Pipeline Ending Manifold (PLEM)/PLET

Pipeline Ending Manifold (PLEM) /PLET

Subsea manifold is a flow-routing subsea hardware (subsea flow router) that connects between subsea trees and flowlines. It is used to optimize the subsea layout arrangement and reduce the quantity of risers connected to the platform. If connected to dual flowlines, the manifold can typically accommodate pigging and have the capability of routing production from a particular tree to a particular flowline.

Pipeline End Manifold (PLEM)

It a simpler version of a cluster manifold generally designed to direct fluids for only one or two subsea Christmas trees. A PLEM generally connects directly to a subsea flow line without the use of a pipeline end termination (PLET).

Manifold Compenents

Four well manifold P&ID.

A manifold is typically composed of the following major components:

• Pipework and valves – contains and controls the production and injection fluids.
• Structure framework – protects and supports the pipework and valves.
• Subsea connection equipment – allows subsea tie-in of multiple pieces of equipment. Types include vertical, horizontal and stab-and-hinge-over connections.
• Foundation – interface between the manifold structure and seabed.
• Controls Equipment – allows the remote control of any hydraulically actuated subseamanifold valves and the monitoring of production and injection fluids. Control pods may be either internal or external to the manifold.

Valves

Valves on the manifold are essential for directing and controlling the flows. They can be either manual or hydraulically actuated. Sometimes chemical injection valves are placed on the manifold as well.

• Branch valves are generally slab type gate valves (similar to tree valves). Their sizes are based on the production/injection tree size.
• Flowline header valves are also gate type, but ball valves have been used previously. Their sizes are based on the flowline size.
• Materials are chosen for compatibility with production and injection fluids. Most of time, it is CRA-clad.
• Double barrier philosophy generally used against production fluids.
  • Two valves in series
  • One valve and one pressure cap
  • Primary seal is generally a metal-to-metal seal

Pipework

A wide range of pipework configurations is possible. Each header connects to an individual flowline. the pipework sizing is based on the tree piping size and the flowline diameters. The main circuit is designed to accommodate pigging operations. The material of construction needs to be compatible with production and injection fluids.

• Test headers can be incorporated to test individual or groups of trees
  • Test headers can be a second or even third header isolated in the manifold
• Insulation may be required for unscheduled or emergency shutdowns

Control System

Control system for the manifolds is the same as the control system for the trees. Multiple options for the control system have been used in the manifold design

• No controls on the manifold. The manifold is controlled by tree subsea control modules (SCMs).
• SCMs on the manifold.
• Manifold with control system distribution units with flying leads going to trees.

Framework Structure

The framework is a welded structure to provide support for the pipework and valves and contain the foundation interface structure. The pipework is allowed to float inside the framework within limits and it is not rigidly attached to the frame. The frame can also be used for lifting and landing of the jumper tie-in tools.

Foundation

• Mud mats – a simple foundation resting directly on the seabed, generally with a short skirt around the perimeter to resist lateral loads.
• Piles – long cylindrical structures embedded into the soil intended to hold a subsea structure above the seabed. Foundations may utilize one or more individual piles.
• Intermediate Structures – an intermediate structure can be used to interface a subsea manifold with a pile foundation to reduce weight of the manifold structure or to ease retrieval of the manifold. Intermediate structures can be either retrievable or permanent structures.

Tie-ins to wells and flowlines

The tie-in hubs placed on the outer edge of the manifold, which are used to tie-in jumpers that bring in fluid from the production wells and export fluid into the flowlines (production manifold). The tie-in sizing is based on the tree piping size and the flowline diameters. and the loads applied from the flowlines

Insulations

Generally gas manifolds are not insulated and oil manifolds are insulated. For oil production, insulation is necessary to allow adequate cool-down time to treat or remove trapped production water. Gas production is generally treated continuously with chemicals to prevent hydrates.

