Looking at North Dakota oil production by county, and historical production by county, gives a better perspective of what is happening in the Bakken and the rest of North Dakota than just looking at total production.
The data is available here: ND Historical Barrels of Oil Produced by County You will notice it says:(Confidential Wells are Not Included). However the total North Dakota does include confidential wells. And I have made adjustments for the confidential wells. The adjustment for March and April came from the NDIC here: State Summary Report April 2014.
The above chart is after adjustment for confidential wells. Even the lowest producer of the big four, Dunn County, outproduces the rest of North Dakota combined.
McKenzie was up 7,168 barrels per day after adjustment this month.
Mountrail was up 5,816 barrels per day after adjustment according to the NDIC. But this is still 10,360 barrels per day below its peak in November of 2013. Mountrail county has been the Bakken’s biggest producer and still leads, by quite a large margin, in total cumulative production. But Mountrail seems to be peaking. Less than half as many rigs are now working Mountrail County as are working McKenzie County.
Dunn County was up 5,738 bp/p after adjustment.
Williams County, the lowest producer of the big four, was up 3,630 bp/d after adjustment.
The rest of North Dakota was up 1,617 bp/d in April but was up considerably more in March.
This chart is not total cumulative production but production since January 2007. 2007 is about the time, or slightly before the time, that heavy drilling and fracking started in the Bkken. From the start the big producer was Mountrail County and has, since 2007, outproduced McKenzie county by almost 72 million barrels. But Montrail county production has since slowed considerably.
Production in Mountrail County will continue to slow because only 17% of drilling rigs are working in that county while 37%, more than twice as many rigs, are working McKenzie County. 18% of North Dakota rigs are working Williams County, 14% are working Dunn County and 14% the rest of North Dakota.
The number of rigs in each county vary, but only slightly, from week to week.
A note of interest, North Dakota has produced 1,123,507,162 barres since January 1st, 2007.
On another subject, I had planned on a post based on the EIA’s Petroleum Supply Monthly which just came out. But it was pretty boring. The EIA is still estimating Texas production to increase 48,000 barrels per day month after month. And I think they are estimating Gulf of Mexico production way too high.
BSEE is a little like Texas RRC, their data is delayed. Except the RRC data is sometimes delayed up to two years where the BSEE data is pretty much in after three months. So the EIA just guesses at where the data will be when it all comes in. But I think that in the case of the GOM they are guessing way too high. They have the GOM up 38 kb/d in March and up 75 kb/d in April. They have US production up 165 kb/d in March and up 202 kb/d in April to 8,378,000 barrels per day. That seems a bit much.
The EIA is predicting the Gulf of Mexico will produce 2 million barrels per day by 2016. They may be trying to rush it a bit.
But there is finally something in MSM, The Washington Post in this case, that I can agree with.
James Woolsey, a former director of the CIA and self-proclaimed energy hawk, argues that the Organization of the Petroleum Exporting Countries (OPEC) has a grip on global oil and gasoline prices so tight that the United States will never be free of its influence. Like most people, Woolsey wrongly believes that OPEC is a powerful cartel.
In reality, OPEC rarely if ever influences its members’ oil production rate. It has almost no impact on prices, except under rare conditions. OPEC has been coasting on a reputation gained in 1973, perpetuating – and benefiting from – a myth about its own importance. It is long past time that myth was dispelled….
The real cost of the OPEC myth is political. Politicians in oil-importing countries blame OPEC for manipulating world oil markets, especially during times of high gasoline prices. For instance, NOPEC (No Oil Producing Exporting Cartels) bills have been introduced to the U.S. Congress over a dozen times since 1999, though none has passed. These bills distract Congress and the public, thereby imposing an opportunity cost on the political system and contributing to congressional paralysis. (Worse still, some politicians seem to know full well that OPEC doesn’t matter, but like a scapegoat for high prices.) The myth also causes U.S. diplomats to waste valuable political capital when they kowtow to various members of OPEC. Government officials are liable to defer to OPEC members and offer (modest) favors in exchange for changes in oil production.
All in all, the West would be better off if it stopped assuming that OPEC drives oil markets. It does not. Most of the credit or blame for rising oil prices in recent years rests with Asian customers, not diabolic moves by OPEC. With the price of oil set by market forces almost entirely outside of its control, OPEC is along for the ride like everyone else.
The article also points out that only Saudi Arabia has any spare capacity, that other OPEC members are pumping all the oil they can. Well… they were wrong on that point, at this time Saudi is also pumping all the oil they can.
The BP data base (total petroleum liquids) shows that Libya’s production fell from 1.5 mbpd in 2012 to 1.0 mbpd in 2013. In response, Saudi Arabia “Cut” their net exports from 8.6 mbpd in 2012 to 8.4 mbpd in 2013 (BP data base).
The BP data suggest that 2013 was the eighth straight year in a row that Saudi net exports were below their 2005 rate of 9.1 mbpd (EIA), as annual Brent crude oil prices doubled from $55 in 2005 to the $110 range for 2011 to 2013 inclusive. This is in marked contrast to the 2002 to 2005 pattern, when Saudi Arabia increased their net exports from 7.1 mbpd in 2002 to 9.1 mbpd in 2005 (EIA), as annual Brent crude oil prices doubled from $25 in 2002 to $55 in 2005.
Jeff,
If it is true that most of the Middle East oil reserves are inflated… what kind of impact could that have on net exports in the future?
I mean…. could we experience a much steeper decline if actual reserves are 100-250 billion less than official stated figures?
Steve
Of course, the really crazy low number is my estimate for the remaining volume of Available CNE (Cumulative Net Exports), i.e., the estimated cumulative remaining volume of GNE (Global Net Exports) available to importers other than China & India.
Available Net Exports (ANE), or GNE less CNI (Chindia’s Net Imports), were 41 mbpd in 2005 (or 15 Gb/year). Based on the 2005 to 2012 rate of decline in the GNE/CNI Ratio, I estimate that post-2005 Available CNE are on the order of about 170 Gb. At the 2005 rate of consumption in ANE, estimated post-2005 Available CNE would be depleted in about 12 years (analogous to a Reserve/Production Ratio).
From 2006 to 2012, cumulative ANE were about 95 Gb, which would put estimated remaining Available CNE at about 75 Gb at the end of 2012. At the 2012 rate of consumption in ANE, estimated remaining Available CNE would be depleted in about 6 years, i.e., the total estimated volume of Global Net Exports of oil available to about 155 net oil importing countries would be totally gone in 6 years (about 2,200 days). Of course, the expectation is for an ongoing decline in ANE, and the current extrapolated data suggest that ANE would theoretically approach zero around the year 2030.
As someone once said, what can’t continue tends not to continue, and there is no way we would have a functioning global economy if two countries consumed anything close to 100% to Global Net Exports of oil, but here’s the problem:
Given an inevitable ongoing decline in GNE, unless the Chindia region cuts their GNE consumption at the same rate as the rate of decline in GNE, or at a faster rate, the resulting ANE decline rate will exceed the GNE decline rate, and the ANE decline rate will accelerate with time. It’s a mathematical certainty.
In any case, the projected rate of decline in the GNE/CNI Ratio puts us at a point in 2030 at which we cannot arrive, but the 2013 data will almost certainly show that we continued to slide toward a point at which we cannot arrive:
http://i1095.photobucket.com/albums/i475/westexas/Slide1_zps9ff3e76d.jpg
Quite the conundrum.
Jeff,
Thanks for the reply. Will the EIA have their international data by July?
I assume you are asking about the consumption data. I don’t know when it’s coming out, but in any case, I’ll probably wait until this fall some time to do some updated charts with 2013 data, to give the EIA time to do one or two revisions. There are so many holes in the BP consumption data set now that we will really have to rely on the EIA consumption data.
My guess is that ANE fell to between 33 and 34 mbpd in 2013, versus 41 mbpd in 2005.
OPEC reserves are about 800 billion barrels less than they claim. They claim 1200 billion barrels and they have 4 at the most.
However what they never had will not greatly affect their decline rate. Even if they do have 400 billion barrels that is way more than non-OPEC countries have. And non-OPEC countries produces 60% of the world’s oil with what OPEC says is 277 billion barrels. OPEC produces only 40% of the world’s oil so I doubt they even have 400 billion barrels of reserves.
What will affect their decline rate will be all the infill drilling they have done in the past 10 to 12 years. They have decreased their decline rate with infill drilling and horizontal wells near the top of their reservoirs. This has kept the decline rate down but has dramatically increased their depletion rate. Whe the water starts to hit those horizontal wells then the decline will set in with a vengeance.
Hi Ron,
OPEC reserves(not including Orinoco belt extra heavy reserves) are about 500 Gb according to Jean Laherrere. See
http://aspofrance.viabloga.com/files/JL_2013_oilgasprodforecasts.pdf
Dennis, that may be the case, I am not so sure. However my point is OPEC reserves are no different from non-OPEC reserves. If a country is producing every barrel they can then we can infer that the more oil a country has to produce the more they will produce.
Does that make sense to you? It makes perfect sense to me and is the one thing almost everyone forgets when they talk about proven or recoverable reserves. It doesn’t really matter. The more oil they have the more oil you will see them producing.
Well, a choice not to produce is not functionally different than an inability to produce.
I’m not too comfortable with presumed enormous departures of reality from that reported because, again, it requires too big a conspiracy.
But it’s likely pretty easy to redefine things internal to Aramco that would let them feel comfortable with all sorts of reporting.
Can’t a solid computation be made from data leaked over the years, specifically the geographic size of Ghawar X the at some point leaked quoted thickness of pay? That would provide a nice upper bound quantity?
I have always wondered why there is not more hard data available to the public about Middle Eastern reserves considering the number of western contractors and employees that have worked there.
I can see confidentiality agreements holding up in the case of companies and well to do employees such as engineers or accountants but in the case of tradesmen- considering how many must have had access to critical info over the years- some of them should be retired and talking.
You don’t have to be an engineer to understand an overheard conversation in principle or to understand that instructions to put a certain piece of equipment down hole at a certain depth means that is either the upper or lower boundary of the pay zone.
It seems to be a given to me that an experienced reservoir engineer with some experience in Saudi Arabia can deduce a huge amount of information just by looking at satellite photos of wells drilled over time.
I have never actually even seen an oil well and know nothing more about oil than what I have learned in internet forums such as this one but the same basic principles of management apply across all businesses and from one business or owner to another in a given business.Managing a supergiant Saudi field can’t be but so different from managing any other dry land supergiant.
If I were a footloose young guy I would be ready to bet my life I could get hired on on a Fracking crew and smuggle offsite a quart or two of any fracking fluid ever brought onto the sites I worked on.Somebody is probably more than ready to pay big money for such samples.
Adequate samples could probably be had just by asking for scrapped parts from the pumps and hoses and pipes used to handle them on the job that are no doubt sold or given away to local scrap dealers.
Lots of foremen on trade jobs are in the habit of giving away or deliberately overlooking the disappearance of such items since it is the cheapest way of keeping the job site clean and neat and in compliance with environmental regulations. I know because I have done a little dumpster diving myself over the years being a rolling stone.
Chemists these days don’t need more than a minute sample of a substance to analyze it.
It doesn’t make sense that Norway (small population, highly educated, wealthy) would would produce every barrel of oil possible, but that is exactly what they’re doing. And, I’ve never seen one an example where this wasn’t the case. It’s never even seriously talked about. Amazing!
Norway likely shut in some of their production in the 80s when demand crashed, storage was maximized, and North Sea output was skyrocketing. Like almost all other nations they’ve likely been going full tilt for a long time. How many nations/states have ever had the luxury of prorationing? TX, KSA, Kuwait, UAE perhaps? Supposedly those last two cut back a bit during 2009.
Another factor in assessing OPEC is what screwed up messes most of them are. Russia is a model of efficient orderly work in contrast to Venezuela/Iran/Iraq. Their reserves were truly underestimated originally and the gains made in the 80s were no doubt justified to some extent, although not the laughably ad hoc manner in they attempted to outdo each other in this manner. But the horrendous practices displayed in reservoir management by so many of these countries means they might as well have stayed at the original reserves figures, or thereabouts anyway. The US used to be addicted to flush production too but the government intervened in the 30s to put a stop to fields being drilled like pincushions, leading to massive waste; the same hasn’t really happened with most of OPEC, not to say non-OPEC nations like Mexico.
The incentive to produce was higher than previous prices.
But that was back before money was printed whimsically.
It should be much, much easier to embrace not producing and let the wars begin. After a population decline, the Arabs might think they can be dominant.
Hi Ron.
Laherrere estimates about 800 Gb of 2p world reserves in early 2013 (not including extra heavy reserves which are about 400 Gb).
Of these reserves 300 Gb are non-Opec and 500 Gb are Opec reserves.
As for opec producing “flat out”, this is the proved developed reserves that are being depleted at similar rates to non-Opec proved developed reserves.
It is possible that OPEC nations have chosen to develop their reserves more slowly than non-Opec nations. Jean Laherrere’s estimates of proved plus probable reserves and the actual production levels of Opec and non-Opec indicate that an assumption that the R/P ratios are similar in Opec and non-Opec producers may be incorrect.
The bottom line, producing every barrel that it can, means producing all the developed reserves that it can.
We have pretty good data from the EIA for the US.
In Dec 2012 proved producing reserves were about 21 Gb and 2.4 Gb were produced for an R/P of about 9. For the World we don’t know what the proved producing reserves are.
Better to use proved reserves of 33 Gb for the US, for an R/P of 14. If the R/P for the world was 14 this would indicate C+C reserves of 385 Gb, so clearly there must be a great deal of variation in R/P ratios from nation to nation.
Using BP data, non-Opec R/P (excluding extra heavy reserves) is about 17. For Opec the R/P is 37 using Jean Laherrere’s 500 gb reserve estimate for Opec.
From my perspective, the explanation for this 2 to 1 difference is that OPEC countries choose to develop their reserves more slowly than non-Opec nations. Note that there is a lot of variation in R/P ratios amongst non-Opec nations from 10 on the low side to 24 on the high side. All nations do not develop reserves at the same rate.
“They have decreased their decline rate with infill drilling and horizontal wells near the top of their reservoirs.” This is of such fundamental importance that I can’t see how many fail to grasp it. As far as I’m concerned it make almost all of the projections that keep appearing ridiculous. I have spoken to so many “real” oilfield geologists and it’s all they talk about — creaming deposits, acceleration of depletion. Why is this so hard to get through to analysts? Oh well.
Hi Doug,
I have not had the pleasure of talking to many oil field geologists.
Over at peak oil.com Rockman and Rocdoc (I think they are both geologists) seem less concerned. They believe that there will be a peak and decline, but I do not think they believe that there will be the production cliff that some envision.
When the decline becomes steep in Ghawar the annual rate of decline will likely top out at 25 to 30%. This will be a very big deal, but KSA will attempt to keep it hidden. It will be pretty obvious however because unless there is a huge increase in drilling the overall KSA output will decline over a long period (say the 12 month average will decrease for many consecutive months). We don’t have a lot of information on KSA, we will just have to watch the output numbers from several sources.
Dennis,
You mean an increase like this one?
http://www.bloomberg.com/news/2013-07-23/saudi-aramco-s-oil-push-to-raise-rig-count-to-record.html
“Saudi Arabian Oil Co., the world’s largest crude exporter, is set to add more drilling rigs than expected this year and hire more in 2014 as new fields are drilled to counter dwindling output from aging deposits.”
That was last years news! Not sure what their next plan is? That is right, just remembered. Drill shale gas, replace crude being burnt in power stations, and export the oil saved.
How does that shell and pea game go again?
PS
“The increase in rigs will also help the country find new deposits and pump more hydrocarbons offshore, al-Husseini said. Aramco plans to raise gas output in the Red Sea and Persian Gulf to reduce domestic use of crude oil and retain more for export. It will also drill seven wells to test shale-gas deposits in the northwest this year, Oil Minister Ali Al-Naimi said in March.”
I think that Red Sea gas could be deep water sub salt. Not what you would call cheap and convenient.
I don’t think it will be long before the bubble bursts for Saudi. I am not sure how many more tricks they have up their sleeve.
Hi Toolpush,
Yes. Interesting that rigs have increased by more than a factor of 3 compared to a decade ago (200 vs. 60).
Also of interest is how this compares with the US rig count at present, 1748 rigs in the US vs 200 rigs in Saudi Arabia.
Output per rig (I don’t know the oil gas rig breakdown) is 47 kb/d per rig in the KSA vs. 4.8 kb/d per rig in the US.
We should get some of those Saudi rigs so we can get more oil! 🙂
Dennis,
It is always hard to compare drilling rig numbers from the States to other countries, as the US has always had about 1/2 half of the worlds working drilling rigs and in a league all of their own. World wide there are approx 4000. The Saudi count is certainly heading up very quickly.
Hi Toolpush,
Yes, I had heard that. Rigs for world less US are 1512, that would be about 46 kb/d per rig worldwide similar to KSA.
So KSA looks like it is going flat out on development, though the World is certainly not developing its oil as aggressively as the US. As you mention this has been the case for a long time.
Dennis,
If the Saudi’s need a few more rigs, then maybe they could borrow a few from Iraq. I don’t think they will be using them for a while, and it would be safer storage in Saudi, than Iraq at the moment.
Hi Toolpush,
Agreed!
I looked at the rig efficiency (output per rig) using oil rig data from Baker Hughes. It turns out that KSA still has pretty high efficiency compared to the rest of the world (excluding US, Canada, and KSA). For the rest of world oil rig efficiency is 54 kb/d/rig in 2013 and 93 kb/d/rig in 2003 (using EIA C+C output data)
Above I suggested KSA may be flat out in developing its oil resources, but that was due to bad rig count data.
For KSA oil rig efficiency was 176 kb/d/rig in 2013 and 462 kb/d/rig in 2003. There has been a big drop in rig efficiency in KSA over the last 10 years (a factor of 2.6), but rig efficiency in KSA is still 3 times higher than the rest of the World.
In another decade, perhaps the oil rig efficiency in KSA will drop to the rest of the world’s level, at that point their oil field development will be flat out.
Dennis,
They are still drilling the last of the big ones, as in Manifa. Next year they intend to drill the last and poorer sections of the Shaybah Field and Khurais field. This may show up a decline in rig productivity, but anything after that certainly will, especially as they move into their shale plays, which in itself is an admission they are on their knees.
As you say, it will show up in an increasing rig count first.
Well if OPEC only has 400 billion barrels and the rest of the world 277 billion in proved reserves, and we’ve burnt something like 1300 billion, then we’re already 2/3 of the way through. Of course this doesn’t include probable reserves, or does it? These numbers, if true, are horrifying.
Hi Frugal,
Jean Laherrere estimates that C+C URR=2700 Gb, about 1200 Gb have been produced, 800 Gb are 2P reserves which are not extra heavy, 200 Gb will be added to 2P reserves from discovered resources and there are about 400 Gb of extra heavy 2P reserves with another 100 Gb to be added in the future from discovered resources.
Note also that Jean Laherrere’s estimates are conservative, a Hubbert Linearization on OPEC and non-OPEC crude less extra heavy output suggests a World URR of 2600 Gb for crude less extra heavy oil.
When the 500 Gb of extra heavy is added to this we get a C+C URR of 3100Gb.
See Jean Laherrere’s paper at link below especially fig 31 and 32 on page 21.
http://aspofrance.viabloga.com/files/JL_2013_oilgasprodforecasts.pdf
Climate change is more of a worry.
Dennis,
Did you just state that “CLIMATE CHANGE is more of a worry?”
“I’d buy that for a dollar.* — ROBOCOP
steve
I get that you guys crunch the numbers very hard and I have every respect for that. I am new here. I have been following the wisdom of Jeffery Brown at ASPO conferences and anyplace else I can get his latest updates for almost 10 years. As a non geologist, I would like a layman’s answer for when roughly we will break out of this cycle of $100 – 110 oil? When will the rubber meet the road? What are all your best guesses?
Thanks from all the rest of us who are just trying to plan a life!
Karen
Karen, my best guess is, I haven’t a clue. If I really had a great deal of confidence as to when and which way oil would break out of the current trend, I would put all my money in the futures marked and clean up. But I don’t so I won’t.
Of course part of the problem is two things affect the price of oil, geology and the economy. Well make that three things, politics or war. If the economy crashes then oil prices will drop fast. If it does not but oil production starts to drop then oil prices will rise. Or if things get really bad in Iraq then prices will rise. Or if peace breaks out in Libya and their production gets back to normal, then prices will drop… a little anyway.
So you see, there is just no way of knowing. Sorry I could not be of more help.
Thanks Ron I appreciate that concise explanation.
Hi Karen,
I agree with Ron.
If there are no major wars and the economy continues to grow slowly (no big recessions like 2009 or 1930-33) then the geology points to higher prices. The first two assumptions are pretty questionable and even if correct we don’t know how fast prices will rise, when they will start to rise or by how much they will rise.
Short answer, I have no idea what will happen to oil prices.
Indeed, nice article about OPEC.
And even if it doesn’t change the current situation, getting out of this “OPEC as the root of high prices” myth could maybe help tackle it (the situation) a bit.
And it is indded highly linked to the “myth”, or “false common image” that could be summarized as :
“first oil shock (73) = Yom Kippur/Arab embargo= geopolitical story= nothing to do with geologic constraints”
When the real story was much more :
– end 1970 : US production peak, the energy crisis starts from there, with some heating fuel shortages for instance (some articles can be found on NYT archive on that), or :
http://upload.wikimedia.org/wikipedia/commons/c/c5/US_Oil_Production_and_Imports_1920_to_2005.png
– Nixon name James Akins to go check what is going on.
