Exxon, and the Implications of 8%
Posted by Stuart Staniford on November 17, 2005 - 3:44am
In the past, peak oil projections have used fairly low decline rates for FIP - 3%-6%. There are now several pieces of evidence that the FIP decline rate might be more like 8%. Adding that to Chris Skrebowski's list of new projects makes for a very rough ride:
Production projection with 2005 ODAC Megaprojects plus various average decline rates of existing fields and the supply required to maintain "business as usual".
...the industry is dealing with a phenomenon that is exaggerated by the lack of investment over the past 18 years. This phenomenon is the decline rate for the older reservoirs that form the backbone of the world’s oil production, both in and out of OPEC. An accurate average decline rate is hard to estimate, but an overall figure of 8% is not an unreasonable assumption. The maintenance required to slow the rate of decline, and increase the overall recovery, is a key element of the supply picture going forward.He also notes what has been extensively discussed here at TOD:
Finally, the oil service industry is not in particularly good shape to meet the needs of a rapid worldwide ramp up in activity. A lot of the rig fleet, and much of the equipment are old. Very little spare capacity exists. This combination will compromise the service response, but the most disturbing shortage by far is the lack of specialized E&P professionals. A lot of skilled people have either been laid off, or have retired from the industry in the last 18 years. This shortage is as acute on the service side as it is on that of the operators. Training their replacements takes time, and there is already a great deal of evidence to suggest that the industry is fighting over the core of professionals that remain.It's also been noted by the EIA that Saudi fields are declining by 5%-12%, and that Iran's fields are declining by 8%-13%. So OPEC countries appear to generally fit what Andrew Gould is talking about.
Today, I got email from Kyle Swanson, a Professor of Mathematics and Atmospheric Sciences at the University of Wisconsin-Milwaukee. Kyle looked into what would happen if one did a MegaProjects style analysis on Exxon circa 2001. (Exxon being the most optimistic of the big oil companies - eg. the one not yet running ad campaigns asking the public for help in producing enough oil). Kyle's conclusion:
Looking over Exxon's annual reports for the past 5 years, I think that a reasonable case can be made that Exxon's internal liquid decline rate is actually about 10%.I didn't quite do it the same way as Kyle, but I come out in the same ballpark. Let's replicate and extend his analysis graphically so that we can see exactly what's going on. Here's Exxon's oil production (including NGL and tar sands), over the last five years from their annual reports:
Recent Total Exxon Liquids Production (dark green) with 2001 projection (purple).
The 2005 number is actually the 2nd quarter, taken from Petroleum Review. As you can see, the dark green line is basically flat, with very slight fluctuations. They certainly haven't been growing production in any significant way. However, if we follow Kyle's advice and take a look at their 2001 annual report, we see that they certainly thought they would - they estimated that they would grow at 3% annually through 2007. That's the purple line.
Now, let's take a look at how they expected to do that. A complete list of projects is on page 32. The planned (as of 2001) capacity additions reaching first oil in each year, are shown, along with what actually happened:
Exxon planned and actual additions to capacity reaching first oil in each year.
You can see there's a certain tendency for things to get delayed (as in 2002), and then catch up (as in 2003, where they actually got a little ahead of schedule). The dip in early 2005 production is probably accounted for by the large fraction of new capacity for 2004 that got delayed.
Now, given all this, we can compute a decline rate for FIP from subtracting out the new projects. However, there's one tricky point here. As I have noted in the past, a project which hits first oil in year X, probably doesn't hit peak production until some time in year X+1, and year X+2 might well be the first year to see peak production for the entire year. So assuming a new project in 2001 creates it's peak capacity for all of 2001 creates a significant error. As a rough approximation, I'm going to treat all these projects as though they add nothing in the first year, but the full capacity in the following year. With that assumption, we can make the following picture:
Exxon production together with production computed from various constant decline rates plus actual new projects that reached first oil the prior year. Y-axis is millions of barrels per day, and is not zero-scaled.
Clearly, if there had been no decline in FIP, Exxon would be in seventh heaven, with production up 1mbpd over the last four years, instead of down slightly. That's the power of depletion. Also clearly, a model of constant depletion rate plus new project peak capacity cannot perfectly account for the data. The 8% and 10% curves mostly bracket the actual line, but not perfectly. In fact, if we work the other way and ask what non-constant decline rate would have been required to exactly fit the actual production, we get this:
Exxon estimated annual decline rate in fields in production.
Now, the exact numbers shouldn't be taken too literally here. Remember we have this slightly crude model for the onset of new production in there and the 2005 number is only half way through the year - it could decline more, or some more of the delayed projects might come on and push production up (and thus the decline rate down). My average of these decline rates is 9.4%, not too different than Kyle's 10%. However, clearly the extrapolation of a curve this bumpy by it's average taken as a constant has to be viewed with a little caution.
Before we leave Exxon, one last graph. Let's look at what would have happened to production if they'd had the exact same declines, but all projects had come on exactly as planned in 2001. That would be the middle blue curve here (more-or-less between what they hoped for, and what actually happened).
Exxon production, production goals in 2001, and the prodution they would have achieved with no new project delays, but otherwise identical decline rates. Note that the graph is not zero-scaled.
Clearly, the bulk of Exxon's failure to grow their supply as they hoped does not come from project delays, but rather than from somewhat underestimating the decline rate in their existing fields. Indeed, for the last eight years, all of the very considerable new capacity that Exxon has bought on at great expense and enormous trouble has only gone to offset declines. They have not managed to grow their production or market share one iota. So when Exxon CEO Lee Raymond says
When oil's at $60 a barrel, at least $20 of that is speculative and not supported by the fundamentals.one has to wonder why he feels so confident when his own company is running with Alice and the Red Queen: going hard at it just to stay in the same place.
At any rate, all of this evidence - Saudia Arabia, Iran, Exxon, is reasonably consistent with Ray Gould's 8% number. What does that mean?
Well, if we take Chris Skrebowski's list of projects, this years production of around 84mbpd, and add various decline rates, we get this picture.
Production projection with ODAC Megaprojects plus various average decline rates of existing fields and the supply required to maintain "business as usual".
- Chris Skrebowski has missed most of the volume of new projects in his analysis.
- Andrew Gould is smoking dope, Exxon, Iran, and Saudi Arabia are an anomalously bad piece of the production mix, and the average decline rate is really much lower.
- Life is about to get less fun, pretty quickly.
I think we'd better focus on figuring out whether there's any possibility of 1) or 2) being correct.
Contact
- Content: editors at theoildrum dot com
- Tech support: support at theoildrum dot com
License
This work is licensed under a Creative Commons Attribution-Share Alike 3.0 United States License.
Are there models that suggest rate of decline might accelerate from year to year as more aggressive extraction mechanisms are brought on line?
I modelled the world oil production logistic curve with normal distribution given the following:
PO production = 30.9 Gbbo/year
Total URR = 2400 Gbbo
The standart deviation for this is 31 years.
