Time-Dependent Failure Mechanisms

Time-dependent failure mechanisms involve some form of degradation—loss of material or other form of weakening over time. These threats are efficiently assessed via the PoF triad (see ). Under this protocol, exposure is measured as unmitigated material loss or crack progression rates (normally units of mpy or mm/yr), mitigation is a reduction in exposure (a reduction in exposure rate), and resistance is the effective^[1] wall thickness of the component. Under this assessment protocol, PoD will be >0 unless a material impervious to any time-dependent failure mechanism is assessed or mitigation is 100%—both being unusual possibilities. There are however, pipeline materials with very low susceptibility to certain types of time-dependent failure mechanisms. In those cases, the assessment will show very low PoD and PoF values.

While the discussion here often focuses on steel transmission pipelines, the same time-dependent failure mechanisms are possible in a gathering, distribution, offshore system and on facility components. Even when very different materials are involved—for example, plastic vs steel—the mechanisms are modeled exactly the same way. The same risk assessment techniques apply to all types of pipeline components and, indeed, to any object.

The production of an intermediate calculation, TTF, in an assessment for time-dependent failure mechanisms, reflects the time aspect of degradation type threats and distinguishes them from time-independent failure mechanisms. The TTF is used to produce PoF but is also useful as a stand-alone value for decision-making. It is an essential determinant of inspection and integrity assessment frequencies.

Most pipeline materials are chosen for their ability to have unlimited life spans, so long as deterioration mechanisms are avoided. For most materials, the deterioration mechanisms are corrosion and cracking, with sub-classifications such as UV degradation and creep included for certain materials. In some pipeline systems, such as gathering pipelines intended for finite service lives, some amount of degradation (corrosion) is accepted. See discussion in .

Degradation does not usually progress uniformly on all components of a pipeline or even on a single component. In the assessment of time-dependent threats, the measurement of interest is: probability and potential severity of one or more degrading locations per unit surface area. The challenge will often be the prediction of very small areas of degradation among large areas that are damage free.

• 1. Basic risk assessment model.
  2. Assessing corrosion potential: sample of data used

PoF and System deterioration rate

The risk assessment described in this chapter is measuring/estimating the probability and aggressiveness of phenomena such as corrosion and cracking as time-dependent mechanisms. Unmitigated exposure is the first element of the measure of PoF, as it is for all threats.

For time-dependent mechanisms, damage potential, as measured by exposure, may be very low in many instances, making PoF low, even with minimal mitigation and resistance. Examples include corrosion potential for steel pipe in dry, sandy, benign soils; components well protected by coatings and cathodic protection; and plastic or concrete lines in dry, neutral pH soils. When exposure is low, long TTF is expected, even when mitigation is weak. The appearance of long TTF periods for some low degradation estimates may at first seem excessive. However, they are not inconsistent with research including one study that uses 220+ years as a median life expectancy for the normally corrosion-vulnerable material of cast iron [2].

On the other hand, aggressive degradation conditions may exist—high exposures. Examples include corrosion mechanisms involving acidic, contaminated soils; steel pipe with a high potential to become anodic to other buried structures; concrete pipe in high chloride soils; MIC activity; AC induced current; and high-stress, high fatigue cycle conditions. In extreme cases, a high degradation rate can lead to through-wall failure of a component in a matter of days.

To translate damage potential into the probability of failure for a component, additional factors such as the wall thickness, material properties, and stress levels need to be considered. In simplest terms and with some assumptions, given an initial wall thickness and a degradation rate, the time to corrode or crack through the component wall can be estimated. More minor wall loss depth over a larger area can also lead to a failure in a higher-stress scenario (metal volume loss leading to rupture), and, at the other extreme, pinhole leaks through the pipe wall do not necessarily constitute failure under the “excessive leakage” definition often used or implied for distribution pipeline systems.

Age-based or historical leak-rate based risk estimates generally play a more limited role in risk management, as is discussed in .

Measurements vs Estimates

Risk assessments of time-dependent failure mechanisms rely on both materials science based estimates of possible degradation—for example, soil corrosivity based on its chemistry–and actual measurements of degradation, often extrapolated from the measurement site to the location being assessed. This manifests as parallel analyses paths in the assessment where the most recent and most accurate information plays the larger role in the assessment. See the earlier discussion in .

Use of Evidence

When degradation mechanisms are not directly observable, the assessment must use mostly indirect evidence to infer damage potential. This is consistent with the historical practice of corrosion control on buried pipelines. Any detection of degradation damages or direct measurements of actual degradation rate can then be used to calibrate the previous assessment results and/or tune the risk model.

Where a degradation rate is actually measured, the risk assessment can be calibrated with this information. A finding of ‘no damage’ however, must be used carefully. Caution must be exercised in assigning favorable rates based solely on the non-detection of damages at certain times and at limited locations. It is important to note that the potential for some corrosion or cracking damages can be high even when no active damage is detected during a sampling process, especially a random sampling process.

See detailed discussion of use of inspection and integrity assessment information, .

Corrosion—General Discussion

Background

As a common cause of failure in most metallic structures, including metallic pipelines, corrosion often plays a large role in risk assessment. Even for non-metallic pipeline components, the expanded definition of ‘corrosion’ as any degradation mechanism, brings corrosion into the risk assessment. Background discussions on types of corrosion can be found in PRMM.

Assessing Corrosion Potential

As with other failure modes, evaluating the potential for corrosion follows logical steps, replicating the thought process that a corrosion control specialist would employ. This involves (1) identifying, at all locations, the types of corrosion possible, both on internal, external surfaces; (2) identifying the vulnerability of the pipe material—how probable and how aggressive is the potential corrosion; and (3) evaluating the corrosion prevention measures used.

Quantifying this understanding is done using the same PoF triad that is used to evaluate each failure mechanism: exposure, mitigation, and resistance, each measured independently. This will result in the following measurements, ready to be combined into a TTF estimate from which a PoF estimate can emerge:

• Aggressiveness of unmitigated corrosion at contact point between internal contents and component (units of mpy or mm/yr)
• Aggressiveness of unmitigated corrosion at contact point between external environment and component. (units of mpy or mm/yr)
• Effectiveness of mitigation measures (units = %)
• Amount of resistance (units = equivalent wall thickness, inches or mm)

The independent measurements of exposure and mitigation are critical to the understanding of corrosion damage potential. For example, a subsurface environment of Louisiana swampland may present a very corrosive environment, while a dry Arizona desert environment typically produces a very low corrosion rate. The mitigation—the coating system and the cathodic protection system—are obviously more critical to damage prevention in Louisiana. Perhaps, the damage potential in the Louisiana system with very robust corrosion prevention could be made roughly equivalent to the Arizona desert situation where minimal corrosion preventions are needed since the environment is very benign. But it is important to understand when the damage potential is low because of exposure versus due to mitigation.

The two factors that must be assessed to define the corrosion exposure are the material type and the environment. The environment includes the conditions that impact the pipe wall, internally as well as externally. Because most pipelines pass through several different environments, the assessment must allow for this by sectioning appropriately.

Corrosion mechanisms are among the most complex of the potential failure mechanisms. There are a wide variety of available mitigation methods and supporting inspection techniques. As such, many more pieces of information are efficiently utilized in assessing this threat. Because corrosion is usually a highly localized phenomenon, and because inspection opportunities often provide only general information, uncertainty is often high.

Corrosion rate

The time to failure is related to the resistance of the material and the aggressiveness of the corrosion mechanism—the mitigated corrosion rate. The material resistance is a function of material strength and dimensions, most notably wall thickness and the stress level. This chapter examines the process of estimating first the unmitigated- and then the mitigated corrosion rate. A separate estimate is produced for internal and external corrosion potential.

The unmitigated corrosion rate is the ‘exposure’ in the exposure-mitigation-resistance modeling triad. Exposure estimates should consider the formation of a protective layer or film of corrosion by-products that often occurs and precludes or reduces continuation of the damage. Similarly, temperature effects, rare weather conditions, releases of chemicals, or any other factors causing changes in the corrosion rate should be considered.

Corrosion is a volumetric loss of material but common convention states corrosion rate in terms of depth penetration (pitting). Mils per year (mpy, one mil = 1/1,000 inch) and mm/year are common units of pitting corrosion rates in metals.

While plastics are often viewed as corrosion proof, sunlight and airborne contaminants (perhaps from nearby industry) are two degradation initiators that can affect certain plastic materials and can be efficiently modeled as corrosion in a risk assessment.

Unmitigated Corrosion Rates

As the phrase implies, an unmitigated corrosion rate is a measure of the corrosion progression that may occur in the absence of any corrosion control actions. Normally, a pitting rate is used as the most conservative measure, since pitting rates are usually the most aggressive. When a general (non-pitting) corrosion rate is also active, the resistance measurement (see ) should take into account loss of component integrity by loss of metal, in addition to loss of integrity by a pitting-induced leak.

There is much research available showing corrosion rates under various laboratory scenarios. Even though laboratory results are often not directly transferable to field conditions, they nonetheless provide valuable insight into plausible corrosion rates, especially when extreme conditions, unlikely to be seen in actual field characteristics, are simulated in the laboratory and suggest maximum rates.

Note that corrosion rates are very situation specific. Any type of corrosion might lead to a failure under the right circumstances, even when history suggests it to be relatively rare failure mechanism.

Recall the previous discussion of measurements versus estimates arising from inferential information. Proper risk assessment uses all available information. In the case of corrosion rates, information often appears in both general forms—measurements and inferences. The final estimate emerges from an examination of both, after adjustments for information age and accuracy have been made. The assessment chooses the best estimate based on the strength of evidence—newer and more accurate information is chosen over older, less accurate information. Note the nuances that have to be considered. For example, highly accurate measurements, but taken some distance from the point of interest where conditions may not be consistent (ie, internal corrosion coupons); or measurements taken at a point in time no longer reflective of recent conditions.

See also PRMM.

Types of corrosion

Many types of corrosion are possible. All can be efficiently modeled in the same way. The discussion here will focus on corrosion of carbon steel. Regardless of material or specific corrosion mechanism, the corrosion assessment should recognize the two locations where corrosion can occur—the external surface of the component or the internal surface. Since these two are significantly different both in terms of exposure and mitigation, they are usually best assessed independently.

For evaluation purposes, the two corrosion (types) locations are further broken down as follows:

External Corrosion:

• Exposure to Atmosphere
• Burial in Soil
• Submersion in Water
• AC-induced
• Interferences.

Internal Corrosion:

• Stream-based
• Under-deposit.

MIC is a potential exacerbating factor in most of these and is therefore appropriately assessed within each, instead of as an independent aspect.

From a chemistry perspective, these corrosion processes are often very similar.

External Corrosion

A pipeline component can be susceptible to external corrosion damage via atmospheric corrosion, subsurface corrosion (including submerged conditions), or both.

Atmospheric corrosion deals with pipeline components that are in contact with the atmosphere. It is a normally a less aggressive corrosion mechanism but there are dramatic exceptions. Alternately wet and dry areas, such as splash zones near water bodies or an annular space inside buried casings, have caused aggressive corrosion and pipeline failures. Failure potential due to atmospheric corrosion are lower in most segments because 1) most pipelines are predominantly buried and, hence, have few portions exposed to the atmosphere, 2) atmospheric corrosion rates are usually low, and 3) there are increased inspection opportunities for above-ground components.

Subsurface corrosion includes both onshore and offshore installations and is the result of potentially very aggressive mechanisms, including various types of galvanic corrosion cells and interference potential from electrical sources and other buried structures. There are also challenges in gaining knowledge of actual corrosion on subsurface components. Subsurface pipe corrosion is often the most information-rich area of risk assessment, reflecting the numerous data-collection practices and the complicated mechanisms underlying this type of corrosion.

Modern metallic distribution pipeline systems (steel and ductile iron, mostly) are installed with coatings and/or cathodic protection when soil conditions warrant. This is equivalent to practices in modern transmission pipelines. However, in many older metal systems, especially older urban distribution systems, little or no corrosion barriers were put into design considerations.

As a special form of subsurface external corrosion, AC-induced corrosion is best examined independently. Also warranting special attention in subsurface systems are nearby sources of DC electricity that can interfere with protective systems or generate new corrosion potential.

Erosion can be thought of as an external corrosion mechanism (in the broad definition of ‘corrosion’). Often due to moving water, it is most often included in geohazards. The potential for undermining (loss of support), impingement forces, and others is normally more likely than material loss due to erosion. However, one can envision scenarios involving susceptible component materials in an aggressive flowing (or even stagnant) fluid environment that warrants assessment as a bona fide external degradation mechanism. Erosion or abrasion by wind borne particles is an example. UV degradation of plastics and other material-property changing mechanisms can be included here and/or in the resistance estimations. See and .

Internal Corrosion

Internal corrosion deals with the potential for corrosion originating within the pipeline. Some significant pipeline failures have been attributed to internal corrosion. Internal corrosion results in wall loss and is caused by a reaction between the inside pipe wall and the interior environment, ie, the product being transported and its flow regime. Internal corrosion may not be the result of the product intended to be transported, but rather a result of impurities in the product stream. Erosion is a possible internal corrosion mechanism (again, in the broad definition of ‘corrosion’) as is discussed in a later section.

MIC

The term microbiologically-influenced corrosion (MIC) is used to designate the localized corrosion affected by the presence and actions of microorganisms. MIC was described in a previous section.

External corrosion manifestations of MIC are typically characterized by pitting and crevice corrosion, according to some experts. Soils with sulfates or soluble salts are favorable environments for anaerobic sulfate-reducing bacteria [69]. Also additional discussion in PRMM.

Erosion

As noted previously, erosion is also considered here as a potential time dependent mechanism for both internal and external surfaces. For instance, an exposed concrete pipe in a flowing stream can be subject to erosion as well as mechanical forces. Erosion on an interior component wall is caused by high velocity flow streams containing abrasive particles and can be particularly damaging at impingement points such as elbows.

Corrosion Mitigation

Corrosion mitigation is specific to the type of corrosion and, often, to the location. Details are discussed in subsequent sections. Here, the philosophy of modeling corrosion mitigation is discussed.

