Overview Of Pipeline Engineering

Pipeline, riser and subsea engineering

Overview of pipeline engineering

2

All information contained in this document has been prepared solely to illustrate engineering principles for a training course, and is not suitable for use for engineering purposes. Use for any purpose other than general engineering design training constitutes infringement of copyright and is strictly forbidden. No liability can be accepted for any loss or damage of whatever nature, for whatever reason, arising from use of this information for purposes other than general engineering design training. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means whether electronic, mechanical, photographic or otherwise, or stored in any retrieval system of any nature without the written permission of the copyright holder. Copyright of this book remains the sole property of: Jee Limited Hildenbrook House The Slade Tonbridge Kent TN9 1HR England © Jee Limited 2006

Table of contents Volume one FIELD LAYOUTS

7

Expectation

9

Example layouts

10

Pipeline and Cable Uses

16

Subsea equipment

22

Platform and riser configurations

29

ROUTE SELECTION

43

Expectation

45

Survey Techniques

47

Soil Types

56

Routing of pipeline

63

PIPE SIZING

77

Expectation

79

Diameter Sizing

80

Wall Thickness for Bursting

88

Wall Thickness for Hydrostatic Collapse

95

Rigid steel pipe manufacture

101

Buckles

116

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Overview of pipeline engineering

MATERIALS

127

Expectation

129

Selection for Strength

130

Selection for Corrosion Resistance

134

Clad and Lined pipes

139

Titanium and Composites

143

EXTERNAL COATINGS

151

Expectation

153

External Corrosion Protection

154

Cathodic Protection

160

On-bottom Stability

164

Thermal Insulation

169

Pipe-in-Pipe Systems

182

Active Heating of Lines

193

DESIGN METHODS

199

Expectation

201

Limit State Design

202

Identification of Limit States Derivation of Safety Factors DNV OS-F101 design

202 211 220

HP/HT and HIPPS

225

Fishing Interaction

230

Vortex-Induced Vibration

237

COMMON WORK

245

Expectation

247

Construction Survey

248

Route Preparation

252

Welding

258

Non-destructive Testing (NDT)

273

INSTALLATION METHODS

279

Expectation

281

S-Lay

282

J-Lay

291

Reel-lay

295

Bundles and Towed Installations

300

Flexibles and Umbilicals

311

Volume two CONSTRUCTION SUPPORT

317

Expectation

319

Landfalls

320

Trenching and Burial

329

Pre-commissioning

342

TIE-INS, SPOOLS AND RISERS

353

Expectation

355

Tie-ins and Spools

356

Rigid Risers

372

Risers Fixed to Jacket Steel Catenary Risers Top Tensioned Risers Hybrid Risers

Flexible Riser Installation Flexible Pipe Manufacture Installation Analysis Riser Configurations and Equipment

INTRODUCTION TO INTEGRITY

372 375 380 382

385 385 391 395

403

Expectation

405

Failures : Frequency and Incidents

406

PIMS

415

FLOW ASSURANCE

425

Expectation

427

Operational Controls

428

Additives

434

Pigging

437

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Overview of pipeline engineering

PIPELINE INSPECTION

449

Expectation

451

Risk-Based Inspection Plan

452

External survey

456

Internal Inspection

460

Anomaly Assessment

470

Spans Pits and Dents Exposure

470 475 479

Remedial Works

MODIFICATION AND REPAIR

484

493

Expectation

495

Isolation

496

Tie-Ins

505

Repairs

514

Decommissioning

530

PROFILES

535

ACRONYMS & ABBREVIATIONS

581

ACKNOWLEDGEMENTS & REFERENCES

589

Field layouts

Field layouts

9

EXPECTATION

EXPECTATION ƒ Worldwide variations in field layout ƒ Depends on: ƒ ƒ ƒ ƒ

Product being recovered (gas or oil) Water depth and environment (waves and current) Proximity to land or the terminal Predicted life of reservoirs

ƒ Equipment and terminology used ƒ Uses of additional lines and controls ƒ Fluid injection into reservoir or flow ƒ Manifold valve operation and pigging Different parts of the world take different approaches to offshore hydrocarbon recovery. This is due to a number of factors, including custom and practice for the region and the cost and confidence in carrying out a particular solution in that region. Examples are presented of typical developments, including examples of equipment. We will introduce some of the common terms that are used in the industry. It is uncommon to find just a single pipeline running from the field to the land terminal. We examine the other types of additional lines found in an offshore field.

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EXAMPLE LAYOUTS

LAYOUT Refinery

Facility fence

Crossing Landline

Pipework

Landfall / shore approach Process platform

FPSO

1st valve at pig trap

SPM

Floating hose & tails

Crossing Unmanned platform with surface trees

Pig launcher Riser

Catenary riser

SSIV for gas

PLEM Trunk / export pipeline to shore (gas, condensate or oil)

Z spool L spool SSIV

Tie-in

Flowline (oil/gas mix )

Manifold (cluster)

Jumper

Subsea wellheads (trees)

We differentiate between flowlines, trunk pipelines and pipework. Wellheads may either be on an unmanned platform with surface trees, or with subsea wellheads around a manifold cluster. This slide shows the recovery of hydrocarbons from the wellheads through a FLOWLINE and RISER to the FPSO or platform, from where it leaves through a TRUNK or EXPORT PIPELINE to the landfall. Normally, the fluid from the wells (gas, oil, water and sand plus any injected chemicals) would be separated into two commercial streams at the facility (two out of oil, gas and condensate), which are delivered to shore down separate pipelines. Sometimes, the gas condensate is injected into the oil export line. In deep water, the processing facilities are on a FPSO (Floating Production, Storage and Offloading) vessel, with the product being shuttled to a SPM (Single Point Mooring) system and a pipeline to shore. In shallower water, it is possible to use a fixed process platform on a jacket with a pair of permanent pipelines to shore. The trunklines continue as LANDLINES to the refinery, where heavier wall PIPEWORK is used. PIPEWORK is also used on the process facility. This course provides an overview of the design, installation and operation of pipelines.

Field layouts

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GULF OF THAILAND ƒ Shallow water ƒ Dry trees on unmanned platforms

ƒ Process platforms

In many areas of the world, oil and gas is found in relatively shallow water depths of up to 100 m (330ft). Developments often take the form of unmanned platforms with ‘dry’ trees fitted on top. These can be easily serviced – unlike the deeper water wet trees which are fitted to the top of wells at seabed level. (We will examine dry and wet trees later: a dry tree is above the sea surface and can be easily maintained whereas a wet tree is located at the seafloor.) The flowlines link the unmanned platforms to the manned process platform. Export lines send the gas, oil or condensate to shore or to a tanker from a buoy or floating storage unit (FSU).

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MORPETH - GULF OF MEXICO

Two extremes of field layout show how different deeper water developments vary. British Borneo’s Morpeth development is a small field and a neat layout, and was completed in 1998. It is located in 520 m (1700ft) of water, in the Gulf of Mexico Ewing Bank (EW) blocks 921, 964 and 965, off the shore of Louisiana. The Morpeth deck is 34 m (110ft) square and the facilities are spread over two levels. The process equipment has a design throughput of 6100 m³ (38 500bbl) per day and 1.2 million m³ (42 million scf) per day of gas. It was the first tension leg platform (TLP) without surface completions. There are three production wells and an adjacent water injection tree located some 460 m (1500ft) from the Atlantia Seastar TLP. The production flowlines can be pigged back to the wells using loops at the wellheads. Well fluids and water injection lines are brought into I tubes below the waves using six flexible lines. Strakes on the 219.1 mm and 323.8 mm (8in and 12in) rigid export steel catenary risers (SCRs) are used to prevent vortex-induced vibration (VIV). The pipeline system was designed to handle throughput volumes of twice the Morpeth peak production rates. The two export lines deliver the processed oil and gas to the Grand Isle 115 platform lying in 112 m (366ft) of water near the continental shelf margin, some 35 km (19 miles) from Morpeth. From Grand Isle 115, the oil continues through the main Amberjack pipeline system to the Clovelly onshore terminal in Louisiana. The gas and gas liquids go through Texaco’s Discovery pipeline system.

Field layouts

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FOINAVEN - WEST OF SHETLANDS

The Foinaven gas and oil development, shown above (based on as-built survey data), is a very different story. It is a far more complicated arrangement with further flowlines and risers having been added since the original installation was completed in 1997. Water depth at the field is around 500 m (1640ft) reducing to around 450 m (1500ft) at the floating production storage offloading (FPSO) unit. The pliant wave configuration for the risers was developed for this installation, making use of their flexibility to connect to the flowlines. This is not quite as straightforward as it sounds and was designed to avoid clashing of the risers and umbilicals. The two drill centres to the left (orange) and foreground (cerise) north and west of the FPSO are served by 219.1 mm to 355.6 mm (8in to 14in) rigid lines bringing the well fluids to flowline termination assemblies (FTAs) which are connected to flexible risers (green). Lines to both fields provide injection from the rear cluster. The grey lines show submerged buoys supporting the anchor cables that maintain the FPSO on station. The length of these can be adjusted at the vessel to move within a predefined envelope so balancing out fatigue damage of the anchor cables. Process facilities consist of two parallel oil separation and gas compression trains with a combined liquid handling capacity of 23 000 m³ (145 000 bbls) per day and 3.2 million m³ (114 million scf) per day of gas. Gas compression capacity is shared approximately 50:50 between export and providing artificial lift to oil production wells (gas-lift). Currently around 15% of produced gas is used as fuel. The gas is exported through the lines to the right (salmon pink) first through Schiehallion and on to Sullom Voe before being sent offshore again to the Magnus EOR project to increase recovery from that reservoir. Where ■ EOR = enhanced oil recovery

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FPSO AND SHUTTLE TANKER ƒ Floating production storage and offloading ƒ Central turret ƒ Weathervanes

ƒ Shuttle tankers ƒ Connected at stern of FPSO ƒ Offload every two days

The Foinaven FPSO has a central turret system permitting the vessel to ‘weathervane’ minimising environmental (wind, waves and current) loading. Other such vessels may have a forward turret or a fixed orientation depending upon the environmental forces they must withstand. In Arctic or tropical regions, some FPSOs can release the attached riser flowlines and cables so that the vessels can steam out of danger of icebergs or hurricanes/typhoons. The Petrojarl Foinaven FPSO was one of the first vessels to be used in such extreme conditions, being exposed to the hostile Atlantic weather and strong seabed currents. It has an overall length of 240 m (787ft) and an oil storage capacity of around 47 700 m³ (300 000 bbls). Crude offloading and fiscal metering facilities are installed at the stern of the FPSO and shuttle tankers hook up and load approximately every two days at current oil production rates. Two new 95 000 m³ (600 000 bbl) shuttle tankers were commissioned in early 2003 (Petronordic and Petroatlantic) and transport oil primarily to the Flotta oil terminal in Orkney with a small number to Tranmere on Merseyside.

Field layouts

15

EXAMPLE LAYOUTS - SUMMARY ƒ Three typical layouts ƒ Shallow water ƒ Above water trees on unmanned platforms ƒ Flowlines run to central processing

ƒ Deeper water ƒ Subsea trees on wellheads for remote clusters ƒ Connected to floating units

ƒ Export to shore ƒ Separate lines for oil, gas condensate and gas ƒ Shuttle tanker to SPM or quayside

Any questions? Three typical arrangements of offshore field developments have been described. In shallower water, it is convenient to construct simple un-manned platforms with the trees out of the water. These make them easy to maintain and operate. The flowlines run to a central manned process platform. In deeper water, subsea trees from remote well clusters may connect either to a floating unit or to a fixed platform. We will see later that tensioned floating facilities may be fitted with ‘dry trees’ if they are stationed above the drilling centre. Once treated, the product is sent to shore by separate streams. This may be through pipelines or shuttle tankers. Some gas may be used as fuel aboard or re-injected to aid recovery of oil.

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PIPELINE AND CABLE USES

IN-FIELD OR FLOWLINES ƒ From wellhead or manifold to platform or FPSO ƒ Carries a mixture of oil, gas, water and sand ƒ Short lengths ƒ Up to 16 km to 30 km (10 miles to 19 miles)

ƒ Small diameter ƒ 168 mm to 324 mm (6in to 12in)

ƒ Flexible or rigid ƒ Laid by reel, J or S-lay methods ƒ Depends on cost ƒ Water depth, barge availability, diameter and coating We will be referring to two main types of line – flowlines and trunklines. Some general rules are shown above. However, diameters and lengths outwith the ranges specified may be encountered. The type of pipe (rigid or flexible) and methods of installation may also differ. Installation method is usually determined by cost and is affected by the water depth, barge availability, diameter and coating type amongst other things. Notwithstanding this, the rule holds that the flowline takes the mixed fluids to the processing facility on the platform or FPSO where the oil, gas and condensate are separated from the water, sand and any chemicals injected into the reservoir. Then, the individual streams can be sent to shore normally in two export pipelines – for an oil field, the lines will be for oil and gas, for a gas field, the lines will be for gas and condensate. It may be that a shuttle tanker is used to transfer oil from a small field to an SPM ashore – avoiding the need for a large diameter oil export line. Subsea separation is a new technology that is being proposed for some Norwegian developments. It will completely eliminate the need on small fields for a platform or FPSO. The two streams of oil and gas can be sent ashore from an underwater separation unit controlled and powered using umbilical cables.

Field layouts

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EXPORT OR TRUNKLINES ƒ From platform or FPSO to shore or offloading SPM ƒ Carries single product ƒ Oil OR gas OR condensate ƒ Exception Goldeneye – onshore processing

ƒ Long lengths ƒ Hundreds of km (miles)

ƒ Larger diameters used ƒ Up to 1219 mm (48in)

ƒ Rigid lines laid by S-lay Occasionally, the reservoir product and flow rate is such that unseparated gas is sent to shore for processing from an unmanned platform (for example, Goldeneye in Scotland). This decision was taken when the whole-life capital and operating costs (CAPEX and OPEX) were assessed.

JUMPERS AND SPOOLS ƒ Short lengths around 100 m (328ft) ƒ Accommodate thermal movement ƒ Avoids loads from pipeline being transmitted to end structure

ƒ Often L, Z or doglegged shape with flanged ends

ƒ Jumpers ƒ Connects between wellhead and manifold ƒ Flexible or rigid spools

ƒ Spool piece ƒ Connects from end of pipeline to risers ƒ Rigid or flexible

Other terms for pipelines that may be encountered are jumpers which are used to connect the wellhead to the manifold and spool pieces which connect between the pipeline and risers. There is some overlap between these terms. Jumpers tend to refer to short lengths of flexible lines and rigid spools may be used to connect the wellhead to the infield line or manifold.

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Rigid spools and jumpers are often shaped to allow thermal expansion of the pipeline itself. This may be of the order of 1 m to 2 m (3ft to 7ft) or even more. These L or Z shaped connections allow bending to take place at the platform or wellhead, avoiding loads being transmitted from the pipeline to these structures.

BUNDLES ƒ In-field flowlines ƒ Many small diameter lines in a carrier pipe ƒ Carrier 813 mm to 1219 mm (32in to 48in) ƒ Thin wall – less than 12.7 mm (½in)

ƒ ƒ ƒ ƒ

Used to gather flow from separate wells Improved thermal and impact protection Towed out to field and annulus flooded Lengths up to 7.5 km (5 miles) ƒ Two lengths connected together using jumpers

ƒ Integrated manifolds In cases where a cluster of wellheads remote from the platform, serves a small field, instead of running separate flowlines a bundle may be used. This contains a number of rigid flowlines in a large diameter (but thin-walled) carrier and the whole unit is towed out to the field in lengths up to 8 km (5 miles) where it is lowered to the seabed by flooding the annulus. By gathering all the lines within a carrier, it is possible to provide better thermal properties and improve on the impact protection. The manifolds can be integrated within the bundle package to save on the numbers of offshore spool pieces and installation operations that are required.

Field layouts

19

OTHER IN-FIELD LINES AND CABLES ƒ Fram Vest Development, Norway

The commercially recoverable reserves in Fram Vest are estimated to total 16 million m³ (100 million bbl) of oil and 3.5 billion m³ (120 billion ft³) of gas, with a life of 15 years. The field commenced production in the autumn of 2003. It lies some 22 km (14 miles) north of the Troll C facility and is being developed by Norsk Hydro, taking advantage of the existing infrastructure in the Troll area. This first development may pave the way for the development of other low volume reservoirs in the area that are not profitable at present, . The oil is transported in two 90 km (56 mile) long pipelines from Troll C to Mongstad. The gas is re-injected as pressure support. Additional lines in the development include provision for a pigging loop, water injection, gas injection and gas lift, along with associated umbilicals.

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OTHER IN-FIELD LINES AND CABLES ƒ Co-mingled flow pipeline ƒ Gathers flow from a number of wells ƒ Requires test line – may be used as pigging loop

ƒ Methanol, glycol and chemical injection ƒ Protects from corrosion or improves flow rate

ƒ Water or gas injection

Piggyback to field

ƒ Helps to recover oil from reservoir

ƒ Gas lift at well or riser ƒ Used to lift heavy oils

ƒ Umbilical cables

Production from field

ƒ Control lines to monitor flow or operate valves

With a number of wells located at a remote site, it may be prudent to gather the product (oil/gas mix) together in a single, co-mingled flowline to avoid loss of heat and improve flow rates. However, it is common to provide a smaller diameter test line of to prove individual down hole conditions. Alternatively, this may also be configured as a pair of lines which combine the comingled/test line operations with a pigging loop. The pig can be sent down from the process facility to the wellhead manifold and returned to the platform, sweeping out wax or hydrates ahead of it. Some flows need injection from the platform to the well in order either to improve flow or prevent corrosion. This uses a small diameter – 76 mm (3in) diameter line piggybacked on the main flowline or it can be pumped through one of the hoses in an umbilical. Some fields require water to be injected to improve the recovery of gas from the reservoir. This is injected through a separate well from the recovery well, driving the product ahead. Similarly, gas may be abstracted and re-injected into an oil reservoir to aid recovery. Or gas may be needed just at the well or riser to help heavy oil flow up through the vertical section of the flowline. Control of the valves and manifolds at the field is usually accomplished with a separate umbilical laid adjacent to flowlines. This may also contain chemical injection lines and monitoring cables to determine the conditions at the wellhead.

Field layouts

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PIPELINE & CABLE USES SUMMARY ƒ Flowlines or in-field lines ƒ Mixed product from wellhead to process facility

ƒ Trunk or export lines ƒ Separated hydrocarbon streams to shore

ƒ Jumpers and spools ƒ Bundles ƒ Other lines and cables Any questions?

Short in-field lines carry mixed product out of the well to the process facility. Separate streams are then sent to shore through export lines. The ends of these pipelines are connected to the riser at the platform and the manifold or wellhead using short lengths of rigid or flexible jumpers or spoolpieces. Some in-field lines are installed in bundles, possibly incorporating the many other lines and cables needed for field development.

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SUBSEA EQUIPMENT

WELLHEAD TREES ƒ Fits onto drilling template ƒ ‘Christmas trees’

ƒ Control of flow from well ƒ Control and choke valves ƒ Workover operations

ƒ Trawling ƒ Impact and snagging

Once a well has been drilled into the formation, the blow-out preventer (BOP) stack is replaced with a wellhead tree unit such as shown above. Because of the shape and structure of early units, they were sometimes fancifully called Christmas trees. Different configurations are used for various fields depending upon what future work is envisaged. Operations to carry out repairs or increase flowrates are called well ‘workovers’. The trees are attached onto the casing tube and control the production rate along the flowline using valves and chokes. The right hand picture shows the installation of such a unit through the moonpool for the Petrobras Roncador project. The operators provide an indication of the equipment’s size. Where fishing interaction is likely, a trapezoidal protective structure (not shown) can be fitted over the wellhead tree.

Field layouts

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MANIFOLDS ƒ Serve remote well clusters ƒ Connected with jumpers ƒ Rigid or flexible

ƒ Pigging loop ƒ Control umbilical

Where a cluster of wells is remote from the platform, as shown on the right, they are often served by a manifold and are connected using flexible or rigid jumpers . Added functionality can be provided to control of the wells through an umbilical cable to the platform, or a pigging loop to flush wax or hydrates on a regular basis (daily or weekly). The left photograph shows a manifold with fishing protection structure. The right photograph shows installation of an FMC-designed manifold (with the location buckets/guides next to the strop).

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TROIKA DEVELOPMENT - GREEN CANYON ƒ Compact eight slot manifold ƒ Rigid insulated jumpers

ƒ Small manifold for installation ƒ Longest multiphase tie-back in GoM

The Troika oil field development is in 823 m (2700ft) deep water and is located 241 km (150 miles) offshore Louisiana in Green Canyon 244 unit. Troika was developed using a compact eight-slot subsea manifold, tied back to Shell’s Bullwinkle platform 22.5 km (14 miles) away in 410 m (1350ft) of water. This required the longest multi-phase subsea tie-back system in the Gulf of Mexico. The Troika field was initially developed using five wells, positioned 15.2 m to 33.5 m (50ft to 110ft) from the central manifold. The conventional subsea trees are rated at 69 MPa (10ksi), and are dual-bore 102 mm x 51 mm (4in x 2in) configurations, installed using guidelines. Thermally-insulated jumpers are used to connect the individual trees to the subsea manifold. Each jumper is rigid, although normal bends accommodate thermal expansion. Electrical connections from the manifold to the tree were made with the aid of an ROV. The Troika template/manifold system measures 13.7 m long by 9.4 m wide (45ft by 31ft) and reaches a maximum height of 7.9 m (26ft) above the seafloor. This small size permitted its installation, using just a supply boat and the drilling rig (shown in photograph top right). The template weighs approximately 43 tonne (95kip) and provides support to the manifold and the jumpers, flowlines and trees. Two 273.1 mm (10in) diameter carbon steel production flowlines connect the Troika subsea manifold to the Bullwinkle platform. These flowlines are insulated to minimise paraffin deposition and to provide reaction time for hydrate prevention, following an unplanned shut-in. Corrosion inhibition is provide by means of chemical injection into the subsea manifold. The flowlines were constructed in bundled cross-sections in four 11.3 km (7 mile) lengths, and are encased in an open-cell foam, in 609.6 mm (24in) carrier pipes. The design heat-transfer coefficient for the assembly is 1 W/m²/K (0.176 BTU/hr/ft²/°F).

Field layouts

25

LARGE MANIFOLD

An appreciation of the size of some manifolds can be gained from this photograph.

PLETS AND PLEMS ƒ Pipeline end terminations

ƒ Pipeline end manifolds

In areas of the world with deepwater, soft seabeds and no fishing interaction, it is common to use a vertical connection between the end of the pipeline and spool. PLETs are lowered to the seabed attached to the end of the pipeline with a vertical bend. A hinged attachment point as shown on the top left photograph provides tension to prevent buckling of the pipeline. The central photograph shows the testing of a spoolpiece connection to the Mardi Gras PLET. The right hand photograph shows similar pre-installation testing for a flexible jumper.

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PLEMs include some valve work and can be larger. They are sometimes connected after the pipeline has been installed and pigged. The lower left photograph shows a 610 mm (24in) pipeline with two 323.8 mm (12in) marine loading lines These were pulled from the beach attached to a PLEM/loading system manifold and installation sled at Isle de Bioko, Equatorial Guinea, West Africa. A simple PLEM on a skid on the lower right is installed following the pipeline installation.

SPM AND SALM ƒ Single point mooring ƒ Anchor chains to pile

ƒ Single anchor leg mooring ƒ Sakhalin – lowered to avoid ice ƒ Single hinged anchor arm ƒ Fixed with piles to seabed The left photograph shows a Mitsubishi SPM located in Himegi Japan. The buoy is of diameter 11.0 m x 4.0 m x 4.8 m high (36ft x 13ft x 16ft). It is held by just four 120 mm (5in) diameter chains attaches to seabed anchors or piles. It is sized for a maximum moored vessel of 280 000 DWT. The maximum loading rate is 12 000 m³/hr (75 500 bbl/hr) for 24 hour turnaround. The vessel is connected to the buoy and can weathervane on the rotating top section. The hoses connect to the swan neck seen at sea surface level. SPMs are often used in shallow water for discharge to shore but can also be found at deepwater fields associated with FPSOs. A SALM is a mooring system utilizing a single anchor base and single riser, designed to operate as an unmanned marine terminal in shallow water. One is used in the Sakhalin fields, Russia, north of Japan. The unit can be lowered into the glory hole during winter months to avoid the ice floes.

Field layouts

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PIPELINE CROSSINGS ƒ Crossings ƒ Blocks ƒ Mattresses ƒ Rock dump

At pipeline crossings, it is common to provide supports to ensure a vertical separation of 300 mm (12in) or 450 mm (18in) – depending on local requirements. These supports can be concrete blocks or mattresses or – as shown bottom left – simple rock dump from an ROV. Because the spans may be subject to vibration in currents and could snag trawler nets, it is usual that the whole length is protected with rock dump or mattresses. The photographs show the stern deck of the Oceaneering’s DP-2 MSV Ocean Intervention during pipeline crossing mattress installation work. It successfully installed 100 concrete mattresses, weighing 4.5 tonnes (10 000lb) each, as insulation and thermal protection for a flowline at depths greater than 1800 m (6000ft) in the Gulf of Mexico. An Oceaneering ROV manoeuvred the 12.2 m (40ft) handling frame at the seabed to position the mattresses end to end.

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SUBSEA EQUIPMENT - SUMMARY ƒ ƒ ƒ ƒ ƒ

Wellhead trees Manifolds PLETs and PLEMs SPMs and SALMs Pipeline crossings

Any questions?

This has shown a selection of typical equipment and features associated with field development, as well as introducing some of the common acronyms used.

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PLATFORM AND RISER CONFIGURATIONS

FIXED PLATFORMS ƒTubular steel jackets

Shearwater

Troll

ƒUp to 500 m (1600ft)

ƒConcrete gravity base ƒFrom 30 m to 300 m (100ft to 1000ft) ƒStorage in base cells ƒIceberg zones

ƒ Risers

Hibernia

ƒ ƒ ƒ ƒ

Rigid fixed steel I tubes with flexible pipe J tubes with flexible or rigid pipe Rigid steel catenary riser (SCR)

In the shallowest water, we can make use of fixed platforms. These can be constructed from a lattice of tubular steel or reinforced concrete. The former are normally used from the shallowest seas up to a depth of about 300 m (1000ft). However, some examples are found in deep enclosed seas in up to 500 m (1600ft). Such structures are generally installed by launching horizontally from a carrier barge and then tilting to the vertical by flooding various compartments. The legs are then piled into the seabed. Concrete gravity based (CGB) platforms are generally floated out upright using evacuated storage cells in the base to provide buoyancy and ballast. A minimum water depth is needed en route to the final destination to accommodate the CGB’s draught. At the field, the cells can be flooded in a controlled sequence to progressively sink the CGB until it is in position on the seabed. They have the advantage that spare cells can be used for product storage. They are often used in arctic regions where they need to resist sea ice or bergs. Examples of this are the Hibernia platform shown and the Russian Sakhalin platforms, north of Japan.

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Risers for these steel platforms can be rigid steel pipework attached to the legs or jacket face. On a CGB, the risers can be run either up the outside of the structure or more commonly, internally within the legs. These are then connected up to the pipeline using rigid spool pieces on the seabed. Alternatively, I tubes or J tubes may be attached in the construction yard. Flexible pipelines are then pulled into these after installation. Small diameter rigid pipe can also be pulled into J tubes (yielding the pipe steel) if the radii are gentle enough. Rigid steel catenary risers have also been used with fixed platforms.

OTHER FIXED PLATFORMS ƒ Compliant towers, compliant piled towers and guyed towers ƒ 250 m to 1750 m (800ft to 5750ft) ƒ Risers as for shallow water platforms

Compliant piled tower

GB260 compliant tower GB260 floatout

As water depths increase, compliant towers, compliant piled towers or guyed towers are used. Instead of splayed legs, these tend to have parallel sides. Guyed platforms have diagonal cables (in a similar manner to broadcasting masts) to provide lateral stability against currents. Since these structures are essentially fixed to the seabed, they use riser designs similar to other fixed platforms. Trees are usually located in the dry on the lower deck.

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FPSOs ƒ Floating production storage offloading ƒ 20 m to 2500 m (70ft to 8000ft) ƒ Early production, small fields, deeper water ƒ Weathervaning ƒ Central or forward turrets - releasable in tropical/arctic

ƒ Fixed alignment - side mounted risers

ƒ Risers ƒ Flexibles - catenary, S, wave ƒ 250 m to 1500 m (800ft to 5000ft)

ƒ Hybrid riser ƒ 1000 m (3300ft) upwards

ƒ Steel catenary riser (SCR) ƒ 1000 m (3300ft) upwards

FPSOs are used in all water depths. They are vessel shaped as shown above. In shallower water, they are used for early production or shallower fields. In deeper water, they provide an alternative to fixed platforms. There was a limitation on their use within USA waters until early 2006, when doublehulled FPSOs gained approval. They usually rely on four or five groups of anchor cables to hold their station. In order to minimise wind and current forces, they may ‘weather vane’. This means that all the anchor cables and risers are connected to a turret, which can rotate. This may be located either centrally or at the bow as shown. In areas where winds from a single direction predominate, the vessels are kept at a fixed alignment and designed to resist all environmental forces. They can be anchored at the bow and stern with the risers attached to the side of the vessel. Risers for FPSOs can be flexible pipelines between approximately 250 m and 1500 m (800ft to 5000ft). Different arrangements such as simple catenary, steep S, lazy S, steep wave or lazy wave can be used, depending on the water depth, current and vessel movement. Hybrid risers consist of a buoyant stalk (or tower) from the seabed up to about 100 m beneath the surface. From the top of the stalk to the vessel a flexible pipe is used. Some vessels use a rigid steel pipeline in a simple catenary. This can be subjected to vortex-induced vibration (VIV).

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OTHER FLOATING PLATFORMS ƒ Tension leg platforms (TLP) ƒ 100 m to 1500 m (330ft to 5000ft)

Heidrun TLP

Genesis spar

ƒ Spars ƒ 300 m to 1700 m (1000 ft to 5600ft)

ƒ TLP or SPAR risers ƒ Tensioned rigid pipe ƒ SCRs

ƒ SFPS (catenary cables) ƒ 500 m to 2200 m (330ft to 7200ft) ƒ FPSO type risers Spar

Tension leg platforms rely on vertical anchoring to the seabed. The semi-submersible pontoons provide buoyancy. Spars, deep draught floaters, deep draught caisson vessels (DDCV) and single column floaters (SCF) all rely on a large cylindrical tube combined with catenary anchor cables, to provide improved lateral stability. Risers for both of these systems can be vertical rigid steel pipes. These are often attached to the platform on an independently-tensioned floor. SCRs are also used. Not shown above are semi-floating production systems (SFPS). These have a surface structure similar to that for a TLP. However, they are anchored in a similar manner to FPSOs using catenary cables. Their risers are similar to those for the fixed alignment FPSO: flexibles, hybrids or SCR.

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RISER USES ƒ Section of line from seabed to topsides ƒ Term includes lines from FPSO to SPM

ƒ Many types and uses: ƒ ƒ ƒ ƒ ƒ

Drilling Production Export/import Workover Control, power & chemicals

Drilling mud riser Workover riser Production risers

The riser is normally defined as a section of pipeline from seabed to topside. This would normally include the multiflow lines from the wells or manifold to the processing facility and the export trunk oil and gas lines to shore. However, for a FPSO, the term ‘riser’ might mean the export lines to the SPM, which need not necessarily return to the seafloor. And, as the picture shows, the drilling mud riser is also slung between the platform and the vessel without touching the seabed. So, there are many variants on this theme and we can categorise risers in terms of their functions, where they are used, and their physical configurations. First of all, let us look at the functions that the risers perform. Risers are used for drilling, production, export, workover and umbilicals. For the pipeline engineer, the main focus of attention is on the production risers. However, similar technology applies to all of them. The picture shows a traditional fixed platform. It contains a rack of production risers in the centre of the jacket (from the platform wells) and also a rack of production risers on one outside face, serving the flowlines and export pipelines. The platform derrick may either be used to workover existing new wells or drill new ones, in which event there will be a workover or drilling riser in the main rack beneath it. In this particular case, the drilling fluids are provided from a floater adjacent to the platform via temporary flexible risers hung in a catenary.

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DRILLING RISER Drill string

Semi-sub

Conductor Insulation/ buoyancy

Riser system

BOP stack system

Service pipe

Mud down centre cuttings up annulus Guide base

The above picture shows a drilling riser with a blow out preventer (BOP) stack beneath it. This provides four methods of preventing blow-out, ultimately by crimping the riser. This fatally damages the riser, so its operation is controlled by the drillers and only used in an emergency. As you can see from the cross-section, the purpose of this riser is to contain the rotating drill bit. Mud is forced down the centre, and mud plus cuttings up the annulus. Typically, the service pipes will consist of: ■ Two 114 mm (4 ½in) choking or kill pipes ■ One 168 mm (6in) booster line ■ Two 60 mm (2½in) hydraulic lines ■ Electrics Approximately 95 to 98% of buoyancy is provided in the form of an epoxy syntactic foam (glass or plastic microspheres in an epoxy matrix) applied as half shells or quarter shells. This also serves to reduce the heat loss from the riser, to maintain a lower mud viscosity.

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PRODUCTION AND EXPORT RISERS

FPSO

FPSO Storage vessel Catenary riser Tethered midwater arch buoy Flowline risers (lazy S) Clump weight Subsea manifold

SPM

W riser Turret with bend stiffeners Anchor cables Distributed buoyancy Export risers (lazy wave)

Touchdown clamp and tether

The picture shows flexible flowline risers running from the seabed in a lazy S configuration up to a floating production vessel. The export risers are configured in a lazy wave with the distributed buoyancy rather than the midwater arch tethered to the clump on the seabed. The risers leading to the storage vessel are in a simple catenary. An alternative used on the Girassol project for a pipeline linking to the SPM buoy is a W riser. This uses distributed buoyancy to lift the central section (avoiding high hydrostatic head), yet keeping the area adjacent to the buoy deeper than the shuttle tanker’s draught. Although the lefthand view above shows flexible risers, rigid steel risers are also used in deeper water. The W riser shown is rigid pipe although flexibles can be used. They are designed to provide enough draught for vessels passing over them but remain shallow enough to avoid excessive collapse pressures due to the density differential between seawater and product oil.

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RISER CODES

Workover rig

FPSO

Shuttle

ƒ General requirements ƒ ISO 13828-1 API 17A

ƒ Subsea control umbilicals ƒ ISO 13628-5 API 17E & I

ƒ Workover riser ƒ ISO 13628-7 API 17G

ƒ Dynamic production riser ƒ ISO 16389 API RP-2RD

ƒ Wellhead and tree ƒ ISO 13628-4 API 17E

ƒ Subsea production control ƒ ISO 13628-6 API 17F

ƒ Flexible pipe ƒ ISO 13628-2 API 17J & K

The picture shows a semi-sub workover rig with a workover riser connected to a subsea well. The FPSO is already on station and connected to the shuttle or storage tanker. The well may be some distance from the FPSO. The purpose of the workover riser is to connect the production tubing and annulus back to the rig in order that maintenance tasks can be done downhole or the production tubing can be pulled and replaced. A comparison is given of the relevant sections of the ISO and API codes for different aspects of the work. Not detailed on the bullet points are: ■ ROV interfaces - ISO 13628-8 API 17H (from the earlier ISO 13628-6 API 17D) ■ Remotely operated tools (ROT) - ISO 13628-9 ■ Through flowline systems (TFL) - ISO 13628-3 API RP 17C

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RIGID RISERS TO FLOATING VESSELS

Vessel

SPM

Shuttle

Turret Bare pipe Buoyant sleeves

Compliant Vertical Axis Riser

W riser

Top Tensioned Riser

Lazy Wave Steel Catenary Riser Buoyant sleeves

Steel Catenary Riser

Bare pipe

The Compliant Vertical Axis Riser (CVAR) and the Lazy Wave Steel Catenary Risers (LWSCR) are alternatives to the simple Steel Catenary Riser (SCR). They accommodate greater vessel movement by flexing. The Top Tensioned Riser (TTR) accommodates vessel movement by applying a tension at the vessel and allowing the riser to ride up and down in a shaft. Both the CVAR and LWSCR make use of sections of buoyant sleeved pipe to modify the simple catenary shape. Buoyancy on the W riser ensures that the hydrostatic pressure is not excessive. In the case of the CVAR, the lower section of pipe (perhaps half of the water depth) ensures a near-horizontal portion of pipe (at mid-water depth), allowing vertical movement at the vessel to be taken out of the system and preventing it from significantly modifying the axial stress. The horizontal offset is typically a quarter of the water depth. The CVAR can be used with well development and workover vessels (not shown above). For export risers with severe vessel movement, the LWSCR may be used. This requires a significantly greater horizontal offset than either the CVAR or the SCR, approximately the same as the water depth. The total suspended length approaches twice the water depth. It has a buoyant length of about one third of the water depth set a similar distance along the pipe from the touchdown position. It is possible to use TTRs and CVARs configurations for drilling or well development.

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STEEL CATENARY RISER

Flex joint

Courtesy of Halliburton

Welded connections

Touchdown point

The schematic above shows a rigid steel catenary riser (SCR). It lifts off the seabed at the touchdown point and rises in a catenary to attach to the vessel. Normally there will be a flex joint at the connection to the vessel. Sometimes, titanium is used for the critically stressed section at the touchdown point. These types of riser are commonly used at depths up to 1500 m (5000ft) but on the Mardi Gras Thunder Horse project in the Gulf of Mexico, two SCRs have just been installed in 1840 m (6035ft) of water. The diameters of these are 508 mm and 610 mm (20in and 24in). SCRs are rarely used at depths shallower than around 450 m (1500ft), because fatigue becomes a major issue and other types of riser are more cost effective.

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TOP TENSIONED RISER

Heidrun tension leg platform (TLP) with rigid risers

Tensioned risers are primarily used in conjunction with ‘floating’ facilities such as the tension leg platform illustrated, semi-submersible drill rigs and production platforms (eg Buchan) and drill ships. The riser response to wave and currents loads and to vortexinduced vibration (VIV) is controlled by the application of tension. With top tensioned risers, it is possible to locate the tree in the dry rather than at the seabed.

CVAR AND LWSCR ƒ ƒ ƒ ƒ

Catenary vertical axis riser Lazy wave steel catenary riser Higher vessel excursion and motion Fatigue at touchdown and VIV near surface

VIV fatigue CVAR

Bending fatigue

LWSCR

Touchdown fatigue

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Use of catenary vertical axis riser (CVAR) or lazy wave steel catenary riser (LWSCR) will accommodate more vessel excursion and movement. The CVAR configuration can be used for all stages from drilling to export of the product. These require similar end fixity considerations at the seabed as those of the TTR and SCR. Checks are also needed with regard to VIV fatigue in steady high currents just below the surface wave layer.

HYBRID RISERS ƒ Rigid tower

Buoyancy

ƒ Self buoyant ƒ Minimise transfer of load to FPSO

ƒ Linking flexibles ƒ Fixed vessel orientation ƒ Benign conditions

Flexible risers

Export lines from FPSO to SPM

Rigid riser tower

Girassol field with hybrid risers and flowline bundles

Hybrid risers involve a combination of tensioned rigid and flexible pipe. The example above shows the rigid pipe used for the (long) vertical portion and the flexibles attaching from the top of that vertical portion in a catenary to a floating production vessel. Hybrids are seen as a potential deep water solution, where the use of flexibles is limited by the weight of the flexible being held at the top. The rigid part of the system is limited to the lower depths where the hydrodynamic loadings are low. They have been used with fixed orientated FPSOs (rather than turrets) in the benign waters of West Africa.

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PLATFORMS AND RISERS – SUMMARY ƒ Types of production platform and other floating facilities ƒ Range of water depths

ƒ Types of riser ƒ Typical water depth range for rigid and flexibles

ƒ Wet and dry trees Any questions?

The different types of production facilities have been shown along with their limitations in water depth. They are served by different types of rigid or flexible riser. Ideally, the tree used to control flow from the well is located on the lower deck of the platform or host floater. This means that it can be operated and maintained easily. However, this is only possible when the riser is vertical and the vessel is immediately above the template. Where the well cluster is remote from the host, or rigid catenary and flexible risers are used then subsea trees are essential.

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FIELD LAYOUTS - SUMMARY ƒ ƒ ƒ ƒ ƒ ƒ

Typical field layouts Types of pipeline and cable Examples of equipment installed subsea Examples of platforms and floating units Arrangements of rigid and flexible risers Terms and acronyms used

Any questions?

Fields are developed using slightly different equipment depending on a number of parameters. The main examples have been given – both subsea and above water – introducing their names and acronyms. This course will concentrate on the pipelines (flowlines and export lines) but it important to be aware of associated equipment used.

Route selection

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EXPECTATION

EXPECTATION ƒ Preparation for design and construction ƒ Survey equipment and techniques ƒ For all stages of pipe construction and operation

ƒ Metocean surveys ƒ From reservoir exploration stage

ƒ Soil types and properties ƒ Needed for lateral resistance and trenching

ƒ Route planning ƒ Areas of seabed to avoid ƒ Determination of pipeline length We will introduce the main survey techniques for designing and constructing rigid subsea pipelines. Some equipment can also be used during the operational and maintenance phase. Metocean data collected at field exploration stage is needed during design. The soil at the seabed has an important bearing on a pipeline’s ability to withstand environmental forces. We also need such data prior to trenching operations in order to select appropriate equipment. We have included geotechnical studies because they do not tend to be included on mechanical engineering courses. Soil properties differ from those of other materials in that they are natural deposits rather than being manufactured to a specified standard. The main considerations that influence the routing of a pipeline are presented. We will show some example areas of the seabed which need to be avoided. The selected route naturally determines the length of the pipeline and leads to the next stage of design.

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WHEN ARE SURVEYS DONE? Year 1

Year 2

Year 3

Year 4

Year 5

Year 6

Year 7

Year 8

Year 9 Year 10 TYPICAL PROJECT

Seismic exploration Exploration drilling

Deep seismic and metocean

Feasibility Conceptual design Front end engineering design Detailed design

Desktop

Procurement Construction Production drilling

Geophysical and geotechnical

Prelay, post-lay and post-trench

Commissioning Operation

As-built

Inspection

First of all, when during the life of a pipeline do we carry out surveys? Here we have a typical schedule for a project, from seismic exploration through to the start of production operations. Surveys of various types feature strongly throughout. At the reservoir discovery and evaluation stage (shown above as deep seismic exploration), it is likely that metocean data will also be collected. Desktop studies are likely to be used prior to offshore surveys for pipeline design. With regard to pipelines, we are concerned with three main phases of survey: ■ DESIGN: The proposed pipeline route is surveyed to identify seabed features and soil properties along the pipeline route. These are necessary for the pipeline design and the installation engineering. ■ CONSTRUCTION: At various stages during construction, the pipeline is surveyed to ensure that the as-installed pipeline is in accordance with the design. ■ OPERATION: During operation, the pipeline is surveyed to ensure that it remains in the design condition. Operational surveys are addressed later in the Integrity Management Inspection module.

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SURVEY TECHNIQUES

SURVEY: WHAT IS IT? ƒ Survey means gathering information on the offshore environment ƒ Use of existing data

ƒ Offshore investigation techniques ƒ Geophysical – topography ƒ Vessel, ROTV and ROV based sonar

ƒ Geotechnical – soils ƒ CPT, vibrocore, grab sample

ƒ Metocean – environmental forces ƒ Wave and current meters

Three types of survey are used in pipeline engineering: ■ Geophysical gathers data on the seabed contours and the shallow rock strata. The tools used are vessel and ROV mounted sonar devices. ■ Geotechnical gathers data on the soil types and strengths. The tools used are cone penetrometers, vibrocorers and grab samplers. ■ Metocean gathers data on the environment, including waves and currents. The tools used are current and wave meters. More on what these look like below.

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SONAR DEVICES ƒ Sonar used to find seabed profile, wrecks, wellheads, rock outcrops etc Towed fish sidescan Sidescan transducer

Pinger Hydrophone

Combined transducer

Sub bottom profiler (boomer)

Picture courtesy Sonar Research Development Ltd

Geophysical surveys are carried out using a variety of sonar devices as illustrated above. All send sound signals from a device to the seabed and listen for the echo return from the bed itself or from soil layers just beneath. The equipment then interprets the strength, time and direction of the echoes. Their functions are as follows: ■ The towed fish sidescan, as the name implies, is towed behind the vessel on a cable. This allows it to fly closer to the seabed, picking up more detail but over a smaller width giving a picture of the seabed sufficient in detail to gauge contours, wellheads, rock outcrops, wrecks and other similar features. It is even possible, with practice, to distinguish different types of seabeds such as sand, gravel or shells. ■ The sidescan transducer is the same as the towed fish but attached to the hull of the ship. It surveys swathes either side of the vessel. ■ The combined transducer is an echo sounder for mapping the seabed under the vessel. It has two frequencies with differing beamwidths for improved resolution. ■ For use in seismic work, the pinger and boomer emit high energy pulses of high and low frequency sound respectively. These pulses penetrate the seabed and reflect from the soil layers beneath it. The reflections are picked up with arrays of hydrophones and interpreted to give an understanding of the patterns of soil layers beneath the surface.

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GEOPHYSICAL SURVEY ƒ Seabed bathymetry ƒ Contours – false colour

ƒ Sub-bottom profile ƒ Soil layers and rockhead

A geophysical survey plots the shape of the seabed (its contours) and those of the soil layers underneath. In the case of oil exploration, the geophysical surveyors are looking for deep layers containing oil and gas structures. In the case of a pipeline route survey, we are really only interested in the very top layer, or down to about 4 m (13ft) if we are trenching or dredging. Horizon lines are correlated using known geophysical data (i.e. vibrocores) and these are used to determine the actual make up of the layers seen in the geophysical survey.

ROTV ƒ Remotely operated towed vehicles ƒ Controlled survey height above seabed ƒ Fin pitch operated from vessel through umbilical ƒ Speedy survey of large areas of seabed ƒ Initial survey at design phase Deploying BRUTIV

Use of ROTVs is now the main source of pipeline route survey information.

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By flying the equipment at a controlled height above the seabed, it is possible to rapidly obtain topological and pipeline span data. The operator on the vessel is able to change the pitch of the fins through the data umbilical cable. The BRUTIV (Bottom-Referenced Underwater Towed Instrumented Vehicle) can be towed at a speed of several knots just a few metres (ten feet or so) above the seafloor to obtain continuous colour video imagery along transect lines several kilometres (miles) long.

ROV SURVEYS ƒ ROV survey can include: ƒ ƒ ƒ ƒ ƒ ƒ

Video Depth of burial Sonar imaging CP testing Wall thickness Flooded member determination

ƒ During pipelay and for the integrity management operational phase

ROV surveys are conducted both prior to construction for small areas of concern, and at stages during construction particularly the touchdown point or crossings. However, they are classically used during the life of the pipeline to determine spanning sections and depth of soil cover. In addition to providing a visual video record of the pipeline condition, a range of other activities can be performed as listed above. These include wall thickness measurement, where Ultrasonic Testing (UT) equipment is mounted on the ROV. Also the ROV can be used to determine if structural tubular members have become flooded. This is particularly useful for the analysis of jacket legs, when it is necessary to determine if structural members have cracked and become flooded. The photograph is of a small ROV used for minor survey work – perhaps the touchdown location during installation in shallow waters or the inspection of a riser or short lengths of spanning or rock dump. Much more powerful ROVs rigged with multiple cameras, lights and CP test equipment would be required for the inspection of the whole length of a pipeline in strong currents.

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AUV ƒ Autonomous underwater vehicles

AUVs are un-tethered ROVs that are programmed with the survey route, launched from the support vessel and then recovered at the end of the survey. For pipelines that are reasonably close to land, the AUV does not even require a support vessel as it can be launched and recovered from land. The AUV can carry a range of instrumentation such as: ■ side scan sonar ■ sub-bottom profiler ■ multibeam echo sounders ■ video camera ■ altimeter ■ telemetry equipment The survey information can be downloaded from the AUV either after retrieval or in real time as it is gathered during the survey itself. The benefit is the speed of the survey is greater than a normal ROV and the support vessel does not have to be close to the vehicle.

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AUV RATIONALE ƒ Heavy R&D ƒ All types of seabed survey ƒ Not mature for pipeline inspection

ƒ No turning circle ROTV and fish

AUV

ƒ ‘Salvage’ issue There is heavy investment in AUV research and development at present by the major survey companies. However, they are best used for seabed and route surveys. Their use for pipeline inspection is as yet not a mature technology. Removing the umbilical from the inspection tool has particular benefits in deep water. Surveys can be completed more quickly and the handling is improved. An AUV is better able to follow curves, arcs and changing depths than a tethered vehicle. The AUV can be programmed to maintain a constant height above the seabed, typically about 40 m (130ft), and it will maintain this more easily than a tethered ROV as it is not affected by the heaving, pitching and rolling of the surface vessel. An AUV sortie mission may be 48 hours at 2 m/s (4 knots) with a final positional accuracy of around 3½ m (10 ft). AUVs have been used throughout the world including the North Sea, Gulf of Mexico, West Africa and Brazil. Many tens of kilometres of survey lines have been successfully run. One advantage of AUVs over towed equipment such as fish is that they do not require a turning circle when carrying out the transverse runs (see upper portion of track). To avoid tangling of tow lines it is necessary to make a wide sweep at each end of the track. AUVs can reduce data gathering time by half (see lower portion of track). Although potentially, AUVs could be launched from a slipway and recovered a number of days later having gathered all the data, at present they still require a vessel as a guard ship. A trawler skipper catching one with his haul of fish can claim compensation for net damage and claim the unmanned vehicle as salvage. Reports of recent AUV work in the Mediterranean suggests that they could not recover inshore data in depths less than 100 m (330ft) and the cost was more than that for other more conventional equipment. Typical rates are $90 000 per day compared with an ROV at $30 000 per day. However, in deep water, the rule of thumb is that they cost three times that of the alternatives for five times the benefit.

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GEOTECHNICAL SURVEYS ƒ Sample and test seabed soils ƒ Use cone penetrometer and/or vibrocores

Geotechnical surveys establish the nature of the soil along the pipeline route. They typically use a cone penetrometer tester (CPT), as shown in the picture above left. This is a small device dropped onto the seabed with a coiled probe which is forced into the seabed. On its way in, it measures the cone resistance, sleeve friction on its side, friction ratio and pore pressure at its tip. All of these are recorded as they vary with depth of penetration. By cross-referring to calibration data, these features can be used to determine whether the soil is sand or clay and what strength or friction angle it has. The picture is of a Fugro Seascout CPT. It weighs 1 tonne (2200lb), is 2 m (6.6ft) square by 2.4 m (7ft) high, has a 100 mm² (0.155in2) probe cross sectional area and a maximum penetration of 6 m (20ft). The picture on the right is the head of a vibrocorer. This recovers a sample tube of the actual seabed for correlation. It is often used with a tripod stand to ensure accurate entry.

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METOCEAN SURVEY ƒ Wind, tide, wave and current ƒ Currents ƒ Acoustic doppler current profilers ƒ Current meters, electromagnetic, acoustic, rotor

ƒ Waves ƒ ƒ ƒ ƒ

Buoys Subsurface pressure, velocity Radar Satellites

The third element of survey is the metocean survey, telling us the environmental conditions. This data is needed at the design stage and is normally assessed from existing measurements and interpolation techniques. The slide lists the instruments used to measure currents and waves and shows a picture of an acoustic doppler current meter, a relatively recent development, which can determine the currents at various locations throughout the water column. Radar monitoring from satellites is also now used to provide wave heights worldwide.

SURVEY TECHNIQUES - SUMMARY ƒ Three sets of data ƒ Route contours - route planning ƒ Width of laybarge anchor spread

ƒ Soil type strength - route planning ƒ Waves and currents - field development stage

ƒ Route planning surveys ƒ ƒ ƒ ƒ

Ship and ROTV - quickly covers a large area ROV - detailed information close to seabed AUV - new technology but with high potential Geotechnical - CPT and vibrocore along centreline

Any questions?

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There are two types of survey that are performed prior to preparing the route for pipeline installation, these being geotechnical and geophysical surveys. Metocean data has usually been already collected during the field evaluation phase. Where it is likely that an anchored laybarge will be used, the width of side-scan survey should be extended to the width of the anchor pattern – perhaps as much as 3 km (2 miles) to either side of the pipeline route. The surveys assess if the route is suitable for installation of the pipeline and identify any obstructions to construction. Survey ships can cover an area of the seabed more quickly than an ROV. However, more detailed work is best done close to the seabed by ROVmounted units. AUVs are still being developed but they have the potential for rapid collection of data. At route planning, it is common to undertake soils investigation using CPT and vibrocore at least along the centreline of the pipeline route.

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SOIL TYPES

WHAT IS SOIL? ƒ Engineers ƒ ƒ ƒ ƒ ƒ

Soils are weathered or decomposed bedrock May have been eroded Transported by wind, water or ice Re-deposited in homogenous or mixed layers May contain organic (plant) material

ƒ Geologists ƒ Classify the above as ‘weak rock’

ƒ Farmers and gardeners ƒ Interested in ƒ Top 0.2 m (8in) of organic topsoil for growing ƒ Drainage of subsoil under-layer

Although engineers are interested in soils from the point of view of their foundation strength, groups such as geologists and agriculturalists have other different interests and ways of looking at soil. We tend to define soil as weathered bedrock which may have been eroded, sorted and transported by natural processes before being re-deposited some distance from its origin. It may have organic material mixed with it, which tends to reduce its strength. It may be partly reformed into weak sandstone or mudstones. We differentiate between soils and rock. Geologists tend to view all rock and soils as a continuum (no classification division between them). They are more concerned with the origin and mineralization than the engineering strength. Whereas engineers usually have to understand the behaviour of Quaternary deposits (last 2 million years); from a geologist’s point of view, this is regarded as very young drift material that has yet to fully form.

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Agriculture is more interested in the upper layers which need to contain plenty of organic material although drainage is also of concern. Organic material is definitely undesirable from the point of view of sound foundation strength. All these groups – and many others – have their own ideas about the optimum method of classifying soils. There is no universal approach or codes so caution should be maintained when reviewing soils reports.

TEXTURAL SOIL CLASSIFICATION ƒ Texturally, soils divided into: ƒ Coarse grained ƒ Visible to naked eye ƒ >0.060 mm (2.4thou) ƒ Sands, gravels cobbles and boulders

ƒ Fine grained

Sand

Gravel

Silt

Clay

ƒ <0.060 mm (2.4thou) ƒ Silts and clays ƒ Clay is ‘cohesive’

ƒ Real soil is a matrix with a range of sizes Sands and gravels can be identified in the field by visual inspection. Sands are particles smaller than 2 mm (79thou) in diameter but larger than 60 μm (2.4thou). Finer soils such as silts and clays can be discriminated by touch and simple tests in water. Silts are slightly granular – testing between the teeth is common. Clays are smoother with no discernable grains. Silts will disintegrate when dropped into water whereas clays will remain as a clump. Silts will dry quickly in the hand. With silt, dry lumps can be powdered easily by hand whereas dry lumps of clays can be broken but not powdered between fingers. Silts exhibit little plasticity and marked dilatancy. Clays exhibits plasticity but no dilatancy. Dilatancy (or bulking) is the inelastic volume increase caused by soil particles moving relative to each other under shearing forces. It should be noted that pure soils are rare as real soil is a mixture of particle sizes. The exact division between each term depends upon the soils investigation code being used. Examples of particle size distributions for real soils are given later on.

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BS 5930 GRAIN SIZE CURVES

SILTS FINE SOILS

Percentage passing

Drainage properties 100%

Practically impervious k<10-8 m/s

Low permeability poor drainage 10-6 >k>10-9 m/s

Gap-graded silty, gravelly medium-fine SAND

SANDS

200 Boulders

60 Cobbles

20 Coarse

6 Medium

Fine

Coarse

Medium

Grain size (mm) log scale 0.2 0.6 2 Fine

0.06 Coarse

CLAYS

0.006 0.02 Medium

Basic soil type

Fine

0.002

GRAVELS COARSE SOILS

VERY COARSE SOILS

High permeability generally k>10-5 m/s (fine sands). Maximum can approach 1 m/s

Uniform fine GRAVEL

Well graded sandy, slightly silty GRAVEL

0%

The slide shows three typical soil descriptions and the particle size distribution arranged in accordance to BS 5930 : 1999 Code of practice for site investigations; and BS 1377-2 : 1996 Methods of test for soils for civil engineering purposes – Classification tests. In general, very coarse soils such as cobbles and boulders cannot be recovered from samples because they are larger than the core diameters. Descriptors such as ‘gravelly’ and ‘slightly sandy’ or ‘very silty’ are set at up to 5%, between 5% and 20% and more than 20% levels, respectively. Terms such as GRAVEL/SAND means approximately equal proportions of each. Gap-graded means that there are missing particle sizes. Some codes have been designed for agriculture – others for geology – rather than engineering. Descriptions and the number of divisions vary greatly between codes used around the world: soil types may be shifted across, resulting in a “coarse sand” being defined as a “fine gravel” etc. The rule is to look at the actual gradings rather than the descriptors. Note that some codes show the larger particles on the left; others (as above) show them on the right. But shapes of profiles may be similar (top left to bottom right) because percentage retained is changed to percentage passing. Again, look carefully at the sizes. In the US, there are a number of different systems for various purposes: ■ Unified Soil Classification ■ Highway Research Board (AASHO) Classification ■ ASTM (Pedological Soils Classification) – but used for engineering design ■ Federal Aviation Agency (FAA) or Civil Aeronautical Administration (CAA) Classification ■ Geological Classification (Wentworth) ■ Textural Classification for Agriculture

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COMPARING SAND, CLAY AND MIXED SOIL

ƒ Shear strength versus normal stress

φ

σ3

φ) n(

σn θ

Failure shear

τ=

a ·t

τ

Mohr’s circle σ1

Pure clay

σn φ = 0 or c soil

Mixed soil

t an + σ n· τ=c

τ=c

σn

c = 0 or φ soil

τ

c

Pure sand

τ

(φ)

σn c - φ soil

The three graphs show the shear strength against normal stress for the different classification of soil using the traditional approach. Where: ■ c = cohesion ■ τ = shear stress ■ σn = normal stress ■ σ1 = major principal stress ■ σ3 = minor principal stress ■ φ = internal angle of friction Pure sands have no cohesion and can be represented by the equation τ = σn· tan(φ), indicating that the frictional resistance varies with the value of normal stress. With ductile materials such as steel, we often use von Mises equivalent stress (maximum distortion energy theory) or Tresca (maximum shear stress theory). Soils are better modelled using the Coulomb-Mohr Theory. The Mohr’s circle diagrams are shown above can be visualised as the principle stresses acting on a wedge of soil of angle θ to the horizontal. The normal stress, σ1 with shear down the slope σ3. The principal stresses (σ1 and σ3) are drawn on the lower axis. The vertical line from the axis to where the Mohr’s circle is tangential, indicates the failure shear stress. It is possible to make a vertical cut in a clay and for this to remain standing without support for some time. This cannot be done with dry sand which tends to slump until a slope with an angle approximately equal to the angle of internal friction (the friction between the grains) is formed. Pure clays do not increase in strength with increasing normal stress. For this reason, the equation τ = c is applicable, showing cohesion as a constant value with increasing overburden. That is to say, a cohesive soil has a shear strength even when the normal stress is zero (at the soil surface).

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However, many real soils exhibit some features of both cohesion and internal friction, so the equation τ = c + σn· tan(φ) is used. The figure shows two Mohr’s circles used to describe such as soil, calculated at different depths (overburdens).

MAIN SOIL TYPES – PROPERTIES

ƒ Plasticity and cohesion ƒ Clays are plastic, cohesive, expansive/compressible ƒ Sands are non-plastic and non-cohesive (granular) ƒ Silts and loess ƒ Very fine grained ƒ Generally non-plastic and mostly cohesionless

ƒ Muds are soft fine-grained organic deposits ƒ Low friction and cohesion values

ƒ Calcium carbonate soils ƒ Cover 30% of the seabed (mainly in tropical regions) ƒ Can be any particle size – clays to gravel ƒ Cementation – reformed (hard pan, dolomite, chalk) Sands and gravels are non-plastic and non-cohesive. Silts and loess (wind-formed deposits) are even finer grained particles and are usually also cohesionless. However, clays are both plastic and cohesive. They tend to have other properties such as being expansive or compressible when loaded. Most soil investigation work was originally undertaken on silicate soils. However, some 30% of the sea floor has carbonate soils. The assumption generally made is that these are predominately calcium carbonate (CaCO3). They may be of any particle size (from very fine to cobble size) and tend to reform by cementation, forming layers of harder material.

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SOIL TESTING ACCURACY

ƒ Inherent soil variability ƒ Vertically and laterally ƒ Naturally-laid deposit

Pipe in trench CPT measurement

ƒ Limited availability of information ƒ Proximity of tests to pipe route ƒ Restricted access to areas of seabed

ƒ Imperfect information for design ƒ Investigation techniques don’t reflect true soil values ƒ Measurement errors and testing imperfections ƒ Disturbed specimen, limited sample size or missing layers ƒ Imperfect empirical relationships to derive values

Because soil is a naturally occurring deposit, its properties vary both vertically and horizontally. Commonly, there is more variation in the vertical direction because soils tend to be laid in lenses. Even within a homogenous soil horizon, natural soils have different properties due to variation in mineral composition, environmental conditions during deposition, stress history and moisture content. It is common to average the results of a number of samples and look at the best estimate, upper and lower bounds. A large factor of safety should also be used. We may not have identified the fabric of the soil which may have thin deposits of sand just a few grains thick within a body of clay helping with drainage. We often have to limit the number of tests along the pipe route. This can be because of costs or restriction in access due to adjacent seabed equipment. Existing operators have been known to prevent sampling within 500 m (1640ft) of their pipeline – even for a crossing design. For critical designs of wellheads or clump anchors, it is common to return to undertake additional soil testing at the exact location of the item. However, it must be recognised that testing samples of soil does not necessarily provide us with exact values for design. The equipment has some inherent error (tolerance or accuracy) by its very nature. If we recover soil to the surface for laboratory testing, it will have been disturbed, giving slightly different values from that on the seabed. Our sample is generally of a limited size – typically 100 mm (4in) in diameter so any bedding or joints (cracks) in a sample of clay or chalk may not be well represented, leading to inaccurate estimation of strength or permeability of rubbly or blocky material. Finally, the values that we measure are generally not those used for design. We make use of empirical relationships to derive the engineering information, leading to either randomly or systematically based inaccuracies. The new Eurocode 3 (ENV 1997 parts 1 to 3) gives good guidance on soil design using limit state methods. However, there is no comprehensive international standard for soil identification and testing yet. National standards such as BS 8004 and the US Unified Classification can be used but are primarily designed for land-based work. The Norsok standard G-001 Rev 2 Oct 2004 - Marine Soil Investigations - is specifically designed for offshore use.

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Refer to Géotechnique 55 March 2005 Volume LV N°2 pp 95-108 Non-parametric simulation of geotechnical variability, P L Bourdeau & J I Amundaray, Institution of Civil Engineers ISSN 016-8505 (www.geotechnique-ice.com). The figure shows how variability in soil properties tends to be greater vertically than horizontally, even in a homogenous horizon of a single soil type. The colours simulate perhaps weak to strong soil or fine to coarse grain size. The CPT on the left has encountered average to low values. The pipe trench will be cut through average to high values. In this instance the scale of fluctuation is large, but changes may occur at a much finer scale.

SOIL TYPES - SUMMARY ƒ No international standard as yet ƒ Size of grain

ƒ Granular soil (sand, gravel) – φ ƒ Cohesive soil (clays) – c ƒ May be over-consolidated / very stiff

ƒ Muds (silt and clay mix) – c-φ ƒ Mixed soil, often soft with organic contribution

ƒ Carbonate soils ƒ Variable along pipeline route ƒ Inaccuracy in recovery and testing methods Any questions?

There are no international standards as yet. However, we normally describe soils on the basis of their grain size. Granular soils are described by their angle of friction (φ). Clays are defined by a value of cohesion. Most soil is mixed and require both φ and cohesion to describe their strength. Muds are such an example and may contain significant amounts of organic material. A further class of soil are the carbonates found throughout the warmer seas of the world. The soil particles here may be of any size but tend to bind together in a weak rock. It must be noted that our results of surveys are bound to provide variation due not only to the changes in soil type along the route but to the method of recovering survey data.

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ROUTING OF PIPELINE

CHOOSING THE BEST ROUTE

ƒ Straight line ƒ Any ideas on the obstacles to routing the pipeline in a straight line?

The starting point for the best route is a straight line from where you found the reserves to where you want them delivered. However, very few pipelines go in a straight line and there are numerous factors which lead us away from the straight route. These are discussed in the following pages.

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SURVEYS FOR ROUTE SELECTION

ƒ Avoid problem areas ƒ Desk study ƒ Existing infrastructure

ƒ Bathymetry ƒ Slopes and features

ƒ Soils ƒ Trenching

ƒ Waves and currents ƒ Pipeline stability

A number of surveys will be carried out prior to route selection. These are aimed at minimising problems such as minimising crossings of existing pipelines, avoidign unstable areas of the seabed or hard ground for trenching and ensuring environmental forces do not destabilise the lines.

DESK STUDY

ƒ Desk study - at conceptual design stage ƒ ƒ ƒ ƒ

Contours Geology Block ownership Existing pipelines, wells, wrecks & cables

ƒ Cost effective ƒ One day offshore ≡ 8 weeks for an engineer

Before conducting an offshore survey, it is often cost-effective to conduct a desk study. This simply means gathering together the existing data about the seabed along the pipeline route. In areas of mature oil and gas exploration, there is usually a comprehensive amount of data available. In the West of Shetland and North Sea, the

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UK Deal website provides a wealth of information regarding existing infrastructure and seismic surveys. Sources are: ■ Admiralty Charts ■ Geological Survey maps of surficial sediments and underlying geology ■ Government block licence information ■ Wellhead and pipeline positions from Notices to Mariners ■ Oil company surveys conducted during seismic and drilling operations ■ Oil company surveys of adjacent subsea facilities

SEABED OBSTRUCTIONS

ƒ ƒ ƒ ƒ

Platforms Wells Wrecks Cables ƒ No deviation ƒ Protection

ƒ Safety zone 500 m (1640ft) or 201 m (660ft)

Seabed obstructions cause deviations in the pipeline route around them. In the North Sea, platforms, wells and wrecks are normally avoided by 500 m (1640ft). In the US, the distance is somewhat less at 201 m (660ft) - one furlong, though this was originally defined when fields were in shallower waters. We also need to consider anchoring areas around subsea works for work-over vessels. The oil industry shares the seabed with the telecommunications industry (amongst others). With the advent of subsea fibre optics for international phone calls and internet traffic, there are many cables currently being installed. Whilst crossing an existing cable would probably not require a pipeline route deviation, it would be important to know where the crossing would occur and to take measures to protect the cable against damage.

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Existing line

PIPELINE CROSSINGS

30° min

Protection 1 km (3300 ft) straight

1 km to 2 km (3300ft to 6600ft) radius Existing pipelines are preferably crossed perpendicularly, with the minimum angle being 30°. The reason for this is that any shallower angle of the approach would lead to a long and extensive crossing with a greater amount of protection needed over the area. With anchored laybarges, the anchoring procedure also becomes more difficult at angles less than 30°. Looking in plan at the pipeline route, there is a minimum radius for the curves that the laybarge can achieve. Typically this is 1 km (3300ft) radius for a small (6in, 152 mm) pipeline and up to 2 km (6600ft) for a large (40in, 1.016 m) pipeline. The reason for this is that we are relying on seabed friction to pull against in order to form the bend.

OTHER USERS OF SEABED

ƒ ƒ ƒ ƒ ƒ

Other countries Exclusion zones Dredging areas Shipping lanes Other companies’ acreage

Bacton

NORTH SEA

UNITED KINGDOM

UK Sector

Dutch Sector

Dredging areas

Restricted Area Belgian Sector

Zeebrugge

BELGIUM Interconnector Pipeline

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Many other users have a claim on the seabed and can influence the seabed route, as can be seen from the route chosen for the interconnector pipeline between Bacton and Zeebrugge. ■

■ ■ ■ ■

It may be advantageous to avoid crossing national boundaries. For example, the interconnector pipeline skirts the Dutch sector. This avoids the requirement of meeting Dutch legislation and of reporting to the Dutch authorities during the operation of pipeline. Transporting of hydrocarbon products across national boundaries may attract high tariffs and taxes. There are restricted areas where military operations are carried out and where dredging is carried out. Where there are busy shipping lanes, the route should go perpendicular so that the construction vessels spend the minimum amount of time obstructing those lanes. With trunk lines, it is often necessary to cross the license blocks of other companies. Normally this is done by way of negotiation - company A crossing company B’s licence block in return for company B crossing company A’s licence block somewhere else. In case of difficulties, the Government Departments (DTI in the UK) responsible for licensing oil and gas exploration may have the authority to impose a solution.

MORE USERS OF THE SEA

ƒ Fishing grounds ƒ Spawning and nursery areas

ƒ SAC – special areas of conservation ƒ Corals and sponges

ƒ Landfalls – SSSI ƒ Environmental impact assessment (EIA) There may be environmental pressure to avoid fishing grounds, sites of special scientific interest and special areas of conservation. The approach is to evaluate the sensitive areas and select the route of minimum environmental impact in consultation with interested parties. The main photograph shows a twin-rigged beam trawler used for flatfish, shrimp and prawn fishing. The insets show a soft coral, a blue sponge and an anemone found in cold North Atlantic waters at depths of 300 m to 600 m (1000ft to 2000ft) near the Foinaven development, West of Shetland. The cold water corals were unexpected finds during the initial surveys for this development.

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In environmentally sensitive areas such as landfalls, it may be necessary to carry out an environmental impact assessment as part of the project approval process.

SEABED FEATURES

ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Sandwaves Rocks Pock marks Iceberg scour Mud slides Mud volcanoes Coral

Areas of rock outcrops and sandwaves are avoided where possible. As a fallback, the pipeline may be routed through the valleys of sandwaves if they have a suitable orientation. As a last resort, and if it is necessary to cross mobile sandwaves, the sandwave may be dredged down to the level of the valleys. Rock outcrops are avoided to permit trenching or limited self embedment, which improves pipeline stability. Damage can occur to pipelines laid directly on rock so where ridges of rock must be crossed, a layer of gravel is laid between as a bedding. Pockmarks are craters typically 5 m to 10 m (16ft to 33ft) across and 2 m to 4 m (7ft to 13ft) deep, thought to originate from shallow gas pockets. The pipeline would be routed around, rather than across these. Mudslides sometimes occur on steep slopes, particularly near river estuaries and on the continental slope. If these slopes cannot be avoided, then the route should run directly down the slope rather than across it. Subsea mud volcanoes and volcanic eruptions simply have to be circumnavigated. Coral can be found at shallow or very great depths.

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SANDWAVES

ƒ Avoid or pre-sweep ƒ Reforms quickly

These two pictures show an aerial view of sandwaves in a shallow sea and (right) a falsecolour side scan along a pipe route. They can be encountered wherever strong currents combine with sandy seabeds in shallow water. The region is either avoided or the waves are removed just before the pipeline is laid. They reform within a few tides.

POCKMARKS AND ICEBERG SCOUR

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This view of a pockmark field in the Beaufort Sea (with an ice scour through the middle) shows how uneven the seabed can be. Such fields of pockmarks are found throughout the world adjacent to hydrocarbon reservoirs. They are thought to be caused by release of small shallow gas deposits, which remove the finer particles from the seabed sediments, leaving a depression. If the route cannot be avoided, then these holes will need to be filled in during seabed modifications prior to pipelay operations.

MUD VOLCANOES

ƒ Near hydrocarbons ƒ Gas leak from formations ƒ Careful routing of lines

ƒ Cold mud mounds ƒ 5 m to 500 m high on land ƒ Currents sweep away soft deposits

Mud volcanoes are also known as sedimentary volcanoes or gas-oil volcanoes. The above photographs show small examples on land at Cape Alyat near the Caspian Sea. Because they are cool, they are considered a tourist attraction, and the mud is deemed to have curative properties being mainly composed of silica with trace elements. They also occur subsea and can erupt powerfully, similarly to magmatic volcanoes, hurling flames to great heights. However, they tend to spew water, hydrocarbon gases and tons of mud. They have periods of quiescence and then burst into activity again. If possible, the area should be avoided. However, they often are found close to hydrocarbon regions and are caused by leakage of gas from great depths. The methane gas is formed in younger strata overlying the oil fields. On land, they can reach heights of up to 500 m (1600ft) but subsea, due to the soft nature of the mud, deposits tend to be rapidly moved by currents. The resulting soft seabed is not ideal for pipelaying.

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BP SHAH DENIZ AZERBAIJAN CASPIAN SEA

ƒ Shah Deniz platform ƒ Adjacent to extinct mud volcano

ƒ Other features ƒ Diapir collapse – faulting ƒ Upwardly mobile salt dome

ƒ ƒ ƒ ƒ

Shallow gas Large deep-seated debris flows Seabed channels 12 mud volcanoes ƒ Associated widespread debris flows

ƒ Careful flowline routing The BP Shah Deniz gas condensate platform is located adjacent to an extinct subsea mud volcano. The oil field lies between Mobil's Oquz, Chevron's Asheron and Exxon's Nakhchiuan fields. Its name can be translated as 'King's Sea'. The prospect is situated in the South Caspian Sea, off the Azerbaijan shore, approximately 70 km (44 miles) south-east of Baku. It lies in water depths ranging from 50 m (160ft) in the north-west, to 600 m (2000ft) in the south-east. The contract area covers approximately 860 km² (330 sq miles). Reserve estimates have been calculated at between 250 to 500 million tonnes (1.5 to 3 billion barrels) of oil and 50 to 100 billion m³ (2 to 4 trillion ft³) of gas. Detailed bathymetry provided information on the faults associated with mud diapir† collapse, shallow gas, debris flows 1 km (3300ft) below the seabed and modern-day features such as mud volcanoes and seabed channels. In total, twelve separate mud volcanoes have been identified. The largest of these, north of the reservoir, produces a major debris flow over 5 km (3 miles) wide. The grid lines on the lower sonar plot of the field are at 2.5 km (1.5 mile) spacing. †Diapirs

are low density rocks such as salt, shale or magma that force their way upward in domes or mushroom shapes.

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CORAL

ƒ Types ƒ Coral reefs ƒ Deep cold water coral

ƒ Field character ƒ 100 m diameter, 5 m high ƒ 1000 m deep ƒ Mound and tail ƒ Sand volcanoes

ƒ Impact ƒ Environmentally sensitive ƒ Damaged by trawling

ƒ Damaging to coating ƒ Flexible pipelines Although coral reefs have been known about for millennia, it is only very recently that coral mounds have been found in deep and cold waters. The Darwin mounds in the Rockall trough off the north-east coast of Scotland are shown above. These were discovered in 1998, and hundred of these mounds cover an area of around 100 km². Similar fields have been located in deep waters off the coast of Brazil having caused damage to flexibles. Mounds in that region are even closer together having the appearance of a cheese grater. The individual mounds are around 100 m (330ft) in diameter and some 5 m (16ft) high. However much larger mounds exist southwest of Ireland in Porcupine Seabight, some 800 m (2600ft) deep. Here, they reach over 1000 m (0.6 mile) across and are 200 m (660ft) high. The carbonate rock of the Darwin mounds is built on what appear to be sand volcanoes – the result of fluidised sand dewatering possibly as a result of slumping. The tops of the mounds (shown orange) are home to live colonies of deep-water coral species and the biological communities they support. The green areas on the chart show the much larger tails (invisible on sidescan images), but which are characterised by high density populations of giant protozoans, up to 0.2 m (8in) in diameter. These corals are extremely slow growing and are easily damaged. Trawl damage has been seen (even at such depths), which is unlikely to be repaired for centuries. For pipelines laid in such regions, we may expect damage to coatings, especially to flexibles.

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PLATFORM APPROACH

Pipelay vessel

H Minimum separation between vessel and platform (typically 15 to 20 m (50ft to 65ft))

Platform H Axial movement of pipe due to thermal expansion

Flanged connections (could also be welded or mechanical connectors) End of rock dump or trench

Where a pipeline is laid to any existing platform, the laybarge must pass to one side of the platform. The pipeline end is laid down to be later connected with a dogleg or the L shaped spoolpiece shown above. (The line cannot lay straight up to the platform without the barge running into the platform.) However, the spoolpiece must also be liftable and alignable. This means it will have a limited length, so it is necessary to find a compromise between the requirements of the laybarge and the spoolpiece.

SHORE APPROACH

Wave refraction

Land

Shore approach route

Direct route

Laybarge at 12 m (40ft) LAT

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A typical third-generation laybarge has a draft of about 12 m (40ft). It may therefore only be able to get within 3 km or 4 km (2 or 2.5 miles) of the shore, depending on the rate at which the seabed slopes. The implication is that shore approaches should be perpendicular, in order to minimise the length of pipe which must be pulled from ship to shore and thus minimise the pulling forces. However, first generation work barges operating in sheltered waters around the Gulf of Mexico (GoM) were able to come into shallower depths down to 4 m (13ft). The larger fourth-generation DP barges may need a water depth of 16 m (52ft) for their thrusters to operate without churning up the seabed. A second reason for pipelines approaching perpendicular to the shoreline, is for stability. The waves refract as they come into shallow water, which means that they approach the shore in a direction close to a right angle, no matter which way they had been travelling further out. The high water particle velocities associated with breaking waves are in the same direction as the waves, so routing the pipeline perpendicular to the shore minimises the destabilising cross-velocities. Even so, it is normal to bury the pipeline on its final approach and across the beach in the surf zone.

ROUTE SELECTION - SUMMARY

ƒ Desktop and surveys for routing ƒ Identify and avoid or minimise: ƒ ƒ ƒ ƒ

Seabed obstructions Pipeline crossings Users of the sea Seabed features and composition

ƒ Special routing at: ƒ Platform approach ƒ Shore approach

ƒ Minimum cost option Any questions? For areas of the world where there are already a number of developed fields, a lot of information can be obtained using low-cost desk studies. We would supplement this information with topographic and soils surveys. Subsea pipelines are generally unable to follow the direct straight line route for many reasons. It is common to examine a number of possible routes and minimise the clashes. The finally chosen route is a cost-driven compromise.

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ROUTE SELECTION - SUMMARY

ƒ Survey methods ƒ Used for all stages throughout a pipeline life ƒ Vessels, ROTVs, ROVs

ƒ Soil types ƒ Sands or clays ƒ Variability and uncertainty

ƒ Routing issues ƒ Desk studies, topographic and soils surveys ƒ Length of line now fixed

Any questions? The three different types of offshore survey have been shown along with the main techniques and equipment. Soils and their variability are an important issue in trenching and stability. Initially, desk top surveys can help with route planning. This is followed by geotechnical and topographic surveys at sea. Metocean data will normally have been obtained from desk top or have been undertaken at the original reservoir determination/evaluation stage. The main considerations that influence the routing of a pipeline have been presented. This provides us with the length of line.

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Pipe sizing

Pipe sizing

79

EXPECTATION

EXPECTATION ƒ Pipeline diameter (bore) ƒ Determining head losses in pipelines ƒ Liquid lines (condensate, oil or water) ƒ Gas lines ƒ Mixed oil/gas flows (multiphase from wells)

ƒ Criticality of diameter

ƒ Wall thickness ƒ Internal bursting pressure ƒ External water pressure (collapse)

ƒ Methods of making linepipe ƒ Buckling This section outlines the process of determining the diameter and wall thickness of a pipeline. There are three methods of making linepipe for the hydrocarbon industry. Videos of these show the processes. The causes and effects of buckling are described along with methods of avoidance.

