[sparky]

.
Rockman , what does ted Reed mean when he is quoted
"5. Eagle Ford wells now cost $6.5 to $12 million to drill and complete, and then pay off in three years on average."

I'm I wrong or is it 90% of the production , more or less 10%

[ROCKMAN]

DC – “So there does not need to be any change, just more of the same.”. Something of a contradiction IMHO. More of the same means some big changes: more capex spent, more rigs running, more hands hired, more service companies working, etc. That was the reason for the increased drilling activity. I would take more of the same to mean holding activity flat. To reach the rig count being projected would require a lot of change.

The number of rigs running had been increasing significantly a year ago. But this isn’t a year ago today. The rig count has been flat to down a bit at time this year. And it shows in the drop in Bakken oil production we’ve seen this year (http://bakkenshale.com/drilling-rig-count/). The improvement in efficiency has helped but those factors have already kicked in so where would the additional gains be seen? Based on current stats there no reason to believe there will be any significant increase in rig count, number of wells drilled or production added. In fact, even a small increase seems possible.

But, as you say, there are multiple factors that create the end results. And it’s just as easy to slap positive or negative expectations. But in another few months well have the full 2013 stats to look at to give a better view of the current dynamics. But even with those numbers it doesn’t forecast activity in 2014+ in stone.

[ROCKMAN]

sparky – I’m not sure I understand your question about 90% vs. 10%. But as far as the meaning of #5: the payout of the well is typically the time it takes to recover 100% of the drilling/completion costs less the royalty, production taxes and operating expenses of a well. A 3 yr p/o isn’t bad but doesn’t represent an outstanding rate of return. Typically we’re always hoping for a p/o on the order of 12 months. Obviously our hopes aren’t always met. LOL.

But there’s also the potential for a little dishonest spin: it might take me 3 years to p/o the drilling cost of the well: a true statement. But I also spent a good deal of capex to take that leases, buy the seismic and pay my staff. And none of those expenses were used to calc the p/o I just presented. Nor did I include the cost of acreage I don’t drill and end up releasing. At least a year ago the SEC started issuing warnings to public companies that were putting out big press releases about how much their drilling efforts were costing but weren’t including the hundreds of $millions spent on leases, seismic and other overhead.

The wide range of costs reflects that not all such wells are drilled the same. Due to regs an operator with a small lease might only be able to drill a 1,200’ lateral. And such a lateral might only have 6 frac stages. OTOH on the much bigger lease immediately offsetting that 1,200’ lateral an operator might be able to drill a 5,000’ lateral and hit it with 20 frac stages.

That’s why it so difficult to judge these plays in a general sense. On top of the wide variation in well costs you then add wide variations in results. In the above example due to variations in geology the shorter $6.5 million well might flow at twice the initial rate of the $12 million longer lateral. But it wouldn’t be impossible for the longer well to ultimately recover more oil than the shorter well…would just take longer to do so. You can even find a good bit of variation due to what company drilled the wells…not all are as good at it as others are. And then there’s the time factor: the learning curve can build very fast in one portion of a trend.

Without factoring those and other details it’s nearly impossible to define a “typical” or “average” well IMHO.

[TheServant]

Hi all,

New member, but have been following sites such as this, Oil Drum, etc for 6 or 7 years.

Just curious on any take on the number of new wells being drilled in the Texas tight oil plays recently. (~4000/yr EFS & ~9000/yr Permian). I would assume, if I am reading this right, that once this level of drilling in TX tap out these plays (2 yrs, 5 yrs, 10yrs?), this level of drilling activity would, in part, shift to Bakken, assuming oil prices continue to hover around $100/barrel. I see one of DCs recent models assumes an increase to 3600/yr. For the sake of argument, what if it climbs to somewhere closer to 9000/yr?

Forgive me if the link doesn't show up as this is my first go at it. It seems this article, or one similar to it was just posted in a thread during the past week, but darned if I can't find it.

http://blog.mysanantonio.com/eagle-ford-fix/2013/07/four-quarters-4092-new-wells-in-the-eagle-ford-shale/?shared=email&msg=fail

Thanks.

[dcoyne78]

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. ....

Hi Rockman,

I know you are fond of saying there is no such thing as an average. I would disagree, the concept is not always useful, but just because all wells are not the same does not mean there is no average. Lets take for example oil wells (as defined by the RRC) in the Eagle Ford trend. I took a sample of the data from the RRC in December of 2012 for the Eagle Ford 2 field (I realize it is a trend, but in the database they call it a field), I took about half (first half of the alphabet as they are listed alphabetically) of the producing wells and looked at the month to month production from first output and defined this as the "average well".