Similar to other mitigation where an OR gate can combine mitigation measures acting independently, a multi-layer defense against corrosion uses the same modeling approach. The common mitigation against external corrosion for a buried metal pipeline is a two-part defense of coating and cathodic protection (CP). These two are usually employed in parallel and provide redundant protection. Some practitioners rate these measures as equally effective, in theory at least. Since each can independently prevent or reduce corrosion, an OR gate can be used in assessing the combined effect. The notion of independence here refers to a modeling protocol, not to an idea that the two are not related in considerations of real world design, economics, maintenance, etc.

An effective modeling approach quantifies external corrosion potential by coupling exposure (corrosion aggressiveness) with the probability of one or more active corrosion points on the pipeline segment. This probability is based on an estimate of the frequency of active corrosion locations, derived from estimates of coating holiday rates plus the efficiency with which CP prevents those holidays from experiencing corrosion.

Underpinning this procedure is the belief that the simultaneous occurrence of multiple defects is appropriately modeled as the product of the independent defect rates. That is, the probability of both 1 and 2 occurring simultaneously is Probability 1 x Probability 2.

Corrosion Failure Resistance

The resistance to failure by corrosion is efficiently measured as an effective wall thickness. The wall thickness is a critical part of all stress-carrying capacity calculations that underpin resistance estimates in thin-shelled, pressure containing structures. This wall thickness, taken with the mitigated corrosion rate, yields a time to failure, or remaining life estimate. For example, a 0.250” effective wall thickness, experiencing 10 mpy pitting corrosion, would be expected to leak in 25 years. A rupture could occur sooner, depending on the lateral corrosion damage and the stress level. This is efficiently modeled in a parallel analysis—‘growing’ the corrosion damage laterally as well as in depth. The shorter of the leak-driven or the rupture-driven TTF estimate provides the final TTF value for use in generating the PoF estimate.

The ‘effective’ adjective in front of ‘wall thickness’ allows inclusion of any weaknesses (previous damages, manufacturing or construction defects, stress concentrators, etc) or vulnerabilities (selective seam corrosion, heat affected zones of welds, etc) which, when modeled as equivalent reductions in pipe wall thickness, show reduced remaining life estimates and corresponding increases in PoF. This is fully discussed in .

Sequence of eval

Regardless of the type of corrosion or its location on the pipeline system, the risk assessment protocol is the same. That protocol is as follows:

1. Estimate Exposure (assuming no mitigation).
2. Estimate Mitigation Effectiveness.
3. Combine the above into an estimate of degradation (PoD, typically expressed as mpy or mm/year).

Estimate exposure levels

The unmitigated corrosion rate for the PXX level of conservatism desired is first estimated.

This first step involves evaluating the pipe’s internal and external environments. For each corrosion type, external and internal, and their associated sub-types (AC induced, MIC, etc), an assessment is made of the corrosivity at the material’s interface with its immediate environment, if no mitigation is employed. Once a database of location-specific characteristics of the pipeline and its surroundings is built, this process can be at least partially automated. The following discussion illustrates a typical approach to characterizing each component’s environmental exposures (the threats to the pipe from its immediate environment).

To differentiate two general types of external corrosion, typically with quite different pitting rates, contacts with the atmosphere are first identified. These include locations with depth of cover = 0, casings, tunnels, spans, valve vaults, manifolds, and meters. Under an assumption of a mostly-buried pipeline, these occurrences are rarer and represent potential for atmospheric corrosion.

Next, location-specific characteristics that typically harbor more aggressive atmospheric corrosion rates are identified. These include supports, hangars, splash zones, tree sap depositions, and many others. These are treated as external corrosion ’hot spots’.

If the pipe is not exposed to the atmosphere, then the typical assumption is that it is immersed in soil or water and should be treated as being in a subsurface corrosive environment. As with atmospheric corrosion, location-specific info is needed. Soil corrosion rates are measured or estimated at all points along the pipeline. Provisions can also be added to capture scenarios where a component is exposed to both atmospheric and soil corrosivities, such as a pipeline laid atop the ground, at ground/air interfaces, in splash zones, and others.

For internal corrosion, the normal assumption is that all portions of the system are exposed to the product being transported and, hence, to any internal corrosion potential promulgated by that product. Therefore, all portions have general exposure to internal corrosion. Especially where corrosion rates can change over both time and space—for example, where contaminant and velocity excursions impact internal corrosion —a probability-weighted corrosion rate can be used.

Next, location-specific characteristics that exacerbate internal corrosion such as areas of accumulations of solids and liquids, are identified, perhaps by elevation profiles, velocity profiles, and product stream analyses. These are ‘hot spot’ locations for increased internal corrosion rates, analogous to the external corrosion hot spots.

Estimate mitigation effectiveness

For barrier-type mitigation, such as coatings, and certain chemical inhibitors, the probability of a gap in protection per unit of surface area to be protected is estimated. For subsurface corrosion, both soil burial and submersion in water, the probability of unprotected surface area is similarly estimated. Then, the role of secondary mitigation measures such as CP, inhibitor injection, cleaning, etc are overlaid with the barrier effectiveness.

These mitigation effectiveness estimates can be very challenging to produce. Much information is often available, but inferential and/or location-specific in nature, requiring interpretation and extrapolation to assessed areas with less information. Overline surveys provide very useful but only indirect evidence.

Estimate Degradation Rate

Exposure and mitigation estimates are then combined to yield probabilistic damage rates, after mitigation, typically in units of mpy or mm per year. All combinations of unmitigated exposure and mitigation effectiveness are considered along the assessed pipeline. Hot spots—ie, aggressive unmitigated corrosion—at locations with weak mitigation will show highest damage rates.

The mitigated damage rate estimates are now combined with estimates of effective pipe wall thickness to estimate TTF. This is value, again usually changing along the pipeline, is often of more interest than the final PoF. TTF can more effectively drive risk management decision-making, including integrity re-assessment intervals.

Finally, choosing and applying a representative relationship between TTF and PoF yields the estimate for corrosion PoF for the future year of interest.

External Corrosion

As with all PoF analyses, we begin with an assessment of the exposure level and then consider mitigation measures and finally, the ability to absorb damage (resistance). Measuring these independently is an essential aspect of understanding the corrosion threat to component integrity.

A very benign environment, from a corrosion threat perspective, can be seen as roughly equivalent to a more corrosive environment with effective mitigation, but calls for a significantly different risk management approach. For example, loss of corrosion mitigation on a component buried in a desert may not significantly increase failure potential—due to already-low exposure levels. The same loss—effectiveness reduction—for a component buried in a swamp would be much more serious. This important distinction is apparent in a risk assessment that measures exposure separately from mitigation.

External Corrosion Exposure

A major aspect of assessing external corrosion potential is an evaluation of the environment surrounding the component. See PRMM for a brief introduction to galvanic corrosion.

Different pipe materials have differing susceptibilities to damage by various conditions. Potential deterioration of cement-containing materials such as concrete or asbestos-cement pipe, plastics, metals, and others may need to be included here. Any and all knowledge of pipe material susceptibility to degradation should be incorporated into the exposure estimates.

Exposure estimation entails imagining a completely unprotected surface. Unmitigated corrosivity is primarily a measure of how well the external environment can act as an electrolyte to promote galvanic corrosion on the pipe. Additionally, aspects of the external environment that may otherwise directly or indirectly promote corrosion mechanisms should be considered. These include bacterial activity, the presence of corrosive-enhancing chemicals, and stray electrical effects.

Coating systems, most commonly paint, are often used to protect corrodible metallic surfaces but are not to be considered when assessing exposure. Because a coating system is always considered to be an imperfect barrier, the external electrolyte—usually soil, water, or atmosphere—is assumed to be in contact with the pipe wall at some points and hence requires an estimate of its aggressiveness (exposure).

The evaluator should be alert to instances where the external conditions change rapidly along the pipeline route. Changes in soil type, water table (for example, low elevation creek crossings), and the presence of casings are obvious examples for buried components. Less obvious are certain road bed materials, past waste disposal sites, imported foreign materials, etc. that can cause highly localized corrosive conditions. In an urban environment, the high number of construction projects leaves open the opportunity for many different materials to be used as fill, foundation, road base, etc. Some of these materials may promote corrosion by acting as a strong electrolyte, attacking the pipe coating, or harboring bacteria that add corrosion mechanisms. A lower resistivity soil will promote graphitization of low ductility cast iron pipe as well as corrosion of carbon steel.

The assessment should also consider situations where piping of different ages and/or coating conditions is joined. Dissimilar metals, or even minor differences in chemistry along the same piece of steel pipe, can cause galvanic cells to form and promote corrosion.

If it can be demonstrated that corrosion is not possible in a certain area, exposure (corrosion rates) are essentially zero. The evaluator should ensure that adequate tests of all possible corrosion-enhancing conditions at all times of the year have been made.

Atmospheric type

Atmospheric corrosion is the chemically driven degradation in a material resulting from interaction with the atmosphere. The oxidation of metal in the air is the most common manifestation. The estimated annual loss due to atmospheric corrosion is estimated to be billions of dollars [31].

Even predominantly-below-ground cross-country pipelines are not immune to this type of damage. Components are exposed to the atmosphere when they are installed above ground level or are in subsurface enclosures such as vaults or casings. In the risk assessment, it is appropriate to capture an atmospheric corrosivity value for all areas of the pipeline, even when contact with the atmosphere is not occurring. This is the same for soil corrosivity. As part of the dynamic segmentation process, portions that are actually unburied will use the atmospheric corrosion value rather than the soil corrosivity values.

Certain characteristics of the atmosphere can enhance or accelerate corrosion. For steel, this is the promotion of the oxidation process. Oxidation of metal is the primary mechanism examined here although the process is identical for any other corrosion scenario of a pipeline material in an atmosphere.

The most common atmospheric characteristics influencing metallic corrosion include:

• Moisture. Higher air humidity or other moisture contact is usually more corrosive.
• Temperature. Higher temperatures tend to promote corrosion.
• Airborne chemicals: naturally occurring airborne chemicals such as salt or CO₂ or man-made chemicals, often considered pollutants, such as chlorine and compounds containing SO₂ typically accelerate oxidation (corrosion) processes.

Marine atmospheres are usually highly corrosive, and the corrosivity tends to be significantly dependent on wind direction, wind speed, and distance from the coast. An equivalently corrosive environment is created by the use of deicing salts on the roads of many cold regions.

Dew and condensation can exacerbate corrosion. A film of dew, saturated with sea salt or acid sulfates, and acid chlorides of an industrial atmosphere provides an aggressive electrolyte for the promotion of corrosion. Also, in humid regions where nightly condensation appears on many surfaces, the stagnant moisture film can promote corrosion. Frequent rain washing which dilutes or eliminates contamination can help reduce otherwise aggressive corrosion rates.

Temperature plays an important role in atmospheric corrosion in two ways. First, there is the normal increase in corrosion activity which can theoretically double for each ten-degree increase in temperature. Secondly, the temperature differences of metallic objects from the ambient temperature promotes condensation. This temperature difference may be due to lags in temperature equalization due to the metal’s heat capacity. As the ambient temperature drops during the evening, metallic surfaces tend to remain warmer than the humid air surrounding them and do not begin to collect condensation until some time after the dew point has been reached. As the temperature begins to rise in the surrounding air, the lagging temperature of the metal structures will tend to make them act as condensers, maintaining a film of moisture on their surfaces. The period of wetness is often much longer than the time the ambient air is at or below the dew point and varies with the section thickness of the metal structure, air currents, relative humidity, and direct radiation from the sun. Differences in temperature between pipe wall due to flowing product and ambient conditions can cause similar effects.

Cycling temperature has produced severe corrosion on metal objects in tropical climates, in unheated warehouses, and on metal tools or other objects stored in plastic bags. Since the dew point of an atmosphere indicates the equilibrium condition of condensation and evaporation from a surface, a temperature below the dew point enables corrosion by condensation on a surface that could be colder than the ambient environment.

Airborne pollutants are another source of corrosion. Sulfur dioxide (SO₂), which is the gaseous product of the combustion of fuels that contain sulfur such as coal, diesel fuel, gasoline and natural gas, has been identified as one of the most important air pollutants which contribute to the corrosion of metals. Less recognized as corrosion promoters, are the nitrogen oxides (NO_x), which are also products of combustion. A major source of NO_x in urban areas is the exhaust fumes from vehicles. Sulfur dioxide, NO_x and airborne aerosol particles can react with moisture and UV light to form new chemicals that can be transported as aerosols. [1026]

In the absence of direct corrosion rate measurements, a schedule can be devised to show not only the effect of a corrosion promoter, but also the interaction of one or more promoters. For instance, a cool, dry climate is thought to minimize atmospheric corrosion. If a local industry produces certain airborne chemicals in this cool, dry climate, however, the atmosphere might now be as severe as a tropical seaside location.

See PRMM for an example list of relative corrosivities for different types of atmospheres. To utilize such lists in a modern risk assessment, corrosion rate estimates should be assigned to each. For instance, an atmosphere characterized by industrial pollutants and/or a marine environment, especially when surfaces are alternately wet and dry, may support corrosion rates of 10 to over 50 mpy. A cool, dry, desert environment may support virtually negligible rates—0.1 mpy or less.

It should be apparent by now, that proper segmentation is required in a modern risk assessment. Components with atmospheric exposures must be distinct from those that have no such exposures. A cased piece of pipe will be an independent section for assessment purposes since it has a distinct risk situation compared with neighboring sections with no casing. The neighboring sections will often have no atmospheric exposures and hence no atmospheric corrosion threat at all. Similarly, within a facility, components located near to emissions of pollutants and/or high heat, may suffer radically different corrosion rates than other components in the same facility.

Subsurface Corrosion

Although subsurface components of many materials can be susceptible, this part of the corrosion exposure assessment will most commonly apply to metallic pipe material that is buried or submerged. If the component being evaluated is not vulnerable to subsurface corrosion, as may be the case for a plastic pipeline, this exposure goes to zero. If the component is totally aboveground (and flood potential is ignored), the segmentation process allows this component to also have zero exposure to subsurface corrosion.

More than one corrosion mechanism may be active on a buried metal structure. Complicating this is the fact that corrosion processes are mostly detected indirectly, not by direct observation.

Soil corrosivity

Because a coating system is always considered to be an imperfect barrier, the soil is always assumed to be in contact with the pipe wall at some points. Soil corrosivity is often initially a qualitative measure of how well the soil can act as an electrolyte to promote galvanic corrosion on the component. Aspects of the soil that may otherwise directly or indirectly promote corrosion mechanisms should also be considered. These include bacterial activity and the presence of other corrosion-enhancing substances.