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DIAMETER SIZING

CHOOSING THE DIAMETER ƒ Large enough for peak flow ƒ Check for low flow condition ƒ Assume a wall thickness to determine bore ƒ Typically, t = D ÷ 22 ƒ Specify by fixed outside diameters

Having selected the pipeline route, the next problem to be addressed is to determine its diameter. The pipeline diameter is sized for peak flow and ensures that flow conditions and pressure drop are within acceptable ranges. However, one must also check for low flow condition in case this leads to laminar flow and corrosion at the bottom of the pipe. In this section, we will examine the three types of flow and how to size the diameter for each. Hydrocarbon pipelines are specified by outside diameter, D. This remains constant such that as the wall thickness, t increases, the bore reduces. This contrasts with pipe used in the lower pressure water industry which keeps the internal diameter (bore) constant, varying the outside diameter with changing wall thickness. It is necessary to make an assumption regarding the wall thickness in order to determine the bore (internal pipe diameter). The D/t ratio is often in the range between 18 and 30, with thicker wall in deeper water. We suggest using a value of 22 for the first estimate.

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TYPES OF FLOW ƒ Liquid ƒ Gas ƒ Multiphase

Wellhead

Separator and pumps on platform or FPSO

Flowline

Export pipelines to shore

Riser Multiphase

Oil/condensate Gas

Well Cap-rock Reservoir

Gas Oil Water

Pipelines are designed for one of three types of flow: either liquid, gas or multiphase. The diagram above shows a schematic of a subsea development. Following the oil from the reservoir where it is single-phase, it passes up to the wellhead. As the pressure reduces on the way up, gas comes out of solution and gives multiphase flow. This passes through the wellhead (which is essentially a valve) and into the horizontal flowline. It passes through here in multi-phase flow back towards the production facility where it travels up the riser and into the separator. The prime function of the production facility is to separate the oil and gas into single phases, and put these into separate export pipelines where they can be pumped to shore or to a tanker. The following pages show how pipeline diameter is determined for the different flow regimes.

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LIQUID FLOW LINE SIZING ƒ Pressure drop due to friction

f ⋅ ρ ⋅v 2 ⋅ L ΔP = 2⋅D 1 ΔP ∝ 5 D The pressure drop, ΔP in a liquid flow line is defined by the above formula, where: ■ f = friction factor ■ ρ = liquid density ■ v = liquid velocity ■ L = pipeline length ■ D = internal diameter (pipe bore) The friction factor is found from the Moody diagram (see next slide) and is generally constant across a wide range of velocities. The density and length are similarly known. The design is carried out by trying a range of standard diameters, finding the minimum size at which the available pressure drop is sufficient to deliver the peak volumetric flow. The equation reduces to pressure drop being inversely proportional to the fifth power of the diameter. This is an extreme sensitivity to the bore: since the pipelines we normally specify are manufactured in steps of 51 mm (2in), experienced engineers can quickly size the outside pipe diameter. An example may be given that using inch sizes, the ratio (10/8)5 = 3 – or pressure drop would be a three times more going from a 10in to 8in bore – and (16/14)5 = 2. Obviously, here we have ignored the wall thickness, but the principle is demonstrated: stepping up to the next standard diameter can significantly reduce the pressure drop in a line. Typical flow velocities in pipelines will generally be in the following range: OIL: GAS:

Min = 1 m/s (3.3ft/s) Min = 3 m/s (10ft/s)

Max = 3 m/s (10ft/s) Max = 9 to 11 m/s (30ft/s to 35ft/s)

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MOODY DIAGRAM

R

e

D ⋅ν ⋅ρ μs hL

L ν2 ⋅ D 2 ⋅g

Relative roughness = absolute roughness / diameter

Friction factor, f

f =

=

Reynolds number, Re

The Moody diagram above is a plot of friction factor on the vertical axis against Reynolds number (proportional to velocity) on the horizontal axis. The curves show values of friction factor for different roughness of the inside of the riser. The curves for a given roughness are fairly flat in the turbulent region to the right hand side of the diagram. This means that for a given roughness, the friction factor varies little with velocity if the flow is in the turbulent region. A note of caution on Moody diagrams and friction factors: there are two different systems in use. The above is the US system which is used throughout the oil and gas industry. The other system has a friction factor f ' or λ (lambda) = 0.25 f, and is shown in some UK water industry textbooks. For common pipeline sizes and materials, the ranges of values are: ■ Reynolds numbers between 105 and 107 ■ Line pipe roughness < 0.5 mm (20mil), giving ■ Relative Roughness between 0.0005 and 0.002 These ranges result in most pipelines having friction factors between 0.01 and 0.015. The graph shows use of the chart: by following the curve from the relative roughness of 0.0001 to where it crosses the Reynolds N° of 6 x 105, we can read off the friction factor on the left axis of 0.014. Where ■ D = inside diameter of pipe ■ f = friction factor ■ g = gravitational acceleration ■ hL = head lost in friction ■ L = length of pipeline ■ Re = Reynolds’ number ■ μ = kinematic viscosity ■ ν = dynamic viscosity ■ ρ = density of fluid

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SIZING FOR GAS FLOW ƒ Similar to liquid, but compressible ƒ With increasing distance along pipeline: ƒ ƒ ƒ ƒ

Pressure drops Gas expands Velocity increases Drag increases

Distance along pipeline in km (miles)

ƒ Still has empirical formulae ƒ Weymouth and Panhandle approximations As the slide indicates, sizing the diameter for a gas pipeline requires a similar approach to liquid lines but is slightly more complex. The complexity is introduced by the compressibility of the gas, which means that, as the pressure drops along the pipeline, the gas expands. Its velocity increases and the drag increases in proportion to the square of the velocity. The overall result of this is that the pressure drops along the initial sections of the gas pipeline are small, compared with those at the far end. Although this sounds complex, the relationship can be described with empirically derived formulae allowing a straightforward assessment of pressure-drop for a given line size.

Liquid flowrate

HORIZONTAL MULTI-PHASE FLOW Froth

Bubble Slug Plug

Annular mist Wavy stratified

Smooth stratified

Oil

Gas

Gas flowrate

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From a well, you typically find a mixture of oil, water, gas and sand. Any combination of gas and liquid flowing together down a pipeline is known as multi-phase flow. Depending on the proportion of gas and liquid and the overall speed of the flow, the phases may adopt different patterns. These are known as flow regimes. The flow regime will also be influenced by the geometry of the pipeline (whether it is going up or down hill or on the level). The importance of determining the flow regime is that different flow regimes cause different pressure drops per unit length of pipeline. The slide above shows seven flow regimes for a horizontal line, depending upon the proportion of oil and gas, and the driving pressure in the line: ■ Where the oil and gas flow rates are low, the flow is smooth stratified. The liquid separates to the bottom of the line and the gas flows at higher speed at the top of it. ■ As the gas flowrate increases, the differential flow causes the surface to become wavy. ■ At higher rates still, we get annular mist flow. This is typical of gas condensate lines where the gas velocity is very high and there is only a small proportion of liquid, which is forced out to the edges and runs along the pipe wall in tears. ■ If the proportion of oil is increased from an annular mist flow, whilst keeping the pressures high, the flow can form froth. Both phases are dispersed and travel at the same speed. ■ At the highest flow rates but when the oil is the greater fraction, the regime moves to bubble flow where bubbles of gas are entrained in a matrix of liquid and all flows at the same speed. ■ If the flow rate decreases slightly, then the bubbles tend to coalesce and separate out at the top of the pipeline. They form plugs of gas. ■ Slug flow is common in oil and gas production flowlines where the flow rates are fairly high. Liquid travels in slugs, with pockets of gas in between. The slugs generally initially form at low points on the line or at the foot of risers. Plug and slug flow can cause problems at pumps and fittings due to the surges as the density of the flow changes. The transitions between the different flow regimes depend upon a number of factors such as topography of the pipeline and additives to the fluid. Researchers adopt different terms (such as pseudo-slug, intermittent slug or bubbly slug) to further subdivide the phases.

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SIZING FOR MULTI-PHASE FLOW ƒ ƒ ƒ ƒ

Size for max flow Check for min flow Networks Correlated software ƒ Pipesim ƒ Flow regime ƒ Pressure drop

ƒ Explicit software ƒ Olga 2000 ƒ Profes Transient The technique for sizing for multi-phase flow is essentially the same as liquid and gas single-phase lines, in that one initially finds the size required to accommodate the maximum flow, and then checks that there are no problems induced by the minimum flow condition. Example low flow problems are: ■ Water dropout in stratified flow leading to corrosion at the bottom of the flowline ■ Difficulties in getting the flow up the riser Also, life is rarely so simple as to have a single well and a single tie-back flowline. As the diagram indicates, subsea developments often have many wells, manifolded together with multiple flowlines back to the separator. In order to design for these conditions, it is necessary to use computer simulation to determine the flow regimes and therefore the pressure drop. Computer simulations can either rely on correlations or can solve the physics of the flow explicitly. ‘Pipesim’ is an example of a programme which uses correlations based upon experimental measurements to which curves are fitted and the results interpolated or extrapolated to the conditions for your pipeline. Estimates are given of the rate of slugging and the maximum size that needs to be accommodated in the trap. Examples of explicit codes are Olga 2000 and Profes Transient. These use equations rooted in the basic fluid properties; they can, for example, model the shape of the front and rear of a slug in order to determine the forces as it passes through a bend.

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DIAMETER SIZING - SUMMARY ƒ Diameter sizing ƒ Peak flow ƒ Low flow

ƒ Extreme sensitivity to bore ƒ Limited number of standard diameters available

ƒ Liquid flow sizing ƒ Gas flow sizing ƒ Multi-phase flow Any questions? To summarise diameter sizing, one finds a diameter suitable for conveying the peak flow at the available pressure drop and then checks that this does not cause problems at the minimum flow. The bore has a strong effect on pressure drop. The standard diameters are normally available in 51 mm (2in) steps. It is therefore a relatively quick process selecting the diameter required to suit both peak and low flow rates. For single-phase liquid and gas flows this process can be done analytically. For multi-phase flow and networks, computer simulation is required.

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WALL THICKNESS FOR BURSTING

SIZING WALL THICKNESS ƒ Thick enough to contain pressure ƒ What else should be taken into account in determining the wall thickness?

The principle for sizing for wall thickness is to make the pipe wall thick enough to contain the maximum allowable operating pressure. This sets the minimum value for the wall thickness. There are many other factors to take into account which may lead to the selection of a thicker wall. These are detailed in the following section.

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INFLUENCES ON WALL THICKNESS Human safety ƒ Others ƒ Bending stresses Internal pressure ƒ Buckles Corrosion allowance ƒ Reeling Manufacturing ƒ Seabed stability tolerance ƒ Fatigue ƒ Hydrostatic collapse ƒ ƒ ƒ ƒ

ƒ Manufactured bends ƒ Stress concentrations

The slide above lists the factors to be taken into account in determining wall thickness: ■ In cases where the pipeline runs close to people, such as on risers and spoolpieces, the wall thickness is increased to give an additional safety margin (lower stress). ■ Internal pressure has already been mentioned. ■ The wall thickness design must allow for corrosion and for manufacturing tolerances on the thickness of the steel (or the centrality of the hole within the pipe). ■ The pipe must resist hydrostatic collapse due to the external pressure of sea water more on this later. ■ The pipeline must resist bending due to self-weight or environmental loading. ■ It must resist running buckles. This is an effect where a single imperfection (e.g. some ovality) can allow hydrostatic collapse to start and to run both ways along the pipeline until it is all flattened, or runs into shallow water. The material needs to be strong enough to resist this, or must have thick buckle arrestors at intervals along the pipeline. ■ If the pipe is to be reeled, it needs to be fairly thick to avoid local wrinkling on the reel. ■ In some circumstances the pipeline may need a thicker wall to increase its self weight to ensure that it remains stable on the seabed - more on this later. ■ Fatigue can occur due to wave and current motion on risers and pipeline spans. ■ In manufactured bends, allowance needs to be made for thinning of the wall during the bending process. ■ As shown in the figure, where a pipe is attached to a stiffer fitting, this can induce a stress concentration which may require local thickening of the wall to give a proper transition.

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THICKNESS FOR PRESSURE

tmin = ƒ Where

( pi − pe ) ⋅ D 2 ⋅ A ⋅σ y

+ C A + t tol Corrosion allowance

Resist bursting

ƒ D = Outside pipe diameter ƒ t = wall thickness ƒ A = 72% or 60%

ƒ Pipe standards ƒ API 5L ƒ ISO 3183

External pressure, pe

Manufacturing tolerance

Internal pressure, pi

The wall thickness needed for pressure containment is found using the above equation. Where: ■ t min = minimum wall thickness ■ pi and pe = internal and external pressures (Normally, p is defined as the difference between the maximum internal pressure and the minimum external pressure) ■ D = outside diameter ■ A = design factor (traditionally 0.72 for pipelines and 0.6 for risers, which sets the peak hoop stress to 72% and 60% of yield respectively) ■ σy = specified minimum yield stress for the material (see next section) ■ τtol = negative manufacturing tolerance on wall thickness (typically 1 mm or 1.5 mm (40thou to 60thou) for welded and 12.5% of nominal thickness for seamless for ISO 3183) ■ CA = corrosion allowance, typically 3 to 6 mm (1/8in to ¼in) Having found the minimum thickness, the nominal thickness is found as the next standard pipe thickness above this (taken from API 5L or ISO 3183). However, when purchasing long lengths of pipe (hundreds of kilometers or miles), it can be more economical to manufacture specials using the minimum thickness.

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COMBINED LOADS ƒ Equivalent stress

σ eq =

(σ

Lay tension, pressure and thermal forces cause axial stresses

2 h

+ σ l2 − σ h ⋅ σ l + 3 ⋅ τ 2 Self weight or current causes bending (axial) stresses

)

Internal pressure differential causes hoop stresses

The above equation calculates the equivalent stress using Von Mises method. Where: ■ σeq = equivalent stress ■ σh = hoop stress ■ σl = longitudinal (axial) stress ■ τ = shear or torsional stress Where we have loads in different orientations we need to use a yield method, such as Von Mises to combine stresses to determine an equivalent stress. The diagram above shows an example of a pipeline spanning across a gap, causing bending. The hoop stress induced by the internal over-pressure is orientated in the circumferential direction around the pipe. The residual lay tension or axial forces produce tension or compression in the pipe wall. This must be added to the bending stress, which is also orientated axially along the pipe producing a tensile or compressive stress at top or bottom at different positions along the pipe (hog or sag condition). We can normally ignore the shear stresses in pipeline analysis since these do not occur at the same point around the circumference as the peak axial forces. It is uncommon to have torsional stresses in rigid pipelines.

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INCREASED WALL FOR RISERS ƒ Drop riser stress level by 25% at platform ƒ Hoop stress down from 72% to 60% of yield

ƒ Stronger section of adjacent pipeline ƒ DNV 500 m (1640ft) ƒ US codes 152 m (500ft)

ƒ Greater consequence in event of failure ƒ Personnel safety As already mentioned, close to the platform or at the landfall, the hoop stress levels are typically reduced from 72% to 60% of SMYS. Some codes also require a stronger section of pipeline within a certain distance of personnel. The distance varies with the code – the Norwegian DNV is further than that for API. The British PD code has no specified requirement. In very deep waters of 1000 m (3300ft) or more, perhaps even the DNV requirement should be increased: bubbles from a gas leak may be carried some distance by sea currents towards the platform. This is in order to give an added margin of strength and therefore an increased factor of safety due to the proximity of people.

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SURGE Pressure wave backs up pipeline at speed of sound Valve

Moving fluid

Stationary fluid

ƒ Valve closure ƒ Fluid stops against valve whilst fluid behind still moving ƒ Fluid compresses ƒ Pressure wave backs up pipeline as moving fluid meets stationary fluid When valves are closed, a pressure wave is set up in the pipeline. The effect is sometimes seen in the domestic setting with copper pipes and is known as ‘water hammer’. The celerity (transmission velocity) of the pressure wave is the speed of sound in the product.

SURGE PRESSURES ƒ Joukousky equation ƒ Where: ƒ ƒ ƒ ƒ

ΔP = ρ ⋅ α ⋅ V

ΔP = change in velocity ρ = density of oil α = speed of sound in oil = 1300 m/s (=4265 ft/s) V = velocity of oil prior to shut-in

ƒ Slow closure of the valve ƒ Closure time longer than wave travelling to pipeline end and back

ƒ Allow 10% internal design pressure Maximum surge value is given by the Joukousky equation. ‘Velocity of oil’ can be replaced by ‘change in velocity’ for cases of partial valve closure. It is apparent that lower fluid velocities give lower surge pressures.

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The pressure wave resulting from a valve closure travels back up the pipeline. reflected at the pipeline end and travels back down the line to the valve.

It is

The surge pressure can be greatly reduced by slow closure of the valve. If the valve is closed slowly, particularly if the closure time is greater than the time required for the surge wave to travel to the pipeline end and back, the total overpressure is reduced. To avoid increasing the strength of the pipe excessively, it is common to allow 10% extra design pressure and slow the rate of valve closure. Closure time may be 2 minutes or more.

WALL THICKNESS FOR BURST SUMMARY ƒ ƒ ƒ ƒ ƒ

Various influences Thick enough for pressure Bending during installation and at spans Risers and landfalls Surge pressures

Any questions?

The wall thickness design of a pipe starts off by picking a minimum thickness for pressure containment and then checking for other loading – particularly bending – during installation or if spanning is expected. In some countries, the wall thickness design of pipelines is prescribed in their national legislation.

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WALL THICKNESS FOR COLLAPSE

HYDROSTATIC COLLAPSE ƒ Local buckle in pipeline due to external pressure ƒ Increases with external pressure and ovality ƒ Resisted by wall thickness and yield strength

Deep water pipelines can often have periods when the external hydrostatic water pressure exceeds the internal pressure. The governing criterion for wall thickness and material grade can be resistance to collapse (due to external loads) rather than resistance to bursting (due to internal loads).

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COLLAPSE CRITERIA ƒ Characteristic resistance for external pressure pc is given by

(pc − pel ) ⋅ (pc2 − pp2 ) = pc ⋅ pel ⋅ pp ⋅ fo ⋅

D t

(DNV OS-F101)

Where: ■ D = diameter of pipeline ■ fo = pipe ovality = (Dmax - Dmin)/D ■ pc = characteristic resistance pressure to collapse of pipeline ■ pel = elastic collapse pressure for a perfect tube ■ pp = plastic collapse pressure for a perfect tube ■ t = wall thickness Collapse depends on ovality, caused by fabrication tolerances and subsequent handling. For example, on reel barges, the pipe is deformed during storage and installation. External collapse of thin walled pipes is primarily driven by the elastic properties of the steel. Ovalisation of the pipe results in the hydrostatic forces on the flat sides being much larger than the hydrostatic forces on the ends. This creates moments within the pipe wall that tend to increase the ovalisation. When elastic and plastic resistance to this ovalisation is overcome, a runaway flattening of the pipe occurs. The above criterion is taken from DNV OS-F101 Submarine Pipeline Systems 2000 (commonly called DNV 2000). The characteristic resistance is given by solving the above equation (which is equation 5.18 in the DNV code) for external overpressure of an oval pipe. This is essentially the same approach as PD 8010, although the inherent safety factor is different, the ovality (fo) is defined differently and the code has a less conservative lower limit.

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ADD BENDING AND COMPRESSION ƒ Hydrostatic collapse made worse by bending and compression ƒ Criteria from DNV OS-F101 2

2 2 ⎛ ⎛ Sd ⎞ ⎞⎟ ⎛ ⎛ pe ⎞ ⎞ Md ⎜γ γ ⎟ ⎜ ⎟ + γ SC γ m ⎜⎜ ⎟ ⎟ + ⎜ γ SC γ m ⎜ p ⎟ ⎟ ≤ 1 ⎜ SC m α c M p α S ⎝ c ⎠⎠ ⎝ c p⎠ ⎠ ⎝ ⎝

ƒ Two critical combinations ƒ Installation - high external pressure with bending ƒ Operation - high thermal axial forces Where: ■ Md = design bending moment ■ Mp = bending moment capacity ■ Sd = design axial compressive force ■ Sp = axial force plastic capacity ■ pc = characteristic collapse pressure ■ pe = external overpressure ■ αc = flow stress parameter ■ γm = partial factor for material resistance ■ γSC = partial factor for safety class The onset of collapse is exacerbated by bending and axial compression. Critical conditions are: ■ during pipelay when both the external pressure differential across the pipewall and the bending are high ■ during hot operation when the axial compressive loads can be high This is equation 5.24 given by DNV OS-F101 for pipes subjected to bending moment, effective axial force and external overpressure.

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DIFFERENT FORMULAE ƒ Conflicting empirical formulae for low D/t ƒ Safety factors not always explicit ƒ No agreement between API 1111 and DNV OS-F101

ƒ Bending during laying operations 16000 14000

Water depth m (ft)

12000

8000 6000 4000

Comparison of existing collapse prediction methods

2000

Because it is only recently that pipelines have been laid at extreme depths, some codes do not define the method for calculating collapse pressure. There are various formulae available for predicting the collapse of pipe. As illustrated in the figure above, although there is good correlation between the equations in the shallower depths, there is significant variation in the predictions in the deep water, low D/t region. Even the use of the latest API 1111 and DNV OS-F101 codes results in the selection of different wall thicknesses. Assessment of the additional bending during installation needs to be included along with the response behaviour of the particular laybarge chosen.

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CASE STUDY - BLUESTREAM ƒ Russia to Turkey, Black Sea, twin pipelines ƒ Depth: 2150 m (7054 ft) ƒ Diameter: 610 mm (24 in) ƒ Wall thickness 31.8 mm (1.25 in)

ƒ Experimental work to confirm collapse behaviour

As a consequence of concern regarding the collapse behaviour of thick walled pipelines, the Bluestream project undertook experimental work to confirm the collapse behaviour for their specific application.

BLUESTREAM SOLUTION

Comparison of Existing Collapse Prediction Methods 16000

Water depth m (ft)

14000 12000

8000 6000 4000

Bluestream design case

2000

D/t for Bluestream is 19.182 at maximum water depth of 2150 m (7154ft). The selected solution indicates that the more conservative predictions may be more appropriate in deep water. An allowance must always be made for the installation stresses (bending, spanning and axial) in addition to the pure collapse pressures for the line once installed at depth.

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HYDROSTATIC COLLAPSE SUMMARY ƒ Causes of hydrostatic collapse ƒ External overpressure and ovality of laid pipe

ƒ Resisted by ƒ Wall thickness and yield strength of steel

ƒ Additional considerations ƒ Bending and axial compressive forces

ƒ Different formulae and approaches ƒ Bluestream used testing

Any questions?

We have looked at the causes of hydrostatic collapse which are principally the external overpressure of the pipeline during laying when there is no counterbalancing internal fluid pressure. However, the ovality of a laid pipeline has a major influence on the pressure needed to initiate collapse. The collapse is resisted by increasing either the wall thickness or the yield strength of the steel. Since such buckles are most likely to occur during laying, some additional considerations must be allowed for. There are stresses induced in bending (such as at touchdown for S, J-lay or Reel lay methods) and axial compressive forces again due to hydrostatic pressures. We have shown that different formulae give different solutions in terms of D/t especially at depth. The Bluestream Project used a conservative formula backed up by testing of the pipelines. The consequence of the initial collapse results in a local buckle. However, this can turn into a running buckle which zips along pipeline until it reaches shallow water or a stiffer section of pipeline. The common way to provide this extra stiffness is to fit buckle arrestors at regular intervals.

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RIGID STEEL PIPE MANUFACTURE

LINEPIPE OPTIONS ƒ Rigid steel pipe manufacturing methods ƒ Seamless ƒ Used for pipework - smaller diameters and thicker walls

ƒ HFI ƒ High frequency induction welded pipe ƒ Continuous process from strip steel

ƒ SAW ƒ ƒ ƒ ƒ

Submerged arc welded pipe Usually UOE process to form pipe Three-roller bending of plate for larger diameters Spiral weld pipe for larger diameters from strip steel

ƒ Three roller bending and spiral welded pipe There are three methods of manufacturing rigid steel pipe for the oil and gas industry. These are seamless, HFI and SAW. Seamless pipe is commonly used for smaller diameter lines subsea, especially for the reel lay method where a thick wall is advantageous. It is also often used for manufacturing process pipework in refineries where the pipe needs to span between supports. A second method uses continuous steel strip to form pipes. High frequency induction (HFI) welding effectively limits the thickness of pipe wall and so it cannot be used to make the thicker pipes. The width of the steel strip also limits the maximum circumference of the pipe. In USA, the term electric resistance welding (ERW) is used instead of HFI. Strictly speaking, this is a similar process using copper anodes to deliver the current. It is still in use for the manufacture of small structural hollow sections – both square and circular up to 6in (150 mm) – but which is prohibited for use on hydrocarbon pipelines. There are three different types of submerged arc welding (SAW) processes used to make line pipe. The UOE method is when a plate of steel is first formed into a U shape, then

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rounded into an O and welded, and then finally expanded (E) to form the finished pipe shape. Maximum plate dimensions and the forming mills limit the diameter of pipe that can be made using UOE. When the diameter needs to be bigger than that commonly used in oil and gas (but often required by the water industry), a similar SAW process can be used. The plates are curved into the pipe shape using three-roller-bending and then the short pup sections are welded together to form the 12 m (40ft) long linepipe. An alternative SAW method forms the strip into a spiral (just like a cardboard tube) and can make any diameter of pipeline. However, it is not often used for offshore hydrocarbon lines because of perceived problems with tolerances and subsequent forming of the field butt welds close to the diagonal seams. Additionally, there is much more weld required than for any other method and inevitably some must be at the bottom of the pipe when laid. Intelligent pig inspections may not identify all downstream weld defects because the sensor may skip over the frequent beads.

SOURCE OF MATERIALS

Iron ore

Smelter Pig iron Steel ingot

Rolling

Blast furnace Vacuum degassing

Strip mill Hot billet

Steel strip

Plate mill Steel plate

Seamless mill

HFI pipe mill

UOE pipe mill

Seamless pipe

HFI pipe

UOE (SAW) pipe

The above diagram shows the routes for the materials from smelting iron ore, to making steel, to forming the steel ingot into plate and strip, to the formation of pipes. Modern mills use vacuum degassing method to remove gas from the steel whilst molten. The alternative is to repeatedly roll an ingot or to cast the steel directly as a plate. These methods are still undertaken at older facilities. Note that only the seamless method is classed as hot-forming. The other two processes use steel strip or plate which has been pre-rolled to the correct thickness. This improves the pipe wall tolerances though it means that a seam weld is needed.

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MANUFACTURING METHODS

Wall thickness in mm (inch)

1. Seamless 2. High frequency induction (HFI) welded 3. UOE or submerged arc welded (SAW) 35

1¼

30

1

25

1

20

3

¾

15

½

2

10

¼

5 0 0

250

10

500

20

750

30

1000

40

1250

50

1500

60

1750

70

Outside diameter in mm (inch)

The choice of pipe manufacturing method is primarily dependent on pipe size and wall thickness. The above graph shows approximate areas of diameter and wall thickness available from each method. All three methods can produce the high standards of pipe necessary for offshore pipelines. In areas of capability overlap, cost is usually the prime driver in selecting the manufacturing method, and the usual ranking is HFI as lowest cost, then SAW, then seamless. Some mills extend the range of diameters and wall thicknesses which can be achieved by each of these methods. The graph is a guide only on typical sizes supplied worldwide. Some plants can produce thicker walls – for example, Corus SAW mill can handle up to 50 mm (2in) and HFI pipe trials have been made at the Welding Institute up to 25 mm (1in).

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COMPARISONS ƒ Seamless ƒ Clean - lamination-free ƒ Eccentricity ƒ Thick

ƒ HFI ƒ Successor to ERW (electric resistance welding) ƒ Better control of thickness in strip

ƒ SAW ƒ Thicker wall than HFI ƒ Good control of plate thickness Seamless has the advantage of no weld and tends to be a “clean” steel (without laminations), suitable for use on sour duty where hydrogen-induced cracking might otherwise be a problem. Due to the manufacturing process, the hole can be eccentric, leading to a requirement for greater wall thickness tolerances (API 5L permits 12.5% rather than 5% for HFI or SAW pipe). Whilst it can be made very thick, this can lead to less than 12 m (40ft) joint lengths in the larger sizes simply due to the mass of steel within the ingot. This is the only method to form the pipe from hot steel. The other two methods have laminations embedded during the rolling process within either the steel strip or plate. They form the pipe from essentially cold steel and have an axial weld. HFI (High Frequency Induction) is the most recent process, and produces low cost, high quality tube from strip. SAW pipe is also known as seam welded and UOE. With HFI and SAW, control of the thickness of strip or plate is better, but the seam needs careful checking since the highest stresses are normally in the hoop direction.

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SEAMLESS PIPE MANUFACTURE

The seamless pipe manufacturing process is generally used for small to medium diameter pipe. The process is as follows: ■ Heat cylindrical billet in furnace ■ Billet passes through rollers and is pierced to form central hole (see picture below) ■ The pipe is further formed with a central mandrel to produce the inside diameter ■ A stretch reducing mill is then used to obtain final pipe dimensions ■ The pipes are rotated as they are allowed to cool before final NDT (NonDestructive Testing), pressure testing and inspection.

3-ROLL PIERCER

106

Overview of pipeline engineering

By angling the three rollers on the diagonal, the hot billet can be rotated to form a cylinder at the same time as it is being forced onto the piercer. The rapid speed of pipe manufacture is determined by the rate of cooling of the billet.

MANNESMAN SEAMLESS - VIDEO

The Vallourec & Mannesman plug rolling mill produces seamless pipes in sizes between 177 mm and 355 mm (7in and 14in) diameter with wall thicknesses of between 6 mm and 30 mm (¼in and 1¼in). The video shows the manufacture of up to six strands of tube-making rounds using continuous casting methods from the liquid steel. These are 175 mm, 225 mm or 270 mm (6.9in, 8.8in or 10.6in) in diameter. These are cut to length and delivered to the pipe mill. ‘Centred’ billets (for handling) up to 4.7 m (15½ft) long and 2.1 tonnes in weight are first preheated to about 700°C (1290°F) before placing in the rotating hearth furnace. Here, they are further heated to around 1280°C (2340°F) and soaked to ensure optimal heat distribution through the cross section. Hot billets are removed at 30 s cycles and sent to the rolling mill, where they are pierced using a die and helical rollers. This process forms the hollow tube and elongates the bloom by five-fold. From here, the plug rolling mill reduces the wall thickness and the reeler smoothes the inside and outside faces using helical rollers. A further reheating process to 900°C (1650°F) and descaling is required before the bloom is sent to the 10 stand sizing mill, where the correct diameter is formed. The pipe is then cooled and straightened. Heat treatment may be used to attain the finished hardness of steel. NDT testing, inspection and marking the now-cut pipe ensures the quality of the finished product. Other treatment such as coating with polyethylene, threading or upsetting of one end (not shown) may be required prior to delivery to the client.

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HFI WELDED PIPE PROCESS

High frequency induction (HFI) welded pipe is a continuous manufacturing process as follows: ■ Coil is trimmed to the correct width and individual coils are flash-welded together ■ The coil is then rolled into a tube using forming mills ■ The tubular shape is induction welded and ultrasonically tested online ■ The weld bead is removed using planes when hot so the finished weld is not visible ■ The pipe is cut to length and may be passed for further processing to a stretch reduction mill depending on size required Whilst not shown on the above diagram, there are storage devices prior to the forming mill that allows the plate preparation to continue independently of the welding, so that stopping one does not immediately stop the whole line.

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FINISHED FORMING

Smaller diameter pipe is processed slightly to its finished diameter, wall thickness and length in the standardising or stretch reducing mill. The finished pipes are identified and weld position highlighted. The pipe is hydraulically tested. This same process is used to manufacture circular and rectangular hollow steel sections for buildings.

CORUS HFI PROCESS - VIDEO

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The video follows the manufacture of line pipe in the 20in mill in Hartlepool through the following stages: ■ Joining of steel coils to form a continuous strip ■ Forming before welding ■ Welding and NDT (non-destructive testing) ■ Heat treatment of the HAZ (heat affected zone) ■ Cutting into lengths ■ Quality of the line pipe is recorded by an individual number on each section, ensuring traceability The photograph above shows the continuous length of pipe being cut into standard 12 m (40ft) lengths.

SAW PROCESS : UOE FORMING

Submerged arc welding (SAW) permits thicker plate to be joined than HFI. Generally used for large diameter pipes, the first half of the UOE process consists of the following: ■ Plate edge preparation and pre-forming ■ Rolling (or die form, e.g. UOE) to form cylinder as per the picture below ■ Edge closure and tack weld seam

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U PRESS

Tags have been attached for the subsequent welding and the plate width is trimmed to the correct circumference. The edges are crimped to help with further processes. It is then bent in the U press using massive rams first to push down, and then rams either side of the side rollers are brought together to complete the first forming operation. A second press (not shown) finalises the forming of the pipe into the O shape, at which stage the joint is tack-welded.

SAW WELDING

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The pipe is welded using granular flux piled around the two edges of the pipe. With thicker plate, it is common for two passes of SAW. The first is undertaken on the inside of the pipe. The second (as shown above) is with the units on the outside of the pipe. (A double V shape weld preparation is needed for this at the earlier edge trimming stage.) The picture shows the pile of white granular flux piled onto the joint. Surplus flux is being vacuumed off to the right and the still hot, welded seam is revealed.

SAW PROCESS: NDT AND EXPAND

The remainder of the SAW process is as follows: ■ Initial NDT radiographic examination of the welds ■ Mechanical expansion ■ Hydraulic testing ■ Further NDT of the welds including ultra sonic examination and radiography ■ Heat treatment may be used as necessary ■ Machine ends The following are pictures of the ultrasonic inspection and the mechanical expander.

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ULTRASONIC INSPECTION

The weld quality is carefully checked by automatic ultrasonic inspection. A pass/fail is determined automatically by computer. inspection.

Any defects are flagged for

MECHANICAL EXPANSION

Mechanical expansion brings the diameter to tolerance and also improves the physical properties of the steel. This unit expands the pipe in steps down its length.

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SEAM WELDED PIPE MANUFACTURE VIDEO

The CORUS video showed SAW seam-welded pipe manufacture. Points to note are: ■ Steel plate arrives at the mill and is carefully prepared for forming. ■ Tabs are added along with a unique number, for traceability ■ The plate is formed into a pipe ■ The welding process begins with a tack weld along the seam before the internal and external SAW welds are completed in a single pass each. ■ At each stage the integrity is checked with ultra-sound. ■ The pipes are then expanded mechanically to the correct size and to within the correct tolerances. The photograph above shows the etched micrograph of the submerged arc weld with the internal and external passes (the pipe must be rotated so both can be executed from above). The heat affected zone (HAZ) is also clearly seen in the plate metal to either side of the welds.

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OTHER MANUFACTURING METHODS ƒ Three-roller bending ƒ Large diameter / thick wall ƒ Short drum lengths ƒ SAW seam and butt welds

ƒ Spiral pipe ƒ Continuous process ƒ Internal and external SAW ƒ Low pressure in water industry

There are other methods of manufacture but these are not commonly used for oil and gas pipelines offshore. When the pipe diameter becomes large – 1066.8 mm (42in) and above in some plants – or the wall thickness is excessive, it is necessary to roll plate longitudinally using three roller bending techniques. These can then be connected using multiple SAW welds and the short drum lengths connected with butt welds. Spiral pipe is commonly found in the low pressure water industry and to a limited extent, for land-lines, where repairs can more easily be undertaken. Like HFI, it is a continuous process but larger diameters can be manufactured. The angle of the machine is adjusted to suit the width of coil steel and pipe size.

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STEEL PIPE MANUFACTURE SUMMARY ƒ Rigid steel line pipe ƒ Source of materials ƒ Hot billet, strip or plate steel

ƒ Manufacturing methods ƒ Seamless ƒ HFI ƒ UOE

ƒ Water industry large diameter pipe ƒ Three-roller bending and spiral pipe

Any questions? Line pipe for subsea usage can be rigid or flexibles. We will look at flexibles in a later module. Here we examined the three common manufacturing methods for rigid steel pipe. They each require a different form of steel as input. Each has a different range of diameter and wall thickness. The tolerances achieved by each method are also different. We mentioned two other methods for the manufacture of larger diameter, low pressure lines used by the water industry.

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BUCKLES

WHAT ARE BUCKLES? ƒ Scope for confusion with the term, ‘buckle’ ƒ Three pipe failure modes ƒ Local buckle ƒ Caused by hydrostatic collapse and/or bending

ƒ Strut buckle ƒ Lateral or upheaval buckle, due to internal pressure and temperature rise

ƒ Running buckle ƒ Initiated by local buckle, driven by hydrostatic pressure

ƒ Two resulting conditions ƒ Wet or dry ƒ Depends on whether there is leakage

Just about everything the pipeline engineer fears may go wrong with his pipeline tends to be called a buckle, so there is plenty of scope for confusion. There are three distinct mechanisms and two end results: ■ local buckle: an example of a local buckle would be the crease and hinge caused by bending a copper central heating pipe too far. Local buckles are caused by bending in this way and can be exacerbated by hydrostatic pressure ■ running buckle: we have already described running buckles as the complete flattening of the pipe due to hydrostatic pressure. They need an initiator such as a dent or a local buckle to start them off, but thereafter the energy comes from the water pressure ■ strut buckle: an example of a strut buckle is the bow caused by pushing together the ends of a ruler. This type of buckle occurs in both lateral and upheaval buckles in pipelines where the compression forces are induced by the internal pressure and temperature rise ■ a wet buckle indicates that there is a hole in the line ■ a dry buckle indicates that there is no perforation of the line

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WHY ARE BUCKLES A PROBLEM? ƒ Combination of ƒ ƒ ƒ ƒ

External overpressure Bending Axial compression Geometric imperfection

Local pipeline buckle

ƒ Pipe wall collapses ƒ Blocking pipe bore ƒ May cause a leak ƒ Wet buckle

Buckles are caused by a combination of various conditions. The main fear in all cases is blockage or rupture of pipes. In the case of the strut buckle, the global bending is not so much of a problem as the fact that it induces high levels of local bending at the mid-point of the buckle, which could induce a local buckle. We will now consider lateral and upheaval buckles in more detail.

EXAMPLE OF LATERAL BUCKLING

The above picture shows a side scan sonar image of a lateral buckle, where a small diameter flowline has snaked as a result of a modest 50°C (122°F) temperature rise.

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A high temperature, high-pressure pipeline laid on the seabed is prone to lateral buckling. Attempts have been made to lay a pipeline in a deliberately snaked configuration to promote multiple lateral buckles so that the strain levels are controlled. However, it is rare that an S-laybarge can achieve the frequency of snaking needed to achieve this (due to the high lay tension).

DESIGN FOR LATERAL BUCKLING ƒ Pipeline on seabed, expanding due to temperature and pressure loads ƒ Can be accommodated during design ƒ Ensure that there are multiple small buckles rather than one big concentrated one

A lateral buckle from a single defect at midpoint

Allowing the pipeline on the seabed to snake due to pressure and temperature loads can realistically be accommodated during design, and had probably been occurring for many years before survey techniques were able to detect and measure it. The key here is to avoid all the expansion being taken out at a single location. Instead, it is preferable to induce large numbers of small lateral buckles along the length of pipe. These would then dissipate the strain harmlessly.

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UPHEAVAL BUCKLING ƒ Buried pipe trying to expand ƒ Due to pressure and temperature ƒ But has nowhere to go

ƒ Insufficient depth of burial ƒ Likely to cause plastic hinge or pipe rupture ƒ Snag for trawling gear Pipeline buckle Uplift

Axial movement ‘fed-in’ by thermal expansion

Initial out-of-straightness

In previous slides, we noted that lateral buckling takes advantage of the lack of constraint in an unburied pipeline. In the case of a buried pipeline, it does not have the ability to snake laterally. Instead the pressure and temperature loads are locked in and the pipeline acts as a coiled spring. The diagram above shows an upheaval buckle where the pipe initially has a slight upward imperfection which becomes amplified by the compressive load. It reaches the point where the forces moving the buckle upwards exceed the overburden offered by the soil. The result is the pipe erupting through the soil and forming a loop. These are typically 5 to 10 m (16 to 33ft) high above the seabed and have a 40 m (130ft) wavelength. The bend at the apex may be so severe as to induce a local buckle and/or rupture. Even if the pipe survives the initial upheaval buckle, the next fishing vessel to cross the location will probably tangle with the pipeline and may break it. When the buckle has been identified and fishermen advised (but prior to rectification), if hooking still occurs, then the fault may lie with the trawlermen. However, it would not be in the oil company’s best interest to sue!

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UPHEAVAL BUCKLING PREVENTION ƒ Restrict pipe movement ƒ Out-of-straightness survey after trenching ƒ Sufficient rockdump and backfill to prevent upward movement ƒ Monitor cover during operation

ƒ Heat exchanger to reduce inlet temperature

If the pipeline to be buried is of a sufficient temperature and pressure to be at risk of upheaval buckling, then it is necessary to prevent the upheaval buckling by design. The techniques are as follows: ■ To conduct an out-of-straightness survey looking particularly for any hog bends (upward bends) in the pipeline profile. ■ Apply sufficient rock dump and backfill to give an overburden on the pipeline sufficient to prevent its upward movement in the first place. It is then necessary to monitor this thickness of rock dump to make sure that it remains in place throughout the pipeline design life. ■ As an alternative, it is possible through process design on the platform or by placement of a heat exchanger spoolpiece on the inlet to the flowline to reduce the inlet temperature and hence the propensity to upheaval buckling.

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BUCKLE PROPAGATION ƒ Propagation pressure ƒ Less than collapse hydrostatic pressure

ƒ Hence once started, buckle ‘zips’ along pipeline

p pr

fy ⋅ α fab ⎛ t ⎞ 2.5 = 35 ⋅ ⋅⎜ ⎟ γ m ⋅ γ SC ⎝ D ⎠ Propagation

Where: ■ D = nominal outside diameter ■ fy = yield strength ■ ppr = plastic collapse pressure ■ t = nominal wall thickness (uncorroded) ■ αfab = fabrication factor ■ γm = partial factor for material resistance ■ γSC = partial factor for safety class The external pressure required to cause a buckle to propagate is lower than is required to collapse the pipe. Hence if the pipe is not designed to resist buckle propagation, any local buckle accidentally introduced will propagate. This is not normally a problem for pipelines installed in shallow water, where wall thickness is governed by internal pressure containment. As water depths increase, buckle propagation design begins to dominate. It is possible to design pipelines to exceed the buckle propagation pressure and design instead to the external collapse pressure with adequate mitigation measures. These include the use of buckle arrestors to limit the damage caused if a buckle is initiated. Since buckles are normally caused during installation, and the worst conditions for buckle propagation also occur during installation when the pipeline is empty, this forms the principal design case. It is normal to design allowing 100% of any corrosion allowance as part of the wall in the analysis because we have a new pipe during installation. During its operational life, the thinner wall (due to corrosion) is not subject to the high installation bending forces.

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PROPAGATING BUCKLE PRESSURE ƒ After collapse is initiated

External pressure MPa (ksi)

ƒ Constant applied external pressure remains ƒ Causing buckle propagation X60 carbon steel, 1% ovality

7010

Collapse Pressure

60 50

Propagation Pressure

8

1. Increased thickness ratio prevents buckle propagation

40 6 30

10

2. Fixed thickness ratio; buckle will propagate until pressure reduces (to very shallow water) D/t

4

1

20 2

2

0 0

10

20

30

40

50

60

This graph compares the collapse and propagation pressures for an API X60 pipe with an ovality of 1% over a range of D/t ratios. For a particular D/t ratio, there will be a maximum water depth that the pipe can withstand. However, if the pipe does start to buckle, we can derive two results from the graph: ■ By tracing from the blue line horizontally to the left, we obtain the increased ratio and thus the wall thickness needed to prevent buckle propagation. ■ By tracing vertically down to the red line below, we obtain the overpressure and thus the water depth to which the buckle will propagate.

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BUCKLE ARRESTORS ƒ Having initiated a local buckle, will the water pressure flatten the whole pipeline? ƒ Buckle arrestors ƒ Most useful during installation

Integral ring buckle arrestor

Concrete weight coating

Grout

Heavy-walled pipe joint integral cylinder buckle arrestor

Grouted external ring buckle arrestor

The onset of a local buckle is most likely to occur under combined load conditions, i.e. when the hydrostatic pressure is combined with bending and axial load. Pipelay is a critical condition when high bending is combined with the hydrostatic pressure. If a local buckle does occur, it will initiate at the location of highest combined load. Once initiated, the buckle can propagate beyond the region of combined loading because the pipe’s resistance to hydrostatic collapse is reduced either side of the buckle by the flattening and increased ovalisation in those locations. Buckle arrestors are commonly used at intervals along the pipeline to limit the propagation of the buckle. A typical pipe wall 19 mm (0.75in) thick may need around 50 mm (2in) thickness to arrest a buckle. These would be located at perhaps 100 m to 500 m (330ft to 1640 ft) centres along the pipeline. The spacing is determined by the method proposed to rectify the buckle - it may be the size of the tensioners on the barge (which are needed to pull the damaged section back on deck). Larger tensioners can recover more flattened (and non-buoyant) pipe, so spacing can be increased. Buckle arrestors will stop running buckles after a local buckle has formed at any time. However, they are most useful during installation when the effects of bending are greatest: the laybarge can stop and recover the flattened section. During operation, however, a major operation is required to mobilise equipment to cut out and replace part of the pipeline.

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SOLUTION TO RUNNING BUCKLES ƒ Allow for ovality, bending and tension ƒ Make pipe sufficiently thick ƒ Insert buckle arrestors ƒ Distance between dependant on barge capability and procedure for recovery

The solution for design against hydrostatic collapse must take account of the ovality of the line pipe supplied and installed, along with the predicted stresses due to bending and tension during pipelay. In deep water, the wall thickness is generally greater than that needed just for the operating and test pressure of the contents. Where buckles may propagate, then buckle arrestors need to be added at regular intervals. The spacing is dependant on the risk assessment and the procedure proposed to recover from a buckle.

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BUCKLES - SUMMARY

ƒ Three types of buckle ƒ Local buckle during installation ƒ Global or strut buckles ƒ Lateral - horizontal ƒ Upheaval – vertical

ƒ Running buckle

ƒ Two conditions ƒ Dry or wet buckles

ƒ Buckle arrestors Any questions? There are three types of buckling that can occur in a pipeline. Local buckles are generated by either a localised hydrostatic collapse or by significant bending stresses. Running buckles result from the propagation of a local hydrostatic induced buckle. Global buckles occur over long sections of the pipeline. Lateral and upheaval buckles can both be categorised as global buckles and result from the expansions associated with the thermal and pressure loads applied to the pipeline during operation. Lateral buckles occur in the horizontal plane with pipelines resting on the seabed surface. They are less severe than upheaval buckles as longer sections of the pipeline are able to deflect laterally. Upheaval buckles occur when there is insufficient soil on top of a buried pipeline to restrain the out-of-plane buckling deflections resulting from expansion. The pipeline buckles over a relatively short length and so the strains are concentrated into a smaller section of the pipeline than in lateral buckling. Local buckles, running buckles and upheaval buckles are considered as failure modes and should be avoided by design. Lateral buckles may be acceptable provided that they are are not too severe.

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PIPE DESIGN - SIZING - SUMMARY ƒ Diameter sizing ƒ Wall thickness determination ƒ Bursting and hydrostatic collapse

ƒ Methods of rigid steel pipe manufacture ƒ Seamless, HFI/ERW, UOE/SAW

ƒ Buckles ƒ Combined bending, external overpressure, compression and geometric imperfections ƒ Local, strut and running

Any questions? We have introduced the principal concepts for subsea pipeline design for diameter and wall thickness. The main manufacturing methods for rigid steel pipelines have been described. The causes and means of prevention of different types of pipeline buckle have been explained.

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EXPECTATION

EXPECTATION ƒ Material selection ƒ Strength ƒ Corrosion resistance ƒ Normally bare steel inside ƒ Corrosion allowance

ƒ Corrosion inhibitors and chemical additives ƒ Corrosion resistant alloys (CRAs) ƒ Clad and lined pipes ƒ Linepipe supply and welding

ƒ Titanium and composites – not for linepipe ƒ Risers, topsides, gratings and protection covers

We examine what limitations there are in using carbon steel for pipe walls. Selection of the material is based on a combination of strength as well as corrosion resistance. We examine what benefits there are in using inhibitors or other chemical protection. Because pipelines are normally operated without an internal lining, we need to carefully examine the effects of corrosion and find when we should select a more expensive corrosion resistant alloy. Clad and lined pipe construction may prove cheaper to purchase but welding can be more difficult. Although not used for linepipe, the use of titanium may be used for certain sections of risers. Similarly, composite materials are used for liners and topsides pipework as well as walkway gratings and wellhead protection covers. Use of such materials may be more commonplace as their properties become better known to designers and installers.

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SELECTION FOR STRENGTH

WHAT PIPE MATERIAL? ƒ Start with carbon steel ƒ Need to look for: ƒ Yield strength ƒ Corrosion resistance

Question coming 2 slides ahead … please look up from notes

In selecting a pipe material, there are two major factors we are looking for: these are its yield strength and its corrosion resistance. The technique is to start with common carbon steel and escalate to more expensive solutions in order to meet the yield strength and corrosion resistance requirements. By ‘common carbon steel’ we mean one containing between 0.2% and 0.3% carbon. This is slightly more than mild steel, which has less than 0.15% carbon. Weldability is better with lower carbon content. Steels with a carbon equivalent more than 0.4% normally require heat treatment.

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YIELD STRENGTH

Stress, σ MPa (ksi)

Elastic

Ultimate stress

Plastic range

517 (75)

Necking

413 (60)

SMYS Elastic limit Linear E=σ/ε 0

0 0.2 0.5

Work hardening Plateau of ductility

Strain, ε (%)

Failure (breaks)

15 to 20

What do we mean by yield strength? This is illustrated in the graph above for grade X60 steel pipe. The vertical axis shows stress and the horizontal axis shows strain. If you imagine cutting a cuboid sample out of the wall of the pipeline and stretching it, its behaviour would reflect the above graph. As you first applied the load, it would stretch (imperceptibly) and if the load were released, the sample would return elastically to its original size, following the line of Young’s modulus, E. If the stress remains below the elastic limit then the material returns to its original state when the load is released, and there is no permanent deformation. However, if you applied a load past the elastic limit, the material would stretch plastically. Releasing the loads within this zone would leave the sample stretched and permanently deformed. Applying further load would cause the sample to ‘neck’ and finally to break. Linepipe steels can be classified by their specified minimum yield strength (SMYS) and ultimate strength (UTS) points. The API 5L code (commonly used for line pipe) defines SMYS as the stress needed to achieve 0.5% strain. Some structural codes define it at 0.2% of recoverable strain (parallel to the linear elastic line). The ratio of yield to ultimate stresses is set at a maximum of 93%. Typically, the strain reaches between 15% and 20% before breaking. In design, we generally seek to keep the pipeline steel in the region below SMYS. If it goes past this, we are into strain-based design. In the example above, the yield stress of the material is 413 MPa (megapascals). This corresponds to 60 ksi (thousand pounds per square inch) in imperial units and is termed grade X60, as defined in API standard 5L. In ISO 3183 (the international linepipe code), the equivalent steel grade is L415.

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CHOICE OF GRADE ƒ Most pipelines in X52 to X65 range ƒ Available from grades A, B through to X120

ƒ Why not go for very high strength steels and save on weight of steel? ƒ Ductility ƒ Plastic deformation

ƒ Weldability ƒ Avoidance of heat treatment

ƒ Fracture toughness ƒ Accept defects with no brittle failure

Given that steel costs about the same per tonne regardless of grade, why should we stick with X65 and not go for twice the strength? The answer to this lies in terms of the ductility, toughness and weldability of the steel. ■ ■ ■

Ductility is the ability of the material to deform plastically before failure. Weldability means that the pipe can be welded together aboard the laybarge without the need for heat treatment. Fracture toughness is the ability of the material to accept defects (such as weld inclusions) without these leading to brittle fracture.

As a result of these requirements, most pipeline steels come in the X52 to X65 range, although higher grades (X70 to X100) and lower grades (X42 or even grade B) are available.

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SELECTION FOR STRENGTH SUMMARY ƒ Design based on yield stress ƒ Maintain pipeline within elastic region ƒ Up to 5% strain

ƒ Reel-lay and J-tube installation exceptions

ƒ Constraints ƒ Ductility, weldability and facture toughness

ƒ Typical API 5L grades: X52 to X65 ƒ Yield 358 MPa to 448 MPa (52 ksi to 65 ksi)

ƒ Equivalent ISO 3183 grades: L360 to L450 Any questions? Most pipeline design maintains the steel within the linear elastic region up to 0.5% strain. Notable exceptions are during construction when the wall is deliberately pushed well into the plastic region during reel-lay and J-tube installation. The main constraints limiting the use of very strong pipe have been described. We usually select grades X52 to X65 that are relatively easy to weld successfully.

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SELECTION FOR CORROSION RESISTANCE

WHAT CAUSES INTERNAL CORROSION? ƒ Three corrosion types: ƒ Sweet corrosion, CO2 ƒ Pitting and general wastage

ƒ Sour corrosion, H2S, ƒ Cracking and deep pitting ƒ Highly toxic ƒ Use ISO 3183 Class C

ƒ Oxygen corrosion (rust) ƒ Water in flowlines ƒ Same as external corrosion – but different solution

Sweet corrosion and sour corrosion come from hydrocarbon conditions. Sweet corrosion manifests itself as pitting and general wastage. Sour corrosion causes cracking in the pipe wall leading to deep pits which may cause leakage. Oxygen corrosion (rust) can come from water injection duty on the inside of the pipe or seawater on the outside. Having said that, it is very rare to experience oxygen corrosion on the outside of a subsea pipeline because it is protected by a cathodic protection system (see ahead). Note that ISO 3183 Class C linepipe is specifically for sour service lines. API 5L does not have an equivalent.

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COMBATTING INTERNAL CORROSION ƒ Corrosion allowance ƒ 3 to 6 mm (0.118in to 0.236in)

ƒ Use an inhibitor ƒ Coats pipe wall

ƒ Use a CRA ƒ 316 stainless ƒ Duplex ƒ Nickel alloy

ƒ Use a liner/cladding ƒ Methanol or glycol ƒ ‘Mops up’ water In designing for internal corrosion, we use common carbon steel as a starting point and escalate from there to find a solution. A typical escalation sequence is as follows: ■

■ ■

■

Apply a corrosion allowance of 3 to 6 mm (0.118in to 0.236in) of sacrificial steel. If the duty requires much more than 6 mm (¼in) of steel, it is probably too aggressive and there is a risk of isolated pits penetrating the wall during the life of the pipeline. The use of an inhibitor might therefore be justified. Corrosion inhibitors can be added to the flow. They provide a protective coating to the inside wall of flowlines and are developed to suit the individual application. Corrosion inhibitors typically slow the rate of corrosion by a factor of 10. If inhibitors would still not be sufficiently effective, use a corrosion-resistant alloy (CRA) - such as a stainless steel or nickel alloy - for the pipe, or line the inside of the pipe with a 3 mm to 5 mm layer of CRA. CRAs tend to have a material cost of three to ten times that of carbon steel and are also two to three times slower to lay due to increased welding times. This results in pipeline costs being up by a factor of three to six, so are not an option to be embarked upon lightly. Polyethylene or glass-reinforced plastic (GRP) liners have been used successfully in water-injection lines as a cladding to protect a carbon steel pipe from oxygen corrosion. However, there are material problems to be resolved (particularly the collapse of the liner) before they are used in hydrocarbon duty. They are considerably cheaper than corrosion resistant alloys, being about double the cost of carbon steel.

Methanol and glycol (for gas pipelines) are added to pipelines to absorb water, binding to it at a molecular level. They mop up free water, preventing it forming acids with any H2S or CO2 present. They are also added for process reasons (to prevent hydrates or wax formation) rather than to prevent corrosion, but if they are present they will enhance the effectiveness of corrosion inhibitors. These additives need to be separated at the terminal and returned to the field. One way of doing this is via a piggyback line, as shown in the above picture.

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CORROSION INHIBITORS ƒ Inhibitor vaporises ƒ Migrates to recessed areas and cavities ƒ Condenses on surface ƒ Ions dissolve in moisture film ƒ Ions form protective film

Pipeline section showing active VCI protection in all three phases : liquid, inter-phase and vapour phase

Corrosion Inhibitor Courtesy: Cortec® Corporation

The slide details the process by which corrosion inhibitors work. However, at the interface of the oil and brine, preferential corrosion can occur to produce ‘tramlines’ along the length of the pipe. There are various methods for introducing corrosion inhibitors to pipeline systems. The main methods are as follows: ■ ■

Continuous Injection - This is the preferred method to give reliable corrosion control. The inhibitor is injected through an injection line at rates from 2 ppm to 100 ppm according to the corrosivity of the fluid. Batch Treatment - This can be used where no injection facilities are available. Usually batched through a pig launcher in a diluted form of diesel/kerosene. Batches normally range from 80 to 400 litres (20 to 100 gal US) per week depending on size of pipeline and corrosivity of fluid.

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CORROSION-RESISTANT ALLOYS ƒ CRA properties ƒ More expensive to purchase than carbon steel ƒ Long lead times – limited worldwide supply ƒ Strength and other properties ƒ Strength, density, thermal expansion and conductivity

ƒ Product composition for selection ƒ Shorter lengths and slower to weld ƒ Common types ƒ 316 stainless, duplex, nickel alloy ƒ Cheapest to dearest – but improved resistance

ƒ 13% chrome difficult to weld Corrosion-resistant alloys are far more expensive to purchase per tonne than carbon steel with the common duplex grade about five times the cost. With a limited number of manufacturers, there are long lead times. A single pipeline project may use a significant percentage of the worldwide supply. Their properties differ with some being notably different from that of carbon steel. Thick wall seamless CRA pipes may only be available in short lengths of 9 m or 6 m (30ft or 20ft) and butt welding operations may take twice as long for duplex as that for carbon steel. Selection of such materials needs careful examination of the product composition. With the presence of H2S, hydrogen-induced cracking of the wall may still occur. Common grades are listed above in increasing cost. However, the most expensive grades are the most resistant to corrosion. For example, grade 316 is only resistant to sweet corrosion, duplex is resistant to sweet and low levels of H2S, whilst nickel alloys resist sweet and high levels of H2S. Some grades are notoriously difficult to weld.

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INTERNAL CORROSION - SUMMARY ƒ Three causes of internal corrosion ƒ Product composition – CO2, H2S, H2O ƒ Different effects – pitting or general loss

ƒ ƒ ƒ ƒ ƒ

Corrosion allowance Chemical injection - inhibitor CRA Cladding – hydrocarbon lines PE liners – water injection line

Any questions?

The product composition provides an indication of the content of the line. With carbon dioxide, hydrogen sulphide or water in the line, it is likely that different forms of corrosion may occur. For low levels of attack, the initial approach of providing additional wall thickness may be sufficient. It is best to use a piggyback line to inject inhibitor before moving to exotic materials such as corrosion resistant alloys. Savings may be made by using the CRA as a cladding inside oil or gas lines. Water injection lines installed using the reel-lay or bundle methods may demand the use of PE liners.

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CLAD AND LINED PIPES

CRA-CLAD FLOWLINES ƒ Combines corrosion resistance of CRA with strength of carbon steel ƒ Thin inner layer 3 mm or 5 mm (⅛in or ¼in) ƒ Metallurgically or mechanically-bonded ƒ Seamless – explosive or cast ƒ UOE – rolled and seam welded

ƒ Care needed at ends ƒ Special welding techniques ƒ Careful alignment tolerances

ƒ Ignore cladding in strength calculations ƒ Young’s modulus and expansion characteristics By using a thin layer of CRA on the inside of a pipeline, it is possible to use a strong carbon steel pipe for highly corrosive product. The purchase cost is less than a thickwalled wholly CRA linepipe and because we can take advantage of the stronger grades of steel, it may result in a thinner wall overall. These pipes are usually limited to flowlines because it is more cost-effective to take out corrosive product at the facility than to clad a whole length of export line.Commonly, the cladding is 2 mm to 3 mm thick on pipelines less than 328.3 mm (12in) and up to 5 mm on larger diameters. A number of techniques have been used to metallurgically or mechanically-bond the inner cladding to the pipe, depending on the manufacturing method and diameter. These include: ■ Rolling of plate ‘sandwiches’, then UOE rolling and welding the layers separately along the seam ■ Explosive bonding followed by rolling, roll bonding for UOE pipes ■ High pressure sintering/diffusion bonding a layer of CRA ■ A layer of CRA being ‘buttered on’ to the pipe as a weld material ■ And even spun casting.

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Post-manufacture heat treatment is needed to restore the properties of the cladding and the carbon steel pipe. Because of the thinness of the cladding, it is important that care be taken with alignment at the ends for the butt welds. In some cases, it is possible to weld the liner and the pipe itself with the same high grade alloy. In this instance, buttering of the weld bevel is required. With other combinations, it is necessary to weld the inner section separately from the outer using different welding wire and techniques. TIG is often used for the cladding and first pass of the outer pipe, and NDT of this is required before continuing with the remainder of the weld. Cladding therefore slows the field weld process considerably, with far higher rates of rejects: it may take three times longer to butt weld clad pipe compared with simple carbon steel.

PLASTIC-LINED PIPE ƒ Internal water corrosion protection ƒ Medium density polyethylene (MDPE) liner PE pipe Steel pipe string Tension

FBE Carbon steel pipe PE liner

Shrink wrap capping CRA

Swagelining die

Field weld

ƒ Joint make-up is time consuming at load-on ƒ Feasible with only 1 joint per 500 m (1640ft) string When steel pipe is to be carrying significant amounts of water, then internal corrosion becomes an issue. This is a particular concern for water injection flowlines with long service lives. One solution is to use a medium density polyethylene (MDPE) liner pipe, inserted into the steel pipeline that seals the steel against contact with the water. The process of lining the steel pipe with the MDPE liner is known as Swagelining, this process is illustrated above. It requires that the MDPE liner has an outer diameter slightly larger than the inner diameter of the steel pipe. The liner is then pulled through the die and steel pipe under tension. The tension through the die reduces the diameter of the liner enough for it to pass through the steel pipe. Once pulled through, the tension is released and the liner attempts to return to its original diameter. This then creates a tight fit between the liner and the steel pipe. To connect two sections of lined pipe together then the connection is made as illustrated above. Two short sections of pipe made from a corrosion resistant alloy (CRA) are welded to the end of each steel pipe joint. A larger diameter cap

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is then placed and welded over the whole joint. The two sections of MDPE are then positioned to ensure the water contents will only contact the CRA pipe sections. The make-up of the joints for plastic lined pipe is a time consuming process, which makes the process uneconomical if using the S-lay or J-lay methods. Reeling has the advantage that the pipe strings are fabricated onshore in 500 m (1640 ft) lengths. It is then possible to swage line these long pipe strings in a single activity onshore, prior to reeling the string onto the spool. This then means only one joint is required for each 500m pipe string. It then becomes viable to use plastic lined pipe for reeling operations. This type of lined pipe has been used on the Foinaven field for the water injection flowlines. The field is west of the Shetland Isles at a depth of between 396 m (1300 ft) and 607 m (2000 ft). The depth meant that the water injection flowlines would have to survive their required 25 year service life without maintenance. Development of the field began in 1996 and 15 km (50000 ft) of 254 mm (10 in) pipe and 2.8 km (9300 ft) of 203 mm (8 in) PE lined pipe were installed by reeling from the Norlift vessel.

PE-LINED PIPE CONSIDERATIONS ƒ Costly connection system ƒ Used with long stalks/strings

ƒ Limits use to reel lay and bundles ƒ Land-based assembly methods

ƒ Used with water injection lines ƒ Better protection than internal epoxy coating ƒ Difficult to assure internal field joint epoxy coatings ƒ Not subject to erosion/wear from particles in water

ƒ Specified by certain clients

The main problem with PE-lined pipe relates to the field joints. It is not possible to continuously coat the whole length of the line and field joints. It is necessary to use a CRA field joint system which is too costly to undertake at every 12 m (40ft) pipe joint. This limits its use to land-based assembly methods such as reel lay and bundles when lengths up to 500 m can be threaded before PE recovery takes place. Nevertheless, it is the only system permitted by leading clients for water injection lines. The alternative is to coat the inside of these lines with either FBE or epoxy

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paint. However, severe corrosion of such lines has often occurred and has been linked to erosion from particles in the water or poor field joint repairs.

CLAD AND LINED PIPELINES SUMMARY ƒ Clad pipe ƒ Corrosive hydrocarbon products ƒ Sweet and sour service

ƒ Thin bonded layer of CRA ƒ Cheaper than wholly CRA

ƒ Difficulties with welding

ƒ PE-lined pipe ƒ Used for water-injection lines ƒ Specified by leading clients

ƒ Limited to reel-lay and bundles because of expensive connections

Any questions? Opportunities to minimise corrosion with corrosive hydrocarbons or water injection lines are provided by cladding or lining the inside of a carbon steel line. Cladding is cheaper than providing linepipe out of CRA but does present difficulties with the butt welds. PE-lining is limited to reel-lay and bundles because of costly CRA connections at the field joints.

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TITANIUM AND COMPOSITES

TITANIUM PROPERTIES ƒ ƒ ƒ ƒ ƒ ƒ

Good strength to weight ratio Relatively low E to strength ratio High proof to UTS ratio Good fatigue performance Corrosion resistance Properties of Ti-6AI-4V annealed rod ƒ ƒ ƒ ƒ

0.2% proof stress 938 MPa (136ksi) Tensile strength 1007 MPa (146ksi) Elongation on 5D 14% Reduction in area 40%

In its pure form, titanium has a comparatively low strength and few applications. However, when combined with other elements to form alloys, the material properties can be greatly enhanced. Titanium has a relatively low elastic stiffness (Young’s Modulus) compared to its strength. It also has a greater spring back in forming and machining operations than steel. One of the main benefits of titanium alloy is very high strength to weight ratios. Components that would otherwise be made in steel can be made using titanium, giving comparable performance at a much lower weight. Titanium alloys have a fatigue performance which is similar to or better than steels and aluminium alloys (compared on a density basis). The fatigue limit is typically 0.4 to 0.6 of tensile strength.

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Titanium has excellent corrosion resistance and so is ideal for offshore applications. It is highly resistant to sea water and brine, oxidising acids, aqueous chloride solutions, wet chlorine gas and sodium hypochlorite.

TITANIUM AND STEEL COMPARISON 1200 160

Ti-6AI-4V annealed Nominal Stress MPa (ksi)

1000

140 120

800

100

X65 pipe steel 600

80 60

400

40 200

0

20 0 0

2

4

6

8

10

12

14

16

Strain (%)

The graph shows how carbon steel has a lower yield than titanium but has approximately twice the Young’s modulus, E. That is to say it is stiffer, and will elongate approximately half that of titanium providing the stress remains below yield.

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TITANIUM

Material Yield stress

Titanium

X65 steel

759 MPa (110 ksi)

450 MPa (65 ksi)

Cycles to failure at 100 MPa (14.5 ksi) Young’s modulus

68

·106

0.4 ·106

110 GPa (16·106ksi) 210 GPa (30.5·106ksi)

ƒHigh cost ƒInformation on: ƒTouchdown point stress joints ƒTaper stress joints ƒAvailable from: www.titaniuminfogroup.co.uk To cope with the demands of the touchdown point, titanium joints may be used. The strength, flexibility, fatigue properties and temperature range are very beneficial compared to steel. The yield stress given above relates to Ti-6Al-4V ELI (ASTM grade 23, UNS N° R56407) used for deep water drilling risers, choke/kill lines, dynamic production/export risers, taper stress joints and fasteners. The standard grade Ti-6Al-4V (ASTM grade 5, UNS N° R56400) yields at 827 MPa (120 ksi) and is used for drill pipe. However, the cost per tonne is 20 to 40 times that of steel – though considerable savings can be made because of the reduction in both the wall thickness and the density of pipe. Note: Jee runs a three day advanced course on materials covering: ■ ■ ■

Titanium GRP Elastomers

Delegates receive a wealth of detail on their properties and applications, sufficient to know when these materials might be useful. See www.jee.co.uk for information.

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HEIDRUN DRILLING RISERS ƒ Tension leg platform ƒ Operational in Norway since 1992

ƒ 20 new well completions ƒ 24 titanium drilling riser joints

ƒ Performed well ƒ Care with TIG welds ƒ Pores limit fatigue life

ƒ 6 month test of composite joint

Titanium drilling riser joints

The Heidrun drilling platform is a tension leg platform (TLP) which operates in a northern area of the Norwegian Sea in 345 m (1132ft) of water. It is the most northerly TLP installed to date. The platform was developed and run by Conoco and Statoil, and has been operating since 1992. The titanium alloy used is Ti-6Al-4V ELI (ASTM grade 23) – ELI has extra low interstitial O, N and H for improved toughness. The joints are 552.3 mm (22in) bore with 22.23 mm (0.75in) wall and 14.685 m (48.2ft) long. These are TIG welded to compact flanges. The joints have a 3 mm (⅛in) internal hydrogenated nitrile liner for wear resistance and external protective layer. Care was needed with welding to limit the size of pore defects which limit the fatigue life. Due to the field’s relatively extreme operating conditions, it became feasible to develop the high pressure drilling riser from titanium and not from the more traditional steel. The high strength to weight ratio of titanium means that the drilling riser weighs 55% that of the steel equivalent. At present, the titanium drilling riser has produced 20 new wells and the inspection of the riser after each retrieval has found no detrimental defects of the titanium material. A number of other developments (Green Canyon, Garden Banks and Neptune) make use of titanium for the taper joint at the base of the riser. There are over 20 years experience with titanium on the Kristin export catenary riser, and they have also been used at Åsgard and Njord. DNV has issued RP-F201 (2002), Design of titanium risers with fatigue guidance (SN curves). Note that successful testing of composite drilling risers (CDRs) has also been carried out at Heidrun between July 2001 and January 2002 during inspection/maintenance of the titanium risers.

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WHAT ARE COMPOSITES? ƒ Solid material comprising fibres or particulates embedded in a matrix ƒ ƒ ƒ ƒ

Wide range of fibres and particulates Wide range of matrix materials Thermoset or thermoplastic polymeric resins Metals and ceramics

ƒ Properties only achieved in final component

Most objects we work with on a day to basis could be considered a composite and made from more than one material. The closest natural composite to the polymer composites being considered today is probably wood. Indeed there are a lot of lessons to be gained from seeing how wood structures are designed and assembled and how they perform in practice. The most important thing to remember about composites is that the final properties are dependent on the manufacturing process and are only achieved after the component has been manufactured.

COMPOSITE MATERIALS BENEFITS ƒ Material ƒ Lightweight ƒ Corrosion resistance ƒ Fatigue performance

ƒ Installation ƒ Ease of handling ƒ Use of hand tools ƒ May eliminate hot work

Composite laminate sheet Picture courtesy of EDO Speciality Plastics

ƒ Others ƒ Thermal insulation, fire, failure mode etc

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The principle benefits that can be derived from the use of composites are listed above. The lightweight properties are more important in weight sensitive applications. Composites are very cost effective where high metallurgy CRA (corrosion resistant alloy) alternatives would be required. The installation advantages are often not appreciated at the start of a project and become more apparent as the labour force progress through the learning curve.

SUBSEA PROTECTIVE STRUCTURES Wellhead protection

Valve cover

Shell Cocoon wellhead protection (fisher-friendly)

Composite materials can be used for many protective subsea structures including wellhead and valve protection. The main value to be gained from the use of composites is weight saving, which can enable substantial savings in installation cost by enabling the use of lowercost lift vessels, or to enable the protective structure to be attached to the flowline during pipe installation. The fabrication cost is competitive with that of conventional steel and concrete technology. The lower material modulus of GRP may impose limitations for some structural applications, for example templates. The purchase cost for GRP is slightly more expensive than that for steel. However, the fabrication and installation costs are much less, making composites very attractive financially.

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TITANIUM AND COMPOSITES SUMMARY ƒ Titanium ƒ High strength to weight ratio ƒ Good fatigue performance and corrosion resistance ƒ Used successfully for Heidrun drilling riser joints

ƒ Composites ƒ ƒ ƒ ƒ

High strength to weight ratio if correctly designed Good fatigue performance and corrosion resistance Good thermal insulation properties for fire resistance Used successfully in subsea protection structures ƒ Reduced weight eases installation

Any questions? Titanium and composites are advanced materials that can have significant benefits when compared to steel. Titanium, although expensive can become a feasible pipe material due to its higher strength:weight ratios, better fatigue performance and corrosion resistance in comparison with steel. Titanium drilling riser joints have been successfully used on the Heidrun riser and to present date have showed no detrimental effects. Composites also are an alternative to steel for some applications. Composites can be designed to have their strength in a principal direction and so can become very efficient for strength to weight ratios. Composite components can also be designed to have good fatigue performance and corrosion resistance for specific applications. Composites are successfully used for subsea protection structures as their lightweight enables the structures to be installed from smaller vessels.

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PIPE DESIGN - MATERIALS SUMMARY ƒ ƒ ƒ ƒ ƒ ƒ

Start with carbon steel and escalate Ensure sufficient yield strength Three types of internal corrosion Methods of combating internal corrosion Clad and lined pipelines Titanium and composites – specialist areas

Any questions?

In summary, material selection aims to satisfy the requirements for strength and corrosion resistance. The technique is to start with common carbon steel and to escalate until you find the solution. Ensure that the effects of internal corrosion are minimised first using corrosion allowance and chemical additives before moving on to costly exotic materials and welding techniques. Titanium and composites are only used in specialist areas.

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EXPECTATION

EXPECTATION ƒ External coatings ƒ Corrosion protection ƒ Concrete for on-bottom stability

ƒ Thermal ƒ Why they are needed ƒ What coatings are available

ƒ Pipe-in-pipe systems ƒ Field joints

ƒ Active heating systems

The previous module defined the size and material for the pipeline. This module examines coatings used on rigid pipelines. Most pipelines have an exterior coating for prevention of corrosion. We explain why this and other external coatings of concrete or thermal materials are sometimes applied, and the types of coatings that are available. For extreme thermal conditions, pipe-in-pipe systems may be necessary. Field joints need to be made quickly - generally a matter of minutes - and coatings which are acceptable for the main linepipe may not be suitable for covering the welds. Where insulation is not enough by itself, some lines use active heating systems to maintain the product above the minimum allowable temperature.

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EXTERNAL CORROSION PROTECTION

EXTERNAL CORROSION AND PROTECTION ƒ Primarily, oxygen corrosion ƒ Rust – pitting and general wastage

ƒ Corrosion-protective coatings ƒ Line pipe first cleaned and shot-blasted ƒ Fusion-bonded epoxy (FBE) ƒ 0.5 mm (20 thou) thick applied to hot pipe

ƒ Polyolefin coatings - PE, PU or PP ƒ 2 mm (80 thou) impact protection over FBE with adhesive

ƒ Coal tar epoxy (CTE) ƒ Older technology

ƒ Field joint cutback – heat shrink wrap ƒ Overlap with factory-applied coating The primary attack on the external surfaces of the pipe is oxygen corrosion. There are two levels of defence - the first is the anticorrosion coating on the pipe. The second is the cathodic protection system. The anticorrosion coatings take the form of fusion-bonded epoxy (FBE) similar to the enamel on cooker hobs, polypropylene coating or bitumen/coal tar epoxy (CTE). CTE is a 6 mm layer of tar with a bonded-in layer of glass fibre. It is now used less frequently in the UK and USA – although it may still found on operational pipelines installed a decade or more ago. In all cases the pipeline is first cleaned and shot-blasted to conform with the Swedish standard Sa2½, according to ISO 8501-1. Sometimes, FBE is then used alone, but it is usually used as a first layer in combination with polyurethane PU, polypropylene PP or polyethylene PE for impact protection. At the field joints, it is common to apply sheets of shrink wrap which bond to the pipe and provide an overlap of 50 mm (2in) or so with the factory-applied coating. A cutback at the pipe-ends of 100 mm to 200 mm (4in to 8in) is needed because the heat from the

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welding operations would damage the coating. This section needs to be protected using a rapidly applied system. With FBE-coated pipe, it is possible to simply shot-blast and spray on a rapid cure epoxy layer at the field joint.

CORROSION COATINGS ƒ Can be used both externally or internally ƒ May be combined with ƒ Thermal insulation ƒ Fire protection

Firetex M89 Epoxy Thermal Barrier

Images courtesy of Leigh Paints

The corrosion coating system is normally used to provide external protection, but some pipelines also require internal protection (for example, water injection and tanker loading lines). This is normally provided by applying an epoxy-type of lining to individual pipes prior to welding, with hand completion at the field joints. The external protection system is often combined with other materials to provide impact, thermal or other benefits.

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COATING MATERIALS ƒ Epoxy powder (FBE) Advantages Excellent adhesion Doesn’t shield CP system

Disadvantages Low impact resistance Poor shear stress resistance

ƒ Tape wrap Advantages Simple application Useful for covering weld areas

Disadvantages Shields CP system Adhesive subject to biodegradation

Fusion-bonded epoxy (FBE) is by far the commonest coating for offshore pipelines. This is typically 0.5 mm (0.040in) thick and is a very smooth hard coating. It is applied by heating the pipe and spraying on a powder. However, FBE does tend to chip when hit and it is often used as the base layer of a multi-layer coating systems. Occasionally, it is used as a single or double application (with no further coatings) in the deep waters of the Gulf of Mexico – careful handling is required to prevent mechanical damage. Nevertheless, it should not be so used at temperatures over 70°C (158°F) when in contact with seawater. Tape wrap has often been used for pipe joints and for the whole length of some landlines. It is quick to apply at butt welds, but other jointing systems with fewer disadvantages (such as shrink wrap coating) have replaced it.

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COATING MATERIALS ƒ Glass reinforced bitumen or coal-tar Advantages Easy to apply - minimal surface preparation Permeable to CP systems

Disadvantages Subject to cracking Coal-tar is carcinogenic Environmental concerns

ƒ Polyolefin coatings (PE, PU and PP) Advantages High corrosion protection Good handling

Disadvantages Limited temperature ranges Poor shear stress resistance

A further two common coatings are shown above. Bituminous coatings were once the standard form of protection but they are now rarely used offshore due to environmental concerns. Thin layers of glass reinforcement tape are embedded into the thickness of bitumen whilst it is still liquid. PE, PU and PP’s temperature and shear resistance disadvantages limit them to being applied as part of a ‘coating system’ often in combination with FBE. PE should not be used for temperatures more than 85°C (185°F) PU can operate up to temperatures of 100°C (212°F) Different types of PP are limited to temperatures less than 75°C to 140°C (167°F to 284°F). The particular cleaning chemical used to degrease the pipe and the grade of FBE may prove to be a problem at temperatures over 110°C (230°F) due to disbondment issues.

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SPLASH ZONE ƒ Riser section of pipelines ƒ CP inoperable without seawater for conductivity

ƒ Thick layer of rubber / neoprene ƒ Resistance to degradation from salt water, UV light-corrosive agents, ozone and sharp abrasive particles in waves

ƒ Vulcanised – short lengths ƒ Antifouling ƒ Reduction in wave and current drag The splash zone is particularly vulnerable to corrosion. However, cathodic protection cannot be used because it requires the seawater to make the electrical circuit. Instead, a very thick vulcanized rubber coating is often used to protect the riser in this region. Since this is a high light level region, some systems add antifouling to the coating to prevent build-up of marine growth. The picture shows Trelleborg’s Viking system applied to risers. The method of applying the rubber is to clean and shot blast the length of pipe and then helically wind on thin strips of rubber sheet from rolls. The pipes are then heated to vulcanise the rubber into a single mass and bond it to the pipeline riser section. Because the furnaces are of limited size, this necessarily limits the lengths of pipe to be coated.

