Learnings

Outcomes

For safe operation of a hydrogen network, the general principles of system isolation for hydrogen and natural gas similar as they focus on managing risk to a level of “As Low As Reasonably Possible” (ALARP). Best practice for the isolation of plant is provided by the Health and Safety Executive (HSE) in Health and Safety Guidance (HSG) 253. 

The guidance leads to the selection of positive or proved isolation methods. It is envisaged that a Double Block and Bleed (DBB) valve arrangement will be used for the isolation of equipment on hydrogen systems during maintenance activities. For any part of the network that will need to be physically isolated, the use of proved isolation, as required, will lead to an overall increase in valve quantities compared to a natural gas network to make the risk ALARP. the increase is partly due to requirement for pressure equalisation lines across larger main isolation valves, increasing the number of small-bore plug valves required for hydrogen compared to the natural gas network.

Any newly designed natural gas transmission system would likely fall into in the same categories and would contain a very similar number of valves. However, when compared to the existing natural gas transmission system, a hydrogen transmission system may see a reduction in overall valve count due to historical site modifications on aged natural gas assets during their operational life, resulting in an increasing valve count over time.

The length of pipework required on each hydrogen site will likely result in 20% to 30% increase in the pipe length than for a natural gas site. The increase in pipework is primarily linked to the larger hazardous areas seen within hydrogen systems. It is also likely that consequence modelling would result in increased distances on site.

As most of the simpler asset sites (e.g. entry point, exit point and multi-junctions) do not have permanent full relief cases and the pressure system is only vented during maintenance activities. As with pipework length, the footprint, roads and boundary fencing will likely be between 20% to 30% larger for the simpler sites to accommodate the larger hazardous areas. This assumes the geographical location of the site and operation procedures allows the manual venting hazardous zones from the maintenance vents to exceed the sites’ boundary fence whilst posing a tolerable risk to the public. 

Compressor stations with permanent vents or flares will have a much larger footprint requirement than a typical natural gas compressor site. The simple hydrogen compressor station is 3.3 times the size of the natural gas reference case, and the complex station 6 times larger than the natural gas reference case. 

The project has provided practical evidence on material requirements that can be found in the main hydrogen design standards as well as in other research and industry references which is aimed to serve as input for future NGT specifications for a hydrogen gas NTS. 

Regarding the material requirements found in both current NGT standards and hydrogen design codes. The following findings can be surmised: 

·       Most hydrogen design standards appear to present a reduction in fracture and impact toughness values as well as hardness requirements for parental and weld material. Higher hardness materials are more susceptible to damage due to hydrogen embrittlement. 

·       Most hydrogen-related publications are interconnected. For instance, IGEM refers to ASME B31.12, which in turn is linked to the EIGA report. Consequently, the material requirements they present are generally similar. In cases where there are differences in acceptance or minimum values, NGT will need to decide which standard to adopt. Given that these standards are still evolving, it seems prudent to initially adopt a conservative value.

Hydrogen is generally compatible with most polymeric materials used in natural gas service according to the literature, though it may increase permeation and leakage rates. This is considered in the acceptance criteria for valves in hydrogen gas service where the shell and seat test duration are doubled, as presented in Annex M in API 6D.

Maturity 
TRL 2-4  
The maturity of the existing uprating process is advanced, consideration for how hydrogen impacts this new process has not been made and therefore the TRL is low at the start of this project but should rapidly increase. 

Opportunity
100% and multiple asset classes including Project Union
The project will cover all of the network routes and Above Ground Installation (AGI)/Compressor station locations and assets on the NTS. 

The project also can be applied to Project Union phasing decisions.

Deployment costs
-
The project is not delivering something that will be deployed on the network.

Innovation cost              
£1,006,729.33
The cost of the innovation includes a desktop study, site visits (travel), reporting and project management.

Financial Saving
-
The project may result in financial savings if the findings can be used to avoid costly changes to NTS assets and configurations however this will not be realised within this work.

Safety
-
The project can be taken forward to update policies and procedures for hydrogen, which will enable safe operation and maintenance of the NTS.

Environment               
-
The project will not have any direct CO2 savings but will help enable hydrogen in the NTS.

Compliance
Ensures compliance
The project will support compliance with relevant safety standards for safe operation of hydrogen network in the future.

Skills & Competencies
Individuals
Individuals directly involved with the project will gain an understanding into the hydrogen networks and current NTS assets designs with hydrogen. 

New tool, skills and competencies will need to be developed across the departments.

