bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Design and Analysis of a TLP 9 5/8-in. Threaded Connection
Authors: Valka W.A. , Fox S.A. 
Published: October 2008

ABSTRACT
The design of a 9–5/8 inch threaded connection for long term production applications is presented. The threaded connection was designed for joining sections of 9–5/8 inch production riser for a tension leg platform in 1600 feet of water for the Santa Barbara Channel. The connection utilizes a tapered thread profile, a preloaded external shoulder and a primary metal-to-metal pressure seal at the nose of the pin.
The following items were evaluated for the threaded connection using finite element analysis and the results are presented: the ability to transmit the applied static loads. the ability to survive the applied cyclic loads and the ability to maintain a seal under all load conditions.

INTRODUCTION
A production riser connector for long term service must satisfy requirements similar to both drilling riser and normal casing connectors. Like a drilling riser connector, a production riser connector must withstand significant load variations in the riser and be designed for fatigue. In addition. like a casing connector. a production riser connector must be designed for full well pressure in case of a tubing leak and for major workovers. Metal to metal sealing is also required due to the long term application.
Production risers, 9–5/8, were studied for the TLP application considered. Riser analyses were performed to determine the maximum combination of bending and tension loads at any point in the riser for various design conditions. These conditions and loads are summarized in Table 1. In addition to these loads. a full spectrum of bending loads for fatigue design was determined. The spectrum was in the form of bending load ranges and number of corresponding cycles in a years time.

FEATURES OF THE CONNECTOR
The connector chosen to satisfy these conditions consists of a box and pin member with a two thread per inch, two inch diametral taper per foot thread. The nose of the pin forms the metal-to-metal primary pressure seal by creating an interference fit with the box during assembly. The seal is pressure energized which assures sealing integrity without the need for excessive interference and resulting high assembly stresses. The connector has an external shoulder which is preloaded during assembly. The external shoulder provides for positive makeup. reduces the alternating stresses in the pin threads. and ensures that the connector will remain assembled. The connector ends are sized to weld directly onto the 9–5/8 inch pipe, therefore, upset pipe is not required. The connector assembly with overall dimensions is shown in Figure 1. Figure 2 shows the overall and detailed view of the connector box. Figure 3 shows the same view for the connector pin.
CIDS Completion And Mobilization To The Antares Site
Authors: Phillips G.W. , Chen A.C.T. 
Published: October 2008

ABSTRACT
The Glomar Beaufort Sea I was successfully mobilized to its first drilling location, the Exxon Antares prospect in the Alaskan Beaufort Sea, only 13-1/2 months after go-ahead. The paper reviews the completion of construction, describes the site surveys and its characterization, and details mobilization operations from Japan to Alaska.

INTRODUCTION
The Glomar Beaufort Sea I, a Concrete Island Drilling System (CIDS), is a United States Coast Guard certified Mobile Offshore Drilling Unit (MODU) and is classed by the American Bureau of Shipping as a Maltese Cross A-I Caisson Drilling Unit. Its structure is comprised of three basic stacked components:A compartmented A537 steel Mud Base 312 ft in length, 295 ft in breadth and 25 ft deep with raked sides.A central core prestressed and post-tensioned concrete BRICK, octagonal in shape, 234 ft across the flats, 44 ft in height, straight sided.An EH-36 (modified to -60"F) steel deck unit,290.5 ft in length, 274 ft in breadth, and 26 ft deep with raked sides built as two independent deck barges. The Glomar Beaufort Sea I (CIDS) was installed on its initial Alaskan Beaufort Sea drill site, the Exxon Antares' prospect, only 13.5 months after a letter of intent was signed with the Nippon Kokan (NKK) shipyard in Japan and 10 months after the first concrete was poured. At the peak of activity, 4 shipyards and 2 offsite facilities utilizing over 1600 workers were engaged in fabricating the principal sub-assemblies: mud base, brick, port and starboard deck barges, drill rig, and quarters. Numerous papers and articles have detailed the design (References 1 through 15). This paper summarizes the completion of construction and its mobilization to the drill site.

