[TheDude]

Meanwhile, across the Rio Grande, production is also booming. No, really. Enough with the laughter. Tamaulipas production has "soared" from 9 kb/d in 2011 to ca. 18 kb/d of late. Confusingly enough the PEMEX data site lists 6 fields for Región Norte, but the production gains all seem to be in "Otro," other fields - about 36 kb/d for the 6 listed but the rest were at 117 kb/d in Feb, up about 40 kb/d in two years. Small potatoes perhaps but PEMEX has been dithering about with shale drilling and perhaps it's paid off in a small way here.

[dcoyne78]

Rockman,

Thanks for the info on NPV, I will use an annual DR of 12.5 and split the difference and use a 15 year period for my NPV calculation.

The problem with rounding is this, if we add 1.5+1.5 we get 3 or 2 or 4, depending on if we round down or up and whether we round before adding and so forth. If we are talking about trillions of barrels of oil (in the case of a world estimate of URR), the difference between 2 and 4 is significant, so I think giving an estimate of 3 makes more sense. If we are adding 1.8 and 1.7 we could say the answer is 4, but I believe 3.5 conveys more information. YMMV.

I assume you are referring to 5.2 billion barrels of oil? It is only 2 significant digits, if I said 5200 million barrels, would you like that better? You can certainly round it to 5.

I do this because the USGS did a mean TRR estimate for the Bakken/Three Forks of 7.4 BBO (or 7400 MMBo if you like). So I started comparing my estimates for the Bakken to this 7.4 number, I will continue to do this, if only to annoy

DC

[ROCKMAN]

Dude - “This is partly because although its oil-and-gas-production side makes a fat profit, its refining business loses a fortune, and its petrochemicals division is also loss-making." And as a result of their refining biz running so badly last time I saw the numbers Mexico was spending 1/3 of the revenue it was getting from oil sales to buy and import refined products...mostly from the US. Add that sucking sound to the monies the govt pulls out of PEMEX it's a wonder they aren't deeper in debt. But part of the reason for the debt not being bigger is PEMEX being way behind on big capex projects like DW GOM development.

And again it's the refining angle that I think the Chinese could play so well with the Mexicans. Pay Mexico what it gets from US refiners but crack the oil in Mexico and give them their share at cost. That alone could save them $billions per year. And the latest chatter: if the Chinese build any new Mexican refineries to the right specs Mexico/China might start importing Eagle Ford Shale oil. Not that crazy an idea when you consider at least 50,000 bbls of EFS oil per day are being tankered to east coast Canadian refineries today because they can make much better spreads than Gulf Coast refineries. The Mexico/China link may also explain China's proposal to spend $1 billion restarting a shutdown refinery on the Caribbean coast of Coast Rica. Limon is not very far from Mexico’s big offshore field. Also not very far from Corpus Christi from where that EFS oil is being shipped all the way to eastern Canada.

[ROCKMAN]

Not oil but NG yet similar optimism: A little premature to poke fun at them but also a bit premature IMHO for them to start hyping such a headlines as “Poland's Shale Gas Hopes Buoyed by Promising Test Output”

“WARSAW, Aug 28 (Reuters) – Lane Energy Poland, an oil and gas exploration company controlled by ConocoPhillips, is extracting some 8,000 cubic metres of shale gas per day at a test well in northern Poland, an amount unseen in Europe to date. Poland, whose hopes for shale gas faded after three international firms quit after disappointing drilling results, has been looking for signs of bigger quantities of the unconventional gas, which could help it reduce its reliance on Russia.

The daily amount of gas being produced there still does not qualify as commercial production, but is the largest obtained in any shale gas well so far in Europe, the newspaper said. Poland, which consumes 15 billion cubic metres of gas a year, mostly imported from Russia, has estimated its recoverable shale gas reserves at up to 768 billion cubic metres. It has issued more than 100 shale gas exploration licences to local and international firms which have drilled 48 wells to date.”

