Saudi Arabia - production forecasts and reserves estimates
Posted by Euan Mearns on August 30, 2007 - 10:27am in The Oil Drum: Europe
Topic: Supply/Production
Tags: aspo, colin campbell, original, production forecast, reserves, saudi arabia [list all tags]
In his recent post, Ace assumes ultimate recoverable reserves (URR) in Saudi Arabia to be 175 Gb (billion barrels). With 112 Gb already produced, that leaves only 63 Gb remaining. Colin Campbell (the founder of ASPO) has estimated total reserves for Saudi Arabia of 275 Gb (news letter 66), believed to be C+C+NGL (crude oil + condensate + natural gas liquids). There is an enormous discrepancy between this and Ace's analysis that ought to be explained.
This post is a brief summary of my views on Saudi reserves and production. My conclusion is that Saudi Arabia likely has at least 120 Gbs of remaining reserves (C+C+NGL) for a URR in excess of 240 Gbs (C+C+NGL). The remaining reserves according to this analysis are almost double those reported by Ace.
The importance of reserves and production forecasting
The point I have reached in my analysis of peak oil and energy decline is that reserves and production forecasting are of paramount importance. It seems increasingly likely to me that Planet Earth has ample supplies of alternative energy that may be gathered (nuclear and renewable solar sources) and which may replace declining fossil solar fuels when that happens. The major challenge that confronts us is not a lack of energy or engineering solutions but one of political, institutional, corporate and personal behaviour. The human race seems intent upon running for the edge of an energy cliff. Persuading politicians and OECD institutions now that energy decline is a very serious threat to the future of industrial civilisation is the single most important task that confronts us. Reliable and credible energy forecasts lie at the heart of that task.
Forecasting oil, gas, coal, uranium reserves and production is a highly complex process, not to be taken lightly. It is therefore with some reservations that I present this view on Saudi Arabian reserves and production as I simply do not have all the information required to do this job reliably. This seems an appropriate time to quote Colin Campbell's 10th commandment:
ALL NUMBERS ARE WRONG – THE QUESTION IS : BY HOW MUCH ?
I will follow a combined bottom up and top down approach, drawing on the work Stuart Staniford and I have done on Ghawar, Aramco reserves estimates (pre-nationalisation based on BP data), Aramco forecasts for new projects (pdf) and Hubbert linearisation.
Why C+C+NGL
All the figures presented here are for C+C+NGL making direct comparison with Ace who has used C+C only, problematic. My apologies for that, but I have good reasons for doing so.
The first is laziness. I find the BP statistical review of world energy to be a very readily accessible source of data which I use all the time - and BP quote C+C+NGL.
The second is the fact that NGL is a vital constituent of any petroleum system. In simple terms, the kerogen rich petroleum source rocks produce progressively lighter hydrocarbons with increasing pressure and temperature during burial. Starting with crude oil, the kerogen will then produce light oil, condensate, wet gas and once it is near completely cooked it will produce dry methane. So NGL, which condenses out of wet gas is a vital constituent of any petroleum system and should not be ignored in my opinion.
And third, gas production in the Middle East has been relatively low to date owing to remoteness from European and North American markets that historically have been served by local sources of gas. With increasing amounts of liquefied natural gas (LNG - not to be confused with NGL) now being produced, NGLs are tending to make up a significant amount of new production that is coming on stream. Ignoring NGLs at this stage, therefore, may present an unduly pessimistic picture.
However, it must also be pointed out that the energy content of Saudi NGL is about 70% of Saudi crude oil. So 1 barrel of NGL is not equivalent to 1 barrel of crude oil in energy terms. No adjustment has been made for the differing energy contents.
Saudi official reserves and their decline
The starting point for this analysis is to look at the official Saudi reserves estimates for 1980 as stated in the BP Statistical Review. A figure of 168 Gbs is quoted. This is the figure carried by Aramco when it was run by American companies, pre-nationalisation. As far as we know, this was an objective assessment of recoverable reserves at that time. Since 1980, Saudi Arabia has produced 77 billion barrels and declining the 168 figure for this production leaves 91 billion still to be produced, an observation made by Robert Rapier in an earlier post.
