The Department of Environmental Protection Wednesday announced it has fined NFG Midstream Trout Run LLC of Erie $250,000 for multiple violations of the Clean Streams Law and department regulations during construction of the Trout Run Gathering System pipeline in five Lycoming County municipalities during 2011 and 2012.

“Department staff documented continuing violations at multiple locations during a seven month period,” DEP Director of District Oil and Gas Operations John Ryder said. “NFG’s failure to implement and maintain erosion and sediment control best management practices resulted in several sediment discharges into unnamed tributaries to Mill Creek and Lycoming Creek, Lycoming Creek, and an exceptional value wetland.”

The department’s investigation began in October 2011 when inspectors discovered sediment on State Route 973, no temporary stabilization, and ineffective best management practices used to control erosion and sedimentation issues.

Periodic inspections by DEP staff during construction of the 16-mile gathering line resulted in the issuance of 13 Notices of Violation to NFG, including 12 violations for sediment discharges to waters of the Commonwealth, many of which are classified as exceptional value or high quality waterways.

In November 2011, a landslide in the company’s right of way above Ringler Road in Lewis Township caused the road to be closed temporarily.

Additional discharges occurred to an unnamed tributary to Lycoming Creek, an exceptional value stream, below the road. The sediment discharge violations continued to occur until Jan. 18, 2012.

While the sediment discharges did impact the waterways, the department did not document any impact to fish or other aquatic life from any of the violations. NFG has instituted additional environmental protocols since this time and has addressed the environmental issues identified on this project.

The pipeline was built in Gamble, Hepburn, Lewis, Loyalsock and McIntyre townships. It begins at a Seneca Resources well pad in McIntyre Township and ends at an interconnect station at the Transco transmission pipeline in Loyalsock Township.

NFG paid the penalty on September 18.


Oil and gas pipelines, including pumping stations, have established an impressive safety record over the years.  However, failures have occurred for a variety of reasons, with corrosion and faulty material or faulty welding comprising about 61 percent of the causes of those failures.  In 2011, following major tragic natural gas incidents, DOT and PHMSA issued a Call to Action to accelerate the repair, rehabilitation, and replacement of the highest-risk pipeline infrastructure.  Among other factors, pipeline age and material are significant risk indicators.  Pipelines constructed of cast and wrought iron, as well as bare steel, are among those that pose the highest-risk.

There are approximately 2.6 million miles of pipeline networks in the United States of which 304,725 are natural gas transmission lines.  The network includes the "gathering" lines (the ones that transport oil and natural gas from well sites to compressor stations and other processing facilities), the 20- to 42-inch transmission lines (that carry oil and gas long distances), and distribution lines as small as 2 inches that carry gas into homes and businesses.

The May 15, 2014 pipeline failure in Los Angeles that released 10,000 to 20,000 gallons of crude oil was caused by a valve failure on a 20-inch above-ground high-pressure pipeline and occurred at the pumping station of the pipeline logistics company that owns the pumping station where the failure occurred. 


Photo above shows cleanup crews at the pumping station in Los Angeles where a failed valve released between 10 and 20 thousand gallons of crude oil on May 15, 2014


Increase in enforcement actions
Since 2009, in an attempt to further improve the safety of the pipelines, Pipeline and Hazardous Materials Safety Administration (PHMSA) has proposed more than $33 million in civil penalties against pipeline operators, $10 million more than the amount proposed in the previous five years combined.  It has also issued 544 enforcement orders over the past five years, constituting more than half of all orders issued by the agency since 2002.  PHMSA also reports 45 percent less serious pipeline incidents, those resulting in fatalities or major injuries, since 2009.  The count has declined each year since 2009.

"The results are clear: we are using our enforcement tools to hold pipeline operators accountable and also resolve enforcement actions quicker than ever," said PHMSA Administrator Cynthia Quarterman.

In 2013, PHMSA initiated 266 enforcement cases against pipeline operators for problems involving their integrity management programs, risk assessments, failure prevention and mitigation programs, and several other possible regulatory violations identified during failure investigations and routine inspections.  In addition to proposing penalties for each federal violation, enforcement orders also include case-specific safety instructions to ensure all issues have been resolved.

Why this increase in enforcement actions by the PHMSA?

About 50 percent of the pipelines have been in the ground since the 1950s and 1960s.  Many of the welds and protection coatings on these pipelines do not meet current safety standards.  Since the 1990s we have witnessed an increased appearance of stress corrosion cracking (SCC) defects that led to some spectacular pipeline failures.  Considering the significant rise of oil and gas production during the last decade and the introduction of new products and chemicals inside these aging pipelines, the DOT PHMSA is concerned and is trying to force the pipeline operators to comply with the federal requirements.


Stress corrosion cracking (SCC) is cracking induced by the combined influence of tensile stress and corrosive environments, in combination with temperature effects.


Based on the hazardous liquid pipeline incidents reported to the PHMSA across the United States between January 2002 July 2012, there were 1,692 incidents, of which 321 were pipe incidents along the mainline and 1,027 were involving different equipment components such as tanks, valves, or pumps.

