Of these possibly 120 billion barrels according to IHS are due to underestimates in the Middle East.
Right, Saudi oil reserves were way underestimated. Hell they are still underestimated, they say they have about 200 billion barrels yet to be discovered. That is in addition to the 260 billion barrels of already "proven" reserves. The whole damn country is just floating on oil.
And otherwise highly intelligent people really believe this stuff. It is enough to make a grown man cry.
The KSA has only recently developed fields that contain the second half of their P1, P2 & P3 Reserves & past Consumption of 462-Gb as described including their production plans last month. They have expressed their intention to develop 394-Gb of this by 2054. In 2007 and beyond, we will continue to see Hubbert Linearization models undergo realignment such that KSA's (all liquids) URR shifts from an indicated 197-Gb to 394-Gb. This is known affectionately as the Global and KSA dogleg (pre-revision graph credit to Euan Mearns) and will become more prominent as the decade progresses:
It is too early to assess the cumulative effect of similar latent fields opening, but Jean Laherrere (with two decades experience in linearizations) is already illustrating that the new regime indicates that (all liquids) URR has moved from 2250-Gb to 3100-Gb.
This bodes well for long term availability of oil globally, but is not an indicator that Peak Rate or Peak Date will be extended. It will likely only dampen the decline rate.
Clearly, Jeffrey's use of HL is flawed. In both KSA & Globally, we can see that 2003, 2004 & 2005 indicate something new is afoot. 2006 extends that pattern in both jurisdictions. We can already see that 2007 cannot bring this new paradigm back to the norms. Using a calculator, any of us can see that KSA would have to drop to 8.4-mbd and globally we'd have to dip to 77-mbd from 86-mbd to get back to the old regime lines. And that ain't gonna happen. So we have in effect five years of HL new regime to consider.
I warned in October that inventories were bulging. The cutbacks were a natural reaction. Anybody who didn't believe it thru November and December has to look at last week's prices (now 22% below September) and ask when they will stop fooling themselves. Both EIA and IEA are showing surplus capacity at almost double that of a year ago.
Peak Oil got on the Iran bandwagon and piggybacked a ride to its 15 minutes of fame. The fear factor is evaporating before our eyes and the marketplace is returning to historic real norms.
There are 13 recognized Outlooks that tell us we are on our way to 90-mbd shortly after the inaugeration of the next usa President. There are NONE that defy that trend. There are no recognized URR Estimates that are showing a decline in annual URR. In fact, because they are consistent on Reserves, they are in effect going up 31-Gb/yr because they have chosen not to deduct last year's Consumption.
To defend a URR of 2086-Gb and a Peak in 2005 brings the level of debate to cult status. It is inconceibable that global production that has risen from 77-bd to 86-mbd in a mere 48 months is just going to roll over 'cuz of Jeffrey's misguided use of that same calculator. It is apparent from the list of folks who tell us supply is going up and the credentials or lack thereof of those on the very short list who say otherwise, that one camp is very wrong (again).
"There are 13 recognized Outlooks that tell us we are on our way to 90-mbd shortly after the inaugeration of the next usa President. There are NONE that defy that trend. There are no recognized URR Estimates that are showing a decline in annual URR."
Freddy, what is the current average of these outlooks regarding a peak date and maximum rate per day achieved?
You are basing this forecast of production on a few years trendlines that have seen the price of oil going up. What happens when the price of oil stagnates or declines over a year or two? Prices for new production and enhanced recovery are increasing at 25 to 50% per year in such places as Alberta tar sands. Probably same is true for KSA and deepwater Gulf of Mex. Then also consider that places like Iran and Mexico don't have the political will to increase production. And other places like Iraq and Nigeria are on the edge of civil war with factions fighting over who gets the benefits of oil.
Bottom line: IMO your forecast of 95 mbd is unlikely given economic considerations and political turmoil. Remember URR does not mean increased production, only that oil can be produced at a certain cost.
1. No storms in the gulf last year. (At the start of the year 06 you would have had trouble finding someone to take this bet).
2. Mild winter (almost no winter infact)Even without cold weather we are still getting thru our oil stocks. A normal winter and you would be looking at a much different price.
3. The market has learned to live with the risk of no spare capacity. Like living next to a volcano after a while you stop thinking about it same situation here. Nigeria could explode any minute this is not priced into the market it has just learned to live with it..
4. SPR is being used as the swing producer untill the 05 storms this was not the case.
5. The Saudis oil production begin falling while oil was around $76. Production cuts I dont think so.
6. This market is dodging bullets. It required a string of positive events to allow it to fall to this level.
Using the current "low" oil price as a sign that all is well is misleading. It would only have taken one "normal" event to have sent it running a lot higher...
All is not well in the oil market one only has to check the falling tanker rates...
This site shows daily changes in the tanker index, but doesn't provide dollar rate or historic data. I just tried a quick search and couldn't find one that did.
The comment that tanker rates are set to plunge seems accurate (see below), but doesn't provide any insight into oil depletion. We already know that exports haven't increased, so one would expect tanker rates to drop, regardless of whether the cause was limited supply or reduced demand.
Tanker Rates May Drop for Third Year, Hurting Frontline, OSG
2007-01-05 05:16 (New York)
By Alaric Nightingale
Jan. 5 (Bloomberg) -- The cost of transporting oil on
supertankers may fall for a third consecutive year as crude
shipments ease and new vessels are launched, prompting owners to
sell ships as scrap metal or adapt them for other uses.
Companies including Frontline Ltd. and Overseas Shipholding
Group Inc. may earn about $43,000 a day for hauling 2-million-
barrel cargoes on the benchmark 40-day round trip between the
Middle East and Japan during 2007, according to the median
estimate of 10 analysts surveyed by Bloomberg. Earnings averaged
$59,250 a day last year.
``We are looking at a year of high vessel deliveries and
softer trading conditions than typically prevailed over the past
three years,'' said Mark Jenkins, a senior analyst in London for
Simpson, Spence & Young Ltd., the world's largest closely held
shipbroker. ``That's likely to result in some owners of older
ships finally accepting that it's time to cash in their chips.''
Earnings for Hamilton, Bermuda-based Frontline, whose fleet
has the world's biggest carrying capacity, and Overseas
Shipholding are being squeezed by an expansion in the global
tanker fleet and a drop in Middle East exports. Since November,
OPEC has pledged to cut crude supplies by 1.7 million barrels a
day. Next year, 35 supertankers enter service, more than double
this year's additions.
