Steel Pipe Manufacturing Process

AMERICAN has been producing line pipe for a variety of applications since 1963. Our Birmingham, Ala., facility occupies more than 228,000 square feet under roof and includes two working mills and quality assurance chemical- and strength-testing laboratories on site.
ISO Certified Quality

AMERICAN Steel Pipe earned its ISO 9002 certification in May 1995. According to the International Organization for Standardization: “TheISO 9000 series of standards represents the essential requirements that every enterprise must address to ensure consistent production and timely delivery of goods and services to the marketplace.”

AMERICAN is proud to be recognized by this body as a compliant, certified company, reassuring our customers of our quality, integrity and sound business standards.
Production Process

AMERICAN utilizes a series of quality-controlled checkpoints and inspections that ensure an end product that meets specifications and exceeds your expectations. It all begins with the best in raw material.
Step 1: Purchasing



Quality control is embedded into all steps of our production process, beginning with the purchase of raw material. We use only high-quality, continuous-cast, fully killed, control-rolled, fine-grain, low-carbon steel. This coiled skelp is supplied by a number of dependable, reputable suppliers who have been associated with AMERICAN for years.

Skelp inventory is cross-checked against supplier documentation as received, and entered into a computer database.
Step 2: Loading



Coils are staged for entry according to order requirements, verified against database information, and loaded into the mill using a dual cone uncoiler.
Step 3: Edging



Skelp edges are sheared or milled to pre-specified widths and the lead end of each coil is squared for threading into the mill.
Step 4: Forming



Our mills utilize a modern, edge-forming system for controlled skelp shaping. This technology provides the latest innovations in forming, including pre-form stands, cage and internal forming, and fin pass stands to allow for a more precise cylinder.
Step 5: Welding



A high-frequency welder is utilized as operators examine and adjust weld parameters, including alignment, temperature, speed and trim removal.
Step 6: Weld Seam Annealing



Seam annealers provide heat to the weld area to a minimum temperature of 1600° F. Temperature is measured and recorded by an optical pyrometer linked to the mill computer system.
Step 7: Sizing/Cutting



Three sizing stands and one straightening stand are utilized to ensure that our pipe meets or exceeds API 5L specifications and additional standards as specified by customers. A rotary cutoff machine is used to cut pipe to length, and the mill computer automatically assigns a unique identification to each piece as it is cut.
STEP 8: Preliminary Inspecting



Each pipe is visually inspected to assure compliance with specified requirements. One pipe per coil is transferred to an ultrasonic inspection station for mill feedback prior to being routed back into normal processing.
STEP 9: End Finishing



Each pipe is machined on both ends according to API 5L bevel requirements or the customer’s specification.
STEP 10: Inspecting



Pipe is then routed through numerous tests including a hydrostatic test, an ultrasonic weld inspection, an end finish check, a wall thickness verification, a straightness evaluation, and an inside and outside surface visual inspection. Other tests are conducted on selected pipe or upon customer’s request.
STEP 11: Measuring/Coding



Each pipe is weighed, measured, stenciled and bar-coded for complete identification and traceability upon shipment. Pipe characteristics are verified against database order information before they are sent to shipping.

http://www.american-usa.com/resources/american-steel-pipe-resources/american-steel-pipe-manufacturing-process%20accessed%20on%2026/01/2014

Tanzania: Gas Pipeline Commissioning 2014

Written by Tanzania Daily News on 11/11/2013

THE 542-km gas pipeline from Mtwara to Dar es Salaam and the 150MW gas fired power plant at Kinyerezi 1 will be commissioned in December, next year as scheduled.

Execution of the mega projects will go a long way towards boosting power generation and solve electricity shortages, according to the Permanent Secretary in the Ministry of Energy and Minerals, Mr Eliakim Maswi.

"Not only will the projects ease shortages but they will also help the country to save money it has been spending to operate costly diesel-fired power plants," Mr Maswi said over the weekend.

The government has in the past been pumping between 900bn/- and 1.2tri/- annually to the Tanzania Electric Supply Company (Tanesco) to purchase oil to run power plants at Tegeta and Ubungo.

The PS made a three-day tour along the pipeline's route together with representatives of development partners, including the World Bank, African Development Bank (AfDB) and United States Agency for International Development (USAID).

"At present, natural gas accounts for between 40-45 per cent of power generation in the country but the rate will increase to about 80 per cent when the projects are completed," Tanesco's Managing Director Felchesmi Mramba said.