However, since 1980 there have been significant improvements in production technology, in particular the advent and widespread use of horizontal wells and 3D and 4D seismic that enable more accurate targeting of by-passed oil. This has lead to an improvement in recovery factors since 1980, and the figure of 91 Gbs remaining may justifiably be adjusted upwards to account for this.
Using the API Facts and Figures Centennial edition (1959) production data from 1936 to 1966 and BP production data from 1966 to 2006 shows that Saudi Arabia has produced 120 Gbs to date. Anchoring the production decline profile (the red line) on 1980 points to initial recoverable reserves of 211 Gbs with 91 Gbs remaining. But as already stated, these numbers should perhaps be adjusted upwards to account for improved recovery factors.
Conceptual production forecast
Forecast numbers are production capacity. Actual production may be lower depending upon demand. Click all charts to enlarge
The conceptual production forecast for Saudi Arabia has the following assumptions:
Ghawar
The Ghawar forecast is based on the base case revision 1 model I presented here. This is truly a bottom up analysis based on combining the reservoir volume determined from published maps and reservoir data combined with estimates made of the depletion state of the field estimated from published 3D models. The step down in production in the interval between now and 2017 represents the gradual death of northern Ghawar and transferral of production to the south which is much less depleted and may sustain a reduced plateau for many years.
Between now and 2028, 21 Gb of production is shown of an estimated 40 Gb remaining reserves. Some time beyond 2028, Ghawar production will go into rapid decline as the south end of the field becomes exhausted.
Abqaiq
Abqaiq is the most mature of the Saudi supergiants. The status of Abqaiq is rather obscure. The Linux map discussed here and subsequent posts shows oil remaining only in the crest and ridges of the structure. Jaffe and Elass (pdf) show zero production for 2004, although this may be clouded by periodic inclusion of Abqaiq production together with Ghawar. Multi-phase pumps (pdf) have been deployed to help produce the remaining oil.
Abqaiq is an ageing queen that no doubt would benefit from periodic rest and I have therefore conceptually shown sporadic annual production of up to 400,000 bpd that is turned on when needs require. A total of 657 million barrels of Abqaiq production is in the model.
Heritage super-giants
The heritage supergiants are those mature fields that together with Ghawar and Abqaiq have made up Saudi production for the last 50 years. These include Safaniyah, Berri, Shaybah, Qatif, Marjan, Zuluf, Abu Safah and the Hawtah trend fields. These fields are much less mature than Ghawar and it is difficult to estimate their future performance. The oil in Safaniyah, Zuluf and Marjan is very sour (contains high sulphur content) which creates refining and hence marketability problems. I consider it likely that these fields are not producing flat out but are production constrained owing to poor marketability of their oil. The Saudis are taking steps to increase their own refining capacity to deal with this problem.
It is difficult to know what decline rate to apply to this group of fields. Some, like Safaniyah and Shaybah may not decline at all in the foreseeable future. Whilst others like Berri and the smaller Hawtah trend fields may experience more rapid decline in the years ahead. Jaffe and Elass report natural decline rates of 7 to 8% that is stemmed to 2% by intervention. In the interest of being conservative, I have declined the heritage assets at a rate of 5% per annum. This may prove to be too high. They contribute 27.5 Gbs to 2028.
New Fields
New Fields are based on the Saudi Aramco projects time line, posted by Ace. Project delays have been a common feature of the recent commodities bull run and delays have therefore been built into the model.
Hawiyah (Khuff), Khursaniyah, Hawiyah (Khuff) II, Nuayyim, Shaybah expansion and Yanbu NGL have all been delayed by one year. Khurais and Manifa have been delayed by 2 years.
Two projects - 2007, Khursaniyah ethane+NGL, 290,000 bpd and 2008 Yanbu ethane + NGL, 195,000 bpd - are not included because it is not clear that these are genuine liquids projects. Ethane is a gas.
The new projects are all included at their nameplate capacity but are declined at a rate of 2% per annum thereafter.
Discovered undeveloped
A 500,000 bpd allowance is made for discovered undeveloped fields from 2015 that are declined at 2% per annum thereafter.
Yet to find
A further 500,000 bpd allowance is made for fields as yet undiscovered from 2017 (10 years from now) that too are declined at 2% per annum.
All this is speculative and conceptual. It seems unlikely in an oil rich country like Saudi Arabia that oil developments will grind to a halt after Manifa - thus it seems prudent to include some allowance for these future but as yet undetermined projects.