As you know, this is tricky because the RRC doesn't give individual well data, it gives the production on the lease, which in many cases has multiple wells completed at different times. So I threw out leases with multiple wells if the wells were completed at very different times (if they were within a month I used the data) and if say 4 wells were completed within two months and then 5 more wells were completed 15 months later, I used the first 14 months for the first 4 wells and ignored the rest of the data. This is because I could only guess at which output was from the newer wells vs the older wells. This "average well" will change over time, especially as the sweet spots become fully drilled. For charts below data is the average of 251 wells in 175 leases starting production between August 2010 and June 2012 (data collected in Dec 2012) with output between 5 months and 24 months. The average completion costs I don't have data for, but if I did, the average would be the total completion costs for all wells divided by the number of wells. Does this mean all the wells are exactly the same? No, but if gives a rough idea that if we drill a hundred more wells the total cost will be roughly 100 times the average. If drilling costs were increasing or decreasing over recent months, one would use the cost per well over the past 6 months or so to get a better estimate, it is not perfect, that is why it is called an estimate.





Edit: this data is from the Eagle Ford 2 field, I remembered incorrectly.

DC

[rockdoc123]

for those interested in understanding the economics of the various shale plays there is a very detailed article that was posted on PO news at one point

http://www.ogj.com/articles/print/volume-111/issue-4/exploration---development/economics-fiscal-competitiveness-eyed.html

it breaks down the analysis into jurisdictions, takes into account lease costs, full in drill costs etc. The only piece I can see missing from their cost calculation is G&A which is always a bit of a moving target as it tends to be amoritized over the whole of your business (bad for the small operator, good for those with lots of activity).

I used to use the discounted profit to investment ration (which they calculate for various jurisdictions across NA) as a first look at whether or not a project was worth pursuing. In general a DPI of 0.3 or higher is attractive in a large portfolio. Of course if you are a small company betting the bank on winning big that won't work for you. What jumps out is that for Canada the level of DPI can be achieved down to 100,000 bbl EUR/well whereas in the US jurisdictions it appears to require 200,000 bbl EUR/well.

When thinking about this topic it is important to remember it is the average of your wells that matters, not each individual well. The overall project can still be quite attractive if you have a number of wells that are subeconomic on a standalone basis (but still produce) if they are offset by a number of wells with better than hurdle rate EUR. It is important when looking at shale economics to look at them from a project basis rather than a single well basis. As well there are more costs involved than just drilling and completion that need to be managed (eg: water disposal) which is why the manufacturing approach is important.

[dcoyne78]

DC – “So there does not need to be any change, just more of the same.”. Something of a contradiction IMHO. More of the same means some big changes: more capex spent, more rigs running, more hands hired, more service companies working, etc. That was the reason for the increased drilling activity. I would take more of the same to mean holding activity flat. To reach the rig count being projected would require a lot of change.

The number of rigs running had been increasing significantly a year ago. But this isn’t a year ago today. The rig count has been flat to down a bit at time this year. And it shows in the drop in Bakken oil production we’ve seen this year (http://bakkenshale.com/drilling-rig-count/). The improvement in efficiency has helped but those factors have already kicked in so where would the additional gains be seen? Based on current stats there no reason to believe there will be any significant increase in rig count, number of wells drilled or production added. In fact, even a small increase seems possible.

But, as you say, there are multiple factors that create the end results. And it’s just as easy to slap positive or negative expectations. But in another few months well have the full 2013 stats to look at to give a better view of the current dynamics. But even with those numbers it doesn’t forecast activity in 2014+ in stone.

Hi Rockman,

What I am claiming is that the rate of increase in the number of wells does not need to increase, in a future post I will show on a semilog plot that the rate of increase in wells added even in Maugeri's scenario is decreasing, I think it will decrease to between 5 and 10 % (from about 40 %), but I doubt it will decrease to zero unless prices drop to $75/barrel (current break even price for the Bakken), it could happen, but only with an economic crash. I think a slight rise in prices is more likely and if (and I think that should be capitalized) well completion costs also fall, even to 8 million, flat well additions (1800 wells/year) seems unlikely. Time will tell.

I agree that the scenario is optimistic, in fact I would be surprised if 3600 wells/year is reached in the time frame Maugeri suggests, I was just trying to create a scenario based on his assumptions to see if it looked realistic. One comment on the rigs and completion rates. My understanding is that the number of rigs needed to drill a given number of wells depends on how efficient various companies are in drilling ops, not all companies are the same, as the leaders become more efficient other companies play catch up and become more efficient as well. You think this dynamic has played itself out in the Bakken and all companies have reached their limit in improving efficiency. Based on reporting from North Dakota companies are claiming that they can bring completion costs down further. Also the current bottleneck seems to be fracking, I am not sure if the rig count is all that relevant if that is correct, though I am clearly not as falmiliar with the oil industry as you, so please correct any and all mistakes I make, I appreciate your feedback.

