bluuebunny/crossref_metadata_2025_split huggingface dataset:
Process Equipment for Offshore Viscous Crude Handling: Captain Field
Authors: Sutton John E. 
Published: October 2008

Abstract
The Captain Field in the UK Sector of the North Sea is an accumulation of relatively high density, high viscosity, low temperature, low GOR crude oil, all factors which in themselves present challenges in the design of oil and gas processing equipment. The selection of an FPSO-based production facility, with its inherent motion characteristics, compounded these challenges. The Captain Field facility design has successfully incorporated several novel features to address the oil, water and gas processing requirements.

Introduction
The Captain Field is located in UKCS Block 13/22a, 130 km northeast of Aberdeen, in 104 metres of water. The oil accumulation is heavy and viscous by North Sea standards, being 19.3°API and 88 cP at a relatively low reservoir temperature and pressure of 30°C and 93 bara, and with a gas/oil ratio of 23 sm3/m3 (130 scf/stb).@ The fluid properties and offshore environment require innovative horizontal drilling, well completions, and artificial lift technology for economically successful field development. Extended reach, horizontal wells are proposed for all oil producers and water injectors, to be drilled from two drilling centres. Downhole electric submersible pumps will deliver a capacity of 20,000 per well. The initial development comprises a Wellhead Protector Platform (WPP) tied back 1.5 km to a Floating Production Storage and Offloading vessel (FPSO), from which export quality crude will be shuttle tanker. Later stages of development will likely utilise subsea or additional wellhead platform tie-backs to the FPSO.
Process design for the Captain field has had to address several significant concerns not normally encountered in offshore processing applications. The principal problems which have been addressed in the facility design are in the primary three phase separation. Although the separator vessels are some of the largest in the North Sea, implementation ofconventional separator design parameters would have required even larger vessels, exceeding practical limits.
Separator internals have been designed to minimise effects of external motion acceleration forces on the vessels. Submerged liquid inlets to "water wash", the incoming crude are employed to enhance efficiency of separation of the liquid phases. Because of the extremely high foaming tendency of the Captain crude, a novel "foam handling package" has been developed. This process allows treatment of the foam outside of the primary separator, rather than trying to accommodate the foam within an oversized separator vessel. Also, overhead spray headers have been installed in the primary separators in an experimental attempt to mechanically break foamaccumulations. And finally, the process separation train has been designed to accommodate the "mousse effect" (gas carry-under in the outlet oil stream) noted in Captain and other North Sea heavy crudes.
These factors and others have been successfully combined into an integrated process facility designed specifically for the Captain field.
Mars TLP Drilling and Production Riser Systems
Authors: Denison E.B. , Howell C.T. , Ju G.T. , Gonzalez R. , Myers G.A. , Ashcornbe G.T. 
Published: October 2008

Abstract
The Mars riser systems are a major departure from those previously used on TLPs. All risers are operated with top tensions only 20% above their wet weight; the high-pressure, light-weight drilling riser has a secondary pressure barrier while drilling the majority of the well; a platform-style rig is used and all risers incorporate vortex suppression devices. These advances reduce TLP payload, reduce the risks associated with simultaneous drilling and production and minimize fatigue damage and riser interference in an area exposed to frequent Loop Current events. The design and analysis of the systems required the development and improvement of analysis tools, the performance of a multitude of hydrodynamic tests and the development of a scheme for careful tension-sharing among the three tubulars.

Introduction
The simplest introduction to the Mars riser systems is to compare them with the riser systems on the Auger TLP (I), which was installed in roughly the same water depth in 1993- 91. Auger was designed to use proven deepwater drilling methods and platform-like completion techniques. It uses a fixed rig, a drilling riser, a subsea BOP stack and a guidelineless reentry system very similar to those used on today's deepwater floating drilling vessels. Auger uses a surface BOP for well completions and work overs. It requires a lateral mooring system to position the rig (and thus the entire TLP) for reentries, drilling, and completions. It does not use a traditional seafloor well template and, due to the spread-well seafloor pattern, has minimal potential for riser interference.
The Mars TLP utilizes a smaller, platform-style, skid able rig. The high-pressure drilling riser, in conjunction with a surface BOP, still gives a platform-style look for most drilling and completion operations. The skidable rig and gudelines eliminate the need for a lateral mooring system and allow a smaller wellbay. The system also reduces the tensioner stroke requirements by placing the surface trees nearly directly above the subsea wellheads. I t uses an Auger-style dual-casing well system and a conventional hydropneumatic tensioner system which capitalizes on the smaller stroke requirement.
Development of a fuller understanding of riser-to-riser interference in storms and in Loop Current events (LCEs) has allowed the lower operating tensions and closer well spacings for Mars. Reducing VIV and manipulating riser fluids 'and coatings to control thermal effects (tension sharing variations) also help alleviate problems associatedwith low tensions.