Putting all this together provides the conceptual production forecast model shown above. The peak in liquids production is 2011 and the average post-peak decline is 3%. The modelled decline and depletion rates are shown below. Depletion is based on a URR of 240 Gbs (see the following section). The reserves depletion rate cannot go on rising forever, and at some point in the future, the death of S Ghawar (and other supergiants) will lead to periods of accelerated decline that will lower the reserve depletion rate.
Decline rate = year on year change as % of production that year.
Depletion rate = annual production as % of remaining reserves based on an assumption of 240 Gbs URR (see following section)
| Asset | Production allocation 2007-2028 Gbs | Hydrocarbon |
|---|---|---|
| Ghawar | 20.9 | Arab light |
| Abqaiq | 0.66 | Arab light |
| Heritage assets | 27.5 | mixed, biased sour |
| Hawiyah (Khuff) | 2 | NGL |
| Khursaniyah | 3.2 | Arab light |
| Hawiyah (Khuff) II | 1.6 | NGL |
| Nuayyim | 0.61 | Super light |
| Shaybah expansion | 1.5 | Extra light |
| Yanbu NGL | 1.2 | NGL |
| Khurais | 6.7 | Arab light |
| Manifa | 4.5 | Arabian heavy |
| Discovered undeveloped | 2.2 | |
| Yet to find | 2.0 | |
| Total 2007 to 2028 | 75 |
Hubbert Linearisation
Regular readers of The Oil Drum will recognise this Hubbert Linearisation (HL) chart that I have posted many times on various threads. When it was first posted it received cries of derision from certain posters because my favoured trend is the "stretch HL" drawn between 1991 and 2005 (the red line). How could anyone have the audacity to draw a trend between two points pointing to 240 Gbs whilst there was a well-defined linear trend pointing to around 180 Gbs (the blue line)?
Saudi oil minister Ali I. Al-Naimi holds Saudi Oil production and the future of industrial civilisation in his hands
The logic is this:
We know for sure that in the period 1991 to 2002, Saudi Arabia was not pumping at capacity. The southern third of Ghawar (Haradh) was'nt even developed and numerous discoveries were standing idle, we saw $10 oil in 1998 and Saudi Arabia probably had over 2 million bpd spare capacity. The linear trend from 1991 to 2002 therefore does not see all the reserves and it seems highly likely that this will underestimate the Saudi resource.
1991 (GW I) and 2005 were two years that Saudi Arabia was likely pumping at or near capacity. It is hypothesised that had they pumped at capacity for the interim period then the HL would have declined along the red line and would be pointing towards 240 Gbs.
The red symbols represent the production forecast detailed above and needless to say I was fairly satisfied to see these lining up along my stretch HL trend. This doesn't make it right, but it certainly adds a degree of internal consistency. 2006 production is the last blue symbol.
There has been much debate about HL on TOD over the past year ranging from those such as Westexas who have blind faith in the method to Robert Rapier who has expressed doubts that HL has predictive qualities. I have always adopted a moderate view acknowledging usefulness so long as the limitations are recognised and understood. On this basis for the time being my view on Saudi reserves of C+C+NGL is that these will be at least 240 Gbs.
Downside risk
Staurt has recently circulated an internet chart of Ghawar production that shows 4 million barrels per day (mmbpd) for 2007. This is about 1 mmbpd lower than shown in my production model. The provenance of this data is unknown, as is its reliablity. 4 mmbpd, however, matches anecdotal evidence from other sources considered to be reliable.
The reduction in Ghawar of 1 mmbpd over 2 years as indicated on this chart matches the decline in Saudi production over the same period. This brings us back to the question of why Ghawar production may have fallen at a rate of 10% per annum for two years?
One possibility is that the depletion state of Ghawar is more advanced than was concluded in my analysis and that Ghawar is now on the slide indicated in my forecast to begin in 2011. It is therefore within the realms of possibility that the Saudis have been caught unprepared for a collapse in N Ghawar production, and the scramble for rigs and new projects that is now underway has come too late to forestall a drop in their productive capacity. The altenative explanation is that mature parts of N Ghawar are being rested to allow new wells to be drilled and reservoir pressure to rise etc.
