[ROCKMAN]

DC - Difficult to predict future costs using histories for the last 5 to 7 years. First, more recent wells have much longer laterals and mucho frac stages. But that also means fewer wells per acreage positions. Prices could be normalized on a footage basis. But then you need to see 4 or 5 years production history to normalize results.

One of the big savings factor has been a very big reduction in drill time. But such gains on that order can be made in the future. As you know there are physical limits. Fast mob/multipad drilling saves some money but those are in place now. Not much more improvement possible IMHO.

And then there's the learning curve with respect to sweet/sour spots. And that varies from company to company as well as variations in the potential variations in one company's acreage and anothers. And lastly not all companies do the job as good as others.

Very tough task indeed.

[Oily Stuff]

DC, I understand NPV very well, I simply fail to see it's significance in tight oil economic discussions. My bad, I suppose, as I am old school and when I make a decision to drill or not to drill a well it is based on well costs, risk, estimated time to pay the well back, product prices and ultimate estimated return on investment over the life of the well. The net present value of an income stream is only relevant to me if I am selling production, or buying someone else's income stream. I am not a public company, it is not necessary for me to impress others, or myself with reserve studies; for lack of a better description my business plan has always been to hold on to every barrel of production I find like my life depended on it. Since I started just north of standard derricks, oil prices are up nearly 1200%.

Having said that, I guess NPV is important to folks having to wait 4 years to get their money back on development costs. I always like to get my money back in less than 18 months. Four years to pay out, with 25-30% annual decline rates and I would have died at an early age from stress. Or become a horse shoer.

To understand how tight oil sources will play out relative to our energy future in America that facet of my industry, clearly different than mine, needs to tell the truth, to not hide the important details in corporate statements. I do not believe that it is telling the complete truth. Are these well profitable enough for Americans to count on 40,000 well bores and 5 million barrels per day? I personally do not think so. There endenth my rant for the day.

Your 10 year EUR's are very similar to my guesses via DI data in the EF sweet spots. Outside the carpet bombing that the bigger companies do in what they believe are sweet spots (hard to tell sorting thru 19 wells in one unit exactly how sweet), in the not so sweet spots, less EUR and many, many wells in the EF, will not pay back costs.

If I may: I think the LLS to WTI premium thing is about gone for the EF, plus/minus 3-5 bucks over WTI, no more 15-18 dollars, regardless of volume, IMO. We are saturated with crude oil along the GC at the moment and that's only going to get worse. I cannot even term up my oil at the moment because the market is so volatile. So going forward I would count on WTI prices and that's about it. I think the net price per barrel those tight oil guys make, after this and that, is 65 dollars. What I cannot discount from that is the cost of borrowed money. Would it not be considerable?

And lastly, if I may, let us not assume that drilling costs are going to go down, on average, in any tight oil play simply because Leo says they will. Where is the data to substantiate that? I won't go into that but it astounds me that anyone can say that costs will go down, in anything, over the next 5 years. That would be the first time for me. My costs, for instance, since my first well 40 years ago, are up over 400%. Year to year they have never gone down. Lower well costs is faith based optimism, I guess hoping for more technological break thru and/or making the mistake of listening to CEO's on CNBC and believing them. When I have the time, and care, which I don't either, I cannot AFE those EF wells, with average lateral lengths and average frac stages, at anything less than 7 million dollars. Maybe they can whack off a few days of rig time, and moving costs, by sliding a rig around on the same pad, big deal. A week of reaming and lost circulation, a stuck BHA and not so average well costs are above 8, easy.

Now lastly, promise, I don't think well costs are going to go down because I think the water situation in S. Texas has reached critical mass. I hear Lessors are now fussin' about water, big time, and are thru watching the ESP's in their Carrizo wells need to be lowered every month and the TDS of that water go up, up, up. Some of these shale dudes are trucking 150,000 BW for frac'ing, 50 miles or more. Figure 50 cents a barrel, plus 4 hours of trucking at 120 an hour, 160 BW per truck, that's 4.00 a barrel, there abouts. We are in the worse drought in history in Texas, prolonged and very, very severe. My prediction is that rig counts will go down in the EF soon because of the W word.

It would be a mistake to assume anything associated with drilling these shale wells is going to go down. Product prices will go down, not costs.

