bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation Of Field Dispersant Research Oil Spills
Authors: McAuliffe C.D. 
Published: October 2008

ABSTRACT
Dispersant application to spilled oil in most instances has the greatest chance of minimizing environmental damage, compared with other control methods. Thus, carefully conducted and analyzed research oil spills are the best way to determine dispersant effectiveness.
Of the large number of research oil spills that have been carried out, only a few have shown significant oil dispersion. Oil dispersions exceeding 10- 30% have been shown for some of the API research studies. Good oil dispersions have been discounted by some workers that used incorrect calculation methods.
Dispersed oil concentrations in the water column greatly exceeded those observed for untreated oil slicks in samples at 1, 3, 6 and 9 m (3, 10, 20 and 30 R). These concentrations approximated those expected for measured spill thickness. Such dispersion is a second independent method to show effectiveness.
Improvements can be made in sampling and analyzes of oil in water over those carried out in 1978 and later. Because of the time required for a sampling vessel to traverse even 1.6 or 3.2 m3 (10 or 20 bbl) slicks, sample coverage is unlikely to be increased significantly. However continuous analyzes at multiple depths by fluorometery would increase data along transects.

INTRODUCTION
For oil spills exceeding 160 m3/dayl (1,000 bbl/day), chemical treatment of dispersible oils is the best method of spill control and means of minimizing adverse environmental effects. For oils that are dispersible, the principal reasons are:Rapid response compared to other methodsl,2Prevents or minimizes oil from stranding or entering sensitive biological habitats1,3Greatly reduces oil "stickiness"1,4,5
Because of the importance of prompt use of chemical dispersant to minimize adverse environmental effects, correct evaluation of dispersant effectiveness in research field investigations is essential.
Two field methods of measuring how effective chemical formulations disperse a surface oil slick into the underlying water is to measure the concentrations of oil in the water, or measure the oil remaining on the surface. Several methods have been used for both approaches.
Underwater methods have included taking individual water samples at selected locations within the slick or plume boundaries and at several depths. These samples have been analyzed by various methods such as infrared, ultraviolet, and gas chromatography. Fluorometers and turbidimeters have been used to measure concentrations continuously along transects through the underlying water.
Surface evaluations have included visual observations from aircraft and ships, surface sampling, various types of photography, and other remote sensing instruments such as IR and UV scanners. In the United Kingdom, dispersant are and have been used to control oil spills. The effectiveness has been roughly determined by visual observations and infrared measurements.6
No attempt has been made to review the various techniques, but to concentrate on methods of measuring dispersed oil in the water column.
Ninian Third Party Project: A Unique North Sea Challenge
Authors: Christensen M.L. , Banks R.P. 
Published: October 2008

ABSTRACT
The Ninian Field, operated by Chevron on behalf of the Ninian Field Group, is a mature North Sea producer. Rationalisation of the topside facilities and declining production rates had left spare equipment and capacity in the Platform production systems. This spare capacity coupled with Ninian's strategic location in the Northern North Sea made it an ideal candidate for tie-in of subsea fields.
Staffa, Lyell and Strathspey, operated by Lasmo, Conoco and Texaco respectively, are three such third party subsea developments using Ninian topside facilities.
The Ninian Third Party Project is unique since it is the first offshore development where three third party operated subsea fields are processed by another operator and developed within the same timescale. In addition, major topside modifications were performed while Ninian continued to operate.
Through sharing the lessons learned by Chevron as operator and manager of the Third Party Project, others will benefit in improved efficiency, planning and organisation for similar future endeavors.
The impacts of managing a major project (over 3 million offshore construction manhours) with an existing operations infrastructure, interfaces with Third Party Entrants, safety, productivity and efficiency results are among the issues which will be addressed.

INTRODUCTION
The Ninian Field is located some 110 miles North East of the Shetland Islands within Blocks 3/3 and 3/8 in the area commonly known as the East Shetland Basin. The Ninian Field maintains a strategic position in the Basin.
The field was discovered in February 1974 and began production in December 1978. With an estimated 3 billion barrels of oil in place, the field is expected to recover 1.2 billion barrels of oil producing well into the next century.
The field was developed using three platforms, the giant concrete Ninian Central and the two conventional steel structures of Southern and Northern.
Oil export from Ninian is via a 36" pipeline to the largest terminal in Europe - Sullom Voe located 110 miles away on the main island of the Shetlands. Oil from Ninian Southern is pumped up and over Central through a manifold to the 36" export line. Ninian Central also acts as a hub gathering production from Unocal's Heather Field, BP's Magnus Field and Total's Alwyn North Field.
Since their initial construction, all three platforms have received regular updates to their production systems. On Ninian Southern and Central Platforms the original two train, three vessel production separator systems have been optimised to single train, two vessel operation, leaving redundant production vessels in place. Also on Ninian Southern Platform in response to Ninian's declining production and reduction in associated fuel gas availability the LPG recovery plant was decommissioned.
For these, and other reasons, Ninian Southern and Central Platforms were best suited for host satellite developments.
Springing Damping Of Tension Leg Platforms
Authors: Huse Erling , Utnes Torbjørn 
Published: October 2008

