[rockdoc123]

Having seen some recent comments regarding shale production in the US that were somewhat out of line with reality I thought I would sit down and offer up some information I believe is central to the issues surrounding shale production and hence PO. Rather than respond to the various threads I thought I would break up my thoughts into a few threads which will make commenting (assuming anyone wants to discuss) less confusing. I think there are some important issues here with direct impact on PO and it would be good for everyone to have a better understanding. I will use EagleFord as my main example simply because it has attracted most of the activity as of late. As background to this thread prior to retiring I was a senior executive for one of the major shale producers in North America and as a consequence had exposure to all of the elements that make the business work both as it applies to North America and elsewhere in the world where shale has now become important (i.e. Argentina, Algeria, Australia, Europe etc). I was also afforded the opportunity to meet and discuss many of these issues with analysts from some of the banks (Credit Suisse as an example) and the main industry consultants who look at company performance in this area (WoodMackenzie as an example). I think that gives me some unique insight but I also must say I do not have all the answers, in fact I do not think anyone does at this point in time. Not that long ago someone who has been quoted in the press as being a “shale expert” told me there is no such thing as a shale expert, we are too early in the understanding of how it all works.
Here is Part I which deals with EUR and the estimation of reserves.

The issues with EUR
One problem I see is that everyone and his dog tosses around comments regarding EUR being less than what companies are saying but generally they are comparing apples with oranges, or worse yet pineapples. There are a number of things that drive Eagleford production and EUR. The trend is ENE to SSW and there is a general deepening from the NE to the SW. There are also areas of thickening with a generally pattern of the shales being thicker to the SSW. Several issues of importance, the thicker the shale the greater the in-place resource and the greater the chance for overpressure, the deeper the shale the greater the hydrocarbon gas content and the greater the chance for overpressure. So deeper and thicker is generally better with the provisio that you can’t be so deep as to be in an area that is not favorable for high liquid content. This is why there are certain areas along the EagleFord trend that have much higher IP (initial production rate) and are generally viewed to have a higher EUR. Counties such as Gonzales, La Salle and Dimmit are in a good position for both thickness and depth and companies such as EOG have taken advantage of that trend. EUR is generally reported in the shale plays in terms of MBOE (thousands of barrels of oil equivalent). When you are talking about pure oil the correlation of BOE and bbls is of course 1:1 but in the case of dry gas it is 1 bbl is equivalent to 6 MCF (this is now standardly applied in the industry and expected by SEC and TSX). No matter what methodology of shale hydrocarbon reserve calculation you use (there are 3 or 4 main ones that are better or worse in certain aspects) the IP rate has an influence on EUR. As a consequence gassy shales which generally have the advantage of expansion drive and additional compression due to overpressuring can have a much higher IP on a BOE basis than pure oil. So where you see some companies such as EOG reporting EUR of say 200 – 300 MBOE and other companies such as say Rosetta reporting EUR of >600 MBOE it doesn’t mean that either company has done their curve matching or calculations incorrectly nor that Rosetta is somehow trying to lie to make their play look better, it is simply to do with the fact EOG does not have much gas content in their production whereas Rosetta is higher gas content than oil content. Although on a BOE basis EOG would have a lower EUR/well it is actually way more economic than Rosetta’s production due to a disconnect between oil and natural gas pricing. When you look at reported EUR you need to understand what the hydrocarbon makeup is.

Problems with reserve estimation
Perhaps one of the most important issues being faced in estimating reserves is there is really no long term production in the EagleFord such that you can determine what the actual decline will look like. Whether you subscribe to the hyperbolic decline theory , a power law decline theory or an exponential decline, only having a few years of production history makes it nearly impossible to predict accurately what is going to happen and hence what ultimate EUR will be. There has been a lot of modeling research done in this area over the past few years much of which appears in SPE papers but there is no general consensus at this point. I could go into a long technical discussion about the various methods that are now being used for predictions but given none is a panacea there isn’t much point. I think the reality is that it is unreasonable to believe in infinite production from any given well, something that pure hyperbolic decline approaches. At the same time shales are different than regular gas reservoirs due to the very low permeabilities which means you shouldn’t see pure exponential decline either. A solution that I’ve seen some of the Texas A&M researchers adopt is to use hyperbolic decline but at some point have a limit imposed by assumptions regarding input to the ARPs equation that is commonly used for decline analysis. Power Law decline seems to work better but also has the problem of having an unrealistically long life span.