OK…a bit of a reality check. They say they have recoverable reserves of 768 billion cu meters (27 trillion cu ft) and yet they haven’t profitable produced one cu ft of NG yet. And 8,000 cu meters sounds like a lot but that’s 280 mcf/day. Don’t know what NG sells for in Poland but after reducing for my guess for royalties and assuming $4/mcf that’s about $900 net income per day. No idea what that well cost but for every $1 million of cost it will take about 3 years to recover the initial investment of the drilling alone. So if the well only cost $3 million (about half of what a US well might cost) it will take around 10 years to just break even. That may explain why “The daily amount of gas being produced there still does not qualify as commercial production”. And then there's that logistical issue we've talked about in other threads: there are individual counties in Texas with more drilling rigs running than all the EU combined. Add that with the nature of sovereign mineral ownership and capex requirements it would be very difficult for Poland to ever develop its shales in the manner we see in the US even if they did have the same potential.

Granted they could see some significant improvements as they develop a local learning curve. But it might be advised to wait to offer buoyed hopes until that happens.

[rockdoc123]

Don’t know what NG sells for in Poland but after reducing for my guess for royalties and assuming $4/mcf that’s about $900 net income per day.

It would offset the price they pay to the Russians which in the winter time runs from $9/Mcf to $14/Mcf.
This is what the major attraction was with respect to European (and especially Polish or Ukrainian) shale gas. Also the Poles do not want to be at the mercy of the Russians who have threatened to stop shipping gas altogether at peak demand times. There was a point a couple of years ago where the Poles were a few days away from running out of gas entirely right in the middle of a nasty winter.

I think in this case conventional economic analysis takes a backseat to assurance of supply.

[ROCKMAN]

Thanks doc. I was sure it had to be higher but didn't want to guess. I agree that the politics of the situation will likely over rule the economics to some degree.

I read something the other day I had not heard before: Russia is negotiating some sort of treaty with the EU whereby they would be the sole NG exporter into the region. Rather odd if true. Have you seen anything along those lines?

[rockdoc123]

No but having been involved somewhat in the European shale gas studies it is pretty clear that no one trusts the Russians. The Russian strategy in the past is to placate countries in order to get them to commit to contracts and then stiff them whenever they can to run up the price. Arguably Russia has had problems serving their own needs from time to time due to a combination of intermittent cyclical high demand and infrastructure issues but the general opinion of the Europeans I have spoken with is it is unwise to trust them as a sole deliverer.

[Strummer]

Also the Poles do not want to be at the mercy of the Russians who have threatened to stop shipping gas altogether at peak demand times. There was a point a couple of years ago where the Poles were a few days away from running out of gas entirely right in the middle of a nasty winter.

That episode was a bit more complicated. It wasn't the Russians who caused it, but Ukraine. Russian pipelines to Europe are transited through Ukraine, and Ukraine at one point refused to pay Russia for the gas that they consume. And the whole thing was most likely US-orchestrated anyway, just one of the many US efforts trying to destabilize the relations between Europe and Russia. Russia has no interest in alienating its EU customers.

[dcoyne78]

DC – ...[snip]

I hesitate to forecast the change in EUR. The problem is that wells drilled in 2 years will be done differently than wells drilled 3 years ago. Besides having longer laterals and more frac stages some may be drilled on tighter spacings. Longer laterals are one way to offset the lower production potential of the less sweet spots. So some of these future wells might have EUR’s comparable to earlier sweeter wells. But it will come at a higher costs. Two wells might project to have the same EUR’s but one may cost 50% more to drill than the other so it diminishes it’s economic significance even while delivering the same amount of oil.

And for the love of Dog stop making projections down to the tenth of a percent. Remember what we geologists say 2 + 2 is equal: somewhere between 3 and 5. LOL

Hi Rockman,

I misunderstood the last part of this post, I thought you were referring to URR predictions of 5.2 BBO, but I think you were referring to the 12.4 %/a decrease in EUR and, I agree, lets call it 12 % or between 10 and 15 % if you prefer.

I do these models in a two stage fashion, first I attempt to model TRR by assuming only that EUR decreases at some future point in time at a constant yearly rate, I adjust the rate of decrease of EUR to match the mean TRR estimate of the USGS (for the Bakken) and double the USGS estimate for the EFS (TRR=1.75 BB0) because they doubled the Bakken/Three Forks estimate in their recent update so I assume they might do the same for the EFS at some future date.

