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# Case Study Of Production Of A Bakken Shale Well

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I repeatedly warned people that shale oil and gas producers tend to exaggerate the EURs (estimated ultimate recovery) of their wells and then under-estimate the fair armortization costs in order to show better financial results. I analyzed one most productive well owned by Continental Resources (NYSE:CLR) and showed why the EUR calculated by CLR was way too high. CLR claimed that the Charlotte 2-22H well will produce 561 MBOE. I estimated an EUR of 200 MBOE.

How to Calculate a Reasonable EUR Estimate

To re-cap, I proposed to modify the Arps Type Curve formula by introducing a decay factor of roughly 7% annually, or 0.0002/Day, so as to reflect a reasonable terminal decline of the wells. I also proposed a rule of thumb to estimate the EUR quickly:

Wait 60 days or 90 days after production started, so that the production rate PR stabilizes. Take that production rate PR and multiply by 500 days to estimate how much more will be produce, add the volume already produced to get the EUR.

How accurate does my method project? To find out, I need to test my method on a well with long production history to study. I found one such well to study. It started production on Sep 19, 2006.

The Sveen 34x-14 Bakken Well Owned By XTO Energy

The Sveen 34X-14 well was developed by XTO Energy Inc., which is now part of Exxon Mobil (NYSE:XOM). Here is a link to data on that well. There is a 230 pages comprehensive document on that well. The production started on Sep. 20, 2006. So there's six years of history.

Here are the monthly productions of that well, in BOEs:

Cumulative production of the well is 280 MBOE after six years.

Modeling the Production of the Sveen 34X-14 Well

I selected these parameters to model the well's historic production:

• IP = 900 BPD (Same as in my last article)
• D = 0.02/Day (a bit less than 0.027/Day in my last article)
• B-Factor = 1.55 (a bit higher than 1.465 in my last article)
• Decay factor Beta = 0.0002/Day (Same as last article)

Here is how my projection compares with the actual production:

My projection seems to match pretty well. XTO conducted a re-fracing operation on the well in August 2009, which seems to have boosted the production rate for a while. But the production rate has since then fallen back to my projection curve.

I used the same IP = 900 BPD and same long term decay factor of Beta = 0.0002/Day as used in my last article. But I had to make two adjustments to make the curve fit:

1. The initial decline D is reduced from 0.027/Day to 0.020/Day. This means the wells six years ago probably declined a bit slower. The newer wells today, due to closer fracing stages, may decline faster.

2. The B-factor is increased a bit from 1.465 to 1.550. This means the decline flatten out a little bit sooner in the old wells. The newer wells takes a little bit longer for the decline to flatten out.

Both of the above changes would result in a slightly higher EURs. So I am not surprised that the EUR will be higher than 200 MBOE. The accumulated production so far is 280 MBOE.

Since the initial decline D is slower, the production rate stabilize quicker in the old wells. So I will use 60 days after the production start, instead of 90 days, to use my rule of thumb to estimate EUR:

• At 60 days, the projected IP is 451.4 BPD, the projected cumulative production is 36.78 MBOE.
• EUR = 451.4 BPD * 500 days + 36.78 MBOE = 263 MBOE.

My result of EUR = 263 MBOE is close to cumulative production of 280 MBOE, but is still a bit lower than the actual production. This is mainly due to the re-fracing done in August 2009 which did boosted the production rate. But it appears to me that the EUR gain from re-fracing is very limited.

How much more will this well produce?

As of Sep. 2012, the well produces 40 BPD. The projected decline rate is 0.0005/Day. Assuming this decline rate holds, the remaining production volume is approximately 40 BPD / 0.0005 = 80 MBOE. If we cut the well off at 20 BPD level, then 40 MBOE will be produced.

So this well's ultimate production will likely be 280 MBOE + 40 MBOE, or 320 MBOE. Compared with my estimate of 263 MBOE, the well has gained 60 MBOE of extra production due to re-fracing treatment.

How Much Does Re-Fracing Help?

Producers pitch re-fracturing the wells as being effective in boosting EURs and extend a well's life span. I am skeptical to the claim. As shown in the above chart, the re-fracing done in August 2009 only marginally boosted the production rate. However the production boosting effect diminished quickly. In three years, it's almost gone.

In SPE 154669, Mark Craig of Devon Energy (NYSE:DVN) claimed that a cash study of 13 re-stimulated (re-fracing) Barnett wells show that re-fracing, at a cost of \$0.9M per well, can boost EUR by 0.8 BCF.

Such claim is ridiculous. The average accumulative production of all Barnett shale wells is no more than 0.67 BCF per well. It is absurd to claim that re-fracing can more than double a well's EUR. As a matter of fact, paying \$0.9M cost to gain 0.8 BCF extra production. That's a production cost of only \$1.13/mmBtu. If it is a such a great deal, producers should rush back to Barnett to re-stimulate all the wells. But they don't. So the claim cannot stand the test of water.

Craig Cooper estimated that re-fracing costs \$0.095M per stage. If a well contains 25 stages, one re-fracing operation will cost \$2.4M. As the re-fracing only boost production marginally and it lasts less than three years, it seems to me that re-fracing is wasting money.

In a presentation (page 16), XTO showed the production rate before and after the Sveen 34x-14 was re-stimulated:

It looks to me they did manage to boost water production a lot, as all the injected water comes right back out. But the oil and gas production gain was much less impressive.

Based on my calculation, re-fracing contributed to 60 MBOE extra production. At \$65/BOE value, it contributed to \$3.90M revenue. As XTO carried out multiple re-fracing operations on the well's six year history so far, I believe the economic benefit of re-fracing is zero.

Discussions and Investment Implications

Geologist Arthur Berman and others have been sounding the alarm for a long time that the US NG industry is engaged in efforts to pitch overly-optimistic projections in the shale well revolution. The money spent on shale development far out-weight the economic return. The capital spending of shale producers routinely out-pace revenue stream by several times. Despite of the gloomy reality, producers continue reckless money spending in aggressive well drillings, thanks to generous money from banks and investors.

This is an non-sustainable bubble. I see a looming debt crisis in the shale industry, which has accumulated more than half a trillion dollars in debts thanks to their shale revolution adventure. The NG industry will collapse once bank lending is cut off, leading to collapse of US natural gas supply. As a result it will send natural gas and coal price skyrocketing. It will happen soon.

The biggest beneficiary to the looming crisis in the NG sector, is the US coal sector. That's where I put my money in. You should, too!

The coal sector was wrongfully punished by the wide-spread meme:

"Coal is dead. Cheap and abundant natural gas is replacing coal"

Nothing is further from the truth!

I made the efforts to do the calculation and modeling to find the truth behind the rosy pitches of NG companies. I am convinced that the real data says I was right and the industry experts were wrong.

I ask you to follow my math and do your own analysis. If you agree with me, pull your money out of the shale industry and into the US coal sector. The coal story is the biggest investment opportunity in more than a decade. I am holding my coal stocks firm.

Disclosure: I am long JRCC, ANR, ACI, BTU.