bluuebunny/crossref_metadata_2025 huggingface dataset:
The Gulf Of Mexico Air Quality Study: An Industry Perspective
Authors: Shannon B.E.
Published: October 2008

Section 328 of the Clean Air Act Amendments of 1990 required the EPA to promulgate a rule establishing air pollution control requirements for Outer Continental Shelf (OCS) sources. Congress exempted Gulf of Mexico OCS sources west of 87.5 degrees longitude (near the border of Alabama and Florida) pending the results of a "three year" study conducted by the Department of Interior (DOI) - Minerals Management Service (MMS). The study required an examination of the impacts of emissions from OCS activities in such areas that fail to meet the National Ambient Air Quality Standard (NAA 0S) for either ozone or nitrogen dioxide. This paper reviews the MMS Gulf of Mexico Air Quality Study's (GMA OS) emission inventory development, historical ozone episode modeling, field sampling, and preliminary photochemical modeling results. Industry has developed a standardized spreadsheet to calculate emissions and a software package to allow operators to figure out the cost to control OCS sources for NOX and VOCS under the EPA's OCS Air Regulations (40 CFR Part 55). Cost estimates are provided for various regulatory scenarios currently being reviewed by the EPA and MMS.

CONGRESSIONAL MANDATE

Oil and gas exploration and production operations conducted on the OCS are regulated by the MMS, U.S. Coast Guard (USCG), Environmental Protection Agency (EPA), and the Department of Transportation (DOT). Air emission from OCS sources have historically been regulated by MMS until passage of the Clean Air Act Amendments of 1990 (CAAA)1. Title Ill, Section 328 of the CAAA - Air Pollution from OCS Activities (42 U.S.C. 7627), mandated that EPA develop regulations to control air pollution from OCS sources located offshore the States along the Pacific, Arctic and Atlantic Coasts, and along the United States Gulf Coast off the State of Florida eastward of longitude 87 degrees and 30 minutes. These regulations have been codified at 40 CFR Part 55- Outer Continental Shelf Air Regulations2. For portions of the United States Gulf Coast OCS that are adjacent to the States of Texas, Louisiana, Mississippi, and Alabama, 40 CFR Part 55 does not apply and air pollution regulatory authority remains with MMS3. This congressional exemption, for the central and western Gulf of Mexico, from EPA OCS air regulations was passed pending a MMS research study which will examine the impacts of emissions from OCS activities in such areas that fail to meet the NAAQS for either ozone (O3) or nitrogen dioxide (NOx).

Since Los Angeles, California is the only NOx non-attainment area in the United States the GMAQS will focus on O3 non-attainment areas along the Gulf Coast. The primary and secondary standard for O3 is 0.120 parts per million (ppm) (or 120 parts per billion (ppb))4. An area is designated as non-attainment when one maximum hourly average O3 concentration is above 120 ppb. For the GMAQS these areas include Houston, Texas and its surrounding counties; Beaumont - Port Arthur, Texas; Baton Rouge and Lake Charles, Louisiana, with their surrounding parishes.
Portable, Accurate Toxicity Testing
Authors: Sabaté R.W. , Stiffey A.V. , Dewailly E.L. , Hinds A.A. , Vieaux G.J.
Published: October 2008

Ever tightening environmental regulations, severe penalties for non-compliance, and expensive remediation costs have stimulated development of methods to detect and measure toxins. Most of these methods are bioassays that must be performed in the laboratory; none previously devised has been truly portable. The U.S. Army, through the Small Business Innovative Research program, has developed a hand-held, field deployable unit for testing toxicity of battlefield water supplies. This patented system employs the measurable quenching, in the presence of toxins, of the natural bioluminescence produced by the marine dinoflagellate algaPyrocystis lunula.

The procedure's inventor used it for years to measure toxicity concentrations of chemical warfare agents - actually, their simulants, primarily in the form of pesticides and herbicides - plus assorted toxic reagents, waterbottom samples, drilling fluids, even blood. While the procedure is more precise, cheaper, and faster than most bioassays, until recently it was immobile. Now it is deployable in the field.

The laboratory apparatus has been proven to be sensitive to toxins in concentrations as low as a few parts per billion, repeatable within a variation of 10% or less, and - unlike some other bioassays - effective in turbid or colored media. The laboratory apparatus and the hand-held tester have been calibrated with the EPA protocol that uses the shrimplike Mysidopsis bahia. The test organism tolerates transportation well, but must be rested a few hours at the test site for regeneration of its light producing powers. Development of a freeze-dried reagent, now under way, will make the portable tester even more convenient to use.

Toxicity now can be measured confidently in soils, water columns, discharge points, and many other media in situ. Most significant to the oil industry is that drilling fluids can be monitored continuously on the rig.