– Akins goes around all US producers, saying this won’t be communicated to the media, but needs to be known, national security question
– The results are bad : no additional capacity at all, production will only go down, the results are also presented to the OECD
– The reserves of Alaska, North Sea, Gulf of Mexico, are known at that time, but to be developed the barrel price needs to be higher
– In parallel this is also the period of “rebalance” between oil majors and countries on each barrel revenues (Ghadaffi being the first to push 55/50 for instance), and creation of national oil companies.
– there is also the dropping of B Woods in 71 and associated $ devaluation, also putting a “bullish” pressure on oil price.
– So to be able to start Alaska, GOM, North Sea, and have some “outside OPEC” market share, the barrel price needs to go up (always good for oil majors anyway) and this is also US diplomacy strategy
– For instance Akins, then US ambassador in Saudi Arabia, is the one talking about $4 or $5 a barrel in an OAPEC meeting in Algiers in 1972
– Yom Kippur starts during an OPEC meeting in Vienna, which was about barrel revenus percentages, and barrel price rise.
– The declaration of the embargo pushes the barrel up on the spots markets (that just have been set up)
– But the embargo remains quite limited (not from Iran, not from Iraq, only towards a few countries)
– It remains fictive from Saudi Arabia towards the US : tankers kept on going from KSA, through Bahrain to make it more discrete, towards the US Army in Vietnam in particular.
– Akins is very clear about that in below documentary interviews (which unfortunately only exists in French and German to my knowledge, and interviews are voiced over) :
http://www.youtube.com/watch?feature=player_embedded&v=fQJ-0jAr3LQ
For instance after 24:10, where he says that two senators were starting having rather “strong voices” about “doing something”, he asked the permission to tell them what was going on, got it, told them, they shat up and there was never any leak. The first oil shock “episode” starts at 18:00
The “embargo story” was in fact very “practical”, both for the US to “cover up” US peak towards US public opinion or western one in general, but also for major Arab producers to show “the Arab street” that they were doing something for the Palestinians.
In the end, clearly a wake up call that has been missed.
Note : About Akins, see for instance :
http://www.washingtonpost.com/wp-dyn/content/article/2010/07/26/AR2010072605298.html
And his famous foreign affair article :
http://www-personal.umich.edu/~twod/oil-ns/articles/for_aff_aikins_oil_crisis_apr1973.pdf
His report to Nixon in 71 or 72 is still classified to my knowledge though, would be interesting to know if it can be declassified now.
Somewhat my point elsewhere regarding shut in amounts.
The past historical norms of shut in amounts, the various oil embargos, the iran / iraq war (8 years!), the Soviet surrender and upheaval . . . those took not only more barrels off the market, but FAR more % of total global oil output off the market —
in comparison to Libya’s 1+ mbpd, Syria’s 350K, Sudan’s few hundredK, Iran’s 1.5M. This is what, 4 million out of 75?
Those events of the past, decades long events in total, were one helluva lot more than 5% of total supply shut in over those periods.
Face it. The difference is China’s insatiable consumption.
I believe Ron is basically right in saying that the OPEC countries are all pumping flat out, or at least so close to flat out that the difference is negligible.
In effect this means that OPEC no longer has the power to drive oil prices DOWN by raising production , but it does not mean that OPEC has lost the power to drive prices up by cutting production a little.
I suppose it does not matter much RIGHT NOW about them losing the power to drive prices down these days since we are no longer in a cold war with the old USSR which was highly dependent on oil revenues.They certainly would not want to drive prices down for us under current conditions for any reason I can come think of.
But think about this.Consider the possibility that oil prices start climbing fast enough to destabilize the world economy badly enough to threaten OPEC countries .In that case they can’t help either themselves or oil importers.It is almost inconceivable for the moment that we would start exporting democracy to Venezuela the way we did to Sand Country when Saddam got too big for his britches. But who knows what a desperate China or a desperate USA might do in ten years if faced with a bad enough crisis?
It is hard for an armchair guy like me to come by good price elasticity numbers for oil.Maybe nobody has any. But in my estimation oil is price highly inelastic in the short term meaning that a small fall in supply results in a rise in prices sufficient to actually substantially increase the gross revenues paid to sellers.
(Long term is different.In that case buyers have some options such as buying a much smaller car or tossing an oil furnace and buying a heat pump.Governments can opt for mass transit instead of more highway lanes.This does not mean that demand can be reduced enough to actually lower the price of oil. That is probably never going to happen given that the market is constantly flooded with eager new customers and that depletion and rust and inflation never sleep.)
This is a very common occurrence in agricultural markets. Farmers who have half a crop of apples in a bad year for apples nationally get more gross income from a half crop than from a normal crop in a normal year.
So OPEC probably still does have the power to raise prices even though stopping any given OPEC country from cheating on its export quota seems to be a pipe dream.
BUT it is not impossible that OPEC could at least temporarily get its act together again and drive prices up substantially for at least a little while.Politics make strange bedfellows and the OPEC crowd already knows its way around to each others bedrooms. Some thing could happen that would stiffen their resolve to adhere to quotas at least temporarily.
I for one have never believed in speculators controlling prices on any commodity unless we redefine speculators as actual owners of production and distribution.IF a commodity makes it to market the market pays in accordance with demand and supply.
If a so called speculator has a way of holding supply off the market then he must actually be in than case an owner of supply or distribution.
If he manages to accumulate enough supply and hold it off the market temporarily nevertheless in the end he must sell it and thereby depress prices about equally so speculation taken all around is a wash.
Ron has explained this here several times and also at the TOD now archived.What ever price changes are brought about by speculation are short term and average out over a fairly short term as if there were no speculators. Speculating taken all around is a zero sum game with costs taken out making it even worse than zero sum.
WHO calls 11-nation meeting over Ebola crisis in west Africa
UN agency say drastic action needed to fight deadliest outbreak on record in Guinea, Liberia and Sierra Leone
http://www.theguardian.com/world/2014/jun/26/who-ebola-crisis-west-africa
USA Today article on Ebola outbreak:
http://www.usatoday.com/story/news/world/2014/06/28/ebola-west-africa-outbreak/11615045/
This is all the ongoing failure of US thinking to embrace the upcoming paradigm.
Who cares who is pumping flat out?
Why should they? Why shouldn’t they keep it for the future?
Think about this for a moment. You’re the leader of the House of Saud and you get a phone call from the US asking for more production.
You say . . . “but I want to keep it for my grandchildren”.
The US says, “but the world needs it now.”
Your reply at some point has to be . . . “Well, what’s in it for me? I need something more than just the prevailing price. What can you offer? Can you change your form of government to provide Saudi Arabia final say in all of your governmental policies, perhaps beginning with mandatory conversion to Islam of all your citizens?”
The US says “of course not. That’s ridiculous.”
“Well, maybe it’s a bit extreme, but then . . . the situation seems to be extreme, doesn’t it?”
Silence.
Don’t forget that the US (or at least the oil industry) is also very much interested in high oil prices, to keep current production on profit, but also for all the investment aspects.
We clearly are around the breaking point :
– oil prices “breaking” the economies
– barely high enough to keep investment in future capacity going.
Who cares who is pumping flat out?
Why should they? Why shouldn’t they keep it for the future?
Alas, the Arab word is subjected to the same immediacy bias as the rest of us. Humans in general discount the future for the present — we don’t really care what happens to the world in 50 years.
If we have oil that we can extract and sell at a profit now, we tend to extract it now. So yes OPEC is pumping flat out right now — high oil prices are great motivator to do so. If oil prices were $10/barrel and it cost OPEC $20/barrel to extract the oil, then OPEC certainly would conserve.
But there are other ways. Perhaps: “Our reserves have been greatly overstated. We just don’t have it.” (even if they do) A desire to keep it in the ground could evolve to be very powerful.
In general Saudi analysis has always said “we cannot shut down production to spike price because that destroys our customers and reduces our own revenue”.
But surely they have noticed that they are still selling oil at $113? Why not take it up to $120 with a discussion of “saving for grandchildren”.
About two years ago when the wacko Iraqi oil minister (the one who saw 15 mbpd by 2017) was faced with low production . . . HE came out and said, we are considering not pursuing this large production and keeping the oil for our grandchildren.
But I must say I never heard that from him again.
Well yes, Iraq is the only place where i the world that in a way or an other, they will keep the oil for future generations, but it is planned not for theirs ones.
Giovanni
RE: Opec,
Asian customers have money to spend on petroleum b/c Americans buy Asian goods (junk). In so doing they indirectly lend Asians the money they use to buy the petroleum.
Because Americans are buying Asian junk, they are the ones responsible for retiring and servicing the loans that allow Asians to both buy- and burn fuel … to bid world oil prices.
Only American interests that gain are Wall Street (lenders), domestic oil producers (sell @ world prices) … auto industry (skims off the top): basically a handful of tycoons.
Bankruptcy from every side: US imports fuel, exports its jobs. Asia, US and the rest combine to consume (destroy) what remains of irreplaceable capital faster than any one country could do by itself. The countries indenture themselves to bankers in order to do so. At the end of the day we are out of fuel + massive overhang of debts + insatiable bankers and tycoons desperate to find suckers to retire these debts = ruin. We are all Iraqis, now.
You couldn’t invent such a crazy system if you tried … too bad the space aliens imposed it on us by force.
There is a certain element of twisted genius in Steve’s reasoning. It is hard to agree with him in detail since he paints with a very broad brush but even harder to disagree in general terms.
His remarks have caused me to think of something that has been on my mind a long time.
The so called free world other than the US has long been getting a free ride at our expense it military terms.We have borne the main burden of keeping things more or less peaceful and the sea routes open ever since I can remember.Vietnam may have been a mistake but if we had not fought there and in Korea the world would be a very different place in terms of empires today.If we had not fought in Sand Country for the last couple of decades the world would be a very different place in terms of empires and power centers.
Maybe things would be better for the world in general but my estimate is that they would be much worse for us Westerners.
If Saddam had managed to maintain control of Kuwait what would the international oil markets have looked like? Who would he have formed alliances with and sold to under favorable terms?
Would Iraq be a nuclear power today? In that case so would be Saudi Arabia and maybe a couple more countries. The Saudis would have found a way to get the bomb if Iraq got it.
The fact that no convincing evidence of weapons of mass destruction were found in Iraq is not evidence that Saddam or his successors would not have gone to work on getting some later on.Personally I find it hard to imagine that he would not have eventually gone for the bomb given his history and the danger of his country from a nuclear Iran.( not yet but only because we are ” over there ” in fact and in principle via sanctions)
We have succeeded in preventing Iran from getting it so far but with the changing international power balance I am not sure we can stop them too much longer.
I can’t see Obama sending our navy to intercept ships headed to China from Iran if and when the Chinese choose to ignore our efforts to isolate Iran.They need us for now more than need them but how long will that last?ONE ANSWER- ONLY for so long as they can get rid of our dollars by buying things with them on the world market.Another answer- maybe only for a few more years until they can develop their own consumer economy and build up their own MIC to the point they can dominate their hemisphere.
Of course we had some help on the ground at times but the burden in treasure and most of the burden in ( western) blood has been ours since WWII.
BUT we are getting it back in terms of screwing the world with the almighty dollar. At some point all our friends and our enemies as well are going to bitterly regret ever holding a dollar because it will be worthless.
An economic crash does not necessarily mean the end of the human species or the end of industrial civilization but it sure as hell means that we Yankees are never going to pay our accumulated debts.
One would think the Iranian price for helping Maliki would be undoing all sanctions, or maybe blending Iranian oil with Iraqi and flowing it out of Basra. Payment to Iraq who then sends half to Iran. Let’s the US save face.
“One would think the Iranian price for helping Maliki would be undoing all sanctions”
FWIW: I suspect the US is letting ISIS invade Iraq as to tool to get rid of Maliki in favor or someone else. Its been well know for quite some time that the US State dept wants Maliki gone.
Recall that the US let the Shah get booted out of Iran for simular reasons in 1979. Unfortuntely the plan didn’t go as planned as the Islamists took over instead of getting a replacement for the Shah that they wanted.
1. The US could have started airstrikes on ISIS and at least slowed them down.
2. The US directly or indirectly funded ISIS in Syria (Weapons, Ammo and training)
3. KSA is likely pulling the strings of ISIS in attempt to remove the Shia from control of Iraq. Its very likely that KSA (sunni controlled) is funding ISIS (Sunni)
A powerful item not prominent in the MSM is what QE has done to the concept of money.
This is a significant part of why, going forward, it may not make sense to presume price will define drilling. Price may be meaningless. Things can unfold such that no one cares about amounts of a whimsically created substance, ie, money.
As for debt, who cares about owing whimsically created substance? We saw this overtly in Greece. They had debt. The EU orchestrated an obfuscated default, while forbidding the screwed creditors from collecting on the debt insurance they had bought (aka credit default swaps). Allowing the swaps to trigger risked the global system, so with a wave of a hand, debt disappeared and legally binding swap contracts were decreed void.
So . . . think not too very much about money and oil. It’s not really very different from thinking about air and oil, as in created from thin.
Central banks cannot create ‘new money’ (make unsecured loans). They are collateral constrained. Only private-sector finance can make unsecured loans (as they do they become insolvent).
If the central bank makes unsecured loans (or it takes the defective assets of the private sector as collateral) it also becomes insolvent like a private sector bank. The outcome is no lender of last resort = bank runs. This is occurring in Argentina and Venezuela right now (also Japan).
What determines drillers’ costs is geology, what matters is drillers’ costs relative to all the other costs. I don’t have to tell anyone over here that every new barrel costs the drillers more energy/materials to extract every day.
What we do with oil after we have it in hand is non-remunerative: we drive oversize metal boxes in circles on flat petroleum surfaces. Consumers cannot meet the cost of fuel (or car, roads, military machine, credit or anything else) by driving; to meet drillers’ etc. increasing real costs the customers must borrow … more every day. Like drilling, credit has exponential costs as well since the only way to retire and service the ballooning debt is to borrow more (according to the Federal Reserve records) …
… a lot more …
… something on the order of 7- or 8 hundred trillion dollars (according to Bank of International Settlements)! Cars are expensive we just don’t have a handle on how costly they really have turned out to be.
Bookkeeping: Expenses – Income = zero.
(Cost of fuel + cost of credit) – (returns on use of fuel which is zero) = 0
We must borrow all our returns. No wonder we’re broke.
There is a wealth of useful quotes in this humdinger of a Houston Chronicle piece:
http://www.houstonchronicle.com/business/energy/article/Junk-debt-exposes-shale-firms-to-Fed-changes-5585184.php
a) ”Higher interest rates might make risky new bond issues by shale producers less attractive, and a flight of investor capital could leave the producers short on a commodity even more precious than oil: Cash.
“This might work out for a single producer in the Eagle Ford or the Bakken, but for an industry as a whole, this is not very sustainable,” said Vivendra Chauhan, a London-based analyst with Energy Aspects. A survey of 35 U.S. oil and gas producers by Energy Aspects showed their revenue and capital expenditures were essentially one to one. ”
b) ”The U.S. Energy Information Administration projects that nearly four of every five new barrels of oil produced in North Dakota’s Bakken Shale and South Texas’ Eagle Ford Shale simply replace output lost to the high depletion rates.”
c) ”Shale companies outspend their cash flow to keep their production rates up, and results get poorer but more expensive as operators drill farther away from a play’s best areas.
Production from shale wells typically falls 65 percent to 90 percent in their first year, according to the Oxford Institute.”
and so on…….most well informed piece from the MSM I have seen – Houston, we have a problem….
It’s behind a pay wall but you can get the whole article if you copy and paste the below title into the Google search bar.
Shale’s junk debt could get shaky if Fed raises rates
About 80 percent of the 115 exploration-and-production firms that Moody’s Investors Service follows are junk rated, as are more than 70 of the 97 companies under Standard & Poor’s purview.
Ron Quoted from Article:
“Shale’s junk debt could get shaky if Fed raises rates”
I don’t believe the Fed is going to raise rates anytime soon. Q1 2014 GDP was revised down to -2.9%. Higher taxes, more gov’t regulations and Obamacare are taking a toll on the economy which was already shaky. Interest rates are very likely to continue to decline for the rest of the year.
That said, I do believe the creditors will take away the punch bowl from LTO drillers, probably in the next 12 to 18 months. Creditors will only lend as long as the LTO drillers can show solid growth. Based upon your work and others, it appears that production growth is slowing and will probably stall in the next 12 months. After that I can’t see creditors continue to loan billions every year.
The Fed can’t raise rates! High oil prices are stifling the world economy… raising rates would send the world economy into a tailspin.
If only governments would smarten up and take advantage of those super-low rates to invest in the infrastructure needed to transition us to a post-carbon economy. A transition that would put a lot of people to work… and there is certainly need for that.
The famous line with respect to the Fed is that it is supposed to “to take away the punch bowl just as the party gets going”.
There is no party… folks can’t afford the gas to get to the party.
The Fed rate is low because the price of oil is high. As we know here at POB the price of oil can’t come down because the marginal cost of production requires high prices. So the only option left to us is to become brutally more efficient in our use of energy, and out of necessity to transition to solar and wind.
“The Fed rate is low because the price of oil is high. ”
No, Actually part of the reason why the price of oil is high is because interest rates are at rock bottom. If the Fed raised rates it would likely trigger deflation. Demand for energy would contract and the price would drop as it did back in 2008/2009 (Oil dropped to about $30/bbl back in Jan/Feb 2009). The Dollar lost about 1/3 of its buying power since about 2000. If you adjusted for the dollar’s decline the cost for a barrel of oil in the year 2000 dollars is only about $66/bbl. Adjusted for inflation, the price of Oil is about the same it was in 1980:
http://inflationdata.com/Inflation/Inflation_Rate/Historical_Oil_Prices_Table.asp
year bbl adj for inflation
1980 $37.42 $106.36
Considering that the the US interest rates in 1980 were about 14%, we got it easy compared to back then!
The Fed cannot raise rates because the US gov’t and many businesses are insolvent. The US gov’t already pays about $400 Billion on just interest payments on the debt at current rates. If the US interest rates normalized, back to about 5% the interest payments on the debt would soar to about $1T per year. which would be close to half its revenue. The US gov’t would have to cut its spending in half just to service the debt.
You might be assuming that raising rates would lower the price of oil, probably yes in the short term. But we saw post 2009 the price of oil climb back up to ~100/barrel even though the world economy still sucked.
It’s the marginal cost of production that counts now, not demand.
As Kopits presentation pointed out it’s supply that matters now… not demand.
Finally looking at the real oil price chart you linked to. I think it would be fair to say that 1980 was an anomalous year that was largely due to geo-political events and not a geology driven supply problem. from 1986 to 2003 the real price of oil was mostly well under $40/barrel.
The present context is profoundly different from the past.
AWS wrote:
“You might be assuming that raising rates would lower the price of oil, probably yes in the short term. But we saw post 2009 the price of oil climb back up to ~100/barrel even though the world economy still sucked.”
Your basically agreeing with me then. Interest rates dropped when the Fed begain ZIRP (Zero Interest Rate Policy) and QE when oil prices began to rise in May-June 2009. Bernanke announced QE in March 2009 the week when the S&P hit 666. In 2008, the Fed was raising rates. and rates completed normalization during July-August 2008, right when the oil prices began to correct. I believe in August 2008, rates peaked 5.25%. Rates were also much higher in 2008 ~5% when Oil was at $147/bbl.
If rates normalized, demand would decrease, especially in Asia since the US consumers would be buying less plastic crap. And all of the other central banks would be forced to raise rates to prevent capital from leaving, causing global Oil demand decreases. The US dollar would also strengthen as demand for dollars would increase as investors sought to invest in the US again seeking higher returns on bond investments. Lenders are not lending to Americans because there is no interest yield. Which would you rather do: Lend out your savings for 0.1% or 5%? I betting you rather collect 5% on your savings then 0.1% which is well below the rate of inflation. So investors choose to invest in Asia because the returns are much better than in the US. So if you want more investment in the US, the US needs to normalize rates again.
“As Kopits presentation pointed out it’s supply that matters now… not demand.”
No, Kopits argued that supply can’t keep up with demand. Demand for Oil in Asia remains strong despite higher prices because of Credit bubble. Low US/EU interest rates is causing investors to invest oversea as they believe there are higher returns by investing in Asia which is fueling the Asian Credit bubble. Consider that, until very recently the economy was booming in China, as there was a massive investment in infrastructure in China. So much, that auto sales in China 1/3 more than in the US. In 2013 China sold 22 million cars in China. The US sold 15.6 million in 2013. The cost of oil is sold at a premium in Asia. I believe oil prices in Asia was around $112-$120/bbl in 2013. So to suggest that higher prices oil caused low interest rates is pure bunk!
“Finally looking at the real oil price chart you linked to. I think it would be fair to say that 1980 was an anomalous year…”
You completely missed my point. Look at the unadjusted cost of oil in 1980: $37.42 avg per bbl. In 1980 $37.42 was equivalent to $106 in 2013 dollars priced in oil. If the value of the dollar didn’t depreciate, we would only be paying $37.42 per bbl today. The dollar has lost 2/3 of its value since 1980. Interest rates were 14% even though the price of Oil was high. Thus High oil prices didn’t cause low inflation rates.
Your assumption that oil prices and interest rates are directly correlated is wrong. The reason why interest rates are rock bottom is because the US is insolvent and the Fed has to keep real interest negative to prevent the US from defaulting. However, ZIRP is unsustainable and eventually judgment day will come.
Hypothetically, Lets suppose next month 10 supergiants are discovered and the price of Oil drops to back to $10/bbl. The Fed still would not normalize interest rates because interest payments would rise to $1T per year, which would force a default.