So, 212,000 BO x 60 dollars a barrel, net = 12.5 million dollars and they have spent 7- 8 million to get that. Sorry, that's ugly.

But God bless 'em.

[TheServant]

DC,

First, thank you for responding to my earlier post. I figured 4000-9000 wells/yr in the Bakken was wildly optimistic, but thought I would throw it out there since it is apparently feasible (at least in TX) given data from the 2 TX tight oil plays.

This calls to question how long this kind of drilling can be maintained in the Texas plays. If I am eyeballing your first model on Eagle Ford, it looks like it has about 3000 cumulative wells drilled by mid 2013. If the previous article I linked is accurate and 4000 or so wells have been drilled in the past 4 quarters alone, it seems to be running well ahead of this first estimate. Perhaps active drilling in this play will wrap up before 2020 instead. Hard to say.

Still trying to envision where those rigs will go in several years once room for new wells begins to run out in the TX plays. I find your modeling interesting. Certainly a difficult task given all the variables involved. Thx.

Dave

[ROCKMAN]

OS - I agree with you about the unlikely decrease in cost. Maybe a bit for $'s per foot. But the shales will prove to be very valuable...for the US consumers. They don't need to be concerned about NPV, ROR or payout time. The shales are adding to domestic production. If not reducing prices much at least reducing our trade balance. A great wealth transfer to mineral owners, service companies and state tax collectors. Management and staff ain't doing to shabby either.

But someone loses: shareholders. And while it may just be me being politically incorrect again, I'm not going to lose much sleep worrying about them. You pays your money and takes your chances. Not much different than blowing your wad in Vegas. I've seen too many folks their money at stock with no idea of what they were doing. Just succombing to greed.

Always going to be winners and losers. The mineral owners, the state revenuers, the hands, the consumers and the govt trade balance wins. I can live with it. LOL

[Oily Stuff]

RM, exactly: shareholder equity will ultimately suffer when the drilling treadmill can no longer be sustained. When the drilling stops things will go not down the hill, but virtually over the cliff.

I do not believe personally that even the biggest of tight oil players can do what they say they can do without continuing to borrow enormous amounts of money. My question would be, what is, what will the total indebtedness of public, tight oil companies ultimately be and are they servicing that debt in such a manner that when they can no longer grow, or sustain production income streams will that debt be paid. Or will lending institutions that loaned the money be hung out to dry and need to be bailed out...by us? Far fetched? Maybe. Maybe not. CHK has been selling other tight oil assets to reduce their debt liability, what happens when those tight oil assets are actually plugging liabilities, production income is screaming down at the speed of sound and there are no more willing buyers? As we both know a dry hole, or a well that is depleted can't then be sold like a cow, or a duplex. When it's gone, brother its gone, right?

[ROCKMAN]

OS - I worry even less about the bankers then the shareholders. LOL. Really. If the path follows past meltdowns, like in the early 80's, the public won't likely be bailing any of them out. Perhaps I've dealt with bankers more than you and seen how good they are at covering their butts. Take CHK. No matter how bad they implode I doubt they'll ever go bankrupt or dissolve. Typically when it gets that bad someone, like ExxonMobil, will take them over and assume the debt in the process. The hit will fall on the shareholders. Like all booming stock plays the trick is to know when to bail. Doesn't matter if it's homebuilders, dotcoms or shale players: buy low...sell high...and for Dog's sake don't get greedy and hang in there too long.

I've worked for some small pubcos and have watched it up close and personal. For the most part it really is a rigged game. I've told the story about pissing away $18 million to drill hz wells that, while increasing production rate greatly, didn't add $1 of new reserves. And the stock boomed. And eventually the last shareholders got slaughtered when the company filed bankruptcy and was taken over by another pubco. The last hanger-ons got about $0.05 for stock that had topped out over $5/share. One silver lining: the biggest hit was taken by a Wall Street raider that did a hostile take over of the company. Some just Karma there. LOL. But all the facts were there in the annual report if they took the time to read it. But they didn't: they just greedily swallowed the Kool-Aid the brokers fed them. A travesty but completely legal. I just hope I can finish out my career by not working for any publco.

