bluuebunny/crossref_metadata_2025 huggingface dataset:
Reliability-Based Fatigue Design Criteria For Offshore Structures Considering The Effect Of Inspection And Repair
Authors: Moan Torgeir , Hovde G.O. , Blanker A.M.
Published: October 2008

Current fatigue design criteria for offshore structures are based on SN-data and the Miner-Palmgren approach. The acceptable cumulative damage in some codes is made dependent on a vaguely defined feature of accessibility for inspection. This paper presents a reliability based fracture mechanics (FM) calibration of the allowable cumulative damage which depends on the quality of inspection in terms of probability of crack detection curves. Target safety levels are taken to correspond to a cumulative damage of 0.1 and 0.3 with no effect of inspection.

INTRODUCTION

Fatigue and fracture are important failure modes of welded offshore structures. Significant progress has recently been made in developing rational design methods to handle these failure modes, especially by using reliability methods, see e.g. [1].

Fatigue design criteria are commonly based on the SN-Miner- Palmgren approach where the allowable cumulative damage, D = ?n/N1, is made dependent upon the consequences of failure and access for inspection as specified e.g. by NPD [2]. However, existing criteria are qualitative.

The purpose of the present paper is to quantity the effect of inspection depending upon its quality for a given inspection strategy.

Welded joints in TLP tethers and tubular joints of jackets are considered for illustration purposes. This is done by determining the allowable cumulative damage in the SN approach as a function of the quality of inspection. The calibration of this simple design approach is based on a probabilistic fracture mechanics model of fatigue crack growth,

CRACK GROWTH MODEL

The crack growth is described by a generalization of the Paris-Erdogans equation,(Mathematical equation) (available in full paper)

as introduced by Newman & Raju [3]. In this approach the surface crack is assumed to be semielliptical with semiaxes a and c at any stage during crack growth, where a is the crack depth, c is the half crack length, N is the number of stress cycles, ?K is the stress intensity factor range, and C and m are material parameters.

Analysis of the distribution of the material parameter, C, for steels shows C to approximately follow a Iognormal distribution. The crack growth parameters may be reasonably modelled as: C Iognormally distributed with C(I.1 .10−13 [4],0.55), where (,) are the mean, with units N and mm, and the coefficient of variation, respectively. Instead of using C as a random variable, InC is used herein, see Tables 1 and 2. m is assumed fixed and equal to 3.1 [4].

The stress intensity factor range at any point of the crack front for surface cracks in plane plates subjected to tension and bending loads is expressed as [3] (Mathematical equation) (available in full paper) where S1 and Sb are tension and bending stress ranges, respectively. S is the total stress range, t is the plate thickness and W is the width of the plate.
Taut Leg Spread Moorings: A Cost-Effective Stationkeeping Alternative For Deepwater Platforms
Authors: D'Souza R.B. , Dove P.G.S. , Kelly P.J.
Published: October 2008

Spread moored floating production platforms are employed worldwide in the exploitation of offshore hydrocarbons. To date they have all employed catenary spread mooring systems (CSMS) using chain or combination wire/chain components. In water depths to 1500 feet and beyond, such simple wire/chain systems become increasingly inefficient and costly. To improve cost efficiency, tighten watch circles and 10wer vertical load on the platform several innovations have been introduced such as the use of submerged spring buoys (Ref. I), ground wire, and ropes made from synthetic aramid fiber. An aramid rope has yet to be employed in a permanently spread moored production platform as industry awaits a better understanding of the long term behavior of this material (Ref. 2). The installed cost of a deep water (XM remains high despite these innovations and a need exists for even more efficient spread moorings as industry looks to water depths of 3000 feet and beyond. The most promising alternative to the (XM to emerge in recent years is the Taut Leg Spread Mooring (TLSM) system, with short scope legs (Fig. 1) and where vertical uplift on the anchors is permitted (Ref 3, 4). This paper explains the operating principles of a TLSM, its performance sensitivity to variations of key parameters and shows the cost benefit versus a CSM by specific case studies.

FUNDAMENTAL BEHAVIOR EXPLAINED

To develop a cost efficient design, it is essential to understand the basic mechanisms by which a TLSM resists platform mean loads and wave induced motions. The behavior is most easily grasped by studying the simple taut leg system shown in Figure 2. k consists of a light weight, elastic mooring leg in water depth D stretched between the anchor point A and the fairlead point F separated by a horizontal distance L. The anchor point is fixed and resists horizontal and vertical forces.