The possibly damaging interaction between the soil and the pipe coating is not a part of this variable. Soil effects on the coating (mechanical damage, moisture damage, etc.) should be considered when judging the coating effectiveness as a mitigation variable.

The importance of soil as a factor in the galvanic cell activity is not widely agreed on. Historically, the soil’s resistance to electrical flow has been the measure used to judge the contribution of soil effects to galvanic corrosion. As with any component of the galvanic cell, the electrical resistances play a role in the operation of the circuit. Soil resistivity or conductivity therefore seems to be one of the best and most commonly used general measures of soil corrosivity. Soil resistivity is a function of interdependent variables such as moisture content, porosity, temperature, ion concentrations, and soil type. Some of these are seasonal variables, corresponding to rainfall or atmospheric temperatures. Some researchers report that abrupt changes in soil resistivity are even more important to assessing corrosivity than the resistivity value itself. In other words, strong correlations are reported between corrosion rates and amount of change in soil resistivity along a pipeline [41].

As the environment that is in direct contact with the pipe, soil or water characteristics that promote corrosion must be identified. The evaluator should list those characteristics and assess all locations accordingly. Resistivity is widely recognized as a variable that generally correlates with corrosion rate of a buried metal. Additional soil characteristics that are thought to impact metallic and concrete pipes include pH, chlorides, sulfates, and moisture. Some publicly available soils databases (such as USGS STATSGO) have ratings of corrosivity of steel and corrosivity of concrete that can be used in a risk evaluation.

Even within a given pipeline station, soil conditions can change. For instance, tank farm operators once disposed of tank bottom sludges and other chemical wastes on site, which can cause highly localized and variable corrosive conditions. In addition, some older tank bottoms have a history of leaking products over a long period of time into the surrounding soils and into shallow groundwater tables. Some materials may promote corrosion by acting as a strong electrolyte, attacking the pipe coating or harboring bacteria that add corrosion mechanisms. Current soil conditions should ideally be tested to identify placement of non-native material and soils known to be corrosion promoting.

A schedule can be developed to assess the average or worst case (either could be appropriate—the choice, however, must be consistently applied) soil resistivity. This is a broad-brush measure of the electrolytic characteristic of the soil.

Sample Pitting Corrosion Rates, mpy

Type
Atmospheric	Salt Water	Soil
0.001-5	1-50	1-20

Subsurface corrosion of nonmetallic pipes

The same methodology is used to assess the damage potential from buried pipe corrosion for nonmetallic materials. For nonmetallic pipe materials, the corrosion mechanisms may be more generally described as degradation mechanisms

AC-Induced Corrosion

If a pipeline becomes energized by AC current, perhaps by passing through a magnetic field, a sometimes-very-aggressive type of corrosion can occur. This is typically seen on steel pipelines located near to higher power AC transmission systems. See PRMM pages for more information.

No AC power in proximity of a component will usually be the lowest risk scenario followed by various exposure levels created by AC power being nearby, its configuration, soil resistivity, coating condition, and numerous other factors, with various possible levels of preventive measures being used to protect the pipeline

EAC

Environmentally assisted cracking (EAC) occurs from the combined action of a corrosive environment and a cyclic or sustained stress loading. Combining a crack growth rate with a corrosion growth rate is one way to model the potentially more aggressive nature of EAC. While corrosion significantly contributes to this failure mechanism, it is discussed and modeled as a cracking phenomenon in .

External Corrosion Mitigation

The most common form of prevention for external corrosion on metallic surfaces is to isolate the metal from the offending environment. This is usually done with coatings. If this coating is perfect, the corrosion process is effectively stopped—the electric circuit is blocked because the electrolyte is no longer in contact with the metal. It is safe to say, however, that no coating is perfect. If only at the microscopic level, defects will exist in any coating system.

For a buried or submerged metallic pipeline, common industry practice is to employ a two-part defense against galvanic corrosion on components. The first line of defense is a coating over all metallic surfaces, as discussed above.

The second line of protection typically employed in a buried steel pipeline is called cathodic protection (CP). Creating an electrical current on a metallic component that is immersed in an electrolyte (such as soil or water) provides a means to reverse the electrochemical process that would otherwise cause corrosion.

As would be expected, corrosion leaks are seen more often in pipelines where no or little corrosion prevention steps are taken. It is not unusual, to find older metallic components that have no coating, cathodic protection, or other means of corrosion prevention. In certain countries and in certain time periods in most countries, corrosion prevention was not undertaken.

Most transmission pipeline systems in operation today have cathodic protection systems, even if they were not initially provisioned with them. The presence of unprotected iron pipe and non-cathodically protected steel lines, is found in older distribution systems. As would be expected, these locations are statistically correlated with a higher incidence of leaks [51] and are primary candidates in many “repair-and-replace” decision-support models.

In some older buried metal station designs, little or no corrosion prevention provisions were included. If the station facilities were constructed during a time when corrosion prevention was not undertaken, or added after several years, then one would expect a history of corrosion-caused leaks. In the US, lack of initial cathodic protection was fairly common for buried station piping constructed prior to 1975.

Corrosion prevention requires a great deal of continuous attention in most pipeline systems. This should be a part of assessing a program’s effectiveness. This requires evaluation of various corrosion control measures including program appropriateness and adequacy for conditions, coverage, and PPM. A good PPM program includes inspection programs on tanks and vessels, for atmospheric corrosion, hot-spot protection, and overline surveys for buried portions.

For buried pipeline components, the general form of the mitigation estimate will be the combined effectiveness of the coating and the CP. This is conceptually an OR gate since each is an independent means of mitigation, at least theoretically. The effectiveness of each is measured in defect rate or gap rate; fraction unprotected per unit surface area, e.g. coating holidays per square foot of coated area, CP gaps per sq meter of protected surface, etc. The probability of both a coating holiday and a CP occurring simultaneously is the probability of an active corrosion location.

Consideration of changing mitigation effectiveness over time is an important aspect of risk assessment. This includes not only coating degradation and damages, and changes in CP, but also changes in inspection and remediation practices throughout the history of the segment. For example, a segment may be assigned three different mitigation effectiveness estimates:

1. Prior to installation of CP (coating effectiveness only, if any)
2. From installation of CP to when overline coating surveys (and subsequent remediations) became common practice
3. Future years for which risk estimates are sought.

Each of these time periods suggests differences in mitigation which result in different modeled mpy degradation rates. Coupling the mitigated mpy rates with their respective time periods produces estimates of remaining wall thickness postulated for today and future times.

Actual measurements of remaining pipe wall thickness will ‘re-set the clock’ by overriding these estimates—replacing estimates of ‘what might have happened’ with ‘what actually did happen’. A pressure test can also be used to re-set the clock by confirming that a certain level of metal loss did not occur. The role of inspection and testing as is detailed in .

Coating

Discounting its role in supporting the economics of CP, coating effectiveness is appropriately assessed in terms of its barrier effectiveness or defect rate.

Common pipeline system coatings include paint, tape wraps, waxes, hydrocarbon-based products such as asphalts and tars, epoxies, plastics, rubbers, and other specially designed coatings. For aboveground components, painting is the most common technique with many different surface preparation and paint systems being used. Some different coating materials might be found in distribution systems compared with transmission pipelines (such as loose polyethylene bags surrounding cast iron pipes), but these are still appropriately evaluated in terms of their suitability, application, and the related maintenance practices. See PRMM for more on this.

Some coating defects are more severe, not simply from a ‘larger is worse’ size perspective but from a variety of secondary effects. A smaller coating defect can sometimes create more consequential damage. Since corrosion results in a volumetric loss of metal, a small area of corrosion can create deeper defects sooner, compared to a larger corroding area. Coating effectiveness is the complement of coating gap rate, ie, coating effectiveness = (1 – coating gap rate).

To assess the present coating condition, several things should be considered, including the original installation process.

Coating evaluations—measurements

A directly measured coating defect rate—in units such as defects per square foot or square meter—is the most useful input to the risk assessment. A rigorous evaluation of coating condition would involve specific measurements of defects found, adjusted by the time that has passed since the inspection and the detection/identification abilities of equipment used during the inspection.

Several overline survey technologies have been developed to provide coating condition information for buried pipelines. Direct examinations, usually requiring excavations, also provide opportunities to directly measure coating defect rates and possibly extrapolate those findings to similar unexcavated segments.

Cathodic protection is designed to compensate for coating defects and deterioration. One way to assess the condition of the coating is to measure how much cathodic protection is needed per unit of surface area. Cathodic protection requirements are related to soil characteristics and the amount of exposed steel on the pipeline. Coatings with defects allow more steel to be exposed and hence require more cathodic protection. Cathodic protection is generally measured in terms of current consumption. A certain amount of electrical potential halts the electrochemical forces that would otherwise cause corrosion, so the amount of current generated while maintaining this required voltage is a gauge of cathodic protection. A corrosion engineer can make some estimates of coating condition from these numbers. This is often expressed as a % bare value, suggesting the coating gap rate.

Finally, metal loss inspections, such as from ILI, also provide evidence of coating defect rates. The coating defect rate can be significantly underestimated by the confounding role of CP. While external metal loss by corrosion certainly confirms that both coating defect and gap in CP exists, a finding of no external metal loss does not confirm coating integrity/effectiveness (for example, coating could failed but CP is protective).

Coating evaluations—estimates

In the absence of a direct measurement of coating effectiveness, an estimate can be generated. This will usually be much less certain but may be the only information available to the risk assessment. How effectively the coating is able to reduce corrosion potential at any point in time can be assessed in terms of defect rate and shielding potential. The defect rate—at any point in time depends on four factors, each of which should contribute to the estimate:

1. Quality of the coating system itself
2. Quality of the coating application
3. Damage/degradation rate since installation
4. Effectiveness of the inspection and defect correction program.

The first two address the fitness of the coating system—its ability to perform adequately in its intended service for the life of the project, given its material properties and its application. A quality coating is of little value if the application is poor. The second two consider the maintenance of the coating. When the last 2 factors are sufficiently quantified, perhaps by an inspection process, then a measured defect rate is available and the inferred estimate is not needed.

For estimation purposes, each of these components can be quantified based on their contribution to defect rate. The last factor—ability to remedy defects—will indicate a reduction in defect rate, while the others are usually assumed to add to current and future defect rates. There will be dependencies. A high initial quality coating is of reduced value if the application is poor; protection during installation and service is weak, or when the inspection and defect correction program is poor.

In the absence of measured coating defect rates (via overline survey or ILI or inferred by CP current demand), an estimation model for buried components could take the following general form:

([base defect rate] + [in service damage rate]) x [application factor] x [remediation factor]

Where

Base defect rate is defects per surface area per year, expected from this coating in this environment when application is perfect.

Application factor = multiplier, >= 1.0, showing increase in defect rate due to non-perfect application of the coating. This should account for both increased defect rates when initially applied plus increased defects due to application-related accelerated degradation of the coating in service.

Damage rate = additional defects (beyond those expected with an aging but perfectly applied original coating of this type), in units of defects per unit surface are per year; expected at this location since last inspection, since original installation, or in the future, depending upon risk being measured.

Remediation factor = multiplier, <=1.0, showing the decrease in defect rate due to effectiveness of inspection and remediation practices. This is an offset to the damage rate. It captures the general effectiveness of addressing coating defects, either since last inspection, since original installation, or in the future, depending upon risk period being measured. This reflects both the rigor of the remediation intention and the error rates in finding and adequately correcting the defects. This factor would not appear in a detailed risk assessment since location-specific remediation, usually re-coatings associated with excavations, would be directly included in the risk assessment. These locations can often be assumed to be initially defect free, and will have different date of coating installation and inspection, often a different type of coating, and updated quality control of application, compared to neighboring segments. All of these should combine to show increased coating effectiveness and reduced PoF at the remediated location.

The inputs should be supported by formalized reasoning analyses and be expressed in measurement units like defects per square meter. Such subjective SME estimates should be verified or modified based on subsequent data collection such as coating surveys or experience gained from excavation inspections.

Different analyses are usually warranted for mill-applied versus field-applied (for example, girth welds) coating types and application qualities since application is more problematic for field-applied coatings.

Considerations that should inform these estimates are further discussed below.

Coating fitness

An evaluation of the coating in terms of its ability to perform, ie, its appropriateness in its present application, is usually appropriate. Where possible, an SME should use data from coating stress tests or actual field experience to rate the quality. When these data are not available, drawing from any similar experience or from judgment will be required. See PRMM for a sample list of qualitative descriptors which are used only to better ground the analyses. These descriptors should include era of manufacture issues—ie, an older coating that, at the time of selection was believed to be fit for the application, but which was later revealed by the passage of time in service, to be inappropriate.

Coating Application

Most designed coating systems will experience relatively long service lives when properly applied. Part of the fitness assessment should include the likelihood of proper application. When installation is potentially more problematic, error rates are expected to increase. A good example is the use of polyethylene ‘shrink sleeves’ to cover and protect girth welds. This field-applied coating system has a good track record for some operators and very poor for others. Since its success is very sensitive to the environmental factors during installation and the skill of the installer, there is a wide disparity in experience. It is not uncommon for the same pipeline to have a section, installed by one crew, to have no issues while another section, installed by a different crew, experiences widespread and system failures of girthweld coatings. Under certain application errors, these sleeves are additionally susceptible to disbondment and subsequent shielding of CP currents, making their presence even more problematic to those owners with the more poorly applied sleeves. Certain field-applied tape coatings used on girth welds have similar experiences and problems.

The quality of the coating application process can be judged in terms of attention to pre-cleaning, coating thickness as applied, the application environment (control of temperature, humidity, dust, etc.), and the curing or setting process. See PRMM.

Coating condition

Ideally, sufficient inspection information will exist to inform estimates of coating effectiveness along a buried pipeline. Where coating inspections and repairs are performed but data for a subject segment is not available, the practice of the past and future inspection can be evaluated for thoroughness and timeliness. Distinctions may be necessary for various types of coating defects, eg, disbondments may not be detectable by certain inspection methods. Documentation should also be an integral part of the best possible inspection program—absence of complete documentation leading to reduced confidence in inspection effectiveness.

