Learnings

Outcomes

Key Outputs

 • Completion of the 5% hydrogen flow test as detailed in the Master Test Plan, including launch and close-out events.

 • Identification of future test requirements as a result of the findings. 

• Results collated, documented and validated for impact on next phases of hydrogen development activities.

For repurposed electrical, instrumentation and mechanical assets, the main aim of the testing was to gain all evidence determining the relationship of the 5% hydrogen blend with repurposed assets that have already seen many years of natural gas service. The evidence required includes researching: 

• Any changes to the operations of the two flow control valves situated on the FutureGrid site, specifically open and close times of the valves and any changes in power gas control. The process contains one 18” Mokveld flow control valve from the ex-Enron Billingham ICI Above Ground Installation site and one 8” Neles control valve, from the ex-Sellafield site. 

• How 5% hydrogen interacts with pressure reduction equipment, this was carried out using the ex-Hays Chemicals pressure reduction skid. The skid comprises of two Pietro Fiorentini pilot-controlled regulators with incorporated slam-shut overpressure protection devices, two further pilot-controlled pressure-reducing regulators and two pressure relief valves to protect against over-pressures. 

• For evidence, maintenance activities including inspections to be conducted as per policies and procedures carried out by trained and competent personnel as determined by DNV and the original equipment manufacturers’ instructions. This includes testing of all equipment. Testing includes equipment response times, testing for gas leakage, ensuring consistent equipment control accuracy, and determining safety device pressure variations from predetermined set points. This is to ensure no changes as to what is deemed as acceptably safe on the transmission network today. 

• For evidence of boiler operation, maintenance, inspections and reviewing operating procedures as determined by National Gas and the original equipment manufacturer. This includes testing all equipment, ascertaining response times, checking for gas leakage, checking for increased levels of hydrocarbons, ensuring accurate and precise pressure control and checking to ensure safety device pressure variations are still within acceptable tolerances as found today on the natural gas transmission system. The aim of the evidence obtained will be used to closely analyse differences in gas consumption, thermal efficiency, and any concerns with any newly found or existing defects, through conditions such as existing internal corrosion and the effects that hydrogen may have. Standard service checks consist of inspecting the pilot light and the boiler flue, checking for correct gas pressure and gas flow, ensuring all electrical controls remain unchanged between natural gas and operating with a 5% hydrogen blend. 

• How effective at sealing 5% blends the mechanical isolation valves are that are commonly found on our network. This is done through a mixture of Cameron ball valves, Robert Cort ball valves, Audco plug valves and small bore Oliver valves that make up the main majority of the valves within the process. Evidence including to check the sealing capability of the valves seats with the additional 5% blend of hydrogen, as per National Gas Transmissions’ procedures and original equipment manufacturers’ instructions. Noise assessments are also to be undertaken to determine if there are any noticeable increases in decibels when venting sections of pipeline or ball valve cavities from the baseline data.

 • Changes to behaviour of high-pressure vessels, filter strainer/elements which are used to protect downstream equipment from contaminants within the pipeline. Analysing changes in differential pressures at different flows, and the effects of hydrogen on the filter housings and elements. • Vibration analysis to be undertaken for operating with natural gas and 100% hydrogen

Value tracking  

Data Point                                

Maturity                       

TRL4-5                                                 

NIA project for testing 5% hydrogen blend testing on the FutureGrid facilitiy

Opportunity                 

100% & multiple asset classes

This project has created additional knowledge and understanding of how the characteristics of 5% hydrogen blend will impact our network operations. 

Deployment costs                   

£0

No. This is being conducted as an extension to the FutureGrid NIC project. 

Innovation cost                        

£ 344,469                                             

Cost of innovation project 

Financial Saving          

£48,100,000
The benefits forecasted below were guaranteed to be achieved following the successful completion of commissioning activities on the FutureGrid hydrogen test facility, hydrotest and more recently embarking on the 100% natural gas test in the test facility. All of these drives the project towards realising the 2 key benefits below and furthermore enabling opportunities for future phases to develop learning further. The first is the benefit of conducting the 5% hydrogen blend test during the FutureGrid Phase 1 NIC test programme, compared to completing it separately. This delivers a clear cost saving in the short term. In addition, there is the wider benefits case associated with the completion of the full FutureGrid Test Programme which is further unlocked by this project.

