bluuebunny/crossref_metadata_2025 huggingface dataset:
The Terra Nova FPSO Turret Mooring System
Authors: Howell G.B. , Duggal A.S. , Lever G.V.
Published: October 2008

The Terra Nova FPSO consists of a new-build vessel with a disconnectable internal turret mooring system. Nineteen risers and umbilicals from four drill centers are connected to the turret with a maximum design throughput of 150,000 bopd. The turret system is designed to allow the vessel to quickly disconnect from its moorings and risers to avoid impact with unacceptably large icebergs, and to allow the FPSO to remain moored on station during the severe 100-year storm conditions. These unique requirements for Terra Nova have resulted in the development of one of the most sophisticated turret mooring systems to date.

This paper presents some of the key drivers that led to the unique design of the Terra Nova turret mooring system, and provides a detailed description of the various components of the turret, focusing on both the structural and mechanical, and the fluid-transfer systems. The paper also provides an overview of the disconnection and reconnection of the turret mooring system, illustrating its compliance with the stringent requirements in the design basis. Finally the paper provides a summary of the turret design, fabrication and installation milestones over the life of the project.

Introduction

The Terra Nova FPSO will be located in approximately 95 meters water depth on the Grand Banks off the East Coast of Newfoundland, Canada. The harsh environment at the Terra Nova location is much like the northern North Sea with a 100- year significant wave height of 16 meters, and 1-hour mean wind speeds of 40 m/s. The FPSO is situated in "iceberg alley" where large icebergs from Greenland and Ellesmore Island drift south with the Labrador current. Surveys have shown the presence of iceberg scour marks on the seabed, and statistics indicate that the site could see as many as 66 large icebergs in a single season (April - July). Table 1 provides a summary of the design storm conditions for both the 1-year and 100-year return intervals.

The Terra Nova FPSO system consists of a new-build FPSO vessel with a disconnectable internal turret mooring system. The turret supports 14 risers and 5 umbilicals servicing wellheads in four or more glory holes, with a maximum design throughput of 150,000 bopd. The turret mooring system has been designed to maintain station in the 100-year storm environment, and to be disconnectable to avoid an approaching iceberg on a collision course. Once the FPSO disconnects, the mooring and riser system is supported by the spider buoy that has an equilibrium depth of 35 meters below sea level.

This paper provides a detailed description of the unique turret mooring system designed by FMC SOFEC Floating Systems for the Terra Nova FPSO, focusing on both the structural and mechanical system, and the fluid-transfer system. The paper also provides a description of the disconnection and reconnection of the turret mooring system, and the design, fabrication and installation milestones over the life of the project.
Reservoir Development Plan for the Terra Nova Field
Authors: Skaug M. , Kerwin K. , Katay J.
Published: October 2008

The Terra Nova Oilfield located offshore Newfoundland, Canada, is currently under development according to a subsea layout with 4 "drill" centres and a floating production storage and offloading (FPSO) vessel. First Oil is planned for mid 2001. The base case reservoir development requires a total of 24 development wells plus flexibility to develop additional upside potential. Reservoir flexibility management requires waterflood and gas injection capability. The options of changing to water-alternating-gas (WAG) later in field life as well as converting certain producers to injectors are also a feature of the reservoir management plan. The development plan requires that 6 wells be pre-drilled prior to the arrival of the FPSO vessel. Results from these wells have confirmed the vertically layered reservoir and the need for horizontal as well as vertical and highly deviated wells. The presence of faults that potentially may ompartmentalize the reservoir has resulted in a development plan where the early wells are laid out as producer - injector pairs within individual fault blocks. Each fault block has been designated for either gas injection or water flooding. However, as new information about the reservoir, its geology and degree of compartmentalization becomes available through the drilling of the development wells and early production experience, the location and type of later wells will ensure that the all parts of the field are being produced in an optimized way.

Introduction

The Terra Nova Oilfield is situated offshore on the Grand Banks, 350 km east-southeast of St. John's, Newfoundland, Eastern Canada (Fig. 1). Water depth in the area is about 95 m. The field is estimated to contain over 150 million cubic meters (one billion barrels) of oil in place, of which around 58 million cubic meters (370 million barrels) are expected to be recovered. Based on a daily production rate of up to 23,850 cubic meters (150,000 barrels) per day, the field would produce for about 12 to 15 years, beginning in mid 2001.

Terra Nova was discovered in 1984 with the drilling of the K-08 discovery well. A total of nine wells were drilled in and around the field between 1984 and 1988. Terra Nova is the second major oil field discovered on the Grand Banks, the first field being Hibernia which was put on production in 1997.

