In this interview MFDevCo’s Developments Manager, Mick Hibbert, and Technical Manager, Peter-Giles Robinson, discuss how gas-to-wire solutions use existing infrastructure and standard equipment to reduce cost and risk.
The oil and gas industry has a reputation for being relatively risk-averse, would you agree?
MH: Exploring and operating offshore requires significant investment, operators and investors need to minimise, mitigate and manage uncertainties that come with operating in an offshore environment. Technology risk is a key element of any project and while the industry has been extremely innovative, there is understandable reluctance to invest capital in something that may not work. You want to be certain the development approach you use has the best chance of success. You don’t want to be finding out if something actually works after it’s installed in a marine environment because it’s pretty expensive to make corrections offshore.
PR: This is one reason why gas-to-wire is a perfect solution – all the equipment required has been proven in use onshore and offshore, and the technology risk is extremely low indeed.
MH: Peter makes a key distinction, operators can be wary of employing new technology until someone else has proven it works, that’s why there are bodies funding R&D promoting new tech, but once the industry is comfortable with something it simply becomes equipment. What we are proposing to use is equipment, not technology.
The most obvious differences between conventional offshore gas production and gas-to-wire are the addition of a generator to convert gas into power and the means of transmitting that to shore via cables, rather than piping gas. Starting with the power generation, where is this equipment already being used?
PR: I’m sure everyone knows that generating power from gas is absolutely not new and has been a key component in onshore power generation for decades. All the equipment involved is proven and currently in use – generators, transformers, substations, power networks themselves.
What people may be less aware of is that this equipment is being used right now on many gas fields to power the platform, processing equipment and compressors. The difference is that instead of the generated power being used to compress and pipe gas back to shore, we use similar equipment to convert all recovered gas into power which is transmitted back to shore as energy.
What types of generators do you expect to employ?
PR: We are proposing to use open cycle gas turbines which will be supplied by Siemens. If you want a recent example, in March BEIS approved the construction of a new rapid response gas power station in Bedfordshire which will use open cycle gas turbines, in much the same way as we will use them on an offshore gas-to-wire project (http://www.millbrookpower.co.uk/).
That’s not the only parallel with what we are doing, the CEO of Drax Power, the company building the site, saw this as part of the new gas generation the UK needs in order to provide flexible power to the grid as part of the country’s transition to a lower carbon economy. What Drax are looking to do onshore, we seek to do offshore; again, like Drax we will deliver power needed and in addition we will ensure that the country’s valuable, discovered and developed natural resources are fully utilised.
What’s is the difference between open cycle, closed cycle and combined cycle gas turbines?
PR: Open cycle means that the working cycle is open. The gas turbine breathes air and exhausts to atmosphere. In a closed cycle the working fluid is continuously cycled and a heat source heats the fluid which powers the turbine. An example of a closed cycle is a nuclear power plant where the reactor heats the working fluid, in most cases steam, which drives the turbine. The steam circulates from the reactor to turbine, then is cooled and compressed to make it ready to take power off the reactor again.
Combined cycle turbines primarily produce power from an open cycle gas turbine, and also use the waste heat from the exhaust in a closed cycle to convert water into steam which is then used to generate more power using an additional steam turbine. This increases the power generated per unit of gas and is more efficient. Increased efficiency also reduces the amount of CO2 produced per MWh generated. However, combined cycle plant has drawbacks – they’re large, heavy, expensive and they need a working cycle of water. Examples of combined cycle plants in operation offshore are the Norwegian Snorre B, Eldfisk and Oseberg platforms, where the power is used for gas compression and water injection for enhanced recovery.
MH: If we were operating onshore we would definitely be using combined cycle. It’s very challenging to do offshore for a number of reasons – the additional space, the added weight, and the additional maintenance and operational support needed. The water system is pure water which has to be made up from time to time. Superheat saltwater and you’ve got a big materials problem because of scaling – chemicals, cleaning, maintenance is going to be prohibitively expensive. The condenser uses a sea water circuit to cool the steam which is vulnerable to fouling. On land it’s a no brainer but offshore, it’s all about the economics and reducing the risks involved.
Aside from the installation of additional turbines what other changes need to be made to convert an installation into a gas-to-wire project?
MH: The priority is always to minimise modifications as much as you can. If there is enough real estate on the platform then there is no need to remove anything. We will just leave it there, take it offline and mothball it. If we need the real estate for expansion, we can take plant off either immediately or later on a demobilise as needed basis.
PR: We don’t want to incur the cost of removing modules if we don’t have to.
MH: This means that we can demobilise equipment on an opportunistic basis. For example, if we know that we will want to remove equipment in 6 months’ time because we will need the space, we can plan ahead to contract on a vessel sail-by basis, which means we can lower the cost of removing the module compared to paying for the vessel solely to remove our equipment. It’s a highly efficient way to reduce cost which we can take advantage of, unlike a new facility which will need to have everything installed on an immediate basis.
PR: Really, it’s a lot about reconfiguring the platform to host the power generation equipment, and the transformers. This may be localised beefing up of the structure to carry the weight, or relocation of modules and equipment to make room, while maintaining safety and integrity.
What is the lifespan of a turbine?
