[Ron Patterson]

More on does the Bakken date include Three Forks?
The below chart is oil production from the Bakken and all North Dakota, both taken from the URLs I posted above. As you can see the lions share of production comes from the Bakken. In May the Bakken area produced 745,399 barrels of oil per day. All North Dakota produced 810,314 barrels per day. That means only 64,915 barrels of North Dakota was produced outside the Bakken. So if the data they post for the Bakken does not include Three Forks then only a tiny amount of oil was produced from the Three Forks.

But obviously that is not the case. All the data they quote for the Bakken includes the Three Forks.



I have several posts on the on my web site http://peakoilbarrel.com/

[Oily Stuff]

John, thanks for reminding us how the business works, but a few days of rig time absolutely does NOT automatically equate to a cheaper well. And of course the well count in N. Dakota includes Three Forks wells. Is CHK still in the Utica? I think they bailed on that long ago. In the 90's rigs were moved, not skidded, and often took a week and 40 truck loads, today they can skid them 30 feet in 4 hours but it still takes days, spud to spud. Big deal. If this tight oil jazz depends on 3 days of rig time to make the difference in OK and mediocre, we are in big trouble.

In my dumb ass roughneck opinion the US rig fleet is maxed out; we cannot support more rigs with services and qualified personal. What we have now is what we are gonna have going forward. RM is right, if this stuff in the Bakken is so hunky dory, why are there not 400 rigs running in it? Money is no object, clearly. Same in the EF. Something does not add up.

You have bought into the hoopla. Show me the carfax.

[SeaGypsy]

Thanks Oily. (Is there a single insider here who agrees with Maugeri? it seems highly unlikely.)

[John_A]

$this->bbcode_second_pass_quote('Ron Patterson', '')$this->bbcode_second_pass_quote('', 'J')ohn A wrote:
And it should be noted that your 5730 number probably doesn't include the Three Forks, seems a bit low to have both in that number. Last at the beginning of the year the Three Forks wells totaled almost 1000 all by themselves.

[John_A]

$this->bbcode_second_pass_quote('Oily Stuff', 'J')ohn, thanks for reminding us how the business works, but a few days of rig time absolutely does NOT automatically equate to a cheaper well. And of course the well count in N. Dakota includes Three Forks wells.

[Pops]

I still haven't read Leo's entire paper but here are the high points:

It doesn't seem to be quite as effusive as his last, it even has a special section titled U.S. will Still Import Oil (for Diane Sawyer US news reader who reported on the last version saying we'd be the largest Exporter, lol))

Here is his assessment of well decline
$this->bbcode_second_pass_quote('', 'T')rue, like for shale gas, shale oil wells exhibit their peak production rates during the first weeks of operation, generally referred to as initial production during the first 30 days, or IP30. Eventually, they register 40–50 percent lower rates by the end of the first year of production and a further 30–40 percent decline rate by the end of the second year. To date, wells with longer observed production histories of 5–6 years reveal average production rates flattening by about more than 10 percent of IP30 after the fifth year.

[Pops]

One thing he mentions that I hadn't considered (I know! hard to believe! LOL) is that extracting tight oil "deposits" are not like developing a traditional "reservoir". A tight oil well is a universe all it's own, unlike a large "pool" of oil where what happens at one location can affect other wells, a fracked well influences only an area a large as the fractures. The upshot is an individual well can go from permit to production in just a few of months. He goes into this in some detail in sec 4.

I'll just say that takes for granted the manpower and equipment is available. He mentions on pg 8 that waiting lists are a thing of the past but the last Directors Cut said the wait is 92 days in May and the list is 500 wells long (again this might be weather).

[ROCKMAN]

Pops - exactly. There are both positive and negative differences between conventional reservoirs and fractured formations. The best positive: the technical term we use is "cookie cutter" plays. Unlike the limiter areal extent of a conv. fld the frac tend can carry for 100+ miles. But just like your Christms efforts not all cookies come out looking as good. It will be rare to drill a shale well that doesn't produce some hydrocarbons.

