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Pipeline corrosion takes place from both the inside and outside. Corrosion on the inside is minimized by excluding oxygen and by raising the pH of any contained water, typically by addition of sodium hydroxide or lithium hydroxide. Abrasive grit carried by the contained fluid also causes internal pipe erosion, especially at pipe elbows. The techniques used for minimizing internal corrosion are not suitable for use on the outside of the pipe because it is impractical to permanently change the pH of the surrounding soil and because it is impossible to exclude oxygen from the surrounding soil.
Some pipelines have internal coatings and carry highly toxic sour gas (H2S). At any coating defect, such as produced by erosion, H2S will cause internal corrosion.
The focus of this web page is on external corrosion, so internal corrosion is only mentioned here because the total pipe wall thickness reduction is the sum of the external corrosion and the internal corrosion and internal erosion.
Supplementary information is available via Managing System Integrity of Gas Pipelines and via Transmission Gas Pipeline Integrity Measurement.
Barlow's formula assumes that the pipe material is uniform in character. Unfortunately real pipe is not uniform for several practical reasons. Real pipe is made from sheet steel which is then rolled and factory welded into truck transportable cylinders. These cylinders are in turn are field welded to form a pipeline. During the steel production process every effort is made to control the steel quality by controlling the mix of constituant elements and by controlling the crystal structure via forging processes and controlled heat treatment. However, once welding commences there are problems. The welding process introduces localized heating past the steel melting point and introduces weld fillet material that is not identical to the rolled steel in either elemental mix or crystal structure. Furthermore, the liquification of weld fillet and adjacent steel may trigger a concentration of additives/impurities at the junction between the weld fillet and the rolled steel.
A real weld can be viewed as successive transitions from the original steel with a well controlled crystal structure and additive/impurity concentration, through a region of super heated steel with modified crystal structure, through a region of uncontrolled crystal structure and additive/impurity concentration, through the weld fillet material with its own crystal structure and additive/impurity concentration, through another region of uncontrolled crystal structure and additive/impurity concentration, through another region of super heated steel with modified crystal structure and finally to original steel with its well controlled crystal structure and additive/impurity concentration.
There is additional complexity because generally the transition regions in the weld are not normal to the tensile stress vector.
In real pipe the longitudinal welds are generally factory made and the girth welds are generally made in the field. In both cases the welding atmosphere is controlled but not ideal. The welds are generally x-rayed to check for obvious voids but x-ray photographs do not reveal crystal structure and/or additive/impurity control problems.
A further problem with welds is that the pipe surface at the weld is not as smooth as the original rolled steel. This lack of smoothness affects the adherence of the subsequently applied dielectric material and/or coatings, which adherence is critical for protection against long term corrosion.
STEEL PIPELINE IMPLEMENTATION:
Oil and natural gas pipelines are fabricated from steel pipe because steel provides sufficient strength for handling durability and high pressure operation at a reasonable cost. The pipe sections are fabricated in truck transportable lengths. Each length has an external dielectric (electrical insulating) coating that is usually physically protected from minor scratching either by a spiral tape wrap or by a plastic sleeve. The pipe lengths are welded together in the field, adjacent to the prepared pipeline trench shortly before burial.
A properly executed pipe weld provides a reliable gas tight high strength connection that has a low electrical resistance. The weld should x-rayed to confirm proper weld depth and that there are no voids (trapped gas bubbles) within the weld.
For distribution piping welded connections are made at intervals along the pipe for connection of magnesium blocks, that perform an important role in corrosion prevention.
The welding process damages the pipe's dielectric coating near the welds. After welding the pipe outside surface in the vicinity of the welds is cleaned and then coated with an epoxy dielectric. This coating is then physically protected by a spiral tape wrap or a protective sleeve.
Generally the trench contains a bed of gravel which has been tumbled to remove sharp edges. The welded pipe is lowered into the trench with a mobile crane. The pipe steel has enough elasticity to withstand the stresses associated with this method of pipe installation.
More tumbled gravel is poured over the pipe and then the trench is back filled.
Pipelines properly fabricated in this manner from an electrical perspective provide a uniform potential steel surface covered by a dielectric. The purpose of the magnesium blocks is to change to electrical potential of the surrounding soil with respect to the electrical potential of the pipe.
The pipe manufacture is generally rigorously controlled in a steel plant. The pipe must meet both dimensional and material specifications. The cost implications to the pipe manufacturer of supplying out-of-specification pipe are major, so the pipe usually conforms with engineering specifications when it leaves the steel plant.
