bluuebunny/crossref_metadata_2025 huggingface dataset:
Evolution Of Subsea Production Systems: A Worldwide Overview
Authors: Hansen R.L. , Rickey W.P.
Published: October 2008

The evolution in the use of subsea technology has seen advancement -from I well in the Gulf of Mexico in 1961 to over 750 wells in a tide variety of locations by the end of 1993. Along with the growth in numbers, the industry has seen rapid advances in technology, distances from the host facility, and water depth records. This paper gives an overview of the evolutionary changes in subsea applications, with emphasis on the most active regions, and some of the milestone installations that shaped the technology advance.

INTRODUCTION

In the 33 years since the first subsea well was completed in the Gulf of Mexico in 1961, the use of subsea wells has spread to most offshore producing areas of the world, as shown by Figure 1. By late 1993, a total of approximately 752 subsea wells have been completed worldwide, with over 440 of these wells still in service. This paper will provide an overview of subsea technology development by focusing on three areas which exemplify the technology used worldwide:The Gulf of Mexico and West Coast of North AmericaThe North Sea andThe Campos Basin of Brazil.

SUBSEA TECHNOLOGY OVERVIEW

Subsea wells have been used in a variety of configurations. Typical arrangements shown by Figure 2 include single satellite wells consisting of subsea trees situated on their individual guidebases; subsea trees located on steel template structures with production manifolds; and clustered well systems which are single satellite wells connected to a nearby subsea manifold. These various design layouts and hybrid arrangements of them are usually produced back to platforms or to floating production vessels, although some have also been produced to shore. Over 50 floating production systems (FPS) have been deployed worldwide, with over 30 currently active.

Maximum water depth experience of subsea wells has reached 2562 feet in the Campos Basin and 2245 feet in the Gulf of Mexico. Figure 3 shows the water depth experience range for worldwide subsea wells. The deepest production experience to date is the Aquila extended well test by Agip in 2788 feet of water in the Mediterranean in 1993. Maximum producing distance to the host facility is 30 miles for a gas reservoir and 12 miles for an oil reservoir, both in the North Sea. Most subsea wells have produced by natural flow, but over 110 wells have been produced by gas lift. Pressure maintenance with subsea water injection wells is used where needed.

Well servicing or workovers can be performed using reentry from a floating drilling unit or jackup, Also, specialized techniques such as through flowline (TFL) operations can be performed downhole by pumping tools from the surface host facility through the flowlines and down the tubing. Chemicals can be pumped into the formation through the flowlines, and chemicals can be injected into the subsea tree or downhole by pumping from the surface host facility through hydraulic hoses in the subsea control umbilical. Pressure and temperature can be monitored at the tree or even downhole.
Marlim-4: A Subsea Production Well Overtaking Deepwater Frontiers-Part Ii-Completion Work
Authors: Dias Ronaldo
Published: October 2008

In order to bring into production Brazilian most prolific offshore fields, all of them situated in water depths beyond 400 m, Petrobras, the Brazilian Oil Company, has developed a simple, reliable and cost effective Guidelineless Wet Christmas Tree, designed for applications up to 1,000 m (3,281 ft) water depth]. After installing 16 such trees in Campos Basin, at a maximum depth of 781 m (2,562 ft), the Company faces the challenge of putting onstream Marlirn-4, a well at 1,027 m (3,370 ft) water depth, in the south area of the Marlim Complex. In addition to its strategic role in the Company's endeavor to produce from increasingly deep waters, Marlim-4 will also establish a new world record for subsea completions. This paper presents a brief summary of Marlim's development plan and describes the activities programmed for Marlim-4' s completion.

INTRODUCTION

Since the first oil strike in Campos Basin, back in 1974, Petrobras has been setting several milestones in the Offshore Industry, developing new production system concepts and improving subsea equipment design. Every achievement attained through these years was based on four major principles: careful planning, feedback from field experience, intensive research and courage to take risks.

As exploratory work went on, hydrocarbons accumulations were discovered in waters deeper than ever before, pointing out the necessity to upgrade the available technology to produce the newly-found areas.

