2.1. Brief Description of a Hydrogen Pipeline
2.1.1. Choice of Pipeline Materials
2.1.2. Defects Unique to Hydrogen Pipelines
2.1.3. The Question of Blended Hydrogen Pipelines
2.2. The Effects of Hydrogen on Steels
- In the case of blended hydrogen-natural gas pipelines, before existing gas in the pipeline can be replaced, the feasibility of doing so has to be considered with respect to material fatigue, pipeline failure due to overpressure, and HE . Using nitrided steel or higher grade pipeline steel was also said to improve safety . The effect of coatings, however, needs further study to determine its effectiveness in preventing HE .
3. Pipeline Inspection
3.1. An Overview of Pipeline Integrity Management
- “Defect detection and identification”: This is done through “inspection, monitoring, testing and analysis techniques.”
- “Defect growth prediction”: The data collected is used alongside damage prediction models for this.
- “Risk-based management”: The origins of risks are studied, the likelihood of failure is estimated and the consequences of failure are examined.
3.2. Defect Detection and Identification
3.2.1. Non-Destructive Evaluation (NDE)
Ultrasonic Testing (UT)
Phased Array UT (PAUT)
Time of Flight Diffraction (TOFD)
Guided Wave Testing (GWT)
Microwaves NDE (MW)
Magnetic Flux Leakage (MFL)
Electromagnetic Acoustic Transducer (EMAT)
Eddy Current Inspection (ET)
Radiograhy Testing (RT)
Electromechanical Impedance (EMI)
Infrared Thermography (IRT)
Magnetic Barkhausen Noise (MBN)
Visual Testing (VT)
|UT||“High penetration depth” and can measure internal and external coating as well as wall thickness . Also allows estimation of external corrosion . Has a higher confidence level than MFL .||Requires liquid coupling between transducer and pipeline, making it difficult to conduct ILI with gas pipelines . UT signals also need to be de-noised to obtain valid information .||✓||✓|
|MW||Able to detect and image defects in metals under dielectric coatings . Changes in the thickness of coatings can also be monitored .||Current methods require significant interpretation of data, display unclear “defect geometry”, and have a low “spatial resolution” .||✓|
|MFL||The required resolution can be chosen by varying parameters such as sensor spacing .||Only works well in easily magnetised metals and may cause the pipe to become magnetised indefinitely resulting in product flow restrictions [11,15].||✓|
|EMAT||No need for couplant, making it ideal for gas pipelines . Literature provides validation of EMAT for identifying and sizing SCC cracks and corrosion in gas pipelines .||The transducer needs to be less than 1 mm from the specimen and even so, its “detection ability and efficiency” is lower compared to UT . This could present a challenge for coated pipelines.||✓|
|GWT||Not necessary to remove pipeline coating across the entire area of inspection . Useful as an initial screening method and for SHM [71,74].||Unable to detect defects oriented along the length of pipe and there is a trade-off between range and resolution .|
|EC||Responsive to a variety of parameters and usable over a wider temperature range . It is also lightweight and cheap to deploy .||Can only be used on materials that conduct electricity, is highly dependent on “lift-off distance” and is unable to detect “external defects” through the pipeline wall [11,15].||✓|
|RT||No preparation of the surface is necessary and the insulation does not have to be removed before inspection .||Potential danger from radiation to living things nearby .||✓|
|ECIT||Non-contact and capable of “sub-millimetre/millimetre crack” detection .||Possibly necessary to paint the specimen to improve its “optical properties” and obtain better sensitivity .|
|EMI||Sensitive to localised corrosion and suitable for SHM of pipes .||Currently only demonstrated to work for stainless steel plates .|
|IRT||Could be incorporated with technology such as drones to quickly inspect large sections of the pipeline for CUI .||Ability to detect CUI depends on the temperature of the pipeline and how close water is located to the surface .||✓|
|MBN||Able to detect microstructure and stress present in materials quickly without any harm to the operator .||Challenging to find “a consistent behaviour of the MBN signal”. The signal “can only be picked up near the surface of the materials” .|
|VT||Operation is cheap and simple . Could potentially be automated .||Highly dependent on the operator and only suitable for defects on the surface .||✓||✓|
3.3. Prediction Models
- “Single-value corrosion growth rate model”: Utilises a corrosion growth rate that is constant for modelling over the required period.
- “Linear corrosion growth rate model”: Assumes corrosion growth is a linear function of time.