Preliminary Design Work, Concept Evaluation

Dual-Casing Production Risers
The Mars Production Riser System is patterned alter Auger (I). Details above and below the seabed are shown in Figure 1. Safety and operability are the predominant design goals.
Gulf of Mexico Subsidence Monitoring Project with a New Formation Compaction Monitoring Tool
Authors: de Kock A.J. , Johnson T.J. , Hagiwara T. , Zea H.A. , Santa F. 
Published: October 2008

Abstract
Formation compaction in unconsolidated geo pressured turbidite reservoirs in the Gulf of Mexico (GOM) is an issue of great uncertainty and concern. When compaction occurs, it changes the porosity and permeability properties of the reservoir rock and can affect recovery efficiency and well productivity. It can deform well tubulars, creating operational problems and shortening well life. If compaction is significant, especially when multiple stacked reservoirs are involved (as in the case in this field example), then compaction can create a subsidence bowl at the ocean floor. In GOM offshore operations, this could cause platforms to subside deeper into the water and therefore create potentially severe safety problems. Therefore, failure to properly address issues of compaction and subsequent subsidence during the design and development phases of these capital intensive, deepwater projects could lead to severe financial setbacks.
Because of the broad impact of compaction and seafloor subsidence, it is crucial to have a compaction monitoring program in place. As a result, we developed a new Formation Compaction Monitoring Tool (FCMT) and new methods of measurement and interpretation. The FCMT is a wireline device that uses multiple gamma-ray detectors to determine locations of and precise distance between radioactive markers planted in the formation or casing. Compaction of the formation can be measured by changes in the distance between the markers. For precise estimation of the vertical distance between a pair of markers, the new method uses an array of three or four detectors.
By examining the tool response to a marker, we developed a new method to determine the exact vertical and lateral location of the marker using a Lorentzian response model. Consequently, not only the vertical compaction but also lateral displacement of markers can be monitored with the new method..
The accuracy of the tool was established in the test facility where gamma-ray sources were placed at precisely known intervals. The tools were logged centralized at three logging speeds (5, 10, and 15 ft/min.), and data were collected at 0.1 in. intervals. The vertical distances between a pair of radioactive markers spaced 30 ft apart were measured accurately to within 0.1 in.
The first base-line logs were collected successfully in the four wells in a GOM deepwater development. High consistency among measurements from different logging passes proved that the FCMT can provide precise distance measurements with newly developed methods.

Introduction
Formation compaction is a major concern in unconsolidated sand reservoirs. Compaction can reduce formation porosity and permeability, affecting long-term hydrocarbon production from the reservoir. Compaction can deform well tubulars, creating operational problems and shortening well life. If compaction is significant, it can cause subsidence of ocean floor, leading to severe safety problems for offshore platforms.
The Engineering of Pigging Equipment for Subsea Systems in Campos Basin
Authors: Lino A.C.F. , Mastrangelo C. , Pereira F.B. , Gomes M.G.F.M. 
Published: October 2008

Abstract
PETROBRAS EXPLOITS oil from fields located in deep water in Campos Basin, a subsea project which faces some problems. One of them is wax build-up subsea production flowlines. So, since 1990, methods to prevent and remove wax deposits have been studied.
The occurrence of wax build-up in flowlines installed in cold sea bottoms is a permanent challenge, so pigging among other methods, is used to control wax deposition on pipeline internal surfaces. Pigging in subsea systems is a difficult task, because reliability in equipment, facilities, and procedures.
This paper is a continuation of other papers that Petrobras has presented in international conferences and describes pigging requirements for subsea equipment, flowlines, platforms and FPSOs designed for the Campos Basin. Some devices that Petrobras has developed to run pigs in subsea systems, such as dual diameter scraper pig, subsea pig signaler, piggable Y, and piggable loops, are also presented.