From any level of examination or testing, the current coating properties can be compared against design or intended properties to assess the degradation or other inconsistency with design intent.

Inspection results should lead to assignments of increased or decreased defect rates with consideration of the time periods in between inspections. A PXX defect rate—new holidays emerging per length of pipe per year—should be applied to the time periods between inspections. The inspection, once conducted, serves to re-set the clock—overriding the previously estimated defect rate (with consideration for inspection capabilities, including error rates).

When a direct measurement of defect rates is unavailable, estimates based on the above considerations must be made. Coating defect rates can range from 100%, a value used for uncoated surfaces, to only one in tens of thousands of square feet of surface area. One study [1051] estimated 7.38 coating defect sites per linear km for a 30 yr old pipe based on UK data. This study also estimated the proportion of coating defect sites with active corrosion = 1%, thereby giving insight into estimating a CP gap rate, discussed in the following section.

• 1. Migrating from Qualitative Descriptors:

In the absence of good coating defect rate information for a particular pipeline, a rate can be inferred by ‘recycling’ some previously collected coating information. Utilizing previously assigned, qualitative descriptions of coating condition, perhaps from an older risk assessment, can be useful.

A simple thought-exercise can provide plausible coating defect rates from the descriptors. A scale based on these qualitative descriptors can be generated as illustrated below:

Sample Linkage of Coating Descriptors to Coating Defect Rates

Coating Evaluation	Assumed %Effective	Resulting Defect Rate	Estimated Defect Rate
excellent	0.9999999	1E-07	5.0E-07
good	0.99999	1E-05	2.5E-06
fair	0.99	0.01	3.2E-04
poor	0.9	0.1	4.0E-02

Per square foot of coated surface

This links the qualitative descriptor—perhaps carried over from a previous risk assessment—to a defect rate implied by that descriptor. This is obviously a very coarse assessment and should be replaced by better knowledge of the specific pipeline being evaluated.

To better visualize the implications of this simple relationship, and perhaps to help SME’s derive such a relationship, consider the following ‘defect rate estimates’ for a sample pipe diameter of 12″. For various lengths of the 12″ pipe, the probability of a coating defect is estimated. This can then be used to help validate and tune the coating assessment protocols since records and/or SME’s can often relate actual experiences with a particular coating to such defect rates.

Visualizing Coating Defect Rates

Coating Evaluation	Defect Rate per sq ft per year	Probability of Defect in Segment, per year
		L = 1 ft	L = 10 ft	L = 100 ft	L = 1000 ft	L = 5280 ft
excellent	5.0E-07	0.00%	0.00%	0.02%	0.16%	0.83%
good	2.5E-06	0.00%	0.02%	0.18%	1.75%	8.91%
fair	3.2E-04	2.46%	22.1%	91.8%	100%	100%
poor	4.0E-02	11.8%	71.4%	100%	100%	100%
absent	1.0E+07	100%	100%	100%	100%	100%

In the above table, a mile of “excellent” coating has about a 15% chance of having at least one defect. A ‘fair’ coating under this system is almost certain to have at least one defect every 1000 ft. These results might seem reasonable for a specific pipeline’s coating. The probability of a coating defect is assumed to be proportional to both the quality of coating and the length of the segment (length as a surrogate for surface area of the segment). If the results are not consistent with expert judgment—perhaps ratings for “fair” are too severe, for instance, for the intended level of conservatism—then the modeler can simply modify the equation that relates the coating descriptor to defect rate.

Of course, this model is using many assumptions that might not be reasonable for many pipelines. In addition to the highly arguable initial assumptions, many complications of reality are ignored. For instance coatings fail in many different ways, so the meaning of coating “failure” (shielding vs increased conductance vs. holiday, etc) should be clarified.

Nonetheless, these estimates capture a perceived relationship between coating quality and surface area in estimating probability of coating damage or defect. Note that in this application, the probability of a defect diminishes rapidly with diminishing segment length. As segments are combined to show PoF along longer stretches of the pipeline, the small defect counts must be preserved (and not rounded). The modeler should be cautious that, through length-reduction and rounding, the probabilities are not accidentally masked.

• 1. Estimating coating condition

For a pipeline system being assessed, installation records indicate that a high-quality paint was applied per detailed specifications to all aboveground components. The operator sends a trained inspector to all aboveground sites once each quarter, and corrects all reported deficiencies at least twice per year. Pending field inspection and additional SME input, the evaluator makes a preliminary, experience-based estimate of one coating defect every 10 square feet of pipe at hot spots such as supports and air/ground interfaces; and an estimated defect rate of 0.001 per square foot elsewhere.

In a subsequent examination, a different pipeline system contains multiple locations of aboveground components at metering stations and other surface facilities. Minor coating repair—touch-up painting—is done occasionally at these locations at the request of the local operating personnel. No formal painting or inspection specifications exist. The regional field personnel request paint work whenever it is deemed necessary, based solely on personal, but experienced, opinion.

The evaluator feels that the utilized paint system is appropriate for the conditions. Application is suspect because no specifications exist and the painting contractor’s workforce is subject to regular turnovers. Inspection is providing some assurance because the foremen do make specific inspections for evidence of atmospheric corrosion and are trained in spotting this evidence. Defect remediation is suspect because defect reporting and correction is not consistent.

Given the higher uncertainty and the desire to produce conservative estimates (P90), the risk evaluator assigns coating defect rates ten times higher on this pipeline than those used in the previous example. The evaluator also assigns an even higher coating defect rate to segments inside buried casings. This recognizes a known hot spot where coating damages are common and corrosion exposure is also often higher (due to alternating wet/dry conditions).

These values will next be used to estimate the number of active corrosion points which will be paired with corrosion rate estimates for each location, leading to a preliminary quantification of external corrosion failure potential for the above ground portions.

Cathodic protection

As previously noted, CP is one of the two commonly used defenses against metallic corrosion; the other is coatings. Cathodic protection employs an electric current to offset the electromotive force of corrosion. A current is applied to the metallic component and electrochemical reactions take place at the anode and cathode.

As a modeling convenience, CP effectiveness can be assessed as an all-or-nothing mitigation measure. Its role is technically to slow down a corrosion process but, in practical application, meeting a CP criteria is believed to effectively halt any corrosion. The science suggests that every 100 mV shift from native potential results in an order of magnitude less corrosion rate. Attempts to only reduce rather than halt corrosion by CP are not found.

The CP demand is related to the characteristics of the electrolyte, anode, and cathode. Older, poorly coated, buried steel facilities will have quite different CP current requirements than will newer, well-coated steel lines. Old and new sections must often be well isolated (electrically) from each other to allow cathodic protection to be effective. Given the isolation of buried piping and vessels, a system of strategically placed anodes may sometimes be more efficient than a rectifier impressed current system at pipeline stations. It is common to experience electrical interferences among buried station facilities where electrical short circuiting, shorting (unwanted electrical connectivity) of protective current occurs with other metals and may lead to accelerated corrosion.

Distribution systems and buried piping at larger facilities are often divided into zones to optimize cathodic protection. Given the isolation of sections, the grid layout, and the often smaller diameters of distribution piping, a system of distributed anodes—strategically placed anodes—is sometimes more efficient than a rectifier impressed current system.

Offshore pipelines and structures also employ CP. Because of the strong electrolytic characteristics of water, especially seawater, adequate cathodic protection is often achieved by the direct attachment of anodes (sometimes called bracelet anodes) at regular spacing along the length of the pipeline. Impressed current, via current rectifiers, is sometimes used to supplement the natural electromotive forces. The design life of the anodes is always important since the anodes deteriorate over time.

See PRMM for more background discussion.

CP system effectiveness

A CP test lead is an accessible connection to a buried pipe component, usually a wire attached to the component and brought above ground. The test lead provides an opportunity to measure the pipe-to-soil voltage to determine the effectiveness of the CP application. Although major cathodic protection problems can be caught during normal readings of widely-spaced test leads, localized problems are harder to detect and can be significant.

The use of test lead readings to gauge cathodic protection effectiveness has some significant limitations since they are, in effect, only spot samples of the CP levels. Nonetheless, monitoring at test leads is the most commonly used method for inspecting adequacy of CP on pipelines. The role of the test leads as an indicator of CP effectiveness should be based on an estimation of how much piping is being monitored by test lead readings. We can assume that each test lead provides a measure of the pipe-to-soil potential for some distance along the pipe on either side of the test lead. As the distance from the test lead increases, uncertainty as to the actual pipe-to-soil potential increases. Uncertainty increases with increasing distance because the test lead reading represents the pipe-to-soil potential in only a localized area. Because galvanic corrosion can be a localized phenomenon, the test leads provide only limited information regarding CP levels distant from the test leads. How quickly the uncertainty increases with distance from the test lead depends on factors such as soil conditions (electrolyte), coating condition (CP demand), and the presence of other buried metals (interference sources). According to one rule of thumb, the test lead reading provides good information for a lateral distance along the pipe that is roughly equal to only the depth of cover,

As a risk assessment modeling approach, a linear scale in length of pipe between test leads for transmission pipelines while a percentage of pipe monitored might be more appropriate for a distribution piping grid. For preliminary and less detailed risk assessments, an effective zone of ‘influence’ for information obtained at the test lead may be more useful in understanding risk.

Offshore, the effectiveness of the cathodic protection can also be assessed by pipe-to-soil voltage readings although these systems normally provide few opportunities to install and later access useful test leads. When pipe-to-electrolyte readings are taken by divers or other means at locations along the pipeline, this can be treated in the risk assessment as a type of survey—either test lead or CIS, depending on the spacing of readings.

Closely-spaced pipe-to-soil voltage reading surveys (CIS) provide more definitive indications of CP effectiveness, as detailed in PRMM. These surveys are performed in a variety of ways, both onshore and off.

One obstacle to obtaining a complete overline survey is the presence of pavement over the pipeline often limiting the access to the electrolyte. More permeability and other characteristics impact the loss of data, with older asphaltic pavements sometimes having minimal impact and newer concrete pavements making readings impossible. Inaccessible locations caused by encroachments, landowner issues, and others, also create gaps in a survey.

Varying amounts of post-survey analyses are applied following a CIS. Some companies simply react only to instant off readings less negative than -0.85V. Others use NACE criteria to identify numerous types of anomalies based on severity of dips (trending) in continuous readings and combinations of trending behaviors of the ON and OFF readings. Further analyses opportunities include gaining insights into coating performance and possible deterioration rates.

CP effectiveness

CP effectiveness is the complement of CP gap rate, ie, CP gap rate = (1 – CP effectiveness).

Removing age and criteria considerations for a moment, let us focus on the distance-from-reading aspect of estimating CP effectiveness. According to the above beliefs, the evaluator has options for interpolating between readings from the annual test lead survey.

The relationship between confidence and probability of detection can be formalized. Mathematical checks can also be employed to ensure that gap rates are capped to realistic values, even when confidence is extremely low. By dividing the gap rate by the confidence, the final gap rate increases with decreasing confidence—0.01 gaps/ft² with 50% confidence yields 0.02 gaps/ft²; with 10% confidence, 0.1 gaps/ft²; and so forth. Then, the risk assessor can assign to all locations, a gap emergence rate (x gaps/ft² per year) to account for new interference sources, shielding effects, coating deterioration, and other causes of diminished CP. By one strategy, pipeline segments within 10 ft of a test lead, receiving annual confirmations of acceptable CP levels, will show essentially complete CP effectiveness—100% effective mitigation. As distance from test leads increases and/or time between readings increases, CP gaps are modeled to emerge.

Monitoring Frequency

The role of age in CP surveys is the same as for other types of inspections. The time between inspections and the rate of emergence of anomalies during this interval combine to show the benefits of any inspection timing protocol.

Continuous CP monitoring via existing SCADA systems is becoming more common. Report-by-exception systems are used, monitoring pipe-to-soil voltages and even differences from native potentials when buried coupons, not under the CP circuit influence, are included. The cost/benefit analysis of continuous monitoring is dependent upon the damages that could result from CP outage periods. When more frequent and longer duration outages in more corrosive environments are being avoided by improved monitoring, benefits increase and costs are justified. See also a relevant discussion under Sabotage threat assessment.

Interference and Shielding

CP effectiveness can be reduced when interferences change aspects of the intended protective galvanic cell. Changes to anode, cathode, or electrolytic pathways can all cause interference. Common interferences situations arise where electrical shorting occurs with other metals or shielding essentially blocks protective currents from reaching the surface to be protected. Extreme interferences may create anodic regions on the metal intended to be protected. This accelerates corrosion rates and should be considered in the exposure estimates.

Two types of mitigation interference are appropriately evaluated in a pipeline risk assessment: DC-related and shielding effects. AC effects, and especially attempts to mitigate them (unintentionally blocking some protective DC while controlling AC), can impact CP systems but are more recognized as adding to corrosion potential rather than reducing mitigation. Where there is believed to be a stronger influence on mitigation, AC effects should certainly appear in both places in the risk assessment.

In assessing the interference potential, the assessment should consider the isolation techniques used in separating protected surfaces from other CP systems, sources of electrical power, and metals, including nearby pipelines, casings, foundations, junkyards, offshore platforms, shore structures, and many others. When isolation is not provided, joint cathodic protection of the structure and the protected metal should be in place.

Because distribution systems are often co-located in areas congested with other buried utilities, often with their own CP systems, special operator methods by which interference could be detected and prevented may be employed. Examples include strict construction control, strong programs to document locations of all buried utilities, close interval surveys, extensive use of test leads and interference bonds, and increased inspections.

In a more robust risk assessment on a buried pipeline, the presence of a nearby buried feature—metallic or potential source of shielding—causes a new dynamic segment. Each occurrence of a casing, foreign pipeline or utility crossing, electric railroad crossing, buried metal debris, concrete structure, and others would be an independent pipeline segment for purposes of risk assessment. Such segments would carry the risk of interference (including shielding effects) whereas neighboring segments might not. For transmission pipelines in corridors with foreign pipelines, higher threat levels of interference may exist, although it is common for pipeline owners in shared corridors to cooperate, perhaps bonding their systems together, and thereby reduce interference potentials.

The two potential mitigation interference phenomena, shielding and DC-related interference are discussed in PRMM.