Future proof              
Supports business strategy 
The project will help enable hydrogen in the NTS and support the energy transition.        

The project has the potential to influence future decision-making, such as Project Union phasing and RIIO-3 investment to enable NTS network decisions on future hydrogen transmission infrastructure

Lessons Learnt

To enable the design of hydrogen transmission system the following variables need to be defined to this form the basis to how the NTS was designed. These are all generally known due to the network being developed over time. 

·       Where the hydrogen is coming from – this will be dependent on the sources and locations of hydrogen production.

·       How much hydrogen is produced over the entire life cycle of the assets.

·       When hydrogen will be produced – will there be entry diurnal or seasonal production cycles to consider?

·       What will the standard process conditions for network entry. 

·       What will be the demand (diurnal and seasonal) volumes and cycles?

·       Where will the hydrogen demand come from – user type (industrial and/or residential) and locations? 

·       What storage and available pipeline storage (linepack) will be required to manage variations in hydrogen demand from users.

·       Whether to take the prescriptive or performative approach to design (as described in IGEM/TD/1 Supplement 2) for new hydrogen assets and how to ensure compatibility with existing assets. 

All these variables need to be known to design and compare a hydrogen network with the NTS, this will allow a more accurate comparison between hydrogen assets based on the following principles.

·       Comparison of physical differences regardless of energy flows and physical sizing

·       Comparison of hydrogen and natural gas when energy flows are equal and evaluate physical asset differences. 

·       Comparison of hydrogen and natural gas when physical assets are of equal size and evaluate energy flow differences. 

There are two approaches used when designing a pipeline network, the choice of approach taken will influence the wall thickness of the pipeline and consequently lead to greater capital costs. The approaches are references within Institution of Gas Engineers and Managers (IGEM) and the American Society of Mechanical Engineers (ASME) design codes. 

·       Option A – a prescriptive approach which will limit design factors leading to thicker pipeline walls than a comparative natural gas pipeline resulting in higher costs due to more material per unit length.

·       Option B – a performative approach which will lead to less stringent design factors as the material used would have a higher level of quality assurance and testing to demonstrate that the material is suitable for hydrogen service. This will lead to a thinner wall pipe and in theory lower capital costs however the retail price would increase due to the additional costs on the manufacturer due to the associated quality assurance and testing. 

The designers of a hydrogen need to determine which Option to adopt as this will impact the market and Option A is the more conservative approach and the use of Option B needs to be reviewed to gain confidence of the suitability for line pipe. Material manufacturers are starting to produce materials with certification for hydrogen suitability through recognised notified bodies which could lead to a price premium for materials for hydrogen use. 

Depressurisation of a gas network is a critical safety and operational procedure; it is used during maintenance to create a safe environment to allow inspection and repair of the network’s components. It is also used during emergencies to reduce the extent of damage to system. Depressurisation is achieved through (1) venting (2) flaring (3) recompression, venting is the simplest, most cost-effective method and used across the national gas transmission system and therefore used during the project. 

The use of this methods leads to larger hazardous areas around the components and from the vents at the hydrogen sites resulting in larger site footprints to ensure that the hazardous zones are controlled. More research is required to evaluate the other methods. A combination of methods is likely required to ensure hydrogen is depressurised safely and to allow smaller site footprints. For example, flaring could be used in place of venting during planned maintenance and to prevent large releases of gas into atmosphere.  Recompression results in the capturing of gas emissions to allow injection back into the network this would be more in line with decarbonisation and Net Zero targets. It would also minimise the volumes of waste hydrogen released. 

The WP2.10- Material Requirements report provides a guideline and input to be considered for a new hydrogen internal design specifications or could be included as annexes or supplements to existing ones. However, due current lack of specific guidance in comparison to natural gas materials, hydrogen testing certification requirements are not well established, this leads to suppliers and vendors using certified laboratories to test against the acceptance criteria. More information is required on how laboratories comply with the standards in order to inform any new hydrogen gas service requirements for NGT internal specifications and quality assurance until internationally recognised certification is available. 

The following can be done to build on the findings of this project:

·       A more detailed and exhaustive review of current NGT specifications and design standards on a component-by-component basis to identify where hydrogen assets will require different test and acceptance criteria to natural gas assets.

·       More analysis on what standard or values should be used for hydrogen design codes due to the current slight differences between the available hydrogen standards. 

·       A periodical check on new standards and annexes for hydrogen gas service components to ensure the latest requirements and test acceptance criteria is used for NGT hydrogen specifications.