Norway: Quickflange Develops New Subsea Pipeline Repair Solution

Quickflange, one of the industry’s leading providers of high performance pipe connection systems with thousands of topside applications worldwide, launched its new subsea pipeline repair solution – the Quickflange Subsea.

The new solution, which has been designed to bring low impact, robust and cost effective flange-to-pipe connections to subsea operations, will be available for delivery immediately and will be applicable for pipeline sizes of up to 12” with larger sizes to follow.

The Quickflange Subsea can be utilised in a number of subsea scenarios, such as emergency and contingency pipeline spool repair, but also applications in pipe lay, decommissioning, and modification. While the Quickflange Subsea is a global solution, key target markets include offshore Brazil, Asia Pacific and the North Sea.

“For too long, the mechanical connector market has been characterised by high subsea intervention costs, long lead times and complex and expensive solutions. No longer!” saidQuickflange CEO, Rune Haddeland.

“With the Quickflange Subsea, operators will be able to enjoy, for the first time, low impact, flexible and cost effective subsea pipeline repairs that are also highly reliable and robust. Quickflange is delighted to be launching this revolutionary new solution today and look forward to making as big an impact subsea as we have already done topside.”

The Quickflange Subsea can easily be slid onto the pipe with a hydraulic tool then used to activate the flange. This results in a mechanically robust flange-to-pipe connection and a less onerous installation compared to other more cumbersome mechanical systems. Key benefits of the Quickflange Subsea include:

• Simplicity & Flexibility. The Quickflange Subsea is simple to install and activate. As it is up to 60% shorter than other pipe-end connectors, it is easier to handle with straightforward diver operations and no specialist diver training required. The solution can be used on multiple pipe ranges with the installation being fully retrievable and reusable, thereby being ideal for emergency repair and contingency repair systems.

• Significant Cost Savings. Thanks to the simplicity of the concept, the Quickflange Subsea also delivers significant cost savings in regard to subsea repair time, subsea operations, diver and support vessel costs. This includes reduces lead and delivery times and faster implementation with a reduction in required diver time and less required pipe preparation, such as coating removal and deburial. The Quickflange Subsea also comes with flexible rental options and installation tooling to reduce CAPEX.

• Finally, the Quickflange Subsea comes with Maximum Reliability & Robustness. There are no moving parts, grips or other components, ensuring that less can go wrong. Third party testing has demonstrated that the solution is equivalent to welded weld-neck flanges in terms of pressure retention and load resistance with the assembled joint being stronger than the flange itself

The introduction of the Quickflange Subsea to market follows an extensive testing programme with the Norwegian Research Council, the University of Agder, the National Hyperbaric Centre in Aberdeen and Brazilian operator, Petrobras.

Quickflange AS is one of the industry’s leading providers of total pipeline and piping solutions to the oil & gas sector and has deployed its topside piping solutions in over 2,900 activations worldwide in regions, such as the UK, Norway, Belgium, Denmark, the Netherlands, Brazil, the Middle East and Australia. Quickflange counts BP, BG Group, ConocoPhillips and Exxon among its customers.

Quickflange has offices in Stavanger, Aberdeen and Dubai, and has a technology centre in Tvedestrand, Norway, where the research and product development, production and assembly of all the Quickflange tools take place.

Source: Subsea World News – Norway: Quickflange Develops New Subsea Pipeline Repair Solution, diakses Februari 2014.

What are PIG’s, PIG Launchers, and PIG Receivers and Why Are They Important?

Pipelines are a fundamental part of the oil and gas industry and they are by far the primary transportation method for crude oil, natural gas and even the refined product. However, building a pipeline network is a massive project and though most pipelines ultimately “pay for themselves” with the product they transport, they are still an expensive investment. It is essential for this investment to be well maintained and monitored. One of the most effective ways of doing that is with PIGs and the PIG launchers and receivers that facilitate them.

What Are PIG’s?

PIG’s are devices that are inserted into pipelines and used to clean, inspect, or maintain the pipeline as they pass through it. They may also be used to separate different batches or types of product within the pipeline. For effective movement through the pipeline they are usually cylindrical or spherical and may be bullet shaped.

PIG’s were traditionally used in the oil industry for large diameter pipelines. However, because of their useful qualities and the benefits they bring to pipelines, they have begun to be used in a very broad range of pipelines from small to large diameter. Nowadays they are also by no means found only in the oil and gas industry; they can be found in use at many plants and industrial sites and are effective just about anywhere a pipeline is in use. For example PIGs and PIG systems may be found in operation at plants and factories that process lubricating oils, toiletries, paints, a host of different chemicals, consumer cosmetics, and even foodstuffs.

Because the demands placed on PIGs are so diverse, the PIGs themselves may be made out of a wide variety of different materials. Often some type of steel is used and depending on requirements and budgetary concerns it could be stainless steel, duplex stainless steel, low-strength carbon steel, high-strength carbon steel. Again depending on how corrosive the materials the PIGs will be coming into contact with are, the PIGs may also be coated with corrosion-resistant materials or other specialty coatings. In addition to steel, PIGs may also be made out of polyurethane foam and other material types.

The earliest PIGs were likely made of straw and wrapped in wire to facilitate pipe cleaning. Conventional wisdom holds that it was from this early use that PIGs get their name since the squealing sounds they made as they passed through the pipes reminded people of the sounds a pig makes. The industry term PIG is likely a backronym and it is generally explained to mean ‘Pipeline Inspection Gauge;’ however, some people also use it to mean’ Pipeline Intervention Gadget.’

A special type of PIG called a “Smart PIG” puts a more high tech spin on things. This type of PIG has special electronics and sensors that allow it to not only clean and maintain the pipeline but to also gather additional information about the condition of the pipeline itself such as surface pitting, corrosion, cracks, or weld defects. This information is usually gathered using magnetic flux leakage (MFL) PIGS or PIGS equipped with electromagnetic acoustic transducers.

What are PIG Launchers and PIG Receivers?

In simplest terms the PIG launchers and PIG receivers are the sections of the pipeline which allow the PIG to enter and exit the pipeline. They are generally funnel, Y-shaped sections of the pipe which can be pressurized or depressurized and then safely opened to insert or remove PIGs. Most pigging systems use bidirectional launchers and receivers that can work in either direction. This is important to allow the PIG to be retrieved by the launcher if there is a blockage in the pipeline which prevents it from reaching the receiver.

PIG launchers and receivers come with safety valves and locking system to prevent accidents. They are also optimized to be suitable to the pressure and temperature requirements of the pipeline. Launchers and receivers may be horizontal or vertical depending on the needs of the pipeline.

Some launchers are designed to hold multiple PIGs at once and configured to launch them according to preset conditions. This is very useful because it allows much of the work to be done remotely. Additionally it prevents the launcher from having to be depressurized and repressurized again each time a single PIG is needed. It is the pressure from the flow of product that moves the PIGs through the pipeline. Thus one of the main roles of launchers and receivers is to safely interface between the low-pressure outside world and the high-pressure pipeline.

How Do PIG Launchers and Receivers Work?

The exact procedure for operating a PIG launcher or PIG receiver will vary somewhat depending on the particular pigging system being used. However, for the most part it will include the following steps:

Launcher:

• Pipeline operator should make sure that the isolation valve and kicker valve are closed.
• If the system is a liquid system then the drain valve and vent valve should then be opened to allow air to displace the liquid; if the system is a gas system then the vent should be opened so that the launcher reaches atmospheric pressure.
• After the PIG launcher is completely drained to 0 psi, with the vent and drain valves still open, the trap door should then be opened.
• The PIG should then be loaded with its nose in contact with the reducer.
• Closure seals and other sealing surfaces should be cleaned and lubricated as needed and then the trap door should be closed and secured.
• The drain valve is then closed and the trap is slowly filled by gradually opening the kicker valve.
• Once filling is complete the vent valve is closed so that the pressure will equalize across the isolation valve.
• The isolation valve is then opened and the PIG is ready for launching.
• Next the main valve is gradually closed, increasing the flow through the kicker and behind the PIG until finally the PIG leaves trap altogether and enters the pipeline itself.
• After the PIG leaves the launcher the mainline valve is fully opened and the isolation valve and kicker valve are closed.