$40,000 a Day
Owners probably will earn $40,000 a day from their
supertankers in the first quarter on the Middle East-Asia
voyage, according to the median estimate of nine of the
analysts. That compares with $71,910 last year, according to
London-based shipbroker Galbraith's Ltd.
The very large crude carriers, or VLCCs, that will either
head for conversion yards or be broken up for scrap are likely
to be those with one layer of steel separating their cargo tanks
from the ocean. Single-hull vessels, due to be banned by the
United Nations from 2010, usually earn less and are a higher
risk to the environment than those with two hulls.
Frontline's profit fell 19 percent to $381 million in the
nine months to September as a glut of vessels reduced hire
rates. Earnings at New York-based Overseas Shipholding, the
biggest U.S.-based tanker owner, dropped almost 21 percent to
$279.4 million. Frontline said fourth-quarter performance would
be even ``weaker'' as reduced OPEC shipments cut vessel demand.
Hire rates for VLCCs dipped below Frontline's stated break-
even levels at one stage in the fourth quarter. Profit from the
company's single-hull tankers probably was hit even harder,
earning about $10,000 a day less than double hulls, Chief
Executive Officer Bjorn Sjaastad said in November.
Just as earnings for the vessels declines, a rally in crude
prices is presenting owners with other, more profitable ways of
employing them.
Last week i asked Jeffrey at what rate KSA production would have to return to or exceed for him to admit that his sentiment on KSA Peak was in error. He was silent. I will give u and/or others the same opportunity.
Rather than challenge almost every one of your points, i will approach it in this fashion: Last autumn, i was almost alone in forecasting that the usa avg contract price would return to the low 50's by year end from its Sept high of $69/barrel. From early reporting it appears that oil closed out at approx $54. At what contract price (not spot) would u agree that your hunch and position is in error ... and we'll wait and see?
I would say one thing that would be very important when analyzing future SA rates is that only looking at C+C needs to stop. They have major GTL projects, as well as huge additional refinery capacity coming online in coming years (ie they will be exporting less crude and more refined products).
The refinery capacity that they are adding makes it sound like they are much more optimistic about their future production than many around here.
They may need all their NG just to run the gas turbines that are pumping more water. Also their growing pop. requires more desalinization plants. In 05 KSA produced only 1/7th of the NG that the US produced.
Yes increasing KSA's refining capacity could mean that they are optimistic on production but/and it could also mean they acknowledge that there is a worldwide shortage of light sweet oil and KSA's "Arab Light" is an intermediate grade with high sulphur content -- for which there is currently and for the at least next 4 years there will be a shortage of refining capacity in the US and Asia.
First, this site is mostly interested in po, not peak prices. Regarding the latter, you predicted low prices because your lot predicted record production. In the event, production plateaud but we had another warm winter, and it is weather related demand destruction, not price, that is the real reason prices have not gone back up even tho storage is down to last year's. THere is absolutely no indication that the major consuming nations are cutting back on account of price. Regarding po, your consensus projections' predictions for 06 were for significantly higher produciton than 05, and there was no recession even as avg price hit a nominal record for any year... so, your continued hopes for higher production in future years should have a logical explanation for last year's miss, otherwise you should join peak now.
Second, I posted the following reply to a comment you made a week ago... the new format lets me see my comments, but not whether they generated responses, so maybe you can't see it:
As I told wt, no month will be remembered as a peak, just as no q will be. What is important is the peak year; the interesting points are a) that a great 3q was not able to bring 06 above 05, and b) that 4q dropped back quickly, indicating that 3q production level is not likely to continue.
Your comparing the 1999/02 plateau with the current one is like apples and oranges... then, the US, japan, and parts of europe were in recession, and prices were low. The current plateau is happening with good gdp growth and record prices. Everybody, not least sa, is producing balls out. Not one barrel was left behind last year on account of low prices or demand destruction, excluding only the modest cutback by opec nov/dec. In spite of this, all of your contributors, including colin, over predicted 06 production, and by a lot... what, indeed, was their consensus for 06 production? This is a serious question, and one which you could answer if you are willing to... but, I don't really expect an answer as it would undermine your position.
Meanwhile, stuart and his plateau was right on, and wt was not far behind. Something seems to have gone awry with your consensus, given that nominal 06 prices were at a record high. What might have happened?
THe peak oil now (pon) crowd thinks major producers are declining at a much higher rate than your lot expected. north sea, sa, mexico, us gulf, china? (certainly daqing, but anyway a bit murky there), etc. us historical decline data does not work for the rest of the world because of the high tech, eg horizontal, is allowing fields to be produced at a higher rate at the end of their life, naturally leading to very rapid decline rates. Old on shore fields are being produced exactly as off shore fields are, and will therefore have similar decline rates. This certainly appllies to nearly all sa fields, not least ghawar, and probably iran/q8 as well (the latter may anyway have to reduce production on account of parliament wishing to limit produciton to 2% of actual, as opposed to imanginary, reserves.)
A reason mentioned by a few is equipment. Your fav IEA says there will be no problem "as long as the necessary investments are made." IEA probably meant financial. But, what if what is necessary exceeds the world's available rigs? SA is increasing rigs as fast as they can, which is already slashing us gom ng production. And, while sa produciton is no doubt higher now that they have 60 rigs than what it would be if they has stayed with 18, production is nevertheless declining fairly rapidly.
Colin, thrice bit mostly on account of deep offshore in s. atlantic basin, is naturally a little shy. IMO he is looking for ngl production to come on line faster than is likely.
How long wiil we manage to cling to the plateau? How long will new fields (none in sa) manage to make up for accelerating decline and equipment delays? We'll just have to wait and see. Your conviction that production will soon revert to an upward climb should explain why 06/05 was flat. You have been turning Economics 101 on its head; economists normally claim that high prices lead to higher supply in a free market, not that high prices lead to lower or stagnant supply.
BTW, how interesting that it is all happening at once. US ng peaks in 01, canadian ng in 02, world oil in 05/6, the us now inporting coal as GB and western europe desperately looks to import oil and gas... We live in interesting times. Lets hope for more warm winters, which is the real demand destruction these days, not price. Consider that high ng last year boosted fuel oil demand, missing this year...
The price of oil is not really low they are volatile I'd urge someone with the numbers to track the price of oil over the last few years and I think you will see that it has been varying over a far wider range than normal. This is in fact the signature of peak oil. Highly volatile prices with random spike as events converge to cause a "run on the bank".
Expect more of it over the next few years.
