The BP Energy outlook published last month, goes into great detail about the changing global energy mix. From some points of view, it is changing rapidly, but objectively, the “energy transition” is going to be gradual, even with the best will in the world. There is a lot of speculation about when “peak demand” for oil will occur: 2040 seems to be a rough guide, however, it is a plateau and gradual decline. No cliff-edge on the horizon.
Show me the money
What struck me about this detailed analysis is that there is a big omission – at least in the publication – maybe not in the analysis – but who knows? This omission is so fundamental to the world economy, it may just be too complicated, or too scary, to put in.
As I pointed out in a previous post or two, there is a very strong correlation between energy and GDP, and the historical norm has been cheap energy, particularly oil. This is in many ways logical – you look for natural resources in the easiest places (geologically at least), and statistically – throwing darts at a dart board will tend hit the big targets first (apologies to all explorationists out there… not making any disparaging remarks about this noble science – but making a mathematical point). Evidence that energy is going to get more expensive would point to lower GDP growth – and given the world’s population and aspirations for better standards of living – that could be a disaster in the making, and certainly not something anyone would want to draw attention to in something as mundane as a Global Energy Review.
The BP Energy Outlook doesn’t (as far as I can see) address the question of the cost of all that oil that is going to peak in 2040… and here I start to disagree strongly with many pundits. Discussing oil supply without discussing cost is like dreaming of your next vacation without worrying about your budget… a nice exercise but ultimately likely to end in disappointment and tears.
Drill baby, drill
Most people are rightly impressed with the fact that the US shale industry is contributing so much oil to the world’s supply. According to the EIA data, the Permian has increased production by 1 million bopd since July 2015. This is a remarkable achievement. A giant deep-water field like Total’s Egina project offshore Nigeria has been almost a decade in the making with a $16bn price tag, and will add roughly 200,000 bopd, which at first blush looks quite expensive.
However, what is truly remarkable about the US shale is that the Permian has not added 1 million bopd since July 2015. In fact it has added a NET 1 million barrels. According to the EIA data, this region has actually added 4,960,000 bopd over this period. Yes, you read that right – 5 million bopd of new production, which is just less than the output of seven of Opec’s members combined (Gabon, EG, Libya, Ecuador, Algeria, Qatar and Venezuela), or roughly the same as the world’s biggest oil field Gwahar in Saudi Arabia.
But yes, you have spotted the problem: in the same period, “legacy” production has declined by circa 4 million bopd. Hence the net increase. The decline rate on legacy production is just under 6% per month, and maybe significantly the decline rate appears to be on an increasing trend.
(non) Risky Business
Its hard to get clean data, but taking an assumption of 20 days per well, or 1.5 wells per rig per month, and using the active rig data we can get an estimate of the number of new wells drilled since July 2015. This is a staggering 12,183 new wells. Applying an average well cost of $5m, this equates to $61 Bn (to be clear, that is Billion) of DrillEx. At 2018 prices, well costs are probably closer to $7.5m, which would be nearer $90 Billion… (NB here I am using DrillEx to cover drilling and fraccing costs). I have no data on what the split is between producing and DUCs – and clearly some percentage are DUCs, but since half the cost is fraccing, the numbers are still impressive.
It takes a bit of working, and an assumption (based on the data) on decline rates – but by taking a point in time – July 2015 when production was 1.87 mmbbls/day and plotting the decline (5.6% per month) in this “legacy production”, compared to the “new production” that has been brought on by this massive Capex injection we can see that there has been the expected positive effect in production ramping up to 2.87 mmbbls/day in February 2018. I then apply the current monthly decline rate (6.1% per month) to the incremental portion of the February 2018 production – simulating a complete halt to drilling and/or completion activity (I am not suggesting this is a realistic scenario of course – just trying to access the EUR). I then let this run to some production/economic cut-off.
The red area – the area between the two curves – is the total incremental production that will have been achieved by the investment of $60-$90 bn. This volume is 2.4bn barrels – which is not a trivial volume of oil, especially when compared to the last decade’s exploration results in conventional oil.
However, it is easy to see that this is expensive oil as it costs somewhere between $25-$40/bbl – just for DrillEx…. Not including land acquisition, corporate overheads, Opex or Abandonment costs.. If you add all that in, corporate break-evens north of $50/bbl look like a minimum.
It is also salient to think that these numbers cover 2015-2017, a period where the industry focused on the “hot” areas, the sweet-spots, using the best tech, the best rigs and crews, benefitting from several years of efficiency and technology gains (which will be difficult to replicate going forwards), and with limited cost inflation. So, it is very hard to see how the cost of production will ever go below this.
Interestingly, research by Al Rajhi Capital – taking a very different approach (working backwards from company accounts) got to a corporate “breakeven” – of $65/bbl, a number that tallies with all the reports of the LTO companies losing money quarter after quarter.