BACKGROUND

A quick, precise, novel bioassay that uses the natural bioluminescence of the microscopic marine dinoflagellate Pyrocystis lunula was developed by a U.S. Navy scientist to detect and measure toxicity of, among other substances, chemical warfare agents. This work was conducted with CWA simulants, mostly in the form of commercial herbicides and pesticides. The inventor and associates disclosed the novel method to the scientific community in a 1985 report on the photometer used in the procedure (1) and in a 1986 paper on the detection of trichothecenes (2). The trichothecenes paper described a perfect qualitative correlation (Fig. 1) of the novel test with the Environmental Protection Agency protocol (3) that uses the tiny, shrimplike Mysidopsis bahia for testing drilling fluids toxicity. The novel method was announced to the petroleum industry as a development study in a 1990 Offshore Technology Conference paper (4). This work led to five Navy patents (5), to which a private environmental company has acquired exclusive marketing licenses under the government's technology transfer program..
The Spool Tree: First Application Of A New Subsea Wellhead/Tree Configuration
Authors: Lopez R.H. , Mansell Michael , Stewart A.A.
Published: October 2008

The subsea SpoolTree system (also known as "Horizontal" or "Valveless" tree) features a spool with a wellhead connector below and a wellhead connector profile on top; the tubing hanger is hung off inside the spool; the valves are situated on the side of the spool and there are no valves in the vertical bore of the wellhead/tree system. This configuration requires the well completion to be run after the tree has been installed but it enables the completion to be pulled without the tree being removed. The running tools and accessories required for the SpoolTree are simpler than for a conventional system. A description of the concept as applied for the first time in the Gryphon Field is provided.

The novelty of the concept lies in the configuration of the equipment, not in the technology employed The system offered cost and delivery time advantages, but of prime concern was the safety implication of using this novel equipment, and a comprehensive safety evaluation was carried out.

The safety features of the Gryphon SpoolTree system are described and all 7 safety studies investigating the System from various angles are summarized.

The final section addresses future potential applications of the Concept.

BACKGROUND

When the decision on the Gryphon Field development configuration was taken, around the middle of 1992, it required that the wells would be completed subsea and linked to a FPSO moored nearby (Ref. 1). There would be four different types of well:oil producew,water injectors;an aquifer water supply well;a dual-purpose gas (injection/production) well.

At the time, the option of using pump-assisted dumpflood ('pumpflood') wells to replace the water supply well and the injectors (see Ref.2) was still under consideration. The consequence for the subsea trees would be that types (ii) and (iii) above would be replaced by a tree allowing full-bore access to a 7" completion, designed for facilitating wireline access for the running/retrieval of 7" nominal hydraulic downhole pumps.

At the time of initial enquiry, requirements common to all subsea trees were formulated as follows:The project schedule allowed 9 months from committal date to deliver of the first trees.Simplicity and proven technology should be employed where possible to safeguard the schedule requirements.Safety levels should be at least as good as existing designs.Cost reductions (compared to existing hardware) must be sought.Pressure and temperature levels are not excessive, and standard 5000 psi equipment would be adequate.18 3/4 " wellheads with standard casing configuration would be used, though certain casing strings may be omitted in certain wells.Valves would be operated by direct hydraulic control, both by the Workover Control system as well as by the Production Control System.
Marginal Field Development In Mature Areas Of The North Sea
Authors: Coker J.W.A.
Published: October 2008

In the North Sea a comprehensive infrastructure of production, installations and pipelines have been installed in the last 20 years. As the existing oil and gas fields start to decline, it is cost effective to use the spare capacity on these existing production installations for marginal fields. To ensure economy in the marginal field development the facilities on the outlying fields must be reduced to a minimum. The facilities needed are very dependant on the product being processed and the distance to the existing production installation. However, experience has shown that the modifications necessary on the existing installations can be extensive, difficult to estimate and normally has had significant cost escalation.

This paper will outline the North Sea infrastructure, indicate the types of minimum facilities and installations used on the satellite fields, and briefly discuss the problems with modifications on existing installations.

EXISTING INSTALLATIONS IN THE NORWEGIAN NORTH SEA

The major production installations in the Norwegian North Sea are grouped in five areas;Ekofisk area (Southern North Sea)Sleipner area (Southern North Sea)Frigg area (Mid North Sea)Oseberg (Mid North Sea)Statfjord/Gullfaks area (Northern North Sea).

Most of these areas are connected to a gas pipeline system which either exports to the Continent or Great Britain, Very little gas is used in Norway and therefore nearly 100% is exported. There have been built or are under planning three large diameter pipeline systems to the Continent and two pipelines to Great Britain, the total capacity is over 200 MSm3/Day. Because of the long distance to the Continent the southern pipeline systems used are dry gas systems and therefore the gas can be delivered to the market without further processing. The Frigg systems is a semi dry system with limited processing on land. However, the system from Statfjord/Gullfaks is a wet system, the gas being processed on land in Norway before transfer to the southern gas systems. This gas infrastructure has dictated the process systems required on the platforms located in the different areas.

