bluuebunny/crossref_metadata_2025 huggingface dataset:
The Troll Olje Subsea Development Concept
Authors: Bakken Christian , Liverud Arne
Published: October 2008

As a part of the Troll Olje Development the Subsea systems will be one of the largest developments to date to be installed. Norsk Hydro 's experience from the previous subsea projects has materialized into the concept for Troll Olje.

All contracts for equipment have been placed and installations will start early 1994 and finish medio 1997.

This paper will describe the subsea system, highlight some technical challenges and elaborate on the contract strategy.

INTRODUCTION

The subsea production system is based on a cluster concept, satellite wells tied back to manifold centres. The manifold centres are tied back to the floating production unit (FPU) via a production riser base. Figure 1 shows the subsea facilities layout and Figures 2 and 3 show it schematically.

The wells of each cluster are connected to a manifold centre via a flexible flowline and an infield Integrated Service Umbilical (ISU). The infield ISU contains control and power functions, a service line and a scale inhibitor line.

Parallel gathering lines and production risers transport produced fluids from the individual manifold centres to the FPU via the production riser base. Each manifold is connected to the production riser base by a main ISU which is connected to the FPU by a riser ISU. These ISUS have the same contents: control and power functions, a service line and a scale inhibitor line.

The only valving on the production riser base is associated with the gas lift system. A single gas lift umbilical riser provides lift gas to the riser base where it is distributed to each production riser.

A gas injection well is located in the southern Oil Province. It receives injection gas via a dedicated flexible injection line/riser from the FPU and is controlled/serviced through an infield ISU from a manifold centre.

A separate riser base is provided for the gas and oil export products. A single oil export riser connects to a steel pipeline which transports the oil to shore, A single gas export riser connects to a steel pipeline which transports the gas to the Troll Phase 1 platform where it will be combined with the Phase 1 gas and pipelined to shore.

SYSTEM DESCRIPTION

General Functional Requirements

The Troll Olje field design production rates are 25,000 Sm3/sd of oil, 40,000 Sm3/sd of water and 65,000 Sm3/sd of total liquids, Production from individual wells may be as high as 6,000 Sm3/sd but rates are expected to average around 3,000 Sm3/sd. Production fluid gas-oil ratio (GOR) will vary between 60 and 300 Sm3/Sm3 but certain wells may be produced as high as 2,000 Sm3/Sm3 in order to maintain gas production.

The reservoir pressure is 159 bara at the datum of 1547 m mean sea level (MSL). The corresponding temperature is 68°C. The flowing wellhead pressures will vary considerably due to decreasing reservoir pressure and the expected wide variation in water cut and GOR. The maximum shutin wellhead pressure is 143 bara.
Buckling Of Pipe And Tubing Constrained Inside Inclined Wells
Authors: Chen Yu Che , Adnan Sarmad Che
Published: October 2008

This paper presents a new approach to predict the buckling behaviors of a drill pipe constraint in an inclined well. The relationship between the MU pipe configuration along the well and the external load applied to the pipe is investigated. Different models of buckling behaviors are verified. Our work is a general approach since several factors such as the gravity and the hole inclination are included in this analysis.

1. INTRODUCTION

Helical buckling is an important parameter for drilling process. The phenomenon of helical buckling was first investigated by Lubinski1,2et al. and led to the well-known helix pitch/force relationship, which was subsequently used by other3. These analyses assumed that the weight of the drill pipes or tubular are negligible compared with externally applied forces. Another important phenomenon for the initiation of the buckling was investigated by Paalay et al.4 and Dawson et al.5 Their analyses showed that a drill pipe will initially deform into a sinusoidal configuration along the low side of the hole. Later on, Chen et al.6,7,8 extended their results and showed that for horizontal holes, the already buckled drill pipe will change its configuration from a sinusoidal wave into a helix as the axial force increased. The axial loads associated the initiation of the sinusoidal and helical forms of the drill pipe are derived and confined experimentally. For these previous research, the drill pipes are either assumed to be weightless or are lying in a horizontal holes where the weight of the drill pipes does not affect the axial load along the pipes.