Combined Mitigation Effectiveness

When a coating holiday or a CP coverage anomaly is located, that location may be treated as having reduced mitigation or at least reduced reliability of mitigation. When both coating and CP gaps coincide, an active corrosion location is assumed.

In the absence of location-specific coating and CP gap information, general gap rates for each are used to determine the probability of coincident gaps. SME’s can normally produce credible gap rate estimates for lengths of pipeline or areas of facilities. Based on older surveys, experience with excavations on the assessed system and similar systems, they can estimate how often they would expect a coating defect or an area unprotected by CP. This is of course not as reliable as an overline survey or ILI-based information, but is sometimes all that is available to an assessment.

With coating holiday rates and CP coverage gap rates, an estimate of the number of active corrosion points can be made. This is illustrated in the following example:

Example

The risk assessor has conducted a facilitated SME meeting and has obtained, for the preliminary P90 risk assessment of 20 miles of pipeline, estimates of coating and CP gap rates. He has chosen units of ‘per mile’ to help SME’s produce their estimates (he can later convert to per ft2, a more appropriate unit to account for varying pipe diameters and associated surface areas). Results are SME estimates of 30 coating holidays per mile and 2 CP gaps per mile.

Since he seeks a probability of coincident gap in a very small area, he chooses one linear foot of pipeline as representative of the size of each hypothetical gap, converts the SME estimates to a ‘per foot’ unit, and multiplies them together to arrive at a frequency of coincident gap locations:

30/5280 gaps/ft x 2/5280 gaps/ft x 5280 ft/mile
= 0.011 coincident gaps/mile

For the 20 miles being assessed, he finds a small chance of active corrosion locations, expressed as a frequency of occurrence of:

20 miles x 0.011gaps/mile = 0.22 gaps in the assessed segment, or
22% probability of an active corrosion location somewhere in this 20 mile length of pipeline.

This approach reflects the reality of the complex corrosion control choices commonly encountered in pipeline operations. It is not uncommon for the corrosion specialist to have results of various types of surveys of varying ages and be faced with the challenge of assimilating all of this data into a format that can support decision making. Mirroring the SME’s valuations provides the additional benefits of showing the value of some techniques over others as well as the value in increased survey frequencies. Additional adjustments for survey accuracy (including conditions under which the survey took place), operator errors, and equipment errors are also relevant. Such adjustments should play a role in assessments (even though they are not illustrated here) because they are important considerations in evaluating actual CP effectiveness. The assessment scheme is patterned after the decision process of the corrosion control engineer, but is of course considering only some of the factors that may be important in any specific situation.

External Corrosion Resistance

As noted, the resistance to failure by corrosion is efficiently measured as an effective wall thickness. This thickness, taken with the mitigated corrosion rate, yields a time to failure, or remaining life estimate. In the case of external corrosion and pressure containment, hoop stress carrying capacity is affected since, it is the extreme fibers of the vessel (pipe or component) that are being degraded. This has the effect, at least theoretically, of causing more loss of strength than an equivalent amount of interior wall loss.

See .

Internal Corrosion

Background

An assessment of the potential damage by internal corrosion is appropriate for most risk assessments. Internal corrosion results in pipe wall loss and is caused by a reaction between the inside pipe wall and the interior environment, ie, usually the product being transported and the influences of its flow regime. As with most analyses presented in this book, the focus is on steel components but the principles apply to all pipe materials. The assessment of the threat from internal corrosion is conducted by an examination of the product stream characteristics and the preventive measures being taken to offset corrosion potential. Presentation of the chemistry underlying internal corrosion mechanisms is beyond the scope of this text.

Corrosive activity may not be the result of the product intended to be transported, but rather a result of impurities in the product stream. Water and solids intrusion into a natural gas stream, for example, is not uncommon. As with other hydrocarbons, the natural gas (methane) will not harm steel, but water and other impurities can certainly promote corrosion.

The electrochemical process that causes steel to corrode from products transported involves anodic and cathodic reactions just as in external corrosion. Substances that commonly contribute to corrosion in pipelines are dissolved acid gases such as carbon dioxide (CO₂) and hydrogen sulfide (H₂S) as well as organic acids. For the electrochemical reactions to occur, an ionizing solvent must be present, which in the pipeline environment is usually water. Salts, acids, and bases dissolved in the water create the necessary electrolyte. Influencing factors can be very complex. For example, CO2 exacerbated corrosion of carbon steel varies with changes in velocity, pH, temperature, and shows significant changes to various combinations of these factors.

Internal corrosion commonly causes damage to the bottom portions of the pipe. In theory, a pipeline carrying hydrocarbons and a small amount of water will not experience internal corrosion if the water is dispersed and suspended in the product stream rather than flowing as a separate phase in contact with the bottom of the pipe.

Depending on the definition of ‘failure’ used in the risk assessment, reactions occurring inside pipe components that do not threaten integrity of those components may be excluded. An example of this is the buildup of wax or paraffin in some oil lines. While such buildups cause operational problems, they do not normally contribute to the corrosion threat unless they support or aggravate a mechanism that would otherwise not be present or as severe. See also the discussion under .

Some of the same measures used to prevent internal corrosion, are used not only to protect the pipe, but also to protect the product from impurities that may be produced by corrosion. Jet fuels and high-purity chemicals are examples of pipeline products that are often carefully protected from such contaminants.

Certain facilities can be exposed to corrosive materials in higher concentrations and for longer durations. Sections of station piping, equipment, and vessels can be isolated as “dead legs” for hours, weeks, or even years. The lack of product flow through these isolated sections can allow internal corrosion cells to remain active allowing accumulations of corrosion damages over time. Also, certain product additive and waste collection systems can also concentrate corrosion promoting compounds in station systems designed to transport products within line pipe specifications.

Exposure

To more efficiently model the various types of internal corrosion, it can be categorized into general classes, depending on the exposure scenario. One categorization uses two scenarios, corrosion under normal versus abnormal (or ‘special’) conditions. In the first, the transportation of a product always corrosive to the pipe (or other component) wall, is examined. In the second are scenarios where the product is corrosive to the pipe wall only under abnormal conditions. The distinction between the two becomes blurred in some scenarios, but is still a useful way to ensure both classes are addressed in an assessment.

The corrosivity of the pipeline contents that are routinely in immediate contact with the pipe wall are first assessed. The greatest threat exists in systems where the product is inherently incompatible with the component material and is also in continuous contact. This can be termed ‘general’ since it is the corrosivity that is most obvious and potentially occurs over the majority of the pipeline.

Another threat arises when corrosive impurities can get into the product stream (ie, an ‘upset’ scenario) or become concentrated/combined to create a more corrosive condition. This can be called a ‘special’ corrosion rate since it is abnormal, occurring infrequently over time and/or in only very few locations along the pipeline. These two scenarios can be assessed separately and then combined for an assessment of product corrosivity:

Corrosion Rate = [general product stream corrosivity] +
[corrosivity under special conditions]

These are additive since the worst case scenario would be a scenario where both are active in the same pipeline at the same location—both a corrosive product and potential for additional corrosion through special conditions. The balance between the two is situation specific, but because hydrocarbons are inherently non-corrosive to most pipe materials and most transportation of hydrocarbons strives for very low product contaminant levels, special corrosion rates might dominate for many hydrocarbon transport scenarios. In water transport, by contrast, general corrosion would be expected to dominate.

To begin, we assess the general corrosion potential from normal contact between flowing product and the component wall, based on product specifications and/or product analyses. Next, the potential for abnormal contacts between component wall and contents is assessed. Higher concentrations and contact durations of dropout contaminants such as water and solids accumulations in low spots can occur during no-flow, low-flow, or steep inclination conditions. Scenarios of offspec product receipts are included as special corrosivity. In either case, the term contaminant is used here to mean some transported substance that is beyond the agreed upon product purity specification limits and is corrosive to the pipe wall, even though the specification may allow some amounts of the substance.

Each of the two general scenarios of internal corrosion are assigned an unmitigated corrosion rate—the exposure—normally in units of mpy or mm/year, and a probability that such a corrosion rate manifests at the location being evaluated. This parallels the approach used to evaluate external corrosion. The locations of coincident loss of protective coating and CP, thereby allowing external corrosion, is analogous to the locations of sufficient contact time between corrosive substances and internal pipe wall that allow internal corrosion.

In many cases, assigning a mpy (or mm per year) exposure value will be a very generalized approximation. Rarely will an actual or even potential corrosion rate at a particular location be fully understood. Sometimes actual corrosion rates on similar components in similar conditions will be known. Sometimes, laboratory corrosivity rates in laboratory conditions will be known and may be extrapolated to field conditions. Use of either in estimating potential corrosivity at other locations will be problematic, but may be the only basis for an estimate. Since actual rates will be very site-specific, a plausible range of rates, rather than a single value, may be more useful. From such a range, especially if an underlying probability distribution is also known or can be reasonably theorized, P50 and P90+ values for location-specific corrosion rates can be assigned.

Recall an earlier discussion of the ‘test of time’ as providing some evidence regarding the level of exposure. In the case of internal corrosion potential, however, ‘years in service without findings of corrosion’ may not be very compelling evidence, given the typical ranges of transported fluids and the often-changing operation and maintenance practices that many pipelines experience. See .

General Corrosion (Flow stream characteristics)

It is often economically advantageous to transport substances through a pipe that has some susceptibility to corrosion by the substance. This implicitly accepts the damage potential as manageable and/or the threats to integrity as tolerable.

There can be varying degrees of corrosivity tolerated by a transporter. These are examined in PRMM. Rates of 200 mpy or more have been seen in actual operating hydrocarbon pipelines and are clearly intolerable for most operations. Unmitigated corrosion potential approaching 10 mpy or more would be considered aggressive by most pipeline operators. Rates of 0.1 to 2 mpy are often treated as mildly corrosive and sometimes even as inconsequential. Note however, that over many years, even mild corrosion can threaten integrity.

Transportation of products by pipeline is normally governed by contracts that state delivery specifications. Most specifications will state the acceptable limits of product composition as well as the acceptable delivery parameters. When formal contracts do not exist, there is usually an implied contract that the delivery will fit the customer’s need and be compatible with the transportation process. See additional discussion of specifications under .

The product specification can be violated when the composition of the product changes. This will be termed off-spec and will cover all episodes where the product deviates sufficiently from the intended specification to cause corrosion.

Most transmission pipelines require, via transportation specifications, that transported products are non-corrosive to the pipeline materials. Distribution systems, as receivers of transmission-quality product, similarly expect only non-corrosive products. Gathering systems generally do not carry such specifications and some amounts of corrosive products are expected. Regardless of the existence of a specification, episodes that create corrosion potential are possible in all types of pipeline systems and commonplace in some.

While very specific corrosion chemical processes can be modeled, it is often within the realm of desired accuracy to simplify corrosivity estimates. In one such simplification, the flow stream characteristics can be efficiently divided into two main categories—water related and solids related—for purposes of evaluating corrosivity [94].

Internal corrosion is also a common threat in hydrocarbon gathering pipelines where mixtures, including water and solids, and multiphase fluids are transported. Microorganism activities that can promote internal corrosion should also be considered. Sulfate-reducing bacteria and anaerobic acid-producing bacteria are sometimes found in oil and gas pipelines. They produce H₂S and acetic acid, respectively, both of which can promote corrosion [79].

Water is a pipelined product that presents special challenges in regard to internal corrosion prevention. Metallic water pipes often have internal linings (cement mortar lining is common) to protect them from the corrosive nature of the transported water. Raw or partially treated water systems for delivery to agricultural and/or landscaping applications are becoming more common. Water corrosivity might change depending on the treatment process and the quality of the transported water.

Special Corrosion (Upset potential and/or Abnormal Situations)

This is a measure of the potential for an increase in corrosion activity due to abnormal situations like contamination of the transported product or flow pattern changes. For instance, low flow rates can increase the chance of solid or liquid deposition and accumulation, while higher flow rates can cause erosion. Anything that leads to increased corrosive contaminant contact with pipe walls will logically increase corrosion potential and rate. Relevant phenomena can be rare and hard to assess. For instance, drag-reducing agents that are sometimes added by pipeline operators to enhance throughput can lower the ability of flowing hydrocarbon to entrain water by dampening turbulence. On the other hand, a return to higher flow rates can remove accumulations and could therefore be seen as preventative as described later.

• 1. Liquid and solids holdup when critical angle exceeded

Under an assumption that a pipeline is designed to receive products and sustain a flow regime that minimize corrosion, accumulations of corrosive fluids and solids are considered to be abnormal conditions and hence modeled as part of the ‘special corrosion’ rates. Changes in flow patterns including stagnant flow conditions that lead to increased corrosion potential can usually be considered to be special conditions for most portions of most pipelines under the assumption that such scenarios are rare. If this assumption is not valid—ie, accumulations, higher contact time with pipe wall, etc are normal, then corrosion-accelerating flow patterns can form the basis of the ‘general’ corrosion rate. This involves treating accumulations of allowed-by-specification constituents as part of the ‘general corrosion’ rate, perhaps to better distinguish from accidental introductions of contaminants (constituents not allowed by specification).

A critical inclination angle calculation can be used to supplement and support exposure estimates at specific locations. This can be extended into applications of flow modeling that predict corrosive locations along a pipeline based on fluid stream, flow regime, elevation profile, pressures, temperatures, and other factors, continues to improve. Sophisticated models with high quality input data can more reliably predict depositions, accumulations, and subsequent special corrosion rates, in addition to corrosion potential from ‘normal’ contact of product stream with pipe wall.

When such modeling includes the effects of inhibitors, biocides, and perhaps other mitigation measures, the predictions generated should be treated as mitigated corrosion rates in the risk assessment. Therefore, provisions for failure of a mitigation measure should be considered.

The overall assessment of upset potential or abnormal conditions, as contributing factors to special internal corrosion potential, can be accomplished through an evaluation of the product stream and the items listed in PRMM.

Recall that estimates of exposure assume no mitigation. When mitigation is defined as only measures taken by the pipeline owner, then mitigation taken by others becomes part of the exposure evaluation. So, the likelihood of an error in a supplier’s delivery system, leading to a contamination episode, is a part of the exposure estimate. Alternatively, a full exposure-mitigation analyses could be conducted on the product delivery system into the pipeline with the results feeding into the pipeline’s product corrosivity exposure estimates.