As the fairlead point translates away from the anchor point in response to an applied mean load, tension is induced in the leg as it stretches elastically between the points. An equilibrium position is attained when the moment created by the horizontal force components (H *D) is balanced by the moment created by the vertical force couple (V*L) between the anchor and fairlead points. As the line slope angle relative to the horizontal decreases, distance L increases requiring a smaller vertical force and therefore smaller line tension to resist a given horizontal force. However, line scope and therefore cost also increases. If horizontal force per unit of line volume is used as a measure of cost efficiency, it can be demonstrated that the most cost efficient line slope of a simple TLSM to resist a horizontal mean load is 450 (scope/depth ratio of 1.414).

In a catenary system, mean offset is controlled by line weight and pretension. Lines composed of materials with lighter weights and with larger pretensions produce.
Structural Aspects Of Snorre Mating
Authors: Aiming A.H. , Muren Jan
Published: October 2008

The deck and the hull of the Snorre TLP were successfully connected South of Stord on the Norwegian westcoast in September 1991. The 28.000 tonnes deck was lifted off its supports by a large launch barge, transported to the ballasted hull and accurately positioned over the columns.

The main challenge of the operation was to control deflections of the hull, deck and barge to obtain the desired load distribution between the 16 hull support stools, 4 on each column top. On each stool the load was taken by an array of deformation tubes. The arrangement of the tubes was decided on the basis of both dynamic and static analysis.

Step by step computer simulations were performed during the operations,, along with measurements of the deflection of the deck, barge and deformation tubes. This enabled full control of the operation and large flexibility when modifications to the original procedures were required.

The mating took place in the autumn with risk of swell. Dynamic analysis of the hull and barge in the mating configuration was performed to decide on the requirement for additional dampers between the column tops and the deck. It was found that friction on the prearranged guides and restraints gave the necessary damping to prevent unacceptable impacts.

The deck was positioned well inside the agreed tolerances of +/- 100 mm. This was achieved due to good preparations, both on the engineering and the construction sides.

INTRODUCTION

Snorre is a four column TLP built for the Snorre Field in the North Sea west of Nofway. The connection of the hull and deck structures took place in Digernessundet south of Stord in September 1991. The total operation was divided in two, the lift-off of the deck from the fabrication site by a barge, and the connection, or mating, of the deck and the hull.

The column diameter of Snorre is 25 meters, while the centere to centre distance of the columns are 76 meters. The column height is 63 meters. The pontoon cross section is 11,5 times 11,5 meters.

The deck fabricator was responsible for the lift-off and mating, while the Main Engineering contractor was responsible for the design of the hull and deck connection points and the structural integrity of the TLP. This involved a detailed arrangements of the deformation tubes, guides and ballast distribution. Key personnel from the detail engineering phase where engaged for following up of the operation. The follow-up team prepared tools and measurement schedules to enable an accurate follow-up and an early identification of possible deviations.

This paper will not describe the marine operations more than what is required to give an understanding of the procedure. The main aspects will be the engineering preparations, and main parameters to control during the operations.

LIFT-OFF OF DECK

The deck was fabricated on 16 fabrication supports, 8 on each side of the dry dock. The supports had the same location relative to the deck as the mating stools on the hull. The barge with grillage was located under the deck at a low water level in the dock.
Concrete Repairs With Corrosion Protection: An Economical Alternative To Platform Replacement
Authors: Sgouros G.E. , Webster T.E. , Hennegan N.M.
Published: October 2008

The combination of structural repairs and galvanic (sacrificial) cathodic protection has extended the service life of an offshore reinforced concrete platform by 10 to 15 years. The 18-year-old structure had suffered severe corrosion-related deterioration because of shortcomings of the original design and exposure to both seawater and high-chloride brine leakage from the waterflood injection facilities.

Several innovative repair techniques were used. The underwater sections of the columns were repaired using preplaced aggregate concrete. Embedded zinc anodes were used to protect the above and underwater portions of the reinforcement in the columns. The deck was repaired using cast-in-place concrete or shotcrete, and its underside was sprayed with metallized zinc for cathodic protection of the reinforcement.

Other reinforced concrete platforms in the Gulf of Mexico have been protected with impressed current cathodic protection1. However, we believe this is the first application of galvanic cathodic protection on an offshore reinforced concrete platform in the Gulf of Mexico. This project proved that properly planned and executed concrete repairs can offer a much faster and economical alternative compared to replacement, even for severely deteriorated structures.

DESCRIPTION AND FUNCTION OF THE WATERFLOOD PLATFORM

The waterflood platform at Main Pass 69, about 20 miles east of Venice, Louisiana, is a concrete barge which was installed in 1972 for Shell Oil Company. The purpose of this facility is to support waterflood equipment which filters and reinjects water into underlying oil-bearing formations to maintain reservoir pressure and help sweep residual oil out of the ground.

