A Rational Approach to Pipeline Material Selection

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.

Source : http://www.pipelineandgasjournal.com/rational-approach-pipeline-material-selection?page=show

Pipeline Route Selection – The Route to Success

IPLOCA president Doug Evans highlights the importance of properly planning and executing the route selection process inherent in any pipeline project, taking into account such key considerations as primary selection factors, engineering requirements, corridor selection as well as subterranean challenges and geohazards

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 minimises 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.

This article was written by Doug Evans, president 2012-2013, International Pipe Line & Offshore Contractors Association (IPLOCA).

Source: http://www.oilandgastechnology.net/pipeline-news/pipeline-route-selection-%E2%80%93-route-success

The Role of Cathodic Protection in Offshore Pipeline Integrity

WHAT IS OUT THERE?

Over 24,000 miles of pipeline have been laid on the Outer Continental Shelf (OCS) in the Gulf of Mexico since 1948. Over the years, much of this pipeline has been abandoned or removed, but as of June 1997, there were still some 17,000 miles of active pipe. Pipe-laying activity has been up and down over the years, somewhat mirroring the "boom and bust" cycles of the oil and gas industry. Some 1,222 miles are over 30 years old, and 5,952 miles have celebrated a 20th anniversary. Obviously these 5,000-plus miles of pipe would be considered at higher risk from an integrity standpoint than the 11,000 miles younger than 20. The mere fact that these old lines are still in operation reflects well on the skills of the corrosion control community (Figure 1).

Figure 1. Active Gulf of Mexico Pipelines: Mileage vs. age

EXTERNAL CORROSION CONTROL OF OFFSHORE PIPELINES

All offshore pipelines are protected from seawater corrosion in the same way. The primary corrosion control system is pipeline coating. This is supplemented with cathodic protection (CP) to provide protection at coating defects or "holidays." In the Gulf of Mexico, the pipeline coatings used until the early to mid-1970s were either asphaltic/ aggregate, "Somastic"-type, coatings or hot-applied coal tar enamels. Since then, the trend has been to use fusion-bonded epoxy powder coatings. In the earlier days, the trend in cathodic protection (CP) was to rely on impressed-current systems. In the 1960s and early 1970s, zinc bracelet anodes attached to the pipe were widely used. Since then, more efficient aluminum alloys have surpassed zinc as the preferred material for offshore galvanic anodes. There are, however, still some operators using impressed current systems and some using zinc anodes.

BRACELET ANODES

Virtually all new pipelines installed in the Gulf of Mexico are equipped with aluminum bracelet anodes. There are two basic types, square shouldered and tapered.

The square-shouldered anodes are typically used on pipe that has a concrete weight coating. When installed, the anodes are flush with, or slightly recessed inside, the outside diameter of the concrete.

The tapered anodes are designed to be installed on pipelines with only a thin film corrosion coating. The whole idea is to protect the bracelet anodes during the pipe-laying process. The anodes are particularly at risk from mechanical damage when the pipeline travels over the stinger on the back of the lay barge.

Even with these tapered designs, non-weight-coated pipelines still sustain anode damage, which can in turn cause coating damage. Several methods are being used to combat this problem. The use of cast-on polyurethane tapers is gaining popularity, and mounting both halves of the bracelet on top of the pipe is a common technique when pipe is laid from a reel barge and the anodes have to be attached offshore (Figures 2 and 3).

Figure 2. Six-inch pipe reeled on the barge Chickasaw

Figure 3. Tapered Bracelet anodes installed on top of pipe

DESIGNING CP SYSTEMS FOR OFFSHORE PIPELINES

When designing a cathodic protection system for a pipeline, the corrosion engineer has to consider the following variables, all of which will have an impact on the final anode alloy and size selection:

• Design life required - (minimum is 20 years)
• Pipe diameter length and to-from information
• Geographic location
• Type of coating
• Pipe-lay / installation method
• Water depth
• Burial method
• Product temperature
• Electrical isolation from platforms or other pipelines

The smart cathodic protection designer will look early on at the intended pipe installation method, as this will have a direct impact on the amount of coating damage one may expect (there is also a risk of having anodes detached during the lay process). In all pipeline design guidelines, the conservative approach is advised. For example, the majority of early Gulf of Mexico (buried) pipelines were designed on the basis of 2 mA / ft. of bare steel and 5% coating failure. In essence, this means taking 5% of the total pipeline surface area, and applying 2 rnA / ft. of cathodic protection current to it. This may sound reasonable, until one looks at what 5% bare means:

On a 40 ft. joint of 12 in. pipe, 5% bare coating would have 2 square feet of bare steel, or to express it another way. 4 linear feet of pipe would have the coating gone from 180° of the circumference. This is an extremely conservative figure. As a result, the early pipeline system designs would appear to be very conservative.