TechGuy,
I am on the same page as you here.
I covered some of this issue some time back in the post CENTRAL BANKS’ BALANCE SHEETS, INTEREST RATES AND THE OIL PRICE
Economic growth (as expressed as GDP) is well correlated with growth (changes) in debt. To me it appears as the world is getting close to using up their balance sheets.
Thanks Rune,
I am just trying to point out that besides an energy crisis that the world also faces debt and demographic crises too. I fear at some point all these problems will converge at the same time creating the perfect storm. When one them happens is going cause the others to happen like dominoes, as they are inter-dependent.
I’d say no. Most junk rated debt is not extremely short term, which is what the Fed can control.
Longer term rates, enraging most of Wall Street, have been in decline this year from 3% January to 2.5% now (10 USTs). That reflects a presumption of eroding economic activity, certainly confirmed by Q1’s -2.9%.
The higher rates are coming story is entirely dependent on buoyant economic growth, which is frankly hard to see at $113 Brent.
Thanks for the graphs and the work you are putting into this.
It would be nice to have the very first graph with all counties as a stacked area graph
http://office.microsoft.com/en-au/excel-help/present-your-data-in-an-area-chart-HA010218671.aspx
I am really loving the theme/design of your site. Do you ever run into any web browser compatibility problems?
A couple of my blog audience have complained about my site not operating correctly in Explorer
but looks great in Chrome. Do you have any suggestions to help fix this issue?
Rockman posted over on PeakOil.com concerning this post above, which was re-posted there:
rockman on Sun, 29th Jun 2014 9:20 am
A nice focus on the reality of the Bakken. I wish he had gone to the next logical step and express what his data implies. So I’ll stick my nose in and do it. I’m by no means an expert in the Bakken. But after 40 years of chasing oil/NG I do understand a few things about trend development. The first thing you learn is that there is no such thing as the “average production” of wells in a trend…which is often misused to predict future production. One can certainly do the math easy enough but that doesn’t mean it should be used as many do. The simple analogy: two tubs of water…one at 200F and one at 0F. So the “average” temp is 100F so it should be comfortable to stick your hand in either…right? Obviously not. Same dynamic when taking the average production of the sweet spot Bakken counties and project similar future production in counties where little drilling is currently happening.
The oil patch generally does a good job on focusing on the more productive portions of a trend. It was even easier to do in the Bakken because it wasn’t a new trend: it had been tested with vertical wells for 50 years before the horizontal boom began. That allowed the oil patch to focus on the sweet spots from the start.
So what do the optimistic Bakken “experts” do? They take drilling results of the best areas the companies concentrate on and assume similar future drilling results in the areas that the companies specifically avoid. A great example: about a year ago a well was drilled into an untested area where cornucopians would have done such an optimistic projection. Now I bet you think I’m going to tell you the well underperformed. I’m not. The well didn’t underperform. It didn’t perform at all: the Bakken formation wasn’t even present in this area. Amazing with a half century of drilling they didn’t know there was no Bakken in this area, eh?
Essentially they stuck their hand into that 200F water…ouch. But the averagers can take a well with no Bakken production and add it to a well that produces 400k bo. And…Ta Da! The average well in the two areas produces 200k bo. So they can take the area where there is no Bakken reservoir, divide it by the average unit size to give # future drill sites and proclaim # X 200k bo of future production…from an area where the Bakken doesn’t even exist.
Certainly simple “logic” any fool can follow…as many do.
I had no idea that’s how they estimated the URR of the Bakken. However I am familiar with the wells I think you are talking about.
Chesapeake Drills Unsuccessful Wells in Southwest ND
But you did not stick your neck out far enough. How do you see Bakken production playing out in the next few years? Some “experts” see the Bakken peaking at about 1.2 mb/d within the next 12 months or so. I tend to agree with that assessment. Do you?
I talked about “Survivorship bias,” on a prior thread. Here’s an example from an oil field in West Texas. URR were about 4 mb, from 38 wells, plus casinghead gas.
Peak annual production was 441,000 BO from 38 wells, at 32 bpd per well.
Annual production in 1972 was 121,000 BO from 30 wells, at 11 bpd per well.
The six year decline rate in average per well production was 18%/year. If we applied this decline rate to the 38 wells producing in 1966, the total production in 1972 would have been 151,000 BO, when the actual production was 121,000 BO, because 8 wells were no longer producing.
This is the problem with taking an average projected decline rate and applying it to all currently producing Bakken wells, i.e., a lot of the wells aren’t going to see their 5, 10, 15, 20 year and so on birthdays.
Anyone have any data for total number of Bakken wells that were completed from about 2007 to 2013 inclusive that are already plugged and abandoned or temporarily abandoned?
How long does the owner have to P&A a Bakken hole? Is the the same in both states? Who pays if the owner/driller goes bust?
Bingo.
If it’s a hazard to the citizenry, then the state would demand the most recent owner pay to P&A it. Of course, if he’s a bankrupt LLC, all assets having been drained a priori, then there is no pocket to tap.
Note however that EPA has had the power in the past to go after previous owners, not just current owners. That could be interesting.
Hi Jeff,
As Enno already pointed out, the survivorship bias is corrected by filling in zeroes for wells that are no longer producing, that is what he does with his data set. We only have data out to about 6 years, but the data to that point includes all months since a well started producing, if it produced no oil during any month then that zero level is part of the average. Likewise when we project future well output for an “average well” some wells will produce zero, and others will produce more than zero and the average is the output divided by the number of wells.
When the wells are down to a couple of barrels per day it does not add up to a lot of oil.
For Bakken wells completed between Feb 2007 and November 2013 2% had zero output for at least their final three months of reported production (last reported month for data set was February 2014). This is based on 6800 wells.
Note that not all of these wells are necessarily plugged and abandoned, many are probably just down for maintenance. It is not uncommon for a well to be taken off line for 3 or 4 months and then be brought back online.
Rockman on Sun, 29th Jun 2014 11:16 am
Ron – I think the data presented in this report could be the best induction of the future. Given these counties have produced the surge in Bakken production each person here can look at the plots and judge the future projections for those areas. I think most will project much of that activity will be falling off. And given the established high initial decline rates production in these counties will drop significantly as drilling falls off.
So how will future production in the rest of the Williston Basin play out in the Bakken? If one assumes the oil patch has been ignoring areas of the play that are just as sweet as what has been developed then the future looks bright. And if the oil patch isn’t brain dead then the optimists might be a tad too optimistic IMHO.
Hi Ron,
Using Wes’s data I don’t really see an end to the increase in Bakken output coming very soon. I am not sure which optimistic projections Rockman is referring to, there are some very optimistic estimates that I don’t agree with, but 8 Gb (which is in line with the mean USGS estimate) seems reasonable. There are some very pessimistic estimates that are over a billion barrels below the proved reserves plus produced oil at the end of 2012 (3.8 Gb), those estimates don’t seem very reasonable to me.
According to the logic of PO believers in regards to average wells in the Bakken….The sexual characteristics of the average human on planet earth is best represented by shemales. Go figure.
I couldn’t disagree more with Rockman’s assertion, that the oil industry has concentrated it’s efforts on the sweet spots first. This is an oft repeated fallacy of PO believers, that is not supported by the factual evidence presented by the people on the ground doing the actual work.
As proof, I invite all open minded participants in this forum to simply go to KOG’s website @ kodiacog.com, click on their June Investor Presentation, and proceed to page 7. There you will find a map of most of THE 10,000 SQ.MILE SWEET SPOT (thermally mature area), surrounded by the 4,000 sq. mile not so sweet spot (marginally mature area) also with some dead areas showing, mostly to the far NW and SW. The exact bulls eye of the entire oil producing Bakken is in the area just east of the word Koala and south of the river. See all the fuzziness there? That’s what the map looks like when CLR does it’s well density projects with 16 wells /sq. mile, or 32 wells/ spacing unit.
Then, look at the EUR’s KOG gets from their various land positions shown in yellow. Anyone believe me yet? Now start counting all the wells….There’s probably only about 6 or 7,000 wells shown here. The rest (1-2,000 wells) are completely outside of this core area,…and getting very low EUR’s,… that then get AVERAGED into the mix.
Anyone can see that the vast majority of acreage in this giant sweet spot only has 1 or 2 wells per spacing unit, and these are thereby just LEASE HOLDING WELLS. The few wells in the mostly empty areas are only EXPLORATORY WELLS, and most likely have very low EUR’s. The few very fuzzy areas with much well density are only EXPERIMENTAL WELLS. These wells are all located on the very sweetest spots within THE SWEET SPOT. Notice how spread out they all are from each other? That’s the proof of how big the sweet spot actually is, and how under developed it still is. NOT ONE SINGLE COMPANY IS INVOLVED WITH ANY FULL FIELD PRODUCTION AT THIS TIME. The first PILOT project doesn’t even start until 2015!!!!
If CLR’s full field development plan calls for 16 wells per sq. mile, and there is a 10,000 sq. mile area where this will be applied, can anyone figure out how many wells that will take? Then add in 8 wells per sq. mile for the surrounding 4,000 sq. miles, plus all the unknown amount of wells outside of that area, most of which will not get more than 300k EUR’s on average with today’s technology, and are thereby of questionable economic value anyway.
I think you people should start focusing on how many wells there will be, not on average EUR’s /well. Then, maybe, just maybe, some of you will start to see the light. The 903 billion BOE that CLR is referring to is mostly located right on that map. The bottom still hasn’t been located yet so it’s still growing, but it’s already Ghawar sized. And, you people think it will peak tomorrow?
What a surprise. Another promotional post for Continental Resources.
Jeffrey J Brown,
Has it ever occurred to you, that this very web site just might well be the very worst place in all of cyberspace to push an oil stock???
I DO NOT PROMOTE CLR IN ANY WAY WHATSOEVER,…AND YOU KNOW IT!!!
WE can all clearly see your complete lack of response to the CONTENT of my post.
Here’s some videos explaining exactly what you are doing here, and why.
http://youtu.be/exdK7Lirngg
http://youtu.be/v5vzCmURh7o
Why don’t you contribute something of value to this forum?
Comments like yours are the main reason why the general public does not believe in peak oil.
One can see why the Oil Drum editors told you to get lost.
When I encounter the acronym ELM, I immediately think “Export Land Model”
That concept is quite a contribution to how we model the peak.
I don’t think Jeffrey Brown deserves anyone screaming at him in ALL CAPS given what he has contributed.
Aws, I deleted the post you replied to for that very reason.
Ron
Jeff always makes well reasoned (often humorous) contributions to Ron’s Blog. I’ve no idea who way “yelling” at him, but it’s certainly not warranted — under ANY circumstances.
They may not enjoy thinking about it but there is a day coming when Jeff and Ron are going to be pretty popular with MSM journalists.They may have to go into hiding or hire body guards to keep the paparazzi away.
I wonder if Forbes will fire MrLynch and offer them jobs as columnists..Even a poor cow college guy such as myself can tell the difference between moonshine and oil and I have never even seen an oil well or an oil refinery – except for a very small one.
We are going to be in a hell of a fix once we get to running on that sort of oil altogether because too many drivers are going to have a snort or two while filling up at self service pumps.
I think maybe I will send a copy of my resume to the Colorado School of Mines.
I guess they will be needing some all around agriculture guys pretty soon given the new definition of oil.I have extensive experience with several varieties of ag oil, including peach, corn , barley, rye,apple, and the emergency sort made out of plain old table sugar.
I think Jeff and Ron may need to go into hiding, but in the same way as Aljazera reporters in Egypt. Telling the truth is more likely to be a criminal activity than a U turn from the MSM on this issue.
I am not afraid of heat pumps per se if they are sold in the form of refrigerators which are in service twenty four seven three sixty five and are sold by the millions. Fridges are pretty reliable. So are window air conditioners. The problem with reliability and service arises when units are sold in low volumes and nobody really knows how to work on them and because of the initial low volume the dedicated parts are a pain in the ass for the manufacturer to keep in stock due to the low call for them years from now and since they never did sell many units in the first place they can get away with just leaving the customer hanging.
They can’t get away with that with fridges because the stink would ruin the brand name.
It is good shopping wisdom to never buy a low volume item of any sort unless it has very high utility because it is far more apt to break than an equivalent product sold in large quantities to the public.
And while a dryer is a real juice sucker the one at my house is used only an hour or two a week.
Now if I were the benevolent dictator of this fine country I would mandate the availability of all functional parts on a sliding scale based on price of everything sold. The more expensive the item the higher the time standard. Cheap computers would be ok at three to five years. Applainces that cost over a thousand buck would have to be guaranteed repairable for twenty years.
There is no doubt in my mind that for anybody with money available and a reasonable intention of staying put one of these heat pump water dryers or water heaters would be a great investment if it has an extended warranty.I personally expect retail electricity prices to rise at between five and ten percent a year on average for the foreseeable future.
And ten or fifteen years down the road they will probably be mandated and the old resistance heaters outlawed. But at that time they will also be sold in large numbers and therefore much cheaper relatively speaking.
Low volume equals high cost. I can get a good water heater for four hundred bucks with a long term warranty and a good air conditioner for the same money. No way in hell does it cost an extra seven hundred bucks to integrate the two considering the savings in shipping and packaging and actually marketing the heater.
That extra seven hundred is markup and marketing and advertising and above all the price of low volume manufacturing and distribution.
Now as far as hot water is concerned – the volume used is such that the payback time should be a lot shorter on average and that would help justify the higher initial cost of a heat pump hot water heater.
I built a solar domestic system from odds and ends of stuff that supplies about three fourths of our domestic hot water and so I will probably never buy a heat pump hot water heater or dryer. If the govt mandates such a purchase I will buy a couple of spares and put them in the big barn during the blowout get rid of them sale.
Three hundred watt clear incandescent bulbs are priceless now.I have only half a dozen left and can’t find any more at any price even at a flea market. I use them only a few hours a year but I gotta have them or spend a small fortune installing new lights with adequate output.
I should have bought a truckload of small cans of freon for fifty cents a can when it was outlawed. Car collectors are paying twenty bucks or more a can for it now if they can find any.
“I should have bought a truckload of small cans of freon for fifty cents a can when it was outlawed. Car collectors are paying twenty bucks or more a can for it now if they can find any.”
Propane will work as a substitute refrigerant, but the system needs to be clearly label since it has to be completely purged before tubing joints are re-soldered (for obvious reasons). Propane is even a more efficient refrigerant than R-22
Thanks for that bit of info. I have never known of anybody putting propane in an automotive ac.The guys that want real Freon R12 are not going to open a can of it until they are ready to take their car to a high dollar show when everything has to be exactly as original to have a shot at winning.
The little cans are like Barbie dolls. Collectible in the original packaging.
The older hot rods and classics on the street are virtually all converted to R22 which works just fine in my opinion.I didn’t notice any difference in my old trucks ac output when I converted them.
I intend to be ready the next time the nanny state outlaws something and buy up as much as I can afford. I wonder how many people have noticed the actual results of efforts to outlaw guns. The people who manufacture and sell them are running flat out and getting rich. Ditto for ammo manufacturers.You can’t buy a box of plain old twenty two s any more without getting lucky and hitting the store at the same minute a delivery is made.
But eventually the people hoarding ammo are going to realize it is not going to get super expensive anytime soon and that it is not going to be outlawed.
Given time they will give up on making a big profit on it and start selling it at yard sales for about half what they paid for it when it becomes obvious it is getting stale.
If oil wasn’t so hard to store in large quantities I would buy as much diesel as my finances would allow since I am absolutely convinced it IS going to go up pretty fast over the next few years.
Now here is another useful tidbit most people don’t know. You can run a diesel tractor or truck or car on plain old heating oil in a pinch.It is not good for the engine but it is not going to destroy it in short order either.My maternal grandfather ran a farm tractor on heating oil for many years because it was a little cheaper and it never gave any problems.Sometimes you can get a hundred gallons or even more for free or for next to nothing just for hauling it away when somebody gets rid of an old oil furnace and upgrades to a heat pump.
This could be a critical bit of knowledge in the event of the unspeakable actually happening. A drum of diesel in a post WWIII mad house would be priceless. I could plow and plant enough corn with fifty gallons to feed a whole lot of people for a long time. Ditto a home heating oil tank full of furnace fuel. It’s nasty compared to regular diesel but it is basically the same stuff except for being less contaminated with corrosive substances that are not good for engines and not having some additives to improve its lubricating qualities.Fuel injectors and fuel injection pumps are VERY expensive. So stick to real diesel if possible but if ever there comes a time when it is either heating oil or no oil……………….
That should read more contaminated.
OFM Wrote:
“Now here is another useful tidbit most people don’t know. You can run a diesel tractor or truck or car on plain old heating oil in a pinch.It is not good for the engine”
To my knowledge they are the same. The only difference is the the red dye to distinguish it for the road tax. As a Farmer, you can legally buy non-road diesel if you only use for vehicles on your land (ie tractor, or truck). In some states with heavy fuel-road taxes its a big savings.
“A drum of diesel in a post WWIII mad house would be priceless. I could plow and plant enough corn with fifty gallons to feed a whole lot of people for a long time.”
There is another option. During WW2 when Diesel was rationed or not available. Farmers used wood gasifiers to run their tractors:
http://en.wikipedia.org/wiki/Wood_gas_generator
“During World War II gasoline was rationed and in short supply. In Great Britain, France, the United States and Germany, large numbers of such generators were constructed or improvised to convert wood and coal into fuel for vehicles. Commercial generators were in production before and after the war for use in special circumstances or in distressed economies.”
“The US Federal Emergency Management Agency (FEMA) published a book in March 1989 describing how to build a gas generator in an emergency when oil was not available”
Here an article on how to build one:
http://journeytoforever.org/biofuel_woodgas.html
Of course most farms don’t have a lot of wood or coal available so this probably has limits. Also the engine will produce less than half the power output as petro. You can use gasifiers on both Gasoline and diesel engines. You would need some petro to start the engine.
That said the biggest issue is going to be fallout from both bombs and Spent Fuel pools at nuclear reactors.
http://commons.wikimedia.org/wiki/File:Fallout_map_USA_(FEMA).jpg
Although I don’t think this map includes the fallout from nuke power plants which will fail without constant maintenance. I am pretty sure that the entire nation would be in red if they were included.
I think the only practical way is to to protect the soil from fallout is with acres of plastic sheeting. If you can keep the hot particles from contaminating the soil it will be safe. without it, the plants will absorb the isotopes and end up in the food. You would have to protect the soil before the fallout happens and remove it after most of the fallout settles out. Probably a couple of years. Greenhouses would probably be affective option to grow food, until the fallout settles out. The plants will get hit with radiation but they would absorb hot particles. Plants are much more resilient to radiation than animals and humans. You would of course need a water source that isn’t contaminated.
Personally, I would plant beans over corn since, corn is mostly starch which isn’t healthy (gets converted into sugar during digestion ie diabetes). Beans are the closest approximation to protein. Plus, beans are Legumes which can also perform nitrogen fixation via soil bacteria and avoid the need for external nitrogen based fertilizers. But avoid Soybean since it produces an endocrine disruptor. Navy beans, Pinto, Lentils, Peanuts are all good sources for food.
“If oil wasn’t so hard to store in large quantities I would buy as much diesel as my finances would allow since I am absolutely convinced it IS going to go up pretty fast over the next few years.”
OK with diesel, but gasoline has storage issues since over time the Butane in the gasoline will evaporate out making it difficult to start engines. Gasoline also has oxygen additives which will break down and react with the gasoline over time.
Large amounts Diesel can be stored in home heating oil tanks. You need to add a additive to prevent microbes from growing. You can store the tanks in a shed or outbuilding.
Potatoes, peanuts and walnut trees — maximum calories per unit acre. Unfortunately it takes a walnut tree 7 yrs to begin yielding.
Odd ancillary tidbit, you can plant coffee in elevated tropics essentially under banana plants. It needs shade, and draws nothing from the soil for calories, so the bananas are happy.
As I said before my old grandfather ran home heating oil for years without problems in his diesel tractors. Most older people will tell you it is ok.Most farmers in times gone by did the same.
And truth be told many a distributor is probably still delivering furnace oil out of the same tanks as diesel.
But times change.
A diesel injection pump overhaul or replacement is apt to cost well into four figures and real diesel fuel is supposed to have additives to give it better lubrication qualities and detergents to keep that pump and the injectors clean.Fuel injectors cost hundreds of dollars EACH.
IF you want to run heating oil as diesel you should at least understand that you are probably shortening the life of your engine even though you may not realize it. You can live a long time smoking cigarettes. A diesel engine can run a long time on crappy fuel. But three thousand hours is not the same as eight or ten thousand hours.
Here is an excerpt from the state of Alaska’s official website.Pay particular attention to number three.
xxxx
1. What is ultra-low sulfur diesel?
Ultra-low sulfur diesel (ULSD) is diesel fuel containing a maximum of 15 parts per million (ppm) of sulfur. Previous sulfur levels were up to 3,000 ppm for Alaska’s on-highway diesel.
2. Will the newest diesel engines require this fuel?
Serious damage will occur without it. Sulfur in diesel fuel must be lowered to become compatible with modern pollution-control technology being installed on later model diesel engines. This equipment will reduce fine particles (soot) and pollutants in diesel exhaust by over 90%.
3. What happens if I fuel my new truck with the old high sulfur fuel?
Incorrectly fueling a 2007 model year or later engine with high sulfur fuel will damage the emission controls. The catalyst will be rendered useless and the emissions will not be controlled. Excess sulfur will plug the particulate trap which may cause a back pressure and possibly damage the engine. Fueling a 2007 and newer model year engine with high sulfur fuel will void the engine warranty and is against federal law.