An overall view of the concrete barge is shown in Figure 1. The barge has a 45 ft. by 37 ft. deck area which is supported by 24 straight and 8 battered 16 in. diameter columns on a hollow concrete base of 45 ft. by 45 ft. by 12 ft. The vertical clearance between the two decks is 19 ft. 8 in., which was designed to provide 2.7 ft. of air gap during hurricanes. The dead weight of the structure excluding buoyancy was estimated to be 710 kips. The operational weight of the equipment on the deck was estimated to be 210 kips.

The barge was constructed onshore using lightweight cast-in-place concrete, floated to the location and set on the bottom in about 2 ft. of water by flooding the base section. Draft of the barge and deck during tow was estimated to be 6.25 ft. A channel to the site as well as a 65 ft. square area (16 ft. below the mudline) at the site were dredged for the installation. (The dredged area at the site was backfilled with clam shells before lowering the barge.) The final elevation of the barge bottom was 8 ft. below mudline. Four 24 in. diameter 50 ft. long corner pin piles were driven to help secure the barge in place.
Diverless Intervention Ball Valve System
Authors: Steele John
Published: October 2008

This paper describes the application, design, research and development and field data for Diverless Intervention Insert Ball Valve design. With the ever increasing demand to develop subsea oil and gas fields in deeper water, it has become necessary to subdivide the insert valve range into a valve design which is "diver maintainable" and valves with inserts which can only be recovered using remotely operated tool systems. These remotely operated systems have been designated as DIVERLESS INTERVENTION systems.

The innovative design of the Diverless Intervention Ball Valve provides a new dimension in ball valve technology. Specifically designed for topside and subsea piping systems, the new insert design allows ball, seats, stem, trunnion and seals to be self contained in an insert. The unique one piece unit inserts into a valve housing which can be welded or flanged in the pipeline, allowing the field repairable insert to be easily removed from the housing should future maintenance be necessary.

INTRODUCTION

World-wide oil and gas production through necessity is moving towards an increase in the exploration of deep water fields (over 300 metres deep). In conjunction with this and for commercial exploitation of small fields, we can see an increase in subsea tie-ins back to existing production platforms. These changes in subsea exploration necessitate the need for new technology in all aspects of diverless intervention systems. This paper describes and details a very important part of this new technology. The TK Diverless Intervention Ball Valve design is state-of-the-art in valve technology and also a world first.

INSERT DESIGN APPLICATION AND IN SERVICE DATA

Main applications for insert ball valve technology are predominately for subsea systems. An example of applications are as follows:ESDV (Emergency Shutdown Valve) Subsea Template Isolation/Diversion Block Valves for Import/Export Lines.

At this time TK insert valves are in operation in both United Kingdom and Norwegian sectors of the North Sea.

DIVER MAINTAINABLE

A 16"class 1500 metal seated insert ball valve was installed spring 1990 and commissioned autumn 1990. The valve application is emergency shutdown on the main platform gas transfer line between platforms B & A in the Beryl field.

DIVERLESS INTERVENTION

9" class 5000 metal seated insert ball valves were installed summer 1992 commissioned (subsea) autumn 1992. Valve application is isolation/diversion for production templates located in the Loke and Sliepner East fields.

DIVERLESS INTERVENTION APPLICATION - STATFJORD SATELLITE FIELD

Insert ball valves 9 class 5000 will be utilized for (production and injection) templates (Fig. 5) isolation on Statfjord North and East fields (Fig. 9 and 10), in over 300 metres depth of water. Production from both fields is pipelined to the Statfjord "C" platform.

Two valves are installed on each template (Fig. 5) one valve on each template has been designed for hydraulic actuation at a later date.
Computation Of Hydrodynamic Damping Coefficients At Low Keulegan Carpenter Numbers
Authors: Dalton Charles , Sun Xiaohua , Zhang Jianfeng , Zhuang Lixian
Published: October 2008

This paper presents the results of a numerical calculation of the drag coefficient on a circular cylinder in planar oscillatory flow at low Keulegan-Carpenter numbers. This calculation represents the classical hydrodynamic damping problem. The two dimensional time-dependent stream-function/vorticity equations for an incompressible fluid are solved by a finite-difference procedure. The drag coefficient values are determined through an integration of the pressure and shear stress around the surface of the cylinder. The results show that the Stokes-Wang result is duplicated at ? =1035 (? = d2/vT, where d is the cylinder diamter, T is the period of the flow oscillation, and v is the kinematic viscosity of the fluid). For values of ? as high as 130,000, the calculated drag coefficients agree closely with experimental values.

INTRODUCTION

The hydrodynamic damping of moving bodies is important in several areas of offshore engineering. Small amplitude, high frequency oscillations can occur in situations involving marine riser vibrations, the oscillations of the tethers on compliant structures, etc. The prediction of fatigue and the analysis of the dynamic behavior of a moving structure require an understanding of hydrodynamic damping. The accurate prediction of damping is then an important factor in describing platform motions and, therefore, in accomplishing platform design. Our analysis considers damping due to viscous effects on small bodies only; radiation damping will not be considered in this study.