Receiver:

• The receiver should be pressurized.
• The bypass valve should be fully opened.
• The isolation valve should be fully opened and the mainline valve partially closed.
• Once the PIG arrives the isolation and bypass valves should be closed.
• The drain valve and vent valve are then opened.
• Once the trap is fully depressurized to 0 psi the trap can be opened and the PIG removed.
• The closure seal and other sealing surfaces should be cleaned and lubricated as needed and the trap door should then be re-shut and secured.
• The receiver should then be repressurized and returned to its original condition.

These processes may differ somewhat on different systems and of course if the launcher will be launching multiple PIGs then they should all be loaded at the loading stage.

Why Are PIGs and PIG Launchers and Receivers Important?

There are four main benefits for using PIGs:

Separation – PIGs can be used to physically separate different products within a pipeline. Without PIGs the pipeline would need to either be flushed out between products, or a portion the second product would be contaminated with the first product. Both options would result in waste. With PIGs acting as separators, however, this problem is eliminated.

Cleaning and Maintenance – PIGs clean the pipeline by scraping away building up and debris and pushing it safely into the receiving trap. This improves the efficiency and flow of the pipeline and helps prevent corrosive damage to the pipes.

Inspection – Smart PIGs using technologies such as MFL and ultrasonics can inspect the pipeline for welding defects, cracks, pitting, and other problems. Caliper PIGs can also take estimates of the internal geometry of the pipeline.

Positioning and monitoring – Smart PIGs not only inspect and retain the data about the pipeline, they can also provide information about where the particular defect or trouble area of the pipeline is located. This prevents unnecessary digging up of healthy parts of the pipeline and if a problem isn’t severe enough to warrant replacing, it also allows the trouble section to be closely monitored and the PIG results to be compared across multiple time frames to track damage progression.

PIG launchers and PIG receivers are integral to the pipelines pigging system. Their safety valves, security locks, and ability to pressurize and depressurize provide a safe way for the PIGs to be loaded and removed without danger to the pipeline and equipment or human personnel. STI Group provides its customers with high quality, dependable PIG launchers and PIG receivers that can be used in standalone systems or as a skid mounted unit.

Source: Pig Launcher and Receiver are Critical to Midstream Pipelines, diakses Februari 2014.

Pipeline Coating

3M offers a total Pipeline Corrosion Protection Solution with a variety of functional pipe coatings for both internal and external use, as well as in-the-field rehabilitation applications for girthweld/field joint coatings. Withstand harsh chemicals to extend the life expectancy of your equipment – and help to ensure a more reliable operation.

Internal Pipe Coating

3M™ Scotchkote™ Liquid Epoxy Coatings provide corrosion protection for steel pipeline interiors, fittings and other equipment.

• Total solutions, including girth weld protection
• Provides flow enhancement
• Suitable for a wide range of oils, gases and fluids

External Pipe Coating

3M™ Scotchkote™ Fusion Bonded Epoxy Coatings provide maximum external protection for underground or subsea steel pipelines:

• Withstand saltwater, wastewater, petrochemical and other harsh environments
• Minimize damage during manufacture, transit and installation

Flow Efficiency

3M™ Scotchkote™ Two Component Epoxy Coatings act as internal linings for gas pipelines:

• Increase gas flow, reduce deposit build-up
• Corrosion and chemical resistance
• Minimize solvent emissions during application

3M™ Flow Efficiency Liner Corrosion Protection Products

Corrosion Protection

Choose from a variety of easily applied, high performance 3M™ Corrosion Protection Tapes, including:

• All-weather PVC-based tapes
• Self-fusing insulating putties in tape form
• Pipe primers for quick-drying surface prep

 

Flowline Coating

Protect the critical connection between wellhead and manifold or production facilities with 3M™ Scotchkote™ Coatings for flowlines:

• Internal and external corrosion protection
• Broad range of chemical resistance and service conditions

3M™ Flowline Corrosion Protection Products (Gulf, English)

Field Joint Coating

3M™ Scotchkote™ Field Joint Coatings provide protection to the pipeline’s weakest link.

• Novel heat-curable film coating
• 2-part liquid coating
• High solids spray system for expoxy application

Source: Pipeline Corrosion Protection – 3M Oil & Gas : 3M Saudi Arabia, diakses Februari 2014.

Pipeline Inspection

In the United States, millions of miles of pipeline carrying everything from water to crude oil. The pipe is vulnerable to attack by internal and external corrosion, cracking, third party damage and manufacturing flaws. If a pipeline carrying water springs a leak bursts, it can be a problem but it usually doesn’t harm the environment. However, if a petroleum or chemical pipeline leaks, it can be a environmental disaster. More information on recent US pipeline accidents can be found at the, National Transportation Safety Board’s Internet site. In an attempt to keep pipelines operating safely, periodic inspections are performed to find flaws and damage before they become cause for concern.

When a pipeline is built, inspection personnel may use visual, X-ray, magnetic particle, ultrasonic and other inspection methods to evaluate the welds and ensure that they are of high quality. The image to the left show two NDT technicians setting up equipment to perform an X-ray inspection of a pipe weld. These inspections are performed as the pipeline is being constructed so gaining access the inspection area is not problem. In some areas like Alaska, sections of pipeline are left above ground like shown above, but in most areas they get buried. Once the pipe is buried, it is undesirable to dig it up for any reason.

So, how do you inspect a buried pipeline?

Have you ever felt the ground move under your feet? If you’re standing in New York City, it may be the subway train passing by. However, if you’re standing in the middle of a field in Kansas it may be a pig passing under your feet. Huh??? Engineers have developed devices, called pigs, that are sent through the buried pipe to perform inspections and clean the pipe. If you’re standing near a pipeline, vibrations can be felt as these pigs move through the pipeline. The pigs are about the same diameter of the pipe so they range in size from small to huge. The pigs are carried through the pipe by the flow of the liquid or gas and can travel and perform inspections over very large distances. They may be put into the pipe line on one end and taken out at the other. The pigs carry a small computer to collect, store and transmit the data for analysis. In 1997, a pig set a world record when it completed a continuous inspection of the Trans Alaska crude oil pipeline, covering a distance of 1,055 km in one run. Click here to read more about this record setting inspection.

Pigs use several nondestructive testing methods to perform the inspections. Most pigs use a magnetic flux leakage method but some also use ultrasound to perform the inspections. The pig shown to the left and below uses magnetic flux leakage. A strong magnetic field is established in the pipe wall using either magnets or by injecting electrical current into the steel. Damaged areas of the pipe can not support as much magnetic flux as undamaged areas so magnetic flux leaks out of the pipe wall at the damaged areas. An array of sensor around the circumference of the pig detects the magnetic flux leakage and notes the area of damage. Pigs that use ultrasound, have an array of transducers that emits a high frequency sound pulse perpendicular to the pipe wall and receives echo signals from the inner surface and the outer surface of the pipe. The tool measures the time interval between the arrival of a reflected echos from inner surface and outer surface to calculate the wall thickness.

On some pipelines it is easier to use remote visual inspection equipment to assess the condition of the pipe. Robotic crawlers of all shapes and sizes have been developed to navigate the pipe. The video signal is typically fed to a truck where an operator reviews the images and controls the robot.

Source: Pipeline Inspection, diakses Februari 2014.

New pipe-in-pipe design ensures effective insulation

Derek Bish
Tata Steel

Increasing demand for energy, matched with high commodity prices and advances in technology, are driving operators to extract whatever reserves remain in the challenging UK continental shelf. Therefore, the requirement to transfer these multi-phase products from often high-pressure/high-temperature (HP/HT) wells back onshore is an even more demanding prospect.