Our current analysis is based on the work by Cheatham3et al. and Paalay4et al. We consider the influence for the weight of the drill pipe on its configurations and investigate the stability of the drill pipe using energy method9,10We find that gravity influences the buckling of a pipe in two ways. Firstly, the axial component of the weight increases the thrusting force at the bottom of the hole and speeds up the buckling process. On the other hand, the radial component of the weight of the pipe acts as spring constant for an elastic foundation that resists the buckling of the pipe. A general form for the heliea.1pitch-force relation is reached and the transitional behaviors of the pipe between different buckling modes am investigated.

2. PIPESINHORIZOIWALWELLS

INTIATION OF SINUSOIDAL DEFORMATION

The initiation load for a long pipe deforming into a sinusoidal wave in a horizontal well was given by Dawson and Paslay5 based on Paslay and Bogy's4 work. This equation is written as (Mathematical equation) (available in full paper)

For a long pipe, we can set /=L/n½ in Eq. 1 and the critical load is similar to the buckling force for a beam on an elastic foundation9 with the foundation constant k=w/r.
Evaluation Of Field Dispersant Research Oil Spills
Authors: McAuliffe C.D.
Published: October 2008

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

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

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

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

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'Connor J.J.
Published: October 2008

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

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).
Study Of Sweet Corrosion In Horizontal Multiphase, Carbon Steel Pipelines
Authors: Vuppu A.K. , Jepsom W.P.
Published: October 2008

Sweet corrosion in carbon steel pipelines carrying oil-water mixtures has long been a problem in the oil industry. A study to determine the corrosion rates and the type of deposits formed on the pipe surface under such multiphase flow conditions is described. Experiment are performed in a 10.16cm ID flow loop. Full pipe flow and slug flow conditions and the effect of a few inhibitors is studied. Temperatures upto 60C and several pressures, flow rates, oil-water fractions are studied. It is observed that non protective iron carbonate scales are formed below 60C. Iron carbide skeleton which emerges from the carbon steel is detected. Corrosion rates increase with an increase in temperature and carbon dioxide partial pressure and liquid flow rates. With an increase in oil/water fraction, corrosion rates increase upto 60% oil, for the conditions studied. Iron carbonate crystal deposition increases with temperature and pressure. Evidence of bubble collapse and localized corrosion is observed under slug flow conditions.

INTRODUCTION

Corrosion related problems in oil-gas production and processing operations result in millions of dollars each year in down time, lost production and damaged pipelines. With the use of enhanced oil recovery techniques, carbon dioxide corrosion in oil-water pipelines has become common causing much concern in transportation of these multiphase fluids over long distances from remote wells to separation sites. The use of corrosion inhibitors, surfactants and drag reducing agents to reduce the corrosion has met only with partial success. The effectiveness of these corrosion reducing agents depends on the flow regimes existing in the pipeline.

Several workers have studied carbon dioxide corrosion in carbon steel pipelines. However most of the studies were carried out in single phase systems using deionized water, or brine solutions saturated with carbon dioxide. Almost all the previous studies were conducted in rotating cylinder electrode equipment and in autoclaves. Recently some research was conducted in small diameter, single and two phase horizontal pipelines. However the flow mechanisms in small diameter pipelines, i.e. less than 5 cm can be different from those existing in 10 cm and larger diameter pipes. The effects of different flow regimes such as stratified, plug flow and slug flow have not been addressed. Hence, any extrapolation of results from single/two phase small diameter pipelines to multiphase larger diameter ones can lead to grave errors in prediction of corrosion rates.

Green, Johnson and Choi1 have shown the significant effect of the different flow regimes on corrosion rates. In slug flow, the instantaneous corrosion values obtained when a slug passes were at least two orders of magnitude larger than those existing under stratified flow conditions.

