bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design of Subsea Multiple Pig Launcher for ETAP
Authors: Smith B. , Blower S. , Ferguson G. 
Published: October 2008

Abstract
This paper describes the design of a multiple pig launcher for installation on the MACHAR subsea production manifold, located 150 miles east of Aberdeen, in 300 feet water depth. The manifold forms an integral part of BP's Eastern Trough Area Project (ETAF') and is linked to the Central Processing Facility (CPF) platform by a 22 mile long subsea multi-phase pipeline. The length of this pipeline and the resulting temperature drop from the 120°C well temperature means that wax deposition is a potential problem. To maintain optimum efficiency frequent pigging operations will be required to remove the wax deposits. The ability to maintain this efficiency over the life of the field is fundamental to the economic viability of the whole field. This requirement has led to the development of an innovative design solution for the subsea pig launcher to enable single line subsea pigging operations to be carried out as an integral part of the pipeline maintenance programme. The design is based on optimising CAF'EWOPEX costs, utilising conventional surface vesselsfor deployment and the provision of a reliable, fail safe, ROV operated pig launch mechanism. Although pig launchers have previously been deployed for subsea use, the specific requirement for continuous operation as part of the pipeline maintenance programme will possibly be the first application of this type of equipment in the World.
The most significant aspect of this development is the provision of a reliable, cost effective, long term pigging facility for subsea operations based on simple operation and minimum intervention times.

Introduction : Background
Consent to start the 1.6 billion GBP development of the Eastern Trough Area Project was granted in December 1995. It involves the development of seven distinct fields each of which would have been marginal, stand alone, developments but have been combined into an integrated project by alliance partnerships. Fundamental to the Success of the project is the application of alliance working Concepts embracing the principles of the industry's CRINE (Cost Reduction initiative for the New Era) initiative. BP, with a 58% interest in the development, will operate the ETAP facilities on behalf of the partners : BP, Shell, Esso, Agip. Murphy, TOTAL and Mitsubishi Oil.
The fields involved in the development are Marnock. Mungo, Monan and Machar, Heron, Egret and Skua along with two future fields, Mirren and Scoter will be operated by BP. They have combined estimated reserves of some 400 million barrels of oil, 35 million barrels of natural gas liquids and 1.1 trillion cubic feet of sales gas.
Design and Installation of a Cost Effective Completion System for Horizontal Chalk Wells Where Multiple Zones Require Acid Stimulation
Authors: Thomson D.W. , Nazroo M.F. 
Published: October 2008

Abstract
An innovative completion design that allows multiple acid fracs to be performed in horizontal subsea chalk-formation wells with a single trip into the wellbore has recently been codeveloped by a major North Sea operator and an oilfield engineering/manufacturing/service company. The project was initiated to develop a system that would allow multiple acid stimulations to be efficiently performed in the shortest possible time in the North Sea Joanne Field. The system ultimately developed allows acid stimulation of up to 10 different zones in a single trip with no through-tubing intervention. The first well in which this new technique was used had 7 zones, and 3 additional wells with 10 zones each were later completed. The development of this system and case histories of the first four subsea wells requiring stimulation will be presented in the paper.
The key element of the system is a multi-stage acid frac tool (MSAF) that is similar to a sliding sleeve circulating device and is run in the closed position. Up to 9 MSAF tools can be run in the completion with isolation of each zone being achieved by hydraulic-set retrievable packers that are positioned on each side of an MSAF tool. Each sleeve contains a threaded ball seat with the smallest ball seat in the lowest sleeve and the largest ball seat in the highest sleeve. With this system, stimulation of 10 separate zones is accomplished in 12-18 hours by a unique procedure that lubricates varying sized low-specific gravity balls into the tubing and then pumps them to a mating seat in the appropriate MSAF, thus sealing off the stimulated zone and allowing stimulation of the next zone which is made accessible by opening the sleeve.
This technique provided a substantial reduction in the operational time normally required to stimulate multiple zones and allowed the stimulations to be precisely targeted within The case history data will provide comparisons in operational times between traditional stimulations and this new method as well as the significant enhancements to cost that resulted from its use. Additionally, this completion method allowed the stimulations to be designed and matched to the requirements of each reservoir zone, which provided the most cost efficient treatments possible.