From 1984 on, giant fields, such as Albacora and Marlim, were spotted in ultra-deep waters, representing a challenge harder than the previous ones. To cope with the difficulties of the new enterprise a step by step development plot has been chosen, aiming to get technological capability for fill recovery of the existing reserves, placed in water depths ranging from 400 m (1,312 fl) to 1,000 m (3,281 ft). Looking back at the outstanding success accomplished in the last years, one can easily confirm that this was the right strategy to be followed: 219 WCTS have already been installed in Brazilian's continental shelf and technology to produce wells up to 1,000 m (3,281 ft) is completely dominated, despite the capital constraints suffered by the Company.

Nowadays, an outlook of the two most important offshore provinces in Brazil, Santos and Campos Basins, shows that the future lies in waters even deeper, what imposes the need for another strategy to be defined in order to reach anew target. The experience gained during the development of the Marlim Pilot System has showed that the installation of an early Floating Production System pays, even in deep waters. It is a good manner to pave the way to master new technologies, anticipating oil and gas production and collecting reservoir data that can help to minimize the uncertainties related to geological aspects and production mechanisms, thus increasing the chances of success and decreasing the risks involved.
The Troll Oil Pipeline Project: A Welcome Challenge to Survey Technology
Authors: Trodal L. , Nilsen Ø.
Published: October 2008

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

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

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

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

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

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

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.
The Norne Production Ship - Design Considerations
Authors: Odland J.
Published: October 2008

The Norne Production and Storage Vessel (PSV) will be the largest monohull production facility in the world with a throughput capacity of 173,000 bbl oil and 238 mill scf gas per day, Production will be based on subsea completed wells, drilled through five templates and connectedto the turret moored PSV via flexible rises and flowlines. A high capacity swivel stack has been designed fortransfer of oil/gas/water between turret and facilities on the process deck. The Norne field is located further north than any other Norwegian field in operation or under development, and the water depth on location is 380 m.

INTRODUCTION

The Norne field is located in Block 6608/1 O, about 200 km west of the mid-Norway coast. The water depth on location is about 380 m. The top of the reservoir is found at a depth of 2525 m below MSL. At a reference depth of 2639 m the formation pressure is 273 bar and the temperature 98 degrees C.

The recoverable oil reserves are about 72 mill. Sm3. The reservoir drive mechanism will be a combination of water and gas injection. Initially all produced gas will be reinjected into the gas cap.

The plateau production rate representing a yearly recovery rate of 12.57. of total recoverable reserves Will be maintained for 3-4 years. The field will produce forabout 16 years.

The development scenario is based on a Production and Storage Vessel (PSV) in combination with a subsea production system comprising 6 oil producers, 6 water injectorsand 2 gas injectors. The wells will be drilled through five subsea templates, two located in the northern part and three in the southern part of the field. The templates will be connected to the PSV via flexible flowlines and risers.

THE PRODUCTION AND STORAGE VESSEL

The PSV is a turret moored, ship-shaped production, storage and offloading vessel of Tentech 850 S design, see Fig.1. With throughput capacities as listed below the Nome PSV will be the largest monohull production system in the world.

(Available In Full Paper)

The vessel will, on location, be moored by means of a 12 point mooring system with 12 anchor chain winches arranged on the turret of the vessel. Five fully azimuthing, variable speed thrusters will be utilized as an active element in the station keeping and heading control, see section Instrumentation and control.

The turret which will be held geostationary by the mooring lines, will also serve as attachment for all the flexible risers. From the swivel, on top of the turret, {he well stream is transferred to the inlet separator on the process deck.

A total of 16 storage tanks and 2 slop tanks with a total capacity of 117,000 m3 will be arranged in the hull. Double bottom tanks, wing tanks and peak tanks provide ample capacity (about 48,000 m3) to maintain sufficient draught in ballast condition. All water ballast tanks and systems are segregated from the oil storage tanks. Accommodation for 120 persons will be arranged in the forward part of the vessels.
Troll Oil: The first concrete FPS
Authors: LØset Øystein , Haakonsen Knut Olav
Published: October 2008

The Troll Oil FPS platform is the first with concrete hull and the greatest semi built to date. This paper describes the platform concept, design challenges, and in more detail the civil construction, mechanical installation and marine operations of the Troll Oil platform hull.