Up until now, the common belief in the industry was that pipe-in-pipe systems able to withstand environmental challenges such as corrosion, structural integrity, and thermal management, would be too costly and complex to apply to riser systems.

Tata Steel worked closely with supply partners to engineer, procure, and construct these assemblies to further develop this innovative technology as a cost-effective solution to flow assurance issues.

Need for insulation

HP/HT fields are technically more complex to develop because of the inherently higher energy in the well fluid and its multi-phase composition. Managing the extreme pressure and operating temperature must be based and evaluated on criteria such as corrosion, maintaining structural integrity, and thermal management.

One particular challenge is the management of pipeline shutdown. Less expensive solutions for managing the insulation of bends such as wet coatings, compromise overall shutdown times due to reduced thermal efficiency. Solutions, such as “self-draining” spools, present a significant design challenge that can be mitigated by the inclusion of pipe-in-pipe bends, enabling the same thermal integrity to be maintained in the whole line.

Tata Steel has previously implemented a solution for pipe-in-pipe bends for a North Sea development. Since then, new insulation techniques have been developed that give far superior insulation properties.

Risers, spools, and bends

The main challenge with the construction of pipe-in-pipe bends is how to pass the inner flowline bend into the outer casing pipe. It is important that pipe bends have a straight portion on the end to enable efficient welding to the next pipe section and this can present the insertion of one bend into the other.

The second construction challenge is efficient insulation. Wrapping or sheathing is simply not practical here as the insulation would occupy the annulus of the assembly and prevent the integration.

New insulation system

Drawing of the geometry of one pipe into another.

The system developed by Tata Steel overcomes these problems by deploying granular Nanogel insulation into the annulus of the pipe-in-pipe system. Nanogel is made by first forming a silica gel, then expelling the water from the silica matrix. The resulting material is granular with trapped nanopores of air, inhibiting heat transfer by conduction, convection, and radiation (with the inclusion of an opacifier).

The deployment of a novel polymeric bulkhead, cast directly into the annulus, provides a solid barrier to retain the insulation, which allows for the relative movement of the inner and outer bends. The polymer is a “syntactic” material, silicone rubber with glass microspheres dispersed through the matrix with high strength, flexibility, and thermal efficiency. The tangent ends of the inner and outer bends are held rigidly to ensure that the assembly tolerances achieved at manufacture are retained when the unit is transferred to the welding contractor for incorporation into the pipeline spool or riser.

In order for the insulation to be effectively deployed and provide the consistent thermal performance, the annular gap throughout the assembly must be uniform. It is important the manufacturing tolerances of the pipe and bends are closely controlled.

Steel pipe and bend manufacture

Together with Tata Steel, Eisenbau Krämer (EBK) and the pipe bending plant of Salzgitter Mannesmann Grobblech (SMGB) have developed a series of controls, including a process and measurement system, to ensure all bend dimensions are closely controlled and mating bends can be produced, matched, and paired to ensure the most accurate assembly is produced.

In respect to the process-related thinning in the extrados of the hot induction bends, the wall thickness for the inner and outer mother pipes was increased accordingly. To match precisely, the mother pipes have been manufactured with the same ID as the riser pipes.

16-in. clad bends being transferred to the quenching tank after austenitization at SMGB pipe bending mill.

EBK supplied Tata Steel with the mother pipe, which has material properties that allow formation through hot induction bending. The main material challenges are to ensure the mechanical properties are suitable after bending. Therefore, SMGB is taking responsibility for the chemical design of the pre-material. This also involves the consideration of a series of heat treatment and forming processes. EBK uses a multi-pass welding process and steel plate from premium mills in Europe. The manufacturing process at EBK generates pipe of the closest dimensional control through a series of cold forming and sizing operations such as external calibration.

At the SMGB pipe bending plant, the special mother pipes are bent by hot induction bending. Heat is applied through electrical induction to the mother pipe materials and the pipe is slowly formed to give the correct geometry. In most pipeline applications the critical dimensions are the positions and attitudes of the ends of the bends (center-to-end dimension) to maintain the overall geometry of the pipeline. However, with pipe-in-pipe bends it is important that the bend radius is also accurately controlled to ensure the two bends can be integrated. The precise dimensions after bending also need to be maintained following heat treatment. For the inner clad bends, a full-body quench and temper heat treatment is applied at the SMGB bending mill in order to guarantee homogenized material properties for the bends, to fulfill mechanical and corrosion requirements.

HP/HT material properties

Additional material complexities have to be overcome. Generally, in HP/HT lines there are challenges because of corrosion, low temperature toughness, and strength. These parameters require careful material selection to maintain the balance of properties from the outset through to bend production. Thermal stresses need to be managed as the loads are shared between inner and outer pipe. In addition, the insulation can lead to extremes of temperature being retained in the pipe materials during operation and shutdown that can form challenging conditions for conventional steel products.

Conclusion

HP/HT well environments present some of the most challenging and technologically demanding conditions for field developments, not least because the properties in each reserve offer significant challenges in terms of material selection and design.

Tata Steel and its supply partners have expanded capabilities further with the design and creation of cost-effective insulated pipe-in-pipe bends for risers and spools – an accomplishment previously considered too difficult.

Pipe-in-pipe bends, while challenging technologically, can lead to simplification of overall pipeline design and can give better pipeline performance in times of operation and shutdown.

Source: New pipe-in-pipe design ensures effective insulation – Offshore, diakses Februari 2014.

NEW WELDING TECHNOLOGIES PROVIDE DRAMATIC ADVANTAGES FOR ON-SITE PIPE WELDING

The installation of gas pipe through the designated wetland areas of Mississippi and Alabama could prove challenging for any contractor, but the thick-walled pipe specified on the Gulfstream Project presented new welding challenges for contractor Sunland Construction Inc. Because the pipe is two times as thick as that typically used, Sunland relies on innovative welding techniques to decrease the number of weld passes necessary and most importantly, to assure the welds produced are consistent, x-ray quality.

Sunland Construction Inc., headquartered in Eunice, Louisiana, turned to The Lincoln Electric Company’s Autoweld® automatic orbital pipe welding system for the fill and cap passes and the STT® (Surface Tension Transfer®) process to lay the critical root pass. By implementing these new welding technologies, Sunland has been able to remove one electrode pass from the root pass process as well as eliminate all grinding from this step. With the Autoweld system, the company has reduced the time to put in the fill and cap passes.

“We have realized dramatic improvements since using the new Lincoln welding systems in both higher quality and time savings,” said Joe Ratcliff, Project Manager for Sunland Construction Inc. “Our welders are proud of the new equipment, it has made the welding portion of this job run smoothly.”

Gulfstream Project

The Gulfstream Project is a natural gas pipeline that originates near Pascagoula, Mississippi and crosses the Gulf of Mexico to Manatee County, Florida. Once onshore, the pipeline stretches across south and central Florida to Palm Beach County. This natural gas pipeline will serve Florida utilities and power generation facilities, generating 1.1 billion cubic feet per day of additional natural gas – enough to supply electricity for 4.5 million homes.

Sunland Construction Inc.’s portion of the pipeline includes installation of 6.1 miles of 36″ diameter pipe in Jackson County, Mississippi and 9 miles in Mobile County, Alabama.

A 27-year-old company with five divisions, Sunland won the Gulfstream job through a competitive bid process. More than 250 employees are being utilized on this project – taking a total of seven months to complete. Sunland expects its portion of the Gulfstream project to be wrapped up in early 2002.

According to Ratcliff, preparing for pipe installation on this job is no small feat. “Before we can even begin to weld, we must first clear the land, prepare a right of way, install piling in some areas, erect construction bridges and bring in additional soil where need. Because of the conditions of the wetland areas, all welding crews have to work on large, 4 ft. x 20-ft. timber mats. These mats, sometimes put down in a number of layers, provide a stable, dry work surface. Once work is complete in an area, Sunland Construction Inc. is also responsible for restoring the surrounding area to its original condition.

