bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Troll Oil Pipeline Project: A Welcome Challenge to Survey Technology
Authors: Trodal L. , Nilsen Ø. 
Published: October 2008

Abstract
The design and engineering of the Troll oil pipeline has been totally dependant on recent development within detailed underwater survey! mapping techniques. To achieve the required data accuracy, resolution and density, a large extent of the survey work has been carried out with Remotely Operated Yehicles (ROY). This project is considered a first step into the kind of detailed subsea survey work which will be required in deeper waters (1500-2000 metres) for engineering and construction purposes, within the next 5 years.

The project
The Troll Oil Pipeline is planned between the Troll West field in the middle of the Norwegian trench in the North Sea and the oil refinery at Mongstad on the west coast of Norway. The pipeline will transport the oil part of the large Troll gas field to shore. The construction of this pipeline will be completed within 1995.
The offshore section of the route starts at the Troll field in 320 meters of water. The generally flat and soft seabed is superimposed by numerous depressions (pockmarks) with a general horizontal size of 50 to 200 metres and a local depth of 5 to 15 metres. At 55 kilometres the route enters the coastal area where the terrain is dominated by rock outcrops and increasing slopes as the route enters over a threshold into the fjord area (the Fensfjord) and towards Mongstad (refinery). Just after the fjord threshold the route passes its deepest part in a depression with a depth of 540 metres. The remaining part of the route is along a flat and soft seabed (fjord bottom) with water depth ranging from 400 to 470 metres. The passage itself is rather narrow with very steep rock faces at both sides of the route.
The landfall will be through a mini-tunnel drilled from shore through bedrock in its full length of 760 metres with its exit point at 3 15 metres of water.
The route, route profile and terrain is shown in figures 1 and 4. Figure 4 is a hill shaded image (based on a digital terrain model) of the general bathymetry ofthe last 30 kilometres (inshore section).
The engineering challenges for this pipeline route has been the landfall and the fjord threshold area, where the critical issue has been whether pipeline construction is feasible within such a terrain. The final construction solution from kilometre point (ref figure 1) 55 to shore includes the following:pre-laid gravel supports (in total 29) amounting to 23000 m3 of gravellow-tension laying to reduce free-spanning of the pipelineshore-approach solution within the steep rock face to Mongstadremoval of soft sediments at the mini tunnel piercing areaareas which have to be avoided due to potential instability of sediment and boulders from the steep fjord sides.

Survey technology
From the survey technology point of view the challenge has been to establish reliable data with the required accuracy, resolution and data density for pipeline feasibility studies and design in such a terrain as represented by the fjord threshold area and the landfall.
The Impact of Green Water on FPSO Design
Authors: Buchner B. 
Published: October 2008

ABSTRACT
For weather-vaning turret moored FPSO's in survival conditions the bow is always exposed to the wave action. When the waves come above the freeboard, this can result in considerable amounts of green water on the deck. This can cause damage to the sensitive equipment at the bow, like the fluid swivel, piping, turret structureand chemical stores. Taking also into account the tendency in several new designs to place the accommodation superstructure forward of the turret at the bow, the impact of green water on FPSO design will become more important in the future.
Based on a series of mode/ tests this paper presents an rientation into the various aspects which play a role in the green water loading on FPSO units. First the occurring phenomena are described. Second the effect of the environmental conditions, such as the wave height, wave period and current velocity, are highlighted. Finally several design aspects are considered. The influence of the bow shape, the position of the equipment on the deck and the shape of breakwaters will be discussed.

INTRODUCTION
For ships and naval vessels, green water damage to superstructures, deck plating, hatches and topsides equipment is a common occurrence. However, methods for the prediction of green water or deck wetness arelimited in number. Based on model tests with a frigate, the author showed in [1] that these methods are sometimes based on assumptions which can be questioned. It was concluded that the development or improvement of these types of prediction methods is indispensable for the evaluation of the operability and safety of ships in rough seas.
For turret moored FPSOs the same conclusion is valid. However, contraty to ships or naval vessels, permanently moored FPSOs cannot change their heading or speed when they come into survival conditions. They should therefore be able to deal with all the loads related to these extreme conditions. In the past the investigation of system safety was generally limited to the mooring loads, the low-frequency motion behavior and related topics. However, in recent years the impact loading due to slamming and green water has become a more important factor in the design of FPSO'S. Due to the fact that the bow of this type of weather-vaning system is always exposed to the wave action, considerable green water loading can occur to the sensitive equipment at the bow. The fluid swivel, piping, turret structure and chemical stores can therefore be damaged. Taking into account the tendency in several new FPSO designs to place the accommodation superstructure forward of the turret at the bow, the impact of green water on FPSO design will become more important in the future.
The main objective of the present study was therefore to investigate the phenomena, problems and trends in green water occurrence and loading. This will be done based on an extensive model test series with a typical FPSO. The present paper presents an orientation into the problem. In a later stage, more detailed analysis [2] and computational aspects will be highlighted.
Barracuda Field: New Records for Turret Moored FPSO's
Authors: Carneiro P.R.B. 
Published: October 2008