Through a loan of 1.9tri/- from Exim Bank of China, Tanzania is implementing the mega pipeline project that will also include construction of gas processing plants at Madimba in Mtwara and Songo Songo Island in Lindi. It will also include two power plants at Kinyerezi with capacities of generating 150MW and 240MW, respectively.

"The Kinyerezi 1 will be completed by August, next year while Kinyerezi 2 will be completed in one and half years," Mr Maswi said.

The processing plant at Madimba will have a capacity to process 200 million standard cubic feet (mscf) and it will have provisions which would allow the capacity be upgraded to 600 mscf while the pipeline will have a capacity to transport 780 mscf per day.

An existing 16-inch natural gas pipeline from Songo Songo to Dar es Salaam, which is owned by Pan African Energy has been facing capacity constraints amid growing energy demand in the country.

The new pipeline will include 36-inch pipes in a distance of 512km on land as well as 30km of 24-inch concretecoated pipe to run through the Indian Ocean from Songo songo Island to Somanga area in Lindi region.

"As we speak, 142-km long pipes have been joined through wielding and we expect to finish laying the pipeline by July next year," the Project Quality Manager, Mr Pieter Erasmus, said.

http://allafrica.com/stories/201311110439.html

Baltic Pipeline in Subsea tie-in Phase

During the two-week operation, two of the 1,224-km (760-mi) pipeline’s three sections offshore Finland will be joined inside a hyperbaric welding station.

As with the parallel Line 1, the three sections feature reduced pipe-wall thicknesses as the design pressure of the gas drops from 220 to 177.5 bar (3,191 to 2,574 psi) on its journey from Portovaya Bay, northern Russia to Lubmin on the German Baltic Sea coast. This design means there is no need for an interim compressor station, reducing the amount of steel required and allowing faster pipelay.

The hyperbaric tie-ins are being performed at two offshore locations where the design pressure changes from 220 to 200 bar (3,191 to 2,901 psi) and from 200 to 177.5 bar (2,901to 2,574 psi), respectively.

Connection of the central and southwestern sections will take place in June off the Swedish island of Gotland in a water depth of around 110 m (361 ft).

Welding operations will be set up by divers and remotely controlled from Technip’s DSV Skandi Arctic, using equipment from the pipeline repair system administered by Statoil on behalf of a pool of pipeline operators.

Three pipe-handling frames will be lowered from the vessel and positioned over the pipeline ends on the seabed. The frames will move the ends of the overlapping parallel pipeline segments to aline them for welding after they are cut to the correct length. Pipe ends will then be beveled and the pipes lifted and moved into place.

Welding should take a day. The weld will be inspected with ultrasound and, assuming an acceptable outcome, the welding equipment will be retrieved to the vessel while the pipe-handling frames lower the pipeline back on to the seabed.

All water will be removed from the completed pipeline during the summer followed by drying of the evacuated pipeline.

Nord Stream 2’s onshore and offshore sections will be connected early in the fall, and after testing, the line is scheduled to come onstream before end-2012.

http://www.offshore-mag.com/articles/2012/05/baltic-pipeline-in-subsea-tie-in-phase.html accessed on 26/01/2014

Underwater Welding

Intrduction

The fact that electric arc could operate was known for over a 100 years. The first ever underwater welding was carried out by British Admiralty – Dockyard for sealing leaking ship rivets below the water line. Underwater welding is an important tool for underwater fabrication works. In 1946, special waterproof electrodes were developed in Holland by ‘Van der Willingen’. In recent years the number of offshore structures including oil drilling rigs, pipelines, platforms are being installed significantly. Some of these structures will experience failures of its elements during normal usage and during unpredicted occurrences like storms, collisions. Any repair method will require the use of underwater welding. 

Classification

Underwater welding can be classified as 

1) Wet Welding 

2) Dry Welding 

In wet welding the welding is performed underwater, directly exposed to the wet environment. In dry welding, a dry chamber is created near the area to be welded and the welder does the job by staying inside the chamber. 

Wet Welding

Wet Welding indicates that welding is performed underwater, directly exposed to the wet environment. A special electrode is used and welding is carried out manually just as one does in open air welding. The increased freedom of movement makes wet welding the most effective, efficient and economical method. Welding power supply is located on the surface with connection to the diver/welder via cables and hoses. In wet welding MMA (manual metal arc welding) is used. 

Power Supply used : DC 

Polarity : -ve polarity 

When DC is used with +ve polarity, electrolysis will take place and cause rapid deterioration of any metallic components in the electrode holder. For wet welding AC is not used on account of electrical safety and difficulty in maintaining an arc underwater. 