Deployment method

The following vessels are typically used for manifold deployment:

• Drill Rig: through moon pool or keel-hauled on drill string
• Heavy Lift vessels (Derrick Barges): through moon pool or over side
• Work-class vessels: over side on crane or winch

The following equipments are typically required:

• Manifold hydraulic installation tool
• Sling sets, either wire rope or synthetic fiber

Applicable API Specs

• API Spec 17P – Templates and Manifolds
• API Spec 17D – Specifications for subsea wellhead and Christmas tree equipments
• API Spec 17A – Recommended practice for design and operation of subsea production systems
• API Spec 17H, ISO 13628-8 – ROV Interfaces

Reference: http://www.piping-engineering.com/pipe-flanges-types-systems.html

Underwater welding by diver

Underwater Welding

Underwater welding is performed while the welder is submerged, often at elevated barometric pressures.  This introduces a variety of challenges that require specialized skills and training that are taught at CDA Technical Institute (formerly Commercial Diving Academy).  Because of the adverse conditions and inherent dangers associated with underwater welding (also known as wet welding) divers must be trained to an exceptionally rigorous standard with highly specialized instruction.

Wet Welding

Welding underwater can be acheived by two methods: wet welding & dry welding. Wet welding entails the diver to perform the weld directly in the water. It involves using a specially designed welding rod, and employs a similar process used in ordinary welding. Here are advantages to wet welding:

• Cheap and fast
• high tensile strength
• ease of access to weld spot
• no habitat
• no construction

Dry Welding / Hyperbaric Welding

Another method of welding underwater is hyperbaric welding or dry welding. Hyperbaric welding is the process by which a chamber is sealed around the structure that is to be welded. It is then filled with a gas (typically mixture of helium and oxygen, or argon), which then forces the water outside of the hyperbaric sphere. This allows for a dry environment in which to perform the weld. Here are some advantages to dry welding:

• welder / diver safety
• higher weld quality
• surface monitoring
• non-destructive testing

Underwater Welding AWS Certification

At CDA, students may earn an underwater welding certification, under AWS standards D3.6. The underwater welding qualification meets a strict standard and is only achieved by the most dedicated students. It requires successful completion of the practical portion of both the Top-side and the Underwater Welding course and recognizes Underwater Welding Qualifications for Class C fillet weld to AWS D3.6M.

Comprehensive Training

Our commercial diver training goes beyond underwater welding and our graduates are proficient in many other useful skills from underwater salvage, pipeline construction and repair, rigging, the operations of underwater tools (jack-hammers, hydraulic drills and chainsaws). These skills and certifications go beyond the required training and are a part of The CDA Advantage. They make graduates from CDA Technical Institute Air/Mixed Gas Commercial Diver Program a top choice for Diving Companies.  Click here for more information on CDA's curriculum and comprehensive commercial diving program.

Individuals interested in a career in underwater welding should know that this specific task represents only 5 to 10% of the duties a commercial diver will be expected to perform and is not a stand-alone career. This is why CDA is committed to providing comprehensive training in all aspects of commercial diving.  It is worth noting that CDA is the only school that is owned and operated by an active commercial diver and underwater welder! Founder Captain Ray Black has been an underwater welder since 1989 and has worked worldwide.

CDA prides itself on having a team of instructors with years of diving experience, international training and a combined military service of almost 200 years.  CDA Technical Institute is the only fully accredited dive school in the United States of America, owned and operated by an active Commercial Diver and Underwater Welder.  Capt. Black’s diving resume includes underwater welding throughout the world; in the deep seas off the coast of Singapore and Malaysia, Peru, Brazil, South Africa, Aberdeen Scotland (North Sea), and Israel (see video for footage of this dive).

