Crack Propagation on Pipeline

Polyethylene (PE) is the primary material used for gas pipe applications. Because of its flexibility, ease of joining and long-term durability, along with lower installed cost and lack of corrosion, gas companies want to install PE pipe instead of steel pipe in larger diameters and higher pressures. As a result, rapid crack propagation (RCP) is becoming a more important property of PE materials.

This article reviews the two key ISO test methods that are used to determine RCP performance (full-scale test and small-scale steady state test), and compare the values obtained with various PE materials on a generic basis. It also reviews the status of RCP requirements in industry standards; such as ISO 4437, ASTM D 2513 and CSA B137.4. In addition, it reviews progress within CSA Z662 Clause 12 and the AGA Plastic Materials Committee to develop industry guidelines based on the values obtained in the RCP tests to design against an RCP incident.

Background

Although the phenomenon of RCP has been known and researched for several years 1, the number of RCP incidents has been very low. A few have occurred in the gas industry in North America, such as a 12-inch SDR 13.5 in the U.S. and a 6-inch SDR 11 in Canada, and a few more in Europe.

With gas engineers desiring to use PE pipe at higher operating pressures (up to 12 bar or 180 psig) and larger diameters (up to 30 inches), a key component of a PE piping material - resistance to rapid crack propagation (RCP) - becomes more important.

Most of the original research work conducted on RCP was for metal pipe. As plastic pipe became more prominent, researchers applied similar methodologies used for metal pipe on the newer plastic pipe materials, and particularly polyethylene (PE) pipe 2. Most of this research was done in Europe and through the ISO community.

Rapid crack propagation, as its name implies, is a very fast fracture. Crack speeds up to 600 ft/sec have been measured. These fast cracks can also travel long distances, even hundreds of feet. The DuPont Company had two RCP incidents with its high-density PE pipe, one that traveled about 300 feet and the other that traveled about 800 feet.

RCP cracks usually initiate at internal defects during an impact or impulse event. They generally occur in pressurized systems with enough stored energy to drive the crack faster than the energy is released. Based on several years of RCP research, whether an RCP failure occurs in PE pipe depends on several factors:

• Pipe size.
• Internal pressure.
• Temperature.
• PE material properties/resistance to RCP.
• Pipe processing.

Typical features of an RCP crack are a sinusoidal (wavy) crack path along the pipe, and “hackle” marks along the pipe crack surface that indicate the direction of the crack. At times, the crack will bifurcate (split) into two directions as it travels along the pipe.

Test Methods

The RCP test method that is considered to be the most reliable is the full-scale (FS) test method, as described in ISO 13478. This method requires at least 50 feet of plastic pipe for each test and another 50 feet of steel pipe for the reservoir. It is very expensive and time consuming. The cost to obtain the desired RCP information can be in the hundreds of thousands of dollars.

Due to the high cost for the FS RCP test, Dr. Pat Levers of Imperial College developed the small-scale steady state (S4) test method to correlate with the full-scale test3. This accelerated RCP test uses much smaller pipe samples (a few feet) and a series of baffles, and is described in ISO 13477. The cost of conducting this S4 testing is still expensive, but less than FS testing. Several laboratories now have S4 equipment. A photograph with this article shows the S4 apparatus used by Jana Laboratories.

Whether conducting FS or S4 RCP testing, there are two key results used by the piping industry; one is the critical pressure and the other is the critical temperature.

The critical pressure is obtained by conducting a series of FS or S4 tests at a constant temperature (generally 0°C) and varying the internal pressure. At low pressures, where there is insufficient energy to drive the crack, the crack initiates and immediately arrests (stops). At higher pressures, the crack propagates (goes) to the end of the pipe. The critical pressure is shown by the red line in Figure 1 as the transition between arrest at low pressures and propagation at high pressures. In this case, the critical pressure is 10 bar (145 psig).

Figure 1: Critical Pressure (Plot of crack length vs. pressure)

Data obtained at 0° C (32°F).

Due to the baffles in the S4 test, the critical pressure obtained must be corrected to correlate with the FS critical pressure. There has been considerable research within the ISO community conducted in this area. Dr. Philippe Vanspeybroeck of Becetel chaired a working group - ISO/TC 138/SC 5/WG RCP - that conducted S4 and FS testing on several PE pipes 4. Based on their extensive research effort, the WG arrived at the following correlation formula 5 to convert the S4 critical pressure (Pc,S4) to the FS critical pressure (Pc,FS):

Pc,FS = 3.6 Pc,S4 + 2.6 bar (1)

It is important to note that this S4/FS correlation formula may not be applicable to other piping materials, such as PVC or polyamide (PA). For example, Arkema has conducted S4 and FS testing on PA-11 pipe and found a different correlation formula for PA-11 pipe 6.

The critical temperature is obtained by conducting a series of FS or S4 tests at a constant pressure (generally 5 bar or 75 psig) and varying the temperature 7. At high temperatures the crack initiates and immediately arrests. At low temperatures, the crack propagates to the end of the pipe. The critical temperature is shown by the red line in Figure 2 as the transition between arrest at high temperatures and propagation at low temperatures. In this case, the critical temperature is 35°F (2°C).

Figure 2: Critical Temperature (Plot of crack length vs. temperature)

Data obtained at 5 bar (75 psig).

