Most gas pipelines are used for transporting and distributing natural gas from gas fields to consumer installations and homes. This gas is extracted from rocky reserves occurring deep beneath the surface of the Earth. The main chemical ingredients present in natural gas are hydrocarbons such as methane, pentane, butane and ethane, as well as some impurities. In spite of the presence of corrosive contaminants, natural gas is considered a clean-burning fuel as it contains the lowest amount of pollutants.

Contaminants in natural gas include oxygen, chlorides, carbon dioxide (CO2), hydrogen sulfide (H2S), water vapor, sulfur dioxide (SO2), carbonyl sulfide, carbon disulfide (CS2), sulfur trioxide (SO3) and sulfur mercaptan. Each of the sulfur compounds is highly corrosive to metals and some nonmetals. For example, hydrogen sulfide attacks most metallic pipelines as well as some plastic pipes. The minimization of impurities can reduce the rate of corrosion damage of pipes.

After it is extracted from the underground reservoir, raw gas is processed and purified to some extent. During processing, it is purified by removing some of the acidic gases like hydrogen sulfide as well as carbon dioxide. Amine treatment and polymeric membrane treatment are the most popular cleaning processes. Later, the elemental sulfur particles are removed by the Claus process. Moisture removal occurs during the triethylene glycol process. New technologies have been developed for removing corrosive contaminants more effectively. The quality of final gas output depends on the cleaning technology used and the operational efficiency of the processes.

Factors Affecting the Internal Surfaces of Gas Pipelines

An electrochemical reaction leading to internal corrosion in gas pipelines can take place when the internal surface is exposed to moisture, forming electrolytes along with contaminants such as chlorides, CO2, sulfur compounds and oxygen. Stray electricity due to nearby electric cables can also cause or aggravate the corrosive reactions and cause corrosive pit formation on internal surfaces.

The severity of the corrosion damage depends on:

  • Concentration of individual contaminants
  • Certain dangerous combinations of these corrosive contaminants
  • Gas velocity and pressure levels
  • Temperature
  • Gas leakage as well as seepage of moisture and air from pipe joints due to low pressure in pipelines whenever gas supply is stopped

The temperature and velocity of natural gas play a decisive role in causing the chemical and electrochemical reactions that result in corrosion damage. However, even some of the microorganisms colonizing on the wall of the gas pipe have been found to be the causative factors in many cases. Bacterial activity, which is fed by hydrocarbon nutrients and moisture, produces organic acids and acidic gases, which corrode internal metallic surfaces.

Fire and Explosion Hazard Prevention

Gas pipe explosions have been reported in almost every country, as they could occur anywhere along the length of natural gas pipelines. Gas leaks, oxygen and the presence of an ignition source are the essential conditions of fire and explosion. Older gas pipes are at a greater risk due to gas leaks at the site of internal corrosion. Another possible cause of leaks is pipeline damage due to unauthorized digging or natural disasters like a landslide.

Sources of ignition include:

  • Friction during grinding and chipping, causing spark generation
  • Gas cutting or welding
  • Open flames such as candles or lanterns
  • Electric arc while turning a switch on or off
  • Static electric charge

Gas distributors adopt different types of preventive and corrective measures for safety and fire prevention for gas pipelines, including:

  • Fire prevention at design and layout stages by complying with the latest global standards
  • Automatic supervisory control and data acquisition (SCADA) control of critical gas flow and other operating parameters
  • Gas leak detection and smoke detection systems
  • Heat detection and fire detection systems
  • Corrosion detection and pipe wall thickness monitoring
  • Automatic water sprays and other firefighting equipment and systems
  • Multi-level emergency plans, evacuation plans and compliance with EHS regulatory requirements
  • Local-level public awareness training, mock drills and audits

Detecting Internal Corrosion

Corrosion of internal surfaces of a natural gas pipeline can be detected by many different techniques, such as:

  • Visual inspection of the inside surface of the gas pipe after it is opened
  • Measuring the wall thickness of the pipeline externally by using specific instruments
  • Critical examination of corrosion coupons installed
  • Examination of probes installed in the gas pipeline
  • Using in-line monitoring or examination tools to inspect the pipe and to mark the spots of metal loss, pitting corrosion and rust formation

Gas distributors make efforts to minimize the internal corrosion of pipelines by controlling variations in pipeline operating parameters as well as by adopting corrosion protection systems.

Gas Quality Control

Risk of internal corrosion of the gas pipe is minimized by reducing the contaminants in the gas entering the inlet of the pipeline. Efforts are made to enforce strict quality control standards. Gas samples are analyzed on fixed intervals, and solids and liquids taken from the inside of pipelines are also checked for corrosive substances such as sulfur compounds and bacteria.

Monitoring natural gas pipelines is both complicated as well as expensive, as the pipelines are spread out through the length and breadth of the U.S. Sampling and investigation, as well as manual inspection, costs billions of dollars per year.

