Editorial: Bringing gas to the masses [NGW Magazine]
Norway and the UK are both trying to coax the remaining gas from deep beneath their respective continental shelves in the teeth of the same three long-term problems: seemingly limitless imports of relatively cheap pipeline gas or LNG; ever-closer regulatory scrutiny of their upstream practices; and a customer base that wants zero-carbon sources of energy without considering the cost.
Norway appears to be moving faster in terms of perception: its Johan Sverdrup field for example – a 660,000 barrels/day giant – runs on hydro generated onshore. But then it starts off with an advantage – abundant hydro – not available to the UK.
Another area where Norway has the edge over the UK is that it has a single offshore gas transporter, Gassco, which can take a holistic approach to the problem.
There is already a shortage of transport infrastructure, be it liquefaction capacity at Snohvit or in the pipelines, it said in a mid-January report on the upstream.
New field projects in the South Barents Sea, where production is planned to start between 2025 and 2027, need gas transport; delaying the projects will destroy value. At the same time, commissioning the fields without an optimal transport solution for the gas will also provide lower value of the oil production, according to its analysis.
For example, the Wisting field partners have requested capacity for gas processing at Johan Castberg and Snohvit. Gassco said that the choices made by the Wisting partners could be important for the realisation of other resources in the area and affect the construction of new gas capacity in the Barents Sea. With the exception of the Snohvit plant, all Norway’s gas produced goes to Europe.
But gas demand growth there is uncertain as uncompromising policy-makers see all fossil fuels as equally bad.
The UK is in an analogous position to Norway regarding the age of its upstream assets, the downward trend of its output and the need to make the most of what is left. There has been very good progress since the oil price crash, according to the chairman of the offshore regulator, Oil & Gas Authority, Tim Eggar.
A former energy minister in the 1980s who oversaw more competitive licensing rounds, Eggar congratulated the offshore for adding nearly 4bn barrels of oil equivalent to the forecasts and achieving year-on-year production efficiency increases since the oil price crash.
But he was also confrontational at the mid-January Maximising the Economic Recovery (MER) conference mid-January. He told the UK upstream industry at its home in Aberdeen that it had to act much faster and go farther in reducing its carbon footprint. He said it had a “social licence to operate” for now, but that was “under serious threat” and “there is no scope of a second chance.”
As a part of a clamp-down, he said the OGA would be “looking much more closely at flaring and venting, where we are responsible for issuing consents – using performance benchmarking which we know has helped drive positive changes in aspects of stewardship.”
This might well worry smaller companies who may have to rethink their plans in the light of the implicit additional costs of becoming carbon-neutral. They might have been hoping to fly under the radar.
Other producers talk about offshore wind generation to run their plants and finding other solutions that do away with gas turbines – a major source of offshore carbon emissions. But in any event there is likely to be a trade-off between MER and emissions reductions.
In its defence, upstream lobby group Oil & Gas UK (OGUK) pointed to its Roadmap 2035 – one of the first major industrial responses to government plans to reduce or offset carbon emissions to net zero by 2050 in the UK and 2045 in Scotland.
OGUK might also take comfort in Eggar’s determination to “accelerate the move to ensure there is a diverse array of skills and people for the long-term energy offshore and supply industry,” unless he is referring solely to the long-term decommissioning programme ahead.
But what of demand? Owing to political decisions, Europe’s biggest gas market, Germany, is planning to close all its nuclear plants in the next few years; its coal and lignite plants have limited lifetimes and the Groningen gas field in the Netherlands has maybe two more years to run, and only at minimal volumes. While it has made progress with subsidised renewables, it is an industrialised economy in northern Europe that depends heavily on gas, year-round. This all should be encouraging for gas producers.
The alternative gaseous forms of energy that can run through the existing grid are going to be more expensive to produce and deliver than methane, and the capacity to do so at scale does not yet exist. How prepared is the EU public to fund all these investments given the parlous state of the economy of the region?
As always, gas will have to fend for itself: the European Commission’s newly established Just Transition Fund excludes all fossil fuels from its scope for investments. But the Brussels-based industry group Eurogas says gas will be increasingly important for reaching carbon neutrality in 2050 and that the EC should support all solutions that can help achieve its climate and energy objectives.
It argues that the focus has to be on technologies that help countries to shift rapidly from carbon intensive fuels to cleaner fuels such as coal to gas in power generation or funding for efficient small gas boilers. A “fit for purpose regulatory framework” should support the deployment of renewable and decarbonised gas and that implies natural gas at the core. Should this need to be said? Apparently so.