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157 comments on The 2008 IEA WEO - Production Decline Rates
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157 comments on The 2008 IEA WEO - Production Decline Rates
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Good analysis, however, one more piece of data is needed. Does the 4.5% decline rate apply to TOTAL liquids production or to just the crude oil, excluding NGLs?
Since NGLs are increasing this could make a difference to the aggregate decline rate.
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.
Euan,
Very good points and related questions!
As I understand, the IEA decline rates apply to conventional crude and condensate (C&C), for which 2007 production was about 70 mbd. Unconventional crude production from oil sands would be excluded, as the IEA would probably assume oil sands production rates would not decline.
The least squares fit of the IEA decline data suggests a 4.5% decline rate for existing fields in production (FIP), which agrees with CERA's number. However, the IEA average observed decline rate for post peak fields is 6.7% which is about 10% higher than CERA's estimate of 6.1% (Table 1 CERA report Oct 2007). This should imply that the IEA's decline rate for FIP should be about 5%, higher than the year old CERA figure of 4.5%, but it's not.
The IEA WEO 2008, released in Nov 2008, uses 4.5% FIP decline rate whereas the IEA MTOMR 2008, released in July 2008, used a higher decline rate on slide 23 of this presentation by ex IEA executive, Lawrence Eagles.
www.iea.org/textbase/speech/2008/eagles_mtomr2008.pdf
The suggested translation of Mr Eagles statement "just to stand still" is "just to remain on peak plateau".
My cynical view of the 2030 IEA 105 mbd liquids forecast is that it had to meet two key criteria to satisfy political objectives. First, the forecast had to be at least 100 mbd in 2030. Forecast production below 100 mbd would be seen as too pessimistic, although more realistic. Second, no peak in the production could be shown. Both these criteria were met by the IEA's forecast.
In order for the IEA to meet both of the above criteria, they had to be overoptimistic not just on production increases from NGL, non conventional, EOR and yet to find, but also had to use an artificially low FIP decline rate of only 4.5%.
In my opinion, the world average FIP decline rate is somewhere between 5% and 7%, applied to conventional C&C of 70 mbd. As more countries enter decline, the FIP decline rate should increase. For example, Russia is now in decline, after ending its C&C plateau in 2007.
A key reason for increasing FIP decline rates is the recent oil production from offshore basins such as the North Sea and Gulf of Mexico, both of which are in decline now. Deepwater oil decline rates can be very high. Deepwater C&C production started about fifteen years ago. Many of those mature deepwater fields are now declining at rates of around 20%.
The IEA also agrees that deepwater FIP decline rate are high but uses different rates for different reports. Table 10.8 of the WEO 2008 report shows deepwater post peak FIP decline rates to about 12% on average. In contrast, the IEA OMR March 2008 report stated the following in relation to offshore oil on page 23
The chart on page 23 showed decline rates for UK at over 20%.
Deepwater oil FIP decline rates are high and this explains why Brazil is struggling to increase production. Brazil has added about 500 kbd new deepwater capacity in late 2007.
http://en.wikipedia.org/wiki/Oil_megaprojects_(2007)
Unfortunately, Brazil's C&C production only increased from 1.75 mbd in 2007 to 1.80 mbd in 2008 (YTD avg Aug 08).
http://www.eia.doe.gov/ipm/supply.html
Assuming that Brazil's non deepwater oil is about 0.3 mbd, this implies that Brazil's deepwater oil FIP decline rate could be as high as 30%.
Due to high decline rates in deepwater oil, I am forecasting that world deepwater oil production is now a peak plateau of about 7 mbd shown by the red line in the chart below. Colin Campbell, has overestimated deepwater oil production due potentially to underestimating decline rates. In Apr 2007, Colin Campbell forecast a 12.4 mbd peak and just last month revised the peak downwards by almost 4 mbd to 8.6 mbd. For the reasons given in red on the chart, I believe that deepwater oil is on a peak 7 mbd plateau now.