The power source should be a direct current machine rated at 300 or 400 amperes. Motor generator welding machines are most often used for underwater welding in the wet. The welding machine frame must be grounded to the ship. The welding circuit must include a positive type of switch, usually a knife switch operated on the surface and commanded by the welder-diver. The knife switch in the electrode circuit must be capable of breaking the full welding current and is used for safety reasons. The welding power should be connected to the electrode holder only during welding. Direct current with electrode negative (straight polarity) is used. Special welding electrode holders with extra insulation against the water are used. The underwater welding electrode holder utilizes a twist type head for gripping the electrode. It accommodates two sizes of electrodes. The electrode types used conform to AWS E6013 classification. The electrodes must be waterproofed. All connections must be thoroughly insulated so that the water cannot come in contact with the metal parts. If the insulation does leak, seawater will come in contact with the metal conductor and part of the current will leak away and will not be available at the arc. In addition, there will be rapid deterioration of the copper cable at the point of the leak.

Hyperbaric Welding (Dry Welding)

Hyperbaric welding is carried out in chamber sealed around the structure o be welded. The chamber is filled with a gas (commonly helium containing 0.5 bar of oxygen) at the prevailing pressure. The habitat is sealed onto the pipeline and filled with a breathable mixture of helium and oxygen, at or slightly above the ambient pressure at which the welding is to take place. This method produces high-quality weld joints that meet Xray and code requirements. The gas tungsten arc welding process is employed for this process. The area under the floor of the Habitat is open to water. Thus the welding is done in the dry but at the hydrostatic pressure of the sea water surrounding the Habitat. 

Risk Involved

There is a risk to the welder/diver of electric shock. Precautions include achieving adequate electrical insulation of the welding equipment, shutting off the electricity supply immediately the arc is extinguished, and limiting the open-circuit voltage of MMA (SMA) welding sets. Secondly, hydrogen and oxygen are produced by the arc in wet welding. Precautions must be taken to avoid the build-up of pockets of gas, which are potentially explosive. The other main area of risk is to the life or health of the welder/diver from nitrogen introduced into the blood steam during exposure to air at increased pressure. Precautions include the provision of an emergency air or gas supply, stand-by divers, and decompression chambers to avoid nitrogen narcosis following rapid surfacing after saturation diving. For the structures being welded by wet underwater welding, inspection following welding may be more difficult than for welds deposited in air. Assuring the integrity of such underwater welds may be more difficult, and there is a risk that defects may remain undetected. 

Advantage of Dry Welding

1) Welder/Diver Safety – Welding is performed in a chamber, immune to ocean currents and marine animals. The warm, dry habitat is well illuminated and has its own environmental control system (ECS). 

2) Good Quality Welds – This method has ability to produce welds of quality comparable to open air welds because water is no longer present to quench the weld and H2 level is much lower than wet welds. 

3) Surface Monitoring – Joint preparation, pipe alignment, NDT inspection, etc. are monitored visually. 

4) Non-Destructive Testing (NDT) – NDT is also facilitated by the dry habitat environment. 

Disadvantage of Dry Welding

1) The habitat welding requires large quantities of complex equipment and much support equipment on the surface. The chamber is extremely complex. 

2) Cost of habitat welding is extremely high and increases with depth. Work depth has an effect on habitat welding. At greater depths, the arc constricts and corresponding higher voltages are required. The process is costly – a $ 80000 charge for a single weld job. One cannot use the same chamber for another job, if it is a different one. 

Advantage of Wet Welding

Wet underwater MMA welding has now been widely used for many years in the repair of offshore platforms. The benefits of wet welding are: 

1) The versatility and low cost of wet welding makes this method highly desirable. 

2) Other benefits include the speed. With which the operation is carried out. 3) It is less costly compared to dry welding. 

4) The welder can reach portions of offshore structures that could not be welded using other methods. 5) No enclosures are needed and no time is lost building. Readily available standard welding machine and equipments are used. The equipment needed for mobilization of a wet welded job is minimal. 

Disadvantage of Wet Welding

Although wet welding is widely used for underwater fabrication works, it suffers from the following drawbacks: - 

1) There is rapid quenching of the weld metal by the surrounding water. Although quenching increases the tensile strength of the weld, it decreases the ductility and impact strength of the weldment and increases porosity and hardness. 

2) Hydrogen Embrittlement – Large amount of hydrogen is present in the weld region, resulting from the dissociation of the water vapour in the arc region. The H2 dissolves in the Heat Affected Zone (HAZ) and the weld metal, which causes Embrittlement, cracks and microscopic fissures. Cracks can grow and may result in catastrophic failure of the structure. 