In the second stage I try to estimate economically recoverable resources (ERR) based on the EIA reference oil price scenario, NPV based on your suggestions and figuring in OPEX, transport costs, financial costs and well completion costs. I assume well completion costs will fall to $7 million per well by late 2015 and that by this time the optimum lateral length and number of frac stages has been established and that any attempt to increase lateral length or number of frac stages would only decrease the profitability of the well due to the increased well costs. (If NPV12.5 is $10 million and well completion cost increases from $7 million to $10 million, we have reduced our profits to zero.)

So I am not looking for you to predict that well EUR will decrease by 12.8 %/ year, I am looking for guidance that well EUR is likely to decrease at between x and y % per year if real well costs remain fixed and the number of wells added per year also remains fixed ( a thought experiment of sorts). Once I have this guess, then the number of wells added per year is adjusted so that it remains profitable to produce oil, as EUR decreases the number of wells added per year decreases and this reduces the rate of decrease of EUR for new wells.

Under the scenario that you propose (longer lateral lengths and more frack stages), I would need to guess at the increased well costs which might result in order to attempt to model economically recoverable resources. In fact if things play out as you suggest, (and I would say that your guess would be much better than mine) would no decrease in EUR make sense? If so, what sort of increase in well costs per year (in real dollars adjusted for inflation) makes sense? A range is fine, maybe10-20%/a increase in well completion costs, if EUR decreases from 10% to 0 %? I was trying to keep the model doable, I am fully aware that no model can fully capture the complexity of the real world. I would like to create a low and high scenario to attempt to bracket the possible future output.

I forgot to mention the tighter spacings, though I think this would tend to offset the longer laterals and greater number of frack stages, though it could increase the potential number of new wells, this is another variable which I have fixed on the assumption that the optimum configuration has been established in plays such as the Bakken and the Eagle Ford.

DC

[ROCKMAN]

DC - “I am looking for guidance that well EUR is likely to decrease at between x and y % per year” I’m really not sure I could come up with a credible answer. So many variables that if you select extremes for a window I suspect the end points could vary by 20% to 40%.

“I would need to guess at the increased well costs which might result in order to attempt to model economically recoverable resources.” Just a guess but I don’t think we’ll see a significant increase in well costs beyond where we are no. There are physical and lease limits as to how far they’ll drill a lateral which also limits the number of frac stages. In fact by focusing on tighter spacing those metrics might actually decrease a bit.

And then there’s the problem of how to weight those statistics. Not all the trend will be suitable for tighter spacing and increased drilling even with longer laterals. One measure of these variables is what happened in Wilson Country. One of the big boys took over 20,000 acres and paid a huge sum. Then they drilled about 8 hz Eagle Ford wells that had such poor results the completely dropped the entire county from the program and offered the entire position for pennies on the dollar. Even though we’re not shale players I looked at it because it was such a bargain. There certainly was little EFS potential but some possibilities in the Austin Chalk and Buda. But leases were already beginning to expire and there just wasn’t enough time to work the seismic adequately.

When you can wipe out an entire county (and Texas counties are large) as a result of one operator’s failed efforts it’s difficult to make any grand model for the entire trend (especially what’s left of it) without breaking it into more discrete packages. And I don’t have enough details to be able to do that. I suspect the major EFS players do have some idea and will follow their models.

The shift to tighter spacing may be the best indication of diminishing economic value of the undrilled areas. As earlier wells deplete the production infrastructure becomes much underutilized. By drilling tighter spacing total expense is reduced making for more favorable economics even if the new wells have lower URR values. But some percentage of those closer spaced wells will be a bust because they’ll tap into fractures that were drained by earlier completions. But what percentage? No way to make a guess IMHO.

[ROCKMAN]

DC - Something comes to mind with the valiant efforts you and others are making. I commented in another thread that folks should realize that when Hubbert made his famous US PO prediction he was using a very mature data base. His prediction actually had more to do with the decline in the discovery rate of new wells more than the decline rate of producing wells. He used the production history of one of the greatest boom times in US history starting in the 1940’s. But by the time he made his projection most of those big conventional oil fields had been discovered and we were chasing progressively smaller ones.