Deepwater oil production to 2030 - click to enlarge
source of unmodified chart http://www.aspo-ireland.org/index.cfm/page/newsletter
The IEA WEO's use of a world average decline for FIP of 4.5% is too low. It's even lower than the 5% number used in the IEA MTOMR July 2008. The IEA is overoptimistic and has probably not taken into full consideration the impact of very high deepwater oil FIP decline rates. I believe that a more appropriate world average FIP decline rate is between 5% and 7%, but probably closer to 7%.
Ace - thanks for much additional insight. I'll try and answer the main points:
Everyone needs to be wary of comparing segments of IEA with CERA. They use the same terminology as each other, but apply different definitions to that terminology. CERA Figure 5 shows their definition of "build up" - zero to 80% of peak, and plateau - 80% of peak either side. CERA Table 1 is for Post Plateau - so that is all fields that have already declined beyond 80% of peak. The IEA definition is given in Box 10.3, page 235. Their definition of plateau is 85% of peak. But they start to measure decline from peak - Decline phase 1 is form peak to 85% of peak. CERA decline phase 1 is from 80 to 50% of peak.
But this doesn't explain your observation since the IEA definition is more conservative and should be lower than CERA - but as you point out, its not. From memory, CERA Table 2 provides an excellent summary of their findings that is lacking in the IEA report. The latter contains so many different definitions, for me it is near impossible to follow.
On the same theme, the IEA say this, page 221.
On the same page they note that the post-peak decline rate is 5.1% for their data set, and so they are adjusting this upwards by 1.6% to account for higher decline rates in the myriad smaller fields not included in their data base. This seems a very reasonable thing to do. I don't believe that CERA made such adjustment, and so on this basis one may expect the IEA decline figure to be higher than CERA - but its not.
IMO it is a pretty straight forward exercise to calculate decline rates from this data set of 800 fields and to then apply the results consistently. I'd estimate its 1 to 4 weeks work and the results could be summarised in a 2 page report. So I understand your cynicism born out of reading hundreds of pages of technically detailed prose that do not stand up to scrutiny and cross examination.
In deep water:
Table 10.8 p 238
Post-plateau average estimate for deep water from the IEA is 11.2%. CERA table 2 quote 17.9% decline for deep water fields. The IEA post-plateau figure should be broadly equivalent to the CERA decline figure.
Last time I looked at UK North Sea decline rates (Nov 2006) the underlying decline rate was 13% moderated to an observed decline rate of 7.6% by new field developments. The underlying decline rate incorporates operating activities like in fill drilling and EOR, thus the natural decline rate will be somewhat higher than 13%. But for the purpose of production forecasting it is a figure close to 8% that should be applied.
http://www.theoildrum.com/story/2006/11/19/135819/75
One big problem I have with these decline numbers is that the returns on in field drilling are expected to be constant. And in field drilling itself is expected to occur at a constant rate.
It makes more sense to assume in field drilling is influenced by price and the field decline.
Higher prices accelerate in field drilling and declines accelerate in field drilling.
Also in field drilling by definition is finite and can only expand until the field is fully drilled.
Your ability to expand and maintain your infield drilling campaign is limited to the size of the
field.
Given the above we would expect that over the last several years in field drilling campaigns have been steeped up and at some point will result in steeper decline rates as they have increased the depletion
rate.
You saw a similar pattern when the US peaked except without the technical advances that keep production higher to greater depletion levels.
Whats really needed to understand our future oil supply given that discovery is well in the past is a understanding of the infield drilling campaigns and their effect at the field level.
Given that most infield drilling campaigns implicitly work to keep production at its peak design level and generally don't exceed it by to much. One would expect that producers of existing fields will do whatever they can to keep production close to peak but the pressure to increase production in existing fields is low simply because of constraints on the above ground oil gathering infrastructure. You can have production decline and deal with that fairly easily but expanding production is exponentially more expensive then maintaining the current production rate.
The overall effect is you have an unknown change in the depletion rate driving a constant production rate.
However one thing is for sure if production remains constant then the depletion rate is increasing in developed fields.
Next we know for a fact that our technology is capable of extracting oil at high depletion rates 20-25% is not unknown and in some fields even higher. Thus our ability to deplete a oil field with modern technology is probably close to physical limits increasing depletion rates beyond 20% or so becomes limited by EROEI issues.
