[Pops]

I mentioned just the other day, a majority of supply comes from a few giants, Cobb takes this up here quoting from a '09 study:

The world’s 507 giant oil fields comprise a little over one percent of all oil fields, but produce 60 percent of current world supply (2005).

“[A] majority of the largest giant fields are over 50 years old, and fewer and fewer new giants have been discovered since the decade of the 1960s.”

The 2009 study focused on 331 giant oil fields ... Of those, 261 or 79 percent are considered past their peak and in decline.

The average annual production decline for those 261 fields has been 6.5 percent.

An evaluation of giant fields by date of peak shows that new technologies applied to those fields has kept their production higher for longer only to lead to more rapid declines later. As the world’s giant fields continue to age and more start to decline, we can therefore expect the annual decline in their rate of production to worsen. Land-based and offshore giants that went into decline in the last decade showed annual production declines on average above 10 percent.

The worst case I've always thought is pulling future production forward producing a cliff in the production curve instead of a gentle decline. The example cited of Canatrell N injection increasing production dramatically in just a couple of years but then subsequently seeing an 80% drop in 8 years is the perfect illustration.

[Plantagenet]

Matt Simmons made this point years ago in his book about the importance of the supergiant Ghawar oil field, KSA. In amongst all the news about world oil supply, I always try to keep an eye out for the latest word on production from Ghawar.

[ROCKMAN]

P – And this is what I find troubling about some of the hype about the shale trends. No doubt these plays have increased US production and will continue to help as long as oil prices stay high. And until most of the location are drilled. But there isn’t single Bakken or Eagle Ford well that will be producing a significant volume of oil 10 years from now. Maybe a lot of new wells drilled 10 years from now producing a lot but current existing wells will be well on their way to depletion.

And that’s because these new plays aren’t “fields” in the conventional sense like the giants referred to in the study. There are probably wells in Ghawar that are 40+ years old producing more oil today then the best Bakken well. Maybe a lot of them. The decline rate of the shale wells is huge compared to those in the giants. The decline rate of the trend isn’t because of all the new wells being drilled. Some folks like to toss out impressive numbers for ultimate recoverable reserves for these trends but comparing those to the giants is like comparing apples to zebras IMHO. The biggest difference: when oil fell to less than $12/bbl in 1986 the production from the giant fields wasn't abandoned. Even at such a low price that oil could be produced profitably. And if oil prices fell tomorrow the existing unconventional wells would keep producing. But new wells to replace the quickly declining ones…ain’t going to happen.

Another false sense of security is the amount of oil we get from the Deep Water GOM. Certainly huge fields discovered out there compared to onshore tends. But not new: first DW field: 1976. Since then over 160 DW fields have been developed. Engineering advances and high oil prices made it possible. But the typical DW field won’t last 40+ years. Many will fall below economic limit in less than 10 years after they begin producing. The other misconception is that as engineering technology advances we’ll just go into ever deeper waters to find more oil. The problem there is that the vast majority of the remaining oceans have virtually no hydrocarbon potential. Even if you could drill and produce in 20,000’ of water it won’t matter because you’re not going to find much oil in igneous rocks. No tech is going to create what isn’t there.

Thanks to higher prices we have a lot more oil to produce even in the US. But we aren’t replacing those old giants. It’s just a delaying action IMHO.

[Econ101]

But there isn’t single Bakken or Eagle Ford well that will be producing a significant volume of oil 10 years from now.

WRONG

The bakken just retired what is largely regarded as its first well, it was drilled in 1952 and had no laterial legs. Production is on an almost straight up trend. Technologies are advancing rapidly and the result seems to be more oil the more holes you poke and prod. I think potential recovery rates are going to approch 40%-50% when all is said and done.

[Econ101]

The problem there is that the vast majority of the remaining oceans have virtually no hydrocarbon potential.

WRONG

Japan is developing the methane ice. Brazil has several huge new developments underway. Exploration is ongoing and intense. To say there is nothing left is simply short sighted and hasty I would say.

When counting up the billions and billions of barells of shale production still in front of us dont forget to add in the billions and billions of barells of known off shore reserves we cant develop because of peak oil politics.