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EXTERNAL PROTECTION SUMMARY ƒ Caused by rusting of pipeline in seawater ƒ Coating types ƒ Usually three-layer FBE/adhesive/PP ƒ Older process thick CTE coating

ƒ Shrink wrap or FBE for field joints ƒ Thick rubber used for splash zone

Any questions?

A number of different coating materials are used to prevent corrosion of the outside of the pipeline in seawater. Most pipelines are now coated using three-layer protection. The CTE process may still be found in some areas of the world and on older pipelines. In the highly corrosive environment of the splash zone of risers, it is often necessary to use thick rubber coatings.

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CATHODIC PROTECTION

CATHODIC PROTECTION ƒ Galvanic system ƒ Sacrificial method - gradual deterioration of anode ƒ Potential difference between anode and steel ƒ Uses zinc, magnesium or aluminium as anode

ƒ Impressed current system ƒ Adjustable direct current applied through transformer rectifier ƒ Output typically 2 to 30 Amps at 1 to 2 Volts ƒ Uses graphite bed as anode

There are two main methods of providing protection against external corrosion: the galvanic method or impressed current. Offshore, the former predominates, and we attach anodes at intervals along the pipe.

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CATHODIC PROTECTION (CP) SYSTEM ƒ Anodes ƒ 8 to 12 pipelengths ƒ Reel lay at much greater centres

ƒ Bracelet or half-shells

ƒ Ablate away ƒ Protect exposed areas of pipe with coating damage ƒ More important at end of life

If the coating becomes scratched or damaged at any time during the life of the pipeline, the second line of defence is the cathodic protection system, where aluminium or zinc anodes are attached at intervals to the pipeline, as shown in the picture above. Typical anode spacings would be 100 m (328 ft). However, this distance is increased by perhaps five times on pipelines installed by the reel-lay method, which relies on a rapid lay rate. Such anodes are less efficient and need to be larger than those using the S-lay or J-lay methods. If an area of pipe steel becomes exposed, the anode sets up an electric circuit whereby aluminium or zinc goes into solution in the seawater, in preference to the iron from the steel. Although installed with the pipeline, they become more important towards the end of its life as damage increases. In some cases, it may be necessary to replace spent anodes during the life of the pipeline.

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CATHODIC PROTECTION OR COATING? ƒ Optimise cost balance between the two methods CP Coating

Cost

Coating & CP

Optimum level (typically 98%) 0

% Pipe of protected by coating

100

This diagram illustrates the advantage of using a combination of CP and coating to prevent corrosion. The cost of providing a perfect coating with no defects is very high, as is the cost of protecting a bare pipeline using purely CP throughout the design life. Hence, generally, a combination of the two methods is used, with the CP system protecting the regions of the pipeline where defects or degradation of the coating over time leave the pipeline exposed, allowing water and oxygen to reach the surface.

CATHODIC PROTECTION SUMMARY ƒ Anodes ƒ Used for subsea pipelines and manifolds

ƒ Impressed current ƒ Used for land pipelines and platforms

ƒ Overall protection ƒ Combination of coating and CP ƒ Minimum cost solution

Any questions?

Anodes are attached to subsea pipelines to protect areas of coating that are damaged during their life. That is an economic combination of coating and cathodic protection.

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An alternative is the impressed current which requires ground beds to produce the potential.

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ON-BOTTOM STABILITY

ON-BOTTOM STABILITY ƒ Any ideas what this is? ƒ Making sure that the pipeline does not move under storm conditions ƒ Typically two design cases: ƒ Construction, air-filled, 1 year storm ƒ Operation, product-filled, 100 year storm

ƒ Three times design life

It is necessary to ensure that once placed on the seabed, the pipeline does not move under storm conditions. This requirement often conflicts with the need for insulation, where applying thick layers of foam makes the pipe much more buoyant and less stable. The stability design will typically consider two cases: ■ the construction case when the pipe is in an air-filled condition but only needs to resist a one-year storm wave ■ the operational case when it is product-filled but needs to resist a hundred-year storm wave. We choose 1 year and 100 year return periods respectively, because they are each approximately three times the design life of the pipeline in that condition.

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HYDRODYNAMIC FORCES

Hydrodynamic lift Inertia Buoyancy

Hydrodynamic drag

Weight Lateral friction Bottom reaction Stability means ensuring that the pipe has sufficient submerged weight not to move under storm conditions. Looking at the diagram above, this means that the (available) lateral friction must exceed the drag due to the current and waves. Looking at the vertical forces, when the pipeline is placed on the seabed it has its submerged weight (ie self-weight less buoyancy) countered by the bottom reaction from the seabed. If we now introduce a fluid flow over the top of the pipe, this results in lift and drag. You are perhaps familiar with the lift generated by aircraft wings where the air flows faster over the top than it does underneath. In this case, we have water flow over the top of the pipe but no flow underneath. This generates lift. In addition, there is a drag force caused by a high-pressure build up on one side of the pipe and a low-pressure wake behind it. The effect of the lift is to reduce the bottom reaction. The lateral friction is proportional to the bottom reaction. So, as the fluid speed increases, the lateral friction will reduce and the drag will increase until the limit of stability is reached when the drag matches the lateral friction. In wave flow, there is an additional factor due to the acceleration of the wave, which induces inertial forces on the pipeline as well as lift and drag. The drag, lift and inertial forces all vary over a complete wave cycle..

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STABILITY ANALYSIS ƒ What can you do if it is not stable? ƒ Ideas?

ADD CONCRETE COATING

If the pipeline is not stable, the primary means of stabilising it is to add a concrete weight coat. The picture shows a typical 50 to 100 mm (2in to 4in) of concrete being added to the pipe joints. Points about concrete coating are as follows: ■ Because concrete has a low cost per unit weight compared with steel, it is almost always cheaper to add a concrete coating, rather than increase the thickness of the steel

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Concrete is not generally applied over the top of foam coatings, but it is not unknown with more rigid insulation systems such as the syntactic materials Higher density concrete (specific gravity of 3.050 instead of 2.400) can be used to reduce the required thickness Almost every line over 16 inch diameter needs to be concrete-coated to counteract the increased buoyancy of large diameter lines Concrete also acts to protect the pipeline against impact

Typically, steel costs twelve times more than concrete per tonne. However, the submerged weight of steel is five times that of normal concrete so the savings are reduced.

TRENCH THE PIPELINE ƒ Trenching alone ƒ Reduces current effects (shielding) ƒ Steep side slope keeps pipeline in place ƒ Slope angle is soil-type dependant

ƒ Helps reduce trawling impacts

ƒ Trenching with burial ƒ Eliminates hydrodynamic forces on pipeline ƒ Provides thermal insulation

ƒ Cover to top of pipeline varies ƒ Landfall 2 m to 3 m (6ft to 10ft) – offshore 0.3 m (1ft) An alternative to concrete-coating is to trench the pipeline. This has two main effects in terms of stability. Firstly, it shields the pipeline from hydrodynamic loads. Secondly, it provides an upward slope on either side of it which effectively increases the lateral friction. However, the shape of the trench depends on soil type. Fine sands, soft muds and silts do not usually result in a steep enough trench. Additionally, some trawl interaction protection is given by lowering the pipeline below the surrounding seabed. If burial is undertaken as well, then a further insulating benefit is given by the soil. There is more about trenching in the Construction Support module. The depth to the top of the pipe varies depending upon the risk of scour removing the cover. At the landfall, 2 m or even 3 m may be needed. In deeper water where there are low currents and a non-mobile seabed, this can be substantially less.

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ON-BOTTOM STABILITY - SUMMARY ƒ Current and wave forces on pipeline ƒ Two conditions ƒ Empty 1 yr storm ƒ Full 100 yr storm

ƒ Concrete coat ƒ Trench pipeline Any questions?

The principle of stability is to ensure that the pipeline has sufficient weight such that it does not move under storm conditions. The main techniques are concrete-coating and trenching.

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THERMAL INSULATION

WHY INSULATE A PIPELINE? ƒ Production temperatures ƒ 60°C to 160°C (140°F to 320°F)

ƒ Ambient ƒ 5°C (41°F)

ƒ What problems may be caused by allowing oil or gas to cool?

This section addresses the issue of why we need to insulate pipelines and the techniques available to do so.

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PROBLEMS DUE TO COOLING ƒ Wax ƒ Oil lines

ƒ Hydrates ƒ Gas lines - water at high pressures

ƒ Viscosity ƒ Increased friction - head loss

ƒ Separation ƒ Emulsions

The main reason for insulating a pipeline is that process problems can occur if the oil or gas is allowed to cool to ambient temperatures. These problems are: ■ Wax can crystallize out of oil flows. It collects on the pipe wall, and both reduces the pipe diameter and increases its roughness, so it greatly increases the pressure drop. One way of avoiding this is to keep the production warm. Another way is to pig regularly and we will come to this later under the Routine Operations module. ■ Hydrates can form in gas lines. These are waxy ice crystals made up from methane gas and water and occur in conditions of high pressure and low temperature. In extreme conditions, they can collect and block a pipeline. Insulation and warmth are one way of avoiding them. Methanol can also be used to inhibit them. To remove a build up of hydrates, one solution is to depressurise the line, but this may not always be successful. ■ As the temperature decreases, the viscosity of oil increases as does the pressure drop. However, this is not normally too much of a problem unless the oil is so viscous that it sets at ambient temperatures. ■ At lower temperatures, water and oil can form a stable emulsion. It is therefore important to the separation process at the topside that temperatures are kept above the emulsion point, typically 30°C (86°F).

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SELECTION OF COATINGS ƒ ƒ ƒ ƒ ƒ ƒ

Insulate Thermal inertia Withstand maximum temperature Withstand maximum collapse pressure Handling and reeling without damage Not cause pipeline to destabilise (increased uplift or flotation)

A coating has a number of purposes. It must provide the insulation required to keep the product warm throughout the length of the pipeline. If the flow is stopped for some reason, then insulation will prevent the product from cooling too much prior to restarting operations. This may be for 24 hours or more. On restarting, the pumps must be able to cope with the increased viscosity. Some insulation materials can withstand higher temperatures and pressures than others. Typical product temperatures for flowlines are up to 110°C (230°F), though this can be exceeded especially with deep water fields. It is often the case that a protective outer coating is used to improve the handleability of the coating, preventing damage to the insulation layer. Flowlines are often installed using reelbarges. Softer foams cannot be reeled successfully without crushing damage. If the insulation layer is too thick or not dense enough, then the pipeline may be too light in weight for stability. In extreme cases, the pipeline may float during installation when is empty.

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INSULATION TECHNIQUES ƒ Trench & backfill ƒ Heat loss 5 to 10 W/(m² K) (0.9 to 1.8 BTU/hr/ft²/°F)

ƒ Foam coating ƒ 1.5 to 5 W/(m² K) (0.3 to 0.9 BTU/hr/ft²/°F)

Solid PU PUF FBE

ƒ Pipe-in-pipe

Pipe

ƒ 0.8 to 2.5 W/(m² K) (0.1 to 0.4 BTU/hr/ft²/°F)

There are three main techniques for insulating a pipeline: ■ You can trench and backfill it. The covering of soil provides a layer of insulation. Although a poor insulator, it is possible to obtain the required U value using a thick layer of soil ■ You can apply a coating, as shown in the pipes in the picture which has a solid inner layer to withstand the high temperature and an outer solid layer to improve handling ■ You can enclose the flowline in a carrier pipe and put insulation (rockwool or microspheres or polyurethane foam) in-between, thus creating a pipe-in-pipe system Where: ■ PU = PolyUrethane ■ PUF = PolyUrethane Foam ■ FBE = Fusion-Bonded Epoxy Typical range for PU foam coating is a U value between 1.5 and 5 W/m²/K (0.265 and 0.884 BTU/hr/ft²/°F). The equivalent for P-I-P is 0.8 to 2.5 W/m²/K (0.141 and 0.442 BTU/hr/ft²/°F).

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PU FOAM COATING - VIDEO

Bredero Price Coaters Ltd video of PUF coating. Here is an example of a foam-coated pipe, where the flowline is coated with an anticorrosion barrier of fusion bonded epoxy (FBE) followed by a layer of polyurethane foam and an outer water-excluding sheath of solid polyurethane. The video shows the pipe being rotated and the foam being poured from nozzles which move axially along the pipe. Another method of applying the coating (but which is not shown) is to extrude the foam over the outer surface of the pipeline.

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COATING DEGRADATION MECHANISMS ƒ ƒ ƒ ƒ

Creep Water absorption Cracking Hydrolysis

Through Life Overall Coating Strain

12 10

ƒ Combined effects

Strain (%)

8 6 4 2 0 0

2

4

6

8

10

12

14

16

Time (years)

For foams, creep can be an important factor affecting their insulation properties. Over time, the coating will become thinner due to the pressure of the surrounding water. Not only do we have less thickness of insulation, but the thermal properties of the denser coating are poorer. The graph shows typical strain over the life of a coating. Water can diffuse through polymer coatings. The water conducts heat more readily than the polymer, and so the thermal conductivity of the coating increases over time. Where the pipe has been subjected to damage during installation bending or subsequent impact, cracking can occur. It can even be caused by age degradation. This can cause water penetration to the steel or even spalling of the coating. Finally, all plastics are subject to hydrolysis or degradation when subjected to heat and water. The water binds to and splits the bonds of the molecules. Some materials are able to resist this better than others. When assessing reduction in insulation capability over time, some of these mechanisms combine - for example, if the coating cracks, water can reach deeper more quickly and become absorbed into the material. Hydrolysis can then degrade the insulation exacerbating creep. The following slides look at the coating types and define the operational limits.

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INSULATION COATINGS ƒ ƒ ƒ ƒ ƒ ƒ

GSPU (glass syntactic polyurethane) SPU (syntactic polyurethane) PPF (polypropylene foam) PUF (polyurethane foam) Epoxy (PU replacement) Mini-sphere matrix

A range of coating systems are available or being developed for deep water applications. The main coating types are shown above and the first three will be described further in the following slides. Mini-spheres act in a similar way to glass syntactic foams but are the size of a pea up to golf-ball or more. The space between the mini-spheres is filled with GSPU. They are commonly used for ROV and other buoyancy units.

GSPU AND SPU ƒ Syntactic polyurethane ƒ Glass or plastic microspheres in PU matrix

ƒ Maximum depth - 3000 m (9850 ft) for GSPU ƒ Maximum temperature - 140°C (284°F) ƒ Typical U-value range - 2 - 5 W/m²/K (0.4 - 0.9 BTU/ft2/hr/°F) ƒ Reelable ƒ Widely used West Africa, South America, Gulf of Mexico

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Microscopic hollow glass or plastic spheres are used to provide insulation. These are mixed into liquid polyurethane which then sets hard. Plastic spheres cannot withstand the pressures that glass spheres can. This can be applied to pipes installed using the reel-lay method.

PPF Polypropylene foam Maximum depth - typically 600 m (1967 ft) Maximum temperature - 150°C (302°F) Typical U-value range - 2.5 - 5 W/m²/K (0.44 - 0.9 BTU/ft2/hr/°F) ƒ Reelable ƒ Examples of advanced PPF

ƒ ƒ ƒ ƒ

ƒ Nile - 1000 m - 90°C (3280 ft - 194°F) ƒ Crosby - 1200 m - 90°C (3937 ft - 194°F) ƒ Madison - 1400 m - 65°C (4593 ft - 149°F) Typical PPF coatings have a maximum depth of around 600 m (1967ft). However, advanced PPF materials have been developed and applied at depths of around 3000 m (9840ft), though at the expense of their resistance to the highest of temperatures.

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PUF ƒ Polyurethane foam ƒ Low density option ƒ Maximum water depth 100 m (328 ft) ƒ Typical U: 0.3 to 2 W/m²/K (0.053 to 0.352 BTU/ft2/hr/°F)

ƒ High density option ƒ Maximum water depth < 1000 m (3280 ft) ƒ Typical U-values: 2 to 5 W/m²/K (0.4 to 0.9 BTU/ft2/hr/°F)

ƒ Crushing limitations at depth ƒ Max temperature 150°C (302°F) ƒ Depth range too limited for ‘deepwater’ applications The simplest (and amongst the cheapest) insulation is a foamed polyurethane. It uses gas bubbles to provide the required U value. This comes in two ‘flavours’: ■ low density provides good insulation but is limited in water depth ■ high density provides reduced insulation but is good for deeper water We need to carefully assess the crushing over the life of the pipeline and restrict the maximum temperature. It is not good at resisting the bending rollers of a reel barge.

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LØGSTØR RØR - VIDEO

SPS_01 Logstor single pipe with concrete.mpg

The video shows manufacture of Løgstør Rør’s ‘single pipe’ insulation system which features a pair of water stops either side of every field weld. The pipes are precoated externally with FBE which is then preheated to ensure a good bond with the sprayed on isocyanate foam coating. The foam can withstand 110°C (230°F) and is typically applied as a 10 mm to 30 mm (0.4in to 1.2in) layer in densities of 150 kg/m³ to 375 kg/m³ (9.4 lb/ft³ to 23.4 lb/ft³). An outer polyethylene shell is hot applied to provide full hydrostatic pressure resistance down to 200 m (656ft). The ends are tapered for welding and bonded to the FBE pipe coating. A steel cage is spun around each pipe and a dense heavyweight concrete (containing iron ore) is slip-formed around the pipe in a vertical system. This contrasts with other methods which use sprayed, shotcreted or gunited concrete applied to a horizontal rotating pipe. The vertical system results in a denser, less porous casting. Half shell anodes are fitted to the ends of some of the pipes. Their outer diameter matches the concrete coating. Once the pipe is welded on the laybarge, the field coat is made up using a heat shrink sleeve over the joint. Two insulated half shells are banded on and the gap is injected with syntactic polyurethane foam. The slope of the firing line helps ensure no voids are left as the foam sets. The properties of the foam are not as efficient as the pipe insulation at 0.145 W/m³ (0.014 BTU/ft³/hr) at a density of 810 kg/m³ (51 lb/ft³). Total water absorption is less than 2.5% and it can resist a pressure of 15 MPa at 23°C (2176 psi at 73°F). The total field joint process takes 7 minutes for each pair of the double jointed pipes.

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FIELD JOINTS ƒ Protection over butt welds ƒ Need to consider: ƒ ƒ ƒ ƒ ƒ ƒ

Corrosion protection Thermal requirements Compatibility and overlap with factory coatings Matching diameter of concrete Speed of application and curing Health and safety issues

Once two sections of line pipe have been welded together, the corrosion protection and insulation layers need to be made good. Field joints need to be matched for compatibility with the main factory applied coatings. In general they overlap these and make a seal of 50 mm (2in) or so. If there is concrete applied for weight coat, the field joint is generally filled out to the same diameter. This is necessary when the pipe is laid over a stinger from an S-lay barge. It is important to fit the field joint makeup into the production plan. Speed is often of the essence to reduce pipelay costs. For this reason, different materials may be used than in the factory, but which can be applied and cured more quickly. This is sometimes subject to detailed health and safety scrutiny.

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DEEPWATER FLOWLINE REQUIREMENTS ƒ Deep water flowlines ƒ Often means high pressure and multiphase flow ƒ Hydrate problems ƒ Gas at low temperatures and high pressures

ƒ Design conditions ƒ Must keep sufficiently warm when flowing ƒ Must allow sufficient period of shut-down ƒ May possibly need to heat product

ƒ Requirements ƒ Hydrostatic pressure ƒ U value and high temperatures ƒ Reeling Deepwater developments often have associated thermal constraints to avoid production of hydrates in gas lines or long multiphase flowlines. The major design conditions issues for a deepwater coating system often take the form of a required U-value and a specified cool-down period. That is, we need to consider both normal operations and shutdown conditions, when there may be a requirement to maintain heat as long as possible or even warm the product up again from cold ambient temperatures. These effectively determine the selection of suitable coating capable of withstanding high hydrostatic pressures and product temperatures. The coating suppliers have additionally had to contend with characterising and accounting for the degradation processes. With flowlines, one commonly chosen installation method is reeling. This further limits the selection of coatings, due to the high strains produced by bending around the reel.

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THERMAL INSULATION - SUMMARY ƒ Avoid operating problems ƒ Wax, hydrates, viscosity and separation

ƒ ƒ ƒ ƒ

Use burial, foam or pipe-in-pipe Typical coating materials Field joint coatings Deepwater flowline requirements ƒ Operation, cool-down time and restart

Any questions?

We need to avoid a number of flow-related problems by insulating the pipe. Wax builds in oil lines, hydrates form in gas lines, and viscosity increases at cooler temperatures. All tend to increase friction (and hence production costs) or reduce the flow. If a multi-phase product gets too cold, there may be separation problems at the facility due to it forming an emulsion. Three methods are commonly used to reduce heat loss. In this section, we have looked at typical insulation coatings. There are differences in the materials used at field joints. We have examined the particular problems which may arise in deep water flowlines due to the high pressures and temperatures at the well head and the long lengths of lines used.

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PIPE-IN-PIPE SYSTEMS

PIPE-IN-PIPE CONSTRUCTION ƒ Corus Hydrotherm pipe-in-pipe manufacture Steel carrier with FBE coating Microspheres

Pipe with FBE coating Here is an example of a pipe-in-pipe system where the annulus between the steel carrier and the pipe is filled with alumina silicate microspheres. The microspheres are tiny hollow spheres and look like cement dust. The technique is to assemble the pipes together, rotate them vertically, fill with the microspheres, and put rubber water stops at both ends.

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HYDROTHERM - VIDEO

Courtesy of CORUS

Hydrotherm uses microspheres to insulate a pipe-in-pipe. It is a relatively costly system, but because the microspheres are inert at high temperatures – above 140°C (284°F) – it can be used where syntactics start to break down. The process is carefully controlled by weighing to ensure that the correct packing of the spheres permits some of the hydrostatic head to transfer from the outer to the inner pipe.

PIPE-IN-PIPE SYSTEMS ƒ A variety available from ITP, BPCL, Bredero Price, Løgstør Rør, CORUS and others One atmosphere

ƒ Insulants used are: ƒ ƒ ƒ ƒ

Microspheres Rockwool PUF Vacuum

Internal pressure

External pressure

ƒ Various connection schemes Conventional thermal insulation coatings, such as low density foams, have low strength and would crush in deep water applications. But they are very efficient as insulators.

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Pipe-in-pipe systems offer a means of achieving high thermal efficiency in deep water applications. The insulation product is placed in the annulus between the inner product pipe and the outer carrier pipe, in pre-assembled lengths. The outer steel pipe has sufficient strength to withstand the hydrostatic load, and the insulation product does not require any intrinsic strength. Pipe-in-pipe systems are made up on the laybarge, although the requirement to join both an inner pipe and outer pipe significantly reduces the rate of lay. Various connection systems have been developed to increase the speed at which the outer carrier pipe connection can be made.

OUTER PIPE WALL THICKNESS ƒ Require large wall thickness to prevent collapse of outer pipe ƒ Pressurise nitrogen in annulus to reduce wall thickness ƒ Thermal implications

The outer pipe wall thickness can be reduced by internally pressurising the annulus with nitrogen gas. However, this does have thermal implications.

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THERMAL IMPLICATIONS ƒ Foam insulant ƒ Must be open-celled to avoid crushing ƒ Open cells less efficient than closed cell foam

ƒ Increased convection ƒ High pressure gives increased gas density ƒ Increased convection within foam cells ƒ Increased convection across annulus

ƒ Troika – Gulf of Mexico ƒ Pressurised annulus - problems When pressurising the annulus with gas, consideration has to be given to the effect of the pressure on the insulant material. If a foam is being used, this must be open-celled to allow pressure equalisation through the foam and to avoid crushing of the foam. Open cells are less efficient insulators than closed cell foams. A further implication of pressurising the gas is that, with the resultant increased density, convective heat transfer increases. The Troika pipe-in-pipe system in the Gulf of Mexico failed to meet its thermal targets because these effects were not correctly accounted for.

PIPE-IN-PIPE DEEPWATER CHALLENGES ƒ Thick outer pipe ƒ Resists full hydrostatic collapse

ƒ Installation method and assembly rate ƒ J-lay barges are set up for single weld joints

ƒ Connection of outer pipe ƒ Real need for bulkheads and shear stops? ƒ Bulkheads ƒ Prevent flooding of whole annulus

ƒ Shear stops ƒ Prevent inner pipe sliding relative to outer

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The principal deepwater challenges for pipe-in-pipe systems are listed above. ■ Significant material costs can be incurred as a result of the thick outer pipe being required to resist the full hydrostatic collapse pressure. Since the annulus is at 1 atmosphere, no beneficial effect can be taken from the internal product pressure. ■ Rapid assembly is required to control installation costs. The need for both inner and outer pipe connections greatly reduces the layrate. This is especially true of J-lay barges which use single welding stations. ■ Outer pipe connection details must be rigorously designed. Pipeline failure has already occurred as a result of inappropriate design of the outer pipe connection details. Are intermediate bulkheads and shear stops required? ■ Bulkheads are needed to prevent flooding of long lengths of line annulus with resulting loss in insulation properties. The spacing of bulkheads is determined by the length of insulation that can be lost without arrival temperatures dropping too much. ■ Shear stops are provided to prevent the inner pipe sliding relative to the outer. During installation only the outer pipe is held by the tensioners. The need for shear stops needs to be ascertained on a case-by-case basis depending upon the method of insulation and the relative size of the pipes. A study of the operational temperature flow regime may also indicate shear stops.

PIPE-IN-PIPE J-LAY ISSUES ƒ Inner and outer pipe joints made at single weld station ƒ Potentially poor lay rate ƒ Rapid connection system desirable for outer pipe ƒ Mechanical connector ƒ Sliding sleeve

With the J-lay method, there is a single weld and coating station. The pipe-in-pipe lay rate is consequently much slower if conventional steel half-shells are used for the joint. A number of systems have been proposed and used to speed this up. Most make use of either a mechanical connector or sliding sleeve.

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PIPE IN PIPE JACKET

Metal jacket

Steel Half-shell half-shell Flow line

Weld Insulant

Rubber water stop

For a pipe in pipe system tensioning is a more difficult problem. It is the outer jacket which is put in tension, so at least some of the jacket weld (both girth and seam welds) must be completed before the first tensioner. Normally at least the root weld and first pass are completed before the tensioner. This requirement puts a limit on the use of tensioners (effectively the first pair are made redundant as they are before the first jacket weld stations). This means that double pipeline systems are laid approximately 1/2 to 1/3 times slower than conventional ‘single’ pipelines. Another problem is performing the NDT of the flowline efficiently.

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SLIDING SLEEVE CONNECTOR ƒ Less welding than half-shells ƒ Design and fabrication issues for fatigue performance ƒ Erskine experience 1 2 3

4

1. Inner pipes welded together 2. Sleeve slid across 3. Sleeve butt welded to bell-end of outer carrier 4. Sleeve fillet welded to the other pipeline

The purpose of the sliding sleeve is to reduce the welding time for the outer pipe. A welded sliding sleeve will require at least one of the welds to be a fillet weld rather than a butt weld. This has significant implications with respect to fatigue performance, which must be duly accounted for in both design and fabrication. The Erskine pipeline failed because of this type of connection.

BONGA SOLUTION Vacuum

Field weld

Sleeve slid on

Shop-welded ends

Pipe-in-pipe

Insulation Preformed insulation

Injection

For the Bonga field, pre-formed ends were welded onto the outer pipe in order to speed up the assembly of the pipe-in-pipe system. The axial stress in the outer pipe is then transferred to the inner pipeline through a single structural weld.

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Preformed blocks of insulation are then fitted around the weld prior to a sleeve section with the primary vacuum insulation being slid on. The sleeve is then held in place by injection of a quick-setting plastic.

PIPE-IN-PIPE REEL-LAY ISSUES ƒ Bending and straightening of inner pipe ƒ Spacers ƒ Reelable bulkheads and water seals

Pipe-in-pipe systems can be reeled. The major issue is the control of bending and straightening of the inner pipe. The bending of the outer pipe is displacement-controlled by the reel and straightener. The inner pipe is displacement-controlled at intermittent points only (the spacer locations). The discontinuous contact with the inner pipe means it is not possible to straighten the pipe fully during the reeling process. Other issues include the design of intermediate bulkheads and water seals which also have to be reelable. It is important that no additional strain is concentrated at these points.

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DEEP WATER REELED PIPE-IN-PIPE ƒ Nile: 1100 m (3610 ft) maximum water depth ƒ Spacer pitch 2 m (6.5 ft) ƒ Coiled buckle arrestor (internal spring) ƒ Annular water seals every 400 m (1312 ft)

Technip have installed the Nile pipe-in-pipe flowline in 1100 m (3608ft) water depth in the Gulf of Mexico (GoM), and are currently working on a project for 2100 m (6888ft) water depth.

LNG ENVIRONMENTAL RISK ƒ Rupture of LNG tank or transporter tanker ƒ Forms cold vapour cloud ƒ Heavier than air ƒ Unconfined vapour cloud explosion (UVCE)

ƒ Environmental concerns ƒ Terminal sited far from existing residential areas ƒ Ship moored far from onshore tanks Spilled LNG (liquefied natural gas) in a large scale leak can produce very cold vapour which in general will remain heavier than air until it absorbs sufficient heat from surrounding surfaces and air. If the cold vapour forms a flammable heavier-than-air fuel-air cloud, it may find an ignition source near the ground and cause an unconfined vapour cloud explosion (UVCE) during the dispersion process. This could be a simple spark from even a mobile phone or hobnail boots.

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Because cold LNG is reduced to some 1/628 of its original volume and the transporter ships are so large - the largest Q Max vessels currently being built holds 265 000 m³ (9.4x106ft³) of liquid - there are serious concerns regarding leaks. Explosive release of such a large amount of energy at once would be an absolutely calamitous disaster. There are currently a number of concerns requiring the location of LNG moorings and loading/unloading facilities to sites remote from habitation. If a cloud were to form from an accidental leak or terrorist attack on the ship, it can spread a very long distance from the source. U.S. Coast Guard requested that Sandia National Laboratories review the ‘Independent Risk Assessment of the Proposed Cabrillo Port LNG Deepwater Port Project’ off the coast of Malibu, California. The conclusion states that a flammable liquefied natural gas (LNG) vapour cloud could extend 12 kilometres (7.3 miles). (Reference Sandia Report Sand2005-7339 January 2006.) A recent incident occurred at the Skikda gas-liquefaction plant in Algeria in January 2004. The blast shook buildings and shattered windows more than a mile away and 27 lives were lost with injuries to a further 80 people. It was the deadliest incident in over 30 years. A small amount of LNG had leaked from a pipeline and the vapour was drawn into a boiler which exploded when it was relit. Nevertheless, the use of such refrigerated vessels provides a convenient means of transporting the fuel to where it is needed. The alternative is to leave it as a gas, but this means providing long intercontinental trunk lines.

LNG PIPE-IN-PIPE-IN-PIPE ƒ Cold low pressure liquid API 5L X65 pipe to withstand hydrostatic pressure Vacuum for leak test API 5L X65 pipe Aerogel or vacuum – insulation Invar pipe 4 mm (0.16in) wall – primary containment (zero contraction) Liquefied natural gas at -160°C (-256°F) less than 40 bar (580 psi)

Currently there are a number of proposals to install P-I-P-I-P systems to transport liquefied natural gas. This is at present limited to short distances such as lines from a near-shore offloading facility to shore. The alternative is to construct insulated pipelines and contraction loops on long jetties out to the dolphin or sea-island where the LNG tankers moor. However costly this is, the danger of catastrophic loss of a subsea LNG pipeline means that at present, such proposals remain as cost-benefit and risk-assessment studies.

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LNG needs to be kept very cold to maintain it as a liquid, but the required pressure is low – only enough to pump the short distance to shore. Invar or similar material has a zero (or even negative) coefficient of thermal expansion. This provides designers with a means of matching the linear contraction of the innermost sleeve (when in contact with LNG during discharge) with the behaviour of that for the outer pipeline, in contact with seawater at perhaps 5°C (41°F). The wall thickness of the inner pipe is very thin – only needing to resist low pressure. The corrosion resistance of invar is excellent and there is no need for a corrosion allowance. However, costs for Invar are very high. The two outer pipes are of normal carbon steel grade X65 or similar. These need to resist external water pressure. However, if they come into contact with the cold LNG, they are liable brittle failure. The annuli between the pipes contain either vacuum or aerogel to provide insulation and a means of testing for leaks. Spacers holding the lines coaxially must be designed carefully to avoid heat bridging between the pipe layers.

PIPE-IN-PIPE - SUMMARY ƒ ƒ ƒ ƒ ƒ

Improved thermal properties Better able to resist deep water pressure Slows down production Care needed at joints Can be installed by all methods ƒ Care needs to be taken in J-lay and reel-lay

ƒ P-I-P-I-P for LNG ƒ Only at loading/discharge berths

Any questions? When conditions demand better insulation, it is possible to install a pipe-in-pipe system. It is better able to resist high external pressure without creep or crushing. But this comes at the cost of speed of installation. Additional care is needed at joints. All the installation methods can make use of pipe-in-pipe. Special considerations for Jlay and reel-lay have been explained. The recent development for LNG terminals is limited to relatively short pipeline strings as a replacement for existing insulated lines on jetties.

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ACTIVE HEATING OF LINES

HEATING ƒ Heat required for: ƒ Hydrate and wax avoidance ƒ Start up viscosity ƒ Process separation

ƒ Approaches: ƒ Use electrical cables ƒ In bundles, use heating pipes - Gulfaks ƒ Hot water in pipe-in-pipe annulus - Britannia

Insulation systems are widely used to reduce the heat loss from the pipeline system. There are cases where we may have a requirement to add heat to the pipeline system, particularly in shut-down and start-up conditions. There are a number of ways of adding heat to a system.

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ELECTRICAL HEATING ƒ 3 main categories: ƒ Induction ƒ Wire induces eddy currents ƒ Pipe wall heats up

ƒ Direct impedance ƒ Current passed down pipe wall eg Asgard

ƒ Trace heating ƒ Electric wire heats up ƒ P-I-P systems

ƒ Consider costs ƒ Shutdown/startup

Combipipe Induction system

Electrical heating systems can take three basic forms: ■ Induction heating - where the electromagnetic field around the electrical cable induces surface eddy currents on the pipe causing the pipe wall to heat-up. An example of this system is illustrated above. The induction heating cable does not have to be in contact with the pipe. This means that a cable can be separately laid alongside the pipeline. ■ Direct impedance - where a current passed along the pipeline heats the pipe wall. This system is in use on Asgard. ■ Trace heating - where the electrical cable itself heats up. Trace heating systems require the heating element to be installed in or under the pipeline insulation coating. Trace heating is widely use in onshore applications and is also being marketed by Technip in their heated pipe-in-pipe system. However, there are considerable operating costs involved in continuous electrical heating of lines. It may be best reserved for shutdown/startup operations.

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HEATING PIPES Gullfaks bundle 3

2

1

1

4

1. Control lines 2. Gas injection 3. Methanol injection 4. Insulation 5. Production lines 6. Hot water return 7. Hot water supply 8. Insulation

6 5

5 8 7

7

Thermal Analysis

Hot water heating pipes have been used in bundles. This figure illustrates an arrangement as used in the Gulfaks satellite bundles. The production flowlines and heating pipes are within an insulated nitrogen filled carrier pipe, which is itself within an outer water filled carrier pipe. Heat input is required to sustain a long cool-down period following shut-down. Heat transfer from the heating pipes to the production flowlines is by convection in the nitrogen and radiation. The Britannia bundles used an alternative hot water heating system, where the hot water flowed within the carrier pipe itself. Because part of the carrier annulus remains nitrogen filled, extra weight must be found in the bundle to counteract buoyancy.

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BRITANNIA CIRCULATION SYSTEM ƒ Uses waste platform heat ƒ Hidden carrier corrosion

219 mm (8in) Test line 89 mm (3in) Methanol line 324 mm (12in) Heating line and carrier annulus return 356 mm (14in) Production

On the Britannia project, waste heat at the platform was utilised to keep warm water circulating through a dedicated 324 mm (12in) pipe adjacent to the 356 mm (14in) production flowline. At the well manifold the slightly cooler water returns to the platform though the annulus. One difficulty with this system is that there may be hidden corrosion on the internal side of the carrier pipe. The system was designed to heat up to operating temperature from cold within 24 hours.

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ACTIVE HEATING OF LINES SUMMARY

ƒ What happens with no heating ƒ Means of achieving direct heating ƒ Three methods of electric heating ƒ Reserve for shutdown/startup

ƒ Two methods of water in bundles

Any questions?

We have listed the four main problems when heat is not provided (wax, hydrates, viscosity and product separation). The three methods of active heating using electrical power to provide heat have been examined, along with the two bundle approaches to heating flowlines.

EXTERNAL COATINGS - SUMMARY ƒ ƒ ƒ ƒ ƒ ƒ

Corrosion protection Cathodic protection On-bottom stability Thermal insulation Pipe-in-pipe systems Active heating of lines

Any questions?

We have examined the needs and means of applying coatings to pipelines.

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Overview of pipeline engineering

They are needed to assist in avoiding external corrosion and keeping the pipe in place on the seabed. The first is achieved with a combined approach of coating and CP. An alternative to concrete coating is to trench the pipeline. Thermal coatings can be applied directly or through the use of pipe-in-pipe systems. If even more heat is needed then active heating can be applied.

Design methods

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EXPECTATION

EXPECTATION ƒ Limit state design ƒ DNV OS-F101: 2000

ƒ Pipeline buckling ƒ HIPPS systems ƒ Fishing interaction ƒ Types of trawling ƒ Protection pipeline

ƒ Vortex-induced vibration ƒ Fatigue damage at risers and pipeline spans

We will look at modern limit state design theory and how this may be applied. We introduce the Norwegian standard commonly known as DNV OS-F101, which is the leading limit state design code used for pipelines. The modern design approach can lead to cost savings when assessing pipe buckles. We also consider how the use of HIPPS systems can lead to thinner walled flowlines. We examine whether we need to design all pipelines for fishing interaction or if we can safely make cost savings by eliminating trenching. Fatigue damage to pipelines can be caused by rapid vibration caused by currents flowing over them. We will look at means of assessing for VIV.

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LIMIT STATE DESIGN Identification of Limit States

LIMIT STATE FAILURE CLASSIFICATIONS ƒ Designer assesses all limiting failure states ƒ Need not know exact cause of failure

ƒ Classes ƒ ƒ ƒ ƒ

Ultimate Service Fatigue Accidental

ƒ Any fool can build a bridge that stands up, but it takes an engineer to build a bridge that just barely stands up There are four limit state classifications that are usually considered in modern design. There may be more than one limiting state in each class. When assessing a pipeline, we need to ensure the design complies with the codes and the client’s needs. We don’t necessarily need to worry too much about the detailed lead up to the failure condition. The adage above implies that we should strive to design as economically as possible. Let us see how the four limit state classifications are applied to the failure of bridges. Remember, we normally only need to determine the limiting mechanism conditions, not what caused them. However, in the next two slides, we are also describing how they came about. This is to help us understand the differences between the four limit state conditions.

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LIMIT STATE FAILURE MECHANISMS ƒ Ultimate ƒ Loads exceed strength ƒ London bridge - heavier buildings ƒ Foundations were exposed by scour

ƒ Fell down - unusable

ƒ Service

Medieval London bridge

ƒ Usable but does not achieve client’s needs ƒ Thin plank over stream ƒ Feet get wet ƒ Rope bridge ƒ Feels wobbly ƒ Millennium footbridge

Rope bridge

Millennium bridge

The ultimate limit state indicates that the loads applied to the structure exceed its strength. In other words, it fails or collapses. In the nursery rhyme, ‘London Bridge is falling down’, the bridge had so many houses and storerooms built on and over it that people may have thought that they were walking through a tunnel with shop fronts on either side rather than crossing a bridge. The piers to the bridge were so wide that they constricted the flow of the river. At certain times of the tide, the differential water levels either side of the bridge were up to 1.5 m (5ft) and a weir effect prevented passage of boats. Severe scour of the soil beneath the piers caused loss of support. This lead to the installation of protective starlings (timber sheet piles) which further restricted flows. Eventually, the weight of the buildings exceeded what the foundations could support. In service limit state, the structure may be quite safe. However, people either cannot use the structure in its intended manner (it does not achieve the requirements set out in the Basis of Design), or they feel unsafe in using it. (Perhaps the boatmen beneath the old London bridge would have perceived it as a service failure as they shot the weir.) As children, we have all used too thin a plank to cross a gap. If we made a bridge to cross a stream, perhaps we were able to cross without it dipping into the water. However, if two were to cross together, they might get wet feet. The rope bridge across a gorge in an Indiana Jones film invariably has someone too scared to cross because it is moving too much. The classic modern service failure was London’s millennium footbridge. When it opened, the crowds crossing caused it to sway from side to side at a fundamental frequency. This made others walk in step and the bridge began to oscillate even more. The bridge was quickly closed and dampers fitted. Again, this is a service limit state because of excessive deflections - though this time laterally rather than vertically.

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LIMIT STATE FAILURE MECHANISMS ƒ Fatigue ƒ Subject to repeated bending stress ƒ Tacoma Narrows

ƒ Strength of material deteriorates ƒ Avoid locations of stress concentration ƒ S-N curve - assess-and-monitor or overdesign?

ƒ Accidental

S

ƒ Unexpected incident

N

ƒ Vehicle hits suspenders or ship hits pier ƒ Provide Armco barrier and fendering ƒ Kobe viaduct ƒ Designed for lesser earthquakes

ƒ Not a design condition for the structure Fatigue caused by repeated bending results in loss of strength of the material itself. The classic example was the failure of the Tacoma Narrows suspension bridge (upper photograph above), which is shown to most engineers at college. The bridge was designed to resist predicted winds but the deck fluttered violently at speeds approximately half these, 19 m/s (42 mph),. It originally was thought of as a service failure (similar to the Millennium bridge), and it gained a reputation as ‘Galloping Gertie’ in such winds - with people ‘thrill-seekers’ using it from July through November of 1940. However, the repeated flexing caused loss of strength due to fractures at points of stress concentration and it eventually collapsed violently but with no loss of life (apart from a dog). It is possible to design members using the low stresses determined from horizontal section of S-N curves. However, this is not necessarily the most economic option. It is better to assess the number of cycles and use appropriate stress levels on the inclined section of the graphs. By eliminating stress concentration points, design can be carried out economically. Where fatigue damage is suspected, then monitoring the structure can provide prior warning of damage. Accidental limit states are not normally a design condition for the structure itself. They are caused by unexpected incidents that would cause the structure itself to be totally uneconomic. As an example, we might consider a lorry that hits the suspension wires of a bridge or a wayward ship hitting the support piers. We do not design the bridge to resist this: we add Armco barriers or marine fendering to deflect such impacts back into the main flow and thus protect the bridge with secondary structures. Another example might be the Kobe elevated roadway (shown above), a 3 km section of which fell over during the 1995 earthquake. Japan is a seismic region and the viaduct was designed to resist what was thought a safe level acceleration. However, the shallow event that hit the city occurred within 20 km (12 miles) of the centre, and at Richter 7.2 was well beyond what had been assessed as reasonable.

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LIMIT STATES FOR PIPELINES ƒ What do you think the limit states may be for a pipeline? ƒ ƒ ƒ ƒ

Ultimate Service Fatigue Accidental

ƒ End condition rather than the initial cause Try to concentrate on the end condition, rather than what leads up to it. Accidental limit states are normally not a design case for the pipeline itself. However, we need to assess the likelihood of the incident, and to provide protection if required to reduce the consequences to an acceptable level. For this reason, the cause does become important.

LIMIT STATES FOR PIPELINES ƒ Ultimate ƒ Pipe bursting or collapsing

(thin wall or corrosion)

ƒ Service ƒ Insufficient throughput rate (bore too small) ƒ Too low a delivery temperature (poor insulation) ƒ Inability to pig line (bends too tight)

ƒ Fatigue ƒ Loss of material strength (flexing at a dent, span VIV or installation wave motion)

ƒ Accidental ƒ Blockage of pig ƒ Reduced operating pressure

}

(trawlboard, vessel or anchor impact dent)

Although not essential, we have included some of the possible causes to help understand the issues.

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HISTORICAL BACKGROUND FOR PIPELINES ƒ Pipeline codes rooted in 1950s ƒ BS PD 8010, IP6, ASME/ANSI B31.4 and B31.8

ƒ Engineers had slide-rules, not computers ƒ Allowable stress design (ASD) ƒ Codes based on not going over yield ƒ Later modified for reel-lay

ƒ Limited number of cases considered ƒ Single factors of safety (or ignorance) ƒ Combined all the unknowns together

Widely used pipeline engineering design codes such as ASME B31.4, B31.8 and BS PD 8010 specify generalised safety factors that were appropriate to technology and standards of control in the 1950s. Design was normally undertaken using slide-rules rather than calculators, so simplified procedures were specified of necessity. It was common to consider only a limited number of ultimate and service cases. Some codes do not even include the installation case as one of these. This design methodology is often termed allowable stress design. These techniques were based on not taking the material beyond yield, although adaptations were subsequently made to these codes to include strain-based design, such as required for reel-lay. We can now rapidly undertake analysis of many cases using spreadsheets or more advanced analysis methods. We can include the separate uncertainties associated with the material and the loads, which may differ for each case under consideration. This means that today, the allowable stress design (ASD) codes are now considered as excessively conservative in some areas.

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BASIS FOR 0.72 DESIGN FACTOR ƒ Pipelines are commonly designed to operate at 72% of SMYS ƒ This is derived from: ƒ Mill tests to 90% SMYS hoop ƒ Allow 80% of that in operation ƒ 0.9 x 0.8 = 0.72

ƒ Arbitrary ƒ Not written in stone ! ƒ Has resulted in a few failures The derivation of the 0.72 usage factor for pipe wall hoop stress is shown above. The inherent level of safety which was chosen is quite arbitrary. However, it resulted in few failures.

THINGS HAVE IMPROVED ƒ Manufacture ƒ Better steel compositions and control ƒ Better thickness and ovality tolerances ƒ Better factory welds ƒ Better defect detection

ƒ Offshore ƒ Better welding and NDT ƒ Better pressure measurement and control ƒ Better corrosion control ƒ Better inspection and repair

We can take advantage of the technological improvements in manufacturing and control, shown above.

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SAFETY MARGINS INCREASED Probability Operating Pressure

Burst Pressure Today

Today 1950

1950

Bigger safety margin

Pressure

All aspects of pipeline operations and manufacture will have tolerances. Over the years, careful measurement of the various aspects have provided us with a better knowledge of numerical values for these individual tolerances. The combination of these may be represented on a probability graph, as shown above. The two ‘skewed bell curves’ for the operation and strength of pipelines (shown in solid red) were originally close together, with negligible overlap. By better control of the operational loads and the strength of the pipe (shown in yellow dashes), the two curves have been pulled apart from each other, so the effective safety margin has increased. This gives scope for new design methods to safely reduce the strength of the pipe or increase the load.

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NEW DESIGN APPROACH ƒ Consider the true failure conditions for the pipeline (not necessarily yield) ƒ Assess the consequences of failure ƒ Apply rational safety margins ƒ Derived using separate partial safety factors applied to materials and loads for each failure case ƒ Codes set down these factors

ƒ Basis of new approach is: ƒ Limit state ƒ Risk and reliability The new design techniques move away from the potentially arbitrary design criteria of previous codes. They are based on the actual failure conditions of the pipeline combined with an assessment of the consequences of failure. Safety margins are defined to give an acceptable and definable reliability. Separate partial safety factors are set down in the codes (both for materials and loads, and for each failure condition) in order to achieve these margins.

PRIZE ƒ Provide confidence in level of safety ƒ Meet tougher challenges and extend technical boundaries ƒ ƒ ƒ ƒ ƒ

Higher pressure for same wall Extreme temperatures Deep water Non-trenched lines Develop smaller fields

ƒ Give lower costs Trawl board impact on unburied line

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The need for new design techniques has come from a number of drivers, as indicated above. These are principally the need to meet demands of lower cost and tougher technical requirements, whilst maintaining an adequate (and fully assessed) level of safety. Examples where new design techniques are being used are shown in the rest of this module.

LIMIT STATE DESIGN - SUMMARY ƒ How safety factors were developed ƒ Allowable stress at yield ƒ Single FoS / basis of 72% SMYS

ƒ Improvements in ƒ Manufacture ƒ Measurement, inspection and corrosion control

ƒ Increased margins permit ƒ Cost saving ƒ Safely extend technical boundaries ƒ Higher temperatures, pressures and deeper water

Any questions? We have examined how the pipeline codes were developed in the 1950s. They were based on not permitting the pipe steel to yield and having a single factor of safety. Typically, for most codes worldwide, the permitted safe level of stress was 0.72 SMYS. We now have improvements in manufacture of the pipe both in control of tolerances in material and geometry. Installation and operation of pipelines is better with improved measurement and inspection. This new approach to design permits cost savings, or alternatively more throughput down existing lines. We can now consider higher temperatures or pressures and deeper water lines.

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Derivation of Safety Factors

PARTIAL SAFETY FACTORS ƒ How do code writers select safety factors? ƒ Quantified using risk and reliability analysis ƒ Also called structural reliability analysis

ƒ Define what all the failure modes are ƒ Finds the risk of each occurring

ƒ Determine safety classes ƒ Sets individual partial safety factors on loads and materials to give acceptable, uniform risk of failure

ƒ Apply safety margins rationally Modern codes (such as the suite of structural Eurocodes for steel, concrete, aluminium, masonry, timber, soils and seismic or the AISC LRFD code) are all written using limit state principles. The limit state codes use partial safety factors on loads and materials, rather than the generalised safety factors used by the traditional design equations. These are derived by the code writers using the method of risk and reliability. This is also known as structural reliability analysis in the US. Each possible failure mode is defined and an assessment is made of the risk of each occurring. For pipelines, a range of safety classes has been defined. The partial safety factors appropriate for each class are determined by the writers of the codes using reliability methods, which define the distributions on the load and strength. The safety factors are therefore applied rationally to give a specific level of safety. The following slides give an overview of the risk and reliability methodology.

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WHAT IS RISK? ƒ Risk = probability x consequence ƒ Numerical values for each Consequence of failure

High

Highest risk

Medium risk Lowest risk

Low Low

Probability of failure High

Risk is normally defined as the product of probability of an event occurring and the consequences of that event. A simple Boston square is illustrated, which gives a means of presenting and comparing levels of risk. The consequence of failure is often determined in money terms with a price being put on each life lost. The probability of an event happening is usually determined by the use of event fault trees, reliability block diagram or Markov methods, where reliability values and Boolean logic calculate the likelihood of failure. A failure that has a high probability of occurring and a high consequence would be considered high risk. For most systems, risks in the red and yellow squares must be removed by design. Even those in the green squares should be removed if the costs of doing so are low. More detailed systems now exist with more boxes and bands, numerically quantifying the likelihood levels for each axis. Perhaps these would have six bands – the lowest being something likely to occur at least once per year, and the highest being an event occurring less frequently than every 10 000 years. Knowing the consequence of failure, we can determine the appropriate or target level for the probability of failure.

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TARGET RELIABILITY ƒ DNV OS-F101 pipeline safety classes ƒ Failure frequencies acceptable to society Safety Description class Low

Minor consequence to life or environment

Significant consequence to life or Medium environment under temporary conditions High

Significant consequence to life or environment under normal conditions

Probability of failure 10-3 /yr 10-4 /yr 10-5 /yr

Pipelines are assessed in DNV OS-F101 into one of three safety classes, depending upon the consequence of failure and period of risk. The associated frequencies or probability of failure normally considered acceptable to society are derived in order to give uniform risk. Note that probability of failure is stated in terms of a number of failures per year for each pipeline. That should mean longer pipelines need better factors than short ones. However, this is not reflected in the present codes. Whereas we have been emphasising up to now just how accurate the code writers are in the derivation of the load and strength probability distributions, this table seems somewhat arbitrary. However, it reflects common practice for safety engineers in only using the numbers 1, 2 or 5 multiplied by a power of ten for their answer. For pipeline designers, there are only these three safety classes. Other industries (such as nuclear) use more.

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FACTOR SELECTION BY CODE WRITERS DNV selects factors of safety Failure modes Loads and tolerances

Limit state and allowable stress designs often result in similar sizes but the former can be justified rationally

Strength and tolerances Monte-Carlo for load and strength distributions

DNV adjusts factors No

Acceptable failure rate? Probability of failure

Yes

Ensure consequence of failure < acceptable target level

The basic reliability assessment method is shown in this flow diagram. Each step of the process is described in the following slides. The partial safety factors and their values are adjusted to ensure that the consequence of failure is less than a target level deemed acceptable to society.

DNV OS-F101 FAILURE MODES ƒ Ultimate failure modes ƒ ƒ ƒ ƒ

Burst through over-pressure Burst through corrosion defect Leak through corrosion defect Burst through upheaval buckle

ƒ Service failure modes ƒ Insufficient flow through wax buildup on walls ƒ Low arrival temperature through insulation degradation

ƒ Plus others The first activity is to identify all of the things that could go wrong and lead to a failure. This listing of failure modes on a particular contract is also known as a risk register.

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Examples of some of the possible ultimate failure modes and how they might occur are itemised above.

MONTE-CARLO PREDICTION

Pipe diameter

Probability

Probability

Probability

ƒRandom number generator (0 to 1) ƒActual probability distributions

Wall thickness

Material strength

ƒ Pressure in pipe derived in a similar manner

5%ile Characteristic

ƒDerive probability for pipe burst strength

Probability

ƒ Plus others such as ovality, eccentricity and weight

Burst strength

A number of measurements are taken to guarantee line pipe conforms to the specification. These include the minimum and maximum diameters at the ends and along the length of an individual 12 m (40ft) pipe, the ovality, wall thickness, yield and ultimate strengths of the steel and the pipe unit weight. By deriving the actual probability distributions for the measured tolerances in pipe manufacture, it is possible to find the distribution of pipe strength in bursting when subjected to an internal overpressure. Typically, a random number generator produces a figure between 0 and 1.000. Using the total length of ordinate bars on a histogram, the value of the random number can be read along as a proportion of this, so determining a value for each parameter. Nowadays, use of computer programmes can determine exact values, independent of the width of the histogram bars. Depending on the shape of the individual curves, generated numbers can be applied to each of the variable distributions, deriving values for the diameter, wall thickness and material strength for a particular pipe. (Pipe parameter combinations outwith those given in API 5L or ISO 3183 are rejected.) However, for pipe within tolerances, an individual burst strength can then be calculated. In a Monte-Carlo prediction, thousands of runs are used to produce the probability distribution for pipes, and the 95% characteristic value determined. A similar process can be applied to derive the distribution of pressure in the pipe along with the characteristic load.

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LOAD DISTRIBUTION ƒ For each failure mode, define the loads ƒ For each load combination, quantify ƒ Expected variations ƒ Accidental variations ƒ Measurement tolerances

ƒ Apply Monte-Carlo to get load distribution ƒ ƒ ƒ ƒ

Random number generator Uses probability distribution Many thousands of combinations Combined probability graph for loads

For each failure mode we need to consider the load that could lead to that failure. For that load we need to first identify the load equation and those parameters that contribute to the load. For example, if the failure mode is burst through over-pressure, the load is pressure differential across the pipe wall and the parameters that contribute are the internal contents pressure and the external hydrostatic pressure. For each load parameter we then quantify the potential variations and distributions for that parameter. We then apply a probabilistic technique, such as Monte Carlo simulation, to the load equation to determine the distribution of load. Monte Carlo simulation uses random number generators and the probability distributions of the particular loading condition. After many thousands of runs, the combined probability graph can be derived for the loads. Not that the code developers have chosen partial safety factors for the variations and distribution in loads. The designer only has to assess the loads and combinations, and apply the factor to them.

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STRENGTH DISTRIBUTION ƒ For each failure mode: ƒ Define the material properties and parameters to resist the load

ƒ For each property, quantify: ƒ Expected variations ƒ Accidental variations ƒ Measurement tolerances

ƒ Apply Monte-Carlo to get strength distribution

We take the same approach to determine the distribution of strength. The following slide shows the combination of the load and strength distributions on a probability density graph. Note that the code authors have undertaken this work for us, assessing all the tolerances and defining the appropriate partial safety factors.

PROBABILITY OF FAILURE ƒ Calculate characteristic strengths and loads ƒ Set at 5% or 95% confidence levels

ƒ Find probability of failure ƒ Intersection between strength and load curves

ƒ Assess consequence of failure (high - low) ƒ Risk is probability x consequence ƒ Derive safety factors

F[r,s]

Failure domain S

R

R,S

From the Monte Carlo simulations, the code writers calculate the characteristic values for the strengths and loads.

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The probability of failure is then the overlap between the two curves. Separately, the consequences of failure are assessed. The risk is then simply the product of the probability and the consequence. From this, it is possible to derive a set of suitable safety factors to maintain risk at a suitable level.

COMPARISON OF APPROACHES Material Material yield 0.2% ultimate (elastic) (plastic)

Working stress due to load

True loadfactor method Older API and BSI allowable stress methods

Probability

Euronorms & current BSI limit-state

FoS multiplier derives factored load FoS – derives permissible stress

γload Characteristic load, Gk 95%

γmaterial Risk of failure 5%

Characteristic strength, fk

Stress

We may represent the increasing stress levels first due to the loads and then the yield and the ultimate strength of the material on a linear graph. The load factor method simply multiplies the load and checks whether it is less than the elastic limit of the material. This is generally used when the method of calculating the load is not rigorous. In API and older BS codes, a slightly different approach reduced the yield stress by a factor to obtain a permissible working stress for the material. This was then compared with the calculated (un-factored) working stress due to load. Failures occur using the load factor and allowable stress methods, but it is difficult to identify whether the problem lies with the loads or the strength due to the single combined FoS. With the modern DNV, BS and Euronorms, the limit state method is used. It is recognised that the stress due to the load varies over time and may be represented by a probability curve. Similarly, the strength of the material will vary, though over a narrower band. By applying one partial safety factor to the characteristic loads, and one to the characteristic material strength, these probability curves are brought together. The partial factors on the loads cover a number of combinations. Note the shape of the probability curves are different for each. The material factor (which is deemed here to incorporate tolerances on the shape of beam) can be defined as a much sharper curve than that of the loads. This is due to extensive testing and tighter quality control during manufacture. Improved testing can result in smaller partial factors, and ultimately a more economic design.

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The small area of overlap represents where the system would fail. It is normally quoted in terms of powers of ten per year: e.g. 10-3, 10-4 or 10-5 yr-1. More sensitive or critical designs attract higher confidence levels, thus necessitating either higher strength material or thicker wall. In designing using the limit state method, there is no need to worry about the shape of the probability curves. The modern codes take care of these by adjusting the factors that are applied to the characteristic loads (which are defined at the 95% confidence level).

DERIVATION OF SAFETY FACTORS SUMMARY

ƒ Boston square ƒ Cost and likelihood of failure determine risk

ƒ Acceptable target probabilities for pipelines ƒ Risk and reliability ƒ Assessment of probability of failure ƒ Failure at overlap of load and strength distributions ƒ Used to derive partial safety factors

ƒ Comparison of approaches ƒ Load factor, allowable stress and limit state

Any questions? We have introduced the concept of risk being dependent upon the costs and likelihood of a failure occurring. This can be represented on a Boston square. The acceptable targets for pipeline failure given in DNV OS-F101 are categorised into three safety classes. The procedures for risk and reliability assessment result in probability distributions for loads on the pipeline and its strength. The area where these overlap is used to assess likelihood of failure. Such graphs are used by the code writers to derive appropriate partial safety factors. Finally, we underlined the three main approaches used by designers showing how older codes used the yield strength but the limit state codes also use the ultimate strength.

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DNV OS-F101 design

LIMIT STATE DESIGN AND DNV OS-F101 ƒ DNV OS-F101 2000 ƒ Submarine Pipeline Systems (DNV OS-F101) ƒ Comprehensive method for pipeline design ƒ Increase in calculation effort over API 1111

ƒ Associated publications ƒ Recommended practices ƒ Design guidelines

ƒ Limit states categories for a pipeline ƒ Ultimate, serviceability, fatigue and accidental

ƒ DNV OS-F101 design for buckling DNV OS-F101 embodies the limit state design methods and, in conjunction with associated supporting documents, covers all aspects of pipeline design. It is generally more comprehensive than API 1111 but at the cost of a slight increase in calculation effort. As previously stated, there are many limit states for a pipeline with several categories of limit state. We have already covered the categories commonly used. As an example, we will give a flavour of the document in how it designs for buckling.

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DNV OS-F101 STRUCTURE

Gudesp

Multispan

Trawlboard JIP

Spanning

Guideline 13 Interference between Trawl Gear and Pipelines

RP F105 Spanning pipelines Existing CNs, RPs, Guidelines and rules CN30.5 Environmental conditions CN30.6 Structural reliability analysis of marine structures RP O501 Erosive wear in piping systems Guidelines for flexible pipes Rules for verification of flexible risers and pipes RP B401 Cathodic protection design RP E305 On-bottom stability

DNV OS-F101

Deepipe JIP

RP F101 Residual strength of corroded pipelines [internal pressure]

Residual strength JIP

RP F101 Residual strength of corroded pipelines [external pressure]

Guideline X Design of HP/HT pipelines

Guideline X Reeling - Fracture assessment Reeling JIP

Guideline X Design of Deepwater pipelines

SUPERB

Guideline X upheaval buckling Laying Criteria

Hotpipe JIP

Upheaval buckling JIP

This diagram illustrates the general structure of the code. The code is supported by a number of guidelines and recommended practices, many of which are recently developed or still in the process of development.

DNV OS-F101 APPROACH ƒ Ultimate [ULS] ƒ Bursting ƒ Local & global buckling ƒ Unstable fracture & Plastic collapse

ƒ Serviceability [SLS] ƒ Ovality ƒ Accumulated plastic strain ƒ Damage to or loss of concrete coating ƒ Yielding ƒ Ratcheting

ƒ Fatigue [FLS] ƒ Pressure cycling ƒ Vibration

ƒ Accidental [ALS] ƒ Dropped objects ƒ Trawl gear hooking ƒ Earthquake

DNV OS-F101 makes extensive use of limit state design. The areas are shown above. ULS - ultimate limit state SLS - serviceability limit state FLS - fatigue limit state ALS - accidental limit state

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EXAMPLE OF LIMIT STATE DESIGN ƒ DNV OS-F101 local buckle limit state ƒ Load-controlled condition

ƒ Operating pipeline subject to: ƒ Bending moment ƒ Axial force and ƒ Internal overpressure

ƒ DNV combines three limit state conditions ƒ All contribute and interact ƒ Causing local buckle failure

As an example of limit state design, we consider one of the local buckle limit state functions defined by DNV OS-F101. For this, the criteria uses load-controlled conditions with internal overpressure. That is the load conditions representative of an operating pipeline on the seabed. This limit state function considers local buckling due to combined loads. It therefore combines a number of individual limit state conditions and defines how they interact.

BUCKLE CRITERION ƒ DNV OS-F101 criterion ƒ Internal overpressure with load-controlled bending 2 2⎞ 2 ⎛ ⎛ Sd ⎞ ⎛ ⎞ ⎟ ⎛ ⎞ Δp d Δp d ⎜ Md ⎜ ⎟ ⎜ ⎟ ⎜ ⎟ γ SC ⋅ γ m + γ SC ⋅ γ m ⎜ ⋅ 1− ⎜ ⎟ ⎟+⎜ ⎟ ≤1 ⎜ α c ⋅ Sp ⎟ ⎜ α c ⋅ Mp ⎝ α c ⋅ pb (t 2 ) ⎠ ⎟ ⎝ α c ⋅ pb (t 2 ) ⎠ ⎝ ⎠ ⎝ ⎠

Ratio of applied axial force to plastic axial force

Ratio of applied moment to plastic moment

Ratio of internal overpressure to burst pressure

ƒ γSC , γm and αC are safety factors

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The criterion given by equation 5.23 of DNV OS-F101 is based on several ratios and factors. The first ratio is the applied axial force to the plastic compression force. The total axial force is the resultant of the applied tension, submerged pipe weight and end pressure load. The second ratio is the total applied moment to the plastic moment. This gives us the tendency of the moment due to the buckling bend to cause a plastic hinge in the pipe wall. The third ratio is the internal over-pressure to the collapse pressure. This gives us the tendency of the pipeline to maintain its shape whilst pressurised. There are several partial safety factors included in DNV OS-F101. These are included in the equation to help improve the accuracy of the buckling prediction for ‘real life’ conditions. Where: ■ Md = Design bending moment ■ Mp = Plastic moment resistance ■ pb = Burst pressure ■ Sd = Design effective axial force ■ Sp = Characteristic plastic axial force resistance ■ t2 = Nominal wall thickness less the corrosion allowance ■ αc = Flow stress parameter accounting for strain hardening ■ γSC = Safety class resistance factor ■ γm = Material resistance factor ■ Δpd = Design differential overpressure

LIMIT STATE DESIGN - SUMMARY

ƒ Identification of limit states ƒ ULS, SLS, FLS and ALS

ƒ Derivation of safety factors ƒ Risk-based approach

ƒ DNV OS-F101 design approach ƒ Core and associated documents ƒ More comprehensive than API 1111

ƒ Considers all limit states ƒ Local buckles - three interacting limit states ƒ Load controlled condition with bending, axial and overpressure

Any questions? For a particular pipeline design, it is necessary to assess the limit state conditions that apply.

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The authors of the particular code have previously determined the particular safety factors to be considered as variables to the input. Risk and reliability are used to provide a logical derivation of the values. The DNV approach has a number of documents that are fully compatible with limit state design methods making it a more comprehensive approach than the API 1111 – although the latter is slightly simpler to use. Local buckles such as lateral or upheaval buckling are deemed to be load controlled combined with the bending moment, the axial force and overpressure.

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HP/HT AND HIPPS

HIPPS AND HP/HT ƒ High Integrity Pressure Protection System (HIPPS) ƒ Limits the maximum operating pressure of pipeline

ƒ Used on HP/HT systems ƒ High pressure / high temperature (HP/HT) definition ƒ Greater than 690 bar (10 ksi) and more than 150°C (300°F)

ƒ High pressure wells are typically in the range 400 to 1000 bar (5 800 to 14 500 psi) ƒ High temperature wells are in the range 100°C to 160°C (212°F to 350°F) ƒ Generally associated with deep reservoirs

As oil is found at ever increasing depths below the sea bed, then the technology required to extract the oil must meet the specific design that this entails. Although the definition for an HP/HT reservoir is one with pressures over 690 bar and temperatures over 150°C, the term is more loosely applied when one of the parameters lies just outside this range. Deep reservoirs are naturally more highly pressured as a result of the greater depth. Reservoir pressure is typically relative to the water column above it. Reservoir temperatures are relative to the earth’s temperature, which is also a function of depth below the surface. Flowline design pressure is usually based on the shut-in wellhead pressure, which is usually significantly greater than the operating (flowing) pressure.

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HIPPS ƒ Reduce wall thickness – 30% cost reduction ƒ Not 100% reliable therefore full pressure design in critical (high safety class) regions

ƒ Used on Kingfisher project since 1997 Host platform 100 bar (1.5 ksi)

508 mm (20in) production line: ~ 250 bar to 350 bar (3.6 ksi to 5.1 ksi) (low pressure) ~ 30 km to 50 km (20 miles to 30 miles) 102 mm (4in) chemical injection line (full pressure) 102 mm (4in) service/test line (full pressure) 200 bar (3 ksi) operational through choke

Fortified zone for people proximity 500 m (1640ft) safety zone

690 bar (10 ksi) shut-in pressure Manifold with HIPPS

Fortified zone for surge collapse

Because shut-in wellhead pressures can be much higher than normal operating pressures, there is wasted pipeline capacity other than in upset conditions. High integrity pressure protection systems (HIPPS) have been developed to allow pipelines to be designed for the flowing pressures rather than the shut-in pressures and to provide a high degree of confidence that the maximum allowable operating pressure (MAOP) of a pipeline will not be exceeded. This has the potential to offer significant cost savings to production flowlines from satellite developments, where there would be a possibility that the pipeline would see shut-in wellhead pressures (SIWP). For example, if an SSIV (subsea isolation valve) or ESV (emergency shut-down valve) were activated. In a HP/HT development project, the cost of the pipeline can be 75% of total budget. By providing a thinner wall pipeline, cost savings of a third may be made. Any pipeline over 20 km (12 miles) with pressure rating of bar 350 bar (5ksi) or more may benefit. The limit on pressure also applies to other equipment at the platform. The HIPPS system is not 100% reliable and therefore other precautions are typically also taken, for example: ■ ■

Design pipeline for no burst in case of HIPPS failure Increase pressure rating in critical areas ie riser and SSIV to full SIWP

The Kingfisher project went on line in late 1997, and the system operated with no problems until a series of transmitter faults were reported by the HIPPS system. These were successfully resolved by a modified maintenance regime using methanol to clear the orifices of the input lines to the detectors. Despite attracting much attention – as the savings in flow-line costs were several million dollars and the whole project was brought on stream early and under budget – the solution was not repeated for five years. Once proven, however, many repeat systems followed in the North Sea, with over 20 systems installed up to the end of 2005.

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HIPPS LAYOUT Small bore bypass line

Methanol inlet line Maintenance/test valve V1

V2

From wells

To platform

Initiators

P1 P2 P3

Logic solver HIPPS Control system with redundancy

This illustrates the typical HIPPS configuration. It consists of: ■ High reliability pressure barrier (typically two gate valves) ■ High reliability over pressure detection system (typically three pressure sensors) ■ High reliability controls system to operate pressure barrier (typically fully redundant subsea control module) ■ By pass line to de-pressurise behind barrier if activated

HIPPS STANDARD ƒ IEC 61508 standard ƒ Performance-based, non-prescriptive ƒ Verifies safety of potentially hazardous installations ƒ Four safety-integrity levels (SILs) ƒ Higher number - safer

ƒ HIPPS systems ƒ One valve SIL 3 ƒ System SIL 4

ƒ Land-based emergency shutdown systems ƒ In use for over 30 years

HIPPS system on subsea skid with full diameter bypass pipework

Functional safety standard IEC 61508 ‘Safety Standard for Safety Instrumented Systems’ is a performance-based, non-prescriptive method of verifying safety of potentially hazardous installations.

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IEC61508 and its companion IEC61511 are the new standards for the life-cycle management of instrumented protection systems, and will become common-place in major contracts across all process industries in the near future. The need to specify quantitative safety targets for overall systems, and for their separate protection subsystems, has grown rapidly over the last ten years. This feature has become known as Functional Safety and numerous standards and guidelines have emerged, most of which incorporate the idea of safety-integrity levels (SILs). The quantified target (either a failure rate or a probability of failure on demand) determines which of four target SILs is called for. The higher the SIL then the more onerous the qualitative requirements to be observed during the life-cycle. There are different requirements for high and low demand equipment. For the low demand mode of operation, the standard has associated average probabilities of failure to perform its design function on demand as follows: ■ ■ ■ ■

SIL 1 : ≥10-2 to <10-1 SIL 2 : ≥10-3 to <10-2 SIL 3 : ≥10-4 to <10-3 SIL 4 : ≥10-5 to <10-4

An individual valve may only reach SIL3. However, it is possible to achieve a SIL 4 for the complete HIPPS system by using redundant components. Experience and confidence with similar emergency shutdown valve systems has been gained on landlines, where they have been in use for over 30 years. Thus, safety-integrity is addressed from two points of view: ■ Meeting the numerical failure rate target ■ Meeting the qualitative requirements for the SIL in question

HIPPS REQUIREMENTS ƒ Operates independent of other systems at installation ƒ Overpressure quickly isolated at source ƒ Initiators ƒ High accuracy set-point (1%)

ƒ Voting logic ƒ Valves ƒ Robust but slower actuators and valves ƒ Spring-operated ESDV – closures less than 5 s ƒ Actuator oversizing (5 times) HIPPS are designed to operate totally independently of other control systems operating the pipeline or installation. The overpressure in the main line is quickly detected and isolated at the source.

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This is done using three or more initiators with a very high accuracy of set-point. This is typically 1% or better. The voting logic determines if a situation is safe or unsafe based on the output of the initiators. The valves automatically operated by the logic system with no input from operators. Because long flowlines will not be subjected to the full pressure immediately, it is possible to use robust but slower actuators and valves to shut off the flow. Such units are cheaper than fast closure equipment. The actuators are normally spring-driven and are oversized to ensure closure. Typical stroking times usually less than 5 s, although this is dependent upon the diameter and length of the line.

HP/HT AND HIPPS - SUMMARY ƒ Deeper wells will have relatively higher pressures and temperatures ƒ HIPPS systems limit the maximum operating pressures in the pipeline ƒ Therefore enable thinner pipe walls to platform

ƒ Main features of initiators and valves ƒ IEC 61508 standard ƒ SIL levels for function on demand

Any questions? As oil is extracted at ever greater depths, the pressures and temperatures of the well fluids increase. This then requires the development of pipeline systems that can accommodate higher pressures and temperatures. The increases in temperatures can mean significant increases in wall thickness of the pipelines to ensure pressure containment. HIPPS systems have been developed to limit the maximum operating pressures within the pipelines at greater depths. The objective is to enable thinner walled pipe to be installed and so save on the cost of the pipeline materials. The main features of the HIPPS initiators and valves have been listed. These need to be supplied to IEC 61508 in order to ensure that the system functions on demand at the appropriate SIL level.

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FISHING INTERACTION

NON-TRENCHED PIPELINES ƒ Traditional UK practice - 406 mm (16in) rule ƒ Pipelines less than this diameter trenched ƒ This and larger diameters not trenched

ƒ Basis ƒ Shell tests (late 70s) ƒ Subsequent Department of Energy guidelines

ƒ Now small diameter lines left on seabed untrenched when safe to do so ƒ Foinaven and Schiehallion

ƒ USA – trench all inshore and larger lines ƒ Smaller lines self-bury in soft sediments Pipelines are trenched for three reasons: ■ stability ■ insulation ■ protection from trawl gear Trenching for stability reasons is seldom needed except in shallow waters. The main reason for trenching in the past has been for protection of the pipeline from trawl gear. Traditionally in the North Sea, all pipelines of less than 406 mm (16in) diameter have been trenched. Whilst there has never been a legal requirement for this, the UK Department of Energy issued guidelines in 1984 (based on work carried out by Shell) which spawned the 16in rule of thumb for trenching of small diameter pipelines. More recently, limit state design has been applied to the interaction of trawl gear on pipelines leading to a number of developments not trenching small diameter lines. Reference: OTH 561 - HSE Offshore Technology Report - Guidelines for the Trenching Design of Submarine Pipelines, prepared for HSE by Jee, 1999.

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In the US, regulations differ: larger diameter lines and those in shallow water close to shore must be buried. States have different distances from shore or depths to determine what pipelines are classified as ‘inshore’. In the softer sediments of the Gulf of Mexico smaller diameter pipelines will self bury and there are no large trawlers cutting through the seafloor. However, a risk has been identified of the small, local shrimp-boat trawls snagging on larger pipelines: an incident has occurred in shallow water caused by a vessel hitting and rupturing a large diameter gas-line, resulting in the total loss of boat and crew in the resulting fireball.

TYPES OF TRAWLING ƒ Pelagic trawls ƒ Large vessels fishing midwater (herring and mackerel)

Warp Otterboard Net Bridle

ƒ Weights can touch seabed

ƒ Demersal beam trawls

Weight

ƒ Large steel beams hold net open ƒ Tickler chains force Warp fish upward ƒ Beam impacts directly Beam with pipelines

Net

A number of different types of trawling are used. Some of these can impact with pipelines or subsea structures. Pelagic (mid-water) trawling is not normally a problem for the oil and gas industry. Although these powerful boats are extremely large, operating out of port for many months at a time, the trawl nets are held open with doors (or otterboards) that are designed to stay above the height of pipelines and well head manifolds. By adjusting the speed of the vessel, the net height can be lifted or lowered to intercept shoals of fish. However, the risk is from the weights used to keep the net down. These inevitably touch the bottom from time to time and are typically 1.1 tonnes up to as much as 5 tonnes. The vessels operate at 1.9 m/s (3.75 knots) to 2.8 m/s (5.5 knots) for the fasterswimming mackerel. Beam trawls are used for whitefish and flatfish (sole plaice or megrim). Two nets are trawled from warps attached from either side of the vessel. The beams used to hold the net open can be 9 m to 12 m long and weigh up to 10 tonnes. Towing speeds are between 2.1 m/s and 3.6 m/s (4 and 7 knots). The fishing grounds may be as deep as 200 m (650ft). Allowance needs to be made for added mass of the water in and around the beams, the chains and other gear. Scallops are also dredged using drag rigs, sometimes with a number of small toothed nets trailing behind a bar. However, the size and weight of these bars is somewhat less than for beam trawlers.

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Reference: A Fishing Industry Guide to Offshore Operators published by the Fisheries and Offshore Oil Consultative Group March 2001, ISBN 0 7559 0162 2.

TYPES OF TRAWLING ƒ Demersal otter trawls ƒ Commonest trawling method (round fish & shell fish) ƒ Mud plumes guide fish into mouth of nets

ƒ Otterboards and clumps impact and drag ƒ Boards can Warps get stuck Otterboard under spans Sweep ƒ Fishermen follow Clump Net Bridle pipelines (FAD) Headline floats Groundgear Bridle ƒ Depths to 1000 m rockhoppers (3300ft)

The commonest method of trawling uses bottom or demersal otterboards. These are of a slightly different shape to those used for pelagic trawling. The fish are demersal (bottom dwellers) or benthic (live in the mud), such as cod, flatfish and nephrops (scampi). They are of higher value at market than pelagic fish, which tend to come ashore already sold, fully prepared for the supermarket shelves. Otterboards are used to hold the nets open. The floats on the headline lift the top of the net and the groundgear (kept somewhat behind the headline and consisting of chain and circular rubber disks called rockhoppers) ensures that the mouth of the net is kept in close contact with the seabed. The fish are guided into the net by plumes of mud disturbed by the heavy otterboards (trawl doors). Smaller fish can escape through square mesh panels in the net but larger ones collect in the cod-end. The otterboards are between 5.3 m² and 8 m² (57ft² and 86ft²) and weigh between 1.4 tonnes and 3 tonnes. Again allowance should be made for added mass. The central clump weights are roller or drag chain type and can be as heavy as 2 tonnes. Towing speed is between 1.3 m/s and 1.8 m/s (2.5 and 3.5 knots). It is common for these trawlermen to closely follow pipelines. These are fish attractive devices (FAD) because of the warmth and protection from currents. Trawl scars can even be found in the seabed above buried pipelines. There are other types of fishing used throughout the world (such as purse seine, gill netting, baited lines, creels and lobster pots) but these have little effect on oil field developments.

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DESIGN APPROACHES ƒ Overtrawlable ƒ Structure cannot snag trawl equipment ƒ Otterboard, ground equipment and nets ride over

ƒ Cannot be damaged by warp wires ƒ Smooth surface - truncated pyramid ƒ No obstructions or gaps ƒ Not too high

ƒ Fisher-friendly ƒ ƒ ƒ ƒ

Location noted on charts Structure catches trawl gear but does not hold fast Trawler reverses and easily recovers gear Preferred by some fishing associations

There are two approaches made by the offshore oil and gas industry when designing structures for the seabed. Pipelines and many well heads, manifolds and valves are normally designed to permit trawling over them. A common approach is to make the protection structures from tubular members with infill panels in a truncated pyramid shape. The side slopes are typically 50° or less and the height less than about 5 m (16ft). The panels are often hinged or removable to allow access in the future. Trawl boards can jam in any gaps left beneath or within the framework. Warps can hold fast, or be guided by protruding bolt heads or other features and act as a cheese wire, cutting into the structure. With high structures and steep sides, it is possible for the rockhopper disks to tighten around the corner diagonals. A lot of such protection structures, although still being installed as overtrawlable, are not. It is perhaps a surprise that some enlightened fishing associations (such as the SFF) actually prefer structures not to be classified as overtrawlable but ‘fisher-friendly’. This means that they are labelled as such on charts and fishermen avoid them. However, should a trawl approach such a structure, the gear will not pass over it. The trawler can reverse and recover the nets easily. This means that the structure should have no overhanging snags or hooks that might cause the warps or bridles to be caught fast, preventing recovery.

