This analysis applies only to the crude oil + condensate (C+C) from fields already on production in 2007 (the dark blue field).

The evolution of NGLs will be the subject of separate report later this week by Rune Likvern that will amongst other things examine liquid : gas ratio evolution as well as gas production forecasts.

NGL’s (Natural Gas Liquids)

I am now anticipating a future post on IEA WEO 2008, which will be about…… NGL’s.

NGL’s are mainly proceeds from Natural Gas production. IEA combines NGL’s and condensates in their projections.
NGL’s normally have a volumetric energy/heat content in the range of 70 - 75 % of crude oil.

To describe the “wetness” or “dryness” of Nat Gas from a reservoir, it is common within the industry to describe this through a parameter that shows the development of the ratio between NGL’s and Nat Gas with time. The “wetter” a Nat Gas is, the higher this ratio is, and vice versa.

It has been observed for fields, areas and regions that the Nat Gas normally becomes “drier” with time, i.e. yields fewer liquids per unit of Nat Gas produced. If this is plotted onto a diagram, it shows that the ratio of NGL’s (liquids) on Nat Gas over time has a downward slope.

Click on the diagrams for larger versions.

The above diagram shows IEA WEO projections on NGL’s production. The blue area shows the projection from IEA WEO 2008, the yellow line the projection from IEA WEO 2006.

It is worthwhile noticing that the IEA in their most recent WEO projects a stronger growth in NGL’s towards 2030, while they simultaneously have lowered their projections on growth in Nat Gas production from WEO 2006 to WEO 2008. This suggests that IEA in WEO 2008 projects higher liquids (NGL’s) to Nat Gas ratio than in WEO 2006.

The diagram above shows the parameter of NGL’s to Nat Gas ratio with time. The red line is derived from IEA WEO 2008, the grey line derived from IEA WEO 2006, and the blue line has been derived from BP Statistical Review 2008 (Nat Gas production) and form EIA International Petroleum Monthly Table 4.3 which only lists NGL’s that is without Condensate.

Here it is worthwhile to notice that IEA now projects a higher world NGL to Nat Gas ratio towards 2030. In IEA WEO 2008 there have been found no explanation for this.
Actual figures, though only on world’s NGL’ suggests that this ratio has been running flat through the recent years.

The diagram above shows OPEC’s NGL production (light blue area) stacked on OPEC’s Condensate production (darker blue area) based upon EIA IPM tables 4.1, 4.3 and 4.4 for the years 1980 to 2008YTD (YTD; as of August 2008, from EIA IPM Nov. 2008) plotted against the primary y- axis.

In the same diagram is OPEC Nat Gas production from BP Statistical Review 2008 (for the years 1980 - 2007) shown as a red line plotted against the secondary y-axis. BP SR does not yet list Nat Gas production for Angola, Ecuador and Iraq, and judging from BP data the contribution from these 3 is estimated to be around 2 % of present total OPEC Nat Gas production. Angola and Ecuador are presently listed as having relatively small Nat Gas reserves.

In the diagram note how Nat Gas production for OPEC is growing faster than NGL’s and Condensate’s production. This suggests that the Nat Gas within OPEC is becoming “drier” with time.

Again, IEA defines NGL’s as NGL + Condensate.

As NGL’s and Condensate’s are not part of the OPEC quota system, OPEC members has an incentive to produce these as it generates additional revenues.

It is also worth to take note of that OPEC NGL’s and Condensates continued to grow during the period of the mid 80’s that by some has been referred to as the “quota wars” within OPEC. OPEC lost market shares (both relatively and absolutely) for crude oil to growing production from Alaska, the North Sea and Western Siberia during these years.

The above diagram shows the actual development in liquids (NGL + Condensate) to Nat Gas ratio for OPEC based upon data from EIA and BP (and derived from the tables listed further above in this comment) as white circles connected with a black line.
The actual NGL to Nat Gas ratio for OPEC is based upon actual data from presently two of the world’s present most acknowledged and respected data sources.
The light green circles connected with a black dotted line shows the NGL to Nat Gas ratio derived from IEA WEO 2008.

NOTE: The diagram of the actual NGL to Nat Gas ratio for OPEC shows a downward slope over time, i.e. the Nat Gas becomes drier. This is in accordance with what has been observed as “normal” for fields, areas and regions, and OPEC as a group does not, as of now, represent any exemption.
(More on this in an upcoming post about NGL’s and IEA WEO 2008 on The Oil Drum.)