4. Why is EPA doing this?
Over the last few decades, health scientists have demonstrated negative health impacts from exposure to diesel exhaust and soot. Exposure to diesel exhaust is widespread and there is increasing evidence that diesel exhaust or soot may cause lung cancer and aggravate health conditions.
5. Will my old diesel engines run on ultra-low sulfur diesel?
Older vehicles and equipment will run on ultra-low sulfur diesel and will experience a small reduction in particulate matter. Operators of old diesel engines may want to replace gaskets and seals as very old gaskets shrink and leak when running on low sulfur fuels. However, EPA and the Engine Manufacturers Association do not anticipate problems burning ultra-low sulfur diesel in old engines. On the other hand, vehicles and equipment outfitted with new emission control technology ( e.g. diesel vehicles with 2007 model year and later engines can fail if run on the high sulfur diesel fuel).
xxxxxx
Times change.
Some evidence that heating oil is not formulated the same as current day diesel:
http://www.eia.gov/todayinenergy/detail.cfm?id=5890
I am pretty sure before the EPA changes Diesel fuel and home heating oil had the same level of sulfur content.
I found this article about the differences:
http://www.ehow.com/list_5970492_differences-heating-oil-_amp_-diesel.html
“Shortages in some types of fuels sometimes results in distributors blending fuels like kerosene, jet fuel and different diesel types with traditional heating fuel into one fuel. This fuel is then sold as home heating fuel. Furnaces that burn heating fuel are more forgiving than vehicle engines are, so this blending is not a problem. Diesel engines require higher-quality fuel so that the fuel burns consistently and generates the proper compression, so this blend would negatively impact the engine’s performance.”
[This probably doesn’t affect the life of the engine, but the performance]
“Heating fuel lacks an additive which lubricates the piston and o-rings. Without this lubrication the engine will quickly seize up. Diesel fuel contains this additive. According to Exxon Oil Company, this additive has been required and included for several years.”
[OK, but seems odd since it indicates that the refineries started adding a lubricant in the past few years, but it didn’t have it before? Perhaps because they are removing the sulfur they have now add a lubricant]
Hello Mac,
On our rig we run Cat 399’s. Which are some what old. The maintenance book states if running high sulfur fuels, then oil changes are required more frequently. One of our mechanics actually prefers high sulfur fuel as it tends to lubricate the top end better, but not sure about the injectors.
I note #3 warning, is all bout pollution controls, and nothing about the longevity of the engine. If society breaks down to the point where diesel is not available, I don’t think air pollution on a farm will the high on the priority list.
I know in Britain they color the heating fuel red, and there are big finds for having traces of the red die in your engine. It doesn’t stop everyone from using it, but it stops most people.
As i understand it, heating fuel is just diesel with 500 ppm sulfur. Which is pretty similar to our MGO (marine gas oil). I am not sure why you are allowed to burn it in your heater, but not in you engine?
The more frequent oil changes are recommended because some of the sulphur in the fuel finds it’s way into the crankcase with blowby where it forms sulphuric acid – only in trace amounts to be sure but still enough to accelerate wear.
High sulphur content does indeed add to lubricity.Cleaning up the air required removing the sulphur.Removing the sulphur meant putting in additives to maintain proper fuel injection pump lubrication.
You cannot be sure the additives and detergents needed for modern diesel engines are in oil sold for heating oil.The oil change intervals get longer all the time and are now well past ten thousand miles meaning contaminants have a long time to build up and start eating and wearing away bearings and block metal and rings and pistons.
IF you must run heating oil as diesel fuel prudence requires shortening the oil change interval substantially.
Beyond that modern diesels are both computerized and equipped with pollution control systems and if the pollution controls are poisoned by dirty fuel the engine will not run properly. Fuel economy suffers substantially and it is even possible it will not run at all sometimes although I do not personally know of any cases getting to that point.
The reason I happen to be well informed about this sort of stuff is that I am professionally trained farmer and when I was working I kept up with such affairs as part of my work. Farming is like everything else, it gets more involved year after year.
The usual charge for picking up a tractor in the busy season and hauling it to and from the shop these days is a couple of hundred bucks if it is not too far. The pickup and delivery alone can run five hundred dollars or more if you are way out in the boonies in relation to your dealer. Labor charges are arbitrary depending on the mood of the service writer and the greed of the shop owner but a hundred dollars an hour is pretty cheap these days for a factory certified diesel tech in a modern shop.Then you figure you are losing one percent or more of your potential revenue for each day you are running late planting while costs remain the same. If you are running late harvesting and the weather turns against you it could be a disaster.
It is not unusual for a shop to be backed up a week or more at certain seasons.You can’t always borrow or rent a tractor.We always kept a spare or even two spares because ours were always old ones when we bought them. Three well maintained older tractors will put you a lot closer to fail safe than one new one.
Mac,
Thanks for the feed back. I have had it recommended to me to add a quart of 2 stroke oil to 25 gals of diesel every 4 or 5 tank fulls. Have you heard of this and is it useful? The idea is to clean the injectors and help lubricate fuel pumps and top end.
Maybe we can get them into the Ecuadorian embassy with Julian Assange. I personally will contribute a hundred bucks each to their airfare and defense.
The latest from Michael C Lynch. It is relatively easy to register and post at Forbes
http://www.forbes.com/sites/michaellynch/2014/06/27/peak-oil-3-has-production-peaked/
They didn’t! Try getting your facts straight. I’ve heard it helps.
Get yourself a mirror buddy. You are practicing what is called psychological projection.
How about you webhubtelescope?
What is your comment regarding the CONTENT of my posts?
I am not projecting anything. I am presenting the truth exactly as it is. If you don’t agree, then simply disprove what I am saying.
Yo, guy. Are you sure celebrating a specified, narrow area of geography is a good thing when everything happens by trucks and there are no roads? The smaller the area, the more likely they get in each other’s way.
If the trucks don’t roll, production falls. This happened just 7 months ago with a 50K bpd production fall due to trucks not rolling.
Watcher,
I suppose whether a 14,000 sq. mile oil field that has an estimated 903 billion BOE in it is a narrow area of geography, or not, is probably a matter of opinion. But keep in mind that a square 120 miles X 120 miles would equal 14,400 sq. miles. It would take you 8 hours driving at 60mph to drive around the entire perimeter. For comparison, the Ghawar is only 179 X 19 miles for a total of 3306 sq. miles.
There is a MAJOR problem with traffic on almost all Bakken roads almost all the time, which has a very negative impact on production. Just part of life in the oil patch during a boom. Not to worry.
The December disaster in production was caused by extreme cold, not road congestion. Shit happens.
No. It was caused by trucks not rolling.
It doesn’t matter why. Go back and check how many new wells came online that month. It was a solid number. What could not happen was oil get carried from well to depot, because the trucks did not roll.
Ghawar uses pipes. Bakken uses trucks. So all that really matters is if they get in each other’s way and slow down. That’s all that has to happen. A slow down.
And btw, the Teamsters are WAY overdue to put in a visit with those $85K/yr drivers. That’s a nice chunk of cash with which to pay union dues. Should justify nice pay increases, too. And hours per week regulations, don’t you think?
Watcher,
Sorry, it does matter, because if you don’t have your facts straight, you will continue to have an incorrect understanding of the ongoing development of the Bakken.
Only 49 wells came on line that month, as compared to 218 in April, 2014.
Why don’t YOU, spelled Y-O-U, do the checking from now on. You are not operating with correct information, and therefore are in no position to tell others what to do regarding correct information.
Like most other developing oil fields the Bakken uses BOTH gathering pipelines and trucks.
The extreme cold weather did not allow for the usual number of well completions. That’s why only 49 new wells came on line. End of story.
Just try finding even one single informed person in this forum, that agrees with you on this issue. You stand entirely alone.
You told Mr.Brown that he hasn’t contributed anything of “value to this forum”.
That is false and you are being confronted with the facts, which is why you are projecting your own inadequacies on others.
Web,
I was obviously referring to his comments about my post, not his overall input. It seems that you and I both agree, that he can do much better. I wonder if he too agrees?
Pump and sell.
Our promotion friends never give up, and as they say:
“a sucker is born every minute”
Dave,
Anyone who would sell a well functioning shale oil stock at this point in time would have to be quite dumb, but enough people are doing it, so there is always room to get in for anyone who wants to.
Not to pump it, but I think you should know that CLR’s stock was worth just $15 in 2009, and you can buy it today at about $158, if you want, but I’m certainly not selling my shares at that LOW of a price. They expect to triple production in just the next five years, and have over one billion BOE in reserves. As that’s about how much oil the Bakken has produced so far, I don’t think you have any idea of what you are even talking about.
So who’s the sucker? The guy who doesn’t own any, or the guy that does? Go figure.
You people are also just as confused about the Eagle Ford, as you are about the Bakken.
Try going to BTE’s website at baytexenergy.com. Then locate their June Investor Presentation and fast forward to pages 21 and 22. On the map on page 21 you can see the well density of a recently acquired 22,000 acres which is located right in the heart of the EF. The surface has hardly even been scratched. On page 22 you can see an EUR map, as well as an ownership map. Conoco probably has the best acreage, but EOG gets the best results. The possible well density in the EF has already been proven to be much higher than the Bakken’s. It is also rapidly expanding to the East (not even shown on this map) and like the Bakken has multiple, still unexplored benches. No one in their right mind expects the EF to peak anytime soon within the next five years, or so. The maps show you exactly why.
To properly understand shale oil, you have to access company web sites. Otherwise, you are just standing way out in left field somewhere making a lot of noises. Why even bother?
Mr. Martin; I am actually on the ground in the EF and don’t have the time, or the inclination to waste my days looking at websites for good news from public companies needing to spew forth good news.
First of all, development of the EF is not rapidly spreading eastward. If you are referring to the Eaglebine to the NE in the East Texas basin, that is a different animal altogether. The NE limits in the EF are being well delineated with bad well results. “Bad” means they will never pay out drilling and completion costs.
EOG posts the best IP’s in the EF, if that is what you mean by “best results,” because they gut their wells from the beginning on wide open chokes to make public press releases that give people like you goose bumps. EOG does not know how to spell reservoir management. EOG is the perfect example of saturating sweet spots and sweet infrastructure spots; they are drilling wells # 12H thru 15H on a 1000 acre unit with laterals 330 feet apart. They are smart, they can borrow lots of money and raise more money to say on the wheel. Conoco, or Burlington, can spell and their “results” will perhaps be better in the long run if “better” means more recoverable oil per well, which of course it does.
It looks to me like, from my research on DI, and buddies of mine with boots on the ground, not under a computer, denser well spacing will result in lower EUR per well and much higher debt. Maybe higher URR, sure; but at what cost?
A while back I eluded to extenuating circumstances in developing any oilfield that cannot be predicted accurately. I can name a bunch of extenuating circumstances that may put the skids on tight oil development, none more evident that the use of critical human groundwater sources to frac with in a very, very dry S. Texas. That will become a very big issue very soon. Rail car explosions, earthquakes, groundwater contamination, spills, blowouts, dumb politicians, steel shortages, guar bean crops in India; all kinds of things can change the future and prevent 8 million dollar tight oil wells from being drilled on 5 acre spacing like you think.
To properly understand shale oil you must actually avoid company web sites at all costs.
Respectfully,
You People
Mike,
Are you suggesting that it was a mistake not to believe industry presentations in regard to possible recoverable reserves in the Monterey Shale Play?
Well sir, I think that I made no such mistake and neither did you.
Hey, that Monterey thing, now there is an extenuating circumstance that led to an oilfield not turning out like people thought…dumbness. I forgot that one.
Speaking of dumbass . . .
Should have typed: Are you suggesting that it was a mistake to believe industry presentations in regard to possible recoverable reserves in the Monterey Shale Play?
Mr Martin seems to be a wannabe cornucopian expert at least so far as American tight oil is concerned.I wish I could believe he is right because that would make it more likely the old age welfare state will outlast my old age.
I ”am afeared” however that the facts are not as he so fervently wishes them to be.
As far as believing in cornucopian experts go one of the two biggest is probably the inestimable Mr Lynch who is currently explaining how it doesn’t matter over at Forbes about how the definition of oil has been changed over the last decade by the business as usual crowd to include palm oil , moonshine, natural gas liquids , refinery gains, and anything else that will burn and can be poured even if it has to be heated a couple of hundred degrees above ambient to pour it- or even converted at great expense from a solid to a liquid.
Mr Lynch conveniently forgets to remind his readers at Forbes that he has been wrong about the price of oil in his projections over the last decade or so to the tune of about three hundred percent.
He forgets that all the other things that used to be called something else and are now called oil are not as energy dense or as cheap economically or environmentally as oil.He forgets that the uses they used to be put to still have to be met.
Remember folks. Mr Lynch has said it. It does not matter if we call other things oil so long as we can say production is still increasing. It does not matter that he’s been wrong to the tune of about a factor of three in predicting oil prices over the last few years.
But if prices go up by a factor of three again will people still listen to him? Of course they will because most people want to believe in continued good times and he has a nice resume and a slot to publish his fairy tales at a big business as usual site.
Forbes is like just about any other msm publication except more so. The money comes in directly from advertising and indirectly by pushing and shaping public opinion so as to enhance the business prospects of the owners and the owners buddies.Mr Lynch is certainly doing a good job for them in making sure the public does not wake up to peak oil.
I suppose the other best known cornucopian expert is YERGIN. We used to have fun at TOD pricing oil in Yergins. He has been wrong in his projections of price IIRC by about the same margin as MR LYNCH.
METHINKS peak oilers who may have missed the peak by a couple of years or a couple of million barrels a day are far more deserving of respect. And in the end the peak oil pessimists of recent times are probably going to be given credit by historians for being right already. Historians are not apt to be so easily fooled by such elementary ( but nevertheless reliable in dealing with the public) tricks as changing definitions in the middle of discussion of historical events.
Mr Lynch at Forbes a couple of days ago. I forgot to put the quote in the above comment.
”The second problem with the claims of a production peak are that they usually are confined to crude and condensate, rather than total petroleum liquids, which includes natural gas liquids like propane and biofuels like ethanol. While total liquids production has increased by 5.7 mb/d since May 2005 (the putative peak), crude and condensate have “only” grown by 2.4 mb/d.”
But wait, there’s more! Peak oil advocates insist that only conventional oil should be considered because, well, no one’s every really explained why it matters. Excluding shale oil production does, indeed, make it appear as if “oil” production may have peaked in May 2005, but what’s the point?
Now here it is excerpted in his own words
”claims of a production peak are that they usually are confined to crude and condensate, rather than total petroleum liquids, which includes natural gas liquids like propane and biofuels like ethanol”
TAKE THAT PEAK OILERS . ETHANOL IS A PETROLEUM LIQUID.
I would never have guessed my poor deceased brother had his very own oil business located in the woods back of the peach orchard a few weeks every summer as time permitted and right in his kitchen in the middle of the winter. Now of course his total annual production never approached more that a half a barrel of finished petroleum liquid and even then he never did manage to get the water cut below about fifteen or twenty percent( one sixty to one seventy on the proof stick).
And in terms of net energy I am afraid his results were dismal at best since leaving ashes around and chopping wood leaves a lot of evidence around for busybodies to run across.So he fired his refinery with propane and after allowing for that water cut and the inherent shortage of energy in this particular variety of ” petroleum” molecule his output would not have had more than fifty percent of the energy content of plain old crude oil.
Some body ought to tell Mr Lynch about net energy. I am afraid it is a topic not taught in political science and economics classes.
But now if we stop to consider that there must be at least a least a million hillbillies with small refineries that means maybe as much as five hundred thousand barrels of petroleum production annually.Maybe even a million barrels.
I expect Hubbert is spinning in his grave he is laughing so hard.
I first encountered Michael Lynch on the USENET during the 90’s where he posted as mclynch. He along with the Stanford computer guru and world class cornucopian John McCarthy had ongoing debates with Jay Hanson. Later Lynch was occasionally active on the Hanson inspired One List (later Yahoo) groups such as energyresources. One positive – interchanges with Lynch were pleasant as he was unusually polite.
Mac,
Sorry, I am NOT a cornucopian. I am a realist, so I am only interested in the truth, the whole truth, and nothing but the truth.
Ah yes, the choke. Reservoir management as a function of choke.
Imagine that.
Mike,
My reply to you apparently did not get posted. I’ll try to get back to you on this, but you might have to wait until tomorrow.
Bated breath.
Mike,
Why don’t you go to seekingalpha.com and write Eagle Ford into the search box. This will pull up all the recent articles about the present ongoing eastward expansion of the Eagle Ford on all the MULTIPLE layers. You do not seem to very well informed about what’s going on where your boots are.
Eog’s average well spacing in the EF is presently about 40 acres. They might have done some wild experiment with downspacing all the way down to 5 acre spacing, that I don’t know about, but it is more likely that they would first try 20, then 10, long before they try five.
EOG has extrememly high IP’s, which they flout to a equally high degree, but their high IP’s are backed up by their high production, (they are the biggest producer in EF) which at the end of the day is all that really matters here.
They are the acknowledged leader in not only the EF, but also the entire US shale industry. In the last five years EOG’s stock price has increased by about 260%, while Conoco’s (COP) has “only” increased by about 175%. They are a very good company and I’m sure they do everything just about right, but EOG still leads the pack.
By the way, when a company is cash flow positive AND pays a dividend, they don’t go into debt to do downspacing experiments. But, EOG recently borrowed more money to pay for some large land positions in four new/old upcoming shale plays.
By the way I don’t only rely on company websites for my information flow, and I double check everything through research on the web, anyway. Part of my research is done at this site. Your comment has just become part of my research and information flow. But, I choose to disregard most of what you say on the grounds that you seem to be operating with a bias against correct information from the net, and you seem to value your own oil field experience higher than correct information.
Why don’t you combine your oil field experience with correct information, and start investing in oil companies? As successful downspacing experiments just about double the amount of oil gotten from any given area, any company doing this on all their properties will likely see the value of their stock doubled. And, this is what EOG is basically doing and all the other oil companies are following and adopting their downspacing experiments.
Here’s what doubling does to stock investments. http://youtu.be/t3d0Y-JpRRg
In case you STILL don’t get it. EOG and all the other shale oil companies are going to keep downspacing, doubling production, and doubling their stock price, until it is no longer profitable to do so. I seriously question your understanding of basic math.
In case you STILL don’t get it. EOG and all the other shale oil companies are going to keep downspacing, doubling production, and doubling their stock price, until it is no longer profitable to do so. I seriously question your understanding of basic math.
I am really laughing my ass off. You really don’t understand shale oil math at all. Drilling twice as many wells on the same acreage will not double production at all. First you get less oil from the “in between” wells but the biggest factor will be the decline in all the already drilled wells.
Neither the Bakken or Eagle Ford will ever double production from where they are today. If you actually think they will then you are way out of touch with what is going on in the shale oil patch.
Ron,
The math had been done long before the oil companies started doing downspacing. Yes, there is well communication between closely spaced wells in the same zones, but it’s not interzonal.
Imagine ten men standing in a circle each with $100 dollars. Then each man steals $10 from the man to his left. What is the result?
Now imagine the same situation, except each man steals $20 from the man to his left. What is the result?
That is the principle here, but it doesn’t apply to an oil field, because a circle is a closed system and, as you well know, oil fields are not.
So, now picture 10 men standing in a row, where each man steals $10 from the man to his left. The result is that the man furthest to the left ends up with $90, the next 8 men end up with $100 each, and the last man on the right ends up with $110.
Now try it with $20. So, what is the big difference for the eight men in the middle compared to stealing just $10?
Stealing oil is perhaps best understood as just sharing oil between wells. It lowers average EUR’s/well, but increases overall EUR for the whole area downspaced. It makes very good economic sense, therefore oil companies do it.
IT is kind of like GMO corn. The yield/acre goes up, but the yield/plant does not. How is this possible? It’s simple. GMO corn plants can simply be grown closer together without adversely affecting the output of each other. Farmers downspace GMO corn, but not traditional corn. Get it, now? It’s all about applying the correct technology to how you are trying to make money.
What’s happening in the shale oil world is that EOG figured out how to put two wells much closer together, and get away with it. They did this by changing their well design, and only fracking out about 300 feet from the well bore. But they absolutely pulverize all the rock their fracks come in contact with. Everyone else was/still are still fracking 600 and up to 1200 feet out from the well bore, and this leaves a lot of rock unfracked, and hence unproductive.
How can you determine that production will not be doubled, if no one even knows the ultimate OOIP of ANY shale play at present?? You also don’t know the ultimate % of oil that will be recovered, because NO ONE knows at this point. We only know that estimates of OOIP in all shale plays is always increasing, and the %’s of recoverable oil are always increasing.
CLR’s July presentation shows a chart showing confirmed and proposed takeaway capacity to now reach 4 million barrels a day. That suggests an eventual production in the 3-3.5 million bpd range, but that’s not until pretty far away in the future.
You are the one who is out of touch with what is going on in the shale oil patch. A revolution is occurring right in front of you, but you still haven’t even noticed. And it’s because you are focused on the size of doughnut holes, instead of the size of the doughnuts.
Try changing your focus and see what happens to your thinking.
Ron,
Here is an excerpt from a SA article, that came out over one year ago, which explains it all step by step. The fact that you don’t know any of this stuff, is proof that you are out of touch with the whole shale industry.
You will have to source the original article to see all the maps and graphs.