Here is what I got:
Year Production Change Cummulative change relative to year 0
0 30.88049825 0.10% 0.00%
1 30.88049825 0.00% 0.00%
2 30.84838404 -0.10% -0.10%
3 30.78425576 -0.21% -0.31%
4 30.68831322 -0.31% -0.62%
5 30.5608548 -0.42% -1.04%
6 30.40227596 -0.52% -1.55%
7 30.21306715 -0.62% -2.16%
8 29.9938113 -0.73% -2.87%
9 29.74518084 -0.83% -3.68%
10 29.46793426 -0.93% -4.57%
11 29.16291223 -1.04% -5.56%
12 28.8310334 -1.14% -6.64%
13 28.47328974 -1.24% -7.80%
14 28.09074164 -1.34% -9.03%
15 27.68451269 -1.45% -10.35%
16 27.25578415 -1.55% -11.74%
17 26.80578925 -1.65% -13.20%
18 26.33580732 -1.75% -14.72%
19 25.84715776 -1.86% -16.30%
20 25.34119383 -1.96% -17.94%
21 24.81929652 -2.06% -19.63%
22 24.28286831 -2.16% -21.37%
23 23.7333269 -2.26% -23.14%
24 23.17209914 -2.36% -24.96%
25 22.60061485 -2.47% -26.81%
26 22.02030097 -2.57% -28.69%
27 21.43257571 -2.67% -30.60%
28 20.83884299 -2.77% -32.52%
29 20.24048703 -2.87% -34.46%
30 19.63886723 -2.97% -36.40%
31 19.03531332 -3.07% -38.36%
32 18.43112077 -3.17% -40.31%
33 17.82754659 -3.27% -42.27%
34 17.22580534 -3.38% -44.22%
35 16.62706559 -3.48% -46.16%
36 16.0324467 -3.58% -48.08%
37 15.44301593 -3.68% -49.99%
38 14.85978596 -3.78% -51.88%
39 14.28371276 -3.88% -53.75%
40 13.71569384 -3.98% -55.58%
41 13.15656684 -4.08% -57.40%
42 12.60710849 -4.18% -59.17%
43 12.06803397 -4.28% -60.92%
44 11.53999651 -4.38% -62.63%
45 11.02358743 -4.47% -64.30%
46 10.51933641 -4.57% -65.94%
47 10.02771211 -4.67% -67.53%
48 9.549123056 -4.77% -69.08%
49 9.083918785 -4.87% -70.58%
50 8.63239124 -4.97% -72.05%
Probably the real picture will be much worse because of the increasing political tensions, the shift to faster depleting oil sources (smaller standart deviation) etc. If you can notice the "tension" percentage gets to 5% in the first 10 years; then almost doubles in only 5 years; and then almost doubles again the next 5 years. This speeding of the worsening trend goes up to the standard deviation year +31. I would suggest that years 10-15 will be most critical because of the sharp rise of the pre peak production drop.
Any comments on this will be very much welcomed.
P.S. Is it possible to place an Excel graph here?
initial production. Then the producers tend to invest in expanding production depending on market conditions (which are rather unpredictable). When the field reaches its peak, in most cases it is much more reasonable to maintain a sustained decline than to fight the peak - nobody would pour huge money in a declining field, because the investments are not likely to pay off. For example I am sure that if they drill more wells in West Texas they can temporary rise the production to say 1.2 mln.bbd but then it is inevitable that the production will again slowly slide down (following the logistic curve) and the slide will soon become uncontrollable. That's why they preffer to have a long controllable decline than making unfeasable investments. In short the logistic curve is what we can expect from a field if we target maximum production all the while during its lifetime.
I think that in the short term we will see the West Texas pattern world wide - the first several years will be of significant constant decline rates (3-4%?). But after that the shortages will attract huge investments and in the medium turn the production curve will start to follow closely the logistic curve as producers scramble to boost production by all means.
Of course all of this is too speculative for me to bet on... If the producers start chasing their long-term interest they will probably abandon the "maximum production" goal and even allow temporary free fall of production to preserve it for the future. This is what may cause the real trouble and why we need sufficient energy independance now.
Why again does it follow the logistic curve?
In the past, peak oil projections have used fairly low decline rates for FIP - 3%-6%. There are now several pieces of evidence that the FIP decline rate might be more like 8%. Adding that to Chris Skrebowski's list of new projects makes for a very rough ride:
Most of us thinking about peak oil have been aware for some time that the central uncertainty is the decline rate on fields in production (FIP). This dramatically affects when one believes peak will be, and seems to be the main difference between more pessimistic projections such as Chris Skrebowski's , and CERA's. It's also critically important in assessing the economic impact, since the faster total production declines, the harder it will be for the economy to adjust, and as we go further and further past peak, the fewer new projects there will be to add to the declining bulk of production.
In the past, peak oil
initial production. Then the producers tend to invest in expanding production depending on market conditions (which are rather unpredictable). When the field reaches its peak, in most cases it is much more reasonable to maintain a sustained decline than to fight
I presume similar analysis could be done for BP who have grown their total production and Shell who haven't?
All oil executives are talking down the future oil price in public. Even our local one, Mr Ruttensdorfer from OMV. The reason is simple. They want to be left alone. No windfall tax, no post peak planning, no substitution projects, no hassle with -god beware- forced consumption restriction (driving on alternate days, etc).
Buisness as usual keeps the American dream alive.
It is psychologic: A popular saying in the german wehrmacht 1944 was: Comrades, enjoy war, peace will be terrible.
But actually there is a possibility that he genuinely believes this, as OMV has a very interesting record of offsetting decline. They have very few and small fields but alledgedly manage to squeeze them to the last drop, at least if one can trust an article published in the German magazine "Der Spiegel" not so long ago. (They also raved about new technologies such as a new kind of 3D-seismographic)
"Der Spiegel" also hinted that this record of managing to keep up a plateau could give hope to the rest of the industry. However, what they totally forget in my opinion, is that the OMV-operations can't be compared to the majors neither in scale nor in quality.
So Ruttensdorfer might really think all is rosy, at least if he is dumb enough not to look beyond his own company...
There's something I don't quite understand about your analysis - is 8% a decline rate for a typical individual field after peak, or a typical decline rate for a collective of FIPs past (collective) peak (some of which may individually be at plateau or even pre-peak rather than yet declining)? I guess this is like the distinction between Skebowski's type II and type III depletion.
The Exxon analysis is clearly for a collective of Exxon fields but the 8% figure quoted above from the Schlumberger looked like an attempt to give a typical figure for an individual field.
Even if the individual field depletion rate is high, the collective depletion rate of a groups of FIPs would presumably also depend on the time distribution of production starting in different fields and so might not be as high if not all the individual fields of the collective are declining (I'm just thinking out loud here ...)
The post-peak global decline may well mirror the typical decline rate of individual fields while we still rely on a small number of long-lived big fields for the bulk of our production (and when most of these are in decline). However, in the future when most production comes from small fields (or mopping up projects) with short lifetimes, presumably the global decline rate will increasingly mirror the decline rate in discoveries (with a few years lag). This may give us a longer shallow tail, especially when coupled with the slow ramp-up of LQHCs.