SUMMARY
The present report describes an experimental investigation of the springing damping of a TLP column in calm water, current and waves. The tests were done as motion decay tests with a 1:40 scale model of a single column. In calm water without current the damping was linear at small amplitudes and represented a damping level of about 0.1 percent of critical damping. The most severe current and waves increased the damping by a factor of about 4 compared to calm water. Test results are also presented for the effect of varying radius of curvature at the lower edge of the column. Finally a series of numerical predictions have been done, based on numerical solution of the basic viscous flow equations. The calculations, limited to two-dimensional flow cases, correlate very well with the experiments.

INTRODUCTION
Tension leg platforms are normally designed to have their heave, roll, and pitch resonant frequencies well abovethe frequencies of the wave spectrum. This is in order to prevent first order wave forces from inducing excessive resonant motions in these directions, which could lead to serious fatigue stresses in the tethers. However, due to non-linear wave forces there will be some excitation forces occurring at the sum-frequencies of the components in the wave spectrum. Thus there is still a possibility of significant fatigue stresses in the tethers due to resonant heave, pitch, and roll. The phenomenon is often referred to as "springing" in the tethers.
Present-day theories for second order excitation forces have limitations regarding accuracy. Even more serious is the lack of theory for prediction of the hydrodynamic damping of the very small, high-frequency motions in question.
The investigations described in the present paper were done as part of a joint industry project in 1990 and have been confidential until now.

SCOPE OF PRESENT INVESTIGATION
The main objective of the investigations described in the present report is to provide experimental information on the hydrodynamic springing damping of a TLP column as influenced by the presence of current and waves, and by variation of radius of curvature at the lower edge of the column. A further objective is to show results of numerical calculations of the damping in calm water and compare them with the experiments.

MODEL DESCRIPTION
The experimental investigations were done as model tests with a 1:40 scale model of a TLP column of 25 m diameter and 37.5 m draught. Fig. 1 shows the model dimensions. The model was made of steel. Two versions of the model were tested, the two models having different radius of curvature at the lower edge. One version of the model had its lower edge machined to a sharp corner with radius of curvature less' than 0.1 The second version had a radius curvature of 20 mm, model scale. model was painted to obtain hydraulically smooth surface.
The Mobile Bay Project
Authors: Johnson Harland E. , Kartzke R.J. , Kruger R.M. 
Published: October 2008

ABSTRACT
The discovery of major natural gas reserves underlying State and federal waters in and near Mobile Bay, Alabama, beginning in 1979, led to a number of business and technical challenges that were addressed quite differently by industry operators. This paper describes one operator's overall approach to the preparation and execution of an economic development plan for the production of deep, hot, sour, high pressure gas in a shallow water, environment tally sensitive area. Extensive reservoir modeling, based on limited geophysical, geological, and well test data combined with technical evaluation of a number of development alternatives, led to an eleven well, three field development spread over 61,000 acres, with offshore production collected and dehydrated at three offshore platforms and pipelined to a 300 MCFD onshore treating facility. Production began in late 1993. Unique design and construction features are summarized, and serve as an introduction to a series of papers that cover selected features in more detail.
Location of Leases-Figure 1(Available in full paper)

INTRODUCTION
On October 20, 1993, production began from the first of three offshore sour gas fields comprising Exxon's Mobile Bay Project, culminating a twelve-Year exploration and development effort. Within a few weeks, as the other fields and the onshore treating facility were brought on line, the overall production rate surpassed the nominal 300 MCFD design basis, making it the world's largest offshore sour gas development. The $1 billion, grassroots project will develop over one trillion cubic feet of Norphlet gas reserves off the coast of Alabama.