3) Another disadvantage is poor visibility. The welder some times is not able to weld properly

Principle of Operation of Wet Welding

The process of underwater wet welding takes in the following manner: The work to be welded is connected to one side of an electric circuit, and a metal electrode to the other side. These two parts of the circuit are brought together, and then separated slightly. The electric current jumps the gap and causes a sustained spark (arc), which melts the bare metal, forming a weld pool. At the same time, the tip of electrode melts, and metal droplets are projected into the weld pool. During this operation, the flux covering the electrode melts to provide a shielding gas, which is used to stabilize the arc column and shield the transfer metal. The arc burns in a cavity formed inside the flux covering, which is designed to burn slower than the metal barrel of the electrode.

Developments in Underwater Welding

Wet welding has been used as an underwater welding technique for a long time and is still being used. With recent acceleration in the construction of offshore structures underwater welding has assumed increased importance. This has led to the development of alternative welding methods like friction welding, explosive welding, and stud welding. Sufficient literature is not available of these processes. 

Scope for Further Developments

Wet MMA is still being used for underwater repairs, but the quality of wet welds is poor and are prone to hydrogen cracking. Dry Hyperbaric welds are better in quality than wet welds. Present trend is towards automation. THOR – 1 (TIG Hyperbaric Orbital Robot) is developed where diver performs pipefitting, installs the trac and orbital head on the pipe and the rest process is automated. Developments of diverless Hyperbaric welding system is an even greater challenge calling for annexe developments like pipe preparation and aligning, automatic electrode and wire reel changing functions, using a robot arm installed. This is in testing stage in deep waters. Explosive and friction welding are also to be tested in deep waters. 

References 

1) D. J Keats, Manual on Wet Welding. 

2) Annon, Recent advances in dry underwater pipeline welding, Welding Engineer, 1974. 

3) Lythall, Gibson, Dry Hyperbaric underwater welding, Welding Institute. 

4) W.Lucas, International conference on computer technology in welding. 

5) Stepath M. D, Underwater welding and cutting yields slowly to research, Welding Engineer, April 1973. 

6) Silva, Hazlett, Underwater welding with iron – powder electrodes, Welding Journal, 1971.  

http://www.metalwebnews.com/howto/underwater-welding/underwater-welding.pdf

Pipeline Pigging

Pipeline Pigging Products is a manufacturer of Internal Pipeline Cleaners referred to in the trade as “Poly Pigs.” Constructed of a flexible open cell polyurethane foam and various external wrappings, Poly Pigs have the ability to negotiate short radius bends, ells, tees, multi-dimensional piping and reduced port valves.

The slightly oversized Poly Pig forms a “sliding seal” in the pipe, and is designed to remove product buildup, foreign matter and loose sediment.

How Does Pipeline Pigging Work?

While buildup in a pipeline can cause transmittal slows or even plugging of the pipeline, cracks or flaws in the line can be disastrous. A form of flow assurance for oil and gas pipelines and flowlines, pipeline pigging ensures the line is running smoothly.

The maintenance tool, pipeline pigs are introduced into the line via a pig trap, which includes a launcher and receiver. Without interrupting flow, the pig is then forced through it by product flow, or it can be towed by another device or cable. Usually cylindrical or spherical, pigs sweep the line by scraping the sides of the pipeline and pushing debris ahead. As the travel along the pipeline, there are a number functions the pig can perform, from clearing the line to inspecting the interior.

There are two main hypotheses for why the process is called "pipeline pigging," although neither have been proved. One theory is that "pig" stands for Pipeline Intervention Gadget. The other states that a leather-bound pig was being sent through the pipeline, and while it passed, the leather squeaked against the sides of the pipe, sounding like a squealing pig.

Engineers must consider a number of criteria when selecting the proper pig for a pipeline. First, it's important to define what task the pig will be performing. Also, size and operating conditions are important to regard. Finally, pipeline layout is integral to consider when choosing a pig.

Because every pipeline is different, there is not a set schedule for pigging a line, although the quantity of debris collected in a pipeline and the amount of wear and tear on it can increase the frequency of pigging. Today, pipeline pigging is used during all phases of the life of a pipeline.

Types Of Pipeline Pigs

Although first used simply to clear the line, the purpose of pipeline pigging has evolved with the development of technologies. Utility pigs are inserted into the pipeline to remove unwanted materials, such as wax, from the line. Inline inspection pigs can also be used to examine the pipeline from the inside, and specialty pigs are used to plug the line or isolate certain areas of the line. Lastly, gel pigs are a liquid chemical pigging system.