RCP In ISO

The International Standards Organization (ISO) product standard for PE gas pipe, ISO 4437, has included an RCP requirement for many years 8. This is because there were some RCP failures in early generation European PE gas pipes, and the Europeans had conducted considerable research on RCP in PE pipes. Also, European gas companies were using large-diameter pipes and higher operating pressures for PE pipes, both of which make the pipe more susceptible to RCP failures.

Below is the current requirement for RCP taken from ISO 4437:

Pc > 1.5 x MOP (2)

Where: Pc = full scale critical pressure, psig

MOP = maximum operating pressure, psig

Most manufacturers use the S4 test to meet this ISO 4437 RCP requirement. If the requirement is not met, then the manufacturer may use the FS test. Therefore, the ISO 4437 product standard requires that RCP testing be done, and also provides values for the RCP requirement.

RCP In ASTM

Until recently, ASTM D 2513 did not address RCP at all 9. The AGA Plastic Materials Committee (PMC) requested that an RCP requirement be added to ASTM D 2513, similar to the RCP requirement in the ISO PE gas pipe standard ISO 4437. The manufacturers agreed to include a requirement in ASTM D 2513 that RCP testing (FS or S4) must be performed. The ASTM product standard D 2513 does not include any required values.

PMC has agreed with this approach and will develop its own industry requirement in the form of a “white paper.” 10 The first draft was just issued within PMC with the following proposed requirement:

PC,FS > leak test pressure.

Leak test pressure = 1.5 X MOP.

RCP In CSA

CSA followed the direction of ASTM. The product standard CSA B137.4 11 requires that the RCP testing must be done. The values of the RCP test will be stipulated in CSA Z662 Clause 12, which is the Code of Practice for gas distribution in Canada. Clause 12 recently approved the requirement as shown nearby.

12.4.3.6 Rapid Crack Propagation (RCP) Requirements

When tested in accordance with B137.4 requirements for PE pipe and compounds, the standard PE pipe RCP Full-Scale critical pressure shall be at least 1.5 times the maximum operating pressure. If the RCP Small-Scale Steady State method is used, the RCP Full-Scale critical pressure shall be determined using the correlation formula in B137.4.

(end of box)

RCP Test Data

The critical pressure is the pressure - below which - RCP will not occur. The higher the critical pressure, the less likely the gas company will have an RCP event. In most cases, as the pipe diameter or wall thickness increases, the critical pressure decreases. Therefore, RCP is more of a concern with large-diameter or thick-walled pipe. Following are some typical critical pressure values for various generic PE materials. For most cases, the pipe size tested is 12-inch SDR 11 pipe.

PE Material S4 Critical Pressure (PC,S4) at 32°F (0°C)/Full Scale Critical Pressure (PC,FS) @ 0°C

Unimodal MDPE 1 bar (15 psig)/6.2 bar (90 psig)

Bimodal MDPE 10 bar (145 psig) /38.6 bar (560 psig)

Unimodal HDPE 2 bar (30 psig)/9.8 bar (140 psig)

Bimodal HDPE (PE 100+) 12 bar (180 psig)/45.8 bar (665 psig)

In general, the RCP resistance is greater for HDPE (high-density PE) than MDPE (medium-density PE). However, there is a significant difference when comparing a unimodal PE to a bimodal PE material, about a ten-fold difference.

Bimodal PE technology was developed in Asia and Europe in the 1980s. This technology is known to provide superior performance for both slow crack growth and RCP, as evidenced by the table. For the bimodal PE 100+ materials used in Europe and Asia, the S4 critical pressure minimum requirement is 10 bar (145 psig), which converts to 560 psig operating pressure. This means that with these bimodal PE 100+ materials, RCP will not be a concern. Today, there are several HDPE resin manufacturers that use this bimodal technology. Recently, a new bimodal MDPE material was introduced for the gas industry 12,13 with a significantly higher S4 critical pressure compared to unimodal MDPE - 10 bar compared to 1 bar.

Another measure of RCP resistance is the critical temperature. This is defined as the temperature above which RCP will not occur. Therefore, a gas engineer wants to use a PE material with a critical temperature as low as possible. Although critical temperature is not used as a requirement in the product standards, it is an important parameter, and perhaps should be given more consideration. Following is a table with some typical critical temperature values for various generic PE materials. For most cases, the pipe size tested is 12-inch SDR 11 pipe.

PE Material/Critical Temperature (TC) at 5 bar (75 psig)

Unimodal MDPE 15°C (60°F)

Bimodal MDPE -2°C (28°F)

Unimodal HDPE 9°C (48°F)

Bimodal HDPE -17°C (1°F)

Again, we see that RCP performance for HDPE is slightly better than MDPE, but there is a significant difference between bimodal PE and unimodal PE. The bimodal MDPE and HDPE materials have the lowest critical temperatures, which means the greatest resistance to RCP.

Conclusion

As gas companies use PE pipe in more demanding applications, such as larger pipe diameters and higher operating pressures, the resistance of the PE pipe to rapid crack propagation (RCP) becomes more important. In this article we have discussed the phenomenon of RCP and the two primary test methods used to determine RCP resistance - the S4 test and the Full Scale test. We reviewed the correlation formula between the FS test and S4 test for critical pressure. We have also discussed the two primary results of RCP testing - the critical pressure and the critical temperature.

