I understand many people agree with Arthur Berman’s stance on shale gas. I do not, however, think that his new stance against shale liquids will catch on. Here is his latest slide in his stance against the Eagle Ford shale play. It should be noted that he left out his previous statement, ” less than 20% of wells will be commercial”. That line was in the previous version of this slide.
Even though Berman’s group would disagree, I still think it is pretty early to forecast accurately many of the more oily Eagle Ford wells, especially if you are going against what people operating in the trend believe. The cool thing is, I do not even have to project any EURs, I can just use the data out there to disprove some of the stances laid out in this slide. The easiest point to disprove is that 20% will have EURs > 100,000 BOE and I will focus there. I will only use the most liquids-rich wells in the trend, wells with a GOR < 20 Mcf/bbl. This comes out to about 210 wells, a nice sample size.
Here are the wells in map form. All of these are in the liquids rich portions of the play, I do not think this can be argued.
And here are these wells ranked in order of BOE produced. No projections, just good ole’ fashioned raw data.
25% of these wells have already produced greater than 100,000 BOE. How are the berman projections less than the actual data is one question. Has new data come out in the 2 months since he gave his presentation? Sure. If someone has some thoughts, leave a comment, or email me.
One more point to think about is that these wells represent the early wells in the operator’s programs. They will only get better as time moves on.
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Interesting, but maybe Berman is using an mcf to boe conversion based upon product price (20 to 1) rather than btu content (6 to 1). Is that possible?
Keep up good work!
That is a good point. Here are the numbers recrunched at 20:1 and 15:1. I only used wells that first produced from May 2010 back. This reduced the sample size from 210 to 80, but I think it’s more than fair to give the wells at least 6 months production.
15:1 – 31% have produced greater than 100 MBOE.
20:1 – 18% have produced greater than 100 MBOE.
Also, NGLs are not represented here.
Is it likely the exploration companies are drilling their best oil prospects first? Do you have a good idea how the seismic data currently being gathered is being used? Is it possible the exploration companies are looking for oil in the seismic they have and then going after it? In addition, exploration to some degree seems to be concentrated around proven oil wells, insofar as that’s possible, in keeping with that old oil-patch approach, “close-ology”. That practice would seem to skew the GOR data. It stands to reason that in this atmosphere where there’s a shortage of completion services, and an abundance of drilling to hold leases, the oilier prospects would be moved to the top of the completion list. It just seems to me prudent management at the exploration companies would be directing the exploration in a fashion which would maximize their oil results/revenues at this stage of the game. Does this make sense to you?
The production figures being reported to the RRC currently aren’t very helpful, being rather spotty and dilatory (I think you’ve commented on that unfortunate state of affairs in the past). As a completely objective observer on all this, all things considered, I’d have to contend that it’s too early to tell if there’s likely to be an oil bonanza in the Eagle Ford. It seems to me important to keep in mind that what we’re dealing in here is hyperbole, and that there are huge interests at stake, and that “to be wary is to be wise.” “The only one who knows for sure is Dr. Drill,” as Daniel Yergin once reminded us. It’s the vagaries of oil and gas drilling that keep the wild in wildcatting.
When you layer Eagle Ford activity on top of an Eagle Ford isopach, you do see some indications that operators are drilling on their thick acreage first. Some of the thicker areas are the Maverick Basin, original Hawkville and some areas of the Sugarkane/Blackhawk Corridor. This would indicate operators drilling their better acreage first like you say. However, it may take some time before the operators shoot and interpret seismic and other necessary science. Small regional sweet spots will continue to be found as operators progress their programs.
Mr. Berman’s low Marcellus shale gas reserve estimates are not supported by the data. I had never heard of Mr. Berman (and now I know why) until he spoke at the Republic of Ithaca, NY anti natural gas program farce this past week. A simple analysis of SEC reserves reported by all public companies shows Mr. Berman’s estimates are far too low. Applying pubically known Marcellus reserves to a small fraction of the total Marcellus acres that have high organic content and depths deeper than 3000 feet easily yields reverve potential of 850 TCF and more. And this equates to only a 20% recovery of gas in place for the “sweet” spots. Also iIndustry always improves its recovery techniques and that is why we have “univeral” reserve creep over time in unconventional resources. Not sure what Mr. Berman’s motivation is other than he must have some deep need for publicity at any cost but his lack of understanding on reserves is scary. Then on top of that add the Utica reverves that may have as much gas as the Marcellus plus the four or five other shales that have been discovered through drilling the Marcellus and you easily have a 1600 TCF resource base. It’s a no-brainer. We’re now looking at far more than 100 year noncoventional gas supplies at current demand rates and rising rapidy.
Though not directly related to Berman’s analysis, the operators are reported EURs of 200 to 600 mboe in the oil window. Its a long ways from 100 mboe to the mid-point of 400.