Mike,

I would like to add one more question to the ones I asked on the last page (which I hope you'll answer)

Have you thought about whether the advance in technology make any difference to the number of wells you need to drill to deplete oil reserves? I.e. you need to drill fewer wells now to get all the oil out of the ground?

In order to take some effective action, I think you should rely on something a little more substantive than 'things run out, so oil must be doing so soon.'
Mike Lynch
PS Many accuse the 'neo-cons' of promoting arguments like Matt Simmons, so I'm not sure why you say my arguments are right-wing.

The difference is that Campbell and others look at continuous technological innovation and assume it will disappear, they look at continued discovery of oil and assume it will stop, they look at rising production and assume it will reverse.

If you say that the industry has a certain discovery rate over time, why then expect it to drop to zero? Otherwise, you are assuming the existence of oil that you haven't found yet.
Mike Lynch

Yes, I do, but it's a much more valid question than that of a global peak. I gave a talk this spring looking at it, and argued that non-OPEC 'paused' after the 1998 price collapse, and should (should, not choice of verb) resume growth soon. If it doesn't, that's highly suggestive.
I was just in Brazil and they are very optimistic, but they're an unusual case.
Mike Lynch

Well i think that ASPO would claim its about comparative rates but YES thats my point a well i guess you both need to estimate how much oil in place there is..

discovery rates MUST be limited by how much oil in the ground there really is even if no one knows what that value is..even if its a contradictory rate..

for instance if the areas left to look shrink with exploration elsewhere a set industry volume of exploration assets (or increases in) may concentrate in remaining viable areas and push rates up! why because you get increasing returns dispute the fact the amount left to be discovered globally diminishes


this set asset concentration phenomena is perhaps more common than we think across a wide variety of disciplines and studies? it is a intuitive one but it extends to studies of field by field recovery data due to enhanced recovery

remember my position here is a comparative one between you and mainstream PO theorists such as ASPO/campbell

everyone is assuming a value for undiscovered oil in a best guess sense..

your value may be better than ASPOs ?

the nature of the problem is predicting the range of effects you would see... we might not see what we expect as we approach peak

i was struck by the amazing volatility in production of whale oil around "peak" again perhaps resulting from the concentrating of fleets onto remain schools to fully harvest them despite there being fewer and fewer schools... the graph is on these forum somewhere IIRC.

One of my concerns is we are getting locked into strict positions on what we will see or predict and in turn reputations and egos are getting locked into the positions as well...

we could face a situation where your predictions on production growth are more accurate and deflate the ASPO position and in turn again delay forward planning be it market lead or not dispute ASPO having made some profound points about leaving the fossil fuel age behind which you have already stated must happen sometime?

what is the nature of this argument we(the whole global peak oil thing) are in and how measured is it

Boris
London

Then explain how Hubbert got it so right for the lower-48?

Saying he got lucky does not count.

Why have large discoveries clearly peaked?

Calling on the moon does not count.

http://www.bobpark.org/

Can anyone answer to me how the average recovery rate is calculated in rough lines?

And i also wonder how reserve growth relates to recovery rate increases?

The recovery factor is dependent on the following main factors

1) Continuity of the pore structure ( think tiny beer cans connect to each other but for natures beauty some of the cans are NOT connected or with few connections) which will effect if the oil has a CHANCE to get to the well

2) Permeability - think resistance to flow. There may be a connection but it is tight for the beer to flow through. Thus you will not empty cans that are connect through such connections

3) Capillary Pressure - this is a force which is related to surface tension and wetability. It is a force which traps ( you need to exert work/pressure drop to move it out ) a phase in the pore structure. It is related to rock type, grain sorting ( all of same size, mixed, more of one less of the other) etc. So a particular reservoir sand ( again do not forget that nature does not stay constant and varies everywhere ) will have a particular capillary pressure profile for DIFFERENT saturations of the fluid. Different implies as you produce the fluids from the reservoir the saturation of the oil/water will change. We could also stick gas in here but lets try to keep it simple.

4) Saturation of the fluids in the pore space ( % of oil and water) -Here it would be better if we had a diagram to explain the fact that a droplet of oil WILL NOT flow through a pore throat unless it has a sufficiently high saturation. If it has a low saturation only the water will be able to move past such a pore. Thus there is a minimum saturation below which oil does not move. This get a little bit more complicated when we produce and then inject water and then reverse this process, but lets leave this alone.

