Khebab,

Your final graph is interesting. Are you estimating annual decline as the percentage increase of [this year] over [previous year]? Would you care to speculate about the reasons for the change in character of the curve after 1960? Before then it seems almost uncorrelated year on year, whereas after 1960 it gets much smoother and remains so for the next four decades, apart from the last hurrah (Prudhoe Bay?) in 1978-ish. What changed in 1960?

Thanks Khebab for your useful comments

hmm... maybe but it seems that growth is occuring mainly in the other liquid category:

Correct

growth in C+C seems to have stalled despite planned new supply from megaprojects:

Correct but is this a temporary trend or a sustained one? That is the big question, which is very dependent on what is happening in Saudi Arabia, Russia and Iraq.

It seems to me that these forecasts have been somewhat optimistics and were forecasting something very close to business as usual (i.e. ~2%/year growth in supply). The actual production plateau was not predicted (see chart above). Have you conducted a post-mortem analysis?

Yes, I have the projects in my database, and did some post-mortem work. One could even argue that the decline is somewhat smaller, if the decline in Saudi is voluntary. I still don't feel that we have a definite answer on this.

The presence of a plateau is not obvious on your Figure, it seems that production growth from 2005 to 2010 is pretty much inline with the growth we had between 1982 and 2005.

That depends on how one defines plateau. I called it an upsloping plateau, which in the light of demand growth is correct (demand outstripping supply).In the absolute term it is incorrect. Next to that it also depends on what numbers one takes, Liquids Production has increased with 1 million barrels per day from 2005 to 2006 according to the IEA. However the EIA figures do not show such an increase but a "real" plateau.

The point of this exercise was not to look at a plateau vs peak from a micro scale but from a macro scale. Ill try to be more clear next time in my definitions!

Is the decline rate stationary? if you look at production decline in mature regions, the decline rate seems to linearly accelerate (~0.13% per year):

First we need to define what we mean with decline rate, in this post I looked at the total stock of existing fields (including those in a built up phase of production, on plateau and already past-peak). Your chart seems to include total production over time, not total production from a point in time. And then the development of the decline rate over time of that amount of production.

As to whether the decline rate is stationary, it is not. According to some it goes in cycles because of the addition of new production (in the case of existing stock through technology), and the outfasing of quickly declining oil fields over time. The technological vision is that the decline rate can be slowed down in a period of high oil prices.

To my opinion it is not correct to compare the development of decline rates in one oil producing region to another. This will lead to bad estimates because each region has many different characteristics. The problem here is then again a lack of data. While logistic models in general if sufficient correct data input is supplied can give an excellent outcome, we don't have such data. Fortunately over time we are getting somewhere, data quality is improving!

Rembrandt, thank you for reminding me that price signals require years to work their way through stucture-intensive industry, and also for the the excellent analysis you generously contribute.

PLAN, PLANt, PLANet
Errol in Miami

Deuterium,
I wasn't commenting on fields that are currently producing like Cantarelle, but rather on fields like Baku which was discovered in the 1880's and few reservoirs waterflooded or the giant American fields that were far past their peak in 1980.

There's a great paper on CO2 enhancement published by the US Department of Energy and available online. I'd link it but I'm a computer moron, but its entitled "Ten Basin Oriented Strategies for CO2 Enhancement" .
try this:
http://www.fe.doe.gov/programs/oilgaspublications/eorco2/east-central-te...
I'll finished this post, then looked for the link again to try to hook up. But any rate, the DOE says that on fields like that the production averaged around 10% of the original oil in place in the United States, so that leaves a target of the balance of the oil in place-as much as 6 times the primary production, as a target for tertiary production. This assumes that the US has a big enough sample of the world basins for its statistical conclusions to be useful worldwideThe particular assessment i linked to shows 80 billion barrels from the Giant Fields of the Texas Gulf Coast and the Panhandle. Thats right, the geographical assessment makes no sense, it seems to be all oilfields outside the Central and east basin platforms of the Permian basin, but the info is good.
Bob Ebersole

Tuning the extraction rate up and down using the Oil Shock model gives insight that you can't get from HL. FWIW

deuterium, look at my posts downthread. Off shore wells that are drilled horizontally don't run out of oil more quickly than onshore wells, but rather the workovers cost 10 or 20 times as much as the equivalent workover on an onshore well, so the well can't be produced for years at low level of production with a high water cut.