Today most have no problem understanding the nature of exploration: you go for the biggies first and then eventually chase the smaller ones left. Apparently that was a radical concept to some degree in his day. Not to take anything away from his effort but he didn’t make his projection 10 to 15 years earlier when those plays began developing. That would have been truly amazing. But this is where folks are today: trying to predict peak EFS, peak Bakken, peak et al but trying to do so early in the exploration process that it may not be possible to develop any projection that has a reasonable possibility of being correct. Imagine trying to do this in 2020: I suspect at that point if production is still increasing in the EFS, Bakken, etc. it would be much easier to project the peak production in those plays. And even then much would depend upon having stable oil prices throughout the projections. That was another factor Hubbert had in his favor: thanks to the efforts of the Texas Rail Road Commission to maintain stable oil they fluctuated very little prices (when adjusted for inflation) for the better part of 25 years. What are the odds that current oil prices will remain static for the next 20 years? I have no idea.

[ROCKMAN]

Nice to see someone taking a common sense approach to frac’ng. As pointed out before the oil patch can function just fine while operating within the rules. Just need to have them well defined. If they can still develop the shales in South Africa under these regs that’s fine. If not then then they don’t drill…the people have spoken. Always good to stay ahead of the game. Something a number of New England states failed to do when the frac’ng boom started.

“Companies seeking shale gas exploration permits in South Africa will need to apply for a water usage license. South Africa last year lifted a moratorium on shale gas exploration in its Karoo region, where the extraction technique known as fracking might tap what is believed to be some of the world's biggest reserves of the energy source.

Water is a scarce commodity in the vast, semi-arid Karoo region. "I have taken the decision to issue a notice of intention to declare fracking a controlled activity in terms of the National Water Act. What this means is that fracking becomes a water use, thus requiring a water use license," water minister Edna Molewa told journalists. The regulatory process around fracking in South Africa has been slow and no exploration permits have been issued yet. Companies that have expressed an interest in exploring South Africa's shale gas potential include Royal Dutch Shell.

Developing just a 10th of South Africa's estimated resources could boost the economy by $20 billion a year and create 700,000 jobs according to researchers.”

[ROCKMAN]

An update on future shale activity in NY. As background understand that a mineral lease has a fixed time limit typically 3 to 5 years. If no drilling takes place before that limit is reached the lease automatically expires. I suspect the legal battle CHK had fought was over a possible force majeure clause that suspended the expiration date if matters were beyond the control of a company. In this case the statewide ban on frac’ng.

Chesapeake Energy (CHK) will finalize an agreement next week to drop 12K acres of land leased for energy drilling in New York state, Reuters reports, ending a two-year legal battle with landowners who wanted to renegotiate for better terms. CHK's decision to drop the leases is a sign of the growing frustration of energy firms over operating in New York, where a moratorium on fracking is in its sixth year, and an indication that CHK is pulling back on spending after years of aggressive acreage buying.

Assuming this legal challenge is across the board in NY state then most of the leases taken either have expired or will shortly. As such the people of NY have spoken through their elected representatives: no shale frac’ng in NY. Just as it should be IMHO. No company has an inherent right to drill let alone frac a well anywhere. Minerals owners and the state will lose out on $billions of revenue and won’t have a huge reserve of NG close at hand. But that was their option. No doubt many companies and more than a few mineral owners are disappointed but such is life in a republic…can’t make everyone happy.

[Tanada]

Rockman, It gets me to wondering if the pull out of NY is because it just doesn't pay that much and they will be focusing more on Western PA and Eastern OH? Harrison county OH produces gas that is so wet they count it as Oil on the state statistics and so far the activity has been modest but steadily growing.

[ROCKMAN]

Tanada - I suspect you're correct. Multiple factors go into such decisions. Part of CHK's decision may have more to do with their capex constraints than the regs. If NY ever decides to allow frac’ng I suspect there would be some resurgence in drilling. I’ve seen estimates as high as $1/mcf advantage to producing in NY state as a result of savings on transport costs from the Gulf Coast. And NG prices have been on the rise a bit. OTOH it looks like the east coast may be getting a bit of a price break on heating fuel with so much domestic (and cheaper) oil reaching the eastern refineries. Probably not a great deal of a disincentive to not switch to NG but some.