DC

[Pops]

The Director's Cut says the backlog is in completions, 90 days waiting list in May and 500 wells on the list.
Yes it could be the weather in whole or part.

[dcoyne78]

The Director's Cut says the backlog is in completions, 90 days waiting list in May and 500 wells on the list.
Yes it could be the weather in whole or part.

Pops,

Weather has played some part, but there seems to be a lack of fracking ability (that is not enough crews/equipment) so the impression that things are going flat out (by those in the know) seems correct.

At some point the bottle necks may work themselves out, but this points to increased well completion costs (in order to attract more crews and equipment) rather than the reverse.

It could work out that these two forces (there's that dynamics again) balance (increased operations efficiency vs increased costs to attract fracking services) and completion costs may stay flat. As Rockman likes to remind us it's complex.

DC

[dcoyne78]

sparky – I’m not sure I understand your question about 90% vs. 10%. But as far as the meaning of #5: the payout of the well is typically the time it takes to recover 100% of the drilling/completion costs less the royalty, production taxes and operating expenses of a well. A 3 yr p/o isn’t bad but doesn’t represent an outstanding rate of return. Typically we’re always hoping for a p/o on the order of 12 months. Obviously our hopes aren’t always met. LOL.

Hi Rockman,

Lease costs are excluded? Also I assume the future cash flows are discounted, what is the typical annual discount rate? My average Bakken well barely pays out to 9 million after 3 years (at an 8 % discount rate), so if prices drop or well costs go up and a 3 year payout is the minimum acceptable level, then you are absolutely correct that the wells added will not be increasing (and they may decrease) unless well completion costs go down or prices go up. Maybe the three year payout is not an NPV type of calculation?

I used an oil price of $102/barrel, but deducted the $12/barrel needed to get the oil to the east coast where they can probably get the Brent price at the refinery gate, I also used a 25 % royalty and tax rate at the well and assumed other costs of $7/barrel (OPEX and financial costs). For a low risk adventure like the Bakken, would oil companies possibly accept a 5 year well payout?

DC

[Pops]

Weather has played some part, but there seems to be a lack of fracking ability (that is not enough crews/equipment) so the impression that things are going flat out (by those in the know) seems correct.

At some point the bottle necks may work themselves out, but this points to increased well completion costs (in order to attract more crews and equipment) rather than the reverse.

It could work out that these two forces (there's that dynamics again) balance (increased operations efficiency vs increased costs to attract fracking services) and completion costs may stay flat. As Rockman likes to remind us it's complex.

DC

My comment about the weather was for the Bakken Boosters here at PO.com, another "dynamic" altogether, lol

I've been posting fairly regulary that growth has been slowing since last may.

Here is a Director's Cut snip from last Sept.

Great weather for drilling and hydraulic fracturing activity resulted in a 1.4% production
increase from June to July. That is the smallest month to month percentage increase since
April 2011. The combined effect of several factors has led to a noticeable slowing of
activity and production growth. Rig count has decreased significantly to around 190-195
as operators transition to higher efficiency rigs and implement cost cutting measures.
The idle well count increased significantly indicating an estimated 394 wells waiting on
fracturing services. Rapidly escalating costs have consumed capital spending budgets
faster than many companies anticipated and uncertainty surrounding future federal
policies on hydraulic fracturing is impacting capital investment decisions.

The Directors Cut is a pretty straight ahead commentary:
https://www.dmr.nd.gov/oilgas/directors ... rchive.asp

[ROCKMAN]

DC – yep…not an uncommon practice for public companies to report just what the actually drilling/completion costs were and leave out the other expenses. Technically not a lie but given the hundreds of $millions companies had tied up in leases it starting getting the SEC upset. Those costs don’t terrible effect the individual well economics but when taken of a company-wide basis those are serious level cash outflows. A lot of companies went very negative on their books when the shale gas plays went south because of huge book write downs more for their undrilled acreage then their NG production.

A 5 year payout is nothing to brag about. You can often buy pure production properties around that level. But for a public company (which most shale players are) that could be a gold mine. Remember those public companies are constantly being pressured by Wall Street to add booked reserves. A 5 year payout might generate less than a 6% ROR but that’s not nearly as important as ever such well adding two or three times the multiple in booked proved reserves. I skip the details I’ve offered before but I’ve seen companies knowingly drill poor wells so they could boost their books and make WS happy. At least happy long enough for management to cash out their stock options.