Many investigators have studied the chemistry of carbon dioxide corrosion in water and have determined iron carbonate as the main corrosion product.
New Subsea Technology Enhances Safety In Coiled-Tubi Operations During Well Test
Authors: Allred W.R. , Clark J.A.
Published: October 2008

To preserve the safety of the rig when it is necessary to shut-in the well during coiled tubing service operations, the operator must be able to sever or pull the coiled tubing before emergency valve closure can take place. Norman y, because of the time factor, as in the case of a drill ship drive-off condition, pulling the tubing is not a viable option. The operator, therefore, has to depend upon available cutting methods.

Until recently, unless the coiled tubing in use was 1- ¼-inch [3.18 cm] OD × .095 [.241 cm] wall thickness or smaller, the operator had to solely rely on the shear rams of the coiled tubing blowout preventer (BOP) to cut the coiled tubing. Since the method of choice for cutting tubing is with mechanisms that can cut at the safety valve, with the shear ram of the coiled tubing BOP as a secondary safety system, it was apparent that the cutting capabilities of available mechanisms needed enhancement to accommodate the new larger-diameter coiled tubing.

This paper will describe the design and testing of a new 15,000 psi [103.4 1 MPa]-rated ball and seat mechanism that has a 3.O-inch [7.62 cm]-ID and has the capability to cut coiled tubing with OD's as large as 1-½-inches [3.81 cm] and a wall thickness of l/8- inch [.32 cm]. This is an improvement over traditional cutting mechanisms, which only offer 2- ¾-inch [6.99 cm]-ID for 15,000 psi [103.41 MPa]- rated equipment, and a cutting limitation of 1-¼-inch [3.18 cm] OD × .095 [.241 cm] wall thickness coiled tubing.

The increased OD and wall-thickness sizes that can be cut with this ball and seat cutting mechanism provide the operator with a more flexible coiled tubing service program that can enhance operational safety. The mechanism is adaptable to current designs of subsea test trees in use on floaters and drilling ships. Presently, the mechanism is being incorporated into a 15,000 psi [103.41 MPa]-rated safety valve for use on a jackup or land rig (Figure 1) (Available in full paper).

In addition to data from cutting tests performed with the newly-developed ball and seat mechanism, the paper will also address the applicability of this mechanism to new and existing well test safety valve designs.

INTRODUCTION

Since rig safety during a well test is one of the main priorities of the operator, the utilization of a reliable downhole safety valve to insure well control is of major importance. Because of its enhanced safety and flexibility characteristics, the safety valve that is normally used on a floater rig or drillship is the subsea test tree (Figure 2) (Available in full paper). This valve, which is spaced out in the BOP stack on the ocean floor, allows the operator to shut-in the well and unlatch from the test string in the event an emergency situation, such as a drive-off condition on a drillship, occurs.
Optimization Of Hpht Wells: Reducing The Cost Of Design Integrity
Authors: Watkins D.M. , Johnson R.E. , Moe G.R.
Published: October 2008

Optimization of easing and tubing designs for critical wells has become increasingly important for economic reasons. This paper describes an investigation into the relationship between design criteria (minimum acceptable design factors and maximum acceptable number of pipes) and cost. The measurement of design integrity by both design factors and by probability of failure was evaluated with respect to reduction of costs. The results indicate that significant cost reductions, often on the order of 10-20%, are available by optimization of the string design.

INTRODUCTION

Tubular goods represent between 16% to 25% of total well costs 1,2 which amounts to between $3,000,000 and $7,000,000 for a deep, critical well. This provides the opportunity to save millions of dollars per operator per year by optimization of the tubulars so that the casing and tubing in the Well meets design integrity standards without being over-designed.