Doesn't help us in the near term though :-|
In the long run, it will probably all look roughly logistic as Hubbert said. But what happens over the next five years will just be a little jog up or down on the Hubbert curve, but might make quite a bit of difference to our experience of it.
As Brazil is making the sugarcane ethanol thecnology disponible to other third world countries it is possible that these countries will not have need to use coal. IMHO almost all South America, all Central America and India can try go for sugracane ethanol. They will produce less grains and sugar for export, but they will need import less oil or coal. So, it is possible that these third world countries be less affected than USA by the Peak Oil. However, some economic effect will be visible.
Sorry my bad english, my native language is portuguese.
Brazil's sugarcane ethanol - better buy now while we not use it all - see you, Germany and Japan want make comercial contracts with Brazil government to buy our ethanol...
What Carlos is saying is easily proven - if you use a source that is high in simple sugars, the ethanol yield should be higher and less energy intensive to extract. Corn never made sense to me in the first place, other than we happened to grow a lot of it in the midwest that we were having trouble selling.
The real energy comes into play when you distill the cane, because standard distilling methods use heated fermentation. However, this isn't necessary - you can do a normal standard fermentation and then do distillation and reduce the energy input quite a bit. And the energy for distillation can be anything that produces heat - corncobs, old tires, anything that will burn.
Traditional thinking and distillation processes accept the energy inputs as "required", yet they do not have to be from oil or gas, and the primary ferment doesn't have to be heated due to the high native sugar content. It's not corn - we aren't converting starches to sugars here. It's just that when a process engineer gets hold of something like this, they always use the same input heat energy (NG) and opt for the highest yield in the shortest time. But even this could be offset by using the leftover cane leaves and waste to make biogas to self-power the distillation, if standard fermentation were used as a first step.
Why worry about the EROEI too much anyway - if gas continues to climb (as most here are sure it will), then there is nothing out there that will substitute into the existing transportation fleet EXCEPT ethanol and biodiesel. Nothing else is transportable and will work in a standard IC engine except these two alternatives. The real issue is using coal or other less expensive means to heat the distillation process, where the energy input is highest in the ethanol process. Using lower cost heat inputs changes everything in the EROEI equation, but requires engineers to step outside their box a bit.
This is the last thing you want on any land - it grows over a foot per day in the summer, has a 20-30' deep tap root which is nearly impossible to kill, and it absolutely grows over everything else.
The "red weed" in War of the Worlds was mild in comparison. State agencies have spent literally millions trying to get rid of this weed. It can pull down electric utility poles and pry shingles from roofs it grows so fast. And it doesn't even make anything useful - just cellulose, which is energy intensive to use at this time. It's also a booger to harvest - wraps around any and everything, and sends down roots wherever it grows over and touches the ground again.
I think cane or sugar beets would be lots easier to deal with...
Goats and Sheep are being used in some areas of the USA to get rid of it after they killed it the year before. The goats and Sheep eating all new sprouts, hoping to kill it! It has not happened yet.
Drive alone almost any southern Rural highway, or back road and you will see it growing!
What is nice, is that Kudzu is edible to humans. Large leaves steamed and used like grape leaves. Last night's stem shoots cut and put in stir fries. Roots used for teas and other things, even some form of bread flour.
But low in sugar content! If it were used to fuel the Fementation process of the SugarCane, Then great! Otherwise Know where you local supply is for the edible parts and try to keep it out of your yard.
It kills everything in its path within several years, even big old oaks, and fast growing pines.
Looking at the various decline percentage graphs for Exxon, we can certainly see that the optimistic 2-4% decline rate is utter nonsense. It's not even close!
What I find particularily funny is the 2001 prediction by Exxon, after several years of flat production they expected production to grow almost exponentially! But I guess you have to be optimistic, otherwise you'd lose your shareholders.
If we are indeed riding the green line in your last graph, then we can say that April 2005 was indeed the peak of oil production (as was suggested in a previous post).
Unfortunately this line does not match any predictions made by any of the commentators (even the really pessimistic ones like ASPO). How can that be? Has everyone underestimated FIP decline rates?
He says a lot of new fields today are exploited using high-tech methods from the beginning. Many oil industry experts assume that means total recovery will be greater. Simmons says that's wrong. You may get the oil out faster, but total recovery will be the same or worse. Which means the backside of the curve will be much steeper for these modern oil fields than they were for the old U.S. ones.
This analysis suggests that Simmons is correct.
What makes this confusing is that there are other rates involved which get mixed up with the pure extraction or depletion rate. Besides extraction rate, you have average construction rates and what I call fallow and maturation rates, which delays the outflow of oil from recently discovered fields.
If you need a mathematical model that you can actually reason about (unlike the logistic curve), I refer you to my oil shock model here:
http://mobjectivist.blogspot.com/2005/10/oil-depletion-model-posts.html
So my model should do prediction better than the logistic. Just like Kirchoff's law does prediction of electrical circuit behavior better than not using Kirchoff's law. Primarily because it is based on stochastic first-order rate behavior, which the logistic curve does not do. The logistic curve does a model of homogeneous discrete-entity dynamics which does not match oil depletion dynamics.
If you were to rephrase the question, does the logistic curve do a better heuristic than a model developed from first principles? Ask the software gaming industry that one.
Again, if you want to argue that the logistic model is no good, the only argument I accept is a quantitative evaluation showing that some other model has lower residuals than the logistic on future data that wasn't used to fit the parameters (for a few different countries where the logistic does ok). If you can come up with such an evaluation, I shall be delighted to accept that you have advanced the state of the art and we can all start using the WebHubble model instead of the logistic model. In the meantime, further words are just methane in the wind.
If the problem is that you aren't familiar with the problem of overfitting, there is a simple explanation here.
In regard to best case scenarios, Texas has seen an average net decline rate of 2.3% per year over the past 33 years. Note that this is net, after very intense drilling. This intensity of drilling, for a number of reasons--such as personnel and equipment shortages--is unlikely to be matched worldwide.
In regard to the cornucopians assertion that "technology will save us," I have started asking what technology can do for fields like the East Texas Field, which once was the largest oil field in the Lower 48. Today, East Texas is producing about 1.2 million bpd of water, with a 1% oil cut. How can technology increase oil production from a field that has watered out? East Texas is to Texas as Ghawar is to Saudi Arabia.
http://www.neb.gc.ca/energy/EnergyReports/EMAGasSTDeliverabilityCanada2005_2007/EMAGasSTDeliverabili tyCanada2005_2007_e.pdf
I think that this is profound for a quasi-government agency. As for the natural gas, what is not clear to me is how much of it is needed to run the oil sands extraction operations in Fort McMurry?
muhandis
Dear Sir,
Your astute response to Stuart's excellent 8% post on theoildrum led me also to more closely read many of the comments which followed. In doing so, I caught you using the superb word "cornucopians," which I believe should be widely used. Were you its most recent recoiner, in this context?
I have added a copy below of a post I made today to Chris Lydon's site BOP, one which features this word, and I always like to give credit where credit is due, especially when I think that this characterization of the pagan Pollyannas as Cornucopians will follow them to the grave.