The pipeline operators and their insurers face significant liability every time there is a release from the pipeline.  In case where there was an explosion and fatality, the costs are astronomical.  Unfortunately, there are millions of miles of pipelines across the United States and keeping all these miles safe from physical or corrosion damage is next to impossible.  So, incidents happen or a regular basis.  There is also the concern that the pipelines that were laid in the 50s and 60s that constitute about 50 percent of the several millions of miles of pipe in the ground are aging to the point that they are ticking time bombs.  Approximately 25 percent of the capital expenditures every year go into replacing aging pipelines.

Considering the increased enforcement activity in rail, highways and pipeline industries, it is very timely to provide a summary of the causes of pipeline failures, including corrective solutions. This blog addresses the causes and contributing factors (C&CF) to gas and liquid pipeline failures. 


Brief Overview of the Liquid & Gas Pipelines

Liquid Pipelines

Crude oil must undergo refining before it can be used as product.  Once oil is pumped from the ground, it travels through pipelines to tank batteries.  A typical tank battery contains a separator to separate oil, gas, and water.  After the crude oil is separated, the crude oil is kept in storage tanks, where the oil is then moved through large-diameter, long-distance trunk lines to refineries, other storage tanks, tanker ships, or railcar.  The pressure in the trunk lines is initiated and maintained by pumps to overcome friction, changes in elevation, or other pressure-decreasing factors.  Drag reducing agents (DRAs) are also used to improve throughput by decreasing the effects of friction.  Pump stations are located at the beginning of the line and are spaced along the pipeline at regular intervals to adequately propel the oil along. In 1998, there were 80 companies operating crude oil pipelines in the United States.

Once oil is refined, product pipelines transport the product to a storage and distribution terminal.  The products include gasoline, jet fuel, diesel fuel, ammonia, and other liquids. Other product pipelines transport liquefied petroleum gases (LPG) and liquefied natural gas (LNG) and highly volatile liquids (HVL) such as butane and propane.

Breakout tanks are aboveground tanks used to relieve surges in a liquid pipeline system, or to receive and store liquid transported by a pipeline prior to continued transportation by the pipeline.

Natural Gas Pipelines

The purpose of natural gas gathering and transmission pipelines is similar to that of crude oil gathering and crude oil trunk lines; however, the operating conditions and equipment are quite different.  For example, gas transmission pipelines use compressors instead of pumps to force the gas through the pipe.  The transmission lines connect to the distribution systems through the “city gate” valve and the metering station, which delivers the natural gas to the consumers via small-diameter, low-pressure lines. Natural gas is often treated in scrubbers or filters to ensure that it is dry prior to distribution.

In addition to the vast mileage of underground piping spanning the United States, a multitude of other facilities were required for the interstate transport of liquids and gases. The major facilities of interest in this blog are pump and compressor stations, valve stations, and metering devices.  For instance, gathering lines connect individual gas wells to field gas treatment facilities and processing facilities, or to branches of a larger gathering system.  The natural gas is processed at the treatment facility to remove water; sulfur; and acid gases, hydrogen sulfide, and carbon dioxide. From the field processing facilities, the dried and cleaned gas enters the transmission pipeline.

The big leap in pipeline steel quality started in the ‘60s, as the use of low carbon steels resulted in tougher grades.  In that time other improvement in pipeline industry procedures, as testing all new pipeline construction by a hydrostatic pressure ”field” test, assured the proper serviceability of the pipe before its operational phase.  The attention and safety for the existing pipelines was enhanced by the introduction of "in-line" tools; at that time they were able to inspect for corrosion defects on a “live”.  Furthermore, the development of coatings gave another help for controlling the external corrosion.  In the ‘70s the introduction of TMPC “Thermo Mechanical Process” was the latest breakthrough for increasing the pipeline steel strength, toughness without any detrimental effect on weldability.

Pipelines can vary from 2-inch in diameter for gathering lines to 48-inches for transmission lines.  Most modern pipelines are constructed of either seamless steel or steel with a welded longitudinal seam in 40 to 60 feet lengths.  The individual pipe joints are welded together into sections.  To inhibit corrosion, they apply pipe coatings and wrappings at the steel mill or on-site.  A natural gas distribution main has a 24-inch minimum depth.  A transmission pipeline have a minimum depth of 30 inches in rural areas and deeper in more populated areas.  The pipelines are purchased to strict specifications that ensure the pipe is ductile.  This inherent ductility ensures that a defect in the pipeline will not fail by brittle fracture.

Pipelines are pressure tested in addition to nondestructive testing prior to being put into service.  Normally, pipelines are hydrostatically stressed to levels above their working pressure and near their specified minimum yield strength.  This pressure is held for several hours to ensure that the pipeline does not have defects that may cause failure in use.  This proof test of pipelines provides an additional level of confidence that is not found in many other structures.

Since the 1940s, all of the oil and gas transmission lines have been built by welding.  In general, American Petroleum Institute (API) 5L specification steels are used in pipelines.  Pipeline wall thicknesses are established on the pressure in the line and on the allowable hoop stress levels for the material.  The allowable stress levels for gas pipelines vary based on the location of the pipeline and are regulated by the U.S. Department of Transportation (DOT).