PIPELINE INTEGRITY

When considering the role of cathodic protection (CP) in pipeline integrity we should investigate what causes offshore pipelines to fail and leak. If all the failures of pipelines in the Gulf of Mexico were counted and tabulated, the findings would probably show the general trend expressed in Figures 4 and 5. (These graphs are based on studying a limited sample of failure reports from two oil companies.)

Figure 4. Causes of offshore pipeline failure

Figure 5. Causes of offshore riser failure

Since external corrosion is only responsible for a very few of the documented pipeline failures, we could truthfully say that, in general, the combination of CP and coatings is doing a good job.

However, we must not be led into a false sense of security. The only reason the external leaks have not started in earnest is that the old systems were unknowingly over-designed. Thus, a 25-year design life has effectively turned into 30, 35 or even 40 years.

There is a practical limit on how long sacrificial anodes will last, and it is based on the auto-corrosion rate of the anode material. If we were to assume that pipeline systems are all good for at least 30 years, then there should be several thousand miles of pipeline with depleted CP systems (Figure 1). The question, then, is why are we not seeing more external failures?

In truth, the answer to that question is that we probably are seeing a higher external corrosion leak rate than we have at any time in the past. But when will it peak? The pitting rate of steel in seawater on a well-coated pipeline in the absence of cathodic protection anodes could vary between 0.01-0.05 inches per year. Thus, it could take anywhere from 5 to 25 years to pit through an inch of steel. This amount of loss could be sufficient to cause a pipeline failure. Higher corrosion rates can be generally expected when the pipe coating has a combination of large damaged areas and adjacent pinhole defects, and when the pipe is exposed to seawater rather than mud. There is also a particular risk of microbiologically influenced corrosion (MIC) on buried lines with bitumastic-type coatings and depleted cathodic protection.

WHAT IS THE RISK?

On pipelines in excess of 30 years old, the risks are quite high. If the cathodic protection systems have depleted, then corrosion will begin at numerous sites all over the pipeline. Unless detected and retrofitted, the first leak could be the end of the pipeline, as the next several hundred won't be far behind. There are only so many clamps that an operator can afford to install before economic concerns dictate pipeline replacement or abandonment. Given the cost of laying pipelines offshore today, many of the lines will never be replaced, and this could result in early deaths of the oil and gas fields they service. Other old lines are the critical links between the new deep water fields and the shore-based markets. Loss of these lines will present an interesting and unenviable dilemma for operators.

WHAT IS THE ANSWER?

There are three basic strategies that a pipeline owner can adopt:

1. Survey the pipeline cathodic protection system.
2. Retrofit the cathodic protection anodes on pipelines of a certain vintage.
3. Do nothing (and hope that the laws of electrochemistry will ignore your pipeline), essentially ignoring the problem.
Cathodic Protection Surveys
Close-interval cathodic protection surveys are the most logical strategy, but strangely enough, operators in the Gulf of Mexico survey very little. When a survey is actually run, it is usually of little value because the method used (trailing wire) inherently produces erroneous data.

There are accurate survey systems available; these either involve physically contacting the line at intervals or utilizing remotely operated vehicles (ROV's) (Figure 6) to track the pipeline and carry reference electrode arrays above the pipeline at known locations (a typical plot from such a survey is shown Figure 7). This type of survey will let the operator see the condition of the line and make informed decisions regarding retrofitting.

Figure 6. Work-class ROV Challenger equipped for pipeline survey. Photo courtesy of Sonsub Inc,

Figure 7. Detailed pipeline CP inspection plot. Green trace is current density, red trace is potential. Downward green spikes indicate anode locations; upward spikes reflect coating damage.

In addition to the corrosion data shown, the survey will also yield important information on the precise location of the pipeline and the depth of burial below the seabed; these data points can be crucial when designing the eventual anode retrofit.

Retrofit Anodes on Pipelines of a Certain Age

Retrofitting the cathodic protection system with supplemental anodes would only make sense if the line in question is very old and the required additional life were significant. The cost to perform a pipeline cathodic protection inspection will run anywhere from $2,000 to $6,000 per mile, and that cost may be eliminated if the decision to retrofit is made. There will only need to be a post-installation survey, once the new anodes are laid.
Of course, retrofitting pipeline cathodic protection systems offshore is not always a simple matter, especially when lines are deeply buried. Often, the retrofit program will need an up-front survey to find the pipeline - so why not survey it first?

Do Nothing

Very often this decision is made based on the following logic: "If I know I have a problem, I will have to take care of it; if I don't survey the pipeline, I will not have to find out whether or not I have a problem." This logic sounds like the chronic smoker who dares not visit the doctor for fear it will be discovered he has lung cancer! A surprising number of operators follow this logic.

SUMMARY

In summary, it must be concluded that cathodic protection plays an absolutely vital role in pipeline integrity offshore. Cathodic protection is cheap and reliable, with an outstanding track record of success in offshore applications. But cathodic protection systems have a finite life and unprotected steel has a very short life in seawater. Check your cathodic protection if the pipeline is more than 25 years old.

Source : http://stoprust.com/technical-papers/26-offshore-pipeline-integrity/