Offshore Infrastructure Reuse Can Contribute to Decarbonization

The Hydrogen Offshore Production project identifies an alternative to decommissioning by providing reuse options for offshore infrastructure. It aims to prove the feasibility of decentralized hydrogen generation, storage, and distribution to provide a bulk hydrogen solution.

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There are more than 250 platforms and 45,000 km of pipeline installed within the UK Continental Shelf. As these assets near the end of their economic life, operators plan to decommission the facilities in an efficient and cost-effective manner. The complete paper describes the Hydrogen Offshore Production project, which identifies an alternative to decommissioning by providing reuse options for offshore infrastructure while addressing the challenge of a low-carbon energy supply.

The North Sea basin, including the portion within UK waters, supplies approximately 60% of the energy demand of the EU and Norway. Decreasing levels of oil and gas production, coupled with the EU pledge made in Paris in 2015, will result in an energy transition over the next few decades.

An area of opportunity for the UK is the offshore infrastructure across the continental shelf. The North Sea, at present, is marked by declining oil and gas production and high decommissioning costs. As part of the energy transition, there is merit in considering potential reuse and repurpose options ahead of decommissioning, taking advantage of the extensive levels of capital investment over the productive life of the North Sea.

The objective of this project is to provide a means to generate and supply hydrogen at scale by harnessing existing offshore infrastructure. This will be achieved by proving the feasibility of several decentralized hydrogen generation, storage, and distribution solutions that collectively provide a bulk hydrogen solution. As part of the project, an industrial hydrogen production test site will be established.

Hydrogen Supply Solution

The Hydrogen Offshore Production (HOP) project will identify the most appropriate technologies for offshore hydrogen generation for both low- and zero-carbon approaches. Preliminary work as part of a study on the potential for generation and application of hydrogen in an offshore environment found both low- and zero-carbon technologies that are appropriate. Fig. 1 shows the potential scheme, and an overview of the characteristics of each of these systems is given.

Fig. 1—Potential hydrogen-generation scheme in an offshore oil and gas environment.

Low-Carbon Hydrogen-Supply Solutions

Hydrogen and graphene from methane. One approach uses methane as a feed stock and applies a microwave plasma to produce hydrogen and high-quality graphene. The technology is currently in the demonstration phase; a working prototype has been developed in Cambridge. Phase 1 of this project would build upon the existing design of this system and identify modifications required for offshore operation.

Hydrogen from methane reforming. Two methane-reforming technologies are being considered: modular-steam methane reforming (SMR) and auto-thermal reforming (ATR). In SMR, methane reacts with steam in the presence of a catalyst at temperatures between 750 and 900°C to produce synthesis gas. Then, a reaction converts the syngas to hydrogen and carbon dioxide. Hydrogen quality following the SMR process is approximately 75%. Additional processing steps will increase purification levels to 99.9%. The project will consider using a modular version of this process, which would allow for replication of the system across several assets.

As a process technique, ATR is similar to SMR in that natural gas and steam are the feed materials. The feed mix is reformed through a two-stage process of gas-heated reforming followed by autothermal reforming where oxygen is injected. The products of this process are the same as for SMR.

Modular SMR unit technologies are currently available and their level of certainty in performance is reasonably high; however, these would require integration testing for commercialization offshore. Process challenges with both schemes exist in that conventional ATR or SMR processes have never been built or operated offshore, although the technology itself is established and mature. The process is operated at high temperature and pressure but is highly automated and requires minimal intervention.

Zero-Carbon Hydrogen-Supply Solutions

Hydrogen from electrolysis. Electrolysis solutions are used onshore for production of small-scale hydrogen; no electrolysers fit for offshore deployment are available today. Transitioning this approach offshore could supply hydrogen at scale through replication across several assets while driving a market for improved electrolysis performance.

Offshore wind technology has experienced rapid development over the past decade. Installing offshore hydrogen electrolysers coupled to wind farms presents an opportunity to harness this energy with greater flexibility. The hydrogen produced by the electrolysers could then be exported to shore through existing offshore pipelines with minor modifications for hydrogen transport. Because advances in onshore electrolysis technology are taking place rapidly, this project would integrate the best available technologies in an offshore solution.

In this scenario, one would consider the location of floating offshore wind farms in the vicinity of existing oil and gas infrastructure that is earmarked for decommissioning. This infrastructure could be repurposed to house water purification together with electrolysers for hydrogen production. The hydrogen could be exported to the onshore gas grid by existing pipelines.

Hydrogen Storage in Pipelines

Producing hydrogen remotely from end users highlights challenges involving transport, storage, and distribution. To address those challenges, the authors consider methods for storage in existing offshore pipelines, gas storage at reduced pressures, and decarbonization at source by injection of hydrogen produced offshore into the gas-export line.

Currently, five methods exist to transport or store hydrogen:

  • High-pressure gas
  • Liquid hydrogen
  • Absorbed onto other materials
  • Chemically bonded to another element
  • Through oxidation of reactive metals

High-pressure gas in cylinders is the most used of these methods. Advances in material technology led to improved performance of these cylinders (lightweight composite cylinders that allow more hydrogen to be stored within the same volume); however, more needs to be done to address the storage and transport challenges if hydrogen is to become a feasible energy vector for the UK.
One option takes advantage of the offshore pipeline network as a potential storage medium for hydrogen gas. Though many offshore pipelines are still in use, several are empty or ready for decommissioning. Hydrogen gas could be stored in these pipelines, acting as storage tanks and drawn down or used as required to meet peaks and troughs in energy demand.

The Phase 1 feasibility study will address process risks such as bulk storage of hydrogen underwater and current unknowns such as pressure and temperature profiles across the pipeline system to facilitate storage. With offshore pipeline storage, this scheme is considered inherently safer than existing onshore storage options. Additionally, if the scheme proves feasible, it presents significant potential to save capital costs.

Accelerating Low-Carbon Hydrogen Supply

The UK and northeast Scotland are in a favorable position to leverage their knowledge and experience for the delivery of an effective energy transition to an integrated and net-zero offshore industry. A planned project will help drive down emissions and accelerate the shift to low carbon and clean growth, providing significant potential for a global sustainable export market. Two key areas of the project will drive the acceleration of an industrial low-carbon hydrogen supply: establishing an industrial test site and introducing a new business stream for offshore oil and gas asset operators.

This project will create an onshore industrial hydrogen production test site at the Flotta oil terminal in Orkney. The Flotta terminal, commissioned in 1977, covers an area of 1.6 km2 in Orkney north of mainland Scotland. Crude oil is imported to the terminal from several offshore installations through a 30-in. subsea pipeline.

A key challenge for the Flotta terminal is energy security. If the terminal experienced a power outage, a knock-on effect might exist for production shutdown across the Flotta catchment area. Hydrogen, produced locally at a test site, could be used as an energy vector to support these energy security challenges during successful integration of hydrogen production with brownfield facilities.

Throughout the UK, several laboratory-scale test facilities for hydrogen technologies exist. The authors believe that the site discussed in the complete paper would be the first fit-for-purpose industrial testing site specifically for hydrogen technologies, where industrial-scale solutions can be tested and proven ahead of commercialization and deployment at scale. The existing facility requires expansion to be able to test the scale of technologies proposed within this project.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195772, “Offshore Infrastructure Reuse Contribution to Decarbonization,” by Hayleigh Pearson, Christopher Pearson, and Luca Corradi, The Oil and Gas Technology Centre, et al., prepared for the 2019 SPE Offshore Europe Conference and Exhibition, Aberdeen, 3–6 September. The paper has not been peer reviewed.