What is interesting is what has made IEA in their WEO 2008 assume that Nat Gas within OPEC will become 30 - 50 % “richer”/”wetter” towards 2015?

IEA have in their reference scenario forecast a strong growth in Nat Gas production from OPEC (inclusive Middle East) towards 2030, but they have come short of explaining why OPEC Nat Gas grows “richer”/”wetter” in their projections.

This is important as IEA have balanced their liquids supplies towards 2030 in WEO 2008 with an increase in NGL’s supplies, while crude oil supplies has been revised down relative to earlier editions of the WEO’s.

Perhaps some of the readers can help out in explaining this?

Nate, I imagine all these statements apply to parts of the global production stack that matter most to those who made the statements.

It is not possible to make coherent sense out of Chapter 10 of this report because it is incoherent.

Two things though that bother me:

1. IEA make an allowance for higher decline rates in the 69,200 fields not included in their data base and this seems a reasonable thing to do that sets them apart I believe from CERA. Its just that this allowance of +0.9% disappears in their final analysis (Chapter 11) and in their charts.

2. IEA are forecasting decline to accelerate going forward by 1% (on part of the stack) while CERA concluded that decline was constant.

So my best guess right now is that 4.5+0.9 = 5.4% may be a good figure to use right now and that this may increase to 6.4% by 2030. I think it unlikely that the current observed global average is much higher than 5.4% or it would not have been possible to have grown production this year.

I'm very curious about the 30m bpd (more or less) of crude yet to be found plus the crude oil fields yet be be developed. in light of the statements of the companies that are charged with the development of these fields, the amounts seem extremely optomistic.

Since any 'great finds' are likely to be offshore in very deep water or in arctic regions, I don't see how the 2030 production targets could be met with less investment.]

So ... my question is ...

what are these dudes smoking?

Table 9, p239

IEA definitions, all 2P initial reserves:

Super-giant >5 billion bbls
Giant - 500 million to 5 billion
Large - 100 million to 500 million

The rule of thumb is that decline is higher in smaller fields, and so I cannot explain why ME OPEC Giant fields are declining faster than ME OPEC Large fields. Other factors such as onshore - offshore also impact data, so perhaps this is just one of those statistical outliers. ME OPEC production is of course impacted by political field management that clouds the decline story.

More important is a concern I have about forecasting decline in the ME OPEC super giants. The way these fields are developed, they are held on a suppressed plateau for a long time since only parts of these huge fields get drilled and produced at any one time. However, once they run out of new dry oil areas to drill then the fields will fall off plateau and will decline like other fields. This accelerated future decline may not be captured by the historic production data.

Eastender, I think you need to give some thought to two variables which I'm not convinced are handled correctly in your analysis:

OPEC spare capacity

Global Total Liquids production and oil price, January 2002 to present. Production data from the IEA, data files supplied by Rembrandt Koppelaar. Monthly average WTI oil prices from Economagic.

Global spare production capacity from this presentation by Lawrence Eagles of the IEA (link lost). Note how 8mmbpd spare capacity in 2002 had all but disappeared by 2004. It has since then grown slightly but is once again in decline.

Bringing spare capacity on has the effect of lowering observed decline rate and vice versa. If you could incorporate ± spare capacity into your analysis it would likely provide a better picture - I think.

http://www.theoildrum.com/node/4007

Megaprojects planning horizon

The fall off in mega projects post-2012 is almost certainly influenced by a 5 year planning horizon.

Project slippage is also very important and results in over-estimation of new capacity in the near term.

You're not suggesting that the IEA liquids production model upon which multi-billion $ investment decisions will be made is little better than a hand drawn sketch, are you?

I was waiting for someone else to open that can of worms, since it smacked me square in the eye, and yet all the pros are chewing over analysis of minute discrepancies in what looks like unreliable data. Not being from the oil patch, I feel like my job is to read and be quiet -- but you opened the box.

The "red" area is almost 5.5MBD by 2030, and its slope almost exactly mirrors the decline of "conventional" crude. The sum of Crude, currently producing, Crude, yet to be developed, Crude, fields yet to be found and most mysteriously Crude, additional EOR maintains an absolutely flat slope from its peak of 2005!

Is that pure fantasy, or is there some hopeful expectation that the recent signing of the "Status of Forces" agreement with Iraq will finally allow a great deal of crude to be "found" in Iraq?