However, the transportation, field storage, field assembly, installation and testing processes rely heavily on the skill, experience and care used by the field personnel. In a major pipeline project there may be hundreds of field personnel involved of varying skill and experience working under adverse conditions, so quality control of every step of the installation process is very difficult.
After pipe installation the pipe should be subject to both hydraulic and gas pressure tests. These two tests, if properly performed, will check the physical integrity of the pipe but will not detect problems with the external dielectric coating. The external dielectric coating can be electrically checked only if all pipe ends and pipe branches are electrically insulated from ground. Even then the results are uncertain unless all of the pipe is below the water table at the time of testing.
One of the industry problems is lack of adequate third party supervision of these tests. If any of these tests detect a problem, the costs of remediation can be huge. Hence the pipeline installation subcontractors have a strong financial motivation to conceal unsatisfactory test results.
Most pipeline accidents that are not caused by external physical damage to the pipe arise from inadequate testing at the time of installation or from long term corrosion mechanisms. For example, the 2010 San Bruno fire in California was traced by the US National Transportation Safety Board (NTSB) to failure to perform a hydraulic pressure test on the pipe section that failed.
EXTERNAL CORROSION PREVENTION BY USE OF A DIELECTRIC COATING:
External corrosion minimization is achieved first by use of a dielectric coating on the outside of the steel pipe which excludes both water and oxygen from the outside surface of the pipe. To the extent that this dielectric coating is properly applied and remains defect free there is no external pipe corrosion.
However, in the field there are many ways that the external dielectric coating can acquire defects. Examples include:
Scratches while in transport;
Scratches during handling while in storage;
Too much exposure of the dielectric coating to sunlight;
Scratches during field assembly;
Inadequate cleaning after welding;
Inadequate coating and failure of coating bonding in the vicinity of welds;
Scratches while being lowered into the gravel bed;
Scratches while gravel is being poured over the pipe
Scratches due to thermal or stress related pipe expansion/contraction within the gravel bed;
Scratches by frost heaving within or adjacent to the gravel bed;
Scratches due to inadvertent application of external force, such as by the side leg of a back hoe or boom truck;
Scratches by augers that are used to install adjacent utility poles;
Scratches by back hoe buckets that are used to install adjacent buried services including:
potable water, sanitary sewer, storm sewer, local natural gas distribution, telephone, Cable TV, data communication and electricity;
Scratches by backhoes that are used to create drainage paths during flood emergencies.
ELECTRICAL CORROSION PREVENTION:
The steel pipeline industry recognizes that in spite of its best efforts, the external dielectric coating on buried steel pipes may have application and installation defects and will likely eventually get scratched by mechanisms beyond the control of the pipeline owner. Hence buried steel pipelines also use an electricity based mechanism for external corrosion protection. However, this electricity based corrosion protection mechanism can be defeated by proximity to major grounded electrical equipment such as wind turbine electricity generators. Thus the combination of almost inevitable pipeline dielectric coating defects plus proximity of a wind turbine electrical generator can lead to electrically accelerated corrosion of a buried steel pipeline. If that pipeline contains high pressure natural gas, oil and/or toxic hydrogen sulphide (H2S) gas, a major public safety/fire/property damage incident can result.
There have been recent developments in more scratch resistant pipeline coatings. However, these new coatings do not solve the problem of hundreds of thousands of km of existing buried steel pipe with inferior coatings.
For practical reasons most buried steel natural gas distribution pipelines are corrosion protected using sacrificial magnesium electrodes. This arrangement is sometimes referred to as a Galvanic Anode System for cathodic protection. Absent proximity of major grid connected electrical equipment and assuming that the imperfections in the dielectric coating are relatively small the magnesium electrodes produce a differential voltage that makes the steel pipe about 1.9 volts negative with respect to the surrounding ground water. Practical experience has demonstrated that in locations that are remote from major grounded electrical equipment this methodology is adequate to prevent normal corrosion. In remote areas where there is no nearby major electrical equipment the magnesium electrodes may be quite far apart. Magnesium is an expensive metal and is typically used in 25 pound blocks because it slowly corrodes away over time. Hence pipeline companies try to minimize their use of these magnesium electrodes by spacing them as far apart as circumstances reasonably permit at the time of original pipeline installation.