In fact if I'm right about the situation expect a peak about Feb 15-March 15 or so to the 70-80 dollar range.
I've debated making the prediction but now I'm about 80% confident it will happen. We will see.
Hmm the chart seem to be off by a bit we should be back down quite a bit form the last peak.
But notice how bumpy the price peaks are not by any means smooth.
About what I thought it should be. We should start another spike soon as I said.
The main point is that if oil is really plentiful we will simply continue to drop of this peak if not it will spike again.
Using a calculator, any of us can see that KSA would have to drop to 8.4-mbd and globally we'd have to dip to 77-mbd from 86-mbd to get back to the old regime lines. And that ain't gonna happen.
No? After the latest announcement the Saudi are just 100.000 b/d away from reaching 8.4.
Like the emperor you have been shown to be naked. Only you're more like the court jester.
I am continually surpised that so many people on TOD refuse to believe that some or all of Saudi production cuts since last summer could be the result of a deliberate policy of production restraint arising from the drop in the price of oil.
To suggest that Saudi production has droppped from 9.60 mm bpd to 8.50 mm bpd in a little over six months purely as a result of involuntary production decline is naive in the extreme. This would suggest an annualised decline rate of somewhere in the region of 20% which is clearly ridiculous.
To my mind the credibility of numerous contributors on this board will be put in serious jeopaardy unless they are willing to admit that Saudi Arabia is capable (and willing) to enact VOLUNTARY production cuts to stabilise OECD petoleum stock levels and thereby defend certain price levels for crude oil.
The risk of continued denial of this possibility is that many hitherto credible and valuable contributors to this site collecively become seen as the "boy who cried wolf". In the longer term, the importance and ramifications of peak oil (or peak hydrocarbons) are too important for any knowledgeable contributor to lose credibility over such a transparent case of market management as Saudi Arabia is currently engaged in.
Please, can we get back to debating issues of clearly greater substance. It is absolutely 100% given that Saudi has voluntarily cut production quotas in accordance with OPEC policy and this will be clearly demonstrated as soon as oil prices rise again to the mid-$60's. This will occur when OECD petroleum stock levels decline to a more historic average than at present. This in turn will occur when sustained colder winter weather arrives or OPEC production cuts finally take necessary effect in the market. In any case I expect prices to begin to recover going into the second quarter as the market bids for barrels to increase stockpiles ahead of the US hurricane season.....
why do you consider a 20% annual decline rediculous ? as westex, etal have discussed when the water rises to the level of the horizontal wells, what else would you expect ? i am not saying it is or is not 20% but 20% is NOT rediculous
Ultimately 20% would not be a ridiculous decline rate for one field (as we may be seeing at Cantarell for example), but it seems excessive relative to an entire producing region across multiple fields at differnet stages of production/decline.
I am not aware of any producing basin (as opposed to an individual field) that has declined at such a rate and certainly not within such a short time of having hit its highest production levels (ignoring the eaarly 1980's peak which we know was subsequently impacted by macroeconomic rather than geologic issues).
More importantly, decline in older producing regions (such as Saudi) seems to start relatively slowly and then accelerate. I think this is because secondary and tertiary recovery are deployed sequentially. In newer production basins like the North Sea (and particularly with newer fields in the North Sea) decline sets in rapidly almost from the outset of production. This seems to be because primary, secondary and tertiary production techniques are deployed from the start to maximise net present (monetary) value of the field's reserves.
I am by no means an expert in this field. What I have writtten above is largely a result of what I have learnt here and on other sites and I have no wish to start a war of words. However I stand by my assertion that many people with more knowledge and input than myself are putting their reputations at risk here. These people need to have their credibility intact far more than I do when the peak oil issue is debated in a wider environment than TOD.
To suggest that Saudi production has dropped from 9.60 mm bpd to 8.50 mm bpd in a little over six months purely as a result of involuntary production decline is naive in the extreme. This would suggest an annualized decline rate of somewhere in the region of 20% which is clearly ridiculous.
According to the EIA, the last time that the Saudis (KSA) made 9.6 mpbd (C+C) was 9/05. Again according to the EIA, KSA has never exceeded 9.6 since then--and IMO it never will. Assuming that the 2/07 production estimate of 8.5 mbpd is correct, we have seen a decline of 11.4% in 15 months, or an annual decline rate of about 9%. Note that to get more accurate numbers over a longer time period, we need to use logarithmic calculations.
I have frequently pointed out that Ghawar and Cantarell are similar fields--the two largest producing fields in the world, carbonate reservoirs, where the remaining oil is in rapidly thinning oil columns between expanding gas caps and rising water legs.
We have quite a bit more data on Cantarell. According to the WSJ, as of early 2006, the remaining oil column at Cantarell of 800' was thinning at the rate of about 300' per year. The worst case decline rate, i.e., the most realistic IMO, was for an annual decline rate of 40% per year. Energy analyst David Shields has discussed how Pemex sought to hide their internal estimate of the Cantarell decline rate, using a more optimistic decline rate in public. (I wonder if Saudi Aramco might be doing the same?)
Ghawar has probably produced close to 60 Gb. Matt Simmons quoted a retired Aramco executive (the old Aramco) as saying that Ghawar would never, in his opinion, exceed 70 Gb. If that is correct, the field is about 85% depleted. We do know that the oil column was thinning rapidly, because the vertical wells were watering out, which is why they were forced to go to horizontal wells. Even after going to horizontal wells, the best case is that they still producing about one barrel of water for every two barrels of oil--not a stable situation. Until recently at least, Ghawar accounted for more than half of KSA's production. What do you think will happen to Saudi production when the water hits the horizontal wells?
I have repeatedly described Ghawar and Cantarell as two warning beacons, burning brightly in the night sky--heralding the onset of Peak Oil. IMO, these two fields, which at least at one time accounted for 10% of world C+C production, are both in terminal decline.
You are one of the people who I am most worried about in terms of blowing your credibility by putting all your eggs in the "Saudi has peaked" basket. It will not matter in the future if you have been right on 99 out of 100 other issues, you will be remmebered (and attacked by the Cornucopian factions) for the one you got wrong.
In my opinion, none of us can say with absolute certainty what is the situation at Ghawar and other KSA fields. Neither can we rely on "retired Aramco executives" who have spoken to Matt Simmons. Without documentary evidence this all "hearsay" and opinion.
It is my opinion KSA is currently voluntarily holding back production from the market to try to draw down OECD petroleum inventories and increase (or at least support) crude oil prices. There are numerous previous examples of this behaviour by KSA and OPEC in general.