[rockdoc123]

I do not believe personally that even the biggest of tight oil players can do what they say they can do without continuing to borrow enormous amounts of money. My question would be, what is, what will the total indebtedness of public, tight oil companies ultimately be and are they servicing that debt in such a manner that when they can no longer grow, or sustain production income streams will that debt be paid. Or will lending institutions that loaned the money be hung out to dry and need to be bailed out...by us? Far fetched? Maybe. Maybe not. CHK has been selling other tight oil assets to reduce their debt liability, what happens when those tight oil assets are actually plugging liabilities, production income is screaming down at the speed of sound and there are no more willing buyers? As we both know a dry hole, or a well that is depleted can't then be sold like a cow, or a duplex. When it's gone, brother its gone, right?

I've spent some time going through CHK financials and management report to SEC. I think I've mentioned before that the level of debt they currently have when compared with their net cash flow is not that high with respect to other public companies of that size. As you say being able to cover carrying charges and still pull in a profit is paramount but CHK is in a good spot due to their operating policy of securing large land positions in new plays. As the play gets proven up they can hang onto the best acreage and either sell or farmout on a leveraged basis the acreage that isn't as good. As an example in the last couple of years they have been able to fully fund their aggressive drilling campaign from asset sales and farmouts which leaves the free cashflow (a couple of billion I believe) to handle debt carrying costs and eventually retire it. Given their debt is probably secured I suspect they may be paying as much as $130 MM/year in carrying charges which still leaves them a lot of cash. The plan with all of the shale companies is not to continue drilling at a hectic pace. These companies are all convinced of the hyperbolic decline model and as a consequence there is a point where most of their wells are in the decades long predictable low output level that when stacked up is good steady cashflow requiring little in the way of capital expenditure and minimal operating costs. Of course then we are back to arguing about the decline model.

Another point I'd like to make is some here seem to think that in public companies insiders can run up the stock price and then sell off their shares at a huge profit. Nothing could be further from the truth. Having worked in a few of the small independents at the senior management and officer level I can tell you that your opportunity to sell shares is very, very limited simply because there is always something going on that is material information that has not been disclosed to the public. Programmed trades, whereby you specify a certain amount of shares to be sold on a regular interval is very difficult to execute in practice as you have to institute them at a point when everything is public knowledge (almost never the case). As a consequence if you are an insider the only real chance you have for a payday is if the company is successful and can be sold which effectively frees up management to sell their shares. In my experience investors who watch the signals have a much better chance of not losing their shirts than the management of a particular company does simply because investors can sell whenever they want.

[Oily Stuff]

Rockdoc, I appreciate your consistent and passionate defense of the tight oil, public companies. You live and work in that world, I don't. I never did and like RM, I don't intend to, ever.

The ability to fund an aggressive drilling campaign can be partially funded by liquidating unwanted acreage positions as long as there are willing buyers with their own borrowed money available to acquire that acreage. As the bloom falls off the shale bushes that is less likely to occur. In my part of the S. Texas EF play tens of thousands of acres leased 3 years ago is simply going to be released. Dropped, not perpetuated. BHP has written down vast amounts of their acreage position from Petrohawk; the American tax payer took the hickey on that. Folks who bought CHK acreage in the Utica probably can't give it away now, or in the Marcellus NFZ ( no frac'ing zone); lets ask Rex how he feels about his shale acquisitions. There will be less of that sort of inner breeding, IMO. Besides, how are those big guys going to stay on the drilling treadmill if they are selling acreage?

If the plan is to not drill so aggressively going forward that is contrary to the 40,000 well, 5 million BOPD, energy independence plan I hear ever day from fellas like Leo and I am a tad bit confused by that part of your statement. They may believe in hyperbolic decline rates with long fat tails but that does not mean that's what they will get. The "reservoir" they drain is only as big as the frac radius they create. If we went on the hunt for fractured AC wells drilled in the 80's that produced 20 years we would be hunting a long time. We'd find a few that lasted 10 years, but not many. I am kind of a fan of Webble Telescopes work over at TOD; if these wells can produce at stripper well levels, which I doubt, the incremental lift costs per barrel are going to be astronomical. $50,000 dollar rod jobs don't work too well on 8 BOPD wells.

