bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Mustique / Shasta Project: A Small Operator's Deepwater Management Challenge
Authors: Huber David S. , Smith Clint D. 
Published: October 2008

Abstract
The project management approach taken by a small independent oil company's first venture into subsea is described from initial business plan scoping economics to putting the wells on-stream, Hardy wanted to remain strictly a producer without a large internal engineering staff, However, they were adverse to delegating the project management or design responsibility to an outside company. The solution was a project management team approach with senior representatives of the major vendors being directly involved in the upfront design process. The vendor selection process included all the major contracting methods including turnkey, partnering, teaming and cost-plus.
The Mustique / Shasta project in the Gulf of Mexico included three wells in 800- I 100 ft water depth tied back 9- 12 miles to two platforms in 650 0 water depth.

Introduction
The technical challenges faced in developing a deepwater subsea field are the same for a large multinational or a small independent operator. However. the managerial challenges are significantly different given the small company's lack of in house engineering and project management expertise. Strong focus on risk management is the key to success for the small oil company given that the capital costs of even a small deepwater subsea project is a very high percentage of the market value of the oil company. The approach and lessons learned on the Mustique/Shasta project can lead not only to minimizing upfront capital cost but also help ensure long-term quality and reliability of the production facilities.
Mustique and Shasta were not to be one-off projects. The business plan was to have an assembly line of continuous small gas tie-back projects after Mustique / Shasta but more importantly expand into projects that would add far more significant value to the company in the future. Specifically, this was defined as deepwater oil developments, 25 - 50 MMBO, in up to 2500 ft water depth. Positioning the company [o grow, while not hiring a large engineering staff, was a formidable task for a company that had only operated land and very shallow water depth offshore fields. To our knowledge Hardy is significantly smaller than any operator that has taken on the deepwater development challenge. It was vital that the company's first subsea project be a strong success and the company's key management knew that most projects fail not because of poor technology but because of poor management. Tremendous emphasis was placed on the quality of the project management process including personnel, contracts, interfaces and equipment design.
The issues addressed and methodology used as part of the project management philosophy focused on optimizing the development through strong vendor input and extensive use of commercial engineering.
The Geotechnical Centrifuge in Offshore Engineering
Authors: Murff J.D. 
Published: October 2008

Abstract
One of the greatest needs in offshore geotechnical engineering is for large scale test measurements on which to calibrate design procedures. The geotechnical centrifuge offers at least a partial remedy. Because it allows one to properly simulate stresses, it is a legitimate, relatively inexpensive option to full scale field testing. As such it is a valuable technique and can be an excellent complement to laboratory tests, l-g model tests and numerical analyses. However, it has not been widely used by industry even though the capability has existed for almost thirty years. This paper argues that this technology should gain acceptance beyond the research community,
The paper presents an overview of centrifuge principles, philosophies of use, and limitations of the technique. For illustration, several actual applications of centrifuge testing for complex offshore problems are described. Results are shown to provide important insights into prototype behavior and to agree well with full scale measurements where these are available.

Introduction
Probably the greatest need in offshore geotechnical engineering is for relevant large scale field measurements. For example, a great deal of effort has been expended in collecting all the axial load tests of piles that might be relevant to offshore applications (Pelletier, et all. This effort has clearly shown that there are relatively few tests that are sufficiently well documented that they can be used in any quantitative analysis and fewer still that are even within an rder of magnitude of the load carrying capacity of modem deep water foundations. This is particularly noteworthy since the design procedures (AP[2) are basically empirical and it is prohibitively expensive to carry out site specific offshore field load tests as is frequently done on land. A few tests, mostly onshore, have been carried out by industry that were especially designed to be applicable to offshore conditions. These few tests play a very important role in calibrating our design procedures but there are clearly major drawbacks in such test programs:the largest piles that have been tested have capacities that are an order of magnitude or more smaller than full scale offshore piles,most tests have beenconducted on pile segments embedded at relevant depths through eased holes,a single program can cost several million dollars to perform,the programs consist of very few tests and hence the test conditions are very limited, andit is virtually impossible to find a site with ideal conditions so that some loss of control is inevitable.
At the same time it can be argued that in spite of a fifty year history with offshore piles, reliable observations of their performance are relatively scarce.
Neptune Project: Spar History and Design Considerations
Authors: Glanville R.S. , Halkyard J.E. , Davies R.L. , Steen A. , Frimm F. 
Published: October 2008

Abstract
Neptune marks the first use of this type of structure to support production operations. The paper will discuss existing spar type structures and the development of the Spar design for the Neptune project. Design considerations for hull sizing and mooring system are discussed. Motion analyses and confirming model tests are presented. The well system design is introduced, which allows for the use of surface type trees providing economical well bore intervention capability. The topsides facility layouts are described. The Spar's capability of future drilling operations, using a semisubmersible drillingrig moored alongside the Spar, is discussed.