Introduction
The Judy/Joanne Fields are located in the central North Sea on block 3017a (commonly known as the J Block of the UK North Sea), 280 kilometers South East of Aberdeen. The water depth is approximately 80 meters. The complete field development consists of a 24-slot platform for Judy and a 12-slot subsea template for Joanne. Production from the Joanne subsea manifold is transported through two 12-inch pipelines, 5-kilometers in length, to the Judy platform.
Deepwater Installation of an Electrical Submersible Pump in Campos Basin, Brazil
Authors: Mendonp J.E. 
Published: October 2008

Abstract
In October11994 Petrobras, leading a team of six companies has installed for the first time in the world an ESP in a subsea well. The subsea ESP system in the well RJS-221, located in 86 meters water depth, in the Carapeba oilfield has now completed more than two years in operation without failures. The success with this installation has encouraged Petrobras to proceed with this project in order to extend the application of this technology to 1150 meters water depth in the second Phase. This paper presents briefly the first subsea ESP installation, calling attention to the main aspects that make the difference from a conventional to a subsea ESP installation and focuses on the developments for the deepwater installation in the well RJS-477, in 11 07 meters water depth, in the East-Albacora oilfield by mid 1997.

Introduction
The oil production in the Brazilian coast is mainly focused on the giant reservoirs discovered in deepwater, making use of floating production systems, that receive the production directly from the satellite wells or from subsea manifolds. In Campos Basin 13 fixed towers were installed, all of them in shallow waters, up to 300 meters. From these, eight are in the so-called North-east Pole of Campos Basin.
Stimulated by an increased oil demand, this production is being complemented by new discoveries in deeper and deeper waters. This production was for a long time based on natural flow, water injection in the reservoir and in the artificial lift method of gas lift.
Production Development has signified the capacity to deal with the increase in the number of floating production units, with longer flowlines, as well as with the problems brought by well depletion and reservoir specific limitations.
Water and gas lift injection used to be the first options to adopt in the majority of the cases. But the efficiency of these solutions is not high and they are not always feasible. Reservoir pressure may be insufficient to produce over long distances and gas lift loses a lot of efficiency in long horizontal flowlines, typical of subsea wells, as well as with the BSW increase.
A new method was then required for oil production over long distances, specially from deepwater wells, allowing the platform to be placed in shallow waters, and for a reduction in the number of platforms, thus simplifying the production layout and reducing the investments.
Within the PROCAP 2000 Program for deepwater technology development, a project was created by the end of 1992 in order to develop such a method.
20 Years of Drilling and Completion Experience in Campos Basin: A Results Review
Authors: Bastos Bráulio Luís C.X. 
Published: October 2008

Abstract
Campos Basin has been producing since 1977, initially from a water depth of 120 m (394 ft), on the Enchova field, to today's record of 1027 m (3,370 ft), in Marlim South field. It will be presented how the profile of Campos Basin environment, considering oil accumulations and water depth, pushed the technology toward deeper and deeper waters. Drilling and completion main concepts, techniques and equipment used in Campos Basin all over these years, together with their performance, will be discussed, as well as their impact on different projects and the basin results.
Milestones in the basin exploration and exploitation, along with surpassed difficulties will be presented, showing their importance for the province development. The paper will also show how the amount of experience gathered throughout these years pointed towards new trends in technology, which already starts to be tested and used in prototype and pilot projects all over the basin. This knowledge starts to prove useful not only in Campos Basin but also on many different offshore sites around the world.

Introduction
Located offshore Rio de Janeiro state, on the southeast region of Brazil, Campos Basin is, by far, the main petroleum province in Brazil. Its area covers 110 sq. km, ranging from 50 (164 ft) to 3,400 m (1 1,155 ft) water depth.
Presently, twenty years after first commercial oil production in 1977, Campos Basin installations comprise 14 futed platforms and 14 floating production systems, distributed among 33 oil fields. This installations account for an average production of 600,000 BOPD (representing near 70 % of the domesticproduction) and 9.5 million daily cubic meters of gas. This production is handled and exported to shore via over 2,900 km of oil and gas flowlines.
By December, 1996, Brazilian total reserves of oil and equivalent gas added up to 11 billion barrels. Of this total, 82 % is located offshore, 63 % in water depths greater than 400 m. Presently, these deep water fields already answer for near one quarter of domestic oil production. In the future, this share will increase until, by year 2005, reaching a level of 70 % of Brazilian production.

Campos Basin Development Milestones
History of Carnpos Basin can be divided in three different periods, each one with its own set of unique characteristics.