Based on current estimates, over 98% of pipelines are buried.  No matter how well these pipelines are designed, constructed and protected, once in place they are subjected to environmental effects (such as oxygen, carbon dioxide, sodium chloride, and so on), external damage, coating disbondments, inherent mill defects, soil movements/instability and third party damage (such as an excavator physically rupturing the pipe or damaging the protective coating or undermining the pipeline supporting soil). 



The most common pipes being used are the high strength pipe steels such as the API 5L/EN10208 grade X65, X70 and X80/L455MB-L690MB.  As the media inside the pipelines are becoming more aggressive, stainless steel and corrosion-resistant alloy (CRA) pipes are gaining in importance. 

We typically perform the C&CF investigations after a pipeline failure.  The various pipeline product types we deal with encompass the following:



Liquid Pipelines

·         Crude oil pipelines that include crude oil, sour crude and low vapor pressure products;

·         Water pipelines that include water, freshwater, produced water, saltwater and sour water;

·         High vapor pressure pipelines that include ethylene, propane, pentanes and liquid ethane;

·         Miscellaneous pipelines that include miscellaneous gas and oil effluents.


In addition to crude oil, the most common liquids transported are refined petroleum products, such as:  gasoline, aviation gasoline, jet fuel, home heating fuels, diesel fuels, natural gas liquids (NGL), liquefied petroleum gas (LPG), anhydrous ammonia.


Gas Pipelines

·         Sour natural gas pipelines that carry natural gas with a hydrogen sulfide partial pressure great than 0.3 per cent;

·         Natural gas pipelines that included natural gas, sweet gas, and fuel gas;


Today’s pipe steels are higher strength than those used previously and are today designed with weldability in mind. The most common steels used for oil and gas cross country pipelines conform to API 5LX or similar such standards.


Table 1. Summary API 5L Strength Requirements









Tensile (ksi)









Yield (ksi)










Strength levels can be achieved by several methods including gross chemistry, micro-alloying, and cold expansion of the pipe when produced at the pipe mill.  In higher strength grades the trend is to use cold expansion and micro-alloying so that carbon and manganese can be kept at relatively low levels, thus reducing heat affected zone hardness and helping reduce, though not eliminate concerns about weld metal hydrogen.  For example, it is typical to see carbon contents of less than 0.05% in modern X70 and X80 steels with some X80 steels having Pcm values of less than 0.20.

Several processes and combinations of processes currently used for the field welding of cross country line pipe. These include shielded metal arc welding (SMAW), self-shielded flux cored arc welding (FCAW-S), and gas metal arc welding (GMAW).  With GMAW the transfer mode must also be consider, short arc, controlled short arc as in Surface Tension Transfer®, spray, and globular.  Some manufacturers use the metal (MCAW)-cored wires in order to increase productivity compared to manual arc welding.

However, up to now the conventional SMAW with coated stick electrodes using either cellulosic or basic low hydrogen systems suitable for vertical up and down positions is applied where terrain, project length, climatic conditions or human resources do not permit automated welding.  SMAW is also widely used for tie-ins and repair welding.


Some of the installation activities in a typical steel transmission project include:

1.   Installation and maintenance of environmental control devices

2.    Pavement removal and pavement final restoration

3.   Trench excavation in both soil and rock

4.   Pipe bending, welding and joint-holiday coating

5.   Pipe installation by open cut method

6.   Pipe installation by directional drilling method

7.   Pipe installation by conventional casing boring method

8.   Pipe installation using well pointing methodology

9.   Pipe integrity testing by air or water

10.                Complete restoration of all disturbed areas to industry leading expectations


Some of the typical activities involved during the construction of the transmission station include:

1.   Installation and maintenance of environmental control devices

2.   Fabrication of proposed facilities

3.   Concrete foundations installation and building erection

4.   Measurement and regulation runs installation

5.   Launcher and receiver installation

6.   “Hot” tie-ins utilizing short stop and spherical tee technology

7.   Filter-separator installation

8.   Holding tank and dike system installation

9.   Heater installation

10.                Cathodic protection rectifier systems

11.                Pipe integrity testing by air or water

12.                Complete restoration of all disturbed areas




Failure Modes of Gas and Liquid Pipelines

Based on assessments of the transmission pipeline failures over the last 20 years, the main causes and contributing factors to pipeline rupture include the following:

·         Physical (mechanical) damage (gouges and dents, plain dents, wrinkles, etc. normally created by handling during transportation, construction or maintenance activities or by excavation by utility owners/operators/tenants near the pipelines) - about 11 percent of the incidents.  One recent example is the leak at the Magellan Oil Products Pipelines, Nemaha County, Nebraska, in December 2011. The leak occurred in Nemaha County, Nebraska, when a tenant operating a bulldozer struck two parallel pipelines: one 8-inch-diameter line transporting diesel fuel and one 12-inch-diameter line transporting jet fuel and gasoline.  Approximately 27,300 gallons of diesel fuel, 27,500 gallons of jet fuel, and 64,200 gallons of gasoline were spilled.


View of a dent and a gouge on a liquid pipeline


·         Corrosion (internal, external or stress corrosion cracking) about 25 percent of the incidents.  Of these, about two thirds are caused by external corrosion and one third is caused by internal corrosion.