Debris after piggingSource: www.ppsa-online.com

Similar to cleaning your plumbing line,utility pigs are used to clean the pipeline of debris or seal the line. Debris can accumulate during construction, and the pipeline is pigged before production commences. Also, debris can build up on the pipeline, and the utility pig is used to scrape it away. Additionally, sealing pigs are used to remove liquids from the pipeline, as well as serve as an interface between two different products within a pipeline. Types of utility pigs include mandrel pigs, foam pigs, solid cast pigs and spherical pigs.

Pipeline pig

Source: www.pipeline-pigging.com

Inspection pigs, also referred to as in-line inspection pigs or smart pigs, gather information about the pipeline from within. . The type of information gathered by smart pigs includes the pipeline diameter, curvature, bends, temperature and pressure, as well as corrosion or metal loss. Inspection pigs utilize two methods to gather information about the interior condition of the pipeline: magnetic flux leakage (MFL) and ultrasonics (UT). MFL inspects the pipeline by sending magnetic flux into the walls of the pipe, detecting leakage, corrosion, or flaws in the pipeline. Ultrasonic inspection directly measures the thickness of the pipe wall by using ultrasonic sounds to measure the amount of time it takes an echo to return to the sensor

Specialty pigs, such as plugs, are used to isolate a section of the pipeline for maintenance work to be performed. The pig plug keeps the pipeline pressure in the line by stopping up the pipeline on either side of where the remedial work is being done.

A combination of gelled liquids, gel pigs can be used in conjunction with conventional pigs or by themselves. Pumped through the pipeline, there are a number of uses for gel pigs, including product separation, debris removal, hydrotesting, dewatering and condensate removal, as well as removing a stuck pig.

Because there now exist multi-diameter pipelines, dual and multi-diameter pigs have been developed, as well.

http://www.rigzone.com/training/insight.asp?insight_id=310&c_id=19 http://www.pipepigs.com/

Decommissioning Regulations for Pipelines

Although a number of international treaties govern the disposal of waste at sea, including the management of decommissioned offshore structures, there are no international regulations or guidelines, relating specifically to the decommissioning of pipelines. At present, pipeline decommissioning is covered within national legislation.

In the UK, the Petroleum Act 1998 [Ref 3] outlines the requirements for owners of installations and pipelines

to obtain approval for their decommissioning programme from the Secretary of State. The decommissioning programme should contain details of cost and proposals for removal and disposal. It must be supported by an EIA and is submitted to the Department for Energy and Climate Change (DECC).

Pipelines should be the subject of a separate decommissioning programme unless they are located within the same field as other equipment or installations to be decommissioned at the same time.

In addition to the approval of the decommissioning programme for a pipeline, the following may also be required:

• Confirmation that the requirements of the Coast Protection Act 1949 Section 34 Part II have been satisfied

• Fulfilment of notification requirements for the Health and Safety Executive (HSE) under regulation 22 of the Pipeline Safety Regulations 1996 [Ref 7]

• Any environmental consents or permits required during decommissioning activity

• Disposal of materials on shore must comply with relevant health and safety, pollution prevention and waste requirements/permits

If part or the entire pipeline is to be removed or the decommissioning programme would result in a change to 

any part of the Table A information in the original Pipeline Works Authorisation (PWA) then a PWA Variation would also be required.

If the approved decommissioning programme for a pipeline contains proposals for the placement of associated materials on the seabed such as rock dump, then a licence must be obtained under the Marine and Coastal Access Act 2009 [Ref 4] in England and Wales or the Marine (Scotland) Act 2010.

In Norway, pipelines and cables are not specifically referred to in Chapter 5 Decommissioning, of the Petroleum Act 1996. They are, however, covered by a separate White Paper 47 (1999–2000), ‘Disposal of Pipelines and Cables on the Norwegian Continental Shelf’.

Notification of Disused Pipelines

In the UK, the owner of a pipeline must notify the DECC when a pipeline reaches the end of its operational life. Under certain circumstances, this may be before other facilities in the same field. In such cases the DECC may consider the deferral of decommissioning for the pipeline until the end of the whole field life.

Some pipelines may represent important UKCS infrastructure and provide the means for future development of hydrocarbons reserves, or storage of carbon dioxide or gas in the basin. To allow for the future reuse, the decommissioning of such pipelines may also be deferred. 