ISO standards were the first to recognize the importance of RCP, especially in larger diameter pipe sizes, and incorporated RCP requirements in product standards, such as ISO 4437. The Canadian standards soon followed, and an RCP test requirement has been added to CSA B137.4. The required values for RCP testing are being added to the CSA Code of Practice in CSA Z662 Clause 12 for gas piping. ASTM just added an RCP requirement to its gas pipe standard ASTM D 2513. The corresponding AGA PMC project to develop RCP recommendations for required values from RCP testing is in progress.

In this article, we also discussed some results of RCP testing. In general, the HDPE materials have slightly greater RCP resistance than MDPE materials used in the gas industry. A more significant difference is observed when comparing unimodal PE materials to bimodal PE materials. Existing data indicate that bimodal HDPE materials show a significant increase in critical pressure compared to unimodal HDPE materials and also have considerably lower critical temperature values.

In addition, this bimodal technology has now just been introduced for MDPE. This bimodal MDPE material also has a significantly higher S4 critical pressure (10 bar vs. 1 bar) and a lower critical temperature than unimodal MDPE materials. With several PE resin manufacturers being able to produce bimodal PE materials, it is likely that in the near future, all PE materials used for the gas industry will be bimodal materials because of their superior RCP resistance.

Reference:

“Rapid Crack Propagation Increasingly Important in Gas Applications: A Status Report”, Dr. Gene Palermo, http://pipelineandgasjournal.com/rapid-crack-propagation-increasingly-important-gas-applications-status-report

Pipeline Routing

Oil and gas pipeline routes are pivotal pieces of information upon which pipeline engineering depends. The route will define the pipeline size, terrain, soils, and engineering analysis requirements. Engineering assessment based upon agreed alignment selection criteria is an important part of a linear project. To be able to reach the best construction line and optimise its components, the phases – namely corridor, route, alignment, and construction line selection — should be studied in the given order.

Selecting the optimum route does not end with geotechnical challenges, as it also requires interactive coordination between the owner, the engineer, the regulator, the landowners, the construction contractor and a multitude of other project stakeholders and interested parties. 

In North America, pipeline route selection is driven by regulatory requirements at the federal, state and local levels and involves finding a route that minimizes the impact on the environment and archaeological artefacts and recognises the concerns of the landowners while considering the geotechnical challenges which affect the construction of the pipeline. In arctic regions like Siberia, the soil conditions are an important consideration where areas of permafrost are interspersed with normal soils. In the permafrost areas, the pipeline will be installed above ground on supports and the depth of the permafrost determines the design of the supports, while in normal soil areas the pipeline is buried in a trench in the conventional manner.

In mountainous terrain, such as in Turkey, geotechnical considerations are a significant aspect of pipeline route selection, as well as environmental and landowner concerns. The pipeline design must address geohazard mitigation for seismic areas and sections of the route which could be subject to landslides.

Geo-political factors can also affect the route selection. Bringing Caspian Sea gas to Europe requires, among other pipelines, a new pipeline in Europe. A northern route requires a longer pipeline routed through environmentally sensitive areas, but this route supports future expansion of the pipeline system’s capacity. A southern route is shorter and reduces environmental concerns, but as this route also involves a marine crossing, the future expansion of the pipeline system is curtailed.

Primary selection factors

The detailed pipeline route selection is preceded by defining a broad area of search between the two fixed start and end points. That is, possible pipeline corridors. The route can then be filtered with consideration of public safety, pipeline integrity, environmental impact, consequences of escape of fluid, and based on social, economic, technical environmental grounds, constructability, land ownership, access, regulatory requirements and cost.

Economic, technical, environmental and safety considerations should be the primary factors governing the choice of pipeline routes. The shortest route might not be the most suitable, and physical obstacles, environmental constraints and other factors, such as locations of intermediate offtake points to end users along the pipeline route should be considered. Offtake points may dictate mainline routing so as to minimise the need or impact of the offtake lines or spurs.

Many route constraints will have technical solutions (e.g. routing through flood plains), and each will have an associated cost.

Corridor selection in project key stages

Pipeline routing is an iterative process, which starts with a wide ‘corridor of interest’ and then narrows down to a more defined route at each design stage as more data is acquired, to a final ‘right of way’ (ROW). Initially, a number of alternative corridors with widths up to 10 km wide are reviewed. Each project will have its own specific corridor-narrowing process depending on project size and location.

Pipeline corridors should initially be selected to avoid key constraints. The route can then be further refined through an iterative process, involving consultation with stakeholders and landowners and a review of the EIA criteria, to avoid additional identified constraints. The ultimate aim is to achieve an economically and environmentally-feasible route for construction.

Terrain, subterranean conditions, geotechnical and hydrographical conditions

The geography of the terrain traversed can generally be divided into surface topography and subterranean geology. Both natural and man-made geographical features can be considered under these two headings.