This can be seen in the steady decline in field lifetimes over the last few decades generally blamed on finding smaller fields but we know from WHT's work that discovery does not follow field size so this is a incorrect assumption. Instead given everything we know we should expect that field depletion rates have been climbing on average for decades. And further more we know that the maximum depletion rates possible are high.
Now the way around this situation is to increase URR and thus decrease the calculated depletion rate
the easiest way to increase URR in existing fields is to type a new entry into a computer database.
Problem solved.
Memmel, this is similar to what I thought: The IEA numbers only distinguish natural decline and observed decline. But for a forecast (or scenario) both are only theoretical numbers, which provide an orientation:
Natural decline only happens if there is zero additional investment. But in reality this rarely happens as long as the field isn't hopelessly depleted - except for serious above-ground problems like in Iraq.
Also the "observed decline" only gives an orientation from the historical development, as the future decline doesn't simply depend on *if* investments will be made but also *which* and *how many* investments are made. For example future decline may depend on if the remaining reserve of a region will be tackled by vertical or horizontal wells. Much of this will depend on the future oil price, which may determine if more expensive methods will pay off - or also if sufficient capital, equipment, personnel etc. are available. In their scenarios this is partly addressed by the the IEA as they distinguish between conventional crude and "EOR" reserves.
So I don't think that the IEA's decline numbers can only be used as a rough orientation but not as a forecast as future production depends on many more parameters.
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?
I don't know the answer to the question of "wetness" vs. "dryness" of OPEC oil/gas as it relates to NGL, but I am looking forward to any upcoming posts on NGL production. Does anyone know what the "wetness" of the NGL is in the various Saudi megaprojects, or does the IEA claim to know things we don't about the laundry list of Saudi megaprojects? And what of the two new refinery additions that KSA is working on? Will KSA simply keep more of their production at home and sell the finished product of natural gas abroad (natural gas being difficult to move in gas form)?
http://www.hydrocarbons-technology.com/projects/khurais/
http://www.bloomberg.com/apps/news?pid=20601072&sid=a.558dKzK2NY&refer=e...
http://www.gasandoil.com/goc/company/cnm54378.htm
http://www.energybulletin.net/node/4785
Either way, I have become more interested in the ways in which NGL and natural gas product can be used in transportation, through propane, compressed natural gas and even methanol.
The market seems to be assuming enough supply of raw product to satisfy the markets of the world (at least in the near term) given the current price of petroleum products across the board (nat gas, propane, crude oil, gasoline, even methanol) all down by huge amounts and still falling as of today, (only a few dollars above the $50 flat mark for crude oil), and if KSA were to actually be able to deliver the 12.5 million barrels per day that they had earlier said they could do, and actually delivered, at this time of economic
contraction we would be awash in oil and NGL.
Should I just go ahead and buy that discounted Mercedes S-Class? Hmmmm....:-)
RC
Rune - Good work on the "wetness" question. My sense of the report is not that IEA did detailed and defensible calcs to come up with their projection for growth in NGLs (or EOR, or other new supply), but rather that they attempted to kick the question of additional supply into areas where the data is fuzzier and projections are harder to prove or disprove than regular conventional crude. I'd be willing to bet that they had no such explanation for increasing wetness of produced gas. But that's just a gut level guess.
ChrisN, thank you.
I think you are on to something when you refer to possible more “fuzziness” surrounding NGL’s.
From what I have seen of documentation on NGL’s (and there is little available in the public domain) it should be expected that Nat Gas will become drier with time.
The other factor affecting NGL production (extraction) is volume of Nat Gas produced. Towards 2030 IEA projects a big increase in Nat Gas production from Middle East (and other OPEC members). This could happen, the reserves are there, but Nat Gas in the Middle East is increasingly sour (H2S and CO2) which requires treatment before it enters the market (either by pipeline or LNG).
This suggests heavier investments in the production of Nat Gas, and with the ongoing credit crunch in mind, it might also be that the capital will not be there at the pace desired.