But not all produce good returns. Some actually lose money. OTOH you can easily drill a dry hole chasing a conventional reservoir but once discovered the economic risk of the development drilling goes way down. And that'a one of the big trade offs.

The other is just as obvious: well life. I've seen convention oil fields produce with little decline for years...in some cases for a decade or more. In addition to producing a nice long term cash flow it lessens the requirement to quickly drill replacement wells to maintain the reserve base. Especially critical for pubcos.

As you say there really aren't shale fields. They are trends. And natural variations in the trends: sweet spots and sour spots. Which is exactly why we have endless debates about how many wells will be drilled, rates and URR. But there is one fact that never changes: once a convention fld is discovered the risk/reward ratio falls significantly. Not so in the shale trends. It's not rare that some of the most profitable wells are immediately offset by some of the worst. The biggest benefit of the cookie cutter plays: if not for the high oil prices that make them viable probably half the US oil companies wouldn't exist today. Probably an even smaller % of pubcos.

[rockdoc123]

$this->bbcode_second_pass_quote('', 'J')ohn, thanks for reminding us how the business works, but a few days of rig time absolutely does NOT automatically equate to a cheaper well. And of course the well count in N. Dakota includes Three Forks wells. Is CHK still in the Utica? I think they bailed on that long ago. In the 90's rigs were moved, not skidded, and often took a week and 40 truck loads, today they can skid them 30 feet in 4 hours but it still takes days, spud to spud. Big deal. If this tight oil jazz depends on 3 days of rig time to make the difference in OK and mediocre, we are in big trouble.

[Oily Stuff]

Regarding the expansion of the domestic rig fleet in the US, to serve and perpetuate the tight oil industry, of course money is very much the issue, Professor; I was being facetious. I believe the 3 primary areas of shale development in the US are saturated with service capability at the moment, perhaps over saturated as I see lots of iron stacked these days in S. Texas, particularly frac pumps, etc. If what you say is correct and there is no more capital available to these guys, and they are now having to rely entirely on cash flow to develop their lease positions (?), no established drilling contractor is going to want to increase its rig inventory to watch it become idle again in 4 years. I wouldn't, would you? I believe the tight oil development "system" is maxed out and indeed it is entirely because of cash flow and decline rates equal to 80% the first 3 years of well life. Personally I would not invest anything in the future of tight oil at this point, not even a travel trailer to rent to a hand. That day has come and gone, IMO.

I disagree with you adamantly about available "bodies" to support an increase the domestic rig fleet. I don't know what you see from glass board rooms; not out here in the field.

We're off track and arguing simply for the sake of arguing (and correcting me), I think. I piped up on this interesting thread because I am not a big fan of Leo and his anti conservation plan. And mostly because I cannot begin to fathom how drilling costs in shale wells is going to go down from 9 million dollars to 4 1/2 million dollars over the next 5 years. Since we are all interested in our energy future and what role tight oil development plays in that future, well costs are huge. When these shale guys get all red in the cheeks about 2:1 rates of return over 25 years it is easy to understand why they like to blabber about declining well costs. They might get to 2.2:1 total ROI. Rockman, do you see your drilling costs going down by 50% over the next 5 years?

Me neither.

Maybe for the carpet bombers like CHK and EOG and MPC but across the entire shale trend, 50%? Really? Does anyone have an actual AFE that I can see, please; not Papa Papa in a Forbes rant but actual real well cost numbers? Last I heard the increase in proppants, stages, having to haul 150,000 bbls. of water because all of sudden land owners are worried about their water, fracs alone were over 3 million dollars a pop. If they can drill and complete a 15,000 ft. TMD well for another 1.5 million, into the tanks, I am truly impressed.

[rockdoc123]

I don't have an AFE in my hand (I'm retired and don't hang onto that crap from the past) but can tell you the last company I worked with our Marcellus D&C costs dropped from $7.5 to $5 MM in a period of a year and a half mainly through efficiencies and better planning. I realize you are one of those who don't believe corporate statements but as I have been trying to tell people here anything that a publically traded company states whether it is a press release, in a presentation to investors, on their website is under the scrutiny of the SEC and it is illegal to fabricate numbers. Few companies try that gambit just because you get caught eventually and run the risk of losing your listing.

