By George Kaplan
Norwegian oil production peaked in 2000 to 2001; gas production may be peaking about now. Oil hit a low in 2013 and then recovered towards a new local peak, probably concurrent with the gas.
Drilling and Development
The most surprising thing I find with their industry is that the drop in oil price made almost no difference the drilling activity shown here (all data here and below taken from the NPD - Norwegian Petroleum Directorate - which provides more data than just about any other such organisation).
There was a high level of drilling activity in 2013 and 2014 which then actually increased in 2015 and was still high in 2016, although exploration well numbers look to be decreasing now. This may be just a consequence of the momentum built up in the high price years, or because of the influence of Norwegian regulatory regime (which has always sought to smooth out development activity, though less so recently with new Conservative governments), or a move to new frontiers in the Norwegian and Barents Seas (the background area chart shows proportion of wells in each sea). The development wells marked N/A (information not available) are probably mostly oil judging by the fields being drilled, the non-production wells are mostly injection with a few for observation and disposal.
The number of rigs and proportion of dry wells have remained pretty steady, as has the proportion of subsea wells. A few of their platforms have dedicated drilling rigs, which means it's fairly cheap to drill new wells and allows even small, near field deposits to be developed - for example Troll Brent B is a new field in production this year with only 24 mmbbls OOIP (and likely relatively low recovery), and Sindre another which is so small there are no estimates yet. They also use wellhead platforms with jack-ups, which allow lower cost wells than a full subsea development.
The drilling has not resulted in many discoveries, only the two small fields mentioned above are true 'reserves' added in the last five years, although there are a few potential 'resource' finds (for description of the meaning of the resource categories 4F etc. see below). Overall, though, there has been a decline in industry activity. Approvals for development fell a lot in 2015 and 2016, but there has been a recovery this year - mostly for small near field tie backs or outreach wells I think - and in particular overall investment fell markedly for the first time in 2014 through 2015 after almost continued exponential growth, and will likely be down again in 2016.
New production coming on stream has been steady - a result of past decisions, and lease activity has actually increased, with the Norwegian and Barents Seas attracting interest (though the North Sea looks close to the end now). The time to develop fields from discovery has reduced as the basin matures, this closely matches the UK and probably most other areas; currently it is averaging around four years, which means most of the developments are small and require relatively little appraisal, design and construction effort. In the chart below the all the numbers are normalized against cumulative totals (leases by acreage, discoveries by recoverable oil equivalents).
Despite the maintained drilling activity oil production is likely to start falling again in the next couple of years.
The big fields, Ekofisk, Statfjord, Gullfaks and Oseberg, are now close to exhaustion and some are in gas blowdown phase; recent growth has been from many small fields, often subsea tie-backs. The drilling activity from 2010 seems to have arrested a lot of the decline in the older fields and produced a plateau, with newer fields providing a slight increase.
Their more recent success growth has been from gas production with Troll the biggest by far, but also from Snohvit (producing LNG in the far north) and Aasgard, Sleipner and Ormen Lange. However they are producing these fields hard (possibly to meet sales agreements) and production may be peaking now: and recent additions have been from increasingly smaller fields. Ormen Lange is definitely in decline and Troll production allowance was recently increased by the government, possibly to fill the gap. LNG fields often have long delivery agreements, twenty or more years, and fixed production over that period, but I don't know if that is the case for Snohvit (they could have come up with a better name as well, if you ask me - I actually did some work on it a very long time ago when they were looking at a floating option, and did bits and pieces on a lot of the other fields too).
Note that the chart shows actual field wellhead production, however a lot of the gas has been re-injected for pressure support on some of the bigger fields, and is (or will be) only produced for sale later in the field life.
The evolution of reserves for oil and gas is shown below. NPD provides initial discovery and current reserves. I couldn't quite match these up with production numbers. It's pretty close for oil but not for gas. I used sales figures for gas (to allow for reinjection) but even so there was about 25% more gas than the reduction in reserves (compared with only 1% for oil). This may be partly to do with measurement issues or with conversion between gas volumes and equivalent barrels (or partly my misunderstanding - if anyone knows more please elaborate). I've shown the NPD remaining reserve number against 2017 in the charts.
NPD do not follow the proven-probable-possible-contingent categories used most other places but have reserves and resources at various levels depending on their stage of development. They also split things as 'F' for first, and 'A' for additional (which I think covers things like EOR if it is being considered). The numbers given below are all for 'F' resources only (it might be there are no 'A' allowances in any of the fields currently). I've only included details for the resource values that might be developed, that doesn't mean the empty entries are zero.
The big uptick in 2010 is from the Johan Sverdrup discovery, which was almost 2 Gb, found in an area which had been thought to be fairly well explored already. The largest field in the resource categories is Johan Castberg, which is in the Barents Sea. It is a marginal development at current prices, as it needs an FPSO, presumably with some kind of ice resistant hull, and extensive subsea infrastructure. Most of the other resource-only fields are pretty small.
It's also fair to say that the progress for exploration and development in the northern seas has not been particularly positive. The Snohvit LNG plant and Goliat oil platform each had significant start-up issues. There were high hopes for (expensive) oil exploration wells that have come in dry or with small gas finds (e.g., Korpfjell and Gemini Nord for Statoil this year). Smaller oil discoveries, like the Kayak well at 20 to 50 Gboe and near the expected Johan Carlsbad development, cannot be developed as easily as in the North Sea as there is far less infrastructure (e.g. making gas monetization very difficult so it has to be reinjected) and fewer anchor facilities (i.e. only one at the moment) that can support tie-backs.
I had a go at projecting oil and gas production based on stated reserves and resources, projects in production and development, and known discoveries. The dominance of gas production makes some of this quite difficult - small gas fields might be produced for only a few years, whereas large ones have long, steady plateaus (maintained by adding compression and new wells) and then can die suddenly.
I've included all 4F resources, most 5F and about half 7F (such fields are in lower case). The yellow line shows the limit for fields in production, the white one shows fields in development and those above are in appraisal. The new oil production is dominated by the Johan Sverdrup field, its phase II development is not yet approved but will almost certainly go ahead. Johan Castberg is the second largest, and also pretty likely to proceed (eventually). The total developed liquids, assuming the curves run out forever is 15% above the NPD remaining reserve and resource number (thus allowing for some earlier end-of-life shutdown and a bit of reserve growth).
I'm not sure if the decline around 2019 will actually be seen - it's similar to numbers seen before 2010, but much steeped than has been maintained since. However if the decline rate is reduced near term then it will have to get steeper some time as depletion always wins in the end. To some extent they look to be in a red queen race - trying to maintain a short term plateau to 2030, even the Johan Sverdrup development has much higher production rates than would have been used in the past for such a fields size.
There are some other probable projects that might add more oil. These are redevelopments of existing mature fields. I have included some - e.g., Njord-Hyme, Snorre IOR and Frigg - but there are other possibilities. One of the biggest is Yme, which is an old field abandoned as uneconomic in 2001. NPD do not list any reserve for it, but only about 15% of the OOIP has been recovered. Repsol installed a jack-up to start redeveloping the field, but it was declared structurally unsound and was removed without ever operating in 2013. They are likely to have another try soon.
For gas things are dominated by the long plateau on Troll. There are far fewer undeveloped resources and reserves than for oil and it looks to me that production is peaking about now and decline will soon be obvious. The yellow and white lines show producing, in development and appraisal fields and, as for oil, the total developed natural gas (and NGL), assuming the decline curves run out for ever, is a bit above the NPD stated remaining combined reserves and resources for the fields included.