I went to a play about the life of Buckminster Fuller last night -- I think there is a lot of reason to be hopeful about the world and its people, but I don't derive any hope from CERA, IEA, or their client organizations. But then, I'm not an oil specialist, and I really should just keep my head down.

Hi Westexas,

PEMEX says that Mexico can get production back up to 3 million barrels per day.

http://www.canada.com/calgaryherald/news/calgarybusiness/story.html?id=e...

What do you think?

Cliff Wirth

TROLL DECLINE RATES

Troll production Jan. 1999 - Sep. 2008.


Development in Troll decline rate.

Like the above?

it would be interesting to look at what Simmons calls net decline rates (declines from existing production plus the effect of workovers, enhanced recovery, plus new fields, etc.) for discrete regions, e.g., Texas, Alaska, North Sea, Indonesia, Mexico, overall US Lower 48, etc.

Some of this can be calculated easily enough from the EIA data. Most of the series start at 1981, so since then net decline rates have been:

• All US: 2.0%
• PADD2: 2.8%
• PADD3: 1.5%
• Texas: 3.3%
• PADD5: 2.6%
• Alaska: 3.1%
• Fed Offshore: -2.2%
• California: 2.0%

Using the EIA's international total oil supply data and from each country's most recent peak year through 2007 gives:

• Mexico: 3.2%
• Venezuela: 2.8%
• Norway: 4.9%
• UK: 7.4%
• Indonesia: 4.2%

For those who prefer to exclude certain parts of the oil supply, note that looking at BTU-valued C+C production gives quite similar results:

• Mexico: 3.3%
• Venezuela: 3.0%
• Norway: 5.2%
• UK: 7.6%
• Indonesia: 4.4%

"net decline rates"

This should be the same as what the IEA calls "observed decline", isn't it?
I think that the various deline parameters and its values could be clearer.

I'd wish very much to see a table like this (template with random numbers):

+ perhaps a column with the overall decline from all fields.

Davemart,
do you mean the article "Cold black gold" in the Economist? If not, could you send me (or post here) the weblink to the article you mean? Thanks a lot!

Readers of this site are probably not a very representative sample of the American public.

{redundant comment deleted)

polytropos:

How do we know that the decline rates for OPEC are accurate?

We don't. Even IEA admits this to a certain degree. See more details e.g. at
Fuzzy Focus on Saudi Arabia

ELM

I don't now the right number but I think yes.
See also the most recent posting on ELM in TOD.

Euan,

First, a question regarding your statement that “The IEA is to be applauded for conducting and reporting a detailed analysis of global oil field decline rates”. I have only read the summery and have not seen the section on methodology so please correct me if I’ve interpreted the summery incorrectly. Accepting, for the moment, that the IEA’s decline rate model is correct, do they not apply this decline model to recoverable reserves amounts that are supplied by the producers? In other words, the IEA has not made an independent study of the proven remaining reserves in any of the fields they’ve modeled. They ‘ve modeled their decline assumptions based upon unverified proven reserve values.

Secondly, I’ll offer a rather brash statement that any effort to offer a “decline rate” on any of these fields based on each field’s historic decline rate is rather futile for the most part. I do not condemn the effort to make such generalizations as it’s the only approach available since the producers (especially the KSA) won’t provide the necessary data. Above all else, there is no such number as a single decline rate for any water drive reservoir. Many of the largest oil fields, such as Ghawar, in the world fall into this category. Just for the moment, let’s ignore water injections methods and look at the typical decline rates of such fields. First, there is no such thing as a typical FIELD decline rate. Let’s look at a typical WELL decline rate. Initially, little decline is seen in fields with strong water drives. As the oil is produced the oil/water interface rises and thus maintains a fairly consistent flow rate. But eventually the interface approaches the perforations in the particular well bore. At this point declines rates of 10% to 30% are not uncommon. The total volume of produced FLUID might change little, but the production stream now contains an increasing percentage of formation water. A well originally may be producing 5000 bopd but some time after the water hits the perfs it may still be flowing 5000 bbls of fluid a day but only 2500 bopd since it is now producing a 50% “water cut”. In very efficient water drive reservoirs the well may go from 0% water cut to a 90%+ w/c in just a couple of years.