“As a Commercial Diver and Underwater Welder, I have worked all over the world.  I have experienced different cultures, people and environments; I have seen the world from the surface and from the depths of the global seas. Being a commercial diver / underwater welder has afforded me and my family a life style that I can’t imagine that I could have had doing anything else.  From; Wet Welding (underwater) on 42 inch pipelines flowing with jet fuel to the Israeli Army, 9 clicks from the Gaza Strip, in the Mediterranean Sea to; repairing oil rigs off the coast of Peru and Chile, to; salvaging of a 300' / 1000 ton dry dock off the coast of Florida, that once supported and repaired the USS Constitution.  All my ventures into the sea have taught me the need and demand for quality Deep Sea Diver Training.  If you want to be an Underwater Welder, I would encourage you to take advantage of the world renowned, internationally recognized training my school offers and to take ahold of your life now, because "Knowledge is Power" when you choose to venture into the depths of the deep sea.”
“Make it Hot” - Capt. Ray Black

Reference: https://www.commercialdivingacademy.com/underwater-welding.cms

Pipeline mechanical connector/flange

Securing subsea pipeline integrity.

For pipelines suffering corrosion, scouring or mechanical damage, time is of the essence when executing a repair. Any reduction in the time taken to intervene and repair subsea pipelines, directly affects the time required on site by subsea contractors, divers and support vessels. Reduction in time means reduction in total service costs.

Pipeline integrity

The ultimate goal of Quickflange is to provide clients with the tools to facilitate management of subsea pipelines. In addition, Quickflange contributes to overall time and cost reductions by providing a solution that simplifies the process of terminating cut pipelines with standard flanges.

Pipeline mechanical connector

The solution is machined very simply from a standard, off-the-shelf ANSI flange (or other), and has no moving parts, gaskets, grips or other components. Connection is made through the use of a hydraulically activated cold-forge technique.

An effective pipeline repair tool

Quickflange is far smaller and lighter (up to 70%) than comparable systems. This ensures significant time savings, resulting in:

• Less time required to excavate the pipeline and remove coatings
• Minimal equipment required to deploy the flange – such as air-bags, deployment frames
• Less time required on the seabed to assemble and activate the flange compared to any other systems
• The same tools and procedures to assemble and bolt the Quickflange to the mating flange on the spool

The Quickflange system also includes external pressure test facilities as standard in order to verify successful activation, prior to spool assembly

Reference: http://www.quickflange.com/menu/technology--product/subsea-/c643971b-8fcf-4408-a9ad-839b729d840f/1

Pig trap /pig launcher/intelligent pig

About Pigs

Pipeline pigs are devices that are inserted into and travel throughout the length of a pipeline driven by a product flow. They were originally developed to remove deposits which could obstruct or retard flow through a pipeline. Today pigs are used during all phases in the life of a pipeline for many different reasons.

Although each pipeline has its own set of characteristics which affect how and why pigging is used, there are basically three reasons to pig a pipeline:

• To batch or separate dissimilar products;
• For displacement purposes;
• For internal inspection.

The pigs which are used to accomplish these tasks can be divided into three categories:

• Utility Pigs, which are used to perform functions such as cleaning, separating, or dewatering.
• In Line Inspection Tools, which provide information on the condition of the line, as well as the extent and location of any problems.
• Gel Pigs, which are used in conjunction with conventional pigs to optimize pipeline dewatering, cleaning, and drying tasks.

The type of pig to be used and its optimum configuration for a particular task in a particular pipeline should be determined based upon several criteria, which include:

• The purpose
  
  • Type, location, and volume of the substance to be removed or displaced in conventional pigging applications,
  • Type of information to be gathered from an intelligent pig run,
  • Objectives and goals for the pig run.
• The line contents
  • The contents of the line while pigging,
  • Available vs. required driving pressure,
  • Velocity of the pig.
• Characteristics of the pipeline
  
  • The minimum and maximum internal line sizes,
  • Maximum distance pig must travel,
  • Minimum bend radius, and bend angles,
  • Additional features such as valve types, branch connections, and the elevation profile.

UTILITY PIGS

Utility pipeline pigs can be divided into two groups based upon their fundamental purpose:

• Cleaning Pigs, which are used to remove solid or semi-solid deposits or debris from the pipeline.
• Sealing Pigs, which are used to provide a good seal in order to either sweep liquids from the line, or provide an interface between two dissimilar products within the pipeline.

