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UK North Sea Summary Part II: Reserves, Recent Production and Future Projections

UK North Sea Summary Part II: Reserves, Recent Production and Future Projections thumbnail

The OGA issues UK oil and gas reserve values each year, but only in total, not for individual fields as is done in Norway, Mexico, GoM and Brazil (which reports by basin rather than field). The reserves are not backdated to discovery date so it’s not possible to generate anything like a true creaming curve, but they are split into categories of proved, probable and possible, and, since 2015, contingencies. Operators in the

UK North

Sea have up to five years to announce estimated resources in discoveries so there may be uncertainties for recent years, unlike in the Norwegian section where estimate must be declared as soon as they are known.

For both oil and gas the impetus to increase production after 2015 wasn’t accompanied by a matching increase in reserves so there was a marked decrease in R/P, which is still continuing for natural gas. The values of 11 and 6 years would suggest average decline rates going forward of 9% and 15% respectively (and increasing for gas). There are a number of projects in development or planned but their reserves should mostly be already included in proved or probable/possible numbers.

Remaining reserves are really quite low now – around the amount of a couple of the largest early fields – and are falling slowly, while cumulative reserves are starting to trend towards a limit (more so for oil than gas).

Recent Production

Oil production plateaued through 2019. A local peak was expected for 2018 but delays in some projects pushed this backwards. Recent production is showing a marked decline possibly partly due to the pandemic impact though I would expect this to have a bigger effect in the coming years because of delays in exploration, FIDs and maintenance. The current decline is more due to the lack of recent discoveries, the shut down and decommissioning of rising numbers of platforms and the trough in FIDs following the 2015 price crash coincident with an increase in start-ups of projects initiated in the preceding years when prices were high and now starting to decline. Plus there is a seasonal effect as planned maintenance requiring shutdowns is scheduled for late spring and summer.

Most greenfield projects are designed with a plateau period but few actually show much of one, either because of start-up and operation issues or because of the desire to accelerate production in successful developments. Tiebacks and other brownfield upgrades tend to show rapid ramp-up and immediate decline. Both types of projects are represented in start-ups since 2010, most (by number) are tiebacks but the largest proportion of new production is now coming from heavy oil projects (some individual projects are described below). These may show real plateau periods because they are limited by capacity for handling produced water, which appears soon after start-up, but this won’t be evident before another couple of years operation.

Natural gas had a longer plateau than oil. This year’s decline is less easy to identify because of the seasonal cycle as maintenance and peak shaving production is scheduled to match demand.

Most of the imports to the UK come direct via dedicated pipeline from the Nyhamna gas plant in Norway. Originally this only handled production from the Ormen Lange field, which is now in decline, although subsea compression is being added to boost production and increase recovery. To fill the pipeline Aasta-Hansen was recently started and Dvalin, a smaller field, is nearing start-up.

LNG now fills most extra winter peak demand but in the past the Rough field storage, decommissioned in 2016, or some seasonally operated fields such as Sean in the Southern North Sea, now mostly exhausted, were used.

Before development is allowed in the UK the project operator is required to submit an Environment Statement. These are also made available on-line at the operators’ sites. One section required in each is an expected best-case production profile for the full life cycle. This is called a P10 estimate (unless you are Chevron who, just to make it easier for us all, decided to call it P90), meaning the operator has modelled a 10% chance of meeting or exceeding this number. Some operators also a P50 profile, but not many. The P10 estimates for the largest recent developments are shown in the following sections and also for estimates of new fields used in projections shown below.


Buzzard has been the largest producing UK field for this century, has exceeded expectations and continues to produce at the high end of recent estimates.  A new development, Buzzard II, was due to start in 2020 but has been delayed by at least a year because of the price crash. It will allow a maximum net increase of production of about 45,000bpd, in its second year, and add 50Mbbls of recoverable reserve.

The Golden Eagle Area Development (GEAD) is operated by CNOOC, like Buzzard. It was another fairly large recent start up now in terminal decline but with no redevelopment plans.

Clair Ridge

Clair Ridge has been one of BPs major projects of recent years. It was built to exploit further the billions of barrels of heavy oil (API in the low 20s) in place in the Greater Clair area. It is a second platform after Clair Phase I. Things have not gone well with cost overruns, the start-up delayed from 2016 and, now, poorer than expected well performance with higher water cuts. As a minimum more wells will be required, which will probably limit the overall throughput, but there may need to be a write down of reserves. There were plans for another platform with three drill centres in the area but those must be on prolonged hold now.