But even two fields with identical water drive characters, reservoir characteristics and ultimate recoverable reserves may have drastically different FIELD decline rate PROFILES even though the all the wells in both fields have IDENTICAL decline rates. In Field A all the wells have perforations approximately the same height above the oil/water interface. In this situation, the field decline rate would increase very rapidly. In Field B the wells are a different height above the interface and thus individual wells begin the rapid declines in a staggered order. Thus this FIELD’s decline rate would be combination of wells ranging from high decline rates to little or no decline at any one point in time. Field A may enter a decline rate of 35% while Field B may never exceed 10%. Yet the fields are identical except for the locations of the perforations in all the wells.

But there is also a third decline phase in such reservoirs. Once the water cut has reached a high level (75%+) the oil production decline rate will drop to perhaps 1% t0 3% for decades. I work with fields today which were first produced 60 years ago which are still commercial even though 98%+ of the production steam is water. For the last 20 years many have shown decline rates under 2%. And even thought the net oil production is relatively low, many fields have produced the majority of their ultimate recover at water cuts above 70%.

Hang in there if I haven’t sent you into a comma already. This lesson in reservoir engineering is critical to appreciating a POTENTIAL huge underestimate of future maximum global oil production rates the IEA has offered.

Back to Ghawar. This field has not been allowed to develop a natural decline profile thanks to the massive effort by the KSA to inject water into the fields reservoirs (I’m not an expert on this field but I do know it is actually made up of several different “pools” which, though connected, exhibit different flow characters). The water injection program has allowed the high flow rates we’ve seen for decades. It has also greatly increased the ultimate recover of the field. But there is one very critical aspect that this water injection has not changed: the very high decline rate every individual well experiences when the water hits the perfs. In fact, the water injection often results in even higher decline rates then would have been seen under a natural production profile. This is an irrefutable law of petroleum reservoir engineering: at some point in time each well in Ghawar will go into a high decline rate profile. An individual well may jump from a 3% decline to a 30%+ decline in as little as a year. The only technique which can lessen this impact is to reduce that wells total flow rate. Though this would allow an improved ultimate recovery, it obviously reduces the net oil production. Regardless, each well in Ghawar Field, as well as in every other major water drive oil field in the world, will slip into a high decline rate profile. How quickly the ENTIRE Ghawar Field decline rate falls will be a function of how quickly the water interface reaches the various wells in the field. Given the complexity of the multiple pool aspects of the field as well as the very high original oil column, it would be a difficult model if we had all the detailed data the KSA has. And we don’t have it. But that lack of detail doesn’t change the fact that each individual well in Ghawar Filed will enter a high decline rate phase at some point in time. How this fact will affect over all field decline will be a function of how quickly X number of wells reach this point.

Though we can’t verify the fact but let’s assume Ghawar Field is experiencing a decline rate of 3%. This decline rate CANNOT be used to predict the field’s future production rate profile once the water/oil interface begins reaching the perforations in the different wells. It should also be noted that there is a relatively small number of Ghawar for a field its size. This greatly enhances the impact on the FIELD production rate as water reaches more of the wells. But I will repeat myself because it’s that important: there is no such thing as “decline rate” for any water drive oil reservoir in the world. There are at least three distinct decline phases in each field’s life. If one had access to all the data as well as a great deal of man power, one could generate a “production rate profile” for future oil production across the globe. This would require production rate profiles for each major field which would then be combined. But again, there is no such thing as a CONSTANT decline rate which can be applied to today’s rates which would predict future oil production rates at any one point in time. But given the averaging effect we might come close. But that could only be done by generation a complete production profile for each major field over its ENTIRE life. Every water drive reservoir produced be man has generated three unique decline phases: a low initial decline followed by a significantly higher decline followed again by a relatively low decline rate.