Within these two groups, a further subdivision can be made to differentiate among the various types or forms of pigs:
• Mandrel pigs, which have a central body tube, or mandrel, and various components which can be assembled onto the mandrel to configure a pig for a specific duty;
• Foam pigs, which are molded from polyurethane foam with various configurations of solid polyurethane strips and/or abrasive materials permanently bonded to them;
• Solid cast pigs, which are moulded in one piece, usually from polyurethane, and;
• Spherical pigs or spheres, which are of either a solid composition or inflated to their optimum diameter with glycol and/or water. 

GEOMETRY PIGS

A geometry / caliper pig is a configuration pig designed to record conditions, such as dents, wrinkles, ovality, bend radius and angle, and occasionally indications of significant internal corrosion by making measurements of the inside surface of the pipe.

IN LINE INSPECTION TOOLS (ILI) / SMART PIGS

In Line Inspection provides information on the condition of the pipe and/or its contents. With few exceptions, the In Line Inspection Tool itself is simply the tool which gathers the data, which is then analysed by the engineers and technicians to determine and report on the condition of the line. 

Although the two most common requirements are for geometry/diameter measurement and for metal-loss/corrosion devices, the information which can be provided by these intelligent pigs covers a much wider range of inspection and troubleshooting needs which include:

Diameter / geometry measurements; Curvature monitoring; Pipeline profile; Temperature / pressure recording; Bend measurement; Metal-loss / corrosion detection;

Photographic inspection; Crack detection; Wax deposition measurement; Leak detection; Product sampling, and; Mapping.

 

PLUGS

A plug is a specialist pig that can be used to isolate a section of pipeline at pressure while some remedial work is undertaken. The plugs can withstand pressures up to 200 bars typically. The plug works by gripping into the line pipe and then having a separate sealing system. Lower pressure techniques include High Friction pigs, which provide a barrier for depressurised systems.

   

GEL PIGS

Gel pigs are a series of gelled liquid systems which have been developed for use in pipeline operations, either during initial commissioning, or as a part of a continuing maintenance program. Most pipeline gels are water-based, but a range of chemicals, solvents, and even acids can be gelled. Some chemicals can be gelled as the bulk liquid and others only diluted in a carrier. Gelled diesel is commonly used as a carrier of corrosion inhibitor in gas lines. There are four main types of gel that are used in pipeline applications:

• Batching, or separator gel
• Debris pickup gel
• Hydrocarbon gel
• Dehydrating gel

As a liquid, although highly viscous, the gel can be pumped through any line which will accept liquids. Gel pigs can be used alone (in liquid lines), in place of batching pigs, or in conjunction with various types of conventional pigs. When used with conventional pigs, gelled pigs can improve overall performance while almost eliminating the risk of sticking a pig.

Gel pigs do not wear out in service like conventional pigs. They can, however, be susceptible to dilution and gas cutting. Care must be taken, therefore, when designing a pig train that incorporates gel pigs to minimize fluid bypass of the pigs, and to place a conventional pig at the back of the train when displacing with gas.

The principle pipeline applications for gel pigs are as follows:

Product separation Debris removal Line filling/hydrotesting Dewatering and drying

Condensate removal from gas lines Inhibitor and biocide laydown Special chemical treatment Removal of stuck pigs

Specially formulated gels have also been used to seal valves during hydrostatic testing. Gels have been developed with a controlled gellation time and a controlled viscosity for temporary pipeline isolation purposes. 

PIG TRAPS/LAUNCHERS/RECEIVERS

Pig traps are used for inserting pigs into a pipeline then launching, receiving, and finally removing them without flow interruption. Pig traps are not generally proprietary products and are usually made to a specification drawn up by the user. However, pig trap closures are proprietary products and form a critically important part of a pigging system. Safety is a major consideration in the selection of a closure. All closures must have a built-in safety lock which prevents them being opened while the trap is pressurised. 