Understanding of the fluid motion generated by a body undergoing sinusoidal oscillations is the first step in determining the hydrodynamic damping. The flow field can be characterized by two of the following parameters: KC =Umax T/d =2?a/d, Re =Umax d/v and ? =Re/KC =d2/uT, where Umax is the maximum oscillatory velocity, T is the period of oscillation, d is the diameter, u is the kinematic viscosity, and a is the amplitude of oscillation. In the above definition, KC is the Keulegan-Carpenter number, Re is the maximum velocity Reynolds number and ? is the frequency parameter. For small KC (KC <  > 1), the drag coefficient can be predicted by the Stokes-Wang law, (Mathematic equation)(available in full paper)

The Stokes-Wang drag coefficient is developed from the Navier-Stokes equations in the absence of the convective terms which were taken to be negligible, an assumption which is applicable only for low values of KC. When KC increases, the convective terms increase in magnitude and the Stokes-Wang law no longer adequately represents the solution. The higher KC problem has no analytical solution; therefore, the force description is based on experimentally determined coefficients. The conventional force description is given by the Morison equation which typically represents the force on a fixed cylinder due to an oscillating fluid. The Morison equation decomposes the instantaneous force into a linear sum the drag and inertia forces.
An Experimental Study Of Tendon/Riser Pairs In Waves
Authors: Duggal A.S. , Niedzwecki J.M.
Published: October 2008

Results from a large-scale experimental study to investigate wave interaction with single and paired flexible cylinders are presented. The cylinders were designed to be representative of TLP risers or tendons in 1006 m (3000 ft) of water. The data from the single cylinder tests illustrates the complex, multi-modal nature of the response. Direct comparison of the experimental data with Morison equation based finite element simulations are presented. Analysis of the paired cylinder data shows the importance of modeling the hydrodynamic interference between the cylinders. The importance of accounting for the non-Gaussian nature of the relative displacement between the cylinders in the prediction of collisions between the cylinders is discussed.

Introduction

With the design and construction of Tension Leg Platforms (TLP) in water depths of 914"3048 m (3000" 10,000 ft), the response of the flexible, tubular members like the tendons and risers become an increasing concern. The tendons and risers are subjected to loading due to waves and currents, as well as the motions of the hull of the platform. These structural members have diameters ranging from about 0.25"1 m (0.83"3.28 ft) and are supported by the tension applied at the top. Structurally, due to their low bending stiffness these members can be thought of as strings. The dynamic behavior of a string is characterized by an infinite number of modes with a modal separation equal to the fist natural frequency. This becomes important as an increase in water depth typically implies a larger number of natural frequencies in the range of excitation. This cam lead to a complicated multi-modal response and is further complicated by the arrangement of these flexible members in groups in close proximity with one another. Due to the presence of the other members, the flow kinematics can be modified leading to modifications of the loading in magnitude, frequency and phase, which then influences the response. For members in close proximity, this complicated response phenomenon can lead to extreme excursions resulting in collisions between the cylinders. This leads to design considerations like how to determine the response of these risers and tendons, and how closely spaced can they be placed before the threat of collisions becomes important. To investigate this phenomenon, a research study into the fundamental and applied aspects of wave interaction with flexible cylinders was undertaken at the Offshore Technology Research Center, Texas A&M University. The study involved a complementary experimental and analytical investigation of regular and random surface wave interaction with a pair of flexible cylinders representative of TLP risers or tendonsin 1006 m(3300 ft) of water (Duggal 1992). The research study was divided into three phases.
Deepwater Subsea Completion: State Of The Art And Future Trends
Authors: Ribeiro O.J.S. , Costa L.A.G.
Published: October 2008

This paper describes the state of the art of deep water subsea completion techniques and equipment, showing the milestones that were reached through the completion of wells placed in water depths beyond 700 m, namely MARLIM 03, 06, 07, 08, and 09 (the latter being the current subsea completion record, in 781 m). It also shows the expertise developed through the design and manufacturing of equipment to operate in water depths up to 1,800 m, as well as the future trends in subsea completion. The First End Vertical Connection, Tubing Packer Hanger, Shear able Riser Joint, Integrated Drilling and Completion Base (BINT), and the future use of centrifugal submersible pumps in subsea wells are some examples of the technical innovations that are currently being introduced.

INTRODUCTION

Since 1984, PETROBRAS' most significant oil finds are located in deep waters, beyond 300m. The Albacora and Marlim fields were followed by the Salema, Bijupira, Barracuda and the 382 Area fields, among others. Motivated by these discoveries, the company has been employing efforts to obtain the technological capability to produce economically and safely the immense reserves already discovered in water depths of up to 2,000 m.