“Welding for this job is completed with three crews, one welding right after the other,” noted Ratcliff. “The first crew installs the root pass, the second crew immediately follows using stick welding to accomplish a hot filler pass, and then the Autoweld crew completes the welding process with fill and cap passes.”

Because of the extreme conditions on the site, the Autoweld process is performed inside of a welding “house” or modular unit that is lifted and moved every 40 ft. (from joint to joint) by a Caterpillar Challenger with a side boom.

The Pipe

Pipe for the on-land portion of the Gulfstream Project is provided by Berg Steel Pipe Corporation of Panama City, Florida and its parent company, Europipe GmbH of Germany. The X70 pipe ranges in wall thickness from 0.635 to 1.22. This thick-walled pipe was specified so the pipeline could handle the pressure range of the Gulfstream system. Pipe is coated with a Fusion Bond Epoxy (FBE) on both the interior and exterior, and a majority of the pipe is also concrete coated for buoyancy control.
Root Pass

Sunland Construction Inc. utilized the STT process because of the advantages it offered.

STT is a modified MIG process that uses high frequency inverter technology with advanced Waveform Control to produce high quality welds while also significantly reducing spatter and smoke. STT technology has the ability to control weld puddle heat independently of wire feed speed – this allows the welder more control over the puddle and provides the ability to adjust the heat input to achieve the desired root bead profile. The welder simply positions the arc on the forward portion of the weld puddle and follows it around the pipe in a vertical down fashion.

With the system, Sunland welders can achieve a uniform gap by using an internal, pneumatic clamp to line up and space the pipe for accurate welding.

For the Gulfstream Project in particular, STT is able to produce a quality weld and allows an increased amount of weld metal to be placed on the heavy wall pipe for improved resistance to cracking. With STT, Sunland only has to make one pass for the root bead as compared to two passes plus grinding time with stick.

“Since the root pass is the foundation for the rest of the weld, achieving a high quality, strong and uniform weld is very important to us,” said Ratcliff. “We are very pleased with the STT. It has allowed us to save time and is an easy system for our welders to learn. The STT process is very forgiving, meaning that it helps compensate for misalignments, if and when necessary.”

The two STT machines on the Gulfstream job site are used in conjunction with Lincoln’s .045 L-56™ SuperArc® wire and 100 percent CO2 shielding gas. As compared to blended gases, CO2 is able to provide better penetration and is less expensive.

“The STT is able to apply a root bead with great consistency over a wide variety of joint conditions” explained Ratcliff.

Hot Filler Pass

Once the root pass is complete, the next team of welders follows closely behind to weld in the hot filler pass. Due to the thickness of the pipe on this job, Sunland Construction Inc. elected to put a single downhill hot filler pass over the root with a downhill, low hydrogen stick process. “The added filler metal we deposited at this stage gives us additional backing to lay the first wire filler and means that we don’t have to make quite as many passes with the Autoweld system,” noted Ratcliff.

To do this interim step, Sunland is using Lincoln’s LH-D 80 rod with a conventional 300-amp Lincoln belt-driven welder.

Fill and Cap

For the Gulfstream Project, Sunland Construction Inc. decided to invest in an automated process to weld the fill and cap passes. Previously, Sunland has been completing the fill and cap passes with a 70+ stick electrode, welded vertical down and requiring numerous passes.

“We wanted an automatic method to increase efficiencies and decrease overall costs,” said Ratcliff. “It was also important for us to find a system that could provide a quality product but yet was easy to operate.

In its quest, the company contacted a number of manufacturers to research which system would work best in this application. “We narrowed down our choices and visited a couple of manufacturers to try out their systems, one of those being Lincoln Electric,” noted Ratcliff. “Our team traveled to Lincoln’s Cleveland headquarters where we had the opportunity to run our procedures on an actual Autoweld set-up. After we returned, we listed the pros and cons of every system and Lincoln’s Autoweld came out on top. A big factor in our decision was the amount of technical support that Lincoln could provide to us.”
The Autoweld system is enclosed in a house, so that welding can be done out of the elements. These houses are moved by sidebooms ( Challengers ) from one length of pipe to the next. Sunland uses six Caterpillar Challengers with PTO driven generators to produce the 100 amps at 460 volts needed to operate the Autoweld and accessories.

Lincoln’s Autoweld system uses a specially designed lightweight-welding head to travel around the circumference of the pipe. In addition, the unit utilizes an external crawler band placed on the pipe to one side of the field joint weld bevel. Two machines operating simultaneously complete the vertical up welding – one machine starts at the bottom with the other starts on the side. Once the machine that started on the side reaches the top, it then is positioned to start at the bottom to complete its side of the pipe. Using the vertical up process is a break from the traditional, vertical down welding typically utilized for pipe.

Each wall thickness of pipe requires different machine settings for each specific pass. These settings are charted and can easily be set from the machine. The Autoweld system uses a flux core .052″ wire and a shielding gas of 25 CO2/75 argon.

With Autoweld, Sunland Construction Inc. is achieving repetitiously consistent, x-ray quality welds. “Autoweld makes a very consistent, uniform, and precision-controlled metal deposit,” noted Ratcliff. “The weld has high tensile strength and good Charpy values in the weld and pipe heat zones. The machine is also very durable and dependable.”

Sunland’s Autoweld system is powered by an Invertec® V350-PRO, an extremely lightweight inverter that is able to handle multi-process applications. The hallmark of this power source is an extremely smooth arc due to the unit’s advanced inverter technology.

“We feel the V-350 is the state of art in welding equipment, it gives you the ability to maintain precise settings and arc performance,” claimed Ratcliff. “Even after long hours of use on our construction site, the machine was dependable.”

Quality Control

All welds once completed are visually inspected and then x-rayed with an internal crawler. All welds must meet API 1104 Section 9 requirements.

Service

Sunland Construction Inc. has been extremely pleased with the service it receives from Lincoln. “The on site support provided by the Lincoln Electric Mobile team of Troy Gurkin and Steven Brown has been superb,” said Ratcliff. “We also enjoyed tremendous support from the Cleveland based Autoweld group including Eric Stewart, Autoweld technician, who was on site for much of the project. Lincoln has gone out of its way to help us implement our new processes and suggest new technologies when appropriate.”

Sunland has also taken advantage of Lincoln’s training programs on-site and in Cleveland. “Lincoln was challenged with taking welders at all different levels of expertise and work with them to learn to understand and operate the Autoweld system. It was a massive training effort that required quite a bit of Lincoln’s time. We appreciate all they have done to make this job run smoothly.”

Future

Sunland Construction Inc. is already planning on how the new STT and Autoweld machines can be used on future jobs to increase efficiencies.

Source: New Technologies for Pipe Welding | Lincoln Electric, diakses Februari 2014.

How are subsea gas pipelines built

Sea can go several kilometers deep. Laying a pipe at the bottom is a challenge. However, 6,000 kilometers of pipelines are laid at the bottom of the North Sea, some of which have been there for 40 years already.

The world’s largest vessel, Solitaire, is 300 meters long and about 40 meters wide. This particular vessel is involved in the construction of the Nord Stream gas pipeline.

Searching for obstacles

Subsea gas pipelines account for 45 per cent of natural gas exports to Europe. Seabed is carefully surveyed along its entire route before laying the gas pipeline. Specialists must identify all potential obstacles including sunk ships, ammunition, and simply large boulders. These obstacles are either removed or bypassed. At this stage, specialists also identify locations where the pipelines should be buried or backfilled.

All pipes for future gas pipeline are subject to a special treatment. From the inside, they are treated with an antifriction coating which is reducing resistance during gas transmission. Externally, pipes are treated with an anticorrosion coating and then with a negative buoyancy concrete coating.

Floating houses

Pipes are laid on the seabed by special pipelaying vessels. Pipelaying vessels are huge floating platforms which can accommodate several hundreds of people at a time.