In August 1996 a Development Application for Terra Nova was submitted to the Canadian-Newfoundland Offshore Petroleum Board (C-NOPB). The application outlined a subsea development with up to six "drill" centres and a Floating Production Storage and Offloading (FPSO) vessel. A total of 32 development wells was included for the delineated area of the field, covering both producer and injector wells. It was anticipated that 10 wells would be drilled and completed before production of First Oil. The selected facility had flexibility to develop additional upside potential in the field provided by non-delineated areas, and another 12 wells were foreseen for these areas.
On the Calibration of Design Collapse Strengths for Quenched and Tempered Pipe
Authors: Adams A.J. , Moore P.W. , Payne M.L.
Published: October 2008

API/ISO TC67 SC5 Workgroup 2B is currently undertaking the modernisation of API Bulletin 5C3/ISO 10400 for casing and tubing performance property equations. This paper describes the test data and analysis methods being used to develop and evaluate proposed new collapse equations for quenched and tempered (Q&T) pipe. As the work is still at committee stage, presentation of detailed results must await a future publication; however, sufficient detail is given to allow a full understanding of the various analysis techniques, as wellas the final results when they appear.

Introduction

Limitations of Existing Approach.

The technical basis of the current Bulletin 5C31 was prepared in the early 1960s. Various limitations have been identified since its first publication, as follows.The collapse test data2 upon which the equations are based is now rather old, and pipe production practices have improved considerably in the intervening period. It is therefore likely that the equations do not accurately represent the performance of modern tubulars.The majority of the collapse tests were for short specimens (L/Do = 2), which are now known to overestimate the collapse strength of real pipe 3–6.The collapse strength equations result in a widely varying margin between the ultimate and design collapse strengths over the Do/t range for well tubulars7, and thus also in predicted failure probability (Pf)8,9.The mean value equations are relatively poor predictors of ultimate collapse strength compared to modern formulations, which have been shown to be much more accurate10.The same equations were used for both Q&T and non- Q&T pipe. However, recent work11,12 has shown that the two classes have different collapse behaviour, and therefore need individual strength equations.The collapse test specimens were manufactured using a wide range of production methods (e.g., seamless and ERW, cold and hot rotary straightening), and no attempt was made to determine the various effects on collapse strength. Subsequent work12 has demonstrated that both straightening and heat treatment have a significant effect on collapse strength, and thus should be included explicitly in any modern treatment.The present formulation for plastic collapse strength is implicitly based on the assumption that collapse strength is proportional to the specified minimum, rather than the actual, yield stress. This is acceptable as long as the ratio of actual to specified minimum yield stress is constant for all grades. However, analysis of production quality data10 has shown that this ratio varies considerably by grade, and thus that the current treatment can and should be improved.Finally, the present approach cannot accommodate non- API grades, such as high-collapse (HC) pipe.

Choice of Calibration Method.

For the reasons above, it was decided to proceed with the modernisation of Bulletin 5C3, and the task was allotted to API/ISO SC5 workgroup 2b in mid-1998.
Caisson and Pile Combinational Foundation System
Authors: Shirazi Ali , Mahan Amir
Published: October 2008

The popular and traditional system, which has been used as a foundation in many offshore structures, is the system of piles. In some conditions this system has not sufficient efficiency. Some conditions such as existence of the thick liquid layers mud mat, the depth of water and also required free board in some offshore projects cause some problems. In these conditions there isn't any sufficient accuracy in pile driving and because of long length of piles in lateral buckling it is necessary to use stronger piles to avoid buckling during operation and it leads to use the uneconomical profiles as pile. This paper describes a new combinational foundation system, using caisson and pile, and explains the construction and installation stages. In addition, the paper explains the advantages of this method in compare with the traditional method of pile foundation system.

Introduction

The pile foundation system is one of the popular methods, which is used as the foundation in offshore structures. In this method piles are designed for bearing vertical and also lateral loads. The design loads for pile are not only the loads that exert during the life of main structure but also the loads, which apply during pile driving. The quantities of these loads aredependent on the type and the thickness of soil layers and also the properties of selected pile are dependent on the length of pile in free buckling.

The accuracy of driving operation is another problem that occurs during pile driving. Guaranty of operation accuracy is not possible in traditional method completely and it is clear that providing a high accuracy during pile driving, especially in the batter piles, is very important in some offshore projects. New system, which this paper proposes, can provide high accuracy for pile driving and also the caisson buoyancy's can reduce the vertical applied loads to piles and caisson can protect piles against negative surface friction, which happens between the surface of piles and bed soil. Therefore the designed piles in the new system can be more economical than designed piles in traditional foundation system that is constructed with piles only. Also in this new system, piles can work in a higher efficiency.