LOCATION AND LEASEHOLDINGS
The offshore portion of the Mobile Bay Project is located in State of Alabama and adjacent Federal offshore waters, about 30 miles south of the city of Mobile, Alabama, Figure 1. Most of the twelve State and five federal leases, covering 61,000 acres, were acquired in State and federal sales in 1981-84, for lease bonuses totaling $400 million. Except for the State Tract 114 Unit, in which Hunt has a 25% interest, all of the leases are 100% Exxon. Royalties vary from 1/6 on OCS leases to 28% on some State leases. State severance taxes vary from six to eight per cent, and Baldwin County also currently levies an additional one per cent.Discovered in 1983, the unitized Bon Secour Bay (BSB) Field (State Tracts 62, 63, 64, 78 and part of 77), lies inside Mobile Bay, about three to five miles north of the mouth of the Bay.The North Central Gulf (NCG) Field, discovered in 1984, is located on State and federal leases two to six miles south of Fort Morgan peninsula, It is made up of three units: the Block 827 unit (OCS Blocks 827 and 828), the Tract 116 Unit (State Tracts 115 and 11 6), and the Tract 114 Unit (State Tract 114 and part of 113).The Northwest Gulf (NWG) area is three to eight miles south of Dauphin Island. It includes the unitized NWG Field (State Tracts 111, 112, and 131), and the OCS Block 867 Unit (OCS Block 867 and part of 91 1).
Workover Application Of A Spar Buoy Riser In Deep Water
Authors: Valenzuela E.D. 
Published: October 2008

ABSTRACT
A small spar buoy permanently moored by a workover riser is technically and commercially feasible in 3,000 to 6,000 feet of water subjected to the by of Mexico environment. The workover equipment used for wireline and coil tubing operations is located on the deck of the spar using surface tools for re-entry of subsea wells. Fatigue analyses indicate that the spar riser could remain in the field either working and moored to the tree cap base or parked on a temporary location to weather a hurricane.

INTRODUCTION
Good experience has been gained in the use of subsea wireline and coiled tubing operations for subsea applications run horn a MODU or DSV. The daily rate and mobilization and demobilization of these types of vessels is expensive. The purpose of this study is to determine the commercial and technical feasibility of a permanently moored spar buoy that can support the workover equipment required for wireline and coiled tubing operations from the surface. In the case of coiled tubing operations, the injector head and reel package are located on the spar, while all the other related workover equipment, such as pumps, fluids, tanks, cement, nitrogen and safety equipment are located on a tender work boat. By using the injector head and reel package on the spar, motions of the work boat do not affect the workover operation performed from the spar.

APPROACH
The approach of this study is to design and prove feasibility of a small spar that is permanently moored to the bottom of the tree bearing cap base using a rigid steel riser. Figures 1 and 2 show the elevation of the spar riser and the permanent and temporary attachments to the tree. The spar is transferred to the top of the tree to be worked over by the utilization of a winch line on the work boat and also using ROV support.
For wireline operations, the air tugger, wireline reel package and wireline tools are brought aboard the spar when surface wireline is conducted through the riser, All other services that would be required are on board the supply vessel which is moored adjacent to the buoy. Table 1 shows the total weights of the wireline equipment on the spar.
In the case of coiled tubing workover, the coiled tubing reel package, injector head, snubbing units, ginpole, crane and ballast pumps, as well as safety equipment, are brought on board the spar. Table 2 shows the split of equipment weights on the spar and on the work boat.

SPAR RISER CONFIGURATION
The spar riser configuration consists of a spar buoy and a rigid riser. The spar buoy OD is 25-feet and its length is 70 feet. It has a 5-foot moonpool in its center that is used to deploy the steel rigid workover riser designed for 3,000 to 6,000 feet of water. The spar buoy weighs 250 kips in air and has a total displacement of 1.9 million pounds; therefore, the total spar net lift is 1.65 million pounds.
The Development Of A Floating Storage Unit For The Alba Project
Authors: O&apos;Connor J.J. 
Published: October 2008

ABSTRACT
This paper reviews the options that were available for the export of Alba crude oil. It discusses pipe line and offshore loading parameters that led to the selection of a floating storage unit. Field specific requirements were identified and built into the conceptual design.
The regulatory and certification regeme applicable was for the U.K. continental shelf.
The FSU layout, facilities and mooring requirements are reviewed along with the requirements for future growth. The flexible risers are a vital link between sea bed pipelines and the FSU, the selection and sizing of risers and swivels is discussed. The pumping system, tank layout and pipe work is the key to flexibility and production support. The FSU is designed and constructed to provide flexibility for production parameters and provide space and weight-canying capacity for future growth. The shuttle tanker arrangements for the offtake of Alba crude is described along with safety and shutdown systems. The shuttle tanker is dedicated to the field and equiped with bow loading facilities and full dynamic positioning capability.