Sincerely,
John O'Brien
Peak Oil: The Blissful Cliff
the only reason the smart Chinese continue to fund this corrupted administration is that the Chinese "pickle market" bankers are betting on what they see as: we are on the road to driving off the very road, and in the ensuing crash our capital and our control is passing onto them.
We are committing happily collective suicide --as a democracy, a culture and as a business --waving to God, maybe, as we fly over the blissful cliff, power steering engaged. Only Permaculture, sunlight, and getting to know one another pretty quickly may save us.
But it looks a lot llike the smart money's against us.
Down with the Cornucopians!
the cubist
However, there are a number of qualifiers - if these are indeed old reserves, the R/P of 10 is probably high - witness the US experience, where R/P has been growing. Also, they are oil equivalent, so there presumably gas there as well. All in all, I still think we are looking at Exxon decline rates in the 8% range minimum.
I think in general we need to acknowledge there is significant uncertainy in this analysis, just based on the fluctuations year to year in the apparent decline rate. We are probably at something like 9+-3 for Exxon.
My company (Anonymous Oil International) has a decline rate exceeding 15% because we push to maximize production. We do this because offshore operating costs are high, and by getting it out as fast as possible, we reduce the operating overhead over time quite a bit. Many offshore operations do the same thing, and it is likely to become the norm as lifting and finding costs are rising to stratospheric heights. Thunderhorse is a prime example of this, where the injection wells are actually in place before first oil. But as much as that monster cost them, the only way to get your money back and then make more is to move the whole thing to the next big project...
When you leave for the next field - how easy is it for a small company to come in after you to try and mop up the dregs?
How many fields are being produced in a similar manner to deep sea? I believe Dave has mentioned already that there are two opposite models running on peak and depletion - West Texas vs North sea.
It has appeared to me reading TOD posts over the last 6 months that most production of the last 20 years and going forward is like Thunder Horse. Fields are mapped, brought online with strategic well locations and pressures are maintained right from the start with CO2 or water.
Won't this force a Hubbert's peak that would be (relatively) wide and flat to be more of a spike. That is, narrow in time, but high with respect to maximum production in bpd. Won't this extraction technique make small fields look larger, at least short term? In aggregate won't this result in short term higher production that will be harder to maintain over time, due to shorter life span of fields? And won't this give everyone false data on field size (if my assumptions are true) when stating reserves? I want to understand the effect of these different approaches on peak production of fields.
Wait a second. I'm not a bright guy or an oil industry insider, but doesn't that imply that the foundation of the oil industry depends on the kind of growth dependent economics that is so frequently viewed negatively at this site?
If a large fraction of producers are depending on new fields ("the next big thing") to recover the costs of their current infrastructure investments, what happens to those company's ability to continue operating when ROI drops to the point they are operating at a loss? To stay profitable and in business, wouldn't you have to get the oil out faster and faster by increasing production rates as GeoPoet's company is doing? What happens at the tipping point when companies can no longer:
- Increase production by expanding the number of production fields year to year, either by exploration and develpment or mergers and aquisitions.
- Reduce production costs by making improvements to recovery rate.
- Cover the cost of bringing new assets on line with their current financial resources.
- Grow their bottom line to maintain the confidence of their investors.
Forget geology for a minute. What's going to happen to the economics of the industry when it can no longer maintain existing profit margins? Clearly the majors aren't at that point, but how much production is in the hands of more economically vulnerable companies? How long post-peak will the smaller producers be able to stay in business? Aren't most of the ones that haven't been bought out doing the kind of production the majors won't touch?Someone, please, point out why this shouldn't keep me up at night. Give me some numbers to show how little impact production loss due to small company failure is going to have. :-(
No, we cannot reasonably expect to grow exponentially as the reserve prospects dwindle. There will be further consolidation in the independent oilfield - no way to avoid that. People will cash out as well if they cannot find decent prospects. It wouldn't surprise me to see half the independent oil companies here in the US gone in 10-20 years, as their resources deplete and they cannot afford to buy into the international market. They will have to sell out or sit and watch their reserves dwindle unless new domestic areas get opened up, and even then the bidding may be fierce.
It will be interesting...
I haven't heard anything about Thunderhorse since BP said it had suffered, during Katrina, 10% damage. That would be about $100 million.
Could you tell me where it is being repaired and how long it will take to repair?
Thanx,
James
Great post, thank you.
I suspect I am stating the obvious for many posters at TOD. BUT, it is a lot harder to maintain production from a base of 80 mbd when decline rate is 8% as opposed to say 50 mbd. Bringing new fields (mostly small) online just doesn't have the impact that it did before.
It appears that many non believers (unconvinced?) about the peak are underestimating the effect of percent declines on large numbers. The decline rate may be the same as 25 years ago but the base is so much larger now. You need ever larger amounts coming online at the very time it is harder to find larger fields.
What helps you in the financial markets with compounding interest is hurting us now in maintaining production. Just a fixed rate on an ever increasing base equals a larger absolute mbd that you have to come up with.
It has always bothered me that people are constantly substituting % declines (or % new production) with actual predicted barrels pumped. This is very confusing unless you parse the number as you have done. It seems that there might be a tendancy for people to say "our decline is only X% and we have been coping with this for decades so it is not a problem".
Thoughts on this Stuart? Again great post.
One of the possibilities raised by Stuart is the following:
"Andrew Gould is smoking dope, Exxon, Iran, and Saudi Arabia [with decline rates of 8-10%] are an anomalously bad piece of the production mix, and the average decline rate is really much lower."
And then, WestTexas notes the following very interesting fact:
"In regard to best case scenarios, Texas has seen an average net decline rate of 2.3% per year over the past 33 years. Note that this is net, after very intense drilling. This intensity of drilling, for a number of reasons--such as personnel and equipment shortages--is unlikely to be matched worldwide."
So what exactly is the anomaly in this picture? Is it Texas, or the others? According to WestTexas, the low historic decline rate in Texas has to do with the exceptional intensity of drilling and availability of expertise and equipment in Texas. This suggests, however, that stemming the decline in the places mentioned by Stuart is also simply a matter of sufficient investment in infrastructure and expertise.
Is there any reason to believe that the places with much higher declines cited by Stuart might shortly see the level of expertise and investment that has been brought to bear in Texas for 35 years now, thus reducing their decline rates to 2-3%? And if not, why not? And can these factors that make the situation in places cited by Stuart different from Texas be adequately addressed if we scramble frantically enough over the next couple of years?
However, for those of us in the energy industry the future couldn't be brighter--provided that the angry, and perhaps hungry and cold, soccer moms are not rioting at the gates of the mansions of the energy producers. It will be interesting to see if relatively free markets in energy survive very long in a post-peak oil world. With just a taste of the higher energy prices to come, Congress is already deep into delusional thinking.
In Texas I was under the impression that secondary methods such as water injection etc.. were only introduced later in the cycle and as such will themselves have reduced the decline rates. Wereas in areas like Saudi and off shore they have been applied almost from first oil thus having the opposite effect of extending the hight of the curve but at the same time making the decline much steeper...