Moisture in the gas, as well as its ingress at pipe joints, greatly influences the onset of corrosion. It dissolves sulfur compounds and chlorine compounds. If the corrosion begins, on average the pipeline thickness is reduced by almost 2 mils annually, but in many cases corrosion occurs much more rapidly. Moisture can accumulate at bends, pipe joints and low-lying zones where corrosion damage can progress much faster. Over the years, the corrosion eats away the thick wall and pipes can rupture at various spots, causing gas leaks followed by fire as well as explosion.

Monitoring Techniques

In order to comply with the Pipeline Safety Improvement Act (PSIA), gas distributors depend on different investigations and surveys conducted by independent inspection and monitoring agencies.

The detection and monitoring of gas pipelines for internal corrosion is done by:

  • In-line detection techniques
  • Intrusive techniques
  • Non-intrusive techniques
  • Combination system comprising both intrusive and non-intrusive systems

In-line Inspection
Inline inspection involves smart pigs, or sensing devices placed inside the gas pipelines at special entry points. These get carried by the gas flow along a certain length of the pipe. If the pigging of the pipes at the time of initial construction is not planned, it can require costly modification at a later stage.

Certain sensors are able to measure properties of pipeline contents indirectly from the outside. Acoustic techniques are used to measure a pipeline's wall thickness from the outside. Certain devices can measure the noise produced by corrosion products from the outside of the pipe.

Intrusive Techniques
Intrusive techniques include:

  • Corrosion coupons along the length of pipeline
  • Probes that measure electrical resistance

The coupon is comprised of a strip of metallic substance having the same composition as the pipeline material. Its initial weight is recorded and weight loss is monitored at a predetermined interval by removing it and weighing accurately. Weight loss points to the onset of corrosion and its progression. However, obtaining access for its examination is an important limitation in difficult terrains, as corrosion often occurs in spots of difficult access. The safety of inspectors in examining these coupons is also a critical issue. Probes used for measuring resistance suffer from similar limitations.

Non-intrusive Techniques
Ultrasonic devices are the most popular non-intrusive systems. Pipe thickness is measured by applying a voltage to the outer metallic surface of the pipe, across a piezo electric crystal, generating a sound wave in the ultrasonic band. The time required for travel of the wave through the metal and back to the device is indicative of the pipe thickness. This method is safe for the inspector, but it involves digging to get access to the top surface of the pipe. It may fail to detect the onset of corrosion at an early stage.

Combination Techniques
Some companies offer a combination of an ultrasonic system and an electrical resistance device. Others use an instrument transducer, which is mounted permanently on the pipeline along with a handheld device carried by the inspector for recording the changes in wall thickness based on transducer indication. This system can be operated by maintenance technicians checking the cathodic protection system, thus saving on the manpower required.

We need to progress toward real-time monitoring, which is comprised of permanently installed probes, transducers collecting signals from probes continuously, and data-logging devices that highlight changes in wall thickness and the rate of metal loss.

Protective Coatings for Gas Pipelines

Along with cathodic protection, an anti-corrosion coating provides the best practical preventive measure against explosions and corrosion damage of the asset. Coating is a critical component of natural gas pipelines, conveying gas from the field to homes and industries. Both internal coatings as well as external coatings work in tandem with cathodic protection to ensure the safety and economical operation of pipelines in the long run.

Internal surface coatings also contribute to the hydraulic flow efficiency of the gas pipelines along with the mitigation of metal loss due to corrosion. Advanced plastic coatings used on the internal surfaces of pipes ensure a lower surface roughness as compared to the surface of the metallic pipes they protect. Friction encountered by gas during the flow is reduced due to coating, and there is energy-saving in driving gas compressors. When pipes are stored outside temporarily before installation, internal coating provides the necessary temporary corrosion protection.

Surface Preparation

The longevity of internal coating of gas pipes depends on the quality of surface preparation. Steps involved in surface preparation include:

  • Chemical (phosphoric acid) cleaning
  • Thermal cleaning
  • Internal grit blasting (which also reduces risk of stress corrosion cracking)
  • Surface curing

During these steps, the removal of mill scale and other deposits from the inside surface is ensured. For the hydraulic testing of pipes, chemically treated water is used so as to inhibit corrosion and the growth of bacteria—at least temporarily.

Selection of Coating Material

Factors to be considered during the selection and design of coatings include:

  • Mechanical properties of coating
  • Susceptibility to damage during pipe handling for installation and repair
  • Soil chemistry
  • Compatibility for in-situ joint coating
  • Pipeline operating conditions such as flow velocity, pressure changes, temperature
  • Compatibility with cathodic protection selected

Popular coating materials used today include:

  • Liquid epoxy and fusion bonded epoxy (FBE)
  • Polyolefins
  • Polyesters
  • Polypropylenes
  • Polyethylenes
  • Butyl rubber

Different nanomaterials are also mixed with the resins to enhance the anti-corrosion properties.