My reference to "20% decline" was made in reference to an annnualised extrapolation from last summer's peak production rate of 9.50 mm bpd. It does indeed look very different if you calculate it from Sept 2005 when 9.60 mm bpd was achieved. One could also argue that the decline would lok very small on an annualised basis if taken from all time peak production in 1980 (??). My point remains however that it SEEMS unlikely to me that KSA as a whole would suffer a 20% annualised decline from recent peak rates (ie summer 2006) even if Ghawar is in permanent decline.
From my reading about Ghawar, I am left with the impression that it would better be described as a series of smaller oil (still huge) oil fields rather than one entity. The recent Haradh development (300 kbpd) seems in fact to be part of the southern part of Ghwar but is talked about as a separate field. In this respect I think it is likely that parts of Ghawar are in more serious decline than others, and indeed that some parts can still undergo further development.
Do you think that "when the water hits the horizontal wells" this is likely to affect all the whole of Ghawar at the same time? Would this not suggest a far more uniform field than Simmons et al lead us to beleive is the case? Clearly when each individual well encounters water, that is pretty much it for that well, but how many wells are there across the whole of the Ghawar complex?
It is my opinion KSA is currently voluntarily holding back production from the market to try to draw down OECD petroleum inventories and increase (or at least support) crude oil prices. There are numerous previous examples of this behavior by KSA and OPEC in general.
In the past, Saudi Arabia has tended to curtail production when prices fell, and to increase production when prices rose, i.e., Saudi was the successor to Texas as the primary "swing" producer, which is why I use Texas as a model for Saudi Arabia.
This time, Saudi Arabia announced their "voluntary" production cutbacks, just as oil prices were headed to all time record (nominal) highs. This also corresponded to the start of the 2006 Saudi stock market crash, in contrast to the Venezuelan stock market, which is booming.
My opinion is based on mathematical (HL) models. Saudi Arabia started declining--as I predicted--at the same stage of depletion at which Texas started its permanent decline. Based on the HL model, Saudi Arabia is 60% depleted. I am not aware of a single case history of a producing region (60 Gb or more) showing sustained production increases past the 60% of Qt mark. In effect, you are arguing in favor of something that the world, insofar as I know, has never seen.
I understand your reasoning and I know I am incapable of refuting the HL mathematical model. I am not convinced the model will prove accurate for KSA, because their production decisions are I believe more complex than those of the Texas Railroad Commission. Furthermore technology has changed dramatically since Texas peaked allowing for greater recovery of oil.
This has had the effect of prolonging the "tail" of production in Texas whilst doing nothing to change the date or size of peak. But hasn't it also significantly increased the URR of Texas? If that is rigth, does it not also that peak production occurred before 50% Qt, and increasingly so every year?
If such technology has existed several decades beforehand, would it be fair to say that Texas may have peaked sooner and at a higher rate than it did, or alternatively that it would have been able to sustain a higher rate of production than it actually managed in the early 1970's as the technology was not then developed?
"Secondary" and "tertiary" production techniques now appear to be applied at the inception of a fields's production. This means that peak flow rates will occur right at the beginning of a field's life. I am just a beginner when it comes to HL, but surely this fact would refute the methodoliogy if applied to recent individual fields in the North Sea, or indeed to the North Sea as a territory if we only counted fields developed since, say, 1990. Clearly, if peak production occurs at the beginning of a field's life, it will be quicker to reach 50% Qt, but production rate per se will be an irrelevance in predicting URR? Or am I completely out of my depth here?
In the same way I think that developing (or developed) technology enables greater recovery of OOIP and increased URR. Inevitably this causes the HL curve to flatten. Peak production rates may not increase, but post-peak production will continue for longer on a shallower decline curve. This means that it should be more likely that we see increasing cases of " sustained production increases past the 60% of Qt mark" since the URR will still be increasing at that time. Doesn;t this make the HL method less predictive than it migh first appear? Obviously, in retrospect, these production increases will not have been "past the 60% Qt mark" because, unbeknownst to us at the time, URR was increasing and thus %Qt was therefore less than 60% during the period of observation... I am confusing myself here....
I am not trying to be argumentative here, but thse questions have been bugging me for some time and appear very relevant to the general subject matter at TOD.
Furthermore technology has changed dramatically since Texas peaked allowing for greater recovery of oil.
Two points.
First, the North Sea peaked 29 years later than the Lower 48 (1999 versus 1970), but the North Sea, like the Lower 48, peaked right at the 50% of Qt mark (C+C). So much for better technology.
Second, we have had access to much improved technology here in the Lower 48 and Texas, and depletion marches on.
I am not arguing that technologyn has not been available in Texas/Lower 48. I am questioning what would have happened to peak production and date if the sort of technology we have today (horiozontal well, bottlebrush wells, etc) had been available in, for example, the 1960's.
Similarly, if the UK North Sea had ALL been developed as new fields are (ie going to peak production within the first year, and then into a long term decline thereafter), would this not have dramatically altered the shape of the curve, and therefore the results extrapolated from that curve?
Both of these are clearly totally hypothetical questions, but they seem relevant in that the theoretical answers suggest that Hubbert might have had to revise his theory had present day technology been available in the 1950's.
This certainly does not mean that the whole HL methodology is wrong, but as URR increases year by year as marginal improvements are made in recovery processes, or as oil prices allow production from previously non-viable fields, this must have an impact on the results of the methodology itself, if only to broaden the Qt range at whick peak will be crossed for example.
I would love to see an HL plot for all (UK and Norwegian) North Sea fields developed since 1990 - I am convinced it would lead us to hugely different conclusions than Hubbert's original work. Though maybe an extreme case, it would make an argument for consideration of technology improvements since Hubbert originally produced his theory.
You don't apply HL to individual fields. In its most useful form it is a heuristic of the production profile of a range of fields that statistically vary in rate parameters.
I would love to see an HL plot for all (UK and Norwegian) North Sea fields developed since 1990 - I am convinced it would lead us to hugely different conclusions than Hubbert's original work. Though maybe an extreme case, it would make an argument for consideration of technology improvements since Hubbert originally produced his theory.
Not to be a prick, but it did take me about 30 seconds to find that with google. Perhaps before you become "convinced" you should at least look at the data.
Right, Saudi oil reserves were way underestimated. Hell they are still underestimated, they say they have about 200 billion barrels yet to be discovered. That is in addition to the 260 billion barrels of already "proven" reserves. The whole damn country is just floating on oil.