The Bakken is gearing up for a radical downspacing. High density testing will kick off this year with several large-scale pilots being simultaneously initiated across the play. Several operators – including Continental Resources (CLR), Whiting Petroleum, EOG Resources (EOG), Kodiak Oil & Gas (KOG) and Oasis Petroleum (OAS) – have announced extensive evaluation programs. Others are likely moving ahead in the same direction, without special announcement. Many of the pilots are comprehensive, geoscience-heavy and are based on very aggressive downspacing patterns. Several projects will test “vertical downspacing,” with wells arrayed throughout a wide section of the Bakken/Three Forks (TF) interval, including the lower TF benches. Large amounts of capital are being committed to the effort: Continental plans to drill 47 wells in its program; Kodiak will be spending one third of its total budget this year on high density pilots; and Whiting is initiating six or seven multi-well projects.
Importantly, the downspacing in the Bakken may give broad acceptance to a new approach – which is showing signs of emerging – to managing fracture stimulation programs in thick shales. “Array Fracking” may be a good moniker to describe the concept of creating an integrated fracture systems in a thick, high oil content reservoir from multiple optimally positioned wellbores (similar approach seems to be gaining traction in the Niobrara).
The picture below from Continental’s presentation provides the idea of how aggressive some of the downspacing pilots can get. In this specific case, “high density drilling” means up to 32 wells per single drilling unit in full development mode with laterals landed in four stacked intervals (possibly five if TF4 proved productive), a truly staggering density relative to the 7-8 well patterns that have been considered “dense” until recently.
(Click to enlarge)
(Source: Continental Resources October 9, 2012 Presentation)
The results of the evaluations, if positive, may become an important catalyst for the Bakken as a whole and could lead to yet another leap in the estimate for the play’s recoverable reserves and economic value. Several highly reputed operators claim that they see minimal on-production communication between wellbores with short offset intervals (this is, for example, Continental’s view based on their evaluation on over a hundred well pairs’ performance, the view also shared by Kodiak). The feasibility of downspacing with dense arrays of wellbores is still an uncharted territory. It very much remains to be proven – for each specific area and set of geological intervals – that a meaningful downspacing can be achieved without big sacrifice in the EUR per well. The search process may also bring substantial modifications to the way wells are currently being completed and produced. If proven successful, the approach may mean quite a revolution for the Bakken development.
What is the motivation behind the effort to downspace? According to Whiting Petroleum’s CEO Jim Volker:
“
What that really is all about is the recognition that when you go through – and do the oil in place calculations – through most of the properties and look at most of the operators in the basin, including ourselves, at the current density that we’re drilling, we’re getting about 10%, maybe as much as 11% or 12% recovery, of the oil in place. The question has always been -we’ve drilled at these wells based on essentially no interference – the question in our minds here over the last several months and last year or so, and not just ourselves but other operators, is: What happens? How do we increase that recovery efficiency?
And so the idea here is to drill a series of pilots – and we’re going to be doing that in both Hidden Bench, Pronghorn, Sanish, possibly Missouri Breaks as well – to go in and drill on higher densities, essentially doubling the density in the better reservoirs in there, to demonstrate our ability to increase that recovery efficiency, get it up from 10% or 11% up to somewhere around 20%. And what that means is breaking up more rock. And we don’t believe that with the current spacing that we are on, that we are getting all of the oil that’s out there. So that’s really what this is all about.
The amount of incremental oil that can be recovered if high density drilling proves viable is enormous. Continental Resources currently estimates total oil in place in the Bakken Petroleum System – including Deeper Three Forks – at 903 billion barrels.
(Click to enlarge)
(Source: Continental Resources October 9, 2012 Presentation)
Harold Hamm, Continental Resources’ Chairman and CEO, commented during the company’s earnings call last week:
“
Obviously, the initial recoveries are always low in these large fields. Historically, that’s been the case. And as you go on and technology advances along with development, that number always tend to increase. So at 5% [oil recovery rate], you’re looking at 45 billion barrels. So is that within reason? I think it is.
The 45 billion barrel estimate is almost a double from the 24 billion barrel figure established by Continental three years ago. In terms of oil reserves, the new estimate may put North Dakota, ahead of many oil-rich countries.
Continental Is Leading The Charge
Continental is again at the forefront of the effort, having announced four comprehensive pilot density projects to test 320-acre and 160-acre spacing in the Middle Bakken and first three benches of the Three Forks. The program includes 47 gross wells.
(Click to enlarge)
(Source: Continental Resources October 9, 2012 Presentation)
Importantly, Continental has stated in the past that they are not seeing any reduction in initial production rates from wells drilled on tighter spacing, the view the company re-iterated during its earnings conference call last week:
“
… As far as the density is concerned – obviously, we’ve got a lot of wells – we’ve got numerous wells that have been drilled in pairs of wells that are 660 feet offset: the Middle Bakken and the first bench well, and they are 660-foot offsets. And we’re not seeing any influence on IPs or even EUR. So I mean, there’s just a constant building of data set out here that’s saying that the pattern is not causing any kind of degradation in at least initial rates.
… It really is going to be about the quality of the rock in a given area and how it performs with the stimulation technologies that we’re currently applying, leaving room, of course, for additional optimization, additional stimulation techniques that we might use in the future.
Continental has already initiated its first 320-acre pilot density project, with three wells currently being completed and two more being drilled. The 160-acre pilot and the next 320-acre pilot are scheduled to spud by mid-2013, with the third 320-acre pilot planned to spud in the third quarter of 2013.
(Click to enlarge)
(Source: Continental Resources February 2013 Presentation)
Continental’s evaluation program is remarkably comprehensive and integrates four intervals, the Middle Bakken, TF1, TF2 and TF3. In each pilot, the wells are arrayed to help determine the optimum well spacing and pattern to maximize the ultimate recovery of oil from the multiple Bakken and Three Forks reservoirs.
According to Continental’s press release, these “aggressive pilot projects over a wide area in the field” will be drilled and completed over the next 18 months, with production coming on line starting in late 2013. All wells in the program should be producing in the first quarter of 2014. These exploration and appraisal programs should help determine the ultimate recovery of the field and drive valuations higher by accelerated de-risking and down-spacing.
Kodiak Oil & Gas
Kodiak is moving ahead with two high-density pilot programs this year, one in its Smokey operating area and the other in its Polar operating area. The two pilots with include up to 24 wells and are an important undertaking for Kodiak, with one third of the company’s 2013 budget committed to the program. Both projects are well underway. In the Polar project, Kodiak is currently running three rigs. In the Smokey area, one rig will be finishing three more wells.
(Click to enlarge)
In both pilot programs, Kodiak intends to drill six wells in the Middle Bakken and six wells in the Three Forks. In the Middle Bakken, individual wells will be drilled approximately 800 to 850 feet apart (taking into effect lease line setbacks and the size of the drilling unit). The Three Forks wells will be located in the first and second benches (what Kodiak calls the Upper Three Forks and Middle Three Forks intervals). Kodiak has set out to locate the wells in the Three Forks based upon an alternating sequence between the first and second benches to reduce the impact of possible communication between the two intervals and make sure that the frac procedure “is opening this entire interval up.” The final location of all the Three Forks wells is yet to be confirmed: Kodiak has just completed coring operations on one of the wells in the Polar project area and will be evaluating the core to determine the optimal location of well bores in the Three Forks.
During its earnings call last week, Kodiak made an important comment regarding the lack of on-production communication between wellbores, which largely confirms Continental’s assessment:
“
… We have drilled wells this closely spaced several times. While we see pressure communication occasionally during fracture stimulation procedures, we have not observed any sustained interference between wells during production. We believe it is important to see what the impact of spacing is on a larger group of wells within the drilling unit.
Another comment from Kodiak during the call is also highly relevant and interesting:
“
During the second half of December 2012, we observed evidence of communication between wells during fracture stimulation procedures. As a result of that we decided to revise our completion procedures. Based upon our new observations, we decided to shut in all producing wells within the immediate vicinity of completion operation of new wells. With this approach we are seeing a positive response from the shut in wells once they are returned to production, which leads us to believe that we are initiating new fractures into the old well bores and finding new reserves.
While the comment at first glance may sound worrisome, it does not condemn the downspacing concept. In fact, to the contrary, it illustrates how a multi-well array may be used to create a fracture system that would be more effective from a recovery rate perspective than one associated with a single well:
“
What you do see, you get different fractures. Some of the individual fractures go a long ways and fluid will go a long ways, but we’re not packing proppant out there. Our proppant packs within a few hundred feet of the well bore we believe. So occasionally you see the fluid travel over a distance. We have seen wells that were producing actually communicating with a fracked well nearby and so we’ve been very careful to shut all of our producing wells in when we frac. But we are not seeing communication or we’re not seeing interference during production. It changes once you take that, you release that pressure, flow the wells back, the cracks that you open up over a long distance seem to heal up and where we have fracked wells near producing wells, the producing wells tend to get better. …We believe that as we frac wells more closely together we’re going to create more fractures and actually enhance the production.
That’s all just the difference between your hydraulic link and your prop link and like Jim said, we’ve seen hydraulic links over a couple of thousand feet into existing well bores. But to close, usually our performance is a little better on the existing wells. …We have seen some positive responses when we’ve brought some wells back on production. And so we’re not sure it’s going to be a negative impact whatsoever at this part.
The “few hundred feet” comment from Kodiak for the proppant packing range is the critical data point that may ultimately define the density of the development. The discussion indicates that we may see “array fracking” as the next phase in fracking technology and management technology evolution – the simultaneous optimization of multiple lateral positions throughout a thick interval to create the most effective fracture system measured against cost.
Kodiak expects to commence completion operations in its Polar area project in Williams County around midyear. The company is planning a micro-seismic project to gather additional information during the completion process.
(Click to enlarge)
(Source: Kodiak Oil & Gas February 2012 Presentation)
Completion operations in the Smokey area in McKenzie County will be done throughout the year with full development completed after the Polar project.
(Click to enlarge)
(Source: Kodiak Oil & Gas February 2013 Presentation)
Oil, gas and salt water disposal infrastructure has been completed in each of the pilot areas with the expectation of them being fully operational prior to completion operations.
Kodiak expects that they will not have immediate information about the pilot programs available publicly due to the length of time it will take to complete the operations and the time necessary to evaluate the production. However, the company hopes to gain some useful information towards year end.
Whiting Petroleum
Whiting Petroleum is planning at least six, possibly seven, downspacing pilots, in its key operating areas to be initiated over the next several months: one in Hidden Bench, one in Pronghorn, and four in Sanish Field. Several pilots are aggressively-spaced (as low as 160 acres).
(Click to enlarge)
(Source: Whiting Petroleum February 2013 Presentation)
In Sanish, Whiting plans four high density pilots to be initiated in the first half of 2013. If successful, the downspacing may add up to three additional Middle Bakken wells per 1,280-acre spacing unit.
(Click to enlarge)
(Source: Whiting Petroleum February 2013 Presentation)
In Pronghorn, the company plans to test a six-well high-density pilot targeting Pronghorn Sand on a 1,280-acre spacing unit, up from the initial plan of three wells per spacing unit.
(Click to enlarge)
(Source: Whiting Petroleum February 2013 Investor Presentation)
In Hidden Bench, where Whiting has recently identified an additional productive oil-bearing reservoir (the “Middle Bakken Silt”) positioned between the Middle Bakken and Three Forks, the company plans to test this zone by drilling 160-acre spaced wells above and below this target zone and stimulating these wells with large frac volumes. Whiting believes that this higher density drilling could also improve recovery efficiency in the Middle Bakken reservoir.
(Click to enlarge)
(Source: Whiting Petroleum February 2013 Investor Presentation)
Whiting expects to complete its pilots, particularly in Hidden Bench and Pronghorn, by mid-year and should start to see some results already in the third quarter of this year. The company commented during their earnings call:
“
If those are successful, as we expect them to be, we’ll be able to capitalize on that, go into full development mode on this higher density spacing towards the latter part of the year and certainly into 2014…And then it’s going to take a little bit of planning to go ahead and re-space a lot of this. We’re actually looking at the possibility of re-spacing Sanish right now. There’s no reason not to do that. And so at any rate, we’ll try to make sure that all of that happens as efficiently as possible. But I think as the terms of actually getting in the development mode, we’re going to be talking about the latter part of this year or early next year before we can actually drill on that higher density.
Other Operators’ Downspacing Programs
EOG Resources has also announced that it is actively testing 160-acre spacing both in the Parshall and Antelope Extension. It is important to note that EOG has been drilling the Parshall predominantly on a single well per unit pattern. As a result, EOG is in a great position to optimize the development of what is arguably the most productive and still sparsely developed part of the play using advanced approaches.
(Click to enlarge)
(Source: EOG Resources February 2013 Investor Presentation)
Oasis Petroleum has also announced that this year it will test shorter spacing distances between wellbores (6 wells per formation in single drilling unit) but in certain tests may place wellbores as closely as 400 feet from each other. Oasis plans to complete infill pilots on the majority of its acreage this year.
(Click to enlarge)
(Source: Oasis Petroleum February 2013 Investor Presentation)
The majors, Exxon Mobil (XOM) and Statoil (STO), and super-independents, ConocoPhillips (COP), Marathon Oil (MRO) and Hess Corporation (HES), as well as privately held operators – the companies that account for a large portion of drilling activity in the Bakken – rarely share sufficient details of their operation in the play. However there are multiple indications that the downspacing evaluation and deeper Three Forks testing by this group of companies is also ongoing.
Conclusion
Based on the wave of testing activity across the board, the shift towards high density drilling patterns in the Bakken, at least in its most prolific areas, may occur rapidly. The fact that many of the announced high density pilots are configured on aggressively downspaced well patterns indicates that the 160-acre spacing is already used by several operators as the “null hypothesis” for full development mode, at least for those areas where well productivity is high. Clearly, the results of the pilot programs will not be known perhaps for another few years. If positive, Continental’s 45 billion barrel estimate for total recoverable reserves in the play may prove conservative.
Under an optimistic scenario, the downspacing, in combination with the lower Three Forks development, may have a dramatic impact on potential resources that various companies would be able to count on. If early indications from the pilot drilling this year prove positive, investors would obtain a reason to start pricing some of this upside in the stocks already this year. Continental Resources presentation from last fall shows that the company’s resource potential could triple if well density went from 320 acres to 160 acres and included the deeper intervals.
(Click to enlarge)
(Source: Continental Resources February 2013 Presentation)
The economics of the downspacing is a somewhat different issue. It is hard to imagine that aggressive well patterns will have no material impact on the projected EURs. With many “bread & butter” wells in the Bakken having ~300-400 MBoe EURs and as a result underwhelming economics, the downspacing may not work everywhere. In the more prolific parts of the play however, the appeal of the concept is tremendous.
The downspacing pilots should provide operators in the Bakken with rich new data. Once the early phase work is complete and operators turn to designing drilling plans for full field development, they will look at the best areas and calculate how to optimize and maximize value of the resource in the ground. With a better understanding of what the sweet spots are and what deliverability and operational efficiencies can be gained from these large-scale high density programs, the array designs and completion technology will be modified to ultimately produce better economic returns. A logical step in the evolution of this truly bountiful and still very young play that is quickly approaching the age of maturity.
Read-Across To Bakken Focused Stocks
The downspacing trend discussed above should provide a meaningful contribution to the long list of operating catalysts that 2013 will bring for the Bakken. The impact on Bakken-focused stocks should be universal (although likely gradual). Companies with highest quality acreage positions should benefit most.
Carl,
This can be done up to a point, until the extra oil produced is equal to the extra cost of drilling more wells.
If EUR per well falls to a certain point the economics no longer work out so EUR per well matters as long as oil companies are interested in making money.
So far in the Bakken there has been no significant increase in average oil output per well over the 2009 to 2013 period.
In the Eagle Ford it is a little more difficult to track so in that play perhaps new well EUR is increasing, I will have to update my numbers.
Carl, you are basically saying the whole Bakken is just one giant sweet spot and they have hardly started drilling it. However the sweetest, most productive area is, or was, Mountrail County. It had outproduced McKenzie by about 75 million barrels. Yet the drillers are beginning to leave Mountrail County. If you check the active drilling list:
Current Active Drilling Rig List
You will find that McKenzie County currently has 68 rigs working that county. But Mountrail County has only 32 rigs, less than half the rigs of McKenzie. There has to be a reason that rigs are leaving Mountrail. And that is because new wells in Mountrail are producing less and less oil.
The biggest and most productive of sweet spots, Mountrail, is just not that sweet anymore. The figures don’t lie.
Ron,
I appreciate your point of view. But, keep in mind that Montrail was the first hot spot in ND. It took the industry awhile to found out about Mckenzie. That’s why it’s cumlative production is so much lower. But, you can’t make hasty and correct conclusions without more solid knowledge. You need to understand the general development plan to get things straight. It doesn’t have any real meaning how many drilling rigs, or for that matter how much oil is getting produced in any given county at any given time.
But, I gotta go. Hope some others will come with some decent comments. It might be a good idea to get to the bottom of any disagreements. That’s what forums are for. Right?
Ron,
Another thought….
The Madison formation traditionally used to be the record holder for the most cumlative production in ND. Maybe it still does, I don’t know. But it has produced close to one billion barrels of oil so far.
The fact that it has mostly outproduced the Bakken over time, however, is not particularly relevant to anything. It’s just had more time to out perform.
If you look at KOG’s map again, you can plainly see that Montrail county has been drilled at a higher well density, then most other places….the fuzziness. But, it has not peaked yet. No way. And it’s remaining EUR’s might be lower than some other hot places, but it’s still 1st class property.
You have to keep in mind the still undelineated lower TF2 and TF3, and eventual (?) TF4. Most of the 3,400 sq. mile delineation so far has only been under Williams and Mckenzie counties. Only a very small part of Montrail county has been delineated so far. But, it is quite likely that these levels extend right under the MB and TF1 into the sweet spot of Montrail county as well. Therefore, as usual with the Bakken, you are looking at a moving target. It is simply IMPOSSIBLE to figure out the peak until you know the final figure for the Bakken OOIP, and also what % of that will be recoverable. And, I don’t think you should repeat Hubbert’s main mistake. Try to remember that, “It ain’t over until it’s over.”
As to where the rigs are, I note CLR has some in Oklahoma. Oklahoma’s well flow is way below the Bakken flow rates. Odd they waste the rigs there.
Watcher,
As I have said before,….It’s not about oil. It’s all about money. CLR gets much more bang for their bucks in their SCOOP acreage. That’s why they are there. Pumping less oil also holds the oil price up. Both the EF and the Permian have better economics than the Bakken. The Niobrara might also be better too. There are many downsides to Bakken production…..like the winter, and road congestion. It is the biggest, not the best.
Ron, I’m sorry to say, but your adjustment method for the individual counties isn’t very accurate for McKenzie, Mountrail, or Williams. In reality, McKenzie County production was up 7,168 bbl/d in April 2014 compared to March 2014, while Mountrail County production was up 5,816 bbl/d and Williams County production was up 3,630 bbl/d. Your estimates of the change in production in Dunn County and the rest of the state outside the “big four” counties are more accurate.
You can deal with the confidential wells by using the production numbers from the state production summaries inside the monthly production PDFs (https://www.dmr.nd.gov/oilgas/mprindex.asp). These summaries do include production from confidential wells.
But let me make things a bit easier. I don’t have any qualms sharing the spreadsheet I use to track county-by-county production data, so I have uploaded the spreadsheet to Google Drive. Head to http://goo.gl/2DyVeV. You can download an Excel file under the file menu. The data all seem all right doing this, but unfortunately the original formatting of the graphs will be messed up. Furthermore, if you are going to play around any with the data, I recommend not making any edits to the three “raw” sheets as other sheets are dependent on these data.
Wes, thanks for the info,I have now made the adjustments to reflect the adjustments made by the NDIC on that page. I had completely forgotten about this page. I will Not forget it again however.
And thanks for the spreadsheet data.
Thanks a million.
I have a post up on updates on Bakken,
THE REVIVAL OF MOUNTRAIL’s ”OLD” SWEET SPOTS
Not altogether clear. Are the “old sweet spots” old wells being refracked? Or new wells in the same region.
And . . . how old were the old wells that defined the sweet spots having already been drilled? Are these new wells many more frack stages because those old wells were 3 yrs old, even if drilled near them?
Watcher,
In case Rune doesn’t have time to reply…..They are all new wells in the same old region.
It’s pretty difficult and confusing trying to understand what’s really going on in the Bakken now, and it ain’t gonna get any easier in the future . But, many of the older wells are at least 3-4 or more years old, and done with a now outdated technology and understanding of extracting oil from shale. New wells in old areas can now easily have EUR’s that are 50% higher, than the old wells. But you can’t easily see this from using general well statistics. At some point you need to find the exact coordinates of each well, as well as it’s age, lateral length, # of fracks etc. There are always way to many variables. You people think you are comparing apples to apples, but you are really just comparing apples to oranges, to banas to grape fruit, and that never works. That’s why you are all lost.
There has been at least a 50% increase in EUR’s right across the board for virtually all wells in the Bakken when compared to wells , say five years old, or older. Rune’s post merely proves, or at least suggests this. But CLR came to the same conclusion long ago through correct analysis of their well density experiments, and multilevel production experiments. Even with downspacing from 320 to 160 acres, new wells were still outperforming old single wells by a 50% increase. It is because of what Hubbert NEVER understood….Technological improvements over time.
On a side note oil prices are also much higher, while wells have become much cheaper even when producing 50% more. It’s a win, win, win, situation for the oil companies. And you people think it’s foolish to own shale oil stocks??? GAWD!
Anyone know this age old story? http://youtu.be/-Pknme2ahwA The Bakken is an elephant. Get it? Anybody?
