bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Terra Nova FPSO Turret Mooring System
Authors: Howell G.B. , Duggal A.S. , Lever G.V. 
Published: October 2008

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.