MH: Good question, lifespan, maintenance and replacement are key considerations. This is one of the reasons why companies have moved over to aero-derivative turbines in the majority of North Sea applications. Unlike frame-set turbines, aero-derivative turbines are modularised; there are three basic modules: inlet compressor, combustion chamber and outlet turbine. The combustion module is the one which has the most thermal stress and the part that will wear out first. In an aero-derivative you can replace the combustion module, which is almost routine offshore now. Every four years the whole gas turbine unit can be removed from the platform and sent for major overhaul. A new or overhauled unit can be installed in its place. The whole operation takes a few days. So, these aero-derivatives are cheaper to maintain, a lot quicker to take offline and get back on stream.
We’ve talked about the topsides, what about the connection required to transmit the power to shore?
PR: We have two options, if there’s nearby renewables infrastructure they will have an offshore substation called a collector station, that collects all the power from the wind turbines and then converts that to a higher voltage so that can be sent to shore. The higher voltage is required to limit the losses, you lose less at higher voltage.
MH: It depends on whether you’re transmitting in AC or DC. Transmitting AC over long distances results in line losses because cables are close together, each conductor pulsating at 50Hz builds electromagnetic flux which induces an electrical current in its neighbours. This is parasitic to the main power that you’re transmitting. This is why transmitting at high voltage is beneficial because its mainly the current that creates the inefficiency, you decrease the current and increase the voltage. You do that through simple transformers. One of the beauties of AC is that those transformers are simple to manufacture.
The advantage of transmitting in DC is that there is no frequency, therefore no induced parasitic current in neighbouring conductors in the cable so you can transmit over much longer distances; which is why it is being used to transmit power over vast distances in Russia and China. One beauty of DC is you don’t need to synchronise, it’s like joining batteries together. That’s why the interconnectors between UK and Europe are DC.
How difficult will it be to connect up to the substation?
MH: Most substations are built for expansion and physical interface connections are already in place including j-tubes which are used to pull the cables into the power bus. We know that there is usually capacity on substations to accept additional power. All the work that needs to be done is on the surface aside from laying the cable itself.
What are the considerations if we cannot connect to an offshore substation?
MH: In that case we will need to connect directly into an onshore connection. Again, this uses tried and tested equipment, which is readily available, all it requires is the civil works to get you into that substation. Of course, you also need ullage in the local grid that the substation connects to onshore to allow that. If not, that is not the end of the story, what it does mean is that the local grid might need to be expanded. Again, we have a very mature national grid in the UK and modifications can be done without significant difficulty. Obviously, you need to work within the environmental constraints involved in shore works and permissions.
PR: The long-lead item will be manufacturing the cables which may be bespoke for the project – it could be AC or DC, as Mick has said, and could include control systems such as fibreoptic cables bundled in there. Aside from that we will also need to obtain the necessary consents and environmental studies but the installation itself is relatively simple.
MH: Good summary, installation of the cable is the one piece of the puzzle that has some element of the unknown, which are two-fold – the weather, always a weather risk when laying a cable but we’ve been coping with this for decades and decades so we know how to manage that. The second unknown is seabed congestion from cables and pipelines criss-crossing the North Sea. We have to be sympathetic to that, but this is all solvable.
PR: In UK waters there are shipwrecks and unexploded ordinance, so prior to any installation we will need to check the route to make sure there is nothing surprising there. Next Geosolutions, which originated from a joint venture between Marnavi Offshore and Tecno In , has that capability.
MH: When converting offshore gas platforms in some instances they will have their own pipeline back to shore or they will have their own pipeline connector to another platform that has a pipeline back to shore. Now there is the opportunity to use those pipeline corridors that have been checked and cleared of ordinance as a cable route back to shore. That doesn’t mean that there won’t be anything else to clear, I’ve seen instances where there is an eight-wheeler concrete mixer adjacent to a pipeline that’s fallen off a ship somewhere. These things do happen, but you can trace a redundant gas pipeline and use that route, or you can take a dogleg and follow those routes to minimise any crossings. Again, each project is specific.
One thing we haven’t discussed in carbon capture, is that something being considered?
PR: There are few projects that can claim they have captured significant amounts of carbon, that’s where the technology is not proven. Some projects at some stage may be feasible, but right now the amount of equipment you’d need for an efficient operation would be difficult in terms of space and weight, the systems are not proven and aren’t very efficient themselves. Capturing carbon takes a lot of power that would otherwise be transmitted and the process itself also generates CO2. Current top of class carbon capture solutions can only capture 90% of the CO2, and that’s from gas streams with a high concentration of CO2, like ammonia production. Applying it to high temperature exhaust is difficult. The Drax pilot plant only captures 360 tons of CO2 per year out of some 20 million tons CO2 produced. At some point the technology – and carbon capture is still very much a technology – will become efficient enough and a lot smaller so that you could definitely apply it. The technology still has a long way to go. When it is demonstrated to work and is economic, while it would be more cost effective to add from the start it certainly is something that could be added in later.
Why do you think gas-to-wire has not been implemented before?
MH: It’s all about timing – the gas resources exist, the platforms are in place, we have the equipment and know-how required. Talk to an operator five years ago they would have said that what they are doing is still economically viable and they would have continued with that approach, but now those facilities are no longer commercial, which creates the opportunity.
PR: Possibly the biggest change is the political willpower and impetus to maximise recovery of domestic resources and the requirement to meet the increasing demand for power. Gas has been identified as a bridging fuel because it’s the cleanest way to meet the increasing energy demand as we transition to a greener energy future.