And otherwise highly intelligent people really believe this stuff. It is enough to make a grown man cry.
Ron Patterson
The KSA has only recently developed fields that contain the second half of their P1, P2 & P3 Reserves & past Consumption of 462-Gb as described including their production plans last month. They have expressed their intention to develop 394-Gb of this by 2054. In 2007 and beyond, we will continue to see Hubbert Linearization models undergo realignment such that KSA's (all liquids) URR shifts from an indicated 197-Gb to 394-Gb. This is known affectionately as the Global and KSA dogleg (pre-revision graph credit to Euan Mearns) and will become more prominent as the decade progresses:
It is too early to assess the cumulative effect of similar latent fields opening, but Jean Laherrere (with two decades experience in linearizations) is already illustrating that the new regime indicates that (all liquids) URR has moved from 2250-Gb to 3100-Gb.
This bodes well for long term availability of oil globally, but is not an indicator that Peak Rate or Peak Date will be extended. It will likely only dampen the decline rate.
Freddy you cannot draw conclusions from a three year change in the curve....
Clearly, Jeffrey's use of HL is flawed. In both KSA & Globally, we can see that 2003, 2004 & 2005 indicate something new is afoot. 2006 extends that pattern in both jurisdictions. We can already see that 2007 cannot bring this new paradigm back to the norms. Using a calculator, any of us can see that KSA would have to drop to 8.4-mbd and globally we'd have to dip to 77-mbd from 86-mbd to get back to the old regime lines. And that ain't gonna happen. So we have in effect five years of HL new regime to consider.
I warned in October that inventories were bulging. The cutbacks were a natural reaction. Anybody who didn't believe it thru November and December has to look at last week's prices (now 22% below September) and ask when they will stop fooling themselves. Both EIA and IEA are showing surplus capacity at almost double that of a year ago.
Peak Oil got on the Iran bandwagon and piggybacked a ride to its 15 minutes of fame. The fear factor is evaporating before our eyes and the marketplace is returning to historic real norms.
There are 13 recognized Outlooks that tell us we are on our way to 90-mbd shortly after the inaugeration of the next usa President. There are NONE that defy that trend. There are no recognized URR Estimates that are showing a decline in annual URR. In fact, because they are consistent on Reserves, they are in effect going up 31-Gb/yr because they have chosen not to deduct last year's Consumption.
To defend a URR of 2086-Gb and a Peak in 2005 brings the level of debate to cult status. It is inconceibable that global production that has risen from 77-bd to 86-mbd in a mere 48 months is just going to roll over 'cuz of Jeffrey's misguided use of that same calculator. It is apparent from the list of folks who tell us supply is going up and the credentials or lack thereof of those on the very short list who say otherwise, that one camp is very wrong (again).
"There are 13 recognized Outlooks that tell us we are on our way to 90-mbd shortly after the inaugeration of the next usa President. There are NONE that defy that trend. There are no recognized URR Estimates that are showing a decline in annual URR."
Freddy, what is the current average of these outlooks regarding a peak date and maximum rate per day achieved?
95-mbd in 2020
Sounds a little high and far out, but not completely unreasonable. I wonder what the % of the total liquid that C+C will be?
I would assume it would be considerable smaller than it is today. Just read an article and it looks like the CTL push in the US may be starting.
You are basing this forecast of production on a few years trendlines that have seen the price of oil going up. What happens when the price of oil stagnates or declines over a year or two? Prices for new production and enhanced recovery are increasing at 25 to 50% per year in such places as Alberta tar sands. Probably same is true for KSA and deepwater Gulf of Mex. Then also consider that places like Iran and Mexico don't have the political will to increase production. And other places like Iraq and Nigeria are on the edge of civil war with factions fighting over who gets the benefits of oil.
Bottom line: IMO your forecast of 95 mbd is unlikely given economic considerations and political turmoil. Remember URR does not mean increased production, only that oil can be produced at a certain cost.
The reason for the fall in the price of oil is.
1. No storms in the gulf last year. (At the start of the year 06 you would have had trouble finding someone to take this bet).
2. Mild winter (almost no winter infact)Even without cold weather we are still getting thru our oil stocks. A normal winter and you would be looking at a much different price.
3. The market has learned to live with the risk of no spare capacity. Like living next to a volcano after a while you stop thinking about it same situation here. Nigeria could explode any minute this is not priced into the market it has just learned to live with it..
4. SPR is being used as the swing producer untill the 05 storms this was not the case.
5. The Saudis oil production begin falling while oil was around $76. Production cuts I dont think so.
6. This market is dodging bullets. It required a string of positive events to allow it to fall to this level.
Using the current "low" oil price as a sign that all is well is misleading. It would only have taken one "normal" event to have sent it running a lot higher...
All is not well in the oil market one only has to check the falling tanker rates...
Know of a good website to track up to date tanker rates?
This site shows daily changes in the tanker index, but doesn't provide dollar rate or historic data. I just tried a quick search and couldn't find one that did.
http://www.lloydslist.com/
The comment that tanker rates are set to plunge seems accurate (see below), but doesn't provide any insight into oil depletion. We already know that exports haven't increased, so one would expect tanker rates to drop, regardless of whether the cause was limited supply or reduced demand.
Tanker Rates May Drop for Third Year, Hurting Frontline, OSG
2007-01-05 05:16 (New York)
By Alaric Nightingale
Jan. 5 (Bloomberg) -- The cost of transporting oil on
supertankers may fall for a third consecutive year as crude
shipments ease and new vessels are launched, prompting owners to
sell ships as scrap metal or adapt them for other uses.
Companies including Frontline Ltd. and Overseas Shipholding
Group Inc. may earn about $43,000 a day for hauling 2-million-
barrel cargoes on the benchmark 40-day round trip between the
Middle East and Japan during 2007, according to the median
estimate of 10 analysts surveyed by Bloomberg. Earnings averaged
$59,250 a day last year.
``We are looking at a year of high vessel deliveries and
softer trading conditions than typically prevailed over the past
three years,'' said Mark Jenkins, a senior analyst in London for
Simpson, Spence & Young Ltd., the world's largest closely held
shipbroker. ``That's likely to result in some owners of older
ships finally accepting that it's time to cash in their chips.''
Earnings for Hamilton, Bermuda-based Frontline, whose fleet
has the world's biggest carrying capacity, and Overseas
Shipholding are being squeezed by an expansion in the global
tanker fleet and a drop in Middle East exports. Since November,
OPEC has pledged to cut crude supplies by 1.7 million barrels a
day. Next year, 35 supertankers enter service, more than double
this year's additions.