As far as the Eagle Ford is concerned there was a paper written by Swindell in 2012
Swindell, G.S., 2012. Eagle Ford shale – an early look at Ultimate Recovery, SPE 158207.
That attempts to do what Berman and others have done with Barnett by looking at statistics of EagleFord well production. Where this particular study is far superior to anything Berman or Dave Hughes have attempted is that it actually tries to split up wells based on amount of perforations, frac size, fluid type. The author admits the database isn’t perfect (often reports on cluster production rather than single well production) but qualifies that he took the wells with the most complete data. There are a number of things that they demonstrated and several interpretations that I believe aren’t realistic given the data. Something very important that has to be understood is that the industry standard to convert oil to gas is 1 bbl = 6 MCF which equates to a BOE. This was originally done because gas and oil traded on a 6 times basis. It no longer does but all companies use this conversion as it is standard and the SEC requires it. The author of this report chose to use 20:1 to recognize the large gap in prices. What that does of course is alter the results such that gassy wells will have a lower EUR using this study than would be reported by the company although the actual decline model is very close, it is simply a conversion factor. They also use a group normalized decline function where they stop production in a group once the well count reaches 10. This helps to alleviate the problem of strict hyperbolic decline resulting in reserves which are too large. The main results of interest in the study are that :
1. Some areas have higher EUR. As I mentioned previously this has to do with thickness, depth and presence of overpressuring. As an example the highest EUR is calculated for Dewitt country at 403 MBoe/well and in comparison the nearby Karnes county calculation ends up with EUR of 210 MBoe/well. This seems to make sense given Dewitt has thicker shale and is more clearly in the pure oil window whereas Karnes county seems to be in the Wet gas window. The average they end up calculating for everything they have looked at is ~210 MBOE/well.
2. There seems to be an obvious correlation between IP and EUR, especially for oil. This is good as it suggests the methodology used for curve fitting by companies is valid. The fit for gas isn’t as good which is not surprising given that operators fiddle around with a lot of things during gas testing that can affect IP rate.
3. There is a definite correlation of perforated length (how much hole is open to the formation) versus EUR. The authors suggest that beyond 5100 feet of length it seems to have declining EUR but they have no way of quality controlling those wells (i.e. were there problems in the completion, casing collapse, plugging etc) so the longer reach well analysis is wanting at this point.
4. There is a poorly defined general increase in EUR with size of frac
5. There seems to be no correlation between when a well was drilled versus EUR which the authors suggests means technology isn’t improving but in reality the level of information on the data is not good enough to jump to that conclusion given there is no information available regarding tubing size, pumps used, choke size etc.

I’d ask you to remember that range ….200 to 400 MBOE as an independent calculation based on looking at readily available data. Now to compare with what various companies have been saying.

EOG is recognized as the most important and biggest player in the EagleFord at this time. EOG have suggested they have EOR’s as high as 450 MBOE. They are clearly in the best trend where production is mainly oil and some condensate, shale is thick and overpressured.
Rosetta has reported quite high EUR (up to 650 MBOE) but their production is mainly gas with liquids.
Swift Energy reports EUR of La Salle county at 310 MBOE /well and 286 MBOE/well for McMilken oil. La Salle county is in the oil to condensate window
Anadarko has widespread acreage throughout both the gas and oil windows and suggest on average that the EUR/well is 450 MBOE.
Cabot is exclusively in the oil window and talk about EUR’s in the range of 380 – 550 MBOE.
BHP which bought PetroHawk acreage in 2011 reports EUR of 150 -250 MBOE/well for the Red Hawk play which is pretty much pure oil. The Black Hawk play which is a bit deeper and has more gas and condensate has reported EUR of 500 – 750 MBOE/well (again remember the difference between gas and oil with respect to EUR).