Bringing N Ghawar decline forward by 4 years produces a modified forecast in the near term. Saudi watchers will note that 2005 becomes the peak year in a 30 year undulating plateau spanning 1990 to 2020. 5 billion barrels production are lost in the period to 2028 relative to the base case forecast presented above.
Summary
| URR Gb | Remaining Gb | Recovery % | Notes | |
|---|---|---|---|---|
| Ace | 175 | 63 | 25 | C+C only |
| Pre-nationalisation | 211 | 91 | 30 | minimum |
| Mearns | 240 | 120 | 34 | minimum |
| Campbell | 275 | 155 | 39 | |
| Saudi official | 384 | 264 | 55 | BP+produced |
The recovery factors are based on an ussumed 700 Gbs of original oil in place. This is the figure reported by Baqi and Saleri and by Colin Campbell.
The projected recovery factor for the official Saudi reserves is unrealistically high for the whole country. 55% may be achieved in the N Ghawar production sweet spots but most certainly not in poorer quality reservoirs that make up much of the countries resource base.
In his analysis, Ace concluded:
it is now almost a certainty that Saudi Arabia passed peak C&C production of 9.6 mmbd in 2005
In reaching this conclusion, Ace assumed that Saudi Arabia had no market for most of its sour crude oil and allocated only 20 billion barrels to sour crude reserves whilst acknowledging that the actual figure may be much higher. 85 Gbs recoverable reserves were booked for Ghawar, whilst Stuart's analysis suggested 96 Gbs and my base case analysis suggested 97 Gbs. Not all new projects were included at nameplate capacity and NGL is not included in this analysis of C+C only. It seems that worst possible case assumptions have been made at each stage which not surprisingly then leads to a low estimate of reserves and a picture of imminent production collapse. The indicated country-wide recovery factor of 25% is very low.
Campbell's analysis of Saudi reserves is rather superficial. He recognises official Saudi estimates of original oil in place to be 716 Gb but prefers a figure of 600 Gb based on anecdotal evidence from reliable sources. A generous 45% recovery factor is applied to the 600 Gbs to get a figure of around 270 Gbs. This figure matches Saudi official reserves estimates and it is suggested that the Saudis report URR and not remaining reserves. This certainly fits the practice of showing no decline in the annual reserves return.
Time to recall Colin Campbell's 10th commandment:
ALL NUMBERS ARE WRONG – THE QUESTION IS : BY HOW MUCH ?
It is up to individual readers to decide where the truth lies.
Acknowledgement
Professor Goose, Stuart Staniford, Khebab, Luis de Sousa and Ace reviewed the text and provided helpful comments. This does not mean they necessarily agree with the content.
Further articles on The Oil Drum about Saudi Arabia:
by Stuart Staniford
- Saudi Arabia and Gas Prices
- Depletion Levels in Ghawar
- The Status of North Ghawar
- Further Saudi Arabia Discussions
- Water in the Gas Tank
- A Nosedive Toward the Desert
- Saudi Arabian oil declines 8% in 2006
by Euan Mearns
- Ghawar reserves update and revisions (1)
- GHAWAR: an estimate of remaining oil reserves and production decline (Part 2 - results)
- GHAWAR: an estimate of remaining oil reserves and production decline (Part 1 - background and methodology)
- Saudi production laid bare
- Saudi Arabia and that $1000 bet
by Heading Out
- Simple mathematics - The Saudi reserves, GOSPs and water injection
- Of Oil Supply trains and a thought on Ain Dar
by Ace
http://science.reddit.com/info/2k75q/comments
theoildrum authors thank you for helping them get more readers... :)
One observation: If you plug in the 2006 and 2007 year to date production numbers, the HL plot is reverting back to the 1991 to 2001 P/Q intercept line. This is consistent with the Texas model, where a careful analysis of the pre-peak data show that the most accurate pre-peak estimate of URR came from discounting the "dogleg up."
It's nice to see TOD contributers using objective terms such as "blind faith" for yours truly, especially when the available 2006 and 2007 data show the HL plot reverting back to the 1991 to 2001 P/Q intercept, which you have somehow failed to show.
Of course, one would think that an objective writer would at least acknowledge that my HL based warnings of an imminent Saudi production decline have--based on the production data--been correct. Could I still be wrong? Sure, if and when Saudi production exceeds its 2005 average annual production in a given calendar year. But until then, the production data are supporting a 2005 final production peak for Saudi Arabia.