The shale ops lend themselves to this kind of cost cutting because they are high effort, lots of things going on with a lot of room for savings by addressing more than one well at a given time. As an example EOG bought a sand mine in order to decrease their costs for the large amounts of sand they use in fraccing operations. The better companies approach it as a manufacturing business where attention to costs all the way down the line mean the difference between success and failure

In my experience you aren't going to see that kind of cost cutting ability when you are drilling one off conventional wells.

[John_A]

$this->bbcode_second_pass_quote('Oily Stuff', ' ')Does anyone have an actual AFE that I can see, please; not Papa Papa in a Forbes rant but actual real well cost numbers?

[Oily Stuff]

Thanks guys, it seems the best we can do is simply rely on what the shale boys tell us these wells cost. In spite of your best efforts, and SEC mandated corporate statements, I don't buy into the idea that a 14-15,000 TMD well, with 5K of lateral, and 18 frac stages, can cost 4 1/2 million dollars, landman to gauger. Sorry, no way. But, hey, what do I know?

Off topic, but important to me on a personal level, Pat Campbell died yesterday in Houston. Pat worked for Boots and Coots in the 1980s and later joined Joe Bowden at Wild Well Control where he and Joe built WWC into a first rate well control company, often in the face of fierce competition from higher profile companies like Boots and Coots and Red Adair. Today Wild Well Control is likely the leading well control company in the world. Pat was very innovative in his approach to capping design and implementation and was a very astute business man as well. Pat is gone now, as is Joe, Coots, Red, and of course, Myron. The world owes these men a great deal of appreciation for the brave work they did, work that ultimately saved the world valuable natural resources and prevented immense environmental harm.

Men like Pat Campbell were legends, one of kind, colorful characters in the history of the oilfield. Get some rest, Pat; give my love to Coots.

[John_A]

$this->bbcode_second_pass_quote('Oily Stuff', 'T')hanks guys, it seems the best we can do is simply rely on what the shale boys tell us these wells cost. In spite of your best efforts, and SEC mandated corporate statements, I don't buy into the idea that a 14-15,000 TMD well, with 5K of lateral, and 18 frac stages, can cost 4 1/2 million dollars, landman to gauger. Sorry, no way. But, hey, what do I know?

[Oily Stuff]

John A, we should all simply agree that these are very expensive wells, these tight oil efforts. And it is good to listen to all the hubbub these public companies spew forth and not necessarily accept it, to try and blow holes in it. Leo is on an tight oil mission of abundance; don't worry, be happy.

I have seen frac invoices for over 3M, a source water well to the Carrizo Groundwater formation in S. Texas is 300K; casing the shale well, top to bottom with 5 1/2", cementing that and 3000 feet of surface casing, with hardware, 400K, minimum; man the locations those guys build alone are 300K. That's over 4 million already, without lease acquisition and production facilities. Oh, and without that big mama jama rig out there rotating away for 2 weeks, at 90K a day with condiments.

It matters only from the standpoint that we need to understand how slim the margins are these shale fellers work for and how precarious this shale boom is. Seventy dollar oil would change the complexion of all this tight oil thing almost instantly. Look what happen to the shale gas business just a few years ago. The liquids party could end almost just as fast. My side of the oil and natural gas business is from Mars, those shale dudes are from Pluto, IMO. Its not even the same business.

It was a great honor to work for Boots Hansen and Coots Matthews, thank you. They were the best.

[ROCKMAN]

Notice that after the tremendous improvement in drilling efficiency including cutting down drilling time and rig movement time the costs have been reduced to $6 to $12 million per well. And bear in mind that there is no such thing as an “average EFS well cost”. The reason for that wide range is that some wells can only be drilled with shorter laterals to comply with the regs. Shorter laterals also mean fewer frac stages. Shorter laterals with fewer stages typically mean a less productive well. Which also implies that there is no “average productivity” of an EFS well. A company can post their average cost to drill and complete a well but that number is meaningless unless you have the specifics of how those wells were drilled. And the companies never release that data.