In the Ekofisk/Sleipner areas the gas system is a dry/sales gas system. Therefore the liquid products are unstable and the N.G.L. products are transported with the oil products to land for further processing, In the Oseberg/Statfjord/Gullfaks area the liquids produced are stabile, therefore the gas export will be a rich gas and must have the N.G.L. removed before transfer to the southern gas systems. Export from the Frigg area is special as the gas from the reservoir is very dry and needs very little processing.

Gas from the fbture Troll field will be transported untreated to Norway for processing before transfer to the dry export system. This project is the largest example of mukiphase flow over long distances and deep water in the Norwegian North Sea.
Investigation Into Scale Effects On Motions And Mooring Forces Of A Turret-Moored Tanker
Authors: Withers Johan , Dercksen Albert
Published: October 2008

A loaded 200 kDWT tanker moored by means of an internal bow-turret is exposed to survival conditions (colinearly directed irregular waves and wind). The water depth amounts to 82.5 m and the turret mooring system consists of 6 equally spaced chains.

By means of time-domain computations of the coupled chain-mooring-tanker system the wave frequency (WF) and low frequency (LF) turret motions and chain/turret forces are simultaneously determined.

The model tests were carried out on scale 82.5. The results of the computations are compared with the results of the model tests using the wave registration as calibrated in the basin. The comparison required the modelling of some additional damping which is expected to originate from small sway and yaw motions which were measured during the model test.

Investigations on scale effects in the resistance coefficients of the hull in surge direction are presented. Finally the sensitivity to changes in the values of the drag and inertia coefficients of the chains on the mooring loads in the chains and turret construction is given.

INTRODUCTION

A moored tanker exposed to irregular head seas performs small amplitude WF pitch, heave and surge motions and relatively large amplitude low frequency surge motions around a mean surge displacement. The mean surge displacement is caused by the mean wave drift force and the steady wind force. The low frequency surge motions are due to the low frequency part of the second order wave drift forces. Since the total damping of the low frequency motions is small, and in irregular head seas the frequency of the slowly varying forces corresponds to the natural surge frequency of the system, resonance occurs. Large low frequency surge motions and consequently large mooring forces may be the result.

For the design of the mooring system, the large amplitude motions and the corresponding forces are required and it is therefore of prime importance to have knowledge about the low frequency excitation and reaction forces. The excitation and reaction forces as acting on a chain-turret moored tanker are given below:velocity dependent wave drift forces (including wave drift damping)viscous damping forceswind damping forcesinertia forces due to the virtual mass of the tankerrestoring and damping forces caused by the mooring system.

In order to determine the total restoring and damping forces of the mooring system the wave frequency tanker motions are required too. By means of an integrated computation (mooring-system-tanker) in the time domain, the instantaneous WF and LF restoring and damping forces as acting on the mooring lines and the turret construction will be used as input for the equation of low frequency motion of the tanker at every time interval to solve the new low frequency turret motions and velocities. The contribution of the hydrodynamic damping induced by the mooring chains on the low frequency part of the vessel motions may be considerable as was shown in Refs, [1] and [2](Available in full paper)
Record-Breaking Water Depth For Fixed Concrete Platforms
Authors: Knudsen Arnt , Skjaeveland Helge , Lindseth Severin , Høklie Morten
Published: October 2008

This paper describes the special design and construction aspects of the TROLL Gravity Base Structure (GBS), When installed in 1995 this platform will be the world's tallest offshore concrete structure, situated in the North Sea in a waterdepth of 300 m or 1000 feet, The paper describes design chllenges such as the ringing waveloading phenomenon as well as novel features, such as flexjoint connection to topside and large scale prefabrication.

TROLL FIELD HISTORY

The Troll gas field is located in 300 to 350 meter water in the northern part of the North Sea, some 80 km northeast of Bergen. The Troll gas reservoir, which was discovered in 1979, cover close to 700 square kilometers in Blocks 31/2, 31/3, 31/5 and 31/6. Troll contains a sweet very lean gas and the recoverable gas reserves are estimated to approximately 1250 billion cubic meters (44 TCF), making Troll the largest offshore gas field in Europe.

The Troll field is planned to be developed in three phases; Phase 1, which is gas production mainly from Block 31/6 also often called the Troll East field; Phase II or Troll Oil, which is oil production mainly from Block 31/2 also often called the Troll West field; Phase Ill future gas production from Block 31/3.

Figures and tables at end of paper Norske Shell was in the spring 1986 appointed as the development operator of the Phase I gas development in Troll East and Statoil will subsequently take over as production operator. Other Partners are Norsk Hydro, Saga Petroleum, Elf Aquitaine, Conoco and Total Marine.