I get your point about the rig count now. And given how oil prices are acting now I wouldn’t fault a bit of optimism. But after doing this for 38 years I'm always looking over my shoulder for trouble. LOL.

[rockdoc123]

DC – yep…not an uncommon practice for public companies to report just what the actually drilling/completion costs were and leave out the other expenses.

The actual numbers can’t be hidden, they are there in the SEC filings for all publically traded companies and are fairly transparent if you take the time to look.

A 5 year payout is nothing to brag about.

Any one measure of economic viability is never a great thing to hang your hat on in my opinion. As an example a project with a 2 year payout might seem great but if it has net free cashflow of a few hundred thousand dollars a year as compared to a project that has 5 year payout with a hundred million a year in free cashflow I can tell you which one I would take if I had access to the requisite capital. The same can be said for measures such as discounted profit to investment ratio where you could have a very attractive DPI with a very small NPV and a much less attractive DPI with a very large NPV. Again the decision on which you would do may be exactly the opposite of what you might think. That`s why I always liked to look at a string of measures including DPI, NPV per BOE, payout, recycle ratio etc.

[dcoyne78]

In an attempt to make Maugeri’s scenario more realistic, I made a few changes to his assumptions.
First I used an average well profile (Model C) which matches the Bakken data quite closely. Compare with Maugeri’s well profile (model M) which was used from Jan 2011 to Jan 2014 (see Figure 2)

Figure 1 well profile


Figure 2, model and data



Maugeri assumes that real oil prices will fall to $65 (WTI Price) by 2018 and then remain at that level and that well completion/drilling costs will fall by 8 % per year bringing the cost from $9 million down to $6 million over 5 years, after that we will assume well costs will remain flat.

I am only changing the oil price assumption by assuming no change in prices. The rational for this is that a rise in prices will lead to an economic slowdown and that a fall in prices will lead to lower output and that these will tend to keep prices at close to the 2012 average of $102.5/barrel (Brent Price).

Break even is reached in 2019 and because the oil price is not rising and well costs are not falling so an equilibrium is reached where it is no longer profitable to drill more wells beyond 21,800 producing wells which is reached in 2019. Total output in this scenario is 6.8 Gb (billion barrels of oil) from 1953 to 2073 which is close to the USGS mean estimate of 7.4 Gb for all of the Bakken . This scenario is for North Dakota only.

Figure 3



Figure 4




Figure 5



DC

[dcoyne78]

Thanks DC I was being facetious, mention of Leo M. puts me in a tizzy, I appoligize.

I'm just wondering how realistic is it to think new wells per yr will double from 1,700 to 3,600 per yr in just 4 years? Is that just continuously improving technique, more rigs or something else?

I'm sure you've noticed that increase in well numbers has been slowing for the last year - at least through may annualized growth has declined from 52%/a to 36%/a

Of course then production growth has fallen too from 66% to 26%
as we speak horizontal rigs going for oil are down 11% from last year
http://www.reuters.com/article/2013/07/ ... 6220130726

Obviously just a snapshot but thought I'd throw it out, whatdda ya thinK?

Hi Pops,

First I do not think an increase to 3600 wells/year is very likely. I try to create several scenarios to cover the various possibilities. Also for the optimistic people like Leo Maugeri, I am trying to show that even if his optimistic assumptions are met and the output is at the F5 level of the recent USGS estimate for the Bakken/Three Forks trend (11.4 GBb) that a peak is reached in 2019 followed by a rapid decline.

I also present a somewhat pessimistic scenario where the number of net producing wells added per year remains at 1800 wells/year (close to the current level of 1769 wells/a) until 48000 wells are reached (that part is not pessimistic, but similar to levels forecast by the NDIC of 46,000 wells). Reality will likely be a slight fall in well costs to around $7 million, a rise in wells added per year to 2400 by Jan 2018 and probably level prices (with fluctuations above and below $100 per barrel which are unpredictable IMO).

Note that the first scenario presented here was the most unrealistic, it has steeply falling well costs matched by falling prices, sharp rises in wells added per year and no decrease in average well productivity until Jan 2018 followed by steep decreases in well productivity to keep total cumulative output for the Bakken/Three Forks to the "reasonable" level of 12 Gb. That scenario also attempted to include both Montana and North Dakota which was why it went to 60,000 wells and other scenarios (for ND only) stopped at 48,000 wells.