- “Non-linear corrosion growth rate model”: Assumes corrosion growth is a non-linear function of time with soil and pipe material being parameters that can be controlled.
- “Markov model: Uses a “continuous-time, non-homogeneous linear growth approach” using “initial pit-depth distribution” and a “soil-pipe dependent parameter”.
- Monte-Carlo Simulation: Mathematical models of the specimen are solved a large number of times to obtain a “distribution of alternative possible values about the nominal point”. This is commonly used to determine the uncertainty of a “deterministic calculation”.
- “Time-dependent generalised extreme value distribution”: Uses the corrosion rate distribution of a “generic textural soil” that varies with time.
- “Time-independent generalised extreme value distribution”: Uses the corrosion rate distribution of a “generic textural soil” that does not vary with time.
- Gamma process: A continuous probability distribution that is dependent on a scale and shape parameter. An assumption that is inherent with the Gamma model is that the defects are detectable by ILI tools.
- “Brownian motion with drift” model: Treats corrosion as a “stochastic process independent increment”. The model suits processes that has alternating increases and decreases and is thus ideal for corrosion due to its alternating “active and passive” behaviour.
4. Evaluation of Current Pipeline Inspection Methods for Hydrogen Pipelines
4.2.1. Effectiveness of Coatings
4.2.2. Monitoring Coating Health
- The “Copper-Hydrogen embrittlement test”
- The “inclined wedge method” to test for residual embrittlement
- The “incremental step loading method” to test for hydrogen embrittlement threshold
4.2.3. The Effect of Coatings on the Choice of Inspection Method
- Thickness of coating: The distance between the sensor and metal surface due to the coating layer (known as lift-off) reduces the sensitivity of inspection . The lift-off itself may vary due to the uneven thickness of the coating, complicating matters further . This is likely to affect inspections of pipeline conducted using EC due to its dependence on lift-off .
- Conductivity of Coating: Coating conductivity may again interfere with methods such as EC . Additionally, since MFL works best in metals that are easily magnetised, if the coating possesses this property, it may interfere with MFL inspections of the pipeline.
5. Novel Inspection Methods
- A new method for validating GWT that “enables the operator to combine the ability of FE analysis to predict the signals reflected from a large number of different defect cases with the complex geometric and environmental effects specific to the particular pipe structure which cannot be effectively simulated” . This method can be extended to methods other than GWT .
- A new method for characterising pitting resistance: “ultrasonic relative attenuation coefficient of high-order cumulant” is used to reduce Gaussian noise and tease apart noise caused by changes to the microstructure during corrosion . This finding can then be used for characterising pitting resistance .
- A new “state-of-the-art” method for monitoring corrosion using permanently installed transducers is proposed that results in “repeatability values of 23 nm and 46 nm in the thickness measurements of a mild steel sample over the periods of 1 h and 24 h ”.
- A new method uses electromechanical impedance to track corrosion-induced thickness loss . A piece of PZT (lead zirconate titanate) is attached to a steel plate and, “using the direct and converse piezoelectricity effect of the PZT transducer, the discrepancy in the mechanical impedance of the stainless steel plate caused by corrosion can be identified by the discrepancy in the admittance signature of the PZT transducer ”. The method was found to differ in its measurement of corrosion degrees, from actual corrosion by a maximum of 4.11% .
- A new method for simultaneous crack detection and thickness measurement using a single probe is discussed . It was found that “crack-like defects with depth 0.3 mm (0.2) or higher can be detected” but the “amplitude drop value cannot be used to estimate the size of defects of 3mm depth or larger ”.
- The use of water immersion UT allowed coating thickness to be measured with a lower degree of error. In particular, the time-of-flight (TOF) of the “reflected echo on the time-domain waveform” was determined . Although this will require further study, it has been theorised that this could be adapted to other types of coating materials in water . An interesting extension to this study would be to determine if this could be deployed in-line.
6. Possible Areas of Future Research
6.1. Risk Assessment of Natural Gas Pipelines
6.2. Inspection of Coating Pipelines
6.3. Investigation of properties of pipelines steels
- Hydrogen damage is a known issue, and it is difficult to detect.
- Coatings are used to mitigate corrosion, however, attention must be given to the type of coatings used. In hydrogen pipelines, the coatings currently in use do not stop hydrogen from permeating the steel surface.
- Inspection methods are available to evaluate hydrogen damage, each with its associated advantages and disadvantages. The choice of an inspection technique is dependent on the application environment and required accuracy among other factors.