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TRAWL GEAR VIDEO

Jee has carried out research on the interaction of trawl gear and pipelines. The video clip shows the various types of trawl gear, their motion across the top of the pipeline and the resultant loadings on it. These are discussed further in the next slide. Note that the term ‘warp’ refers to the wire leading from trawler down to the trawl door (or otterboard). For pipeline interaction, we are concerned with sea floor (demersal) fishing for cod, flatfish and shrimp rather than the mid-depth (pelagic) species. The picture shows two typical V-type, steel otterboards as used in the North Sea.

EFFECTS OF TRAWL GEAR

Effect Impact

Consequence Dent

Pullover

Deflection and yielding Deflection and yielding Gear snagged

Hooking

Limit state Fatigue or Serviceability Ultimate (local buckle) Ultimate (local buckle) Ultimate (gear loss)

Remedy Coating or trench Trench Trench Inform

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There are three main interaction effects due to trawl gear passing over pipelines. The first is the impact when the gear first comes into contact with the pipeline. This is similar to a dropped object impact and can result in a dent. The main protective measure against it is to apply a coating to the pipe. The second effect is the pullover force as the gear is pulled over the top of the pipeline. This can drag the pipeline and bend it, in extreme cases resulting in a local buckle. The remedy for this would be to trench the pipeline to get it out of the way of the trawl gear. The third effect is hooking of fishing gear on the pipeline. In other words, the gear passes under the pipeline and becomes entangled to the point where it comes fast. For small diameter lines, when the fishing vessel pulls hard it will lift the line and release the gear, so there is no permanent entrapment of the gear. The implication is that the design of the flowline needs to accommodate accidental lifting of the line by a height sufficient to release the trawl gear. For larger diameter lines, 324 mm to 406 mm (12in to 16in) and above the vessel may not be able to lift the pipeline sufficiently before the warps break and this tends to be more of a problem for the fishermen than the pipeline. (Protection using rock dump is covered elsewhere.)

FISHING INTERACTION - SUMMARY ƒ Two approaches for structures ƒ Overtrawlable and fisher-friendly

ƒ Significant impact and bending loads were thought to be applied to small diameter pipelines by trawl gear ƒ Trenching small diameter pipelines was previously the solution ƒ Modern limit state design no longer requires all pipelines to be trenched Any questions? We have covered the types of trawling that may impact with subsea oil and gas pipelines and seabed structures. The two approaches for protection are to make them fully overtrawlable or to ensure that fishermen will be able to recover gear if they clash. Previous pipeline design philosophy was to assume that trawl gear interaction could impart significant impact and bending loads to small diameter pipelines. In the North Sea, it was usually specified that small diameter pipelines were trenched to protect them from trawl gear. However, modern limit state design codes applied to

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recent pipeline designs has meant that some small diameter lines are no longer required to be trenched to protect them from trawl gear interaction.

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VORTEX-INDUCED VIBRATION

DESIGN OF STEEL RISERS ƒ Hydrodynamic loadings ƒ Give rise to bending

ƒ Oscillatory loads ƒ Waves and currents ƒ Vortex shedding ƒ Give rise to fatigue

The riser experiences hydrodynamic loadings from the seawater flowing past. The riser is therefore subjected to bending. Fluctuating loads due to waves and VIV will induce fatigue damage.

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WHAT IS VORTEX SHEDDING?

As a fluid flows past any bluff body, such as a riser, it will not be able to stay attached to the body. The flow separates from the body and vortices form behind it. These vortices are unstable and are shed and drift downstream. This is illustrated above. The coloured contours show the vorticity in the flow (i.e. areas where fluid is swirling). Vortices are being shed alternately from either side of the riser. The shedding frequency for a rigid riser depends only on the riser diameter and the fluid velocity. As the velocity increases, so does the shedding frequency.

Vortex shedding frequency

VORTEX-INDUCED VIBRATIONS (VIV)

Locked-in Cross-flow 2 x Nat.freq.

Locked-in In-line Nat.freq.

Non-flexing riser response

Flexing riser response

Flow velocity

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The changing flow patterns cause fluctuating drag and lift forces on the riser. These fluctuating loads cause the riser to oscillate. When the frequency of these forces is close to the natural frequency of the riser span, the riser resonates and large-amplitude vibrations occur. This effect is vortex-induced vibration. Vortex-induced vibrations occur in two forms: ■ In-line vibrations (where the riser moves backwards and forwards in the same direction as the current flow) and ■ Cross-flow vibrations (where the riser motion is at right angles to the current flow). The figure above shows how the riser response changes with current velocity. Initially the vortex shedding frequency increases linearly with the flow velocity. As the frequency of vortex shedding approaches the natural frequency of the riser span, the amplitude of oscillations increases. The riser oscillations then start to control the vortex shedding and the riser oscillations and the vortex shedding lock-in at the natural frequency of the riser span. At first this will be in the form of in-line vibrations. As the current velocity increases further, the in-line vibrations die out and are then replaced by larger-amplitude cross-flow motions at twice the natural frequency of the riser.

TRIALS OF PIPELINE VIV - VIDEO

The video shows the results of a test of a pipeline span in a tow tank. The short section of pipe is sprung at the ends in order to permit movement. We first see the in-line vibrations from the top of the pipe, then as the velocity increases, the camera angle moves to the rear and the more violent cross-flow oscillations occur.

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PREDICTING RELATIVE RESPONSE OF VIV 1.2

Amplitude a/D

1

0.8

0.6

0.4

In-line

0.2

Cross-flow

0.15 0 0

1

2

3

4

5

6

7

8

9

10

11

12

Reduced Velocity Vr = V / (Fn× D)

An overview of the response of vibrations is illustrated above. The axes are nondimensional amplitude and velocity. As flow velocity increases, in-line vortex induced vibrations are initiated. The first mode of in-line oscillations is caused by symmetrical vortices being shed. The second mode is caused by asymmetrical shedding. At higher flow velocities, the fluctuating loads due to the asymmetric shedding induce vibrations in the cross-flow direction. These are of much larger amplitude.

VIV SUPPRESSION STRAKES Strake mouldings banding strapped to pipeline

CRP installing strakes on stinger

Strakes fitted to chimney for wind VIV suppression

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The oscillation of the pipe will give rise to fatigue damage. If the analysis of VIV predicts that fatigue life will be too short, then the solutions are to support the riser more frequently or to add VIV suppression devices (such as helical strakes) to the span. Strakes are a familiar sight on the tops of tall factory chimneys. They disrupt the vortices to give a confused but steady wake, thus removing the excitation force. They do increase the drag (about double), so the hydrodynamic loadings need to be checked again. Strakes are also used to suppress vibrations on long risers (where adding a guide is obviously not an option). Note that strakes are available in a range of pitches and heights.

COMPUTATIONAL FLUID DYNAMICS

Since we are looking at technology issues in this course, here is a brief word about the use of CFD (computational fluid dynamics), which in the broadest of terms is like finite element analysis for fluids. The above diagram shows a CFD model of flow around a straked riser. This analysis was done by Jee in order to understand the behaviour of fluid flows around strakes with different configurations. This study was the first step towards improving and optimising the strake profile to give maximum suppression for minimum drag.

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OTHER VIV SUPPRESSION OPTIONS ƒ More supports ƒ Reduce effective span length

ƒ Shrouds ƒ Fixed

ƒ Fairings ƒ Fixed or rotating

Perforated Axial slatted shroud shroud

Perforated shroud with barnacles

Guide vane

Streamlined Splitter plate Flexible fairing fairing haired fairing

For rigid risers fixed to jacket legs using sleeves, one option is to reduce the effective length between the supports. Guides will reduce the span length, increase the natural frequency, lower the reduced velocity (perhaps moving the riser out of the cross-flow regime) and reduce the bending stresses. Shrouds or splitters can be used. A range of designs is shown above. They work in slightly different ways. Shrouds have the advantage in that they are omni-directional. They are effective from whichever way the current comes. They disrupt the flow around the riser and break up the vortices. Where there is a dominant direction of current flow, fixed vanes or fairings can be used. If the current direction is not constant, then these units need to be allowed to swivel around the pipe. Streamlined fairings work by allowing the flow to remain attached so that vortices are not formed in the first place. They have the advantage in that the forces acting on the pipe can be greatly reduced. Splitter plates do not stop vortices forming, but they separate the flow passing on each side of the riser and prevent the vortices from interacting. This stabilises the flow and stops the vortices from being shed. The photograph shows a square perforated shroud on a riser. However, it also shows that the grill openings are ideal niches for marine growth, which may block and nullify the protection.

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VORTEX-INDUCED VIBRATION SUMMARY ƒ Loads on risers ƒ Hydrodynamic forces ƒ Oscillatory loads

ƒ VIV and fatigue ƒ Strakes and shrouds Any questions?

The main design aspects included bending forces due to structural considerations but also wave and current loads. The latter might result in fatigue caused by vortex-induced vibration. Strakes and shrouds were examined as a solution to this problem.

CURRENT DESIGN METHODS SUMMARY ƒ Limit state design ƒ Numerical evaluation of risk

ƒ HP/HT and HIPPS ƒ Long step-outs

ƒ Fishing interaction ƒ Need for pipeline burial

ƒ Vortex-induced vibration ƒ Reduced fatigue life

Any questions? By making use of limit-state methods and risk-based design, it is possible to provide a logical basis for determining pipeline rupture frequency.

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HIPPS makes safe use of thinner wall pipe on long step-outs. Proper evaluation of fishing effort and activity enables unburied pipelines to operate at appropriate levels of risk. Reduction in VIV means extending the fatigue life of risers and spanning pipelines.

Common work

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EXPECTATION

EXPECTATION ƒ ƒ ƒ ƒ

Construction survey Route preparation Welding Non-destructive testing (NDT)

Whichever method of installing the pipeline – be it flowline or trunkline – there are some common activities which apply to all installation methods. We are required to survey the pipeline route before and after pipelaying. This module provides the common types and equipment used for surveys. The preconstruction survey ensures that the route is clear. Here, we examine the particulars for this route survey. Where the seabed is not suitable, some activity may be necessary to clear or improve the route. At present most pipelines are welded. The main methods of welding are covered along with the non-destructive testing needed at each and every weld.

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CONSTRUCTION SURVEY

SURVEYS DURING CONSTRUCTION

Year 1

Year 2

Year 3

Year 4

Year 5

Year 6

Year 7

Year 8

Year 9 Year 10 TYPICAL PROJECT

Seismic exploration Exploration drilling

Deep seismic and metocean

Feasibility Conceptual design Front end engineering design Detailed design

Desktop

Procurement Construction Production drilling

Geophysical and geotechnical

Prelay, post-lay and post-trench

Commissioning Operation

As-built

Inspection

As we saw earlier, a number of surveys are carried out during the construction period. Here, we will particularly look at the pre-lay, touchdown during lay, post-lay, posttrench, post-burial and as-built surveys.

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PRE-CONSTRUCTION SURVEY OPERATIONS ƒ Confirms route remains clear ƒ Additional survey for minor changes to route ƒ Cover full width of anchor pattern ƒ Towed sonar fish, ROTVs and AUVs

ƒ Detailed surveys for areas of remediation ƒ ƒ ƒ ƒ

Sandwaves to remove Pockmarks to fill Rock to clear away Towed equipment and ROVs

ƒ Details of tie-ins at wellheads and riser ƒ Length of spools ƒ ROVs and divers It is often the case that minor additions to the survey route will be required. Occasionally, discrepancies in the original work need to be resurveyed to prove the route remains clear of shipwrecks and debris. This work is usually undertaken using towed fish, vessel-mounted sonar or remotely operated towed vehicles (ROTVs). Sometimes, additional survey work is needed to cover the full width between the anchors: the final anchor pattern is determined by the particular vessel and the client may not have covered sufficient distance from the pipeline centreline. Autonomous underwater vehicles (AUVs) can be used to undertake longitudinal and transverse lines efficiently. Where there are mobile sandwaves, the area needs to be resurveyed to estimate the volume to remove. Other areas that require improvement are often resurveyed in more detail by the rock-dump or blasting sub-contractors. In addition to the towed fish, remotely operated vehicles (ROVs) are ideal for detailed surveys of smaller areas. Where improvements have been made immediately before laying, the new condition of the seabed is resurveyed to confirm its condition. It is useful to resurvey the tie-ins in more detail. This may be to confirm the orientation of the wellhead and double check the length of the spools to be used. For these tasks, we can use ROVs, or even divers in shallower waters. At present, we do not re-test the soils along the pipe route – whereas for cable installation, this is now becoming standard practice.

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SURVEYS DURING & POST CONSTRUCTION ƒ Monitoring of touch-down point ƒ Confirms stress in pipeline less than yield ƒ Pipeline kept within construction corridor ƒ ±5 m or ±3 m (±15ft or ±10ft) ƒ Tighter tolerance at pipeline ends, crossings and bends

ƒ ROVs and vessels

ƒ Post-lay ƒ Checks for spans at undulations of seabed ƒ Remediation requirements

ƒ ROVs and ROTVs

ƒ Post-trench and post-burial or rock dump ƒ Cross-section of trench and depth of cover ƒ ROVs and ROTVs The touchdown point of the pipeline is continuously monitored to ensure no overstress of the pipeline by whichever method of lay. It is important that the line be maintained within the construction corridor. This is generally set at 10 m (30ft) wide although at the ends of the pipeline and critical points such as crossings and horizontal bends it may be less. Following laying, surveys determine where spans need rectification. If the pipeline is to be trenched, then the depth and shape of trench is measured. Where burial or rockdump is required, then the cover is checked to prevent upheaval buckling. Normally, a combination of ROV and ROTV surveys provide assurance to the client that the pipeline has been installed in accordance with specification.

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CONSTRUCTION SURVEYS SUMMARY ƒ Pre-construction ƒ Route resurvey and preparatory work

ƒ Touchdown position ƒ Avoid buckling of pipeline

ƒ Post-construction ƒ Assure client that pipeline installed to specification

Any questions?

Pre-construction surveys are undertaken to assure the contractor that the design survey has identified all obstructions and where preliminary work is needed. Surveys are carried out at all stages of construction to provide assurance both to the contractor and the client that the pipeline is being installed according to the specification. That is, it has not been overstressed and it is within the corridor permitted with no unexpected spans, and for trenched pipelines it is at the correct depth.

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ROUTE PREPARATION

START-UP ANCHORS ƒ Initiation target box ƒ ±3 m by ±5 m along centreline (±10ft by ±15ft)

ƒ Start-up anchors ƒ Distant from end of pipeline – 5 to 8 x water depth

ƒ Fixed points

Chains and rings on seabed

ƒ Large mooring anchors in a pattern ƒ Individually tested

ƒ Driven pile ƒ Suction (can) anchor ƒ Clump

Pipeline end target box

Wire and chain to laybarge

A target box for the end of the pipeline will have been defined in the coordinate system. The coordinates are often defined as Eastings and Northings with reference to the universal transverse Mercator (UTM) for a particular geoid such as ED50 – the European datum defined in 1950. The fixed point is often a long distance from the target box. For high tension installation methods, such as S lay, it can be 5 to 8 times the water depth beyond the end of the startup point. Often, such anchor legs are referred to as having a ‘scope’ of 5 to 8. The holding power of a number of standard anchors can be utilised. Each is individually positioned and tensioned against the vessel’s own anchors or a temporary anchor laid specifically for the purpose at the bow. The groundleg chains are joined with rings and brought together to connect to the abandonment and recovery wire of the lay vessel. Though four anchors are shown here, with very high tensions 8, 12 or 16 high holding capacity anchors may be required. Alternatively, a pile or suction anchor may be installed with an attached length of groundleg chain. This pile is normally removed after the installation.

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The clump anchor is the simplest method but it limited to shallow water and low tensions. A dead weight of concrete and steel is placed on the seabed – it relies on simple friction so the submerged weight needs to be three or four times the holdback tension. It is most suited to sandy bottoms with higher friction coefficients than mud or clay soils. The wire is attached to the installation head on the end of the pipeline. Its length is carefully adjusted to ensure the pipeline touches down within the box. It is rare that a pipeline can be initiated using the existing structure of the platform. This is because of the distance required and alignment. Also, the forces mean that the jacket structure would need to have been designed with this use in mind.

ROUTE PREPARATION ƒ Route preparation means clearing and preparing the route for pipelay: ƒ ƒ ƒ ƒ ƒ

Debris removal Rockdump rough terrain Prepare start-up and laydown locations Prepare crossings Pre-sweep sandwaves

Debris removal involves shifting objects which may have been dropped or dragged onto the route since the route survey. These will normally only be moved if they present an obstruction (or in the case of unexploded munitions, a danger) to pipelay and cannot easily be avoided. If the pipeline is to be trenched, disused cables, anchor chains and wires will be cleared or cut so as to avoid tangles with the trenching equipment. On the approaches to the Norwegian coast, there have been instances where large piles of rockdump have been placed to support a pipeline across submerged valleys which would otherwise have led to unacceptably long spans. Startup and laydown locations sometimes need a layer of concrete mattresses to keep the pipeline ends clear of soft soil, with the flooding valves accessible to ROV or divers. Also, there are cases where a separate anchor or pile may be installed for the laybarge to pull against, though this operation is usually done by the laybarge itself. The sketch at the bottom of the picture shows a typical crossing construction, where concrete mattresses have been placed either side of an existing pipeline. This allows the new pipeline to be laid across, and then rock-dumped for stability and making the system overtrawlable.

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PRE-SWEEP SANDWAVES

120 m (400ft) max

Pre-sweeping to clear (or reduce) sandwaves is normally carried out by trailing suction hopper dredgers, such as that shown schematically above and in the picture below. A pipe with a suitable head is trailed at the required depth and the spoil sucked up into the hold of the ship. Excess water is skimmed off. The pre-sweeping is undertaken only a few days prior to the pipe-laying operation to reduce the risk of the area being naturally backfilled prematurely. The maximum operating depth for such a vessel is in the region of 120 m (400ft). However, sandwaves typically occur where the water depth is less than this, and there is a mobile sandy seabed with high currents.

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TRAILING SUCTION HOPPER DREDGER

Queen of the Netherlands, courtesy Boskalis Offshore bv

Typically the sand and water mix is sucked up and discharged into the hold. The water and fines drain off and discharge directly to sea through the overflow. A plume of fines is inevitably discharged into the sea. It may take 2 hours to fill the hold before the vessel sails to the discharge site. The sand can be discharged in three ways: ■ by directly opening the hopper doors and dumping through the water column onto the seabed. Although some fines are lost in this way, the dump is rapid and this minimises discharge of a plume ■ by pumping through a fall pipe or the suction pipes down to the seabed. This results in a cleaner water column at the spoil site and may be needed for environmental concerns. ■ by pumping through floating hoses or spraying from a ‘trumpet’ at the stern to discharge onshore in a land reclamation area. Again this minimises the amount of fines in the water So it can be seen that most of the loss of fines in a plume is during the loading operation rather than the discharge.

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SAKHALIN - VIDEO

Glory Hole

SALM Buoy

Rock Pad

Pipeline The Russian Sakhalin development – just north of Japan – has to contend with frozen seas in winter. The SALM buoy is stored in a glory hole during these months. The film shows the excavation and levelling of the glory hole using a trailing suction dredger. Additional seabed preparation was carried out for the pipeline and to provide scour protection for the platform. Because the pipeline was only two kilometres (a mile and a quarter) long and the site is in a new area of development, a crane barge was adapted with the addition of a stinger to become the laybarge.

ROUTE PREPARATION - SUMMARY ƒ ƒ ƒ ƒ

Remove debris, soft areas and fill hollows Prepare startup anchors Prepare crossings of existing pipelines Sand wave presweeping ƒ Undertaken just days before pipelay

Any questions?

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The route is prepared for the pipeline in advance of pipelay activities. This means that any debris between the outer laybarge anchors may have to be removed. Hollows or soft material along the route may need to be filled to provide a sound foundation for the pipe itself. At startup and laydown, there may be clearance requirements or deadman anchors may need to be installed. Where the route crosses existing pipelines, protection must be given to prevent damage. If the route cannot avoid sandwaves then these are removed just days before the laying. This avoids the waves reforming due to current movement.

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WELDING

WELDING ƒ Three welding techniques used on firing line ƒ SAW sometimes used for double headers

ƒ ƒ ƒ ƒ

Joint preparation - V or U shaped welds Manual, semi and fully-automated Welding specifications for steel pipe Defects and defect detection

There are three welding techniques that are commonly used on laybarges to join the individual pipes together on the firing line. We are not including in these the SAW method that we saw used for pipe manufacture and which is sometimes used to join two 12 m (40ft) sections into a ‘double header’ or ‘double joint’. This necessitates rotating the pipes in a separate bay. For all three techniques, we are going to examine the preparation of the pipe ends, the shape of which is determined by the welding method and whether it is manual or automated. The former produces V shaped welds, the latter produces the more efficient (narrower) U shape. The standard bevel end to a pipe is for V slots: the alternative J preparation is for U slots. We will touch on the need to prepare full welding specifications and look at the methods and types of defects which need rectification.

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WHAT IS WELDING? ƒ Most expensive operation for offshore lines ƒ General welding requirements ƒ Means of melting or fusing metal ƒ Strength at least that of pipe wall ƒ Other physical properties to be acceptable ƒ Testing coupons

ƒ Exclude air from weld ƒ Remove oxides from the weld

Field-welding is the most expensive factor in construction and is the most common method of joining pipe sections for oil and gas pipeline construction. The weld deposits should have a tensile strength at least equal to the parent metal, and with a compatible chemical composition. Most welding methods used for pipelines use a filler material (electrode) and an electric arc between the electrode and the pipe to melt the metal. Test coupons are used to prove the other properties of the proposed welding method. These relate to the brittleness and toughness of the surrounding pipe steel as well as the weld. Air needs to be excluded from the weld deposit. This is done by the use of a gas as a shield. Some methods also use a flux, which forms a layer of slag over the solidified weld material.

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WELDING ƒ General welding considerations ƒ Welding techniques ƒ SMAW - stick ƒ GTAW - TIG ƒ GMAW - MIG

ƒ Welding methods ƒ Manual ƒ Semi-automatic ƒ Fully automated

A number of techniques are used for field jointing of pipelines, the most common being shielded metal arc, gas-tungsten arc and gas-metal arc welding. Their common names are stick, TIG and MIG respectively. The latter two of these lend themselves to semi-automatic and fully automatic processes. The shielded metal arc is solely a manual method, during which the welder fully controls the position of the electrode and the speed of the formation of the weld. This ‘stick’ technique is very common where there is a skilled workforce readily available. This includes the USA. Repairs of defects in automated welding are often undertaken by trained welders using SMAW. By semi-automatic, we mean that there is some input from the welder. He needs to adjust the lateral position of the ‘bug’ to ensure that the weld follows the correct track. This is a very common method in Europe. Fully automatic welding employs a laser device so that the bug can be guided automatically. The welder is only required to fit the track and start the operation. This is yet to gain common acceptance in the offshore pipeline industry for field-welds but is often used for factory operations - such as the SAW method for pipe manufacture.

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SHIELDED METAL ARC (SMAW) STICK

Flux coating Arc between electrode and pipe

Consumable electrode

Evolved gas shield Slag layer (to be removed)

Core wire

Weld metal Parent metal or previous weld pass Shielded metal arc welding is also known as stick welding or manual metal arc (MMA). Heat is provided by an electric arc that melts a consumable electrode and also some of the parent metal. When it cools, it hardens to form one pass of the weld. The consumable electrode serves as one pole of the arc, the pipe steel being welded as the other pole. Electrode, steel pipe and arc make up an electric circuit back to the power source, which may be either DC or AC. A covered electrode has a solid metal core and an outer layer of material that insulates the core from accidental contact with the pipe wall. The core covering also provides gas to shield the weld from air and it may also contain special elements to improve weld quality. Manual methods using stick electrodes are limited in the amount of weld metal that can be deposited in a single operation. This is due to the volume of metal contained within the electrode. Before a new electrode is started, the weld metal needs to be exposed by removal of the slag layer. SMAW is mainly used on steels, including carbon steels, stainless steels and nickel alloys, and can be applied over a wide range of thicknesses. Materials require cleaning following welding, but because of the flux/slag, some minor contamination is acceptable.

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SMAW CROSS-SECTION

Cap pass Filler passes Hot pass Root pass

30° angle bevel 25 mm (1in) plate 1.5 mm (1/16in) root face Courtesy of CRC-Evans

The first two welds - the root and hot passes - may be completed by the line-up team, with the bulk of the welding finished by follow-up welders. The thinner capping layer aims for a smooth finish to eliminate stress concentration build-up. The root pass is critical - it can “burn through” the wall and melt away the metal, dropping it into the pipe. A removable copper ring is sometimes attached to the line-up clamp in order to prevent this. The aim is to deposit a similar amount of weld material on each pass. It is not desirable to place too much in a single pass because of stresses that build up on cooling. Cracking of the adjacent parent metal may then occur. The root pass can be made from inside the pipe and subsequent passes from the outside (though normally, all would be made from the outside). Slag needs removing before the next weld pass or coating repair. Thin-walled pipe may only require one filler pass. Limitations of this method are that it is not an easily controlled process, and can therefore result in shape defects, slag inclusions, Hydrogen Induced Corrosion Cracking (HICC) and arc strikes. The direction of welding (whether it is from above, or vertical or even from beneath) must be taken into account. Access for the welder and the length of the rod must also be considered, especially when working underneath the pipe (in the overhead position).

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SMAW METHODOLOGY ƒ Consumable stick electrode with covering (usually cellulose) ƒ Weld shielding by CO2 released from electrode coating ƒ Welder positions electrode and compensates for electrode consumption ƒ Welder has to stop when electrode fully consumed

GAS TUNGSTEN ARC (GTAW) - TIG

Ceramic gas nozzle Gas shield

Tungsten electrode Reel feed

Arc

Weld metal

Filler wire

Parent metal or earlier weld pass An inert gas shield is required when welding with tungsten electrodes using the gastungsten arc welding (GTAW) process. This process is particularly suited to welding thin material and to depositing the first weld bead (root pass) because penetration can be controlled more easily than with other welding processes. Good heat control is possible with this process and it is possible to weld with or without filler metal.

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The non-consumable electrodes are not deposited as part of the metal weld. The steel being welded is melted, and the electrode serves only as one pole of the electrical circuit. Usually with pipeline welding, however, a filler wire is fed into the weld joint, providing additional material. The filler wire is supplied from the reel feed.

GTAW METHODOLOGY ƒ Also known as Tungsten Inert Gas (TIG) ƒ Semi-automatic or automatic ƒ Non-consumable tungsten electrode ƒ Filler metal wire fed continuously to weld ƒ Shielding by inert gas supplied externally

GTAW can be used on all weldable materials including steels, stainless steel, nickels, aluminium, magnesium, copper and reactive metals such as titanium. It can weld up to around 6 mm (0.25in) joint thickness if done manually. Automated GTAW methods can weld thicker sections. The materials must be very clean both chemically and mechanically as there is no flux/slag as in SMA. Its limitations include ■ Can result in tungsten inclusions in weld ■ Root concavity ■ Limited penetration/fusion ■ Crater pipes and porosity ■ Needs high pressure inert gas supply with own inherent safety issues ■ May need water cooling supply to torch

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GAS METAL ARC (GMAW) - MIG

Reel feed Gas nozzle Gas shield Arc

Weld metal

Consumable electrode (filler wire)

Parent metal or earlier weld pass This is similar to GTAW but the electrode is now consumed from the reel. It also provides filler material for the weld. This is the method used by the CRC-Evans automatic welding machine - a popular and well-proven method dating from 1980s.

GMAW METHODOLOGY ƒ Also known as metal inert gas (MIG) ƒ Semi-automatic or automatic ƒ Consumable electrode wire fed continuously to the weld ƒ Shielding by externally supplied inert gas (usually argon) ƒ No flux build-up ƒ ‘Fast and furious’ ƒ Use of surface tension transfer (STT) – more control

ƒ Similar end preparation to GTAW

Gas metal arc welding also uses heat from an electric arc. The arc is covered by an inert gas, such as argon or helium. The inert gas shielded metal arc process uses a consumable, continuous electrode. Since this process requires no flux, no slag is produced on top of the weld. Gas for shielding is delivered to the weld area through a

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tube. GMAW is particularly applicable to difficult metals and alloys susceptible to contamination from the atmosphere and porosity. CO2 can be used as a shielding gas in this method. It can weld similar metals to GTAW and weld joint thicknesses from thin to very thick sections. Pre-cleaning of the parent materials is required as there is no flux/slag. Its limitations include ■ Lack of fusion ■ Porosity ■ Silica inclusions ■ Solidification problems (cracking etc) When compared with GTAW, it has been described as being fast and furious. Some weld specifications require the root and hot pass to be undertaken in GTAW, with the filler and capping passes in GMAW. However, other specifications reverse this; it should be noted that either method can be used for the whole weld. The newer process of surface tension transfer (STT) overcomes the lack of control with conventional MIG, and yet provides rapid controlled welding with minimal weld spatter. This is commonly used for oil and gas pipeline installation though comparatively unknown in other industries. The voltage and current are continuously monitored and adjusted throughout the welding operation: it detects when a ball of molten metal is discharged from the end of the wire electrode altering the potential and throughput accordingly.

WELDING PROCEDURES AND TESTS ƒ Site welding ƒ Welding procedures ƒ Repair procedures

ƒ Welder tests ƒ Weld tests

ƒ Non-destructive tests (NDT) ƒ Destructive tests (sample coupon) ƒ Tensile strength ƒ Hardness ƒ Toughness

Before any welding takes place on site, a full set of welding procedures are drawn up and agreed. These will cover all standard welds to be used on the contract, agreement on what defects can be allowed, what must be repaired, the method of repair for different defects, and what will require a cut-out. Welders will be tested to prove their individual competency on these procedures. These welds will then be tested to prove the procedures are correct. Normally, non-destructive testing is first carried out over the whole weld to identify defects, and then sections of

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each test weld will be cut out to ensure that the tensile strength is greater than that of the pipe wall, and that no problems exist with the weld hardness or toughness which might give rise to brittle fracture.

JOINT PREPARATION

ƒ UK - BS 4515, BS EN 288-9 ƒ USA - API 1104

1.5 mm 1.6 mm (0.060in)1.6 mm (1/16in) (1/16in)

12.7 mm (0.5in)

1.0 mm (0.040in)

7.9 mm (0.312in)

2.8 mm (0.110in)

22.2 mm (0.867in)

ƒ Weld bevel cut using pipe facing machine ƒ Two pipe ends aligned using line-up tool/clamp ƒ Normally semi-automatic welding using GTAW or GMAW ƒ Applicable codes

Line pipe is usually manufactured and delivered with ends prepared at a standard 30° bevel. To increase productivity with semi-automatic welding, this is modified to a J shape resulting in a U shaped weld and reduced weld filler material. It is possible to reduce the number of individual passes, saving both time and material. The end of the pipe joint is prepared using a pipe facing machine which cuts a bevelled edge. This operation normally takes between 2 and 5 minutes, depending on the pipe wall thickness and skill of the operator. The two bevelled pipe ends are then aligned using a line-up clamp. The root pass and hot pass are made and the line-up clamp is removed. The filler passes are then made using one or two automatic welding units.

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JOINT PREPARATION

Line up & internal welding clamp Joint facing machine

Joint aligning machine Photos courtesy of CRC-Evans

Dual-nozzle welding machine (bug)

Single nozzle bug in use inside shack

Proper joint preparation is the first step in preventing weld defects. The ends of the pipes must be clean and, if bevelled, must have the proper angle and thickness of bevel. The gap between the ends of the pipe, if specified, must be prescribed for the pipe size and welding methods used, and two joints must be properly aligned before welding begins. Other factors affecting weld quality include proper welding current and proper electrode angle. Line-up clamps should be internal to provide concentricity of pipe bore and must not cause scoring or otherwise damage the pipe surfaces. Each joint of pipe should be swabbed with a leather or canvas belt disc of the proper diameter or cleaned to remove dirt, grease, loose mill scale, or other substances before line-up. Pipes should be kept free of dirt when work is not in progress. Open ends of pipe should be closed with an approved cap or plug, securely fixed to prevent unauthorised removal. Before welding, joints should be cleaned free of all paint, grease, oxide, rust and other contaminants. Cleaning should extend for at least 30 mm (1.2in) from the joint on both internal and external faces. Burrs, score marks, indentations or other small imperfections may require smoothing out by filling or grinding. If these are serious, then the pipe end may require cutting back and the joint re-preparing. If moisture is present then the pipe may require drying, so that joints are completely dry. Welding is then weather dependant.

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SEMI AND FULLY AUTOMATED WELDING ƒ Semi-automatic ƒ Fine positioning of electrode controlled by welder ƒ GTAW or GMAW

ƒ Automatic ƒ Electrode controlled automatically ƒ SAW, GTAW or GMAW

Courtesy of CRC-Evans

Cap pass Filler passes Hot pass Root pass

The manual method SMAW uses a fixed stick electrode that is consumed as the weld is made. The welder controls the position of the electrode and arc, and compensates for the consumption of the electrode end. Once the electrode is fully consumed, the welder has to stop and replace the electrode. He then chips away to remove the slag in order to restart the next welding rod on clean metal. Manual welders often have to work in unpleasant conditions: the weld may need protection to prevent the wind blowing in dirt and grit, moisture and cold - all of which can have an important effect on weld quality. To some extent, semi and fully automated welding techniques remove some of the restrictions. Use of continuous wire eliminates the restrictions on the maximum volume of metal contained in stick electrodes, so fewer passes are needed. Semi-automatic methods use a consumable wire electrode or filler that is fed automatically to the welding head. The welder still manually controls the position of the electrode and arc, but does not have to stop to replace consumed electrodes. Among the advantages of automated welding machines are an increased weld deposition rate, reduced volume of weld metal, improved consistency of weld strength, toughness and NDT quality, reduced vulnerability of weld quality to human error, reduced physical strain on welder/operator, ease of training operations, reduced manpower and equipment requirements for heavy wall and large diameter pipe.

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SEMI-AUTOMATED WELDING ƒ Fewer welders but increased support ƒ Change from standard 30° bevel to J shape ƒ Line up clamp ƒ Bug rail attached ƒ Pre-heat pipe ƒ Operator monitors bug position & adjusts for accuracy

Internal root welding

Bug rail

Photo courtesy of Pipeline Induction Heat Ltd

Prior to welding, the pipe is usually pre-heated using propane burners or induction units. The induction type uses rapidly alternating electrical fields to induce eddy currents in the pipe wall, which gives a uniform heat throughout the wall of the pipe. The pre-heating causes the evaporation of any moisture near the weld site and allows a slower cool-down rate after the welding. This reduces the problems associated with rapid cooling, particularly hydrogen embrittlement. Specialist line up clamps can be used to complete an internal bead run, which allows greater tolerances on the joint fitting operations. Alternatively the bead (or root pass) can be undertaken from the outside with just a simple clamp used to keep the two ends together and aligned. An external steel band is used as a rail to run the ‘bug’ or welding machine. The operator needs to watch the bug ride along the band and make corrections using a horizontal adjustment knob in order to correctly align the welding machine with the centreline of the joint. The torch oscillates from side to side of the weld to ensure filling of the gap. The welds are made on one side of the pipeline from the top (12 o’clock position) down to the bottom of the pipe (6 o’clock location). The weld on the other side of the pipe is then completed, again in the downward direction. Immediately after the internal or external root bead, the hot pass is completed. Then a number of fill passes are carried out (dependent upon the thickness of pipe). Finally a cap weld is added in the same manner. Typically, on large diameter lines, the whole operation from clamping to completion of the root bead is a matter of a few minutes, with rates of 1 - 1½ m/min (3 to 5ft/min) for the filler runs. Multiple stations are used on laybarges to increase productivity.

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WELDING STEEL PIPE ƒ Useful specifications ƒ ƒ ƒ ƒ ƒ ƒ ƒ

BS 2633 Class 1 arc welding of pipework BS 2971 Class 2 arc welding of pipework BS 4677 arc welding of stainless steel pipework BS 4515 welding of onshore steel pipelines BS EN 288-9 welding procedures ASME B 31.3 process piping API Std 1104 welding of pipelines

ƒ Company procedures or national standards ƒ Local conditions - low ambient temperatures

The above provides a list of common standards used worldwide for welding and NDT. There may also be company or national standards specified for a particular contract, which take into account the particular conditions - perhaps the local steel quality or particularly low ambient temperatures.

WELDING - SUMMARY ƒ Three main types of welding ƒ SMAW (stick welding, MMA) ƒ GTAW (TIG) ƒ GMAW (MIG) including SST

ƒ Joint preparation ƒ Manual, semi and fully-automated ƒ Welding specifications for steel pipe Any questions?

There are three main methods of welding: ■ SMAW (Shielded Metal Arc Welding), also known as stick welding or MMA (Manual Metal Arc) welding

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■ ■

GTAW (Gas Tungsten Arc Welding) GMAW (Gas Metal Arc Welding)

Prior to welding, we need to prepare the joints to maximise weld integrity. Various automated methods of welding are used in pipeline construction to increase efficiency.

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NON-DESTRUCTIVE TESTING (NDT)

STEEL WELD DEFECTS ƒ Imperfections caused by ƒ Poor welding technique ƒ High residual stresses in component

ƒ Steels susceptible to ƒ Porosity ƒ Cracking

Transverse crack

Axial crack

ƒ Solidification ƒ Hydrogen ƒ Reheat

ƒ Weld repair

Lamination in parent plate initiates crack in weld or lack of fusion

Slag inclusions Root crack

Full details and records should be kept on all welds and welders. Then if faults occur, problems with a particular welder or his equipment can be identified. Strict controls on weld quality means that testing must be done to ensure weld integrity. Comprehensive inspection of all completed welds is also required. Weld defects must be identified and prevented in future. Cracking can be caused by: ■ hydrogen generated during the welding process ■ residual stresses acting on a welded joint ■ rolling laminations in the pipe itself or poor bonding with the adjacent steel. Cracking is related to the parent material composition, thickness, heat input, stresses and the presence of hydrogen If a weld does contain imperfections (other than cracks) they may be repaired, but a repair should only be attempted once at each weld. All imperfections should be removed by grinding to clean sound metal. Should laminations, split ends or longitudinal seam defects be discovered in pipe, the whole joint should be removed from the line.

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NDT METHODS ƒ Dye penetrant inspection (DPI) ƒ Also known as penetrant flaw detection (PFD)

ƒ Magnetic particle inspection (MPI) ƒ Principle is magnetic flux leakage

ƒ Radiographic inspection ƒ Ultrasonic inspection

DPI is a surface-only inspection method, applicable to all non-porous, non-absorbing materials. The advantages of DPI are: ■ it can be used on non-ferromagnetic materials (such as stainless steel) ■ it has the ability to test large parts with portable kit ■ it is simple, cheap and easy to interpret Its disadvantages are: ■ it only detects defects open to the surface ■ careful surface preparation is required ■ it is not applicable to porous materials ■ it is temperature-dependant ■ it is not possible to retest indefinitely ■ compatibility of chemicals needs to be assured Magnetic Particle Inspection detects surface and sub-surface imperfections in ferromagnetic materials. A magnetic field is induced in the component and any defects disrupt the magnetic flux. Defects are revealed by applying ferromagnetic particles. The advantages of MPI are: ■ it detects some sub-surface defects ■ it is rapid and simple to understand ■ pre-cleaning is not as critical as with DPI ■ it works through thin coatings using cheap and rugged equipment ■ it is a direct test method Its disadvantages are: ■ that it is applicable to ferromagnetic materials only ■ there is a requirement to test in two directions ■ demagnetisation may be required ■ odd-shaped parts are difficult to test ■ it can damage the component under test.

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Although useful, DPI and MPI are not the prime means of ensuring that pipeline butt welds are free from defects. For this, we use radiography and ultrasonics.

RADIOGRAPHY ƒ ƒ ƒ ƒ ƒ

Radiography can be X-ray or gamma ray Permanent record of weld Hazardous to health Does not pick up all flaws Access needed on both sides of weld

Pipe weld X-ray by Applied Inspection Ltd

JME pipeline crawler

Radiography or ‘bombing’ imposes electromagnetic radiation on the test object, causing radiation to be transmitted to varying degrees dependant on the density of material through which it is travelling. Variations in transmission are detected by photographic film or fluorescent screens. It is applicable to all metals, non-metals and composites. A film is wrapped onto the outside of the pipe weld along with identifying alphanumeric lead markers. A radioactive source on the inside of the pipe is exposed briefly from its lead-lined container. Its advantages are: ■ it provides a permanent record showing internal flaws ■ it can be used on most materials, giving a direct image of flaws Its disadvantages are: ■ it is a health hazard so cannot be used adjacent to other workers (such as the welding crews) ■ it is sensitive to defect orientation and has limited ability to detect fine cracks. ■ access both sides (internal and external) is required ■ it is limited by material thickness ■ the weld must cool down enough to place the film around the pipe, so this may be the critical activity in the pipelay operations ■ Skilled interpretation is required, which results in relatively slow results with high capital outlay and running costs. PD 8010 requires 100% radiographic inspection for all welds in areas where leakage is a hazard (e.g. offshore, road, rail, and watercourse crossings) or where repair is difficult. API 1111 requires at least 90% (and preferably 100%) of welds be inspected by radiography, UT or another form of NDT.

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ULTRASONIC TESTING ƒ Automated ultrasonic testing (UT) growing in popularity ƒ Close proximity to welding ƒ Cool down for couplant

Heerema

ƒ Cost comparable to automatic pipeline radiography UT system ƒ Shows weld defects in 3D ƒ More confidence in small defects ƒ Wall thickness Manual UT of has no effect

test weld by Applied Inspection Ltd

Until recently, pipeline weld inspection has been traditionally solely the domain of radiography. With the advent of mechanised GMAW, ultrasonics as a method of nondestructive examination has proven to be an effective option to detect non-fusion defects orientated unfavourably for radiography. The mechanised UT of pipeline girth welds is now readily available. However, the codes require the presence of a skilled operator, able to undertake a manual review in order to confirm and verify the results of the automatic UT. With ultrasonic inspection, high frequency sound waves are introduced to material, interfaces between materials of differing acoustic properties reflect or transmit sound, the reflected sound is displayed on a monitor. Both manual and automatic techniques are used - sometimes in conjunction with each other or with radiography. Although UT can be used near the welders, the pipe does need to cool down before the couplant is applied. With mechanised UT inspection, the array of probes is moved around the girth weld by a motorised carrier, which travels along the same track the welding apparatus uses. Signals received by the ultrasonic instruments are monitored by electronic gates and both amplitude of signal and its time of arrival can be collected. In evaluating the scan results, the operator makes a decision as to weld acceptability based on the length of the signal exceeding a threshold. Acceptability criteria for ultrasonic NDT is currently being prepared. Its advantages are: ■ it is sensitive to cracks at various orientations ■ it is portable and safe, with the ability to penetrate thick sections ■ it measures depth and through-wall extent ■ with automatic UI, the actual shape of the weld defect can be determined in 3D. This enables acceptance of some minor defects that might have required repair when using radiography ■ modern computer systems can give a pass/fail automatically, with only the occasional need for further interpretation.

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Its disadvantages are: ■ it is not easily applied to complex geometries and rough surfaces (though this is not a problem with straight runs of line pipe) ■ it is unsuited to coarse-grained materials ■ it requires highly skilled and experienced technicians.

NON-DESTRUCTIVE TESTING SUMMARY ƒ Defects and defect detection ƒ Methods ƒ Radiography ƒ X-ray, gamma ray

ƒ Ultrasonic ƒ 3D visualisation

ƒ DPI and MPI

Any questions?

After welding, the integrity of the weld needs to be confirmed, and several methods of weld testing have been discussed along with the defects that they can find. The two main methods are radiography and the more modern method of ultrasonics which provides a 3D visualisation of the defects – giving confidence with smaller flaws.

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COMMON WORK - SUMMARY ƒ Surveys before and throughout installation ƒ Towed fish, vessel, ROTV, ROV and divers

ƒ Preparation of seabed for laying ƒ Soft sediment, holes, crossings and sandwaves ƒ Startup – pipe initiation in target box

ƒ Welding methods ƒ Semi-automatic and manual on firing line

ƒ Testing of every weld ƒ Buckling at touchdowns and difficult to repair later

Any questions? Surveys are needed throughout the lay process by a variety of methods. The seabed generally requires some preparation prior to lay and a fixed point is needed for initiation of the pipe lay. The welding methods used for pipelay are covered. It is important to assure that every weld is acceptable prior to laying because the pipeline experiences high stresses at touchdown and repairs after laying are costly. Also, a flaw in the weld may result in accelerated localised corrosion affecting the operating life of the pipeline.

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EXPECTATION

EXPECTATION ƒ Rigid steel pipeline installation ƒ S-lay – commonest method ƒ Anchored or DP vessels

ƒ J-lay – deep water installation ƒ Dynamic positioned vessels

ƒ Reel-lay – flowlines ƒ Subjects pipe to plastic yield – stress analysis ƒ Quayside construction – rapid layrate

ƒ Bundles and towed methods – flowlines ƒ Land-based construction

ƒ Flexible pipelines – flowlines ƒ Umbilical cables This module introduces the major methods of installing pipe. By far the commonest method is S-lay. This can be used for all water depths and for flowlines and export lines. In deeper water, the slightly slower J-lay method is employed. This requires DP to maintain station. There is less pipeline stress near touchdown. With reel-lay, bundles and towed methods, the pipelines are assembled on land and either loaded onto a reel or towed to the field. Lay rates are more rapid, but the methods are limited to the smaller diameters (or lengths) used for flowlines. With reellay the pipeline is yielded as it is loaded onto the reel and again when it is straightened. However, once it leaves the barge, it is installed in a similar manner to that of the J-lay with minimum stress at touchdown. Flexible pipelines and umbilical cables are installed in a similar manner. However, the stresses are kept lower still because of the relatively non-robust nature of these items.

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S-LAY

WHAT IS S-LAY ? ƒ Takes its name from the shape of the suspended pipe ƒ Pipe must be tensioned to hold its shape

Overbend Area

Sagbend Area Tension

S-lay takes its name from the suspended shape of the pipe at the end of the barge, which lays in a gentle ‘S’ from the stinger to the seabed. The crucial feature of this method is that the pipe must be held under high tension to hold its shape.

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SAIPEM PIPER ANCHORED S-LAY BARGE

The above picture shows a typical S-lay anchored barge. This takes 12 m (40ft) lengths of pipe, which can be seen stacked on its deck. It places these in a firing line, running down the centre of the vessel, and welds them up. The pipe then runs out of the stern of the vessel down the stinger and into the water. As the pipe is welded up, so the vessel is winched forward on an anchor system. It has 12 anchors, and 2 anchor tugs to position them, though only one anchor is moved at a time.

LORELAY DP S-LAY BARGE

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The above picture shows the Lorelay in front of a platform. The stinger at the back of the boat is lifted, showing that it is not yet in pipelay mode. As with the previous barge, it assembles 12 m (40ft) joints into a welded pipeline and Slays them onto the seabed. The main difference is that it is a ship-shaped vessel rather than a barge, and applies the necessary tension through dynamic positioning thrusters. The thrusters make it easier to manoeuvre close to platforms than for anchored laybarges, which have to carefully position their anchor cables to avoid clashes with the jacket legs during barge movement.

SOLITAIRE

ƒ Entered market in 2000 ƒ 3 times size of Lorelay ƒ Seven double joint or 24 m (80ft) weld stations A further S-lay barge is the Solitaire, which is three times larger than the Lorelay and is aimed at large diameter trunk lines. Welding and coating repair operations are divided equally between seven workstations. The length of the vessel means that it is able to use double-jointed pipes, so speeding up the lay rate. On the Magnus EOR 610 mm (20in) line, it achieved an average lay rate of 8 km/day (5 mile/day) and a peak of 9.3 km/day (5.8 mile/day).

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SAIPEM S-LAY - VIDEO

The Saipem video features the lay process of the Zeepipe. The pipe was laid by two semi-submersible laybarges, the Castoro Sei and the Semac-1 with a fleet of support vessels including pipe carriers, supply vessels, anchor handling tugs, guard vessels and survey vessels. The continuous (24 hour) pipelay process is fully explained, including line-pipe leaving the pipe coating facility, double joint length production, passage through the firing line and barge movement.

INSTALLATION ENGINEERING ƒ Working out how a particular vessel will install the pipeline ƒ Firing line sequence ƒ Pipelay curve settings ƒ Start and finish of lay

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The purpose of installation engineering is to work out how a particular vessel will install a pipeline. It is the domain of the vessel owners and has two key activities. The first is determining the firing-line sequence to spread the time needed to make the weld evenly amongst the welding stations. The second activity is to set the pipeline curve. This is addressed in the next slide. Normally, pipelines which run from land will be laid from beach to platform. Interfield lines can be laid in either direction. The initial holdback wire tension anchoring may be the decisive factor.

LAY STRESS ANALYSIS ƒ The installation contractor checks the stresses in the lay curve ƒ Anchor locations to ensure correct tension Horizontal firing line Hog bend

Sag bend

Tension

Lay curve

Stinger Anchor cables

The installation contractor will check the stresses in the lay curve, and from this will determine the optimum stinger settings (these cannot easily be adjusted once pipelay has commenced) and the tension to apply for a given water depth. Inshore, the detailed anchor pattern locations will be worked out in order to avoid any obstacles and yet provide the necessary tension at the sag bend. This needs knowledge of the soil conditions on either side of the laying centreline.

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ADJUSTING THE LAYING STRESSES ƒ Adjust ƒ Stinger roller settings (radius of curvature) ƒ Stinger angle

ƒ Find ƒ Tension for given water depths

ƒ Operating conditions ƒ Hold station ƒ A&R

The installation vessel controls the stresses in the pipeline by setting of the stinger angle and roller positions, and by controlling the tension. At each water depth, the necessary tension to maintain the pipeline within safe stresses is determined. Each barge will have a maximum sea state for laying operations and holding station. There will also be more severe weather conditions when the pipeline needs to be abandoned - and the improved seas in which it can be recovered (A&R procedures).

TENSIONERS

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The above pictures show tensioner sets. These are pairs of caterpillar tracks that are hydraulically brought together to grip the pipe and apply a back tension. Dead band for pipe tensioners is between +25% and -10% of set level, so normally the pipeline is still. If it moves, then the welding kit moves with it. The photographs show two pipe tensioners manufactured by SAS Gouda (www.sasgouda.nl). The one mounted within the laybarge has a concreted pipeline being launched though it. The unit still in their manufacturing facility is rated at 200 tonnes (441 kip).

FIRING LINE SEQUENCE ƒ Firing line is a production line where pipe joints are welded and tested Coating

NDT

Tensioners

Weld stations

The firing line can be viewed as the factory assembly line for the pipeline. It runs down the centre of the barge. The figure above shows the firing line for the Lorelay. In this, new pipes are aligned and root-welded forward in the vessel (near the bow) and then passed from right to left through the welding stations, having a filler welds and a cap weld added. As weld is added, the pipe passes through multiple sets of tensioners to the nondestructive testing stations, where a radiograph is taken of the weld. From there, it passes to the back of the ship where a field joint coating is applied, after which the pipe passes down the stinger and into the water. The key to the firing line is to make sure that the time taken to complete the entire process is divided evenly amongst the stations. For example, if it takes 45 minutes to complete the operation from alignment through to field joint coating and there are 9 stations, then the objective would be to spend 5 minutes at each station. If it were necessary to spend, for example, 10 minutes at one station (and 4½ minutes at the others), then this would slow the vessel speed to half and so would double the cost of construction.

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S-LAY PERFORMANCE AND COST ƒ 3rd generation laybarge: ƒ ƒ ƒ ƒ

4.5 km/day (2.8 mile/day) for single pipe 2 km/day (1.25 mile/day) for pipe-in-pipe Guide cost $350 000/day Typical depth limit 500 m (1640ft) due to anchor mooring systems

ƒ Solitaire: ƒ 8 km/day (5 mile/day) for single pipe ƒ Depth limit about 2500 m (8200ft) due to 400 tonne (kip) tensioner capacity

The above slide contains some ball-park information on pipelay speeds, limitations and vessel costs. However, it should be noted that these vary considerably from vessel to vessel. The pipelay market is an opportunity rather than a commodity market. The prices do not necessarily reflect the cost of building and running the vessels. Instead, they climb in busy years and drop in quiet years. Two points of comparison. Firstly, due to its length and number of welding stations, the Solitaire goes twice as quickly. Its DP system avoids the 500 m (1640ft) depth limitation of anchor mooring, meaning that its limit is due to tensioner capacity. Secondly, pipe-in-pipe systems take about twice as long to lay because they require about twice as much welding. Typical figures are a maximum of 2 km (6600ft) per day, average 1.6 km (5250ft) per day. An interesting point to note regarding the anchoring depth limitation and the type of opportunity market, is that an anchored laybarge is being used for a large contract in 1100 m (3600ft) of water because of the lack of availability of other vessels in the contractor’s fleet. The slower operations due to anchor movement did not increase costs prohibitively.

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S-LAY - SUMMARY ƒ S-lay is horizontal assembly and laying in an S-curve under tension ƒ Large anchored and DP vessels ƒ Installation engineering optimises the lay rate Any questions?

The S-lay method derives its name from the shape of the lay curve. The ‘S’ shape arises from having a horizontal assembly or ‘firing’ line on the vessel deck. The pipe is then laid under tension down to the seabed. The high forces required to keep the pipeline under tension means that the installation vessels need to be substantial in size with strong anchors or Dynamic Positioning (DP) thrusters to react the required tension. S-lay vessels usually utilise around four weld stations, and the lay-rate can be optimised by the correct distribution of weld passes as the pipe joints travel along the firing line through the weld stations.

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J-LAY

WHAT IS J-LAY? ƒ ƒ ƒ ƒ

Name from shape of lay curve Single work station Work station Low touchdown stress Deeper water = steeper angle

Upending Ramp

Horizontal pre-assembly pipe racks

J-lay takes its name from the shape of the suspended pipe, which forms a ‘J’ going from the surface of the vessel to the seabed. This curve is similar to a catenary and develops lower stress levels in the pipe than S-lay. Its main limitation is that it has a single work station in which to assemble the pipe. Consequently, most J-Lay systems make use of pre-assembled strings of 4 to 6 pipes. The additional time spent making a joint at a single work station is compensated for by attaching 4 to 6 pipe joints rather than just one. The figure shows the ramp at a relatively shallow angle. This is needed for installing in shallow water - perhaps near landfall. In deeper water, the angle becomes steeper almost vertical.

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BLUESTREAM PROJECT - VIDEO

The deepwater section of the Bluestream project was laid using the Saipem 7000 JLaybarge. The 50 m (164ft) quad joints were offloaded from the pipe transport barge and stored on deck. The corrosion coating of the quad joints was inspected and then the ends were bevelled. A turning device rotated each quad joint by a quarter turn to avoid alignment of the longitudinal seals in adjacent sections. The quad joints were upended and hoisted to the top of the J-Lay tower, where a line-up clamp aligned them with the previous section. Welding was performed using three Presto twin-torch welding units mounted on a rotating carousel. After welding, the quad joint was lowered a few metres to the NDT and field joint coating station on the floor below, where 100% automated ultrasonic weld inspection took place. It is common practice to separate the welding area from the coating area for cleanliness. After the field joint coating was applied the tensioners were activated. The tensioners have a lay capacity of 252 tonnes and contingency holding capacity of over 1000 tonnes. The S7000 has a dynamic positioning system which allows the correct tension to be maintained in the pipeline as it is lowered to the seabed. The system enables the laybarge to remain stable in winds approaching 30 knots.

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J-LAY PERFORMANCE AND COSTS ƒ Performance ƒ Lay speeds up to 2.3 km/day (1.4 mile/day) - half of S-lay rate ƒ Vessel cost up to $350,000 per day Stationary ƒ Ideal for deep water

ƒ Improve speed

clamped line pipe

ƒ One-shot welding or ƒ Mechanical connectors

Stationary clamped pipe

Internal mandrel

Consumable ring rotated and compressed radially

Acergy’s radial friction welding system

The above slide shows ball-park lay speeds and vessel costs. This system is ideal for use in deep water, where the low lay stresses and low horizontal tensions required lend themselves to installation from dynamically positioned vessels. Although quicker one-shot welding methods have been developed, they have yet to be used for a contract. Acergy’s radial friction welding system is shown. One further way of improving the speed of assembly at a single work station is to use mechanical connectors, similar to those used downhole. Reluctance by operators to use what is perceived as novel technology means that neither has been adopted to speed up J-lay installation.

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J-LAY - SUMMARY ƒ J-lay is vertical assembly and laying in a J-curve with low horizontal tension ƒ Large DP vessels ƒ Less power needed than S-lay DP

ƒ Approximately half the lay rate but similar costs to S-lay ƒ Potential for deepwater, connectors and rapid welding Any questions? The J-lay method has a ‘J’ shaped lay curve due to the vertical assembly line located in a tower that is fitted to the vessel deck. This has the advantage over the S-lay method that lower horizontal tensions are required to maintain the required bend radius at the bottom of the lay curve. The lower tensions mean that the vessels do not require anchoring, so usually operate with Dynamic Positioning (DP) thrusters. These will use less power than DP systems for S-lay vessels. Because the vessels are dynamically positioned, they are able to operate in deeper water. The lay rate is approximately half that of the S-lay process because there is only a single weld station on the assembly line. However, the cost of vessel deployment is about the same. This is offset by the ability of J-lay vessels to operate in deep water. The single weld station is usually the limiting factor in the speed of pipe installation. Therefore, there has been a demand for research into the potential for connectors and rapid welding techniques to improve the efficiency of this installation method.

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REEL-LAY

REEL LAY ƒ Pipe yielded as it is unwound from a big reel ƒ Laid in J-curve from DP ship

The picture above shows a reel of pipe on board the Technip Apache. The construction site is at Technip’s Evanton facility loading pipe onto the Deep Blue. Reeling is a technique where the pipe is assembled into long lengths onshore and is wound onto a reel on the vessel by yielding the steel. At the field it is then unwound, straightened and J-laid down to the seabed. The dynamically positioned vessel is able to lay rapidly because there are no welds to complete.

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TECHNIP APACHE - VIDEO

This video shows the capabilities of the ‘Apache’ rigid pipe reel-lay vessel, operated by Technip. It discusses the following aspects of reel-lay from the Apache in more detail. This and other vessels have now been used for deeper reel-lay operations. The welding, testing and joint coating of pipe joints to form the pipeline section to be reeled are undertaken at an onshore spoolbase. The onshore facility can provide a more controlled environment for welding and testing and so joint integrity can be ensured at a lower cost than if performing offshore welding of joints. Technip have three permanent spoolbases in the world. One on the west coast of Scotland at Evanton, one in Norway and another in Brazil. However, temporary spoolbases can be constructed around the world as required. In 1995, the Apache vessel underwent an upgrade that provided the vessel with a main permanent single reel capable of carrying 2000 tonnes (2205 ton) of 406 mm (16 in) diameter pipe. This is the equivalent of 10 km (6.2 mile) of 406 mm (16 in) pipe or 24 km (14.9 mile) of 254 mm (10 in) pipe. It also carries two smaller auxiliary reels for smaller diameter pipe. The pipe on these smaller reels can be installed in parallel or on “piggy-back” with the main pipeline being laid. The updated configuration has been used to install pipe to a depth of 1400 m in offshore Brazil.

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HELIX ENERGY’S EXPRESS

The Express shown above can accommodate reeled rigid steel or flexible pipeline. The rigid line requires straightening prior to installing using a similar curve to that for J lay. At the stern of the vessel, the straightener system can be seen on the adjustable angled tower. Below them, there is a tensioner system which fixes the pipeline temporarily to permit anodes to be attached.

REEL-LAY PERFORMANCE AND COSTS ƒ Up to 406 mm (16in) pipe diameter ƒ 457 mm (18in) on Deep Blue

ƒ Thick pipe needed to avoid buckling on reel ƒ D/t<22 for Apache (thinner on Deep Blue)

ƒ ƒ ƒ ƒ ƒ ƒ

Ductile steel - higher grades unsuitable Between 5 and 50 km (3 - 30 mile) per trip 1 km/hr (0.6 mile/hr) installation rate No concrete coating Need onshore fabrication site Guide cost $200 000 per day

Reeling has a set of performance characteristics and constraints which are quite different to those of S-lay and J-lay.

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Current vessels are limited to a maximum pipe diameter between 324 mm and 457 mm (12in and 18in), because larger pipelines would buckle if one tried to reel them at the radii of the present drums. Once on site, the installation rate is very quick - 1000 m (0.6 mile) per hour, 24 km (15 mile) per day This compares to say 4 to 8 km/day (2.5 to 5 mile/day) for S-lay and J-lay. Attaching a piggyback line will roughly halve the lay rate. The other main limitations are: ■ To avoid buckling and wrinkling during reeling, the pipe needs to have a diameter to thickness ratio less than 22. In other words, they need to be quite thick. The larger size of reel on the Deep Blue will relax this requirement somewhat. ■ It needs a ductile steel, so high strength steels may be unsuitable. ■ There is a volume and weight limitation as to how much pipe can be taken per trip. However, longer lines can be assembled using a number of trips. ■ One major constraint is that one cannot reel a concrete-coated pipe. The concrete falls off. However, the requirement for stability is met by using a thick-walled steel pipe, which is also a requirement for reeling in the first place. ■ A fabrication site is needed in order to make up the pipe and reel it on to the vessel. These are already available in established areas such as the UK, Norway, Gulf of Mexico, Brazil and Angola.

ACERGY FALCON ƒ Mix of all three methods ƒ Stock of linepipe in hold – no land construction site

ƒ Horizontal firing line ƒ Bending and straightening as per reel-lay ƒ J-lay installation curve

One further pipelay vessel is the Acergy Falcon (formerly the Stolt Seaway Falcon). It uses a mix of all three methods. It has a single welding station in the horizontal on the deck. The pipe is lifted and yielded, runs over the top of the reel, is re-straightened on the ramp and is then J-laid from there. It can lay in areas where there is no convenient spool base at a rate comparable with Slay barges but with low residual tension.

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REEL-LAY - SUMMARY ƒ Onshore fabrication and reeling ƒ Offshore straightening and J-lay ƒ Falcon an optimised mix of systems Any questions?

The reel-lay method has the advantage over the S-lay and J-lay methods in that the welds can be made efficiently onshore and then the pre-welded pipeline can be quickly unreeled from the vessel at a high lay-rate. The unreeling process involves straightening the pipe after the plastic bending deformation induced during reeling of the pipe onto the spool. Then the pipe is laid from the stern of the vessel through a J-lay type tower. The disadvantage of this lay method is that a limited length of pipeline can be carried to the installation site in one trip.

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BUNDLES AND TOWED INSTALLATIONS

TOWING ƒ Bundle or single pipe assembled on land ƒ Towed from the beach to site using tugs ƒ Several towing practices ƒ Surface tow (including Flow-lay) ƒ Controlled depth tow (mid-depth) ƒ Bottom and near-bottom tow

As with the reeled pipe, an onshore facility is needed for pipeline assembly for towed installation methods. However, instead of the jetty and berth required for the reel-laybarge, a gently sloping sheltered bay is needed for bundles. The bundles are trimmed for a buoyancy of around -30 N/m (-2.1 lbf) prior to towing to site. A number of methods have been used to tow flowlines to site. These are classified by the buoyancy in the pipeline and hence the height in the water column at which the tow takes place. Single lines are sometimes installed by the near-bottom tow or surface tow methods.

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SURFACE TOW METHODS ƒ Surface tow methods must ensure ƒ Pipeline in wave zone only for short periods ƒ May be liable to fatigue problems ƒ Impact with vessels or objects

ƒ Use of buoys ƒ Float-and-lower

ƒ Flow-lay ƒ Reusable PE pipe ƒ Concreted flowline

Strap and release mechanism Reusable PE buoyancy pipe

Flowline with coating

Surface tow systems use shore-based construction sites and then float the pipelines to the offshore field. There they are flooded and laid in position. The method is sometimes used for landfalls, where temporary buoyancy is attached to the pipeline as it leaves the laybarge or construction site to make it easier to reach the shore. The buoys are then disconnected to sink the pipeline in place. Such a float-and-lower method is widely used throughout the world. In the sheltered, shallow sea to the west of Trinidad, long lengths of pipelines are assembled on the beach. They are then towed out to sea and the buoyancy tanks removed once the pipe string has been lowered down to the seabed. There the individual strings are diverconnected together using conventional bolted flanges. No expensive laybarge is needed, only small floating plant. Surface towing of bundles has not been widely used due to fears of bending fatigue, and also the risk of collisions with vessels crossing the path of the bundle during tow. The ‘Flow-lay™’ system minimises the fatigue problem by limiting the tow-out operations to only a few days in good weather/seas whilst maintaining tension on the trail tug. It was developed from bundle towing technology. Either the flowline or the carrier can be flooded, depending on the relative weights and buoyancy of each, and the on-bottom stability requirements. The PE pipe is then released to the surface where it is recovered for future use. It promises considerable savings over other systems of installation for single or double lines in remote areas of the world.

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OOOGURUK - BEAUFORT SEA ƒ Flatpack bundle in very shallow water ƒ Wells drilled from man-made offshore island ƒ 2.7 m (9ft) deep trench 9 km (5.6 miles) long ƒ Backfill protection against uplift, strudel scour and gouging

ƒ Pipe-in-pipe flowline ƒ Annulus vacuum and pressure monitor

Gas Spacer injection Diesel fuel

Trench to shore Gas Oil Water P-I-P flowline

Water injection

Concrete Insulation

Pioneer’s Oooguruk field development is in Harrison Bay of the Beaufort Sea, North Slope, Alaska. Some 40 to 60 wells will be drilled (early 2007) from a 7 m (23ft) high island standing in less than 1.5 m (5ft) of water some 9 km (5.6 miles) from shore. First oil is scheduled for early 2008. The 2.4 ha (6 acre) island was constructed during the coldest months by trucking gravel on an ice haul road build over the frozen sea. The flatpack (or open) bundle takes the production fluids ashore and supplies water and gas injection facilities plus diesel fuel to the island. The flowline is 323.8 mm by 406.4 mm (12in by 16in) pipe-in-pipe. This and the other lines are connected with 250 mm (10in) wide spacers at 6 m (20ft) intervals. Pioneer will employ an annulus vacuum monitor or pressure monitoring system for environmental protection. The inside of the internal pipe operates at about 40 bar (580psi); hence if high pressure is detected in the annulus then an internal leak has been detected. If low pressure is detected, this signifies a potential external leak. All lines are grade X52 or higher for compatibility with potentially high operational strains. The 0.6 m high by 1 m wide (2ft by 3ft) bundle is to be installed in a 2.7 m (9ft) deep pre-excavated trench in the seabed, giving almost 2 m (7ft) of cover when backfilled in order to prevent uplift buckling. Backfill to the trench also protects against ice gouging and strudel scour (where river water flows offshore over the ice each summer, scouring a hole through the floe and whirl-pooling down into the seabed beneath). The pipeline will continue onshore for a further 3.7 km (2.3 miles), making the pipeline length a total of 12.7 km (7.9 miles). Source: Offshore Engineer June 2006.

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BUNDLES ƒ Pipelines fabricated onshore ƒ Placed inside carrier ƒ Towed to site Britannia Bundle

Test flowline Methanol flowline Heating flowline Production flowline

Gullfaks Bundle

Bundles as depicted in the picture above are groups of flowlines encased within a carrier pipe. The carrier pipe provides buoyancy, which allows the bundle to be completely fabricated onshore, towed offshore and then the annulus flooded to sink it in place and provide stability.

CONTROLLED DEPTH TOW ƒ Recent records for longest towed bundles: ƒ 7.5 km (4.7 miles) – Land and Marine Projects ƒ 7.2 km (4.5 miles) – Subsea 7

Tow Tug

Trail Tug

Transponders Trailhead

Ballast chains

Towhead

Controlled-depth tow, as the name implies, is towing the bundle such that it stays in mid-water between the seabed and the surface. When one considers that bundles may be 5 to 7 km (3 to 4½ miles) long and the water depth may be 100 m (330ft), it is quite a feat to keep the bundles straight and steady without perturbations, which could take it either to the surface or the seabed.

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PRINCIPLE OF CDT ƒ Small amount of buoyancy is countered by chains

Neutrally buoyant bundle

Ballast chains

Webbing straps Wire

Chain

2 m to 3 m (6ft to 10ft) above seabed

‘Extra’ links on seabed for stability during trimming for tow and at field location

For a controlled-depth tow, the carrier pipe is sized so that the bundle is slightly positively buoyant and then chains are attached to the underside. The bundle is then towed out into a sheltered bay. Being positively buoyant, the carrier pipe rises from the seabed and lifts the chain until enough links are suspended to counteract buoyancy. Divers then work their way along the bundle to see how many links are left on the seabed and to trim these as necessary to give an even negative buoyancy. Once trimmed, the whole bundle is tensioned between a leading and trailing tug and towed to site. As the speed increases, the chains slope backwards. This generates lift as well as drag as they pass through the water. This means that, at a certain speed, the bundle will become neutrally buoyant and will rise from the seabed. The speed of the tugs is adjusted to maintain the lowest point of the bundle about 10 m to 15 m (30ft to 50 ft) above the seabed and the tow and trailheads at a similar depth below the surface.

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BOTTOM TOW ƒ Near-bottom tow ƒ Used in the Gulf of Mexico: ƒ Up to 10 km (6 mile) sections

Question coming up three pages on... Please look up from your notes

ƒ Seabed conditions required: ƒ Flat ƒ Clear of other lines and obstacles

Buoyancy

Transponder

Towing vessel

Towhead structure

Chain ballast

Bottom tow, as the name implies, is where the bundle is dragged along the bottom. However, the improvement shown above is near-bottom tow. The carrier and buoyancy is sized to ensure that the bundle is just positively buoyant. Chains are then attached to give a controlled amount of submerged weight. This technique has been used successfully in the Gulf of Mexico, where bundles were constructed along the beach, launched into the surf zone and then pulled along the seabed to site. The tow route to the offshore field can be hundreds of kilometres (miles) long, following a detailed pre-surveyed route avoiding such features as coral and rock outcrops, and as many pipeline crossings as possible.

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DEEPWATER BUNDLES ƒ Girassol project ƒ Deepest installation of a pipeline bundle at 1350 m (4430 ft) ƒ ‘Wet bundle’ system

Girassol Field layout

ƒ Established technology Courtesy: Elf Exploration Angola can be applied in water depths of 1000 m (3280 ft) ƒ Systems now being designed for 2600 m (8530 ft)

Use of unpressurised carriers (which remain flooded) means that the insulation needs to be able to resist the full water pressure at the field. This means, however, that essentially any depth can be achieved - though the insulation can be costly.

DEEPWATER BUNDLE DESIGN ƒ Controlled depth or bottom tow ƒ Main issues for deepwater ƒ Safety of N2 on construction site near plant and personnel ƒ Initial pressurisation of flowlines/carrier

Conventional CDT bundle for depths to 250 m (820ft)

ƒ Super-pressurise flowlines and decant into annulus at holding location ƒ Flood at holding station and bottom tow to field

ƒ Wet or flatpack bundle In deepwater, bundles can be installed using controlled depth or bottom tow methods to transport them to location from the fabrication site.

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There are safety concerns in pressurising gas above 25 bar (363 psi) in a thin-walled carrier on the construction site. Plant may impact and rupture the pipe, causing an explosion adjacent to personnel. The picture shows the relative thinness of the carrier used for the Gannet development. Although not a deepwater bundle, a similar thickness might be used for deep water. It cannot be made thick enough to withstand hydrostatic collapse because its weight would increase too much. Normally, bundles counteract the hydrostatic pressures at the field by pressurising the carrier pipe annulus with nitrogen. In deep water, the substantially higher pressures cannot be provided prior to launch. Health and safety considerations require that the differential pressure never exceeds around 25 bar (360 psi) at the construction site. The total mass of the bundle needs to remain constant during all stages of the mid-depth tow-out. Injecting additional nitrogen at an intermediate-depth holding station would increase the weight, making the bundle too heavy. So the flowlines can be superpressurised for the initial loadout to the parking area in around 200 m (650 ft) water depth. There, the pressure in the flowlines and carrier is equalised by venting the gas in the flowlines into the carrier annulus. Thus the higher hydrostatic pressures at the field can be counteracted. Alternatively, from the parking area, the carrier can be flooded and a bottom tow method used. Finally, the whole bundle can be towed out ‘wet’, as used for the Girassol Project. The insulation was designed to resist the full hydrostatic pressure with no need for flooding at the field.

WHY BUNDLES? ƒ What are the advantages and disadvantages of bundles compared to other forms of pipelay?

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BUNDLES PROS AND CONS ƒ Pros ƒ Good for many parallel pipes – narrow corridor ƒ Use of pipe-in-pipe ƒ Include manifold and precommission ƒ Good for heating and insulation ƒ Include umbilical ƒ Carrier offers protection ƒ No concrete needed for stability ƒ Land-based construction costs are lower

ƒ Cons ƒ Only straight routes or gentle curves ƒ All eggs in one basket ƒ Short lengths ƒ Difficulty of monitoring or repair of individual lines ƒ Installation restricted to fine weather (summer months)

Bundles have many advantages. They are economic for many parallel pipes. In some cases, it is possible to install the manifold pipework in the tow head and to precommission this and the control system. It is also possible to arrange for heating and/or insulation of pipelines. This may be done by including pipe-in-pipe or re-circulating heating lines. The umbilical no longer requires armouring and can be pulled inside the carrier for protection. The carrier pipe, once installed, is non-pressure containing and forms a good structural barrier against fishing interaction and dropped objects, meaning that there is no requirement to trench the bundle. The drawbacks of bundles are that they are restricted to short routes and relatively short lengths. The longest controlled depth towed bundle to date is 7.5 km (4.7 mile), whereas the longest bottom towed bundle is about 20 km (12.4 mile). Finally, ‘all your eggs are in one basket’ with a bundle. If, for any reason, there is a problem, then all your flowlines and manifolds are out of commission until the problem is sorted out. It may be difficult to monitor corrosion of the annulus with heating systems.

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TOWED SYSTEMS ƒ Projects ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Troika Gulfaks Skene Britannia Green Canyon Girassol – wet bundle Oooguruk – flat pack

ƒ Contractors ƒ ƒ ƒ ƒ

Subsea 7 Land and Marine RJ Brown Acergy

Towed bundle and pipe-in-pipe systems have been installed in relatively deep waters. Girassol is 1350 m (4430ft) deep but uses the ‘wet bundle’ method without a pressurised annulus. This avoids the health and safety concerns during launch when there are high differential pressures in the carrier. These are needed to counteract the hydrostatic pressure at the field. Because the only vessel requirements are two tugs for the short tow period, these can be hired as needed on the open market. A number of contractors are able to offer this type installation. The 9 km (5.6 mile) long open (flatpack) Oooguruk bundle is currently being constructed in Alaska for installation between an artificial island and the shoreline on behalf of Pioneer Natural Resources.

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BUNDLES - SUMMARY ƒ Bundles ƒ ƒ ƒ ƒ

Allow low cost high quality onshore fabrication Permits rapid offshore installation Good for multiple parallel lines Limited to flowline diameters and lengths

Any questions?

Bundles have the advantage over single rigid pipelines that they can contain several individual flowlines within a single carrier pipe. The installation of a bundle then becomes a very efficient method of installing multiple parallel lines along a single route. However, the installation efficiency of S-lay and J-lay methods is heavily constrained by the time required for welding the pipe joints together. The make-up of joints for bundles requires the welding of the multiple flowlines of various lengths making bundle installation by S-lay or J-lay methods unfeasible; and the only alternative is to lay individual flowlines. Bundles are fabricated at low cost onshore facilities and then towed out for installation on the seabed.

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FLEXIBLES AND UMBILICALS

WHAT IS A FLEXIBLE?

External sheath

Pressure vault

External sheath Armours Pressure vault Armours Pressure sheath

Pressure sheath

Carcass

Carcass

A flexible pipe is one that is designed to bend to (relatively) small radii without damage. The above diagram shows a typical construction: ■ The carcass is a corrugated steel structure that supports the pressure sheath against collapse inwards from gas that has diffused out of the oil into the armour layers ■ The pressure sheath is a plastic layer (nylon, PE or polyamide) that provides a seal to contain the flow and a corrosion barrier to stop the internal fluids corroding the windings ■ The pressure vault consists of interlocked hoop windings that resist the hoop stress ■ The armour windings are non-interlocking wires laid more in the axial direction. They resist tension and pressure end cap force ■ Outside is the external sheath, which is a continuous plastic layer (PE or polyamide) to keep sea water out of the windings

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INSTALLING FLEXIBLE PIPE ƒ Flexible pipe loaded onto vessel carousel ƒ Quay adjacent to fabrication yard

The flexible flowline is wound off its reels in the factory, over a conveyor belt or roller system, onto the vessel and into the carousel, as shown in the picture above. This means that the quayside needs to be adjacent to the fabrication yard. The carousel is normally horizontal in the vessel hold, but modular spools can be located on deck.

FLEX-INSTALL CAPABILITY DP vessels Fast lay Low stress curve Flowline rather than trunkline market ƒ Primary concerns ƒ ƒ ƒ ƒ

ƒ Gripping flexible ƒ without damage

Where the lay tension (mainly due to self weight of the flexible) is high, the pipe is routed through a vertical lay tower such as that shown above. It passes over the set of

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curved rollers at the top, then vertically through the tensioners and down into the water below. The tensioners normally have 3 or 4 gripping points around the circumference of the pipe. This minimises the ovalisation of the pipe. In addition, the tensioners need to work over a long-enough length to avoid crushing the internal layers of the pipe. Where lay tension is small (shallow water) the flexible may be laid over a curved chute, or over the curved vessel stern ramp. With water depths over 400 m (1300ft), it is normal to install over a guide as shown above.

SMD UMBILICAL CABLE ENGINE ƒ Used for deep water ƒ Umbilical wound five times around drum ƒ Held by drum friction ƒ Wraps shifted laterally ƒ 14 mm (½in) to 150 mm (6in) diameter

For shallower water, umbilical cables can be lowered using a horizontal tensioner and chute system similar to that used for flexible pipelines. However, for deeper water, the tension can put the cable at risk. If a cable is wound five times around a drum, then there are enough friction losses to hold any tension applied to the cable. However, if the drum is a simple one, the cable will spool right off one edge. This SMD (formerly Soil Machine Dynamics Ltd) cable engine keeps the position of the five wraps constant relative to the edges of the drum enabling the whole length to be laid without conventional tensioners. It is capable of supplying 40 tonne (88 kip) at a payout rate of 2 to 4 m/s (4 to 8 knots). It can be used for jobs ranging from 14 mm (½in) lightweight cable up to 150 mm (6in) for armoured cable.

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WHO INSTALLS FLEXIBLES AND CABLES? ƒ Technip ƒ Sunrise 2000, Deep Blue

Helix Intrepid

ƒ Acergy ƒ Condor, Falcon

ƒ Subsea 7 ƒ Kommandor 3000, Seven Seas, Skandi Navica

ƒ Helix ƒ Express, Intrepid

ƒ SapuraCrest ƒ Sapura 3000

Most of the major contractors are able to install flexible pipelines or cables. The equipment required is easily fitted onto any DP work vessel. The photo is that of the Intrepid which can install cables and both flexible and rigid reeled pipelines.