Now my question to you is this - knowing that all this investment will just barely let you manage to run in place rather than really grow significantly, would you invest your money in that operation?
This comes back to the fundamental question of why both the IOCs and the NOCs have not been interested in investing over the last 20 years. Part of that may have been due to price but we've now got 3+ years straight of higher oil prices with no end in sight and they still are not rushing to make massive investments. As someone else pointed out, Exxon is investing exactly what they did previously, $18 billion, which at higher prices for rigs, cement, people, etc., means less actual new production.
Follow the money and it says the same thing - investing heavily further in oil is not smart (right now).
But no one is spending money at the slot machines either!
Technology will save us!!
So where is the big bucks going into the "NEW HIGH TECH" replacement for all that oil we aren't going to be investing in?
Sugarcane is not going to Fuel the 8% production decline, not even if it were 2% production decline, where the numbers would be only 613 million barrels a year gone missing. ( 84 mbpd times 2%, times 365 ( sugarcane even at 2 crops per year in tropical climates ))
If we were to go the route of Virgin's founder and make all plant waste usable as an ethanol maker would we still make up the differance of the small 2% decline rate of 613 million barrels??
Hey what if the decline rate is 4% , or 8% well gee, I don't think anyone is going to at all happy with those bigger numbers.
So When is year Zero ( 0 )? I guess we have to ask that!!
If year Zero is 2010 we have a few years to get our act together. But what if year Zero was this year, or last year? Or next year? What do we do then?
Please someone help me here! I need to know where to invest my fortunes!
And given the green line in Stuart's last graph, there's no way we're going any higher from now on.
Time to kiss our lifestyles goodbye!
I drive 2 times a week at most. I keep my NG fired heater set at 50 degrees, the lowest setting on the device. I know where everything in my yard that is edible is, and what time of year I can get a meal from it. I know that just within walking distance I could myself survive on the plants in the area. I can survive off less than 300 dollars a month and keep this life style. Or go further down and still survive on ZERO dollars a month.
But few if any of those that I know in this area can do the same.
Toss in New York City and you might see how many folks that can live close to the bone. Likely those on the streets already will never see the change! Only those that have roofs or power now will suffer.
Per the Texas railroad commission at http://www.rrc.state.tx.us/divisions/og/information-data/stats/ogisopwc.html
Texas production in 1973: 1,257,057 Mbbl
Texas production in 2004: 349,233 Mbbl
Decline rate = ln(349,233/1,257,057)/31 years
= 4.1%/year
This should be the absolute upper bound on decline rates used - no economic restrictions on production, as many wells as needed, every economic incentive to produce.
I think you need to factor this in as something that is inevitable. In countries with a national oil company, their operating overhead is tremendous. Where we use a single engineer, they use from 3 to 20 to do the same thing. Each has a secretary and/or underlings. It is a means for the government to employ their people.
This large operating overhead is a defacto limiter with respect to actual field economics. The Pertaminas and CNOCs simply cannot make money the way we do here in the US with our smaller independents. Even today, one of the reasons CNOC and others entertain and contract with larger independents is to defray costs and still get the lions share of reserves. A smaller company can get in and do the work faster and cheaper than the national oil companies can. The risk is also spread better.
But in places like Mexico, where Pemex will not allow outside operators in, they will simply cho9ke on small field economics. They will be forced to operate at a loss or else throw in the towel and walk away, even if there is oil there. The only thing that will change this is a huge price jump in oil. So, what would you imagine the future holds??
The 2.3% decline rate I used is a simplistic average decline rate, not the mathematically more accurate 4.1% decline rate. However, shouldn't this be the absolute lower bound on (net) decline rates used (and not upper bound?).
It is pretty interesting to go back and look at the 10 years after 1972 (the year Texas peaked). Over the following 10 years, the number of producing wells increased by 14%, as a result of the biggest drilling boom in state history, but production fell by almost 30%. If the world peaks this year and if the world follows the Texas model, crude oil + condensate production would fall from 74 million bpd this year to about 53 million bpd 10 years from now.
Given the fact that three of the four fields now producing one million bpd or more have peaked, or will shortly peak (four out of four if we count Ghawar), a 53 million bpd estimate for 10 years from now may be optimistic. It all depends on how fast the non-conventional stuff can be brought on line.
I keep trying to get my head wrapped around what's going to happen as we go forward here over the next few years, and the answer simply just isn't converging. What I know for certain is that there are some real issues with depletion rates that are going to bit progressively harder as we go forward. The situation in the North Sea is just the leading edge of a depletion wave that will hit at some point - the majors are bringing these big projects deepwater projects online, and the more I examine them the more I'm convinced that they are running them as hard as they can to keep their production rates propped up (and recover the cost of capital). When the day of reckoning comes, we could be looking at a situation where we have 15 million bbl/d of deepwater oil production depleting at 15% per year, without substantial new projects coming online to mitigate. Coupled with OPEC/FSU stagnation/declines, that would be a catastrophe.
Typo, or did miss something?
PEMEX just came out with Oct 2005 numbers.
Total liquids production for the first 10 months down 2.3% from first 10 mos 2004. The coming Mexican decline has profound implications for U.S., since they are our 2nd highest source of imported oil.
Please don't confuse "depletion" with "decline". I've had to correct many people about this. A 5% depletion rate means that you extract 5% of the ultimately recoverable oil out of a field in one year. A 5% decline rate means that production falls by 5%. Depletion leads to decline, but depletion happens from day one. In a way, they aren't really related terms since as decline rates rise, the depletion rate falls. Don't mix up the terms!
Doing this right, you can add the discovery curves continuously and thus get a handle of the depletion rates without getting all worked up over the decline rates.
January - 3,790
February - 3,784
March - 3,668
April - 3,855
May - 3,882
June - 3,873
July (the month when Emily hit) - 3,481
August - 3,842
September - 3,783
October - 3,628
http://www.simmonsco-intl.com/research.aspx?Type=msspeeches
About one third of the way down it looks like a new data point (oil field) arrives in 2004 for which there is no line, and all numbers from that point down are pushed down by one line.
The charts on 14, 15, and 16 are wrong too, accounting for some increases in 2004.
Funny that he did not check it before. And I suspect that most of the viewers were "already converted" and knew the message, even if the charts did not accurately depict it.
Caspian Sea Total = 2.44/mbd, includes
- AGC Megastructure 1.0/mbd
- Kashagan 1.0/mbd
- Tengiz expansion .44/mbd
All other projects amount to 2.51/mbd including .25/mbd from Thunderhorse.From my current research, the AGC and partly Kashagan (via the new Aktau-Baku pipeline) depend on the Baku-Tbilisi-Ceyhan (ends in Turkey - BTC) pipeline which was supposed to come online this year but is now delayed sometime into next year 2006. Tengiz expansion uses the Caspian pipeline to Novorossiisk (Russia, Black Sea). For many reasons, Kashagan (CERA/Skrebowsky 2008) is a challenging project to say the least. For all three projects, for example, based on Lutz Kleveman's The New Great Game, I can think of roughly about 10 interest groups in the Caspian area that would like to blow up these pipelines. But there are many other problems, especially with Kashagan.