The state of structure

The main goal of this project is design and construction an efficient and economical foundation for an offshore structure. Especial conditions in installation location of foundation make this foundation to be difference from other foundation. Therefore a new method is needed for construction in these conditions. The new foundation system transfers loads from main structures to the bed soil. The water depth is about 10 meters and free board is 12 meters. The upper layers of bed soils are 15 to 20 meters of liquid mud and under these layers there are layers with considerable strength. Therefore the free length of pile during pile driving is about 40 meters.
Flowline Burial: The Key to Unlocking Subeconomic Marginal Discoveries
Authors: Osborne Roger , Frazer Ian
Published: October 2008

Large cost reductions can be achieved by utilizing buried and coated flowlines. Subsea flowlines in liquid dominant production systems are prone to difficulties with regard to flow assurance issues. Thermal solutions to keep the produced fluid at a temperature high enough to avoid wax formation and avoid the risk of hydrate blockage can be prohibitively expensive. Flowlines are probably the largest single cost item, apart from drilling, in a subsea production system. This paper will disclose and review the results of studies into insulating properties of super-saturated deep-water soils. It will explain how buried and coated flowline systems can achieve results similar to that obtained with more expensive Pipe in Pipe (PIP) systems. It will show how system performance is improved over that of Pipe in Pipe systems and it will explain the operational methods of deep and ultra-deep water burying equipment.

Subsea developments that have been shelved because of high costs may become viable by use of buried and coated systems. Improved system performance and cost reductions can be achieved using buried andcoated systems.

Introduction

The application of buried and coated flowlines can make developments that currently require pipe in pipe flowlines up to 25 miles in length economically more attractive. This is achieved by understanding the insulating properties of subsea soils and how burial can be achieved. Economics and cost drivers of buried solutions will be reported. Thermal performance will be shown to be similar to that of more expensive systems.Historically Flowlines in excess of 12 to 15 miles for Oil/Multiphase service gravitate to PIP solutions.For Subsea step-out systems, flowline costs are probably the greatest single dollar ($) value second to drilling.Buried and coated Flowline systems give similar performance to PIP solutions. Step-out distances in excess of 25 miles can be achieved for oil dominant systems.The cost of burial and coating is potentially 40% to 50% of that of PIP.Recent investigation and measurement of deepwater soils has shown that the thermal conductivity (k) value of such soil has beneficialthermal properties beyond what is normally assumed.

The benefits of buried and coated (B&C) flowlines ascompared to pipe-in-pipe (PIP) systems may be described in terms of potential cost savings, an increase in allowable transient shutdown times, extension of the "no touch" period, and longer duration before waxappearance and hydrate formation.

Investigation has shown that;B&C (buried & coated) OHTC (Overall Heat Transfer Coefficient) or U value can be close to that of PIP.Burial systems have much longer transient cool down times than PIPOHTC marginally dependent upon burial depth, after ~4 Flowline diameters little gain.Deepwater clays thermal conductivity is unaffected by remoulding (If done correctly)Trench back-fill soil samples indicate low probability of void spaces
FPSO Standards and Recommended Practices
Authors: Parker Wanda J. , Grove Todd W.
Published: October 2008

The oil and gas production industry has expressed an interest in being able to utilize Floating, Production, Storage and Offloading (FPSO) units as a development option in the deepwater areas of the United States (U.S.) Gulf of Mexico (GOM) outer continental shelf (OCS). Operators will need regulatory approval from both the United States Coast Guard (USCG) and the Minerals Management Service (MMS) for a FPSO project. Neither the USCG nor MMS currently have regulations specifically for the design and operation of FPSOs on the OCS. A workgroup was formed under the Offshore Operators Committee's Deepwater Subcommittee to assist MMS and USCG in reviewing the existing regulations and body of standards, specifications, recommended practices and classification society rules and guides concerning the design and operation of FPSOs on the OCS for the Gulf of Mexico. The effort also aimed to identify gaps in the regulations and industry standards. This paper provides a summary of the major findings of the workgroup. In addition to the items discussed in this paper, the workgroup report identified other areas where additional modifications to regulations or industry standards may be warranted.

Introduction

As operators have moved into the deeper waters of the GOM over the last several years, interest has been growing in potentially utilizing FPSOs as a development option to the floating production systems (tension leg platforms (TLP), spars, etc) and subsea tie backs to either floating production systems or fixed platforms that are currently being utilized. In discussions with MMS and USCG, it became apparent that several studies would need to be conducted to confirm the acceptability of these systems for the GOM. MMS indicated that an Environmental Impact Statement (EIS) would be prepared for the first FPSO proposed to be utilized in the GOM. In working with industry, MMS agreed to do a programmatic EIS on the generic use of FPSOs in the GOM if industry would fund the study. The joint industry project DeepStar agreed to fund the EIS1. The draft EIS on the Proposed Use of Floating Production, Storage and Offloading Systems on the Gulf of Mexico Outer Continental Shelf in the Western and Central Planning Areas2,3 was published in August 2000 for comment. The final EIS is expected to be published in the first quarter of 2001 with a Record of Decision to be published no earlier than 30 days from the publication of the final EIS.