Reference: http://ppsa-online.com/about-pigs.php

Hydrotest on offshore pipeline

Leak detection equipment adapted for pipeline hydrotests, rehab projects

Pipeline leaks involve transition of the fluid from the internal pressure to the lower external pressure. This generates an acoustic signal, due to the turbulence and sudden expansion of the fluid mass.

Co.L.Mar's Acoustic Leak Detector (ALD) technology is designed to acquire and process the acoustic data and to extract the leakage from the ambient noise. The system's main components are an underwater acoustic sensor for acquiring the data along the pipeline; a transmission line to relay data to the surface vessel; a reception unit; and PC-based, proprietary software that evaluates in real time the signal acquired and its development along the pipeline track, analyzing the data from statistical, energetic, and spectral viewpoints.

ALD sensors in towed version.

The signal generated by a leak is detectable mainly as ultrasound, which the ALD receiver converts to an audible lower frequency. Different sensors are used depending on the operational mode:

• Towed fish, in which the sensor is towed along the pipeline track by a vessel at speeds of up to 6 knots, typically in water depths of up to 100 m (328 ft). This technique is suited to line inspections, with optional use of a USBL system for greater positioning accuracy
• Diver-manipulated (ALD-DIVER), in which the diver drives the system around the flange to be inspected, with the data sent via soft cable to the surface receiver
• Vertical deployment, suitable for line and flange inspections. The sensor is lowered from the vessel's side and kept vertical by means of a clump weight
• ROV-deployed, in which the sensor is installed on the vehicle, with the latter tracking the pipeline at a speed of around 0.5-1 knots.

Early this year, BJ Services contracted Co.L.Mar to support a pre-commissioning program for two newly installed, 48-in [1.2-m] gas pipelines in the Baltic Sea. ALD equipment and personnel were on standby during hydrotesting of the first of the 1,200-km (745-mi) lines, the equipment being supplied in both ROV and towed fish versions.

"There is an increasing need for pipeline contractors to have contingency services in case of leakage occurring during hydrotests," said Co.L.Mar Managing Director Luigi Barbagelata. "The client will not accept a pipeline if there are any leaks."

Pipeline inspection with ALD installed on an ROV.

For this project, Barbagelata noted, "the client asked us to adapt our towed fish system to work in water depths of up to 250 m [820 ft], which involved design and manufacture of a new ‘fish sensor' and towing system. Data acquired by the sensor are modified and transmitted by means of a single armored coaxial cable, also used for power injection."

During April and May, Co.L.Mar undertook a similar job in the Kazakh sector of the Caspian Sea. ALD equipment was sent offshore while personnel were on standby at the company's headquarters in La Spezia, northern Italy, after securing visas to avoid delays in any necessary response.

Acoustic leak detection is also used for pipeline rehabilitation projects.

"With this kind of inspection," Barbagelata explained, "it is common to encounter large leaks and low pressures, and in these cases chemical or optical sensors detecting particles in seawater can give positive results. For that reason, the ROV and diver-deployed ALD versions now feature a channel that can host an additional sensor – either a dye detector (fluorescin) or a hydrocarbon detector. Data from the extra sensor are multiplexed with acoustic information and sent to the surface via the same transmission line. In this way, it is possible to run a chemical and optical inspection of the pipeline simultaneously."

Recently, Co.L.Mar took delivery of an underwater leak simulator which simulates liquid and gas leaks across a range of pressures (2-200 bar, or 29-2,901 psi) and leak sizes.

"The on-site conditions can be replicated and the acoustic signal generated can be measured and used as a precise target reference," said Barbagelata. "During trials with the simulator, a signal is acquired by calibrated hydrophones and the data are processed using a proprietary software, allowing definition of each leak's source level and spectral distribution. This information allows us to better set up the equipment prior to an inspection with knowledge of the pressure and flow conditions."

For over a year, Co.L.Mar has also been working on a new monitoring system for leak detection on subsea structures. This would involve permanently installed sensors on critical equipment such as christmas trees, manifolds, subsea valves, and flanges.