The principal geographical features which are likely to be encountered and should be taken into account include:

Surface:

• Crops, livestock, woodlands;     
• Natural beauty, archaeological, ornamental rivers, mountains;
• Water catchment areas, forestry;
• Population, communications, services;
• Contouring, soil or rock type, water, soil corrosivity;
• Designated areas, protected habitats, flora and fauna
• Subterranean:
• Earthquake zone;
• Geological features;
• Infill land and waste disposal sites, including those contaminated by disease, radioactivity or chemicals;
• The proximity of past, present and future mineral extractions, including uncharted workings, pipelines and underground services;
• Areas of geological instability, including faults, fissuring and earthquake zones;
• Existing or potential areas of land slippage, subsidence and differential settlement;
• Tunnels;
• Ground water hydrology, including flood plains.

Geo-hazards

Geo-hazards are widespread phenomena that are influenced by geological and environmental conditions and which involve both long-term and short-term processes. They range in size, magnitude and effect. Many geo-hazards are naturally occurring features and processes (e.g. landslides, debris flow, seismic activity, rock falls, etc.) but there are also many geo-hazards that are caused by anthropogenic processes (e.g. undermining, landfills, engineered fill, chemistry and contamination, etc.), and these too need to be taken into account during the pipeline routing exercise.

Geo-hazards are identified as geological, hydro-geological or geomorphological events that pose an immediate or potential risk that may lead to damage or uncontrolled risk. The type, nature, magnitude, extent and rate of geological processes and hazards directly influence pipeline route selection. Therefore, the process of early-stage terrain evaluation and the identification and assessment of geo-hazards and ground conditions are important as they can lead to extensive cost and time savings in the design and construction of a pipeline.

The process enables the routing of the pipeline through the most suitable terrain, problem areas are identified, serious geo-hazards are avoided, where possible, and risks are minimised and mitigated. In addition, terrain evaluation is undertaken so that the need for expensive remedial measures or site restoration works is limited or prevented and the operability of the pipeline is safeguarded through a proper appreciation of the terrain conditions. By minimizing the risk of damage to the pipeline the risk to human safety is reduced.

Terrain evaluation

Terrain evaluation along the pipeline corridor can be achieved using a variety of low-cost techniques that include satellite imagery and aerial photography interpretation, surface mapping and various other remote sensing techniques. This data can be incorporated, together with historical data on seismic events, geological features, meteorological processes and hydrological data, within a geographic information system (GIS – see below) and detailed terrain and hazard models developed.

Terrain evaluation supports the anticipation, identification and assessment of the physical hazards and constraints within and outside of the pipeline corridor. It is essential that features outside the corridor be evaluated, as hazardous events outside of the corridor may be triggered by construction activity within the corridor and the resultant event may impact upon the pipeline.The risks associated with geo-hazards or the likelihood of an event occurring and its consequences can be qualitatively and quantitatively assessed using a scoring system or by a quantitative risk assessment (QRA). 

Safety of the pipeline is paramount in the routing selection. The extreme effect of a geological hazard on the pipeline is a rupture and it is this event that terrain evaluation and risk analysis seeks to avoid by improving the decision-making progress used in selecting the most appropriate route for the pipeline.

  

Conclusion

In onshore and pipeline projects alike, the potential for catastrophe is always lurking close at hand to catch the naïve or complacent investor and contractor off-guard. However, when these challenges are successfully addressed, leaving a pipeline system with solid integrity and performance as well as satisfied investors, contractors and communities, projects can be very rewarding, both in financial terms as well as in the esteem accorded to all those involved.

References: “Pipeline Route Selection”. http://www.oilandgastechnology.net/pipeline-news/pipeline-route-selection-%E2%80%93-route-success.

Spiral Wound Linepipe for Offshore Applications

In certain parts of the world it is highly relevant to use spiral welded pipes for offshore applications. This is driven by cost, project characteristics and the desire to manufacture the pipe close to where it is to be used.

Spiral welded line pipe has been used extensively for onshore applications, however there has been some reluctance to specify spiral welded line pipe for offshore applications. A joint industry project is beeing carried out together with coil manufacturers, pipe manufacturers, installation contractors and operators to review the status regarding offshore applications for spiral welded pipes and identify the most critical technology gaps using a technology qualification process. Detailed suggestions as to how the gaps can be met have been made. An update on efforts to close these gaps is ongoing.

The challenges for spiral welded line pipe include design, metallurgical and quality control issues. The design issues include
fracture arrest, collapse and displacement controlled loading conditions which are all highlighted in DNVs standard for submarine pipelines (DNV OS F101). The design issues regarding load controlled displacement are mainly due to limited experience with spiral welded line pipe subjected to large strains. For running fracture the limited experience with spiral welded pipe for offshore applications is an issue.

There are 5 new spiral welded pipe mills in United States so availability has improved. The review includes an assessment of typical pipe material test results and whether properties required for offshore applications can reasonably be expected.

Det Norske Veritas (U.S.A.), Inc. (DNV) and MCSKenny are carrying out a joint industry project (JIP) to investigate the suitability of spiral welded pipe for offshore applications. It appears that the industry has a general understanding that the performance of spiral welded (SAWH) pipes is different to Submerge Arc Welded (SAWL)/ High Frequency Welded(HFI)/ Electric Resistance Welded ERW linepipe when exposed to the same loading conditions, and that currently existing design standards for offshore applications may not be applicable.