1) 1974 to 1982: "20.000 Leagues Under the Sea".
By the year 1974, the northern region of Rio de Janeiro state, around the city of Campos, was a typical country site. Sugar cane agriculture, cattle raising and fishing were the main economical activities.
Campos Basin: A Real Scale Lab for Deepwater Technology Development
Authors: Assayag M.I. , Castro G. , Minami K. , Assayag S. 
Published: October 2008

Abstract
During the past 20 years, driven by the national economical and political pressures caused by the several petroleum crisis of the 70s and 80s, Petrobras has had to innovate in order to increase the Brazilian oil output. The major problem was that the large Brazilian oil reservoirs were all located offshore in water considered too deep, at that time. The water depth was 120m, the distance to shore was more than 100 km, and the estimated production rate was around 7 times higher than in the Brazil Northeast platforms. The adopted solution was based on the international technology available, that is, using fixed platforms. That was certainly a tremendous change in what has been done before, and, certainly, it was the first step to a new era of production facilities. The use of conventional technology would demand both a long lead time to the first barrel and the resources were not compatible with the urge of cutting down the oil import, and to the delicate country foreign cash flow balance. Petrobras had to dare trying new concepts using national technology in its own production facilities as a huge R&D lab. Examples of new production systems, equipment, process, procedures and approaches tried in Campos Basin is given throughout this paper. Past successes and failures that led to the currently used technology, as well as the more recently planned prototype testing programs are presented.

Introduction
The 1973 world oil crisis brought a tremendous economical impact on most countries, especially on those with strong dependence on imported oil. This led to the increase in investment on oil and gas exploration and production worldwide, including the search of new technology for producing fields located in hostile environment.
The first oil discovery in the Camps Basin, in Brazil. occurred in 1974, just in the middle of the economical chaos created by the crisis, worsened by the country's unfavorable external payment balance. Bringing the newly discovered prolific oil province on to production, as fast and at the lowest cost as possible, became a key issue for Petrobras. The increased throughput would help reducing the burden of Brazil to manage its increasing external debts. The oil import was responsible, at that time, for a significant portion of the Brazilian payment unbalance.
The country had to reduce its oil consumption and, at the same time, increase its oil production. The reduction would come with the introduction of alcohol fueled automobile, and the use of other alternative energy sources, while the increase would mainly come through the Camps Basin offshore development.
The problem was to produce in conditions never experienced before. The Garoupa and Enchova Fields, the first ones in the Basin, located in 120 m depth, were already considered in deep waters, at the time.
Automatic Welding and Ultrasonic Inspection for J-Lay of the MARS Tension Leg Platform Export Pipelines
Authors: Kopp F. , Perkins G.G. , Laing B.S. , Prentice G. , Springmann S.P. , McDermott J. , Stevens D.M. 
Published: October 2008

Abstract
The paper describes the use of automatic welding and ultrasonic weld inspection for the deepwater J-Lay of the 18-inch oil and 14-inch gas export pipelines from the MARS Tension Leg Platform (TLP) in the Gulf of Mexico. While automatic welding has seen frequent use on offshore pipelines, its use on deepwater J-Lay was a first, and a significant development effort was undertaken to ensure success during offshore pipelay. To maximize the probability of detecting significant weld defects in these deepwater pipelines, especially those defects with significant through-wall height, Shell specified use of automated Ultrasonic Inspection (UT). This type of inspection can be used to quickly and accurately locate and sue the through-wall dimensions of a defect. These features, in combination with the high toughness of the automatic welds, made it possible to use the Alternative (i.e. Fitness for Purpose) Acceptance Criteria of the Appendix to API 1104, instead of the workmanship criteria of Section 6 of API 1104. As such, a good balance was achieved between, on the one hand minimizing the overall repair rate by not having to repair indications that were not harmful to the weld, an4 on the other hand, maximizing the probability of finding and suing significant weld defects. This first time use of automated UT and application of fitness for purpose weld acceptance criteria on an offshore pipeline project in the Gulf of Mexico goes a long way towards validating the approach as a suitable and cost effective inspection method.

Introduction
The MARS Tension Leg Platform (TLP), a 72%28% joint venture between Shell Offshore, Inc. and BP Exploration, is located in Garden Banks Block 864 in 2940 ft water depth. The two export pipelines, a 14-inch gas pipeline, and an 18- inch oil pipeline were to be installed by J-Lay, using the same J-Lay equipment and lay vessel (the dynamically positioned Derrick Barge DB 50) as used previously to install the 12- inch export pipelines to Shell's Auger TLP'. Dunng J-Lay 165-ft-long pre-fabricated quadruple joints are brought onboard in large storage bins. The quadruple joint is upended in the J-Lay tower and welded in a single station. While on the Auger Project acceptable cycle times were achieved using manual welding (SMAW), the larger pipe diameter and wall thickness on the MARS project warranted an investigation of using automatic gas metal arc welding (GMAW) to obtain much faster joint cycle times than could be achieved using SMAW. The pipelay contractor J Ray Mc Dermott and Shell had negotiated a risk sharing agreement, where both would pay for the incremental cost of automatic welding and UT, but also would share savings resulting from a faster lay rate.
Application of Composite Materials in Deep Water Offshore Platforms
Authors: Botros Fikry , Williams Jerry , Coyle Edward 
Published: October 2008