Plans were submitted to the Norwegian Parliament in the fall of 1986 to develop the unitized field. The main gas resources from Troll East, will be produced as Phase I whereas the oil and gas reserves from Troll West needed further study to define development options and phasing. Later it is decided that Norsk Hydro shall develop and operate an oil production from a concrete floating unit.

Development concept

Since the field was declared commercial, more than 80 different development concepts have been considered by Norske Shell. The first plans submitted to the Parliament for Troll Phase I offshore development concept was a fully integrated production, drilling and quarters platform supported by a concrete Gravity Base Structure (GBS). Gas would be exported through the Zeepipe and Statpipe/Norpipe transportation systems to the continent and condensate was assumed to be exported to Sture via Oseberg. During the period up to 1989 this plan was worked up to point of progression to detailed engineering. Engineering work concentrated on cost reduction, deferral of expenditures to improve project economics and measures to improve safety and operability.

In the light of new developments in technology, alternative development concepts were then reviewed. In early 1990 it was decided to adopt the onshore processing concept as the preferred alternative for development of Troll Phase 1 gas.
Jackup Canti-Leg: An Extended Reach System
Authors: Childers M.A. , Song K.K.
Published: October 2008

The requirement to drill, work over, recomplete, deepen, redrill or abandon wells on multi-well production platforms has increased and is increasing in the Gulf of Mexico. The conventional solution to do the latter has been to obtain a cantilever jackup, a jackup with a skid off capability, or a platform rig. Most multi-well platforms can accommodate one of the latter tools; however, there are a number of situations in which these approaches are either physically or economically unfeasible. Platform rigs require a lot of space, are heavy, require high mob and demob cost with long rig up (R/U) and rig down (R/D) times. Waiting on weather for loading is not uncommon. Platform production shut-in is required while R/U, R/D and maybe for the entire time if critical production equipment must be moved to make space for the rig. Jackup rigs spud canholes in the wrong place, pipeline(s), platforms with structural or equipment obstructions, well clusters that are out of reach of the cantilever extension, or the requirement to cantilever to the extreme with severely reduced set-back and hook loads may inhibit their effectiveness. Jackup skid-off rigs take platform space which mayor may not be available, requires long R/U and R/D times, and required production shut-in during R/U and R/D. The use of "macaroni" or platform self erecting rigs with small hook load capabilities (200,000-300,000 Ibs) have been tried many times with limited success when the latter options were unacceptable. In essence, reserves are being left in the ground due to a lack of equipment capability.

The "canti-leg" jackup, an abbreviated name for cantilever-leg, is a portable, self erecting, compact structural support system that can be used with most cantilevered jackups main cantilever beams. It converts the cantilever beams into simply supported beams, which result in full rated hook, set back, etc., loads at up to 70 foot and in some cases 90 foot extension. The relative motion between the production platform and jackup is absorbed via a bearing assembly that is mounted on the "A" frame support sitting on the platform. The canti-Ieg is an attractive and economic alternative to reach wells on multi-well platforms that were uneconomic and/or impractical with other methods.

NEED AND REQUIREMENT

When jackup drilling rig designs evolved during the 1950's and 60's, a slot was placed at the aft end of the rig in which the well being drilled would fit. The first rigs had a rather small slot in which one, two or possibly three wells could be drilled on close spacing. This was accomplished by the rig being stationary and the crown block or the substructure being skidded port or starboard as well as forward or aft. As time evolved, the slots became bigger of which the standard is now approximately 50' × 50'.
Subsea Flexible Pipeline Burial Using A Lightweight Pipeline Trencher
Authors: Dansette Nicholas , Robertson N.C.
Published: October 2008

During 1993 a flexible, lightweight flexible pipeline trencher successfully trencher over 140 km of pipeline to 1.5 meter burial depth. This paper provides an overview of the system with emphasis on specific operational results with specific contracts. Results covered will be amount and depth buried, soil bottom changes, burial speed, remedial work, backfilling, and operational factors/limitations encountered.

INTRODUCTION

Flexjet I was designed and fabricated in the first six months of 1992 with the goal of providing operational results at the end of 1992 to allow preparation for the 1993 operational season. The trenching system and overall concept design was a cooperative effort between Coflexip and Perry Tritech Inc. The concept goal, and final result, was to provide a lightweight pipeline trenching system based around proven Perry Tritech ROV products and systems incorporating Coflexip experience in pipeline burial.

FLEXJET GENERAL OVERVIEW

The Flexjet is a free flying, lightweight (12 tonne) pipeline burial vehicle that incorporates standard TRITON? systems technology. The 400 HP water jetting system is electrically and hydraulically controlled by a 100 HP TRITON? ROV which is located in the center of the Flexjet vehicle. The Flexjet has a set of tracks that are used during burial operations and general bottom crawling. When transiting to the operational area on the seabottom the Flexjet is neutrally buoyant and "flies" as a standard ROV. Once on the seabottom the vehicle can be ballasted down by bringing onboard 1.5 tonnes of water with the Variable Ballast System (VBS). At any time the vehicle may be deballasted and flown again as a standard ROV. Transition from neutral buoyancy to full ballast (or deballast) is about 20 minutes. The 1.5 tonne ballast load during crawling allows a 1.0 tonne draw bar pull of the Flexjet.