So to wrap this discussion up I think that when talking about liquids and oil using a range of EUR/well between 200 and 400 MBOE is probably reasonable. Again what is important in looking at overall EUR is understanding first what the production consists of (oil, condensate or gas) and the location within the play fairway. Given the above discussion it should be fairly easy to arrive at a map of EUR areas which should more closely represent the overall potential of the pool.

In terms of looking a reserves for a basin rather than a well one important point is to understand current well spacing, the opportunity for downsizing (which some companies are doing) and whether or not that will result in well interference.

A final provisio is that the recovery factors we are talking about here are less than 10% of the calculated OOIP (original oil in place). It is quite likely that recovery rate will improve a few percentage over the coming years as a lot of research is currently being applied in this area.

Up next a discussion on Economics of shale.

[thylacine]

Thanks for your post Rockdoc - I'm looking forward to reading your future posts as well. I struggle with getting my head around all the conflicting reports which come out about unconventional oil/gas. It seems as if everyone who writes on the subject is also pushing their own barrow of commercial spruiking, emotional attachment, personal beliefs/biases etc. Your comments on most matters usually inject a note of sanity into debates and are based on actual experience and letting the data speak.

[Beery1]

EUR and economics are only an issue to the rubes and assorted mouth-breathers who can be conned into buying into the shale bubble.

The real issue is flow and depletion rates. We have people who don't know a damned thing about shale crowing about how it is going to bring a new age of oil prosperity and make the 1970 peak look like Mt. Etna compared with Mt. Everest, whereas in reality, shale will amount to nothing more than what was achieved by drilling in Alaska.

[ROCKMAN]

First, kudos to rockdoc for presenting the most digestible description I seen for the general public. Many times such efforts are either simplistic to the point of being misleading or so detailed it can’t be readily absorbed.

Beery – I agree but there’s another important factor that many don’t see. Let’s accept a grossly overly optimistic assumption that enough unconventional wells are drilled fast enough to recover to our 1971 production rate. As rockdoc describes the details of depletion rates of the unconventional reservoirs can vary but universal high decline rates can’t be denied. Wells in the classic large water drive conventional oil reservoirs could maintain high production rates for many years longer than the unconventional wells. To whatever level the current plays increase US oil production there won’t be such a “coasting period”.

But we’ve gotten a nice bump in oil production…the stats can’t be denied. And the bump will last as long as oil prices stay high, there are still locations to drill and the public companies have few other options to grow or just maintain their reserve base. But it’s that high price requirement that many of those optimistic projections fail to account for either out of ignorance or an agenda. Some take the bump as proof that PO isn’t a factor today. IMHO it’s one of the best indications that the PO dynamic is affecting the economy and will continue to do so. As rockdoc offers if oil prices fall back to levels of 10 years ago few unconventional wells would be drilled. These plays aren’t going to lead to low oil prices given their existence depends on those high prices.

And IMHO that’s the real danger of some of the hype: the public thinks there is relief for the economy not too far down the road. As soon as enough of these wells are drilled we’ll be back to BAU. And that discourages them from at least beginning to make meaningful adjustments that many feel are already decades late. And that lack of support for significant change is communicated to the politicians who often find it difficult to go against such public sentiment. We’ve seen many ideas that would improve our energy future IF they were deployed. Ideas that would also help our climate’s future. But they require public support. Public support that’s difficult to muster as long as many think we’ve found the silver bullet that can kill the PO monster.

[rockdoc123]

EUR and economics are only an issue to the rubes and assorted mouth-breathers who can be conned into buying into the shale bubble.

I disagree (see part 2). Economics is important as it drives the activity. Companies are only going to invest when the economics work for them. ROCKMAN has pointed out the fact the high price of oil has driven the recent activity and it was the $10 +/MCF prices for natural gas that originally drove the shale gas activity. IHS Energy did a study awhile ago where they determined that shale gas activities supported about 600,000 jobs in the US as of 2011 and was predicted to rise to 870,000 jobs by 2015. In 2010 they attribute $76.9 billion of GDP to shale gas efforts and expect that to rise to $118 billion by 2015. The lower natural gas prices also are seen as a catalyst for further manufacturing jobs. The effects on the overall economy are pretty important.