Another factor may be there’s now some more solid EUR estimates from those early wells drilled and that may have taken some of the shine off the rose.

[rockdoc123]

Rockman, It gets me to wondering if the pull out of NY is because it just doesn't pay that much and they will be focusing more on Western PA and Eastern OH? Harrison county OH produces gas that is so wet they count it as Oil on the state statistics and so far the activity has been modest but steadily growing.

I don't think it is necessary to read more into it than the CHK press release. They were first in on the shale play in New York and signed many access contracts at what was the going rate back then. Since then they have been sitting patiently during the very long moratorium on fraccing. They attempted to get an order of Force Majeure applied which would have seen their contracts extended under the same terms but the New York courts ruled against that claim. As a consequence CHK would have to renegotiate all of their contracts again, assuming that the New York gov't ever gets around to lifting the fraccing ban and that impact on potential economics is anyones guess at this point. The Marcellus in New York is arguably more liquid rich than larger parts of CHK's holdings in Pennsylvania so I don't think it has anything to do with their focus on high ROR yield shales. Seems to me this action fits with the rest of their strategy where they concentrate on the acreage that has the best hopes of working in the near term with the best returns. Given the uncertainty of the ban being lifted and the uncertainty regarding what new lease terms would entail it makes sense that CHK would want to get this one off the books and focus their activities elsewhere.

[dcoyne78]

I got some data on the EFS, I focused on the Eagle Ford 1 and Eagle Ford 2 fields, that produced about 90 % of the total crude output of the EFS and about 72 % of C+C output (about 18 % of EFS C+C is lease condensate).

Of 85 single well leases that started production in June and July 2012 and having 12 or 13 months of oil output, the average cumulative output was 86 kb, the median cumulative output was 77 kb. An analysis I had done earlier for 116 wells starting production between Jan 2011 and Jan 2012 had an average cumulative 12 month output of 108 kb. It is not clear if this decrease is real, I plan to update my earlier EFS analysis at some point and will share the results when they are available, the earlier analysis suggested a 30 year EUR of about 190 kb for the average EFS well (qi=22500, b=0.5, di=0.23) using an Arps hyperbolic to estimate future output.

DC

[ROCKMAN]

More bad news for the hopeful Mississippian Lime fracture play in Kansas. Even though my company wouldn't drill any of the shale plays, about two years ago we had a negotiation with a group putting together a large lease position in the ML trend. Neither we nor they had any intention of drilling. But if the trend had boomed we would have flipped our lease position and walked away with a very nice profit. Similar to the $12 billion payday Petrohawk had doing the same thing in the Eagle Ford. Unfortunately we couldn’t come up with a trade our two groups could agree upon and dropped the idea.

Shell is pulling out of Kansas after its exploratory wells didn’t show enough potential to stay, another in a series of departures by major exploration companies that have given up on the Kansas side of the Mississippian Lime formation. Shell, which is selling off its 45 producing wells and 600K acres in nine Kansas counties, stopped drilling in July as it reviewed results for its exploratory wells. Chesapeake, EnCana and Apache have been gone from the state for more than a year, and Midstates Petroleum filed its last intent to drill in April.

As been pointed out before: not all shales are equal.

[dcoyne78]

For those interested I have updated my future ND Bakken/ Three Forks scenarios

at http://oilpeakclimate.blogspot.com/

Note that ERR is economically recoverable resources and that the TRR for these scenarios are about 6, 8 and 11.5 BBO for the low, medium, and high scenarios respectively, the details can be found at the link above.



Remember that the sweet spots eventually become fully drilled and new well EUR then begins to decrease. The USGS F5 (5 % probability that TRR will be more) estimate for the North Dakota portion of the Bakken/ Three Forks is between 11 and 12 BBO and the F50 estimate is about 8 to 9 BBO. Even if we assume that the F5 estimate is reached, output still peaks at about 1.2 MMb/d in 2017.

DC

[Pops]

Thanks DC. I think the most dramatic take-away is how little the peak and date changes even with a doubling of URR.