Introduction
The occurrence of different types of deposits on pipelines, which affects operational routine in offshore installations, led Petrobras to deal with this problem.
In order to evaluate the available methods for preventing and removing these deposits and to develop others, the Program on Deepwater Exploitation Systems has been studying and testing many techniques. Special attention has been given to wax prevention and removal methods, for this is one of the main operational problems to be faced up to.
Since the beginning of first phase of Albacora field exploitation in 1989, it has been noticed that some production flow lines presents organic deposits build-up. This phenomenon happens when paraffin comes out of solution, as the oil reaches the WAF' (Wax Appearance Point), due to low sea bottom temperatures.
Although Petrobras is aware of asphaltene, scale and hydrate occurrence, this paper will focus on present diificulties, solutions and procedures adopted by Petrobras to minimize wax deposit impact on deep water exploitation projects applying pigging. The use of pigging techniques implies an additional investment that must be foreseen in the initial phase of the project.
The following aspects will be highlighted:Piggable equipment for subsea systems.The use of pigging in Albacora, Marlim and Barracuda fields.

The Engineering of Pigging Equipment for Subsea Systems in Campos Basin
Petrobras exploits oil from fields located in deep water in Campos Basin, a subsea project which faces some problems. One of them is wax build-up in subsea production flowlines. So, since 1990, methods to prevent and remove wax deposits have been studied.
The occurrence of wax build-up in flowlines installed in cold sea bottoms is a permanent challenge, so pigging among other methods, is used to control wax deposition on pipeline internal surface.
What Future for Conventional Pipelay Barges?
Authors: Borelli Antoine J. , Perinet Dominique 
Published: October 2008

Abstract
In order to study the evolution of Conventional Pipelay Barges, the paper presents the past and present capabilities of some selected laybarges and how their equipment has been modified to suit the market needs. A second section reviews the pipelay market needs to date and its major characteristics. A segmentation between Conventional lay, Flexible line and Rigid Reel lay is apparent. All three segments grow significantly from 19% to 1997 and remain at a sustained level of activity for the years thereafter. There is a tendency to shift to smaller diameters and deeper waters. The last section discusses the pipe lay barge evolution; it concludes that the fields where the greatest gains can be achieved for the industry seem to be: for station keeping, dynamic positioning; for laying techniques, S-lay: and for production rates, real-time nondestructive control techniques.

Introduction
Since the Sixties, conventional pipelay barges have dominated the market of pipelaying. This has remained the case, even though considerable innovation and effort has been put into alternative laying techniques such as bottom-tow or near-the-bottom-pull or tow, surface-tow, rigid steel and flexible, reel barge or J-lay.
Throughout this period, ETPM has operated conventional pipelay barges, such as DLB 1601, DLB Polaris or LB 200, first on their own behalf, and later for the McDermott-ETPM Joint Venture. The Company is therefore well placed to look back at the various challenges the industry has met up to now to review those it will be facing in the near future, and to outline the improvements and innovations that will be required to adapt to new market requirements.

Past & Present Barge Capabilities
Present Lay barge capabilities have been largely determined by the successive challenges the industry has had to face.

Large diameter trunklines
The challenge to transfer large quantities of crude or gas over very long distances, with minimum intermediate boosting platforms, started in the North Sea in the mid Seventies. It sill continues today and extends to other areas as well.
Typical characteristics of some selected projects are shown in Table 1.
This has resulted in the construction of a different generation of lay-barges able to work in harsh environments, of two types monohull, such as DLB 1601, or semisubmersible, such as the LB 200 (ex Viking Piper) or SEMAC I. These were further upgraded later in time to suit the needs of the market, mainly with regard to tensioning devices, stinger capacities, monitoring and control systems, handling equipment and welding equipment.
Further, the water depths in which the pipelines were to be laid increased dramatically with the crossing of the Norwegian Trench (deeper than 350m) which resulted in additional increases in tension and stinger/ramp capacity (see Fig. 1- LB 200 laying Zeepipe IIB for Statoil).
Evolution Of Concrete Monohulls After The Nkossa Barge
Authors: Valenchon C. , Rossig J.H. , Anrhs S. 
Published: October 2008

Abstract
The NKOSSA Oil Production Barge, now in production offshore Congo in the South Atlantic, is the first Concrete Monohull Production Vessel, and by far the largest concrete barge ever built.
From the unique experience of designing and building this large concrete monohull, extrapolations towards other concepts using larger vessels have been developed.
The first step of the evolution is to add to the production functions the functions of crude oil storage, and offloading while either keeping a spread mooring for mild environments or choosing a turret mooring for harsher environments (FPSO).
The latest and most innovative evolution is a concept for the development of deep water fields in mild environmental areas such as the Gulf of Guinea. This concept is an FPSO which performs, in addition to its usual functions, all drilling and work-over operations, while allowing dry well heads to be placed above the deck of the unit, called a "Multifunction Barge" (MFB).