I know this is long winded but be patient…here comes a really interesting part. Cantarell Filed in Mexico represents the other major category of reservoir drive mechanisms: pressure depletion, Very simply it’s like shaking up a warm bottle of Coke and popping the cap off quickly. The dissolved CO2 expands quickly and pushes the Coke out of the bottle. Same mechanism in some oil reservoirs: natural gas dissolved in the oil expands when the pressure is reduced when production begins and pushes the oil out of the reservoir. But just like with the Coke bottle the gas escapes quickly and none is left to push the remaining liquid out. Pressure depletion reservoirs typically have low ultimate recoveries…in some case as low as 10%. But there is one very nice aspect of this system. As the field declines the production rate can be plotted on a log-normal graph and typically a very straight line can be drawn to predict the production rate at any future time. To prevent this decline pattern, long ago PEMEX began injecting nitrogen into the TOP of the Cantarell Field to prevent the normal pressure drop. This was done with the largest N2 recovery/injection plant on the globe. As long as the N2 injection volume matches the loss of pressure associated with the oil flow the field would produce at a nearly constant rate…perhaps just a few % decline. This is the opposite of a water drive system which pushes oil up towards the perfs in the wells. Here the N2 forms a gas cap above the oil and pushes the oil DOWN towards the perfs as the gas cap expands. But just as in the water drive reservoirs, eventually the N2/oil interface will begin reaching the perorations in the producing wells. Again, it takes a great deal of detailed data to predict this future production rate profile for the FIELD. But the future production rate profile for each well is very certain: it will be producing 100% oil until the N2/oil interface approaches. At that point the production stream for that WELL may swing from 100% oil to 100% nitrogen in as little as a year. It’s obvious that the interface has begun reaching numerous wells in the last year or so. Last reports from PEMEX I’ve seen indicate a 30%+ FIELD decline rate. But 6 months from today they may be reporting a 5% decline rate. There may be a period of time where the N2/oil interface doesn’t reach any of the remaining wells. But then 18 only from today the interface might reach all the reaming wells over a very short period of time and they could be reporting an 80%+ decline rate at that time. Cantarell Field, though a mega field, represents a small percentage of global production. But it a very critical portion of US refinery source of sweet crude. The decline to date is already impacting our supply chain although that’s been masked somewhat by demand destruction.

Again, I’m not discounting the effort. But consider how very wrong the projection may be should the water level suddenly reach a large number of Ghawar wells in the next few years. This possibility is no more far fetched then if I had made the same statement regarding Cantarell Field 2 years ago. And look where it is today.

I'd say that the correct way to read their statement is that the decline rate worldwide of those fields that are in decline is in the 6.7% range. Other fields that aren't in decline somewhat offset that.

I disagree.
It's a simple birth-death analogy;
present production x exp((birth rate - death rate) x tyears)=future production

Once born you can only die. That death rate is 6.7%.
The birth rate, 'new production from existing fields' is megaprojects numbers plus some kind of factor for non-megaprojects.
Megaprojects for the last few years has averaged at 3 mbpd additional.
The megaprojects projections for 2008,2009 and 2010 is around 5 mbpd.

A 5mbpd 'birthrate'is about 7% --5mbpd/72mbpd=6.95% so oil production should grow by ~200000 bpd each year initially.

Over half of that increase rate comes from OPEC which has no incentive to increase production under low oil prices.

If the birthrate retreats to 3.5 mbpd/72mbpd or 4.9% then
there will be a net growth of -1.8% per year or initially decline about 1.2 mbpd each year.

In 45 years the world will be at an annual decline of .58 mbpd/yr(29 mbpd total)

The oil industry is dying.
No point in throwing good money after bad.

OTH, ethanol production currently at .7 boepd is curently increasing at 42000 boepd increase/yr(6%).

In 45 years ethanol(14 mboepd-390 billion gallons per year-4 billion tons of biomass) will be increasing at .62 mboepd and the rise in ethanol production will cancel the annual decline in oil.

http://www.marketresearchanalyst.com/2008/01/26/world-ethanol-production...

Look for more ethanol investment around the world.

Positive,

And this is where the conversation gets fuzzy. All producing fields are in decline. The decline rate for a new field may be almost zero but it is in decline. But the decline rate for that field will change over time. One of the producing fields may be declining at exactly 6.7%. But no field has ever declined at a constant rate. The hypothetical field I just mentioned may go into a 25% decline rate 2 years from now. If so, how far off would it's projected contribution to global production might this generate? This field might be in a late stage water drive depletion state and the decline rate could drop to 3% in a few years and thus generate an underestimate of its future contribution. There is one constant in the law of petroleum engineering: decline rates for water drive reservoirs are not constant.

This was the point of my long winded discourse above: there is no such thing as an unchanging decline rate in a water drive reservoir. They always change. And such reservoirs make up the majority of the major oil fields in the world. What ever the decline rate at Ghawar field is today, it is an absolute certainty that it will be significantly different at some point in the future. Even if by some fluke the 6.7% decline stated were correct for all the producing fields in the world, the history of all oil production history shows that rate will not stay constant. To predict the production rate of the currently existing oil fields in the world requires a prediction of the changes in decline rates. As I said, if the 6.7% is correct then we know how much oil will be producing from these fields in 12 months or so. But you can't take that rate forward 15 years: it will change.