PROJECT OVERVIEW
The Alba Field, operated by Chevron UK, is located 130 miles north-east of Aberdeen in the UK sector of the North Sea.
Discovered in 1984, it holds recoverable reserves of approximately 370 million barrels of oil and production commenced in January 1994. The development is being progressed in two phases with the first phase involving he installation of a fixed platform in the Northern sector of the field (Alba Northern Platform) in association with a permanently moored Floating Storage Unit. [Figure 1]. (Available in full paper) The FSU is the first purpose-built vessel of its type in the North Sea. Stabilised crude oil stored on the FSU will be pumped, via a hose pipeline from the FSU to tandem moored shuttle tankers using a stem mooring and offloading system. The initial production profile will average 70,000 bbbls oil per day. The second phase will be developed at a later date. [Figure 2]. (Available in full paper)
The FSU is permanently moored approximately 3km from ANP in 138m of water by a Bottom Mounted Internal Turret. The BMIT is anchored by 12 composite chain and wire rope mooring lines with piled anchors designed to secure the FSU for continuous operation in all weather conditions.
The subsea pipelines from ANP are terminated in a pipeline end manifold to which the FSU is connected via a 300mm diameter flexible riser for stablised crude and a 10Omm diameter flexible riser for exporting diesel oil from the FSU to ANP.
Conceptual design of the FSU was carried out by the project team in conjunction with consultants. Basic design, detailed design and construction of the FSU was the responsibility of the shipyard in Ferrol, Spain. The BMIT was designed and procured by the mooring specialist.
Vertical Loads on Drag Embedment Anchors
Authors: Fulton T.M. , Stewart W.P. 
Published: October 2008

ABSTRACT
As industry moves into deeper water and economical solutions for mooring systems are sought, anchor systems capable of withstanding vertical loads are needed. Current industry standards and API recommendations constrain a mooring line to be tangent to the seabed when a drag embedment anchor is used.
This paper shows that current High Holding Power (HHP) anchors such as the Bruce FFTS and Vryhof Stevpris can withstand significant vertical loads, By introducing a mooring line angle at the seabed, the vertical load at the anchor only increases slightly. The technical feasibility and economic benefits of this concept are described. New types of drag embedment anchors specifically designed to withstand vertical loads are also discussed.

DRAG ANCHOR TYPES
Drag anchors can be grouped in many different categories. For simplicity, they are grouped in this paper into three categories: "old" style "low" efficiency anchors (e.g., LWT, Danforth, Stockless, Bruce Cast), High Holding Power (HHP) anchors (e.g., Bruce FFTS, Vryhof Stevpris), and new generation Vertically Loaded Drag Embedment Anchors (VLA) (e.g., Bruce DENLA, Vryhof Stevmanta), see Figures 1 and 2.
The discussion is limited to deeply embedded HHP and VLA anchors in soft cohesive soils. Many of the ideas presented are applicable to anchors in harder soils. It is shown that HHP anchors can resist loading of around 30-40 times their weight, including substantial vertical loads. It is also shown that VIA anchors, after they have been "tripped" or "keyed", can perhaps resist 100-200 times their weight at any angle.

CURRENT DESIGN PRACTICES
Current mooring design practices for drag anchors require the mooring line always to have tangential contact with the seabed. Reference 1 states "If drag anchors are used, the outboard mooring line length should be sufficient to allow the lines to come tangent to the ocean bottom at the anchor when the system reaches the maximum anticipated offset under the damaged condition". Reference 2 includes a very similar statement.
The U.S. Navy"s mooring design manual, Reference 3, states "Drag-embedment anchors are designed to resist horizontal loading. A near-zero angle between the anchor shank and the seafloor (shank angle) is required to assure horizontal loading at the anchor.. .. As the shank angle increases from zero, the vertical load on the anchor increases and the holding power of the anchor decreases". However, one design office in the Department of the Navy typically uses a seabed line angle of 3° as a maximum with no anchor performance reduction.
A recent departure from the traditional no uplift at the seabed approach has been ABS approval of a Floating Production System mooring designed to have a seabed line angle of 3.5° in the damaged condition (one-line damaged -100 year hurricane). ABS stated, however, they would not allow a seabed line angle in the intact condition (no damaged lines -100 year hurricane).