As a rule, several vessels participate in the process of pipe laying. Special barges continuously supply pipes to a pipelaying vessel, which is preceded by a vessel monitoring the seabed. The supplied pipes are unloaded on storage sites located directly on the deck of the pipelaying vessel. They should have a stock of pipes for 12 hours of work.

How pipes are laid

Special conveyor is installed on the pipelaying vessel, which receives pipes that are welded here as well. Each welded joint is then ultrasonically tested for defects. Anticorrosion coating is applied to all joints after welding. Welded pipes are moving over the conveyor towards the aft. Stinger, a special boom, immersed in the water at an angle, over which the pipes are gradually lowered onto the seabed, is located here. It defines the required deflection of the top part of the gas pipeline, which prevents metal deformation.

As a rule, pipes lie on the seabed under their own weight. They don’t need to be fixed, because each pipe weighs up to several tons after the concrete coating is applied. Pipes are laid in special trenches and backfilled with ground only in some locations, e.g. at landfalls, to ensure stability of the pipe.

From sea to shore

The process of laying a subsea gas pipeline normally starts not on the shore, as one could think, but in the sea. Gas pipeline can consist of several sections built at different times from different vessels and then connected to each other. Gas pipeline should be able to withstand different pressures in different sections, for this purpose pipes with different wall thickness are used.
Upon the completion of the subsea section construction, pipes are drawn on shore using a special winch installed on firm ground which is connected to the pipe with steel ropes and is slowly drawing it from the sea. The pipeline is then connected with its onshore section – a tie-in is made.

Hydro testing of the gas pipeline is a mandatory stage. For that, the pipeline is filled with water under requisite pressure and left for some time to identify possible defects. Condition of the gas pipeline is carefully monitored after its commissioning as well. Special electronic devices for in-pipe inspection are used in this process.

Source: How are subsea gas pipeline built, diakses Februari 2014.

What Happens When a Pipeline is Shut Down?

In Canada, there are more than half a million kilometres of oil and gas pipelines that are in operation and more than 50 per cent of those pipelines are located in Alberta. With the amount of pipelines running throughout Canada it is important for all stakeholders, including oil and gas companies and affected landowners, to understand that pipelines have a lifecycle and how each lifecycle phase may affect them. Throughout a pipeline’s lifecycle the owner/operator of the pipeline will make decisions about the pipeline’s level of use. When a company decides to stop using a pipeline, replace a pipeline, or re-route a pipeline, questions can surface about what happens to the old pipeline and the effects this would have on landowners.

Each province has its own regulatory agency with a set of specific requirements for pipelines but if a pipeline crosses provincial borders then it falls under the jurisdiction of the National Energy Board (NEB). Under the NEB there are three different options that a company can choose from when they decide to stop using a pipeline: deactivation, abandonment or decommissioning, all of which require NEB approval.

The NEB refers to deactivation as “to remove temporarily from service”. More specifically, the NEB goes on to state that in practice it is acceptable that portions of pipeline that are in a deactivated state:

• Never return to service,

• Can remain in a deactivated state for an unspecified amount of time, or

• Can eventually be abandoned.

An application for deactivation likely would be subject to conditions. It will also likely require that the company completes periodic status reporting for the deactivated line. The NEB also suggests that it would be beneficial for a company to consult with stakeholders regarding a deactivation. These consultations should address any questions or concerns that stakeholders may have about the deactivation. These concerns can relate to the protection of the stakeholder’s property, safety of people and protection of the environment.

 A company also has the option to reactivate a deactivated line. The company must file an application with the NEB that explains the need for reactivation. The application must also have a description of the proposed activities to reactivate said pipeline and it must also identify all potential impacts.

The NEB consistently holds companies accountable to its stakeholders and the public during the construction, post-construction, operation and abandonment of a pipeline’s lifecycle. The term ‘abandonment’ can sound ominous and make it seem as though a company can simply leave a pipeline with no accountability on their part. The reality is quite the opposite.

When a company is applying for abandonment it is deciding to permanently stop using a pipeline and wants leave to “abandon the operation of a pipeline”. The abandonment phase of a pipeline often starts after a company has already deactivated the line. Once a company decides to abandon a pipeline it must apply for abandonment of the pipeline and of the connected facilities.

When abandoning a pipeline, reclamation criteria need to be agreed upon by all affected parties including the owner/operator, regulatory authority and the landowners prior to any commencement of field activity. This reclamation program is designed to ensure that the right-of-way land surface condition is returned to the state it was in prior to beginning of abandonment activities. If circumstances permit, the right-of-way land surface condition should be returned to the condition that it was in prior to any pipeline installation.

There are two options for the abandonment of a pipeline. It can either be removed from the ground or it can be left in the ground after it has been cleaned and treated. The NEB considers land use management to be the most important factor to think about when deciding if a pipeline section should be removed upon abandonment or remain in place. To make this decision it is important to know what the land is currently used for and what potential uses it has along the pipeline right-of-way. A company must also consult and gather input from all appropriate sources including any affected stakeholders to support the decision to abandon in place or through removal. It is important to consider the potential uses of land because abandoning a pipeline in place could have an effect on future development. It could cause issues for excavation for foundations, pilings or ongoing management practices such as installing sub-drains or deep ploughing.

If a pipeline is to be abandoned in place, key environmental protection measures should be considered. For example, there should be minimal disruption to future or ongoing land management activities and a complete cleaning procedure should be documented. Any spills or contaminated sites should be cleaned to prevailing regulatory requirements and a revegetation strategy should be put in place to achieve pre-abandonment conditions while keeping soil stability and erosion control as a priority. A monitoring program should also be implemented in a way that is acceptable to all affected parties to ensure a process to complete remediation.

The NEB requires that all abandonment applications have a public review process, which can be oral or written. Like deactivation, if the NEB decides to allow abandonment it may be subject to conditions. These conditions normally need to be met before abandonment is complete. When a company has met all of the conditions ordered by the NEB and the risk to public safety, property and environment is considered to be at an acceptable level, the NEB oversight ends. However, the NEB may still intervene if necessary.

After an owner/operator has abandoned a pipeline, it still has many responsibilities. The owner/operator is responsible for making sure the right-of-way and any facilities that were left in place stay free of any problems that could be associated with the abandonment. The owner/operator should include a right-of-way monitoring program in the post-abandonment plan.

Abandoning a pipeline and decommissioning a pipeline have similar definitions, however there is a difference. A company can decommission a particular line and by doing so it is not discontinuing service throughout the rest of the connected lines. A pipeline that is part of a larger series of lines can be decommissioned to no longer transport hydrocarbons while the rest of the series of lines continue to provide service.

For further information about deactivation, abandonment and decommissioning please visit the NEB website:http://www.neb-one.gc.ca/clf-nsi/index.html

Source: What happens when a pipeline is shut down – Communica, diakses Februari 2014.

Pre-commissioning the Nord Stream pipeline

Project represents the world’s longest offshore dewatering operation/sealing tool run 

Marco Casirati
Jarleiv Maribu
Nord Stream AG

John Grover
Daniel Fehnert
Baker Hughes PPS

 

As submarine gas pipelines get longer and more remote, the challenge of pre-commissioning becomes greater. No project demonstrates this better than the groundbreaking Nord Stream pipeline, which comprises two 760-mi long, 48-in. diameter twin gas transmission pipelines running from Russia to Germany through the Baltic Sea – a delicate marine environment that needs to be protected and preserved.

In September 2011, the pre-commissioning of the Nord Stream Line 1 was completed ahead of schedule. Line 2 pre-commissioning was completed one year later. These are the world’s longest single-section offshore pipelines.

Nord Stream pipeline route. (Image courtesy Nord Stream)

The following discusses some of the challenges experienced during the planning, engineering and preparation for the pre-commissioning of this pipeline, and relate the relevant field experience collected during execution. A review of the schedule and lessons learned is also provided.