The second study effort was to do a comparative risk assessment to evaluate and compare oil spill and fatality risks for the FPSO with a spar, a TLP and a shallow-water jacket serving as a hub and host to deepwater production. The Offshore Technology Research Center completed that study for MMS4.
The Sihil Reservoir: The Fifth Block of Cantarell Field
Authors: Lopez Jose A. Aquino , Gonzalez H. Guillermo Ortega
Published: October 2008

The Cantarell field, discovered in 1976, is one of the largest oil fields in the world. This oil giant is a mature field and has produced over 7,800 million barrels of oil during 22 years of exploitation. It is made up of four blocks: Akal, Nohoch, Chac, and Kutz. Heavy oil and gas from Upper Cretaceous carbonate breccia is produced from 223 wells using primary and secondary recovery methods.

The possibility of the existence of a prospective hydrocarbon trap located below the Cantarell Field was recognized in 1990. Through various studies, this new reservoir was explored and defined. The new discovery, Sihil, surpasses all previous predictions regarding the quantity of oil reserves, thereby making the discovery of the fifth block in the Cantarell Field the most important discovery in the last decade.

Sihil allows Pemex Exploration and Production (PEP) to establish a strategic plan to add even more hydrocarbon reserves using data provided by investigation of other underlying blocks.

Introduction to the Cantarell Field

Cantarell Field, discovered in 1976 offshore Campeche, Mexico, is the sixth largest oil field in the world. It is located on the continental shelf in the southern part of the Gulf of Mexico and within the east-central part of the Bay of Campeche, 80 kilometers (km) northwest of Ciudad del Carmen, Campeche, Mexico (see Figure 1: Location of Cantarell Oil Field).

This petroleum giant is considered to be a mature field. It has produced approximately 7,861 million barrels (bbl) of oil during 22 years of production and exploitation. Prior to discovering Sihil, the Cantarell field was known to be composed of four blocks: Akal, Nohoch, Chac, and Kutz (see Figure 2: Map of Akal, Nohoch, Chac, and Kutz fields). The most important block is Akal, which contains over 90 percent of Cantarell's oil reserves.

The Cantarell field currently produces approximately 1.4 million barrels per day (mmbpd) and production is expected to increase upon completion of a major expansion and modernization program conducted by Pemex. Hydrocarbons produced from this field are oils with an API of 20Â° to 24Â°. Production comes from 205 wells using primary and secondary recovery methods.

The Sihil Reservoir, located in a thrust block below the Akal field, was discovered in 1998 and is the fifth block of the Cantarell field. This technical paper will concentrate on the assumptions and challenges that led to the discovery of Sihil Reservoir.

Geologic History of the Cantarell Field

The regional tectonic model proposed by R.R. Rojas (Reference 1) provides insight into the Akal and Sihil structures. Typical Cretaceous and Jurassic structure in the region is the result of normal faulting during the Early Cretaceous, though some authors claim that the process started in the continental part of the Jurassic Late Tithonian.

This system shows a decollement level that corresponds to the Middle Jurassic salts, with the development of salt rollers.
Ultra-Deepwater Steel Hybrid-Riser Concept for Offshore Brazil
Authors: Andueza A. , Stefen S.F. , Silve R.M.
Published: October 2008

Petrobras has around 17.3 billions barrels of oil reserves being half of them under more than 1000 meters water depth. In addition, 60% of offshore exploratory concessions are also deeper than 1000 meters water and half of these concessions at more than 2000 meters. Therefore, the future Brazilian oil discoveries should be located offshore in ultra-deep waters. Beyond 2000 meters water depth flexible riser technology is so far not proved. Therefore, the new challenge is to develop an ultra-deep water hybrid riser technology in order to incorporate these reserves in the Company's assets.

This paper shows a preliminary technical feasibility study considering a hybrid riser configuration for a typical deep water field in Campos Basin, Offshore Brazil. The water depth is 1800 meters and the riser is attached to a turret at bow FPSO (Floating Production Storage & Offloading) vessel. The results indicate an attractive alternative design concept that fulfil some typical difficulties related to ultra-deep waters such as high vertical loads on the production floating unit.

The analysis methodology uses the Finite Element Method through commercial computer codes packages MSC/Patran and Abaqus. The hydrodynamic loads are computed through programming using PCL (Patran Command Language).