Cost savings from conducting the 5% hydrogen blend test as part of FutureGrid Phase1:

£815k cost to carry out 5% blend test separately to the FutureGrid Test Programme under Phase 1

£345k cost to carry out 5% blend test as part of the FutureGrid Test Programme under Phase 1

£470k direct consumer saving, achieved once the 5% blend test is completed as part of the FutureGrid Test Programme under Phase 1

Unlocking the benefits are associated with the FutureGrid Phase 1 Programme

The key financial benefits of the FutureGrid programme of works are the following:

- Method 1 – Creation of world leading Net Zero test facility as a focus for hydrogen testing: In order to gather the required understanding and knowledge of how a hydrogen NTS would operate, a number of the different types of assets and tests we would need to carry out could either all be completed separately or combined on a single test facility. This projected benefit saw £20.5m saved against the cost of conducting all eligible tests separately.

- Method 2 – Avoiding valve replacement as part of work to connect industrial clusters: Currently the most likely scenario for hydrogen transition and adoption will be at industrial clusters. The NTS will be used to join several clusters together by 2040, the plans of which are being developed in detail under Project Union. To facilitate this, safety critical assets such as valves would all need to be replaced for hydrogen operation if they are not proven to be compatible to operate safely in hydrogen blends up to 100%. FutureGrid unlocked this opportunity to prove this compatibility, with projected benefits of avoiding a proportion of valve replacement being at least £46.5m.

Safety              

0%                                           

N/A

Environmental             

81,000,000 tonne of carbon emissions                            

FutureGrid also presented an opportunity to reduce carbon emissions, with a total of 81m tonnes of carbon emissions expected to be avoided:

· Unlocking the opportunity for the NTS to convert to 100% hydrogen by 2050: we have assumed a linear reduction in demand towards 2050 as previously quoted in the ENA Pathways Report reducing from 880 TWh in 2020 to 440 TWh in 2050. Assuming 440 TWh and a CO2 emissions per energy demand of 0.0549 kg/ft3 by converting the NTS to 100% hydrogen by 2050 we will reduce carbon emissions by 81 million tonnes CO2 e.

Avoiding valve replacement as part of work to connect industrial clusters: removing the need for all valves to be replaced by proving their compatibility with hydrogen could see at 100,000 tonnes of CO2 e being saved based on an initial part of the NTS transitioning to hydrogen

Compliance                 

Support Compliance                  

Identified key parameters to support our policy and compliance areas to be aware of and consider.

Skills & Competencies            

No change                    

N/A

Future proof                

Support business strategy.         

Supports National Gas business strategy and Project Union

Lessons Learnt

Key testing lessons 
Test plan: The test plan was developed to maximise the use of the facility and replicate the maximum amount of transmission scenarios. This was achieved by creating two flow loop philosophies, high and low-flow loops. The high-flow loop had no pressure drop on it, allowing the recompression unit to run freely up to its maximum flow rate. This replicated the higher velocities we see on the NTS. 

The low flow loop simulated a smaller customer offtake where National Gas would typically drop the pressure with pre heat and then meter the gas to a fiscal level to bill the end user. This loop had a maximum flow through its assets and the compressor matched that flow. Both flow loops had 6 flow rates going up in incremental stages again representing the different scenarios seen on the NTS. On the facility there were different technologies in metering and the flow loop layout with the test plan, meant that at all the flows there was comparable data between the relevant assets. 

Testing: Testing was successfully completed with all hydrogen blends and 100% hydrogen, new methods included safer ways of working with hydrogen and this was implemented into the test procedures used. Revised methods of working included using nitrogen to purge vent stacks before any hydrogen venting was to take place, to ensure ignition risk was fully mitigated. Technical challenges: The flow facility has achieved the original objective set by National Gas to test key ex-service assets that are representative of the gas transmission system, using hydrogen gas blends under a range of different flow conditions. 

However, some teething issues were encountered after commissioning of the facility:

• When carrying out the natural gas valve operational checks, the 36” Cort ball valve (Lanark) was leaking, and despite multiple attempts, it was not possible to obtain a positive seal. Due to no availability of a replacement, and complexities with swapping out the valves, National Gas requested that the valve should remain open and be excluded from further testing, and testing should continue to be scheduled without this. 

