerged weight have induced cyclic lateral motions and eventually settlement of 5-15% of the pipeline diameter. See Figure 1 and 2.Seabottom unevenness The presence of small scale bottom irregularities at the moment of installation will result in non-uniform contact pressures and thus contribute to non-uniform initial embedment. It may be enough to avoid gaps under the pipeline in the "troughs" and embedment in the seabed corresponding to the average ripple height may be obtained. Scour induced free spans need a start. Sometime, somewhere along the pipeline there must be an onset of scour.
Due to irregularities in the seabed and variations in initial embedment, there will most probably, be locations along the pipeline where the scour will be initiated.In case no gaps are present, the onset of scour will occur at locations where the embedment is minimal, or at locations where the soil conditions are such that the wave generated pressure differences between either sides of the pipeline cause the intergranular flow in the sand, under the pipe, to initiate scouring.If small gaps are present, those gaps will cause the onset of scour. Model investigations showed that even in situations with moderate tidal velocities scour under a pipeline will occur due to increased bed shear stresses in almost any small gap below the pipe, also in cases with no sediment transport on the flat seabed. After onset of scour, a scour induced free span will develop:–the gap under the pipe will deepen till equilibrium depth;
Offshore Pipeline Drying With Dry Air and Pigs
Authors: Stowers H.L. 
Published: October 2008

A properl cleaned and dried pipeline, offshore or onshore, can be commissioned and operated with dehydrated gas without encountering any internal problems caused by water or solids.... The validity of this statement is slowly being acknowledged by natural gas transmission and distribution companies, primarily those companies that have had serious problems with wet gas, hydrates, freeze ups or equipment damage.
The ability to start up a new or recently hydro-tested dry gas pipeline without encountering any problems caused by the pipeline's internal condition is a compelling reason for cleaning and drying. It completely eliminates any possibility of regulator icing, hydrate formation and damage to delicate seats, seals and meters. Plus, a potential cause of corrosion is removed, the flow efficiency is improved and there will be no dissatisfied customers downstream.
There is no magical cure for a pipeline full of wet gas. Once a pipeline has been commissioned there is no way to avoid the embarrassment of having to spend unbudgeted funds to correct problems.
It is very difficult to dry a pipeline after it has been brought to operating pressure, because the affinity of natural gas for water is reduced drastically as the pressure is increased. At atmospheric pressure natural gas can hold approximately 30 times more water than it can at 600 psig. That means that water left in the pipeline after commissioning can be evaporated at a rate about 30 times slower than at atmospheric pressure. That rate is further reduced by the presence of some 1 to 7 pounds of water per mmscf already in the gas.
Some natural gas transmission companies have begun specifying that their onshore pipelines be dried to a dew point temperature of -38.5 degree F. which corresponds to 7 pounds of water per mmscf. A few offshore gas producers are also using that specification on offshore pipelines built to carry dehydrated natural gas. There continues to be more companies specifying dryness requirements every year and in a few years it will very probably be a standard requirement.
These reasons for cleaning and drying onshore natural gas pipelines also apply offshore where hydrate and internal corrosion problems perhaps cause the greatest concern. The conditions under which hydrates will form are well established and basically involve temperatures, pressures, gas composition and the presence of water. The conditions under which internal corrosion can begin are also well understood and include the presence of water.
If liquid water and water bearing rust and mill scale are removed from the pipeline, then the potential for internal problems caused by those items does not exit.
It is possible to remove the water, rust and mill scale from a pipeline but it is not as easy as running a few pigs. First, the hydrostatic test water is removed with a displacement pig, also called a dewatering pig (of which there are many types). But, the worlds most efficient dewatering pig is not going to dry the wall of the pipe.
Rapid Makeup Coupled Tendon Connection
Authors: Pallini J.W. , Milberger L.J. 
Published: October 2008

ABSTRACT
This paper discusses the design, analysis, and operation of a threaded tendon connection that uses a coupling having dissimilar thread forms on the two ends. This allows makeup of the connection by a partial turn of rotation of the coupling while holding the tendon tubulars fixed.
Also discussed in this paper are possible makeup tools and other features that can be incorporated into the connector.

INTRODUCTION
A TLP typically makes use of tendons, attached to the comer columns of the platform, to moor the platform.
Current and proposed designs for TLP tendons make use of tubular steel members of roughly 24 to 30 inches in diameter having three-quarters of an inch to one and one-half inches wall thickness. These tendons also extend well over 1000 feet in length.
Several methods exist for connection, transportation, and installation for the tendons. Tendons may be fabricated by welding pipe sections together on shore and floating the tendons to the installation site, where they are upended and installed. An alternative method is to deliver the tendon to the installation site, on a boat or barge, in sections. These sections can then be connected, using a derrick barge, and lowered into the water vertically as each section is added. In order to quickly connect the tendon sections, a mechanical connector must be incorporated on the ends of the tendon section.
The requirement for this connector include:Vertical assembly of up to 240 feet length tendon joint.Structural strength equal to or greater than the pipe body.Sufficient fatigue life for the specific application.Operational characteristics which allow for ease of installation.Ability of the connection to seal the tendon from sea water in most cases. These requirements typically lead to classic designs of weld-on threaded joints which make use of a male member (commonly referred to as the pin) on one tubular joint, which makes up to a female member (commonly referred to as the box) on the mating joint. Makeup of the connection normally requires rotation of one of the tubular joints with at least several turns, while holding the other joint fixed. This is a difficult task when dealing with the long tendon joints, particularly when working on a derrick barge which may be moving considerably while floating in the ocean. Performing this task can also require a very large fixture for aligning and rotating the tendon section.
There are also connectors available that snap together by forcing together male and female sections by using a hydraulic makeup tool to provide a high axial makeup force. These connectors usually make use of a shallow thread or annular grooves. This paper is not intended to address these type of connectors nor attempt to compare their load carrying capacities to this Rapid Makeup Coupled Connection.
The connector being presented here makes use of a coupling that contains a different thread type on each end of the coupling. (See Figure 1.)