History of Spars
Spars have been used for decades as marker buoys and for gathering oceanographic data. The first significant Spar for our purposes is Flip, a structure owned by the U.S. Navy andoperated by the Scripps Institution of Oceanography in California. Flip was put into service in 1965 and is used primarily for ocean acoustic measurements.
Flip is 350 feet long. Its hull is 20 feet in diameter over the bottom half and tapers down to a 12 foot diameter where it passes through the water plane. A shipshape bow is fitted tothe upper end and houses the accommodations, power plant and other equipment, and the controls.
The vessel is towed out to the desired location and upended using its ballast control system. Upending takes approximately 30 minutes, the first 29 being consumed in going from horizontal to 10 degrees of tilt. Once the vessel is upright the instrument booms are extended and the testprogram started. Operating draft is about 270 feet.
Although Flip on occasion has been tethered to the sea floor, it is more commonly allowed to drift in the ocean currents. When the program is complete the ballasting operationis reversed and Flip is towed back to port.
In the early sixties Nippon Telegraph installed a Spar off the coast of Japan to carry a microwave relay station. This Spar is445 feet long with a stepped hull ranging in diameter from 10 feet to 20 feet. The topside structure is a cylinder, 50 feet in diameter by 33 feet high, with equipment, accommodations and a heliport on top. A four point catenary mooring of 3 inch chain connected to 175 ton clump weights keeps the Spar in place. Operating draft is 330 feet.
In the mid seventies Shell installed an oil storage and oftloading Spar at Brent Field, in the North Sea, which is the largest diameter Spar built to date. The hull is 95 feet in diameter, necks down to 55 feet at the water plane, and the operating draft is 357 feet. This Spar was designed to store300,000 barrels of produced crude and to transfer it to bow loading tankers. The mooring system consists of 6 lines, each made up of a 1000 ton concrete gravity anchor, 2600 ft. of 3.5" wire rope, and 935 ft. of 4" chain.
The Hibernia Platform: A New Topsides Structural Concept
Authors: Hewlett D. , Hatcher S.J. , Alner K. 
Published: October 2008

Abstract
The Hibernia Platform uses a new deck structural concept based on the integration of very large modules, i.e. "Super Modules", to form a single primary deck support structure. The paper describes the structural concept, and how it was designed and constructed.
The new concept was advanced from the initial idea to a fully developed design, the Super Modules constructed, transported around the world to the assembly site in Canada, and finally assembled into one structure.
The design effectively makes use of the structural steel frame of the individual nodules to act as the overall deck support structure, thereby eliminating the need for a separate module support frame. Because the modules are the full height of the deck, module lifting operations were nor required, and hook-up work was kept to a minimum.
Extra light strength steel was used extensively for the Primary structure which resulted in significant cost and weight savings.
The feasibility of integrating very large modules using multi-wheeled trailers was demonstrated. Tight dimensional control was essential to a successful integration.
The Super Module deck concept is applicable to other Platforms where minimizing cost and topsides weight is important for the installation and operating phases.

Concept Development
The Hibernia Topsides structure was initially conceived to be similar to several other GBS platforms such as Statfjord "B" and "C". These platforms have an open truss type module support frame(M SF) about 19 meters deep supporting one layer of individual modules. The modules were designed as separate structures for lifting and for the operating phase. In 1986 the first detailed study of the Hibernia Topsides was performed b y Stone and Webster Canada Limited 1. One of the restraints put on the design at that time was that the Topsides should not extend out beyond the perimeter of the GBS so that any icebergs that hit the GBS would be highly unlikely to damage the Topsides. This resulted in a very tall Topsides with multiple levels of individual modules. The final arrangement arrived at required 25 modules weighing up to 2200 tonnes, which the limit of most semi-submersible crane vessels (SSCV's) at that time, for the height and reach required.
Mobil. the Hibernia operator at that time, decided to further study the Topsides configuration to reduce the cost and weight and in 1987 Aker Engineering a .s. of Oslo, Norway were asked to see what alternative approaches were possible. In the first phase of their study, they retained the original concept of a MSF but proposed to use fewer, larger modules which achieved significant cost savings. However, in the second stage of their study they proposed a completely new concept that departed from the MSF concept. Aker proposed that there would be only five "Super Modules" which would be the full height and width of the deck. By joining the individual nodules side by side, an overall primary deck structure 30 meters deep was achieved.
The Glas Dowr FPSO Project
Authors: Lane John A. 
Published: October 2008