PERFORMANCE OF FLEX-INSTALL ƒ Laying speed ƒ 12 km/day (7.5 mile/day)

ƒ Maximum diameter ƒ 480 mm (19in) - bore

ƒ Multiple line installation ƒ Up to 3

ƒ Can be re-used (Petrobras)

The laying speed is comparable with that for the reel-lay method. There is no need to fit anodes during the laying operations but care is needed in handling the flexible pipeline or cable.

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Remember, that flexible pipelines are specified by their internal diameter and this is set by the manufacturing process rather than any limitation on laying. By using multiple spools, it is possible to lay up to three flexibles or umbilicals at the same time. Petrobras has recovered and refurbished a number of flexibles for reuse. These are long flowlines and risers in deep water. However, in Australian fields, where there are shallower water depths and shorter lengths of line, the risk assessment favours disposal over reuse.

FLEXIBLES AND UMBILICALS SUMMARY ƒ ƒ ƒ ƒ

Flexibles are stored on carousels Laid vertically in deep water Laid overboard in shallower water Cables use tensioner or drum winch

Any questions?

Flexibles are stored on carousels and unreeled to install them on the seabed. For deepwater, they are laid vertically in a J-lay configuration to maintain the required tension, similar to the reeling process. In shallow water, they can simply be laid overboard using a chute and tensioner. Deepwater cables can be laid using a drum winch rather than a tensioner system.

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INSTALLATION METHODS SUMMARY

ƒ Main installation methods ƒ S lay, J lay, reel lay, bundles and flex lay

ƒ S-lay commonest and used for trunk lines ƒ J-lay for deepwater lines ƒ Reel and bundles assembled on land ƒ Rapid installation of smaller diameters

ƒ Flexibles and cables laid similar to J lay ƒ Continuous lengths without need for joints

Any questions?

The main installation techniques for rigid pipelines, bundles and flexibles have been presented. We have highlighted where modifications are needed to these methods for deepwater lines.

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EXPECTATION

EXPECTATION ƒ Basic activities for landfalls ƒ Trenching pipelines and cables ƒ Reasons and methods

ƒ Main commissioning activities

Trunk pipelines generally bring oil or gas to shore. We will introduce the basic activities required for landfall construction. Smaller diameter pipelines are often buried. We look at the reasons and main methods for the trenching and burial of pipelines on the seabed. Finally, the main activities for pre-commissioning pipelines for product receipt are introduced.

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LANDFALLS

SCHEMATIC OF LANDFALL

Cofferdam through tidal zone Winch & reelwinder

Cutter dredges trench to laybarge depth

Laybarge

The landfall, as the name implies, is where a pipeline comes onshore. The construction process is shown schematically above and is focussed on preparing the site for the laybarge to install the pipe. The preparation activities are: ■ Drive a sheet steel cofferdam through the tidal zone and excavate inside it. The cofferdam holds the trench open against the wash of the tide. ■ Continue the trench from the cofferdam using a cutter dredger. Keep dredging until the laybarge arrives to maintain this trench open against tidal and wave action. ■ Excavate the remainder of the trench up the beach to the winch site. ■ Install the linear winches and cable storage drums on the beach. This is normally attached to a sheet pile anchor to react the pulling force. A typical trench depth is 3 m (10ft) to ensure that the pipeline stays buried well below any future erosion of the beach. The trench is normally dredged out to about 12 m (40ft) LAT (that is, 12 m water depth relative to the lowest astronomical tide). This ensures that the remainder of the pipeline can be post-lay trenched using offshore trenching equipment.

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NORFRA LANDFALL, DUNKIRK ƒ Dredging of landfall at Dunkirk ƒ Wing walls protect dunes from flooding ƒ Cofferdam keeps beach trench open ƒ Jackup piling ƒ Spud-leg dredger nearshore trench

The landfall was required for a 835 km (519 mile), 1067 mm (42in) high pressure pipeline bringing natural gas from the Draupner E platform in the Norwegian North Sea sector to the coast of France. This landfall required the installation of a cofferdam and pipe pull-in equipment, levelling of sandwaves at the shore approach, stabilisation and protection of the laid pipeline with rockdumping and finally tie-in between the section of pipeline at the landfall and the other section laid from the platform towards Dunkirk. The wing walls to the cofferdam helped protect the area behind the beach from flooding, should the dune protection be breached by storms. These are generally constructed using land-based piling hammers and crane equipment. The long cofferdam ensured that longshore drift of sand did not refill the trench between high and low water marks. The jackup barge was floated in to shallow water at high tide and the legs deployed. This meant that it could continue to pile throughout the tidal cycle unaffected. A spud-legged dredger used its cutter suction arm to open a trench in the nearshore section.

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SHEET STEEL PILING ƒ U section (Larssen)

‘Clutch’

‘Pan’

Clutch details

ƒ Z section (Frodingham) ‘Clutch’

Clutch details

Arcelor-Mittel manufacture two styles of sheet steel piles: the U and Z sections. These are also known as Larssen and Frodingham piles. See www.sheet-piling.arcelor.com for available section sizes and design software. Elsewhere in the world other similar designs are used. See www.pilespecs.com for a world-wide list of sheet pile specifications. The difference between the two is the location of the clutches that link the steel piles together. The Larssen has the joint near the neutral axis of the complete section. If the clutch holds well, then there is no movement between the adjacent piles and a large section modulus can be developed. The Frodingham does not rely on clutch friction to develop its full section modulus because the pile spans between the extreme fibres in tension and compression. Steel grades for these piles are to EN 10027 or ASTM: ■ S270GP yield stress 270 N/mm² (39 ksi) ■ S355GP yield stress 355 N/mm² (51 ksi) ■ A328 yield stress 270 N/mm² (39 ksi) ■ A572 Grade 50 yield stress 345 N/mm² (50 ksi)

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CUTTER DREDGER ƒ Excavates shallow water trenches

The diagram shows a cutter dredger. The arm is lowered to the seabed, cuts the soil and lifts it in a slurry to the vessel, thence to a floating hose leading from the stern. This excavation occurs prior to the pipeline being brought ashore. The cutter head moves from one side to the other and then back, as the dredger moves forward along the line of the trench. This is accomplished by first lifting one of the spud legs and swivelling the whole barge and cutter arm around the second leg by pulling/releasing the forward anchor wires. At the end of each cut, one spud leg is lowered and the other lifted, causing the barge to move forward along the line of the trench: the anchor winch wires sweeping the arm back across the face of the excavation. For a landfall, the slurry is typically pumped 100 m (330ft) from the vessel through a floating pipe, and is placed in a spoil heap. Once the pipeline is in place, this spoil is redredged and placed back over the pipe.

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BEACH PULLS ƒ Buoyancy to reduce seabed friction ƒ On finishing pull-in ƒ Laybarge continues laying offshore ƒ Pull head cut off ƒ Welded to pre-laid landline section pipe-by-pipe

ƒ Isolating flange ƒ Anodes offshore ƒ Impressed current onshore

ƒ Shoreline ESD isolation valve The beach pull, as illustrated in the picture above, is where the pipe is assembled on board the lay vessel and pulled into the pre-dredged trench using cables and a linear winch. Temporary buoyancy has been attached to the pipeline to reduce seabed friction. Once the shore pull is complete, the laybarge continues laying the pipeline towards its offshore location. The pulling head is cut off and the section up to the pre-laid landline is completed pipe-by-pipe. It is common to have an electrically-insulating flange just before the shoreline emergency shutdown (ESD) valve. This maintains separation between protection systems –sacrificial anodes are used offshore, whilst impressed current is commonly used for the landline section. An alternative (not shown) to pulling onshore from the laybarge is to pre-assemble the pipe onshore and use a pull-barge to pull it offshore. As before, the end can be picked up with a lay barge and laying continued offshore. If the pipeline is laid from the offshore end towards the shore, and then laid down prior to the installation of the landfall section, a tie-in will be necessary. This can be done above water by the laybarge using derricks to lift the two ends above the sea level and completing a weld alongside. The excess length of pipeline is then laid in a loop on the seabed. However, most pipelines would start from the landfall and go out to sea.

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GOLDENEYE PIPE-PULL - VIDEO

The 100 km (60 mile) long Goldeneye pipeline and piggyback were installed during the summer of 2003 at St Fergus on the north-east coast of Scotland. Because the dunes were to be breached and the area is of sensitive environmental interest, the opportunity was taken to install a second landfall line at the same time for future pipeline connection. This is the Atlantic Cromerty pipeline. At St Fergus, seven gas pipelines have their landfalls. These bring ashore most of the UK supply and are connected to three adjacent gas treatment plants. Gaining approval from the national security services to breach the dunes in this environmentally and security-sensitive area was a major challenge. Van Oord, the landfall contractor first constructed a cofferdam 130 m long and 25 m wide (426ft x 82ft). An anchor wall was also piled to provide a deadman for the two 350 tonne (772 kip) linear winches. The Goldeneye pipeline was trenched out to 1200 m (4000ft) from the beach to provide cover of 2 m (6.7ft) nearshore and 1 m (3.3ft) offshore. This was undertaken by the barge ‘Manta’ using a jetting machine (above), which excavated the soil and pumped it out through a pair of eductor tubes into two windrows either side. High and low pressure water was supplied through hoses using pumps on board the Manta. Some of the anchor wires from the vessel required a mid-line buoy to ensure vertical separation from the existing live pipelines. A second vessel, the ‘Coastal Worker’ completed the shallowest sections of the trench inshore using a suction pipe lowered from the side of the vessel and sidecasting the material through a discharge pipe. Finally, the dunes were carefully reinstated and stabilised using marram grass.

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DIRECTIONALLY-DRILLED LANDFALLS ƒ Main benefits ƒ ƒ ƒ ƒ

Minimum disruption to environment Minimal third party disturbance Less risk of flooding than with open cut method Pipeline installed at great depth

The overhead shows the drilling rig site and the reel barge in position at a landfall site in Northern Holland (plus an artist’s impression of the method).

DRILLING RIG

The photograph shows a typical directional drilling rig. Horizontal directional drilling is now established as a method of installing pipelines and cables under a range of obstacles and in a number of cases has replaced traditional open cut techniques.

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LAND AND MARINE DRILLING VIDEO

Pilot hole drilled from shore

Stitch drilling from jack-up

Pilot hole widened as barge lays out pipeline

Pipeline drawn back to shore behind reamer

Directional control of pilot

The video shows how a landfall can be accomplished with minimum environmental disruption by drilling first a pilot hole using a land-based rig out to a laybarge. Then the pilot hole is widened using a reamer, allowing the laybarge to lay a section of the pipeline onto the seabed which can be drawn back to shore. The alternative (shown top right) is to drill from a jack-up barge and pull the pipeline from shore. Using a development of this technique, sometimes known as ‘stitch drilling’, it is possible to accomplish long distances in sections of around 1.7 km (1 mile). During construction of the Hoover offshore crude oil pipeline system, it was necessary to cross Quintana beach to reach Freeport Texas. To avoid disrupting the sensitive ecosystem, it was deemed necessary to run the pipe underground. This was done by drilling 1200 m (4000ft) from the mainland to the sea. A land-based directional drilling rig with a 127 mm (5in) washpipe and 76 mm (3in) drillstring opened the hole beneath the beach and out to a barge where successively larger reamers were attached and pulled through the hole, opening it up to 914 mm (36in) – around 25% larger than the pipeline. Meanwhile, the 508 mm (20in) pipeline was laid on the seabed by the Horizon Lonestar S-lay barge. After the final reamer pass, a diver attached it to the pipeline via a swivel and universal joint. The pipeline was drawn through the hole using a force of 2.2 MN (500kip) in 17 hours.

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LANDFALLS - SUMMARY ƒ At the landfall, you need to: ƒ ƒ ƒ ƒ ƒ ƒ

Prepare a trench May need a cofferdam Position laybarge as close as possible Pull the pipe up the beach into pre-dredged trench Backfill trench in surf zone Reinstate beach

ƒ Directional drilling alternative ƒ Minimise environmental disruption

Any questions? Above is the procedure for constructing a landfall. Initially a trench will be prepared through the surf zone, which may require the use of a cofferdam to prevent the walls collapsing and the trench refilling. Then the laybarge will be positioned as close to the shore as possible using either anchors or DP. The pipe is then laid from the back of the lay vessel and pulled to the beach by linear winches. Once the pipeline is installed, the trench can then be backfilled to bury the pipeline in the surf zone. Finally the beach will be reinstated to remove evidence of the pipeline installation. At many low-lying landfall sites throughout the world, it is important to avoid disturbance to the natural beach protection. Directional drilling requires only a small site to drill a hole deep beneath the beach area. Many of the operations and environmental disruption caused at a conventional landfall are thus avoided.

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TRENCHING AND BURIAL

TRENCHING AND BACKFILLING ƒ Lowering the pipeline below the natural seabed level for protection or stability ƒ Three methods are used ƒ Any ideas what they are? ƒ Plough ƒ Jet ƒ Cut

Trenching means removing the soil under the pipeline so that it falls below the natural seabed level. It is normal to undertake trenching after the pipeline is laid on the seabed. However, umbilical cables are often laid and buried in one operation and occasionally pipelines are laid into a prepared trench - such as we have just seen at landfalls. Backfilling means replacing the soil so that the pipeline becomes buried. Not all trenched pipelines are backfilled because the shape of the trench itself can provide some protection. There are three methods of trenching: ploughing, jetting and cutting. Each method has a preferred range of soils for optimum trenching.

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PLOUGH ƒ Ploughing spread is ƒ One DSV ($100 000 per day) ƒ Two tugs ($30 000 per day per tug)

The picture above shows a plough. It has skids at the front (left hand side) and a ploughshare at the back. Offshore, the plough is lowered over the pipeline with the share open. (It splits in half down a vertical plane and opens about a hinge at the top of the plough). The pipeline is picked up by rollers at the back and the share is closed underneath. Tugs or an anchored laybarge then pull the plough forward via a warp attachment at the front. The share digs in and produces a triangular trench under the pipe into which it falls as the plough moves forward.

CTC PLOUGH INITIATION - VIDEO

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The animation by CTC shows how their plough is lowered from the vessel on a wire and located over the pipeline with its split shares open. Lights and cameras on the ROV allow this to be accomplished safely using the plough’s onboard thruster units. The pipeline is lifted into the forward and stern roller boxes and the shares closed using the ram. By lowering the skids at the front, the depth of cut is adjusted as the plough is pulled forward by the bridle chain. It is necessary to check the stresses in the pipeline during the initiation and trenching (with pipe resting at the base of trench to the stern).

PIPELINE PLOUGH PERFORMANCE ƒ Soft clay 800 m/hr (2600ft/hr) ƒ Stiff clay 100 to 200 m/hr (330 to 660ft/hr) Cu > 400 kPa (58psi) ƒ Loose sand 500 m/hr (1650ft/hr) ƒ Med/dense 75 m/hr (250ft/hr) ƒ Dense sand 20 m/hr (65ft/hr) ƒ V. dense sand Refusal ƒ Chalk/rock Variable, rough trench

Typical values for plough performance are given in the table above. The point to bring out here is that it is capable of working on nearly all types of soil, including friable chalk and rock. The major difficulty that it encounters is very dense sand, where the permeability is low. The reason for refusal in dense sand is that, as the plough tries to cut and lift a segment of the sand, it requires water to fill the void created. In low permeability sand, the water cannot reach the interstical voids between the grains and a hydraulic lock results. Some ploughs pump water down to the share tip to prevent this. Ploughs can be employed in water depths down to about 400 m (1300ft), although deeper water is possible using large DP tugs and careful control of the bollard pull to within 5 tonnes (11 kip).

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PIPELINE JET SLED ƒ Jetter spread ƒ Typically flat bottom barge with water jet pumps ƒ $70 000 per day

ƒ Also requires two anchorhandling tugs ƒ $20 000 per day each

The above picture shows the Jet Sled. A barge on the surface pumps seawater down to the sled which discharges out through the jetting arms and blasts away the soil. The sled is towed by the jetting barge. This tool is used extremely effectively. There are two main points to consider. The first is that the soil is whipped away and dispersed, so is not available as backfill. The second is that the machine works best in consistent conditions. For example, if it is on full pressure to excavate some stiff clay and moves into an area of soft sand, it could excavate a large unwanted crater in seconds.

JET SLEDGE PERFORMANCE ƒ ƒ ƒ ƒ ƒ

Soft clay Firm clay Stiff clay All sands Chalk/rock

400 m/hr (1300ft/hr) 100 to 200 m/hr (330 to 660ft/hr) refusal (surface fractures) 400 m/hr (1300ft/hr) refusal (surface fractures)

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The above table gives some general characteristics which indicate that the jet sledge is best used in sand or soft to firm clay. Jet sledges work in depths down to about 200 m (650ft), the limitation being current forces and the length of umbilical power cable or water hoses. In deeper waters, ROV jetting or cutter machines can be employed.

PIPELINE MECHANICAL CUTTER ƒ Mechanical cutter spread is specialist support vessel ($150 000 per day) ƒ Allseas’ Digging Donald

As the name implies, the mechanical cutter is a device that drives along the pipeline with mechanical teeth or buckets excavating a trench. Mechanical cutters are well suited to hard seabed soil conditions. The above picture shows the Digging Donald - a tracked vehicle with two chainsaw arms reaching under the pipe. The Digging Donald has the advantage that it does not need to make contact with the pipe during the trenching operation.

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MECHANICAL CUTTER

Trenchsetter with Digging Donald

This picture shows the Digging Donald being deployed from the Allseas Trenchsetter support vessel.

CUTTER PERFORMANCE ƒ Soft clay

300 m/hr (990ft/hr)

ƒ but may sink or skid

ƒ ƒ ƒ ƒ ƒ ƒ

Stiff clay 100 to 200 m/hr (330 to 660ft/hr) Loose sand 200 to 300 m/hr (660 to 990ft/hr) Med/dense 200 m/hr (660ft/hr) Dense sand 100 m/hr (330ft/hr) Very dense 75 m/hr (250ft/hr) Chalk/rock variable high tooth wear

Again cutters can be used in most types of soil. Their particular ‘bête noire’ is to cut through chalk or soft clay, where boulders or flint embedded within the soil tend to break or blunt the teeth on the cutters. Cutter units are limited only by the means of deployment and length of umbilical cable being acted upon by the ocean current.

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TALON TRENCHER ƒ Swords on ROV ƒ Cutter and jetter options

ƒ Used for deep water flowlines ƒ Insulation of soil

ƒ ‘Flies’ to location

In deepwater, it becomes difficult to plough due to the length and flexibility of the towing warps. A conventional jetter also has problems following the line of a pipe when being slung from a barge. Devices such as the Talon Trencher, pictured above, have therefore been developed. They have of a pair of ‘swords’ mounted under an ROV (remotely operated vehicle) which can ‘fly’ down to the pipeline and commence burial. The swords can either be jet arms or cutters, depending upon the soil conditions. They fit either side of the flowline and lower it to depth. The machine is usually used for deepwater lines, which may require burial for insulation reasons rather than protection against trawler impact.

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DEEPWATER TRENCHING ƒ Used for thermal insulation in deep water ƒ No requirement for stability or trawling protection

ƒ Challenges: ƒ Soft soils ƒ Equipment sinks in ƒ Trench walls unstable

ƒ Plough tow rope catenary cannot give even pull ƒ Plough tends to surge and damage pipe

ƒ ROV cut or jet methods required

Trenching may be used in deepwater for thermal insulation. It is not required for stability in waves or currents because the effects of both are reduced in deep water. Nor is there as much trawling effort in such depths. However, we tend to find soft soils which prevent the use of tracked equipment. Trench walls in such soil tend to collapse more readily. Ploughing methods for pipelines cannot be used much below 400 m (1300ft). This is because the catenary in the wire results in the plough surging forward and then stopping until the tow vessel moves forward and reapplies the force. During the surges the plough may deviate off line and damage the pipe. This means that ROV cutting or jetting methods are preferred. The ROV uses the pipeline as a ‘monorail’ guide and support.

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UMBILICAL AND CABLE BURIAL SYSTEMS Towed sled cable plough

Tracked jetting cable burial system

Cutter wheel for rock

The same three methods are used for burial of umbilicals and cables. Costs are lower because less soil needs to be removed because of the smaller diameter of these compared with pipelines. Similar equipment is used for umbilicals and cables, so these will be examined together. Sometimes, these terms are used interchangeably, but a cable usually provides power through copper cables or data down optical fibre links. An umbilical usually has small bore chemical injection or hydraulic lines as part of the bundle. This tracked jetting vehicle is used to bury umbilicals and cables after laying as a separate operation. It needs a firm seafloor to operate but the cable is trenched and buried in one pass. The cable is passed though a protective tube in the ploughshare. Jetting is ideal for silty and sandy seabeds. Where the ground is softer a towed sled plough system may be employed. This operates best in coarse sand, silt and clay. The plough displaces a wedge of soil upwards and then lets it drop back down burying the cable. In harder ground or rock, a cutter wheel may be used to make a slot. Again the cable is laid into the bottom of the trench.

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CTC CABLE JETTER

The CTC tracked trencher can jet cut and disperse the seabed sediment lowering the cable into a trench.

UMBILICAL AND CABLE BURIAL ƒ Single pass - lay and bury ƒ Slower production ƒ Single vessel

ƒ Dual pass - lay then bury ƒ Or trench then lay

ƒ Care needed with umbilicals ƒ ƒ ƒ ƒ

Single pass minimises tension Ensures alignment of trencher follows umbilical Catenary to allow for wave and current movement Armouring to protect against rock impact ƒ English Channel electricity cables - pre-cut slot

Where possible, a single pass lay and bury system should be used. This generally results in a slower lay rate since the operation is dependent upon the speed of trenching. However, a single operation means that total costs may be lower. If this is not possible, the commonest practice is to lay the cable first and then trench and backfill. If the umbilical follows the route of a pipeline, then it may be laid into the

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previously cut trench. That is, three operations - lay the pipeline, cut the trench, lay the umbilical. Whereas pipelines have some inherent strength, the smaller diameter of umbilicals and cables inevitably means that there are additional risks of them parting due to high tension. This is especially true when the trenching and burial is completed as a separate operation and the alignment of the trench is not exactly that of the umbilical. Single pass helps minimise the tension in the unit. However, a suitable design of catenary from the vessel into the trencher must account for the wave and current movement of the cable and the vessel. In cut rock trenches, there may be the need for additional armouring to provide protection against the rock rubble that backfills in on top of the cable. When electricity cables were laid across the English Channel in 1986, a trench was precut in the chalk and a guide wire laid into the trench. The wire was removed in a separate operation when the slot was cleaned out and power cables were then laid. The trench then backfilled naturally with sand.

CTC CABLE PLOUGH

The CTC plough is located over the cable, which it lifts into the guide chutes before being towed forward by the tug. Depth of trench is controlled using the forward skids. It is different from a pipeline plough in that the ploughshare is very narrow, enabling it to trench and bury the cable in a single operation.

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PIPELINE BACKFILLING ƒ Natural backfill ƒ Backfill plough ƒ Rockdump

Although umbilical cables are generally backfilled in the same operation as trenching, this is not so for pipelines other than those lowered by sand fluidisation (jetting). Having trenched the pipeline, it is sometimes necessary to backfill it (for protection or thermal insulation). Note that pipeline trenches can also be left open under some circumstances. There are three main ways of doing this, which are presented here in order of escalating cost: ■ Natural backfill means leaving the pipe in the trench and waiting for tide and waves to wash the soil into the trench and to fill it over the pipe. This has the advantage of being free and the disadvantage that it may take some time and is only feasible in certain areas like the Southern North Sea which have sufficiently high sediment transport. It would be very slow in the Central North Sea and negligible in the Northern North Sea. ■ The next level up is to use a mechanical backfill plough to push the soil from the sides of the trench back over the pipeline. ■ If there is no soil to pull back over the trench, then the third method is to rock dump. This is shown in the picture above: a ship with gravel and a digger in the hold. The digger shovels gravel onto a conveyor system and drops it down a fall pipe. The fall pipe runs from the ship down to close to the seabed and can be seen in the inset. It has thrusters and sensors on the end to position the rock over the pipeline. Larger vessels are available to supply the quantities of rock needed for trunk pipelines. They are typically fitted with longer fall pipes suitable for water depths of 800 m (2600ft) or more.

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TRENCHING AND BURIAL SUMMARY ƒ A variety of techniques to trench and/or bury pipelines and cables ƒ Depends on the type of soil ƒ Granular sands and gravels ƒ Cohesive clays and silts ƒ Soft rock

ƒ Cables can be trenched and buried ƒ Three types of backfill Any questions? There are several methods used to trench/bury pipelines. The selection of the method is dependant on the type of soil in which the pipeline must be buried. The ploughing method works well in most soil types, except for very dense sands. The jetting method will not work in stiff clays and chalk or rock. Cutters are suited to all soil types but are particularly suitable for working in chalk and rock. Similar methods can be employed for umbilicals and cables, but it is common for the trenching and backfill to be undertaken in a single operation. Where trenches need to be backfilled three methods are used depending upon whether there is available spoil or natural backfill conditions. The final option of rockdump is the most costly because of the need to import fill material.

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PRE-COMMISSIONING

WHAT IS COMMISSIONING? ƒ Commissioning ƒ Operations for first product delivery through the line

ƒ What then is ‘pre-commissioning’?

Sometimes the terms commissioning and pre-commissioning are confused.

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PRE-COMMISSIONING OPERATIONS ƒ Flooding ƒ Flood the pipeline with treated water ƒ Fresh water for flexibles with 316 SS

ƒ Send through gauging pig

ƒ Hydrotest ƒ Pressurise to prove strength and leak tightness

ƒ Dewater ƒ Pig out the water and dispose of it

ƒ Dry (gas lines) ƒ Hygroscopic swab and air or vacuum dry

ƒ Intelligent pig run (baseline) The pipeline is flooded with treated water in order to be able to strength-test it. (Water is used rather than air in order to keep the pressurisation energy to a minimum, and so too the consequences of any failure.) At the same time, a gauging pig is passed through the line to prove that the bore is clear. This is more fully explained in the flow assurance module. The water used is generally filtered seawater containing: ■ Oxygen scavenger to prevent rusting ■ Biocide to prevent bacteria which might produce hydrogen sulphide ■ Fluorescent dye to help with tracing any leaks Because of environmental concerns, the biocide or fluorescent dye are sometimes omitted. If the line is being commissioned quickly afterwards the biocide may not be needed. It may be better if the dye is only pumped in when the hydrotesting has determined that there are some leaks. Flexibles with a 316 stainless steel carcass will need fresh water since the material is prone to chloride stress corrosion-cracking. The sequence of events is normally to flood the line after trenching and burial. However, in some cases the extra weight is beneficial, so the line is flooded prior to trenching. This is particularly so of flexibles which are normally pressurised (to a low pressure) prior to trenching. It is also true of pipelines with low relative density, where there is a risk of flotation during backfilling. The remainder of pre-commissioning is to hydrotest and dewater as explained in the following slides. Good practice would suggest the use of an intelligent pig to provide a baseline of defects for the future integrity management operations. How can we be sure of wall thickness loss without having the initial data to compare with?

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PRE-COMMISSIONING AND DOCUMENTATION

ƒ Check integrity of ancillary equipment ƒ ƒ ƒ ƒ

Power and communications Gas compression equipment Product transmission SCADA monitoring systems

ƒ Check efficiency and safety ƒ Produce documentation for commissioning ƒ Operations manuals ƒ Emergency procedures ƒ Maintenance manual ƒ Including inspection regime

The pre-commissioning phase should also be used to check the integrity of the ancillary equipment to the pipeline, which includes the equipment and the systems shown above. Some of the checks might be: ■ Are the gauges giving the correct readings? ■ Are pumps and valves operating correctly ■ Is the correct information being displayed on the SCADA screens? ■ Are flows being registered within tolerances? The full set of manuals for operating the line through its life need to be handed over. This should include proposals for decommissioning at the end of the pipeline life.

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DEFERRED COMMISSIONING ƒ Early phase of field development ƒ Commissioned following season ƒ Left filled with treated water or inert gas ƒ Water filled - biocide, fungicide, oxygen scavenger, all air removed ƒ Dry inert gas (N2) - kept at a positive pressure

ƒ Survey to check for leaks

It may be necessary to have a deferral period between testing and commissioning. If this is case, the line should be filled with a temporary fluid to minimise internal corrosion. Suitable fluids for deferral include dry inert gas, product gas and product, oil or water to which biocides and fungicides are added. If using water, then care should be taken to ensure that all the air is removed from the pipeline and that the water contains no corrosive materials. It is also advisable to leave the pipeline under a small positive pressure and check the line periodically for leakage until commissioning commences.

HYDROTESTING PRESSURES ƒ Strength test ƒ 1.5 times MAOP or 90% hoop stress for 24 hours ƒ Gas lines may test to 105% SMYS ƒ Pre-yielding helps with cyclic loading fatigue

ƒ Risers and other preformed bend sections ƒ Separate strength test prior to installation ƒ At a higher pressure for thicker wall

ƒ Leak test ƒ Tie-in joints may be leak-tested at 1.1 times MAOP for 3 to 6 hours to prove valves and fittings

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Normally, the hydrotest pressure on the pipeline is set to 1.5 times maximum allowable operating pressure or 90% of hoop stress, whichever is less. The test is held for 24 hours. This is for three reasons: ■ By starting and finishing at the same time, a complete daily temperature range is accommodated. ■ To ensure that small leaks are detected. ■ In the past some failures have been shown to be time-dependent and have occurred within the 24-hour period. The US codes have slightly reduced requirements at 125% or 140% of maximum design pressure held for just 8 hours. In the ‘Pipe Size and Route’ module, we mentioned that risers are often designed to a lower design factor with thicker walls. This in turn means that they should be strengthtested to a higher pressure. Therefore, they are typically strength-tested in a fabrication yard prior to being assembled into a pipeline system. Once the pipeline, the spoolpieces, the risers, the valves and the pig traps have all been strength-tested individually, the pipeline is assembled and leak-tested to 1.1 times MAOP for 3 to 6 hours, or as long as it takes to prove that all assembly joints are sealed. When conducting hydrostatic tests on gas pipelines, it is may be necessary to take the test pressure to 105% SMYS (dependant on national codes). The resulting yielding in the pipeline serves to smooth out any stress concentration points that may have developed from incomplete weld penetrations. This helps to improve fatigue properties which is important in gas lines as they tend to undergo more cyclic loading than oil lines.

HYDROSTATIC TEST ƒ Pressure test various sections of the pipeline (risers or crossings for landlines) ƒ Usually conducted after backfilling on land

ƒ ƒ ƒ ƒ ƒ

All air & debris removed Filtered clean water Safety precautions Test longest sections possible Safe disposal of water

Hydrostatic tests involve filling sections of the pipeline with water and then pressurising them to check for possible leaks or defects. With landlines, the operation may be required to be undertaken only once, after burial because it is possible to dig down and repair leaks. However, this is difficult with offshore lines, so it is common to undertake hydrotests at a number of additional stages such as after laying and after trenching. For the main pipeline sections, the hydrostatic test should take also place after backfilling to

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identify any possible damage to the pipeline that has occurred during to the backfilling process. It is vital that all trapped air is removed prior to full test pressurisation. The air pockets need to be removed as they can be compressed (which means the pipe takes longer to reach the full test pressure) and would also become a hazard if the pipe were to rupture. To prevent air becoming trapped, it is usual to install the water behind a pig. The air being flushed out is then kept backpressured to prevent the pig running away from the water. Also to be noted is that valve bodies, bypass pipework, etc. need to be vented and sealed to relieve the air. The water for use in a hydrostatic test needs to be clean and filtered. Filtering is particularly important if the water is being taken from a natural source like the sea, rivers or streams. If water is being taken from the sea then it may also require desalinating when hydrotesting pipe containing 316 stainless steels (some clad pipe and flexibles). When releasing the water back into the environment after the hydrotest, it is important that the test water has been cleaned of any harmful corrosion inhibitors, bactericides or other chemicals. Safety precautions will also need to be adhered to and should include measures to protect public and personnel, prevent pollution or damage to roads, waterways and rivers, and obviously to ensure that no work is still being undertaken on sections being tested. With arctic landlines, it may be necessary to use heated water for the hydrotest to prevent freezing. Here, quite unusually, the use of air for the pressure test may be used since these lines are generally remote from personnel and any explosive rupture would do little damage to third parties.

COMMISSIONING ƒ Remove hydrotest water and dry pipeline ƒ Introduce product ƒ For oil or petroleum ƒ Pig train used to minimise interface mixing ƒ Temporary vessel to separate product/water mix

ƒ For hydrocarbon gases or liquefied gases ƒ Water displaced by air or dewatering pigs ƒ Drying required ƒ Methanol swabbing, dehydrated gelled pigs, dry air or vacuum drying

Usually the final steps in pre-commissioning is to remove the water from the hydrotest and dry the pipeline if necessary. For oil and petroleum based products, the drying and introduction of the product is simpler than for hydrocarbon gas products. With flammable or toxic products that are liquid at ambient temperature (e.g. oil and petroleum), it is acceptable to displace the water with the product and use a series of pigs

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to minimise the water/product interface. It may be necessary to provide a temporary separator at the end of the pipeline to separate the product from the oil for the first stages of operation as water may have collected in valves and fittings that may take a while to be flushed out. If the pipeline is to convey products that are flammable and gases at ambient temperature (e.g. LPG, natural gas, hydrogen, etc) then the pipeline will require the test water to be removed independently of the product and for some products the line will require drying. The choice of drying method depends on the degree of dryness required. A common method for gas and LPG pipelines is to swab through with pigs to remove the majority of water. Then methanol is conveyed between a series of pigs. After the methanol, the pipeline is purged with dry nitrogen. Where gas is being delivered to the end user, then vacuum drying or air drying is needed as a final step. When introducing products, precautions should be taken to ensure the mixtures of the gases or liquids is not done in a way that may result in explosive combinations.

DEWATERING

Nitrogen

Methanol

Water & Methanol mix

For a gas line, fill with nitrogen prior to drying For an oil line, introduce product directly

Water

Flow

For gas trunk lines, dewatering would be done with a train of pigs, perhaps with gel or methanol between, as shown in the above diagram. The line would then be vacuumdried to remove all traces of water before the introduction of export quality gas. Such a procedure would not be necessary with a two-phase flowline or an oil trunk line, where the likelihood is that the water would be displaced by a pig train driven by the production fluid.

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AIR/NITROGEN DRYING OF PIPELINE ƒ Foam pig swabs – absorb & push water out ƒ Warm desiccated air or nitrogen ƒ Reduction in outlet hygrometer readings ƒ Indicates reduction of dew point ƒ Completion of drying ƒ Typically a differential of 5C° (9F°) between inlet and outlet

ƒ Usually completed within a few days even for large diameter trunk lines Foam pig trains may initially be run to act as swabs, removing any condensed water from the walls and push any liquid out in front of them. Then warm dry gas is delivered to the inlet. Either air or nitrogen is used. The latter is an inert gas so has the advantage for hydrocarbon lines in that we can safely introduce gas without fear of explosion. The picture shows BJ process air drier unit. This can deliver -73°C (-100°F) dewpoint air which is used to achieve extremely low dewpoints during pipeline drying. As the differential dew point readings reduce, the drying process is completed. It is common to achieve a final dewpoint of -20°C (-4°F). This is a rapid process, but which may be followed by additional vacuum drying.

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VACUUM DRYING ƒ Export and sour gas lines only ƒ Follows nitrogen drying A - Pump down phase B - Vapourisation/evacuation phase C - Dehumidification/vacuum purging phase (check for ice crystal formation – allow to re-melt) D - Vacuum release & return to atmospheric pressure

Pressure (millibar) Logarithmic Scale

1E3

A

0 0

B

Drying Time (days)

C

D

30

Vacuum drying means attaching vacuum pumps to one or both ends of the pipeline and drawing a vacuum. It is only used for gas lines where water vapour would be a problem. If you reduce the pressure above water, you also reduce its boiling point. An example of this is that mountaineers find that water boils at less than 100°C (212°F) at altitude, and consequently boiled eggs take longer to cook. Inside the pipeline, the pumps reduce the pressure to the point where water will boil at (say) 4°C (39°F), or whatever the ambient temperature is. The drawdown curve flattens as the water vapour comes off. The finishing process involves stopping the pumps and checking whether the pressure rises. As the pipeline reaches that of the seawater, further vacuum will freeze ice crystals on the inside of the wall. Thus the air will initially appear to be fully dried. However, by releasing the vacuum slightly, these crystals will melt. Only when all the water is converted to vapour and removed from the system will the graph stabilise. It only works where the line has already been dried using other means. Puddles of water take a very long time to clear. If necessary at pig traps, valve chambers etc, it may be possible to enter the line and remove standing water using squeegees. The process can last for 4-12 weeks, depending on the pipeline size and length. For this reason and the costly delays, it is avoided wherever possible.

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PRE-COMMISSIONING - SUMMARY ƒ Prepare documentation ƒ Hydrotest ƒ Flood ƒ Pressurise

ƒ Dewater ƒ Flush out with nitrogen or product ƒ Dry – swabs and air dry ƒ Vacuum dry for sour gas or consumer gas line

Any questions? The activities required in pre-commissioning an installed pipeline ready for product transfer are shown above. The first task will be to prepare the required documentation, which include the operating and maintenance manuals and the emergency procedures. Then the pipeline will be hydrotested to ensure its integrity. The hydrotest procedure is shown above. Initially the pipeline is flooded with water and then pressurised. Then the hydrotest water is removed either using nitrogen or the product. If the product is to be gas it may be necessary to dry the line using swabs or warm air. The costly process of vacuum drying is needed for certain gas lines.

CONSTRUCTION SUPPORT SUMMARY

ƒ Basic landfall activities ƒ Use of pre-trenching

ƒ Post-lay trenching and burial ƒ Main pre-commissioning activities Any questions?

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Overview of pipeline engineering

The basic aims for landfall construction are to protect the trench through the beach area whilst avoiding flooding of the land. Once the pipeline is brought ashore, it is buried deeply to protect it in the surf zone. It is one of the few times that a trench is normally preformed prior to laying the pipeline. The reasons and main methods for the trenching and burial of pipelines on the seabed have been covered. The amount of seabed soil to be removed with post-lay trenching is much less than for pre-lay because the position of the pipeline is known. The methods to protect umbilicals are similar, though smaller plant is used.

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EXPECTATION

EXPECTATION ƒ Connecting in pipelines to topsides jacket or floating host ƒ Flanges and hub connectors ƒ Spoolpieces and jumpers ƒ Installation of rigid risers ƒ Flexible risers

Spoolpieces and risers are needed to connect the pipeline to the platform or FPSO. The usual method for linking between the pipeline and spoolpiece is using flanges. However, other proprietary systems are available. We show how flexibles are manufactured although we mainly concentrate on the installation methods.

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TIE-INS AND SPOOLS

SPOOLPIECES, FLANGES AND HUBS ƒ Subsea pipelines allowed to expand ƒ Spoolpieces take up expansion ƒ Typically 30 m to 100 m (100ft to 330ft)

Dog-leg or Z-shape

U - shape L - shape

ƒ Weld-neck mated with swivel ring flange ƒ Soft iron ring in groove

ƒ Proprietary connections ƒ Lighter flanges ƒ Taper-lok

ƒ Clamps using hubs ƒ Grayloc

ƒ Collet and hubs Spoolpieces are required to connect between the end of the pipeline and the riser or wellhead. Subsea pipelines are normally allowed to expand on the seafloor. This is in contrast with buried onshore lines with thrust blocks to resist movement. The length of the spoolpiece is kept as short as possible to enable it to be lowered into position without damage yet long enough to take up the expansion in bending. For this reason, it is common to use L, U or Z shaped thick-walled spools with formed 5D (or gentler) bends. When connecting the spool to the end of the pipeline, it is possible to use either standard API weld-neck flanges mated with a swivel ring flange. The swivel permits the bolt holes to be aligned without applying torque forces. The seal is made using a soft iron ring (either oval or hexagonal in cross-section) fitted into a standard groove in the flanges.

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Alternatively, it is possible to make use of proprietary systems. These may be lighter weight flanges (Taper-lok) or use hubs and clamps (Grayloc) or collets (vertical connections in GoM).

RIGID STEEL SPOOLPIECES USING DIVERS ƒ Metrology ƒ Measure spool length and four angles for flanges

ƒ Fabricate on deck and lower to seabed ƒ Use of flanges or connectors ƒ Commonest method ƒ Flange leaks at make-up, testing or operation ƒ Not too loose nor too tight – crushing of seal

ƒ Lifted and welded at barge ƒ Shallow water only

ƒ Hyperbaric welding – dry habitat on seabed ƒ Used in North Sea and Australia Divers first need to measure the spoolpiece distance and the angles (vertical and horizontal at both flanges) between the pipeline and riser ends. This is then reproduced on the deck of the workbarge and pressure tested prior to being carefully lowered the seabed. Flanges or connectors are then made up by the divers. This is by far the commonest method. However, flanges can and do leak. The force on the bolts needed to draw the ends of the spool up (accounting for any mis-measurement) and make the seal is undertaken once. This then usually must serve for the hydrotest and operational conditions with no further adjustment. The pressure at hydrotest can make the pipeline and spool move and is greater than will be experienced in normal operation. For hot lines, the final condition may mean further movement. It is important not to undertighten the bolts nor to overtighten and crush the soft iron seal. An alternative approach that can be used in shallow water – 30 m (100ft) – is to use derricks on the barge to lift the end of the pipeline out of the water and weld on the spoolpiece and riser. In deeper water, hyperbaric welding can be undertaken. This eliminates connectors entirely but is costly. The divers operate in a dry habitat at the seabed.

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FLANGE LEAKAGE PROBLEM ƒ Gaskets held with locally-produced skillets ƒ Misalignment and poor seating ƒ Crushed during flange tightening

Skillet

ƒ Seal required for: ƒ Make-up ƒ Initial over-tightened

ƒ Hydrotest ƒ Bolts ‘flogged up’ ƒ Yielding of bolts ƒ Further crushing ƒ More leaks

Crushed gasket

ƒ Operation Jee Ltd was called in to investigate a problem with flange leakages during a spoolpiece installation. Concern was raised by the client as to whether the seal obtained on hydrotest would leak further when the higher temperature and lower operational pressure were imposed. There were many possible causes suggested, including the arrangement of the spool lengths, the thickness of paint on the flange faces, the out-of-specification dimensions of flanges and bolts, the material grade of the gasket and flanges, the sub-contractors’ experience and their actual tightening procedures (which differed slightly from those laid down). Subsea, it is common to tighten the bolts once at make-up. They should initially be tightened to leave a residual tension of just under half their yield. This single operation should then maintain the seal during the hydrotest and operational phase with no further adjustment. During make-up, there is no internal pressure and ambient temperatures, but there may be some mis-measurement (angular or axial) or fabrication tolerance of the spoolpiece and flanges, which needs to be pulled in. At hydrotest, the internal pressure is the highest it is likely to experience but there is no increase in temperature. Spoolpieces may move from their initial position; flanges may rotate slightly and pull apart. For the operational phase, temperatures may cause expansion of the pipeline and further movement may occur. The conclusion reached following analysis was that the cause was related to the method of holding the gasket during tightening operations. The gaskets were located within locally-made skillets to ensure they aligned with the flange grooves. The skillets’ inner holes were not concentric within the rims. Because they did not hold the gaskets centrally between the bolts, the gaskets were crushed during the initial make-up operation. At this stage, the bolting up procedure using bolt tensioners caused overtightening and crushing of the soft iron. Leaks were detected during the hydrotest and this then resulted in individual bolts being ‘flogged up’ further with no regard to equalling out the load in each. It is suspected that this operation caused some of the bolts to yield, as well as further deforming the gasket seal.

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The solution was to renew the gaskets, skillet and bolting, and to revisit procedures to prevent a recurrence.

DIVERLESS CONNECTION METHODS ƒ Saturation diving limit ƒ Normal safe maximum 200 m (656ft) - Europe ƒ Absolute limit 300 m (984ft) - US

ƒ Deepwater challenge: ƒ Reliable diverless connections between components ƒ Alignment of components ƒ Vertical or horizontal makeup

Divers are often used to connect a rigid pipe spoolpiece from the bottom of the riser to the end of the pipeline. However, divers cannot work in the deepest water. Diving is at its absolute limit at 300 m (984ft) water depth using saturation methods. Normal safe maximum operating depths are less at 200 m (656ft). This range covers most of the fields in the waters around the UK and the North Sea. In deep water, the connections between components in a subsea production and flowline system have to be made without the use of divers. The challenges associated with diverless connections are: ■ Reliability - we may need to operate the connectors many times during the life of the pipeline. This means that we want it to make and break every time for all units throughout the service life. We cannot go down and adjust something or repair a damaged flange if the connector system goes wrong! ■ Alignment - this is often achieved using different mechanisms for initial line-up and final seal ■ Orientation - some systems can only make horizontal connections, others can also connect directly to vertical risers. Diverless systems originally developed for deep water are now also used in diving depths.

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WHY DEEPWATER ƒ Elephant fields in Gulf of Mexico ƒ Each is the size of North Sea reserves ƒ ƒ ƒ ƒ

Kings Peak 40·106 m³ (250 MMboe) Thunder Horse 160·106 (1000) King Kong 40·106 (250) Llano 160·106 (1000)

GOM Developments in >450 m (1476ft) water depth

The world’s shallow water oil and gas reserves have been developed. The continuing demand for oil is driving the need to develop more difficult reserves in deeper waters. There are considerable deep water reserves in the Gulf of Mexico and other parts of the world, and we are seeing rapid technical advances being made so that these reserves can be exploited. MMboe - Millions of barrels of oil equivalent

WEST AFRICA ƒ Similar story elsewhere ƒ Offshore West Africa ƒ Girassol, Angola ƒ Bonga, Nigeria ƒ 120·106 m³ (750 MMboe)

Courtesy of Van Oord ACZ

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Offshore West Africa is another area of considerable deep water reserves and we are seeing much activity in this region.

DEEPWATER AREAS AND BASINS

NWECS (UK) Southern Caspian Sea

Eastern Canada

Southern CA

Egypt

GOM Nigeria Equatorial AngolaGuinea Congo Campos Gabon Basin Namibia South Africa

Indonesia

The above map – produced by Offshore Magazine and Mustang Engineering – shows where the major deepwater basins lie and where future developments may take place. Current development areas are named in yellow with new and future regions indicated in red. The white area offshore of California is now deemed a former area. Where: ■ NWECS (UK) = Northwest European continental shelf (United Kingdom)

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WHAT IS DEEP? ƒ In 1975, the 813 mm (32 in) Forties line laid in 150 m (500 ft) water was considered deep ƒ Now, figure is about 1000 m (3300 ft)

However, not everyone agrees with this arbitrary definition of deep at 1000 m (3300ft). Flexible riser manufacturers, ROV buoyancy suppliers, fishermen, sport and commercial divers all have different views. This also changes around the world.

DEEP PIPELINES

Pipeline difficulty (water depth x diameter)

(m²) 2500

Oman-India

Measure of difficulty

2000 Mensa (Lorelay)

1500

TransMed Pipelines Marlin (Apache) (Castoro Sei)

1000 500

BlueStream (J-lay)

MedGaz

25 000 20 000 15 000

Diana

10 000

Messina Strait (Castoro Sei)

5 000

Forties (Castoro Due)

0 1965

(ft²)

0 1970

1975

1980

1985

1990

1995

2000

2005

2010 Year

This figure illustrates the advance in deep water pipelines. The axes show difficulty, here defined as water depth x diameter and plotted by the year. We can see that currently we are going through a period of rapidly increasing difficulty.

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Along with deeper pipelines, we have correspondingly increased depths for platforms and associated risers.

PIPELINE CONNECTION SOLUTIONS ƒ Principles: ƒ Necessary requirements ƒ Reversible connection ƒ Retrievable seals

ƒ Often desirable ƒ No hydraulics remaining on seabed ƒ Preferably one ROV trip ƒ Self-seal on opening ƒ Pressure balanced ƒ Testing of seal

ƒ Alignment methods: ƒ ƒ ƒ ƒ

Flexible jumper Rigid pipe spool Straight pull-in Deflect-to-connect

ƒ Example systems: ƒ ƒ ƒ ƒ

DMaC KOSCON MATIS & UTIS BRUTUS

For diverless connection of spoolpieces to connect the end of the pipeline to the bottom of the riser there are a number of principles common to all methods. The two essential principles are that the connection can be reversed if something goes wrong and that any seals can be retrieved and replaced if they become worn or damaged during the installation or during subsequent operation. It is also better if we leave as few hydraulic parts on the seabed as possible. After a number of years, these will almost certainly cease to function and cannot be serviced. If there are a number of connections to be made, then it is preferable that all go down to the seabed at the start of operations. The ROV can pick up the necessary part when needed. It takes a long time for an ROV to be recovered to the surface to have a new tool or part added and then return down to the seabed. If possible, any hose fittings should self-seal when the connection is opened and such items should be pressure balanced to avoid large make-up forces. Many systems are able to test the seal prior to the hydrotest. There are four basic methods or configurations for making subsea connections, as listed above. Note that these methods apply to both diver and diverless connections and tie-ins. The basic principles of connection (reversible connection and retrievable seals) again apply to both diver and diverless connections. However, they are more technically challenging and costly to achieve for a diverless system.

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INITIAL SPOOL ALIGNMENT METHOD ƒ Flexible spool ƒ Wire pull-in - flexible flowlines ƒ Fly-to-place - umbilicals and cables

ƒ Direct pipe pull-in - no thermal expansion ƒ Only at one end of the pipeline

ƒ Rigid flowline spool - accurate fabrication ƒ Spool pull-in - joint made at seabed ƒ Deflect-to-connect - joint made at seabed ƒ J-tube pull-in - joint made at top

ƒ Rigid or flexible spool with vertical stab ƒ Installed on guide posts Flexibles are commonly stabbed horizontally. A number of proprietary systems use wires and small winches on the ROV to bring the end of the flexible pipe towards the riser. For umbilicals and cables, the ROV can directly ‘fly’ the ends together. Where thermal expansion of the pipeline is not a consideration, the pipeline itself can be pulled directly into the manifold structure either using diver or ROV intervention and the topside vessel crane. This method can only be used at one end of the pipeline. In contrast to flexibles, all rigid spools require accurate measurement and fabrication, in combination with an alignment system that can apply considerable force to bring the ends together. Three methods can be used for the initial alignment of a rigid spool. A direct pull-in can use wire (as for the flexible) or rams on the ROV tool. Deflect-to-connect makes use of buoyancy on the line to reduce seabed friction and wires bring the ends together. We will examine the J-tube method in the Risers module. Rigid spools can also be made up using vertical stab-ins at either end. These spools are an inverted U shape and are aligned using guide post systems.

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FLEXIBLE PIPELINE PULL-IN

1 Run pull-wire from porch

2 Connect to flowline pullhead

4 Remove pullhead

3 Wire pull-in

5. Make-up connection

The above slide shows a diverless pipeline pull-in sequence.

INTEC DMaC FOR RIGID OR FLEXIBLE - VIDEO

The DMaC connector is extensively used in the West of Shetlands in the north of Scotland. The procedure follows that shown on the previous slide. It is used for both rigid and flexible pipeline spools. Other proprietary designs exist that do not require as accurate a rotational alignment of the end of the pipeline. However, they operate on similar principles. The picture shows a DMaC manifold unit containing a number of connection ports.

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DEFLECT-TO-CONNECT AND VERTICAL STAB Risers on fixed platform

Set down of rigid pipe end within tolerance

Pull-in wire

Vertical stab lowered into place

Deflect-to-connect rigid pipeline with buoyancy and chains

Deflect-to-connect can be used with the ends of rigid pipelines. Even large diameters up to 914 mm (36in) have been installed in this way. Pipelay initiation must ensure that the end sits within a rigid target box. The weight of the pipe is minimised using buoys and chains. A wire pulls the end of pipe over to the riser. The ends are finally connected using collets or clamps. Care must be exercised when recovering the buoyancy modules, since without the weight of the pipe, they surface rapidly. Vertical stab-in risers can be lowered down using barge or platform cranes. An ROV helps guide the spool onto the ends of the riser and pipeline.

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FINAL MAKE-UP AND SEAL ƒ Collet connectors ƒ Clamp and hub systems ƒ Flanges

Collet

Guide post for lowering down on wire

Clamp

ƒ Pull-in and connection system retrievable Collet type connector

Kongsberg UTIS

For deepwater developments, dedicated remote pull-in systems have been designed. They may utilise diverless technology such as collet connections or clamp and hub systems combined with retrievable pull-in tools. Alternatively, lightweight or standard flanges may be used. These require much larger equipment to install the bolts and tighten the nuts. In all cases, as much of the equipment as possible is recovered for use on the next connection. Ideally, only the connectors themselves should remain. The photograph shows one type of collet connector tool.

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VERTICAL STAB AND HINGE-OVER

Collet connector Collet connector Connector assembly hinges assembly is lowered on assembly lands in over flexible or rigid flowline receiver pyramid during pipe lay-away

ROV makes hot-stab to make up and test connector assembly

It was originally perceived to be easier to use vertical stab-ins because these can be lowered into place. This slide illustrates the vertical stab and hinge-over system used for initiating and connecting the first end of a flexible pipeline.

DIVERLESS INSTALLATION ƒ Rigid spool with vertical stab

The picture illustrates a rigid spool with vertical stab connections.

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DIVERLESS INSTALLATION ƒ Vertical spool ƒ Easier to lower and align ƒ Both ends connected together ƒ Minimises makeup forces and moments at ends ƒ Requires hinged PLET 2

1

3

This sequence illustrates the vertical stab subsea tie-in being made. Vertical spools are the common method used in the Gulf of Mexico where trawling snag risk is low. It is much easier to lower the spool and connect up both ends in one operation. Provided the metrology has been undertaken carefully, the make-up forces and moments are almost eliminated. However, the pipeline must be laid with a vertical bend on a hinged pipeline end manifold (PLET).

BIG INCH ARTICULATED CONNECTOR - VIDEO

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One problem associated with diverless rigid spool tie-ins is misalignment of the connection hubs. The Big Inch articulated connector illustrated above allows for up to 5° of misalignment. Connection is first made using funnel and guide post, then the seal is made by drawing the ends together using a clamping mechanism. The seal can be pressure tested prior to commissioning.

FLANGE MAKE-UP ƒ MATIS system ƒ Lightweight or standard flanges ƒ Minimum equipment left on seabed

The above slide shows the MATIS (Modular Advanced Tie In System) diverless makeup system, which can effect subsea diverless connections utilising a variety of connection systems. The system operates by aligning the ends of the pipes using conventional remotely operated pipe handling frames to bring the flanged ends within the flange alignment frame. Once final alignment has been achieved and a gasket has been inserted, the flange faces are brought together and a cassette compatible with the flange type is lowered into the frame. This cassette inserts the studs into the bolt holes in the flanges and then runs the nuts onto the studs. When each stud has a nut on it, the whole assembly is tensioned up to the particular flange’s specific requirements. One advantage of MATIS (or other similar systems such as BRUTUS) is that only normal bolted flanges remain at the seabed.

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TIE-INS AND SPOOLS - SUMMARY ƒ Flanges and proprietary hub systems ƒ Above-water welding ƒ Hyperbaric welding

ƒ Spoolpiece shapes and metrology ƒ Diverless connection principles ƒ Initial alignment techniques (soft land) ƒ Flexibles and rigid lines ƒ Horizontal and vertical spools

ƒ Final make-up (hard land) ƒ Collets, clamps or flanges ƒ Seal testing

Any questions? We have covered the main approaches to connecting the end of the pipeline to the riser. These are usually connected with standard flange and a swivel ring flange. However, there are certain times when the pipeline and spool are lifted and welded above-water. In some parts of the world, hyperbaric welding is undertaken by divers. In deep water, beyond the limits for divers, we have to use reliable systems. The main principles for these were listed. There are normally two stages in connecting spools: there is the initial alignment which brings the end within the reach of the tool, and the final make-up when the seal is made between the hubs or flanges. These stages are sometimes referred to as soft landing and hard landing. Ideally, the seal can be tested by the ROV prior to commissioning.

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RIGID RISERS Risers Fixed to Jacket

RIGID PIPE FIXED RISER DESIGN Pig trap

ESDV

ƒ Design as for pipeline ƒ Watch for: ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Thicker wall 5D bends Hang from top, free at base ESDV and SSIV Splash zone corrosion protection Site for pig traps, facing out to sea Fatigue due to waves and VIV

Anchor flange

Guide

Guide Space to flex down

The pipe wall thickness design for a riser is fundamentally similar to that for the pipeline in terms of meeting pressure containment, bending, and hydrostatic collapse requirements. However, there are additional aspects to watch out for: ■ The wall thickness will be higher due to the lower design factors. This is to give an increased measure of safety on pressure containment close to habitation. ■ The bends need to have a radius of at least 5 diameters in order to facilitate intelligent pigging. This can have a marked effect on the space requirements for the larger diameters. ■ The normal configuration is to hang the riser from an anchor flange and constrain it laterally using guides. It is therefore important to allow space under the base for it to flex (e.g. as it heats up), otherwise it will go into compression and this will exacerbate the bending due to wave loading. ■ The emergency shutdown valve (ESDV) will be the first fitting at the top of the riser.

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Splash zone corrosion can be problematic in that the area is wetted, exposed to oxygen but not protected by the cathodic protection system. Elastomer cladding is a typical solution. Pig traps usually face out to sea to cater for the unlikely event that they eject a pig. Riser fatigue is invariably a big issue, and we consider it in detail. Subsea isolation valves (SSIVs) are not compulsory on non-gas lines but are often installed up to 500 m (1640ft) from the jacket. They may be a ball valve for an incoming line or a non-return clapper valve for an export line.

RETROFIT RISERS ƒ Existing risers, J-tubes, guide slots ƒ Jacket member spacing for clamp supports ƒ Threading riser inside jacket legs ƒ Rails ƒ Lifting tackle

When retrofitting risers to a jacket, there are additional issues to consider. The first is whether there was any provision at the construction stage to put in spare risers, or Jtubes, or conductor slots, or riser support brackets. If so, the retrofit riser can make use of these. With no provision, the normal approach is to fit mechanical clamp/guide assemblies around jacket members, and to install the riser in sections into the guides. The picture above shows the second of three sections of the 355.6 mm (14in) Montrose riser being installed on Forties Charlie. Most of the riser ran up the outside of the jacket. The swan neck in the picture went uppermost and routed the riser inside the jacket below the splash zone. One point to note is the slenderness of the riser, and the inherent difficulties in lifting and upending without overbending it.

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J-TUBE ƒ Yields pipe twice ƒ J-tube ƒ Large diameter ƒ Large radius bends ƒ Bell mouth above seabed

ƒ Plug seal ƒ Inhibited water in annulus

Seal plug slung on clamp

A J-tube is typically a 508 mm to 762 mm (20in to 30in) tube with a 30D bend. Through this a small diameter (102 mm to 324 mm or 4in to 12in) rigid steel (or flexible) riser may be pulled up. In pulling up the J-tube, the rigid steel riser will be yielded round the bend and then yielded straight again as it is pulled in. Because the annulus between the J-tube and the riser itself cannot be easily inspected, it is common to seal the bottom end with a plug and fill the annulus with inhibited water. The photograph shows a typical sealing plug (black and yellow) slung on a lifting clamp. The picture shows a finite element analysis of a J-tube installation undertaken by Jee on the Nuggets Field Development. Not shown in the analysis is the bell mouthed orifice at the bottom end, which aids location of the riser in the J-tube.

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Steel Catenary Risers

STEEL CATENARY RISER STRESSES

Flex joint

Stress

Pipeline ≈ 20% Yield

High bending at touchdown Bending (without flex joint)

Total Stress

Bending

Weight Vessel High fatigue

Touchdown

Distance

High fatigue

The above diagram illustrates the shape of a steel catenary riser and the associated stresses. The riser is simply a steel pipe hung from the vessel to the seabed. Compared to the length of the span, the pipe stiffness is small and the behaviour of the pipe approximates to that of a chain, hence the term “catenary”. However, in practice this type of rigid riser is highly stressed/fatigued at the flex joint and at the touch down point, yet lowly stressed over the majority of its length. Firstly, let us look at the stress and fatigue characteristics of the riser. The stress pattern is a function mainly of its self-weight and bending as shown in the graph above. For the majority of the riser, the stress and fatigue levels are low. At the top, high bending stresses would result if there were a rigid connection to the vessel. Therefore a flex joint is introduced (see subsequent slide) which also serves to relieve the bending fatigue due to wave loading. At the touchdown there is a region of high bending and high fatigue. The fatigue is caused by a magnification of the vessel motions at the touchdown; i.e. if the vessel heaves a distance x, the touchdown point moves a distance many times x. Titanium pipe is sometimes used in this area (see details below).

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FLEX JOINT ƒ Flex joint allows riser to pivot at vessel Attachment flange with

ƒ Low bend moment centre-ball ƒ Typically ±5° Elastomer ƒ Solves fatigue Reinforcement problem at top

Body

ƒ Bend stiffeners Extension unsuitable for rigid risers ƒ Fatigue checks still needed along riser length ƒ VIV and touchdown

SCR FlexJoint

With flexibles, bend stiffeners are used to avoid over-bending of the riser. Steel pipes in themselves have a much greater rigidity than bend stiffeners and the length of such stiffeners is limited, so they cannot provide enough protection to rigid steel risers. Instead, rigid steel risers are typically fitted with flex joints at the vessel. This permits limited angular movement with a low bending moment. Using flex joints avoids fatigue failure at the vessel, but checks are needed that the remaining length of the riser is not over-bent. Fatigue at the touchdown point tends to dominate the design life of such risers. Careful modelling of the soil-pipe interaction is needed. In strong currents near the surface but below the wave action, vortex-induced vibration (VIV) fatigue may also be an issue.

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TOUCHDOWN POINT

Bending moment

ƒ Highest bending stresses ƒ Amplification of vessel movements ƒ Compression waves ƒ Soil interface Laydown Lift

Top vertical actuation

At the touchdown point, the vessel motions are amplified due to the shape of the catenary. Sending the touchdown point backwards and forwards over the seabed tends to form a trench. This was replicated in the tests above, and the resultant increase in force to lift the riser out of the mud is shown in the graph. Rails running 10 m (33ft) along the harbour wall allowed the trials to include lateral pullouts of the pipe. The graph shows the best technique for identifying the soil suction effect. It relies on comparing a riser lift-up with a lay-down. The lift-up will feel the suction forces, the lay-down will not. By reversing the lay-down data and placing it on top of the lift-up, the suction effects can be estimated by the difference in the curves. One particular point to watch for is the generation of compression waves in the riser if the vessel heaves faster than the riser is able to freefall through the water. This can cause buckling and/or a whiplash effect at the touchdown point.

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STEEL CATENARY RISERS INITIATION ƒ Lay from reel lay or J-lay vessel ƒ Attach buoyant or strake sections Stakes or fairings

A&R wire

Buoyant section

Pull head

A typical installation sequence for a SCR or LWSCR riser up to an FPSO is as follows: ■ The flowline installation vessel would lay the riser section as normal towards the location of the FPSO ■ For a LWSCR a buoyant section is added ■ Fairings, shrouds or stakes may be required in the upper section to combat VIV effects. ■ A standard laydown procedure would be undertaken using the A&R wire and winch attached to a temporary pull head.

RIGID STEEL CATENARY RISER CONNECT ƒ Host vessel recovers riser using winch Support vessel

Turret

Recovery wires

Pull head

FPSO (or TLP)

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When the host vessel arrives and moors, it attaches a wire to the riser end, and winches it under the turret. To avoid excessive stresses at touchdown, it is common to use an auxiliary craft to provide horizontal tension. The riser is pulled further into the FPSO and a dry connection made on the turret. (The turret allows the vessel to weather vane without twisting up the moorings and risers). Some FPSOs have the turret at the bow. In areas with a predominant current, wave and wind direction, it is not necessary to have turrets. In this case, the SCR is brought along the side. The riser configuration is then complete.

SCR RECOVERY ƒ SCR docking off platform ƒ FlexJoint ƒ Monkeyface ƒ Two pull wires

A typical docking of a side-mounted SCR of a semi-sub. An Oil States’ FlexJoint docks into the open socket. Two pullwires and a monkeyface are used to maintain sufficient touchdown tension to prevent buckling.

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Top Tensioned Risers

TENSIONED (RIGID)

Heidrun tension leg platform (TLP) with rigid risers

Tensioned risers are primarily used in conjunction with ‘floating’ facilities such as the tension leg platform illustrated, semi-submersible drill rigs and production platforms (e.g. Buchan) and drill ships. The riser response to wave and currents loads and to vortex-induced vibration (VIV) is controlled by the application of tension.

TOP TENSIONED STEEL RISER ƒ Pros ƒ TLPs and spars ƒ Bigger diameters ƒ Greater pressures and temperatures ƒ Can do localised repairs ƒ Used for drilling, completion and workover operations ƒ Production and export risers

ƒ Cons ƒ More weather sensitive ƒ Taper stress joint required ƒ Complex anchor base ƒ Host above well template

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The above slide summarises some of the benefits and problems associated with vertical tensioned steel risers. These are usually used on hosts such as TLPs and spars where the well template is immediately below the vessel. We can accommodate larger diameter lines at higher pressures and temperatures. Because the riser is vertical and under high tension, the riser is essentially in a fixed location so it is possible to undertake inspection and repairs. The same configuration can accommodate all types of operation as well as production and export. However, the response of the riser is extremely weather sensitive. The high tension needs to be resisted by additional fixity to the seabed through the casing grouted to the upper layers of soil. Moments at the base demand a taper stress joint and a complex base design.

MARS TLP ƒ Mars platform ƒ 4 pontoons ƒ Tendon on foundation piles for TLP vessel anchorages ƒ 20 wells

ƒ Risers assembled using drilling derrick ƒ Proprietary connectors ƒ Lowered and fixed to template anchorage

Derrick Deck Hull Pontoon

Well pipes Tendons 20 wells Piled bases

The Mars tension leg platform is designed for deep water drilling. It is built to withstand the winds and heavy seas of hurricanes. Mars drills wells and processes oil and gas from its own 20 wells as well as flowlines from other well clusters. In addition to the risers, there are 12 flexible tendons (3 at each corner) which move with the sea but firmly anchor each pontoon of the rig. These tendons are linked to piles in the seafloor some 900 m (2940ft) below. The Derrick is used to assemble the risers which are made up from standard lengths with proprietary connectors. Once at seabed, the taper joint is connected to the anchorage and the tension is transferred to the floor.

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Hybrid Risers

HYBRID RISERS

Buoyancy

Flexible risers

Export lines from FPSO to SPM

Rigid riser tower Control Girassol field umbilicals with hybrid risers and flowline bundles

Hybrid risers involve a combination of tensioned rigid and flexible pipe. The example above shows the rigid pipe used for the (long) vertical portion and the flexibles attaching from the top of that vertical portion in a catenary to a floating production vessel. Hybrids are seen as a potential deep water solution, where the use of flexibles is limited by the weight of the flexible being held at the top. The rigid part of the system is limited to the lower depths where the hydrodynamic loadings are low. The export monobuoy Single Point Mooring (SPM) enables visiting tankers to ‘weathervane’ around it, thus minimising wind and current forces acting on the vessel.

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GIRASSOL MULTI-RISER SOLUTION

Subsea swivels

Flexible risers

Rigid tower

Articulated joint

Girassol risers Courtesy of Acergy

An example for a more benign West African environment is the Girassol configuration above. Here a cost-effective solution is obtained by spanning most of the 1400 m (4600ft) water column with tensioned (by buoyancy) steel risers, and spanning a short step from the top of the tower to the moving vessel with flexibles. The floating production storage and offloading (FPSO) ship is used because it is more economical than a fixed platform in deeper water.

GIRASSOL MULTI-RISER TOWER Section through tower

Six X65 219 mm (8in) by 13.6 mm wall product and injection risers Four gas lift lines 559 mm (22in) core pipe X65, 25.4 mm (1in) wall Cathodic protection Insulation seals and foam Interlocking syntactic foam blocks

Riser tower assembly on beach

Two 56.8 mm (2in) by 3 mm wall super-duplex service lines Strapping Pictures courtesy of Acergy

The riser towers were assembled on the beach in the manner of the wet bundles used for the flowlines to the wellhead manifolds. They were then towed out to the field.

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There, they were pulled down to pre-prepared fixed bases. Connections at the seabed were undertaken by ROV. The flexible sections between the flotation unit at the top of the towers and the FPSO was completed using divers.

RIGID STEEL RISERS - SUMMARY ƒ Rigid steel risers slung from jacket ƒ J tube for small diameter steel pipelines and cables

ƒ Steel catenary risers (SCR) ƒ Flex joint at top – touchdown groove in seabed

ƒ Top tensioned risers using connectors ƒ Taper flex joint

ƒ Hybrids used on Girassol Project Any questions?

Traditionally, rigid steel pipe risers are slung from the platform topsides and held between guides on the jacket legs. Small flowlines may be pulled directly into a J tube. The end is sealed to prevent hidden corrosion. Steel catenary risers to floating facilities usually have a flex joint at the top, but care is needed at the touchdown point to avoid dragging the pipeline laterally out of the groove in soft sediments. Top tensioned risers are lowered from the vessel with connectors joining each section. The bottom end is subjected to high bending stress, necessitating the use of a taper flex joint at the seabed. On the Girassol project, where due to the depth of the field, it was necessary to make use of ROV connection systems at the seabed. A rigid bundle section was used from the seabed to diving depths. This is able to move slightly, but currents and wave action means that this section remains almost fixed. The riser pipes are insulated and buoyed throughout their length but have a large buoyant unit at the top. From here to the FPSO vessel, flexibles were used. They could be connected using divers and were better able to resist the wave and current action near the surface.

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FLEXIBLE RISER INSTALLATION Flexible Pipe Manufacture

WHY HAVE FLEXIBLES? ƒ The cost of materials and manufacture is more than for rigid steel lines ƒ So why use them? ƒ Capability ƒ Dynamic risers ƒ Can accommodate large movements

ƒ Cost effectiveness ƒ Rapid installation ƒ Integral risers and jumpers

Flexibles of a given diameter contain more steel than the equivalent rigid line. Due to their complexity of manufacture, they are inevitably more expensive to make than rigid lines - so why use them? As the slide indicates, the primary driver to develop flexibles was for dynamic risers which connect a static pipeline to a vessel or some other facility that is moving on the waves. Rigid lines are not capable of performing this function. Other applications for which they prove cost effective are jumpers (spoolpieces between wellheads and manifolds) or integral flowlines, where the flexible can run from the production facility all the way to the manifold or wellhead without any joins. The latter two are often cost effective due to their rapid installation. A flexible may be ten to twenty times the price of a rigid steel line but the installation vessels will be considerably cheaper. The purchase/installation cost ratio for rigid is 30%/70% whereas flexibles the ratio is reversed - 70%/30%.

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FLEXIBLES SIZE AND PRESSURE RANGE ƒ Flowline (rather than trunkline) range Working pressure for flexibles

9

600

6

400

Pressure (ksi)

Pressure (bar)

800

3

200 0 0

100 5

200

10 300

15 400

500 20

Internal diameter - bore mm (inch)

The requirement to bend conflicts with having large-diameter, high-pressure flexibles. However, as shown in the graph above, the diameter and pressure ranges for flexibles entirely cover the flowline market. Note that the diameters refer to the inside diameter of the pipe, which contrasts with rigids where the diameter is the (nominal) outside diameter. Flexibles also cover the complete range of requirements for deep water, and are being evolved to address deeper and deeper applications as such fields are developed. The largest flexibles to date are 483 mm (19in) inside diameter. One has been developed by Technip for the Bonga export pipeline.

FLEXIBLE CROSS SECTION DESIGN ƒ A number of choices affect the design: ƒ ƒ ƒ ƒ

Smooth or rough bore (gas) High pressure or low pressure Dynamic or static Normal or deep water

ƒ Incorporation of umbilical controls ƒ Small bore hydraulic and electrical lines

ƒ Insulation ƒ Comfoam tape

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Each of these subjects is considered below. The picture shows Wellstream’s gas lift umbilicals (GLUs) riser flexible. This consist of a number of individual bore, gas lift lines surrounded by the structural and protective layers. Where additional insulation is needed a foamed tape is wrapped helically around the flexible prior to the outer protective seal layer.

SMOOTH OR ROUGH BORE

SMOOTH BORE

ROUGH BORE

Plastic

Steel carcass

Smooth bore flexibles can be used on non-gas services (such as oil or water injection). Because they have a smooth plastic inner bore, they offer less resistance to flow. However, should the product contain gas or dissolved gas, it will be necessary to have a steel carcass on the inside of the plastic. Gas naturally permeates through the plastic at a low flowrate due to diffusion. Should the bore be vented, the build up of gas outside the plastic tube could have sufficient pressure to cause it to collapse, which would ruin the pipe. The carcass acts to prevent such collapse and renders the flexible a ‘rough bore’. The carcass is generally made of 316 stainless steel flat strip, which is bent and interlocked to give a layer resistant to external pressure.

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HIGH OR LOW PRESSURE

Crosswound tensile armours Zeta interlocked spiral 55° structure

Pressure loads + tensile loads

Pressure loads Tensile loads

For high pressures (i.e. most in-pipeline applications) a separate pressure vault layer is needed to withstand the pressure loads as shown in the left hand picture. For low pressures, the tensile armours can be wound at the ‘magic angle’ of 55°, which is ideal for the dual function of resisting tensile and hoop pressure loads without twisting. The angle is a result of the hoop stresses being twice that of tensile stresses when resisting internal pressures.

DYNAMIC OR STATIC

STATIC

Steel to steel contact

DYNAMIC

Anti-friction plastic tape or sheath

For risers, which are a dynamic application where the pipe is continually moving and thus the layers are continually rubbing over each other, it is necessary to have antifriction layers as shown on the right. Note that it is not possible to change from one

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structure to another without an end fitting, so if a pipe is to form a static flowline and a riser in one length, then it must all be made to a dynamic specification.

NORMAL OR DEEP WATER NORMAL

Zeta (Technip) Pressure vault

DEEPWATER

Dynamic Teta

Static Teta

Projected for very deep water Plastic sheath Carcass

For normal water depths, the Zeta layer (or equivalent layer for other manufacturers) has sufficient bending strength (EI value) to resist hydrostatic collapse. For deep water, a greater EI (or stiffness) value is needed, as offered by the Teta design (amongst others).

NKT FLEXIBLE PIPE MANUFACTURE - VIDEO

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The main points covered are: ■ Extrusion of plastic layers ■ Winding of pre-formed wire layers using ‘cable-winding’ machine as pipe is pulled through the centre of the machine ■ Storing on large reels in between processes ■ Quality control to ISO 9000

MYTHS DISPELLED ƒ ƒ ƒ ƒ ƒ

End fittings Gas permeation Hydrolysis Damage Integrity monitoring Gas released and monitored Phoenix Beattie unflanged end

Flexibles are a widely-used, high-integrity product. Here are some myths exploded: ■ End fittings have failed in the past due to extrusion of plastic layers on thermal cycling. This is now well understood. Any vulnerable fittings were recalled and replaced. Current fittings have a different design, and are sometimes baked to remove the plasticiser. This process may take over a month to complete. ■ Small amounts of gas will diffuse through the plastic layers. The gas is collected in the annulus and vented at the end fittings. A spin-off is that this provides a means of monitoring the integrity of the flexible. ■ Some plastics (nylons for example) suffer hydrolysis in the presence of water. With time, this leads them to soften and go to a mush. This is also well understood, and alternative plastics would be used in the design of flexibles subject to water in the flowstream. ■ The outer sheath can suffer damage during installation and operation. This allows water to flood into the windings where it may combine with permeating gases to corrode the windings. The windings are therefore designed to cope with this environment by using steels that are resistant to hydrogen-induced cracking and sulphide stress corrosion. ■ Integrity monitoring is necessary for flexibles, and particularly for dynamic risers. It is available through a number of inspection and monitoring routes. The approach has been set out in ISO 13628-2 (API 17J).

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Installation Analysis

FLEXIBLE RISER ANALYSIS ƒ Confirm configuration will stand all loads ƒ Final condition ƒ All stages during installation

ƒ We consider the following: ƒ ƒ ƒ ƒ

Static Dynamic Software Remedies

Having established the different riser configurations and cross-section designs, we will now look at flexible riser analysis: the computer prediction of the response of risers to wave and vessel motions. This will cover the following: ■ ■ ■ ■

Static analysis to find mean configuration and response to currents and vessel drift Dynamic analysis to find response to waves and vessel motions Software to carry out the analysis What to do if the riser is outside its capability

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STATIC ANALYSIS ƒ Inputs

Excursion

ƒ Riser weight, stiffness ƒ Buoyancy, anchors, constraints ƒ Overall geometry

Flow

Ebb Tide

ƒ Load cases ƒ Current, tide, vessel drift (3D)

ƒ Outputs ƒ Shape, including minimum bend radius ƒ Tensions ƒ Vessel and anchor loads The above slide lists the inputs, load cases and outputs for a riser static analysis. It is normal to first determine the boundary envelope for the shape of the riser considering the above input forces. Remember, that this will be in 3D rather than 2D shown above. At this stage minimum and maximum tensions, vessel and anchor loads may be found.

DYNAMIC ANALYSIS ƒ Inputs/loads as per static plus ƒ Regular or random waves ƒ Vessel response amplitude operators (RAOs) ƒ 6 degrees of freedom ƒ 6 phase angles - differ with varying frequencies

ƒ Analysis ƒ Time or frequency domain

ƒ Outputs as per static plus ƒ Motion envelopes (clashing) ƒ Compression waves ƒ Fatigue

Heave Surge

Yaw Sway

Roll Pitch Vessel motion

Dynamic analysis needs to build on the static analysis.

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It considers the full response of the vessel and riser to a regular wave train. If this analysis proves acceptable, a simulated random wave set may be used for more detailed work. Either time or frequency domain analysis may be used depending upon the power (and cost) of the computer. We can now determine whether a pair of risers are likely to clash and cause impact damage. Compression waves can be a concern. This can be likened to a whip effect, where the wave, initiated by the vessel dropping into a wave trough, travels down the flexible riser until it reaches the seabed. At this point, the riser crushes and is damaged. Fatigue of the wires in a riser can be a problem where there is an inadequate bend stiffener at the surface or the curvature of the riser at the mid-water arch or the seabed. This causes repeated bending in the wires and eventually fatigue of the riser.

SOFTWARE ƒ ƒ ƒ ƒ

Orcaflex (see www.orcina.com) Flexcom (see www.mcs-international.co.uk) ABAQUS (see www.abaqus.com) Offpipe (see www.offpipe.com)

The above software can be used for both static and dynamic riser analyses.

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ORCAFLEX DYNAMIC ANALYSIS VIDEO

The above animation shows the motions of a flexible riser passing over a mid-water arch and spanning up to a vessel. The waves not only put lateral loads on the riser, they also make the vessel and arch move.

REMEDIES ƒ Adjust inertia to drag ratio ƒ Adjust configuration ƒ Arches ƒ Anchors ƒ Buoyancy

ƒ Add bend stiffener ƒ Add bend restrictor Bend restrictor

Two bend stiffeners on flexible prior to shipping

What can be done if the riser is overbent, or clashes, or is in some other way deemed unsuitable by the static or dynamic analysis? Remedies are as follows:

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Make the pipe denser, increasing its inertia to drag ratio. This generally improves the dynamic response. If the riser is too light, it may not ‘fall’ through the water as fast as the vessel, leading to compression waves as the vessel heaves. Adjust the riser configuration to one more suited to the conditions (see previous and following slides for descriptions of configurations). If the problem is overbending at an end termination then add a bend stiffener. The picture shows two bend stiffeners. Their purpose is to support the riser as it arcs, such that it deflects over a longer length and does not lock-out or overstress at the minimum bend radius. Bend stiffeners need to be analysed carefully.