Folks can make a projection based on recent reduction in costs and project it to even greater cost reduction. But a meaningless stat IMHO. If they want to be credible they need to explain how those new cost savings will be achieved. Wells are now being drilled as fast as possible according to the folks who are actually drilling the wells. None of the components are getting cheaper: the rigs, the casing, and the frac’s. From the folks who actually sign the invoices on a daily basis: those costs are not decreasing. What has saved money has been the reduction from spud to spud period. No one I know actually drilling the EFS is expecting any significant change in that metric now. The learning curve has been maxed out IMHO.

From: http://www.aei-ideas.org/2013/03/eagle- ... ale-facts/

“Most of these facts about Eagle Ford Shale come from Ted Reed, vice president of operational efficiency for Houston-based Baker Hughes, who was quoted in this San Antonio Express-News article “Eagle Ford Economics Makes Lots of Sense.”

1. The threshold level for drilling a profitable oil well in the South Texas oil and gas field is somewhere between $50 and $57 per barrel (see chart above). West Texas oil is currently selling for about $90 per barrel.

2. Texas now has more than one-fifth of the world’s drilling rigs.

3. The Texas Railroad Commission report at the end of February that it issued 1,978 drilling permits in January, a 25% increase compared to 1,581 permits issued the same month last year.

4. Two years ago, it took more than 30 days from the start of drilling one well to start the next one in the Eagle Ford. Now it’s taking only about half that time – 16 days, on average. That means operators can run fewer drilling rigs, but drill just as many wells as they did previously.

5. Eagle Ford wells now cost $6.5 to $12 million to drill and complete, and then pay off in three years on average.

6. According to Reed, “There are a lot of people making money out here. Unless the oil and gas operators are making money, this [boom] doesn’t exist.”

So yes: the EFS is still economic to drill in general. And as long as oil prices stay high the play will continue strong. Until most of the viable locations are drilled and then the play will die regardless of the price of oil. Just as every play has ever done since the beginning of the oil age.

[John_A]

$this->bbcode_second_pass_quote('Oily Stuff', 'J')ohn A, we should all simply agree that these are very expensive wells, these tight oil efforts. And it is good to listen to all the hubbub these public companies spew forth and not necessarily accept it, to try and blow holes in it. Leo is on an tight oil mission of abundance; don't worry, be happy.

[dcoyne78]

I have attempted a more realistic model with 1800 wells/year and prices rising similar to the EIA Ref scenario. Real well costs decrease to 6 million at an 8 %/year rate of decrease and then decrease at 1.2 % per year. I assume an 8 % discount rate, $12/barrel transportation costs, 25 % royalty and taxes, and $7/barrel OPEX plus financial costs and an initial well cost of 9 million (before costs start to decrease). Breakeven costs are considered and wells added decreases as these are reached in 2026. Note that NPV=net present value which is the discounted net revenue for the average well, in this case calculated over 15 years.







DC

[Pops]

That's great DC, very cool.

So between this and the first you posted we get a possible range. Interestingly they both peak in the late oughts.

[dcoyne78]

$this->bbcode_second_pass_quote('ROCKMAN', 'A')nd again I'll ask the same question: if the number of wells drilled for the Bakken is to significantly increase then what metrics have to significantly change? First, the number of rigs drilling. They might be saving a little time skidding the rigs but that's already happening...not just in the future. Last stats I saw the rig count was flat to maybe a tad down? And there are still thousands of leased locations waiting for a rig. The companies don't appear to be restricted by a lack of capital.

So simply other than just arbitrarily predicting the well count will increase it would be nice to see what expectations justify that assumption. At least something beyond wishful thinking. I can accept any reasonable explanation but I need to see it offered. It seems that the debate starts after the assumption of an increased well count is accepted .