Thursday, March 10, 2011

Bakken Shale Oil

A look at shale oil:
I have also looked a little more at the Eagle-Ford and Niobrara plays. My conclusion is that all of the producers are seriously exaggerating what they have, but what they have is still valuable.

In the analysis below I have concluded that the Bakken could probably be brought to 3 million barrels/day by 2020 and maybe the sum of the other shale plays could reach a similar level. (Note added 14/8/11 - As pointed out below, there probably is not enough space to drill to ever get to the necessary number of wells, so my conclusion is probably wrong, by a large amount).The USA uses about 20 Mb/d (for me M=million, but in the oil industry it is thousand and MM is million), and imports about 13 Mb/d. I expect imports to decline by 1/2 before 2020. Most of the decline could be offset by rapid development of domestic production, which is now viable due to price and technology. To get there, by my estimates, the industry would have to add about 140 horizontal rigs/year, on average, for the next 10 years. Given the MENA unrest, and the sustained high price for oil, that development now has a high likelihood of happening.

These horizontal wells, on average, seem to be 1-2 miles deep, and near 2 miles horizontal. That's 3 to 4 miles of drill pipe per well. 60,000 wells in the next 10 years could mean 200,000 miles of pipe. I don't know how much steel is in a pipe, but let's guess that 1 car equals 200 feet of pipe. That comes to about 5 million cars over 10 years, or about 4% of USA annual car production. I am surprised that it is that small. Even if I'm off by a factor of 2, we could supply all of the pipe just by building 5% fewer cars at 5% less steel per car. Given the expected increase in gasoline prices that is almost certain to happen anyway.

However the big limitation is environmental. Getting to 3Mb/d in the Bakken means drilling 30,000 producing wells by end 2020, and drilling near 5000 wells in the single year of 2020, vs about 500 in 2009. Where does the water come from, and how is the contaminated water treated for multiple frac'ing of 30,000 wells, or 5000 wells per year? Technically it's feasible, practically I'm not so sure.

Some urls:

My analysis:

Looking at Continental Resources’ (CLR) and Brigham’s reports we find one excellent consistency and a couple of major inconsistencies.
Brigham’s average production of 1800 b/d for the first week, 1100 b/d for the first 30 days, and 830 b/d for the first 60 days falls on a smooth curve that includes CLR’s 450 b/d for the first 90 days. This curve implies a production rate of 90 b/d at the end of the first year, only 5% of the first week’s average production rate.
If we take a production rate at the end of the first year of 100 b/d, declining to zero at the end of the 10th year, we have 165 kb for those 10 years. Add in the 75 kb from the first year and we have 240 kb EUR. This is a long way from the 300 to 400 kb EUR projected by CLR in their EUR vs frac stages chart. Their median EUR projection seems to be about 360 kb which is still high vs the decline curve, but much lower than the 518 kb they have modeled. Very strange.
I have tried curves using the 30, 60, and 90 day average rates as end of period rates, or as average for each of the first, second, and third 30 day periods instead. Thus I have a range of EURs from 240 to 410 kb, with a middle value about 340 kb. However the low end is the one consistent with both companies’ real wording. The safest EUR number to use is probably 250 kb/well.
In their curve of IP vs EUR Continental shows a first 30 day IP of 600 b/d corresponding to an EUR of 500 kb, and a 30 day average IP of 1000 b/d as an outlier vs 1100 as an average for Brigham. However a 30 day IP of 600 subtends a 90 day average production a long way below 450b/d, and therefore a much lower EUR. CLR’s EUR estimates look totally unrealistic, and inconsistent with their other data.
There is a lot of inconsistency in the Continental data. Their 30 day production rate curve vs frac stages must be for a lower producing set of wells than the 90 day curve.  Both curves suggest that anything over 18 stages is well into diminishing returns. Near 15 stages looks optimum.
From Nov ’09 to Aug ’10 CLR has gone from 4 to 18 rigs, and from about 25 to about 33 “days on well”, about 10 wells/rig/yr at end 2010.  Elsewhere they report 800 “gross” wells for 562 “net” wells. This would suggest 30% non-producers, , ie 7 producing wells per rig per year.   With 164 rigs  in Q4 2010, one would expect an average of at least 120 for the year, providing less than 700 new wells. A judgment call would suggest 6 producing wells per rig per year.
CLR then shows about 2300 wells producing in the Bakken at mid 2010, of which 2075 are horizontal multi frac wells. 2300 wells produce about 350 kb/d at end 2010, or 150 b/d/well. It looks like there were 400 wells added in 2007, 550 in 2008, 500 in 2009, and > 600 in 2010. An average production in the first year of 500 b/d/well, declining to 160 in the second year, 80 in the third year and 65 in the 4th year, etc.,  would give us near 150 b/d/well at end 2010, which is consistent, and is also consistent with an EUR of about 250 kb/well. So we now have some numbers to project future growth in output.
CLR claims there were 164 active rigs working in the Bakken in late 2010. If we add 60 rigs per year to 2020, and maintain 7 wells/rig/yr, and if my calculation is correct, we would be producing 3 million barrels/day in 2020. If present production declines by 4%/yr through 2020, we would have a net gain in output of 0.5 million barrels/d to offset declining imports, 10% of the expected decline if we are lucky.

See, (8/14/11) and especially note this contribution from Rockman
FOR ALL Another meaty story by HO...mucho thanks. I've never worked this trend so have nothing to contribute in particular about it. But I want to point out to those who don't appreciate why this is an "unconventional" play. HO's general decline curve says it all. This is not a field in the conventional sense. It is a "play". Compare to the Mother of conventional fields: Ghawar. It is still producing a significant volume after many decades. But more important: many of the original wells are still producing. They have periodically drilled new wells to enhance recovery but the main reservoirs are still prodcing. HO’s decline curve clearly shows the Bakken is a very different animal. Original Ghawar wells came on at 5,000+ bopd and held there for decades. For the most part a Bakken well’s production becomes relatively insignificant after several years compared to thir imtial rate. There is some history of success re-frac’ng such wells but seldom as valuable as the initial completion.
No doubt the Bakken, Eagle Ford and similar unconventional plays will add significantly to our reserve base. But at a cost that requires higher oil prices. But it’s still important to remember there is an end to this road also. These are not the first major fractured oil reservoirs to be developed with frac’d horizontal wells. The Austin Chalk (a “limestone” shale) had it big day in Texas. Same big initial rates, same decline rate profile, same boost to oil production, same hype. And for the most part the play is dead even at current high oil prices. And for a simple reason: almost no more drill sites left to poke. In fact the current boom in Eagle Ford drilling is a result of the decline in AC drilling: it’s one of the few oil plays left in Texas. And in time it will be fully developed just as the Bakken will. And once most of the finite number of locations is drill the oil rates will drop off a cliff.
These plays can help give us some breathing room. But they don’t change the game significantly IMHO. Would be nice if we use this crutch to give us a little more time to make adjustments to PO. But I have my doubts.

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