Think about the geometry of a horizontal well. The centralisers on the rods rub up against the casing, rods are hard to screw and unscrew after pumping under stress, and the oil must flow by gravity through the horizontal leg to get to the downhole pump. If the well sands it must be jetted out with high pressure water after pumping the water through coiled tubing, its not like a 5,000 ft verticle well. Plus, workover rigs are mostly on a barge and require a captain and an engineer as well as the tool pusher for the workover rig. It just plain costs a million bucks for a workover that might cost $100K onshore with a rig thats trucked in and half the crew size.
That means that a well becomes uneconomic much more quickly.
Bob Ebersole

Rembrandt,

First, let me disqualify myself a little. I was an english major in school, because I loved hippy girls, the beautiful sounds of words and was lazy to boot. I was drafted into oil and gas exploration by my father, an Oil and Gas Title Attorney , but my family's first real involvement was in about 1950 as investors in Houston. Something really strange happened, after 2 years or so I discovered I loved the oil patch and buying oil leases and had a real talent for parts of it. I can follow many mathematical arguements and know a lot about geology, geophysics and technology, but my best guesses about physical quantities are just that, good guesses.

I really appreciate the bottom up analysis that you have generously shared with us, and I could no more do your work than a duck can tapdance I'm really awed by your work, and Khebab's,Stuart's, Ace's and the rest of the quantitative guys with real mathematical skills.

Oil production and consumption has been increasing staedily for years, and the fields that I consider candidates for tertiary development all had their peaks before 1970. The world produced about 60-65 million barrels per day. The natural pressure in the fields was expended, and the fields will have to either be repressurised through waterflood, gas injection or CO2 injection to get much production, and that will be both expensive and require lots of high level engineering. So I'd say as a practical matter that if we could get 5 million barrels of oil per day for the next 30 years this would be a resounding success.

If you'll look at the National Petroleum Council reportgraphs, they suggest that in 2050 the world could get 40 million barrels of oil per day from tertiary develpment, which I consider wildly overoptimistic. Westexas suggests that all this type of production will do is slow the decline, and I think he's right about this. But the resource is real and should extend oil production a long time past my life, though, although not at the rates they suggest.

Why its not being done as yet is based in contemporary history. The big oil companies started to consider the US to be geopoliticially unsafe about 1973 when Richard Nixon put price controls on US oil, followed by the Windfall Profits Tax. They changed the whole focus of their exploration to natural gas offshore in the Western Gulf of Mexico in shallow water areas. They were barred from drilling in the California and West Coast areas after the Santa Barbara blow out, and NIMBYism was created in Florida and the US East Coast too, and the Exxon Valdez oil spill at Cook Inlet barred them from ANWAR. This was an reaction to the sixty years of political manipulation by the owners of the major oil companies who had resisted the New Deal, sold gasoline to the Japanese in their war of conqest in China, and the Nazis in their invasion of Poland. The majors redeemed themselves with their efforts in 1942 building pipelines to the East Coast of the US. But, all my life the Major Oil Companies have caused major problems in both the USA and the rest of the world. Now 88% of the exploration areas of the world is controlled by National Oil Companies (source:API), and nobody except themselves have considered it to be unjust or undeserved.

The Upstream arms of the multinational oil companies are designed to do one thing-locate and produce new Giant and Supergiant oilfields. And they are superb at that, now they are pretty well out of new areas to explore, although deep water technology is adding new deepwater areas, and therefore more prospects. The big boys can't make money anymore on establishing new fields or even step-out wells onshore in the USA. Their internal overhead is so bloated that a 10 million barrel of oil reservoir won't make them any money . They sold off almost all their Gulf Coast and Mid Continent production, they are operating very few fields except in the Permian Basin and California in the USA. In other words, they no longer have acreage positions or wells in the old fields in the USA onshore basins, and the ones that they do have still are mostly already developed.
Bob Ebersole

My grand father was a Blacksmith I am a Lawyer My Grandson will be a Blacksmith.

Regarding Russia, the newspaper article that everyone quotes is a July 10, 2007 Moscow Times Article:

Alfa Report Sees Trouble Looming in Oil Sector
By Anatoly Medetsky
Staff Writer

Alfa Bank warned on Monday that "production stagnation is unavoidable" at the country's oil fields and further downgraded its target prices for shares in most Russian oil companies.

The dramatic worsening in its outlook was the result of the government's reluctance to consider lowering taxes on oil firms and a higher proportion of water in the declining output, the bank said in a research report.

The IEA was quoted in the Moscow Times as saying

IEA Sees Oil Output Plateau
Reuters
LONDON — Russian oil production may level out from 2010 to 2012 and stall until the middle of the decade, the International Energy Agency said Monday.