ABSTRACT
An early production system will introduce everal innovations and set records when it comes on stream at BARRACUDA, the third largest of the giant oilfields offshore BRAZIL.
The floating production unit will be a 52,000 dwt FPSO, turret type mooring and a process plant with capacity to process 30,000 bopd.
It will remain on location for a minimum of five years. The tanker modifications and overhaul are nderway. The FPSO will be prepared to Process the oil and offload it to a tandem moored shuttle tanker. The produced gas will be both reinfected and exported to shore through adedicated riser pipeline.
This unit will comprise the world's largest turret with capacity for 34 risers and the world's deepest FPSO, moored in 840 meters Water depth.

INTRODUCTION
The development of BARRACUDA field calls fOr three production units supporting some 145 wells, between oil and gas production and water injection wells. Peak production is estimated at 190,000 bopd and 83.5 million cubic feet per day of associated gas. To achieve these goals, PETROBRAS will first bring a pilot production system on stream, to get more information on the reservoir. In this phase 11 production Wells will be completed, ten of which have already been drilled. More than 40 kilometers of flexible production bundles, 12 kilometers of flexible risers and eleven wet Christmas trees are also envisaged.
The Floating Production Unit will be an FPSO, with a process plant with capacity up to 30,000 bopd, a turret mooring system and a stackabie multi-path swivel.
This paper describes the technical aspects of the processing tanker "P.P. MORAES" conversion itItO a Floating Production Storage and Offloading unit to be installed in very deep waters.

"P.P. MORAES" HISTORY
The process tanker P.P. MORAES was built in '1959 as Crude Oil Tanker of about 33,000 dwt. In 1974 she was jumboized to 52,000 dwt. Finally, in 1979the vessel was converted into a Crude Oil Processing &Storage Tanker with a 60,000 bopd process plant.
The current main characteristics of the vessel are the following:
(Available in full paper)
The helideck was designed for a SIKORSKY S-61 or similar helicopter. The vessel has operated for 14 years in Campos asin - Brazil (from Dec 1979 to May 1993), as an FPSO with a Calm-Yoke System, in Garoupa field and more recently as the Pilot production unit of Albacora Field.

SUBSEA LAY OUT
The BARRACUDA pilot system comprises 11 satellites producers wells spread around the FPSO. Figure 1 illustrates the FPSO and the well locations, as well as the flowlines and the gaspipe routes possible.

FPSO NEW CHARACTERISTICS DESCRIPTION OIL SYSTEM
Crude oil from the wells will be brought to a common production header before passing through the swivel. Two filters, in parallel, will retain any solid wax formed inside the lines. Theoil will then be heated to 40 deg. Centigrade, to hamper wax crvstal fOrmatiOn and ease oil/9as separation. The oil stream shall then go into one of the two main separation trains.
Gryphon A - Features and Operational Benefits
Authors: Doble Paul A.C. , Workman Dave M. , Addy Peter 
Published: October 2008

ABSTRACT
The Gryphon A Floating Production, Storage and Offloading (FPSO) unit has a number of novel designfeatures. These features include a unique hull shape, an anchoring system with thruster-assisted mooring, a sliding bearing turret and a transfers system across the turret based on a drag chain. A simple hose system loads shuttle tankers from cargo tanks with a capacityof 525,000 barrels. Gryphon A has now been in operation in the North Sea for over a year, including one of the worst winters for many years. This operationally tested man y of these features.
The technology of FPSOs has developed such that they can be used in man y different environmental conditions. Development of previously uneconomic reservoirs isnow possible because of 10w capital and operational costs of FPSOS. However, costs may be reduced further with effective specifications for FPSO'S
This paper describes the operational experience of the Gryphon A FPSO and ho w that experience can be used to develop more cost effective FPSOS.