To equate that to the Liza Field that Exxon and partners are developing in deep-water offshore Guyana, the Phase 1 project cost is estimated to be $4.4bn, which will access some 450mmbbls of reserves. The total project should access some 3.2bn bbls recoverable. For the first-phase (which is usually the most expensive), the development cost is circa $10/bbl. Various deep-water projects report full-cycle costs of $30-$40/bbl and make very good returns once capex is sunk (Opex of $4-$6/bbl on some fields).
Now clearly this is an unfair comparison, because for every Liza discovery there is a trail of expensive disappointment in multiple dry exploration wells – whereas in the shale, the “F” part of Finding and Development (“F&D”) costs is essentially zero. So it would be unfair to compare this on a Development cost basis only. Indeed, this is why Big Oil states break-evens of $40-$50/bbl – you have to have a big expensive machine capable of adsorbing the exploration write-offs to get you to the rare-pearls like Liza. However, from these numbers, even when you factor in finding costs in conventional, (a) shale looks expensive relatively and (b) there is no cheap oil.
The bullish view on shale is that “we don’t know what we don’t know” and that (1) there is a lot of oil (2) we are at the beginning of the learning curve, don’t underestimate US ingenuity and innovation (3) current data could be better used with collaboration. Makes sense. However, as per other commentators, a key question is at what price the incremental. And is the innovation an open ended gusher?
A rather less bullish view can be found in the more technical literature – although oddly it is less reported.
When is a reservoir not a reservoir?
It always grates to read about the new shale “fields”. The LTO plays are resource plays and are quite distinct from conventional oil and gas fields. That being said, is it correct to assume that there is no similarity between conventional and unconventional production behaviour?
In 4Q 2017 we started to hear about the increasing Gas Oil Ratio questions that were being raised. This has, as far as I know not been put to bed one way or another, but anecdotal evidence would seem to point to an increasing problem. Notably, oil production may currently be capped by the ability to handle (read “flare”) the gas – and considerable investment is underway in gas pipeline infrastructure – which if true should lead to a pop in oil production as/when the gas can be exported. That being said, it sounds like additional cost to me. Back in the subsurface, the GOR issue raises the question of whether this is a reservoir pressure issue.
For the technical reader this is whether the oil production is dropping the pressure non-locally below the bubble point and allowing gas to come out of solution and preferentially reach well bores. For the non-technical, its what happens when you open a can of fizzy drink or champagne…. Opening the can drops the pressure, the fizzing is the gas that was dissolved in the drink returning to is gaseous phase.
Conventional wisdom says this shouldn’t happen – as the shale is tight and each well acts as an isolated production pod – only as big as the extent of the fracs. If that isn’t the case then local depletion could start to cause non-local gas issues.
In parallel to the GOR stories, a more recent data point appeared in this months’ JPT – referencing a study by Schlumberger has shown that “child” wells (infill wells) produce less than “parent” wells – in conventional oilfield development this would literally be a surprise to no one if the well spacing was too close and the infill wells drilled after a period of depletion.
The JPT article notes that the production of “child” wells is actually better than the parent wells – but the trick is that this is because bigger frac jobs are over-riding the lower productivity. (NB. This study looked mostly at the Bakken and the Eagleford as these have enough “histroy” to be meaningful). However….
When the results remove the benefit of the longer laterals and bigger loads of sand pumped now, the parent wells outperform the next generation about 70% of the time…
The technological advances that have brought such a bonanza to the LTO regions, may well now be towards the end of the creaming curve with the incremental productivity achieved offsetting the more fundamental problem that over exploitation is causing a classic problem of dynamic reservoir damage. It is hard to see “technology” solving this fundamental reservoir engineering problem anytime soon…
In retrospect, it would have been favourable if early developers concentrated development, leaving significant undeveloped sections for later drilling. But companies rushing to lock up leases by drilling wells had other priorities. JPT
“Americans have more faith in technology that has not been invented yet than they do in God.” Art Berman
The problem is that the older wells are depleting the hydrocarbons and the reservoir pressure required to get them out of this ultratight rock. Fracturing plans aim to stimulate a limited area around a well, but the reality shown in multiple presentations at the fracturing conference show fractures regularly extending out thousands of feet. JPT
It is highly unlikely that this kind of research will feature in quarterly updates from debt-laden shale focused companies any time soon. And none of this sounds like abundant cheap oil.
As an experienced O&G professional said to me this week – when big-oil applies their more systematic approach to shale, and finds that it doesn’t work as promised by the wildcatters, we will see big-oil exiting shale and returning to the search for conventional oil. That will be the sign the party is over. Bye Bye Energy Dominance, Bye Bye Energy Independence… but the supply gap left by this change of focus is truly worrying. Talk of Energy Independence has convinced the world that there is no supply side issue any time before we are all completely weaned off oil. Oh boy.
Paraphrasing Charles Baudelaire and a well known film,
The greatest trick the devil ever pulled was convincing the world he didn’t exist.