WT I think the problem people are having and why they are slamming HL is that KSA puts being a swing producer above production rate. So they may not be maximizing production but trying to maintain a capacity buffer for emergency use even as they decline. If you add this concept esp if they are trying to maintain a 1mbpd plus buffer it skews the data.
The people that claim that KSA can produce more are assuming that they have a large buffer and some day will pump at capacity. While I think they generally don't have a lot of spare capacity and will only use it for short periods of time during major emergencies. So I think your right for "day to day" production but I also think KSA is not producing at maximum. Next of course the amount of spare capacity they have is unknown. What will be interesting going forward is if the bring large fields online and we see no change in production rates then we know that are working like mad to rebuild spare capacity. Over time we will eventually ferret out how much spare capacity KSA has and its nature at the moment I don't think we have enough information. However because of political reasons I don't think its all that relevant to daily production and your estimate are probably closer to the truth.
Finally my opinion is if you assume they want to maintain a spare capacity buffer even as they decline all the data seems to fit so I think this paper is making in correct assumptions.
One more thing KSA has adopted and in fact been a leader in developing technology to enhance production rates this is not
included. The dogleg for the US occurred because of a massive drilling campaign. KSA has a different profile but newer technology probably has resulted in inflated reserve estimates. KSA itself uses enhanced extraction rates to justify their highly inflated reserve estimates so you have to assume that they have seen some significant improvements in extraction rates from technical advancements. We have reason however to doubt this translates into higher final recoveries at high production rates.
So KSA production is not a black and white issue and its sad that its treated as such.
Everything Saudi Arabia has done in developing their oil resources has been aimed at maximising recovery at the expense of high production in the short term.
Ghawar alone could have produced at over 15 million barrels per day but has never done much over 5. The Saudis have also left huge fields lying fallow. None of this would ever have happened within the OECD.
There principal use of horizontal wells has been to maximise recovery from poorer quality reservoirs and to control water cuts in the vicinity of mobile oil water contacts.
The advent of new technology - mainly horizontal drilling and 3D and 4D seismic has led to a justifiable expectation of higher recovery factors over the years. The one-off reserves inflation in the 1980s and in particular the fact that they have not been declined for production since remains a seroius problem.
Why Euan, you almost sound like...
nevermind :P
I'm curious as to why these technologies have not turned around the Texas and North Sea declines.
BTW, a question I have been meaning to ask you. Were there ever any material restrictions on drilling in the North Sea?
Because these fields have been grossly mismanaged in such a way that most of the OOIP is now locked in no matter what kind of technology you bring into it. KSA has done a great service by slowly producing their oil to maximize long term profit. We at the USofA are concerned with this quarters shareholder earnings...
I nominate this comment for the top 10 list of most nonsensical comments ever posted on The Oil Drum.
We're not talking about turning around decline here but estimating URR.
The biggest hydrocrabon resource as far as I'm aware in NW Europe is not Statfjord, Troll, Brent or Forties but the Claire field west of Shetland. A huge accumulation of relatively heavy oil (20 api) in poor quality Devonian sandstone reservoir. This field lay fallow for decades as the oil was not producible using vertical wells - but much diligant work by BP (which I was involved in in a small way) has led to development of the best reservoir segments using horizontal wells. This has added to the URR of the UK.
In Norway, the giant Troll west field is gas with a thin oil rim. Norsk Hydro spent many years modelling the producibility of this oil using horizontal wells (I was also involved in a small way in that modleling work) - as it turns out Troll W became Norway's largest oil producer, I believe, for a few years. Again, this oil was not recoverable using vertical wells and producing this oil using horizontals has added to the URR of Norway.
If I could second what I take to be the thrust of this post. What I think I can see SA doing is shutting in premium quality production capacity such that X Mbpd can be turned on quickly. This capacity is the last bits of production from key fields (such as Abqaiq) and could be used to increase SA production for short periods of time (lets say up to 100-200 days).
Now there is a world of difference between a short term peak rate and long term base capacity. Its the former that SA is talking to the world about - but the later that people are assuming.
In this way SA can offset limited duration issues (say someone attacking Iran), but it doesn't deal with the base load of world demand.
So, in short - close down the scraps of the high quality fields against short term needs. Drill new fields to make up for the loss of base production in mature fields and keep long term total capacity stable. No increases in capacity over the 9Mbpd we are seeing, except for short emergencies.