Each pipeline carrying a fluid emerges from the ground at the fluid source, at pumping/compressor stations and at consumer premises. Generally at these locations distribution pipe is connected to furnaces, boilers, pumps, compressors, etc. that are electrically grounded. On distribution pipes there are a large number of such random electrical ground connections so the pipe can be considered to be at ideal electrical ground potential. Hence the magnesium electrodes bias the ground water surrounding the pipes at 1.9 volts positive with respect to ideal electrical ground potential.
If an external electrically induced ground current changes the ground water potential by less than 1.0 volt at the pipeline then 0.9 volts of negative bias remain on the pipe with respect to the surrounding ground water and the pipeline corrosion protection is not seriously compromised. The 1.0 volt may consist of 0.5 volt DC + 0.5 volt AC. However, if the ground water potential near the pipeline drops by more than 2.0 volts rapid electrically accelerated pipe corrosion will occur at pipe dielectric coating defects.
A practical real life problem is that the pipeline potential measuring apparatus used by pipeline service persons may only respond to DC potentials whereas the corrosion may be accelerated by the proximity of grounded electrical equipment such as three phase transformers. Under adverse soil over bedrock conditions such electrical equipment can accelerate the corrosion of buried steel pipelines located over 1 km from from the electrical equipment.
In past cases of natural gas pipeline rupture due to Stress Corrosion Cracking (SCC) the Transportation Safety Board of Canada (TSBC) has calculated the average rate of crack formation assuming that the dielectric coating failed at or soon after the time of original pipe burial. The TSBC has found crack growth rates in the range 0.15 mm / year to 0.40 mm / year. In order to ensure detection of such cracks before they trigger rupture failures it is necessary to In Line Scan and then pressure test a pipeline at 150% of Maximum Approved Operating Pressure (MAOP) about every five years. The corrosion rate may be electrically accelerated as set out at ELECTRICALLY ACCELERATED PIPELINE CORROSION.
Murphy's Law basically says that if there is a way for something to be done wrong that leads to equipment damage and/or personnel injury, sooner or later someone will find it. Usually Murphy strikes as a result of insufficient personnel training.
With respect to the corrosion issues raised herein some common Murphy issues are:
1. A backhoe operator scratches a pipeline and then covers up that scratch without reporting it, or if he/she does report it the report lacks sufficient detail for a repair crew to later find the scratch and fix the dielectric coating on the pipe. A large scratch can eventually lead to a pipe rupture failure.
2. A thief learns where the magnesium electrodes are and steals them for their scrap metal value. Then there is no bias voltage protection and electrically accelerated corrosion is much worse.
3. Major transmission pipelines use DC power supplies instead of magnesium electrodes to provide bias voltage protection. However, such protection is easily inadvertently compromised by trades persons who fail to use insulated pipe hangers or who fail to use appropriate dielectric fittings or dielectric isolation on flange bolts.
4. Such power supplies may also be accidentally compromised by grounded remote metering circuits.
5. Such power supplies, unless monitored via a computerized alarm system, are easily accidentally left off or inadvertently turned off by persons who simply do not understand the operation of the corrosion protection system.
6. There is no comprehension by pipeline personnel of the effect of electrically accelerated corrosion due to proximity of major grounded electrical equipment. With an adverse soil structure this corrosion triggering electrical equipment may be more than 1 km from the pipeline axis. The effect of this remote electrical equipment may not be detectable with normal pipeline service equipment.
The pipe material can be characterized by its linear elastic constant which is known as Youngs Modulus Ym. By definition:
Ym = (stress / strain)
stress = Sh
strain = dL / Lo
dL = change in unstressed material length Lo along the stress axis
Ym = Sh / (dL / Lo)
Sh = Ym (dL / Lo)
Note that if the pipe material is operating in its elastic region and if the strain (dL / Lo) is uniformly distributed throughout the pipe material then the working stress Sh is proportional to Youngs Modulus Ym. If Ym is constant then the stress is uniformly distributed throughout the pipe material and Barlow's Formula is valid.