So, roughly half of ExxonMobil's new future production comes from the Caspian. I expect the downward trend as shown in the Exxon Production graph for 2005 to continue. Given their apparent FIP declines and almost certain further delays in Caspian production, new production will not offset their declines any time soon.
I wonder what a similar analysis for Beyond Petroleum would yield. They seem to be doing much better than ExxonMobil in terms of new E&P. However, these downward trends have not cut into ExxonMobil profits ;)
I agree that Stuart has the kernel of a book here; one that would fit well with Simmons and Deffeyes, et al.
With respect to the peak occurring when 50% of the resource base is consumed, that is a result of a fairly simple model that doesn't necessarily reflect real world effects of technological improvements in extraction technology and national politics. PFC Energy analyzed the production curves of non-OPEC countries that are in currently in decline and noted that the average depletion level which corresponds to the onset of decline is 54%. There's no guarantee that the 54% observation will continue to hold but I almost always prefer experimental evidence over theoretical results. Thus I wouldn't be shocked to see the peak slightly after 50% of Qt.
Given Stuart's post here and worrisome news out of the Middle East (Kuwait, Saudi Arabia) lately, this reminds me of Roscoe Bartlett using the Apollo 13 mission as an analogy to the current situation in his ASPO-USA presentation. Unfortunately, with Michael Lynch, CERA, USGS, EIA and IEA presenting contrary versions of reality, it is not as straightforward as simply calling up NASA and saying "Houston, we've got a problem". And as Stuart's post makes clear, the always enlightening ExxonMobil CEO Lee Raymond is not making our life any easier at this point either despite his company's weak performance.
So, I expect that new supply will plateau in the next few years and each year that happens, we will be told that new capacity is right around the corner, so hold tight. And since homo sapiens really doesn't like hearing bad news, that's just what people will do, they will wait for the miracle that never seems to come. Then, at some point in the future a few years further out (between 2009 and 2013?), the consensus will come that "hey!, world oil production has peaked, we're screwed!"
Personally, I am getting more and more pessimistic with each day's new revelations and Stuart's concluding point 3. "Life is about to get less fun, pretty quickly" should be taken very, very seriously since his points 1. (Skrebowski has missed some projects) and point 2. (Gould is a pot-head) are not credible.
And they will all want to drive cars and live The American Dream ...
Leonard Cohen agrees:
Trying to collect some of the thoughts...
The idea that higher production means higher decline, which must be balanced with ever higher new production, might be a new (and sobering) thought to many.
The second thought is that OPEC, certainly Ghawar, has been combining secondary with primary production, which extends max production but leads to very high decline rates when the field peaks.
The third thought is that all four giants are, or are about to, enter terminal decline.
Combining these thoughts is a little scary.
It would be interesting to know the background of the various major oil ceo's. Those with a geology background may be well aware of the situation. However, those with an economics background might actually believe that oil will fall (it always has), and therefore it makes little sense to invest capital to find more when costs are high. Of course, even if an executive thinks oil will stay high, the potenital damage to profits and share prices from lower prices makes stock options, and the buybacks to remove the new shares from the market, easy to justify. Many E&P ceo's, and the banks that loan to the E&P's, keenly remember the bankruptcies during the late nineties when oil fell to $10, leading them to hedge their future production. What seems obvious to peak oilers is not necessarily obvious to those diligently working in the industry.
Having participated in the Indian transporation system lately, Stuart, I'm sure you can appreciate that India's oil consumption efficiency would be vastly improved if they'd drop their massive gas taxes and protectionist auto-import laws so the populace could spend their transportation budget on new, fuel-efficient (and less polluting) cars, rather than being forced to drive the 30-year-old two-stroke lawnmowers they have today. ;-)
You have been posting on here for some time now as an editor. Without going back through all your posts, this one seems to be a step toward the dark side in the Peak Oil conversation here. Am I correct? You seem more pessimistic than a few months ago.
I agree with the "book" comments. The escalator image could be the central organizing concept: "Up the Down Escalator: The More We Drill the Less There Is"
1. How much did Skrebowski miss in his analysis? Neither you nor Skrebowski has quantified it. For example, Skrebowski writes: "It is not at all clear if the world's oil companies can provide an incremental 3mnplus b/d from all the small, untabulated projects and infill drilling going forward year after year." This can't really be counted as bona fide proof that oil companies cannot provide such an increment. It's just a hand wave, and you've got to somehow nail this down to make your calculation convincing.
Small fields are a big factor. Look at the pyramid (P. 5) in this pdf from Simmons:
http://hubbert.mines.edu/news/Simmons_02-1.pdf
53% of world oil production comes from fields smaller than Skrebowski's 100,000mbd cut-off for a megaproject.
Here's the critical question: of all the new oil coming on-stream in a given year, what is the percentage of mega vs. non-mega projects. This should be easy to calculate by subtracting new megaproject flows from the total projection increase for a given year. This might be where your Exxon data is given you a bum steer. Exxon doesn't do small projects.
2. I don't have the exact figures, but the word is that the U.S. has had a dearth of megaprojects for some time. So the megaproject method would predict that the U.S. should be declining at close to 8%/year, but it's not. The average percentage decline for the U.S. since 1971 has been about 1.6%. For 2000-2004, the figures are:
2000: 1%
2001: 0.3%
2002: 0.9%
2003: 1.1%
2004: 4.4%
The figures are nowhere near 8%. Has the U.S. had a lot of megaprojects? This would seem to be a variant of the phenomenon above.
3. The method also leaves out unconventional oils like ethanol. Even today, ethanol is in the megaproject class:
World production of ethanol in 2004 was 10.77 billion gallons (=40.8 billion liters), which comes out to roughly 700,000 barrels/day. The heat content of ethanol is 3.5MMbtu/barrel, so energy production from ethanol is 2,450,000 MMbtus/day. Gasoline, on the other hand, has a heat content of 5.3MMbtu/barrel, and thus ethanol production is equivalent to gasoline production of about 460,000barrels/day.
On the average there are 19.5 gallons of gasoline in a barrel of crude oil, so ethanol is providing the gasoline equivalent of 1 million barrels/day of conventionally refined crude oil. For comparison, Indonesia produced 1.2mbd of crude oil in 2003. Ethanol is as big a factor in the world gasoline market as Indonesia.
Sources for this calculation are here.
Ethanol is classified as oil by the EIA, and is growing at about 9% per year. Also, it does not deplete at all.
GTL is a similar factor which is not being accounted for.
4. A figure which confuses me is Skrebowski's 1.1mbd for Type III depletion. Why is that so low? I would like to see that 1.1mbd expressed as a percentage of total production from post-peak countries. I don't know what that percentage is, but it would seem to be a good indicator of the total production decline rate when most/all countries enter Type III depletion. If it turns out be high (like your 8%), that would support your view.