CONSTRUCTION COMPLETION

Mud Base Construction
Construction of the Mud Base began at NKK's Tsurumi Works on September 28, 1983 and continued until March 13, 1984. The Mud Base was launched by skidding it onto a submersible barge. This created an interesting multiple degree of freedom problem involving variable and offset loads and inclination of the barge coupled with tidal effects that the shipbuilder resolved with a computer controlled barge ballast system. The Mud Base was then launched from the barge and towed 250 miles from the Tsurumi works to the Tsu works to await assembly with the BRICK. After arrival at Tsu, a 3 inch thick asphalt rubber compound was applied hot over the entire top of the Mud Base within the shear curb using conventional road building equipment to evenly distribute the load from the BRICK into the Mud Base structure. The asphalt rubber compound was developed and tested under contract by B.A. Va11erga, Inc. and consisted of 15% asphalt paving grade binder, which contained 20% ground vulcanized rubber, and 85% aggregate, made up of 70% clean dry river sand and 30% Meso1ite.
Offshore Pipeline Construction By A Near-Surface Tow
Authors: Tatsuta M. , Kimura H. 
Published: October 2008

ABSTRACT
A pipe tow method is one of the most economical ways to construct offshore pipelines. It is a method that does not require large equipment such as a tensioner or a lay barge. The long pipe strings, however, are affected by waves and currents. If a surface tow is adopted, the action of waves is severe and results in high dynamic stresses. The effect of wave force has strong nonlinear characteristics. It is therefore important to establish ways to evaluate the motions of long pipe strings in waves.
Model tests were conducted using three types of models. A computer program based on the finite difference method was also developed to analyze the dynamic response of pipe strings to waves. Test models were analyzed by the program, and the validity of the analysis method was confirmed.
This paper discusses the results of the model tests, theoretical calculations and fatigue investigations. It also describes the near-surface tow method used for offshore pipeline construction in Chengbei oil field in 1985.

INTRODUCTION
For constructing offshore pipelines, the most popular method is the lay barge method. For waxy crude .oil pipelines insulated by a coaxial system, however, a large amount of welding is required. But a tow method presents great economical advantages, compared with the lay barge method. In an area where the water is shallow and the seabed consists of soft clay, the surface tow method and the near-surface tow method are preferred over the mid-depth tow method or the bottom pull. method.
During towing, the pipe strings are affected by waves and currents. They are bent by currents and develop dynamic stresses under wave action. Wave induced cyclic stresses may cause fatigue damage in the pipe strings. The waves also create dynamic forces. in the bands which connect the pipe and the floater.
The method to predict the motions of long towed pipe strings was reported by Verner et al.(1984)! No reports have been published on the influence of wave action on pipe string motion except by Costello et al.(1983),2 though they provided no detailed information concerning wave influence.
Until now, no elaborate method to predict the pipe motion during towing has been available because of the considerably complicated analysis that results from the interaction between the wave and the pipe-floater system. A constructor has to select comparatively conservative conditions on the basis of past experience.
If we can evaluate the critical sea conditions for towing and the degree of fatigue damage during towing, the safety of surface and near-surface towing can be ensured and the tow method can be applied to a wider range of sea conditions than previously.
To predict the influence of wave action on pipe strings, model tests, theoretical calculations and fatigue investigations were conducted. The results are described in this paper.
The Eider Production Platform Concept: A Platform in Deep Water With Small Reserves
Authors: Smulders B.H.N. , Franklin J.L. , Logan B.L. 
Published: October 2008

1. ABSTRACT
The Eider Field is a relatively small North Sea oilfield in 157m (515 ft) water depth. A cost effective design was essential to allow economic development of the field.
This paper describes a number of unique features of the Eider development which include the minimisation of platform based facilities by extensive use of two nearby platforms, state of the art jacket design, a large integrated deck containing all process facilities and utilities, a power export facility to utilise excess gas, and a control and safety system to allow manned and unmanned operation. As a result of these and other measures the capital and operating costs were substantially reduced below the original budget estimates.