CONCEPT DESCRIPTION

For the Troll Oil floating platform a semi submersible with concrete hull was selected, mainly due to cost effectiveness and a favorable schedule. The schedule was essential to the project since the oil exploitation of the Troll field is anticipated to be jeopardized as the parallel gas emptying of the reservoir proceeds. At the time of making the project decisions, the schedule of the complete platform was among the shortest to be carried through for an offshore development in the North Sea. This can be illustrated by the time from EPCI contract award to deck mating which was 24 months (carried out early February 1995). The platform is shown in fig. 1.

The process design capacities for the Troll Oil semi are:

(Available In Full Paper)

Maximum number of flexible risers that can be tied back to the concrete semi is 33, serving up to 5 clusters of subsea wells and oil and gas export from the platform.

The topsides of the semi consists of:

(Available In Full Paper)

With a module support frame (MSF) of 11,400 tons, the concrete hull is to support 32,500 tons, including contingencies and riser guide frame.

The MSF is supported on the top of the concrete columns by single support points, see fig. 2 in order to provide a moment free connection. The dynamic forces in the steel MSF are thereby reduced, and consequently the fatigue loads. This single support is in principle a vertical bar on each concrete column, requiring a significant local thickening of the concrete wall right underneath.

The concrete hull itself is built up of 4 rectangular pontoons, forming globally a square. From each corner of this square one cylindrical column extends through the waterline. These 4 columns support the MSF at a freeboard of 25 m. The subdivision of the pontoon into watertight compartments was determined by requirements to accidental flooding. Within each compartment open transverse stiffeners and a longitudinal wall along the centerline are designed for structural strength purposes. This structural configuration contributes towards a minimization of weight and of water displacement.

The columns has an inner cofferdam to provide sufficient floating stability in case of leakage damage of the outer cylindrical wall. In the intersection node between the column and the pontoon the cylindrical cross section is stiffened by vertical walls. In this lower area the fairleads of the mooring system are attached to the column through a prestressing tendon arrangement. Reference is made to figures 3 and 1.

Key Data for Troll Oil Semi

(Available In Full Paper)

The mooring is a passive 16 lines system and consists of winches, fairleads and chain lockers. Each mooring is a 4 segment line with stud chain and wires.
Oceanographic Design Data for South Pass Area Block 47
Authors: Suheyda Joseph N.
Published: October 2008

The paper summarizes the methods and results of work to determine the operational and extreme oceanographic design data for the platform in South Paas Block 47, Site specific design &ta are required for mud slide/soft bottom areas. The objective of the work was to develop site specific wind, water level, wave and current values for average return periods of I, 10, 100, 1000 and 10, OW)years as part of the geotechnical and relisbilit y analyses. l%e paper shows how oceanographic design data for a wide range of return periods can be developed in a consistent manner. The extreme data were generated using two hydrodynamic models a hurricane storm surge and transport model, and a hurricane wave model. The wave model explicitly involves wave/sea floor interactions in the study area. The results of the study gave the simultaneous occurring values of the design data. Wave heights for the site were 26.7 ft, 50.8 ft, 66.7 ft, 77.8 ft and 83.9 ft for average return periods of 1, 10, 100, 1000 and 10,000 years. The simultaneous wind speeds (1 wc average) associated with these same average return periods were 137 ft/s, 144 ftls, 226 ft/s, 240 ft/s and 259 ft/s. Current speeds at the surface were 3.0 ft/s, 4.3 ft/s, 6.3 ft/s, 6,6 fr/s and 7.1 ftls for the same return periods.

Introduction

This report presents the results of a study to define the meteorological and oceanographic conditions that are pertinent to the design and operation of an oil production platform located in South Pass Area Block 47. The water depth at the design site in Block 47 is 224 ft. Bottom sediments at the design site and in the surrounding area are soft clays which have been observed to affect storm wave action.

The environmental conditions considered in this report rnclude operational and extreme winds, water levels, waves, and currents1. Operstional conditions refers to environmental conditions which are expected to occur frequently during the life of the structure, such as resulting from a winter storm. Extreme conditions refers to environmental conditions which occur rarely during the life of the structure, such as resulting from a severe hurricane. The purpose of this study was to accumulate and analyze existing environmental data, and to use statistical and computer models to develop a quantitative description of the operational and extreme environmental conditions at the design site.