Riser Configurations and Equipment

CONFIGURATIONS ƒ Flexible riser configurations ƒ J-tube ƒ Catenary ƒ Lazy S and steep S ƒ Mid-water arch

ƒ Lazy and steep wave ƒ Distributed buoyancy

ƒ Compliant wave and S

The flexible configurations can be: ■ Within a J-tube. We examined J tubes earlier for rigid risers. But flexibles can also be brought up though one. ■ In a simple catenary. ■ In a S shape or a wave. Lazy or steep S risers use submerged arches. Waves use distributed buoyancy. The compliant S and compliant wave are variations developed by Technip for improved response to environmental forces. These configurations are given in more detail in the following slides.

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FREE HANGING CATENARY RISER

FPSO Top stiffeners prevent overbending

Protection needed against wear at touchdown

Bend stiffeners on catenary risers beneath a platform

The free hanging catenary riser is the simplest flexible riser configuration. It is only suitable for moderate environmental conditions or for set-ups with negligible heave motions such as on a Tension Leg Platform (TLP). Bend stiffeners are increasing in length. They may be up to 14 m (46 ft) long.

S RISER

Locating clamp

FPSO Top stiffeners Mid-water arch buoyancy

Arch units

Lazy-S

Steep-S Tethered clamp

Tether Clump weights

Clump base

The S-configuration riser is good for satellite tie-backs, where vertical access from FPSO to a drilling template is not necessary.

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The mid-water arch is produced by a single buoyancy unit anchored to the seabed. A number of risers can pass over a single buoyancy unit, which fixes their separation relative to each other. The configuration gives very good dynamic response but arch behaviour may restrict its use in shallow waters; that is, less than 90 m (295 ft). The steep-S configuration is particularly good for multiple riser situations where seabed space becomes restricted. The locating clamps hold the flexible centrally in the buoy. The two trumpets prevent overbending of the pipe during installation. An appreciation of the size of the mid-water arch is given by the photograph of the two men stood within the CRP unit (produced by Trelleborg).

WAVE RISER

Buoyancy mouldings

FPSO

Banding system for buoyancy

Top stiffeners Distributed buoyancy modules

Steep wave

Bottom stiffener Clump weight

Lazy wave Clamp sections for fixing to flexible

Titanium band and bolts

CRP advanced fixing system for distributed buoyancy

The lazy wave riser is good for deep water diverless installation. Dynamic response is very sensitive to cross currents due to lack of any anchoring. This riser configuration is not recommended if a large number of individual risers must be accommodated within a single anchoring sector. The steep wave configuration is good for congested seabed developments. However it is limited to single or well separated lines. The steep wave gives a very good dynamic response. When fitting the buoyancy, it is now common practice to use a GRP-epoxy clamp with Kevlar or titanium banding rather than steel clamps with long bolts (see the tethered clamp on the compliant wave). Titanium has a lower Young’s modulus and greater strength than stainless steels so permits the flexible to expand during operation whilst keeping sufficient tension to hold the clamp.

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BUOYANCY ƒ Used on flexibles and hybrid risers ƒ Similar problems to insulation foams ƒ Creep ƒ Water ingress

ƒ Attachment point ƒ stresses and heat ƒ Dual use as insulation in some cases

Installing flexible with distributed buoyancy

Buoyancy is often needed with risers. It is made from similar materials to the insulation coatings described earlier. However, special design detail is needed at the attachment point.

COMPLIANT WAVE RISER

FPSO Top stiffener Distributed buoyancy modules

Pliant wave

Tethered clamp Clump weight

ƒ Technip development ƒ Hybrid between lazy wave and steep wave ƒ Advantages of lazy wave ƒ Dynamic behaviour of steep wave Bottom tethered clamp

Technip has developed the compliant wave riser. This was used at the Foinaven development in the West of Shetland (WoS), north of Scotland.

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This hybrid combines the advantages of the lazy wave with the dynamic behaviour of the steep wave. The position of the lower tethered clamp means that the length of the flexible on the seabed can be laid in any direction.

MULTIPLE RISERS ƒ SFPS vessel ƒ Compliant wave ƒ Footprint of risers ƒ Compact at vessel ƒ Fans out ƒ Compact at wells

ƒ Easily installable ƒ Non-clash

The figure shows a semi-floating production system (SFPS). It has catenary anchor cables with multiple compliant lazy wave risers. The tails of the risers are brought together on the seabed directly beneath the vessel. In this case, work is done close to the seabed end. By fanning out, the risers can be designed not to clash with each other or the vessel’s anchor cables.

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COMPLIANT-S RISER

FPSO

ƒ Technip development ƒ Controls riser touch down behaviour ƒ Shallow waters and harsh environmental conditions

Top stiffener Mid-water arch buoyancy

Bend restrictor

Tethers Clump weight

Installing flexible with bend restrictor

CRP Linksyn restrictor units

Technip has also developed and patented the compliant S riser. This improves on the lazy-S characteristics by controlling the behaviour of the riser at the touch down point. It is very effective in shallow waters and harsh environmental conditions. The photograph shows installation of a flexible fitted with a bend restrictor. In this instance it is used to limit bending radii adjacent to an end manifold. Trelleborg manufacture the Linksyn units used for bend restrictors. Restrictors do not permit the flexible to be bent to a tighter radius than that specified.

FLEXIBLE RISER COMPARISON Riser type

Catenary

S

Wave

Pros

ƒ Simplest design and installation configuration

ƒ Very good ƒ Good for deepwater, dynamic diverless installations response ƒ Economical for small ƒ Good for risers restricted seabed ƒ Compliant wave good for space congested seabed space ƒ Good for with many fanned-out multiple riser identical risers situations

Cons

ƒ Only suitable in moderate environmental conditions ƒ Requires platforms with negligible heave (TLP or Spar)

ƒ Restricted in shallow waters by motion of arch

ƒ No anchoring, so very sensitive to crosscurrents ƒ Lazy wave unsuitable for large numbers of different diameters risers due to clashing

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The critical water depths where one option gives way to another will depend upon the environmental loadings, the response of the vessel and the number of risers (their dynamic envelopes must not clash with each other).

FLEXIBLE RISER INSTALLATION SUMMARY ƒ Unbonded layers of steel and plastics ƒ Different make-up to suit usage ƒ Consider total cost of supply and installation

ƒ Size limited by working pressure ƒ Maximum 480 mm (19in) bore

ƒ Problems with early flexibles now solved ƒ Configurations of flexible risers ƒ Simple catenary ƒ Lazy, steep or pliant S ƒ Lazy, steep or pliant wave

ƒ Analysis and equipment needed for each

Any questions? Flexible pipelines are unbonded layers of wire and plastics, each contributing to the behaviour of the whole. Different arrangements of these layers are required for the particular requirements or usage of each flexible. It is necessary to consider the total cost of supply and installation rather than just the initial cost of purchase, which is much more than for a rigid steel pipe. However, flexibles are usually limited to flowline sizes because of the strength of the various layers. We examined various problems with flexibles and how they have been solved. We have examined the shapes taken up by a number of different flexible riser configurations, plus the equipment needed for each.

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TIE-INS SPOOLS AND RISERS SUMMARY ƒ Spools and jumpers ƒ Connections methods ƒ Welding (above-water or hyperbaric) ƒ Flanges or proprietary hubs with clamps or collets

ƒ Rigid riser installation methods ƒ Fixed, J-tube, SCR, TTR and hybrid

ƒ Flexible risers ƒ Manufacture, installation and equipment

Any questions? Typical methods of installing tie-in spools and risers have been reviewed. The options for connecting the pipeline to the spoolpiece will depend on the water depth, but traditional flanges are commonly used. The risers can be either made using rigid steel pipe or flexible pipe. The method of manufacture of flexibles has been covered.

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EXPECTATION

EXPECTATION ƒ Aim to prevent incidents ƒ Loss of containment ƒ Lack of operability

ƒ Safe for people, equipment & surroundings ƒ Extend facility’s life ƒ Why a PIMS is needed ƒ What it should include

We will illustrate why a structured approach is required to integrity management and describe how we avoid accidents. We aim to keep the number of incidents to a minimum and operate the pipeline safely for as long as possible. The best way of doing this is by setting up a pipeline integrity management system (PIMS). We examine what it should include and how it should be operated.

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FAILURES : FREQUENCY AND INCIDENTS

BATHTUB CURVE

Design mistakes Construction incidents Inherent defects Wear and tear effects Lack of inspection Inadequate repairs Out-of-date or ignored procedures Operator error Stable failure rate Third-party influences

End of pipeline life Component replacement

Number of failures

ƒ Changes in failure rate through life

Life of pipeline or component

Pipelines are like any other mechanical or electrical component used in industry. Initially, there is a high rate of failure. Some of these are due to mistakes made by the designer or the interpretation by the supplier, fabricator or contractor. These inherent defects with the pipeline system have not been detected by the assessment or inspection regime. Gradually, though, the rate of failure drops to near zero, and for most of the pipeline’s life it remains reasonably stable. Events are often as a result of third party failures or damage – perhaps adjacent equipment may suffer a failure and impact on the line or fishing interaction with a pipeline. Eventually, however, the equipment wears down or corrodes away through old age. This even applies to us as our teeth fall out and joints creak. Even when the defect is found, it may not be easy or convenient to repair. When a component is replaced, unexpected changes may occur because the part is slightly different from what it has replaced. The adage, “If it ain’t broke, don’t fix it” has some truth to it.

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Another common source of failure can be traced to operating or inspection procedures and regimes not being maintained up to date. By this time, the original designer or writer of a procedure has long since disappeared and his intention may be lost. Operators tend to become slipshod in adherence, missing out steps or developing their own fix to events without referring back up for review. Below are just three incidents showing events at the three stages of the bathtub curve. We include them to make people aware of some incidents that have happened – after all, it is better to learn from others than suffer from our own mistakes.

PLUTO - PIPELINES UNDER THE OCEAN ƒ Lead-lined pipeline ƒ Second world war

ƒ Pressurised laying ƒ Hydrostatic collapse

ƒ Low through-put ƒ Increased pumping pressure (re-inflated line)

The PLUTO lines were laid during the second world war to supply petrol (gasoline) to the allied forces for the re-occupation of France. Two types of different cross-sections were used: codenamed the HAMEL and HAIS. The former was rigid steel pipe, laid using floating drums, whilst the latter was the first use of pipeline reel lay vessels. HAIS line was based on telegraph cable technology but with the inner core replaced by continuously-cast lead pipe. Trials showed that it needed to be laid whilst pressurised to offset hydrostatic collapse. The final specification of the HAIS pipeline shown above was for a flexible pipe comprising an inner lead pipe of 76 mm (3in) diameter, two layers of prepared paper tape, 1 layer of bitumen prepared cotton tape, 4 layers of mild steel tape, jute bedding, steel armour wires and an outermost layer of jute servings. However, even with internal pressure, the external hydrostatic force caused these to flatten slightly during installation. This may have been due to inadequate control of tension, resulting in greater bending at touch-down compared with what could be achieved today. Because the through-put was not initially what was expected, the operators increased the pressure trying to overcome what was thought to be more line friction than had been estimated. However, this pressure increase fortuitously had the effect of ‘re-inflating’ the lines over time and so fuel supplies were restored.

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HURRICANE GEORGES 1998 ƒ Chevron pipeline ƒ Water depth 33.5 m (110ft)

ƒ Mudslide initiated by Hurricane Georges ƒ Pipeline parted 6.1 m (20ft) below mudline

Chandeleur Islands’ lighthouse

ƒ Restart procedure not followed faithfully ƒ Leak not identified

ƒ MMS investigation ƒ OCS report 99-0053 The pictures show the Chandeleur Islands’ lighthouse before and after Hurricane Georges hit at the end of September 1998. Substantial modification to the seafloor sediments swept away the barrier islands. A crude oil pipeline operated by the Chevron Pipe Line Company in the South Pass area, Block 38 was hit by a mudslide set off by the same event. It is normal in extraordinary events such as earthquakes, floods and high winds to close down all operations. A previously planned restart incorporating inspections and tests is then followed. However, this procedure was not followed by the operators and they failed to detect that the line had parted having been covered by 6 m of heavy mud. Some 1306 m³ (8212 bbl) leaked out during restart. The Minerals Management Service (MMS) investigation concluded that the cause was a combination of the hurricane and mudslide followed by human error. “The damage to the pipeline occurred as a result of a natural hazard, specifically, a mudslide that was precipitated by Hurricane Georges in the latter part of September 1998. The pipeline was found completely parted 20 feet below the mudline. Deviations from established other-than-normal startup operating procedures contributed to the failure to identify the pipeline leak promptly.” Full details are contained in their OCS report 99-0053. A list of incidents for the USA offshore oil and gas industry can be found at the MMS website http://www.mms.gov/incidents. Other countries have similar information such as the UK’s http://www.hse.gov.uk/offshore/index.htm. In Australia, the www.workcover.vic.gov.au/vwa/home.nsf website is a good source of general construction operational health and safety (OH&S) incidents and information. By signing up to their ‘safety soapbox’, they email a weekly report on safety issues worldwide. Third party causes include many associated with shrimping nets snagging valves causing leaks, over-dredging of navigation channels, and jackup legs being dropped onto pipelines.

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GUANABARA BAY PIPELINE LEAK ƒ Increased throughput ƒ Operations over-pressured line ƒ Major environmental damage

ƒ New zig-zag for expansion ƒ Float and lowered into trench ƒ Details

Satellite image by Canadian Centre for Remote Sensing

ƒ 11 km (6.8 miles) long ƒ 457.2 mm (18in) diameter ƒ 50 mm (2in) concrete

A pipeline leads from Campos Elisios at the north of Guanabara Bay near Rio de Janeiro to the Ilha do Governador (Governor’s Island), on which the international airport is sited. The pipeline was not supplying the required throughput so the operators increased the pressure causing a rupture near the water’s edge. Guanabara Bay is an enclosed shallow water and the spill caused major environmental damage and loss of public support for the operators. The pressure had exceeded the capacity of the line towards the end of its life. The report identified thermal and pressure cycling (ratchetting) resulting in loss of steel strength capacity. This was combined with loss of wall thickness, towards the end of its life. The pipeline was decommissioned and a new one installed by the SuperPesa Group (www.superpesa.com.br). This was floated into position using pontoons and lowered into a pre-prepared trench. However, the problem of expansion was overcome by forming induction bends in each pipe-length prior to welding. Expansion buckling problems is thus avoided using this zig-zag form – each pipe-length has a preferred point of bending avoiding a build-up of moment at a single point along the pipeline. The photograph shows the line being installed over the laybarge stinger with rectangular pontoon floats.

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CAUSES OF FAILURE ƒ Failures result from mistakes ƒ Lack of knowledge transfer ƒ From designers to installers to operators

ƒ Deliberate risk taking ƒ ƒ ƒ ƒ

Cost savings Speed things up Lack of maintenance Ignoring warnings or procedures

ƒ Combination of a number of minor incidents ƒ Warning signs not heeded ƒ Ignored or lack of full understanding

It is usual that failures are caused by mistakes, and in the vast majority of instances, they can be prevented. In a lot of cases, the original intent has not been passed on completely to others in the team. With large undertakings and teams, it is not always possible for everyone to be fully aware of all the hazards. Other failures are caused by people making a conscious decision to save money or time. Maintenance is omitted or let slide, operators or third-parties (shrimpers, dredgers, jackup operators) deliberately ignore warnings or fail to carry out procedures in full. In some instances, the failure is caused by a number of smaller incidents which in themselves do not result in failure (leading people to become complacent) but when occurring together result in disaster. Perhaps there are unexpected precursor signs, which require investigation. However, the potential consequences are not fully realised, or these warnings are simply ignored.

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PREVENTION ƒ Verification of calculations and procedures ƒ Validation of software ƒ In-house and external reviews

ƒ Full traceability ƒ Design intent and purchasing

ƒ Inspection of parts ƒ Quality control

ƒ Training ƒ Maintenance of equipment ƒ Testing

ƒ Protective measures ƒ Hard (rock dump or covers) or soft (inform) What can we do about it? We need to ensure that all calculations and procedures are checked. This may be internally and where appropriate external review by an independent consultant. Computer software is becoming easier to use these days although we often have a plethora of rarely used features (bloatware). However, this has two consequences: engineers often become overconfident in its use and it is often applied to the wrong problem. It is good practice when conducting an independent check to use a different package (that you are familiar with). Every decision on the design intent and purchasing should be traceable. A similar approach should be made during construction where full records should be available of linepipe, welding equipment, welders and consumables used at each butt. Full quality control and testing (where appropriate) is required of every item on the job. It is essential that everyone should be aware of their sphere of work. This applies from designers through to operators. During the pipeline life, a maintenance regime should be adhered to, with appropriate testing of gauges and equipment. Finally, it is important that where we cannot control events, we provide protection. This may be in the form of rock dump though shipping channels, dropped object or overtrawlable covers to pipeline and valvework, or it might be providing information to fishermen or shipping in the vicinity of the pipeline.

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Monetary cost $

COST OF QUALITY

Cost of failure (direct repair, financial penalties, delays to schedule and loss of image)

Total costs

Cost of inspection, testing and evaluation 0%

Level of quality

100%

The above curve shows how as quality assurance (QA) improves the cost rises steeply as the curve approaches 100% quality. QA costs include prevention of failures by inspection and testing of material and equipment used. But it is also important to keep to the supply programme time restraints to avoid equipment hire overruns or (in the last instance) client-imposed financial penalties. If failure does occur, then fines may be imposed by government bodies. The company image will suffer a loss, which is difficult to quantify financially apart from a rise insurance levels but it will have an effect on both future clients and the public. Shell’s Brent Spar was a notorious example of when a poor public perception caused significant financial losses to a company. Although shown as a well-defined line on the above graph, it is difficult to fully assess exact failure costs. For this reason, it is shown as a dotted line. This is in contrast to QA and HSE costs, which can be reasonably accurately determined. Nevertheless, by summing the two, we can get an appreciation of the total quality costs. By aiming for the minimum point, we can optimise the benefit to the company and client in terms of profits and customer satisfaction.

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PIG TRAP INCIDENT - VIDEO

An example of how a number of apparently insignificant and minor changes to operational procedures can result in a failure is given by the above training video. The main problems are listed below: ■ Selection of a vertical loading arrangement at the design stage. This caused impact damage to the release valve and allowed corrosion of the door. ■ Poor choice of material for the trap, based on a cost saving. It was to be always exposed to the severely corrosive marine spray conditions on the open upper deck of the platform. ■ Operations placing seawater into the trap to soften the impact of the sphere on loading. This increased the corrosion problems. ■ The use of a grease to reduce corrosion and erosion at the door seal. This reduced the friction available to keep the door closed. ■ Lack of appreciation that the door was not staying shut and the belief that such doors normally need a bit of back pressure to operate. ■ Replacement of the O-ring with a larger one. This solved the immediate problem but the change was not fed back to the change committee for review. It was fortunate that no ignition source caused a tragedy. Correct selection of electrical and other equipment was the final back-up to avoid the fireball.

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FAILURES - SUMMARY ƒ Bathtub curve ƒ Example incidents at three phases of life ƒ Start of operation – design and construction flaws ƒ Low level risks – often from third parties ƒ End of life – equipment wear and tear

ƒ Causes and prevention of failure ƒ Build-up of small changes causing failure Any questions?

We have identified the different types of failure and the likelihood of them occurring throughout a pipeline life. Some examples of events have been given. We have covered why they occur and some means of prevention. The video shows how small out-of-compliances or un-documented changes to procedures can result in failure.

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PIMS

PIMS ƒ Pipeline integrity management system ƒ During operational phase

ƒ Objectives ensuring safe operation ƒ No accidents ƒ No harm to people ƒ No deterioration of environment

ƒ Integrity assurance cycle

Plan Learn

Do Measure

A PIMS document codifies good pipeline operating practice. It ensures the three objectives for safe operation to equipment, people and the environment. By following the four principle steps of the integrity assurance cycle. The final step of which is seen by some as the most important. This ensures that the loop is closed out in a report stating how well a particular operation was undertaken and what should be improved next time. A later slide expands on this cycle. That is to say, we should not just follow prepared procedures without looking for better, safer practices and noting where things could have gone wrong. Nevertheless, modifications to procedures should only be made following set management change procedures. It must be remembered that operation of pipelines – in particular, those for hydrocarbon transport – there is great potential for breaching the above objectives. They are dangerous when guidelines are not followed.

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KEY ASPECTS OF INTEGRITY ƒ Four distinct activities ƒ ƒ ƒ ƒ

Operations and safety systems Structural integrity Modifications management Flow assurance

ƒ Need to be addressed in parallel ƒ Complementary to each other ƒ Cannot be addressed in isolation

ƒ PIMS serves to manage risks ƒ Procedures, operations/contingency plans & reviews ƒ Records how risks were removed The four distinct activities listed above must be considered in a comprehensive integrity management system. These aspects should be addressed in parallel and are complementary to each other so must not be treated in isolation. We will address each on the following slides. The activities within the PIMS serve the primary purpose of managing risk. The risk management process and assessments that have been carried out in the development of the procedures, plans and reviews that form part of the PIMS are recorded and include clear statements on the assumptions made, level of risk and actions needed to mitigate the risk. The assessments address both the threats and the consequences. The risk assessment process includes periodic reviews and updates as the risk profile changes with time and experience. Records are kept of the reviews carried out, the actions taken and how the risks have been mitigated in design, construction and operation.

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OPERATIONS AND SAFETY SYSTEMS ƒ Pipeline operation ƒ Kept within designed operating envelope

ƒ Safety systems ƒ Inspected, maintained and tested ƒ Ensure safe operation ƒ Optimise performance

The operations and safety systems are concerned with ensuring the pipeline is operating within the designed operating envelope and that safety systems – for example, emergency shutdown valves (ESDVs) – are inspected maintained and tested to ensure safe operation and optimum performance. The photographs show a 323.8 mm (12in) class 900 ESDV used on an Indian gas project supplied by Hawa Valves (India) pvt ltd (www.hawavalves.com/spv.htm); and a cutaway and testing of a pressure relief valve.

STRUCTURAL INTEGRITY ƒ Monitoring, measuring and prediction ƒ Internal and external condition of pipeline

ƒ Based on actual condition ƒ Implementation of controls to maintain line ƒ Pro-active, risk-based approach

ƒ Threats to pipeline ƒ ƒ ƒ ƒ ƒ

Low cathodic protection (CP) readings Damage to coating Dents Joint failure Internal corrosion – assessment throughout life

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The structural integrity activity is concerned with the monitoring, measurement or prediction of internal and external pipeline condition, the assessment of structural integrity of the pipeline based on its actual condition, and the implementation of controls to ensure that the structural integrity is maintained. This area includes the major activities of pipeline inspection and corrosion assessment. Integrity can best be assured by taking a pro-active, risk-based approach to find and assess potential threats. Pipeline inspection is focused on monitoring and control of the external condition of the pipeline and the associated protections systems such as coatings and cathodic protection (CP). Potential threats include low CP, damaged coatings, dents and failure of joints. Corrosion is the most significant internal degradation mechanism for pipelines and needs to be assessed, monitored and controlled throughout service life. The following modules will examine how the structural integrity of the pipeline can be ensured.

MODIFICATION MANAGEMENT ƒ Changes to the network ƒ Additional tie-ins ƒ Planned servicing or replacement of equipment

ƒ Changes to throughput throughout life ƒ Outwith envelope ƒ Alteration of temperatures and pressures ƒ Line contents composition ƒ Increase in water cut later in life

ƒ Changes to operational procedures ƒ Change control committee ƒ Integrated into updated PIMS Major modifications and rectification work on the pipeline systems can pose a significant threat to the ongoing integrity of the pipeline systems if not managed and controlled in the context of the whole system. These include replacement parts or changes to throughput when these drift out of the original specification envelope. The reservoir may not behave as originally envisaged during the design. For example, a higher water cut at the end of life may result in higher than expected temperatures. These can increase problems with slugging or pipeline expansion, resulting in the risk of lateral/upheaval buckling of the pipeline or an increase in forces acting on the riser guides. When changes are made to the operational procedures, these should be carefully scrutinised by a change committee to ensure there is no increase in risk. Modifications and additions to the pipeline system have to be integrated into the PIMS.

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RISER COATING DAMAGE

The picture shows coating loss from a riser at the lower end of the splash zone. The thick neoprene corrosion coating has been scraped away by a wire. This may have been as a result of some unidentified construction activity.

FLOW ASSURANCE ƒ Provide optimum operations processing ƒ ƒ ƒ ƒ

Flow velocity Pressures Temperatures Product composition – chemical treatment/additives

ƒ Flow parameters ƒ Affect corrosion rates and internal forces ƒ Control wall loss, hydrates and wax formation ƒ Water cut, gas-oil ratio and slugging flow

ƒ Identify critical conditions – signal flag ƒ Need for good record keeping ƒ Ease of access to interrogate historical data The purpose of flow assurance is to provide the optimum operating process parameters (flow velocities, pressures, temperatures, product composition). It should also identify critical process/ flow upset conditions that may threaten integrity.

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The flow conditions have a significant influence on corrosion rates and forces produced within the pipeline, such as water cut, slugging flow, changes in temperature. These may change over the service life of the pipeline. An understanding is needed of past and present history and how conditions may change in the future.

PRISM - SPAN COMPARISON ƒ 2001 ƒ Exposure

ƒ 2002 ƒ Short span

ƒ 2003 ƒ Longer

ƒ 2004 ƒ Excessive

ƒ 2005 ƒ Rock dump An example integrity analysis package is Prism. The above typical screen dump shows output for an anonymous pipeline currently being managed by Jee Ltd. [Currently, Jee Ltd is the ‘Pipeline Competent Person’ for 600 km (373 miles) of North Sea pipelines (39 subsea lines, one umbilical and 4 landlines), defining the requirements and frequency of inspection for the PIMS.] The slide shows how a pipeline span increased in length through the years 2001 to 2004. The final picture shows the pipeline having been rock dumped. The blue line at top of each year shows lengths of exposed pipeline. Red bars just below show sections that have started to span. By clicking on the grey bars, a pictorial representation of the side scan image can be brought up. Cyan indicates sections that have been stabilised using rock dump. Other information on the plots are the distances along the pipeline (KP or chainages), red numbers above the grey bars anomaly report references, the yellow triangle (left hand side of grey bar in 2004) shows where the anomaly has exceeded the maximum allowable value, requiring remedial action.

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PLAN-DO-MEASURE-LEARN CYCLE ƒ Plan ƒ Develop operating procedures and inspection plans ƒ Hazard identification and assessment (HAZID/HAZOP)

ƒ Set reporting criteria and performance standards

ƒ Do ƒ Operation and inspection examples coming up

ƒ Measure ƒ Inspect and test equipment biennially ƒ Valve closure speed and leak (bypass) rate

ƒ Defect analysis and database

ƒ Learn ƒ Inspection experience and need for remedial works ƒ Successful operation – refine inspection plan The plan-do-measure-learn cycle is vital for good integrity management. Whether we wish to assure flow rates or to undertake regular inspection, servicing, maintenance, replacement or modification to the systems, we first have to develop the appropriate procedures and plans. This may include identification and assessment of hazards and their risks in formal HAZIDS or HAZOPS. All must be recorded as part of the PIMS for future review. We must set standards also for what criteria are deemed out of range and how such conditions should be reported if they arise. Standards of performance for each item of equipment must be set. These may be how quickly a valve closes in normal operation and in an emergency; what amount of bypass flow is deemed to be acceptable, etc. We will cover many examples of the ‘Do’ phase in later modules. Each item of plant and every operation (regular or one-off) in the procedures and plans developed earlier needs to be compared with the performance standards set down. Perhaps we need to take a valve out every two years for servicing and performance testing. Defects to the pipeline system must all be recorded in the database for future reference. This must provide an easy and rapid means of comparing how these defects have developed over time. The learn phase means that the PIMS procedures can and should be kept up to date with information whether the operation or inspection proved successful or not. It should also flag-up when remedial action is needed. If whilst undertaking the work, operators can identify ways of improving inspections or procedures then this phase may indicate the need for refinements to make the operation safer or more robust. For example, in the 2006 survey of the spanning pipeline on the previous slide, it will be possible to see whether the rock dump succeeded in eliminating the scour and exposure of the pipeline at the ends of the span.

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PERSONNEL ƒ Suitably qualified and experienced (SQEP) ƒ Need for training and familiarisation

ƒ Organogram (organisational chart) ƒ Relationships between members of team ƒ Integrity and operations support ƒ Pipeline design, inspection, corrosion, process and topsides specialists ƒ Offshore operations ƒ Superintendent responsible for assets ƒ Project team ƒ Developing operations for maintenance or inspection

ƒ Clearly defined responsibilities

ƒ Single point of overall responsibility Those operating the PIMS should be SQEP personnel with competence in their own particular field. Training or familiarisation may be needed when situations change or when new equipment is added. Regular refresher meetings provide confidence that the whole team is cognoscente with current developments and changes in procedures. To help the PIMS team operate effectively, it is recommended that an organogram clearly shows who team members are and how they communicate to each other. This is particularly so for the larger pipeline networks where personnel are frequently replaced or move to different areas. It is necessary to identify the different specialists for support, operations and projects – as shown in the suggested groupings, above. It is necessary to appoint one person as a single point of overall responsibility. In the UK, this is the ‘Pipeline Responsible Person’.

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PIMS - SUMMARY ƒ Three objectives for safe operation ƒ No accidents, no injuries, no environmental damage

ƒ Four parallel and complementary activities ƒ ƒ ƒ ƒ

Operations and safety Structural integrity Modification management Flow assurance

ƒ Integrity assurance cycle ƒ Plan-do-measure-learn

ƒ Organogram ƒ Clear roles and responsibilities for team

Any questions? A PIMS is required to ensure nothing goes wrong whilst operating the pipeline network. We need to balance the four activities which must be run together. This can be done using the integrity assurance cycle and providing clear responsibilities for each member of the team.

INTEGRITY MANAGEMENT SUMMARY ƒ Failure frequencies throughout life ƒ Bathtub curve

ƒ PIMS ƒ Means to ensure safe operation ƒ Extend the life of the facility

Any questions?

Different types of failures occur throughout the life of a pipeline. We have seen how the frequency of failure and the reasons for them can be seen using the bathtub curve.

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By setting up a PIMS, it is possible to limit incidents thus ensuring safe operation of the pipeline. The system should also aim to extend the bottom of the bathtub curve for as many years as possible.

Flow assurance

Flow assurance

427

EXPECTATION

EXPECTATION ƒ Ensure pipeline operates, and continues to operate, in the intended manner ƒ Daily, weekly and monthly operations ƒ Optimise flow throughput rate ƒ Minimise internal corrosion and erosion

ƒ Tasks to ensure safe working ƒ Maintaining flow within design envelope

ƒ Pigging ƒ Removal of water, hydrates and wax ƒ Different types of pigs and their functions

ƒ Additives to pipelines to enhance operations Flow assurance is the skill of optimising the throughput of oil and gas through the pipeline, whilst reducing as much as possible the loss of wall thickness through corrosion and erosion. This is done by injecting additives and pigging on a very frequent regular basis to remove unwanted deposits in the line. Controlling the flow in a pipeline within the safe working design envelope also helps prevent internal damage to the pipe walls. We will introduce the activities required for the safe operation of subsea pipelines. By this, we mean, work carried out on a frequent regular basis (rather than annual inspections). Some of these regular operations will involve additives to the product in order to enhance the flow. This may be done as a continuous process or in a batch. A description is given for the various types of pigs and their functions. The Inspection module covers the use of intelligent pigs.

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OPERATIONAL CONTROLS

CONTROL THROUGHPUT AND CONDITION ƒ Maintain designed flow ƒ Flow characteristics (slugging) ƒ Fluid properties (min/max temperature and pressure) ƒ Avoiding transients ƒ Whole life of pipeline (conditions at start and end)

ƒ Controlling ƒ Wax deposition or hydrate formation ƒ Viscosity or emulsions

ƒ Minimise ƒ Corrosion and erosion There are a range of conditions that must be controlled. These are particularly associated with the flow conditions and rates. As discussed later, problems can arise in the pipeline if the flow conditions are not carefully controlled. The resulting problems that may arise are due to wax or hydrates. These can block the line. If temperatures fall, the fluid may be too viscous to pump efficiently or the product mix may form inseparable emulsions. Corrosion and erosion are also controlled by the way the pipeline is operated.

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HYDRATES ƒ Methane and water compounds ƒ Resembles snow or ice in gas lines ƒ High pressure and low temperatures ƒ Forms plugs downstream of valves – hysteresis ƒ Joule-Thomson cooling Pressure bara (ksi)

120

Hydrate formation - Hyde gas (SNS)

100

1.5

Hydrates

80

1.0

60 40 No Hydrates

20 0

32 0

41 5

50 10 Temperature °C (°F)

59 15

0.5

0 68 20

Hydrates are a particular problem in multi-phase flow and wet gas flow, where water is present. They are formed under conditions of low temperature and high pressure. They are subject to hysteresis, which means that their formation depends upon the conditions they have been subjected to upstream. Hydrates have a tendency to form downstream of valves because of the Joule-Thomson cooling effect at a pressure reduction. A hydrate plug can block the line. This presents both an operational and a safety problem. The pressure differential across that plug will increase. It may then shift at high pressure and travel along the line at high velocity. It can therefore cause damage when it reaches a bend or some equipment. Control of hydrate formation is by the control of the operating pressure and temperature of the pipeline, and by injection of a hydrate inhibitor. The graph shows the safe operating zone to the right of the dotted line for the Hyde gas line in the Southern North Sea. The solid line shows the temperature of formation but it will take a higher temperature (dotted) for the hydrates to melt.

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WAX ƒ Long-chain paraffins ƒ Condenses on pipeline wall and restricts flow ƒ Keep up flow rate

Wax deposition can be a problem for oil lines. As the oil cools the long-chain paraffins in the oil can form a waxy deposit on the pipeline walls. This restricts the flow, increases the pressure drop down the line and can be very costly. Wax formation is restricted by maintaining a higher fluid temperature, which can be assisted by keeping up the flowrate.

CORROSION ƒ Corrosion inhibition ƒ Corrosion inhibitor carried in liquid phase ƒ Stratified flow - only bottom of pipe is protected ƒ Pitting corrosion in upper part of pipe becomes a problem

ƒ Water phase drop-out ƒ Low flow velocity - water drops out ƒ Water can be highly acidic ƒ Increased corrosion at bottom of pipe - tramlines ƒ Shut-downs can lead to water accumulation at low points

Gas

Oil

Brine

As corrosion inhibitor is carried in the liquid phase, we may not get adequate protection in stratified flow.

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Water drop out in stratified flow can cause localised corrosion. The water can be highly acidic, leading to rapid corrosion. At the interface between oil and the water, selective attack can lead to the formation of tramline grooves in the wall.

EROSION ƒ Multiphase flowlines ƒ Fluid contains sand and water ƒ Erosion at bends and valves - sandblasting

ƒ Oil trunk lines ƒ Cavitation collapse Weld bead

Flow Erosion

Corrosion pit Erosion

100 ƒ Erosional velocity V = 122 Ve = e ρ ρ ƒ For oil γ = 800 kg/m3 (50 lb/ft3), Ve = 4.3 m/s (14.1 ft/s)

It is perhaps easy to understand that flowlines containing multiphase fluids direct from the well may contain sand and water, in addition to the oil and gas. This can result in a sandblasting effect on the pipe wall, causing erosion of the steel as the flow changes direction at bends. However, erosion can also occur in oil trunk lines to shore, where there are no abrasive elements in the flow. If the velocity of oil itself is too great, then any small bump or cavity in the wall may cause cavitation bubbles to form. When the bubbles collapse or implode, the resulting shockwaves can also erode the wall. This effect is often seen downstream of field weld, where the bead or root protrudes out of the boundary layer of fluid attached to the wall, causing disruption to the flow. The photograph shows the effect of a field weld root bead and the lines of erosion it causes downstream. API RP 14E gives the above formula for the velocity at which erosion may start to occur. Where: ■ Ve = erosional velocity ■ ρ = density of fluid Different formula are needed for SI and metric because of the units in the numerator constant. Where corrosion has left a pit, then this can also disrupt the flow and erode the wall on the downstream side, increasing the length of the defect.

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TURN-DOWN – OPERATIONAL ENVELOPE ƒ Reservoir becomes depleted ƒ Flow parameters change throughout life ƒ Water cut increases ƒ Temperature in gas lines may increase ƒ Axial expansive forces – at end or uplift/lateral buckling

ƒ Temperature in oil lines may decrease ƒ Insulation designed for end of life – may have crushed ƒ Wax problems – more frequent pigging

ƒ Flow rates decrease – colder delivery ƒ Gas/oil ratio alters

ƒ Operational changes ƒ Chemical additives may be alter ƒ Water and gas injection Because we are abstracting oil and gas from the reservoir, the flow parameters through the pipeline will alter throughout life. With a gas field, the amount of water may increase. This water is often hot, and as these slugs pass through the pipeline, the expansion along the pipeline may increase – this could cause uplift or lateral buckling problems where there was no risk of this before. In oil lines, the temperatures tend to decrease over time causing waxing which may require more frequent pigging. In general, flow rates will decrease causing additional cooling along the length of the pipeline. For mixed lines, the ratio of gas to oil may alter. This is dependent on the depth of the oil well within the reservoir. Operationally, the chemicals added to the line may alter or the method of assisting recovery by injection of water or gas. It is necessary to account for all of these changes whilst maintaining the line within the operational envelope.

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OPERATIONAL CONTROLS SUMMARY ƒ Maintain flow within envelope ƒ Temperature and pressure

ƒ Deleterious effects ƒ ƒ ƒ ƒ

Slugs, surge Wax, hydrate blockages Increased viscosity, emulsions Corrosion, erosion

ƒ Turn-down ƒ Methods to maintain flow within envelope

Any questions? We have looked at what we mean by routine operations. They are the means of ensuring that the flow is maintained within the design envelope. This generally means controlling the temperature and pressure in the line. If the product strays out of this, then some of the effects may be the formation of slugs or pressure surges. We have looked at some of the effects when temperatures fall - such as the formation of wax and hydrates, the increase in friction due to high viscosity or formation of emulsions, which cannot be separated. The pipeline itself can be affected by corrosion and erosion.

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ADDITIVES

ADDITIVE APPLICATION ƒ Continuous ƒ Hydrate inhibitor ƒ Corrosion inhibitor ƒ Erosion/corrosion control ƒ Wax suppressants ƒ Drag reducing agents ƒ Biocide

ƒ Batching ƒ Corrosion inhibitor ƒ Periodic coating of pipe wall (say 3 monthly) ƒ Used in wet gas lines or from unmanned minimum facilities ƒ Gives good covering over all of wall

ƒ Methods ƒ Introduce slug of additive between pigs ƒ Spray pig

A range of chemicals can be added to the flow as part of the pipeline operation. There are two main methods of introducing additives to the pipeline - continuous injection and batching. Continuous injection involves, as the name implies, the continuous pumping of an additive into the product stream. The types of additive commonly used in this way are listed above. The alternative means of introducing additives to the pipeline is to periodically send slugs of additive into the line between pigs. This method is used for corrosion inhibitors only because they are able to coat the pipe wall rather than modify the behaviour of the fluid.

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BATCH INJECTION OF INHIBITOR SLUG ƒ Logistics ƒ Inhibitor and carrier fluid ƒ Pigs, launchers, storage tanks and pumps ƒ Personnel

ƒ Supply of carrier fluid (diesel) ƒ Disrupt normal operations ƒ Receiving slug ƒ Ensure large enough separator and slug catcher Leading pig

Slug of carrier fluid and corrosion inhibitor

Trail pig

For batch injection of corrosion inhibitor, there are a number of requirements. These include the pigs to contain the slug of inhibitor, the pumps and personnel to carry out the work. The supply of the carrier fluid to the end of the pipeline must be considered. This contrasts sharply with the automatic continuous injection method where only the inhibitor itself is needed. Normal product delivery operations must be disrupted during the batch treatment process. The slug must be caught at the far end of the pipeline and the carrier fluid decanted out from the product.

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INHIBITOR SPRAY PIG ƒ Inhibitor carried within pig ƒ Sprayed onto walls at pressure ƒ Proprietary system ƒ Therefore not ‘off-the-shelf’

The alternative method of batch inhibiting is the use of the inhibitor spray pig. This is a proprietary product and would have to be designed and built for a specific application.

ADDITIVES - SUMMARY ƒ Additives used to improve flow and reduce corrosion ƒ Inject continuously or in batch for corrosion Any questions?

We can introduce additives into the pipeline to improve the flow characteristics and reduce the possibility of corrosion. To improve flow, additives can reduce drag and suppress wax formation. To reduce corrosion, there are inhibiting chemicals. The injection of additives can be either a continuous process or anti-corrosion agents can be delivered in batched slugs.

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PIGGING

WHAT ARE PIGS? ƒ Pigs are devices driven by the pipeline fluid ƒ Low differential pressure ƒ Bleeding past rubbers ƒ Surge and stopping in gas lines

ƒ Bypass used to slow passage Metal or plastic body

Bypass

Pipe wall

Flow

Suspension rubber cups

Pigs are devices driven through the pipeline by the pipeline fluid. They come in all shapes and sizes and perform a number of functions, as explained below. In essence, they contain the components shown in the diagram above. There are cups to seal against the pipeline wall, giving the device its driving force, and a body upon which the cups are mounted, which contains brushes, gauge plates or other devices that give the pig its function. Only a small pressure differential is usually needed to propel a simple pig, around 0.5 bar (0.75 psi), depending on the diameter and condition of the line. Normally there is some bleeding of the line contents past the rubber disks in either direction as they deform to follow the contours of the wall. In gas lines, pigs will tend to repeatedly surge forward and stop if not carefully controlled. Some pigs are built with a bypass tube to slow them down and flush debris out within the upstream product.

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PIG LAUNCHER

Door

Vent valve D and gauge

Mainline trap valve B

Pig signaller

Pig Trap kicker valve C

Flow Mainline bypass valve A

Flow

Launch tray

Under normal operation, valves A, B and C are left open and the pig launcher door is kept closed. When a pig is to be launched, the valves B and C are closed and the vent valve D is used to release gas pressure. The door is opened and the pig pushed into the trap. Valve D is shut again. The door resealed and valve C cracked open again until the trap pressure equalises with that of the pipeline. Valve C is closed and valve B opened. The pig can be launched by opening valve C again and then gradually closing valve A. A pig signaller indicates passage of the pig. Once the pig is in the main pipeline, valves A, B and C are fully opened again for normal operation. For pig receipt, a similar unit is used except that the pig signaller is on the other side of valve B to indicate that the pig has been caught. The photographs show a typical landline pig launcher and a subsea unit supplied by Pipeline Engineering (www.pipelineengineering.co.uk) to installation contractor Subsea 7. This operates at a depth of 130 m (426ft) in Esso’s Jotun field in the North Sea (Norwegian sector). It is a 150 mm by 250 mm (6in by 10in) subsea class 1500 vertical pig launcher with receiver facilities. The unit can launch or receive both conventional and intelligent pigs. It has full subsea capabilities including a soft landing system and ROV operations compatibility. The unit consists of three sections: a manifold interface, the protection head and pig launcher. The manifold section is bolted to the subsea manifold and includes three pedestals for the Soft Landing System. When the launcher/receiver is not in use, the protection head is used to protect the manifold from damage and corrosion. It is fitted with hydraulic quick connect/disconnect collett connectors and a control panel to allow removal and connection of the head by ROV. The pig launcher assembly, which is kept either onshore or on the barge until required, is fitted with three pig release fingers and three baskets capable of launching and receiving three conventional pigs or one intelligent pig respectively. The pig launcher and receiver is designed in accordance with PD 5500, permanent pipework to Det Norske Veritas (DNV), and the launcher/receiver structure to DNV and NORSOK.

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JOBS DONE BY PIGS ƒ ƒ ƒ ƒ

Cleaning wax and solids Sweeping out liquids Corrosion inhibition Proving bore is clear Pig designed for very fine cleaning of aviation fuel line Note use of sailcloth disks between wire bristles

Most pipelines are pigged at least occasionally, if not routinely, for the reasons listed on the slide above. ■

Cleaning out waxes and solids may be necessary on an oil pipeline where wax is deposited on the wall. Deposition of wax can dramatically increase the pressure drop necessary to get the flow through the pipeline. Where it is not possible to insulate the pipeline sufficiently to avoid wax deposition, regular pigging to remove the wax is often the solution. This would apply particularly to oil trunk lines.

■

Sweeping out liquids tends to be done by spheres. These are usually polyurethane balls pressurised with glycol to a diameter a few percent above the pipeline internal diameter. Taking a gas trunk line as an example, it might accumulate condensates that would need to be swept out on a regular basis. This would keep the level of liquids in the line under control and would avoid the occasional arrival of a very large slug of liquids at the terminal, an event that might cause process problems.

■

Corrosion inhibitor pigs can be used to introduce a slug of inhibitor into a line with the objective of coating the entire pipeline inside wall with corrosion inhibitor.

■

Proving the bore is clear is carried out during hydrotesting at the pre-commissioning stage. It may also be used when a dent is suspected.

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SPHERES ƒ ƒ ƒ ƒ

Solid (smaller diameters) or inflated Sweeping liquids from lines Spreads inhibitor onto wall circumference Automatic launch for frequent basis

Spheres are frequently used in wet gas and multi-phase lines on a regular basis. This might even be more frequent than once a day. They are used to sweep liquids from lines to prevent build up of slugs. They can spread a corrosion inhibitor around the full circumference of the wall to prevent it collecting at the bottom of the pipe. Some platforms have an automatic launch system with a cartridge containing half a dozen spheres. These can be individually launched with little or no manual input. They are usually slightly oversized (2%) to give good seal with inside bore of pipe.

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FOAM PIGS ƒ Polyurethane foam body ƒ Usually polyurethane coated ƒ May incorporate ribs or brush bands Picture courtesy PII Kershaw

Foam pigs are generally bullet-shaped, moulded from open cell polyurethane foam and usually with an external PU coating. They come in a variety of shapes, sizes and colours. They have no independent sealing elements but are compressed axially by the pressure differential, which gives sufficient radial expansion to form a seal between the pig body and pipe wall.

FOAM PIGS ƒ ƒ ƒ ƒ ƒ

Sweeping liquids and solids Light cleaning duties Flexible but not too durable Can get heavy duty versions If stuck, can sometimes be broken up with increased pressure – but don’t rely on it !

Foam pigs are a general-purpose but lightweight pig suitable for sweeping liquids and solids from a pipeline. Specific applications can be ‘built-in’ at the moulding stage where

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gritted bands, brushes, jetting holes, magnet inserts (for tracking) or studs (for fixing of gauge plates or scrapers) can be added. They have the advantage of being tolerant of tight bends and bore restrictions. They will also break-up if they become stuck. This makes them useful for an initial pig run prior to a more robust brush or scraper pig being used. Their disadvantage is that they wear out quickly, although heavy duty versions exist for single pass usage on long lines.

BATCH PIGS ƒ Sweeping liquids from lines ƒ Inhibitor batching ƒ Sweeping spheres and pigs entering from side branches ƒ Gel pigging ƒ Multiphase lines ƒ Sand gathered into gel

Batch pigs can be solid molded or metal bodied. Metal bodied pigs utilise polyurethane or rubber seal discs or cups. The material selection is dependent on the specific application. Metal bodied pigs offer the ability to add a range of attachments that may be used to perform a range of functions. They are commonly used for removal of liquids and inserting a batch slug of corrosion inhibitor. If smaller diameter spheres or pigs have been used to clean a smaller diameter branch pipeline, once it enters the main line the larger bore means that there is no differential pressure to move it. A batch pig can be sent down the main line to sweep it up. Gel pigging may be carried out to de-sand a multiphase line. The gel picks up solid debris and removes it from the line. The gel also lubricates the pig and gives improved drive.

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BRUSH PIGS ƒ Removal of solid debris and wax ƒ Bypass ports ƒ Jet of fluid ƒ Debris suspended in front ƒ Swept out ƒ Slows pig

Brush pigs are used for cleaning the bore. By-pass ports are used to produce flow in front of the pig. This flow helps prevent the build-up of debris or wax in-front of the pig. By-pass ports are typically threaded holes with plugs. The operator can therefore adjust how much by-pass occurs prior to entry.

SCRAPER PIGS ƒ Polyurethane or steel blades or ploughs ƒ Wax removal

Scraper pigs are used for the removal of wax deposits from the pipe wall.

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The spring joint at the middle of this example helps it negotiate tight bends.

SPECIALIST PIGS ƒ Pin-wheel pig ƒ Magnetic cleaning pig

Picture courtesy PII Kershaw

In addition to the basic cleaning and sweeping operations, pig bodies can be configured for specialist functions. The picture above shows a magnetic cleaning pig in use in Germany, where magnets have been mounted on the body of the pig and have pulled a veritable bird’s nest of welding rods from the pipeline. Note also the bi-directional sealing discs on the pig and a gauging disc, which can just be seen behind the welding rods. Approximately 3000 rods were extracted on the first passage of the pig. This dropped to 1000 rods at the next pass and down to zero after five runs. These are only two examples of specialist pigs. You can imagine the myriad of shapes, sizes and functions that have been adapted over the years.

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A CAUTIONARY TALE ƒ Slug formation uphill Direction of flow Slugs formed up-hill High head loss

Dribbling over crest No recovery of head

ƒ Small pig for first run but is lost in system ƒ Big pig purges slugs but gets stuck ¾ along ƒ Splashes into condensate and water puddles ƒ Formation of hydrate plug

ƒ Pressure differential melts hydrates ƒ Pig surges forward - almost hits end of pipe Trevor Jee was approached to resolve a problem with an infield line that was normally pigged on a regular monthly basis. A pig had become stuck in the launcher and it was decided to suspend pigging for a number of months. In the meantime, the pressure needed to maintain flow rose more than tenfold. The reason for this was traced to the undulating nature of the pipeline: the high pressure loss was due to slugs of product which needed to be forced uphill. On the downhill slope, the liquid dribbled over the crests of the hills and very little pressure head was recovered. The system pressure was brought down and the stuck pig removed from the launcher. When the operations were resumed, it was decided to use a smaller than normal pig for the first run. This got lost in the system as the gas flowed past the pig. The full size pig which followed had the effect of removing some of the slugs, but puddles of condensate overlying water had formed in a hollow. As the pig hit these, a spray of water and condensate splashed out and formed a hydrate plug. This effectively blocked the passage of the pig about three-quarters of the way down the length of the pipeline. The pressure behind the pig was increased to 90 bar (1300 psi) and that in front of the pig was gradually reduced by bleeding off. When the differential reached 50 bar (725 psi), the hydrates became unstable and melted. This occurred just as Trevor arrived on site. The pig surged forward and backward like a spring until the pressures equalised on either side. When their calculations were checked, even though the volume of the pig catcher had been forgotten, there was just enough distance to prevent the pig hitting the end of the line.

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PIGGING - SUMMARY ƒ Pigs and spheres are devices driven by fluid ƒ They carry out ƒ ƒ ƒ ƒ

Cleaning Gauging Batching and Specialist functions

ƒ May be used daily, weekly or monthly ƒ Cost-benefit analysis

Any questions? Pigs are small components that are driven through the pipeline by the flow of the fluid. They can perform a wide range of activities to ensure the correct operation of the pipeline, these activities are summarised above. For routine operations, these may be used very frequently. The exact frequency of use will be determined by a cost-benefit analysis.

FLOW ASSURANCE - SUMMARY ƒ Operations ƒ Maintain temperature and pressure within envelope

ƒ Chemical injection ƒ Wax, hydrate and corrosion control ƒ Improved flow rate ƒ Continuous or batch

ƒ Pigging Any questions?

We have introduced routine operations to maintain the pipeline flow within the designed envelope.

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Some improvement to the regime can be achieved by adding corrosion inhibtors or other chemicals to prevent the formation of wax or hydrates. Most routine operations are undertaken using pigs or spheres.

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EXPECTATION

EXPECTATION ƒ Understand the need for and basis of pipeline inspections ƒ Know the methods used for internal and external inspection ƒ Know what anomalies to look for in routine inspections and maintenance ƒ Discuss methods of assessing anomalies ƒ Know the methods available to correct the anomalies that are found

We will introduce the activities required for the operation of subsea pipelines. The first requirement is to understand the inspections that are carried out. Why do we do them and how do we decide what to look for? Various methods of conducting internal and external inspections of pipelines are examined. A description is given for the various types of anomalies that may be found during an inspection. An overview is given for the methods of assessing the various different anomalies and finally the methods of correcting those anomalies are discussed.

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RISK-BASED INSPECTION PLAN

WHY INSPECT DURING OPERATION? ƒ Damage ƒ Debris ƒ Anode removal or early wastage ƒ Exposure ƒ Spans ƒ Leaks ƒ Rock cover

Under ‘Installation’, we mentioned that surveys were carried out to characterise the seabed, and that further surveys were required during operation. These typically look for anything that may have gone wrong with the pipeline: ■ Damage – impact from trawler activity or objects dropped from platforms or supply boats ■ Debris – near to or draped over the pipeline (large boulders are dragged and lifted by trawlers) ■ Anode wastage – usually anodes are knocked off by fishing but they can be ablated away following coating damage ■ Exposure of a previously buried line ■ Spans – scour of soil from beneath the pipeline ■ Leaks – usually from flanges ■ Loss of rock cover

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HOW OFTEN TO INSPECT ƒ Of old (1970-90) once a year by ROV ƒ Now, responsibility of Operator ƒ Inspection plan

There is a variety of techniques to survey the pipeline, and the operator is also presented with a choice of when it is necessary to survey. In the prescriptive regime of the 1980s, an annual survey of the entire length of the pipe was required. In the goal-setting regime of today, in UK waters, it is the responsibility of the operator to determine a safe inspection interval as part of his inspection plan. The result of this is that most inspections in the early part of the pipeline life are carried out annually, and they are then spaced further apart if the results are benign.

INSPECTION PLAN

Identify risks Write an inspection plan Inspect pipeline and report Interpret results

Decide what to fix

Decide when next to inspect and scope of inspection

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The flowchart above shows the processes involved in pipeline integrity management. It is an iterative process in which the results of inspections are fed back in to the inspection plan and future inspections modified accordingly.

RISK-BASED INSPECTIONS ƒ Hazards identified ƒ Inspections targeted according to ƒ risk (probability x consequence) ƒ value of inspection

Not worth inspecting for

Consequence of failure

Highest value of inspection

Probability of failure

n tio y c e l it sp i ca n I it cr

Risk-based inspections use probabilities, consequences and the usefulness of inspections to arrive at a suitable inspection regime. The various hazards facing the pipeline are identified and the risk is evaluated. The value of inspecting is then assessed for that particular hazard. For example, inspection can tell you if a span is developing to an unacceptable length, but it cannot tell you if somebody is going to drop an anchor on your pipeline. All this data is used to give an overall value for the inspection, and the inspections can be prioritised accordingly.

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RISK-BASED INSPECTION PLAN SUMMARY ƒ Range of hazards and anomalies ƒ Variety of inspection techniques available ƒ Inspections driven by risk and value Any questions?

A subsea pipeline faces many hazards during its lifetime. Inspections must be done to ensure that the pipeline continues to operate safely. Several tools are available to externally inspect the pipeline. The external inspection strategy will be driven by an assessment of the risks due to the anomalies and the usefulness of the chosen inspection technique in countering those risks. The inspection plan will evolve over the life of the pipeline using feedback from the results of the inspections.

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EXTERNAL SURVEY

EXTERNAL INSPECTION METHODS ƒ Initially, side-scan sonar, ROTV or AUVs ƒ Rapid review of pipeline route ƒ Spans and exposure

ƒ ROV ƒ Slower investigation work of defects already uncovered ƒ CP system

ƒ Diver ƒ Shallow water investigations at landfalls and risers The year-to-year maintenance of the pipeline involves external inspection surveys followed by remedial works to correct any problem areas. The pipeline may be surveyed by side-scan sonar, remotely operated towed vehicles (ROTVs) held some 20 m (66ft) above the seabed, or autonomous underwater vehicles AUVs. ROTVs can view at an angle of 30° from the horizontal, so this height will cover the pipeline and the immediate adjacent area. The initial surveys may be carried out by ROV (as shown in the picture), especially if detailed information is needed. However, side scan sonar is far more common for the routine survey of pipelines. AUVs are more suitable for inspection of long lengths of major trunk lines Modern side scan sonar is quite capable of picking up any physical objects of concern to the pipeline and of estimating span heights and lengths. Being considerably faster (perhaps by as much as a factor of 10), and therefore lower cost, it is in widespread use.

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However, ROVs do have some specialist advantages: ■ They are able to carry pipe detectors, as shown in the picture, which will detect buried pipelines and will determine the level of rock dump on top of them. ■ They can take cathodic protection measurements. ■ They can make a thorough investigation of spans, both in terms of touchdown point and vibration characteristics. These measurements can resolve whether or not it is truly necessary to take remedial action on a span. Divers are limited to shallow water investigation work where ROVs are unable to operate due to cavitation of their thrusters.

SIDESCAN SONAR ƒ Towed fish or ship mounted ƒ Monitor pipeline profile, spans, burial, seabed features, lateral buckling Track of vessel Exposure due to scour 172 m (564ft)

Pipeline span

Sidescan sonar techniques use a towed fish such as that shown in the picture above. They are based on sonar, whereby the device emits a sound pulse and listens for the echo. It interprets the strength, time and direction of the echo to give a picture of the pipeline and seabed in sufficient detail to gauge pipeline features such as embedment and spans. Seabed features can be distinguished such as sand waves, debris, trawl scars, etc. The sonar printout is from an integrity management contract currently being undertaken at Jee Ltd. The seabed mega-ripples are indicative of a mobile sandy bottom and the exposed section of pipeline is clearly visible together with the region either side of the span where the mega-ripple pattern has been disrupted by scour. The shadow at the centre shows where scour has developed sufficiently to cause an unsupported length of pipeline to span freely. This may be further investigated by ROV to determine the support end points.

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ROV VISUAL SURVEY

Typical screen shots from an ROV survey show disrupted weight coating at an anode beneath substantial marine growth. The second view is of a spanning pipeline at a field joint. Both screens show the date and position (Eastings and Northings) and chainage along the pipeline with essential other ROV camera view data.

EXTERNAL INSPECTION - SUMMARY ƒ Initial pass - side-scan sonar, ROTV or AUV ƒ Further investigation by ROV or diver ƒ Exact length of span requires closer inspection

ƒ Each technology has pros and cons Any questions?

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The external inspection of the pipeline can be carried out using the following technologies: ■ Side-scan sonar ■ ROTV ■ AUV ■ ROV ■ Diver Side-scan sonar using fish or ROTV is the cheapest and fastest method but cannot pick up fine details – especially those beneath the pipe. ROV is a more flexible method than side scan sonar, and the ROV can carry a range of extra instrumentation. AUVs are a relatively new technology but much development is going on. They are potentially the most flexible method of all.

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INTERNAL INSPECTION

WHAT IS INTELLIGENT PIGGING? ƒ Internal survey for corrosion and cracks ƒ Typically every 5 or 10 years

In addition to external inspection, there are internal inspection techniques available for pipelines. These range from the simple gauge plate check for dents and debris, through to sophisticated pig checks for cracks and corrosion. In this section, we will look at three types of intelligent pigs - the magnetic flux, ultrasonic and eddy current pigs, describing their function and their uses. Before an intelligent pig is sent down the line, a full pig cleaning operation would normally be carried out to ensure the intelligent pig remains undamaged and that the data obtained from the pig run is the highest quality possible.

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INSPECTION TECHNOLOGIES ƒ Magnetic flux leakage ƒ Ultrasonic thickness ƒ Eddy current for flexibles

There are two main technologies: magnetic flux leakage (MFL) and ultrasonic thickness measurement (UT). Each has started by finding wall thickness loss (general corrosion defects, both inside and outside), and has then been rotated into the hoop direction to find axial cracks. A final technology, that of eddy current, is being developed for the inspection of flexibles. The following slides contain examples of each of these pigs.

MAGPIE - VIDEO

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The Magpie tool is inserted into the pipeline using pigtrap launchers and is propelled along the inspection route by the pressurised oil or gas. The tool uses magnetic flux leakage (MFL) to detect defects in the pipe wall and a digital signal processing data logger to record up to 1000 pieces of data per second. Above-ground sensors use Bluetooth to track the position of the tool before logging the information using GPS. On retrieval from the pipeline, the data is uploaded from the tool and then sent to the lab for processing and interpretation.

MAGNETIC FLUX PIGS

The picture above shows the PII magnetic flux pig. In the picture you can see the magnetic brushes and the finger-like arrays of magnetic flux detectors. The rest of the pig contains power and data storage facilities. It is used to detect internal and external corrosion defects in oil and gas pipelines. Variants are available to detect both axiallyoriented and hoopwise-oriented cracks. Typical speeds of intelligent pigs are from 0.3 to 5 m/s (1ft/s to 16 ft/s). If the product flow is faster than this, it is normal to include a bypass system to permit the pig to travel slower than the oil. Head losses for pigs are typically less than 1 bar (15 psi).

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FLUX LEAKAGE DETECTION No defect present Brush

Brush

Sensor

N Magnet

Magnet S

PIPEWALL SECTION

Defect present

DEFECT

Brush

Brush

Sensor

N Magnet

Magnet S

LEAKAGE FIELD

The above diagram illustrates how the pig detects corrosion defects. In the noncorroded condition, the two brushes form a magnetic circuit and the flux passes through the pipeline wall with little passing either side. However, in the lower diagram with the defect present, there is less metal through which the flux can pass, and some of it leaks outside the pipe wall and is detected by the sensor.

PRESENTATION OF DATA ASSESSMENT

Reported peak depth as %ge of wall

Simplified RSTRENG and ANSI/ASME B31.G assessment of the internal corrosion located in 8.74 mm (0.344in) wall thickness pipe

4

8

12

16

20

Reported axial length mm (in)

24

28

32

Courtesy of PII Group

The above diagram shows an example of results obtained from an MFL pig. It shows over 450 000 internal metal loss features, and there were also over 3500 external metal loss features identified. This analysis looks for any defects where the dimensions exceed those tolerable at 1.5 x MAOP, or where the peak depth exceeds 80%.

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In this case there were 19 defects identified as possibly needing repair. A detailed assessment was also carried out in each case, measuring the effective depth and length of the defect, which reduced the number of defects requiring repair down to just one.

ULTRASONIC PIG

The ultrasonic pig is used to detect corrosion defects in liquid lines. The liquid is crucial in acting as a couplant for the sound emitted by the ultrasonic probes. For these pigs to function in a gas line, they must be run within a slug of liquid. Alternatively pigs are available that use wheels running along the pipe wall to transmit the ultrasonic vibrations into the pipe wall. More modern ultrasonic pigs are also able to detect cracks of may different orientations in the pipe wall, including longitudinal cracks.

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PRINCIPLE OF OPERATION ƒ Sound waves transmitted into pipe wall ƒ Echos from front and back of pipe wall picked up by detector Transmitter Requires liquid couplant

Pipeline inner wall Lamination Pipeline outer wall

The probes on the ultrasonic pig work in exactly the same way as hand held ultrasonic thickness probes. They emit a sound wave and detect the front and back pulses reflected from the specimen. By calibrating the speed of sound in the pipe steel (using a sample of known thickness), it is possible to interpret the sound time delay in terms of metal thickness. It is also possible to interpret, from the time of the first reflection, whether the corrosion defect is on the inside or the outside of the pipe wall.

EXAMPLE ULTRASONIC PIG OUTPUT ƒ More intuitive output ƒ Colour-coded depths Corrosion at helical weld

Normal (no defect)

Plate inclusions

Acid attack pitting

The output from the ultrasonic pig is a pixellated scan of the entire internal surface of the pipe.

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In the picture above, any normal reading has been colour-coded white and corrosion defects given a colour code depending on their depth. One can see on the left-hand side a spiral weld with preferential corrosion. Across the middle of the scan, there are some corrosion pits characteristic of acid attack and one can also see some red inclusions running parallel to the plate-rolling direction. The output of the ultrasonic pig is far more intuitive than the magnetic flux pig and a general picture of the state of the pipeline can be obtained rapidly at the end of the pig run.

OTHER PIGS ƒ ƒ ƒ ƒ ƒ ƒ

Gyroscopic pig Leak detection pig Neutron scatter pig Camera and tethered inspection Crawlers Wax and scale assessment

A variety of other pigs have been developed for pipeline inspections. Gyroscopic pigs can be used to survey a pipelines shape and can also detect spans by the vibration of the pipeline as the pig passes through the pipeline span. Leaks can be detected by mounting sound detectors on a pig and listening for characteristic sounds of fluid leaking. Neutron scatter pigs were developed to detect whether the pipeline was buried or spanning and have largely been superseded by side scan sonar surveys. It is possible to survey the sections of pipeline close to the pig trap using tethered pigs. Crawler pigs use on-board power to propel themselves against the fluid flow. Their range is limited by the availability of on-board power. There is also a range of crawler pigs that can be introduced at the landfall end of a subsea pipeline and crawl up to 12 km (7½mile) inside the line, towing an umbilical to give an on-site evaluation of the line’s condition. Pigs have also been developed to measure the wax and scale coating the inside of a pipeline.

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EDDY CURRENT PIG FOR FLEXIBLES

Flexible pipes present a different set of inspection requirements. The primary mode of failure for which it is necessary to inspect is that of cracks in the hoop and armour windings (rather than corrosion defects). The eddy current pig, pictured above, is being developed to detect such cracks. It functions by inducing an eddy current in the windings and detecting the difference in the resulting electromagnetic field caused by a crack.

EDDY CURRENT MEASUREMENT ƒ Detect defects in metallic layers

The above picture is an output from the device showing a crack in one of the armour wires.

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INTEGRITY OF FLEXIBLE RISERS ƒ Flexibles external inspection ƒ Similar to rigid pipe plus additional monitoring

Vent gas monitor on flange

ƒ Polymer coupons ƒ Removed from port for testing

ƒ Vent gas monitoring ƒ Continuous automatic testing

ƒ Fibre optic cables ƒ Laid within the armour layers ƒ Continuous length assessment

Flexibles can be externally inspected but the scope for internal inspection is limited. The integrity of the flexible riser liner can be monitored using coupons or vent gas monitoring. Coupons are small samples of liner sitting within the flow of oil or gas that can be removed during inspections for testing. The condition of the polymer liners in flexibles can be assessed by monitoring of the gas that diffuses into the windings layers. This photograph illustrates the vent gas monitoring system. The flexible pipe manufacturers are developing fibre optic cable systems that are laid into the armour windings. These can monitor any potentially damaging stretching of the armour wires.

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INTERNAL INSPECTION - SUMMARY ƒ Comprehensive internal survey of steel pipelines for corrosion and crack detection ƒ Two main technologies, two orientations ƒ Pigs available for other tasks ƒ Flexible inspection under development Any questions?

Intelligent pigs enable comprehensive internal inspections of the pipeline to check for corrosion or cracks in the pipe wall. There are two main technologies used by intelligent pigs for internal inspections, these are magnetic flux leakage (MFL)and ultrasonic thickness (UT). A third technology of eddy currents is under development to enable the inspection of flexibles.

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ANOMALY ASSESSMENT Spans

SPANS ƒ Section of unsupported pipeline ƒ ƒ ƒ ƒ ƒ ƒ ƒ

Uneven seabed Rock dump Sandwaves Scour Rocks Coral outcrop Pipe crossing

Pipeline crosses seabed depression

Pipeline crosses seabed with changes in slope

Pipeline crosses seabed rock outcrop

A pipeline span is simply a section of the line that is not in contact with the seabed. This can be due to a variety of reasons, the most common of which is an uneven seabed on the selected route. Pipelines submerged in seawater form quite efficient beams, resulting in a relatively high bending stiffness and a tendency to span over seabed undulations. Rock dump can cause spans, in that the rock berm is designed to be stable and resist dissipation due to environmental loads. The seabed around the rockdump may not be as stable, and scour of the seabed may result in a pipeline suspended between periodic mounds of rockdump. Sandwaves are a feature of many soft seabeds, including the southern North Sea. The sandwaves tend to propagate, resulting in continuously moving pipeline spans unless the pipeline is lowered to below the trough level. Seabed scour can be regional or localised. Regional scour is the general lowering of the seabed, which tends to destroy pipeline trenches and create spans. Localised scour is

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caused by the presence of the pipeline. This can be caused by seabed currents, fish digging themselves in under the pipe, or variations in seabed sediment.

SPANS IN UK SECTOR OF NORTH SEA ƒ 33000 spans on 7800 km (4900 mile) pipe ƒ Only 800 > 0.5 m (1.6 ft), 260 > 0.8 m (2.6 ft) high ƒ 19000 < 10 m (33 ft) long around 100 > 60 m (197 ft) long S p a n L e n g th

Log (F) = 1.6632 - 2.9169 Log (H) 1

Span Height (m)

L o g (F ) = 4 . 2 0 6 2 - 0 . 0 3 8 0 L

10000

10

100

1

Frequency

10000

Frequency

Span Height 0.1

100

1 0

50

100 S p a n L e n g th (m )

150

200

Spans are very common. In the North Sea UK Sector alone there are in excess of 33 000 spans in 7800 km (4900miles) of pipelines. That is an average of one every 230 m (750ft). Of these, most are short and low, maybe only a few inches high at most. Only a few hundred are of any concern, either due to the integrity of the span or for their potential to cause hooking of fishing gear. First-pass span analysis is principally about identifying which spans present a problem and require further evaluation. Typical spans have been described statistically. The distribution of span height is loglog; while the distribution of span length is log-linear. There is no significant correlation between span height and length.

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SPAN ASSESSMENT ƒ Determine critical span lengths - during pipeline design ƒ ƒ ƒ ƒ

First-pass Installation case Operation case What spans are likely to occur

ƒ Assess fitness-for-purpose of span found following construction or during operation ƒ Detailed assessment of stress and fatigue

There are a number of approaches to span assessment, which vary depending on when they are carried out in the life of a pipeline. During design, a first pass spanning assessment will often be performed. The purpose of this assessment is to determine limits on allowable span length for the installation contractor to work to. The assessment of these span limits is normally based on conservative criteria, which ensure that no short or long term damage of the pipe will result. Also during design, an assessment of the seabed profile along the proposed route may be performed to identify whether pipeline spans are expected to occur, and if so where and how long. This assessment of the route would be based on survey data and would use finite element analysis (using a general FEA package such as ABAQUS, or a specialist pipeline package such as Orcaflex or Sage Profile) to ‘lay’ the pipeline over the anticipated seabed profile. This analysis would give predictions of the numbers and sizes of expected spans and therefore allow an assessment of the route preparation or span remedial work that will be required. This is obviously important to allow assessments of cost to be made. Subsequent span analysis is performed during operation of the pipeline to address any anomalous spans identified. The analysis is therefore to determine the acceptability of a known span length, and would entail a detailed assessment of stresses and fatigue.

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WHY CORRECT SPANS? ƒ Yield and plastic hinges ƒ Vortex-induced vibration PROBLEM bending & fatigue Current & wave action

Axial tension & compression

End supports

Gap & trench shielding

The section of a pipeline that spans is subject to its own self-weight, fluid loading and potentially third-party loads from fishing gear. This could cause it to yield and to fail in bending with plastic hinges. If this mechanism could occur, then it is necessary to stabilise the span and give it additional support. A second mode of failure for spans is a fatigue failure due to vortex-induced vibrations (VIV). These are vibrations induced in the span due to the passage of currents (and waves) perpendicular to the pipe. These cause the pipe to oscillate at its natural frequency which, over a period of time, can lead to fatigue failure. Again, should fatigue failure due to VIV be predicted for a particular span, it would need to be supported to prevent this happening. Major span lengths can prevent internal pipeline inspections because of the risk of overstressing failure when the weight of an intelligent pig is passed through.

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SPAN CONCERNS ƒ Peak stresses - static and dynamic loads ƒ Global buckling - axial operational loads ƒ Fatigue caused by strong currents ƒ Vortex-induced vibrations (VIV)

ƒ Plus wave and tidal oscillatory loads ƒ Particularly in shallow water

Span analysis considers three main aspects: ■ The potential failure due to excessive stresses from a long span ■ The buckling of the span through excessive local bending ■ The span failing due to column buckling caused by thermal expansive axial forces ■ The likelihood of vortex-induced vibrations (VIV) occurring and hence the potential for fatigue failure These aspects are considered during both the pre-construction analysis and the operational analysis.

SPAN ASSESSMENT - SUMMARY ƒ Spans are unsupported sections of pipeline ƒ Result of uneven seabed terrain ƒ A common occurrence (33 000 in UK North Sea)

ƒ Subsequent problems ƒ Bending and yield, VIV and fishing gear snagging

ƒ Design assessment ƒ Determine maximum allowable span length ƒ DNV out-of-straightness/bottom roughness

Any questions?

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Pipeline spans are a common occurrence where the seabed terrain is uneven. The main problem with assessing ‘real’ spans is determining the actual length and height of the span. The difficulties in determining accurately the span height and length arise from ■ The variable end conditions for different seabed soil types ■ The potential for any mid-span touchdown ■ The spans may move and change shape over time. For the design of a pipeline, it is important to assess the maximum allowable span length. This should be done for both the installation and operational cases. For maximum allowable span lengths, it will be necessary to establish the peak stresses in the pipeline for both static and dynamic loading of the span, consider the potential for pipeline buckling due to the combined axial and bending loads within the span. Also, possible fatigue due to VIV and interference with trawl gear may need to be assessed. The DNV approach makes use of finite element methods to assess interplay between adjacent spans. Pits and Dents

PIPELINE WALL DEFECT TYPES ƒ Internal corrosion pit ƒ General wastage of wall ƒ Dent

Having found a defect during the internal survey, the next step is to decide whether it is safe to continue operation or whether it is necessary to make a repair. We will consider the approaches taken in evaluating the internal corrosion and dents. Internal corrosion is rarely so simple as an isolated pit. The picture above shows some general corrosion, some erosion, some preferential attack of the weld and some isolated pits. The issue is how do we evaluate whether the pipe is safe?

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ASSESSMENT OF CORROSION ƒ Long defect fails as rupture ƒ Short defect fails as leak ƒ Based on ƒ Axial length ƒ Remaining wall thickness ƒ Proximity of other defects

Using finite element analysis and burst tests, corrosion defects have been assessed and formulae developed to predict the safe operating pressure for a given defect or set of combined defects. The assessment method is based primarily on the axial length of the defect (or its equivalent axial length if there are a number of defects together) and the remaining wall thickness. A long defect will fail as a rupture while a short defect will fail as a leak. It is therefore crucial to distinguish whether groups of pits are close enough to act as a single defect or whether they will all act as isolated pits. Cookbook formulae are given for the above analysis in ASME B31.G and more recently (and more comprehensively) in DNV RP-F101 ‘Corroded Pipelines’, 1999 (note: not to be confused with DNV OS-F101).

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ASSESSMENT OF IMPACT DENTS ƒ Gouges or cracks could fail by rupture ƒ Plain dents could fatigue or obstruct pigs ƒ Based on ƒ Unpressurised dent depth ƒ Gouges, cracks, sharp folds

The assessment of dented pipelines is usually based on the unpressurised dent depths. It is crucially dependant on whether there are any localised defects such as gouges, cracks or sharp folds within the dent. Essentially plain dents (without gouges, cracks or sharp folds) fail at the same pressure as undented pipe. Consequently the problems that they cause are centred on fatigue and the obstruction of pigs. The latter is due to the fact that the dent reduces the diameter of the pipeline locally and could cause the pig to jam. The fatigue aspect is due to the fact that there are stress concentrations at the dent, which will flex as the internal pressure varies. This is covered in the next slide. Should there be any gouges or cracks, then the dent could fail rapidly and catastrophically due to a time-dependant creep in the material. To avoid this, the pressure must be held below 85% of what it was when the dent was formed.

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FATIGUE IN DENTS

Dent size (% of diameter)

Δσ/ΔPP Stress Concentration Factor

160 140

Plain pipe 1%

120

2%

100

100

3% 4% 5%

80

6% 60

7% 8%

40

9% 10%

20

10

0 15

20

25

30

35

D/t ratio

40

45

50

3

⎛ 100 ⎞ 3 Fatigue ∝ σ = ⎜ ⎟ = 10 10 ⎠ ⎝ 3

The above chart shows stress concentration factor (in this case the stress divided by the internal pressure) versus D/t ratio. For offshore pipelines we are typically in the D/t ratios of 15 to 25. The experimental results in the graphs show that the deeper the dent, the higher the stress concentration factor. It can be seen that a 7% dent in a pipe with a D/t ratio of 25 induces a stress 10 times higher than that for a plain undented pipe. Given that fatigue is proportional to stress cubed, this dent therefore reduces the fatigue life by a factor of 10³ or 1 000. In summary, known defects may be acceptable provided that they are are not too severe.

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PIT AND DENT ASSESSMENT SUMMARY ƒ Internal corrosion ƒ Determine risk of rupture or leakage ƒ Assess corrosion length, remaining wall thickness and proximity of other defects

ƒ Dents ƒ Determine risk of rupture, interference with pigging ƒ Reduced fatigue life on gas lines ƒ Assess dent depth and presence of other defects

Any questions? For the assessment of internal corrosion defects, the objective will be to determine the risk of pipeline rupture or leakage. The assessment should consider the length of the defect, the remaining pipe wall thickness and the proximity of other defects to establish if they are significant. Exposure

PIPELINE EXPOSURE ƒ Pipelines buried for ƒ Protection ƒ Stability ƒ Insulation

Pipelines are often buried for reasons of protection, thermal insulation or stability. If a section of pipeline that was previously buried is found to be exposed on the surface then

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this needs to be assessed. Depending on the reasons why it was originally buried, it may be acceptable for a short section of line to be left exposed. Note that rock dump cannot be used to restore thermal insulation because of the free flow of water between the rock so mattresses or trench and burial are needed.

EXPOSURE ANOMALY ASSESSMENT ƒ Pipeline may be acceptable with no cover ƒ Exposure risks ƒ Upheaval buckling ƒ Loss of stability in storms ƒ Lateral buckling or coating damage

ƒ Potential for third-party interference ƒ Impact damage – coating or anode removal

ƒ Cooler arrival temperatures for thermal insulation ƒ Risks of emulsion, wax or hydrate formation

ƒ Assess potential for deterioration ƒ Develop into span with bending and VIV risks Exposed sections of pipeline may still be acceptable, particularly for short lengths. However, assessment is required. Where cover was provided to prevent pipe movement, the line may be at risk of upheaval or lateral buckling. In shallower waters, winter storms may move the pipeline and initiate buckling or damage coating. Trawler gear may impact the pipeline and remove coating or anodes. Where the cover was needed to maintain the temperature of the pipeline, the arrival properties of the product may become out of specification. Assessment is undertaken to establish if the exposure is critical and so requires remedial action, or if the defect is not critical and the pipeline may continue to operate as normal. For the assessment of spans, the potential problems are bending, buckling and vortexinduced vibrations.