Nord Stream

The Nord Stream pipelines are defined as the offshore system which exports gas from Vyborg, Russia, crossing the Gulf of Finland and the Baltic Sea, to a receiving terminal in Lubmin (Greifswald), Germany. In addition to crossing Russia and Germany, the pipelines also cross the Exclusive Economic Zones (EEZ) of Finland, Sweden, and Denmark. Each pipeline has a capacity of 84 MM cm/d (2.9 bcf/d), with a total yearly capacity (for both pipelines) of 55 bcm (1.9 tcf).

The pipelines are designed with a segmented design pressure concept in accordance to the gas pressure profile along the route. There are no intermediate platforms along the route.

Each of the three sections was installed with offshore subsea terminations (start-up and laydown heads) designed for both the start-up and laydown operations and subsequent pre-commissioning activities. This was required because each of the sections had to be pressure tested separately.

Subsequently, the sections were joined by hyperbaric tie-ins at KP 297 and KP 675 thus creating a single 760-mi (1,223-km) pipeline.

Saipem was selected as the contractor for construction activities, while Baker Hughes was the selected contractor for the pre-commissioning work. The design and construction concept had a significant impact on the pre-commissioning execution.

Pre-commissioning concept

The initial concept was based on water filling from onshore to onshore, using large-diameter crossovers at the subsea tie-in locations for flooding. High-pressure crossovers would then be installed for pressure testing. Thus, all three sections of the pipeline had to be laid before commencing pre-commissioning operations.

Since the German area consisted of an almost closed bay with very shallow water and low currents, flooding was to be performed from Russia to Germany with dewatering in the opposite direction. This plan required a water winning and injection spread to be installed at the Russian landfall, with an air spread installed at the German landfall.

In an effort to reduce the environmental impact of the water treatment as much as possible, caustic soda (NaOH) and sodium bisulphite (NaHSO3) were initially selected as additives; the first to stifle anaerobic bacteria activity, the latter as an oxygen scavenger. The use of caustic soda generated significant concerns because of the possibility of precipitation of carbonates and blockage at crossover locations. Consequently, detailed water sampling and analysis trials were performed.

All pre-commissioning activities on the Nord Stream project were essentially “one-shot” operations that could not be repeated or reversed without major schedule impacts or affecting the permitting limitations for water disposal.

The pre-commissioning philosophy was further discussed and modified during the tendering phase with consultations between Nord Stream, Saipem, and Baker Hughes.

The resulting adopted philosophy was based on subsea intervention at the wet end of the sections from a subsea construction vessel (SCV). This philosophy enabled each section to be completed independently of any other sections, and enabled Section 1 (closest to Russia) to be pre-commissioned earlier in the year, while the sea at the Russian coast remained frozen and while Section 3 pipelay was still ongoing. This resulted in significantly increased schedule flexibility. The final pre-commissioning concept was established as:

• Pre-commissioning spreads onshore were located in autonomous areas separate from the construction sites used for the permanent facilities
• Pre-commissioning pigs for the subsea pipeline would not traverse the permanent pig traps or permanent valves
• Flooding, cleaning, and gauging (FCG) were performed offshore onboard the SCV. All subsea handling was performed by ROV
• Water was treated with sodium bisulphite and ultra violet light (UV) only
• Pressure test of sections 1 and 2 from SCV
• Pressure test of Section 3 from the receiving terminal in Germany (to reduce vessel time and risk from waiting on weather)
• De-watering from Germany with water discharge in Russia, after completion of subsea hyperbaric tie-in at KP 297 and KP 675
• Drying from Germany to Russia
• Nitrogen as a barrier between air and gas during commissioning of the pipelines.

The flooding, cleaning, gauging, and pressure-testing spread were installed onboard the Saipem vessel Far Samsonand included suction pumps, a water treatment system, flooding and pressure test pumps. In addition, pressure test pumps for Section 3 were installed at the German landfall.

Flooding, cleaning and gauging activities were performed by the crew aboard the subsea construction vessel. (Image courtesy Nord Stream)

The dewatering and drying spread was located at German landfall and included 15 x 760 cu m (530 x 26,839 cu ft) steel water tanks. The Russian landfall was developed as a water receiving facility, and included a settling pond and a temporary 20-in. floating discharge line.

The FCG pig train was designed to ensure that the operation could be completed in a single pig run while providing contingency pigs to account for wet buckle scenarios during pipe laying. For each section, four bi-directional pigs were used. The pigs were back loaded into the subsea test head and installed on the seabed up to one year before the operation.

Flooding, cleaning and gauging pig. (Image courtesy Nord Stream)

The dewatering pig train was designed to ensure that water removal and desalination could be completed in a single pig run:

• The first batch of four pigs was separated by slugs of potable water designed to dilute to an acceptable level the residual salt content remaining on the pipe wall
• The second batch of four pigs was separated by dry air to pick up water remaining after the desalination pigs
• The pig train was spaced so that the first four pigs could be received and removed before the arrival of the second set of four pigs.

Dewatering pig. (Image courtesy Nord Stream)

Key challenges

The Nord Stream pre-commissioning work scope provided several key challenges because of its size, geographic location and environmental sensitivity. These challenges included:

Pipeline length. This was the world’s longest offshore dewatering operation and the world’s longest sealing tool run. Experience from the pre-commissioning team and the pig vendor was important in ensuring that pig integrity could be maintained along the full pipeline length. It was also essential to establish the location of possible events, particularly in case of gauge plate damage or stuck pigs. This required the development of a carefully managed pig tracking system.

Pipeline volume and water depth. Each 48-in. pipeline had an internal volume of 1.3 MMcm (343 MMgal). The maximum water depth, combined with losses, required a dewatering pressure of 29 barg. Therefore, a very large air compressor spread was necessary in Germany.

Sealing tool. (Image courtesy Nord Stream)

Vessel limitations. Since the flooding spread was large, the SCV had to comply with challenging criteria including deck space, accommodations, ROVs, cranes, and power generators. The fitting of all necessary equipment for a safe operation required input from specialists and extreme attention to detail.

Weather. Most of the Baltic Sea freezes in winter. This limits the offshore operational window. Water winning and water disposal could not be performed while the sea was frozen.

Water treatment. The water treatment philosophy was refined to provide the most environmentally friendly approach, in compliance with the applicable international and local regulations, while maintaining corrosion protection and minimizing the possible formation of precipitates inside the pipeline.

Noise pollution. Strict noise restrictions required the purchase of a custom air-compressor-spread to ensure compliance.

Diesel handling and storage. Large diesel volumes for the compressor spread in Germany required a custom diesel storage and handling system to receive and distribute 100 cm/d (26,417 gal/d) of diesel with no containment loss.

Waste management. A comprehensive waste management system was implemented to separate, track, and manage all the waste produced during the project’s execution.

Schedule and execution

The contract for the Nord Stream pre-commissioning was awarded in August 2009. Tendering commenced early, allowing sufficient time for multiple concepts to be considered before settling on the preferred concept upon which the pre-commissioning contract was based. The tender period ran for about nine months concurrently with other project approvals to allow for immediate commencement.

The engineering procedures prepared for pre-commissioning totaled some 110 documents over an 18-month period, and which required review and approval by both Saipem and Nord Stream. The 18-month period was necessary not only for the base scope engineering, but also to evaluate all possible options and changes.

To meet the flow and pressure demands while achieving the strict environmental and noise targets set, a large percentage of the pre-commissioning equipment was procured new for the project. The early award afforded a 12-month period for equipment building, testing, and delivery. Despite robust contracting strategies, some vendors did not meet their delivery schedules; however, the window allowed sufficient float for this to not affect the project’s schedule.

The success and performance of the flooding, cleaning, gauging, and pressure testing operations can be attributed to 100% contingency of critical equipment and full onshore spread function testing, including all interconnection piping. It took 41 days to complete Pipeline 1 and 38 days to complete Pipeline 2.

The success and performance of the dewatering, drying, and nitrogen packing operations can be attributed to a combination of excellent pigs and reliable compressor spread performances.

The full pre-commissioning of each line was completed in less than 150 days from commencement of FCGT to the completion of nitrogen injection.