Fusion Bonded Epoxy (FBE)

Today’s gas pipelines are mostly coated with fusion bonded epoxy. This coating requires adequate surface preparation to ensure strong long-term adhesion to the pipe surface.

Key advantages of FBE coatings for gas pipes include:

  • Excellent physical properties such as flexibility
  • Fatigue resistance
  • Cavitation resistance
  • Thermal capability
  • Erosion resistance
  • Slip resistance

These coatings ensure superior adhesion to steel surfaces even in hostile environments, and can withstand heat of up to 230°F (110°C).

FBE is available in powder form. It is charged electrostatically, to enable it to attract and adhere to the heated surface of the grounded metallic pipe. The pipe is heated and maintained at 465°F (240°C) using the induction heating elements, ensuring that the powder has enough time to melt, spread and crosslink on the surface.

The most common gas pipeline coating systems are:

  • Single FBE layer
  • Dual FBE layer
  • Three-layer system: FBE with polyolefins or butyl rubber

Single FBE Layer
FBE in single layer is coated with a thickness of 400 to 700 microns. It has a single layer of FBE powder coating made of thermosetting pit, and adheres to cleaned and roughened pipe surfaces with excellent bond strength, flexibility and toughness.

FBE application is totally solvent-free. It has inherent chemical resistance, but cathodic disbondment can occur in rare cases. FBE is also highly compatible with cathodic protection. It has low permeability for oxygen.

Dual FBE Layer
Dual-layer FBE is comprised of a bottom anti-corrosion layer of FBE with strong adhesion, with a top layer designed and formulated with fillers and FBE with heavy duty impact-resistance, cavitation resistance, abrasion protection and gouge protection.

Normal dual FBE layer coatings for gas pipes may have thicknesses varying from 550 microns to 850 microns. For heavy duty piping, the thickness may go up to 1050 microns.

Three-Layer FBE Polyolefin System
The three-layer polyolefin FBE coatings can have a thickness ranging from 1275 microns to 3000 microns for moderate to heavy duty applications.

The system includes:

  • FBE bottom adhesion layer (150 micron thickness) with strong adhesion to metallic substrate
  • Bonded polyolefin mid layer (125–150 micron thickness) with superior flexibility
  • Top polyethylene or polypropylene layer for high-temperature and moisture-resistant applications. For higher temperatures and offshore applications, polypropylene is more appropriate. The high-density polyethylene top layer provides toughness as well as reduced permeability for oxygen penetration and moisture penetration.

Coextruded Three-Layer Tapes
Two-layer tapes have many disadvantages when compared with the superior self-amalgamating type of coextruded three-layer tapes as coatings. These three-layer tapes contain a stabilized carrier film of polyethylene, covered with an adhesive of a butyl-rubber material on the top and bottom of the layers. Adhesive layers, used in between the layers of three-layer coextruded tapes with carrier films, provide seamless adhesion without any clearly marked interface between the adhesive layer and the intermediate carrier film. These tapes are wrapped in spirals inside and outside the pipe, forming a homogeneous seamless sleeve coating on the metal substrate. The layer of butyl rubber will self-amalgamate in the interface area, producing an impermeable sealed pipe.

Some Limitations of Coating Materials

Normally, a polyethylene top layer restricts the application to temperatures between -4° and 175°F (-20° and 80°C). On the other hand, the polypropylene top layer makes it suitable for temperatures of up to 220°F (105°C). Specially formulated, high-temperature single and dual-layer FBE can be used up to 285°F (140°C) under dry conditions, while a normal FBE coating is used from -22° to 175°F (-30° to 80°C).

As in the case of a dual-layer PVC-PE system, the PVC layer can fail due to its brittle nature as it loses its plasticizer due to aging. Disbondment from the steel surface can start early in such cases due to the loss of adhesive strength. This can result in thelocalized corrosion of steel pipes.

Even the polyethylene with butyl rubber dual-layer coating can fail due to the loss of adhesive in the carrier film, and disbondment can begin gradually. This can result in the risk of moisture penetration with oxygen to the steel surface, causing the onset of a corrosive reaction.

Field Coating vs. Factory-Produced Coating

Facilities available at factories ensure that factory coatings are produced under standard conditions and automatic controls ensure a high degree of reliability. However, if a coating has to be applied on site, the surface preparation, coating, curing and other steps involved need skilled manpower, inspection, equipment and site supervision. Some amount of coating for joints and repair work may have to be done at the worksite invariably. The reliability of the system in such cases would depend on the quality of work done at the site, which acts as the weakest link in the system. The storage of coating material on site, under adverse conditions, is also very challenging. Taking care of EHS concerns on site needs adequate planning.


As a significant proportion of gas pipeline fire disasters are caused by pipeline damage due to corrosion, it is worthwhile to design pipelines to minimize corrosion and to ensure minimal contaminants in the gas. The use of anti-corrosion coatings, along with cathodic protection and the continuous monitoring of pipelines, can further strengthen the corrective and preventive measures required to be followed.