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LOSS OF ROCK-DUMP PROTECTION ƒ Summer survey revealed gas line exposure ƒ Shallow water of shore approach

ƒ Possible causes ƒ ƒ ƒ ƒ ƒ

Insufficient original design – OK until 100 yr storm New analysis methods to combine current and wave Adjacent pipeline rock dump modified flow pattern Settlement of foundation Broken armour stone

ƒ Surveys & storm records ƒ Identify cause

Natural seabed

Armour layer Under layer

ƒ Restored before winter

Whilst normally, scour is a problem for mobile sandy or silty seabeds exposed to strong currents, Jee Ltd was involved with an exposure of a rock-dumped pipeline. The summer survey of 2006 of a natural gas export pipeline for a major operator revealed that the armour layer had been lost in the shallows of the shore approach – in water depths of 7 m to 9 m (23ft to 30ft). The survey showed some 100 m (330ft) of exposed pipeline and a short 9 m (30ft) spanning section. This deterioration had been worsening over the last three surveys, despite the pipeline protection having been stable for the previous 17 years. An adjacent pipeline had been rock dumped at about this time and may have modified the current and wave regime. However, there are a number of other possibilities. The original size of armour stone may have been too small. It is common to design for 1:100 year return wave and currents. Such a severe storm may not have occurred until just before the adjacent pipeline needed additional protection (both lines were affected at the same time). Recent developments in rock sizing recommend adding algebraically the shear due to waves and the shear on the rock slope due to current : earlier analysis methods added their velocities algebraically and then applied them to the slope. The natural seabed used as a foundation may have settled or scoured away. The armour rock may have been damaged and broken in storms over the years, leaving a stone size insufficient to provide stability – many shore protection works fail gradually in this way. A study of the recent storm data and last five year’s of annual video and side-scan surveys is likely to indicate why the armour stone has been lost. However, due to the length of exposed pipeline and the proximity of winter storms, it is necessary to order more rock dump immediately to restore the protection for the final 10 to 15 years of the pipeline’s life, and avoid further spans forming.

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EXPOSURE ASSESSMENT SUMMARY ƒ Exposure caused by ƒ Scour of sand or silty seabed ƒ Damage to rock dump

ƒ Cover needed for ƒ Protection – impact from trawler or dropped object ƒ Stability – uplift or lateral buckling ƒ Insulation – flow assurance (wax / hydrate formation)

ƒ Assessment may show no action to be taken ƒ Monitor in following surveys

Any questions? Exposed lengths of pipeline can be due to scour of sand or soft sediments or by damage to rock armour layers. The assessment needs to consider why the pipeline was covered in the first place. It may show that no action need be taken immediately, but that the situation requires monitoring.

ANOMALY ASSESSMENT SUMMARY ƒ Pipeline span ƒ Assess risk and consequences of buckling and VIV

ƒ Internal corrosion and dent ƒ Determine risk of rupture or leakage, interference with pigging and reduced fatigue life

ƒ Exposure ƒ Cover needed for thermal or impact protection ƒ Risk of further deterioration, buckling or damage ƒ Could be precursor to span

Any questions? Spans are not necessarily a cause for concern. There are many short spans on pipelines. However, in the case of spans higher than 0.7 m (2ft), these become a risk to trawler

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men. Yielding damage can also occur by buckling or bending under self weight. Fatigue damage may be caused by VIV in strong currents. For the assessment of internal corrosion defects, the objective will be to determine the risk of pipeline rupture or leakage. The assessment should consider the length of the defect, the remaining pipe wall thickness and the proximity of other defects to establish if they are significant. For the assessment of dents in the pipe wall, the objective will be to determine the risk of pipeline rupture, reduced fatigue life or if the dent depth is sufficient enough to prevent the passage of pigs. The assessment should consider the unpressurised dent depth and the presence of other defects, such as gouges, cracks or sharp folds. Sections of pipelines that become exposed may be acceptable, but the situation must be assessed and monitored because scour can develop into spans.

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REMEDIAL WORKS

REMEDIAL WORKS ƒ Retrofit anodes ƒ Span correction ƒ Pipeline stabilisation ƒ ƒ ƒ ƒ

Anti-scour fronds Grout bags Mattresses Rock dump

ƒ Clamp ƒ Sealant application

Having conducted a survey, it may be necessary to carry out some maintenance tasks (remedial works). These are detailed in the following slides. Retrofit anodes tend to be a sled full of zinc placed next to the depleted anode and electrically connected to the pipe. Before fitting, it would be normal and wise to establish the cause of the anode depletion. Span correction is applied where the span is too long and may be prone to overstress or fatigue due to vortex-induced vibration. The correction takes a number of forms. It could be the placement of sand or grout bags at mid-span to provide support. Alternatively mattresses could be placed below and above the span, or the span could be rockdumped. If the pipeline has been dented or there is a corrosion defect then a clamp may be placed around the pipe - either to seal any leaks or to support the dent and prevent fatigue. Clamps are dealt with below, but other options are covered in the Modifications and Repairs module.

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STABILISATION ƒ ƒ ƒ ƒ

Grout bags Anti-scour fronds Mattresses Rock dump

Where the pipeline has deburied and is unstable and moving around on the seabed, pipe stabilisation is necessary. Were it not corrected, this could lead to a fatigue failure of the pipe. A number of techniques are available. These include ■ anti-scour fronds, as shown in the picture. When placed over the pipeline, these will trap sediment from the water and build a sand berm which stabilises the pipeline. ■ concrete or bitumen mattresses laid over the pipe. ■ grout bags placed over the pipe. ■ rock dumped onto the pipe

STABILISATION MATTRESSES

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Dense mattresses are placed over the pipeline to stabilise it. These mattresses may be of bitumen and rope construction, or of concrete blocks on a rope matrix (shown above). Both, when placed over the pipeline, will conform to the shape of the pipeline and seabed.

PRINCIPLE OF BOLTED CLAMP

First we will consider clamp repairs, using a landline clamp to show the principles. The picture shows the clamp being installed around a pipe. Its flanges will be bolted together on both sides. There are elastomeric seals around each end and down both sides so that if any fluid does leak out into the annulus, it is contained by the clamp.

SUBSEA HIGH PRESSURE REPAIR CLAMP ƒ Sturdy ƒ Rated up to ≈200 bar (≈3000 psi) ƒ Hinges open for installation ƒ Pipe must be able to take weight

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When the pipeline clamp is scaled up to accommodate large diameter and high-pressure lines, it can become a very heavy and robust device. The clamp shown above weighs 40 tonnes and has a steel thickness of 406 mm (16in). There are hydraulic clamps on the top to hinge it open and closed. Each bolt is three inches in diameter, is over a metre long and needs buoyancy attached to help the diver lift it into place. From the viewpoint of the pipeline engineer, one crucial calculation to carry out is to check that the damaged pipeline still has sufficient strength to withstand the self-weight of the clamp being attached.

CLAMP AS A PRESSURE VESSEL ƒ Clamp becomes part of pipeline ƒ Permanent or temporary repair Damage to pipeline (hole) Seal

There are two ways to use pipeline repair clamps: as pressure vessels or as structural supports. The pressure vessel mode is shown in the diagram above. The clamp forms a sealing chamber around a leaking pipe. In this mode the clamp is truly pressure containing and forms part of the pipeline system.

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CLAMP AS STRUCTURAL SUPPORT ƒ Clamp not pressure-containing ƒ Permanent repair Epoxy or grout

Damage to pipeline (dent)

The second mode is for structural support. The clamp is attached to the outside of a dented (but non-leaking) pipe. The annulus between the clamp and pipe is filled with grout and this is allowed to set. When the pipeline is repressurised, the hoop stresses from the pipe are transmitted out to the clamp. The clamp thereby gives structural support and stops the dent flexing, hence returning the fatigue life of the damaged section back to that of the undamaged pipe. The clamp is therefore a permanent structural repair but is not pressure containing.

LEAK REPAIR ƒ www.Seal-Tite.com ƒ Pressure-activated sealant for small leaks ƒ Can be delivered using a batch pig train

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One company, Seal-Tite, provides a new leak repair concept without the need for external intervention. It is claimed that Seal-Tite is able to cure leaks with only a brief off-line period. The leak repair sealant is deployed inside the pipeline: for subsea pipeline applications it can be delivered to the leak site in a train of pigs. The pressure differential across the leak polymerises the liquid sealant and plugs the leak. This system has been used successfully offshore and in a wide range of other applications.

POLYMERISING SEALANT PROCESS

Seal Element

Flow

Safety valve

Safety valve

ΔPressure across leak site starts polymerization Seal Element

1. Fluid escaping through leak site

ΔP increase as sealant builds at leak site

2. Sealant bridging across leak site Safety valve

Seal Element

Sealant flexible polymer seal at leak site

3. Leak sealed

The pictures above illustrate the process of sealing a leak adjacent to a safety valve. Initially the fluid escapes through the hole. The pressure differential across the leak starts the polymerisation process. The sealant starts to solidify at the edges of the leak and the hole is gradually plugged.

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REMEDIAL WORKS - SUMMARY ƒ Unacceptable anomalies must be rectified ƒ Anodes can be retro-fitted to a pipeline ƒ There are a range of techniques for rectifying spans ƒ A clamp can repair dents or corrosion ƒ Severe damage will necessitate replacement of the damaged section ƒ Leak-sealing technology is available Any questions? If anomalies are found to be unacceptable then rectification of the anomaly must be performed. This could take the form of ■ Fitting an anode sled to a pipeline ■ Removing or diminishing a span by using fronds, mattresses, rock dump or support ■ Fitting a clamp to a damaged section of pipeline ■ Using a sealing solution to plug a small leak In cases of severe damage the affected section of pipeline will need to be replaced. This is covered in the Repair module.

PIPELINE INSPECTIONS - SUMMARY ƒ Need for and basis of pipeline inspections ƒ Methods used for inspection ƒ Anomalies to look for in routine inspections and maintenance ƒ Methods of assessing anomalies ƒ Methods available to correct the anomalies that are found Any questions?

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We have introduced the main concepts for the integrity management of subsea pipelines. Inspections are necessary to ensure the continued safe operation of the pipeline. Anomalies are identified and corrected before they are severe enough to cause problems. The nature and frequency of inspections is determined by a risk-based inspection plan. External inspections can be done using ROV, side scan sonar or AUV. inspections are done using intelligent pigs.

Internal

Following an inspection, any anomalies are first identified and then assessed. Those that are judged to be unacceptable are corrected.

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Modification and repair

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495

EXPECTATION

EXPECTATION ƒ System needs to be upgraded over time ƒ Identify the methods of pipeline isolation, hot tap and tie-in ƒ Major repairs and pipeline replacement ƒ Know what to consider when planning the decommissioning of a pipeline

The requirements of a pipeline system changes over time. We may wish to add a new branch to the network. This involves a tie-in with a tee or wye (shaped like a T or Y) to existing pipe. Where this is not a hot tap, it is necessary to first isolate the section to be cut open. An overview is given for the methods that can be used for pipeline isolation and tie-ins. The ‘Integrity Management’ module covered minor remedial works intended to stabilise the damaged section. Where a deep dent or major damage has occurred, it may be necessary to replace a section of the line or even the whole pipeline or riser. We will look at methods to carry these out. Finally, the considerations for planning the decommissioning of pipelines are discussed.

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ISOLATION

ISOLATION ƒ Isolate before working on a pipeline ƒ Repair, replacement or tie-in ƒ Make the pipeline safe to work on

ƒ Procedure ƒ De-pressurise ƒ Remove hydrocarbons and toxic products ƒ Fill with inert medium ƒ

Suggested basic procedure ƒ

Decommission pipeline and flood

ƒ Why may this be undesirable? When we are not hot-tapping a connection, in order to effect a repair or to install facilities for a third party tie-in to the line, we need to isolate a section of the pipeline. This is necessary to make the pipeline safe. This effectively means removing the internal pressure and hydrocarbons or toxic contents from the pipeline. One way of doing this might be to shut down, depressurise and water-flush the entire pipeline. In most cases, this is undesirable from an operational point of view. For example, in a gas trunk line, the depressurisation would involve flaring a lot of gas (lost inventory), and flooding would lead to a requirement to dewater and vacuum dry, which could put the pipeline out of service for many months.

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LOCAL ISOLATION ƒ Isolating just the worksite from the pipeline contents Work site

Hydrocarbon Inert fluid/gas Isolation plug

The alternative to depressurising and flooding the entire line is to perform a local isolation. This introduces an internal barrier between the product and the worksite. Therefore, only a short section of the pipeline is flooded and the time taken to flood, dewater and dry is greatly reduced. Depending on the isolation system used, pipeline pressure may also be resisted, avoiding the need to depressurise the system.

ISOLATION METHODS ƒ ƒ ƒ ƒ

High friction pigs Tethered or remote set isolation plugs Pipe freezing Hot tap and stopple

There are a range of isolation techniques. The main ones are listed above and are described in the following slides.

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HIGH FRICTION PIGS ƒ Close to platform ƒ Head 3 bar (44 psi)

Outer pipe wall Direction of flow

ƒ Trains of pigs Differential Pressure acting over the seal

Main body of pig

Flange diameter

Differential pressure

Friction

Wall force

Friction force Wall force

High friction pigs are bi-directional pigs with oversized polymeric discs giving a high seal with the pipewall. They are available from a range of pig manufacturers. The principle they use is that increasing the differential pressure acting over the pig seal will result in an increase in the force applied on the wall. This increased wall force then causes an increase in the frictional force resisting the pigs movement. Increases in frictional force result in an increase in the differential pressure. The point at which in the pig becomes trapped in the pipeline is determined by controlling the differential pressure applied over the pig. They can generally hold differential pressures of about 3 bar (44 psi) and are therefore used for isolation where the pipeline is depressurised. The use of trains enables a greater total differential to be held. They are pigged into place. Because the high seal discs will wear during this placement operation, they are generally limited to use within about 2 km (1.2 mile) of the pig trap. The design of high friction pigs is critical to their functioning. Consideration should be made to ensuring the flanges are capable of holding the seals against the high drag forces and ensuring they do not pull out. Care should be taken to ensure the seals will not buckle. Compression set may become a problem, where the seal material relaxes and does not provide the necessary sealing resistance.

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ISOLATION PLUGS ƒ ƒ ƒ ƒ

Tethered close to platform 120 bar (2.2 ksi) Remote away from platform 80 bar (1.2 ksi) Deployed through pig launcher Upstream pipeline pressure locks plug against pipe wall

Courtesy: ITAS - Isolation plug

Isolation plug locking mechanism

Isolation plugs are pigged to the required location, have brake shoes which set against the pipe wall and hold them in position even against full-line pressure, and elastomeric seals which are inflated to effect a complete seal against the pipe wall. Tethered isolation plugs are suitable for use near to a platform and have been used extensively for functions such as change-out of platform emergency shutdown valves. The plug is pigged into position and receives power and control through an umbilical which is run down the inside of the line. There is a limit to how far the plug can be pigged from the platform because the plug has to tow the umbilical behind it. Tethered plugs are capable of withstanding 150 bar (2180 psi) differential pressure. Remote set isolation pigs are similar in principle to the tether plugs, but do not utilise an umbilical. Power and control is provided onboard and is remotely operated. This means that there is no limit to where in the line the isolation pig can be used. Remote set plugs are capable of withstanding of the order of 80 bar (1160 psi) differential pressure.

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ISOLATION PLUG

This is another manufacturer’s isolation plug showing the details of the slightly different locking mechanism.

REMOTE ISOLATION PIG

The figure above illustrates the method of remotely activating a SmartPlug isolator. The vessel sends extreme low frequency (ELF) signals to a seabed array. As the plugs arrive, the ELF communication link (ECL) activates the remote activation system (RAS) which locks the plugs in place.

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For a section of pipeline to be de-activated, it is necessary to send a pair of plugs through the line in the same operation with sufficient separation.

PIPE FREEZING ƒ Introduce plug by freezing liquid/gel within the pipeline ƒ Water-based gel ƒ Maintain at -20°C to -40°C (-4°F to -40°F) To surface vessel

Freeze jacket

High seal pigs

Coolant

Coolant L

Vent

Gel Insulation Cut-out area

Product Gas

Pipe freezing produces a plug by freezing a slug of water or gel within the pipeline. The gel or water is introduced within a train of high seal pigs. Liquid nitrogen is used to chill the coolant on the vessel. This coolant is then pumped through a freeze jacket installed around the pipe. The pipe is maintained at a temperature of -20°C to -40°C (-4°F to 40°F).

PIPE FREEZING ƒ Form a solid frozen plug in pipeline ƒ Can withstand pressures >270 bar (3916 psi) ƒ Avoids need to drain down and refill systems

Pipe freezing a 324 mm (12in) carbon steel oil line Courtesy: Cyril Bishop

Internal view of freeze plug Courtesy: BJ Process and Pipeline Services

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Pipe freezing involves the controlled formation of a solid frozen plug inside the pipeline using specialist equipment and techniques. Once formed, the plugs provide isolation of the line while pipework modifications are carried out. The pictures show the process on a landline. However, the technique has frequently been successfully used subsea.

HOT TAP AND STOPPLE ƒ Can be used at any location ƒ Holds approx 70 bar (1000 psi) ƒ Only single block ƒ Sequence ƒ ƒ ƒ ƒ

Install split tee Hot-tap - drill Bypass (optional) Insert stopple

The final isolation method to be considered is hot-tap and stopple. ■ A split tee is installed around the pipeline. This can either be welded or bolted to the pipeline. ■ A valve and cutting head are attached to the tee and the hot-tap is made. ■ The valve is closed, the cutter unit is removed and a stopple unit is attached. ■ The stopple is inserted into the pipeline to isolate a section of line. ■ If desired a bypass line can be used, but this is rarely done subsea. ■ The isolated section of line can be purged and worked on. ■ When the repairs are complete the stopple units can be removed from the valves and a seal disk can be inserted to allow the valves to be removed, leaving only a blank flange bolted to the tee.

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HOT TAP AND STOPPLE - VIDEO

This animation shows the hot tap and stopple operation.

ISOLATION - SUMMARY ƒ Make the pipeline safe to work on ƒ Range of methods dependent on location and pressure ƒ ƒ ƒ ƒ

High friction pigs Isolation plugs Pipe freezing Hot tap and stopple

Any questions?

The simplest method of isolation is to insert a high friction pig to block the line. The use of this is limited by both pressure differential and distance from pig inserter. Isolation plugs lock against the side of the pipe wall, forming a barrier to prevent product flow in the isolated section. These plugs can be either remotely operated or tethered, depending on the location of the isolated section.

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Overview of pipeline engineering

Pipe freezing is another method of isolating a section of the pipeline, involving the formation of solid frozen plugs capable of withstanding high pressures. Line stopping involves hot tapping the pipeline, to insert a block head, which prevents flow of product through a section.

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TIE-INS

TIE-INS ƒ ƒ ƒ ƒ ƒ

Expansion of pipeline network Providing an entrance for a third party Repair / replacement of pipe section Diversion of pipeline leg Methods ƒ Existing flange, tee or wye ƒ Hot tie-in ƒ Hot tap - use of valved flange

ƒ Cold tie-in ƒ Isolate section and purge with inert gas

Repairing damage is not the only reason for needing to work on the pipeline. Other common reasons are expansion of the network as new fields are brought on stream or the requirement to tie in a third party pipeline. Because of decommissioning of some unmanned platforms, a new bypass diversion was inserted into the Frigg line (2004 and 2005 seasons). Where facilities such as a tee or wye have not already been provided, it is necessary to add them whilst the pipeline is in service. An alternative solution is to use a single hot tap (without the stopple). This can be installed with hyperbaric welding or clamp as before, and provides a valved flange to the new branch. For a cold tie in, following isolation using one of the methods already described, a section of the line is purged with inert gas.

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STATS GROUP HOT TAP TEE REPAIR CLAMP ƒ 1168.4 mm by 609.6 mm (46in x 24in) Tee ƒ Contingency bolted clamp ƒ 144 bar (2.1 ksi) MAOP trunk pipeline

The photograph shows a hot tap Tee repair clamp supplied by Stats Group. It is a contingency repair system for a 46in 144 bar trunk pipeline.

TIE-IN PROCEDURE

Isolation Gas test Remove coating

Inspection for: • Diameter & ovality • Pipe material • Wall thickness

Clean weld area

• Corrosion

Cut / bevel pipe

• Laminations and inclusions

Jointing / welding Radiography / ultrasonic tests

• Weld seams in vicinity • Deposits in pipe

The procedure for a tie-in follows the flow diagram to the left. Once the coating is removed, full inspection is required prior to ensure the area is acceptable prior to cutting into the pipe itself.

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ADD A NEW TEE ƒ Hot tap to avoid shut-down

Installation of horizontal Tee

A new tee can be added to the pipeline without the need to shut down the existing pipeline, using the hot tap procedure described previously. The horizontal T is installed with the cutter unit and clamp bolts attached. In the Gulf of Mexico, it is more common to use a vertical Tee, so the slinging arrangement is different.

GROUTED TEE TIE-IN CONNECTION ƒ Eliminates welding on pipeline ƒ Maintain production capacity during tie-in ƒ No pipe ovality problems ƒ Metallurgical independence ƒ Reduces safety hazards

For smaller lower pressure lines, grouted tees may be used. This avoids welding.

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The grouting sleeve can be dimensioned to allow for any pipe ovality and provides an electrical insulation between the new and existing lines.

TDW SUBSEA HOT-TAP VIDEO

This video illustrates the hot tapping process used to perform a repair to a 12” flowline in the Yellow sea off the coast of northern China. This flowline supplied 40million cubic meters of gas daily to Tianjing. Due to the vital importance of the pipeline to Tianjing city, the repair work has to be carried out without interruption to normal supply of gas to Tianjing and especially to the main power plant in the area. CNOOC had developed the fields in the west of Gulf of Bo Hai, Yellow Sea in northern China. In the late spring of 2000 the pipeline was damaged, possibly due to impact from a sunken ship. The damaged pipeline has a dent of 11” x 5” x 0.5” and a rupture of 2.5” long. Initially, CNOOC installed a make-shift sleeve pipe for the damaged pipe section. However, due to the severity of the damage, it was unlikely that the pipeline could be pigged in the future and therefore a permanent repair was required. Armed with the hot-tapping technology from TWD and Oil States Hydro-Tech, repair work to the pipeline was carried out in October 2001. CNOOC were in charge of the project, while COOEC carried out the repair work. The hot tapping operation allowed a bypass to be installed, enabling the continuous supply of gas to Tianjing while the damaged pipe was replaced by a pre-fabricated section.

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PREFITTED BLANK FLANGE ƒ Avoid shut-down of existing pipeline ƒ Requires knowledge of future requirements ƒ Repair sites cannot be foreseen

ƒ Added cost to pipelay double block and bleed valve provision

Tappable blank flange

Tappable flange

A recent innovation is the tappable blank flange, which provides a location at which a valve can be installed and hot-tapped into should it be required at a later time. This avoids the need for fitting a pipe clamp or hyperbaric welding. Compared with these alternatives, the tappable blank flange is relatively inexpensive. However, the possible tie-in locations need to be foreseen. Future damage locations cannot be determined. How many of these flanges should be added to pipelines and where is a matter of judgement. The added cost must be allowed for - especially if it is for a third-party. Good practice dictates the use of double block valves with a bleed system between. This means that safe operation can be guaranteed.

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VALVING ƒ Provide suitable facilities and valving for: ƒ Precommissioning new line ƒ Operational pigging ƒ Future entrants without shutting down existing facilities

ƒ Principles ƒ Double block and bleed arrangement ƒ Provides safe isolation

ƒ Drains at low points in piping ƒ Vents at high points

Consideration should be given to the requirements of pre-commissioning, operational pigging and future tie-in facilities. To achieve isolation, a double block and bleed valve arrangement is required. This means that two valves are used with a bleed-tapping between. This provides redundancy and a means of monitoring for leakage. In piping, provision of drains and vents will enable dewatering and drying of pipework.

PIGGING FACILITIES

Pig trap Branch line flow New Existing

Main line flow

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Once the mainline tee has been fitted with double block and bleed valves, the branch flow can be attached. It too has a double block and bleed termination. The valve arrangement provides full isolation both from the main line and the branch line ensuring a safe working environment for divers or future operators of the lines. This illustrates how pigging facilities can then be provided. Temporary or permanent pigging facilities can be attached. If the pig trap were then removed, this arrangement could be used for provision of future additional tie-ins. Again, an extra double block and bleed valve set arrangement would provide the means of isolating the two-branch lines independently.

ADD A NEW WYE ƒ Wye piece ƒ Same diameter as the existing ƒ Allows pigging of the new line into the existing ƒ Longer pigs

ƒ Different size lines ƒ Dual diameter pig

Main pipeline

Pigged in this direction

Branch line

Where the new branch is of the same diameter as the existing line, the use of wyes rather than tees means that both the lines are piggable. Longer pigs are normally used to ensure that they pass the junction. In gas lines, the pressure on the branch should be adjusted to ensure easy passage. If the pressure is too high, the pig will stop before the wye. If it is too low, as the pig passes, the flow will divert back up the branch. Where the branch line is smaller than the main line, a dual diameter pig is used. If the branch is not to be pigged, then bars are sometimes provided at the opening of the wye to ensure easy passage of the pig. Although normally pigs are sent in only one direction, an arrangement like railway points is available that ensures pigs can be sent in the reverse direction to either branch.

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NEW WYE

New entrant

ƒ Shut down existing pipeline ƒ Isolate and cut-out section ƒ Install new wye Abaqus FE stress model

New wye on skid

Existing pipeline

The new valves, pipework and wye piece would normally be mounted onto a skid with a protection structure over. Valves are normally added to enable shut down of either branch. Again, double block and bleed system would be provided. The pipeline would be shut down and the section isolated as before. The new wye would be connected up using bends. The FE model of a reinforced wye piece recently carried out by Jee shows the high stresses (yellow) during hydrotesting in the ‘crotch’ area. The wye can be manufactured from sections of a 30° bend and a straight pup piece. The three stiffener plates help to prevent the widest section from bellying out.

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TIE-INS - SUMMARY ƒ Need for tie-ins ƒ Tie-in procedure ƒ Thorough inspection of existing line condition

ƒ Grouted, bolted clamps and prefitted flange ƒ Valving ƒ Double block and bleed

ƒ Pigging facilities ƒ Comparison of tee and wye Any questions? With the continuing expansion of pipeline networks, it will often be necessary to connect (or tie-in) new pipelines with existing pipelines to provide services to new locations. Tie-ins can also be used to bypass sections of pipe that require replacement. We have looked at the steps in undertaking a tie-in with careful inspection of the existing line to ensure that it is in a suitable condition. A number of methods have been described including bolted or grouted clamps and a pre-fitted blank flange - useful when the need had been foreseen. The main principles of valving and fitting of pig traps has been described. Tees and wyes have been compared with regard to pigging.

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REPAIRS

REPLACEMENT SPOOL ƒ May be needed if pipeline is severely dented, buckled or ruptured ƒ Basic sequence on following slide ƒ Two options: ƒ Hyperbaric weld ƒ Mechanical connector

In cases where the pipeline damage is too extensive to be repaired by a clamp, it will be necessary to cut a section out and insert a new replacement spool. The techniques for doing this are initially to isolate the pipe and then to insert the new section with either a hyperbaric weld or a repair connector. These issues are addressed in the following slides.

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SPOOL REPLACEMENT ƒ Locate damage

ƒ Remove and clean coatings

ƒ Isolate ƒ Cut-out ƒ Excavate ƒ Install new spool

WELD OR CONNECT? Once the location of a leak or damage has been detected, the pipeline on either side is isolated using one of the methods described earlier. The seabed beneath the site needs excavating to gain access for the equipment needed. The damaged pipework is cut out and a new section of spool inserted. We have two options to make the ends up: welding or jointing.

HYPERBARIC WELD ƒ Dry weld within chamber ƒ Diver performs weld ƒ Multiple qualifications ƒ Diving, welding, NDT

ƒ Procedures to account for pressure effects: ƒ Arc voltage ƒ Arc stability ƒ Chemistry ƒ Heliox mix is needed even in air diving depths

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During the initial development of the North Sea oil and gas fields in the late 60s and early 70s, it became apparent that the wet welding techniques used in salvage and civil engineering applications would not be adequate for these deeper water conditions. This lead to the development of hyperbaric welding techniques which have been utilised for the tie-in and repair of subsea pipelines. A hyperbaric weld is carried out in a dry chamber, known as a habitat, which is placed over the pipeline and the seawater is expelled with a helium/oxygen breathing gas. Diver-welders enter the habitat and perform the welding operation in a dry environment, working at the ambient seabed pressure. Prior to the installation of the habitat, the pipe ends are aligned using pipe handling frames located on the pipeline. Hyperbaric welding was initially developed using manual procedures, such as Gas Tungsten Arc Welding (GTAW) and Shielded Metal Arc Welding (SMAW). GTAW (due to its high quality but slow deposition rate) has been used mainly for the root and hot pass, and SMAW, which is a quicker but a less controlled process, used for the weld cap. The quality of manual welding is directly related to the performance of the welder, which can vary from welder to welder, and is also be dependant on the water depth, as human performance can be impaired due to the effects of hydrostatic pressure. In recent years, mechanised welding systems have been developed which have improved the overall quality and repeatability of hyperbaric welding, and also allow welding to be carried out at greater depths. Special welding procedures need to be prepared to account for the different pressure at depth. However, the operator needs to maintain full qualifications in diving, end preparation, welding of a number of possible diameters, wall thicknesses and pipes material as well as many types of NDT operations.

HYPERBARIC SPREAD

Welding habitat

Pipe alignment frame

ƒ Frigg diversion 2004/5 ƒ Large pipe, 813 mm (32in); thin wall, 19 mm (¾in) ƒ Total of 6 pups for line diversion ƒ Platforms to be removed These figures show a welding habitat and associated pipe alignment frame.

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Subsea 7 have undertaken a number of hyperbaric welds for Total on the Frigg lines’ TP1 / MCP-01 bypasses as part of an EPIC contract. This required hyperbaric welding on 813 mm and 610 mm (32in and 24in) pipelines to re-route them around two platforms in 90 m to 110 m (300 to 360 m) of water. Hyperbaric welding was selected because they are large diameter with a relatively thin wall, 19 mm (¾in). In the first season 4 pups (8 welds) were welded with a further 4 welds during the second season. Once the Frigg diversions were completed, the steel platforms will be removed in their entirety (similar to the procedure at Maureen) but only the topsides will be removed from the gravity concrete base structures. This contract follows Subsea 7’s successful completion of hyperbaric welding work in Australia.

PROS AND CONS OF WELD ƒ Diving time generally greater than connectors ƒ Water depth limitation ƒ Manual SMAW - 200 m (660ft) deep ƒ GTAW deeper - in excess of diving depths

ƒ Pipeline returned to original condition ƒ ‘Golden weld’ testing

A hyperbaric weld will generally take considerably longer than is required to make up a mechanical connection. There are water depth limitations for hyperbaric welds, although welds are generally feasible within diver depths. The advantage of a hyperbaric weld is that the pipeline is returned to its original condition with no subsea equipment remaining. It is also possible to avoid hydrotesting of the repair by use of the ‘Golden Weld’.

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GOLDEN WELD ƒ Full NDT of repair welds ƒ Radiographic, ultrasonic and magnetic particle inspection

ƒ Test results used as evidence for weld acceptability ƒ Repaired section does not require hydrotest or further testing ƒ Spools or pup pieces have been yard-tested

A ‘Golden Weld’ will undergo a thorough testing with a number of different nondestructive testing (NDT) methods. The results are used to verify the acceptability of the weld. This then eliminates the need to conduct a full hydrotest of the entire pipeline containing the repaired section. Note that new sections or pups being used to replace defective sections will have already undergone a full hydrotest in the yard or on the vessel prior to their incorporation into the existing system

MECHANICAL CONNECTORS ƒ Install connector on cut ends of pipeline ƒ Seal on outside of pipe ƒ A number of systems available

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The alternative to a hyperbaric weld is the use of a mechanical connector. There are a variety of connectors available, but all make a seal with the outside of the pipe, which first needs to be cleaned of all coatings. The main types are described in the following slides. The diver in the picture is inserting the Flexiforge tool into the connector. See next slide.

FLEXIFORGE CONNECTOR ƒ Pipe cut and flange sleeved onto end ƒ Tool expands pipe plastically ƒ Connector remains elastic ƒ Grips around outside of pipe

The Flexiforge system is available from Big Inch. The system involves an end fitting incorporating a standard flange, which slips onto the cut pipe end and is swaged. This is a cold-forging process performed using an internal expansion tool. The pipe is plastically expanded into the connector. The connector incorporates a system of rings and grooves that ensure a metal-to-metal seal. Because the thicker-walled Flexiforge fitting is elastically expanded whilst the pipe is plastically expanded, the fitting becomes pretensioned in the hoop direction once the forging tool is removed. This ensures a high axial load capacity.

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MORGRIP CONNECTOR Gripping segments (two per pipe shown)

Undamaged section of pipeline

Pipe end abutment

Ball cage

External seal test port

Twin seals

Replacement pipe spool

The Morgrip connector is available from Hydratight. The connector is slid on to the cut pipe, positioned and then activated by tensioning longitudinal bolts. The Morgrip contains graphite activated metal sealing rings (shown in black in the picture). It has an attachment mechanism, based on ball bearings, which indent the external surface of pipe. These act to wedge the connector onto the pipe, so that the harder the pressure tries to push it off, the more the ball bearings dig in. Two sets of seals are incorporated to allow a leak test to be performed between them.

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MORGRIP ƒ Generally diver-installed ƒ ROV version available

ƒ Tensioning bolts ƒ Activates gripping system and metal seals

Both diver and ROV installable versions are available. The Morgrip connector has been used for both repairs and new-build tie-in applications.

PROS AND CONS OF CONNECTORS ƒ Connectors quicker than hyperbaric weld ƒ Availability of diverless systems means no depth limitations ƒ Some systems able to accommodate poor axial tolerances ƒ Need to perform leak test ƒ Back pressure between the seals

ƒ Time to procure ƒ Emergency repairs

ƒ Smaller sizes of pipe The main advantages of mechanical connector systems are the fast make-up time and, because diverless systems are available, no depth limitation. Mechanical connectors do need to be leak tested which, for some connectors, requires a full system hydrotest.

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This full system test can be avoided if the connector includes a seal test port, as does Morgrip. This tests as a back pressure between the seals. Some types of connectors are not made for larger diameter pipelines, and specials may be difficult to procure in time for emergency repair operations. Depending upon the risk assessment, it is normal to have either standby connectors or a fully trained hyperbaric welding team.

ROVS USED FOR DIVERLESS REPAIRS A-frames or moonpool

In shallow water, use a direct umbilical Workclass or eyeball ROV

Strong umbilicals supplying control, power and support

Sea current

Heavy equipment & tools lowered from surface

Lightweight tether

‘Cursor’ launch system Tether management system (TMS) or ‘Top Hat’

Workclass ROV carries tool pack or equipment slung beneath Steerable garage unit with thrusters

Secondary eyeball ROV

The figure shows three procedures for operating ROVs, two of which are specifically designed for deepwater applications. When operating in deepwater environments, one of the main concerns is the time taken to lower the ROV to the seabed (this can be several hours). As the ROV requires a power supply cable there is a problem in that the umbilicals become both heavy (due to their length and strength requirements) and are subjected to large loads due to sea currents. Operators have developed two main systems where a powered unit with separate thrusters carries the workclass ROV down to the work site. This unit can be sized to withstand the loads from the main umbilical. When in position, it then releases the ROV on a lightweight umbilical or tether. This is normally up to a few hundred metres long, but can be made up to 1 km (3280 ft). The figure shows two different methods of deepwater ROV installation. One involves lowering the ROV in a steerable garage. Any heavy equipment or selections of tooling can then be lowered to the seabed on a separate frame. This method may also include a secondary eyeball class ROV slung beneath, which can be used to oversee the operations of the workclass ROV or other tasks. The second method involves lowering the ROV on a device known as a TMS (tether management system) or Top Hat which releases the ROV at the worksite. The ROV in this case grasps a separate tool unit beneath. This may be a trencher, burial device, flowline connection module, suction anchor installation, mining or military. Launch using a ‘Cursor’ enables the almost neutrally buoyant ROV to be pushed safely through the surface zone (where the thrusters have difficulty operating) into the deeper

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water beneath the vessel. The cursor can run down a set of rails or wires, and it holds the TMS or garage. Typically, workclass ROVs locate themselves by the left arm grasper, and manipulate using the right arm. When following a pipeline, the ROV may fly above the route, run on tracks or grip the line using wheels.

DIVERLESS REPAIRS ƒ Diverless repair techniques: ƒ During construction: ƒ Cut and remove damaged section, install A&R head to pull pipeline back up and continue laying ƒ Recover buckled or dropped pipeline to surface to effect repair

ƒ In operation: ƒ Repair pipe section in place with mechanical connectors or grouted sleeve

ƒ Flexible risers: ƒ Normally replaced ƒ Leaking annulus can be repaired by flushing with inhibited water

ƒ Risk reduction plan ROV-operated systems have been developed for pipeline repair in deepwater. That is, below diver depth. During installation, the buckled section may be cut off and removed, and a temporary pulling head fixed onto the end of the undamaged section to enable the line to be dewatered, thus restoring its buoyancy. The recovery wire is then pulled up to the laybarge and laying resumes. Alternatively, the buckled line may be used as a recovery system to pull the undamaged section back in order to effect a repair on the barge. We have just seen how a pipe can be repaired with mechanical connectors once in operation. Flexible risers are normally replaced. However, some repairs of impact damage to the outer layer may be effected using clamps. The annulus is then filled with inhibited water. In practice, most deepwater systems are built to perform a specific repair as part of a risk reduction plan. Fortunately, they are rarely used.

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BUCKLE REPAIR CUTTER ƒ Sonsub-Saipem ƒ Bluestream wet buckle repair system

Diamond cutter unit

This cutter can be used to repair a wet buckle at depths of up to 2200 m (7220ft). It was developed for use on the Bluestream Project in the Black Sea. The intention is to cut the pipe below the buckle and insert a recovery head. The evacuated pipe can then be brought back to the surface and laying continued.

BLUESTREAM HEAD ƒ Bluestream depth 2150 m (7050ft) of water ƒ ROV-operated equipment

ƒ Use of cutter to produce ‘square end’ ƒ Pressure to force pipe onto anvil ƒ Pipeline plastically deformed to form seal ƒ Single use unit Pipeline

Anvil

Deformed pipe wall

Pressurised volume

The second tool designed to be used by the ROV sealed the end of the pipe, enabling water to be removed and allowing the more buoyant pipe to be lifted.

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A thin-walled can was inserted inside the pipe and expanded. This plastically deformed the end of the pipe onto an anvil. The latter deformed elastically. When the pressure was released, the anvil recovered (elastically) and held the permanently deformed pipe wall using friction. Valves (not shown) permitted the pipe to be purged. This reduced the weight enabling the pipeline to be recovered onto the laybarge, where the unit could be cut off. Fortunately, it was a contingency item only. Although proven technology, it was not used in anger.

RISER REPAIR ON FOINAVEN VIDEO

Diverless riser repair is shown in the above video. The main points are: ■ The deep water, 500 m (1640 ft) flexible risers had external sheath damage during installation, and this caused flooding of the armour layers. ■ The task was to displace the seawater with inhibitor in order to prevent deterioration of the armour wires. ■ This was carried out by remotely operated vehicles (ROVs), which fitted clamps over the damaged sections and drilled vent holes to facilitate flooding of the annulus with inhibitor.

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BALLAST WATER SEALINE BAHAMAS ƒ Loading facility ƒ Crude sent from shore storage tanks to ‘sea island’ ƒ Ballast water line discharge from ship to shore ƒ 914.4 mm (36in) by 1200 m (3937ft)

ƒ Inspection using RTD tethered crawler ƒ Ultrasonic pipeline inspection technology ƒ Detector stand-off at nominal bore 75 mm (3in)

ƒ Transmission medium ƒ Water or oil

ƒ Zig-zag coverage of wall

Spider PIT

The ballast water line is used to transfer contaminated water from the tankers moored at the terminal when they are receiving crude oil from the onshore storage tanks. The site applied internal lining at the field joints failed due to quality control (QC) problems during construction, resulting in severe internal corrosion. A single pipeline was used to transport oil offloaded from tankers at a sea island structure to the tank-farm onshore. Because it was a single line, it was not possible to regularly pig the line after each discharge. Röntgen Technische Dienst bv (RTD Quality Services) of Rotterdam provided an ultrasonic tethered crawler inspection Spider PIT to detect loss of wall thickness in the line. The detectors had a stand-off from the wall of 75 mm and were passed in a zig-zag pattern over the whole inner surface of the line. It is necessary to use a liquid medium such as water or oil between such detectors and the inside surface of the steel.

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CORROSION OF SEALINE BAHAMAS ƒ Severe pitting corrosion ƒ Particularly bottom of line ƒ 12.7 mm (½in) down to 3 mm (⅛in) wall thickness ƒ Corroded areas over 0.5 m (18in) long

The RTD crawler proved that severe corrosion had occurred, particularly to the bottom of the line. The nature of the corrosion took the form of deep pits: in places the wall had been reduced from 12.7 mm down to just 3 mm; in some areas, the corrosion affected over 500 mm length mainly at the 6 o’clock position (bottom of pipeline). In three pits, there was just 2 mm of wall left. It was suspected that the intermittent discharge of oil (every few days or so) allowed the small amount of water to drop out and collect at the and then travel back down to the lower offshore end of the pipeline. The photographs show sections of the line that were subsequently removed during the repair operations. The first shows the corroded wall with a core sample removed for testing (at lower right) and the pits covered with corrosion product (rust). The second shows a cleaned surface prior to repair, demonstrating the depth of the pits encountered.

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GRP RELINING OF SEALINE BAHAMAS ƒ Glass-reinforced plastic liner ƒ Simple butt connection with GRP overlap ƒ Strings pushed into steel pipe avoiding buckling

ƒ Pressure test liner ƒ Grouting of annulus ƒ 300 m (1000ft) sections ƒ Start at lower end ƒ Monitoring at ports ƒ Grout release ensures full filling of annulus

Land and Marine Engineering relined the sealine using a glass reinforced plastic (GRP) liner. This was purchased in 15 m (49.2ft) lengths and assembled into 200 m (656ft) strings using simple GRP overwrapping of the square-butt ends. The strings were pushed down into the damaged steel line using winches on the beach attached to a beam at the rear of the string. Sets of rollers on top, bottom and sides of the pipe were required to avoid strut buckling of each string. These had to be released as the beam moved forward. The photograph shows the pressure testing of the liner. Once this was completed, the annulus was filled with grout to provide fixity to the liner within the pipe during operation. This commenced at the offshore end with displaced water being released from ports drilled into the damaged steel line every 300 m (1000ft). The ports were monitored for arrival of the grout so that operations could move to the next section towards the shore.

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REPAIR - SUMMARY ƒ Operations for repairing ruptured pipelines ƒ Hyperbaric weld ƒ Diver qualifications and welding equipment ƒ Golden weld testing

ƒ Connectors ƒ Morgrip and Flexiforge

ƒ Benefits of using welds or connectors ƒ Diverless repair ƒ Installation and operation - risk reduction systems

ƒ Relining weakened line Any questions? In the Integrity Management module, we looked at repair clamps that can be used as a reinforcement for minor defects such as dents. However, when a section of the pipeline has become significantly damaged, then it may be necessary to replace that section of the line with a replacement spool. Two types of connection can be made to tie-in the spool. One is to perform a hyperbaric weld, this will be relatively expensive. A ‘golden weld’ means that the system does not require a pressure test. The other tie-in method is to fit mechanical connectors to the ends of the spool and the existing pipeline. A range of mechanical connectors are available. The advantage is they do not all require a diver to make the tie-in and allow remote operation in deepwater. In deep water, we must use diverless techniques to connect the pipelines to the risers or well heads. We also need diverless methods for repair to lines should damage occur. The tools used for undertaking such work usually are attached to ROVs. We have examined how these tools are operated. Methods of pipeline and flexible riser repair have been shown, both during installation and operation. Repair systems must be fully tested and available for emergency operations. Fortunately, they are rarely needed. Where a leak has not yet occurred on a short length of sealine, it is possible to provide strength using a GRP lining.

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DECOMMISSIONING

DECOMMISSIONING ƒ OSPAR convention 1992 ƒ Portugal agreement 1999: ƒ Platforms under 10 000 tonnes removed ƒ 34 over that on case-by-case basis ƒ Maureen platform - removed ƒ Frigg – workscope though to 2012 ƒ Topsides to go with tubular steel supports ƒ Concrete gravity bases remain

ƒ Pipelines on case-by-case

ƒ Emotive issue: Brent Spar What to do in order to decommission pipelines and platforms has been debated for decades. The focus of the debate has been platforms, and pipelines have received little attention. The centre for the discussions has been the OSPAR (Oslo/Paris) Convention. This met in Portugal in 1999 and agreed that in the North Sea, platforms under 10 000 tonnes should be removed. Platforms over that weight, along with pipelines, should be considered on a case-by-case basis. The Maureen platform has already been removed from the Northern North Sea. The plans to remove the topsides to the Frigg platforms have been drawn up. The tubular steel support structure will also be removed but those with a concrete gravity base are to stay. The alternative to totally removing tubular supports is to cut them off at a level safe for shipping. This might be preferred when they are fixed to the seabed with difficult-to-detach piles. The Frigg removal work is to be completed by the end of 2012.

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We should not be complacent about decommissioning. The public storm over the deepsea disposal of Brent Spar is a case in point. No matter what the carefully evaluated scientific and environmental solution might be, a lot of damage can be done to a company’s reputation and sales if the public relations are not handled correctly.

DECOMMISSIONING TO DATE ƒ Common in Gulf of Mexico ƒ Not as common in North Sea ƒ Most rigid pipelines put into ‘protective storage’ ƒ Reuse - perhaps for CO2 injection

ƒ Deferred decommissioning ƒ No precedent for other lines ƒ Accountants cost savings

ƒ Many flexibles pulled up for reuse ƒ Especially in Brazil

ƒ Brazil – used as reef (with topsides removed) ƒ Nursery for fish Although a common practice in GoM, there have been relatively few pipelines abandoned to date in the North Sea. Most of them are cleaned and then sealed, so a decision on their long-term future can be made at a later date. They might be reused for development of smaller reserves or for injection of CO2 back into reservoirs. This helps with extraction and may gain carbon credits in the future. By deferring the decommissioning, it has the advantage of not setting a precedent. The costs of the work can be postponed into some future year’s accounts. However, the trend elsewhere appears to be towards leaving buried pipelines in place and removing unburied lines. Flexibles have a good record for re-use, particularly in Brazil where they are routinely retrieved, refurbished and re-laid. This is not so in Australian waters where flexibles tend to be recovered to the shore for disposal. Incidentally, the Brazilians have also recently placed a disused structure in a fish spawning ground to act as an artificial reef. This has been done with the backing of government fisheries scientists and has been shown to be successful in terms of providing a safe haven in which fish can breed. This lead might be followed elsewhere in the world. It raises the question of whether pipelines on the seabed are beneficial to fish (and even to fishermen) in acting as breeding sites.

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DECOMMISSIONING - SUMMARY ƒ Limited subsea pipeline decommissioning ƒ Mothballed pipelines ƒ Disused but protected

ƒ Flexibles reused ƒ Topsides removed ƒ Support structures either removed or cut off Any questions?

Decommissioning involves the removal of subsea equipment and components at the end of the service life. In the North Sea, there has been limited decommissioning of pipelines. Many are mothballed or abandoned in a state of protected storage after the subsea manifolds, wellheads or similar structures have been removed . Where possible, flexibles will be reused. Platform topsides often require removal due to their visible nature, but how they are ultimately disposed of will be determined on a case-by-case basis. The supporting structure may be removed entirely or cut-off at a level safe for shipping.

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SUBSEA PIPELINE OPERATION SUMMARY ƒ You should now: ƒ Identify the methods of pipeline isolation, tie-ins and repair ƒ Know what to consider when planning the decommissioning of a pipeline

Any questions?

An overview was given for the methods of isolation, tie-ins and repairs that may be needed during the life of a pipeline. Finally, the considerations for planning the decommissioning of pipelines have been described.

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Profiles

536

Overview of pipeline engineering

Profiles

537

TREVOR JEE MANAGING DIRECTOR MA CEng FIMechE

Date of Birth: Nationality: Education: Academic Qualifications: Professional Qualifications:

1958 British Oxford University (MA) Honours degree in Engineering Science Chartered Engineer Fellow of the Institution of Mechanical Engineers

Current Position at Jee Limited Trevor Jee is a mechanical engineer with over twenty five years’ experience in the design, construction and operation of oil industry pipelines. He formed Jee Limited in 1988 and has built it up into a specialist pipelines engineering and training company. As managing director he is responsible for the technical review and project management of study work, for the presentation and development of courses, and the sales and growth of the company

Specific Expertise and Experience at Jee Limited As well as a broad experience of pipeline matters and wide ranging personal contacts throughout the oil industry, Trevor has particular expertise in: ■ Conceptual and detailed design of subsea pipelines ■ Project management of studies and joint industry projects ■ Use of connectors in pipe-in-pipe systems ■ Trench versus non-trench decisions using risk analysis ■ Setting up and running the company ISO9001 quality system ■ Computer analysis of fluid/mechanical/structural/soils/thermal problems ■ Training courses in pipeline engineering ■ Technical and marketing consultancy ■ Sales, marketing, recruitment and growth of Jee

538

Overview of pipeline engineering

Pipeline Engineering Studies ■ SARFAP – project management of full scale, high pressure tests of acoustic loading on a subsea structure for BP ■ Project Management of large diameter pipeline full scale overtrawling trials for ExxonMobil, Shell, Subsea7, ConocoPhillips, and Statoil ■ CUEL – project Management of Pre-feed study on Dutch sector pipelines ■ BP – SARFAP project management of consortium doing model tests and designing full scale tests ■ Subsea7 – flume tank model tests and design advice for overtrawlable structure ■ Sakhalin Energy – design of risers on Sakhalin 2 project ■ Unocal – development of connector assembly tool designed for diverless operation ■ Finite element analysis of dropped pipe ■ Project Management and model tests for large diameter pipeline overtrawling trials ■ Writing ISO21369 on testing of mechanical connectors for use in pipelines ■ Writing PD8010 onshore and offshore pipeline code ■ Design of a diverless connector assembly tool ■ Fishing gear interaction with flexibles ■ BP/BGI – conceptual design of a subsea LNG pipeline system including cross section, construction and risk analysis, with detailing of components ■ BP – Lateral buckling analysis with varying soils conditions ■ Shell – construction options for laying and trenching of long umbilical ■ Fishing trials in Yell Sound: effect of rock dump on fishing practices for Magnus EOR project ■ Unocal – analysis of long pipeline spans and advice on remedial measures ■ UKOOA – audit of oil/government/fishing data flows ■ Coflexip – review of trenching study ■ BP – comparison of code and legislation for UK, Norway, Holland and Germany ■ CRP Group – CFD, physical testing and software on strakes ■ Stolt Offshore – surface-lay study ■ BP – 3D presentation in HIVE on vortex shedding ■ Market survey on pigging ■ Completion and issue of IP guidelines for testing of mechanical connectors for use in pipelines ■ Enterprise Oil – Corrib fishing types and intensity study Coflexip – pipelay curve finite element analysis model ■ ■ BP – CFD validation study on vortex shedding from rigid cylinders ■ BPCL – thermal design software ■ Multiflex – umbilical design ■ Set up and run joint industry project on the testing of mechanical connectors for use in pipelines. Write IP code ■ CRP Group – geotechnical design of clump weights ■ UKOOA – spans and fishing interaction study ■ Production and publication of OTH561 Trenching Guidelines JIP. Computer analysis and physical testing of trawl board motion and pipe response. Development of risk-based trench versus non-trench decisions. Management of client and subcontractor interfaces ■ Analysis of fishing loads on sloping well protection structure ■ SeaMark – design of concrete protection structures ■ Support for West Sole pipeline defect analysis and for Amethyst pipeline dent/fatigue analysis including finite element approach and grout crushing study. ■ Non-trenching analyses for BP Schiehallion and Total ALE projects ■ Completion of low cost pipeline connection systems JIP, producing final report and testing specification, with studies on catenary riser loads, and dent testing.

Profiles

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539

Modelling of the loads imparted to wellhead structures by trawl gear pullover. Assessing the cost and technical benefits of the use of connectors in pipe-in-pipe systems. Feasibility study on subsea LNG loading pipelines Risk analysis of lifting subsea components on Foinaven project, and for assessing the benefit of a high integrity pressure protection system on Troika pipe-in-pipe system. Thermal and upheaval buckling analyses of the Gannet bundle, together with development of concrete/foam insulation system. Transient thermal analysis of Gullfaks satellite bundle system using finite element approach Development of new piggable wye design on Foinaven Setting up and running the Trenching Guideline JIP, attracting 16 companies, with technical work on trawl board pullover loads and pipe dynamic response Freespan analysis and definition of anomaly limits for Conoco southern North Sea pipeline system Chairman for Foinaven project HAZOP meetings Pipelay vessel motion analysis and estimate of availability for West of Shetland weather conditions Studies on installation and repair issues for screwed subsea pipelines Novel pipelay methods for Black Sea including use of connectors in pipelines Setting up Low cost pipeline connection systems JIP and providing technical support on pipeline load envelopes, connector selection and testing Study on non-trenching of flowline and the status of trenching design world-wide 3D analysis of creep of a foam coating subject to hydrostatic and thermal loads. Advice on uni-axial testing of samples to provide input parameters Prediction of heat losses due to radiation, convection and conduction in a multipipe caisson and subsea bundle Feasibility and costs of deepwater bundles Dynamic analysis and technical feasibility of steel catenary risers Use of screwed connectors to provide a low cost step-out flowline from Magnus Layout design and definition of installation procedure for a retro-fit wye junction in a major gas trunk line Detailed design of fire protection system for a tank farm in the Seychelles Design calculations for hydrodynamic loads on concrete protection structures during installation and operation BP – research studies on deepwater bundles, screwed flowlines and ways of extending S-lay capability into deeper waters

Training courses Trevor has been responsible for the production of the Jee Limited training courses and presents the following: ■ Overview of Pipeline Engineering ■ Offshore Pipeline Construction course ■ Pipeline Operations and Integrity Management ■ Subsea Pipeline Design ■ Offshore Installation Calculations He has also been responsible for: ■ Writing and delivering a pipelines, tankage and materials course for Military Works Force ■ Managing and marketing the Composites and Titanium course with QinetiQ ■ Developing the advanced pipeline engineering training course for Petrobras

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Summary of Previous Experience ■

Andrew Palmer and Associates Limited, 1988-1992 □ Lead Engineer, British Gas North Morecambe project. Detailed design of trunk line □ Project manager, Shell Nelson project. Conceptual and detailed design of export pipelines □ Lead Engineer, British Gas Morecambe Bay subsea safety valve conceptual study □ Lead Engineer, BP Miller insulated landline detailed design □ Lead Engineer, BP Miller wye conceptual and detailed designs □ Project Manager, MOD inshore magnetic ranges. Design, procurement and installation of subsea structures □ Technical studies and reports including upheaval buckling, evaluation of BS8010, span assessment, and trenching chalky soils

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British Petroleum, 1979-1988 □ BP Petroleum development, Aberdeen. Mechanical engineer providing technical and commercial support to the pipeline operations group □ BP International, London. Mechanical engineer on the design of risers and pipelines □ BP Trading, London and BP Chemicals, Hull. Graduate Engineer on monitored professional development scheme

Profiles

541

MIKE HAWKINS TECHNICAL DIRECTOR BTech (Hons) CEng MIMechE

Date of Birth: Nationality: Education:

19 May 1962 British Loughborough University

Academic Qualifications: Professional Qualifications:

Degree in Mechanical Engineering Member of the Institution of Mechanical Engineers

Current Position at Jee Limited Since 1994 Mike has been working with Jee Limited, initially as Senior Engineer and more recently as Technical Director.

Specific Expertise and Experience at Jee Limited In his time with Jee, Mike has been responsible for many studies and activities. Particular fields of expertise include: ■ Computer analysis of fluid, mechanical, structural, soils and thermal problems ■ Trawl gear interaction with pipelines and the prediction of fishing gear loads ■ Upheaval and lateral buckling ■ Modelling of impact and denting ■ Heat transfer and modelling of transient behaviours ■ Creep of foam insulation systems ■ Analysis of pipeline freespans, vortex induced vibrations and fatigue assessment ■ Risk and reliability analysis ■ ABAQUS finite element analysis ■ Presentation of pipeline training courses ■ Conceptual and detailed design of pipeline and rigid riser systems

542

Overview of pipeline engineering

Pipeline Engineering Studies ■ Dolphin – Third party verification of Dolphin Project sealines and export pipeline detailed design. ■ Perenco – Development of Pipeline Integrity Management System, inspection plans and general integrity management support for Perenco’s southern North Sea pipeline system. ■ JIP – Project management of joint industry project investigating the over-trawling of large diameter pipelines. ■ BP – Project management of design and test programme investigating acoustic resonance in small bore connections in subsea PLEM. Involved co-ordination and management of a consortium of technical experts. ■ Technip – Preparation of corporate pipeline design guidelines for world-wide use. ■ Chevron Texaco – Qualitative risk assessment and detailed fatigue analysis of pipeline spans in the Gulf of Thailand. ■ Scott Wilson – Pipeline expert advising on and evaluating options for lowering of existing subsea pipeline to facilitate deeper dredging of Colombo Harbour shipping channel. ■ Shell – Third party verification of Goldeneye gas export trunkline detailed design and installation analysis. ■ Various – preparation and presentation of training courses on subsea pipeline and riser design, construction and operation. ■ Clough – route profile analysis for pipeline laid onto severely undulating seabed in Gulf of Thailand. Operational stress analysis and span fatigue assessment for resulting spans. Analysis of proposed excavation options for span rectification and stress analysis. ■ BP – conceptual design of subsea LNG pipeline system. ■ Mobil – assessment of over-trawlability of large diameter bundles. ■ BP – stress analysis and fitness-for-purpose assessment for re-trenching of nearshore sections of West Sole pipelines. ■ Advantica – development and evaluation of limit state design methods for pipeline stability, impact damage and upheaval buckling. ■ Balmoral – evaluation and analysis of water diffusion into Girassol riser buoyancy modules. ■ CRP – design of various clump weight foundations. ■ BP – assessment of pipeline restabilisation options for the West Sole pipelines. ■ BP – study of seabed scour and pipeline exposure trends for the Miller near shore pipeline section, including recommendations of remedial action requirements. ■ Coflexip – study of pipeline/soil interaction for hot pipelines. ■ BPCL – development of bespoke software for mechanical and thermal analysis of pipeline insulation coatings. ■ BP – assessment of span on Ninian pipeline in surf region. ■ BP – assessment of concrete loss and major span on Inde pipeline ■ Kongsberg – market review of subsea connectors. ■ Statoil - transient thermal analysis of Gullfaks Satellites heated bundle system using ABAQUS FE code. ■ Trenching Guidelines JIP - various studies and activities, including: development of a fishing gear pullover model simulating the interaction of trawl gear with pipelines; dynamic analysis of pipeline response due to trawl gear loadings using ABAQUS FE code; integration of these models into a risk analysis spreadsheet; sensitivity analysis of trenching related design parameters, including lateral buckling; evaluation of North Sea fishing gear characteristics. ■ Enterprise Oil - feasibility study and cost estimates for flowline installation, by both conventional and novel methods (including screwed connectors, bottom tow, etc), for offshore field development in the Black Sea.

Profiles

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543

BP Exploration - Volcanera, Columbia - feasibility study, supplier/manufacturer evaluation and preparation of cost estimate for the use of 13Cr linepipe and mechanical connectors for the Volcanera flowline system (onshore). Hunting Oilfield Services - technical support to tender preparation for pipeline system in Qatar, including site visit and assessment of conditions and requirements of route and facility tie-in. Hunting Oilfield Services - Low Cost Pipeline Connectors JIP - studies on pipeline loading envelopes, offshore assembly and installation, pipeline repair methods. Laing Oil & Gas - thermal design of riser caisson systems for Shell Pelican and Lasmo Birch developments. Balmoral Webco - development of long term creep and thermal performance model for multi-layer pipeline coatings and design support on coating systems for various subsea pipelines. Flight Refuelling - market survey for application of through-pipeline data transfer system. BP Exploration - conceptual design and costing for low cost step-outs from Magnus using screwed flowlines installed from a drill rig. BP Exploration - feasibility and costing of steel and flexible catenary risers for the Magnus field. SeaMark Systems - detailed design of Statfjord Satellites dogleg concrete protection structures. CWA - detailed design of fire protection system for tank farm for SEPEC in the Seychelles SeaMark Systems - design calculations for subsea concrete structures: soils assessment, trawl board impact, steel reinforcement design, installation loads, dropped object impact, and soils settlement

Training courses Mike presents the following training courses on pipeline engineering: ■ Overview of Pipeline Engineering ■ Offshore Pipeline Construction ■ Pipeline Operations and Integrity Management ■ Subsea Pipeline Design

Summary of Previous Experience ■

Brown and Root Marine, 1992-1994 □ British Petroleum, Andrew Development Project. Lead engineer on export pipelines through FEED and detail design phases □ British Gas, Armada Project Conceptual Design. Senior pipeline engineer on export pipelines, high temperature in-field production flowlines, platform and subsea tie-ins and risers □ Hamilton Oil, Douglas Pre-Development and Essential Engineering. Lead engineer on conceptual design of pipeline/flowline system and detailed design of risers and J-tubes for concrete gravity structure □ Statoil, Statfjord Satellite Project. Pipeline engineer on installation of risers in J-tubes

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Andrew Palmer and Associates Limited, 1990-1992 □ Norsk Hydro, Brage Pipelines. Engineering verification of designs for upheaval buckling, cathodic protection system and J-tube pull-in of risers

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544

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Exxon, Passive Fire Protection of Risers. Conceptual review and evaluation of proprietary and novel passive fire protection systems for use on gas and oil risers between cellar deck and splash zone levels British Gas, North Morecambe Development. Pipeline Engineer on main gas trunkline and methanol pipeline Shell, Nelson Project. Pipeline Engineer on conceptual and detailed engineering phases Shell, Brent long term development study into the Brent intrafield pipeline requirements for various platform refurbishment options

British Petroleum, 1980-1990 □ Pipeline engineer on pipeline and riser design, operational support, research and development, with North Sea project support □ Mechanical Engineer on motor fuels research □ Engineering Trainee involved in design work on Ula-Cod and Mossmorran-Grangemouth pipelines □ Engineering trainee on plant inspection and construction

Profiles

545

MARTIN EAST OPERATIONS MANAGER BSc (Hons) MSc CEng MIMechE

Date of Birth: Nationality: Education:

Academic Qualifications: Professional Qualifications:

23 Aug 1965 British Crewe Boys Grammar School University of Sheffield Loughborough University of Technology Honours degree in Mathematics MSc in Computer Integrated Engineering Chartered Engineer Member of the Institution of Mechanical Engineers NAFEMS Registered Analyst (Advanced)

Current Position at Jee Limited Martin has been working with Jee Limited since 1996, initially as Senior Engineer and more recently as Operations Manager.

Specific Expertise and Experience at Jee Limited Martin is responsible for supervising and carrying out most of the finite element analysis (FEA) and computational fluid dynamics (CFD) work at Jee limited. Finite Element Analysis Martin has eight years experience of the ABAQUS finite element analysis software and has used it in the design of umbilicals and pipeline coating systems. Structural analyses have included ■ limit-state design of HP/HT pipelines ■ many lateral buckling assessments of surface-laid pipelines ■ upheaval buckling analysis of trenched and buried pipelines ■ thermal analysis of surface laid and trenched umbilicals ■ riser and spoolpiece design ■ bottom roughness analysis ■ the analysis of concrete spool-piece protection covers ■ span assessments for flowlines on undulating seabeds ■ seismic analyses of risers in a GBS platform leg ■ design of a pipeline crossing

546

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Overview of pipeline engineering

trawl gear pulling over a pipeline the energy absorption capability of an elastomeric coating analysis of pipelay and pipe pulls

Computational Fluid Dynamics Martin has used both Fluent and CFX packages for fluid flow analysis. Analyses have included ■ the hydrodynamic effects of helical strakes on a riser ■ the effect of strake pitch and profile on performance for a helical strake ■ the flow of backfill spoil onto a trenched pipeline ■ the influence of chord length on the performance of a streamlined riser fairing ■ heat flow and natural convection inside an insulated cabinet containing pipework ■ hydrodynamics of riser fairings Other Analysis Work Martin has done hundreds of calculations, primarily using Mathcad. Calculations include ■ stability assessments of pipelines ■ pipeline spanning assessments ■ rock berm assessments ■ lateral buckling calculations ■ heat transfer and cooldown of coated pipelines and pipe-in-pipe systems ■ thermal expansion assessment ■ vortex-induced vibration and fatigue of spanning pipelines ■ fracture assessment ■ wellhead protection structure design Pipeline Engineering Studies In his time with Jee Limited, Martin has also been responsible for many studies and activities for a variety of clients ■ Dolphin – Third party verification of Dolphin Project sealines and export pipeline detailed design. ■ Dolphin – Third party verification of Dolphin Project umbilical design. ■ BP – Project management of design and test programme investigating acoustic resonance in small bore connections in subsea PLEM. Involved co-ordination and management of a consortium of technical experts. ■ BP – stress analysis and stability assessment of near-shore sections of West Sole pipelines. ■ Coflexip – study of pipeline/soil interaction for hot pipelines. ■ BPCL – development of bespoke software for thermal analysis of pipe-in-pipe system. ■ BP – assessment of span on Ninian pipeline in surf region. ■ BP – assessment of concrete loss and major span on Inde pipeline. ■ SARFAP – project management of full scale, high pressure tests of acoustic loading on a subsea structure for BP. ■ BP – assessment of pig and slug train impacts on riser bends. ■ BP – study into the effects of coating disbondment on Thunderhorse risers. ■ BP – above-ground pipeline cost-reduction study. ■ Technip – review of spoolpiece dropped object protection design. ■ Sakhalin Energy – concept designs for risers on Sakhalin 2 project. ■ SEAPI – fitness-for-purpose assessment of damaged linepipe ■ Shell – flume tank tests and associated work for assessment of the required power cable protection for the Brent Alpha redevelopment. ■ Elf Exploration – Assessment of spans on the Claymore pipeline to establish the characteristics which contributed to the hooking and capsizing of the Westhaven. ■ Total – QRA of fishing interaction on the spans of the Frigg pipelines.

Profiles

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547

Wellstream – assessment of fishing interaction with flexible pipelines. BP – study to assess and improve data on the location of subsea structures and pipelines received by foreign fishermen fishing in the UK sector of the North Sea

Training courses Martin is responsible for the development of the Subsea Pipeline Design course and presents the following training courses on pipeline engineering: ■ Overview of Pipeline Engineering ■ Pipeline Operations and Integrity Management ■ Subsea Pipeline Design

Summary of Previous Experience ■

EMRC Europe Limited, 1988-1996 □ Finite element analysis of static, dynamic, thermal, fluid flow and fatigue problems on structures ranging from printed circuit boards to ships □ Responsible for training, benchmarking, technical support and software development

Profiles

549

ALAN KNOWLES SENIOR ENGINEER Eur Ing BSc(Hons) CEng MICE

Date of Birth: Nationality: Education:

Academic Qualifications: Professional Qualifications:

17 October 1951 British Park High Grammar School for Boys Birkenhead Technical College Liverpool Polytechnic College Honours Degree in Civil Engineering Chartered Engineer Member of the Institution of Civil Engineers FEANI European Engineer

Current Position at Jee Limited Alan is a civil engineer with over twenty-five years’ experience in the design of oil, gas and water pipelines. He has also worked in the nuclear industry, substantiating structures for the safety issues associated with seismic events. Alan joined Jee Limited as a Senior Engineer in 2002.

Specific Expertise and Experience at Jee Limited Alan has particular expertise in the following: ■ Installation methods for subsea lines for hydrocarbon developments ■ Design and specification of onshore and offshore pipelines ■ Soil assessment for pipeline trenching, burial and pile design ■ Subsea pipe bundles ■ Flowlines, landfalls, directional drilling, river crossings, marine structures and sea defences ■ Both conventional and single-point moorings for tankers ■ Finite element analysis of subsea equipment and finite difference analysis in soils ■ Calculations for coated pipelines with regard to both stability and thermal insulation ■ Design and construction of outfalls including investigation of primary and secondary effluent dispersion patterns

Overview of pipeline engineering

550

Pipeline Engineering Studies ■ Report on the pipeline requirements at pre-FEED study stage for a small, three field, gas development in the southern North Sea ■ Dolphin – third party assessment of subsea pipeline crossings ■ Pipeline-fishing interaction including the assessment of overtrawling structures, pipelines and bundles through flume tank testing and full-scale overtrawling trials at sea ■ Vortex-induced vibration analysis for fatigue, pipe span, on-bottom stability and risers ■ Unocal – development of a subsea clamp for VIV and current monitoring ■ Technip – fishing interaction study assessing the effects of spoil heaps at the edge of pipeline trenches ■ Sakhalin Energy – concept designs for risers on Sakhalin 2 project ■ Technip – development of pipeline flange design sheet ■ CUEL – assessment of installation, hydrotest and operating loads on subsea flanges Training courses Alan has authored a number of Jee Limited courses and presented them on four continents, both to the public and for companies in-house. These courses include: ■ Overview of Pipeline Engineering ■ Offshore Pipeline Construction ■ Offshore Installation Calculations ■ Subsea Pipeline Design ■ Army depots and landlines

Summary of Previous Experience ■

Osprey Consulting, 1996 – 2002, Contract Engineer - Design Management □ Working for Smit Land & Marine Engineering on submarine pipeline studies and proposals in the North Sea and elsewhere □ Development of a new system for flowline installation including the supervision of analysis and marine tank trials at Maritime Institute of Netherlands (MARIN) □ Preparation of feasibility study reports for HDD landfall at the Tangguh Development Irian Jaya; the Method Statement for decommissioning and removal of disused outfalls at BNFL Sellafield; and a feasibility option study for the discharge of an alternative fuel, Orimulsion at an existing SBM facility at Saint John, Canaport □ Presentations to clients for various studies and proposals □ Design work and method statements for submarine outfalls tender preparation

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Devonport Management Ltd, 1996 – 2001 □ Devonport Management Limited through Sanderson Watts Associates, upgrading and seismically qualifying 1900’s docks to permit the refitting of nuclear submarines □ Author of Design Substantiation Reports for Cross-Site Services Contract, 14 Dock Flooding/Dewatering system and the 14 Dock DSR Summary Report, which was used to gain safety approval in order to commence modifications □ Author of the Independent Technical Assessment report for 9 Dock penstocks

Profiles

551

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Subsequently, Assistant Design Authority for the adjacent dock being redeveloped to accommodate the larger Trident submarines. Procedures involved nuclear-industry Hazard and Operability (HAZOP) evaluation and Value Engineering Option assessments. Worked in conjunction with five alliance members co-ordinating design. Total value £375M Design included use of finite difference package FLAC and pseudo-static methods such as Mononobe-Okabe/Westergaard analysis Decommissioning analysis of Windscale Pile chimney for BNFL. Seismic FE modelling and report recommending demolition Also assisted in similar study of BTC building on site. This work involved independent checking of seismic analysis of mezzanine floor

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Smit Land & Marine Engineering, 1988 – 1996, Principal Engineer/Analyst □ Analysis and design of the bulkheads for Britannia Bundles, using the finite element suite ANSYS, to the AISC code of practice □ Risk assessment of the sensitivity to measured tolerances and the weight control of the bundles □ Hydraulic analysis of tankfarm landline and offshore SBM and pipelines at Whiddy oil terminal, Bantry Bay, Eire. Shore protection works design □ Assessment of technical requirements for dynamic pipe bundle enquiries. This involved sizing their carrier pipe, design of thermal insulation and fully-integrated tow and trailheads, manifolds, bulkheads and cathodic protection. Projects included Hudson, Heidrun, Thelma, Joanne, Captain and Columba Field Developments □ Deepwater tender study for Foinaven bundles □ Ethylene land-line design and survey including route selection and design of river and canal crossings using directional-drilling techniques □ Mooring analyses and procedures for pipe-laying vessels at the Forties, Miller and Mobil Beryl landfalls □ Final design presentation (including hydraulic study) of the large diameter, deepwater outfalls at Piraeus Athens: these three pipelines were of posttensioned concrete designed to accommodate earthquake forces by use of spigot and socket joints. Additionally, the shore approach rock armouring and pipeline armour protection had to be able to withstand severe storm conditions □ Development of thermal insulant gel for Gannet subsea bundle. Trials including pumping tests of the non-Newtonian pseudo-plastic fluid at BHRA; computer simulation of insulant/heat properties at SIA and inhouse; co-ordination of heat experiments at Salford University and Fulmer Yarsley Laboratories; and full-scale bundle simulation at Shell’s Billiton Laboratories in Arnhem, Netherlands □ Supervision of marine soil investigations for outfalls at Fleetwood and Lyme Regis. Feasibility studies for offshore sea defences and outfall studies at Worthing. Soils investigations for directionally-drilled crossings of landlines

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Smit Land & Marine Engineering, 1974 – 1988, Design Engineer/Site Engineer □ Site investigation, structural design and report; then the subsequent supervision for reconstruction of an historic listed stone jetty at Plas Newydd. Rip-rap stone apron design around the jetty in strong tidal currents of the Menai Straits and associated cathodic protection of structures □ Analysis of single buoy mooring (SBM) cable support to allow the exceptional tidal differences in Bay of Fundy

Overview of pipeline engineering

552

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Design of installation procedure for anchor chains of SBMs in Canada and Mexico Responsible for development of suites of programmes for pipeline stresses, concrete weight coating, outfall diffusion design, submarine plough design for lowering pipelines, and wave and current analyses Supervision and selection of company requirements for technical computers. This included the assessment and selection of bought-in software such as the finite element package ANSYS, vessel mooring analysis GMOOR, general design package Mathcad, spaceframe design QSE and the automatic language translation package Globalink. Installed the first NT Domain within the Costain Group Design of conventional buoy mooring (CBM) and hose handling pontoon for crude/fuel oil and liquefied petroleum gas (LPG) discharge facility at Lobito, Angola Principal author of the accompanying Commissioning, Operations, Maintenance and Safety Manuals for the project Feasibility study for major offshore gas field development in Morecambe Bay. Undertook stability analyses of subsea pipeline and assisted in report preparation Designed subsea pipeline and CBM facility of onshore oil terminal for power station in Cyprus Worked on Santos submarine outfall Brazil. Designed and supervised construction of 1200 tonne pulling head and deep marine cofferdam. Monitored wrapping, concreting and weight control of the 2.2 m diameter pipeline Responsible for surveys, feasibility studies, preparation of contract documents, temporary and permanent works designs Worked at ICI Frodsham, on construction of a bridge over the River Weaver. Completed initial hydrographic and land surveys for the location of bridge foundations. Responsible for setting out and temporary works design, for control and ordering of earthworks and marine piling. Engineer in charge of outfall construction into the Weaver Navigation Responsible for the design and detailing of building foundations and floor slabs on land reclaimed from a former sulphuric acid plant

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John Taylor & Sons, 1971 – 1972, Assistant/Resident Engineer □ Assisting with the design of a totally subterranean pumping station for lifting surface runoff to a height of 5 m using twin 1.6 m diameter Archemedian screw pumps □ Assistant Resident Engineer working on Hoylake and West Kirby resewerage scheme. This included construction of a primary treatment works and two pumping stations along with tunnelling sewers in poor sandy ground

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Holland & Hannen and Cubitts, 1968 – 1970, Site Engineer □ Responsible for setting out a large retraining centre in Hanley, on a reclaimed slag heap with difficult contaminated ground conditions

Profiles

553

PHIL MEDLICOTT SENIOR PIPELINE ENGINEER BSc PhD CEng MIMechE

Date of Birth: Nationality: Education:

13 February 1952 Irish Nottingham University

Academic Qualifications:

BSc in Mechanical Engineering PhD in Acoustics - Mechanical Engineering Chartered Engineer Member of the Institution of Mechanical Engineers

Professional Qualifications:

Current Position at Jee Limited Phil is a senior pipeline engineer and joined Jee Limited in July 2000.

Specific Expertise and Experience at Jee Limited In his time with Jee Limited, Phil has been responsible for many studies and activities. Particular fields of expertise include: ■ FEED studies including use of Pipesim ■ Pipeline piggability studies ■ Pipeline stability analysis using PRCI software ■ Fishing field trials to assess trawl gear interaction with pipelines ■ Tank testing to assess trawl gear interaction behaviour with pipelines ■ Verification, design and cost studies of alternative subsea pipeline and umbilical schemes ■ Preparation of ISO 21329:2004 Standard for testing of mechanical connectors for use in pipelines ■ Presentation of training courses covering pipeline design, pipeline integrity management and use of composite materials in offshore applications ■ Determine suitability of mechanical connectors for S and J-lay Pipeline Engineering Studies ■ Dolphin – Third party verification of Dolphin Project umbilical detailed design.

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Perenco – Development of Pipeline Integrity Management System for Perenco’s southern North Sea pipeline system. Perenco - Review of intelligent pigging methods Perenco – Pipeline span screening using DNV-RP-F105 JIP – Tank testing for joint industry project investigating the over-trawling of large diameter pipelines. Technip – Preparation of Mathcad design sheets for world-wide use. Chevron Texaco – Stability analysis of pipelines in the Gulf of Thailand. BP – conceptual design of subsea LNG pipeline system. Enterprise Oil - feasibility study and cost estimates for pipeline and riser installation. BP – Pipeline piggability studies including pigging from single launcher/receiver BP – Review of inspection and testing requirements for loading hoses CUEL – Conceptual FEED study for new development in the North Sea Apache – Steady state two phase modelling of pipelines for FEED study using Pipesim BP – Fishing pipeline overtrawlability field trials in Shetland Islands CUEL - Study to investigate rationale for changing or eliminating hydrotest procedure Unocal –Development of monitoring equipment, test programme and analysis routines for assessment of vortex induced vibration of pipeline spans BP – Review of mechanical connector systems BP - Review of technical study into acoustic resonance found in flexible risers Technip – Pipeline on seabed stability analysis using PRCI Level 2 and Level 3 software Wellstream – Flexible seabed stability analysis using PRCI Level 2 and Level 3 software CUEL – Pipeline on seabed stability analysis using PRCI Level 2 and Level 3 software CRP Assessment of vortex induced vibration reduction devices by laboratory testing

Training courses Phil presents the following training courses on pipeline engineering: ■ Overview of Pipeline Engineering ■ Pipeline Operations and Integrity Management ■ Subsea Pipeline Design ■ Pipeline stability and use of PRCI pipeline stability software ■ Overview of properties and implementation of polymer composite materials in offshore applications

Parallel activities In 1994 Phil Medlicott established his own engineering consultancy business which specialises in the use of polymer/composite materials technology to meet oil industry and transport requirements. He still continues to operate this business and has provided the following services: ■ Project manager of a £280,000 Joint Industry Project to develop the qualification methodology for FRP lined downhole tubing and flowlines. This work was completed at the end of 2003 and included the successful testing of FRP lined steel tubing systems in 160°C and 5000 psi production service environments over 4000 hrs ■ Preparation of ISO 14692:2002 GRP piping Standard for use within the oil and natural gas industries

Profiles

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Implementation of composite applications on BP Davy and BP Bessemer (9% of topside weight) Studies covering range of applications and performance issues of composite coiled tubing and umbilicals Presented with special award at CMMO3 conference in recognition of my activities promoting use of composites in offshore applications. Preparation of GRP grating specification for Shell Development of technical requirements for composite caissons

Summary of Previous Experience ■

BP Sunbury Research Centre 1989–1994 Senior Mechanical Engineer □ BP representative on three major Joint Industry Programmes concerned with the use of composite materials in the oil industry □ Responsible for preparing proposals for internally and externally funded R&D and disseminating information to business units □ Acquired practical knowledge of the design and chemical resistance of polymeric materials in oil industry and petrochemical applications

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BP Sunbury Research Centre 1977–1989 Technologist □ Carried out feasibility study that resulted in setting up of major multi million joint venture programme between BP, Leyland Vehicles and the DTI □ Responsible for the design, manufacture and testing of highly stressed engineering components made from fibre reinforced plastic composites. This involved hands-on work and led to a good appreciation of the interaction of manufacturing process with design and performance □ Inventor and designer of BP composite high speed flywheel (EP 0 145 182) developed for vehicle regenerative braking system □ Responsible for analytical stress and dynamic analysis, finite element stress analysis, and carrying out material testing □ Produced design guide of thermoplastic lined composite pressure vessels □ Designed and arranged field testing of novel oil pollution recovery equipment. This was subsequently developed further and marketed by BP

Publications and conference presentations ■ ■ ■ ■ ■ ■

Performance of FRP Lined steel tubing in production environment,' P Medlicott, Fourth International Conference On Composite Materials For Offshore Operations. Houston, TX, October 4 – 6, 2005 'Static Electricity and the Use of GRP Materials Offshore', P Medlicott, Fourth International Conference On Composite Materials For Offshore Operations. Houston, TX, October 4 – 6, 2005 'Composite Material Selection & Implementation in Oil & gas Applications', Materials Selection for Upstream Oil and Gas" IQPC conference, Aberdeen, 27th January 2004 'Static Electricity and the Use of GRP materials Offshore', CMOO-3 Houston 31st October to 2nd November 2000 'Composite Materials: Addressing Static Electricity Issues in Offshore Applications' ETCE/OMAE 2000 Conference in New Orleans, February 14 17th, 2000 'Progress towards a Qualification Methodology for FRP Lined Tubing and Flowlines in Production Service", Oilfield Engineering with Polymers Conference 26th October 1998

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Overview of pipeline engineering

'Use of Non-Metallic materials Downhole' Aberdeen 24th April 1998. IBC conference 'Advances in Downhole Technologies' 'Qualification Methodology for FRP Lined tubing for Production Service: A Joint Industry PROGRAM' 2nd International Conference on Composite materials for Offshore Operations (CMOO2), Houston, October 28-30 1997. 'Using Composite Materials to Minimise Weight and Maintenance and Maximise Safety' Euroforum Offshore Platforms '96, London, 18-19th March 1996 'How can Composite Materials be Successfully Applied to your Current and Future Offshore Projects? IIR Conference Aberdeen, 15-16th November 1995 'Overviewing the Diverse Applications and Advantages of Composites in the Offshore Industry' IIR Conference Aberdeen, 7 - 8th December 1994 'GRP and HDPE: Alternative Solutions to Corrosion', UK Corrosion, London 19-21st October 1993

Profiles

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STUART JOYNSON SENIOR ENGINEER BSc (Hons) PEng

Nationality: Education: Academic Qualifications: Professional Qualifications:

British Salford University Degree in Civil Engineering Professional Engineer Member of the Institution of Civil Engineers

Current Position at Jee Limited Stuart joined Jee Ltd in 2006 as an Offshore Construction Specialist and is currently involved in preparing and updating various training courses and expanding the company’s range of activities. Stuart’s particular areas of expertise include: ■ Offshore pipeline installation ■ Landfall construction ■ Flowline bundle fabrication and installation ■ Subsea trenching ■ Estuary crossings ■ Marine outfalls ■ Pipeline refurbishment ■ Decommissioning

Summary of Previous Experience ■

Corus Construction and Industrial, February 2002 to June 2006 □ Business development manager promoting services and materials within the Offshore and Renewable Energy sectors. This involved representing the Company at conferences and exhibitions, meeting prospective clients, giving presentations, preparing and submitting proposals and reporting on the status of the wind energy and marine renewable industries.