I hope to have a post up at http://oilpeakclimate.blogspot.com/ soon covering some of the scenarios for the Bakken.

DC

[dcoyne78]

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.

Thanks pops.

I made a mistake on this scenario with my prices so that the breakeven calculations are off. My apologies.

Corrected chart below:







DC

[dcoyne78]

For the sake of argument, what if it climbs to somewhere closer to 9000/yr?

I think this is quite unrealistic, for that matter 3600 new wells/year by 2018 is also pretty unrealistic. Keep in mind for the Bakken/Three Forks in North Dakota the NDIC predicts about 46,000 wells total, so if 9000 wells/year were possible we would run out of room in less than 5 years (because we only need about 40,000 more wells to get to 46,000).

DC

[Oily Stuff]

Mr. Dcoyne, thank you for your good work in the Bakken. I always find it interesting and I hope soon that you can begin similar work in the Eagle Ford shale here in S. Texas where I do not believe the wells are near as good as Bakken wells.

I make my living drilling for, and producing crude oil and I can assure you of 3 things brought up in your good thread that are not true in the real world, IMO: one, public companies find ways to not tell the truth about costs that they tout to the public all the time; it is part of the disingenuous manner in which they sell stock in their own companies and it exemplifies the lack of truth in advertising about tight oil resources. People interested in our energy future don't have the time to look at the tiny little print in a corporate statement, they want to hear the straight skinny on reserves, decline rates, and well costs on CNBC and in Forbes, from honest people looking you straight in the eye. Rockdoc, I am indeed one of "those" kind of people. Two, no stinkin' tight oil well can be drilled and completed for 4 1/2 million dollars, not including lease acquisition costs etc., not 9K feet deep and 9K feet out, no way, not ever. Costs are going up for me, and everyone else in the oil biz every day, not down. And three (forgive me Rockdoc but I flunked your tight oil economics course long ago and don't need to take it again), if it takes 5 years to pay out an 8 million dollar oil well, whether 5 or 50 wells in your prospect, EOG or Slap Your Pappy Oil Company, you are eventually in big trouble. NPV is only relevant in the equation if you are looking to bail out of that prospect with over inflated reserve calculations. In the real world dollars count.

I am glad those shale guys think they can do for what they do for 60% IRR over 20 years, bless their little confused hearts; we need the oil. But sooner or later, it will catch up to them.

Before you drop off the big scoreboard to the right, thank you for your excellent work.

[John_A]

Mr. Dcoyne, thank you for your good work in the Bakken. I always find it interesting and I hope soon that you can begin similar work in the Eagle Ford shale here in S. Texas where I do not believe the wells are near as good as Bakken wells.

They aren't. You are right.

[dcoyne78]

[quote="Oily Stuff"]Mr. Dcoyne, thank you for your good work in the Bakken. I always find it interesting and I hope soon that you can begin similar work in the Eagle Ford shale here in S. Texas where I do not believe the wells are near as good as Bakken wells.
...
Two, no stinkin' tight oil well can be drilled and completed for 4 1/2 million dollars, not including lease acquisition costs etc., not 9K feet deep and 9K feet out, no way, not ever. ...And three (forgive me Rockdoc but I flunked your tight oil economics course long ago and don't need to take it again), if it takes 5 years to pay out an 8 million dollar oil well, whether 5 or 50 wells in your prospect, EOG or Slap Your Pappy Oil Company, you are eventually in big trouble. NPV is only relevant in the equation if you are looking to bail out of that prospect with over inflated reserve calculations. In the real world dollars count.

Iquote]

Oilystuff,

Thanks. I agree well completion costs are not likely to go from 9 million to 4.5 million.
What about to 6 million with pad drilling and walking rigs (lease costs are not included in any of these figures)? Keep in mind that NPV is what you use to convert future dollars to present real dollars, a dollar 10 years from now is worth less to me than a dollar today so I reduce the value of those future dollars in an NPV calculation.

For the Eagle ford, the research I have done (primarily on the Eagle Ford 2 field) suggests a 10 year EUR of 212 kb for the Eagle Ford vs 259 kb for the Bakken trend.
If we assume well cost of $7 million decreasing to 5.5 million by 2018 and flat after that, oil prices flat at 102.5 dollars/barrel (inflation adjusted), 20 % royalties and taxes, an 8 % discount rate, 7 dollars/ barrel of OPEX and other financial costs, and $3/ barrel transportation costs to the refinery and keep the ten year NPV of cash flow above the real well cost (or else new drilling stops), we get the following:



Let me know if my assumptions above are way off and I'll adjust them.

DC