This seems timely to my previous post regarding debt: http://www.theoildrum.com/node/10139#more

Lastly, I know you think I am dumb but actually I don't believe that CEO's use embellished, partially omitted or somewhat altered statements about their companies tight oil performance for their own personal stock gain. I think they have a fiduciary responsibility to their shareholders to keep a happy face. And to their lenders. And the prettier the picture they paint the more likely they are to be able to keep the little hamster wheel turning.

RM is legitimately concerned for shareholder equity; me too. You are absolutely correct also, shareholders have the ability to bail. The best I can hope for is that they know when to bail. Its part of the reason this debate regarding truth in tight oil advertising needs to continue.

[rockdoc123]

If the plan is to not drill so aggressively going forward that is contrary to the 40,000 well, 5 million BOPD, energy independence plan I hear ever day from fellas like Leo and I am a tad bit confused by that part of your statement.

I think there is a big difference from the political machinations of folks out there talking about energy independence and the shale gas operators who could give two hoots about that, all they care about is making money. It would be nice to think of them all as being altruistic, America First…yada yada yada, but the reality is they are more like Aubrey McClellan…what’s in it for me. Luckily there are laws that control what they can and can’t do.
From that perspective the bigger shale players like XTO and CHK aren’t about continuous growth, they realize that there is a limit which is controlled by capex requirements and service company availability as well as ever dwindling land opportunities. This is why in Canada there were a number of these companies that went to the income trust model before the gov’t closed that part of the business which they saw as a huge tax leak. I need to mention I’m retired now, have been for a couple of years but still pay attention to what is going on. When I was involved in this business our model was not dissimilar to CHK (we hired a few people away from that organization) which was OK…what sort of relatively predictable cash flow would we like to see for a decade or more assuming oil prices hold steady. Based on that we (believing in the hyperbolic decline story) planned several years of continuous drilling activity that would get us to that point. Of course the best laid plans of mice and men gang aft aglay and overabundance of gas, market crash, tight equity markets all conspire to make companies adjust those plans. Hence CHK and XTO taking write downs in very dry gas acreage (not a lot of the shales have breakeven prices below $3/Mcf when there are no liquids involved) and as you point out having to hold off on activity in parts of the Marcellus due to the NIMBY lobby. They gradually refocus their activity but as I’ve also said previously the very liquid rich parts of the shale are also problematic because the delivery rate isn’t as high as it is in the more gassy overpressured areas. There is actually an ideal liquid richness that works best at current prices. That being said it doesn’t mean the reserves aren’t there if the price deck changes, which is as certain as death and taxes.

They may believe in hyperbolic decline rates with long fat tails but that does not mean that's what they will get. The "reservoir" they drain is only as big as the frac radius they create. If we went on the hunt for fractured AC wells drilled in the 80's that produced 20 years we would be hunting a long time. We'd find a few that lasted 10 years, but not many. I am kind of a fan of Webble Telescopes work over at TOD; if these wells can produce at stripper well levels, which I doubt, the incremental lift costs per barrel are going to be astronomical. $50,000 dollar rod jobs don't work too well on 8 BOPD wells.

We are talking about apples and oranges though. I too saw lots of fracced wells drilled in the 70’s and 80’s that lasted a few years….the difference is they were almost all invariably vertical wells. The long horizontal wells with multistage propped fracs connect a much, much large part of the reservoir and each of those fractures acts as a conduit. If you only have a couple of fractures and count on the replenishment from shale perm to the fracture and then to the well bore you will not get anywhere near an economic rate, but if you have many fractures the chances are astronomically higher. I think on another thread I pointed out that there are a number of wells from shales that have long histories of production. Not all wells are going to be as good and some will require workovers. There are a number of recent papers in the SPE that speak to the economic viability of such workovers and of course it really depends on what you need to do. Small re-fracs are already being done and believed to be economic as they are clearing up problems with the previous completion and work is still ongoing with regards to what lift mechanisms are most appropriate (i.e. gas lift or ESP rather than rod pumps).

I think they have a fiduciary responsibility to their shareholders to keep a happy face. And to their lenders. And the prettier the picture they paint the more likely they are to be able to keep the little hamster wheel turning.