An important issue is to establish how the spiral wound linepipe can be produced consistently to a high level of quality, and what is required by the design standard for spiral welded pipe to be fit for purpose for offshore use. Some of the main areas of concern regarding the quality of spiral wound line pipe will be discussed. The aim is to assess whether SAWH linepipe can be considered equivalent to SAWL and HFI/ERW linepipe.

The use of spiral welded linepipe (SAWH) for pipelines has generally been the most popular manufacturing choice of linepipe for onshore low pressure pipelines, pipelines transporting water, ship borne piping, or very shallow water, low pressure pipelines (≤ 500 ft). Recently there has been more interest in the use of spiral woundline pipe, due to the following reasons:

• There are five new SAWH pipe mills in America with “state-of-the-art” technology. 
• SAWH linepipe is a cost-effective solution compared to the other manufacturing processes. 
• Generally, the chemical compositions, mechanical properties and dimensional tolerances are assumed to be comparable to SAWL pipe. 
• SAWH linepipe can be manufactured in 80 ft lengths with diameters from 20 to more than 100-inch OD and wall thicknesses ranging from approximately 9 to 25 mm. 
• Some SAWH pipe mills have coating capabilities for 80 ft pipe lengths (FBE and 3-layer coating systems). 80 ft pipe lengths could mean less fabrication costs for the installation contractors.

Source:
https://www.google.co.id/url?sa=t&rct=j&q=&esrc=s&source=web&cd=2&cad=rja&ved=0CDEQFjAB&url=http%3A%2F%2Fwww.otcnet.org%2F2011%2Fpages%2Fschedule%2Ftech_program%2Fdocuments%2Fotc217951.pdf&ei=FwruUp6eG5LskAev_4CABQ&usg=AFQjCNFARe4qSkec6aTGEQ6cCf2-y81kDQ&sig2=4P3aETvm293ITvlrTvhy1A&bvm=bv.60444564,d.eW0

Pipeline Material Selection

Originally written by Krupavaram Nalli, Tebodin & Partners LLC, Sultanate of Oman

With the recent spate of material failures in the oil and gas industry around the world, the role of a material and corrosion engineer in selecting suitable material has become more complex, controversial and difficult. Further, the task had become more diverse, since now modern engineering materials offer a wide spectrum of attractive properties and viable benefits.

From the earlier years or late ’70s, the process of materials selection that had been confined exclusively to a material engineer, a metallurgist or a corrosion specialist has widened today to encompass other disciplines like process, operations, integrity, etc. Material selection is no more under a single umbrella but has become an integrated team effort and a multidisciplinary approach. The material or corrosion specialist in today’s environment has to play the role of negotiator or mediator between the conflicting interests of other peer disciplines like process, operations, concept, finance, budgeting, etc.

With this as backdrop, this article presents various stages in the material selection process and offers a rational path for the selection process toward a distinctive, focused and structured holistic approach.

What is material selection in oil and gas industry? Material selection in the oil and gas industry - by and large - is the process of short listing technically suitable material options and materials for an intended application. Further to these options, it is the process of selecting the most cost- effective material option for the specified operating life of the asset, bearing in mind the health, safety and environmental aspects and sustainable development of the asset, technical integrity and any asset operational constraints envisaged in the operating life of the asset.

What stages are involved? The stages involved in the material selection process can be outlined as material selection 1) during the concept or basic engineering stage, 2) during the detailed engineering stage, and 3) for failure prevention (lessons learned).

Concept Stage

Material selection during the concept stage basically means the investigative approach for the various available material options for the intended function and application. In this stage, a key factor for the material selection is an up-front activity taking into consideration operational flexibility, cost, availability or sourcing and, finally, the performance of the material for the intended service and application.

The material and corrosion engineer’s specialized expertise or skills become more important as the application becomes critical, such as highly sour conditions, highly corrosive and aggressive fluids, high temperatures and highly stressed environments, etc.

It is imperative at this concept stage that the material selection process becomes an interdisciplinary team approach rather an individualistic material and corrosion engineer’s choice. However, some level of material selection must be made in order to proceed with the detailed design activities or engineering phase.

The number and availability of material options in today’s industry have grown tremendously and have made the selection process more intricate than a few decades back. The trend with research and development in the materials sciences will continue to grow and may make the selection even more complex and intriguing.

It should be understood that, at the concept design stage, the selection is broad and wide. This stage defines the options available for specific application with the available family of materials like metals, non metals, composites, plastics, etc. If an innovative and cost-effective material choice is to be made from an available family of options, it is normally done at this stage.

At times, material constraints from the client or operating company or the end user may dictate the material selections as part of a contractual obligation. Sourcing, financial and cost constraints at times may also limit and obstruct the material selections except for vey critical applications where the properties and technical acceptability of the material is more assertive and outweighs the cost of the material.

Materials availability is another important criterion on the material selection which impacts the demanding project schedules for the technically suitable material options. Also, different engineering disciplines may have different and specific requirements like constructability, maintainability, etc. However, a compromise shall be reached at this stage among all the disciplines concerned to arrive at a viable economic compromise on the candidate material.

Detailed Engineering Stage

Materials selection during the detailed design stage becomes more focused and specific. The material selection process narrows down to a small group or family of materials, say: carbon steels, stainless steels, duplex stainless steels, Inconels or Incoloys, etc. In the detail design stage, it narrows down to a single material and other conditions of supply like Austenitic stainless steels, Martensitic stainless steels, cast materials, forged materials, etc.