ELASTIC ENERGY CONTENT:
Consider an element of pipe material of cross sectional area Ao, length Lo and volume:
Vo = Ao Lo
For an element of pipe material operating in its linear elastic region force F is given by:
F = Sh Ao = (Ym Ao / Lo) dL
and the elastic energy Ee content of the material is given by:
Ee = [(Ym Ao) / (2 Lo)] dL^2
and the elastic energy density in the pipe material is given by:
Ee / Vo = [(Ym) / (2 Lo^2)] dL^2
= (Ym / 2) (strain^2)
Note that for a pipe operating in its linear elastic region with uniform strain the elastic energy density is distributed in proportion to the Youngs Modulus Ym
STRESS CORROSION CRACKING
Practical experience has shown that the most common mechanism of long term spontaneous pipeline rupture failure is a phenomena known as Stress Corrosion Cracking (SCC). If a pipe wall material is under tensile stress, molecular energy dynamics make the material more prone to chemical corrosion. If the material changes caused by welding cause either a local tensile stress increase or a local chemical change and if the conformal dielectric coating at or near the weld fails and if the local chamical environment is adverse then a stress corrosion crack may be initiated. If a corrosion reaction causes a chemical change at the pipe wall which causes the Youngs Modulus Ym to locally increase a disproportionate amount of the elastic energy in the pipe is borne by the pipe molecules deep in the crack. As a result the crack advances. Field experience has shown that such cracks typically increase in depth at rates of 0.15 mm / year to 0.5 mm / year until the pipe fails by rupture.
Pipes laid during the 1950s usually relied on dielectric tape rather than fusion bonded epoxy for the external dielectric coating. Typically due to "tenting" the bond between the tape and the steel at or adjacent to a weld was unsatisfactory which has allowed initiation of stress corrosion cracks. Over time a stress corrosion crack gets longer and deeper until the pipe fails. If two or more such random cracks join the pipe can fail very quickly.
In the derivation of Barlow's Formula an implicit simplifying assumption is made that the hoop stress is evenly distributed throughout the pipe material. In effect there is an implicit assumption that Ym is constant independent of radial position in the pipe material. However, in practical pipes the pipe geometry forces the strain to be almost uniformly distributed throughout the pipe material. Hence the elastic energy per unit volume is actually distributed in proportion to the Youngs Modulus Ym. Under circumstances of metallurgical nonuniformity Ym is not constant and there may be a localized region where Ym is large causing the local elastic energy density to exceed the inter-crystal binding energy. Hence the local working stress Sh exceeds the local yield stress Sy. Such circumstances cause initiation and propagation of pipe cracks.
The most common origin of this problem is a long term chemical interaction between the pipe material and the pipe contents or the pipe external environment which leads to a pipe material property change. This pipe material property change manifests itself as an increase in the local value of Ym and hence an increase in the elastic energy density of the pipe material. As a result at the pipe surface the local working stress Sh exceeds the local yield stress Sy and a crack is initiated. Generally tangential stress concentration causes such cracks to be parallel to the pipe axis. These cracks eventually lead to rupture type pipe failures. Hence it is essential to identify circumstances where long term chemical interaction between the pipe and its contents or between the pipe and its external environment can lead to significant increases in the local value of Ym.
In Fusion Bonded Epoxy (FBE) coated steel pipes a common cause of this problem is a long term chemical interaction between the steel pipe material and hydrogen gas entrained in the pipe contents or generated as a result of electrolysis of surrounding water. The rate of this long term chemical interaction increases with the fluid operating temperature and with the hydrogen gas partial pressure. If the chemical interaction between the pipe contents/environment and the pipe wall causes:
Sh > Sy
at the pipe wall cracks are initiated and the working stress in the remaining thickness of the pipe wall increases. If this process is permitted to continue the pipe will eventually undergo a rupture failure.
Materials that can be continuously transported through high pressure steel pipelines are limited to those materials that do not cause stress corrosion cracking.
Hydrogen gas at high temperature/pressure is well known to promote stress corrosion cracking of steel pipe. This author is not aware of any simple fix for a high pressure steel pipeline that has carried significant entrained hydrogen gas for a significant period of time other than reducing the pipeline's Maximum Allowed Operating Pressure (MAOP). The requirement to prevent hydrogen accumulation in pressure tube type nuclear reactors is a well known issue.
If a hydraulic pressure test is done on an old pipeline that may have a wide incidence of stress corrosion cracking extreme care should be used to avoid over stressing the remaining pipe material. It is prudent to do a pressure test on a short length of representative pipe first such that if the short pipe length ruptures the entire pipeline is not rendered totally unusable by being over stressed.