[rockdoc123]

I think potential recovery rates are going to approch 40%-50% when all is said and done.

although I agree that recovery factors in the shales will increase the current recovery factor in the Eagleford is 6% according to EOG who is the premier player in the trend. The Bakken has seen some success from water injection but the reservoir is somewhat different with a middle member that has permeabilities in the micro-darcies whereas most of the Eagleford is in the nano-darcies range. There is also an issue with expandable clays in the Eagleford which would limit the use of water injection (injecting water would actually decrease effective permeability). My understanding is that the recovery factor in the Bakken even with injection is still only around 9 - 10%. There is a long way to go to 40%-50% IMHO. That is likely an unreasonable ask.
Each % increase is however important, at the same time it probably doesn't do anyone any favors to be overly optimistic.

[John_A]

Thanks to higher prices we have a lot more oil to produce even in the US. But we aren’t replacing those old giants. It’s just a delaying action IMHO.

Life is a delaying action Rock. In the end, we all have it coming, oil fields certainly don't get a special dispensation from the laws of physics any more or less than humans do.

The question is all about "how much delay" I suppose, and how fast the regular consumer can make certain that their lifestyle isn't dependent on what some corporation decides to charge for their liquid fuels, of whatever origin. The demonstrable example of why big fields matter , and why various organizations estimate more oil recovery than some might suppose being found in this Oil Drum graphic.

[Quinny]

ROCKMAN or Econ101?

Not exactly a brain teaser is it?

[rockdoc123]

A point that is missed here when comparing conventional production to shale production is the shape of the decline.
As a general rule a conventional fields gradually ramp up to a peak of production as more wells are added, that peak can be held for a few years (the length determined by a variety of issues including reservoir, drive mechanism, pressure maintenance etc.) but then the field goes into continuous decline at rates anywhere from 6%/annum to 15%/ annum although I've seen some fields with particularily poor pressure support show terminal declines as high as 30%/annum. In contrast unconventional oil (shales mostly and less the tight clastic plays) reaches a very rapid peak on a well by well basis, declines exponentially for a few years and then reaches a point of hyperbolic or near hyperbolic decline. During the initial decline you can see rates of 50% - 70%/annum but when you hit the hyperbolic decline portion the rate is very slow and can be in the order of 1% or so.
Where this distinction is important is that it speaks to the use of the term "scalable" by shale operators. Basically if you think the hyperbolic decline portion has production around 50 bbl/d/well then you would need would need a thousand wells to equate to 50,000 bbl/d/field. Operators like this type of production profile as it gets them off the exploration treadmill for sometime once they reach the target production level during hyperbolic decline.
The point missed by both Berman and Hughes in their analyses is they look at the number of wells that need to be drilled each year to keep production the same as it is during the exponential decline portion of the wells. The appropriate way of looking at the problem is how many wells do you need producing at their hyperbolic declines to equate to a production rate that you deem appropriate. If you wanted a million barrels of production a day then you would need 20,000 wells all producing at their hyperbolic decline rate (using the 50 bbl/d scenario).

[ROCKMAN]

I don’t mind anyone disagreeing with my opinions. That’s one of the nice aspects of participating in such forums. It just seems like a waste of time to debate facts that take less than a 60 second Internet search to authenticate. “…three-quarters of the world oceanic area…can be dismissed immediately in hydrocarbon prospectivity terms.” From:

http://www.onepetro.org/mslib/servlet/o ... OE-v19-007

“The deep ocean basins, beyond the foot of the continental slope, account for three-quarters of the world oceanic area (Hedberg et al., 1979) or about 50% of the total earth's surface. However, sediment thickness over almost all of this area is less than 1 km (often less than 500m) and it can be dismissed immediately in hydrocarbon prospectivity terms (e g. Hedberg et a l , 1979; Hedberg, 1983; St. John et al., 1984; Tucholke, 1986) In addition, numerous holes drilled by the Deep Sea Drilling Project (DSDP) and its successor the Ocean Drilling Project (ODP) have shown the sediments of the ocean basins to be generally fine-grained and poor in reservoir quality, very poor in organic carbon, and near flat-lying in attitude, which would prevent migration and trapping of any hydrocarbons formed (Table I, e.g. Hedberg, 1983;Katz, 1986)”


And speaking of Bakken production what is the current average production rate of Bakken wells that were drilled more than 10 years ago? As I just pointed out above documented facts go a lot further to proving one’s statement than just a hollow “WRONG” reply. BTW I’m about to drill a well in a field that has a few wells that were drilled in 1948 still producing. An average of 1 bopd but still producing. I suppose that counts as “significant” if one lowers their standards enough. LOL.