The IEA, adviser to 26 industrialized consumer nations, said it had based its forecast on a study of the top 20 development projects through to 2012 and an assumed 3 percent annual net decline rate for baseload production.

If you put in a more realistic decline rate than 3%, the result is clearly worse. Claude Mandil of IEA is quoted as saying:

Demand for oil will increase in the coming years and, taking into account the decline from non-OPEC country production (Russia, Norway, UK, ...), OPEC's share of the world market will increase in absolute value by 2050.

This statement doesn't say Russia, per se, is declining, but it is not expected to increase enough to make up for the decline in other countries.

Other comments that seem to bolster the view of a near term decline in oil production is this one from Jeffrey Brown:

What I found interesting in the article was the statement by an executive VP with the TNK-BP Joint Venture, Kris Sliger, "What could be wrung from the older fields has been tapped."

The Russian Energy Minister previously warned of the possibility of a "real collapse in oil production," (if they don't launch an immediate frontier exploration program).

Also, Jeff Rubin of CIBC in Canada, speaking at this year's ASPO conference sees little growth potential for Russian oil, according to Heading Out:

He felt that Russia’s role in providing a growing supply is beginning to be played out, with rising domestic consumption of up to 4.5% swamping any gains in production. He thinks that current export levels will be the best that Russia will provide, at around 7 mbd, and the shortfall from anticipated growth will not be available from OPEC.

Finally, in the papers circulated to staff by Euan Mearns on October 11, Ferdinand Banks of University of Uppsala, Sweden in "Architecture of World Oil" says:

The output of Norway has almost certainly reached a summit, Russia is at or approaching a peak (but in any case the macroeconomy of that country is progressing in a fashion where there will probably be less oil to export) and in a decade or earlier there will be a peaking of at least one of the large suppliers in the Middle East. Accordingly, it is not too early to ring the alarm bells.

Regarding China, part of the evidence is in the form of lack of production. Production is barely inching up:

2005____3,609
2006____3,686
2007 YTD July___3,725

Also, Prof. X. Pang of ASPO China, speaking at the ASPO conference in Ireland, presented this chart:

Memmel,
Russia is mostly onshore production. King Hubbert drew up his data from analising onshore basins because offshore didn't exist very much before his retirement and death, just as the 3D seismic and horizontal drilling didn't exist, or producing tar and calling it oil.Bob Ebersole

All peak predictions. I repeat. ALL peak predictions are based on Deffeyes.

That isn't actually true now is it. For example, I don't see any Deffeyesian influence in Skrebowski's work.

Excuse me, but I can't remember Kunstler or Deffeyes calling a peak in 1998-1999 and 2000-2002.

Kunstler has always used other data as reference, and Deffeyes did call a peak on Thanksgiving Day 2005.

Could you provide some reference?

PS: Excellent work, Rembrandt, many thanks for this, you always spark the most intelligent discussions here!

Thanks, this might be very, very interesting!

Which does look to be what people are going.

Personally I'd say we are set for a wavering plateau for the 5-8 years as the plays of various countries come out and are countered. As we get towards the end of that time things will become increasingly desperate to keep the production up. Fields will be overproduced. At the end of that period some major event, an invasion, pandemic, depression, etc. will hit and not cause, but herald, a reasonable steep decline (~8%) as things stop working, systems break down and serious insurrection strikes.

I think national and international entities are planning for such behaviour (SA, US, Europe) and are just about at the stage of taking the covers off their game plays for the transition period.

As the curse goes: may you live in interesting times.

Davidyson:

That depends on whether the gas-oil-water separation plant has a dual use and its original capital cost.

The hydrocarbon stream is mostly an emulsion in formation and as it gets to the surface. But it costs damn little to sepate the oil, gas and water. Gas bubbles out of oil when the pressure drops at the surface and oil floats on top of water. Mostly its just done with a storage tank, and sometimes a heater treater and some chemical to break the emulsion. And since the storage tanks can be used for a little hoarding, a dual purpose, too big for the wells that the tanks serve doesn't cost much money.

Seperators work either by heating the emulsion so the water drops to the bottom or by adding an emulsion breaker chemica. An engineer around here can tell us the cost, but its not too much. The casing head gas that bubbles out of the emulsion is used for fuel for heating the oil on a lot of wells. Other than that use or as fuel for pumping units, the gas has to be compressed again to put in a pipeline. Overseas, where it can't be monitored by governments with an idea as to its value, the gas is flared (burned as waste).