Mr. Martin, remember that for all the new technology babble you read about on the internet, the E in EUR still stands for estimated. Your estimates, my estimates, BHP, CHK or FBI estimates, they are all just estimates. Higher IP’s don’t necessarily translate into higher recovery of OOIP. Just cause you read about it on the internet does not make it so.
Thank you, but it is not necessary you respond to my previous comment, sir; or this one. I would not read it anyway and I will not reply to anymore of yours. Promise. The way you write down to people kind of makes me want to go rinse off with a garden hose.
You people.
Mike,
In EOG’s case in the EF, their higher IP rates DO translate into a higher recovery of OOIP. After all, that’s why they do them in the first place.
It certainly sounds like your writing down to me, if all your “communication” only goes one way.
You come across as a person who is in awe about the power of information and the Internet, and wish to repress the free exchange of information and opinions on such. Yet you, yourself, use this same format of exchange of information and opinions via the Internet. How odd. But, if you aren’t happy with your life, you can always just change it……if you can. But, it kinda sounds like you can’t. Chill pills are available.
I believe you are a prisoner in Plato’s cave by your own choice. Why not just remove your chains and move on? http://youtu.be/UQfRdl3GTw4
Waiting to hear if he was comparing post mega frack wells to pre mega frack wells. Unlikely he’d make a mistake.
I don’t think you’ve studied the matter of proppant flow and truck trips required to accumulate rather a lot of millions of pounds of it on site to do 30 stages. Or 60.
It might also be appropriate for the NDIC to choke production in order to reduce flaring, as they mentioned a few months ago. I suspect not . . . for that reason. A better reason would be to do state wide reservoir management and not be interested in production growth. Maybe 900Kbpd is just fine. Keep it in the ground for the great grandchildren. Burn up foreign oil first.
Warren advocates this.
Watcher (and others)
As of April 2014 it has become harder to analyze the growing amount of data coming from NDIC.
The high number of shut in (idle) wells makes it more challenging to look at what is really going on.
Something is clear and if you look at figure 12 in
THE REVIVAL OF MOUNTRAIL’s ”OLD” SWEET SPOTS for Parshall pool, the recent growth in LTO extraction has been accompanied with a strong growth in net wells added.
Extraction from Parshall was on a downward trend that was offset by some net additions of wells. Something changed last fall.
A more detailed look at new and old wells will likely help identify the causes for the growth.
Looking at the average cumulative oil extraction for the wells, which wobble around a little, it is as of now hard to find a definite trend. We will learn more with time.
However there is one clear trend, if the data from NDIC is to be believed.
Total liquid [water + oil] extraction has been on an upward trend in the recent years. NDIC data shows that it is stronger growth in water extraction than in oil extraction, in other words and looking at aggregate extraction data, the water to oil ratio has been growing considerably in recent years.
The higher water to oil ratio was not expected and has likely physical explanations as longer laterals results in more friction losses (total length of pipe) and water normally flows more willingly than oil.
What I sense we also need to learn more about is the interaction between hydrofractures with natural fractures which creates loosely connections for the liquids to flow.
Thanx.
In a very truck-like way, explosive growth in water production can slow operations down, too. Disposal requires trucks. Adds to traffic jams. Disposal wells do fill up.
Rune,
In regards to your comment,
“What I sense we also need to learn more about is the interaction between hydrofractures with natural fractures which creates loosely connections for the liquids to flow.”
Have you not been following all the recent production gains from using more advanced slick water fracks?
More and more companies have been using them, and attributing a considerable portion of the increase in oil recoveries to them. Here is a small sample from (OAS).
“Oasis Petroleum Inc. decreased well costs in the first quarter of the year despite poor weather conditions, said Thomas Nusz, chairman and CEO. Due to the company owned well services division, OWS, well costs were cut by roughly $0.4 million. In the first quarter, 80 percent of all Oasis wells were completed on multi-well pads. Nusz said the sixteenth drilling rig has been added, and, the company has been working on new completion techniques based on a slickwater approach. The method has proven to create a 25 percent production uplift. “Based on encouraging results to date from slickwater tests and other completion technology, we intend to complete over 60 percent of our wells in the second half of 2014 with alternative completion techniques. We are focused on designs that may increase production or reduce costs, ultimately driving higher per well and per drilling spacing unit returns,” Nusz said.”
Her’s another.
“Bakken Explorers 2014: Slickwater fracks boost EURS for Halcon Resources
Moves to all pad drilling, will spend half of 2014 drilling, completions capex in Fort Berthold Bakken
Steve Sutherlin
For Petroleum News Bakken
Halcon Resources has raised its estimated ultimate recoveries 39 percent for wells in its Fort Berthold area acreage due in large part to the success of slickwater fracking, which the company began using in 2013. Halcon’s average EUR now is 801,000 barrels of oil equivalent, of which 687,000 barrels or 86 percent is oil.
“We plan to complete all future wells in Williston Basin with slickwater fracks,” Floyd Wilson, Halcon chairman and CEO, said in a Feb. 27 conference call.
Halcon’s revised EUR may be too conservative – the slickwater-completed wells in the Fort Berthold area are currently outperforming the 801,000 boe type curve. The company’s engineers now estimate an average EUR for its Fort Berthold wells at 970,000 boe.
In its Williams County focus area, Halcon increased its estimated average gross EUR 43 percent to 477,000 boe, with oil making up 87 percent.
“We’ve increased the average type curves on our EUR estimates in all areas based on improved results related to drilling and completion modifications,” Wilson said, adding that one of the big improvements has been slickwater fracks. “We started with those up in the Williams County area. They were very successful. We’ve started down in Fort Berthold with those, and they’re meaningfully outperforming our new type curve.”
As a result of that success, Halcon plans to spend 49 percent of its $950 million overall drilling and completions budget on its Fort Berthold acreage in 2014.
“In the Williston Basin, our Bakken/Three Forks program is going great,” Wilson said. “We have production growth there in 2013 of 77 percent. This year, all of our rigs are drilling in the highest-return area at Fort Berthold. We expect to spend a little – just barely less than half – of our drilling and completion capex in 2014 in the Williston Basin.”
Halcon will also move to all pad drilling in 2014.
“We expect to draw 100 percent of our 2014 wells off pad versus a little less than 75 percent last year,” Wilson said.
Since transitioning to pad drilling, Halcon reports cutting its spud to total depth time by 25 days and reports a savings of $1.3 million in drilling four wells on one pad compared to drilling four separate wells.
Downspacing inventory boost
Downspacing continues to pay off for Halcon as it continues with infill drilling. Early results suggest that up to 16 wells per spacing unit may be feasible in the Fort Berthold area, a density which could potentially increase the company’s Fort Berthold well inventory as much as three-fold, Wilson said. “Continued downspacing there has yielded real success and has the potential to more than triple our operated well inventory in the Fort Berthold, as events unfold,” he said.
In pilot testing of downspacing in the northern end of its North Fort Berthold area in McKenzie County in the third quarter, Halcon had three Bakken wells on spacings of 660 feet that came in with an average initial potential, IP, of 2,665 boepd. Halcon decided to downspace the majority of future drilling in its Fort Berthold area on 660-foot spacings, as well as to drill both Bakken and Three Forks wells on 660-foot spacings on four other pads in the Fort Berthold area. The company is also will test downspacing in its acreage in Williams County.
In addition to downspacing, Halcon is also testing deeper into the Three Forks formation, testing the second bench of the Three Forks in its Fort Berthold area. Halcon also has a 15.5 percent working interest in a Continental Resources operation that is testing the first three benches of the Three Forks.
“We’re looking at 660-foot … middle Bakken wells,” Wilson said. “We’re looking at lease line wells wherever possible, so you don’t leave that oil behind. We’re looking at … full development of the first bench of the Three Forks and all the areas that we think it’s good. And we’re looking at significant second bench development in those areas that we think it’s good. And those areas where we think it’s good are being augmented daily by information from other operators, because everybody is solving for the same thing.”
Good years
Halcon had a good year in 2013, and 2014 looks even better with production guidance up, reserves up, and costs and capital expenditure down.
Halcon’s fourth quarter Bakken/Three Forks production rose 15 percent over the third quarter, despite brutal winter weather in December, which the company estimates cut production by 1,040 boepd.
In 2013, the company’s Williston Basin production increased by more than 75 percent.
Williston Basin production averaged 24,125 boepd in the fourth quarter, compared to third quarter output of 21,039 boepd.
Halcon Resources is planning to increase company-wide production by more than 60 percent in 2014 while reducing its previously estimated capex. In mid-December, Halcon announced it had lowered its 2014 drilling and completions budget by 14 percent from $1.1 billion to $950 million. That revised 2014 drilling and completion capex is approximately 36 percent less than the approximately $1.5 billion the company spent on drilling and completions in 2013.
In the Williston Basin, Halcon plans to operate four drill rigs and spud between 40 and 50 gross operated wells, and plans to participate in another 200 to 225 gross non-operated wells with an average working interest of 3 percent.
The company currently has 141 Bakken and 39 Three Forks wells producing in the Williston Basin, another 12 Bakken and seven Three Forks wells either being completed or awaiting completion and two Bakken and two Three Forks well being drilled. Halcon holds approximately 142,000 net acres in the Williston Basin, and operates approximately 75 percent of that acreage with an average working interest of 94 percent.
Halcon ranked as the 12th largest Bakken oil producer in North Dakota in December based on output from operated, non-confidential wells.”
Rune,
Here is an excerpt from another article for you with tons of info on some of the issues you (and I) are trying to make others aware of. It is written by an old adversary of yours, Michael Filloon, published at Seeking Alpha, and dates from Oct, 20th, 2013. The title is…. Bakken Update: Frac Sand Pricing Could Go Parabolic As EOG Resources’ Well Design Revolutionizes Unconventional Oil Production … As I was unable to provide the tables with well information, some of what he is saying might sound odd to you. But, this is just an appetizer, and I hope you will be inspired to read the whole article as written. It would be well worth your time and effort, as it pretty much explains all Bakken developments between 2010 – 2013.
“The number of rigs drilling liquids rich plays in U.S. basins looks to trend sideways to down going forward. This has led some to believe operators are cutting back, which is not the case. Developmental programs are moving forward to pad drilling as operators have large leaseholds held by production. Pad drilling saves time, which decreases costs. Batch drilling and zipper fracs reduce costs and will allow more wells to be drilled and completed without raising cap ex. The frac sand growth story has less to do with an increased number of wells drilled and more to do with an increase in proppant intensity, and longer laterals coupled with decreased drilling and completion times. Newer completion styles are creating larger fractures closer to the well bore. The greater the void, the larger the volume of proppant needed. Frac sand producers will benefit from this directly, as the larger the fractures the more sand needed to fill the void. These changes could be the start of something bigger, as early results point to much higher production per well for roughly the same cost.
I first addressed better source rock stimulation in November of 2012. EOG Resources (EOG) pioneered fraccing shorter and wider fractures. Before this, operators were trying to create longer fracs in an attempt to garner increased shale surface area contact deeper into the shale. It was believed this would maximize recoveries, but it also created issues. Longer fractures are further from the well bore. This distance is difficult to bridge, as it has to push proppant over a greater distance. Less proppant is secured in the fractures and this increases crushing and closure of those fractures. This significantly decreases EURs. Thinner fractures also have less surface area, which creates greater pressures. These greater pressures require more resilient ceramic proppant, which is approximately 10 times more expensive than sand. Since EOG Resources creates shorter, wider fracs, it reduces that pressure allowing for the use of all sand fracs. The increased void created by this completion design requires more proppant. In some cases, these wells use up to a million pounds of sand for every 1000 feet of lateral. EOG first used this in the Eagle Ford and Permian Basin.
Eagle Ford
The above wells are all in the oil window. Those results are centered in and around Gonzales County. I usually do not use 24 hour IP rates when charting well performance. In this case I did as the numbers were fantastic. I included the choke size, and it shows this production was accomplished while keeping well pressures up. The results are even better when you take lateral length into consideration. Some of these wells aren’t even a mile long and are some of the best unconventional results in the U.S. to date.
When comparing Penn’s results to EOG, keep in mind the resource mix is separated out of EOG’s numbers. Penn used a tighter choke, but the size difference is not significant enough to make a material difference. The important variable is proppant amounts. EOG is dumping over 2400 lbs. of sand per foot. This is important because the more proppant, the better the perceived source rock stimulation.
In July, I reported that Whiting (WLL) had also changed its completion design. This was significant, as other operators were beginning to use a similar, or like design. At that time, EOG had used this technology in the Eagle Ford, Permian and Bakken. Although effective in all three plays, EOG reduced its exposure to the Permian in favor of the Bakken last year. This is not to say the Bakken is superior, but EOG was worried about a falling NGL price. The decision was reinforced by its ability to rail Bakken crude and receive LLS pricing. Not only is Whiting using the same type of completion method, it has expanded to the northeast extension of Wattenberg Field. This application may be universal, as it should work in most plays. Rumor has it that EOG has also used it successfully in the PRB. Although other operators were slow to copy what EOG is doing, there is no doubt a large number will have it figured out in 2014.
The purpose of this article is to show how this well design has implications that could significantly increase the use of frac sand in unconventional U.S. oil plays. I assert this will happen even if oil production maintains a zero growth environment, as increased usage is on a per foot basis. I have collected data on the majority of EOG’s North Dakota Bakken wells using this new design, and older wells used as a comparison. This data not only covers the amount of sand used per well, but its affect on initial production rates and production per foot. In order to see the difference in completion styles, I have provided data in the table below comparing these changes and how it affected production. The series of tables below provide EOG’s new design broken down by area.
Bakken
The above data is from the best producing field in North Dakota, and is almost completely controlled by EOG. The IP range is quite good, but one should not focus on this entirely. Depletion may be more important, as this percentage provides a view of longer-term production. Well 21239 was important to EOG, as it was one of the first major outperformers of this well design. This is a top 5 Bakken well as of 180 days of production. This well produced 357274 barrels of oil in the first year (360 days). Its IP 360 is 992 Bo/d. Calculating the depletion rate from the first 90 days of production to 360 days shows the advantage of this completion design. It depletes less than 10% of its production over this timeframe. Due to the decreased depletion, it raises a question as to how and when matrix production will begin. Initial well production is greater and derives for the fractures created in completion. This is when production is at its greatest, but so is depletion. Depending on the play these fractures will cease production sometime between years 3 and 5. At this time the shale matrix will start producing at a much lower production and depletion rate. Matrix production has an approximate depletion of 3% to 5% per year. The question is if depletion is curtailed through better source rock stimulation and propping, will we see matrix production further out. If so, it could change how we model EURs. Keep in mind that well 21239 is a top five well, and there are several newer wells with better 90 day IP rates. These wells had a less restrictive choke, so we could see a higher initial depletion rate.
Northeast McKenzie County has been a focus, and is considered the second best area in EOG’s leasehold. When compared to Parshall Field, the Antelope area produces more natural gas. The Three Forks is much better than in Mountrail County, while the middle Bakken is better in Parshall. This seems to level out acreage values in comparison. Well 22486 is the best producer to date. Due to the higher gas content, a higher depletion rate is produced. Over the first 340 days of production it has produced 376287 barrels of oil. Keep in mind, this is a longer lateral at 13595 feet. This level of source rock stimulation is impressive, given the horizontal leg is much longer than a standard long lateral.
Western Williams’ results are much better than the old design, but the depletion rate was not as impressive. Well pressures are lower due to an interval being more shallow. This negatively impacts initial production rates, but the wells are cheaper to drill. In reality, these are still excellent numbers offering exceptional payback. IP rates are much better, and I would guess there is more upside going forward.
These numbers mean little without examples of the previous design. Geology can be different from one mile to the next, it is important to use results from the same general area. This provides a geology baseline, which provides the affects of differing well design. I have seen this done in the past, but comparing areas of differing geology provides little information on well design. The tables below provide this information.
It is difficult to produce a good comparison using long laterals given EOG didn’t drill many early in Parshall Field development. Short laterals have historically produced better on a per foot basis. This is more effective because the pump trucks aren’t as stressed. At this time, EOG believed it was more cost effective to drill a vertical for every 5000 feet of lateral. The two earliest results were abysmal, but well 21194 provides better data. We get much different results when comparing to short laterals much closer to well 21239.
Results from 2010 and earlier in Parshall Field were highly variable. Some of the wells completed here are some of the best in play, but other wells performed poorly like three of the above wells. Stage lengths were too long, creating inadequate source rock stimulation. Volumes of water and proppant were too low, which did little to prop open the fracs. This is why numbers can be misleading with respect to average production numbers in the Bakken. Although horizontal success rates in the Bakken are high (99%), there are significant differences from one well to the next. Operators are now more consistent, which has increased IP rates and EURs.
Northeast McKenzie County is well suited for pad development. QEP Resources’ (QEP) purchase of Helis’ acreage in Grail and Croff fields gave an idea of its worth on a per acre basis. A large number of these wells model to EURs of 1000 MBoe. This includes both the middle Bakken and upper Three Forks. Parshall Field has had a better middle Bakken interval, but northeast McKenzie County has a much better Three Forks. Well 22486 may be the best northeast McKenzie County well to date. It could be the best Bakken well ever depending on how the well depletes. Keep in mind this lateral is over thirteen thousand feet long. EOG has completed a significant number of wells in its Antelope Prospect that have IP rates that modeling EURs above 1000 MBoe. The table below is a comparison of wells near EOG’s top McKenzie County producer.
Well 22486 outperforms its old completion design by a wide margin. It is important to note that 22486 is a longer lateral, but it still significantly outperforms on a per foot basis. This is consistent with many of the new northeast McKenzie wells, as 90-day IP rates vary from 1358 Bo/d to 1839 Bo/d. It would seem this completion design functions better in wells with a higher gas resource mix. It will take time to be certain, as there is greater oil depletion in McKenzie County wells.
EOG Resources has also tested this design in western Williams. This has been an interesting area, as historical returns have not been as good. Several operators made early bets on the area, but until recently we hadn’t realized western Williams’ potential. On the cost side, a well here is about a million dollars less than in deeper areas of the play. Drilling times are shorter, and lower well pressures allowed the use of cheaper proppant. This savings had made the play economic, but IRRs were nowhere near those closer to Nesson. Northeast McKenzie and southwest Mountrail counties model to EURs of 750 MBoe to 1000 MBoe with older completions. Western Williams modeled to just 350 MBoe to 450 MBoe. EOG’s new completions are producing much better results. Only Liberty, which was recently acquired by Kodiak (KOG), has been able to match EOG’s results. It has done this using slickwater fracs. I have provided a table below to compare EOG’s 20766 with its old completion design.
The wells in this area are more recent, so the results are better. We can see what EOG was trying to do with its old design. It is important to note that before it changed its design, EOG was already at the top end with respect to proppant volumes. To provide a comparison of how these techniques differ and its affect on production, I have provided the table below.
The above Parshall Field data provides key variables supporting the validity of this proppant heavy well design. Both long and short laterals were used in comparison. As you can see, EOG uses much tighter stages and increased amounts of water and proppant per foot. I used specific wells nearby for comparison. This has its advantages and disadvantages, as I believe the comparison needs to be made in like geology, so the closer the better. Most of Parshall Field was drilled early, so EOG improved on its design over time and also used mostly short laterals. It did only a few long laterals before moving to this newer design, so comparisons were limited. As you can see, it was able to tighten up stages significantly, and this seems to aid in better source rock stimulation. It also used a very high concentration of proppant and water per foot. Although the newer design seemed to be better it produced less crude per foot than the old short lateral. What improved was depletion, which is almost non-existent from 90 to 270 days of production. By manipulating the depletion curve, we will see a significant uptick in EURs.
McKenzie County was a better area for comparison. EOG developed it later than Parshall Field, so well designs are more consistent. Its old design used decent amounts of water and proppant, so we don’t see the discrepancies like Parshall. I am unsure why, but EOG used longer stages. The new design improves near-term production and more importantly depletion is still much lower. This depletion was higher than in the Parshall Field, but this has more to do with resource mix than well design.
Western Williams did not produce the lower depletion rate seen in the first two areas. Production per foot was consistent. These well results show why EOG continually beats quarterly earnings, as analysts didn’t know about these completion improvements. I have been talking about this since November of last year and finally have enough data to support the validity of the technique. It is a simple premise and this is why I believe we will see operators reproducing variations next year. Whiting has already reported its plug and perf completion with cemented liners, increased stages and perforations per stage. Whiting states this technique does not increase well costs. I think this is accomplished by using an all sand frac, which decreases exposure to much higher priced ceramic proppant. The removal of ceramic proppant seems to be more than enough to counter additional costs related to cemented liners, additional sand and stages.”
A New Wind Turbine Generates Back The Energy It Takes To Build It In Just 6 Months
By Joe Romm, Climate Progress, on June 27, 2014 at 3:04 pm
Aws,
I haven’t looked at the study… but is it just focused on the energy or does it include all materials and energy costs in the mining, manufacture and transportation of those materials?
Steve
Sorry Steve. I haven’t read the original paper yet.
Just came across this post, sort of old, but worth highlighting given there is little room for efficiency improvements in the typical electric-resistance clothes dryer.
The heat pump dryer may be the answer to the energy crisis in our laundry room
Lloyd Alter, Treehugger, March 6, 2014
I got an even better answer to the energy crisis in our laundry rooms, though it is a bit complicated with multiple pieces and varying approaches depending on season.
It’s called air drying.
An indoor rack for winter.
A clothes line and clothes pins for summer.
Not quite as fancy, granted. And not all high tech, which means that it, of course, is far inferior to the heat pump dryer. But it is a touch less expensive than $1500 and somehow, despite not containing nearly so much advanced technology, uses less energy. At least, that’s what initial studies suggest.