The strength of the pipe under bending, tension and external pressure is considered through the standard DNV OS-F101 [1]. This standard is proposed specifically for the analysis of submarine pipelines.

Introduction

The steel hybrid riser concept [2,3,4,5] is composed by a SCJ (Steel Catenary Jumper) connected to a SSVR (Self-Standing Vertical Riser) through a goose neck spool piece, as shown in Figure 1. The connection of the two rigid risers is provided by a typical flex-joint. The SSVR requires a subsurface buoy at the top to keep its vertical stability. In addition, the SCJ is attached at the base of a bow turret of a typical FPSO built on the hull of a former VLCC (Very Large Crude Carrier). At the seabed the connection is modeled as a hinge, however, a taper joint or a flexjoint could be considered based on a further local analysis not included in this paper.

One of the main advantages of such configuration is that it eliminates entirely riser soil interaction, therefore, any TDP (Touch Down Point) design constraints. Another important advantage is that the concept is made completely of steel pipes, which gives more flexibility in terms of construction and procurement.

The proposed configuration in this work was defined through the analysis of the results of a preliminary study of several simulations.

The System Specification is described below:WD (Water depth) = 1800 metersPipe Outer Diameter = 12.75 inPipe wall thickness = 1 inPipe material: API 5L X65SCJ length = 1700 metersSSVR length = 800 metersBuoy upthrust = 1470 kNFlex joint connecting SCJ top and FPSOFlex joint connecting SCJ and SSVROperational offset: 10% of water depthAccidental offset: 15% of water depthVLCC ship with turret system
Analysis of Splices used in Large Synthetic Ropes
Authors: Leech C.M. , Flory J.
Published: October 2008

The analysis of eye splices used in synthetic rope is considered by categorising splice geometries and then developing the modelling for each type. The three splices considered are commonly used in wire ropes and are applied to six round one aramid ropes; the splices are the long or transmission splice, the admiralty or locktuck splice and the Liverpool splice. The geometry of each is analysed and then applied to determine the load capability for each type. The internal friction and contact forces are also discussed.

Introduction

Large synthetic ropes are widely used in many traditional structural applications. These ropes are terminated and this can be achieved by a variety of mechanisms. Their ends can be cast into in epoxy fittings or terminations, they can be gripped or they can be spliced either to another rope or to themselves forming an eye. Analyses haves been conducted on the strength and life of these ropes, but little analysis has been done on the splicing of these ropes. This paper describes three splice geometries and introduces the analysis associated with each.

Modern synthetic ropes vary in construction and in the constituent fibre materials. The assembly geometries consist of the oldest geometry namely twisting of strands around a core axis, of braiding and plaiting of strands, and of layering of groups of strands. The strands are formed by twisting, braiding or plaiting of yarns and these yarns are formed from textile or rope yarns that in turn are assembled from the smallest fibre groups. Thus the development of the rope from the basic component is achieved through a hierarchical tree, in which the geometry of assembly is the link between consecutive levels.

The material components used in modern polymer fibre ropes have a range of properties that can be exploited in rope construction, namely strength, stiffness, creep and relaxation, fatigue life, shock and impact resistance, and friction for internal energy absorption, fibre abrasion and rope integrity.

Much has been done in recent years on the analysis of rope performance, fatigue and internal heating. However, the analysis of termination of such ropes by splicing has not been done before. The following splices are considered.

The long (transmission) splice for twisted structures is achieved by stagger cutting each strand in the standing end and laying in its path a strand from the joining splice end. This is the simplest splice geometry. The analysis for the splice integrity requires an estimate of the contact friction.

The Admiralty (locktuck) splice uses a braid geometry formed by weaving the strands from the standing end with those of the splice. Contact is enforced at the crossover points and friction again ensures that the splice does not disintegrate.
Suspension Transport In Southern Alaskan Coastal Waters
Authors: Wright F.F.
Published: October 2008

Sporadic. large-volume transport of suspended silts and clays characterizes the inshore sedimentary regime of southern Alaska. Both in fiords and on the open shelf there is rapid deposition of an undistinguished periglacial mud which is carried as discrete layers n, in, and under the seasonally stratified waters of the region. This phenomenon, analogous to spring floods in temperate areas, is particularly important in late summer and autumn when thermohaline stratification of the coastal waters is most pronounced. Within a given coastal water column there are routinely two or more water masses with density contrasts as great as 4 g/l. Such density surfaces are quite adequate to support the highly turbid glacial run-off waters of the region, which rarely contain more than 0.5 g/l suspended sediment. Much of the suspended material travels in individual bolusses which behave as water asses, sinking to a level corresponding to their effective density and gradually losing their load by settling and flocculation. Apparently internal turbulence within a bolus tends to maintain relatively coarse particles in suspension for considerable periods. This accounts for the transport of silts and even fine sands across sills in fiords and even beyond the continental shelf, in contrast to classic turbidity current transport which tends to be strictly controlled by sea floor topography. Both the turbid waters and the discontinuous currents associated with this mode of sedimentation may be critical factors in the conduct of diver or submersible operations in inshore waters where appropriate conditions exist.