Trenching results are obtained with 400 total horse power of jetting power split between high pressure and low pressure jetting systems.

The high pressure jetting system consists of 2 X 125 HP pump/motor sets. The high pressure jet on the trenching arms face forward into the direction of Flexjet travel and are used to cut or fluidise the soil. Each 125 HP assembly produces 6,623 LPM at 8.5 bar.

The low pressure clearing jet systems consists of 2 X 75 HP motor/pump assemblies. The low pressure jets on the trenching arms face aft and are used to clear the fluidised soil from the trench as it is fluidised by the high pressure jets. Each 75 HP assembly produces 13,247 LPM at 1.7 bar.

Several sets are trenching and backfilling arms are available with the Flexjet system. This array of rapid change arms are:0.5 meter burial arm set1.0 meter burial arm set1.5 meter burial arm set2.0 meter burial arm setTwo types of backfilling arms

All arms are flange mounted and can be changed on deck in 30-40 minutes.
Design And Installation Of Auger Steel Catenary Risers
Authors: Phifer E.H. , Kopp Frans , Swanson R.C. , Allen D.W. , Langner C.G.
Published: October 2008

The Auger export pipelines are connected to the TLP by steel catenary risers (SCRs). This is believed to be theftrst time steel pipe has been used for catenary risers. SCRs offer advantages over tensioned risers, since SCRs need no heave compensation and no subsea connections, and over risers made of "flexible pipe", since SCRs are much less expensive. However, significant design effort was required to prove that the SCRs could safely withstand environmental loads and the effects of TLP motions. The design effort consisted of extensive dynamic analyses as well as full scale fatigue testing of both the riser joint welds and the flexible joint that connects the riser to the TLP pontoon. Devices which suppress vortex induced vibrations were also tested. SCR installation is accomplished by lowering the riser on the abandonment and recovery cable from the J-Lay installation vessel and transferring the riser on a chain that is run through a chain jack hung from the TLP upper deck structure. A special Installation and Maintenance System was built for this purpose.

INTRODUCTION

Oil and gas export pipelines are connected to Shell's Auger Tension Leg Platform (TLP) by steel catenary risers (SCRs). Each SCR is essentially an extension of the pipeline [1], suspended in a near-catenary shape from a TLP pontoon to the seafloor. See Figure 1. The SCRs are composed of steel pipe sections welded end-to-end, terminating at a flexible joint which is supported by a receptacle mounted on the pontoon. Piping is routed from the deck down a TLP column and along the pontoon, where there is a flange connection to the top of thei1exible joint. This is believed to be the first application of steel pipe for catenary risers.

SCRs offer advantages over risers made of "flexible pipe" since SCRs are much less expensive. SCRs also offer advantages over top tensioned risers since SCRs need no heave compensation, no subsea connections, and no flexible jumpers to transition to fixed piping at the production deck. For some applications a disadvantage of catenary risers compared to top tensioned risers is the length of active footprint on the seafloor, but this is not the case for Auger.

Each SCR has an outside diameter of 12.75 inches and a wall thickness of 0.688 inch. The pipe material is API 5LX-52. The entire riser has a triple coat epoxy/polyethylene coating for corrosion protection and high abrasion resistance in the touchdown area. The upper 500 feet has a 0.5-inch thick neoprene coating for additional protection and marine growth prevention, plus triple-start helical strakes for suppression of vortex induced ibration (VIV). The flexible joint provides a rotation capacity for the upper end of the riser of ±14 degrees from the installed orientation of the riser, which is 11 degrees from vertical. See Figure 2. The maximum operating pressure is 2160 psi and the maximum operating temperature is 100 degrees F.
Design, Fabrication, And Loadout Of Auger Hull
Authors: Luyties W.H. , Balint S.W. , Smith P.L. , Pellegrini Umberto , Chianis J.W.
Published: October 2008

The Auger Tension Leg Platform (W) hull is a 73,000 st displacement structure weighing 21,500 st. It consists of four stiffened cylindrical columns connected by four stiffened rectangular pontoons and operates at a mean draft of 94 ft. The structure was designed for in-place conditions using both time domain analyses to capture non-linear wave load effects and linearized frequency domain analyses. Extensive use was made of finite element analyses (FEA) to design structural components. The hull was fabricated by Belleli S.p.A. in Italy on Iandskidways, Ioaded onto two submersible barges, and floated off in preparation for a wet transport across the Atlantic Ocean. Throughout the fabrication, Shell and Belleli engineers and site construction personnel worked closely together to insure that the final product was a cost effective and fit-for-purpose structure. As a result of the work performed on the Auger hull a number of important lessons were learned that will be applicable to the next TLP hull and should result in an even more cost effective structure.