Quad 604

Quad 604 is a new BP operated FPSO that has replaced the old one for the Scheihalion and Loyal fields to allow redevelopment and significant increase in their ultimate recoveries. So far performance has been average at best and looks like it might get worse as overall decline rate is predicted at around 9% but natural decline looks to be around 20 to 30% and few new wells have been added since start-up.

Catcher Area

The Catcher Area contains medium heavy oil (API in the higher 20s). The initial development comprises three fields and so far their performance must have exceeded even the most optimistic estimates, though they are now starting to decline. There are three other, significantly smaller prospects in the area; the first, Laverna is in development and is and due to start production in 2021.

Western Isles Development Project

WIDP has been a bit of a disaster. It was probably marginal when it was originally approved and since then there have been several years of delays, cost overruns because of quality and safety issues, mostly from the Chinese shipyard that won the fixed price construction contract, a couple of price crashes since FID and, latterly, the fields (especially Barra) have not performed to expectations so that daily production and, probably, the ultimate recovery are lower than expected. From memory there has been quite a turn over in the senior management at Dana, the operator, and its owner, the Korean Oil Company, is probably not very happy. There are other tie-in targets in the area but the performance of Barra might have changed the risk assessment for future exploration.


The Kraken development is heavy oil and has the largest produced water processing system in the North Sea. Its performance has been excellent so far, beating the P10 plan, although water breakthrough may have accelerated a bit earlier than planned


Mariner is operated by Equinor, its only one in the UK sector. It is heavy oil (second lowest API after Kraken) and uses condensate dilution and electric submersible pumps for EOR. It had a slightly delayed start up and hasn’t to date done too well. However it may now be starting to catch up and water breakthrough is low, so the problem may be with the surface facilities rather than the wells or reservoir.

Shetland Gas Plant

Four gas-condensate fields in the Greater Laggan area (West of Shetland) have been developed by Total with subsea wells and long (-est in the world) multi-phase flow lines feeding the Shetland Gas Plant. Phase I involved the Laggan and Tormore fields and would have to be described as disappointing. An expected plateau of three or four years actually lasted only a few months, hence Phase II, involving Glenlivet and Edradour, had to be brought forward to partially fill the spare capacity in the gas plant. The plant was also planned to allow exploitation of other gas fields in the area, but the first possibility, Glendronach, has been downgraded by 40%, through appraisal drilling, after much hype upon its discovery, and has high mercury levels that would require significant changes at the plant. There were some articles last year that Total might be looking to sell the gas plant, but nothing since.  (Apologies to anyone that’s colour blind for these charts but in the industry green and red are pretty standard colours used for oil and gas).

Top Down Projections

Verhulst curves were fitted to C&C and natural gas production from the five areas of the offshore production: Central North Sea (three curves), Northern North Sea (three curves), Southern North Sea (one curve), Irish Sea (one curve) and West of Shetland (two curves). The Irish Sea and the Southern North Sea are almost exclusively dry gas and the others are mostly oil or gas-condensate.

No constraints were applied to set reserves, which became an output (or an emergent property as they like to say these days) and came out as 35Gb C&C and 24Gboe natural gas.

The oil fitting was reasonable, especially for recent years, although the Piper Alpha trough proved difficult to match.

Fitting the gas production proved difficult, I tried weighting recent years higher than earler ones but it didn’t help much. It probably needs a few more years of data and a different split of curves to get much better because gas production may be heading for a new local peak (see below).

Bottom Up Projections

The production from fields in categories for recently develop, in development and planned projects below are taken from the P10 cases in environmental statements where available. Some others came from company presentations that included expected production profiles and others, especially for some planned developments, are estimates based on any available data, usually estimated reserves and design flow rate. Therefore for fields in development or planned the production rates are likely to be overestimated and the start-up schedule to be early, especially now with additional delays due to the pandemic and low oil price.

Production numbers through 2020 are measured annual averages (pro-rationed from August for this year) and the mature fields are estimated as an exponential decay.

A recent University of Aberdeen study stated that over a quarter (or 4.2Gboe by its estimates) of the potential reserves would be uneconomic with prices below $45. Much of the future production depends on existing and aging infrastructure. Often the new resources will be inadequate to justify the operating and maintenance costs without some residual production from earlier developments so that the longer prices stay low and new developments deferred the more likely it becomes that some resources are left stranded. Just from an EROI consideration it would become impossible to recover the energy of extraction, irrespective of oil price or risk acceptance. Decommissioning commitment costs may also militate against some of the smaller prospects ever reaching FID.