Introduction

Ancient mariners often navigated by the appearance of turbid river waters at the sea surface considerable distances from shore. Modern aerial and satellite photographs have demonstrated that this phenomenon is extremely common; fresh river waters bearing considerable loads of suspended sediment spread many miles from shore (Stevenson, 1969). This suspension transport is due to the relative density differences between the cold, saline seawater and the warmer, fresh river water, despite theconsiderable quantities of suspended material in the fresh water. A similar phenomenon has been observed by divers and deep submersibles at the sea floors of the continental shelf and slope where rather slow down-slope movement of turbid waters, quite distinct from classic turbidity currents, is often seen (Moore, 1969). Within the deep sea, persistent turbid layers carrying very dilute suspensions of fine clay particles have been reported by various observers. Discrete turbid water layers capable of carrying large quantities of suspended sediment supported on density interfaces within the water column have been postulated (Gould, 1951; Stetson and Smith, 1938).

Multiple turbid layers within the water column have been observed in southern Alaskan fiords (Wright, 1970). It is believed that this may be a very significant agency of sediment transport, not merely within fiords but also on the shelf and slope.
The Blake Development Project proves the flexibility of FPSOs in the successful completion of a schedule driven modification to a producing FPSO
Authors: Soeters Mireille , Reynolds Keith , van  Elk Harry
Published: October 2008

The Bleo Holm is an FPSO owned and operated by Bluewater, leased by Talisman for operation of the Ross & Parry Fields located in the North Sea. After discovery of the nearby Blake Field and evaluation of several development concepts a tieback of the Blake field to the Bleo Holm FPSO was selected.

In order to be able to produce the Blake field through the Bleo Holm, extensive modifications to the Bleo Holm facility were required that would only be possible to implement during a shutdown period. Without production during the shutdown period the owners of the Ross & Parry Fields would be subject to a loss of oil revenue. Minimisation of the shutdown period was therefore absolutely essential and was reflected in the execution schedule that became the project driver.

This paper describes the development of the project during all its phases (concept, engineering, construction and commissioning) and highlights how the construction schedule, being the main driver, influenced decisions taken during the course of the project.

The paper also discusses the flexibility of the FPSO concept and the benefits the Blake Field Tie-in to the Bleo Holm provided to the field owners and to Bluewater.

Introduction

The Bleo Holm FPSO (Floating Production Storage and Offloading Facility) is located in the North Sea 100km North East of Aberdeen in the Moray Firth. The Bleo Holm FPSO is owned and operated by Bluewater and leased to Talisman Energy and partners Nippon Oil, Intrepid and Kerr McGee, for production of the Ross & Parry fields. The field is located in license blocks 13/28a and 13/29a and has estimated recoverable reserves of 50 to 70 million barrels of oil. From sub-sea well completions and flexible risers, well fluids are delivered to the Bleo Holm where, after separation into oil, gas and water, oil is stored in the cargo tanks. The resultant gas is compressed for gas lift and export and the cleaned water is routed overboard. First oil from the Ross & Parry Fields was achieved 19th April 1999. The Blake field, in license blocks 13/24 and 13/29, laying approximately 10 km North from the Bleo Holm location, was discovered in mid 1997. The Blake field, operated by BG Group, is owned by BG Group and partners Paladin and Talisman Energy. The recoverable reserves of the Blake Field were estimated to be approximately 80 million barrels of oil.

Initially a dedicated production facility for the Blake Field Development was considered and, following technical, economic and safety evaluations of the various solutions an FPSO concept was selected as the most favourable. As a result of the fall in oil price in 1998 a standalone development was no longer considered economically viable and the concept of a subsea tie-back to a host facility was generated. The following facilities were identified as having the potential.
Development of a Deep Sea FPSO Suitable for the Gulf of Mexico Area
Authors: Park In-Kyu , Shin Hyun-Soo , Chung Hoe-Woo , Beek Johan W.F.
Published: October 2008

An overall conceptual design development of a deep sea FPSO suitable for the Gulf of Mexico area is described. The oil storage capacity was determined after the market screening by analyzing the answers to questionnaires submitted to potential field operators. The locations of turret, accommodation, topsides, flare boom and offloading equipment have been studied carefully before selecting the final location on the general arrangements. The basic drawings of general arrangements, lines, mid-ship section, accommodation layout and outfitting systems are developed. The basic hydrostatic calculations, stability, motions, mooring, structural and riser analyses are also carried out. The model tests are carried out at 2-dimensional wave flume for roll motion and wave model basin for global performances. In order to reduce the roll motion, a box-like mid-ship section is adopted with projected bilge keels. The model tests confirmed the expected good motion performances. A turret moored, one million barrels storage capacity, double hull FPSO is found to be most suitable in the Gulf of Mexico.