Seems very sensible to me.
Correct but this introduces errors in estimating their true reserves and you must include the technology effect which offsets to some extent this spare capacity. Considering that this capacity is anywhere from 500k to 1mbpd or more and its been a systematic part of KSA production ( swing producer ) we have a fairly large margin of error in reserve estimate. However since HL is based on real production data not the probably offsetting effects of advanced technology and shut in capacity its probably closer to the right answer. So in general KSA has been shutting in capacity and using advanced technology to deplete the fields they do produce at a higher rate. The net result is they probably end up close to HL but its not simple. HL in effect hides this complexity its "builtin" people who disprove HL pull out one of the variables of their choice but don't acknowledge at the variables. Its pretty clear that KSA has been fairly aggressive in producing fields when they do produce them for example and its rumored that they produce to the point of field damage during crisis conditions.
I guess I don't see the point in discrediting HL its a tool and it seems to provide valuable information along with all our other information sources. And as far as the way people discredit it they simply don't understand how it works. But claiming that you can fit a lot of curves to a data set and thus one fit is wrong is .... I won't even go there.
One problem I have with HL based on KSA production history is that it implies some sort of predestination with regards to how fast they can pump oil and what the eventual yield will be. In reality, decisions that they make can obviously affect the near-term rate and the URR. Develop Haradh using MRC wells? Develop Khurais? Squeeze more oil out of Abqaiq with new technology? Will they get what they expect? Who knows, but in any case, there is no information whatsoever on these prospects embedded in past KSA production rates.
While it is very possible that they will never match the 2005 peak again, it doesn't logically follow that the decline rate and the URR are magically determined by a line drawn through a set of data points.
Both the US Lower 48 and Russia have made more oil than Saudi Arabia. If we construct HL models based on production through 1970 and 1984 respectively for the Lower 48 and Russia, the post-1970 and post-1984 cumulative production for the Lower 48 and Russia have basically been what the HL models predicted it would be.
My confidence in the HL method is based on an evaluation of the method as applied to several large producing regions, not "blind faith." I think that the method works because we tend to find the big fields first, and "Peak Oil" is basically the story of the rise and fall of large oil fields.
In my opinion, the HL method is controversial because people don't like the answers it is providing.
I'm not going to question your eyesight, but I will question the ability of the HL method to "see" how much oil is in Haradh (or Khurais, etc.).
Similarly, most reservoirs in the lower 48 (the East Texas field being an exception) have rather low recovery rates, mostly because they were produced early. If you and oilmanbob and thousands of others decide to go after a lot of that oil using EOR wo whatnot, won't that give a different production decline profile and a higher URR than predicted by the current HL plot? Now, there's no way Texas or the lower 48 are going to come close to re-peaking, but that is not the only consideration.
I don't disagree with your message. I just question one of your sales pitches.
In defense of WT and Hubbert linearsation-King Hubbert made his prdictions on crude plus condensate produced with primary and secondary production. What I'm talking about, and other companies too is the 390 billion barrels left behind in the lower 48 states as a tertiary development target has a huge absolute volume. To get the oil to an average 60% recovery, we're talking another 156 million barrels to be produced.
But lets get realistic about the situation I have a hard time believing that most fields can be produced at even 1/2 of the original production rate, and probably more like a quarter of the original rate seems a likely scenario. The whole reason the pressures were wasted was because the operators pulled the wells too hard. The THAI method seems to be great for making bitumen produce at very high rates, yet these are virgin reservoirs and still have solution gas, and the process isn't going to be suitable for rocks with a high proportion of limestone, like the entire Permian Basin. Think about it-the 700 degree temperature is going to turn that limestone into cement, which doesnt produce very easily. And, the process may not work at all on medium to light oil in great sandstone reservoirs. The best, most productive reservoirs like the East Texas field have already had 50% of the original oil in place produced by primary and secondary methods. It had a natural water drive in that field
We currently produce about 3.8 mbopd, and at the highest the US produced around 10 mbopd. If the tertiary guys could get that up to 5 mbopd I'd consider it heroic work. But we are consuming 21 million barrels of oil per day. That leaves a gap of 15 or 16 mbopd. The Canadian Bitumen might provide as much as 5 million barrels, so we are still looking at a shortfall of perhaps 10 million barrels of oil to be produced. Alan Drake's Electrification of Rail will save us another 2 to 3 million barrels, so we are still looking at a shortfall of 7 or 8 million barrels of oil that has to come from somewhere- and its obviously hybrids and increased cafe standards,bicycles, electric vehicles, natural gas to diesel from stranded natural gas. I'm not a doomer, but I sure think its going to take everone in the country and the world working together to keep reasonable prosperity . Look at the tail end of King Hubbert'curve-it trails off a long ways. Bob Ebersole
I take it you meant another 156 billion barrels.