[Graeme]

You are totally insane. This precisely the kind of activity that leads to further carbon emissions and ultimately ecocide. The fossil fuel industry has to be stopped.

[rockdoc123]

You are totally insane. This precisely the kind of activity that leads to further carbon emissions and ultimately ecocide. The fossil fuel industry has to be stopped.

OK....lets stop all oil and gas production tomorrow. And precisely how many people do you think will die in the ensuing months while they figure out that wind power isn't continuous, solar only works for certain areas and certain things....etc, etc?

So when we do this immediate stoppage of oil and gas exactly what do you think your chances of survival are?

What needs to be done, as I have stated countless times on this forum is have a long rolling peak which allows for gov'ts to properly subsidize other alternatives (which still require research). This can't be the US approach which was Obama to pork barrel his buddies into "green" enterprise that was simply a way of bilking the country of millions of dollars.

I've just come up with a new term Idiot + Greenie + Gridiot.

[Graeme]

Shale gas is only going to supply us with a few more years of energy (see EWG in other thread) before it goes into decline. What then? We have to switch to renewables using a scenario like the WWF. There are many others. The faster this transition occurs the better not only because of fossil fuel supply constrainsts but also because our environment is rapidly deteriorating before our eyes. Of course there will be some economic pain during this transition (mainly investment in infrastructure) but the alternative of not doing so is eventual extinction. Which do you prefer?

Let's combine renewable introduction with shale gas backup. What do you think of this idea?

RACKING COULD BE KEY TO RENEWABLE ENERGY'S FUTURE

Solar energy production at the utility scale still needs another decade or more to become competitive with relatively cheap gas produced by fracking, according to an analysis by Citigroup. Even as solar becomes competitive, the US will need gas produced by fracking as a reliable backup when renewable power isn't available.

Writer David Roberts at Grist, a site focused on energy issues, recently highlighted an analysis of energy trends produced by Citigroup. The Citi report (pdf) is interesting for a couple reasons. First, it estimates the date at which large-scale solar energy production could compete with relatively cheap natural gas produced by fracking. Second, the report suggests that even after that point, the success of renewable energy will depend on the reliable backup of natural gas. In other words, fracking isn't an impediment to moving toward more renewable energy. It's a necessary part of getting there over time.

Gas Prices Will Rise and Solar Prices Will Fall

At present, the boom in natural gas production in the United States that has resulted from fracking has pushed prices to levels that everyone agrees are economically unsustainable. Gas wells cost money, and producers simply can't make a profit selling at the current rate of less than $3/MMBtu (1,000,000 BTUs). The glut in the market means new production will slow until prices rise to an economically sustainable level.

Because widespread fracking is relatively new compared to the lifetime of a well (up to 35 years) and because the overhead associated with environmental regulations has yet to be determined, the break-even cost of natural gas from isn't precisely known. The Citi report estimates the it will have to rise to $4-6/MMBtu, but the authors note that other estimates have been as high as $6-8/MMBtu; Zero Hedge published an even higher estimate of $8-9/MMBtu. The point is, natural gas prices will rise gradually until drilling is profitable again. That eventual price could be double or triple current prices.

Meanwhile, the break-even cost of solar installations continues to drop at a fairly predictable level. I say fairly predictable because Citigroup actually uses two different methods to estimate the rate at which the price of solar will decline. The more conservative estimate is called "single-speed" and the more optimistic estimate is "three-speed." Again, the point is that the cost of large-scale solar is dropping gradually over time.

So with the cost of natural gas rising and the cost of solar dropping, one can envision that at some point those two lines will cross. That's the point at which utility-scale solar becomes competitive with gas produced by fracking. We'll get to a chart of that in a moment, but first there's one more wrinkle that needs to be considered: insolation.

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