Introduction

The Gulf of Mexico was the last offshore oil field area not open for FPSOs. The absence of FPSOs from the GoM is partly due to the well-developed production and pipeline infrastructure. Another reason is the relative prevalence of gas developments in the GoM. As production enters deeper water and far away from any export infrastructure, the demand for FPSOs gets stronger. The final threshold to open the GoM for FPSOs was a safety confirmation. MMS (the Minerals Management Services) have expressed concerns about FPSO deployment, which have focused on the performance of offloading operations and the vessels' survivability during hurricanes in the GoM. According to the EIS (Environmental Impact Statement) recently issued by MMS, potential sitespecific impacts are essentially the same as with other deepwater development and production systems. The FPSO has been widely used as a most competitive production system concept in other offshore fields where infrastructure is not sufficient, or where the fields are marginal. As the water depth for offshore fields increases, more offshore operators have selected the FPSO concept. Considering the size of the oil reservoirs in the GoM, FPSOs will be widely adopted by the main operators.

On December 31st 2001 the MMS announced its decision to allow the industry to propose using FPSOs in the central and western Gulf of Mexico.

This paper presents an overall conceptual design development of a deep sea FPSO suitable for the Gulf of Mexico area. The locations of turret, accommodation, topsides, flare boom and offloading equipment have been studied carefully before selecting the final location on the general arrangements. Environmental conditions in the Gulf of Mexico, such as hurricanes, ultra-deep water depth and loop currents, required special consideration in the dimensioning and arrangements.
Reducing Spatial Aliasing in Wave-Equation Multiple Attenuation
Authors: Jiao Jianwu , Leger Pierre , Stevens John
Published: October 2008

Multiples are a major problem in offshore seismic exploration. Wave-equation methods are a popular tool for multiple attenuation, but behave poorly in the presence of spatial aliasing. This paper will propose a method to reduce the effect of spatial aliasing. It does this by first applying a linear transformation to the wave equation. This transformation reduces dips in the data, but does not involve approximations, nor does it change the form of the equation. Wave extrapolation is then performed using an efficient Kirchhoffstyle phase-shift operation. The modeled multiples are adaptively subtracted from the original traces with a multichannel constrained filter. The proposed method has givengood results on a data set from the East Coast of Canada.

Introduction

The basic model in seismic processing assumes that reflection data consists of primaries only. If multiples are not removed they can be misinterpreted as, or interfere with, primaries. Therefore the attenuation of multiple reflections has been an important research subject and many methods have been developed. The methods can be classified into two types: those that exploit the periodic nature of multiples, and those that exploit the moveout differences between multiple and primary reflections.

The first category includes predictive deconvolution in the x-t or ?-? domain. Predictive deconvolution assumes that the multiples are periodic within an application window and that the primary events are not - that is, the multiples can be predicted and thereby subtracted from the seismic records. In the prestack x-t domain, water bottom multiples are periodic only for zero offset traces and flat-water bottoms. To achieve periodicity of multiples for far-offset traces, transforms such as the ?-? transform or the radial trace method must be applied. Still, for shallow water depths (shorter period multiples), periodicity only holds in a limited window. Predictive deconvolution can introduce spurious events and needs to be applied with care. It is more effective for removing "ringing" multiple energy than longer period waterbottom multiples.

The second category includes methods in the F-K, K-L and ?-? domains. While these methods are routinely used and can be very effective, there have a number of problems. All of these methods lose effectiveness when the velocity discrimination between primary events and multiples is small. This is the case at near offsets where there is little or no separation of primary and multiple events, and at all offsets when there is little velocity difference. Their effectiveness is further reduced when the seismic events violate the modeling assumptions (non-hyperbolic events for F-K and K-L, or non-parabolic events after NMO for ?-?).