5. Your model makes a specific prediction for production next year (80mbd), so I look forward to seeing you explain the glitch if oil production increases. ;-)
If it reached that value at one time historically, there is no reason it couldn't hit that point again.
http://mobjectivist.blogspot.com/2005/10/shock-model-applied-to-usa-lower-48.html
http://mobjectivist.blogspot.com/2005/10/shock-model-with-aspo-discovery-data.html
The oil shock model is nice because it uses these extraction rates directly to fit the production curves.
http://mobjectivist.blogspot.com/2005/10/oil-depletion-model-posts.html
I think that there's alot of confusion out there between extraction rate, depletion, and decline of flows. To paraphrase your model, by increasing the extraction rate, we can temporarily increase production, but the resultant drain in reserves will come back to haunt us with steeper declines later on. Therefore, taking Texas as an example, we might expect to see a slower production decline in response to high prices now, as a result of an increased extraction rate, with the penalty paid in a steeper decline later on due to a reduced reserve base. My impression is that this is not intuitive to most people - the assumption is that the decline rate slows if the production decrease slows, whereas in reality, all that is happening is that oil is being pulled harder from the reservoir, robbing Peter in the future to pay Paul now so to speak.
Getting back to the deepwater wells, the nice thing is that they are pretty straightforward to interpret - they are produced full out from day 1 and the production rate is always maximized. Therefore, there is no hiding the exponential nature and high depletion rates behind varying extraction rates. In your model, the resource additions can be treated as delta functions, i.e., basically negligible ramp up, completely unmasking the decline rate to reveal the "true" larger extraction rate.
God forbid we should ever see an 8% decline rate in reality for a basin like the US - that would indicate that reserve addition/discovery has totally ended. Of course, this is pretty much what's going on in the North Sea right now, and the economists have had to bite their arms off trying to explain it, as it is so unlike the US situation.
http://mobjectivist.blogspot.com/2005/10/uk-north-sea-simulation.html
I have heard of "rolling up your sleeves" but "bite their arms off"? That's an interesting visual.
- Even if "small" fields (less than 100/kbd) account for 53% of world production (as of 2002), who cares because...
- Declines from the big FIPs (36% from fields producing in excess of 200/kbd), if they are actually in the 8% range, will just move fields "up" the pyramid, thus widening the pyramid at the top and and narrowing it at the bottom, which means...
- Smaller fields are producing more as a total % but altogether we have less because those smaller fields, unless they are new start-ups that will become big fields, are not going to produce anymore than they already do--they will produce less because they are in secondary or tertiary recovery.
I myself do not see this as a happy trend. Indeed, the more distributed the production is over smaller fields (FIP or new) all over the world, the less secure and more expensive it is to bring that oil to market as a function of price. Unless prices remain high or rise, smaller FIP and new or prospective small fields can fall out of or never go into production because it is not economical to produce the oil given the overhead. So, it is the end of cheap oil anyway you look at it.It is always important to remember that we are not running out of oil, we are running out of cheap oil. 'Nuff said.
I think we are mixing up statistics. You are calculating average percentage decline for the US of 1.6% from 1971 until now. However, WHT is calculating an average of about 6% for the lower 48. I don't think you guys are looking at the same data.
My guess is that you are looking at total US liquids production. This would include oil from Alaska (as Prudhoe bay came on production in the late '70's?) as well as deep water production (which started in the '80's) and a considerable volume of natural gas liquids, that have become an increasing percentage of the liquids production in the US.
Also when we talk about the underlying decline for the whole world, we are really talking about production trend that sits below all of the projects on either CERA's or Chris Skrebowski's list of megaprojects. We all presume this is in decline, although no one has really demonstrated it or its magnitude yet. It includes the production of all the fields that are on decline, all of the new projects that are too small to be on these mega-project lists, and any other sources of liquids that show up in the 84 mmbo of daily production that we are trying to predict the trend of (NGLs, GTLs, biofuels?, etc.). The trend of this gross production stream is not the same as the average of multiple fields in decline.
It may be possible to get a handle on this underlying trend by looking at non-OPEC production over the past 5 years and subtracting out the mega-projects that have been brought on over that period. Because of the past spare capacity in some of the OPEC countries (Saudi especially) we can't do the same thing for the whole world.
But I think the other factors you mention also have the same modulating effects. Plus the latencies of bringing things on-line, and if these get included in the average rate even though production has not really started. Oh, those nutty oil companies and their accountants :-)
That's right. And Stuart's post here, good as it is, does not demonstrate it either. But there are signs and portents. Greater Burgan, Ghawar concerns, Cantarell, China's internal production, Iran, the North Sea, stalled Russian increases, obviously Iraq. This is the whole declines issue. Stuart's post today does not resolve the question, it just raises more alarms--these concerns are reasonable on the available evidence, however.
I would suggest, at least over the few years or so, that we pay special attention to new reservoirs like West Africa deepwater (Gulf of Guinea), as we have both posted on, or the Caspian Sea region (AGC megastructure, Tengiz, Kashagan) or Brazil deepwater. These are the only places in the world where significant new production will be coming online in the next 5 years outside any new Middle East production we may see--or not. Other prospective areas represent much smaller potential new capacity. Decline rates do represent the major problem but the definitive data is just not there. No transparency and too much speculation, though the trends look bad.
2000 to 2001 0.7
2001 to 2002 1.0
2002 to 2003 1.1
2003 to 2004 1.1
2004 to 2005 0.3 (8 months data)
Generally we are seeing a growth of slightly under 1 million barrels/day, slowing this year partially due to hurricanes
We know most of this has come from the FSU (now slowing), some from Mexico till this year. I don't have an account of worldwide projects during this period, but I am sure they have totaled far more than 1 million barrels/day worth. By itself, Exxon had new projects that averaged around 300,000 barrels annual production over that period. The FIP must be declining. I hope someone can do all the accounting you are wanting - it would be interesting. I don't have time.
I do think you have valuable comments, however.
Out of time, will be back.
Regarding gasoline from ethanol, we are not yet discussing "Peak Energy" but "Peak Oil" - over time there will undoubtedly be increased biomass and coal-to-liquid production to meet liquid fuel demand not met from oil. Ethanol (from corn, sugarcane or switchgrass) should not be added to the supply calculations to define Peak Oil. There is 'total energy supply' and 'total crude oil supply' - it is conceivable that in the years closest to the Peak, we could see an slight increase in the former even with a decrease in the latter.
WWW.thebiomassdrum.com
Okay so I am kidding too, by then the internet is a no brainer local project only idea.
I recall from A Short History of Progress that one of the causes of cultural decline was soil exhaustion. Without NG or other fertilizer, wouldn't the soils in which you grow crops for ethanol, food, etc., eventually deplete?
Big-Ag is inherently tied to ADM, DOW and every other chemical manufacturer. Once on that tit, they cannot step off easily. Government subsidies, whether intentionally or not, force farmers into double damned decisions - they are screwed either way, so which is less painful? Cheap chinese and south american products from NAFTA, CAFTA and every other bad trade agreement also hammer farmers. I can buy chinese asparagus for $.50 a can, but US stuff is $1 more - cheap oil and open trading borders have screwed the economics up. It will take much higher oil prices and a return to trading sanity before farmers can make a decent living without ADM or other intensely chemical support.