"We are working on two types of sensors – one short range and omni-directional, which basically could detect a leak within a few meters of the subsea structure," Barbagelata noted. "The other would be bigger, and with a much larger operating range – perhaps 50 m [164 ft] – which would in addition give information on the direction of a leak. The main challenge is ensuring long-term reliability, because maintenance costs for subsea equipment are prohibitive."

Reference: http://www.offshore-mag.com/articles/print/volume-71/issue-11/italy-supplement/leak-detection-equipment-adapted-for-pipeline-hydrotests-rehab-projects.html

Pipeline pigging/how pipeline pig work

Pipeline Pigging with Smart Pigs

Smart Pigs or Pipeline Inspection Gauges are large pieces of machinery pulled together with powerful technology that help with the maintenance of transmission pipelines. These pipeline pigging devices are major components to pipeline safety and accident prevention.  These inspection tools provide data on the condition ofpipelines which help gauge the health and integrity of the pipes. In a time where environmental protection is key and of global concern, smart pigs are the peacekeepers of the delicate relationship between pipelines and Mother Earth (and regulators). In addition, these smart pipeline pigs make sure that transmission of the product doesn't stop due to pipeline integrity issues, which can be disasterous to the bottom line.

Fun Fact: Why are they called pigs? Well, besides it is an acronym for Pipeline Inspection Gauge, it is said that it is also because of the squealing sound they make when running through a pipe. This is especially true of the cleaning pigs used to clean pipelines.

High-quality pipeline construction is integral as these pipes operate under immense pressure. One leak can cause a massive explosion. {Refer to our pipeline information page to see how pipelines can leak}. Luckily, smart pigs are capable of diagnosing problems that can lead to these environmental disasters before they happen.

Types of Defects Dedected by Smart Pig Technology

In General, Smart Pigs are used to detect stress corrosion cracking, general and pitting corrosion.

In specific: gouges, dents, pit corrosion, anomalous weld seams, longitudinal cracks, longitudinal grooves, and general corrosion are all detectable.

Pipeline Smart Pigs Explained 

If you've ever had an MRI or know what one is then you can imagine a pipeline pig very similarly. These often two-ton objects are equipped with highly tuned sensors that can gauge the thickness of the pipes they are traveling through along with cracks, fissures, erosion and other problems that may affect the integrity of the pipeline. Data is collected and transmitted to a team that interprets that data to gauge the health of the pipeline segments being scanned. If any problems are found then teams not only know what the problem is thanks to a heavy set of data points, but know exactly where to go to replace the affected pipe thanks to highly tuned sensors.

You may think some poor chap is sitting with a remote control directing this behemith smart pig through hundreds or thousands of miles of pipeline, but these wonders of technology are free-swimming. This means that the pressure within the pipelines that help the gas or oil move "swiftly" through also keeps the smart pig moving up to ten miles per hour.

Common Terminology: When referring to using a smart pig inline inspection tool for a pipeline someone may refer to the process as "pigging the pipeline."

Some common synonyms for smart pigs:

Pipeline pig, pipe pig, pipeline inspection gauge, pipeline inline inspection tool, natural gas pipeline inspection, corrosion detection pig

Reference: smartpigs.net/ 

Crack on Offshore Pipelines

Stress corrosion cracking can be a serious threat to the integrity of natural gas and petroleum pipelines. The pipeline industry responded to this threat by performing a comprehensive research program to determine the cause(s) of the failures and investigate various techniques for preventing future failures. A relatively concise list of discoveries has had a measurable impact on mitigation of the stress corrosion cracking threat.

Stress corrosion cracking can be a serious threat to the integrity of natural gas and petroleum pipelines. Photo: DNV

Starting with the first recognized stress corrosion cracking failure in 1965, the intergranular form of cracking (also known as high-pH SCC) was investigated to identify the causative agent and the controlling metallurgical, environmental, and stress related factors. In the 1980s, a second, transgranular form of stress corrosion cracking (near neutral pH SCC) was discovered in Canada, resulting in a similar scope of research activities designed to develop mitigation methods for this form of cracking. The information developed in these research programs has been incorporated into pipeline integrity management programs.