[rockdoc123]

And speaking of Bakken production what is the current average production rate of Bakken wells that were drilled more than 10 years ago? As I just pointed out above documented facts go a lot further to proving one’s statement than just a hollow “WRONG” reply. BTW I’m about to drill a well in a field that has a few wells that were drilled in 1948 still producing. An average of 1 bopd but still producing. I suppose that counts as “significant” if one lowers their standards enough. LOL.

yes but here I believe you are comparing apples with grapefruits. The long lateral multi-stage fracs were not accomplished in 1948 or even 10 years ago, that is a relatively recent addition to the mix. Slic-water fracs weren't de rigeur 10 years ago either. The scale of the operation is important, however,....1000 wells producing at 50 bbls/day is more than double the production coming from most fields currently in, say Colombia, but also about 100 times as many wells.

[Pops]

The point missed by both Berman and Hughes in their analyses is they look at the number of wells that need to be drilled each year to keep production the same as it is during the exponential decline portion of the wells. The appropriate way of looking at the problem is how many wells do you need producing at their hyperbolic declines to equate to a production rate that you deem appropriate. If you wanted a million barrels of production a day then you would need 20,000 wells all producing at their hyperbolic decline rate (using the 50 bbl/d scenario).

But a million boed isn't the talking point is it? No one argues any more that these areas won't make a million or 2 for a year or 2 or 10. Berman points out In this presentation that it is actually taking fewer wells to meet replacement today as the sweet spots are becoming obvious. The question is, how big are the sweet spots and how far can you extrapolate that production?

[seahorse3]

Well, proof is in the pudding right? As I pointed out in another thread on one example, Chesapeake, the leader in all these shale plays according to some, even with their "experience" they downgraded their future reserves by 20%. So, sounds like replacement is a serious issue to me.

[ROCKMAN]

rockdoc -You missed the point. The issue was how significant will production be in 10 years from a Bakken or Eagle Ford well drilled today...not from either trend as a whole. The discussion wasn't about how much oil would be coming from the plays in 10 years. The Bakken wells have a long established history of stripper production. And thank goodness for the US strippers...where a lot of our production comes from.

The issue was: "But there isn’t single Bakken or Eagle Ford well that will be producing a significant volume of oil 10 years from now." A 50 bopd well is nice but not very significant IMHO compared to a well flowing 900 bopd. And 20k Bakken wells making 50 bopd each is significant but just to a degree. Even that amount would represent less than 6% of current US consumption. Certainly nothing to sneeze at but not a game changer either IMHO. But a single well making 50 bopd being significant compared to our consumption? Maybe significant to my income stream; otherwise I don't think so.

OTOH predicting 50 bopd from currently drilling wells seems a tad optimistic based what some of the Bakken players are recording:

http://www.google.com/search?q=bakken+o ... B745%3B391

Some are reporting rates of recent wells being less than 50 bopd after just 3 years. OTOH why quibble over 50 bopd vs. 25 bopd in 10 years? Either way it would be beneficial but otherwise not much of an impact on PO IMHO. Obviously the impact of the oily shales is much more significant today and will remain so as long as prices stay high.

How significant is that 50 bopd benchmark? There are currently 349,771 wells in the US making less than 50 bopd. There are 17,371 wells making more than 50 bopd. Or about 5% of our total oil wells. So I suspect expectations of many of the shale wells being 50 bopd or better years down the road is a tad optimistic.

[rockdoc123]

How significant is that 50 bopd benchmark? There are currently 349,771 wells in the US making less than 50 bopd. There are 17,371 wells making more than 50 bopd. Or about 5% of our total oil wells. So I suspect expectations of many of the shale wells being 50 bopd or better years down the road is a tad optimistic.

but this falls into the same problem that Berman and Hughes have which is statistically they include all wells with no discrimination between perforated length, completion type, size of frac, propant material, tubing size, pump or not pumped etc. These all make some difference as has been shown by the operators as well as by the study I pointed to on one of these threads. To get to the heart of the potential problems requires proper analysis which often only the companies have the right data to do. As an example the last company I was with had drilled a 2 km reach lateral into one of the new shale plays, ran a seven stage frac and had great calc IP results on test but when brought on stream the IP was less than half. Turns out the reason was the casing collapsed, effectively shutting off some of the perforations. Someone looking at the production data wouldn't know that, however, and would assume the formation was only capable of that small IP. Devil, details.
BTW my 50 bbl/d number is based on my Eagleford analogy where I used a typical IP, declined at very high rates for the first few years and then followed by hyperbolic decline. There is always a range of production that these wells sit around when they are hyperbolic I used 50 as a number of the longer wells in the trend have gravitated to that level, although it is still early days.

