ROOT CAUSES AND
CONTRIBUTING FACTORS OF GAS AND LIQUID PIPELINE FAILURES
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
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.
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).
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.
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
|
||||||||
|
42
|
46
|
52
|
56
|
X60
|
X65
|
X70
|
X80
|
|
|
Tensile
(ksi)
|
0
|
3
|
6
|
1
|
75
|
77
|
82
|
90-120
|
|
Yield
(ksi)
|
2
|
6
|
2
|
6
|
60
|
65
|
70
|
80
|
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 inspection– about 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 OF PIPELINES
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 OF LIQUID & GAS PIPELINES
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.
Erosion-corrosion
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.
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 FailuresThe 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.
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.
METROPOLITAN PIPELINE FAILURE INVESTIGATIONS
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
E-mail: metroforensics@gmail.com
We are happy to
announce the launch of our twitter account. Please make sure to follow us
at @MetropForensics
To unsubscribe from
future technical blogs and announcements, please reply to this email with the
word “unsubscribe” in the subject line.
Metropolitan appreciates your business.
Feel free to recommend our services to your
friends and colleagues.