- SHM is a desirable method, but finding a suitable SHM technique is challenging and needs to consider not only the technical requirements but also cost (both capital and operating expenditure).
Institutional Review Board Statement
Informed Consent Statement
Data Availability Statement
Conflicts of Interest
|PEM||Proton Exchange Membrane|
|FCEV||Fuel Cell Electric Vehicles|
|LOHC||Liquid Organic Hydrogen Carriers|
|HIC||Hydrogen Induced Cracking|
|SSCC||Sulphide Stress Corrosion Cracking|
|SOHIC||Stress Oriented Hydrogen Induced Cracking|
|HALP||Hydrogen-Affected Localised Plasticity|
|HELP||Hydrogen Enhanced Localised Plasticity|
|MFL||Magnetic Flux Leakage|
|ET||Eddy Current Testing|
|HSC||Hydrogen Stress Cracking|
|SSC||Stress Corrosion Cracking|
|HIBC||Hydrogen Induced Blister Cracks|
|ECM||External Corrosion Monitoring|
|PAUT||Phased Array Ultrasonic Testing|
|TOFD||Time of flight Diffraction|
|GWT||Guided Wave Testing|
|GMT||Guided Microwave Testing|
|EMAT||Electromagnetic Acoustic Transducer|
|MBN||Magnetic Barkhausen Noise|
|CUI||Corrosion Under Insulation|
|CZM||Cohesive Zone Modelling|
|TSL||Traction Separation Law|
|PZT||Lead Zirconate Titanate|
|PEC||Pulsed eddy current|
|MECT||Movement-induced Eddy Current|
|ECIT||Eddy-current Induced Thermography|
|SHM||Structural Health Monitoring|
|IQI||Image Quality Indicator|
|HEE||Hydrogen Environment Embrittlement|
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|Reference||Defect||Description & Cause|
|1||Hydrogen Induced Cracking (HIC) ||HIC occurs when hydrogen recombines in the steel to form gaseous molecules in voids .|
|2||Hydrogen Stress Cracking (HSC)/ Stress Corrosion Cracking (SCC) ||Occurs at surface or near-surface . Forms as a result of tensile static load and a corrosive medium being present together .|
|3||Hydrogen Induced Blister Cracks (HIBC) ||Occurs when the pressure exerted by molecular and atomic hydrogen in the material is high enough to form blisters .|
|4||Stress—Oriented HIC (SOHIC) [8,16]||SOHIC is also known as Type I SSC and occurs when HIBC is parallel to the applied stress .|
|5||Hydrogen Embrittlement (HE) ||HE is the result of hydrogen entering the steel either during manufacturing or due to exposure to hydrogen during service. This manifests in the form of deteriorated mechanical properties [14,15].|
|Hydrogen Level in Pipeline||Overall Risk Level|
|Less than 20%||“Not significant”|
|20% to 50%||“Significant increase” in overall risk for service lines but the overall increase in risk in distribution mains is “moderate”|
|Greater than 50%||Impermissible level of overall risk|
|GHG (greenhouse gas) emissions are lowered if hydrogen is produced from sustainable energy sources ||Blending hydrogen into a methane pipeline could lead to a higher occurrence of “over-pressure, explosions, leakage and cracking ”|
|Replacing conventional diesel fuel with hydrogen (in fuel cells) for transportation could reduce emissions of sulfur dioxides and nitrogen oxides and improve air quality ||The presence of hydrogen means that it can interact with pipeline steels and cause HE |
|The hydrogen-natural gas mixture, used as is for heat and electricity generation, is a cleaner fuel than pure natural gas ||Existing pipelines need to be modified by removing “undesirable parts,” replacing valve fittings and ideally coating the pipeline internally to allow hydrogen to be transported at high pressures |
|The cost of re-purposing NG lines for hydrogen transportation is significantly lower than building a new hydrogen line ||Operation of hydrogen lines requires thrice the compression power of NG lines and is more expensive |
|Obtaining relevant approvals and ensuring compliance with procedures would mean that a new hydrogen pipeline would take 5–7 years to complete from initial planning to commission ||Retrofitting “turbo-compressors” to handle gas with a volumetric hydrogen content of more than 40% is not possible as yet |
|Pipeline Material||Material Properties||Mechanical Properties||Blended Pipeline Suitability||Processing Conditions||Environmental Conditions||Testing & Analysis|
|Super Duplex Steel||-||-||-||-||[68,69]||-|
|Use non-destructive testing (NDT) to determine condition of a structure|
|Using readings taken by removable transducers and instruments to assess the integrity of structures||Readings are usually taken by permanently attached instruments and transducers|
|Usually conducted when machines are not in operation and measurements are irregular||Regular measurement during operation|
|Defect||ASME B31.12||BS 7910|