Introduction
Concrete fixed offshore platforms are found all over the world including Norway, UK, USA, Australia, the Netherlands and Germany. Some of these platforms were installed over 25 years ago. They have demonstrated their excellent long term behaviour in the offshore environment, with very limited maintenance.
After installation in the North Sea in 1995 of the Heidrun Concrete TLP (Ref. l), and the Troll Olje Concrete Semi-Submersible (Ref. 2), the NKossa Barge is the third concrete floater to be installed offshore during this decade.
This "barge type" structure has been built within an EPC contract following an international call for tender for a steel hull, in which the bidders were allowed to propose a concrete alternative.
The paper presents first the main features of the NKossa oil production barge, and a brief history of other concrete floaters, then the evolution of the NKossa concept to concrete FPSO's and the Multifunction Barge is discussed.

The NKossa concrete barge
The NKossa Field, in production since June 7, 1996, is located 60 km off the Congo coast in water depths ranging from 150 m on the East side to 300 m on the West side. The field has been developed using two steel drilling/wellhead platforms, a production facility, and two Floating Storage/Offloading vessels for oil and LPG. It was decided to use a Floating Production Unit for the hydrocarbon processing facility and for reasons stated below, to construct it out of concrete rather than steel.
This unit, which is the largest concrete monohull ever built, has an operating displacement of 110,000 tomes and is designed to carry a deck load of 33,000 tomes.
The barge houses 80 people, serves as control centre for the other field installations and provides oil treatment, LPG production, gas reinjection, and water injection functions, as well as all utilities (see fig. 1 and table 1).
Offshore Facilities Audit Results
Authors: Pomfret Bill 
Published: October 2008

Abstract
Accidents and downgrading incidents are occurring every minute of every hour of every day somewhere in the Offshore Oil Industry. Contrary to popular belief the safety and risk control standards in the industry are unacceptable, and the industry is paying the price with major increases in insurance coverage. The financial costs to the industry in every nation of the world are underestimated because management are unaware of the extent of such losses, due to under reporting, cover ups and there being no desire or requirement to cost out such incidents. This paper will present illustrated case histories from over 250 offshore audits carried out from Canada's east coast and the arctic, the North Sea, Africa, Middle East, Malaysia, China, Korea etc. using the 5 Star Health & Safety Management System (T.M.) (Offshore Module). The average audit result from 19961997 concludes that, those audited scored less than 71% and only achieved a two star grading, a sad indictment of the industry. However, those achieving 4 and 5 stars saved millions of dollars in premium reductions.

TEXT
Chairman, Offshore Technology Conference, Organising Committee members and fellow delegates, it is indeed an honour to be selected to address this prestigious event. It is my sincere hope that the aspects I will cover will prove both relevant and interesting, but above all, that it will make a contribution to reducing the terrible number of deaths, injuries and unplanned production losses as have been experienced by the industry in the continuous search for black gold. Throughout this presentation and in the 5 Star system the word "Safety" refers to accident, fire and loss prevention, the maintenance of occupational health and welfare and the effective control of pollution from the rig or platform. Over the past few years 1 and my team have conducted some 250 audits in many parts of the world, from the North Sea to Canada's arctic and from the Middle East to Malaysia and from South Africa to China. The system we have used to conduct these audits is the 5 Star Health & Safety Management System (TM) offshore or marine modules, of which the proprietary rights are held by Safety Projects International Inc. The audit system was developed through the 1970's and 1980's based on the combined experience of S.P.1. staff and several clients who made significant contributions, B.P. Petroleum Development staff in Aberdeen helped considerably in the development and evaluation of the prototype module. The audit criteria covers some 108 elements of which 78 are universally applicable to all industries and 30 elements which pertain to the specific area of the rig or platform. The 5 Star system identifies the strengths and weaknesses of any safety program: It allows for the quantification of managements efforts. Possibly the most important facet of the whole program is the giving of recognition to management and labour by means of a star grading for reaching certain high standards of achievement. Like grading hotels, management understand star grading systems well.