Three techniques
There are three common techniques used for management of the integrity of pipelines subject to stress corrosion cracking and other time dependent threats; hydrostatic testing, direct assessment, and in-line inspection (ILI). Directly following the initial stress corrosion cracking failures of gas transmission pipelines in the 1960s, hydrostatic testing was the primary tool used to confirm the integrity of the affected pipelines and prevent additional failures. The pipelines were pressure tested with water at pressures significantly higher than the operating pressure in order to remove any near critical flaws. This technique has a number of limitations. Very few, if any, stress corrosion cracking flaws are removed, and the pipeline must be taken out of service for testing. In dry climates, obtaining adequate sources of water can be a challenge, while freezing of the water can be an issue in winter months or northern climates. For liquid petroleum pipelines, the water must be extensively treated prior to discharge back into the environment. There also is a finite probability of a phenomenon known as a pressure reversal occurring, where the failure pressure after a hydrostatic test is lower than the maximum test pressure, as a result of subcritical crack growth during the hydrostatic test.

Alternatives to hydrostatic testing
Because of these limitations, there has been significant interest within the pipeline community in the development of alternatives to hydrostatic testing. One alternative is SCC Direct Assessment (SCCDA). The first recommended practice for SCCDA was issued in 2004 (NACE Standard RP0204-2004). SCCDA is a structured process intended to assist pipeline companies in assessing the extent of stress corrosion cracking on buried pipelines, thus contributing to their efforts to improve safety by reducing the impact of external stress corrosion cracking on pipeline integrity. The term is somewhat of a misnomer in that the process is much more extensive than simply examining the pipeline for evidence of stress corrosion cracking.

The first step in the process (pre-assessment) involves the collection of existing information on the pipeline that can be used to assess the likelihood that the pipeline is susceptible to stress corrosion cracking. The applied research described above has formed the basis for establishing the critical information that should be collected. In the case of high-pH stress corrosion cracking, the initial selection of the most susceptible segments is based on five factors; operating stress (>60% of the specified minimum yield strength), temperature (>100°F), distance from compressor station (< 20 miles), pipeline age (>10 years) and coating type (other than fusion bonded epoxy (FBE)). In the case of near neutral pH SCC, there are four factors, excluding operating temperature.

Other types of information on the pipeline can be used for the selection of dig sites in the chosen segments. Again, much of this information is based on the applied research performed and includes factors such as topography, drainage, and soil type (near neutral pH SCC), the magnitude and frequency of cyclic pressure fluctuations, the specific coating type, including the girth weld coating, surface preparation for the coating, coating condition and prior history on the pipeline. A significant issue with SCCDA is that it is not capable of reliably identifying the location or locations of the most severe stress corrosion cracking on a pipeline segment. Accordingly, it is not necessarily a replacement for hydrostatic testing or in-line inspection in all instances. The pre-assessment phase of SCCDA may indicate that a particular pipeline segment is not likely to be susceptible to stress corrosion cracking and therefore, other threats are of a more immediate concern. An example would be a newer pipeline with an FBE coating. On the other hand, ILI, hydrostatic testing, or even pipe replacement may be warranted if extensive, severe stress corrosion cracking is found.

In-line inspection is the third technique used to manage time-dependent threats on operation pipelines. There is a long history of using magnetic flux leakage and, to a lesser extent, ultrasonic tools to address internal and extern corrosion threats on transmission pipelines. Around the time the NACE SCCDA recommended practice was being developed, there was a growing consensus within the pipeline industry that the new generation of crack detection tools would eliminate the need for hydrostatic testing or any of the elements of SCCDA. Integrity management would consist of four elements; find the cracks, size the cracks, assess the cracks and repair the cracks.