But that's my point. The lower 48 production data to date has no information about the heroic efforts which could be employed to get that extra oil, and so an HL analysis would not account for it. If a massive effort could even slow down the decline in production, that would also represent a deviation from the HL prediction. Certainly not "Happy Motoring", but it will be needed for any kind of transition.
As for the East Texas field, sometimes it's better to be lucky than good. The recovery after secondary production will be around 75%, which is amazing given the haphazard way it was produced (30,000 wells etc.).
This in my opinion is correct. But was you fall back to the case that the future is similar to the past you get back on HL. This means that you should be careful about the validity of data points shortly after peak production.
Next HL probably stays optimistic post peak. Its implicitly assuming that the amount of work put into production is basically a constant with production dropping only from depletion effects. For oil its implicitly assuming that the number of new wells drilled is a simple function of the size of the field probably effectively constant. Its measuring the life/death cycle of the wells and I've not set around and figured out the actual well drilling pattern that gives this sort of Gaussian production curve. I think the key feature is actually the rate that wells are closed in not the details of the drilling campaign. The fact that the "death" of wells is directly related to URR is what gives HL its utility the drilling campaign itself just determines the height and slope of the curve but the death rate is the critical factor. The sweet spot for the HL method is the data between when the rate or production growth start decreasing and the peak. This is the cleanest data given HL's assumptions. The drilling campaign is in a steady state for the most part and changes in production are pretty much only from the death of wells. WT has in my opinion correctly applied HL thus I believe his results.
I guess if people are willing to take the data range from the first inflection point to the beginning of the peak plateau's and argue about HL I'd be more willing to listen.
Trying to prove HL wrong outside of its "sweet" spot is not interesting. Notice that given this analysis its pretty obvious that massive drilling campaigns post peak are probably simply extracting the resources faster and not increasing URR. Since so much of oil is in the long tail it will be a long time if ever before we find out what the real URR is. In any case the constraints on a good HL analysis are pretty obvious its surprising that people seem hell bent to disprove it. HL is not rocket science its a good simple model.
75 % recovery after secondary for east texas? isn't current recovery in the 50% range with a 99% water cut ? i dont see how east texas is going to get to 75%.
Actually, 75% is on the low end. I have several sources for this. A report prepared by U. Texas in 2003 said that as of 2003 5.3 billion barrels had been produce out of 7 billion OOIP (76%). The book Nontechnical Guide to Petroleum Geology, Exploration, Drilling, and Production by Norman J. Hyne says 82% will be produced, and Jean Leherrere estimates 85%. All secondary production.
u of texas and jean leherrere notwithstanding, i doubt the figure. but i cant say that i have read either or your references. i have never, ever heard of a secondary recovery project with anywhere near that recovery. gravity drainage, maybe, but that is not a secondary recovery method. my guess is that the ooip is understated. and of course the water injection may be completely incidental to the recovery by gravity drainage.
but i am always open minded and willing to learn something new. i will take a look at the references you have cited. and fwiw, oilmanbob quotes 50% a few posts up.
The following is from this abstract of a SPE paper.
Well said. This is precisely my problem with HL--it doesn't take into account things that we know for a fact can influence production volumes.
As one more example, consider the talk recently about how there has been a paradigm shift in OPEC's view of the market, and how they are apparently much more willing to restrain production and drive up prices. Whether this was caused by their seeing proof that $70 oil would not instantly wreck the US economy or their desire to maximize revenues as they approach the peak is, in one sense, irrelevant. The point is there seems to be at least one major factor influencing their production volume aside from geology.
Note my question up the thread--Why hasn't better technology reversed the Texas and North Sea production declines?