From the formation of the Nord Stream pre-commissioning team in early 2008, to the completion of pre-commissioning operations on Line 2 in August 2012, the following milestones were achieved:

• RFQ issued for pre-commissioning operations, November 2008
• Pre-commissioning contract awarded to Baker Hughes, August 2009
• Engineering and procurement operations commenced, September 2009
• Contracts placed for all Wet Buckle Contingency (WBC) equipment, December 2009
• WBC equipment mobilized and function-tested, March 2010
• Contracts placed for all pre-commissioning equipment, June 2010
• Pre-commissioning FCGT equipment mobilized, February 2011
• Operational period for FCGT on Line 1, March to May 2011
• Dewatering and drying equipment mobilized, June 2011
• Operational period to dewater, dry, and N2 pack Line 1, July to August 2011
• Line 1 gas in work completed, September 2011
• Operational period for FCGT on Line 2, March to May 2012
• Operational period to dewater, dry, and N2 pack Line 2, July to August 2012
• Line 2 gas in work completed, September 2012
• Pre-commissioning sites reinstated, October 2012.

Results

The subsea heads, the hot stabs, and the pig tracking system worked flawlessly during the FCGT operations.

All the FCG pigs performed as expected and no damage was observed. The water filtration, additive system, and pumping spread operated consistently at or above their specified duty.

Success of the flooding operation was demonstrated during the pressure test where air content was confirmed to be well within the DNV requirement of less than 0.2%.

The cleaning operation removed less than 2 kg (4.4 lb) of construction debris in each section, supporting the belief that almost all the construction debris was removed. Some iron oxide, small amounts of sand, and some red-colored dust were also removed.

The gauging plates confirmed the internal diameter to be within the design requirements. Out of six smart gauge runs, only one gave a damage indication (which was proved to be false).

The pressure test operations were all accepted after only hours of pressure stabilization prior to the mandatory 24-hour holding period. The main reason for the quick and successful pressure test was the favorable spring weather conditions, whereby the temperatures were similar at the surface and at the bottom of the Baltic Sea.

Dewatering and drying

The use of temporary onshore pig traps, together with the temporary 48-in. valve, resulted in a very smooth and controlled dewatering operation. This made it easier to control the operation and to keep water and air separated during the launching of the train. The train was launched with Pig 4 as a “perfect” barrier between the desalination water and the air.

The compressor spread and dryers, as well as all support systems, met or exceeded their specified duties throughout the operation. As planned, air injections ceased when the dewatering pig train had traveled 60% of the pipeline length, with the remaining pig travel driven by the expanding air. This was implemented to save fuel and to minimize the depressurization requirements after receipt of the pig train in Russia.

Throughout the dewatering operation, the pig tracking vessel followed the different pigs all the way to the Russian coast. First, the two sets of sealing tools (one set from KP 297 and one set from KP 675) arrived, and then the dewatering train. Such accurate pig tracking was necessary when diverting the water in front of each pig to the settling pond.

During the receipt of the pig train, the desalination water was checked for chloride content. The analysis demonstrated that the final chloride content was well below the specified limit of 200 ppm. The amount of water received in front of the swabbing pigs was very small.

Based on experience from Pipeline 1 (very little water), the flow in front of the swabbing pigs was routed through the silencers for Pipeline 2.

Based on calculations and observations, the amount of water in front of the swabbing pigs was less than 1 cu m (264 gal). This is an impressive result and occurred because of good pigs, internal coating, and very smooth operations (with only the use of the discharge control valve toward the end of the operation to maintain maximum 1 m/s velocity).

The desalination pigs showed little wear after traveling the length of the pipeline. The swabbing pigs showed greater wear, but still maintained sealing integrity. That indicates that they had been running mostly dry and confirmed the excellent results.

The drying operation for Pipeline 1 was completed after 18 days, and included a soak period of 24 hours. An atmospheric water dewpoint of better than -35°C (-31°F) was achieved and confirmed by a 24-hour soak period. Based on this, pipeline 2 was dried to better than -35°C and accepted without a soak period.

During the drying, 4.5 cu m (1,189 gal) of water was removed (calculated based on dew point readings and air volume). This corresponds to a water film thickness of 1 micron on the pipeline wall, and demonstrates the best dewatering results ever achieved (regardless of pipeline size and length). Dryness was also confirmed post-commissioning where gas dew point levels were recorded.

Nitrogen

To avoid explosive mixtures in the pipeline (as set out in DNV OS-F101) during commissioning (gas filling), there was a need to use an inert gas as a barrier between the air and the natural gas in the pipeline. For various reasons, nitrogen packing differed between lines 1 and 2:

• Line 1 was completely filled with 99.9% pure nitrogen from Germany
• Line 2 was partially filled from Russia (gas filling end) using a 99.9% pure nitrogen batch equal to 10% of the pipeline volume.

For both pipelines, the mixing zone between air and nitrogen was approximately 1.5 km (1 mi). The mixing zone between nitrogen and gas was approximately 2 to 3 km (1.25 to 1.86 mi).

It was important to maintain the interface velocity above the critical minimum to obtain these results.

Water treatment

Treatment of the sea water was carried out onboard the SCV where the seawater injection pumps were installed. Pre-commissioning water was pumped into the pipelines at KP297 and KP675.

The water treatment included the following steps:

• Filtration through 200 µm and 50 µm cartridge filters
• Online injection of oxygen scavenger (OS), a commercial solution of sodium bisulphite and iron-based catalyst
• UV light treatment.

The key analytical parameters of seawater for the control of the treatment operations were obtained in a laboratory onboard the SCV.

Metered amounts of OS were dosed and adjusted daily to match the measured oxygen concentrations of filtered seawater. Based on the results of the test program, the OS dosage rate was set at the stoichiometric value, equal to 6.5 mg OS/mg O2.

Dissolved oxygen concentrations in the filtered seawater were generally at saturation values (over-saturation concentrations were also measured at times), ranging between 12.5 mg/l and 15.0 mg/l.

Special attention was given to the potential environmental impact of oxygen depleted water at the discharge location. A special water diffuser was designed and installed. The purpose was to achieve a high re-oxygenation effect in the proximity of the discharge point. This was a requirement of the water discharge permit from the Russian authorities. The effectiveness of the diffuser was confirmed by field measurements during dewatering.

A UV treatment unit was also installed onboard the pre-commissioning vessel. The unit had a design “killing rate” of more than 99% of the initial bacteria count at effective UV dosages of 40 ÷ 60 mj/cm². Bacteriological analysis was carried out in the laboratory onboard the SCV during the FCG operations for both total anaerobic and total aerobic bacteria before and after the UV package.

The calculated “killing rates” for anaerobic bacteria were generally in-line with expectations.

The results and observations confirmed the management of the water treatment achieved the project targets. There was no measurable impact on the marine environment at the discharge location and preservation of the integrity of the pipelines was confirmed.

Environmental considerations

Most of the water was discharged directly into the sea. The water treatment, as presented above, was acceptable for direct discharge.

The discolored water in front of each pig was captured and settled before being discharged back to sea. This water was diverted to the water settlement pond. Water stored in the pond was discharged to sea through filters after a minimum 24-hour settling period. All water discharged to sea was clean and contained no oxygen.

The discharge point was 600 m (1,968 ft) offshore and was fitted with a diffuser nozzle to ensure rapid oxygenation of the water.

The discharge water was continuously monitored by the environmental authorities and showed compliance with local and international regulations (oxygen levels were found greater than 7 ppm well within 100 m (328 ft) distance from the diffuser as required by the regulations).

The noise generated in Germany was monitored by a third party. The compressor spread complied in full with the stringent noise limitations for the project.

The sound proofing of all individual units also improved the working environment for the operational personnel and improved safety, as normal verbal communication was possible within the area of the compressor spread.