SYNOPSIS
The Glas Dowr FPSO paper describes a modern "Fast Track" Bluewater Project that began in December 1995 and will be completed with "First Oi/" targeted in May 1997. The Glas Dowr was "Converted and Outfitted" for installation in the Amerada Hess (AHL) Durward & Dauntless Field, UK Central Sector of the North Sea. The Glas Dowr, which is Cornish for Bluewater, commenced life in a Japanese shipyard, before sailing 14,000 nautical miles to Harland & Wolff (H&W) in Belfast for the Project Conversion Phase. The Glas Dowr project continued with the sea tow from Belfast to the Tees Offshore Base for the Outfitting Phase of the project, this covered the installation and integration of the Pre- Assembled Units (PAU's) with the Ship Marine and Utility Systems. From Tees Offshore Base, the FPSO will be towed to the North Sea Durward & Dauntless Field, UK Blocks 21/16 and 21/11 for installation and hook up to the pre installed anchors, Subsea wellheads and manifolds. The paper describes the project strategy adopted, the Operations influenceon the project plus a description of the Self Verification process to obtain the necessary Certification for North Sea FPSO duties.
The names Durward and Dauntless are derived from the classic novels of Sir Walter Scott. Dauntless was the epithet applied to Harold, son of a Danish Viking, whowas granted land between the Wear and the Tyne. The Quentin Durward novel chronicles the activities of a young Scott who enlists in the Corps of Scottish Archers in 15th century France.

1. Introduction to the Field
The Durward and Dauntless Fields are located in the Central North Sea in water depths of 90 metres, approximately 140 Km east of Aberdeen. The Durwardand Dauntless reservoirs were discovered in 1993 and 1994 respectively, the distance between the two fields being 7.5 Km. Amerada is the Operator of both the fields. The Glas Dowr is located between the two fields in the pipeline corridor, at approximately 4.3 Km from the Durward Field, north of the Fulmar pipeline. The Glas Dowr is anchored to the sea bed using a combination of chains, wires and anchors set in a triangular configuration with nine anchors in groups of three spaced 120 degrees apart.
The subsea wells are tied back to the FPSO through a series of subsea manifolds, pipelines, riser bases and riser systems connecting into the turret. A combined subsea production and water injection manifold is located at the Dauntless Field and a separate water injection and production manifold is located at the Durward Field.
The Subsea Control System is an Electro-Hydraulic System combining Field Bus communications and electronic technology with an established high pressure hydraulic system designed to provide control and monitoring of Subsea wellheads and manifolds. Theinitial control requirement is for 7 wells, 5 producing wells and 2 water injection wells. The system is designed for the future control of 45 wells.
Effluent Discharge Limits and How Have They Been Met
Authors: Twijnstra Seppo 
Published: October 2008

Abstract
Introduction. This paper covers a brief description of the Troll field off and on-shore process facilities and the design facilities required to meet the effluent discharge limitations.
Gas from the reservoir, at a design rate of 100 × 106 Sm3/d, enters the four gas-liquid separation trains at theplatform. In the separators a three phase separation takes place between the gas, the condensed water and the liquid hydrocarbons. The aqueous phase is cleaned in the Oily Water Treatment facilities before it is discharged to sea. The hydrocarbon condensate is re-injected into the main gas stream for further stabilisation on-shore. The total fluid is transported through two 36" carbon steel pipelines to the onshore processing facilities. To avoid hydrate formation and excessive corrosion in the transport lines, caused by the equilibrium water and CO2 from the gas, Mono Ethylene Glycol (MEG), which is regenerated at the on-shore plant, is injected into the two gas transport pipelines to shore.
Gas and liquids from the two wet gas pipelines arrive at the on-shore plant in two slug catchers at a pressure of approximately 95 bar and a temperature of 3°c. Gas from theslug catchers is discharged to three identical gas conditioning trains, where it is treated to sales gas specification by a cooling process and compressed by means of five export compressor trains for further transport into the Zeepipe and Statpipe export systems. Glycol, with a concentration of 75 wt % is injected in the gas processing trains to prevent hydrate formation.
The liquids (hydrocarbon condensate and glycol) from the slug catchers mixed with the glycol and hydrocarbon condensate from the gas trains are separated in a glycolcondensate separator. Hydrocarbon condensate from this separator is further processed to sales specification in acondensate stabilisation unit. From the stabiliser the condensate is pumped into the condensate export pipeline to the Norske Hydro oil terminal at Sture. Flash gas which isgenerated at the different stages of the condensate treatment facilities is recovered and recycled into the gas processing trains. The glycol is regenerated to 90 wt % in three identicalglycol regeneration units before it is recycled to the platform for re-injection into the wet gas pipelines. The water from the re-boilers in the glycol regeneration units is sent to the oilywater treatment facilities for further treatment before being discharged to sea (fig. 1).