There are limits to this as I have said on numerous occasions. For a CEO to state in public that “we have 4 billion barrels of 2P reserves” and not have an audited reserve report to back it up invites a phone call from the SEC. For that same CEO to say “we believe that our acreage has the potential to contain as much as 4 billion barrels of prospective resources” is completely different and completely legal. The fact that he didn’t add “or it might contain only 10 million barrels” doesn’t fool sophisticated investors who understand terminology. And all of the information for public companies is readily available to anyone who wants to plough through 10Ks and annual reports. You can’t embellish the facts in those documents given they get signed off by external reserve and accounting auditors. Investing in oil and gas isn’t for the faint of heart but at least there are some clear rules which aren’t as apparent in the mining industry as anyone who got burned by the Bre-X fallout is well aware of.

[Graeme]

How do posters in this thread respond to this then?

Trouble in fracking paradise

The shale revolution is “a little bit overhyped,” Shell CEO Peter Voser said last week as his company announced a $2.1 billion write-down, mostly owing to the poor performance of its fracking adventures in U.S. “liquids-rich shales.” Which of its shale properties have underperformed, Shell didn’t say, but CFO Simon Henry admitted that “the production curve is less positive than we originally expected.”

Shell was a latecomer to the tight oil game. As late as 2010 it was acquiring mineral rights at inflated prices, predicting that those properties would produce 250,000 barrels per day in five years. Three years down the road, they are yielding only 50,000 barrels per day, and the company intends to sell half of its shale gas and tight oil portfolio. Shell has officially abandoned its production target of 4 million barrels per day by 2012-2018. Instead, Voser said, “we are targeting financial performance.”

Second-quarter earnings were dismal for the so-called oil supermajors. Shell, BP, Exxon Mobil, Chevron, Total SA, Statoil, and Eni SpA all reported sharply lower profits.

Production was also down nearly across the board, with only Total SA reporting an increase.

Of course, none of this would be a surprise for those who read my article from March, “Oil majors are whistling past the graveyard.”

The declining profitability and production primarily owed to lower oil prices and rising costs. As Platts reported in June, total capital spending for the top 100 U.S. producers in 2012 rose 18 percent year on year. Costs will be higher still this year.

Rising costs are partly due to the tight oil boom itself. Producers that invested heavily in tight oil production are struggling to maintain output against the accumulating undertow of existing wells, where output declines rapidly. Geologist David Hughes finds an average decline rate of 60 percent to 70 percent for the first year of production in new wells in the Bakken shale of North Dakota. And a new statistical analysis by Rune Likvern at The Oil Drum shows production from most Bakken wells falls by 40 percent to 65 percent in the second year.

smartplanet

[rockdoc123]

How do posters in this thread respond to this then?

The title and content are misleading.

Yes Shell reported a loss that was partly due to their shale operations but also due to their operations in Nigeria where they are bleeding money due mainly to oil theft. Note that Shell CEO indicates there are good and bad areas in the shales and they are still confident in their holdings.

BP actually had a much higher profit before adjustments than they did for the same quarter and first half of 2012….their replacement cost profit was negative mainly due to tax adjustments and the fact they capitalized all of the GOM spill costs.

Exxon Mobil had lower earnings but this is compared with strong asset sales in the same quarter of 2012 and their comment as to the main reason for lower earnings was

Weaker refining margins and volumes associated with planned refinery turnaround and maintenance activities negatively impacted Downstream earnings.

they also stated that excluding the impacts of entitlement volumes, Opec quota effects and divestments production was essentially flat.

With regards to ENI it is a bit of a tempest in a teapot…their quarter production was 1648 Mboepd versus 1656 Mboepd for the same quarter in 2012 or a change iof 0.5% which is negligible (i.e. you only need a few shut in periods for maintenance to create that sort of difference). Their comment was they still expect 2013 production to be in line with that from 2012. They did see reduced refinery revenues as a result of overall industry downturn in Europe. ENI is not a big shale player.

As to Chevron earnings were down but had nothing to do with decreased production according to their press release:

The decrease was largely due to softer market conditions for crude oil and refined products. Earnings were also reduced as a result of repair and maintenance activities in our U.S. refineries.”

For Statoil a similar story….their comment is outside of Norway (and there are no shale plays in Norway) they delivered record production and are on track to hit their 2013 targets. They note lower revenues were due to lower prices for liquids and gas and weak trading results.

So complete BS on the part of the writer who wants to portray the second quarter earnings of these majors as saying something about shale.