Lessons learned

A summary of the lessons learned during the execution of the work underscored the importance of:

• Early identification and focus on long-lead items
• Early establishment of a pre-commissioning concept
• Early selection of main water source and water treatment regime
• Early start of engineering and planning
• Early involvement in permanent design work (identify pre-commissioning requirements)
• Early establishment of any additional local authority requirements
• Early establishment of pre-commissioning environmental basis
• Early identification of risks and maintaining a focus on them
• Maintaining a risk register with regular reviews and updates
• Maintaining focus on equipment and function tests
• Carefully selecting key subcontractors and suppliers
• Careful and comprehensive follow up and control of critical supplies and suppliers
• Approving procedures well in advance of field operations.

In addition to these, it was found that pig tracking was very useful for control of operation and for accurate information to stakeholders. And in general, the project also underscored the importance of maintaining continuity of key personnel.

Conclusion

Given the considerable challenges, pre-commissioning of the Nord Stream pipelines was remarkably successful. Besides being concluded within budget and ahead of schedule, the technical achievements were impressive. They included:

• World’s longest, single-section dewatering operation
• World’s longest travel distance for tie-in sealing tools
• Combined dewatering/sealing tool removal operation
• Effective dewatering operation confirmed by the quick-drying operation
• Quick and effective pressure test operations (favorable temperatures)
• Effective water pumping through two 6-in. LFH (2,500 cu m/hr or 0.66 m/s pig speed in 48-in. pipeline)
• Effective cleaning and gauging operations
• Effective pigs specifically designed for the work
• Successful pig tracking for good control and operational confidence
• Effective water treatment concept with practically no effect on the environment.

These results were obtained by experienced personnel working as a team and focusing on:

• Early engineering and planning
• Early involvement in pipeline design requirements
• Early focus on long-lead items (e.g. pipeline head)
• High-quality equipment and experienced personnel
• Continuous attention to safety, risk, and environment
• Correct procedures prepared early by involved personnel
• Professional operational execution, monitoring and control.

Acknowledgment

Based on a paper presented at the Deep Offshore Technology International Conference held Nov. 27-29, 2012, in Perth, Australia.

 

Source: Pre-commisioning the Nord Stream pipeline – Offshore, diakses Februari 2014.

Stability of Equilibrium

As noted, the buckling propensities of a system are reflected in the shape of the equilibrium path, ie. the load- deflection curve. If a system is in equilibrium then its total potential energy,   U, has a turning value since an infinitessimal disturbance,   dδ, of the system from its equilibrium position does not change the potential energy (PE) –   δ is any convenient characterising displacement. Expressed mathematically, the equilibrium path is thus defined by :

( 1a)           U’   ≡   dU/dδ   =   0

The type of equilibrium which exists at any point on the path – stable, neutral or unstable – is also an important consideration; it may be deduced by taking the second derivative :-

( 1b)           U”   ≡   d2U/dδ2	>   0   ;     PE – minimum     stable equilibrium
	=   0   ;     PE – zero slope     neutral equilibrium
	<   0   ;     PE – maximum     unstable equilibrium

It will be appreciated from the sketches above that, compared to the elementary load building blocks, the plate- like components of thin- walled structures are complex in their deflections and in the mathematical descriptions thereof. We shall therefore not attempt to analyse these components – the interested reader is instead referred to the literature on plates and shells.
It is important however to appreciate the general physical behaviour of plate- like components and how this is governed by the energy principles embodied in equations ( 1). We shall therefore apply the principles to various mechanisms to illustrate how the response may be stable or unstable – and significantly how imperfections affect behaviour. The conclusions reached for mechanisms are directly applicable also to plate- like components.

 

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We consider first a typical perfect mechanism which behaves in a stable, neutral or unstable manner depending on the mechanism’s geometry.

 

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Effect of imperfections

Perfect structures are figments of the imagination. If the mechanism above were manufactured, it would be impossible to ensure that initially A, B, and C all lay on the load’s line of action, or that both springs were completely free before the load was applied.

 

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Small imperfections can have a marked effect on buckling behaviour
as this example demonstrates.

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These examples, though dealing with one particular mechanism, confirm the following conclusions which are quite general for imperfect buckle- prone structures :

• Imperfections lead to deflections growing from the start of loading, and eliminate any sharp critical bifurcation point. Collapse is therefore not necessarily catastrophic as growing deflections warn of imminent failure.
• As deflections grow, the imperfect structure’s behaviour tends to that of the ideal structure.
• Imperfections reduce the load carrying capability of a structure for a given deflection, and also the maximum capacity ( p* above ) when the secondary path is unstable.
• The effects of imperfections are much more pronounced when the post- buckling path is unstable – for example   α = 2 above.
• For structures with neutral or stable post- buckling paths, the main effect of imperfections is usually to introduce high bending stresses at an early stage of loading thus leading to failure through strength limitations rather than geometric collapse. This conclusion influences the treatment of imperfect columns below.
• Different forms of imperfection – for example out-of-straightness compared to load eccentricity – give rise to similar behaviour. Thus if the sole imperfection in the above example were the load eccentricity   e shown here, rather than an initial out- of- straightness, then the resulting performance is very similar to that deduced previously for out- of- straightness. The reader should confirm these results.
• An important corollary of this last conclusion is the impossibility of categorising imperfections solely from the observed behaviour of a structure which is nominally ideal. Indeed such a categorisation is unnecessary in most cases, as, when all said and done, it is the behaviour itself which is important.

Submerged pipelines

With the gradual depletion of easily exploitable gas and oil fields, less accessible sub-sea reserves are being increasingly tapped. The distribution pipework of these often lie at depths of around 200 m and is thus subjected to substantial external pressures. It is imperativethat pipe buckling is prevented as it propagates catastrophically, being driven by a longitudinal component of the water pressure at the speed of sound in the metal wall. Cross- sections taken from various positions along a partially collapsed pipe are shown on the left here.

The minimum pressure which maintains buckle travel in a particular pipe is the critical   propagation pressure,   p_c for the pipe, and we turn now to the prediction of this   ‘buckling load.’

The buckled shape indicates gross plastic deformation – indeed elastic effects pale into insignificance and the pipe material assumed to be perfectly plastic, with yield strength   S_y. As a result of this non-conservatism, the energy methods of the previous sections cannot be used; however work-energy principles are applicable.

The adopted model consists of unit length of the thin pipe ( t/D –> 0 ) illustrated here, with four   plastic hinges – a, b, c and d. Deformation occurs only at the hinges, so the four lobes of the cross- section rotate about the hinges without otherwise deforming, thus forming the collapsed shape a’, b’, c’, d’.

The material at a plastic hinge is taken to be perfectly plastic – ie. stresses can only be either zero or yield as shown at ( i) below. If pure bending occurs across the thickness   t then tensile yield extends across half the thickness ( ii) and compressive yield extends across the remaining half thickness. The resultant ( iii) of each stress block is a force   S_y t/2 ( per unit length). The hinge therefore develops a constant bending moment   M_y = S_y t² /4 per unit length as collapse proceeds ( iv).

The work-energy principle may now be applied to the propagation pressure collapsing the plastic hinged model.
Work done by external propagation pressure :
=   pressure ∗ change in volume   ;     or, per unit length :
=   p_c ∗ decrease in cross- sectional area   =   p_c ∗ square area a–b–c–d   =   p_c D² /2
Strain energy gain of the four plastic hinges, per unit length :
=   4 M_y ∗ rotation of each hinge over the process   =   S_y t² ∗ π/2
Equating work and energy leads to an estimate of the propagation pressure :
p_c   =   π ( t/D )² S_y

The model underestimates the propagation pressure mainly because it neglects strain- hardening and the finite extent of the plastic hinges – this last may be appreciated by comparing the actual buckled shape with the collapsed model. A more realistic empirical expression fitted to experimental results is shown; this tends to the model as   t/D –> 0.

The ability of this simple model (without empiricisms) to provide a ball park estimate of the collapse load should be appreciated.

 

Source: DANotes: Buckling: mechanism stability, subsea pipeline collapse, diakses Februari 2014.