Something else to ponder: when they say all current fields are declining at rate of 6.7% Does that mean producing CAPABILITY has decline that much in the last 12 months or does that mean the CAPABILITY has declined that since they first started producing? It will be interesting to see how many take the statement one way or the other. It’s also worth considering that historical production levels do not indicate production capability. Oil production rates dropped dramatically in the 80’s do to demand destruction. One can’t take those lower rates as a measure of depletion. Also, at times of high oil prices, operators have techniques that allow them to produce wells above a natural decline rate. During such times you might see little decline and, perhaps, even a growth in production capability. Unfortunately such efforts are relatively short-lived and tend to decrease ultimate recovery. For more then a decade I’ve heard stories from expats working for the KSA that excessive production rates at Ghawar were significantly shortening the field’s life.

I didn’t really want to post that long statement on reservoir engineering. But with few exceptions most statically analysis of historic oil production immediately violates one of the most important assumptions in such analysis: the past profile dictates the future. If this were true then all water drive reservoirs like Ghawar would never deplete: they have little or no decline early in their life. If one were to plot the production from Ghawar for the first 20 years the projected decline would predict many TRILLONS of barrels of future production. Obviously this would be true. The rate changes over time. The only way to predict the future decline rate of such a field is through a volumetric analysis of the reserves. Even if we had this data the analysis is less then perfect and needs to be adjusted over time as the actual production profile is generated.

Er... So actually the USGS numbers for undiscovered are out by a factor of more than 3!

That would only be a true statement if you assume that their 2000 prediction was for discoveries through 2003 and that isn't the case. The image you posted clearly says that the prediction is through 2025.

IOW, some of the numbers significantly outperformed their prediction.

@Aceditor

Thanks for this insightful comment. Have you looked at how the reserve/resources analysis is tied in to the production analysis? As far as I can analyse it at this point the USGS study this time is only used as a theoretical basis to make the outlook look more positive, it is not used in the production analysis at all. I base this judgement on the following statement (page 259, page 66 of the pdf):

"Conventional oil production from yet-to-be found fields is projected to reach 19 mb/d in 2030, based upon the projected discovery of 114 billion barrels worldwide over the projection period."

The 114 billion barrels are a far cry from the 939 billion barrels the USGS wrote down in their 2000 study.

Correct me if I'm wrong, but Wedge 3 "yet to find" I take to be the supply gap, back calulacated from projected demand. Otherwise, "yet to find" oil would decrease with time.

aceditor,

I can offer that the scale of production rate improvement at Weyburn Field may be realistic. I’m not familiar with this field’s specifics but looking at the production curve it may be a combination water-drive with some pressure depletion support. Water flooding fields is old technology. Most big west Texas fields have been on water injection for over 40 years. Gas injection, such as N2 or Co2, has been around a while too. Again, I can only make a generalization, but re-pressuring a reservoir can generate flow rates comparable to its initial high rate in the best of circumstances. These projects are very cost sensitive. Injection is a costly process. Also, the injected gas has to be purchased or generated on site. Both costly. But the pay off can be huge especially in re-establishing high flow rates.

But I would caution accepting any across the board estimate of how much production could any secondary recovery method yield from older fields in the future. If an old field is a candidate for such an effort today it was probably so many years ago and the process had begun back then. But for technical reasons to complex to go into here, not all reservoirs lend themselves to secondary recovery regardless of oil prices. I’ve seen many secondary recovery efforts fail both mechanically as well as economically. It is very dangerous (and likely incorrect) to assume that very many older fields which haven’t undergone secondary recovery efforts will actually respond very positively by future efforts. There has been a large and active segment of the oil patch that has sought out and bought such opportunities for at least the last 30 years. If there is an old field with a few hundred millions bbls of residual left in it and no one is conducting secondary recovery operations in it today there’s a good reason: it probably doesn’t work well in that particular field. And it probably wouldn’t work well at $150/bbl and definitely will fail at $50/bbl.

These decline rates are also a far cry from what a certain consultancy firm has reported. The surprising thing is that they have both used the IHS database and come up with starkly contrasting conclusions.