The deferral of pipeline decommissioning to the end of field life or for possible reuse is carried out under the ‘Interim Pipeline Regime’ (IPR). The DECC will send the pipeline owner a Disused Pipeline Notification form requesting details on the status of the pipeline. The DECC will consult with other government departments and then issue a letter outlining the conditions under which it is prepared to defer decommissioning to a specified date. If reuse of the pipeline is considered viable, then suitable and sufficient maintenance of the pipeline is required of the owner.

http://www.oilandgasuk.co.uk/cmsfiles/modules/publications/pdfs/OP083.pdf

Crack Detection in Gas Pipelines

Intelligent pigs, which detect geometry defects and metal loss in long distance pipelines have been around for many years. It has also been possible for several years to detect crack-like defects with the ultrasonic method in liquid pipelines. In gas lines, however, the detection of crack-like defects incurs a high additional cost because the ultrasonic method requires a coupling liquid, and ultrasonic pigs can only be run with a liquid batch. A crack detection pig for gas pipelines was therefore urgently required.

The new EmatScan® CD is capable of detecting crack-like defects in gas pipelines with the ultrasonic method without a coupling liquid. The EmatScan® CD utilises EMAT (Electro Magnetic Acoustic Transducer) technology, whereby the ultrasonic pulse is generated electro-magnetically inside the material by an electric pulse applied to a coil in the sensor. The EmatScan® CD has already successfully inspected several gas pipelines in North America and is currently available in the size of 36 inches.

Introduction

High pressure long distance pipelines transporting gas, crude oil or products are inspected by intelligent pigs for the location of defects. These inspections are an important contribution to the continued safe operation of these pipelines.

Typical defects are geometrical anomalies, metal loss and crack-like defects. Intelligent pigs are measuring robots which are propelled through the pipeline to detect defects, using appropriate measuring techniques.

For geometrical anomalies, pigs with mechanical sensors have been used for many years. It is customary to inspect new pipelines with calliper pigs prior to commissioning.

In the 1970s metal loss (corrosion) was the type of anomaly that caused the development of the first intelligent pigs. For metal loss two technologies are customarily used: the ultrasonic method, which measures the wall thickness directly, or the magnetic flux leakage (MFL) method, which responds to the change of the magnetic field in the presence of metal loss.

The ultrasonic method is the more accurate method, but a coupling liquid is required to apply the ultrasonic pulse to the pipe wall. It is therefore mainly used in liquid pipelines. The MFL method, on the other hand, does not require a coupling liquid and is therefore the preferred method for gas pipelines. Both types of instrument have been operated for many years and play a central role in the upkeep and maintenance of high pressure long distance pipelines.

During the 1990s longitudinal crack like defects began to appear additionally in more and more pipelines causing serious problems. This led to the development of a new generation of crack detection pigs.

Types of Cracks

Even though isolated fatigue cracks have been seen since the 1970s, it was the increased appearance of stress corrosion cracking (SCC) defects in the 1990s that led to some spectacular pipeline failures in Russia and North America. Figure 1 shows typical SCC colony.

SCC develops in pipelines under narrowly defined conditions. These include: susceptibility of the steel, moisture of the soil, soil chemistry, quality of the coating, variable stress and highly increased temperatures. SCC first appeared in the above mentioned areas mainly in high pressure pipelines directly downstream of compressor stations and now also occurs more and more often in liquid pipelines, even though these lines do not display increased temperatures.

Apart from SCC, metal fatigue cracks are becoming increasingly common, mainly due to the increasing accumulated number of pressure cycles in the aging pipeline population.

Cracks, which influence the structural integrity of the pipeline, are mainly longitudinally orientated, caused by the predominant stress distribution in the steel. Fatigue cracks can grow both from the internal or the external surface of the wall. Because of the growth mechanism, SCC cracks are external defects.

Batching with UltraScan® CD

In the early 1990s the UltraScan® CD crack detection pig was developed by GE Energy. It uses angular beam ultrasonic technology to detect longitudinal cracks. The sensors operate in the immersion mode, the transported fluid is used as coupling liquid.

The basic principle is demonstrated in Figure 2. The angular ultrasonic beam is reflected to and fro between the two surfaces at an angle of 45°. If the signal is reflected by a crack it travels back along the same path and is received by the same sensor as the echo signal. The appearance of the echo signal along the time coordinate indicates whether the crack is located internally or externally. As the tool is designed to detect longitudinal cracks the sensors are slanted with circumferential orientation to allow the beam to travel through the wall perpendicular to the longitudinal direction. In order to scan each defect from both sides two sets of sensors are employed, one operating clockwise, the other in an anti-clockwise direction. Each ultrasonic pulse is monitored up to two and a half full reflections (skips), meaning each crack is seen by several sensors from different distances. This results in a redundancy of information which is important to guarantee a reliable detection of the cracks and to differentiate between real cracks and harmless small inclusions in the material.

