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Could UK Oil Production Peak Again In 2019?


Production History And Reserves

UK oil production peaked in 1999. The peak was probably pushed out a couple of years because of the major production interruptions following the Piper Alpha disaster. Production declined quickly until around 2011, then the high oil price allowed more brownfield and then greenfield developments that created a third local peak in 2016. Production is declining again this year but there are several large projects due that will create another peak in 2018 or 2019 (nearly equal to the 2016 one). After that terminal decline is likely. The chart below shows C&C production split according to the year of first production of the field.

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Like all such all diagrams, this shows that the largest fields were developed first and declined the slowest.

Most data here is taken from the new UK Oil and Gas Authority (which replaced part of the disbanded Department of Energy and Climate Change), some from the Scottish Parliament and the rest from Company and Trade Paper publications (but presented without the implied “Everything is Awesome” imaginary soundtrack that accompanies and influences everything from all such sources).

Reserves for oil and gas have been declining fairly steadily since 2000. The UK reports according to SEC rules (i.e. including only developed reserves and those with definite development plans) and, from this year, reports 3P and contingent resources. The R/P ratio given below is based on 2P numbers. The oil reserves include onshore oil (which is around 100 mmbbls) and NGLs (which are about 4 to 5 percent of the total).

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Natural gas reserves in particular are looking low and declining fast – possibly mostly gone except for some associated gas in the remaining oil reserves by 2030 without some big discoveries – but this post concentrates mostly on oil. Remaining 2P oil reserves (as of December 2015) are 4.2 Gb (so say about 3.9 C&C only) , and for gas, 2.1 Gboe. There have been studies that indicate around 5.6 Gb of undiscovered recoverable oil (and 3.6 Gboe of natural gas): UK OGA

However recent activity for licensing, exploration drilling and development approvals would suggest that the E&Ps think that the putative undiscovered oil and gas is going to be difficult to find and expensive to bring to production. Recent drilling activity has mostly been for development wells with only fourteen exploration wells in 2016 (plus two sidetracks) dropping to five and one in the first half of 2017. Appraisal wells have been even fewer, only eight in 2016 and one so far this year, reflecting previous years drop in discoveries, especially any large fields. 2017 figures are through July.

Related: Natural Gas Prices Poised To Rise As Exports Boom

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Many of the development wells are predrilling for subsea completions on projects due over the next couple of years. Hence these numbers, too, will decline as those projects come on line and fewer follow. It’s also notable that drilling dropped after the short price dip in 2008, but didn’t pick up again as prices and overall E&P activity rose significantly from 2009 through 2013.

Discoveries have dropped off in line with the decline in drilling and reserves, as would be expected. UKOGA does not provide individual fields reserves that I have found so this chart only gives numbers of discoveries (only one last year and none this). The fall off would be even more marked based on size as only small fields are now being found (and no gas fields for five years).

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The UK Oil and Gas Authority don’t provide easily analysed data concerning the licensed blocks, although there are a couple of Excel files they have that I haven’t been able to download which might. In the two full rounds, plus one supplementary round since 2015 there have only been four firm wells bid out of 75 new licences; there are a few conditional wells but all the other bids have been for new seismic (and much of it 2D) or review of data only, followed by drill-or-drop.

Recent Production

Recent monthly production numbers for C&C and Natural Gas, with drilling rig numbers (from Baker Hughes) are given below. Production is highly seasonal because maintenance turnarounds are scheduled in spring and summer when the weather is clement and gas demand is low. Installation of new facilities occur then as well which means that new production tends to ramp up mostly in the first half of the next year.

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UK production comes from many small and medium sized fields; this is in contrast with Norway where most production comes from fewer large fields. The top ten fields by production in 2016 are shown below. Collectively they have peaked (note UK is a month behind in producing the data compared to most other governments that issue good data, so these numbers only go to April). Franklin and Clair are offline and all shown are in decline. Collectively they process far more water than oil, as is common in mature fields, and their water cut is still continuing to increase.

Related: The $50 Billion Backlog Of U.S. Energy Projects

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Buzzard has been the largest producing field for many years and has stayed on plateau for about three years longer than originally expected, but it now looks to be hitting high decline rates. Its water cut has passed 50 percent, which is often a threshold for the end of a plateau, and still increasing.

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Recent fields additions have been small, and most go into almost immediate decline, for example the Cladhan field started up in December 2015 and looks to be already exhausted, (in fairness it is classed as a gas field so the production would likely but to recover a small oil deposit before starting the blow down of the gas). However, the next batch of projects to come on line are much larger – some fields shown in the legend, but with no flow numbers yet are for facilities that have been, or are currently being, installed but did not show production in April.

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Future Production Projection

A proposed projection for production until 2030 is given below. The projects before the yellow line are now operating or being constructed. Expected start up times and nameplate capacities (in brackets after the name) have been taken from company presentations. Expected availability, ramp up times, plateau periods and decline rates have been estimated based on the type of installation and to match given 2P reserve numbers. The total recoverable oil for developed and due fields from 2016 to exhaustion, is 3.7 Gb, which matches fairly well with the estimate given above (maybe a bit low, but there may be fields included in the UK OGA numbers that have development plans but are not in construction yet. The “recent” fields are anything started in the last three years, and have slightly different assumed decline parameters than the mature fields.