Gail, those who wrote this need to read and understand the CERA and the IEA reports carefully - assuming they are referring to CERA here. They would then see that the two organisations have reached what appear to be virtually identical conclusions founded on more or less the same data sets.

Great post Gail but it only makes me hunger for more detail. For instance, the decline rates stated: how is decline in production capability distinguished from production curtailed by demand destruction. Even today, if OPEC cuts production what number will we compare production of a year ago? If the KSA produces 10% less oil in 2009 should we take it to mean their production capability declined 10%? Of course not. In my 33 years I’ve rarely seen an operator reduce production rates below the maximum sustainable even in low pricing periods. In the case of Ghawar Field, if the KSA were to reduce pumping for a year or so and then quickly went back to a maximum sustainable rate, they would likely show an increase in production capability over the last period of max sustained rate. This commonly happens in water drive reservoirs that are shut in for a while. You get a bump up in natural rate. Sort of a “catch up” phenomenon. It won’t last for long but if you time your measurements right you can rightly say the field has stopped declining and actually showed an increase in delivery ability. It’s just one of several ways in the oil patch to support a misrepresentation with truthful facts.

When Matt Simmons spoke at the ASPO-USA meeting in Sacramento in September, he mentioned that a few months before, he had performed a spot poll at a Baker Hughes' meeting. He asked a room of about 120 or so of their top field managers from around the world what their decline rates were? If I remember properly (fee free to correct me here) he used less than 4%, 4-6% and 6-8%. He said none of the hands went up for 4% and under, 20-30% for 4-6%%, and about 60% voted for 6-8%, with the rest being above 8%. Obviously, there’s a bias due to their field portfolio, but he felt it was telling that no one raised their hand for <= 4%.

Matt’s pointed out many times that only 5% of the proven reserves and production data has been audited, so if CERA, IEA and EIA were actually using scientific data analysis, the error values on all of their graphs would be larger in both magnitude (oil volume or y-axis) and timing (date or x-axis) than the differences that we are discussing: 87 MBD vs. 100+ MBD for production and 2005 vs. 2030 plus for peak oil. To give an example of how the devil is in the details that no one may be able to see, the MMS uses an average UTRR rate of 60% for the 120 billion barrels they estimate can be recovered from the U.S. outer continental shelf. This is probably high by a factor of 2. I also question the IEA's new production capital cost gestimates. EIA’s data showed both on and off shore production costs have been rising faster than IEA’s model. They also ignored Resource Nationalism, which will come into play as exporting countries production approaches their internal consumption.

An interesting counter point to the IEA report was Peter Well’s presentation also at the ASPO-USA Sacramento meeting. He purchased the IHS data for about $100k and augmented it with proprietary data from KSA. He felt that peak crude would occur in 2018 with crude + condensates in 2020. I would put far more stock in his work because they actually checked their predictive models against existing depleted fields (~95% match) and showed the uncertainty in their future projections.

To be fair to them it goes without saying that some new fields are going to be discovered and developed and that EOR is going to be a factor. I don't think that's blind faith. The issue to be resolved in policy terms should be whether the rates they predict for that are reasonable based on trends over the last couple of decades or whether they are using it as a fudge factor in a wildly optimistic manner to get the politically required prediction (at least for public consumption) of continuing growth.

The IEA graph shows that this organization is not interested in facts. It is claiming that 45 million barrels per day will be produced in 2030 from existing undeveloped and newly discovered. As noted on numerous occasions above this is a contrivance to keep the world production of conventional oil flat for the next 22 years. Do they seriously expect people to believe that there is 2/3 of OPEC production sitting in reserve around the globe? They obviously believe Saudi claims about 12 million barrels per day of production capacity and apply it to the rest of the producers. Only the Saudis make such claims, so the IEA has no basis to extrapolate in such a stupid manner even if the Saudi claims are true.

Given the decline in discovery, which is statistically significant and not some transient induced by oil prices or above ground factors, the light blue zone is what the yet to be found production should look like and not like the rapidly expanding red zone. Since there is no evidence that the reserve production capacity is anywhere as large as claimed by the Saudis, the light blue zone should be much thinner.

The natural gas liquids zone is also a contrivance since it is monotonically increasing when in the real world all the major gas basins are not growing and many are in decline (North America and the North Sea for example, Russian gas will be in decline by 2020). Total oil and liquids production in 2030 will not be 100 but probably less than 70 million barrels per day in 2030 assuming no catastrophic declines occur such as Saudi fields going the way of Yemen's Yibal.