Effluent discharge limits
Emission objectives. The design for the Troll on-shore plant and off-shore platform had to fulfill the discharge limitations as imposed by the Project for hydrocarbon emission to air andhydrocarbon and glycol emissions to sea. These limitations meant that the hydrocarbon emissions to air, under normal operation, had to be restricted to an absolute minimum for both the platform and the on-shore facilities. Only those off gases which technically could not be re-routed to the process and /or were not suitable for reprocessing were allowed to be flared or vented.
Some Challenges and Innovations for Deepwater Developments
Authors: Salama Mamdouh M. 
Published: October 2008

Abstract
As the oil industry continues its effort to exploit oil and gas reservoirs in deeper waters, new technologies are required to enable the industry to proceed with effective exploration and development programs under the pressure of low oil prices. Threfore serious efforts are being devoted toward the evaluation and the application of innovative approaches to reduce exploration, development, and operating cost. These innovations involve advances in floating production concepts, expanded use of subsea completions, application of composite materials and optimization of life cycle cost. This paper reviews the different concepts that are currently being considered for deepwater development and summarizes the current effort to develop cost effective composites for many critical deepwater applications. In addition, the paper discusses existing technical barriers that need to be recognized and addressed to satisfy the economic and performance requirements for the application of composite materials.

Introduction
The interest in exploration and development of reserves in deepwater has greatly increased because of the positive views, as demonstrated by Shell's Auger field, that large reserves and high productivity wells can be found. This interest can be illustrated by the success of the recent Central Gulf of Mexico Oil and Gas Lease Sale No. 157, April 24, 1996, during which more than 380 leases in water depth between 2500 and 10.000 feet were awarded. This can also be illustrated by comparing the deepwater leasing activities in the Gulf of Mexico for the last three years. While in 1994 less than % million acres were leased in water depth above 1000 A, the area leased in 1 995 and 1 996 were about 2.4 and 4.8 million acres, respectively. In addition, there is a great interest in accelerating the development of the known deepwater discoveries. In the Gulf' of Mexico alone, there are more than 15 known discoveries in water depth between 3000 and 7500 feet. Deepwater activities in other parts of the world such as the North Sea, Brazil, West Africa. Australia, China, and Vietnam are also expanding.
The ability to economically explore and develop these deepwater leases depends on the oil industry's capability to develop solutions based on the innovative application of technology. These innovations cover broad areas that include exploration, drilling, development, reservoir management, and operations. The development and application of new concepts for structural, equipment and materials have greatly been advanced during the last decade. This paper reviews the different concepts that are currently being considered of a deepwater development and summarizes the current effort to expand the use of cost effective composites for many critical deepwater applications.
The Pompano Subsea Inspection
Authors: Ganguly P. , Goldberg L. , Wood B. 
Published: October 2008

Abstract
During launch preparations for the Pompano deepwater jacket, a horizontal X-brace of the jacket experienced excessive wind induced vortex vibrations. This paper describes the post installation analysis work that was done, provides details of the development and execution of the subsea inspection program that 'was designed to examine the X-brace joints for evidence of fatigue cracks, and furnishes the results of the field experience. In conclusion the paper highlights the deepwater Atmospheric Diving Suit inspection techniques that are currently available in the Gulf of Mexico.

Introduction
The Pompano jacket (Fig. 1) is a four legged bottom founded steel structure which was installed in June, 1994 at the south east comer of Viosca Knoll 989 lease block. The development is owned jointly by British Petroleum Inc. (BPX), and Kerr McGee Corp., and operated by the former.
During the fabrication of the jacket it was noticed that certain wind conditions excited the horizontal cross brace on elevation B between elevations -345 ft and -520 ft (below the mean water level). This was attributed to wind vortex induced vibration (VIV), and a supplementary member was connected to the center of the panel to control out of plane vibrations and prevent fatigue damage. The brace geometry and relevant member size and material data are shown in Fig. 2. The panel was restrained throughout the construction and transportation phases. but it was necessary to remove the tie down approximately twelve hours prior to launch. This caused severe VIV under the prevailing wind conditions with a natural period of about one second, and an estimated response amplitude of twelve inches.
Initial estimates suggested that significant portions of the fatigue life of the joints had been consumed and that cracks may be present in the as installed condition. Results of the initial findings are shown in Table 1. Although visual examinations of the affected X-brace connections using a ROV performed immediately after installing the jacket confirmed the absence of gross discontinuities, it was realized that this type of inspection would not have been able to detect smaller fatigue cracks extending part way through the member wall thickness if such cracks existed. A detailed non destructive examination of the joints was therefore planned.
In view of potential consequences of cracked joints at such an early stage in the life of the platform, it was also proposed to conduct a study to assess the significance of the cracks prior to the detailed examination of the joints. The results of this study would provide appropriate information to effectively react to what might be discovered.