|Fatigue Crack||Refer to API 1104||Clause 8|
|UT||HIC, HSC, HIBC, SOHIC ||UT tools can detect, with a 95% confidence level, the affected area with a tolerance of ±0.3 mm to ±0.6 mm. However, the requirement for coupling means this would be difficult to do in-line |
|EMAT||HIC, HSC, HIBC, SOHIC ||Isla and Cegla  describes an “8-element EMAT phased array” at an operating frequency of 1 MHz being able to detect defects with a width of 0.2 mm and a depth of 0.8 mm present on the opposite surface of the array.|
|RT||HIC, HSC, HIBC, SOHIC ||The choice of an image quality indicator (IQI) and subsequent processing will determine the sensitivity of the RT conducted . The smallest IQI appears to be 1mm in diameter. |
|MFL||“Metal loss” (e.g., corrosion) ||Statistical analysis of MFL data to obtain defect shape parameters can reach up to 90% accuracy for length, 84% for width and 78% for depth . Niese et al.  describes combining EMAT, MFL and EC to accurately measure the wall thickness of a specimen and determine the location of metal loss in the wall of the specimen. However, the sensitivity of this method is not discussed.|
|Type of Coating||Description|
|Metallic coatings [102,103]||Electroplating high strength steels with cadmium (Cd) or zinc (Zn) can act to mitigate corrosion . However, this process can cause hydrogen to enter the steel; hence, the specimen needs to be put through de-embrittling’ by heating for about 8 to 24 h to enable “diffusible” hydrogen to leave the metal . In the case of 304 austenitic stainless steel, aluminium (Al), copper (Cu), nickel (Ni) and Zn were electroplated onto the specimen with differing degrees of success . Zn and Ni, for instance, were found to be ineffective at protecting the underlying steel against HEE (Hydrogen Environment Embrittlement) . These coatings were found to have fractured at “very low strains” in tensile testing, causing the specimen to come into into contact with hydrogen, resulting in the initiation of HEE . Cu appeared to be the more successful coating—with commendable tensile ductility, and adhesion . However, parts with improper coating and “pinholes” were found to act as points of failure for the coating .|
|Non-metallic coatings [102,103,104]||Coatings made of compounds were found to have significant utility. Black oxide is shown to lower the ingress of atomic hydrogen into steel and slow down the formation of surface cracks arising from lubricants . Aluminium consisting of MAX phase coatings was also found to be functional as a “protective coating” at high temperatures . NiP and Ti-DLC coatings were found to have the same problems seen in “on top” coatings of metals: cracking was seen at low strains, and hydrogen could come into contact with the specimen being protected . Categorised as “hard coatings”, compounds such as TiC, TiN, BN, TiO2 and WC are able to act as effective barriers against hydrogen ingress . However, their effectiveness is dependent on “service conditions”, the presence of defects in the coatings and structural integrity of the coatings .|
|Metallic Coatings||Non-Metallic Coatings||All Coatings|
|Subject of Inspection: Pipeline||As explained earlier, if the coating is conductive, it could interfere with EC inspections of the pipeline . The same is likely to be the case for MFL inspections if the coating is easily magnetised. There appears to be a gap in literature regarding inspecting pipelines with metallic coatings.||If the coating is dielectric, MW testing can be considered .||A traditional UT inspection of the pipeline material would be hard to perform due to multiple material surfaces and the need for coupling . Non-contact ultrasonic techniques have been developed, but these have their own limitations . For instance, laser ultrasonic requires the sample to have a finish surface “like a mirror” while capacitive ultrasonic transducers involve a complicated sample preparation process .|
|Subject of Inspection: Coating||Traditional UT relies on a change in acoustic impedance to make thickness measurements . Hence, inspection of coatings using traditional UT is likely to produce stronger signals if the pipeline material and coating have differing acoustic impedance.||Traditional UT could potentially be used for thickness measurements of the coating . Techniques that such as MFL will not work for insulators . There is a potential for holiday inspection to be used for insulator coatings .||Visual inspection would be applicable for all types of coating but is subjective .|
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