That being said, realize that if you limit yields by to much, you limit the Whole Food chain for everyone!
Peak Oil might not only mean you can't drive to work, It might mean you can't eat today either.
Ever try to go back to row boat and sail boat fishing fleets!! Think about that too!!
Peak OIl also means in large part Peak FOOD production.
Future production = New megaprojects - Depletion + Current production
Type I depletion (by definition) can be offset in the same field through infill drilling and EOR, and thus does not require any new discovery or new megaproject to compensate for it.
It seems to me that the only relevant figure is Type III depletion, because Types I and II (by definition) can be offset.
We would only be affected by the total 8% (I+II+III) figure if all infill drilling, EOR and new projects came to a complete halt in the post-peak period (i.e. if all offsetting was impossible).
Type I depletion, by definition, is the depletion of wells in a field, when that depletion is being offset by expanded production (EOR, infill drilling) within that same field. To an observer outside the field, it's not really depletion at all, because it is being compensated. If a field only has Type I depletion, its production is not dropping. So you don't need a new project somewhere to compensate for Type I depletion. It's already being compensated within the field. If you use a new project to compensate for Type I depletion, then you are compensating for it twice. Once with infilling drilling (because it is Type I), and once with the new project.
Suppose we stop infill drilling, EOR and new projects. We just maintain the infrastructure we've got and pump it down. That depletion rate is the total depletion rate of FIP. You can't deplete more than that without actively sabotaging the infrastructure. The figure must equal Type I+II+III because it includes the depletion of every existing oil well in the world. It should be possible to estimate by multiplying the average decline of a single well times the number of wells in the world.
So does this mean that the actual rate of decline is even higher than the 8% reported since the infill drilling and EOR should be mitigating that decline rate somewhat?
Also, as I understand the term, Stuart is not discussing depletion rate directly as depletion simply refers to how much oil is being removed from the field in a given time period. If I pump 2.5 mbpd then I am depleting the field by 2.5 mbpd. That is not rate of decline, which is the difference in outputs in one time period versus a prior time period when outputs were higher.
The gents here at TOD tend to harp on the difference between depletion and decline and as I understand it, they are not the same thing. In this assessment, Stuart appears to mainly be discussing rate of decline.
If someone cares to clarify my understanding (or misunderstanding), I'd appreciate it. Or, if I am understanding Stuart correctly, that would be good to know as well.
- Texas and the US lower 48. I know this is the classic Hubbert prediction and historical data trend (Texas) but a case can be made that Hubbert's model does not generalize to the whole world. Also, show me in some detail (geology) that Texas really does reflect the realities of other mature (Middle East) oil fields.
- The North Sea UK/Norway. This has always been an offshore production, it has been produced hard historically, these kind of offshore operations deplete quickly and the way it was produced does not necessarily reflect how production will go elsewhere. Show me that other offshore operations will go the same way (deeper water or not).
I am throwing a monkey wrench into the works here, sort of playing devil's advocate. Tell me how Texas and the North Sea are exemplary of our world-wide production problems.I am trying to learn something.
In regard to the Texas giant, East Texas, versus the Saudi giant, Ghawar, East Texas is a sandstone reservoir, while Ghawar is a carbonate reservoir; however, I understand that Ghawar is substantially a carbonate grainstone, which is more or less the carbonate equivalent of a sandstone. Both fields have high porosity and high permeability pay zones with active water drives, but of course the Ghawar Field has much thicker pay section. The common connection is that once the water hits the producing wells--whether they are vertical or horizontal--it's over. Technology can't do anything to revive a field that has watered out. The final East Texas peak corresponded precisely with the overall Texas peak. The East Texas Field today is producing 1.2 million bpd of water, with a 1% oil cut.
In regard to the North Sea P/Q versus Q plot, the Y axis (P/Q) intercept (at 0.14) is much greater than the Lower 48 intercept (0.062) and the Texas intercept (0.06), but all three regions--regardless of their decline rates--peaked at around 50% of Qt (total estimated cumulative production). The North Sea peaked at 52%; the Lower 48 at 48% (makes sense) and Texas at 54%.
I think that Texas (the swing producer) is to the Lower 48 as Saudi Arabia (the swing producer) is to the world. The Saudis are at 55% of Qt. The world is at 50%.
Jeffrey Brown
This wide variety of geoligic rock types, reservoirs and conditions would confound most explorationists in other countries. Usually they have one or two key geologic features to deal with. But if we take the big East Texas play everyone is familiar with, it is basically a sandstone/limestone pl;ay - just like Saudi Arabia.
One key difference is that no single company owned this big play - even today, many operators "do their own thing" within their own piece of this huge field. The result has been that many areas are dead from over production, waterfloods have killed wells prematurely, and all kinds of other nastiness. offsetting this, we have always had the best technology and resources domestically to deal with all of this. And small companies as well to keep on poking holes in their own little pieces to draw out the last dregs.
ARAMCO, doesn't have this going on - they have a central committee and planning, but remember that this means the associated overhead too. Yet the reservoir types are similar except in terms of permeability - theirs is even better than ours was, and they can draw more oil out faster.
IMHO, ARAMCO depletion will be more rapid because their planning was central, their perm higher, and their technology applied MUCH newer.
Offshore, the North Sea and the GOM are similar in terms of development histories - technology from each has migrated to the other. Both were basically developed during the last quarter of the 20th century. Their reservoirs have roughly similar characteristics at the rock level, but in the GOM, the Mississippi river deltaic sediments make the trapping mechanisms more problematic (smaller) and difficult to locate. In the UK, they do not have the depositional influence of a river as large as the Mississippi, which is the predominant feature of the GOM. Thus the North Sea deposits tended to be more massive and easier to find. Yet their seas and weather make the production harder.
I would venture to say that North sea depletion would be a bit more rapid than GOM simply because their fields tend to be larger and better defined. However, we have poked 3 times as many holes in the GOM, and we have pushed production limits more because we can field smaller projects here with our calmer weather. So IMHO, comparing the two is reasonable, primarily because of the application of identical technologies, in spite of the geologic differences.
How about looking at mega projects in the past, say since 2000, for non-OPEC and non-FSU (to avoid confounding from shut-in and/or politically affected production changes), and then comparing this with actual production changes for the affected regions? The result should be the combined effect of new/increased production from smaller fields and the decline rate from all fields. This small field/all field decline rate info could then be added to currently planned mega projects in these regions going forward.
A second interesting point, if data is available, would be to see what the average delay of mega projects was in the past, from initial announcement to actual first production. This would be a conservative look at future delays because there was less shortage of infrastructure, particularly rigs, in the 2000-2005 period than we expect over the next several years.
And, Saudi poached five deepwater rigs from the gom to look for gas in their own gulf, so the trend may be world wide.
(a) reserves
(b) depleion
(c) cost of replacement ?