2 FIELD DEVELOPME NT

2.1 Reservoir
The Eider Field is located in Block 211/16a and 211 /21a in the UK sector of the North Sea, some 187 km north east of the onshore oil terminal in the Shetlands, and 13 km north of the Shell/Esso existing North Cormorant platform (Fig 1). The field is an elongated banana shape of about 8 km length, with oil bearing formation at around 2750m (9000 ft) below sea level in the Middle Jurassic Brent group of sands. The field can be developed from a single platform.
The current expectation of recoverable reserves is 85 MMSTB (million stock tank barrels), which will be produced at an average oil rate of 45,000 BPD in the peak year requiring a peak gross capacity of 65,000 BPD. Pressure maintenance by means of water injection at a peak of 75,000 BPD will be required almost from the start of production, and will be managed to ensure natural flow of the wells throughout the field life of 20 to 25 years. The Eider Field is being developed by Shell UK Expro, the operator for the joint venture between Shell and Esso.

2.2 Concept Development
When a project team was formed in April 1984, the proposed concept was a stand alone fully integrated steel platform at an estimated MOD (Money of the Day) cost of just over £900 million, including drilling. The proposed concept was fully self supporting with oil being processed to satisfy the Brent oil transportation system requirements for entry at the nearby North Cormorant platform. The concept had been chosen on the basis of three exploration wells and preliminary reservoir studies, which estimated the recoverable reserves at 115 - 125 MMSTB.
Shortly thereafter the full 3D seismic studies reduced the estimated reserves to 85 MMSTB and the economics of the original concept were at best marginal. In a first review the original platform was scaled down for the lower throughput but this resulted in only marginal savings. Then the project went back to the drawing board reviewing many alternatives including floating production units and subsea developments. The new "composite satellite" concept as described in this article was finally selected.
Measurement Of Ekofisk Subsidence
Authors: Rentsch H.C. , Mes M.J. 
Published: October 2008

SUMMARY
Subsidence of Ekofisk platforms was recognized late 1984. Several measurement programs were initiated to determine the subsidence bowl shape as well as the subsidence history at the seabed. The measurement programs are described, their apparent accuracies are shown and their contributions to specific knowledge of Ekofisk seabed subsidence is discussed.

INTRODUCTION
Phillips Petroleum Company Norway is the operator for the Ekofisk Field, located roughly in the center of the North Sea. Several platforms, located near the center of' this field, are connected by bridges. This group of platforms is referred to as the Complex. One of these platforms is a concrete tank structure, a perforated wall surrounds this structure. The field was discovered in 1969 and has produced oil and gas since 1971.
The Subsidence of the platforms at the Ekofisk Complex was noticed late 1984. The most obvious indication of seabed Subsidence at Ekofisk was a change in the number of visible holes in the breakwater wall on the Tank. When the Tank was installed in the summer of 1973, five holes were visible (Figure 1). Today only 3 holes are visible.
Another indication of subsidence was the obvious high water level with respect to the steel platform references. The boat landing of one of the older jackets (the 2/4-C jacket) was located at the water level originally. This boat landing was below water even at low tide in 1984. Certain inspection and maintenance work that could originally be done with scaffolding started to require divers. A map of the Greater Ekofisk Area is shown in Figure 2.
These indications were stronger than could be expected from platform settlement. This led to the SUsplcl0n of subsidence. Several measurement programs were initiated to determine if a Subsidence bowl was present and what the rate of subsidence might be.
The first measurements which clearly demonstrated the presence of a subsidence bowl were bathymetric measurements obtained along pipelines in the Ekofisk area during the summer of 1984. The pattern of the pipelines form a 10-armed starfish. It was possible to interpolate between pipelines to obtain a crude bathymetric map. A subsidence bowl was clearly evident from this mapping process indicating that the platforms were following the movement of the seabed and not just settling.
The methods for precise subsidence monitoring started during the 1984/1985 winter. Searching of historical files and intensive subsidence monitoring, permitted Phillips Petroleum Company to piece together a picture of the process of subsidence to date. From a review of all available data, a picture has been created to show the historical subsidence trends and the accuracy associated with these estimates.