When foreign material enters the pipe from external sources (not product stream sources), product contamination and internal corrosion are possible. With the lower pressures normally seen in distribution systems, infiltration can be a problem. Infiltration occurs when an outside material migrates into the pipeline. Most commonly, water is the substance that enters the pipe. While more common in gravity-flow water and sewer lines, a high water table can cause enough pressure to force water into even pressurized pipelines including portions of gas distribution systems. Conduit pipe for fiber optic cable or other electronic transmission cables is also susceptible to infiltration and subsequent threats to system integrity.

Special corrosion rates can be extremely aggressive. An operator installed a new hydrocarbon gathering system (oil and condensates) which, after only a few years in service, experienced internal corrosion leaks. Upon investigation, corrosion rates in excess of 200 mpy were discovered—far exceeding what was thought plausible in such systems. MIC was identified as a prime contributor. MIC rates up to about 10 mm/year (about 400 mpy) have been shown to be possible under laboratory conditions. Special pitting corrosion rates that do not involve MIC can also be very high.

Probability of Corrosion Rates

The most robust internal corrosion assessments will use surface areas in the probability estimates. Analogous to the assessment of external corrosion potential, this approach allows the assessment to highlight specific locations where internal corrosion is more likely, for example, at bottom of pipe at low spots with lower velocities and greater likelihood of contaminants having been introduced.

Recall the discussion of measurements and inferences as a means to model the disparity of information commonly seen along a typical pipeline. In some locations, direct measurements of corrosion rates will be available. In other locations, only relatively weak inferential evidence will be available and must be used to create an estimate of corrosion rate.

Monitoring is a key aspect of estimating the exposure, recognizing that many monitoring activities will be measuring a mitigated corrosion rate. Monitoring can be either direct or indirect. In either case, extrapolation from the monitored locations to all unmonitored locations will be required.

Monitoring and measurements that can be useful in the assessment include the use of probes and coupons, scale analysis (product sampling), inhibitor residual measurements, dewpoint control results, monitoring of critical points by ultrasonic wall thickness measurements, and effluent examinations from pigging programs.

It is not uncommon for pipelines to experience changes in service conditions over their lifetimes. In the oil and gas industry, product streams and excursion potentials change as new wells are tied in to existing pipelines and the stream experiences changes in composition, pressure, or temperature. While an internal corrosive environment might have been stabilized under one set of flowing conditions, changes in those conditions may promote or aggravate corrosion. Liquids settle as transport velocity decreases. Cooling effects might cause condensation of entrained liquids, further adding to the amount of free, corrosive liquids. Liquids may now gravity flow to the low points of the line, causing corrosion cells in low-lying collection points. Reduced velocities and increased depositions may prevent sweeping of accumulated solids and liquids.

Inspection for Corrosion Damages

Repeated wall thickness measurements at the same location, usually by ILI or NDE, offer a means of direct corrosion monitoring. The high inaccuracies associated with locating and sizing the often tiny, pin-hole type corrosion features means that uncertainty should be a part of the findings.

An alternate method is to use a spool (test) piece of pipe that can be removed and directly inspected for corrosion damage.

Any inspection program must consider inaccuracies and limitations of extrapolations of results and be repeated at appropriate intervals.

Caution must be exercised when assigning benign corrosion rates based solely on the non-detection of internal corrosion at certain times and at limited locations. It is important to capture where the potential for corrosion might be high, even when no active corrosion has yet been detected.

Indirect Corrosion Monitoring

Spot monitoring of internal corrosion is often done by either an instrumented probe or by insertion and subsequent inspection of a coupon designed to corrode when exposed to the transported product. Both methods require an attachment to the pipeline to allow the probe or coupon to be inserted into and extracted from the flowing product. More advanced configurations of probes or coupons, such as provisions for accumulations and simulations of stagnant pitting potential, add more credibility to any extrapolations from location-specific monitoring.

Monitoring of product streams also presents opportunities to infer corrosion potential. Product stream composition measurements range from simple moisture analyzers to full chromatograph analyses and from monthly composite sample ‘bombs’ or occasional ‘grab samples’ to nearly continuous analyses.

Monitoring of the materials displaced from a steel pipeline during maintenance pigging may include a search for corrosion products such as iron oxide—mentioned as a ‘direct’ monitoring method—or fluids and solids that are corrosive. Since contact time with the pipe wall is an important aspect of corrosion rate, the presence of corrosive materials alone is not the full picture. Nonetheless, examination of pigging effluent will help to assess both the corrosion potential and the extent of damage in the line. Examinations of filters and traps for corrosion by-products like iron oxide yields similar useful information, both direct and indirect.

Extrapolations

A probability estimate will normally be required to incorporate a potential corrosion rate into the risk assessment. The probability of a certain corrosion rate at a specific location on the pipeline arises from an understanding of all the elements previously discussed—corrosion mechanisms, product stream characteristics, and results from inspection and monitoring. Since much of this information will not be precisely known at all points along the pipeline, extrapolations from where it is known will be necessary. Furthermore, since conditions often change over time, both time- and location-uncertainties arise. Therefore, uncertainty over time (ranges of possible corrosion rates at the same location over time) and space (distance from locations of known or better-estimated corrosion rates) are both included in the probability values.

A probability or confidence level assigned to corrosion rate estimates captures the amount of uncertainty of the extrapolations as well as the uncertainty in the measurements of corrosion rates at the known locations.

Pipeline XYZ relies upon ACME Production Company to deliver a hydrocarbon stream substantially free of any corrosive component. Historical performance data from product stream analyzers and an examination of ACME’s potential error rates associated with processes related to product delivery lead to estimates of general product stream corrosivity and possible contaminate drop out potentials at the delivery point and locations farther downstream. Then, flow patterns are studied to estimate contaminant accumulation potentials at the location being assessed. Combining both leads to estimates of 0.1 mpy 90% of the time and 10 mpy 10% of the time, at the location of interest. Pipeline XYZ estimates product corrosivity to be 0.1 x 0.9 + 10 x 0.1 = 1.1 mpy as a probability-weighted (also potentially viewed as a time-weighted corrosion rate) summation of corrosion rates at this location. An alternative approach would be to use 0.1mpy for P50 and 10 mpy for P90 estimates of internal corrosion exposure at this location. The internal corrosion mitigation practices would then be used with these estimates to arrive at the potential damage rate estimates.

Mitigation

Having assessed the potential for a corrosive product stream, the evaluator can now examine and evaluate mitigation measures being employed against potential internal corrosion. The probable effectiveness of mitigation measures is used with the exposure estimates to assess damage potential, modeled as a reduction in unmitigated damage rate. Estimating mitigation effectiveness will be challenging in many cases. The goal is to understand, for each unit of surface area (square inch of internal surface area), the ability of the mitigation measure to at least partially block corrosion that would otherwise occur.

With both exposure and mitigation varying along the pipeline, the probability of worst-case corrosion is directly related to the probability of mitigation gaps coinciding with the higher corrosion rates. Gaps in mitigation effectiveness at contamination accumulation points are more threatening than gaps occurring elsewhere.

Typical internal corrosion mitigation measures include:

• Internal coatings,
• Inhibitor injection,
• Regular cleaning,
• Operational measures such as flowrate modifications to sweep of liquid/solid accumulations, and
• Product treatments.

Monitoring via coupon or other probe is a common supporting activity although it is not a direct mitigation itself.

Although there are real-world dependencies among these measures (for example, inhibitors may not be effective without mechanical removals of buildups by pigging), they can generally be modeled as independent measures and can be related using OR gate math.

Pigging

It is common practice in many pipelines to use pigs to prevent long-term accumulations of liquids and solids and clean internal surfaces of a pipeline. Types of pigs, frequency of cleaning, and characteristics of the cleaning ‘run’ are all important to the program effectiveness (see background discussions in PRMM). Components such as sharp bends may reduce the cleaning effectiveness and, when coupled with a relative low spot—ie, critical angle exceeded—then this location may become a hot spot for internal corrosion.

Monitoring of the materials displaced from the pipeline following a cleaning pig should include a search for corrosion by-products such as iron oxide in steel lines. This will help to assess the extent of corrosion in the line and therefore the effectiveness of the pigging. A reduction in contaminant residence time—contact time with pipe wall—may be the appropriate measure of effectiveness. This will ‘reward’ more frequent and more thorough cleaning operations.

Inhibitor injection

Corrosion-inhibiting chemicals can be injected into the pipeline to prevent or reduce corrosion damage. Inhibitors are applied at intervals or continuously. Inhibition programs can be very expensive. Inhibitor effectiveness is often partially verified by an internal monitoring program as described above.

Formulations may have “oxygen-scavenging” properties that allow them to bond with the oxygen in the fluid and prevent its reacting with the pipe (oxygen being the primary corrosion agent with steel). Other chemical formulations create a film or barrier between the metal and the fluid. Biocides can be added to address micrbiologically-induced corrosion.

In some applications, another benefit of these additives is that they usually contain surface-active compounds that decrease oil and water interfacial tension so as to make it more difficult for water to separate from the oil flow. Conversely, chemical demulsifiers that are added to oil to remove water during processing before delivery to the pipeline can have the undesired effect of increasing the interfacial tension and thus causing easier separation of oil and water in the pipeline flow.

The risk assessment should consider whether the inhibitor injection equipment is well maintained and injects the proper amount of inhibitor at the proper rate.

Generally, it is difficult to completely eliminate corrosion through inhibitor use alone. A pigging program is usually necessary to supplement inhibitor injection. The pigging is designed to mechanically remove free liquids, solids, or bacteria colony protective coverings, which might otherwise interfere with inhibitor or biocide performance. Experience in some company’s internal corrosion programs is that chemical inhibition is virtually ineffective without supplemental mechanical cleaning via pigs.

Even with both inhibition and mechanical cleaning, effectiveness is uncertain. When pitting corrosion is prevalent, mechanical cleaning and inhibitor effectiveness in narrow, deep corrosion features is problematic. Challenges are even more pronounced in multi-phase or multi-velocity flow regimes. Any change in operating conditions must entail careful evaluation of the impact on inhibitor effectiveness.

Recall that accumulation points are typically hot spots for internal corrosion. Therefore, gaps in inhibition effectiveness at contamination accumulation points are more threatening than gaps occurring elsewhere.

Internal coating/liners

Internal coating has not been common practice for many pipelines but is growing in popularity due to advancements in liner materials, the deterioration of valuable pipelines, and their high replacement/repair costs. Internal coating includes the use of liners inserted into existing pipes, spray-on concrete or mortar, plastic, or other material, and the manufacture of multi-material composite pipes. A common concern in such systems is the detection and repair of a leak that may occur in the liner. Such leaks may accelerate corrosion at locations far from the leak location.

If an internal coating system is employed as defense against internal corrosion, its role in mitigation can be assessed in the same way as an external coating system. Its effectiveness can be judged by the same criteria as coatings for protection from atmospheric corrosion and buried metal corrosion described in this chapter. A holiday or defect rate per unit area shows the effectiveness of the coating. The probability of a defect coinciding with a corrosivity event—which is 100% of the surface area for general corrosivity and often <100% of the surface area for special corrosivity—yields the probability of that corrosion rate manifesting. Coating defects at internal corrosion hot spots points are more threatening than defects occurring elsewhere.

Note that an internal coating/liner that is applied for purposes of reduction in flow resistance might be of limited usefulness in corrosion control.

Operational measures

Dehydration, filtering, and other methods are commonly used to address corrosion potential prior to the product contacting the internal pipe wall, especially when the pipe material and product are not incompatible but where concentrations of impurities could lead to corrosion. Temperature, pressure, and flow rate control are other operational measures typically used to reduce corrosion potential, especially where duration of contact between product and material surfaces is a critical determinant of damages. The effectiveness of such measures is dependent upon many factors, including equipment design and maintenance, monitoring, and operator skills and procedures.

• 1. Assessing internal corrosion:

A section of a pipeline carrying natural gas from offshore production wells is being examined. Drying and sulfur-removal treatment takes place offshore. The line has been designed for flow rates that limit contaminant deposition or, if deposition does occur, residence time. Variance to design flow rates is common but unquantified.

Inhibitor is injected to manage corrosion from associated liquids that get past the treatment process. It has been determined that the inhibitor injector had failed for several weeks prior to correcting the malfunction. Pigs are run bi-monthly to clean out any accumulations. Both liquids and solids are removed.

Corrosion rates are monitored continuously via probes. Because the probes are located at the onshore receiving station, it is not possible to use the data to simulate corrosion resulting from deposition.

The highest corrosion rates observed at these coupons is 2.1 mpy but most readings are less than 0.1 mpy.

The evaluator requires a quick initial assessment and quantifies the damage potential as follows:

Exposure: Product corrosivity

The line is exposed to corrosive components only under upset conditions, but upset conditions appear to be rather frequent. The unmitigated general corrosion rate is estimated from experience with similar pipelines, to be 5 mpy, at the P90 level of conservatism. Corrosion probes normally show virtually no corrosion but are not deemed to provide representative corrosion rates at the more critical locations.

A critical angle calculation is performed and locations with inclines exceeding the critical angle are identified. These locations are assigned a P90 special corrosion rate of 10 mpy—additive to the general corrosion rate—due to deposition/accumulation potential. Therefore, some locations along this pipeline are modeled to have 5 + 10 = 15 mpy of corrosion potential prior to mitigation.

Mitigation

Inhibitor injection the inhibitor injection program is designed to limit corrosion to 1 mpy anywhere in the treated segment. Since effectiveness is difficult to achieve at all locations and the risk assessment is to be conservative, 50% effectiveness is the initial SME estimate, based on changes from pre-inhibition observations, ie 2.1 mpy observed in coupon analysis. This also captures the idea that inhibition alone, without prevention of accumulations, is more problematic.

Operational measures SME’s assign a P90 value of 20% effectiveness for operational procedures alone, in acknowledgment that design flow rates should minimize depositions and sweep accumulations, but there do not appear to be devices or procedures to strictly control flowrates. SME’s estimate that relatively low flow conditions manifest about 10% of the year. This value is doubled to arrive at a P90 estimate of 20%.

Pigging 50% effectiveness is assumed as an initial SME estimate based on trial-and-error applications of pig types and pigging frequencies used over several years.

Effectiveness of each of the preventive measures (inhibitor injection, operational measures, and maintenance pigging) is limited because of difficulties in continuously achieving corrosion control with the actions in a real-world production environment.