View of internal corrosion inside a crude oil pipe


·         Equipment and Material defects and/or weld failures (gasket o-ring failure, seal/pump packing failure, control/relief equipment malfunction, girth weld failures due to misalignment, incomplete fusion, weld cracks, improper repair welds, defective fabrication weld, defective pipe seam, defective pipe, wrinkle, bend or buckle, and other reasons) – about 36 percent of the incidents;

·         Incorrect or negligent operation or inspectionabout 11 percent of the incidents;

·         Damage due to natural forces (lightning, cold/freezing weather, earthquakes, heavy rain or floods, earth movement, etc.) – 6 percent of the incidents;

·         Other outside force damage (vandalism, terrorism) – about 3 percent;

·         All other causes (SCADA breakdown, programming errors) – about 8 percent




Mechanical damage commonly manifests itself in one of four forms.  The first and most serious is encroachment damage (or “third party” damage) that occurs when the pipe is struck by earthmoving equipment.  It usually consists of a shallow residual dent plus a gouge, sometimes called a “combined defect” because it consists of both a geometry distortion and a stress-concentrator or notch.

The severity of mechanical damage is rooted in the presence of microcracks that develop at the base of the gouge during the process of dent re-rounding due to pressure (and to some extent elastic rebound).  As with plain dents, dents with gouges respond differently to static and cyclic pressure loading.




Unfortunately, there is a large population of dents that exist in the pipeline networks.  Between 2004 and 2005, studies performed using metal loss tools reported more than 66,000 dents in 57,000 miles of pipeline, or about 1-2 dents per mile.  Fifty percent of all pipelines contain 10 or more dents. 

The other important form of damage arises principally during construction of the pipeline, during ground movement/settling (buckling) and through some rock impingement.  Most often the damage is seen as prominent dents on the bottom half of the pipeline, often called “plain dents”.  Plain dents are defined injurious if they exceed a depth of 6% of the nominal pipe diameter.



Other major defect classifications that typically arise when assessing pipeline damage include:

·                     Wrinkle Bends- they are associated with the bending or buckling of pipe that result in creating local indentations along the length of the failed area;

·                     Constrained dents – these are the type of dents that are held in place during the process of pressure cycling.  The fatigue life for constrained dents is significantly lower than the fatigue life for unconstrained dents.






Corrosion is the deterioration of a material that results from a reaction with its environment.  In the most common use of the word, this refers to the electrochemical oxidation of metals.  Rusting, the formation of iron oxides, is a well -known example of electrochemical corrosion.  Failure statistics indicate that approximately 24 percent of hazardous liquid pipeline incidents are caused by corrosion.  External corrosion was the cause of 9.7 percent of incidents, internal corrosion caused 7.9 percent, and for 5.2 percent of incidents, the type of corrosion was unspecified.  The buried external surface of the proposed pipeline would be exposed to a wide variety of environmental conditions, from dry soils (considered to be less corrosive) to wet soils containing salts and byproducts from fertilizers, agricultural chemicals, or animal wastes (considered to be more corrosive).  A combination of measures would be used to protect the pipeline from corrosion as described below.  External corrosion protection for the pipeline would involve a combination of external coating and cathodic protection systems.  Internal corrosion would be monitored through in-line inspections. External corrosion and internal corrosion are described in further detail below.

The corrosion-related cost (damage repairs, capital and O&M) to the transmission pipeline industry is approximately $6 to $10 billion annually.  Unfortunately, despite the significant replacement costs associated with corrosion damage, even today the selection of materials for transport of oil and gas is not always made with sufficient emphasis on corrosion resistance, but rather on good mechanical properties, ease of fabrication and low cost.  Due to the material loss rates resulting from internal corrosion, it becomes necessary to thoroughly characterize the behavior (for example: CO2 corrosion behavior at low partial pressure, under supercritical condition) of high strength steels which are used for oil and gas pipelines such as API 5L X65, X70 and X80.

It is a great challenge to classify the types of corrosion in the oil and gas industry in a uniform way.  One can divide the corrosion on the basis of appearance of corrosion damage, mechanism of attack, industry section, and preventive methods.  There are many types and causes of corrosion.  The mechanism present in a given piping system varies according to the fluid composition, service location, geometry, temperature, and so forth.  In all cases of corrosion, the electrolyte must be present for the reaction to occur.  In the oil and gas production industries, the major forms of corrosion include sweet corrosion, sour corrosion, oxygen corrosion, galvanic corrosion, crevice corrosion, erosion corrosion, microbiologically induced corrosion, and stress corrosion cracking.


Main Types of Corrosion

The main types of corrosion include:

·                     General Corrosion;

·                     Localized corrosion (pitting/crevice corrosion);

·                     Sour corrosion (H2S corrosion)

·                     Stray-Current Corrosion;

·                     Erosion-Corrosion

·                     Stress Corrosion Cracking (SCC), including sulfide stress-cracking;

·                     Microbiologically-Influenced Corrosion (MIC);


General Corrosion

Corrosion of the pipe wall can occur either internally or externally.  External corrosion may be caused by damage to coatings, manufacturing defects within the metal, or through loss of the cathodic protection.  Internal corrosion occurs when corrosive liquids or condensates are transported through the pipelines.  Causes of internal corrosion include: chloride, carbon dioxide, hydrogen sulfide, oxygen, and microbiological activity that produces corrosive conditions.  Depending on the nature of the corrosive liquid and the transport velocity, different forms of corrosion may occur, including uniform corrosion, sweet (carbon dioxide) corrosion, sour (hydrogen sulfide) corrosion, oxygen corrosion, galvanic corrosion, pitting/crevice corrosion, and erosion-corrosion.  