In principle the wall thickness of a steel pipe can be electronically scanned from the inside using a device known as a pig or In Line Inspection Tool that moves along the inside of the pipe. The pig can detect locations where the pipe wall is too thin. Advanced pigs can also detect pipe cracks. However, there are many practical problems with pigs. They cannot get into some pipe sections due to non-compatible valves and fittings. They generate mountains of computer printout that frequently is not examined for lack of skilled personnel with adequate time. Interpretation of pig data requires some skill. Every pipe fitting type and pipe fitting size generates a different pig signature. Resolution of external cracks near welds is difficult. Responding to pig data is even more difficult. Many existing pipelines predate the use of accurate GPS survey equipment, so even if one knows exactly where a pig was inserted in a pipeline and exactly how far the pig travelled from the insertion point to where it detected a problem, that information may not be sufficient to tell a repair crew exactly where they have to dig to locate and fix the problem. Furthermore, the problem may be in the middle of a roadway within a maze of other buried services.
There have been major pipeline rupture failures that occurred simply because no one with sufficient skill had the time to examine the data that pigs had collected.
The position of this author is that due to practical problems with pigs, from a safety perspective there is no substitute for a periodic hydraulic pressure test. However, such pressure tests entail prolonged shutdowns of pipeline systems and may lead to governmental orders for pipe replacement, so pipeline companies will usually do all in their power to avoid conducting such tests. Pipeline companies will purchase a pig and will collect pig data in accordance with regulatory requirements. However, there is inadequate legislative motivation for pipeline owners to analyze and act on the pig data that they collect.
Thus, provided that a pipeline is properly fabricated and initially tested, long term corrosion remains as a major risk, not withstanding the fact that the pipeline company may appear to be in compliance with regulations relating to pig testing.
MULTIPLE FAILURE PROBLEMS:
It should be noted that a serious external corrosion related accident requires three failures, first a failure of separation between the pipeline and an urban population, then a failure of the pipe dielectric coating, then a failure of the electrical corrosion prevention system.
Unfortunately society frequently tolerates a failure of two of the three protection mechanisms without taking any remedial action. Therein lies the potential for major accidents when a happenstance causes a failure of the third protection mechanism.
Another hidden failure mechanism is a change in pipe usage. If a pipeline was originally designed to carry fluids less dense than water and then after construction its usage is changed to carry fluids more dense than water new environmental risks are introduced that were not contemplated during the original pipeline design and route selection. In the event of a pipe rupture fluids less dense than water float and there is equipment that can separate and recover these fluids. If the fluid is more dense than water it sinks and fluid separation and recovery are almost impossible. The result may be major environmental damage, including pollution of potable water, that persists for many years.
UNANTICIPATED URBAN GROWTH:
An excellent example of failure of separation between people and major pipelines is Enbridge Line 9 in Toronto. The Enbridge Line 9 oil pipeline, when it was originally installed in the 1970s, was far from any dense urban population. The pipe wall thickness was the minimum permitted at the time because at the time of installation there was no dense urban population in proximity to the pipeline and material cost minimization was the dominant issue.
However, the Grater Toronto Area became the fastest growing metropolis in Canada. Now for many km from Brampton to Oshawa Enbridge Line 9 is surrounded by nearby major buildings and storm sewer grates. A Line 9 rupture could become a major disaster with oil running through the Toronto storm sewer system, into Lake Ontario, then into the Toronto potable water intakes. As I write this document Enbridge is planning to replace sections of Line 9 with new thicker wall pipe with a high grade dielectric coating. Various parties are demanding that all of Line 9 in urban areas be pressure tested to the material Specified Minimum Yield Stress and/or replaced.
A comparable new threat to pipelines is wind farms. Many pipelines were originally designed and installed in rural areas with no contemplation that they would eventually be in proximity to major grid connected electrical equipment (wind turbine transformers) that can accelerate pipe steel corrosion at any buried pipe coating defect.
There is also a new class of pipeline corrosion risks related to grounded electrical equipment located near pipeline corridors. In an effort to efficiently utilize land, in some places 3.0 MVA wind turbines are being installed in or adjacent to existing dedicated energy transmission corridors. However, wind turbine transformers can cause ground currents that lead to rapid corrosion of nearby buried steel pipelines. It is crucial that the electrical codes relating to wind turbines and other distributed power equipment address this ground current issue. Every wind turbine within a wind farm must be separately isolated from its transmission/distribution line via an ungrounded low capacitance delta type transformer connection. Every wind turbine must be fitted with ground fault detection and alarm signalling. Substation transformers need to be selected for low harmonic generation.
There needs to be new legislation that makes parties that cause ground currents financially responsible for accelerated corrosion damage to nearby buried steel pipelines. In extreme cases, especially in the proximity of large unbalanced electrical power inverters, or with subsurface bed rock, the radius of such ground current induced pipeline damage can extend more than 3 km from the electrical equipment grounding point.
This web page last updated May 12, 2019.
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