• 1. Swiss Cheese Analogy: More Slices and/or Fewer Holes Reduces Event Probability

Total, using OR gate math: 1-(1-0.5)(1-0.2)(1-0.5) = 80% initial estimate of combined mitigation effectiveness.

Damage Rates

Based on this initial P90 evaluation, mitigated corrosion rates are estimated to range from 1 to 3 mpy along the pipeline: 5 mpy x (1-80%) = 1 mpy to 15 mpy x (1-80%) = 3 mpy at low spots. These values are next used with best estimates of current wall thicknesses at all locations to obtain estimates of TTF. The extreme damage rate—15 mpy is plausible at low spots if mitigation fails—is also used to help establish the relationship between TTF and PoF by calculating a worst-case damage rate.

Erosion

Erosion, usually as a form of internal corrosion, can also considered a time dependent failure mechanism. Erosion can be thought of as ‘mechanical corrosion’ (recall the roots of the word ‘corrosion’).   Erosion is the removal of a component’s wall material caused by the abrasive or scouring effects of substances moving against the component. It is a form of corrosion in the most general definition of the word. Abrasive particles moving at high velocities and impinging on an internal surface are the normal causes of erosion. Since internal erosion is generally avoided through design and operational measures, the potential for erosion can be treated as a special corrosion rate under internal corrosion. It often warrants an independent evaluation in the overall risk assessment, however.

While commonly associated with internal wall loss due to product stream characteristics, it can also occur on external surfaces. Wind born sand particles can cause significant damages to certain component materials, for example.

Erosion of pipe or component wall thickness is considered in this part of the risk assessment, while erosion of support, such as soil erosion during a flood, is captured under geohazards and resistance.

Interior wall erosion is a real problem in some oil and gas production regimes. Production phenomena such as high velocities, two-phase flows, and the presence of sand and solids create the conditions necessary for damaging erosion.

If occurring in the product stream, impingement points such as elbows and valves are the most susceptible erosion points. Gas at high velocities may be carrying entrained particles of sand or other solid residues and, consequently, can be especially damaging to the pipe components.

Historical evidence of erosion damage is of course a strong indicator of susceptibility. Other evidence includes high product stream velocities (perhaps indicated by large pressure changes in short distances) or abrasive fluids. Combinations of these factors are the strongest evidence. If, for instance, an evaluator is told that sand is sometimes found in filters or damaged valve seats, and that some valves had to be replaced recently with more abrasion-resistant seat materials, he may have sufficient reason to suspect significant exposure to this threat in certain components, especially those with impingement points. Calculations are available to help determine susceptibility when parameters such as velocity, particle size, and liquid contents are known or can be estimated.

A PoF for erosion is generated in the same way as for corrosion and cracking. First, an unmitigated erosion rate is estimated and normally expressed in mpy or mm/year. If mitigation such as liners or injected fluids are used to protect pipe surfaces, their effectiveness is estimated. The mitigated erosion rate is then used with an effective wall thickness (see ) in TTF estimates. The TTF estimates lead to PoF estimates. As with corrosion, a probability aspect is usually needed, especially when a gap in mitigation—such as a hole in a liner—must coincide with an impingement point before damage occurs.

Cracking

Cracking as a failure mechanism has not been a dominant source of accidents for most pipeline systems. However, for susceptible systems, failure modes can be dramatic and have resulted in serious incidents. Examples include fatigue failures in metallic components and rapid crack growth phenomena in plastics.

For all pipeline materials in common use, cracking can be evaluated in the same fashion as for steel. This is a major benefit for risk assessment.

As with other failure modes, evaluating the potential for cracking follows logical steps, replicating the thought process that a specialist would employ. This involves (1) identifying, at all locations, the types of cracking possible, both on internal, external surfaces; (2) identifying the vulnerability of the pipe material—how probable and how aggressive is the potential cracking; and (3) evaluating the prevention measures used.

As with corrosion potential, quantifying this understanding is done using the same PoF triad that is used to evaluate each failure mechanism: exposure, mitigation, and resistance, each measured independently. This will result in the following measurements, ready to be combined into a TTF estimate from which a PoF estimate can emerge:

• Aggressiveness of unmitigated cracking at any point on the component (units of mpy or mm/yr).
• Effectiveness of mitigation measures; a reduction in crack growth rate that would otherwise occur (units = %).
• Amount of resistance (units = equivalent wall thickness, inches or mm).

For purposes of risk assessment, the potential for cracking can be evaluated in two general categories: fatigue and environmentally assisted cracking (EAC). This categorization is useful since the two, while similar and sometimes overlapping, require slightly different analyses.

Background

Defects and flaws are found in all materials. They may be invisible to the naked eye but, when subjected to sufficient stress, may enlarge to critical dimensions, ie, dimensions that precipitate failure. Predicting the initiation and subsequent rate of growth accurately is usually not possible; cracks may emerge and grow over decades or virtually instantly depending on the circumstances.

Stress concentrators are another common contributing factor in crack related failures. Any discontinuity in a material, such as a sharp edge, slot, gouge, scratch, or dent, can increase the stress level. Fatigue lives of components can be significantly altered by corrosion damages. In corrosion fatigue, the acting stresses sufficient to cause failure can be less severe because pipe strength is diminished as a result of corrosion. For example, corrosion pits can become stress concentrators that allow routine pressure fluctuations to cause the formation and growth of cracks in the pit. When cracking is accelerated by environmental factors such as corrosion, the term Environmentally Assisted Cracking (EAC) is used to describe the phenomena.

Other phenomena influence crack potential by changing material properties. The metallurgy of steels or properties of non-metallic components can change from, for instance, exposure to excessive heat sources such as open flames as well as excessive cold. Changes in non-metallic materials can parallel the discussion of steel components. For instance, UV degradation, when causing brittleness in some plastics, can impact failure potential in ways similar to the HAZ in steel.

Fatigue loads will further the susceptibility to crack-type failures. Crack progression advancing solely through repeated cycles of mechanical effects is called fatigue cracking in this discussion.

In some larger, high-pressure gas pipelines, catastrophic fractures have been observed where the cracks propagate for miles along the pipeline. In these cases crack growth is rapid, exceeding the depressurization wave and potentially causing a violent release over considerable distance.

These kinds of failures increase the size of the product-release point but not necessarily the volume of the release. There is certainly an increased threat from mechanical damage—projectile debris for example. Steel sleeves can be used to arrest the crack growth until the depressurization wave passes, and crack-resistant materials, heavier-walled or duplex pipe are also preventive measures.

Catastrophic or “avalanche” failures are further discussed under ‘exposure.’

Crack initiation, activation, propagation

Some modelers of cracking identify three distinct phases of crack progression through a material: initiation, activation, and propagation (fracture). All three are required before material failure by cracking occurs. This is a useful model for pipeline risk assessment since each of the three can be influenced by different factors whose identification and assessment leads to better understanding of failure potential and failure avoidance.

In this simple model, the crack potential and cracking avoidance can be understood as follows. If initiators—defects, stress concentrators, etc—can be avoided, then concerns for subsequent activation, propagation, and cracking failure are reduced. If initiators are present, then activation may be avoided by control of fatigue and/or stress. Propagation potential is impacted by flaw characteristics and stress, with the latter influenced by component thickness, allowing for the use of crack arrestors to prevent propagation.

Assessment Nuances

More so than most other failure mechanisms, cracking analyses bring shades of gray to the assignment of exposure, mitigation, and resistance. Factors such as material characteristics that influence the rate of cracking through a component wall can logically be classified as either an exposure variable or resistance variable. So, if material degradation or change (for example, creation of a HAZ) causes the material properties to change, is that better modeled as increased crack propagation rate (ie, more exposure)? or rather as reduced effective wall thickness (ie, less resistance)? Either will work—mathematically, there will be no difference in PoF estimates—but the latter may be more intuitive from a modeling perspective.

Additional nuances appear in determining whether risk reduction actions are more appropriately modeled as changes to mitigation (blocking an exposure) versus resistance (absorbing forces), as is detailed in the discussion of mitigation and resistance later in this chapter.

Recall also the example of other modeling choices (reduced exposure or increased resistance?) for the role of an expansion loop or a span in a pipeline.

Fortunately, these nuances do not really interfere with robust risk assessment.  Rather, they are a matter of preference for the designer of the assessment.  The choices made should not impact accuracy of the assessment and the decision process itself will often help to reinforce basic risk modeling concepts in the mind of the designer.

Exposure

Fatigue

Although historical pipeline accident data does not indicate that cracking is a dominant failure mechanism in most pipelines, fatigue failure has been identified as the largest single cause of metallic material failure [47] and is certainly a real threat to some pipeline components. Fatigue is the weakening of a material due to repeated cycles of stress and is dependent on the number and the magnitude of the cycles. (See PRMM)

Fatigue cracking occurs as a result of repetitive, or cyclic, stress loadings on a pipe. Cyclic stresses can be axial (parallel to the axis of pipeline), circumferential (hoop stress in the tangential direction), or radial (perpendicular to the axis). Hoop stress is usually the most important source of cyclic loadings in pipelines because stress created by internal pressure is normally the largest stress the pipe experiences.

Fatigue is characterized by the formation and growth of microscopic cracks on one or both sides of the pipe wall. The first stage in the fatigue process is crack initiation, or nucleation. While nucleated cracks do not cause a fracture, some may coalesce into a dominant crack as the variable amplitude loading continues. In the second stage, the dominant crack grows in a more stable manner, and may eventually reach the thickness of the wall to produce a leak. Alternatively, the dominant crack may exceed a critical length or depth that the pipe steel can no longer endure. In this potential third stage, the crack becomes unstable and rapidly grows to a size that can produce a fracture and rupture.

Because the most highly stressed points are normally on the outer surface of a pressurized component, fatigue cracks usually originate on the exterior of the pipe and progress inwardly.^[2] Pipe segments most vulnerable to fatigue cracking are those with pre-existing flaws or dents and other surface deformities caused by mechanical forces during installation or while in service. Stresses can concentrate at these damage sites, enabling cracks to form and grow after a relatively small number of load cycles, a phenomenon sometimes called low-cycle fatigue.^[3] Other locations on a pipe susceptible to stress concentrations include discontinuities at grain boundaries and voids formed during pipe manufacturing.

Ref [1027] summarizes factors affecting fatigue life of metals as follows:

• • • Magnitude of stress including stress concentrations caused by part geometry.
    • Quality of the surface; surface roughness, scratches, etc. cause stress concentrations or provide crack nucleation sites which can lower fatigue life depending on how the stress is applied.
    • Surface defect geometry and location. The size, shape, and location of surface defects such as scratches, gouges, and dents can have a significant impact on fatigue life.
    • Significantly uneven cooling, leading to a heterogeneous distribution of material properties such as hardness and ductility and, in the case of alloys, structural composition.
    • Size, frequency, and location of internal defects. Casting defects such as gas porosity and shrinkage voids, for example, can significantly impact fatigue life.
    • In metals where strain-rate sensitivity is observed (ferrous metals, copper, titanium, etc.) strain rate also affects fatigue life in low-cycle fatigue situations.
    • For non-isotropic materials, the direction of the applied stress can affect fatigue life.
    • Grain size; for most metals, fine-grained parts exhibit a longer fatigue life than coarse-grained parts.
    • Environmental conditions and exposure time can cause erosion, corrosion, or gas-phase embrittlement, which all affect fatigue life. [1027]

These influences should be taken into account, as much as is practical, in the evaluation of material resistance.

Crack Growth Rate

From a risk assessment modeling point of view, a representative crack growth rate is sought and will be used with an estimate of effective resistance. The counts and magnitudes of stress cycles linked to crack growth rates is a rational way to model exposure, ie crack growth rate. This is admittedly an oversimplification of this complex issue. Fatigue depends on many variables as noted previously. At certain stress levels, even the frequency of cycles—how fast they are occurring—is found to affect the failure point.

It is conservative to assume that any amount of cycling is potentially damaging. Stress magnitudes can be based on a percentage of the tolerable operating stress levels or proportional loadings can be used. (Also see PRMM for discussion on categorizing pairings of cycle magnitude and frequency.)

Less common causes of fatigue on buried components and aboveground connections to equipment include loading cycles from traffic, wind loadings, water impingements, harmonics in piping, rotating equipment, and ground freezing/thawing cycling. Surges, slack line and vapor pocket collapse, and other transients are examples of abnormal initiators of cycles. Modern SCADA systems provide an excellent means of collecting stress cycles (from internal pressure changes) for examination.

A load spectrum is the family of stress-producing cycle counts and magnitudes. An equivalent cycle representing the full spectrum of actual cycles can be determined by a method such as Rainflow counting. S-N curves relate cyclic stress levels (uniaxial stresses, normally) with counts that result in failure, assuming that stresses are well below the material’s elastic limit. This is sometimes referred to as the high-cycle fatigue regime, where counts greater than 10^4 can be absorbed before failure occurs. The S-N curve is also used to determine the damage contribution from each cycle. Cumulative damage theories have been developed to relate the spectrums of cycling to failure time via the S-N curves. The Miner’s Rule (or Palmgren-Minor Rule) collects the damage contributed by each cycle. The Paris Law equations are also used to relate stress intensity factors to fatigue crack growth.

With tens of thousands of cycles typically required for failure in this regime, representative crack growth rates will usually be very small. For instance, even if a relatively small cycle count of 10,000 cycles is required to fail a component of wall thickness of 0.250”, the implied crack rate is 250/10,000 = 0.025 mils per cycle.

Low cycle fatigue occurs when loadings produce stresses beyond the elastic limit and plastic deformation occurs. Pressure testing of components can produce this type of fatigue. Relationships using strain limits have been formulated to predict failure under these high stress loading scenarios. [1028]

A possible source of fatigue stresses is highway and railroad crossings. Research in these scenarios have produced design guides that include considerations for circumferential and longitudinal stresses due to earth loads, traffic loads, and the pipe’s internal pressure. For instance, the following variables used in such calculations provide insight into the most critical determinants of imparted stresses:

SLh	SHh	Stress	Cyclic stress due to the highway
KLh	KHh	Stiffness factor	Dependent on wall thickness to diameter ratio & soil type
GLh	GHh	Geometry factor	Dependent on depth & diameter
R		Pavement type factor
L		Axle configuration factor
Fi		Impact factor	Dependent on depth according to formula 1.75–0.03·(H-5) for depths of 5’ – 30’and equal to 1.75 for depths < 5’
w		Applied surface pressure	83.3 psi for single axle (12 kips / 144 in2)
			69.4 for tandem axle (10 kips / 144 in2)
H	Depth		Depth from top of pavement to crown of pipe
D	Diameter		Nominal outside diameter of the pipe
tw	Wall Thickness		Nominal wall thickness of the pipe

• 1. Estimating fatigue cracking rates:

PRMM presents an example point assignment scheme for evaluating fatigue risk in an older risk assessment approach. Modifying that example to reflect the updated risk assessment approach, the following example of assessing fatigue potential is offered.