As I’ve said previously shale is the game for small companies who manage costs actively. Shell is not in that league which is why they failed in their first project in the Netherlands. They don’t really speak to why they had problems in the US, could be they were too liquid rich which results in lower deliverability but my guess is they are just not in the same game as the shale companies.

In comparison EOG who is one of the better shale players reported year over year crude oil production growth of 34%, their income per share was $2.42 versus $1.47 for the same quarter in 2012 and they specifically mention cost reductions in the major shale areas. In fact they are increasing their target for production and growth for the year.

How about the other important shale player CHK? Earnings per share for the second quarter were $0.51 versus $0.06 for the same period in 2012. EBITDA for the second quarter was up 26% on the same quarter in 2012. Production was up 2% for the quarter which would translate into 7% year on year and like EOG they are raising their guidance for the second half of 2013.

So I would say the facts point to a contrary conclusion, the shales seem to be working for the companies that know what they are doing.

[dcoyne78]

...And lastly, if I may, let us not assume that drilling costs are going to go down, on average, in any tight oil play simply because Leo says they will. Where is the data to substantiate that?
...
EF wells, with average lateral lengths and average frac stages, at anything less than 7 million dollars. Maybe they can whack off a few days of rig time, and moving costs, by sliding a rig around on the same pad, big deal. A week of reaming and lost circulation, a stuck BHA and not so average well costs are above 8, easy.

Public oil companies are saying that well costs are coming down in the Bakken.
http://www.startribune.com/business/194405301.html

Reger and other executives said drilling times also are dropping — to about 90 days from when the bit first hits the ground to initial oil and gas production. In early 2012, it took twice as much time because oil field services such as hydraulic fracturing teams were in short supply.

One well now can be drilled for $8.4 million to $8.8 million, and company officials see that dropping to $8 million on average by the end of the year. Some wells in Montana, because of the drilling circumstances, have cost under $5 million, the company said. Other wells, including some the company decided not to invest in, have cost $10 million or more.

http://bakkenshale.com/news/hesss-bakken-drilling-days-well-costs-down/

The main reason for lower investment levels is improving costs. Hess can drill the average well in just 26 days compared to 32 days in the second quarter of 2012. That along with other costs savings measures has driven Bakken drilling & completion costs down from $13.4 million to $8.6 million over the past year.

http://bakkenshale.com/news/sm-energys-bakken-production-up-utilizing-walking-rigs/#more-3801

During the quarter, the company released two traditional rigs and contracted a walking rig. SM plans to run three rigs through 2013. Almost all activity is infill drilling at this point. SM is has largely completed its exploration efforts and its efforts to hold leases with production.

Pad drilling has driven costs down 8% on the company’s Gooseneck acreage to an average of $6.5 million

I admit that I don't have definitive data, only news reports. Also keep in mind that I am adjusting for inflation so real well costs don't reflect general inflation. If over 40 years a dollar has decreased in value by 200 % and your nominal costs have gone up by 400 %, the real costs have gone up by only 200 %, though it is possible that your real costs have gone up by a factor of 5, luckily, the real oil price has also gone up by a factor of 5. Note that overall consumer prices have increased by a factor of 5 over the last 40 years so if your nominal well costs have gone up by 400 %, then your real costs are pretty much flat, so I would guess that you are using real costs (adjusted for inflation.)

I have tried to account for the sweet spot effect by decreasing well EUR by 10.5 % per year starting in 2017. Three year EUR is 172 kb in Jan 2015 and falls at a gradually increasing rate to 152 kb by Jan 2017 and then 136 kb in Jan 2018, and break even is reached in 2020 when 3 year EUR has fallen to 104 kb. Note that based on comments here I used a 3 year NPV to assess break even and assumed real well costs at $ 7 million and that prices remain at around $102/ barrel at the refinery gate and $3/barrel transportation costs.



For the experts I have a question:

Based on fields such as the Austin Chalk, once the sweet spots were fully drilled how quickly did the average new well's EUR decrease per year? 10 %/a, 50 %/a? I am sure it depends in part on drilling intensity, but lets say companies continue to drill at the maximum rate attained before the decreasing well EUR became evident, what would you expect to see in the Bakken and/or Eagle Ford? Thanks.