Methods

The determination of the operational and extreme environmental conditions at the design site were baaed upon the application of physical and computer models.

For the operational conditions, wind speeds were determined from wind statistics for the north central Gulf Of Mexico. The wind speed statistics used included the Summary of Synoptic Meteorologyical Observations (SSMO) data2 and observations of wind speeds at offshore platforms on the Louisiam shelf. The average annual wrnd statistics are given in Table 1.
Foundation Soil Motion in South Pass 47
Authors: Hooper James R.
Published: October 2008

The interactions between large storm waves and a soft clay seafloor were studied during the foundation investigation for a platform to be constructed in South Pass 47, offshore the Mississippi Delta.

Seafloor stability and soil motion were analyzed for storms with intensities ranging 10 to 10,000-yr.return intervals.

The study included analysis of site conditions if it becomes buried by mudtlows.

Introduction

The delta tiont of the Mississippi River is a geologically dynamic environment where marginally stable sediments sometimes eonstmin development of oil and gas resources.

It is recognized, however, that relatively stable regions of seafkm exist within the delta, and that these areas may be suitable locations for hydrocarbon production facilities.

The goal of this study was to develop parameters for the design of platform foundation piling in a region of questionable seafloor stability.

One facet of the investigation was the evaluation of potential sediment motion under the weight of hurricane waves3"4.

The investigation was part of a probability-based study of the reliability characteristics of production facilities, performed by Beasfor the owner, Energy Development Corporation.

As input to that study, it was necessary to examine wave-seafloor interactions for storm waves ranging in size horn thow associated with a 10-y. average annual return period to those of a 1O,OOO-Y. storm using oceanographic data supplied by Suhaydae.

Physical Setting

SPJ17is located on the submarine platform of the Mississippi River Delta about 5 miles downslope from the mouth of SouthThe eastern half of the block contains several long valley- IiIce depressions in tie seafloor that lead down into SP-47 from Block 35 in the north. A large lobe-like seafloor feature is defined by the bathymetry contours in the southeast comer of SP-47, After studying the results of repeated surveys of the delta, Shepard suggested in 1955 that these valley and lobe sedloor features are the result of sediment mass movements and he noted that some appeared to change in size and shape on successive bathymetry maps.

Site History

The origination of the modem delta is generally accepted to be located where the river splits into three main channels at Head of Passes, about 100 miles south of the city of New Grleans, Loukiana. This is the latest of seven Mississippi River deltas which have formed along the Louisiana coast sinoe the ocean reached near-present level about 5000 y. ago.

The modem phase is now about 450 yr. old and has created a 50-mile wide submerged deltaic platform that is extending into the Gulf of Mexico at rates varying between 150 and Pass. Water depths range from 180 ft to 380 ft and the average seafloor gradient is about 1% (Fig. 1). The platform site is in the northeast quadrant in a water depth of 224 ft.

The eastern half of the block contains several long valley-IiIce depressions in tie seafloor that lead down into SP-47 from Block 35 in the north.
Identification of Lithology in Gulf of Mexico Miocene Rocks
Authors: Hilterman F.J. , Sherwood J.W.C. , Schellhorn R. , Bankhead Brad , DeVault Bryan
Published: October 2008

In the (W of Mexico, many gas-saturated sands are not Bright Spots and thus arc difficult m dewct on conventional 31) seismic data. These small amplitude reelections occur frequently in pliocene-Miocene exploration plays when the acoustic impedances of the gas-saturated sands id shales are approximately the same. In these areas, geophysicists have had limited success using AV() to reduce the exploration risk. That interpretation of the conventional AV() attributes is often difficult and contains questionable relationships to the physical properties of the media. A 31) AV() study was conducted utilizing numerous well-log suites, core analyses, and production histories to help calibrate the seismic response to the pctrophysical properties. This study resulted in an extension of the AV() method to a technique that now displays Bright Spots when very clean sands and gas saturated sands occur. These Iitho-stratigraphic reflections on the new AV() technique are related to Poisson's ratio, il petrophysicid property that is normally mixed with the acoustic impedance on conventional 3D migrated data.