The estimated remaining recoverable reserves are shown after the discovery additions for each case. In 2020 the OGA estimates were 10 to 20Gboe remaining, with a mean of 15.3; this is the same range as estimated in 2016 despite 2.5Gboe of production in the meantime, so maybe the UK has joined OPEC on the quiet.. I think, at best, the number will be at the low end of this range (the median case gives 10.8Gboe) and even to achieve that discovery successes need to increase substantially. Last year 240mmbbls were discovered and the trend has been downward recently; less than 100mmbbls were added to reserves by greenfield FIDs; less than 100mmbbls were added from brownfield FIDs (FIDs allow reserves to be classed as proved, so don’t affect overall P2 estimates); and less than 110mmbbls from other upward reserve revisions, though much of this was negated by downward revisions in other fields. The biggest single prospect for new discoveries seems to be gas or gas-condensate fields in the Central North Sea.


Over the past decade a cottage industry has sprung up for producing reports concerning North Sea decommissioning. There have been publications from OGA, UKOG, Arup, the Scottish Parliament, the Royal Academy of Engineering, Westwood, the University of Aberdeen, Intergenerational Foundation and probably others, e.g. from financial advisors, plus several peer reviewed journal papers. The UK is at the forefront of offshore decommissioning, maybe a bit behind GoM, but many of the structures so far removed there have been small and in very shallow water.

The UK has many structures (about three times as many as in the Norwegian sector, which has larger fields) some of which are large concrete gravity based structures or steel jackets, and most of which are piled into the seabed. The average age of equipment is almost 30 years. Ownership changes and modifications over the life cycle complicate decommissioning planning and execution.

The time value of money means that decommissioning costs don’t figure highly in original FIDs but can be important considerations for late life assett sales.

The OGA estimated a total cost of  £39 billion, but this included 35% efficiency savings. Others have pointed out that on multi-billion projects cost overruns are the norm so around £83 billion is probably more realistic. So far, however, there have been reductions of 19% from original estimates, though, as the biggest gains tend to come within the first years of new technologies, this might be the best that can be achieved and cost creep is now more likely. About half is for plugging and abandonment of wells, the rest for removal and scrapping of structures, and site remediation and monitoring. Annual costs are expected to rise fairly steadily from £1.1 billion in 2020 until peaking in 2028 at above £2.2 billion. However low oil prices will likely lead to deferrals of such work, making it progressively more difficult snd costly as work forces and supply chains shrink. For offshore Western Europe annual costs are expected to peak above $9 billion in 2033.

This cost is borne by the operators but can be claimed against previous taxes paid on the field’s profits., so about half will fall on the British taxpayer (explaining why the industry become a net loss maker in 2016). There are also questions to be asked about whether the E&Ps will be able to afford this as production and income fall.

Nominally there are regulations to ensure that the costs are still covered when the large companies sell their late-life assets to smaller ones but these have not been tested in highly volatile market conditions. Asset sales can be clean breaks, where buyers need to supply a parent company guarantee (difficult for small companies with limited operations) or a decommissioning security arrangement, or the sellers may retaining some or all decommissioning liabilities, which can make sales more attractive, to reduce future financial, environmental and reputational risks, and be advantageous for tax benefits depending on individual sale characteristics e.g.age, expected future production, low side risks).

Tax regulations have been written to maximise economic recovery, part of which is to promote late life sales and investment, while safeguarding taxpayers exposure to losses. Needless to say this is contrary to the governments carbon budget aspirations.

Off Topic Finish: E&P Company Proved Reserves

The following data comes from 10-k or 20-f end of year statements of major or large independent operator companies. By the SEC rules since 2007 only proved developed and undeveloped reserves get reported. Some companies from Canada and UK also report probable reserves but these are too few to mean much, and many that do concentrate on oil sands.

Overall the amount expected to be extracted (termed P2) is proved (termed 1P) plus probable (2P). In fact that is the definition of proved plus probable – i.e. the amount with a better than 50% chance of production. Without probable reserve numbers it’s difficult to get a full understanding of a company’s real standing.

A new field typically has probable reserves of 50 to 60% of proved, but there can be a huge spread depending on field uncertainties. As the field ages the ratio tends to decrease to zero at end of life, even if there is overall reserved growth. For companies as whole something similar occurs unless there are continuing decent discoveries, which there has been few of recently except in LTO, or beneficial sales and acquisition activity.