Galvanic Corrosion: Happens when two metals with different electrode potentials are connected in a corrosive electrolytic environment. The anodic metal develops deep pits in the surface.


Galvanic corrosion


The figure below shows an example of internal corrosion that occurred in a crude oil pipeline due to high levels of saltwater and carbon dioxide (CO2).


Internal corrosion in a crude oil pipeline


Localized corrosion (pitting/crevice corrosion)

Electrochemical potential differences result in selective crevice or pitting corrosion attack.  Pitting corrosion or crevice corrosion occurs when the chromium-rich passive oxide film on an alloy surface breaks down in a chloride-rich environment (see figure below).  Higher chloride concentrations, more acidic environments and elevated temperatures all increase the likelihood for breakdown of this passive film.




Sour corrosion (H2S corrosion)

The deterioration of metal due to contact with hydrogen sulfide (H2S) and moisture is called sour corrosion which is the most damaging to drill pipe.  Although H2S is not corrosive by itself, it becomes a severely corrosive agent in the presence of water, leading to pipeline embrittlement.  Hydrogen sulfide when dissolved in water is a weak acid, and therefore, it is a source of hydrogen ions and is corrosive.  The corrosion products are iron sulfides (FeSx) and hydrogen.  Iron sulfide forms a scale that at low temperature can act as a barrier to slow corrosion.  The forms of sour corrosion are uniform, pitting, and stepwise cracking.  The figure below is the image of an oil and gas pipeline under sour corrosion.



Stray Current Corrosion

This form of corrosion is similar in concept to that of galvanic corrosion, however the electric current generated is not due to just having dissimilar metals in contact. In this case there is a power source generating the current.  Corrosion can be accelerated through ground currents from dc sources.  Electrified railroads, mining operations, and other similar industries that utilize large amounts of dc current sometimes allow a significant portion of current to use a ground path return to their power sources.  These currents often utilize metallic structures (pipelines) in close proximity as a part of the return path.  This “stray” current can be picked up by the pipeline and discharged back into the soil at some distance down the pipeline close to the current return.  Current pick-up on the pipe is the same process as cathodic protection, which tends to mitigate corrosion.  The process of current discharge off the pipe and through the soil of a dc current accelerates corrosion of the pipe wall at the discharge point.  This type of corrosion is called stray current corrosion.


This was the shaft of a trawler with stray current damage. The smooth scalloping and tiny pores are typical of stray current corrosion in stainless steel.



The erosion corrosion mechanism increases corrosion reaction rate by continuously removing the passive layer of corrosion products from the wall of the pipe.  The passive layer is a thin film of corrosion product that actually serves to stabilize the corrosion reaction and slow it down.  As a result of the turbulence and high shear stress in the line, this passive layer can be removed, causing the corrosion rate to increase.  The erosion corrosion is always experienced where there is high turbulence flow regime with significantly higher rate of corrosion and is dependent on fluid flow rate and the density and morphology of solids present in the fluid.  High velocities and presence of abrasive suspended material and the corrosive fluids in drilling and produced fluids contribute to this destructive process.  This form of corrosion is often overlooked or recognized as being caused by wear.


Stress Corrosion Cracking (SCC)

A particularly detrimental form of pipeline corrosion is known as stress corrosion cracking (SCC).  SCC is defined as the brittle fracture of a normally ductile metal by the conjoint action of a specific corrosive environment and a tensile stress.  On underground pipelines, SCC affects only the external surface of the pipe, which is exposed to soil/groundwater at locations where the coating is disbonded.  The primary component of the tensile stress on an underground pipeline is in the hoop direction and results from the operating pressure.  Residual stresses from fabrication, installation, and damage in service contribute to the total stress.  Individual cracks initiate in the longitudinal direction on the outside surface of the pipe.  The cracks typically occur in colonies that may contain hundreds or thousands of individual cracks.



Over time, the cracks in the colonies interlink and may cause leaks or ruptures once a critical-size flaw is achieved.  In the presence of chloride ions, in a marine environment, certain alloys are susceptible to SCC, or chloride ion-induced SCC.  The chloride ion interacts chemically with the material at the very tip of a crack where tensile stresses are highest, making it easier for the crack to propagate.  This failure mode can destroy a component at stress levels that are below the yield strength of an alloy, and final failure can occur suddenly.  A Transgranular chloride SCC in 304L SS is shown below.



Even though isolated fatigue cracks have been seen since the 1970s, it was the increased appearance of stress corrosion cracking (SCC) defects in the 1990s that led to some spectacular pipeline failures in Russia and North America.  The figure below shows typical SCC colony.