IMO, regardless of whether we are Capitalists, Communists or Britney Spears Worshipers and regardless of whether it is Texas, the North Sea or Saudi Arabia, we generally find the biggest fields first. A production peak does not mean that we stop finding fields and it does not mean that we stop trying to extract the last barrel of recoverable oil out of the reservoir.
It does mean that we can't offset the declines from the old, larger oil fields.
That is my point about using the wildly different post-peak Lower 48 and Russian production profiles. The post-1970 and post-1984 cumulative production numbers were basically what the HL models predicted they would be.
The thing about HL is it tends to give you a URR not surprisingly based on how the fields are developed. Its insensitive to the exact nature of the development except that the growth should reasonably follow the assumed population like pattern. It need not be maximum growth etc etc. It also probably underestimates the amount of oil extracted in the tail end of a fields life when more aggressive methods are used. But since its primary utility is near peak and post peak its faults probably don't effect its "predictive" power.
Its very much a sledgehammer and a simple tool but considering the uncertainties involved its seems to be a pretty good tool. If HL is pointing to peak you need in my opinion some strong evidence that the region is not close to peaking. Its simplicity is both its strength and in a sense its weakness. In general people that object seem to not understand it. Its a simple model of the exploitation of a resource that makes the assumption that future exploitation of the resource will follow previous methodology. I.e the future is like the past and any slowing in the growth rate of production is caused by depletion of the underlying resource.
Thus its a fairly sensible simple model and useful in the case of incomplete data. So far none of the arguments against HL are that strong in general its the bias of the people that dislike the model that reject it.
And finally the URR calculated but HL and by other measures is probably not the same number. This is easy to see for example since people that dismiss HL are assuming a massive investment will be made as a field declines to increase URR and also enhance production rates while HL does not make this assumption. This is why it does not capture the flat peak we find in practice or the so called dogleg. The assumption that the future is the same as the past fail at peak but it becomes strong afterwards.
Anyway I'm not going to debate HL the facts will become clear soon enough and with issues such as Export Land and the potential for the oil industry itself to crumble etc etc
I don't see the projected production rates as relevant now.
So I think HL's and all the other depletion based models are either irrelevant are close to irrelevant now. Politics, war, weather and economics will determine how much oil is produced from now on out and I expect the real amounts will be far less than predicted by depletion modeling. We are going to kill the golden goose.
I don't think there has been much investigation of this and I believe it may have significant explanatory power.
OPEC went through an early post-nationalization phase which was the equivalent of the kids finally getting the keys to the bank vault. There was little or no market discipline and the attempt was made to maximize immediate returns.
OPEC now appears to have significant market discipline and I suspect this is due to increasing financial sophistication and their own recognition that they have a finite resource and need to manage that finite resource to maximize value extraction. They see themselves as pumping dollars, not oil, and will act as necessary to maintain the value of the income stream.
I suspect that within 6 months we will see OPEC taking more oil off the market in anticipation of a US/UK recession.
"I suspect that within 6 months we will see OPEC taking more oil off the market in anticipation of a US/UK recession."
Interesting.
Finance markets seem to say (futures market) there'll be no recession.
Also, IEA seems to say that sub-prime (et-al) fiasco will not make a dent into oil demand.
But still OPEC will cut?
It'll be an interesting coming 6 months, whatever happens, that's for sure.
A year or two ago the Wall Street Journal looked at the predictive power of oil futures and concluded that they were utterly worthless more than about 6 months out. This differs from certain other commodities so they sought to explain this and their best guess was that the market lacked complete information (or transparency) thus making futures "bets" problematic.
"The greatest shortcoming of the human race is our inability to understand the exponential function." -- Dr. Albert Bartlett
Into the Grey Zone
Yes, but that was only for Oil futures market.
And I am now talking about the whole economy AND the next 6 months.
Apples and oranges?
Could the "dog leg up" in '03 not be a case of mild overproduction by KSA in their role as swing producer in response to the Gulf War? I'm not sure picking just two data points,'91 and '03, and assuming a steady state, sustainable rate happening at just those two points is good HL. But because they seemed to always be under or over producing, it makes their true producible reserves a mystery. Their reponse to any kind of supply problem in the past has typically been overproduction. The point that newer recovery methods should rightly add a lot of the bypassed oil from past bouts of overproduction to the older reserve numbers seems valid. But is this going to change the KSA peak time much?