In this search for technological capability stand out the PROC.AP program, the Petrobras Technological Development Program on Deepwater Production Systems. The 6 years program that ended in 1991, allowed a coordinated and integrated action between all the different company's departments, suppliers and R&D Centers at low cost and within the time frame the company demanded.

Deepwater production is a vital issue for Petrobras, because although presently only 8% of the average crude production (650,000 bpd) comes from wells that are located deeper than 400 m of water depth, this figure is expected to reach 61% by 2001 (barring any onshore or shallow water discovery). Furthermore, the deepwater fields account for 66% of total proved and potential hydrocarbons reserves in Brazil.

This paper shows the state of the art of the Deepwater Completion Technology, achieved through the PROCAP or via products jointly developed by the Petrobras' Production Department and its suppliers, as well as the innovations that are that are being currently introduced and the future trends in the area.

STATE OF THE ART

COMPLETION OF THE MARLIM FIELD WELLS

In March, 1991 the 3-MRL-3-RJS well was completed in 721 m water depth with a subsea Christmas tree specially designed for operations with a dynamically positioned (DP) drilling unit without guidelines. The success of the operation, the first in the world at that time, confirmed the technical feasibility of the lay-away operation with DP units and the following items summarize the main achievements:Subsea completion water depth record 721 m (2,365 ft)World's first purpose built guidelineless (GLL) lay-away subsea tree installedFirst well drilled with a DP rig completed in the world
Production Subsea Installations Control And Supervision Electronic Systems Development
Authors: Pinho F. O.J. , Sampaio D.S.
Published: October 2008

This paper intends to present not only a supervision and control subsea electronic system development history in the PETROBRAS Production Department, but also their architecture, basic characteristics and offshore operational results.

The aimed projects are:

MUXCOM: The MUXCOM project, conducted by PETROBRÁS and BRASNOR, a PETROBRÁs affiliate company in Norway, has developed an electro-hydraulic multiplexed control system, which has been installed at Bonito-n production wel1 in Campos Basin, Brazi1, and is under uninterrupted operation since November/1990.

SESCO: As a MUXCOM evolution, it was developed by PETROBRAS a second Supervision and Control Electronic System (SESCO " Sistema EletrÔnico de Supervisao e Controle) for application at "OCTOS-1OOO, a subsea production template-manifold, composed by seven "X-mas trees" and also developed by PETROBRÁS. The communication between the surface unit and the seven subsea units is done trough a two-wire network. The subsea units power supply is done by the communication signal, itself. The system is also able to be integrated to the P1atform Central Supervision and Control Station (ECOS), what permits the OCTOS-1OOOoperation from the rig main control console.

MUXCOM PROJECT

The MUXCOM (Multiplexed Control and Monitoring) projects was part of PETROBRÁS "Deep Water Capability Program"(PROCAP) and its main objective was the identification of critical points and cost allocation of a subsea control system designed to operate at 1000 m water depth. The program should also provide the basis for a control system more suitable for the Brazilian scenario.

Reliability is the most important requirement when dealing with subsea production control systems, but some other points 1ike versatility and cost efficacy are important as well.

The project development was based on wel1 tested standard components with good field records in order to reduce cost and failures risk and, therefore, extensive testing at component 1evel was not required. However, a 1ot of tests were carried out to ensure that al1 of them could work together in the proposed configuration and submitted to 100 bar external pressure.

Special attention was paid to some critical components 1ike hydraulic and electrical connectors and solenoids valves.

MUXCOM'S ELECTRONICS

During the MUXCOM project conceptual development phase, a market survey was carried out to verify the feasibility of introducing a market available electronics into the system and so reducing the cost and time of developing it by ourselves.

It was concluded, after sane inquiries, that there was no electronic package available in the market able to fulfill our requirements and to fit the project budget. It was also considered that the effort that should be spent in order to modify and to adapt the market available electronic system to our application would be almost so high as developing a brand new and dedicated one.

Therefore, it was decided to go into a dedicated electronic system development from scratch.
A Fully Compensated High-Pressure Riser Telescope
Authors: Nergaard Arnfinn , Freyer Jan
Published: October 2008

Riser technology is a key element in the ever increasing number of mobile floating production and subsea well inlervention vessels. When there is a requirement for vertical access though pressurised conduits, the relative motion needs to be catered for by tensioning compensation systems. This paper describes u new approach in which relative motion problems are solved in the riser itself This is achieved through application of a new design telescope that strokes without changing volume or internal pressure. When applying this principle in a production or intervention riser, topside mounted equipment can be fixed on the deck of the floater.