SCC develops in pipelines under narrowly defined conditions. These include: susceptibility of the steel, moisture of the soil, soil chemistry, quality of the coating, variable stress and highly increased temperatures.  SCC first appeared in the above mentioned areas mainly in high pressure pipelines directly downstream of compressor stations and now also occurs more and more often in liquid pipelines, even though these lines do not display increased temperatures.

Apart from SCC, metal fatigue cracks are becoming increasingly common, mainly due to the increasing accumulated number of pressure cycles in the aging pipeline population. 
Corrosion fatigue is a mode of cracking in materials under the combined actions of cyclic loading and a corrosive environment.  Corrosion fatigue crack growth rates can be substantially higher in the corrosive environment than fatigue crack growth under cyclic loading in a benign environment. 


Cracks, which influence the structural integrity of the pipeline, are mainly longitudinally orientated, caused by the predominant stress distribution in the steel.  Fatigue cracks can grow both from the internal or the external surface of the wall. Because of the growth mechanism, SCC cracks are external defects.  For SCC to occur, three conditions must be met simultaneously: the material must be susceptible to SCC; the fluid must be capable of inducing SCC; and a tensile stress must be present that is greater than a critical tensile stress.

Some alloys are considerably more prone to SCC than others, with nickel content playing a major role.  Austenitic stainless steels like 304 (8-10% nickel) and 316 (10-14% nickel) are particularly susceptible.  Carbon steels, nickel base alloys and duplex stainless steels are highly resistant to SCC.

Photomicrograph of chloride-induced stress corrosion cracking in 316 stainless steel (100x magnification).


The two basic types of SCC on underground pipelines that have been identified are classical or “high pH” cracking (pH 9 to 10), which propagates intergranularly (intergranular stress-corrosion cracking – ISCC; it propagates along the grain boundaries), and “near-neutral pH” cracking, which propagates transgranularly (transgranular stress-corrosion cracking).  TSCC is fracture that propagates through the metal grains rather than following the grain boundaries.  Each form of SCC initiates and propagates under unique environmental conditions.  Near-neutral pH SCC (< pH 8) is most commonly found on pipelines with polyethylene tape coatings that shield the cathodic protection current.(5)  The environment that develops beneath the tape coating and causes this form of cracking is dilute carbonic acid.  Carbon dioxide from the decay of organic material in the soil dissolves in the electrolyte beneath the disbonded coating to form the carbonic acid solution.  High-pH SCC is most commonly found on pipelines with asphalt or coal tar coatings.  The high-pH environment is a concentrated carbonate bicarbonate solution that develops as a result of the presence of carbon dioxide in the groundwater and the cathodic protection system.


Sulphide stress cracking

Raw oil can be contaminated with undesirable compounds.  When H2S and large quantities of carbon dioxide (CO2) are present, the unrefined fuels are said to contain ‘acid gas’ because these gases form acids when mixed with water. The term ‘sour gas’ is used for unrefined fuels containing H2S - a very corrosive, toxic and flammable gas.



The requirements for SSC to occur include: a susceptible material; a sufficiently sour fluid (H2S concentration above a threshold); and a tensile stress above a critical level. An increase in the following parameters can contribute to the rate at which SSC occurs: material properties such as tensile strength and hardness; hydrogen ion concentration in the fluid (pH-value); H2S partial pressure; total tensile stress (applied and residual); temperature; and exposure time.

On an atomic scale, SSC is a special case of hydrogen embrittlement. When a susceptible metal surface comes into contact with sour gas, the H2S molecules react to form metal sulphide and hydrogen atoms. The latter diffuse into the material at the tip of the crack at which tensile stresses are highest. Hydrogen diffusion and accumulation in the lattice, on interfaces and on grain boundaries reduce the material’s ability to deform plastically, leading to hydrogen embrittlement that facilitates crack propagation.

In sour environments such as mixtures of oil + seawater + H2S, SCC and SSC can pose a synergistic threat. Crack propagation caused by the chloride ion interaction with the tensile-loaded crack tip may proceed more readily if the material ahead of the crack tip has been embrittled by atomic hydrogen. The term ‘environmental cracking’ describes the synergistic actions of SCC and SSC.


Microbiologically Influenced Corrosion (MIC)

Microbiologically influenced corrosion (MIC) is defined as corrosion that is influenced by the presence and activities of microorganisms, including bacteria and fungi.  It has been estimated that 20 to 30 percent of all corrosion on pipelines is MIC-related.  MIC can affect either the external or the internal surfaces of a pipeline.



Microorganisms located at the metal surface do not directly attack the metal or cause a unique form of corrosion.  The byproducts from the organisms promote several forms of corrosion, including pitting, crevice corrosion, and under-deposit corrosion.  Typically, the products of a growing microbiological colony accelerate the corrosion process by either: (1) interacting with the corrosion products to prevent natural film-forming characteristics of the corrosion products that would inhibit further corrosion, or (2) providing an additional reduction reaction that accelerates the corrosion process.