The multitude of sensors are mounted on the sensor carrier so that the entire pipe circumference is scanned in one pass (Fig. 3). The effective distance between sensors in circumferential direction is about 10 mm. The individual skids of the sensor carrier are mounted in such a way that geometric irregularities of the pipe are compensated and the sensors are always locally orientated with the right angle to the wall.

During the inspection, large amounts of data are generated. During the travel of a 24 inch UltraScan® CD tool through a 100 km long pipeline, 100 terra bytes of primary data are generated. The data is screened in real time for signals relating to crack like defects and only those signals are stored in the on board solid state memory. To achieve this, the most advanced FPGA electronic components are employed in the tool.

The UltraScan® CD detects all defects of 25 mm minimum length and 1 mm minimum depth. The data is displayed as a coloured area scan (C-Scan). The colour displays the intensity of the reflected signal according to the colour code. The intensity of the signal is an indication of the depth of the defect (Figure 4). UltraScan® CD tools have inspected more than 15 000 km of pipeline since their introduction in 1994 and detected a total of 3000 SCC colonies and over 700 fatigue cracks.

The ultrasonic technology is established as the industry’s most reliable and accurate method to detect cracks. In liquid pipelines the UltraScan® CD can be applied directly in the transported medium. This is not the case in gas pipelines, because the coupling liquid is not readily available. To inspect a gas pipeline reliably for cracks the UltraScan® CD tool has been run in a liquid batch in recent years (Figure 5). Even though this batch technology is well proven, it causes interruptions in the production and additional cost. These interruptions not only lead to loss of income for the line operator, but are often simply not possible because of the dependency of the end customer on the delivery.

A solution of this dilemma is now offered with the EmatScan® CD.

EmatScan® CD

For the EmatScan® CD the EMAT technology has been employed. This technology has the advantage that no coupling liquid is required. The ultrasonic pulse is generated inside the wall by an electro magnetic effect.

Principle of operation

Figure 6 demonstrates the difference between the standard piezoelectric sensor of the UltraScan® CD and the EMAT sensor. In the case of the piezoelectric sensor, the ultrasonic pulse is generated by a crystal inside the sensor and is transferred to the wall through the coupling liquid. The EMAT sensor, on the other hand, consists of a permanent magnet and an electric coil. The pipe wall is magnetised locally by the permanent magnet and an electric pulse sent through the coil generates eddy currents inside the wall. An eddy current flowing in the magnetic field gives rise to the so called Lorentz force, causing a deflection of the crystal lattice. Through this movement of the lattice the ultrasonic wave is generated right inside the metal itself.

Based on the orientation of the magnetic field and the eddy currents, ultrasonic waves are induced which travel in different directions inside the pipe wall. This mechanism also works in the reverse for the reception of an ultrasonic pulse.

In the case of the EmatScan® CD EMAT sensor three different waves are generated: the SH (shear horizontal) wave, the RH (rayleigh high frequency) wave and the TS (thickness shear) wave.

The individual waves fulfil different tasks: The SH wave front extends over the entire thickness of the wall and travels in circumferential direction through the wall. This wave provides the basic information, responding to any crack oriented in longitudinal direction. The RH wave only oscillates close to the internal surface and also travels in circumferential direction, responding to internal cracks only. By combining the information generated by the SH and RH waves it is possible to distinguish between internal and external cracks. This combined information is also used to estimate the depth of the crack. The TS wave travels perpendicularly into the wall and is used to measure the actual wall thickness of the pipe joint.

The EmatScan® CD features three sensor heads per sensor carrier equally spaced over the circumference. The sensor acts as transmitter and receiver. Each sensor head transmits an ultrasonic pulse, which, in the case of the existence of a crack like defect, is reflected and received by the same sensor. Part of this pulse also travels on around the circumference and is received by the adjacent sensor head as a very strong transmission signal.

The relevant information for the detected crack is deducted from the strengths of the reflected echo and the transmission wave. The part of the pipe circumference located between two sensor heads respectively is divided into three zones: the near gate for crack echoes which arrive ahead of the transmission signal of the neighbouring sensor head, the far gate for echoes which arrive after the transmission signal and the transmission gate for the reception of the transmission wave itself. Additionally there is a dead zone directly in the sensor head area from which no signals are received.

Based on the fact that each EMAT sensor head is able to scan a large portion of the pipe circumference, the EmatScan® CD tool only needs a total of 12 sensor heads located on four sensor carriers. The individual sensor carriers are mounted with an angular set off to allow for covering the entire pipe circumference.