Design

Configuration

The Auger TLP hull is a 73,000 st displacement structure supporting an operating payload of 17,800 st, including deck steel, topsides facilities, and riser tension, and tendon pretension of 12,000 st. It consists of four cylindrical columns connected by four rectangular pontoons and is held on location by 12 tendons and 8 mooring lines. The columns are 74 ft in diameter, stiffened longitudinally and circumferentially, with a 34 ft diameter inner shell, stiffened circumferentially. The pontoons are 28 ft tall by 35 ft wide boxes, made up of orthogonally stiffened flat plates. In the short direction the column centerlines are spaced at 214 ft, while in the long direction the spacing is 264 ft. The hull will operate at a nominal draft of 94 ft although an additional 5 ft of draft can be accommodated for possible subsidence due o reservoir compaction. Figure 1 summarizes the principle hull dimensions. The total weight of the hull is approximately 21,500 St.

The hull is subdivided into compartments by horizontal flats in the columns and vertical bulkheads in the columns and pontoons. Pontoon compartments are permanent ballast tanks, as are the perimeter column compartments at pontoon level, All other compartments are void tanks, Compartment size is selected to prevent tendons going slack under the reduced extreme environmental condition (1 year return period hurricane or 10 year winter storm) with compartment damage and compensating ballast to even out the tendon loads, Damage is defined as two compartments flooded at the waterline or one compartment flooded elsewhere, The keel inside the inner shell is protected by a double bottom; consequently, the inner shell compartment is not considered susceptible to damage.

A pumproom is located at the keel inside the inner shell at each column, with a 7 ft diameter access tunnel connecting each pair of pumprooms through the short pontoons.
Response Based Design Conditions in the North Sea: Application of a New Method
Authors: Romans Peter S. , Vandersohuren Luc
Published: October 2008

The estimation of rare, extreme environments from a relatively short oceanographic database is crucial to the calculation of loads and responses of offshore structures. A novel and consistent approach has been developed that makes use of a number of asymptotic properties of extremes. A storm can be adequately characterized by its most probable extreme wave or the resultant structural response. This allows us to treat storms, rather than sea states, as the essential random, independent events; to account correctly for uncertainty in the largest wave and structural response within a storm; and to deal with the uncertainty in the seventy of randomly arriving storms, including the rare storms that are more severe than those in the database. The method provides the long term load statistics essential to reliability analysis and to the calibration of environmental load factors in design codes.

We demonstrate the application of the method to the prediction of extreme waves, loads and "response based" environmental design conditions for a drag dominated structure in the North Sea.

INTRODUCTION

The estimation of extreme waves.

The loads induced by extreme storms are critical in the design of offshore structures for location in severe seas, The load arises References and figures at end of paper from a combination of waves, currents and wind, though waves are generally the dominant factor. The problem of specifying meteorological and oceanographic (met-ocean) design conditions is one of estimating these environmental variables corresponding to some return period, typically 100 years, on the basis of measured or hind cast time series extending over a relatively short period, 5 to 25 years. For the North Sea and some other areas, a widely used approach to obtaining design wave heights has involved fitting cumulative distributions to the significant wave heights of successive three hour sea states[1,2]. U is common to neglect both the correlation between successive sea states and uncertainty in the extreme wave of a sea state. In spite of this, the distributions are used to estimate a 100 year return value. Similar processes are used separately foreach met-ocean variable. The consequent 100 year wind, 100 year wave and 100 year current are conservatively assumed to occur simultaneously and act in the same direction. For a typical jacket structure, this will lead to a "design load" that is much more severe than the "true" 100 year load.
Submarine Gas Hydrate Estimation: Theoretical and Empirical Approaches
Authors: Ginsburg G.D. , Soloviev V.A.
Published: October 2008

The published submarine gas hydrate resource estimates are based on the concepts of their continuous extent over large areas and depth intervals and/or the regionally high hydrate concentrations in sediments. The observational data are in conflict with these concepts. Atpresent such estimates cannot be made to an accuracy etter than an order of magnitude. The amount of methane in shallow subbottom (seepage associated) gas-hydrate accumulations is estimated at 1014m3 STP, and in deep-seated hydrates at 1015 m2, according to observational data. From the genetic standpoint forthe time being gas hydrate potential could be only assessed as far less than 1017m3 because rates of related hydrogeological and geochemical processes have not been adequately studied.