BACKGROUND
Gryphon A is a ship shaped floating production, storage and offloading unit (FPSO) located in Block 9/18b in the North Sea. Its location is 200 miles North East of Aberdeen, Scotland.
Papers presented at the Offshore Technology Conference in Houston in 1994 (References 1 to 3) describe the ship in detail.
In summary (Figure 1), the ship is 257m long and operates in a water depth of 112 m. It is located fifteen hundred meters from a cluster of 12 subsea wells that include production, water injection, gas and aquifer wells. The process facilities can produce 60 MBPD of oil from 80 MBPD of gross fluids.
The ship went into production on 14 October 1993 and, since then, has operated extremely well. It has continued to operate throughout several Force 12 storms and has produced oil with a cumulative uptime from first production of over 96% (Figure 2). Production has never been shut down, or reduced, because of the weather. There have been no equipment failures attributable to weather or motion of the ship. Thirty-five tanker lifting have exported over 15 million barrels of crude.
With this background this paper outlines, qualitatively, some of the criteria used in designing the Gryphon A facilities and the lessons learned through the operation.

SHIP PERFORMANCE
The design of the Gryphon A process facilities was based on performance criteria obtained from modeltests. The overriding requirement was for all equipment facilities to remain in operation through a one year return storm. Production equipment was designed to operate with pitch and roll of six degrees(single amplitude), with a pitch period of 14 seconds and a roll period of 12 seconds. Equipment and facilities wererequired to survive and remain operable following a 100-year return storm. Ail structural elements were designed to withstand a ship damage criteria equivalent to a roll of 15 degrees.The flare tower, 41 .4m above main deck level, is positioned at the extreme aft, starboard side of the ship.
Requalification of an Unmanned Jacket Structure Using Reliability Methods
Authors: Dalane Jan Inge , Haver Sverre 
Published: October 2008

ABSTRACT
A reliability assessment of an existing jacket structure exposedto reservoir subsidence is considered in this paper. Due to reduced air gap the probability that a wave will hit the deck is increasing and this is crucial concerning the future safety for an existing structure. A consideration of the safety level as a function of subsidence is therefore established in order to identify when the safety level drops below an acceptable safetylevel and corrective actions must be taken. Reliability methods is used to describe the uncertainties involved in the problem and then used to make a cost optimal decision.

INTRODUCTION
Offshore structures do usually have a large reserve capacity. This reserve capacity is often measured in terms of a Reserve Strength Ratio (RSR) defined as the ratio between the load level causing global failure of the structure and the 100-year design environmental load. For a jacket structure in the North Sea, the RSR value is typically in the range of 2-4. This means that a very large wave is required in order to fail the jacket structure. It is therefore often claimed that the most likely failure mode for offshore structure is failure due to a wave hitting the deck. Large reservoir subsidence will reduce the available air gap of existing platforms considerably compared to what was used in the design load calculations. Loads caused by a wave crest hitting the deck will be very large. and deck mpact is therefore likely to be crucial regarding the structural safety of platform under such conditions.
If the code requirement to available air gap can not be met after a number of years in operation, e.g. due to subsidence. it must be documented that the platform has a sufficient capacity to resist the loads which can occur if a wave crest hits the deck structure. By using reliability analysis. the following important questions can be addressed:Is the present safety level acceptable?When are actions necessary in order to maintain an acceptable safety level?Which actions are most cost effective?
One advantage by a reliability approach is that it is possible to utilise a realistic description of the uncertain parameters. This is not possible by a standard code check.
The approach presented in this paper involves the following steps:Probabilistic description of the severe environmental conditions.Estimation of the loads caused by waves hitting the deck structure.Assessment of the platform capacity using a non-linear structural analysis.
The results of these steps are then build into a reliability formulation of the problem. and the annual failure probability for different subsidence levels are estimated. An unmanned jacket structure is considered in this study. If a structural collapse only have economical impact. the information about failure probability can be used to do a cost optimal decision regarding corrective actions. The example platform is a four legged jacket structure with K-brace configuration and located in a water depth of about 70 m.
The Application of the Reeled Pipe Method for Deepwater Pipelaying
Authors: Hebert C.L. , Dchani Hassan 
Published: October 2008

ABSTRACT
In the development of the Tahoe prospect, Shell Oil Company, designed the flowlines to be dual 4" nominal lines to begin in 1500 feet of water and laid to the Bud Platform in 273 feet of water. The flowlines were to be laidsimultaneously since they were to be tied into previously laid flexible jumper lines. The flexible jumpers were retrieved, the rigid pipewelded to the ends and the flowlines laidutilizing the Reeled Pipe Method to Main Pass 252, the location of the Bud Platform, where conventional risers were installed to make the surface connection.
This paper will describes the pipe laying techniques used for this project. Specifically, the improvements in stinger design to permit lower horizontal tension loads, the use of dualpipe reels to maximize productivity, and the advantages of laying from a DP vessel.