All designers of casing or tubing make decisions that balance cost against risk. The cost of the casing and tubing string can be reduced to some extent by controlling (operationally) the load on the pipe. Beyond that, the designer is often left to decide what minimum design factors are acceptable based on personal and corporate experience1. In a sense, the designer already considers the perceived probability distribution of the load and of the load resistance of the pipe when selecting an appropriate minimum design factor, yet cannot precisely say how much additional risk is involved in modifying those design factors.

Usually, the rating is some relatively low estimate of the actual load resistance of the pipe and the load is based on a very conservative estimate of the potential load conditions. The resultant design factor's arc used to evaluate a string's design integrity against failure modes: Burst, Collapse, Tension, Compression, and von Mises equivalent (VME) Triaxial Stress. Minimum acceptable design factors are usually greater than 1.0 to account for uncertainty in both load and load resistance.

If the safety factor could be determined, all designs with SF > 1.0 would be acceptable. Since neither the loads nor the load resistance can be known precisely for each point in the string, the chance that SF < 1.0 must be determined in order to estimate a probability of failure (PF).

Lowering the design factors to reduce the cost of the string involves no additional operational expense but does require careful justification. This is the role of PF analysis. Alternatively, increasing the number of pipe sections is a well known but underutilized method of reducing tubular costs. Doing so means that there is less excess load resistance capability along the length of the string. The usual argument against doing this is the additional expenses of maintaining additional categories and tracking the pipe. These expenses are increased in order to lower the risk of mixing the pipe on the rig and inserting a joint or a coupling where its strength will be insufficient.
Fast-Track Flexible Flowline Installation In Mississippi Canyon
Authors: Freet T.G. , Fitzgerald C.W. , Rebello A.
Published: October 2008

Oryx Energy Company has successfully completed the fast track development of three subsea Mississippi Canyon 400 Unit wells in water depths ranging from 1355 feet to 2088 feet. The first well came on line in July 1993, just ten months after project approval, and all three wells were producing within thirteen months of project initiation. Flexible flowlines from each well were tied back to a shallow water platform, resulting in the longest and deepest flexible pipe installation in the Gulf of Mexico to date.

This paper reviews the selection and design of a flexible flowline system for surface connect/layaway from each well and tieback to a host platform covering distances of four to seven miles. The rationale for flowline system selection and actual field experiences of installing flexible pipe with welded connections are discussed. The challenges of coordination and scheduling with the drilling rig, lay barge, and host platform are reviewed. In addition, the inspection and repair of an anchors nagged flexible pipe section is addressed.

FIELD DEVELOPMENT HISTORY

The Mississippi Canyon (MC) 400 Unit is located in the Gulf of Mexico approximately one hundred miles southeast of New Orleans, Louisiana (Figure 1). The Unit consists of Blocks 356, 357, 400, 401, 444, and 445. The Operator became 100% owner of these blocks by acquiring leases, drilling to earn rights, and assuming relinquished ownership interests1.

In 1988, two exploratory wells were drilled in Block 401 (MC 401#1 and 401#2) in water depths of 1355 feet and 1697 feet. The wells were temporarily abandoned pending evaluation and eventual formation of the Unit.

In July 1992, preliminary engineering studies were undertaken to evaluate development options for the Unit. Various scenarios were considered, including well counts ranging from two to five. Concurrent with these studies, an evaluation was performed on the construction of a new platform in MC 357 for the tieback and processing of Unit wells. This evaluation was then compared with tieback opportunities at existing platforms in the area; this was an attractive option because early production could be achieved with lower capital requirements. Negotiations with the platform operator at West Delta (WD) 152 eventually led to a lease space agreement for tieback and production of MC 400 Unit wells.

In October 1992, a project plan was approved to develop three subsea wells in the Unit. The two MC 401 wells were to be completed, while a proposed location in MC 445 would be drilled and completed; all three wells would be tied back to the WD 152 platform (Figure 2).