INTRODUCTION

Natural hydrates frequently occur in outer continental margins and deep-water inland seas and lakes covering bout 10% of the total water area. However the estimates of their abundance that have been made are speculative. The published estimates derive from the concepts of their continuous extent over largeareas and depth intervals and/or of the regionally high hydrate concentrations in sediments. Meanwhile, the analysis of the world wide data suggests that submarine hydrates locally occur, largely in accumulations. The aims of this paper are to substantiate the local nature of the submarine gas hydrate distribution and to try to estimate their abundance from the observational data and the geological notions of their formation.

2.REVIEW OF PREVIOUS ESTIMATES

Two recent papers3,4 have presented the overviews of submarine gas hydrate methane content. For brevity we shall consider only the published estimates which are based on the adequately justified underlying data. These estimates4,6 ranging within the limits (1.8-13.91) × 1016 m3 STP have resulted from themultiplication Q = S × h × K × Z × E and relies on three different concepts. One such concept4,6 assumes gas hydrates to occur within the HZ through the sediments relatively enriched with organic, matter (in the papers5,6, Corg > 1%). The range of the obtained values (2.0-13.9) × 10"6 m3 depends mainly on the adopted values of S (1 × 107 to 3.17 × 107km2v) and Z (5 to 10%). Another concept5 deals with seismic records. It was inferred from seismics that in the Beaufort Sea gas hydrates occupy about 75% of the band-like area of 7 × 105 km2 extending along the continental slope at water depths from 400 to 2800 m. They were supposed to completely fill pores of the lowermost 40 m of the HZ where porosity was 30%. As the length of the studied area is 20 times less than the total length of continental margins, Qg was calculated as 20-fold Qr and constituted 1.8 × 1016 m3 The third concept" starts from the fluid migration odel" in which hydrates are precipitated from fluids ascending from under the HZ. According to this model, S (2.3 × 107 km2) includes the area of accretionary prisms and regions of high Cenozoic sedimentation rate, and Z is assumed to be equal 50%.
Hydrostatic Collapse Research In Support Of The Oman India Gas Pipeline
Authors: Stark Peter R. , McKeehan David S.
Published: October 2008

This paper provides a summary of the collapse test program conducted as part of the technical development for the Ultra Deep Oman to India Pipeline.

The paper describes the motivation for conducting the collapse test program, outlines the test objectives and procedures, presents the results obtained, and draws conclusions on the factors affecting collapse resistance.

INTRODUCTION

Oman Oil Company (OOC) is implementing the 1139 km Oman to India Gas Pipeline Project (OIP). The pipeline will cross the Arabian Sea, initiating at Ra's al Jifan in Oman with landfall at Rapar Gadhwali in India, and will encounter a maximum water depth in the Dalrymple Trough of 3525 m, This is over three times deeper than any pipeline yet laid, Fig, 1 shows the principle features of the route.

Likely methods of installation include J-lay and reeling, both of which result in bending strain in the sagbend near the seabed whilst reeling also applies a bend and straightening technique which results in residual ovality after straightening. Tension and bending are known to reduce the collapse resistance of pipe and, during installation, these factors, in combination with a maximum bottom pressure of 35.4 MPa (5135 psi), make the possibility of pipe collapse due to external hydrostatic pressure a major factor in the pipeline design.

Gas throughput requirements necessitate a minimum internal pipeline diameter of 24 inches and, based on existing collapse design theory, preliminary engineering selected a 24-inch ID × 1.625-inch WT (max) grade X-70 material for the pipeline.

To achieve a realistic production rate, the use of UOE pipe is required, however, little or no data is available on the collapse performance nor on the combined effect ofpressure and bending for UOE pipe of this diameter and D/t ratio (17.2).

In order to address these and other issues, and as part of he overall pipeline design verification process, OOC instigated a comprehensive collapse testing program which began in March 1994.

MOTIVATION FOR TESTING

Although a good body of literature exists on the general theory of pipe collapse, specific tests this project for the following reasons:Existing collapse pressure data on large diameter, low D/t UOE pipe is very limited.Data on collapse under combined bending and pressure does not exist for such pipes.The collapse pressure of pipe manufactured by the UOE process has consistently been found to be lower than that of pipe of the same grade produced by different manufacturing processes.There is little data available regarding buckle arrestor performance for this diameter and D/t pipe and it is therefore necessary to validate any buckle arrestor design experimentally.

SCOPE OF TESTING

The test program comprised four parts.

Part 1 involved the straight collapse testing of 20-inch OD × 1.1 25-inch WT, X65 pipe specimens each approximately 4,5m (15ft) in length. Part 2, 3 and 4 tests used 26-inch OD × 1.625-inch WT, X60 pipe specimens approximately 8.8m (29 ft) in length.
DEEPSTAR 902 Cloud Point Round Robin
Authors: Williams T.M. , Santamaria M.M.
Published: October 2008

Wax deposition is a problem in many oil fields and wells. Since wax precipitates and may cause deposition problems when the oil is cooled below its cloud point, an accurate method to determine an oil's cloud point is needed.