Unfortunately, the experience with crack detection tools has not been as desirable as had been hoped. Over the past few years, there have been at least two service failures of pipelines in which the operators were using crack detection tools for integrity management. In the case of one failure in Carmichael MS, the cause and contributing factors could not be confirmed because of extensive fire damage to the failed pipe. A portion of the fracture did propagate along the seam weld and the pipeline had a history of seam weld defects. The pipe section that contained the failure also had been previously hydrostatically tested at a pressure much higher than the failure pressure. This information, taken together, suggests that a likely cause of failure was the growth of a seam weld defect in service. In the second case, a failure near Marshall MI, there was evidence that fatigue cracks grew from a colony of pre-existing stress corrosion cracks.

Accuracy of crack sizing
The problem with the current generation of crack detection tools appears to be related to the accuracy of crack sizing. The tools are very good at finding crack-like features, and the length accuracy for the features also typically is good. The problem is the depth accuracy. The feature calls are usually binned by depth into several depths; e.g. <15% of wall thickness, 15–30% of wall thickness, 30–45% of wall thickness and >45% of wall thickness. Currently, there does not appear to be sufficient accuracy in the binning process for integrity management purposes. The failure pressures in pipelines containing cracks are much more sensitive to depth than to length of the flaws. The problem could be related to the precision and accuracy of the tool, or the analytical process for analyzing the tool data.

Because of these sizing issues, pipeline operators are sometimes required to perform a confirmatory hydrostatic test on portions of their system to demonstrate the performance of the crack detection tool. In some cases, pipeline operators also may be faced with a situation where a large number (thousands) of features are found on a segment of a pipeline. The elements of SCCDA can then be used, in conjunction with the standard crack sizing, to identify which feature are most likely to be an integrity threat and should be excavated. These elements are also used to prioritize pipeline systems for in-line inspection. The point is that fundamental understanding of the SCC process, developed through applied research, is still of significant value in integrity management.

As previously described, the information developed in the research programs is also used by pipeline companies to operate their pipelines in a way that reduces the risk of stress corrosion cracking failures. Where there is a risk of high pH SCC, after-coolers are installed at compressor stations to reduce outlet temperatures. Operators may control pressure fluctuations to reduce the risk of both forms of stress corrosion cracking. Cathodic protection systems are enhanced, monitored, and maintained to keep the pipe to soil potential out of the potential range for cracking. Finally, this research information is used by prudent operators in construction activities to reduce the risk of stress corrosion cracking in the future. Near white surface preparation procedures and coatings, such as FBE, are selected to minimize stress corrosion cracking initiation. Girth weld coating systems are selected to minimize shielding. The pipeline systems are designed to minimize operating temperatures and cyclic pressures.

Future trends
The detection and sizing capabilities of the crack detection tools will undoubtedly improve, but there will always be a need for elements of SCCDA, developed through applied research, to prioritize pipeline segments for inspection. Depending on the pace of improvements in the precision and accuracy of these systems, there may continue to be a necessity, for the near future, to use elements of SCCDA to help identify which features are most likely to be SCC threats.

Although not discussed in this article, there are other stress corrosion cracking threats to operating pipelines. Ethanol is used in almost all of the gasoline consumed in the United States as an oxygenating agent and octane booster. The current blend limit is 10% ethanol, but this may be increased to 15% in the near future. Denatured fuel grade ethanol is transported to terminals where it is blended with gasoline. Pipelines are the most efficient method to transport the ethanol but the threat of internal stress corrosion cracking has prevented general transportation via pipelines. Research is ongoing to address this threat.

A new internal stress corrosion cracking threat from alcohol was recently identified. Methanol is sometimes used as a drying agent for pipelines directly following hydrostatic testing. In northern climates, neat methanol is also sometimes used for hydrostatic testing to avoid freezing. There is growing evidence that this methanol has caused internal stress corrosion cracking of some pipelines; research is ongoing to address this threat.

Reference: https://pipabawahlaut.wordpress.com/category/crack-on-offshore-pipelines/