5) Interference between phases - When oil and water are in contact they interfere with each others movement.

6) Relative Permeability- Taking the above concepts (3, 4, 5 ) we relate into a relation which tries to express how oil and water will flow as the saturations of the two change. This relationship will reflect the fact that at certain low oil saturations the oil will flow at very reduced permeabilities and thus will not be RECOVERABLE.

Now with the above, we stick this information into a reservoir simulator to model the flow of the oil when we drill wells in different parts of the reservoir. We run these models until wells water cut reaches uneconomic limit and then look at all the oil left behind. The recovered vs. left behind gives me a Recovery Factor.

This is very simplified and there is much more here that needs to be explained but it would take much more TIME.

Thanks for this lenghty explanation,

some more questions on recovery rate:

You say that the recovered vs. the left behind gives the recovery factor.

Does this mean that the Estimated ultimate recovery vs the left behind is actually the recovery rate?

As an example does it means that when experts refer to a current recovery rate of around 35% for the world average they mean that approximately 2200 billion barrels can be recovered (1000 produced, 1200 reserves) ? which would then be 35% of OIIP?

Are fields which are not yet in production but under development also factored into this recovery rate calculation?

And fields which are possible to produce (economically and geologically) but not under development at the moment ?

Any idea on how accurate this recovery rate estimation is since it is a global figure?

Hey, Joe, yes I agree. I am much more worried about a number of things, like biodiversity. Also, I think there are a lot of people in the Third World who would be better off with commercial energy like oil (kerosene or LPG) instead of deforesting their locale.

I don't think we face a food crisis, since the developed nations are suppressing production and the developing nations are pursuing low-tech methods of production, and could raise productivity enormously.

For drilling, the comparison is to wells/sedimentary basin. This is hardly precise, but the difference is so enormous, that the possibility that, say, Central Africa, is not as promising as East Texas doesn't matter (on a global level). There is, to my knowledge, no metric by region (although the USGS is doing pretty good).

For Saudi Arabia, Matt has provided absolutely no evidence other than anecdotal about the level of drilling. At CSIS, the Saudis showed a graph with all wells drilled historically, which he didn't challenge. (He said he was referring to seismic, I think he said gravimetric, studies.) I have data on wells drilled historically and will publish soon (depending on how much time I spend here).
Mike Lynch

On the subject of recovery:

You have a very large box of sand and in the middle there is a pool of oil and the rest of the sand in this box is water.

I come along and poke some holes (wells) and seismic measurements and estimate the size of this pool. This number will now be the Original Oil In Place ( OOIP ).

My boss comes along and wants me to tell him what will be the Reserves for this box. He wants the Ultimate Recoverable (UROR), what he could expect to get out of this pool if we produces it to the very economic limit of the this operation.

The OOIP and UROR can and will change as we get more information and data changes or technology changes.

UROR could be one number if we just do Primary Recovery, just produce the wells. It could be large from the Primary if we apply a Secondary Recovery Process such as Water Injection.

The you have Remaining Reserves. You have been producing for 5 years and there is still some oil that can be recovered over the next 3 yrs. This is your Remaing which is less than Ultimate.

What are the IEA and others doing? I have no clue. But I would think they are reporting Reserves as those Remaining and Ultimate if the field is new.

Check this out

Reserves

I skimmed through the PDF . I spotted an incosistency (but after all the grant work during the last week I might be wrong). He said that computers and 3D and seismic did not make a difference on the real size of the reserves. But at one point he states that back in 1973, everyone thought that the Big G had 60mi barrels, which is followed by a 2003 cummulative production of 55.
Yet that seems to reinforce other analyst's position that 3d and computers do make a difference in the URR. I mean after all how can it be that Big G is still producing if the original estimates and not the updated ones (which used 3D visualization) are correct.
It does not make sense to me (but the same thing can be said about my post)

Precisely. Those reserves numbers are not known best as we get closer to the END. We have more wells with more data points.

Remember, we are trying to estimate the size of a field which may be 2km by 1 km, with data points with HARD data from wells whose wellbore diameters maybe on the order of 8.5 inches.

The seismic data is considered soft data. It is indirect and usually can only give me a better estimate of the geometry of the reservoir. It tells me nothing on the level of the pores where the gas/oil/water are.

It is a guesstimating process. Thus we could over estimate and as well under estimate. The people in the oil company looking after the field have the best data. What they give others is another issue.

Slight mistake

"are known" vs. " are not known"