Shortly after the great tsunami hit, I was reading Gibbon’s “Decline and Fall . . . ” and I came upon a wonderful description of a similar event in antiquity. Whilst on the plane back from Berlin today I had a similar experience whilst reading Tacitus’ “The Annals of Imperial Rome” A wonderful description of a credit crunch, complete with property slump and government bail-out. From the reign of Tiberius:

Then Tiberius came to the rescue. He distributed a hundred million sesterces among specially established banks, for interest-free three year state loans, against security of double the value in landed property. Credit was thus restored; and gradually private lenders, too, reappeared. However, land transactions failed to adhere to the provisions of the senatorial decree. As usual, the beginning was strict, the sequel slack.

http://rustle.blogsome.com/2008/11/18/credit-crunch-in-ancient-rome-3/

Any explanation of political collapse carries lessons not just for the study of ancient societies, but for the members of all complex societies in both the present and future. Dr Tainter describes nearly two dozen cases of collapse and reviews more than 2000 years of explanations. He then develops a new and far-reaching theory that accounts for collapse among diverse kinds of societies, evaluating his model and clarifying the processes of disintegration by detailed studies of the Roman, Mayan and Chacoan collapses.

http://www.adlibris.com/se/product.aspx?isbn=052138673X

Joseph A. Tainter (December 8, 1949) is a U.S. anthropologist and historian. He studied anthropology at the University of California and Northwestern University, where he received his Ph.D. in 1975. He currently is the Head of the Department of Environment and Society at Utah State University. His previous positions include Project Leader of Cultural Heritage Research, Rocky Mountain Forest and Range Experiment Station, Albuquerque, New Mexico and professor of anthropology at the University of New Mexico. Dr. Tainter is also the author or editor of many articles and monographs. His best-known work is The Collapse of Complex Societies. This 1988 book examines the collapse of Maya and Chacoan civilizations, and the Roman Empire, in terms of network theory, energy economics and complexity theory. Tainter argues that societies collapse when their investments in social complexity reach a point of diminishing marginal returns.

According to Tainter, societies become more complex as they try to solve problems. Social complexity can include differentiated social and economic roles, reliance on symbolic and abstract communication, and the existence of a class of information producers and analysts who are not involved in primary resource production. Such complexity requires a substantial "energy" subsidy (meaning resources, or other forms of wealth). When a society confronts a "problem," such as a shortage of or difficulty in gaining access to energy, it tends to create new layers of bureaucracy, infrastructure, or social class to address the challenge.

For example, as Roman agricultural output slowly declined and population increased, per-capita energy availability dropped. The Romans "solved" this problem by conquering their neighbours to appropriate their energy surpluses (metals, grain, slaves, etc). However, as the Empire grew, the cost of maintaining communications, garrisons, civil government, etc. grew with it. Eventually, this cost grew so great that any new challenges such as invasions and crop failures could not be solved by the acquisition of more territory. At that point, the empire fragmented into smaller units.

We often assume that the collapse of the Roman Empire was a catastrophe for everyone involved. Tainter points out that it can be seen as a very rational preference of individuals at the time, many of whom were actually better off (all but the elite, presumably). Archeological evidence from human bones indicates that average nutrition actually improved after the collapse in many parts of the former Roman Empire. Average individuals may have benefited because they no longer had to invest in the burdensome complexity of empire.

In Tainter's view, while invasions, crop failures, disease or environmental degradation may be the apparent causes of societal collapse, the ultimate cause is diminishing returns on investments in social complexity (in contrast, Jared Diamond's 2004 book, Collapse: How Societies Choose to Fail or Succeed, focuses on environmental mismanagement as a cause of collapse). Finally, Tainter musters modern statistics to show that marginal returns on investments in energy, education and technological innovation are diminishing today. The globalised modern world is subject to many of the same stresses that brought older societies to ruin.

However, Tainter is not entirely apocalyptic: "When some new input to an economic system is brought on line, whether a technical innovation or an energy subsidy, it will often have the potential at least temporarily to raise marginal productivity" (p. 124). Thus, barring continual conquest of your neighbors (which is always subject to diminishing returns), innovation that increases productivity is -- in the long run -- the only way out of the dismal science dilemma of declining marginal returns on added investments in complexity.

http://en.wikipedia.org/wiki/Joseph_Tainter