• There were some issues with the Hays filter skid which required a major overhaul. However, it later became apparent that there remained issues with the filter that could not be rectified. Following agreement with National Gas, the Hays filter DP transducer was replaced with the Enron filter DP transducer, following completion of the 2% hydrogen high-flow tests (note that a second issue was later found, affecting the differential pressure results for the 2% hydrogen low-flow tests, and the 5% hydrogen tests). 

• The compressor is used to control the pressure and flow rate around the facility. This is achieved via three set points: inlet pressure, outlet pressure and flow rate. These are maintained by adjustment to the compressor speed and the bypass valve. On completion of the high-flow tests with 2% hydrogen, some issues were encountered with the compressor. These were addressed by the manufacturer but resulted in a 10-week delay to the schedule. Some parts needed to be replaced, but it was not confirmed if this was due to hydrogen exposure. It should be noted that when the compressor was working once again, the remaining tests using 2% hydrogen, and all the testing using 5%, 20% and 100% hydrogen, were completed without issue. It should be noted that the ex-service flow control valves that are located around the facility are not electrically connected to the system, so do not form part of the flow control loop. 

 • Challenges arose due to ATEX and DSEAR concerns when moving from a class 2A to 2C gas. For example, instrumentation, lighting and other electrical equipment had to be considered. The original Hays kiosk was identified as not compliant with hazardous area classification regulations, meaning the doors had to be removed, which caused some technical challenges with the winter weather conditions at Spadeadam and National Gas’ assets. New methods of safe venting and purging were utilised to overcome any additional risks associated with venting hydrogen. Some issues were encountered with relief valves lifting early when operating with high-pressure hydrogen. It is yet to be ascertained whether it is equipment related or hydrogen related, and further research into this area will be carried out. 

Key project learnings The lessons we learnt in Phase 1 were adopted and then implemented into FutureGrid Phase 2. We have already started implementing them in this project. A few of the examples are as follows: 

Project planning: We have conducted project planning by setting project milestones in advance of the project commencing. We have also used the RASIC register for each deliverable to define the roles of each project partner. In addition to this, the project plan with clear deliverables for each stage gate has also been defined prior to the project commencing. 

Legal process: One of the lessons we learnt was to commence legal discussions as early as possible and also define clear deadlines. We implemented this lesson into the legal discussions at the start of Phase 2 and were able to complete it within a two-month time frame, which is a significant achievement for projects of that size. 

Project management: We implemented all the positive project management learnings we had refined in Phase 1 into Phase 2. This meant the governance structure and the steering group setup are similar. In addition, we are also managing risks and financial management in a similar method as it was proven to be successful in Phase 1. 

Intelligent management of onsite specialists and resource to maximise output: We learnt in Phase 1 that the site specialists and resource time need to be managed efficiently in order to maximise the maximum output. We worked in collaboration with DNV to shape resources profiles and level of escalation at both DNV and National Gas. As a result we were able to delegate duties and were able to deliver in the most efficient manner. 

Decommissioned assets sourced earlier: We have sourced most of our assets as early as possible to avoid any dependencies on other decommissioning projects. The assets were sourced and stored at one of our facilities in Cawood. 

Inspection of assets prior to transport: In Phase 1, once the assets were transported to Spadeadam, we conducted inspections and remediation activities as we realised some of the assets were not in the condition we expected initially. As a lesson, we are conducting asset inspections prior to assets being delivered on site to avoid transporting assets which are unfit for purpose. Also, we are conducting valve remediation activities at National Gas Service’s depot which means that these activities are conducted in the most efficient and cost-effective manner.

 Design: One of the key lessons learnt in Phase 1 was the management of the design process in the project. We have planned the design process at the very initial stage of the project by outlining key milestones and sub-tasks prior to the project commencing. We have also limited any construction activities without design approvals, which avoids any changes to the construction activities due to design changes. In addition to this, we have also future-proofed the design by adding PIG traps to the design. 

Spares consideration: We found having as many spares as possible in Phase 1 to be a key lesson. We are conducting early surveys of the Huntingdon site before decommissioning to determine critical spares. Also, we are in the process of creating a spares management plan for assets.