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Independent consultant, January 2001 to February 2002 □ Undertaking engineering studies associated with pipeline bundles, umbilicals, landfalls and sealine installation including costing and construction feasibility assessment. Projects were undertaken for major offshore construction companies, consulting engineers and oil and gas companies.

Overview of pipeline engineering

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In association with Jee Limited preparing and presenting offshore construction training courses in the UK and overseas.

Land and Marine Engineering Limited and associated companies (over 30 years) □ Production line manager, June 1999 to December 2000. Responsible for obtaining offshore construction work associated with flowline bundles, pipeline trenching, tanker terminals, decommissioning and relining. This involved marketing, preparation of prequalifications and tenders and negotiations with prospective clients. □ Operations manager, May 1992 to May 1999. Responsible for the following: □ Marketing of the flowline bundle technique including the submission of budgetary proposals. □ Co-ordination of tender preparation and the submission of bids for major offshore pipeline bundle projects. □ Liaison with alliance partners. □ Management of the company’s pipeline assembly area at Tain including liaison with landowners and environmental organisations. This included the preparation of the annual environmental monitoring reports with input from environmental consultants and various specialists □ Project manager for the Gannet pipeline bundle installation contract, May 1990 to May 1992. This £46 million E.P.I.C. contract included the fabrication and installation in Shell Expro’s Gannet Field of four pipeline bundles with lengths up to 3.6km. These bundles were assembled at Tain where up to 120 staff were employed. The project office staff were located in Middlesex where the engineering, procurement, and contract administration duties were undertaken. As Project Manager, was responsible for all aspects of the contract including liaison with the Client and J.V. partners, cost control, engineering design, safety, Q.A. and environmental management and approval of all phases of the work. □ January 1990 to May 1990, Responsible for establishing the Company’s pipeline assembly area at Tain in Scotland. This £1.5 million development was undertaken in 16 weeks and included the erection of fabrication buildings, formation of access roads over tidal areas, precasting and positioning concrete pipe supports, setting up permanent offices and installation of all services. Was based in Tain during this period and negotiated all sub-contracts and liaised directly with the local council on all planning matters. Established a working relationship with the various environmental groups concerned about the site development and addressed meetings with local business and similar associations. □ Operations manager, 1988 to 1990. Responsible for the following: □ The company’s activities in North and South America. □ Projects involving the relining of underwater pipelines. □ Operation of the company’s offshore survey department. □ The management of the company’s pipeline assembly site in Scotland including finalisation of the leases with the landowners, negotiations with the planning authority and preparation of baseline environmental studies. Some particular activities and projects undertaken included: □ The supervision on behalf of the client of the installation of two pipelines to an offshore terminal in the Dominican Republic. Both of these lines were installed by the off-bottom towing technique.

Profiles

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The preparation of procedures and safety plans for the Gannet flowline bundle installation tender. Business development manager, 1983 to 1988. Responsible for: □ Seeking out potential work for the company in the western hemisphere and progressing it through the proposal/bidding stage. □ Investigating new activities and business opportunities for the company. □ Marketing the company’s activities with the Scottish Regional Councils. Particular activities and projects undertaken included: □ The engineering design, preparation of procedures and the insertion of a fibreglass liner pipe inside a corroded subsea pipeline to an offshore oil terminal in Eastern Canada. □ The selection of a construction site for controlled-depth tow pipeline installation in the North Sea. This included the preparation of the planning applications, environmental impact assessment, discussions with the Authorities and representing the company at the public enquiry. This enquiry lasted for 10 days and eighteen expert witnesses were called to give evidence. □ The submission of tenders for offshore work in Canada, USA and Latin America. □ The installation of a single point mooring and subsea cable offshore Canada. General manager of Wescan Maritime Consultants Ltd, Calgary, Canada, 1981 to 1983. Responsible for establishing and operating this joint venture company, which undertook engineering design work relating to underwater pipelines and associated marine terminals. The work included marketing, preparing proposals, undertaking engineering studies as well as managing the office and supervising staff. Some of the major projects responsible for included: □ The detailed design and preparation of drawings and specifications for eight multi-pipeline river crossings at Norman Wells in the Canadian Arctic for Esso Resources Canada Ltd. These pipelines of various diameters up to 356 mm and with lengths up to 1360 m terminate on artificial islands constructed in the river. They are protected against ice during the “break-up” period and carry crude, gas, injection water and control cables. □ The preparation of installation procedures and cost estimates for pipelines to production facilities in the Canadian Beaufort Sea. □ An offshore survey, followed by detailed engineering, to investigate the stability of an existing pipeline to a single buoy mooring off the eastern coast of Canada. □ An evaluation of bottom tow installation methods for a 32 km long gas pipeline to Vancouver Island in water depths of up to 300 m. □ The preparation of tender documents for a feasibility study for a tanker terminal in the Beaufort Sea. Chief project engineer, 1978 to 1981. Responsible for the work and the operations of the Design Department, the Project Engineering Department and the Drawing Office. Some of the major projects responsible for included: □ The installation of four pipelines, each with a total length of 13.1 km, within the Bombay Harbour area. These lines, which carry oil and gas from the Bombay High Field, are up to 914 mm in diameter and were pulled into position in pre-dredged trenches.

Overview of pipeline engineering

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The 610 mm diameter gas Pipeline crossing of the Magellan Straits in Southern Argentina. This 45 km long pipeline was pulled ashore into pre-dredged trenches on both the North and South side of the crossing from E.T.P.M.’s laybarge 1601. The Southern shore approach onto the Island of Tierra del Fuego was 2.5 km long and required a 1000 tonne pulling system. □ A feasibility study, together with hydrographic and geophysical surveys for Hydrocarbons (GB) Ltd on the Morecambe Bay Gas field in the Irish Sea. This work resulted in the final pipeline route and the location of the landfall at Barrow being selected and included the preparation of installation procedures and cost estimates. □ The installation of five product pipelines and two telemetry cables between the Gulf and Texaco Refineries at Milford Haven in Wales. These lines, which are each 7 km long, vary in diameter from 222 mm to 323 mm. The crossing of the Haven involved extensive dredging before the lines could be simultaneously pulled into position. □ The design and installation of a G.R.P. sleeve to go inside a corroded offshore ballast water line. This 914 mm diameter line terminated at Burmah Oil’s tanker terminal in the Bahamas, 1200 m offshore in 35 m of water. □ The pull ashore of three pipelines (2 x 1220 mm and 1 x 400 mm diameter) from a laybarge anchored 1.2 km offshore at Dos Bocas in Mexico. Each pipeline was pulled into its final position by a 1200 tonne capacity land based winch arrangement. The client was Pemex. □ The project engineering work required for the Tay estuary crossing for British Gas. The marine crossing section of this 7.7 km long pipeline was pulled into position in a pre-dredged trench with a 1200 tonne capacity winch set up. □ The installation of three steel flowlines to the Texaco Tartan Platform in the North Sea. These lines were pulled from the reel barge Apache up the “J” tube risers on the platform, to their termination points, using a 200 tonne linear winch. □ The landfalls on each side of the Firth of Forth for the 1066 mm diameter feeder line crossing for British Gas. The pipeline was pulled from Brown & Root’s laybarge “Semac” moored offshore, into its final position using a 1200 tonne pulling system. Project manager for the Land & Marine single buoy mooring joint venture, 1977 to 1978 □ Responsible for the marketing, preparation and finalisation of fabrication tenders, preparation of installation procedures, scheduling and cost estimating for offshore oil terminals in the U.K. Sector of the North Sea. During this period the following major proposals were submitted. □ A S.A.L.M. export terminal together with a single anchor leg storage (S.A.L.S.) terminal for Mesa Petroleum’s Beatrice Field in the Moray Firth. □ A C.A.L.M. and a S.A.L.M. for BP’s Buchan Field in the North Sea. These were designed to accommodate 70,000 DWT tankers and to be located in 110 metres of water. □ Supply boat moorings for various North Sea operators.

Profiles

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Design/Project Engineer (head office based), 1972 to 1976. Work undertaken included: □ The preparation of the detailed design and specifications for a twin pipeline crossing of the River Forth for Scottish Gas. These pipelines are 460 mm diameter and 700 m long. □ The design of a 1900 m long x 914 mm diameter effluent outfall at Viana do Castello, Portugal. This pipeline was later pulled out into a trench blasted into the seabed. □ Project engineering work for the Forth Tanker Terminal for British Petroleum Ltd. Two 1219 mm diameter pipelines complete with risers were pulled from the construction site to the offshore terminal located in 35 m of water. □ Project engineering for BP Ninian pipeline landfall at Grutwick in the Shetland Islands. This 914 mm diameter oil pipeline was pulled ashore from the laybarge Viking Piper along the prepared seabed. □ Project engineering for the shore approach and landfall for the Shell Flags pipeline at St. Fergus, Scotland. This 914 mm diameter gas line was pulled ashore from the laybarge anchored 1.5 km offshore, and was then buried into the seabed using the TMIII trenching machine. □ The design, planning, procurement and preparation of procedures for a marine outfall at Santos in Brazil. This 1750 mm diameter steel pipeline 4 km long, was constructed on an area reclaimed from the sea and was then bottom-pulled into its final position.

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Assistant project manager, 1969 to 1972. Projects worked on in this capacity included: □ River Neath crossings for British Petroleum Ltd. Thirteen pipelines varying in diameter from 102 mm to 762 mm were constructed off site and then floated to the location and lowered into a dredged trench. □ The installation of a hot fuel oil pipeline across Milford Haven for Gulf Oil. This 342 mm diameter line, 1.5 km long, was insulated with polyurethane and concrete weight coated prior to being pulled into a pre-dredged trench. The contract included a pumping station, flow metering, leakage detection and telemetry systems. □ The installation of a submerged tunnel, 1.6 km long, across Hollands Diep for the Rijkswaterstaat. This 4 m diameter tunnel was constructed in 60 m long concrete sections in a dry dock. The sections were then towed to the tunnel site, lowered into position and jointed up underwater. The dredged trench for the tunnel sections was then backfilled Contracts engineer, 1966 to 1968. Some of the projects worked on during this period on site included: □ An extension to an existing sea outfall at Grimsby for Courtaulds. □ The installation of a 1090 mm diameter sea outfall, 760 m long at Eastbourne, UK. The steel pipeline was assembled onshore, encased in concrete, and pulled out through extensive cofferdams into a pre-dredged trench using barge mounted winches. An onshore pumping station 15 m deep was constructed within a diaphragm wall as part of the contract. □ The assembly and installation of two major marine outfalls at The Hague in Holland. The effluent outfall is 2240 mm in diameter and 2.5 km long. The individual steel pipes, each weighing 50 tonnes,

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Overview of pipeline engineering

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after being encased in concrete, were welded together on a launchway. The offshore trench was dredged, but the inshore section was formed from a sheet pile jetty extending 500 m out into the North Sea. The complete outfall was pulled into its final position using winches mounted on a workbarge. The second outfall was a sludge line, 356 mm diameter and 10 km long. This was constructed on land and bottom pulled into the pre-dredged trench. The installation of seven pipelines to connect Gulf Oil’s offshore terminal for 350,000 DWT tankers in Bantry Bay, Eire, to the landbased tank farm. The lines, varying in diameter from 222 mm to 1067 mm were constructed onshore and then pulled into position. At the terminal end, in 35 m of water, vertical risers were installed and connected to the pipelines with underwater flanges using a derrick barge.

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Brown & Root (UK) Ltd, 1968 to 1969 □ Field Engineer working offshore on derrick and lay barges in the southern sector of the North Sea. Projects worked on included the installation of platforms, the laying of pipelines and the setting of risers.

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Ward Ashcroft & Parkman – Consulting engineers, 1965 to 1966 □ Involved in the design of sewage works and other reinforced concrete structures

Profiles

563

BRUCE STOWELL SENIOR ENGINEER Eur Ing BEng(Hons) NDip CEng MIMechE MIGEM

Date of Birth: Nationality: Education:

Academic Qualifications:

Professional Qualifications:

30 November 1965 British Hilton College KwaZulu Natal South Africa Technikon Witwatersrand South Africa University of Salford Honours degree in Mechanical Engineering National Diploma in Mechanical Engineering Chartered Engineer Member of the Institution of Mechanical Engineers Member of the Institution of Gas Engineers & Managers Registered Eur Ing with European Federation of National Engineers Association

Current Position at Jee Limited Bruce is a senior engineer at Jee Ltd. He joined the company at the beginning of 2006.

Specific Expertise and Experience at Jee Limited Bruce has been responsible for carrying out the following activities. ■ Umbilical stability verification - Arabian Gulf ■ Pipeline integrity management, emergency spares assessment - North Sea ■ Engineering critical assessment on defective pipework - Indonesia ■ Specification writing - North Sea ■ Pipeline stability analysis – Thailand ■ Riser defect assessment – North Sea

Summary of Previous Experience Bruce has 14 years experience within the Petrochemical Industry and has been a chartered engineer for eleven years.

564

Overview of pipeline engineering

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Ove Arup, 1998-2003 □ Pre-FEED works for the development of offshore LNG and LPG storage in Angola for Kellogg Brown and Root □ Sakhalin phase two pre qualification and lead mechanical engineer for FEED tender specification and subsequent tender submission for two concrete gravity structures. Designed the installation and marine navigation systems. Carried out risk assessment on the internal placement of risers and conductors within the shafts □ Topsides project manager for the joint venture FEED for the development and costing of three offshore platforms to be located in the southern North Sea □ Lead mechanical engineer for the West Natuna ACE moveable gas production unit. Designed the pumping and control system for the floatoff, wet tow, installation and removal of the platform. Wrote the installation procedures and was responsible for the installation of the base penetration into the seabed and the lifting of the deck. Developed the analysis that was run to predict the performance of the installation systems during actual installation □ Mechanical engineer for the Malampaya CGS condensate storage system. Designed the manifold system for the condensate storage and export including the mechanical installation system to flood and install the CGS to the seabed. Wrote the installation programme and analysed the time taken for installation

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British Gas / Transco, 1991-1998 □ Project Manager and Planning Supervisor for replacement of Halon fire retardant systems to water mist systems within the compressor cabs at all of the compressor stations throughout the UK. □ Engineering and cost implications of pressure upgrades to 85 barg within the NTS □ Feasibility studies for the Aberdeen, Michlemersh and Towton compressor stations □ Mechanical Tender evaluation for the contract award of the Wooler compressor station □ Site Mechanical engineer for an international joint venture for the development of the Karachaganak field in Kazakhstan, the second largest gas field in the world. Carried out safety assessment and development of packages to improve production □ Compressor stations and the addition of both series and parallel compressor streams □ Pipe stress analysis to ASME B31.1 / 3 / 8 and to TD12 □ Hornsea phase 6 and 7 additional storage facilities □ Addition of the Selexol CO2 removal streams at the LNG storage facilities in the UK □ North Morecambe onshore terminal pipe systems □ Zeebrugge Interconnector pipeline specification □ Existing pipeline pressure upgrades to 75 barg □ Writing of pressure systems schemes of inspection for Easington onshore terminal and for Citigen combined heat and power station

Profiles

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Flight Systems Mintech, South Africa 1985-1988 □ Specialised in the manufacturing and installation of diesel engine protection systems for the open cast coal and diamond mining industry in Southern Africa

Profiles

567

JONATHAN FRANKLIN SENIOR PIPELINE ENGINEER BEng (Hons) CEng MIMechE

Date of Birth: Nationality: Education:

12 June 1972 British Brunel University

Academic Qualifications: Professional Qualifications:

Degree in Mechanical Engineering Member of the Institution of Mechanical Engineers Registered Offshore Survival Certificate

Current Position at Jee Limited Jonathan has been working with Jee Limited since June 2006. He is responsible for a range of pipeline engineering project work and the development and presenting of courses.

Specific Expertise and Experience at Jee Limited Jonathan is involved in a wide range of pipeline engineering projects, specialities include: ■ Remnant life assessment ■ Onshore pipeline design assessments ■ Subsea LNG pipelines ■ Failure investigation ■ Pipeline integrity management ■ Subsea insulation systems ■ Defect assessment Pipeline Engineering Studies ■ Perenco – Evaluation of pigging options for Southern North Sea pipeline ■ BP – Development of standards for deepwater pipelines Training courses Jonathan is currently developing a number of new courses for deepwater flowlines and risers.

Overview of pipeline engineering

568

Summary of Previous Experience ■

Advantica (formerly British Gas Research & Technology), 1994-2006 □ Manager of Engineering Analysis team from June 2003. Responsible the financial, project and resource management of a team of engineers undertaking a wide range of static and dynamic analysis for the oil and gas industry. The turnover of the team was typically £2,000,000 per annum. □ Lead technical engineer for implementation of Middle East business plan. Helped to establish Advantica’s integrity business in the Middle East. □ Abu Dhabi Marine Operating Company (Adma Opco) – Zakum and Umm Shaif Fields. Remnant Life Assessment of Offshore Flowlines and Pipelines. Lead engineer for the assessment of over 140 flowlines using probabilistic methods. □ Abu Dhabi Company for Onshore Gas Operations (Gasco) – Asab and Habshan Plants. Failure investigations and process evaluation of large onshore gas processing plants. □ National Grid - Uprating of Feeder 13 of the UK NTS. Site surveying and stress analysis for uprating of high pressure gas transmission pipelines. Finite element analysis of pipeline components. □ Eversheds – Specialist Legal Advice on explosion incidents. □ BG Egypt - Pigging problem advisor. Advisor on a number of offshore and onshore pigging problems. □ BG Group - Subsea LNG pipeline. Evaluated proposed schemes for subsea LNG transport and minimal marine facilities. □ BG Tunisia - Miskar platform. Stress analysis of wellhead pipework. □ Various - Failure Investigations. Root cause investigations and simulated testing. □ National Grid - Fire & Explosion Investigation. Specialist pipeline investigation engineer. Attended over 25 fire and explosion incidents and represented client in court. □ Linepipe Group Sponsored Project - X80 Full-scale Pipeline Testing. Conducted a number of full scale bust tests to validate API 5L X80 material.

Profiles

569

NICK YUNXIAO WANG PIPELINE ENGINEER Phd

Date of Birth: Nationality: Education: Academic Qualifications:

9 July 1965 British University College London PhD in Structural Engineering

Current Position at Jee Limited Nick Yunxiao joined Jee Ltd at the end of June, 2006.

Specific Expertise and Experience at Jee Limited Nick Yunxiao has been involved, since joining Jee Ltd, in the BP West of Shetland Pipeline pullover study – a review and re-assessment of the impact from the changed fishing activity in the area. Particular fields of expertise used in the project include: ■ collate data for various production/gas lift/water injection flowlines from the previous work and from the client ■ identify six typical flowlines for analysis based on the preliminary calculations ■ carry out lateral buckling FE analysis for the chosen flowlines ■ carry out pullover FE analysis for the chosen flowlines ■ carry out hooking FE analysis for the chosen flowlines ■ strain acceptance assessment using OTH 561 ■ write the final report Training courses Nick is currently writing material for a number of new courses for deepwater flowlines and risers.

Summary of Previous Experience ■

KW Ltd, 2002-2006, Principle Engineer □ Post-buckling assessment of 4” Vent and glycol pipelines, Simian and Sapphire Fields. The objectives of the nonlinear finite element analysis were to determine the post-buckling response of idealised imperfection for 4” pipelines, which may arise as a result of the pipe being out of imperfection detection range or insufficient soil cover at known imperfection locations; to estimate the likely range of peak strains in the buckle; and to assess the acceptability of buckled pipe for continued pipeline operation

Overview of pipeline engineering

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Reeling verification and upheaval buckling analysis for Rhum pipe-in-pipe (PIP) system (BP Rhum field development project), taking into account strain history effects associated with reeling installation. The nonlinear finite element analysis was to determine the soil cover requirements for upheaval buckling for the reeled pipe-in-pipe system for various imperfection heights Flowline thermal cyclic studies - lateral buckling and pipeline walking analysis using ABAQUS finite element analysis package, Greater Plutonio Development, BP Angola Block 18; wrote a special FORTRAN programme for ABAQUS to simulate the non-linear behaviour of soil incorporating the mobilisation, break-out and progressive loss of uplift resistance of soil Lateral buckling analysis and pipeline protection design for Munro pipelines (Munro field, North Sea), including detailed FE analyses on the 10’’ pipeline and to conclude whether unacceptable lateral deformations and stress and strain localisations would occur in the pipelines Pipeline protection analysis (dropped object and fishing gear impact) for Saturn pipelines. The objective of the nonlinear finite element analysis is to confirm the suitability of the mechanical protection proposed for the pipeline sections at the tie-in locations according to the type of fishing gear used and the intensity of fishing in the proposed locations, to determine the maximum impact energy that the pipeline and the tie-in spools can withstand, with and without mattress protection, from fishing gear interaction and dropped objects Pipeline protection analysis (dropped object and fishing gear impact) for Horn Wren pipelines; Analysis and assessment of lateral buckling of oil export, water injection and oil transport pipelines, Azeri project, Phase 2 Pipelines, for Mentor Subsea Technology Services Inc. The objective of the study is to assess the safety of the pipeline under specified maximum operational pressure and temperature and to determine mitigation measures with the maximum assurance that lateral buckling would not endanger the operating safety of pipelines Strain based and limit state assessment for high temperature PIP flowline, Shell Howe Field Development Project, using finite element analysis to demonstrate integrity of the PIP system under cyclic operating conditions, taking into account strain history effects associated with reeling installation Lateral buckling analysis and tie-in spool seismic analysis for Baobab deepwater production pipeline system Analysis of lateral buckling and fishing interaction effects (pullover, hooking and lateral buckling analysis) on Simian and Sapphire pipelines, for Genesis Detailed finite element analysis of installation and operating stresses in Gulf of Aqaba crossing pipeline (36” deepwater pipeline), including simulation of pipelay, girth weld ECA to BS7910 and seismic analysis Strain based design of Braemar PIP system, including FE simulation of reeling and in-service response, Engineering Critical Assessment (ECA) of girth welds JIP Phase III fracture and fatigue assessment involving the analysis of test results from various test specimen Stress analysis for Smith Projects involving thermal and dynamic stress assessments of an aeroplane engine

Profiles

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Mott MacDonald, 1996-2002, Senior Engineer □ Complex finite element modeling using with FEMAP □ Finite element dynamic analysis using ABAQUS, STAAD, LUSAS □ In-house software development to predict and display the dynamic response of railway bridges. Awarded the Milne Prize □ Project Engineer for the detailed dynamic analysis of existing bridges on the West Coast Main Line (UK) to determine suitability for the passage of high-speed trains, based on a ballast destabilisation criterion □ Rating of damaged bridges – a field assessment method, including the coding of a software DBAS (Damaged Bridge Assessment System) incorporating the assessment methods developed in the project □ Preparation of program for simulating deep-water pipeline installation for Saipem, including S-lay and J-lay □ Dynamic pushover analysis of jacket structures. The objective of the project is to determine the service and ultimate capacity of the structure subjected to 100-year return environmental forces using ABAQUS finite element package □ Explosion-specific analysis of Blackwall Tunnels, the project was to assess the capacity of the Southbound and Northbound tunnels to withstand explosion incidents from explosives placed inside the tunnels or dropped onto the top of the tunnels □ Dynamic analysis of South Korea Yongjong bridge

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Shanghai Port Machinery Plant, 1989-1996, Assistant Engineer, Engineer, and Senior Engineer □ Supervision of all structural analysis, plus technical software systems □ Structural and dynamic analysis for main projects such as special-purposeportal cranes, 900t-ship unloaders □ In-house software development, such as in-house fatigue assessment software especially coded for SPMP (Shanghai Port Machinery Plant) products □ Research project – On the Application of Modern Design Methods to Port Machinery – sponsored by Shanghai Municipal Government

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Dalian Jiaotong University, 1986-1989, Student □ Post Graduate Student, MSc, Fracture Mechanics

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Guangzhou Maritime School, Lecturer □ Lectured on Theoretical Mechanics, Mechanics of Materials, Engineering Mechanics □ Graded exam papers. □ Supervised laboratory work

Profiles

573

PAUL JOB PIPELINE ENGINEER MEng CEng MIMechE

Date of Birth: Nationality: Education:

13 March 1979 British Exeter College University of Surrey

Academic Qualifications: Professional Qualifications:

Masters degree in Mechanical Engineering Chartered Engineer Member of the Institution of Mechanical Engineers Basic Offshore Safety Induction and Emergency Training (BOSIET)

Current Position at Jee Limited Paul Job joined Jee Limited in 2002. His main responsibilities in the department are based around finite element analysis, design and CAD work for the offshore oil and gas industry, and also presenting and writing training courses for both the public and incompany. Other duties include studies for clients, which commonly involve developing spreadsheets in MathCAD and Microsoft Excel and writing technical reports

Specific Expertise and Experience at Jee Limited Offshore support Paul has provided offshore support in the North Sea, for general imaging surveys of a clients’ pipeline network and development of a new gas field. This included follow-on work to interpret the results, assess the integrity of the pipelines and advise the client of remedial activities required. Flume tank trials Paul has been regularly involved in flume tank trials for clients. These involve arranging fabrication of scale models such as overtrawlable wellhead protection structures and pipelines, and testing their interaction with fishing trawl gear. Data recorded during the tests via Dasylab is then post-processed to determine pullover loads.

574

Overview of pipeline engineering

FEED studies Paul has been involved in a number of FEED studies, which included the steady-state modelling of multiphase pipelines using Pipesim, and finite element analysis for upheaval buckling and overtrawling of pipelines. Finite Element Analysis Paul has worked on a number of FEA jobs since joining Jee, using both ABAQUS and ANSYS. These include analyses as follows: ■ Riser analysis - investigating operational and earthquake loads of the risers supported inside a concrete gravity base structure, to be used on the Sakhalin project. This included a two-week placement based at Aker Kvaerner’s offices in Oslo, Norway. ■ Parametric flexible pipeline analysis, to determine the effect of trenching on the interaction of trawl gear in the North Sea. ■ Analysis of pipe pull, installing a pipeline in a pre-dredged trench using the bottom-tow method ■ Parametric upheaval analysis on a flexible pipeline, to determine an installation methodology to ensure the pipeline does not upheave during hydrotest or operation. ■ Analysis of a hot-tap tie-in to a spoolpiece, to determine the stresses during operation and the allowable hydrotest pressure ■ Analysis to prove a fabricated wye piece fit-for-purpose ■ Parametric thermal analysis of an insulated flexible pipeline Other analysis software Paul has recently been involved in a number of stability analyses using the PRCI/AGA pipeline stability software package, including both flexible and rigid pipelines. He has also completed verification analyses using the marine dynamics program Orcaflex for static and dynamic analysis of flexible pipeline and cable systems in an offshore / marine environment, and also the computational fluid dynamics package CFX. Pipeline training courses Paul has been presenting training courses since September 2003, both in-company and to the public, including Subsea pipeline design, Offshore pipeline construction and Subsea pipeline installation calculations (3 days). These courses have been in various locations around Europe and USA. Paul wrote a one-day overview course on umbilical design, installation and operation towards the end of 2004. Since then he has co-presented the in-house course to Saipem, and it has now been added to the regular courses offered by Jee. Clamp Connector Tool Design Paul has worked on this project for the last three years, developing a tool to install mechanical connectors on subsea pipelines using an ROV. This has included developing the design from concept to a detailed design with fabrication drawings. The tool has now been fabricated and is awaiting final testing. QA System Paul has upgraded Jee’s Quality Assurance System, to ensure it is in compliance with the requirements of ISO 9001:2000.

Summary of Previous Experience Paul worked for Exxon Mobil for one year during his MEng degree course. He worked for their Supply and Distribution Department, which dealt with the operation of a multiproduct onshore pipeline network, distributing oil and gas to storage terminals in the UK. Whilst there, he completed two major projects, the first of which was a study into improving the efficiency of the pumping operation on the network. The second project

Profiles

575

involved the installation and implementation of a condition monitoring system on the pumps, to monitor the condition of shaft bearings.

Profiles

577

DAVID APPLEFORD GRADUATE ENGINEER MEng (Hons) AMIMechE

Date of Birth: Nationality: Education:

15 May 1979 British University of Bristol

Academic Qualifications: Professional Qualifications:

Masters degree in Mechanical Engineering Associate Member of the Institution of Mechanical Engineers Basic Offshore Safety Induction and Emergency Training (BOSIET)

Current Position at Jee Limited David joined Jee Limited in September 2003. His main responsibilities include finite element analysis, performing studies and research projects for clients, developing spreadsheets in MathCAD and Microsoft Excel and writing technical reports. David is continuing to develop his skills in pipeline engineering with the aim of achieving Chartered Engineer status. He has recently attained his Basic Offshore Safety Induction and Emergency Training certificate and is keen to gain some offshore experience on survey or pipelay vessels. He has also attended an LRQA Internal QMS Auditor Course and is involved in performing internal audits for Jee limited. He was also involved with developing the new Jee Limited website www.jee.co.uk.

Specific Expertise and Experience at Jee Limited Finite element analysis Since being trained by ABAQUS in August 2004, David has worked on several FEA jobs. These have included: ■ Analysis of the vibration of subsea flow termination assemblies ■ Verification of the fitness-for-purpose of fabricated wye pieces applicable to generic class 600 pipeline systems ■ Verification of the fitness-for-purpose of mechanical pipeline connectors ■ Spool piece design – Analysis of tie-in spool pieces to determine loads due to pipeline end expansion ■ Manifold design – In-place and installation analyses of a manifold and associated ladder frame support

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578

■

Assessment of the effects of coating eccentricity on the overall heat transfer coefficients of pipelines and the cool-down performance through a comparative study between concentric and eccentric pipe coatings

Engineering Studies David has undertaken a series of fishing interaction studies for clients. These have involved: ■ Scale model testing of subsea protective structures ■ Investigating ways to improve fishermen’s awareness of subsea obstacles and the consequences of their interaction ■ Gathering fishing data from a number of sources across Europe, Africa and the Middle East ■ Calculating fishing gear pullover loads, impact energies and dent assessment ■ FEA of pipeline pullover response and trawl door hooking During his time at Jee Limited, David has also worked on the development of a Microsoft Excel and Visual Basic spreadsheet to analyse deepwater pipe-lay capabilities of pipelay vessels and has also been involved in writing various MathCAD calculation sheets.

Pipeline stability David has been involved in a number of stability analyses using the PRCI/AGA stability software package, including both flexible and rigid pipelines. In addition he has done calculations on vortex-induced-vibrations and has performed a study on the effectiveness of self-burial-spoilers in the Southern North Sea. Training courses Since joining Jee Limited David has attended the following pipeline engineering training courses: ■ ■ ■ ■

Overview of Pipeline Engineering Offshore Pipeline Construction Pipeline Operations and Integrity Management Subsea Pipeline Design

He has also been trained in using the finite element analysis package ABAQUS and in using the marine dynamics program Orcaflex for static and dynamic analysis of flexible pipeline and cable systems in an offshore / marine environment. Recently David was involved in writing a half-day training course on the use of BP’s pipeline related Engineering Technical Practices. Other experience at Jee Limited David has attended an LRQA Internal QMS Auditor Course and is now involved in performing internal audits for Jee Limited. He was also involved with developing the new Jee Limited website www.tja.co.uk.

Profiles

579

GRAHAM WILSON GRADUATE ENGINEER MEng AMIMechE

Date of Birth: Nationality: Education: Academic Qualifications: Professional Qualifications:

11th June 1981 British Runshaw College Lancaster University Masters degree in Mechanical Engineering Associate Member of the Institution of Mechanical Engineers

Current Position at Jee Limited Graham joined Jee limited in October 2004 as a Graduate Engineer. Since then he has started a structured training program to develop his skills in pipeline engineering, aiming to achieve chartership with the IMechE through the MPDS scheme. His main responsibilities at Jee Limited include performing studies and research projects for clients, developing MathCAD and Microsoft Excel design sheets and writing technical reports.

Specific Expertise and Experience at Jee Limited Pipeline engineering studies In his time with Jee Limited, Graham has worked on a number of different studies and activities, including: ■ The design and development of a test rig to analyse the fatigue effects of acoustic resonance on a FTA ■ MathCAD modelling of a pig and slug train impact on a variety of riser bends ■ The development of a series of MathCAD design sheets, covering: □ Stabilisation of rigid and flexible pipelines □ Use of rockdump stitches to prevent lateral buckling in rigid pipelines and pipe-in-pipe systems □ Wall thickness design to various design codes □ Design of pipeline crossings ■ Investigation of a number of subsea flange leaks and recommendations for repair ■ Analysis of pipeline freespans for vortex induced vibrations and fatigue ■ Structural sacrificial anode design ■ Pipeline stability assessment using the PRCI/AGA pipeline stability software

580

Overview of pipeline engineering

Fishing interaction ■ Graham has undertaken a series of fishing interaction studies for clients, which have involved: ■ Gathering fishing data from a number of sources across Europe, Africa and the Middle East ■ The calculation of fishing gear pullover loads, impact energies and dent assessment ■ FEA of pipeline pullover response and trawl door hooking He has also been involved in a number of scale model flume tank trials, assessing the overtrawlability of a range of subsea protection structures. Finite Element Analysis After successfully completing the ABAQUS training course, Graham has worked on a number of FEA jobs. These have included the assessment of installational and operational loads on a range of pipeline components, as well as performing trawl gear pullover and hooking analyses for a series of pipelines in both the North Sea and the Mediterranean. Other analysis software After completion of an in house Orcaflex training course, Graham has been involved in the development of dynamic riser analysis exercises for the Jee Riser design training course. He has also completed pipeline stability analyses using the PRCI/AGA pipeline stability software and performed flow analysis using Pipesim. Training courses Since joining Jee Limited, Graham has attended the following Jee pipeline engineering training courses: ■ Overview of Pipeline Engineering ■ Offshore Pipeline Construction ■ Subsea Pipeline Design ■ Installation Calculations ■ Pipeline Operations and Integrity Management Graham has also been involved in the development of the Subsea Pipeline Design course exercises. He has also written modules and material for a Technip in-company course. Other experience at Jee Limited As part of the Jee quality procedures, Graham is responsible for the non-conformance review, which aims to identify any trends in the problems encountered by the company that could be prevented. Graham has also received training in the use of PRISM integrity management software.

Acronyms & abbreviations

582

Overview of pipeline engineering

Acronyms & abbreviations

+ve -ve °C °F 30D 3D 3rd AC AGA AGI Al ALARP ALS ANSI API approx. ASB ASD ASME AUV AVTUR Bar g BAT bbl BHP BLEVE BMP BOP BP bpd BPEO BS C2H4 C2H6 C3H6 C3H8 C4H10 C5H12 C6H5CH3 C6H6 C6H14 C10H8 CA CALM CAPS CBM CDT CDTM CDUs CFD CH4 CHP

positive negative degree Celsius degree Fahrenheit bend radius of 30 times the pipe diameter three-dimensional Third Alternating Current American Gas Association Above-Ground Installation Aluminium As Low As Reasonably Possible Accidental Limit State American National Standards Institute American Petroleum Institute approximate Above SeaBed Allowable Stress Design American Society of Mechanical Engineers Autonomous Underwater Vehicle Aviation Turbine (fuel) Bar gauge (1 bar = 100 kN/m²) Best Available Technology US oil barrel (1 bbl = 0.159 m³) Brake Horse Power (1 BHP = 745.7 W) Boiling Liquid, Expanding Vapour, Explosion Best Management Practice Blow-Out Preventer British Petroleum Ltd barrels per day Best Practical Environmental Option British Standard Ethene (Ethylene) Ethane Propene (Propylene) Propane Butane or Isobutane Pentane or Isopentane Toluene Benzene n-Hexane Napthalene Corrosion Allowance Catenary Anchor Leg Mooring Cranfield Automated Pipe-welding System Conventional Buoy Mooring Controlled Depth Tow Controlled Depth Tow Method Crude oil Distillation Units Computational Fluid Dynamics Methane Combined Heating and Power

583

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CITHP Cl2 CNS CO CO2 COMAH CP cP CPF CPT CRA CRT cSt CSO CSOL CTE CTOD D/t DC DD dia, diam. DIN DMaC DnV DP DPI DRA DSAW DSV DTI DWT ECA EIA EIS EMIT EN EOR EP EPDM ERD ERP ERW ESD ESDV ESIA ETAP ESV FBE FEA FEED FEHM FHM Fi Fi FLAGS

Overview of pipeline engineering

Closed-In Tubing Head Pressure Chlorine Central Nervous System Carbon Monoxide Carbon Dioxide Control Of Major Accident Hazards Cathodic Protection or Code of Practice Centipoise (1 cP = 1 x 10-3 Pa·s) Central Processing Facitlity Cone Penetrometer Test Corrosion Resistant Alloy Cathode Ray Tube CentiStokes (1 cSt = 1 x 10-6 m2/s) Coflexip Stena Offshore Coflexip Stena Offshore Limited Coal -Tar Enamel Crack Tip Opening Displacement Diameter to wall thickness (ratio) Direct Current Directional Drilling diameter Deutsches Institut für Normung e.V. (German standards) Diverless Maintained Cluster (connection system) Det Norske Veritas Dynamic Positioning (vessel) Dye Penetrant Inspection Drag Reduction Agent Double Submerged Arc Welding Diver Support Vessel Department of Trade and Industry Dead Weight Tonnage Engineering Criticality Assessment Environmental Impact Assessment Environmental Impact Statement Examination, Monitoring, Inspection and Testing Euronorm Enhanced Oil Recovery Evacuation Plan Ethylene Propylene Diene Monomer Extended Reach Drilling Emergency Recovery Plan Electrical Resistance Welding Emergency Shut-Down Emergency Shut-Down Valve Environmental and Social Impact Assessment Eastern Trough Area Project Emergency Shut-down Valve Fusion Bonded Epoxy Finite Element Analysis Front End Engineering Design Fire and Explosion Hazard Management Fire Hazard Management Fire Fighting Far north Associated Gas System

Acronyms & abbreviations

FLS FP FPS FPSI FPSO FRSU FRP FSM FSO ft gal US GAEL GBS GCHPL GEBCO GIS GMAW GoM GOR GPR GPSS GRP GSPU GTAW H2 H2O H2S HAL HAT HAZ HAZAN HCl HCV HDD HDPE He HEPC HFI HFW HIC HICC HIPPS HP HP/HT HSE ID IFC in IP ISGOTT ISO JIP JONSWAP KP

Fatigue Limit State Foam Pourers or FluoroProtein Forties Pipeline System Forties Pipeline System and Infrastructure Floating Production Storage and Offloading (facility) Floating Regasification and Storage (unit for LNG) Fibre Reinforced Plastic Field Signature Measurement (or Method) Floating Storage and Offloading (facility) foot (1 ft = 0.3048 m) US gallon (1 gal US = 3.785 litre) Graben Area Export Line Gravity Based Structure Grangemouth Combined Heat and Power Limited GEneral Bathymetric Chart of the Oceans Geographic Information System Gas Metal Arc Welding Gulf Of Mexico Gas Oil Ratio Ground Penetrating Radar Government Pipeline and Storage System (UK) Glass-Reinforced Plastic Glass Syntactic PolyUrethane Gas Tungsten Arc Welding Hydrogen Water Hydrogen Sulphide Hiden Analytical Limited Highest Astronomic Tide Heat Affected Zone HAZard ANalysis Hydrogen Chloride Hydrant Control Valve Horizontal Directional Drilling High Density PolyEthylene (PE-HD) Helium Hose End Pressure Coupling High Frequency Induction High Frequency Welding Hydrogen-Induced Cracking Hydrogen-Induced Corrosion Cracking High Integrity Pressure Protection System High Pressure High Pressure/High Temperature Health and Safety Executive Internal Diameter International Finance Corporation inch (1 in = 25.4 mm) Institute of Petroleum or Inspection Plan International Safety Guide for Oil Tankers and Terminals International Standards Organisation Joint Industry Project JOint North Sea WAve Project Kilometre Point (chainage in km)

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LAFB LAT LCP LFS LFSS LHD LLDPE LNG LP LPG lpm LRFD LRP M MAOP MATIS max MDPE MEG MFL MIG mil mile min MMA MMboe MMscfpd MOL MP MPI MPRE MSL N° N2 NACE Nd NDT NFPA NGL NGO NH3 NNF NPSH NUI OD OHTC op. OPA OTDR PCR PD PDF PDQ PE

Overview of pipeline engineering

Local Authority Fire Brigade Lowest Astronomical Tide Lack of Cross Penetration Lack of Fusion Surface Lack of Fusion Subsurface Linear Heat Detection Linear Low Density PolyEthylene Liquid Natural Gas Low Pressure Liquefied Petroleum Gas Litres Per Minute Load and Resistance Factor Design Lead Replacement Petrol Monitors Maximum Allowable Operating Pressure Modular Advanced Tie-In System maximum Medium Density PolyEthylene Mono Ethylene Glycol Magnetic Flux Leakage Metal Inert Gas (welding) thousandth of an inch (1 mil = 25.4 μm) 1 mile = 1.609 km minimum or minute Manual Metal Arc (welding) Million barrels of oil equivalent Million standard cubic feet per day (gas flow) Main Oil Line Medium Pressure Magnetic Particle Inspection Military Pipeline Repair Equipment Mean Sea Level number Nitrogen National Association of Chemical Engineers Neodymium Non-Destructive Testing National Fire Protection Association Natural Gas Liquid Non-Governmental Organisation Ammonia Normally No Flow Net Positive Suction Head Normally Unattended Installation Outer Diameter Overall Heat Transfer Coefficient operating Oil and Pipelines Agency (UK) Optical Time-Domain Reflectometry Pipeline Cost Reduction Positive Displacement (flow meters) Probability Density Function Production, Drilling and Quarters (platform areas) PolyEthylene

Acronyms & abbreviations

PFP PGD PIMS PL PLEM PP PPA PPE PPF ppm psi PSV PU PUF QC/DC RAO RD ROT ROV ROW RP RTU SAC SAGE SALM SAW SAWL SAWH SBM SCADA SCC SCR sec SFR SG SIWP SLS SMAW SMYS SPM SPU SRB SS SSC SSIV SSSI TAPS TARA TFHE Tg Ti TIG TLP TMAW TMS

Passive Fire Prevention Permanent Ground Deformation Pipeline Integrity Management System Pipeline PipeLine End Manifold Polypropylene Pressure Point Analysis Personal Protection Equipment PolyPropylene Foam parts per million pounds per square inch (1 psi = 0.069 bar) Pressure Safety Valve PolyUrethane PolyUrethane Foam Quick Connect/Disconnect (coupling) Response Amplitude Operators Relative Density Remotely Operated Tool Remotely Operated Vehicle Right Of Way Reference Publication or Recovery Plan Remote Terminal Unit Special Area of Conservation Scottish Area Gas Evacuation Single Anchor Leg Mooring Submerged Arc Welding Submerged Arc Welding (Longitudinal seam) Submerged Arc Welding (Helical seam) Single Buoy Mooring (See SPM) Supervisory Control And Data Acquisition Stress Corrosion Cracking Steel Catenary Riser second Strategic Fuel Reserve Specific Gravity Shut-In Wellhead Pressure Serviceability Limit State Submerged Metal Arc Welding Specified Minimum Yield Stress Single Point Mooring (See SBM) Syntactic PolyUrethane Sulphuate Reducing Bacteria Stainless Steel Sulphide Stress Cracking SubSea Isolation Valve Site of Special Scientific Interest Trans-Alaska Pipeline System TArtan Riser Access Tactical Fuel Handling Equipment Glass transition temperature Titanium Tungsten Inert Gas (welding) Tethered or Tensioned Leg Platform Tungsten Metal Arc Welding Tethered Managament System (for ROVs)

587

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TOFD TOM TRB TRF U/C UD UI UK UKCS UKOOA ULS ULSD UOE USA UT UTS V VIV VP X52, X65, X80 YAG ΔP σeq σh σl

Overview of pipeline engineering

Time of Flight Diffration Total Oil Marine Through (or Three) Roller Bending Thermal Radiation Flux Undercut Uni-directional Ultrasonic Inspection United Kingdom United kingdom Continental Shelf United Kingdom Offshore Operators Association Ultimate Limit State Ultra-Low Sulphur Diesel U-ing, O-ing and Expanding (method of pipe manufacture) United States of America Ultrasonic Testing or Thickness (measurement) Ultimate Tensile Strength Vanadium or Volt Vortex-Induced Vibration Vapour Pressure API pipe steel grades Yttrium Aluminium Garnet Change in pressure Equivalent Stress Hoop Stress Longitudinal Stress

Acknowledgements & references

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Overview of pipeline engineering

Acknowledgements and references

591

The following companies have kindly provided images, videos or help with this course. Their help is gratefully acknowledged.

ABANDONRITE Enviro Services Nabors Industries Inc 3000, 500 - 4th Avenue S.W. Calgary Alberta T2P 2V6 Tel +1 (403) 508-7900 Fax: +1 (403) 508-7909 Email [email protected] www.abandonrite.com ACERGY MS LTD (Formerly Stolt Offshore) (MATIS Modular Advanced Tie-In System and Talon Trencher) Dolphin House Windmill Road Sunbury-on-Thames Middlesex UK TW16 7HT Tel: +44 1932 773700 Fax: +44 1932 773701 www.acergy-group.com ABAQUS FINITE ELEMENT SOFTWARE 1080 Main Street Pawtucket RI 02860-4847 Tel: +1 (401) 727 4200 Fax: +1 (401) 727 4208 E-mail: [email protected] ADAS ENVIRONMENTAL MANAGEMENT SERVICES Woodthorne Wergs Road Wolverhampton WV6 8TQ Tel: +44 (1902) 754 190 Fax: +44 (1902) 743 602 www.adas.co.uk ADVANTICA TECHNOLOGIES LTD (Study for Shah Deniz in Azerbaij – with BP and Transco) Ashby Road Loughborough Leicester LE11 3GR Tel: +44 (1509) 282 000 Fax: +44 (1509) 283 131 E-mail: [email protected] www.advanticatech.com

ALLSEAS GROUP SA (Solitaire and Lorelay Laybarges, Digging Donald & Trenchsetter) 81, Route de la Coula CH 1618, Chatel-st. Denis SWITZERLAND Tel: +41 (21) 9489191 Fax: +41 (21) 9489141 E-mail: [email protected] www.allseas.com ALYESKA PIPELINE SERVICE COMPANY (Trans-Alaska Pipeline System, or TAPS) 1835 South Bragaw St MS-542 Anchorage Alaska 99512 www.alyeska-pipe.com ARCELOR RPS - Sheet Piling 66, rue de Luxembourg L-4009 Esch/Alzette (Luxembourg) Tel: (+352) 5313-3105 Fax: (+352) 5313-3290 E-mail: [email protected] www.sheet-piling.arcelor.com APPLIED INSPECTION LTD (NDT) Applied House Old Colliery Lane Holmewood Chesterfield Derbyshire S42 5RB Tel: +44 (1246) 851864 Fax: +44 (1246) 852243 E-mail: [email protected] www.appliedinspection.co.uk AQUADEVICE Yokota Manufacturing Co Ltd. 1-3-6 Minami Yoshijima Naka-ku Hiroshima Japan Tel: +81 82-241-8672 Fax: +81 82-504-1115 www.aquadevice.com

Overview of pipeline engineering

592

ARC MACHINES, INC (Automatic pipe welding equipment) 10500 Orbital Way Pacoima CA 91331 USA www.arcmachines.com ARCELOR RPS UK LTD (Sheet steel piling) Queensway Business Centre Dunlop Way Scunthorpe North Lincolnshire, UK DN16 3RN Tel: +44 (870) 770 8057 Fax: +44 (870) 770 8059 E-mail: [email protected] www.sheet-piling.arcelor.com ASHTON GATE ENGINEERING LTD (Hot pipe bending, fabrication welding and tube rolling) Baynton Road Ashton Bristol BS3 2EB Tel +44 (117) 966 1337 Fax +44 (117) 953 8496 Email [email protected] www.ashtongateeng.co.uk ASPLUNDH TREE EXPERT CO 708 Blair Mill Road Willow Grove PA 19090 Tel +1-800-248-TREE (8733) www.asplundh.com BIG INCH MARINE SYSTEMS INC A Subsidiary of Stolt Offshore Inc (Flexiforge connector) Northwoods Industrial Park West 12235 FM 529 Houston Texas 77041-2806 Tel: +1 (713) 896 1501 Fax: +1 (713) 466 1283 E-mail: [email protected] www.big-inch.com

BOSKALIS OFFSHORE BV Rosmolenweg 20, PO Box 43 3350 AA Papendrecht The Netherlands Tel: +31 78 696 9011 Fax: +31 78 696 9571 E-mail: [email protected] www.boskalis.nl or WESTMINSTER DREDGING COMPANY Westminster House Crompton Way Segensworth West Fareham Hants PO15 5SS Tel: +44 1489 885 933 Fax: +44 1489 578 588 Email: [email protected] www.boskalis.co.uk BJ PROCESS AND PIPELINE SERVICES Beeston Royds Industrial Estate Geldered Road Leeds LS12 6EY Tel: +44 (113) 251 1300 Fax: +44 (113) 251 1391 www.bjservices.com BP PLC (Study for Shah Deniz in Azerbaij – with Advantica and Transco) 1 St James's Square London SW1Y 4PD Tel: +44 (207) 496 4000 Fax: +44 (207) 496 4630 www.bp.com BREDERO PRICE COATERS LTD (BPCL) Bredero House Imperial Dock Leith, Edinburgh EH6 7DT Tel: +44 (131) 553-9640 Fax: +44 (131) 553-9699 www.bredero-shaw.com BRITISH GAS (Walney Channel crossing Case Study) See Transco R J BROWN See Technip-Coflexip

Acknowledgements and references

CCP (CORROSION CONTROL PRODUCTS COMPANY) AND PACTIV CORPORATION (Rockguard foam pipe coating) 1480 West Artesia Blvd Gardena CA 90248-3215 Tel: +1 (310) 532-9314 Fax: +1 (310) 532-1472 E-mail: [email protected] www.farwst.com/ccp CLOCK SPRING COMPANY, LP (Pipeline repair) 14107 Interdrive West Houston, TX.77032 Tel: +1 (281)-590-8491 Fax: +1 (281) 590 9528 E-mail: [email protected] www.clockspring.com COBHAM FLUID SYSTEMS Holland Way Blandford Forum Dorset UK DT11 7BJ Tel: +44 (0) 1258 486600 Fax: +44 (0) 1258 486601 [email protected] www.cobhamfluidsystems .com COFLEXIP SA See Technip-Coflexip CONOCO FLOW IMPROVER SOLUTIONS (LiquidPower™ DRA, Texaco Basin Case Study and Heidrun drilling riser) Conoco Center 600 North Dairy Ashford Houston, TX 77079 Tel: +1 (281) 293-1000 Fax: +1 (281) 293-1440 www.conoco.com CORRIDOR PIPELINE LTD (Case study Bruderheim Alberta) Springwood Business Centre Suite 14, 363 Sioux Road Sherwood Park Alberta T8A 4W7 Tel: +1 (780) 416 2446 Fax: +1 (780) 416 2447 E-mail: [email protected] www.corridorpipeline.com CORROSION CONTROL PRODUCTS COMPANY See CCP

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CORROCEAN Teglgaarden Hornebergvn 7 Trondheim Norway Tel: +47 73 82 5000 Fax: +47 73 82 5050 CORROSION COST CC Technologies 6141 Avery Road Dublin Ohio 43016-8761 Tel: +1 (614) 761 1214 Fax: +1 (614)-761-1633 E-mail: [email protected] www.corrosioncost.com CORTEC® CORPORATION (Corrosion inhibitor) 4119 White Bear Parkway St. Paul, MN 55110 Tel: +1 (651) 429 1100 Fax: +1 (651) 429 1122 www.cortecvci.com CORUS (Steel & Hydrotherm) 30 Millbank London SW1P 4WY Tel: +44 (20) 7717 4444 Fax: +44 (20) 7717 4455 www.corusgroup.com CRANFIELD UNIVERSITY Cranfield Bedfordshire MK43 OAL Tel: +44 (1234) 750 111 Fax: +44 (1234) 750 875 www.cranfield.ac.uk CREST See Sapura Crest CRC-EVANS PIPELINE INTERNATIONAL INC (Automatic welding, pipe installation equipment and PIH) 11601 N. Houston-Rosslyn Rd Houston TX 77086 Tel: +1 (281) 999 8920 Fax: +1 (281) 999 8724 or

594

AUTOMATIC WELDING The Pipeline Centre Farrington Rd Rossendale Road Industrial Estate Burnley BB11 5SW Tel: +44 (1282) 415 323 Fax: +44 (1282) 457 890 E-mail: [email protected] CRP GROUP LIMITED (Now part of the Trelleborg Group) Stanley Way Stanley Skelmersdale Lancashire WN8 8EA England Tel: +44 (0)1695 712000 Fax: +44 (0)1695 712111 www.crpgroup.com CSO, CSOL See Technip-Coflexip CTC MARINE PROJECTS LTD (Trenching equipment) Coniscliffe House Coniscliffe Road Darlington County Durham DL3 7EE England Tel: +44 (0) 1325 390500 Fax: +44 (0) 1325 390555 www.ctcmarine.com DIGGING DONALD AND SUPPORT VESSEL, TRENCHSETTER (Mechanical subsea trencher) See Allseas DIXON MARINE CONSULTING LTD 11 White Hart Street Aylsham Norwich Norfolk NR11 6HG Tel: +44 (1263) 733 530 Fax: +44 (1263) 733 730 E-mail: [email protected] www.dmcltd.com

Overview of pipeline engineering

DSND SUBSEA (DET SONDENJFELDS NORSKE DAMPSKIBSSELSKAB) (Vessels) Serviceboks 506 Bark Silasvei 5 4898 Grimstad, Norway Tel.: +47 37 29 55 00 Fax: +47 37 29 55 45 www.dsnd.no EMC EUROPEAN MARINE CONTRACTORS LTD (Now part of Eni Saipem group) Saipem House Station Road Motspur Park Surrey KT3 6JJ Tel: +44 (0) 20 - 8296 5171 Fax: +44 (0) 20 - 8296 5104 E-mail: [email protected] www.e-m-c.co.uk EPRIS INTERNATIONAL LTD (Emergency pipeline repair and isolation system) Middlefield Road Middlefield Industrial Estate Falkirk FK2 9HU Tel: +44 (1324) 623 682 Fax: +44 (1324) 632 570 E-mail: [email protected] www.eprisinternational.com ESSO PETROLEUM (Chad-Camaroon pipeline and UK multi-product lines) ExxonMobil House Ermyn Way Leatherhead KT22 8UX Tel: +44 (1372) 222000 www.esso.com EUROPIPE Formerstraße 49 40878 Ratingen, Germany Tel: +49 (2102) 857 0 Fax +49 (2102) 857 285 E-mail: [email protected] www.europipe.com

Acknowledgements and references

FINE TUBES LTD Estover Works Plymouth Devon, UK, PL6 7LG Tel: +44 (1752) 735 851 Fax +44 (1752) 733 301 E-mail: [email protected] www.finetubes.com FLEXCOM & FREECOM 3D OFFSHORE SOFTWARE See MCS International FMC KONGSBERG OFFSHORE (UTIS - Universal Tie-In System) (An FMC Corporation Subsidiary) PO Box 1012 N-3601 Kongsberg, Norway Tel: +47 32 73 98 98 Fax: +47 32 73 96 60 E-mail: [email protected] www.fmckongsbergsubsea.com FMC MEASUREMENT SOLUTIONS (Oil and gas flowmeters) 6677 Gessner Suite 315 Houston TX 77040 Tel: +1 (713) 510 6970 E-mail: [email protected] www.fmcmeasurementsolutions.com FORCE TECHNOLOGY Park Alle 345 DK-2605 Brondby Denmark Tel. +45 4326-7000 Fax +45 4326-7011 www.force.dk FOSTER WHEELER PETROLEUM DEVELOPMENT (Kadanwari Field Case Study) Shinfield Park Reading Berkshire RG2 9FW Tel: +44-(118) 913 1234 Fax: +44-(118) 9132333 www.fwc.com

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FOUNDOCEAN (Formerly SeaMark Systems Ltd) Ledger House Forest Green Road Fifield Maidenhead, Berks SL6 2NR Tel: +44-(0) 1628 788614 Fax: +44-(0) 1628 788604 www.foundocean.com www.seamarksystems.com FUEL SUBSEA ENGINEERING (DMaC umbilical connector tool) (Now part of Intec Engineering/Heerema) Bourne House Lansbury Estate 102 Lower Guildford Road Knaphill Surrey GU21 2EP Tel +44 (1483) 795300 Fax +44 (1483) 795315 www.fuelsubsea.com FUGRO NV Veurse Achterweg 10 P.O. Box 41 2260 AA Leidschendam Tel: +31 (70) 311 1422 Fax: +31 (70) 320 2703 E-mail: [email protected] www.fugro.nl GEO-GRAF, INC (GPR gas pipeline leak detection) 511 Beechwood Drive Kennett Square PA 19348 Tel: +1 800 690 3745 Fax: +1 (610) 444 3191 E-mail: [email protected] www.geo-graf.com GEOLINE APS Sage Profile (Subsea pipeline analysis) Vinagervej 11, 1 2800 Kgs, Lyngby Denmark Tel: +45 45875855 Fax: +45 45875855 E-mail: [email protected] www.geoline.dk

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GETMAPPING PLC (Aerial photography) The Old Toy Factory 10 The Business Park Jackson Street Coalville LE67 3NR Tel: +44 (1530) 835 685 www.getmapping.com GUSTO MSC INC and IHC GUSTO BV (Now part of SBM Offshore group) See SBM www.gusto.nl HDI HORIZONTAL DRILLING INTERNATIONAL INC (Colville River HDD case study) 3430 Rogerdale Road Houston TX 77042-5016 Tel: 713-785-3369 Fax: 713-785-4094 www.hdiinc.com HEAMAN PIPE BENDING INC 6030 - 30 Street Edmonton Alberta Canada Tel: +1 (780) 440 1955 Fax: +1 (780) 468 6117 E-mail: [email protected] www.heaman.com HEAT TRACE LTD (Pipeline heat tracing) Cromwell Road Bredbury Stockport Cheshire SK6 2RF Tel: +44 (161) 430 8333 Fax: +44 (161) 430 8654 Email: [email protected] www.heat-trace.ltd.uk HEEREMA MARINE CONTRACTORS NEDERLAND BV (Balder laybarge) Vondellaan 47 2332 AA Leiden The Netherlands Tel: +31 (71) 579 9000 Fax: +31 (71) 579 9099 E-mail: [email protected] www.heerema.com

Overview of pipeline engineering

HELIX ENERGY SOLUTIONS GROUP, INC (Well operations, production and Caldive) 400 North Sam Houston Pkwy East Houston Texas 77060 USA Tel: +1 (281) 618 0400 www.helixesg.com HYDRATITE SWEENEY (Morgrip subsea connectors) Bentley Road South Darlaston West Midlands WS10 8LQ Tel: +44 (121) 505 0600 Fax: +44 (121) 505 0800 E-mail: [email protected] www.hydratightsweeney.com INTERLIANCE LLC. Associates for the California Energy Commission (Gulf Coast to California Pipeline Case Study) 151 Kalmus Drive, Suite K-2 Costa Mesa California 92614 Tel: +1 (714) 540 8889 Fax: +1 (714) 540 6113 E-mail: [email protected] www.interliance.com ITAS (Pigging and isolation plugs) Tankbåtveien 1 4056 Tananger Norway Tel: +47-51 69 08 00 Fax: +47-51 69 08 01 E-mail: [email protected] www.itas-no.com ITP INDUSTRIAL THERMO POLYMERS LTD (Pipeline insulation) 2316 Delaware Avenue Suite 216 Buffalo NY 14216 Fax: +1 (905) 846 0363 Tel: +1 800 387 3847 www.tundrafoam.com

Acknowledgements and references

JME LTD (NDT equipment) Crown House Crown Street West Lowestoft Suffolk NR32 1SG Tel: +44 (1502) 500 969 Fax: +44 (1502) 511 932 E-mail: [email protected] www.jme.co.uk KONGSBERG (UTIS - Universal Tie-In System) See FMC Kongsberg LAND AND MARINE PROJECT ENGINEERING LTD (Directional drilling, landfalls and bundles) (Formerly part of Costain / Smit Groups) Dock Road North Bromborough Wirral Merseyside CH62 4LN Tel: +44 (151) 641 5600 Fax: +44 (151) 641 9990 www.landandmarine.com LASMO PLC Now part of Eni Saipem Group (Kadanwari Field Case Study) 101 Bishopsgate London EC2M 3XH Tel: +44 (20) 7892 9000 Fax: +44 (20) 7892 9292 www.lasmo.com LEIGH PAINTS Tower Works Kestor Street Bolton BL2 2AL Tel: +44 (1204) 521 771 Fax: +44 (1204) 382 115 E-mail: [email protected] www.wjleigh.co.uk LIFTEX CORPORATION (Pipeline lifting slings) 7266 Wynnpark Houston, TX 77008 Tel: +1 (800) 863 0900 Fax: +1 (713) 868 3234 www.liftex.com

597

LINCO EQUIPMENT INC (Mobile soil sampling) I-39 & U.S. 24 West El Paso IL 61738 Tel: +1 (309) 527 6455 Fax: +1 (309) 527 6600 E-mail: [email protected] www.linco.com LØGSTØR RØR A/S (Pre-insulated pipelines, pipe-in-pipe) Løgstør Rør A/S Danmarksvej 11 DK-9670 Løgstør Tel.: +45 99 66 10 00 Fax: +45 99 66 11 80 E-mail: [email protected] www.logstor.com MCCONNELL DOWELL (Natural Gas Line Australia) Tally Ho Business Park 16 Lakeside Drive Burwood East Victoria 3151 Australia Tel: + 61 3 8805 5200 Fax: +61 3 8805 5376 www.mcconnelldowell.com MACCAFERRI LTD (Gabions and geotextiles, Severn River Bank - Case Study) 7400 The Quorum Oxford Business Park Garsington Road Oxford OX4 2JL Tel: +44 (1865) 770 555 Fax: +44 (1865) 774 550 www.maccaferri.co.uk MAT AND TIMBER SERVICES Division of Sarum Hardwood Structures Ltd 124-126 Stockbridge Road Winchester Hampshire SO22 6RN Tel.: +44 (1962) 87 75 00 Fax: +44 (1962) 84 22 92 E-mail: [email protected] www.grootlemmer.com/GrootNL/Mats.htm MATIS MODULAR ADVANCED TIE-IN SYSTEM See Stolt Comex Seaway

598

MCS INTERNATIONAL (Flexcom & Freecom 3D offshore software) Lismoyle House Merchants Road Galway Ireland Tel: +353 (91) 566 455 Fax: +353 (91) 566 457 E-mail: [email protected] www.mcs-international.co.uk MERLIN CONNECTORS See Oil States Industries MILLER ELECTRIC MANUFACTURING CO (Welding equipment) 1635 W Spencer St PO Box 1079 Appleton WI 54912-1079 Tel: +1 (920) 734 9821 www.millerwelds.com MOLESEYE LTD (Records of underground services) Washington Court Washington Lane Edinburgh EH11 2HA www.moleseye.com MORGRIP (Underwater connector) See Hydratight Sweeney NKT FLEXIBLES I/S (Flexible subsea pipelines) Priorparken 510 DK-2605 Broendby Denmark Tel: +45 43 48 30 00 Fax: +45 43 48 30 10 E-mail: [email protected] www.nktflexibles.com NORFRA A/S (Dunkirk landfall) Strandveien 106 N-9292 Tromsø Norway Tel: +47 77 60 24 00 Fax: +47 77 60 24 25 E-mail: [email protected] www.norfra.no

Overview of pipeline engineering

OIL STATES INDUSTRIES LTD (Merlin pipe connectors) 7701 South Cooper Street Arlington, TX 76001 Tel: +1 817 548 4200 Fax. +1 817 548 4250 E-mail: [email protected] www.oilstates.com OLYMPIC PIPELINE COMPANY (Whatcom Creek / Bellingham Gas Pipeline Case Study) 2319 Lind Ave SW Renton WA 98055 Tel: +1 (425) 235 7736 www.olypipeline.com ORCINA LTD (Orcaflex software) Daltongate Ulverston Cumbria LA12 7AJ Tel: +44 1229 584742 Fax: +44 1229 587191 E-mail: [email protected] www.orcina.com PACTIV CORPORATION See CCP PETROBRAS Maracal Adhemar de Queiroz EDISE Avenida Republica do Chile 65 Centro Rio de Janeiro RJ Brasil Tel: +55 (21) 2534 4477 Fax: +55 (21) 2534 2288 www.petrobras.com.br PII PIPELINE SOLUTIONS Atley Way North Nelson Industrial Estate Cramlington Northumberland NE23 1WW Tel: +44 191 247 3486 Fax: +44 191 247 3419 www.piigroup.com PIPE INDUCTION HEAT LTD (PIH) See CRC-Evans

Acknowledgements and references

PSI PLUGGING SPECIALISTS INTERNATIONAL AS (Smartplug) Fabrikkveien 15 PO Box 8011 Postterminalen N-4068 Stavanger Norway Tel: +47 51 44 32 40 Fax: +47 51 44 32 41 www.plugging.com RAHCO INTERNATIONAL INC (Onshore pipeline construction vehicle) 8700 N Crestline Spokane WA 99217 Tel: +1 (509) 467 0770 Fax: +1 (509) 466 0212 E-mail: [email protected] www.rahco.com RENDA MARINE INC (Marshland dragline and dredging) 17128 Market Street Channelview TX 77530 Tel: +1 (281) 864 9552 Fax: (281) 864 9554 E-mail [email protected] www.rendamarine.com R J BROWN See Technip-Coflexip ROCKWATER (CDT) See Haliburton Subsea – now Subsea 7 ROYAL DUTCH SHELL GROUP See Shell RSK ENVIRONMENT LTD Spring Lodge 172 Chester Road Helsby Cheshire WA6 0AR Tel: +44 (1928) 726 006 Fax: +44 (1928) 725 633 www.rsk.co.uk RTD GROUP LTD RTD Head Office Delftweg 144, 3046 NC Rotterdam The Netherlands Tel: +31 (0) 10 208 82 08 Fax: +31 (0) 10 415 80 22 www.rtd-group.com

599

RUPTURE PIN TECHNOLOGY (Pressure safety systems ESDVs) 8230 SW 8th Street Oklahoma City OK 73128 Tel: +1 (405) 789 1884 Fax: +1 (405) 789 1942 www.rupturepin.com SAGE PROFILE (Subsea pipeline analysis) See GeoLine SAPURA CREST PETROLEUM BERHAD (incorporating Teknik Lengkap, TL Geosciences and TL Offshore) 7 Jalan Tasik The Mines Resort City 43300 Seri Kembangan Selangor Malaysia Tel: +603 8659 8800 Fax: +603 8659 8811 www.crest.com.my SAS GOUDA BV Tielweg 1 2803 PK Gouda The Netherlands Tel: +31 (182) 538800 Fax: +31 (182) 534443 www.sasgouda.nl SASOL GAS LTD (Mozambique river crossing case study) 32 Hill Street Ferndale Randburg 2125 South Africa Tel: +27 (11) 889 7600 Fax: +27 (11) 889 7956 www.sasol.com SBM OFFSHORE NV (Single buoy moorings, FSOs and FPSOs) 5 Route de Fribourg PO Box 152 CH 1723 Marly Switzerland Tel: + 41 26 439 99 20 Fax: + 41 26 439 99 39 www.sbmoffshore.com www.singlebuoy.com

600

SEAEYE MARINE LTD Sister company to Hydrovision (Panther ROV) Seaeye House Lower Quay Road Fareham Hampshire PO16 0RQ Tel: +44 (1329) 289 000 Fax: +44 (1329) 289 001 E-mail: [email protected] www.seaeye.com SEAMARK SYSTEMS LTD (concrete mattresses) See Foundocean www.seamarksystems.com SEAWAY FALCON (Reel barge) See Stolt Comex SERIMER DASA (Automated pipe welding) Serimer Dasa 8 rue Mercier 77290 Mitry-Mory France Tel: +33 1 60 21 67 00 Fax: +33 1 60 21 67 01 www.serimerdasa.com SHELL EXPLORATION & PRODUCTION (Nigerian Pipeline sabotage) Shell Centre London SE1 7NA Tel: +44 (20) 7934 1234 Fax +44 (20) 7934 8060 www.shell.com SIERRA PACIFIC CORP (Infrared thermography) 284 Sea Rim Ave Las Vegas NV 89148 Tel: +1 (702) 369-3966 Fax: +1 (702) 369-397 www.x20.org SMIT INTERNATIONALE N.V. (CDT – see also Land and Marine) Zalmstraat 1 3016 DS Rotterdam The Netherlands Tel: +31 (10) 454 9911 Fax: +31 (10) 454 9298 www.smit.com

Overview of pipeline engineering

SONAR RESEARCH & DEVELOPMENT LTD See SRD SPM INSTRUMENT AB (Condition monitoring systems) Box 4 645 21 Strängnäs Sweden Tel: +46 152 225 00 Fax: +46 152 150 75 E-mail: [email protected] www.spminstrument.se SRD SONAR RESEARCH & DEVELOPMENT LTD (Underwater video) Grovehill Industrial Estate, Beverley East Yorkshire HU17 0LF Tel: +44 (1482) 869 559 Fax: +44 (1482) 872 184 E-mail: [email protected] www.srduk.com STARTRAK PIGGING TECHNOLOGIES (Pigging and river crossing inspections) 27235 Highway Blvd Katy TX 77493 Tel: +1 (281) 599 7557 Fax: +1 (281) 578 9181 E-Mail: [email protected] www.starpig.com STATOIL ASA N-4035 Stavanger Norway Tel: +47 51 99 00 00 Fax: +47 51 99 00 50 www.statoil.com STOLT COMEX SEAWAY MS LTD See Acergy SUBSEA 7 (Formed from Halliburton Subsea and the subsea activities of DSND) Stoneywood Park Dyce Aberdeen AB21 7DZ Tel: +44 (1224) 722 877 Fax: +44 (1224) 795 459 www.subsea7.com

Acknowledgements and references

SUPERPESA Av Brasil, 42301 Rio de Janeiro RJ Brazil 23095-700 Contact Augusto Cesar Abreu Tel: +55 (21) 2394-9000 Fax: +55 (21) 2413-7521 www.superpesa.com.br TALON SUBSEA TRENCHER See Stolt Comex Seaway TAPS TRANS-ALASKA PIPELINE SYSTEM See Alyeska TDW See Williamson TECHNIP-COFLEXIP (Apache, Pliant wave and S risers) 22 rue Jean Moré BP 7 – 76580 Le Trait France Tel +33 2 95 05 50 00 Fax +33 2 95 37 49 60 www.technipcoflexip.com TECHNICAL TOOLBOXES INC (TTI) (Software products for the energy industry) Technical Toolboxes P. O. Box 980550 Houston, TX 77098-0550 TEKNIK LENGKAP See Sapura Crest THRUST SHORE See Trench Shore TIG TITANIUM INFORMATION GROUP Unit B2 Dudley Central Trading Estate Shaw Road Dudley West Midlands DY2 8TP Tel: +44 (1384) 254563 Fax: +44 (1384) 258381 www.titaniuminfogroup.co.uk TL (TEKNIK LENGKAP) OFFSHORE See Sapura Crest

601

TOTAL DUNBAR (Insulated pipe connector) See Total TOTAL EXPLORATION UK PLC (formally TotalFinaElf) 2 place de la Coupole La Défense 6 92400 Courbevoie France Tel: +33 (1 47) 44 45 46 Fax: +33 (1 47) 44 78 78 www.totalfinaelf.com TTI See Technical Toolboxes TRANSCANADA TransCanada Tower 450 - 1 Street SW Calgary Alberta T2P 5H1 Tel: +1 (403) 920 2000 Fax: +1 (403) 920 2200 www.transcanada.com TRANSCO (Gas transmission pipelines for British Gas) (Study for Shah Deniz in Azerbaij, – with BP and Advantica) 31 Homer Road Solihull West Midlands B91 3LT Tel: +44 (121) 626 4431 www.transco.uk.com TRELLEBORG CRP AB P.O. Box 153 SE-231 22 Trelleborg Sweden Street address: Henry Dunkers gata 2 Tel: +46 410 670 00 Fax: +46 410 427 63 www.trelleborg.com TRENCH SHORE LTD (Landline trench support products) Unit 22 Amalgamated Industrial Park Cheddington Lane Long Marston Tring Herts HP23 4QR Tel: +44 (1296) 661 622 Fax: +44 (1296) 668 234 E-mail: [email protected] www.trenchshore.com

602

TRENCOR INC (Landline trenching machines) 1400 East Highway 26 Grapevine TX 76051 Tel: +1 (817) 424 1968 Fax: +1 (817) 421-9485 www.trencor.com TRIAD WESTERN CONSTRUCTORS INC (Auger boring, pipe ramming and HDD) 512 North Broadway PO Box 850 Cortez Colorado 81321 Tel: +1 (970) 565 4257 Fax: +1 (970) 565 1057 E-mail: [email protected] www.triadwestern.com TWI LTD (The Welding Institute) Granta Park Great Abington Cambridge CB1 6AL Tel: +44 (0)1223 899 000 Fax: +44 (0)1223 892588 www.twi.co.uk VERMEER MANUFACTURING COMPANY (Rock trenchers and HDD) 1210 Vermeer Road Pella Iowa 50219 Tel: +1 (641) 628 2000 Fax: +1 (641) 628 4283 www.vermeer.com

Overview of pipeline engineering

VIA+ VISITLESS INTEGRITY ASSESSMENT LTD (Satellite earth condition monitoring) Lacey Court 344 12th Ave SW Calgary Alberta T2R 0H2 Tel: +1 (403) 265-8420 Fax: +1 (403) 243-0042 E-mail: [email protected] www.via-plus.net T D WILLIAMSON INC (Shortstopp® connection) 6801 S 65th W Ave Tulsa Ohio Tel: +1 (918) 447 5100 www.tdwilliamson.com THE WELDING INSTITUTE LTD See TWI LTD WWW.X20.ORG (infrared thermography) See Sierra Pacific Corp X100 STUDIES See Shell Global Solutions, TransCanada, Advantica, Serimer Dasa, Cranfield University and BP

Acknowledgements and references

603

Additional Help Additional help was provided by individuals: Cyril Bishop (Pipe freezing and hot tapping) Herman Duff (Malaysian pipeline) Mike Mosedale (Cartoonist) Frank Gibbons (Marsh and wetlands)

References “Corrosion Costs and Preventive Strategies in the United States”, G.H. Koch, M.P.H. Brongers, N.G. Thompson, Y.P. Virmani, and J.H. Payer, Study by CC Technologies, Report FHWA-RD-01-156, September 2001. “Oman India Pipeline: Development of Design Methods for Hydrostatic Collapse in Deep Water”, C Tam, P Raven, R Robinson, T Stensgaard, A M Al-Sharif & R Preston, Offshore Pipeline Technology Conference (OPT96) Amsterdam, 15-16 February. “Liquefaction hazards and their effects on buried pipelines”, T D O’Rourke and P A Lane (1989), Tech Rep NCEER-89-0007, National Center for Earthquake Engineering Research, Buffalo, NY, 1 February.

Web Sites The following web contact addresses may also be of use: API American Petroleum Institute www.api.org ASME American Society of Mechanical Engineers www.amse.org ANSI American National Standards Institute www.ansi.org BS British Standards Institute www.bsi-global.com DTI Department of Trade and Industry www.dti.gov.uk DNV Det Norske Veritas www.dnv.com

604

Overview of pipeline engineering

GIS RESOURCE University of Edinburgh (Geographic Information System) www.geo.ed.ac.uk/home/giswww.html HSE UK Health and Safety Executive (Offshore Safety Reports and Contact Research Reports) www.hse.gov.uk WORKSAFE VICTORIA Australian State of Victoria Health and Safety Accident Prevention Arm (Good international contacts worldwide) www.workcover.vic.gov.au IP Institute of Petroleum www.petroleum.co.uk ISO International Organisation for Standardization www.iso.org MINERALS MANAGEMENT SERVICE (MMS) USA Authority for Pipelines – Offshore incidents in Pacific and Gulf of Mexico www.mms.gov and www.mms.gov/offshore/index.htm NACE - THE CORROSION SOCIETY National Association of Corrosion Engineers www.nace.org OS Ordnance Survey (of Great Britain) www.ordsvy.gov.uk SHEET PILING SPECIFICATIONS Search engine for sheet piling specifications www.pilespecs.com DEAL DATA REGISTRY FOR UK OFFSHORE OIL AND GAS Data and information about offshore oil and gas exploration and production for the UK www.ukdeal.co.uk USDA US DEPARTMENT OF AGRICULTURE (Forestry. drainage, energy and environment) www.usda.gov

Acknowledgements and references

605