The risk assessment has identified two types of cyclic loadings in a specific pipeline section: (1) a pressure cycle of about 200psig caused by the start of a compressor about twice a week and (2) vehicle traffic causing an external loading resulting in a 5-psi longitudinal stress at a frequency of about 100 vehicles per day. The section is approximately 4 years old and has an MOP of 1000psig. The traffic loadings and the compressor cycles have both been occurring since the line was installed.

For the first case, the evaluator uses a frequency of (2 starts/week ∞ 52 weeks/year ∞ 4 years) = 416 cycles and a cycle magnitude of (200psig/1000psig) = 20% of MAOP per cycle. Using these values and published crack growth information yields a crack growth rate of 0.1 mpy, using additional conservative assumptions regarding defects present, material toughness, crack properties, and other factors.

For the second case, the to-date cycles are equal to (100 vehicles/day ∞ 365 days/year ∞ 4 years) = 146,000. The cycle magnitude is equal to (5psig/1000psig) = 5% of MAOP. Using these two values even in a conservative analysis results in very small per-cycle crack growth rates, and summarizes into annual estimate of crack growth at 0.02 mpy.

The cracking rates are conservatively assumed to coincide at a single theoretical defect, resulting in a combined crack rate of 0.12 mpy for use in TTF calculations.

Vibrations/Oscillations

As an indicator of potential fatigue loadings and a common cause of failure of mechanical couplers, sources of vibration can be included in the risk assessment. Rotating equipment—pumps and compressors—are common sources of vibration. Components on supports, especially when shared with traffic as on a road or railroad bridge, can be subjected to continuous or intermittent vibrations. Vehicle traffic over buried components can impart vibrations in addition to direct fatigue stresses. When vibration is believed to be a separate failure mechanism from fatigue, it can be added to the risk assessment, perhaps most logically as increased PoF from cracking. Failures involving separation of mechanical couplings like threaded or flanged connections, more influenced by vibration effects than classical fatigue, can be considered types of cracking failures.

There are often more opportunities for fatigue type failure mechanisms within more complex facilities including severe pump starts/stops, pressure cycles, fill cycles, traffic loadings, etc. Rotating equipment vibrations, as a prime contributor to vibration effects, can be directly measured or inferred from evidence such as action type (piston versus centrifugal, for example), speed, operating efficiency point, and cavitation potential. Vibration monitoring is a common part of rotating equipment instrumentation, mostly to ensure reliability but also supporting integrity management.

Vibration and oscillations are also possible due to fluid movements around a pipeline, including wind and water: Vortex induced vibration (VIV); wind induced vibration (WIV). Vortex shedding, whether by wind or water, can generate sufficient forces under certain circumstances, to move a pipeline segment. This movement can become rapid and relatively large, causing fatigue loadings in the pipe material. Fluid density, speed, cross sectional area in flow stream, frictional drag across the object and other factors influence the onset and magnitude of movements.

• 1. Vibrations or Oscillations can Cause Fatigue

Vibration monitoring provides insights into fatigue potential. This helps to identify when a material is subjected to higher vibration frequency (number of events/time), and/or, higher magnitude (change amount), considering duration (time) and proximity to component being assessed (when not the component itself), A robust program would include monitoring of in-service equipment/material’s frequency, duration, and level and location of vibration stresses from various sources, including pumps, rotating equipment, wind, throttling valves, surges, temperature changes, ground movements, traffic, etc.

Common practices to minimize vibration effects include compensations designed into equipment supports, PPM practices especially for rotating equipment, the use of pulsation dampers, and the use of high ductility materials operating at relatively low stress levels. The assessment should also consider varying risk reduction effectiveness of programs such as continuous monitoring with automatic shutdown (which shuts down equipment upon exceedance of pre-set vibration limit) versus monitoring with alarm versus manual monitoring (ie, spot sampling).

Mechanical Couplers

Separation of mechanical couplers—screwed connections, flanges, etc—can also be modeled as a cracking phenomenon. There is a time-dependency implied in these types of failures since, at one time, no leak was present. The time until sufficient ‘loosening’ occurs can be treated as analogous to a crack progression rate through a material.

EAC

Environmentally assisted cracking (EAC) occurs from the combined action of a corrosive environment (or other material-property-influencing environment), coupled with a cyclic or sustained stress loading. The more common EAC forms include stress corrosion cracking (SCC), hydrogen stress corrosion cracking (HSCC), sulfide stress corrosion cracking (SSCC), hydrogen-induced cracking (HIC), hydrogen embrittlement, and corrosion fatigue. Corrosion fatigue cracking arises from the same pressure-related cyclic stresses that produce fatigue and mechanical cracking but are exacerbated by active corrosion mechanisms. These are all recognized flaw-creating or flaw-propagating phenomena.

Some forms of EAC can be caused or exacerbated by hydrogen-assisted cracking. For instance, when sources of hydrogen are present—such as from agents in a product stream (such as H₂S) or from external sources such as excessive cathodic protection voltage—cracking potential may increase. Hydrogen-assisted cracking can occur as a result of the diffusion and concentration of atomic hydrogen in a crack space or other micro-structural void in a metal. These concentrations may increase the existing stress load on the metal to form a stress concentrator where cracks can develop. Hydrogen can also adsorb to the metal surface to reduce surface energy and migrate to the microstructure reducing interatomic bond strength and providing a nucleation site for cracks. See also the discussion of failures of repair sleeves due to hydrogen permeation through steel (, and ref [1001]).

As perhaps the most common of the EAC forms in pipelines, SCC has been more deeply researched than others, allowing further discussion. While specific to SCC, some of the following discussion is also relevant to the other types of EAC, for example, residual stresses, sensitizing agents on material surface, etc.

SCC

Stress corrosion cracking occurs under certain combinations of physical stresses coupled with active corrosion. Accounting for several hundred documented pipeline failures in the United States [52] some investigators think that the actual number of SCC related failures is higher since SCC is often very difficult to recognize.

See PRMM for a background discussion of this most common form of EAC.

Low stress in a benign environment is the condition least likely to support SCC, whereas high stress in a corrosive environment is the most favorable. Maximum SCC rates of over 40 mpy have been reported in both laboratory and field environments.

It is generally accepted that three conditions must be present to support SCC: tensile stress, a susceptible material, and a corrosive environment at the surface.

In addition to the necessary three conditions to support SCC, an additional factor must be present for an SCC failure to occur. This is the formation of a crack of critical size. Since SCC is characterized by colonies of tiny cracks, the formation of a critical-size crack involves the coalescence of multiple, otherwise-benign tiny cracks. There are many instances of SCC colonies that will not coalesce nor grow and therefore pose no threat to a pipeline. However, there is not currently a reliable way to differentiate these from the fewer scenarios where component integrity is actually threatened by the colonies.

ASME/ANSI B31.8 identifies high risk factors, as discussed in PRMM. An automatic screening incorporating these criteria can be set up in a computer environment. Note, however, that operators report discovery of SCC in locations that do not have all of these characteristics. Therefore, the threat (unmitigated SCC crack growth rate) cannot often be assigned zero.

Stress Tensile stress on the surface of a component is a prerequisite for SCC. A static surface stress may be generated from in-service conditions, such as sustained internal pressures. The acting stress may also be residual in nature, introduced during bending and welding in manufacturing, or it may arise from external soil pressure and differential settlement. At sites of surface damage, such as dents and corrosion pits, stress levels in the circumferential and axial directions are higher than on undamaged portions of the pipe surface. The same locations on the pipe that concentrate cyclic stresses, such as gouges, surface discontinuities, and appurtenances, can concentrate static stresses. In many cases, the stress will be virtually undetectable. Furthermore, breaks in the surface film may occur at these discontinuities to make the area more prone to electrochemical corrosion.^[4]

As with most cracking regimes, the higher the stress, the more potential for SCC crack formation and growth. Limiting the introduction of residual stresses during pipe manufacturing, transportation, and installation are important to reduce SCC susceptibility. Internal pressure is the major in-service source of static hoop stress. Lowering the operating pressure of a pipeline would be expected to reduce the potential for SCC. Some sources suggest that a stress level corresponding to design factor of class 2 (per regulations in the US: CFR 49 Part 192), 0.60, could be considered to be a threshold, below which there is no evidence of cracking. By this criteria, SCC would not be expected in class 3 or 4 areas (population density categories in US regulations, see Class Location) which correspond with design factors of 0.5 and 0.4. However, the specific relationship between SCC and hoop stress is not well established. Evidence from SCC failures show that hoop stresses have varied between 46 and 77 percent of the SMYS of a pipeline.⁴

Environment High pH levels are believed to be a contributing factor in classic SCC on steel surfaces.

Material type In steel, a higher carbon content (>0.28%) is thought to increase the likelihood of stress corrosion cracking.

These necessary conditions for SCC of steel are further discussed in PRMM.

Nonmetal EAC

As noted, nonmetal materials are also susceptible to mechanical-corrosion mechanisms such as stress corrosion cracking (SCC). While the environmental parameters that promote EAC in nonmetals are different than in metals, there are some similarities. When a sensitizing agent is present on a sufficiently stressed pipe surface, the propagation of minute surface cracks accelerates. This mirrors the mechanism seen in metal pipe materials. Organic chemicals can also aggravate environmental stress corrosion cracking [2]. For plastics, sensitizing agents can include detergents and alcohols. The evaluator should determine (perhaps from the material manufacturer) which agents may promote EAC. A high stress level coupled with a high presence of contributing soil characteristics would warrant assignment of a relatively high crack exposure in the risk assessment.

Avalanche Failure

Avalanche failure potential was previously noted. A crack will move at the speed of sound through a material. If the crack speed is higher than the depressurization wave—where pressure is the driving force creating the failure stress—then cracking continues. Material properties and thickness can each reduce crack speed. Crack arrestors take advantage of this. Less compressible products depressure quickly and therefore do not provide the sustained driving force for continued crack growth. So, changes in either the material or the product can change the potential for crack propagation.

• 1. Crack propagation vs product depressurization

Mitigation & Resistance

Cracking mechanisms are somewhat unique in that they often involve more complex interactions of cause and effect variables. Many crack scenarios involve a force that causes a movement or strain which generates a stress which grows a crack. Failure potential can be reduced by reducing the initial force, by protecting against the force, by reducing the movement, or by absorbing the strain or stress without damage.

Consider wave induced vibration (WIV). Wind is the initiating force and cannot be changed, but it can be blocked. A windscreen or re-direction would be a measure that changes the movement potential. The pipe movement from WIV could also be prevented by changing span length, pipe weight or profile, or adding dampers. Alternatively, stress levels could be changed by altering the amount of restraint at the supports.

Crack growth rate is the measure of exposure and is usually a function of a component’s movements and stresses. The operator often has more control over cracking exposure than exposures from other threats. In cracking, mitigation is therefore sometimes indistinguishable from changes to exposure and resistance. Many measures to reduce failure potential from fatigue are actually changes to exposure rather than defenses against a pre-established exposure. For instance, risk reduction can be achieved through reduction of internal pressure cycles—directly reducing the exposure level.

A challenge is determining which operational changes are 1) actually altering the exposure versus 2) blocking the exposure (mitigation) versus 3) resisting the exposure (resistance). Classifying each change as either exposure, mitigation, or resistance is sometimes not as obvious as for other failure mechanisms. Fortunately, the risk assessment format and mathematics ensures the same final PoF estimate regardless of how the elements are classified. Nonetheless, a brief discussion of some nuances in the cracking PoF assessment is warranted to deepen the understanding of modeling crack failure potential.

Depending on how integrated they are with exposure estimates, some actions and devices can be clearly modeled as independent mitigation measures. Use of pipe casings or other load transfer techniques would reduce the transmission of loads to the pipe and could be considered independent mitigation measures. Most would agree that the wind screen option in the previous WIV example is best modeled as a mitigation.

Vibration dampers, anti-WIV devices, special supports are examples that can be modeled as either mitigation—blocking the movement that causes damage—or resistance—allowing the component to absorb the forces without damage. The forces generating the exposure have not changed, but the component is either more protected from or more able to tolerate their otherwise damaging effects.

Other potential mitigation measures may already be included in the exposure estimates. These include minimization of component vibrations and stress through careful attention to equipment supports, PPM practices, continuous monitoring with automatic shutdown (ie, excessive exposure is being prevented). A pulsation damper is potentially modeled as either a mitigation device or is factored into exposure estimates, perhaps contingent upon the owner of the equipment^[5] or the primary intent of the damper.

In EAC, mitigation of corrosion will also reduce the EAC crack growth rates. When the risk assessment combines the corrosion growth rate with the cracking rate into the EAC growth rate, then the corrosion mitigation is accounted for.

In many cases, cracking PoF reduction occurs more directly through resistance influences. Choice of material (even specific steel metallurgy), wall thickness, and stress level reduce crack growth potential from a resistance standpoint. It is common practice to put extra strength components with very high ductility into applications where higher fatigue loadings are anticipated. Use of high ductility materials operating far from their maximum stress levels is a proven method of designing crack resistance into a structure.

1. 1. See Chapter 10 ↑
   2. According to the Canadian National Energy Board (NEB), there have been no reported cases of internal SCC in North American transmission pipelines (NEB 2008). ↑
   3. Conversely, high-cycle fatigue occurs under a low-amplitude loading in which a large number of load cycles is required to produce failure. ↑
   4. At sites of surface damage, such as dents and corrosion pits, stress levels in the circumferential and axial directions are higher than on undamaged portions of the pipe surface. ↑
   5. See for a discussion of foreign owned/operated risk mitigation systems. ↑