DC

[ROCKMAN]

DC - As far as the Austin Chalk goes there was very little effort to focus on sweet spots in much of the trend. Virtually every legal location in the heart of the play was drilled. But like every fracture play individual well results were dependent on how many natural fractures it cut and how many were hit by the franc job. Of course, like every trend it had its limits and eventually terminated for the most part. But during the height of the crazy times Chalk deals weren't pitched on the basis of a geologist's map but on the basis of a lease map. Basically if you had a lease you drilled well.

[dcoyne78]

DC,

First, thank you for responding to my earlier post. I figured 4000-9000 wells/yr in the Bakken was wildly optimistic, but thought I would throw it out there since it is apparently feasible (at least in TX) given data from the 2 TX tight oil plays.

This calls to question how long this kind of drilling can be maintained in the Texas plays. If I am eyeballing your first model on Eagle Ford, it looks like it has about 3000 cumulative wells drilled by mid 2013. If the previous article I linked is accurate and 4000 or so wells have been drilled in the past 4 quarters alone, it seems to be running well ahead of this first estimate. Perhaps active drilling in this play will wrap up before 2020 instead. Hard to say.

Still trying to envision where those rigs will go in several years once room for new wells begins to run out in the TX plays. I find your modeling interesting. Certainly a difficult task given all the variables involved. Thx.

Dave

Dave,

The Baker-Hughes well counts are relatively new, I am not sure how to interpret them, if you check out the following image or link (from RRC of TX):

or this link

http://www.rrc.state.tx.us/eagleford/images/EagleFordShalePlay070313-large.jpg

The oil well number for July is about 3800 total, if you look at the RRC data for the various Eagle Ford fields many wells (about 20 %) are on schedule but not yet producing which brings the number of producing oil wells down to about 3000.

It may be that the Baker Hughes numbers reflect both oil and gas wells. From April to July there has been an increase of about 700 oil wells on schedule, if 80 % of the 3100 from april were producing that would be about 2500 wells producing in April for an increase of 500 producing oil wells from April to July, if we assume these are spread evenly over the three months, that is about 167 net oil wells added per month or a yearly rate of 2000 wells/a.

In the Permian most wells are vertical rather than horizontal and these can be added more quickly probably about 6000-8000 per year (there are about twice as many rigs turning and the wells can be drilled more quickly because they don't have 5000-10000 foot lateral sections.

The oil industry guys can correct my mistakes.

DC

[ROCKMAN]

DC - These should be some fairly accurate numbers from DrillingInfo that draws of the TRRC public data base. To avoid confusion these deal with only wells that began producing between June 2012 and May 2013. Of the 869 wells 293 were classified as NG and 576 as oil wells. Of course the NG wells yield a good bit of oil also. When I get a moment I'll break it down to the last 3 and 6 months.

[ROCKMAN]

DC - Forget those numbers. Search engine screwed up. Double checked:

Last 12 months: 1439 oil. 249 NG
Last 6 months: 828 oil. 118 NG

[TheServant]

Thanks DC and RM.

That gives me a much better idea of the activity ongoing in TX and what might be the future activity in ND (& clears up my surprise after reading the article referencing the Baker-Hughes #s). Didn't realize the Permian Basin wells were primarily vertical. That makes much more sense.

[ROCKMAN]

TS - I don't have the numbers handy but there has been a good bit of hz drilling in the Permian but a lot of the gains have been from CO2 injection projects. New wells were often shallow vertical wells.

[dcoyne78]

DC - Forget those numbers. Search engine screwed up. Double checked:

Last 12 months: 1439 oil. 249 NG
Last 6 months: 828 oil. 118 NG

Thanks Rockman,

I assume these are for the Eagle Ford. Do you also have numbers for the Permian or more specifically the Spraberry Trend? Is it possible to break these down by horizontal vs vertical wells? Also for the numbers you gave are all those wells producing? Or are they just on the schedule? Thanks again.

DC

[ROCKMAN]

DC - I'll see what I can pull up for the Spraberry.

Yes...all EFS and all hz. Those numbers are for wells actually put on production in the stated time frames. Much more meaningful then rig counts and permit numbers. These are the real deal and not projections. Of course the rate of new wells coming on in the future may be less. Just talking to a vendor Friday who does a lot of work in
the EFS and he ran down a long list of operators that were releasing a lot of rigs. But it will probably take as least 6 months for such a slow up to be seen in new wells starting to produce.