$40,000 a Day
Owners probably will earn $40,000 a day from their
supertankers in the first quarter on the Middle East-Asia
voyage, according to the median estimate of nine of the
analysts. That compares with $71,910 last year, according to
London-based shipbroker Galbraith's Ltd.
The very large crude carriers, or VLCCs, that will either
head for conversion yards or be broken up for scrap are likely
to be those with one layer of steel separating their cargo tanks
from the ocean. Single-hull vessels, due to be banned by the
United Nations from 2010, usually earn less and are a higher
risk to the environment than those with two hulls.
Frontline's profit fell 19 percent to $381 million in the
nine months to September as a glut of vessels reduced hire
rates. Earnings at New York-based Overseas Shipholding, the
biggest U.S.-based tanker owner, dropped almost 21 percent to
$279.4 million. Frontline said fourth-quarter performance would
be even ``weaker'' as reduced OPEC shipments cut vessel demand.
Hire rates for VLCCs dipped below Frontline's stated break-
even levels at one stage in the fourth quarter. Profit from the
company's single-hull tankers probably was hit even harder,
earning about $10,000 a day less than double hulls, Chief
Executive Officer Bjorn Sjaastad said in November.
Just as earnings for the vessels declines, a rally in crude
prices is presenting owners with other, more profitable ways of
employing them.
Baltic Dry is the standard. Perhaps u can get a friendly tanker link from one of the sites that cover it.
http://www.slate.com/id/2090303/
http://investmenttools.com/futures/bdi_baltic_dry_index.htm
In the meantime, here's a historic view compliments of iea:
http://trendlines.ca/energy.htm#misc
Last week i asked Jeffrey at what rate KSA production would have to return to or exceed for him to admit that his sentiment on KSA Peak was in error. He was silent. I will give u and/or others the same opportunity.
Rather than challenge almost every one of your points, i will approach it in this fashion: Last autumn, i was almost alone in forecasting that the usa avg contract price would return to the low 50's by year end from its Sept high of $69/barrel. From early reporting it appears that oil closed out at approx $54. At what contract price (not spot) would u agree that your hunch and position is in error ... and we'll wait and see?
I would say one thing that would be very important when analyzing future SA rates is that only looking at C+C needs to stop. They have major GTL projects, as well as huge additional refinery capacity coming online in coming years (ie they will be exporting less crude and more refined products).
The refinery capacity that they are adding makes it sound like they are much more optimistic about their future production than many around here.
They may need all their NG just to run the gas turbines that are pumping more water. Also their growing pop. requires more desalinization plants. In 05 KSA produced only 1/7th of the NG that the US produced.
It would make sense to add refinery capacity if you are importing refined products, because of internal increased consumption.
Yes increasing KSA's refining capacity could mean that they are optimistic on production but/and it could also mean they acknowledge that there is a worldwide shortage of light sweet oil and KSA's "Arab Light" is an intermediate grade with high sulphur content -- for which there is currently and for the at least next 4 years there will be a shortage of refining capacity in the US and Asia.
"At what contract price (not spot) would u agree that your hunch and position is in error ... and we'll wait and see?"
That depends on the psychology of the market participants.
"Last autumn, i was almost alone in forecasting'
Lets all give fast freddy a round of applause and a pat on the back of the head he so desperately needz.
Freddy
First, this site is mostly interested in po, not peak prices. Regarding the latter, you predicted low prices because your lot predicted record production. In the event, production plateaud but we had another warm winter, and it is weather related demand destruction, not price, that is the real reason prices have not gone back up even tho storage is down to last year's. THere is absolutely no indication that the major consuming nations are cutting back on account of price. Regarding po, your consensus projections' predictions for 06 were for significantly higher produciton than 05, and there was no recession even as avg price hit a nominal record for any year... so, your continued hopes for higher production in future years should have a logical explanation for last year's miss, otherwise you should join peak now.
Second, I posted the following reply to a comment you made a week ago... the new format lets me see my comments, but not whether they generated responses, so maybe you can't see it:
As I told wt, no month will be remembered as a peak, just as no q will be. What is important is the peak year; the interesting points are a) that a great 3q was not able to bring 06 above 05, and b) that 4q dropped back quickly, indicating that 3q production level is not likely to continue.
Your comparing the 1999/02 plateau with the current one is like apples and oranges... then, the US, japan, and parts of europe were in recession, and prices were low. The current plateau is happening with good gdp growth and record prices. Everybody, not least sa, is producing balls out. Not one barrel was left behind last year on account of low prices or demand destruction, excluding only the modest cutback by opec nov/dec. In spite of this, all of your contributors, including colin, over predicted 06 production, and by a lot... what, indeed, was their consensus for 06 production? This is a serious question, and one which you could answer if you are willing to... but, I don't really expect an answer as it would undermine your position.
Meanwhile, stuart and his plateau was right on, and wt was not far behind. Something seems to have gone awry with your consensus, given that nominal 06 prices were at a record high. What might have happened?
THe peak oil now (pon) crowd thinks major producers are declining at a much higher rate than your lot expected. north sea, sa, mexico, us gulf, china? (certainly daqing, but anyway a bit murky there), etc. us historical decline data does not work for the rest of the world because of the high tech, eg horizontal, is allowing fields to be produced at a higher rate at the end of their life, naturally leading to very rapid decline rates. Old on shore fields are being produced exactly as off shore fields are, and will therefore have similar decline rates. This certainly appllies to nearly all sa fields, not least ghawar, and probably iran/q8 as well (the latter may anyway have to reduce production on account of parliament wishing to limit produciton to 2% of actual, as opposed to imanginary, reserves.)
A reason mentioned by a few is equipment. Your fav IEA says there will be no problem "as long as the necessary investments are made." IEA probably meant financial. But, what if what is necessary exceeds the world's available rigs? SA is increasing rigs as fast as they can, which is already slashing us gom ng production. And, while sa produciton is no doubt higher now that they have 60 rigs than what it would be if they has stayed with 18, production is nevertheless declining fairly rapidly.
Colin, thrice bit mostly on account of deep offshore in s. atlantic basin, is naturally a little shy. IMO he is looking for ngl production to come on line faster than is likely.
How long wiil we manage to cling to the plateau? How long will new fields (none in sa) manage to make up for accelerating decline and equipment delays? We'll just have to wait and see. Your conviction that production will soon revert to an upward climb should explain why 06/05 was flat. You have been turning Economics 101 on its head; economists normally claim that high prices lead to higher supply in a free market, not that high prices lead to lower or stagnant supply.