Background

The Petroleum Industry presently faces the challenge of developing smaller fields in deeper waters. In addition we see smaller fields being made commercial by increasing the production over shorter field life. These factors favour developments bused on mobile and/or reusable systems, of which ships and semisubmersibles will represent a major part. The main difference between a fixed and a floating platform is the relative motion between the seabed and the floater.

A point on the floater translates and accelerates along all three axes of freedom relative 10 a point on the seabed. In addition the floater rotates around the same three axes. All connections between the vessel and the seabed need to h designed with this in mind. A floating production system may be based on WC1lSbeing remote or located under the floater. In the latter ease the system is in function comparable to a fully integrated fixed PDQ (Production, Drilling, Quarters) platform. The platform also drills and works over the wells. The basic configuration for this case (when disregarding the Tension Leg Platform (lZP) system) is subsea x-mas trees located on the seabed under the floater. The connections between the vessel and seabed arc generally three main kinds; mooring lines, well extension conduits (production and annulus) and WCI1control lines (electric and hydraulic). See figure I - Basic Floating Production System.

There are two basically different ways to configure risers or connecting lines; a vertical "straight" line or a free-hanging catenary based system. A vertical system needs some sort of compensation to cater for relative motion. For the catenary based systems a number of different configurations have been developed. Examples arc; straight catenarics (anchor lines, flexible risers, control lines), and sleep and lazy S-curve configurations.

The vertical line can be a pure mechanical connection like a guideline that is compensated for motion by a constant tension winch. The basically important and absolutely necessary vertical system is the tieback of the well-bore for well establishment, intervention and maintenance. In that case it is a stiff and rigid connection and it needs to be compensated for motion and tensioned for the weight of the system itself. This applies mainly to drilling risers, workover risers or production risers.
Coiled-Tubing-Deployed Electric Submersible Pumping System
Authors: Lidisky D.J. , Pursell J.C. , Russell W.K. , Dwiggins J.L. , Lidisky Reda , Coburn G.S.
Published: October 2008

The results of what is believed to be the first CT deployed Electric Submersible Pump (ESP) will be presented in this paper. Coiled tubing (CT) has long been used to accommodate many workover operations where a drilling or workover rig is either not available or is cost prohibitive. In many areas, the cost or lack of available rigs to service an ESP has been a limiting factor when considering ESPS for artificial lift. This field example shows the effectiveness of a coiled tubing unit for installing an ESP. The technical considerations addressed when designing a completion are discussed as they relate to a specific field installation. The installation proves the viability of using CT units as a means to utilize ESPS for artificial lift.

INTRODUCTION

CT has been used throughout the world for a variety of workover operations since its introduction in the 1960s. CT is used extensively for a variety of purposes including: logging highly deviated wells, well stimulation, cementing, perforating, drilling and cleaning out fill material. The same economics which drive the use of CT for the above operations, make it an attractive method for deploying ESPS where the cost of a workover rig is prohibitive.CT is a continuous length of tubing coiled onto a large reel which is driven by a portable control unit. An injector feeds the tubing into the well and is also used to pull the tubing out of the well (Fig. 1). The tubing is fed through well control equipment and into the well. CT is currently available in a variety of sizes ranging from 0.75 inch outside diameter (0. D.) (19.1 mm) to 3-1/2 inch O.D. (88.9 mm). Also, yield strengths from 70,000 psi (483 MPa) to 100,000 psi (689 MPa) are available. Most CT is similar to standard N-80 grades of tubing and may be considered for use in environments suitable for N-80 tubing. If extreme corrosion resistance is a requirement for a given completion, other materials such as titanium exist to suit almost any downhole environment.

The ESP system comprises a downhole pump, electric power cable and surface electrical controls. In a typical application, the downhole pump is suspended on a tubing string hung in the wellhead and submerged in the well fluid (Fig. 2). The ESP has the broadest range of any artificial lift method. Pumps are available from 100 bbl/day (18.4 m3/day) up to 95,000 bbl/day (15,100 m3/day). ESPS can produce from depths up to 15,000 feet (4570 meters) in 4- 1/2 inch (114.3 mm) and larger casings. Systems are available to perform in wells with bottom hole temperatures up to 450 deg F (232 deg C).

Because both the CT technology and the ESP technology already existed, only the details of a work window for the purposes of assembling and running ESP equipment had to be designed and built. Also, a procedure for using ESPS and CT together had to be formulated.
Installation Of 27 7/8-In. Coiled-Tubing Tailpipes In Live Gas Wells
Authors: Campbell J.A. , Bayes K.
Published: October 2008

This paper describes a technique for installing 2 7/8" coiled tubing as tailpipe extensions below existing production packers in live gas wells.

Large savings in rig time and deferred production have been made using this technique. Fluid losses to the formation do not occur and no expensive rig time is used in killing or cleaning up the wells as would occur in conventional workovers below existing production packers.