A variety of bacteria have been implicated in exacerbating corrosion of underground pipelines and these fall into the broad classifications of aerobic and anaerobic bacteria. Obligate aerobic bacteria can only survive in the presence of oxygen, while obligate anaerobic bacteria can only survive in its absence.  A third classification is facultative aerobic bacteria that prefer aerobic conditions, but can live under anaerobic conditions.  Common obligate anaerobic bacteria implicated in corrosion include sulfate reducing bacteria (SRB) and metal-reducing bacteria.  Common obligate aerobic bacteria include metal-oxidizing bacteria, while acid-producing bacteria are facultative aerobes.  The most aggressive attacks generally take place in the presence of microbial communities that contain a variety of types of bacteria.  In these communities, the bacteria act cooperatively to produce conditions favorable to the growth of each species.  For example, obligate anaerobic bacteria can thrive in aerobic environments when they are present beneath biofilms/deposits in which aerobic bacteria consume the oxygen. In the case of underground pipelines, the most aggressive attack has been associated with acid-producing bacteria in such bacterial communities.


MIC corrosion in a steel tank


Mitigation of Corrosion

A good starting point is to reference API RP571 "Damage Mechanisms Affecting Fixed Equipment in the Refining Industry." This recommended practice describes degradation mechanisms found in refineries, affected materials, critical factors used to identify the mechanism, affected units or equipment, appearance or morphology of damage, prevention/mitigation measures, inspection and monitoring recommendations, and related mechanisms.

External Corrosion

Corrosion is an electrochemical phenomenon and, therefore, can be controlled by altering the electrochemical condition of the corroding interface. For external wall surfaces, altering the electrochemical nature of the corroding surface is relatively simple and is done by altering the voltage field around the pipe. By applying a negative potential and making the pipe a cathode, the rate of corrosion (oxidation) is reduced (corrosion is mitigated) and the reduction process is accelerated. This means of mitigating corrosion is known as cathodic protection (CP).

CP is achieved in practice by one of two primary types of CP systems, including sacrificial anode (galvanic anode) CP and impressed-current CP.  Sacrificial anode CP utilizes an anode material that is electronegative to the pipe steel. When connected to the pipe, the pipe becomes the cathode in the circuit and corrosion is mitigated.  Typical sacrificial anode materials for underground pipelines are zinc and magnesium.

Impressed-current CP uses direct current power supplies (rectifiers) at selected locations along the pipeline to supply protective electrical current.  Cathodic protection current is forced to flow in the opposite direction of currents produced by corrosion cells.  The protective current is supplied to the pipeline through a ground bed that typically contains a string of suitable anodes ((cast iron, graphite, platinum clad, mixed metal oxide, etc.), with soil as an electrolyte.  A wire connected to the pipeline provides the return path for the current to complete the circuit, where the pipeline is the cathode and corrosion is mitigated.

CP is most often used in conjunction with a coating.  There are always flaws in the coating due to application inconsistencies, construction damage, or the combination of natural aging and soil stresses.  If left unprotected, corrosion will occur at these coating flaws (holidays). Often the rate of attack through the wall is much higher at the holiday than the general attack of a bare steel surface. The use of a coating greatly reduces the total amount of current required to achieve protection of the pipeline system; therefore, CP and external coatings are utilized together wherever possible. CP can be used to mitigate all types of corrosion previously discussed (general, stray current, MIC, and SCC).

Sometimes it is difficult to determine the level of CP necessary to mitigate the different corrosion mechanisms and to identify which type of corrosion is present. Stress corrosion cracking presents additional problems. First, the high-pH form of SCC is only found on pipelines protected with CP. The products that result from cathodic reactions occurring on the pipe surface during CP in conjunction with soil chemistry produce the environment necessary for high-pH SCC. Since high-pH SCC only propagates in a very limited potential range, maintaining the potential of the pipe surface outside of this range by proper CP control will prevent growth of the high-pH SCC cracks. In addition, it has been established that proper CP control can inhibit the growth of near-neutral SCC cracks.

Internal Corrosion

Internal corrosion is also an electrochemical process; however, CP is not a viable option for mitigating internal corrosion in a pipeline. One of the first defense systems against corrosion for transmission pipelines is to ensure that the product being transported is free of moisture. Dry, deaerated natural gas and moisture-free oil and petroleum products are not corrosive. For corrosion to occur, there must be moisture, CO2, oxygen, or some other reduction reactant, such as one produced by microbes.  Operators typically control moisture, oxygen, and CO2 contents of the transported product, but these constituents can enter the pipeline through compressor or pump stations, metering stations, storage facilities, or other means.  Gathering lines in production fields have a much more significant problem with internal corrosion than the typical transmission pipeline.

Other Modes of Failures
The occurrence of defects on the pipe body can compromise the structural integrity of the pipeline.  These defects can be caused by various situations, including: impact of components that fall or otherwise damaged during rail or marine transportation or handling, excessive bending at the installation phase, superficial cracks formed during the pipeline transportation to the job site, and so on.  Transportation-induced metal fatigue is a failure mechanism for pipe transported primarily by railroad and has also been associated with marine transportation.  This type of fatigue is found along the longitudinal seam weld of the pipe and is caused by the cyclic stresses imposed during transportation as the pipe is subjected to frequent motion.