BTW, how interesting that it is all happening at once. US ng peaks in 01, canadian ng in 02, world oil in 05/6, the us now inporting coal as GB and western europe desperately looks to import oil and gas... We live in interesting times. Lets hope for more warm winters, which is the real demand destruction these days, not price. Consider that high ng last year boosted fuel oil demand, missing this year...
The price of oil is not really low they are volatile I'd urge someone with the numbers to track the price of oil over the last few years and I think you will see that it has been varying over a far wider range than normal. This is in fact the signature of peak oil. Highly volatile prices with random spike as events converge to cause a "run on the bank".
Expect more of it over the next few years.
In fact if I'm right about the situation expect a peak about Feb 15-March 15 or so to the 70-80 dollar range.
I've debated making the prediction but now I'm about 80% confident it will happen. We will see.
usa centric oil volatility with Price in black on LS axis & % in red on RS axis:
Trying to steal content and/or infringe copyright ?
Forgot to read this I suspect
The chart on the linked page is probably what he meant to link, it fits Freddy's description at least.
Hmm the chart seem to be off by a bit we should be back down quite a bit form the last peak.
But notice how bumpy the price peaks are not by any means smooth.
About what I thought it should be. We should start another spike soon as I said.
The main point is that if oil is really plentiful we will simply continue to drop of this peak if not it will spike again.
Using a calculator, any of us can see that KSA would have to drop to 8.4-mbd and globally we'd have to dip to 77-mbd from 86-mbd to get back to the old regime lines. And that ain't gonna happen.
No? After the latest announcement the Saudi are just 100.000 b/d away from reaching 8.4.
Like the emperor you have been shown to be naked. Only you're more like the court jester.
I am continually surpised that so many people on TOD refuse to believe that some or all of Saudi production cuts since last summer could be the result of a deliberate policy of production restraint arising from the drop in the price of oil.
To suggest that Saudi production has droppped from 9.60 mm bpd to 8.50 mm bpd in a little over six months purely as a result of involuntary production decline is naive in the extreme. This would suggest an annualised decline rate of somewhere in the region of 20% which is clearly ridiculous.
To my mind the credibility of numerous contributors on this board will be put in serious jeopaardy unless they are willing to admit that Saudi Arabia is capable (and willing) to enact VOLUNTARY production cuts to stabilise OECD petoleum stock levels and thereby defend certain price levels for crude oil.
The risk of continued denial of this possibility is that many hitherto credible and valuable contributors to this site collecively become seen as the "boy who cried wolf". In the longer term, the importance and ramifications of peak oil (or peak hydrocarbons) are too important for any knowledgeable contributor to lose credibility over such a transparent case of market management as Saudi Arabia is currently engaged in.
Please, can we get back to debating issues of clearly greater substance. It is absolutely 100% given that Saudi has voluntarily cut production quotas in accordance with OPEC policy and this will be clearly demonstrated as soon as oil prices rise again to the mid-$60's. This will occur when OECD petroleum stock levels decline to a more historic average than at present. This in turn will occur when sustained colder winter weather arrives or OPEC production cuts finally take necessary effect in the market. In any case I expect prices to begin to recover going into the second quarter as the market bids for barrels to increase stockpiles ahead of the US hurricane season.....
why do you consider a 20% annual decline rediculous ? as westex, etal have discussed when the water rises to the level of the horizontal wells, what else would you expect ? i am not saying it is or is not 20% but 20% is NOT rediculous
Ultimately 20% would not be a ridiculous decline rate for one field (as we may be seeing at Cantarell for example), but it seems excessive relative to an entire producing region across multiple fields at differnet stages of production/decline.
I am not aware of any producing basin (as opposed to an individual field) that has declined at such a rate and certainly not within such a short time of having hit its highest production levels (ignoring the eaarly 1980's peak which we know was subsequently impacted by macroeconomic rather than geologic issues).
More importantly, decline in older producing regions (such as Saudi) seems to start relatively slowly and then accelerate. I think this is because secondary and tertiary recovery are deployed sequentially. In newer production basins like the North Sea (and particularly with newer fields in the North Sea) decline sets in rapidly almost from the outset of production. This seems to be because primary, secondary and tertiary production techniques are deployed from the start to maximise net present (monetary) value of the field's reserves.
I am by no means an expert in this field. What I have writtten above is largely a result of what I have learnt here and on other sites and I have no wish to start a war of words. However I stand by my assertion that many people with more knowledge and input than myself are putting their reputations at risk here. These people need to have their credibility intact far more than I do when the peak oil issue is debated in a wider environment than TOD.
According to the EIA, the last time that the Saudis (KSA) made 9.6 mpbd (C+C) was 9/05. Again according to the EIA, KSA has never exceeded 9.6 since then--and IMO it never will. Assuming that the 2/07 production estimate of 8.5 mbpd is correct, we have seen a decline of 11.4% in 15 months, or an annual decline rate of about 9%. Note that to get more accurate numbers over a longer time period, we need to use logarithmic calculations.
I have frequently pointed out that Ghawar and Cantarell are similar fields--the two largest producing fields in the world, carbonate reservoirs, where the remaining oil is in rapidly thinning oil columns between expanding gas caps and rising water legs.
We have quite a bit more data on Cantarell. According to the WSJ, as of early 2006, the remaining oil column at Cantarell of 800' was thinning at the rate of about 300' per year. The worst case decline rate, i.e., the most realistic IMO, was for an annual decline rate of 40% per year. Energy analyst David Shields has discussed how Pemex sought to hide their internal estimate of the Cantarell decline rate, using a more optimistic decline rate in public. (I wonder if Saudi Aramco might be doing the same?)
Ghawar has probably produced close to 60 Gb. Matt Simmons quoted a retired Aramco executive (the old Aramco) as saying that Ghawar would never, in his opinion, exceed 70 Gb. If that is correct, the field is about 85% depleted. We do know that the oil column was thinning rapidly, because the vertical wells were watering out, which is why they were forced to go to horizontal wells. Even after going to horizontal wells, the best case is that they still producing about one barrel of water for every two barrels of oil--not a stable situation. Until recently at least, Ghawar accounted for more than half of KSA's production. What do you think will happen to Saudi production when the water hits the horizontal wells?
I have repeatedly described Ghawar and Cantarell as two warning beacons, burning brightly in the night sky--heralding the onset of Peak Oil. IMO, these two fields, which at least at one time accounted for 10% of world C+C production, are both in terminal decline.