INTRODUCTION
Shell decided to utilize sub-sea technology in the development of the Tahoe Field. It Wi3S decided to pre-drill a well, install a control umbilical and lay the flowlines from the well location to an existing platform. The flowlines and control umbilical were tied into the well with the use of a Flowline Connector Assembly (FCA). The FCA was lowered and connected to the well by a drilling rig which was positioned at the well sight. Tahoe is located in 1500 feet of water at Viosca Knoll 783 and the existing platform, Bud, is in 273 feet of water at Main Pass 252.
The project consisted of laying approximately 60,500' of 4.5" × 0.438" wt, X-42 Production Line pipe and approximately 60,500' × 0.438" wt, X-42 Annulus pipe. Each flowline terminated with 300 feet of 4.5" × 0.531" wt, X-52 pipe. Both lines arc coated with Fusion Bonded Epoxy (FBE) coating as arc the field welds. Sixty-five (65) pounds of sacrificial aluminum anodes are attached to the pipe at 640 feet intervals. The plan was to recover two previously laid flexible pipe jumpers, approximately 2,()()() feet long, weld the rigid pipe to the flexible pipe and lay away from the WCII to the Bud Platform.
Because of the water depth and the complexity of the job, the DB 50 was the vessel of choice. The water depth was such that moored vessels arc difficult to work, although, there halve been some recent development to mooring systems that have increased water depths limitations. The DB 50's Dynamic Positioning (DP) system is well suited for this water depth. It was also decided to utilize the Reeled Pipe Method to install the flowlines. This would minimize the time in the field, as well as weather exposure for the construction vessel. This combination made for a very cost effectivesolution for this project.

PIPE REELING
The pipe, delivered in double random lengths, was welded and reeled onto the pipe reels at the land facilities in Morgan City, Louisiana, The pipe was fabricated into 360 feet long stalks and rolled onto the storage rack until sufficient stalks were completed to begin the pipe reeling process.
The Norne Field Development Overview
Authors: Adlam John 
Published: October 2008

ABSTRACT
The Norne field is the largest discovery on the Norwegian continental shelf in more than a decade with recoverable oil reserves of 450 Million bbl. Reservoir drive mechanism will be a combination of gas and water reinjection. The largest monohull production ship in the world will be built to develop the field. To improve theproject economics and company performance a clearobjective was established to reduce investments costs by 25-30% and a time from find to first oil of 5-6 years. The paper will describe both the concept development chosen to achieve these goals and the method of working used to find a simple robust solution to meet uncertainties in project development, reservoir nperformance and regional potential while maintaining a fast track approach.

INTRODUCTION
The block 6608/1O Norne field is the largest discovery on the Norwegian continental shelf in more than a decade. The field extends for 10 km, is 2 km wide and is located 200 km west of the mid-Norway coast in 380 m waters.
The Norne field is owned by a partnership of Statoil (50%), Saga (15%), Norsk Hydro (15%), Enterprise (1O%) and Agip (10%). Statoil is the operator.
Well 6608/1 O-2 first penetrated the Norne reservoir in December 1991. Appraisal well 6608/1 O-3 was drilled in 1993 and proved the field?s northerly extension.
Based on results from those two wells, a development project began in 1993.
Exploration well 6608/1 O-4 was drilled in a separate smaller structure north-east of Nome and proved some additional reserves.
To improve project economics and company performance, a clear objective was established to reduce investment costs by 25-30% to the established levelcurrent in 1993. The Nome organization in Sept. ?94 submitted a Plan for Development and Operation (PDO) to the Norwegian authorities for final approval firstquarter of 1995.

NORNE RESERVOIR
Norne hydrocarbons are located in sandstone rocks of the Lower and Middle Jurassic age. The column consists of a 100 m thick oil zone with an overlying gas cap. The reservoir is a flat structure and the top reservoir is at a depth of about 2525 m below mean sea level. The reservoir pressure is close to hydrostatic. At reference depth 2639 m below mean sea level the formation pressure is 273 bar and the temperature 98 degrees C. The reservoir quality is generally good with 100-to 2,500 md horizontal permeabilities.
Total field reserves are estimated at 160 mill. Sm3 of oiland 29 mrd. Sm3 of gas (free gas and associated gas). Based on reservoir simulation and risk analysis the most likely recoverable oil reserves is about 72 mill. Sm3 for a recovery rate Of roughly 45%.
The reservoir drive mechanism, will be a combination of water and gas injection. Produced gas will be reinfected into the gas cap and water will be injected into the water zone. The concept will be designed for alternating water and gas injection in the southern part of the field. Production wells will be located to delay gas and water breakthrough and to minimize gas and water production.