FLOWLINE SYSTEM SELECTION

During the preliminary engineering phase, one of the first tasks was to perform an initial screening of various flowline scenarios. The objective of the screening evaluation was to focus engineering effort on cases most likely to be recommended, and avoid parallel effort on unlikely scenarios.
Lateral Loading on Piles Due to Slope Instability
Authors: Lupini F. , Chacin M.E. , Furiol A. , Troconis C.M. , Vargas F.
Published: October 2008

This paper presents the Carpet Oil Loading Terminal Case history for which very flat slope instability was esponsible for the failure and structural collapse of seven ooring and/or breasting dolphins, plus the collapse of all Of the intermediate supports of catwalk bridges that rovide access to the dolphins, from or to the loading latforms. These supports collapsed before the dolphinsd as, in the whole, they were much weaker to support ateral thrusts, even though they were strengthened with additional piles, on several occasions. When movement of he dolphinsjrst became apparent, a monitoring program as designed to measure the displacement of the pile caps, Primary cause for failure was the very weak nature of he subsoil, but the triggering mechanism was the need to redge the bottom, further than previously in the past, ecause of the new recent condition of salutation and edimentation and to accommodate larger tankers with nger draughts. Although most of the dolphins failed in a hree year period, the trestles and the loading platformsHave not shown, so far, significant signs of distress.

This paper deals with the site assessment program, with at caused the failures, how the collapse occurred and he conclusions that were drawn during the study. eferencesn, omenclaturea, ndfiguresatendofpaper.

INTRODUCITION

Although Carpet site is not typically offshore the earning's from this case record may be very helpful in xamining other failures such those that have occurred in everal occasions in the Gulf of Mexico, or better in etermining methodologies for the design of offshore tructures that have to be located temporarily or rmanently in soft mud regions elsewhere in the world.

The Caripito Oil Loading Terminal belongs to Lag oven .A. and is located in the north east region of Venezuela, rth of the Orinoco river delta region, as shown in Figure 1.

The facilities consist of two main trestles as shown in igure 2, with two loading platforms (Terminal 2 and rminal 3) and eleven dolphins, numbered 5 to 15, built In 1981-1982. Terminal 1 is a smaller structure for service essels and in all has four dolphins, 1 to 4, built in theSame period. The whole complex is located on the rightiver bank of the San Juan River which, in truth, despite eing located about 70 km up-river horn the sea, behaves ery much like an estuary, with considerable tidal mplification. Tides at sea in the Gulf of Praia seldomReach 2.5 meters while at Carpet Terminal the tidal Fluctuation may reach 4.5 meters. The tide is semidiurnal ith a six hour cycle from low to high tide (MLWS to HWS).

Almost all of the dolphins are located in the slope of the river, except the breasting dolphins 7, 8, 12, 13 which are located near the toe. Because of the high level of salutation nd sedimentation produced after the seventies due to theeforestation process between the late fifties and the sixties, at the river high basin, the terminal area is ermanently dredged to ensure sufficient draught for the vessels.
Development of a New Metocean Design Basis for the NW Shelf of Europe
Authors: Grant C.K. , Dyer R.C. , Leggett I.M.
Published: October 2008

The paper discusses the development of a new metocean design basis for a deep water harsh environment off the NW shelf of Europe. The principal steps taken to achieve this, in an auditable and scientific manner, within the constraints of the available data and short time scale, are described. The industry partnership approach adopted to ensure early acceptance by all the relevant contributors, is outlined.

INTRODUCTION

This paper discusses the development of a new meteorological and oceanographic ("metocean") design basis for the first West of Shetland (WOS) Developmentsquadrant 204 (see Fig. 1). This area is exposed to the fill force of Atlantic storms which together with the water depth and a complex ocean current regime, presentunique challenges.