I don’t know, though. I’m sure soon we’ll invent a complicated and expensive computer chip running on fossil fuels that will somehow be more efficient at drying than, you know, evaporation.
Plus use a woodstove in the winter and a small fan.
There was a time when everyone could heat and cook with wood. That time is long gone. If everyone did that now then all the trees in the world would disappear in less than one year.
Internal combustion engines can run on moonshine, as can maybe home heating and lighting.
I like the idea of home/village-scale alcohol (ethanol?) distillation.
Alcohol is good for a surprising number of things, such as also with regard to medical (sterilization) uses and food preservation.
I’d like to learn how and might begin by doing a simple cider this summer, time permitting. I know that’s not distillation, but it’s a start.
Lately, I’ve been interested in how a small cabin/house might be built with local materials and little if any tools. Today, I thought again of how they did the Trulli, and of dry-stacked stone in general and of using sand as insulation. Apparently, it is very effective if done well. So you have something like that for the walls, with a simple reciprocal roof made of logs and a thatch covering. I suspect that would make a good house for the rocky and rainy northern maritime climate over here.
If I did an adult all-season live-in treehouse, I might do it with salvaged/scavenged palettes (skids) and wool and/or cotton/denim for insulation. Attachment of the house to the tree would be by friction, using wire or a good rope threaded through a hole in each piece of wood emanating from the tree-trunk in a radial pattern. A similar pattern would be done directly below, if at a 45-degree angle for each piece of wood as support for the above beams which would all be rope or wire-threaded together.
My place is heated by a wood stove, so the rack goes next to that in the winter with the little thermoelectric wood stove fan pointed toward the clothes. Works grand.
I wonder how the numbers would add up if the potential buyer of such a dryer invested the extra thousand bucks in a wind farm or solar farm or a solar system of his own.
It is too bad such efficient new machines are priced like Teslas. Wonderful but only for the rather well to do who are lucky with appliances. I personally knowing the rep of modern day appliance manufacturers and their repair men would never buy one for fear of finding out it would be functionally obsolete in less than ten years due to lack of available repair parts or that ”sub assembly” xyz has gone bad and costs eleven hundred bucks plus labor.
I have an essentially functionally ” brand new ”thru the wall vented electronic kerosene furnace that has never had over a thousand gallons of oil put thru it.We had a power surge that wiped out the electronics. No parts available and this is a major Japanese brand.IF the parts were available they would charge half the price of new to fix it .
Sometime back I had three different manufacturer certified techs work on a new dryer under warranty before they fixed it on the fourth try.Should have taken it back to the store of course.I line dry my laundry unless the weather is wet or I am in busy. Saving a quarters worth of juice in ten or fifteen minutes hanging clothes on a line and bringing them back in is not a very efficient use of one’s time if there are other pressing tasks or a job to be taken care of.
Old farmer mac says:
I wonder how the numbers would add up if the potential buyer of such a dryer invested the extra thousand bucks in a wind farm or solar farm or a solar system of his own.
I think where we are heading, and given the amount of energy we need to replace to successfully transition to a post-carbon economy, demand destruction via efficiency will be hugely valuable.
There are systems level benefits to the transformational approaches to energy efficiency that for example a heat pump clothes dryer can bring that should not be overlooked. From a grid level, this kind of efficiency gain leads to a beneficial shaving of peak electricity demand. From a housing efficiency perspective, eliminating the need to punch a 4″ diameter hole in an exterior wall will reduce heating demand, with beneficial electric and natural gas grid level knock-on effects.
Indoor Rack – got two -used frequently in winter. Winter gets down to -25 Celsius with snow up to my waist in spots.
Outdoor Clothes line – got one, which is used on week-ends when the weather allows, when it’s not rainy or too humid.
Kids – got two.
Wife – got one.
Full time jobs in household – two, we’re busy! .. add on the hours of commuting a week.
Electric resistance clothes dryer – got one, because of the the two kids, wife and full time jobs.
Clothes dryer is kind of a necessity… and I would like to reduce the energy consumption that my present clothes dryer demands.
As for being leery about heat pumps… no one thinks twice about the heat pump in their fridge! So why dismiss it when it is applied to other appliances?
Hey aws,
Nah, I’m not leery about heat pumps. I just always get a good laugh from the constant idea that replacing natural processes with complicated and expensive machinery running on fossil fuel is the way to tackle climate change and depletion.
Not everyone agrees with me, but I think it’s fairly inevitable that the only endgame for this is humanity coping with the nasty effects of climate change and depletion–we’re not fixing either, as seems clear at this point to me–and using way less energy and resources. I expect that mostly to be forced rather than voluntary. Which is unfortunate, because we could make things potentially a lot less worse if we would use less voluntarily.
I think the thought process behind getting a machine to do something that the air will do naturally is a good chunk of the reason we’re in this mess.
That’s my commentary on society, though. Not trying to be a jerk toward you. Sounds like you make a conscious effort to reduce your resource usage. Since that isn’t the most common thing, I got nothing but respect for you.
Fair points and I have wouldn’t disagree with you regarding the foreseeable impacts of climate change and resource depletion.
Hopefully things turn out on the slightly better side of bad. At least doing what I can on the demand side of things within the paradigm (reality, expectations) I have to live within may leave my family a little more resilient to volatility.
Most of my acquaintances would suggest I am overdoing it, so I don’t mind someone suggesting to me I am not doing enough.
As for buying into complexity… well professionally my instinct is to abhor complexity and dependency, but I can live with it if it does offer a substantial benefit.
Ostensibly, a lot of people have barberry bushes hedging their homes, for example, which happen to contain berberine, which is a good antibiotic.
Cool, ay?
Apparently, many other poisonous plants and so-called weeds– perhaps even all of them– are useable/have been used for various medical/health purposes…
I wonder what’s up with Afghanistan, poppies, the UStates’ war-on-drugs, CIA drug trafficking, and the state-as-a-racket.
In a time of universal deceit, telling the truth will be a revolutionary act. – George Orwell
It is colder than a witch’s teat in May out there today. I am hoping for a little global warming very soon.
If some math is calculated, an answer might give some perspective.
One million times 365 equals 365 million. If they’re barrels of oil, then it’s 365 million barrels. With a 50 year timeline, the total return is possibly 50 years times 365 million.
365,000,000 x 50 = 18,250,000,000 barrels of oil. That’s my prediction and I’m sticking to it. The math helps.
If they’re all in the Bakken, the expected ultimate return is 18.25 billion barrels over a 50 year period with a steady rate of 1 million barrels per day production that is definitely going to be shipped to refineries.
In 50 years the price of oil just might be higher than the 100 dollars it is today, so the capital invested will more than likely be returned with a profit.
Oil is money in the bank.
I am so sick and tired of buying useless, worthless new clothes dryers, I give up. If you can, buy one from the early 70’s that never stop working. Forget about new clothes dryers that break down and are too expensive to fix, it is a waste of time and money.
Have to get to work and it is a very busy time. Have something good to eat and it’ll be a better day.
Hi Ronald,
The oil has to be profitable in order for it to be produced. Today at 1 MMb/d Bakken oil can be produced profitably. You assume that all areas of the Bakken/Three Forks have uniform well productivity (estimated ultimate recovery per well). That assumption is incorrect. A few wells last for 50 years, most last no longer than 30 (at profitable levels) and the majority may be more like 20 years.
Let’s try the following (which is still very optimistic): current average EUR is 350 kb, assume 40,000 wells, that is 14 Gb. Now make it a little more realistic and assume that only the first 15,000 wells have an EUR of 350 kb and the next 25,000 wells have a lower EUR of 220 kb (this is roughly the USGS estimate for the Three Forks sweet spots and the non-sweet spot areas of the Bakken), that results in about 11 Gb.
An even more realistic estimate based on reasonable economic assumptions for oil prices and well costs, tax rates, transport costs, royalties, and discount rate is about 30,000 wells at most will be drilled profitably. Using EUR=350 kb for the first 15k wells (still optimistic) and EUR=220 kb for the next 15k wells leads to a URR of 8.5 Gb, this is close to what we would expect if the USGS mean estimate is correct.
Where did your math go wrong? The output will not remain at one million barrels per day for 50 years, it may remain at that level on average for 5 or 6 years (with a peak at around 1.2 MMb/d), but output will fall as well EUR begins to decrease.
The output will not remain at one million barrels per day for 50 years, it may remain at that level on average for 5 or 6 years…
Wildly over optimistic.
Hi Ron,
Below is a scenario based in a TRR of 7.5 Gb with an ERR of 6 Gb when reasonable economic assumptions are applied. The average output from Jan 2014 to Dec 2018 (5 years) is 1040 kb/d. The scenario has 19,000 total wells and coincides with the USGS F95 TRR level of 7.5 Gb for the North Dakota Bakken/Three Forks (F95= a 95 % probability that TRR will be 7.5 Gb or more). Maximum annual rate of new well EUR decrease (not decline rate) is 19 % and 170 new wells are completed per month from May 2014 to Dec 2016 at which point fewer wells are added (decreasing by 4 wells each month to May 2020 when 11 wells are added per month up to 2041). Chart below.
Dennis,
Apparently you are not at all aware of CLR’s, by now very outdated explanation of what their well data was telling them back in October, 2010, or you flat out don’t accept it. Anyway, here’s a copy of it for you to ponder over, but I’ve become quite curious as to why you think your ever changing predictions about the Bakken are somehow right, but the oil industry, (you know those guys on the ground actually doing all the work) have somehow got it all wrong.
FYI… The USGS gets almost all it’s information about the Bakken from CLR, but by law it HAS to be about five years out of date. It is also a government entity and is under considerable pressure by various powers that be. Therefore, the numbers they use are not particularly useful or relevant to July, 2014. If you don’t accept this 24 billion BOE estimate from CLR, then I would appreciate knowing exactly why you don’t. I think a lot of other people would like to know too. The maps and tables referred to can be accessed at clr.com
Continental Resources, Inc. – Bakken Field Recoverable Reserves 2/4/2011
Continental Resources, Inc., announced October 2010 that the Bakken Field could potentially contain recoverable reserves of up to 24 billion barrels of oil equivalent. This includes 20 billion barrels of oil and 4 billion barrels of oil equivalent from associated natural gas. This estimate is based on the following facts and assumptions derived from technology available to the industry today.
Assumptions
1) 500,000 barrels of oil equivalent recoverable per well based on Continental’s average results to date.
2) Middle Bakken and Three Forks act as separate reservoirs ( i.e. 500,000 Boe per reservoir)
3) Dual-zone development (both Middle Bakken and Three Forks reservoirs)
4) 320-acre spacing per well (4 wells per zone, therefore 8 wells per 1280-acre spacing unit)
5) Estimated area of continuous oil reservoir
a. Area 1: 10,314 square miles (6.6MM acres) thermally mature
b. Area 2: 4,357 square miles (2.8MM acres) marginally mature/migrated
Risk factors
1) Area 1- the Middle Bakken risked at 100% and the Three Forks at 70%
2) Area 2- the Middle Bakken risked at 90 % and the Three Forks at 60 %
(Area 1 and Area 2 are shown on Figure 1, and reserve calculations based on the assumptions outlined above are shown on Table 1)
The fact that Continental’s estimate is 5 times larger than the 4.3 billion barrel estimate published by the USGS in April 2008 has been a source of some concern and question by those not familiar with the Bakken Field.
Continental believes the USGS estimate was fair and reasonable given the data available at the time of its report. Like Continental, the USGS utilized existing producing Bakken wells to estimate ultimate oil recoveries per well and the effective drainage area. The difference between the estimates is that recoveries on a per-well basis have increased substantially since June 2007, which is the cutoff date for wells used by the USGS in its analysis. Since June 2007, approximately 1,680 new horizontal producing Bakken wells have been drilled, and these wells have been completed using almost exclusively single leg horizontal and multi-staged fracture stimulation technology. This improved completion technology has produced higher EURs across the Bakken field. Likewise, testing has shown the Three Forks acts as a separate reservoir, which in effect has the potential to double the recoverable reserves in the Bakken field. The North Dakota Industrial Commission has recognized the improved well performance and Three Forks potential, and in January 2011 announced that recoverable reserves from the Bakken- Three Forks reservoirs could reach 11 billion barrels in North Dakota alone. This is over 5 times the NDIC’s original estimate of 2.1 billion barrels in the ND Bakken, which was published in 2008.
It is a natural evolution for resource plays to grow over time through innovation and technology, as demonstrated by the growth of the Barnett, Fayetteville, Marcellus, Haynesville and Eagleford resource plays. As plays grow, it becomes necessary to re-assess and adjust reserve estimates based on new results and information. The Bakken is no different. Production results and reserve estimates for Bakken wells have improved and continue to improve in line with advances in technology. Based on these results, an upward revision of the 2008 estimates of recoverable reserves for the Bakken field is warranted. The growth of the Bakken is yet another testament to the ingenuity of the oil and gas industry.”
Hi Carl,
I have a range of scenarios which change as I get more information.
The actual data from the NDIC shows that the average well profile is likely to be 350 kb of oil. Note that when I have used well profiles such as the well profile proposed by James Mason in 2012, or the NDIC’s typical well profile, the actual well output does not match the model. The model takes the well profile for the average well and the number of producing wells from the NDIC and just adds it up.
I will stick with the USGS estimates, you are free to believe CLR, I read their investor presentations every month, I guess I am as skeptical of their presentations as you are of the USGS estimates.
See
http://oilpeakclimate.blogspot.com/2013/04/bakken-model-suggests-7-billion-barrels.html#more
especially the 5th and 6th figures of that post.
Also remember that CLR well profiles are in boe rather than barrels. About 20% of that EUR is natural gas, which is not all that profitable.
You may not be aware that the USGS released a new estimate in April 2013, for North Dakota the mean estimate is 10 Gb for TRR (which ignores economics). I use the USGS estimate because the EUR=500 kb well used by continental does not match the actual NDIC output data.
Dennis,
IT is not a matter of belief!!! All the well data from CLR, not to mention all the other oil companies, PROVE that the USGS data is way out of date and therefore no longer relevant. I do hope you realize, that what you are actually arguing is, “That what was TRUE at one point in time is still true today, when your talking about a shale play that is a rapidly moving target.” This does not even qualify as a disagreement between us. You simply need to get yourself, and all your information up to date.
However, the only way to do so is to access company websites, or read Seeking Alpha articles, which are inevitably based almost solely upon company website data. But, you don’t accept any of this “modern” information because it doesn’t jibe with any of your “ancient” information. Of course it doesn’t! But, that doesn’t disprove any of it.
This is like trying to have a discussion with someone about whether man can fly or not. You are saying we can’t, because none of your data from 1800-1900 says we can. When I show you the modern day data on flying, you reject it, because it doesn’t match your TRUE data from 1800-1900. Your data is/was correct, but it is no longer relevant.
At the end of the day, you really only have four choices.
1.) You accept CLR’s data….until it is disproved.
2.) You disprove CLR’s data.
3.) Admit that you don’t know.
4.) Deny that CLR’s data has any relevance.
You chose the fourth choice, which simply means that you are in DENIAL! But, no need to feel alone. Everyone at this site is in denial. To believe in PO in July, 2014 you HAVE to be in denial, and bury your head in the sand when confronted with what’s really going on with US shale oil plays.
The 500kb well CLR is referring to is the “AVERAGE” well in the 14,000 sq. mile area known as the kitchen. IT DOES NOT APPLY TO ANY WELL OUTSIDE OF THAT AREA!!!!
You are counting very low EUR lease holding and exploration wells from way outside that area, and that is what is distorting your data, BECAUSE YOU WANT YOUR DATA DISTORTED; SO IT WILL PROVE THE CASE FOR PO.
Therefore, to get a proper perspective you have to get the geograghical coordinates for each well in your data base and then plot them on a map that clearly delineates where the kitchen is. Then only consider those wells, that are actually in the kitchen, because that’s all anyone else in the industry is doing.
From another post,… there was no reply button to your comment, so I’ll take it on here. Yes, at some point in time oil companies will likely run into downspacing difficulties. The question is when? What you don’t seem to realize is that EOG is the first mover behind all this downspacing. They did it first in the EF, and others are now trying it in the Bakken, and it works!
CLR is presently testing 160 acre spacing (4wells/sq.mile) in the Bakken, but also in four different zones at the same time. That means 16 wells/ sq. mile in the 10,000 sq. mile central core of the sweet spot, which means a theoretical total of 160,000 wells just there.
Meanwhile in the EF, EOG is down to about 40 acre spacing, and testing 20 acre spacing…and it still works.
WHY??? Because they have learned to shut in neighboring wells while they are fracking. The fracking then stimulates the near by shut in wells, and they produce MORE, not less.
That shutting in trick also adds much fuzziness to all your Bakken well data, which also contributes to distortions.
I hope that helps.
Carl,
If you give the boundary coordinates of what you call The Kitchen, or show me where this is defined, I don’t mind to redo my cumulative production analyses only for wells in this area, based on NDIC data, to see how they are actually doing.
Enno,
I have never bothered to determine the boundary coordinates, as I have never put any effort into trying to determine average EUR’s/well, or any kind of peaking scenarios.
But, I think it’s great that you are willing to do so, as that would lead to a quantum leap in understanding the Bakken. The next logical step would then be to do the same thing for the 4,357 sq. mile marginally mature Bakken. Then everywhere outside of that. But, you need to take the average for each area to get a clear idea of what’s going on.
But, you’ll still be way behind the industry, because the industry operates with information from specific land positions within each area. Each company usually coins a name for each specific sweet spot they are working on to identify it. Then an average EUR for that sweet spot is often given. They are usually in the 700-900kb/well range.
But, some of the best maps of these areas can be found at CLR’s website, now clr.com , as it has always been “their thing” to delineate these areas. I would suggest that you first look at the small map that goes with their technical paper from Oct, 2010. Click on “Our Operations”, then technical papers, you’ll find it at the bottom.
That map by the way is made by the USGS, so you might have to take it with a grain of salt. The industry is not so sure that the mature Bakken extends all the way to the Brocten Froid Fault to the NW.
But there you can see that the bulls eye is centered on Mckenzie county, and just about the entire county is thereby located in this giant sweet spot.
But I believe the exact epicenter of the Bakken is somewhere about 15-20 miles east of the geographical center of Mckenzie county. That pulls EOG’s Sanish land package in Montrail county closer to the exact epicenter, where judging by EUR’s it belongs.
Then check out the map on page 8 of CLR’s July Investor Presentation to see their land position superimposed on the 14,000 sq. mile sweet spot. Then note the smaller area within which is marking the ongoing delineation of TF2 and TF3. You will eventually have to include wells in that area too.
Next go to kodiakog.com to view their map on page 7 of their June presentation. This shows the location of most, but not all, of the wells drilled in the Bakken. Here you can plainly see that the majority of the giant sweet spot only has lease holding wells on it. Most of the areas that are fuzzy and bleary with wells are the downspacing experiments, and exploratory wells of TF2 and TF3. None of these areas are in full field production (16 wells/sq. mile) as yet.
Note Kodiak’s Wildrose area. This is outside of the sweetest spot acreage and is only getting about 350kb/well.
My opinion is that the average well in the Mature Bakken is getting about 500- 750kb, in the marginally mature about 300-500kb/well. Everything outside of that less than 300kb, which I simply ignore anyway, as it’s too close to the breakeven price.
Then, lastly go to oasispetroleum.com and view the map on page 13 of their June investor presentation. This shows you both the delineated TF2 and TF3 areas, and also how far they expect it to extend. They are already getting 400-600kb/well in those lower levels.
Hope that helps.
Carl,
In the coming month or so I plan to do a geographical analysis of the NDIC data, with the purpose to show the quality of the different drilling area’s, at least based on the recent past. Based on what I’ve read, I belief you (or certain companies) are way too optimistic with the 10-14 k square miles sweet zone you mentioned, but the analysis should give a clear answer on that.
Dennis
Just ran across this article, which lends support to my case, but erodes yours. Good luck with it!
Even with production of the first billion barrels of oil under their collective belt, operators in the increasingly stacked Bakken/Three Forks play are spearheading a technological renaissance, in hopes of reversing notoriously rapid, and acute, decline rates. However, shipping any additional crude to refineries represents another matter altogether.
In a play where dry holes are an anomaly, operators are digging deeper beneath the Williston basin, while also evaluating myriad completion, stimulation and enhanced recovery technologies to sequentially increase flowrates. At the same time, supplementing already record production threatens to further aggravate lingering takeaway issues. The problems have snowballed this year, with a series of railroad derailments and occasional explosions that has invited federal pressure on the rail transport of what officials had claimed was über-volatile Bakken oil. On top of that, with an unrivaled volume of associated gas being flared, local regulators are being squeezed publicly to cut back production until the infrastructure catches up, forcing operators to come up with alternative gas capture plans.
Nevertheless, projected drilling and completion expenditures for 2014 suggest that the infrastructure woes have failed miserably to dim the luster of the sprawling Bakken/Three Forks, which traverses beneath most of western North Dakota, eastern Montana, northern South Dakota and into the Western Canadian provinces of Saskatchewan and Manitoba. Despite its expansive areal reach, nearly all activity is centered in Mountrail, Dunn, McKenzie and Williams Counties in the North Dakota fairway and, to a lesser degree, neighboring Montana.
According to a Wood Mackenzie analysis released April 2, Bakken/Three Forks operators are expected to spend upwards of $15 billion this year on drilling and completions. The analysis suggests that they will have little difficulty recouping that investment, considering the Bakken and its largely successful sub-plays hold close to $118 billion in remaining value. Jonathan Garrett, Americas upstream research analyst for Wood Mackenzie, said in a release that Bakken/Three Forks oil production is expected to average 1.1 MMbpd in 2014, growing to 1.7 MMbpd by 2020.