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The developments listed that are above the yellow line are pure guesses based on known discoveries and tentative plans discussed in company presentations and trade papers (i.e. currently in appraisal). There is another 1.2 Gb C&C in the production shown. some of this is from small gas fields which I have just given nominal condensate production numbers (a couple of these have actually had their licenses relinquished, but someone else may take them up again).

All attractive discoveries are immediately fast-tracked, even with recent low oil prices, and many of the more marginal, aged legacy discoveries were developed when oil prices rose above $100. Therefore all of the larger oil developments in these putative projects are quite unusual (read difficult), and likely to be expensive, e.g.: Rosebank has layered reservoirs between lava flows or some such; Fram is a thin oil rim with large gas cap (and has been around since the Eighties); the Hurricane operated fields are basement rock (deposits in fractures in granite which has been pushed above the source rock for the oil), Bentley is heavy oil, the previous licensee went bust, it might be developed using steam injection, which is quite marginal for offshore developments because it’s difficult to prevent excessive heat losses; the Pilot fields are similar but more advance in concept for steam injection; Bressay is marginal heavy oil and it’s development was cancelled by Statoil last year, possibly until they see the results of the Mariner development, which is similar but more commercial.

As pretty well all the forthcoming projects are now in the later development stages of construction, commissioning or installation there are few to none reasonably sized projects for the UK currently in detailed design. Most of the larger engineering design teams have broken-up and the remaining installation and start-up teams will probably soon follow. If there is another boom period it may be difficult quickly to ramp up project activity, so meeting the schedule for unapproved projects as shown is going to be increasingly problematic.

And to end on an upbeat note (as seems to be required in all MSM articles these days – we don’t seem to be considered mature enough to be able to cope with bad news) though here slightly pretentious, this is “At the Theatre” and/or “The First Outing” by Renoir, showing good things really can come from humans using oil (with a UK connection too). Renoir isn’t considered quite top tier and this might not be one of his best (or it just might be) but the young lady shown, at that time and that place, definitely did think everything was awesome; and with no post-modern irony or need to take a selfie either.

By George Kaplan via Peak Oil Barrel

7 Comments on "Could UK Oil Production Peak Again In 2019?"

  1. twocats on Sat, 19th Aug 2017 3:22 pm 

    I wish that first graph had a Brent spot price paired with it. Sell low, buy high!

  2. rockman on Sat, 19th Aug 2017 3:44 pm 

    twocats – True but everyone should remember the high/low periods of oil prices. With that in mind it’s not too difficult to appreciate the lag time between prices and production increases/decreases similar to what you see on a graph of US oil production.

    What truly stands out is the lack of a huge production surge in the UK compared to the US in the last 10 years. And we know why that is so: the US onshore shales.

  3. energy investor on Sat, 19th Aug 2017 6:08 pm 


    IIRC Buzzard was found/started producing when I owned Nexen shares in about 2005-2006, so most production from that source has been a good prices. But the original projection was that it should have started to play out by now.

    I recall that Maggie Thatcher’s “economic miracle” was the rapidly expanding wealth from North Sea oil and gas that allowed her to beat the coal miner’s strikes led by Arthur Scargill.

    Now all British homes are heated by gas and they look ahead to the coming winter with trepidation over energy supplies and costs.

    God save our noble Queen ! (as the anthem goes)

  4. rockman on Sat, 19th Aug 2017 10:57 pm 

    Investor – “IIRC Buzzard was found/started producing when I owned Nexen shares in about 2005-2006, so most production from that source has been a good prices.” Yes, by lucky timing. But it was discovered in 2001 by PanCanadian, and developed initially by EnCana & finally by Nexen. It was drilled based on a Brent price around $25/bbl. Maybe less: Brent was below $20/bbl by the end of 2001.

    That was my point about the time lag between exploration and production. IOW Buzzard Field was not the result of high oil prices.

  5. Antius on Sun, 20th Aug 2017 9:38 am 

    There is scant sign of Thatcher’s economic miracle in UK historical growth statistics. In fact, UK growth has been practically zip since before the Berlin wall came down.

    Boom and bust cycles are less frequent and less pronounced, but growth has been weak for 30 years. This was a period during which the UK was one of the world’s biggest oil exporters. Presumably someone did well out of it.

  6. Cloggie on Sun, 20th Aug 2017 9:55 am 

    Talking about the British economy, this is Northampton:

    (study picture, no knowledge of Dutch required)

  7. rockman on Sun, 20th Aug 2017 2:58 pm 

    Antius – ” This was a period during which the UK was one of the world’s biggest oil exporters. Presumably someone did well out of it.” Presumably it was the British govt that collected $BILLIONS in royalties and taxes. And presumably the companies that produced the oil/NG, along with their employees had shareholders. And presumably the Brit ff consumers who had abundant supplies of domestic resources. And lastly, presumably the consumers of that exported petroleum which the used it to fuel a portion of their economies.

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