Well, proof is in the pudding right? As I pointed out in another thread on one example, Chesapeake, the leader in all these shale plays according to some, even with their "experience" they downgraded their future reserves by 20%. So, sounds like replacement is a serious issue to me.

not sure if it was on that thread or another but I pointed out that the writedown CHK took was due to decreased prices, not the fact they had less gas. Under the SEC rules which use guidelines for reserve reporting from SEC/AAPG/SEG there is a standard to prove that the reserves could be produced economically. When gas prices took their death spiral below $3 a large part of the BOE based reserves of CHK fell below the economic level meaning that what was in proven undeveloped would have to move to probable. The reserves don't go away and would be rebooked if gas prices were to rise to the correct level. This same thing happened to the heavy oil players a few years back when the differential was high and heavy prices dropped below an economic threshold. The following years prices recovered and the reserves reappeared on the books.

The question is, how big are the sweet spots and how far can you extrapolate that production?

I think this is the one place where technology does come into play. Our current fraccing technology might get us say 300 Mbbl EUR from a well in the deeper, overpressured part of the Eagleford trend as an example and perhaps only 200 Mbbl EUR when drilled in the less overpressured area today but it likely isn't a big jump to improve the technology so that what is a poorer trend today can recover the same reserves as the good trend does at some point in the future. I think people lose sight of how quickly this technology has changed over the past couple of years and I don't know of anyone in the service industry who is claiming we are topped out in new things to implement.

[seahorse3]

Rockdoc,

SEC standards are essentially meaningless. You made a thread not so long ago that showed how complicated it is to know and determine anything, that one could report as "reserve" anything to the SEC. Case in point is Chesapeak, which doesn't have its "reserves" independently confirmed to the extent its competitors do. Here is a quote:

Independent firms produced 77 percent of Chesapeake’s reserve estimates in 2011; but third-party firms produced 89 percent of the reserve estimates at each of nine Chesapeake competitors, the WSJ reports. “Chesapeake’s crosstown rival,” Devon, targets about 90 percent for independent review. At SandRidge Energy, another crosstown competitor, that number is about 95 percent.


The worry for Chesapeake is that its level of oversight could cause high reserve estimates, leading to excessive write-downs in the future. Historically, Chesapeake’s write-downs have been in line with industry averages, according to a review of estimate revisions from 2006 to 2011.

William Kazmann, president of LaRoche Petroleum Consultants in Dallas tells the WSJ he’d be more comfortable if 85 percent of Chesapeake’s reserves were independently audited.

Chesapeake’s lower figure, he added, “doesn’t make me unduly uncomfortable, but I’d rather see a higher number.”

http://stateimpact.npr.org/oklahoma/2012/08/13/more-questions-about-chesapeakes-reserves/

All that to say, SEC standards are not that reliable. They may be the only standard we have, but there is a lot of play in those numbers.

[Pops]

not sure if it was on that thread or another but I pointed out that the writedown CHK took was due to decreased prices, not the fact they had less gas.

The article SH is referring to indicated CHK filings which stated implicitly that the write down was due to overestimation of "drilling" performance and higher than expected pressure decline in their initial offering and they inked in a 26% permanent reduction of reserves as a result.

Overall reserves fell 40% as I remember with only 15% being due to price.

I think the thread title was "gas hype" and as I remember I pointed out to you there that it was a permanent write down according to the article. All respect, you should read the article because unless I'm reading it entirely wrong it goes exactly to your recurring point that everyone is afraid of the SEC when the fact is CHK sold stock in the trust based on a guess then a year later wrote down the reserves 25% because real life was 25% "below expectations".

[Quinny]

Be careful Pops - the resident expert knows it all. I suppose however with more than one expert on board now we might get a more balanced view.