Location

In the general are the sea bed slopes from the edge of the continental shelf (approx, 200 m), to the bottom of the Fame-Shetland channel, where depths are 1000 m or re. The development location is in a water depth range of 375 m to 850 w with the first field "Foinaven", in 450to 500 m. For comparison the deepest North Sea development in the UK sector is BP's Magnus, in 185 m. ig. 2 demonstrates the differences in metocean designcriteria and illustrates the scale of the engineering challenge.

Data Sources

In the early 1970's, weather ships sponsored by the UK Offshore Operators Association (UKOOA) at "Fitzroy" (60°W, 4°W) measured wind and wave data. These were replaced later in the 70's by weather buoys at the "Foula"location approx. 50 km to the ENE. In the 1980's, dataas collected by the UKOOA data buoy DB3 in Block 206/6. During summer exploratory drilling, oceancurrent measurement campaigns by individual operators are also supported the drilling programmed in the area.

In addition to the measured wind and wave data the North European Storm Study (NESS) provides data from computer models (ref. 1). The NESS dataset contains some 25 years of winter data from 1964 to 1989, and provides output at 30 km intervals over the whole WOS area). Selected grid points and other data source locations are in Fig. 1.

Initial Design and Operational Criteria

Early metocean criteria for Foinaven issued in late 1993, were based on proprietary work carried out for the North West Approaches Group (NWAG) in 1988. NWAG is an ongoing joint industry group, with the objective of exchanging and collecting metocean data for the WOS area. It was formed in 1986 and currently has 13 oil company members (chaired by BP), together with the UKHealth and Safety Executive (HSE).

To reduce the period from discovery to development ("fast-track" project), requires considerable compression of the concept engineering, with design basis development in parallel with reservoir evaluation. The metocean design basis was, therefore, required considerably earlierthan has been traditional practice. A decision on the metoman data gathering was made in late 1993 afterconcept engineering identified the faibility of a floating production development on Foinaven.
An International Company's Gas Strategy In The Far East And Its Related Offshore Operations: A Case History
Authors: Duval B.C. , Beuaue J.M.
Published: October 2008

This exploration and production strategy for gas was first developed in the late 60's when indonesia was rightly perceived as being a country with arge, geologically promising and almost untouched offshore acreage. First oil and later gas, discoveries were made in the Mahakam Delta Basin of Kalimantan, and very large gas fields were developed in response to a fast growing market for LNG, especially in Japan and the Far East Therearfter, a proactive search for opportunities in several countries was started, and this led to a concentration on fields in Thailand and Myanmar that had been already discovered but had not been developed because of specific technical difficulties and/or marketing uncertainties.

The risks and challenges of these projects are discussed, including the replacement of reservesin a mature area (Mahakam), the production of thin, numerous and structurally complicated reservoirs (Bongkot, Thailand), and the resolution of commercial problems (Myanmar), These challenges were successfully dealt with by the application of a combination of modern geo scientific technologies, the integration of separate disciplines and the introduction of cost-reduction measures,

INTRODUCTION

Total (hereinafter called the Company) has put into effect, over a period of the last 20 years, an aggressive strategy for the production of gas in the Far East. For the Company this type of activity had begun at an eelier date in the North Sea, with the discovery, development and production of the Friggfield (in U.K. and Norwegian waters) and in the Middle East with participation in the ADGAS liquefaction project and GASCOS LPG scheme (Abu Dhabi],

Although other gas projects have been launched during recent years in the North Sea (notably theoperated Alwyn-Dunbar complex in the U.K.) and in Argentina, it is in Southeast Asia that the number of developments has grown most spectacularly, to the point that this region of the world, which already figures very significantly in the upstream activity of the Company, will soon become our principal centre of operations and profit.

It seems interesting to describe the birth and development of this strategy with reference to both the planned moves and the events that influencedtheir progress. Each of these projects carried specific risks and challenges, technical or otherwise, and these will be analysed, together with the methodologies and approaches which were adopted to meet these challenges and attain the planned objectives.

The strategy encompassed Indonesia, Thailand, Myanmar and Vietnam, but the latter country will