This technique has applications particularly in depleted reservoirs that could be impaired by traditional workover methods.

INTRODUCTION

The Leman gas field was discovered in the early 1960's and has been producing gas from the Rotleigendes sandstone sincel969. (See Figure I.) As cumulative production has increased, reservoir pressures have declined to the point where the formation is no longer able to support a column of fluid, consequently causing problems whenever workovers are attempted which require kill fluid across the perforated interval. These operations can result in large amounts of fluid being lost to the formation, resulting in formation damage and delayed reinstatement of production. In most cases, any tubular change outs or work associated with completions are performed by setting isolation plugs in the existing tailpipes, preventing any associated problems with loss of kill fluids to the producing interval. As production rates have declined, the ability of individual wells to lift out produced fluid has been reduced, resulting in liquids accumulating in the wellbore. Liquid load up in the wellbore has resulted in increased hydrostatic pressure on the reservoir, further reducing the energy available to produce gas.

Over recent years a number of Leman wells have been worked over using a cantilever jack-up rig to remove the original 5½" production string and replace it, typically, with a 3 ½" diameter string to improve production velocities and fluid removal from the wells.

These operations have continued, however, in 1991 it was recognised that to optimise production velocities in the casing sections below the production packers, the existing tailpipes would have to be extended several hundred feet down to the perforated interval.

With the known problem of performing workovers across the perforated interval, it was decided to use wireline to install 2 7/8" tailpipe extensions with the wells still live. It was felt that any technique to install tailpipes would only be financially beneficial if it could be accomplished without introducing kill fluid into the producing formation. The maximum length of tailpipe that could be run on wireline with current techniques was in the order of 50 feet. Post commissioning results have shown that tailpipes of this length did not provide any substantial benefits and it was recognised that the length of the tailpipe would be crucial to maximise the lifting capacity of the produced gas below the production packer.
Design Of Insulated Flowlines For Mobile Bay
Authors: Hoose J.W. , Hazlegrove B.M.
Published: October 2008

Insulated CRA flowlines are used in Mobile Bay for connecting well templates to host processing platforms. This paper describes the design of the flowline insulation system. Design issues for structural integrity are presented. Inlet temperatures of up to 200°F and operating pressures of up to 11,000 psi are accounted for. The flowline system consists of a 4-inch CRA pipe in an 8-inch carbon steel jacket.

INTRODUCTION

Gas reserves in three offshore fields in the Mobile Bay area are being developed; the Bon Secour Bay Field (inside Mobile Bay), the Northwest Gulf Field (south of Dauphin Island), and the North Central Gulf Field (south of Fort Morgan Peninsula). Water depths in the area range from 10 to 50 feet. Insulated subsea flowlines were designed to connect three 8-pile production platforms to seven remote well templates, while a gathering system connects the production platforms to an onshore processing plant in south Mobile County. The primary fluid service is hot, high pressure, sour gas.

The flowline system consists of two fluid conduits, produced gas and dilution water, and an 8 Kv rated electric power cable. Deoxygenated dilution water is pumped from shore to the production platforms and then to the well templates for use in flushing out the wells to dissolve salts. Power is supplied from the production platforms to the well templates. The produced gas flowline design pressure is based on shut-in tubing pressures of 8700 psi for Bon Secour Bay and North Central Gulf Fields and 11,000 psi for Northwest Gulf Field. The design flowline temperature is based on a maximum cooler inlet temperature of 2000 F. The flowline is Insulated to prevent hydrate formation under reduced f10wrates during winter months.

The flowline field arrangement (In Figure 1) includes the following:Bon Secour Bay (BSB) Field Production platform In Alabama State Block 62 connected to a remote well template In Alabama State Block 63 with two (2) gas flowlines, two (2) dilution lines, and one (1) power cable.North Central Gulf (NCG) Field Production platform In Alabama State Block 115 connected to a remote well template In Alabama State Block 114 with one (1) gas flowline, one (1) dilution line, and one (1) power cable.Production platform in Alabama State Block 115 connected to a remote well template in Alabama State Block 827 with one (1) gas flowline, one (1) dilution line, and one (1) power cable.Northwest Gulf (NWG) Field Production platform In Alabama State Block 112 connected to a remote well template In Alabama State Block 112 with one (1) gas flowline, one (1) dilution line, and one (1) power cable.Production platform In Alabama State Block 112 connected to a remote well template In Alabama State Block 868 with one (1) gas flowline, one (1) dilution line, and one (1) power cable.
Investigation Of A North Sea Oil Platform Drill Cuttings Pile
Authors: Hartley J.P. , Watson T.N.
Published: October 2008

A comprehensive study of the drill cuttings pile at N W Hutton was undertaken in August, 1992. Fifty one welIs have been drilled in the field, mainly using mineral oil based drill fluids, with the cuttings discharged to sea.