Depending on the criticality of the application at this stage the material properties, manufacturing processes and quality requirements will be addressed to more precise levels and details. This may sometimes involve extensive material-testing programs for corrosion, high temperature, and simulated heat treatment as well as proof testing.

From the concept to detailing stage is a progressive process ranging from larger broad possibilities to screening to a specific material and supply condition.

At times, the selection activity may involve a totally new project (greenfield) or to an extension of existing project (brownfield). In the case of an existing project, it could be necessary to check and evaluate the adequacy of the current materials; it may be necessary at times to select a material with enhanced properties. The candidate material shall normally be investigated for more details in terms of cost, performance, fabricability, availability and any requirements of additional testing in the detail engineering stage.

Failure Prevention (Lessons Learned)

Material selection and the sustainability of material to prevent any failure during the life of the component is the final selection criterion in the process.

Failure is defined as an event where the material or the component did not accomplish the intended function or application. In most cases, the material failure is attributed to the selection of the wrong material for the particular application. Hence, the review and analysis of the failure is a very important aspect in the material selection process to avert any similar failures of the material in future.

The failure analysis - or the lessons learned - may not always result in better material. The analysis may, at times, study and consider the steps to reduce the impact on the factors that caused the failure. A typical example would be to introduce a chemical inhibition system into the process to mitigate corrosion of the material or to carry out a post-weld heat treatment to minimize the residual stresses in the material which has led to stress corrosion cracking failure.

An exhaustive review and study of the existing material that failed, including inadequacy checks and a review of quality levels imposed on the failed materials, is required before an alternate and different material is selected for the application.

The importance of the failure analysis cannot be overstressed in view of the spate of failures in recent times in the oil and gas industry. The results of failure analysis and study will provide valuable information to guide the material selection process and can serve as input for the recommendation in the concept and design stages of the project. It strengthens and reinforces the material selection process with sound back-up information.

Let us take a general view of material recommendations for pipelines. Some of the materials most relevant for use in pipelines in the Middle East are indicated for information and guidance in Table 1. The recommendations are general in nature and each pipeline is to be studied in detail case by case as regards operating conditions, fluid compositions, etc. before any final selections.

Also, other considerations - like the total length of the pipeline, above or below ground installation, nature of the pipeline (export line or processing line, etc.) – that are to be taken into consideration during the detailed engineering phase.

Table 1: General Material Selection for Pipelines in Oil and Gas Industry.

Notes: CA: Corrosion Allowance, CS: Carbon Steel, CRA: Corrosion Resistant Alloy and GRP: Glass Reinforced Plastics. The recommendations in Table 1 are for guidance only. Each pipeline is to be analyzed on a case-by-case basis based on operating conditions and fluid compositions.

Conclusion

To maintain the integrity of the asset and provide a safe, healthful working environment it is always a welcome event to have the material selection process be executed as a holistic team approach rather than an individual metallurgist’s or corrosion specialist’s choice.

References: “A Rational Approach To Pipeline Material Selection”.http://www.pipelineandgasjournal.com/rational-approach-pipeline-material-selection.

Pipe Flange

There are different types of pipe flanges  used in the piping systems depending upon the fluid, PT rating, material of construction, connecting equipment etc.  Below are the types of flanges used in piping based on facing


1) Flat Face (FF) Flanges:
These pipe flanges are used when the counter flanges are flat face. They are mainly used at connection to cast iron equipment, valves and specialties. This flat face flange has a gasket surface in the same plane as the bolting circle face.



2) Raised Face (RF) Flanges:
These pipe flanges are the most commonly used flanges. The raised face thickness for 150# and 300# are included in the specified flange thickness and for higher rating they are not included in the flange thickness.



3) Male-Female (M/F) Face Flanges:
These pipe flanges are better version of Raised face flanges.



4) Tongue-Groove (T/G) Face Flanges:
These pipe flanges are most reliable type of flange joint but are costlier than the other type of flanges.



5) Ring Type Joint (RTJ) Flanges:
These pipe flanges are most reliable type of flange joint but are costlier than the other type of flanges. The Ring Type Joint flanges are generally used in high pressure (Class 600 and higher rating) and/or high temperature services above 800°F (427°C).


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

Pipeline Hot Tap

What is a Hot Tap and why it is made?

Hot Taps or Hot Tapping is the ability to safely tie into a pressurized system, by drilling or cutting, while it is on stream and under pressure.

Typical connections consist:

Tapping fittings like Weldolet®, Reinforced Branch or Split Tee.

Split Tees often to be used as branch and main pipe has the same diameters.

Isolation Valve like gate or Ball Valve.

Hot tapping machine which includes the cutter, and housing.

Mechanical fittings may be used for making hot taps on pipelines and mains provided they are designed for the operating pressure of the pipeline or main, and are suitable for the purpose.

Design: ANSI B31.1, B31.3, ANSI B31.4 & B31.8, ASME Sec. VIII Div.1 & 2

Fabrication: ASME Sec. VIII Div.1

Welding: ASME Sec. IX

NDT: ASME Sec. V

There are many reasons to made a Hot Tap. While is preferred to install nozzles during a turnaround, installing a nozzle with equipment in operation is sometimes advantageous, especially if it averts a costly shut down.