DESCRIPTION OF MONITORING METHODS
Several measurements systems were used in determining the total amount of subsidence. They are illustrated in Figure 3. The pre-1984-measurements were not intended for Subsidence monitoring, so their accuracy is not as good as would be desired. Other monitoring methods were initiated after the subsidence was discovered.
Station Keeping In Deep Water: An Alternative To Dynamic Positioning
Authors: Wolff C.V. , Lohr C.J. , Wudtke D.J. 
Published: October 2008

ABSTRACT
As recently as 10 years ago, deep water for drilling rigs was 600 feet and beyond. Really deep water, 1000'+, was on the horizon but reserved for dynamically positioned ships. Only 2-3 years ago some experts still proclaimed that moored operations beyond 2000' were not possible or realistic. Today, a number of semi's moor routinely in 2000-3000' WD; the new Trendsetter class semi, "Zane Barnes," now operates in the Gulf of Mexico in up to 4000' WD, while D.P. drill ships are working beyond 700Q'. Both types are projected to go well beyond this with present day equipment. Although distinctly different, technologies for deep water mooring and dynamic positioning have come of age. They have proven reliable, effective, and economical. The question no longer is whether one could moor at all or should use D.P., but which is the more economical and expedient way to operate. Today, moored drilling operations are realistic in up to 6000' WD and may possibly exceed this with current state-of-the art technologies. Economic considerations will dictate where the transition to D.P. occurs. A hybrid, i.e., a semi that has deep water mooring as well as D.P. capability, may eventually evolve if market conditions demand drilling beyond 6000' WD. Design aspects of riser systems and sub-sea equipment will dominate and outweigh stationkeeping concerns.

INTRODUCTION
Reading & Bates has been a leader in deepwater mooring technology from the start. Until the "Zane Barnes" was built, the RB semi's "M. G. Hulme, Jr." and "Sovereign Explorer" have held water depth records in the North Sea. The key to success in deepwater mooring is the result of many factors, namely:Reliable design, analysis, selection, and testing of the mooring tackle, i.e., anchor, chain, and wire rope.Innovative design and selection of the proper machinery to store, deploy, retrieve, and tension the mooring lines.Design, selection, and use of a reliable and proven anchor handling system.Employment of a sufficiently powerful and adequately outfitted anchor handling vessel managed by an experienced crew.Selection and training of knowledgeable and experienced marine rig operating crews.Reliable and expedient engineering support during construction, start-up, and operations.
Design effort for the "Zane Barnes" got under way early in 1~84. The emphasis was on new technology, not simply scaling up existing designs. Many new ideas took hold and bore fruit. Today, one can simply state that most goals were achieved, and the "Zane Barnes" is a resounding success.

OBJECTIVES AND HISTORIC BACKGROUND
Primary emphasis in the initial concept formulation for a new class semisubmersib1e was put on much greater deck variable load, superior motion, very deep water capability, efficient and safe operating characteristics.
Previously, maximum water depth was approximately 1500–2500' for moored semi's, and about 6000' for D.P. drill ships. Market projections in 1984 were for 3000' WD in the near term, and 5000' in the long term.
With Poseidon Technology Towards Year 2000
Authors: Furuholt E.M. , Torp T.A. 
Published: October 2008

ABSTRACT
The Poseidon project aims at developing technology for subsea multiphase development of offshore oil and gas fields. This paper shows the potential of this technology through three synthetic North Sea field examples. The investment cost may be reduced by 10-40% using multiphase technology. Realizing this technology with an unmanned wellhead platform concept or a subsea (Poseidon) concept may give neglible cost differences. The main technical areas of concern are listed and some conclusions are drawn as to the future use of multiphase technology.