Mechanical design

The EmatScan® CD is of modular design, similar to any modern pipeline inspection tool (Figure 7). The individual modules travel inside the pipeline on cups or rollers. They are connected by universal joints to allow the passing of bends. The electronic components are housed in pressure tight bodies. Electronically the individual bodies are connected by especially designed pressure tight cables and plugs. The first module houses the batteries for the power supply of the electronic system, while the second houses the electronic components for data treatment and storage. Trailing behind these modules are the four sensor carriers with three sensor heads each.

The cups of the first module seal the tool inside the pipe to allow for the build up of the differential pressure needed to propel the tool through the pipeline.

Since the SH wave front extends over the full thickness of the wall, the frequency of this wave is dependent on the wall thickness of the pipe. For pipelines with wall thickness that differ from the range of 9 to 16 mm sensor heads with different frequencies must be employed.

Test results

Inspection results are displayed as B-Scan and C-Scan. The B-Scan displays the signals of an individual sensor with respect to time (y-coordinate), with the sensor travelling down the pipeline displayed in the x-coordinate. The intensity of the received signal is displayed as colour, with red indicating the maximum intensity.

Figure 8 shows test results of defects with the minimum depth of 1 mm. The group of defects shown in Figure 9 feature different angles with respect to the longitudinal direction – this is clearly seen in the results. Figures 10 and 11 demonstrate the capability of the system to resolve two defects in close vicinity, both in the longitudinal direction (Figure 10) and in the circumferential direction (Figure 11).

By combining the results of the individual types of wave an estimate for the depth of the crack like defect can be determined. In the inspection report the depth is reported in 3 classes:

1) less than 2 mm deep

2) 2 mm to 5 mm deep

3) more than 5 mm deep.

Using the depth and length information the influence of each defect on the safe operating pressure of the pipeline can be calculated.

Economy

The EmatScan® CD tool provides an important contribution to the safe operation of gas pipelines, in that it detects with high probability all defects relevant for the structural integrity of the pipe material. Apart from the aspects of safety and environmental protection this also has positive economical consequences, eliminating the cost a failure of a gas pipeline would generate, not to mention the loss of public opinion connected to such an incident.

Special aspects

The EmatScan® CD can be employed in gas lines only. Due to the fact that the ultrasonic pulse needs to travel over relatively long distances around the circumference of the pipe, the medium or material in direct contact with the pipe wall has a great influence on the propagation of the wave. In liquid-carrying pipelines, a lot of the ultrasonic energy is lost by part of the wave migrating into the liquid, so that the signal amplitude vanishes before the wave reaches the Far Gate or the adjacent sensor.

The coil of the test head must be within 0.5 mm of the internal pipe surface. To achieve this, the coil section of the test head is gently pressed against the wall, causing it to slide along as the tool is progressing through the pipe line. One of the challenges during the development was to find the right material for the abrasion resistant layer on top of the sensor coil that at the same time would influence the strength of the electric signal as little as possible.

Field testing

The EmatScan® CD has completed runs successfully in several gas pipelines in North America. One of the lines was of special interest, because it had already been inspected by the UltraScan® CD running in a liquid batch. As a consequence of this the locations and dimensions of several crack-like defects were known prior to the EmatScan® CD run. All defects found by the reliable UltraScan® CD tool were also found by the EmatScan® CD.

by Hartmut Goedecke, Dipl Ing., Stephan Tappert, Dipl. Ing., Mirko Smuk, Dipl. Ing., Achim Hugger, Dipl. Ing., Josef Franz, Dipl. M

References :

1) Yemoans M.; Ashworth B.; Strohmeier U.; Hugger A.; Wolf T.; “Development of 36” EmatScan” CD Crack Detection Tool”, International Pipeline Conference 2002, Calgary, Canada

2) Ashworth B.; Willems H.; Uzelac N.; Barbian O.A.; “Detection and Verification of SCC in a Gas Transmission Pipeline”, International Pipeline Conference 2000, Calgary, Canada.

3) Ashworth B.; Ucelac N.; Willems H.; Barbian O.A.; “Detection and Verification of SCC in a Gas Transmission Pipeline”, International Pipeline Conference 1998, Calgary, Canada.

4) Willems H.; Barbian O.A.; Stripf H.; Gemmecke H. “UltraScan” CD – A new Tool for Crack Detection in Pipelines”,International Pipeline Monitoring and Rehabilitation Seminar 1995, Houston, USA.

http://pipeliner.com.au/news/crack_detection_in_gas_pipelines/043294/