Remarks before made a Hot Tap

A hot tap shall not be considered a routine procedure, but shall be used only when there is no practical alternative.

Hot Taps shall be installed by trained and experienced crews.

It should be noted that hot tapping of sour gas lines presents special health and metallurgical concerns and shall be done only to written operating company approved plans.

For each hottap shall be ensured that the pipe that is drilled or sawed has sufficient wall thickness, which can be measured with ultrasonic thickness gauges. The existing pipe wall thickness (actual) needs to be at least equal to the required thickness for pressure plus a reasonable thickness allowance for welding. If the actual thickness is barely more than that required for pressure, then loss of containment at the weld pool is a risk.

Welding on in-service pipelines requires weld procedure development and qualification, as well as a highly trained workforce to ensure integrity of welds when pipelines are operating at full pressure and under full flow conditions.

Hot Tap setup

For a hot tap, there are three key components necessary to safely drill into a pipe; the fitting, the Valve, and the hot tap machine. The fitting is attached to the pipe, mostly bywelding.In many cases, the fitting is a Weldolet® where a flange is welded, or a split tee with a flanged outlet (see image above). Onto this fitting, a Valve is attached, and the hot tap machine is attached to the Valve (see images on the right). For hot taps, new Stud Bolts, gaskets and a new Valve should always be used when that components will become part of the permanent facilities and equipment. The fitting/Valve combination, is attached to the pipe, and is normally pressure tested. The pressure test is very important, so as to make sure that there are no structural problems with the fitting, and so that there are no leaks in the welds. The hot tap cutter, is a specialized type of hole saw, with a pilot bit in the middle, mounted inside of a hot tap adapter housing. The hot tap cutter is attached to a cutter holder, with the pilot bit, and is attached to the working end of the hot tap machine, so that it fits into the inside of the tapping adapter. The tapping adapter will contain the pressure of the pipe system, while the pipe is being cut, it houses the cutter, and cutter holder, and bolts to the Valve.

Hot Tap operation

The Hot Tap is made in one continuous process, the machine is started, and the cut continues, until the cutter passes through the pipe wall, resulting in the removal of a section of pipe, known as the “coupon”. The coupon is normally retained on one or more u-wires, which are attached to the pilot bit. Once the cutter has cut through the pipe, the hot tap machine is stopped, the cutter is retracted into the hot tap adapter, and the Valve is closed. Pressure is bled off from the inside of the Tapping Adapter, so that the hot tap machine can be removed from the line. The machine is removed from the line, and the new service is established.

Hot Tap Coupon

The Coupon, is the section of pipe that is removed, to establish service. It is very highly desirable to “retain” the coupon, and remove it from the pipe, and in the vast majority of hot taps, this is the case. Coupon retention is mostly the “job” of the u-wires. These are wires which run through the pilot bit, and are cut and bent, so that they can fold back against the bit, into a relief area milled into the bit, and then fold out, when the pilot bit has cut through the pipe. In almost all cases, multiple u-wires are used, to act as insurance against losing the coupon.

Line Stopping

Line Stops, sometimes called Stopples (Stopple® is a trademark of TD Williamson Company) start with a hot tap, but are intended to stop the flow in the pipe. Line Stops are of necessity, somewhat more complicated than normal hot taps, but they start out in much the same way. A fitting is attached to the pipe, a hot tap is performed as previously detailed. Once the hot tap has been completed, the Valve is closed, then another machine, known as a line stop actuator is installed on the pipe. The line stop actuator is used to insert a plugging head into the pipe, the most common type being a pivot head mechanism. Line stops are used to replace Valves, fittings and other equipment. Once the job is done, pressure is equalized, and the line stop head is removed. The Line Stop Fitting has a specially modified flange, which includes a special plug, that allows for removal of the Valve. There are several different designs for these flanges, but they all work pretty much the same, the plug is inserted into the flange through the Valve, it is securely locked in place, with the result that the pressure can be bled off of the housing and Valve, the Valve can then be removed, and the flange blinded off.

Line Stop setup

The Line Stop Setup includes the hot tap machine, plus an additional piece of equipment, a line stop actuator. The Line Stop Actuator can be either mechanical (screw type), or hydraulic, it is used, to place the line stop head into the line, therefore stopping the flow in the line. The Line Stop Actuator is bolted to a Line Stop Housing, which has to be long enough to include the line stop head (pivot head, or folding head), so that the Line Stop Actuator, and Housing, can be bolted to the line stop Valve. Line stops often utilize special Valves, called Sandwich Valves. Line Stops are normally performed through rental Valves, owned by the service company who performs the work, once the work is completed, the fitting will remain on the pipe, but the Valve and all other equipment is removed.

Line Stop operation

A Line Stop starts out the same way as does a Hot Tap, but a larger cutter is used,. The larger hole in the pipe, allows the line stop head to fit into the pipe. Once the cut is made, the Valve is closed the hot tap machine is removed from the line, and a line stop actuator is bolted into place. New gaskets are always to be used for every setup, but “used” studs and nuts are often used, because this operation is a temporary operation, the Valve, machine, and actuator are removed at the end of the job. New studs, nuts, and gaskets should be used on the final completion, when a blind flange is installed outside of the completion plug. The line stop actuator is operated, to push the plugging head (line stop head), down, into the pipe, the common pivot head, will pivot in the direction of the flow, and form a stop, thus stopping the flow in the pipe.