Aggregate Bakken oil production reached the milestone one-billion-barrel mark in the first quarter, according to IHS data, with North Dakota having produced 852 million bbl and Montana roughly 151 million bbl through the first three months of 2014. Figures released by the North Dakota Industrial Commission’s Department of Mineral Resources (DMR) showed March oil production hitting a record 977,051 bpd, surpassing the previous high mark of 976,453 bpd set last November, before the brutal winter reached its apex. In addition, as of January, North Dakota producers had managed to divert a cumulative 30.5 Bcf, or 983 MMcfd, of gas from flare stacks, according to state production data
DMR Director Lynn Helms said he expects daily oil production to double to 1.6 MMbbl by 2017. The state’s chief regulator said February saw a record 10,186 producing wells, with up to 40,000 additional new wells “possibly in the thermally mature area.” Toward that end, 183 rigs were active in the Williston basin, as of May 20, broken out to 174 in North Dakota, with the remaining nine in Montana, according to Baker Hughes data, which showed 190 rigs drilling in the like period of 2013. At the same time, Baker Hughes documented 707 new wells constructed in the basin in the first quarter, representing a 21.5% increase over the 582 new wells constructed year-over-year. More evidence that operators are moving ever-closer to meeting Helms’ prediction comes from the U.S. Energy Information Administration’s (EIA) latest rig efficiency count, which shows the Bakken continuing to lead all tight oil plays, with each rig delivering 498 bpd in May, which is expected to grow to 505 bpd per rig this month.
GOING DEEPER
The Bakken-Three Forks generally is described as a carbonate sandwiched between two source shales. As currently delineated, the play includes five discrete stratigraphic units, comprising the Upper Devonian and Lower Mississippi-age Bakken petroleum system, which in turn takes in the uppermost Lodgepole Limestone, the upper, middle and lower Bakken Shale members, and the underlying Devonian Three Forks/Sanish formations, Fig. 1. Depths can exceed 11,000 ft in the center of the play and, on average, the Bakken formation thickness ranges from 80 ft to a high of about 145 ft in westernmost North Dakota. However, the average depths seem to change daily, as operators continue to explore the lower benches of the underlying Three Forks.
Historically, the primary oil-bearing Middle Bakken member has been the principal production zone of this petroleum system. Operators, however, continue to push bits into the deeper three benches of the underlying Three Forks, which the United States Geological Survey (USGS) last year estimated holds 3.73 Bbbl of undiscovered and technically recoverable reserves.
Bakken pioneer Continental Resources, by far the play’s most dominant leaseholder, likewise is credited as the trailblazer for the drive into the once-ignored Three Forks. The play’s pacesetter is credited with initiating the industry’s full-field development of the Middle Bakken, as well as all three benches of the Three Forks in the prolific Antelope area.
Last year, Continental recorded what it termed, “encouraging results” from 20 exploratory wells, and plans to further test the lower three benches with up to 24 Three Forks wells this year. “Initial results from the 20 LTF (lower Three Forks) wells show these lower formations could be commercially viable over a significant portion of the play. Additional production data are needed, but we are convinced that the ultimate resource potential is bigger than early estimates,” venerable, Continental Chairman and CEO Harold Hamm told investors earlier in 2014.
Coinciding with multi-interval development targeting the lower benches of the Three Forks, Continental is expanding the density drilling pilot program that it initiated last year with its Hawkinson unit in Dunn County, N.D., Fig. 2. Continental is operating seven density pilots, including three additional programs to be completed this year. The operator also is increasing use of mega-pads, with up to 30 wells, each, in its bellwether Antelope complex in North Dakota’s Mountrail, McKenzie, and Williams Counties. Hamm said the inaugural, 14-well, Hawkinson density pilot entailed 1,320-ft spacing within the same formation, which, he said, “implies the ability to produce four wells in a single spacing unit within each formation.”
ig. 2. The 14-well Hawkinson density drilling pilot has sustained 150 days of “impressive” production results.
In what it claims “validates full-field development and demonstrates vast resource potential,” Continental says the Hawkinson project has sustained impressive production results after more than 150 days with “13 of 14 wells trending, on average, 50% above the 603-Mboe model EUR (estimated ultimate recovery).” The Hawkinson wells were completed using Continental’s standard completion designs, with 100,000 lb of proppant for each of the 30-stage frac jobs. During second-half 2014, the operator plans to complete the three additional density pilots with 660-ft spacing, testing eight producing wells in a single spacing unit within each formation.
Other prominent players, including Marathon Oil and Whiting Petroleum, have followed suit, with density tests of their own to optimize multi-horizon drainage from the Bakken and Three Forks structures.
Marathon said co-development of the two formations is “progressing, with high-density pilots delivering strong results” in tests of eight wells per a 1,280-acre drilling spacing unit. Whiting, meanwhile, plans to initiate a higher-density pilot program in the Sanish field, which if successful, it says could add a total of 191 new Middle Bakken locations. The operator said it also intends to re-frac several Sanish wells during the year.
While optimized well spacing and mega-well drilling pads have contributed to sequential decreases in what were once among the highest well costs among the unconventional plays, the matter of improving sharp decline rates has become the primary focus. Recovery rates of typical Bakken wells reportedly are in the 4%-to-6% range, far below the double-digit recovery rates seen in other shale plays, which, owing to the high-quality sweet crude, operators have been willing to live with. While Bakken wells deliver exceptionally high initial production (IP) rates, often exceeding 1,000 bpd, declines of up to 65% in the first year (Fig. 3) have promoted a wholesale revision of completion and stimulation strategies, including a new multi-variable production forecast model that helps operators customize completions to address area-specific characteristics and, hopefully, increase flowrates and overall recoveries.
IMPROVING THE FLOW
As operators transition from optimizing drilling efficiencies to increasing reservoir drainage, basin-wide experimentation is underway to identify the most effective completion scenarios. In efforts to isolate the best strategy for increasing EUR and maximizing asset value, operators across-the-board are testing a variety of completion and stimulation programs.
Since its earliest developments in the Bakken-Three Forks, Whiting Oil & Gas has relied on time-expedient sliding sleeve completions, but recently has begun conversion to cemented liner plug-and-perf completions, Fig. 4. By comparison, the former 30-stage methodology afforded only one frac port per stage, thereby yielding 30 entry points into the sweet spot. Cemented liner completions, on the other hand, allow three perforation clusters for each of the 40 stages, for a total of 120 entry points.
Fig. 4. Comparison of Whiting’s sliding sleeve completions (top) with its new cemented liner plug-and-perf completion technique, which yields 120 entry points, as opposed to the 30 entry points of the earlier-generation completions.
To compare the two approaches, Whiting pointed to wells drilled in its Skov unit in the Missouri Breaks area. The original Skov 31-28-1H well was completed with sliding sleeve technology and flowed 927 bopd, while two subsequent wells were completed with cemented liners and flowed at an average 1,145 bopd.
Whiting further modified the cased liner completion strategy in April, when its SKOV 31-28-3H was completed using a new CT-deployed, fracture stimulation technique. Though that well marked its first use of CT for stimulation deployment, Whiting Chairman and CEO James Volker said the potential, in tandem with the cemented liner completions, is undeniable. “This was really an experiment and it’s still fairly early,” he told analysts in the first-quarter earnings call.
Oklahoma’s WPX Energy was one of the earliest Bakken converts to cemented liner and typical plug-and-perf completions. Bryan Guderian, senior vice president of operations, told Petroleum News Bakken that the completion technique “has proved to be a best practice in the basin, and our well results reflect the quality of how we’re drilling and completing these wells.”
Continental, meanwhile, says it continues to experiment with alternate completion methods in 20% of its wells, primarily focusing on slickwater fracture stimulations, heavier proppant concentrations and more frac stages per well.
In a related development, the Energy & Environmental Research Center (EERC) at the University of North Dakota in April launched the second phase of an ongoing CO2 EOR study. EERC Associate Director John Harju told the Bismarck Tribune on April 29 that the two-year R&D project may not attain the 15% to 20% recoveries seen with CO2 EOR in conventional Williston basin wells, but additional 4%-to-6% recoveries would still amount to a sizeable increase in production volume.
MULTIVARIATE PRODUCTION METRIC
Given the geographical and lithological vagaries of the sweeping play, relying solely on one-dimensional regression models and standard decline curve analysis, to estimate production, over time, for different completion and stimulation types, often delivers ambiguous results. So says Halliburton, which recently unveiled its so-called Guideline for Completion (GFC) multivariate completion normalization and efficiency metric, which considers multiple parameters to engineer area-specific completion and stimulation programs for both the Bakken and the Three Forks formations.
According to Halliburton, the comprehensive and mathematically justified, regression model analysis has delivered extremely close correlations for the specific areas and diverse completion types employed within the Bakken/Three Forks, Fig. 5. In April, Halliburton detailed the multifaceted analysis in a paper presented at the SPE Western North American and Rocky Mountain Joint Regional Meeting in Denver.
Fig. 5. Distribution of the Bakken and Three Forks wells analyzed as part of the multivariate production model. At last count, upward of 6,873 wells had been evaluated. Image courtesy of Halliburton.
The evaluation dissected in the paper considered some 6,440 wells with full completion and production data, representing every operator active in the Williston basin, said Geoffrey Gullickson, principal technical professional for Halliburton’s Denver technology team and lead author of the study. The aim of the model, he said, is to evaluate the expected production benefits and costs of various completion designs over different time spacings.
“The purpose is to optimize the stimulation and completion program for the metrics we can control very readily, both from a system perspective, as well as drilling and wellbore construction perspectives. Essentially, we’re trying to integrate the drilling-to-completion side of things, to optimize production,” Gullickson said.
Halliburton said that the multivariate regression analysis considers 15 geographically weighted parameters to evaluate the effects of various completions throughout the play, some of which are more significant than others. The parameters include lateral length, proppant type and density, number of frac stages, and volume of treatment fluid, as well as the different completions employed in the play, from sliding sleeves to open hole and cemented liner plug-and-perf completions. According to the authors, decline curve analysis can be incorporated into the methodology, to assess the performance of wells throughout any time period.
Dr. Kumar Ramurthy, Halliburton’s technical manager for the Rockies, West Coast and Alaska, said the metric is not intended to provide a blanket recommendation for completions. “Different methodologies are being promoted, strictly from a frac perspective. One company is promoting slickwater as the way to go, and another company is advocating larger (completion) jobs as the way to go. By doing this type of analysis and normalizing it, we can come up with area-specific designs that are optimized to make better wells. We’re not going to say that this is the way you should do it across-the-board, but, based on our design, we can predict production within a very high degree of accuracy,” he said.
Owing to the wide variances of the Bakken and Three Forks, including the various completion types and latent geological characteristics, the formations are evaluated separately. “The Three Forks is a completely different monster, as we also have to look at which of those benches they are completing and determine if there is any communication between the Three Forks and the Bakken,” said Ramurthy.
The multivariate approach, Gullickson said, is particularly beneficial in the stacked plays intrinsic to the Bakken/Three Forks, where using standard statistical methodologies does not deliver reasonably accurate quantification of production potential. “That’s what we found from doing the geographically weighted regression, as well as the principal component regression.” he said. “We needed a way to show the cumulative interaction of the components that are readily available and we can mine, regardless of operator.”
“Specifically, the reason we are getting very, very good correlations is because this is a multivariate approach. Instead of looking at the typical metric of fluids in gallons per ft or gallons over 1,000 ft, or again, proppant in pounds per ft or pounds over 1,000 ft, we bring in the zone spacing. Therefore, the mechanically isolated compartmentalization of these multi-stage treatments is considered, in addition to the volumetric input and the effective proppant volume fraction. Bringing all those components together yields an extremely component-predictive set, as opposed to individually comparing the stimulation inputs from a single variant or metric-interaction perspective.”
NO ACTIVITY SLOWDOWN
Throughout the play, no less than 33 operators delivered production in the first quarter, according to a May 13 analysis by the veteran shale observer, Powell Shale Digest. A sampling of the go-forward activities of a handful of the more active players suggests that the Bakken-Three Forks is in no danger of losing its stature as a prime hunting ground, anytime soon.
Continental Resources plans to drill 287 net (870 gross) wells, including the 24 it is projecting for the lower benches of the Three Forks, within its commanding 1.2-million-acre position. In the first quarter, the Oklahoma City operator increased year-over-year production 27%, to 97,500 boed. Continental says it plans to average 21 rigs in the Bakken-Three Forks throughout the year.
Whiting Oil & Gas Corp. controls nearly 685,000 net acres and, in the first quarter, delivered a company-record 73,325 bopd. Whiting has identified 3,738 gross potential drilling locations within its holding. The firm kicked off the second quarter with what it says was its “best well result to date” in Cassandra field, Williams County. While no specific drilling plans have been announced, Whiting said it plans to begin a development drilling program, using nine wells per spacing unit in its prospective Middle Bakken holdings, as opposed to its original Sanish development plan of three to four wells per 1,280-ft spacing unit.
EOG Resources holds 110,000 net acres, 90,000 of which are in the core Bakken fairway, with the remaining 20,000 acres in its Antelope extension. Within its holdings, EOG plans to run between six and seven rigs this year, and drill 86 net wells. EOG says that as it continues to succeed with 1,300-ft spacing, it plans to test further reduced spacing this year.
During 2013, EOG said it managed to increase average flowrates in its leasehold from 894 bopd to 1,342 bopd, with equal improvements of 63% in average 100-day production rates. In a May 5 investor presentation, the operator said it had increased Bakken production at year-end 2013 by 38% over the year prior, to 86,000 boed.
Oasis Petroleum of Houston, after divesting non-operated properties in and around its Sanish project area for $321.9 million to an undisclosed buyer, still holds 506,960 net acres. Oasis reported that its second-quarter production will increase to between 43,000 and 46,000 boed. Oasis said it plans to operate 16 rigs this year. Its drilling plans include completing roughly 30 wells in the second and third benches of the Three Forks.
Marathon Oil, which holds 370,000 net acres prospective for the Middle Bakken and lower Three Fork benches, recorded net 43,000-boed production in the first quarter, a 16% hike over production in the first three months of 2013. Marathon plans to run six rigs this year and drill 75 to 85 net wells. This year, Marathon has established a completed well target of $7 million to $7.8 million.
Hess Corp. controls a Williston basin leasehold comprising 644,000 net acres, where it produced 63,000 boed in the first quarter, compared to an average 67,000 boed last year. The reduction was attributed to Hess’ curtailment of first-quarter production until the Tioga gas plant expansion was completed. Nevertheless, during the initial 2014 quarter, Hess put 30 wells on production. In 2013, Hess averaged 14 rigs and drilled a cumulative 195 wells. Meanwhile, on May 19, Hess CEO John Hess unveiled the operator’s upgraded Tioga plant, which he said is intended to reduce the volume of gas the company flares to as low as 15%, with an objective of eventually cutting flaring to as low as 10%.
FLARING, RAIL IN CROSSHAIRS
The timing of Hess’ Tioga plant expansion could not have been better. North Dakota regulators face increasing pressure to reduce flaring, which has accounted for as much as 36% of associated gas being burned off on-site. A serious dearth of pipeline capacity is at the root of the unprecedented volume of flared gas, which has not only increased public and political scrutiny, but is sending millions of dollars of potential revenue into flare stacks. North Dakota officials estimate that flaring is costing that state nearly $1 million a month in production tax revenue.
With the North Dakota Petroleum Council’s (NDPC) Flaring Task Force taking the lead, the industry recently presented a multi-faceted proposal to the Industrial Commission that it says is aimed at cutting flaring of associated gas to 10% within six years.
Among the solutions being promoted is the so-called “CNG in a box” developed by GE and Ferus Natural Gas Fuels LP, which employs a portable compression-and-cooling unit to convert field gas into fuel for rigs, frac pumps and other wellsite equipment. Statoil Oil and Gas LP says that it is using the mobile CNG system on bi-fuel rigs and other equipment that it operates.
Blaise Energy, a Bismarck-based company specializing in monetizing stranded gas, says it is using would-be flared gas in scalable modular systems that provide electrical power for one operator’s CNG compressor.
The flaring issue magnifies the pipeline deficiencies that have led to an estimated 70% of Bakken crude being shipped over railroads. Over the past year, this takeaway mode has come under an increasingly hotter fire, due to a string of train derailments, all carrying Bakken oil. The U.S. Department of Transportation (DOT) responded by tightening some of the rules regarding over-rail deliveries, while another agency proposed that Bakken crude be degasified before being loaded into tanker cars, a measure that the industry says would be economically prohibitive.
In January, the U.S. Pipeline and Hazardous Materials Safety Administration issued the recommendation after a train loaded with Bakken oil caught fire during a collision in Casselton, N.D. The NDPC responded with an all-inclusive Bakken crude characteristics study, which, in May, concluded that independent analysis of 152 samples revealed that Bakken oil was no more combustible than other light, sweet crudes produced elsewhere in the country.
NO END IN SIGHT
Even while recognizing that operators must reverse the steep decline rates, an executive of perhaps the leading cheerleader for the Bakken-Three Forks said those who may believe the play is about to run its course have little to stand on. Speaking at the IHS CERAWeek in Houston, Continental President Rick Bott said the Bakken-Three Forks is on pace for “at least three decades of growth. Bott told the Houston Chronicle that critics are “focusing on the wrong story’ when they look strictly at the rapid decline rates in the first year of production. “There is a steep decline, but then there is a very, very long tail. You get flush production, but it’s the tail you really count on. It can be a growth or a long plateau, based on the price signal. It’s only a question of the technology we can apply.”
I was reading that the USG has allowed some companies to export distillate(oil??) . What effect will it have on the refiners in USA and also prices in the market ? What are the short,medium (no long term since in shale oil this does not exist)effects of this policy ?
Actually, the way that read is condensate will be authorized for export, provided it has some refinery processing done to it for safety.
It would be nice to have description of that process.
Hole,
By law no one is allowed to export raw oil from the US, but a few companies have gotten permission to do so, through a dispensation. Instead, there has been extensive export of petroleum products such as gasoline, condensate (mostly to Canada) and diesel, because that is perfectly legal. That’s why your pump prices remain so high.
CLR is presently pressing Obama to lift the ban on exports of raw oil. He will probably do this if he needs to “buy” European support for any kind of major intervention in the Mideast. The reasoning is that their apparently “shouldn’t” be so much of a price spread between WTI and BRENT, if the free market is allowed to work. But, this is all part of CLR’s grand plan to get Bakken oil classified as Bakken Lite, which will then become the benchmark oil price for the entire world.
And, you people actually still think the Bakken is going to peak tomorrow?
I am not afraid of heat pumps per se if they are sold in the form of refrigerators which are in service twenty four seven three sixty five and are sold by the millions. Fridges are pretty reliable. So are window air conditioners. The problem with reliability and service arises when units are sold in low volumes and nobody really knows how to work on them and because of the initial low volume the dedicated parts are a pain in the ass for the manufacturer to keep in stock due to the low call for them years from now and since they never did sell many units in the first place they can get away with just leaving the customer hanging.
They can’t get away with that with fridges because the stink would ruin the brand name.
It is good shopping wisdom to never buy a low volume item of any sort unless it has very high utility because it is far more apt to break than an equivalent product sold in large quantities to the public.
And while a dryer is a real juice sucker the one at my house is used only an hour or two a week.
Now if I were the benevolent dictator of this fine country I would mandate the availability of all functional parts on a sliding scale based on price of everything sold. The more expensive the item the higher the time standard. Cheap computers would be ok at three to five years. Applainces that cost over a thousand buck would have to be guaranteed repairable for twenty years.
There is no doubt in my mind that for anybody with money available and a reasonable intention of staying put one of these heat pump water dryers or water heaters would be a great investment if it has an extended warranty.I personally expect retail electricity prices to rise at between five and ten percent a year on average for the foreseeable future.
And ten or fifteen years down the road they will probably be mandated and the old resistance heaters outlawed. But at that time they will also be sold in large numbers and therefore much cheaper relatively speaking.
Low volume equals high cost. I can get a good water heater for four hundred bucks with a long term warranty and a good air conditioner for the same money. No way in hell does it cost an extra seven hundred bucks to integrate the two considering the savings in shipping and packaging and actually marketing the heater.
That extra seven hundred is markup and marketing and advertising and above all the price of low volume manufacturing and distribution.
Now as far as hot water is concerned – the volume used is such that the payback time should be a lot shorter on average and that would help justify the higher initial cost of a heat pump hot water heater.
I built a solar domestic system from odds and ends of stuff that supplies about three fourths of our domestic hot water and so I will probably never buy a heat pump hot water heater or dryer. If the govt mandates such a purchase I will buy a couple of spares and put them in the big barn during the blowout get rid of them sale.
Three hundred watt clear incandescent bulbs are priceless now.I have only half a dozen left and can’t find any more at any price even at a flea market. I use them only a few hours a year but I gotta have them or spend a small fortune installing new lights with adequate output.
I should have bought a truckload of small cans of freon for fifty cents a can when it was outlawed. Car collectors are paying twenty bucks or more a can for it now if they can find any.
Here’s why I don’t think the economy will be able to “get out of its own way” (in spite of improving statistics.)
EIA World Crude + Condensate Data
World C + C Supplies are expanding at only 0.16% (125,000 bpd) Year on Year. This is compared to approx. 8 times that rate (1 Million bpd) up to 2005, and a bit over twice that rate (300,000 bpd) from 2005 to 2012. – Can you say, “reaching the top of the curve?”
It’s hard to see Global Growth at much more than 1% with these numbers, and with most of that going to China, and some of the Oil Exporters.