At any rate, all of this is cheap and off-the-shelf equipment that is portable on trucks. The real limitation on continuing to produce wells with a high water cut is the high per well overhead of major oil companies. I'm sure that companies like BP or even Talisman add on a factor to each well that amounts to a cost like this-something like $1,000 dollars a month per well to operate a well, and maybe $20,000 a month for the lower limit of a field. The real constraint is inengineers and oilfield workers-a person can only look after so many wells at once, and the labor cost always grows as the production gets worse. Older equipment breaks down more often, and requires more frquent workovers. The main reason it drops off so radicially offshore is that workovers cost 10 times as much or more than onshore workovers, and the more the workover costs the more oil the well has to make to be profitable.

I don't know that I've explained this very well, so let me give an example. Suppose you have a well that has a potential of 1,000 barrels a day brand spanking new. In two or three years it starts making a significant water cut, maybe 50%. The well is still worth producing, its making 500 barrels of oil and 500 barrels of water, so a million dollar offshore workover pays back quickly, plus the operator has 30 or 40 wells in the same field sharing the overhead.
After 7 years, the well needs another $1million workover, but the water cut has gone to 70% and the production declined to 300 bbls a day because of the high water cut. After another year the well needs new flow lines and tanks, while the oil cut has declined to 10% or 100 bbls a day plus it needs another million dollar workover. It becomes clear that the operator isn't going to get its money back and the operator plugs the well and salvages the equipment. And thats the reason offshore wells have a big production decline at the end of the well life.
Meanwhile, onshore the same workover costs maybe $50 K as opposed to $1 million offshore. The wells can still be profitable producing a 2% water cut on 1,000 barrels a day worth of fluid, so the wells are produced virtually forever.

Its all about overhead and being a low cost operator. Bob Ebersole

The problem is it seems everyone is high even HL is probably underestimating future decline rates.

If we don't have a good lower bound then ?

So far contemplating the possible lower bound i.e HL corrected for offshore vs onshore production gives a lower bound estimate well below current predictions. This means in my opinion some of the proposed productions scenarios are simply wrong and should be discounted.

This means that current HL predictions should be used as the high estimate. The shock model could provide lower bounds.

In effect most of the bottom up approaches can readily be discounted with the single exception of Bakarahti.

JK - I have history matched Chris's forecasts for the past 3 years - there's an interesting story - but want to give him the chance to repsond to my queries first.

For example, he expected a substantial increase in 06, not shown in the above and which did not occur, in addition to a substantial increase in 07, shown above, and which also did not occur, or at least not yet.

Remember the past = demand and the future = capacity. How do you know the new projects did not materialise? My view is that most probably did, and Saudi cut production to make way for the new capacity.

Oh, I agree. Reserves growth will not affect the peak much. We're talking about longer term reserves projections here.

I've only said this about a million times on this website and elsewhere.

Speaking as a Canadian, that's certainly way up there on my list of worries.

"You want to do WHAT? Abrogate NAFTA? I don't think so, my little snowbound friend. Let me introduce you to my good buddy Mr. M1 Abrams. Of course you'll be getting to know him very well, so you can just call him 'M1'. Now out of the way, he and all his chums are heading to Fort McMurray."

If I had money to blow...I would be investing like mad right now in companies that specialize in heavy crude processing/refining.

yes, looks like we're going to have to learn to share :)

The very broad overview of potential production given above of course cannot cover all of the potentially significant factors -

Beside the probability of geoeconomic turmoil as global capitalism enters recession
(with the knowledge that PO (energy denial) and GW (insurance denial) both preclude any normal recovery of investor confidence]
which would hinder the vital development & deployment of non-fossil options,
there is also a further major obstacle that may be worth noting.

Namely effects of the growing number of extreme weather events.

For instance, following the damage to Thunderhorse in GOM, a series of repair dates have now slipped to the end of 2008,
and the main owner, BP, is pulling out of all GOM operations bar this and one other mega-platform.

So how soon will weather costs, whether direct or via insurance, make the GOM somewhere the industry as a whole would rather avoid ?

Personally I doubt that any reliable prediction of future oil supply can be formed as I am already seeing cascade effects of cock-ups, cocked-up conspiracies, and their compounding consequences leading to absurdly unpredictable outcomes.

For instance, a tree-damaged drainpipe at a disease research lab,
an unprecedented rainfall event,
and Britain's mountain sheepfarmers lose half their year's sales income via markets' untimely banning for a Foot & Mouth outbreak --
Just how likely (predictable) was that outcome ?

And we are only at the start of the steepening of the curves of the key problems' intensification.

Regards,

Backstop