Completion Plug

In order to remove the Valve used for line stop operations, a completion plug is set into the line stop fitting flange (Completion Flange). There are several different types of completion flange/plug sets, but they all operate in basically the same manner, the completion plug and flange are manufactured, so as to allow the flange, to accept and lock into place, a completion plug. This completion plug is set below the Valve, once set, pressure above the plug can be bled off, and the Valve can then be removed. Once the plug has been properly positioned, it is locked into place with the lock ring segments, this prevents plug movement, with the o-ring becoming the primary seal. Several different types of completion plugs have been developed with metal to metal seals, in addition to the o-ring seal.

Line Stopping Procedure

Reference : http://www.wermac.org/specials/hottap.html

Vortex Induced Vibration on Offshore Pipeline

In fluid dynamics, vortex-induced vibrations (VIV) are motions induced on bodies interacting with an external fluid flow, produced by – or the motion producing – periodical irregularities on this flow.

A classical example is the VIV of an underwater cylinder. You can see how this happens by putting a cylinder into the water (a swimming-pool or even a bucket) and moving it through the water in the direction perpendicular to its axis. Since real fluids always present some viscosity, the flow around the cylinder will be slowed down while in contact with its surface, forming the so called boundary layer. At some point, however, this boundary layer can separate from the body because of its excessive curvature. Vortices are then formed changing the pressure distribution along the surface. When the vortices are not formed symmetrically around the body (with respect to its midplane), different lift forces develop on each side of the body, thus leading to motion transverse to the flow. This motion changes the nature of the vortex formation in such a way as to lead to a limited motion amplitude (differently, then, from what would be expected in a typical case of resonance).

VIV manifests itself on many different branches of engineering, from cables to heat exchanger tube arrays. It is also a major consideration in the design of ocean structures. Thus study of VIV is a part of a number of disciplines, incorporating fluid mechanics, structural mechanics, vibrations, computational fluid dynamics (CFD), acoustics, statistics, and smart materials.

Pipelines at the bottom of the sea are susceptible to ocean currents. Even relatively calm currents can induce turbulences in the wake of the pipeline, which results in the pipeline to start 'dancing'. Pipe vibrations can trigger fatigue, with catastrophic fracture as a result. Consequently, when designing submarine pipelines, caution is being paid to avoid such vibrations. Our research engineers use powerful software to predict submarine pipeline stability.

“Dancing at Great Depth”

Even relatively calm currents can induce turbulences in the wake of the pipeline, resulting in pipeline oscillations. The pipeline vibrations can trigger fatigue, causing accelerated damage. Since fatigue damage can give rise to complete fracture with catastrophic consequences, extreme caution is being paid in order to avoid such vibrations when designing submarine pipelines. Flow patterns around submarine pipelines greatly depend on the velocity of the sea currents and on the tube diameter. When the current becomes too strong, turbulences show up in the wake of the pipeline. This vortex shedding exerts an alternating force on the pipeline. Consequently, the pipeline is being subjected to cyclic loading. The pipeline starts to dance, following a characteristic ‘number-eight’ path. Under cyclic loading, the pipe is being exposed to fatigue, which could cause the pipe to fail under surprisingly modest stresses.

Current State of Art

Much progress has been made during the past decade, both numerically and experimentally, toward the understanding of the kinematics (dynamics) of VIV, albeit in the low-Reynolds number regime. The fundamental reason for this is that VIV is not a small perturbation superimposed on a mean steady motion. It is an inherently nonlinear, self-governed or self-regulated, multi-degree-of-freedom phenomenon. It presents unsteady flow characteristics manifested by the existence of two unsteady shear layers and large-scale structures.

There is much that is known and understood and much that remains in the empirical/descriptive realm of knowledge: what is the dominant response frequency, the range of normalized velocity, the variation of the phase angle (by which the force leads the displacement), and the response amplitude in the synchronization range as a function of the controlling and influencing parameters? Industrial applications highlight our inability to predict the dynamic response of fluid–structure interactions. They continue to require the input of the in-phase and out-of-phase components of the lift coefficients (or the transverse force), in-line drag coefficients, correlation lengths, damping coefficients, relative roughness, shear, waves, and currents, among other governing and influencing parameters, and thus also require the input of relatively large safety factors. 

Fundamental studies as well as large-scale experiments (when these results are disseminated in the open literature) will provide the necessary understanding for the quantification of the relationships between the response of a structure and the governing and influencing parameters.

It cannot be emphasized strongly enough that the current state of the laboratory art concerns the interaction of a rigid body (mostly and most importantly for a circular cylinder) whose degrees of freedom have been reduced from six to often one (i.e., transverse motion) with a three-dimensional separated flow, dominated by large-scale vortical structures.

References:
”Vortex-induced Vibration”. http://en.wikipedia.org/wiki/Vortex-induced_vibration.
“Vortex Induced Vibrations, A Swinging Problem”. http://www.ocas.be/Vortex-Induced-Vibrations