Recently there has been interest in techniques based on wave theory, which can be considered extensions of conventional predictive deconvolution. Multiples are predicted by either wavefield extrapolation1,2,3 or wavefield inversion4. They are then subtracted from the original data.
Tandem Mooring LNG Offloading System
Authors: Poldervaart L. , Queau J.P. , Van Wyngaarden Wim
Published: October 2008

The attractiveness of placing a natural gas liquefaction plant on a vessel moored at or close to an offshore field is known. This vessel can either be part of an oil development in which it liquefies associated gas or a stand alone development of a gas field. In the associated gas case, the Floating LNG (FLNG) unit makes certain oil developments feasible by turning the associated gas disposal into a moneymaking opportunity. In the gas field case, the FLNG makes remote offshore field production economic. The safe reliable transfer of this LNG in open sea, possibly harsh, environment has however not been possible. The proposed LNG Offloading Arm (LOA) effectively combines proven technology and operating experience to effect the safe and reliable transfer of LNG between tandem moored vessels or between a fixed tower and LNG carrier in up to 5 meter significant seas. The concept is based on the experience of mooring systems surviving 100 years storms, dis-connectable mooring systems in typhoon areas and work performed on cryogenic swivels. The LOA structure consists of "vertical" and "horizontal" arm section with swivels to provide articulations required to follow the relative motions between the FLNG and the tandem moored LNG carrier. The vertical section is supported from a cantilevered rotating structure on the back of the FLNG vessel or on a fixed tower. The horizontal section connects the LNG carrier to the lower end of the vertical section. Each section is composed of a central pipe for LNG transfer and a large diameter outer pipe structure also used as the vapor return from the LNG carrier. The LNG carrier can be passivelymoored using gravity restoration by weights located in the horizontal section of the loading arm or DP assisted using both the arm and the LNG carrier thruster system.

Introduction

The technology for cryogenic liquefaction and storage of LNG on an offshore floating vessel is known. The safe reliable ship to ship transfer of this LNG in an open sea, possibly harsh, environment has however not been possible. SBM having experience in both the supply and operation of mooring systems put this experience to work in the development of a Tandem LNG Offloading system. The philosophy adopted for this development was to keep the design simple and whenever possible stick to components that had a known track record.

Having over 40 years experience in the design, supply, and operation of Single Point Mooring (SPM) systems and Floating Production Storage and Offloading (FPSO) systems the value of simple robust design was well understood and applied to this LNG Arm development. Known technology and operational experience either directly or indirectly applied to the Arm include soft yoke or gravity moorings (Fig. l), articulated fluid transfer arms (Fig. 2), cryogenic swivels (Fig. 3a and b) and tandem mooring systems (Fig. 4).
Correcting for Vector Infidelity With OBS Data: From Ugh to Aah !
Authors: Clarke R.A. , Dellinger J.A.
Published: October 2008

Vector infidelity is the failure of ocean-bottomseismic geophones to respond isotropically to incoming seismic energy. With the rising popularity of multi-componentocean bottom seismic data, the issue of vector infidelity is becoming increasingly important. There are numerous causes of vector infidelity, which may be due to seafloor conditions, acquisition equipment or even processing.

We illustrate this with a catalogue of examples, highlighting the effects on the data and the final processed image, and we present some techniques to correct for these infidelities.

Introduction

Traditional marine seismic acquisition, using streamers of hydrophones, only records the pressure field at the receivers. Ocean bottom seismic acquisition, on the other hand, typically uses four component sensors in order to record the full wavefield at the receivers. While this provides moreinformation about the true elastic nature of the earth, it also leads to more a complex processing flow.

One of the first steps in this flow should be to correct for possible vector infidelity in the data. This occurs for numerous reasons. The cable or node is physically located on the seafloor so that the seafloor itself is a cause of vector infidelity. Spatial variations in the seafloor conditions can alsolead to variable coupling, and may cause a cable to lay in an odd position. For example, a rock could cause the cable to be twisted, leading to orientation errors, while a small hollow could cause the geophone to not be in contact with the seafloor at all.

As the cables are layed down they twist slowly, so thatthere is not usually a preferred top and bottom. Typically the geophones are gimbaled such that the vertical component remains vertical. This gimbal is very similar to a heavilydamped pendulum. However, because the gimbal can move, even though it is heavily damped, it often leads to crosstalkbetween the horizontal and vertical components, which shows up as converted wave energy on the vertical component. Fixed geophones may help reduce this, and would be cheaper to manufacture, but would add further complications to the processing.

The geometry of the cable also leads to vector infidelity. The cable is stiffer in the in-line direction so the in-line component of the recorded data usually has a higher frequency content. The coupling is typically better in the in-line direction than in the crossline. There is also evidence that cables mayroll when struck by the seismic wavefield, and the resulting motion is then superposed on the data of the crossline component.

These considerations, combined with the difficulties of placing cables in areas where the seafloor may be crowded, have led to recent interest in node technology. Nodes have more isotropic geometries and so should have fewer vectorinfidelity issues than cables. However, there may still be problems with coupling, and also problems due to the gimbals, so it is likely that a vector fidelity correction will still be needed.