Abstract
This paper presents the results of a joint project between Conoco Inc., DuPont Advanced Materials System and Kvaerner to investigate the technical feasibility and cost benefits that may be derived from the use of composite materials for structural applications in deep water platforms. The focus of the study was a hypothetical Tension Leg Wellhead Platform (TLWP) installed in I, 400 m water depth in a typical North Sea environment. Although a TLP r e p m t s the most weight sensitive platform configuration, almost all floating production facilities will some benefit from saving weight and lower maintenance costs associated with composite materials.
The project started with the premise that all the platform structure would be considered for composites applications including the hull, deck, topside facilities, risers and tethers. Further screening m w e d down the emphasis for the preliminary design effort to the hull and deck, although all potential applications were considered in the economic assessment. The design concepts developed were driven by the cost of raw materials and the availability of low-cost large-structure fabrication processes. Global design was performed for a base case steel platform as we1 I as for several alternative configurations each comprising a different degree of application of composites in the topsides, hull and risers. The applications ranged from substituting steel payload with composite alternatives all the way to composite columns and deck pontoons and main structural members. A cost estimate for the different platform configurations was conducted and compared to base case steel TLWP.
The paper also highlights important obstacles that need to be overcome before there is wide acceptance of composite materials as a substitute for steel in the offshore industry. Demonstration of the performance of composites is particularly critical for primary structural applications such as those considered in this study.

Introduction
In June 1995 was established between DuPont, Conoco and Kvaerner with the ultimate goal of commercialization of am composite applications within the oil and gas industry. The present study was conducted to investigate the offshore use of composites from a holistic view point in order to provide guidance to themembers as to which particular applications should be pursued Composites have proven to be cost effective and are already being used in a variety of offshore applications such as gratings, being used in a variety of offshore applications such as gratings, skids, tanks, -etc. The objective of this study was to determine if quantum breakthroughs could be made by the use of composites in the primary structure.
Supersonic, High Pressure, Low Radiation Flare System Design
Authors: Smith Scot K. , Selle Gary K. 
Published: October 2008

Abstract
Two years ago, Callidus Technologies Inc. recognized the need in the industry for a new and different method of flaring high pressure gases from onshore and offshore production facilities. After a review of the existing flare tip technologies currently available in the marketplace, a program was developed and implemented to design and prove, in full scale testing, a flare tip that would provide for lower radiation levels, lower flare tip weight, and improved smokeless performance. The flare tip is the first in the world to utilize converging-diverging super-sonic nozzle technology in the flaring of production gases. By using these nozzles to increase the waste gas exit velocities to greater than Mach 1, this flare tip inspirates significantly larger quantities of air into the combustion zone. This results in a much cleaner burning flame, lower emissions in the form of radiation, and a much higher momentum in the flame envelope due to the increased mass of material giving a stiffer and more up-right flame. All of these factors combine to produce shorter boom lengths, reduced flare emissions, and smaller relief header size due to higher flare backpressures. In addition to the combustion process improvements in the flare tip, an evaluation of the construction techniques and metallurgy's was undertaken and relevant improvements were made in these areas also.
To prove the theoretical application of this supersonic nozzle technology, a test facility was designed and constructed to test the flare tip. Initially, a scale model was tested at relatively low flows, up to flows of 10 million standard cubic feet a day. This testing proved very successful. The test facility was then modified to flow larger rates, up to 200 million standard cubic feet a day of natural gas. Testing of the full size flare tips has proven achievement of the theoretical design goals for the project. This new design concept is now being introduced to the production industries worldwide.

Introduction
Flare systems are used in offshore and onshore production and drilling facilities to dispose of the associated gases and liquids from testing and production. In some parts of the world, these hydrocarbon streams can be vented directly to the atmosphere with acceptable environmental impact and with approval of local agencies/government. Combustion of these gases using a flare is used where the impact to the environment is determined to be significant, or safety issues associated with venting unburned hydrocarbons mandate.
Flare systems can be separated into two basic types: Open flares with visible flames and Enclosed flares with non visible flames. Open flares are typically designated as high pressure type or "pipe" flare type.