Internal Inspections

Pipeline companies have a comprehensive program for monitoring the safety of its pipelines.  Multiple inspection tools are used to assess pipeline integrity, including pipeline inspection gauges or "pigs" that perform various maintenance operations on the pipeline.  These tools check for metal loss, cracking and third-party damage, depending on the unique needs of each segment.  Inspections continuously evaluate the pipelines so that every mile of regulated pipeline is inspected on no longer than a five-year rotation.

As part of its rigorous integrity management program, operators conducted integrity assessments on 3000 pipeline segments totaling 120,000 miles during 2013.  Because some segments were assessed multiple times with different technologies and methods, the total number of assessment miles came to 440,000.

In-line inspections enable the pipeline operators to prioritize any necessary maintenance, and can prevent problems from occurring. These inspections are performed by tools called “smart pigs.”  Two of the most common in-line inspection tools are the caliper/bend tool and the metal loss tool. These tools are loaded into the pipeline and are carried through the line by the flow of product. The purpose of running a caliper/bend tool is to measure restrictions and deformations in the pipeline. The metal loss tool is used to detect metal loss along the length of the pipeline.  Both tools have on-board odometers to pinpoint where there may be a problem with the pipeline.


There are many benefits to performing in-line inspections, both to the pipeline operator and to the public.  For the operators, it provides a way to identify and prioritize any required maintenance on the pipeline.  The most important aspect of in-line inspections is safety.  Quite often, these inspections identify situations that may not be a problem now, but if left undetected, could pose a problem in the future.  By performing these inspections on a regular basis, pipelines will continue to operate safely for years to come.

Electro Magnetic Acoustic Transducer (EMAT) Tool - Detects crack-like features in the seam and body as well as coating disbondment


Hydrostatic Testing

A hydrostatic test involves filling a portion of the pipeline with water and using pumps to add additional water in order to pressure test the pipeline for a specified period of time. Hydrostatic testing is used to strength test new pipe at the completion of pipeline installation in the field prior to placing the line in service.Hydrostatic testing is also used for integrity assurance after a line is in operation.

The hydrostatic test establishes the pressure carrying capacity of a pipeline and identifies defects that might affect integrity during operation. Should a defect be discovered, the operators would repair the pipeline and perform the test again.
The purpose of a hydrostatic test is to test the integrity of the pipeline under environmentally safe conditions and to ensure the safe operation of the pipeline, both of which benefits the pipeline company, the public, and the environment.


Evaluations included material specifications, field construction procedures, caliper tool results, deformation tool results, welding procedures including back welding, NDT records, failures or leaks during hydrostatic testing, or in-service operations to identify systemic problems with pipe girth weld geometry.



Our failure investigation services include:

·                     On-site inspection

·                     Laboratory analysis, including chemical analysis and metallography

·                     Mechanical testing, including loads and vibration measurement

·                     Data analysis, including statistical analysis

·                     Reporting

In cases of damage, a conclusive failure evaluation and identification of the primary cause is necessary. The root cause is to be found through a holistic view on the complex interaction between relevant parameters relating to design, production and operation. A laboratory analysis provides valuable help in determining the cause. After all, the damaged component itself provides the only objective record of how the damage occurred, and the information it contains can be coaxed out by applying suitable material examination methods.

Metropolitan’s corrosion scientists are uniquely suited to solve a wide range of complex corrosion problems, because they can couple their own broad expertise with that of our mechanical, civil/structural, electrical, and chemical engineers, as well as statisticians, chemists, and polymer scientists.  As a result, we can provide a comprehensive, integrated approach to complex problem solving.  Working in the consulting, product-development, and litigation-support arenas, Metropolitan assists clients in a diverse range of industries, including pipeline (liquid, gas, water, and other), nuclear and fossil-fuel power generation, mining, marine, aeronautical, chemical processing, pulp and paper, construction, utilities (electric, gas, and water), transportation and infrastructure, electronics and semi-conductors, inorganic and organic coatings (paints), and biomedical.  We investigate construction and transportation accidents, determine the probable causes of the accidents, issue safety recommendations, study construction and transportation safety issues, and evaluate the safety effectiveness of the insured SOPs.  We prepare accident reports, safety studies, special investigation reports, safety recommendations, and statistical reviews.

Our services include:

·                     Consulting and product development

·                     Material selection and compatibility assessment

·                     Field inspections and laboratory examinations

·                     Root-cause failure analysis

·                     Corrosion monitoring and remaining-life estimation

·                     Accelerated life testing

·                     Corrosion susceptibility assessment

·                     Electrochemical and corrosion testing

·                     Performance evaluation of paints and coatings

Types of corrosion investigated:

·                     General or uniform corrosion

·                     Localized corrosion: pitting, crevice, and intergranular

·                     Microbiologically influenced corrosion (MIC)

·                     Stress corrosion cracking (SCC) and corrosion fatigue

·                     Hydrogen embrittlement

·                     Galvanic corrosion

·                     Selective leaching

·                     Erosion-corrosion

·                     High-temperature oxidation, carburization, and sulfidation

·                     Atmospheric corrosion



Metropolitan Engineering, Consulting & Forensics (MECF)

Providing Competent, Expert and Objective Investigative Engineering and Consulting Services

P.O. Box 520

Tenafly, NJ 07670-0520

Tel.: (973) 897-8162

Fax: (973) 810-0440


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