Samples of oil from three wells were collected and distributed to ten laboratories. The results indicate that cloud point temperature measurement is not as well defined as expected. The results of this study are discussed in this paper.

INTRODUCTION

The objectives of this project were to:compare methods of measuring cloud point temperatures,explain why methods yield differing results,illustrate data deviation, andrecommend suitable techniques.

At the request of. the Deepstar 900 Study Group, samples of oil from three wells in the Gulf of Mexico were collected and distributed to ten laboratories forcloud point measurements.

Most methods used were able to determine a cloud point within 10°F of the average cloud point determined by all methods. A discussion of the results and the analysismethods used follows.

DISCUSSION

Sample Collection and Dktribution Methods Samples from three wells were collected in new, five gallon cans. Sampling instructions and well conditioning suggestions were shipped to the field with the empty cans.

After the three samples were received by the authors, each sample was immersed in a hot water bath at 150° F. While the samples were being heated, theywere mixed with a 3 blade paddle stirrer connected to a variable speed electric motor. After each sample washeated and mixed, it was pumped from the sample container into 10 different containers for distribution.

Experimental Equipment and Procedure

The three samples were sent to 10 different laboratories for cloud point measurement. Some laboratories used multiple methods to measure the cloud points; therefore, 12 techniques were studied. Three laboratories used DSC techniques and three used viscosity techniques. Though similar techniques were followed, procedures varied and so did results. Short descriptions of the measurement techniques are given below.

Lab 1-Cross Polar Microscopy

A cross-polar microscope was ficatiom A video was used at used at × 125 magnithe temperature stage. The sample was heated to 176 °F and cooled to 140 °F at 1.8 °F/min. It was then cooled from 140 °F to 32°F at 0.18°F/min. Onset of crystallization was recorded asthe cloud point.

Lab 2-Viscometer, Brookfield

The sample was heated to 150°F. The viscosity was measured using a special low viscosity spindle. Cloud point was detected as a change in the slope of the Iog(viscosit y) versus temperature curve.

Lab 3-Cross Polar Microscorpy

A sample was heated in hot water near 130°F in the original container and shaken to ensure no wax was left on the walls of the container. The entire sample was then poured into a 1 liter pressure vessel and heated(under pressure) to 180 °F for one hour to ensure that all of the paraffin was redissolved. After one hour, the temperature was dropped to about 150 °F.
Jacket Launch by Self-Propelled Launch Vessel: A Cost-Effective Method
Authors: Leenaars Cees E.J.
Published: October 2008

During the month of March 1994 the first ever direct jacket launch from a self-propelled semi-submersible heavy-lift vessel was successfully completed.

The successful launch at Bombay High followed direct on the load-out and transportation of jacket and piles from Korea.

Shown is that jacket fabrication in low wage areas can result in substantial cost savings when using the advantages of transportation by a self-propelled launch - vessel.

The special characteristics of a self-propelled launch vessel are discussed.

Limits for the maximum jacket size are given based on the details of the conversion from heavy-lift vessel to launch vessel.

A short report of the actual launch operation at Bombay High is given.

INTRODUCTION

Traditionally the concept of transportation and launch by a tug and barge combination has restricted the range of suitable construction sites because of the required short transportation distances.

The longer the sailing distance for a tug and launch barge combination the more negative the exposure for the project, i.e.:High transportation costs as a result of potential high mobilisation time of the required launch barge;Long transportation time due to relative slow speed and weather sensitivity resulting inschedule uncertaintyHigher risks relating to damage and/or total loss during transportation, which results in higher costs for Marine Cargo Insurance coverage.

The introduction of a self-propelled launch unit opens up a large range of world-wide construction locations, eliminates the above mentioned negative exposures related to longer distances and offers arange of low wage construction areas.

FABRICATION COST SAVINGS

Fabrication cost savings can be obtained when a jacket is fabricated in a low wage area. In Figure 1 is indicated how much can be saved on building a jacket for West Africa in alternativeconstruction areas compared to fabrication in Northern Europe.

(Available In Full Paper)

Shown is that building in Vietnam - Philippines - China region can lead to savings over US$ 15 million.

As the situation on the international market changes continuously, possible savings have to be investigated for each project individually.

Traditionally the mobilisation from low wage areas by tug/barge combinations was thought not to be attractive due to the long distance.

The problems of mobilisation over a long distance by tug/barge areHigh risk; due to less control of the barge by the tow wire,Long transportation time;due to low speed of the barge/tug combination,High accelerations;resulting in extra steel weight of the jacket and the sea fastenings,High insurance costs; as a result of the above disadvantages.

These disadvantages can be avoided by transportation on a self-propelled launch vessel.

CHARACTERISTICS OF A SELF-PROPELLED LAUNCH VESSEL

By using a self-propelled launch vessel above mentioned problems can be captured.