The group of largest companies, whether by accident or design, used to keep R/P numbers around ten years; now I don’t know. Sales, discovery, extension and production figures are usually available for the companies and would give a clearer picture but take an effort to extract; maybe next year depending on lockdown, weather, health etc. issue before then.

These are supposed to be the US reporting companies with largest reserves in order of oil and gas assets (excluding oil sands) but I can’t guarantee I haven’t missed some.

The proportion of undeveloped reserve in the oil and gas totals lies between 35 and 45% for most companies. On average this has been fairly constant over the years considered but an individual company can show more volatility, especially the smaller ones.

It’s noticeable that the two (ex-) national oil companies have lost so much both as a proportion and absolutely since 2014. Petrobras had huge debts and has been selling assets; Pemex has huge debts too but hasn’t sold much but has opened Mexican leases to outside companies – its main problem is a lack of discoveries.

The magnitude of changes since 2014 and 2018 appear independent of the company’s total holdings, which means the smaller companies experience large volatility.

Anadarko disappeared in 2019, Husky and Noble (not considered above) have gone this year and it looks like a few more might be heading that way.

Oil reserves have dropped 6% since 2014, natural gas by 13% and bitumen has gained 13%. I’d expect the probable reserves have dropped by much more for oil and gas, and might be small anyway for oil sands. The ratio of undeveloped reserves has fallen steadily for natural gas but there’s not much of a trend for oil.

Last year’s figures are going to especially interesting given the price crash and large impairments that all companies have reported, combined with a lack of discoveries and a dearth of FIDs (which allow probable reserves to be booked as proved). I expect the drops to be significantly larger than from 2014 to 2015, and that there will be no growth in oil sands but a major downward adjustment. Logic would suggest undeveloped reserves would drop more than developed but that didn’t appear to be the case in 2015.

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7 Comments on "UK North Sea Summary Part II: Reserves, Recent Production and Future Projections"

  1. DT on Sat, 6th Feb 2021 10:53 am 

    Looks like the oil industry is alive and well (pun intended). Somewhat in decline however for many years to come. So much for the so called Clean green transition to renewable, sustainable, FF extenders such as wind and solar.

  2. Cloggie on Sat, 6th Feb 2021 12:19 pm 

    Exactly, and there are enormous fossil fuel reserves in the Baltic as well:

    “Nord stream 2 has started laying pipes in Danish waters”

    “German ex-chancellor sees ‘too much ideology’ around Nord Stream 2”

    “The controversial Nord Stream 2 natural gas pipeline is “in the interests of many European Union countries” and the bloc shouldn’t jeopardize the project, Austria’s Chancellor Sebastian Kurz said”

  3. DT on Sat, 6th Feb 2021 12:41 pm 

    Cloggie I don’t get it why would they be building Gas pipelines in Europe If there is this widespread push for all things clean green renewable and sustainable? Why build FF pipelines at all? You keep saying there is a transition going on and building these projects for FF’s sounds contradictory and counter intuitive.

  4. Cloggie on Sat, 6th Feb 2021 12:48 pm 

    DT, the transition in Europe is going to take 30 years. Until 2050 we are certainly going to need fossil fuel, the rest of the world much longer (if there will be anything left for them, until that time).

    These new pipelines bring us Russian natural gas, that is considerably cleaner than oil, not to mention coal. In Europe, we are rapidly closing down coal and nuke power and the old pipelines through the Ukraine are near end-of life and the dirt poor Ukrainians make supply unreliable by illegally tapping from it.

    The Nord Stream 2 pipeline through the Baltic is the best solution.

  5. DT on Sat, 6th Feb 2021 1:04 pm 

    “Until 2050 we are certainly going to need fossil fuel”

    Really Cloggie? After 2050 no more FF? What will replace asphalt, concrete,synthetic rubber, plastic polymers, agricultural ff feed stocks such as fertilizers, pesticides, herbicides, diesel power for tilling, harvesting and shipping……..Cloggie the list goes on, I am starting to think that perhaps you suffer from some kind of delusional mental issues. Please seek help if that be the case my European friend.

  6. print baby print on Sun, 7th Feb 2021 2:23 pm 

    Dt You didn’t hear about oil on asteroids , coal under the ocean floor , cow manure , ask clogg he will explain you. Shame on you

  7. James bromfield on Thu, 11th Feb 2021 1:18 pm 

    So all is good, the North Sea oil is still abundant and wealth and prosperity will return to the uk citizens.

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