THE POSEIDON PROJECT
The Poseidon project was started in 1984 as a cooperation between Institut Francais du Petrole (IFP), Total and Statoil. The aim of the five year project is to develop the technology for subsea development of deepwater oil and gas fields. The concept, fig. 1 includes subsea wells, subsea multiphase pumps and long distance multiphase pipelines.
In this project, IFP has developed a multiphase pump. An industrial prototype of this pump will be tested in a flow-loop, outside Lyon late 1988. Total has developed the subsea station and put main emphasis on full-scale test of an electric motor for the multiphase pump. This motor was tested in 150 meters of water outside the west coast of Norway in the autumn of 1987. Statoil's part of the work has been the pipeline system. A computer program for dynamic simulation of multiphase flow has been developed and used to study slugging phenomena and transient behaviour during start-up and shut-down of the pipeline. Moreover, numerous tests have been performed to study hydrate formation in flowing media as well as corrosion and erosion in the presence of oil, gas water and sand. Special consideration has been given to corrosion under sand beds and inhibitor efficiency in the roof of pipelines carrying mainly gas. Instrumentation for reservoir monitoring and control of pump inlet conditions have been studied. Finally, Statoil has headed the field concept studies in which also personnel from Total and IFP have taken part. This paper will present some of the conclusions from these studies.

CONVENTIONAL OIL AND GAS FIELD DEVELOPMENTS
Fig. 2 shows the functions included in a conventional field development. To arrive at new concepts it is necessary to consider if all these functions are necessary and where the accompanying equipment should be placed.
Apart from the pipelines, the main part of the equipment and therefore also the investment and operating costs are connected to well control/manifolding, separation and pumping.
Well control and manifolding are always necessary. The question is therefore whether the equipment should be placed on a platform or on the sea bottom.
The equipment for separation and pumping is today always placed on a platform. Platforms for water depths of 70 to 500 meters, as in the Norwegian part of the North Sea, tends to be very large constructions, fig. 3. The Gullfaks C platform, which will be installed in 220 meters of water depths late this year, will cost in the order of 18 billion NOK.
I-Rjs-199 B: First Deepwater Test In Offshore Brasil
Authors: Sancho J. 
Published: October 2008

ABSTRACT
Elf Aquitaine acting as operator of a joint venture including Agif and Hispanoil spudded in November 1982 a well 1-RJS-199 B) by 808 meters of water.
This well, located on the South-east corner of the block ACS 50 at the top of a salt related structure, was drilled to a total depth of 5015 meters.
This block is situated on the northern margin of the Santos basin at less than 200 km of the main Campos discoveries.
The carbonates of the Macae formation and the turbiditic sands of the Ubatuba formation which constituted the main objectives of the well were recognized.
Significative shows of hydrocarbons were observed in the turbiditic sands of the Ubatuba formation. Carbonates of the Macae formation were completely tight.

GENERAL INFORMATION
The well 1-RJS-199 B has been drilled by the dynamic positioning drill ship "PELERIN" to fulfill the well commitment taken by the ELF - AGIP - HISPANOIL joint venture on service contract block ACS 50 (SF 23 - X - IV).
This block which covers an area of 2825 Sq km is located 75 km south of RIO de JANEIRO and 180 km south west of the Campos fields.
Drilling started on November 19th, 1981 on the top of a large salt related anticline.
Water depth on this location was 808 meters.
The well was plugged and abandonned on March 17th 1982 after reaching the depth of 5015 m.
The geographic coordinates of the well are as follows :X = 42° 03' 04" 87 WY = 23° 53' 03" 37 S

REGIONAL GEOLOGICAL FRAMEWORK
The Santos basin encompasses an area close to 120.000 sq km between latitudes 24° and 28°.
It covers all the continental shelf and extends over a large part of the slope.
A ridge appears beyond the 2000 m water depth (Torres - Trinidade ridge) which is underlined by a noticeable reduction of sediment thickness (less than 5 km).
This ridge marks the limit between the Santos basin and the Sao Paulo plateau where the sedimentary column grows thicker.
A major trenching fault (Santos fault) the outline of which is nearly parallel to the coast separates two large domains.
To the west of this fault the internal part of the Santos basin is covered by reduced series of Upper Cretaceous and Tertiary age only the thickness of which is less than 3000 m. Towards the coast it rests on the Precambrian series which are represented by the Serra do Mar.
This fault, the actual throw of which can reach 3000 m, has probably an ancient inheritance.
All its life long the internal part of the basin has been the site of an intense erosion.
It helped to feed the external part of the Santos basin located on the downthrown side of the fault where the sedimentary thickness can reach 9000 m.