bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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.
Biological Noise On Seismic Data
Authors: Fulton T.K. 
Published: October 2008

ABSTRACT
The geophysicist increases the resolution of the subsurface by using closely-spaced detectors. Ambient noise becomes more important with the short recording arrays so as to increase the importance of biological noise. It becomes causes a crew to stop shooting rather than simply degrading the final results Planning acquisition with knowledge of the habits and sounds of creatures can reduce possible down time and additional processing costs to attenuate the noise Noise avoidance is both cost effective and environmentally desirable. The objectives of this paper are to illustrate some noises, identify others, and alert the industry about the problem.
The problem is not new; biological noise also degrades the ability of the Navy to identify distant ships. The sources of biological noise are migratory. Navy research and data bases of biological an ambient noise can be useful to the seismic industry to enable it to avoid the noise when possible.

INTRODUCTION
Forget what you've heard about the silence of the sea. It's not always quiet down there. Many fish and other animals grunt, squeak, or whistle by grinding their teeth vibrating their swim bladders, or by burping out air. While the spectrum of most fish noise is higher than the useful seismic spectrum, many whale noises are near 20 Hz. Noise due to shipping, on the other hand, clusters around 50 Hz. An authority on ambient marine noise indicated that at one time, noise at 20 Hz was thought to also be due to shipping as peaks in the spectrum at 20 and 50 Hz seemed to change together with the relative amount of shipping. It seems that whales, like humans, just â??talk' louder in a noisy environment. Background noise has also been noted to increase with seismic activity in a similar way. While biological noise may increase with the presence of a seismic survey, the failure of the sources to leave the area allow one to conclude that the sources are not threatened. The proximity of biological creatures to the seismic sensing cable allows their noise to be a problem. Noises from toad, menhaden, croaker, drum, and cat fish can be detected for perhaps 1000 feet Snapping shrimp are also responsible for a high ambient noise level.

OBSERVATIONS
The seismic industry has long had problems with shark damage to its recording cables. Figure 1 (reproduced from OTC paper 4929) shows a shark bite which damaged a cable. Manta rays have also become entangled in recording gear to cause damage.
Biological noise can be thought of as a point source near the seismic cable. Energy from such a source arrives at the cable to form a pattern dependent on the offset. The left portion of Figure 2 shows predictable first break patterns as a function of offset and spread geometry. The right hand portion shows a shot record with a separate noise source at an offset of about 1000 feet estimated from the curvature of the arrival time pattern.
Reservoir Management Aspects Of Producing Oil From Thin Oil Rims In The Troll Field
Authors: Kydland Torgeir , Wennemo S.E. , Olsen Gudmund 
Published: October 2008

ABSTRACT
The 22–26m thick oil zone in the Troll West Oil Province, offshore Norway, is planned to be developed by 18800m long horizontal wells. The viability of such wells has been proven by long-term testing. To obtain economic oil production the wells will be completed in the lower part of the oil rim close to the oil-water contact. The high water production which is expected can, to some extent, be controlled by gas reinfection. A flexible gas injection scheme will therefore be implemented.
Allowing wells to produce free gas together with the oil (supercritical - production) has been shown to accelerate oil recovery and to improve lift and balance well pressures at the subsea manifolds.
The complexity of the Troll field together with simultaneous oil and gas production from different parts of the field makes development planning and reservoir management a great challenge. Significant movements of the fluid contacts across the field are expected. To predict the global effects accurately in addition to local phenomena, such as gas and water coning in oil wells, very flexible simulation models have been constructed.

INTRODUCTION
The Troll oil and gas field is located in 300m water depth offshore Norway and covers an area of 700km2 (Fig. 11. It contains an up to 26m thick oil rim sandwiched between a large gas cap and an active aquifer. The field consists of three easterly tilted fault blocks (Fig.2). In the western most fault block, the Troll West Oil Province (TWOP), the oil column is 22- 26m thick. The estimated oil in-place in this province is 155x106m3. In the central fault block, the Troll West Gas Province (TWGP), the oil zone is 12 – 14m thick and the estimated oil in-place 440x 106Sm3. In the Troll East fault block the oil column is only O - 4m.
The major gas accumulation is found in Troll East with a gas in-place estimated at 1072x109 Sm3. In the TWGP the estimated gas in-place is 570x109Sm3, and in the TWOP 2.7x109Sm3.
The development of Troll is divided in three phases. Phase 1 includes gas production from Troll East and is planned to start in October 1996. Phase 2 covers development of the oil resources. A plan for development and operations(PDO) of the oil in the TWOP was prepared during 1991 and was approved in 1992. This plan assumes production startup by the beginning of 1996. Oil production from the TWGP is presently under evaluation, The TWOP development concept has flexibility to include a future development also of the oil resources in the TWGP.
Phase 3 includes large scale gas production from Troll West. The gas strategy will be coordinated with the oil production and will not be settled until the extent of the oil development in the TWGP has been defined.
Development Of Shuttle Tanker Loading Systems In The Norwegian Sector Of The North Sea
Authors: Krogstad Ivar 
Published: October 2008

ABSTRACT
The bow loading systems developed for the Norwegian sector are relatively sophisticated. Continuous improvement in the designs has taken place.
Several of the components we have developed have new advanced features:Chain stopper releasable up to the chain breaking load.Crude oil coupler for engagement with self closing hose termination piece.Drum with radial rope outlet which eliminates chafing contact.Cardan suspension of the crude oil riser which allows both the use of conventional pipe swivels and a load cell carrying the complete riser load.
All crude oil transported from the Norwegian sector of the North Sea passes through the above system. This system is also used in the British sector and in the first loading system offshore Nova Scotia. The number of offloading operations has passed 4000.

INTRODUCTION
The weather conditions in the North Sea are harsh and the strain on the mooring and crude oil transfer equipment is considerable. In the Norwegian sector there has been a continuous development of the shuttle tanker loading systems. This development is carried out partly to counteract heavy strain, but the main reason for the modification of the tanker loading systems is changes in the loading buoy design.

LOADING BUOY TYPE AND CHANGES
Fig. 1 shows the location of the various crude oil fields with shuttle tanker loading facilities. The present, and some future such fields, are summarized as follows: Crude oil loading from two CALM buoys was started at Ekofisk in July 1971 and terminated in October 1975 when the pipeline to Teeside was put into operation1,4
In 1978 the first articulated loading platform (ALP) at Statfjord was put into service and later four similar buoys installed, two at Statfjord and two at Gullfaks. The two first Statfjord buoys were later replaced by subsurface loading buoys without mooring facilities (UKOLS).
On the Oseberg field the test production phase 1986–88 was carried out by means of a PTS vessel with stern offloading facilities. A pipeline to Sture took over the crude oil transport.
On Haltenbanken further north in the Norwegian Sea a floating loading platform will be installed on the Draugen field in 1993 and two subsurface buoys for turret mooring and oil transfer are intended for the Heidrun field.

SHUTTLE TANKER BOW LOADING SYSTEMS
The shuttle tanker loading systems used to date in the Norwegian sector of the North Sea are bow loading systems (BLS), i.e. both the hawser and the hose are connected to the tanker bow section. The hawser connection for these shuttle tankers are in the vessels centerline. The position of the hose connection is in the centerline below the hawser connection on the Statfjord and Gullfaks tankers, and on the port side of the forecastle deck for the remaining systems.

EKOFISK TYPE1,2,4
A "self-mooring" system was specified for the shuttle tankers. The 12 inch circ. floating polypropylene messenger was picked up by a grapnel, hoisted through the SPM fairlead and connected to a dummy line from a traction winch.