WT,
You are one of the people who I am most worried about in terms of blowing your credibility by putting all your eggs in the "Saudi has peaked" basket. It will not matter in the future if you have been right on 99 out of 100 other issues, you will be remmebered (and attacked by the Cornucopian factions) for the one you got wrong.
In my opinion, none of us can say with absolute certainty what is the situation at Ghawar and other KSA fields. Neither can we rely on "retired Aramco executives" who have spoken to Matt Simmons. Without documentary evidence this all "hearsay" and opinion.
It is my opinion KSA is currently voluntarily holding back production from the market to try to draw down OECD petroleum inventories and increase (or at least support) crude oil prices. There are numerous previous examples of this behaviour by KSA and OPEC in general.
My reference to "20% decline" was made in reference to an annnualised extrapolation from last summer's peak production rate of 9.50 mm bpd. It does indeed look very different if you calculate it from Sept 2005 when 9.60 mm bpd was achieved. One could also argue that the decline would lok very small on an annualised basis if taken from all time peak production in 1980 (??). My point remains however that it SEEMS unlikely to me that KSA as a whole would suffer a 20% annualised decline from recent peak rates (ie summer 2006) even if Ghawar is in permanent decline.
From my reading about Ghawar, I am left with the impression that it would better be described as a series of smaller oil (still huge) oil fields rather than one entity. The recent Haradh development (300 kbpd) seems in fact to be part of the southern part of Ghwar but is talked about as a separate field. In this respect I think it is likely that parts of Ghawar are in more serious decline than others, and indeed that some parts can still undergo further development.
Do you think that "when the water hits the horizontal wells" this is likely to affect all the whole of Ghawar at the same time? Would this not suggest a far more uniform field than Simmons et al lead us to beleive is the case? Clearly when each individual well encounters water, that is pretty much it for that well, but how many wells are there across the whole of the Ghawar complex?
In the past, Saudi Arabia has tended to curtail production when prices fell, and to increase production when prices rose, i.e., Saudi was the successor to Texas as the primary "swing" producer, which is why I use Texas as a model for Saudi Arabia.
This time, Saudi Arabia announced their "voluntary" production cutbacks, just as oil prices were headed to all time record (nominal) highs. This also corresponded to the start of the 2006 Saudi stock market crash, in contrast to the Venezuelan stock market, which is booming.
My opinion is based on mathematical (HL) models. Saudi Arabia started declining--as I predicted--at the same stage of depletion at which Texas started its permanent decline. Based on the HL model, Saudi Arabia is 60% depleted. I am not aware of a single case history of a producing region (60 Gb or more) showing sustained production increases past the 60% of Qt mark. In effect, you are arguing in favor of something that the world, insofar as I know, has never seen.
I understand your reasoning and I know I am incapable of refuting the HL mathematical model. I am not convinced the model will prove accurate for KSA, because their production decisions are I believe more complex than those of the Texas Railroad Commission. Furthermore technology has changed dramatically since Texas peaked allowing for greater recovery of oil.
This has had the effect of prolonging the "tail" of production in Texas whilst doing nothing to change the date or size of peak. But hasn't it also significantly increased the URR of Texas? If that is rigth, does it not also that peak production occurred before 50% Qt, and increasingly so every year?
If such technology has existed several decades beforehand, would it be fair to say that Texas may have peaked sooner and at a higher rate than it did, or alternatively that it would have been able to sustain a higher rate of production than it actually managed in the early 1970's as the technology was not then developed?
"Secondary" and "tertiary" production techniques now appear to be applied at the inception of a fields's production. This means that peak flow rates will occur right at the beginning of a field's life. I am just a beginner when it comes to HL, but surely this fact would refute the methodoliogy if applied to recent individual fields in the North Sea, or indeed to the North Sea as a territory if we only counted fields developed since, say, 1990. Clearly, if peak production occurs at the beginning of a field's life, it will be quicker to reach 50% Qt, but production rate per se will be an irrelevance in predicting URR? Or am I completely out of my depth here?
In the same way I think that developing (or developed) technology enables greater recovery of OOIP and increased URR. Inevitably this causes the HL curve to flatten. Peak production rates may not increase, but post-peak production will continue for longer on a shallower decline curve. This means that it should be more likely that we see increasing cases of " sustained production increases past the 60% of Qt mark" since the URR will still be increasing at that time. Doesn;t this make the HL method less predictive than it migh first appear? Obviously, in retrospect, these production increases will not have been "past the 60% Qt mark" because, unbeknownst to us at the time, URR was increasing and thus %Qt was therefore less than 60% during the period of observation... I am confusing myself here....
I am not trying to be argumentative here, but thse questions have been bugging me for some time and appear very relevant to the general subject matter at TOD.
Two points.
First, the North Sea peaked 29 years later than the Lower 48 (1999 versus 1970), but the North Sea, like the Lower 48, peaked right at the 50% of Qt mark (C+C). So much for better technology.
Second, we have had access to much improved technology here in the Lower 48 and Texas, and depletion marches on.
I am not arguing that technologyn has not been available in Texas/Lower 48. I am questioning what would have happened to peak production and date if the sort of technology we have today (horiozontal well, bottlebrush wells, etc) had been available in, for example, the 1960's.
Similarly, if the UK North Sea had ALL been developed as new fields are (ie going to peak production within the first year, and then into a long term decline thereafter), would this not have dramatically altered the shape of the curve, and therefore the results extrapolated from that curve?
Both of these are clearly totally hypothetical questions, but they seem relevant in that the theoretical answers suggest that Hubbert might have had to revise his theory had present day technology been available in the 1950's.
This certainly does not mean that the whole HL methodology is wrong, but as URR increases year by year as marginal improvements are made in recovery processes, or as oil prices allow production from previously non-viable fields, this must have an impact on the results of the methodology itself, if only to broaden the Qt range at whick peak will be crossed for example.
I would love to see an HL plot for all (UK and Norwegian) North Sea fields developed since 1990 - I am convinced it would lead us to hugely different conclusions than Hubbert's original work. Though maybe an extreme case, it would make an argument for consideration of technology improvements since Hubbert originally produced his theory.
You don't apply HL to individual fields. In its most useful form it is a heuristic of the production profile of a range of fields that statistically vary in rate parameters.
There ya go from this article.
Not to be a prick, but it did take me about 30 seconds to find that with google. Perhaps before you become "convinced" you should at least look at the data.