Introduction

During the last five years, the significance of 3D seismic data in reducing the risks of oil/gas exploration has ham well documented.however, (here still exists areas, especially in over pressured zones, where conventionally process 3D seismic data exhibits poor data quality making it difficult 10 map structure and stratigraphy. in fact. the amplitude variations on the conventional seismic bear no relationship to the known geology. Thus, it is not surprising that in Ume areas, 1i) synthetic seismograms show a very poor t]e to the seismic data.

While 3D stacking has received much acclaim, Tucker: warned that stacking enhances continuity and parallelism ofthe reflection. ... but overstocking can destroy the geology. ... Stacking can also distort the stratigraphy ... thus playing havoc with successful stratigraphic mapping. These astute observations were made (in 1982) before the advent 01 AV()' and before the information content of (he reflection stack was fully understood.' 1(is primarily the mixing of' two pctrx)physical properties, acoustic impedance and Poisson's ratio, that leads to the distortion of the, geology and stratigraphy.

In this study. d robust method of, separating the effects of acoustic impedance from Poisson's ratio was developed and applied to a GOM offshore area. Numerous wells, some dating to the late 60s, arc scattered throughout the 3D AV() study area. The exploration play is P1ioccne-Mioctnw, imd is Iocated in the shallow-water transition mm! of Texas and I.ouisiana. Borehole information was utilized for both calibration and verification of the reservoir characterization from the 3D seismic data.
Evidence for scale effects in the end bearing capacity of open-ended piles in sand
Authors: Hight D.W. , Lawrence D.M. , Farquhar G.B. , Mulligan G.W. , Gue S.S. , Potts D.M.
Published: October 2008

The paper draws on the following to examine the effect of pile diameter on the end bearing capacity of open-ended piles driven insand: laboratory tests to measure sand plug capacity; finite element analyses to examine sand plug behaviour a data base of load tests on driven open-ended piles in sand

The evidence which is assembled strongly suggests a tip resistance which reduces with increasing pile diameter, at least at reasonable values for limiting pile displacement. The ability of the API RP2A design method to predict this trend is discussed.

Introduction

When an open-ended tubular steel pile is driven into sand it is observed that sand moves up inside the pile as the pile penetrates, to fro-n an internal sand column. In the North Sea it has been observed that at the completion of driving the level of the sand inside a pipe pile is usually similar to or only a few metres lower than the level of the sand outside the pile. Similar observations have been made in model piles driven into laboratory prepared beds of sand (e.g. Fig. 1 from Kishidal). It is evident that during driving, at least in the early stages, the resistance of the sand column is not sufficient to exceed the bearing capacity of the sand below the pile tip, so that sand flows into the pile. Exceptions occur in small diameter model piles, which can plug during driving (B s 75mm in Fig. 1) and in long fill-scale piles in which observations of incremental tilling ratio suggest that plugging, or partial plugging, develops at large pile penetrations.

The components of resistance to static load on a pipe pile are illustrated in Fig. 2. They comprise:cxtcmal shaft friction, Q,eannular tip bearing capacity, Q.sand plug resistance, Qp,

Conventionally two limiting cases are considered for the tip capacity Fig. 2). In case (a), the column resistance is insufficient to cause a bearing failure of the sand beneath the pile tip; in this case Ihe pile penetrates by sliding pas[ [he sand on its inner and outer surfaces and by bearing failure around the pile annulus - this mode of failure is refaed to as ‘non-plugging’. In case (b), the column resistance exceeds the bearing capacity of the sand below the pile tip and the pile fails as if closed-ended -in this case the sand in the pile is said to have ‘plugged’ or ‘locked-up’.

There is a growing body of evidence to suggest that under static loading, the sand may plug despite having flowed into the pile during driving. This difference in response to dynamic and static loading is an important clue to understanding the mechanism by which sand plug resistance is mobilised.

Between 1984 and 1988 Shell UK Exploration and Production commissioned a series of studies aimed specifically at investigating the effect of an internal driving shoe on the static capacity of sand plugs in pipe piles.