The cuttings pile was mapped using a 3D side scan sonar system and the periphery was defined by towed side scan sonar and gamma ray spectrometer surveys. The pile was cored by vibrocorer to a maximum depth of 2.35m. The cores were assessed geotechnically and subsampled for physicaI and chemical analyses.

Environmental impact was investigated by grab sampling at 12 stations out to 7500m, Selected on the basis of cuttings distribution.

All surveys and samples were located using a differential global positioning system.

The results are relevant to the corrosion and long-term environmental effects of oily cuttings piles, the remove/leave alone debate, and abandonment planning.

Beneath the platform the pile is 5m high, with a low angle of repose and extending out to about 200m.

The cuttings in the cores were SOJ, with laminations and only minor compaction in deeper layers. The top 1-1.5m resembled freshly discharged material. The cores were sub sampled for hydrocarbon, trace metals and sulphide content and grain size analysis. Metals analyses included identification of metal species to estimate bioavailability and implications of pile disturbance.

Estimates of oil migration within the pile are made from correlation of the chemical analyses results with the drilling history, in particular the change from diesel to low toxicity base oil in 1984.

Strong gradients were found in the faunal data which correlate well with the physical and chemical results. Dense populations of opportunists species were present adjacent to the platform, including a novel molluscan opportunist.

This is the first comprehensive study of an oily cuttings pile and is a contribution to the debate on their long term impact and fate on abandonment.

INTRODUCTION

Oil based drilling fluids (OBM) have been extensively used in the development of North Sea oil and gas reserves to facilitate the drilling of often highly deviated wells through long sections of halite or reactive shales. The discharge to sea of the resultant rock chippings (cuttings) has been permitted by North Sea states, although with progressively more stringent discharge standards.

OBM cuttings tend to be more cohesive than those drilled with water based fluids (WBM) because a proportion of the mud remains adhered to the cuttings surface even after treatment with efficient shale shakers. Unless strong water currents are present (as for example, in the southern North Sea) this cohesive nature results in the majority of cuttings forming a mound beneath and adjacent to the installation. These piles of discharged cuttings have a number of operational implications including hindering jacket inspection and maintenance, increased loading of structural members and enhanced corrosion through sacrificial.
Confirmation Of A Wel ?S Mechanical Integrity
Authors: Bigelow E.L.
Published: October 2008

Environmental protection is a major consideration in developing today's offshore resources. Protecting the natural habitat from pollutants is a significant factor in offshore drilling and production. It is also important that shallow, potable water supplies and other important minerals be protected from contamination beneath the surface. Today, wireline technique scan effectively monitor tubular goods and annular cement to determine their capacity to confine potentially harmful materials. The location of corrosion, pits, splits, and other corrosive effects on the inside or outside of tubular goods can be pinpointed, and the magnitude quantitatively evaluated with acceptable accuracy. A system of sectorial evaluation permits the entire tubular periphery to be accurately evaluated for cement shear and hydraulic bond, and to determine if effective zone isolation is established. Data from several test wells and practical field examples support the effectiveness of the sectored, pad-mounted bond log instrument. Recognition of zone isolation and/or hydraulic cement integrity is virtually 100% accurate with the proper measurements, and pinpointing problem areas in a casing string permits effective remedial action to be taken. When conditions are irreparable, the well can be properly plugged and abandoned.

CASING OVERVIEW

Steel casing is manufactured by means of two successive processes that convert an iron oxide to an iron and steel alloy. A blast furnace initially transforms the iron ore to molten pig iron, a solution of carbon, iron, silicon, phosphorous and sulfur. The pig iron is then refined by a steelmaking process to reduce the high concentrations of unwanted elements to acceptable levels, steel being the end product. Steel is formed into casing and other tubular goods at a pipe mill. The heat energy used to convert iron ore to steel is ironically the cause of corrosion of steel casing in a wellbore (Fig. l).l

CEMENT OVERVIEW

During well cementing operations, a cement slurry is pumped downhole through the casing and back up the annular space between pipe and borehole wall. The cement is then allowed to "set" or "cure" and, as a result, develop its compressive strength.2 Cement serves two principal function:shear bond, which mechanically supports the casing, Andhydraulic bond, which restricts fluid movement longitudinally along the casing and between adjacent geological horizons

A fundamental problem in cementing is fully displacing the fluid in the casing annulus. Hydraulic bond at the cement- to-formation interface is largely influenced by the presence or absence of filter cake and by rock type.

Permeable formations usually experience better hydraulic bond because cement slurry loses water to the formation and develops a higher compressive strength.2 High efficiency is often difficult to achieve as a result of the ease with which cement flows through the larger annular regions and its ability to flow through narrow annular regions. Several remedial measures alleviate the problem, Also, well cement.